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+10-K
+1
+cpe-20141231x10k.htm
+10-K
+20141231 10K
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+FORM 10-K 
+☒ ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For The Fiscal Year Ended December 31, 2014 
+OR 
+☐ TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934 
+For the transition period from ____________ to ____________ 
+Commission File Number 001-14039 
+Callon Petroleum Company 
+(Exact Name of Registrant as Specified in Its Charter) 
+Delaware 
+(State or Other Jurisdiction of 
+Incorporation or Organization) 
+64-0844345 
+(IRS Employer 
+Identification No.) 
+200 North Canal Street 
+Natchez, Mississippi 
+(Address of Principal Executive Offices) 
+39120 
+(Zip Code) 
+601-442-1601 
+(Registrant’s Telephone Number, Including Area Code) 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of Each Class 
+Name of Each Exchange on Which Registered 
+Common Stock, $.01 par value 
+New York Stock Exchange 
+10.0% Series A Cumulative Preferred Stock 
+New York Stock Exchange 
+Securities registered pursuant to section 12 (g) of the Act: None 
+Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒ 
+Indicate by check mark whether the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒ 
+Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ 
+Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐ 
+Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☐ 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (check one): 
+Large accelerated filer 
+☐ 
+Accelerated filer 
+☒ 
+Non-accelerated filer 
+☐ 
+(Do not check if smaller reporting company) 
+Smaller reporting company 
+☐ 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ 
+Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 201 4 was approximately $456.3 million. The Registrant had 55,510,729 shares of common stock outstanding a s o f February 27, 2015 . 
+DOCUMENTS INCORPORATED BY REFERENCE 
+Portions of the definitive Proxy Statement of Callon Petroleum Company (to be filed no later than 120 days after December 31, 2014 ) relating to the Annual Meeting of Stockholders to be held on May 14, 2015 , which are incorporated into Part III of this Form 10-K. 
+Table of Contents 
+TABLE OF CONTENTS 
+Special Note Regarding Forward-Looking Statements 
+3 
+Definitions 
+4 
+Part I 
+Items 1 and 2. 
+Business and Properties 
+5 
+Acquisitions and Divestitures 
+69 
+Oil and Natural Gas Properties 
+7 
+Reserves and Production 
+10 
+Production Wells and Leasehold Acreage 
+14 
+Other 
+16 
+Regulations 
+17 
+Available Information 
+17 
+Item 1A. 
+Risk Factors 
+25 
+Item 1B. 
+Unresolved Staff Comments 
+37 
+Item 3. 
+Legal Proceedings 
+37 
+Item 4. 
+Mine Safety Disclosures 
+37 
+Part II 
+Item 5. 
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+38 
+Performance Graph 
+39 
+Item 6. 
+Selected Financial Data 
+40 
+Item 7. 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+41 
+Overview and Outlook 
+41 
+Liquidity and Capital Resources 
+43 
+Results of Operations 
+46 
+Significant Accounting Policies and Critical Accounting Estimates 
+53 
+Subsequent Events 
+55 
+Item 7A. 
+Quantitative and Qualitative Disclosures About Market Risk 
+56 
+Item 8. 
+Financial Statements and Supplementary Data 
+58 
+Report of Independent Registered Public Accounting Firm 
+59 
+Consolidated Balance Sheets 
+60 
+Consolidated Statements of Operations 
+61 
+Consolidated Statements of Comprehensive Income 
+62 
+Consolidated Statements of Stockholders’ Equity 
+63 
+Consolidated Statements of Cash Flows 
+64 
+Notes to Consolidated Financial Statements 
+65 
+Item 9. 
+Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+89 
+Item 9A. 
+Controls and Procedures 
+89 
+Item 9B. 
+Other Information 
+89 
+Report of Independent Registered Public Accounting Firm 
+90 
+Part III 
+Item 10. 
+Directors and Executive Officers and Corporate Governance 
+91 
+Item 11. 
+Executive Compensation 
+91 
+Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+91 
+Item 13. 
+Certain Relationships and Related Transactions and Director Independence 
+91 
+Item 14. 
+Principal Accountant Fees and Services 
+91 
+Part IV 
+Item 15. 
+Exhibits 
+92 
+Signatures 
+95 
+2 
+Table of Contents 
+Special N ote Regarding Forward Looking Statements 
+All statements, other than statements of historical fact, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve quantities, present value and growth and other plans and objectives for our future operations, are forward-looking statements. Although we believe the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance. 
+Forward-looking statements include the items identified in the preceding paragraph, information concerning possible or assumed future results of operations and other statements in this Form 10- K identified by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions. 
+You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect our operations, markets, products, services and prices and cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause our actual results to differ materially from those indicated in any forward-looking statement i nclude, but are not limited to: 
+· 
+the timing and extent of changes in market conditions and prices for oil, natural gas and NGLs (including regional basis differentials), 
+· 
+our ability to transport our production to the most favorable markets or at all, 
+· 
+the timing and extent of our success in discovering, developing, producing and estimating reserves, 
+· 
+our ability to fund our planned capital investments, 
+· 
+the impact of government regulation, including regulation of endangered species, any increase in severance or similar taxes, legislation relating to hydraulic fracturing, the climate and over-the-counter derivatives, 
+· 
+the costs and availability of oilfield personnel services and drilling supplies, raw materials, and equipment and services, 
+· 
+our future property acquisition or divestiture activities, 
+· 
+the effects of weather, 
+· 
+increased competition, 
+· 
+the financial impact of accounting regulations and critical accounting policies, 
+· 
+the comparative cost of alternative fuels, 
+· 
+conditions in capital markets, changes in interest rates and the ability of our lenders to provide us with funds as agreed, 
+· 
+credit risk relating to the risk of loss as a result of non-performance by our counterparties, and 
+· 
+any other factors listed in the reports we have filed and may file with the SEC. 
+We caution you that the forward-looking statements contained in this Form 10- K are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. These risks include, but are not limited to, the risks described in Item 1A of this Annual Report on Form 10-K for the year ended December 31, 2014 (the “ 2014 Annual Report on Form 10-K”), and all quarterly reports on Form 10-Q filed subsequently thereto. 
+Should one or more of the risks or uncertainties described above or in our 2014 Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. 
+All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement. 
+3 
+Table of Contents 
+DEFIN ITIONS 
+All defined terms under Rule 4-10(a) of Regulation S-X shall have their prescribed meanings when used in this report. As used in this document: 
+· 
+ARO : a sset retirement obligation. 
+· 
+Bbl or Bbls : barrel or barrels of oil or natural gas liquids. 
+· 
+Bcf : Billion cubic feet of natural gas. 
+· 
+BOE : barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas. The ratio of one barrel of oil or NGL to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas. 
+· 
+BBtu : billion Btu . 
+· 
+BOE/d : BOE per day. 
+· 
+BLM: Bureau of Land Management. 
+· 
+Btu : a British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit. 
+· 
+DOI: Department of Interior. 
+· 
+EPA: Environmental Protection Agency. 
+· 
+FASB: Financial Accounting Standards Board . 
+· 
+GAAP: Generally Accepted Accounting Principles in the United States. 
+· 
+GHG: greenhouse gases. 
+· 
+LIBOR : London Interbank Offered Rate. 
+· 
+LOE: lease operating expense , including workover expense . 
+· 
+MBbls : thousand barrels of oil. 
+· 
+MBOE : thousand BOE. 
+· 
+MBOE/d : Mboe per day. 
+· 
+Mcf : thousand cubic feet of natural gas. 
+· 
+MMBbls : million barrels of oil. 
+· 
+MMBOE : million BOE. 
+· 
+MMBtu : million Btu. 
+· 
+MMcf : million cubic feet of natural gas. 
+· 
+MMcf/d : MMcf per day. 
+· 
+NGL or NGLs : natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams. 
+· 
+NYMEX : New York Mercantile Exchange. 
+· 
+Oil : includes crude oil and condensate. 
+· 
+PDPs : proved developed producing reserves. 
+· 
+PDNPs : proved developed non-producing reserves. 
+· 
+PUDs : proved undeveloped reserves. 
+· 
+RSU : restricted stock units. 
+· 
+SEC : United States Securities and Exchange Commission. 
+With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross. 
+4 
+Table of Contents 
+PA RT I. 
+Ite ms 1 and 2 – Business and Properties 
+Overview 
+Callon Petroleum Company has been engaged in the exploration, development, acquisition and production of oil and natural gas properties since 1950. 
+In 2013, we completed our onshore strategic repositioning that began in 2009, shifting our operations from the offshore waters in the Gulf of Mexico to the onshore Permian Basin in West Texas. Our asset base is concentrated exclusively in the Midland Basin, a sub-basin located within the broader Permian Basin, characterized by high drilling success rates, high oil content, multiple vertical and horizontal productive intervals, and extensive production history. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. 
+Our net daily production for calendar year 2014 was 5,648 BOE/d (approximately 82% oil), representing an approximately 155% increase over comparable net daily Permian production in 2013 . The increase is primarily attributed to our increased focus on horizontal development initiated in 2012. We currently operate two horizontal drilling rigs focused on four prospective zones for development. 
+As of December 31, 2014 , we had estimated net proved reserves of 25.7 MMBbls and 42.5 Bcf, or 32.8 MMBOE, all of which were located in the Midland Basin. Additionally, 78% of our proved reserves were crude oil and 55% were proved developed at year-end 2014 on a BOE basis. 
+Our Business Strategy 
+Our goal is to enhance stockholder value through the execution of the following strategy: 
+Drive production and maximize resource recovery and reserve growth through horizontal development of our resource base. We believe our horizontal development efforts provide improved returns relative to vertical development of our resource base. Our initial vertical development programs allowed us to amass a database related to the subsurface geology and rock characteristics over the last several years. This information, combined with our review of industry activity and best practices, provided the foundation for us to initiate the horizontal development of our resource base in 2012 and further increase horizontal activity in recent quarters. As of December 31, 2014, we ha d 49 g ross producing horizontal wells, all of which we operate. During the fourth quarter of 2014, approximately 70% of our total Permian production was sourced from horizontal wells. We expect to grow the contribution of horizontal production volumes, both from our existing properties and from properties acquired in recent acquisitions, as we continue to execute a resource development program almost exclusively focused on horizontal development. 
+Expand our drilling portfolio through evaluation of existing acreage. Our horizontal development drilling efforts to date have been primarily focused on the Upper and Lower Wolfcamp B zones. We have focused on these development zones to reduce drilling risk as we continue to grow our asset base in the Permian Basin, though we have continued to expand our development focus on a measured basis. Most recently, we drilled three Lower Spraberry wells in the Southern and Central Midland Basin in the second half of 2014, complementing three Wolfcamp A wells placed on production in the Southern Midland Basin since the third quarter of 2013. We believe incremental opportunities exist to selectively target other prospective zones across various positions of our acreage, including the Clearfork, Jo Mill, Middle Spraberry, Wolfcamp C and Cline formations (in order of relative depth). In addition, we will continue to monitor the efficiency of our horizontal wells related to reservoir drainage over time, and will pursue downspacing initiatives within target zones if we believe overall returns would be enhanced. 
+Pursue selective acquisitions in the Permian Basin. During 2014, we continued to demonstrate our ability to acquire and trade acreage in the Midland Basin. Most significantly, we acquired 6,230 gross ( 3,862 net) acres located in Midland and Andrews Counties, which are in close proximity to our existing Carpe Diem and Pecan Acres fields, for approximately $210 million. Due to its close proximity to our existing fields, we believe this acquired acreage can be efficiently integrated into our ongoing horizontal development activity. The acquisition added 194 gross ( 121.6 net) potential horizontal drilling locations targeting the currently producing Wolcamp B, Lower Spraberry and Middle Spraberry zones, and additional potential horizontal drilling locations targeting four other prospective zones that are producing in offsetting fields. We also expanded our asset base in existing core development 
+5 
+Table of Contents 
+fields by acquiring 1,527 net acres for approximately $8.2 million through a “bolt-on” strategy whereby we identify and pursue smaller blocks of offsetting acreage that are potentially inefficient for the current owner to develop, but have value to Callon based on its location relative to our acreage. These smaller scale acquisitions generally provide acreage at costs significantly below the value assigned to larger blocks of acreage. While remaining mindful about our liquidity, we will continue to pursue leasehold acquisitions in the Permian Basin, and primarily in the Midland Basin, that have horizontal resource potential that can be further augmented by “bolt-on acreage” acquisitions and acreage trades over time. 
+Maintain financial liquidity and capacity to capitalize on growth opportunities. We believe that our asset base provides the opportunity to deploy a significant amount of capital for horizontal development in the coming years. We have focused on positioning ourselves to supplement our cash flow from operations with an improved cost of debt capital. In conjunction with our acquisition completed in the fourth quarter of 2014, we raised approximately $430 million in gross proceeds through a combination of common equity and long-term debt securities to support the acquisition and our ongoing development efforts in the Midland Basin. 
+Our Strengths 
+Established resource base and acreage position in the Permian Basin . Our production is exclusively from the Permian Basin in West Texas, an area that has supported production since the 1940s. The basin has well-established infrastructure from historical operations, and we believe the B asin also benefits from a relatively stable regulatory environment that has been established over time. We have assembled a position of approximately 18,065 net surface acres in the Southern and Central Midland Basin that are prospective for multiple oil-bearing intervals that have been produced by us and other industry participants. As of December 31, 2014 , our estimated net proved reserves were comprised of approximately 78% oil and 22% natural gas, which includes NGLs in the production stream. 
+Multi-year drilling inventory . Our current acreage position in the Permian Basin provides visible growth potential from a horizontal drilling inventory of approximately 525 locations, or 20 years under our current two-rig horizontal drilling program, based solely on four currently producing zones, which include the Lower Spraberry, the Wolfcamp A and the Upper and Lower Wolfcamp B. This drilling inventory increases to over 1,000 drilling locations, with the addition of drilling locations from other prospective zones, which include the Clearfork, Middle Spraberry, Jo Mill, Wolfcamp C and the Cline (or Wolfcamp D). Our identified well locations across our Southern and Central Midland Basin acreage are based upon the results of horizontal wells drilled by us and other offsetting operators, and our analysis of core data and historical vertical well performance. 
+Experienced team operating in the Permian Basin. We have assembled a management team experienced in acquisitions, exploration, development and production in the Midland Basin. Reflective of this experience, we have realized improvements in our drilling and capital efficiency since launching our horizontal drilling program in 2012 and drilling more than 5 0 horizontal wells with lengths varying from approximately 5,000 feet to 10,000 feet. We continue to evaluate our completion techniques, and downspacing initiatives that we believe have the potential to improve resource recovery and contribute to enhanced returns on capital. In addition, we regularly evaluate our operating results against those of other operators in the area in an effort to benchmark our performance against the best performing operators and evaluate and adopt best practices. 
+High degree of operational control . We operate nearly all of our Permian Basin acreage and have limited continuous drilling requirements across our acreage. For example, only 10% of our planned development drilling activity in 2015 is required to satisfy acreage commitments, with decreasing obligations in future years. This acreage status, combined with our control as an operator across the majority of our properties, provides us the opportunity to modify our operational plans to respond to changes in operational and commodity price environments. In addition, we have the ability to change our drilling schedule as needed to manage the assimilation of newly acquired acreage that may have drilling commitments. 
+Operating culture focused on safety and the environment . We have a Health, Safety and Environmental (“HSE”) department dedicated to our operations in the Permian Basin. This group is responsible for developing and implementing work processes to mitigate safety and environmental risks associated with our work activities. With emphasis on planning, training and communication, and empowering both our employees and third party service providers with Stop Work Authority, we continue to improve operational performance. Callon has enhanced Management of Change, routine inspections and compliance action tracking methods with the implementation of a HSE management system software program. This department also coordinates closely with our operational team to ensure effective communication with appropriate regulatory bodies as well as landowners. We believe that our proactive efforts in this area have made a positive impact on our operations and culture. 
+6 
+Table of Contents 
+Exploration and Development Activities 
+Our 2014 total capital expenditures, including acquisitions, were $455.5 million, representing a 166% increase over 2013 capital expenditures. Of the $455.5 million, $217.7 million was allocated to drilling, development and leasehold acquisition activity in the Permian B asin. During 2014 , we drilled 27 gross ( 24.4 net) horizontal and 7 gross ( 4.3 net) vertical wells, while completing 31 gross ( 27.3 net) horizontal and 5 gross ( 3.1 net) vertical wells. Capital expenditures for 2014 included the following expenditures (in millions): 
+Southern Midland Basin 
+$ 
+160.3 
+Central Midland Basin 
+56.9 
+Northern Midland Basin 
+0.5 
+Total operational expenditures 
+217.7 
+Capitalized general and administrative costs allocated directly to exploration and development projects 
+12.5 
+Capitalized interest 
+2.4 
+Total capitalized general and administrative and interest costs 
+14.9 
+Total operational expenditures inclusive of capitalized general and administrative and interest costs 
+232.6 
+Acquisitions 
+222.9 
+Total capital expenditures 
+$ 
+455.5 
+In late 2014, we expanded our horizontal pad development efforts to six fields. We expect our 2015 horizontal drilling program will be primarily focused on development of established Upper and Lower Wolfcamp zones in the Southern and Central Midland Basin. We also expect to drill five wells in the Southern and Central Midland Basin t argeting the Lower Spraberry shale formation and one well t argeting the Wolfcamp A shale formation. 
+Recent Dev elopments 
+We are currently operating two horizontal drilling rigs, complemented by an additional vertical rig that is being used to drill the vertical section of horizontal wells . Based on current commodity market conditions, the Company has elected to release the vertical rig in mid-March and focus on a two-rig horizontal program for the balance of 2015. 
+Oil and Natural Gas Properties 
+As of December 31, 2014 , our estimated net proved reserves totaled 32.8 MMBOE and included 25.7 MMBbls of oil and 42.5 Bcf, of natural gas with a pre-tax present value, discounted at 10%, of $629.7 million. Pre-tax present value is a non-GAAP financial measure, which we reconcile to the GAAP measure of standardized measure of $579.5 millio n in note (d) to the table below. Oil constituted approximately 78% of our total estimated equivalent net proved reserves and approximately 77% of our total estimated equivalent proved developed reserves. 
+7 
+Table of Contents 
+The following table sets forth certain information about our estimated net proved reserves prepared by our independent petroleum reserve engineers by major area and for all other properties combined at December 31, 2014 : 
+Pre-tax 
+Discounted 
+Estimated Net Proved Reserves 
+Present 
+Oil 
+(MBbls) 
+Natural Gas 
+(MMcf) 
+Total 
+(MBoe) 
+Value 
+($000) 
+(a) 
+(b)(c)(d) 
+Southern Midland Basin 
+16,973 
+26,102 
+21,323 
+$ 
+416,463 
+Central Midland Basin 
+8,736 
+16,337 
+11,459 
+219,286 
+Northern Midland Basin 
+24 
+109 
+42 
+803 
+Other 
+— 
+— 
+— 
+(6,872)
+Total 
+25,733 
+42,548 
+32,824 
+$ 
+629,680 
+(a) 
+We convert Mcf to BOE using a conversion ratio of six Mcf to one Bbl. This ratio, which is typical in the industry and represents the approximate energy equivalent of a Mcf to a Bbl, does not reflect to market price equivalence of Mcf of natural gas compared with a Bbl of oil or NGLs. On a market price equivalence basis, a barrel of oil or NGLs has a substantially higher price than six Mcf of natural gas. 
+(b) 
+Represents the present value of future net cash flows before deduction of federal income taxes, discounted at 10%, attributable to estimated net proved reserves as of December 31, 2014 , as set forth in the Company’s reserve reports prepared by its independent petroleum reserve engineers, DeGolyer and MacNaughton . 
+(c) 
+Includes a reduction for estimated plugging and abandonment costs that is reflected as a liability on our balance sheet at December 31, 2014 , in accordance with accounting for asset retirement obligations rules. These obligations were retained following the sale of our offshore operations. The negative Pre-Tax Discounted Present Value of the “Other” reflects plugging and abandonment obligations exceeding the future net cash flows. 
+(d) 
+The Company uses the financial measure “Pre Tax Discounted Present Value” which is a non-GAAP financial measure. The Company believes that Pre Tax Discounted Present Value, while not a financial measure in accordance with GAAP, is an important financial measure used by investors and independent oil and gas producers for evaluating the relative value of oil and natural gas properties and acquisitions because the tax characteristics of comparable companies can differ materially. The total standardized measure calculated in accordance with the guidance i ssued by the FASB for disclosures about oil and gas producing activities for our proved reserves as of December 31, 2014 was $579.5 million inclusive of the $50.1 million discounted estimated future income taxes relating to such future net revenues. The projected per Mcf natural gas price of $6.38 used in the 2014 reserve estimates has been adjusted to reflect the Btu content, transportation charges and other fees specific to the individual properties. The projected per barrel oil price of $86.30 used in the 2014 reserve estimates has been adjusted to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality. 
+8 
+Table of Contents 
+Permian Basin 
+As of December 31, 2014 , we owned leaseholds in 27,366 net acres in the Permian Basin. Average net production from the Company’s Permian Basin properties increased 155% to 5,648 B OE/d in 2014 from 2,227 BOE/d in 2013 . 
+Southern Midland Basin 
+· 
+Counties (fields) 
+o 
+Upton (East Bloxom and Opal) 
+o 
+Reagan (Taylor Draw and Garrison Draw) 
+o 
+Crockett (Block 5) 
+· 
+10,790 net acres as of December 31, 2014 
+· 
+59 gross ( 54 net) vertical and 39 gross ( 36 net) horizontal producing wells as of December 31, 2014 
+· 
+Initiated horizontal development in 2012 
+· 
+4 th quarter 2014 net production: 4,519 BOE/d ( 90% horizontal) 
+The Southern Midland Basin is our largest operating area in terms of productio n. W e currently have 10,790 net acres in this area. We commenced horizontal drilling efforts at our East Bloxom field in 2012 and have expanded our efforts to two additional fields in the Southern Midland Basin using pad development. Our horizontal wells are currently producing from three zones of the Wolfcamp shale (Upper Wolfcamp B, Lower Wolfcamp B and Wolfcamp A). We plan to continue focusing on these intervals in 2015 and also place our first Lower Spraberry well on production in the first quarter of 2015 . 
+Central Midland Basin 
+· 
+Counties (fields) 
+o 
+Midland (Carpe Diem , Pecan Acres , Ca sselman and Bohannon ) 
+o 
+Ector (Kayleigh and Bohannon ) 
+o 
+Andrews ( B o hannon ) 
+o 
+Martin (Casselman) 
+· 
+7,275 net acres as of December 31, 2014 
+· 
+218 gross ( 144 net) vertical and 11 gross ( 8 net) horizontal producing wells as of December 31, 2014 
+· 
+Initiated horizontal development in 2013 
+· 
+4 th quarter 2014 net production: 2,736 BOE/d 
+The Central Midland Basin ha s historically been the focus of our high-graded vertical drilling program, targeting multiple zones down to the Woodford shale. We shifted our focus to horizontal development in this area with our initial Wolfcamp B wells placed on production in the first quarter of 2014 in our Carpe Diem field. We have continued with program development of both the Wolfcamp B and Lower Spraberry zones in this field over the course of the year and are currently expanding our horizontal development to the Pecan Acres field. Importantly, we recently completed our last vertical well in the area and have no plans or obligations to drill any future vertical wells within our Permian Basin property base . 
+In addition to this organic drilling activity, in October 2014 w e acquired 6,230 gross ( 3,862 net) acres located in Midland, Andrews and Martin Counties, which are in close proximity to our existing Carpe Diem and Pecan Acres fields. Since the closing of the acquisition, we have placed two Wolfcamp B and one Lower Spraberry wells on production. 
+Northern Midland Basin 
+We acquired 21,617 net acres in Borden and Lynn Counties in 2012 . We currently own 9,301 net acres following our decision to allow acreage in the Northern Midland Basin to expire as we refine d our targeted areas for exploration . At this time, we have no plans for future activity a nd anticipate that our Northern Midland Basin acreage will expire in its entirety by 2016. As such, we reclassed approximately $2 5 million of the carrying value of our Northern Midland acreage that were classified as unevaluated properties to evaluated properties. We have no PUDs attributable to this acreage. At December 31, 2014, we had one gross (one net) producing vertical well in this area. 
+9 
+Table of Contents 
+For additional details regarding our Permian wells and related information, please see “Present Activities and Productive Wells” included below within this Item. 
+Other Property 
+We own a leasehold in 37,326 net acres located in various counties in Nevada. These leases are with the Bureau of Land Management and carry p rimary term s that expire in 2018 and 2019 . We are evaluating this acreage in conjunction with a third-party consultant and developing options for future activ ity. Callon does not have any drilling commitments related to this acreage during the primary term. However, we reclassed approximately $3 million of the carrying value of our Nevada acreage that were classified as unevaluated properties to evaluated properties. We have no PUDs or drilling commitments attributable to this acreage. We own additional immaterial properties in Louisiana. 
+Proved Reserves 
+Estimates of volumes of proved reserves at year-end, net to our interest, are presented in MBbls for oil and in MMcf for natural gas, including NGLs, at a pressure base of 15.025 pounds per square inch. Total equivalent volumes are presented in BOE. For the BOE computation, 6,000 cubic feet of gas are the equivalent of one barrel of oil. The ratio of six Mcf of gas to one BOE is typically used in the oil and gas business and represents the approximate energy equivalent of a barrel of oil and a Mcf of natural gas. The price of a barrel of oil is much higher than the price of six Mcf of natural gas, so the ratio of six Mcf to one BOE does not reflect the economic equivalent of a barrel of oil to six Mcf of gas. 
+The following table sets forth certain information about our estimated net proved reserves. All of our proved reserves are currently located in the continental United States and also included volumes in federal and state waters in the Gulf of Mexico at year-end 2012. 
+For the Year Ended December 31, 
+2014 (a) 
+2013 (a) 
+2012 (a) 
+Proved developed 
+Oil (MBbls) 
+14,006 
+5,960 
+4,955 
+Natural gas (MMcf) 
+25,171 
+9,059 
+10,680 
+MBOE 
+18,201 
+7,470 
+6,735 
+Proved undeveloped 
+Oil (MBbls) 
+11,727 
+5,938 
+5,825 
+Natural gas (MMcf) 
+17,377 
+8,692 
+9,073 
+MBOE 
+14,623 
+7,387 
+7,337 
+Total proved 
+Oil (MBbls) 
+25,733 
+11,898 
+10,780 
+Natural gas (MMcf) 
+42,548 
+17,751 
+19,753 
+MBOE 
+32,824 
+14,857 
+14,072 
+Financial Information 
+Estimated pre-tax future net cash flows (b) 
+$ 
+1,330,628 
+$ 
+680,627 
+$ 
+592,424 
+Pre-tax discounted present value (b) (c) 
+$ 
+629,680 
+$ 
+301,144 
+$ 
+250,097 
+Standardized measure of discounted future net cash flows (b) (c) 
+$ 
+579,542 
+$ 
+283,946 
+$ 
+231,148 
+(a) 
+The Company’s estimated proved reserves as of December 31, 201 4 were prepar ed by DeGo l yer and MacNaughton and estimated proved reserves as of December 31, 2013 and 2012 were prepar ed by Huddleston & Co. 
+(b) 
+Includes a redu ction for estimated plugging and abandonment costs that is reflected as a liability on our balance sheet at December 31, 2014 and 2013 , in accordance with accounting for asset retirement obligations rules. 
+(c) 
+The Company uses the financial measure “ p re-tax discounted present value” which is a non-GAAP financial meas ure. The Company believes that p re-tax discounted present value, while not a financial measure in accordance with GAAP, is an important financial measure used by investors and independent oil and gas producers for evaluating the relative value of oil and natural gas properties and acquisitions because the tax characteristics of comparable companies can differ materially. The total standardized measure calculated in accordance with the guidance issued by the FASB for disclosures about oil and gas producing activities for our proved reserves as of December 31, 2014 was $579.5 million inclusive of the $50.1 million discounted estimated future income taxes relating to such future net revenues. The projected per Mcf natural gas price of $6.38 used in the 2014 reserve estimates ha s been adjusted to reflect the Btu content, transportation charges and other fees specific to the individual properties. The projected per barrel oil price of $86.30 used in the 2014 reserve estimates 
+10 
+Table of Contents 
+ha s been adjusted to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality. 
+See Note 13 of our Consolidated Financial Statements for the additional information regarding the Company’s reserves including its estimates of proved reserves, PDPs, PUDs and the Company’s estimates of future net cash flows and discounted future net cash flows from proved reserves. 
+The Company’s estimated net proved reserves increased 121% to 32.8 MBOE from 14.9 MBOE at December 31, 2014 and 201 3 , respectively. Additions during the year were due to (1) 15.7 MMBOE related to the Company’s horizontal development of a portion of its Permian Basin properties and (2) 4.7 MMBOE related to acquired properties in the Permian Basin. These increases were partially offset by (1) 2.1 MMBOE related to the Company’s production during 2014 and (2) 0.3 MMBOE of net revisions , including 0.8 MMBOE of positive performance-related re visions that were offset by 1.1 MMBOE of PUD reclassifications. 
+Proved Undeveloped Reserves (PUDs) 
+Annually, the Company reviews its PUDs to ensure appropriate plans exist for development. PUD reserves are recorded only if the Company has plans to convert these reserves into PDPs within five years of the date they are first recorded. Our development plans include the allocation of capital to projects included within our 2015 capital budget and, in subsequent years, the allocation of capital within our long-range business plan to convert PUDs to PDPs within this five year period. In general, our 2015 capital budget and our long-range capital plans are primarily governed by our expectations of internally generated cash flow and credit facility borrowing availability. Reserve calculations at any end-of-year period are representative of our development plans at that time. Changes in commodity pricing, oilfield service costs and availability, and other economic factors may lead to changes in development plans. 
+The following table summarizes the Company’s recorded PUDs (in MBOE) : 
+For the Year Ended December 31, 
+2014 
+2013 
+2012 
+Permian Basin 
+14,623 
+7,387 
+6,040 
+Medusa (a) 
+— 
+— 
+1,297 
+Total 
+14,623 
+7,387 
+7,337 
+(a) 
+Effective July 1, 2013, we sold our interest in the Medusa field. See Note 3 for additional information. 
+Our PUDs increased 98% to 14.6 M MBOE from 7.4 M MBOE at December 31, 2014 a nd 2013 , respectively. We added 10.1 MMBOE to our PUDs , net of revisions, primarily from the continued horizontal development of our Permian Basin properties. The increase in PUDs was partially offset by the reclassification of 1.8 MMBOE, or 24% , included in the year-end 2013 PUD reserves, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately $34.6 million, net . Also offsetting the increase was the removal of 1.1 MMBOE of PUDs, including the impact from the reclassification of previous vertical PUDs to the horizontal probable category given our focus on horizontal development . 
+The Company plans to develop its PUDs as part of a multi-year drilling program. At December 31, 2014 , we had no reserves that remained undevelo p ed for five or more years, and all PUD drilling locations are currently scheduled to be drilled within three to five years of their initial recording. 
+Controls Over Reserve Estimates 
+Compliance as it relates to reporting the Company’s reserves is the responsibility of our Senior Vice President of Operations, who has over 35 years of industry experience including 2 7 years as a manager and is our principal engineer. In addition to his years of experience, our principal engineer holds a degree in petroleum engineering and is experienced in asset evaluation and management. 
+Callon’s controls over reserve estimates included retaining DeGolyer and MacNaughton , a Texas registered engineering firm, as our independent p etroleum and geological firm. The Company provided to DeGolyer and MacNaughton information about our oil and gas properties, including production profiles, prices and costs, and DeGolyer and MacNaughton prepared its own estimates of the reserves attributabl e to the Company’s properties. All of the information regarding 2014 reserves in this annual report is derived from DeGolyer and MacNaughton ’s report. DeGolyer and MacNaughton ’s reserve report letter is included as an Exhibit to this annual 
+11 
+Table of Contents 
+report. The principal engineer at DeGolyer and MacNaughton who certified the Company’s reserve estimates has over 4 0 years of experience in the oil and gas industry and is a Texas Licensed Professional Engineer. Further professional qualifications include a degree in petroleum engineering and membership in the International Society of Petroleum Engineers and the American Association of Petroleum Geologists . 
+All of the information regarding 2013 and 2012 reserves in this annual report is derive d from reserve reports prepared by Huddleston & Co. , Inc., a Texas engineering firm. 
+To further enhance the control environment over the reserve estimation process, our S trategic Planning Committee , a committee of the Board of Directors, assist s management and the Board with its oversight of the integrity of the determination of the Company’s oil and natural gas reserves and the work of our independent reserve engineer . The Committee’s charter also specifies that the Committee shall perform, in consultation with the Company’s management and senior reserves and reservoir engineering personnel, the following responsibilities: 
+· 
+Oversee the appointment, qualification, independence, compensation and retention of the independent petroleum and geological firm (the “Firm”) engaged by the Company (including resolution of material disagreements between management and the Firm regarding reserve determination) for the purpose of preparing or issuing an annual reserve report. The Committee shall review any proposed changes in the appointment of the Firm, determine the reasons for such proposal, and whether there have been any disputes between the Firm and management. 
+· 
+Review the Company’s significant reserves engineering principles and policies and any material changes thereto, and any proposed changes in reserves engineering standards and principles which have, or may have, a material impact on the Company’s reserves disclosure. 
+· 
+Review with management and the Firm the proved reserves of the Company, and, if appropriate, the probable reserves, possible reserves and the total reserves of the Company, including: (i) reviewing significant changes from prior period reports; (ii) reviewing key assumptions used or relied upon by the Firm; (iii) evaluating the quality of the reserve estimates prepared by both the Firm and the Company relative to the Company ’s peers in the industry; and (iv) reviewing any material reserve s adjustments and significant diffe rences between the Company’s a nd Firm’s estimates. 
+· 
+If the Committee deems it necessary, it shall meet in executive session with management and the Firm to discuss the oil and gas reserve determination process and related public disclosures, and any other matters of concern in respect of the evaluation of the reserves. 
+During our last fiscal year, we filed no reports with other federal agencies which contain an estimate of total proved net oil and natural gas reserves. 
+12 
+Table of Contents 
+Production Volumes, Average Sales Prices and Operating Costs 
+The following table sets forth certain information regarding the production volumes and average sales prices received for, and average production costs associated with, the Company’s sale of oil and natural gas for the periods indicated (dollars in thousands, except per unit data) . 
+For the Year Ended December 31, 
+2014 
+2013 
+2012 
+Production 
+Oil (MBbl) 
+1,692 
+911 
+977 
+Natural gas (MMcf) 
+2,220 
+3,011 
+3,588 
+Total (MBoe) 
+2,062 
+1,413 
+1,575 
+Revenues 
+Oil sales 
+$ 
+139,374 
+$ 
+88,960 
+$ 
+96,584 
+Natural gas sales 
+12,488 
+13,609 
+14,149 
+Total 
+$ 
+151,862 
+$ 
+102,569 
+$ 
+110,733 
+Operating costs 
+Lease operating expense 
+$ 
+22,372 
+$ 
+19,779 
+$ 
+23,330 
+Production taxes 
+8,973 
+4,133 
+3,224 
+Total 
+$ 
+31,345 
+$ 
+23,912 
+$ 
+26,554 
+Average realized sales price 
+Oil (Bbl) (excluding impact of cash settled derivatives) 
+$ 
+82.37 
+$ 
+97.65 
+$ 
+97.41 
+Oil (Bbl) (including impact of cash settled derivatives) 
+84.85 
+99.32 
+98.86 
+Natural gas (Mcf) (excluding impact of cash settled derivatives) 
+5.63 
+4.52 
+3.94 
+Natural gas (Mcf) (including impact of cash settled derivatives) 
+5.59 
+4.47 
+3.94 
+Total (BOE) (excluding impact of cash settled derivatives) 
+73.65 
+72.59 
+69.43 
+Total (BOE) (including impact of cash settled derivatives) 
+75.64 
+73.56 
+70.41 
+Operating costs per BOE 
+Lease operating expense 
+$ 
+10.85 
+$ 
+14.00 
+$ 
+14.81 
+Production taxes 
+4.35 
+2.92 
+2.05 
+Total 
+$ 
+15.20 
+$ 
+16.92 
+$ 
+16.86 
+13 
+Table of Contents 
+Present Activities and Produc tive Wells 
+The following table sets forth the wells drilled and completed during the periods indicated. All such wells were drilled in the continental United States. 
+Drilled 
+Completed (a) 
+Awaiting Completion 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Southern Midland Basin 
+Vertical wells 
+1 
+1.0 
+1 
+1.0 
+— 
+— 
+Horizontal wells 
+22 
+20.1 
+22 
+20.1 
+3 
+3.0 
+Total 
+23 
+21.1 
+23 
+21.1 
+3 
+3.0 
+Central Midland Basin 
+Vertical wells 
+4 
+1.8 
+3 
+1.3 
+1 
+0.4 
+Horizontal wells 
+5 
+4.3 
+9 
+7.2 
+— 
+— 
+Total 
+9 
+6.1 
+12 
+8.5 
+1 
+0.4 
+Northern Midland Basin 
+Vertical wells 
+2 
+1.5 
+1 
+0.8 
+— 
+— 
+Total 
+2 
+1.5 
+1 
+0.8 
+— 
+— 
+Total vertical wells 
+7 
+4.3 
+5 
+3.1 
+1 
+0.4 
+Total horizontal wells 
+27 
+24.4 
+31 
+27.3 
+3 
+3.0 
+Total 
+34 
+28.7 
+36 
+30.4 
+4 
+3.4 
+(a) 
+Completions include wells drilled prior to 201 4 . 
+The following table sets forth the Company’s drilled and completed wells, none of which were natural gas or nonproductive for the periods reflected: 
+2014 (a) 
+2013 
+2012 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Oil wells 
+Development 
+19 
+15.5 
+19 
+17.2 
+14 
+9.7 
+Exploratory 
+13 
+11.7 
+7 
+5.0 
+7 
+6.2 
+Total 
+32 
+27.2 
+26 
+22.2 
+21 
+15.9 
+(a) 
+Does not include two gross (two net) non-producing exploratory wells . 
+The following table sets forth productive wells as o f December 31, 2014 : 
+Oil Wells 
+Natural Gas Wells 
+Gross 
+Net 
+Gross 
+Net 
+Working interest 
+328 
+243.0 
+— 
+— 
+Royalty interest 
+3 
+0.1 
+— 
+— 
+Total 
+331 
+243.1 
+— 
+— 
+A well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas reserves on a BOE basis. However, most of our wells produce both oil and natural gas. 
+14 
+Table of Contents 
+For the periods presented, the following table sets forth by major field(s) net production volumes and percentage of estimated proved reserves: 
+For the Year Ended December 31, 
+Production Volumes (MBOE) 
+% of Total Proved Reserves 
+2014 
+2013 
+2012 
+2014 
+2013 
+2012 
+Permian Basin: 
+Southern Midland Basin 
+1,497 
+612 
+402 
+65% 
+85% 
+51% 
+Central Midland Basin 
+549 
+193 
+189 
+35% 
+14% 
+16% 
+Northern Midland Basin 
+16 
+8 
+— 
+0% 
+1% 
+0% 
+Total 
+2,062 
+813 
+591 
+100% 
+100% 
+67% 
+Offshore and other (a) 
+— 
+600 
+984 
+0% 
+0% 
+33% 
+Total 
+2,062 
+1,413 
+1,575 
+100% 
+100% 
+100% 
+(a) 
+In late 2013, we sold the remaining interests in our producing offshore fields and in the Haynesville shale. 
+Leasehold Acreage 
+The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage as of December 31, 2014 . 
+Developed 
+Undeveloped 
+Total 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Louisiana 
+936 
+200 
+188 
+55 
+1,124 
+255 
+Texas (a) 
+20,991 
+16,487 
+12,498 
+10,879 
+33,489 
+27,366 
+Federal onshore (b) 
+— 
+— 
+37,626 
+37,326 
+37,626 
+37,326 
+Total 
+21,927 
+16,687 
+50,312 
+48,260 
+72,239 
+64,947 
+(a) 
+A portion of our Texas acreage requires continu ous drilling to hold the acreage for which we have included in our development plans, though the cost to renew this acreage, if necessary, is no t considered material. 
+(b) 
+The Company’s lease of this acreage, located in Nevada, expires in 2018 and 2019 . The lease requires no drilling activity to hold the acreage, and we continue to evaluate our position and monitor the activity of other operators conducting drilling in the area. 
+Undeveloped Acreage Expirations 
+The following table sets forth by geographic area as o f December 31, 2014 the number of our leased gross and net undeveloped acres that will expire over the next three years unless production begins before lease expiration dates. Gross amounts may be more than net amounts in a particular year due to timing of expirations. 
+Net 
+Gross 
+2015 
+2016 
+2017 
+Total 
+Texas 
+Southern Permian Basin 
+165 
+— 
+— 
+165 
+165 
+Central Permian Basin 
+— 
+— 
+— 
+— 
+— 
+Northern Permian Basin (a) 
+7,307 
+648 
+— 
+7,955 
+10,575 
+Nevada (b) 
+— 
+— 
+— 
+— 
+— 
+Total 
+7,472 
+648 
+— 
+8,120 
+10,740 
+(a) 
+7,916 of the total remaining net acres include extension options that would allow us to extend the primary term for a period of two years. 
+(b) 
+The Company’s lease of this acreage does not expire until 2018 and 2019 . 
+The expiring acreage set forth in the table above accounts for 17% of our net undeveloped acreage ( 48,260 total net acres) and there are no PUD reserves attributable to such acreage. We are continually engaged in a combination of drilling and development and discussions with mineral lessors for lease extensions, renewals, new drilling and development units and new leases to address any potential expiration of undeveloped acreage that occurs in the normal course of our business. 
+15 
+Table of Contents 
+Title to Proper ties 
+The Company believes that the title to its oil and natural gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of such properties. The Company’s properties are potentially subject to one or more of the following: 
+· 
+royalties and other burdens and obligations, express or implied, u nder oil and natural gas leases; 
+· 
+overriding royalties and other burdens created by us or our predecessors in title; 
+· 
+a variety of contractual obligations (including, in some cases, development obligations) ari sing under operating agreements; farm-out agreements, production sales contracts and other agreements that may affect the propert ies or their titles; 
+· 
+back-ins and reversionary interests existing under purchase agree ments and leasehold assignments; 
+· 
+liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual l iens under operating agreements; 
+· 
+pooling, unitization and communitization agre ements, declarations and orders; and 
+· 
+easements, restrictions, rights-of-way and other matters that commonly affect property. 
+To the extent that such burdens and obligations affect the Company’s rights to production revenues, these characteristics have been taken into account in calculating Callon’s net revenue interests and in estimating the size and value of its reserves. The Company believes that the burdens and obligations affecting our properties are typical within the industry for properties of the kind owned by Callon. 
+Insurance 
+In accordance with industry practice, the Company maintains insurance against some, but not all, of the operating risks to which its business is exposed. While not all inclusive, the Company’s insurance policies include coverage for general liability insuring onshore operations (including sudden and accidental pollution), aviation liability, auto liability, worker’s compensation, and employer’s liability. The company carries control of well insurance for only those onshore operations that it is contractually bound to do so. At the depths and in the areas in which the Company operates, and in light of the vertical and horizontal drilling that it undertakes, the Company typically does not encounter high pressures or extreme drilling conditions onshore. 
+Currently, the Company has general liability insurance coverage up to $1 million per occurrence and $2 million per policy in the aggregate, which includes sudden and accidental pollution liability coverage for the effects of pollution on third parties arising from its operations. The Company’s insurance policies contain high policy limits, and in most cases, deductibles (generally ranging from $0 to $250,000) that must be met prior to recovery. These insurance policies are subject to certain customary exclusions and limitations. T he Company maintains up to $100 million in excess liability coverage, which is in addition to and triggered if the underlying liability limits have been reached. In addition, the company purchases pollution legal liability coverage in the amount of $5 m illion , which is excess and difference in conditions of the liability coverage. 
+The Company requires all of its third-party contractors to sign master service agreements in which they agree to indemnify the Company for injuries and deaths of the service provider’s employees, as well as contractors and subcontractors hired by the service provider. Similarly, the Company generally agrees to indemnify each third-party contractor against claims made by employees of the Company and the Company’s other contractors. Additionally, each party generally is responsible for damage to its own property. 
+The third-party contractors that perform hydraulic fracturing operations for the Company sign master service agreements generally containing the indemnification provisions noted above. The Company does not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations. However, the Company believes its general liability and excess liability insurance policies would cover foreseeable third party claims related to hydraulic fracturing operations and associated legal expenses, in accordance with, and subject to, the terms of such policies. 
+The Company re-evaluates the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and natural gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. While based on the Company’s risk analysis, it believes that it is properly insured, no assurance can be given that the Company will be able to maintain insurance in the 
+16 
+Table of Contents 
+future at rates that it considers reasonable. In such circumstances, the Company may elect to self-insure or maintain only catastrophic coverage for certain risks in the future. 
+Major Customers 
+Our produ ction is sold generally on month-to-month contracts at prevailing prices. The following table identifies customers to whom we sold a significant percentage of our total oil and natural gas production, on an equivalent basis, during each of the 12-month periods indicate d: 
+For the Year Ended December 31, 
+2014 
+2013 
+2012 
+Enterprise Crude Oil, LLC 
+51% 
+38% 
+32% 
+Plains Marketing, L.P. 
+22% 
+15% 
+15% 
+Sunoco 
+10% 
+0% 
+0% 
+Shell Trading Company 
+0% 
+31% 
+39% 
+Other 
+17% 
+16% 
+14% 
+Total 
+100% 
+100% 
+100% 
+Because alternative purchasers of oil and natural gas are readily available, the Company believes that the loss of any of these purchasers would not result in a material adverse effect on Callon’s ability to market future oil and natural gas production. We are not currently committed to provide a fixed and determinable quantity of oil or gas in the near future under our contracts. 
+Corporate Offices 
+The Company’s headquarters are located in Natchez, Mississippi, in approximately 51,500 square feet of owned space. We also maintain leased business offices in Houston and Midland, Texas. Because alternative locations to our leased spaces are readily available, the replacement of any of our leased offices would not result in material expenditures . 
+Employees 
+Callon had 109 employees as of December 31, 2014 . None of the Company’s employees are currently represented by a union, and the Company believes that it has good relations with its employees. 
+Regulations 
+General. Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the entire oil and natural gas industry is continuously being reviewed for amendment and/ or expansion. Some of these requirements carry substantial penalties for failure to comply. 
+Exploration and Production . Our operations are subject to federal, state and local regulations that include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds and letters of credit) covering drilling and well operations. Other activities subject to regulation are: 
+· 
+th e location and spacing of wells; 
+· 
+the method of drilling and completing and operating wells; 
+· 
+th e rate and method of production; 
+· 
+the surface use and restoration of properties upon which wells are drilled a nd other exploration activities; 
+· 
+notice to surface owners and other third parties; 
+· 
+the ve nting or flaring of natural gas; 
+· 
+the p lugging and abandoning of wells; 
+· 
+the discharge of contaminants into water and the em ission of contaminants into air; 
+· 
+the disposal of fluids used or other wastes obtaine d in connection with operations; 
+· 
+the marketing, transportat ion and reporting of production; and 
+17 
+Table of Contents 
+· 
+the valuation and payment of royalties. 
+Operations conducted on federal or state oil and natural gas leases must comply with numerous regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Department of the Interior (“DOI”) Bureaus or other appropriate federal or state agencies. 
+Our sales of oil and natural gas are affected by the availability, terms and cost of pipeline transportation. The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation. If these regulations change, we could face higher transmission costs for our production and, possibly, reduced access to transmission capacity. 
+Various proposals and proceedings that might affect the petroleum industry are pending before Congress, the Federal Energy Regulatory Commission, or FERC, various state legislatures, and the courts. The industry historically has been heavily regulated and we can offer you no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue nor can we predict what effect such proposals or proceedings may have on our operations. 
+We do not currently anticipate that compliance with existing laws and regulations governing exploration and production will have a significantly adverse effect upon our capital expenditures, earnings or competitive position. 
+Environmental Matters and Regulation. Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the U.S. Environmental Protection Agency (“ EPA ”) issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. Violations of environmental laws could result in administrative, civil or criminal fines and injunctive relief. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Further, the EPA has identified environmental compliance by the energy extraction sector as one of its enforcement initiatives for 2014-2016 and, as a general matter, the oil and natural gas exploration and production industry has been the subject of increasing scrutiny and regulation by environmental authorities. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. Although such laws and regulations can increase the cost of planning, designing, installing and operating our facilities, it is anticipated that, absent the occurrence of an extraordinary event, compliance with them will not have a material effect upon our operations, capital expenditures, earnings or competitive position in the marketplace. 
+Waste Handling. The Resource Conservation and Recovery Act (“ RCRA ”) , as amended , and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of oil and natural gas are exempt from regulation as hazardous wastes under RCRA and its state analogs, it is possible that some wastes we generate presently or in the future may be subject to regulation under RCRA and state analogs. Additionally, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in 
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+Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. 
+Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of wastes associated with oil and natural gas exploration and production could increase our costs to manage and dispose of such wastes. 
+Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“ CERCLA ”) , imposes joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or so–called potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes. 
+Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we have generated and will generate wastes that may fall within CERCLA’s definition of hazardous substance and may have disposed of these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum. We may also be the owner or operator of sites on which hazardous substances have been released. To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under CERCLA; we also do not know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties. In the event contamination is discovered at a site on which we are or have been an owner or operator or to which we sent hazardous substances, we could be liable for the costs of investigation and remediation and natural resources damages. 
+We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including offsite locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination. 
+Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act (“ OPA ”) , and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States (a term broadly defined to include, among other things, certain wetlands) , as well as state waters for analogous state programs. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or applicable state analog . The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. These laws and regulations also prohibit the discharge of dredge or fill material in regulated waters, including wetlands , unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. 
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+Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. 
+The Oil Pollution Act is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters. 
+Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws. 
+Air Emissions. The federal Clean Air Act, as amended, and comparable state and local laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and modified and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, on April 17 , 2012, the EPA published final regulations under the federal Clean Air Act that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail below in “Regulation of Hydraulic Fracturing.” These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties and seek injunctive relief for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects. 
+Greenhouse Gas ( “ GHG ” ) Regulation. More stringent laws and regulations relating to climate change and GHGs may be adopted in the future and could cause us to incur material expenses in complying with them. In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions. Although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutant s . 
+T he EPA has established GHG reporting requirements for certain sources in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissions. Although these requirements do not limit the amount of GHGs that can be emitted, they could require us to incur significant costs to monitor, keep records of, and potentially report GHG emissions associated with our operations if the reporting threshold is reached with production growth. The EPA recently announced its intention to take measures to require or encourage reductions in methane emissions, including from oil and natural gas operations. Those measures include the development of NSPS regulations in 2016 for reducing methane from new and modified oil and gas production sources and natural gas processing and transmission sources. 
+In addition to possible federal regulation, a number of states, individually and regionally, also are considering or have implemented GHG regulatory programs. These potential regional and state initiatives may result in so-called “Cap-and-Trade programs”, under which overall GHG emissions are limited and GHG emissions are then allocated and sold, and possibly other regulatory requirements, that could result in our incurring material expenses to comply, such as by being required to purchase or to surrender allowances for GHGs resulting from our operations. These federal, regional and local regulatory initiatives also could adversely affect the marketability of the oil and natural gas we produce. The impact of such future programs cannot be predicted, but we do not expect our operations to be affected any differently than other similarly situated domestic competitors. 
+Regulation of Hydraulic Fracturing. Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act (“ SDWA ”) , regulates the underground injection of substances through the Underground Injection Control (“ UIC ”) , program. Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions and not at the federal level, as the SDWA expressly excludes regulation of these fracturing 
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+activities (except where diesel is a component of the fracturing fluid, as further discussed below) . Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing have been proposed in recent sessions of Congress but have not passed. 
+The EPA, however, issued guidance on permitting hydraulic fracturing that uses fluids containing diesel fuel under the UIC program, specifically as “Class II” UIC wells. At the same time, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices and the EPA has commenced a study of the potential impacts of hydraulic fracturing activities on drinking water resources. The EPA has announced that it plans to propose standards in 2014 that such wastewater must meet before being transported to a treatment plant. As part of these studies, the EPA has requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. 
+The EPA has adopted regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes Ne w Source Performance Standards f or hydraulically fractured natural gas wells to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured gas wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2 015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA may issue revised rules that are likely responsive to some of these requests. If revised, these rules could require modifications to our operations or increase our capital and operating costs without being offset by increased product capture. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty. In addition, the U.S. Department of the Interior published a revised proposed rule that would update existing regulation for hydraulic fracturing activities on federal lands, including requirements for disclosure, well bore integrity and handling of flowback water. EPA has announced that it is considering regulations under the Toxic Substance Control Act to require evaluation and disclosure of hydraulic fracturing. 
+In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The federal government is currently undertaking several studies of hydraulic fracturing’s potential impacts, most notably the EPA’s study on the environmental impacts of hydraulic fracturing, the final results of which are not yet available.. These ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. 
+Several states, including Texas, and some municipalities, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission has adopted rules and regulations implementing this legislation that apply to all wells for which the Railroad Commission issues an initial drilling permit after February 1, 2012. The new law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act ( “ OSHA ” ) for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. 
+Additionally, some states, localities and local regulatory districts have adopted or have considered adopting regulations to limit, and in some case impose a moratorium on hydraulic fracturing or other restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water. Further, there has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could 
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+adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing. 
+Surface Damage Statutes (“SDAs”) . In addition, a number of states and some tribal nations have enacted SDAs. These laws are designed to compensate for damage caused by oil and gas development operations. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain binding requirements for payments to the operator in connection with exploration and operating activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs. 
+National Environmental Policy Act and Endangered Species Act . Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act (“ NEPA ”) , which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. To the extent that our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects. 
+The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ or its habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. If the Company were to have a portion of its leases designated as critical or suitable habitat or a protected species were located on a lease, it may adversely impact the value of the affected leases. 
+Mineral Leasing Act of 1920 (“Mineral Act”) . The Mineral Act prohibits direct or indirect ownership of any interest in federal onshore oil and natural gas leases by a foreign citizen or a foreign corporation except through stock ownership in a corporation formed under the laws of the United States or of any U.S. state or territory, and only if the laws, customs, or regulations of their country of origin or domicile do not deny similar or like privileges to citizens or corporations of the United States. If these restrictions are violated, the oil and gas lease or leases can be canceled in a proceeding instituted by the United States Attorney General. Although the regulations of the Bureau of Land Management (“BLM”) (which administers the Mineral Act) provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. The Company owns an interest in federal leaseholds in Nevada. It is possible that holders of the Company’s equity interests may be citizens of foreign countries, which could be determined to be citizens of a non-reciprocal country under the Mineral Act. In such event, the federal onshore oil and gas leases held by the Company could be subject to cancellation based on such determination. 
+Other Regulation of the Oil and Natural Gas Industry. The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production. 
+The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. Federal and state regulations govern 
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+the rates and other terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas. 
+Although oil and natural gas sales prices are currently unregulated, the federal government historically has been active in the area of oil and natural gas sales regulation. We cannot predict whether new legislation to regulate oil and natural gas sales might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate, oil and natural gas liquids are not currently regulated and are made at market prices. 
+Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following: 
+· 
+the location of wells; 
+· 
+the method of drilling and casing wells; 
+· 
+the timing of construction or drilling activities, including seasonal wildlife closures; 
+· 
+the rates of production or “allowables”; 
+· 
+the surface use and restoration of properties upon which wells are drilled; 
+· 
+the plugging and abandoning of wells; and 
+· 
+notice to, and consultation with, surface owners and other third parties. 
+State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations we can drill. 
+Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements. 
+Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. 
+FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and for the release of our excess, if any, natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all 
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+purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities. 
+Under FERC’s current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting gas to point-of-sale locatio ns. 
+The pipelines used to gather and transport natural gas being produced by the Company are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), the Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In August 2011, the PHMSA issued an Advance Notice of Proposed Rulemaking regarding pipeline safety, including questions regarding the modification of regulations applicable to gathering lines in rural areas. 
+Oil and NGLs Sales and Transportation. Sales of oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. 
+The Company’s sales of oil and natural gas liquids are also affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by the FERC under the Interstate Commerce Act. The FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors. 
+Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors. 
+Any transportation of the Company’s crude oil, natural gas liquids and purity components (ethane, propane, butane, iso-butane, and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts 171-180 (“HMR”), including Emergency Orders by the FRA and new regulations being proposed by the PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids. 
+State Regulation. Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill. 
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+The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us. 
+Commitments and Contingencies 
+The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment will not have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies included, and claims for damages to property, employees, other persons, and the environment resulting from the Company’s operations could have on its activities. See Note 14 for additional information. 
+Available Information 
+We make available free of charge on our Internet web site (www.callon.com) our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the SEC. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE., Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an Internet site (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers, like Callon, that file electronically with the SEC. 
+We also make available within the Investors section of our Internet web site our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and Audit, Compensation and Nominating and Governance Committee Charters, which have been approved by our board of directors. We will make timely disclosure by a Current Report on Form 8-K and on our web site of any change to, or waiver from, the Code of Business Conduct and Ethics for our principal executive and senior financial officers. A copy of our Code of Business Conduct and Ethics is also available, free of charge by writing us at: Chief Financial Officer, Callon Petroleum Company, P.O. Box 1287, Natchez, MS 39121. 
+Item 1A. Ri sk Factors 
+Risk Factors 
+Depressed oil and natural gas prices may adversely affect our results of operations and financial condition . Our success is highly dependent on prices for oil and natural gas, which are extremely volatile, and the oil and natural gas markets are cyclical. Approximately 8 0% of our anticipated 2015 production, on a BOE basis, is oil. Starting in the second half of 2014, the NYMEX price for a barrel of oil has fallen sharply, from a price of $105.37 on June 30, 2014 to $49.76 on February 27 , 201 5 . In addition, NYMEX prices for natural gas have been low compared with historical prices. Extended periods of low prices for oil or natural gas will have a material adverse effect on us. The prices of oil and natural gas depend on factors we cannot control such as weather, economic conditions, and levels of production, actions by OPEC and other countries and government actions. Prices of oil and natural gas will affect the following aspects of our business: 
+· 
+our revenues, cash flows and earnings; 
+· 
+the amount of oil and natural gas that we are economically able to produce; 
+· 
+our ability to attract capital to finance our operations and the cost of the capital; 
+· 
+the amount we are allowed to borrow under our credit facilities; 
+· 
+the profit or loss we incur in exploring for and developing our reserves; and 
+· 
+the value of our oil and natural gas properties. 
+Any substantial and extended decline in the price of oil or natural gas could have an adverse effect on our borrowing capacity, our ability to obtain additional capital, and our revenues, profitability and cash flows. 
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+If oil and natural gas prices remain depressed for extended periods of time, we may be required to take additional write - downs of the carrying value of our oil and natural gas properties. We may be required to write - down the carrying value of our oil and natural gas properties when oil and natural gas prices are low. Under the full cost method, which we use to account for our oil and natural gas properties, the net capitalized costs of our oil and natural gas properties may not exceed the present value, discounted at 10%, of future net cash flows from estimated net proved reserves, using the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month, plus the lower of cost or fair market value of our unproved properties. If net capitalized costs of our oil and natural gas properties exceed this limit, we must charge the amount of the excess to earnings. This type of charge will not affect our cash flows, but will reduce the book value of our stockholders’ equity. Because the oil price we are required to use to estimate our future net cash flows is the average price over the 12 months prior to the date of determination of future net cash flows, the full effect of falling prices may not be reflected in our estimated net cash flows for several quarters. We review the carrying value of our properties quarterly and once incurred, a write - down of oil and natural gas properties is not reversible at a later date, even if prices increase. See Note 13 to our Cons olidated Financial Statements. 
+Our actual recovery of reserves may substantially differ from our proved reserve estimates and our proved reserve estimates may change over time. This Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. In addition, drilling, testing and production data acquired since the date of an estimate may justify revising an estimate. 
+Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from the estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report. Additionally, reserves and future cash flows may be subject to material downward or upward revisions, based on production history, development drilling and exploration activities and prices of oil and natural gas. We incorporate many factors and assumptions into our estimates including: 
+· 
+Expected reservoir characteristics based on geological, geophysical and engineering assessments; 
+· 
+Future production rates; 
+· 
+Future oil and natural gas prices and quality and locational differences; and 
+· 
+Future development and operating costs. 
+You should not assume that any present value of future net cash flows from our estimated net proved reserves contained in this Form 10-K represents the market value of our oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves at December 31, 2014 on average 12-month prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures , the rate and timing of production, and changes in governmental regulations or taxes. At December 31, 2014 , approximately 25% of the discounted present value of our estimated net proved reserves consisted of PUDs. PUDs represented 45% of total proved reserves by volume. Recovery of PUDs generally requires significant capital expenditures and successful drilling operations. Our reserve estimates include the assumption that we will make significant capital expenditures to develop these undeveloped reserves and the actual costs, development schedule, and results associated with these properties may not be as estimated. In addition, the 10% discount factor that we use to calculate the net present value of future net revenues and cash flows may not necessarily be the most appropriate discount factor based on our cost of capital in effect from time to time and the risks associated with our business and the oil and gas industry in general. 
+Information about reserves constitutes forward-looking information. See “Forward-Looking Statements” for information regarding forward-looking information. 
+Unless we replace our oil and gas reserves, our reserves and production will decline. Our future oil and gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our production, revenues, reserve quantities and cash flows will decline. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be limited to the extent cash flow from operations is 
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+reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. 
+Exploring for, developing, or acquiring reserves is capital intensive and uncertain. We may not be able to economically find, develop, or acquire additional reserves, or may not be able to make the necessary capital investments to develop our reserves, if our cash flows from operations decline or external sources of capital become limited or unavailable. As part of our exploration and development operations, we have expanded, and expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture stimulation techniques. The utilization of these techniques requires substantially greater capital expenditures, currently expected to be in excess of three times the cost, as compared to the drilling of a traditional vertical well. If we do not replace the reserves we produce, our reserves revenues and cash flow will decrease over time, which will have an adverse effect on our business. 
+Our business requires significant capital expenditures and we may not be able to obtain needed capital or financing on satisfactory terms or at all . Our exploration and development activities are capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Historically, we have funded our capital expenditures through a combination of cash flows from operations, borrowings under our credit facility and public debt and equity financings. In 2014 , our total capital expenditures, including expenditures for leasehold interests and property acquisitions, drilling, seismic and infrastructure, were approximately $455.5 million. Our 2015 capital budget for drilling, completion and infrastructure is estimated to be approximately $150 to $165 million. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technologica l and competitive developments. 
+If the borrowing base under our revolving credit facility or our revenues decrease as a result of lower oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or cash available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our drilling locations, which in turn could lead to a possible expiration of our leases and a decline in our estimated net proved reserves, and could adversely affect our business, financial condition and results of operations. 
+Our revolving credit facility and second lien term loan facility contain restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities. Our credit facilities restrictive covenants that limit our ability to, among other things: 
+· 
+incur additional indebtedness; 
+· 
+create additional liens; 
+· 
+sell assets; 
+· 
+merge or consolidate with another entity; 
+· 
+pay dividends or make other distributions; 
+· 
+engage in transactions with affiliates; and 
+· 
+enter into certain swap agreements. 
+In addition, we will be required to use substantial portions of our future cash flow to repay principal and interest on our indebtedness. Our credit facilities require us to maintain certain financial ratios and tests, including a minimum asset value coverage ratio of total debt. The requirement that we comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business. 
+Our borrowings under our revolving credit facility and second lien term loan facility expose us to interest rate risk. Our earnings are exposed to interest rate risk associated with borrowings under our revolving credit facility, which bear interest at a rate elected by us that is based on the prime, LIBOR or federal funds rate plus margins ranging from 1 .75% to 2.75% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base. Our second lien term loan bears interest at a 
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+rate of LIBOR , subject to a floor of 1%, p lus 7.5 0 %. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition. 
+The borrowing base under our revolving credit facility may be reduced below the amount of borrowings outstanding under such facilities. Under the terms of our revolving credit facility, our borrowing base is subject to redeterminations at least semi-annually based in part on prevailing oil and gas prices. A negative adjustment could occur if the estimates of future prices used by the banks in calculating the borrowing base are significantly lower than those used in the last redetermination. The next redetermination of our borrowing base is scheduled to occur on or about March 31, 2015. In addition, the portion of our borrowing base made available to us is subject to the terms and covenants of the revolving credit facility including, without limitation, compliance with the financial performance covenants of such facility. In the event the amount outstanding under our revolving credit facility exceeds the redetermined borrowing base, we are required to either (i) grant liens on additional oil and gas properties (not previously evaluated in determining such borrowing base) with a value equal to or greater than such excess or (ii) repay such excess borrowings over five monthly installments. We may not have sufficient funds to make any required repayment. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, an event of default would occur under our revolving credit facility. 
+The unavailability or high cost of drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget. From time to time, our industry has experiences a shortage of drilling rigs, equipment, supplies, water or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. Increasing levels of exploration and production may increase the demand for oilfield services and equipment, and the costs of these services and equipment may increase, while the quality of these services and equipment may suffer. The unavailability or high cost of drilling rigs, pressure pumping equipment, supplies or qualified personnel can materially and adversely affect our operations and profitability. 
+Our operations substantially depend on the availability of water. Restrictions on our ability to obtain, dispose of or recycle water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner. Water is an essential component of our drilling and hydraulic fracturing processes. Historically, we have been able to secure water from local landowners and other sources for use in our operations. During the last few years, West Texas has experienced extreme drought conditions. As a result of the severe drought, some local water districts may begin restricting the use of water under their jurisdiction for drilling and hydraulic fracturing to protect the local water supply. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil, NGLs and natural gas, which could have an adverse effect on our business, financial condition and results of operations. 
+Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area. All of our producing properties are geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of oil, natural gas or natural gas liquids. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations. 
+Our exploration projects increase the risks inherent in our oil and natural gas activities. We may seek to replace reserves through exploration, where the risks are greater than in acquisitions and development drilling. Our exploration drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including: 
+· 
+the results of our exploration drilling activities; 
+· 
+receipt of additional seismic data or other geophysical data or the reprocessing of existing data; 
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+· 
+material changes in oil or natural gas prices; 
+· 
+the costs and availability of drilling rigs; 
+· 
+the success or failure of wells drilled in similar formations or which would use the same production facilities; 
+· 
+availability and cost of capital; 
+· 
+changes in the estimates of the costs to drill or complete wells; and 
+· 
+changes to governmental regulations. 
+Delays in exploration, cost overruns or unsuccessful drilling results could have a material adverse effect on our business and future growth. 
+Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns. Exploration, development, drilling and production activities are subject to many risks, including the risk that commercially productive deposits will not be discovered. We may invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that any leasehold acreage acquired will be profitably developed, that new wells drilled will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, wells that are profitable may not achieve our targeted rate of return. 
+In addition, we may not be successful in controlling our drilling and production costs to improve our overall return. We may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including: 
+· 
+unexpected drilling conditions; 
+· 
+pressure or irregularities in formations; 
+· 
+equipment failures or accidents and shortages or delays in the availability of drilling rigs and the delivery of equipment; and 
+· 
+compliance with governmental requirements. 
+Failure to conduct our oil and gas operations in a profitable manner may result in write - downs of our proved reserves quantities, impairment of our oil and gas properties, and a write- down in the carrying value of our unproved properties, and over time may adversely affect our growth, revenues and cash flows. 
+Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could prevent them from being drilled or delay their drilling. Our management team has identified drilling locations as an estimation of our future development activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these identified drilling locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system, marketing and transportation constraints, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the identified drilling locations will ever be drilled or if we will be able to produce oil or natural gas from these drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the identified locations are located, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified. 
+The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Approximately 45% of our total estimated proved reserves as of December 31, 2014, were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves. 
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+We may be unable to integrate successfully the operations of future acquisitions with our operations, and we may not realize all the anticipated benefits of these acquisitions. Our business may include producing property acquisitions that would include undeveloped acreage. We can offer no assurance that we will achieve the desired profitability from any acquisitions we may complete in the future. In addition, failure to assimilate recent and future acquisitions successfully could adversely affect our financial condition and results of operations. Our acquisitions may involve numerous risks, including: 
+· 
+operating a larger combined organization and adding operations; 
+· 
+difficulties in the assimilation of the assets and operations of the acquired business, especially if the assets acquired are in a new geographic area; 
+· 
+risk that oil and natural gas reserves acquired may not be of the anticipated magnitude or may not be developed as anticipated; 
+· 
+loss of significant key employees from the acquired business: 
+· 
+diversion of management’s attention from other business concerns; 
+· 
+failure to realize expected profitability or growth; 
+· 
+failure to realize expected synergies and cost savings; 
+· 
+coordinating geographically disparate organizations, systems and facilities; and 
+· 
+coordinating or consolidating corporate and administrative functions. 
+Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. If we consummate any future acquisition, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisition and current operations, which in turn, could negatively impact our results of operations. 
+We may fail to fully identify problems with any properties we acquire, and as such, assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities. We are actively seeking to acquire additional acreage in Texas or other regions in the future. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, operating and capital costs and potential environmental and other liabilities. Although we conduct a review of properties we acquire which we believe is consistent with industry practices, we can give no assurance that we have identified or will identify all existing or potential problems associated with such properties or that we will be able to mitigate any problems we do identify. Such assessments are inexact and their accuracy is inherently uncertain. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for preclosing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms. 
+Unexpected subsurface conditions and other unforeseen operating hazards may adversely impact our ability to conduct business. There are many operating hazards in exploring for and producing oil and natural gas, including: 
+· 
+our drilling operations may encounter unexpected formations or pressures, which could cause damage to equipment or personal injury; 
+· 
+we may experience equipment failures which curtail or stop production; 
+· 
+we could experience blowouts or other damages to the productive formations that may require a well to be re-drilled or other corrective action to be taken; 
+· 
+storms and other extreme weather conditions could cause damages to our production facilities or wells. 
+Because of these or other events, we could experience environmental hazards, including release of oil and natural gas from spills, natural gas-leaks, accidental leakage of toxic or hazardous materials, such as petroleum liquids, drilling fluids or fracturing fluids, including chemical additives, underground migration, and ruptures. 
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+If we experience any of these problems, it could affect well bores, gathering systems and processing facilities, which could adversely affect our ability to conduct operations. We could also incur substantial losses in excess of our insurance coverage as a result of: 
+· 
+injury or loss of life; 
+· 
+severe damage to and destruction of property, natural resources and equipment; 
+· 
+pollution and other environmental damage; 
+· 
+clean-up responsibilities; 
+· 
+regulatory investigation and penalties; 
+· 
+suspension of our operations; and 
+· 
+repairs to resume operations. 
+We cannot assure you that we will be able to maintain adequate insurance at rates we consider reasonable to cover our possible losses from operating hazards. The occurrence of a significant event not fully insured or indemnified against could materially and adversely affect our financial condition and results of operations. 
+Factors beyond our control affect our ability to market production and our financial results. The ability to market oil and natural gas from our wells depends upon numerous factors beyond our control. These factors could negatively affect our ability to market all of the oil or natural gas we produce. In addition, we may be unable to obtain favorable prices for the oil and natural gas we produce. These factors include: 
+· 
+the extent of domestic production and imports of oil and natural gas; 
+· 
+federal regulations generally prohibiting the export of U.S. crude oil; 
+· 
+federal regulations applicable to exports of liquefied natural gas (LNG); 
+· 
+the proximity of hydrocarbon production to pipelines; 
+· 
+the availability of pipeline capacity; 
+· 
+the demand for oil and natural gas by utilities and other end users; 
+· 
+the availability of alternative fuel sources; 
+· 
+the effects of inclement weather; 
+· 
+state and federal regulation of oil and natural gas marketing; and 
+· 
+federal regulation of natural gas sold or transported in interstate commerce. 
+In particular, in areas with increasing non-conventional shale drilling activity, capacity may be limited and it may be necessary for new interstate and intrastate pipelines and gathering systems to be built. 
+The marketability of our production is dependent upon oil and condensate trucking facilities owned and operated by third parties, and the unavailability of these facilities would have a material adverse effect on our revenue. Our ability to market our production depends in substantial part on the availability and capacity of oil and condensate trucking operations owned and operated by third parties. Our failure to obtain these services on acceptable terms could materially harm our business. We may be required to shut in wells for lack of a market or because of inadequate or unavailable trucking capacity. If that were to occur, we would be unable to realize revenue fr om those wells until production arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. 
+The disruption of third party trucking facilities due to maintenance, weather or other factors could negatively impact our ability to market and deliver our oil and condensate. The third parties control when , or if , such trucking facilities are restored and what prices will be charged. In the past, we have experienced disruptions in our ability to market oil and condensate from bad weather. We may experience similar interruptions as we continue to explore and develop our Permian Basin properties in the future. If we were required to shut in our production for long periods of time due to lack of trucking capacity, it would have a material adverse effect on our business, financial condition, results of operations and cash flows. 
+Part of our strategy involves drilling in new or emerging shale formations using horizontal drilling and completion techniques. The results of our planned drilling program in these formations may be subject to more uncertainties than conventional drilling programs in more established formations and may not meet our expectations for reserves or production. The results of 
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+our recent horizontal drilling efforts in new or emerging formations, including certain intervals in the Wolfcamp shale, the Spraberry shale and the Cline shale in the Permian basin, are generally more uncertain than drilling results in areas that are developed and have established production. Because new or emerging formations have limited or no production history, we are less able to rely on past drilling results in those areas as a basis predict our future drilling results. Further, access to adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more challenging in new or emerging areas. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, access to gathering systems and takeaway capacity or otherwise, and/or natural gas and oil prices decline, our investment in these areas may not be as economic as we anticipate, we could incur material write - downs of unevaluated properties and the value of our undeveloped acreage could decline in the future. 
+The loss of key personnel could adversely affect our ability to operate. We depend, and will continue to depend in the foreseeable future, on the services of our senior officers and other key employees, as well as other third-party consultants with extensive experience and expertise in evaluating and analyzing drilling prospects and producing oil and natural gas from proved properties and maximizing production from oil and natural gas properties. Our ability to retain our senior officers, other key employees and our third party consultants, none of whom are subject to employment agreements, is important to our future success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business. 
+We may not be insured against all of the operating risks to which our business is exposed. In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We cannot assure you that our insurance will be adequate to cover losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. No assurance can be given that we will be able to maintain insurance in the future at rates we consider reasonable and may elect none or minimal insurance coverage. The occurrence of a significant event, not fully insured or indemnified against, could have a material adverse effect on our financial condition and operations. 
+Competitive industry conditions may negatively affect our ability to conduct operations. We compete with numerous other companies in virtually all facets of our business. Our competitors in development, exploration, acquisitions and production include major integrated oil and gas companies and smaller independents as well as numerous financial buyers, including many that have significantly greater resources. Therefore, competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources permit. We also compete for the materials, equipment and services that are necessary for the exploration, development and operation of our properties. Our ability to increase reserves in the future will be dependent on our ability to select and acquire suitable prospects for future exploration and development. Factors that affect our ability to compete in the marketplace include: 
+· 
+our access to the capital necessary to drill wells and acquire properties; 
+· 
+our ability to acquire and analyze seismic, geological and other information relating to a property; 
+· 
+our ability to retain the personnel necessary to properly evaluate seismic and other information relating to a property; 
+· 
+our ability to procure materials, equipment and services required to explore, develop and operate our properties, including the ability to procure fracture stimulation services on wells drilled; and 
+· 
+our ability to access pipelines, and the location of facilities used to produce and transport oil and natural gas production. 
+Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “ Dodd-Frank Act”) establishes federal oversight and regulation of over-the-counter derivatives and requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the over-the-counter market. 
+Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized. In one of its rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC approved on November 5, 2013, a proposed rule imposing position limits for certain futures and option contracts in various commodities (including natural gas) and for swaps that are their economic equivalents. Certain specified types of hedging transactions are exempt from these position limits, provided that such hedging transactions satisfy the CFTC’s requirements for “bona fide hedging” transactions or positions. Similarly, the CFTC has issued a proposed rule on margin requirements for swap transactions, which proposes an exemption for commercial end-users, entering into uncleared swaps in order to hedge commercial risks affecting 
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+Table of Contents 
+their business, from any requirement to post margin to secure such swap transactions. In addition, the CFTC has issued a final rule authorizing an exception for commercial end-users using swaps to hedge their commercial risks from the otherwise applicable mandatory obligation under the Dodd-Frank Act to clear all swap transactions through a registered derivatives clearing organization and to trade all such swaps on a registered exchange. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations. All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business . 
+While it is not possible at this time to predict when the CFTC will issue final rules applicable to position limits or margin requirements, depending on the Company’s ability to satisfy the CFTC’s requirements for the various exemptions available for a commercial end-user using swaps to hedge or mitigate its commercial risks, these rules and regulations may require us to comply with position limits, margin requirements and with certain clearing and trade-execution requirements in connection with financial derivative activities. The Dodd-Frank Act may require our current counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which could increase the cost to us of entering into such derivatives. The Dodd-Frank Act may also require our current counterparties to financial derivative transactions to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties, and may cause some entities to cease their current business as hedge providers. These changes could reduce the liquidity of the financial derivatives markets thereby reducing the ability of commercial end-users to have access to financial derivatives to hedge or mitigate their exposure to commodity price volatility. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available capital for other commercial operations purposes), materially alter the terms of future swaps relative to the terms of our existing bilaterally negotiated financial derivative contracts, and reduce the availability of derivatives to protect against commercial risks we encounter . 
+If we reduce our use of derivative contracts as a result of the new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas and natural gas liquids prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and natural gas liquids. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations, or cash flows. 
+We may not have production to offset hedges. Part of our business strategy is to reduce our exposure to the volatility of oil and natural gas prices by hedging a portion of our production. In a typical hedge transaction, we will have the right to receive from the other parties to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the other parties this difference multiplied by the quantity hedged. Additionally, we are required to pay the difference between the floating price and the fixed price when the floating price exceeds the fixed price regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements even though such payments are not offset by sales of physical production. 
+By hedging, we may not benefit from price increases. Hedging can prevent us from receiving the full advantage of increases in oil or natural gas prices above the fixed amount specified in a hedge transaction in the case of a swap. We also enter into price “collars” to reduce the risk of changes in oil and natural gas prices. Under a collar, no payments are due by either party so long as the market price is above a floor set in the collar and below a ceiling. If the price falls below the floor, the counter-party to the collar pays the difference to us and if the price is above the ceiling, we pay the counter-party the difference. Another type of hedging contract we have entered into is a put contract. Under a put, if the price falls below the set floor price, the counter-party to the contract pays the difference to us. See “Quantitative and Qualitative Disclosures About Market Risks” for a discussion of our hedging practices. 
+Our hedging transactions expose us to counterparty credit risk . Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contrac t. During periods of falling commodity prices, our hedging transactions expose us to risk of financial loss if our counterparty to a derivatives transaction fails to perform its obligations under a derivatives transaction (e.g., our counterparty fails to perform its obligation to make payments to us under the derivatives transaction when the market (floating) price under such derivative falls below the specified fixed price). We are unable to predict sudden changes in a counterparty’s 
+33 
+Table of Contents 
+creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss. 
+The inability of one or more of our customers to meet their obligations to us may adversely affect our financial results . Our principal exposures to credit risk are through receivables resulting from the sale of our oil and natural gas production, which we market to energy marketing companies, refineries and affiliates, advances to joint interest parties and joint interest receivables. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. The largest purchaser of our oil and natural gas accounted for approximately 51 % of our total oil and natural gas revenues for the year ended December 31, 2014 . We do not require any of our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. Joint interest receivables arise from billing entities who own a partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we choose to drill. We have limited ability to control participation in our wells. 
+Compliance with environmental and other government regulations could be costly and could negatively impact production. Our operations are subject to numerous laws and regulations governing the operation and maintenance of our facilities and the discharge of materials into the environment or otherwise relating to environmental protection. For a discussion of the material regulations applicable to us, see “Regulations.” These laws and regulations may: 
+· 
+require that we acquire permits before commencing drilling; 
+· 
+impose operational, emissions control and other conditions on our activities; 
+· 
+restrict the substances that can be released into the environment in connection with drilling and production activities; 
+· 
+limit or prohibit drilling activities on protected areas such as wetlands and wilderness areas; and 
+· 
+require measures to remediate or mitigate pollution and environmental impacts from current and former operations, such as cleaning up spills or dismantling abandoned production facilities. 
+Under these laws and regulations, we could be liable for costs of investigation, removal and remediation, damages to and loss of use of natural resources, loss of profits or impairment of earning capacity, property damages, costs of and increased public services, as well as administrative, civil and criminal fines and penalties, and injunctive relief. Certain environmental statutes, including the RCRA, CERCLA, OPA and analogous state laws and regulations, impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released. We could also be affected by more stringent laws and regulations adopted in the future, including any related to climate change, greenhouse gases and hydraulic fracturing. Under the common law, we could be liable for injuries to people and property. We maintain limited insurance coverage for sudden and accidental environmental damages. We do not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Also, we do not believe that insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability or we may be required to cease production from properties in the event of environmental incidents. 
+Climate change legislation or regulations restricting emissions of “greenhouse gasses” ( “ GHG ” ) could result in increased operating costs and reduced demand for the oil and natural gas we produce. In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions. Although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. The EPA recently announced its intention to take measures to require or encourage reductions in methane emissions, including from oil and natural gas operations. Those measures include the development of NSPS regulations in 2016 for reducing methane from new and modified oil and gas production sources and natural gas processing and transmission sources. 
+In addition, the EPA requires the reporting of GHG emissions from specified large GHG emission sources including onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities, which may include facilities we operate. Reporting of GHG emissions from such facilities is required on an annual basis. We will have to incur costs associated with this reporting obligation. 
+In addition, the United States Congress has considered (but not passed) legislation to reduce emissions of GHGs and many states have already taken or have considered legal measures to reduce or measure GHG emissions, often involving the planned development of GHG emission inventories and/or cap and trade programs. Most of these cap and trade programs would require major sources of 
+34 
+Table of Contents 
+emissions or major producers of fuels to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. These allowances would be expected to escalate significantly in cost over time. The adoption and implementation of any legislation or regulatory programs imposing GHG reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGS associated with our operations or could adversely affect demand for the oil and natural gas that we produce. 
+Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects. In an interpretative guidance on climate change disclosures, the SEC indicates that climate change could have an effect on the severity of weather (including storms and floods), the arability of farmland, and water availability and quality. If such effects were to occur, our exploration and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production activities either because of climate-related damages to our facilities in our costs of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate chan ge could also have an indirect e ffect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. In addition, our hydraulic fracturing operations require large amounts of water. Should drought conditions occur, our ability to obtain water in sufficient quality and quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. 
+Federal legislation and state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. Hydraulic fracturing is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing activities are typically regulated by state oil and gas commissions but not at the federal level, as the federal Safe Drinking Water Act expressly excludes regulation of these fracturing activities (except where diesel is a component of the fracturing fluid). We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with the wells for which we are the operator. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under federal and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury. In March 2010, the EPA announced that it would conduct a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. A progress report was issued in December 2012; a final report is not yet available. The agency also announced that one of its enforcement initiatives for 2014 to 2016 would be to focus on environmental compliance by the energy extraction sector. This study and the EPA’s enforcement initiative could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. 
+A committee of the U.S. House of Representatives conducted an investigation of hydraulic fracturing practices. Legislation was introduced before Congress, but not passed to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states and local or regional regulatory authorities have adopted or are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For example, New York has announced that it will ban high volume hydraulic fracturing. Further, Pennsylvania has adopted a variety of regulations limiting how and where fracturing can be performed. While we have no operations in either New York or Pennsylvania, any other new laws or regulations that significantly restrict hydraulic fracturing in areas in which we do operate could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby affect the determination of whether a well is commercially viable. Further, the EPA has announced initiatives under the CWA to establish standards of wastewater from hydraulic fracturing and under TSCA to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals, and the BLM has indicated that it will continue with rulemaking to regulate hydraulic fracturing on federal lands. In addition, if hydraulic fracturing becomes further regulated at the federal level, our fracturing activities could become subject to additional permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs and potential liabilities. Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. In addition, restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that we are ultimately able to produce in commercial quantities. 
+35 
+Table of Contents 
+We are now subject to regulation under NSPS and NESHAPS programs, which could result in increased operating costs. On April 17, 2012, the EPA issued final rules that subject oil and natural gas production, processing, transmission and storage operations to regulation under the NSPS and the NESHAP programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards require owners/operators to reduce VOC emissions from natural gas not sent to the gathering line during well completion either by flaring, using a completion combustion device, or by capturing the natural gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to newly fractured wells and also existing wells that are refractured. Further, the finalized regulations also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules may require changes to our operations, including the installation of new equipment to control emissions. 
+Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation. In recent years, the Obama administration’s budget proposals and other proposed legislation have included the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production. If enacted into law, these proposals would eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. These changes include, but are not limited to (1) the repeal of the percentage depletion allowance for oil and gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for U.S. production activities and (4) the increase in the amortization period from two years to seven years for geophysical costs paid or incurred in connection with the exploration for or development of, oil and gas within the United States. It is unclear whether any such changes will be enacted or how soon any such changes would become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could negatively affect the Company’s financial condition and results of operations. 
+There are inherent limitations in all control systems, and misstatements due to error or fraud that could seriously harm our business may occur and not be detected. Our management, including our Chief Executive Officer and Chief Financial Officer, do not expect that our internal controls and disclosure controls will prevent all possible error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, an evaluation of controls can only provide reasonable assurance that all material control issues and instances of fraud, if any, in our company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Further, controls can be circumvented by the individual acts of some persons or by collusion of two or more persons. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. A failure of our controls and procedures to detect error or fraud could seriously harm our business and results of operations. 
+We have no plans to pay cash dividends on our common stock in the foreseeable future. We have no plans to pay cash dividends in the foreseeable future. Any future determination as to the declaration and payment of cash dividends will be at the discretion of our board of directors and will depend upon our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors deemed relevant by our board of directors. In addition, the terms of our credit facilities prohibit us from paying dividends and making other distributions. 
+Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations. Our business has become increasingly dependent on digital technologies to conduct certain exploration, development, production and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our exploration or production operations. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyber-attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. 
+36 
+Table of Contents 
+While we have not experienced cyber-attacks, there is no assurance that we will not suffer such attacks and resulting losses in the future. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks. 
+ITEM 1B. Unr esolved Staff Comments 
+None. 
+ITEM 3. Leg al Proceedings 
+We are a defendant in various legal proceedings and claims, which arise in the ordinary course of our business. We do not believe the ultimate resolution of any such actions will have a material effect on our financial position or results of operations. 
+ITEM 4. Mi ne Safety Disclosures 
+Not applicable. 
+37 
+Table of Contents 
+PAR T II. 
+ITEM 5. Ma rket for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+Market Information 
+Our common stock trades on the New York Stock Exchange under the symbol “CPE”. The following table sets forth the high and low sale prices per share as reported for the periods indicated. 
+Common Stock Price 
+2014 
+2013 
+High 
+Low 
+High 
+Low 
+First quarter 
+$ 
+9.00 
+$ 
+6.13 
+$ 
+5.82 
+$ 
+3.62 
+Second quarter 
+11.75 
+8.15 
+4.00 
+3.19 
+Third quarter 
+12.09 
+8.46 
+5.49 
+3.40 
+Fourth quarter 
+8.99 
+4.09 
+7.60 
+5.18 
+Holders 
+As of February 27, 2015 the Company had approximately 2,995 common stockholders of record. 
+Dividends 
+We have not paid any cash dividends on our common stock to date and presently do not expect to declare or pay any cash dividends on our common stock in the foreseeable future as we intend to reinvest our cash flows and earnings into our business. The declaration and payment of dividends is subject to the discretion of our Board of Directors and to certain limitations imposed under Delaware corporate law and the agreements governing our debt obligations. The timing, amount and form of dividends, if any, will depend on, among other things, our results of operations, financial condition, cash requirements and other factors deemed relevant by our Board of Directors. In addition, certain of our debt facilities contain restrictions on the payment of dividends to the holders of our common stock. 
+Holders of our Series A preferred stock are entitled to a cumulative dividend whether or not declared, of $5.00 per annum, payable quarterly, equivalent to 10.0% of the liquidation preference of $50.00 per share. Unless the full amount of the dividends for the Series A Preferred Stock is paid in full, we cannot declare or pay any dividend on our common stock. 
+During the fourth quarter of 201 4 , neither the Company nor any affiliated purchasers made re purchases of Callon’s equity securities. 
+Equity Compensation Plan Information 
+The following table summarizes information regarding the number of shares of our common stock that are available for issuance under all of our existing equity compensation plans as of December 31, 2014 ( securities amounts are presented in thousands). 
+Plan Category 
+Number of securities to be issued upon exercise of outstanding options 
+Weighted-average exercise price of outstanding options, warrants and rights 
+Number of securities remaining available for future issuance under equity compensation plans 
+Equity compensation plans approved by security holders 
+15 
+$ 
+13.71 
+1,132 
+Equity compensation plans not approved by security holders 
+15 
+$ 
+14.37 
+- 
+Total 
+30 
+$ 
+14.04 
+1,132 
+For additional information regarding the Company’s benefit plans and share-based compensation expense, see Notes 8 and 9 to the Consolidated Financial Statements. 
+38 
+Table of Contents 
+Performance Graph 
+The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the performance of the Company’s common stock relative to four broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. 
+T he graph below compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the S&P 500 Index and SIG Oil Exploration & Production Index from December 31, 200 9 , through December 31, 2014 . 
+The stock performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing. 
+Comparison of Five Year Cumulative Total Return 
+Assumes Initial Investment of $100 
+December 201 4 
+For the Year Ended December 31, 
+Company/Market/Peer Group 
+2009 
+2010 
+2011 
+2012 
+2013 
+2014 
+Callon Petroleum Company 
+$ 
+100.00 
+$ 
+394.67 
+$ 
+331.33 
+$ 
+313.33 
+$ 
+435.33 
+$ 
+363.33 
+S&P 500 Index - Total Returns 
+100.00 
+115.06 
+117.49 
+136.30 
+180.44 
+205.14 
+SIG Oil Exploration & Production Index 
+100.00 
+123.12 
+111.96 
+104.20 
+131.89 
+94.56 
+39 
+Table of Contents 
+ITEM 6. Selected Fi nancial Data 
+The following table sets forth, as of the dates and for the periods indicated, selected financial information about us. The financial information for each of the five years in the period ended December 31, 2014 has been derived from our audited Consolidated Financial Statements for such periods. The information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and Notes thereto. The following information is not necessarily indicative of our future results (dollars in thousands, except per share amounts) . 
+For the Year Ended December 31, 
+2014 
+2013 
+2012 
+2011 
+2010 
+Statement of Operations Data 
+Operating revenues 
+Oil and natural gas sales 
+$ 
+151,862 
+$ 
+102,569 
+$ 
+110,733 
+$ 
+127,644 
+$ 
+89,882 
+Operating expenses 
+Total operating expenses 
+$ 
+113,592 
+$ 
+91,905 
+$ 
+100,043 
+$ 
+88,022 
+$ 
+68,703 
+Income from continuing operations 
+38,270 
+10,664 
+10,690 
+39,622 
+21,179 
+Net income (a) 
+37,766 
+4,304 
+2,747 
+106,396 
+8,386 
+Earnings (loss) per share ("EPS") 
+Basic 
+$ 
+0.67 
+$ 
+(0.01)
+$ 
+0.07 
+$ 
+2.81 
+$ 
+0.29 
+Diluted 
+$ 
+0.65 
+$ 
+(0.01)
+$ 
+0.07 
+$ 
+2.76 
+$ 
+0.28 
+Weighted average number of shares outstanding for Basic EPS 
+44,848 
+40,133 
+39,522 
+37,908 
+28,817 
+Weighted average number of shares outstanding for Diluted EPS 
+45,961 
+40,133 
+40,337 
+38,582 
+29,476 
+Statement of Cash Flows Data 
+Net cash provided by operating activities 
+$ 
+94,387 
+$ 
+54,475 
+$ 
+51,290 
+$ 
+79,167 
+$ 
+100,102 
+Net cash used in investing activities 
+(452,501)
+(79,804)
+(93,703)
+(91,511)
+(59,738)
+Net cash provided by (used in) financing activities 
+356,070 
+27,202 
+(243)
+38,703 
+(26,252)
+Balance Sheet Data 
+Total oil and gas properties 
+$ 
+742,155 
+$ 
+324,187 
+$ 
+269,521 
+$ 
+215,912 
+$ 
+168,868 
+Total assets 
+876,770 
+423,953 
+378,173 
+369,707 
+218,326 
+Long-term debt (b) 
+335,000 
+75,748 
+120,668 
+125,345 
+165,504 
+Stockholders' equity 
+433,735 
+279,094 
+205,971 
+201,202 
+15,810 
+Proved Reserves Data 
+Total oil (MBbls) 
+25,733 
+11,898 
+10,780 
+10,075 
+8,149 
+Total natural gas (MMcf) 
+42,548 
+17,751 
+19,753 
+35,118 
+32,957 
+Total (MBOE) 
+32,824 
+14,857 
+14,072 
+15,928 
+13,641 
+Standardized measure (c) 
+$ 
+579,542 
+$ 
+283,946 
+$ 
+231,148 
+$ 
+270,357 
+$ 
+198,916 
+(a) 
+Net income for 2011 includes $69.3 million of income tax benefit related to the reversal of the Company’s deferred tax asset valuation allowance. See Note 10 for additional information. 
+(b) 
+See Note 4 for additional information. 
+(c) 
+Standardized measure is the future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet. Prices are based on either the preceding 12-months’ average price, based on closing prices on the first day of each month, or prices defined by existing contractual arrangements. Future production and development costs are based on current estimates with no escalations. Estimated future cash flows have been discounted to their present values based on a 10% discount rate. 
+40 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+ITEM 7. Mana gement’s Discussion and Analysis of Financial Condition and Results of Operations 
+General 
+The following management’s discussion and analysis describes the principal factors affecting the Company’s results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying audited consolidated financial statements , information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results , which are included in various parts of this filing. Our website address is www.callon.com . All of our filings with the SEC are available free of charge through our website as soon as reasonably practicable after we file them with, or furnish them to, the SEC. Information on our website does not form part of this report on Form 10- K . 
+We are an independent oil and natural gas company established in 1950. We are focused on the acquisition, development, exploration and exploitation of unconventional, onshore, oil and natural gas reserves in the Permian Basin in West Texas, and more specifically, the Midland Basin. Our operations to date have been predominantly focused on horizontal drilling of several prospective intervals, including multiple levels of the Wolfcamp formation. We have assembled a multi-year inventory of potential horizontal well locations and intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and acquisition of additional locations through acreage purchases, joint ventures and asset swaps. Our production was approximately 82% oil and 18% natural gas for the year ended December 31, 2014 . On December 31, 2014 , our net acreage position in the Permian Basin was 27,366 net acres, including 9,301 net acres in the Northern Midland Basin that the Company plans to let expire . 
+Significant accomplishments for 2014 include: 
+· 
+Acquired 6,230 gross ( 3,862 net) surface acres in Midland , Andrews , Martin and Ector Counties for approximately $210 million, which added over 1,300 BOE/d of production and approximately 194 gross ( 121.6 net) potential horizontal drilling locations (see below) ; 
+· 
+Expanded our existing core development areas in Upton and Reagan Counties by acquiring 1,527 net acres for $8.2 million; 
+· 
+Increased Permian Basin annual production in 2014 by 155% to 2,062 MBOE as compared to 2013; 
+· 
+Increased 2014 proved reserves by 121% to 32.8 MMBOE as compared to 2013; 
+· 
+Placed a total of 31 g ross horizontal wells on production from four distinct intervals ; 
+· 
+Increased the Credit Facility’s borrowing base to $250 million with a syndicate of 10 lending institutions ; 
+· 
+Retired the r em aining $48.5 million of the 13% Senior Notes, improving our cost of capital; and 
+· 
+Completed a common stock offering for $129.4 million in gross proceeds and e ntered into a new $300 million second lien term loan to partially fund the previously mentioned acquisition and planned capital expenditures. 
+Acquisition activity 
+In the first quarter of 2014, the Company acquired 1,527 net acres in Upton and Reagan Counties, Texas, which are located in the Southern Midland Basin near its existing core development fields, for an aggregate cash purchase price of $8.2 million. The properties bear a working interest of 100% and an average net revenue interest of 78% . 
+On October 8, 2014, the Company completed the acquisition of undeveloped acreage and producing oil and gas properties located in Midland, Andrews, Martin and Ector Counties, Texas. Including estimated purchase price adjustments, total net consideration paid for the a cquisition was approximately $210 million for an estimated 62% working interest ( 46.5% net revenue interest). 
+Key attributes of the acquired fields in the Central Midland Basin include: 
+· 
+6,230 gross ( 3,862 net) surface acres, 95% of which are located in Midland and Andrews Counties, in close proximity to the Company’s existing Carpe Diem and Pecan Acres fields in Midland County 
+· 
+194 gross ( 121.6 net) potential horizontal drilling locations targeting the Wolfcamp B, Lower Spraberry and Middle Spraberry zones which are currently producing in offsetting fields 
+· 
+255 gross ( 159.9 net) additional potential horizontal drilling locations targeting four other prospective zones including the Wolfcamp A, Wolfcamp D (Cline), Clearfork and Jo Mill 
+· 
+100% of targeted horizontal zones held by production 
+41 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+The Company assumed operatorship of the properties November 1, 2014 and currently owns an estimated 62.7% working interest after the recent purchase of additional working interests in October 2014. See Note 3 in the Footnotes to the Financial Statements for additional information regarding the acquisition. 
+Operational Highlights 
+Followi ng the sale of our remaining producing offshore and Haynesville properties in the fourth quarter of 2013, all of our producing properties are located in the Permian Basin. As a result of our acquisition and horizontal development efforts, our Permian production grew 154% in 2014 compared to 2013, increasing to 2,062 MBOE from 813 MBOE, respectively. Our production in 2014 was approximately 82% oil and 18% natural gas. 
+Net Production (MBOE) 
+Twelve Months Ended December 31, 
+2014 
+2013 
+Change 
+% Change 
+Permian 
+Southern Midland Basin 
+1,497 
+612 
+885 
+145% 
+Central Midland Basin 
+549 
+193 
+356 
+184% 
+Northern Midland Basin 
+16 
+8 
+8 
+100% 
+Total 
+2,062 
+813 
+1,249 
+154% 
+Offshore and other 
+Medusa 
+— 
+302 
+(302)
+(100)% 
+Haynesville shale 
+— 
+18 
+(18)
+(100)% 
+Gulf of Mexico shelf and other 
+— 
+280 
+(280)
+(100)% 
+Total 
+— 
+600 
+(600)
+(100)% 
+Total 
+2,062 
+1,413 
+649 
+46% 
+During 2014 we operated two horizontal rigs and one vertical rig . The following table summarizes the Company’s drilling activity in the Permian Basin for the year ended December 31, 2014 : 
+Drilled 
+Completed (a) 
+Awaiting Completion 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Southern Midland Basin 
+Vertical wells 
+1 
+1.0 
+1 
+1.0 
+— 
+— 
+Horizontal wells 
+22 
+20.1 
+22 
+20.1 
+3 
+3.0 
+Total 
+23 
+21.1 
+23 
+21.1 
+3 
+3.0 
+Central Midland Basin 
+Vertical wells 
+4 
+1.8 
+3 
+1.3 
+1 
+0.4 
+Horizontal wells 
+5 
+4.3 
+9 
+7.2 
+— 
+— 
+Total 
+9 
+6.1 
+12 
+8.5 
+1 
+0.4 
+Northern Midland Basin 
+Vertical wells 
+2 
+1.5 
+1 
+0.8 
+— 
+— 
+Total 
+2 
+1.5 
+1 
+0.8 
+— 
+— 
+Total vertical wells 
+7 
+4.3 
+5 
+3.1 
+1 
+0.4 
+Total horizontal wells 
+27 
+24.4 
+31 
+27.3 
+3 
+3.0 
+Total 
+34 
+28.7 
+36 
+30.4 
+4 
+3.4 
+(a) 
+Completions include wells drilled prior to 2014 . 
+Permian Reserve Growth 
+As of December 31, 2014 , our estimated proved reserves increased 121% to 32.8 MMBOE compared to 14.9 MMBOE of proved reserves at year-end 2013 . O ur significant growth in proved reserves was primarily attributable to our horizontal development and acquisiti on efforts . Our proved reserves at year-end 2014 were 78% oil and 22% natural gas, compared to 80% oil and 20% natural gas at year-end 2013 . 
+42 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Liquidity and Capital Resources 
+Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions, the sale of debt and equity securities and asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration and exploitation of oil and natural gas properties, in addition to r efinancing of debt instruments. 
+During the third and fourth quarters of 2014, we amended the borrowing base under our Credit Facility, entered into a second lien term loan and completed a common stock offering to support the funding of our Central Midland Basin acquisition completed in October 2014 and our ongoing operations and acquisition initiatives which are discussed in greater detail in Notes 5 , 10 and 14 in the Footnotes to the Financial Statements. In addition, we regularly evaluate other sources of capital to complement our cash flow from operations and other sources of capital as we pursue our long-term growth plans in the Permian Basin. 
+Based upon current commodity price expectations for 201 5 , we believe that our cash flow from operations and borrowings under our Credit Facility and S econd L ien L oan will be sufficient to fund our operations for 2015 , including any deficiencies in the Company’s current net working capital. However, future cash flows are subject to a number of variables, including forecast production volumes and commodity prices. Approximatel y 9 5 % o f our current 201 5 capital program is allocated to properties we operate and, as a result, the amount and timing of a substantial portion of our planned capital expenditures is largely discretionary in the event we determine it prudent to curtail drilling and completion operations due to capital constraints or reduced returns on investment in periods of commodity price weakness. 
+Cash and cash equivalents de creased $2.0 m illion in the year ended December 31, 2014 to $1.0 million compared to $3.0 million at December 31, 2013 . As of February 27, 2015 , our available liquidity was $172.0 million . 
+Liquidity and cash flow 
+For the Year Ended December 31, 
+2014 
+2013 
+2012 
+Net cash provided by operating activities 
+$ 
+94.4 
+$ 
+54.5 
+51.3 
+Net cash used in investing activities 
+(452.5)
+(79.8)
+(93.7)
+Net cash provided by (used in) financing activities 
+356.1 
+27.2 
+(0.3)
+Net change in cash 
+$ 
+(2.0)
+$ 
+1.9 
+$ 
+(42.7)
+Operating activities. For the year ended December 31, 2014 , net cash provided by operating acti vities was $94.4 million, compared to $54.5 million for the same period in 2013 . The increase was primarily due to an increase in oil sales and an increase in gains on the settlement of derivative contracts, partially offset by an increase in production taxes and lease operating expense. Production and realized prices are discussed below in Results of Operations. See Notes 6 and 7 in the Footnotes to the Financial Statements for a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation. 
+Investing activities . For the year ended December 31, 2014 , net cash used in investing activities was $452.5 million compared to $79.8 million for the same period in 2013 . Net cash used in investing activities during the year included $232.6 million in capital expenditures (not including acquisition costs) , an increase of $ 72.9 million over 2013, primarily attributable to our drilling and completion activities in the Permian Basin , driven by the addition of a second horizontal drilling rig in August 2013 . Net cash used in investing activities also included $222.9 million in acquisition costs , an increase of $212.0 million over 2013. Net cash provided by investing activities included proceeds of $3.0 million received fr om the sale of c ertain properties and equipment , a n $87.0 million decrease compared to the same period in 2013, when the Company received proceeds of $90.0 million from the sale of Medusa and our other offshore properties. See Note 3 in the Footnotes to the Financial Statements for additional information on acquisitions and dispositions. 
+43 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+2015 Capital Plan 
+In early February 201 5 , we announced an operational capital budget for 201 5 in the range of $150 to $165 million. This represents a reduction of approximately 25%-30% to the comparable 2014 budgeted amounts in response to a low er oil and natural gas price environment . 
+We expect our 2015 horizontal drilling program will be primarily focused on program development of established Upper and Lower Wolfcamp B zones and the Lower Spraberry zones in the Southern and Central Midland Basin with lateral lengths ranging from approximately 5,000’ to 10,000’. 
+In addition to the operational capital expenditures above, we budgeted approximatel y $17.2 million for capitalized general and administrative expenses and certain retained plugging and abandonment expenses related to divested Gulf of Mexico shelf assets. 
+We are the operator for approximately 95% of our 2015 capit al program and, as a result, the amount and timing of these capital expenditures are largely discretionary depending on commodity prices and other factors. We currently expect to fund our 2015 cap ital program through a combination of cash flow from operations and Credit Facility borrowings. 
+Financing activities. For the year ended December 31, 2014 , net cash provided by financing activities was $356.1 million compared to cash provided by financing activities of $27.2 million during the same period of 2013 . Net cash provided by financing activities during the year ended December 31, 2014 included $122.5 million of net proceeds from the issuance of common stock and a net $291.6 million of borrowings on our Credit Facility and Second Lien Loan, offset by a $50.1 million redemption of our Senior Notes. In addition, the Company paid approximately $ 7 .9 million in preferred stock dividends. See Notes 5 and 10 in the Footnotes to the Financial Statements for additional information about the Company’s debt and equity offering. 
+Senior secured revolving credit facility (“Credit Facility”) 
+On March 11, 2014, the Company entered into the Fifth Amended and Restated Credit Agreement to the Credit Facility with a maturity date of March 11, 2019. JPMorgan Chase Bank, N.A. is Administrative Agent, and participating lenders include Regions Bank, Citibank, N.A., Capital One, N.A., KeyBank, N.A., Whitney Bank, IberiaBank, N.A., OneWest Bank, N.A., SunTrust Bank and Royal Bank of Canada. The total notional amount available under the Credit Facility is $500 million. Amounts borrowed under the Credit Facility may not exceed the borrowing base, which is generally reviewed on a semi-annual basis. In conjunction with the closing of the Acquisition on October 8, 2014, the borrowing base on the Company’s Credit Facility was amended to $250 million. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. As of December 31, 2014 , the balance outstanding on the Credit Facility was $35.0 million with a weighted-average interest rate of 1.91% , calculated as the LIBOR plus a tiered rate ranging from 1.75% to 2.75% , which is determined based on utilization of the facility. In addition, the Credit Facility carries a commitment fee of 0.5% per annum, payable quarterly, on the unused portion of the borrowing base . 
+Term loans 
+On March 11, 2014, the Company entered into a secured term loan in an aggregate amount of up to $125 million, including initial commitments of $100 million and additional availability of $25 million subject to the consent of two-thirds of the lenders and compliance with financial covenants after giving effect to such increase. The term loan had a maturity date of September 11, 2019, and was no t subject to mandatory prepayments unless new debt or preferred stock we issued. It was prepayable at the Company’s option, subject to a prepayment premium. The prepayment amount was (i) 102% if the prepayment event occurs prior to March 11, 2015, and (ii) 101% if the prepayment event occurs on or after March 15, 2015 but before March 15, 2016, and (iii) 100% for prepayments made on or after March 15, 2016. The term loan was secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor agreement. On April 10, 2014, the Company drew an initial amount of $62.5 million with an original issue discount of 1.0% . 
+On October 8, 2014, the term loan described above was repaid in full using a new secured second lien term loan (the “ Second Lien Loan ”) in conjunction with the closing of the Central Midland Basin acquisition , resulting in a loss on ear ly extinguishment of debt of $3.1 million . The Second Lien Loan has a maturity date of October 8, 2021. On October 8, 2014, the Company drew an initial amount of $300 million with a discount of 2.0% and an interest rate of 8.5% , calculated at a rate of LIBOR (subject to a floor rate of 1.0% ) plus 7.5% per annum. The Second Lien Loan may be prepaid at the Company’s option, subject to a prepayment premium. The 
+44 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+prepayment amount is (i) 102% if the prepayment event occurs prior to October 8, 2015, and (ii) 101% if the prepayment event occurs on or after October 8, 2015 but before October 8, 2016, and (iii) 100% for prepayments made on or after October 8, 2016. The Second Lien Loan is secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor agreement. The Royal Bank of Canada is Administrative Agent, and participants include several institutional lenders. 
+13% Senior Notes due 2016 (the “Senior Notes”) and d eferred c redit 
+On April 11, 2014, the Company completed the full redemption of the remaining $48.5 million principal amount of outstanding Senior Notes using proceeds from the term loan issued on March 11, 2014 . The redemption resulted in a net $3.2 million gain on the early extinguishment of debt (including $4.8 million of accelerated deferred credit amortization). The gain represents the difference between the $50.1 million paid for the redemption of the Senior Notes ( $1.6 million of redemption costs, primarily the call premium) and the carrying value of the remaining Senior Notes of $53.3 million (inclusive of $4.8 million of deferred credit). The Company also paid $0.2 million in accrued interest through the redemption date. Upon the redemption, the indenture governing the Senior Notes was discharged in accordance with its terms. 
+Common Stock Offering 
+On September 15, 2014, the Company completed an equity offering for $129.4 million in gross proceeds. The offering consisted of 12,500,000 shares of the Company’s common stock at a price to the public of $9.00 per share, before underwriting discounts, and the exercise in full by the underwriters of their option to purchase 1,875,000 additional shares of common stock at $9.00 per share. See Note 10 in the Footnotes to the Financial Statements for additional information about the Company’s equity offerin g. 
+Contractual Obligations 
+The following table includes the Company’s current contractual obligations and purchase commitments : 
+Payments due by Period 
+Total 
+< 1 Year 
+Years 2 - 3 
+Years 4 - 5 
+>5 Years 
+Second Lien Loan 
+$ 
+300,000 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+300,000 
+Credit Facility 
+35,000 
+— 
+— 
+35,000 
+— 
+Drilling rig leases and related (a) 
+45,333 
+16,893 
+21,930 
+6,510 
+— 
+Office space lease and other commitments 
+3,130 
+637 
+1,219 
+855 
+419 
+Total 
+$ 
+383,463 
+$ 
+17,530 
+$ 
+23,149 
+$ 
+42,365 
+$ 
+300,419 
+(a) 
+The <1 Year column includes $3,733 related to the early termination provisions of one of the Company’s vertical drilling rigs (See Note 14 ), and the amount assumes the lessor is unable to re-charter the rig and staffing personnel to another lessee. Should the lessor re-charter the rig and its related personnel to a new lessee, the $3,733 would be reduced by the value of the new lessee’s rental payment s. 
+Income Taxes 
+The Company’s income tax expense varies from the statutory rate primarily due to the effect of state income taxes and non - deductible executive compensation expenses . For additiona l information, see the Income Tax discussion included below in Results of Operations and Note 11 to the Consolidated Financial Statements. 
+45 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Results of Operations 
+The following table sets forth certain operating information with respect to the Company’s oil and natural gas operat ions for the periods indicated: 
+For the Year Ended December 31, 
+2014 
+2013 
+Change 
+% Change 
+2012 
+Change 
+% Change 
+Net production: 
+Oil (MBbls) 
+1,692 
+911 
+781 
+86% 
+977 
+(66)
+(7)% 
+Natural gas (MMcf) 
+2,220 
+3,011 
+(791)
+(26)% 
+3,588 
+(577)
+(16)% 
+Total (MBOE) 
+2,062 
+1,413 
+649 
+46% 
+1,575 
+(162)
+(10)% 
+Average daily production (BOE/d) 
+5,648 
+3,871 
+1,777 
+46% 
+4,303 
+(432)
+(10)% 
+% oil (BOE basis) 
+82% 
+64% 
+62% 
+Average realized sales price: 
+Oil (Bbl) (excluding impact of cash settled derivatives) 
+$ 
+82.37 
+$ 
+97.65 
+$ 
+(15.28)
+(16)% 
+$ 
+97.41 
+$ 
+0.24 
+— 
+Oil (Bbl) (including impact of cash settled derivatives) 
+84.85 
+99.32 
+(14.46)
+(15)% 
+98.86 
+0.46 
+— 
+Natural gas (Mcf) (excluding impact of cash settled derivatives) 
+$ 
+5.63 
+$ 
+4.52 
+$ 
+1.11 
+24% 
+$ 
+3.94 
+$ 
+0.58 
+15% 
+Natural gas (Mcf) (including impact of cash settled derivatives) 
+5.59 
+4.47 
+1.12 
+25% 
+3.94 
+0.53 
+13% 
+Total (BOE) (excluding impact of cash settled derivatives) 
+$ 
+73.65 
+$ 
+72.59 
+$ 
+1.06 
+1% 
+$ 
+69.43 
+$ 
+3.16 
+5% 
+Total (BOE) (including impact of cash settled derivatives) 
+75.64 
+73.56 
+2.08 
+3% 
+70.41 
+3.15 
+4% 
+Oil and natural gas revenues (in thousands): 
+Oil revenue 
+$ 
+139,374 
+$ 
+88,960 
+$ 
+50,414 
+57% 
+$ 
+96,584 
+$ 
+(7,624)
+(8)% 
+Natural gas revenue 
+12,488 
+13,609 
+(1,121)
+(8)% 
+14,149 
+(540)
+(4)% 
+Total 
+$ 
+151,862 
+$ 
+102,569 
+$ 
+49,293 
+48% 
+$ 
+110,733 
+$ 
+(8,164)
+(7)% 
+Additional per BOE data: 
+Sales price 
+$ 
+73.65 
+$ 
+72.59 
+$ 
+1.06 
+1% 
+$ 
+69.43 
+$ 
+3.16 
+5% 
+Lease operating expense 
+10.85 
+14.00 
+(3.15)
+(23)% 
+14.81 
+(0.81)
+(5)% 
+Production taxes 
+4.35 
+2.92 
+1.43 
+49% 
+2.05 
+0.87 
+42% 
+Operating margin 
+$ 
+58.45 
+$ 
+55.67 
+$ 
+2.78 
+5% 
+$ 
+52.57 
+$ 
+3.10 
+6% 
+Revenues 
+The following tables are intended to reconcile the change in oil, natural gas and total revenue for the respective periods presented by reflecting the effect of changes in volume and in the underlying commodity prices , as well as the impact of our hedge program for the year ended December 31, 2012 when we had designated our derivative contracts as accounting hedges. 
+(in thousands) 
+Oil 
+Natural Gas 
+Total 
+Revenues for the year ended December 31, 2011 
+$ 
+100,962 
+$ 
+26,682 
+$ 
+127,644 
+Volume increase (decrease) 
+(1,926)
+(7,840)
+(9,766)
+Price increase (decrease) 
+(3,872)
+(4,693)
+(8,565)
+Impact of hedges 
+1,420 
+— 
+1,420 
+Net increase (decrease) in 2012 
+(4,378)
+(12,533)
+(16,911)
+Revenues for the year ended December 31, 2012 
+$ 
+96,584 
+14,149 
+110,733 
+Volume increase (decrease) 
+(6,528)
+(2,278)
+(8,806)
+Price increase (decrease) 
+(1,096)
+1,738 
+642 
+Net increase (decrease) in 2013 
+(7,624)
+(540)
+(8,164)
+Revenues for the year ended December 31, 2013 
+$ 
+88,960 
+$ 
+13,609 
+$ 
+102,569 
+Volume increase (decrease) 
+76,237 
+(3,575)
+72,662 
+Price increase (decrease) 
+(25,823)
+2,454 
+(23,369)
+Net increase (decrease) in 2014 
+50,414 
+(1,121)
+49,293 
+Revenues for the year ended December 31, 2014 
+$ 
+139,374 
+$ 
+12,488 
+$ 
+151,862 
+46 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Oil revenue 
+For the year ended December 31, 2014 , oil revenues of $139.4 million increased $ 50.4 million, or 57% , compared to revenues of $89.0 million for the same period of 2013. The increase primarily related to an 86% increase in total production, while the average realized sales price decreased 16% . The increase in production was wholly attributable to a 1,048 MBbls increase in Permian production resulting from an increased number of producing wells from acquisitions and our horizontal drilling program offset by normal and expected declines from our existing wells. Partially offsetting the Permian increase was a 267 MBbls decline in production due to the sale of our deepwater Medusa field in the fourth quarter of 2013. 
+For the year ended December 31, 2013 , oil revenues of $89.0 million decreased $7.6 million, or 8% , compared to revenues of $96.6 million for the same period of 2012 . Lower production from our offshore properties, primarily related to the sale of Habanero field in December 2012 and our Medusa and shelf properties in the fourth quarter of 2013, drove the revenue decline. Also contributing to the production decline were 20 days of down time for scheduled downstream pipeline maintenance at our Medusa field in the second quarter of 2013, approximately five days of production downtime at our key producing Permian Basin fields in the fourth quarter of 2013 due to severe winter weather causing electricity outages and the extended curtailment of trucking capacity to transport offtake and due to normal and expected declines from other producing wells. Collectively, these declines were offset by the 222 MBbls increase in our oil production from our Permian properties. 
+Natural gas revenue (including NGLs) 
+Natural gas revenues of $12.5 million de creased $1.1 million, or 8% , during the year ended December 31, 2014 compared to $13.6 million for the same period of 2013 . The average realized price increased to $5.63 per Mcf from $4.52 per Mcf, or 24% , while total production decreased 26% . The decrease in production was primarily attributable to a 1,919 MMcf decrease in production due to the sale of our offshore fields and Haynesville property in the fourth quarter of 2013. Offsetting the production decline was a 1,128 MMcf increase in production from our Permian properties resulting from an increased number of producing wells as mentioned above. 
+Natural gas revenues of $13.6 million decreased $0.5 million, or 4% , during the year ended December 31, 2013 compared to $14.1 million for the same period of 2012 . While the average realized price increased 15%, a 16% decrease in production reduced total revenue. The production declin es were primarily attributable to the shut-in of production of our Mobile Bay 908 property, the sale of our offshore fields, the sale of our Haynesville property in the fourth quarter of 2013 as well as normal and expected declines from our existing wells. Offsetting these declines was a 248 MMcf increase in horizontal well production from our Permian properties . 
+47 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Operating E xpenses 
+For the Year Ended December 31, 
+Per 
+Per 
+Total Change 
+BOE Change 
+2014 
+BOE 
+2013 
+BOE 
+$ 
+% 
+$ 
+% 
+Lease operating expenses 
+$ 
+22,372 
+$ 
+10.85 
+$ 
+19,779 
+$ 
+14.00 
+2,593 
+13% 
+(3.15)
+(22)% 
+Production taxes 
+8,973 
+4.35 
+4,133 
+2.92 
+4,840 
+117% 
+1.43 
+49% 
+Depreciation, depletion and amortization 
+56,724 
+27.51 
+43,967 
+31.12 
+12,757 
+29% 
+(3.61)
+(12)% 
+General and administrative 
+25,109 
+12.18 
+20,534 
+14.53 
+4,575 
+22% 
+(2.35)
+(16)% 
+Accretion expense 
+826 
+0.40 
+1,785 
+1.26 
+(959)
+(54)% 
+(0.86)
+(68)% 
+Gain on sale of other property and equipment 
+(1,080)
+(0.52)
+— 
+— 
+(1,080)
+— 
+(0.52)
+— 
+Impairment of other property and equipment 
+— 
+— 
+1,707 
+1.21 
+(1,707)
+(100)% 
+(1.21)
+(100)% 
+Acquisition expense 
+668 
+0.32 
+— 
+— 
+668 
+— 
+0.32 
+— 
+For the Year Ended December 31, 
+Per 
+Per 
+Total Change 
+BOE Change 
+2013 
+BOE 
+2012 
+BOE 
+$ 
+% 
+$ 
+% 
+Lease operating expenses 
+$ 
+19,779 
+$ 
+14.00 
+$ 
+23,330 
+$ 
+14.81 
+(3,551)
+(15)% 
+(0.81)
+(5)% 
+Production taxes 
+4,133 
+2.92 
+3,224 
+2.05 
+909 
+28% 
+0.87 
+42% 
+Depreciation, depletion and amortization 
+43,967 
+31.12 
+49,701 
+31.56 
+(5,734)
+(12)% 
+(0.44)
+(1)% 
+General and administrative 
+20,534 
+14.53 
+20,358 
+12.93 
+176 
+1% 
+1.60 
+12% 
+Accretion expense 
+1,785 
+1.26 
+2,253 
+1.43 
+(468)
+(21)% 
+(0.17)
+(12)% 
+Impairment of other property and equipment 
+1,707 
+1.21 
+1,177 
+0.75 
+530 
+45% 
+0.46 
+61% 
+Lease operating expenses (“LOE”) . These are daily costs incurred to extract oil and natural gas out of the ground and deliver to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and workover expenses related to our oil and natural gas properties. 
+LOE for the year ended December 31, 2014 increased by 13% to $22.4 million compared to $19.8 million for the same period of 2013 primarily due to $9.7 million in costs related to the growth in Permian production and operations, including an increase in workover expenses associated with the impact of accelerated horizontal well activity on surrounding producing wells. These increases were partiall y offset by a decrease in costs of $7.1 million resulting from the sale of our deep water Medusa field and our other offshore fields. LOE per BOE for the year ended December 31, 2014 decreased by 22% to $10.85 per BOE from $14.00 per BOE for the same period of 2013. The 22% decrease is primarily attributable to a 46% increase in production while keeping expenses in line. 
+LOE for the year ended December 31, 2013 d ecreased by 15% to $19.8 million compared to $23.3 million for the same period of 2012 . The decrease was primarily due to $3.4 millio n of remediation costs on our Haynesvill e property i n 2012, for which we had no similar costs in 2013, and an estimated decrease of $3.2 million of LOE resulting from the sale of our interests in Habanero, Medusa, the Medusa Spar facilities , our Haynesville property and substantially all our remaining shelf properties. These decreases were partially offset by $3.0 million in LOE costs related to the growth in Permian production and operations, including an increase in workover expenses associated with accelerated horizontal well activity. 
+Production taxes. Production taxes include severance and ad valorem taxes. Severance taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and gas properties. 
+For the year ended December 31, 2014 , production taxes incr eased 117% , or $4.9 million, to $9.0 million compared to $4.1 million for the same period of 2013 . The increase was predominantly attributable to an increase in onshore production subject to these taxes accompanied by a decline in offshore production, resulting from the sale of our Gulf of Mexico position in 2013, which was exempt from production taxes. 
+For the year ended December 31, 2013 production taxes of $4.1 million increased 28%, or $0.9 million, compared to $3.2 million for the same period of 2012. The increase was predominantly attributable to the previously mentioned increase in onshore production 
+48 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+subject to these taxes and a decline in offshore production, resulting from the sale of our Gulf of Mexico position in 2013, which is exempt from production taxes. 
+Depreciation, dep letion and amortization (“DD&A”). Under the full cost accounting method, we capitalize costs within a cost center and then systematically expense those costs on a units-of-production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unevaluated properties, less accumulated amortization; (ii) the estimated future expenditures to be incurred in developing proved reserves; and (iii) the estimated dismantlement and abandonment costs, net of estimated salvage values. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years. 
+For the year ended December 31, 2014, DD&A increased 29% from $44.0 million compared to $56.7 million for the same period of 2013. The increase is primarily attributable to a 46% increase in production, offset by a 12% decrease in our per BOE DD&A rate. For the year ended December 31, 2014, DD&A on a per unit basis decreased to $27.51 per BOE compared to $31.12 per BOE for the same period of 2013 as a result of our increase in our estimated proved reserves relative to our depreciable base as a result of our efforts on development, exploration, and exploitation of onshore oil and natural gas reserves in the Permian Basin. 
+For the year ended December 31, 2013, DD&A of $31.12 per BOE remained relatively flat compared to $31.56 per BOE for the same period of 2012. 
+General and administrative, net of amounts capitalized (“G&A”) . These are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, depreciation of corporate level asset s, public company costs, vesting of equity and liability awards under share-based compensation plans and related mark-to-market valuation adjustments over time, fees for audit and other professional services and legal compliance. 
+G&A for the year ended December 31, 2014 increased to $ 25.1 million (including $3.1 million in fair value adjustment of cash-settled RSU awards ) compared to $20.5 million (including $2.9 million in fair v alue adjustment of cash-settled RSU awards ) for the same period of 2013 . The increase was primarily related to the following items: 
+· 
+$1.4 million in non-recurring, cash expense s related to a threatened proxy contest incurred in 2014 
+· 
+$2.5 million in non-recurring expenses (both cash and non-cash components) primarily related to the accelerated vesting of outstanding equity awards for early retirement of employees 
+· 
+an increase of $0.2 million related to the fair value adjustment of cash-settled RSU awards 
+G&A for the year end ed December 31, 2013 rema ined relatively flat at $20.5 million (including $ 2.9 million in fair value adjustment of cash-settled RSU awards ) compared to $20.4 million (including $ 1.6 million in fair value adjustment of cash-settled RSU awards ) for the same period of 2012 . The $0.1 million increase was related to the following items: 
+· 
+an increase of $1. 3 million related to the fair value adjustment of cash-settled RSU awards 
+· 
+a decrease of $1.6 million pri marily related to non-recurring employee-related expenses including early retirement and severance expense incurred in 2012 
+Accretion expense . The Company is required to record the estimated fair value of liabilities for obligations associated with the retirement of tangible long -lived assets and the associated asset retirement costs. Interest is accreted on the present value of the asset retirement obligations (“ARO”) and reported as accretion expense within operating expenses in the consolidated statements of operations. 
+Accretion expense related to our ARO decreas ed 54% for the year ended December 31, 2014 compared to the same period of 2013 . The decrease in a ccretion expense correlates with the Company’s average ARO , which was $6.5 million during 2014 versus $11.5 million during 2013. The reduction in our average ARO was primarily a result of the divestiture of our offshore fields in the fourth quarter of 2013. See Note 12 in the Footnotes to the Financial Statements for additional information regarding the Company’s ARO. 
+49 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Accretion expense related to our asset retirement obligation decreased 21% for the year ended December 31, 2013 compared to the same periods of 2012 . Accretion expense generally correlates directionally with the Co mpany’s ARO which was $6.7 million at December 31, 2013 versus $13.3 million at December 31, 2012 . 
+Acquisition expense 
+Acquisition expense of $0.7 million for the year ended December 31, 2014 relates to acquisition related costs with respect to our acquisition efforts in the Permian Basin. See Note 3 in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions. 
+Gain on sale of other property and equipment 
+See Note 14 in the Footnotes to the Financial Statements for a discussion of the gain on the sale of specialized deep water property and equipment. 
+Impairment of o ther p roperty and e quipment 
+See Note 14 in the Footnotes to the Financial Statements for a discussion regarding the recognition of the impairment on specialized deep water property and equipment. 
+50 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Other Income and Expenses and Preferred Stock Dividends 
+Interest expense. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our credit facility or with term debt. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to our lender in interest expense , net of capitalized amounts . In addition, we include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees in interest expense. The amortization of the deferred credit related to our 13% Senior Notes wa s recorded as an offset to interest expense. 
+Gain/Loss on derivative instruments. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the price of oil and natural gas . This amount represents the (i) gain (loss) related to fair value adjustments on our open derivative contracts and (ii) gains (losses) on settlements of derivative contracts for positions that have settled within the period. We provide a reconciliation of these components of the gain/loss on derivative contracts in Note 5. 
+Income tax expense. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. When appropriate based on our analysis, we record a valuation allowance for deferred tax assets when it is more likely than not that the deferred tax assets will not be realized. 
+For the Year Ended December 31, 
+2014 
+2013 
+$ Change 
+% Change 
+Interest expense 
+$ 
+9,772 
+$ 
+6,094 
+$ 
+3,678 
+60% 
+Gain on early extinguishment of debt 
+(151)
+(3,696)
+3,545 
+(96)% 
+(Gain) loss on derivative contracts 
+(31,736)
+1,360 
+(33,096)
+(2,434)% 
+Other income, net 
+(515)
+(485)
+(30)
+6% 
+Total 
+$ 
+(22,630)
+$ 
+3,273 
+Income tax expense 
+$ 
+23,134 
+$ 
+3,104 
+$ 
+20,030 
+645% 
+Equity in earnings of Medusa Spar LLC 
+— 
+17 
+(17)
+(100)% 
+Preferred stock dividends 
+(7,895)
+(4,627)
+(3,268)
+71% 
+For the Year Ended December 31, 
+2013 
+2012 
+$ Change 
+% Change 
+Interest expense 
+$ 
+6,094 
+$ 
+9,108 
+(3,014)
+(33)% 
+Gain on early extinguishment of debt 
+(3,696)
+(1,366)
+(2,330)
+171% 
+Loss (gain) on derivative contracts 
+1,360 
+(1,717)
+3,077 
+(179)% 
+Other income, net 
+(485)
+(79)
+(406)
+514% 
+Total 
+$ 
+3,273 
+- 
+$ 
+5,946 
+- 
+- 
+Income tax expense 
+$ 
+3,104 
+$ 
+2,223 
+$ 
+881 
+(40)% 
+Equity in earnings of Medusa Spar LLC 
+17 
+226 
+(209)
+(92)% 
+Preferred stock dividends 
+(4,627)
+— 
+(4,627)
+— 
+Interest expense 
+Interest expense incurred during the year ended December 31, 2014 in creased $3.7 m illion to $9.8 million compared to $6.1 million for the same period of 2013 . The increase is primarily attributable to the $11.4 million increase in expense related to additional draws on our Credit Facility and term loans in 2014 compared to the corresponding period of the prior year . Offsetting the increase is a $ 7.9 million decrease in interest expense related to our Senior Notes following a $48.5 million partial redemption during the fourth quarter of 2013 and a full redemption of the remaining outstanding principal in April 2014. Also offsetting the increase was a $0.2 million increase in capitalized interest , resulting from a higher average unevaluated property balance period over period . 
+51 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Interest expense incurred during the year ended December 31, 2013 de creased $3.0 million to $6.1 million compared to $9.1 million for the same period of 2012. The decrease was related primarily to an additional $2.3 million of interest capitalized in 2013 versus 2012, approximately $0.3 million of reduced interest payments attributable to the redemption of $48.5 million principal of the Company’s Senior Notes in December 2013 and $0.1 million of additional deferred credit amortization recognized in 2013 compared with 2012. The additional capitalized interest was related to a higher balance year-over-year in average unevaluated oil and natural gas properties following the purchase of additional unevaluated acreage and exploration costs incurred in the Permian Basin. 
+(Gain) loss on early extinguishment of debt 
+During April 2014, the Company completed a full redemption of the remaining $53.3 million carrying value of its outstanding Senior Notes using proceeds from the issuance of a secured second lien term loan . The carrying value included $48.5 million of principal value and $4.8 million of unamortized deferred credit. The Company recognized a net $3.2 million gain on early extinguishment of debt, comprised of the recognition of $4.8 million in deferred credit, offset by $1.6 million of redemption expenses. See Note 5 for additional information concerning the gain on early extinguishment of debt. 
+During October 2014, the Company repaid in full the existing term loan using proceeds from the Second Lien Loan resulting in a loss on early extinguishment of debt of $3.1 million. The loss was comprised of a $1.7 million prepayment premium and the recognition of $1.4 million of unamortized issuance cost s . See Note 5 for additional information concerning the loss on the early extinguishment of debt. 
+During December 2013, the Company redeemed $53.8 million carrying value of its Senior Notes using a portion of the proceeds from the Company’s May 2013 preferred equity offering. The $53.8 million of carrying value included $48.5 million of principal value and $5.3 million of unamortized deferred credit. The Company recognized a net gain of $3.7 million on the early extinguishment of debt, comprised of the recognition of $5.3 million in deferred credit, offset by $1.6 million of redemption expenses. 
+Loss (gain) on derivative contracts 
+For the year ended December 31, 2014 , the net gain on derivative instruments was $31.7 million, compared to a $1.4 million net loss in 2013 . Se e Notes 6 and 7 in the Footnotes to the Financial Statements for a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation. 
+For the year ended December 31, 2013 , the net loss on derivative instruments was $1.4 million, compared to a $1.7 millio n net gain in 2012 . 
+Income tax expense 
+The effective tax rate of 38% in 2014 and 42% in 2013 differed from the federal income tax rate of 35% primarily due t o the effect of state taxes, non-deductible executive compensation expenses and percentage depletion. For additional information, see Note 11 to the Consolidated Financial Statements. 
+Preferred stock dividends 
+Preferred s tock dividends for the year ended December 31, 2014 i ncreased $3.3 million compared to the same period of 2013 . We issued the Preferred Stock on May 30, 2013. Accordingly, the year ended December 31 , 2014 reflects dividends for the entire year compared to a partial year in 2013. Dividends reflect a 10% dividend rate and $79 million liquidation value. See Note 10 in the Footnotes to the Financial Statements for additional information. 
+52 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Summary of Significant Accounting Policies and Critical Accounting Estimates 
+The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been use d . Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under GAAP. We also describe the most significant estimates and assumptions we make in applying these policies. See Note 2 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K for a discussion of additional accounting policies and estimates made by management. 
+Oil and natural gas p ropert ies 
+The Company utilizes the full cost method of accounting for its oil and natural gas properties whereby all costs incurred in connection with the acquisition, exploration and development of oil and natural gas reserves, including certain overhead costs, are capitalized into the “full cost pool.” The amounts capitalized into the full cost pool are depleted (charged against earnings) using the unit-of-production method. The full cost method of accounting for oil and natural gas properties requires that the Company makes estimates based on its assumptions of future events that could change. These estimates are described below. 
+Depreciation, depletion and amortization (DD&A) of oil and natural gas properties 
+The Company calculates DD&A by using the depletable base, which is equal to the net capitalized costs in our full cost pool plus estimated future development costs, and the estimated net proved reserve quantities. Capitalized costs added to the full cost pool include the following: 
+· 
+costs of drilling and equipping productive wells, dry hole costs, acquisition costs of properties with proved reserves, delay rentals and other costs related to exploration and development of our oil and natural gas properties; 
+· 
+payroll costs including the related fringe benefits paid to employees directly engaged in the acquisition, exploration and/or development of oil and natural gas properties as well as other directly identifiable general and administrative costs associated with such activities. Such capitalized costs do not include any costs related to the production of oil and natural gas or general corporate overhead; 
+· 
+costs associated with unevaluated properties, those lacking proved reserves, are excluded from the depletable base. These unevaluated property costs are added to the depletable base at such time as wells are completed on the properties or management determines these costs have been impaired. The Company’s determination that a property has or has not been impaired (which is discussed below) requires assumptions about future events; 
+· 
+estimated costs to dismantle, abandon and restore properties that are capitalized to the full cost pool when the related liabilities are incurred (see also the discussion below regarding Asset Retirement Obligations); 
+· 
+estimated future costs to develop proved properties are added to the full cost pool for purposes of the DD&A computation. The Company uses assumptions based on the latest geologic, engineering, regulatory and cost data available to it to estimate these amounts. However, the estimates made are subjective and may change over time. The Company’s estimates of future development costs are reviewed at least annually and as additional information becomes available; and 
+· 
+capitalized costs included in the full cost pool plus estimated future development costs are depleted and charged against earnings using the unit-of-production method. Under this method, the Company estimates the proved reserves quantities at the beginning of each accounting period. For each BOE produced during the period, the Company records a DD&A charge equal to the amount included in the depletable base (net of accumulated depreciation, depletion and amortization) divided by our estimated net proved reserve quantities. 
+53 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Because the Company uses estimates and assumptions to determine proved reserves (as discussed below) and the amounts included in the depletable base, our depletion rates may materially change if actual results differ from these estimates. 
+Ceiling t est 
+Under the full cost method of accounting, the Company compares, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (excluding cash flows related to estimated abandonment costs), to the net capitalized costs of proved oil and natural gas properties net of related deferred taxes. The Company refers to this comparison as a “ceiling test.” If the net capitalized costs of proved oil and natural gas properties exceed the estimated discounted (at a 10% annualized rate ) future net cash flows from proved reserves, t he Company is required to write- down the value of its oil and natural gas properties to the value of the discounted cash flows. Estimated future net cash flows from proved reserves are based on a twelve-month average pricing assumption. Given the volatility of oil and natural gas prices, it is reasonably possible that the Company’s estimates of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. If oil and natural gas prices remain at current levels or decline further , even if only for a short period of time, write- downs of oil and natural gas properties could occur in the future. See Note 13 for additional information regarding the Company’s oil and natural gas properties. 
+Estimating reserves and present value of estimated future net cash flows 
+Estimates of quantities of proved oil and natural gas reserves, including the discounted present value of estimated future net cash flows from such reserves at the end of each quarter, are based on numerous assumptions, which are likely to change over time. These assumptions include: 
+· 
+the prices at which the Company can sell its oil and natural gas production in the future. Oil and natural gas prices are volatile, but we are required to assume that they remain constant, using the twelve-month average pricing assumption. In general, higher oil and natural gas prices will increase quantities of proved reserves and the present value of estimated future net cash flows from such reserves, while lower prices will decrease these amounts; and 
+· 
+the costs to develop and produce the Company’s reserves and the costs to dismantle its production facilities when reserves are depleted. These costs are likely to change over time, but we are required to assume that they remain constant. Increases in costs will reduce estimated oil and natural gas quantities and the present value of estimated future net cash flows, while decreases in costs will increase such amounts. 
+Changes in these prices and/or costs will affect the present value of estimated future net cash flows more than the estimated quantities of oil and natural gas reserves for the Company’s properties that have relatively short productive lives. If oil and natural gas prices remain at current levels or decline further, it will have a negative impact on the present value of estimated future net cash flows and the estimated quantities of oil and natural gas reserves. 
+In addition, the process of estimating proved oil and natural gas reserves requires that the Company’s independent and internal reserve engineers exercise judgment based on available geological, geophysical and technical information. We have described the risks associated with reserve estimation and the volatility of oil and natural gas prices under “Risk Factors.” 
+Sales of oil and natural gas properties are accounted for as adjustments to the net full cost pool with no gain or loss recognized unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves. 
+Unproved p roperties 
+Costs, including capitalized interest, associated with properties that do not have proved reserves are excluded from the depletable base, and are included in the line item “Unevaluated properties. ” Un evaluat ed property costs are transferred to the depletable base when wells are completed on the pro perties or management determi nes that these costs have been impaired . In addition, the Company is required to determine whether its un evaluat ed properties are impaired and, if so, include the costs of such properties in the depletable base. The Company determines whether an un evaluat ed property is impaired by periodically reviewing its exploration program on a property-by-property basis. This determination may require the exercise of substantial judgment by management. 
+54 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Asset r etirement o bligations 
+We are required to record our estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-life assets and the associated asset retirement costs. Interest is accreted on the present value of the asset retirement obligation s and reported as accretion expense within operating expenses in the Consolidated Statements of Operations. See Note 12 for additional information. 
+Derivatives 
+To manage oil and natural gas price risk on a portion of our planned future production, we have historically utilized commodity derivative instruments (including collars, swaps, puts, and other structures) on approximately 50% to 75 % of our projected production volumes in any given year. We do not use these instruments for trading purposes. Settlement of derivative contracts are generally based on the difference between the contract price and prices specified in the derivative instrument and a NYMEX price or other cash or futures index price. 
+W e elected to no longer designate derivative contracts executed after January 1, 2012 as accounting hedges and a s such our derivative positions are carried at their fair value on the balance sheet with changes in fair value recorded through earnings . 
+Derivative contracts that were entered into at and prior to December 31, 2011 were accounted for as cash flow hedges, and were recorded at fair value on our consolidated balance sheet. Changes in fair value were recorded through other comprehensive income (loss), net of tax, in stockholders’ equity. The changes in fair value related to ineffective derivative contracts were recognized as derivative expense (income). The estimated fair value of our derivative contracts is based upon closing exchange prices on NYMEX and in the case of collars and floors, the time value of options. For additional information regarding derivatives and their fair values, see Notes 6 and 7 to the Consolidated Financial Statements and Part II, Item 7A Commodity Price Risk. 
+Income t axes 
+The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices). See Note 11 for additional information regarding Income Taxes. 
+Recent Accounting Standards 
+In May 2014, the F ASB issued accounting standards update (“ASU”) No. 2014-09, Revenue from Contracts with Customers. The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU No. 2014-09 will replace most of the existing revenue recognition requirements in GAAP when it becomes effective. The guidance in ASU No. 2014-09 is effective for public entities for annual reporting periods beginning after December 15, 2016, including interim periods therein. Early adoption is not permitted. The Company is currently evaluating the method of adoption and impact this standard will have on its financial statements and related disclosures . 
+55 
+Table of Contents 
+Item 7A. Quan titative and Qualitative Disclosures about Market Risk 
+We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative instruments. 
+Commodity price risk 
+The Company’s revenues are derived from the sale of its oil and natural gas production. The prices for oil and natural gas remain extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and government actions. From time to time, the Company enters into derivative financial instruments to manage oil and natural gas price risk. The total volumes which we hedge through the use of our derivative instruments varies from period to period; however, generally our objective is to hedge approximately 50% to 75% of our anticipated internally forecast production for the next 12 to 24 months, subject to the covenants under our Credit Facility. Our hedge policies and objectives may change significantly with movements in commodities prices or futures prices, in addition to modification of our capital spending plans related to operational activities and acquisitions. 
+As of February 27, 2015 , we had commodity contracts covering approximately 6 3 % and 6 2 % of our expected oil and natural gas production for calendar year 2015 , respectively, based on the midpoint of publicly disclosed guidance as of March 4, 2015 and including the impact of derivative contracts established after December 31, 2014 . Our short call options related to natural gas have been integrated with swaps for purposes of this calculation. Our actual production will vary from the amounts estimated, perhaps materially. See Note 6 in the Footnotes to the Financial Statements for a description of the Company’s outstanding derivative contracts at December 31, 2014 and derivative contracts established subsequent to that date. 
+The Company may utilize fixed price swaps, which reduce the Company’s exposure to decreases in commodity prices and limit the benefit the Company might otherwise have received from any increases in commodity prices. Swap contracts may also be enhanced by the simultaneous sale of call or put options to effectively increase the effective swap price as a result of the receipt of premiums from the option sales. Additionally, the Company may sell put options or call options in conjunction with a swap and use the proceeds to increase the fixed price received. 
+The Company may utilize price collars to reduce the risk of changes in oil and natural gas prices. Under these arrangements, no payments are due by either party as long as the applicable market price is above the floor price (purchased put option) and below the ceiling price (sold call option) set in the collar. If the price falls below the floor, the counter-party to the collar pays the difference to the Company, and if the price rises above the ceiling, the counterparty receives the difference from the Company. Additionally, the Company may sell put options at a price lower than the floor price in conjunction with a collar (three-way collar) and use the proceeds to increase either or both the floor or ceiling prices. 
+The Company may purchase put options, which reduce the Company’s exposure to decreases in oil and natural gas prices while allowing realization of the full benefit from any increases in oil and natural gas prices. If the price falls below the floor, the counterparty pays the difference to the Company. 
+The Company enters into these various agreements from time to time to reduce the effects of volatile oil and natural gas prices and does not enter into derivative transactions for speculative purposes. Presently, none of the Company’s derivative positions are designated as hedges for accounting purposes. 
+Interest rate risk 
+On December 31, 2014 , the Company’s debt consisted of $300.0 million related to its Second Lien Facility and $35.0 million related to its Credit Facility. The Company is subject to market risk exposure related to changes in interest rates on our indebtedness under the Second Lien Loan and Credit Facility. As of December 31, 2014 , the weighted average interest rate on our Credit Facility borrowings was 1.91% and the interest rate on our Second Lien Loan borrowings was 8.50% . An increase or decrease of 1% in the interest rate would have a corresponding increase or decrease in our annual net income of approximately $3.4 million based on the $335.0 million outstanding in the aggregate under the two facilities on December 31, 2014 . The Company is also subject to market risk exposure going forward related to changes in interest rate for the Second Lien Loan and Credit Facility . See Note 5 to the Consolidated Financial Statements for more information on the Company’s interest rates on debt. 
+56 
+Table of Contents 
+Counte rparty and customer credit risk 
+The Company’s principal exposures to credit risk are through receivables from the sale of our oil and natural gas production, joint interest receivables and receivables resulting from derivative financial contracts. 
+The Company markets receivables from the sale of our oil and natural gas production to energy marketing companies. We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. For the year ended December 31, 2014, three purchasers accounted for more than 10% of our revenue: Enterprise Crude Oil, LLC ( 51 % ) ; Plains Marketing, L.P. ( 22 % ); and Sunoco ( 1 0 % ). We do not require any of our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. At December 31, 2014 our total receivables from the sale of our oil and natural gas production were approximately $18.9 million. 
+Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have or intend to drill. We have little ability to control whether these entities will participate in our wells. At December 31, 2014 our joint interest receivables were approximately $6.9 million. 
+At December 31, 201 4 our receivables resulting from derivative c ontracts w ere approximately $4.1 million. Our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. The counterparties on our derivative instruments currently in place are lenders under our revolving credit facility. We are likely to enter into additional derivative instruments with these or other lenders under our revolving credit facility, representing institutions with an investment grade ratings. We have existing International Swap Dealers Association Master Agreements (“ISDA Agreements”) with our derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of offset upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may offset all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaul ting party. At December 31, 2014 we had a net derivative asset position of $27.9 million and a net derivative liab ility position of $1.3 million. 
+57 
+Table of Contents 
+ITEM 8. Finan cial Statements and Supplementary Data 
+Page 
+Report of Independent Registered Public Accounting Firm 
+59 
+Consolidated Balance Sheets as of December 31, 2014 and 2013 
+60 
+Consolidated Statements of Operations for Each of the Three Years in the Period Ended December 31, 3014 
+61 
+Consolidated Statements of Comprehensive Income (Loss) for the Three Years in the Period Ended December 31, 2014 
+62 
+Consolidated Statements of Stockholders’ Equity (Deficit) for Each of the Three Years in the Period Ended December 31, 2014 
+63 
+Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2014 
+64 
+Notes to Consolidated Financial Statements 
+65 
+58 
+Table of Contents 
+Report of Indepe ndent Registered Public Accounting Firm 
+The Board of Directors and Stockholders of 
+Callon Petroleum Company 
+We have audited the accompanying consolidated balance sheets of Callon Petroleum Company as of December 31, 2014 and 2013 , and the related consolidated statements of operations, comprehensive income, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2014 . These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. 
+We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. 
+In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Callon Petroleum Company as of December 31, 2014 and 2013 , and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2014 , in conformity with U.S. generally accepted accounting principles. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Callon Petroleum Company’s internal control over financial reporting as of December 31, 2014 , based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ( 2013 framework) and our report dated March 4, 2015 , expressed an unqualified opinion thereon. 
+/s/Ernst & Young LLP 
+New Orleans, Louisiana 
+March 4, 2015 
+59 
+Table of Contents 
+Part I. Financial Information 
+Item I. Financial Statements 
+Callon Petroleum Company 
+Consolidated Bal ance Sheets 
+(in thousands, except par and per share values and share data) 
+December 31, 2014 
+December 31, 2013 
+ASSETS 
+Current assets: 
+Cash and cash equivalents 
+$ 
+968 
+$ 
+3,012 
+Accounts receivable 
+30,198 
+20,586 
+Deferred tax asset 
+— 
+3,843 
+Fair value of derivatives 
+27,850 
+60 
+Other current assets 
+1,441 
+2,063 
+Total current assets 
+60,457 
+29,564 
+Oil and natural gas properties, full cost accounting method: 
+Evaluated properties 
+2,077,985 
+1,701,577 
+Less accumulated depreciation, depletion and amortization 
+(1,478,355)
+(1,420,612)
+Net oil and natural gas properties 
+599,630 
+280,965 
+Unevaluated properties 
+142,525 
+43,222 
+Total oil and natural gas properties 
+742,155 
+324,187 
+Other property and equipment, net 
+7,118 
+7,255 
+Restricted investments 
+3,810 
+3,806 
+Deferred tax asset 
+44,688 
+57,765 
+Deferred financing costs 
+18,200 
+1,098 
+Other assets, net 
+342 
+278 
+Total assets 
+$ 
+876,770 
+$ 
+423,953 
+LIABILITIES AND STOCKHOLDERS’ EQUITY 
+Current liabilities: 
+Accounts payable and accrued liabilities 
+$ 
+76,753 
+$ 
+53,447 
+Accrued interest 
+5,993 
+17 
+Cash-settled restricted stock unit awards 
+3,856 
+4,173 
+Asset retirement obligations 
+4,747 
+4,120 
+Deferred tax liability 
+6,214 
+— 
+Fair value of derivatives 
+1,249 
+1,036 
+Total current liabilities 
+98,812 
+62,793 
+13% senior notes: 
+Principal outstanding 
+— 
+48,481 
+Deferred credit, net of accumulated amortization of $0 and $26,239 , respectively 
+— 
+5,267 
+Total 13% senior notes 
+— 
+53,748 
+Senior secured revolving credit facility 
+35,000 
+22,000 
+Secured second lien term loan 
+300,000 
+— 
+Asset retirement obligations 
+1,927 
+2,612 
+Cash-settled restricted stock unit awards 
+7,175 
+3,409 
+Other long-term liabilities 
+121 
+297 
+Total liabilities 
+443,035 
+144,859 
+Stockholders’ equity: 
+Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized: 1,578,948 and 1,578,948 shares outstanding, respectively 
+16 
+16 
+Common stock, $0.01 par value, 110,000,000 and 60,000,000 shares authorized; 55,225,288 and 40,345,456 shares outstanding, respectively 
+552 
+404 
+Capital in excess of par value 
+526,162 
+401,540 
+Accumulated deficit 
+(92,995)
+(122,866)
+Total stockholders’ equity 
+433,735 
+279,094 
+Total liabilities and stockholders’ equity 
+$ 
+876,770 
+$ 
+423,953 
+The accompanying notes are an integral part of these consolidated financial statements. 
+60 
+Table of Contents 
+Callon Petroleum Company 
+Consolidated Sta tements of Operations 
+(in thousands, except per share data) 
+For the Year Ended December 31, 
+2014 
+2013 
+2012 
+Operating revenues: 
+Oil sales 
+$ 
+139,374 
+$ 
+88,960 
+$ 
+96,584 
+Natural gas sales 
+12,488 
+13,609 
+14,149 
+Total operating revenues 
+151,862 
+102,569 
+110,733 
+Operating expenses: 
+Lease operating expenses 
+22,372 
+19,779 
+23,330 
+Production taxes 
+8,973 
+4,133 
+3,224 
+Depreciation, depletion and amortization 
+56,724 
+43,967 
+49,701 
+General and administrative 
+25,109 
+20,534 
+20,358 
+Accretion expense 
+826 
+1,785 
+2,253 
+Gain on sale of other property and equipment 
+(1,080)
+— 
+— 
+Impairment of other property and equipment 
+— 
+1,707 
+1,177 
+Acquisition expense 
+668 
+— 
+— 
+Total operating expenses 
+113,592 
+91,905 
+100,043 
+Income from operations 
+38,270 
+10,664 
+10,690 
+Other (income) expenses: 
+Interest expense 
+9,772 
+6,094 
+9,108 
+Gain on early extinguishment of debt 
+(151)
+(3,696)
+(1,366)
+(Gain) loss on derivative contracts 
+(31,736)
+1,360 
+(1,717)
+Other income 
+(515)
+(485)
+(79)
+Total other (income) expense 
+(22,630)
+3,273 
+5,946 
+Income before income taxes 
+60,900 
+7,391 
+4,744 
+Income tax expense 
+23,134 
+3,104 
+2,223 
+Income before equity in earnings of Medusa Spar LLC 
+37,766 
+4,287 
+2,521 
+Equity in earnings of Medusa Spar LLC 
+— 
+17 
+226 
+Net income 
+37,766 
+4,304 
+2,747 
+Preferred stock dividends 
+(7,895)
+(4,627)
+— 
+Income (loss) available to common stockholders 
+$ 
+29,871 
+$ 
+(323)
+$ 
+2,747 
+Income (loss) per common share: 
+Basic 
+$ 
+0.67 
+$ 
+(0.01)
+$ 
+0.07 
+Diluted 
+$ 
+0.65 
+$ 
+(0.01)
+$ 
+0.07 
+Shares used in computing income (loss) per common share: 
+Basic 
+44,848 
+40,133 
+39,522 
+Diluted 
+45,961 
+40,133 
+40,337 
+The accompanying notes are an integral part of these consolidated financial statements . 
+61 
+Table of Contents 
+Callon Petroleum Company 
+Consolidated Stateme nts of Comprehensive Income 
+(in thousands) 
+For the Year Ended December 31, 
+2014 
+2013 
+2012 
+Net income 
+$ 
+37,766 
+$ 
+4,304 
+$ 
+2,747 
+Other comprehensive income (loss): 
+Change in fair value of derivatives designated as hedges, net of tax 
+— 
+— 
+(1,624)
+Comprehensive income 
+37,766 
+4,304 
+1,123 
+Preferred stock dividends 
+(7,895)
+(4,627)
+— 
+Comprehensive income (loss) available to common shareholders 
+$ 
+29,871 
+$ 
+(323)
+$ 
+1,123 
+The accompanying notes are an integral part of these consolidated financial statements. 
+62 
+Table of Contents 
+Callon Petroleum Company 
+Consolidated Statem ents of Stockholders’ Equity 
+(in thousands) 
+Preferred Stock 
+Common Stock 
+Capital in Excess of Par 
+Accumulated Other Comprehensive Income (Loss) 
+Retained Earnings (Deficit) 
+Total Stockholders' Equity 
+Balance at 12/31/2011 
+$ 
+— 
+$ 
+394 
+$ 
+324,474 
+$ 
+1,624 
+$ 
+(125,290)
+$ 
+201,202 
+Comprehensive income: 
+Net income 
+— 
+— 
+— 
+— 
+2,747 
+Other comprehensive loss 
+— 
+— 
+— 
+(1,624)
+— 
+Total comprehensive income 
+— 
+— 
+— 
+— 
+— 
+1,123 
+Shares issued pursuant to employee benefit plans 
+— 
+— 
+235 
+— 
+— 
+235 
+Restricted stock 
+— 
+4 
+3,407 
+— 
+— 
+3,411 
+Balance at 12/31/2012 
+$ 
+— 
+$ 
+398 
+$ 
+328,116 
+$ 
+— 
+$ 
+(122,543)
+$ 
+205,971 
+Comprehensive income: 
+Net income and comprehensive income 
+— 
+— 
+— 
+— 
+4,304 
+4,304 
+Shares issued pursuant to employee benefit plans 
+— 
+— 
+243 
+— 
+— 
+243 
+Restricted stock 
+— 
+6 
+3,162 
+— 
+— 
+3,168 
+Preferred stock issued 
+16 
+— 
+70,019 
+— 
+— 
+70,035 
+Preferred stock dividend 
+— 
+— 
+— 
+— 
+(4,627)
+(4,627)
+Balance at 12/31/2013 
+$ 
+16 
+$ 
+404 
+$ 
+401,540 
+$ 
+— 
+$ 
+(122,866)
+$ 
+279,094 
+Comprehensive income: 
+Net income and comprehensive income 
+— 
+— 
+— 
+— 
+37,766 
+37,766 
+Shares issued pursuant to employee benefit plans 
+— 
+— 
+262 
+— 
+— 
+262 
+Restricted stock 
+— 
+4 
+2,054 
+— 
+— 
+2,058 
+Common stock issued 
+— 
+144 
+122,306 
+— 
+— 
+122,450 
+Preferred stock dividend 
+— 
+— 
+— 
+— 
+(7,895)
+(7,895)
+Balance at 12/31/2014 
+$ 
+16 
+$ 
+552 
+$ 
+526,162 
+$ 
+— 
+$ 
+(92,995)
+$ 
+433,735 
+The accompanying notes are an integral part of these consolidated financial statements. 
+63 
+Table of Contents 
+Callon Petroleum Company 
+Consolidated Statem ents of Cash Flows 
+(in thousands) 
+For the Year Ended December 31, 
+2014 
+2013 
+2012 
+Cash flows from operating activities: 
+Net income 
+$ 
+37,766 
+$ 
+4,304 
+$ 
+2,747 
+Adjustments to reconcile net income to cash provided by operating activities: 
+Depreciation, depletion and amortization 
+58,014 
+45,393 
+51,043 
+Accretion expense 
+826 
+1,785 
+2,253 
+Amortization of non-cash debt related items 
+1,272 
+471 
+402 
+Amortization of deferred credit 
+(487)
+(3,164)
+(3,086)
+Equity in earnings of Medusa Spar LLC 
+— 
+(17)
+(226)
+Deferred income tax expense 
+23,134 
+2,778 
+2,223 
+Net loss (gain) on derivatives, net of settlements 
+(27,650)
+2,730 
+(1,683)
+Impairment of other property and equipment 
+— 
+1,707 
+1,176 
+Gain on sale of other property and equipment 
+(1,080)
+— 
+— 
+Non-cash gain on early debt extinguishment 
+(151)
+(3,696)
+(1,366)
+Non-cash expense related to equity share-based awards 
+1,126 
+2,092 
+1,697 
+Change in the fair value of liability share-based awards 
+3,936 
+2,903 
+1,620 
+Payments to settle asset retirement obligations 
+(3,808)
+(721)
+(1,314)
+Changes in current assets and liabilities: 
+Accounts receivable 
+(7,915)
+(3,497)
+(883)
+Other current assets 
+622 
+(560)
+100 
+Current liabilities 
+12,805 
+3,583 
+1,753 
+Payments to settle vested liability share-based awards 
+(3,469)
+(239)
+(3,383)
+Change in other long-term liabilities 
+(106)
+(711)
+103 
+Change in other assets, net 
+(448)
+(666)
+(1,886)
+Net cash provided by operating activities 
+94,387 
+54,475 
+51,290 
+Cash flows from investing activities: 
+Capital expenditures 
+(232,596)
+(159,724)
+(133,299)
+Acquisition 
+(222,883)
+(10,885)
+(2,075)
+Proceeds from sales of mineral interest and equipment 
+2,978 
+89,992 
+39,936 
+Distribution from Medusa Spar LLC 
+— 
+813 
+1,735 
+Net cash used in investing activities 
+(452,501)
+(79,804)
+(93,703)
+Cash flows from financing activities: 
+Borrowings on credit facility 
+132,500 
+80,000 
+53,000 
+Borrowings on term loan 
+382,500 
+— 
+— 
+Payments on credit facility 
+(119,500)
+(68,000)
+(43,000)
+Payments on term loan 
+(84,149)
+— 
+— 
+Payment of deferred financing costs 
+(19,779)
+(146)
+— 
+Redemption of 13% senior notes 
+(50,057)
+(50,060)
+(10,225)
+Issuance of preferred stock 
+— 
+70,035 
+— 
+Issuance of common stock 
+122,450 
+— 
+— 
+Payment of preferred stock dividends 
+(7,895)
+(4,627)
+— 
+Taxes paid related to exercise of employee stock options 
+— 
+— 
+(18)
+Net cash provided by (used in) financing activities 
+356,070 
+27,202 
+(243)
+Net change in cash and cash equivalents 
+(2,044)
+1,873 
+(42,656)
+Balance, beginning of period 
+3,012 
+1,139 
+43,795 
+Balance, end of period 
+$ 
+968 
+$ 
+3,012 
+$ 
+1,139 
+The accompanying notes are an integral part of these consolidated financial statements. 
+64 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+IND EX TO THE NOTES TO CONS OLIDATED FINANCIAL STATEMENTS 
+1. 
+Description of Business and Basis of Presentation 
+9 . 
+Asset Retirement Obligations 
+2. 
+Summary of Significant Accounting Policies 
+10 . 
+Equity Transactions 
+3. 
+Acquisitions and Dispositions 
+11 . 
+Income Taxes 
+4 . 
+Earnings (Loss) Per Share 
+12 . 
+Asset Retirement Obligations 
+5 . 
+Borrowings 
+13 . 
+Supplemental Information on Oil and Natural Gas Operations (Unaudited) 
+6 . 
+Derivative Instruments and Hedging Activities 
+14 . 
+Other 
+7 . 
+Fair Value Measurements 
+15 . 
+Summarized Quarterly Financial Information (Unaudited) 
+8 . 
+Employee Benefit Plans 
+Note 1 - Description of Busi ness and Basis of Presentation 
+Description of business 
+Callon Petroleum Company is an independent oil and natural gas company established in 1950. The Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company partially owned by a member of current management. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. 
+Callon is focused on the acquisition, development, exploration and exploitation of unconventional, onshore, oil and natural gas reserves in the Permian Basin in West Texas, and more specifically, the Midland Basin. The Company’s operations to date have been predominantly focused on horizontal drilling of several prospective intervals, including multiple levels of the Wolfcamp formation. Callon has assembled a multi-year inventory of potential horizontal well locations and intends to add to this inventory through delineation drilling of emerging zones on our existing acreage and acquisition of additional locations through acreage purchases, joint ventures and asset swaps. 
+Basis of presentation 
+Unless otherwise indicated, all dollar amounts included within the footnotes to the financial statements are presented in thousands, except for per share and per unit data. 
+The Consolidated Financial Statements include the accounts of the Company, and its subsidiary, Callon Petroleum Operating Company (“CPOC”). CPOC also includes the subsidiaries Callon Offshore Production, Inc. and Mississippi Marketing, Inc. All intercompany accounts and transactions have been eliminated. In the opinion of management, the accompanying audited consolidated financial statements reflect all adjustments, including normal recurring adjustments and all intercompany account and transaction eliminations, necessary to present fairly the Company’s financial position, the results of its operations and its cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation. 
+Note 2 – Summary of Significant Accounting Policies 
+A. 
+Use of Estimates 
+The preparation of financial statements in conformity with United States generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 
+B. 
+Cash and Cash Equivalents 
+The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. 
+65 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+C. 
+Accounts Receivable 
+Accounts receivable consists primarily of accrued oil and natural gas production receivables and joint interest receivables from outside working interest owners . 
+D. 
+Revenue Recognition and Natural Gas Balancing 
+The Company recognizes revenue under the entitlement method of accounting. Under this method, revenue is deferred for deliveries in excess of the Company’s net revenue interest, while revenue is accrued for the undelivered volumes. Production imbalances are generally recorded at the lower of cost or market. The revenue we receive from the sale of NGLs is included in natural gas sales. Natural gas balancing receivables and payables were immaterial as of December 31, 2014 and 2013. 
+E. 
+Major Customers 
+The Company’s production is generally sold on month-to-month contracts at prevailing prices. The following table identifies customers to whom it sold greater than 10% of its total oil and natural gas production during each of the years ended: 
+For the Year Ended December 31, 
+2014 
+2013 
+2012 
+Enterprise Crude Oil, LLC 
+51% 
+38% 
+32% 
+Plains Marketing, L.P. 
+22% 
+15% 
+15% 
+Sunoco 
+10% 
+0% 
+0% 
+Shell Trading Company 
+0% 
+31% 
+39% 
+Other 
+17% 
+16% 
+14% 
+Total 
+100% 
+100% 
+100% 
+Because alternative purchasers of oil and natural gas are readily available, the Company believes that the loss of any of these purchasers would not result in a material adverse effect on its ability to market future oil and natural gas production. 
+F. 
+Oil and Natural Gas Properties 
+The Company uses the full cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as oil and gas propert ies . Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest capitalized on unevaluated leases, other costs related to exploration and development activities, and site restoration, dismantlement and abandonment costs capitalized in accordance with asset retirement obligation accounting guidance. Costs capitalized also include any internal costs that are directly related to exploration and development activities, including salaries and benefits, but do not include any costs related to production, general corporate overhead or similar activities. The Company capitalized $16,688 , $14,753 and $13,331 of these internal costs during 2014, 2013 and 2012, respectively. 
+When applicable, proceeds from the sale or disposition of oil and natural gas properties are accounted for as a reduction to capitalized costs unless the sale would significantly alter the relationship between capitalized costs and proved reserves, in which case a gain or loss is recognized in income. 
+Historical and estimated future development costs of oil and natural gas properties which have been evaluated and contain proved reserves, as well as the historical cost of properties which have been determined to have no future economic value, are depleted using the unit-of-production method based on proved reserves. Excluded from this amortization are costs associated with unevaluated properties, including capitalized interest on such costs. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties or the Company determines that these costs have been impaired. 
+Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, 
+66 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net o f related tax effects (the full cost ceiling amount). These rules generally require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling . See Note 13 for additional information regarding the Company’s oil and natural gas properties. 
+Upon the acquisition or discovery of oil and natural gas properties, the Company estimates the future net costs to dismantle, abandon and restore the property by using available geological, engineering and regulatory data. Such cost estimates are periodically updated for changes in conditions and requirements. In accordance with asset retirement obligation guidance, such costs are capitalized to the full cost pool when the related liabilities are incurred. In accordance with full cost accounting rules, assets recorded in connection with the recognition of an asset retirement obligation are included as part o f the costs subject to the full cost ceiling limitation. The future cash outflows associated with settling the recorded asset retirement obligations are excluded from the computation of the present value of estimated future net revenues used in determining the full cost ceiling amount. 
+G. 
+Other Property and Equipment 
+The Company depreciates its other property and equipment of $7,118 and $7,255 at December 31, 2014 and 2013, respectively, using the straight-line method over estimated useful lives of three to 20 years. Depreciation expense of $836 , $750 and $760 relating to other property and equipment was included in general and administrative expenses in the Company’s consolidated statements of operations for the years ended December 31, 2014, 2013 and 2012, respectively. The accumulated depreciation on other property and equipment was $14,005 and $13,240 as of December 31, 2014 and 2013, respectively. The Company reviews its other property and equipment for impairment when indicators of impairment exist. See Note 14 for addition al information. 
+H. 
+Capitalized Interest 
+The Company capitalizes interest on unevaluated oil and gas properties. Capitalized interest cannot exceed gross interest expense. During the years ended December 31, 2014, 2013 and 2012, the Company capitalized $4,295 , $4,410 and $2,109 of interest expense. 
+I. 
+Deferred F inancing C osts 
+Deferred financing costs are stated at cost, net of amortization, which is computed using the straight-line method over the life of the loan, which is reflective of the effective interest rate method. Deferred financing costs of $18,200 and $1,098 as of December 31, 2014 and 2013, respectively, net of accumulated amortization. Amortization of deferred financing costs of $1,272 , $471 and $402 was recorded for the years ended December 31, 2014, 2013 and 2012, respectively. 
+J. 
+Asset Retirement Obligations 
+The Company is required to record its estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Interest is accreted on the present value of the asset retirement obligations and reported as accretion expense within operating expenses in the consolidated statements of operations. See Note 12 for additional information. 
+K. 
+Derivatives 
+The Company’s derivative contracts executed prior to 2012 were designated as cash flow hedges, and were recorded at fair market value with the changes in fair value recorded net of tax through other comprehensive income (loss) (“OCI”) in stockholders’ equity. Ineffective derivative contracts or ineffective portions of contracts designated as cash flow hedges were recognized as gain or loss on derivative contracts . The last of the Company’s derivative contracts designated as cash flow hedges expired on December 31, 2012. Derivative contracts executed subsequent to December 31, 2012 and outstanding as of December 31, 2014 were not designated as accounting hedges, and are carried on the balance sheet at their fair market value. Changes in the fair value of derivative contracts not designated as accounting hedges are reflected in earnings as a gain or loss on derivative contracts. See Notes 6 and 7 for additional information regarding the Company’s derivative contracts. 
+67 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+L. 
+Income Taxes 
+Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties for financial reporting purposes and income tax purposes. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards, statutory depletion carryforward s and tax credit carryforwards, net of a valuation allowance. A valuation allowance is provided for that portion, if any, of the asset for which it is deemed more likely than not that it will not be realized. See Note 11 for additional information. 
+M. 
+Share-Based Compensation 
+The Company grants to directors and employees stock options and restricted stock awards (“RS awards”) . The Company also grants restricted stock unit awards (“RSU awards”) that may be settled in cash or common stock at the option of the Company and RSU awards that may only be settled in cash (“Cash-settleable RSU awards”). 
+Stock Options. For stock options the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value as calculated using the Black-Scholes option pricing model and recognized straight-line over the vesting period (generally three years). 
+RS awards, RSU awards and Cash-settleable RSU awards. For RS and RSU awards that the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value and recognized straight-line over the vesting period (generally three years). For Cash-settleable RSU awards that the Company expects or is required to settle in cash, share-based compensation expense is based on the fair value remeasured at each reporting period as calculated using a Monte Carlo pricing model, because vesting of these awards is subject to a market condition, with the estimated value recognized over the vesting period (generally three years). 
+N. 
+Statements of Cash Flows Supplemental Information 
+During the three year period ended 2013, the Company paid no federal income taxes. During the years ended December 31, 2014, 2013 and 2012, the company made cash interest payments of $7,283 , $13,189 and $13,920 , respectively. 
+O. 
+Investment in Medusa Spar LLC 
+During the fourth quarter of 2013, the Company closed on the sale of its 15.0% working interest in the Medusa field, its 10.0% membership interest in Medusa Spar LLC (“LLC”), and substantially all of its remaining Gulf of Mexico shelf properties. Prior to the sale, the Company’s ownership interest in the LLC was accounted for under the equity method of accounting. The LLC held a 75% undivided ownership interest in the deepwater spar production facilities at the Medusa field in the Gulf of Mexico and earned a tariff based upon production volume throughput from the Medusa area. The Company was obligated to process through the spar production facilities its share of production from the Medusa field and any future discoveries in the area. The balance of the LLC was owned by Oceaneering International, Inc. and Murphy Oil Corporation. See Note 3 for additional information on the Medusa divestiture. 
+P. 
+Earnings per Share (EPS) 
+The Company’s basic EPS amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS, using the treasury-stock method, reflects the potential dilution caused by the exercise of all options and vesting of all restricted stock and restricted stock units settleable in shares. 
+Q. 
+Recent Accounting Pronouncements 
+In May 2014, the Financial Accounting Standards Board issued accounting standards update (“ASU”) No. 2014-09, Revenue from Contracts with Customers. The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU No. 2014-09 will replace most of the existing revenue recognition requirements in GAAP when it becomes effective. The guidance in ASU No. 2014-09 is effective for public entities for annual reporting periods beginning after December 15, 2016, 
+68 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+including interim periods therein. Early adoption is not permitted. The Company is currently evaluating the method of adoption and impact this standard will have on its financial statements and related disclosures. 
+Note 3 – Acquisitions and Dispositio ns 
+2014 acquisitions 
+In the first quarter of 2014 , the Company acquired 1,527 net acres in Upton and Reagan Counties, Texas, which are located in the southern portion of the Midland Basin near its existing core development fields, for an aggregate cash purchase price of $8,200 . The properties bear a working interest of 100% and an average net revenue interest of 78% . 
+On October 8, 2014, the Company completed the acquisition of certain undeveloped acreage and producing oil and gas properties located in Midland, Andrews, Ector and Martin Counties, Texas (the “ Central Midland Basin Acquisition”) for an aggregate cash purchase price of $210,205 , including estimated purchase price adjustments of $2,367 based on an effective date of May 1, 2014. The Company assumed operatorship of the properties on November 1, 2014, and acquired a 62% working interest ( 46.5% net revenue interest) in the Central Midland Basin Acquisition. The aggregate cash purchase price was funded with a combination of the net proceeds from an equity offering of $122,450 and a portion of the proceeds from borrowings under the Second Lien Loan. For additional information on the debt transactions and equity offering, see Notes 5 and 10 , respectively. 
+The Central Midland Basin Acquisition was accounted for under the purchase method of accounting, which involves determining the fair value of the assets acquired and liabilities assumed. The following purchase price allocation is based on management’s estimates of the fair value of the assets acquired and liabilities assumed. The following table summarizes the acquisition date fair values of the net assets acquired: 
+Oil and natural gas properties 
+$ 
+91,895 
+Unevaluated oil and natural gas properties 
+118,450 
+Asset retirement obligations 
+(140)
+Net assets acquired 
+$ 
+210,205 
+The following unaudited summary pro forma financial information for the year ended December 31, 2014 and 2013 has been presented for illustrative purposes only and does not purport to represent what the Company’s results of operations would have been if the Central Midland Basin Acquisition had occurred as presented, or to project the Company’s results of operations for any future periods. The pro forma financial information was prepared assuming the Central Midland Basin Acquisition and the debt transactions and equity offering discussed in Notes 5 and 10 , respectively, occurred as of January 1, 2013. The pro forma adjustments are based on available information and certain assumptions that management believes are reasonable, including revenue, lease operating expenses, production taxes, depreciation, depletion and amortization expense, accretion expense, interest expense and capitalized interest. 
+For the Years Ended December 31, 
+2014 
+2013 
+Revenues 
+$ 
+180,458 
+$ 
+151,766 
+Income from operations 
+53,526 
+36,002 
+Income available to common stockholders 
+33,674 
+4,033 
+Net income per common share 
+Basic 
+$ 
+0.57 
+$ 
+0.07 
+Diluted 
+$ 
+0.56 
+$ 
+0.07 
+2013 acquisitions 
+During the second quarter of 2013, the Company acquired approximately 2,468 gross ( 2,186 net) acres in Reagan and Upton Counties, Texas, which is located in the Southern Midland Basin and which is prospective for both horizontal and vertical drilling. The acquisition also included seven gross vertical wells and 1,301 barrels of oil equivalent proved reserves. The purchase price of $11,000 was funded using a portion of the proceeds from the preferred stock offering (discussed in Note 10 ). 
+69 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+2012 acquisitions 
+During the first quarter of 2012, the Company acquired 16,233 gross ( 14,653 net) acres in Borden County, which is located in the Northern Midland basin. The Northern Midland basin has had limited drilling activity compared with the Southern Midland basin (where our current production is located), increasing the economic risk related to these drilling activities. The purchase price of $14,538 was funded from existing cash balances. During the third quarter of 2012, we acquired an additional 8,095 gross acres ( 6,964 net) in this area for a total consideration of $4,835 . 
+During the second quarter of 2012, the Company signed a purchase and sale agreement to acquire 2,319 gross ( 1,762 net) acres in southern Reagan County, Texas for a total purchase price of $12,012 , which was financed with a draw on the Credit Facility. The transaction had an effective date of May 1, 2012 and closed on July 5, 2012. 
+2013 dispositions 
+During the fourth quarter of 2013, the Company closed on the sale of its 15.0% working interest in the Medusa field (Mississippi Canyon blocks 582 and 538), our 10.0% membership interest in Medusa Spar LLC, and substantially all of our remaining Gulf of Mexico shelf properties for total net cash consideration of approximately $88,000 after customary purchase price adjustments. Also during the fourth quarter of 2013, the Company closed on the sale of its 69% interest in the Swan Lake field for $2,000 . This was the Company’s only field in the Haynesville shale. T he proceeds from these sales were accounted for as a reduction to capitalized costs as the sale s did not significantly alter the relationship between capitalized costs and proved reserves. 
+2012 dispositions 
+During 2012, the Company closed on the sale of its 11.25% working interest in the Habanero field (Garden Banks Block 341) for net cash consideration of $39,410 after customary purchase price adjustments. T he proceeds from this sale were accounted for as a reduction to capitalized costs as the sale did not significantly alter the relationship between capitalized costs and proved reserves. 
+Note 4 - Ear nings Per Share 
+Basic earnings (loss) per share is computed by dividing income (loss) available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings (loss) per share includes the potential dilutive impact of non-vested restricted shares and unexercised options outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. A reconciliation of the basic and diluted net income per share computation is as follows: 
+70 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+The following table sets forth the computation of basic and diluted earnings per share: 
+For the Year Ended December 31, 
+2014 
+2013 
+2012 
+Net income (loss) 
+$ 
+37,766 
+$ 
+4,304 
+$ 
+2,747 
+Preferred stock dividends 
+(7,895)
+(4,627)
+— 
+Income (loss) available to common stockholders 
+$ 
+29,871 
+$ 
+(323)
+$ 
+2,747 
+Weighted average shares outstanding 
+44,848 
+40,133 
+39,522 
+Dilutive impact of stock options 
+— 
+— 
+8 
+Dilutive impact of restricted stock 
+1,113 
+— 
+807 
+Weighted average shares outstanding for diluted income (loss) per share (a) 
+45,961 
+40,133 
+40,337 
+Basic income (loss) per share 
+$ 
+0.67 
+$ 
+(0.01)
+$ 
+0.07 
+Diluted income (loss) per share 
+$ 
+0.65 
+$ 
+(0.01)
+$ 
+0.07 
+The following were excluded from the diluted earnings per share calculation because their effect would be anti-dilutive: 
+Stock options 
+30 
+52 
+52 
+Restricted stock 
+317 
+398 
+123 
+(a) 
+Because the Company reported a loss available to common stockholders for the year ended December 31, 2013, no unvested stock awards were included in computing loss per share because the effect was anti-dilutive. 
+Note 5 – Borr owings 
+The Company’s borrowings consisted of the following at: 
+For the Year Ended December 31, 
+2014 
+2013 
+Principal components: 
+Senior secured revolving credit facility 
+$ 
+35,000 
+$ 
+22,000 
+Secured second lien term loan 
+300,000 
+— 
+13% Senior Notes, principal 
+— 
+48,481 
+Total principal outstanding 
+335,000 
+70,481 
+13% Senior Notes, unamortized deferred credit 
+— 
+5,267 
+Total carrying value of borrowings 
+$ 
+335,000 
+$ 
+75,748 
+Senior secured revolving credit facility (the “Credit Facility”) 
+On March 11, 2014, the Company entered into the Fifth Amended and Restated Credit Agreement to the Credit Facility with a maturity date of March 11, 2019. JPMorgan Chase Bank, N.A. is Administrative Agent, and participating lenders include Regions Bank, Citibank, N.A., Capital One, N.A., KeyBank, N.A., Whitney Bank, IberiaBank, N.A., OneWest Bank, N.A., SunTrust Bank and Royal Bank of Canada. The total notional amount available under the Credit Facility is $500,000 . Amounts borrowed under the Credit Facility may not exceed the borrowing base, which is generally reviewed on a semi-annual basis. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. In conjunction with the closing of the Acquisition on October 8, 2014, the borrowing base on the Company’s Credit Facility was amended to $250,000 . 
+As of December 31, 2014 , the balance outstanding on the Credit Facility was $35,000 with a weighted-average interest rate of 1.91% , calculated as the LIBOR plus a tiered rate ranging from 1.75% to 2.75% , which is determined based on utilization of the facility. In addition, the Credit Facility carries a commitment fee of 0.5% per annum, payable quarterly, on the unused portion of the borrowing base. The Company had $ 215,000 of available borrowings under the Credit Facility as of December 31, 2014. 
+71 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+Term loans 
+On March 11, 2014, the Company entered into a term loan in an aggregate amount of up to $125,000 , including initial commitments of $100,000 and additional availability of $25,000 subject to the consent of two-thirds of the lenders and compliance with financial covenants after giving effect to such increase. The term loan had a maturity date of September 11, 2019, and was not subject to mandatory prepayments unless new debt or preferred stock wa s issued. It was prepayable at the Company’s option, subject to a prepayment premium. The prepayment amount was (i) 102% if the prepayment event occurs prior to March 11, 2015, and (ii) 101% if the prepayment event occurs on or after March 15, 2015 but before March 15, 2016, and (iii) 100% for prepayments made on or after March 15, 2016. The term loan was secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor agreement. On April 10, 2014, the Company drew an initial amount of $62,500 with an original issue discount of 1.0% . 
+On October 8, 2014, the term loan described above was repaid in full using proceeds from a new secured second lien term loan (the “Second Lien Loan”) in conjunction with the closing of the A cquisition, resulting in a loss on early extinguishment of debt of $3,054 . The Second Lien Loan has a maturity date of October 8, 2021. On October 8, 2014, the Company drew an initial amount of $300,000 with a discount of 2.0% and an interest rate of 8.5% , calculated at a rate of LIBOR (subject to a floor rate of 1.0 %) plus 7.5% per annum. The Second Lien Loan may be prepaid at the Company’s option, subject to a prepayment premium. The prepayment amount is (i) 102% if the prepayment event occurs prior to October 8, 2015, and (ii) 101% if the prepayment event occurs on or after October 8, 2015 but before October 8, 2016, and (iii) 100% for prepayments made on or after October 8, 2016. The Second Lien Loan is secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor agreement. The Royal Bank of Canada is Administrative Agent, and participants include several institutional lenders. 
+13% senior notes due 2016 (“Senior Notes”) and deferred credit 
+On April 11, 2014, the Company completed a full redemption of the remaining $48,481 principal amount of outstanding Senior Notes using proceeds from the Second Lien Loan. The redemption resulted in a net $3,205 gain on the early extinguishment of debt (including $4,780 of accelerated deferred credit amortization). The gain represents the difference between the $50,057 paid for the redemption of the Senior Notes ( $1,576 of redemption costs, primarily the call premium) and the carrying value of the remaining Senior Notes of $53,261 (inclusive of $4,780 of deferred credit). The Company also paid $193 in accrued interest through the redemption date. Upon the redemption, the indenture governing the Senior Notes was discharged in accordance with its terms. 
+Using a portion of the proceeds from the sale of our interest in Medusa on December 17, 2013, the Company redeemed $48,481 of its Senior Notes, which resulted in a net $3,696 gain on the early extinguishment of debt. The gain represents the difference between the $50,057 paid for the redemption of the Senior Notes (inclusive of $1,576 of redemption expenses, primarily the call premium) and the carrying value of $53,756 (inclusive of the $5,275 of accelerated deferred credit amortization). 
+In June 2012, the Company redeemed $10,000 of its Senior Notes, which resulted in a net $1,366 gain on the early extinguishment of debt. The gain represents the difference between the $10,225 paid for the redemption of the Senior Notes (inclusive of $225 of redemption expenses, primarily the call premium) and the carrying value of $11,591 (inclusive of the $1,591 of accelerated deferred credit amortization). 
+Restrictive covenants 
+The Company’s Credit Facility and Second Lien Loan contain various covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. The Company was in compliance with these covenants at December 31, 2014 . 
+Note 6 - Der ivative Instruments and Hedging Activities 
+Objectives and strategies for using derivative instruments 
+The Company is exposed to fluctuations in oil and natural gas prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil and natural gas production. The Company utilizes a mix of 
+72 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+collars, swaps, puts, calls and similar derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes. 
+Counterparty risk and offsetting 
+The use of derivative instruments exposes the Company to the risk that a counterparty will be unable to meet its commitments. While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument; see Note 7 for additional information regarding fair value. 
+The Company executes commodity derivative contracts under master agreements that have netting provisions that provide for offsetting payables against receivables. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement. 
+Financial statement presentation and settlements 
+Settlements of the Company’s derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets. See Note 7 for additional information regarding fair value. 
+Derivatives not designated as hedging instruments 
+The Company elected not to designate its derivative contracts as accounting hedges for contracts executed subsequent to December 31, 2012 . Consequently, the Company records its derivative contracts at fair value in the consolidated balance sheet and records changes in fair value as a gain or loss on derivative contracts in the consolidated statement of operations. Cash settlements are also recorded as gain or loss on derivative contracts in the consolidated statement of operations. 
+The following table reflects the fair value of the Company’s derivative instruments for the periods presented: 
+Balance Sheet Presentation 
+Asset Fair Value 
+Liability Fair Value 
+Net Derivative Fair Value 
+Commodity 
+Classification 
+Line Description 
+12/31/2014 
+12/31/2013 
+12/31/2014 
+12/31/2013 
+12/31/2014 
+12/31/2013 
+Derivatives not designated as Hedging Instruments under ASC 815 
+Natural gas 
+Current 
+Fair value of derivatives 
+$ 
+1,262 
+$ 
+60 
+$ 
+(7)
+$ 
+— 
+$ 
+1,255 
+$ 
+60 
+Natural gas 
+Non-current 
+Other long-term liabilities 
+— 
+— 
+— 
+(72)
+— 
+(72)
+Oil 
+Current 
+Fair value of derivatives 
+26,588 
+— 
+(1,242)
+(1,036)
+25,346 
+(1,036)
+Total 
+$ 
+27,850 
+$ 
+60 
+$ 
+(1,249)
+$ 
+(1,108)
+$ 
+26,601 
+$ 
+(1,048)
+73 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+As previously discussed, the Company’s derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated: 
+For the Year Ended December 31, 2014 
+Presented without 
+As Presented with 
+Effects of Netting 
+Effects of Netting 
+Effects of Netting 
+Current assets: Fair value of derivatives 
+$ 
+27,850 
+$ 
+— 
+$ 
+27,850 
+Current liabilities: Fair value of derivatives 
+$ 
+(1,249)
+$ 
+— 
+$ 
+(1,249)
+For the Year Ended December 31, 2013 
+Presented without 
+As Presented with 
+Effects of Netting 
+Effects of Netting 
+Effects of Netting 
+Current assets: Fair value of derivatives 
+$ 
+8 
+$ 
+52 
+$ 
+60 
+Current liabilities: Fair value of derivatives 
+1,088 
+(52)
+1,036 
+Long-term liabilities: Fair value of derivatives 
+$ 
+(72)
+$ 
+— 
+$ 
+(72)
+Derivatives not designated as hedging instruments under ASC 815 
+For the periods indicated, the Company recorded the following related to its derivatives in the consolidated statement of operations as gain or loss on derivative contracts: 
+For the Year Ended December 31, 
+2014 
+2013 
+2012 
+Natural gas derivatives 
+Net gain (loss) on settlements 
+$ 
+(84)
+$ 
+(148)
+$ 
+34 
+Net gain (loss) on fair value adjustments 
+1,267 
+230 
+(241)
+Total gain (loss) 
+$ 
+1,183 
+$ 
+82 
+$ 
+(207)
+Oil derivatives 
+Net gain (loss) on settlements 
+$ 
+4,170 
+$ 
+1,518 
+$ 
+— 
+Net gain (loss) on fair value adjustments 
+26,383 
+(2,960)
+1,924 
+Total gain (loss) 
+$ 
+30,553 
+$ 
+(1,442)
+$ 
+1,924 
+Total gain (loss) on derivative contracts 
+$ 
+31,736 
+$ 
+(1,360)
+$ 
+1,717 
+Derivatives designated as hedging instruments under ASC 815 
+The Company’s derivative contracts executed prior to December 31, 2012 were designated as accounting hedges. The table below presents the effect of the Company’s derivative financial instruments on the consolidated statements of operations as an increase to oil and natural gas sales: 
+For the Year Ended December 31, 
+2014 
+2013 
+2012 
+Amount of gain reclassified from OCI into income 
+$ 
+— 
+$ 
+— 
+$ 
+1,420 
+74 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+Derivative positions 
+Listed in the tables below are the outstanding oil and natural gas derivative contracts as of December 31, 2014: 
+For the Three Months Ended 
+March 31, 
+June 30, 
+September 30, 
+December 31, 
+Oil contracts 
+2015 
+2015 
+2015 
+2015 
+Collar contracts combined with short puts (three-way collar): 
+Volume (MBbls) 
+158 
+159 
+— 
+— 
+Price per Bbl 
+Ceiling (short call) 
+$ 
+99.10 
+$ 
+99.10 
+$ 
+— 
+$ 
+— 
+Floor (long put) 
+$ 
+90.00 
+$ 
+90.00 
+$ 
+— 
+$ 
+— 
+Short put 
+$ 
+75.00 
+$ 
+75.00 
+$ 
+— 
+$ 
+— 
+Swap contracts: 
+Total volume (MBbls) 
+171 
+136 
+129 
+74 
+Weighted average price per Bbl 
+$ 
+92.25 
+$ 
+92.18 
+$ 
+92.25 
+$ 
+92.20 
+Put spreads: 
+Volume (MBbls) 
+— 
+— 
+138 
+138 
+Long put price per Bbl 
+$ 
+— 
+$ 
+— 
+$ 
+90.00 
+$ 
+90.00 
+Short put price per Bbl 
+$ 
+— 
+$ 
+— 
+$ 
+75.00 
+$ 
+75.00 
+For the Three Months Ended 
+March 31, 
+June 30, 
+September 30, 
+December 31, 
+Natural gas contracts 
+2015 
+2015 
+2015 
+2015 
+Collar contracts combined with short 
+puts (three-way collar): 
+Volume (BBtu) 
+248 
+227 
+207 
+161 
+Weighted average price per MMBtu 
+Ceiling (short call) 
+$ 
+4.67 
+$ 
+4.32 
+$ 
+4.32 
+$ 
+4.32 
+Floor (long put) 
+$ 
+4.00 
+$ 
+3.85 
+$ 
+3.85 
+$ 
+3.85 
+Short put 
+$ 
+3.50 
+$ 
+3.25 
+$ 
+3.25 
+$ 
+3.25 
+Swap contracts: 
+Total volume (BBtu) 
+271 
+237 
+219 
+228 
+Weighted average price per MMBtu 
+$ 
+3.98 
+$ 
+3.98 
+$ 
+3.98 
+$ 
+3.96 
+Short call contract: 
+Short call volume (BBtu) 
+108 
+109 
+110 
+111 
+Short call price per MMBtu 
+$ 
+5.00 
+$ 
+5.00 
+$ 
+5.00 
+$ 
+5.00 
+Subsequent to December 31, 2014, the Company restructured its portfolio of benchmark West Texas Intermediate oil hedges for 2015 and separately entered into new swap arrangements. The Company converted all of its three-way collars and put spreads into new swap contracts with fixed swap prices that received a premium to prevailing swap price levels at the time to reflect the value of the monetized put spreads embedded in the converted non-swap structures. Following the restructuring transaction and addition of new swap contracts, we currently have an average of 4,165 barrels of oil per day hedged at a weighted average swap price of $70.89 per barrel for calendar year 2015. 
+In addition, the Company recently entered into basis differential swaps that provide for a fixed price spread between the Midland and NYMEX prices for West Texas Intermediate oil. The Company hedged an average of approximately 4,120 barrels of oil per day from March 2015 to December 2015 at a weighted average Midland swap spread of ($2.39) per barrel. 
+75 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+The following derivative contracts for oil were executed subsequent to December 31, 2014: 
+For the Three Months Ended 
+March 31, 
+June 30, 
+September 30, 
+December 31, 
+Oil contracts 
+2015 
+2015 
+2015 
+2015 
+Swap contracts: 
+Total volume (MBbls) 
+231 
+273 
+253 
+253 
+Weighted average price per Bbl 
+$ 
+60.77 
+$ 
+60.09 
+$ 
+59.83 
+$ 
+59.83 
+Swap contracts (Differentials): 
+Total volume (MBbls) 
+152 
+400 
+382 
+326 
+Weighted average price per Bbl 
+$ 
+(2.41)
+$ 
+(2.40)
+$ 
+(2.39)
+$ 
+(2.38)
+Note 7 - Fair Valu e Measurements 
+The fair value hierarchy outlined in the relevant accounting guidance gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable, and these valuations have the lowest priority. 
+Fair Value of Financial Instruments 
+Cash, cash equivalents, restricted investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments. 
+Debt. The Company’s debt is recorded at the carrying amount in the consolidated balance sheet. The carrying amount of floating-rate debt approximated fair value because the interest rates were variable and reflective of market rates. 
+The following table summarizes the respective carrying and fair values at: 
+` 
+December 31, 
+2014 
+2013 
+Carrying Value 
+Fair Value 
+Carrying Value 
+Fair Value 
+Credit Facility 
+$ 
+35,000 
+$ 
+35,000 
+$ 
+22,000 
+$ 
+22,000 
+Second Lien Loan 
+300,000 
+300,000 
+— 
+— 
+13% Senior Notes due 2016 (a) 
+— 
+— 
+53,748 
+50,299 
+Total 
+$ 
+335,000 
+$ 
+335,000 
+$ 
+75,748 
+$ 
+72,299 
+(a) 
+The fair value, using Level 2 inputs, was based upon estimates provided by an independent investment banking firm. 2013 fair value was determined only in relation to the $48,481 face value outstanding of the 13% Senior Notes. The remaining $5,267 represent ed the deferred credit , which was excluded from the fair value calculation. See Note 5 for additional information. 
+Assets and liabilities measured at fair value on a recurring basis 
+Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheet. The following methods and assumptions were used to estimate fair value: 
+Commodity derivative instruments. The fair value of commodity derivative instruments is derived using an income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. The Company believes that the majority of the inputs used to calculate the commodity derivative instruments fall within Level 2 of the fair-value hierarchy based on the wide availability of quoted market prices for similar commodity derivative contracts. See Note 6 for additional information regarding the Company’s derivative instruments. 
+76 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis: 
+December 31, 2014 
+Balance Sheet Presentation 
+Level 1 
+Level 2 
+Level 3 
+Total 
+Assets 
+Derivative financial instruments (current) 
+Fair value of derivatives 
+$ 
+— 
+$ 
+27,850 
+$ 
+— 
+$ 
+27,850 
+Derivative financial instruments (non-current) 
+Other assets, net 
+— 
+— 
+— 
+— 
+Sub-total assets 
+$ 
+— 
+$ 
+27,850 
+$ 
+— 
+$ 
+27,850 
+Liabilities 
+Derivative financial instruments (current) 
+Fair value of derivatives 
+$ 
+— 
+$ 
+(1,249)
+$ 
+— 
+$ 
+(1,249)
+Derivative financial instruments (non-current) 
+Other long-term liabilities 
+— 
+— 
+— 
+— 
+Sub-total liabilities 
+$ 
+— 
+$ 
+(1,249)
+$ 
+— 
+$ 
+(1,249)
+Total net assets (liabilities) 
+$ 
+— 
+$ 
+26,601 
+$ 
+— 
+$ 
+26,601 
+December 31, 2013 
+Balance Sheet Presentation 
+Level 1 
+Level 2 
+Level 3 
+Total 
+Assets 
+Derivative financial instruments (current) 
+Fair value of derivatives 
+$ 
+— 
+$ 
+60 
+$ 
+— 
+$ 
+60 
+Derivative financial instruments (non-current) 
+Other assets, net 
+— 
+— 
+— 
+— 
+Sub-total assets 
+$ 
+— 
+$ 
+60 
+$ 
+— 
+$ 
+60 
+Liabilities 
+Derivative financial instruments (current) 
+Fair value of derivatives 
+$ 
+— 
+$ 
+(1,036)
+$ 
+— 
+$ 
+(1,036)
+Derivative financial instruments (non-current) 
+Other long-term liabilities 
+— 
+(72)
+— 
+(72)
+Sub-total liabilities 
+$ 
+— 
+$ 
+(1,108)
+$ 
+— 
+$ 
+(1,108)
+Total net assets (liabilities) 
+$ 
+— 
+$ 
+(1,048)
+$ 
+— 
+$ 
+(1,048)
+Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis 
+Acquisition. On October 8, 2014, the Company completed the Acquisition as discussed in Note 3. The Company determined the fair value of the assets acquired using the income approach based on expected future cash flows fr o m estimated reserve quantities; costs to produce and develop reserves; and oil and gas forward prices. Asset retirement obligations assumed in connection with the Central Midland Basin Acquisition were determined in accordance with applicable accounting standards. The fair value measurements were based on level 2 and level 3 inputs . For more information on the A cquisition see Note 3 . 
+During the second quarter of 2013, the Company completed an acquisition as discussed in Note 3. The Company determined the fair value of the assets acquired using the income approach based on expected future cash flows from estimated reserve quantities; costs to produce and develop reserves; and oil and gas forward prices. Asset retirement obligations assumed in connection with th is acquisition were determined in accordance with applicable accounting standards . The fair value measurements were based on level 2 and level 3 inputs. 
+Other Property and Equipment. As discussed in Note 14 , the Company’s decision to abandon certain of its other property and equipment, that had been classified as held for sale, resulted in an impairment charge of $1,707 which is included in the Company’s Statement of Operations for the year ended December 31, 2013 . The impairment charge was valued using level 3 inputs. See Note 14 for more information. 
+Note 8 – Emplo yee Benefit Plans 
+The Company utilizes various forms of incentive compensation designed to align the interest of the executives and employees with those of its stockholders. Tabular disclosures related to the share-based awards are presented in Note 9 . The narrative that follows provides a brief description of each plan, summarizes the overall status of each plan and discusses current year awards under each plan: 
+77 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+Savings and Protection Plan 
+The Savings and Protection Plan (“401-K Plan”) provides employees with the option to defer receipt of a portion of their compensation, and the Company may, at its discretion, match a portion of the employee’s deferral with cash. The Company may also elect, at its discretion, to contribute a non-matching amount in cash and Company Common Stock to employees. The amounts held under the 401-K Plan are invested in various funds maintained by a third party in accordance with the directions of each employee. An employee is fully vested, including Company discretionary contributions, immediately upon participation in the 401-K Plan. The total amounts contributed by the Company, including the value of the common stock contributed, were $1,017 , $923 and $918 in the years 2014 , 2013 and 2012 , respectively. 
+2011 Omnibus Incentive Plan (the “2011 Plan”) 
+The 2011 Plan, which became effective May 12, 2011 following shareholder approval, authorized and reserved for issuance 2,300,000 shares of common stock, which may be issued upon exercise of vested stock options and/or the vesting of any other share-based equity award that is granted under this plan. The 2011 Plan is the Company’s only active plan, and included a provision at inception whereby all remaining, un-issued and authorized shares from the Company’s previous share-based incentive plans became issuable under the 2011 Plan. This transfer provision resulted in the transfer of an additional 841,000 shares into the plan, increasing the quantity authorized and reserved for issuance under the 2011 Plan to 3,141,000 at the inception of the plan. Another provision provided that shares which would otherwise become available for issue under the previous plans as a result of vesting and/or forfeiture of any equity awards existing as of May 12, 2012, would also increase the authorized shares available to the 2011 Plan. As of December 31, 2014 , the 2011 Plan had 1,132,000 shares remaining and eligible for future issuance. 
+Equity awards issued under this plan may be subject to various vesting, accelerated vesting, and forfeiture provisions upon the occurrence of certain events. Any vested but unexercised options contractually expire 10 years from the date of grant. Equity awards under the 2011 Plan generally vest over time but may also be subject to attaining a specified performance metrics and may vest immediate ly or cliff vest at a specified date. The Company will recognize expense on the grant date for all immediately vesting awards, while it will recognize expense ratably over the requisite service (i.e. vesting) period for both cliff and ratably vesting awards. For performance-based awards, the Company recognizes expense based on its analysis of the performance criteria, and records or reverses expense as necessary based on its analysis. For market-based awards, the Company recognizes expense based on its analysis of the market criteria, and records expense as necessary based on its analysis. Awards with a market-based provision do not allow for the reversal of previously recognized expense, even if the market metric is not achieved and no shares ultimately vest or are awarded. 
+Cash-Settle d RSU Awards 
+Certain of the Company’s RSUs awarded require cash settlement. Cash-settle d RSU awards are accounted for as liabilities as the Company is contractually obligated to settle these awards in cash. The fair value of the Company’s market-based RSU awards is calculated using a Monte Carlo valuation model, which considers such inputs as the Company’s and its peer group’s stock prices, a risk-free interest rate, and an estimated volatility for the Company and its peer group. Changes in the fair value of cash-settleable awards are recorded as adjustments to compensation expense. 
+Market-based RSUs: A significant portion of the Company’s cash-settle d RSU awards include a market-based vesting condition that determines the actual number of units that will ultimately vest. The number of RSUs that vest is based on a calculation that compares the Company’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between 0% and 200% of the base units awarded. 
+78 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+As of December 31, 2014 , the Company had the following cash-settleable RSU awards outstanding (including those that are not based on a market condition): 
+(shares in 000s) 
+Base Units Outstanding 
+Potential Minimum Units Vesting 
+Potential Maximum Units Vesting 
+Vesting in 2015 
+837 
+52 
+1,622 
+Vesting in 2016 
+416 
+60 
+772 
+Vesting in 2017 
+24 
+24 
+24 
+Other 
+137 
+137 
+137 
+Total cash-settleable RSU awards 
+1,414 
+273 
+2,555 
+For the year ended December 31, 2014 , 523,000 market-based cash-settle d RSUs subject to the peer market-based vesting described above vested at between 150% - 200% , depending on the date of vesting , resulting in cash payment s of $1,241 in 2014 and payable amounts of $3,599 in 2015. Also during 2014 , 58,000 non-market-based cash settle d RSUs vested, resulting in cash payment s of $559 in 2014. During 2013 , 260,000 market-based cash-settle d RSUs subject to the peer market-based vesting described above vested at 100% of their issued units, resulting in cash payment s of $1,669 in 2014. Also during 2013 , 65,000 non-market-based cash settl ed RSUs vested, resulting in cash payment s of $239 in 2013. See Note 9 for additional informa tion regarding cash-settleable RSUs. 
+Note 9 - Shar e-Based Compensation 
+As discussed in Note 8 , the Company grants various forms of share-based compensation awards to employees of the Company and its subsidiaries and to non-employee members of the Board of Directors. At December 31, 2014 , shares available for future share-based awards, including stock options or restricted stock grants, under the Company’s only active plan, the 2011 Plan, were 1,132,000 . 
+The following table presents share-based compensation expense for each respective period: 
+For the Year Ended December 31, 
+2014 
+2013 
+2012 
+Share-based compensation cost for: 
+Equity-based 
+Liability-based 
+Equity-based 
+Liability-based 
+Equity-based 
+Liability-based 
+RSU equity awards 
+$ 
+4,223 
+$ 
+— 
+$ 
+3,975 
+$ 
+— 
+$ 
+4,210 
+$ 
+— 
+Cash-settleable RSU awards 
+— 
+6,918 
+— 
+5,347 
+— 
+2,916 
+401(k) contributions in shares 
+270 
+— 
+219 
+— 
+218 
+— 
+Total share-based compensation cost (a) 
+$ 
+4,493 
+$ 
+6,918 
+$ 
+4,194 
+$ 
+5,347 
+$ 
+4,428 
+$ 
+2,916 
+(a) 
+The portion of this share-based compensation cost that was included in general and administrative expense totaled $7,2 35 , $5,751 and $4,081 for the same years, respectively, and the portion capitalized to oil and gas properties was $4,176, $3,791 and $3,263 , respectively. 
+The following table presents the unrecognized compensation cost for the indicated periods: 
+For the Year Ended December 31, 
+Unrecognized compensation cost related to: 
+2014 
+2013 
+2012 
+Unvested RSU equity awards 
+$ 
+3,979 
+$ 
+5,331 
+$ 
+6,320 
+Unvested cash-settleable RSU awards 
+4,977 
+7,669 
+2,826 
+The Company’s unrecognized compensation cost related to unvested RSU and cash-settleable RSU awards is expected to be recognized over a weighted-average perio d of 1.6 years. 
+The following table summarizes the Company’s liability for cash-settle d RSU awards for the periods indicated: 
+December 31, 
+Consolidated Balance Sheets Classification 
+2014 
+2013 
+Cash-settled restricted stock unit awards - current 
+$ 
+3,856 
+$ 
+4,173 
+Cash-settled restricted stock unit awards - non-current 
+7,175 
+3,409 
+Total cash-settled RSU awards 
+$ 
+11,031 
+$ 
+7,582 
+79 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+Stock Options 
+The Company issued no stock options for the past three years and had no options vest or forfeit during 2014 . Additionally, no options were exercised, and 22,000 options expired unexercised during the year. As of December 31, 2014 , the Company had 30,000 options outstanding and exercisable at a weighted average exercise price per option of $14.04 , with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 1.3 years. 
+As of December 31, 2013, the Company had 52,000 options outstanding and exercisable at a weighted average exercise price per option of $13.75 , with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 2.3 years. As of December 31, 2012, the Company had 67,000 options outstanding and exercisable at a weighted average exercise price per option of $11.82 , with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 2.7 years. 
+Restricted Stock Units 
+The following table represents unvested restricted stock activity for the year ended December 31, 2014: 
+Weighted average 
+(shares in 000s) 
+Number of Shares 
+Grant-Date Fair Value per Share 
+Period over which expense is expected to be recognized 
+Outstanding at the beginning of the period 
+2,262 
+$ 
+5.03 
+Granted 
+333 
+9.67 
+Vested (a) 
+(684)
+6.34 
+Forfeited 
+(43)
+4.11 
+Outstanding at the end of the period 
+1,868 
+$ 
+5.40 
+1.2 
+(a) 
+The fair value of shares vested was $4,338 . 
+For the year ended December 31, 2013, the Company granted 944,000 RSUs with a weighted average grant-date fair value of $3.82 per share. The fair value of shares vested during 2013 was $2,689 . For the year ended December 31, 2012, the Company granted 1,008,000 RSUs with a weighted average grant-date fair value of $5.22 per share. The fair value of shares vested during 2012 was $2,817 . 
+Note 10 – Eq uity Transactions 
+10% Series A Cumulative Preferred Stock (“Preferred Stock”) 
+Holders of the Company’s Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10.0% per annum of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share). Dividends are payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by our Board of Directors. Preferred Stock dividend s were $7,895 and $4,627 in 2014 and 2013 , respectively. 
+The Preferred Stock has no stated maturity and is not be subject to any sinking fund or other mandatory redemption. On or after May 30, 2018, the Company may, at its option, redeem the Preferred Stock, in whole or in part, by paying $50.00 per share, plus any accrued and unpaid dividends to the redemption date. 
+Following a change of control, the Company will have the option to redeem the Preferred Stock, in whole but not in part for $50.00 per share in cash, plus accrued and unpaid dividends (whether or not declared), to the redemption date. If the Company does not exercise its option to redeem the Preferred Stock upon a change of control, the holders of the Preferred Stock have the option to convert the Preferred Stock into a number of shares of the Company’s common stock based on the value of the common stock on the date of the change of control as determined under the certificate of designations for the Preferred Stock. If the change of control occurred on December 31, 2014 , and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of the common stock on such date ( $5.45 ) as t he value of a share of common stock, each share of Preferred Stock would be convertible 
+80 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+into approximately 9.2 shares of common stock. If the Company exercises its redemption rights relating to shares of Preferred Stock, the holders of Preferred Stock will not have the conversion right described above. 
+Common Stock 
+On September 15, 2014 the Company completed an underwritten public offering of 12,500,000 shares of its common stock at $9.00 per share, before underwriting discounts, and the exercise in full by the underwriters of their option to purchase 1,875,000 additional shares of common stock at $9.00 per share. The Company received net proceeds of approximately $122,450 , after the underwriting discounts and estimated offering costs, which were used to fund a portion of the purchase price of the Acquisition (see Note 3 ) . 
+Note 11 - Inco me Taxes 
+The Company provides for income taxes at a statutory rat e of 35% adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses and state income taxes. The effective tax rate for the years ended December 31, 2014 and 2013 was 38% and 42% , respectivel y. 
+The following table presents Callon’s deferred tax assets and liabilities with respect to its carryforwards and other temporary differences: 
+As of December 31, 
+2014 
+2013 
+Deferred tax asset 
+Federal net operating loss carryforward 
+$ 
+86,629 
+$ 
+70,365 
+Statutory depletion carryforward 
+8,876 
+8,880 
+Alternative minimum tax credit carryforward 
+208 
+208 
+Asset retirement obligations 
+1,003 
+1,024 
+Other 
+6,621 
+7,575 
+Total deferred tax asset 
+103,337 
+88,052 
+Deferred tax liability 
+Oil and natural gas properties 
+54,723 
+26,412 
+Other 
+10,140 
+32 
+Total deferred tax liability 
+64,863 
+26,444 
+Net deferred tax asset 
+$ 
+38,474 
+$ 
+61,608 
+If not utilized, the Company’s federal operating loss (“NOL”) carryforwards will expire as follows: 
+Year Expiring 
+Total 
+2015-2020 
+2021-2023 
+2024-2026 
+2027-2029 
+2030-2034 
+Federal NOL carryforwards 
+$ 
+247,513 
+$ 
+— 
+$ 
+111,415 
+$ 
+14,408 
+$ 
+41,379 
+$ 
+80,311 
+The Company ’s current operations are located in Texas and are subject to the Texas margin tax. T he Company has established a full valuation allowance on the tax benefits associated with state net operating loss carryforwards of approximately $171,907 , which expire in years through 203 4 , related to other states in which the Company does not anticipate generating taxable state income. These amounts are not included in the deferred tax summary table above. 
+The Company had no significant unrecognized tax benefits at December 31, 2014 . Accordingly, the Company does not have any interest or penalties related to uncertain tax positions. However, if interest or penalties were to be incurred related to uncertain tax positions, such amounts would be recognized in income tax expense. Tax periods for years 200 1 through 2014 remain open to examination by the federal and state taxing jurisdictions to which the Company is subject. 
+81 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+Below is a reconciliation of the reported amount of income tax expense attributable to continuing operations to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income from continuing operations. 
+For the Year Ended December 31, 
+Components of income tax rate reconciliation 
+2014 
+2013 
+2012 
+Income tax expense computed at the statutory federal income tax rate 
+35% 
+35% 
+35% 
+Percentage depletion carryforward 
+—% 
+(8)% 
+(22)% 
+State taxes net of federal benefit 
+1% 
+4% 
+6% 
+Restricted stock and stock options 
+—% 
+5% 
+2% 
+Section 162(m) 
+2% 
+6% 
+22% 
+Other 
+—% 
+—% 
+4% 
+Effective income tax rate 
+38% 
+42% 
+47% 
+For the Year Ended December 31, 
+Components of income tax expense 
+2014 
+2013 
+2012 
+Current state income tax expense 
+$ 
+— 
+$ 
+326 
+$ 
+110 
+Deferred federal income tax expense 
+22,373 
+2,652 
+1,777 
+Deferred state income tax expense 
+761 
+126 
+336 
+Total income tax expense 
+$ 
+23,134 
+$ 
+3,104 
+$ 
+2,223 
+Note 12 - Asset Reti rement Obligations 
+The table below summarizes the activity for the Company’s asset retire ment obligations: 
+For the Year Ended December 31, 
+2014 
+2013 
+Asset retirement obligations at January 1, 2014 
+$ 
+6,732 
+$ 
+13,301 
+Accretion expense 
+826 
+1,785 
+Liabilities incurred 
+638 
+679 
+Liabilities assumed 
+140 
+— 
+Liabilities settled 
+(2,130)
+(457)
+Liabilities related to oil and gas properties sold 
+— 
+(4,765)
+Revisions to estimate 
+468 
+(3,811)
+Asset retirement obligations at end of period 
+6,674 
+6,732 
+Less: Current asset retirement obligations 
+(4,747)
+(4,120)
+Long-term asset retirement obligations at December 31, 2014 
+$ 
+1,927 
+$ 
+2,612 
+Certain of the Company’s operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded on the Consolidated Balance Sheets at December 31, 2014 as long-term restricted investments were $3,810 . These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties. 
+82 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+Note 13 – Supplemental Information on Oil and N atural Gas Properties (Unaudited) 
+The following table discloses certain financial data relating to the Company’s oil and natural gas activities, all of which are located in the United States. 
+For the Year Ended December 31, 
+2014 
+2013 
+2012 
+Evaluated Properties 
+Beginning of period balance 
+$ 
+1,701,577 
+$ 
+1,497,010 
+$ 
+1,421,640 
+Capitalized G&A 
+10,071 
+10,014 
+12,148 
+Property acquisition costs (a) 
+94,541 
+10,885 
+2,075 
+Exploration costs 
+118,251 
+147,164 
+22,703 
+Development costs 
+153,545 
+36,504 
+38,444 
+End of period balance 
+$ 
+2,077,985 
+$ 
+1,701,577 
+$ 
+1,497,010 
+Unevaluated Properties 
+Beginning of period balance 
+$ 
+43,222 
+$ 
+68,776 
+$ 
+2,603 
+Property acquisition costs (a) 
+128,342 
+2,259 
+29,590 
+Exploration costs 
+11,177 
+10,767 
+34,674 
+Capitalized interest 
+4,295 
+4,410 
+2,109 
+Transfers to evaluated 
+(44,511)
+(42,990)
+(200)
+End of period balance 
+$ 
+142,525 
+$ 
+43,222 
+$ 
+68,776 
+Accumulated depreciation, depletion and amortization 
+Beginning of period balance 
+$ 
+1,420,612 
+$ 
+1,296,265 
+$ 
+1,208,331 
+Provision charged to expense 
+56,663 
+42,251 
+48,524 
+Sale of mineral interests 
+1,080 
+82,096 
+39,410 
+End of period balance 
+$ 
+1,478,355 
+$ 
+1,420,612 
+$ 
+1,296,265 
+(a) 
+For more information on acquisitions refer to Note 3 
+Unevaluated property costs primarily include lease acquisition costs, unevaluated drilling costs, seismic, capitalized interest and certain overhead costs related to exploration and development. These costs are directly related to the acquisition and evaluation of unproved properties. The excluded costs and related reserves are included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined. The Company expects that the majority of these costs will be evaluated over the next three but within five years. 
+Subsequent to December 31, 2014 and through February 27, 2015, the Company completed five horizontal wells, drilled four horizontal wells and had two horizontal wells in progress. 
+Depletion per unit-of-production, on a BOE basis, amounted to $27.51 , $31.12 and $31.56 for the years ended December 31, 2014, 2013, and 2012, respectively. Lease operating expense s per unit-of-production, on a BOE basis, amounted to $10.85 , $14.00 , and $14.81 for the years ended December 31, 2014, 2013, and 2012, respectively. 
+Under the full cost accounting rules , the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full cost ceiling amount). These rules generally require pricing based on the preceding 12-months’ average oil and natural gas market prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling . Given the volatility of oil and natural gas prices, it is reasonably possible that the Company’s estimate of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. If oil and natural gas prices remain at current levels or decline further , even if only for a short period of time, write-downs of oil and natural gas properties could occur in the future. 
+83 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+Estimated Reserves 
+The Company’s proved oil and natural gas reserves at December 31, 2014 have been estimated by DeGolyer and MacNaughton, the Company’s current independent petroleum engineers. The Company’s proved oil and natural gas reserves at December 31, 2013 and 2012 were estimated by Huddleston & Co., Inc. The reserves were prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions. 
+There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only, and should not be deemed exact. In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company’s oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves. 
+Changes in the estimated net quantities of oil and natural gas reserves, all of which are located onshore within the continental United States and offshore within the Gulf of Mexico (prior to December 31, 2013), are as follows: 
+Reserve Quantities 
+For the Year Ended December 31, 
+2014 
+2013 
+2012 
+Proved developed and undeveloped reserves: 
+Oil (MBbls): 
+Beginning of period 
+11,898 
+10,780 
+10,075 
+Revisions to previous estimates 
+(243)
+(2,540)
+(488)
+Purchase of reserves in place 
+3,223 
+150 
+38 
+Sale of reserves in place 
+- 
+(3,294)
+(504)
+Extensions and discoveries 
+12,547 
+7,713 
+2,636 
+Production 
+(1,692)
+(911)
+(977)
+End of period 
+25,733 
+11,898 
+10,780 
+Natural Gas (MMcf): 
+Beginning of period 
+17,751 
+19,753 
+35,118 
+Revisions to previous estimates 
+(215)
+(5,351)
+(10,838)
+Purchase of reserves in place 
+8,591 
+317 
+115 
+Sale of reserves in place 
+- 
+(4,576)
+(4,404)
+Extensions and discoveries 
+18,641 
+10,619 
+3,350 
+Production 
+(2,220)
+(3,011)
+(3,588)
+End of period 
+42,548 
+17,751 
+19,753 
+Proved developed reserves: 
+Oil (MBbls): 
+Beginning of period 
+5,960 
+4,955 
+5,069 
+End of period 
+14,006 
+5,960 
+4,955 
+Natural gas (MMcf): 
+Beginning of period 
+9,059 
+10,680 
+11,605 
+End of period 
+25,171 
+9,059 
+10,680 
+MBOE: 
+Beginning of period 
+7,470 
+6,735 
+7,003 
+End of period 
+18,201 
+7,470 
+6,735 
+Proved undeveloped reserves: 
+Oil (MBbls): 
+Beginning of period 
+5,938 
+5,825 
+5,006 
+End of period 
+11,727 
+5,938 
+5,825 
+Natural gas (MMcf): 
+Beginning of period 
+8,692 
+9,073 
+23,513 
+End of period 
+17,377 
+8,692 
+9,073 
+MBOE: 
+Beginning of period 
+7,387 
+7,337 
+8,925 
+End of period 
+14,623 
+7,387 
+7,337 
+84 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+Total Proved Reserves: The Company ended 2014 with estimated net proved reserves of 32,824 MBOE, representing a 121% increase over 2013 year-end estimated net proved reserves of 14,857 MBOE. The increase wa s primarily due the Company’s development of its properties in the Permian Basin, on which it drilled a total of 34 gross ( 28.7 net) wells , and acquisitions made during 2014. This increase wa s primarily offset by 2014 production and revisions. 
+The Company ended 2013 with estimated net proved reserves of 14,857 MBOE, representing a 6% increase over 2012 year-end estimated net proved reserves of 14,072 MBOE. The increase was primarily due the Company’s development of its properties in the Permian Basin offset by the sale of the Company’s interest in the Medusa field and due to the Company’s reclassification of certain vertical PUD locations to the horizontal probable and PUD categories. 
+The Company ended 2012 with estimated net proved reserves of 14,072 MBOE, representing a 12% decrease over 2011 year-end estimated net proved reserves of 15,928 MBOE. The decrease was primarily due to the sale of the Company's interest in the Habanero field and the downward revision of our Haynesville Shale undeveloped reserves at year-end 2012, which were reduced due to low natural gas prices. These decreases were partially offset by the Company’s development of a portion of its Permian B asin, on which it drilled a total of 27 oil wells during 2012. 
+Extrapolation of performance history and material balance estimates were utilized by the Company’s independent petroleum and geological firm to project future recoverable reserves for the producing properties where sufficient history existed to suggest performance trends and where these methods were applicable to the subject reservoirs. The projections for the remaining producing properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to nonproducing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production, and to a small extent, horizontal PDP and PUD categories. 
+Proved Undeveloped Reserves: The Company annually reviews its proved undeveloped reserves (“PUDs”) to ensure an appropriate plan for development exists. Generally, reserves for the Company’s onshore properties are booked as PUDs only if the Company has plans to convert the PUDs into proved developed reserves within five years of the date they are first booked as PUDs. The Company’s PUDs increased 98% to 14,623 MBOE from 7,387 MBOE at December 31, 2014 and 2013, respectively. The Company added 10,125 MBOE to its PUDs, net of revisions, primarily from the continued horizontal development of its Permian Basin properties and from acquisitions in the Permian Basin. The increase in Permian Basin PUDs was partially offset by the reclassification of 1,757 MBOE, or 24% , included in the year-end 2013 PUD reserves, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately $34,619 , net. Also offsetting the increase was the removal of 1,132 MBOE of PUDs, including the impact from the reclassification of previous vertical PUDs to the horizontal probable category given our focus on horizontal development. 
+The Company’s PUDs increased 1% to 7,387 MBOE from 7,337 MBOE at December 31, 2013 and 2012, respectively. The Company added 5,168 MBOE to its PUDs, primarily from the continued horizontal development of its Permian Basin properties. The increase in Permian Basin PUDs was partially offset by 3,724 MBOE, or 51% , included in the year-end 2012 PUD reserves related to vertical PUD locations that were reclassified to horizontal probable reserves , and to a small extent, horizontal PDP and PUD categories. The reclassified vertical PUDs include locations that included certain target zones that were expected to be more efficiently developed by the Company’s multi-level horizontal drilling programs initiated in 2012. Also offsetting the Permian Basin PUD growth were the sale of 1,297 MBOE, or 18% , included in the year-end 2012 PUD reserves related to our Medusa field and the conversion of a small portion of 2012 PUD reserves to PDPs during 2013 from the drilling of vertical wells. 
+The Company's PUDs decreased 18% to 7,337 MBOE from 8,925 MBOE at December 31, 2012 and 2011, respectively. Additions during the year added 2,344 MBOE to the Company's PUDs, offset by (1) 557 MBOE primarily comprised of transfers to PDPs as a result of our development program, (2) 1,148 MBOE related to the sale of Habanero, and (3) 2,227 MBOE related to reductions in our PUD reserves, primarily related to the Haynesville Shale, by amounts no longer deemed to be economic PUDs at year-end. Of the Company's year-end 2011 PUD reserves, 6% were converted to proved developed producing reserves by year end 2012, at a total cost of approximately $19 million, net. 
+85 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+Standardized Measure 
+The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2014. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Prices are based on the preceding 12-months’ average price based on closing prices on the first day of each month. The following table summarizes the average 12-month oil and natural gas prices net of differentials for the respective periods: 
+2014 
+2013 
+2012 
+Average 12-month price, net of differentials, per Mcf of natural gas 
+$ 
+6.38 
+$ 
+5.45 
+$ 
+4.81 
+Average 12-month price, net of differentials, per barrel of oil 
+$ 
+86.30 
+$ 
+92.16 
+$ 
+94.68 
+Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate. 
+Natural gas production from our Permian Basin and former deepwater offshore properties has a high Btu content of separator natural gas. The natural gas per Mcf prices of $6.38, $5.45 and $4.81 used in the 2014, 2013 and 2012, respectively, reserve estimates include adjustments to reflect the Btu content, transportation charges and other fees specific to the individual properties. The oil prices per Bbl of $86.30, $92.16 and $94.68 used in the 2014, 2013 an d 2012 reserve estimates have been adjusted to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality. 
+Standardized Measure 
+For the Year Ended December 31, 
+2014 
+2013 
+2012 
+Future cash inflows 
+$ 
+2,492,178 
+$ 
+1,193,299 
+$ 
+1,115,570 
+Future costs 
+Production 
+(873,469)
+(357,005)
+(249,329)
+Development and net abandonment 
+(288,081)
+(155,667)
+(273,817)
+Future net inflows before income taxes 
+1,330,628 
+680,627 
+592,424 
+Future income taxes 
+(164,490)
+(68,239)
+(55,772)
+Future net cash flows 
+1,166,138 
+612,388 
+536,652 
+10% discount factor 
+(586,596)
+(328,442)
+(305,504)
+Standardized measure of discounted future net cash flows 
+$ 
+579,542 
+$ 
+283,946 
+$ 
+231,148 
+Changes in Standardized Measure 
+For the Year Ended December 31, 
+2014 
+2013 
+2012 
+Standardized measure at the beginning of the period 
+$ 
+283,946 
+$ 
+231,148 
+270,357 
+Sales and transfers, net of production costs 
+(120,518)
+(78,661)
+(84,044)
+Net change in sales and transfer prices, net of production costs 
+(156,066)
+(46,088)
+47,261 
+Net change due to purchases and sales of in place reserves 
+111,331 
+(145,711)
+(35,665)
+Extensions, discoveries, and improved recovery, net of future production and development costs incurred 
+299,192 
+212,431 
+53,446 
+Changes in future development cost 
+186,605 
+153,983 
+39,815 
+Revisions of quantity estimates 
+(7,673)
+(68,958)
+(77,322)
+Accretion of discount 
+30,114 
+25,010 
+30,989 
+Net change in income taxes 
+(32,940)
+1,751 
+13,969 
+Changes in production rates, timing and other 
+(14,449)
+(959)
+(27,658)
+Aggregate change 
+295,596 
+52,798 
+(39,209)
+Standardized measure at the end of period 
+$ 
+579,542 
+$ 
+283,946 
+$ 
+231,148 
+86 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+Note 14 – Other 
+Commitments and contingencies 
+The Company is involved in various claims and lawsuits incidental to its business. In the opinion of management, the ultimate liability hereunder, if any, will not have a material adverse effect on the financial position or results of operations of the Company. 
+The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment are not expected to have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies hereunder, and claims for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities. 
+Operating leases 
+In April 2012, the Company contracted a drilling rig (the “Cactus 1 Rig”), which it subsequently renewed in December 2014 for a term of two years ending November 2016. In April 2014, the Company contracted an additional horizontal drilling rig (the “Cactus 2 Rig”), which it subsequently renewed in December 2014 for a term of two years ending in November 2016. The Cactus 2 Rig replaced a previously contracted horizontal drilling rig, which was cancelled in March 2014. In August 2014, the Com pany signed a one-year contract for a vertical drilling rig to be used as part of its horizontal drilling program, drilling the vertical section of horizontal wells. The rig lease agreements include early termination provisions that would reduce the minimum rentals under the agreement, and also include provision s that would reduce the minimal rental payments assuming the lessor is able to re-charter the rig and staffing personnel to another lessee. Subsequent to December 31 , 2014, the Company decided to terminate its one-year contract for the vertical rig effective April 201 5 and currently may be required to pay approximately $3,733 in reduced rental payments over t he remainder of the lease term. Also subsequent to December 31, 2014 , the Company extended the terms of its Cactus 1 Rig and Cactus 2 Rig to end in July 2018 and August 2018, respectively. Lease payments in 2014 were $ 17,877 and are expected to approximate $ 16,893 (including early termination payments) , $10,980 , $10,950 and $6,510 i n 2015, 2016 , 2017 and 2018, respectively. 
+Other property and equipment 
+During 2012, the Company sold certain specialized deep water property and equipment valued at $527 and determined that certain equipment components were not usable without additional rework and thus recorded an impairment charge to with respect to such equipment of $1,177 . During 2013, after selling certain specialized deep water property and equipment valued at $114 , the Company made a decision to abandon the equipment. As such the Company recorded an impairment charge of $1,707 representing the remaining value of this equipment. During 2014, the Company entered into an agreement to sell the property and equipment to a third party. As a result of the subsequent sale of the property and equipment, the Company recognized a gain of $1,080 . 
+87 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+Note 15 – S ummarized Quarterly Financial Information (Unaudited) 
+2014 
+First Quarter 
+Second Quarter 
+Third Quarter 
+Fourth Quarter 
+Total revenues 
+$ 
+33,285 
+$ 
+40,502 
+$ 
+39,657 
+$ 
+38,418 
+Income from operations 
+6,645 
+12,080 
+11,562 
+7,983 
+Net income 
+1,863 
+4,740 
+12,201 
+18,962 
+Income (loss) available to common shares 
+(111)
+2,767 
+10,227 
+16,988 
+Income (loss) per common share - basic 
+$ 
+0.00 
+$ 
+0.07 
+$ 
+0.24 
+$ 
+0.31 
+Income (loss) per common share - diluted 
+$ 
+0.00 
+$ 
+0.07 
+$ 
+0.23 
+$ 
+0.30 
+2013 
+First Quarter 
+Second Quarter 
+Third Quarter 
+Fourth Quarter 
+Total revenues 
+$ 
+22,541 
+$ 
+22,760 
+$ 
+30,797 
+$ 
+26,471 
+Income from operations 
+898 
+957 
+6,345 
+2,464 
+Net income (loss) 
+(800)
+758 
+1,082 
+3,264 
+Income (loss) available to common shares 
+(800)
+78 
+(892)
+1,291 
+Income (loss) per common share - basic 
+$ 
+(0.02)
+$ 
+— 
+$ 
+(0.02)
+$ 
+0.03 
+Income (loss) per common share - diluted 
+$ 
+(0.02)
+$ 
+— 
+$ 
+(0.02)
+$ 
+0.03 
+88 
+Table of Contents 
+ITEM 9. Chan ges In and Disagreements With Accountants on Accounting and Financial Disclosure 
+There have been no disagreements with the independent auditors on any matters of accounting principles or practices, financial statement disclosure, or auditing scope or procedures. 
+Item 9A. Co ntrols and Procedures 
+Disclosure controls and procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our Chief Executive Officer and Chief Financial Officer performed an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2014. 
+Management’s report on internal control over financial reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. generally accepted accounting principles. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2014 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission ( 2013 framework)(the COSO criteria). Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2014 . 
+Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+The Company’s independent registered public accounting firm has issued an attestation report regarding its assessment of the Company’s internal control over financial reporting as of December 31, 2014 , which follows Part II, Item 9B of this filing. Additionally, the financial statements for each of the years covered in this Annual Report on Form 10-K have been audited by an independent registered public accounting firm, Ernst & Young LLP whose report is presented immediately preceding the Company’s financial statements included in Part II, Item 8 of this Annual Report on Form 10-K. 
+Changes in internal control over financial reporting . There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting. 
+ITEM 9A (T). Controls and Procedures 
+See Item 9A. 
+ITEM 9B. Othe r Information 
+Submissions of m atters to a v ote of the s ecurity h olders 
+None. 
+89 
+Table of Contents 
+Repo rt of Independent Registered Public Accounting Firm 
+The Board of Directors and Stockholders of 
+Callon Petroleum Company 
+We have audited Callon Petroleum Company’s internal control over financial reporting as of December 31, 201 4 based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ( 2013 framework)(the COSO criteria). Callon Petroleum Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. 
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+In our opinion, Callon Petroleum Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 201 4 , based on the COSO criteria. 
+We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Callon Petroleum Company as of December 31, 201 4 and 201 3 , and the related consolidated statements of operations, comprehensive income, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2014 , and our report dated March 4, 2015 expressed an unqualified opinion thereon. 
+/s/Ernst & Young LLP 
+New Orleans, Louisiana 
+March 4, 2015 
+90 
+Table of Contents 
+PAR T III. 
+ITEM 10. Direc tors, Executive Officers and Corporate Governance 
+For information concerning Item 10, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 14, 2015 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+The Company has adopted a code of ethics that applies to the Company’s chief executive officer, chief financial officer and chief accounting officer. The full text of such code of ethics has been posted on the Company’s website at www.callon.com, and is available free of charge in print to any shareholder who requests it. Request for copies should be addressed to the Secretary at mailing address Post Office Box 1287, Natchez, Mississippi 39121. 
+ITEM 11. Exec utive Compensation 
+For information concerning Item 11, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 14, 2015 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+ITEM 12. Sec urity Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+For information concerning the security ownership of certain beneficial owners and management, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 14, 2015 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+ITEM 13. C ertain Relationships and Related Transactions and Director Independence 
+For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 14, 2015 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+ITEM 14. Prin cipal Accountant Fees and Services 
+For information concerning Item 14, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 14, 2015 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+91 
+Table of Contents 
+Item 15 . Exh ibits 
+The following is an index to the financial statements and financial statement schedules that are filed in Part II, Item 8 of this report on Form 10-K. 
+Number 
+Exhibit 
+Description 
+1 
+The following is an index to the financial statements and financial statement schedules that are filed in Part II, Item 8 of this report on Form 10-K. 
+Report of Independent Registered Public Accounting Firm 
+Consolidated Balance Sheets as of December 31, 2014 and 2013 
+Consolidated Statements of Operations for each of the three years in the period ended December 31, 2014 
+Consolidated Statements of Stockholders’ Equity (Deficit) for each of the three years in the Period Ended December 31, 2014 
+Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2014 
+Notes to Consolidated Financial Statements 
+2 
+Schedules other than those listed above are omitted because they are not required, not applicable or the required information is included in the financial statements or notes thereto. 
+3 
+Exhibits 
+2 
+Plan of acquisition, reorganization, arrangement, liquidation or succession* 
+3 
+Articles of Incorporation and Bylaws 
+3.1 
+Certificate of Incorporation of the Company, as amended through January 17, 2014 (incorporated by reference to Exhibit 3.1 of the Company’s Form 10- Q filed on August 6, 2014 
+3.2 
+Certificate of Designation of Rights and Preferences of 10% Series A Cumulative Preferred Stock (incorporated by reference to Exhibit 3.5 of the Company’s Form 8-A filed on May 23, 2013. 
+3.3 
+Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408) 
+4 
+Instruments defining the rights of security holders, including indentures 
+4.1 
+Specimen Common Stock Certificate (incorporated by reference from Exhibit 4.1 of the Company’s Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408) 
+4.2 
+Certificate for the Company’s 10% Cumulative Preferred Stock (incorporated by reference to Exhibit 4.1 of the Company’s Form 8-A filed May 23, 2013 
+9 
+Voting trust agreement 
+None 
+10 
+Material contracts 
+10.1 
+Callon Petroleum Company 1996 Stock Incentive Plan as amended on May 9, 2000 (incorporated by reference from Appendix I of the Company’s Definitive Proxy Statement on Schedule 14A, filed March 28, 2000, File No. 001-14039) 
+10.2 
+Callon Petroleum Company 2002 Stock Incentive Plan (incorporated by reference to Exhibit 10.13 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2001, File No. 001-14039) 
+10.3 
+Amendment No. 3 to the Callon Petroleum Company 1996 Stock Incentive Plan (incorporated by reference from Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed January 5, 2009, File No. 001-14039) 
+10.4 
+Amendment No. 1 to the Callon Petroleum Company 2002 Stock Incentive Plan (incorporated by reference from Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed January 5, 2009, File No. 001-14039) 
+10.5 
+Callon Petroleum Company Amended and Restated 2006 Stock Incentive Plan (incorporated by reference from Exhibit 10.3 of the Company’s Current Report on Form 8-K, filed January 5, 2009, File No. 001-14039) 
+92 
+Table of Contents 
+10.6 
+Callon Petroleum Company 2009 Stock Incentive Plan effective as of April 30, 2009 (incorporated by reference from Exhibit A to the Company’s Definitive Proxy Statement on Schedule 14A, filed March 30, 2009, File No. 001-14039) 
+10.7 
+Amendment to the Callon Petroleum Company 1996 Stock Incentive Plan effective as of August 7, 2009 (incorporated by reference from Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2009, File No. 001-14039) 
+10.8 
+Callon Petroleum Company 2010 Phantom Share Plan, adopted May 4, 2010 (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on May 7, 2010) 
+10.9 
+Form of Callon Petroleum Company Phantom Share Award Agreement, adopted May 4, 2010 (incorporated by reference to Exhibit 10.2 of the Company’s current Report on Form 8-K filed on May 7 , 2010) 
+10.10 
+Deferred Compensation Plan for Outside Directors; Callon Petroleum Company (effective as of January 1, 2011) (incorporated by reference to Exhibit 10.17 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2010, File No. 001-14039) 
+10.11 
+Amended and Restated Severance Compensation Agreement, dated as of March 15, 2011 and effective as of January 1, 2011, by and between Fred L. Callon and Callon Petroleum Company (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on March 18, 2011) 
+10.12 
+Form of Amended and Restated Severance Compensation Agreement, dated as of March 15, 2011 and effective as of January 1, 2011, by and between Callon Petroleum Company and its executive officers (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed on March 18, 2011) 
+10.13 
+Callon Petroleum Company 2011 Omnibus Incentive Plan (incorporated by reference from Exhibit A of the Company’s Definitive Proxy Statement on Schedule 14A filed March 21, 2011, File No. 14039) 
+10.14 
+Agreement, dated March 9, 2014, among the Company and Lone Star Value Investors, L.P., Lone Star Value Co-Invest I, L.P., Lone Star Value Investors GP, LLC, Lone Star Value Management, LLC, Jeffery E. Eberwein and Matthew R. Bob (incorporated by reference from Exhibit 10.1 on Form 8-K, filed on March 10, 2014, File No. 001-14039) 
+10.15 
+Fifth Amended and Restated Credit Agreement among Callon Petroleum Company, JPMorgan Chase Bank, National Association, as administrative agent and the Lenders and parties named therein dated March 11, 2014 (incorporated by reference to Exhibit 10.1 to the Company’s Report on Form 10-Q/A filed June 11, 2014) 
+10.16 
+Operator Resignation and Transition Agreement between Callon Petroleum Operating Company and Henry Resources LLC dated August 29, 2014 (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed October 14, 2014) 
+10.17 
+Purchase and Sale Agreement between Callon Petroleum Operating Company, as Purchaser, and NAWAB energy partners, lp and NAWAB WI, lp, as Sellers, dated August 29, 2014 (incorporated by reference to Exhibit 10.2 of the Company’s Report on Form 8-K filed October 14, 2014) 
+10.18 
+Purchase and Sale Agreement between Callon Petroleum Operating Company, as Purchaser, and Hedloc Investment Co. LP, as Seller, dated August 29, 2014 (incorporated by reference to Exhibit 10.3 of the Company’s Report on Form 8-K filed October 14, 2014) 
+10.19 
+Amendment No. 2 to Fifth Amended and Restated Credit Agreement among Callon Petroleum Company, JPMorgan Chase Bank, National Association, as administrative agent and the Lenders and parties named therein dated October 8, 2014 (incorporated by reference to Exhibit 10.4 of the Company’s Report on Form 8-K filed October 14, 2014) 
+10.20 
+Second Lien Credit Agreement among Callon Petroleum Company, Royal Bank of Canada and the Lenders party thereto, dated October 8, 2014 (incorporated by reference to Exhibit 10.5 of the Company’s Report on Form 8-K filed October 14, 2014) 
+10.21 
+Second Lien Intercreditor Agreement among Callon Petroleum Company, JPMorgan Chase Bank, National Association, Royal Bank of Canada, and the other parties named therein dated October 8, 2014 (incorporated by reference to Exhibit 10.6 of the Company’s Report on Form 8-K filed October 14, 2014) 
+11 
+Statement re computation of per share earnings* 
+12 
+Statements re computation of ratios* 
+13 
+Annual Report to security holders, Form 10-Q or quarterly reports* 
+14 
+Code of Ethics 
+14.1 
+Code of Ethics for Chief Executive Officers and Senior Financial Officers (incorporated by reference to Exhibit 14.1 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-14039) 
+16 
+Letter re change in certifying accountant* 
+93 
+Table of Contents 
+18 
+Letter re change in accounting principles* 
+21 
+Subsidiaries of the Company 
+21.1 
+Subsidiaries of the Company 
+22 
+Published report regarding matters submitted to vote of security holders* 
+23 
+Consents of experts and counsel 
+23.1 
+Consent of Ernst & Young LLP 
+23.2 
+Consent of DeGolyer and MacNaughton, Inc. 
+23.3 
+Consent of Huddleston & Co., Inc. 
+24 
+Power of attorney* 
+31 
+Rule 13a-14(a) Certifications 
+31.1 
+Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a) 
+31.2 
+Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a) 
+32 
+Section 1350 Certifications of Chief Executive and Financial Officers pursuant to 
+Rule 13(a)-14(b) 
+99 
+Additional Exhibits 
+99.1 
+Reserve Report Summary prepared by DeGolyer and MacNaughton, Inc. as of December 31, 201 4 
+101 
+Interactive Data Files ** 
+* 
+Not applicable to this filing 
+** 
+Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability. 
+94 
+Table of Contents 
+SIGN ATURES 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+Callon Petroleum Company 
+Date: 
+March 4, 2015 
+/s/ Joseph C. Gatto, Jr. 
+By: Joseph C. Gatto, Jr., senior vice president, 
+chief financial officer (principal financial officer) and treasurer 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+Date: 
+March 4 , 201 5 
+/s/ Fred L. Callon 
+Fred L. Callon (principal executive officer, director) 
+Date: 
+March 4, 2015 
+/s/ Joseph C. Gatto, Jr. 
+Joseph C. Gatto, Jr. (principal financial officer) 
+Date: 
+March 4, 2015 
+/s/ Mitzi P. Conn 
+Mitzi P. Conn (principal accounting officer) 
+Date: 
+March 4, 2015 
+/s/ L. Richard Flury 
+L. Richard Flury (director) 
+Date: 
+March 4, 2015 
+/s/ John C. Wallace 
+John C. Wallace (director) 
+Date: 
+March 4, 2015 
+/s/ Anthony J. Nocchiero 
+Anthony J. Nocchiero (director) 
+Date: 
+March 4, 2015 
+/s/ Larry D. McVay 
+Larry McVay (director) 
+Date: 
+March 4, 2015 
+/s/ Matthew R. Bob 
+Matthew R. Bob (director) 
+Date: 
+March 4, 2015 
+/s/ James M. Trimble 
+James M. Trimble (director) 
+95
\ No newline at end of file
diff --git a/raw/filings/0000928022/2014/0000928022-15-000032/filing_metadata.csv b/raw/filings/0000928022/2014/0000928022-15-000032/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..bcb3f037fc958b96c5f70a6a7aab6dedf9deee58
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@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000928022,CPE,Callon Petroleum Co,10-K,2015-03-05,2014-12-31,2015-03-04T23:51:16.000Z,0000928022-15-000032,cpe-20141231x10k.htm,10-K,21358466,1,0,https://www.sec.gov/Archives/edgar/data/928022/000092802215000032/cpe-20141231x10k.htm,https://www.sec.gov/Archives/edgar/data/928022/000092802215000032/,2014,2014,1
diff --git a/raw/filings/0000928022/2014/0000928022-15-000032/item1.txt b/raw/filings/0000928022/2014/0000928022-15-000032/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000928022/2014/0000928022-15-000032/item13.txt b/raw/filings/0000928022/2014/0000928022-15-000032/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..9b7b9df2a156a52f30620724690d3fe0314e08b3
--- /dev/null
+++ b/raw/filings/0000928022/2014/0000928022-15-000032/item13.txt
@@ -0,0 +1,2 @@
+ITEM 13. C ertain Relationships and Related Transactions and Director Independence 
+For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 14, 2015 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2014/0000928022-15-000032/item9a.txt b/raw/filings/0000928022/2014/0000928022-15-000032/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..7cd68d0f6a2810fb7af882c4d72870a7101ea515
--- /dev/null
+++ b/raw/filings/0000928022/2014/0000928022-15-000032/item9a.txt
@@ -0,0 +1,8 @@
+Item 9A. Co ntrols and Procedures 
+Disclosure controls and procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our Chief Executive Officer and Chief Financial Officer performed an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2014. 
+Management’s report on internal control over financial reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. generally accepted accounting principles. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2014 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission ( 2013 framework)(the COSO criteria). Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2014 . 
+Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+The Company’s independent registered public accounting firm has issued an attestation report regarding its assessment of the Company’s internal control over financial reporting as of December 31, 2014 , which follows Part II, Item 9B of this filing. Additionally, the financial statements for each of the years covered in this Annual Report on Form 10-K have been audited by an independent registered public accounting firm, Ernst & Young LLP whose report is presented immediately preceding the Company’s financial statements included in Part II, Item 8 of this Annual Report on Form 10-K. 
+Changes in internal control over financial reporting . There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting. 
+ITEM 9A (T). Controls and Procedures 
+See Item 9A.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2014/0000928022-15-000032/rp_note.txt b/raw/filings/0000928022/2014/0000928022-15-000032/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000928022/2014/0000928022-15-000032/rpt_disclosure.txt b/raw/filings/0000928022/2014/0000928022-15-000032/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..ac2a47d652c5f0d3c5750bc35f4c31257c1b9c10
--- /dev/null
+++ b/raw/filings/0000928022/2014/0000928022-15-000032/rpt_disclosure.txt
@@ -0,0 +1,13 @@
+Certain Relationships and Related Party Transactions 
+The Board’s Audit Committee charter provides that the Audit Committee shall review and approve all related party transactions. A transaction will be considered a “related party transaction” if the transaction would be required to be disclosed under Item 404 of Regulation S-K. In addition, our Code of Business Conduct and Ethics provides that an officer’s or a Director’s conflict of interest with Callon may only be waived if the Nominating and Corporate Governance Committee approves the waiver and the full Board ratifies the waiver. As of December 31, 2015, we are not aware of any related party transactions with our executive officers that may cause a conflict of interest with us. 
+Recoupment Policy 
+We have no recoupment policy applicable to annual incentive bonuses or equity awards other than those required under Sarbanes-Oxley legislation, though the Committee continuously evaluates the need to adopt such a policy. 
+Compensation Committee Report 
+The Compensation Committee has reviewed and discussed with management the CD&A required by Item 402(b) of Regulation S-K promulgated under the Securities Exchange Act of 1934, as amended, and based on such review and discussions, the Committee has recommended to the Board that the CD&A be included in this proxy statement relating to the 2016 Annual Meeting of Stockholders. 
+Respectfully submitted by the Compensation Committee of the Board, 
+L. Richard Flury, Chairman 
+Larry D. McVay 
+Anthony J. Nocchiero 
+John C. Wallace 
+James M. Trimble 
+44
\ No newline at end of file
diff --git a/raw/filings/0000928022/2015/0000928022-16-000132/filing.txt b/raw/filings/0000928022/2015/0000928022-16-000132/filing.txt
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index 0000000000000000000000000000000000000000..a455094e22be20606b1dd360e707536a53f8b1e1
--- /dev/null
+++ b/raw/filings/0000928022/2015/0000928022-16-000132/filing.txt
@@ -0,0 +1,5469 @@
+10-K
+1
+cpe-20151231x10k.htm
+10-K
+2015_CPE_Form_10-K
+UNITED STATES SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+FORM 10-K 
+☒ ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For The Fiscal Year Ended December 31, 2015 
+OR 
+☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934 
+For the transition period from ____________ to ____________ 
+Commission File Number 001-14039 
+Callon Petroleum Company 
+(Exact Name of Registrant as Specified in Its Charter) 
+Delaware 
+(State or Other Jurisdiction of 
+Incorporation or Organization) 
+64-0844345 
+(IRS Employer 
+Identification No.) 
+200 North Canal Street 
+Natchez, Mississippi 
+(Address of Principal Executive Offices) 
+39120 
+(Zip Code) 
+601-442-1601 
+(Registrant’s Telephone Number, Including Area Code) 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of Each Class 
+Name of Each Exchange on Which Registered 
+Common Stock, $.01 par value 
+New York Stock Exchange 
+10.0% Series A Cumulative Preferred Stock 
+New York Stock Exchange 
+Securities registered pursuant to section 12 (g) of the Act: None 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒ 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒ 
+Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ 
+Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐ 
+Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant ’ s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒ 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition s of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (check one): 
+Large accelerated filer 
+☐ 
+Accelerated filer 
+☒ 
+Non-accelerated filer 
+☐ 
+(Do not check if smaller reporting company) 
+Smaller reporting company 
+☐ 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ 
+Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 201 5 was approximately $537.5 million. The Registrant had 80,843,938 shares of common stock outstanding as of February 26, 2016 . 
+DOCUMENTS INCORPORATED BY REFERENCE 
+Portions of the definitive Proxy Statement of Callon Petroleum Company (to be filed no later than 120 days after December 31, 2015 ) relating to the Annual Meeting of Stockholders to be held on May 12, 2016 , which are incorporated into Part III of this Form 10-K. 
+Table of Contents 
+TABLE OF CONTENTS 
+Special Note Regarding Forward-Looking Statements 
+3 
+Definitions 
+4 
+Part I 
+Items 1 and 2. 
+Business and Properties 
+5 
+Exploration and Development Activity 
+7 
+Oil and Natural Gas Properties 
+8 
+Reserves and Production 
+9 
+Production Wells and Leasehold Acreage 
+12 
+Other 
+14 
+Regulations 
+16 
+Available Information 
+16 
+Item 1A. 
+Risk Factors 
+24 
+Item 1B. 
+Unresolved Staff Comments 
+36 
+Item 3. 
+Legal Proceedings 
+36 
+Item 4. 
+Mine Safety Disclosures 
+36 
+Part II 
+Item 5. 
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+37 
+Performance Graph 
+38 
+Item 6. 
+Selected Financial Data 
+39 
+Item 7. 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+40 
+Overview and Outlook 
+42 
+Liquidity and Capital Resources 
+43 
+Results of Operations 
+48 
+Significant Accounting Policies and Critical Accounting Estimates 
+56 
+Item 7A. 
+Quantitative and Qualitative Disclosures About Market Risk 
+60 
+Item 8. 
+Financial Statements and Supplementary Data 
+62 
+Report of Independent Registered Public Accounting Firm 
+63 
+Consolidated Balance Sheets 
+64 
+Consolidated Statements of Operations 
+65 
+Consolidated Statements of Stockholders’ Equity 
+66 
+Consolidated Statements of Cash Flows 
+67 
+Notes to Consolidated Financial Statements 
+68 
+Item 9. 
+Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+91 
+Item 9A. 
+Controls and Procedures 
+91 
+Item 9B. 
+Other Information 
+92 
+Report of Independent Registered Public Accounting Firm 
+93 
+Part III 
+Item 10. 
+Directors and Executive Officers and Corporate Governance 
+94 
+Item 11. 
+Executive Compensation 
+94 
+Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+94 
+Item 13. 
+Certain Relationships and Related Transactions and Director Independence 
+94 
+Item 14. 
+Principal Accountant Fees and Services 
+94 
+Part IV 
+Item 15. 
+Exhibits 
+95 
+Signatures 
+98 
+2 
+Table of Contents 
+Special N ote Regarding Forward Looking Statements 
+All statements, other than statements of historical fact, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve quantities, present value and growth and other plans and objectives for our future operations, are forward-looking statements. Although we believe the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance. 
+Forward-looking statements include the items identified in the preceding paragraph, information concerning possible or assumed future results of operations and other statements in this Form 10- K identified by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions. 
+You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect our operations, markets, products, services and prices, and cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause our actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to: 
+· 
+the timing and extent of changes in market conditions and prices for oil, natural gas and NGLs (including regional basis differentials) ; 
+· 
+our ability to transport our production to the most favorable markets or at all ; 
+· 
+the timing and extent of our success in discovering, developing, producing and estimating reserves ; 
+· 
+our ability to fund our planned capital investments ; 
+· 
+the impact of government regulation, including regulation of endangered species, any increase in severance or similar taxes ; legislation relating to hydraulic fracturing, the climate and over-the-counter derivatives ; 
+· 
+the costs and availability of oilfield personnel services and drilling supplies, raw materials, and equipment and services ; 
+· 
+our future property acquisition or divestiture activities ; 
+· 
+the effects of weather ; 
+· 
+increased competition ; 
+· 
+the financial impact of accounting regulations and critical accounting policies ; 
+· 
+the comparative cost of alternative fuels ; 
+· 
+conditions in capital markets, changes in interest rates and the ability of our lenders to provide us with funds as agreed ; 
+· 
+credit risk relating to the risk of loss as a result of non-performance by our counterparties ; and 
+· 
+any other factors listed in the reports we have filed and may file with the SEC. 
+We caution you that the forward-looking statements contained in this Form 10- K are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. These risks include, but are not limited to, the risks described in Item 1A of this Annual Report on Form 10-K for the year ended December 31, 2015 (the “ 2015 Annual Report on Form 10-K”), and all quarterly reports on Form 10-Q filed subsequently thereto. 
+Should one or more of the risks or uncertainties described above or in our 2015 Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. 
+All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement. 
+3 
+Table of Contents 
+DEFIN ITIONS 
+All defined terms under Rule 4-10(a) of Regulation S-X shall have their prescribed meanings when used in this report. As used in this document: 
+· 
+ARO : a sset retirement obligation. 
+· 
+Bbl or Bbls : barrel or barrels of oil or natural gas liquids. 
+· 
+Bcf : Billion cubic feet of natural gas. 
+· 
+BOE : barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas. The ratio of one barrel of oil or NGL to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas. 
+· 
+BBtu : billion Btu . 
+· 
+BOE/d : BOE per day. 
+· 
+BLM: Bureau of Land Management. 
+· 
+Btu : a British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit. 
+· 
+DOI: Department of Interior. 
+· 
+EPA: Environmental Protection Agency. 
+· 
+FASB: Financial Accounting Standards Board . 
+· 
+GAAP: Generally Accepted Accounting Principles in the United States. 
+· 
+GHG: greenhouse gases. 
+· 
+LIBOR : London Interbank Offered Rate. 
+· 
+LOE: lease operating expense , including workover expense . 
+· 
+MBbls : thousand barrels of oil. 
+· 
+MBOE : thousand BOE. 
+· 
+MBOE/d : M BOE per day. 
+· 
+Mcf : thousand cubic feet of natural gas. 
+· 
+MMBbls : million barrels of oil. 
+· 
+MMBOE : million BOE. 
+· 
+MMBtu : million Btu. 
+· 
+MM cf : million cubic feet of natural gas. 
+· 
+MMcf/d : MMcf per day. 
+· 
+NGL or NGLs : natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams. 
+· 
+NYMEX : New York Mercantile Exchange. 
+· 
+Oil : includes crude oil and condensate. 
+· 
+OPEC: Organization of Petroleum Exporting Countries 
+· 
+PDPs : proved developed producing reserves. 
+· 
+PDNPs : proved developed non-producing reserves. 
+· 
+PUDs : proved undeveloped reserves. 
+· 
+RSU : restricted stock units. 
+· 
+SEC : United States Securities and Exchange Commission. 
+With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross. 
+4 
+Table of Contents 
+PA RT I. 
+Ite ms 1 and 2 – Business and Properties 
+Overview 
+Callon Petroleum Company has been engaged in the exploration, development, acquisition and production of oil and natural gas properties since 1950. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. 
+Our asset base is concentrated in the Midland Basin, a sub-basin located within the broader Permian Basin. Our drilling activity during 2015 focused on the horizontal development of several prospective intervals, including multiple levels of the Wolfcamp formation and, more recently, the Lower Spraberry shale. As a result of our acquisition and horizontal development efforts, our net daily production for calendar year 2015 as compared to calendar year 2014 grew approximately 70% to 9,610 BOE/d (approximately 80% oil) . We have assembled a multi-year inventory of potential horizontal well locations and intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and acquisition of additional locations through acreage purchases, joint ventures and asset swaps. In response to the low commodity price environment, we announced in early February our plans to shift from a two rig program to a single active rig in March 2016. We intend to monitor opportunities to redeploy our second drilling rig on our asset base if market conditions improve or in conjunction with potential acquisitions of new acreage. 
+As of December 31, 2015 , our net proved reserve volumes increased 65% as compared to year-end 2014 to 54.3 MMBOE, comprised of 80% crude oil including 43.3 MMBbls with the remaining 20% natural gas of 65.5 Bcf. A pproximately 53% of our net proved year-end 2015 reserves were proved developed on a BOE basis. 
+Our Business Strategy 
+Our goal is to enhance stockholder value through the execution of the following strategy with an emphasis on safety : 
+Maintain fiscal discipline, financial liquidity and our capacity to capitalize on inorganic growth opportunities. We recognize that it takes fiscal discipline and a keen focus on controlling capital allocation and operating costs to operate in a commodity price environment where prices have fallen significantly over the past 18 months. To that end, we intend to continue to work with our service partners to reduce drilling, completion and operating costs while also working internally to reduce our overhead costs. For example, in early 2016, we announced plans to moderate our development pace and preserve liquidity by transitioning to a one-rig drilling program that allows us to reduce our 2016 operational capital budget by nearly 35% but which we believe will still provide for year-over-year production growth. We also raised approximately $1 83.7 million in gross proceeds from two common equity offerings during 2015 to support recent acquisitions and our ongoing development efforts in the Midland Basin. Collectively, we believe that the reduction in planned capital expenditures, a 20% increase in the borrowing base under our senior secured revolving credit facility received after our fall 2015 redetermination and the successful raise of proceeds through the sale of common stock during 2015 position us to maintain sufficient liquidity and remain flexible in an uncertain commodity price environment with the ability to increase our acreage footprint through potential acquisition opportunities. 
+Drive production and maximize resource recovery and reserve growth through horizontal development of our resource base. We entered the Midland Basin in 2009 focused on a vertical development program that allowed us to amass a comprehensive database of subsurface geologic and other technical data. This internally derived data in conjunction with our analysis of offsetting and nearby industry activity and best practices, positioned us in 2012 to transition to efficient, multi-pad horizontal development. The success of our horizontal development is reflected in our significant year-over-year production growth, which increased 70% in 2015 to 3,508 MB OE ( 9,610 B OE /d) compared to 2,062 M B OE ( 5,649 B O E /d) in 2014. Additionally, we grew reserves 65% in 2015 to 54.3 MMB OE from 32.8 MMB OE at year-end 2014, including reserve extensions and discoveries replacement in 2015 of 22.4 MMBOE . We intend to continue to grow the contribution of horizontal production volumes, both from our existing properties and from properties acquired in recent acquisitions, as we continue to execute a resource development program almost exclusively focused on horizontal development. 
+Expand our drilling portfolio through evaluation of existing acreage. Given the challenging commodity price environment, capital allocation decisions have become increasingly important. We have shifted almost all of our near-term development focus to the Lower Spraberry given its potential for strong capital efficiency and returns on capital. However, we intend to continue our efforts to expand 
+5 
+Table of Contents 
+our drilling inventory through selective delineation of additional zones. During 2015, we successfully added the Middle Spraberry to our list of producing zones within our acreage, increasing our producing zone count to five distinct zones including the Lower Spraberry, Wolfcamp A and the Upper and Lower Wolfcamp B zones. We believe incremental opportunities exist to selectively target other prospective zones across various positions of our acreage, including the Clearfork, Jo Mill, Wolfcamp C and Cline (also called the Wolfcamp D) formations (in order of relative depth). In addition, we will continue to monitor the efficiency of our horizontal wells related to reservoir drainage over time, and will pursue down-spacing initiatives within target zones if we believe overall returns would be enhanced. For example, based on an analysis of our own producing wells coupled with our assessment of peer activity, we recently increased our Lower Spraberry wells per section from seven wells-per-section to ten wells-per-section. We will continue to evaluate our well spacing with an eye towards maximizing resource recovery. 
+Pursue selective acquisitions in the Permian Basin. During 2015, we continued to acquire and trade acreage in the Midland Basin despite a volatile commodity price environment which is typically characterized by divergent views of asset valuation. In 2015, w e acquired nearly 628 net acres located in our existing Carp e Diem and CaBo area (Cassleman- Bohannon fields) located primarily in Midland and Andrews Counties for approximately $29. 8 million. We also recently acquired 305 net acres located in our CaBo area for approximately $9.3 million. Together, the acquisitions added production of 530 BOE/d (81% oil) and added 56 net potential horizontal drilling locations across all prospective zones, including 42 net potential horizontal drilling locations in currently producing Middle Spraberry, Lower Spraberry, Wolfcamp A and Wolfcamp B zones. Importantly, since the acquired acreage was located within our existing Central Midland Basin area where we have focused our near-term development efforts, we are able to immediately earn returns on these incremental investments. We also remain committed to our “bolt-on” strategy of expanding our asset base by identifying and pursuing smaller blocks of offsetting acreage that are potentially inefficient for the current owners to develop but have value to Callon based on their location relative to our acreage. These smaller scale acquisitions generally provide acreage at costs below the value assigned to larger blocks of acreage. While remaining focused on preserving a high level of liquidity, we plan to continue to pursue leasehold acquisitions in the Permian Basin with horizontal resource potential that can also be further expanded by “bolt-on acreage” acquisitions and acreage trades over time. 
+Our Strengths 
+Established resource base and acreage position in the core of Permian Basin . Our production is exclusively from the Permian Basin in West Texas, an area that has supported production since the 1940s. The B asin has well established infrastructure from historical operations, and we believe the Basin also benefits from a relatively stable regulatory environment that has been established over time. We have assembled a position of approximately 17,675 net surface acres in the Southern and Central Midland Basin that are prospective for multiple oil-bearing intervals that have been produced by us and other industry participants. As o f December 31, 2015 , our estimated net proved reserves were comprised of approximately 80% oil and 20% natural gas, which include s NGLs in the production stream. 
+Economic, multi-year drilling inventory in a lower commodity price environment . O ur current acreage position in the Permian Basin provides growth potential from a horizontal drilling inventory of approximately 504 gross locations based solely on five currently producing zones, including the Lower Spraberry, Middle Spraberry, Wolfcamp A and the Upper and Lower Wolfcamp B. Our identified well locations across our Southern and Central Midland Basin acreage are based upon the results of horizontal wells drilled by us and other offsetting operators and by our analysis of core data and historical vertical well performance. To the extent that long-term production data and microseismic data support the potential for reduced spacing between lateral wellbores to improve total resource recoveries, our number of drilling locations may increase over time. 
+Experienced team operating in the Permian Basin. We have assembled a management team experienced in acquisitions, exploration, development and production in the Midland Basin. Reflective of this experience, we were an early adopter of efficient multi-well pad development, transitioning to this development model in 2012 which enabled us to realize improvements in our drilling and capital. Since 2012, we have drilled more than 9 0 horizontal wells with lengths varying from approximately 5,000 feet to 10,000 feet, and we continue to evaluate our completion techniques. In addition, we regularly evaluat e our operating results against those of other operators in the area in an effort to benchmark our performance against the best performing operators and evaluate and adopt best practices. We believe that the experience of our team is highlighted by our success in achieving significantly lower well capital costs and reducing our operating cost structure to generate the operating margins and capital efficiency to operate effectively in the current environment. 
+6 
+Table of Contents 
+Significant amount of operational control . We operate nearly all of our Permian Basin acreage and have no drilling obligations within our acreage base, providing us a distinct advantage that enables us to modify our operational plans quickly and drill in areas that offer highest return on capital potential. For example, as commodity prices continued to decline throughout 2015, we announced in the third quarter our plans to shift our development plan exclusively to our Central Midland acreage to focus on the Lower Spraberry which has demonstrated strong returns on capital. Our operating team reacted quickly to pivot our operations and worked with our service partners to coordinate a smooth and efficient transition to the new plan while meeting our previous production targets. 
+Operating culture focused on safety and the environment. We have a Health, Safety and Environmental (“HSE”) department dedicated to our operations in the Permian Basin. This group is responsible for developing and implementing work processes to mitigate safety and environmental risks associated with our work activities. With emphasis on leadership engagement, planning, training and communication, and empowering both our employees and third party service providers with Stop Work Authority, we continue to improve operational performance. We have enhanced Management of Change, routine facility maintenance and inspections, and compliance action tracking methods with the implementation of a HSE management system software program. We also utilize the program to distribute all incident reports, including near miss events and safety observations to track trends, learn from our mistakes and implement corrective actions to drive improvement across our operations. This department also coordinates closely with our operational team to ensure effective communication with appropriate regulatory bodies as well as landowners. We believe that our proactive efforts in this area have made a positive impact on our operations and culture. 
+Exploration and Development Activities 
+Our 2015 total capital expenditures, including acquisitions, on a cash basis were $259.5 million , representing a 43 % d ecrease over 2014 capital expenditures. Of th e $259.5 million, $205.7 mil lion was allocated to operational capital expenditures, including drilling, development and leasehold acquisition activity. During 2015 , we drilled 3 6 gross ( 27.1 net) horizontal and no vertical wells, while completing 33 gross ( 2 5.8 net) horizontal and 1 gross ( 0 . 4 net) vertical wel ls. 
+Capital expenditures , on a cash basis, include the following for the periods indicated (in millions): 
+For the Year Ended December 31, 
+2015 
+2014 
+Southern Midland Basin 
+$ 
+118.0 
+$ 
+160.3 
+Central Midland Basin 
+87.7 
+56.9 
+Other 
+— 
+0.5 
+Total operational expenditures 
+205.7 
+217.7 
+Capitalized general and administrative costs allocated directly to 
+exploration and development projects 
+11.1 
+12.5 
+Capitalized interest 
+10.5 
+2.4 
+Total capitalized general and administrative and interest costs 
+21.6 
+14.9 
+Total operational expenditures inclusive of capitalized general 
+and administrative and interest costs 
+227.3 
+232.6 
+Acquisitions 
+32.2 
+222.9 
+Total capital expenditures 
+$ 
+259.5 
+$ 
+455.5 
+In January 2016, we announced an operational capital budget for 2016 in the range of $75 to $80 million on an accrual, or GAAP, basis . In the first quarter of 2016 we plan to transition from a two-rig to a one-rig program , retaining the option to quickly redeploy the second rig to either our existing acreage or new acreage related to an y potential acquisition opportunit ies . We expect o ur 2016 horizontal drilling program will focus almost exclusively on the Lower Spraberry zone in the Central Midland Basin with lateral lengths ranging from approximately 5,000’ laterals to 9,000’ laterals. All wells will be completed from two to three well pads. We plan to have 19 gross (1 3.7 net) operated horizontal wells scheduled to be placed on production t arget ing the Lower Spraberry shale during 2016 . Also, we plan to have two gross (0.4 net) non-operated horizontal wells scheduled to be placed on production during 2016 targeting the Lower Spraberry and Wolfcamp A shale. The two non-operated horizonta l wells will be 10,000’ laterals that leverage our existing acreage position. 
+7 
+Table of Contents 
+Recent Developments 
+In the first quarter of 2016, we completed the acquisiti on of an additional 4.9% working interest ( 3.7% net revenue interest) in our Ca sselman-B o hannon fields for total cash consideration of $9.3 million, excluding customary purchase price adjustments. We currently own a 71.3% working interest ( 53.5% net revenue interest) in the Ca sselman-B o hannon fields following the completion of this recent acquisition. 
+Oil and Natural Gas Properties 
+As of December 31, 2015 , our estimated net proved reserves totale d 54.3 MMBOE and include d 43.3 MMBbls of oil an d 65.5 Bcf, of natural gas with a pre-tax present value, discounted at 10%, of $574.6 million. Pre-tax present value is a non-GAAP financial measure, which we reconcile to the GAAP measure of standardized measure of $570.9 million. Oil constituted approximately 80% of our total estimated equivalent net proved reserves and approximately 78% of our total estimated equivalent proved developed reserves. 
+The following table sets forth certain information about our estimated net proved reserves prepared by our independent petroleum reserve engineers by major area at December 31, 2015 : 
+Estimated Net Proved Reserves 
+Oil 
+(MBbls) 
+Natural Gas 
+(MMcf) 
+Total 
+(MBoe) (a) 
+Southern Midland Basin 
+17,867 
+36,218 
+23,903 
+Central Midland Basin 
+25,481 
+29,319 
+30,368 
+Total 
+43,348 
+65,537 
+54,271 
+(a) 
+We convert Mcf to BOE using a conversion ratio of six Mcf to one Bbl. This ratio, which is typical in the industry and represents the approximate energy equivalent of a Mcf to a Bbl, does not reflect to market price equivalence of Mcf of natural gas compared with a Bbl of oil or NGLs. On a market price equivalence basis, a barrel of oil or NGLs has a substantially higher price than six Mcf of natural gas. 
+Permian Basin 
+As of December 31, 2015 , we owned leaseholds in 17,675 net acres in the Permian Basin. Average net production from our Permian Basin properties increased 70% to 9,610 BOE/d in 2015 from 5,649 BOE/d in 2014 . 
+Our Southern Midland Basin area is comprised of fields located in Upton, Reagan and Crockett Counties, Texas. We commenced our horizontal development efforts for the Permian Basin in this region in 2012. Our Central Midland Basin area, encompassing Midland, Ector, Andrews and Martin Counties, began to transition to horizontal development in 2013. 
+Producing Wells 
+Net Daily 
+Horizontal 
+Vertical 
+Producing 
+Region 
+Net Acres 
+Production 
+Gross 
+Net 
+Gross 
+Net 
+Horizontal Zones 
+Southern Midland Basin 
+9,766 
+5,860 
+54 
+51 
+36 
+31 
+Upper Wolfcamp B 
+Lower Wolfcamp B 
+Wolfcamp A 
+Central Midland Basin 
+7,909 
+3,745 
+29 
+22 
+197 
+137 
+Lower Spraberry 
+Middle Spraberry 
+Wolfcamp B 
+Total Permian Basin 
+17,675 
+9,605 
+83 
+73 
+233 
+168 
+During 2015, we allowed our entire Northern Midland Basin position o f 9,3 01 net acres to expire as we refined our targeted areas for exploration. For additional details regarding our Permian wells and related information, please see “Present Activities and Productive Wells” included below within this Item. 
+8 
+Table of Contents 
+Other Property 
+W e also concluded our evaluation of our undeveloped acreage position in Nevada and elected to release our hold on the acreage. We own additional immaterial properties in Louisiana . 
+Proved Reserves 
+Estimates of volumes of proved reserves at year-end, net to our working interest, are presented in MBbls for oil and in MMcf for natural gas, including NGLs, at a pressure base of 14.65 pounds per square inch. Total equivalent volumes are presented in BOE. For the BOE computation, 6,000 cubic feet of gas are the equivalent of one barrel of oil. The ratio of six Mcf of gas to one BOE is typically used in the oil and gas business and represents the approximate energy equivalent of a barrel of oil and a Mcf of natural gas. The price of a barrel of oil is much higher than the price of six Mcf of natural gas, so the ratio of six Mcf to one BOE does not reflect the economic equivalent of a barrel of oil to six Mcf of gas. 
+The following table sets forth certain information about our estimated net proved reserves. All of our proved reserves are currently located in the continental United States. 
+For the Year Ended December 31, 
+2015 (a) 
+2014 (a) 
+2013 (a) 
+Proved developed 
+Oil (MBbls) 
+22,257 
+14,006 
+5,960 
+Natural gas (MMcf) 
+38,157 
+25,171 
+9,059 
+MBOE 
+28,617 
+18,201 
+7,470 
+Proved undeveloped 
+Oil (MBbls) 
+21,091 
+11,727 
+5,938 
+Natural gas (MMcf) 
+27,380 
+17,377 
+8,692 
+MBOE 
+25,654 
+14,623 
+7,387 
+Total proved 
+Oil (MBbls) 
+43,348 
+25,733 
+11,898 
+Natural gas (MMcf) 
+65,537 
+42,548 
+17,751 
+MBOE 
+54,271 
+32,824 
+14,857 
+Financial Information (in thousands) 
+Estimated pre-tax future net cash flows (b) 
+$ 
+1,160,808 
+$ 
+1,330,628 
+$ 
+680,627 
+Pre-tax discounted present value (b) (c) 
+$ 
+570,906 
+$ 
+629,680 
+$ 
+301,144 
+Standardized measure of discounted future net cash flows (b) (c) 
+$ 
+570,890 
+$ 
+579,542 
+$ 
+283,946 
+(a) 
+The Company’s estimated proved reserves as of December 31, 201 5 and 2014 were prepar ed by DeGo l yer and MacNaughton and estimated proved reserves as of December 31, 2013 were prepar ed by Huddleston & Co. 
+(b) 
+Includes a redu ction for estimated plugging and abandonment costs that is reflected as a liability on our balance sheet at December 31, 2015 and 2014 , in accordance with accounting standards for asset retirement obligations. 
+(c) 
+The Company uses the financial measure “ p re-tax discounted present value” which is a non-GAAP financial meas ure. The Company believes that p re-tax discounted present value, while not a financial measure in accordance with GAAP, is an important financial measure used by investors and independent oil and natural gas producers for evaluating the relative value of oil and natural gas properties and acquisitions because the tax characteristics of comparable companies can differ materially. The total standardized measure calculated in accordance with the guidance issued by the FASB for disclosures about oil and natural gas producing activities for our proved reserves as of December 31, 201 5 wa s $570.9 million net of di scounted estimated future income taxes relating to such future net revenues. The projected per Mcf natural gas price of $2.73 used in the 201 5 reserve estimates ha s been adjusted to reflect the Btu content, transportation charges and other fees specific to the individual properties. The projected per barrel oil price of $47.25 used in the 2015 reserve estimates ha s been adjusted to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality. 
+See Note 13 of our Consolidated Financial Statements for the additional information regarding the Company’s reserves including its estimates of proved reserves and the Company’s estimates of future net cash flows and discounted future net cash flows from proved reserves. 
+9 
+Table of Contents 
+The Company’s estimated net proved reserves increased 65% t o 54.3 MBOE at December 31, 2015 from 32.8 MBOE at December 31, 2014 . Additions during the year were due to ( 1) 22.4 MMBOE related to the Company’s horizontal development of a portion of its properties and (2) 3.4 MMBOE related to acquired properties . These increases were partially offset by (1) 3.5 MMBOE related to the Company’s production during 201 5 and (2) 0. 8 MM BOE of net revisions . 
+Proved Undeveloped Reserves 
+Annually, the Company reviews its PUDs to ensure appropriate plans exist for development. PUD reserves are recorded only if the Company has plans to convert these reserves into PDPs within five years of the date they are first recorded. Our development plans include the allocation of capital to projects included within our 2016 capital budget and, in subsequent years, the allocation of capital within our long-range business plan to convert PUDs to PDPs within this five year period. In general, our 2016 capital budget and our long-range capital plans are primarily governed by our expectations of internally generated cash flow and senior secured revolving credit facility borrowing availability. Reserve calculations at any end-of-year period are representative of our development plans at that time. Changes in commodity pricing, oilfield service costs and availability, and other economic factors may lead to changes in development plans. 
+The following table summarizes the Company’s recorded PUDs (in MBOE) : 
+For the Year Ended December 31, 
+2015 
+2014 
+2013 
+Southern Midland Basin 
+8,936 
+10,931 
+6,671 
+Central Midland Basin 
+16,718 
+3,692 
+716 
+Total 
+25,654 
+14,623 
+7,387 
+Our PU Ds increased 75% to 25.7 M MBOE at December 31, 2015 from 14.6 M MBOE at December 31, 2014 . We added 13.8 MMBOE to our PUDs , net of revisions, primarily from the continued horizontal development of our properties. The increase in PUDs was partially offset by the reclassification of 2.7 MMBOE, or 19% , included in the year-end 201 4 PUDs, to PDPs as a result of our horizontal development of properties at a total cost of approximatel y $55.9 million, net. 
+The Company plans to develop its PUDs as part of a multi-year drilling program. At December 31, 2015 , we had no reserves that remained undevelo p ed for five or more years, and all PUD drilling locations are currently scheduled to be drilled within five years of their initial recording. 
+Controls Over Reserve Estimates 
+Compliance as it relates to reporting the Company’s reserves is the responsibility of our Senior Vice President of Operations, who has over 35 years of industry experience , including 2 8 years as a manager , and is our principal engineer. In addition to his years of experience, our principal engineer holds a degree in petroleum engineering and is experienced in asset evaluation and management. 
+Callon’s controls over reserve estimates included retaining DeGolyer and MacNaughton , a Texas registered engineering firm, as our independent p etroleum and geological firm. The Company provided to DeGolyer and MacNaughton information about our oil and gas properties, including production profiles, prices and costs, and DeGolyer and MacNaughton prepared its own estimates of the reserves attributabl e to the Company’s properties. All of the information regarding 2015 and 2014 reserves in this annual report is derived from DeGolyer and MacNaughton ’s report. DeGolyer and MacNaughton ’s reserve report letter is included as an Exhibit to this annual repor t. The principal engineer at DeGolyer and MacNaughton who certified the Company’s reserve estimates has over 4 0 years of experience in the oil and gas industry and is a Texas Licensed Professional Engineer. Further professional qualifications include a degree in petroleum engineering and membership in the International Society of Petroleum Engineers and the American Association of Petroleum Geologists . 
+All of the information regarding 2013 reserves in this annual report is derived from reserve reports prepared by Huddleston & Co. , Inc., a Texas engineering firm. 
+To further enhance the control environment over the reserve estimation process, our S trategic Planning Committee , a committee of the Board of Directors, assist s management and the Board with its oversight of the integrity of the determination of the Company’s oil and 
+10 
+Table of Contents 
+natural gas reserves and the work of our independent reserve engineer . The Committee’s charter also specifies that the Committee shall perform, in consultation with the Company’s management and senior reserves and reservoir engineering personnel, the following responsibilities: 
+· 
+Oversee the appointment, qualification, independence, compensation and retention of the independent petroleum and geological firm (the “Firm”) engaged by the Company (including resolution of material disagreements between management and the Firm regarding reserve determination) for the purpose of preparing or issuing an annual reserve report. The Committee shall review any proposed changes in the appointment of the Firm, determine the reasons for such proposal, and whether there have been any disputes between the Firm and management. 
+· 
+Review the Company’s significant reserves engineering principles and policies and any material changes thereto, and any proposed changes in reserves engineering standards and principles which have, or may have, a material impact on the Company’s reserves disclosure. 
+· 
+Review with management and the Firm the proved reserves of the Company, and, if appropriate, the probable reserves, possible reserves and the total reserves of the Company, including: (i) reviewing significant changes from prior period reports; (ii) reviewing key assumptions used or relied upon by the Firm; (iii) evaluating the quality of the reserve estimates prepared by both the Firm and the Company relative to the Company ’s peers in the industry; and (iv) reviewing any material reserve s adjustments and significant diffe rences between the Company’s a nd Firm’s estimates. 
+· 
+If the Committee deems it necessary, it shall meet in executive session with management and the Firm to discuss the oil and gas reserve determination process and related public disclosures, and any other matters of concern in respect of the evaluation of the reserves. 
+During our last fiscal year, we filed no reports with other federal agencies which contain an estimate of total proved net oil and natural gas reserves . 
+11 
+Table of Contents 
+Production Volumes, Average Sales Prices and Operating Costs 
+The following table sets forth certain information regarding the production volumes and average sales prices received for, and average production costs associated with, the Company’s sale of oil and natural gas for the periods indicated (dollars in thousands, except per unit data) . 
+For the Year Ended December 31, 
+2015 
+2014 
+2013 
+Production 
+Oil (MBbl) 
+2,789 
+1,692 
+911 
+Natural gas (MMcf) 
+4,312 
+2,220 
+3,011 
+Total (MBoe) 
+3,508 
+2,062 
+1,413 
+Revenues 
+Oil sales 
+$ 
+125,166 
+$ 
+139,374 
+$ 
+88,960 
+Natural gas sales 
+12,346 
+12,488 
+13,609 
+Total 
+$ 
+137,512 
+$ 
+151,862 
+$ 
+102,569 
+Operating costs 
+Lease operating expense 
+$ 
+27,036 
+$ 
+22,372 
+$ 
+19,779 
+Production taxes 
+9,793 
+8,973 
+4,133 
+Total 
+$ 
+36,829 
+$ 
+31,345 
+$ 
+23,912 
+Average realized sales price 
+Oil (Bbl) (excluding impact of cash settled derivatives) 
+$ 
+44.88 
+$ 
+82.37 
+$ 
+97.65 
+Oil (Bbl) (including impact of cash settled derivatives) 
+56.82 
+84.84 
+99.32 
+Natural gas (Mcf) (excluding impact of cash settled derivatives) 
+2.86 
+5.63 
+4.52 
+Natural gas (Mcf) (including impact of cash settled derivatives) 
+3.26 
+5.59 
+4.47 
+Total (BOE) (excluding impact of cash settled derivatives) 
+39.20 
+73.65 
+72.59 
+Total (BOE) (including impact of cash settled derivatives) 
+49.18 
+75.63 
+73.56 
+Operating costs per BOE 
+Lease operating expense 
+$ 
+7.71 
+$ 
+10.85 
+$ 
+14.00 
+Production taxes 
+2.79 
+4.35 
+2.92 
+Total 
+$ 
+10.50 
+$ 
+15.20 
+$ 
+16.92 
+Present Activities and Produc tive Wells 
+The following table set s forth the wells drilled and completed during the periods indicated. All such wells were drilled in the continental United States. 
+For the Year Ended December 31, 2015 
+Drilled 
+Completed (a) 
+Awaiting Completion 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Southern Midland Basin horizontal wells 
+12 
+11.8 
+15 
+14.8 
+— 
+— 
+Central Midland Basin horizontal wells 
+24 
+15.3 
+18 
+11.0 
+6 
+4.3 
+Central Midland Basin vertical wells 
+— 
+— 
+1 
+0.4 
+— 
+— 
+Total Midland Basin wells 
+36 
+27.1 
+34 
+26.2 
+6 
+4.3 
+(a) 
+Completions include wells drilled prior to 2015 . 
+The following table sets forth the Company’s drilled and completed wells, none of which were natural gas or nonproductive for the periods reflected: 
+2015 
+2014 (a) 
+2013 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Oil wells 
+Development 
+14 
+11.4 
+19 
+15.5 
+19 
+17.2 
+Exploratory 
+22 
+15.7 
+13 
+11.7 
+7 
+5.0 
+Total 
+36 
+27.1 
+32 
+27.2 
+26 
+22.2 
+(a) 
+Does not include two gross (two net) non-producing exploratory wells . 
+12 
+Table of Contents 
+The following table sets forth productive wells as of December 31, 2015 : 
+Oil Wells 
+Natural Gas Wells 
+Gross 
+Net 
+Gross 
+Net 
+Working interest 
+316 
+240.5 
+— 
+— 
+Royalty interest 
+3 
+0.1 
+— 
+— 
+Total 
+319 
+240.6 
+— 
+— 
+A well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas reserves on a BOE basis. However, most of our wells produce both oil and natural gas. 
+For the periods presented, the following table sets forth by major field(s) net production volumes and percentage of estimated proved reserves: 
+For the Year Ended December 31, 
+Production Volumes (MBOE) 
+% of Total Proved Reserves 
+2015 
+2014 
+2013 
+2015 
+2014 
+2013 
+Southern Midland Basin 
+2,139 
+1,497 
+612 
+44% 
+65% 
+85% 
+Central Midland Basin 
+1,367 
+549 
+193 
+56% 
+35% 
+14% 
+Other 
+2 
+16 
+8 
+0% 
+0% 
+1% 
+Total Midland Basin 
+3,508 
+2,062 
+813 
+100% 
+100% 
+100% 
+Offshore and other (a) 
+— 
+— 
+600 
+0% 
+0% 
+0% 
+Total 
+3,508 
+2,062 
+1,413 
+100% 
+100% 
+100% 
+(a) 
+In late 2013, we sold the remaining interests in our producing offshore fields and in the Haynesville shale. 
+Leasehold Acreage 
+The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage as of December 31, 2015 . 
+Developed 
+Undeveloped 
+Total 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Louisiana 
+936 
+200 
+188 
+55 
+1,124 
+255 
+Texas (a) 
+21,705 
+17,639 
+87 
+36 
+21,792 
+17,675 
+Total 
+22,641 
+17,839 
+275 
+91 
+22,916 
+17,930 
+(a) 
+A portion of our Texas acreage , which we have included in our development plans, requires continu ous drilling to hold the acreage , though the cost to renew this acreage, if necessary, is no t considered material. 
+In 2015 , we concluded our evaluation of our undeveloped acre age position in Nevada and elected to release our hold on the acreage (37 , 626 net and gross acres) . 
+Undeveloped Acreage Expirations 
+The following table sets forth by geographic area as of December 31, 2015 the number of our leased gross and net undeveloped acres that will expire over the next three years unless production begins before lease expiration dates. Gross amounts may be more than net amounts in a particular year due to timing of expirations. 
+Net 
+Gross 
+2016 
+2017 
+2018 
+Total 
+Total 
+Southern Permian Basin 
+— 
+— 
+— 
+— 
+— 
+Central Permian Basin 
+— 
+4 
+3 
+7 
+87 
+The expiring acreage set forth in the table above accounts for approximately 8% of our net undeveloped acreage ( 91 total net acres) and there are no PUD reserves attributable to such acreage. We are continually engaged in a combination of drilling and development 
+13 
+Table of Contents 
+and discussions with mineral lessors for lease extensions, renewals, new drilling and development units and new leases to address any potential expiration of undeveloped acreage that occurs in the normal course of our business . 
+Title to Proper ties 
+The Company believes that the title to its oil and natural gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of such properties. The Company’s properties are potentially subject to one or more of the following: 
+· 
+royalties and other burdens and obligations, express or implied, u nder oil and natural gas leases; 
+· 
+overriding royalties and other burdens created by us or our predecessors in title; 
+· 
+a variety of contractual obligations (including, in some cases, development obligations) ari sing under operating agreements; farm-out agreements, production sales contracts and other agreements that may affect the propert ies or their titles; 
+· 
+back-ins and reversionary interests existing under purchase agree ments and leasehold assignments; 
+· 
+liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual l iens under operating agreements; 
+· 
+pooling, unitization and communitization agre ements, declarations and orders; and 
+· 
+easements, restrictions, rights-of-way and other matters that commonly affect property. 
+To the extent that such burdens and obligations affect the Company’s rights to production revenues, these characteristics have been taken into account in calculating Callon’s net revenue interests and in estimating the size and value of its reserves. The Company believes that the burdens and obligations affecting our properties are typical within the industry for properties of the kind owned by Callon. 
+Insurance 
+In accordance with industry practice, the Company maintains insurance against some, but not all, of the operating risks to which its business is exposed. While not all inclusive, the Company’s insurance policies include coverage for general liability insuring onshore operations (including sudden and accidental pollution), aviation liability, auto liability, worker’s compensation, and employer’s liability. The C ompany carries control of well insurance for only those onshore operations that it is contractually bound to do so. At the depths and in the areas in which the Company operates, and in light of the vertical and horizontal drilling that it undertakes, the Company typically does not encounter high pressures or extreme drilling conditions onshore. 
+Currently, the Company has general liability insurance coverage up to $1 million per occurrence and $2 million per policy in the aggregate, which includes sudden and accidental pollution liability coverage for the effects of pollution on third parties arising from its operations. The Company’s insurance policies contain high policy limits, and in most cases, deductibles (generally ranging from $0 to $250,000) that must be met prior to recovery. These insurance policies are subject to certain customary exclusions and limitations. T he Company maintains up to $100 million in excess liability coverage, which is in addition to and triggered if the underlying liability limits have been reached. In addition, the company purchases pollution legal liability coverage in the amount of $5 million , which is excess and difference in conditions of the liability coverage. 
+The Company requires all of its third-party contractors to sign master service agreements in which they agree to indemnify the Company for injuries and deaths of the service provider’s employees, as well as contractors and subcontractors hired by the service provider. Similarly, the Company generally agrees to indemnify each third-party contractor against claims made by employees of the Company and the Company’s other contractors. Additionally, each party generally is responsible for damage to its own property. 
+The third-party contractors that perform hydraulic fracturing operations for the Company sign master service agreements generally containing the indemnification provisions noted above. The Company does not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations. However, the Company believes its general liability and excess liability insurance policies would cover foreseeable third party claims related to hydraulic fracturing operations and associated legal expenses, in accordance with, and subject to, the terms of such policies. 
+The Company re-evaluates the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and natural gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance 
+14 
+Table of Contents 
+may become unavailable in the future or unavailable on terms that are economically acceptable. While based on the Company’s risk analysis, it believes that it is properly insured, no assurance can be given that the Company will be able to maintain insurance in the future at rates that it considers reasonable. In such circumstances, the Company may elect to self-insure or maintain only catastrophic coverage for certain risks in the future. 
+Major Customers 
+Our production is sold generally on month-to-month contracts at prevailing prices. The following table identifies customers to whom we sold a significant percentage of our total oil and natural gas production, on an equivalent basis, during each of the 12-month periods indicate d: 
+For the Year Ended December 31, 
+2015 
+2014 
+2013 
+Enterprise Crude Oil, LLC 
+42% 
+51% 
+38% 
+Plains Marketing, L.P. 
+19% 
+22% 
+15% 
+Permian Transport and Trading 
+15% 
+7% 
+— 
+Sunoco 
+9% 
+10% 
+— 
+Shell Trading Company 
+4% 
+— 
+31% 
+Other 
+11% 
+10% 
+16% 
+Total 
+100% 
+100% 
+100% 
+Because alternative purchasers of oil and natural gas are readily available, the Company believes that the loss of any of these purchasers would not result in a material adverse effect on Callon’s ability to market future oil and natural gas production. We are not currently committed to provide a fixed and determinable quantity of oil or gas in the near future under our contracts. 
+Corporate Of fices 
+The Company’s headquarters are located in Natchez, Mississippi, in a building owned by the Company . We also maintain leased business offices in Houston and Midland, Texas. Because alternative locations to our leased spaces are readily available, the replacement of any of our leased offices would not result in material expenditures . 
+Empl oyees 
+Callon had 9 3 employees as of December 31, 2015 . None of the Company’s employees are currently represented by a union, and the Company believes that it has good relations with its employees . 
+15 
+Table of Contents 
+Regulations 
+General. Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the entire oil and natural gas industry is continuously being reviewed for amendment and/ or expansion. Some of these requirements carry substantial penalties for failure to comply. 
+Exploration and Production . Our operations are subject to federal, state and local regulations that include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds and letters of credit) covering drilling and well operations. Other activities subject to regulation are: 
+· 
+th e location and spacing of wells; 
+· 
+the method of drilling and completing and operating wells; 
+· 
+th e rate and method of production; 
+· 
+the surface use and restoration of properties upon which wells are drilled a nd other exploration activities; 
+· 
+notice to surface owners and other third parties; 
+· 
+the ve nting or flaring of natural gas; 
+· 
+the p lugging and abandoning of wells; 
+· 
+the discharge of contaminants into water and the em ission of contaminants into air; 
+· 
+the disposal of fluids used or other wastes obtaine d in connection with operations; 
+· 
+the marketing, transportat ion and reporting of production; and 
+· 
+the valuation and payment of royalties. 
+Operations conducted on federal or state oil and natural gas leases must comply with numerous regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the DOI Bureaus or other appropriate federal or state agencies. 
+Our sales of oil and natural gas are affected by the availability, terms and cost of pipeline transportation. The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation. If these regulations change, we could face higher transmission costs for our production and, possibly, reduced access to transmission capacity. 
+Various proposals and proceedings that might affect the petroleum industry are pending before Congress, the Federal Energy Regulatory Commission, or FERC, various state legislatures, and the courts. The industry historically has been heavily regulated and we can offer you no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue nor can we predict what effect such proposals or proceedings may have on our operations. 
+We do not currently anticipate that compliance with existing laws and regulations governing exploration and production will have a significantly adverse effect upon our capital expenditures, earnings or competitive position. 
+Environmental Matters and Regulation. Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the EPA issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. Violations of environmental laws could result in administrative, civil or criminal fines and injunctive relief. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons , air emissions or other 
+16 
+Table of Contents 
+waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Further, the EPA has identified environmental compliance by the energy extraction sector as one of its enforcement initiatives for 2014-2016 (and has solicited comments on continuing this initiative for fiscal years 2017-2019) and, as a general matter, the oil and natural gas exploration and production industry has been the subject of increasing scrutiny and regulation by environmental authorities. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. Although such laws and regulations can increase the cost of planning, designing, installing and operating our facilities, it is anticipated that, absent the occurrence of an extraordinary event, compliance with them will not have a material effect upon our operations, capital expenditures, earnings or competitive position in the marketplace. 
+Waste Handling. The Resource Conservation and Recovery Act (“RCRA”) , as amended , and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of oil and natural gas are exempt from regulation as hazardous wastes under RCRA and its state analogs, it is possible that some wastes we generate presently or in the future may be subject to regulation under RCRA and state analogs. Additionally, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. 
+Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of wastes associated with oil and natural gas exploration and production could increase our costs to manage and dispose of such wastes. 
+Comprehensive Environmental Response, Compensation and Liability Act. T he Comprehensive Environmental Response, Compensation and Liability Act (“ CERCLA ”) , imposes joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or so–called potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes. 
+Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we have generated and will generate wastes that may fall within CERCLA’s definition of hazardous substance and may have disposed of these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum. We may also be the owner or operator of sites on which hazardous substances have been released. To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under CERCLA; we also do not know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties. In the event contamination is discovered at a site on which we are or have been an owner or operator or to which we sent hazardous substances, we could be liable for the costs of investigation and remediation and natural resources damages. 
+We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including offsite locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous 
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+substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination. 
+Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act (“ OPA ”) , and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States (a term broadly defined to include, among other things, certain wetlands) , as well as state waters for analogous state programs. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or applicable state analog . The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. These laws and regulations also prohibit the discharge of dredge or fill material in regulated waters, including wetlands , unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. 
+The Oil Pollution Act is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters. 
+Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws. 
+Air Emissions. The federal Clean Air Act, as amended, and comparable state and local laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and modified and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, on April 17 , 2012, the EPA published final regulations under the federal Clean Air Act that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail below in “Regulation of Hydraulic Fracturing.” These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties and seek injunctive relief for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects. 
+In 2015, the EPA proposed new rules limiting methane emissions from the oil and gas industry. The proposed rules, if adopted, would amend the air emissions rules for the oil and natural gas sources and natural gas processing and transmission sources to include new standards for methane. Simultaneously with the proposal of the methane rules, EPA released a proposal soliciting comments on two alternatives for aggregating multiple surface sites into a single-source of air quality permitting purposes. Depending upon the alternative selected by EPA, sites which currently would not require permitting under the Clean Air Act could require permits, an outcome that could result in costs and delays to our operations; however, given the present uncertainty regarding this rule, the extent and magnitude of that impact cannot be reliably or accurately estimated. 
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+Greenhouse Gas Regulation. More stringent laws and regulations relating to climate change and GHGs may be adopted in the future and could cause us to incur material expenses in complying with them. In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions. Although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. 
+The EPA has established GHG reporting requirements for certain sources in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissions. Although these requirements do not limit the amount of GHGs that can be emitted, they could require us to incur significant costs to monitor, keep records of, and potentially report GHG emissions associated with our operations if the reporting threshold is reached with production growth. The EPA recently announced its intention to take measures to require or encourage reductions in methane emissions, including from oil and natural gas operations. Those measures include the development of NSPS regulations in 2016 for reducing methane from new and modified oil and gas production sources and natural gas proc essing and transmission sources discussed in more detail above in “Air Emissions.” 
+In addition to possible federal regulation, a number of states, individually and regionally, also are considering or have implemented GHG regulatory programs. These potential regional and state initiatives may result in so-called “Cap-and-Trade programs”, under which overall GHG emissions are limited and GHG emissions are then allocated and sold, and possibly other regulatory requirements, that could result in our incurring material expenses to comply, such as by being required to purchase or to surrender allowances for GHGs resulting from our operations. These federal, regional and local regulatory initiatives also could adversely affect the marketability of the oil and natural gas we produce. The impact of such future programs cannot be predicted, but we do not expect our operations to be affected any differently than other similarly situated domestic competitors. 
+Regulation of Hydraulic Fracturing. Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act (“ SDWA ”) , regulates the underground injection of substances through the Underground Injection Control (“ UIC ”) , program. Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions and not at the federal level, as the SDWA expressly excludes regulation of these fracturing activities (except where diesel is a component of the fracturing fluid, as further discussed below) . Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing have been proposed in recent sessions of Congress but have not passed. 
+The EPA, however, issued guidance on permitting hydraulic fracturing that uses fluids containing diesel fuel under the UIC program, specifically as “Class II” UIC wells. At the same time, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices and the EPA has commenced a study of the potential impacts of hydraulic fracturing activities on drinking water resources. The EPA has announced that it plans to propose standards that such wastewater must meet before being transported to a treatment plant. The final rule date is estimated to be March 2016. As p art of these studies, the EPA has requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur additional initiatives to regulate hydraulic fracturing under the SDWA or otherwise. 
+The EPA has adopted regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes Ne w Source Performance Standards f or hydraulically fractured natural gas wells to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured gas wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA may issue revised rules that are likely responsive to some of these requests. If revised, these rules could require modifications to our operations or increase our capital and operating costs without being offset by increased product capture. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty. The BLM finalized regulations for hydraulic fracturing 
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+activities on federal lands. Among other things, the BLM rules impose new requirements to validate the protection of groundwater, disclosure of chemicals used in hydraulic fracturing and higher standards for the interim storage of recovered waste fluids from hydraulic fracturing. This rule is the subject of legal challenges and a federal district court in Wyoming has issued preliminary injunction temporarily delaying implementation of the BLM rule. In addition, the EPA has announced that it is considering regulations under the Toxic Substance Control Act to require evaluation and disclosure of hydraulic fracturing. 
+In addition, there are certain governmental reviews either underway or bei ng proposed that focus on environmental aspects of hydraulic fracturing practices. The federal government is currently undertaking several studies of hydraulic fracturing’s potential impacts, most notably the EPA’s study on the environmental impacts of hydraulic fracturing, the final results of which are not yet available. These ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. 
+Several states, including Texas, and some municipalities, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission has adopted rules and regulations implementing this legislation that apply to all wells for which the Railroad Commission issues an initial drilling permit after February 1, 2012. The new law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act ( “ OSHA ” ) for disclosure on an internet W eb site and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. 
+Additionally, some states, localities and local regulatory districts have adopted or have considered adopting regulations to limit, and in some case impose a moratorium on hydraulic fracturing or other restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water. Further, there has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing. 
+Surface Damage Statutes (“SDAs”) . In addition, a number of states and some tribal nations have enacted SDAs. These laws are designed to compensate for damage caused by oil and gas development operations. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain binding requirements for payments to the operator in connection with exploration and operating activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs. 
+National Environmental Policy Act and Endangered Species Act . Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act (“ NEPA ”) , which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. To the extent that our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects. 
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+The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ or its habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. If the Company were to have a portion of its leases designated as critical or suitable habitat or a protected species were located on a lease, it may adversely impact the value of the affected leases. 
+Mineral Leasing Act of 1920 (“Mineral Act”) . The Mineral Act prohibits direct or indirect ownership of any interest in federal onshore oil and natural gas leases by a foreign citizen or a foreign corporation except through stock ownership in a corporation formed under the laws of the United States or of any U.S. state or territory, and only if the laws, customs, or regulations of their country of origin or domicile do not deny similar or like privileges to citizens or corporations of the United States. If these restrictions are violated, the oil and gas lease or leases can be canceled in a proceeding instituted by the United States Attorney General. Although the regulations of the BLM (which administers the Mineral Act) provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. The Company own ed an interest in federal leaseholds in Nevada. It is possible that holders of the Company’s equity interests may be citizens of foreign countries, which could be determined to be citizens of a non-reciprocal country under the Mineral Act. In such event, the federal onshore oil and gas leases held by the Company could be subject to cancellation based on such determination. 
+Other Regulation of the Oil and Natural Gas Industry. The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production. 
+The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. Federal and state regulations govern the rates and other terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas. 
+Although oil and natural gas sales prices are currently unregulated, the federal government historically has been active in the area of oil and natural gas sales regulation. We cannot predict whether new legislation to regulate oil and natural gas sales might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate, oil and natural gas liquids are not currently regulated and are made at market prices. 
+Exports of US Crude Oil Production . The federal government has recently ended its decades-old prohibition of exports of oil produced in the lower 48 states of the US. It is too recent an event to determine the impact this regulatory change may have on our operations or our sales of oil. The general perception in the industry is that ending the prohibition of exports of oil produced in the US will be positive for producers of U . S . oil. 
+Drilling a nd Production. Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following: 
+· 
+the location of wells; 
+· 
+the method of drilling and casing wells; 
+· 
+the timing of construction or drilling activities, including seasonal wildlife closures; 
+· 
+the rates of production or “allowables”; 
+· 
+the surface use and restoration of properties upon which wells are drilled; 
+· 
+the plugging and abandoning of wells; and 
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+· 
+notice to, and consultation with, surface owners and other third parties. 
+State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations we can drill. 
+Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements. 
+Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. 
+FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and for the release of our excess, if any, natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities. 
+Under FERC’s current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting gas to point-of-sale locations. 
+The pipelines used to gather and transport natural gas being produced by the Company are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), the Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In August 2011, the PHMSA issued an Advance Notice of Proposed Rulemaking regarding pipeline safety, including questions regarding the modification of regulations applicable to gathering lines in rural areas. 
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+Oil and NGLs Sales and Transportation. Sales of oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. 
+The Company’s sales of oil and natural gas liquids are also affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by the FERC under the Interstate Commerce Act. The FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors. 
+Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors. 
+Any transportation of the Company’s crude oil, natural gas liquids and purity components (ethane, propane, butane, iso-butane, and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts 171-180 (“HMR”), including Emergency Orders by the FRA and new regulations being proposed by the PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids. 
+In October 2015, the PHMSA issued proposed new safety regulations for hazardous liquid pipelines, including a requirement that all hazardous liquid pipelines have a system for detecting leaks and establish a timeline for inspections of affected pipelines following extreme weather events or natural disasters. 
+State Regulation. Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill. 
+The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us. 
+Commitments and Contingencies 
+The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment will not have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies included, and claims for damages to property, employees, other persons, and the environment resulting from the Company’s operations could have on its activities. See Note 14 for additional information. 
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+Available Information 
+We make available free of charge on our W eb site (www.callon.com) our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the SEC. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE., Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an Internet site (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers, like Callon, that file electronically with the SEC. 
+We also make available within the About Callon section of our W eb site our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and Audit, Compensation , Strategic Planning and Reserve, and Nominating and Governance Committee Charters, which have been approved by our B oard of D irectors. We will make timely disclosure by a Current Report on Form 8-K and on our W eb site of any change to, or waiver from, the Code of Business Conduct and Ethics for our principal executive and senior financial officers. A copy of our Code of Business Conduct and Ethics is also available, free of charge by writing us at: Chief Financial Officer, Callon Petroleum Company, P.O. Box 1287, Natchez, MS 39121 . 
+Item 1A. Ri sk Factors 
+Risk Factors 
+Depressed oil and natural gas prices may adversely affect our results of operations and financial condition . Our success is highly dependent on prices for oil and natural gas, which are extremely volatile, and the oil and natural gas markets are cyclical. Approximately 80% of our anticipated 2016 production, on a BOE basis, is oil. Starting in the second half of 201 4 , the NYMEX price for a barrel of oil has fallen sharply, from a price o f $105.37 on June 30, 201 4 to $32.78 on February 26, 2016 . I n addition, NYMEX prices for natural gas have been low compared with historical prices. Extended periods of low prices for oil or natural gas will have a material adverse effect on us. The prices of oil and natural gas depend on factors we cannot control such as weather, economic conditions, levels of production, actions by OPEC and other countries and government actions. Prices of oil and natural gas will affect the following aspects of our business: 
+· 
+our revenues, cash flows and earnings; 
+· 
+the amount of oil and natural gas that we are economically able to produce; 
+· 
+our ability to attract capital to finance our operations and the cost of the capital; 
+· 
+the amount we are allowed to borrow under our credit facilities; 
+· 
+the profit or loss we incur in exploring for and developing our reserves; and 
+· 
+the value of our oil and natural gas properties. 
+Any substantial and extended decline in the price of oil or natural gas could have an adverse effect on our borrowing capacity, our ability to obtain additional capital, and our revenues, profitability and cash flows. 
+If oil and natural gas prices remain depressed for extended periods of time, we may be required to take additional write - downs of the carrying value of our oil and natural gas properties. We may be required to write - down the carrying value of our oil and natural gas properties when oil and natural gas prices are low. Under the full cost method, which we use to account for our oil and natural gas properties, the net capitalized costs of our oil and natural gas properties may not exceed the present value, discounted at 10%, of future net cash flows from estimated net proved reserves, using the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month, plus the lower of cost or fair market value of our unproved properties. If net capitalized costs of our oil and natural gas properties exceed this limit, we must charge the amount of the excess to earnings. This type of charge will not affect our cash flows, but will reduce the book value of our stockholders’ equity. Because the oil price we are required to use to estimate our future net cash flows is the average price over the 12 months prior to the date of determination of future net cash flows, the full effect of falling prices may not be reflected in our estimated net cash flows for several quarters. We review the carrying value of our properties quarterly and once incurred, a write - down of oil and natural gas properties is not reversible at a later date, even if prices increase. See Note 13 to our Co ns olidated Financial Statements. 
+24 
+Table of Contents 
+For the period ended December 31, 2015, we recorde d a $208.4 mi llion write-down of oil and natural gas properties as a result of the ceiling test limitation driven primarily by the significant decrease in oil prices beginning in the fourth quarter of 2014. The ceiling test calculation as of December 31, 2015 used the average NYMEX price of $ 50.16 per barrel of oil and $ 2.64 per Mcf of natural gas . The oil prices used at December 31, 2015 were approximately 8% lower than the September 30, 2015 price of $ 54.48 per barrel of oil , and the gas prices were approximately 25% lower than the September 30, 2015 price of $ 3.53 per Mcf of natural gas . Oil prices have continued to decline since December 31, 2015. As a result, we anticipate that further impairments may occur. For example, not taking into account subsequent drilling results, production, changes in oil and natural gas prices, and changes in future development and operating costs, a 10% decrease in oil and natural gas prices would have resulted in an additional $ 108.2 million write down in the year ended December 31, 2015. 
+Our actual recovery of reserves may substantially differ from our proved reserve estimates and our proved reserve estimates may change over time. This Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. In addition, drilling , testing and production data acquired since the date of an estimate may justify revising an estimate. 
+Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from the estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report. Additionally, reserves and future cash flows may be subject to material downward or upward revisions, based on production history, development drilling and exploration activities and prices of oil and natural gas. We incorporate many factors and assumptions into our estimates including: 
+· 
+Expected reservoir characteristics based on geological, geophysical and engineering assessments; 
+· 
+Future production rates; 
+· 
+Future oil and natural gas prices and quality and locational differences; and 
+· 
+Future development and operating costs. 
+You should not assume that any present value of future net cash flows from our estimated net proved reserves contained in this Form 10-K represents the market value of our oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves at December 31, 2015 on average 12-month prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures, the rate and timing of production, and changes in governmental regulations or taxes. At December 31, 2015 , approximately 34% of the discounted present value of our estimated net proved reserves consisted of PUDs. PUDs represented 47% of total proved reserves by volume. Recovery of PUDs generally requires significant capital expenditures and successful drilling operations. Our reserve estimates include the assumption that we will make significant capital expenditures to develop these PUD s and the actual costs, development schedule, and results associated with these properties may not be as estimated. In addition, the 10% discount factor that we use to calculate the net present value of future net revenues and cash flows may not necessarily be the most appropriate discount factor based on our cost of capital in effect from time to time and the risks associated with our business and the oil and gas industry in general. 
+Information about reserves constitutes forward-looking information. See “Forward-Looking Statements” for information regarding forward-looking information. 
+Unless we replace our oil and gas reserves, our reserves and production will decline. Our future oil and gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our production, revenues, reserve quantities and cash flows will decline. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be limited to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. 
+25 
+Table of Contents 
+Exploring for, developing, or acquiring reserves is capital intensive and uncertain. We may not be able to economically find, develop, or acquire additional reserves, or may not be able to make the necessary capital investments to develop our reserves, if our cash flows from operations decline or external sources of capital become limited or unavailable. As part of our exploration and development operations, we have expanded, and expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture stimulation techniques. The utilization of these techniques requires substantially greater capital expenditures, currently expected to be in excess of three times the cost, as compared to the drilling of a traditional vertical well. If we do not replace the reserves we produce, our reserves revenues and cash flow will decrease over time, which will have an adverse effect on our business. 
+Our business requires significant capital expenditures and we may not be able to obtain needed capital or financing on satisfactory terms or at all . Our exploration and development activities are capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Historically, we have funded our capital expenditures through a combination of cash flows from operations, borrowings under our senior secured revolving credit facility and public debt and equity financings. In 2015 , our total operational capital expenditures, including expenditures for drilling, completion and facilities , were approximat ely $ 205.7 mill ion (on a cash basis) . Our 2016 budget for operational capital expenditures is currently estimated to be approximatel y $ 7 5 to $ 80 m illion (on an accrual, or GAAP, basis) . The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technologica l and competitive developments. 
+If the borrowing base under our senior secured revolving credit facility or our revenues decrease as a result of lower oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or cash available under our senior secured revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our drilling locations, which in turn could lead to a possible expiration of our leases and a decline in our estimated net proved reserves, and could adversely affect our business, financial condition and results of operations. 
+O ur senior secured revolving credit facility and s econd lien term loan facility contain restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities. Our credit facilities contain restrictive covenants that limit our ability to, among other things: 
+· 
+incur additional indebtedness; 
+· 
+create additional liens; 
+· 
+sell assets; 
+· 
+merge or consolidate with another entity; 
+· 
+pay dividends or make other distributions; 
+· 
+engage in transactions with affiliates; and 
+· 
+enter into certain swap agreements. 
+In addition, we will be required to use substantial portions of our future cash flow to repay principal and interest on our indebtedness. Our credit facilities require us to maintain certain financial ratios and tests, including a minimum asset value coverage ratio of total debt. The requirement that we comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business. 
+Our borrowings under ou r senior secured revolving credit facility a nd second lien term loan facility expose us to interest rate risk. Our earnings are exposed to interest rate risk associated with borrowings under our senior secured revolving credit facility, which bear interest at a rate elected by us that is based on the prime, LIBOR or federal funds rate plus margins ranging from 1 .75% to 2.75% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base. Our second lien term loan bears interest at a rate of LIBOR , subject to a floor of 1.0% , p lus 7.5% . If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition. 
+26 
+Table of Contents 
+The borrowing base under our senior secured revolving credit facility may be reduced below the amount of borrowings outstanding under such facilities. Under the terms of our senior secured revolving credit facility , our borrowing base is subject to redeterminations at least semi-annually based in part on prevailing oil and gas prices. A negative adjustment could occur if the estimates of future prices used by the banks in calculating the borrowing base are significantly lower than those used in the last redetermination. The next redetermination of our borrowing base is scheduled to occur on or about March 31, 201 6 . In addition, the portion of our borrowing base made available to us is subject to the terms and covenants of the senior secured revolving credit facility including, without limitation, compliance with the financial performance covenants of such facility. In the event the amount outstanding under our senior secured revolving credit facility exceeds the redetermined borrowing base, we are required to either (i) grant liens on additional oil and gas properties (not previously evaluated in determining such borrowing base) with a value equal to or greater than such excess or (ii) repay such excess borrowings over five monthly installments. We may not have sufficient funds to make any required repayment. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, an event of default would occur under our senior secured revolving credit facility . 
+The unavailability or high cost of drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget. From time to time, our industry has experiences a shortage of drilling rigs, equipment, supplies, water or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. Increasing levels of exploration and production may increase the demand for oilfield services and equipment, and the costs of these services and equipment may increase, while the quality of these services and equipment may suffer. The unavailability or high cost of drilling rigs, pressure pumping equipment, supplies , water or qualified personnel can materially and adversely affect our operations and profitability. 
+Our operations substantially depend on the availability of water. Restrictions on our ability to obtain, dispose of or recycle water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner. Water is an essential component of our drilling and hydraulic fracturing processes. Historically, we have been able to secure water from local landowners and other sources for use in our operations. During the last few years, West Texas has experienced extreme drought conditions. As a result of the severe drought, some local water districts may begin restricting the use of water under their jurisdiction for drilling and hydraulic fracturing to protect the local water supply. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil, NGLs and natural gas, which could have an adverse effect on our business, financial condition and results of operations. 
+Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area. All of our producing properties are geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of oil, natural gas or natural gas liquids. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations. 
+Our exploration projects increase the risks inherent in our oil and natural gas activities. We may seek to replace reserves through exploration, where the risks are greater than in acquisitions and development drilling. Our exploration drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including: 
+· 
+the results of our exploration drilling activities; 
+· 
+receipt of additional seismic data or other geophysical data or the reprocessing of existing data; 
+· 
+material changes in oil or natural gas prices; 
+· 
+the costs and availability of drilling rigs; 
+· 
+the success or failure of wells drilled in similar formations or which would use the same production facilities; 
+27 
+Table of Contents 
+· 
+availability and cost of capital; 
+· 
+changes in the estimates of the costs to drill or complete wells; and 
+· 
+changes to governmental regulations. 
+Delays in exploration, cost overruns or unsuccessful drilling results could have a material adverse effect on our business and future growth. 
+Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns. Exploration, development, drilling and production activities are subject to many risks, including the risk that commercially productive deposits will not be discovered. We may invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that any leasehold acreage acquired will be profitably developed, that new wells drilled will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, wells that are profitable may not achieve our targeted rate of return. 
+In addition, we may not be successful in controlling our drilling and production costs to improve our overall return. We may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including: 
+· 
+unexpected drilling conditions; 
+· 
+pressure or irregularities in formations; 
+· 
+lack of proximity to and shortage of capacity of transportation facilities; 
+· 
+equipment failures or accidents and shortages or delays in the availability of drilling rigs and the delivery of equipment; and 
+· 
+compliance with governmental requirements. 
+Failure to conduct our oil and gas operations in a profitable manner may result in write - downs of our proved reserves quantities, impairment of our oil and gas properties, and a write- down in the carrying value of our unproved properties, and over time may adversely affect our growth, revenues and cash flows. 
+Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could prevent them from being drilled or delay their drilling. Our management team has identified drilling locations as an estimation of our future development activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these identified drilling locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system, marketing and transportation constraints, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the identified drilling locations will ever be drilled or if we will be able to produce oil or natural gas from these drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the identified locations are located, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified. 
+The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Approximately 47% of our total estimated proved reserves as of December 31, 2015 , were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves. 
+We may be unable to integrate successfully the operations of future acquisitions with our operations, and we may not realize all the anticipated benefits of these acquisitions. Our business may include producing property acquisitions that would include 
+28 
+Table of Contents 
+undeveloped acreage. We can offer no assurance that we will achieve the desired profitability from any acquisitions we may complete in the future. In addition, failure to assimilate recent and future acquisitions successfully could adversely affect our financial condition and results of operations. Our acquisitions may involve numerous risks, including: 
+· 
+operating a larger combined organization and adding operations; 
+· 
+difficulties in the assimilation of the assets and operations of the acquired business, especially if the assets acquired are in a new geographic area; 
+· 
+risk that oil and natural gas reserves acquired may not be of the anticipated magnitude or may not be developed as anticipated; 
+· 
+loss of significant key emplo yees from the acquired business; 
+· 
+inability to obtain satisfactory title to the assets we acquire; 
+· 
+a decrease in our liquidity if we use a portion of our available cash to finance acquisitions; 
+· 
+a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions; 
+· 
+diversion of management’s attention from other business concerns; 
+· 
+failure to realize expected profitability or growth; 
+· 
+failure to realize expected synergies and cost savings; 
+· 
+coordinating geographically disparate organizations, systems and facilities; and 
+· 
+coordinating or consolidating corporate and administrative functions. 
+Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. If we consummate any future acquisition, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisition and current operations, which in turn, could negatively impact our results of operations. 
+We may fail to fully identify problems with any properties we acquire, and as such, assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities. We are actively seeking to acquire additional acreage in Texas or other regions in the future. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, operating and capital costs and potential environmental and other liabilities. Although we conduct a review of properties we acquire which we believe is consistent with industry practices, we can give no assurance that we have identified or will identify all existing or potential problems associated with such properties or that we will be able to mitigate any problems we do identify. Such assessments are inexact and their accuracy is inherently uncertain. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for preclosing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms. 
+Unexpected subsurface conditions and other unforeseen operating hazards may adversely impact our ability to conduct business. There are many operating hazards in exploring for and producing oil and natural gas, including: 
+· 
+our drilling operations may encounter unexpected formations or pressures, which could cause damage to equipment or personal injury; 
+· 
+we may experience equipment failures which curtail or stop production; 
+· 
+we could experience blowouts or other damages to the productive formations that may require a well to be re-drilled or other corrective action to be taken; 
+· 
+storms and other extreme weather conditions could cause damages to our production facilities or wells. 
+Because of these or other events, we could experience environmental hazards, including release of oil and natural gas from spills, natural gas-leaks, accidental leakage of toxic or hazardous materials, such as petroleum liquids, drilling fluids or fracturing fluids, including chemical additives, underground migration, and ruptures. 
+29 
+Table of Contents 
+If we experience any of these problems, it could affect well bores, gathering systems and processing facilities, which could adversely affect our ability to conduct operations. We could also incur substantial losses in excess of our insurance coverage as a result of: 
+· 
+injury or loss of life; 
+· 
+severe damage to and destruction of property, natural resources and equipment; 
+· 
+pollution and other environmental damage; 
+· 
+clean-up responsibilities; 
+· 
+regulatory investigation and penalties; 
+· 
+suspension of our operations; and 
+· 
+repairs to resume operations. 
+We cannot assure you that we will be able to maintain adequate insurance at rates we consider reasonable to cover our possible losses from operating hazards. The occurrence of a significant event not fully insured or indemnified against could materially and adversely affect our financial condition and results of operations. 
+Factors beyond our control affect our ability to market production and our financial results. The ability to market oil and natural gas from our wells depends upon numerous factors beyond our control. These factors could negatively affect our ability to market all of the oil or natural gas we produce. In addition, we may be unable to obtain favorable prices for the oil and natural gas we produce. These factors include: 
+· 
+the extent of domestic production and imports of oil and natural gas; 
+· 
+federal regulations generally prohibiting the export of U.S. crude oil; 
+· 
+federal regulations applicable to exports of liquefied natural gas (LNG); 
+· 
+the proximity of hydrocarbon production to pipelines; 
+· 
+the availability of pipeline and/or refining capacity; 
+· 
+the demand for oil and natural gas by utilities and other end users; 
+· 
+the availability of alternative fuel sources; 
+· 
+the effects of inclement weather; 
+· 
+state and federal regulation of oil and natural gas marketing; and 
+· 
+federal regulation of natural gas sold or transported in interstate commerce. 
+In particular, in areas with increasing non-conventional shale drilling activity, capacity may be limited and it may be necessary for new interstate and intrastate pipelines and gathering systems to be built. 
+The marketability of a portion of our production is dependent upon oil and condensate trucking facilities owned and operated by third parties, and the unavailability of these facilities would have a material adverse effect on our revenue. Our ability to market our production depends in part on the availability and capacity of oil and condensate trucking operations owned and operated by third parties. Our failure to obtain these services on acceptable terms could materially harm our business. We may be required to shut in wells for lack of a market or because of inadequate or unavailable trucking capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. 
+The disruption of third party trucking facilities due to maintenance, weather or other factors could negatively impact our ability to market and deliver our oil and condensate. The third parties control when , or if , such trucking facilities are restored and what prices will be charged. In the past, we have experienced disruptions in our ability to market oil and condensate from bad weather. We may experience similar interruptions as we continue to explore and develop our Permian Basin properties in the future. If we were required to shut in our production for long periods of time due to lack of trucking capacity, it would have a material adverse effect on our business, financial condition, results of operations and cash flows. 
+Part of our strategy involves drilling in new or emerging shale formations using horizontal drilling and completion techniques. The results of our planned drilling program in these formations may be subject to more uncertainties than conventional drilling programs in more established formations and may not meet our expectations for reserves or production. The results of 
+30 
+Table of Contents 
+our recent horizontal drilling efforts in new or emerging formations, including certain intervals in the Wolfcamp shale and the Spraberry shale in the Permian basin, are generally more uncertain than drilling results in areas that are developed and have established production. Because new or emerging formations have limited or no production history, we are less able to rely on past drilling results in those areas as a basis predict our future drilling results. Further, access to adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more challenging in new or emerging areas. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, access to gathering systems and takeaway capacity or otherwise, and/or natural gas and oil prices decline, our investment in these areas may not be as economic as we anticipate, we could incur material write - downs of unevaluated properties and the value of our undeveloped acreage could decline in the future. 
+The loss of key personnel could adversely affect our ability to operate. We depend, and will continue to depend in the foreseeable future, on the services of our senior officers and other key employees, as well as other third-party consultants with extensive experience and expertise in evaluating and analyzing drilling prospects and producing oil and natural gas from proved properties and maximizing production from oil and natural gas properties. Our ability to retain our senior officers, other key employees and our third party consultants, none of whom are subject to employment agreements, is important to our future success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business. 
+We may not be insured against all of the operating risks to which our business is exposed. In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We cannot assure you that our insurance will be adequate to cover losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. No assurance can be given that we will be able to maintain insurance in the future at rates we consider reasonable and may elect none or minimal insurance coverage. The occurrence of a significant event, not fully insured or indemnified against, could have a material adverse effect on our financial condition and operations. 
+Competitive industry conditions may negatively affect our ability to conduct operations. We compete with numerous other companies in virtually all facets of our business. Our competitors in development, exploration, acquisitions and production include major integrated oil and gas companies and smaller independents as well as numerous financial buyers, including many that have significantly greater resources. Therefore, competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources permit. We also compete for the materials, equipment and services that are necessary for the exploration, development and operation of our properties. Our ability to increase reserves in the future will be dependent on our ability to select and acquire suitable prospects for future exploration and development. Factors that affect our ability to compete in the marketplace include: 
+· 
+our access to the capital necessary to drill wells and acquire properties; 
+· 
+our ability to acquire and analyze seismic, geological and other information relating to a property; 
+· 
+our ability to retain the personnel necessary to properly evaluate seismic and other information relating to a property; 
+· 
+our ability to procure materials, equipment and services required to explore, develop and operate our properties, including the ability to procure fracture stimulation services on wells drilled; and 
+· 
+our ability to access pipelines, and the location of facilities used to produce and transport oil and natural gas production. 
+Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “ Dodd-Frank Act”) establishes federal oversight and regulation of over-the-counter derivatives and requires the U.S. Commodity Futures Trading Commission (the “CFTC”) and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the over-the-counter market. 
+Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized. In one of its rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC approved on November 5, 2013, a proposed rule imposing position limits for certain futures and option contracts in various commodities (including natural gas) and for swaps that are their economic equivalents. Certain specified types of hedging transactions are exempt from these position limits, provided that such hedging transactions satisfy the CFTC’s requirements for “bona fide hedging” transactions or positions. Similarly, the CFTC has issued a proposed rule regarding the capital that a swap dealer or major swap participant is required to post with respect to its swap business, but has not yet issued a final rule. The CFTC issued a final 
+31 
+Table of Contents 
+rule on margin requirements for swap transactions in January 2016 , which includ es an exemption for commercial end-users which enter into uncleared swaps in order to hedge commercial risks affecting their business, from any requirement to post margin to secure such swap transactions. In addition, the CFTC has issued a final rule authorizing an exception for commercial end-users using swaps to hedge their commercial risks from the otherwise applicable mandatory obligation under the Dodd-Frank Act to clear all swap transactions through a registered derivatives clearing organization and to trade all such swaps on a registered exchange. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations. All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business . 
+While it is not possible at this time to predict when the CFTC will issue final rules applicable to position limits or capital requirements, depending on the Company’s ability to satisfy the CFTC’s requirements for the various exemptions available for a commercial end-user using swaps to hedge or mitigate its commercial risks, these rules and regulations may require us to comply with position limits, and with certain clearing and trade-execution requirements in connection with financial derivative activities. When a final rule on capital requirements is issued, t he Dodd-Frank Act may require our current counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which could increase the cost to us of entering into such derivatives. The Dodd-Frank Act may also require our current counterparties to financial derivative transactions to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties, and may cause some entities to cease their current business as hedge providers. These changes could reduce the liquidity of the financial derivatives markets thereby reducing the ability of commercial end-users to have access to financial derivatives to hedge or mitigate their exposure to commodity price volatility. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available capital for other commercial operations purposes), materially alter the terms of future swaps relative to the terms of our existing bilaterally negotiated financial derivative contracts, and reduce the availability of derivatives to protect against commercial risks we encounter . 
+In addition, federal banking regulators have adopted new capital requirements for certain regulated financial institutions in connection with the Basel III Accord. Once the regulations are fully implemented, financial institutions subject to the capital requirements may require that we provide cash or other collateral with respect to our obligations under the financial derivatives in order to reduce the amount of capital such financial institutions may have to maintain. Alternatively, financial institutions subject to the capital requirements may price transactions so that we will have to pay a premium to enter into derivatives in an amount that will compensate the financial institutions for the additional capital costs relating to such derivatives. Rules implementing the Basel III Accord capital requirements could materially reduce our liquidity and increase the cost of derivative contacts (including through requirements to post collateral which could adversely affect our available capital for other commercial operations purposes.) 
+If we reduce our use of derivative contracts as a result of the new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas and natural gas liquids prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and natural gas liquids. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations, or cash flows. 
+We may not have production to offset hedges. Part of our business strategy is to reduce our exposure to the volatility of oil and natural gas prices by hedging a portion of our production. In a typical hedge transaction, we will have the right to receive from the other parties to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the other parties this difference multiplied by the quantity hedged. Additionally, we are required to pay the difference between the floating price and the fixed price when the floating price exceeds the fixed price regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements even though such payments are not offset by sales of physical production. 
+Our hedging program may limit potential gains from increases in commodity prices or may result in losses or may be inadequate to protect us against continuing and prolonged declines in commodity prices. We enter into hedging arrangements from time to time to reduce our exposure to fluctuations in oil and natural gas prices and to achieve more predictable cash flow. Our hedges at December 31, 2015 are in the form of swaps, collars and short calls placed with the commodity trading branches of certain national banking institutions and with certain other commodity trading groups. We cannot assure you that these or future 
+32 
+Table of Contents 
+counterparties will not become credit risks in the future. Hedging arrangements expose us to risks in some circumstances, including situations when the counterparty to the hedging contract defaults on the contractual obligations or there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received. These hedging arrangements may also limit the benefit we could receive from increases in the market or spot prices for oil and natural gas. We cannot assure you that the hedging transactions we have entered into, or will enter into, will adequately protect us from fluctuations in oil and natural gas prices. In addition, at December 31, 2015, we had approximately 1,464 MB bls oil volumes hedged for NYMEX prices for 2016, in addition 1,464 MBbls oil volumes hedged for the Midland basis differentials . These hedges may be inadequate to protect us from continuing and prolonged declines in oil and natural gas prices. To the extent that oil and natural gas prices remain at current levels or decline further, we will not be able to hedge future production at the same pricing level as our current hedges and our results of operations and financial condition would be negatively impacted. 
+Our hedging transactions expose us to co unterparty credit risk. Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract. During periods of falling commodity prices, our hedging transactions expose us to risk of financial loss if our counterparty to a derivatives transaction fails to perform its obligations under a derivatives transaction (e.g., our counterparty fails to perform its obligation to make payments to us under the derivatives transaction when the market (floating) price under such derivative falls below the specified fixed price). We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss. 
+The inability of one or more of our customers to meet their obligations to us may adversely affect our financial results . Our principal exposures to credit risk are through receivables resulting from the sale of our oil and natural gas production, which we market to energy marketing companies, refineries and affiliates, advances to joint interest parties and joint interest receivables. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. The largest purchaser of our oil and natural gas accounted for approximately 42% of our total oil and natural gas revenues for the year ended December 31, 2015 . We do not require any of our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. Joint interest receivables arise from billing entities who own a partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we choose to drill. We have limited ability to control participation in our wells. 
+Compliance with environmental and other government regulations could be costly and could negatively impact production. Our operations are subject to numerous laws and regulations governing the operation and maintenance of our facilities and the discharge of materials into the environment or otherwise relating to environmental protection. For a discussion of the material regulations applicable to us, see “Regulations.” These laws and regulations may: 
+· 
+require that we acquire permits before commencing drilling; 
+· 
+impose operational, emissions control and other conditions on our activities; 
+· 
+restrict the substances that can be released into the environment in connection with drilling and production activities; 
+· 
+limit or prohibit drilling activities on protected areas such as wetlands and wilderness areas; and 
+· 
+require measures to remediate or mitigate pollution and environmental impacts from current and former operations, such as cleaning up spills or dismantling abandoned production facilities. 
+Under these laws and regulations, we could be liable for costs of investigation, removal and remediation, damages to and loss of use of natural resources, loss of profits or impairment of earning capacity, property damages, costs of increased public services, as well as administrative, civil and criminal fines and penalties, and injunctive relief. Certain environmental statutes, including the RCRA, CERCLA, OPA and analogous state laws and regulations, impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released. We could also be affected by more stringent laws and regulations adopted in the future, including any related to climate change, greenhouse gases and hydraulic fracturing. Under the common law, we could be l iable for injuries to people and property. We maintain limited insurance coverage for sudden and accidental environmental damages. We do not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Also, we do not believe that insurance coverage for the full potential liability that 
+33 
+Table of Contents 
+could be caused by sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability or we may be required to cease production from properties in the event of environmental incidents. 
+Climate change legislation or regulations restricting emissions of “greenhouse gasses” (“GHG”) could result in increased operating costs and reduced demand for the oil and natural gas we produce. In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions. Although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. The EPA recently announced its intention to take measures to require or encourage reductions in methane emissions, including from oil and natural gas operations. Those measures include the development of NSPS regulations in 2016 for reducing methane from new and modified oil and gas production sources and natural gas processing and transmission sources. 
+In addition, the EPA requires the reporting of GHG emissions from specified large GHG emission sources including onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities, which may include facilities we operate. Reporting of GHG emissions from such facilities is required on an annual basis. We will continue to incur costs associated with this reporting obligation. 
+In addition, the United States Congress has considered (but not passed) legislation to reduce emissions of GHGs and many states have already taken or have considered legal measures to reduce or measure GHG emissions, often involving the planned development of GHG emission inventories and/or cap and trade programs. Most of these cap and trade programs would require major sources of emissions or major producers of fuels to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. These allowances would be expected to escalate significantly in cost over time. The adoption and implementation of any legislation or regulatory programs imposing GHG reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGS associated with our operations or could adversely affect demand for the oil and natural gas that we produce. 
+Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects. In an interpretative guidance on climate change disclosures, the SEC indicates that climate change could have an effect on the severity of weather (including storms and floods), the arability of farmland, and water availability and quality. If such effects were to occur, our exploration and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production activities either because of climate-related damages to our facilities in our costs of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate chan ge could also have an indirect e ffect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. In addition, our hydraulic fracturing operations require large amounts of water. Should drought conditions occur, our ability to obtain water in sufficient quality and quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. 
+Federal legislation and state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. Hydraulic fracturing is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing activities are typically regulated by state oil and gas commissions but not at the federal level, as the federal Safe Drinking Water Act expressly excludes regulation of these fracturing activities (except where diesel is a component of the fracturing fluid). We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with the wells for which we are the operator. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under federal and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury. In March 2010, the EPA announced that it would conduct a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. A draft report has been released, but a final report is not yet available. The agency has identified one of its enforcement initiatives for 2014 to 2016 environmental compliance by the energy extraction sector (and has solicited comments on continuing this initiative for fiscal years 
+34 
+Table of Contents 
+2017 to 2019). This study and the EPA’s enforcement initiative could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. 
+A committee of the U.S. House of Representatives conducted an investigation of hydraulic fracturing practices. Legislation was introduced before Congress, but not passed to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states and local or regional regulatory authorities have adopted or are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For example, New York has banned high volume hydraulic fracturing. Further, Pennsylvania has adopted a variety of regulations limiting how and where fracturing can be performed. While we have no operations in either New York or Pennsylvania, any other new laws or regulations that significantly restrict hydraulic fracturing in areas in which we do operate could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby affect the determination of whether a well is commercially viable. Further, the EPA has announced initiatives under the Clean Water Act to establish standards of wastewater from hydraulic fracturing and under the Toxic Substance Control Act to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals. The BLM finalized regulations for hydraulic fracturing activities on federal lands. Among other things, the BLM rules impose new requirements to validate the protection of groundwater, disclosure of chemicals used in hydraulic fracturing and higher standards for the interim storage of recovered waste fluids from hydraulic fracturing. This rules is the subject of legal challenges and a federal district court in Wyoming has issued preliminary injunction temporarily delaying implementation of the BLM rule. In addition, if hydraulic fracturing becomes further regulated at the federal level, our fracturing activities could become subject to additional permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs and potential liabilities. Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. In addition, restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that we are ultimately able to produce in commercial quantities. 
+We are now subject to regulation under NSPS and NESHAPS programs, which could result in increased operating costs. On April 17, 2012, the EPA issued final rules that subject oil and natural gas production, processing, transmission and storage operations to regulation under the NSPS and the NESHAP programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards require owners/operators to reduce VOC emissions from natural gas not sent to the gathering line during well completion either by flaring, using a completion combustion device, or by capturing the natural gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to newly fractured wells and also existing wells that are refractured. Further, the finalized regulations also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules may require changes to our operations, including the installation of new equipment to control emissions. 
+We are subject to stringent and complex federal, state and local laws and regulations governing, among other things, worker health and safety, the discharge of materials into the environment and environmental protection that may cause it to incur substantial costs. In some areas of Texas, there has been concern that certain formations into which disposal wells are injecting produced waters could become over-pressured after many years of injection, and the governing Texas regulatory agency is reviewing the data to determine whether any action is necessary to address this issue. If the Texas state agency were to decline to issue permits for, or limit the volumes of, new injection wells into the formations currently utilized by the Company, the Company may be required to seek alternative methods of disposing of produced waters, including injecting into deeper formations, which could increase its costs. 
+Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation. In recent years, the Obama administration’s budget proposals and other proposed legislation have included the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production. If enacted into law, these proposals would eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. These changes include, but are not limited to (1) the repeal of the percentage depletion allowance for oil and gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for U.S. production activities and (4) the increase in the amortization period from two years to seven years for geophysical costs paid or incurred in connection with the exploration for or development of, oil and gas within the United States. It is unclear whether any such changes will be enacted or how soon any such changes would become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could negatively affect the Company’s financial condition and results of operations. 
+35 
+Table of Contents 
+There are inherent limitations in all control systems, and misstatements due to error or fraud that could seriously harm our business may occur and not be detected. Our management, including our Chief Executive Officer and Chief Financial Officer, do not expect that our internal controls and disclosure controls will prevent all possible error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, an evaluation of controls can only provide reasonable assurance that all material control issues and instances of fraud, if any, in our company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Further, controls can be circumvented by the individual acts of some persons or by collusion of two or more persons. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. A failure of our controls and procedures to detect error or fraud could seriously harm our business and results of operations. 
+We have no plans to pay cash dividends on our common stock in the foreseeable future. We have no plans to pay cash dividends in the foreseeable future. Any future determination as to the declaration and payment of cash dividends will be at the discretion of our board of directors and will depend upon our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors deemed relevant by our board of directors. In addition, the terms of our credit facilities prohibit us from paying dividends and making other distributions. 
+Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations. Our business has become increasingly dependent on digital technologies to conduct certain exploration, development, production and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our exploration or production operations. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyber-attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. 
+While we have not experienced cyber-attacks, there is no assurance that we will not suffer such attacks and resulting losses in the future. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks. 
+We may be subject to the actions of activist shareholders. We have been the subject of increased activity by activist shareholders. Responding to shareholder activism can be costly and time-consuming, disrupt our operations and divert the attention of management and our employees from executing our business plan. Activist campaigns can create perceived uncertainties as to our future direction, strategy or leadership and may result in the loss of potential business opportunities, harm our ability to attract new investors, customers and joint venture partners and cause our stock price to experience periods of volatility or stagnation. Moreover, if individuals are elected to our board of directors with a specific agenda, our ability to effectively and timely implement our current initiatives, retain and attract experienced executives and employees and execute on our long-term strategy may be adversely affected. 
+ITEM 1B. Unr esolved Staff Comments 
+None. 
+ITEM 3. Leg al Proceedings 
+We are a defendant in various legal proceedings and claims, which arise in the ordinary course of our business. We do not believe the ultimate resolution of any such actions will have a material effect on our financial position or results of operations. 
+ITEM 4. Mi ne Safety Disclosures 
+36 
+Table of Contents 
+Not applicable. 
+37 
+Table of Contents 
+PAR T II. 
+ITEM 5. Ma rket for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+Market Information 
+Our common stock trades on the New York Stock Exchange under the symbol “CPE”. The following table sets forth the high and low sale prices per share as reported for the periods indicated. 
+Common Stock Price 
+2015 
+2014 
+High 
+Low 
+High 
+Low 
+First quarter 
+$ 
+8.15 
+$ 
+4.66 
+$ 
+9.00 
+$ 
+6.13 
+Second quarter 
+9.40 
+7.35 
+11.75 
+8.15 
+Third quarter 
+9.65 
+6.03 
+12.09 
+8.46 
+Fourth quarter 
+10.18 
+6.87 
+8.99 
+4.09 
+H olders 
+As of February 26, 2016 the Company had approximatel y 2,917 common stockholders of record. 
+Dividends 
+We have not paid any cash dividends on our common stock to date and presently do not expect to declare or pay any cash dividends on our common stock in the foreseeable future as we intend to reinvest our cash flows and earnings into our business. The declaration and payment of dividends is subject to the discretion of our Board of Directors and to certain limitations imposed under Delaware corporate law and the agreements governing our debt obligations. The timing, amount and form of dividends, if any, will depend on, among other things, our results of operations, financial condition, cash requirements and other factors deemed relevant by our Board of Directors. In addition, certain of our debt facilities contain restrictions on the payment of dividends to the holders of our common stock. 
+Holders of our 10% S eries A Cumulative P referred S tock are entitled to a cumulative dividend whether or not declared, of $5.00 per annum, payable quarterly, equivalent to 10.0% of the liquidation preference of $50.00 per share. Unless the full amount of the dividends for the 10% S eries A Cumulative P referred S tock is paid in full, we cannot declare or pay any dividend on our common stock. 
+During t he fourth quarter of 2015 , neither the Company nor any affiliated purchasers made repurchases of Callon’s equity securities. 
+Subsequent to December 31, 2015, a total of 120,000 shares of the Company’s 10% Series A Cumulative Preferred Stock were exchanged for 719,000 shares of c ommon s tock. 
+Equity Com pensation Plan Information 
+The following table summarizes information regarding the number of shares of our common stock that are available for issuance under all of our existing equity compensation plans as of December 31, 2015 (securities amounts are presented in thousands). 
+Plan Category 
+Number of securities to be issued upon exercise of outstanding options 
+Weighted-average exercise price of outstanding options, warrants and rights 
+Number of securities remaining available for future issuance under equity compensation plans 
+Equity compensation plans approved by security holders 
+— 
+$ 
+— 
+2,927 
+Equity compensation plans not approved by security holders 
+15 
+$ 
+14.37 
+— 
+Total 
+15 
+$ 
+14.37 
+2,927 
+38 
+Table of Contents 
+For additional information regarding the Company’s benefit plans and share-based compensation expense, see Notes 8 and 9 to the Consolidated Financial Statements. 
+Performance Graph 
+The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the performance of the Company’s common stock relative to four broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. 
+T he graph below compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the S&P 500 Index and SIG (Susquehanna International Group, LLP) Oil Exploration & Production Index from December 31, 20 10 , through December 31, 2015 . 
+The stock performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing. 
+Comparison of Five Year Cumulative Total Return 
+Assumes Initial Investment of $100 
+December 2015 
+For the Year Ended December 31, 
+Company/Market/Peer Group 
+2010 
+2011 
+2012 
+2013 
+2014 
+2015 
+Callon Petroleum Company 
+$ 
+100.00 
+$ 
+83.95 
+$ 
+79.39 
+$ 
+110.30 
+$ 
+92.06 
+$ 
+140.88 
+S&P 500 Index - Total Returns 
+100.00 
+102.11 
+118.45 
+156.82 
+178.28 
+180.75 
+SIG Oil Exploration & Production Index 
+100.00 
+90.94 
+84.64 
+107.12 
+76.81 
+42.18 
+39 
+Table of Contents 
+ITEM 6. Selected Fi nancial Data 
+The following table sets forth, as of the dates and for the periods indicated, selected financial information about the Company . The financial information for each of the five years in the period ended December 31, 2015 has been derived from our audited Consolidated Financial Statements for such periods. The information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and Notes thereto. The following information is not necessarily indicative of our future results (dollars in thousands, except per share amounts) . 
+For the Year Ended December 31, 
+2015 
+2014 
+2013 
+2012 
+2011 
+Statement of Operations Data 
+Operating revenues 
+Oil and natural gas sales 
+$ 
+137,512 
+$ 
+151,862 
+$ 
+102,569 
+$ 
+110,733 
+$ 
+127,644 
+Operating expenses 
+Total operating expenses 
+$ 
+346,622 
+$ 
+113,592 
+$ 
+91,905 
+$ 
+100,043 
+$ 
+88,022 
+Income (loss) from operations 
+(209,110)
+38,270 
+10,664 
+10,690 
+39,622 
+Net income (loss) (a) 
+(240,139)
+37,766 
+4,304 
+2,747 
+106,396 
+Income (loss) per share ("EPS") 
+Basic 
+$ 
+(3.77)
+$ 
+0.67 
+$ 
+(0.01)
+$ 
+0.07 
+$ 
+2.81 
+Diluted 
+$ 
+(3.77)
+$ 
+0.65 
+$ 
+(0.01)
+$ 
+0.07 
+$ 
+2.76 
+Weighted average number of shares outstanding for Basic EPS 
+65,708 
+44,848 
+40,133 
+39,522 
+37,908 
+Weighted average number of shares outstanding for Diluted 
+EPS 
+65,708 
+45,961 
+40,133 
+40,337 
+38,582 
+Statement of Cash Flows Data 
+Net cash provided by operating activities 
+$ 
+86,852 
+$ 
+94,387 
+$ 
+54,475 
+$ 
+51,290 
+$ 
+79,167 
+Net cash used in investing activities 
+(259,160)
+(452,501)
+(79,804)
+(93,703)
+(91,511)
+Net cash provided by (used in) financing activities 
+172,564 
+356,070 
+27,202 
+(243)
+38,703 
+Balance Sheet Data 
+Total oil and natural gas properties 
+$ 
+711,386 
+$ 
+742,155 
+$ 
+324,187 
+$ 
+269,521 
+$ 
+215,912 
+Total assets 
+788,594 
+863,346 
+423,953 
+378,173 
+369,707 
+Long-term debt (b) 
+328,565 
+321,576 
+75,748 
+120,668 
+125,345 
+Stockholders' equity 
+362,758 
+433,735 
+279,094 
+205,971 
+201,202 
+Proved Reserves Data 
+Total oil (MBbls) 
+43,348 
+25,733 
+11,898 
+10,780 
+10,075 
+Total natural gas (MMcf) 
+65,537 
+42,548 
+17,751 
+19,753 
+35,118 
+Total (MBOE) 
+54,271 
+32,824 
+14,857 
+14,072 
+15,928 
+Standardized measure (c) 
+$ 
+570,890 
+$ 
+579,542 
+$ 
+283,946 
+$ 
+231,148 
+$ 
+270,357 
+(a) 
+Net income for 2011 include d $69 ,283 of income tax benefit related to the reversal of the Company’s deferred tax asset valuation allowance. Net loss for 2015 include d the recognition of a write-down of oil and natural gas properties o f $208,435 as a result of the ceiling test limitation and $108,843 of income tax expense related to the recognition of a valuation allowance. See Notes 11 and 13 for additional information. 
+(b) 
+See Note 5 f or additional information. 
+(c) 
+Standardized measure is the future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet. Prices are based on either the preceding 12-months’ average price, based on closing prices on the first day of each month, or prices defined by existing contractual arrangements. Future production and development costs are based on current estimates with no escalations. Estimated future cash flows have been discounted to their present values based on a 10% discount rate. See Note 13 for additional information. 
+40 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+ITEM 7. Mana gement’s Discussion and Analysis of Financial Condition and Results of Operations 
+General 
+The following management’s discussion and analysis describes the principal factors affecting the Company’s results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying audited consolidated financial statements, information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results, which are included in various parts of this filing. Our Web site address is www.callon.com . All of our filings with the SEC are available free of charge through our Web site as soon as reasonably practicable after we file them with, or furnish them to, the SEC. Information on our Web site does not form part of this report on Form 10-K. 
+We are an independent oil and natural gas company established in 1950. We are focused on the acquisition, development, exploration and exploitation of unconventional, onshore, oil and natural gas reserves in the Permian Basin in West Texas, and more specifically, the Midland Basin. Our operating culture is centered on responsible development of hydrocarbon resources, safety and the environment, which we believe strengthens our operational performance. Our drilling activity is predominantly focused on the horizontal development of several prospective intervals, including multiple levels of the Wolfcamp formation and, more recently, the Lower Spraberry shale. We have assembled a multi-year inventory of potential h orizontal well locations and intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and acquisition of additional locations through acreage purchases, joint ventures and asset swaps. Our production was approximately 80% oil and 20% natural gas for the year ended December 31, 2015 . On December 31, 2015 , our net acreage position in the Permian Basin was 17,675 net acres. 
+Commodity Prices 
+The prices for oil and natural gas remain extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and actions by OPEC and other countries and government actions. Prices of oil and natural gas will affect the following aspects of our business: 
+· 
+our revenues, cash flows and earnings; 
+· 
+the amount of oil and natural gas that we are economically able to produce; 
+· 
+our ability to attract capital to finance our operations and cost of the capital; 
+· 
+the amount we are allowed to borrow under our senior secured revolving credit facility ; and 
+· 
+the value of our oil and natural gas properties. 
+Beginning in the second half of 2014, the NYMEX price for a barrel of oil declined from $105.37 on June 30, 2014 to $32.78 on February 26, 2016. For the year ended December 31, 2015, the average NYMEX price for a barrel of oil was $48.82 per Bbl compared to $92.83 per Bbl for the same period of 2014 . The NYMEX price for a barrel of oil ranged from a low of $34.73 per Bbl to a high of $61.43 per Bbl for the year ended December 31, 2015 . 
+For the year ended December 31, 2015 , the average NYMEX price for natural gas was $2.66 per MMBtu compared to $4.41 per MMBtu for the same period in 2014 . The NYMEX price for natural gas ranged from a low of $1.76 per MMBtu to a high of $3.23 per MMBtu for the year ended December 31, 2015 . 
+41 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+The table below illustrates the impact of crude oil and natural gas price assumptions on our estimated total proved reserve volumes for the year ended December 31, 2015 . The volumes resulting from the sensitivity analysis, which are for illustrative purposes only, incorporate a number of assumptions and have not been audited by the Company’s third-party engineer. 
+12-Month Average Prices 
+Estimate Total 
+Proved Reserves 
+Pricing Scenarios 
+Oil ($/Bbl) 
+Natural gas ($/Mcf) 
+(MBOE) 
+December 31, 2015 reserve report 
+$ 
+50.16 
+$ 
+2.64 
+54,271 
+Combined price sensitivity 
+Oil and natural gas +10% 
+$ 
+55.18 
+$ 
+2.90 
+54,778 
+Oil and natural gas -10% 
+$ 
+45.14 
+$ 
+2.38 
+53,623 
+Oil price sensitivity 
+Oil +10% 
+$ 
+55.18 
+$ 
+2.64 
+54,718 
+Oil -10% 
+$ 
+45.14 
+$ 
+2.64 
+53,716 
+Natural gas sensitivity 
+Natural gas +10% 
+$ 
+50.16 
+$ 
+2.90 
+54,339 
+Natural gas -10% 
+$ 
+50.16 
+$ 
+2.38 
+54,191 
+The Company uses the full cost method of accounting for its exploration and development activities. Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full cost ceiling). These rules generally require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling. For the year ended December 31, 2015 , the Company recorded a $208.4 million write-down of oil and natural gas properties as a result of the ceiling test limitation driven primarily by the significant decrease in oil prices beginning in the fo urth quarter of 2014. Based on prevailing commodity prices in the current environment, we could incur additional ceiling test write-downs in the future. However, we do not currently expect any future potential write-downs to have material adverse effects on the volumes of our proved oil and gas reserves. See Note 13 in the Footnotes to the Financial Statements for more information. 
+The table below presents results of the full cost ceiling test as of December 31, 2015 , along with various pricing scenarios to demonstrate the sensitivity of our full cost ceiling to changes in 12-month average oil and natural gas prices. This sensitivity analysis is as of December 31, 2015 and, accordingly, does not consider drilling results, production, changes in oil and natural gas prices, and changes in future development and operating costs subsequent to December 31, 2015 that may require revisions to our proved reserve estimates and resulting estimated future net cash flows used in the full cost ceiling test. 
+Excess (Deficit) of full 
+cost ceiling over net 
+(Increase) Decrease in excess of full cost ceiling 
+12-Month Average Prices 
+capitalized costs 
+over net capitalized costs 
+Pricing Scenarios 
+Oil ($/Bbl) 
+Natural gas ($/Mcf) 
+(in thousands) 
+December 31, 2015 Actual 
+$ 
+50.16 
+$ 
+2.64 
+$ 
+(208,435)
+Combined price sensitivity 
+Oil and natural gas +10% 
+$ 
+55.18 
+$ 
+2.90 
+$ 
+(99,838)
+$ 
+108,597 
+Oil and natural gas -10% 
+$ 
+45.14 
+$ 
+2.38 
+$ 
+(316,600)
+$ 
+(108,165)
+Oil price sensitivity 
+Oil +10% 
+$ 
+55.18 
+$ 
+2.64 
+$ 
+(107,516)
+$ 
+100,919 
+Oil -10% 
+$ 
+45.14 
+$ 
+2.64 
+$ 
+(308,869)
+$ 
+(100,434)
+Natural gas sensitivity 
+Natural gas +10% 
+$ 
+50.16 
+$ 
+2.90 
+$ 
+(200,415)
+$ 
+8,020 
+Natural gas -10% 
+$ 
+50.16 
+$ 
+2.38 
+$ 
+(215,974)
+$ 
+(7,539)
+42 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Significant accomplishments for 2015 include: 
+· 
+Increased annual production in 2015 by 70% to 9,610 MBOE as compared to 2014; 
+· 
+I ncreased 2015 proved reserves by 65% to 54.3 MMBOE as compared to 2014 ; 
+· 
+Placed a total of 33 gross horizontal wells and expanded horizontal production to five zones; 
+· 
+Financial flexibility enhanced by the completion of two common equity offering s fo r $175.5 m illion in net proceeds ; 
+· 
+Increase d the senior secured revolving credit facility’s borro wing base to $300 m illion ; 
+· 
+Acquired additional working interest s located primarily in Midland and Andrews Counties for approximately $29. 8 million, increasing our working interest s in the Carpe Diem field and CaBo area to approximately 100% and 66.5%, respectivel y ; 
+· 
+Increased total hedging portfolio to 64% and 36% of expected 2016 oil and natural gas volumes, respectively, based on the midpoint of estimates; and 
+· 
+One lost time incident and a 0.73 OSHA reportable incident rate in the field due to enhanced employee safety through near-miss reporting with a focus on quality engagements. 
+Acquisition activity 
+On N ovember 9, 2015, we acquired additional working interest s in 628 net acres located on the Carpe Diem and Casselman-Bohannon fields (“ CaBo ”) in Midland, Andrews and Ector Counties, Texas, which are located in the central portion of the Midland Basin, for an aggregate cash purchase price of $29.8 million based on an effective date of October 1, 2015. The acquisition increases our working interest in the Carpe Diem field to approximately 100% with a net revenue interest of 79% and increases the working interest in the CaBo area to approximately 67% with a net revenue interest of 50%. See Note 3 in the Footnotes to the Finan cial Statements for additional information regarding the acquisition. 
+During the first quarter of 2016, we completed the acquisition of an additional 4.9% working interest (3.7% net revenue interest) in the CaBo area for total cash consideration of $9.3 million, excluding customary purchase price adjustments, increasing our working interest to 71.3% with a 53.5% net revenue interest. 
+Operational Highlights 
+A ll of our producing pro perties are located in the Permian Basin. As a result of our acquisition and horizontal development efforts, our production grew 70% in 2015 compared to 2014 , increasing to 3,508 MBOE in 2015 from 2,062 MBOE in 2014 . Our production in 2015 was approximately 80% oil and 20% natural gas. 
+Net Production (MBOE) 
+For the Year Ended December 31, 
+2015 
+2014 
+Change 
+% Change 
+Permian 
+Southern Midland Basin 
+2,139 
+1,497 
+642 
+43% 
+Central Midland Basin 
+1,367 
+549 
+818 
+149% 
+Other 
+2 
+16 
+(14)
+(88)% 
+Total 
+3,508 
+2,062 
+1,446 
+70% 
+During 2015 , we primarily operated with two horizontal rigs after releasing a vertical drilling rig in March 2015 . The following table s summarize the Company’s drilling activity in the Permian Basin for the year ended December 31, 2015 : 
+Completions include wells drilled prior to the fourth quarter of 2015 . 
+For the Year Ended December 31, 2015 
+Drilled 
+Completed (a) 
+Awaiting Completion 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Southern Midland Basin horizontal wells 
+12 
+11.8 
+15 
+14.8 
+— 
+— 
+Central Midland Basin horizontal wells 
+24 
+15.3 
+18 
+11.0 
+6 
+4.3 
+Central Midland Basin vertical wells 
+— 
+— 
+1 
+0.4 
+— 
+— 
+Total Midland Basin wells 
+36 
+27.1 
+34 
+26.2 
+6 
+4.3 
+(a) 
+Completions include wells drilled prior to 2015 . 
+43 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Reserve Growth 
+As of December 31, 2015 , our estimated proved reserves increased 65% t o 54.3 MMBOE compared to 32.8 MMBOE of proved reserves at year-end 2014 . O ur significant growth in proved reserves was primarily attributable to our horizontal development and acquisiti on efforts . Our pro ved reserves at year-end 2015 were 80% oil and 20% natural gas, compared to 78% oil and 22% natural gas at year-end 2014 . 
+Liquidity and Capital Resources 
+Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions, the sale of debt and equity securities and asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration and exploitation of oil and natural gas properties, in addition to r efinancing of debt instruments. In 2015, we amended the borrowing base under our s enior secured revolving credit facility to $300 million and completed two common stock offerings to raise additional capital . W e regularly evaluate other sources of capital to complement our cash flow from operations and other sources of capital as we pursue our long-term growth plans in the Permian Basin. 
+Cash and cash equivalents in creased $0.2 million in the year ended December 31, 2015 to $1.2 million compared to $1.0 million at December 31, 2014 . As of February 26, 2016 , our available liquidity was $220 million. 
+Liquidity and cash flow 
+For the Year Ended December 31, 
+(in millions) 
+2015 
+2014 
+2013 
+Net cash provided by operating activities 
+$ 
+86.8 
+$ 
+94.4 
+54.5 
+Net cash used in investing activities 
+(259.2)
+(452.5)
+(79.8)
+Net cash provided by financing activities 
+172.6 
+356.1 
+27.2 
+Net change in cash 
+$ 
+0.2 
+$ 
+(2.0)
+$ 
+1.9 
+Operating activities. For the year ended December 31, 2015 , net cash provided by operating activities was $86.8 million, compared to $94.4 million for the same period in 2014 . The decrease was predominantly attributable to the following: 
+· 
+A 9% decline in oil and natural gas revenues precipitated by depressed commodity prices offset by a 70% increase in production. Offsetting the decline in revenues were gains on the sett lement of derivative contracts; 
+· 
+A 17% increase in lease operating expenses and production taxes primarily due to the growth in production and operations. 
+· 
+An increase in nonrecurring early retirement expenses, payments on cash-settled RSU awards and a nonrecurring fee for the early termination of a contract for a vertical rig ; and 
+· 
+An increase in interest expense related to a higher average outstanding debt balance. As previously discussed, borrowings from financial institutions was one of our primary sources of capital to fund for acquisitions, development, exploration and exploitation of oil and natural gas properties. 
+Production, realized prices, and operating expenses are discussed below in Results of Operations. See Notes 6 and 7 in the Footnotes to the Financial Statements for a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation. See Note 3 in the Footnotes to the Financial Statements for more information on the Company’s acquisitions. 
+Investing activities . For the year ended December 31, 2015 , net cash used in investing activities was $259.2 million compared to $452.5 million for the same period in 2014 . The $193.3 million decrease in cash used in investing activities was primarily attributable to the following: 
+· 
+An $1 2 .0 million decrease in operating expenditures primarily due to reductions in drilling and completion costs achieved during 2015 ; 
+· 
+A $6.7 million increase in capital expenditures related to capitalized general and administrative costs allocated directly to exploration and development pr ojects and capitalized interest ; 
+· 
+A $190. 7 million decrease in acquisition costs ; and 
+44 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+· 
+A $2.6 million decrease in proceeds resulting from sales of mineral interest and equipment. 
+Our investing activities , on a cash basis, include the following for the periods indicated (in millions): 
+For the Year Ended December 31, 
+2015 
+2014 
+$ Change 
+Southern Midland Basin 
+$ 
+118.0 
+$ 
+160.3 
+$ 
+(42.4)
+Central Midland Basin 
+87.7 
+56.9 
+30.8 
+Other 
+— 
+0.5 
+(0.5)
+Total operational expenditures 
+205.7 
+217.7 
+(12.0)
+Capitalized general and administrative costs allocated directly to 
+exploration and development projects 
+11.1 
+12.5 
+(1.4)
+Capitalized interest 
+10.5 
+2.4 
+8.1 
+Total capitalized general and administrative and interest costs 
+21.6 
+14.9 
+6.7 
+Total operational expenditures inclusive of capitalized general 
+and administrative and interest costs 
+227.3 
+232.6 
+(5.3)
+Acquisitions 
+32.2 
+222.9 
+(190.7)
+Proceeds from sales of mineral interest and equipment 
+(0.4)
+(3.0)
+2.6 
+Total investing activities 
+$ 
+259.2 
+$ 
+452.5 
+$ 
+(193.4)
+O n an accrual (GAAP) basis, which is the methodology used for establishing our annual capital budget, capital expenditures were as follows for the year ende d December 31, 2015: 
+· 
+Operational capital expenditures of $ 18 5 .9 million ; 
+· 
+Acquisition costs of $32.2 million; and 
+· 
+Total operational expenditures, inclusive of capitalized general and administrative and interests costs of $ 2 46 m illion . 
+General and administrative expenses and capitalized interest are discussed below in Results of Operations. See Note 3 in the Footnotes to the Financial Statements for additional information on acquisitions and dispositions . See Note 14 in the Footnotes to the Financial Statements for a discussion of sale of specialized deep water property and equipment . 
+F inancing activities. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our senior secured revolving credit facility, term debt and equity offerings. For the year ended December 31, 2015 , net cash provided by financing activities was $172.6 million compared to cash provided by financing activities of $356.1 million during the same period of 2014 . The change in net cash provided by financing activities was primarily attributable to the following: 
+· 
+Net borrowings on our senior secured revolving credit facility were $5.0 million, $8.0 million lower compared to the same period of 2014 ; 
+· 
+In March 2014, we entered into a secured second lien term loan and drew an initial amount of $62.5 million . A portion of the proceeds were used to complete the full redemption of the remaining $48.5 million principal amount o f our outstanding 13% Senior Notes d ue 2016 . Subsequently, in October 2014, we entered into a new secured second lien term loan and drew $300 million. The proceeds were used to repay the balance of the previous term loan and to partially fund an acquisition made during 2014 ; and 
+· 
+A $53.0 million increase in proceeds resulting from t wo common stock offerings in 2015 as compared to one offering in 2014. 
+45 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Net cash provided by financing activities includes the following for the periods indicated (in millions): 
+For the Year Ended December 31, 
+2015 
+2014 
+$ Change 
+Net borrowings on credit facility 
+$ 
+5.0 
+$ 
+13.0 
+$ 
+(8.0)
+Borrowings on term loans, net of financing cost 
+— 
+278.6 
+(278.6)
+Redemption of 13% senior notes 
+— 
+(50.1)
+50.1 
+Issuance of common stock 
+175.5 
+122.5 
+53.0 
+Payment of preferred stock dividends 
+(7.9)
+(7.9)
+— 
+$ 
+172.6 
+$ 
+356.1 
+$ 
+(183.5)
+See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s debt . See Note 10 in the Footnotes to the Financial Statements for additional information about the Company’s equity offering s and Series A 10% Cumulative P referred S tock . 
+Senior secured revolving credit facility (“Credit Facility”) 
+On March 11, 2014, the Company entered into the Fifth Amended and Restated Credit Agreement to the Credit Facility with a maturity date of March 11, 2019. JPMorgan Chase Bank, N.A. is Administrative Agent, and participating lenders include Regions Bank, Citibank, N.A., Capital One, N.A., KeyBank, N.A., Whitney Bank, IberiaBank, N.A., OneWest Bank, N.A., SunTrust Bank and Royal Bank of Canada. The total notional amount available under the Credit Facility is $500 million. Amounts borrowed under the Credit Facility may not exceed the borrowing base, which is generally reviewed on a semi-annual basis. As of December 31, 2015, the Credit Facility’s borrowing base was $300 million . The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. As of December 31, 2015 , the balance outstanding on the Credit Facility was $40.0 million with a weighted-average interest rate of 2.07% , calculated as the LIBOR plus a tiered rate ranging from 1.75% to 2.75% , which is determined based on utilization of the facility. In addition, the Credit Facility carries a commitment fee of 0.5% per annum, payable quarterly, on the unused portion of the borrowing base . The Company had $260.0 million of available borrowings under the Credit Facility as of December 31, 2015. 
+Term loans 
+On March 11, 2014, the Company entered into a secured term loan in an aggregate amount of up to $125 million, including initial commitments of $100 million and additional availability of $25 million subject to the consent of two-thirds of the lenders and compliance with financial covenants after giving effect to such increase. The term loan had a maturity date of September 11, 2019, and was no t subject to mandatory prepayments unless new debt or preferred stock we issued. It was prepayable at the Company’s option, subject to a prepayment premium. The prepayment amount was (i) 102% if the prepayment event occurs prior to March 11, 2015, and (ii) 101% if the prepayment event occurs on or after March 15, 2015 but before March 15, 2016, and (iii) 100% for prepayments made on or after March 15, 2016. The term loan was secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor agreement. On April 10, 2014, the Company drew an initial amount of $62.5 million with an original issue discount of 1.0% . 
+On October 8, 2014, the term loan described above was repaid in full using a new secured second lien term loan (the “ Second Lien Loan ”) in conjunction with the closing of an acquisition in the Central Midland Basin , resulting in a loss on ear ly extinguishment of debt of $3.1 million . The Second Lien Loan has a maturity date of October 8, 2021. On October 8, 2014, the Company drew an initial amount of $300 million with a discount of 2.0% and an interest rate of 8.5% , calculated at a rate of LIBOR (subject to a floor rate of 1.0% ) plus 7.5% per annum. The Second Lien Loan may be prepaid at the Company’s option, subject to a prepayment premium. The prepayment amount is (i) 102% if the prepayment event occurs prior to October 8, 201 6 , and (ii) 101% if the prepayment event occurs on or after October 8, 201 6 but before October 8, 201 7 , and (iii) 100% for prepayments made on or after October 8, 201 7 . The Second Lien Loan is secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor agreement. The Royal Bank of Canada is Administrative Agent, and participants include several institutional lenders. 
+10% Series A Cumulative Preferred Stock (“Preferred Stock”) 
+Holders of the Company’s Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10.0% per annum of the $50.00 liquidation 
+46 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+preference per share (equivalent to $5.00 per annum per share). Dividends are payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by our Board of Directors. Preferred Stock dividends were $7 . 9 million , $7 . 9 million and $4 . 6 million in 2015 , 2014 and 2013 respectively. 
+The Preferred Stock has no stated maturity and is not be subject to any sinking fund or other mandatory redemption. On or after May 30, 2018, the Company may, at its option, redeem the Preferred Stock, in whole or in part, by paying $50.00 per share, plus any accrued and unpaid dividends to the redemption date. 
+Following a change of control, the Company will have the option to redeem the Preferred Stock, in whole but not in part for $50.00 per share in cash, plus accrued and unpaid dividends (whether or not declared), to the redemption date. If the Company does not exercise its option to redeem the Preferred Stock upon a change of control, the holders of the Preferred Stock have the option to convert the Preferred Stock into a number of shares of the Company’s common stock based on the value of the common stock on the date of the change of control as determined under the certificate of designations for the Preferred Stock. If the change of control occurred on December 31, 2015 , and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of $8.34 as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately 6.0 shares of common stock. If the Company exercises its redemption rights relating to shares of Preferred Stock, the holders of Preferred Stock will not hav e the conversion right described above. 
+Subsequent to December 31, 2015, a total of 120,000 shares of Preferred Stock were exchanged for a total of 719,000 shares of Common Stock. 
+Common Stock Offering 
+On November 16 , 2015, the Company completed an underwritten public offering of 12,000,000 shares of its common stock at $8.40 per share, before underwriting discounts, and the exercise in full by the underwriters of their option to purchase 1,800,000 additional shares of common stock at $8.40 per share, before underwriting discounts. The Company received net proceeds of approximately $1 10 million , after the underwriting discounts and estimated offering costs , which were used to prepay amounts outstanding under the Credit Facility . 
+On March 13, 2015, the Company completed an underwritten public offering of 9,000,000 shares of its common stock at $6.55 per share, before underwriting discounts, and the exercise in full by the underwriters of their option to purchase 1,350,000 additional shares of common stock at $6.55 per share, before underwriting discounts. The Company received ne t proceeds of approximately $65. 6 million , after the underwriting discounts and estimated offering costs , which were used to prepay amounts outstanding under the Credit Facility . 
+2016 Capital Plan 
+In January 2016, we announced an operational capital budget for 2016 in the range of $75 to $80 million. This represents a reduction of approximately 25% to 30% to the comparable 2015 budgeted amounts in response to a lower oil and natural gas price environment. 
+In the first quarter of 2016 we plan to transition from a two-rig to a one-rig program. We expect our 2016 horizontal drilling program will be focused almost exclusively on the Lower Spraberry zone in the Central Midland Basin with lateral lengths ranging from approximately 5,000’ laterals to 9,000’ laterals. All wells will be completed from two to three well pads. We plan to have 19 gross (13.7 net) operated horizontal wells scheduled to be placed on production target ing the Lower Spraberry shale. Also, we plan to have two gross (0.4 net) non-operated horizontal wells scheduled to be placed on production targeting the Lower Spraberry and Wolfcamp A shale. The two non-operated horizontal wells will be 10,000’ laterals that leverage our existing acreage position. 
+In addition to the operational capital expenditures above, we budgeted approximately $ 1 7.0 million for capitalized general and administrative expenses. 
+Based upon current commodity price expectations for 2016, we believe that our cash flow from operations and available borrowings under our C redit F acility will be sufficient to fund our operations for 2016, including working capital requirements. However, future cash flows are subject to a number of variables, including forecasted production volumes and commodity prices. We are the operator for 90% of our 2016 operational capital program and, as a result, the amount and timing of a substantial portion of our planned capital 
+47 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+expenditures is largely discretionary. Accordingly, we may determine it prudent to curtail drilling and completion operations due to capital constraints or reduced returns on investment as a result of commodity price weakness. Alternatively, we will monitor opportunities to redeploy our second drilling rig on our asset base if market conditions improve or in conjunction with potential acquisitions of new acreage. 
+Contractual Obligations 
+The following table includes the Company’s current contractual obligations and purchase commitments (in thousands) : 
+Payments due by Period 
+Total 
+< 1 Year 
+Years 2 - 3 
+Years 4 - 5 
+>5 Years 
+Secured second lien term loan 
+$ 
+300,000 
+$ 
+— 
+$ 
+— 
+$ 
+300,000 
+$ 
+— 
+Senior secured revolving credit facility 
+40,000 
+— 
+40,000 
+— 
+— 
+Drilling rig leases 
+28,440 
+10,980 
+17,460 
+— 
+— 
+Office space lease and other commitments 
+2,494 
+621 
+1,096 
+717 
+60 
+Total 
+$ 
+370,934 
+$ 
+11,601 
+$ 
+58,556 
+$ 
+300,717 
+$ 
+60 
+48 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Results of Operations 
+The following table sets forth certain operating information with respect to the Company’s oil and natural gas operat ions for the periods indicated: 
+For the Year Ended December 31, 
+2015 
+2014 
+$ 
+Change 
+% Change 
+2013 
+$ Change 
+% Change 
+Net production 
+Oil (MBbls) 
+2,789 
+1,692 
+1,097 
+65% 
+911 
+781 
+86% 
+Natural gas (MMcf) 
+4,312 
+2,220 
+2,092 
+94% 
+3,011 
+(791)
+(26)% 
+Total (MBOE) 
+3,508 
+2,062 
+1,446 
+70% 
+1,413 
+649 
+46% 
+Average daily production (BOE/d) 
+9,610 
+5,649 
+3,961 
+70% 
+3,871 
+1,778 
+46% 
+% oil (BOE basis) 
+80% 
+82% 
+64% 
+Average realized sales price 
+Oil (Bbl) (excluding impact of cash settled derivatives) 
+$ 
+44.88 
+$ 
+82.37 
+$ 
+(37.49)
+(46)% 
+$ 
+97.65 
+$ 
+(15.28)
+(16)% 
+Oil (Bbl) (including impact of cash settled derivatives) 
+56.82 
+84.84 
+(28.02)
+(33)% 
+99.32 
+(14.48)
+(15)% 
+Natural gas (Mcf) (excluding impact of cash settled 
+derivatives) 
+$ 
+2.86 
+$ 
+5.63 
+$ 
+(2.77)
+(49)% 
+$ 
+4.52 
+$ 
+1.11 
+25% 
+Natural gas (Mcf) (including impact of cash settled 
+derivatives) 
+3.26 
+5.59 
+(2.33)
+(42)% 
+4.47 
+1.12 
+25% 
+Total (BOE) (excluding impact of cash settled 
+derivatives) 
+$ 
+39.20 
+$ 
+73.65 
+$ 
+(34.45)
+(47)% 
+$ 
+72.59 
+$ 
+1.06 
+1% 
+Total (BOE) (including impact of cash settled 
+derivatives) 
+49.18 
+75.63 
+(26.45)
+(35)% 
+73.56 
+2.07 
+3% 
+Oil and natural gas revenues (in thousands) 
+Oil revenue 
+$ 
+125,166 
+$ 
+139,374 
+$ 
+(14,208)
+(10)% 
+$ 
+88,960 
+$ 
+50,414 
+57% 
+Natural gas revenue 
+12,346 
+12,488 
+(142)
+(1)% 
+13,609 
+(1,121)
+(8)% 
+Total 
+$ 
+137,512 
+$ 
+151,862 
+$ 
+(14,350)
+(9)% 
+$ 
+102,569 
+$ 
+49,293 
+48% 
+Additional per BOE data 
+Sales price 
+$ 
+39.20 
+$ 
+73.65 
+$ 
+(34.45)
+(47)% 
+$ 
+72.59 
+$ 
+1.06 
+1% 
+Lease operating expense 
+7.71 
+10.85 
+(3.14)
+(29)% 
+14.00 
+(3.15)
+(22)% 
+Production taxes 
+2.79 
+4.35 
+(1.56)
+(36)% 
+2.92 
+1.43 
+49% 
+Operating margin 
+$ 
+28.70 
+$ 
+58.45 
+$ 
+(29.75)
+(51)% 
+$ 
+55.67 
+$ 
+2.78 
+5% 
+49 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Revenues 
+The following tables are intended to reconcile the change in oil, natural gas and total revenue for the respective periods presented by reflecting the effect of changes in volume and in the underlying commodity prices. 
+(in thousands) 
+Oil 
+Natural Gas 
+Total 
+Revenues for the year ended December 31, 2012 
+$ 
+96,584 
+$ 
+14,149 
+$ 
+110,733 
+Volume (decrease) 
+(6,528)
+(2,278)
+(8,806)
+Price increase (decrease) 
+(1,096)
+1,738 
+642 
+Net (decrease) 
+(7,624)
+(540)
+(8,164)
+Revenues for the year ended December 31, 2013 
+$ 
+88,960 
+$ 
+13,609 
+$ 
+102,569 
+Volume increase (decrease) 
+76,237 
+(3,575)
+72,662 
+Price increase (decrease) 
+(25,823)
+2,454 
+(23,369)
+Net increase (decrease) 
+50,414 
+(1,121)
+49,293 
+Revenues for the year ended December 31, 2014 
+$ 
+139,374 
+$ 
+12,488 
+$ 
+151,862 
+Volume increase 
+90,398 
+11,774 
+102,172 
+Price (decrease) 
+(104,606)
+(11,916)
+(116,522)
+Net (decrease) 
+(14,208)
+(142)
+(14,350)
+Revenues for the year ended December 31, 2015 
+$ 
+125,166 
+$ 
+12,346 
+$ 
+137,512 
+Oil revenue 
+For the year ended December 31, 2015 , oil revenues of $125.2 million decreased $ 14.2 million, or 10% , compared to revenues of $139.4 million for the same period of 2014 . The decrease in oil revenue was primarily attributable to a 46% decrease in the average realized sales price , which fell to $44.88 per Bbl from $82.37 per Bbl, and was predominately offset by a 65% increase in production. The increase in production was primarily attributable to a 1,197 MBbls increase in production from our Permian properties resulting from an increased number of producing wells from our horizontal drilling program and acquisitions , offset by normal and expected declines from our existing wells. 
+For the year ended December 31, 2014 , oil revenues of $139.4 million increased $50.4 million, or 57% , compared to revenues of $89.0 million for the same period of 2013 . The increase primarily relate d to an 86% increase in total production, while the average realized sales price decreased 16%. The increase i n production was wholly attributable to a 1,048 MBbls increase in Permian production resulting from an increased number of producing wells from acquisitions and our horizontal drilling program , offset by normal and expected declines from our existing wells. Partially offsetting the Permian increase was a 267 MBbls decline in production due to the sale of our deepwater Medusa field in the fourth quarter of 2013. 
+Natural gas revenue (including NGLs) 
+Natural gas revenues of $12.3 million decreased $0.2 million, or 1% , during the year ended December 31, 2015 compared to $12.5 million for the same period of 2014 . The de crease primarily relates to 49% decrease in the average price realized, which fell to $2.86 per Mcf from $5.63 per Mcf, reflecting decreases in both natural gas and natural gas liquids prices and was predominantly offset by a 94% increase in natural gas volumes. The increase in production was primarily attributable to increased production o f 1,757 MMcf from our Permian properties resulting from an increased number of producing wells as mentioned above. 
+Natural gas revenues of $12.5 million decreased $1.1 million, or 8% , during the year ended December 31, 2014 compared to $13.6 million for the same period of 2013 . The average realized price increase d to $5.63 per Mcf from $4.52 per Mcf, or 2 5 %, while total production decreased 26%. The decrease in production was primarily attributable to a 1,919 MMcf decrease in production due to the sale of our offshore fields and Haynesville property in the fourth quarter of 2013. Offsetting the production decline was a 1,128 M Mcf increase in production from our Permian properties resulting from an increased number of producing wells as mentioned above. 
+50 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Operating Expenses 
+For the Year Ended December 31, 
+Per 
+Per 
+Total Change 
+BOE Change 
+(in thousands, except per unit data) 
+2015 
+BOE 
+2014 
+BOE 
+$ 
+% 
+$ 
+% 
+Lease operating expenses 
+$ 
+27,036 
+$ 
+7.71 
+$ 
+22,372 
+$ 
+10.85 
+4,664 
+21% 
+(3.14)
+(29)% 
+Production taxes 
+9,793 
+2.79 
+8,973 
+4.35 
+820 
+9% 
+(1.56)
+(36)% 
+Depreciation, depletion and amortization 
+69,249 
+19.74 
+56,724 
+27.51 
+12,525 
+22% 
+(7.77)
+(28)% 
+General and administrative 
+28,347 
+8.08 
+25,109 
+12.18 
+3,238 
+13% 
+(4.10)
+(34)% 
+Accretion expense 
+660 
+0.19 
+826 
+0.40 
+(166)
+(20)% 
+(0.21)
+(53)% 
+Write-down of oil and natural gas properties 
+208,435 
+nm 
+— 
+— 
+208,435 
+nm 
+nm 
+nm 
+Rig termination fee 
+3,075 
+nm 
+— 
+— 
+3,075 
+nm 
+nm 
+nm 
+Gain on sale of other property and equipment 
+— 
+— 
+(1,080)
+(0.52)
+1,080 
+nm 
+0.52 
+nm 
+Acquisition expense 
+27 
+0.01 
+668 
+0.32 
+(641)
+(96)% 
+(0.31)
+(97)% 
+For the Year Ended December 31, 
+Per 
+Per 
+Total Change 
+BOE Change 
+(in thousands, except per unit data) 
+2014 
+BOE 
+2013 
+BOE 
+$ 
+% 
+$ 
+% 
+Lease operating expenses 
+$ 
+22,372 
+$ 
+10.85 
+$ 
+19,779 
+$ 
+14.00 
+2,593 
+13% 
+(3.15)
+(22)% 
+Production taxes 
+8,973 
+4.35 
+4,133 
+2.92 
+4,840 
+117% 
+1.43 
+49% 
+Depreciation, depletion and amortization 
+56,724 
+27.51 
+43,967 
+31.12 
+12,757 
+29% 
+(3.61)
+(12)% 
+General and administrative 
+25,109 
+12.18 
+20,534 
+14.53 
+4,575 
+22% 
+(2.35)
+(16)% 
+Accretion expense 
+826 
+0.40 
+1,785 
+1.26 
+(959)
+(54)% 
+(0.86)
+(68)% 
+Gain on sale of other property and equipment 
+(1,080)
+(0.52)
+— 
+— 
+(1,080)
+nm 
+(0.52)
+nm 
+Impairment of other property and equipment 
+— 
+— 
+1,707 
+1.21 
+(1,707)
+nm 
+(1.21)
+nm 
+Acquisition expense 
+668 
+0.32 
+— 
+— 
+668 
+nm 
+0.32 
+nm 
+*nm = not meaningful 
+Lease operating expen ses. These ar e daily costs incurred to extract oil and natural gas out of the ground, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and workover expenses related to our oil and natural gas properties. 
+LOE for the year ended December 31, 2015 increased by 21% to $27.0 million compared to $22.4 million for the same period of 2014 primarily r elated to the growth in Permian production and operations as a result of our horizontal drilling program and acquisition efforts . LOE per BOE for the year ended December 31, 2015 decreased t o $ 7.71 per BOE compared to $ 10.85 per BOE for the same period of 2014 . The $3.14 per BOE decrease resulted primarily from a decrease in the number of workovers period over period and the impact of leveraging fixed expenses over a larger production base . 
+LOE for the year ended December 31, 2014 increased by 13% to $22.4 million compared to $19.8 million for the same period of 2013. LOE per BOE for the year ended December 31, 2014 decreased by 22% to $10.85 per BOE from $14.00 per BOE for the same period of 2013. The $3.15 per BOE decrease was primarily due to the removal of costs related to our deep water Medusa field and our other offshore fields, which were sold during the f ourth quarter of 2013 , offset by a n increase in costs related to the growth in Permian production and operations, including an increase in workover expenses associated with the impact of accelerated horizontal well activity on surrounding producing wells. 
+Production taxes. Production taxes include severance and ad valorem taxes. In general, production taxes are directly related to commodity price changes; however, severance taxes are based upon current year commodity prices, whereas ad valorem taxes are based upon p rior year commodity prices. Severance taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. In the counties where our production is located, we are also subject to ad valorem taxes, which are generally based on the taxing jurisdictions’ valuation of our oil and gas properties. 
+For the year ended December 31, 2015 , production taxes increased 9% , or $0.8 million, to $9.8 million compared to $9.0 million for the same period of 2014 . The increase was primarily due to an increase in ad valorem taxes attributable to a greater number of 
+51 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+producing wells as a result of our horizontal drilling program and acquisition efforts. Offsetting this increase was a reduction in severance taxes as a result of the decline of oil and natural gas revenue as previously mentioned. On a per BOE basis, production taxes for the year ended , December 31 , 2015 dec reased by 36 % co mpared to the same period of 2014 . 
+For the year ended December 31, 2014, production taxes increased 117%, or $4.9 million, to $9.0 million compared to $4.1 million for the same period of 2013. The increase was predominantly attributable to an increase in onshore production subject to these taxes accompanied by a decline in offshore production, resulting from the sale of our Gulf of Mexico position in 2013, which was exempt from production taxes. 
+Depreciation, depletion and amortization (“DD&A”). Under the full cost accounting method, we capitalize costs within a cost center and then systematically expense those costs on a units-of-production basis based on proved oil and natural gas reserve quantities. We calculate depletio n on the following types of costs: (i) all capitalized costs, other than the cost of investments in unevaluated properties, less accumulated amortization; (ii) the estimated future expenditures to be incurred in developing proved reserves; and (iii) the esti mated dismantlement and abandonment costs, net of estimated salvage values. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years. 
+For the year ended December 31, 201 5 , DD&A increase d 22% to $69.2 million from $ 56.7 million compared to the same period of 201 4 . The increase is primarily attributable to a 70 % increase in production, offset by a 2 8 % decrease in our per BOE DD&A rate. For the year ended December 31, 2015 , DD&A on a per unit basis decreased to $19.74 per BOE compared to $27.51 per BOE for the same period of 2014 as a result of the increase in our estimated proved reserves relative to our depreciable base as a result of our efforts on development, exploration, and exploitation of onshore oil and natural gas reserves in the Permian Basin and the write-down of oil and natural gas properties in the third quarter of 2015. 
+For the year ende d December 31, 2014, DD&A increased 29% to $56.7 million from $44.0 million compared to the same period of 2013. The increase is primarily attributable to a 46% increase in production, offset by a 12% decrease in our per BOE DD&A rate. For the year ended December 31, 2014, DD&A on a per unit basis decreased to $27.51 per BOE compared to $31.12 per BOE for the same period of 2013 as a result of the increase in our estimated proved reserves relative to our depreciable base as a result of our efforts on development, exploration, and exploitation of onshore oil and natural gas reserves in the Permian Basin. 
+General and administrative, net of amounts capitalized (“G&A”). These are costs incurred for overhead, including payroll and benefits for our corporate staff, severance and early retirement expenses, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, depreciation of corporate level assets, public company costs, vesting of equity and liability awards under share-based compensation plans and related mark-to-market valuation adjustments over time, fees for audit and other professional services, and legal compliance. 
+G&A for the year ended December 31, 2015 increased to $ 28.3 million compared to $25.1 million for the same period of 2014 . G&A expenses for the periods indicated include the following (in millions): 
+For the Year Ended December 31, 
+2015 
+2014 
+$ Change 
+Recurring expenses 
+G&A 
+$ 
+15.1 
+$ 
+15.3 
+$ 
+(0.2)
+Share-based compensation 
+2.1 
+2.7 
+(0.6)
+Fair value adjustments of cash-settled RSU awards 
+6.1 
+3.1 
+3.0 
+Non-recurring expenses 
+Early retirement expenses 
+3.5 
+1.4 
+2.1 
+Early retirement expenses related to share-based compensation 
+1.1 
+1.1 
+— 
+Expense related to a threatened proxy contest 
+0.4 
+1.5 
+(1.1)
+Total G&A expenses 
+$ 
+28.3 
+$ 
+25.1 
+$ 
+3.2 
+52 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+G&A for the year ended December 31, 2014 increased to $25.1 million compared to $20.5 million for the same period of 2013. G&A expenses for the periods indicated include the following (in millions): 
+For the Year Ended December 31, 
+2014 
+2013 
+$ Change 
+Recurring expenses 
+G&A 
+$ 
+15.3 
+$ 
+15.4 
+$ 
+(0.1)
+Share-based compensation 
+2.7 
+2.1 
+0.6 
+Fair value adjustments of cash-settled RSU awards 
+3.1 
+2.9 
+0.2 
+Non-recurring expenses 
+Early retirement expenses 
+1.4 
+— 
+1.4 
+Early retirement expenses related to share-based compensation 
+1.1 
+— 
+1.1 
+Expense related to a threatened proxy contest 
+1.5 
+0.1 
+1.4 
+Total G&A expenses 
+$ 
+25.1 
+$ 
+20.5 
+$ 
+4.6 
+Accretion expense. The Company is required to record the estimated fair value of liabilities for obligations associated with the retirement of tangible long -lived assets and the associated ARO costs. Interest is accreted on the present value of the ARO and reported as accretion expense within operating expenses in the consolidated statements of operations. 
+Accretion expense related to our ARO decreased 20% for the year ended December 31, 2015 compared to the same period of 2014 . The decrease in accretion expense correlates with the Company’s average ARO balance , which wa s $5.4 mil lion during 201 5 versus $6.5 million during 201 4 . See Note 12 in the Footnotes to the Financial Statements for additional information regarding the Company’s ARO. 
+Accretion expense related to our ARO decreased 54% for the year ended December 31, 2014 compared to the same period of 2013. The decrease in accretion expense correlates with the Company’s average ARO balance , which was $6.5 million during 2014 versus $11.5 million during 2013. The reduction in our average ARO was primarily a result of the divestiture of our offshore fields in the fourth quarter of 2013. 
+Wr i te-down of oil and natural gas properties . Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full cost ceiling amount). 
+During 2015, the Company recognized a write-down of oil and natural gas properties o f $208.4 million as a result of the ceiling test limitation. No write-down was recognized during 2014 . See Note 13 in the Footnotes to the Financial Statements for additional information. Based on prevailing commodity prices in the current environment, we could incur additional ceiling test write-downs in the future. 
+Rig termination fee. During the first quarter of 2015, the Company recognize d $3.1 m illion in expense related to the early termination of the contract for its vertical rig. See Note 14 in the Footnotes to the Financial Statements for additional information. 
+Acquisition expense. Acquisition expense decreased $0.6 million for the year ended December 31, 2015 compared to the same period of 2014. A cquisition expense related to costs with respect to our acquisition efforts in the Permian Basin. See Note 3 in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions. 
+Gain on sale of other property and equipment . During 2014, the Company entered into an agreement to sell certain specialized deep water equipment that resulted in a gain on the sale of other property and equipment of $1.1 million . See Note 14 in the Footnotes to the Financial Statements for a discussion of the gain on the sale of specialized deep wate r property and equipment. 
+Impairment of other property and equipment . During 2013, the Company recorded a write-down of the value of certain assets acquired in 2011 as part of a settlement reached with a former joint interest partner on a deepwater project. See Note 14 in the Footnotes to the Financial Statements for a discussion regarding the recognition of the impairment on specialized deep water property and equipment . 
+53 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+O ther Income and Expenses and Preferred Stock Dividends 
+For the Year Ended December 31, 
+(in thousands) 
+2015 
+2014 
+$ Change 
+% Change 
+Interest expense 
+$ 
+21,111 
+$ 
+9,772 
+$ 
+11,339 
+116% 
+Gain on early extinguishment of debt 
+— 
+(151)
+151 
+nm 
+(Gain) loss on derivative contracts 
+(28,358)
+(31,736)
+3,378 
+(11)% 
+Other income, net 
+(198)
+(515)
+317 
+(62)% 
+Total 
+$ 
+(7,445)
+$ 
+(22,630)
+Income tax expense 
+$ 
+38,474 
+$ 
+23,134 
+$ 
+15,340 
+66% 
+Preferred stock dividends 
+(7,895)
+(7,895)
+— 
+nm 
+For the Year Ended December 31, 
+(in thousands) 
+2014 
+2013 
+$ Change 
+% Change 
+Interest expense 
+$ 
+9,772 
+$ 
+6,094 
+3,678 
+60% 
+Gain on early extinguishment of debt 
+(151)
+(3,696)
+3,545 
+(96)% 
+Loss (gain) on derivative contracts 
+(31,736)
+1,360 
+(33,096)
+(2,434)% 
+Other income, net 
+(515)
+(485)
+(30)
+6% 
+Total 
+$ 
+(22,630)
+- 
+$ 
+3,273 
+- 
+- 
+Income tax expense 
+$ 
+23,134 
+$ 
+3,104 
+$ 
+20,030 
+645% 
+Equity in earnings of Medusa Spar LLC 
+— 
+17 
+(17)
+nm 
+Preferred stock dividends 
+(7,895)
+(4,627)
+(3,268)
+71% 
+Interest expense. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our C redit F acility or with term debt. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to our lender in interest expense , net of capitalized amounts . In addition, we include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees in interest expense. The amortization of deferred credit related to our 13% Senior Notes was recorded as an offset to interest expense until the notes were redeemed in April 2014 . 
+Interest expense incurred during the year ended December 31, 2015 in creased $11.3 million to $21.1 million compared to $9.8 million for the same period of 2014 . Th e increase is primarily attributable to the $18.8 million increase i n expense related to a higher outstandi ng average d ebt balance of $372.3 million in 2015 compared to $174.0 million in 2014. Offset ting the increase is a $6.2 million in crease in capitalized interest compared to the 2014 period, resulting from a higher average unevaluated property balance for the year ended December 31 , 2015 as compared to the same period of 2014, and a $1.3 million decrease in interest expense related to the full redemption of our Senior Notes in April 2014. 
+Interest expense incurred during the year ended December 31, 2014 increased $3.7 million to $9.8 million compared to $6.1 million for the same period of 2013. The increase is primarily attributable to the $11.4 million increase in expense related to additional draws on our Credit Facility and term loans in 2014 compared to the corresponding period of the prior year. Offsetting the increase is a $7.9 million decrease in interest expense related to our Senior Notes following a $48.5 million partial redemption during the fourth quarter of 2013 and a full redemption of the remaining outstanding principal in April 2014. Also offsetting the increase was a $0.2 million increase in capitalized interest, resulting from a higher average unevaluated property balance period over period. 
+Gain (loss) on the early extinguishment of debt. During April 2014, the Company completed a full redemption of the remaining $53.3 million carrying value of its outstanding Senior Notes using proceeds from the issuance of a secured second lien term loan . The carrying value included $48.5 million of principal value and $4.8 million of unamortized deferred credit. The Company recognized a net $3.2 million gain on early extinguishment of debt, comprised of the recognition of $4.8 million in deferred credit, offset by $1.6 million of redemption expenses. See Note 5 for additional information concerning the gain on early extinguishment of debt. 
+54 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+During October 2014, the Company repaid in full the existing term loan using proceeds from the Second Lien Loan resulting in a loss on early extinguishment of debt of $3.1 million. The loss was comprised of a $1.7 million prepayment premium and the recognition of $1.4 million of unamortized issuance cost s . See Note 5 for additional information concerning the loss on the early extinguishment of debt. 
+During December 2013, the Company redeemed $53.8 million carrying value of its Senior Notes using a portion of the proceeds from the Company’s May 2013 preferred equity offering. The $53.8 million of carrying value included $48.5 million of principal value and $5.3 million of unamortized deferred credit. The Company recognized a net gain of $3.7 million on the early extinguishment of debt, comprised of the recognition of $5.3 million in deferred credit, offset by $1.6 million of redemption expenses. 
+(Gain) loss on derivative instruments. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in commodity prices. This amount represents the (i) gain (loss) related to fair value adjustments on our open derivative contracts and (ii) gains (losses) on settlements of derivative contracts for positions that have settled within the period . 
+For the year ended December 31, 2015 , the net gain on derivative instruments was $28.4 million, compared to a $31.7 million net gain in 2014 . The net gain on derivative instruments for the periods indicated include s the following (in millions): 
+For the Year Ended December 31, 
+2015 
+2014 
+$ Change 
+Natural gas derivatives 
+Net gain (loss) on settlements 
+$ 
+1.7 
+$ 
+(0.1)
+$ 
+1.8 
+Net gain (loss) on fair value adjustments 
+(1.2)
+1.3 
+(2.5)
+Total gain (loss) 
+$ 
+0.5 
+$ 
+1.2 
+$ 
+(0.7)
+Oil derivatives 
+Net gain (loss) on settlements 
+$ 
+33.3 
+$ 
+4.1 
+$ 
+29.2 
+Net gain (loss) on fair value adjustments 
+(5.4)
+26.4 
+(31.8)
+Total gain (loss) 
+$ 
+27.9 
+$ 
+30.5 
+$ 
+(2.6)
+Total gain (loss) on derivative contracts 
+$ 
+28.4 
+$ 
+31.7 
+$ 
+(3.3)
+For the year ended December 31, 2014, the net gain on derivative instruments was $31.7 million, compared to a $1.4 million net loss in 2013. The net gain on derivative instruments for the periods indicated include s the following (in millions): 
+For the Year Ended December 31, 
+2014 
+2013 
+$ Change 
+Natural gas derivatives 
+Net gain (loss) on settlements 
+$ 
+(0.1)
+$ 
+(0.1)
+$ 
+— 
+Net gain (loss) on fair value adjustments 
+1.3 
+0.2 
+1.1 
+Total gain (loss) 
+$ 
+1.2 
+$ 
+0.1 
+$ 
+1.1 
+Oil derivatives 
+Net gain (loss) on settlements 
+$ 
+4.1 
+$ 
+1.5 
+$ 
+2.6 
+Net gain (loss) on fair value adjustments 
+26.4 
+(3.0)
+29.4 
+Total gain (loss) 
+$ 
+30.5 
+$ 
+(1.5)
+$ 
+32.0 
+Total gain (loss) on derivative contracts 
+$ 
+31.7 
+$ 
+(1.4)
+$ 
+33.1 
+See Notes 6 and 7 in the Footnotes to the Financial Statements for additional information o n the Company’s derivative contracts and disclosures related to derivative instruments. 
+Income tax expense. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. When appropriate based on our analysis, we record a valuation allowance for deferred tax assets when it is more likely than not that the deferred tax assets will not be realized. 
+55 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+The Company had an income tax expense of $38.5 million for the year ended December 31 , 2015 compared to an income tax expense of $ 23.1 million for the same peri od of 2014 . The increase in income tax expense is primarily related to the establishment of a valuation allowance of $108.8 mil lion in 2015 and the difference in the amount of income (loss) be fore income taxes between periods. The effective tax rate of (19)% in 2015 and 38% in 2014 differed from the federal income tax rate of 35% primarily due to the valuation allowance established in 2015, the effect of state, taxes, and non-deductible executive compensation expenses. 
+The Company had an income tax expense of $23.1 million for the year ended December 31, 2014 compared to an income tax expense of $3.1 million for the same period of 2013. The increase in income tax expense is primarily related to the difference in the amount of income (loss) before income taxes between periods. The effective tax rate of 38% in 2014 and 42% in 2013 differed from the federal income tax rate of 35% primarily due to the effect of state taxes, non-deductible executive compensation expenses and percentage depletion. 
+For additional information, see Note 11 to the Consolidated Fi nancial Statements. 
+Preferred stock dividends . Preferred s tock dividends for the year ende d December 31 , 2015 we re consistent with the same period of 2014 . Dividends reflect a 10% dividend rate and $79 million liquidation value. See Note 10 in the Footnotes to the Financial Statements for additional information. 
+Preferred stock dividends for the year ended December 31, 2014 increased $3.3 million compared to the same period of 2013. We issued the Preferred Stock on May 30, 2013. Accordingly, the year ended December 31, 2014 reflects dividends for the entire year compared to a partial year in 2013 . 
+56 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Summary of Significant Accounting Policies and Critical Accounting Estimates 
+The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been use d . Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under GAAP. We also describe the most significant estimates and assumptions we make in applying these policies. See Note 2 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K for a discussion of additional accounting policies and estimates made by management. 
+Oil and natural gas p ropert ies 
+The Company utilizes the full cost method of accounting for its oil and natural gas properties whereby all costs incurred in connection with the acquisition, exploration and development of oil and natural gas reserves, including certain overhead costs, are capitalized into the “full cost pool.” The amounts capitalized into the full cost pool are depleted (charged against earnings) using the unit-of-production method. The full cost method of accounting for oil and natural gas properties requires that the Company makes estimates based on its assumptions of future events that could change. These estimates are described below. 
+Depreciation, depletion and amortization (DD&A) of oil and natural gas properties 
+The Company calculates DD&A by using the depletable base, which is equal to the net capitalized costs in our full cost pool plus estimated future development costs, and the estimated net proved reserve quantities. Capitalized costs added to the full cost pool include the following: 
+· 
+costs of drilling and equipping productive wells, dry hole costs, acquisition costs of properties with proved reserves, delay rentals and other costs related to exploration and development of our oil and natural gas properties; 
+· 
+payroll costs including the related fringe benefits paid to employees directly engaged in the acquisition, exploration and/or development of oil and natural gas properties as well as other directly identifiable general and administrative costs associated with such activities. Such capitalized costs do not include any costs related to the production of oil and natural gas or general corporate overhead; 
+· 
+costs associated with unevaluated properties, those lacking proved reserves, are excluded from the depletable base. These unevaluated property costs are added to the depletable base at such time as wells are completed on the properties or management determines these costs have been impaired. The Company’s determination that a property has or has not been impaired (which is discussed below) requires assumptions about future events; 
+· 
+estimated costs to dismantle, abandon and restore properties that are capitalized to the full cost pool when the related liabilities are incurred (see also the discussion below regarding Asset Retirement Obligations); 
+· 
+estimated future costs to develop proved properties are added to the full cost pool for purposes of the DD&A computation. The Company uses assumptions based on the latest geologic, engineering, regulatory and cost data available to it to estimate these amounts. However, the estimates made are subjective and may change over time. The Company’s estimates of future development costs are reviewed at least annually and as additional information becomes available; and 
+· 
+capitalized costs included in the full cost pool plus estimated future development costs are depleted and charged against earnings using the unit-of-production method. Under this method, the Company estimates the proved reserves quantities at the beginning of each accounting period. For each BOE produced during the period, the Company records a DD&A charge equal to the amount included in the depletable base (net of accumulated depreciation, depletion and amortization) divided by our estimated net proved reserve quantities. 
+57 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Because the Company uses estimates and assumptions to determine proved reserves (as discussed below) and the amounts included in the depletable base, our depletion rates may materially change if actual results differ from these estimates. 
+Ceiling t est 
+Under the full cost method of accounting, the Company compares, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (excluding cash flows related to estimated abandonment costs and the value of commodity derivative instruments ), to the net capitalized costs of proved oil and natural gas properties net of related deferred taxes. The Company refers to this comparison as a “ceiling test.” If the net capitalized costs of proved oil and natural gas properties exceed the estimated discounted (at a 10% annualized rate ) future net cash flows from proved reserves, t he Company is required to write- down the value of its oil and natural gas properties to the value of th e discounted cash flows. Estimated future net cash flows from proved reserves are based on a twelve-month average pricing assumption. Given the volatility of oil and natural gas prices, it is reasonably possible that the Company’s estimates of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. For the period ended December 31, 2015 , the Company recognized a write-down of oil and natural gas properties of $208.4 as a result of the ceiling test limita tion. If oil and natural gas prices remain at current levels or decline further , even if only for a short period of time, write- downs of oil and natural gas properties could occur in the future. See Note 13 for additional information regarding the Company’s oil and natural gas properties. 
+Estimating reserves and present value of estimated future net cash flows 
+Estimates of quantities of proved oil and natural gas reserves, including the discounted present value of estimated future net cash flows from such reserves at the end of each quarter, are based on numerous assumptions, which are likely to change over time. These assumptions include: 
+· 
+the prices at which the Company can sell its oil and natural gas production in the future. Oil and natural gas prices are volatile, but we are required to assume that they remain constant, using the twelve-month average pricing assumption. In general, higher oil and natural gas prices will increase quantities of proved reserves and the present value of estimated future net cash flows from such reserves, while lower prices will decrease these amounts; and 
+· 
+the costs to develop and produce the Company’s reserves and the costs to dismantle its production facilities when reserves are depleted. These costs are likely to change over time, but we are required to assume that they remain constant. Increases in costs will reduce estimated oil and natural gas quantities and the present value of estimated future net cash flows, while decreases in costs will increase such amounts. 
+Changes in these prices and/or costs will affect the present value of estimated future net cash flows more than the estimated quantities of oil and natural gas reserves for the Company’s properties that have relatively short productive lives. If oil and natural gas prices remain at current levels or decline further, it will have a negative impact on the present value of estimated future net cash flows and the estimated quantities of oil and natural gas reserves. 
+In addition, the process of estimating proved oil and natural gas reserves requires that the Company’s independent and internal reserve engineers exercise judgment based on available geological, geophysical and technical information. We have described the risks associated with reserve estimation and the volatility of oil and natural gas prices under “Risk Factors.” 
+Sales of oil and natural gas properties are accounted for as adjustments to the net full cost pool with no gain or loss recognized unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves. 
+Unproved p roperties 
+Costs, including capitalized interest, associated with properties that do not have proved reserves are excluded from the depletable base, and are included in the line item “Unevaluated properties.” Un evaluat ed property costs are transferred to the depletable base when wells are completed on the pro perties or management determines that these costs have been impaired . In addition, the Company is required to determine whether its un evaluat ed properties are impaired and, if so, include the costs of such properties in the depletable base. The Company determines whether an un evaluat ed property is impaired by periodically reviewing its exploration program on a property-by-property basis. This determination may require the exercise of substantial judgment by management. 
+58 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Asset r etirement o bligations 
+We are required to record our estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-life assets and the associated asset retirement costs. Interest is accreted on the present value of the asset retirement obligation s and reported as accretion expense within operating expenses in the Consolidated Statements of Operations. See Note 12 for additional information. 
+Derivatives 
+To manage oil and natural gas price risk on a portion of our planned future production, we have historically utilized commodity derivative instruments (including collars, swaps, puts, and other structures) on approximat ely 50% to 75 % of our projected production volumes in any given year. We do not use these instruments for trading purposes. Settlement of derivative contracts are generally based on the difference between the contract p rice and prices specified in the derivative instrument and a NYMEX price or other cash or futures index price. 
+O ur derivative positions are carried at their fair value on the balance sheet with changes in fair value recorded through earnings . The estimated fair value of our derivative contracts is based upon closing exchange prices on NYMEX and in the case of collars and floors, the time value of options. For additional informat ion regarding derivatives and their fair values, see Notes 6 and 7 to the Consolidated Financial Statements and Part II, Item 7A Commodity Price Risk. 
+Income t axes 
+The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices). We had a valuation allowance of $108.8 million recorded as of December 31, 2015 . See Note 11 for additional information regarding Income Taxes. 
+Recent Accounting Standards 
+In May 2014, the Financial Accounting Standards Board (“FASB”) issued accounting standards update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will replace most of the existing revenue recognition requirements in GAAP when it becomes effective. In August 2015, the FASB issued ASU No. 2015-14, deferring the effective date of ASU 2014-09 by one year. As a result, the standard is effective for annual periods beginning o n or after December 31 , 201 7 , including interim periods within that reporting period . The Company is currently evaluating the method of adoption and impact this standard will have on its financial statements and related disclosures. 
+In April 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”). The standard requires that the costs for issuing debt should appear on the balance sheet as direct reduction from the debt’s carrying value. The guidance in ASU 2015-03 is effective for public entities for annual reporting periods beginning after December 15, 2015, including interim periods therein, and is to be applied on a retrospective basis. T he Company adopted this standard effective December 31, 2015. As a result, def erred financing costs of $11.4 million and $13.4 million related to the Company’s secured second lien term loan were reclassified from deferred financing costs to a direct reduction from the debt’s carrying value as of December 31, 2015 and 2014 , respectively . 
+In August 2015, the FASB issued ASU No. 2015-15, Interest – Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Ar rangements (“ASU 2015-15”). ASU 2015-15 
+59 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+updates the accounting guidance included in ASU 2015-03 as a result of the June 18, 2015, Emerging Issues Task Force meeting, in which the SEC stated that the SEC staff would not object to an entity deferring and presenting costs related to revolving debt arrangements as an asset. T he Company adopted this standard effective December 31, 2015. For t he years ended December 31, 2015 and 2014, deferred financing costs related to the Company’s senior secured revolving credit facility of $3.6 million and $4.8 mi llion, respectively, we re presented on the balance sheet as an asset. 
+In November 2015, the FASB issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”) , which eliminates the current requirement to present deferred tax liabilities and assets as current and noncurrent amounts on the balance sheet . Instead, entities will be required to classify all deferred tax assets and liabilities as noncurrent on the balance sheet . The guidance in ASU 2015-17 is effective for public entities for annu al reporting periods beginning after December 15, 2016, and interim periods within those annual periods. Early application is permitted. The Company is currently evaluating the timing of its adoption of this ASU , which will not have a material impact on its financial statements. 
+60 
+Table of Contents 
+Item 7A. Quan titative and Qualitative Disclosures about Market Risk 
+We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative instruments. 
+Commodity price risk 
+The Company’s revenues are derived from the sale of its oil and natural gas production. The prices for oil and natural gas remain extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and government actions. From time to time, the Company enters into derivative financial instruments to manage oil and natural gas price risk, related both to NYMEX benchmark prices and regional basis differentials. The total volumes which we hedge through the use of our derivative instruments varies from period to period; however, generally our objective is to hedge approximately 50% to 75% of our anticipated internally forecast production for the next 12 to 24 months, subject to the covenants under our Credit Facility. Our hedge policies and objectives may change significantly with movements in commodities prices or futures pr ices, in addition to modification of our capital spending plans related to operational activities and acquisitions. 
+The Company’s hedging portfolio, linked to NYMEX bench mark pricing , cover s appr oximately 64% and 3 6 % of our expected oil and natural gas production, respectively, for calendar year 2016, based on the midpoint of publicly disclosed guidance as of March 2, 201 6 . In addition, we had commodity hedging contracts linked to Midland WTI basis differentials relative to Cushing covering approximately 44% of our expected oil production for calendar year 2016, based on the midpoint of publicly disclosed oil production guidance as of March 2, 201 6 . Our actual production may vary from the amounts esti mated, perhaps materially. See Note 6 in the Footnotes to the Financial Statements for a descri ption of the Company’s outstanding derivative contracts at December 31, 2015 and derivative contracts established subsequent to that date. 
+The Company may utilize fixed price swaps, which reduce the Company’s exposure to decreases in commodity prices and limit the benefit the Company might otherwise have received from any increases in commodity prices. Swap contracts may also be enhanced by the simultaneous sale of call or put options to effectively increase the effective swap price as a result of the receipt of premiums from the option sales. 
+The Company may utilize price collars to reduce the risk of changes in oil and natural gas prices. Under these arrangements, no payments are due by either party as long as the applicable market price is above the floor price (purchased put option) and below the ceiling price (sold call option) set in the collar. If the price falls below the floor, the counter-party to the collar pays the difference to the Company, and if the price rises above the ceiling, the counterparty receives the difference from the Company. Additionally, the Company may sell put (or call) options at a price lower than the floor price (or higher than the ceiling price) in conjunction with a collar (three-way collar) and use the proceeds to increase either or both the floor or ceiling prices. In a three-way collar, to the extent that realized prices are below the floor price of the sold put option (or above the ceiling price of the sold call option), the Company’s net realized benefit from the three-way collar will be reduced on a dollar-for-dollar basis. 
+The Company may purchase put options, which reduce the Company’s exposure to decreases in oil and natural gas prices while allowing realization of the full benefit from any increases in oil and natural gas prices. If the price falls below the floor, the counterparty pays the difference to the Company. 
+The Company enters into these various agreements from time to time to reduce the effects of volatile oil and natural gas prices and does not enter into derivative transactions for speculative purposes. Presently, none of the Company’s derivative positions are designated as hedges for accounting purposes. 
+Interest rate risk 
+On December 31, 2015 , the Company’s debt consisted of $300 mi llion of outstanding principal related to its Second Lien Loan and $40.0 million related to its Credit Facility. The Company is subject to market risk exposure related to changes in interest rates on our indebtedness under the Second Lien Loan and Credit Facility. As of December 31, 2015 , the weighted average interest rate on our Credit Facility borrowings was 2.07% and the interest rate on our Second Lien Loan borrowings was 8.50% . An increase or decrease of 1% in the interest rate would have a corresponding increase or decrease in our annual net income of approximately $3.4 million based on the $340 million outstanding in the aggregate under the two facilities on December 31, 2015 . The Company is also subject to 
+61 
+Table of Contents 
+market risk exposure related to changes in the underlying LIBOR-based interest rate used for the Term Loan to the extent that available LIBOR election options exceed the 1.0% floor rate. See Note 5 to the Consolidated Financial Statements for more information on the Company’s interest rates on debt. 
+Counterparty and customer credit risk 
+The Company’s principal exposures to credit risk are through receivables from the sale of our oil and natural gas production, joint interest receivables and receivables resulting from derivative financial contracts. 
+The Company markets its oil and natural gas production to energy marketing companies. We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. For the year en ded December 31, 2015 , t hree purchasers accounted for more than 10% of our revenue: Enterprise Crude Oil, LLC ( 42% ); Plains Marketing, L.P. ( 19% ); and Permian Transport and Trading ( 15% ). We do not require any of our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. At December 31, 2015 our total receivables from the sale of our oil and natural gas production were approximately $16.0 million. 
+Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have or intend to drill. We have little ability to control whether these entities will participate in our wells. At December 31, 2015 our joint interest receivables were approximately $19.3 million. 
+At December 31, 2015 our receivables resulting from derivative contracts were approximately $3.9 million. Our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. Most of the counterparties on our derivative instruments currently in place are lenders under our Credit Facility. We are likely to enter into additional derivative instruments with these or other lenders under our Credit Facility, representing institutions with an investment grade ratings. We have existing International Swap Dealers Association Master Agreements (“ISDA Agreements”) with our derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of offset upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may offset all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. At December 31, 2015 we had a net derivative asset position of $19.9 million. 
+62 
+Table of Contents 
+ITEM 8. Finan cial Statements and Supplementary Data 
+Page 
+Report of Independent Registered Public Accounting Firm 
+63 
+Consolidated Balance Sheets as of December 31, 2015 and 2014 
+64 
+Consolidated Statements of Operations for Each of the Three Years in the Period Ended December 31, 201 5 
+65 
+Consolidated Statements of Stockholders’ Equity for Each of the Three Years in the Period Ended December 31, 2015 
+66 
+Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2015 
+67 
+Notes to Consolidated Financial Statements 
+68 
+63 
+Table of Contents 
+Report of Indepe ndent Registered Public Accounting Firm 
+The Board of Directors and Stockholders of 
+Callon Petroleum Company 
+We have audited the accompanying consolidated balance sheets of Callon Petroleum Company as of December 31, 2015 and 2014 , and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2015 . These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. 
+We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. 
+In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Callon Petroleum Company as of December 31, 2015 and 2014 , and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2015 , in conformity with U.S. generally accepted accounting principles. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Callon Petroleum Company’s internal control over financial reporting as of December 31, 2015 , based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ( 2013 framework) and our report dated March 2, 2016 , expressed an unqualified opinion thereon. 
+/s/Ernst & Young LLP 
+New Orleans, Louisiana 
+March 2, 2016 
+64 
+Table of Contents 
+Part I. Financial Information 
+Item I. Financial Statements 
+Callon Petroleum Company 
+Consolidated Bal ance Sheets 
+(in thousands, except par and per share values and share data) 
+December 31, 2015 
+December 31, 2014 
+ASSETS 
+Current assets: 
+Cash and cash equivalents 
+$ 
+1,224 
+$ 
+968 
+Accounts receivable 
+39,624 
+30,198 
+Fair value of derivatives 
+19,943 
+27,850 
+Other current assets 
+1,461 
+1,441 
+Total current assets 
+62,252 
+60,457 
+Oil and natural gas properties, full cost accounting method: 
+Evaluated properties 
+2,335,223 
+2,077,985 
+Less accumulated depreciation, depletion and amortization 
+(1,756,018)
+(1,478,355)
+Net oil and natural gas properties 
+579,205 
+599,630 
+Unevaluated properties 
+132,181 
+142,525 
+Total oil and natural gas properties 
+711,386 
+742,155 
+Other property and equipment, net 
+7,700 
+7,118 
+Restricted investments 
+3,309 
+3,810 
+Deferred tax asset 
+— 
+44,688 
+Deferred financing costs 
+3,642 
+4,776 
+Other assets, net 
+305 
+342 
+Total assets 
+$ 
+788,594 
+$ 
+863,346 
+LIABILITIES AND STOCKHOLDERS’ EQUITY 
+Current liabilities: 
+Accounts payable and accrued liabilities 
+$ 
+70,970 
+$ 
+76,753 
+Accrued interest 
+5,989 
+5,993 
+Cash-settled restricted stock unit awards 
+10,128 
+3,856 
+Asset retirement obligations 
+790 
+4,747 
+Deferred tax liability 
+— 
+6,214 
+Fair value of derivatives 
+— 
+1,249 
+Total current liabilities 
+87,877 
+98,812 
+Senior secured revolving credit facility 
+40,000 
+35,000 
+Secured second lien term loan, net of unamortized deferred financing costs 
+288,565 
+286,576 
+Asset retirement obligations 
+4,317 
+1,927 
+Cash-settled restricted stock unit awards 
+4,877 
+7,175 
+Other long-term liabilities 
+200 
+121 
+Total liabilities 
+425,836 
+429,611 
+Stockholders’ equity: 
+Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized: 1,578,948 and 1,578,948 shares outstanding, respectively 
+16 
+16 
+Common stock, $0.01 par value, 150,000,000 and 110,000,000 shares authorized; 80,087,148 and 55,225,288 shares outstanding, respectively 
+801 
+552 
+Capital in excess of par value 
+702,970 
+526,162 
+Accumulated deficit 
+(341,029)
+(92,995)
+Total stockholders’ equity 
+362,758 
+433,735 
+Total liabilities and stockholders’ equity 
+$ 
+788,594 
+$ 
+863,346 
+The accompanying notes are an integral part of these consolidated financial statements. 
+65 
+Table of Contents 
+Callon Petroleum Company 
+Consolidated Sta tements of Operations 
+(in thousands, except per share data) 
+For the Year Ended December 31, 
+2015 
+2014 
+2013 
+Operating revenues: 
+Oil sales 
+$ 
+125,166 
+$ 
+139,374 
+$ 
+88,960 
+Natural gas sales 
+12,346 
+12,488 
+13,609 
+Total operating revenues 
+137,512 
+151,862 
+102,569 
+Operating expenses: 
+Lease operating expenses 
+27,036 
+22,372 
+19,779 
+Production taxes 
+9,793 
+8,973 
+4,133 
+Depreciation, depletion and amortization 
+69,249 
+56,724 
+43,967 
+General and administrative 
+28,347 
+25,109 
+20,534 
+Accretion expense 
+660 
+826 
+1,785 
+Write-down of oil and natural gas properties 
+208,435 
+— 
+— 
+Rig termination fee 
+3,075 
+— 
+— 
+Gain on sale of other property and equipment 
+— 
+(1,080)
+— 
+Impairment of other property and equipment 
+— 
+— 
+1,707 
+Acquisition expense 
+27 
+668 
+— 
+Total operating expenses 
+346,622 
+113,592 
+91,905 
+Income (loss) from operations 
+(209,110)
+38,270 
+10,664 
+Other (income) expenses: 
+Interest expense 
+21,111 
+9,772 
+6,094 
+Gain on early extinguishment of debt 
+— 
+(151)
+(3,696)
+(Gain) loss on derivative contracts 
+(28,358)
+(31,736)
+1,360 
+Other income 
+(198)
+(515)
+(485)
+Total other (income) expense 
+(7,445)
+(22,630)
+3,273 
+Income (loss) before income taxes 
+(201,665)
+60,900 
+7,391 
+Income tax expense 
+38,474 
+23,134 
+3,104 
+Income (loss) before equity in earnings of Medusa Spar LLC 
+(240,139)
+37,766 
+4,287 
+Equity in earnings of Medusa Spar LLC 
+— 
+— 
+17 
+Net income (loss) 
+(240,139)
+37,766 
+4,304 
+Preferred stock dividends 
+(7,895)
+(7,895)
+(4,627)
+Income (loss) available to common stockholders 
+$ 
+(248,034)
+$ 
+29,871 
+$ 
+(323)
+Income (loss) per common share: 
+Basic 
+$ 
+(3.77)
+$ 
+0.67 
+$ 
+(0.01)
+Diluted 
+$ 
+(3.77)
+$ 
+0.65 
+$ 
+(0.01)
+Shares used in computing income (loss) per common share: 
+Basic 
+65,708 
+44,848 
+40,133 
+Diluted 
+65,708 
+45,961 
+40,133 
+The accompanying notes are an integral part of these consolidated financial statements . 
+66 
+Table of Contents 
+Callon Petroleum Company 
+Consolidated Statem ents of Stockholders’ Equity 
+(in thousands) 
+Preferred Stock 
+Common Stock 
+Capital in Excess of Par 
+Retained Earnings (Deficit) 
+Total Stockholders' Equity 
+Balance at 12/31/2012 
+$ 
+— 
+$ 
+398 
+$ 
+328,116 
+$ 
+(122,543)
+$ 
+205,971 
+Net income 
+— 
+— 
+— 
+4,304 
+4,304 
+Shares issued pursuant to employee benefit plans 
+— 
+— 
+243 
+— 
+243 
+Restricted stock 
+— 
+6 
+3,162 
+— 
+3,168 
+Preferred stock issued 
+16 
+— 
+70,019 
+— 
+70,035 
+Preferred stock dividend 
+— 
+— 
+— 
+(4,627)
+(4,627)
+Balance at 12/31/2013 
+$ 
+16 
+$ 
+404 
+$ 
+401,540 
+$ 
+(122,866)
+$ 
+279,094 
+Net income 
+— 
+— 
+— 
+37,766 
+37,766 
+Shares issued pursuant to employee benefit plans 
+— 
+— 
+262 
+— 
+262 
+Restricted stock 
+— 
+4 
+2,054 
+— 
+2,058 
+Common stock issued 
+— 
+144 
+122,306 
+— 
+122,450 
+Preferred stock dividend 
+— 
+— 
+— 
+(7,895)
+(7,895)
+Balance at 12/31/2014 
+$ 
+16 
+$ 
+552 
+$ 
+526,162 
+$ 
+(92,995)
+$ 
+433,735 
+Net loss 
+— 
+— 
+— 
+(240,139)
+(240,139)
+Shares issued pursuant to employee benefit plans 
+— 
+— 
+268 
+— 
+268 
+Restricted stock 
+— 
+8 
+1,323 
+— 
+1,331 
+Common stock issued 
+— 
+241 
+175,217 
+— 
+175,458 
+Preferred stock dividend 
+— 
+— 
+— 
+(7,895)
+(7,895)
+Balance at 12/31/2015 
+$ 
+16 
+$ 
+801 
+$ 
+702,970 
+$ 
+(341,029)
+$ 
+362,758 
+The accompanying notes are an integral part of these consolidated financial statements. 
+67 
+Table of Contents 
+Callon Petroleum Company 
+Consolidated Statem ents of Cash Flows 
+(in thousands) 
+For the Year Ended December 31, 
+2015 
+2014 
+2013 
+Cash flows from operating activities: 
+Net income (loss) 
+$ 
+(240,139)
+$ 
+37,766 
+$ 
+4,304 
+Adjustments to reconcile net income to cash provided by operating activities: 
+Depreciation, depletion and amortization 
+69,891 
+58,014 
+45,393 
+Write-down of oil and natural gas properties 
+208,435 
+— 
+— 
+Accretion expense 
+660 
+826 
+1,785 
+Amortization of non-cash debt related items 
+3,123 
+1,272 
+471 
+Amortization of deferred credit 
+— 
+(487)
+(3,164)
+Equity in earnings of Medusa Spar LLC 
+— 
+— 
+(17)
+Deferred income tax expense 
+38,474 
+23,134 
+2,778 
+Net loss (gain) on derivatives, net of settlements 
+6,658 
+(27,650)
+2,730 
+Impairment of other property and equipment 
+— 
+— 
+1,707 
+Gain on sale of other property and equipment 
+— 
+(1,080)
+— 
+Non-cash gain on early debt extinguishment 
+— 
+(151)
+(3,696)
+Non-cash expense related to equity share-based awards 
+221 
+1,126 
+2,092 
+Change in the fair value of liability share-based awards 
+6,612 
+3,936 
+2,903 
+Payments to settle asset retirement obligations 
+(3,258)
+(3,808)
+(721)
+Changes in current assets and liabilities: 
+Accounts receivable 
+(4,761)
+(7,915)
+(3,497)
+Other current assets 
+(20)
+622 
+(560)
+Current liabilities 
+8,001 
+12,805 
+3,583 
+Payments to settle vested liability share-based awards related to early retirements 
+(3,538)
+(1,417)
+— 
+Payments to settle vested liability share-based awards 
+(3,925)
+(2,052)
+(239)
+Change in other long-term liabilities 
+80 
+(106)
+(711)
+Change in other assets, net 
+338 
+(448)
+(666)
+Net cash provided by operating activities 
+86,852 
+94,387 
+54,475 
+Cash flows from investing activities: 
+Capital expenditures 
+(227,292)
+(232,596)
+(159,724)
+Acquisitions 
+(32,245)
+(222,883)
+(10,885)
+Proceeds from sales of mineral interest and equipment 
+377 
+2,978 
+89,992 
+Distribution from Medusa Spar LLC 
+— 
+— 
+813 
+Net cash used in investing activities 
+(259,160)
+(452,501)
+(79,804)
+Cash flows from financing activities: 
+Borrowings on senior secured revolving credit facility 
+181,000 
+132,500 
+80,000 
+Payments on senior secured revolving credit facility 
+(176,000)
+(119,500)
+(68,000)
+Borrowings on term loans 
+— 
+382,500 
+— 
+Payments on term loans 
+— 
+(84,149)
+— 
+Payment of deferred financing costs 
+— 
+(19,779)
+(146)
+Redemption of 13% senior notes 
+— 
+(50,057)
+(50,060)
+Issuance of preferred stock 
+— 
+— 
+70,035 
+Issuance of common stock 
+175,459 
+122,450 
+— 
+Payment of preferred stock dividends 
+(7,895)
+(7,895)
+(4,627)
+Net cash provided by financing activities 
+172,564 
+356,070 
+27,202 
+Net change in cash and cash equivalents 
+256 
+(2,044)
+1,873 
+Balance, beginning of period 
+968 
+3,012 
+1,139 
+Balance, end of period 
+$ 
+1,224 
+$ 
+968 
+$ 
+3,012 
+The accompanying notes are an integral part of these consolidated financial statements. 
+68 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+IND EX TO THE NOTES TO CONS OLIDATED FINANCIAL STATEMENTS 
+1. 
+Description of Business and Basis of Presentation 
+9. 
+Share-Based Compensation 
+2. 
+Summary of Significant Accounting Policies 
+10. 
+Equity Transactions 
+3. 
+Acquisitions and Dispositions 
+11. 
+Income Taxes 
+4. 
+Earnings (Loss) Per Share 
+12. 
+Asset Retirement Obligations 
+5. 
+Borrowings 
+13. 
+Supplemental Information on Oil and Natural Gas Operations (Unaudited) 
+6. 
+Derivative Instruments and Hedging Activities 
+14. 
+Other 
+7. 
+Fair Value Measurements 
+15. 
+Summarized Quarterly Financial Information (Unaudited) 
+8. 
+Employee Benefit Plans 
+Note 1 - Description of Busi ness and Basis of Presentation 
+Description of business 
+Callon Petroleum Company is an independent oil and natural gas company established in 1950. The Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company partially owned by a member of current management. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. 
+Callon is focused on the acquisition, development, exploration and exploitation of unconventional, onshore, oil and natural gas reserves in the Permian Basin in West Texas, and more specifically, the Midland Basin. The Company’s operations to date have been predominantly focused on horizontal drilling of several prospective intervals, including multiple levels of the Wolfcamp formation and, more recently, the Lower Spraberry shale. Callon has assembled a multi-year inventory of potential horizontal well locations and intends to add to this inventory through delineation drilling of emerging zones on our existing acreage and acquisition of additional locations through acreage purchases, joint ventures and asset swaps. 
+Basis of presentation 
+Unless otherwise indicated, all dollar amounts included within the F ootnotes to the Financial S tatements are presented in thousands, except for per share and per unit data. 
+The Consolidated Financial Statements include the accounts of the Company, and its subsidiary, Callon Petroleum Operating Company (“CPOC”). CPOC also includes the subsidiaries Callon Offshore Production, Inc. and Mississippi Marketing, Inc. All intercompany accounts and transactions have been eliminated. In the opinion of management, the accompanying audited consolidated financial statements reflect all adjustments, including normal recurring adjustments and all intercompany account and transaction eliminations, necessary to present fairly the Company’s financial position, the results of its operations and its cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation. 
+Note 2 – Summary of Significant Accounting Policies 
+A. 
+Use of Estimates 
+The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 
+B. 
+Cash and Cash Equivalents 
+The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. 
+69 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+C. 
+Accounts Receivable 
+Accounts receivable consists primarily of accrued oil and natural gas production receivables and joint interest receivables from outside working interest owners . 
+D. 
+Revenue Recognition and Natural Gas Balancing 
+The Company recognizes revenue under the entitlement s method of accounting. Under this method, revenue is deferred for deliveries in excess of the Company’s net revenue interest, while revenue is accrued for the undelivered volumes. The revenue we receive from the sale of NGLs is included in natural gas sales. Natural gas balancing receivables and payables were immaterial as of December 31, 2015 and 2014 . 
+In May 2014, the Financial Accounting Standards Board (“FASB”) issued accounting standards update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will replace most of the existing revenue recognition requirements in GAAP when it becomes effective. In August 2015, the FASB issued ASU No. 2015-14, deferring the effective date of ASU 2014-09 by one year. As a result, the standard is effective for annual periods beginning o n or after December 31 , 201 7 , including interim periods within that reporting period . The Company is currently evaluating the method of adoption and impact this standard will have on its financial statements and related disclosures. 
+E. 
+Major Customers 
+The Company’s production is generally sold on month-to-month contracts at prevailing prices. The following table identifies customers to whom it sold greater than 10% of its total oil and natural gas production during each of the years ended: 
+For the Year Ended December 31, 
+2015 
+2014 
+2013 
+Enterprise Crude Oil, LLC 
+42% 
+51% 
+38% 
+Plains Marketing, L.P. 
+19% 
+22% 
+15% 
+Permian Transport and Trading 
+15% 
+7% 
+— 
+Sunoco 
+9% 
+10% 
+— 
+Shell Trading Company 
+4% 
+— 
+31% 
+Other 
+11% 
+10% 
+16% 
+Total 
+100% 
+100% 
+100% 
+Because alternative purchasers of oil and natural gas are readily available, the Company believes that the loss of any of these purchasers would not result in a material adverse effect on its ability to market future oil and natural gas production. 
+F. 
+Oil and Natural Gas Properties 
+The Company uses the full cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as oil and gas propert ies . Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest capitalized on unevaluated leases, other costs related to exploration and development activities, and site restoration, dismantlement and abandonment costs capitalized in accordance with asset retirement obligation accounting guidance. Costs capitalized also include any internal costs that are directly related to exploration and development activities, including salaries and benefits, but do not include any costs related to production, general corporate overhead or similar activities. 
+When applicable, proceeds from the sale or disposition of oil and natural gas properties are accounted for as a reduction to capitalized costs unless the sale would significantly alter the relationship between capitalized costs and proved reserves, in which ca se a gain or loss is recognized . 
+70 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+Historical and estimated future development costs of oil and natural gas properties , which have been evaluated and contain proved reserves, as well as the historical cost of properties that have been determined to have no future economic value, are depleted using the unit-of-production method based on proved reserves. Excluded from this amortization are costs associated with unevaluated properties, including capitalized interest on such costs. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties or the Company determines that these costs have been impaired. 
+Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net o f related tax effects (the full cost ceiling amount). These rules generally require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling . For the period ended December 31, 2015 , the Company recognized a write-down of oil and natural gas properties o f $208,435 a s a result of the ceiling test limita tion. See Note 13 for additional information regarding the Company’s oil and natural gas properties. 
+Upon the acquisition or discovery of oil and natural gas properties, the Company estimates the future net costs to dismantle , abandon and restore the property by using available geological, engineering and regulatory data. Such cost estimates are periodically updated for changes in conditions and requirements. In accordance with asset retirement obligation guidance, such costs are capitalized to the full cost pool when the related liabilities are incurred. In accordance with full cost accounting rules, assets recorded in connection with the recognition of an asset retirement obligation are included as part o f the costs subject to the full cost ceiling limitation. The future cash outflows associated with settling the recorded asset retirement obligations are excluded from the computation of the present value of estimated future net revenues used in determining the full cost ceiling amount. 
+G. 
+Other Property and Equipment 
+The Company depreciates its other property and equipment using the straight-line method over estimated useful lives of three to 20 years. Depreciation expense of $865 , $836 and $750 relating to other property and equipment was included in general and administrative expenses in the Company’s consolidated statements of operations for the years ended December 31, 2015 , 2014 and 2013 , respectively. The accumulated depreciation on other property and equipment was $14,719 and $14,005 as of December 31, 2015 and 2014 , respectively. The Company reviews its other property and equipment for impairment when indicators of impairment exist. See Note 14 for addition al information. 
+H. 
+Capitalized Interest 
+The Company capitalizes interest on unevaluated oil and gas properties. Capitalized interest cannot exceed gross interest expense. During the years ended December 31, 2015 , 2014 and 2013 , the Company capitalized $10,459 , $4,295 and $4,410 of interest expense. 
+I. 
+Deferred F inancing C osts 
+Deferred financing costs are stated at cost, net of amortization, which is computed using the straight-line method over the life of the loan . Amortization of deferred financing costs of $3,123 , $1,272 and $471 was recorded for the years ended December 31, 2015 , 2014 and 2013 , respectively. 
+In April 2015, the F ASB issued ASU No. 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”). The standard requires that the costs for issuing debt should appear on the balance sheet as direct reduction from the debt’s carrying value. The guidance in ASU 2015-03 is effective for public entities for annual reporting periods beginning after December 15, 2015, including interim periods therein, and is to be applied on a retrospective basis. T he Company adopted this standard effective December 31, 2015 . As a result, d ef erred financing costs of $ 11,435 and $13,424 related to the Company’s secured second lien term loan were reclassified from deferred financing costs to a direct reduction from the debt’s carrying value as of December 31, 2015 and 2014 , respectively . 
+71 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+In August 2015, the FASB issued ASU No. 2015-15, Interest – Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements (“ASU 2015-15”). ASU 2015-15 updates the accounting guidance included in ASU 2015-03 a s a result of the June 18, 2015, Emerging Issues Task Force meeting, in which the SEC stated that the SEC staff would not object to an entity deferring and presenting costs related to revolving debt arrangements as a n asset. T he Company adopted this standard effective December 31, 2015. For the y ears ended December 31, 2015 and 2014, d eferred financing costs related to the Company’s senior secured revolving credit facility of $3,642 and $4,776 , re spectively, we re presented on the balance sheet as an asset. 
+J. 
+Asset Retirement Obligations 
+The Company is required to record its estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Interest is accreted on the present value of the asset retirement obligations and reported as accretion expense within operating expenses in the consolidated statements of operations. See Note 12 for additional information. 
+K. 
+Derivatives 
+Derivative contracts outstanding as of December 31, 2015 were not designated as accounting hedges, and are carried on the balance sheet at fair value. Changes in the fair value of derivative contracts not designated as accounting hedges are reflected in earnings as a gain or loss on derivative contracts. See Notes 6 and 7 for additional information regarding the Company’s derivative contracts. 
+L. 
+Income Taxes 
+Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties for financial reporting purposes and income tax purposes. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards, statutory depletion carryforward s and tax credit carryforwards. A valuation allowance is provided for that portion of deferred tax assets , if any, for which it is deemed more likely than not that it will not be realized. As of December 31, 2015 the valuation allowance wa s $ 108,843 . See Note 11 for additional information. 
+In November 2015, the FASB issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”) , which eliminates the requirement to present deferred tax liabilities and assets as current and noncurrent amounts on the balance sheet . Instead, entities will be required to classify all deferred tax assets and liabilities as noncurrent on the balance sheet . The guidance in ASU 2015-17 is effective for public entities for annual reporting periods beginning after December 15, 2016 , and interim periods within those annual periods. Early application is permitted. The Company does not expect the adoption of this ASU will have a material impact on its financial statements . 
+M. 
+Share-Based Compensation 
+The Company grants to directors and employee s stock options a nd restricted stock awards (“RS awards”) . The Company also grants restricted stock unit awards (“ RSU awards ”) that may be settled in cash or common stock at the option of the Company and RSU awards that may only be settled in cash (“Cash-settleable RSU awards”). 
+Stock Options. For stock options the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value as calculated using the Black-Scholes option pricing model and recognized straight-line over the vesting period (generally three years). 
+RS awards, RSU equity awards and Cash-settleable RSU awards. For RS and RSU equity awards that the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value and recognized straight-line over the vesting period (generally three years). For RSU equity awards with vesting subject to a market condition, share-based compensation expense is based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model with the estimated value recognized over the vesting period (generally three years). For Cash-settleable RSU awards that the Company expects or is required to settle in cash, share-based compensation expe nse is based on the fair value measured at 
+72 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+each reporting period as calculated using a Monte Carlo pricing model, because vesting of these awards is subject to a market condition, with the estimated fair value recognized over the vesting period (generally three years). 
+N. 
+Statements of Cash Flows Supplemental Information 
+During the three year period ended 2015 , the Company paid no federal income taxes. During the years ended December 31, 2015 , 2014 and 2013 , the company made cash interest payments of $28,437 , $7,283 and $13,189 , respectively. 
+O. 
+Investment in Medusa Spar LLC 
+During the fourth quarter of 2013, the Company closed on the sale of its 15.0% working interest in the Medusa field, its 10.0% membership interest in Medusa Spar LLC (“LLC”), and substantially all of its remaining Gulf of Mexico shelf properties. Prior to the sale, the Company’s ownership interest in the LLC was accounted for under the equity method of accounting. The LLC held a 75% undivided ownership interest in the deepwater spar production facilities at the Medusa field in the Gulf of Mexico and earned a tariff based upon production volume throughput from the Medusa area. The Company was obligated to process through the spar production facilities its share of production from the Medusa field and any future discoveries in the area. The balance of the LLC was owned by Oceaneering International, Inc. and Murphy Oil Corporation. See Note 3 for additional information on the Medusa divestiture. 
+P. 
+Earnings per Share ( “ EPS ” ) 
+The Company’s basic EPS amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS, using the treasury-stock method, reflects the potential dilution caused by the exercise of options and vesting of restricted stock and RSUs settleable in share s. 
+Note 3 – Acquisitions and Dispositio ns 
+Acquisitions were accounted for under the acquisition method of accounting, which involves determining the fair value of the assets acquired and liabilities assumed under the income approach. 
+2015 acquisitions 
+On November 9, 2015, the Company acquired additional working interest s in 628 net acres located i n the Carpe Diem field and CaBo area in Midland , Andrews , Ector and Martin Counties, Texas, which are located in the central portion of the Midland Basin, for an aggregate cash purchase price of $ 29, 8 00 based on an effective date of October 1, 2015 . The acquis i tion increases the Company’s working interest in the Carpe Diem field to approximately 100% with a net revenue interest of 79% and incr e ases the working interest in the CaBo area to approximately 67% with a net revenue interest of 50% . The following purchase price allocation is based on management’s estimates of the fair value of the assets acquired and liabilities assumed. The following table summarizes the acquisition date fair values of the net assets acquired: 
+Oil and natural gas properties 
+$ 
+24,926 
+Unevaluated oil and natural gas properties 
+4,911 
+Asset retirement obligations 
+(37)
+Net assets acquired 
+$ 
+29,800 
+73 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+2014 acquisitions 
+In the first quarter of 2014, the Company acquired 1,527 net acres in Upton and Reagan Counties, Texas, which are located in the southern portion of the Midland Basin near its existing core development fields, for an aggregate cash purchase price of $8,200 . The properties bear a working interest of 100% and an average net revenue interest of 78% . The following table summarizes the acquisition date fair values of the net assets acquired: 
+Oil and natural gas properties 
+$ 
+930 
+Unevaluated oil and natural gas properties 
+7,394 
+Asset retirement obligations 
+(124)
+Net assets acquired 
+$ 
+8,200 
+On October 8, 2014, the Company completed the acquisition of certain undeveloped acreage and producing oil and gas properties located in Midland, Andrews, Ector and Martin Counties, Texas (the “ Central Midland Basin Acquisition”) for an aggregate cash purchase price of $210,205 based on an effective date of May 1, 2014. The Company assumed operatorship of the properties on November 1, 2014, and acquired a 62% working interest ( 46.5% net revenue interest) in the Central Midland Basin Acquisition. The aggregate cash purchase price was funded with a combination of the net proceeds from an equity offering of $122,514 and a portion of the proceeds from borrowings under the Second Lien Loan. For additional information on the debt transactions and equity offering, see Notes 5 and 10 , respectively. The following purchase price allocation is based on management’s estimates of the fair value of the assets acquired and liabilities assumed. The following table summarizes the acquisition date fair values of the net assets acquired: 
+Oil and natural gas properties 
+$ 
+91,895 
+Unevaluated oil and natural gas properties 
+118,450 
+Asset retirement obligations 
+(140)
+Net assets acquired 
+$ 
+210,205 
+The following unaudited summary pro forma financial information for the year s ended December 31, 2014 and 2013 has been presented for illustrative purposes only and does not purport to represent what the Company’s results of operations would have been if the Central Midland Basin Acquisition had occurred as presented, or to project the Company’s results of operations for any future periods. The pro forma financial information was prepared assuming the Central Midland Basin Acquisition and the debt transactions and equity offering discussed in Notes 5 and 10 , respectively, occurred as of January 1, 2013. The pro forma adjustments are based on available information and certain assumptions that management believes are reasonable, including revenue, lease operating expenses, production taxes, depreciation, depletion and amortization expense, accretion expense, interest expense and capitalized interest. 
+For the Years Ended December 31, 
+2014 
+2013 
+Revenues 
+$ 
+180,458 
+$ 
+151,766 
+Income from operations 
+53,526 
+36,002 
+Income available to common stockholders 
+33,674 
+4,033 
+Net income per common share 
+Basic 
+$ 
+0.57 
+$ 
+0.07 
+Diluted 
+$ 
+0.56 
+$ 
+0.07 
+74 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+2013 acquisitions 
+During the second quarter of 2013, the Company acquired approximately 2,468 gross ( 2,186 net) acres in Reagan and Upton Counties, Texas, which is located in the Southern Midland Basin and which is prospective for both horizontal and vertical drilling. The acquisition also included seven gross vertical wells and 1,301 barrels of oil equivalent proved reserves. The purchase price of $11,000 was funded using a portion of the proceeds from the preferred stock offering (discussed in Note 10 ). The following purchase price allocation is based on management’s estimates of the fair value of the assets acquired and liabilities assumed. The following table summarizes the acquisition date fair values of the net assets acquired: 
+Oil and natural gas properties 
+$ 
+9,025 
+Unevaluated oil and natural gas properties 
+2,000 
+Asset retirement obligations 
+(25)
+Net assets acquired 
+$ 
+11,000 
+2013 dispositions 
+During the fourth quarter of 2013, the Company closed on the sale of its 15.0% working interest in the Medusa field (Mississippi Canyon blocks 582 and 538), our 10.0% membership interest in Medusa Spar LLC, and substantially all of our remaining Gulf of Mexico shelf properties for total net cash consideration of approximately $88,000 . Also during the fourth quarter of 2013, the Company closed on the sale of its 69% interest in the Swan Lake field for $2,000 . This was the Company’s only field in the Haynesville shale. T he proceeds from these sales were accounted for as a reduction to capitalized costs as the sale s did not significantly alter the relationship between capitalized costs and proved reserves. 
+Subsequent event 
+Subsequent to December 31, 2015 , the Company completed the acquisition of an additional 4.9% working interest ( 3.7 % net revenue interest) in the CaBo area for total cash consideration of $ 9,300 , excluding customary purchase price adjustments. Following the completion of this acquisition the Company will own 71.3% working interest ( 53.5% net revenue interest) in the CaBo area . 
+75 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+Note 4 - Ear nings Per Share 
+Basic earnings (loss) per share is computed by dividing income (loss) available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings (loss) per share includes the potential dilutive impact of non-vested restricted shares and unexercised options outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. The following table sets forth the computation of basic and diluted earnings per share: 
+For the Year Ended December 31, 
+2015 
+2014 
+2013 
+Net income (loss) 
+$ 
+(240,139)
+$ 
+37,766 
+$ 
+4,304 
+Preferred stock dividends 
+(7,895)
+(7,895)
+(4,627)
+Income (loss) available to common stockholders 
+$ 
+(248,034)
+$ 
+29,871 
+$ 
+(323)
+Weighted average shares outstanding 
+65,708 
+44,848 
+40,133 
+Dilutive impact of restricted stock 
+— 
+1,113 
+— 
+Weighted average shares outstanding for diluted income (loss) per share (a) 
+65,708 
+45,961 
+40,133 
+Basic income (loss) per share 
+$ 
+(3.77)
+$ 
+0.67 
+$ 
+(0.01)
+Diluted income (loss) per share 
+$ 
+(3.77)
+$ 
+0.65 
+$ 
+(0.01)
+The following were excluded from the diluted earnings per share calculation because their effect would be anti-dilutive: 
+Stock options 
+15 
+30 
+52 
+Restricted stock 
+126 
+317 
+398 
+(a) 
+Because the Company reported a loss available to common stockholders for the year s ended December 31, 201 5 and 2013 , no unvested stock awards were included in computing loss per share because the effect was anti-dilutive. 
+Note 5 – Borr owings 
+The Company’s borrowings consisted of the following at: 
+For the Year Ended December 31, 
+2015 
+2014 
+Principal components: 
+Senior secured revolving credit facility 
+$ 
+40,000 
+$ 
+35,000 
+Secured second lien term loan 
+300,000 
+300,000 
+Total principal outstanding 
+340,000 
+335,000 
+Secured second lien term loan, unamortized deferred financing costs 
+(11,435)
+(13,424)
+Total carrying value of borrowings 
+$ 
+328,565 
+$ 
+321,576 
+C redit F acility 
+On March 11, 2014, the Company entered into the Fifth Amended and Restated Credit Agreement to the Credit Facility with a maturity date of March 11, 2019 . JPMorgan Chase Bank, N.A. is Administrative Agent, and participating lenders include Regions Bank, Citibank, N.A., Capital One, N.A., KeyBank, N.A., Whitney Bank, IberiaBank, N.A., OneWest Bank, N.A., SunTrust Bank and Royal Ban k of Canada. The total notional amount available under the Credit Facility is $500,000 . Amounts borrowed under the Credit Facility may not exceed the borrowing base, which is generally reviewed on a semi-annual basis. As of December 31, 2015, the Credit Facility’s borrowing base was $ 300,000 . The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. 
+As of December 31, 2015 , the balance outstanding on the Credit Facility was $40,000 with a weighted-average interest rate of 2.07% , calculated as the LIBOR plus a tiered rate ranging from 1.75% to 2.75% , which is determined based on utilization of the facility. In addition, the Credit Facility carries a commitment fee of 0.5% per annum, payable quarterly, on the unused portion of the borrowing base. The Company had $ 260,000 of available borrowings under the Credit Facility as of December 31, 2015 . 
+76 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+Term loans 
+On March 11, 2014, the Company entered into a term loan in an aggregate amount of up to $125,000 , including initial commitments of $100,000 and additional availability of $25,000 subject to the consent of two-thirds of the lenders and compliance with financial covenants after giving effect to such increase. The term loan had a maturity date of September 11, 2019, and was not subject to mandatory prepayments unless new debt or preferred stock wa s issued. It was prepayable at the Company’s option, subject to a prepayment premium. The prepayment amount was (i) 102% if the prepayment event occurs prior to March 11, 2015, and (ii) 101% if the prepayment event occurs on or after March 15, 2015 but before March 15, 2016, and (iii) 100% for prepayments made on or after March 15, 2016. The term loan was secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor agreement. On April 10, 2014, the Company drew an initial amount of $62,500 with an original issue discount of 1.0% . 
+On October 8, 2014, the term loan described above was repaid in full using proceeds from a new secured second lien term loan (the “Second Lien Loan”) in conjunction with the closing of the Central Midland A cquisition, resulting in a loss on early extinguishment of debt of $3,054 . The Second Lien Loan has a maturity date of October 8, 2021. On October 8, 2014, the Company drew an initial amount of $300,000 with a discount of 2.0% and an interest rate of 8.5% , calculated at a rate of LIBOR (subject to a floor rate of 1.0% %) plus 7.5% per annum. The Second Lien Loan may be prepaid at the Company’s option, subject to a prepayment premium. The prepayment amount is (i) 102% if the prepayment event occurs prior to October 8, 201 6 , and (ii) 101% if the prepayment event occurs on or after October 8, 201 6 but before October 8, 201 7 , and (iii) 100% for prepayments made on or after October 8, 201 7 . The Second Lien Loan is secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor agreement. The Royal Bank of Canada is Administrative Agent, and participants include several institutional lenders. 
+As of December 31, 2015 , the balance outstanding on the Second Lien Loan was $ 300,000 with an interest rate of 8.5% , calculated at a rate of LIBOR (subject to a floor rate of 1.0% ) plus 7.5% per annum. The Company can elect a LIBOR rate based on various tenors, and is currently incurring interest based on an underlying three-month LIBOR rate, which was last elected in January 2016 . 
+13% senior notes due 2016 (“Senior Notes”) and deferred credit 
+On April 11, 2014, the Company completed a full redemption of the remaining $48,481 principal amount of outstanding Senior Notes using proceeds from the Second Lien Loan. The redemption resulted in a net $3,205 gain on the early extinguishment of debt (including $4,780 of accelerated deferred credit amortization). The gain represents the difference between the $50,057 paid for the redemption of the Senior Notes ( $1,576 of redemption costs, primarily the call premium) and the carrying value of the remaining Senior Notes of $53,261 (inclusive of $4,780 of deferred credit). The Company also paid $193 in accrued interest through the redemption date. Upon the redemption, the indenture governing the Senior Notes was discharged in accordance with its terms. 
+Using a portion of the proceeds from the sale of our interest in Medusa on December 17, 2013, the Company redeemed $48,481 of its Senior Notes, which resulted in a net $3,696 gain on the early extinguishment of debt. The gain represents the difference between the $50,057 paid for the redemption of the Senior Notes (inclusive of $1,576 of redemption expenses, primarily the call premium) and the carrying value of $53,756 (inclusive of the $5,275 of accelerated deferred credit amortization). 
+Restrictive covenants 
+The Company’s Credit Facility and Second Lien Loan contain various covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. The Company was in compliance with these covenants at December 31, 2015 . 
+Note 6 - Der ivative Instruments and Hedging Activities 
+Objectives and strategies for using derivative instruments 
+The Company is exposed to fluctuations in oil and natural gas prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil and natural gas production. The Company utilizes a mix of 
+77 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+collars, swaps, puts, calls and similar derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes. 
+Counterparty risk and offsetting 
+The use of derivative instruments exposes the Company to the risk that a counterparty will be unable to meet its commitments. While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument; see Note 7 for additional information regarding fair value. 
+The Company executes commodity derivative contracts under master agreements that have netting provisions that provide for offsetting assets against liabilities. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement. 
+Financial statement presentation and settlements 
+Settlements of the Company’s derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets. See Note 7 for additional information regarding fair value. 
+Derivatives not designated as hedging instruments 
+The Company records its derivative contracts at fair value in the consolidated balance sheet and records changes in fair value as a gain or loss on derivative contracts in the consolidated statement of operations. Cash settlements are also recorded as gain or loss on derivative contracts in the consolidated statement of operations. 
+The following table reflects the fair value of the Company’s derivative instruments not designated as h edging i nstruments under ASC 815 for the periods presented: 
+Balance Sheet Presentation 
+Asset Fair Value 
+Liability Fair Value 
+Net Derivative Fair Value 
+Commodity 
+Classification 
+Line Description 
+12/31/2015 
+12/31/2014 
+12/31/2015 
+12/31/2014 
+12/31/2015 
+12/31/2014 
+Natural gas 
+Current 
+Fair value of derivatives 
+$ 
+— 
+$ 
+1,262 
+$ 
+— 
+$ 
+(7)
+$ 
+— 
+$ 
+1,255 
+Oil 
+Current 
+Fair value of derivatives 
+19,943 
+26,588 
+— 
+(1,242)
+19,943 
+25,346 
+Total 
+$ 
+19,943 
+$ 
+27,850 
+$ 
+— 
+$ 
+(1,249)
+$ 
+19,943 
+$ 
+26,601 
+As previously discussed, the Company’s derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated: 
+For the Year Ended December 31, 2015 
+Presented without 
+As Presented with 
+Effects of Netting 
+Effects of Netting 
+Effects of Netting 
+Current assets: Fair value of derivatives 
+$ 
+19,943 
+$ 
+— 
+$ 
+19,943 
+For the Year Ended December 31, 2014 
+Presented without 
+As Presented with 
+Effects of Netting 
+Effects of Netting 
+Effects of Netting 
+Current assets: Fair value of derivatives 
+$ 
+27,850 
+$ 
+— 
+$ 
+27,850 
+Current liabilities: Fair value of derivatives 
+(1,249)
+— 
+(1,249)
+78 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+Derivatives not designated as hedging instruments under ASC 815 
+For the periods indicated, the Company recorded the following related to its derivatives in the consolidated statement of operations as gain or loss on derivative contracts: 
+For the Year Ended December 31, 
+2015 
+2014 
+2013 
+Natural gas derivatives 
+Net gain (loss) on settlements 
+$ 
+1,717 
+$ 
+(84)
+$ 
+(148)
+Net gain (loss) on fair value adjustments 
+(1,255)
+1,267 
+230 
+Total gain (loss) 
+$ 
+462 
+$ 
+1,183 
+$ 
+82 
+Oil derivatives 
+Net gain (loss) on settlements 
+$ 
+33,299 
+$ 
+4,170 
+$ 
+1,518 
+Net gain (loss) on fair value adjustments 
+(5,403)
+26,383 
+(2,960)
+Total gain (loss) 
+$ 
+27,896 
+$ 
+30,553 
+$ 
+(1,442)
+Total gain (loss) on derivative contracts 
+$ 
+28,358 
+$ 
+31,736 
+$ 
+(1,360)
+Derivative positions 
+As of December 31, 2015, the Company had no outstanding natural gas derivative contracts. Listed in the table below are the outstanding oil derivative contracts as of December 31, 2015: 
+For the Three Months Ended 
+March 31, 
+June 30, 
+September 30, 
+December 31, 
+Oil contracts 
+2016 
+2016 
+2016 
+2016 
+Swap contracts (NYMEX) 
+Total volume (MBbls) 
+182 
+182 
+184 
+184 
+Weighted average price per Bbl 
+$ 
+58.23 
+$ 
+58.23 
+$ 
+58.23 
+$ 
+58.23 
+Swap contracts (Midland basis 
+differentials) 
+Volume (MBbls) 
+364 
+364 
+368 
+368 
+Weighted average price per Bbl 
+$ 
+0.17 
+$ 
+0.17 
+$ 
+0.17 
+$ 
+0.17 
+Collar contracts combined with 
+short puts (WTI, three-way collar) 
+Total volume (MBbls) 
+182 
+182 
+184 
+184 
+Weighted average price per Bbl 
+Ceiling (short call) 
+$ 
+65.00 
+$ 
+65.00 
+$ 
+65.00 
+$ 
+65.00 
+Floor (long put) 
+$ 
+55.00 
+$ 
+55.00 
+$ 
+55.00 
+$ 
+55.00 
+Short put 
+$ 
+40.33 
+$ 
+40.33 
+$ 
+40.33 
+$ 
+40.33 
+79 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+The following derivative contracts for oil and natural gas were executed subsequent to December 31, 2015 : 
+For the Three Months Ended 
+March 31, 
+June 30, 
+September 30, 
+December 31, 
+Oil contracts 
+2016 
+2016 
+2016 
+2016 
+Collar contracts 
+Total volume (MBbls) 
+120 
+182 
+184 
+184 
+Weighted average price per Bbl 
+Ceiling (short call) 
+$ 
+46.50 
+$ 
+46.50 
+$ 
+46.50 
+$ 
+46.50 
+Floor (long put) 
+$ 
+37.50 
+$ 
+37.50 
+$ 
+37.50 
+$ 
+37.50 
+Natural gas contracts 
+Swap contracts 
+Total volume (BBtu) 
+360 
+546 
+552 
+552 
+Weighted average price per MMBtu 
+$ 
+2.52 
+$ 
+2.52 
+$ 
+2.52 
+$ 
+2.52 
+For the Three Months Ended 
+March 31, 
+June 30, 
+September 30, 
+December 31, 
+Oil contracts 
+2017 
+2017 
+2017 
+2017 
+Call contracts (short) 
+Total volume (MBbls) 
+165 
+167 
+169 
+169 
+Weighted average price per Bbl 
+Call strike price 
+$ 
+50.00 
+$ 
+50.00 
+$ 
+50.00 
+$ 
+50.00 
+Note 7 - Fair Valu e Measurements 
+The fair value hierarchy included in GAAP gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable, and these valuations have the lowest priority. 
+Fair Value of Financial Instruments 
+Cash, cash equivalents, and restricted investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments. 
+Debt. The carrying amount of the Company’s floating-rate debt approximated fair value because the interest rates were variable and reflective of market rates. 
+Assets and liabilities measured at fair value on a recurring basis 
+Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheet. The following methods and assumptions were used to estimate fair value: 
+Commodity derivative instruments. The fair value of commodity derivative instruments is derived using an income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. The Company believes that the majority of the inputs used to calculate the commodity derivative instruments fall within Level 2 of the fair value hierarchy based on the wide availability of quoted market prices for similar commodity derivative contracts. See Note 6 for additional information regarding the Company’s derivative instruments. 
+80 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis: 
+December 31, 2015 
+Balance Sheet Presentation 
+Level 1 
+Level 2 
+Level 3 
+Total 
+Assets 
+Derivative financial instruments (current) 
+Fair value of derivatives 
+$ 
+— 
+$ 
+19,943 
+$ 
+— 
+$ 
+19,943 
+Liabilities 
+Derivative financial instruments (current) 
+Fair value of derivatives 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+Total net assets 
+$ 
+— 
+$ 
+19,943 
+$ 
+— 
+$ 
+19,943 
+December 31, 2014 
+Balance Sheet Presentation 
+Level 1 
+Level 2 
+Level 3 
+Total 
+Assets 
+Derivative financial instruments (current) 
+Fair value of derivatives 
+$ 
+— 
+$ 
+27,850 
+$ 
+— 
+$ 
+27,850 
+Liabilities 
+Derivative financial instruments (current) 
+Fair value of derivatives 
+$ 
+— 
+$ 
+(1,249)
+$ 
+— 
+$ 
+(1,249)
+Total net assets 
+$ 
+— 
+$ 
+26,601 
+$ 
+— 
+$ 
+26,601 
+Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis 
+Acquisition. A s discussed in Note 3 , the Company completed acquisitions during 2014 and 2015. The Company determined the fair value of the assets acquired using the income approach based on expected future cash flows from estimated reserve quantities , costs to produce and develop reserves , and oil and gas forward prices. Asset retirement obligations assumed in connection with acquisition s were determined in accordance with applicable accounting standards. The fair value measurements were based on level 2 and level 3 inputs. 
+Note 8 – Emplo yee Benefit Plans 
+The Company utilizes various forms of incentive compensation designed to align the interest of the executives and employees with those of its stockholders. Tabular disclosures related to the share-based awards are presented in Note 9 . The narrative that follows provides a brief description of each plan, summarizes the overall status of each plan and discusses current year awards under each plan: 
+Savings and Protection Plan 
+The Savings and Protection Plan (“401-K Plan”) provides employees with the option to defer receipt of a portion of their compensation, and the Company may, at its discretion, match a portion of the employee’s deferral with cash. The Company may also elect, at its discretion, to contribute a non-matching amount in cash and Company c ommon s tock to employees. The amounts held under the 401-K Plan are invested in various funds maintained by a third party in accordance with the directions of each employee. An employee is fully vested, including Company discretionary contributions, immediately upon participation in the 401-K Plan. The total amounts contributed by the Company, including the value of the common stock contributed, were $999 , $1,017 and $923 in the years 2015 , 2014 and 2013 , respectively. 
+2011 Omnibus Incentive Plan (the “2011 Plan”) 
+The 2011 Plan, which became effective May 12, 2011 following shareholder approval, authorized and reserved for issuance 2,300,000 shares of common stock, which may be issued upon exercise of vested stock options and/or the vesting of any other share-based equity award that is granted under this plan. The 2011 Plan is the Company’s only active plan, and included a provision at inception whereby all remaining, un-issued and authorized shares from the Company’s previous share-based incentive plans became issuable under the 2011 Plan. This transfer provision resulted in the transfer of an additional 841,000 shares into the plan, increasing the quantity authorized and reserved for issuance under the 2011 Plan to 3,141,000 at the inception of the plan. Another provision provided that shares which would otherwise become available for issu ance under the previous plans as a result of vesting and/or forfeiture of any equity awards existing as of May 12, 2012, would also increase the authorized shares available to the 2011 Plan. 
+At the 2015 Annual Meeting of Shareholders, the Company’s shareholders approved the First Amendment to the Callon Petroleum Company 2011 Omnibus Incentive Plan (the “First Amendment”), which provided for (i) an increase in the number of shares of the 
+81 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+Company’s common stock available for grant under the Plan by 2,000,000 shares from 2,300,000 shares to 4,300,000 shares, (ii) the adoption of a “double trigger” meaning that, in the event of a Company change in control, early vesting or payment occurs only if a change in control occurs and the executive’s employment is terminated or constructively terminated, and (iii) the elimination of the adding back of terminated options and stock appreciation rights shares for future grants. The First Amendment was made effective as of May 14, 2015. Including the transfer provision mentioned above, the quantity authorized and reserved for issuance under the 2011 Plan is 5,141,000 as of the effective date of the First Amendment. As of December 31, 2015 , the 2011 Plan had 2,926,545 shares remaining and eligible for future issuance. 
+RSU e quity a wards . RSU e quity awards issued under this plan may be subject to various vesting, accelerated vesting, and forfeiture provisions upon the occurrence of certain events. RSU e quity awards under the 2011 Plan generally vest over time but may also be subject to attaining a specified performance metrics and may vest immediately or cliff vest at a specified date. The Company will recognize expense on the grant date for all immediately vesting awards, while it will recognize expense ratably over the requisite service (i.e. vesting) period for both cliff and ratably vesting awards. 
+For market-based RSU equity awards, the Company recognizes expense based on the fair value of the awards at the grant date . A wards with a market-based provision do not allow for the reversal of previously recognized expense, even if the market metric is not achieved and no shares ultimately vest or are awarded. Market-based RSU equity awards that vest are based on a calculation that compares the Company’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between 0% and 200% of the base units awarded. 
+Cash- s ettled RSU a wards. Certain of the Company’s RSUs awarded require cash settlement. Cash-settled RSU awards are accounted for as liabilities as the Company is contractually obligated to settle these awards in cash. Changes in the fair value of cash-settleable awards are recorded as adjustments to compensation expense. 
+A significant portion of the Company’s cash-settled RSU awards include a market-based vesting condition that determines the actual number of units that will ultimately vest. The number of RSUs that vest is based on a calculation that compares the Company’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between 0% and 200% of the base units awarded. The fair value of the Company’s market-based RSU awards is calculated using a Monte Carlo valuation model, which considers such inputs as the Company’s and its peer group’s stock prices, a risk-free interest rate, and an estimated volatility for the Company and its peer group. 
+Note 9 - Shar e-Based Compensation 
+As discussed in Note 8, the Company grants various forms of share-based compensation awards to employees of the Company and its subsidiaries and to non-employee members of the Board of Directors. At December 31, 2015 , shares available for future share-based awards, including stock options or restricted stock grants, under the Company’s only active plan, the 2011 Plan, were 2,926,545 . 
+The following table presents share-based compensation expense for each respective period: 
+For the Year Ended December 31, 
+2015 
+2014 
+2013 
+Share-based compensation cost for: 
+Equity-based 
+Liability-based 
+Equity-based 
+Liability-based 
+Equity-based 
+Liability-based 
+RSU equity awards 
+$ 
+3,797 
+$ 
+— 
+$ 
+4,223 
+$ 
+— 
+$ 
+3,975 
+$ 
+— 
+Cash-settleable RSU awards 
+— 
+11,437 
+— 
+6,918 
+— 
+5,347 
+401(k) contributions in shares 
+266 
+— 
+270 
+— 
+219 
+— 
+Total share-based compensation cost (a) 
+$ 
+4,063 
+$ 
+11,437 
+$ 
+4,493 
+$ 
+6,918 
+$ 
+4,194 
+$ 
+5,347 
+(a) 
+The portion of this share-based compensation cost that was included in general and administrative expense totaled $9,299 , $ 7,235 and $ 5,751 for the same years, respectively, and the portion capitalized to oil and gas properties was $6,201 , $ 4,176 and $ 3,791 , respectively. 
+82 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+The following table presents the unrecognized compensation cost for the indicated periods: 
+December 31, 
+Unrecognized compensation cost related to: 
+2015 
+2014 
+2013 
+Unvested RSU equity awards 
+$ 
+5,208 
+$ 
+3,979 
+$ 
+5,331 
+Unvested cash-settleable RSU awards 
+4,728 
+4,977 
+7,669 
+The Company’s unrecognized compensation cost related to unvested RSU equity awards and cash-settleable RSU awards is expected to be recognized over a weighted-average period of 1.8 years . 
+The following table summarizes the Company’s liability for cash-settled RSU awards for the periods indicated: 
+December 31, 
+Consolidated Balance Sheets Classification 
+2015 
+2014 
+Cash-settled restricted stock unit awards (current) 
+$ 
+10,128 
+$ 
+3,856 
+Cash-settled restricted stock unit awards (non-current) 
+4,877 
+7,175 
+Total cash-settled RSU awards 
+$ 
+15,005 
+$ 
+11,031 
+Stock Options 
+The Company issued no stock options for the past three years and had no options vest or forfeit during 2015 . Additionally, no options were exercised, and 15,000 options expired unexercised during the year. As of December 31, 2015 , the Company had 15,000 options outstanding and exercisable at a weighted average exercise price per option of $14.37 , with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 1.3 years. As of December 31, 2014 , the Company had 30,000 options outstanding and exercisable at a weighted average exercise price per option of $14.04 , with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 1.3 years. As of December 31, 2013, the Company had 52,000 options outstanding and exercisable at a weighted average exercise price per option of $13.75 , with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 2.7 years. 
+Restricted Stock Units 
+The following table represents unvested restricted stock activity for the year ended December 31, 2015 : 
+Weighted average 
+(shares in 000s) 
+Number of Shares 
+Grant-Date Fair Value per Share 
+Period over which expense is expected to be recognized 
+Outstanding at the beginning of the period 
+1,868 
+$ 
+5.40 
+Granted (a) 
+560 
+8.98 
+Vested (b) 
+(1,012)
+5.36 
+Forfeited 
+— 
+Outstanding at the end of the period 
+1,416 
+$ 
+6.94 
+1.5 
+(a) 
+Includes 126 market-based RSUs that will vest at a range of 0% - 200% . See Note 8 for additional information about market-based RSU equity awards . 
+(b) 
+The fair value of shares vest ed was $5,425 . 
+For the year ended December 31, 2 014, the Company granted 333,000 RSU s with a weighted average grant-date fair value of $ 9.67 per share. The fair value of shares vested during 2014 was $ 4,338 . For the year ended December 31, 2013, the Company granted 944,000 RSUs with a weighted average grant-date fair value of $3.82 per share. The fair value of shares vested during 2013 was $2,689 . 
+83 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+As of December 31, 2015, the Company had the following cash-settleable RSU s outstanding (including those that are not based on a market condition): 
+(shares in 000s) 
+Base Units Outstanding 
+Potential Minimum Units Vesting 
+Potential Maximum Units Vesting 
+Vesting in 2016 
+332 
+45 
+619 
+Vesting in 2017 
+231 
+19 
+443 
+Vesting in 2018 
+25 
+25 
+25 
+Other 
+167 
+167 
+167 
+Total cash-settleable RSUs 
+755 
+256 
+1,254 
+For the year ended December 31, 2015, 853,673 market-based cash-settled RSUs subject to the peer market-based vesting described in Note 8 vested at between 150% - 200% of their issued units, depending on the date of vesting , resulting in cash payments of $3,319 in 2015 and payable amounts of $9,807 in 2016. Also during 2015, 72,108 non-market-based cash settled RSUs vested, resulting in cash payments of $545 in 2015. During 2014, 523,000 market-based cash-settled RSUs subject to the peer market-based vesting described above vested at between 150% - 200% of their issued units, depending on the date of the vesting, resulting in cash payments of $1,241 in 2014 and $ 3,599 in 2015. Also during 2014, 58,000 non-market-based cash settled RSUs vested, resulting in cash payments of $559 in 2014. See Note 8 for additional information regarding cash-settleable RSUs. 
+Note 10 – Eq uity Transactions 
+10% Series A Cumulative Preferred Stock (“Preferred Stock”) 
+Holders of the Company’s Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10.0% per annum of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share). Dividends are payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by our Board of Directors. Preferred Stock dividends were $7,895 , $7,895 and $ 4,627 in 2015, 2014 and 2013 respectively. 
+The Preferred Stock has no stated maturity and is not be subject to any sinking fund or other mandatory redemption. On or after May 30, 2018, the Company may, at its option, redeem the Preferred Stock, in whole or in part, by paying $50.00 per share, plus any accrued and unpaid dividends to the redemption date. 
+Following a change of control, the Company will have the option to redeem the Preferred Stock, in whole but not in part for $50.00 per share in cash, plus accrued and unpaid dividends (whether or not declared), to the redemption date. If the Company does not exercise its option to redeem the Preferred Stock upon a change of control, the holders of the Preferred Stock have the option to convert the Preferred Stock into a number of shares of the Company’s common stock based on the value of the common stock on the date of the change of control as determined under the certificate of designations for the Preferred Stock. If the change of control occurred on December 31, 2015 , and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of $ 8.34 as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately 6.0 shares of common stock. If the Company exercises its redemption rights relating to shares of Preferred Stock, the holders of Preferred Stock will not have the conversion right described above. 
+Subsequent to December 31, 2015 , a total of 120 ,000 shares of Preferred Stock were exchanged for a total of 719,000 shares of Common Stock. 
+84 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+Common Stock 
+On November 16 , 2015, the Company completed an underwritten public offering of 12,000,000 shares of its common stock at $ 8.40 per share, before underwriting discounts, and the exercise in full by the underwriters of their option to purchase 1,800,000 additional shares of common stock at $8.40 per share, before underwriting discounts. The Company received net proceeds of approximately $ 109,913 , after the underwriting discounts and estimated offering costs , which were used to repay amounts outstanding under the Credit Facility . 
+On March 13, 2015, the Company completed an underwritten public offering of 9,000,000 shares of its common stock at $ 6.55 per share, before underwriting discounts, and the exercise in full by the underwriters of their option to purchase 1,350,000 additional shares of common stock at $6.55 per share, before underwriting discounts. The Company received net proceeds of approximately $ 65,644 , after the underwriting discounts and estimated offering costs , which were used to repay amounts outstanding under the Credit Facility. 
+On September 15, 2014 the Company completed an underwritten public offering of 12,500,000 shares of its common stock at $9.00 per share, before underwriting discounts, and the exercise in full by the underwriters of their option to purchase 1,875,000 additional shares of common stock at $9.00 per share. The Company received net proceeds of approximately $122,514 , after the underwriting discounts and estimated offering costs, which were used to fund a portion of the purchase price of the Central Midland Basin Acquisition (see Note 3). 
+Note 11 - Inco me Taxes 
+The following table presents Callon’s deferred tax assets and liabilities with respect to its carryforwards and other temporary differences: 
+As of December 31, 
+2015 
+2014 
+Deferred tax asset 
+Federal net operating loss carryforward 
+$ 
+107,935 
+$ 
+86,629 
+Statutory depletion carryforward 
+8,843 
+8,876 
+Alternative minimum tax credit carryforward 
+208 
+208 
+Asset retirement obligations 
+630 
+1,003 
+Other 
+8,241 
+6,621 
+Deferred tax asset before valuation allowance 
+125,857 
+103,337 
+Deferred tax liability 
+Oil and natural gas properties 
+6,488 
+54,723 
+Other 
+10,526 
+10,140 
+Total deferred tax liability 
+17,014 
+64,863 
+Net deferred tax asset before valuation allowance 
+108,843 
+38,474 
+Less: Valuation allowance 
+(108,843)
+— 
+Net deferred tax asset 
+$ 
+— 
+$ 
+38,474 
+If not utilized, the Company’s federal operating loss (“NOL”) carryforwards will expire as follows: 
+Year Expiring 
+Total 
+2016-2021 
+2022-2024 
+2025-2027 
+2028-2030 
+2031-2035 
+Federal NOL carryforwards 
+$ 
+308,385 
+$ 
+13,892 
+$ 
+101,495 
+$ 
+39,714 
+$ 
+32,111 
+$ 
+121,173 
+As a result of the write-down of oil and natural gas properties discussed in Note 13, the Company has incurred a cumulative three year loss. Because of the impact the cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, the Company assessed the ability to realize its deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, the Company established a valuation allowance for a portion of the deferred tax asset. The valuation allowance was $108,843 as of December 31, 2015. 
+85 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+The Company had no significant unrecognized tax benefits at December 31, 2015 . Accordingly, the Company does not have any interest or penalties related to uncertain tax positions. However, if interest or penalties were to be incurred related to uncertain tax positions, such amounts would be recognized in income tax expense. Tax periods for years 200 2 through 201 5 remain open to examination by the federal and state taxing jurisdictions to which the Company is subject. 
+The Company provides for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses and state income taxes. The following table presents a reconciliation of the reported amount of income tax expense to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income from continuing operations : 
+For the Year Ended December 31, 
+Components of income tax rate reconciliation 
+2015 
+2014 
+2013 
+Income tax expense computed at the statutory federal income tax rate 
+35% 
+35% 
+35% 
+Percentage depletion carryforward 
+—% 
+—% 
+(8)% 
+State taxes net of federal benefit 
+1% 
+1% 
+4% 
+Restricted stock and stock options 
+—% 
+—% 
+5% 
+Section 162(m) 
+(1)% 
+2% 
+6% 
+Valuation allowance 
+(54)% 
+—% 
+—% 
+Effective income tax rate 
+(19)% 
+38% 
+42% 
+For the Year Ended December 31, 
+Components of income tax expense 
+2015 
+2014 
+2013 
+Current state income tax expense 
+$ 
+— 
+$ 
+— 
+$ 
+326 
+Deferred federal income tax (benefit) expense 
+(69,087)
+22,373 
+2,652 
+Deferred state income tax (benefit) expense 
+(1,282)
+761 
+126 
+Valuation allowance 
+108,843 
+— 
+— 
+Total income tax expense 
+$ 
+38,474 
+$ 
+23,134 
+$ 
+3,104 
+Note 12 - Asset Reti rement Obligations 
+The table below summarizes the activity for the Company’s asset retirement obligations: 
+For the Year Ended December 31, 
+2015 
+2014 
+Asset retirement obligations at January 1, 2015 
+$ 
+6,674 
+$ 
+6,732 
+Accretion expense 
+660 
+826 
+Liabilities incurred 
+165 
+638 
+Liabilities assumed 
+— 
+140 
+Liabilities settled 
+(2,964)
+(2,130)
+Revisions to estimate 
+572 
+468 
+Asset retirement obligations at end of period 
+5,107 
+6,674 
+Less: Current asset retirement obligations 
+(790)
+(4,747)
+Long-term asset retirement obligations at December 31, 2015 
+$ 
+4,317 
+$ 
+1,927 
+Certain of the Company’s operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded on the Consolidated Balance Sheets at December 31, 2015 and 2014 as long-term restricted investments were $3,309 and $3,810, respectively. These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties. 
+86 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+Note 13 – Supplemental Information on Oil and N atural Gas Properties (Unaudited) 
+The following table discloses certain financial data relating to the Company’s oil and natural gas activities, all of which are located in the United States. 
+For the Year Ended December 31, 
+2015 
+2014 
+2013 
+Evaluated Properties 
+Beginning of period balance 
+$ 
+2,077,985 
+$ 
+1,701,577 
+$ 
+1,497,010 
+Capitalized G&A 
+10,529 
+10,071 
+10,014 
+Property acquisition costs (a) 
+26,726 
+94,541 
+10,885 
+Exploration costs 
+81,320 
+118,251 
+147,164 
+Development costs 
+138,663 
+153,545 
+36,504 
+End of period balance 
+$ 
+2,335,223 
+$ 
+2,077,985 
+$ 
+1,701,577 
+Unevaluated Properties 
+Beginning of period balance 
+$ 
+142,525 
+$ 
+43,222 
+$ 
+68,776 
+Property acquisition costs (a) 
+5,520 
+128,342 
+2,259 
+Exploration costs 
+4,576 
+11,177 
+10,767 
+Capitalized interest 
+10,459 
+4,295 
+4,410 
+Transfers to evaluated 
+(30,899)
+(44,511)
+(42,990)
+End of period balance 
+$ 
+132,181 
+$ 
+142,525 
+$ 
+43,222 
+Accumulated depreciation, depletion and amortization 
+Beginning of period balance 
+$ 
+1,478,355 
+$ 
+1,420,612 
+$ 
+1,296,265 
+Provision charged to expense 
+69,228 
+56,663 
+42,251 
+Write-down of oil and natural gas properties 
+208,435 
+— 
+— 
+Sale of mineral interests 
+— 
+1,080 
+82,096 
+End of period balance 
+$ 
+1,756,018 
+$ 
+1,478,355 
+$ 
+1,420,612 
+(a) 
+For more information on acquisitions refer to Note 3 . 
+Unevaluated property costs primarily include lease acquisition costs, unevaluated drilling costs, seismic, capitalized interest and certain overhead costs related to exploration and development. These costs are directly related to the acquisition and evaluation of unproved properties. The excluded costs and related reserves are included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined. The Company expects that the majority of these costs will be evaluated over the next three to five years. 
+Subsequent to December 31, 2015 and through February 26, 2016 , the Company dri lled 5 gross horizontal wells and completed 2 gross horizontal wells and had 5 gross horizontal wells awaiting completion . 
+Depletion per unit-of-production, on a BOE basis, amounted to $19.74 , $27.51 and $31.12 for the years ended December 31, 2015 , 2014 , and 2013 , respectively. Lease operating expenses per unit-of-production, on a BOE basis, amounted to $7.71 , $10.85 , and $14.00 for the years ended December 31, 2015 , 2014 , and 2013 , respectively. 
+The Company uses the full cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as oil and gas properties. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest capitalized on unevaluated leases, other costs related to exploration and development activities, and site restoration, dismantlement and abandonment costs capitalized in accordance with asset retirement obligation accounting guidance. Costs capitalized also include any internal costs that are directly related to exploration and development activities, including salaries and benefits, but do not include any costs related to production, general corporate overhead or similar activities. 
+87 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full cost ceiling). These rules generally require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling. At December 31, 2015, the prices used in determining the estimated future net cash flows from proved reserves were $47.25 per barrel of oil and $2.73 per Mcf of natural gas. For the year ended December 31, 2015, the Company recognized a write-down of oil and natural gas properties of $208,435 as a result of the ceiling test limitation. 
+Estimated Reserves 
+The Company’s proved oil and natural gas reserves at December 31, 2015 and 2014 have been estimated by DeGolyer and MacNaughton, the Company’s current independent petroleum engineers. The Company’s proved oil and natural gas reserves at December 31, 2013 were estimated by Huddleston & Co., Inc. The reserves were prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions. 
+There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only, and should not be deemed exact. In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company’s oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves. 
+The following table s disclose c hanges in the estimated net quantities of oil and natural gas reserves, all of which are located onshore within the continental United States: 
+For the Year Ended December 31, 
+Proved developed and undeveloped reserves: 
+2015 
+2014 
+2013 
+Oil (MBbls): 
+Beginning of period 
+25,733 
+11,898 
+10,780 
+Revisions to previous estimates 
+(1,632)
+(243)
+(2,540)
+Purchase of reserves in place 
+2,932 
+3,223 
+150 
+Sale of reserves in place 
+(23)
+— 
+(3,294)
+Extensions and discoveries 
+19,127 
+12,547 
+7,713 
+Production 
+(2,789)
+(1,692)
+(911)
+End of period 
+43,348 
+25,733 
+11,898 
+Natural Gas (MMcf): 
+Beginning of period 
+42,548 
+17,751 
+19,753 
+Revisions to previous estimates 
+4,870 
+(215)
+(5,351)
+Purchase of reserves in place 
+2,915 
+8,591 
+317 
+Sale of reserves in place 
+(105)
+— 
+(4,576)
+Extensions and discoveries 
+19,621 
+18,641 
+10,619 
+Production 
+(4,312)
+(2,220)
+(3,011)
+End of period 
+65,537 
+42,548 
+17,751 
+88 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+For the Year Ended December 31, 
+Proved developed reserves: 
+2015 
+2014 
+2013 
+Oil (MBbls): 
+Beginning of period 
+14,006 
+5,960 
+4,955 
+End of period 
+22,257 
+14,006 
+5,960 
+Natural gas (MMcf): 
+Beginning of period 
+25,171 
+9,059 
+10,680 
+End of period 
+38,157 
+25,171 
+9,059 
+MBOE: 
+Beginning of period 
+18,201 
+7,470 
+6,735 
+End of period 
+28,617 
+18,201 
+7,470 
+Proved undeveloped reserves: 
+Oil (MBbls): 
+Beginning of period 
+11,727 
+5,938 
+5,825 
+End of period 
+21,091 
+11,727 
+5,938 
+Natural gas (MMcf): 
+Beginning of period 
+17,377 
+8,692 
+9,073 
+End of period 
+27,380 
+17,377 
+8,692 
+MBOE: 
+Beginning of period 
+14,623 
+7,387 
+7,337 
+End of period 
+25,654 
+14,623 
+7,387 
+Total Proved Reserves: The Company ended 2015 with estimated net proved reserves of 54,271 MBOE, representing a 65% increase over 2014 year-end estimated net proved reserves of 32,824 MBOE. The increase was primarily due the Company’s development of its properties in the Permian Basin, on which it drilled a total of 36 gross ( 27.1 net) wells, and acquisitions made during 2015 . This increase was primarily offset by 201 5 production and revisions. 
+The Company ended 2014 with estimated net proved reserves of 32,824 MBOE, representing a 121% increase over 2013 year-end estimated net proved reserves of 14,857 MBOE. The increase was primarily due the Company’s development of its properties in the Permian Basin, on which it drilled a total of 34 gross ( 28.7 net) wells, and acquisitions made during 2014. This increase was primarily offset by 2014 production and revisions. 
+The Company ended 2013 with estimated net proved reserves of 14,857 MBOE, representing a 6% increase over 2012 year-end estimated net proved reserves of 14,072 MBOE. The increase was primarily due the Company’s development of its properties in the Permian Basin offset by the sale of the Company’s interest in the Medusa field and due to the Company’s reclassification of certain vertical PUD locations to the horizontal probable and PUD categories. 
+Extrapolation of performance history and material balance estimates were utilized by the Company’s independent petroleum and geological firm to project future recoverable reserves for the producing properties where sufficient history existed to suggest performance trends and where these methods were applicable to the subject reservoirs. The projections for the remaining producing properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to nonproducing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production, and to a small extent, horizontal PDP and PUD categories. 
+Proved Undeveloped Reserves: The Company annually reviews its proved undeveloped reserves (“PUDs”) to ensure an appropriate plan for development exists. Generally, reserves for the Company’s properties are booked as PUDs only if the Company has plans to convert the PUDs into proved developed reserves within five years of the date they are first booked as PUDs. The Company’s PUDs increased 75% to 25,654 MBOE from 14,623 MBOE at December 31, 2015 and 2014 , respectively. The Company added 13,774 MBOE to its PUDs, net of revisions, primarily from the continued horizontal development of its Permian Basin properties and from acquisitions in the Permian Basin. The increase in Permian Basin PUDs was partially offset by the reclassification of 2,742 MBOE, or 19% , included in the year-end 2014 PUDs, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately $55,933 , net. 
+89 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+The Company’s PUDs increased 98% to 14,623 MBOE from 7,387 MBOE at December 31, 2014 and 2013, respectively. The Company added 10,125 MBOE to its PUDs, net of revisions, primarily from the continued horizontal development of its Permian Basin properties and from acquisitions in the Permian Basin. The increase in Permian Basin PUDs was partially offset by the reclassification of 1,757 MBOE, or 24% , included in the year-end 2013 PUD reserves, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately $ 34,619 , net. Also offsetting the increase was the removal of 1,132 MBOE of PUDs, including the impact from the reclassification of previous vertical PUDs to the horizontal probable category given our focus on horizontal development. 
+The Company’s PUDs increased 1% to 7,387 MBOE from 7,337 MBOE at December 31, 2013 and 2012, respectively. The Company added 5,168 MBOE to its PUDs, primarily from the continued horizontal development of its Permian Basin properties. The increase in Permian Basin PUDs was partially offset by 3,724 MBOE, or 51% , included in the year-end 2012 PUD reserves related to vertical PUD locations that were reclassified to horizontal probable reserves, and to a small extent, horizontal PDP and PUD categories. The reclassified vertical PUDs include locations that included certain target zones that were expected to be more efficiently developed by the Company’s multi-level horizontal drilling programs initiated in 2012. Also offsetting the Permian Basin PUD growth were the sale of 1,297 MBOE, or 18% , included in the year-end 2012 PUD reserves related to our Medusa field and the conversion of a small portion of 2012 PUD reserves to PDPs during 2013 from the drilling of vertical wells. 
+Standardized Measure 
+The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2015 . You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Prices are based on the preceding 12-months’ average price based on closing prices on the first day of each month. The following table summarizes the average 12-month oil and natural gas prices net of differentials for the respective periods: 
+2015 
+2014 
+2013 
+Average 12-month price, net of differentials, per Mcf of natural gas 
+$ 
+2.73 
+$ 
+6.38 
+$ 
+5.45 
+Average 12-month price, net of differentials, per barrel of oil 
+$ 
+47.25 
+$ 
+86.30 
+$ 
+92.16 
+Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate. 
+Natural gas production from our Permian Basin properties has a high Btu content of separator natural gas. The natural gas per Mcf prices of $2.73 , $6.38 and $5.45 used in the 2015 , 2014 and 2013 reserve estimates , respectively, include adjustments to reflect the Btu content, transportation charges and other fees specific to the individual properties. The oil prices per Bbl of $47.25 , $86.30 and $92.16 used in the 2015 , 2014 and 2013 reserve estimates , respectively, have been adjusted to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality. 
+Standardized Measure 
+For the Year Ended December 31, 
+2015 
+2014 
+2013 
+Future cash inflows 
+$ 
+2,227,463 
+$ 
+2,492,178 
+$ 
+1,193,299 
+Future costs 
+Production 
+(827,555)
+(873,469)
+(357,005)
+Development and net abandonment 
+(239,100)
+(288,081)
+(155,667)
+Future net inflows before income taxes 
+1,160,808 
+1,330,628 
+680,627 
+Future income taxes 
+— 
+(164,490)
+(68,239)
+Future net cash flows 
+1,160,808 
+1,166,138 
+612,388 
+10% discount factor 
+(589,918)
+(586,596)
+(328,442)
+Standardized measure of discounted future net cash flows 
+$ 
+570,890 
+$ 
+579,542 
+$ 
+283,946 
+90 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+Changes in Standardized Measure 
+For the Year Ended December 31, 
+2015 
+2014 
+2013 
+Standardized measure at the beginning of the period 
+$ 
+579,542 
+$ 
+283,946 
+$ 
+231,148 
+Sales and transfers, net of production costs 
+(110,476)
+(120,518)
+(78,661)
+Net change in sales and transfer prices, net of production costs 
+(286,660)
+(156,066)
+(46,088)
+Net change due to purchases and sales of in place reserves 
+37,616 
+111,331 
+(145,711)
+Extensions, discoveries, and improved recovery, net of future production and development costs incurred 
+184,469 
+299,192 
+212,431 
+Changes in future development cost 
+108,216 
+186,605 
+153,983 
+Revisions of quantity estimates 
+(12,625)
+(7,673)
+(68,958)
+Accretion of discount 
+62,968 
+30,114 
+25,010 
+Net change in income taxes 
+35,407 
+(32,940)
+1,751 
+Changes in production rates, timing and other 
+(27,567)
+(14,449)
+(959)
+Aggregate change 
+(8,652)
+295,596 
+52,798 
+Standardized measure at the end of period 
+$ 
+570,890 
+$ 
+579,542 
+$ 
+283,946 
+Note 14 – Other 
+Commitments and contingencies 
+The Company is involved in various claims and lawsuits incidental to its business. In the opinion of management, the ultimate liability hereunder, if any, will not have a material adverse effect on the financial position or results of operations of the Company. 
+The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment are not expected to have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies hereunder, and claims for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities. 
+Operating leases 
+As of December 31, 2015, the Company had contracts for two horizontal drilling rigs (the “Cactus 1 Rig” and “Cactus 2 Rig”). The Cactus 1 Rig was initially contracted for a term of two years in April 2012. The Cactus 2 Rig was initially contracted for a term of two years in April 2014. The Cactus 2 Rig replaced a previously contracted horizontal drilling rig, which was cancelled in March 2014. In March 2015, the Company extended the terms of its Cactus 1 Rig and Cactus 2 Rig to end in July 2018 and August 2018, respectively. The rig lease agreements include early termination provisions that obligate the Company to reduced minimum rentals pursuant to a “standby” dayrate for the term of the agreement. These payments would be reduced assuming the lessor is able to re-charter the rig and staffing personnel to another lessee. 
+In January 2016, the Company decided to place the Cactus 1 Rig on standby and will be required to pay a “standby” day rate of $ 15,000 per day, pursuant to the terms of the agreement , and t he Company retain s the option to return the rig to service. 
+In March 2015, the Company decided to terminate its one-year contract for a vertical rig (effective April 2015) . The Company paid approximately $ 3,075 in reduced rental payments over the remainder of the lease term, which ended November 2015 . The amount was recognized as rig termination fee on the consolidated statements of operations for the year ended December 31 , 2015. 
+91 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per unit data) 
+Table of Contents 
+Other property and equipment 
+During 2012, the Company sold certain specialized deep water property and equipment valued at $527 and determined that certain equipment components were not usable without additional rework and thus recorded an impairment charge to with respect to such equipment of $1,177 . During 2013, after selling certain specialized deep water property and equipment valued at $114 , the Company made a decision to abandon the equipment. As such the Company recorded an impairment charge of $1,707 representing the remaining value of this equipment. During 2014, the Company entered into an agreement to sell the property and equipment to a third party. As a result of the subsequent sale of the property and equipment, the Company recognized a gain of $1,080 . 
+Note 15 – S ummarized Quarterly Financial Information (Unaudited) 
+2015 
+First Quarter 
+Second Quarter 
+Third Quarter 
+Fourth Quarter 
+Total revenues 
+$ 
+30,391 
+$ 
+39,242 
+$ 
+34,316 
+$ 
+33,563 
+Income (loss) from operations (a) 
+(12,889)
+6,231 
+(83,910)
+(118,542)
+Net loss (a) 
+(10,197)
+(4,967)
+(111,805)
+(113,170)
+Loss available to common shares 
+(12,171)
+(6,940)
+(113,779)
+(115,144)
+Loss per common share - basic 
+$ 
+(0.21)
+$ 
+(0.11)
+$ 
+(1.72)
+$ 
+(1.58)
+Loss per common share - diluted 
+$ 
+(0.21)
+$ 
+(0.11)
+$ 
+(1.72)
+$ 
+(1.58)
+(a) 
+Loss from operations and net loss for the three months ended September 30, 2015 and December 31, 2015 included write-downs of oil and gas properties of $87,301 and $121,134 , r espectively. 
+2014 
+First Quarter 
+Second Quarter 
+Third Quarter 
+Fourth Quarter 
+Total revenues 
+$ 
+33,285 
+$ 
+40,502 
+$ 
+39,657 
+$ 
+38,418 
+Income from operations 
+6,645 
+12,080 
+11,562 
+7,983 
+Net income (loss) 
+1,863 
+4,740 
+12,201 
+18,962 
+Income (loss) available to common shares 
+(111)
+2,767 
+10,227 
+16,988 
+Income (loss) per common share - basic 
+$ 
+0.00 
+$ 
+0.07 
+$ 
+0.24 
+$ 
+0.31 
+Income (loss) per common share - diluted 
+$ 
+0.00 
+$ 
+0.07 
+$ 
+0.23 
+$ 
+0.30 
+92 
+Table of Contents 
+ITEM 9. Chan ges In and Disagreements w ith Accountants on Accounting and Financial Disclosure 
+On January 11, 2016, the Audit Committee of the Board of Directors of Callon Petroleum Company (the “Company”) approved the engagement of Grant Thornton LLP (“GT”) as the Company’s independent registered public accounting firm for the year ending December 31, 2016. GT has informed the Company that it completed the prospective client evaluation process on January 14, 2016. In connection with the selection of GT , also on January 11, 2016, the Audit Committee informed Ernst & Young LLP (“E&Y”) that they will no longer serve as the Company’s independent registered public accounting firm no later than the date of the filing of the Company’s Form 10-K for the 2015 fiscal year. The Audit Committee made its decision in connection with its annual review of the Company’s independent registered public accounting firm and after soliciting proposals from several accounting firms , including E&Y . 
+During the years ended December 31, 2014 and 2013, and through January 11, 2016, neither the Company nor anyone on its behalf has consulted with GT with respect to either (i) the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on the Registrant’s consolidated financial statements, and neither written nor oral advice was provided to the Company that GT concluded was an important factor considered by the Company in reaching a decision as to any accounting, auditing or financial reporting issue; (ii) any matter that was either the subject of disagreement (as defined in Item 304(a)(l)(iv) of Regulation S-K and the related instructions to Item 304 of Regulations S-K) or a reportable event (as defined by Item 304(a)(l)(v) of Regulation S-K). 
+The report of E&Y on the Company’s consolidated financial statements for the years ended December 31, 2014 and 2013, did not contain an adverse opinion or disclaimer of an opinion, and was not qualified or modified as to uncertainty, audit scope or accounting principles. 
+Item 9A. Co ntrols and Procedures 
+Disclosure controls and procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our Chief Executive Officer and Chief Financial Officer performed an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2015 . 
+Management’s report on internal control over financial reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. generally accepted accounting principles. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2015 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission ( 2013 framework)(the COSO criteria). Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2015 . 
+Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+The Company’s independent registered public accounting firm has issued an attestation report regarding its assessment of the Company’s internal control over financial reporting as of December 31, 2015 , which follows Part II, Item 9B of this filing. Additionally, the financial statements for each of the years covered in this Annual Report on Form 10-K have been audited by an independent registered public accounting firm, Ernst & Young LLP whose report is presented immediately preceding the Company’s financial statements included in Part II, Item 8 of this Annual Report on Form 10-K. 
+93 
+Table of Contents 
+Changes in internal control over financial reporting . There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting. 
+ITEM 9A (T). Controls and Procedures 
+See Item 9A. 
+ITEM 9B. Othe r Information 
+Submissions of m atters to a v ote of the s ecurity h olders 
+None. 
+94 
+Table of Contents 
+Repo rt of Independent Registered Public Accounting Firm 
+The Board of Directors and Stockholders of 
+Callon Petroleum Company 
+We have audited Callon Petroleum Company’s internal control over financial reporting as of December 31, 2015 based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ( 2013 framework)(the COSO criteria). Callon Petroleum Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. 
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+In our opinion, Callon Petroleum Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015 , based on the COSO criteria. 
+We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Callon Petroleum Company as of December 31, 2015 and 2014 , and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2015 , and our report dated March 2, 2016 expressed an unqualified opinion thereon. 
+/s/Ernst & Young LLP 
+New Orleans, Louisiana 
+March 2, 2016 
+95 
+Table of Contents 
+PAR T III. 
+ITEM 10. Direc tors, Executive Officers and Corporate Governance 
+For information concerning Item 10, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 12, 2016 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+The Company has adopted a code of ethics that applies to the Company’s chief executive officer, chief financial officer and chief accounting officer. The full text of such code of ethics has been posted on the Company’s W eb site at www.callon.com, and is available free of charge in print to any shareholder who requests it. Request for copies should be addressed to the Secretary at mailing address Post Office Box 1287, Natchez, Mississippi 39121. 
+ITEM 11. Exec utive Compensation 
+For information concerning Item 11, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 12, 2016 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+ITEM 12. Sec urity Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+For information concerning the security ownership of certain beneficial owners and management, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 12, 2016 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+ITEM 13. C ertain Relationships and Related Transactions and Director Independence 
+For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 12, 2016 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+ITEM 14. Prin cipal Accountant Fees and Services 
+For information concerning Item 14, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 12, 2016 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+96 
+Table of Contents 
+Item 15 . Exh ibits 
+The following is an index to the financial statements and financial statement schedules that are filed in Part II, Item 8 of this report on Form 10-K. 
+Exhibit Number 
+Description 
+The following is an index to the financial statements and financial statement schedules that are filed in Part II, Item 8 of this report on Form 10-K. 
+Report of Independent Registered Public Accounting Firm 
+Consolidated Balance Sheets as of December 31, 2015 and 2014 
+Consolidated Statements of Operations for each of the three years in the period ended December 31, 2015 
+Consolidated Statements of Stockholders’ Equity (Deficit) for each of the three years in the Period Ended December 31, 2015 
+Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2015 
+Notes to Consolidated Financial Statements 
+Schedules other than those listed above are omitted because they are not required, not applicable or the required information is included in the financial statements or notes thereto. 
+2. 
+* 
+Plan of acquisition, reorganization, arrangement, liquidation or succession 
+3. 
+Articles of Incorporation and Bylaws 
+3.1 
+Certificate of Incorporation of the Company, as amended through May 20, 2015 (incorporated by reference to Exhibit 3.1 of the Company’s Form 10-Q, filed on November 5, 2015) 
+3.2 
+Certificate of Designation of Rights and Preferences of 10% Series A Cumulative Preferred Stock (incorporated by reference to Exhibit 3.5 of the Company’s Form 8-A, filed on May 23, 2013) 
+3.3 
+Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Registration Statement on Form S-4, filed on August 4, 1994, Reg. No. 33-82408) 
+4. 
+Instruments defining the rights of security holders, including indentures 
+4.1 
+Specimen Common Stock Certificate (incorporated by reference from Exhibit 4.1 of the Company’s Registration Statement on Form S-4, filed on August 4, 1994, Reg. No. 33-82408) 
+4.2 
+Certificate for the Company’s 10% Cumulative Preferred Stock (incorporated by reference to Exhibit 4.1 of the Company’s Form 8-A, filed on May 23, 2013) 
+9. 
+Voting trust agreement 
+None 
+10. 
+Material contracts 
+10.1 
+Callon Petroleum Company 2002 Stock Incentive Plan (incorporated by reference to Exhibit 10.13 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2001, filed on April 1, 2002) 
+10.2 
+Amendment No. 1 to the Callon Petroleum Company 2002 Stock Incentive Plan (incorporated by reference from Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed on January 5, 2009) 
+10.3 
+Callon Petroleum Company 2010 Phantom Share Plan, adopted May 4, 2010 (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed on May 7, 2010) 
+10.4 
+Form of Callon Petroleum Company Phantom Share Award Agreement, adopted May 4, 2010 (incorporated by reference to Exhibit 10.2 of the Company’s current Report on Form 8-K, filed on May 7 , 2010) 
+10.5 
+Deferred Compensation Plan for Outside Directors; Callon Petroleum Company (effective as of January 1, 2011) (incorporated by reference to Exhibit 10.17 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2010, filed on March 15, 2011) 
+10.6 
+Amended and Restated Severance Compensation Agreement, dated as of March 15, 2011 and effective as of January 1, 2011, by and between Fred L. Callon and Callon Petroleum Company (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed on March 18, 2011) 
+10.7 
+Form of Amended and Restated Severance Compensation Agreement, dated as of March 15, 2011 and effective as of January 1, 2011, by and between Callon Petroleum Company and its executive officers (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed on March 18, 2011) 
+10.8 
+Callon Petroleum Company 2011 Omnibus Incentive Plan (incorporated by reference from Exhibit A of the Company’s Definitive Proxy Statement on Schedule 14A, filed on March 21, 2011) 
+10.9 
+Agreement, dated March 9, 2014, among the Company and Lone Star Value Investors, L.P., Lone Star Value Co-Invest I, L.P., Lone Star Value Investors GP, LLC, Lone Star Value Management, LLC, Jeffery E. Eberwein and Matthew R. Bob (incorporated by reference from Exhibit 10.1 of the Company's report on Form 8-K, filed on March 10, 2014) 
+10.10 
+Fifth Amended and Restated Credit Agreement among Callon Petroleum Company, JPMorgan Chase Bank, National Association, as administrative agent and the Lenders and parties named therein dated March 11, 2014 (incorporated by reference to Exhibit 10.1 of the Company's Report on Form 10-Q/A, filed on June 11, 2014) 
+97 
+Table of Contents 
+10.11 
+Amendment No. 2 to Fifth Amended and Restated Credit Agreement among Callon Petroleum Company, JPMorgan Chase Bank, National Association, as administrative agent and the Lenders and parties named therein dated October 8, 2014 (incorporated by reference to Exhibit 10.4 of the Company's Report on Form 8-K, filed on October 14, 2014) 
+10.12 
+Second Lien Credit Agreement among Callon Petroleum Company, Royal Bank of Canada and the Lenders party thereto, dated October 8, 2014 (incorporated by reference to Exhibit 10.5 of the Company's Report on Form 8-K, filed on October 14, 2014) 
+10.13 
+Second Lien Intercreditor Agreement among Callon Petroleum Company, JPMorgan Chase Bank, National Association, Royal Bank of Canada, and the other parties named therein dated October 8, 2014 (incorporated by reference to Exhibit 10.6 of the Company's Report on Form 8-K, filed on October 14, 2014) 
+10.14 
+Severance Compensation Agreement, dated as of February 13, 2015, by and between Bob Weatherly and Callon Petroleum Company (incorporated by reference to Exhibit 10.1 of the Company's Report on Form 10-Q, filed on May 7, 2015) 
+10.15 
+Agreement, dated March 21, 2015, among the Company and Lone Star Value Investors, L.P., Lone Star Value Co-Invest I, L.P., Lone Star Value Investors GP, LLC, Lone Star Value Management, LLC, Jeffery E. Eberwein and Michael L. Finch (incorporated by reference from Exhibit 10.1 of the Company's report on Form 8-K, filed on March 25, 2015) 
+10.16 
+(a) 
+Form of Callon Petroleum Company Restricted Stock Unit Award Agreement, adopted on March 12, 2015 
+10.17 
+(a) 
+Form of Callon Petroleum Company Phantom Share Award Agreement, adopted on March 12, 2015 
+10.18 
+(a) 
+Form of Callon Petroleum Company Phantom Share Award Agreement, adopted on March 12, 2015 
+10.19 
+(a) 
+Form of Callon Petroleum Company Phantom Share Award Agreement, adopted on March 12, 2015 
+10.20 
+First Amendment to the Callon Petroleum Company 2011 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.1 of the Company's Report on Form 10-Q, filed on November 5, 2015) 
+10.21 
+Underwriting Agreement dated as of November 9, 2015 between Callon Petroleum Company, J.P. Morgan Securities LLC and Credit Suisse Securities (USA) LLC (incorporated by reference from Exhibit 1.1 of the Company's Report on Form 8-K, filed on November 10, 2015) 
+10.22 
+Agreement, dated February 25, 2016, among the Company and Lone Star Value Investors, L.P., Lone Star Value Co-Invest I, L.P., Lone Star Value Investors GP, LLC, Lone Star Value Management, LLC, and Jeffery E. Eberwein (incorporated by reference from Exhibit 10.1 of the Company's report on Form 8-K, filed on February 29, 2016) 
+11. 
+* 
+Statement re computation of per share earnings 
+12. 
+* 
+Statements re computation of ratios 
+13. 
+* 
+Annual Report to security holders, Form 10-Q or quarterly reports 
+14. 
+Code of Ethics 
+14.1 
+Code of Ethics for Chief Executive Officers and Senior Financial Officers (incorporated by reference to Exhibit 14.1 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, filed on March 15, 2004) 
+16. 
+Letter re change in certifying accountant 
+16.1 
+Letter from E&Y dated January 15, 2016 (incorporated by reference to Exhibit 16.1 of the Company's Report on Form 8-K, filed on January 15, 2016) 
+18. 
+* 
+Letter re change in accounting principles 
+21. 
+Subsidiaries of the Company 
+21.1 
+(a) 
+Subsidiaries of the Company 
+22. 
+* 
+Published report regarding matters submitted to vote of security holders 
+23. 
+Consents of experts and counsel 
+23.1 
+(a) 
+Consent of Ernst & Young LLP 
+23.2 
+(a) 
+Consent of DeGolyer and MacNaughton, Inc. 
+23.3 
+(a) 
+Consent of Huddleston & Co., Inc. 
+24. 
+* 
+Power of attorney 
+31. 
+Rule 13a-14(a) Certifications 
+31.1 
+(a) 
+Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a) 
+31.2 
+(a) 
+Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a) 
+32. 
+(b) 
+Section 1350 Certifications of Chief Executive and Financial Officers pursuant to Rule 13(a)-14(b) 
+99. 
+Additional Exhibits 
+99.1 
+(a) 
+Reserve Report Summary prepared by DeGolyer and MacNaughton, Inc. as of December 31, 2015 
+101. 
+(c) 
+Interactive Data Files 
+* 
+Not applicable to this filing 
+(a) 
+Filed herewith. 
+98 
+Table of Contents 
+(b) 
+Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, except to the extent that the registrant specifically incorporates it by reference. 
+(c) 
+Pursuant to Rule 406T of Regulation S-T, these interactive data files are being furnished herewith and are not deemed filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, or Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability. 
+99 
+Table of Contents 
+SIGN ATURES 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+Callon Petroleum Company 
+Date: 
+March 2 , 201 6 
+/s/ Joseph C. Gatto, Jr. 
+By: Joseph C. Gatto, Jr., senior vice president, 
+chief financial officer (principal financial officer) and treasurer 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+Date: 
+March 2, 2016 
+/s/ Fred L. Callon 
+Fred L. Callon (principal executive officer, director) 
+Date: 
+March 2, 2016 
+/s/ Joseph C. Gatto, Jr. 
+Joseph C. Gatto, Jr. (principal financial officer) 
+Date: 
+March 2, 2016 
+/s/ Mitzi P. Conn 
+Mitzi P. Conn (principal accounting officer) 
+Date: 
+March 2, 2016 
+/s/ L. Richard Flury 
+L. Richard Flury (director) 
+Date: 
+March 2, 2016 
+/s/ John C. Wallace 
+John C. Wallace (director) 
+Date: 
+March 2, 2016 
+/s/ Anthony J. Nocchiero 
+Anthony J. Nocchiero (director) 
+Date: 
+March 2, 2016 
+/s/ Larry D. McVay 
+Larry McVay (director) 
+Date: 
+March 2, 2016 
+/s/ Matthew R. Bob 
+Matthew R. Bob (director) 
+Date: 
+March 2, 2016 
+/s/ James M. Trimble 
+James M. Trimble (director) 
+Date: 
+March 2, 2016 
+/s/ Michael Finch 
+Mic ha el Finch (director) 
+100
\ No newline at end of file
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new file mode 100644
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+0000928022,CPE,Callon Petroleum Co,10-K,2016-03-03,2015-12-31,2016-03-02T23:43:45.000Z,0000928022-16-000132,cpe-20151231x10k.htm,10-K,15553543,1,0,https://www.sec.gov/Archives/edgar/data/928022/000092802216000132/cpe-20151231x10k.htm,https://www.sec.gov/Archives/edgar/data/928022/000092802216000132/,2015,2015,1
diff --git a/raw/filings/0000928022/2015/0000928022-16-000132/item1.txt b/raw/filings/0000928022/2015/0000928022-16-000132/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000928022/2015/0000928022-16-000132/item13.txt b/raw/filings/0000928022/2015/0000928022-16-000132/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..144e8bdded01da5936c1766546b73a8fc8e43c1a
--- /dev/null
+++ b/raw/filings/0000928022/2015/0000928022-16-000132/item13.txt
@@ -0,0 +1,2 @@
+ITEM 13. C ertain Relationships and Related Transactions and Director Independence 
+For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 12, 2016 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2015/0000928022-16-000132/item9a.txt b/raw/filings/0000928022/2015/0000928022-16-000132/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..46322d8acda29e4ababd2e8863312324a2ecd7fa
--- /dev/null
+++ b/raw/filings/0000928022/2015/0000928022-16-000132/item9a.txt
@@ -0,0 +1,10 @@
+Item 9A. Co ntrols and Procedures 
+Disclosure controls and procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our Chief Executive Officer and Chief Financial Officer performed an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2015 . 
+Management’s report on internal control over financial reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. generally accepted accounting principles. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2015 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission ( 2013 framework)(the COSO criteria). Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2015 . 
+Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+The Company’s independent registered public accounting firm has issued an attestation report regarding its assessment of the Company’s internal control over financial reporting as of December 31, 2015 , which follows Part II, Item 9B of this filing. Additionally, the financial statements for each of the years covered in this Annual Report on Form 10-K have been audited by an independent registered public accounting firm, Ernst & Young LLP whose report is presented immediately preceding the Company’s financial statements included in Part II, Item 8 of this Annual Report on Form 10-K. 
+93 
+Table of Contents 
+Changes in internal control over financial reporting . There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting. 
+ITEM 9A (T). Controls and Procedures 
+See Item 9A.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2015/0000928022-16-000132/rp_note.txt b/raw/filings/0000928022/2015/0000928022-16-000132/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000928022/2015/0000928022-16-000132/rpt_disclosure.txt b/raw/filings/0000928022/2015/0000928022-16-000132/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..ac2a47d652c5f0d3c5750bc35f4c31257c1b9c10
--- /dev/null
+++ b/raw/filings/0000928022/2015/0000928022-16-000132/rpt_disclosure.txt
@@ -0,0 +1,13 @@
+Certain Relationships and Related Party Transactions 
+The Board’s Audit Committee charter provides that the Audit Committee shall review and approve all related party transactions. A transaction will be considered a “related party transaction” if the transaction would be required to be disclosed under Item 404 of Regulation S-K. In addition, our Code of Business Conduct and Ethics provides that an officer’s or a Director’s conflict of interest with Callon may only be waived if the Nominating and Corporate Governance Committee approves the waiver and the full Board ratifies the waiver. As of December 31, 2015, we are not aware of any related party transactions with our executive officers that may cause a conflict of interest with us. 
+Recoupment Policy 
+We have no recoupment policy applicable to annual incentive bonuses or equity awards other than those required under Sarbanes-Oxley legislation, though the Committee continuously evaluates the need to adopt such a policy. 
+Compensation Committee Report 
+The Compensation Committee has reviewed and discussed with management the CD&A required by Item 402(b) of Regulation S-K promulgated under the Securities Exchange Act of 1934, as amended, and based on such review and discussions, the Committee has recommended to the Board that the CD&A be included in this proxy statement relating to the 2016 Annual Meeting of Stockholders. 
+Respectfully submitted by the Compensation Committee of the Board, 
+L. Richard Flury, Chairman 
+Larry D. McVay 
+Anthony J. Nocchiero 
+John C. Wallace 
+James M. Trimble 
+44
\ No newline at end of file
diff --git a/raw/filings/0000928022/2016/0000928022-17-000023/filing.txt b/raw/filings/0000928022/2016/0000928022-17-000023/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..6ab9261f88a60420dd889d596dcfd997c4c7e88f
--- /dev/null
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@@ -0,0 +1,6463 @@
+10-K
+1
+cpe-20161231x10k.htm
+10-K
+2016_CPE_Form_10-K
+UNITED STATES SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+ 
+ 
+ 
+FORM 10-K 
+ 
+ 
+ 
+☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For The Fiscal Year Ended December 31, 2016 
+OR 
+☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934 
+For the transition period from ____________ to ____________ 
+Commission File Number 001-14039 
+ 
+ 
+ 
+ 
+Callon Petroleum Company 
+(Exact Name of Registrant as Specified in Its Charter) 
+ 
+ 
+ 
+ 
+ 
+Delaware 
+(State or Other Jurisdiction of 
+Incorporation or Organization) 
+64-0844345 
+(IRS Employer 
+Identification No.) 
+200 North Canal Street 
+Natchez, Mississippi 
+(Address of Principal Executive Offices) 
+39120 
+(Zip Code) 
+601-442-1601 
+(Registrant’s Telephone Number, Including Area Code) 
+ 
+ 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of Each Class 
+Name of Each Exchange on Which Registered 
+Common Stock, $.01 par value 
+New York Stock Exchange 
+10.0% Series A Cumulative Preferred Stock 
+New York Stock Exchange 
+ 
+Securities registered pursuant to section 12 (g) of the Act: None 
+ 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒ 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒ 
+Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ 
+Indicate by check mark whether the registrant has submitted electronically and posted on its corporate w ebsite, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐ 
+Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant ’ s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒ 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition s of “large acceler ated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (check one): 
+ 
+ 
+Large accelerated filer 
+☒ 
+Accelerated filer 
+☐ 
+ 
+Non-accelerated filer 
+☐ 
+(Do not check if smaller reporting company) 
+Smaller reporting company 
+☐ 
+ 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ 
+The a ggregate m arket value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2016 was approximately $1,452,262,144 . The Registrant had 201,054,884 sh ares of common stock outstanding as of February 22, 2017 . 
+DOCUMENTS INCORPORATED BY REFERENCE 
+Portions of the definitive Proxy Statement of Callon Petroleum Company (to be filed no later than 120 days after December 31, 2016 ) relating to the Annual Meeting of Stockholders to be held on May 11, 2017 , which are incorporated into Part III of this Form 10-K. 
+ 
+TAB LE OF CONTENTS 
+ 
+ 
+ Special Note Regarding Forward-Looking Statements 
+3 
+ Definitions 
+4 
+ Part I 
+5 
+ Items 1 and 2. 
+Business and Properties 
+5 
+ 
+Oil and Natural Gas Properties 
+7 
+ 
+Reserves and Production 
+7 
+ 
+Capital Budget 
+9 
+ 
+Exploration and Development Activity 
+10 
+ 
+Production Wells 
+10 
+ 
+Production Volumes, Average Sales Prices and Operating Costs 
+11 
+ 
+Leasehold Acreage 
+12 
+ 
+Other 
+12 
+ 
+Regulations 
+14 
+ 
+Commitments and Contingencies 
+21 
+ 
+Available Information 
+21 
+ Item 1A. 
+Risk Factors 
+22 
+ Item 1B. 
+Unresolved Staff Comments 
+34 
+ Item 3. 
+Legal Proceedings 
+34 
+ Item 4. 
+Mine Safety Disclosures 
+34 
+ Part II 
+ Item 5. 
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+35 
+ 
+Performance Graph 
+36 
+ Item 6. 
+Selected Financial Data 
+37 
+ Item 7. 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+38 
+ 
+Overview and Outlook 
+39 
+ 
+Liquidity and Capital Resources 
+40 
+ 
+Results of Operations 
+44 
+ 
+Significant Accounting Policies and Critical Accounting Estimates 
+51 
+ Item 7A. 
+Quantitative and Qualitative Disclosures About Market Risk 
+54 
+ Item 8. 
+Financial Statements and Supplementary Data 
+56 
+ 
+Report of Independent Registered Public Accounting Firm 
+57 
+ 
+Consolidated Balance Sheets 
+59 
+ 
+Consolidated Statements of Operations 
+60 
+ 
+Consolidated Statements of Stockholders’ Equity 
+61 
+ 
+Consolidated Statements of Cash Flows 
+62 
+ 
+Notes to Consolidated Financial Statements 
+63 
+ Item 9. 
+Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+87 
+ Item 9A. 
+Controls and Procedures 
+87 
+ Item 9B. 
+Other Information 
+88 
+ 
+Report of Independent Registered Public Accounting Firm 
+89 
+ Part III 
+ Item 10. 
+Directors and Executive Officers and Corporate Governance 
+90 
+ Item 11. 
+Executive Compensation 
+90 
+ Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+90 
+ Item 13. 
+Certain Relationships and Related Transactions and Director Independence 
+90 
+ Item 14. 
+Principal Accountant Fees and Services 
+90 
+ Part IV 
+ Item 15. 
+Exhibits 
+91 
+ Signatures 
+93 
+ 
+2 
+Table of Contents 
+ 
+Special N ote Regarding Forward Looking Statements 
+ 
+This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”), as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements in this Form 10-K by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions. 
+ 
+All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future are forward-looking statements, including such things as: 
+· 
+our oil and gas reserve quantities, and the discounted present value of these reserves; 
+· 
+the amount and nature of our capital expenditures; 
+· 
+our future drilling and development plans and our potential drilling locations; 
+· 
+the timing and amount of future production and operating costs; 
+· 
+commodity price risk management activities and the impact on our average realized prices; 
+· 
+business strategies and plans of management; 
+· 
+our ability to efficiently integrate recently completed acquisitions; and 
+· 
+prospect development and property acquisitions. 
+ 
+Some of the risks, which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements, include: 
+· 
+general economic conditions including the availability of credit and access to existing lines of credit; 
+· 
+the volatility of oil and natural gas prices; 
+· 
+the uncertainty of estimates of oil and natural gas reserves; 
+· 
+impairments; 
+· 
+the impact of competition; 
+· 
+the availability and cost of seismic, drilling and other equipment; 
+· 
+operating hazards inherent in the exploration for and production of oil and natural gas; 
+· 
+difficulties encountered during the exploration for and production of oil and natural gas; 
+· 
+difficulties encountered in delivering oil and natural gas to commercial markets; 
+· 
+changes in customer demand and producers’ supply; 
+· 
+the uncertainty of our ability to attract capital and obtain financing on favorable terms; 
+· 
+compliance with, or the effect of changes in, the extensive governmental regulations regarding the oil and natural gas business including those related to climate change and greenhouse gases; 
+· 
+the impact of government regulation, including regulation of endangered species; 
+· 
+any increase in severance or similar taxes; 
+· 
+litigation relating to hydraulic fracturing, the climate and over-the-counter derivatives; 
+· 
+the financial impact of accounting regulations and critical accounting policies; 
+· 
+the comparative cost of alternative fuels; 
+· 
+credit risk relating to the risk of loss as a result of non-performance by our counterparties; 
+· 
+weather conditions; and 
+· 
+any other factors listed in the reports we have filed and may file with the SEC. 
+ 
+We caution you that the forward-looking statements contained in this Form 10- K are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. These risks include, but are not limited to, the risks described in Item 1A of this Annual Report on Form 10-K for the year ended December 31, 2016 (the “ 2016 Annual Report on Form 10-K”), and all quarterly reports on Form 10-Q filed subsequently thereto. 
+ 
+Should one or more of the risks or uncertainties described above or in our 2016 Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. 
+ 
+All forward-looking statements attributable to us are expressl y qualified in their entirety by this cautionary statement. 
+3 
+Table of Contents 
+DEFIN ITIONS 
+ 
+All defined terms under Rule 4-10(a) of Regulation S-X shall have their prescribed meanings when used in this report. As used in this document: 
+ 
+· 
+ARO : asset retirement obligation. 
+· 
+ASU : accounting standards update. 
+· 
+Bbl or Bbls : barrel or barrels of oil or natural gas liquids. 
+· 
+BOE : barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas. The ratio of one barrel of oil or NGL to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas. 
+· 
+BBtu : billion Btu. 
+· 
+BOE/d : BOE per day. 
+· 
+BLM: Bureau of Land Management. 
+· 
+Btu : a Britis h thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahre nheit. 
+· 
+DOI: Department of Interior. 
+· 
+EPA: Environmental Protection Agency. 
+· 
+FASB: Financial Accounting Standards Board . 
+· 
+GAAP : Generall y Accepted Accounting Principles in the United States. 
+· 
+Henry Hub : A natural gas pipeline delivery point that serves as the benchmark natural gas price underlying NYMEX natural gas futures contr acts. 
+· 
+GHG: greenhouse gases. 
+· 
+LIBOR : London Interbank Offered Rate. 
+· 
+LOE : lease operating expense. 
+· 
+MBbls : thousand barrels of oil. 
+· 
+MBOE : thousand BOE . 
+· 
+MMB OE : million BOE. 
+· 
+MBOE/d : M BOE per day. 
+· 
+Mcf : thousand cubic feet of natural gas. 
+· 
+MMBbls : million barrels of oil. 
+· 
+MMBOE : million BOE. 
+· 
+MMBtu : million Btu. 
+· 
+MMcf : million cubic feet of natural gas. 
+· 
+MMcf/d : MMcf per day. 
+· 
+NGL or NGLs : natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams. 
+· 
+NYMEX : New York Mercantile Exchange. 
+· 
+Oil : includes crude oil and condensate. 
+· 
+OPEC: Organization of Petroleum Exporting Countries 
+· 
+PDPs : proved developed producing reserves. 
+· 
+PDNPs : proved developed non-producing reserves. 
+· 
+PUDs : proved undeveloped reserves. 
+· 
+RSU : restricted stock units. 
+· 
+SEC : United Stat es Securities and Exchange Commission. 
+· 
+WTI : West Texas Intermediate grade crude oil, used as a pricing benchmark for sales contracts and NYMEX oil futures contracts. 
+ 
+With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross. 
+4 
+Table of Contents 
+PA RT I. 
+Ite ms 1 and 2 – Business and Properties 
+Overview 
+ 
+Callon Petroleum Company has been engaged in the exploration, development, acquisition and production of oil and natural gas properties since 1950. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. 
+ 
+We are an independent oil and natural gas company focused on the acquisition and development of unconventional oil and natural gas reserves in the Permian Basin. The Permian Basin is located in West Texas and southeastern New Mexico and is comprised of three primary sub-basins: the Midland Basin, the Delaware Basin, and the Central Basin Platform. We have historically been focused on the Midland Basin and recently entered the Delaware Basin through an acquisition completed in February 2017. Our drilling activity during 201 6 focused on the horizontal development of several prospective intervals in the Midland Basin , including multiple levels of the Wolfcamp formation and the Lower Spraberry shale. As a result of our horizontal development efforts and contributions from acquisitions , our net daily production for calendar year 201 6 as compared to calendar year 201 5 grew approximately 59% to 15,227 BOE/d (approximately 77% oil) . We intend to grow our reserves and production through the development, exploitation and drilling of our multi-year inventory of identified, potential drilling locations. We intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and acquisition of additional locations through leasehold purchases, leasing programs, joint ventures and asset swaps. 
+ 
+For the year ended December 31, 2016 , our net proved reserve volumes i ncreased 69% as compared to the year end ed December 31, 2015 , t o 91.6 MMBOE, comprised of 78% crud e oil including 71.1 MMBbls with the remaining 22% natural gas o f 122.6 Bcf. A pproximately 47% of our net proved year-end 201 6 reserves were proved developed on a BOE basis. 
+ 
+Our Business Strategy 
+ 
+Our goal is to enhance stockholder value through the execution of the following strateg ies with an emphasis on safety : 
+ 
+Maintain fiscal discipline, financial liquidity and our capacity to capitalize on growth opportunities. During the past several quarters of relative oil price weakness, we moderated our level of drilling activity and high-graded our investments to the highest returning projects to preserve our financial flexibility w hile also maintaining operational momentum. In 2016, we reduced our operational capital expenditu res by 8% from 2 015 to better align internal cash flows with spending, but were still able to deliver organic production and reserve growth given the attractive drilling opportunities within our portfolio. Our ability to pivot our operations and maintain a solid financial position allowed us to selectively purs u e attractive acquisition opportunities during the course of 2016, ultimately putting us in the position to grow our net surface acreage position by a pproximately 122% . Imp ortantly, we funded these inorganic growth initiatives with the issuance of common stock, allowing us to reduce leverage throughout the year and positioning us in a strong financial position for future growth in our organic drilling plans. 
+ 
+Drive production and maximize resource recovery and reserve growth through horizontal development of our resource base. We entered the Midland Basin in 2009 focused on a vertical development program that allowed us to amass a comprehensive database of subsurface geologic and other technical data. Beginning in 2012, we leveraged that subsurface knowledge base to transition to horizontal development of hydrocarbon bearing zones that were previously being exploited with vertical wel ls. Since that time, we have applied t he continued success of our horizontal development a s evidenced in our significant year-over-year pr oduction growth, which increased 59% in 2016 to 5,573 MB OE ( 15,227 B OE /d) compared to 3,508 M B OE ( 9,610 B OE /d) in 2015 . Additionally, we grew reserves 69% in 2016 t o 91.6 MMB OE from 54.3 MMB OE at year-end 2015 , including reserve extensions and discoveries replacement in 2016 of 17.3 MM BOE . We intend to continue to grow our production volumes, both from our existing properties and from properties acquired in recent acquisitions, as we execute a resource development program exclusively focused on horizontal development of currently producing and prospective flow intervals in the Midland and Delaware Basins. 
+ 
+Expand our drilling portfolio through evaluation of existing acreage. We plan to further our efforts to expand our drilling inventory through downspacing tests in existing flow units and selective delineation of new flow units. During 2016, we successfully tested a second flow unit in the Lower Spraberry shale in the Midland Basin, bringing our producing flow unit count in the that sub-basin to six, including the Upper and Lower sections of the Lower Spraberry, Middle Spraberry, Upper and Lower Wolfcamp A and the Upper and Lower Wolfcamp B zones. In the Midland Basin, we believe incremental opportunities exist to develop existing flow units with tighter well spacing, and add new flow units within both currently producing zones that have adequate thickness and new flow units in other prospective zones including the Clearfork, Jo Mill, Wolfcamp C and Cline (also called the Wolfcamp D). As part of our entry into the Delaware Basin, we will be initially focused on development of established zones such as the Wolfcamp A and Wolfcamp B, but plan to test other prospective intervals within both the Bone Spring and Wolfcamp formations in the future. 
+ 
+Pursue selective acquisitions in the Permian Basin. During 2016, we significantly expanded our Permian Basin footprint after entering into agreements to acquire ov er 41,000 n et surface acres in both the Midland and Delaware sub-basins. On a combined basis, the 
+5 
+Table of Contents 
+acquisitions added approximately 950 gross potential horizontal drilling locations across currently producing flow units in the Lower Spraberry, Wolfcamp A and Wolfcamp B zones. These acquisitions have provided the foundation for two new core operating areas that will be a significant component of our near-term drilling plans. In addition to selective evaluation of larger acquisition opportunities in the Permian Basin, we will be fo cused on incremental “bolt-on” acquisitions, acreage trades and leasing programs in these two new areas. 
+ 
+Our Strengths 
+ 
+Established resource base and acreage position in the core of the Permian Basin . Our production is exclusively from the Permian Basin in West Texas, an area that has supported production since the 1940s. The B asin has well established infrastructure from historical operations, and we believe the Basin also benefits from a relatively stable regulatory environment that has been established over time. We have assembled a position of over 56,000 net surface acres in the Permian Basin that are prospective for multiple oil-bearing intervals that have been produced by us and other industry participants. As of December 31, 2016 , our estimated net proved reserves were comprised of approximately 78% oil and 22% natural gas, which include s NGLs in the production stream. 
+ 
+Economic, multi-year drilling inventory in a lower commodity price environment . Our current acreage position in the Permian Basin provides growth potential from a horizontal drilling inventory of approximately 1,550 gross locations based solely on seven currently producin g flow intervals, including the Upper and Lower sections of the Lower Spraberry, Middle Spraberry, Upper and Lower Wolfcamp A, and the Upper and Lower Wolfcamp B. Our identified well locations across our Midland and Delaware Basin acreage positions are based upon the results of horizontal wells drilled by us and other offsetting operators and by our analysis of core data and historical vertical well performance. To the extent that long-term production data and microseismic data support the potential for capital efficient resource recovery from reduced spacing between lateral wellbores and stacked development within thicker zones, the number of drilling locations within currently producing zones may increase over time, complementing potential growth from additional prospective zones without current production. 
+ 
+Experienced team operating in the Permian Basin. We have assembled a management team experienced in acquisitions, exploration, development and production in the Permian Basin. Reflective of this experience, we were an early adopter of efficient multi-well pad development, transitioning to this development model in 2012 which enabled us to realize improvements in our drilling and capital. Since 2012, we have drilled more than 1 09 operated horizontal wells with lengths varying from approximately 5,000 feet to 1 0 , 4 00 feet, continuing to employ new generation completion techniques in an effort to improve capital efficiency. In addition, we regularly evaluate our operating results against those of other operators in the area in an effort to benchmark our performance against the top- performing operators and evaluate and adopt best practices. We believe that the experience of our team is highlighted by our success in achieving significantly lower well capital costs and reducing our operating cost structure to generate the operating margins and capital efficiency to operate effectively in the current environment. 
+ 
+Significant amount of operational control . We operate nearly all of our Permian Basin acreage that is largely held by production, providing us an advantage that enables us to modify our operational plans quickly and drill in areas that offer highest potential returns on capital. For example, as commodity prices continued to decline throughout 2015 and into 2016, we shifted our development plan exclusively to the Monarch operating area to focus on the Lower Spraberry which has demonstrated strong returns on capital over time. Our operating team reacted quickly to pivot our operations and worked with our service partners to coordinate a smooth and efficient transition to the new plan. 
+ 
+Operating culture focused on safety and the environment. We have a Health, Safety and Environmental (“HSE”) department dedicated to our operations in the Permian Basin. This group is responsible for developing and implementing work processes to mitigate safety and environmental risks associated with our work activities. With emphasis on leadership engagement, planning, training and communication, and empowering both our employees and third party service providers with Stop Work Authority, we continue to improve operational performance. We have enhanced Management of Change, routine facility maintenance and inspections, and compliance action tracking methods with the implementation of a HSE management system software program. We also utilize the program to distribute all incident reports, including near miss events and safety observations to track trends, learn from our mistakes and implement corrective actions to drive improvement across our operations. This department also coordinates closely with our operational team to ensure effective communication with appropriate regulatory bodies as well as landowners. We believe that our proactive efforts in this area have made a positive impact on our operations and culture . 
+ 
+ 
+6 
+Table of Contents 
+Oil and Natural Gas Properties 
+ 
+Permian Basin 
+ 
+As of December 31, 2016 , we owned leaseholds in 39,570 ne t acres in the Permian Basin , all of which was located in the Midland Basin on that date . Average net production from our Permian Basin properti es increased 59% to 15,227 BOE/d in 2016 from 9,610 BOE/d in 2015 . The following table sets forth certain information about our major operating areas in the Permian Basin as of December 31, 2016 : 
+ 
+ 
+ 
+Producing Wells 
+Producing 
+ 
+Horizontal 
+Vertical 
+Horizontal Flow 
+Operating Area 
+Net Acres 
+Gross 
+Net 
+Gross 
+Net 
+Unit Zones 
+Monarch 
+7,840 
+56 
+42.4 
+179 
+134.4 
+Middle Spraberry 
+Lower Spraberry 
+Wolfcamp A 
+Wolfcamp B 
+Ranger 
+8,428 
+52 
+40.7 
+13 
+9.2 
+Lower Spraberry 
+Wolfcamp A 
+Upper Wolfcamp B 
+Lower Wolfcamp B 
+Wildhorse 
+20,773 
+22 
+13.9 
+80 
+67.8 
+Lower Spraberry 
+Wolfcamp A 
+Wolfcamp B 
+Other Permian 
+2,529 
+18 
+15.5 
+8 
+8.0 
+Wolfcamp A 
+Upper Wolfcamp B 
+Lower Wolfcamp B 
+Total Permian Basin 
+39,570 
+148 
+112.5 
+280 
+219.4 
+ 
+On February 13, 2017 , the Company completed the acquisition of 27,552 gross ( 16,688 net) acres in the Delaware Basin, primarily located in Ward and Pecos Counties, Texas, from American Resource Development, LLC, for total cash consideration of $633 million, excluding customary purchase price adjustments (the “Ameredev Transaction”). The Company acquired an 82% average working interest ( 75% a ver age net revenue interest) in the properties acquired in the Ameredev Transactio n. The Ameredev Transaction represents our initial entry into the Delaware sub-basin. See Note 3 in the Footnotes to the Financial Statements for additional information related to the Ameredev Transaction. 
+ 
+Other Property 
+ 
+We own additional immaterial properties in Louisi ana . 
+ 
+Reserve Data 
+ 
+Proved Reserves 
+ 
+Estimates of volumes of proved reserves at year-end, net to our working interest, are presented in MBbls for oil and in MMcf for natural gas, including NGLs, at a pressure ba se of 14.65 pounds per square inch. Total equivalent volumes are presented in BOE. For the BOE computation, 6,000 cubic feet of gas are the equivalent of one barrel of oil. The ratio of six Mcf of gas to one BOE is typically used in the oil and gas business and represents the approximate energy equivalent of a barrel of oil and a Mcf of natural gas. The price of a barrel of oil is much higher than the price of six Mcf of natural gas, so the ratio of six Mcf to one BOE does not reflect the economic equivalent of a barrel of oil to six Mcf of gas. 
+ 
+As of December 31, 2016 , our estimated net proved reserves totaled 91.6 MMBOE and included 71.1 MMBbls of oil and 122.6 Bcf, of natural gas with a pre-tax present value, discounted at 10%, of $809.8 mi llion. Pre-tax present value is a non-GAAP financial measure, which we reconcile to the GAAP measure of standardized measure of $809.8 mi llion. Oil constituted app roximately 78% of our total estimated equivalent net proved reserves and approximately 76% of our total estimated equivalent proved de veloped reserves. 
+ 
+7 
+Table of Contents 
+The following table sets forth certain information about our estimated net proved reserves prepared by our independent petroleum reserve engineers . All of our proved reserves are located in the Permian Basin in the continental United States. 
+ 
+ 
+ 
+For the Year Ended December 31, 
+ 
+2016 
+2015 
+2014 
+Proved developed 
+Oil (MBbls) 
+32,920 
+22,257 
+14,006 
+Natural gas (MMcf) 
+61,871 
+38,157 
+25,171 
+MBOE 
+43,232 
+28,617 
+18,201 
+Proved undeveloped 
+Oil (MBbls) 
+38,225 
+21,091 
+11,727 
+Natural gas (MMcf) 
+60,740 
+27,380 
+17,377 
+MBOE 
+48,348 
+25,654 
+14,623 
+Total proved 
+Oil (MBbls) 
+71,145 
+43,348 
+25,733 
+Natural gas (MMcf) 
+122,611 
+65,537 
+42,548 
+MBOE 
+91,580 
+54,271 
+32,824 
+Financial Information (in thousands) 
+Estimated pre-tax future net cash flows (a) 
+$ 
+1,821,221 
+$ 
+1,160,808 
+$ 
+1,330,628 
+Pre-tax discounted present value (a) (b) 
+$ 
+809,832 
+$ 
+570,906 
+$ 
+629,680 
+Standardized measure of discounted future net cash flows (a) (b) 
+$ 
+809,832 
+$ 
+570,890 
+$ 
+579,542 
+ 
+(a) 
+Includes a redu ction for estimated plugging and abandonment costs that is reflected as a liability on our balance sheet at December 31, 2016 and 2015 , in accordance with accounting standards for asset retirement obligations. 
+(b) 
+The Company uses the financial measure “ p re-tax discounted present value” which is a non-GAAP financial meas ure. The Company believes that p re-tax discounted present value, while not a financial measure in accordance with GAAP, is an important financial measure used by investors and independent oil and natural gas producers for evaluating the relative value of oil and natural gas properties and acquisitions because the tax characteristics of comparable companies can differ materially. The total standardized measure c alculated in accordance with the guidance issued by the FASB for disclosures about oil and natural gas producing activities for our proved reserves as of December 31, 201 6 , was $809.8 mill ion , net of discounted estimated future income taxes relating to such future net revenues. The projected per Mcf natural gas price of $2.71 used in the 2016 reserve estimates ha s been adjusted to reflect the Btu content, transportation charges and other fees specific to the individual properties. The projected per barrel oil price of $40.03 used in the 2016 reserve estimates ha s been adjusted to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality. 
+ 
+See Note 13 of our Consolidated Financial Statements for the additional information regarding the Company’s reserves including its estimates of proved reserves and the Company’s estimates of future net cash flows and discounted future net cash flows from proved reserves. 
+ 
+The Company’s estimated net pr oved reserves increased 69% t o 91.6 MBOE at December 31, 2016 from 54.3 MBOE at December 31, 2015 . Additions during the year were due to (1 ) 17.3 MMBOE related to the Company’s horizontal development of a portion of its properties and (2 ) 31.1 MMBOE related to acquired properties . These increases were partially offset by (1 ) 5.6 MMBOE related to the Company’s production during 2016 , (2 ) 2.2 MMBOE related to divestitures, and (3) 3.3 M M BOE of net revisions primarily due to pricing . 
+ 
+Proved Undeveloped Reserves 
+ 
+Annually, the Company reviews its proved undeveloped reserves (“ PUDs ”) to ensure appropriate plans exist for development of this reserve category . PUD reserves are recorded only if the Company has plans to convert these reserves into proved developed producing reserves (“ PDPs ”) within five years of the date they are first recorded. Our development plans include the allocation of capital to projects included within our 2017 capital budget and, in subsequent years, the allocation of capital within our long-range business plan to convert PUDs to PDPs within this five year period. In general, our 2017 capital budget and our long-range capital plans are primarily governed by our expectations of internally generated cash flow , senior secured revolving credit facility borrowing availability and corporate credit metrics . Reserve calculations at any end-of-year period are representative of our development plans at that time. Changes in commodity pricing, oilfield service costs and availability, and other economic factors may lead to changes in development plans. 
+ 
+The following table summarizes the Company’s recorded PUDs (in MBOE) : 
+ 
+ 
+ 
+For the Year Ended December 31, 
+ 
+2016 
+2015 
+2014 
+Permian Basin 
+48,348 
+25,654 
+14,623 
+8 
+Table of Contents 
+ 
+Our P UDs increased 88% to 48.3 M MBOE at December 31, 2016 from 25.7 M MBOE at December 31, 2015 . A dd itions during the year were due to (1) 17.5 M MBOE related to acquired properties , net of divestitures, and (2) 11.9 MMBOE related to the Company’s horizontal development of a portion of its properties, net of revisions . The se increase s were offset by the reclassification o f 6.8 MMBOE, or 27% , inclu ded in the year-end 2015 PUDs, to PDPs as a result of our horizontal development of properties at a total cost of approximate ly $43.4 mi llion, net. 
+ 
+The Company plans to develop its PUD s as part of a multi-year drilling program. At December 31, 2016 , we had no reserv es that remained undevelo p ed for five or more years, and all PUD drilling locations are currently scheduled to be drilled within five years of their initial recording. 
+ 
+Controls Over Reserve Estimates 
+ 
+Compliance as it relates to reporting the Company’s reserves is the responsibility of our Chief Operating Officer , who has over 35 years of industry experience , including 2 9 years as a manager , and is our principal engineer. In addition to his years of experience, our principal engineer holds a degree in petroleum engineering and is experienced in asset evaluation and management. 
+ 
+Callon’s controls over reserve estimates included retaining DeGolyer and MacNaughton , a Texas registered engineering firm, as our independent p etroleum and geological firm. The Company provided to DeGolyer and MacNaughton information about our oil and gas properties, including production profiles, prices and costs, and DeGolyer and MacNaughton prepared its own estimates of the reserves attributabl e to the Company’s properties. All of the information regarding 2016 , 2015 and 2014 reserves in this annual report is derived from DeGolyer and MacNaughton ’s report. DeGolyer and MacNaughton ’s reserve report letter is included as an Exhibit to this annual report. The principal engineer at DeGolyer and MacNaughton who certified the Comp any’s reserve estimates has over 32 years of experience in the oil and gas industry and is a Texas Licensed Professional Engineer. Further professional qualifications include a degree in petroleum engineering and membership in the International Society of Petroleum E ngineers and the Society of Petroleum Evaluation Engineers . 
+ 
+To further enhance the control environment over the reserve estimation process, our S trategic Planning and Reserve Committee , a committee of the Board of Directors, assist s management and the Board with its oversight of the integrity of the determination of the Company’s oil and natural gas reserves and the work of our independent reserve engineer . The Committee’s charter also specifies that the Committee shall perform, in consultation with the Company’s management and senior reserves and reservoir engineering personnel, the following responsibilities: 
+ 
+· 
+Oversee the appointment, qualification, independence, compensation and retention of the independent petroleum and geological firm (the “Firm”) engaged by the Company (including resolution of material disagreements between management and the Firm regarding reserve determination) for the purpose of preparing or issuing an annual reserve report. The Committee shall review any proposed changes in the appointment of the Firm, determine the reasons for such proposal, and whether there have been any disputes between the Firm and management. 
+· 
+Review the Company’s significant reserves engineering principles and policies and any material changes thereto, and any proposed changes in reserves engineering standards and principles which have, or may have, a material impact on the Company’s reserves disclosure. 
+· 
+Review with management and the Firm the proved reserves of the Company, and, if appropriate, the probable reserves, possible reserves and the total reserves of the Company, including: (i) reviewing significant changes from prior period reports; (ii) reviewing key assumptions used or relied upon by the Firm; (iii) evaluating the quality of the reserve estimates prepared by both the Firm and the Company relative to the Company ’s peers in the industry; and (iv) reviewing any material reserve s adjustments and significant diffe rences between the Company’s a nd Firm’s estimates. 
+· 
+If the Committee deems it necessary, it shall meet in executive session with management and the Firm to discuss the oil and gas reserve determination process and related public disclosures, and any other matters of concern in respect of the evaluation of the reserves. 
+ 
+During our last fiscal year, we f iled no re ports with other federal agencies which contain an estimate of total proved net oil and natural gas re serves . 
+ 
+2017 Ca pital B u dg e t 
+ 
+Our operational capital budget for 2017 has been established in the range of $325 to $350 m illion on an accrual, or GAAP, basis, inclusive of a planned transition from a three -rig program that commenced in January 2017 to a four - rig program by July 2017 that would include horizontal development activity at our recent Delaware Basin acquisition (see Note 3 in the Footnotes to the Financial Statements for information on this acquisition). 
+ 
+As part of our 2017 operated horizontal drilling program , w e expect to place 33 – 36 n et horizontal wells on production with lateral lengths ranging from 5,000’ to 10,000’ . We have also budgeted approximate ly $7.5 to $10 million for non-operated operational activity. 
+ 
+9 
+Table of Contents 
+ 
+In addition to the operational capital expenditures budget , which includes well costs, facilities and infrastructure capital, and surface land purchases, we budgeted an estimated $40 to $45 million for capitalized general and administrative expenses and capitalized interest expense s , both on an accrual, or GAAP, basis. 
+ 
+Our revenues, earnings, liquidity and ability to gro w are substantially dependent on the prices we receive for, and our ability to develop our reserves of oil and natural gas. Despite a continued low price environment, we believe the long-term outlook for our business is favorable due to our resource base, low cost structure, financial strength, risk management, including commodity hedging strategy, and disciplined investment of capital. We monitor current and expected market conditions, including the commodity price environment, and our liquidity needs and may adjust our capital investment plan accordingly. 
+ 
+Exploration and Development Activities 
+ 
+Our 2016 total capital expenditures, including acquisitions, on a cash basis we re $866.4 million, o f which $190 m illion was allocated to operational capital expenditures, including drilling and completion and facilities and infrastructure expenditures. 
+ 
+For the year en ded December 31, 2016, we drilled 29 gross ( 20.9 net) horizontal wells, completed 32 gross (23.7 net) horizontal wells and had six gross (4.2 net) ho r izontal wells awaiting completion. 
+ 
+The following table sets forth the Company’s drilled wells, none of which were natural gas or nonproductive for t he periods reflected: 
+ 
+ 
+ 
+2016 
+2015 
+2014 (a) 
+ 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Oil wells 
+Development (b) 
+9 
+4.9 
+14 
+11.4 
+19 
+15.5 
+Exploratory (c) 
+20 
+16.0 
+22 
+15.7 
+13 
+11.7 
+Total 
+29 
+20.9 
+36 
+27.1 
+32 
+27.2 
+ 
+(a) 
+Does not includ e two g ross (two n et) nonproduc tive ex ploratory wells . 
+(b) 
+A development well is a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. 
+(c) 
+An exploratory well is a well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir. 
+ 
+Produc tive Wells 
+ 
+A s of December 31, 2016 , we h ad 428 gross ( 331.9 net) worki ng interest oil wells, three gross ( 0.1 net) royalty interest oil wells and no natural gas wells. A well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas reserves on a BOE basis. However, most of our wells produce both oil and natural gas. 
+ 
+Presen t Activities 
+ 
+Subsequ ent to December 31, 2016 , and through February 22, 2017 , the Comp any drilled four gross ( 3.4 net) horizontal wells and completed five gross ( 3.4 net) horizontal wells and had five gross ( 4.1 net) horizontal wells aw aiting completion. 
+ 
+ 
+10 
+Table of Contents 
+Production Vo lumes, Average Sales Prices and Operating Cost s 
+ 
+The following table sets forth certain information regarding the production volumes and average sales prices received for, and average production costs associated with, the Company’s sale of oil and natural gas for the periods indicated (dollars in thousands, except per unit d ata) . 
+ 
+ 
+For the Year Ended December 31, 
+ 
+2016 
+2015 
+2014 
+Production 
+Oil (MBbl) 
+4,280 
+2,789 
+1,692 
+Natural gas (MMcf) 
+7,758 
+4,312 
+2,220 
+Total (MBOE) 
+5,573 
+3,508 
+2,062 
+Revenues 
+Oil sales 
+$ 
+177,652 
+$ 
+125,166 
+$ 
+139,374 
+Natural gas sales 
+23,199 
+12,346 
+12,488 
+Total 
+$ 
+200,851 
+$ 
+137,512 
+$ 
+151,862 
+Operating costs 
+Lease operating expense 
+$ 
+38,353 
+$ 
+27,036 
+$ 
+22,372 
+Production taxes 
+11,870 
+9,793 
+8,973 
+Total 
+$ 
+50,223 
+$ 
+36,829 
+$ 
+31,345 
+Average realized sales price 
+Oil (Bbl) (excluding impact of cash settled derivatives) 
+$ 
+41.51 
+$ 
+44.88 
+$ 
+82.37 
+Oil (Bbl) (including impact of cash settled derivatives) 
+45.67 
+56.82 
+84.84 
+Natural gas (Mcf) (excluding impact of cash settled derivatives) 
+2.99 
+2.86 
+5.63 
+Natural gas (Mcf) (including impact of cash settled derivatives) 
+3.00 
+3.26 
+5.59 
+Total (BOE) (excluding impact of cash settled derivatives) 
+36.04 
+39.20 
+73.65 
+Total (BOE) (including impact of cash settled derivatives) 
+39.25 
+49.18 
+75.63 
+Operating costs per BOE 
+Lease operating expense 
+$ 
+6.88 
+$ 
+7.71 
+$ 
+10.85 
+Production taxes 
+2.13 
+2.79 
+4.35 
+Total 
+$ 
+9.01 
+$ 
+10.50 
+$ 
+15.20 
+ 
+Major Customers 
+ 
+Our production is sold generally on month-to-month contracts at prevailing prices. The following table identifies customers to whom we sold a significant percentage of our total oil and natural gas production, on an equivalent basis, during each of the 12-month periods indicated: 
+ 
+ 
+ 
+For the Year Ended December 31, 
+ 
+2016 
+2015 
+2014 
+Enterprise Crude Oil, LLC 
+43% 
+42% 
+51% 
+Shell Trading Company 
+18% 
+4% 
+— 
+Plains Marketing, L.P. 
+16% 
+19% 
+22% 
+Permian Transport and Trading 
+— 
+15% 
+7% 
+Sunoco 
+— 
+9% 
+10% 
+Other 
+23% 
+11% 
+10% 
+Total 
+100% 
+100% 
+100% 
+ 
+Because alternative purchasers of oil and natural gas are readily available, the Company believes that the loss of any of these purchasers would not result in a material adverse effect on Callon’s ability to market future oil and natural gas production. We are not currently committed to provide a fixed and determinable quantity of oil or gas in the near future under our contracts. 
+ 
+ 
+ 
+11 
+Table of Contents 
+Leasehold A creag e 
+ 
+Th e following table shows our approximate developed and undeveloped (gross and net) leasehold acreage as of December 31, 2016 . 
+ 
+ 
+ 
+Developed 
+Undeveloped 
+Total 
+ 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Permian Basin (a) 
+36,960 
+29,765 
+14,255 
+9,805 
+51,215 
+39,570 
+Other 
+936 
+200 
+188 
+55 
+1,124 
+255 
+Total 
+37,896 
+29,965 
+14,443 
+9,860 
+52,339 
+39,825 
+(a) 
+A portion of our Permian Basin acreage , which we have included in our development plans, requires continu ous drilling to hold the acreage , though the cost to renew this acreage, if necessary, is no t considered material. 
+ 
+Undeveloped Acreage Expirations 
+ 
+The following table sets forth a s of December 31, 2016 the number of our leased gross and net undeveloped acres in the Permian Basin that will expire over the next three years unless production begins before lease expiration dates. Gross amounts may be more than net amounts in a particular year due to timing of expirations. 
+ 
+ 
+ 
+Net 
+Gross 
+ 
+2017 
+2018 
+2019 
+Total 
+Total 
+Permian Basin 
+4,807 
+2,778 
+1,799 
+9,384 
+13,456 
+ 
+The expiring acreage set forth in the table above accounts for approxim ately 95% of our net undeveloped acreage ( 9,860 total net acres) and there are no PUD reserves attributable to such acreage. We are continually engaged in a combination of drilling and development and discussions with mineral lessors for lease extensions, renewals, new drilling and development units and new leases to address any potential expiration of undeveloped acreage that occurs in the normal course of our business. 
+ 
+Title to Proper ties 
+ 
+The Company believes that the title to its oil and natural gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of such properties. The Company’s properties are potentially subject to one or more of the following: 
+ 
+· 
+royalties and other burdens and obligations, express or implied, u nder oil and natural gas leases; 
+· 
+overriding royalties and other burdens created by us or our predecessors in title; 
+· 
+a variety of contractual obligations (including, in some cases, development obligations) ari sing under operating agreements; farm-out agreements, production sales contracts and other agreements that may affect the propert ies or their titles; 
+· 
+back-ins and reversionary interests existing under purchase agree ments and leasehold assignments; 
+· 
+liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual l iens under operating agreements; 
+· 
+pooling, unitization and communitization agre ements, declarations and orders; and 
+· 
+easements, restrictions, rights-of-way and other matters that commonly affect property. 
+ 
+To the extent that such burdens and obligations affect the Company’s rights to production revenues, these characteristics have been taken into account in calculating Callon’s net revenue interests and in estimating the size and value of its reserves. The Company believes that the burdens and obligations affecting our properties are typical within the industry for properties of the kind owned by Callon. 
+ 
+Insurance 
+ 
+In accordance with industry practice, the Company maintains insurance against some, but not all, of the operating risks to which its business is exposed. While not all inclusive, the Company’s insurance policies include coverage for general liability insuring onshore operations (including sudden and accidental pollution), aviation liability, auto liability, worker’s compensation, and employer’s liability. The C ompany carries control of well insurance for all of its drilling operations. 
+ 
+Currently, the Company has general liability insurance coverage up to $1 million per occurrence and $2 million per policy in the aggregate, which includes sudden and accidental pollution liability coverage for the effects of pollution on third parties arising from its operations. The Company’s insurance policies contain high policy limits, and in most cases, deductibles (generally ranging from $0 to $250,000) that must be met prior to recovery. These insurance policies are subject to certain customary exclusions and limitations. T he Company maintains up to $100 million in excess liability coverage, which is in addition to and triggered if the underlying liability limits have been reached. In addition, the company purchases pollution legal liability coverage in the amount of $5 million , which is excess and difference in conditions of the liability coverage. 
+12 
+Table of Contents 
+ 
+The Company requires all of its third-party contractors to sign master service agreements in which they agree to indemnify the Company for injuries and deaths of the service provider’s employees, as well as contractors and subcontractors hired by the service provider. Similarly, the Company generally agrees to indemnify each third-party contractor against claims made by employees of the Company and the Company’s other contractors. Additionally, each party generally is responsible for damage to its own property. 
+ 
+The third-party contractors that perform hydraulic fracturing operations for the Company sign master service agreements generally containing the indemnification provisions noted above. The Company does not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations. However, the Company believes its general liability and excess liability insurance policies would cover foreseeable third party claims related to hydraulic fracturing operations and associated legal expenses, in accordance with, and subject to, the terms of such policies. 
+ 
+The Company re-evaluates the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and natural gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. While based on the Company’s risk analysis, it believes that it is properly insured, no assurance can be given that the Company will be able to maintain insurance in the future at rates that it considers reasonable. In such circumstances, the Company may elect to self-insure or maintain only catastrophic coverage for certain risks in the future. 
+ 
+Corporate Offices 
+ 
+The Company’s headquarters are located in Natchez, Mississippi, in a building owned by the Company . We also maintain leased business offices in Houston and Midland, Texas. Because alternative locations to our leased spaces are readily available, the replacement of any of our leased offices would not result in material expenditures . 
+ 
+Employees 
+ 
+Callon had 121 employees as of December 31, 2016 . None of the Company’s employees are currently represented by a union, and the Company believes that it has good relations wi th its employees . 
+ 
+ 
+13 
+Table of Contents 
+Regulations 
+ 
+General. Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. L egislation and regulation affecting the entire oil and natural gas industry is continuously being reviewed for amendment and/ or expansion. Some of these requirements carry substantial penalties for failure to comply. 
+ 
+Exploration and Production . Our operations are subject to federal, state and local regulations that include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds and letters of credit) covering drilling and well operations. Other activities subject to regulation are: 
+ 
+· 
+th e location and spacing of wells; 
+· 
+the method of drilling and completing and operating wells; 
+· 
+th e rate and method of production; 
+· 
+the surface use and restoration of properties upon which wells are drilled a nd other exploration activities; 
+· 
+notice to surface owners and other third parties; 
+· 
+the ve nting or flaring of natural gas; 
+· 
+the p lugging and abandoning of wells; 
+· 
+the discharge of contaminants into water and the em ission of contaminants into air; 
+· 
+the disposal of fluids used or other wastes obtaine d in connection with operations; 
+· 
+the marketing, transportat ion and reporting of production; and 
+· 
+the valuation and payment of royalties. 
+ 
+Operations conducted on federal or state oil and natural gas leases must comply with numerous regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by DOI Bureaus or other appropriate federal or state agencies. 
+ 
+Our sales of oil and natural gas are affected by the availability, terms and cost of pipeline transportation. The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation. If these regulations change, we could face higher transmission costs for our production and, possibly, reduced access to transmission capacity. 
+ 
+Various proposals and proceedings that might affect the petroleum industry are pending before Congress, the Federal Energy Regulatory Commission, or FERC, various state legislatures, and the courts. H istorically , t he industry has been heavily regulated and we can offer you no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue nor can we predict what effect such proposals or proceedings may have on our operations. 
+ 
+We do not currently anticipate that compliance with existing laws and regulations governing exploration and production will have a significantly adverse effect upon our capital expenditures, earnings or competitive position. 
+ 
+Environmental Matters and Regulation. Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the EPA issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. Violations of environmental laws could result in administrative, civil or criminal fines and injunctive relief. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons , air emissions or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Further, the EPA has identified environmental compliance by the energy extraction sector as one of its enforcement initiatives for fiscal years 2017-2019 , although the outlook for this initiative is unclear with the incoming administration, and, as a general matter, the oil and natural gas exploration and production industry has been the subject of increasing scrutiny and regulation by environmental authorities. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. Although such laws and regulations can increase the cost of planning, designing, installing and operating our facilities, it is anticipated that, absent the occurrence of an extraordinary event, compliance with them will not have a material effect upon our operations, capital expenditures, earnings or competitive position in the marketplace. 
+14 
+Table of Contents 
+ 
+Waste Handling. The Resource Conservation and Recovery Act (“RCRA”) , as amended , and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of oil and natural gas are exempt from regulation as hazardous wastes under RCRA and its state analogs, it is possible that some wastes we generate presently or in the future may be subject to regulation under RCRA and state analogs. Additionally, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Additionally, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. Non-exempt waste is subject to more rigorous and costly disposal requirements. Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. 
+ 
+Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of wastes associated with oil and natural gas exploration and production could increase our costs to manage and dispose of such wastes. 
+ 
+Comprehensive Environmental Response, Compensation and Liability Act. T he Comprehensive Environmental Response, Compensation and Liability Act (“ CERCLA ”) , imposes joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or so–called potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes. 
+ 
+Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we have generated and will generate wastes that may fall within CERCLA’s definition of hazardous substance and may have disposed of these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum. We may also be the owner or operator of sites on which hazardous substances have been released. To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under CERCLA; we also do not know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties. In the event contamination is discovered at a site on which we are or have been an owner or operator or to which we sent hazardous substances, we could be liable for the costs of investigation and remediation and natural resources damages. 
+ 
+We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including offsite locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination. 
+ 
+Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act (“ OPA ”) , and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States (a term broadly defined to include, among other things, certain wetlands) , as well as state waters for analogous state programs. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms 
+15 
+Table of Contents 
+of a permit issued by the EPA or applicable state analog . The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit from the U.S. Army Corps of Engineers. The EPA has issued final rules on the federal jurisdictional reach over waters of the United States that may constitute an expansion of federal jurisdiction over waters of the United States. The rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals in October 2015 and in January 2017, the United States Supreme Court accepted review of the rule to determine whether jurisdiction rests with the federal district or appellate courts . Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. 
+ 
+The Oil Pollution Act is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters. 
+ 
+Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws. 
+ 
+Air Emissions. The federal Clean Air Act, as amended, and comparable state and local laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and modified and existing facilities may be required to obtain additional permits . As a result, we may need to incur capital costs in order to remain in compliance. For example, on A ugust 16 , 2012, the EPA published final regulations under the federal Clean Air Act that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail below in “Regulation of Hydraulic Fracturing.” These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties and seek injunctive relief for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects. 
+ 
+On June 3, 2016, the EPA expanded its regulatory coverage in the oil and gas industry with additional regulated equipment categories, and the addition of new rules limiting methane emissions from new or modified sites and equipment. There has been discussion of the EPA further expanding its regulatory coverage by developing and proposing rules for existing sites and equipment. Simultaneously with the additional methane rules, EPA released a rule defining site aggregation for air permitting purposes. Should the EPA reconsider this definition, some sites could require additional permitting under the Clean Air Act, an outcome that could result in costs and delays to our operations. 
+ 
+Greenhouse Gas Regulation. More stringent laws and regulations relating to climate change and GHGs may be adopted in the future and could cause us to incur material expenses in complying with them. In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions. Although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. 
+ 
+The EPA has established GHG reporting requirements for certain sources in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissio ns. Although these requirements do not limit the amount of GHGs that can be emitted, they do require us to incur costs to monitor, keep records of, and report GHG emissions associated with our operations. The GHG reporting threshold was recently crossed due to drilling activity, acquisitions, and production growth. The EPA recently began regulating methane emissions from oil and natural gas op erations. Additional regulations for reducing methane from new and modified oil and gas production sources and natural gas processing and transmission sources are discussed in more detail above in “Air Emissions.” 
+ 
+In addition to possible federal regulation, a number of states, individually and regionally, are also considering or have implemented GHG regulatory programs. These potential regional and state initiatives may result in so-called “Cap-and-Trade programs”, under which overall GHG emissions are limited and GHG emissions are then allocated and sold, and possibly other regulatory requirements, that could result in our incurring material expenses to comply, such as by being required to purchase or to surrender allowances for 
+16 
+Table of Contents 
+GHGs resulting from our operations. These federal, regional and local regulatory initiatives also could adversely affect the marketability of the oil and natural gas we produce. The impact of such future programs cannot be predicted, but we do not expect our operations to be affected any differently than other similarly situated domestic competitors. 
+ 
+Regulation of Hydraulic Fracturing. Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act (“ SDWA ”) , regulates the underground injection of substances through the Underground Injection Control (“ UIC ”) , program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions and not at the federal level, as the SDWA expressly excludes regulation of these fracturing activities (except where diesel is a component of the fracturing fluid, as further discussed below) . Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing have been proposed but have not passed. 
+ 
+The EPA, however, issued guidance on permitting hydraulic fracturing that uses fluids containing diesel fuel under the UIC program, specifically as “Class II” UIC wells. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. This report could result in additional regulatory scrutiny that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and business. Further, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. 
+ 
+The EPA has adopted regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards for hydraulically fractured natural gas and oil wells to address emissions of sulfur dioxide, volatile organic compounds, or VOCs, and methane, with a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs and methane emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured gas and oil wells newly constructed or refractured. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells. The BLM finalized regulations for hydraulic fracturing activities on federal lands. Among other things, the BLM rules impose new requirements to validate the protection of groundwater, disclosure of chemicals used in hydraulic fracturing and higher standards for the interim storage of recovered waste fluids from hydraulic fracturing. This rule is the subject of legal challenges and in June 2016 a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority to promulgate the rule, and that decision is currently remains on appeal by the federal government. In addition, the EPA has announced that it is considering regulations under the Toxic Substance Control Act to require evaluation and disclosure of hydrauli c fracturing. 
+Several states, including Texas, and some municipalities, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission has adopted rules and regulations implementing this legislation that apply to all wells for which the Railroad Commission issues an initial drilling permit after February 1, 2012. The new law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act ( “ OSHA ” ) for disclosure on a w ebsite and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. 
+ 
+Additionally, some states, localities and local regulatory districts have adopted or have considered adopting regulations to limit, and in some case impose a moratorium on hydraulic fracturing or other restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water. Further, there has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays 
+17 
+Table of Contents 
+and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing. 
+ 
+Surface Damage Statutes (“SDAs”) . In addition, a number of states and some tribal nations have enacted SDAs. These laws are designed to compensate for damage caused by oil and gas development operations. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain binding requirements for payments by the operator to surface owners/users in connection with exploration and operating activities in addition to bonding requirements to compensate for damages to the surface as a result of such activities . Costs and delays associated with SDAs could impair operational effectiveness and increase development costs. 
+ 
+National Environmental Policy Act and Endangered Species Act . Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act (“ NEPA ”) , which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. To the extent that our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects. 
+ 
+The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ or its habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. If the Company w as to have a portion of its leases designated as critical or suitable habitat or a protected species were located on a lease, it may adversely impact the value of the affected leases. 
+ 
+Mineral Leasing Act of 1920 (“Mineral Act”) . The Mineral Act prohibits direct or indirect ownership of any interest in federal onshore oil and natural gas leases by a foreign citizen or a foreign corporation except through stock ownership in a corporation formed under the laws of the United States or of any U.S. state or territory, and only if the laws, customs, or regulations of their country of origin or domicile do not deny similar or like privileges to citizens or corporations of the United States. If these restrictions are violated, the oil and gas lease or leases can be canceled in a proceeding instituted by the United States Attorney General. Although the regulations of the BLM (which administers the Mineral Act) provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. For any federal leasehold interest that the Company owns, it is possible that holders of the Company’s equity interests may be citizens of a foreign country, which is a non-reciprocal country under the Mineral Act. In such event, the federal onshore oil and gas leases held by the Company could be subject to cancellation based on such determination. 
+ 
+Other Regulation of the Oil and Natural Gas Industry. The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other similar companies in the industry with similar types, quantities and locations of production. 
+ 
+The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. Federal and state regulations govern the rates and other terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas. 
+ 
+Although oil and natural gas sales prices are currently unregulated, the federal government historically has been active in the area of oil and natural gas sales regulation. We cannot predict whether new legislation to regulate oil and natural gas sales might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate, oil and natural gas liquids are not currently regulated and are made at market prices. 
+ 
+Exports of US Crude Oil Production . The federal government has recently ended its decades-old prohibition of exports of oil produced in the lower 48 states of the US. It is too recent an event to determine the impact this regulatory change may have on our operations or our sales of oil. The general perception in the industry is that ending the prohibition of exports of oil produced in the US will be positive for producers of U.S. oil. 
+18 
+Table of Contents 
+ 
+Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following: 
+ 
+· 
+the location of wells; 
+· 
+the method of drilling and casing wells; 
+· 
+the timing of construction or drilling activities, including seasonal wildlife closures; 
+· 
+the rates of production or “allowables”; 
+· 
+the surface use and restoration of properties upon which wells are drilled; 
+· 
+the plugging and abandoning of wells; and 
+· 
+notice to, and consultation with, surface owners and other third parties. 
+ 
+State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect ing the economics of production from these wells or to limit the number of locations we can drill. 
+ 
+Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements. 
+ 
+Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. 
+ 
+Under the Energy Policy Act of 2005 (“EPAct”), Congress amended the Natural Gas Act (“NGA”) to give FERC substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. EPAct also amended the NGA to authorize FERC to “facilitate transparency in markets for the sale or transportation of physical natural gas in interstate commerce,” pursuant to which authorization FERC now requires natural gas wholesale market participants, including a number of entities that may not otherwise be subject to FERC’s traditional NGA jurisdiction, to report information annually to FERC concerning their natural gas sales and purchases. FERC requires any wholesale market participant that sells 2.2 million MMBtus or more annually in “reportable” natural gas sales to provide a report, known as FERC Form 552, to FERC. Reportable natural gas sales include sales of natural gas that utilize a daily or monthly gas price index, contribute to index price formation, or could contribute to index price formation, such as fixed price transactions for next-day or next-month delivery. 
+ 
+FERC also regulates interstate natural gas transportation rates , terms and conditions of natural gas transportation service, and the terms under which we as a shipper may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and for the release of our excess, if any, natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities. 
+ 
+19 
+Table of Contents 
+Under FERC’s current regulatory regime, interstate transportation services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. The FERC-regulated tariffs, under which interstate pipelines provide such open-access transportation service, contain strict limits on the means by which a shipper releases its pipeline capacity to another potential shipper, which provisions include FERC’s “shipper-must-have-title” rule. Violations by a shipper (i.e., a pipeline customer) of FERC’s capacity release rules or shipper-must-have-title rule could subject a shipper to substantial penalties from FERC. 
+ 
+Gathering service, which occurs on pipeline facilities located upstream of FERC- jurisdictional interstate transportation services, is regulated by the states onshore and in state waters. Depending on changes in the function performed by particular pipeline facilities , FERC has in the past reclassified certain FERC- jurisdictional transportation facilities as non-jurisdictional gathering facilities and FERC has reclassified certain non-jurisdictional gathering facilities as FERC-jurisdictional transportation facilities. Any such changes could result in an increase to our costs of transporting gas to point-of-sale locations. 
+ 
+The pipelines used to gather and transport natural gas being pr oduced by the Company are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), the Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In August 2011, the PHMSA issued an Advance Notice of Proposed Rulemaking regarding pipeline safety, including questions regarding the modification of regulations applicable to gathering lines in rural areas. 
+ 
+Oil and NGLs Sales and Transportation. Sales of oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. 
+ 
+The Company’s sales of oil and natural gas liquids are also affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by the FERC under the Interstate Commerce Act. The FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors. 
+ 
+Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors. 
+ 
+Any transportation of the Company’s crude oil, natural gas liquids and purity components (ethane, propane, butane, iso-butane, and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts 171-180 (“HMR”), including Emergency Orders by the FRA and new regulations being proposed by the PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids. 
+ 
+In October 2015, the PHMSA issued proposed new safety regulations for hazardous liquid pipelines, including a requirement that all hazardous liquid pipelines have a system for detecting leaks and establish a timeline for inspections of affected pipelines following extreme weather events or natural disasters. 
+ 
+State Regulation. Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developin g new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill. 
+ 
+The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us. 
+ 
+20 
+Table of Contents 
+Commitments and Con tingencies 
+ 
+The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment will not have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies included, and claims for damages to property, employees, other persons, and the environment resulting from the Company’s operations could have on its activities. See Note 14 for additional information. 
+ 
+Available Information 
+ 
+We make available free of charge on our w ebsite (www.callon.com) our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the SEC. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE., Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an webs ite (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers, like Callon, that file electronically with the SEC. 
+ 
+We also make available within the “ About Callon ” section of our w ebsite our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and Audit, Compensation , Strategic Planning and Reserve, and Nominating and Governance Committee Charters, which have been approved by our B oard of D irectors. We will make timely disclosure by a Current Report on Form 8-K and on our w ebsite of any change to, or waiver from, the Code of Business Conduct and Ethics for our principal executive and senior financial officers. A copy of our Code of Business Conduct and Ethics is also available, free of charge by writing us at: Chief Financial Officer, Callon Petroleum Company, P.O. Box 1287, Natchez, MS 39121 . 
+ 
+ 
+21 
+Table of Contents 
+Item 1A. Ri sk Factors 
+ 
+Risk Factors 
+ 
+Depressed oil and natural gas prices may adversely affect our results of operations and financial condition . Our success is highly dep endent on prices for oil and natural gas, which are extremely volatile. Approximately 77% of our anticipated 2017 production, on a BOE basis, is oil. Starting in the second half of 201 4 , the NYMEX price for a barrel of oil f e ll sharply, from a price of $105.37 on June 30, 201 4 to $26.21 on February 11, 2016. In addition, NYMEX prices for natural gas have been low compared with historical prices. Extended periods of low prices for oil or natural gas will have a material adverse effect on us. The prices of oil and natural gas depend on factors we cannot control such as weather, economic conditions, levels of production, actions by OPEC and other countries and government actions. Prices of oil and natural gas will affect the following aspects of our business: 
+ 
+· 
+our revenues, cash flows and earnings; 
+· 
+the amount of oil and natural gas that we are economically able to produce; 
+· 
+our ability to attract capital to finance our operations and the cost of the capital; 
+· 
+the amount we are allowed to borrow under our senior secured revolving credit facility ; 
+· 
+the profit or loss we incur in exploring for and developing our reserves; and 
+· 
+the value of our oil and natural gas properties. 
+ 
+Any substantial and extended decline in the price of oil or natural gas could have an adverse effect on our borrowing capacity, our ability to obtain additional capital, and our revenues, profitability and cash flows. 
+ 
+If oil and natural gas prices remain depressed for extended periods of time, we may be required to take additional write - downs of the carrying value of our oil and natural gas properties. We may be required to write - down the carrying value of our oil and natural gas properties when oil and natural gas prices are low. Under the full cost method, which we use to account for our oil and natural gas properties, the net capitalized costs of our oil and natural gas properties may not exceed the present value, discounted at 10%, of future net cash flows from estimated net proved reserves, using the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month, plus the lower of cost or fair market value of our unproved properties. If net capitalized costs of our oil and natural gas properties exceed this limit, we must charge the amount of the excess to earnings. This type of charge will not affect our cash flows, but will reduce the book value of our stockholders’ equity. Because the oil price we are required to use to estimate our future net cash flows is the average price over the 12 months prior to the date of determination of future net cash flows, the full effect of falling prices may not be reflected in our estimated net cash flows for several quarters. We review the carrying value of our properties quarterly and once incurred, a write - down of oil and natural gas properties is not reversible at a later date, even if prices increase. See Notes 2 and 13 t o our Cons olidated Financial Statements. 
+ 
+For the period ended December 31, 2016 , we recor ded a $95.8 millio n write-down of oil and natural gas properties as a result of the ceiling test limitation driven primarily by the significant decrease in oil prices beginning in the fourth quarter of 2014. The ceiling test calculati on as of December 31, 2016 was calculated us ing the realized prices used in determining the estimated future net cash flows from proved re serves of $42.75 per barrel of oil and $2.48 pe r Mcf of n atural gas . Oil prices have continued to fluctuate since December 31, 2016 and we may experience further ceiling test write-downs in the future. Any future ceiling test cushion, and the risk we may incur further write-downs or impairments, will be subject to fluctuation as a result of acquisition or divestiture activity. In addition, declining commodity prices or other adverse market conditions, such as declines in the market price of our common stock, could result in goodwill impairments or reductions in proved reserve estimates that would adversely affect our results of operation or financial condition. 
+ 
+Our actual recovery of reserves may substantially differ from our proved reserve estimates and our proved reserve estimates may change over time. This Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. In addition, drilling , testing and production data acquired since the date of an estimate may justify revising an estimate. 
+ 
+Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from the estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report. Additionally, reserves and future cash flows may be subject to material downward or upward revisions, based on production history, development drilling and exploration activities and prices of oil and natural gas. We incorporate many factors and assumptions into our estimates including: 
+ 
+· 
+e xpected reservoir characteristics based on geological, geophysical and engineering assessments; 
+· 
+f uture production rates; 
+· 
+f uture oil and natural gas prices and quality and locational differences; and 
+· 
+f uture development and operating costs. 
+22 
+Table of Contents 
+ 
+You should not assume that any present value of future net cash flows from our estimated net proved reserves contained in this Form 10-K represents the market value of our oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves at December 31, 2016 on average 12-month prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures, the rate and timing of production, and changes in governmental regulations or taxes. At December 31, 2016 , approxima te ly 38% of the discounted present value of our estimated net proved reserves consisted of PUDs. PUDs represented 53% of total prove d reserves by volume. Recovery of PUDs generally requires significant capital expenditures and successful drilling operations. Our reserve estimates include the assumption that we will make significant capital expenditures to develop these PUD s and the actual costs, development schedule, and results associated with these properties may not be as estimated. In addition, the 10% discount factor that we use to calculate the net present value of future net revenues and cash flows may not necessarily be the most appropriate discount factor based on our cost of capital in effect from time to time and the risks associated with our business and the oil and gas industry in general. 
+ 
+Information about reserves constitutes forward-looking information. See “Forward-Looking Statements” for information regarding forward-looking information. 
+ 
+Unless we replace our oil and gas reserves, our reserves and production will decline. Our future oil and gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our production, revenues, reserve quantities and cash flows will decline. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be limited to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. 
+ 
+Exploring for, developing, or acquiring reserves is capital intensive and uncertain. We may not be able to economically find, develop, or acquire additional reserves, or may not be able to make the necessary capital investments to develop our reserves, if our cash flows from operations decline or external sources of capital become limited or unavailable. As part of our exploration and development operations, we have expanded, and expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture stimulation techniques. The utilization of these techniques are capital intensive . I f we do not replace the reserves we produce, our reserves revenues and cash flow will decrease over time, which will have an adverse effect on our business. 
+ 
+Our business requires significant capital expenditures and we may not be able to obtain needed capital or financing on satisfactory terms or at all . Our exploration and development activities are capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Historically, we have funded our capital expenditures through a combination of cash flows from operations, borrowings from financial institutions, the sale of public debt and equity securities and asset dispositions. In 2016 , our total operational capital expenditures, including expenditures for drilling, completion and facilities , were approxima t e ly $190 million on a cash basis ( $142.7 mi llion on an accrual, or GAAP, basis ) . Our 2017 budget for operational capital expenditures is currently estimated to be approximately $325 to $350 mil lion ( on an accrual, or GAAP, basis) . The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technologica l and competitive developments. 
+ 
+If the borrowing base under our senior secured revolving credit facility or our revenues decrease as a result of lower oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or cash available under our senior secured revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our drilling locations, which in turn could lead to a possible expiration of our leases and a decline in our estimated net proved reserves, and could adversely affect our business, financial condition and results of operations. 
+ 
+Our senior secured revolving credit facility and the indenture governing our 6.125% senior unsecured notes due 2024 (“6.125% Senior Notes”) contain restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities. Our senior secured revolving credit facility and the indenture governing o ur 6.125% senior unsecured notes due 2024 c ontain restrictive covenants that limit our ability to, among other things: 
+ 
+· 
+incur additional indebtedness; 
+· 
+make loans to others; 
+· 
+make investments; 
+· 
+merge or consolidate with another entity; 
+· 
+pay dividends or make certain other payments; 
+· 
+hedge future production or interest rates; 
+· 
+create liens that secure indebtedness; 
+23 
+Table of Contents 
+· 
+sell assets; 
+· 
+engage in transactions with affiliates; and 
+· 
+engage in certain other transactions without the prior consent of the lenders. 
+ 
+As a result of these covenants, we are limited in the manner in which we conduct our business and we may be unable to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business. 
+ 
+In addition, our senior secured revolving credit facility requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest, or special interest, if any, on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the agreements governing our indebtedness (including covenants in our senior secured revolving credit facility and the indenture governing the 6.125 % Senior Notes), we could be in default under the terms of the agreements governing such indebtedness. In the event of such default: 
+ 
+· 
+the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest; 
+· 
+the lenders under our senior secured revolving credit facility could elect to terminate their commitments thereunder, cease making further loans and institute foreclosure proceedings against our assets; and 
+· 
+we could be forced into bankruptcy or liquidation. 
+If our operating performance declines, we may in the future need to obtain waivers under our senior secured revolving credit facility to avoid being in default. If we breach our covenants under our senior secured revolving credit facility and seek a waiver, we may not be able to obtain a waiver from the required lenders. If this occurs, we would be in default under our senior secured revolving credit facility, the lenders could exercise their rights, as described above, and we could be forced into bankruptcy or liquidation. 
+ 
+Our borrowings under our senior secured revolving credit facility expose us to interest rate risk. Our earnings are exposed to interest rate risk associated with borrowings under our senior secured revolving credit facility, which bear interest at a rate elected by us that is based on the prime, LIBOR or federal funds rate plus margins ranging from 2.00% to 3.00% depending on the interest rate used and the amount of the loan outstanding in relation to the borrowing base. 
+ 
+The borrowing base under our senior secured revolving credit facility may be reduced below the amount of borrowings outstanding under such facilities. Under the terms of our senior secured revolving credit facility, our borrowing base is subject to redeterminations at least semi-annually based in part on prevailing oil and gas prices. A negative adjustment could occur if the estimates of future prices used by the banks in calculating the borrowing base are significantly lower than those used in the last redetermination. The next redetermination of our borrowing base is scheduled to occur i n March 2017. In add ition, the portion of our borrowing base made available to us is subject to the terms and covenants of our senior secured revolving credit facility including, without limitation, compliance with the financial performance covenants of such facility. In the event the amount outstanding under our senior secured revolving credit facility exceeds the redetermined borrowing base, we are required to either (i) grant liens on additional oil and gas properties (not previously evaluated in determining such borrowing base) with a value equal to or greater than such excess, (ii) repay such excess borrowings over five monthly installments, or (iii) elect a combination of options in clauses (i) and (ii). We may not have sufficient funds to make any required repayment. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowing s or arrange new financing, an event of default would occur under our senior secured revolving credit facility. 
+ 
+We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful. Our ability to make scheduled payments on or to refinance our indebtedness obligations, including our senior secured revolving credit facility and 6.125% senior unsecured notes due 2024 , depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. 
+ 
+If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our senior secured revolving credit facility currently restricts our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition 
+24 
+Table of Contents 
+may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations. 
+ 
+The borrowing base under our senior secured revolving credit facility is currently $500 million, with elected commitments of $385 million. Our next scheduled borrowing base redetermination is expected to occur in March 2017. In the futu re, we may not be able to access adequate funding under our senior secured revolving credit facility as a result of a decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operation s and impair our ability to service our indebtedness. 
+Our leverage and debt service obligations may adversely affect our financial condition, results of operations, business prospects. As o f February 22 , 2017 , we h ad $400 milli on outstanding of 6.125% senior unsecured notes du e 2024 and no balance outstanding under our senior s ecured revolving credit facility, which had an additional $385 million available for borrowing s based on the existing level of commitments . Our amount of indebtedness could affect our operations in several ways, inclu ding the following: 
+ 
+· 
+require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities; 
+· 
+limit management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; 
+· 
+increase our vulnerability to downturns and adverse developments in our busi ness and the economy; 
+· 
+limit our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures or acquisitions or to r efinance existing indebtedness; 
+· 
+place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and e ngage in business combinations; 
+· 
+make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our th en-outstanding bank borrowings; 
+· 
+make us vulnerable to increases in interest rates as our indebtedness under our senior secured revolving credit facility may vary with prevailing interest rates; 
+· 
+place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms go verning their indebtedness; and 
+· 
+make it more difficult for us to satisfy our obligations under the Senior Notes or other debt and increase the risk that we may default on our debt obligations. 
+ 
+We cannot assure you that we will be able to maintain or improve our leverage position. An element of our business strategy involves maintaining a disciplined approach to financial management. However, we are also seeking to acquire, exploit and develop additional reserves that may require the incurrence of additional indebtedness. Although we will seek to maintain or improve our leverage position, our ability to maintain or reduce our level of indebtedness depends on a variety of factors, including future performance and our future debt financing needs. General economic conditions, oil, NGL and natural gas prices and financial, business and other factors will also affect our ability to maintain or improve our leverage position. Many of these factors are beyond our control. 
+ 
+The unavailability or high cost of drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget. From time to time, our industry experiences a shortage of drilling rigs, equipment, supplies, water or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. Increasing levels of exploration and production may increase the demand for oilfield services and equipment, and the costs of these services and equipment may increase, while the quality of these services and equipment may suffer. The unavailability or high cost of drilling rigs, pressure pumping equipment, supplies , water or qualified personnel can materially and adversely affect our operations and profitability. 
+ 
+Our operations substantially depend on the availability of water. Restrictions on our ability to obtain, recycle and dispose of water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner. Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to secure water from local land owners and other sources for use in our operations. If drought conditions were to occur, our ability to obtain water could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows. 
+ 
+Our producing p roperties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of 
+25 
+Table of Contents 
+producing horizons within this area. All of our producing properties are geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of oil, natural gas or natural gas liquids. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations. 
+ 
+Our exploration projects increase the risks inherent in our oil and natural gas activities. We may seek to replace reserves through exploration, where the risks are greater than in acquisitions and development drilling. Our exploration drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including: 
+ 
+· 
+the results of our exploration drilling activities; 
+· 
+receipt of additional seismic data or other geophysical data or the reprocessing of existing data; 
+· 
+material changes in oil or natural gas prices; 
+· 
+the costs and availability of drilling rigs; 
+· 
+the success or failure of wells drilled in similar formations or which would use the same production facilities; 
+· 
+availability and cost of capital; 
+· 
+changes in the estimates of the costs to drill or complete wells; and 
+· 
+changes to governmental regulations. 
+ 
+Delays in exploration, cost overruns or unsuccessful drilling results could have a material adverse effect on our business and future growth. 
+ 
+Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns. Exploration, development, drilling and production activities are subject to many risks, including the risk that commercially productive deposits will not be discovered. We may invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that any leasehold acreage acquired will be profitably developed, that new wells drilled will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, wells that are profitable may not achieve our targeted rate of return. 
+ 
+In addition, we may not be successful in controlling our drilling and production costs to improve our overall return. We may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including: 
+ 
+· 
+unexpected drilling conditions; 
+· 
+pressure or irregularities in formations; 
+· 
+lack of proximity to and shortage of capacity of transportation facilities; 
+· 
+equipment failures or accidents and shortages or delays in the availability of drilling rigs and the delivery of equipment; and 
+· 
+compliance with governmental requirements. 
+ 
+Failure to conduct our oil and gas operations in a profitable manner may result in write - downs of our proved reserves quantities, impairment of our oil and gas properties, and a write- down in the carrying value of our unproved properties, and over time may adversely affect our growth, revenues and cash flows. 
+ 
+Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could prevent them from being drilled or delay their drilling. Our management team has identified drilling locations as an estimation of our future development activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these identified drilling locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system, marketing and transportation constraints, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the identified drilling locations will ever be drilled or if we will be able to produce oil or natural gas from these drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the identified locations are located, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified. 
+ 
+The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Approxim ately 53% of ou r total estimated proved reserves as of December 31, 2016 , were proved 
+26 
+Table of Contents 
+undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves. 
+ 
+We may be unable to integrate successfully the operations of recent and future acquisitions with our operations, and we may not realize all the anticipated benefits of these acquisitions. Our business has and may in the future include producing property acquisitions that include undeveloped acreage. We can offer no assurance that we will achieve the desired profitability from our recent acquisitions or from any acquisitions we may complete in the future. In addition, failure to assimilate recent and future acquisitions successfully could adversely affect our financial condition and results of operations. Our acquisitions may involve numerous risks, including : 
+ 
+· 
+operating a larger combined organization and adding operations; 
+· 
+difficulties in the assimilation of the assets and operations of the acquired business, especially if the assets acquired are in a new geographic area; 
+· 
+risk that oil and natural gas reserves acquired may not be of the anticipated magnitude or may not be developed as anticipated; 
+· 
+loss of significant key emplo yees from the acquired business; 
+· 
+inability to obtain satisfactory title to the assets we acquire; 
+· 
+a decrease in our liquidity if we use a portion of our available cash to finance acquisitions; 
+· 
+a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions; 
+· 
+diversion of management’s attention from other business concerns; 
+· 
+failure to realize expected profitability or growth; 
+· 
+failure to realize expected synergies and cost savings; 
+· 
+coordinating geographically disparate organizations, systems and facilities; and 
+· 
+coordinating or consolidating corporate and administrative functions. 
+ 
+Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. If we consummate any future acquisition, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisition and current operations, which in turn, could negatively impact our results of operations. 
+ 
+We may fail to fully identify problems with any properties we acquire, and as such, assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and pote ntial liabilities. We are actively seeking to acquire additional acreage in Texas or other regions in the future. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, operating and capital costs and potential environmental and other liabilities. Although we conduct a review of properties we acquire which we believe is consistent with industry practices, we can give no assurance that we have identified or will identify all existing or potential problems associated with such properties or that we will be able to mitigate any problems we do identify. Such assessments are inexact and their accuracy is inherently uncertain. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for preclosing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms. 
+ 
+Unexpected subsurface conditions and other unforeseen operating hazards may adversely impact our ability to conduct business. There are many operating hazards in exploring for and producing oil and natural gas, including: 
+ 
+· 
+our drilling operations may encounter unexpected formations or pressures, which could cause damage to equipment or personal injury; 
+· 
+we may experience equipment failures which curtail or stop production; 
+· 
+we could experience blowouts or other damages to the productive formations that may require a well to be re-drilled or other corrective action to be taken; and 
+· 
+storms and other extreme weather conditions could cause damages to our production facilities or wells. 
+ 
+27 
+Table of Contents 
+Because of these or other events, we could experience environmental hazards, including release of oil and natural gas from spills, natural gas-leaks, accidental leakage of toxic or hazardous materials, such as petroleum liquids, drilling fluids or fracturing fluids, including chemical additives, underground migration, and ruptures. 
+ 
+If we experience any of these problems, it could affect well bores, gathering systems and processing facilities, which could adversely affect our ability to conduct operations. We could also incur substantial losses in excess of our insurance coverage as a result of: 
+ 
+· 
+injury or loss of life; 
+· 
+severe damage to and destruction of property, natural resources and equipment; 
+· 
+pollution and other environmental damage; 
+· 
+clean-up responsibilities; 
+· 
+regulatory investigation and penalties; 
+· 
+suspension of our operations; and 
+· 
+repairs to resume operations. 
+ 
+We cannot assure you that we will be able to maintain adequate insurance at rates we consider reasonable to cover our possible losses from operating hazards. The occurrence of a significant event not fully insured or indemnified against could materially and adversely affect our financial condition and results of operations. 
+ 
+Factors beyond our control affect our ability to market production and our financial results. The ability to market oil and natural gas from our wells depends upon numerous factors beyond our control. These factors could negatively affect our ability to market all of the oil or natural gas we produce. In addition, we may be unable to obtain favorable prices for the oil and natural gas we produce. These factors include: 
+ 
+· 
+the extent of domestic production and imports of oil and natural gas; 
+· 
+recen t changes in federal regulations allowing the export of U.S. crude oil after decades of prohibition; 
+· 
+federal regulations authorizing exports of liquefied natural gas (“LNG”), the development of new LNG export facilities under construction in the U.S. Gulf Coast region, and the first LNG exports from such facilities; 
+· 
+the construction of new pipelines capable of exporting U.S. natural gas to Mexico; 
+· 
+the proximity of hydrocarbon production to pipelines; 
+· 
+the availability of pipeline and/or refining capacity; 
+· 
+the demand for oil and natural gas by utilities and other end users; 
+· 
+the availability of alternative fuel sources; 
+· 
+the effects of inclement weather; 
+· 
+state and federal regulation of oil and natural gas marketing; and 
+· 
+federal regulation of natural gas sold or transported in interstate commerce. 
+ 
+In particular, in areas with increasing non-conventional shale drilling activity, pipeline, rail or other transportation capacity may be limited and it may be necessary for new interstate and intrastate pipelines and gathering systems to be built. 
+ 
+The marketability of a portion of our production is dependent upon oil and condensate trucking facilities owned and operated by third parties, and the unavailability of these facilities would have a material adverse effect on our revenue. Our ability to market our production depends in part on the availability and capacity of oil and condensate trucking operations owned and operated by third parties. Our failure to obtain these services on acceptable terms could materially harm our business. We may be required to shut in wells for lack of a market or because of inadequate or unavailable trucking capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. 
+ 
+The disruption of third party trucking facilities due to maintenance, weather or other factors could negatively impact our ability to market and deliver our oil and condensate. The third parties control when , or if , such trucking facilities are restored and what prices will be charged. In the past, we have experienced disruptions in our ability to market oil and condensate from bad weather. We may experience similar interruptions as we continue to explore and develop our Permian Basin properties in the future. If we were required to shut in our production for long periods of time due to lack of trucking capacity, it would have a material adverse effect on our business, financial condition, results of operations and cash flows. 
+ 
+Part of our strategy involves drilling in new or emerging shale plays using horizontal drilling and completion techniques. The results of our planned drilling program in these formations may be subject to more uncertainties than horizontal drilling programs in more established areas and formations, and may not meet our expectations for reserves or production. The results of our horizontal drilling efforts in emerging areas of the Permian Basin, including Howard and Ward Counties, are generally more uncertain than drilling results in areas that are less developed and have more established production from horizontal formations such as the Wolfcamp, Spraberry and Bone Spring horizons. Because emerging areas and associated target formations have limited or no 
+28 
+Table of Contents 
+production history, we are less able to rely on past drilling results in those areas as a basis to predict our future drilling results. In addition, horizontal wells drilled in shale formations, as distinguished from vertical wells, utilize multilateral wells and stacked laterals, all of which are subject to well spacing, density and proration requirements of the Texas Railroad Commission, which requirements could adversely impact our ability to maximize the efficiency of our horizontal wells related to reservoir drainage over time. Further, access to adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more challenging in new or emerging areas. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, access to gathering systems and takeaway capacity or otherwise, and/or natural gas and oil prices decline, our investment in these areas may not be as economic as we anticipate, we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future. 
+ 
+The loss of key personnel could adversely affect our ability to operate. We depend, and will continue to depend in the foreseeable future, on the services of our senior officers and other key employees, as well as other third-party consultants with extensive experience and expertise in evaluating and analyzing drilling prospects and producing oil and natural gas from proved properties and maximizing production from oil and natural gas properties. Our ability to retain our senior officers, other key employees and our third party consultants, none of whom are subject to employment agreements, is important to our future success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business. 
+ 
+We may not be insured against all of the operating risks to which our business is exposed. In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We cannot assure you that our insurance will be adequate to cover losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. No assurance can be given that we will be able to maintain insurance in the future at rates we consider reasonable and may elect none or minimal insurance coverage. The occurrence of a significant event, not fully insured or indemnified against, could have a material adverse effect on our financial condition and operations. 
+ 
+Competitive industry conditions may negatively affect our ability to conduct operations. We compete with numerous other companies in virtually all facets of our business. Our competitors in development, exploration, acquisitions and production include major integrated oil and gas companies and smaller independents as well as numerous financial buyers, including many that have significantly greater resources than us . Therefore, competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources permit. We also compete for the materials, equipment and services that are necessary for the exploration, development and operation of our properties. Our ability to increase reserves in the future will be dependent on our ability to select and acquire suitable prospects for future exploration and development. Factors that affect our ability to compete in the marketplace include: 
+ 
+· 
+our access to the capital necessary to drill wells and acquire properties; 
+· 
+our ability to acquire and analyze seismic, geological and other information relating to a property; 
+· 
+our ability to retain the personnel necessary to properly evaluate seismic and other information relating to a property; 
+· 
+our ability to procure materials, equipment and services required to explore, develop and operate our properties, including the ability to procure fracture stimulation services on wells drilled; and 
+· 
+our ability to access pipelines, and the location of facilities used to produce and transport oil and natural gas production. 
+ 
+Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “ Dodd-Frank Act”) establishes federal oversight and regulation of over-the-counter derivatives and requires the U.S. Commodity Futures Trading Commission (the “CFTC”) and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the over-the-counter market. 
+ 
+Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized. In one of the CFTC’s rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC approved on November 5, 2013, as modified and re-proposed on December 30, 2016, a rule imposing position limits for certain futures and options contracts in various commodities (including Henry Hub Natural Gas , Light Sweet Crude Oil, NY Harbor ULSD, and RBOB Gasoline traded on NYMEX ) and for swaps that are their economic equivalents. Certain specified types of hedging transactions are proposed to be exempt from these position limits, provided that such hedging transactions satisfy the CFTC’s requirements for “bona fide hedging” transactions or positions. Similarly, the CFTC has issued on December 16, 2016 a proposed rule regarding the capital that a swap dealer or major swap participant is required to post with respect to its swap business, but has not yet issued a final rule. The CFTC issued a final rule on margin requirements for uncleared swap transactions in January 2016, which includes an exemption for commercial end-users that enter into uncleared swaps in order to hedge commercial risks affecting their business, from any requirement to post margin to secure such swap transactions. In addition, the CFTC has issued a final rule authorizing an exception for commercial end-users using swaps to hedge their commercial risks from the otherwise applicable mandatory obligation under the Dodd-Frank Act to clear all swap transactions through a registered derivatives clearing organization and to trade all such swaps on a registered exchange. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions 
+29 
+Table of Contents 
+and other regulatory compliance obligations. All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business. 
+ 
+While it is not possible at this time to predict when the CFTC will issue final rules applicable to position limits or capital requirements, depending on our ability to satisfy the CFTC’s requirements for the various exemptions available for a commercial end-user using swaps to hedge or mitigate its commercial risks, these rules and regulations may provide beneficial exemptions or may require us to comply with position limits and other limitations with respect to our financial derivative activities. When a final rule on capital requirements is issued, the Dodd-Frank Act may require our current counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which could increase the cost to us of entering into such derivatives. The Dodd-Frank Act may also require our current counterparties to financial derivative transactions to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties, and may cause some entities to cease their current business as hedge providers. These changes could reduce the liquidity of the financial derivatives markets thereby reducing the ability of commercial end-users to have access to financial derivatives to hedge or mitigate their exposure to commodity price volatility. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available capital for other commercial operations purposes), materially alter the terms of future swaps relative to the terms of our existing bilaterally negotiated financial derivative contracts, and reduce the availability of derivatives to protect against commercial risks we encounter . 
+ 
+In addition, federal banking regulators have adopted new capital requirements for certain regulated financial institutions in connection with the Basel III Accord. The Federal Reserve Board also issued proposed regulations on September 30, 2016, proposing to impose higher risk-weighted capital requirements on financial institutions active in physical commodities, such as oil and natural gas. If and when these proposed regulations are fully implemented, financial institutions subject to these higher capital requirements may require that we provide cash or other collateral with respect to our obligations under the financial derivatives and other contracts we may enter into with such financial institutions in order to reduce the amount of capital such financial institutions may have to maintain. Alternatively, financial institutions subject to these capital requirements may price transactions so that we will have to pay a premium to enter into derivatives and other physical commodity transactions in an amount that will compensate the financial institutions for the additional capital costs relating to such derivatives and physical commodity transactions. Rules implementing the Basel III Accord and higher risk-weighted capital requirements could materially reduce our liquidity and increase the cost of derivative contracts and other physical commodity contracts (including through requirements to post collateral which could adversely affect our available capital for other commercial operations purposes). 
+ 
+If we reduce our use of derivative contracts as a result of any of the foregoing new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas and natural gas liquids prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and natural gas liquids. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations, or cash flows. 
+ 
+We may not have production to offset hedges. Part of our business strategy is to reduce our exposure to the volatility of oil and natural gas prices by hedging a portion of our production. In a typical hedge transaction, we will have the right to receive from the other parties to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the other parties this difference multiplied by the quantity hedged. Additionally, we are required to pay the difference between the floating price and the fixed price when the floating price exceeds the fixed price regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements even though such payments are not offset by sales of physical production. 
+ 
+Our hedging program may limit potential gains from increases in commodity prices or may result in losses or may be inadequate to protect us against continuing and prolonged declines in commodity prices. We enter into hedging arrangements from time to time to reduce our exposure to fluctuations in oil and natural gas prices and to achieve more predictable cash flow. Our hedges at December 31, 2016 are in the form of collars, swaps, put and call options , and other structures placed with the commodity trading branches of certain national banking institutions and with certain other commodity trading groups. We cannot assure you that these or future counterparties will not become credit risks in the future. Hedging arrangements expose us to risks in some circumstances, including situations when the counterparty to the hedging contract defaults on the contractual obligations or there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received. These hedging arrangements may also limit the benefit we could receive from increases in the market or spot prices for oil and natural gas. We cannot assure you that the hedging transactions we have entered into, or will enter into, will adequately protect us from fluctuations in oil and natural gas prices. In addition, at December 31, 2016 , t he Company’s hedging portfolio, linked to NYMEX benchmark pricing, covers approxim ately 3,755 MBbls and 2,920 B Btu of our expected oil and natural gas production, respectively, for calendar year 2017 . We also have commodity hedging contracts linked to Midland WTI basis differentials relative to Cushing covering approximately 2,004 MBbls of our expected oil production for calendar year 2017 . These hedges may be inadequate to protect us from continuing and prolonged declines in oil and natural gas prices. To the extent that oil and natural gas prices remain at current levels or decline further, we will not be able 
+30 
+Table of Contents 
+to hedge future production at the same pricing level as our current hedges and our results of operations and financial condition would be negatively impacted. 
+ 
+Our hedging transactions expose us to counterparty credit risk. Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract. During periods of falling commodity prices, our hedging transactions expose us to risk of financial loss if our counterparty to a derivatives transaction fails to perform its obligations under a derivatives transaction (e.g., our counterparty fails to perform its obligation to make payments to us under the derivatives transaction when the market (floating) price under such derivative falls below the specified fixed price). We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss. 
+ 
+Should we fail to comply with all applicable statutes, rules, regulations and orders administered by the CFTC or the Federal Energy Regulatory Commission (“FERC”), we could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, FERC has been given greater civil penalty authority under the Natural Gas Act (“NGA”), including the ability to impose penalties of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements. We also must comply with the anti-market manipulation rules enforced by FERC under the NGA. Under the Commodity Exchange Act (as amended by the Dodd-Frank Act) and regulations promulgated thereunder by the CFTC, the CFTC has also adopted anti-market manipulation, fraud and market disruption rules relating to the prices of commodities, futures contracts, options on futures, and swaps. Additional rules and legislation pertaining to those and other matters may be considered or adopted by Congress, the FERC, or the CFTC from time to time. Failure to comply with those statutes, regulations, rules and orders could subject us to civil penalty liability. 
+ 
+The inability of one or more of our customers to meet their obligations to us may adversely affect our financial results . Our principal exposures to credit risk are through receivables resulting from the sale of our oil and natural gas production, which we market to energy marketing c ompanies, refineries and affiliates, advances to joint interest parties and joint interest receivables. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. The largest purchaser of our oil and natural gas accounted for approxim ately 43% of o ur total oil and natural gas revenues for the year ended December 31, 2016 . We do not require any of our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. Joint interest receivables arise from billing entities who own a partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we choose to drill. We have limited ability to control participation in our wells. 
+ 
+Compliance with environmental and other government regulations could be costly and could negatively impact production. Our operations are subject to numerous laws and regulations governing the operation and maintenance of our facilities and the discharge of materials into the environment or otherwise relating to environmental protection. For a discussion of the material regulations applicable to us, see “Regulations.” These laws and regulations may: 
+ 
+· 
+require that we acquire permits before commencing drilling; 
+· 
+impose operational, emissions control and other conditions on our activities; 
+· 
+restrict the substances that can be released into the environment or used in connection with drilling and production activities or restrict the disposal of waste from our operations; 
+· 
+limit or prohibit drilling activities on protected areas such as wetlands, wilderness or other protected areas; and 
+· 
+require measures to remediate or mitigate pollution and environmental impacts from current and former operations, such as cleaning up spills or dismantling abandoned production facilities. 
+ 
+Under these laws and regulations, the rate of oil and natural gas production may be restricted below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal, state and local agencies frequently revise environmental laws and regulations, and such changes could result in increased costs for environmental compliance, such as waste handling, permitting, or cleanup for the oil and natural gas industry and could have a significant impact on our operating costs. In general, the oil and natural gas industry recently has been the subject of increased legislative and regulatory attention with respect to environmental matters. For example, the EPA has identified environmental compliance by the energy extraction sector as one of its enforcement initiatives for 2017-2019. 
+ 
+Further, u nder these laws and regulations, we could be liable for costs of investigation, removal and remediation, damages to and loss of use of natural resources, loss of profits or impairment of earning capacity, property damages, costs of increased public services, as well as administrative, civil and criminal fines and penalties, and injunctive relief. Certain environmental statutes, including the RCRA, CERCLA, OPA and analogous state laws and regulations, impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released. We could also be affected 
+31 
+Table of Contents 
+by more stringent laws and regulations adopted in the future, including any related to climate change, greenhouse gases and hydraulic fracturing. Under the common law, we could be liable for injuries to people and property. We maintain limited insurance coverage for sudden and accidental environmental damages. We do not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Also, we do not believe that insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability or we may be required to cease production from properties in the event of environmental incidents. 
+ 
+Climate change legislation or regulations restricting emissions of “greenhouse gases” (“GHG”) could result in increased operating costs and reduced demand for the oil and natural gas we produce. In the absence of comprehensive federal legislation on GHG emission control, the U.S. Environmental Protection Agency (the “EPA”) attempted to require the permitting of GHG emissions. Although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. These permitting provisions, to the extent applicable to our operations, could require us to implement emission controls or other measures to reduce GHG emissions and we could incur additional costs to satisfy those requirements. The EPA has adopted rules to regulate methane emissions, including from new and modified oil and gas production sources and natural gas processing and transmission sources, and has announced its intention to regulate methane emissions from existing oil and gas sources. 
+ 
+In addition, the EPA requires the reporting of GHG emissions from specified large GHG emission sources including onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities, which may include facilities we operate. Reporting of GHG emissions from such facilities is required on an annual basis. We will continue to incur costs associated with this reporting obligation. 
+ 
+The United States Congress has considered (but not passed) legislation to reduce emissions of GHGs and many states and localities have already taken or have considered legal measures to reduce or measure GHG emissions, often involving the planned development of GHG emission inventories and/or cap and trade programs. Most of these cap and trade programs would require major sources of emissions or major producers of fuels to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. These allowances would be expected to escalate significantly in cost over time. The adoption and implementation of any legislation or regulatory programs imposing GHG reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGS associated with our oper ations or could adversely affect demand for the oil and natural gas that we produce. 
+ 
+Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects. In an interpretative guidance on climate change disclosures, the SEC indicates that climate change could have an effect on the severity of weather (including storms and floods), the arability of farmland, and water availability and quality. If such effects were to occur, our exploration and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production activities either because of climate-related damages to our facilities in our costs of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate chan ge could also have an indirect e ffect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. In addition, our hydraulic fracturing operations require large amounts of water. Should drought conditions occur, our ability to obtain water in sufficient quality and quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. 
+ 
+Federal legislation and state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. Hydraulic fracturing is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing activities are typically regulated by state oil and gas commissions but not at the federal level, as the federal Safe Drinking Water Act expressly excludes regulation of these fracturing activities (except where diesel is a component of the fracturing fluid). We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with the wells for which we are the operator. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under federal and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury. In December 2016, the EPA released its final report “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States.” This report concludes that hydraulic fracturing can impact drinking water resources in certain circumstances but also noted that certain date gaps and uncertainties limited EPA’s assessment. The agency has identified one of its enforcement initiatives for 2017 to 2019 to be environmental compliance by the energy extraction sector. This study and the EPA’s enforcement initiative could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. 
+ 
+32 
+Table of Contents 
+A committee of the U.S. House of Representatives conducted an investigation of hydraulic fracturing practices. Legislation was introduced before Congress, but not passed to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states and local or regional regulatory authorities have adopted or are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For example, New York has banned high volume hydraulic fracturing. Further, Pennsylvania has adopted a variety of regulations limiting how and where fracturing can be performed. While we have no operations in either New York or Pennsylvania, any other new laws or regulations that significantly restrict hydraulic fracturing in areas in which we do operate could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby affect the determination of whether a well is commercially viable. 
+ 
+Further, the EPA issued pretreatment standards for wastewater from hydraulic fracturing, prohibiting the discharges of waste water pollutants from onshore unconventional oil and gas extraction to publicly owned treatment works. The EPA has announced an initiative under the Toxic Substance Control Act to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals. The Bureau of Land Management (the “BLM”) finalized regulations for hydraulic fracturing activities on federal lands. Among other things, the BLM rule imposed new requirements to validate the protection of groundwater, disclosure of chemicals used in hydraulic fracturing and higher standards for the interim storage of recovered waste fluids from hydraulic fracturing. A federal district court in Wyoming struck down the BLM rule; the federal government has appealed the district court’s decision. In addition, if hydraulic fracturing becomes further regulated at the federal level, our fracturing activities could become subject to additional permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs and potential liabilities. Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. In addition, restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that we are ultimately able to produce in commercial quantities. 
+ 
+We are now subject to regulation under NSPS and NESHAPS programs, which could result in increased operating costs. On April 17, 2012, the EPA issued final rules that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards (the “NSPS”) and the National Emissions Standards for Hazardous Air Pollutants (the “NESHAP”) programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards require owners/operators to reduce VOC emissions from natural gas not sent to the gathering line during well completion either by flaring, using a completion combustion device, or by capturing the natural gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to newly fractured wells and also existing wells that are refractured. Further, the finalized regulations also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules may require changes to our operations, including the installation of new equipment to control emissions. 
+ 
+The EPA has issued new rules limiting methane emissions from new or modified oil and gas sources. The rules amend the air emissions rules for the oil and natural gas sources and natural gas processing and transmission sources to include new standards for methane. Simultaneously with the methane rules, the EPA adopted new rules governing the aggregating of multiple surface sites into a single-source of air quality permitting purposes. In addition, the EPA had announced plans to begin work on regulations to regulate methane emissions from existing oil and gas sources. 
+ 
+We are subject to stringent and complex federal, state and local laws and regulations governing, among other things, worker health and safety, the discharge of materials into the environment and environmental protection that could result in substantial costs. In some areas of Texas, there has been concern that certain formations into which disposal wells are injecting produced waters could become over-pressured after many years of injection, and the governing Texas regulatory agency is reviewing the data to determine whether any action is necessary to address this issue. If the Texas state agency were to decline to issue permits for, or limit the volumes of, new injection wells into the formations currently utilized by us, we may be required to seek alternative methods of disposing of produced waters, including injecting into deeper formations, which could increase our costs. 
+ 
+Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation. In recent years, the Obama administration’s budget proposals and other proposed legislation have included the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production. If enacted into law, these proposals would eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. These changes include, but are not limited to (1) the repeal of the percentage depletion allowance for oil and gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for U.S. production activities and (4) the increase in the amortization period from two years to seven years for geophysical costs paid or incurred in connection with the exploration for or development of, oil and gas within the United States Whether the proposed legislation will ever be enacted under the newly elected Trump administration remains in question, but the passage of such legislation or any other similar changes in U.S. federal income tax laws could negatively affect our financial condition and results of operations. 
+ 
+There are inherent limitations in all control systems, and misstatements due to error or fraud that could seriously harm our business may occur and not be detected. Our management, including our Chief Executive Officer and Chief Financial Officer, do not 
+33 
+Table of Contents 
+expect that our internal controls and disclosure controls will prevent all possible error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, an evaluation of controls can only provide reasonable assurance that all material control issues and instances of fraud, if any, in the C ompany have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Further, controls can be circumvented by the individual acts of some persons or by collusion of two or more persons. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. A failure of our controls and procedures to detect error or fraud could seriously harm our business and results of operations. 
+ 
+We have no plans to pay cash dividends on our common stock in the foreseeable future. We have no plans to pay cash dividends in the foreseeable future. The terms of our senior secured revolving credit facility prohibit us from paying dividends and making other distributions. In addition, a ny future determination as to the declaration and payment of cash dividends will be at the discretion of our B oard of D irectors and will depend upon our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors deemed rele vant by our B oard of D irectors. 
+ 
+Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations. Our business has become increasingly dependent on digital technologies to conduct certain exploration, development, production and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our exploration or production operations. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyber-attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. 
+ 
+While we have not experienced cyber-attacks, there is no assurance that we will not suffer such attacks and resulting losses in the future. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks. 
+ 
+We may be subject to the actions of activist shareholders. We have been the subject of increased activity by activist shareholders. Responding to shareholder activism can be costly and time-consuming, disrupt our operations and divert the attention of management and our employees from executing our business plan. Activist campaigns can create perceived uncertainties as to our future direction, strategy or leadership and may result in the loss of potential business opportunities, harm our ability to attract new investors, customers and joint venture partners and cause our stock price to experience periods of volatility or stagnation. Moreover, if individuals are elected to our board of directors with a specific agenda, our ability to effectively and timely implement our current initiatives, retain and attract experienced executives and employees and execute on our long-term strate gy may be adversely affected. 
+ 
+ITEM 1B. Unr esolved Staff Comments 
+ 
+None. 
+ 
+ITEM 3. Leg al Proceedings 
+ 
+We are a defendant in various legal proceedings and claims, which arise in the ordinary course of our business. We do not believe the ultimate resolution of any such actions will have a material effect on our financial position or results of operations. 
+ 
+ITEM 4. Mi ne Safety Disclosures 
+ 
+Not applicable. 
+34 
+Table of Contents 
+PAR T II. 
+ 
+ITEM 5. Ma rket for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+ 
+Market Information 
+ 
+Our common stock trades on the New York Stock Exchange under the symbol “CPE”. The following table sets forth the high and low sale prices per share as reported for the periods indicated. 
+ 
+ 
+ 
+Common Stock Price 
+ 
+2016 
+2015 
+ 
+High 
+Low 
+High 
+Low 
+First quarter 
+$ 
+9.05 
+$ 
+4.21 
+$ 
+8.15 
+$ 
+4.66 
+Second quarter 
+12.56 
+8.15 
+9.40 
+7.35 
+Third quarter 
+15.91 
+10.34 
+9.65 
+6.03 
+Fourth quarter 
+18.53 
+12.45 
+10.18 
+6.87 
+ 
+Holders 
+ 
+As of February 22, 2017 the Company had approxim atel y 2,828 common stockholders of record. 
+ 
+Dividends 
+ 
+We have not paid any cash dividends on our common stock to date and presently do not expect to declare or pay any cash dividends on our common stock in the foreseeable future as we intend to reinvest our cash flows and earnings into our business. The declaration and payment of dividends is subject to the discretion of our Board of Directors and to certain limitations imposed under Delaware corporate law and the agreements governing our debt obligations. The timing, amount and form of dividends, if any, will depend on, among other things, our results of operations, financial condition, cash requirements and other factors deemed relevant by our Board of Directors. In addition, certain of our debt facilities contain restrictions on the payment of dividends to the holders of our common stock. 
+ 
+Holders of our 10% S eries A Cumulative P referred S tock are entitled to a cumulative dividend whether or not declared, of $5.00 per annum, payable quarterly, equivalent to 10.0% of the liquidation preference of $50.00 per share. Unless the full amount of the dividends for the 10% Series A Cumulative Preferred Stock is paid in full, we cannot declare or pay any dividend on our common stock. 
+ 
+During 2016 , neither the Company nor any affiliated purchasers made repurchases of Callon’s equity securities. 
+ 
+On February 4, 2016 , a total of 120,000 shares of the Company’s 10% Series A Cumulative Preferred Stock were exchanged for 719,000 shares of c ommon s tock. 
+ 
+Equity Compensation Plan Information 
+ 
+The following table summarizes information regarding the number of shares of our common stock that are available for issuance under all of our existing equity compensation plans as of December 31, 2016 (securities amounts are presented in thousands). 
+ 
+ 
+Plan Category 
+Number of Securities to be Issued Upon Exercise of Outstanding Options 
+Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights 
+Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans 
+Equity compensation plans approved by security holders 
+— 
+$ 
+— 
+2,270 
+Equity compensation plans not approved by security holders 
+15 
+$ 
+14.37 
+— 
+Total 
+15 
+$ 
+14.37 
+2,270 
+ 
+For additional information regarding the Company’s benefit plans and share-based compensation expense, see Notes 8 and 9 to the Consolidated Financial Statements. 
+ 
+35 
+Table of Contents 
+Performance Graph 
+ 
+The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the performance of the Company’s common stock relative to four broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. 
+ 
+T he graph below compares the yearly percent age change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the S&P 500 Index and SIG (Susquehanna International Group, LLP) Oil Exploration & Production Index from December 31, 20 1 1 , through December 31, 2016 . 
+ 
+The stock performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing. 
+ 
+Comparison of Five Year Cumulative Total Return 
+Assumes Initial Investment of $100 
+December 2016 
+ 
+ 
+ 
+For the Year Ended December 31, 
+Company/Market/Peer Group 
+2011 
+2012 
+2013 
+2014 
+2015 
+2016 
+Callon Petroleum Company 
+$ 
+100.00 
+$ 
+94.57 
+$ 
+131.39 
+$ 
+109.66 
+$ 
+167.81 
+$ 
+309.26 
+S&P 500 Index - Total Returns 
+100.00 
+116.00 
+153.57 
+174.60 
+177.01 
+198.18 
+SIG Oil Exploration & Production Index 
+100.00 
+93.07 
+117.80 
+84.46 
+46.39 
+59.28 
+ 
+ 
+ 
+ 
+ 
+ 
+ 
+ 
+ 
+ 
+ 
+ 
+ 
+ 
+ 
+ 
+ 
+ 
+ 
+36 
+Table of Contents 
+ITEM 6. Selected Fi nancial Data 
+ 
+The following table sets forth, as of the dates and for the periods indicated, selected financial information about the Company . The financial information for each of the five years in the period ended December 31, 2016 has been derived from our audited Consolidated Financial Statements for such periods. The information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and Notes thereto. The following information is not necessarily indicative of our future results (dollars in thousands, except per share amounts) . 
+ 
+ 
+ 
+For the Year Ended December 31, 
+ 
+2016 
+2015 
+2014 
+2013 
+2012 
+Statement of Operations Data 
+Operating revenues 
+Oil and natural gas sales 
+$ 
+200,851 
+$ 
+137,512 
+$ 
+151,862 
+$ 
+102,569 
+$ 
+110,733 
+Operating expenses 
+Total operating expenses 
+$ 
+248,328 
+$ 
+346,622 
+$ 
+113,592 
+$ 
+91,905 
+$ 
+100,043 
+Income (loss) from operations 
+(47,477)
+(209,110)
+38,270 
+10,664 
+10,690 
+Net income (loss) (a) 
+(91,813)
+(240,139)
+37,766 
+4,304 
+2,747 
+Income (loss) per share ("EPS") 
+Basic 
+$ 
+(0.78)
+$ 
+(3.77)
+$ 
+0.67 
+$ 
+(0.01)
+$ 
+0.07 
+Diluted 
+$ 
+(0.78)
+$ 
+(3.77)
+$ 
+0.65 
+$ 
+(0.01)
+$ 
+0.07 
+Weighted average number of shares outstanding for Basic EPS 
+126,258 
+65,708 
+44,848 
+40,133 
+39,522 
+Weighted average number of shares outstanding for Diluted 
+EPS 
+126,258 
+65,708 
+45,961 
+40,133 
+40,337 
+Statement of Cash Flows Data 
+Net cash provided by operating activities 
+$ 
+118,567 
+$ 
+86,852 
+$ 
+94,387 
+$ 
+54,475 
+$ 
+51,290 
+Net cash used in investing activities 
+(866,287)
+(259,160)
+(452,501)
+(79,804)
+(93,703)
+Net cash provided by (used in) financing activities 
+1,399,489 
+172,564 
+356,070 
+27,202 
+(243)
+Balance Sheet Data 
+Total oil and natural gas properties 
+$ 
+1,475,401 
+$ 
+711,386 
+$ 
+742,155 
+$ 
+324,187 
+$ 
+269,521 
+Total assets 
+2,267,587 
+788,594 
+863,346 
+423,953 
+378,173 
+Long-term debt (b) 
+390,219 
+328,565 
+321,576 
+75,748 
+120,668 
+Stockholders' equity 
+1,733,402 
+362,758 
+433,735 
+279,094 
+205,971 
+Proved Reserves Data 
+Total oil (MBbls) 
+71,145 
+43,348 
+25,733 
+11,898 
+10,780 
+Total natural gas (MMcf) 
+122,611 
+65,537 
+42,548 
+17,751 
+19,753 
+Total (MBOE) 
+91,580 
+54,271 
+32,824 
+14,857 
+14,072 
+Standardized measure (c) 
+$ 
+809,832 
+$ 
+570,890 
+$ 
+579,542 
+$ 
+283,946 
+$ 
+231,148 
+ 
+(a) 
+Net loss for 2015 include d the recognition of a write-down of oil and natural gas properties of $208,435 as a result of the ceiling test limitation and $108,843 of income tax expense related to the recognition of a valuation allowance. Ne t loss fo r 2016 included the recognition of a write-down of oil and natural gas properties of $95,788 as a result of the ceiling test limitation. See Notes 11 and 13 in the Footnotes to the Financial Statements for additional information. 
+(b) 
+See Note 5 in the Footnotes to the Financial Statements f or additional information. 
+(c) 
+Standardized measure is the future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet. Prices are based on either the preceding 12-months’ average price, based on closing prices on the first day of each month, or prices defined by existing contractual arrangements. Future production and development costs are based on current estimates with no escalations. Estimated future cash flows have been discounted to their present values based on a 10% discount rate. See Note 13 in the Footnotes to the Financial Statements for additional information. 
+ 
+ 
+37 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+ITEM 7. Mana gement’s Discussion and Analysis of Financial Condition and Results of Operations 
+ 
+General 
+ 
+The following management’s discussion and analysis describes the principal factors affecting the Company’s results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying audited consolidated financial statements, information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results, which are included in various parts of this filing. Our w ebsite address is www.callon.com . All of our filings with the SEC are available free of charge through our w ebsite as soon as reasonably practicable after we file them with, or furnish them to, the SEC. Information on our w ebsite does not form part of this report on Form 10-K. 
+ 
+We are an independent oil and natural gas company established in 1950. We are focused on the acquisition, development, exploration and exploitation of unconventional, onshore, oil and natural gas reserves in the Permian Basin in West Texas . Our operating culture is centered on responsible development of hydrocarbon resources, safety and the environment, which we believe strengthens our operational performance. Our drilling activity is predominantly focused on the horizontal development of several prospective intervals, including multiple levels of the Wolfcamp formation and, more recently, the Lower Spraberry shale s . We have assembled a multi-year inventory of potential horizontal well locations and intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swap s. Our production was approxim ately 77% oil and 23% natu ral gas for the year ended December 31, 2016 . On December 31, 2016 , our net acreage position in the Permian Basi n was 39,570 net ac res , excluding acreage re l ated to our recently completed acquisition in the Delaware sub-basin. See Note 3 in the Footnotes to the Financial Statements for additional information about the Company’s acquisitions . 
+ 
+Commodity Prices 
+ 
+The prices for oil and natural gas remain extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and actions by the Organization of Petroleum Exporting Countries and other countries and government actions. Prices of oil and natural gas will affect the following aspects of our business: 
+ 
+· 
+our revenues, cash flows and earnings; 
+· 
+the amount of oil and natural gas that we are economically able to produce; 
+· 
+our ability to attract capital to finance our operations and cost of the capital; 
+· 
+the amount we are allowed to borrow under our senior secured revolving credit facility; and 
+· 
+the value of our oil and natural gas properties . 
+ 
+Beginning in the second half of 2014, the NYMEX price for a barrel of oil declined from $105.37 on June 30, 2014 t o $26.21 on February 11, 2016 . For the year ended December 31, 2016 , the average NYMEX price for a barrel of oil was $43.39 per B bl compared to $48.82 per Bbl for the same period of 2015 . The NYMEX price for a barrel of oil ranged from a low of $26.21 per Bbl to a high of $54.06 per Bbl for the year ended December 31, 2016 . 
+ 
+For the year ended December 31, 2016 , the average NYMEX price for natural gas was $2.46 per MMBtu compared to $2.66 per MMBtu for the same period in 2015 . The NYMEX price for natural gas ranged from a low of $1.64 per MMBtu to a high of $3.93 per MMBtu for the year ended December 31, 2016 . 
+ 
+38 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+The table below presents the cumulative results of the full cost ceiling test along with various pricing scenarios to demonstrate the sensitivity of our full cost ceiling and estimated total proved reserve volumes to changes in 12-month average oil and natural gas prices. This sensitivity analysis is as of December 31, 2016 and, accordingly, does not consider drilling results, production, changes in oil and natural gas prices, and changes in future development and operating costs subsequent to December 31, 2016 that may require revisions to our proved reserve estimates and resulting estimated future net cash flows used in the full cost ceiling test. The volumes resulting from the sensitivity analysis, which are for illustrative purposes only, incorporate a number of assumptions and have not been audited by the Company’s third-party engineer. 
+ 
+ 
+ 
+Ceiling Test Analysis 
+Reserve Analysis 
+Pricing Scenarios 
+12-Month Average Prices 
+Excess (Deficit) 
+of Full Cost 
+Ceiling Over Net 
+Capitalized Costs (a) 
+Estimated Total 
+Proved Reserves 
+ 
+Oil ($/Bbl) 
+Natural gas ($/Mcf) 
+(in thousands) 
+(MBOE) 
+December 31, 2016 Actual 
+$ 
+42.75 
+$ 
+2.48 
+$ 
+12,841 
+91,580 
+ 
+Combined price sensitivity 
+Oil and natural gas +10% 
+$ 
+47.03 
+$ 
+2.73 
+$ 
+166,622 
+92,379 
+Oil and natural gas -10% 
+$ 
+38.47 
+$ 
+2.23 
+$ 
+(140,304)
+90,551 
+Oil price sensitivity 
+Oil +10% 
+$ 
+47.03 
+$ 
+2.48 
+$ 
+152,993 
+92,201 
+Oil -10% 
+$ 
+38.47 
+$ 
+2.48 
+$ 
+(126,674)
+90,816 
+Natural gas sensitivity 
+Natural gas +10% 
+$ 
+42.75 
+$ 
+2.73 
+$ 
+26,789 
+91,708 
+Natural gas -10% 
+$ 
+42.75 
+$ 
+2.23 
+$ 
+(470)
+91,433 
+ 
+(a) 
+The Company uses the full cost method of accounting for its exploration and development activities. Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full cost ceiling amount). These rules require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ce iling. For the year ended December 31, 2016 , the Company recorded a $95.8 million write-down of oil and natural gas properties as a result of the ceiling test limitation primarily driven by a 15 % decrease in the 12-month average realized price of oil from $50.16 per barrel as of December 31, 2015 to $42.75 per barrel as of December 31, 2016 . If commodity prices were to decline, we could incur additional ceiling test write-downs in the future. However, we do not expect such prevailing commodity prices to have significant adverse effects on our proved oil and gas reserve quantitie s. See Notes 2 and 13 i n the Footnotes to the Financial Statements for more information. 
+ 
+Significant accomplishments for 2016 include: 
+ 
+· 
+i ncreased annual production in 2016 by 59% to 5,573 M BOE as compared to 2015 ; 
+· 
+i ncreased 2016 proved reserves by 69% t o 91.6 MMBOE as compared to 2015 ; 
+· 
+d rilled and completed our 100 th horizontal well in the Midland Basin; 
+· 
+e ntered into agreements for multiple acquisitions , creating two new core operating areas and increasing our total acreage footprint by approximatel y 41,000 n et acres; 
+· 
+e nhanced f inancial flexibility through the completion of f our strategic equity offerings for $1.4 b i llion in net proceeds , funding acquisition growth, increasing liquidity and reducing leverage ; 
+· 
+i ssued $400 million in unsecured senior notes in a Rule 144A private offering, reducing our cost of term debt; and 
+· 
+a chieved an OSHA Recordable Incident Rate (“ORIR”), o f 0. 58, wel l below the reported range by other similar sized operators in the Permian Basin and below our average ORIRs reported for the past three years . 
+ 
+Operational Highlights 
+ 
+A ll of our producing properties are located in the Permian Basin. As a result of our acquisition and horizontal development efforts, our production gre w 59% in 2016 compared to 2015 , increasing to 5,573 MBO E from 3,508 MBOE. Our production in 2016 was approxim ately 77% oil and 23% natur al gas. 
+ 
+During 2016 , we o perated with one horizontal rig , after placing a second rig on standby in January 2016, and then operated with two horizontal rigs after returning the second one to service in August 2016. For the year ended December 31, 2016, we dri lled 29 gross 
+39 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+( 20.9 net) horizontal wells, completed 32 gross ( 23.7 net) horizontal wells and had six gross ( 4.2 net) hor izontal wells awaiting completion. 
+ 
+Reserve Growth 
+ 
+As of December 31, 2016 , our estimated net proved reser ves increased 69% t o 91.6 MMBOE compared to 54.3 MMBOE of estimated net proved reserves at year-end 2015 . O ur significant growth in proved reserves was primarily attributable to our horizontal development and acquisiti on efforts . Our prov ed reserves at year-e nd 2016 were 78% oil and 22% natural gas, compared to 80% oil and 20% natural gas at year-end 2015 . 
+ 
+Liquidity and Capital Resources 
+ 
+Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions, the sale of debt and equity securities , and asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration and exploitation of oil and natural gas properties, in addition to r efinancing of debt instruments. 
+ 
+In 2016 , we completed f our common stock offerings and completed a debt offering to raise additional capital . In addition, we amended the borrowing base under our senior secured revolving credit facility to $500 million with a current elected commitment level of $385 million , providing us with additional liquidity. W e continue to evaluate other sources of capital to complement our cash flow from operations and other sources of capit al as we pursue our long-term growth plans. 
+ 
+For the year ended December 31, 2016 , c ash and cash equiv alents in creased $651.8 million to $653.0 million compared to $1.2 million at December 31, 2015 . As of February 22, 2017 , our available liq uidity was $48.9 milli on. 
+ 
+Liquidity and cash flow 
+ 
+ 
+For the Year Ended December 31, 
+(in millions) 
+2016 
+2015 
+2014 
+Net cash provided by operating activities 
+$ 
+118.6 
+$ 
+86.8 
+94.4 
+Net cash used in investing activities 
+(866.3)
+(259.2)
+(452.5)
+Net cash provided by financing activities 
+1,399.5 
+172.6 
+356.1 
+Net change in cash 
+$ 
+651.8 
+$ 
+0.2 
+$ 
+(2.0)
+ 
+Operating activities. For the year ended December 31, 2016 , net cash provided by operating activities wa s $118.6 mill ion, compared to $86.8 million for the same period in 2015 . Th e change in operating activities was predominantly attributable to the following: 
+ 
+· 
+a n increase in revenue, offset by a decrease i n settlements of derivative contracts ; 
+· 
+a n increase in certain operating expenses related to acquired properties; 
+· 
+a n increase in payments i n cash-settled restricted stock unit (“RSU”) awards; 
+· 
+a decrease in payments related to nonrecurring early retirement expenses that were incurred in 2015; and 
+· 
+a change related to the timing of working capital payments and receipts. 
+ 
+Production, realized prices, and operating expenses are discussed below in Results o f Operations. See Notes 6 and 7 in the Footnotes to the Financial Statements for a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation. See Note 3 in the Footnotes to the Financial Statements for more information on the Company’s acquisitions. 
+ 
+Investing activities . For the year ended December 31, 2016 , net cash used in investing activities w as $866 millio n compared to $259 million for the same period in 2015 . The change in investing activities was primarily attributable to the following: 
+ 
+· 
+a $37 m il lion decrease in o perational expenditures primarily due to the transition from a two-rig to a one-rig program in January 2016, offset in part by the release of a vertical rig in April 2015 and the transition back to a two-rig program in August 2016; and 
+· 
+a $644.4 millio n increase in acquisitions, net of proceeds from the sale of mineral interest and equipment. In addition, there was a $46.1 million security deposit in relation to the Ameredev Transaction. The acquisitions were funded with cash and common stock. 
+40 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Our investing activities , on a cash basis, include the following for the periods indicated (in millions): 
+ 
+ 
+ 
+ 
+For the Year Ended December 31, 
+ 
+2016 
+2015 
+$ Change 
+Operational expenditures 
+$ 
+143.9 
+$ 
+205.7 
+$ 
+(61.7)
+Seismic, leasehold and other 
+13.6 
+— 
+13.6 
+Capitalized general and administrative expenses 
+12.7 
+11.1 
+1.6 
+Capitalized interest expense 
+19.9 
+10.5 
+9.4 
+Total capital expenditures (a) 
+190.1 
+227.3 
+(37.2)
+ 
+Acquisitions 
+654.7 
+32.2 
+622.5 
+Acquisition deposits 
+46.1 
+— 
+46.1 
+Proceeds from the sale of mineral interest and equipment 
+(24.5)
+(0.4)
+(24.1)
+Total investing activities 
+$ 
+866.4 
+$ 
+259.2 
+607.2 
+ 
+(a) 
+O n an accrual (GAAP) basis, which is the methodology used for establishing our annual capital budget, operational expenditures for t he year ended December 31, 2016 we re $142.7 million . Inclusive of c apitalized general and administrative expenses and capitalized interest expenses , total capital expenditures were $196.2 millio n . 
+ 
+General and administrative expenses and capitalized interest are discussed below in Results of Operations. See Note 3 in the Footnotes to the Financial Statements for additional information on significant acquisitio ns. 
+ 
+F inancing activities. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our senior secured revolving credit facili ty, term debt and equity offerings. For the year ended December 31, 2016 , net cash provided by financing activities was $1.4 mill ion compared to cash provided by financing activities of $173 million during the same period of 2015 . The change in net cash provided by fina ncing activities was primarily attributable to the following: 
+ 
+· 
+p ayments, net of borrowings, on our Credit Facili ty were $40 million, $45 million more than the same period of 2015 ; 
+· 
+a $1.2 b illion increase in proceeds resulting f rom f our common stock offerings in 201 6 that raised $1.4 b illion as compared to two offerings in 201 5 that raised $175 million; and 
+· 
+a $ 100 million increase in borrowings on fixed-rate debt, resulting from the issuance of $400 milli on of 6.125% senior unsecured senior notes due 2024, net of the repayment of the Company’s secured second lien term loan . 
+ 
+Net cash provided by financing activities includes the following for the periods indicated (in millions): 
+ 
+ 
+ 
+For the Year Ended December 31, 
+ 
+2016 
+2015 
+$ Change 
+Net borrowings on senior secured revolving credit facility 
+$ 
+(40.0)
+$ 
+5.0 
+$ 
+(45.0)
+Payments on term loans 
+(300.0)
+— 
+(300.0)
+Issuance of 6.125% senior unsecured notes due 2024 
+400.0 
+— 
+400.0 
+Payment of deferred financing costs 
+(10.8)
+— 
+(10.8)
+Issuance of common stock 
+1,357.6 
+175.5 
+1,182.1 
+Payment of preferred stock dividends 
+(7.3)
+(7.9)
+0.6 
+Net cash provided by financing activities 
+$ 
+1,399.5 
+$ 
+172.6 
+$ 
+1,226.9 
+ 
+See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s debt. See Note 10 in the Footnotes to the Financial Statements for additional information about the Company’s equity offerings and Series A 10% Cumulative Preferred Sto ck . 
+ 
+Senior secured revolving credit facility (“Credit Facility”) 
+ 
+The total notional amount available under the Company’s Credit Facility is $500 million. Effective November 21, 2016, the Company achieved an indication to increase the Credit Facility’s borrowing base to $500 million, but elected to maintain commitments from lenders at $385 million. As of December 31, 2016 , the Credit Facility had no balance outstanding . 
+ 
+For the year ended December 31, 2016, the Credit Facility had a weighted-average interest rate o f 2.60% , c alculated as the LIBOR plus a tiered rate ranging from 2.00% to 3.00% , which is determined based on utilization of the facility. In addition, the Credit Facility carries a commitment fee of 0.5% per annum, payable quarterly, on the unused portion of the borrowin g base . 
+ 
+See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s Credit Facility . 
+41 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+ 
+Term loan 
+On October 11, 2016, the secured second lien term loan (the “Second Lien Loan”) was repaid in full at the prepayment rate of 101% using proceeds from the sale of the 6.125% senior unsecured notes due 2024, which resulted in a loss on early extinguishment of d ebt of $12.9 million (inclusive of $3.0 million in prepayment fees and $9.9 million of unamortized debt issuance costs). 
+ 
+See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s Second Lien Loan . 
+ 
+6.125% senior notes due 2024 
+ 
+On October 3, 2016, the Company issued $ 400 million aggregate principal amount of 6.125% Senior Notes with a maturity date of October 1, 2024 and interest payable semi-annually beginning on April 1, 2017. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $391 .3 million . The 6.125% Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. 
+ 
+The Company may redeem the 6.125% Senior Notes in accordance with the contractual redemption terms . Following a change of control, each holder of the 6.125% Senior Notes may require the Company to repurchase all or a portion of the 6.125% Senior Notes at a price of 101% of pr incipal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase. 
+ 
+See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s 6.125% Senior Notes . 
+ 
+10% Series A Cumulative Preferred Stock (“Preferred Stock”) 
+ 
+Holders of the Company’s Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10.0% per annum of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share). Dividends are payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by our Board of Directors. Preferred Stock dividends w ere $7.3 mill ion in 2016 . 
+ 
+The Preferred Stock has no stated maturity and is not subject to any sinking fund or other mandatory redemption. On or after May 30, 2018, the Company may, at its option, redeem the Preferred Stock, in whole or in part, by payin g $50.00 per share, plus any accrued and unpaid dividends to the redemption date. 
+ 
+On February 4, 2016, the Company exchanged a total of 120,000 shares of Preferred Stock for 719,000 shares of common stock. As of December 31, 2016, the Company had 1,458,948 shares of its Preferred Stock issued and outstandi ng. 
+ 
+See Note 10 in the Footnotes to the Financial Statements for additional i nformation about the Company’s Preferred Sto ck . 
+ 
+201 7 Capital Plan and Outlook 
+ 
+Our operational capital budget for 2017 has been established in the range of $325 to $350 m illion on an accrual, or GAAP, basis, inclusive of a planned transition from a three -rig program that commenced in January 2017 to a four - rig program by July 2017 that would include horizontal development activity at our recent Delaware Basin acquisition (see Note 3 in the Footnotes to the Financial Statements for information on this acquisition). 
+ 
+As part of our 2017 operated horizontal drilling program we expect to place 33 – 36 net horizontal wells on production with lateral lengths ranging from 5,000’ to 10,000’. We have also budgeted approximately $7.5 to $10 million for non-operated operational activity. 
+ 
+In addition to the operational capital expenditures budget, which includes well costs, facilities and infrastructure capital, and surface land purchases, we budgeted an estimated $40 to $45 million for capitalized general and administrative expenses and capitalized interest expenses, both on an accrual, or GAAP, basis. 
+ 
+Our revenues, earnings, liquidity and ability to grow are substantially dependent on the prices we receive for, and our ability to develop our reserves of oil and natural gas. Despite a continued lo w price en vironment, we believe the long-term outlook for our business is favorable due to our resource base, low cost structure, financial strength, risk management, including commodity hedging strategy, and disciplined investment of capital. We monitor current and expected market conditions, including the commodity price environment, and our liquidity needs and may adjust our capital investment plan accordingly. 
+ 
+ 
+42 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Contractual Obligations 
+ 
+The following table includes the Company’s current contractual obligations and purchase commitments (in thousands): 
+ 
+ 
+ 
+ 
+Payments due by Period 
+ 
+Total 
+< 1 Year 
+Years 2 - 3 
+Years 4 - 5 
+>5 Years 
+6.125% Senior Notes (a) 
+$ 
+400,000 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+400,000 
+Credit Facility (a)(b) 
+— 
+— 
+— 
+— 
+— 
+Interest expense and other fees related to debt commitments (c) 
+193,943 
+26,265 
+51,303 
+49,000 
+67,375 
+Drilling rig leases (d) 
+20,340 
+13,830 
+6,510 
+— 
+— 
+Office space lease and other commitments 
+2,915 
+825 
+1,263 
+827 
+— 
+Total contractual obligations 
+$ 
+617,198 
+$ 
+40,920 
+$ 
+59,076 
+$ 
+49,827 
+$ 
+467,375 
+ 
+(a) 
+Includes the outstanding principal amount only. 
+(b) 
+As of December 31, 2016, the Credit Facility had no balance outstanding. We cannot predict the timing of future borrowings and repayments. 
+(c) 
+Includes scheduled cash payments on the 6.125% Senior Notes and the minimum amount of commitment fees due on the Credit Facility . 
+(d) 
+Drilling rig leases represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a party on December 31, 2016. See Note 14 in the Footnotes to the Financial Statements for additional information related to drilling rig leases. 
+ 
+43 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Resul ts of Operations 
+ 
+The following table sets forth certain operating information with respect to the Company’s oil and natural gas operat ions for the periods indicated: 
+ 
+ 
+For the Year Ended December 31, 
+2016 
+2015 
+$ 
+Change 
+% Change 
+2014 
+$ Change 
+% Change 
+Net production: 
+Oil (MBbls) 
+4,280 
+2,789 
+1,491 
+53% 
+1,692 
+1,097 
+65% 
+Natural gas (MMcf) 
+7,758 
+4,312 
+3,446 
+80% 
+2,220 
+2,092 
+94% 
+Total (MBOE) 
+5,573 
+3,508 
+2,065 
+59% 
+2,062 
+1,446 
+70% 
+Average daily production (BOE/d) 
+15,227 
+9,610 
+5,617 
+59% 
+5,649 
+3,961 
+70% 
+% oil (BOE basis) 
+77% 
+80% 
+82% 
+Average realized sales price: 
+Oil (Bbl) (excluding impact of cash settled derivatives) 
+$ 
+41.51 
+$ 
+44.88 
+$ 
+(3.37)
+(8)% 
+$ 
+82.37 
+$ 
+(37.49)
+(46)% 
+Oil (Bbl) (including impact of cash settled derivatives) 
+45.67 
+56.82 
+(11.15)
+(20)% 
+84.84 
+(28.02)
+(33)% 
+Natural gas (Mcf) (excluding impact of cash settled derivatives) 
+$ 
+2.99 
+$ 
+2.86 
+$ 
+0.13 
+5% 
+$ 
+5.63 
+$ 
+(2.77)
+(49)% 
+Natural gas (Mcf) (including impact of cash settled derivatives) 
+3.00 
+3.26 
+(0.26)
+(8)% 
+5.59 
+(2.33)
+(42)% 
+Total (BOE) (excluding impact of cash settled derivatives) 
+$ 
+36.04 
+$ 
+39.20 
+$ 
+(3.16)
+(8)% 
+$ 
+73.65 
+$ 
+(34.45)
+(47)% 
+Total (BOE) (including impact of cash settled derivatives) 
+39.25 
+49.18 
+(9.93)
+(20)% 
+75.63 
+(26.45)
+(35)% 
+Oil and natural gas revenues (in thousands): 
+Oil revenue 
+$ 
+177,652 
+$ 
+125,166 
+$ 
+52,486 
+42% 
+$ 
+139,374 
+$ 
+(14,208)
+(10)% 
+Natural gas revenue 
+23,199 
+12,346 
+10,853 
+88% 
+12,488 
+(142)
+(1)% 
+Total 
+$ 
+200,851 
+$ 
+137,512 
+$ 
+63,339 
+46% 
+$ 
+151,862 
+$ 
+(14,350)
+(9)% 
+Additional per BOE data: 
+Sales price (excluding impact of cash settled derivatives) 
+$ 
+36.04 
+$ 
+39.20 
+$ 
+(3.16)
+(8)% 
+$ 
+73.65 
+$ 
+(34.45)
+(47)% 
+Lease operating expense 
+6.88 
+7.71 
+(0.83)
+(11)% 
+10.85 
+(3.14)
+(29)% 
+Production taxes 
+2.13 
+2.79 
+(0.66)
+(24)% 
+4.35 
+(1.56)
+(36)% 
+Operating margin 
+$ 
+27.03 
+$ 
+28.70 
+$ 
+(1.67)
+(6)% 
+$ 
+58.45 
+$ 
+(29.75)
+(51)% 
+ 
+44 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Revenues 
+ 
+The following tables are intended to reconcile the change in oil, natural gas and total revenue for the respective periods presented by reflecting the effect of changes in volume and in the underlying commodity prices. 
+ 
+ 
+(in thousands) 
+Oil 
+Natural Gas 
+Total 
+Revenues for the year ended December 31, 2013 
+$ 
+88,960 
+$ 
+13,609 
+$ 
+102,569 
+Volume increase (decrease) 
+76,237 
+(3,575)
+72,662 
+Price increase (decrease) 
+(25,823)
+2,454 
+(23,369)
+Net increase (decrease) 
+50,414 
+(1,121)
+49,293 
+Revenues for the year ended December 31, 2014 
+$ 
+139,374 
+$ 
+12,488 
+$ 
+151,862 
+Volume increase 
+90,398 
+11,774 
+102,172 
+Price decrease 
+(104,606)
+(11,916)
+(116,522)
+Net decrease 
+(14,208)
+(142)
+(14,350)
+Revenues for the year ended December 31, 2015 
+$ 
+125,166 
+$ 
+12,346 
+$ 
+137,512 
+Volume increase 
+66,916 
+9,856 
+76,772 
+Price increase (decrease) 
+(14,430)
+997 
+(13,433)
+Net increase 
+52,486 
+10,853 
+63,339 
+Revenues for the year ended December 31, 2016 
+$ 
+177,652 
+$ 
+23,199 
+$ 
+200,851 
+ 
+Oil revenue 
+ 
+For the year ended December 31, 2016 , oil r evenues of $178 million in creased $ 52.5 million, or 42% , compared to revenues of $125 million for the same period of 2015 . The in crease in oil revenue was primarily attributable to a 53% increase in production offset by an 8% decreas e in the average realized sales price, which fell to $41.51 per Bbl from $44.88 per Bbl . The increase in production was comprised of 1,182 MBbls attributable to wells placed on production as a result of our horizontal drilling program and 547 MBbls attributable to producing wells added from our acquired properties. Of fset ting these increases were normal and expected declines from our existing wells. 
+ 
+For the year ended December 31, 2015 , oil revenues of $125 million de creased $14.2 million, or 10% , compared to revenues of $139 million for the same period of 2014 . The decrease in oil revenue was primarily attributable to a 46% decrease in the average realized sales price, which fell to $44.88 per Bbl from $82.37 per Bbl, and was predominately offset by a 65% increase in production. The increase in production was primarily attributable to a 1,197 MBbls increase in production from our properties resulting from an increased number of producing wells from our horizontal drilling program and acquisitions, offset by normal and expected declines from our existing wells. 
+ 
+Natural gas revenue (including NGLs) 
+ 
+Natural gas revenue s of $23.2 million in creased $10.9 million, or 88% , during the year ended December 31, 2016 compared to $12.3 million for the same period of 2015 . The in crease primarily relates to an 80% increase in natural gas volumes and a 5% increase in the average price realized, which rose to $2.99 per Mcf from $2.86 per Mcf, reflecting increases in both natural gas and natural gas liquids prices. The increase in production was co mprised o f 1,387 MMcf attributable to wells placed on production as a result of our horizontal drilling program and 1, 025 MMcf attribut able to producing wells added from our acquired properties. In addition, the increase in production was also attributable to the increase in the percentage of natural gas produced in our production stream . 
+ 
+Natural gas revenues of $12.3 million decreased $0.2 millio n, or 1% , during the year ended December 31, 2015 compared to $12.5 million for the same period of 2014 . The decrease primarily relates to 49% decrease in the average price realized, which fell to $2.86 per Mcf from $5.63 per Mcf, reflecting decreases in both natural gas and natural gas liquids prices and was predominantly offset by a 94% increase in natural gas volumes. The increase in production was primarily attributable to increased production of 1,757 MM cf from our properties resulting from an increased number of producing wells . 
+ 
+ 
+45 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Operating Expenses 
+ 
+ 
+ 
+ 
+For the Year Ended December 31, 
+ 
+Per 
+Per 
+Total Change 
+BOE Change 
+(in thousands, except per unit data) 
+2016 
+BOE 
+2015 
+BOE 
+$ 
+% 
+$ 
+% 
+Lease operating expenses 
+$ 
+38,353 
+$ 
+6.88 
+$ 
+27,036 
+$ 
+7.71 
+11,317 
+42% 
+(0.83)
+(11)% 
+Production taxes 
+11,870 
+2.13 
+9,793 
+2.79 
+2,077 
+21% 
+(0.66)
+(24)% 
+Depreciation, depletion and amortization 
+71,369 
+12.81 
+69,249 
+19.74 
+2,120 
+3% 
+(6.93)
+(35)% 
+General and administrative 
+26,317 
+4.72 
+28,347 
+8.08 
+(2,030)
+(7)% 
+(3.36)
+(42)% 
+Accretion expense 
+958 
+0.17 
+660 
+0.19 
+298 
+45% 
+(0.02)
+(11)% 
+Write-down of oil and natural gas properties 
+95,788 
+nm 
+208,435 
+nm 
+(112,647)
+nm 
+nm 
+nm 
+Rig termination fee 
+— 
+nm 
+3,075 
+nm 
+(3,075)
+nm 
+nm 
+nm 
+Acquisition expense 
+3,673 
+nm 
+27 
+nm 
+3,646 
+nm 
+nm 
+nm 
+ 
+ 
+ 
+ 
+For the Year Ended December 31, 
+ 
+Per 
+Per 
+Total Change 
+BOE Change 
+(in thousands, except per unit data) 
+2015 
+BOE 
+2014 
+BOE 
+$ 
+% 
+$ 
+% 
+Lease operating expenses 
+$ 
+27,036 
+$ 
+7.71 
+$ 
+22,372 
+$ 
+10.85 
+4,664 
+21% 
+(3.14)
+(29)% 
+Production taxes 
+9,793 
+2.79 
+8,973 
+4.35 
+820 
+9% 
+(1.56)
+(36)% 
+Depreciation, depletion and amortization 
+69,249 
+19.74 
+56,724 
+27.51 
+12,525 
+22% 
+(7.77)
+(28)% 
+General and administrative 
+28,347 
+8.08 
+25,109 
+12.18 
+3,238 
+13% 
+(4.10)
+(34)% 
+Accretion expense 
+660 
+0.19 
+826 
+0.40 
+(166)
+(20)% 
+(0.21)
+(53)% 
+Write-down of oil and natural gas properties 
+208,435 
+nm 
+— 
+nm 
+208,435 
+nm 
+nm 
+nm 
+Rig termination fee 
+3,075 
+nm 
+— 
+nm 
+3,075 
+nm 
+nm 
+nm 
+Gain on sale of other property and equipment 
+— 
+nm 
+(1,080)
+nm 
+1,080 
+nm 
+nm 
+nm 
+Acquisition expense 
+27 
+nm 
+668 
+nm 
+(641)
+nm 
+nm 
+nm 
+ 
+nm = not meaningful 
+ 
+Lease operating expenses. These are daily costs incurred to extract oil and natural gas, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs, gas treating fees , salt water disposal, insurance and workover expenses related to our oil and natural gas properties. 
+ 
+LOE for the year end ed December 31, 2016 increased by 42% to $38.4 mi llion compared t o $27.0 m illion for the same period o f 2015 . Contributing to the increase for the current period was $7.3 million related to oil and natural gas properties acquired during 2016 (see Note 3 in the Footnotes to the Financial Statements for information about the Company’s acquisitions ). Excluding LOE related to these acquired properties, LOE in creased by $4.0 million, or 15% , compared to the same period of 2015 . LO E per BOE for the year ended December 31, 2016 decreased to $6.88 per BOE compared to $7.71 per BOE for the same period of 2015 , which was primarily attributable to h igher produc tion volumes offset by an increase in cost from workover activity on our legacy properties . The increase in prod uction was primarily attributable to an increased number of producing wells from our horizontal drilling program and acquisitions as discussed above. 
+ 
+LOE for the year ended December 31, 2015 increased by 21% to $27.0 million compared to $22.4 million for the same period of 2014 primarily related to the growth in production and operations as a result of our horizontal drilling program and acquisition efforts. LOE per BOE for the year ended December 31, 2015 decreased to $7.71 per BOE compared to $10.85 per BOE for the same period of 2014. The $3.14 per BOE decrease resulted primarily from a decrease in the number of workovers period over period and the impact of leveraging fixed expe nses over a larger production base . 
+ 
+Production taxes. Production taxes include severance and ad valorem taxes. In general, production taxes are directly related to commodity price changes; however, severance taxes are based upon current year commodity prices, whereas ad valorem taxes are based upon prior year commodity prices. Severance taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. In the counties where our production is located, we are also subject to ad valorem taxes, which are generally based on the taxing jurisdictions’ valuation of our oil and gas properties. 
+ 
+For the year ende d December 31, 2016 , p roduction taxes increased 21% , or $2.1 million, to $11.9 million compared to $9.8 million for the same period of 2015 . The increase was primarily due to an increase in sever ance taxes, which was attributable to the increase in revenue. The increase was offset by a decrease in ad valo rem taxes attributable to a lower valuation of our oil and gas properties by the 
+46 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+taxing jurisdictions. On a per BOE basis, production taxes for the year ended December 31, 2016 decreased by 24% compared to the same period of 2015 . 
+ 
+For the year ended December 31, 2015, production taxes increased 9%, or $0.8 million, to $9.8 million compared to $9.0 million for the same period of 2014. The increase was primarily due to an increase in ad valorem taxes attributable to a greater number of producing wells as a result of our horizontal drilling program and acquisition efforts. Offsetting this increase was a reduction in severance taxes as a result of the decline of oil and natural gas revenu e as previously mentioned. On a per BOE basis, production taxes for the year ended, December 31 , 2015 decreased by 36% compared to the same period of 2014. 
+ 
+Depreciation, depletion and amortization (“DD&A”). Under the full cost accounting method, we capitalize costs within a cost center and then systematically expense those costs on a units-of-production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unevaluated properties, less accumulated amortization; (ii) the estimated future expe nditures to be incurred in developing proved reserves; and (iii) the estimated dism antlement and abandonment costs, net of estimated salvage values. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years. 
+ 
+For the year ended December 31, 2016 , DD&A in creased 3% to $71.4 million from $69.2 million compared to the same period of 2015 . T he increase is primarily attributable to a 59% increase in production, offset by a 35% decrease in our per BOE DD&A rate. The increase in production was primarily attributable to an increased number of producing wells from our horizontal drilling program and acquisitions. For the year ended December 31, 2016, DD&A on a per unit basis decreased to $12.81 per BOE compared to $19.74 per BOE for the same period of 2015 . The decrease is attributable to our increased estimated proved reserves relative to our depreciable base and assumed future development costs related to undeveloped proved reserves as a result of additions made through our horizontal drilling efforts and acquisitions, offset by the write down of oil and natural gas properties in the first half of 2016. 
+ 
+For the year ended December 31, 2015, DD&A increased 22% to $69.2 million from $56.7 million compared to the same period of 2014. The increase is primarily attributable to a 70% increase in production, offset by a 28% decrease in our per BOE DD&A rate. The increase in production was primarily attributable to an increased number of producing wells from our horizontal drilling program and acquisitions. For the year ended December 31, 2015, DD&A on a per unit basis decreased to $19.74 per BOE compared to $27.51 per BOE for the same period of 2014 as a result of the increase in o ur estimated proved reserves relative to our depreciable base as a result of our efforts on development, exploration, and exploitation of onshore oil and natural gas reserves in the Permian Basin and the write-down of oil and natural gas properties. 
+ 
+General and administrative, net of amounts capitalized (“G&A”). These are costs incurred for overhead, including payroll and benefits for our corporate staff, severance and early retirement expenses, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, depreciation of corporate level assets, public company costs, vesting of equity and liability awards under share-based compensation plans and related mark-to-market valuation adjustments over time, fees for audit and other professional services, and legal compliance. 
+ 
+G&A for the year ended December 31, 2016 de creased to $ 26.3 million comp ared to $28.3 million for the same period of 2015 . G&A expenses for the periods indicated include the following (in millions): 
+ 
+ 
+For the Year Ended December 31, 
+ 
+2016 
+2015 
+$ Change 
+Recurring expenses 
+G&A 
+$ 
+16.5 
+$ 
+15.1 
+$ 
+1.4 
+Share-based compensation 
+2.7 
+2.1 
+0.6 
+Fair value adjustments of cash-settled RSU awards 
+6.9 
+6.1 
+0.8 
+Non-recurring expenses 
+Early retirement expenses 
+— 
+3.5 
+(3.5)
+Early retirement expenses related to share-based compensation 
+— 
+1.1 
+(1.1)
+Expense related to a threatened proxy contest 
+0.2 
+0.4 
+(0.2)
+Total G&A expenses 
+$ 
+26.3 
+$ 
+28.3 
+$ 
+(2.0)
+ 
+47 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+G&A for the year ended December 31, 2015 increased to $28.3 million compared to $25.1 million for the same period of 2014. G&A expenses for the periods indicated include the following (in millions) : 
+ 
+ 
+For the Year Ended December 31, 
+ 
+2015 
+2014 
+$ Change 
+Recurring expenses 
+G&A 
+$ 
+15.1 
+$ 
+15.3 
+$ 
+(0.2)
+Share-based compensation 
+2.1 
+2.7 
+(0.6)
+Fair value adjustments of cash-settled RSU awards 
+6.1 
+3.1 
+3.0 
+Non-recurring expenses 
+Early retirement expenses 
+3.5 
+1.4 
+2.1 
+Early retirement expenses related to share-based compensation 
+1.1 
+1.1 
+— 
+Expense related to a threatened proxy contest 
+0.4 
+1.5 
+(1.1)
+Total G&A expenses 
+$ 
+28.3 
+$ 
+25.1 
+$ 
+3.2 
+ 
+Accretion expense. The Company is required to record the estimated fair value of liabilities for obligations associated with the retirement of tangible long-lived assets and the associated ARO costs. Interest is accreted on the present value of the ARO and reported as accretion expense within operating expenses in the consolidated statements of operations. 
+ 
+Accretion expense related to our AR O in creased 45% for the year ended December 31, 2016 compared to the same period of 2015 . A ccretion expense generally correlates with the Company’s average AR O, which was $5.6 million at December 31, 2016 versus $5.4 million at December 31, 2015 . See Note 12 in the Footnotes to the Financial Statements for additional information regarding the Company’s ARO. 
+ 
+Accretion expense related to our ARO decreased 20% for the year ended December 31, 2015 compared to the same period of 2014. Accretion expense generally correlates with the Company’s average ARO, which was $5.4 million at December 31, 2015 versus $6.5 million at December 31, 2014 . 
+ 
+Wr i te-down of oil and natural gas properties . Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full cost ceiling amount). T hese rules require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling. 
+ 
+For the year ended December 31, 2016, the Company recognized a write-down of oil and natural gas propertie s of $95.8 milli on as a result of the ceiling test limitatio n, primarily driven by a 15% decrease in the 12-month average realized price of oil from $50.16 per barrel as of December 31, 201 5 to $42.75 per barrel as of December 31, 2016 . F o r the year ended December 31, 2015, the Company recognized a write-down of $208.4 million as a result of the ceiling test limitation , primarily driven by a 47% decrease in the 12-month average realized price of oil from $94.99 per barrel as of December 31, 2014 to $42.75 per barrel as of December 31, 2015 . If commodity prices were to decline, we could incur additional ceiling test write-downs in the future. See Notes 2 and 13 in the Foot notes to the Financial Statements for additional information. 
+ 
+Rig termination fee. For the year ende d December 31, 2015, t he Company recognize d $3.1 m illion in expense related to the early termination of the contract for its vertical rig. See Note 14 in the Footnotes to the Financial Statements for additional information. 
+ 
+Acquisition expense. Acquisitio n expense increased $3.6 million for the year ended December 31, 2016 compared to the same period of 2015 and decrea sed $3.6 million for the year ended December 31, 2016 co mpared to the same period of 2014 . A cquisition expense is relate d to costs with respect to our acquisition efforts in the Permian Basin. See Note 3 in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions. 
+ 
+Gain on sale of other property and equipment . During 2014, the Company entered into an agreement to sell certain specialized deep water equipment that resulted in a gain on the sale of other property and equipment of $1.1 million . 
+ 
+ 
+48 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+O ther Income and Expenses and Preferred Stock Dividends 
+ 
+ 
+ 
+ 
+For the Year Ended December 31, 
+(in thousands) 
+2016 
+2015 
+$ Change 
+% Change 
+Interest expense, net of capitalized amounts 
+$ 
+11,871 
+$ 
+21,111 
+$ 
+(9,240)
+(44)% 
+Loss on early extinguishment of debt 
+12,883 
+— 
+12,883 
+nm 
+(Gain) loss on derivative contracts 
+20,233 
+(28,358)
+48,591 
+(171)% 
+Other income, net 
+(637)
+(198)
+(439)
+222% 
+Total 
+$ 
+44,350 
+$ 
+(7,445)
+ 
+Income tax (benefit) expense 
+$ 
+(14)
+$ 
+38,474 
+$ 
+(38,488)
+(100)% 
+Preferred stock dividends 
+(7,295)
+(7,895)
+600 
+(8)% 
+ 
+ 
+ 
+ 
+For the Year Ended December 31, 
+(in thousands) 
+2015 
+2014 
+$ Change 
+% Change 
+Interest expense, net of capitalized amounts 
+$ 
+21,111 
+$ 
+9,772 
+11,339 
+116% 
+Gain on early extinguishment of debt 
+— 
+(151)
+151 
+nm 
+Gain on derivative contracts 
+(28,358)
+(31,736)
+3,378 
+(11)% 
+Other income, net 
+(198)
+(515)
+317 
+(62)% 
+Total 
+$ 
+(7,445)
+- 
+$ 
+(22,630)
+- 
+- 
+ 
+Income tax expense 
+$ 
+38,474 
+$ 
+23,134 
+$ 
+15,340 
+66% 
+Preferred stock dividends 
+(7,895)
+(7,895)
+— 
+nm 
+ 
+Interest expense , net of capitalized amounts . We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our C redit F acility or with term debt. We i ncur interest expense that is affected by both fluctuations in interest rates and our financing d ecisions. We reflect interest paid to our lender in interest expense , net of capitalized amounts . In addition, we include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees in interest expense. The amortization of deferred credit related to our 13% s enior unsecured n otes due 2016 (“13% Senior Notes”) was recorded as an offset to interest expense until the notes were redeemed in April 2014 . 
+ 
+Interest expense , net of capitalized amounts, incurred during the year ended December 31, 2016 de creased $9.2 million to $11.9 million compared to $21.1 million for the same period of 2015 . The de crease is primarily attributable t o a $9.4 milli on increase i n capitalized interest compared to the 2015 period, resul ting from a higher average unevaluated property balance for the year ended December 31 , 2016 as compared to the same period of 2015 . The increase in unevaluated property was primarily due to acquired properties (see Note 3 in the Footnotes to the Financial Statements for information about the Company’s acquisitions) . Offsetting the decrease was a $0.2 million increase in intere st expense related to our debt due to a higher average debt balance for the year ended December 31, 2016 as compared to the same period of 2015 , resulting from the issuance of our 6.125% Senior Notes in November 2016 . 
+ 
+Interest expense incurred during the year ended December 31, 2015 increased $11.3 million to $21.1 million compared to $9.8 million for the same period of 2014. The increase is primarily attributable to the $18.8 million increase in expense related to a higher outstanding average debt balance of $372.3 million in 2015 compared to $174.0 million in 2014. Offsetting the increase is a $6.2 million increase in capitalized interest compared to the 2014 period, resulting from a higher average unevaluated property balance for the year ended December 31 , 2015 as compared to the same period of 2014, and a $1.3 million decrease in interest expense related to the full redemption of our 13% Senior Notes in April 2014. 
+ 
+Gain (loss) on the early extinguishment of debt. During October 2016, the Second Lien Loan was repaid in full at the prepayment rate of 101% using proceeds from the sale of the 6.125% senior unsecured notes due 2024, which resulted in a loss on early extinguishment of deb t of $12.9 million (inclusive of $3.0 million in prepayment fees and $9.9 mil lion of unamortized debt issuance costs). 
+ 
+During April 2014, the Company completed a full redemption of the remaining $53.3 million carrying value of its outstanding 13% Senior Notes using proceeds from the issuance of a secured second lien term loan . The carrying value included $48.5 million of principal value and $4.8 million of unamortized deferred credit. The Company recognized a net $3.2 million gain on early extinguishment of debt, comprised of the recognition of $4.8 million in deferred credit, offset by $1.6 million of redemption expenses. See Note 5 for additional information concerning the gain on early extinguishment of debt. 
+ 
+During October 2014, the Company repaid in full the existing term loan using proceeds from the Second Lien Loan resulting in a loss on early extinguishment of debt of $3.1 million. The loss was comprised of a $1.7 million prepayment premium and the recognition of 
+49 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+$1.4 million of unamortized issuance cost s . See Note 5 for additional information concerning the loss on the early extinguishment of debt. 
+ 
+Gain ( loss ) on derivative instruments. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in commodity prices. This amount represents the (i) gain ( loss ) related to fair value adjustments on our open derivative contracts and (ii) gain s ( loss e s ) on settlements of derivative contracts for positions that have settled within the period. 
+ 
+For the year ended December 31, 2016 , the net loss on derivative instrumen ts was $20.2 millio n, compared to a $28.4 million net gain in 2015 . The n et gain ( loss ) on derivative instruments for the periods indicated includes the following (in millions): 
+ 
+ 
+ 
+ 
+For the Year Ended December 31, 
+ 
+2016 
+2015 
+$ Change 
+Natural gas derivatives 
+Net gain on settlements 
+$ 
+0.1 
+$ 
+1.7 
+$ 
+(1.6)
+Net loss on fair value adjustments 
+(0.6)
+(1.2)
+0.6 
+Total gain (loss) 
+$ 
+(0.5)
+$ 
+0.5 
+$ 
+(1.0)
+Oil derivatives 
+Net gain on settlements 
+$ 
+17.8 
+$ 
+33.3 
+$ 
+(15.5)
+Net loss on fair value adjustments 
+(37.5)
+(5.4)
+(32.1)
+Total gain (loss) 
+$ 
+(19.7)
+$ 
+27.9 
+$ 
+(47.6)
+ 
+Total gain (loss) on derivative contracts 
+$ 
+(20.2)
+$ 
+28.4 
+$ 
+(48.6)
+ 
+For the year ended December 31, 2015, the net gain on derivative instruments was $28.4 million, compared to a $31.7 million net gain in 2014. The net gain (loss) on derivative instruments for the periods indicated includes the following (in millions): 
+ 
+ 
+ 
+ 
+For the Year Ended December 31, 
+ 
+2015 
+2014 
+$ Change 
+Natural gas derivatives 
+Net gain (loss) on settlements 
+$ 
+1.7 
+$ 
+(0.1)
+$ 
+1.8 
+Net gain (loss) on fair value adjustments 
+(1.2)
+1.3 
+(2.5)
+Total gain 
+$ 
+0.5 
+$ 
+1.2 
+$ 
+(0.7)
+Oil derivatives 
+Net loss on settlements 
+$ 
+33.3 
+$ 
+4.1 
+$ 
+29.2 
+Net gain (loss) on fair value adjustments 
+(5.4)
+26.4 
+(31.8)
+Total gain 
+$ 
+27.9 
+$ 
+30.5 
+$ 
+(2.6)
+ 
+Total gain on derivative contracts 
+$ 
+28.4 
+$ 
+31.7 
+$ 
+(3.3)
+ 
+See Notes 6 and 7 in the Footnotes to the Financial Statements for additional information o n the Company’s derivative contracts and disclosures related to derivative instruments. 
+ 
+Income tax expense. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. When appropriate based on our analysis, we record a valuation allowance for deferred tax assets when it is more likely than not that the deferred tax assets will not be realized. 
+ 
+The Company had an inco me tax benefit of less th an $0.1 mi lli on for the year ended December 31, 2016 compared to an income tax expense of $38.5 million for the same period of 2015 . The change in income tax is primarily related to recording a valuation allowance of $108.8 in 2015 and the difference in the amount of income (loss) before income taxes between periods. The effective tax rate o f 0% in 2016 and (19)% in 2015 differed from the federal income tax rate of 35% primarily due to the valuation allowance for the comparative periods, the effect of state taxes, and non-deductible executive compensation expenses. 
+ 
+The Company had an income tax expense of $38.5 million for the year ended December 31 , 2015 compared to an income tax expense of $23.1 million for the same period of 2014. The increase in income tax expense is primarily related to the establishment of a valuation 
+50 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+allowance of $108.8 million in 2015 and the difference in the amount of income (loss) before income taxes between periods. The effective tax rate of (19)% in 2015 and 38% in 2014 differed from the federal income tax rate of 35% primarily due to the valuation allowance established in 2015, the effect of state, taxes, and non-deductible executive compensation expenses. 
+ 
+For additional information, s ee Note 11 to the Consolidated Financial Statements. 
+ 
+Preferred stock dividends . Preferred s tock dividends for the year ended December 31, 2016 d ecreas ed $0.6 million c ompared to the same period of 2015 . The decrease was due to a decrease in the number of preferred shares outstanding , attributable to a partial share conversion in February 2016 in which the Company exchanged a total of 120,000 shares of Preferred Stock for 719,000 shares of common stock. Preferred stock dividends for the year ended December 31 , 2015 were consistent with the same period of 2014. Dividends reflect a 10% dividend yield. See Note 10 in the Footnotes to the Financial Statements for additional information. 
+ 
+Summary of Significant Accounting Policies and Critical Accounting Estimates 
+ 
+The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been use d . Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under GAAP. We also describe the most significant estimates and assumptions we make in applying these policies. See Note 2 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K for a discussion of additional accounting policies and estimates made by management. 
+ 
+Oil and natural gas p ropert ies 
+ 
+The Company utilizes the full cost method of accounting for its oil and natural gas properties whereby all costs incurred in connection with the acquisition, exploration and development of oil and natural gas reserves, including certain overhead costs, are capitalized into the “full cost pool.” The amounts capitalized into the full cost pool are depleted (charged against earnings) using the unit-of-production method. The full cost method of accounting for oil and natural gas properties requires that the Company makes estimates based on its assumptions of future events that could change. These estimates are described below. 
+ 
+Depreciation, depletion and amortization (DD&A) of oil and natural gas properties 
+ 
+The Company calculates DD&A by using the depletable base, which is equal to the net capitalized costs in our full cost pool plus estimated future development costs, and the estimated net proved reserve quantities. Capitalized costs added to the full cost pool include the following: 
+ 
+· 
+costs of drilling and equipping productive wells, dry hole costs, acquisition costs of properties with proved reserves, delay rentals and other costs related to exploration and development of our oil and natural gas properties; 
+· 
+payroll costs including the related fringe benefits paid to employees directly engaged in the acquisition, exploration and/or development of oil and natural gas properties as well as other directly identifiable general and administrative costs associated with such activities. Such capitalized costs do not include any costs related to the production of oil and natural gas or general corporate overhead; 
+· 
+costs associated with unevaluated properties, those lacking proved reserves, are excluded from the depletable base. These unevaluated property costs are added to the depletable base at such time as wells are completed on the properties or management determines these costs have been impaired. The Company’s determination that a property has or has not been impaired (which is discussed below) requires assumptions about future events; 
+· 
+estimated costs to dismantle, abandon and restore properties that are capitalized to the full cost pool when the related liabilities are incurred (see also the discussion below regarding Asset Retirement Obligations); 
+· 
+estimated future costs to develop proved properties are added to the full cost pool for purposes of the DD&A computation. The Company uses assumptions based on the latest geologic, engineering, regulatory and cost data available to it to estimate these amounts. However, the estimates made are subjective and may change over time. The Company’s estimates of future development costs are reviewed at least annually and as additional information becomes available; and 
+· 
+capitalized costs included in the full cost pool plus estimated future development costs are depleted and charged against earnings using the unit-of-production method. Under this method, the Company estimates the proved reserves quantities at the beginning of each accounting period. For each BOE produced during the period, the Company records a DD&A charge equal to the amount included in the depletable base (net of accumulated depreciation, depletion and amortization) divided by our estimated net proved reserve quantities. 
+ 
+51 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Because the Company uses estimates and assumptions to determine proved reserves (as discussed below) and the amounts included in the depletable base, our depletion rates may materially change if actual results differ from these estimates. 
+ 
+Ceiling t est 
+ 
+Under the full cost method of accounting, the Company compares, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (excluding cash flows related to estimated abandonment costs and the value of commodity derivative instruments ) plus the lower of cost or fair value of unevaluated properties , to the net capitalized costs of proved oil and natural gas properties net of related deferred taxes. The Company refers to this comparison as a “ceiling test.” If the net capitalized costs of proved oil and natural gas properties exceed the estimated discounted (at a 10% annualized rate ) future net cash flows from proved reserves plus the lower of cost or fair value of unevaluated properties , t he Company is required to write- down the value of its oil and natural gas properties to the value of the discounted cash flows. Estimated future net cash flows from proved reserves are based on a twelve-month average pricing assumption. Given the volatility of oil and natural gas prices, it is reasonably possible that the Company’s estimates of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. For the period s ended December 31, 2016 and 2015 the Company recognized a write-down of oil and natural gas properties of $95.8 and $208.4 , respectively, as a result of the cei ling test limitation. If oil and natural gas prices were to decline, even if only for a short period of time, we could incur additional write- downs of oil and natural gas properties in the future. See Notes 2 and 13 i n the Footnotes to the Financial Statements for additional information regarding the Company’s oil and natural gas properties. 
+ 
+Estimating reserves and present value of estimated future net cash flows 
+ 
+Estimates of quantities of proved oil and natural gas reserves, including the discounted present value of estimated future net cash flows from such reserves at the end of each quarter, are based on numerous assumptions, which are likely to change over time. These assumptions include: 
+ 
+· 
+the prices at which the Company can sell its oil and natural gas production in the future. Oil and natural gas prices are volatile, but we are required to assume that they remain constant, using the twelve-month average pricing assumption. In general, higher oil and natural gas prices will increase quantities of proved reserves and the present value of estimated future net cash flows from such reserves, while lower prices will decrease these amounts; and 
+· 
+the costs to develop and produce the Company’s reserves and the costs to dismantle its production facilities when reserves are depleted. These costs are likely to change over time, but we are required to assume that they remain constant. Increases in costs will reduce estimated oil and natural gas quantities and the present value of estimated future net cash flows, while decreases in costs will increase such amounts. 
+ 
+Changes in these prices and/or costs will affect the present value of estimated future net cash flows more than the estimated quantities of oil and natural gas reserves for the Company’s properties that have relatively short productive lives. If oil and natural gas prices remain at current levels or decline further, it will have a negative impact on the present value of estimated future net cash flows and the estimated quantities of oil and natural gas reserves. 
+ 
+In addition, the process of estimating proved oil and natural gas reserves requires that the Company’s independent and internal reserve engineers exercise judgment based on available geological, geophysical and technical information. We have described the risks associated with reserve estimation and the volatility of oil and natural gas prices under “Risk Factors.” 
+ 
+Sales of oil and natural gas properties are accounted for as adjustments to the net full cost pool with no gain or loss recognized unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves. 
+ 
+Unproved p roperties 
+ 
+Costs, including capitalized interest, associated with properties that do not have proved reserves are excluded from the depletable base, and are included in the line item “Unevaluated properties.” Un evaluat ed property costs are transferred to the depletable base when wells are completed on the pro perties or management determines that these costs have been impaired . In addition, the Company is required to determine whether its un evaluat ed properties are impaired and, if so, include the costs of such properties in the depletable base. We assess properties on an individual basis or as a group. The Company considers the following factors, among others: exploration program and intent to drill, remaining lease term, and the assignment of proved reserves. This determination may require the exercise of substantial judgment by management. 
+ 
+Asset r etirement o bligations 
+ 
+We are required to record our estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-life assets and the associated asset retirement costs. Interest is accreted on the present value of the asset retirement obligation s and reported as accretion expense within operating expenses in the Consolidated Statements of Operations. See Note 12 in the Footnotes to the Financial Statements for additional information. 
+52 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+ 
+Derivatives 
+ 
+To manage oil and natural gas price risk on a portion of our planned future production, we have historically utilized commodity derivative instruments (including collars, swaps, put and call options and other structures) on approximately 40% to 60% of our projected production volumes in any given year. We do not use these instruments for trading purposes. Settlement s of derivative contracts are generally based on the difference between the contract price and prices specified in the derivative instrument and a NYMEX price or other cash or futures index price. 
+ 
+O ur derivative positions are carried at their fair value on the balance sheet with changes in fair value recorded through earnings . The estimated fair value of our derivative contracts is based upon current forward market prices on NYMEX and in the case of collars and floors, the time value of options. For additional information regarding derivatives and their fair values, see Notes 6 and 7 in the Footnotes to the Financial Statements and Part II, Item 7A Commodity Price Risk. 
+ 
+Income t axes 
+ 
+The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices). We had a valuation allowance of $140.2 million as of December 31, 2016 . See Note 11 in the Footnotes to the Financial Statements f or additional information regarding Income Taxes. 
+ 
+Accounting Standards Updates (“ASU”) 
+ 
+See Note 2 in the Footnotes to the Financial Statements for additional information regarding ASUs. 
+ 
+Off-balance Sheet Arrangements 
+ 
+We had no off-balance sheet arrangements as of December 31, 2016 . 
+ 
+53 
+Table of Contents 
+Item 7A. Quan titative and Qualitative Disclosures about Market Risk 
+ 
+We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative instruments. 
+ 
+Commodity price risk 
+ 
+The Company’s revenues are derived from the sale of its oil and natural gas production. The prices for oil and natural gas remain extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and government actions. From time to time, the Company enters into derivative financial instruments to manage oil and natural gas price risk, related both to NYMEX benchmark prices and regional basis differentials. The total volumes which we hedge through use of our derivative instruments varies from period to period; however, generally our objective is to hedge approximately 4 0% to 60 % of our anticipated internally forecast production for the next 12 to 24 months, subject to the covenants under our Credit Facility. Our hedge policies and objectives may change significantly with movements in commodities prices or futures prices, in addition t o modification of our capital spending plans related to operational activities and acquisitions. 
+ 
+The Company’s hedging portfolio, linked to NYMEX benchmark pricing, covers approximat ely 3,755 MBbls and 2,920 B Btu of our expected oil and natural gas production, respectively, for calendar year 2017 . We also have commodity hedging contracts linked to Midland WTI basis differentials relative to Cushing covering approximatel y 2,004 MBbls of our expected oil producti on for calendar year 2017 . See Note 6 in the Footnotes to the Financial Statements for a description of the Company’s outstanding derivative contracts at December 31, 2016 , and derivative contracts established subsequent to that date. 
+ 
+The Company may utilize fixed price swaps, which reduce the Company’s exposure to decreases in commodity prices and limit the benefit the Company might otherwise have received from any increases in commodity prices. Swap contracts may also be enhanced by the simultaneous sale of call or put options to effectively increase the effective swap price as a result of the receipt of premiums from the option sales. 
+ 
+The Company may utilize price collars to reduce the risk of changes in oil and natural gas prices. Under these arrangements, no payments are due by either party as long as the applicable market price is above the floor price (purchased put option) and below the ceiling price (sold call option) set in the collar. If the price falls below the floor, the counter-party to the collar pays the difference to the Company, and if the price rises above the ceiling, the counterparty receives the difference from the Company. Additionally, the Company may sell put (or call) options at a price lower than the floor price (or higher than the ceiling price) in conjunction with a collar (three-way collar) and use the proceeds to increase either or both the floor or ceiling prices. In a three-way collar, to the extent that realized prices are below the floor price of the sold put option (or above the ceiling price of the sold call option), the Company’s net realized benefit from the three-way collar will be reduced on a dollar-for-dollar basis. 
+ 
+The Company may purchase put and call options, which reduce the Company’s exposure to decreases in oil and natural gas prices while allowing realization of the full benefit from any increases in oil and natural gas prices. If the price falls below the floor, the counterparty pays the difference to the Company. 
+ 
+The Company enters into these various agreements from time to time to reduce the effects of volatile oil and natural gas prices and does not enter into derivative transactions for speculative purposes. Presently, none of the Company’s derivative positions are designated as hedges for account ing purposes. 
+ 
+Interest rate risk 
+ 
+The Company is subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility. Though we had no balance outstanding on our Credit Facility at December 31, 2016 , based on a notional amount of $10 mill ion outstanding under the facility, a n increase or decrease of 1% in the interest rate would ha ve a corresponding increase or decrease in our annual net income of approximately $0.1 million . See Note 5 in the Footnotes to the Financial Statements for more information on the Company’s interest rates on our Credit Facility . 
+ 
+Counterparty and customer credit risk 
+ 
+The Company’s principal exposures to credit risk are through receivables from the sale of our oil and natural gas production, joint interest receivables and receivables resulting from derivative financial contracts. 
+ 
+The Company markets its oil and natural gas production to energy marketing companies. We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. For the year ended December 31, 2016 , three purchasers accounted for more than 10% of our revenue: Enterprise Crude Oil, LLC ( 43% ); Shell Trading Company ( 18% ); and Plains Marketing, L.P. ( 16% ). We do not require any of our customers to post collateral, and the inability of our significant customers to meet 
+54 
+Table of Contents 
+their obligations to us or their insolvency or liquidation may adversely affect our financial results. At December 31, 2016 our total receivables from the sale of our oil and natural gas production were approximately $47.4 million. 
+ 
+Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have or intend to drill. We have little ability to control whether these entities will participate in our wells. At December 31, 2016 our joint interest receivables were approximate ly $20.6 m illion. 
+ 
+At December 31, 2016 our receivables resulting from derivative contracts were appro ximately $0.3 million. Our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. Most of the counterparties on our derivative instruments currently in place are lenders under our Credit Facility. We are likely to enter into additional derivative instruments with these or other lenders under our Credit Facility, representing institutions with investment grade ratings . We have existing International Swap Dealers Association Master Agreements (“ISDA Agreements”) with our derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of offset upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may offset all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. At December 31, 2016 we had a net derivative asset position of $18.2 million . 
+ 
+55 
+Table of Contents 
+ITEM 8. Finan cial Statements and Supplementary Data 
+ 
+ 
+ 
+Page 
+ Report s of Independent Registered Public Accounting Firm s 
+57 
+ Consolidated Balance Sheets as of December 31, 201 6 and 201 5 
+59 
+ Consolidated Statements of Operations for Each of the Three Years in the Period Ended December 31, 201 6 
+60 
+ Consolidated Statements of Stockholders’ Equity for Each of the Three Years in the Period Ended December 31, 201 6 
+61 
+ Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 201 6 
+62 
+ Notes to Consolidated Financial Statements 
+63 
+ 
+ 
+56 
+Table of Contents 
+Report of Indepe ndent Registered Public Accounting Firm 
+ 
+ 
+Board of Directors and Stockholders 
+Callon Petroleum Company 
+We have audited the accompanying consolidated balance sheet of Callon Petroleum Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2016 , and the related consolidated statements of operations, stockholders’ equity, and cash flows for the year ended December 31, 2016 . These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. 
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. 
+In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Callon Petroleum Company and subsidiaries as of December 31, 2016 , and the results of their operations and their cash flows for the year ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2016 , based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report da ted February 27, 2017 expressed an unqualified opinion. 
+ 
+/s/GRANT THORNTON LLP 
+ 
+Houston, Texas 
+February 27, 2017 
+57 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+ 
+ 
+The Board of Directors and Stockholders of 
+Callon Petroleum Company 
+ 
+ 
+We have audited the accompanying consolidated balance sheet of Callon Petroleum Company as of December 31, 2015, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the t wo years in the period ended December 31, 2015. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. 
+ 
+We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. 
+ 
+In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Callon Petroleum Company as of December 31, 2015, and the consolidated results of its operations and its cash flows for each of the t wo years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles. 
+ 
+ 
+/s/Ernst & Young LLP 
+ 
+New Orleans, Louisiana 
+March 2, 2016 
+58 
+Table of Contents 
+Part I. Financial Information 
+Item I. Financial Statements 
+Callon Petroleum Company 
+Consolidated Bal ance Sheets 
+(in thousands, except par and per share values and share data) 
+ 
+ 
+December 31, 2016 
+December 31, 2015 
+ASSETS 
+Current assets: 
+Cash and cash equivalents 
+$ 
+652,993 
+$ 
+1,224 
+Accounts receivable 
+69,783 
+39,624 
+Fair value of derivatives 
+103 
+19,943 
+Other current assets 
+2,247 
+1,461 
+Total current assets 
+725,126 
+62,252 
+Oil and natural gas properties, full cost accounting method: 
+Evaluated properties 
+2,754,353 
+2,335,223 
+Less accumulated depreciation, depletion, amortization and impairment 
+(1,947,673)
+(1,756,018)
+Net evaluated oil and natural gas properties 
+806,680 
+579,205 
+Unevaluated properties 
+668,721 
+132,181 
+Total oil and natural gas properties 
+1,475,401 
+711,386 
+Other property and equipment, net 
+14,114 
+7,700 
+Restricted investments 
+3,332 
+3,309 
+Deferred financing costs related to the senior secured revolving credit facility 
+3,092 
+3,642 
+Acquisition deposit 
+46,138 
+— 
+Other assets, net 
+384 
+305 
+Total assets 
+$ 
+2,267,587 
+$ 
+788,594 
+LIABILITIES AND STOCKHOLDERS’ EQUITY 
+Current liabilities: 
+Accounts payable and accrued liabilities 
+$ 
+95,577 
+$ 
+70,970 
+Accrued interest 
+6,057 
+5,989 
+Cash-settleable restricted stock unit awards 
+8,919 
+10,128 
+Asset retirement obligations 
+2,729 
+790 
+Fair value of derivatives 
+18,268 
+— 
+Total current liabilities 
+131,550 
+87,877 
+Senior secured revolving credit facility 
+— 
+40,000 
+Secured second lien term loan, net of unamortized deferred financing costs 
+— 
+288,565 
+6.125% senior unsecured notes due 2024, net of unamortized deferred financing costs 
+390,219 
+— 
+Asset retirement obligations 
+3,932 
+4,317 
+Cash-settleable restricted stock unit awards 
+8,071 
+4,877 
+Deferred tax liability 
+90 
+— 
+Fair value of derivatives 
+28 
+— 
+Other long-term liabilities 
+295 
+200 
+Total liabilities 
+534,185 
+425,836 
+Commitments and contingencies 
+Stockholders’ equity: 
+Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized: 1,458,948 and 1,578,948 shares outstanding, respectively 
+15 
+16 
+Common stock, $0.01 par value, 300,000,000 and 150,000,000 shares authorized; 201,041,320 and 80,087,148 shares outstanding, respectively 
+2,010 
+801 
+Capital in excess of par value 
+2,171,514 
+702,970 
+Accumulated deficit 
+(440,137)
+(341,029)
+Total stockholders’ equity 
+1,733,402 
+362,758 
+Total liabilities and stockholders’ equity 
+$ 
+2,267,587 
+$ 
+788,594 
+ 
+ 
+The accompanying notes are an integral part of these consolidated financial statements. 
+59 
+Table of Contents 
+Callon Petroleum Company 
+Consolidated Sta tements of Operations 
+(in thousands, except per share data) 
+ 
+ 
+ 
+For the Year Ended December 31, 
+2016 
+2015 
+2014 
+Operating revenues: 
+Oil sales 
+$ 
+177,652 
+$ 
+125,166 
+$ 
+139,374 
+Natural gas sales 
+23,199 
+12,346 
+12,488 
+Total operating revenues 
+200,851 
+137,512 
+151,862 
+Operating expenses: 
+Lease operating expenses 
+38,353 
+27,036 
+22,372 
+Production taxes 
+11,870 
+9,793 
+8,973 
+Depreciation, depletion and amortization 
+71,369 
+69,249 
+56,724 
+General and administrative 
+26,317 
+28,347 
+25,109 
+Accretion expense 
+958 
+660 
+826 
+Write-down of oil and natural gas properties 
+95,788 
+208,435 
+— 
+Rig termination fee 
+— 
+3,075 
+— 
+Gain on sale of other property and equipment 
+— 
+— 
+(1,080)
+Acquisition expense 
+3,673 
+27 
+668 
+Total operating expenses 
+248,328 
+346,622 
+113,592 
+Income (loss) from operations 
+(47,477)
+(209,110)
+38,270 
+Other (income) expenses: 
+Interest expense, net of capitalized amounts 
+11,871 
+21,111 
+9,772 
+(Gain) loss on early extinguishment of debt 
+12,883 
+— 
+(151)
+(Gain) loss on derivative contracts 
+20,233 
+(28,358)
+(31,736)
+Other income 
+(637)
+(198)
+(515)
+Total other (income) expense 
+44,350 
+(7,445)
+(22,630)
+Income (loss) before income taxes 
+(91,827)
+(201,665)
+60,900 
+Income tax (benefit) expense 
+(14)
+38,474 
+23,134 
+Net income (loss) 
+(91,813)
+(240,139)
+37,766 
+Preferred stock dividends 
+(7,295)
+(7,895)
+(7,895)
+Income (loss) available to common stockholders 
+$ 
+(99,108)
+$ 
+(248,034)
+$ 
+29,871 
+Income (loss) per common share: 
+Basic 
+$ 
+(0.78)
+$ 
+(3.77)
+$ 
+0.67 
+Diluted 
+$ 
+(0.78)
+$ 
+(3.77)
+$ 
+0.65 
+ 
+Shares used in computing income (loss) per common share: 
+Basic 
+126,258 
+65,708 
+44,848 
+Diluted 
+126,258 
+65,708 
+45,961 
+ 
+ The accompanying notes are an integral part of these consolidated financial statements . 
+ 
+60 
+Table of Contents 
+Callon Petroleum Company 
+Consolidated Statem ents of Stockholders’ Equity 
+(in thousands) 
+ 
+ 
+Preferred Stock 
+Common Stock 
+Capital in Excess of Par 
+Retained Earnings (Deficit) 
+Total Stockholders' Equity 
+Balance at 12/31/2013 
+$ 
+16 
+$ 
+404 
+$ 
+401,540 
+$ 
+(122,866)
+$ 
+279,094 
+Net income 
+— 
+— 
+— 
+37,766 
+37,766 
+Shares issued pursuant to employee benefit plans 
+— 
+— 
+262 
+— 
+262 
+Restricted stock 
+— 
+4 
+2,054 
+— 
+2,058 
+Common stock issued 
+— 
+144 
+122,306 
+— 
+122,450 
+Preferred stock dividend 
+— 
+— 
+— 
+(7,895)
+(7,895)
+Balance at 12/31/2014 
+$ 
+16 
+$ 
+552 
+$ 
+526,162 
+$ 
+(92,995)
+$ 
+433,735 
+Net loss 
+— 
+— 
+— 
+(240,139)
+(240,139)
+Shares issued pursuant to employee benefit plans 
+— 
+— 
+268 
+— 
+268 
+Restricted stock 
+— 
+8 
+1,323 
+— 
+1,331 
+Common stock issued 
+— 
+241 
+175,217 
+— 
+175,458 
+Preferred stock dividend 
+— 
+— 
+— 
+(7,895)
+(7,895)
+Balance at 12/31/2015 
+$ 
+16 
+$ 
+801 
+$ 
+702,970 
+$ 
+(341,029)
+$ 
+362,758 
+Net loss 
+— 
+— 
+— 
+(91,813)
+(91,813)
+Shares issued pursuant to employee benefit plans 
+— 
+— 
+275 
+— 
+275 
+Restricted stock 
+— 
+4 
+2,323 
+— 
+2,327 
+Common stock issued 
+— 
+1,198 
+1,465,952 
+— 
+1,467,150 
+Preferred stock conversion 
+(1)
+7 
+(6)
+— 
+— 
+Preferred stock dividend 
+— 
+— 
+— 
+(7,295)
+(7,295)
+Balance at 12/31/2016 
+$ 
+15 
+$ 
+2,010 
+$ 
+2,171,514 
+$ 
+(440,137)
+$ 
+1,733,402 
+ 
+ The accompanying notes are an integral part of these consolidated financial statements. 
+61 
+Table of Contents 
+Callon Petroleum Company 
+Consolidated Statem ents of Cash Flows 
+(in thousands) 
+ 
+ 
+ 
+For the Year Ended December 31, 
+2016 
+2015 
+2014 
+Cash flows from operating activities: 
+Net income (loss) 
+$ 
+(91,813)
+$ 
+(240,139)
+$ 
+37,766 
+Adjustments to reconcile net income to cash provided by operating activities: 
+Depreciation, depletion and amortization 
+73,072 
+69,891 
+58,014 
+Write-down of oil and natural gas properties 
+95,788 
+208,435 
+— 
+Accretion expense 
+958 
+660 
+826 
+Amortization of non-cash debt related items 
+3,115 
+3,123 
+1,272 
+Amortization of deferred credit 
+— 
+— 
+(487)
+Deferred income tax (benefit) expense 
+(14)
+38,474 
+23,134 
+Net loss (gain) on derivatives, net of settlements 
+38,135 
+6,658 
+(27,650)
+Gain on sale of other property and equipment 
+— 
+— 
+(1,080)
+Non-cash (gain) loss on early extinguishment of debt 
+9,883 
+— 
+(151)
+Non-cash expense related to equity share-based awards 
+558 
+221 
+1,126 
+Change in the fair value of liability share-based awards 
+6,953 
+6,612 
+3,936 
+Payments to settle asset retirement obligations 
+(1,471)
+(3,258)
+(3,808)
+Changes in current assets and liabilities: 
+Accounts receivable 
+(30,055)
+(4,761)
+(7,915)
+Other current assets 
+(786)
+(20)
+622 
+Current liabilities 
+25,288 
+8,001 
+12,805 
+Change in other long-term liabilities 
+96 
+80 
+(106)
+Change in other assets, net 
+(840)
+338 
+(448)
+Payments to settle vested liability share-based awards related to early retirements 
+— 
+(3,538)
+(1,417)
+Payments to settle vested liability share-based awards 
+(10,300)
+(3,925)
+(2,052)
+Net cash provided by operating activities 
+118,567 
+86,852 
+94,387 
+Cash flows from investing activities: 
+Capital expenditures 
+(190,032)
+(227,292)
+(232,596)
+Acquisitions 
+(654,679)
+(32,245)
+(222,883)
+Acquisition deposit 
+(46,138)
+— 
+— 
+Proceeds from sales of mineral interest and equipment 
+24,562 
+377 
+2,978 
+Net cash used in investing activities 
+(866,287)
+(259,160)
+(452,501)
+Cash flows from financing activities: 
+Borrowings on senior secured revolving credit facility 
+217,000 
+181,000 
+132,500 
+Payments on senior secured revolving credit facility 
+(257,000)
+(176,000)
+(119,500)
+Borrowings on term loans 
+— 
+— 
+382,500 
+Payments on term loans 
+(300,000)
+— 
+(84,149)
+Issuance of 6.125% senior unsecured notes due 2024 
+400,000 
+— 
+— 
+Payment of deferred financing costs 
+(10,793)
+— 
+(19,779)
+Redemption of 13% senior notes due 2016 
+— 
+— 
+(50,057)
+Issuance of common stock 
+1,357,577 
+175,459 
+122,450 
+Payment of preferred stock dividends 
+(7,295)
+(7,895)
+(7,895)
+Net cash provided by financing activities 
+1,399,489 
+172,564 
+356,070 
+Net change in cash and cash equivalents 
+651,769 
+256 
+(2,044)
+Balance, beginning of period 
+1,224 
+968 
+3,012 
+Balance, end of period 
+$ 
+652,993 
+$ 
+1,224 
+$ 
+968 
+ 
+ The accompanying notes are an integral part of these consolidated financial statements. 
+ 
+ 
+62 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+IND EX TO THE NOTES TO CONS OLIDATED FINANCIAL STATEMENTS 
+ 
+ 
+1. 
+Description of Business and Basis of Presentation 
+9. 
+Share-Based Compensation 
+2. 
+Summary of Significant Accounting Policies 
+10. 
+Equity Transactions 
+3. 
+Acquisitions and Dispositions 
+11. 
+Income Taxes 
+4. 
+Earnings (Loss) Per Share 
+12. 
+Asset Retirement Obligations 
+5. 
+Borrowings 
+13. 
+Supplemental Information on Oil and Natural Gas Operations (Unaudited) 
+6. 
+Derivative Instruments and Hedging Activities 
+14. 
+Other 
+7. 
+Fair Value Measurements 
+15. 
+Summarized Quarterly Financial Information (Unaudited) 
+8. 
+Employee Benefit Plans 
+ 
+Note 1 - Description of Busi ness and Basis of Presentation 
+ 
+Description of business 
+ 
+Callon Petroleum Company is an independent oil and natural gas company established in 1950. The Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company partially owned by a member of current management. As used herein, the “Company,” “Callon ,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. 
+ 
+Callon is focused on the acquisition, development, exploration and exploitation of unconventional onshore, oil and natural gas reserves in the Permian Basin in West Texas. The Company’s operations to date have been predominantly focused on horizontal drilling of several prospective intervals, including multiple levels of the Wolfcamp formation and, more recently, the Lower Spraberry shale in the Midland Basin. Callon has assembled a multi-year inventory of potential horizontal well locations and intends to add to this inventory through delineation drilling of emerging zones on its existing acreage and acquisition of additional locations through working interest acquisitions, acreage purchases, joint ventures and asset swaps. 
+ 
+Basis of presentation 
+ 
+Unless otherwise indicated, all dollar amounts included within the F ootnotes to the Financial S tatements are presented in thousands, except for per share and per unit data. 
+ 
+The Consolidated Financial Statements include the accounts of the Company, and its subsidiary, Callon Petroleum Operating Company (“CPOC”). CPOC also has subsidiaries, namely Callon Offshore Production, Inc. and Mississippi Marketing, Inc. All intercompany accounts and transactions have been eliminated. In the opinion of management, the accompanying audited consolidated financial statements reflect all adjustments, including normal recurring adjustments and all intercompany account and transaction eliminations, necessary to present fairly the Company’s financial position, the results of its operations and its cash flows for the periods indicated. Certain prior year amounts may have been reclassified to conform to current year presentation. 
+Note 2 – Summary of Significant Accounting Policies 
+ 
+A. 
+Use of Estimates 
+ 
+The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 
+ 
+B. 
+Cash and Cash Equivalents 
+ 
+The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. 
+ 
+C. 
+Accounts Receivable 
+ 
+Accounts receivable consists primarily of accrued oil and natural gas production receivables and joint interest receivables from outside working interest owners . 
+63 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+D. 
+Revenue Recognition and Natural Gas Balancing 
+ 
+The Company recognizes revenue under the entitlement s method of accounting. Under this method, revenue is deferred for deliveries in excess of the Company’s net revenue interest, while revenue is accrued for the undelivered volumes. The revenue we receive from the sale of NGLs is included in natural gas sales. Natural gas balancing receivables and payables were immaterial as of December 31, 2016 and 2015 . 
+ 
+See the Accounting Standards Updates (“ASU”) section within this footnote for information about recently issued ASUs related to Revenue Recognition. 
+E. 
+Major Customers 
+ 
+The Company’s production is generally sold on month-to-month contracts at prevailing prices. The following table identifies customers to whom it sold greater than 10% of its total oil and natural gas production during each of the years ended: 
+ 
+ 
+ 
+For the Year Ended December 31, 
+ 
+2016 
+2015 
+2014 
+Enterprise Crude Oil, LLC 
+43% 
+42% 
+51% 
+Shell Trading Company 
+18% 
+4% 
+— 
+Plains Marketing, L.P. 
+16% 
+19% 
+22% 
+Permian Transport and Trading 
+— 
+15% 
+7% 
+Sunoco 
+— 
+9% 
+10% 
+Other 
+23% 
+11% 
+10% 
+Total 
+100% 
+100% 
+100% 
+ 
+Because alternative purchasers of oil and natural gas are readily available, the Company believes that the loss of any of these purchasers would not result in a material adverse effect on its ability to market future oil and natural gas production. 
+ 
+F. 
+Oil and Natural Gas Properties 
+ 
+The Company uses the full cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as oil and gas properties. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest capitalized on unevaluated leases, other costs related to exploration and development activities, and site restoration, dismantlement and abandonment costs capitalized in accordance with asset retirement obligation accounting guidance. Costs capitalized also include any internal costs that are directly related to exploration and development activities, including salaries and benefits, but do not include any costs related to production, general corporate overhead or similar activities. 
+When applicable, proceeds from the sale o r disposition of oil and natural gas properties are accounted for as a reduction to capitalized costs through adjustments to accumulated depreciation, depletion , amortization and impairment unless the sale would significantly alter the relationship between capitalized costs and proved reserves, in which ca se a gain or loss is recognized . 
+ 
+Historical and estimated future development costs of oil and natural gas properties , which have been evaluated and contain proved reserves, as well as the historical cost of properties that have been determined to have no future economic value, are depleted using the unit-of-production method based on proved reserves. Excluded from this amortization are costs associated with unevaluated properties, including capitalized interest on such costs. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties or the Company determines that these costs have been impaired. The Company assesses properties on an individual basis or as a group and considers the following factors, among others, to determine if these costs have been impaired: exploration program and intent to drill, remaining lease term, and the assignment of proved reserves. 
+ 
+Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full cost ceiling). These rules require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling. At December 31 , 2016 and 2015 , the average realized prices used in determining the estimated future net cash flows from proved reserves were $42.75 and $50.16 per barrel of oil , respectively, and $2.48 and $2.64 per Mcf of natural gas , respectively . For the period s ended December 31, 2016 and 2015 , the Company recognized a write-down of oil and natural gas properties of $95,788 and $208,435 , respectively, as a result of the ceiling test limitation. See Notes 2 and 13 f or additional information regarding the Company’s oil and natural gas properties. 
+ 
+64 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+Upon the acquisition or discovery of oil and natural gas properties, the Company estimates the future net costs to dismantle , abandon and restore the property by using available geological, engineering and regulatory data. Such cost estimates are periodically updated for changes in conditions and requirements. In accordance with asset retirement obligation guidance, such costs are capitalized to the full cost pool when the related liabilities are incurred. In accordance with full cost accounting rules, assets recorded in connection with the recognition of an asset retirement obligation are included as part o f the costs subject to the full cost ceiling limitation. The future cash outflows associated with settling the recorded asset retirement obligations are excluded from the computation of the present value of estimated future net revenues used in determining the full cost ceiling amount. 
+ 
+G. 
+Other Property and Equipment 
+ 
+The Company depreciates its other property and equipment using the straight-line method over estimated useful lives of three to 20 years. Depreciation expense of $793 , $865 and $836 relating to other property and equipment was included in general and administrative expenses in the Company’s consolidated statements of operations for the years ended December 31, 2016 , 2015 and 2014 , respectively. The accumulated depreciation on other property and equipment was $15,227 and $14,719 as of December 31, 2016 and 2015 , respectively. The Company reviews its other property and equipment for impairment when indicators of impairment exist. See Note 14 for addition al information. 
+ 
+H. 
+Capitalized Interest 
+ 
+The Company capitalizes interest on unevaluated oil and gas properties. Capitalized interest cannot exceed gross interest expense. During the years ended December 31, 2016 , 2015 and 2014 , the Company capitalized $19,857 , $10,459 and $4,295 of interest expense. 
+ 
+I. 
+Deferred F inancing C osts 
+ 
+Deferred financing costs are stated at cost, net of amortization, and as a direct reduction from the debt’s carrying value on the balance sheet. For revolving debt arrangements, d eferred financing costs are stated at cost, net of amortization, as an asset on the balance sheet. Amortization of deferred financing costs is computed using the straight-line method over the life of the loan . Amortization of deferred financing costs of $3,115 , $3,123 and $1,272 w ere recorded for the years ended December 31, 2016 , 2015 and 2014 , respectively. 
+ 
+J. 
+Asset Retirement Obligations 
+ 
+The Company is required to record its estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Interest is accreted on the present value of the asset retirement obligations and reported as accretion expense within operating expenses in the consolidated statements of operations. See Note 12 for additional information. 
+ 
+K. 
+Derivatives 
+ 
+Derivative contracts outstanding as of December 31, 2016 were not designated as accounting hedges, and are carried on the balance sheet at fair value. Changes in the fair value of derivative contracts not designated as accounting hedges are reflected in earnings as a gain or loss on derivative contracts. See Notes 6 and 7 for additional information regarding the Company’s derivative contracts. 
+ 
+L. 
+Income Taxes 
+ 
+Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties for financial reporting purposes and income tax purposes. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards, statutory depletion carryforward s and tax credit carryforwards. A valuation allowance is provided for that portion of deferred tax assets , if any, for which it is deemed more likely than not that it will not be realized. As of December 31, 201 6 the valuation allowance was $140,192 . See Note 11 for additional information. 
+ 
+M. 
+Share-Based Compensation 
+ 
+The Company grants to directors and employees stock options and restricted stock awards (“RS awards”) . The Company also grants restricted stock unit awards (“ RSU awards ”) that may be settled in cash or common stock at the option of the Company and RSU awards that may only be settled in cash (“Cash-settleable RSU awards”). 
+ 
+Stock Options. For stock options the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value as calculated using the Black-Scholes option pricing model and recognized straight-line over the vesting period (generally three years). 
+ 
+65 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+RS awards, RSU equity awards and Cash-settleable RSU awards. For RS and RSU equity awards that the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value and recognized straight-line over the vesting period (generally three years). For RSU equity awards with vesting subject to a market condition, share-based compensation expense is based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model with the estimated value recognized over the vesting period (generally three years). For Cash-settleable RSU awards that the Company expects or is required to settle in cash, share-based compensation expe nse is based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model, because vesting of these awards is subject to a market condition, with the estimated fair value recognized over the vesting period (generally three years). 
+ 
+See the Accounting Standards Updates section within this footnote for information about recently issued ASUs related to Stock Compensation. 
+ 
+N. 
+Non-cash Investing and Supplemental Cash Flow Information 
+ 
+The following table sets forth the non-cash investing and supplemental cash flow information for the periods indicated: 
+ 
+ 
+ 
+ 
+For the Years Ended December 31, 
+ 
+2016 
+2015 
+2014 
+Non-cash investing information: 
+Change in accrued capital expenditures 
+$ 
+(613)
+$ 
+(16,813)
+$ 
+12,850 
+Supplemental cash flow information (a) : 
+Cash paid for interest, net of capitalized interest 
+$ 
+8,679 
+$ 
+17,978 
+$ 
+2,988 
+ 
+(a) 
+During the three year period ended 2016 , the Company paid no federal income taxes. 
+ 
+O. 
+Earnings per Share ( “ EPS ” ) 
+ 
+The Company’s basic EPS amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS, using the treasury-stock method, reflects the potential dilution caused by the exercise of options and vesting of restricted stock and RSUs settleable in shares. 
+ 
+P. 
+Accounting Standards Updates (“ASU”) 
+ 
+Recently Issued ASUs 
+ 
+In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will replace most of the existing revenue recognition requirements in GAAP when it becomes effective. In August 2015, the FASB issued ASU No. 2015-14, deferring the effective date of ASU 2014-09 by one year. As a result, the standard is effective for annual periods beginning on or after December 31, 2017, including interim periods within that reporting period . The Company is currently evaluating the impact of the standard; however, we do not believe th e standard will have a material impact on our financial statements and related disclosures. 
+ 
+In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers – Principal versus Agent Considerations (Reporting Revenue Gross versus Net) . Under this update, an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This update will be effective for annual an interim reporting periods beginning after December 15, 2017, with early application not permitted. This update allows for either full retrospective adoption or modified retrospective adoption. The Company is currently evaluating the impact of its pending adoption of this guidance on its consolidated financial statements. 
+ 
+In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers – Identifying Performance Obligations and Licensing . This update clarifies two principles of Accounting Standards Codification Topic 606: identifying performance obligations and the licensing implementation guidance. This update will be effective for annual an interim reporting periods beginning after December 15, 2017, with early application not permitted. The Company is currently evaluating the impact of its pending adoption of this guidance on its consolidated financial statements. 
+ 
+In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers - Narrow-Scope Improvements and Practical Expedients . This update applies only to the following areas from Accounting Standards Codification Topic 606: assessing the collectability criterion and accounting for contracts that do not meet the criteria for step 1, presentation of sales taxes and other similar taxes collected from customers, non-cash consideration, contract modification at transition, completed contracts at transition and 
+66 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+technical correction. This update will be effective for annual an interim reporting periods beginning after December 15, 2017, with early application not permitted. The Company is currently evaluating the impact of its pending adoption of this guidance on its consolidated financial statements. 
+ 
+In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (T opic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”). The objective of the standard is to reduce the existing diversity in practice of several cash flow issues, including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payment made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows and application of the predominance principle. The guidance in ASU 2016-15 is effective for public entities for annual reporting periods beginning after December 15, 2017, including interim periods therein. Early adoption is permitted and is to be applied on retrospective basis. The Company is currently evaluating the method of adoption and impact this standard may have on its financial statements and related disclosures. 
+ 
+In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”). The standard requires all lease transactions (with terms in excess of 12 months) to be recognized on the balance sheet as lease assets and lease liabilities. Public entities are required to apply ASU 2016-02 for annual and interim reporting periods beginning after December 15, 2018 with early adoption permitted. The Company is currently evaluating the impact of its pending adoption of this guidance on its consolidated financial statements. 
+ 
+In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). The standard is intended to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows, and will allow companies to estimate the number of stock awards expected to vest. The guidance in ASU 2016-09 is effective for public entities for annual reporting periods beginning after December 15, 2016, including interim periods therein. The Company is currently evaluating the method of adoption and impact this standard may have on its financial statements and related disclosures. 
+ 
+In December 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topics 230): Restricted Cash (“ASU 2016-18”). The objecti ve of the standard is to require the change during the period in total restricted cash and cash equivalents to be included with cash and cash equivalents when reconciling the beginning-of-period and the end-of-period total amounts shown on the statement of cash flows. The Company is currently evaluating the method of adoption and impact this standard may have on its financial statements and related disclosures. 
+ 
+Recently Adopted ASUs 
+ 
+In November 2015, the FASB issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”), which eliminates the current requirement to present deferred tax liabilities and assets as current and noncurrent amounts on the balance sheet. Instead, entities will be required to classify all deferred tax assets and liabilities as noncurrent on the balance sheet. The guidance in ASU 2015-17 is effective for public entities for annual reporting periods beginning after December 15, 2016, and interim periods within those annual periods. As of December 31, 2016, the Company adopted this ASU, which did not have a material impact on its financial stat ements. 
+ 
+Note 3 – Acquisitions and Dispositio ns 
+ 
+2016 acquisitions 
+ 
+On October 20, 2016, the Company completed the acquisition of 6,904 gross ( 5,952 net) acres primarily located in Howard County, Texas from Plymouth Petroleum, LLC and additional sellers that exercised their “tag-along” sales rights, for total cash consideration of $339,687 , excluding customary purchase price adjustments (the “Plymouth Transaction”). The Company funded the cash purchase price with the net proceeds of an equity offering (see Note 10 for additional information regarding the equity offering). The Company acquired an 82% average working interest ( 62% average net revenue interest) in the properties acquired in the Plymouth Transaction. The following table summarizes the estimated acquisition date fair values of the net assets acquired in the acquisition: 
+ 
+ 
+ 
+Evaluated oil and natural gas properties 
+$ 
+65,043 
+Unevaluated oil and natural gas properties 
+274,664 
+Asset retirement obligations 
+(20)
+Net assets acquired 
+$ 
+339,687 
+ 
+67 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+On May 26, 2016, the Company completed the acquisition of 17,298 gross ( 14,089 net) acres primarily located in Howard County, Texas from BSM Energy LP, Crux Energy LP and Zaniah Energy LP, for total cash consideration of $220,000 and 9,333,333 shares of common stock ( at an assumed offering price of $11.74 per share, which is the last reported sale price of our common stock on the New York Stock Exchange on that dat e) for a total purchase price of $329,573 , excluding customary purchase price adjustments (the “Big Star Transaction”). The Company acquired an 81% average working interest ( 61% average net revenue interest) in the properties acquired in the Big Star Transaction. The following table summarizes the estimated acquisition date fair values of the net assets acquired in the acquisition: 
+ 
+ 
+ 
+ 
+Evaluated oil and natural gas properties 
+$ 
+96,194 
+Unevaluated oil and natural gas properties 
+233,387 
+Asset retirement obligations 
+(8)
+Net assets acquired 
+$ 
+329,573 
+ 
+The preliminary purchase price allocation s are subject to change based on numerous factors, including the final adjusted purchase price and the final estimated fair value of the assets acquired and liabilities assumed. Any such adjustments to the preliminary estimates of fair value could be material. 
+ 
+During 2016, the Company also closed on various acquisitions in the Midland Basin for an aggregate total purchase price of approximately $73,240 , net of $23,045 in sales of working interest. The acquisitions included the purchase of additional working interest and acreage in the Company’s existing core operating area. 
+ 
+2015 acquisitions 
+ 
+During 2015, the Company closed on an acquisition in the Midland Basin for an aggregate total purchase price of approximately $ 29,800 . The acquisition included the purchase of additional working interest in the Company’s existing core operating area . 
+ 
+2014 acquisitions 
+ 
+On October 8, 2014, the Company completed the acquisition of certain undeveloped acreage and producing oil and gas properties located in Midland, Andrews, Ector and Martin Counties, Texas (the “ Central Midland Basin Transaction ”) for an aggregate cash purchase price of $210,205 based on an effective date of May 1, 2014. The Company assumed operatorship of the properties on November 1, 2014, and acquired a 62% working interest ( 46.5% net revenue interest) in the Central Midland Basin Transaction . The aggregate cash purchase price was funded with a combination of the net proceeds from an equity offering of $122,450 and a portion of the proceeds from borrowings under the Second Lien Loan. For additional information on the debt transactions and equity offering, see Notes 5 and 10 , respectively. The following purchase price allocation is based on management’s estimates of the fair value of the assets acquired and liabilities assumed. The following table summarizes the acquisition date fair values of the net assets acquired: 
+ 
+ 
+ 
+Evaluated oil and natural gas properties 
+$ 
+91,895 
+Unevaluated oil and natural gas properties 
+118,450 
+Asset retirement obligations 
+(140)
+Net assets acquired 
+$ 
+210,205 
+ 
+During 2014, the Company also closed on various acquisitions in the Midland Basin for an aggregate total purchase price of approximately $8,200 . The acquisitions included the purchase of additional working interest and acreage in the Company’s existing core operating area. 
+ 
+68 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+Unaudited p ro forma financial statements 
+ 
+The following unaudited summary pro forma financial information for the periods presented is for illustrative purposes only and does not purport to represent what the Company’s results of operations would have been if the Big Star Transaction, Plymouth Transaction and Central Midland Basin Transaction had occurred as presented, or to project the Company’s results of operations for any future periods: 
+ 
+ 
+ 
+Twelve Months Ended December 31, 
+ 
+2016 (a) 
+2015 (a) 
+2014 (b) 
+Revenues 
+$ 
+225,326 
+$ 
+168,506 
+$ 
+180,458 
+Income (loss) from operations 
+(41,094)
+(131,435)
+53,526 
+Income (loss) available to common stockholders 
+(85,240)
+(153,735)
+33,674 
+ 
+Net income (loss) per common share: 
+Basic 
+$ 
+(0.68)
+$ 
+(1.18)
+$ 
+0.57 
+Diluted 
+$ 
+(0.68)
+$ 
+(1.18)
+$ 
+0.56 
+ 
+(a) 
+The pro forma financial information was prepared assuming the Big Star Transaction and Plymouth Transaction occurred as of January 1, 2015. 
+(b) 
+The pro forma financial information was prepared assuming the Central Midland Basin Transaction occurred as of January 1, 2013. 
+ 
+The pro forma adjustments are based on available information and certain assumptions that management believes are reasonable, including revenue, lease operating expenses, production taxes, depreciation, depletion and amortization expense, accretion expense, interest expense and capitalized interest. 
+ 
+The properties associated with the Big Star Transaction, the Plymouth Transaction and the Central Midland Basin Transaction have been comingled with our existing properties and it is impractical to provide the stand-alone operational results related to these properties. 
+ 
+Subsequent event 
+ 
+On Februa ry 13 , 2017 , the Company completed the acquisi tion of 27,552 gross ( 16,688 net) acres in the Delaware Basin, primarily located in Ward and Pecos Counties , Texas from American Resource Development, LLC , for total cash consideration of $633,000 , excluding customary purchase price adjustments (the “Ameredev Transaction”). The Company funded the cash purchase price with the net proceeds of an equity offering (see Note 10 for additional information regarding the equity offering). The Company acquired a n 82% ave rage working interest ( 75% avera ge net revenue interest) in the properties acquired in the Ameredev Transaction. In December 2016, in connection with the execution of the purchase and sale agreement for the Ameredev Transaction, the Company paid a deposit in the amount of $46,138 to a third party escrow agent, which was recorded as Acquisition deposit on the balance sheet as of December 31, 2016. 
+ 
+ 
+69 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+Note 4 - Ear nings Per Share 
+ 
+Basic earnings (loss) per share is computed by dividing income (loss) available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings (loss) per share includes the potential dilutive impact of non-vested restricted shares and unexercised options outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. The following table sets forth the computation of basic and diluted earnings per share: 
+ 
+ 
+ 
+For the Year Ended December 31, 
+2016 
+2015 
+2014 
+Net income (loss) 
+$ 
+(91,813)
+$ 
+(240,139)
+$ 
+37,766 
+Preferred stock dividends 
+(7,295)
+(7,895)
+(7,895)
+Income (loss) available to common stockholders 
+$ 
+(99,108)
+$ 
+(248,034)
+$ 
+29,871 
+ 
+Weighted average shares outstanding 
+126,258 
+65,708 
+44,848 
+Dilutive impact of restricted stock 
+— 
+— 
+1,113 
+Weighted average shares outstanding for diluted income (loss) per share (a) 
+126,258 
+65,708 
+45,961 
+ 
+Basic income (loss) per share 
+$ 
+(0.78)
+$ 
+(3.77)
+$ 
+0.67 
+Diluted income (loss) per share 
+$ 
+(0.78)
+$ 
+(3.77)
+$ 
+0.65 
+ 
+Stock options (b) 
+15 
+15 
+30 
+Restricted stock (b) 
+— 
+126 
+317 
+ 
+(a) 
+Because the Company reported a loss available to common stockholders for the year s ended December 31, 2016 , and 2015, no unvested stock awards were included in computing loss per share because the effect was anti-dilutive. 
+(b) 
+Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutiv e. 
+ 
+Note 5 – Borr owings 
+ 
+The Company’s borrowings consisted of the following at: 
+ 
+ 
+ 
+December 31, 
+2016 
+2015 
+Principal components: 
+Senior secured revolving credit facility 
+$ 
+— 
+$ 
+40,000 
+Secured second lien term loan 
+— 
+300,000 
+6.125% senior unsecured notes due 2024 
+400,000 
+— 
+Total principal outstanding 
+400,000 
+340,000 
+Secured second lien term loan, unamortized deferred financing costs 
+— 
+(11,435)
+6.125% senior unsecured notes due 2024, unamortized deferred financing costs 
+(9,781)
+— 
+Total carrying value of borrowings 
+$ 
+390,219 
+$ 
+328,565 
+ 
+C redit F acility 
+ 
+On March 11, 2014, the Company entered into the Fifth Amended and Restated Credit Agreement to the Credit Facility with a maturity date of March 11, 2019 . JPMorgan Chase Bank, N.A. is Administrative Agent, and participa n t s include several institutional lenders . The total notional amount available under the Credit Facility is $500,000 . Amounts borrowed under the Credit Facility may not exceed the borrowing base, which is generally reviewed on a semi-annual basis. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. 
+ 
+Effective July 13, 2016, the Credit Facility’s borrowing base was increased to $385,000 and the Company’s capacity to hedge oil and natural gas volumes was effectively increased with a change in the capacity calculation to a percentage of total proved reserves from proved producing reserves. In addition, the interest rate for borrowings under the Credit Facility was increased 0.25% across all tiers of the pricing grid, resulting in a range of interest costs equal to LIBOR plus 2.00% to 3.00% . There were no modifications to other terms or covenants of the Credit Facility. 
+ 
+Effective November 21, 2016, the Company achieved an indication to increase the Credit Facility’s borrowing base to $500,000 , but elected to maintain the borrowing base at $385,000 . As of December 31, 2016 , the Credit Facility’s borrowing base remained at $385,000 . 
+70 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+ 
+As of December 31, 2016 , the re was no balance outstanding on the Credit Facility . For the year ended December 31, 2016, the Credit Facility had a weighted-average interest rate of 2.60% , calculated as the LIBOR plus a tiered rate ranging from 2.00% to 3.00% , which is determined based on utilization of the facility. In addition, the Credit Facility carries a commitment fee of 0.5% per annum, payable quarterly, on the unused portion of the borrowing base. 
+ 
+Term loans 
+ 
+On March 11, 2014, the Company entered into a term loan in an aggregate amount of up to $125,000 , including initial commitments of $100,000 and additional availability of $25,000 subject to the consent of two-thirds of the lenders and compliance with financial covenants after giving effect to such increase. The term loan had a maturity date of September 11, 2019 , and was not subject to mandatory prepayments unless new debt or preferred stock wa s issued. It was prepayable at the Company’s option, subject to a prepayment premium. The prepayment amount was (i) 102% if the prepayment event occur red prior to March 11, 2015, and (ii) 101% if the prepayment event occur red on or after March 15, 2015 but before March 15, 2016, and (iii) 100% for prepayments made on or after March 15, 2016. The term loan was secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor agreement . 
+ 
+On October 8, 2014, the term loan described above was repaid in full using proceeds from a new secured second lien term loan (the “Second Lien Loan”) in conjunction with the closing of the Central Midland A cquisition, resulting in a loss on early extinguishment of debt of $3,054 . The Second Lien Loan has a maturity date of October 8, 2021 . The Royal Bank of Canada is Administrative Agent, and participants include several institutional lenders. Borrowings under the Second Lien Loan were subject to interest, calculated at a rate of LIBOR (subject to a floor rate of 1.0% ) plus 7.5% per annum. The Company elected a LIBOR rate based on various tenors, and was incurring interest based on an underlying three-month LIBOR rate, which was last elected in July 2016. The Second Lien Loan may be prepaid at the Company’s option, subject to a prepayment premium. The prepayment amount w as (i) 102% of principal if the prepayment event occurred prior to October 8, 201 6 , and (ii) 101% of principal if the prepayment event occur red on or after October 8, 201 6 but before October 8, 201 7 , and (iii) 100% of principal for prepayments made on or after October 8, 201 7 . The Second Lien Loan wa s secured by junior liens on properties mor tgaged under the Credit Facility, subject to an intercreditor agreement. 
+ 
+On October 11, 2016, the Second Lien Loan was repaid in full at the prepayment rate of 101% using proceeds from the sale of the 6.125% senior unsecured notes due 2024, which resulted in a loss on early extinguishment of debt of $ 12,883 (inclusive of $3,000 in prepayment fees and $9,883 of unamortized debt issuance costs). 
+ 
+6.125% senior notes due 2024 (“ 6.125% Senior Notes”) 
+ 
+On October 3, 2016, the Company issued $400,000 aggregate principa l amount of 6.125% Senior Notes with a maturity date of October 1, 2024 and i nterest payable semi-annually beginning on April 1, 2017 . The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $391,270 . The 6.125% Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. 
+ 
+The Company may redeem the 6.125% Senior Notes in accordance with the following terms; (1) p rior to October 1, 2019, a redemption of up to 35% of the principal in an amount not greater than the net proceeds from certain equity offerings, and within 180 days of the closing date of such equity offerings, at a redemption price of 106.125% of principal, plus accrued and unpaid interest, if any, to the date of the redemption, if at least 65% of the principal will remain outstanding after such redemption ; (2) p rior to October 1, 2019, a redem ption of all or part of the principal at a price of 100% of principal of the amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of the redemption; (3) a redemption, in whole or in part, at a redemption price, plus accrued and unpaid interest, if any, to the date of the redemption, (i) of 104.594% of principal if the redemption occurs on or after October 1, 2019, but before October 1, 2020, and (ii) of 103.063% of principal if the redemption occurs on or after October 1, 2020, but before October 1, 2021, and (iii) of 101.531% of principal if the redemption occurs on or after October 1, 2021, but before October 1, 2022, and (iv) of 100% of principal if the redemption occurs on or after October 1, 2022. 
+ 
+Following a change of control, each holder of the 6.125% Senior Notes may require the Company to repurchase all or a portion of the 6.125% Senior Notes at a price of 101% of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase. 
+ 
+13% senior notes due 2016 (“ 13% Senior Notes”) and deferred credit 
+ 
+On April 11, 2014, the Company completed a full redemption of the remaining $48,481 principal amount of outstanding 13% Senior Notes using proceeds from the Second Lien Loan. The redemption resulted in a net $3,205 gain on the early extinguishment of debt (including $4,780 of accelerated deferred credit amortization). The gain represents the difference between the $50,057 paid for the redemption of the 13% Senior Notes ( $1,576 of redemption costs, primarily the call premium) and the carrying value of the remaining 
+71 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+13% Senior Notes of $53,261 (inclusive of $4,780 of deferred credit). The Company also paid $193 in accrued interest through the redemption date. Upon the redemption, the indenture governing the 13% Senior Notes was discharged in accordance with its terms. 
+ 
+Restrictive covenants 
+ 
+The Company’s Credit Facility and the indenture governing our 6.125% Senior Notes contain various covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. The Company was in compliance with these covenants at December 31, 2016 . 
+Note 6 - Der ivative Instruments and Hedging Activities 
+ 
+Objectives and strategies for using derivative instruments 
+ 
+The Company is exposed to fluctuations in oil and natural gas prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil and natural gas production. The Company utilizes a mix of collars, swaps, put and call option s and similar derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes. 
+ 
+Counterparty risk and offsetting 
+ 
+The use of derivative instruments exposes the Company to the risk that a counterparty will be unable to meet its commitments. While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument; see Note 7 for additional information regarding fair value. 
+ 
+The Company executes commodity derivative contracts under master agreements with netting provisions that provide for offsetting assets against liabilities. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement. 
+ 
+Financial statement presentation and settlements 
+ 
+Settlements of the Company’s derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets. See Note 7 for additional information regarding fair value. 
+ 
+Derivatives not designated as hedging instruments 
+ 
+The Company records its derivative contracts at fair value in the consolidated balance sheets and records changes in fair value as a gain or loss on derivative contracts in the consolidated statements of operations. Cash settlements are also recorded as gain or loss on derivative contracts in the consolidated statements of operations. 
+ 
+The following table reflects the fair value of the Company’s derivative instruments for the periods presented: 
+ 
+ 
+ 
+ 
+Balance Sheet Presentation 
+Asset Fair Value 
+Liability Fair Value 
+Net Derivative Fair Value 
+Commodity 
+Classification 
+Line Description 
+12/31/2016 
+12/31/2015 
+12/31/2016 
+12/31/2015 
+12/31/2016 
+12/31/2015 
+Natural gas 
+Current 
+Fair value of derivatives 
+$ 
+— 
+$ 
+— 
+$ 
+(593)
+$ 
+— 
+$ 
+(593)
+$ 
+— 
+Oil 
+Current 
+Fair value of derivatives 
+103 
+19,943 
+(17,675)
+— 
+(17,572)
+19,943 
+Oil 
+Non-current 
+Fair value of derivatives 
+— 
+— 
+(28)
+— 
+(28)
+— 
+ 
+Total 
+$ 
+103 
+$ 
+19,943 
+$ 
+(18,296)
+$ 
+— 
+$ 
+(18,193)
+$ 
+19,943 
+ 
+72 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+As previously discussed, the Company’s derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated: 
+ 
+ 
+ 
+ 
+For the Year Ended December 31, 2016 
+ 
+Presented without 
+As Presented with 
+ 
+Effects of Netting 
+Effects of Netting 
+Effects of Netting 
+Current assets: Fair value of derivatives 
+$ 
+1,836 
+$ 
+(1,733)
+$ 
+103 
+ 
+Current liabilities: Fair value of derivatives 
+(20,001)
+1,733 
+(18,268)
+Long-term liabilities: Fair value of derivatives 
+$ 
+(28)
+$ 
+— 
+$ 
+(28)
+ 
+ 
+ 
+ 
+For the Year Ended December 31, 2015 
+ 
+Presented without 
+As Presented with 
+ 
+Effects of Netting 
+Effects of Netting 
+Effects of Netting 
+Current assets: Fair value of derivatives 
+$ 
+19,943 
+$ 
+— 
+$ 
+19,943 
+ 
+For the periods indicated, the Company recorded the following related to its derivatives in the consolidated statement of operations as gain or loss on derivative contracts: 
+ 
+ 
+ 
+For the Year Ended December 31, 
+ 
+2016 
+2015 
+2014 
+Natural gas derivatives 
+Net gain (loss) on settlements 
+$ 
+102 
+$ 
+1,717 
+$ 
+(84)
+Net gain (loss) on fair value adjustments 
+(593)
+(1,255)
+1,267 
+Total gain (loss) 
+$ 
+(491)
+$ 
+462 
+$ 
+1,183 
+Oil derivatives 
+Net gain on settlements 
+$ 
+17,801 
+$ 
+33,299 
+$ 
+4,170 
+Net gain (loss) on fair value adjustments 
+(37,543)
+(5,403)
+26,383 
+Total gain (loss) 
+$ 
+(19,742)
+$ 
+27,896 
+$ 
+30,553 
+ 
+Total gain (loss) on derivative contracts 
+$ 
+(20,233)
+$ 
+28,358 
+$ 
+31,736 
+ 
+73 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+Derivative positions 
+ 
+Listed in the tables below are the outstanding oil and natural gas derivative contracts as of December 31, 2016 : 
+ 
+ 
+ 
+For the Full Year of 
+For the Full Year of 
+Oil contracts 
+2017 
+2018 
+Swap contracts combined with short puts (WTI, enhanced swaps) 
+Total volume (MBbls) 
+730 
+— 
+Weighted average price per Bbl 
+Swap 
+$ 
+44.50 
+$ 
+— 
+Short put option 
+$ 
+30.00 
+$ 
+— 
+Deferred premium put option 
+Total volume (MBbls) 
+498 
+— 
+Premium per Bbl 
+$ 
+2.05 
+$ 
+— 
+Weighted average price per Bbl 
+Long put option 
+$ 
+50.00 
+$ 
+— 
+Deferred premium put spread option 
+Total volume (MBbls) 
+506 
+— 
+Premium per Bbl 
+$ 
+2.45 
+$ 
+— 
+Weighted average price per Bbl 
+Long put option 
+$ 
+50.00 
+$ 
+— 
+Short put option 
+$ 
+40.00 
+$ 
+— 
+Collar contracts (WTI, two-way collars) 
+Total volume (MBbls) 
+1,351 
+— 
+Weighted average price per Bbl 
+Ceiling (short call) 
+$ 
+58.19 
+$ 
+— 
+Floor (long put) 
+$ 
+47.50 
+$ 
+— 
+Call option contracts (short position) 
+Total volume (MBbls) 
+670 
+— 
+Weighted average price per Bbl 
+Call strike price 
+$ 
+50.00 
+$ 
+— 
+Swap contracts (Midland basis differential) 
+Volume (MBbls) 
+2,004 
+1,825 
+Weighted average price per Bbl 
+$ 
+(0.52)
+$ 
+(1.02)
+ 
+Natural gas contracts 
+Collar contracts combined with short puts (Henry Hub, three-way collars) 
+Total volume (BBtu) 
+1,460 
+— 
+Weighted average price per MMBtu 
+Ceiling (short call option) 
+$ 
+3.71 
+$ 
+— 
+Floor (long put option) 
+$ 
+3.00 
+$ 
+— 
+Short put option 
+$ 
+2.50 
+$ 
+— 
+Collar contracts (Henry Hub, two-way collars) 
+Total volume (BBtu) 
+1,460 
+— 
+Weighted average price per MMBtu 
+Ceiling (short call option) 
+$ 
+3.68 
+$ 
+— 
+Floor (long put option) 
+$ 
+3.00 
+$ 
+— 
+ 
+74 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+Subsequent event 
+ 
+The following derivative contract s w ere executed subsequent to December 31, 2016: 
+ 
+ 
+ 
+For the Remainder of 
+For the Remainder of 
+Oil contracts 
+2017 
+2018 
+Collar contracts combined with short puts (WTI, three-way collars) 
+Total volume (MBbls) 
+— 
+2,738 
+Weighted average price per Bbl 
+Ceiling (short call option) 
+$ 
+— 
+$ 
+62.84 
+Floor (long put option) 
+$ 
+— 
+$ 
+50.00 
+ 
+ 
+Note 7 - Fair Valu e Measurements 
+ 
+The fair value hierarchy included in GAAP gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable, and these valuations have the lowest priority. 
+ 
+Fair Value of Financial Instruments 
+ 
+Cash, cash equivalents, and restricted investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments. 
+ 
+Debt. The carrying amount of the Company’s floating-rate debt approximated fair value because the interest rates were variable and reflective of market rates. 
+ 
+ 
+ 
+December 31, 
+ 
+2016 
+2015 
+ 
+Carrying Value 
+Fair Value 
+Carrying Value 
+Fair Value 
+Credit Facility (a) 
+$ 
+— 
+$ 
+— 
+$ 
+40,000 
+$ 
+40,000 
+Second Lien (a) 
+— 
+— 
+288,565 
+288,565 
+6.125% Senior Notes (b) 
+390,219 
+412,000 
+— 
+— 
+Total 
+$ 
+390,219 
+$ 
+412,000 
+$ 
+328,565 
+$ 
+328,565 
+ 
+(a) 
+F loating - rate debt . 
+(b) 
+The fair value was based upon Level 2 inputs . See Note 5 for additional information about the Company’s 6.125% Senior Notes . 
+ 
+Assets and liabilities measured at fair value on a recurring basis 
+ 
+Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheet. The following methods and assumptions were used to estimate fair value: 
+ 
+Commodity derivative instruments. The fair value of commodity derivative instruments is derived using an income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. The Company believes that the majority of the inputs used to calculate the commodity derivative instruments fall within Level 2 of the fair value hierarchy based on the wide availability of quoted market prices for similar commodity derivative contracts. See Note 6 for additional information regarding the Company’s derivative instruments. 
+ 
+75 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis: 
+ 
+ 
+December 31, 2016 
+Classification 
+Level 1 
+Level 2 
+Level 3 
+Total 
+Assets 
+Derivative financial instruments 
+Fair value of derivatives 
+$ 
+— 
+$ 
+103 
+$ 
+— 
+$ 
+103 
+Liabilities 
+Derivative financial instruments 
+Fair value of derivatives 
+— 
+(18,296)
+— 
+(18,296)
+Total net assets 
+$ 
+— 
+$ 
+(18,193)
+$ 
+— 
+$ 
+(18,193)
+ 
+December 31, 2015 
+Classification 
+Level 1 
+Level 2 
+Level 3 
+Total 
+Assets 
+Derivative financial instruments 
+Fair value of derivatives 
+$ 
+— 
+$ 
+19,943 
+$ 
+— 
+$ 
+19,943 
+Liabilities 
+Derivative financial instruments 
+Fair value of derivatives 
+— 
+— 
+— 
+— 
+Total net assets 
+$ 
+— 
+$ 
+19,943 
+$ 
+— 
+$ 
+19,943 
+ 
+Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis 
+ 
+Acquisitions. The Company determine s the fair value of the assets acquired and liabilities assumed using the income approach based on expected discounted future cash flows from estimated reserve quantities, costs to produce and develop reserves, and oil and natural gas forward prices. The future net revenues are discounted using a weighted average cost of capital. The discounted future net revenues of proved undeveloped and probable reserves are reduced by an additional reserve adjustment factor to compensate for the inherent risk of estimating the value of unevaluated properties. The fair value measurements were based on Level 2 and Level 3 inputs. 
+ 
+Note 8 – Emplo yee Benefit Plans 
+ 
+The Company utilizes various forms of incentive compensation designed to align the interest of the executives and employees with those of its stockholders. Tabular disclosures related to the share-based awards are presented in Note 9 . The narrative that follows provides a brief description of each plan, summarizes the overall status of each plan and discusses current year awards under each plan: 
+ 
+Savings and Protection Plan 
+ 
+The Savings and Protection Plan (“401 (k) Plan”) provides employees with the option to defer receipt of a portion of their compensation, and the Company may, at its discretion, match a portion of the employee’s deferral with cash. The Company may also elect, at its discretion, to contribute a non-matching amount in cash and Company c ommon s tock to employees. The amounts held under the 401 (k) Plan are invested in various funds maintained by a third party in accordance with the directions of each employee. An employee is fully vested, including Company discretionary contributions, immediately upon participation in the 401 (k) Plan. The total amounts contributed by the Company, including the value of the common stock contributed, were $1,018 , $999 and $1,017 in the years 2016 , 2015 and 2014 , respectively. 
+ 
+2011 Omnibus Incentive Plan (the “2011 Plan”) 
+ 
+The 2011 Plan, which became effective May 12, 2011 following shareholder approval, authorized and reserved for issuance 2,300,000 shares of common stock, which may be issued upon exercise of vested stock options and/or the vesting of any other share-based equity award that is granted under this plan. The 2011 Plan is the Company’s only active plan, and included a provision at inception whereby all remaining, un-issued and authorized shares from the Company’s previous share-based incentive plans became issuable under the 2011 Plan. This transfer provision resulted in the transfer of an additional 841,000 shares into the plan, increasing the quantity authorized and reserved for issuance under the 2011 Plan to 3,141,000 at the inception of the plan. Another provision provided that shares , which would otherwise become available for issu ance under the previous plans as a result of vesting and/or forfeiture of any equity awards existing as of May 12, 2012, would also increase the authorized shares available to the 2011 Plan. 
+ 
+At the 2015 Annual Meeting of Shareholders, the Company’s shareholders approved the First Amendment to the Callon Petroleum Company 2011 Omnibus Incentive Plan (the “First Amendment”), which provided for (i) an increase in the number of shares of the Company’s common stock available for grant under the Plan by 2,000,000 shares from 2,300,000 shares to 4,300,000 shares, (ii) the adoption of a “double trigger” meaning that, in the event of a Company change in control, early vesting or payment occurs only if a change in control occurs and the executive’s employment is terminated or constructively terminated, and (iii) the elimination of the adding back of terminated options and stock appreciation rights shares for future grants. The First Amendment was made effective as of May 14, 2015. Including the transfer provision mentioned above, the quantity authorized and reserved for issuance under the 2011 Plan is 5,141,000 as of the effective date of the First Amendment. As of December 31, 2016 , the 2011 Plan had 2,270,448 shares remaining and eligible for future issuance. 
+76 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+ 
+RSU e quity a wards . RSU e quity awards issued under this plan may be subject to various vesting, accelerated vesting, and forfeiture provisions upon the occurrence of certain events. RSU e quity awards under the 2011 Plan generally vest over time but may also be subject to attaining a specified performance metrics and may vest immediately or cliff vest at a specified date. The Company will recognize expense on the grant date for all immediately vesting awards, while it will recognize expense ratably over the requisite service (i.e. vesting) period for both cliff and ratably vesting awards. 
+ 
+For market-based RSU equity awards, the Company recognizes expense based on the fair value of the awards at the grant date . Awards with a market-based provision do not allow for the reversal of previously recognized expense, even if the market metric is not achieved and no shares ultimately vest or are awarded. Market-based RSU equity awards that vest are based on a calculation that compares the Company’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between 0% and 200% of the base units awarded. 
+ 
+Cash- s ettled RSU a wards. Certain of the Company’s RSUs awarded require cash settlement. Cash-settled RSU awards are accounted for as liabilities as the Company is contractually obligated to settle these awards in cash. Changes in the fair value of cash-settleable awards are recorded as adjustments to compensation expense. 
+ 
+A significant portion of the Company’s cash-settled RSU awards include a market-based vesting condition that determines the actual number of units that will ultimately vest. The number of RSUs that vest is based on a calculation that compares the Company’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between 0% and 200% of the base units awarded. The fair value of the Company’s market-based RSU awards is calculated using a Monte Carlo valuation model, which considers such inputs as the Company’s and its peer group’s stock prices, a risk-free interest rate, and an estimated volatility for the Company and its peer group. 
+ 
+Note 9 - Shar e-Based Compensation 
+ 
+As discussed in Note 8 , the Company grants various forms of share-based compensation awards to employees of the Company and its subsidiaries and to non-employee members of the Board of Directors. At December 31, 2016 , shares available for future share-based awards, including stock options or restricted stock grants, under the Company’s only active plan, the 2011 Plan, were 2,270,448 . 
+ 
+The following table presents share-based compensation expense for each respective period: 
+ 
+ 
+ 
+For the Year Ended December 31, 
+ 
+2016 
+2015 
+2014 
+Share-based compensation cost for: 
+Equity-based 
+Liability-based 
+Equity-based 
+Liability-based 
+Equity-based 
+Liability-based 
+RSU equity awards 
+$ 
+4,536 
+$ 
+— 
+$ 
+3,797 
+$ 
+— 
+$ 
+4,223 
+$ 
+— 
+Cash-settleable RSU awards 
+— 
+12,285 
+— 
+11,437 
+— 
+6,918 
+401(k) contributions in shares 
+277 
+— 
+266 
+— 
+270 
+— 
+Total share-based compensation cost (a) 
+$ 
+4,813 
+$ 
+12,285 
+$ 
+4,063 
+$ 
+11,437 
+$ 
+4,493 
+$ 
+6,918 
+ 
+(a) 
+The portion of this share-based compensation cost that was included in general and administrative expense totaled $9,722 , $9,299 and $7,235 for the same years, respectively, and the portion capitalized to oil and gas properties was $7,376, $6,201 and $4,176 , respectively. 
+ 
+The following table presents the unrecognized compensation cost for the indicated periods: 
+ 
+ 
+ 
+December 31, 
+Unrecognized compensation cost related to: 
+2016 
+2015 
+2014 
+Unvested RSU equity awards 
+$ 
+7,276 
+$ 
+5,208 
+$ 
+3,979 
+Unvested cash-settleable RSU awards 
+8,948 
+4,728 
+4,977 
+ 
+The Company’s unrecognized compensation cost related to unvested RSU equity awards and cash-settleable RSU awards is expected to be recognized over a weighted-average period of 2 years . 
+ 
+The following table summarizes the Company’s liability for cash-settled RSU awards for the periods indicated: 
+ 
+ 
+ 
+December 31, 
+Consolidated Balance Sheets Classification 
+2016 
+2015 
+Cash-settled RSU awards (current) 
+$ 
+8,919 
+$ 
+10,128 
+Cash-settled RSU awards (non-current) 
+8,071 
+4,877 
+Total cash-settled RSU awards 
+$ 
+16,990 
+$ 
+15,005 
+ 
+77 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+Stock Options 
+ 
+The Company issued no stock options for the past three years and had no options vest or forfeit during 2016 . Additionally, no options were exercised, and no options expired unexercised during the year. As of December 31, 2016 , the Company had 15,000 options outstanding and exercisable at a weighted average exercise price per option of $14.37 , with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 0.3 years. As of December 31, 2015 , the Company had 15,000 options outstanding and exercisable at a weighted average exercise price per option of $14.37 , with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 1.3 years. As of December 31, 201 4 , the Company had 30,000 options outstanding and exercisable at a weighted average exercise price per option of $14.04 , with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 1.3 years. 
+ 
+Restricted Stock Units 
+ 
+The following table represents unvested restricted stock activity for the year ended December 31, 2016 : 
+ 
+ 
+ 
+Weighted average 
+(shares in 000s) 
+Number of Shares 
+Grant-Date Fair Value per Share 
+Period over which expense is expected to be recognized 
+Outstanding at the beginning of the period 
+1,416 
+$ 
+6.94 
+Granted (a) 
+684 
+12.63 
+Vested (b) 
+(630)
+4.14 
+Forfeited 
+(22)
+9.56 
+Outstanding at the end of the period 
+1,448 
+$ 
+10.81 
+1.6 
+ 
+(a) 
+Includes 143 market-based RSUs that will vest at a range of 0% - 200% . See Note 8 for additional information about market-based RSU equity awards. 
+(b) 
+The fair value of shares vest ed was $2,608 . 
+ 
+For the year ended December 31, 2015 , the Company granted 559,556 RSUs with a weighted average grant-date fair value of $8.98 per share. The fair value of shares vested during 2015 was $5,425 . For the year ended December 31, 2014 , the Company granted 333,468 RSUs with a weighted average grant-date fair value of $9.67 per share. The fair value of shares vested during 2014 was $4,338 . 
+ 
+As of December 31, 2016 , the Company had the following cash-settleable RSUs outstanding (including those that are not based on a market condition): 
+ 
+ 
+(shares in 000s) 
+Base Units Outstanding 
+Potential Minimum Units Vesting 
+Potential Maximum Units Vesting 
+Vesting in 2017 
+227 
+19 
+435 
+Vesting in 2018 
+244 
+25 
+464 
+Vesting in 2019 
+29 
+29 
+29 
+Other 
+191 
+191 
+191 
+Total cash-settleable RSUs 
+691 
+264 
+1,119 
+ 
+For the year ended December 31, 2016 , 281,792 market-based cash-settled RSUs subject to the peer market-based vesting described in Note 8 vested at 200% of their issued units , resulting in payable amounts of $8,662 in 2017 . Also during 2016 , 45,282 non-market-based cash settled RSUs vested, resulting in cash payments of $493 in 2016 . During 2015 , 853,673 market-based cash-settled RSUs subject to the peer market-based vesting described above vested at between 150% - 200% of their issued units, depending on the date of the vesting, resulting in cash payments of $3,319 in 2015 and $9,807 in 2016 . Also during 2015 , 72,108 non-market-based cash settled RSUs vested, resulting in cash payments of $545 in 2015 . See Note 8 for additional information regarding cash-settleable RSUs. 
+ 
+Note 10 – Eq uity Transactions 
+ 
+10% Series A Cumulative Preferred Stock (“Preferred Stock”) 
+ 
+Holders of the Company’s Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10.0% per annum of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share). Dividends are payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by our Board of Directors. Preferred Stock dividends were $7,295 , $7,895 and $7,895 in 2016 , 2015 and 2014 respectively. 
+78 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+ 
+The Preferred Stock has no stated maturity and is not subject to any sinking fund or other mandatory redemption. On or after May 30, 2018, the Company may, at its option, redeem the Preferred Stock, in whole or in part, by paying $50.00 per share, plus any accrued and unpaid dividends to the redemption date. 
+ 
+Following a change of control in which the Company or the acquirer no longer have a class of common securities listed on a national exchange, the Company will have the option to redeem the Preferred Stock, in whole but not in part for $50.00 per share in cash, plus accrued and unpaid dividends (whether or not declared), to the redemption date. If the Company does not exercise its option to redeem the Preferred Stock upon such change of control, the holders of the Preferred Stock have the option to convert the Preferred Stock into a number of shares of the Company’s common stock based on the value of the common stock on the date of the change of control as determined under the certificate of designations for the Preferred Stock. If the change of control occurred on December 31, 2016 , and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of $ 15.37 as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately 3 . 3 shares of common stock. If the Company exercises its redemption rights relating to shares of Preferred Stock, the holders of Preferred Stock will not have the conversion right described above. 
+ 
+On February 4, 2016, the Company exchanged a total of 120 ,000 shares of Preferred Stock for 719,000 shares of c ommon s tock. As of December 31, 2016 , the Company had 1,458,948 shares of its Preferred Stock issued and outstanding. 
+ 
+Common Stock 
+ 
+On December 1 9 , 2016, the Company completed an underwritten public offering of 40,000,000 shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $634,917 . Proceeds from the offering were used to substantially fund the Ameredev Transaction, described in Note 3 . 
+ 
+On September 6, 2016, the Company completed an underwritten public offering of 29,900,000 shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $421,864 . Proceeds from the offering were used to substantially fund the Plymouth Transaction, described in Note 3 . 
+ 
+On May 26, 2016, the Company issued 9,333,333 shares of common stock to partially fund the Big Star Transaction, described in Note 3 , at an assumed offering price of $11.74 per share, which is the last reported sale price of our common stock on the New York Stock Exchange on that date. 
+ 
+On April 25, 2016, the Company completed an underwritten public offering of 25,300,000 shares of its common stock for total net proceeds (after the underwriter’s discounts and commissions and estimated offering expenses) of approximately $205,869 . Proceeds from the offering were used to fund the Big Star Transaction, described in Note 3 , and other working interest acquisitions. 
+ 
+On March 9, 2016, the Company completed an underwritten public offering of 15,250,000 shares of its common stock for total net proceeds (after the underwriting discounts and estimated offering costs) of approximately $94,948 . Proceeds from the offering were used to pay down the balance on the Company’s Credit Facility and for general corporate purposes. 
+ 
+On November 16 , 2015, the Company completed an underwritten public offering of 12,000,000 shares of its common stock at $ 8.40 per share, before underwriting discounts, and the exercise in full by the underwriters of their option to purchase 1,800,000 additional shares of common stock at $8.40 per share, before underwriting discounts. The Company received net proceeds of approximately $109,864 , after the underwriting discounts and estimated offering costs , which were used to repay amounts outstanding under the Credit Facility . 
+ 
+On March 13, 2015, the Company completed an underwritten public offering of 9,000,000 shares of its common stock at $ 6.55 per share, before underwriting discounts, and the exercise in full by the underwriters of their option to purchase 1,350,000 additional shares of common stock at $6.55 per share, before underwriting discounts. The Company received net proceeds of approximately $65,595 , after the underwriting discounts and estimated offering costs , which were used to repay amounts outstanding under the Credit Facility. 
+ 
+On September 15, 2014 the Company completed an underwritten public offering of 12,500,000 shares of its common stock at $9.00 per share, before underwriting discounts, and the exercise in full by the underwriters of their option to purchase 1,875,000 additional shares of common stock at $9.00 per share. The Company received net proceeds of approximately $122,450 , after the underwriting discounts and estimated offering costs, which were used to fund a portion of the purchase price of the Central Midland Basin Transaction , described in Note 3 . 
+ 
+ 
+79 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+Note 11 - Inco me Taxes 
+ 
+The following table presents Callon’s deferred tax assets and liabilities with respect to its carryforwards and other temporary differences: 
+ 
+ 
+As of December 31, 
+ 
+2016 
+2015 
+Deferred tax asset 
+Federal net operating loss carryforward (a) 
+$ 
+135,711 
+$ 
+107,935 
+Statutory depletion carryforward 
+8,843 
+8,843 
+Alternative minimum tax credit carryforward 
+104 
+208 
+Asset retirement obligations 
+1,181 
+630 
+Derivatives 
+6,456 
+— 
+Unvested RSU equity awards 
+2,092 
+1,418 
+Other 
+4,376 
+6,823 
+Deferred tax asset before valuation allowance 
+158,763 
+125,857 
+Deferred tax liability 
+Oil and natural gas properties 
+18,661 
+6,488 
+Derivatives 
+— 
+6,984 
+Other 
+— 
+3,542 
+Total deferred tax liability 
+18,661 
+17,014 
+Net deferred tax asset before valuation allowance 
+140,102 
+108,843 
+Less: Valuation allowance 
+(140,192)
+(108,843)
+Net deferred tax liability 
+$ 
+(90)
+$ 
+— 
+ 
+(a) 
+The Company’s $135,711 deferred tax asset related to NOL carryforwards is net of $9,288 of unrealized excess tax benefits related to stock based compensation. 
+ 
+If not utilized, the Company’s federal operating loss (“NOL”) carryforwards will expire as follows: 
+ 
+ 
+ 
+Year Expiring 
+ 
+Total 
+2017-2022 
+2023-2025 
+2026-2028 
+2029-2031 
+2032-2036 
+Federal NOL carryforwards 
+$ 
+387,745 
+$ 
+56,979 
+$ 
+65,878 
+$ 
+32,714 
+$ 
+53,806 
+$ 
+178,368 
+ 
+As a result of the write-down of oil and natural gas properties discussed in Notes 2 and 13 , the Company has incurred a cumulative three year loss. Because of the impact the cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, the Company assessed the ability to realize its deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, the Company established a valuation allowance for a portion of the deferred tax asset. The valuation allowance was $140,192 as of December 31, 2016 . 
+ 
+The Company had no significant unrecognized tax benefits at December 31, 2016 . Accordingly, the Company does not have any interest or penalties related to uncertain tax positions. However, if interest or penalties were to be incurred related to uncertain tax positions, such amounts would be recognized in income tax expense. Tax periods for years 200 3 through 201 6 remain open to examination by the federal and state taxing jurisdictions to which the Company is subject. 
+ 
+The Company provides for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses and state income taxes. The following table presents a reconciliation of the reported amount of income tax expense to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income from continuing operations : 
+ 
+ 
+ 
+For the Year Ended December 31, 
+Components of income tax rate reconciliation 
+2016 
+2015 
+2014 
+Income tax expense computed at the statutory federal income tax rate 
+35% 
+35% 
+35% 
+Percentage depletion carryforward 
+—% 
+—% 
+—% 
+State taxes net of federal benefit 
+—% 
+1% 
+1% 
+Restricted stock and stock options 
+—% 
+—% 
+—% 
+Section 162(m) 
+(1)% 
+(1)% 
+2% 
+Valuation allowance 
+(34)% 
+(54)% 
+—% 
+Effective income tax rate 
+—% 
+(19)% 
+38% 
+ 
+ 
+80 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+ 
+For the Year Ended December 31, 
+Components of income tax expense 
+2016 
+2015 
+2014 
+Current federal income tax benefit 
+$ 
+(104)
+$ 
+— 
+$ 
+— 
+Current state income tax expense 
+— 
+— 
+— 
+Deferred federal income tax (benefit) expense 
+— 
+(69,087)
+22,373 
+Deferred state income tax (benefit) expense 
+90 
+(1,282)
+761 
+Valuation allowance 
+— 
+108,843 
+— 
+Total income tax expense 
+$ 
+(14)
+$ 
+38,474 
+$ 
+23,134 
+ 
+ 
+. 
+Note 12 - Asset Reti rement Obligations 
+ 
+The table below summarizes the activity for the Company’s asset retirement obligations: 
+ 
+ 
+ 
+For the Year Ended December 31, 
+ 
+2016 
+2015 
+Asset retirement obligations at January 1, 2016 
+$ 
+5,107 
+$ 
+6,674 
+Accretion expense 
+958 
+660 
+Liabilities incurred 
+84 
+165 
+Liabilities settled 
+(2,378)
+(2,964)
+Revisions to estimate 
+2,890 
+572 
+Asset retirement obligations at end of period 
+6,661 
+5,107 
+Less: Current asset retirement obligations 
+(2,729)
+(790)
+Long-term asset retirement obligations at December 31, 2016 
+$ 
+3,932 
+$ 
+4,317 
+ 
+Certain of the Company’s operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded on the Consolidated Balance Sheets at December 31, 2016 and 2015 as long-term restricted investments were $3,332 and $3,309 , respectively. These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties. 
+ 
+ 
+81 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+Note 13 – Supplemental Information on Oil and N atural Gas Properties (Unaudited) 
+ 
+The following table discloses certain financial data relating to the Company’s oil and natural gas activities, all of which are located in the United States. 
+ 
+ 
+ 
+For the Year Ended December 31, 
+ 
+2016 
+2015 
+2014 
+Evaluated Properties (a) 
+Beginning of period balance 
+$ 
+2,335,223 
+$ 
+2,077,985 
+$ 
+1,701,577 
+Capitalized G&A expenses 
+12,222 
+10,529 
+10,071 
+Property acquisition costs (b) 
+216,561 
+26,726 
+94,541 
+Exploration costs 
+38,612 
+81,320 
+118,251 
+Development costs 
+151,735 
+138,663 
+153,545 
+End of period balance 
+$ 
+2,754,353 
+$ 
+2,335,223 
+$ 
+2,077,985 
+Unevaluated Properties (a)( c) 
+Beginning of period balance 
+$ 
+132,181 
+$ 
+142,525 
+$ 
+43,222 
+Property acquisition costs (b) 
+548,673 
+5,520 
+128,342 
+Exploration costs 
+8,631 
+4,576 
+11,177 
+Capitalized interest expenses 
+19,857 
+10,459 
+4,295 
+Transfers to Evaluated Properties 
+(40,621)
+(30,899)
+(44,511)
+End of period balance 
+$ 
+668,721 
+$ 
+132,181 
+$ 
+142,525 
+Accumulated depreciation, depletion and amortization 
+Beginning of period balance 
+$ 
+1,756,018 
+$ 
+1,478,355 
+$ 
+1,420,612 
+Provision charged to expense 
+71,330 
+69,228 
+56,663 
+Write-down of oil and natural gas properties (a) 
+95,788 
+208,435 
+— 
+Sale of mineral interests 
+24,537 
+— 
+1,080 
+End of period balance 
+$ 
+1,947,673 
+$ 
+1,756,018 
+$ 
+1,478,355 
+ 
+ 
+(a) 
+The Company uses the full cost method of accounting for its exploration and development activities. See the Company’s accounting policy about oil and natural gas properties in Note 2 for details on the full cost method of accounting. 
+(b) 
+See Note 3 in the Footnotes to the Financial Statements for additional information about the Company’s significant acquisitions . 
+(c) 
+Unevaluated property costs primarily include lease acquisition costs, unevaluated drilling costs, seismic, capitalized interest expenses and certain overhead costs related to exploration and development. These costs are directly related to the acquisition and evaluation of unproved properties. The excluded costs and related reserves are included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined. The majority of these costs are primarily associated with the Company’s focus areas of its future development program and are expected to be evaluated over ten to fifteen years. T he Company’s unevaluated property balance of $668,721 as of December 31, 2016, consisted of $123,345 , $521,520 and $23,856 of costs attributable to our Monarch , Wild H orse and Ranger operating area s , respectively. 
+ 
+Subsequent to December 31, 2016 , and through February 22, 2017 , the Company drill ed four gross ( 3.4 net) horizontal wells and completed five gross ( 3.4 net) horizontal wells and had five gross ( 4.1 net) horizontal wells a waiting completion. 
+Depletion per unit-of-production, on a BOE basis, amounted to $12.81 , $19.74 and $27.51 for the years ended December 31, 2016 , 2015 , and 2014 , respectively. Lease operating expenses per unit-of-production, on a BOE basis, amounted to $6.88 , $7.71 , and $10.85 for the years ended December 31, 2016 , 2015 , and 2014 , respectively. 
+ 
+Estimated Reserves 
+ 
+The Company’s proved oil and natural gas reserves at December 31, 2016 , 2015 and 2014 have been estimated by DeGolyer and MacNaughton, the Company’s current independent petroleum engineers. The reserves were prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions. 
+ 
+There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only, and should not be deemed exact. In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company’s oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves. 
+ 
+ 
+The following tables disclose changes in the estimated net quantities of oil and natural gas reserves, all of which are located onshore within the continental United States: 
+ 
+ 
+82 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+ 
+For the Year Ended December 31, 
+Proved developed and undeveloped reserves: 
+2016 
+2015 
+2014 
+Oil (MBbls): 
+Beginning of period 
+43,348 
+25,733 
+11,898 
+Revisions to previous estimates 
+(5,738)
+(1,632)
+(243)
+Purchase of reserves in place 
+25,054 
+2,932 
+3,223 
+Sale of reserves in place 
+(1,718)
+(23)
+— 
+Extensions and discoveries 
+14,479 
+19,127 
+12,547 
+Production 
+(4,280)
+(2,789)
+(1,692)
+End of period 
+71,145 
+43,348 
+25,733 
+Natural Gas (MMcf): 
+Beginning of period 
+65,537 
+42,548 
+17,751 
+Revisions to previous estimates 
+13,929 
+4,870 
+(215)
+Purchase of reserves in place 
+36,474 
+2,915 
+8,591 
+Sale of reserves in place 
+(2,765)
+(105)
+— 
+Extensions and discoveries 
+17,194 
+19,621 
+18,641 
+Production 
+(7,758)
+(4,312)
+(2,220)
+End of period 
+122,611 
+65,537 
+42,548 
+ 
+ 
+ 
+ 
+For the Year Ended December 31, 
+Proved developed reserves: 
+2016 
+2015 
+2014 
+Oil (MBbls): 
+Beginning of period 
+22,257 
+14,006 
+5,960 
+End of period 
+32,920 
+22,257 
+14,006 
+Natural gas (MMcf): 
+Beginning of period 
+38,157 
+25,171 
+9,059 
+End of period 
+61,871 
+38,157 
+25,171 
+MBOE: 
+Beginning of period 
+28,617 
+18,201 
+7,470 
+End of period 
+43,232 
+28,617 
+18,201 
+Proved undeveloped reserves: 
+Oil (MBbls): 
+Beginning of period 
+21,091 
+11,727 
+5,938 
+End of period 
+38,225 
+21,091 
+11,727 
+Natural gas (MMcf): 
+Beginning of period 
+27,380 
+17,377 
+8,692 
+End of period 
+60,740 
+27,380 
+17,377 
+MBOE: 
+Beginning of period 
+25,654 
+14,623 
+7,387 
+End of period 
+48,348 
+25,654 
+14,623 
+ 
+Total Proved Reserves: The Company ended 2016 with estimated net proved reserves of 91,580 MBOE, representing a 69% increase over 2015 year-end estimated net proved reserves of 54,271 MBOE. The Company added 48,477 MBOE primarily from the Company’s acquisition and development efforts in the Permian Basin, where it drilled a total of 29 gross ( 20.9 net) wells. This increase was primarily offset by 11,168 M BOE related to divestitures, 2016 production and revisions primarily due to pricing. 
+ 
+The Company ended 2015 with estimated net proved reserves of 54,271 MBOE, representing a 65% increase over 2014 year-end estimated net proved reserves of 32,824 MBOE. The increase was primarily due the Company’s development of its properties in the Permian Basin, where it drilled a total of 36 gross ( 27.1 net) wells, and acquisitions made during 2015. This increase was primarily offset by 2015 production and revisions. 
+ 
+The Company ended 2014 with estimated net proved reserves of 32,824 MBOE, representing a 121% increase over 2013 year-end estimated net proved reserves of 14,857 MBOE. The increase was primarily due the Company’s development of its properties in the Permian Basin, where it drilled a total of 34 gross ( 28.7 net) wells, and acquisitions made during 2014. This increase was primarily offset by 2014 production and revisions. 
+83 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+ 
+Extrapolation of performance history and material balance estimates were utilized by the Company’s independent petroleum and geological firm to project future recoverable reserves for the producing properties where sufficient history existed to suggest performance trends and where these methods were applicable to the subject reservoirs. The projections for the remaining producing properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to nonproducing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production, and to a small extent, horizontal PDP and PUD categories. 
+ 
+Proved Undeveloped Reserves: The Company annually reviews its proved undeveloped reserves (“PUDs”) to ensure an appropriate plan for development exists. Generally, reserves for the Company’s properties are booked as PUDs only if the Company has plans to convert the PUDs into proved developed reserves within five years of the date they are first booked as PUDs. The Company’s PUDs increased 88% to 48,348 MBOE from 25,654 MBOE at December 31, 2016 and 2015 , respectively. The Company added 17,482 MBOE to its PUDs, primarily from acquisitions in the Permian Basin, net of divestitures, and added 12,035 MBOE from the continued horizontal development of its Permian Basin properties, net of revisions. The increase in Permian Basin PUDs was partially offset by the reclassification of 6,823 MBOE , or 27% , inclu ded in the year-end 2015 PUDs, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately $43,415 , net. 
+ 
+The Company’s PUDs increased 75% to 25,654 MBOE from 14,623 MBOE at December 31, 2015 and 2014, respectively. The Company added 13,774 MBOE to its PUDs, net of revisions, primarily from the continued horizontal development of its Permian Basin properties and from acquisitions in the Permian Basin. The increase in Permian Basin PUDs was partially offset by the reclassification of 2,742 MBOE, or 19% , included in the year-end 2014 PUDs, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately $55,933 , net. 
+ 
+The Company’s PUDs increased 98% to 14,623 MBOE from 7,387 MBOE at December 31, 2014 and 2013, respectively. The Company added 10,125 MBOE to its PUDs, net of revisions, primarily from the continued horizontal development of its Permian Basin properties and from acquisitions in the Permian Basin. The increase in Permian Basin PUDs was partially offset by the reclassification of 1,757 MBOE, or 24% , included in the year-end 2013 PUD reserves, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately $ 34,619 , net. Also offsetting the increase was the removal of 1,132 MBOE of PUDs, including the impact from the reclassification of previous vertical PUDs to the horizontal probable category given our focus on horizontal development. 
+ 
+Standardized Measure 
+ 
+The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2016 . You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Prices are based on the preceding 12-months’ average price based on closing prices on the first day of each month. The following table summarizes the average 12-month oil and natural gas prices net of differentials for the respective periods: 
+ 
+ 
+ 
+ 
+2016 
+2015 
+2014 
+Average 12-month price, net of differentials, per Mcf of natural gas (a) 
+$ 
+2.71 
+$ 
+2.73 
+$ 
+6.38 
+Average 12-month price, net of differentials, per barrel of oil (b) 
+$ 
+40.03 
+$ 
+47.25 
+$ 
+86.30 
+ 
+(a) 
+Includes a high Btu content of separator natural gas and adjustments to reflect the Btu content, transportation charges and other fees specific to the individual properties. 
+(b) 
+Includes adjustments to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality. 
+ 
+84 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate. 
+ 
+ 
+ 
+Standardized Measure 
+ 
+For the Year Ended December 31, 
+ 
+2016 
+2015 
+2014 
+Future cash inflows 
+$ 
+3,180,005 
+$ 
+2,227,463 
+$ 
+2,492,178 
+Future costs 
+Production 
+(974,667)
+(827,555)
+(873,469)
+Development and net abandonment 
+(384,117)
+(239,100)
+(288,081)
+Future net inflows before income taxes 
+1,821,221 
+1,160,808 
+1,330,628 
+Future income taxes 
+(1,602)
+— 
+(164,490)
+Future net cash flows 
+1,819,619 
+1,160,808 
+1,166,138 
+10% discount factor 
+(1,009,787)
+(589,918)
+(586,596)
+Standardized measure of discounted future net cash flows 
+$ 
+809,832 
+$ 
+570,890 
+$ 
+579,542 
+ 
+ 
+ 
+ 
+Changes in Standardized Measure 
+ 
+For the Year Ended December 31, 
+ 
+2016 
+2015 
+2014 
+Standardized measure at the beginning of the period 
+$ 
+570,890 
+$ 
+579,542 
+$ 
+283,946 
+Sales and transfers, net of production costs 
+(150,628)
+(110,476)
+(120,518)
+Net change in sales and transfer prices, net of production costs 
+(103,136)
+(286,660)
+(156,066)
+Net change due to purchases and sales of in place reserves 
+260,859 
+37,616 
+111,331 
+Extensions, discoveries, and improved recovery, net of future production and development costs incurred 
+180,228 
+184,469 
+299,192 
+Changes in future development cost 
+82,320 
+108,216 
+186,605 
+Revisions of quantity estimates 
+(35,938)
+(12,625)
+(7,673)
+Accretion of discount 
+57,091 
+62,968 
+30,114 
+Net change in income taxes 
+16 
+35,407 
+(32,940)
+Changes in production rates, timing and other 
+(51,870)
+(27,567)
+(14,449)
+Aggregate change 
+238,942 
+(8,652)
+295,596 
+Standardized measure at the end of period 
+$ 
+809,832 
+$ 
+570,890 
+$ 
+579,542 
+ 
+ 
+ 
+ 
+Note 14 – Other 
+ 
+Commitments and contingencies 
+ 
+The Company is involved in various claims and lawsuits incidental to its business. In the opinion of management, the ultimate liability hereunder, if any, will not have a material adverse effect on the financial position or results of operations of the Company. 
+ 
+The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment are not expected to have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies hereunder, and claims for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities. 
+ 
+Operating leases 
+ 
+As of December 31, 2016 , the Company had contracts for t hree horizontal drilling rigs (the “Cactus 1 Rig” , “Cactus 2 Rig” and “Cactus 3 Rig” ) . The contract terms , as amended through December 31, 2016, of the Cactus 1 Rig and Cactus 2 Rig will end in July 2018 and August 2018 , respectively. Effective October 27, 2016, the Company entered into a contract for the Cactus 3 Rig, which commence d drilling in mid-January 2017. The contract terms of the Cactus 3 Rig will end in July 2017. 
+ 
+The rig lease agreements include early termination provisions that obligate the Company to reduced minimum rentals for the remaining term of the agreement. These payments would be reduced assuming the lessor is able to re-charter the rig and staffing personnel to another lessee. In January 2016, the Company decided to place the Cactus 1 Rig on standby and was required to pay a “standby” day 
+85 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+rate of $ 15,000 per day, pursuant to the terms of the agreement , a llowing t he Company to retain the option to return the rig to service under the contract terms . In August 2016, the Company returned its Cactus 1 Rig to service. 
+ 
+In March 2015, the Company decided to terminate its one-year contract for a vertical rig (effective April 2015) . The Company paid approximately $3,075 in reduced rental payments over the remainder of the lease term, which ended November 2015 . The amount was recognized as rig termination fee on the consolidated statements of operations for the year ende d December 31, 2015. 
+ 
+ 
+Note 15 – S ummarized Quarterly Financial Information (Unaudited) 
+ 
+ 
+2016 
+First Quarter 
+Second Quarter 
+Third Quarter 
+Fourth Quarter 
+Total revenues 
+$ 
+30,698 
+$ 
+45,145 
+$ 
+55,927 
+$ 
+69,081 
+Income (loss) from operations (a) 
+(34,767)
+(50,529)
+16,651 
+21,168 
+Net income (loss) (a) 
+(41,109)
+(70,097)
+21,139 
+(1,746)
+Income (loss) available to common shares 
+(42,933)
+(71,920)
+19,315 
+(3,570)
+Income (loss) per common share - basic 
+$ 
+(0.51)
+$ 
+(0.61)
+$ 
+0.14 
+$ 
+(0.02)
+Income (loss) per common share - diluted 
+$ 
+(0.51)
+$ 
+(0.61)
+$ 
+0.14 
+$ 
+(0.02)
+ 
+(a) 
+Loss from operations and net loss for the three months ended March, 31, 2016 and June 30, 2016 included write-downs of oil and natural gas properties of $34,776 and $61,012 , respectively. 
+ 
+ 
+ 
+2015 
+First Quarter 
+Second Quarter 
+Third Quarter 
+Fourth Quarter 
+Total revenues 
+$ 
+30,391 
+$ 
+39,242 
+$ 
+34,316 
+$ 
+33,563 
+Income (loss) from operations (a) 
+(12,889)
+6,231 
+(83,910)
+(118,542)
+Net loss (a) 
+(10,197)
+(4,967)
+(111,805)
+(113,170)
+Loss available to common shares 
+(12,171)
+(6,940)
+(113,779)
+(115,144)
+Loss per common share - basic 
+$ 
+(0.21)
+$ 
+(0.11)
+$ 
+(1.72)
+$ 
+(1.58)
+Loss per common share - diluted 
+$ 
+(0.21)
+$ 
+(0.11)
+$ 
+(1.72)
+$ 
+(1.58)
+ 
+(a) 
+Lo ss from operations and net loss for the three months ended September 30, 2015 and December 31, 2015 included write-downs of oil and natural gas pro perties of $87,301 and $121,134 , respectively . 
+ 
+ 
+86 
+Table of Contents 
+ITEM 9. Chan ges In and Disagreements w ith Accountants on Accounting and Financial Disclosure 
+ 
+On January 11, 2016, the Audit Committee of the Board of Directors of Callon Petroleum Company (the “Company”) approved the engagement of Grant Thornton LLP (“GT”) as the Company’s independent registered public accounting firm for the year ending December 31, 2016. GT informed the Company that it completed the prospective client evaluation process on January 14, 2016. In conn ection with the selection of GT , also on January 11, 2016, the Audit Committee informed Ernst & Young LLP (“E&Y”) that they w ould no longer serve as the Company’s independent registered public accounting firm no later than the date of the filing of the Company’s Form 10-K for the 2015 fiscal year. The Audit Committee made its decision in connection with its annual review of the Company’s independent registered public accounting firm and after soliciting proposals from several accounting firms , including E&Y . 
+ 
+During the year ended December 31, 2014 and through January 11, 2016, neither the Company nor anyone on its behalf consulted with GT with respect to either (i) the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on the Registrant’s consolidated financial statements, and neither written nor oral advice was provided to the Company that GT concluded was an important factor considered by the Company in reaching a decision as to any accounting, auditing or financial reporting issue; (ii) any matter that was either the subject of disagreement (as defined in Item 304(a)(l)(iv) of Regulation S-K and the related instructions to Item 304 of Regulations S-K) or a reportable event (as defined by Item 304(a)(l)(v) of Regulation S-K). 
+ 
+The report of E&Y on the Company’s consolidated financial statements for the year s ended December 31, 201 5 and 2014 , did not contain an adverse opinion or disclaimer of an opinion, and was not qualified or modified as to uncertainty, audit scope or accounting principles. 
+ 
+Item 9A. Co ntrols and Procedures 
+ 
+Disclosure controls and procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our Chief Executive Officer and Chief Financial Officer performed an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2016 . 
+ 
+Management’s report on internal control over financial reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. generally accepted accounting principles. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2016 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission ( 2013 framework)(the COSO criteria). Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2016 . 
+ 
+Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+ 
+The Company’s independent registered public accounting firm has issued an attestation report regarding its assessment of the Company’s internal control over financial reporting as of December 31, 2016 , which follows Part II, Item 9B of this filing. Additionally, the financial statements for the year ended December 31, 2016, covered in this Annual Report on Form 10-K , have been audited by an independent registered public accounting firm, Grant Thornton LLP, whose report is presented immediately preceding the Company’s financial statements included in Part II, Item 8 of this Annual Report on Form 10 -K. The financial statements for the years ended December 31, 2015 and 2014 were audited by the independent registered public accounting firm, Ernst & Young LLP, whose report is presented immediately preceding the company’s financial statements included in Part II, Item 8 of this Annual Report on Form 10-K. 
+ 
+Changes in internal control over financial reporting . There were no changes to our interna l control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting. 
+ 
+ 
+87 
+Table of Contents 
+ITEM 9A (T). Controls and Procedures 
+ 
+See Item 9A. 
+ 
+ITEM 9B. Othe r Information 
+ 
+Submissions of m atters to a v ote of the s ecurity h olders . 
+ 
+None. 
+ 
+88 
+Table of Contents 
+Repo rt of Independent Registered Public Accounting Firm 
+ 
+ 
+Board of Directors and Stockholders 
+Callon Petroleum Company 
+We have audited the internal control over financial reporting of Callon Petroleum Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2016 , based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s report on internal control over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. 
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016 , based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Company as of and for the year ended December 31, 2016 , and our report dated February 27, 2017 expressed an unqualified opinion on those financial statements. 
+/s/ GRANT THORNTON LLP 
+ 
+Houston , Texas 
+February 27, 2017 
+ 
+ 
+89 
+Table of Contents 
+PAR T III. 
+ 
+ITEM 10. Direc tors, Executive Officers and Corporate Governance 
+ 
+For information concerning Item 10, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 11, 2017 , which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+ 
+The Company has adopted a code of ethics that applies to the Company’s chief executive officer, chief financial officer and chief accounting officer. The full text of such code of ethics has been posted on the Company’s w ebsite at www.callon.com, and is available free of charge in print to any shareholder who requests it. Request for copies should be addressed to the Secretary at mailing address Post Office Box 1287, Natchez, Mississippi 39121. 
+ 
+ITEM 11. Exec utive Compensation 
+ 
+For information concerning Item 11, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 11, 2017 , which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+ 
+ITEM 12. Sec urity Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+ 
+For information concerning the security ownership of certain beneficial owners and management, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 11, 2017 , which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+ 
+ITEM 13. C ertain Relationships and Related Transactions and Director Independence 
+ 
+For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 11, 2017 , which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+ 
+ITEM 14. Prin cipal Accountant Fees and Services 
+ 
+For information concerning Item 14, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 11, 2017 , which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+ 
+90 
+Table of Contents 
+Item 15 . Exh ibits 
+ 
+The following is an index to the financial statements and financial statement schedules that are filed in Part II, Item 8 of this report on Form 10 -K. 
+ 
+ 
+ 
+Exhibit Number 
+Description 
+ 
+Report s of Independent Registered Public Accounting Firm s 
+ 
+Consolidated Balance Sheets as of December 31, 2016 and 2015 
+ 
+Consolidated Statements of Operations for each of the three years in the period ended December 31, 2016 
+ 
+Consolidated Statements of Stockholders’ Equity (Deficit) for each of the three years in the period ended December 31, 2016 
+ 
+Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2016 
+ 
+Notes to Consolidated Financial Statements 
+ 
+Schedules other than those listed above are omitted because they are not required, not applicable or the required information is included in the financial statements or notes thereto. 
+ 
+2. 
+* 
+Plan of acquisition, reorganization, arrangement, liquidation or succession 
+3. 
+Articles of Incorporation and Bylaws 
+ 
+3.1 
+Certificate of Incorporation of the Company, as amended through May 12, 2016 (incorporated by reference to Exhibit 3.1 of the Company’s Quarterly Report on Form 10-Q, filed on November 3, 2016) 
+ 
+3.2 
+Certificate of Designation of Rights and Preferences of 10.00% Series A Cumulative Preferred Stock (incorporated by reference to Exhibit 3.5 of the Company’s Form 8-A, filed on May 23, 2013) 
+ 
+3.3 
+Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Registration Statement on Form S-4, filed on August 4, 1994, Reg. No. 33-82408) 
+4. 
+Instruments defining the rights of security holders, including indentures 
+ 
+4.1 
+Specimen Common Stock Certificate (incorporated by reference from Exhibit 4.1 of the Company’s Registration Statement on Form S-4, filed on August 4, 1994, Reg. No. 33-82408) 
+ 
+4.2 
+Certificate for the Company’s 10.00% Series A Cumulative Preferred Stock (incorporated by reference to Exhibit 4.1 of the Company’s Form 8-A, filed on May 23, 2013) 
+ 
+4.3 
+Indenture of 6.125% Senior Notes Due 2024, dated as of October 3, 2016, among Callon Petroleum Company, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 of the Company's Current Report on Form 8-K, filed on October 4, 2016) 
+ 
+4.4 
+Registration Rights Agreement of 6.125% Senior Notes Due 2024, dated October 3, 2016, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P. Morgan Securities LLC, as representative of the Intitial Purchasers named on Annex E thereto (incorporated by reference to Ehibit 4.2 of the Company's Current Report on Form 8-K, filed on October 4, 2016) 
+9. 
+Voting trust agreement 
+ 
+None 
+10. 
+Material contracts 
+ 
+10.1 
+Callon Petroleum Company 2002 Stock Incentive Plan (incorporated by reference to Exhibit 10.13 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2001, filed on April 1, 2002) 
+ 
+10.2 
+Amendment No. 1 to the Callon Petroleum Company 2002 Stock Incentive Plan (incorporated by reference from Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed on January 5, 2009) 
+ 
+10.3 
+Callon Petroleum Company 2010 Phantom Share Plan, adopted May 4, 2010 (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed on May 7, 2010) 
+ 
+10.4 
+Form of Callon Petroleum Company Phantom Share Award Agreement, adopted May 4, 2010 (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed on May 7 , 2010) 
+ 
+10.5 
+Deferred Compensation Plan for Outside Directors - Callon Petroleum Company, effective as of January 1, 2011 (incorporated by reference to Exhibit 10.17 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2010, filed on March 15, 2011) 
+ 
+10.6 
+Amended and Restated Severance Compensation Agreement, dated as of March 15, 2011 and effective as of January 1, 2011, by and between Fred L. Callon and Callon Petroleum Company (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed on March 18, 2011) 
+ 
+10.7 
+Form of Amended and Restated Severance Compensation Agreement, dated as of March 15, 2011 and effective as of January 1, 2011, by and between Callon Petroleum Company and its executive officers (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed on March 18, 2011) 
+ 
+10.8 
+Callon Petroleum Company 2011 Omnibus Incentive Plan (incorporated by reference from Exhibit A of the Company’s Definitive Proxy Statement on Schedule 14A, filed on March 21, 2011) 
+ 
+10.9 
+Agreement, dated March 9, 2014, among the Company and Lone Star Value Investors, L.P., Lone Star Value Co-Invest I, L.P., Lone Star Value Investors GP, LLC, Lone Star Value Management, LLC, Jeffery E. Eberwein and Matthew R. Bob (incorporated by reference from Exhibit 10.1 of the Company's Current Report on Form 8-K, filed on March 10, 2014) 
+ 
+10.10 
+Fifth Amended and Restated Credit Agreement, dated March 11, 2014, among Callon Petroleum Company, JPMorgan Chase Bank, National Association, as administrative agent and the Lenders party thereto (incorporated by reference to Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q/A, filed on June 11, 2014) 
+ 
+10.11 
+Amendment No. 2 to Fifth Amended and Restated Credit Agreement, effective as of October 8, 2014, among Callon Petroleum Company, JPMorgan Chase Bank, National Association, as administrative agent and the Lenders party thereto (incorporated by reference to Exhibit 10.4 of the Company's Current Report on Form 8-K, filed on October 14, 2014) 
+ 
+10.12 
+Second Lien Credit Agreement, dated October 8, 2014, among Callon Petroleum Company, Royal Bank of Canada and the Lenders party thereto (incorporated by reference to Exhibit 10.5 of the Company's Current Report on Form 8-K, filed on October 14, 2014) 
+ 
+10.13 
+Second Lien Intercreditor Agreement, dated October 8, 2014, among Callon Petroleum Company, JPMorgan Chase Bank, National Association, Royal Bank of Canada, and the other parties named therein(incorporated by reference to Exhibit 10.6 of the Company's Current Report on Form 8-K, filed on October 14, 2014) 
+ 
+10.14 
+Severance Compensation Agreement, dated as of February 13, 2015, by and between Bob Weatherly and Callon Petroleum Company (incorporated by reference to Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q, filed on May 7, 2015) 
+ 
+10.15 
+Agreement, dated March 21, 2015, among the Company and Lone Star Value Investors, L.P., Lone Star Value Co-Invest I, L.P., Lone Star Value Investors GP, LLC, Lone Star Value Management, LLC, Jeffery E. Eberwein and Michael L. Finch (incorporated by reference from Exhibit 10.1 of the Company's Current Report on Form 8-K, filed on March 25, 2015) 
+91 
+Table of Contents 
+ 
+10.16 
+Form of Callon Petroleum Company Restricted Stock Unit Award Agreement, adopted on March 12, 2015 
+ 
+10.17 
+Form of Callon Petroleum Company Phantom Share Award Agreement, adopted on March 12, 2015 
+ 
+10.18 
+Form of Callon Petroleum Company Phantom Share Award Agreement, adopted on March 12, 2015 
+ 
+10.19 
+Form of Callon Petroleum Company Phantom Share Award Agreement, adopted on March 12, 2015 
+ 
+10.20 
+First Amendment to the Callon Petroleum Company 2011 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q, filed on November 5, 2015) 
+ 
+10.21 
+Agreement, dated February 25, 2016, among the Company and Lone Star Value Investors, L.P., Lone Star Value Co-Invest I, L.P., Lone Star Value Investors GP, LLC, Lone Star Value Management, LLC, and Jeffery E. Eberwein (incorporated by reference from Exhibit 10.1 of the Company's Current Report on Form 8-K, filed on March 1, 2016) 
+ 
+10.22 
+Purchase and Sale Agreement, dated April 19, 2016, among BSM Energy LP, Crux Energy, LP and Zaniah Energy, LP, as Sellers, and Callon Petroleum Operating Company, as Purchaser, and Callon Petroleum Company, as Purchaser Parent (incorporated by reference to Exhibit 2.1 of the Company's Current Report on Form 8-K, filed on April 19, 2016) 
+ 
+10.23 
+Registration Rights Agreement, dated May 26, 2016, among Callon Petroleum Company and each of the Persons set forth on Schedule A therein (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K, filed on May 31, 2016) 
+ 
+10.24 
+Amendment No. 3 to Fifth Amended and Restated Credit Agreement, effective as of July 11, 2016, among Callon Petroleum Company, JPMorgan Chase Bank, National Association, as administrative agent and the Lenders party thereto (incorporated by reference to Exhibit 10.4 of the Company's Current Report on Form 8-K, filed on August 8, 2016) 
+ 
+10.25 
+Purchase and Sale Agreement, dated September 1, 2016, between Plymouth Petroleum, LLC, as Seller, and Callon Petroleum Operating Company, as Buyer (incorporated by reference to Exhibit 2.1 of the Company's Current Report on Form 8-K, filed on September 6, 2016) 
+ 
+10.26 
+Amendment No. 4 to Fifth Amended and Restated Credit Agreement, effective as of September 9, 2016, among Callon Petroleum Company, JPMorgan Chase Bank, National Association, as administrative agent and the Lenders party thereto (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K, filed on September 12, 2016) 
+ 
+10.27 
+Purchase Agreement, dated September 15, 2016, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P. Morgan Securities LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K, filed on September 16, 2016) 
+ 
+10.28 
+Purchase and Sale Agreement, dated December 13, 2016, between American Resource Development LLC, American Resource Development Upstream LLC and American Resource Development Midstream LLC, collectively, as Seller, and Callon Petroleum Operating Company, as Purchaser (incorporated by reference to Exhibit 2.1 of the Company's Form 8-K, filed on December 13, 2016) 
+11. 
+* 
+Statement re computation of per share earnings 
+12. 
+* 
+Statements re computation of ratios 
+13. 
+* 
+Annual Report to security holders, Form 10-Q or quarterly reports 
+14. 
+Code of Ethics 
+ 
+14.1 
+Code of Ethics for Chief Executive Officers and Senior Financial Officers (incorporated by reference to Exhibit 14.1 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, filed on March 15, 2004) 
+16. 
+Letter re change in certifying accountant 
+ 
+16.1 
+Letter from E&Y dated January 15, 2016 (incorporated by reference to Exhibit 16.1 of the Company's Current Report on Form 8-K, filed on January 15, 2016) 
+18. 
+* 
+Letter re change in accounting principles 
+21. 
+Subsidiaries of the Company 
+ 
+21.1 
+(a) 
+Subsidiaries of the Company 
+22. 
+* 
+Published report regarding matters submitted to vote of security holders 
+23. 
+Consents of experts and counsel 
+ 
+23.1 
+(a) 
+Consent of Grant Thornton LLP 
+ 
+23.2 
+(a) 
+Consent of Ernst & Young LLP 
+ 
+23.3 
+(a) 
+Consent of DeGolyer and MacNaughton, Inc. 
+24. 
+* 
+Power of attorney 
+31. 
+Rule 13a-14(a) Certifications 
+ 
+31.1 
+(a) 
+Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a) 
+ 
+31.2 
+(a) 
+Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a) 
+32. 
+(b) 
+Section 1350 Certifications of Chief Executive and Financial Officers pursuant to Rule 13(a)-14(b) 
+99. 
+Additional Exhibits 
+ 
+99.1 
+(a) 
+Reserve Report Summary prepared by DeGolyer and MacNaughton, Inc. as of December 31, 2016 
+101. 
+(c) 
+Interactive Data Files 
+ 
+* 
+Not applicable to this filing 
+(a) 
+Filed herewith. 
+(b) 
+Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, except to the extent that the registrant specifically incorporates it by reference. 
+(c) 
+Pursuant to Rule 406T of Regulation S-T, these interactive data files are being furnished herewith and are not deemed filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, or Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability. 
+ 
+ 
+ 
+92 
+Table of Contents 
+SIGN ATURES 
+ 
+ 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+ 
+Callon Petroleum Company 
+Date: 
+February 27 , 201 7 
+/s/ Joseph C. Gatto, Jr. 
+ 
+By: Joseph C. Gatto, Jr., P resident, 
+ 
+C hief F inancial O fficer ( p rincipal financial officer) and T reasurer 
+ 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+ 
+Date: 
+February 27, 2017 
+/s/ Fred L. Callon 
+ 
+Fred L. Callon ( p rincipal executive officer, d irector) 
+ 
+Date: 
+February 27, 2017 
+/s/ Joseph C. Gatto, Jr. 
+ 
+Joseph C. Gatto, Jr. ( p rincipal financial officer) 
+ 
+Date: 
+February 27, 2017 
+/s/ Mitzi P. Conn 
+ 
+Mitzi P. Conn (principal accounting officer) 
+ 
+Date: 
+February 27, 2017 
+/s/ L. Richard Flury 
+ 
+L. Richard Flury (director) 
+ 
+Date: 
+February 27, 2017 
+/s/ John C. Wallace 
+ 
+John C. Wallace (director) 
+ 
+Date: 
+February 27, 2017 
+/s/ Anthony J. Nocchiero 
+ 
+Anthony J. Nocchiero (director) 
+ 
+Date: 
+February 27, 2017 
+/s/ Larry D. McVay 
+ 
+Larry McVay (director) 
+ 
+Date: 
+February 27, 2017 
+/s/ Matthew R. Bob 
+ 
+Matthew R. Bob (director) 
+ 
+Date: 
+February 27, 2017 
+/s/ James M. Trimble 
+ 
+James M. Trimble (director) 
+ 
+Date: 
+February 27, 2017 
+/s/ Michael L. Finch 
+ 
+Michael L. Finch (director) 
+ 
+ 
+93
\ No newline at end of file
diff --git a/raw/filings/0000928022/2016/0000928022-17-000023/filing_metadata.csv b/raw/filings/0000928022/2016/0000928022-17-000023/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..5ca4103f93c089746f1bf327495fc1f9e01ab9f7
--- /dev/null
+++ b/raw/filings/0000928022/2016/0000928022-17-000023/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000928022,CPE,Callon Petroleum Co,10-K,2017-02-28,2016-12-31,2017-02-28T01:39:10.000Z,0000928022-17-000023,cpe-20161231x10k.htm,10-K,15249443,1,0,https://www.sec.gov/Archives/edgar/data/928022/000092802217000023/cpe-20161231x10k.htm,https://www.sec.gov/Archives/edgar/data/928022/000092802217000023/,2016,2016,1
diff --git a/raw/filings/0000928022/2016/0000928022-17-000023/item1.txt b/raw/filings/0000928022/2016/0000928022-17-000023/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000928022/2016/0000928022-17-000023/item13.txt b/raw/filings/0000928022/2016/0000928022-17-000023/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..4103279c3a46f605aeaeebc440a26b8f94579fbc
--- /dev/null
+++ b/raw/filings/0000928022/2016/0000928022-17-000023/item13.txt
@@ -0,0 +1,4 @@
+ITEM 13. C ertain Relationships and Related Transactions and Director Independence 
+ 
+For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 11, 2017 , which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+
\ No newline at end of file
diff --git a/raw/filings/0000928022/2016/0000928022-17-000023/item9a.txt b/raw/filings/0000928022/2016/0000928022-17-000023/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..60763331de75094c04e8011f7c3b5f4079b30091
--- /dev/null
+++ b/raw/filings/0000928022/2016/0000928022-17-000023/item9a.txt
@@ -0,0 +1,19 @@
+Item 9A. Co ntrols and Procedures 
+ 
+Disclosure controls and procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our Chief Executive Officer and Chief Financial Officer performed an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2016 . 
+ 
+Management’s report on internal control over financial reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. generally accepted accounting principles. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2016 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission ( 2013 framework)(the COSO criteria). Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2016 . 
+ 
+Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+ 
+The Company’s independent registered public accounting firm has issued an attestation report regarding its assessment of the Company’s internal control over financial reporting as of December 31, 2016 , which follows Part II, Item 9B of this filing. Additionally, the financial statements for the year ended December 31, 2016, covered in this Annual Report on Form 10-K , have been audited by an independent registered public accounting firm, Grant Thornton LLP, whose report is presented immediately preceding the Company’s financial statements included in Part II, Item 8 of this Annual Report on Form 10 -K. The financial statements for the years ended December 31, 2015 and 2014 were audited by the independent registered public accounting firm, Ernst & Young LLP, whose report is presented immediately preceding the company’s financial statements included in Part II, Item 8 of this Annual Report on Form 10-K. 
+ 
+Changes in internal control over financial reporting . There were no changes to our interna l control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting. 
+ 
+ 
+87 
+Table of Contents 
+ITEM 9A (T). Controls and Procedures 
+ 
+See Item 9A. 
+
\ No newline at end of file
diff --git a/raw/filings/0000928022/2016/0000928022-17-000023/rp_note.txt b/raw/filings/0000928022/2016/0000928022-17-000023/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000928022/2016/0000928022-17-000023/rpt_disclosure.txt b/raw/filings/0000928022/2016/0000928022-17-000023/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..65408483963bc8183b5f77ba812eab8190c28909
--- /dev/null
+++ b/raw/filings/0000928022/2016/0000928022-17-000023/rpt_disclosure.txt
@@ -0,0 +1,25 @@
+Certain Relationships and Related Party Transactions 
+ 
+The Board’s Audit Committee charter provides that the Audit Committee shall review and approve all related party transactions. A transaction will be considered a “related party transaction” if the transaction would be required to be disclosed under Item 404 of Regulation S-K. In addition, our Code of Business Conduct and Ethics provides that an officer’s or a Director’s conflict of interest with Callon may only be waived if the Nominating and Corporate Governance Committee approves the waiver and the full Board ratifies the waiver. As of December 31, 201 6 , we are not aware of any related party transactions with our executive officers that may cause a conflict of interest with us. 
+ 
+Recoupment Policy 
+ 
+We have no recoupment policy applicable to annual incentive bonuses or equity awards other than those required under Sarbanes-Oxley legislation, though the Committee continuously evaluates the need to adopt such a policy. 
+ 
+ 
+38 
+Compensation Committee Report 
+ 
+The Compensation Committee has reviewed and discussed with management the CD&A required by Item 402(b) of Regulation S-K promulgated under the Securities Exchange Act of 1934, as amended, and based on such review and discussions, the Committee has recommended to the Board that the CD&A be included in this Proxy Statement relating to the 201 7 Annual Meeting of Stockholders. 
+ 
+Respectfully submitted by the Compensation Committee of the Board, 
+ 
+L. Richard Flury, Chairman 
+Larry D. McVay 
+Anthony J. Nocchiero 
+John C. Wallace 
+James M. Trimble 
+ 
+ 
+ 
+39
\ No newline at end of file
diff --git a/raw/filings/0000928022/2017/0000928022-18-000013/filing.txt b/raw/filings/0000928022/2017/0000928022-18-000013/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..9aad0ecf203daabfd415b0eac93d06a9ca0883c0
--- /dev/null
+++ b/raw/filings/0000928022/2017/0000928022-18-000013/filing.txt
@@ -0,0 +1,6072 @@
+10-K
+1
+cpe-20171231x10k.htm
+10-K
+Document 
+UNITED STATES SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+________________________________________________ 
+FORM 10-K 
+________________________________________________ 
+☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For The Fiscal Year Ended December 31, 2017 
+OR 
+☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934 
+For the transition period from ____________ to ____________ 
+Commission File Number 001-14039 
+________________________________________________ 
+Callon Petroleum Company 
+(Exact Name of Registrant as Specified in Its Charter) 
+________________________________________________ 
+໿ 
+Delaware 
+(State or Other Jurisdiction of 
+Incorporation or Organization) 
+64-0844345 
+(IRS Employer 
+Identification No.) 
+200 North Canal Street 
+Natchez, Mississippi 
+(Address of Principal Executive Offices) 
+39120 
+(Zip Code) 
+601-442-1601 
+(Registrant’s Telephone Number, Including Area Code) 
+ 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of Each Class 
+Name of Each Exchange on Which Registered 
+Common Stock, $0.01 par value 
+New York Stock Exchange 
+10.0% Series A Cumulative Preferred Stock 
+New York Stock Exchange 
+ 
+Securities registered pursuant to section 12 (g) of the Act: None 
+• 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐ 
+• 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒ 
+• 
+Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ 
+• 
+Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐ 
+• 
+Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒ 
+• 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company in Rule 12b-2 of the Exchange Act (check one): 
+Large accelerated filer 
+☒ 
+Accelerated filer 
+☐ 
+Non-accelerated filer 
+☐ 
+(Do not check if smaller reporting company) 
+ 
+Smaller reporting company 
+☐ 
+Emerging growth company 
+☐ 
+. 
+• 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ 
+• 
+The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2017 was approximately $2,126,066,157 . 
+• 
+The Registrant had 201,939,430 shares of common stock outstanding as of February 23, 2018 . 
+DOCUMENTS INCORPORATED BY REFERENCE 
+Portions of the definitive Proxy Statement of Callon Petroleum Company (to be filed no later than 120 days after December 31, 2017 ) relating to the Annual Meeting of Stockholders to be held on May 10, 2018 , which are incorporated into Part III of this Form 10-K. 
+TABLE OF CONTENTS 
+Special Note Regarding Forward-Looking Statements 
+3 
+Glossary of Certain Terms 
+4 
+Part I 
+5 
+Items 1 and 2. 
+Business and Properties 
+5 
+ 
+Oil and Natural Gas Properties 
+7 
+ 
+Reserves and Production 
+7 
+ 
+Capital Budget 
+10 
+ 
+Exploration and Development Activity 
+10 
+ 
+Production Wells 
+10 
+ 
+Production Volumes, Average Sales Prices and Operating Costs 
+11 
+ 
+Leasehold Acreage 
+12 
+ 
+Other 
+12 
+ 
+Regulations 
+14 
+ 
+Commitments and Contingencies 
+22 
+ 
+Available Information 
+22 
+Item 1A. 
+Risk Factors 
+23 
+Item 1B. 
+Unresolved Staff Comments 
+35 
+Item 3. 
+Legal Proceedings 
+35 
+Item 4. 
+Mine Safety Disclosures 
+35 
+Part II 
+Item 5. 
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+36 
+ 
+Performance Graph 
+37 
+Item 6. 
+Selected Financial Data 
+38 
+Item 7. 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+39 
+ 
+Overview and Outlook 
+39 
+ 
+Liquidity and Capital Resources 
+39 
+ 
+Results of Operations 
+44 
+ 
+Significant Accounting Policies and Critical Accounting Estimates 
+51 
+Item 7A. 
+Quantitative and Qualitative Disclosures About Market Risk 
+55 
+Item 8. 
+Financial Statements and Supplementary Data 
+57 
+ 
+Report of Independent Registered Public Accounting Firm 
+58 
+ 
+Consolidated Balance Sheets 
+60 
+ 
+Consolidated Statements of Operations 
+61 
+ 
+Consolidated Statements of Stockholders’ Equity 
+62 
+ 
+Consolidated Statements of Cash Flows 
+63 
+ 
+Notes to Consolidated Financial Statements 
+64 
+Item 9. 
+Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+87 
+Item 9A. 
+Controls and Procedures 
+87 
+Item 9B. 
+Other Information 
+88 
+ 
+Report of Independent Registered Public Accounting Firm 
+89 
+Part III 
+Item 10. 
+Directors and Executive Officers and Corporate Governance 
+90 
+Item 11. 
+Executive Compensation 
+90 
+Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+90 
+Item 13. 
+Certain Relationships and Related Transactions and Director Independence 
+90 
+Item 14. 
+Principal Accountant Fees and Services 
+90 
+Part IV. 
+Item 15. 
+Exhibits 
+91 
+Item 16. 
+Form 10-K Summary 
+93 
+Signatures 
+94 
+2 
+Table of Contents 
+Special Note Regarding Forward Looking Statements 
+This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”), as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements in this Form 10-K by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions. 
+All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future are forward-looking statements, including such things as: 
+• 
+our oil and gas reserve quantities, and the discounted present value of these reserves; 
+• 
+the amount and nature of our capital expenditures; 
+• 
+our future drilling and development plans and our potential drilling locations; 
+• 
+the timing and amount of future production and operating costs; 
+• 
+commodity price risk management activities and the impact on our average realized prices; 
+• 
+business strategies and plans of management; 
+• 
+our ability to efficiently integrate recent acquisitions; 
+• 
+prospect development and property acquisitions; and 
+• 
+the expected impact of the Tax Cuts and Jobs Act of 2017. 
+Some of the risks, which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements, include: 
+• 
+general economic conditions including the availability of credit and access to existing lines of credit; 
+• 
+the volatility of oil and natural gas prices; 
+• 
+the uncertainty of estimates of oil and natural gas reserves; 
+• 
+impairments; 
+• 
+the impact of competition; 
+• 
+the availability and cost of seismic, drilling and other equipment; 
+• 
+operating hazards inherent in the exploration for and production of oil and natural gas; 
+• 
+difficulties encountered during the exploration for and production of oil and natural gas; 
+• 
+difficulties encountered in delivering oil and natural gas to commercial markets; 
+• 
+changes in customer demand and producers’ supply; 
+• 
+the uncertainty of our ability to attract capital and obtain financing on favorable terms; 
+• 
+compliance with, or the effect of changes in, the extensive governmental regulations regarding the oil and natural gas business including those related to climate change and greenhouse gases; 
+• 
+the impact of government regulation, including regulation of endangered species; 
+• 
+any increase in severance or similar taxes; 
+• 
+litigation relating to hydraulic fracturing, the climate and over-the-counter derivatives; 
+• 
+the financial impact of accounting regulations and critical accounting policies; 
+• 
+the comparative cost of alternative fuels; 
+• 
+credit risk relating to the risk of loss as a result of non-performance by our counterparties; 
+• 
+weather conditions; and 
+• 
+any other factors listed in the reports we have filed and may file with the SEC. 
+We caution you that the forward-looking statements contained in this Form 10-K are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. These risks include, but are not limited to, the risks described in Item 1A of this Annual Report on Form 10-K for the year ended December 31, 2017 (the “ 2017 Annual Report on Form 10-K”), and all quarterly reports on Form 10-Q filed subsequently thereto. 
+Should one or more of the risks or uncertainties described above or in our 2017 Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. 
+All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement. 
+3 
+Table of Contents 
+GLOSSARY OF CERTAIN TERMS 
+All defined terms under Rule 4-10(a) of Regulation S-X shall have their prescribed meanings when used in this report. As used in this document: 
+• 
+ARO : asset retirement obligation. 
+• 
+ASU : accounting standards update. 
+• 
+Bbl or Bbls : barrel or barrels of oil or natural gas liquids. 
+• 
+BOE : barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas. The ratio of one barrel of oil or NGL to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas. 
+• 
+BBtu : billion Btu. 
+• 
+BOE/d : BOE per day. 
+• 
+BLM: Bureau of Land Management. 
+• 
+Btu : a British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit. 
+• 
+Completion : The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency. 
+• 
+Cushing : An oil delivery point that serves as the benchmark oil price for West Texas Intermediate. 
+• 
+DOI: Department of Interior. 
+• 
+EPA: Environmental Protection Agency. 
+• 
+FASB: Financial Accounting Standards Board. 
+• 
+GAAP : Generally Accepted Accounting Principles in the United States. 
+• 
+Henry Hub : A natural gas pipeline delivery point that serves as the benchmark natural gas price underlying NYMEX natural gas futures contracts. 
+• 
+Horizontal drilling : A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval. 
+• 
+GHG: greenhouse gases. 
+• 
+LIBOR : London Interbank Offered Rate. 
+• 
+LOE : lease operating expense. 
+• 
+MBbls : thousand barrels of oil. 
+• 
+MBOE : thousand BOE. 
+• 
+Mcf : thousand cubic feet of natural gas. 
+• 
+MMBOE : million BOE. 
+• 
+MMBtu : million Btu. 
+• 
+MMcf : million cubic feet of natural gas. 
+• 
+NGL or NGLs : natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams. 
+• 
+NYMEX : New York Mercantile Exchange. 
+• 
+Oil : includes crude oil and condensate. 
+• 
+OPEC: Organization of Petroleum Exporting Countries 
+• 
+PDPs : proved developed producing reserves. 
+• 
+PDNPs : proved developed non-producing reserves. 
+• 
+PUDs : proved undeveloped reserves. 
+• 
+Realized price : The cash market price less all expected quality, transportation and demand adjustments. 
+• 
+Royalty interest : An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development. 
+• 
+RSU : restricted stock units. 
+• 
+SEC : United States Securities and Exchange Commission. 
+• 
+Working interest : An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations. 
+• 
+WTI : West Texas Intermediate grade crude oil, used as a pricing benchmark for sales contracts and NYMEX oil futures contracts. 
+With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross. 
+4 
+Table of Contents 
+PART I. 
+Items 1 and 2 – Business and Properties 
+Overview 
+Callon Petroleum Company has been engaged in the exploration, development, acquisition and production of oil and natural gas properties since 1950. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. 
+We are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional onshore oil and natural gas reserves in the Permian Basin. The Permian Basin is located in West Texas and southeastern New Mexico and is comprised of three primary sub-basins: the Midland Basin, the Delaware Basin, and the Central Basin Platform. We have historically been focused on the Midland Basin and entered the Delaware Basin through an acquisition completed in February 2017. Our drilling activity during 2017 was predominantly focused on the horizontal development of several prospective intervals in the Midland Basin, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales. As a result of our horizontal development efforts and contributions from acquisitions, our net daily production for calendar year 2017 as compared to calendar year 2016 grew approximately 50% to 22,940 BOE/d (approximately 78% oil). We intend to grow our reserves and production through the development, exploitation and drilling of our multi-year inventory of identified, potential drilling locations. We intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and acquisition of additional locations through leasehold purchases, leasing programs, joint ventures and asset swaps. 
+For the year ended December 31, 2017 , our net proved reserve volumes increased 50% as compared to the year ended December 31, 2016 , to 137.0 MMBOE, comprised of 78% crude oil including 107.1 MMBbls with the remaining 22% natural gas of 179.4 Bcf. Approximately 51% of our net proved year-end 2017 reserves were proved developed on a BOE basis. 
+Our Business Strategy 
+Our goal is to enhance stockholder value through the execution of the following strategies with an emphasis on safety: 
+Maintain fiscal discipline, financial liquidity and our capacity to capitalize on growth opportunities. During the recent period of relative oil price weakness, we moderated our level of drilling activity and high-graded our investments to the highest returning projects to preserve our financial flexibility while also maintaining operational momentum. In 2017 , we increased our level of operational capital spending by 147% versus the prior year as the improving commodity price environment presented the opportunity to grow production and operational cash flow, while still maintaining prudent leverage and liquidity positions. Following the close of our acquisition of the Ameredev properties in the Delaware Basin in February of 2017 and the subsequent Ward county acreage purchase, we completed a follow-on offering of our 6.125% senior unsecured notes due 2024 (the “6.125% Senior Notes”) in the amount of $200 million , further improving our liquidity position. Our financial discipline during the past year prepared the company for additional operational activity in 2018 which we expect to further improve our ability to leverage attractive field level returns to grow both production and reserves. 
+Drive production and maximize resource recovery and reserve growth through horizontal development of our resource base. We entered the Midland Basin in 2009 focused on a vertical development program that allowed us to amass a comprehensive database of subsurface geologic and other technical data. Beginning in 2012, we leveraged that subsurface knowledge base to transition to horizontal development of hydrocarbon bearing zones that were previously being exploited with vertical wells. Since that time, we have applied the continued success of our horizontal development as evidenced in our significant year-over-year production growth, which increased 50% in 2017 to 8,373 MBOE ( 22,940 BOE/d) compared to 5,573 MBOE ( 15,227 BOE/d) in 2016 . Additionally, we grew reserves 50% in 2017 to 137.0 MMBOE from 91.6 MMBOE at year-end 2016 , including reserve extensions and discoveries replacement in 2017 of 47.4 MMBOE. We intend to continue to grow our production volumes, both from our existing properties and from properties acquired in recent acquisitions, as we execute a resource development program exclusively focused on horizontal development of currently producing and prospective flow intervals in the Midland and Delaware Basins. 
+Expand our drilling portfolio through evaluation of existing acreage. We plan to further our efforts to expand our drilling inventory through downspacing tests in existing flow units and selective delineation of new flow units. During 2017 , we successfully tested a second flow unit in the Lower Spraberry shale in the Midland Basin, bringing our producing flow unit count in the that sub-basin to seven, including the Upper and Lower sections of the Lower Spraberry, Middle Spraberry, Upper and Lower Wolfcamp A and the Upper and Lower Wolfcamp B zones. In December, we completed a test of the Wolfcamp C interval in Reagan County and are actively flowing back the well, which if successful, would increase the producing flow units to eight. In the Midland Basin, we believe incremental opportunities exist to develop existing flow units with tighter well spacing, and add new flow units within both currently producing zones that have adequate thickness and new flow units in other prospective zones including the Clearfork, Jo Mill, and Cline (also called the 
+5 
+Table of Contents 
+Wolfcamp D). As part of our entry into the Delaware Basin, we will be initially focused on development of established zones such as the Wolfcamp A and Wolfcamp B, but plan to test other prospective intervals including the Second Bone Spring and Wolfcamp C as part of our 2018 drilling activity. We are currently producing from three flow units in the Delaware Basin including, the Lower Wolfcamp A, the Wolfcamp B, and the Third Bone Spring. 
+Pursue selective growth opportunities in the Permian Basin. During 2017 , we significantly expanded our Permian Basin footprint after entering in the Delaware Basin by completing an acquisition of 36,206 gross ( 19,176 net) acres. This acquisition provided the foundation for a new core operating area that is a significant component of our near-term drilling plans. We will continue to evaluate opportunities for incremental “bolt-on” acquisitions, acreage trades, and leasing in our core operating areas. In addition, we will evaluate selective larger acquisition opportunities in the Permian Basin. 
+Our Strengths 
+Established resource base and acreage position in the core of the Permian Basin . Our production is exclusively from the Permian Basin in West Texas, an area that has supported production since the 1940s. The Permian Basin has well established infrastructure from historical operations, and we believe the Permian Basin also benefits from a relatively stable regulatory environment that has been established over time. We have assembled a position of over 57,000 net surface acres in the Permian Basin that are prospective for multiple oil-bearing intervals that have been produced by us and other industry participants. As of December 31, 2017 , our estimated net proved reserves were comprised of approximately 78% oil and 22% natural gas, which includes NGLs in the production stream. 
+Economic, multi-year drilling inventory . Our current acreage position in the Permian Basin provides growth potential from a horizontal drilling inventory of approximately 1,550 gross locations based solely on eight currently producing flow intervals, including the Upper and Lower sections of the Lower Spraberry, Middle Spraberry, Upper and Lower Wolfcamp A, and the Upper and Lower Wolfcamp B, and the Third Bone Spring. Our identified well locations across our Midland and Delaware Basin acreage positions are based upon the results of horizontal wells drilled by us and other offsetting operators and by our analysis of core data and historical vertical well performance. To the extent that long-term production data and microseismic data support the potential for capital efficient resource recovery from reduced spacing between lateral wellbores and stacked development within thicker zones, the number of drilling locations within currently producing zones may increase over time, complementing potential growth from additional prospective zones without current production. 
+Experienced team operating in the Permian Basin. We have assembled a management team experienced in acquisitions, exploration, development and production in the Permian Basin. Reflective of this experience, we were an early adopter of efficient multi-well pad development, transitioning to this development model in 2012 which enabled us to realize improvements in our drilling and capital. Since 2012, we have drilled more than 158 operated horizontal wells with lengths varying from approximately 5,000 feet to 10,400 feet, continuing to employ new generation completion techniques in an effort to improve capital efficiency. In addition, we regularly evaluate our operating results against those of other operators in the area in an effort to benchmark our performance against the top-performing operators and evaluate and adopt best practices. We believe that the experience of our team is highlighted by our success in achieving lower well capital costs and reducing our operating cost structure to generate the operating margins and capital efficiency to operate effectively in the current environment. 
+Significant amount of operational control . We operate nearly all of our Permian Basin acreage that is largely held by production, providing us an advantage that enables us to modify our operational plans quickly and drill in areas that offer highest potential returns on capital. During the course of 2017, based upon an evaluation of our development opportunities, we made the decision to add our fifth rig to the Delaware Basin rather than the Midland Basin to take advantage of high rate of return and high net present value opportunities on our Spur acreage. In 2017, we placed 49 gross wells on production, of which 45 gross wells were drilled and operated by Callon. Over 98% of the wells projected to be placed on production in 2018 are Callon operated wells. 
+Operating culture focused on safety and the environment. We have a Health, Safety and Environmental (“HSE”) department dedicated to our operations in the Permian Basin. This group is responsible for developing and implementing work processes to mitigate safety and environmental risks associated with our work activities. With emphasis on leadership engagement, planning, training and communication, and empowering both our employees and third party service providers with Stop Work Authority, we continue to improve operational performance. We have enhanced Management of Change, routine facility maintenance and inspections, and compliance action tracking methods with the implementation of a HSE management system software program. We also utilize the program to distribute all incident reports, including near miss events and safety observations to track trends, learn from our mistakes and implement corrective actions to drive improvement across our operations. This department also coordinates closely with our operational team to ensure effective communication with appropriate regulatory bodies as well as landowners. We believe that our proactive efforts in this area have made a positive impact on our operations and culture. 
+6 
+Table of Contents 
+Oil and Natural Gas Properties 
+Permian Basin 
+As of December 31, 2017 , we owned 57,481 net leasehold acreage in the Permian Basin, all of which was located in the Midland and Delaware Basins. Average net production from our Permian Basin properties increased 50% to 22,940 BOE/d in 2017 from 15,227 BOE/d in 2016 . The following sets forth certain information about our major operating areas in the Permian Basin as of December 31, 2017 : 
+໿ 
+Producing Wells 
+Producing 
+Horizontal 
+Vertical 
+Horizontal Flow 
+Net Acres 
+Gross 
+Net 
+Gross 
+Net 
+Unit Zones 
+Midland Basin: 
+Monarch 
+7,854 
+68 
+49.9 
+175 
+131.4 
+Middle Spraberry 
+Lower Spraberry 
+Wolfcamp A 
+Wolfcamp B 
+Ranger 
+8,113 
+54 
+41.8 
+16 
+12.2 
+Lower Spraberry 
+Wolfcamp A 
+Upper Wolfcamp B 
+Lower Wolfcamp B 
+Wildhorse 
+20,160 
+54 
+39.3 
+76 
+65.7 
+Lower Spraberry 
+Wolfcamp A 
+Wolfcamp B 
+Other Permian 
+2,528 
+18 
+15.5 
+8 
+8.0 
+Wolfcamp A 
+Upper Wolfcamp B 
+Lower Wolfcamp B 
+Total Midland Basin: 
+38,655 
+194 
+146.5 
+275 
+217.3 
+Delaware Basin: 
+Spur 
+18,826 
+38 
+25.3 
+37 
+35.2 
+Third Bone Spring 
+Upper Wolfcamp A 
+Lower Wolfcamp A 
+Wolfcamp B 
+Total Permian Basin 
+57,481 
+232 
+171.8 
+312 
+252.5 
+On February 13, 2017, the Company completed the acquisition of 29,175 gross ( 16,688 net) acres in the Delaware Basin, primarily located in Ward and Pecos Counties, Texas, from American Resource Development, LLC, for total cash consideration of $647 million , excluding customary purchase price adjustments (the “Ameredev Transaction”). The Company acquired an 82% average working interest ( 75% average net revenue interest) in the properties acquired in the Ameredev Transaction. The Ameredev Transaction represents our initial entry into the Delaware Basin. 
+On June 5, 2017, the Company completed the acquisition of 7,031 gross ( 2,488 net) acres in the Delaware Basin, located near the acreage acquired in the Ameredev Transaction discussed above, for total cash consideration of $52.5 million , excluding customary purchase price adjustments. 
+See Note 3 in the Footnotes to the Financial Statements for additional information related to acquisitions. 
+Other Property 
+We own additional immaterial properties in Louisiana. 
+Reserve Data 
+Proved Reserves 
+Estimates of volumes of proved reserves at year-end, net to our working interest, are presented in MBbls for oil and in MMcf for natural gas, including NGLs, at a pressure base of 14.65 pounds per square inch. Total equivalent volumes are presented in BOE. For the BOE 
+7 
+Table of Contents 
+computation, 6,000 cubic feet of gas are the equivalent of one barrel of oil. The ratio of six Mcf of gas to one BOE is typically used in the oil and gas business and represents the approximate energy equivalent of a barrel of oil and a Mcf of natural gas. The price of a barrel of oil is much higher than the price of six Mcf of natural gas, so the ratio of six Mcf to one BOE does not reflect the economic equivalent of a barrel of oil to six Mcf of gas. 
+As of December 31, 2017 , our estimated net proved reserves totaled 137.0 MMBOE and included 107.1 MMBbls of oil and 179.4 Bcf, of natural gas with a pre-tax present value, discounted at 10%, of $1,577 million . Pre-tax present value is a non-GAAP financial measure, which we reconcile to the GAAP measure of standardized measure of $1,557 million . Oil constituted approximately 78% of our total estimated equivalent net proved reserves and approximately 75% of our total estimated equivalent proved developed reserves. 
+The following table sets forth certain information about our estimated net proved reserves prepared by our independent petroleum reserve engineers. All of our proved reserves are located in the Permian Basin in the continental United States. 
+໿ 
+For the Year Ended December 31, 
+2017 
+2016 
+2015 
+Proved developed 
+Oil (MBbls) 
+51,920 
+32,920 
+22,257 
+Natural gas (MMcf) 
+104,389 
+61,871 
+38,157 
+MBOE 
+69,318 
+43,232 
+28,617 
+Proved undeveloped 
+Oil (MBbls) 
+55,152 
+38,225 
+21,091 
+Natural gas (MMcf) 
+75,021 
+60,740 
+27,380 
+MBOE 
+67,656 
+48,348 
+25,654 
+Total proved 
+Oil (MBbls) 
+107,072 
+71,145 
+43,348 
+Natural gas (MMcf) 
+179,410 
+122,611 
+65,537 
+MBOE 
+136,974 
+91,580 
+54,271 
+Financial Information (in thousands) 
+Estimated pre-tax future net cash flows (a) 
+$ 
+3,546,509 
+$ 
+1,821,221 
+$ 
+1,160,808 
+Pre-tax discounted present value (a) (b) 
+$ 
+1,576,755 
+$ 
+809,832 
+$ 
+570,906 
+Standardized measure of discounted future net cash flows (a) (b) 
+$ 
+1,556,682 
+$ 
+809,832 
+$ 
+570,890 
+(a) 
+Includes a reduction for estimated plugging and abandonment costs that is reflected as a liability on our balance sheet in accordance with accounting standards for asset retirement obligations. 
+(b) 
+The Company uses the financial measure “pre-tax discounted present value” which is a non-GAAP financial measure. The Company believes that pre-tax discounted present value, while not a financial measure in accordance with GAAP, is an important financial measure used by investors and independent oil and natural gas producers for evaluating the relative value of oil and natural gas properties and acquisitions because the tax characteristics of comparable companies can differ materially. The total standardized measure calculated in accordance with the guidance issued by the FASB for disclosures about oil and natural gas producing activities for our proved reserves as of December 31, 2017 , was $1,557 million , net of discounted estimated future income taxes relating to such future net revenues. The projected per Mcf natural gas price of $3.47 used in the 2017 reserve estimates has been adjusted to reflect the Btu content, transportation charges and other fees specific to the individual properties. The projected per barrel oil price of $49.48 used in the 2017 reserve estimates has been adjusted to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality. 
+See Note 13 in the Footnotes to the Financial Statements for the additional information regarding the Company’s reserves, including its estimates of proved reserves and the Company’s estimates of future net cash flows and discounted future net cash flows from proved reserves. 
+The Company’s estimated net proved reserves increased 50% to 137.0 MMBOE at December 31, 2017 from 91.6 MMBOE at December 31, 2016 . Additions during the year were due to (1) 47.4 MMBOE related to the Company’s horizontal development of a portion of its properties (2) 10.5 MMBOE related to acquired properties (3) 2.2 MMBOE in upward revisions primarily at our proved developed locations. These increases were partially offset by (1) 8.4 MMBOE related to the Company’s production during 2017 and (2) 6.4 MMBOE of revisions due to the removal of 13 proved undeveloped locations as a result of a change in our development and drilling plans within our operating areas and the removal of certain proved developed vertical well locations. 
+8 
+Table of Contents 
+Proved Undeveloped Reserves 
+Annually, the Company reviews its proved undeveloped reserves (“PUDs”) to ensure appropriate plans exist for development of this reserve category. PUD reserves are recorded only if the Company has plans to convert these reserves into proved developed producing reserves (“PDPs”) within five years of the date they are first recorded. Our development plans include the allocation of capital to projects included within our 2018 capital budget and, in subsequent years, the allocation of capital within our long-range business plan to convert PUDs to PDPs within this five year period. In general, our 2018 capital budget and our long-range capital plans are primarily governed by our expectations of internally generated cash flow, borrowing availability under our senior secured revolving credit facility (“Credit Facility”) and corporate credit metrics. Reserve calculations at any end-of-year period are representative of our development plans at that time. Changes in commodity pricing, oilfield service costs and availability, and other economic factors may lead to changes in development plans. 
+Our PUDs increased 40% to 67.7 MMBOE at December 31, 2017 from 48.3 MMBOE at December 31, 2016 . Additions during the year were due to (1) 3.3 MMBOE related to acquisitions and (2) 30.2 MMBOE related to the Company’s horizontal development of a portion of its properties. The increase in the Permian Basin PUDs was partially offset by 5.9 MMBOE of revisions primarily due to the removal of 13 PUD locations as a result of a change in the Company’s development and drilling plans within its operating areas and downward revisions to its current PUD locations. In addition, these increases were offset by the reclassification of 8.3 MMBOE, or 17% , included in the year-end 2016 PUDs, to PDPs as a result of our horizontal development of properties at a total cost of approximately $57.0 million , net. 
+The Company plans to develop its PUDs as part of a multi-year drilling program. At December 31, 2017 , we had no reserves that remained undeveloped for five or more years, and all PUD drilling locations are currently scheduled to be drilled within five years of their initial recording. 
+Controls Over Reserve Estimates 
+Compliance as it relates to reporting the Company’s reserves is the responsibility of our Chief Operating Officer, who has over 35 years of industry experience, including 29 years as a manager, and is our principal engineer. In addition to his years of experience, our principal engineer holds a degree in petroleum engineering and is experienced in asset evaluation and management. 
+Callon’s controls over reserve estimates included retaining DeGolyer and MacNaughton, a Texas registered engineering firm, as our independent petroleum and geological firm. The Company provided to DeGolyer and MacNaughton information about our oil and gas properties, including production profiles, prices and costs, and DeGolyer and MacNaughton prepared its own estimates of the reserves attributable to the Company’s properties. All of the information regarding 2017 , 2016 and 2015 reserves in this annual report is derived from DeGolyer and MacNaughton’s report. DeGolyer and MacNaughton’s reserve report letter is included as an Exhibit to this annual report. The principal engineer at DeGolyer and MacNaughton, who certified the Company’s reserve estimates, has over 33 years of experience in the oil and gas industry and is a Texas Licensed Professional Engineer. Further professional qualifications include a degree in petroleum engineering and membership in the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. 
+To further enhance the control environment over the reserve estimation process, our Strategic Planning and Reserves Committee, a committee of the Board of Directors, assists management and the Board with its oversight of the integrity of the determination of the Company’s oil and natural gas reserves and the work of our independent reserve engineer. The Committee’s charter also specifies that the Committee shall perform, in consultation with the Company’s management and senior reserves and reservoir engineering personnel, the following responsibilities: 
+• 
+Oversee the appointment, qualification, independence, compensation and retention of the independent petroleum and geological firm (the “Reserve Firm”) engaged by the Company (including resolution of material disagreements between management and the Reserve Firm regarding reserve determination) for the purpose of preparing or issuing an annual reserve report. The Committee shall review any proposed changes in the appointment of the Reserve Firm, determine the reasons for such proposal, and whether there have been any disputes between the Reserve Firm and management. 
+• 
+Review the Company’s significant reserves engineering principles and policies and any material changes thereto, and any proposed changes in reserves engineering standards and principles which have, or may have, a material impact on the Company’s reserves disclosure. 
+• 
+Review with management and the Reserve Firm the proved reserves of the Company, and, if appropriate, the probable reserves, possible reserves and the total reserves of the Company, including: (i) reviewing significant changes from prior period reports; (ii) reviewing key assumptions used or relied upon by the Reserve Firm; (iii) evaluating the quality of the reserve estimates prepared by both the Reserve Firm and the Company relative to the Company’s peers in the industry; and (iv) reviewing any material reserves adjustments and significant differences between the Company’s and Reserve Firm’s estimates. 
+9 
+Table of Contents 
+• 
+If the Committee deems it necessary, it shall meet in executive session with management and the Reserve Firm to discuss the oil and gas reserve determination process and related public disclosures, and any other matters of concern in respect of the evaluation of the reserves. 
+During our last fiscal year, we filed no reports with other federal agencies which contain an estimate of total proved net oil and natural gas reserves. 
+2018 Capital Budget 
+Our operational capital budget for 2018 has been established in the range of $500 to $540 million on an accrual, or GAAP, basis, inclusive of a planned transition from a four-rig program that commenced in July 2017 to a five-rig program by mid-February 2018. 
+As part of our 2018 operated horizontal drilling program, we expect to place 43 to 46 net horizontal wells on production with lateral lengths ranging from 5,000’ to 10,000’. 
+໿ 
+In addition to the operational capital expenditures budget, which includes well costs, facilities and infrastructure capital, and surface land purchases, we budgeted an estimated $23 to $28 million for capitalized general and administrative expenses on an accrual, or GAAP, basis. 
+Our revenues, earnings, liquidity and ability to grow are substantially dependent on the prices we receive for, and our ability to develop our reserves of oil and natural gas. We believe the long-term outlook for our business is favorable due to our resource base, low cost structure, financial strength, risk management, including commodity hedging strategy, and disciplined investment of capital. We monitor current and expected market conditions, including the commodity price environment, and our liquidity needs and may adjust our capital investment plan accordingly. 
+Exploration and Development Activities 
+Our 2017 total capital expenditures, including acquisitions, on a cash basis were $1,072.5 million , of which $419.8 million was allocated to operational capital expenditures, including drilling and completion and facilities and infrastructure expenditures. 
+For the year ended December 31, 2017 , we drilled 49 gross ( 38.2 net) horizontal wells, completed 52 gross ( 41.4 net) horizontal wells and had four gross ( 2.0 net) horizontal wells awaiting completion. 
+The following table sets forth the Company’s drilled wells, none of which were natural gas or nonproductive for the periods reflected: 
+໿ 
+2017 (a) 
+2016 
+2015 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Oil wells 
+Development (b) 
+15 
+10.7 
+9 
+4.9 
+14 
+11.4 
+Exploratory (c) 
+33 
+26.5 
+20 
+16.0 
+22 
+15.7 
+Total 
+48 
+37.2 
+29 
+20.9 
+36 
+27.1 
+(a) 
+Does not include one gross ( 0.97 net) nonproductive exploratory well. 
+(b) 
+A development well is a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. 
+(c) 
+An exploratory well is a well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir. 
+Productive Wells 
+As of December 31, 2017 , we had 544 gross ( 424.3 net) working interest oil wells, three gross ( 0.1 net) royalty interest oil wells and no natural gas wells. A well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas reserves on a BOE basis. However, most of our wells produce both oil and natural gas. 
+Present Activities 
+Subsequent to December 31, 2017 , and through February 23, 2018 , the Company drilled eight gross ( 6.0 net) horizontal wells and completed five gross ( 3.0 net) horizontal wells and had three gross ( 3.0 net) horizontal wells awaiting completion. 
+10 
+Table of Contents 
+Production Volumes, Average Sales Prices and Operating Costs 
+The following table sets forth certain information regarding the production volumes and average sales prices received for, and average production costs associated with, the Company’s sale of oil and natural gas for the periods indicated (dollars in thousands, except per unit data). 
+For the Year Ended December 31, 
+2017 
+2016 
+2015 
+Production 
+Oil (MBbls) 
+6,557 
+4,280 
+2,789 
+Natural gas (MMcf) 
+10,896 
+7,758 
+4,312 
+Total (MBOE) 
+8,373 
+5,573 
+3,508 
+Revenues 
+Oil revenue 
+$ 
+322,374 
+$ 
+177,652 
+$ 
+125,166 
+Natural gas revenue 
+44,100 
+23,199 
+12,346 
+Total 
+$ 
+366,474 
+$ 
+200,851 
+$ 
+137,512 
+Operating costs 
+Lease operating expense 
+$ 
+49,907 
+$ 
+38,353 
+$ 
+27,036 
+Production taxes 
+22,396 
+11,870 
+9,793 
+Total 
+$ 
+72,303 
+$ 
+50,223 
+$ 
+36,829 
+Average realized sales price 
+(excluding impact of cash settled derivatives) 
+Oil (Bbl) 
+$ 
+49.16 
+$ 
+41.51 
+$ 
+44.88 
+Natural gas (Mcf) 
+4.05 
+2.99 
+2.86 
+Total (BOE) 
+$ 
+43.77 
+$ 
+36.04 
+$ 
+39.20 
+Average realized sales price 
+(including impact of cash settled derivatives) 
+Oil (Bbl) 
+$ 
+47.78 
+$ 
+45.67 
+$ 
+56.82 
+Natural gas (Mcf) 
+4.10 
+3.00 
+3.26 
+Total (BOE) 
+$ 
+42.76 
+$ 
+39.25 
+$ 
+49.18 
+Operating costs per BOE 
+Lease operating expense 
+$ 
+5.96 
+$ 
+6.88 
+$ 
+7.71 
+Production taxes 
+2.67 
+2.13 
+2.79 
+Total 
+$ 
+8.63 
+$ 
+9.01 
+$ 
+10.50 
+Major Customers 
+Our production is sold generally on month-to-month contracts at prevailing prices. The following table identifies customers to whom we sold a significant percentage of our total oil and natural gas production, on an equivalent basis, during each of the 12-month periods indicated: 
+໿ 
+For the Year Ended December 31, 
+2017 
+2016 
+2015 
+Plains Marketing, L.P. 
+29 
+% 
+16 
+% 
+19 
+% 
+Enterprise Crude Oil, LLC 
+18 
+% 
+43 
+% 
+42 
+% 
+Rio Energy International, Inc. 
+17 
+% 
+— 
+% 
+— 
+% 
+Shell Trading Company 
+9 
+% 
+18 
+% 
+4 
+% 
+Permian Transport and Trading 
+— 
+% 
+— 
+% 
+15 
+% 
+Other 
+27 
+% 
+23 
+% 
+20 
+% 
+Total 
+100 
+% 
+100 
+% 
+100 
+% 
+Because alternative purchasers of oil and natural gas are readily available, the Company believes that the loss of any of these purchasers would not result in a material adverse effect on its ability to market future oil and natural gas production. We are not currently committed to provide a fixed and determinable quantity of oil or gas in the near future under our contracts. 
+11 
+Table of Contents 
+Leasehold Acreage 
+The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage as of December 31, 2017 . 
+໿ 
+Developed 
+Undeveloped 
+Total 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Permian Basin (a) 
+53,343 
+41,040 
+33,238 
+16,441 
+86,581 
+57,481 
+Other 
+936 
+200 
+188 
+55 
+1,124 
+255 
+Total 
+54,279 
+41,240 
+33,426 
+16,496 
+87,705 
+57,736 
+(a) 
+A portion of our Permian Basin acreage, which we have included in our development plans, requires continuous drilling to hold the acreage, though the cost to renew this acreage, if necessary, is not considered material. 
+Undeveloped Acreage Expirations 
+The following table sets forth as of December 31, 2017 the number of our leased gross and net undeveloped acres in the Permian Basin that will expire over the next three years unless production begins before lease expiration dates. Gross amounts may be more than net amounts in a particular year due to timing of expirations. 
+໿ 
+Net 
+Gross 
+2018 
+2019 
+2020 
+Total 
+Total 
+Permian Basin 
+5,288 
+9,641 
+1,413 
+16,342 
+33,148 
+The expiring acreage set forth in the table above accounts for approximately 99% of our net undeveloped acreage ( 16,496 total net acres). We are continually engaged in a combination of drilling and development and discussions with mineral lessors for lease extensions, renewals, new drilling and development units and new leases to address any potential expiration of undeveloped acreage that occurs in the normal course of our business. 
+Title to Properties 
+The Company believes that the title to its oil and natural gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of such properties. The Company’s properties are potentially subject to one or more of the following: 
+• 
+royalties and other burdens and obligations, express or implied, under oil and natural gas leases; 
+• 
+overriding royalties and other burdens created by us or our predecessors in title; 
+• 
+a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements; farm-out agreements, production sales contracts and other agreements that may affect the properties or their titles; 
+• 
+back-ins and reversionary interests existing under purchase agreements and leasehold assignments; 
+• 
+liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual liens under operating agreements; 
+• 
+pooling, unitization and communitization agreements, declarations and orders; and 
+• 
+easements, restrictions, rights-of-way and other matters that commonly affect property. 
+To the extent that such burdens and obligations affect the Company’s rights to production revenues, these characteristics have been taken into account in calculating Callon’s net revenue interests and in estimating the size and value of its reserves. The Company believes that the burdens and obligations affecting our properties are typical within the industry for properties of the kind owned by Callon. 
+Insurance 
+In accordance with industry practice, the Company maintains insurance against some, but not all, of the operating risks to which its business is exposed. While not all inclusive, the Company’s insurance policies include coverage for general liability insuring onshore operations (including sudden and accidental pollution), aviation liability, auto liability, worker’s compensation, and employer’s liability. The Company carries control of well insurance for all of its drilling operations. 
+Currently, the Company has general liability insurance coverage up to $1 million per occurrence and $2 million per policy in the aggregate, which includes sudden and accidental pollution liability coverage for the effects of pollution on third parties arising from its operations. The Company’s insurance policies contain high policy limits, and in most cases, deductibles (generally ranging from $0 to $250,000) that must be met prior to recovery. These insurance policies are subject to certain customary exclusions and limitations. The Company 
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+Table of Contents 
+maintains up to $100 million in excess liability coverage, which is in addition to and triggered if the underlying liability limits have been reached. In addition, the company purchases pollution legal liability coverage in the amount of $10 million, which is excess and difference in conditions of the liability coverage. 
+The Company requires its third-party contractors to sign master service agreements in which they agree to indemnify the Company for injuries and deaths of the service provider’s employees, as well as contractors and subcontractors hired by the service provider. Similarly, the Company generally agrees to indemnify each third-party contractor against claims made by employees of the Company and the Company’s other contractors. Additionally, each party generally is responsible for damage to its own property. 
+The third-party contractors that perform hydraulic fracturing operations for the Company sign master service agreements generally containing the indemnification provisions noted above. The Company does not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations. However, the Company believes its general liability and excess liability insurance policies would cover foreseeable third party claims related to hydraulic fracturing operations and associated legal expenses, in accordance with, and subject to, the terms of such policies. 
+The Company re-evaluates the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and natural gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. While based on the Company’s risk analysis, it believes that it is properly insured, no assurance can be given that the Company will be able to maintain insurance in the future at rates that it considers reasonable. In such circumstances, the Company may elect to self-insure or maintain only catastrophic coverage for certain risks in the future. 
+Corporate Offices 
+The Company’s headquarters are located in Natchez, Mississippi, in a building owned by the Company. We also maintain leased offices in Houston and Midland, Texas. Because alternative locations to our leased spaces are readily available, the replacement of any of our leased offices would not result in material expenditures . 
+Employees 
+Callon had 169 employees as of December 31, 2017 . None of the Company’s employees are currently represented by a union, and the Company believes that it has good relations with its employees. 
+13 
+Table of Contents 
+Regulations 
+General. Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. Legislation and regulation affecting the entire oil and natural gas industry is continuously being reviewed for amendment and/or expansion. Some of these requirements carry substantial penalties for failure to comply. 
+Exploration and Production . Our operations are subject to federal, state and local regulations that include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds and letters of credit) covering drilling and well operations. Other activities subject to regulation are: 
+• 
+the location and spacing of wells; 
+• 
+the method of drilling and completing and operating wells; 
+• 
+the rate and method of production; 
+• 
+the surface use and restoration of properties upon which wells are drilled and other exploration activities; 
+• 
+notice to surface owners and other third parties; 
+• 
+the venting or flaring of natural gas; 
+• 
+the plugging and abandoning of wells; 
+• 
+the discharge of contaminants into water and the emission of contaminants into air; 
+• 
+the disposal of fluids used or other wastes obtained in connection with operations; 
+• 
+the marketing, transportation and reporting of production; and 
+• 
+the valuation and payment of royalties. 
+Operations conducted on federal or state oil and natural gas leases must comply with numerous regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by DOI Bureaus or other appropriate federal or state agencies. 
+Our sales of oil and natural gas are affected by the availability, terms and cost of pipeline transportation. The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation. If these regulations change, we could face higher transmission costs for our production and, possibly, reduced access to transmission capacity. 
+Various proposals and proceedings that might affect the petroleum industry are pending before Congress, the Federal Energy Regulatory Commission, or FERC, various state legislatures, and the courts. Historically, the industry has been heavily regulated and we can offer you no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue nor can we predict what effect such proposals or proceedings may have on our operations. 
+We do not currently anticipate that compliance with existing laws and regulations governing exploration and production will have a significantly adverse effect upon our capital expenditures, earnings or competitive position. 
+Environmental Matters and Regulation. Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the EPA, issue regulations which often require difficult and costly compliance measures . These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. Violations of environmental laws could result in administrative, civil or criminal fines and injunctive relief. The strict and joint and several liability nature of certain such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons, air emissions or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Further, the EPA has identified environmental compliance by the energy extraction sector as one of its enforcement initiatives for fiscal years 2017-2019, although the outlook for this initiative is unclear with the current administration, and, as a general matter, the oil and natural gas exploration and production industry has been the subject of increasing scrutiny and regulation by environmental authorities. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental 
+14 
+Table of Contents 
+requirements. Although such laws and regulations can increase the cost of planning, designing, installing and operating our facilities, it is anticipated that, absent the occurrence of an extraordinary event, compliance with them will not have a material effect upon our operations, capital expenditures, earnings or competitive position in the marketplace. 
+Waste Handling. The Resource Conservation and Recovery Act (“RCRA”), as amended, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of oil and natural gas are exempt from regulation as hazardous wastes under RCRA and its state analogs, it is possible that some wastes we generate presently or in the future may be subject to regulation under RCRA and state analogs. Additionally, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Additionally, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. Non-exempt waste is subject to more rigorous and costly disposal requirements. Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. 
+Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of wastes associated with oil and natural gas exploration and production could increase our costs to manage and dispose of such wastes. 
+Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), imposes joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or so–called potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes. 
+Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we have generated and will generate wastes that may fall within CERCLA’s definition of hazardous substance and may have disposed of these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum. We may also be the owner or operator of sites on which hazardous substances have been released. To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under CERCLA; we also do not know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties. In the event contamination is discovered at a site on which we are or have been an owner or operator or to which we sent hazardous substances, we could be liable for the costs of investigation and remediation and natural resources damages. 
+We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including offsite locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination. 
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+Table of Contents 
+Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act (“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States (a term broadly defined to include, among other things, certain wetlands), as well as state waters for analogous state programs. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or applicable state analog. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit from the U.S. Army Corps of Engineers. The EPA has issued final rules on the federal jurisdictional reach over waters of the United States that may constitute an expansion of federal jurisdiction over waters of the United States. The rule is the subject of various legal challenges. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. 
+The Oil Pollution Act is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters. 
+Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws. 
+Air Emissions. The federal Clean Air Act, as amended, and comparable state and local laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and modified and existing facilities may be required to obtain additional permits. As a result, we may need to incur capital costs in order to remain in compliance. For example, on August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail below in “Regulation of Hydraulic Fracturing.” These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties and seek injunctive relief for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects. 
+On June 3, 2016, the EPA expanded its regulatory coverage in the oil and gas industry with additional regulated equipment categories, and the addition of new rules limiting methane emissions from new or modified sites and equipment. The EPA attempted to suspend enforcement of the methane rule, but this action was ruled improper. EPA is reported to be considering rulemaking to rescind or revise the rule. Simultaneously with the additional methane rules, EPA released a rule defining site aggregation for air permitting purposes. Should the EPA reconsider this definition, some sites could require additional permitting under the Clean Air Act, an outcome that could result in costs and delays to our operations. 
+Greenhouse Gas Regulation. More stringent laws and regulations relating to climate change and GHGs may be adopted in the future and could cause us to incur material expenses in complying with them. In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions. Although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. 
+The EPA has established GHG reporting requirements for certain sources in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissions. Although these requirements do not limit the amount of GHGs that can be emitted, they do require us to incur costs to monitor, keep records of, and report GHG emissions associated with our operations. The GHG reporting threshold was recently crossed due to drilling activity, acquisitions, and production growth. 
+In addition to possible federal regulation, a number of states, individually and regionally, are also considering or have implemented GHG regulatory programs. These potential regional and state initiatives may result in so-called “Cap-and-Trade programs”, under which overall 
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+Table of Contents 
+GHG emissions are limited and GHG emissions are then allocated and sold, and possibly other regulatory requirements, that could result in our incurring material expenses to comply, such as by being required to purchase or to surrender allowances for GHGs resulting from our operations. These federal, regional and local regulatory initiatives also could adversely affect the marketability of the oil and natural gas we produce. The impact of such future programs cannot be predicted, but we do not expect our operations to be affected any differently than other similarly situated domestic competitors. 
+Regulation of Hydraulic Fracturing. Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act (“SDWA”), regulates the underground injection of substances through the Underground Injection Control (“UIC”), program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions and not at the federal level, as the SDWA expressly excludes regulation of these fracturing activities (except where diesel is a component of the fracturing fluid, as further discussed below). Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing has been proposed in past legislative sessions but has not passed. 
+The EPA, however, issued guidance on permitting hydraulic fracturing that uses fluids containing diesel fuel under the UIC program, specifically as “Class II” UIC wells. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. This report could result in additional regulatory scrutiny that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and business. Further, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. 
+The EPA has adopted regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards for hydraulically fractured natural gas and oil wells to address emissions of sulfur dioxide, volatile organic compounds, or VOCs, and methane, with a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs and methane emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured gas and oil wells newly constructed or refractured. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells. In 2015, the BLM finalized regulations for hydraulic fracturing activities on federal lands. Among other things, the BLM rules imposed new requirements to validate the protection of groundwater, disclosure of chemicals used in hydraulic fracturing and higher standards for the interim storage of recovered waste fluids from hydraulic fracturing. This rule was the subject of legal challenges. In late 2017, the BLM repealed the 2015 ruling; this repeal is the subject of further legal challenges. Similarly, in February 2018, BLM proposed a rule to review certain requirements in its rules regarding the control of methane. 
+Several states, including Texas, and some municipalities, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission has adopted rules and regulations implementing this legislation that apply to all wells for which the Railroad Commission issues an initial drilling permit after February 1, 2012. The new law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) for disclosure on a website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. 
+Additionally, some states, localities and local regulatory districts have adopted or have considered adopting regulations to limit, and in some case impose a moratorium on hydraulic fracturing or other restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water. Further, there has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to 
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+Table of Contents 
+stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing. 
+Surface Damage Statutes (“SDAs”) . In addition, a number of states and some tribal nations have enacted SDAs. These laws are designed to compensate for damage caused by oil and gas development operations. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain binding requirements for payments by the operator to surface owners/users in connection with exploration and operating activities in addition to bonding requirements to compensate for damages to the surface as a result of such activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs. 
+National Environmental Policy Act and Endangered Species Act . Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act (“NEPA”), which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. To the extent that our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects. 
+The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ or its habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. If the Company was to have a portion of its leases designated as critical or suitable habitat or a protected species were located on a lease, it may adversely impact the value of the affected leases. 
+Mineral Leasing Act of 1920 (“Mineral Act”). The Mineral Act prohibits direct or indirect ownership of any interest in federal onshore oil and natural gas leases by a foreign citizen or a foreign corporation except through stock ownership in a corporation formed under the laws of the United States or of any U.S. state or territory, and only if the laws, customs, or regulations of their country of origin or domicile do not deny similar or like privileges to citizens or corporations of the United States. If these restrictions are violated, the oil and gas lease or leases can be canceled in a proceeding instituted by the United States Attorney General. Although the regulations of the BLM (which administers the Mineral Act) provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. For any federal leasehold interest that the Company owns, it is possible that holders of the Company’s equity interests may be citizens of a foreign country, which is a non-reciprocal country under the Mineral Act. In such event, the federal onshore oil and gas leases held by the Company could be subject to cancellation based on such determination. 
+Other Regulation of the Oil and Natural Gas Industry. The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other similar companies in the industry with similar types, quantities and locations of production. 
+The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. Federal and state regulations govern the rates and other terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas. 
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+Table of Contents 
+Although oil and natural gas sales prices are currently unregulated, the federal government historically has been active in the area of oil and natural gas sales regulation. We cannot predict whether new legislation to regulate oil and natural gas sales might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate, oil and natural gas liquids are not currently regulated and are made at market prices. 
+Exports of US Crude Oil Production and Natural Gas Production . The federal government has recently ended its decades-old prohibition of exports of oil produced in the lower 48 states of the US. The general perception in the industry is that ending the prohibition of exports of oil produced in the US will be positive for producers of U.S. oil. In addition, the U.S. Department of Energy (“DOE”) authorizes exports of natural gas, including exports of natural gas by pipelines connecting U.S. natural gas production to pipelines in Mexico, which are expected to increase significantly with the changes taking place in the Mexican government’s regulations of the energy sector in Mexico. In addition, the DOE authorizes the export of liquefied natural gas (“LNG”) through LNG export facilities, the construction of which are regulated by FERC. In the third quarter of 2016, the first quantities of natural gas produced in the lower 48 states of the U.S. were exported as LNG from the first of several LNG export facilities being developed and constructed in the U.S. Gulf Coast region. While it is too recent an event to determine the impact this change may have on our operations or our sales of natural gas, the perception in the industry is that this will be a positive development for producers of U.S. natural gas. 
+Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following: 
+• 
+the location of wells; 
+• 
+the method of drilling and casing wells; 
+• 
+the timing of construction or drilling activities, including seasonal wildlife closures; 
+• 
+the rates of production or “allowables”; 
+• 
+the surface use and restoration of properties upon which wells are drilled; 
+• 
+the plugging and abandoning of wells; and 
+• 
+notice to, and consultation with, surface owners and other third parties. 
+State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affecting the economics of production from these wells or to limit the number of locations we can drill. 
+Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements. 
+Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. 
+Under the Energy Policy Act of 2005 (“EPAct”), Congress amended the Natural Gas Act (“NGA”) to give FERC substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. EPAct also amended the NGA to authorize FERC to “facilitate transparency in markets for the sale or transportation of physical natural gas in interstate commerce,” pursuant to which authorization FERC now requires natural gas wholesale market participants, including a number of entities that may not otherwise be subject to FERC’s traditional NGA jurisdiction, to report information 
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+Table of Contents 
+annually to FERC concerning their natural gas sales and purchases. FERC requires any wholesale market participant that sells 2.2 million MMBtus or more annually in “reportable” natural gas sales to provide a report, known as FERC Form 552, to FERC. Reportable natural gas sales include sales of natural gas that utilize a daily or monthly gas price index, contribute to index price formation, or could contribute to index price formation, such as fixed price transactions for next-day or next-month delivery. 
+FERC also regulates interstate natural gas transportation rates, terms and conditions of natural gas transportation service, and the terms under which we as a shipper may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and for the release of our excess, if any, natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities. 
+Under FERC’s current regulatory regime, interstate transportation services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. The FERC-regulated tariffs, under which interstate pipelines provide such open-access transportation service, contain strict limits on the means by which a shipper releases its pipeline capacity to another potential shipper, which provisions include FERC’s “shipper-must-have-title” rule. Violations by a shipper (i.e., a pipeline customer) of FERC’s capacity release rules or shipper-must-have-title rule could subject a shipper to substantial penalties from FERC. 
+With respect to its regulation of natural gas pipelines under the NGA, FERC has not generally required the applicant for construction of a new interstate natural gas pipeline to produce evidence of the greenhouse gas (“GHG”) emissions of the proposed pipeline’s customers. In August 2017, the U.S. Circuit Court of Appeals for the DC Circuit issued a decision remanding a natural gas pipeline certificate application to FERC, which required FERC to revise its environmental impact statement for the proposed pipeline to take into account GHG carbon emissions from downstream power plants using natural gas transported by the new pipeline. It is too early to determine the impacts of this Court decision, but it could be significant. 
+Gathering service, which occurs on pipeline facilities located upstream of FERC-jurisdictional interstate transportation services, is regulated by the states onshore and in state waters. Depending on changes in the function performed by particular pipeline facilities, FERC has in the past reclassified certain FERC-jurisdictional transportation facilities as non-jurisdictional gathering facilities and FERC has reclassified certain non-jurisdictional gathering facilities as FERC-jurisdictional transportation facilities. Any such changes could result in an increase to our costs of transporting gas to point-of-sale locations. 
+The pipelines used to gather and transport natural gas being produced by the Company are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), the Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In addition, the PHMSA had initially considered regulations regarding, among other things, the designation of additional high consequence areas along pipelines, minimum requirements for leak detection systems, installation of emergency flow restricting devices, and revision of valve spacing requirements. In October 2015, the PHMSA issued proposed new safety regulations for hazardous liquid pipelines, including a requirement that all hazardous liquid pipelines have a system for detecting leaks and that operators establish a timeline for inspections of affected pipelines following extreme weather events or natural disasters. If such revisions to gathering line regulations and liquids pipelines regulations are enacted by PHMSA, we could incur significant expenses. 
+Oil and NGLs Sales and Transportation. Sales of oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. 
+The Company’s sales of oil and natural gas liquids are also affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by the FERC under the Interstate Commerce Act. The FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and 
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+scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors. 
+Further, interstate common carrier oil pipelines must provide service on a non-discriminatory basis under the Interstate Commerce Act (“ICA”), which is administered by FERC. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors. 
+In addition, FERC issued a declaratory order in November 2017, involving a marketing affiliate of an oil pipeline, which held that certain arrangements between an oil pipeline and its marketing affiliate would violate the ICA’s anti-discrimination provisions. FERC held that providing transportation service to affiliates at what is essentially the variable cost of the movement, while requiring non-affiliated shippers to pay the filed tariff rate, would violate the ICA. Rehearing has been sought of this FERC order by various pipelines. It is too recent an event to determine the impact this FERC order may have on oil pipelines, their marketing affiliates, and the price of oil and other liquids transported by such pipelines. 
+Any transportation of the Company’s crude oil, natural gas liquids and purity components (ethane, propane, butane, iso-butane, and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts 171-180 (“HMR”), including Emergency Orders by the FRA and new regulations being proposed by the PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids. 
+In October 2015, the PHMSA issued proposed new safety regulations for hazardous liquid pipelines, including a requirement that all hazardous liquid pipelines have a system for detecting leaks and establish a timeline for inspections of affected pipelines following extreme weather events or natural disasters. 
+State Regulation. Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill. 
+The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us. 
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+Commitments and Contingencies 
+The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment will not have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies included, and claims for damages to property, employees, other persons, and the environment resulting from the Company’s operations could have on its activities. See Note 14 in the Footnotes to the Financial Statements for additional information. 
+Available Information 
+We make available free of charge on our website (www.callon.com) our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the SEC. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE., Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers, like Callon, that file electronically with the SEC. 
+We also make available within the “About Callon” section of our website our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and Audit, Compensation, Strategic Planning and Reserve, and Nominating and Governance Committee Charters, which have been approved by our Board of Directors. We will make timely disclosure by a Current Report on Form 8-K and on our website of any change to, or waiver from, the Code of Business Conduct and Ethics for our principal executive and senior financial officers. A copy of our Code of Business Conduct and Ethics is also available, free of charge by writing us at: Chief Financial Officer, Callon Petroleum Company, P.O. Box 1287, Natchez, MS 39121. 
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+Item 1A. Risk Factors 
+Risk Factors 
+Risks Related to the Oil & Natural Gas Industry 
+Oil and natural gas prices are volatile, and substantial or extended declines in prices may adversely affect our results of operations and financial condition . Our success is highly dependent on prices for oil and natural gas, which have been extremely volatile in recent years. Approximately 77% of our anticipated 2018 production, on a BOE basis, is oil. Starting in the second half of 2014, the NYMEX price for a barrel of oil fell sharply, from a price of $105.37 on June 30, 2014 to $26.21 on February 11, 2016. During 2017 , NYMEX prices ranged from a low of $42.53 per Bbl on June 21, 2017 to a high of $60.42 per Bbl on December 29, 2017 . In addition, NYMEX prices for natural gas have been low compared with historical prices. Extended periods of low prices for oil or natural gas will have a material adverse effect on us. The prices of oil and natural gas depend on factors we cannot control such as macro economic conditions, levels of production, demand for oil and natural gas, relative price and availability of alternative forms of energy, actions by OPEC and other countries, legislative and regulatory actions, technology developments impacting energy consumption and energy supply, and weather. Prices of oil and natural gas will affect the following aspects of our business: 
+• 
+our revenues, cash flows, earnings and returns; 
+• 
+the amount of oil and natural gas that we are economically able to produce; 
+• 
+our ability to attract capital to finance our operations and the cost of the capital; 
+• 
+the amount we are allowed to borrow under our Credit Facility; 
+• 
+the profit or loss we incur in exploring for and developing our reserves; and 
+• 
+the value of our oil and natural gas properties. 
+Any substantial and extended decline in the price of oil or natural gas could have an adverse effect on our borrowing capacity, our ability to obtain additional capital, and our revenues, profitability and cash flows. 
+If oil and natural gas prices remain depressed for extended periods of time, we may be required to make significant downward adjustments to the carrying value of our oil and natural gas properties. Under the full cost method, which we use to account for our oil and natural gas properties, the net capitalized costs of our oil and natural gas properties may not exceed the present value, discounted at 10%, of future net cash flows from estimated net proved reserves, using the preceding 12-months’ average oil and natural gas prices, plus the lower of cost or fair market value of our unproved properties. If net capitalized costs of our oil and natural gas properties exceed this “ceiling test” limit, we must charge the amount of the excess to earnings. This type of charge will not affect our cash flows, but will reduce the book value of our stockholders’ equity. We review the carrying value of our properties quarterly and once incurred, a write-down of oil and natural gas properties is not reversible at a later date, even if prices increase. See Notes 2 and 13 in the Footnotes to the Financial Statements for additional information. 
+For the period ended December 31, 2017 , we did not recognize a write-down of oil and natural gas properties as a result of the ceiling test limitation. The ceiling test calculation as of December 31, 2017 was calculated using the average annual realized prices used in determining the estimated future net cash flows from proved reserves of $51.34 per barrel of oil and $2.98 per Mcf of natural gas. Oil prices continue to fluctuate and we may experience ceiling test write-downs in the future. Any future ceiling test cushion, and the risk we may incur write-downs or impairments, will be subject to fluctuation as a result of acquisition or divestiture activity. 
+Our estimated reserves are based on interpretations and assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. This Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. 
+Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from the estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report. Additionally, estimates of reserves and future cash flows may be subject to material downward or upward revisions, based on production history, development drilling and exploration activities and prices of oil and natural gas. 
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+You should not assume that any present value of future net cash flows from our estimated net proved reserves contained in this Form 10-K represents the market value of our oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves at December 31, 2017 on average 12-month prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures, the rate and timing of production, and changes in governmental regulations or taxes. At December 31, 2017 , approximately 35% of the discounted present value of our estimated net proved reserves consisted of PUDs. PUDs represented 49% of total proved reserves by volume. Recovery of PUDs generally requires significant capital expenditures and successful drilling operations. Our reserve estimates include the assumption that we will make significant capital expenditures to develop these PUDs and the actual costs, development schedule, and results associated with these properties may not be as estimated. In addition, the 10% discount factor that we use to calculate the net present value of future net revenues and cash flows may not necessarily be the most appropriate discount factor based on our cost of capital in effect from time to time and the risks associated with our business and the oil and gas industry in general. 
+Unless we replace our oil and gas reserves, our reserves and production will decline. Our future oil and gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our production, revenues, reserve quantities and cash flows will decline. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. We may not be successful in finding, developing or acquiring additional reserves, and our efforts may not be economic. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be limited to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. 
+Competitive industry conditions may negatively affect our ability to conduct operations. We compete with numerous other companies in virtually all facets of our business. Our competitors in development, exploration, acquisitions and production include major integrated oil and gas companies and smaller independents as well as numerous financial buyers, including many that have significantly greater resources than us. Therefore, competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources permit. We also compete for the materials, equipment, personnel and services that are necessary for the exploration, development and operation of our properties. Our ability to increase reserves in the future will be dependent on our ability to select and acquire suitable prospects for future exploration and development. Factors that affect our ability to compete in the marketplace include: 
+• 
+our access to the capital necessary to drill wells and acquire properties; 
+• 
+our ability to acquire and analyze seismic, geological and other information relating to a property; 
+• 
+our ability to retain the personnel necessary to properly evaluate seismic and other information relating to a property; 
+• 
+our ability to procure materials, equipment, personnel and services required to explore, develop and operate our properties, including the ability to procure fracture stimulation services on wells drilled; and 
+• 
+our ability to access pipelines, and the location of facilities used to produce and transport oil and natural gas production. 
+The unavailability or high cost of drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget. From time to time, our industry experiences a shortage of drilling rigs, equipment, supplies, water or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews and other experienced personnel rise as the level of activity increases. Increasing levels of exploration and production may increase the demand for oilfield services and equipment, and the costs of these services and equipment may increase, while the quality of these services and equipment may suffer. The unavailability or high cost of drilling rigs, pressure pumping equipment, supplies, water or qualified personnel can materially and adversely affect our operations and profitability. 
+Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area. All of our producing properties are geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of oil, natural gas or natural gas liquids. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations. 
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+We may be unable to integrate successfully the operations of recent and future acquisitions with our operations, and we may not realize all the anticipated benefits of these acquisitions. Our business has and may in the future include producing property acquisitions that include undeveloped acreage. We can offer no assurance that we will achieve the desired profitability from our recent acquisitions or from any acquisitions we may complete in the future. In addition, failure to assimilate recent and future acquisitions successfully could adversely affect our financial condition and results of operations. Our acquisitions may involve numerous risks, including: 
+• 
+operating a larger combined organization and adding operations; 
+• 
+difficulties in the assimilation of the assets and operations of the acquired business, especially if the assets acquired are in a new geographic area; 
+• 
+risk that oil and natural gas reserves acquired may not be of the anticipated magnitude or may not be developed as anticipated; 
+• 
+loss of significant key employees from the acquired business; 
+• 
+inability to obtain satisfactory title to the assets we acquire; 
+• 
+a decrease in our liquidity if we use a portion of our available cash to finance acquisitions; 
+• 
+a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions; 
+• 
+diversion of management’s attention from other business concerns; 
+• 
+failure to realize expected profitability or growth; 
+• 
+failure to realize expected synergies and cost savings; 
+• 
+coordinating geographically disparate organizations, systems and facilities; and 
+• 
+coordinating or consolidating corporate and administrative functions. 
+Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. If we consummate any future acquisition, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisition and current operations, which in turn, could negatively impact our results of operations. 
+We may fail to fully identify problems with any properties we acquire, and as such, assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities. We are actively seeking to acquire additional acreage in Texas or other regions in the future. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, adequacy of title, operating and capital costs and potential environmental and other liabilities. Although we conduct a review of properties we acquire which we believe is consistent with industry practices, we can give no assurance that we have identified or will identify all existing or potential problems associated with such properties or that we will be able to mitigate any problems we do identify. Such assessments are inexact and their accuracy is inherently uncertain. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface, title and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for preclosing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms. 
+Restrictions on our ability to obtain, recycle and dispose of water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner. Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to secure water from local land owners and other third party sources for use in our operations. If drought conditions were to occur or demand for water were to outpace supply, our ability to obtain water could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows. In addition, significant amounts of water are produced in our operations. Inadequate access to or availability of water recycling or water disposal facilities could adversely affect our production volumes or significantly increase the cost of our operations. 
+Factors beyond our control affect our ability to market production and our financial results. The ability to market oil and natural gas from our wells depends upon numerous factors beyond our control. These factors could negatively affect our ability to market all of the oil or natural gas we produce. In addition, we may be unable to obtain favorable prices for the oil and natural gas we produce. These factors include: 
+• 
+the extent of domestic production and imports/exports of oil and natural gas; 
+• 
+federal regulations authorizing exports of liquefied natural gas (“LNG”), the development of new LNG export facilities under construction in the U.S. Gulf Coast region, and the first LNG exports from such facilities; 
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+Table of Contents 
+• 
+the construction of new pipelines capable of exporting U.S. natural gas to Mexico; 
+• 
+the proximity of hydrocarbon production to pipelines; 
+• 
+the availability of pipeline and/or refining capacity; 
+• 
+the demand for oil and natural gas by utilities and other end users; 
+• 
+the availability of alternative fuel sources; 
+• 
+the effects of inclement weather; 
+• 
+state and federal regulation of oil and natural gas marketing; and 
+• 
+federal regulation of natural gas sold or transported in interstate commerce. 
+In particular, in areas with increasing non-conventional shale drilling activity, pipeline, rail or other transportation capacity may be limited and it may be necessary for new interstate and intrastate pipelines and gathering systems to be built. 
+The marketability of our production is dependent upon transportation facilities and services owned and operated by third parties, and the unavailability of these facilities or services would have a material adverse effect on our revenue. Our ability to market our production depends on the availability and capacity of pipeline and other transportation operations, including trucking services, owned and operated by third parties. These facilities and services may be temporarily unavailable to us due to market conditions, physical or mechanical disruption, weather, lack of contracted capacity or other reasons. In addition, in certain newer development areas, transportation facilities and services may not be sufficient to accommodate potential production. Our failure to obtain access to transportation facilities and services on acceptable terms could materially harm our business. We may be required to shut in wells for lack of a market or because of inadequate or unavailable transportation capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. If we were required to shut in our production for long periods of time due to lack of transportation capacity, it would have a material adverse effect on our business, financial condition, results of operations and cash flows. 
+Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns. Exploration, development, drilling and production activities are subject to many risks. We may invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that any leasehold acreage acquired will be profitably developed, that new wells drilled will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, including wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, wells that are profitable may not achieve our targeted rate of return. 
+In addition, we may not be successful in controlling our drilling and production costs to improve our overall return. We may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including among others: 
+• 
+unexpected drilling conditions; 
+• 
+pressure or irregularities in formations; 
+• 
+lack of proximity to and shortage of capacity of transportation facilities; 
+• 
+equipment failures or accidents and shortages or delays in the availability of drilling rigs, equipment, personnel and services; and 
+• 
+compliance with governmental requirements. 
+Failure to conduct our oil and gas operations in a profitable manner may result in write-downs of our proved reserves quantities, impairment of our oil and gas properties, and a write-down in the carrying value of our unproved properties, and over time may adversely affect our growth, revenues and cash flows. 
+Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could prevent them from being drilled or delay their drilling. Our management team has identified drilling locations as an estimation of our future development activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these identified drilling locations depends on a number of uncertainties, including among others: 
+• 
+oil and natural gas prices; 
+• 
+the availability and cost of capital; 
+• 
+availability and cost of drilling, completion and production services and equipment; 
+• 
+drilling results; 
+• 
+lease expirations; 
+• 
+gathering, marketing and transportation constraints; and 
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+Table of Contents 
+• 
+regulatory approvals. 
+Because of these uncertain factors, we do not know if the identified drilling locations will ever be drilled or if we will be able to produce oil or natural gas from these drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the identified locations are located, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified. 
+The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Approximately 49% of our total estimated proved reserves as of December 31, 2017 , were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves. 
+The results of our planned development programs in new or emerging shale development areas and formations may be subject to more uncertainties than programs in more established areas and formations, and may not meet our expectations for reserves or production. The results of our horizontal drilling efforts in emerging areas and formations of the Permian Basin, including Howard and Ward Counties, are generally more uncertain than drilling results in areas that are less developed and have more established production from horizontal formations such as the Wolfcamp, Spraberry and Bone Spring horizons. Because emerging areas and associated target formations have limited or no production history, we are less able to rely on past drilling results in those areas as a basis to predict our future drilling results. In addition, horizontal wells drilled in shale formations, as distinguished from vertical wells, utilize multilateral wells and stacked laterals, all of which are subject to well spacing, density and proration requirements of the Texas Railroad Commission, which requirements could adversely impact our ability to maximize the efficiency of our horizontal wells related to reservoir drainage over time. Further, access to adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more challenging in new or emerging areas. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, access to gathering systems and takeaway capacity or otherwise, and/or natural gas and oil prices decline, our investment in these areas may not be as economic as we anticipate, we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future. 
+Unexpected subsurface conditions and other unforeseen operating hazards may adversely impact our ability to conduct business. There are many operating hazards in exploring for and producing oil and natural gas, including: 
+• 
+our drilling operations may encounter unexpected formations or pressures, which could cause damage to equipment or personal injury; 
+• 
+we may experience equipment failures which curtail or stop production; 
+• 
+we could experience blowouts or other damages to the productive formations that may require a well to be re-drilled or other corrective action to be taken; and 
+• 
+storms and other extreme weather conditions could cause damages to our production facilities or wells. 
+Because of these or other events, we could experience environmental hazards, including release of oil and natural gas from spills, natural gas-leaks, accidental leakage of toxic or hazardous materials, such as petroleum liquids, drilling fluids or fracturing fluids, including chemical additives, underground migration, and ruptures. 
+If we experience any of these problems, it could affect well bores, gathering systems and processing facilities, which could adversely affect our ability to conduct operations. We could also incur substantial losses in excess of our insurance coverage as a result of: 
+• 
+injury or loss of life; 
+• 
+severe damage to and destruction of property, natural resources and equipment; 
+• 
+pollution and other environmental damage; 
+• 
+clean-up responsibilities; 
+• 
+regulatory investigation and penalties; 
+• 
+suspension of our operations; and 
+• 
+repairs to resume operations. 
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+We cannot assure you that we will be able to maintain adequate insurance at rates we consider reasonable to cover our possible losses from operating hazards. The occurrence of a significant event not fully insured or indemnified against could materially and adversely affect our financial condition and results of operations. 
+The loss of key personnel could adversely affect our ability to operate. We depend, and will continue to depend in the foreseeable future, on the services of our senior officers and other key employees, as well as other third-party consultants with extensive experience and expertise in evaluating and analyzing drilling prospects and producing oil and natural gas and maximizing production from oil and natural gas properties. Our ability to retain our senior officers, other key employees and our third party consultants, none of whom are subject to employment agreements, is important to our future success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business. 
+Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations. Our business has become increasingly dependent on digital technologies to conduct certain exploration, development, production and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, manage operations, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our exploration or production operations. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyber-attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. Cyber incidents have increased, and the U.S. government has issued warnings indicating that energy assets may be specific targets of cyber security threats. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks. 
+Risks Related to Financial Position 
+Our business requires significant capital expenditures and we may not be able to obtain needed capital or financing on satisfactory terms or at all . We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Historically, we have funded our capital expenditures through a combination of cash flows from operations, borrowings from financial institutions, the sale of public debt and equity securities and asset dispositions. In 2017 , our total operational capital expenditures, including expenditures for drilling, completion and facilities, were approximately $420 million on a cash basis ( $463 million on an accrual, or GAAP, basis). Our 2018 budget for operational capital expenditures is currently estimated to be approximately $500 to $540 million (on an accrual, or GAAP, basis). The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the cost and availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. 
+If the borrowing base under our Credit Facility or our revenues decrease as a result of lower oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or cash available under our Credit Facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our drilling locations, which in turn could lead to a possible expiration of our leases and a decline in our estimated net proved reserves, and could adversely affect our business, financial condition and results of operations. 
+Restrictive covenants in our Credit Facility and the indenture governing our 6.125% Senior Notes may limit our ability to respond to changes in market conditions or pursue business opportunities. Our Credit Facility and the indenture governing our 6.125% Senior Notes contain restrictive covenants that limit our ability to, among other things: 
+• 
+incur additional indebtedness; 
+• 
+make investments; 
+• 
+merge or consolidate with another entity; 
+• 
+pay dividends or make certain other payments; 
+• 
+hedge future production or interest rates; 
+• 
+create liens that secure indebtedness; 
+• 
+sell assets; and 
+• 
+engage in certain other transactions without the prior consent of the lenders. 
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+As a result of these covenants, we are limited in the manner in which we conduct our business and we may be unable to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business. 
+In addition, our Credit Facility requires us to maintain certain financial ratios and to make certain required payments of principal, premium, if any, and interest. If we fail to comply with these provisions or other financial and operating covenants in the Credit Facility and the indenture governing the 6.125 % Senior Notes, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default: 
+• 
+the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest; 
+• 
+the lenders under our Credit Facility could elect to terminate their commitments thereunder, cease making further loans and institute foreclosure proceedings against our assets; and 
+• 
+we could be forced into bankruptcy or liquidation. 
+Our borrowings under our Credit Facility expose us to interest rate risk. Our earnings are exposed to interest rate risk associated with borrowings under our Credit Facility, which bear interest at a rate elected by us that is based on the prime, LIBOR or federal funds rate plus margins ranging from 2.00% to 3.00% depending on the interest rate used and the amount of the loan outstanding in relation to the borrowing base. 
+The borrowing base under our Credit Facility may be reduced below the amount of borrowings outstanding under such facilities. The borrowing base under our Credit Facility is currently $700 million , with elected commitments of $500 million . In the future, we may not be able to access adequate funding under our Credit Facility as a result of a decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations. In addition, we cannot borrow amounts above the elected commitments, even if the borrowing base is greater, without new commitments being obtained from the lenders for such incremental amounts above the elected commitments. Our borrowing base is subject to redeterminations semi-annually, and our next scheduled borrowing base redetermination is expected to occur on or about May 2018 . If our borrowing base were to be reduced, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness. In addition, in the event the amount outstanding under our Credit Facility exceeds the elected commitments, we must repay such amounts immediately in cash. In the event the amount outstanding under our Credit Facility exceeds the redetermined borrowing base, we are required to either (i) grant liens on additional oil and gas properties (not previously evaluated in determining such borrowing base) with a value equal to or greater than such excess, (ii) repay such excess borrowings over six monthly installments, or (iii) elect a combination of options in clauses (i) and (ii). We may not have sufficient funds to make any required repayment. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, an event of default would occur under our Credit Facility. 
+We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful. Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to certain financial, economic, competitive and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. 
+If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. Our Credit Facility currently restricts our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations. 
+Our leverage and debt service obligations may adversely affect our financial condition, results of operations, and business prospects. As of December 31, 2017 , we had $600 million outstanding of 6.125% Senior Notes and $25 million outstanding under our Credit Facility, which had an additional $474 million available for borrowings based on the existing level of commitments. Our amount of indebtedness could affect our operations in several ways, including the following: 
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+• 
+require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities; 
+• 
+limit management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; 
+• 
+increase our vulnerability to downturns and adverse developments in our business and the economy; 
+• 
+limit our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness; 
+• 
+place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations; 
+• 
+make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; 
+• 
+make us vulnerable to increases in interest rates as our indebtedness under our Credit Facility may vary with prevailing interest rates; 
+• 
+place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness; and 
+• 
+make it more difficult for us to satisfy our obligations under the 6.125% Senior Notes or other debt and increase the risk that we may default on our debt obligations. 
+We cannot assure you that we will be able to maintain or improve our leverage position. An element of our business strategy involves maintaining a disciplined approach to financial management. However, we are also seeking to acquire, exploit and develop additional reserves that may require the incurrence of additional indebtedness. Although we will seek to maintain or improve our leverage position, our ability to maintain or reduce our level of indebtedness depends on a variety of factors, including future performance and our future debt financing needs. General economic conditions, oil and natural gas prices and financial, business and other factors will also affect our ability to maintain or improve our leverage position. Many of these factors are beyond our control. 
+We may not be insured against all of the risks to which our business is exposed from ongoing or legacy operations. In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We cannot assure you that our insurance will be adequate to cover all losses or liabilities related to our current or legacy operations. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. No assurance can be given that we will be able to maintain insurance in the future at rates we consider reasonable and may elect none or minimal insurance coverage. The occurrence of a significant event or claim, not fully insured or indemnified against, could have a material adverse effect on our financial condition and operations. 
+Our hedging program may limit potential gains from increases in commodity prices or may result in losses or may be inadequate to protect us against continuing and prolonged declines in commodity prices. We enter into hedging arrangements from time to time to reduce our exposure to fluctuations in oil and natural gas prices and to achieve more predictable cash flow. Our hedges at December 31, 2017 are in the form of collars, swaps, put and call options, and other structures placed with the commodity trading branches of certain national banking institutions and with certain other commodity trading groups. These hedging arrangements may limit the benefit we could receive from increases in the market or spot prices for oil and natural gas. We cannot assure you that the hedging transactions we have entered into, or will enter into, will adequately protect us from fluctuations in oil and natural gas prices. At December 31, 2017 , the Company’s hedging portfolio, linked to NYMEX benchmark pricing, covers approximately 5,842 MBbls and 4,086 BBtu of our expected oil and natural gas production, respectively, for calendar year 2018 . We also have commodity hedging contracts linked to Midland WTI basis differentials relative to Cushing covering approximately 5,289 MBbls of our expected oil production for calendar year 2018 . These hedges may be inadequate to protect us from continuing and prolonged declines in oil and natural gas prices. To the extent that oil and natural gas prices remain at current levels or decline further, we will not be able to hedge future production at the same pricing level as our current hedges and our results of operations and financial condition would be negatively impacted. 
+We may not have production to offset hedges. Part of our business strategy is to reduce our exposure to the volatility of oil and natural gas prices by hedging a portion of our production. In a typical hedge transaction, we will have the right to receive from the other parties to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the other parties this difference multiplied by the quantity hedged regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements even though such payments are not offset by sales of physical production. 
+Our hedging transactions expose us to counterparty credit risk. Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a 
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+counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract. During periods of falling commodity prices, our hedging transactions expose us to risk of financial loss if our counterparty to a derivatives transaction fails to perform its obligations under a derivatives transaction. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss. 
+The inability of one or more of our customers to meet their obligations to us may adversely affect our financial results . Our principal exposures to credit risk are through receivables resulting from the sale of our oil and natural gas production, which we market to energy marketing companies, refineries and affiliates, advances to joint interest parties and joint interest receivables. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. The largest purchaser of our oil and natural gas accounted for approximately 29% of our total oil and natural gas revenues for the year ended December 31, 2017 . We do not require any of our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. 
+We have no plans to pay cash dividends on our common stock in the foreseeable future. The terms of our Credit Facility contain limitations that impact our ability to pay dividends and make other distributions. In addition, any future determination as to the declaration and payment of cash dividends will be at the discretion of our Board of Directors and will depend upon our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors deemed relevant by our Board of Directors. 
+Legal and Regulatory Risks 
+We are subject to stringent and complex federal, state and local laws and regulations which require compliance that could result in substantial costs, delays or penalties. Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. For a discussion of the material regulations applicable to us, see “Regulations.” These laws and regulations may: 
+• 
+require that we acquire permits before commencing drilling; 
+• 
+regulate the spacing of wells and unitization and pooling of properties; 
+• 
+impose limitations on production or operational, emissions control and other conditions on our activities; 
+• 
+restrict the substances that can be released into the environment or used in connection with drilling and production activities or restrict the disposal of waste from our operations; 
+• 
+limit or prohibit drilling activities on protected areas such as wetlands, wilderness or other protected areas; 
+• 
+impose penalties and other sanctions for accidental and/or unpermitted spills or releases from our operations; and 
+• 
+require measures to remediate or mitigate pollution and environmental impacts from current and former operations, such as cleaning up spills or dismantling abandoned production facilities. 
+Significant expenditures may be required to comply with governmental laws and regulations applicable to us. In addition, failure to comply with these laws and regulations may result in the assessment of penalties, permit revocations, requirements for additional pollution controls or injunctions limiting or prohibiting operations. 
+The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal, state and local agencies frequently revise environmental laws and regulations, and such changes could result in increased costs for environmental compliance, such as waste handling, permitting, or cleanup for the oil and natural gas industry and could have a significant impact on our operating costs. In general, the oil and natural gas industry recently has been the subject of increased legislative and regulatory attention with respect to environmental matters. Even if regulatory burdens temporarily ease, the historic trend of more expansive and stricter environmental legislation and regulations may continue in the long-term. 
+Further, under these laws and regulations, we could be liable for costs of investigation, removal and remediation, damages to and loss of use of natural resources, loss of profits or impairment of earning capacity, property damages, costs of increased public services, as well as administrative, civil and criminal fines and penalties, and injunctive relief. Certain environmental statutes, including the RCRA, CERCLA, OPA and analogous state laws and regulations, impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released. We could also be affected by more stringent laws and regulations adopted in the future, including any related to climate change, greenhouse gases and hydraulic fracturing. Under the common law, we could be liable for injuries to people and property. We maintain limited insurance coverage for sudden and accidental environmental damages. We do not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Also, we do not believe that insurance coverage for the full potential liability that could be caused by sudden and 
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+accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability or we may be required to cease production from properties in the event of environmental incidents. 
+Federal legislation and state and local legislative and regulatory initiatives relating to hydraulic fracturing and water disposal wells could result in increased costs and additional operating restrictions or delays. Hydraulic fracturing is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production and is typically regulated by state oil and gas commissions. However, legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of "underground injection," to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as "Class II" Underground Injection Control wells under the Safe Drinking Water Act. The EPA has also published air emission standards for certain equipment, processes and activities across the oil and natural gas sector. In addition, the BLM previously published final rules governing hydraulic fracturing on federal and Indian lands, which rules have been rescinded or suspended, but litigation is ongoing regarding the rules. 
+In some areas of Texas, there has been concern that certain formations into which disposal wells are injecting produced waters could become over-pressured after many years of injection, and the governing Texas regulatory agency is reviewing the data to determine whether any action is necessary to address this issue. If the Texas state agency were to decline to issue permits for, or limit the volumes of, new injection wells into the formations currently utilized by us, we may be required to seek alternative methods of disposing of produced waters, including injecting into deeper formations, which could increase our costs. 
+Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, impose additional requirements on hydraulic fracturing activities or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For example, pursuant to legislation adopted by the State of Texas in June 2011, the chemical components used in the hydraulic fracturing process, as well as the volume of water used, must be disclosed to the RRC and the public. Furthermore, in 2013, the RRC issued the "well integrity rule," which includes new testing and reporting requirements, such as (i) the requirement to submit to the RRC cementing reports after well completion or cessation of drilling, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. Additionally, in 2014 the RRC adopted a rule requiring applicants for certain new water disposal wells to conduct seismic activity searches using the U.S. Geological Survey to determine the potential for earthquakes within a circular area of 100 square miles. The rule also clarifies the RRC's authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The RRC has used this authority to deny permits for waste disposal wells. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of drilling in general and/or hydraulic fracturing in particular. 
+In December 2016, the EPA released its final report “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States.” This report concludes that hydraulic fracturing can impact drinking water resources in certain circumstances but also noted that certain date gaps and uncertainties limited EPA’s assessment. This study could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. 
+There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, water usage and the potential for impacts to surface water, groundwater and the environment generally, and a number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. Several states and municipalities have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances. If new laws or regulations that significantly restrict hydraulic fracturing or water disposal wells are adopted, such laws could make it more difficult or costly for us to drill for and produce oil and natural gas as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements, permitting delays and potential increases in costs. These changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing. 
+Climate change legislation or regulations restricting emissions of “greenhouse gases” (“GHG”) could result in increased operating costs and reduced demand for the oil and natural gas we produce. In recent years, federal, state and local governments have taken 
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+steps to reduce emissions of greenhouse gases. The EPA has finalized a series of greenhouse gas monitoring, reporting and emissions control rules for the oil and natural gas industry, and the U.S. Congress has, from time to time, considered adopting legislation to reduce emissions. Several states have already taken measures to reduce emissions of greenhouse gases primarily through the development of greenhouse gas emission inventories and/or regional greenhouse gas cap-and-trade programs. While we are subject to certain federal greenhouse gas monitoring and reporting requirements, our operations currently are not adversely impacted by existing federal, state and local climate change initiatives. For a description of existing and proposed greenhouse gas rules and regulations, see “Regulations.” 
+In December 2015, the United States participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake "ambitious efforts" to limit the average global temperature and to conserve and enhance sinks and reservoirs of GHGs. The Paris Agreement went into effect on November 4, 2016. The Paris Agreement establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. However, on June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement. It is not clear what steps the Trump Administration plans to take to withdraw from the Paris Agreement, whether a new agreement can be negotiated, or what terms would be included in such an agreement. Restrictions on GHG emissions that may be imposed could adversely affect the oil and gas industry. The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations. 
+Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely impact the demand for, price of, and value of our products and reserves. As our operations also emit greenhouse gases directly, current and future laws or regulations limiting such emissions could increase our own costs. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business. 
+In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Furthermore, claims have been made against certain energy companies alleging that GHG emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other liabilities. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition. 
+Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) establishes federal oversight and regulation of over-the-counter derivatives and requires the U.S. Commodity Futures Trading Commission (the “CFTC”) and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the over-the-counter market. 
+Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized. In one of the CFTC’s rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC has proposed but not yet approved position limits for certain futures and options contracts in various commodities and for swaps that are their economic equivalents (with exemptions for certain bona fide hedging transactions). Similarly, the CFTC has proposed but not yet finalized a rule regarding the capital that a swap dealer or major swap participant is required to post with respect to its swap business has not yet issued a final rule. The CFTC has issued a final rule on margin requirements for uncleared swap transactions in January 2016, which includes an exemption for certain commercial end-users that enter into uncleared swaps in order to hedge bona fide commercial risks affecting their business. In addition, the CFTC has issued a final rule authorizing an exception from the requirement to use cleared exchanges (rather than hedging over-the-counter) for commercial end-users who use swaps to hedge their commercial risks. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations. All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business. 
+While it is not possible at this time to predict when the CFTC will issue final rules applicable to position limits or capital requirements, depending on our ability to satisfy the CFTC’s requirements for the various exemptions available for a commercial end-user using swaps to hedge or mitigate its commercial risks, these rules and regulations may provide beneficial exemptions or may require us to comply with position limits and other limitations with respect to our financial derivative activities. When a final rule on capital requirements is 
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+Table of Contents 
+issued, the Dodd-Frank Act may require our current counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which could increase the cost to us of entering into such derivatives. The Dodd-Frank Act may also require our current counterparties to financial derivative transactions to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties, and may cause some entities to cease their current business as hedge providers. These changes could reduce the liquidity of the financial derivatives markets which would reduce the ability of commercial end-users like us to hedge or mitigate their exposure to commodity price volatility. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of future swaps relative to the terms of our existing financial derivative contracts, and reduce the availability of derivatives to protect against commercial risks we encounter. 
+In addition, federal banking regulators have adopted new capital requirements for certain regulated financial institutions in connection with the Basel III Accord. The Federal Reserve Board also issued proposed regulations on September 30, 2016, proposing to impose higher risk-weighted capital requirements on financial institutions active in physical commodities, such as oil and natural gas. If and when these proposed regulations are fully implemented, financial institutions subject to these higher capital requirements may require that we provide cash or other collateral with respect to our obligations under the financial derivatives and other contracts in order to reduce the amount of capital such financial institutions may have to maintain. Alternatively, financial institutions subject to these capital requirements may require premiums to enter into derivatives and other physical commodity transactions to compensate for the additional capital costs for these transactions. Rules implementing the Basel III Accord and higher risk-weighted capital requirements could materially reduce our liquidity and increase the cost of derivative contracts and other physical commodity contracts (including through requirements to post collateral which could adversely affect our available capital for other commercial operations purposes). 
+If we reduce our use of derivative contracts as a result of any of the foregoing new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas and natural gas liquids prices, which some legislators attributed to speculative trading in derivatives and commodity instruments. Our revenues could t be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations, or cash flows. 
+Tax laws and regulations may change over time, and the recently passed comprehensive tax reform bill could adversely affect our business and financial condition. On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the "Tax Act") that significantly reforms the Internal Revenue Code of 1986, as amended (the "Code"). The Tax Act, among other things, (i) permanently reduces the U.S. corporate income tax rate, (ii) repeals the corporate alternative minimum tax, (iii) eliminates the deduction for certain domestic production activities, (iv) imposes new limitations on the utilization of net operating losses, and (v) provides for more general changes to the taxation of corporations, including changes to cost recovery rules and to the deductibility of interest expense, which may impact the taxation of oil and gas companies. The Tax Act is complex and far-reaching and we cannot predict with certainty the resulting impact its enactment has on us. The ultimate impact of the Tax Act may differ from our estimates due to changes in interpretations and assumptions made by us as well as additional regulatory guidance that may be issued and any such changes in interpretations or assumptions could adversely affect our business and financial condition. See Note 11 to our consolidated financial statements included elsewhere in this Annual Report for additional information. 
+In addition, from time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws, including (i) the elimination of the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties and (iii) an extension of the amortization period for certain geological and geophysical expenditures. While these specific changes are not included in the Tax Act, no accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. The elimination of such U.S. federal tax deductions, as well as any other changes to or the imposition of new federal, state, local or non-U.S. taxes (including the imposition of, or increases in production, severance or similar taxes) could adversely affect our business and financial condition. 
+Provisions of our charter documents and Delaware law may inhibit a takeover, which could limit the price investors might be willing to pay in the future for our common stock. Provisions in our certificate of incorporation and bylaws may have the effect of delaying or preventing an acquisition of the Company or a merger in which we are not the surviving company and may otherwise prevent or slow changes in our board of directors and management. In addition, because we are incorporated in Delaware, we are governed by the provisions of Section 203 of the Delaware General Corporation Law. These provisions could discourage an acquisition of the Company or other change in control transactions and thereby negatively affect the price that investors might be willing to pay in the future for our common stock. 
+34 
+Table of Contents 
+We may be subject to the actions of activist shareholders. We have been the subject of increased activity by activist shareholders. Responding to shareholder activism can be costly and time-consuming, disrupt our operations and divert the attention of management and our employees from executing our business plan. Activist campaigns can create perceived uncertainties as to our future direction, strategy or leadership and may result in the loss of potential business opportunities, harm our ability to attract new investors, customers and joint venture partners and cause our stock price to experience periods of volatility or stagnation. Moreover, if individuals are elected to our board of directors with a specific agenda, our ability to effectively and timely implement our current initiatives, retain and attract experienced executives and employees and execute on our long-term strategy may be adversely affected. 
+ITEM 1B. Unresolved Staff Comments 
+None. 
+ITEM 3. Legal Proceedings 
+We are a defendant in various legal proceedings and claims, which arise in the ordinary course of our business. We do not believe the ultimate resolution of any such actions will have a material effect on our financial position or results of operations. 
+ITEM 4. Mine Safety Disclosures 
+Not applicable. 
+35 
+Table of Contents 
+PART II. 
+ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+Market Information 
+Our common stock trades on the New York Stock Exchange under the symbol “CPE”. The following table sets forth the high and low sale prices per share as reported for the periods indicated. 
+໿ 
+Common Stock Price 
+2017 
+2016 
+High 
+Low 
+High 
+Low 
+First quarter 
+$ 
+16.32 
+$ 
+10.97 
+$ 
+9.05 
+$ 
+4.21 
+Second quarter 
+13.92 
+9.63 
+12.56 
+8.15 
+Third quarter 
+11.74 
+9.34 
+15.91 
+10.34 
+Fourth quarter 
+12.50 
+9.76 
+18.53 
+12.45 
+Holders 
+As of February 23, 2018 the Company had approximately 2,715 common stockholders of record. 
+Dividends 
+We have not paid any cash dividends on our common stock to date and presently do not expect to declare or pay any cash dividends on our common stock in the foreseeable future as we intend to reinvest our cash flows and earnings into our business. The declaration and payment of dividends is subject to the discretion of our Board of Directors and to certain limitations imposed under Delaware corporate law and the agreements governing our debt obligations. The timing, amount and form of dividends, if any, will depend on, among other things, our results of operations, financial condition, cash requirements and other factors deemed relevant by our Board of Directors. In addition, certain of our debt facilities contain restrictions on the payment of dividends to the holders of our common stock. 
+Holders of our 10% Series A Cumulative Preferred Stock are entitled to a cumulative dividend whether or not declared, of $5.00 per annum, payable quarterly, equivalent to 10.0% of the liquidation preference of $50.00 per share. Unless the full amount of the dividends for the 10% Series A Cumulative Preferred Stock is paid in full, we cannot declare or pay any dividend on our common stock. 
+During 2017 , neither the Company nor any affiliated purchasers made repurchases of Callon’s equity securities. 
+On February 4, 2016, a total of 120,000 shares of the Company’s 10% Series A Cumulative Preferred Stock were exchanged for 719,000 shares of common stock. 
+Equity Compensation Plan Information 
+The following table summarizes information regarding the number of shares of our common stock that are available for issuance under all of our existing equity compensation plans as of December 31, 2017 (securities amounts are presented in thousands). 
+໿ 
+Plan Category 
+Number of Securities to be Issued Upon Exercise of Outstanding Options 
+Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights 
+Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans 
+Equity compensation plans approved by security holders 
+— 
+$ 
+— 
+1,338 
+Equity compensation plans not approved by security holders 
+— 
+$ 
+— 
+— 
+Total 
+— 
+$ 
+— 
+1,338 
+For additional information regarding the Company’s benefit plans and share-based compensation expense, see Notes 8 and 9 in the Footnotes to the Financial Statements. 
+36 
+Table of Contents 
+Performance Graph 
+The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the performance of the Company’s common stock relative to two broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. 
+The graph below compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the Standard & Poor’s 500 Index (“S&P 500 Index”), Dow Jones US Select Oil & Gas Exploration and Production Index (“DJ US Select O&G E&P Index”) and Susquehanna International Group, LLP Oil Exploration & Production Index (“SIG Oil E&P Index”) from December 31, 2012, through December 31, 2017 . The SIG Oil E&P Index is no longer an active index and the Company plans to replace it with the DJ US Select O&G E&P Index, which is commonly used by the Company’s peer group. Consequently, this index has been added to the graph below, and we expect to include it in future year’s performance graphs. 
+The stock performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing. 
+Comparison of Five Year Cumulative Total Return 
+Assumes Initial Investment of $100 
+December 2017 
+For the Year Ended December 31, 
+Company/Market/Peer Group 
+2012 
+2013 
+2014 
+2015 
+2016 
+2017 
+Callon Petroleum Company 
+$ 
+100.00 
+$ 
+138.94 
+$ 
+115.96 
+$ 
+177.45 
+$ 
+327.02 
+$ 
+258.51 
+S&P 500 Index - Total Returns 
+100.00 
+132.39 
+150.51 
+152.59 
+170.84 
+208.14 
+DJ US Select O&G E&P 
+100.00 
+131.24 
+115.57 
+87.27 
+109.82 
+110.58 
+SIG Oil Exploration & Production Index 
+100.00 
+128.46 
+91.28 
+48.44 
+62.74 
+62.74 
+໿ 
+37 
+Table of Contents 
+ITEM 6. Selected Financial Data 
+The following table sets forth, as of the dates and for the periods indicated, selected financial information about the Company. The financial information for each of the five years in the period ended December 31, 2017 has been derived from our audited Consolidated Financial Statements for such periods. The information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and Notes thereto. The following information is not necessarily indicative of our future results (dollars in thousands, except per share amounts). 
+໿ 
+For the Year Ended December 31, 
+2017 
+2016 
+2015 
+2014 
+2013 
+Statement of Operations Data 
+Operating revenues 
+Oil and natural gas sales 
+$ 
+366,474 
+$ 
+200,851 
+$ 
+137,512 
+$ 
+151,862 
+$ 
+102,569 
+Operating expenses 
+Total operating expenses 
+$ 
+225,028 
+$ 
+248,328 
+$ 
+346,622 
+$ 
+113,592 
+$ 
+91,905 
+Income (loss) from operations 
+141,446 
+(47,477 
+) 
+(209,110 
+) 
+38,270 
+10,664 
+Net income (loss) (a) 
+120,424 
+(91,813 
+) 
+(240,139 
+) 
+37,766 
+4,304 
+Income (loss) per share ("EPS") 
+Basic 
+$ 
+0.56 
+$ 
+(0.78 
+) 
+$ 
+(3.77 
+) 
+$ 
+0.67 
+$ 
+(0.01 
+) 
+Diluted 
+$ 
+0.56 
+$ 
+(0.78 
+) 
+$ 
+(3.77 
+) 
+$ 
+0.65 
+$ 
+(0.01 
+) 
+Weighted average shares outstanding for Basic EPS 
+201,526 
+126,258 
+65,708 
+44,848 
+40,133 
+Weighted average shares outstanding for Diluted EPS 
+202,102 
+126,258 
+65,708 
+45,961 
+40,133 
+Statement of Cash Flows Data 
+Net cash provided by operating activities 
+$ 
+229,891 
+$ 
+120,774 
+$ 
+89,319 
+$ 
+94,387 
+$ 
+54,475 
+Net cash used in investing activities 
+(1,072,532 
+) 
+(866,287 
+) 
+(259,160 
+) 
+(452,501 
+) 
+(79,804 
+) 
+Net cash provided by (used in) financing activities 
+217,643 
+1,397,282 
+170,097 
+356,070 
+27,202 
+Balance Sheet Data 
+Total oil and natural gas properties 
+$ 
+2,513,491 
+$ 
+1,475,401 
+$ 
+711,386 
+$ 
+742,155 
+$ 
+324,187 
+Total assets 
+2,693,296 
+2,267,587 
+788,594 
+863,346 
+423,953 
+Long-term debt (b) 
+620,196 
+390,219 
+328,565 
+321,576 
+75,748 
+Stockholders' equity 
+1,855,966 
+1,733,402 
+362,758 
+433,735 
+279,094 
+Proved Reserves Data 
+Total oil (MBbls) 
+107,072 
+71,145 
+43,348 
+25,733 
+11,898 
+Total natural gas (MMcf) 
+179,410 
+122,611 
+65,537 
+42,548 
+17,751 
+Total (MBOE) 
+136,974 
+91,580 
+54,271 
+32,824 
+14,857 
+Standardized measure (c) 
+$ 
+1,556,682 
+$ 
+809,832 
+$ 
+570,890 
+$ 
+579,542 
+$ 
+283,946 
+(a) 
+Net loss for 2015 included the recognition of a write-down of oil and natural gas properties of $208,435 as a result of the ceiling test limitation and $108,843 of income tax expense related to the recognition of a valuation allowance. Net loss for 2016 included the recognition of a write-down of oil and natural gas properties of $95,788 as a result of the ceiling test limitation. See Notes 11 and 13 in the Footnotes to the Financial Statements for additional information. 
+(b) 
+See Note 5 in the Footnotes to the Financial Statements for additional information. 
+(c) 
+Standardized measure is the future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet. Prices are based on either the preceding 12-months’ average price, based on closing prices on the first day of each month, or prices defined by existing contractual arrangements. Future production and development costs are based on current estimates with no escalations. Estimated future cash flows have been discounted to their present values based on a 10% discount rate. See Note 13 in the Footnotes to the Financial Statements for additional information. 
+38 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+General 
+The following management’s discussion and analysis describes the principal factors affecting the Company’s results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying audited consolidated financial statements, information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results, which are included in various parts of this filing. Our website address is www.callon.com . All of our filings with the SEC are available free of charge through our website as soon as reasonably practicable after we file them with, or furnish them to, the SEC. Information on our website does not form part of this report on Form 10-K. 
+We are an independent oil and natural gas company established in 1950. We are focused on the acquisition, development, exploration and exploitation of unconventional, onshore, oil and natural gas reserves in the Permian Basin. The Permian Basin is located in West Texas and southeastern New Mexico and is comprised of three primary sub-basins: the Midland Basin, the Delaware Basin, and the Central Basin Platform. We have historically been focused on the Midland Basin and more recently entered the Delaware Basin through an acquisition completed in February 2017. Our operating culture is centered on responsible development of hydrocarbon resources, safety and the environment, which we believe strengthens our operational performance. Our drilling activity is predominantly focused on the horizontal development of several prospective intervals, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales. We have assembled a multi-year inventory of potential horizontal well locations and intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps. Our production was approximately 78% oil and 22% natural gas for the year ended December 31, 2017 . On December 31, 2017 , our net acreage position in the Permian Basin was 57,481 net acres. 
+Significant accomplishments for 2017 include: 
+• 
+Increased annual production in 2017 by 50% to 8,373 MBOE as compared to 2016; 
+• 
+Increased 2017 proved reserves by 50% to 137 MMBOE as compared to 2016; 
+• 
+Entered the Delaware Basin through an acquisition completed in February 2017, acquiring approximately 29,175 gross ( 16,688 net) acres; 
+• 
+In 2017, we transitioned from a two rig to a four rig horizontal drilling program. 
+• 
+Issued an additional $200 million aggregate principal amount of its 6.125% Senior Notes; and 
+• 
+Amended the borrowing base under our Credit Facility to $700 million with a current elected commitment level of $500 million , providing us with additional liquidity. 
+Operational Highlights 
+All of our producing properties are located in the Permian Basin. As a result of our acquisition and horizontal development efforts, our production grew 50% in 2017 compared to 2016 , increasing to 8,373 MBOE from 5,573 MBOE. Our production in 2017 was approximately 78% oil and 22% natural gas. 
+In 2017 , we transitioned from a two rig to four rig horizontal drilling program. For the year ended December 31, 2017 , we drilled 49 gross ( 38.2 net) horizontal wells, completed 52 gross ( 41.4 net) horizontal wells and had four gross ( 2.0 net) horizontal wells awaiting completion. 
+Reserve Growth 
+As of December 31, 2017 , our estimated net proved reserves increased 50% to 137.0 MMBOE compared to 91.6 MMBOE of estimated net proved reserves at year-end 2016 . Our significant growth in proved reserves was primarily attributable to our horizontal development and acquisition efforts. Our proved reserves at year-end 2017 and 2016 were 78% oil and 22% natural gas for both periods. 
+Liquidity and Capital Resources 
+Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions, the sale of debt and equity securities, and asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration and exploitation of oil and natural gas properties, in addition to refinancing of debt instruments. 
+39 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+In 2017 , we issued an additional $200 million aggregate principal amount of our 6.125% Senior Notes to raise additional capital. In addition, we amended the borrowing base under our Credit Facility to $700 million with a current elected commitment level of $500 million , providing us with additional liquidity. We continue to evaluate other sources of capital to complement our cash flow from operations and other sources of capital as we pursue our long-term growth plans. See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s debt. 
+For the year ended December 31, 2017 , cash and cash equivalents decreased $625.0 million to $28.0 million compared to $653.0 million at December 31, 2016 . 
+Liquidity and cash flow 
+Twelve Months Ended December 31, 
+(in thousands) 
+2017 
+2016 
+2015 
+Net cash provided by operating activities 
+$ 
+229,891 
+$ 
+120,774 
+$ 
+89,319 
+Net cash used in investing activities 
+(1,072,532 
+) 
+(866,287 
+) 
+(259,160 
+) 
+Net cash provided by financing activities 
+217,643 
+1,397,282 
+170,097 
+Net change in cash and cash equivalents 
+$ 
+(624,998 
+) 
+$ 
+651,769 
+$ 
+256 
+Operating activities. For the year ended December 31, 2017 , net cash provided by operating activities was $229.9 million , compared to $120.8 million for the same period in 2016 . The change in operating activities was predominantly attributable to the following: 
+• 
+An increase in revenue; 
+• 
+A decrease in settlements of derivative contracts; 
+• 
+An increase in certain operating expenses related to acquired properties; 
+• 
+An increase in payments in cash-settled restricted stock unit (“RSU”) awards; and 
+• 
+A change related to the timing of working capital payments and receipts. 
+Production, realized prices, and operating expenses are discussed below in Results of Operations. See Notes 6 and 7 in the Footnotes to the Financial Statements for a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation. See Note 3 in the Footnotes to the Financial Statements for more information on the Company’s acquisitions. 
+Investing activities . For the year ended December 31, 2017 , net cash used in investing activities was $1,072.5 million compared to $866.3 million for the same period in 2016 . The change in investing activities was primarily attributable to the following: 
+• 
+A $229.8 million increase in operational expenditures primarily due to our transition from a one-rig program in 2016 to a four-rig program in 2017. In August 2016, we transitioned from a one-rig program to a two-rig program. We transitioned from a two-rig program to a three-rig program in January 2017 and from a three-rig program to a four-rig program in July 2017; and 
+• 
+A $23.6 million decrease in acquisitions, net of proceeds from the sale of mineral interest and equipment. 
+Our investing activities, on a cash basis, include the following for the periods indicated (in thousands): 
+໿ 
+Twelve Months Ended December 31, 
+2017 
+2016 
+$ Change 
+Operational expenditures 
+$ 
+355,833 
+$ 
+143,856 
+$ 
+211,977 
+Seismic, leasehold and other 
+16,385 
+13,640 
+2,745 
+Capitalized general and administrative costs 
+17,016 
+12,679 
+4,337 
+Capitalized interest 
+30,605 
+19,857 
+10,748 
+Total capital expenditures (a) 
+419,839 
+190,032 
+$ 
+229,807 
+Acquisitions 
+718,456 
+654,679 
+63,777 
+Acquisition deposits 
+(45,238 
+) 
+46,138 
+(91,376 
+) 
+Proceeds from the sale of mineral interest and equipment 
+(20,525 
+) 
+(24,562 
+) 
+4,037 
+Total investing activities 
+$ 
+1,072,532 
+$ 
+866,287 
+$ 
+206,245 
+(a) 
+On an accrual (GAAP) basis, which is the methodology used for establishing our annual capital budget, operational expenditures for the year ended December 31, 2017 were $392.7 million . Inclusive of capitalized general and administrative expenses and capitalized interest expenses, total capital expenditures were $463.2 million . 
+40 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+General and administrative expenses and capitalized interest are discussed below in Results of Operations. See Notes 3 and 14 in the Footnotes to the Financial Statements for additional information on significant acquisitions and drilling rig leases. 
+Financing activities. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under our Credit Facility, term debt and equity offerings. For the year ended December 31, 2017 , net cash provided by financing activities was $217.6 million compared to cash provided by financing activities of $1,397.3 million during the same period of 2016 . The change in net cash provided by financing activities was primarily attributable to the following: 
+• 
+A decrease in proceeds resulting from common stock offerings. In 2016, we raised $1,357.6 million through four common stock offerings as compared no common stock offerings in 2017; and 
+• 
+A $188.2 million decrease in borrowings on fixed rate debt. In 2016, we issued a $400 million aggregate principal amount of 6.125% Senior Notes, and in 2017, we issued an additional $200 million aggregate principal amount, including a premium issue price of 104.125%, of the 6.125% Senior Notes. 
+Net cash provided by financing activities includes the following for the periods indicated (in thousands): 
+໿ 
+ 
+Twelve Months Ended December 31, 
+ 
+2017 
+2016 
+$ Change 
+Net borrowings on Credit Facility 
+$ 
+25,000 
+$ 
+(40,000 
+) 
+$ 
+65,000 
+Net borrowings on term loans 
+— 
+(300,000 
+) 
+Issuance of 6.125% Senior Notes 
+200,000 
+400,000 
+(200,000 
+) 
+Premium on the issuance of 6.125% Senior Notes 
+8,250 
+— 
+8,250 
+Issuance of common stock 
+— 
+1,357,577 
+(1,357,577 
+) 
+Payment of preferred stock dividends 
+(7,295 
+) 
+(7,295 
+) 
+— 
+Payment of deferred financing costs 
+(7,194 
+) 
+(10,793 
+) 
+3,599 
+Tax withholdings related to restricted stock units 
+(1,118 
+) 
+(2,207 
+) 
+1,089 
+Net cash provided by financing activities 
+$ 
+217,643 
+$ 
+1,397,282 
+$ 
+(1,179,639 
+) 
+See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s debt. See Note 10 in the Footnotes to the Financial Statements for additional information about the Company’s equity offerings and Series A 10% Cumulative Preferred Stock. 
+Credit Facility 
+On May 31, 2017, the Company entered into the Sixth Amended and Restated Credit Agreement to the Credit Facility with a maturity date of May 25, 2022 . The total notional amount available under the Company’s Credit Facility is $2,000 million . Concurrent with the execution of the Sixth Amended and Restated Credit Agreement, the Credit Facility’s borrowing base increased to $650 million , but the Company elected an aggregate commitment amount of $500 million . On November 7, 2017, the Credit Facility’s borrowing base increased to $700 million with a reaffirmed commitment of $500 million , following the semi-annual review. As of December 31, 2017 , the Credit Facility had a balance of $25 million outstanding. 
+For the year ended December 31, 2017 , the Credit Facility had a weighted-average interest rate of 3.11% , calculated as the LIBOR plus a tiered rate ranging from 2.00% to 3.00% , which is determined based on utilization of the facility. In addition, the Credit Facility carries a commitment fee of 0.375% per annum, payable quarterly, on the unused portion of the borrowing base. 
+See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s Credit Facility. 
+6.125% Senior Notes 
+On October 3, 2016, the Company issued $400 million aggregate principal amount of 6.125% Senior Notes with a maturity date of October 1, 2024 and interest payable semi-annually beginning on April 1, 2017 . The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $391.3 million . The 6.125% Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. 
+On May 19, 2017, the Company issued an additional $200 million aggregate principal amount of its 6.125% Senior Notes which with the existing $400 million aggregate principal amount of 6.125% Senior Notes are treated as a single class of notes under the indenture. 
+41 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+The net proceeds of the offering, including a premium issue price of 104.125% and after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $206.1 million . 
+See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s 6.125% Senior Notes. 
+10% Series A Cumulative Preferred Stock (“Preferred Stock”) 
+Holders of the Company’s Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10.0% per annum of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share). Dividends are payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by our Board of Directors. Preferred Stock dividends were $7.3 million in 2017 . 
+The Preferred Stock has no stated maturity and is not subject to any sinking fund or other mandatory redemption. On or after May 30, 2018, the Company may, at its option, redeem the Preferred Stock, in whole or in part, by paying $50.00 per share, plus any accrued and unpaid dividends to the redemption date. 
+On February 4, 2016, the Company exchanged a total of 120,000 shares of Preferred Stock for 719,000 shares of common stock. As of December 31, 2017 , the Company had 1,458,948 shares of its Preferred Stock issued and outstanding. 
+See Note 10 in the Footnotes to the Financial Statements for additional information about the Company’s Preferred Stock. 
+2018 Capital Plan and Outlook 
+Our operational capital budget for 2018 has been established in the range of $500 to $540 million on an accrual, or GAAP, basis, inclusive of a planned transition from a four rig program that commenced in July 2017 to a five rig program by mid-February 2018. 
+As part of our 2018 operated horizontal drilling program, we expect to place 43 to 46 net horizontal wells on production with lateral lengths ranging from 5,000’ to 10,000’. 
+໿ 
+In addition to the operational capital expenditures budget, which includes well costs, facilities and infrastructure capital, and surface land purchases, we budgeted an estimated $23 to $28 million for capitalized general and administrative expenses on an accrual, or GAAP, basis. 
+Our revenues, earnings, liquidity and ability to grow are substantially dependent on the prices we receive for, and our ability to develop our reserves of oil and natural gas. We believe the long-term outlook for our business is favorable due to our resource base, low cost structure, financial strength, risk management, including commodity hedging strategy, and disciplined investment of capital. We monitor current and expected market conditions, including the commodity price environment, and our liquidity needs and may adjust our capital investment plan accordingly. 
+Contractual Obligations 
+The following table includes the Company’s current contractual obligations and purchase commitments (in thousands): 
+໿ 
+ 
+Payments due by Period 
+ 
+Total 
+< 1 Year 
+Years 2 - 3 
+Years 4 - 5 
+>5 Years 
+6.125% Senior Notes (a) 
+$ 
+600,000 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+600,000 
+Credit Facility (b) 
+25,000 
+— 
+— 
+25,000 
+— 
+Interest expense and other fees related to debt commitments (c) 
+262,192 
+39,958 
+79,915 
+78,006 
+64,313 
+Drilling rig leases (d) 
+61,732 
+29,482 
+31,602 
+648 
+— 
+Office space lease and other commitments 
+14,858 
+3,935 
+7,543 
+3,380 
+— 
+Asset retirement obligations (e) 
+6,020 
+1,295 
+— 
+— 
+4,725 
+Total contractual obligations 
+$ 
+969,802 
+$ 
+74,670 
+$ 
+119,060 
+$ 
+107,034 
+$ 
+669,038 
+(a) 
+Includes the outstanding principal amount only. The 6.125% Senior Notes have a maturity date of October 1, 2024 . See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s 6.125% Senior Notes. 
+(b) 
+As of December 31, 2017 , the Credit Facility had a $25 million balance outstanding. We cannot predict the timing of future borrowings and repayments. The Credit Facility has a maturity date of May 25, 2022 . See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s Credit Facility. 
+42 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+(c) 
+Includes estimated cash payments on the 6.125% Senior Notes and Credit Facility and the minimum amount of commitment fees due on the Credit Facility . 
+(d) 
+Drilling rig leases represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a party on December 31, 2017 . The value in the table represents the gross amount that we are committed to pay. However, we will record our proportionate share based on our working interest in our consolidated financial statements as incurred. See Note 14 in the Footnotes to the Financial Statements for additional information related to the Company’s drilling rig leases. 
+(e) 
+Amounts represent our estimates of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note 12 in the Footnotes to the Financial Statements for additional information. 
+43 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Results of Operations 
+The following table sets forth certain operating information with respect to the Company’s oil and natural gas operations for the periods indicated: ໿ 
+Twelve Months Ended December 31, 
+2017 
+2016 
+Change 
+% Change 
+2015 
+Change 
+% Change 
+Net production: 
+Oil (MBbls) 
+6,557 
+4,280 
+2,277 
+53 
+% 
+2,789 
+1,491 
+53 
+% 
+Natural gas (MMcf) 
+10,896 
+7,758 
+3,138 
+40 
+% 
+4,312 
+3,446 
+80 
+% 
+Total (MBOE) 
+8,373 
+5,573 
+2,800 
+50 
+% 
+3,508 
+2,065 
+59 
+% 
+Average daily production (BOE/d) 
+22,940 
+15,227 
+7,713 
+50 
+% 
+9,610 
+(9,595 
+) 
+(100 
+)% 
+% oil (BOE basis) 
+78 
+% 
+77 
+% 
+80 
+% 
+Average realized sales price 
+(excluding impact of cash settled derivatives) : 
+Oil (Bbl) 
+$ 
+49.16 
+$ 
+41.51 
+$ 
+7.65 
+18 
+% 
+$ 
+44.88 
+$ 
+(3.37 
+) 
+(8 
+)% 
+Natural gas (Mcf) 
+4.05 
+2.99 
+1.06 
+35 
+% 
+2.86 
+0.13 
+5 
+% 
+Total (BOE) 
+$ 
+43.77 
+$ 
+36.04 
+$ 
+7.73 
+21 
+% 
+$ 
+39.20 
+$ 
+(3.16 
+) 
+(8 
+)% 
+Average realized sales price 
+(including impact of cash settled derivatives) : 
+Oil (Bbl) 
+$ 
+47.78 
+$ 
+45.67 
+$ 
+2.11 
+5 
+% 
+$ 
+56.82 
+$ 
+(11.15 
+) 
+(20 
+)% 
+Natural gas (Mcf) 
+4.10 
+3.00 
+1.10 
+37 
+% 
+3.26 
+(0.26 
+) 
+(8 
+)% 
+Total (BOE) 
+$ 
+42.76 
+$ 
+39.25 
+$ 
+3.51 
+9 
+% 
+$ 
+49.18 
+$ 
+(9.93 
+) 
+(20 
+)% 
+Oil and natural gas revenues 
+(in thousands) : 
+Oil revenue 
+$ 
+322,374 
+$ 
+177,652 
+$ 
+144,722 
+81 
+% 
+$ 
+125,166 
+$ 
+52,486 
+42 
+% 
+Natural gas revenue 
+44,100 
+23,199 
+20,901 
+90 
+% 
+12,346 
+$ 
+10,853 
+88 
+% 
+Total 
+$ 
+366,474 
+$ 
+200,851 
+$ 
+165,623 
+82 
+% 
+$ 
+137,512 
+$ 
+63,339 
+46 
+% 
+Additional per BOE data: 
+Sales price (a) 
+$ 
+43.77 
+$ 
+36.04 
+$ 
+7.73 
+21 
+% 
+$ 
+39.20 
+$ 
+(3.16 
+) 
+(8 
+)% 
+Lease operating expense (b) 
+5.46 
+6.56 
+(1.10 
+) 
+(17 
+)% 
+7.48 
+(0.92 
+) 
+(12 
+)% 
+Gathering and treating expense 
+0.50 
+0.32 
+0.18 
+56 
+% 
+0.23 
+0.09 
+39 
+% 
+Production taxes 
+2.67 
+2.13 
+0.54 
+25 
+% 
+2.79 
+(0.66 
+) 
+(24 
+)% 
+Operating margin 
+$ 
+35.14 
+$ 
+27.03 
+$ 
+8.11 
+30 
+% 
+$ 
+28.70 
+$ 
+(1.67 
+) 
+(6 
+)% 
+(a) 
+Excludes the impact of cash settled derivatives. 
+(b) 
+Excludes gathering and treating expense. 
+Revenues 
+The following tables are intended to reconcile the change in oil, natural gas and total revenue for the respective periods presented by reflecting the effect of changes in volume and in the underlying commodity prices. 
+(in thousands) 
+Oil 
+Natural Gas 
+Total 
+Revenues for the year ended December 31, 2014 
+$ 
+139,374 
+$ 
+12,488 
+$ 
+151,862 
+Volume increase 
+90,398 
+11,774 
+102,172 
+Price decrease 
+(104,606 
+) 
+(11,916 
+) 
+(116,522 
+) 
+Net decrease 
+(14,208 
+) 
+(142 
+) 
+(14,350 
+) 
+Revenues for the year ended December 31, 2015 
+$ 
+125,166 
+$ 
+12,346 
+$ 
+137,512 
+Volume increase 
+66,916 
+9,856 
+76,772 
+Price increase (decrease) 
+(14,430 
+) 
+997 
+(13,433 
+) 
+Net increase 
+52,486 
+10,853 
+63,339 
+Revenues for the year ended December 31, 2016 
+$ 
+177,652 
+$ 
+23,199 
+$ 
+200,851 
+Volume increase 
+94,518 
+9,383 
+103,901 
+Price increase 
+50,204 
+11,518 
+61,722 
+Net increase 
+144,722 
+20,901 
+165,623 
+Revenues for the year ended December 31, 2017 
+$ 
+322,374 
+$ 
+44,100 
+$ 
+366,474 
+44 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Commodity Prices 
+The prices for oil and natural gas remain extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and actions by OPEC and other countries and government actions. Prices of oil and natural gas will affect the following aspects of our business: 
+• 
+our revenues, cash flows and earnings; 
+• 
+the amount of oil and natural gas that we are economically able to produce; 
+• 
+our ability to attract capital to finance our operations and cost of the capital; 
+• 
+the amount we are allowed to borrow under our Credit Facility; and 
+• 
+the value of our oil and natural gas properties. 
+For the year ended December 31, 2017 , the average NYMEX price for a barrel of oil was $50.80 per Bbl compared to $43.39 per Bbl for the same period of 2016 . The NYMEX price for a barrel of oil ranged from a low of $42.53 per Bbl to a high of $60.42 per Bbl for the year ended December 31, 2017 . 
+For the year ended December 31, 2017 , the average NYMEX price for natural gas was $3.02 per MMBtu compared to $2.55 per MMBtu for the same period in 2016 . The NYMEX price for natural gas ranged from a low of $2.56 per MMBtu to a high of $3.42 per MMBtu for the year ended December 31, 2017 . 
+Oil revenue 
+For the year ended December 31, 2017 , oil revenues of $322 million increased $145 million , or 81% , compared to revenues of $178 million for the year ended December 31, 2016 . The increase in oil revenue was primarily attributable to a 53% increase in production and an 18% increase in the average realized sales price, which rose to $49.16 per Bbl from $41.51 per Bbl. The increase in production was comprised of 2,125 MBbls attributable to wells placed on production as a result of our horizontal drilling program and 1,191 MBbls attributable to producing wells added from our acquired properties. Offsetting these increases were normal and expected declines from our existing wells. 
+For the year ended December 31, 2016, oil revenues of $178 million increased $52.5 million, or 42%, compared to revenues of $125 million for the same period of 2015. The increase in oil revenue was primarily attributable to a 53% increase in production offset by an 8% decrease in the average realized sales price, which fell to $41.51 per Bbl from $44.88 per Bbl. The increase in production was comprised of 1,182 MBbls attributable to wells placed on production as a result of our horizontal drilling program and 547 MBbls attributable to producing wells added from our acquired properties. Offsetting these increases were normal and expected declines from our existing wells. 
+Natural gas revenue (including NGLs) 
+Natural gas revenues of $44.1 million increased $20.9 million , or 90% , during the year ended December 31, 2017 compared to $23.2 million for the year ended December 31, 2016 . The increase primarily relates to a 40% increase in natural gas volumes and a 35% increase in the average price realized, which rose to $4.05 per Mcf from $2.99 per Mcf, reflecting increases in both natural gas and natural gas liquids prices. The increase in production was comprised of 1,969 MMcf attributable to wells placed on production as a result of our horizontal drilling program and 1,375 MMcf attributable to producing wells added from our acquired properties . Offsetting these increases were normal and expected declines from our existing wells. 
+Natural gas revenues of $23.2 million increased $10.9 million, or 88%, during the year ended December 31, 2016 compared to $12.3 million for the same period of 2015. The increase primarily relates to an 80% increase in natural gas volumes and a 5% increase in the average price realized, which rose to $2.99 per Mcf from $2.86 per Mcf, reflecting increases in both natural gas and natural gas liquids prices. The increase in production was comprised of 1,387 MMcf attributable to wells placed on production as a result of our horizontal drilling program and 1,025 MMcf attributable to producing wells added from our acquired properties. In addition, the increase in production was also attributable to the increase in the percentage of natural gas produced in our production stream. 
+45 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Operating Expenses 
+໿ 
+Twelve Months Ended December 31, 
+Per 
+Per 
+Total Change 
+BOE Change 
+(in thousands, except per unit amounts) 
+2017 
+BOE 
+2016 
+BOE 
+$ 
+% 
+$ 
+% 
+Lease operating expenses 
+$ 
+49,907 
+$ 
+5.96 
+$ 
+38,353 
+$ 
+6.88 
+$ 
+11,554 
+30 
+% 
+$ 
+(0.92 
+) 
+(13 
+)% 
+Production taxes 
+22,396 
+$ 
+2.67 
+11,870 
+$ 
+2.13 
+10,526 
+89 
+% 
+0.54 
+25 
+% 
+Depreciation, depletion and amortization 
+115,714 
+$ 
+13.82 
+71,369 
+$ 
+12.81 
+44,345 
+62 
+% 
+1.01 
+8 
+% 
+General and administrative 
+27,067 
+$ 
+3.23 
+26,317 
+$ 
+4.72 
+750 
+3 
+% 
+(1.49 
+) 
+(32 
+)% 
+Settled share-based awards 
+6,351 
+nm 
+— 
+nm 
+6,351 
+nm 
+nm 
+nm 
+Accretion expense 
+677 
+$ 
+0.08 
+958 
+$ 
+0.17 
+(281 
+) 
+(29 
+)% 
+(0.09 
+) 
+(53 
+)% 
+Write-down of oil and natural gas properties 
+— 
+nm 
+95,788 
+nm 
+(95,788 
+) 
+nm 
+nm 
+nm 
+Acquisition expense 
+2,916 
+nm 
+3,673 
+nm 
+(757 
+) 
+nm 
+nm 
+nm 
+໿ 
+Twelve Months Ended December 31, 
+Per 
+Per 
+Total Change 
+BOE Change 
+(in thousands, except per unit amounts) 
+2016 
+BOE 
+2015 
+BOE 
+$ 
+% 
+$ 
+% 
+Lease operating expenses 
+$ 
+38,353 
+$ 
+6.88 
+$ 
+27,036 
+$ 
+7.71 
+$ 
+11,317 
+42 
+% 
+$ 
+(0.83 
+) 
+(11 
+)% 
+Production taxes 
+11,870 
+$ 
+2.13 
+9,793 
+$ 
+2.79 
+2,077 
+21 
+% 
+(0.66 
+) 
+(24 
+)% 
+Depreciation, depletion and amortization 
+71,369 
+$ 
+12.81 
+69,249 
+$ 
+19.74 
+2,120 
+3 
+% 
+(6.93 
+) 
+(35 
+)% 
+General and administrative 
+26,317 
+$ 
+4.72 
+28,347 
+$ 
+8.08 
+(2,030 
+) 
+(7 
+)% 
+(3.36 
+) 
+(42 
+)% 
+Accretion expense 
+958 
+$ 
+0.17 
+660 
+$ 
+0.19 
+298 
+45 
+% 
+(0.02 
+) 
+(11 
+)% 
+Write-down of oil and natural gas properties 
+95,788 
+nm 
+208,435 
+nm 
+(112,647 
+) 
+nm 
+nm 
+nm 
+Rig termination fee 
+— 
+nm 
+3,075 
+nm 
+(3,075 
+) 
+nm 
+nm 
+nm 
+Acquisition expense 
+3,673 
+nm 
+27 
+nm 
+3,646 
+nm 
+nm 
+nm 
+nm = not meaningful 
+Lease operating expenses. These are daily costs incurred to extract oil and natural gas and maintain our producing properties. Such costs also include maintenance, repairs, gas treating fees, salt water disposal, insurance and workover expenses related to our oil and natural gas properties. 
+LOE for the year ended December 31, 2017 increased by 30% to $49.9 million compared to $38.4 million for the same period of 2016 . Contributing to the increase was $11.0 million related to oil and natural gas properties acquired during 2016 and 2017 (see Note 3 in the Footnotes to the Financial Statements for information about the Company’s acquisitions) . LOE per BOE for the year ended December 31, 2017 decreased to $5.96 per BOE compared to $6.88 per BOE for the same period of 2016 , which was primarily attributable to higher production volumes resulting from an increased number of producing wells from our horizontal drilling program and acquisitions as discussed above. 
+LOE for the year ended December 31, 2016 increased by 42% to $38.4 million compared to $27.0 million for the same period of 2015. Contributing to the increase for the current period was $7.3 million related to oil and natural gas properties acquired during 2016 (see Note 3 in the Footnotes to the Financial Statements for information about the Company’s acquisitions). Excluding LOE related to these acquired properties, LOE increased by $4.0 million, or 15%, compared to the same period of 2015. LOE per BOE for the year ended December 31, 2016 decreased to $6.88 per BOE compared to $7.71 per BOE for the same period of 2015, which was primarily attributable to higher production volumes offset by an increase in cost from workover activity on our legacy properties. The increase in production was primarily attributable to an increased number of producing wells from our horizontal drilling program and acquisitions as discussed above. 
+Production taxes. Production taxes include severance and ad valorem taxes. In general, production taxes are directly related to commodity price changes; however, severance taxes are based upon current year commodity prices, whereas ad valorem taxes are based upon prior year commodity prices. Severance taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. In the counties where our production is located, we are also subject to ad valorem taxes, which are generally based on the taxing jurisdictions’ valuation of our oil and gas properties. 
+For the year ended December 31, 2017 , production taxes increased 89% , or $10.5 million , to $22.4 million compared to $11.9 million for the same period of 2016 . The increase was primarily due to an increase in severance taxes, which was attributable to the increase in revenue. The increase was also attributable to an increase in ad valorem taxes due to a higher valuation of our oil and gas properties by 
+46 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+the taxing jurisdictions due to an increased number of producing wells as a result of our horizontal drilling program and acquisitions. On a per BOE basis, production taxes for the year ended December 31, 2017 increased by 25% compared to the same period of 2016 . 
+For the year ended December 31, 2016, production taxes increased 21%, or $2.1 million, to $11.9 million compared to $9.8 million for the same period of 2015. The increase was primarily due to an increase in severance taxes, which was attributable to the increase in revenue. The increase was offset by a decrease in ad valorem taxes attributable to a lower valuation of our oil and gas properties by the taxing jurisdictions. On a per BOE basis, production taxes for the year ended December 31, 2016 decreased by 24% compared to the same period of 2015. 
+Depreciation, depletion and amortization (“DD&A”). Under the full cost accounting method, we capitalize costs within a cost center and then systematically expense those costs on a units-of-production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unevaluated properties, less accumulated amortization; (ii) the estimated future expenditures to be incurred in developing proved reserves; and (iii) the estimated dismantlement and abandonment costs, net of estimated salvage values. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years. 
+For the year ended December 31, 2017 , DD&A increased 62% to $115.7 million from $71.4 million compared to the same period of 2016 . The increase is primarily attributable to a 50% increase in production and an 8% increase in our per BOE DD&A rate. The increase in production was primarily attributable to an increased number of producing wells from our horizontal drilling program and acquisitions. For the year ended December 31, 2017 , DD&A on a per unit basis increased to $13.82 per BOE compared to $12.81 per BOE for the same period of 2016 . The increase is attributable to our increase in our depreciable base and assumed future development costs related to undeveloped proved reserves relative to our increased estimated proved reserves as a result of additions made through our horizontal drilling efforts and acquisitions. 
+For the year ended December 31, 2016, DD&A increased 3% to $71.4 million from $69.2 million compared to the same period of 2015. The increase is primarily attributable to a 59% increase in production, offset by a 35% decrease in our per BOE DD&A rate. The increase in production was primarily attributable to an increased number of producing wells from our horizontal drilling program and acquisitions. For the year ended December 31, 2016, DD&A on a per unit basis decreased to $12.81 per BOE compared to $19.74 per BOE for the same period of 2015. The decrease is attributable to our increased estimated proved reserves relative to our depreciable base and assumed future development costs related to undeveloped proved reserves as a result of additions made through our horizontal drilling efforts and acquisitions, offset by the write-down of oil and natural gas properties in the first half of 2016. 
+General and administrative, net of amounts capitalized (“G&A”). These are costs incurred for overhead, including payroll and benefits for our corporate staff, severance and early retirement expenses, costs of maintaining offices, managing our production and development operations, franchise taxes, depreciation of corporate level assets, public company costs, vesting of equity and liability awards under share-based compensation plans and related mark-to-market valuation adjustments over time, fees for audit and other professional services, and legal compliance. 
+G&A for the year ended December 31, 2017 increased to $27.1 million compared to $26.3 million for the same period of 2016 . G&A expenses for the periods indicated include the following (in thousands): 
+Twelve Months Ended December 31, 
+2017 
+2016 
+$ Change 
+% Change 
+Recurring expenses 
+G&A 
+$ 
+21,554 
+$ 
+16,477 
+$ 
+5,077 
+31 
+% 
+Share-based compensation 
+4,287 
+2,735 
+1,552 
+57 
+% 
+Fair value adjustments of cash-settled RSU awards 
+701 
+6,881 
+(6,180 
+) 
+(90 
+)% 
+Non-recurring expenses 
+Early retirement expenses 
+444 
+— 
+444 
+100 
+% 
+Early retirement expenses related to share-based compensation 
+81 
+— 
+81 
+100 
+% 
+Expense related to a threatened proxy contest 
+— 
+224 
+(224 
+) 
+(100 
+)% 
+Total G&A expenses 
+$ 
+27,067 
+$ 
+26,317 
+$ 
+750 
+3 
+% 
+47 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+G&A for the year ended December 31, 2016 decreased to $26.3 million compared to $28.3 million for the same period of 2015. G&A expenses for the periods indicated include the following (in thousands): 
+Twelve Months Ended December 31, 
+2016 
+2015 
+$ Change 
+% Change 
+Recurring expenses 
+G&A 
+$ 
+16,477 
+$ 
+15,086 
+$ 
+1,391 
+9 
+% 
+Share-based compensation 
+2,735 
+2,068 
+667 
+32 
+% 
+Fair value adjustments of cash-settled RSU awards 
+6,881 
+6,084 
+797 
+13 
+% 
+Non-recurring expenses 
+Early retirement expenses 
+— 
+3,553 
+(3,553 
+) 
+(100 
+)% 
+Early retirement expenses related to share-based compensation 
+— 
+1,115 
+(1,115 
+) 
+(100 
+)% 
+Expense related to a threatened proxy contest 
+224 
+441 
+(217 
+) 
+(49 
+)% 
+Total G&A expenses 
+$ 
+26,317 
+$ 
+28,347 
+$ 
+(2,030 
+) 
+(7 
+)% 
+Settled share-based awards . In June 2017, the Company settled the outstanding share-based award agreements of its former Chief Executive Officer, resulting in $6.4 million recorded on the Consolidated Statements of Operations as Settled share-based awards. 
+Accretion expense. The Company is required to record the estimated fair value of liabilities for obligations associated with the retirement of tangible long-lived assets and the associated ARO costs. Interest is accreted on the present value of the ARO and reported as accretion expense within operating expenses in the Consolidated Statements of Operations. 
+Accretion expense related to our ARO decreased 29% for the year ended December 31, 2017 compared to the same period of 2016 . Accretion expense generally correlates with the Company’s ARO, which was $6.0 million at December 31, 2017 versus $6.7 million at December 31, 2016 . See Note 12 in the Footnotes to the Financial Statements for additional information regarding the Company’s ARO. 
+Accretion expense related to our ARO increased 45% for the year ended December 31, 2016 compared to the same period of 2015. Accretion expense generally correlates with the Company’s ARO, which was $6.7 million at December 31, 2016 versus $5.1 million at December 31, 2015 . See Note 12 in the Footnotes to the Financial Statements for additional information regarding the Company’s ARO. 
+Write-down of oil and natural gas properties. Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full cost ceiling amount). These rules require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling. 
+For the year ended December 31, 2017 , the Company recognized no write-down of oil and natural gas properties as a result of the ceiling test limitation. For the year ended December 31, 2016 , the Company recognized a write-down of oil and natural gas properties of $95.8 million as a result of the ceiling test limitation, primarily driven by a 15% decrease in the 12-month average realized price of oil from $50.16 per barrel as of December 31, 2015 to $42.75 per barrel as of December 31, 2016 . If commodity prices were to decline, we could incur additional ceiling test write-downs in the future. See Notes 2 and 13 in the Footnotes to the Financial Statements for additional information. 
+Rig termination fee. For the year ended December 31, 2015, the Company recognized $3.1 million in expense related to the early termination of the contract for its vertical rig. See Note 14 in the Footnotes to the Financial Statements for additional information. 
+Acquisition expense. Acquisition expense decreased $0.8 million for the year ended December 31, 2017 compared to the same period of 2016 and increased $3.6 million for the year ended December 31, 2016 compared to the same period of 2015 . Acquisition expense for all periods was related to costs with respect to our acquisition efforts in the Permian Basin. See Note 2 in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions. 
+48 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Other Income and Expenses and Preferred Stock Dividends 
+For the Year Ended December 31, 
+(in thousands) 
+2017 
+2016 
+$ Change 
+% Change 
+Interest expense, net of capitalized amounts 
+$ 
+2,159 
+$ 
+11,871 
+$ 
+(9,712 
+) 
+(82 
+)% 
+Loss on early extinguishment of debt 
+— 
+12,883 
+(12,883 
+) 
+nm 
+Loss on derivative contracts 
+18,901 
+20,233 
+(1,332 
+) 
+(7 
+)% 
+Other income 
+(1,311 
+) 
+(637 
+) 
+(674 
+) 
+106 
+% 
+Total 
+$ 
+19,749 
+$ 
+44,350 
+Income tax (benefit) expense 
+$ 
+1,273 
+$ 
+(14 
+) 
+$ 
+1,287 
+(9,193 
+)% 
+Preferred stock dividends 
+(7,295 
+) 
+(7,295 
+) 
+— 
+— 
+% 
+໿ 
+For the Year Ended December 31, 
+(in thousands) 
+2016 
+2015 
+$ Change 
+% Change 
+Interest expense, net of capitalized amounts 
+$ 
+11,871 
+$ 
+21,111 
+$ 
+(9,240 
+) 
+(44 
+)% 
+Loss on early extinguishment of debt 
+12,883 
+— 
+12,883 
+nm 
+(Gain) loss on derivative contracts 
+20,233 
+(28,358 
+) 
+48,591 
+(171 
+)% 
+Other income 
+(637 
+) 
+(198 
+) 
+(439 
+) 
+222 
+% 
+Total 
+$ 
+44,350 
+$ 
+(7,445 
+) 
+Income tax (benefit) expense 
+$ 
+(14 
+) 
+$ 
+38,474 
+$ 
+(38,488 
+) 
+(100 
+)% 
+Preferred stock dividends 
+(7,295 
+) 
+(7,895 
+) 
+600 
+(8 
+)% 
+nm = not meaningful 
+Interest expense, net of capitalized amounts. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under our Credit Facility or with term debt. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to our lender in interest expense, net of capitalized amounts. In addition, we include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees in interest expense. 
+Interest expense, net of capitalized amounts, incurred during the year ended December 31, 2017 decreased $9.7 million to $2.2 million compared to $11.9 million for the same period of 2016 . The decrease is primarily attributable to a $13.9 million increase in capitalized interest compared to the 2016 period, resulting from a higher average unevaluated property balance for the year ended December 31, 2017 as compared to the same period of 2016 . The increase in unevaluated property was primarily due to acquired properties (see Note 3 and 13 in the Footnotes to the Financial Statements for information about the Company’s acquisitions and unevaluated property balance). Offsetting the decrease was a $5.2 million increase in interest expense related to our debt due to a higher average debt balance for the year ended December 31, 2017 as compared to the same period of 2016 , resulting from the issuance of an additional $200 million of our 6.125% Senior Notes in May 2017 (see Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s 6.125% Senior Notes). 
+Interest expense, net of capitalized amounts, incurred during the year ended December 31, 2016 decreased $9.2 million to $11.9 million compared to $21.1 million for the same period of 2015. The decrease is primarily attributable to a $9.4 million increase in capitalized interest compared to the 2015 period, resulting from a higher average unevaluated property balance for the year ended December 31, 2016 as compared to the same period of 2015. The increase in unevaluated property was primarily due to acquired properties (see Note 3 in the Footnotes to the Financial Statements for information about the Company’s acquisitions). Offsetting the decrease was a $0.2 million increase in interest expense related to our debt due to a higher average debt balance for the year ended December 31, 2016 as compared to the same period of 2015, resulting from the issuance of our 6.125% Senior Notes in November 2016 (see Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s 6.125% Senior Notes). 
+Gain (loss) on the early extinguishment of debt. During October 2016, the secured second lien term loan was repaid in full at the prepayment rate of 101% using proceeds from the sale of the 6.125% Senior Notes, which resulted in a loss on early extinguishment of debt of $12.9 million (inclusive of $3.0 million in prepayment fees and $9.9 million of unamortized debt issuance costs). See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s debt. 
+49 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Gain (loss) on derivative instruments. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in commodity prices. This amount represents the (i) gain (loss) related to fair value adjustments on our open derivative contracts and (ii) gains (losses) on settlements of derivative contracts for positions that have settled within the period. 
+For the year ended December 31, 2017 , the net loss on derivative instruments was $18.9 million , compared to a $20.2 million net loss in 2016 . The net gain (loss) on derivative instruments for the periods indicated includes the following (in thousands): 
+໿ 
+For the Year Ended December 31, 
+ 
+2017 
+2016 
+Change 
+Oil derivatives 
+Net gain (loss) on settlements 
+$ 
+(9,067 
+) 
+$ 
+17,801 
+$ 
+(26,900 
+) 
+Net loss on fair value adjustments 
+(11,426 
+) 
+(37,543 
+) 
+26,100 
+Total loss on oil derivatives 
+$ 
+(20,493 
+) 
+$ 
+(19,742 
+) 
+$ 
+(800 
+) 
+Natural gas derivatives 
+Net gain on settlements 
+$ 
+594 
+$ 
+102 
+$ 
+500 
+Net gain (loss) on fair value adjustments 
+998 
+(593 
+) 
+1,600 
+Total gain (loss) on natural gas derivatives 
+$ 
+1,592 
+$ 
+(491 
+) 
+$ 
+2,100 
+ 
+Total loss on oil & natural gas derivatives 
+$ 
+(18,901 
+) 
+$ 
+(20,233 
+) 
+$ 
+1,300 
+For the year ended December 31, 2016 , the net loss on derivative instruments was $20.2 million , compared to a $28.4 million net gain in 2016 . The net gain (loss) on derivative instruments for the periods indicated includes the following (in thousands): 
+໿ 
+For the Year Ended December 31, 
+2016 
+2015 
+Change 
+Oil derivatives 
+Net gain on settlements 
+$ 
+17,801 
+$ 
+33,299 
+$ 
+(15,500 
+) 
+Net loss on fair value adjustments 
+(37,543 
+) 
+(5,403 
+) 
+(32,100 
+) 
+Total gain (loss) on oil derivatives 
+$ 
+(19,742 
+) 
+$ 
+27,896 
+$ 
+(47,600 
+) 
+Natural gas derivatives 
+Net gain on settlements 
+$ 
+102 
+$ 
+1,717 
+$ 
+(1,600 
+) 
+Net loss on fair value adjustments 
+(593 
+) 
+(1,255 
+) 
+600 
+Total gain (loss) on natural gas derivatives 
+$ 
+(491 
+) 
+$ 
+462 
+$ 
+(1,000 
+) 
+ 
+Total gain (loss) on oil & natural gas derivatives 
+$ 
+(20,233 
+) 
+$ 
+28,358 
+$ 
+(48,600 
+) 
+See Notes 6 and 7 in the Footnotes to the Financial Statements for additional information on the Company’s derivative contracts and disclosures related to derivative instruments. 
+Income tax expense. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. When appropriate based on our analysis, we record a valuation allowance for deferred tax assets when it is more likely than not that the deferred tax assets will not be realized. 
+The Company had an income tax expense of $1.3 million for the year ended December 31, 2017 compared to an income tax benefit of less than $0.1 million for the same period of 2016 . The change in income tax is primarily related to deferred state income tax expense. The effective tax rate differed from the federal income tax rate of 35% primarily due to the valuation allowance for the comparative periods, the effect of state taxes, and non-deductible executive compensation expenses. 
+The Company had an income tax benefit of less than $0.1 million for the year ended December 31, 2016 compared to an income tax expense of $38.5 million for the same period of 2015. The change in income tax is primarily related to recording a valuation allowance of $108.8 in 2015 and the difference in the amount of income (loss) before income taxes between periods. The effective tax rate of 0% in 2016 and (19)% in 2015 differed from the federal income tax rate of 35% primarily due to the valuation allowance for the comparative periods, the effect of state taxes, and non-deductible executive compensation expenses. 
+50 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+The following table presents a reconciliation of the federal statutory tax rates to the effective tax rates: 
+ 
+For the Year Ended December 31, 
+Components of income tax rate reconciliation 
+2017 
+2016 
+2015 
+Income tax expense computed at the statutory federal income tax rate 
+35 
+% 
+35 
+% 
+35 
+% 
+State taxes net of federal benefit 
+1 
+% 
+— 
+% 
+1 
+% 
+Restricted stock and stock options 
+— 
+% 
+—% 
+—% 
+Section 162(m) 
+— 
+% 
+(1 
+)% 
+(1 
+)% 
+Valuation allowance 
+(35 
+)% 
+(34 
+)% 
+(54 
+)% 
+Effective income tax rate 
+1 
+% 
+— 
+% 
+(19 
+)% 
+For additional information, see Note 11 in the Footnotes to the Financial Statements. 
+Preferred stock dividends. Holders of our Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10% per annum of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share). 
+Preferred stock dividends for the year ended December 31, 2017 were consistent with the same period of 2016 . Preferred stock dividends for the year ended December 31, 2016 decreased $0.6 million compared to the same period of 2015. The decrease was due to a decrease in the number of preferred shares outstanding, attributable to a partial share conversion in February 2016 in which the Company exchanged a total of 120,000 shares of Preferred Stock for 719,000 shares of common stock. Dividends reflect a 10% dividend yield. See Note 10 in the Footnotes to the Financial Statements for additional information. 
+51 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Summary of Significant Accounting Policies and Critical Accounting Estimates 
+The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under GAAP. We also describe the most significant estimates and assumptions we make in applying these policies. See Note 2 in the Footnotes to the Financial Statements included elsewhere in this Annual Report on Form 10-K for a discussion of additional accounting policies and estimates made by management. 
+Oil and natural gas properties 
+The Company utilizes the full cost method of accounting for its oil and natural gas properties whereby all costs incurred in connection with the acquisition, exploration and development of oil and natural gas reserves, including certain overhead costs, are capitalized into the “full cost pool.” The amounts capitalized into the full cost pool are depleted (charged against earnings) using the unit-of-production method. The full cost method of accounting for oil and natural gas properties requires that the Company makes estimates based on its assumptions of future events that could change. These estimates are described below. 
+Depreciation, depletion and amortization (DD&A) of oil and natural gas properties 
+The Company calculates DD&A by using the depletable base, which is equal to the net capitalized costs in our full cost pool plus estimated future development costs, and the estimated net proved reserve quantities. Capitalized costs added to the full cost pool include the following: 
+• 
+costs of drilling and equipping productive wells, dry hole costs, acquisition costs of properties with proved reserves, delay rentals and other costs related to exploration and development of our oil and natural gas properties; 
+• 
+payroll costs including the related fringe benefits paid to employees directly engaged in the acquisition, exploration and/or development of oil and natural gas properties as well as other directly identifiable general and administrative costs associated with such activities. Such capitalized costs do not include any costs related to the production of oil and natural gas or general corporate overhead; 
+• 
+costs associated with unevaluated properties, those lacking proved reserves, are excluded from the depletable base. These unevaluated property costs are added to the depletable base at such time as wells are completed on the properties or management determines these costs have been impaired. The Company’s determination that a property has or has not been impaired (which is discussed below) requires assumptions about future events; 
+• 
+estimated costs to dismantle, abandon and restore properties that are capitalized to the full cost pool when the related liabilities are incurred (see also the discussion below regarding Asset Retirement Obligations); 
+• 
+estimated future costs to develop proved properties are added to the full cost pool for purposes of the DD&A computation. The Company uses assumptions based on the latest geologic, engineering, regulatory and cost data available to it to estimate these amounts. However, the estimates made are subjective and may change over time. The Company’s estimates of future development costs are reviewed at least annually and as additional information becomes available; and 
+• 
+capitalized costs included in the full cost pool plus estimated future development costs are depleted and charged against earnings using the unit-of-production method. Under this method, the Company estimates the proved reserves quantities at the beginning of each accounting period. For each BOE produced during the period, the Company records a DD&A charge equal to the amount included in the depletable base (net of accumulated depreciation, depletion and amortization) divided by our estimated net proved reserve quantities. 
+Because the Company uses estimates and assumptions to determine proved reserves (as discussed below) and the amounts included in the depletable base, our depletion rates may materially change if actual results differ from these estimates. 
+Ceiling test 
+Under the full cost method of accounting, the Company compares, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (excluding cash flows related to estimated abandonment costs and the value of commodity derivative instruments) plus the lower of cost or fair value of unevaluated properties, to the net capitalized costs of proved oil and natural gas properties net of related deferred taxes. The Company refers to this comparison as a “ceiling test.” If the net capitalized costs of proved oil and natural gas properties exceed the estimated discounted (at a 10% annualized rate) future net cash flows from 
+52 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+proved reserves plus the lower of cost or fair value of unevaluated properties, the Company is required to write-down the value of its oil and natural gas properties to the value of the discounted cash flows. Estimated future net cash flows from proved reserves are based on a twelve-month average pricing assumption. Given the volatility of oil and natural gas prices, it is reasonably possible that the Company’s estimates of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. For the periods ended December 31, 2017 , the Company recognized no write-down of oil and natural gas properties as a result of the ceiling test limitation. For the periods ending December 31, 2016 and 2015 the Company recognized write-downs of oil and natural gas properties of $95.8 million and $208.4 million , respectively, as a result of the ceiling test limitation. If oil and natural gas prices were to decline, even if only for a short period of time, we could incur additional write-downs of oil and natural gas properties in the future. See Notes 2 and 13 in the Footnotes to the Financial Statements for additional information regarding the Company’s oil and natural gas properties. 
+The table below presents the cumulative results of the full cost ceiling test along with various pricing scenarios to demonstrate the sensitivity of our full cost ceiling and estimated total proved reserve volumes to changes in 12-month average oil and natural gas prices on closing prices on the first day of each month. This sensitivity analysis is as of December 31, 2017 and, accordingly, does not consider drilling results, production, changes in oil and natural gas prices, and changes in future development and operating costs subsequent to December 31, 2017 that may require revisions to our proved reserve estimates and resulting estimated future net cash flows used in the full cost ceiling test. The volumes resulting from the sensitivity analysis, which are for illustrative purposes only, incorporate a number of assumptions and have not been audited by the Company’s third-party engineer. 
+໿ 
+12-Month Average Prices 
+Excess (Deficit) of 
+Full Cost Ceiling Over Net Capitalized Costs 
+Pricing Scenarios 
+Oil ($/Bbl) 
+Natural gas ($/Mcf) 
+(in thousands) 
+December 31, 2017 Actual 
+$ 
+51.34 
+$ 
+2.98 
+241,000 
+Combined price sensitivity 
+Oil and natural gas +10% 
+$ 
+56.47 
+$ 
+3.28 
+501,507 
+Oil and natural gas -10% 
+46.21 
+2.68 
+(18,719 
+) 
+Oil price sensitivity 
+Oil +10% 
+$ 
+56.47 
+$ 
+2.98 
+478,728 
+Oil -10% 
+46.21 
+2.98 
+4,060 
+Natural gas sensitivity 
+Natural gas +10% 
+$ 
+51.34 
+$ 
+3.28 
+264,174 
+Natural gas -10% 
+51.34 
+2.68 
+218,615 
+Estimating reserves and present value of estimated future net cash flows 
+Estimates of quantities of proved oil and natural gas reserves, including the discounted present value of estimated future net cash flows from such reserves at the end of each quarter, are based on numerous assumptions, which are likely to change over time. These assumptions include: 
+• 
+the prices at which the Company can sell its oil and natural gas production in the future. Oil and natural gas prices are volatile, but we are required to assume that they remain constant, using the twelve-month average pricing assumption. In general, higher oil and natural gas prices will increase quantities of proved reserves and the present value of estimated future net cash flows from such reserves, while lower prices will decrease these amounts; and 
+• 
+the costs to develop and produce the Company’s reserves and the costs to dismantle its production facilities when reserves are depleted. These costs are likely to change over time, but we are required to assume that they remain constant. Increases in costs will reduce estimated oil and natural gas quantities and the present value of estimated future net cash flows, while decreases in costs will increase such amounts. 
+Changes in these prices and/or costs will affect the present value of estimated future net cash flows more than the estimated quantities of oil and natural gas reserves for the Company’s properties that have relatively short productive lives. If oil and natural gas prices remain at current levels or decline further, it will have a negative impact on the present value of estimated future net cash flows and the estimated quantities of oil and natural gas reserves. 
+In addition, the process of estimating proved oil and natural gas reserves requires that the Company’s independent and internal reserve engineers exercise judgment based on available geological, geophysical and technical information. We have described the risks associated with reserve estimation and the volatility of oil and natural gas prices under “Risk Factors.” 
+Sales of oil and natural gas properties are accounted for as adjustments to the net full cost pool with no gain or loss recognized unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves. 
+53 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Table of Contents 
+Unproved properties 
+Costs, including capitalized interest, associated with properties that do not have proved reserves are excluded from the depletable base, and are included in the line item “Unevaluated properties.” Unevaluated property costs are transferred to the depletable base when wells are completed on the properties or management determines that these costs have been impaired. In addition, the Company is required to determine whether its unevaluated properties are impaired and, if so, include the costs of such properties in the depletable base. We assess properties on an individual basis or as a group. The Company considers the following factors, among others: exploration program and intent to drill, remaining lease term, and the assignment of proved reserves. This determination may require the exercise of substantial judgment by management. 
+Asset retirement obligations 
+We are required to record our estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-life assets and the associated asset retirement costs. We estimate the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of the asset retirement obligation. Interest is accreted on the present value of the asset retirement obligations and reported as accretion expense within operating expenses in the Consolidated Statements of Operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to evaluated properties in the Consolidated Balance Sheets. 
+Estimating the future plugging and abandonment costs of wells and related facilities is difficult and requires management to make estimates and judgments because most of the obligations are many years in the future and asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. 
+See Note 12 in the Footnotes to the Financial Statements for additional information. 
+Derivatives 
+To manage oil and natural gas price risk on a portion of our planned future production, we have historically utilized commodity derivative instruments (including collars, swaps, put and call options and other structures) on approximately 40% to 60% of our projected production volumes in any given year. We do not use these instruments for trading purposes. Settlements of derivative contracts are generally based on the difference between the contract price and prices specified in the derivative instrument and a NYMEX price or other cash or futures index price. 
+Our derivative positions are carried at their fair value on the balance sheet with changes in fair value recorded through earnings. The estimated fair value of our derivative contracts is based upon current forward market prices on NYMEX and in the case of collars and floors, the time value of options. For additional information regarding derivatives and their fair values, see Notes 6 and 7 in the Footnotes to the Financial Statements and Part II, Item 7A Commodity Price Risk. 
+Income taxes 
+The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices). The Company had a valuation allowance of $60.9 million as of December 31, 2017 . See Note 11 in the Footnotes to the Financial Statements for additional information regarding Income Taxes. 
+Accounting Standards Updates (“ASU”) 
+See Note 2 in the Footnotes to the Financial Statements for information regarding ASUs. 
+Off-balance Sheet Arrangements 
+We had no off-balance sheet arrangements as of December 31, 2017 . 
+54 
+Table of Contents 
+Item 7A. Quantitative and Qualitative Disclosures about Market Risk 
+We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer credit risk. We mitigate these risks through a program of risk management including the use of derivative instruments. 
+Commodity price risk 
+The Company’s revenues are derived from the sale of its oil and natural gas production. The prices for oil and natural gas remain volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and government actions. From time to time, the Company enters into derivative financial instruments to manage oil and natural gas price risk, related both to NYMEX benchmark prices and regional basis differentials. The total volumes which we hedge through use of our derivative instruments varies from period to period; however, generally our objective is to hedge approximately 40% to 60% of our anticipated internally forecast production for the next 12 to 24 months, subject to the covenants under our Credit Facility. Our hedge policies and objectives may change significantly with movements in commodities prices or futures prices, in addition to modification of our capital spending plans related to operational activities and acquisitions. 
+The Company’s hedging portfolio, linked to NYMEX benchmark pricing, covers approximately 5,842 MBbls and 4,086 MMBtu of our expected oil and natural gas production, respectively, for the full year of 2018 . We also have commodity hedging contracts linked to Midland WTI basis differentials relative to Cushing covering approximately 5,289 MBbls of our expected oil production for the full year of 2018 . See Note 6 in the Footnotes to the Financial Statements for a description of the Company’s outstanding derivative contracts at December 31, 2017 , and derivative contracts established subsequent to that date. 
+The Company may utilize fixed price swaps, which reduce the Company’s exposure to decreases in commodity prices and limit the benefit the Company might otherwise have received from any increases in commodity prices. Swap contracts may also be enhanced by the simultaneous sale of call or put options to effectively increase the effective swap price as a result of the receipt of premiums from the option sales. 
+The Company may utilize price collars to reduce the risk of changes in oil and natural gas prices. Under these arrangements, no payments are due by either party as long as the applicable market price is above the floor price (purchased put option) and below the ceiling price (sold call option) set in the collar. If the price falls below the floor, the counter-party to the collar pays the difference to the Company, and if the price rises above the ceiling, the counterparty receives the difference from the Company. Additionally, the Company may sell put (or call) options at a price lower than the floor price (or higher than the ceiling price) in conjunction with a collar (three-way collar) and use the proceeds to increase either or both the floor or ceiling prices. In a three-way collar, to the extent that realized prices are below the floor price of the sold put option (or above the ceiling price of the sold call option), the Company’s net realized benefit from the three-way collar will be reduced on a dollar-for-dollar basis. 
+The Company may purchase put and call options, which reduce the Company’s exposure to decreases in oil and natural gas prices while allowing realization of the full benefit from any increases in oil and natural gas prices. If the price falls below the floor, the counterparty pays the difference to the Company. 
+The Company enters into these various agreements from time to time to reduce the effects of volatile oil and natural gas prices and does not enter into derivative transactions for speculative purposes. Presently, none of the Company’s derivative positions are designated as hedges for accounting purposes. 
+Interest rate risk 
+The Company is subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility. As of December 31, 2017 , the Company had $25.0 million outstanding under the Credit Facility with a weighted average interest rate of 3.11% . An increase or decrease of 1.00% in the interest rate would have a corresponding increase or decrease in our annual net income of approximately $0.3 million based on the balance outstanding at December 31, 2017 . See Note 5 in the Footnotes to the Financial Statements for more information on the Company’s interest rates on our Credit Facility. 
+Counterparty and customer credit risk 
+The Company’s principal exposures to credit risk are through receivables from the sale of our oil and natural gas production, joint interest receivables and receivables resulting from derivative financial contracts. 
+55 
+Table of Contents 
+The Company markets its oil and natural gas production to energy marketing companies. We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. For the year ended December 31, 2017 , three purchasers accounted for more than 10% of our revenue: Plains Marketing, L.P. ( 29% ); Enterprise Crude Oil, LLC ( 18% ); and Rio Energy International, Inc. ( 17% ). We do not require any of our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. At December 31, 2017 our total receivables from the sale of our oil and natural gas production were approximately $70.1 million . 
+Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have or intend to drill. We have little ability to control whether these entities will participate in our wells. At December 31, 2017 our joint interest receivables were approximately $42.7 million . 
+At December 31, 2017 our receivables resulting from derivative contracts were approximately $1.9 million . Our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. Most of the counterparties on our derivative instruments currently in place are lenders under our Credit Facility. We are likely to enter into additional derivative instruments with these or other lenders under our Credit Facility, representing institutions with investment grade ratings. We have existing International Swap Dealers Association Master Agreements (“ISDA Agreements”) with our derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of offset upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may offset all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. At December 31, 2017 we had a net derivative liability position of $28.6 million . 
+56 
+Table of Contents 
+ITEM 8. Financial Statements and Supplementary Data 
+ 
+Page 
+Reports of Independent Registered Public Accounting Firms 
+58 
+Consolidated Balance Sheets as of December 31, 2017 and 2016 
+60 
+Consolidated Statements of Operations for Each of the Three Years in the Period Ended December 31, 2017 
+61 
+Consolidated Statements of Stockholders’ Equity for Each of the Three Years in the Period Ended December 31, 2017 
+62 
+Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2017 
+63 
+Notes to Consolidated Financial Statements 
+64 
+57 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+Board of Directors and Stockholders 
+Callon Petroleum Company 
+Opinion on the financial statements 
+We have audited the accompanying consolidated balance sheets of Callon Petroleum Company Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2017 and 2016, the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the two years in the period ended December 31, 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 27, 2018 expressed unqualified opinion. 
+Basis for opinion 
+These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. 
+/s/ GRANT THORNTON LLP 
+We have served as the Company’s auditor since 2016. 
+Houston, Texas 
+February 27, 2018 
+58 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+The Board of Directors and Stockholders of 
+Callon Petroleum Company 
+We have audited the accompanying consolidated statements of operations, stockholders’ equity and cash flows of Callon Petroleum Company for the year ended December 31, 2015. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. 
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. 
+In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated results of operations and cash flows of Callon Petroleum Company for the year ended December 31, 2015, in conformity with U.S. generally accepted accounting principles. 
+/s/Ernst & Young LLP 
+New Orleans, Louisiana 
+March 2, 2016 
+59 
+Table of Contents 
+Part 1. Financial Information 
+Item I. Financial Information 
+Callon Petroleum Company 
+Consolidated Balance Sheets 
+(in thousands, except par and per share data) 
+December 31, 2017 
+December 31, 2016 
+ASSETS 
+Current assets: 
+Cash and cash equivalents 
+$ 
+27,995 
+$ 
+652,993 
+Accounts receivable 
+114,320 
+69,783 
+Fair value of derivatives 
+406 
+103 
+Other current assets 
+2,139 
+2,247 
+Total current assets 
+144,860 
+725,126 
+Oil and natural gas properties, full cost accounting method: 
+Evaluated properties 
+3,429,570 
+2,754,353 
+Less accumulated depreciation, depletion, amortization and impairment 
+(2,084,095 
+) 
+(1,947,673 
+) 
+Net evaluated oil and natural gas properties 
+1,345,475 
+806,680 
+Unevaluated properties 
+1,168,016 
+668,721 
+Total oil and natural gas properties, net 
+2,513,491 
+1,475,401 
+Other property and equipment, net 
+20,361 
+14,114 
+Restricted investments 
+3,372 
+3,332 
+Deferred tax asset 
+52 
+— 
+Deferred financing costs 
+4,863 
+3,092 
+Acquisition deposit 
+900 
+46,138 
+Other assets, net 
+5,397 
+384 
+Total assets 
+$ 
+2,693,296 
+$ 
+2,267,587 
+LIABILITIES AND STOCKHOLDERS’ EQUITY 
+Current liabilities: 
+Accounts payable and accrued liabilities 
+$ 
+162,878 
+$ 
+95,577 
+Accrued interest 
+9,235 
+6,057 
+Cash-settleable restricted stock unit awards 
+4,621 
+8,919 
+Asset retirement obligations 
+1,295 
+2,729 
+Fair value of derivatives 
+27,744 
+18,268 
+Total current liabilities 
+205,773 
+131,550 
+Senior secured revolving credit facility 
+25,000 
+— 
+6.125% senior unsecured notes due 2024, net of unamortized deferred financing costs 
+595,196 
+390,219 
+Asset retirement obligations 
+4,725 
+3,932 
+Cash-settleable restricted stock unit awards 
+3,490 
+8,071 
+Deferred tax liability 
+1,457 
+90 
+Fair value of derivatives 
+1,284 
+28 
+Other long-term liabilities 
+405 
+295 
+Total liabilities 
+837,330 
+534,185 
+Commitments and contingencies 
+Stockholders’ equity: 
+Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized: 1,458,948 shares outstanding 
+15 
+15 
+Common stock, $0.01 par value, 300,000,000 shares authorized; 201,836,172 and 201,041,320 shares outstanding, respectively 
+2,018 
+2,010 
+Capital in excess of par value 
+2,181,359 
+2,171,514 
+Accumulated deficit 
+(327,426 
+) 
+(440,137 
+) 
+Total stockholders’ equity 
+1,855,966 
+1,733,402 
+Total liabilities and stockholders’ equity 
+$ 
+2,693,296 
+$ 
+2,267,587 
+The accompanying notes are an integral part of these consolidated financial statements. 
+60 
+Table of Contents 
+Callon Petroleum Company 
+Consolidated Statements of Operations 
+(in thousands, except per share data) 
+For the Year Ended December 31, 
+2017 
+2016 
+2015 
+Operating revenues: 
+Oil sales 
+$ 
+322,374 
+$ 
+177,652 
+$ 
+125,166 
+Natural gas sales 
+44,100 
+23,199 
+12,346 
+Total operating revenues 
+366,474 
+200,851 
+137,512 
+Operating expenses: 
+Lease operating expenses 
+49,907 
+38,353 
+27,036 
+Production taxes 
+22,396 
+11,870 
+9,793 
+Depreciation, depletion and amortization 
+115,714 
+71,369 
+69,249 
+General and administrative 
+27,067 
+26,317 
+28,347 
+Settled share-based awards 
+6,351 
+— 
+— 
+Accretion expense 
+677 
+958 
+660 
+Write-down of oil and natural gas properties 
+— 
+95,788 
+208,435 
+Rig termination fee 
+— 
+— 
+3,075 
+Acquisition expense 
+2,916 
+3,673 
+27 
+Total operating expenses 
+225,028 
+248,328 
+346,622 
+Income (loss) from operations 
+141,446 
+(47,477 
+) 
+(209,110 
+) 
+Other (income) expenses: 
+Interest expense, net of capitalized amounts 
+2,159 
+11,871 
+21,111 
+Loss on early extinguishment of debt 
+— 
+12,883 
+— 
+(Gain) loss on derivative contracts 
+18,901 
+20,233 
+(28,358 
+) 
+Other income 
+(1,311 
+) 
+(637 
+) 
+(198 
+) 
+Total other (income) expense 
+19,749 
+44,350 
+(7,445 
+) 
+Income (loss) before income taxes 
+121,697 
+(91,827 
+) 
+(201,665 
+) 
+Income tax (benefit) expense 
+1,273 
+(14 
+) 
+38,474 
+Net income (loss) 
+120,424 
+(91,813 
+) 
+(240,139 
+) 
+Preferred stock dividends 
+(7,295 
+) 
+(7,295 
+) 
+(7,895 
+) 
+Income (loss) available to common stockholders 
+$ 
+113,129 
+$ 
+(99,108 
+) 
+$ 
+(248,034 
+) 
+Income (loss) per common share: 
+Basic 
+$ 
+0.56 
+$ 
+(0.78 
+) 
+$ 
+(3.77 
+) 
+Diluted 
+$ 
+0.56 
+$ 
+(0.78 
+) 
+$ 
+(3.77 
+) 
+ 
+Shares used in computing income (loss) per common share: 
+Basic 
+201,526 
+126,258 
+65,708 
+Diluted 
+202,102 
+126,258 
+65,708 
+The accompanying notes are an integral part of these consolidated financial statements. 
+61 
+Table of Contents 
+Callon Petroleum Company 
+Consolidated Statements of Stockholders’ Equity 
+(in thousands) 
+Preferred Stock 
+Common Stock 
+Capital in Excess of Par 
+Retained Earnings (Deficit) 
+Total Stockholders' Equity 
+Balance at 12/31/2014 
+$ 
+16 
+$ 
+552 
+$ 
+526,162 
+$ 
+(92,995 
+) 
+$ 
+433,735 
+Net loss 
+— 
+— 
+— 
+(240,139 
+) 
+(240,139 
+) 
+Shares issued pursuant to employee benefit plans 
+— 
+— 
+268 
+— 
+268 
+Restricted stock 
+— 
+8 
+1,323 
+— 
+1,331 
+Common stock issued 
+— 
+241 
+175,217 
+— 
+175,458 
+Preferred stock dividend 
+— 
+— 
+— 
+(7,895 
+) 
+(7,895 
+) 
+Balance at 12/31/2015 
+$ 
+16 
+$ 
+801 
+$ 
+702,970 
+$ 
+(341,029 
+) 
+$ 
+362,758 
+Net loss 
+— 
+— 
+— 
+(91,813 
+) 
+(91,813 
+) 
+Shares issued pursuant to employee benefit plans 
+— 
+— 
+275 
+— 
+275 
+Restricted stock 
+— 
+4 
+2,323 
+— 
+2,327 
+Common stock issued 
+— 
+1,198 
+1,465,952 
+— 
+1,467,150 
+Preferred stock conversion 
+(1 
+) 
+7 
+(6 
+) 
+— 
+— 
+Preferred stock dividend 
+— 
+— 
+— 
+(7,295 
+) 
+(7,295 
+) 
+Balance at 12/31/2016 
+$ 
+15 
+$ 
+2,010 
+$ 
+2,171,514 
+$ 
+(440,137 
+) 
+$ 
+1,733,402 
+Net income 
+— 
+— 
+— 
+120,424 
+120,424 
+Shares issued pursuant to employee benefit plans 
+— 
+— 
+311 
+— 
+311 
+Restricted stock 
+— 
+8 
+9,098 
+— 
+9,106 
+Common stock issued 
+— 
+— 
+18 
+— 
+18 
+Impact of forfeiture estimate (a) 
+— 
+— 
+418 
+(418 
+) 
+— 
+Preferred stock dividend 
+— 
+— 
+— 
+(7,295 
+) 
+(7,295 
+) 
+Balance at 12/31/2017 
+$ 
+15 
+$ 
+2,018 
+$ 
+2,181,359 
+$ 
+(327,426 
+) 
+$ 
+1,855,966 
+(a) 
+As a result of the adoption of ASU No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting the Company elected to no longer estimate forfeitures. See Note 2 in the Footnotes to Financial Statements for additional information about ASU 2016-09. 
+The accompanying notes are an integral part of these consolidated financial statements. 
+62 
+Table of Contents 
+Callon Petroleum Company 
+Consolidated Statements of Cash Flows 
+(in thousands) 
+For the Year Ended December 31, 
+2017 
+2016 
+2015 
+Cash flows from operating activities: 
+Net income (loss) 
+$ 
+120,424 
+$ 
+(91,813 
+) 
+$ 
+(240,139 
+) 
+Adjustments to reconcile net income to cash provided by operating activities: 
+Depreciation, depletion and amortization 
+118,051 
+73,072 
+69,891 
+Write-down of oil and natural gas properties 
+— 
+95,788 
+208,435 
+Accretion expense 
+677 
+958 
+660 
+Amortization of non-cash debt related items 
+2,150 
+3,115 
+3,123 
+Deferred income tax (benefit) expense 
+1,273 
+(14 
+) 
+38,474 
+Loss on derivatives, net of settlements 
+10,429 
+38,135 
+6,658 
+Loss on sale of other property and equipment 
+62 
+— 
+— 
+Non-cash loss on early extinguishment of debt 
+— 
+9,883 
+— 
+Non-cash expense related to equity share-based awards 
+8,254 
+2,765 
+2,688 
+Change in the fair value of liability share-based awards 
+3,288 
+6,953 
+6,612 
+Payments to settle asset retirement obligations 
+(2,047 
+) 
+(1,471 
+) 
+(3,258 
+) 
+Changes in current assets and liabilities: 
+Accounts receivable 
+(44,495 
+) 
+(30,055 
+) 
+(4,761 
+) 
+Other current assets 
+108 
+(786 
+) 
+(20 
+) 
+Current liabilities 
+30,947 
+25,288 
+8,001 
+Other long-term liabilities 
+121 
+96 
+80 
+Long-term prepaid 
+(4,650 
+) 
+— 
+— 
+Other assets, net 
+(1,528 
+) 
+(840 
+) 
+338 
+Payments for cash-settled restricted stock unit awards related to early retirements 
+related to early retirements 
+— 
+— 
+(3,538 
+) 
+Payments for cash-settled restricted stock unit awards 
+(13,173 
+) 
+(10,300 
+) 
+(3,925 
+) 
+Net cash provided by operating activities 
+229,891 
+120,774 
+89,319 
+Cash flows from investing activities: 
+Capital expenditures 
+(419,839 
+) 
+(190,032 
+) 
+(227,292 
+) 
+Acquisitions 
+(718,456 
+) 
+(654,679 
+) 
+(32,245 
+) 
+Acquisition deposit 
+45,238 
+(46,138 
+) 
+— 
+Proceeds from sales of mineral interest and equipment 
+20,525 
+24,562 
+377 
+Net cash used in investing activities 
+(1,072,532 
+) 
+(866,287 
+) 
+(259,160 
+) 
+Cash flows from financing activities: 
+Borrowings on senior secured revolving credit facility 
+25,000 
+217,000 
+181,000 
+Payments on senior secured revolving credit facility 
+— 
+(257,000 
+) 
+(176,000 
+) 
+Payments on term loans 
+— 
+(300,000 
+) 
+— 
+Issuance of 6.125% senior unsecured notes due 2024 
+200,000 
+400,000 
+— 
+Premium on the issuance of 6.125% senior unsecured notes due 2024 
+8,250 
+— 
+— 
+Payment of deferred financing costs 
+(7,194 
+) 
+(10,793 
+) 
+— 
+Issuance of common stock 
+— 
+1,357,577 
+175,459 
+Payment of preferred stock dividends 
+(7,295 
+) 
+(7,295 
+) 
+(7,895 
+) 
+Tax withholdings related to restricted stock units 
+(1,118 
+) 
+(2,207 
+) 
+(2,467 
+) 
+Net cash provided by financing activities 
+217,643 
+1,397,282 
+170,097 
+Net change in cash and cash equivalents 
+(624,998 
+) 
+651,769 
+256 
+Balance, beginning of period 
+652,993 
+1,224 
+968 
+Balance, end of period 
+$ 
+27,995 
+$ 
+652,993 
+$ 
+1,224 
+The accompanying notes are an integral part of these consolidated financial statements. 
+63 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+1. 
+Description of Business and Basis of Presentation 
+9. 
+Share-Based Compensation 
+2. 
+Summary of Significant Accounting Policies 
+10. 
+Equity Transactions 
+3. 
+Acquisitions and Dispositions 
+11. 
+Income Taxes 
+4. 
+Earnings (Loss) Per Share 
+12. 
+Asset Retirement Obligations 
+5. 
+Borrowings 
+13. 
+Supplemental Information on Oil and Natural Gas Operations (Unaudited) 
+6. 
+Derivative Instruments and Hedging Activities 
+14. 
+Other 
+7. 
+Fair Value Measurements 
+15. 
+Summarized Quarterly Financial Information (Unaudited) 
+8. 
+Employee Benefit Plans 
+Note 1 - Description of Business and Basis of Presentation 
+Description of business 
+Callon Petroleum Company is an independent oil and natural gas company established in 1950. The Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. 
+Callon is focused on the acquisition, development, exploration and exploitation of unconventional onshore, oil and natural gas reserves in the Permian Basin. The Company’s operations to date have been predominantly focused on the horizontal development of several prospective intervals, including multiple levels of the Wolfcamp formation and the Spraberry shales. Callon has assembled a multi-year inventory of potential horizontal well locations and intends to add to this inventory through delineation drilling of emerging zones on its existing acreage and acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps. 
+Basis of presentation 
+Unless otherwise indicated, all dollar amounts included within the Footnotes to the Financial Statements are presented in thousands, except for per share and per unit data. 
+The Consolidated Financial Statements include the accounts of the Company, and its subsidiary, Callon Petroleum Operating Company (“CPOC”). CPOC also has subsidiaries, namely Callon Offshore Production, Inc. and Mississippi Marketing, Inc. All intercompany accounts and transactions have been eliminated. In the opinion of management, the accompanying audited consolidated financial statements reflect all adjustments, including normal recurring adjustments and all intercompany account and transaction eliminations, necessary to present fairly the Company’s financial position, the results of its operations and its cash flows for the periods indicated. Certain prior year amounts may have been reclassified to conform to current year presentation. 
+Note 2 – Summary of Significant Accounting Policies 
+A. 
+Use of Estimates 
+The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 
+B. 
+Cash and Cash Equivalents 
+The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. 
+C. 
+Accounts Receivable 
+Accounts receivable consists primarily of accrued oil and natural gas production receivables and joint interest receivables from outside working interest owners. 
+64 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+D. 
+Revenue Recognition and Natural Gas Balancing 
+The Company recognizes revenue under the entitlements method of accounting. Under this method, revenue is deferred for deliveries in excess of the Company’s net revenue interest, while revenue is accrued for the undelivered volumes. The revenue we receive from the sale of NGLs is included in natural gas sales. Natural gas balancing receivables and payables were immaterial as of December 31, 2017 and 2016 . 
+See the Accounting Standards Updates (“ASU”) section within this footnote for information about recently issued ASUs related to Revenue Recognition. 
+E. 
+Major Customers 
+The Company’s production is generally sold on month-to-month contracts at prevailing prices. The following table identifies customers to whom it sold greater than 10% of its total oil and natural gas production during each of the years ended: 
+໿ 
+For the Year Ended December 31, 
+2017 
+2016 
+2015 
+Plains Marketing, L.P. 
+29 
+% 
+16 
+% 
+19 
+% 
+Enterprise Crude Oil, LLC 
+18 
+% 
+43 
+% 
+42 
+% 
+Rio Energy International, Inc. 
+17 
+% 
+— 
+% 
+— 
+% 
+Shell Trading Company 
+9 
+% 
+18 
+% 
+4 
+% 
+Permian Transport and Trading 
+— 
+% 
+— 
+% 
+15 
+% 
+Other 
+27 
+% 
+23 
+% 
+20 
+% 
+Total 
+100 
+% 
+100 
+% 
+100 
+% 
+Because alternative purchasers of oil and natural gas are readily available, the Company believes that the loss of any of these purchasers would not result in a material adverse effect on its ability to market future oil and natural gas production. 
+F. 
+Oil and Natural Gas Properties 
+The Company uses the full cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as oil and gas properties. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest capitalized on unevaluated leases, other costs related to exploration and development activities, and site restoration, dismantlement and abandonment costs capitalized in accordance with asset retirement obligation accounting guidance. Costs capitalized also include any internal costs that are directly related to exploration and development activities, including salaries and benefits, but do not include any costs related to production, general corporate overhead or similar activities. 
+When applicable, proceeds from the sale or disposition of oil and natural gas properties are accounted for as a reduction to capitalized costs through adjustments to accumulated depreciation, depletion, amortization and impairment unless the sale would significantly alter the relationship between capitalized costs and proved reserves, in which case a gain or loss is recognized. 
+Historical and estimated future development costs of oil and natural gas properties, which have been evaluated and contain proved reserves, as well as the historical cost of properties that have been determined to have no future economic value, are depleted using the unit-of-production method based on proved reserves. Excluded from this amortization are costs associated with unevaluated properties, including capitalized interest on such costs. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties or the Company determines that these costs have been impaired. The Company assesses properties on an individual basis or as a group and considers the following factors, among others, to determine if these costs have been impaired: exploration program and intent to drill, remaining lease term, and the assignment of proved reserves. 
+Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the sum of (a) the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10% , plus (b) the lower of cost or fair value of unevaluated properties, and (c) net of related tax effects (collectively called the full cost ceiling). These rules require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling. At December 31, 2017 and 2016 , the average realized prices used in determining the estimated future net cash flows from proved reserves were $51.34 and $42.75 per barrel of oil, respectively, and $2.98 and $2.48 per Mcf of natural gas, respectively. For the periods ended December 31, 2017 and 2016 , the Company recognized no write-down of oil and natural gas properties and a 
+65 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+$95,788 write-down of oil and natural gas properties, respectively, as a result of the ceiling test limitation. See Notes 2 and 13 for additional information regarding the Company’s oil and natural gas properties. 
+Upon the acquisition or discovery of oil and natural gas properties, the Company estimates the future net costs to dismantle, abandon and restore the property by using available geological, engineering and regulatory data. Such cost estimates are periodically updated for changes in conditions and requirements. In accordance with asset retirement obligation guidance, such costs are capitalized to the full cost pool when the related liabilities are incurred. In accordance with full cost accounting rules, assets recorded in connection with the recognition of an asset retirement obligation are included as part of the costs subject to the full cost ceiling limitation. The future cash outflows associated with settling the recorded asset retirement obligations are excluded from the computation of the present value of estimated future net revenues used in determining the full cost ceiling amount. 
+G. 
+Other Property and Equipment 
+The Company depreciates its Other property and equipment using the straight-line method over estimated useful lives of three to 20 years . Depreciation expense of $900 , $793 and $865 relating to other property and equipment was included in general and administrative expenses in the Company’s consolidated statements of operations for the years ended December 31, 2017 , 2016 and 2015 , respectively. The accumulated depreciation on other property and equipment was $16,259 and $15,227 as of December 31, 2017 and 2016 , respectively. The Company reviews its Other property and equipment for impairment when indicators of impairment exist. See Note 14 for additional information. 
+H. 
+Capitalized Interest 
+The Company capitalizes interest on unevaluated oil and gas properties. Capitalized interest cannot exceed gross interest expense. During the years ended December 31, 2017 , 2016 and 2015 , the Company capitalized $33,783 , $19,857 and $10,459 of interest expense. 
+I. 
+Deferred Financing Costs 
+Deferred financing costs are stated at cost, net of amortization, and as a direct reduction from the debt’s carrying value on the balance sheet. For revolving debt arrangements, deferred financing costs are stated at cost, net of amortization, as an asset on the balance sheet. Amortization of deferred financing costs is computed using the straight-line method over the life of the loan. Amortization of deferred financing costs of $2,150 , $3,115 and $3,123 were recorded for the years ended December 31, 2017 , 2016 and 2015 , respectively. 
+J. 
+Asset Retirement Obligations 
+The Company is required to record an estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-life assets and the associated asset retirement costs. The Company estimates the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of the asset retirement obligation. Interest is accreted on the present value of the asset retirement obligations and reported as accretion expense within operating expenses in the Consolidated Statements of Operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to evaluated properties in the Consolidated Balance Sheets. See Note 12 for additional information. 
+K. 
+Derivatives 
+Derivative contracts outstanding as of December 31, 2017 were not designated as accounting hedges, and are carried on the balance sheet at fair value. Changes in the fair value of derivative contracts not designated as accounting hedges are reflected in earnings as a gain or loss on derivative contracts. See Notes 6 and 7 for additional information regarding the Company’s derivative contracts. 
+L. 
+Income Taxes 
+Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties for financial reporting purposes and income tax purposes. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards, statutory depletion carryforwards and tax credit carryforwards. A valuation allowance is provided for that portion of deferred tax assets, if any, for which it is deemed more likely than not that it will not be realized. As of December 31, 2017 the valuation allowance was $60,919 . See Note 11 for additional information. 
+66 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+M. 
+Share-Based Compensation 
+The Company grants to directors and employees stock options and restricted stock unit awards (“RSU awards”) that may be settled in common stock (“RSU equity awards”) or cash (“Cash-settleable RSU awards”). 
+Stock Options. For stock options the Company expected to settle in common stock, share-based compensation expense was based on the grant-date fair value as calculated using the Black-Scholes option pricing model and recognized straight-line over the vesting period (generally three years ). 
+RSU equity awards and Cash-settleable RSU awards. For RSU equity awards that the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value and recognized straight-line over the vesting period (generally three years ). For RSU equity awards with vesting terms subject to a market condition, share-based compensation expense is based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model with the estimated value recognized over the vesting period (generally three years). For Cash-settleable RSU awards that the Company expects or is required to settle in cash, share-based compensation expense is based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model, because vesting of these awards is subject to a market condition, with the estimated fair value recognized over the vesting period (generally three years ). 
+See the Accounting Standards Updates section within this footnote for information about recently adopted ASUs related to Stock Compensation. 
+N. 
+Non-cash Investing and Supplemental Cash Flow Information 
+The following table sets forth the non-cash investing and supplemental cash flow information for the periods indicated: 
+໿ 
+For the Year Ended December 31, 
+2017 
+2016 
+2015 
+Non-cash investing information 
+Change in accrued capital expenditures 
+$ 
+(39,532 
+) 
+$ 
+(613 
+) 
+$ 
+(16,813 
+) 
+Supplemental cash flow information (a) 
+Cash paid for interest, net of capitalized interest 
+$ 
+— 
+$ 
+8,679 
+$ 
+17,978 
+(a) 
+During the three year period ended 2017 , the Company paid no federal income taxes. 
+O. 
+Earnings per Share (“EPS”) 
+The Company’s basic EPS amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS, using the treasury-stock method, reflects the potential dilution caused by the exercise of options and vesting of restricted stock and RSUs settleable in shares. 
+P. 
+Accounting Standards Updates 
+Recently Issued ASUs - Revenue from Contracts with Customers (Topic 606) 
+In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will replace most of the existing revenue recognition requirements in GAAP when it becomes effective. The standard can be applied using either the full retrospective approach or a modified retrospective approach at the date of adoption. This will be effective for annual and interim reporting periods beginning after December 15, 2017. 
+Throughout 2015 and 2016, the FASB issued several updates to the revenue recognition guidance in Topic 606. In August 2015, the FASB issued ASU No. 2015-14, deferring the effective date of ASU 2014-09 by one year. In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers - Principal versus Agent Considerations (Reporting Revenue Gross versus Net) . Under this update, an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This update allows for either full retrospective adoption or modified retrospective adoption. In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers - Identifying Performance Obligations and Licensing . This update clarifies two principles of Accounting Standards Codification Topic 606: identifying performance obligations and the licensing implementation guidance. In May 2016, the FASB issued 
+67 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+ASU No. 2016-12, Revenue from Contracts with Customers - Narrow-Scope Improvements and Practical Expedients . This update applies only to the following areas from Accounting Standards Codification Topic 606: assessing the collectability criterion and accounting for contracts that do not meet the criteria for step 1, presentation of sales taxes and other similar taxes collected from customers, non-cash consideration, contract modification at transition, completed contracts at transition and technical correction. These updates will be effective for annual and interim reporting periods beginning after December 15, 2017. 
+The Company adopted the new standard on January 1, 2018 using the modified retrospective method at the date of adoption. The Company does not expect the adoption of this standard will have a material impact on our Consolidated Financial Statements. The Company has determined that under certain natural gas processing agreements where control of the natural gas changes at the wellhead or inlet of the processing entity’s system, the treatment of gathering and treating fees should be recorded net of revenue in accordance with the new guidance. Gathering and treating fees have historically been recorded as an expense in lease operating expenses in our Statement of Operations. Beginning on January 1, 2018, the Company anticipates to modify our presentation of revenues and expenses to include these fees net of revenue. 
+Recently Issued ASUs - Other 
+In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”). The standard requires all lease transactions (with terms in excess of 12 months) to be recognized on the balance sheet as lease assets and lease liabilities. Public entities are required to apply ASU 2016-02 for annual and interim reporting periods beginning after December 15, 2018 with early adoption permitted. The Company is currently evaluating the impact of its pending adoption of this guidance on its consolidated financial statements. 
+In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”). The objective of the standard is to reduce the existing diversity in practice of several cash flow issues, including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payment made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows and application of the predominance principle. The guidance in ASU 2016-15 is effective for public entities for annual reporting periods beginning after December 15, 2017, including interim periods therein. Early adoption is permitted and is to be applied on retrospective basis. The Company is currently evaluating the method of adoption and impact this standard may have on its consolidated financial statements and related disclosures. 
+In January 2017, the FASB issued ASU No. 2017-01, Business Combinations-Clarifying the Definition of a Business (“ASU 2017-01”). The guidance in ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. The guidance provides a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired or disposed of is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. The guidance in ASU 2017-01 is effective for annual reporting periods beginning after December 15, 2017, including interim periods therein. The Company will adopt this update prospectively effective January 1, 2018. The adoption of this update will not have an impact on its consolidated financial statements 
+Recently Adopted ASUs 
+In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). The standard is intended to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows, and will allow companies to estimate the number of stock awards expected to vest. The guidance in ASU 2016-09 is effective for public entities for annual reporting periods beginning after December 15, 2016, including interim periods therein. The Company adopted this ASU on January 1, 2017 and it did not have a material impact on its financial statements. The Company has elected to no longer estimate forfeitures. 
+In December 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topics 230): Restricted Cash (“ASU 2016-18”). The objective of the standard is to require the change during the period in total restricted cash and cash equivalents to be included with cash and cash equivalents when reconciling the beginning-of-period and the end-of-period total amounts shown on the statement of cash flows. The Company adopted this ASU on January 1, 2017 and it did not have a material impact on its financial statements. 
+68 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+Note 3 – Acquisitions and Dispositions 
+Acquisitions were accounted for under the acquisition method of accounting, which involves determining the fair value of the assets acquired and liabilities assumed under the income approach. 
+2017 Acquisitions 
+On February 13, 2017, the Company completed the acquisition of 29,175 gross ( 16,688 net) acres in the Delaware Basin, primarily located in Ward and Pecos Counties, Texas from American Resource Development, LLC, for total cash consideration of $646,559 , excluding customary purchase price adjustments (the “Ameredev Transaction”). The Company funded the cash purchase price with the net proceeds of an equity offering (see Note 10 for additional information regarding the equity offering). The Company obtained an 82% average working interest ( 75% average net revenue interest) in the properties acquired in the Ameredev Transaction. In December 2016, in connection with the execution of the purchase and sale agreement for the Ameredev Transaction, the Company paid a deposit in the amount of $46,138 to a third party escrow agent, which was recorded as Acquisition deposit on the balance sheet as of December 31, 2016. The following table summarizes the estimated acquisition date fair values of the acquisition: 
+Evaluated oil and natural gas properties 
+$ 
+137,368 
+Unevaluated oil and natural gas properties 
+509,359 
+Asset retirement obligations 
+(168 
+) 
+Net assets acquired 
+$ 
+646,559 
+On June 5, 2017, the Company completed the acquisition of 7,031 gross ( 2,488 net) acres in the Delaware Basin, located near the acreage acquired in the Ameredev Transaction discussed above, for total cash consideration of $52,500 , excluding customary purchase price adjustments. The Company funded the cash purchase price with its available cash and proceeds from the issuance of an additional $200,000 of its 6.125% senior notes due 2024 (“6.125% Senior Notes”) (see Note 5 for additional information regarding the Company’s debt obligations). 
+2016 Acquisitions 
+On October 20, 2016, the Company completed the acquisition of 6,904 gross ( 5,952 net) acres primarily located in Howard County, Texas from Plymouth Petroleum, LLC and additional sellers that exercised their “tag-along” sales rights, for total cash consideration of $339,687 , excluding customary purchase price adjustments (the “Plymouth Transaction”). The Company funded the cash purchase price with the net proceeds of an equity offering (see Note 10 for additional information regarding the equity offering). The Company acquired an 82% average working interest ( 62% average net revenue interest) in the properties acquired in the Plymouth Transaction. The following table summarizes the estimated acquisition date fair values of the net assets acquired in the acquisition: 
+໿ 
+Evaluated oil and natural gas properties 
+$ 
+65,043 
+Unevaluated oil and natural gas properties 
+274,664 
+Asset retirement obligations 
+(20 
+) 
+Net assets acquired 
+$ 
+339,687 
+On May 26, 2016, the Company completed the acquisition of 17,298 gross ( 14,089 net) acres primarily located in Howard County, Texas from BSM Energy LP, Crux Energy LP and Zaniah Energy LP, for total cash consideration of $220,000 and 9,333,333 shares of common stock (at an assumed offering price of $11.74 per share, which is the last reported sale price of our common stock on the New York Stock Exchange on that date) for a total purchase price of $329,573 , excluding customary purchase price adjustments (the “Big Star Transaction”). The Company acquired an 81% average working interest ( 61% average net revenue interest) in the properties acquired in the Big Star Transaction. The following table summarizes the estimated acquisition date fair values of the net assets acquired in the acquisition: 
+໿ 
+໿ 
+Evaluated oil and natural gas properties 
+$ 
+96,194 
+Unevaluated oil and natural gas properties 
+233,387 
+Asset retirement obligations 
+(8 
+) 
+Net assets acquired 
+$ 
+329,573 
+During 2016, the Company also closed on various acquisitions in the Midland Basin for an aggregate total purchase price of approximately $73,240 , net of $23,045 in sales of working interest. The acquisitions included the purchase of additional working interest and acreage in the Company’s existing core operating area. 
+69 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+2015 Acquisitions 
+During 2015, the Company closed on an acquisition in the Midland Basin for an aggregate total purchase price of approximately $29,800 . The acquisition included the purchase of additional working interest in the Company’s existing core operating area. 
+Unaudited pro forma financial statements 
+The following unaudited summary pro forma financial information for the periods presented is for illustrative purposes only and does not purport to represent what the Company’s results of operations would have been if the Ameredev Transaction, Plymouth Transaction and Big Star Transaction had occurred as presented, or to project the Company’s results of operations for any future periods: 
+໿ 
+Twelve Months Ended December 31, 
+2017 
+(a) 
+2016 
+(a) 
+2015 
+(a) 
+Revenues 
+$ 
+369,527 
+$ 
+243,273 
+$ 
+168,506 
+Income (loss) from operations 
+144,104 
+(39,730 
+) 
+(131,435 
+) 
+Income (loss) available to common stockholders 
+115,787 
+(82,612 
+) 
+(153,735 
+) 
+ 
+Net income (loss) per common share: 
+Basic 
+$ 
+0.57 
+$ 
+(0.50 
+) 
+$ 
+(1.18 
+) 
+Diluted 
+$ 
+0.57 
+$ 
+(0.50 
+) 
+$ 
+(1.18 
+) 
+(a) 
+The pro forma financial information was prepared assuming the Ameredev Transaction occurred as of January 1, 2016 and the Plymouth Transaction and Big Star Transaction occurred as of January 1, 2015. 
+The pro forma adjustments are based on available information and certain assumptions that management believes are reasonable, including revenue, lease operating expenses, production taxes, depreciation, depletion and amortization expense, accretion expense, interest expense and capitalized interest. 
+The properties associated with the Ameredev Transaction, Big Star Transaction, and the Plymouth Transaction have been commingled with our existing properties and it is impractical to provide the stand-alone operational results related to these properties. 
+Note 4 - Earnings Per Share 
+Basic earnings (loss) per share is computed by dividing income (loss) available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings (loss) per share includes the potential dilutive impact of non-vested restricted shares and unexercised options outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. The following table sets forth the computation of basic and diluted earnings per share: 
+(share amounts in thousands) 
+For the Year Ended December 31, 
+2017 
+2016 
+2015 
+Net income (loss) 
+$ 
+120,424 
+$ 
+(91,813 
+) 
+$ 
+(240,139 
+) 
+Preferred stock dividends 
+(7,295 
+) 
+(7,295 
+) 
+(7,895 
+) 
+Income (loss) available to common stockholders 
+$ 
+113,129 
+$ 
+(99,108 
+) 
+$ 
+(248,034 
+) 
+ 
+Weighted average shares outstanding 
+201,526 
+126,258 
+65,708 
+Dilutive impact of restricted stock 
+576 
+— 
+— 
+Weighted average shares outstanding for diluted income (loss) per share (a) 
+202,102 
+126,258 
+65,708 
+ 
+Basic income (loss) per share 
+$ 
+0.56 
+$ 
+(0.78 
+) 
+$ 
+(3.77 
+) 
+Diluted income (loss) per share 
+$ 
+0.56 
+$ 
+(0.78 
+) 
+$ 
+(3.77 
+) 
+ 
+Stock options (b) 
+— 
+15 
+15 
+Restricted stock (b) 
+16 
+— 
+126 
+(a) 
+Because the Company reported a loss available to common stockholders for the years ended December 31, 2016 , and 2015 , no unvested stock awards were included in computing loss per share because the effect was anti-dilutive. 
+(b) 
+Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive. 
+70 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+Note 5 – Borrowings 
+The Company’s borrowings consisted of the following at: 
+໿ 
+ 
+As of December 31, 
+2017 
+2016 
+Principal components: 
+Senior secured revolving credit facility 
+$ 
+25,000 
+$ 
+— 
+6.125% Senior Notes 
+600,000 
+400,000 
+Total principal outstanding 
+625,000 
+400,000 
+Premium on 6.125% Senior Notes, net of accumulated amortization 
+7,594 
+— 
+Unamortized deferred financing costs 
+(12,398 
+) 
+(9,781 
+) 
+Total carrying value of borrowings 
+$ 
+620,196 
+$ 
+390,219 
+Senior secured revolving credit facility (“Credit Facility”) 
+On May 31, 2017, the Company entered into the Sixth Amended and Restated Credit Agreement to the Credit Facility with a maturity date of May 25, 2022 . JPMorgan Chase Bank, N.A. is Administrative Agent, and participants include 17 institutional lenders. The total notional amount available under the Credit Facility is $2,000,000 . Amounts borrowed under the Credit Facility may not exceed the borrowing base, which is generally reviewed on a semi-annual basis. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. Concurrent with the execution of the Sixth Amended and Restated Credit Agreement, the Credit Facility’s borrowing base increased to $650,000 , but the Company elected an aggregate commitment amount of $500,000 . On November 7, 2017, the Credit Facility’s borrowing base increased to $700,000 with a reaffirmed commitment of $500,000 , following the semi-annual review. 
+As of December 31, 2017 , there was $25,000 outstanding on the Credit Facility. For the year ended December 31, 2017 , the Credit Facility had a weighted-average interest rate of 3.11% , calculated as the LIBOR plus a tiered rate ranging from 2.00% to 3.00% , which is determined based on utilization of the facility. In addition, the Credit Facility carries a commitment fee of 0.375% per annum, payable quarterly, on the unused portion of the borrowing base. 
+6.125% Senior Notes 
+On October 3, 2016, the Company issued $400,000 aggregate principal amount of 6.125% Senior Notes with a maturity date of October 1, 2024 and interest payable semi-annually beginning on April 1, 2017 . The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $391,270 . The 6.125% Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. 
+On May 19, 2017, the Company issued an additional $200,000 aggregate principal amount of its 6.125% Senior Notes which with the existing $400,000 aggregate principal amount of 6.125% Senior Notes are treated as a single class of notes under the indenture. The net proceeds of the offering, including a premium issue price of 104.125% and after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $206,139 . The Company used the proceeds, in part, to fund an acquisition completed on June 5, 2017 (discussed further in Note 3 ) and for general corporate purposes. 
+The Company may redeem the 6.125% Senior Notes in accordance with the following terms; (1) prior to October 1, 2019 , a redemption of up to 35% of the principal in an amount not greater than the net proceeds from certain equity offerings, and within 180 days of the closing date of such equity offerings, at a redemption price of 106.125% of principal, plus accrued and unpaid interest, if any, to the date of the redemption, if at least 65% of the principal will remain outstanding after such redemption; (2) prior to October 1, 2019 , a redemption of all or part of the principal at a price of 100% of principal of the amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of the redemption; (3) a redemption, in whole or in part, at a redemption price, plus accrued and unpaid interest, if any, to the date of the redemption, (i) of 104.594% of principal if the redemption occurs on or after October 1, 2019 , but before October 1, 2020 , and (ii) of 103.063% of principal if the redemption occurs on or after October 1, 2020 , but before October 1, 2022 , and (iii) of 101.531% of principal if the redemption occurs on or after October 1, 2021, but before October 1, 2022 , and (iv) of 100% of principal if the redemption occurs on or after October 1, 2022 . 
+Following a change of control, each holder of the 6.125% Senior Notes may require the Company to repurchase all or a portion of the 6.125% Senior Notes at a price of 101% of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase. 
+71 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+Term loans 
+On March 11, 2014, the Company entered into a term loan in an aggregate amount of up to $125,000 , including initial commitments of $100,000 and additional availability of $25,000 subject to the consent of two-thirds of the lenders and compliance with financial covenants after giving effect to such increase. The term loan had a maturity date of September 11, 2019 , and was not subject to mandatory prepayments unless new debt or preferred stock was issued. It was prepayable at the Company’s option, subject to a prepayment premium. The prepayment amount was (i) 102% if the prepayment event occurred prior to March 11, 2015, and (ii) 101% if the prepayment event occurred on or after March 15, 2015 but before March 15, 2016, and (iii) 100% for prepayments made on or after March 15, 2016. The term loan was secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor agreement. 
+On October 8, 2014, the term loan described above was repaid in full using proceeds from a new secured second lien term loan (the “Second Lien Loan”) in conjunction with the closing of the Central Midland Acquisition, resulting in a loss on early extinguishment of debt of $3,054 . The Second Lien Loan has a maturity date of October 8, 2021 . The Royal Bank of Canada is Administrative Agent, and participants include several institutional lenders. Borrowings under the Second Lien Loan were subject to interest, calculated at a rate of LIBOR (subject to a floor rate of 1.0% ) plus 7.5% per annum. The Company elected a LIBOR rate based on various tenors, and was incurring interest based on an underlying three-month LIBOR rate, which was last elected in July 2016. The Second Lien Loan was subject to a prepayment premium. The prepayment amount was (i) 102% of principal if the prepayment event occurred prior to October 8, 2016, and (ii) 101% of principal if the prepayment event occurred on or after October 8, 2016 but before October 8, 2017, and (iii) 100% of principal for prepayments made on or after October 8, 2017. The Second Lien Loan was secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor agreement. 
+On October 11, 2016, the Second Lien Loan was repaid in full at the prepayment rate of 101% using proceeds from the sale of the 6.125% Senior Notes, which resulted in a loss on early extinguishment of debt of $12,883 (inclusive of $3,000 in prepayment fees and $9,883 of unamortized debt issuance costs). 
+Restrictive covenants 
+The Company’s Credit Facility and the indenture governing our 6.125% Senior Notes contain various covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. The Company was in compliance with these covenants at December 31, 2017 . 
+Note 6 - Derivative Instruments and Hedging Activities 
+Objectives and strategies for using derivative instruments 
+The Company is exposed to fluctuations in oil and natural gas prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil and natural gas production. The Company utilizes a mix of collars, swaps, put and call options and similar derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes. 
+Counterparty risk and offsetting 
+The use of derivative instruments exposes the Company to the risk that a counterparty will be unable to meet its commitments. While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument; see Note 7 for additional information regarding fair value. 
+The Company executes commodity derivative contracts under master agreements with netting provisions that provide for offsetting assets against liabilities. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement. 
+72 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+Financial statement presentation and settlements 
+Settlements of the Company’s derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets. See Note 7 for additional information regarding fair value. 
+Derivatives not designated as hedging instruments 
+The Company records its derivative contracts at fair value in the consolidated balance sheets and records changes in fair value as a gain or loss on derivative contracts in the consolidated statements of operations. Cash settlements are also recorded as a gain or loss on derivative contracts in the consolidated statements of operations. 
+The following table reflects the fair value of the Company’s derivative instruments for the periods presented: 
+໿ 
+ 
+Balance Sheet Presentation 
+Asset Fair Value 
+Liability Fair Value 
+Net Derivative Fair Value 
+Commodity 
+Classification 
+Line Description 
+12/31/2017 
+12/31/2016 
+12/31/2017 
+12/31/2016 
+12/31/2017 
+12/31/2016 
+Natural gas 
+Current 
+Fair value of derivatives 
+$ 
+406 
+$ 
+— 
+$ 
+— 
+$ 
+(593 
+) 
+$ 
+406 
+$ 
+(593 
+) 
+Oil 
+Current 
+Fair value of derivatives 
+— 
+103 
+(27,744 
+) 
+(17,675 
+) 
+(27,744 
+) 
+(17,572 
+) 
+Oil 
+Non-current 
+Fair value of derivatives 
+— 
+— 
+(1,284 
+) 
+(28 
+) 
+(1,284 
+) 
+(28 
+) 
+Totals 
+$ 
+406 
+$ 
+103 
+$ 
+(29,028 
+) 
+$ 
+(18,296 
+) 
+$ 
+(28,622 
+) 
+$ 
+(18,193 
+) 
+As previously discussed, the Company’s derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated: 
+໿ 
+ 
+For the Year Ended December 31, 2017 
+ 
+Presented without 
+As Presented with 
+ 
+Effects of Netting 
+Effects of Netting 
+Effects of Netting 
+Current assets: Fair value of derivatives 
+406 
+— 
+406 
+ 
+Current liabilities: Fair value of derivatives 
+(27,744 
+) 
+— 
+(27,744 
+) 
+Long-term liabilities: Fair value of derivatives 
+(1,284 
+) 
+— 
+(1,284 
+) 
+໿ 
+ 
+For the Year Ended December 31, 2016 
+ 
+Presented without 
+As Presented with 
+ 
+Effects of Netting 
+Effects of Netting 
+Effects of Netting 
+Current assets: Fair value of derivatives 
+1,836 
+(1,733 
+) 
+103 
+Current liabilities: Fair value of derivatives 
+(20,001 
+) 
+1,733 
+(18,268 
+) 
+Long-term liabilities: Fair value of derivatives 
+(28 
+) 
+— 
+(28 
+) 
+For the periods indicated, the Company recorded the following related to its derivatives in the consolidated statement of operations as gain or loss on derivative contracts: 
+໿ 
+ 
+For the Year Ended December 31, 
+ 
+2017 
+2016 
+2015 
+Oil derivatives 
+Net gain (loss) on settlements 
+$ 
+(9,067 
+) 
+$ 
+17,801 
+$ 
+33,299 
+Net loss on fair value adjustments 
+(11,426 
+) 
+(37,543 
+) 
+(5,403 
+) 
+Total gain (loss) on oil derivatives 
+$ 
+(20,493 
+) 
+$ 
+(19,742 
+) 
+$ 
+27,896 
+Natural gas derivatives 
+Net gain on settlements 
+$ 
+594 
+$ 
+102 
+$ 
+1,717 
+Net gain (loss) on fair value adjustments 
+998 
+(593 
+) 
+(1,255 
+) 
+Total gain (loss) on natural gas derivatives 
+$ 
+1,592 
+$ 
+(491 
+) 
+$ 
+462 
+ 
+Total gain (loss) on oil & natural gas derivatives 
+$ 
+(18,901 
+) 
+$ 
+(20,233 
+) 
+$ 
+28,358 
+73 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+Derivative positions 
+Listed in the tables below are the outstanding oil and natural gas derivative contracts as of December 31, 2017 : 
+໿ 
+For the Full Year of 
+For the Full Year of 
+Oil contracts (WTI) 
+2018 
+2019 
+Swap contracts 
+Total volume (MBbls) 
+2,009 
+— 
+Weighted average price per Bbl 
+$ 
+51.78 
+$ 
+— 
+Collar contracts (two-way collars) 
+Total volume (MBbls) 
+365 
+— 
+Weighted average price per Bbl 
+Ceiling (short call) 
+$ 
+60.50 
+$ 
+— 
+Floor (long put) 
+$ 
+50.00 
+$ 
+— 
+Collar contracts combined with short puts (three-way collars) 
+Total volume (MBbls) 
+3,468 
+730 
+Weighted average price per Bbl 
+Ceiling (short call option) 
+$ 
+60.86 
+$ 
+58.50 
+Floor (long put option) 
+$ 
+48.95 
+$ 
+50.00 
+Short put option 
+$ 
+39.21 
+$ 
+40.00 
+For the Full Year of 
+For the Full Year of 
+Oil contracts (Midland basis differential) 
+2018 
+2019 
+Swap contracts 
+Volume (MBbls) 
+5,289 
+— 
+Weighted average price per Bbl 
+$ 
+(0.86 
+) 
+$ 
+— 
+ 
+For the Full Year of 
+For the Full Year of 
+Natural gas contracts 
+2018 
+2019 
+Collar contracts (Henry Hub, two-way collars) 
+Total volume (BBtu) 
+720 
+— 
+Weighted average price per MMBtu 
+Ceiling (short call option) 
+$ 
+3.84 
+$ 
+— 
+Floor (long put option) 
+$ 
+3.40 
+$ 
+— 
+Subsequent Event 
+The following derivative contracts were executed after December 31, 2017 and before February 23, 2018: 
+For the Full Year of 
+For the Full Year of 
+Oil contracts (WTI) 
+2018 
+2019 
+Collar contracts combined with short puts (three-way collars) 
+Total volume (MBbls) 
+— 
+1,095 
+Weighted average price per Bbl 
+Ceiling (short call option) 
+$ 
+— 
+$ 
+65.00 
+Floor (long put option) 
+$ 
+— 
+$ 
+55.00 
+Short put option 
+$ 
+— 
+$ 
+45.00 
+Natural gas contracts 
+Swap contracts (Henry Hub) 
+Total volume (BBtu) 
+3,366 
+— 
+Weighted average price per MMBtu 
+$ 
+2.95 
+$ 
+— 
+Note 7 - Fair Value Measurements 
+The fair value hierarchy included in GAAP gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable, and these valuations have the lowest priority. 
+74 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+Fair value of financial instruments 
+Cash, cash equivalents, and restricted investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments. 
+Debt. The carrying amount of the Company’s floating-rate debt approximated fair value because the interest rates were variable and reflective of market rates. 
+໿ 
+ 
+2017 
+2016 
+ 
+Carrying Value 
+Fair Value 
+Carrying Value 
+Fair Value 
+Credit Facility (a) 
+$ 
+25,000 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+6.125% Senior Notes (b) 
+595,196 
+618,000 
+390,219 
+412,000 
+Total 
+$ 
+620,196 
+$ 
+618,000 
+$ 
+390,219 
+$ 
+412,000 
+(a) 
+Floating-rate debt. 
+(b) 
+The fair value was based upon Level 2 inputs. See Note 5 for additional information about the Company’s 6.125% Senior Notes. 
+Assets and liabilities measured at fair value on a recurring basis 
+Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheet. The following methods and assumptions were used to estimate fair value: 
+Commodity derivative instruments. The fair value of commodity derivative instruments is derived using an income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. The Company believes that the majority of the inputs used to calculate the commodity derivative instruments fall within Level 2 of the fair value hierarchy based on the wide availability of quoted market prices for similar commodity derivative contracts. See Note 6 for additional information regarding the Company’s derivative instruments. 
+The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis: 
+December 31, 2017 
+Classification 
+Level 1 
+Level 2 
+Level 3 
+Total 
+Assets 
+Derivative financial instruments 
+Fair value of derivatives 
+$ 
+— 
+$ 
+406 
+$ 
+— 
+$ 
+406 
+Liabilities 
+Derivative financial instruments 
+Fair value of derivatives 
+— 
+(29,028 
+) 
+— 
+(29,028 
+) 
+Total net liabilities 
+$ 
+— 
+$ 
+(28,622 
+) 
+$ 
+— 
+$ 
+(28,622 
+) 
+ 
+December 31, 2016 
+Classification 
+Level 1 
+Level 2 
+Level 3 
+Total 
+Assets 
+Derivative financial instruments 
+Fair value of derivatives 
+$ 
+— 
+$ 
+103 
+$ 
+— 
+$ 
+103 
+Liabilities 
+Derivative financial instruments 
+Fair value of derivatives 
+— 
+(18,296 
+) 
+— 
+(18,296 
+) 
+Total net liabilities 
+$ 
+— 
+$ 
+(18,193 
+) 
+$ 
+— 
+$ 
+(18,193 
+) 
+Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis 
+Acquisitions. The Company determines the fair value of the assets acquired and liabilities assumed using the income approach based on expected discounted future cash flows from estimated reserve quantities, costs to produce and develop reserves, and oil and natural gas forward prices. The future net revenues are discounted using a weighted average cost of capital. The discounted future net revenues of proved undeveloped and probable reserves are reduced by an additional reserve adjustment factor to compensate for the inherent risk of estimating the value of unevaluated properties. The fair value measurements were based on Level 1, Level 2 and Level 3 inputs. 
+Note 8 – Employee Benefit Plans 
+The Company utilizes various forms of incentive compensation designed to align the interest of the executives and employees with those of its stockholders. Tabular disclosures related to the share-based awards are presented in Note 9 . The narrative that follows provides a brief description of each plan, summarizes the overall status of each plan and discusses current year awards under each plan: 
+75 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+Savings and Protection Plan (“401(k) Plan”) 
+The 401(k) Plan provides employees with the option to defer receipt of a portion of their compensation, and the Company may, at its discretion, match a portion of the employee’s deferral with cash. The Company may also elect, at its discretion, to contribute a non-matching amount in cash and Company common stock to employees. The amounts held under the 401(k) Plan are invested in various funds maintained by a third party in accordance with the directions of each employee. An employee is fully vested, including Company discretionary contributions, immediately upon participation in the 401(k) Plan. The total amounts contributed by the Company, including the value of the common stock contributed, were $1,292 , $1,018 and $999 in the years 2017 , 2016 and 2015 , respectively. 
+2011 Omnibus Incentive Plan (the “2011 Plan”) 
+The 2011 Plan, which became effective May 12, 2011 following shareholder approval, authorized and reserved for issuance 2,300,000 shares of common stock, which may be issued upon exercise of vested stock options and/or the vesting of any other share-based equity award that is granted under this plan. The 2011 Plan is the Company’s only active plan, and included a provision at inception whereby all remaining, un-issued and authorized shares from the Company’s previous share-based incentive plans became issuable under the 2011 Plan. This transfer provision resulted in the transfer of an additional 841,000 shares into the plan, increasing the quantity authorized and reserved for issuance under the 2011 Plan to 3,141,000 at the inception of the 2011 Plan. Another provision provided that shares, which would otherwise become available for issuance under the previous plans as a result of vesting and/or forfeiture of any equity awards existing as of May 12, 2012, would also increase the authorized shares available to the 2011 Plan. 
+At the 2015 Annual Meeting of Shareholders, the Company’s shareholders approved the First Amendment to the Callon Petroleum Company 2011 Omnibus Incentive Plan (the “First Amendment”), which provided for (i) an increase in the number of shares of the Company’s common stock available for grant under the Plan by 2,000,000 shares from 2,300,000 shares to 4,300,000 shares, (ii) the adoption of a “double trigger” meaning that, in the event of a Company change in control, early vesting or payment occurs only if a change in control occurs and the executive’s employment is terminated or constructively terminated, and (iii) the elimination of the adding back of terminated options and stock appreciation rights shares for future grants. The First Amendment was made effective as of May 14, 2015. Including the transfer provision mentioned above, the quantity authorized and reserved for issuance under the 2011 Plan is 5,141,000 as of the effective date of the First Amendment. As of December 31, 2017 , the 2011 Plan had 1,338,356 shares remaining and eligible for future issuance. 
+RSU equity awards . RSU equity awards issued under the 2011 Plan may be subject to various vesting, accelerated vesting, and forfeiture provisions upon the occurrence of certain events. RSU equity awards under the 2011 Plan generally vest over time but may also be subject to attaining a specified performance metrics and may vest immediately or cliff vest at a specified date. The Company will recognize expense on the grant date for all immediately vesting awards, while it will recognize expense ratably over the requisite service (i.e. vesting) period for both cliff and ratably vesting awards. 
+For market-based RSU equity awards, the Company recognizes expense based on the fair value of the awards at the grant date. Awards with a market-based provision do not allow for the reversal of previously recognized expense, even if the market metric is not achieved and no shares ultimately vest or are awarded. Market-based RSU equity awards that vest are based on a calculation that compares the Company’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between 0% and 200% of the base units awarded. 
+Cash-settled RSU awards. Certain of the Company’s RSU awards require cash settlement. Cash-settled RSU awards are accounted for as liabilities as the Company is contractually obligated to settle these awards in cash. Changes in the fair value of cash-settleable awards are recorded as adjustments to compensation expense. 
+A significant portion of the Company’s cash-settled RSU awards include a market-based vesting condition that determines the actual number of units that will ultimately vest. The number of RSUs that vest is based on a calculation that compares the Company’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between 0% and 200% of the base units awarded. The fair value of the Company’s market-based RSU awards is calculated using a Monte Carlo valuation model, which considers such inputs as the Company’s and its peer group’s stock prices, a risk-free interest rate, and an estimated volatility for the Company and its peer group. 
+Note 9 - Share-Based Compensation 
+As discussed in Note 8 , the Company grants various forms of share-based compensation awards to employees of the Company and its subsidiaries and to non-employee members of the Board of Directors. At December 31, 2017 , shares available for future share-based awards, including stock options or restricted stock grants, under the Company’s only active plan, the 2011 Plan, were 1,338,356 . 
+76 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+The following table presents share-based compensation expense for each respective period: 
+໿ 
+ 
+For the Year Ended December 31, 
+ 
+2017 
+2016 
+2015 
+Share-based compensation cost for: 
+Equity-based 
+Liability-based 
+Equity-based 
+Liability-based 
+Equity-based 
+Liability-based 
+RSU equity awards (a) 
+$ 
+10,225 
+$ 
+— 
+$ 
+4,536 
+$ 
+— 
+$ 
+3,797 
+$ 
+— 
+Cash-settleable RSU awards (a) 
+— 
+4,294 
+— 
+12,285 
+— 
+11,437 
+401(k) CPE stock fund contributions 
+313 
+— 
+277 
+— 
+266 
+— 
+Total share-based compensation cost (b) 
+$ 
+10,538 
+$ 
+4,294 
+$ 
+4,813 
+$ 
+12,285 
+$ 
+4,063 
+$ 
+11,437 
+(a) 
+Includes the settlement of the outstanding share-based award agreements of the Company’s former Chief Executive Officer, resulting in $6,351 recorded on the Consolidated Statements of Operations as Settled share-based awards for the year ended December 31, 2017 . 
+(b) 
+The portion of this share-based compensation cost that was included in general and administrative expense totaled $5,194 , $9,722 and $9,299 for the years ended December 31, 2017 , 2016 and 2015 , respectively, and the portion capitalized to oil and gas properties was $3,287 , $7,376 and $6,201 , for the years ended December 31, 2017 , 2016 , and 2015 , respectively. 
+The following table presents the unrecognized compensation cost for the indicated periods: 
+ 
+December 31, 
+Unrecognized compensation cost related to: 
+2017 
+2016 
+2015 
+Unvested RSU equity awards 
+$ 
+13,158 
+$ 
+7,276 
+$ 
+5,208 
+Unvested cash-settleable RSU awards 
+3,776 
+8,948 
+4,728 
+The Company’s unrecognized compensation cost related to unvested RSU equity awards and cash-settleable RSU awards is expected to be recognized over a weighted-average period of two years. 
+The following table summarizes the Company’s liability for cash-settled RSU awards for the periods indicated: 
+ 
+December 31, 
+Consolidated Balance Sheets Classification 
+2017 
+2016 
+Cash-settled RSU awards (current) 
+$ 
+4,621 
+$ 
+8,919 
+Cash-settled RSU awards (non-current) 
+3,490 
+8,071 
+Total cash-settled RSU awards 
+$ 
+8,111 
+$ 
+16,990 
+Stock Options 
+The Company issued no stock options for the past three years and had no options vest or forfeit during 2017 . Additionally, no options were exercised, and 15,000 options expired unexercised during the year. As of December 31, 2017 , the Company had no options outstanding. As of December 31, 2016 , the Company had 15,000 options outstanding and exercisable at a weighted average exercise price per option of $14.37 , with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 0.3 years . As of December 31, 2015 , the Company had 15,000 options outstanding and exercisable at a weighted average exercise price per option of $14.37 , with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 1.3 years . 
+77 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+Restricted Stock Units 
+The following table represents unvested restricted stock activity for the year ended December 31, 2017 : 
+ 
+Weighted average 
+(shares in 000s) 
+Number of Shares 
+Grant-Date Fair Value per Share 
+Years Over Which Expense is Expected to be Recognized 
+Outstanding at the beginning of the period 
+1,448 
+$ 
+10.81 
+Granted (a)(b) 
+1,173 
+12.25 
+Vested (b)(c) 
+(797 
+) 
+11.35 
+Forfeited 
+(34 
+) 
+9.57 
+Outstanding at the end of the period 
+1,790 
+$ 
+11.54 
+1.94 
+(a) 
+Includes 89 market-based RSUs that will vest at a range of 0% - 200% . See Note 8 for additional information about market-based RSU equity awards. 
+(b) 
+Includes 73 market-based RSUs that were granted and subsequently vested at 142% of their issued units in 2017. 
+(c) 
+The fair value of shares vested was $9,045 . 
+For the year ended December 31, 2016 , the Company granted 684,090 RSUs with a weighted average grant-date fair value of $12.63 per share. The fair value of shares vested during 2016 was $2,608 . For the year ended December 31, 2015 , the Company granted 559,556 RSUs with a weighted average grant-date fair value of $8.98 per share. The fair value of shares vested during 2015 was $5,425 . 
+As of December 31, 2017 , the Company had the following cash-settleable RSUs outstanding (including those that are not based on a market condition): 
+(shares in 000s) 
+Base Units Outstanding 
+Potential Minimum Units Vesting 
+Potential Maximum Units Vesting 
+Vesting in 2018 
+165 
+13 
+316 
+Vesting in 2019 
+200 
+17 
+384 
+Vesting in 2020 
+— 
+— 
+— 
+Other 
+203 
+203 
+203 
+Total cash-settleable RSUs 
+568 
+233 
+903 
+For the year ended December 31, 2017 , 335,471 market-based cash-settled RSUs subject to the peer market-based vesting described in Note 8 vested at between 142% to 200% of their issued units, depending on the date of the vesting, resulting in cash payments of $3,986 in 2017 and payable amounts of $3,062 in 2018 . Also during 2017 , 43,031 non-market-based cash settled RSUs vested, resulting in cash payments of $526 in 2017 . During 2016 , 281,792 market-based cash-settled RSUs subject to the peer market-based vesting described above vested at 200% of their issued units, resulting in cash payments of $8,662 in 2017 . Also during 2016 , 45,282 non-market-based cash settled RSUs vested, resulting in cash payments of $493 in 2016 . See Note 8 for additional information regarding cash-settleable RSUs. 
+Note 10 – Equity Transactions 
+10% Series A Cumulative Preferred Stock (“Preferred Stock”) 
+Holders of the Company’s Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10% per annum of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share). Dividends are payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by our Board of Directors. Preferred Stock dividends were $7,295 , $7,295 and $7,895 in 2017 , 2016 and 2015 , respectively. 
+The Preferred Stock has no stated maturity and is not subject to any sinking fund or other mandatory redemption. On or after May 30, 2018, the Company may, at its option, redeem the Preferred Stock, in whole or in part, by paying $50.00 per share, plus any accrued and unpaid dividends to the redemption date. 
+Following a change of control in which the Company or the acquirer no longer have a class of common securities listed on a national exchange, the Company will have the option to redeem the Preferred Stock, in whole but not in part for $50.00 per share in cash, plus accrued and unpaid dividends (whether or not declared), to the redemption date. If the Company does not exercise its option to redeem the Preferred Stock upon such change of control, the holders of the Preferred Stock have the option to convert the Preferred Stock into 
+78 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+a number of shares of the Company’s common stock based on the value of the common stock on the date of the change of control as determined under the certificate of designations for the Preferred Stock. If the change of control occurred on December 31, 2017 , and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of $12.15 as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately 4.1 shares of common stock. If the Company exercises its redemption rights relating to shares of Preferred Stock, the holders of Preferred Stock will not have the conversion right described above. 
+On February 4, 2016, the Company exchanged a total of 120,000 shares of Preferred Stock for 719,000 shares of common stock. As of December 31, 2017 , the Company had 1,458,948 shares of its Preferred Stock issued and outstanding. 
+Common Stock 
+On December 19, 2016, the Company completed an underwritten public offering of 40,000,000 shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $634,934 . Proceeds from the offering were used to substantially fund the Ameredev Transaction, described in Note 3 . 
+On September 6, 2016, the Company completed an underwritten public offering of 29,900,000 shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $421,864 . Proceeds from the offering were used to substantially fund the Plymouth Transaction, described in Note 3 . 
+On May 26, 2016, the Company issued 9,333,333 shares of common stock to partially fund the Big Star Transaction, described in Note 3 , at an assumed offering price of $11.74 per share, which is the last reported sale price of our common stock on the New York Stock Exchange on that date. 
+On April 25, 2016, the Company completed an underwritten public offering of 25,300,000 shares of its common stock for total net proceeds (after the underwriter’s discounts and commissions and estimated offering expenses) of approximately $205,869 . Proceeds from the offering were used to fund the Big Star Transaction, described in Note 3 , and other working interest acquisitions. 
+On March 9, 2016, the Company completed an underwritten public offering of 15,250,000 shares of its common stock for total net proceeds (after the underwriting discounts and estimated offering costs) of approximately $94,948 . Proceeds from the offering were used to pay down the balance on the Company’s Credit Facility and for general corporate purposes. 
+On November 16, 2015, the Company completed an underwritten public offering of 12,000,000 shares of its common stock at $8.40 per share, before underwriting discounts, and the exercise in full by the underwriters of their option to purchase 1,800,000 additional shares of common stock at $8.40 per share, before underwriting discounts. The Company received net proceeds of approximately $109,864 , after the underwriting discounts and estimated offering costs, which were used to repay amounts outstanding under the Credit Facility. 
+On March 13, 2015, the Company completed an underwritten public offering of 9,000,000 shares of its common stock at $6.55 per share, before underwriting discounts, and the exercise in full by the underwriters of their option to purchase 1,350,000 additional shares of common stock at $6.55 per share, before underwriting discounts. The Company received net proceeds of approximately $65,595 , after the underwriting discounts and estimated offering costs, which were used to repay amounts outstanding under the Credit Facility. 
+79 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+Note 11 - Income Taxes 
+The following table presents Callon’s deferred tax assets and liabilities with respect to its carryforwards and other temporary differences: 
+ 
+As of December 31, 
+ 
+2017 
+2016 
+Deferred tax asset (a) 
+Federal net operating loss carryforward (b) 
+$ 
+97,437 
+$ 
+135,711 
+Statutory depletion carryforward 
+5,381 
+8,843 
+Alternative minimum tax credit carryforward (c) 
+52 
+104 
+Asset retirement obligations 
+572 
+1,181 
+Derivatives 
+6,186 
+6,456 
+Unvested RSU equity awards 
+1,749 
+2,092 
+Other 
+2,401 
+4,376 
+Deferred tax asset before valuation allowance 
+113,778 
+158,763 
+Deferred tax liability (a) 
+Oil and natural gas properties 
+54,264 
+18,661 
+Total deferred tax liability 
+54,264 
+18,661 
+Net deferred tax asset before valuation allowance 
+59,514 
+140,102 
+Less: Valuation allowance 
+(60,919 
+) 
+(140,192 
+) 
+Net deferred tax liability 
+$ 
+(1,405 
+) 
+$ 
+(90 
+) 
+(a) 
+Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The 2017 Tax Reform lowered the U.S. federal corporate tax rate from 35% to 21%, which caused the Company to remeasure its deferred income tax assets and liabilities at the new rate. As of December 31, 2017 and 2016 , the Company’s tax rate applied was 21% and 35% , respectively. As a result of the change in the applied tax rate on our deferred tax assets and liabilities, the Company recorded a $40,611 reduction in our net deferred tax assets with a corresponding reduction in our valuation allowance. 
+(b) 
+As of December 31, 2016, the Company’s $135,711 deferred tax asset related to NOL carryforwards was net of $9,288 of unrealized excess tax benefits related to stock based compensation. 
+(c) 
+The 2017 Tax Reform repealed the Alternative Minimum Tax (“AMT”) effective for years beginning after December 31, 2017. The result had an immaterial impact in income. 
+U.S. federal net operating loss (“NOL”) utilization was changed by the 2017 Tax Reform for losses incurred in tax years beginning after December 31, 2017. Post-2017 NOLs do not have an expiration period, but may only offset 80% of the Company’s taxable income in any year of utilization. If not utilized, the Company’s existing federal NOL carryforwards, unaffected by the 2017 Tax Reform, will expire as follows: ໿ 
+ 
+Year Expiring 
+ 
+Total 
+2018-2023 
+2024-2026 
+2027-2029 
+2030-2032 
+2033-2037 
+Federal NOL carryforwards 
+$ 
+463,985 
+$ 
+111,431 
+$ 
+14,408 
+$ 
+41,379 
+$ 
+42,158 
+$ 
+254,609 
+As a result of the write-down of oil and natural gas properties discussed in Notes 2 and 13 , the Company has incurred a cumulative three year loss. Because of the impact the cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, the Company assessed the ability to realize its deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, the Company established a valuation allowance for a portion of the deferred tax asset. The valuation allowance was $60,919 as of December 31, 2017 . 
+The Company had no significant unrecognized tax benefits at December 31, 2017 . Accordingly, the Company does not have any interest or penalties related to uncertain tax positions. However, if interest or penalties were to be incurred related to uncertain tax positions, such amounts would be recognized in income tax expense. Tax periods for years 2004 through 2017 remain open to examination by the federal and state taxing jurisdictions to which the Company is subject. 
+The Company provides for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses, restricted stock windfalls, and state income taxes. The following table presents a reconciliation of the reported amount of income tax expense to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income from continuing operations: 
+໿ 
+80 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+ 
+For the Year Ended December 31, 
+Components of income tax rate reconciliation 
+2017 
+2016 
+2015 
+Income tax expense computed at the statutory federal income tax rate 
+35 
+% 
+35 
+% 
+35 
+% 
+State taxes net of federal benefit 
+1 
+% 
+— 
+% 
+1 
+% 
+Section 162(m) 
+— 
+% 
+(1 
+)% 
+(1 
+)% 
+Valuation allowance 
+(35 
+)% 
+(34 
+)% 
+(54 
+)% 
+Effective income tax rate 
+1 
+% 
+— 
+% 
+(19 
+)% 
+ 
+For the Year Ended December 31, 
+Components of income tax expense 
+2017 
+2016 
+2015 
+Current federal income tax benefit 
+$ 
+(48 
+) 
+$ 
+(104 
+) 
+$ 
+— 
+Deferred federal income tax benefit 
+(45 
+) 
+— 
+(69,087 
+) 
+Deferred state income tax (benefit) expense 
+1,366 
+90 
+(1,282 
+) 
+Valuation allowance 
+— 
+— 
+108,843 
+Total income tax (benefit) expense 
+$ 
+1,273 
+$ 
+(14 
+) 
+$ 
+38,474 
+໿ 
+. 
+Note 12 - Asset Retirement Obligations 
+The table below summarizes the activity for the Company’s asset retirement obligations: 
+ 
+For the Year Ended December 31, 
+ 
+2017 
+2016 
+Asset retirement obligations at January 1, 2017 and 2016, respectively 
+$ 
+6,661 
+$ 
+5,107 
+Accretion expense 
+677 
+958 
+Liabilities incurred 
+278 
+84 
+Liabilities settled 
+(711 
+) 
+(2,378 
+) 
+Revisions to estimate (a) 
+(885 
+) 
+2,890 
+Asset retirement obligations at end of period 
+6,020 
+6,661 
+Less: Current asset retirement obligations 
+(1,295 
+) 
+(2,729 
+) 
+Long-term asset retirement obligations at December 31, 2017 and 2016, respectively 
+$ 
+4,725 
+$ 
+3,932 
+(a) 
+Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment. 
+Certain of the Company’s operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded on the Consolidated Balance Sheets at December 31, 2017 and 2016 as long-term restricted investments were $3,372 and $3,332 , respectively. These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties. 
+81 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+Note 13 – Supplemental Information on Oil and Natural Gas Operations (Unaudited) 
+The following table discloses certain financial data relating to the Company’s oil and natural gas activities, all of which are located in the United States. 
+ 
+For the Year Ended December 31, 
+ 
+2017 
+2016 
+2015 
+Evaluated Properties (a) 
+Beginning of period balance 
+$ 
+2,754,353 
+$ 
+2,335,223 
+$ 
+2,077,985 
+Capitalized G&A expenses 
+11,982 
+12,222 
+10,529 
+Property acquisition costs (b) 
+144,358 
+216,561 
+26,726 
+Exploration costs 
+239,453 
+38,612 
+81,320 
+Development costs 
+279,424 
+151,735 
+138,663 
+End of period balance 
+$ 
+3,429,570 
+$ 
+2,754,353 
+$ 
+2,335,223 
+Unevaluated Properties (a)(c) 
+Beginning of period balance 
+$ 
+668,721 
+$ 
+132,181 
+$ 
+142,525 
+Property acquisition costs (b) 
+590,308 
+548,673 
+5,520 
+Exploration costs 
+6,374 
+8,631 
+4,576 
+Capitalized interest expenses 
+33,783 
+19,857 
+10,459 
+Transfers to Evaluated Properties 
+(131,170 
+) 
+(40,621 
+) 
+(30,899 
+) 
+End of period balance 
+$ 
+1,168,016 
+$ 
+668,721 
+$ 
+132,181 
+Accumulated depreciation, depletion and amortization 
+Beginning of period balance 
+$ 
+1,947,673 
+$ 
+1,756,018 
+$ 
+1,478,355 
+Provision charged to expense 
+115,897 
+71,330 
+69,228 
+Write-down of oil and natural gas properties (a) 
+— 
+95,788 
+208,435 
+Sale of mineral interests and equipment (a) 
+20,525 
+24,537 
+— 
+End of period balance 
+$ 
+2,084,095 
+$ 
+1,947,673 
+$ 
+1,756,018 
+(a) 
+The Company uses the full cost method of accounting for its exploration and development activities. See the Company’s accounting policy about oil and natural gas properties in Note 2 for details on the full cost method of accounting. 
+(b) 
+See Note 3 in the Footnotes to the Financial Statements for additional information about the Company’s significant acquisitions. 
+(c) 
+Unevaluated property costs primarily include lease acquisition costs, unevaluated drilling costs, seismic, capitalized interest expenses and certain overhead costs related to exploration and development. These costs are directly related to the acquisition and evaluation of unproved properties. The excluded costs and related reserves are included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined. The majority of these costs are primarily associated with the Company’s focus areas of its future development program and are expected to be evaluated over ten to fifteen years. The Company’s unevaluated property balance of $1,168,016 as of December 31, 2017 , consisted of $121,096 , $447,925 , $26,648 and $572,347 of costs attributable to our Monarch, WildHorse, Ranger and Spur operating areas, respectively. 
+Subsequent to December 31, 2017 , and through February 23, 2018 , the Company drilled eight gross ( 6.0 net) horizontal wells and completed five gross ( 3.0 net) horizontal wells and had three gross ( 3.0 net) horizontal wells awaiting completion. 
+Depletion per unit-of-production, on a BOE basis, amounted to $13.82 , $12.81 and $19.74 for the years ended December 31, 2017 , 2016 , and 2015 , respectively. Lease operating expenses per unit-of-production, on a BOE basis, amounted to $5.96 , $6.88 , and $7.71 for the years ended December 31, 2017 , 2016 , and 2015 , respectively. 
+Estimated Reserves 
+The Company’s proved oil and natural gas reserves at December 31, 2017 , 2016 and 2015 have been estimated by DeGolyer and MacNaughton, the Company’s current independent petroleum engineers. The reserves were prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions. 
+There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only, and should not be deemed exact. In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company’s oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves. 
+82 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+The following tables disclose changes in the estimated net quantities of oil and natural gas reserves, all of which are located onshore within the continental United States: 
+໿ 
+ 
+For the Year Ended December 31, 
+Proved developed and undeveloped reserves: 
+2017 
+2016 
+2015 
+Oil (MBbls): 
+Beginning of period 
+71,145 
+43,348 
+25,733 
+Revisions to previous estimates 
+(5,171 
+) 
+(5,738 
+) 
+(1,632 
+) 
+Purchase of reserves in place 
+8,388 
+25,054 
+2,932 
+Sale of reserves in place 
+— 
+(1,718 
+) 
+(23 
+) 
+Extensions and discoveries 
+39,267 
+14,479 
+19,127 
+Production 
+(6,557 
+) 
+(4,280 
+) 
+(2,789 
+) 
+End of period 
+107,072 
+71,145 
+43,348 
+Natural Gas (MMcf): 
+Beginning of period 
+122,611 
+65,537 
+42,548 
+Revisions to previous estimates 
+6,336 
+13,929 
+4,870 
+Purchase of reserves in place 
+12,711 
+36,474 
+2,915 
+Sale of reserves in place 
+— 
+(2,765 
+) 
+(105 
+) 
+Extensions and discoveries 
+48,648 
+17,194 
+19,621 
+Production 
+(10,896 
+) 
+(7,758 
+) 
+(4,312 
+) 
+End of period 
+179,410 
+122,611 
+65,537 
+ 
+For the Year Ended December 31, 
+Proved developed reserves: 
+2017 
+2016 
+2015 
+Oil (MBbls): 
+Beginning of period 
+32,920 
+22,257 
+14,006 
+End of period 
+51,920 
+32,920 
+22,257 
+Natural gas (MMcf): 
+Beginning of period 
+61,871 
+38,157 
+25,171 
+End of period 
+104,389 
+61,871 
+38,157 
+MBOE: 
+Beginning of period 
+43,232 
+28,617 
+18,201 
+End of period 
+69,318 
+43,232 
+28,617 
+Proved undeveloped reserves: 
+Oil (MBbls): 
+Beginning of period 
+38,225 
+21,091 
+11,727 
+End of period 
+55,152 
+38,225 
+21,091 
+Natural gas (MMcf): 
+Beginning of period 
+60,740 
+27,380 
+17,377 
+End of period 
+75,021 
+60,740 
+27,380 
+MBOE: 
+Beginning of period 
+48,348 
+25,654 
+14,623 
+End of period 
+67,656 
+48,348 
+25,654 
+Total Proved Reserves: The Company ended 2017 with estimated net proved reserves of 136,974 MBOE, representing a 50% increase over 2016 year-end estimated net proved reserves of 91,580 MBOE. The Company added 57,881 MBOE primarily from the Company’s acquisition and development efforts in the Permian Basin, where it drilled a total of 49 gross ( 38.2 net) wells. This increase was primarily offset by 2017 production and revisions. The decrease from revisions was primarily due to the removal of 13 proved undeveloped locations as a result of a change in the Company’s development and drilling plans within its operating areas and the removal of certain proved developed vertical well locations.. 
+The Company ended 2016 with estimated net proved reserves of 91,580 MBOE, representing a 69% increase over 2015 year-end estimated net proved reserves of 54,271 MBOE. The Company added 48,477 MBOE primarily from the Company’s acquisition and development efforts in the Permian Basin, where it drilled a total of 29 gross ( 20.9 net) wells. This increase was primarily offset by 11,168 MBOE related to divestitures, 2016 production and revisions primarily due to pricing. 
+The Company ended 2015 with estimated net proved reserves of 54,271 MBOE, representing a 65% increase over 2014 year-end estimated net proved reserves of 32,824 MBOE. The increase was primarily due the Company’s development of its properties in the Permian Basin, 
+83 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+where it drilled a total of 36 gross ( 27.1 net) wells, and acquisitions made during 2015 . This increase was primarily offset by 2015 production and revisions. 
+Extrapolation of performance history and material balance estimates were utilized by the Company’s independent petroleum and geological firm to project future recoverable reserves for the producing properties where sufficient history existed to suggest performance trends and where these methods were applicable to the subject reservoirs. The projections for the remaining producing properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to nonproducing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production, and to a small extent, horizontal PDP and PUD categories. 
+Proved Undeveloped Reserves: The Company annually reviews its proved undeveloped reserves (“PUDs”) to ensure an appropriate plan for development exists. Generally, reserves for the Company’s properties are booked as PUDs only if the Company has plans to convert the PUDs into proved developed reserves within five years of the date they are first booked as PUDs. 
+The Company’s PUDs increased 40% to 67,656 MBOE from 48,348 MBOE at December 31, 2017 and 2016 , respectively. The Company added 3,267 MBOE to its PUDs, primarily from acquisitions in the Permian Basin, and added 30,198 MBOE from the continued horizontal development of its Permian Basin properties. The increase in the Permian Basin PUDs was partially offset by 5,876 MBOE of revisions primarily due to the removal of 13 PUD locations as a result of a change in the Company’s development and drilling plans within its operating areas and downward revisions to its current PUD locations. In addition, the increase in Permian Basin PUDs was offset by the reclassification of 8,281 MBOE, or 17% , included in the year-end 2016 PUDs, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately $57,019 , net. 
+The Company’s PUDs increased 88% to 48,348 MBOE from 25,654 MBOE at December 31, 2016 and 2015 , respectively. The Company added 17,482 MBOE to its PUDs, primarily from acquisitions in the Permian Basin, net of divestitures, and added 12,035 MBOE from the continued horizontal development of its Permian Basin properties, net of revisions. The increase in Permian Basin PUDs was partially offset by the reclassification of 6,823 MBOE, or 27% , included in the year-end 2015 PUDs, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately $43,415 , net. 
+The Company’s PUDs increased 75% to 25,654 MBOE from 14,623 MBOE at December 31, 2015 and 2014 , respectively. The Company added 13,774 MBOE to its PUDs, net of revisions, primarily from the continued horizontal development of its Permian Basin properties and from acquisitions in the Permian Basin. The increase in Permian Basin PUDs was partially offset by the reclassification of 2,742 MBOE, or 19% , included in the year-end 2014 PUDs, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately $55,933 , net. 
+Standardized Measure 
+The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2017 . You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Prices are based on the preceding 12 -months’ average price based on closing prices on the first day of each month. The following table summarizes the average 12 -month oil and natural gas prices net of differentials for the respective periods: 
+໿ 
+ 
+2017 
+2016 
+2015 
+Average 12-month price, net of differentials, per Mcf of natural gas (a) 
+$ 
+3.47 
+$ 
+2.71 
+$ 
+2.73 
+Average 12-month price, net of differentials, per barrel of oil (b) 
+$ 
+49.48 
+$ 
+40.03 
+$ 
+47.25 
+(a) 
+Includes a high Btu content of separator natural gas and adjustments to reflect the Btu content, transportation charges and other fees specific to the individual properties. 
+(b) 
+Includes adjustments to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality. 
+Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate. 
+໿ 
+84 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+ 
+Standardized Measure 
+ 
+For the Year Ended December 31, 
+ 
+2017 
+2016 
+2015 
+Future cash inflows 
+$ 
+5,920,328 
+$ 
+3,180,005 
+$ 
+2,227,463 
+Future costs 
+Production 
+(1,692,871 
+) 
+(974,667 
+) 
+(827,555 
+) 
+Development and net abandonment 
+(680,948 
+) 
+(384,117 
+) 
+(239,100 
+) 
+Future net inflows before income taxes 
+3,546,509 
+1,821,221 
+1,160,808 
+Future income taxes (a) 
+(166,985 
+) 
+(1,602 
+) 
+— 
+Future net cash flows 
+3,379,524 
+1,819,619 
+1,160,808 
+10% discount factor 
+(1,822,842 
+) 
+(1,009,787 
+) 
+(589,918 
+) 
+Standardized measure of discounted future net cash flows 
+$ 
+1,556,682 
+$ 
+809,832 
+$ 
+570,890 
+໿ 
+(a) 
+As of December 31, 2017 , 2016 , and 2015 the Company’s statutory tax rate applied was 21%, 35% , and 35%, respectively. 
+ 
+Changes in Standardized Measure 
+ 
+For the Year Ended December 31, 
+ 
+2017 
+2016 
+2015 
+Standardized measure at the beginning of the period 
+$ 
+809,832 
+$ 
+570,890 
+$ 
+579,542 
+Sales and transfers, net of production costs 
+(294,172 
+) 
+(150,628 
+) 
+(110,476 
+) 
+Net change in sales and transfer prices, net of production costs 
+176,234 
+(103,136 
+) 
+(286,660 
+) 
+Net change due to purchases and sales of in place reserves 
+129,454 
+260,859 
+37,616 
+Extensions, discoveries, and improved recovery, net of future production and development costs incurred 
+635,000 
+180,228 
+184,469 
+Changes in future development cost 
+36,983 
+82,320 
+108,216 
+Revisions of quantity estimates 
+(79,325 
+) 
+(35,938 
+) 
+(12,625 
+) 
+Accretion of discount 
+80,983 
+57,091 
+62,968 
+Net change in income taxes 
+(20,073 
+) 
+16 
+35,407 
+Changes in production rates, timing and other 
+81,766 
+(51,870 
+) 
+(27,567 
+) 
+Aggregate change 
+746,850 
+238,942 
+(8,652 
+) 
+Standardized measure at the end of period 
+$ 
+1,556,682 
+$ 
+809,832 
+$ 
+570,890 
+Note 14 – Other 
+Commitments and contingencies 
+The Company is involved in various claims and lawsuits incidental to its business. In the opinion of management, the ultimate liability hereunder, if any, will not have a material adverse effect on the financial position or results of operations of the Company. 
+The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment are not expected to have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies hereunder, and claims for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities. 
+Operating leases 
+As of December 31, 2017 , the Company had contracts for five horizontal drilling rigs (the “Cactus Rig 1”, “Cactus Rig 2” “Cactus Rig 3”, “Cactus Rig 4” and “Independence Rig”). The contract terms, as amended through December 31, 2017 , of the Cactus Rig 1 and Cactus Rig 2 will end in January 2020 and February 2021, respectively. The contract terms, as amended in July 2017, of the Cactus Rig 3 that commenced drilling in mid-January 2017, will end in July 2018. Effective April 2017, the Company entered into a contract for the Independence Rig, which commenced drilling in July 2017. The contract terms of the Independence Rig will end in July 2019. Effective November 2017, the Company entered into a contract for the Cactus Rig 4, which commenced drilling in mid-February 2018. The contract terms of the Cactus 4 Rig will end in February 2020. 
+85 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+In March 2015, the Company decided to terminate its one-year contract for a vertical drilling rig (effective April 2015). The Company paid approximately $3,075 in reduced rental payments over the remainder of the lease term, which ended November 2015. The amount was recognized as rig termination fee on the consolidated statements of operations for the year ended December 31, 2015 . 
+໿ 
+Note 15 – Summarized Quarterly Financial Information (Unaudited) 
+2017 
+First Quarter 
+Second Quarter 
+Third Quarter 
+Fourth Quarter 
+Total revenues 
+$ 
+81,363 
+$ 
+82,283 
+$ 
+84,614 
+$ 
+118,214 
+Income from operations 
+32,249 
+23,743 
+31,426 
+54,028 
+Net income 
+47,129 
+33,390 
+17,081 
+22,824 
+Income available to common shares 
+45,305 
+31,566 
+15,257 
+21,001 
+Income per common share - basic 
+$ 
+0.23 
+$ 
+0.16 
+$ 
+0.08 
+$ 
+0.10 
+Income per common share - diluted 
+$ 
+0.22 
+$ 
+0.16 
+$ 
+0.08 
+$ 
+0.10 
+2016 
+First Quarter 
+Second Quarter 
+Third Quarter 
+Fourth Quarter 
+Total revenues 
+$ 
+30,698 
+$ 
+45,145 
+$ 
+55,927 
+$ 
+69,081 
+Income (loss) from operations (a) 
+(34,767 
+) 
+(50,529 
+) 
+16,651 
+21,168 
+Net income (loss) (a) 
+(41,109 
+) 
+(70,097 
+) 
+21,139 
+(1,746 
+) 
+Income (loss) available to common shares 
+(42,933 
+) 
+(71,920 
+) 
+19,315 
+(3,570 
+) 
+Income (loss) per common share - basic 
+$ 
+(0.51 
+) 
+$ 
+(0.61 
+) 
+$ 
+0.14 
+$ 
+(0.02 
+) 
+Income (loss) per common share - diluted 
+$ 
+(0.51 
+) 
+$ 
+(0.61 
+) 
+$ 
+0.14 
+$ 
+(0.02 
+) 
+(a) 
+Loss from operations and net loss for the three months ended March, 31, 2016 and June 30, 2016 included write-downs of oil and natural gas properties of $34,776 and $61,012 , respectively. 
+໿ 
+86 
+Table of Contents 
+ITEM 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure 
+On January 11, 2016, the Audit Committee of the Board of Directors of Callon Petroleum Company (the “Company”) approved the engagement of Grant Thornton LLP (“GT”) as the Company’s independent registered public accounting firm for the year ending December 31, 2016. GT informed the Company that it completed the prospective client evaluation process on January 14, 2016. In connection with the selection of GT, also on January 11, 2016, the Audit Committee informed Ernst & Young LLP (“E&Y”) that they would no longer serve as the Company’s independent registered public accounting firm no later than the date of the filing of the Company’s Form 10-K for the 2015 fiscal year. The Audit Committee made its decision in connection with its annual review of the Company’s independent registered public accounting firm and after soliciting proposals from several accounting firms, including E&Y. 
+During the year ended December 31, 2015 and through January 11, 2016, neither the Company nor anyone on its behalf consulted with GT with respect to either (i) the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on the Registrant’s consolidated financial statements, and neither written nor oral advice was provided to the Company that GT concluded was an important factor considered by the Company in reaching a decision as to any accounting, auditing or financial reporting issue; (ii) any matter that was either the subject of disagreement (as defined in Item 304(a)(l)(iv) of Regulation S-K and the related instructions to Item 304 of Regulations S-K) or a reportable event (as defined by Item 304(a)(l)(v) of Regulation S-K). 
+The report of E&Y on the Company’s consolidated financial statements for the years ended December 31, 2015, did not contain an adverse opinion or disclaimer of an opinion, and was not qualified or modified as to uncertainty, audit scope or accounting principles. 
+Item 9A. Controls and Procedures 
+Disclosure controls and procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) performed an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2017 . 
+Management’s report on internal control over financial reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. generally accepted accounting principles. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2017 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission (2013 framework)(the COSO criteria). Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2017 . 
+Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+The Company’s independent registered public accounting firm has issued an attestation report regarding its assessment of the Company’s internal control over financial reporting as of December 31, 2017 , which follows Part II, Item 9B of this filing. Additionally, the financial statements for the years ended December 31, 2017 and 2016 , covered in this Annual Report on Form 10-K, have been audited by an independent registered public accounting firm, Grant Thornton LLP, whose report is presented immediately preceding the Company’s financial statements included in Part II, Item 8 of this Annual Report on Form 10-K. The financial statements for the year ended December 31, 2015 were audited by the independent registered public accounting firm, Ernst & Young LLP, whose report is presented immediately preceding the company’s financial statements included in Part II, Item 8 of this Annual Report on Form 10-K. 
+Changes in internal control over financial reporting . There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting. 
+87 
+Table of Contents 
+ITEM 9A (T). Controls and Procedures 
+See Item 9A. 
+ITEM 9B. Other Information 
+Submissions of matters to a vote of the security holders. 
+None. 
+88 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+Board of Directors and Stockholders 
+Callon Petroleum Company 
+Opinion on internal control over financial reporting 
+We have audited the internal control over financial reporting of Callon Petroleum Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2017, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2017, and our report dated February 27, 2018 expressed unqualified opinion on those financial statements. 
+Basis for opinion 
+The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s report on internal controls over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+Definition and limitations of internal control over financial reporting 
+A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+/s/ GRANT THORNTON LLP 
+Houston, Texas 
+February 27, 2018 
+89 
+Table of Contents 
+PART III. 
+ITEM 10. Directors, Executive Officers and Corporate Governance 
+For information concerning Item 10, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 10, 2018 , which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+The Company has adopted a code of ethics that applies to the Company’s chief executive officer, chief financial officer and chief accounting officer. The full text of such code of ethics has been posted on the Company’s website at www.callon.com, and is available free of charge in print to any shareholder who requests it. Request for copies should be addressed to the Secretary at mailing address Post Office Box 1287, Natchez, Mississippi 39121. 
+ITEM 11. Executive Compensation 
+For information concerning Item 11, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 10, 2018 , which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+For information concerning the security ownership of certain beneficial owners and management, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 10, 2018 , which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+ITEM 13. Certain Relationships and Related Transactions and Director Independence 
+For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 10, 2018 , which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+ITEM 14. Principal Accountant Fees and Services 
+For information concerning Item 14, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 10, 2018 , which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+90 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Table of Contents 
+PART IV. 
+Item 15. Exhibits 
+The following is an index to the financial statements and financial statement schedules that are filed in Part II, Item 8 of this report on Form 10-K. 
+໿ 
+Exhibit Number 
+Description 
+ 
+Reports of Independent Registered Public Accounting Firms 
+ 
+Consolidated Balance Sheets as of December 31, 2017 and 2016 
+ 
+Consolidated Statements of Operations for each of the three years in the period ended December 31, 2017 
+ 
+Consolidated Statements of Stockholders’ Equity (Deficit) for each of the three years in the period ended December 31, 2017 
+ 
+Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2017 
+ 
+Notes to Consolidated Financial Statements 
+ 
+Schedules other than those listed above are omitted because they are not required, not applicable or the required information is included in the financial statements or notes thereto. 
+2. 
+* 
+Plan of acquisition, reorganization, arrangement, liquidation or succession 
+3. 
+Articles of Incorporation and Bylaws 
+ 
+3.1 
+Certificate of Incorporation of the Company, as amended through May 12, 2016 (incorporated by reference to Exhibit 3.1 of the Company’s Quarterly Report on Form 10-Q, filed on November 3, 2016) 
+ 
+3.2 
+Certificate of Designation of Rights and Preferences of 10.00% Series A Cumulative Preferred Stock (incorporated by reference to Exhibit 3.5 of the Company’s Form 8-A, filed on May 23, 2013) 
+ 
+3.3 
+(a) 
+Bylaws of the Company 
+4. 
+Instruments defining the rights of security holders, including indentures 
+ 
+4.1 
+(a) 
+Specimen Common Stock Certificate 
+ 
+4.2 
+Certificate for the Company’s 10.00% Series A Cumulative Preferred Stock (incorporated by reference to Exhibit 4.1 of the Company’s Form 8-A, filed on May 23, 2013) 
+ 
+4.3 
+Registration Rights Agreement, dated May 26, 2016, among Callon Petroleum Company and each of the Persons set forth on Schedule A therein (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed on May 31, 2016) 
+ 
+4.4 
+Indenture of 6.125% Senior Notes Due 2024, dated as of October 3, 2016, among Callon Petroleum Company, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K, filed on October 4, 2016) 
+ 
+4.5 
+Registration Rights Agreement of 6.125% Senior Notes Due 2024, dated October 3, 2016, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P. Morgan Securities LLC, as representative of the Initial Purchasers named on Annex E thereto (incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K, filed on October 4, 2016) 
+4.6 
+Registration Rights Agreement of 6.125% Senior Notes Due 2024, dated May 24, 2017, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P. Morgan Securities LLC, as representative of the Initial Purchasers named on Annex E thereto (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K, filed on May 24, 2017) 
+9. 
+Voting trust agreement 
+ 
+None 
+10. 
+Material contracts 
+ 
+10.1 
+Form of Amended and Restated Severance Compensation Agreement, dated as of March 15, 2011 and effective as of January 1, 2011, by and between Callon Petroleum Company and its executive officers (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed on March 18, 2011) 
+ 
+10.2 
+Callon Petroleum Company 2011 Omnibus Incentive Plan (incorporated by reference from Exhibit A of the Company’s Definitive Proxy Statement on Schedule 14A, filed on March 21, 2011) 
+ 
+10.3 
+Form of Callon Petroleum Company Restricted Stock Unit Award Agreement, adopted on March 12, 2015 (incorporated by reference to Exhibit 10.16 of the Company’s Annual Report on Form 10-K, filed on March 3, 2016) 
+ 
+10.4 
+Form of Callon Petroleum Company Phantom Share Award Agreement for performance-based awards settleable in cash and stock, granted to officers of the Company, adopted on March 12, 2015 (incorporated by reference to Exhibit 10.17 of the Company’s Annual Report on Form 10-K, filed on March 3, 2016) 
+ 
+10.5 
+Form of Callon Petroleum Company Phantom Share Award Agreement for time-based restricted stock units settleable in cash, granted to officers of the Company, adopted on March 12, 2015 (incorporated by reference to Exhibit 10.18 of the Company’s Annual Report on Form 10-K, filed on March 3, 2016) 
+ 
+10.6 
+First Amendment to the Callon Petroleum Company 2011 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q, filed on November 5, 2015) 
+ 
+10.7 
+Purchase Agreement, dated September 15, 2016, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P. Morgan Securities LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed on September 16, 2016) 
+10.8 
+Sixth Amended and Restated Credit Agreement, dated May 31, 2017, among Callon Petroleum Company, JPMorgan Chase Bank, National Association, as administrative agent and the Lenders party thereto (incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q, filed on August 2, 2017) 
+10.9 
+Purchase Agreement, dated May 19, 2017, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P.Morgan Securities, LLC, as representatives of the Initial Purchasers (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed on May 24, 2017) 
+10.10 
+(a) 
+Offer letter, dated February 6, 2017, by and between Correne S. Loeffler and Callon Petroleum Company 
+10.11 
+(a) 
+Amended and Restated Deferred Compensation Plan for Outside Directors - Callon Petroleum Company, dated as of May 10, 2017 and effective as of May 1, 2017 
+91 
+Table of Contents 
+10.12 
+(a) 
+Amended and Restated Severance Compensation Agreement, dated as of September 19, 2017 and effective as of September 18, 2017, by and between Joseph C. Gatto, Jr., and Callon Petroleum Company 
+10.13 
+(a) 
+Offer letter, dated October 12, 2017, by and between Michol Ecklund and Callon Petroleum Company 
+10.14 
+(a) 
+Form of Amended and Restated Severance Compensation Agreement, dated as of November 6, 2017 and effective as of November 6, 2017, by and between Callon Petroleum Company and its new executive officers 
+10.15 
+(a) 
+Offer letter, dated November 29, 2017, by and between James P. Ulm, II 
+11. 
+* 
+Statement re computation of per share earnings 
+12. 
+* 
+Statements re computation of ratios 
+13. 
+* 
+Annual Report to security holders, Form 10-Q or quarterly reports 
+16. 
+Letter re change in certifying accountant 
+ 
+16.1 
+Letter from E&Y dated January 15, 2016 (incorporated by reference to Exhibit 16.1 of the Company’s Current Report on Form 8-K, filed on January 15, 2016) 
+18. 
+* 
+Letter re change in accounting principles 
+21. 
+Subsidiaries of the Company 
+ 
+21.1 
+(a) 
+Subsidiaries of the Company 
+22. 
+* 
+Published report regarding matters submitted to vote of security holders 
+23. 
+Consents of experts and counsel 
+ 
+23.1 
+(a) 
+Consent of Grant Thornton LLP 
+ 
+23.2 
+(a) 
+Consent of Ernst & Young LLP 
+ 
+23.3 
+(a) 
+Consent of DeGolyer and MacNaughton, Inc. 
+24. 
+* 
+Power of attorney 
+31. 
+Rule 13a-14(a) Certifications 
+ 
+31.1 
+(a) 
+Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a) 
+ 
+31.2 
+(a) 
+Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a) 
+32. 
+(b) 
+Section 1350 Certifications of Chief Executive and Financial Officers pursuant to Rule 13(a)-14(b) 
+99. 
+Additional Exhibits 
+ 
+99.1 
+(a) 
+Reserve Report Summary prepared by DeGolyer and MacNaughton, Inc. as of December 31, 2017 
+101. 
+(c) 
+Interactive Data Files 
+* 
+Not applicable to this filing 
+(a) 
+Filed herewith. 
+(b) 
+Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, except to the extent that the registrant specifically incorporates it by reference. 
+(c) 
+Pursuant to Rule 406T of Regulation S-T, these interactive data files are being furnished herewith and are not deemed filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, or Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability. 
+92 
+Table of Contents 
+Item 16. Form 10-K Summary 
+Not applicable. 
+93 
+Table of Contents 
+SIGNATURES 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+Callon Petroleum Company 
+/s/ James P. Ulm, II 
+Date: 
+February 27, 2018 
+By: James P. Ulm, II 
+Chief Financial Officer (principal financial officer) 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+/s/ Joseph C. Gatto, Jr. 
+Date: 
+February 27, 2018 
+Joseph C. Gatto, Jr. (principal executive officer) 
+ 
+ 
+/s/ James P. Ulm, II 
+Date: 
+February 27, 2018 
+James P. Ulm, II (principal financial officer) 
+ 
+ 
+/s/ Mitzi P. Conn 
+Date: 
+February 27, 2018 
+Mitzi P. Conn (principal accounting officer) 
+ 
+ 
+/s/ L. Richard Flury 
+Date: 
+February 27, 2018 
+L. Richard Flury (director) 
+ 
+ 
+/s/ John C. Wallace 
+Date: 
+February 27, 2018 
+John C. Wallace (director) 
+ 
+ 
+/s/ Anthony J. Nocchiero 
+Date: 
+February 27, 2018 
+Anthony J. Nocchiero (director) 
+ 
+ 
+/s/ Larry D. McVay 
+Date: 
+February 27, 2018 
+Larry McVay (director) 
+ 
+ 
+/s/ Matthew R. Bob 
+Date: 
+February 27, 2018 
+Matthew R. Bob (director) 
+ 
+ 
+/s/ James M. Trimble 
+Date: 
+February 27, 2018 
+James M. Trimble (director) 
+ 
+ 
+/s/ Michael L. Finch 
+Date: 
+February 27, 2018 
+Michael L. Finch (director) 
+ 
+94
\ No newline at end of file
diff --git a/raw/filings/0000928022/2017/0000928022-18-000013/filing_metadata.csv b/raw/filings/0000928022/2017/0000928022-18-000013/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..2084086af47b98df9776108134db56b909d26dc1
--- /dev/null
+++ b/raw/filings/0000928022/2017/0000928022-18-000013/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000928022,CPE,Callon Petroleum Co,10-K,2018-02-28,2017-12-31,2018-02-27T23:03:56.000Z,0000928022-18-000013,cpe-20171231x10k.htm,10-K,18491762,1,0,https://www.sec.gov/Archives/edgar/data/928022/000092802218000013/cpe-20171231x10k.htm,https://www.sec.gov/Archives/edgar/data/928022/000092802218000013/,2017,2017,1
diff --git a/raw/filings/0000928022/2017/0000928022-18-000013/item1.txt b/raw/filings/0000928022/2017/0000928022-18-000013/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000928022/2017/0000928022-18-000013/item13.txt b/raw/filings/0000928022/2017/0000928022-18-000013/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..7fa2bdd6d72a371080698f85c36974dad02aa219
--- /dev/null
+++ b/raw/filings/0000928022/2017/0000928022-18-000013/item13.txt
@@ -0,0 +1,2 @@
+ITEM 13. Certain Relationships and Related Transactions and Director Independence 
+For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 10, 2018 , which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2017/0000928022-18-000013/item9a.txt b/raw/filings/0000928022/2017/0000928022-18-000013/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..0e7bb5ee3426bc118d719bfa7ec1fa74b0a7832e
--- /dev/null
+++ b/raw/filings/0000928022/2017/0000928022-18-000013/item9a.txt
@@ -0,0 +1,10 @@
+Item 9A. Controls and Procedures 
+Disclosure controls and procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) performed an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2017 . 
+Management’s report on internal control over financial reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. generally accepted accounting principles. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2017 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission (2013 framework)(the COSO criteria). Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2017 . 
+Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+The Company’s independent registered public accounting firm has issued an attestation report regarding its assessment of the Company’s internal control over financial reporting as of December 31, 2017 , which follows Part II, Item 9B of this filing. Additionally, the financial statements for the years ended December 31, 2017 and 2016 , covered in this Annual Report on Form 10-K, have been audited by an independent registered public accounting firm, Grant Thornton LLP, whose report is presented immediately preceding the Company’s financial statements included in Part II, Item 8 of this Annual Report on Form 10-K. The financial statements for the year ended December 31, 2015 were audited by the independent registered public accounting firm, Ernst & Young LLP, whose report is presented immediately preceding the company’s financial statements included in Part II, Item 8 of this Annual Report on Form 10-K. 
+Changes in internal control over financial reporting . There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting. 
+87 
+Table of Contents 
+ITEM 9A (T). Controls and Procedures 
+See Item 9A.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2017/0000928022-18-000013/rp_note.txt b/raw/filings/0000928022/2017/0000928022-18-000013/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000928022/2017/0000928022-18-000013/rpt_disclosure.txt b/raw/filings/0000928022/2017/0000928022-18-000013/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..685cf976f9264ec5803008c34fdcc2cfcf2b0db7
--- /dev/null
+++ b/raw/filings/0000928022/2017/0000928022-18-000013/rpt_disclosure.txt
@@ -0,0 +1,5 @@
+Certain Relationships and Related Party Transactions 
+The Board’s Audit Committee charter provides that the Audit Committee shall review and approve all related party transactions. A transaction will be considered a “related party transaction” if the transaction would be required to be disclosed under Item 404 of Regulation S-K. In addition, our Code of Business Conduct and Ethics provides that an officer’s or a director’s conflict of interest with Callon may only be waived if the Nominating and Corporate Governance Committee approves the waiver and the full Board ratifies the waiver. 
+For the fiscal year ended 2018, David Newberry, who is the son of Gary Newberry, our former Senior Vice President and Chief Operating Officer, received $213,500 in total compensation as an employee of the Company, which is consistent with market compensation for his services. In addition, David Newberry was eligible to participate in all benefit plans and programs available generally to the Company’s employees. 
+For the fiscal year ended 2018, Austin Weant, who is the son of Jerry Weant, our Vice President of Land, received $159,366 in total compensation as an employee of the Company, which is consistent with market compensation for his services. In addition, Austin Weant was eligible to participate in all benefit plans and programs available generally to the Company’s employees. 
+Except for the foregoing, as of December 31, 2018, we are not aware of any related party transactions with our executive officers that require disclosure under Item 404 of Regulation S-K.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2018/0000928022-19-000044/filing.txt b/raw/filings/0000928022/2018/0000928022-19-000044/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..7f095b04421aff54fb572be7569032f07fd92d68
--- /dev/null
+++ b/raw/filings/0000928022/2018/0000928022-19-000044/filing.txt
@@ -0,0 +1,5827 @@
+10-K
+1
+a4q18form10k.htm
+10-K
+Document 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+FORM 10-K 
+☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the fiscal year ended December 31, 2018 
+or 
+☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the transition period from ____________ to ____________ 
+Commission File Number 001-14039 
+Callon Petroleum Company 
+(Exact Name of Registrant as Specified in Its Charter) 
+_______________________________________________ 
+໿ 
+Delaware 
+(State or Other Jurisdiction of 
+Incorporation or Organization) 
+64-0844345 
+(IRS Employer 
+Identification No.) 
+1401 Enclave Parkway, Suite 600 Houston, Texas 
+(Address of Principal Executive Offices) 
+77077 
+(Zip Code) 
+281-589-5200 
+(Registrant’s Telephone Number, Including Area Code) 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of Each Class 
+Name of Each Exchange on Which Registered 
+Common Stock, $0.01 par value 
+New York Stock Exchange 
+10.0% Series A Cumulative Preferred Stock 
+New York Stock Exchange 
+Securities registered pursuant to section 12 (g) of the Act: None 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐ 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒ 
+Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ 
+Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐ 
+Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒ 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company in Rule 12b-2 of the Exchange Act: 
+Large accelerated filer 
+☒ 
+Accelerated filer 
+☐ 
+Non-accelerated filer 
+☐ 
+Smaller reporting company 
+☐ 
+Emerging growth company 
+☐ 
+. 
+If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ 
+The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2018 was approximately $2,426,644,330 . 
+The Registrant had 227,875,828 shares of common stock outstanding as of February 22, 2019 . 
+DOCUMENTS INCORPORATED BY REFERENCE 
+Portions of the definitive Proxy Statement of Callon Petroleum Company (to be filed no later than 120 days after December 31, 2018 ) relating to the Annual Meeting of Stockholders to be held on May 9, 2019 , which are incorporated into Part III of this Form 10-K. 
+TABLE OF CONTENTS 
+Special Note Regarding Forward-Looking Statements 
+3 
+Glossary of Certain Terms 
+5 
+Part I 
+6 
+Items 1 and 2. 
+Business and Properties 
+6 
+Oil and Natural Gas Properties 
+7 
+Reserves Data 
+7 
+Capital Budget 
+9 
+Exploration and Development Activit ies 
+9 
+Production Wells 
+10 
+Production Volumes, Average Sales Prices and Operating Costs 
+10 
+Leasehold Acreage 
+11 
+Other 
+11 
+Regulations 
+13 
+Commitments and Contingencies 
+20 
+Available Information 
+21 
+Item 1A. 
+Risk Factors 
+22 
+Item 1B. 
+Unresolved Staff Comments 
+36 
+Item 3. 
+Legal Proceedings 
+36 
+Item 4. 
+Mine Safety Disclosures 
+36 
+Part II 
+Item 5. 
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+37 
+Performance Graph 
+38 
+Item 6. 
+Selected Financial Data 
+39 
+Item 7. 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+40 
+General 
+40 
+Overview and Outlook 
+40 
+Results of Operations 
+41 
+Liquidity and Capital Resources 
+48 
+Critical Accounting Estimates 
+52 
+Item 7A. 
+Quantitative and Qualitative Disclosures About Market Risk 
+55 
+Item 8. 
+Financial Statements and Supplementary Data 
+57 
+Reports of Independent Registered Public Accounting Firm 
+58 
+Consolidated Balance Sheets 
+60 
+Consolidated Statements of Operations 
+61 
+Consolidated Statements of Stockholders’ Equity 
+62 
+Consolidated Statements of Cash Flows 
+63 
+Notes to Consolidated Financial Statements 
+64 
+Supplemental Information on Oil and Natural Gas Operations (Unaudited) 
+85 
+Supplemental Quarterly Financial Information (Unaudited) 
+89 
+Item 9. 
+Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+90 
+Item 9A. 
+Controls and Procedures 
+90 
+Item 9B. 
+Other Information 
+90 
+Part III 
+Item 10. 
+Directors and Executive Officers and Corporate Governance 
+92 
+Item 11. 
+Executive Compensation 
+92 
+Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+92 
+Item 13. 
+Certain Relationships and Related Transactions and Director Independence 
+92 
+Item 14. 
+Principal Accountant Fees and Services 
+92 
+Part IV. 
+Item 15. 
+Exhibits 
+93 
+Item 16. 
+Form 10-K Summary 
+95 
+Signatures 
+96 
+2 
+Special Note Regarding Forward Looking Statements 
+This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”), as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements in this Form 10-K by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions. 
+All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future are forward-looking statements, including such things as: 
+• 
+our oil and natural gas reserve quantities, and the discounted present value of these reserves; 
+• 
+the amount and nature of our capital expenditures; 
+• 
+our future drilling and development plans and our potential drilling locations; 
+• 
+the timing and amount of future capital and operating costs; 
+• 
+production decline rates from our wells being greater than expected; 
+• 
+commodity price risk management activities and the impact on our average realized prices; 
+• 
+business strategies and plans of management; 
+• 
+our ability to consummate and efficiently integrate recent acquisitions; and 
+• 
+prospect development and property acquisitions. 
+Some of the risks, which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements, include: 
+• 
+general economic conditions including the availability of credit and access to existing lines of credit; 
+• 
+the volatility of oil and natural gas prices; 
+• 
+the uncertainty of estimates of oil and natural gas reserves; 
+• 
+impairments; 
+• 
+the impact of competition; 
+• 
+the availability and cost of seismic, drilling and other equipment, waste and water disposal infrastructure, and personnel; 
+• 
+operating hazards inherent in the exploration for and production of oil and natural gas; 
+• 
+difficulties encountered during the exploration for and production of oil and natural gas; 
+• 
+the potential impact of future drilling on production from existing wells 
+• 
+difficulties encountered in delivering oil and natural gas to commercial markets; 
+• 
+changes in customer demand and producers’ supply; 
+• 
+the uncertainty of our ability to attract capital and obtain financing on favorable terms; 
+• 
+compliance with, or the effect of changes in, the extensive governmental regulations regarding the oil and natural gas business including those related to climate change and greenhouse gases; 
+• 
+the impact of government regulation, including regulation of hydraulic fracturing and water disposal wells; 
+• 
+any increase in severance or similar taxes; 
+• 
+the financial impact of accounting regulations and critical accounting policies; 
+• 
+the comparative cost of alternative fuels; 
+• 
+credit risk relating to the risk of loss as a result of non-performance by our counterparties; 
+• 
+cyberattacks on the Company or on systems and infrastructure used by the oil and natural gas industry; 
+• 
+weather conditions; and 
+• 
+any other factors listed in the reports we have filed and may file with the SEC. 
+We caution you that the forward-looking statements contained in this Form 10-K are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. These risks include, but are not limited to, the risks described in Item 1A of this Annual Report on Form 10-K for the year ended December 31, 2018 (the “ 2018 Annual Report on Form 10-K”), and all quarterly reports on Form 10-Q filed subsequently thereto. 
+Should one or more of the risks or uncertainties described above or in our 2018 Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Any forward-looking statement speaks only as of the date of which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except required by applicable law. 
+3 
+In addition, we caution that reserve engineering is a process of estimating oil and natural gas accumulated underground and cannot be measured exactly. Accuracy of reserve estimates depend on a number of factors including data available at the point in time, engineering interpretation of the data, and assumptions used by the reserve engineers as it relates to price and cost estimates and recoverability. New results of drilling, testing, and production history may result in revisions of previous estimates and, if significant, would impact future development plans. As such, reserve estimates may differ from actual results of oil and natural gas quantities ultimately recovered. 
+Except as required by applicable law, all forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. 
+4 
+GLOSSARY OF CERTAIN TERMS 
+All defined terms under Rule 4-10(a) of Regulation S-X shall have their prescribed meanings when used in this report. As used in this document: 
+• 
+ARO : asset retirement obligation. 
+• 
+ASU : accounting standards update. 
+• 
+Bbl or Bbls : barrel or barrels of oil or natural gas liquids. 
+• 
+BOE : barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of natural gas. The ratio of one barrel of oil or NGL to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas. 
+• 
+BOE/d : BOE per day. 
+• 
+BLM: Bureau of Land Management. 
+• 
+Btu : a British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit. 
+• 
+Completion : the process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency. 
+• 
+Cushing : an oil delivery point that serves as the benchmark oil price for West Texas Intermediate. 
+• 
+DOI: Department of Interior. 
+• 
+EPA: United States Environmental Protection Agency. 
+• 
+FASB: Financial Accounting Standards Board. 
+• 
+GAAP : Generally Accepted Accounting Principles in the United States. 
+• 
+Henry Hub : a natural gas pipeline delivery point that serves as the benchmark natural gas price underlying NYMEX natural gas futures contracts. 
+• 
+Horizontal drilling : a drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at an angle within a specified interval. 
+• 
+GHG: greenhouse gases. 
+• 
+LIBOR : London Interbank Offered Rate. 
+• 
+LOE : lease operating expense. 
+• 
+MBbls : thousand barrels of oil. 
+• 
+MBOE : thousand BOE. 
+• 
+Mcf : thousand cubic feet of natural gas. 
+• 
+MMBOE : million BOE. 
+• 
+MMBtu : million Btu. 
+• 
+MMcf : million cubic feet of natural gas. 
+• 
+NGL or NGLs : natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams. 
+• 
+NYMEX : New York Mercantile Exchange. 
+• 
+Oil : includes crude oil and condensate. 
+• 
+OPEC: Organization of Petroleum Exporting Countries. 
+• 
+PDPs : proved developed producing reserves. 
+• 
+PUDs : proved undeveloped reserves. 
+• 
+Realized price : the cash market price less all expected quality, transportation and demand adjustments. 
+• 
+Royalty interest : an interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development. 
+• 
+RSU : restricted stock units. 
+• 
+SEC : United States Securities and Exchange Commission. 
+• 
+Waha : a natural gas delivery point in West Texas that serves as the benchmark for natural gas. 
+• 
+Working interest : an operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations. 
+• 
+WTI : West Texas Intermediate grade crude oil, used as a pricing benchmark for sales contracts and NYMEX oil futures contracts. 
+With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross. 
+5 
+PART I. 
+ITEMS 1 and 2 – Business and Properties 
+Overview 
+Callon Petroleum Company has been engaged in the exploration, development, acquisition and production of oil and natural gas properties since 1950. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. We were incorporated in the state of Delaware in 1994. 
+We are an independent oil and natural gas company focused on the acquisition and development of unconventional onshore oil and natural gas reserves in the Permian Basin. The Permian Basin is located in West Texas and southeastern New Mexico and is comprised of three primary sub-basins: the Midland Basin, the Delaware Basin, and the Central Basin Platform. We have historically been focused on the Midland Basin and entered the Delaware Basin through an acquisition completed in February 2017. We further expanded our presence in the Delaware Basin through our acquisitions in 2018. 
+Our drilling activity during 2018 was predominantly focused on the horizontal development of several prospective intervals in the Midland and Delaware Basins, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales. As a result of our horizontal development efforts and contributions from acquisitions, our net daily production for calendar year 2018 as compared to calendar year 2017 grew approximately 44% to 32,926 BOE/d (approximately 79% oil). For the year ended December 31, 2018 , our net proved reserve volumes increased 74% as compared to the year ended December 31, 2017 , to 238.5 MMBOE, comprised of 76% oil ( 180.1 MMBbls) and 24% natural gas ( 350.5 Bcf). Approximately 54% of our net proved year-end 2018 reserves were proved developed on a BOE basis. 
+We intend to grow our reserves and production through the drilling and development of our multi-year inventory of identified drilling locations. We will also seek to grow our inventory of locations through delineation of emerging zones and selective “bolt-on” acquisition and leasing programs in areas complementary to our core operating areas. 
+Our Business Strategy 
+Our principal objective is to enhance shareholder value through capital efficient growth in proved reserves and associated production and cash flows while acting as a responsible corporate citizen in the areas in which we operate. Key elements of the execution of this strategy include: 
+• 
+Optimizing the development of our multi-zone resource base through thoughtful plans of depletion that are educated by extensive analysis of subsurface data and empirical well results; 
+• 
+Maintaining strong cash margins per unit of production through cost management and proactive investment in production infrastructure; 
+• 
+Improving the capital efficiency of our operations in terms of both well productivity and capital outlays, including supporting facilities; 
+• 
+Maturing our asset base into a sustainable operating model for profitable reinvestment of cash flows for attractive, long-term returns on capital; 
+• 
+Growing our inventory of well locations through delineation of emerging targets on our existing acreage positions and selective acquisitions of leasehold rights and mineral interests in areas complementary to our existing core operating areas; and 
+• 
+Preserving a strong financial position, focusing on appropriate capital allocation decisions under various commodity pricing scenarios, prudent risk management and robust liquidity. 
+Our Strengths 
+We believe the following attributes position Callon to achieve its objectives: 
+• 
+Strong Foundation - Reputation as a safe and responsible operator built over several decades in the oil and gas industry; 
+• 
+Quality Assets - High quality Permian Basin asset base with several years of proven well results from multiple target zones that benefit from early investments in critical supporting infrastructure including sustainable investments in water recycling; 
+• 
+Operational Control - High degree of operational control that allows us to efficiently maximize value through long-term and daily decisions that drive our strategy; 
+• 
+Talented Workforce - Seasoned employee base that has continued to benefit from the hiring of quality employees across various disciplines that have been integrated into our unifying culture. 
+6 
+Oil and Natural Gas Properties 
+Permian Basin 
+As of December 31, 2018 , we owned 84,705 net leasehold acreage in the Permian Basin, all of which was located in the Midland and Delaware Basins. Average net production from our Permian Basin properties increased 44% to 32,926 BOE/d in 2018 from 
+22,940 BOE/d in 2017 . The following sets forth certain information about our major operating areas in the Permian Basin as of December 31, 2018 : 
+໿ 
+Producing Wells 
+Producing 
+Horizontal 
+Vertical 
+Horizontal Flow 
+Net Acres 
+Gross 
+Net 
+Gross 
+Net 
+Unit Zones 
+Midland Basin 
+39,534 
+250 
+186.9 
+304 
+248.2 
+Middle Spraberry, Lower Spraberry, 
+Wolfcamp A, 
+Wolfcamp B, 
+Wolfcamp C 
+Delaware Basin 
+45,171 
+216 
+176.7 
+126 
+76.3 
+Third Bone Spring, 
+Wolfcamp A, 
+Wolfcamp B, 
+Wolfcamp C 
+Total Permian Basin 
+84,705 
+466 
+363.6 
+430 
+324.5 
+Reserve Data 
+As of December 31, 2018 , our estimated net proved reserves grew 74% from prior year-end, totaling 238.5 MMBOE and included 180.1 MMBbls of oil and 350.5 Bcf of natural gas with a standardized measure of discounted future net cash flows of $2.9 billion . Oil constituted approximately 76% of our total estimated equivalent net proved reserves and approximately 72% of our total estimated equivalent proved developed reserves. We added 85 MMBOE of new reserves in extensions and discoveries through our development efforts in our operating areas, where we drilled a total of 70 gross ( 57.5 net) wells. We purchased reserves in place of 39.7 MMBOE from the Delaware Asset Acquisition as well as bolt-on acquisitions completed within the Permian Basin and reduced our estimated net proved reserves through net revisions of previous estimates of 2.0 MMBOE and reclassifications of 9.1 MMBOE to probable reserves. Our net revisions of previous estimates were primarily related to technical revisions of proved undeveloped reserves. We reclassified 19 PUD locations to probable reserves, primarily due to acreage trades and changes in our development plan, including larger pad development concepts and co-development of zones. These changes resulted in the anticipated drilling of PUD locations being moved beyond five years from initial booking. The changes in our proved reserves are as follows (in MBOE): 
+Proved reserves: 
+Reserves at December 31, 2017 
+136,974 
+Extensions and discoveries 
+84,955 
+Purchase of reserves in place 
+39,683 
+Revisions to previous estimates 
+(2,021 
+) 
+Reclassifications due to changes in development plan 
+(9,065 
+) 
+Production 
+(12,018 
+) 
+Reserves at December 31, 2018 
+238,508 
+Annually, the Company reviews its PUDs to ensure appropriate plans exist for development of this reserve category. PUD reserves are recorded only if the Company has plans to convert these reserves into PDPs within five years of the date they are first recorded. Our development plans include the allocation of capital to projects included within our 2019 capital budget and, in subsequent years, the allocation of capital within our long-range business plan to convert PUDs to PDPs within this five year period. In general, our 2019 capital budget and our long-range capital plans are primarily governed by our expectations of internally generated cash flow, borrowing availability under our senior secured revolving credit facility (“Credit Facility”) and corporate credit metrics. Reserve calculations at any end-of-year period are representative of our development plans at that time. Changes in commodity pricing, oilfield service costs and availability, and other economic factors may lead to changes in development plans. The following table shows changes in proved undeveloped reserves for 2018 (in MBOE): 
+7 
+Proved undeveloped reserves: 
+Reserves at December 31, 2017 
+67,656 
+Extensions and discoveries 
+56,710 
+Purchases of reserves in place 
+9,861 
+Transfers to proved developed 
+(11,075 
+) 
+Revisions of previous estimates 
+(4,184 
+) 
+Reclassifications due to changes in development plan 
+(9,065 
+) 
+Reserves at December 31, 2018 
+109,903 
+A breakdown by commodity of our proved oil and natural gas reserves follows: 
+For the Year Ended December 31, 
+Proved developed reserves: 
+2018 
+2017 
+2016 
+Oil (MBbls): 
+92,202 
+51,920 
+32,920 
+Natural gas (MMcf): 
+218,417 
+104,389 
+61,871 
+MBOE: 
+128,605 
+69,318 
+43,232 
+Proved undeveloped reserves: 
+Oil (MBbls): 
+87,895 
+55,152 
+38,225 
+Natural gas (MMcf): 
+132,049 
+75,021 
+60,740 
+MBOE: 
+109,903 
+67,656 
+48,348 
+Total proved reserves: 
+Oil (MBbls): 
+180,097 
+107,072 
+71,145 
+Natural gas (MMcf): 
+350,466 
+179,410 
+122,611 
+MBOE: 
+238,508 
+136,974 
+91,580 
+Controls Over Reserve Estimates 
+Compliance as it relates to reporting the Company’s reserves is the responsibility of our Chief Operating Officer, who is also our principal engineer. Until December 2018, our Chief Operating Officer was Gary A. Newberry who had over 36 years of industry experience, including 30 years as a manager, and holds a degree in Petroleum Engineering. In December 2018, Jeffrey S. Balmer became our Chief Operating Officer upon Mr. Newberry’s retirement from the Company. Dr. Balmer has over 30 years of operations and industry experience. In addition to his years of experience, Dr. Balmer holds B.S. and Ph.D. degrees in Petroleum Engineering, in addition to a M.S. in Environmental and Planning Engineering, and is experienced in asset evaluation and management. 
+Callon’s controls over reserve estimates included retaining DeGolyer and MacNaughton, a Texas registered engineering firm, as our Reserve Engineering Firm. The Company provided to DeGolyer and MacNaughton information about our oil and gas properties, including production profiles, prices and costs, and DeGolyer and MacNaughton prepared its own estimates of the reserves attributable to the Company’s properties. All of the information regarding 2018 , 2017 and 2016 reserves in this annual report is derived from DeGolyer and MacNaughton’s report. DeGolyer and MacNaughton’s reserve report letter is included as an exhibit to this annual report. The principal engineer at DeGolyer and MacNaughton, who certified the Company’s reserve estimates, has over 34 years of experience in the oil and gas industry and is a Texas Licensed Professional Engineer. Further professional qualifications include a degree in petroleum engineering and membership in the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. 
+To further enhance the control environment over the reserve estimation process, our Strategic Planning and Reserves Committee, an independent committee of the Board of Directors, assists management and the Board with its oversight of the integrity of the determination of the Company’s oil and natural gas reserves and the work of our Reserve Engineering Firm. The Committee’s charter also specifies that the Committee shall perform, in consultation with the Company’s management and senior reserves and reservoir engineering personnel, the following responsibilities: 
+• 
+Oversee the appointment, qualification, independence, compensation and retention of the Reserve Engineering Firm engaged by the Company (including resolution of material disagreements between management and the Reserve Engineering Firm regarding reserve determination) for the purpose of preparing or issuing an annual reserve report. The Committee shall review any proposed changes in the appointment of the Reserve Engineering Firm, determine the reasons for such proposal, and whether there have been any disputes between the Reserve Engineering Firm and management. 
+• 
+Review the Company’s significant reserves engineering principles and any material changes thereto, and any proposed changes in reserves engineering standards and principles which have, or may have, a material impact on the Company’s reserves disclosure. 
+• 
+Review with management and the Reserve Engineering Firm the proved reserves of the Company, and, if appropriate, the probable reserves, possible reserves and the total reserves of the Company, including: (i) reviewing significant changes from 
+8 
+prior period reports; (ii) reviewing key assumptions used or relied upon by the Reserve Engineering Firm; (iii) evaluating the quality of the reserve estimates prepared by both the Reserve Engineering Firm and the Company relative to the Company’s peers in the industry; and (iv) reviewing any material reserves adjustments and significant differences between the Company’s and Reserve Engineering Firm’s estimates. 
+• 
+If the Committee deems it necessary, it shall meet in executive session with the Reserve Engineering Firm to discuss the oil and gas reserve determination process and related public disclosures, and any other matters of concern in respect of the evaluation of the reserves. 
+During our last fiscal year, we filed no reports with other federal agencies which contain an estimate of total proved net oil and natural gas reserves. 
+See Supplemental Information on Oil and Natural Gas Operations in Item 8 - Financial Statements and Supplementary Data for additional information regarding our estimated net proved reserves and our estimated future net cash flows and discounted future net cash flows from proved reserves. 
+2019 Capital Budget 
+Our operational capital budget for 2019 has been established in the range of $500 to $525 million on an accrual, or GAAP, basis, running an average of five drilling rigs to support larger, and more efficient, multi-well pad development. Of this range, approximately 15% is comprised of infrastructure and facilities capital. 
+As part of our 2019 operated horizontal drilling program, we expect to place 47 to 49 net wells on production with an increase of approximately 15% in average net lateral length as compared to the 2018 program. 
+໿ 
+In addition to the operational capital expenditures budget, which includes well costs, facilities and infrastructure capital, and surface land purchases, we budgeted an estimated $25 to $30 million for capitalized general and administrative expenses. 
+Our revenues, earnings, liquidity and ability to grow are substantially dependent on the prices we receive for, and our ability to develop, our reserves of oil and natural gas. We believe the long-term outlook for our business is favorable due to our resource base, low cost structure, financial strength, risk management, and disciplined investment of capital. We monitor current and expected market conditions, including the commodity price environment, and our liquidity needs and may adjust our capital investment plan accordingly. 
+Exploration and Development Activities 
+Our 2018 total capital expenditures, including acquisitions, on a cash basis were $1,324.1 million , of which $546.1 million consisted of operational capital expenditures, including drilling and completion and facilities and infrastructure expenditures. 
+For the year ended December 31, 2018 , we drilled 70 gross ( 57.5 net) horizontal wells, completed 65 gross ( 53.1 net) horizontal wells and had 11 gross ( 9.5 net) horizontal wells awaiting completion. 
+The following table sets forth the Company’s drilled wells, none of which were natural gas wells, nor nonproductive wells for the periods reflected: 
+2018 
+2017 (a) 
+2016 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Oil wells 
+Development (b) 
+15 
+12.8 
+15 
+10.7 
+9 
+4.9 
+Exploratory (c) 
+55 
+44.7 
+33 
+26.5 
+20 
+16.0 
+Total 
+70 
+57.5 
+48 
+37.2 
+29 
+20.9 
+(a) 
+Does not include one gross ( 0.97 net) nonproductive exploratory well. 
+(b) 
+A development well is a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. 
+(c) 
+An exploratory well is a well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir. 
+9 
+Productive Wells 
+As of December 31, 2018 , we had 896 gross ( 688.1 net) working interest oil wells, three gross ( 0.1 net) royalty interest oil wells and no natural gas wells. A well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas reserves on a BOE basis. However, most of our wells produce both oil and natural gas. 
+Production Volumes, Average Sales Prices and Operating Costs 
+The following tables set forth certain information regarding the production volumes and average sales prices received for, and average production costs associated with, the Company’s sale of oil and natural gas for the periods indicated (dollars in thousands, except per unit data). 
+For the Year Ended December 31, 
+2018 
+2017 
+2016 
+Production 
+Midland Basin 
+Oil (MBbls) 
+7,557 
+5,871 
+4,280 
+Natural gas (MMcf) 
+13,042 
+10,061 
+7,758 
+Total Midland Basin (MBOE) 
+9,731 
+7,548 
+5,573 
+Delaware Basin 
+Oil (MBbls) 
+1,886 
+686 
+— 
+Natural gas (MMcf) 
+2,405 
+835 
+— 
+Total Delaware Basin (MBOE) 
+2,287 
+825 
+— 
+Total oil (MBbls) 
+9,443 
+6,557 
+4,280 
+Total natural gas (MMcf) 
+15,447 
+10,896 
+7,758 
+Total (MBOE) 
+12,018 
+8,373 
+5,573 
+For the Year Ended December 31, 
+2018 
+2017 
+2016 
+Revenues 
+Oil revenue 
+$ 
+530,898 
+$ 
+322,374 
+$ 
+177,652 
+Natural gas revenue 
+56,726 
+44,100 
+23,199 
+Total 
+$ 
+587,624 
+$ 
+366,474 
+$ 
+200,851 
+Operating costs 
+Lease operating expense 
+$ 
+69,180 
+$ 
+49,907 
+$ 
+38,353 
+Production taxes 
+35,755 
+22,396 
+11,870 
+Total 
+$ 
+104,935 
+$ 
+72,303 
+$ 
+50,223 
+Average realized sales price 
+(excluding impact of settled derivatives) 
+Oil (per Bbl) 
+$ 
+56.22 
+$ 
+49.16 
+$ 
+41.51 
+Natural gas (per Mcf) 
+3.67 
+4.05 
+2.99 
+Total (per BOE) 
+48.90 
+43.77 
+36.04 
+Average realized sales price 
+(including impact of settled derivatives) 
+Oil (per Bbl) 
+$ 
+53.31 
+$ 
+47.78 
+$ 
+45.67 
+Natural gas (per Mcf) 
+3.69 
+4.10 
+3.00 
+Total (per BOE) 
+46.63 
+42.76 
+39.25 
+Operating costs per BOE 
+Lease operating expense 
+$ 
+5.76 
+$ 
+5.96 
+$ 
+6.88 
+Production taxes 
+2.98 
+2.67 
+2.13 
+Total 
+$ 
+8.74 
+$ 
+8.63 
+$ 
+9.01 
+10 
+Major Customers 
+Our production is sold generally on month-to-month contracts at prevailing prices. The following table identifies customers to whom we sold a significant percentage of our total oil and natural gas production, on an equivalent basis, during each of the 12-month periods indicated: 
+For the Year Ended December 31, 
+2018 
+2017 
+2016 
+Rio Energy International, Inc. 
+28 
+% 
+17 
+% 
+— 
+% 
+Plains Marketing, L.P. 
+21 
+% 
+29 
+% 
+16 
+% 
+Enterprise Crude Oil, LLC 
+14 
+% 
+18 
+% 
+43 
+% 
+Shell Trading Company 
+8 
+% 
+9 
+% 
+18 
+% 
+Trafigura Trading, LLC 
+6 
+% 
+— 
+% 
+— 
+% 
+Other 
+23 
+% 
+27 
+% 
+23 
+% 
+Total 
+100 
+% 
+100 
+% 
+100 
+% 
+Because alternative purchasers of oil and natural gas are readily available, the Company believes that the loss of any of these purchasers would not result in a material adverse effect on its ability to market future oil and natural gas production. In order to mitigate potential exposure to credit risk, we may require from time to time for our customers to provide financial security. 
+Leasehold Acreage 
+The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage as of December 31, 2018 . 
+໿ 
+Developed 
+Undeveloped 
+Total 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Permian Basin (a) 
+104,816 
+73,989 
+23,890 
+10,716 
+128,706 
+84,705 
+Other 
+936 
+200 
+188 
+55 
+1,124 
+255 
+Total 
+105,752 
+74,189 
+24,078 
+10,771 
+129,830 
+84,960 
+(a) 
+A portion of our Permian Basin acreage, which we have included in our development plans, requires continuous drilling to hold the acreage, though the cost to renew this acreage, if necessary, is not considered material. 
+The following table sets forth as of December 31, 2018 the number of our leased gross and net undeveloped acres in the Permian Basin that will expire over the next three years unless production begins before lease expiration dates. Gross amounts may be more than net amounts in a particular year due to timing of expirations. 
+໿ 
+Net 
+Gross 
+2019 
+2020 
+2021 
+Total 
+Total 
+Permian Basin 
+5,492 
+2,878 
+568 
+8,938 
+19,798 
+The expiring acreage set forth in the table above accounts for approximately 83% of our net undeveloped acreage ( 10,771 total net acres). We are continually engaged in a combination of drilling and development and discussions with mineral lessors for lease extensions, renewals, new drilling and development units and new leases to address any potential expiration of undeveloped acreage that occurs in the normal course of our business. 
+Other 
+Industry Segment and Geographic Information 
+For segment reporting purposes, the Company considers all of the current development and operating areas to be one reportable segment: the development and production of oil and natural gas. All of the Company’s assets and operations are located within the United States, and all of the production revenues generated from operations are contracted and sold to customers located in the United States. 
+Title to Properties 
+The Company believes that the title to its oil and natural gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of such properties. The Company’s properties are potentially subject to one or more of the following: 
+11 
+• 
+royalties and other burdens and obligations, express or implied, under oil and natural gas leases; 
+• 
+overriding royalties and other burdens created by us or our predecessors in title; 
+• 
+a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements; farm-out agreements, production sales contracts and other agreements that may affect the properties or their titles; 
+• 
+back-ins and reversionary interests existing under purchase agreements and leasehold assignments; 
+• 
+liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual liens under operating agreements; 
+• 
+pooling, unitization and communitization agreements, declarations and orders; and 
+• 
+easements, restrictions, rights-of-way and other matters that commonly affect property. 
+To the extent that such burdens and obligations affect the Company’s rights to production revenues, these characteristics have been taken into account in calculating Callon’s net revenue interests and in estimating the size and value of its reserves. The Company believes that the burdens and obligations affecting our properties are typical within the industry for properties of the kind owned by Callon. 
+Seasonality of Business 
+Weather conditions and seasonality affect the demand for and prices of, oil and natural gas. Due to these fluctuations, results of operations for quarterly interim periods may not be indicative of the results realized on an annual basis. 
+Competition 
+The Company operates in the oil and natural gas industry, which is highly competitive. The Company’s business experiences strong competition from a number of parties that may range from small independent producers to major integrated companies. Competition affects the Company’s ability to acquire additional properties and resources necessary to develop assets. In higher commodity pricing environments, competition also exists in the form of contracting for drilling, pumping, and workover equipment, and securing skilled personnel to both develop and operate existing assets. Many of the competitors mentioned above may be able to pay for more sought-after properties or access equipment, infrastructure, or personnel. The industry also experiences, from time to time, shortages in resources such as the availability of drilling and workover rigs, other equipment, pipes and materials, infrastructures, and skilled personnel, all of which can delay development, exploration, and workover activities as well as result in significant cost increases. 
+Insurance 
+In accordance with industry practice, the Company maintains insurance against some, but not all, of the operating risks to which its business is exposed. While not all inclusive, the Company’s insurance policies generally protect against bodily injury and property damage, pollution and other environmental damages, employee benefits, employee injury and control of well insurance for its exploration and production operations. 
+The Company enters into master service agreements with its third-party contractors, including hydraulic fracturing contractors, in which they agree to indemnify the Company for injuries and deaths of the service provider’s employees, as well as contractors and subcontractors hired by the service provider. Similarly, the Company generally agrees to indemnify each third-party contractor against claims made by employees of the Company and the Company’s other contractors. Additionally, each party generally is responsible for damage to its own property. The Company re-evaluates the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and natural gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. While based on the Company’s risk analysis we believe that we are properly insured, no assurance can be given that the Company will be able to maintain insurance in the future at rates that it considers reasonable. In such circumstances, the Company may elect to self-insure or maintain only catastrophic coverage for certain risks in the future. 
+Corporate Offices 
+The Company’s headquarters are located in Houston, Texas, in a building with office space leased by the Company. We own an office building in Natchez, Mississippi and lease and own offices in the Midland, Texas area. Because alternative locations to our leased spaces are readily available, the replacement of any of our leased offices would not result in material expenditures . 
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+Employees 
+Callon had 218 employees as of December 31, 2018 . None of the Company’s employees are currently represented by a union, and the Company believes that it has good relations with its employees. 
+Regulations 
+General. Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. Legislation and regulation affecting the entire oil and natural gas industry is continuously being reviewed for potential revision. Some of these requirements carry substantial penalties for failure to comply. 
+Exploration and Production . Our operations are subject to federal, state and local regulations that include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds and letters of credit) covering drilling and well operations. Other activities subject to regulation are: 
+• 
+the location and spacing of wells; 
+• 
+the method of drilling and completing and operating wells; 
+• 
+the rate and method of production; 
+• 
+the surface use and restoration of properties upon which wells are drilled and other exploration activities; 
+• 
+notice to surface owners and other third parties; 
+• 
+the venting or flaring of natural gas; 
+• 
+the plugging and abandoning of wells; 
+• 
+the discharge of contaminants into water and the emission of contaminants into air; 
+• 
+the disposal of fluids used or other wastes obtained in connection with operations; 
+• 
+the marketing, transportation and reporting of production; and 
+• 
+the valuation and payment of royalties. 
+Our sales of oil and natural gas are affected by the availability, terms and cost of pipeline transportation. The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation. If these regulations change, we could face higher transmission costs for our production and, possibly, reduced access to transmission capacity. 
+Various proposals and proceedings that might affect the petroleum industry are pending before Congress, the Federal Energy Regulatory Commission, or FERC, various state legislatures, and the courts. Historically, the industry has been heavily regulated and we can offer you no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue nor can we predict what effect such proposals or proceedings may have on our operations. 
+We do not currently anticipate that compliance with existing laws and regulations governing exploration and production will have a significantly adverse effect upon our capital expenditures, earnings or competitive position. 
+Environmental Matters and Regulation. Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the EPA, issue regulations which often require difficult and costly compliance measures. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relating to our owned or operated facilities. Violations of environmental laws could result in administrative, civil or criminal fines and injunctive relief. The strict and joint and several liability nature of certain such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons, air emissions or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. In recent years, the oil and natural gas exploration and production industry has been the subject of increasing scrutiny and regulation by environmental authorities. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. Although such laws and regulations can increase the cost of planning, designing, installing and 
+13 
+operating our facilities, it is anticipated that, absent the occurrence of an extraordinary event, compliance with them will not have a material effect upon our operations, capital expenditures, earnings or competitive position in the marketplace. 
+Waste Handling. The Resource Conservation and Recovery Act (“RCRA”), as amended, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of oil and natural gas are exempt from regulation as hazardous wastes under RCRA and its state analogs, it is possible that some wastes we generate presently or in the future may be subject to regulation under RCRA and state analogs. Additionally, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Additionally, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. 
+Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of wastes associated with oil and natural gas exploration and production could increase our costs to manage and dispose of such wastes. 
+Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), imposes joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or so–called potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes. 
+Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we have generated and will generate wastes that may fall within CERCLA’s definition of hazardous substance and may have disposed of these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum. We may also be the owner or operator of sites on which hazardous substances have been released. To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under CERCLA; we also do not know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties. In the event contamination is discovered at a site on which we are or have been an owner or operator or to which we sent hazardous substances, we could be liable for the costs of investigation and remediation and natural resources damages. 
+We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, and for water disposal, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including offsite locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination. 
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+Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act (“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States (a term broadly defined to include, among other things, certain wetlands), as well as state waters for analogous state programs. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or applicable state analog. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit from the U.S. Army Corps of Engineers. The EPA issued a final rule on the federal jurisdictional reach over waters of the United States in 2015. The rule is the subject of various legal challenges. Recently, the EPA proposed to repeal that rule and re-codify the pre-2015 rule while it revises the definition of “waters of the United States,” creating uncertainty regarding federal jurisdiction over waters of the United States. 
+The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. 
+The Oil Pollution Act is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters. 
+Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws. 
+Air Emissions. The federal Clean Air Act, as amended, and comparable state and local laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and modified and existing facilities may be required to obtain additional permits. As a result, we may need to incur capital costs in order to remain in compliance. Obtaining or renewing permits also has the potential to delay the development of oil and natural gas projects. Federal and state regulatory agencies can impose administrative, civil and criminal penalties and seek injunctive relief for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. 
+On June 3, 2016, the EPA expanded its regulatory coverage in the oil and natural gas industry with additional regulated equipment categories, and the addition of new rules limiting methane emissions from new or modified sites and equipment. Although the EPA attempted to suspend enforcement of the methane rule, this action was ruled improper by the U.S. Court of Appeals for the D.C. Circuit on July 2, 2017. Subsequently, in September 2018, the EPA issued a proposed rulemaking that could substantially change the obligations associated with methane emissions, limiting obligations for the oil and natural gas industry. That rulemaking has not been finalized and, therefore, future obligations continue to remain uncertain. 
+Climate Change. Numerous reports from scientific and governmental bodies such as the United Nations Intergovernmental Panel on Climate Change have expressed heightened concerns about the impacts of human activity, especially fossil fuel combustion, on the global climate. In turn, governments and civil society are increasingly focused on limiting the emissions of greenhouse gases, including emissions of carbon dioxide from the use of oil and natural gas. 
+In December 2015, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change resulted in 195 countries, including the United States, coming together to develop the so-called “Paris Agreement,” which calls for the parties to undertake “ambitious efforts” to limit the average global temperature. The Agreement went into effect on November 4, 2016, and establishes a framework for the parties to cooperate and report actions to reduce greenhouse gas emissions. While the United States announced that it would withdraw from the Paris Agreement on June 1, 2017, given the requirements of the withdrawal process the earliest possible exit would be November 2020. Certain U.S. city and state governments have announced their intention to satisfy their proportionate obligations under the Paris Agreement. In addition, legislation has from time to time been introduced in Congress that would establish measures restricting GHG emissions in the United States, and a number of states have begun taking actions to control and/or reduce emissions of GHGs. 
+15 
+Any legislation or regulatory programs at the federal, state, or city levels designed to reduce GHG emissions could increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Moreover, incentives to conserve energy or use alternative energy sources, such as policies designed to increase utilization of zero-emissions or electric vehicles, as a means of addressing climate change could reduce demand for the oil and natural gas we produce. 
+In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions. Although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. 
+The EPA has established GHG reporting requirements for certain sources in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissions. Although these requirements do not limit the amount of GHGs that can be emitted, they do require us to incur costs to monitor, keep records of, and report GHG emissions associated with our operations. 
+Parties concerned about the potential effects of climate change have also directed their attention at sources of financing for energy companies, which has resulted in certain financial institutions, funds and other capital providers restricting or eliminating their investment in oil and natural gas activities. In addition, some parties have initiated public nuisance claims under federal or state common law against certain companies involved in the production of oil and natural gas. Although our business is not a party to any such litigation, we could be named in actions making similar allegations, which could lead to costs and materially impact our financial condition in an adverse way. 
+Finally, most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of droughts, storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced or cause us to incur significant costs in preparing for or responding to the effects of climatic events themselves. 
+Regulation of Hydraulic Fracturing. Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act (“SDWA”) regulates the underground injection of substances through the Underground Injection Control (“UIC”) program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions and not at the federal level, as the SDWA expressly excludes regulation of these fracturing activities (except where diesel is a component of the fracturing fluid, as further discussed below). Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing has been proposed in past legislative sessions but has not passed. 
+The EPA, however, issued guidance on permitting hydraulic fracturing that uses fluids containing diesel fuel under the UIC program, specifically as “Class II” UIC wells. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. This report could result in additional regulatory scrutiny that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and business. Further, on June 28, 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. 
+On June 3, 2016, the EPA adopted regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package included New Source Performance Standards (“NSPS”) for hydraulically fractured natural gas and oil wells to address emissions of sulfur dioxide, volatile organic compounds (“VOCs”) and methane, with a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule sought to achieve a 95% reduction in VOCs and methane emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured gas and oil wells newly constructed or refractured. The rules also established specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. Notably, on October 15, 2018, the EPA published a proposed rule that would make a series of revisions to the 2016 NSPS; these revisions have yet to be finalized. 
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+Several states, including Texas, and some municipalities, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, Texas law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) for disclosure on a website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. 
+Additionally, some states, localities and local regulatory districts have adopted or have considered adopting regulations to limit, and in some cases impose a moratorium on, hydraulic fracturing or other restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; or restrictions on access to, and usage of, water. Further, there has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the U.S. implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations of harm. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of potential federal or state legislation governing hydraulic fracturing. 
+Surface Damage Statutes (“SDAs”) . In addition, a number of states and some tribal nations have enacted SDAs. These laws are designed to compensate for damage caused by oil and gas development operations. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain binding requirements for payments by the operator to surface owners/users in connection with exploration and operating activities in addition to bonding requirements to compensate for damages to the surface as a result of such activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs. 
+National Environmental Policy Act and Endangered Species Act . Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act (“NEPA”), which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Recent litigation by environmental non-governmental organizations has alleged that the Environmental Assessments for certain oil and natural gas projects violated NEPA by failing to account for climate change and the greenhouse gas emissions impacts of such projects. To the extent that our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects. 
+The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ or its habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. If the Company was to have a portion of its leases designated as critical or suitable habitat or a protected species were located on a lease, it may adversely impact the value of the affected leases. 
+Other Regulation of the Oil and Natural Gas Industry. The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other similar companies in the industry with similar types, quantities and locations of production. 
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+The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. Federal and state regulations govern the rates and other terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas. 
+Although oil and natural gas sales prices are currently unregulated, the federal government historically has been active in the area of oil and natural gas sales regulation. We cannot predict whether new legislation to regulate oil and natural gas sales might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate, oil and natural gas liquids are not currently regulated and are made at market prices. 
+Exports of US Oil Production and Natural Gas Production . In December 2015, the federal government ended its decades-old prohibition of exports of oil produced in the lower 48 states of the US. As a result, exports of U.S. oil have increased significantly, reinforcing the general perception in the industry that the end of the U.S. export ban was positive for producers of U.S. oil. In addition, the U.S. Department of Energy (“DOE”) authorizes exports of natural gas, including exports of natural gas by pipelines connecting U.S. natural gas production to pipelines in Mexico, and the export of liquefied natural gas (“LNG”) through LNG export facilities, the construction of which are regulated by FERC. Since 2016, natural gas produced in the lower 48 states of the U.S. has been exported as LNG from LNG export facilities being developed and constructed in the U.S. Gulf Coast region. This export capacity has steadily increased, and is expected to continue on that trajectory. The general perception in the industry is that this sustained growth in exports will be a positive development for producers of U.S. natural gas. 
+Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following: 
+• 
+the location of wells; 
+• 
+the method of drilling and casing wells; 
+• 
+the timing of construction or drilling activities, including seasonal wildlife closures; 
+• 
+the rates of production or “allowables”; 
+• 
+the surface use and restoration of properties upon which wells are drilled; 
+• 
+the plugging and abandoning of wells; and 
+• 
+notice to, and consultation with, surface owners and other third parties. 
+State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affecting the economics of production from these wells or to limit the number of locations we can drill. 
+Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Some state agencies and municipalities require bonds or other financial assurances to support those obligations. 
+Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. Under the Energy Policy Act of 2005 (“EPAct”), FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. 
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+Under the EPAct Congress amended the Natural Gas Act (“NGA”) to give FERC substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. EPAct also amended the NGA to authorize FERC to “facilitate transparency in markets for the sale or transportation of physical natural gas in interstate commerce,” pursuant to which authorization FERC now requires natural gas wholesale market participants, including a number of entities that may not otherwise be subject to FERC’s traditional NGA jurisdiction, to report information annually to FERC concerning their natural gas sales and purchases. FERC requires any wholesale market participant that sells 2.2 million MMBtus or more annually in “reportable” natural gas sales to provide a report, known as FERC Form 552, to FERC. Reportable natural gas sales include sales of natural gas that utilize a daily or monthly gas price index, contribute to index price formation, or could contribute to index price formation, such as fixed price transactions for next-day or next-month delivery. 
+FERC also regulates interstate natural gas transportation rates, terms and conditions of natural gas transportation service, and the terms under which we as a shipper may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and for the release of our excess, if any, natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities. 
+Under FERC’s current regulatory regime, interstate transportation services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. The FERC-regulated tariffs, under which interstate pipelines provide such open-access transportation service, contain strict limits on the means by which a shipper releases its pipeline capacity to another potential shipper, which provisions include FERC’s “shipper-must-have-title” rule. Violations by a shipper (i.e., a pipeline customer) of FERC’s capacity release rules or shipper-must-have-title rule could subject a shipper to substantial penalties from FERC. 
+With respect to its regulation of natural gas pipelines under the NGA, FERC has not generally required the applicant for construction of a new interstate natural gas pipeline to produce evidence of the GHG emissions of the proposed pipeline’s customers. In August 2017, the U.S. Circuit Court of Appeals for the DC Circuit issued a decision remanding a natural gas pipeline certificate application to FERC, which required FERC to revise its environmental impact statement for the proposed pipeline to take into account GHG carbon emissions from downstream power plants using natural gas transported by the new pipeline. It is too early to determine the impacts of this Court decision, but it could be significant. 
+Gathering service, which occurs on pipeline facilities located upstream of FERC-jurisdictional interstate transportation services, is regulated by the states onshore and in state waters. Depending on changes in the function performed by particular pipeline facilities, FERC has in the past reclassified certain FERC-jurisdictional transportation facilities as non-jurisdictional gathering facilities and FERC has reclassified certain non-jurisdictional gathering facilities as FERC-jurisdictional transportation facilities. Any such changes could result in an increase to our costs of transporting gas to point-of-sale locations. 
+The pipelines used to gather and transport natural gas being produced by the Company are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), the Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In addition, PHMSA had initially considered regulations regarding, among other things, the designation of additional high consequence areas along pipelines, minimum requirements for leak detection systems, installation of emergency flow restricting devices, and revision of valve spacing requirements. In October 2015, PHMSA issued proposed new safety regulations for hazardous liquid pipelines, including a requirement that all hazardous liquid pipelines have a system for detecting leaks and that operators address affected pipelines following extreme weather events or natural disasters. On January 13, 2017, these proposed regulations were finalized; however, the rule was subsequently withdrawn by PHMSA on January 24, 2017. The future disposition of these potential new requirements remains uncertain. 
+Oil and NGLs Sales and Transportation. Sales of oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. 
+19 
+The Company’s sales of oil and natural gas liquids are also affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by FERC under the Interstate Commerce Act. FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors. 
+Further, interstate common carrier oil pipelines must provide service on a non-discriminatory basis under the Interstate Commerce Act (“ICA”), which is administered by FERC. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors. 
+In addition, FERC issued a declaratory order in November 2017, involving a marketing affiliate of an oil pipeline, which held that certain arrangements between an oil pipeline and its marketing affiliate would violate the ICA’s anti-discrimination provisions. FERC held that providing transportation service to affiliates at what is essentially the variable cost of the movement, while requiring non-affiliated shippers to pay the filed tariff rate, would violate the ICA. Rehearing has been sought of this FERC order by various pipelines. It is too recent an event to determine the impact this FERC order may have on oil pipelines, their marketing affiliates, and the price of oil and other liquids transported by such pipelines. 
+Any transportation of the Company’s oil, natural gas liquids and purity components (ethane, propane, butane, iso-butane, and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts 171-180, including Emergency Orders by the FRA regulations initially established on May 8, 2015 by PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids; PHMSA regulations were subsequently amended to remove certain requirements on September 25, 2018. 
+On January 13, 2017, PHMSA issued final new safety regulations for hazardous liquid pipelines, including a requirement that all hazardous liquid pipelines have a system for detecting leaks and addressing affected pipelines following extreme weather events or natural disasters. However, this rule was subsequently withdrawn by PHMSA on January 24, 2017; the future disposition of these potential new requirements remains uncertain. 
+State Regulation. Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill. 
+The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us. 
+Commitments and Contingencies 
+The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment will not have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies included, and claims for damages to property, employees, other persons, and the environment resulting from the Company’s operations could have on its activities. See Note 14 in the Footnotes to the Financial Statements for additional information. 
+20 
+Available Information 
+We make available free of charge on our website (www.callon.com) our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the SEC. 
+We also make available within the “About Callon” section of our website our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and Audit, Compensation, Strategic Planning and Reserve, and Nominating and Corporate Governance Committee Charters, which have been approved by our Board of Directors. We will make timely disclosure on our website of any change to, or waiver from, the Code of Business Conduct and Ethics for our principal executive and senior financial officers. A copy of our Code of Business Conduct and Ethics is also available, free of charge by writing us at: General Counsel, Callon Petroleum Company, 1401 Enclave Parkway, Suite 600, Houston, TX 77077. 
+21 
+ITEM 1A. Risk Factors 
+Risk Factors 
+Risks Related to the Oil & Natural Gas Industry 
+Oil and natural gas prices are volatile, and substantial or extended declines in prices may adversely affect our results of operations and financial condition . Our success is highly dependent on prices for oil and natural gas, which have been extremely volatile in recent years. Approximately 75% - 80% of our anticipated 2019 production is oil, on a BOE basis. Extended periods of low prices for oil or natural gas will have a material adverse effect on us. The prices of oil and natural gas depend on factors we cannot control such as macro-economic conditions, levels of production, demand for oil and natural gas, relative price and availability of alternative forms of energy, actions by OPEC and other countries, legislative and regulatory actions, technology developments impacting energy consumption and energy supply, and weather. Prices of oil and natural gas will affect the following aspects of our business: 
+• 
+our revenues, cash flows, earnings and returns; 
+• 
+the amount of oil and natural gas that we are economically able to produce; 
+• 
+our ability to attract capital to finance our operations and the cost of the capital; 
+• 
+the amount we are allowed to borrow under our Credit Facility; 
+• 
+the profit or loss we incur in exploring for and developing our reserves; and 
+• 
+the value of our oil and natural gas properties. 
+These factors and the volatility of the energy markets, which we expect will continue, make it extremely difficult to predict future oil, natural gas and NGLs price movements with any certainty. During the five years ended December 31, 2018, NYMEX WTI oil futures contract prices ranged from a high of $107.26 per barrel on June 20, 2014 to a low of $26.21 per barrel on February 11, 2016 , and NYMEX Henry Hub gas futures prices ranged from a high of $6.15 per MMBtu on February 19, 2014 to a low of $1.64 per MMBtu on March 3, 2016 . As of December 31, 2018 , NYMEX WTI oil futures contract prices and NYMEX Henry Hub gas futures prices were $45.41 per barrel and $2.94 per MMBtu, respectively. 
+Although oil and natural gas prices have increased significantly since 2016, a buildup in inventories, lower global demand, or other factors could cause commodity prices to weaken, which could negatively affect our cash flows and results of operations. Under such conditions, we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in the present value of our reserves and our ability to develop future reserves. Lower commodity prices may also reduce the amount of oil and natural gas that we can produce economically. 
+If commodity prices decrease from current levels, a significant portion of our development projects could become uneconomic. This may result in our having to make significant downward adjustments to our estimated proved reserves. As a result, a substantial or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. In addition, fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. 
+Any substantial and extended decline in the price of oil or natural gas could have an adverse effect on our borrowing capacity, our ability to obtain additional capital, and our revenues, profitability and cash flows. 
+If oil and natural gas prices remain depressed for extended periods of time, we may be required to make significant downward adjustments to the carrying value of our oil and natural gas properties. Under the full cost method, which we use to account for our oil and natural gas properties, the net capitalized costs of our oil and natural gas properties may not exceed the present value, discounted at 10%, of future net cash flows from estimated net proved reserves, using the preceding 12-months’ average oil and natural gas prices, plus the lower of cost or fair market value of our unproved properties. If net capitalized costs of our oil and natural gas properties exceed this “ceiling test” limit, we must charge the amount of the excess to earnings. This type of charge will not affect our cash flows, but will reduce the book value of our stockholders’ equity. We review the carrying value of our properties quarterly and once incurred, a write-down of oil and natural gas properties is not reversible at a later date, even if prices increase. See Note 2 in the Footnotes to the Financial Statements as well as the Supplemental Information on Oil and Natural Gas Operations for additional information. 
+For the period ended December 31, 2018 , we did not recognize a write-down of oil and natural gas properties as a result of the ceiling test limitation. The ceiling test calculation as of December 31, 2018 was calculated using the average annual realized prices used in determining the estimated future net cash flows from proved reserves of $58.40 per barrel of oil and $3.64 per Mcf of natural gas. Oil 
+22 
+prices continue to fluctuate and we may experience ceiling test write-downs in the future. Any future ceiling test cushion, and the risk we may incur write-downs or impairments, will be subject to fluctuation as a result of acquisition or divestiture activity. 
+Our estimated reserves are based on interpretations and assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. This 2018 Annual Report on Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. 
+Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from the estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report. Additionally, estimates of reserves and future cash flows may be subject to material downward or upward revisions, based on production history, development drilling and exploration activities and prices of oil and natural gas. 
+You should not assume that any present value of future net cash flows from our estimated net proved reserves contained in this 2018 Annual Report on Form 10-K represents the market value of our oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves at December 31, 2018 on average 12-month prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures, the rate and timing of production, and changes in governmental regulations or taxes. At December 31, 2018 , approximately 29% of the discounted present value of our estimated net proved reserves consisted of PUDs. PUDs represented 46% of total proved reserves by volume. Recovery of PUDs generally requires significant capital expenditures and successful drilling operations. Our reserve estimates include the assumption that we will make significant capital expenditures to develop these PUDs and the actual costs, development schedule, and results associated with these properties may not be as estimated. In addition, the 10% discount factor that we use to calculate the net present value of future net revenues and cash flows may not necessarily be the most appropriate discount factor based on our cost of capital in effect from time to time and the risks associated with our business and the oil and gas industry in general. 
+Unless we replace our oil and gas reserves, our reserves and production will decline. Our future oil and gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our production, revenues, reserve quantities and cash flows will decline. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. We may not be successful in finding, developing or acquiring additional reserves, and our efforts may not be economic. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be limited to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. 
+Competitive industry conditions may negatively affect our ability to conduct operations. We compete with numerous other companies in virtually all facets of our business. Our competitors in development, exploration, acquisitions and production include major integrated oil and gas companies and smaller independents as well as numerous financial buyers. Therefore, competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources permit. We also compete for the materials, equipment, personnel and services that are necessary for the exploration, development and operation of our properties. Our ability to increase reserves in the future will be dependent on our ability to select and acquire suitable prospects for future exploration and development. Factors that affect our ability to compete in the marketplace include our: 
+• 
+access to the capital necessary to drill wells and acquire properties; 
+• 
+ability to acquire and analyze seismic, geological and other information relating to a property; 
+• 
+ability to retain the personnel necessary to properly evaluate seismic and other information relating to a property; 
+• 
+ability to procure materials, equipment, personnel and services required to explore, develop and operate our properties, including the ability to procure fracture stimulation services on wells drilled; and 
+• 
+ability to access pipelines, and the location of facilities used to produce and transport oil and natural gas production. 
+The unavailability or high cost of drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget. From time to time, our industry experiences a shortage of drilling rigs, equipment, supplies, water or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews and other experienced personnel rise as the level of activity increases. Increasing 
+23 
+levels of exploration and production may increase the demand for oilfield services and equipment, and the costs of these services and equipment may increase, while the quality of these services and equipment may suffer. The unavailability or high cost of drilling rigs, pressure pumping equipment, supplies, water or qualified personnel can materially and adversely affect our operations and profitability. 
+Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in a single geographic region. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area. All of our producing properties are geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services, or market limitations or interruption of the processing or transportation of oil, natural gas or natural gas liquids. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations. 
+We may be unable to integrate successfully the operations of recent acquisitions with our operations, and we may not realize all the anticipated benefits of these acquisitions. Our business has, and may in the future include, acquisitions that include undeveloped acreage. We can offer no assurance that we will achieve the desired profitability from our recent acquisitions or from any acquisitions we may complete in the future. In addition, failure to assimilate recent and future acquisitions successfully could adversely affect our financial condition and results of operations. Our acquisitions may involve numerous risks, including: 
+• 
+operating a larger combined organization and adding operations; 
+• 
+difficulties in the assimilation of the assets and operations of the acquired business, especially if the assets acquired are in a new geographic area; 
+• 
+risk that oil and natural gas reserves acquired may not be of the anticipated magnitude or may not be developed as anticipated; 
+• 
+loss of significant key employees from the acquired business; 
+• 
+inability to obtain satisfactory title to the assets we acquire; 
+• 
+a decrease in our liquidity if we use a portion of our available cash to finance acquisitions; 
+• 
+a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions; 
+• 
+diversion of management’s attention from other business concerns; 
+• 
+failure to realize expected profitability or growth; 
+• 
+failure to realize expected synergies and cost savings; 
+• 
+coordinating geographically disparate organizations, systems and facilities; and 
+• 
+coordinating or consolidating corporate and administrative functions. 
+Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. If we consummate any future acquisition, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisition and current operations, which in turn, could negatively impact our results of operations. 
+We may fail to fully identify problems with any properties we acquire, and as such, assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities. We are actively seeking to acquire additional acreage in Texas or other regions in the future. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, adequacy of title, operating and capital costs and potential environmental and other liabilities. Although we conduct a review which we believe is consistent with industry practices, we can give no assurance that we have identified or will identify all existing or potential problems associated with such properties or that we will be able to mitigate any problems we do identify. Such assessments are inexact and their accuracy is inherently uncertain. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface, title and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms. 
+24 
+Restrictions on our ability to obtain, recycle and dispose of water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner. Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to secure water from local land owners and other third party sources for use in our operations. If drought conditions were to occur or demand for water were to outpace supply, our ability to obtain water could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. Along with the risks of other extreme weather events, drought risk, in particular, is likely increased by climate change. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows. In addition, significant amounts of water are produced in our operations. Inadequate access to or availability of water recycling or water disposal facilities could adversely affect our production volumes or significantly increase the cost of our operations. 
+Factors beyond our control affect our ability to market production and our financial results. The ability to market oil and natural gas from our wells depends upon numerous factors beyond our control. These factors could negatively affect our ability to market all of the oil or natural gas we produce. In addition, we may be unable to obtain favorable prices for the oil and natural gas we produce. These factors include: 
+• 
+the extent of domestic production and imports/exports of oil and natural gas; 
+• 
+federal regulations authorizing exports of liquefied natural gas (“LNG”), the development of new LNG export facilities under construction in the U.S. Gulf Coast region, and the first LNG exports from such facilities; 
+• 
+the construction of new pipelines capable of exporting U.S. natural gas to Mexico and Permian Basin oil production to the Gulf Coast; 
+• 
+the proximity of hydrocarbon production to pipelines; 
+• 
+the availability of gas processing, pipeline, and/or refining capacity; 
+• 
+the demand for oil and natural gas by utilities and other end users; 
+• 
+the availability of alternative fuel sources; 
+• 
+the effects of inclement weather; 
+• 
+state and federal regulation of oil and natural gas marketing; and 
+• 
+federal regulation of natural gas sold or transported in interstate commerce. 
+In particular, in areas with increasing non-conventional shale drilling activity, pipeline, rail or other transportation capacity may be limited and it may be necessary for new interstate and intrastate pipelines and gathering systems to be built. 
+The marketability of our production is dependent upon transportation facilities and services owned and operated by third parties, and the unavailability of these facilities or services would have a material adverse effect on our revenue. Our ability to market our production depends on the availability and capacity of gas processing facilities and pipeline and other transportation operations, including trucking services, owned and operated by third parties. These facilities and services may be temporarily unavailable to us due to market conditions, physical or mechanical disruption, weather, lack of contracted capacity or other reasons. In addition, in certain newer development areas, processing and transportation facilities and services may not be sufficient to accommodate potential production. Our failure to obtain access to processing and transportation facilities and services on acceptable terms could materially harm our business. We may be required to shut in wells for lack of a market or because of inadequate or unavailable processing or transportation capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. If we were required to shut in our production for long periods of time due to lack of transportation capacity, it would have a material adverse effect on our business, financial condition, results of operations and cash flows. 
+We have entered into firm transportation contracts that require us to pay fixed sums of money regardless of quantities actually shipped. If we are unable to deliver the necessary quantities of production, our results of operations, financial position, and liquidity could be adversely affected. We have entered into firm transportation agreements for a portion of our production in such areas in order to assure our ability, and that of our purchasers, to successfully market our production. We may also enter into firm transportation arrangements for additional production in the future. These firm transportation agreements may be more costly than interruptible or short-term transportation agreements. Additionally, these agreements obligate us to pay fees on minimum volumes regardless of actual throughput. If we have insufficient production to meet the minimum volumes, the requirements to pay for quantities not delivered could have an impact on our results of operations, financial position, and liquidity. 
+Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns. Exploration, development, drilling and production activities are subject to many risks. We may invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee 
+25 
+that any leasehold acreage acquired will be profitably developed, that new wells drilled will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, including wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, wells that are profitable may not achieve our targeted rate of return. Wells may have production decline rates that are greater than anticipated. Future drilling and completion efforts may impact production from existing wells, and parent-child effects may impact future well productivity as a result of timing, spacing proximity or other factors. 
+In addition, we may not be successful in controlling our drilling and production costs to improve our overall return. We may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including among others: 
+• 
+unexpected drilling conditions; 
+• 
+pressure or irregularities in formations; 
+• 
+lack of proximity to and shortage of capacity of transportation facilities; 
+• 
+equipment failures or accidents and shortages or delays in the availability of drilling rigs, equipment, personnel and services; and 
+• 
+compliance with governmental requirements. 
+Failure to conduct our oil and gas operations in a profitable manner may result in write-downs of our proved reserves quantities, impairment of our oil and gas properties, and a write-down in the carrying value of our unproved properties, and over time may adversely affect our growth, revenues and cash flows. 
+Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could prevent them from being drilled or delay their drilling. Our management team has identified drilling locations as an estimation of our future development activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these identified drilling locations depends on a number of uncertainties, including among others: 
+• 
+oil and natural gas prices; 
+• 
+the availability and cost of capital; 
+• 
+availability and cost of drilling, completion and production services and equipment; 
+• 
+drilling results and production decline rates; 
+• 
+lease expirations; 
+• 
+gathering, marketing and transportation constraints; and 
+• 
+regulatory approvals. 
+Because of these uncertain factors, we do not know if the identified drilling locations will ever be drilled or if we will be able to produce oil or natural gas from these drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the identified locations are located, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified. 
+The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Approximately 46% of our total estimated proved reserves as of December 31, 2018 , were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves. 
+The results of our planned development programs in new or emerging shale development areas and formations may be subject to more uncertainties than programs in more established areas and formations, and may not meet our expectations for reserves or production. The results of our horizontal drilling efforts in emerging areas and formations of the Permian Basin are generally more uncertain than drilling results in areas that are more developed and have more established production from horizontal formations such as the Wolfcamp, Spraberry and Bone Spring horizons. Because emerging areas and associated target formations have limited or no production history, we are less able to rely on past drilling results in those areas as a basis to predict our future drilling results. In addition, horizontal wells drilled in shale formations, as distinguished from vertical wells, utilize multilateral wells and stacked laterals, all of which are subject to well spacing, density and proration requirements of the Texas Railroad Commission, which requirements could adversely impact our ability to maximize the efficiency of our horizontal wells related to reservoir drainage over time. Further, access to 
+26 
+adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more challenging in new or emerging areas. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, access to gathering systems and takeaway capacity or otherwise, and/or natural gas and oil prices decline, our investment in these areas may not be as economic as we anticipate, we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future. 
+Unexpected subsurface conditions and other unforeseen operating hazards may adversely impact our ability to conduct business. There are many operating hazards in exploring for and producing oil and natural gas, including: 
+• 
+our drilling operations may encounter unexpected formations or pressures, which could cause damage to equipment or personal injury; 
+• 
+we may experience equipment failures which curtail or stop production; 
+• 
+we could experience blowouts or other damages to the productive formations that may require a well to be re-drilled or other corrective action to be taken; and 
+• 
+storms and other extreme weather conditions could cause damages to our production facilities or wells. 
+Because of these or other events, we could experience environmental hazards, including release of oil and natural gas from spills, natural gas-leaks, accidental leakage of toxic or hazardous materials, such as petroleum liquids, drilling fluids or fracturing fluids, including chemical additives, underground migration, and ruptures. 
+If we experience any of these problems, it could affect wells, gathering systems and processing facilities, which could adversely affect our ability to conduct operations. We could also incur substantial losses in excess of our insurance coverage as a result of: 
+• 
+injury or loss of life; 
+• 
+severe damage to and destruction of property, natural resources and equipment; 
+• 
+pollution and other environmental damage; 
+• 
+clean-up responsibilities; 
+• 
+regulatory investigation and penalties; 
+• 
+suspension of our operations; and 
+• 
+repairs to resume operations. 
+We cannot assure you that we will be able to maintain adequate insurance at rates we consider reasonable to cover our possible losses from operating hazards. The occurrence of a significant event not fully insured or indemnified against could materially and adversely affect our financial condition and results of operations. 
+Multi-well pad drilling may result in volatility in our operating results. We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production, which may cause volatility in our quarterly operating results. 
+The loss of key personnel could adversely affect our ability to operate. We depend, and will continue to depend in the foreseeable future, on the services of our senior officers and other key employees, as well as other third-party consultants with extensive experience and expertise in evaluating and analyzing drilling prospects and producing oil and natural gas and maximizing production from oil and natural gas properties. Our ability to retain our senior officers, other key employees and our third party consultants, none of whom are subject to employment agreements, is important to our future success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business. 
+We may not be able to keep pace with technological developments in our industry. The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected. 
+Our business could be negatively affected by security threats. A cyberattack or similar incident could occur and result in information theft, data corruption, operational disruption, damage to our reputation and/or financial loss. The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, manage operations, process and 
+27 
+record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Our technologies, systems, networks, seismic data, reserves information or other proprietary information, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or could otherwise lead to the disruption of our business operations or other operational disruptions in our exploration or production operations. Cyberattacks are becoming more sophisticated and certain cyber incidents, such as surveillance, may remain undetected for an extended period and could lead to disruptions in critical systems or the unauthorized release of confidential or otherwise protected information. These events could lead to financial losses from remedial actions, loss of business, disruption of operations, damage to our reputation or potential liability. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyberattack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. Cyber incidents have increased, and the U.S. government has issued warnings indicating that energy assets may be specific targets of cybersecurity threats. Our systems and insurance coverage for protecting against cybersecurity risks may not be sufficient. Further, as cyberattacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyberattacks. 
+Risks Related to Financial Position 
+Our business requires significant capital expenditures and we may not be able to obtain needed capital or financing on satisfactory terms or at all . We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Historically, we have funded our capital expenditures through a combination of cash flows from operations, borrowings from financial institutions, the sale of public debt and equity securities and asset dispositions. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, participation of non-operating working interest owners, the cost and availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. 
+If the borrowing base under our Credit Facility or our revenues decrease as a result of lower oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or cash available under our Credit Facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our drilling locations, which in turn could lead to a possible expiration of our leases and a decline in our estimated net proved reserves, and could adversely affect our business, financial condition and results of operations. 
+Restrictive covenants in our Credit Facility and the indenture governing our 6.125% senior unsecured notes due 2024 (“6.125% Senior Notes”) and 6.375% senior unsecured notes due 2026 (“ 6.375% Senior Notes”) may limit our ability to respond to changes in market conditions or pursue business opportunities. Our Credit Facility and the indenture governing our 6.125% Senior Notes and 6.375% Senior Notes contain restrictive covenants that limit our ability to, among other things: 
+• 
+incur additional indebtedness; 
+• 
+make investments; 
+• 
+merge or consolidate with another entity; 
+• 
+pay dividends or make certain other payments; 
+• 
+hedge future production or interest rates; 
+• 
+create liens that secure indebtedness; 
+• 
+sell assets; and 
+• 
+engage in certain other transactions without the prior consent of the lenders. 
+As a result of these covenants, we are limited in the manner in which we conduct our business and we may be unable to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business. 
+In addition, our Credit Facility requires us to maintain certain financial ratios and to make certain required payments of principal, premium, if any, and interest. If we fail to comply with these provisions or other financial and operating covenants in the Credit Facility and the indenture governing the 6.125% Senior Notes and 6.375% Senior Notes, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default: 
+28 
+• 
+the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest; 
+• 
+the lenders under our Credit Facility could elect to terminate their commitments thereunder, cease making further loans and institute foreclosure proceedings against our assets; and 
+• 
+we could be forced into bankruptcy or liquidation. 
+Our borrowings under our Credit Facility expose us to interest rate risk. Our earnings are exposed to interest rate risk associated with borrowings under our Credit Facility, which bear interest at a rate elected by us that is based on the prime, LIBOR or federal funds rate plus margins ranging from 1.25% to 2.25% depending on the interest rate used and the amount of the loan outstanding in relation to the borrowing base. 
+The borrowing base under our Credit Facility may be reduced below the amount of borrowings outstanding under such facilities. The borrowing base under our Credit Facility is currently $1.1 billion , with elected commitments of $850 million . In the future, we may not be able to access adequate funding under our Credit Facility as a result of a decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations. In addition, we cannot borrow amounts above the elected commitments, even if the borrowing base is greater, without new commitments being obtained from the lenders for such incremental amounts above the elected commitments. Our borrowing base is subject to redeterminations semi-annually, and our next scheduled borrowing base redetermination is expected to occur on or about May 2019 . If our borrowing base were to be reduced, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness. In addition, in the event the amount outstanding under our Credit Facility exceeds the elected commitments, we must repay such amounts immediately in cash. In the event the amount outstanding under our Credit Facility exceeds the redetermined borrowing base, we are required to either (i) grant liens on additional oil and gas properties (not previously evaluated in determining such borrowing base) with a value equal to or greater than such excess, (ii) repay such excess borrowings over six monthly installments, or (iii) elect a combination of options in clauses (i) and (ii). We may not have sufficient funds to make any required repayment. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, an event of default would occur under our Credit Facility. 
+We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful. Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to certain financial, economic, competitive and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. 
+If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. Our Credit Facility currently restricts our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations. 
+Our leverage and debt service obligations may adversely affect our financial condition, results of operations, and business prospects. As of December 31, 2018 , we had $600 million outstanding of 6.125% Senior Notes due 2024, $400 million outstanding of our 6.375% Senior Notes due 2026, and $200 million outstanding under our Credit Facility, which had an additional $632.3 million available for borrowings based on the existing level of commitments. Our amount of indebtedness could affect our operations in several ways, including the following: 
+• 
+require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities; 
+• 
+limit management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; 
+• 
+increase our vulnerability to downturns and adverse developments in our business and the economy; 
+• 
+limit our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness; 
+29 
+• 
+place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations; 
+• 
+make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; 
+• 
+make us vulnerable to increases in interest rates as our indebtedness under our Credit Facility may vary with prevailing interest rates; 
+• 
+place us at a competitive disadvantage relative to competitors with lower levels of indebtedness or less restrictive terms governing their indebtedness; and 
+• 
+make it more difficult for us to satisfy our obligations under the 6.125% Senior Notes, 6.375% Senior Notes, or other debt and increase the risk that we may default on our debt obligations. 
+We cannot assure you that we will be able to maintain or improve our leverage position. An element of our business strategy involves maintaining a disciplined approach to financial management. However, we are also seeking to acquire, exploit and develop additional reserves that may require the incurrence of additional indebtedness. Although we will seek to maintain or improve our leverage position, our ability to maintain or reduce our level of indebtedness depends on a variety of factors, including future performance and our future debt financing needs. General economic conditions, oil and natural gas prices and financial, business and other factors will also affect our ability to maintain or improve our leverage position. Many of these factors are beyond our control. 
+We may not be insured against all of the risks to which our business is exposed from ongoing or legacy operations. In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We cannot assure you that our insurance will be adequate to cover all losses or liabilities related to our current or legacy operations. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. No assurance can be given that we will be able to maintain insurance in the future at rates we consider reasonable and may elect none or minimal insurance coverage. The occurrence of a significant event or claim, not fully insured or indemnified against, could have a material adverse effect on our financial condition and operations. 
+Our hedging program may limit potential gains from increases in commodity prices or may result in losses or may be inadequate to protect us against continuing and prolonged declines in commodity prices. We enter into hedging arrangements from time to time to reduce our exposure to fluctuations in oil and natural gas prices and to achieve more predictable cash flow. Our hedges at December 31, 2018 are in the form of collars, put and call options, basis swaps, and other structures placed with the commodity trading branches of certain national banking institutions and with certain other commodity trading groups. These hedging arrangements may limit the benefit we could receive from increases in the market or spot prices for oil and natural gas. We cannot assure you that the hedging transactions we have entered into, or will enter into, will adequately protect us from fluctuations in oil and natural gas prices. These hedges may be inadequate to protect us from continuing and prolonged declines in oil and natural gas prices. To the extent that oil and natural gas prices remain at current levels or decline further, we will not be able to hedge future production at the same pricing level as our current hedges and our results of operations and financial condition would be negatively impacted. 
+We may not have production to offset hedges. Part of our business strategy is to reduce our exposure to the volatility of oil and natural gas prices by hedging a portion of our production. In a typical hedge transaction, we will have the right to receive from the other parties to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the other parties this difference multiplied by the quantity hedged regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements even though such payments are not offset by sales of physical production. 
+Our hedging transactions expose us to counterparty credit risk. Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract. During periods of falling commodity prices, our hedging transactions expose us to risk of financial loss if our counterparty to a derivatives transaction fails to perform its obligations under a derivatives transaction. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss. 
+The inability of one or more of our customers to meet their obligations to us may adversely affect our financial results . Our principal exposures to credit risk are through receivables resulting from the sale of our oil and natural gas production, which we market to energy marketing companies, refineries and affiliates, advances to joint interest parties and joint interest receivables. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. The largest purchaser of 
+30 
+our oil and natural gas accounted for approximately 28% of our total oil and natural gas revenues for the year ended December 31, 2018 . The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. 
+Our ability to use our existing net operating loss carryforwards or other tax attributes could be limited. At December 31, 2018, we had approximately $721 million of federal NOL carryforwards available to offset against future taxable income. Of this NOL carryforward balance, $663 million was generated prior to the effective date of new limitations on utilization of NOLs imposed by the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) and are allowable as a deduction against 100 percent of taxable income in future years but will start to expire in the tax year 2021. Utilization of any NOL depends on many factors, including our ability to generate future taxable income, which cannot be assured. In addition, Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”), generally imposes an annual limitation on the amount of NOLs that may be used to offset taxable income when a corporation has undergone an “ownership change” (as determined under Section 382). Future ownership changes or future regulatory changes could limit our ability to utilize our NOLs. To the extent we are not able to offset our future income with our NOLs, this could adversely affect our operating results and cash flows once we attain profitability. 
+We have no plans to pay cash dividends on our common stock in the foreseeable future. The terms of our Credit Facility contain limitations that impact our ability to pay dividends and make other distributions. In addition, any future determination as to the declaration and payment of cash dividends will be at the discretion of our Board of Directors and will depend upon our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors deemed relevant by our Board of Directors. 
+The availability of shares for sale in the future could reduce the market price of our common stock. In the future, we may issue securities to raise cash for acquisitions. We may also acquire interests in other companies by using a combination of cash and our common stock or only our common stock. We may also issue securities convertible into, or exchangeable for, or that represent the right to receive, our common stock. Any of these events may dilute your ownership interest in our company, reduce our earnings per share and have an adverse impact on the price of our common stock. In addition, sales of a substantial amount of our common stock in the public market, or the perception that these sales may occur, could reduce the market price of our common stock. This could also impair our ability to raise additional capital through the sale of our securities. 
+Legal and Regulatory Risks 
+We are subject to stringent and complex federal, state and local laws and regulations which require compliance that could result in substantial costs, delays or penalties. Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. For a discussion of the material regulations applicable to us, see “Regulations.” These laws and regulations may: 
+• 
+require that we acquire permits before commencing drilling; 
+• 
+regulate the spacing of wells and unitization and pooling of properties; 
+• 
+impose limitations on production or operational, emissions control and other conditions on our activities; 
+• 
+restrict the substances that can be released into the environment or used in connection with drilling and production activities or restrict the disposal of waste from our operations; 
+• 
+limit or prohibit drilling activities on protected areas such as wetlands, wilderness or other protected areas; 
+• 
+impose penalties and other sanctions for accidental and/or unpermitted spills or releases from our operations; and 
+• 
+require measures to remediate or mitigate pollution and environmental impacts from current and former operations, such as cleaning up spills or dismantling abandoned production facilities. 
+Significant expenditures may be required to comply with governmental laws and regulations applicable to us. In addition, failure to comply with these laws and regulations may result in the assessment of penalties, permit revocations, requirements for additional pollution controls or injunctions limiting or prohibiting operations. 
+The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal, state and local agencies frequently revise environmental laws and regulations, and such changes could result in increased costs for environmental compliance, such as emissions control, waste handling, permitting, or cleanup for the oil and natural gas industry and could have a significant impact on our operating costs. In general, the oil and natural gas industry recently has been the subject of increased legislative and regulatory attention with respect to environmental matters. Even if regulatory burdens temporarily ease, the historic trend of more expansive and stricter environmental legislation and regulations may continue in the long-term. 
+31 
+Further, under these laws and regulations, we could be liable for costs of investigation, removal and remediation, damages to and loss of use of natural resources, loss of profits or impairment of earning capacity, property damages, costs of increased public services, as well as administrative, civil and criminal fines and penalties, and injunctive relief. Certain environmental statutes, including the RCRA, CERCLA, OPA and analogous state laws and regulations, impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released. We could also be affected by more stringent laws and regulations adopted in the future, including any related to climate change, GHGs and hydraulic fracturing. Under the common law, we could be liable for injuries to people and property. We maintain limited insurance coverage for sudden and accidental environmental damages. We do not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Also, we do not believe that insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability or we may be required to cease production from properties in the event of environmental incidents. 
+Federal legislation and state and local legislative and regulatory initiatives relating to hydraulic fracturing and water disposal wells could result in increased costs and additional operating restrictions or delays. Hydraulic fracturing is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production and is typically regulated by state oil and gas commissions. However, legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and to require federal permitting and regulatory control of hydraulic fracturing but has not passed. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act. The EPA has also published air emission standards for certain equipment, processes and activities across the oil and natural gas sector, although the EPA is currently in the process of revising its approach to regulation of methane emission. 
+In some areas of Texas, there has been concern that certain formations into which disposal wells are injecting produced waters could become over-pressured after many years of injection, and the governing Texas regulatory agency is reviewing the data to determine whether any action is necessary to address this issue. If the Texas state agency were to decline to issue permits for, or limit the volumes of, new injection wells into the formations currently utilized by us, we may be required to seek alternative methods of disposing of produced waters, including injecting into deeper formations, which could increase our costs. 
+Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, impose additional requirements on hydraulic fracturing activities or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For example, Texas law requires the chemical components used in the hydraulic fracturing process, as well as the volume of water used, must be disclosed to the RRC and the public. Furthermore, the RRC has issued the “well integrity rule” which includes new testing and reporting requirements, such as (i) the requirement to submit to the RRC cementing reports after well completion or cessation of drilling, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. Additionally, the RRC has adopted a rule requiring applicants for certain new water disposal wells to conduct seismic activity searches using the U.S. Geological Survey to determine the potential for earthquakes within a circular area of 100 square miles. The rule also clarifies the RRC’s authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The RRC has used this authority to deny permits for waste disposal wells. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of drilling in general and/or hydraulic fracturing in particular. 
+In December 2016, the EPA released its final report “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States.” This report concludes that hydraulic fracturing can impact drinking water resources in certain circumstances but also noted that certain date gaps and uncertainties limited EPA’s assessment. This study could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. 
+There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, water usage and the potential for impacts to surface water, groundwater and the environment generally, and a number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. Several states and municipalities have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances. If new laws or regulations that significantly restrict hydraulic fracturing or water disposal wells are adopted, such laws could make it more difficult or costly for us to drill for and produce oil and natural gas as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and 
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+abandonment requirements, permitting delays and potential increases in costs. These changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing. 
+Climate change legislation or regulations restricting emissions of greenhouse gases, changes in the availability of financing for fossil fuel companies, and physical effects from climate change could adversely impact our operating costs and demand for the oil and natural gas we produce. In recent years, federal, state and local governments have taken steps to reduce emissions of GHGs. The EPA has finalized a series of GHG monitoring, reporting and emissions control rules, and the U.S. Congress has, from time to time, considered adopting legislation to reduce emissions. Several states have already taken measures to reduce emissions of GHGs primarily through the development of GHG emission inventories and/or regional GHG cap-and-trade programs. While we are subject to certain federal GHG monitoring and reporting requirements, our operations currently are not adversely impacted by existing federal, state and local climate change initiatives. For a description of existing and proposed GHG rules and regulations, see “Regulations.” 
+In December 2015, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change resulted in 195 countries, including the United States, coming together to develop the so-called “Paris Agreement,” which calls for the parties to undertake “ambitious efforts” to limit the average global temperature. The Agreement went into effect on November 4, 2016, and establishes a framework for the parties to cooperate and report actions to reduce greenhouse gas emissions. While the United States announced that it would withdraw from the Paris Agreement on June 1, 2017, given the requirements of the withdrawal process the earliest possible exit would be November 2020. Certain U.S. city and state governments have announced their intention to satisfy their proportionate obligations under the Paris Agreement. A number of states have begun taking actions to control and/or reduce emissions of GHGs. Restrictions on GHG emissions that may be imposed could adversely affect the oil and gas industry. The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations. 
+Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely impact the demand for, price of, and value of our products and reserves. As our operations also emit GHGs directly, current and future laws or regulations limiting such emissions could increase our own costs. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business. 
+In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Furthermore, some parties have initiated public nuisance claims under federal or state common law against certain companies involved in the production of oil and natural gas. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other liabilities. Although our business in not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition. 
+Finally, most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of droughts, storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced or cause us to incur significant costs in preparing for or responding to the effects of climatic events themselves. 
+Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) establishes federal oversight and regulation of over-the-counter derivatives and requires the U.S. Commodity Futures Trading Commission (the “CFTC”) and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the over-the-counter market. 
+Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized. In one of the CFTC’s rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC has proposed but not yet approved position limits for certain futures and options contracts in various commodities and for 
+33 
+swaps that are their economic equivalents (with exemptions for certain bona fide hedging transactions). Similarly, the CFTC has proposed but not yet finalized a rule regarding the capital that a swap dealer or major swap participant is required to post with respect to its swap business. The CFTC issued a final rule on margin requirements for uncleared swap transactions in January 2016, which it amended in November 2018. The final rule as amended includes an exemption for certain commercial end-users that enter into uncleared swaps in order to hedge bona fide commercial risks affecting their business. In addition, the CFTC has issued a final rule authorizing an exception from the requirement to use cleared exchanges (rather than hedging over-the-counter) for commercial end-users who use swaps to hedge their commercial risks. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations. All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business. 
+While it is not possible at this time to predict when the CFTC will issue final rules applicable to position limits or capital requirements, depending on our ability to satisfy the CFTC’s requirements for the various exemptions available for a commercial end-user using swaps to hedge or mitigate its commercial risks, these rules and regulations may provide beneficial exemptions or may require us to comply with position limits and other limitations with respect to our financial derivative activities. When a final rule on capital requirements is issued, the Dodd-Frank Act may require our current counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which could increase the cost to us of entering into such derivatives. The Dodd-Frank Act may also require our current counterparties to financial derivative transactions to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties, and may cause some entities to cease their current business as hedge providers. These changes could reduce the liquidity of the financial derivatives markets which would reduce the ability of commercial end-users like us to hedge or mitigate their exposure to commodity price volatility. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of future swaps relative to the terms of our existing financial derivative contracts, and reduce the availability of derivatives to protect against commercial risks we encounter. 
+In addition, federal banking regulators have adopted new capital requirements for certain regulated financial institutions in connection with the Basel III Accord. The Federal Reserve Board also issued proposed regulations on September 30, 2016, proposing to impose higher risk-weighted capital requirements on financial institutions active in physical commodities, such as oil and natural gas. If and when these proposed regulations are fully implemented, financial institutions subject to these higher capital requirements may require that we provide cash or other collateral with respect to our obligations under the financial derivatives and other contracts in order to reduce the amount of capital such financial institutions may have to maintain. Alternatively, financial institutions subject to these capital requirements may require premiums to enter into derivatives and other physical commodity transactions to compensate for the additional capital costs for these transactions. Rules implementing the Basel III Accord and higher risk-weighted capital requirements could materially reduce our liquidity and increase the cost of derivative contracts and other physical commodity contracts (including through requirements to post collateral which could adversely affect our available capital for other commercial operations purposes). 
+If we reduce our use of derivative contracts as a result of any of the foregoing new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas and natural gas liquids prices, which some legislators attributed to speculative trading in derivatives and commodity instruments. Our revenues could t be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations, or cash flows. 
+Tax laws and regulations may change over time, and the recently passed comprehensive tax reform bill could adversely affect our business and financial condition. On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Act that significantly reforms the Internal Revenue Code of 1986, as amended (the “Code”). The Tax Act, among other things, (i) permanently reduces the U.S. corporate income tax rate, (ii) repeals the corporate alternative minimum tax, (iii) eliminates the deduction for certain domestic production activities, (iv) imposes new limitations on the utilization of net operating losses, and (v) provides for more general changes to the taxation of corporations, including changes to cost recovery rules and to the deductibility of interest expense, which may impact the taxation of oil and gas companies. The Tax Act is complex and far-reaching and we cannot predict with certainty the resulting impact its enactment has on us. The ultimate impact of the Tax Act may differ from our estimates due to changes in interpretations and assumptions made by us as well as additional regulatory guidance that may be issued and any such changes in interpretations or assumptions could adversely affect our business and financial condition. See Note 12 to our consolidated financial statements included elsewhere in this Annual Report for additional information. 
+In addition, from time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws, including (i) the elimination of the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties and (iii) an extension of the amortization period for certain geological and geophysical expenditures. While these specific changes are not included in the Tax Act, no accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or 
+34 
+the effective date of any such legislation would be. The elimination of such U.S. federal tax deductions, as well as any other changes to or the imposition of new federal, state, local or non-U.S. taxes (including the imposition of, or increases in production, severance or similar taxes) could adversely affect our business and financial condition. 
+Provisions of our charter documents and Delaware law may inhibit a takeover, which could limit the price investors might be willing to pay in the future for our common stock. Provisions in our certificate of incorporation and bylaws may have the effect of delaying or preventing an acquisition of the Company or a merger in which we are not the surviving company and may otherwise prevent or slow changes in our board of directors and management. In addition, because we are incorporated in Delaware, we are governed by the provisions of Section 203 of the Delaware General Corporation Law. These provisions could discourage an acquisition of the Company or other change in control transactions and thereby negatively affect the price that investors might be willing to pay in the future for our common stock. 
+We may be subject to the actions of activist shareholders. We have been the subject of an activist shareholder in the past. Responding to shareholder activism can be costly and time-consuming, disrupt our operations and divert the attention of management and our employees from executing our business plan. Activist campaigns can create perceived uncertainties as to our future direction, strategy or leadership and may result in the loss of potential business opportunities, harm our ability to attract new investors, customers and joint venture partners and cause our stock price to experience periods of volatility or stagnation. Moreover, if individuals are elected to our board of directors with a specific agenda, our ability to effectively and timely implement our current initiatives, retain and attract experienced executives and employees and execute on our long-term strategy may be adversely affected. 
+35 
+ITEM 1B. Unresolved Staff Comments 
+None. 
+ITEM 3. Legal Proceedings 
+We are a defendant in various legal proceedings and claims, which arise in the ordinary course of our business. We believe that the ultimate resolution of any such actions will not have a material effect on our financial position or results of operations. 
+ITEM 4. Mine Safety Disclosures 
+Not applicable. 
+36 
+PART II. 
+ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+Market Information 
+Our common stock trades on the New York Stock Exchange under the symbol “CPE”. 
+໿ 
+Holders 
+As of February 22, 2019 the Company had approximately 2,630 common stockholders of record. 
+Dividends 
+We have not paid any cash dividends on our common stock to date and presently do not expect to declare or pay any cash dividends on our common stock in the foreseeable future as we intend to reinvest our cash flows and earnings into our business. The declaration and payment of dividends is subject to the discretion of our Board of Directors and to certain limitations imposed under Delaware corporate law and the agreements governing our debt obligations. The timing, amount and form of dividends, if any, will depend on, among other things, our results of operations, financial condition, cash requirements and other factors deemed relevant by our Board of Directors. In addition, certain of our debt facilities contain restrictions on the payment of dividends to the holders of our common stock. 
+Holders of our 10% Series A Cumulative Preferred Stock are entitled to a cumulative dividend whether or not declared, of $5.00 per annum, payable quarterly, equivalent to 10.0% of the liquidation preference of $50.00 per share. Unless the full amount of the dividends for the 10% Series A Cumulative Preferred Stock is paid in full, we cannot declare or pay any dividend on our common stock. 
+Equity Compensation Plan Information 
+The following table summarizes information regarding the number of shares of our common stock that are available for issuance under all of our existing equity compensation plans as of December 31, 2018 (securities amounts are presented in thousands). 
+໿ 
+Plan Category 
+Number of Securities to be Issued Upon Exercise of Outstanding Options 
+Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights 
+Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans 
+Equity compensation plans approved by security holders 
+— 
+$ 
+— 
+9,807 
+Equity compensation plans not approved by security holders 
+— 
+$ 
+— 
+— 
+Total 
+— 
+$ 
+— 
+9,807 
+For additional information regarding the Company’s share-based compensation expense, see Note 10 in the Footnotes to the Financial Statements. 
+37 
+Performance Graph 
+The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the performance of the Company’s common stock relative to two broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. 
+The graph below compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the Standard & Poor’s 500 Index (“S&P 500 Index”) and Dow Jones US Select Oil & Gas Exploration and Production Index (“DJ US Select O&G E&P Index”) from December 31, 2013, through December 31, 2018 . 
+The stock performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing 
+Comparison of Five Year Cumulative Total Return 
+Assumes Initial Investment of $100 
+December 2018 
+For the Year Ended December 31, 
+Company/Market/Peer Group 
+2013 
+2014 
+2015 
+2016 
+2017 
+2018 
+Callon Petroleum Company 
+$ 
+100.00 
+$ 
+83.46 
+$ 
+127.72 
+$ 
+235.38 
+$ 
+186.06 
+$ 
+99.39 
+S&P 500 Index - Total Returns 
+100.00 
+113.69 
+115.26 
+129.05 
+157.22 
+150.32 
+DJ US Select O&G E&P 
+100.00 
+88.06 
+66.49 
+83.68 
+84.26 
+68.25 
+໿ 
+38 
+ITEM 6. Selected Financial Data 
+The following table sets forth, as of the dates and for the periods indicated, selected financial information about the Company. The financial information for each of the five years in the period ended December 31, 2018 has been derived from our audited Consolidated Financial Statements for such periods. The information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and Notes thereto. The following information is not necessarily indicative of our future results (dollars in thousands, except per share amounts). 
+໿ 
+For the Year Ended December 31, 
+2018 
+2017 
+2016 
+2015 
+2014 
+Statement of Operations Data 
+Operating revenues 
+Oil and natural gas sales 
+$ 
+587,624 
+$ 
+366,474 
+$ 
+200,851 
+$ 
+137,512 
+$ 
+151,862 
+Operating expenses 
+Total operating expenses 
+$ 
+328,094 
+$ 
+225,028 
+$ 
+248,328 
+$ 
+346,622 
+$ 
+113,592 
+Income (loss) from operations 
+259,530 
+141,446 
+(47,477 
+) 
+(209,110 
+) 
+38,270 
+Net income (loss) (a) 
+300,360 
+120,424 
+(91,813 
+) 
+(240,139 
+) 
+37,766 
+Income (loss) per share (“EPS”) 
+Basic 
+$ 
+1.35 
+$ 
+0.56 
+$ 
+(0.78 
+) 
+$ 
+(3.77 
+) 
+$ 
+0.67 
+Diluted 
+$ 
+1.35 
+$ 
+0.56 
+$ 
+(0.78 
+) 
+$ 
+(3.77 
+) 
+$ 
+0.65 
+Weighted average shares outstanding for Basic EPS 
+216,941 
+201,526 
+126,258 
+65,708 
+44,848 
+Weighted average shares outstanding for Diluted EPS 
+217,596 
+202,102 
+126,258 
+65,708 
+45,961 
+Statement of Cash Flows Data 
+Net cash provided by operating activities 
+$ 
+467,654 
+$ 
+229,891 
+$ 
+120,774 
+$ 
+89,319 
+$ 
+94,387 
+Net cash used in investing activities 
+(1,324,057 
+) 
+(1,072,532 
+) 
+(866,287 
+) 
+(259,160 
+) 
+(452,501 
+) 
+Net cash provided by financing activities 
+844,459 
+217,643 
+1,397,282 
+170,097 
+356,070 
+Balance Sheet Data 
+Total oil and natural gas properties 
+$ 
+3,718,858 
+$ 
+2,513,491 
+$ 
+1,475,401 
+$ 
+711,386 
+$ 
+742,155 
+Total assets 
+3,979,173 
+2,693,296 
+2,267,587 
+788,594 
+863,346 
+Long-term debt (b) 
+1,189,473 
+620,196 
+390,219 
+328,565 
+321,576 
+Stockholders’ equity 
+2,445,208 
+1,855,966 
+1,733,402 
+362,758 
+433,735 
+Proved Reserves Data 
+Total oil (MBbls) 
+180,097 
+107,072 
+71,145 
+43,348 
+25,733 
+Total natural gas (MMcf) 
+350,466 
+179,410 
+122,611 
+65,537 
+42,548 
+Total (MBOE) 
+238,508 
+136,974 
+91,580 
+54,271 
+32,824 
+Standardized measure (c) 
+$ 
+2,941,293 
+$ 
+1,556,682 
+$ 
+809,832 
+$ 
+570,890 
+$ 
+579,542 
+(a) 
+Net loss for 2015 included the recognition of a write-down of oil and natural gas properties of $208,435 as a result of the ceiling test limitation and $108,843 of income tax expense related to the recognition of a valuation allowance. Net loss for 2016 included the recognition of a write-down of oil and natural gas properties of $95,788 as a result of the ceiling test limitation. See the Supplemental Information on Oil and Gas Operations for more discussion. 
+(b) 
+See Note 6 in the Footnotes to the Financial Statements for additional information. 
+(c) 
+Standardized measure is the future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet. Prices are based on either the preceding 12-months’ average price, based on closing prices on the first day of each month, or prices defined by existing contractual arrangements. Future production and development costs are based on current estimates with no escalations. Estimated future cash flows have been discounted to their present values based on a 10% discount rate. See the Supplemental Information on Oil and Gas Operations for more discussion. 
+39 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+General 
+The following management’s discussion and analysis describes the principal factors affecting the Company’s results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying audited consolidated financial statements, information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results, which are included in various parts of this filing. Our website address is www.callon.com . All of our filings with the SEC are available free of charge through our website as soon as reasonably practicable after we file them with, or furnish them to, the SEC. Information on our website does not form part of this 2018 Annual Report on Form 10-K. 
+We are an independent oil and natural gas company incorporated in the State of Delaware in 1994, but our roots go back nearly 70 years to our Company’s establishment in 1950. We are focused on the acquisition, development, exploration and exploitation of unconventional, onshore, oil and natural gas reserves in the Permian Basin. The Permian Basin is located in West Texas and southeastern New Mexico and is comprised of three primary sub-basins: the Midland Basin, the Delaware Basin, and the Central Basin Platform. Since our entry into the Permian Basin in late 2009, we have historically been focused on the Midland Basin and more recently entered the Delaware Basin through an acquisition completed in February 2017. We further expanded our presence in the Delaware Basin through our acquisitions in 2018. Our operating culture is centered on responsible development of hydrocarbon resources, safety and the environment, which we believe strengthens our operational performance. Our drilling activity is predominantly focused on the horizontal development of several prospective intervals, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales. We have assembled a multi-year inventory of potential horizontal well locations and intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps. Our production was approximately 79% oil and 21% natural gas for the year ended December 31, 2018 . On December 31, 2018 , our net acreage position in the Permian Basin was 84,705 net acres. 
+Significant accomplishments for 2018 include: 
+• 
+Increased annual production in 2018 by 44% to 12,018 MBOE as compared to 2017 ; 
+• 
+Increased 2018 proved reserves by 74% to 239 MMBOE as compared to 2017 ; 
+• 
+Generated an operating margin of $40.16 per BOE produced, reflecting our high oil mix and operating cost controls; 
+• 
+Expanded our presence in the Delaware Basin through acquisitions of 30,000 net surface acres primarily adjacent to our existing position; 
+• 
+Issued $400 million aggregate principal amount of its 6.375% Senior Notes; 
+• 
+Completed an underwritten public offering of 25.3 million shares of common stock for total estimated net proceeds of approximately $288 million . 
+• 
+Amended the borrowing base under our Credit Facility to $1.1 billion with a current elected commitment level of $850 million , providing us with additional liquidity. 
+Operational Highlights 
+All of our producing properties are located in the Permian Basin. As a result of our horizontal development and acquisition efforts, our production grew 44% in 2018 compared to 2017 , increasing to 12,018 MBOE from 8,373 MBOE. Our production in 2018 was approximately 79% oil and 21% natural gas. 
+For the year ended December 31, 2018 , we drilled 70 gross ( 57.5 net) horizontal wells, completed 65 gross ( 53.1 net) horizontal wells and had eleven gross ( 9.5 net) horizontal wells awaiting completion. 
+Reserve Growth 
+As of December 31, 2018 , our estimated net proved reserves increased 74% to 238.5 MMBOE compared to 137.0 MMBOE of estimated net proved reserves at year-end 2017 . Our significant growth in proved reserves was primarily attributable to our horizontal development and acquisition efforts. Our proved reserves at year-end 2018 and 2017 were 76% oil and 24% natural gas for both periods. 
+40 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Results of Operations 
+The following table sets forth certain operating information with respect to the Company’s oil and natural gas operations for the periods indicated: ໿ 
+Twelve Months Ended December 31, 
+2018 
+2017 
+Change 
+% Change 
+2016 
+Change 
+% Change 
+Net production 
+Oil (MBbls) 
+9,443 
+6,557 
+2,886 
+44 
+% 
+4,280 
+2,277 
+53 
+% 
+Natural gas (MMcf) 
+15,447 
+10,896 
+4,551 
+42 
+% 
+7,758 
+3,138 
+40 
+% 
+Total (MBOE) 
+12,018 
+8,373 
+3,645 
+44 
+% 
+5,573 
+2,800 
+50 
+% 
+Average daily production (BOE/d) 
+32,926 
+22,940 
+9,986 
+44 
+% 
+15,227 
+7,713 
+50 
+% 
+% oil (BOE basis) 
+79 
+% 
+78 
+% 
+77 
+% 
+Average realized sales price 
+(excluding impact of settled derivatives) 
+Oil (per Bbl) 
+$ 
+56.22 
+$ 
+49.16 
+$ 
+7.06 
+14 
+% 
+$ 
+41.51 
+$ 
+7.65 
+18 
+% 
+Natural gas (per Mcf) 
+3.67 
+4.05 
+(0.38 
+) 
+(9 
+)% 
+2.99 
+1.06 
+35 
+% 
+Total (per BOE) 
+48.90 
+43.77 
+5.13 
+12 
+% 
+36.04 
+7.73 
+21 
+% 
+Average realized sales price 
+(including impact of settled derivatives) 
+Oil (per Bbl) 
+$ 
+53.31 
+$ 
+47.78 
+$ 
+5.53 
+12 
+% 
+$ 
+45.67 
+$ 
+2.11 
+5 
+% 
+Natural gas (per Mcf) 
+3.69 
+4.10 
+(0.41 
+) 
+(10 
+)% 
+3.00 
+1.10 
+37 
+% 
+Total (per BOE) 
+46.63 
+42.76 
+3.87 
+9 
+% 
+39.25 
+3.51 
+9 
+% 
+Oil and natural gas revenues 
+(in thousands) 
+Oil revenue 
+$ 
+530,898 
+$ 
+322,374 
+$ 
+208,524 
+65 
+% 
+$ 
+177,652 
+$ 
+144,722 
+81 
+% 
+Natural gas revenue 
+56,726 
+44,100 
+12,626 
+29 
+% 
+23,199 
+20,901 
+90 
+% 
+Total 
+$ 
+587,624 
+$ 
+366,474 
+$ 
+221,150 
+60 
+% 
+$ 
+200,851 
+$ 
+165,623 
+82 
+% 
+Additional per BOE data 
+Sales price (a) 
+$ 
+48.90 
+$ 
+43.77 
+$ 
+5.13 
+12 
+% 
+$ 
+36.04 
+$ 
+7.73 
+21 
+% 
+Lease operating expense (b) 
+5.76 
+5.46 
+0.30 
+5 
+% 
+6.56 
+(1.10 
+) 
+(17 
+)% 
+Gathering and treating expense (c) 
+— 
+0.50 
+(0.50 
+) 
+(100 
+)% 
+0.32 
+0.18 
+56 
+% 
+Production taxes 
+2.98 
+2.67 
+0.31 
+12 
+% 
+2.13 
+0.54 
+25 
+% 
+Operating margin 
+$ 
+40.16 
+$ 
+35.14 
+$ 
+5.02 
+14 
+% 
+$ 
+27.03 
+$ 
+8.11 
+30 
+% 
+Benchmark prices 
+WTI (per Bbl) 
+$ 
+65.23 
+$ 
+50.80 
+$ 
+14.43 
+28 
+% 
+$ 
+43.32 
+$ 
+7.48 
+17 
+% 
+Henry Hub (per Mcf) 
+3.15 
+2.99 
+0.16 
+5 
+% 
+2.52 
+0.47 
+19 
+% 
+(a) 
+Excludes the impact of commodity derivative settlements. 
+(b) 
+Excludes gathering and treating expense. 
+(c) 
+On January 1, 2018, the Company adopted the revenue recognition accounting standard. Consequently, natural gas gathering and treating expenses for the year ended December 31, 2018 were accounted for as a reduction to revenue. See Notes 2 and 3 in the Footnotes to the Financial Statements for additional information regarding revenue recognition and the treatment of gathering and treating expense. 
+41 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Revenues 
+The following tables are intended to reconcile the change in oil, natural gas and total revenue for the respective periods presented by reflecting the effect of changes in volume and in the underlying commodity prices. 
+(in thousands) 
+Oil 
+Natural Gas 
+Total 
+Revenues for the year ended December 31, 2015 
+$ 
+125,166 
+$ 
+12,346 
+$ 
+137,512 
+Volume increase 
+66,916 
+9,856 
+76,772 
+Price increase (decrease) 
+(14,430 
+) 
+997 
+(13,433 
+) 
+Net increase 
+52,486 
+10,853 
+63,339 
+Revenues for the year ended December 31, 2016 
+$ 
+177,652 
+$ 
+23,199 
+$ 
+200,851 
+Volume increase 
+94,518 
+9,383 
+103,901 
+Price increase 
+50,204 
+11,518 
+61,722 
+Net increase 
+144,722 
+20,901 
+165,623 
+Revenues for the year ended December 31, 2017 
+$ 
+322,374 
+$ 
+44,100 
+$ 
+366,474 
+Volume increase 
+141,876 
+18,432 
+160,308 
+Price increase (decrease) 
+66,648 
+(5,806 
+) 
+60,842 
+Net increase 
+208,524 
+12,626 
+221,150 
+Revenues for the year ended December 31, 2018 
+$ 
+530,898 
+$ 
+56,726 
+$ 
+587,624 
+Commodity Prices 
+The prices for oil and natural gas remain extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and actions by OPEC and other countries and government actions. Prices of oil and natural gas will affect the following aspects of our business: 
+• 
+our revenues, cash flows and earnings; 
+• 
+the amount of oil and natural gas that we are economically able to produce; 
+• 
+our ability to attract capital to finance our operations and cost of the capital; 
+• 
+the amount we are allowed to borrow under our Credit Facility; and 
+• 
+the value of our oil and natural gas properties. 
+Oil revenue 
+For the year ended December 31, 2018 , oil revenues of $531 million increased $209 million , or 65% , compared to revenues of $322 million for the year ended December 31, 2017 . The increase in oil revenue was primarily attributable to a 44% increase in production and a 14% increase in the average realized sales price, which rose to $56.22 per Bbl from $49.16 per Bbl. The increase in production was comprised of 3,479 MBbls attributable to wells placed on production as a result of our horizontal drilling program and 507 MBbls attributable to producing wells added from acquired properties. Offsetting these increases were normal and expected declines from our existing wells. 
+For the year ended December 31, 2017, oil revenues of $322 million increased $145 million, or 81%, compared to revenues of $178 million for the year ended December 31, 2016. The increase in oil revenue was primarily attributable to a 53% increase in production and an 18% increase in the average realized sales price, which rose to $49.16 per Bbl from $41.51 per Bbl. The increase in production was in production was driven by 2,125 MBbls attributable to wells placed on production as a result of our horizontal drilling program and 1,191 MBbls attributable to producing wells added from acquired properties. Offsetting these increases were normal and expected declines from our existing wells. 
+Natural gas revenue (including NGLs) 
+Natural gas revenues of $56.7 million increased $12.6 million , or 29% , during the year ended December 31, 2018 compared to $44.1 million for the year ended December 31, 2017 . The increase primarily relates to a 42% increase in natural gas volumes; offset by a 9% decrease in the average price realized, which declined to $3.67 per Mcf from $4.05 per Mcf, reflecting decreases in natural gas. The increase in production was driven by 3,706 MMcf attributable to wells placed on production as a result of our horizontal drilling program and 641 MMcf attributable to producing wells added from acquired properties. Offsetting these increases were normal and expected declines from our existing wells. 
+42 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Natural gas revenues of $44.1 million increased $20.9 million, or 90%, during the year ended December 31, 2017 compared to $23.2 million for the year ended December 31, 2016. The increase primarily relates to a 40% increase in natural gas volumes and a 35% increase in the average price realized, which rose to $4.05 per Mcf from $2.99 per Mcf, reflecting increases in natural gas. The increase in production was comprised of 1,969 MMcf attributable to wells placed on production as a result of our horizontal drilling program and 1,375 MMcf attributable to producing wells added from acquired properties. Offsetting these increases were normal and expected declines from our existing wells. 
+Operating Expenses 
+໿ 
+Twelve Months Ended December 31, 
+Per 
+Per 
+Total Change 
+BOE Change 
+(in thousands, except per unit amounts) 
+2018 
+BOE 
+2017 
+BOE 
+$ 
+% 
+$ 
+% 
+Lease operating expenses 
+$ 
+69,180 
+$ 
+5.76 
+$ 
+49,907 
+$ 
+5.96 
+$ 
+19,273 
+39 
+% 
+$ 
+(0.20 
+) 
+(3 
+)% 
+Production taxes 
+35,755 
+2.98 
+22,396 
+2.67 
+13,359 
+60 
+% 
+0.31 
+12 
+% 
+Depreciation, depletion and amortization 
+181,909 
+15.14 
+115,714 
+13.82 
+66,195 
+57 
+% 
+1.32 
+10 
+% 
+General and administrative 
+35,293 
+2.94 
+27,067 
+3.23 
+8,226 
+30 
+% 
+(0.29 
+) 
+(9 
+)% 
+Settled share-based awards 
+— 
+— 
+6,351 
+0.76 
+(6,351 
+) 
+(100 
+)% 
+(0.76 
+) 
+(100 
+)% 
+Accretion expense 
+874 
+0.07 
+677 
+0.08 
+197 
+29 
+% 
+(0.01 
+) 
+(13 
+)% 
+Acquisition expense 
+5,083 
+0.42 
+2,916 
+0.35 
+2,167 
+74 
+% 
+0.07 
+20 
+% 
+໿ 
+Twelve Months Ended December 31, 
+Per 
+Per 
+Total Change 
+BOE Change 
+(in thousands, except per unit amounts) 
+2017 
+BOE 
+2016 
+BOE 
+$ 
+% 
+$ 
+% 
+Lease operating expenses 
+$ 
+49,907 
+$ 
+5.96 
+$ 
+38,353 
+$ 
+6.88 
+$ 
+11,554 
+30 
+% 
+$ 
+(0.92 
+) 
+(13 
+)% 
+Production taxes 
+22,396 
+2.67 
+11,870 
+2.13 
+10,526 
+89 
+% 
+0.54 
+25 
+% 
+Depreciation, depletion and amortization 
+115,714 
+13.82 
+71,369 
+12.81 
+44,345 
+62 
+% 
+1.01 
+8 
+% 
+General and administrative 
+27,067 
+3.23 
+26,317 
+4.72 
+750 
+3 
+% 
+(1.49 
+) 
+(32 
+)% 
+Settled share-based awards 
+6,351 
+0.76 
+— 
+— 
+6,351 
+— 
+% 
+0.76 
+— 
+% 
+Accretion expense 
+677 
+0.08 
+958 
+0.17 
+(281 
+) 
+(29 
+)% 
+(0.09 
+) 
+(53 
+)% 
+Write-down of oil and natural gas properties 
+— 
+— 
+95,788 
+17.19 
+(95,788 
+) 
+(100 
+)% 
+(17.19 
+) 
+(100 
+)% 
+Acquisition expense 
+2,916 
+0.35 
+3,673 
+0.66 
+(757 
+) 
+(21 
+)% 
+(0.31 
+) 
+(47 
+)% 
+Lease operating expenses. These are daily costs incurred to extract oil and natural gas and maintain our producing properties. Such costs also include maintenance, repairs, gas treating fees, salt water disposal, insurance and workover expenses related to our oil and natural gas properties. 
+LOE for the year ended December 31, 2018 increased by 39% to $69.2 million compared to $49.9 million for the same period of 2017 , primarily due to production volumes increasing 44%. LOE per BOE for the year ended December 31, 2018 decreased to $5.76 per BOE compared to $5.96 per BOE for the same period of 2017 . 
+LOE for the year ended December 31, 2017 increased by 30% to $49.9 million compared to $38.4 million for the same period of 2016. Contributing to the increase was $11.0 million related to oil and natural gas properties acquired during 2016 and 2017 (see Note 4 in the Footnotes to the Financial Statements for information about the Company’s acquisitions). LOE per BOE for the year ended December 31, 2017 decreased to $5.96 per BOE compared to $6.88 per BOE for the same period of 2016, which was primarily attributable to higher production volumes resulting from an increased number of producing wells from our horizontal drilling program and acquisitions as discussed above. 
+Production taxes. Production taxes include severance and ad valorem taxes. In general, production taxes are directly related to commodity price changes; however, severance taxes are based upon current year commodity prices, whereas ad valorem taxes are based upon prior year commodity prices. Severance taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. In the counties where our production is located, we are also subject to ad valorem taxes, which are generally based on the taxing jurisdictions’ valuation of our oil and gas properties. 
+For the year ended December 31, 2018 , production taxes increased 60% , or $13.4 million , to $35.8 million compared to $22.4 million for the same period of 2017 , due to an increase in severance taxes based on higher production volumes. Also attributable is the increase in ad valorem taxes due to a higher valuation of our oil and gas properties by the taxing jurisdictions resulting from an increased number of producing wells in the current period, as a result of our horizontal drilling program and acquisitions. On a per BOE basis, production taxes for the year ended December 31, 2018 increased by 12% compared to the same period of 2017 . 
+43 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+For the year ended December 31, 2017, production taxes increased 89%, or $10.5 million, to $22.4 million compared to $11.9 million for the same period of 2016, due to an increase in severance taxes based on higher production volumes. The increase was also attributable to an increase in ad valorem taxes due to a higher valuation of our oil and gas properties by the taxing jurisdictions due to an increased number of producing wells as a result of our horizontal drilling program and acquisitions. On a per BOE basis, production taxes for the year ended December 31, 2017 increased by 25% compared to the same period of 2016. 
+Depreciation, depletion and amortization (“DD&A”). Under the full cost accounting method, we capitalize costs within a cost center and then systematically expense those costs on a units-of-production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unevaluated properties, less accumulated amortization; (ii) the estimated future expenditures to be incurred in developing proved reserves; and (iii) the estimated dismantlement and abandonment costs, net of estimated salvage values. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years. 
+For the year ended December 31, 2018 , DD&A increased 57% to $181.9 million from $115.7 million compared to the same period of 2017 . The increase is primarily attributable to a 44% increase in production and a 10% increase in our DD&A per BOE rate. The increase in production was primarily attributable to an increased number of producing wells from our horizontal drilling program and acquisitions. For the year ended December 31, 2018 , DD&A on a per unit basis increased to $15.14 per BOE compared to $13.82 per BOE for the same period of 2017 . The increase is attributable to our increase in our depreciable base and assumed future development costs related to undeveloped proved reserves relative to our increased estimated proved reserves as a result of additions made through our horizontal drilling efforts and acquisitions. 
+For the year ended December 31, 2017, DD&A increased 62% to $115.7 million from $71.4 million compared to the same period of 2016. The increase is primarily attributable to a 50% increase in production and an 8% increase in our per BOE DD&A rate. The increase in production was primarily attributable to an increased number of producing wells from our horizontal drilling program and acquisitions. For the year ended December 31, 2017, DD&A on a per unit basis increased to $13.82 per BOE compared to $12.81 per BOE for the same period of 2016. The increase is attributable to our increase in our depreciable base and assumed future development costs related to undeveloped proved reserves relative to our increased estimated proved reserves as a result of additions made through our horizontal drilling efforts and acquisitions. 
+General and administrative, net of amounts capitalized (“G&A”). G&A for the year ended December 31, 2018 increased to $35.3 million compared to $27.1 million for the same period of 2017 . G&A expenses for the periods indicated include the following (in thousands): 
+Twelve Months Ended December 31, 
+2018 
+2017 
+$ Change 
+% Change 
+Recurring expenses 
+G&A 
+$ 
+28,710 
+$ 
+21,554 
+$ 
+7,156 
+33 
+% 
+Share-based compensation 
+6,224 
+4,287 
+1,937 
+45 
+% 
+Fair value adjustments of cash-settled RSU awards 
+359 
+701 
+(342 
+) 
+(49 
+)% 
+Non-recurring expenses 
+Early retirement expenses 
+— 
+444 
+(444 
+) 
+100 
+% 
+Early retirement expenses related to share-based compensation 
+— 
+81 
+(81 
+) 
+100 
+% 
+Total G&A expenses 
+$ 
+35,293 
+$ 
+27,067 
+$ 
+8,226 
+30 
+% 
+G&A for the year ended December 31, 2017 increased to $27.1 million compared to $26.3 million for the same period of 2016 . G&A expenses for the periods indicated include the following (in thousands): 
+Twelve Months Ended December 31, 
+2017 
+2016 
+$ Change 
+% Change 
+Recurring expenses 
+G&A 
+$ 
+21,554 
+$ 
+16,477 
+$ 
+5,077 
+31 
+% 
+Share-based compensation 
+4,287 
+2,735 
+1,552 
+57 
+% 
+Fair value adjustments of cash-settled RSU awards 
+701 
+6,881 
+(6,180 
+) 
+(90 
+)% 
+Non-recurring expenses 
+Early retirement expenses 
+444 
+— 
+444 
+100 
+% 
+Early retirement expenses related to share-based compensation 
+81 
+— 
+81 
+100 
+% 
+Expense related to a threatened proxy contest 
+— 
+224 
+(224 
+) 
+(100 
+)% 
+Total G&A expenses 
+$ 
+27,067 
+$ 
+26,317 
+$ 
+750 
+3 
+% 
+44 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Settled share-based awards . In June 2017, the Company settled the outstanding share-based award agreements of its former Chief Executive Officer, resulting in $6.4 million recorded on the Consolidated Statements of Operations as Settled share-based awards. 
+Accretion expense. The Company is required to record the estimated fair value of liabilities for obligations associated with the retirement of tangible long-lived assets and the associated ARO costs. The present value of the asset retirement obligations is accreted each period and the increase to the obligation is reported as accretion expense within operating expenses in the Consolidated Statements of Operations. 
+Accretion expense increased 29% for the year ended December 31, 2018 compared to the same period of 2017 due to additional abandonment obligations recorded for the Company’s increase in drilling activities for the year, as well as assumed obligations for the Delaware Asset Acquisition. 
+Accretion expense related to our ARO decreased 29% for the year ended December 31, 2017 compared to the same period of 2016. Accretion expense is based on the Company’s ARO balance, which decreased to $6.0 million at December 31, 2017 from $6.7 million at December 31, 2016. See Note 13 in the Footnotes to the Financial Statements for additional information regarding the Company’s ARO. 
+Write-down of oil and natural gas properties. Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full cost ceiling amount). These rules require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling. 
+For the years ended December 31, 2018 and 2017, the Company recognized no write-down of oil and natural gas properties as a result of the ceiling test limitation. For the year ended December 31, 2016, the Company recognized a write-down of oil and natural gas properties of $95.8 million as a result of the ceiling test limitation, primarily driven by a 15% decrease in the 12-month average realized price of oil from $50.16 per barrel as of December 31, 2015 to $42.75 per barrel as of December 31, 2016. If commodity prices were to decline, we could incur additional ceiling test write-downs in the future. See Notes 2 and Supplemental Information on Oil and Natural Gas Operations in the Footnotes to the Financial Statements for additional information. 
+Acquisition expense. Acquisition expense increased $2.2 million for the year ended December 31, 2018 compared to the same period of 2017 and decreased $0.8 million for the year ended December 31, 2017 compared to the same period of 2016 . Acquisition expense for all periods was related to costs with respect to our acquisition efforts in the Permian Basin. See Note 4 in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions. 
+45 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Other Income and Expenses and Preferred Stock Dividends 
+For the Year Ended December 31, 
+(in thousands) 
+2018 
+2017 
+$ Change 
+% Change 
+Interest expense 
+$ 
+58,651 
+$ 
+35,942 
+$ 
+22,709 
+63 
+% 
+Capitalized interest 
+(56,151 
+) 
+(33,783 
+) 
+(22,368 
+) 
+66 
+% 
+Interest expense, net of capitalized amounts 
+2,500 
+2,159 
+341 
+16 
+% 
+(Gain) loss on derivative contracts 
+(48,544 
+) 
+18,901 
+(67,445 
+) 
+(357 
+)% 
+Other income 
+(2,896 
+) 
+(1,311 
+) 
+(1,585 
+) 
+121 
+% 
+Total 
+$ 
+(48,940 
+) 
+$ 
+19,749 
+Income tax expense 
+$ 
+8,110 
+$ 
+1,273 
+$ 
+6,837 
+537 
+% 
+Preferred stock dividends 
+(7,295 
+) 
+(7,295 
+) 
+— 
+— 
+% 
+໿ 
+For the Year Ended December 31, 
+(in thousands) 
+2017 
+2016 
+$ Change 
+% Change 
+Interest expense 
+$ 
+35,942 
+$ 
+31,728 
+$ 
+4,214 
+13 
+% 
+Capitalized interest 
+(33,783 
+) 
+(19,857 
+) 
+(13,926 
+) 
+70 
+% 
+Interest expense, net of capitalized amounts 
+2,159 
+11,871 
+(9,712 
+) 
+(82 
+)% 
+Loss on early extinguishment of debt 
+— 
+12,883 
+(12,883 
+) 
+(100 
+)% 
+Loss on derivative contracts 
+18,901 
+20,233 
+(1,332 
+) 
+(7 
+)% 
+Other income 
+(1,311 
+) 
+(637 
+) 
+(674 
+) 
+106 
+% 
+Total 
+$ 
+19,749 
+$ 
+44,350 
+Income tax (benefit) expense 
+$ 
+1,273 
+$ 
+(14 
+) 
+$ 
+1,287 
+(9,193 
+)% 
+Preferred stock dividends 
+(7,295 
+) 
+(7,295 
+) 
+— 
+— 
+% 
+Interest expense, net of capitalized amounts. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under our Credit Facility or with term debt. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to our lender in interest expense, net of capitalized amounts. In addition, we include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees in interest expense. 
+Interest expense, net of capitalized amounts, incurred during the year ended December 31, 2018 increased $0.3 million to $2.5 million compared to $2.2 million for the same period of 2017 . 
+Interest expense, net of capitalized amounts, incurred during the year ended December 31, 2017 decreased $9.7 million to $2.2 million compared to $11.9 million for the same period of 2016. The decrease is primarily attributable to a $13.9 million increase in capitalized interest compared to the 2016 period, resulting from a higher average unevaluated property balance for the year ended December 31, 2017 as compared to the same period of 2016. The increase in unevaluated property was primarily due to acquired properties (see Note 4 and Supplemental Information on Oil and Natural Gas Operations in the Footnotes to the Financial Statements for information about the Company’s acquisitions and unevaluated property balance). Offsetting the decrease was a $5.2 million increase in interest expense related to our debt due to a higher average debt balance for the year ended December 31, 2017 as compared to the same period of 2016, resulting from the issuance of an additional $200 million of our 6.125% Senior Notes in May 2017 (see Note 6 in the Footnotes to the Financial Statements for additional information about the Company’s 6.125% Senior Notes). 
+Gain (loss) on the early extinguishment of debt. During October 2016, the secured second lien term loan was repaid in full at the prepayment rate of 101% using proceeds from the sale of the 6.125% Senior Notes, which resulted in a loss on early extinguishment of debt of $12.9 million (inclusive of $3.0 million in prepayment fees and $9.9 million of unamortized debt issuance costs). See Note 6 in the Footnotes to the Financial Statements for additional information about the Company’s debt. 
+Gain (loss) on derivative instruments. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in commodity prices. This amount represents the (i) gain (loss) related to fair value adjustments on our open derivative contracts and (ii) gains (losses) on settlements of derivative contracts for positions that have settled within the period. 
+46 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+For the year ended December 31, 2018 , the net gain on derivative instruments was $48.5 million , compared to an $18.9 million net loss in 2017 . The net gain (loss) on derivative instruments for the periods indicated includes the following (in thousands): 
+໿ 
+For the Year Ended December 31, 
+ 
+2018 
+2017 
+Change 
+Oil derivatives 
+Net loss on settlements 
+$ 
+(27,510 
+) 
+$ 
+(9,067 
+) 
+$ 
+(18,443 
+) 
+Net gain (loss) on fair value adjustments 
+72,973 
+(11,426 
+) 
+84,399 
+Total gain (loss) on oil derivatives 
+$ 
+45,463 
+$ 
+(20,493 
+) 
+$ 
+65,956 
+Natural gas derivatives 
+Net gain on settlements 
+$ 
+238 
+$ 
+594 
+$ 
+(356 
+) 
+Net gain on fair value adjustments 
+2,843 
+998 
+1,845 
+Total gain on natural gas derivatives 
+$ 
+3,081 
+$ 
+1,592 
+$ 
+1,489 
+ 
+Total gain (loss) on oil & natural gas derivatives 
+$ 
+48,544 
+$ 
+(18,901 
+) 
+$ 
+67,445 
+For the year ended December 31, 2017 , the net loss on derivative instruments was $18.9 million , compared to a $20.2 million net loss in 2016 . The net gain (loss) on derivative instruments for the periods indicated includes the following (in thousands): 
+໿ 
+For the Year Ended December 31, 
+2017 
+2016 
+Change 
+Oil derivatives 
+Net gain (loss) on settlements 
+$ 
+(9,067 
+) 
+$ 
+17,801 
+$ 
+(26,868 
+) 
+Net loss on fair value adjustments 
+(11,426 
+) 
+(37,543 
+) 
+26,117 
+Total loss on oil derivatives 
+$ 
+(20,493 
+) 
+$ 
+(19,742 
+) 
+$ 
+(751 
+) 
+Natural gas derivatives 
+Net gain on settlements 
+$ 
+594 
+$ 
+102 
+$ 
+492 
+Net gain (loss) on fair value adjustments 
+998 
+(593 
+) 
+1,591 
+Total gain (loss) on natural gas derivatives 
+$ 
+1,592 
+$ 
+(491 
+) 
+$ 
+2,083 
+ 
+Total loss on oil & natural gas derivatives 
+$ 
+(18,901 
+) 
+$ 
+(20,233 
+) 
+$ 
+1,332 
+See Notes 7 and 8 in the Footnotes to the Financial Statements for additional information on the Company’s derivative contracts and disclosures related to derivative instruments. 
+Income tax expense. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. When appropriate based on our analysis, we record a valuation allowance for deferred tax assets when it is more likely than not that the deferred tax assets will not be realized. 
+The Company had an income tax expense of $8.1 million for the year ended December 31, 2018 compared to an income tax expense of less than $1.3 million for the same period of 2017 . The change in income tax is primarily related to the change in the Company’s tax position in the current period, for which there is no longer a cumulative three year loss trend and booking of a valuation allowance for deferred tax benefits as compared to the prior year. Current period income tax expense is comprised of both deferred federal and state income tax expense. 
+The Company had an income tax expense of $1.3 million for the year ended December 31, 2017 compared to an income tax benefit of less than $0.1 million for the same period of 2016. The change in income tax is primarily related to deferred state income tax expense. The effective tax rate differed from the federal income tax rate of 35% primarily due to the valuation allowance for the comparative periods, the effect of state taxes, and non-deductible executive compensation expenses. 
+47 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+The following table presents a reconciliation of the federal statutory tax rates to the effective tax rates: 
+For the Year Ended December 31, 
+Components of income tax rate reconciliation 
+2018 
+2017 
+2016 
+Income tax expense computed at the statutory federal income tax rate 
+21 
+% 
+35 
+% 
+35 
+% 
+State taxes net of federal expense 
+1 
+% 
+1 
+% 
+— 
+% 
+Section 162(m) 
+1 
+% 
+— 
+% 
+(1 
+)% 
+Valuation allowance 
+(20 
+)% 
+(35 
+)% 
+(34 
+)% 
+Effective income tax rate 
+3 
+% 
+1 
+% 
+— 
+% 
+For additional information, see Note 12 in the Footnotes to the Financial Statements. 
+Preferred stock dividends. Holders of our Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10% per annum of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share). 
+Preferred stock dividends for the year ended December 31, 2018 were consistent with the same periods of 2017 and 2016. Dividends reflect a 10% dividend yield. See Note 11 in the Footnotes to the Financial Statements for additional information. 
+Liquidity and Capital Resources 
+Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions, the issuance of debt and equity securities, and non-core asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration and exploitation of oil and natural gas properties, in addition to refinancing of debt instruments. 
+In 2018, we issued $400 million aggregate principal amount of 6.375% Senior Notes with a maturity date of July 1, 2026 and interest payable semi-annually beginning on January 1, 2019. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $394 million . In addition, we amended the borrowing base under our Credit Facility to $1.1 billion with a current elected commitment level of $850 million , providing us with additional liquidity. Also in 2018, we completed an underwritten public offering of 25.3 million shares of common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering costs) of approximately $288 million . We used proceeds from the issuance and offering to partially fund the Delaware Asset Acquisition completed in the third quarter, described in Note 4 in our Consolidated Financial Statements. 
+In 2017, we issued an additional $200 million aggregate principal amount of our 6.125% Senior Notes to raise additional capital. We continue to evaluate other sources of capital to complement our cash flow from operations and other sources of capital as we pursue our long-term growth plans. See Note 6 in the Footnotes to the Financial Statements for additional information about the Company’s debt. 
+For the year ended December 31, 2018 , cash and cash equivalents decreased $11.9 million to $16.1 million compared to $28.0 million at December 31, 2017 . 
+Twelve Months Ended December 31, 
+(in thousands) 
+2018 
+2017 
+2016 
+Net cash provided by operating activities 
+$ 
+467,654 
+$ 
+229,891 
+$ 
+120,774 
+Net cash used in investing activities 
+(1,324,057 
+) 
+(1,072,532 
+) 
+(866,287 
+) 
+Net cash provided by financing activities 
+844,459 
+217,643 
+1,397,282 
+Net change in cash and cash equivalents 
+$ 
+(11,944 
+) 
+$ 
+(624,998 
+) 
+$ 
+651,769 
+Operating activities. For the year ended December 31, 2018 , net cash provided by operating activities was $467.7 million , compared to $229.9 million for the same period in 2017 . The change in operating activities was predominantly attributable to the following: 
+• 
+An increase in revenue due to both increase in realized pricing and production volumes; 
+• 
+A decrease in settlements of derivative contracts, due to overall increases in commodity pricing; 
+• 
+Operating expenses such as LOE and production taxes increasing at a lower rate than revenues; 
+• 
+A decrease in payments for cash-settled restricted stock unit (“RSU”) awards; and 
+• 
+An increase in net changes to working capital 
+48 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Production, realized prices, and operating expenses are discussed below in Results of Operations. See Notes 7 and 8 in the Footnotes to the Financial Statements for a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation. 
+Investing activities . For the year ended December 31, 2018 , net cash used in investing activities was $1,324.1 million compared to $1,072.5 million for the same period in 2017 . The change in investing activities was primarily attributable to the following: 
+• 
+A $191.3 million increase in capital expenditures due to increased activity from our 2018 development program, focused on multi-well pads, as well as additional investments in facilities and infrastructure. We maintained an average of five rigs throughout the year, as compared to 2017, when we averaged three to four rigs. 
+• 
+A $60.2 million increase in acquisitions, net of proceeds from the sale of mineral interest and equipment. 
+Our investing activities, on a cash basis, include the following for the periods indicated (in thousands): 
+໿ 
+Twelve Months Ended December 31, 
+2018 
+2017 
+$ Change 
+Operational expenditures 
+$ 
+537,514 
+$ 
+355,833 
+$ 
+181,681 
+Seismic, leasehold and other 
+8,555 
+16,385 
+(7,830 
+) 
+Capitalized general and administrative costs 
+24,383 
+17,016 
+7,367 
+Capitalized interest 
+40,721 
+30,605 
+10,116 
+Total capital expenditures 
+611,173 
+419,839 
+191,334 
+Acquisitions 
+718,793 
+718,456 
+337 
+Acquisition deposits 
+— 
+(45,238 
+) 
+45,238 
+Proceeds from the sale of mineral interest and equipment 
+(9,009 
+) 
+(20,525 
+) 
+11,516 
+Additions to other assets 
+3,100 
+— 
+3,100 
+Total investing activities 
+$ 
+1,324,057 
+$ 
+1,072,532 
+$ 
+251,525 
+General and administrative expenses and capitalized interest are discussed below in Results of Operations. See Notes 4 and 14 in the Footnotes to the Financial Statements for additional information on significant acquisitions and drilling rig leases. 
+Financing activities. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under our Credit Facility, term debt and equity offerings. For the year ended December 31, 2018 , net cash provided by financing activities was $844.5 million compared to cash provided by financing activities of $217.6 million during the same period of 2017 . The change in net cash provided by financing activities was primarily attributable to the following: 
+• 
+Completed an underwritten public offering of 25.3 million shares of common stock for total estimated net proceeds of approximately $288 million . 
+• 
+Increased in net borrowings of $350 million from increases in net borrowings on the Credit Facility and issuance of our 6.375% senior unsecured notes. 
+Net cash provided by financing activities includes the following for the periods indicated (in thousands): 
+໿ 
+ 
+Twelve Months Ended December 31, 
+ 
+2018 
+2017 
+$ Change 
+Net borrowings on Credit Facility 
+$ 
+175,000 
+$ 
+25,000 
+$ 
+150,000 
+Issuance of 6.125% Senior Notes 
+— 
+200,000 
+(200,000 
+) 
+Premium on the issuance of 6.125% Senior Notes 
+— 
+8,250 
+(8,250 
+) 
+Issuance of 6.375% senior unsecured notes due 2026 
+400,000 
+— 
+400,000 
+Issuance of common stock 
+287,988 
+— 
+287,988 
+Payment of preferred stock dividends 
+(7,295 
+) 
+(7,295 
+) 
+— 
+Payment of deferred financing costs 
+(9,430 
+) 
+(7,194 
+) 
+(2,236 
+) 
+Tax withholdings related to restricted stock units 
+(1,804 
+) 
+(1,118 
+) 
+(686 
+) 
+Net cash provided by financing activities 
+$ 
+844,459 
+$ 
+217,643 
+$ 
+626,816 
+See Note 6 in the Footnotes to the Financial Statements for additional information about the Company’s debt. See Note 11 in the Footnotes to the Financial Statements for additional information about the Company’s equity offerings and Series A 10% Cumulative Preferred Stock. 
+49 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Credit Facility 
+Effective April 5, 2018 , the Company entered into the first amendment to the Sixth Amended and Restated Credit Agreement to the Credit Facility, which (1) increased the borrowing base to $825 million , (2) increased the elected commitment amount to $650 million , (3) amended various covenants and terms to reflect current market trends, and (4) extended the maturity date to May 25, 2023 . 
+Effective September 27, 2018 , the Company entered into the second amendment to the Sixth Amended and Restated Credit Agreement to the Credit Facility, which (1) increased the borrowing base to $1.1 billion , (2) increase the elected commitment amount to $850 million , and (3) amended various covenants and terms to reflect current market trends. As of December 31, 2018 , the Credit Facility’s borrowing base remained at $1.1 billion with an elected commitment amount of $850 million . 
+For the year ended December 31, 2018 , the Credit Facility had a weighted-average interest rate of 3.62% , calculated as the LIBOR plus a tiered rate ranging from 1.25% to 2.25% , which is determined based on utilization of the facility. In addition, the Credit Facility carries a current commitment fee of 0.375% per annum, payable quarterly, on the unused portion of the borrowing base. 
+See Note 6 in the Footnotes to the Financial Statements for additional information about the Company’s Credit Facility. 
+6.125% Senior Notes 
+On October 3, 2016, the Company issued $400 million aggregate principal amount of 6.125% Senior Notes with a maturity date of October 1, 2024 and interest payable semi-annually beginning on April 1, 2017. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $391.3 million . The 6.125% Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. 
+On May 19, 2017, the Company issued an additional $200 million aggregate principal amount of its 6.125% Senior Notes which with the existing $400 million aggregate principal amount of 6.125% Senior Notes are treated as a single class of notes under the indenture. The net proceeds of the offering, including a premium issue price of 104.125% and after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $206 million . 
+See Note 6 in the Footnotes to the Financial Statements for additional information about the Company’s 6.125% Senior Notes. 
+6.375% Senior Notes 
+On June 7, 2018, the Company issued $400 million aggregate principal amount of 6.375% Senior Notes with a maturity date of July 1, 2026 and interest payable semi-annually beginning on January 1, 2019. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $394 million . The 6.375% Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. 
+10% Series A Cumulative Preferred Stock (“Preferred Stock”) 
+Holders of the Company’s Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10.0% per annum of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share). Dividends are payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by our Board of Directors. Preferred Stock dividends were $7.3 million in 2018 . 
+The Preferred Stock has no stated maturity and is not subject to any sinking fund or other mandatory redemption. On or after May 30, 2018, the Company may, at its option, redeem the Preferred Stock, in whole or in part, by paying $50.00 per share, plus any accrued and unpaid dividends to the redemption date. As of December 31, 2018 , the Company had 1.5 million shares of its Preferred Stock issued and outstanding. See Note 11 in the Footnotes to the Financial Statements for additional information about the Company’s Preferred Stock. 
+50 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+2019 Capital Plan and Outlook 
+Our operational capital budget for 2019 has been established in the range of $500 to $525 million with infrastructure and facilities capital comprising approximately 15% of operational capital. We expect to run an average of five drilling rigs to support larger and more efficient, multi-well pad development and we plan to place 47 to 49 net wells on production, with an increase of approximately 15% average net lateral length to approximately 8,400 feet. 
+Our revenues, earnings, liquidity and ability to grow are substantially dependent on the prices we receive for, and our ability to develop our reserves of oil and natural gas. We believe the long-term outlook for our business is favorable due to our resource base, low cost structure, financial strength, risk management, and disciplined investment of capital. We monitor current and expected market conditions, including the commodity price environment, and our liquidity needs and may adjust our capital investment plan accordingly. 
+Contractual Obligations 
+The following table includes the Company’s current contractual obligations and purchase commitments (in thousands): 
+໿ 
+Payments due by Period 
+Total 
+< 1 Year 
+Years 2 - 3 
+Years 4 - 5 
+> 5 Years 
+6.125% Senior Notes (a) 
+$ 
+600,000 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+600,000 
+6.375% Senior Notes (a) 
+400,000 
+— 
+— 
+— 
+400,000 
+Credit Facility (b) 
+200,000 
+— 
+— 
+200,000 
+— 
+Interest expense and other fees related to debt commitments (c) 
+445,240 
+71,922 
+143,843 
+138,162 
+91,313 
+Drilling rig leases (d) 
+46,889 
+33,641 
+13,248 
+— 
+— 
+Other commitments 
+13,299 
+5,050 
+7,814 
+435 
+— 
+Asset retirement obligations (e) 
+14,292 
+3,887 
+5,604 
+— 
+4,801 
+Total contractual obligations 
+$ 
+1,719,720 
+$ 
+114,500 
+$ 
+170,509 
+$ 
+338,597 
+$ 
+1,096,114 
+(a) 
+Includes the outstanding principal amount only. The 6.125% Senior Notes and 6.375% Senior Notes have maturity dates of October 1, 2024 and July 1, 2026 , respectively. See Note 6 in the Footnotes to the Financial Statements for additional information about the Company’s debt obligations. 
+(b) 
+As of December 31, 2018 , the Credit Facility had a $200 million balance outstanding. We cannot predict the timing of future borrowings and repayments. The Credit Facility has a maturity date of May 25, 2023 . See Note 6 in the Footnotes to the Financial Statements for additional information about the Company’s debt obligations. 
+(c) 
+Includes estimated cash payments on the 6.125% Senior Notes, 6.375% Senior Notes, the Credit Facility and the minimum amount of commitment fees due on the Credit Facility. 
+(d) 
+Drilling rig leases represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a party on December 31, 2018 . The value in the table represents the gross amount that we are committed to pay. However, we will record our proportionate share based on our working interest in our consolidated financial statements as incurred. See Note 14 in the Footnotes to the Financial Statements for additional information related to the Company’s drilling rig leases. 
+(e) 
+Amounts represent our estimates of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note 13 in the Footnotes to the Financial Statements for additional information. 
+In 2018, we executed a firm transportation agreement for dedicated capacity on a new pipeline system that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from multiple marketing points in the Permian Basin. Subject to completion of the new pipeline system, which will have delivery points in several locations along the Gulf Coast, we will have a seven year term commitment that will apply applicable tariff rates to our 15,000 Bbls per day commitment. 
+51 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Critical Accounting Estimates 
+The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under GAAP. We also describe the most significant estimates and assumptions we make in applying these policies. See Note 2 in the Footnotes to the Financial Statements included in this 2018 Annual Report on Form 10-K for a discussion of additional accounting policies and estimates made by management. 
+Oil and natural gas properties 
+The Company utilizes the full cost method of accounting for its oil and natural gas properties whereby all costs incurred in connection with the acquisition, exploration and development of oil and natural gas reserves, including certain overhead costs, are capitalized into the “full cost pool.” The amounts capitalized into the full cost pool are depleted (charged against earnings) using the unit-of-production method. The full cost method of accounting for oil and natural gas properties requires that the Company makes estimates based on its assumptions of future events that could change. These estimates are described below. 
+Depreciation, depletion and amortization (DD&A) of oil and natural gas properties 
+The Company calculates DD&A by using the depletable base, which is equal to the net capitalized costs in our full cost pool plus estimated future development costs, and the estimated net proved reserve quantities. Capitalized costs added to the full cost pool include the following: 
+• 
+costs of drilling and equipping productive wells, dry hole costs, acquisition costs of properties with proved reserves, delay rentals and other costs related to exploration and development of our oil and natural gas properties; 
+• 
+payroll costs including the related fringe benefits paid to employees directly engaged in the acquisition, exploration and/or development of oil and natural gas properties as well as other directly identifiable general and administrative costs associated with such activities. Such capitalized costs do not include any costs related to the production of oil and natural gas or general corporate overhead; 
+• 
+costs associated with unevaluated properties, those lacking proved reserves, are excluded from the depletable base. These unevaluated property costs are added to the depletable base at such time as wells are completed on the properties or management determines these costs have been impaired. The Company’s determination that a property has or has not been impaired (which is discussed below) requires assumptions about future events; 
+• 
+estimated costs to dismantle, abandon and restore properties that are capitalized to the full cost pool when the related liabilities are incurred (see also the discussion below regarding Asset Retirement Obligations); 
+• 
+estimated future costs to develop proved properties are added to the full cost pool for purposes of the DD&A computation. The Company uses assumptions based on the latest geologic, engineering, regulatory and cost data available to it to estimate these amounts. However, the estimates made are subjective and may change over time. The Company’s estimates of future development costs are reviewed at least annually and as additional information becomes available; and 
+• 
+capitalized costs included in the full cost pool plus estimated future development costs are depleted and charged against earnings using the unit-of-production method. Under this method, the Company estimates the proved reserves quantities at the beginning of each accounting period. For each BOE produced during the period, the Company records a DD&A charge equal to the amount included in the depletable base (net of accumulated depreciation, depletion and amortization) divided by our estimated net proved reserve quantities. 
+Because the Company uses estimates and assumptions to determine proved reserves (as discussed below) and the amounts included in the depletable base, our depletion rates may materially change if actual results differ from these estimates. 
+Ceiling test 
+Under the full cost method of accounting, the Company compares, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (excluding cash flows related to estimated abandonment costs and the value of commodity derivative instruments) plus the lower of cost or fair value of unevaluated properties, to the net capitalized costs of proved oil and natural gas properties net of related deferred taxes. The Company refers to this comparison as a “ceiling test.” If the net capitalized costs of proved oil and natural gas properties exceed the estimated discounted (at a 10% annualized rate) future net cash flows from 
+52 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+proved reserves plus the lower of cost or fair value of unevaluated properties, the Company is required to write-down the value of its oil and natural gas properties to the value of the discounted cash flows. Estimated future net cash flows from proved reserves are based on a twelve-month average pricing assumption. Given the volatility of oil and natural gas prices, it is reasonably possible that the Company’s estimates of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. For the periods ended December 31, 2018 and 2017 the Company recognized no write-down of oil and natural gas properties as a result of the ceiling test limitation. For the period ending December 31, 2016 the Company recognized write-downs of oil and natural gas properties of $95.8 million , respectively, as a result of the ceiling test limitation. If oil and natural gas prices were to decline, even if only for a short period of time, we could incur additional write-downs of oil and natural gas properties in the future. See Note 2 and Supplemental Information on Oil and Natural Gas Operations in the Footnotes to the Financial Statements for additional information regarding the Company’s oil and natural gas properties. 
+Estimating reserves and present value of estimated future net cash flows 
+Estimates of quantities of proved oil and natural gas reserves, including the discounted present value of estimated future net cash flows from such reserves at the end of each quarter, are based on numerous assumptions, which are likely to change over time. These assumptions include: 
+• 
+the prices at which the Company can sell its oil and natural gas production in the future. Oil and natural gas prices are volatile, but we are required to assume that they remain constant, using the twelve-month average pricing assumption. In general, higher oil and natural gas prices will increase quantities of proved reserves and the present value of estimated future net cash flows from such reserves, while lower prices will decrease these amounts; and 
+• 
+the costs to develop and produce the Company’s reserves and the costs to dismantle its production facilities when reserves are depleted. These costs are likely to change over time, but we are required to assume that they remain constant. Increases in costs will reduce estimated oil and natural gas quantities and the present value of estimated future net cash flows, while decreases in costs will increase such amounts. 
+Changes in these prices and/or costs will affect the present value of estimated future net cash flows more than the estimated quantities of oil and natural gas reserves for the Company’s properties that have relatively short productive lives. If oil and natural gas prices remain at current levels or decline further, it will have a negative impact on the present value of estimated future net cash flows and the estimated quantities of oil and natural gas reserves. 
+In addition, the process of estimating proved oil and natural gas reserves requires that the Company’s independent and internal reserve engineers exercise judgment based on available geological, geophysical and technical information. We have described the risks associated with reserve estimation and the volatility of oil and natural gas prices under “Risk Factors.” 
+Sales of oil and natural gas properties are accounted for as adjustments to the net full cost pool with no gain or loss recognized unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves. 
+Unproved properties 
+Costs, including capitalized interest, associated with properties that do not have proved reserves are excluded from the depletable base, and are included in the line item “Unevaluated properties.” Unevaluated property costs are transferred to the depletable base when wells are completed on the properties or management determines that these costs have been impaired. In addition, the Company is required to determine whether its unevaluated properties are impaired and, if so, include the costs of such properties in the depletable base. We assess properties on an individual basis or as a group. The Company considers the following factors, among others: exploration program and intent to drill, remaining lease term, and the assignment of proved reserves. This determination may require the exercise of substantial judgment by management. 
+Asset retirement obligations 
+We record our estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-life assets and the associated asset retirement costs. We estimate the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of the asset retirement obligation. Interest is accreted on the present value of the asset retirement obligations and reported as accretion expense within operating expenses in the Consolidated Statements of Operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to evaluated properties in the Consolidated Balance Sheets. 
+53 
+Management’s Discussion and Analysis of Financial Condition and Results of Operation 
+Estimating the future plugging and abandonment costs of wells and related facilities is difficult and requires management to make estimates and judgments because most of the obligations are many years in the future and asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. 
+See Note 13 in the Footnotes to the Financial Statements for additional information. 
+Derivatives 
+To manage oil and natural gas price risk on a portion of our planned future production, we have historically utilized commodity derivative instruments (including collars, swaps, put and call options and other structures) on approximately 40% to 60% of our projected production volumes in any given year. We do not use these instruments for trading purposes. Settlements of derivative contracts are generally based on the difference between the contract price and prices specified in the derivative instrument and a NYMEX price or other futures index price. 
+Our derivative positions are carried at their fair value on the balance sheet with changes in fair value recorded through earnings. The estimated fair value of our derivative contracts is based upon current forward market prices on NYMEX and in the case of collars and floors, the time value of options. For additional information regarding derivatives and their fair values, see Notes 7 and 8 in the Footnotes to the Financial Statements and Part II, Item 7A Commodity Price Risk. 
+Income taxes 
+The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices). The Company had no valuation allowance as of December 31, 2018 . See Note 12 in the Footnotes to the Financial Statements for additional information regarding Income Taxes. 
+Accounting Standards Updates (“ASU”) 
+See Note 2 in the Footnotes to the Financial Statements for information regarding ASUs. 
+Off-balance Sheet Arrangements 
+We had no off-balance sheet arrangements as of December 31, 2018 . 
+54 
+ITEM 7A. Quantitative and Qualitative Disclosures about Market Risk 
+We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer credit risk. We mitigate these risks through a program of risk management including the use of derivative instruments. 
+Commodity price risk 
+The Company’s revenues are derived from the sale of its oil and natural gas production. The prices for oil and natural gas remain volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and government actions. From time to time, the Company enters into derivative financial instruments to manage oil and natural gas price risk, related both to NYMEX benchmark prices and regional basis differentials. The total volumes which we hedge through use of our derivative instruments varies from period to period; however, generally our objective is to hedge approximately 40% to 60% of our anticipated internally forecast production for the next 12 to 24 months, subject to the covenants under our Credit Facility. Our hedge policies and objectives may change significantly with movements in commodities prices or futures prices. 
+The Company’s hedging portfolio as of December 31, 2018, linked to NYMEX benchmark pricing, covers approximately 6,389,000 Bbls and 8,282,500 MMBtu of our expected oil and natural gas production, respectively, for the full year of 2019 . We also have commodity hedging contracts linked to Midland WTI oil basis differentials relative to Cushing and Waha natural gas basis differentials covering approximately 4,746,500 Bbls and 11,321,000 MMBtu, respectively, of our expected oil and natural gas production for the full year of 2019 . See Note 7 in the Footnotes to the Financial Statements for a description of the Company’s outstanding derivative contracts at December 31, 2018 , and derivative contracts established subsequent to that date. 
+The Company may utilize fixed price swaps, which reduce the Company’s exposure to decreases in commodity prices and limit the benefit the Company might otherwise have received from any increases in commodity prices. Swap contracts may also be enhanced by the simultaneous sale of call or put options to effectively increase the effective swap price as a result of the receipt of premiums from the option sales. 
+The Company may utilize price collars to reduce the risk of changes in oil and natural gas prices. Under these arrangements, no payments are due by either party as long as the applicable market price is above the floor price (purchased put option) and below the ceiling price (sold call option) set in the collar. If the price falls below the floor, the counter-party to the collar pays the difference to the Company, and if the price rises above the ceiling, the counterparty receives the difference from the Company. Additionally, the Company may sell put (or call) options at a price lower than the floor price (or higher than the ceiling price) in conjunction with a collar (three-way collar) and use the proceeds to increase either or both the floor or ceiling prices. In a three-way collar, to the extent that realized prices are below the floor price of the sold put option (or above the ceiling price of the sold call option), the Company’s net realized benefit from the three-way collar will be reduced on a dollar-for-dollar basis. 
+The Company may purchase put and call options, which reduce the Company’s exposure to decreases in oil and natural gas prices while allowing realization of the full benefit from any increases in oil and natural gas prices. If the price falls below the floor, the counterparty pays the difference to the Company. 
+The Company enters into these various agreements from time to time to reduce the effects of volatile oil and natural gas prices and does not enter into derivative transactions for speculative purposes. Presently, none of the Company’s derivative positions are designated as hedges for accounting purposes. 
+Interest rate risk 
+The Company is subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility. As of December 31, 2018 , the Company had $200.0 million outstanding under the Credit Facility with a weighted average interest rate of 3.62% . An increase or decrease of 1.00% in the interest rate would have a corresponding increase or decrease in our annual net income of approximately $2.0 million based on the balance outstanding at December 31, 2018 . See Note 6 in the Footnotes to the Financial Statements for more information on the Company’s interest rates on our Credit Facility. 
+Counterparty and customer credit risk 
+The Company’s principal exposures to credit risk are through receivables from the sale of our oil and natural gas production, joint interest receivables and receivables resulting from derivative financial contracts. 
+55 
+The Company markets its oil and natural gas production to energy marketing companies. We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. For the year ended December 31, 2018 , three purchasers accounted for more than 10% of our revenue: Rio Energy International, Inc. ( 28% ); Plains Marketing, L.P. ( 21% ); and Enterprise Crude Oil, LLC ( 14% ). The inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In order to mitigate potential exposure to credit risk, we may require from time to time for our customers to provide financial security. At December 31, 2018 our total receivables from the sale of our oil and natural gas production were approximately $87.1 million . 
+Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have or intend to drill. We have little ability to control whether these entities will participate in our wells. At December 31, 2018 , our joint interest receivables were approximately $41.5 million . 
+At December 31, 2018 our receivables resulting from derivative contracts were approximately $2.1 million . Our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. Most of the counterparties on our derivative instruments currently in place are lenders under our Credit Facility. We are likely to enter into additional derivative instruments with these or other lenders under our Credit Facility, representing institutions with investment grade ratings. We have existing International Swap Dealers Association Master Agreements (“ISDA Agreements”) with our derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of offset upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may offset all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. At December 31, 2018 we had a net derivative asset position of $47.2 million . 
+56 
+ITEM 8. Financial Statements and Supplementary Data 
+Page 
+Reports of Independent Registered Public Accounting Firm 
+58 
+Consolidated Balance Sheets as of December 31, 2018 and 2017 
+60 
+Consolidated Statements of Operations for Each of the Three Years in the Period Ended December 31, 2018 
+61 
+Consolidated Statements of Stockholders’ Equity for Each of the Three Years in the Period Ended December 31, 2018 
+62 
+Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2018 
+63 
+Notes to Consolidated Financial Statements 
+64 
+57 
+Report of Independent Registered Public Accounting Firm 
+Board of Directors and Stockholders 
+Callon Petroleum Company 
+Opinion on the financial statements 
+We have audited the accompanying consolidated balance sheets of Callon Petroleum Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2018 and 2017, the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2018, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 26, 2019 expressed an unqualified opinion. 
+Basis for opinion 
+These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. 
+/s/ GRANT THORNTON LLP 
+We have served as the Company’s auditor since 2016. 
+Houston, Texas 
+February 26, 2019 
+58 
+Report of Independent Registered Public Accounting Firm 
+Board of Directors and Stockholders 
+Callon Petroleum Company 
+Opinion on internal control over financial reporting 
+We have audited the internal control over financial reporting of Callon Petroleum Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2018, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2018, and our report dated February 26, 2019 expressed an unqualified opinion on those financial statements. 
+Basis for opinion 
+The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s report on internal control over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+Definition and limitations of internal control over financial reporting 
+A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+/s/ GRANT THORNTON LLP 
+Houston, Texas 
+February 26, 2019 
+59 
+Callon Petroleum Company 
+Consolidated Balance Sheets 
+(in thousands, except par and share data) 
+December 31, 2018 
+December 31, 2017 
+ASSETS 
+Current assets: 
+Cash and cash equivalents 
+$ 
+16,051 
+$ 
+27,995 
+Accounts receivable 
+131,720 
+114,320 
+Fair value of derivatives 
+65,114 
+406 
+Other current assets 
+9,740 
+2,139 
+Total current assets 
+222,625 
+144,860 
+Oil and natural gas properties, full cost accounting method: 
+Evaluated properties 
+4,585,020 
+3,429,570 
+Less accumulated depreciation, depletion, amortization and impairment 
+(2,270,675 
+) 
+(2,084,095 
+) 
+Net evaluated oil and natural gas properties 
+2,314,345 
+1,345,475 
+Unevaluated properties 
+1,404,513 
+1,168,016 
+Total oil and natural gas properties, net 
+3,718,858 
+2,513,491 
+Other property and equipment, net 
+21,901 
+20,361 
+Restricted investments 
+3,424 
+3,372 
+Deferred tax asset 
+— 
+52 
+Deferred financing costs 
+6,087 
+4,863 
+Acquisition deposit 
+— 
+900 
+Other assets, net 
+6,278 
+5,397 
+Total assets 
+$ 
+3,979,173 
+$ 
+2,693,296 
+LIABILITIES AND STOCKHOLDERS’ EQUITY 
+Current liabilities: 
+Accounts payable and accrued liabilities 
+$ 
+261,184 
+$ 
+162,878 
+Accrued interest 
+24,665 
+9,235 
+Cash-settleable restricted stock unit awards 
+1,390 
+4,621 
+Asset retirement obligations 
+3,887 
+1,295 
+Fair value of derivatives 
+10,480 
+27,744 
+Other current liabilities 
+13,310 
+— 
+Total current liabilities 
+314,916 
+205,773 
+Senior secured revolving credit facility 
+200,000 
+25,000 
+6.125% senior unsecured notes due 2024 
+595,788 
+595,196 
+6.375% senior unsecured notes due 2026 
+393,685 
+— 
+Asset retirement obligations 
+10,405 
+4,725 
+Cash-settleable restricted stock unit awards 
+2,067 
+3,490 
+Deferred tax liability 
+9,564 
+1,457 
+Fair value of derivatives 
+7,440 
+1,284 
+Other long-term liabilities 
+100 
+405 
+Total liabilities 
+1,533,965 
+837,330 
+Commitments and contingencies 
+Stockholders’ equity: 
+Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized: 1,458,948 shares outstanding 
+15 
+15 
+Common stock, $0.01 par value, 300,000,000 shares authorized; 227,582,575 and 201,836,172 shares outstanding, respectively 
+2,276 
+2,018 
+Capital in excess of par value 
+2,477,278 
+2,181,359 
+Accumulated deficit 
+(34,361 
+) 
+(327,426 
+) 
+Total stockholders’ equity 
+2,445,208 
+1,855,966 
+Total liabilities and stockholders’ equity 
+$ 
+3,979,173 
+$ 
+2,693,296 
+The accompanying notes are an integral part of these consolidated financial statements. 
+60 
+Callon Petroleum Company 
+Consolidated Statements of Operations 
+(in thousands, except per share data) 
+For the Year Ended December 31, 
+2018 
+2017 
+2016 
+Operating revenues: 
+Oil sales 
+$ 
+530,898 
+$ 
+322,374 
+$ 
+177,652 
+Natural gas sales 
+56,726 
+44,100 
+23,199 
+Total operating revenues 
+587,624 
+366,474 
+200,851 
+Operating expenses: 
+Lease operating expenses 
+69,180 
+49,907 
+38,353 
+Production taxes 
+35,755 
+22,396 
+11,870 
+Depreciation, depletion and amortization 
+181,909 
+115,714 
+71,369 
+General and administrative 
+35,293 
+27,067 
+26,317 
+Settled share-based awards 
+— 
+6,351 
+— 
+Accretion expense 
+874 
+677 
+958 
+Write-down of oil and natural gas properties 
+— 
+— 
+95,788 
+Acquisition expense 
+5,083 
+2,916 
+3,673 
+Total operating expenses 
+328,094 
+225,028 
+248,328 
+Income (loss) from operations 
+259,530 
+141,446 
+(47,477 
+) 
+Other (income) expenses: 
+Interest expense, net of capitalized amounts 
+2,500 
+2,159 
+11,871 
+Loss on early extinguishment of debt 
+— 
+— 
+12,883 
+(Gain) loss on derivative contracts 
+(48,544 
+) 
+18,901 
+20,233 
+Other income 
+(2,896 
+) 
+(1,311 
+) 
+(637 
+) 
+Total other (income) expense 
+(48,940 
+) 
+19,749 
+44,350 
+Income (loss) before income taxes 
+308,470 
+121,697 
+(91,827 
+) 
+Income tax (benefit) expense 
+8,110 
+1,273 
+(14 
+) 
+Net income (loss) 
+300,360 
+120,424 
+(91,813 
+) 
+Preferred stock dividends 
+(7,295 
+) 
+(7,295 
+) 
+(7,295 
+) 
+Income (loss) available to common stockholders 
+$ 
+293,065 
+$ 
+113,129 
+$ 
+(99,108 
+) 
+Income (loss) per common share: 
+Basic 
+$ 
+1.35 
+$ 
+0.56 
+$ 
+(0.78 
+) 
+Diluted 
+$ 
+1.35 
+$ 
+0.56 
+$ 
+(0.78 
+) 
+ 
+Shares used in computing income (loss) per common share: 
+Basic 
+216,941 
+201,526 
+126,258 
+Diluted 
+217,596 
+202,102 
+126,258 
+The accompanying notes are an integral part of these consolidated financial statements. 
+61 
+Callon Petroleum Company 
+Consolidated Statements of Stockholders’ Equity 
+(in thousands) 
+Preferred Stock 
+Common Stock 
+Capital in Excess of Par 
+Retained Earnings (Deficit) 
+Total Stockholders' Equity 
+Balance at 12/31/2015 
+$ 
+16 
+$ 
+801 
+$ 
+702,970 
+$ 
+(341,029 
+) 
+$ 
+362,758 
+Net loss 
+— 
+— 
+— 
+(91,813 
+) 
+(91,813 
+) 
+Shares issued pursuant to employee benefit plans 
+— 
+— 
+275 
+— 
+275 
+Restricted stock 
+— 
+4 
+2,323 
+— 
+2,327 
+Common stock issued 
+— 
+1,198 
+1,465,952 
+— 
+1,467,150 
+Preferred stock conversion 
+(1 
+) 
+7 
+(6 
+) 
+— 
+— 
+Preferred stock dividend 
+— 
+— 
+— 
+(7,295 
+) 
+(7,295 
+) 
+Balance at 12/31/2016 
+$ 
+15 
+$ 
+2,010 
+$ 
+2,171,514 
+$ 
+(440,137 
+) 
+$ 
+1,733,402 
+Net income 
+— 
+— 
+— 
+120,424 
+120,424 
+Shares issued pursuant to employee benefit plans 
+— 
+— 
+311 
+— 
+311 
+Restricted stock 
+— 
+8 
+9,098 
+— 
+9,106 
+Common stock issued 
+— 
+— 
+18 
+— 
+18 
+Impact of forfeiture estimate (a) 
+— 
+— 
+418 
+(418 
+) 
+— 
+Preferred stock dividend 
+— 
+— 
+— 
+(7,295 
+) 
+(7,295 
+) 
+Balance at 12/31/2017 
+$ 
+15 
+$ 
+2,018 
+$ 
+2,181,359 
+$ 
+(327,426 
+) 
+$ 
+1,855,966 
+Net income 
+— 
+— 
+— 
+300,360 
+300,360 
+Shares issued pursuant to employee benefit plans 
+— 
+— 
+533 
+— 
+533 
+Restricted stock 
+— 
+5 
+7,651 
+— 
+7,656 
+Common stock issued 
+— 
+253 
+287,735 
+— 
+287,988 
+Preferred stock dividend 
+— 
+— 
+— 
+(7,295 
+) 
+(7,295 
+) 
+Balance at 12/31/2018 
+$ 
+15 
+$ 
+2,276 
+$ 
+2,477,278 
+$ 
+(34,361 
+) 
+$ 
+2,445,208 
+(a) 
+As a result of the adoption of ASU No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting the Company elected to no longer estimate forfeitures. See Note 2 in the Footnotes to Financial Statements for additional information about ASU 2016-09. 
+The accompanying notes are an integral part of these consolidated financial statements. 
+62 
+Callon Petroleum Company 
+Consolidated Statements of Cash Flows 
+(in thousands) 
+For the Year Ended December 31, 
+2018 
+2017 
+2016 
+Cash flows from operating activities: 
+Net income (loss) 
+$ 
+300,360 
+$ 
+120,424 
+$ 
+(91,813 
+) 
+Adjustments to reconcile net income to net cash provided by operating activities: 
+Depreciation, depletion and amortization 
+184,731 
+118,051 
+73,072 
+Write-down of oil and natural gas properties 
+— 
+— 
+95,788 
+Accretion expense 
+874 
+677 
+958 
+Amortization of non-cash debt related items 
+2,483 
+2,150 
+3,115 
+Deferred income tax (benefit) expense 
+8,110 
+1,273 
+(14 
+) 
+(Gain) loss on derivatives, net of settlements 
+(75,816 
+) 
+10,429 
+38,135 
+(Gain) loss on sale of other property and equipment 
+(144 
+) 
+62 
+— 
+Non-cash loss on early extinguishment of debt 
+— 
+— 
+9,883 
+Non-cash expense related to equity share-based awards 
+6,289 
+8,254 
+2,765 
+Change in the fair value of liability share-based awards 
+375 
+3,288 
+6,953 
+Payments to settle asset retirement obligations 
+(1,469 
+) 
+(2,047 
+) 
+(1,471 
+) 
+Payments for cash-settled restricted stock unit awards 
+(4,990 
+) 
+(13,173 
+) 
+(10,300 
+) 
+Changes in current assets and liabilities: 
+Accounts receivable 
+(17,351 
+) 
+(44,495 
+) 
+(30,055 
+) 
+Other current assets 
+(7,601 
+) 
+108 
+(786 
+) 
+Current liabilities 
+74,311 
+30,947 
+25,288 
+Other long-term liabilities 
+(278 
+) 
+121 
+96 
+Other assets, net 
+(2,230 
+) 
+(1,528 
+) 
+(840 
+) 
+Other 
+— 
+(4,650 
+) 
+— 
+Net cash provided by operating activities 
+467,654 
+229,891 
+120,774 
+Cash flows from investing activities: 
+Capital expenditures 
+(611,173 
+) 
+(419,839 
+) 
+(190,032 
+) 
+Acquisitions 
+(718,793 
+) 
+(718,456 
+) 
+(654,679 
+) 
+Acquisition deposit 
+— 
+45,238 
+(46,138 
+) 
+Proceeds from sales of assets 
+9,009 
+20,525 
+24,562 
+Additions to other assets 
+(3,100 
+) 
+— 
+— 
+Net cash used in investing activities 
+(1,324,057 
+) 
+(1,072,532 
+) 
+(866,287 
+) 
+Cash flows from financing activities: 
+Borrowings on senior secured revolving credit facility 
+500,000 
+25,000 
+217,000 
+Payments on senior secured revolving credit facility 
+(325,000 
+) 
+— 
+(257,000 
+) 
+Payments on term loans 
+— 
+— 
+(300,000 
+) 
+Issuance of 6.125% senior unsecured notes due 2024 
+— 
+200,000 
+400,000 
+Premium on the issuance of 6.125% senior unsecured notes due 2024 
+— 
+8,250 
+— 
+Issuance of 6.375% senior unsecured notes due 2026 
+400,000 
+— 
+— 
+Payment of deferred financing costs 
+(9,430 
+) 
+(7,194 
+) 
+(10,793 
+) 
+Issuance of common stock 
+287,988 
+— 
+1,357,577 
+Payment of preferred stock dividends 
+(7,295 
+) 
+(7,295 
+) 
+(7,295 
+) 
+Tax withholdings related to restricted stock units 
+(1,804 
+) 
+(1,118 
+) 
+(2,207 
+) 
+Net cash provided by financing activities 
+844,459 
+217,643 
+1,397,282 
+Net change in cash and cash equivalents 
+(11,944 
+) 
+(624,998 
+) 
+651,769 
+Balance, beginning of period 
+27,995 
+652,993 
+1,224 
+Balance, end of period 
+$ 
+16,051 
+$ 
+27,995 
+$ 
+652,993 
+The accompanying notes are an integral part of these consolidated financial statements. 
+63 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+1. 
+Description of Business and Basis of Presentation 
+8. 
+Fair Value Measurements 
+2. 
+Summary of Significant Accounting Policies 
+9. 
+Employee Benefit Plans 
+3. 
+Revenue Recognition 
+10. 
+Share-Based Compensation 
+4. 
+Acquisitions and Dispositions 
+11. 
+Equity Transactions 
+5. 
+Earnings (Loss) Per Share 
+12. 
+Income Taxes 
+6. 
+Borrowings 
+13. 
+Asset Retirement Obligations 
+7. 
+Derivative Instruments and Hedging Activities 
+14. 
+Other 
+Supplemental Information on Oil and Natural Gas Operations (Unaudited) 
+Supplemental Quarterly Financial Information (Unaudited) 
+Note 1 - Description of Business and Basis of Presentation 
+Description of business 
+Callon Petroleum Company is an independent oil and natural gas company established in 1950. The Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. 
+Callon is an independent oil and natural gas company focused on the acquisition and development of unconventional onshore oil and natural gas reserves in the Permian Basin. The Permian Basin is located in West Texas and southeastern New Mexico and is comprised of three primary sub-basins: the Midland Basin, the Delaware Basin, and the Central Basin Platform. The Company has historically been focused on the Midland Basin and entered the Delaware Basin through an acquisition completed in February 2017. The Company further expanded its presence in the Delaware Basin through our acquisitions in 2018. 
+Basis of presentation 
+Unless otherwise indicated, all dollar amounts included within the Footnotes to the Financial Statements are presented in thousands, except for per share and per unit data. 
+The Consolidated Financial Statements include the accounts of the Company, and its subsidiary, Callon Petroleum Operating Company (“CPOC”). CPOC also has subsidiaries, namely Callon Offshore Production, Inc. and Mississippi Marketing, Inc. In the opinion of management, the accompanying audited consolidated financial statements reflect all adjustments, including normal recurring adjustments and all intercompany account balance and transaction eliminations, necessary to present fairly the Company’s financial position, results of its operations and cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation. 
+Note 2 – Summary of Significant Accounting Policies 
+Use of Estimates 
+The preparation of financial statements in conformity with U.S. GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets, liabilities, revenues, and expenses. Management regularly evaluates its estimates and assumptions, including those related to valuation of oil and natural gas properties, future asset retirement obligations, income taxes and valuation of deferred tax assets, fair value measurements as it relates to financial instruments, material transactions, and commodity derivatives, and contingency, litigation, and environmental liabilities. Actual results could differ from those estimates. 
+Cash and Cash Equivalents 
+The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. 
+64 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Accounts Receivable 
+Accounts receivable consists primarily of accrued oil and natural gas production receivables and joint interest receivables from outside working interest owners. 
+Revenue Recognition and Natural Gas Balancing 
+Previously, the Company elected to utilize the entitlements method to account for natural gas production imbalances, which is no longer applicable. In conjunction with the Company’s adoption of the new revenue recognition accounting standards, there was no material impact to the financial statements due to this change in accounting for its production imbalances. Natural gas balancing receivables and payables were immaterial as of December 31, 2018 and 2017 . See Note 3 for additional information on revenue recognition. 
+Oil and Natural Gas Properties 
+The Company uses the full cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as oil and gas properties. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest capitalized on unevaluated leases, other costs related to exploration and development activities, and site restoration, dismantlement and abandonment costs capitalized in accordance with asset retirement obligation accounting guidance. Costs capitalized also include any internal costs that are directly related to exploration and development activities, including salaries and benefits, but do not include any costs related to production, general corporate overhead or similar activities. 
+When applicable, proceeds from the sale or disposition of oil and natural gas properties are accounted for as a reduction to capitalized costs through adjustments to accumulated depreciation, depletion, amortization and impairment unless the sale would significantly alter the relationship between capitalized costs and proved reserves, in which case a gain or loss is recognized. 
+Historical and estimated future development costs of oil and natural gas properties, which have been evaluated and contain proved reserves, as well as the historical cost of properties that have been determined to have no future economic value, are depleted using the unit-of-production method based on proved reserves. Excluded from this amortization are costs associated with unevaluated properties, including capitalized interest on such costs. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties or the Company determines that these costs have been impaired. The Company assesses properties on an individual basis or as a group and considers the following factors, among others, to determine if these costs have been impaired: exploration program and intent to drill, remaining lease term, and the assignment of proved reserves. 
+Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the sum of (a) the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10% , plus (b) the lower of cost or fair value of unevaluated properties, and (c) net of related tax effects (collectively called the full cost ceiling). These rules require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling. At December 31, 2018 and 2017, the 12-month average benchmark pricing used to estimate future net cash flows from proved reserves in accordance with the definitions and regulations of the SEC, including differential adjustments, was $58.40 and $51.34 per barrel of oil, respectively, and $3.64 and $2.98 per Mcf of natural gas, respectively. For the periods ended December 31, 2018 and 2017, the Company did no t recognize a write-down of oil and natural gas properties as a result of the ceiling test limitation. At December 31, 2016, the 12-month average benchmark pricing used, including differential adjustments, was $42.75 per barrel of oil and $2.48 per Mcf of natural gas and the Company recognized a $95,788 write-down of oil and natural gas properties as a result of the ceiling test limitation. 
+Upon the acquisition or discovery of oil and natural gas properties, the Company estimates the future net costs to dismantle, abandon and restore the property by using available geological, engineering and regulatory data. Such cost estimates are periodically updated for changes in conditions and requirements. In accordance with asset retirement obligation guidance, such costs are capitalized to the full cost pool when the related liabilities are incurred. In accordance with full cost accounting rules, assets recorded in connection with the recognition of an asset retirement obligation are included as part of the costs subject to the full cost ceiling limitation. The future cash outflows associated with settling the recorded asset retirement obligations are excluded from the computation of the present value of estimated future net revenues used in determining the full cost ceiling amount. 
+65 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Other Property and Equipment 
+The Company depreciates its other property and equipment using the straight-line method over estimated useful lives of three to 20 years . Depreciation expense of $1,078 , $900 and $793 relating to other property and equipment was included in general and administrative expenses in the Company’s consolidated statements of operations for the years ended December 31, 2018 , 2017 and 2016 , respectively. The accumulated depreciation on other property and equipment was $16,562 and $16,259 as of December 31, 2018 and 2017 , respectively. The Company reviews its other property and equipment for impairment when indicators of impairment exist. 
+Capitalized Interest 
+The Company capitalizes interest on unevaluated oil and gas properties. Capitalized interest cannot exceed gross interest expense. During the years ended December 31, 2018 , 2017 and 2016 , the Company capitalized $56,151 , $33,783 and $19,857 of interest expense. 
+Deferred Financing Costs 
+Deferred financing costs are stated at cost, net of amortization, and as a direct reduction from the debt’s carrying value on the balance sheet. For revolving debt arrangements, deferred financing costs are stated at cost, net of amortization, as an asset on the balance sheet. Amortization of deferred financing costs is computed using the straight-line method over the life of the loan. Amortization of deferred financing costs of $2,483 , $2,150 and $3,115 were recorded for the years ended December 31, 2018 , 2017 and 2016 , respectively. 
+Asset Retirement Obligations 
+The Company records an estimate of the fair value of liabilities for obligations associated with the costs to retire tangible long-life assets. The Company estimates the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of the asset retirement obligation. The present value of the asset retirement obligations is accreted each period and the increase to the obligation is reported as accretion expense within operating expenses in the Consolidated Statements of Operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to evaluated properties in the Consolidated Balance Sheets. See Note 13 for additional information. 
+Derivatives 
+Derivative contracts outstanding as of December 31, 2018 were not designated as accounting hedges, and are carried on the balance sheet at fair value. Changes in the fair value of derivative contracts not designated as accounting hedges are reflected in earnings as a gain or loss on derivative contracts. See Notes 7 and 8 for additional information regarding the Company’s derivative contracts. 
+Income Taxes 
+Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties for financial reporting purposes and income tax purposes. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards, statutory depletion carryforwards and tax credit carryforwards. A valuation allowance is provided for that portion of deferred tax assets, if any, for which it is deemed more likely than not that a future benefit will not be realized. As of December 31, 2018 the valuation allowance was $0 . See Note 12 for additional information. 
+Share-Based Compensation 
+The Company grants to directors and employees stock options and restricted stock unit awards (“RSU awards”) that may be settled in common stock (“RSU equity awards”) or cash (“Cash-settleable RSU awards”), some of which are subject to achievement of certain performance conditions. 
+Stock Options. For historical stock options the Company expected to settle in common stock, share-based compensation expense was based on the grant-date fair value as calculated using the Black-Scholes option pricing model and recognized straight-line over the vesting period (generally three years ). 
+RSU equity awards and Cash-settleable RSU awards. For RSU equity awards that the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value and recognized straight-line over the vesting period (generally three years for employees and one year for directors). Certain of the Company’s RSU awards require cash settlement. Cash-settled RSU awards are accounted for as liabilities as the Company is contractually obligated to settle these awards in cash. Changes in the fair value of cash-settleable awards are recorded as adjustments to compensation expense. 
+66 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+For RSU equity awards with vesting terms subject to a performance condition, share-based compensation expense is based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model with the estimated value recognized over the vesting period (generally three years). For cash-settleable RSU awards subject to a performance condition that the Company expects or is required to settle in cash, share-based compensation expense is based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model, with the estimated fair value recognized over the vesting period (generally three years ). 
+See the Accounting Standards Updates section within this footnote for information about recently adopted ASUs related to Stock Compensation. 
+Non-cash Investing and Supplemental Cash Flow Information 
+The following table sets forth the non-cash investing and supplemental cash flow information for the periods indicated: 
+໿ 
+For the Year Ended December 31, 
+2018 
+2017 
+2016 
+Non-cash investing information 
+Change in accrued capital expenditures 
+$ 
+(52,757 
+) 
+$ 
+(39,532 
+) 
+$ 
+(613 
+) 
+Supplemental cash flow information (a) 
+Cash paid for interest, net of capitalized interest 
+$ 
+— 
+$ 
+— 
+$ 
+8,679 
+(a) 
+During the three year period ended 2018 , the Company paid no federal income taxes. 
+Earnings per Share (“EPS”) 
+The Company’s basic EPS amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS, using the treasury stock method, reflects the potential dilution caused by the exercise of options and vesting of restricted stock and RSUs settleable in shares. 
+Accounting Standards Updates 
+Recently issued ASUs - Leases 
+In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”). In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements (“ASU 2018-11”). Together these related amendments to GAAP represent ASC Topic 842, Leases (“ASC Topic 842”). 
+ASU 2016-02 requires lessees to recognize lease assets and liabilities (with terms in excess of 12 months) on the balance sheet and disclose key quantitative and qualitative information about leasing arrangements. The Company has engaged a third-party consultant to assist with its current process of assessing existing contracts, as well as future potential contracts, and to determine the impact of its application on its consolidated financial statements and related disclosures. The contract evaluation process includes review of drilling rig contracts, office facility leases, compressors, field vehicles and equipment, general corporate leased equipment, and other existing arrangements to support its operations that may contain a lease component. 
+The Company plans to elect the package of practical expedients within ASU 2016-02 that allows an entity to not reassess, prior to the effective date, (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases or (iii) initial direct costs for any existing leases, but does not plan to elect the hindsight practical expedient when determining the lease term of existing contracts at the effective date. The new standard also provides practical expedients for an entity’s ongoing accounting. The Company currently expects to elect the short-term lease recognition exemption for all leases that qualify. The Company also currently expects to elect the practical expedient to not separate lease and non-lease components for the majority of classes of underlying assets. 
+Additionally, the Company also plans to elect the practical expedient under ASU 2018-01 and not evaluate existing or expired land easements not previously accounted for as leases prior to the effective date. The Company is working to complete its evaluation of the impact of ASC Topic 842 on its financial statements, accounting policies and internal controls, including implementation of systems and processes to capture, classify and account for leases within the scope of the new guidance and to provide the related disclosures. 
+The Company will adopt this guidance as of January 1, 2019, the transition date, using the simplified transition method described in ASU 2018-11, in which a cumulative-effect adjustment will be recognized in the opening balance of retained earnings in the period of 
+67 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+adoption. At this time, the impact upon adoption of ASC Topic 842 is expected to result in recognition of additional operating liabilities, with corresponding right-of-use assets, ranging from $45 million to $55 million on the Company’s Consolidated Balance Sheet for leases existing as of January 1, 2019, of the same amount based on the present value of the remaining minimum rental payments under current leasing standards for existing operating leases. The adoption of this standard is not expected to have a material impact on the Company’s Consolidated Statement of Income nor Consolidated Statement of Cash Flows. 
+Recently issued ASUs - Other 
+In June 2018, the FASB issued ASU No. 2018-07, Compensation - Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting (“ASU 2018-07”). The standard is intended to simplify several aspects of the accounting for nonemployee share-based payment transactions for acquiring goods and services from nonemployees, including the timing and measurement of nonemployee awards. The guidance in ASU 2018-06 is effective for public entities for annual reporting periods beginning after December 15, 2018, including interim periods therein. The Company does not expect a material impact on its consolidated financial statements upon adoption of this guidance. 
+Recently Adopted ASUs - Revenue Recognition 
+In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 replaced most of the existing revenue recognition requirements in GAAP. See Note 3 for additional information on revenue recognition. 
+The Company adopted the new standard on January 1, 2018 using the modified retrospective method at the date of adoption. Prior to the adoption of ASC 606, gathering and treating fees associated with the Company’s gas processing agreements have historically been presented within lease operating expenses in the statement of operations. The current period presentation reports these fees as a reduction to natural gas revenues. The impact of adoption on the current period statement of operations is as follows: 
+As reported 
+Adjustments 
+Presentation without adoption of ASC Topic 606 
+Operating revenues 
+Natural gas sales 
+$ 
+56,726 
+$ 
+7,646 
+$ 
+64,372 
+Total operating revenues 
+587,624 
+7,646 
+595,270 
+Operating expenses 
+Lease operating expenses 
+$ 
+69,180 
+$ 
+7,646 
+$ 
+76,826 
+Total operating expenses 
+328,094 
+7,646 
+335,740 
+Recently Adopted ASUs - Other 
+In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”). The objective of the standard is to reduce the existing diversity in practice of several cash flow issues, including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payment made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows and application of the predominance principle. The Company adopted this update on January 1, 2018 and it did not have a material impact on its consolidated financial statements. 
+In January 2017, the FASB issued ASU No. 2017-01, Business Combinations-Clarifying the Definition of a Business (“ASU 2017-01”). The guidance in ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. The guidance provides a screen to determine when a set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired or disposed of is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. The Company adopted this update effective January 1, 2018. The adoption of this update did not have a material impact on its consolidated financial statements. 
+68 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). The standard is intended to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows, and will allow companies to estimate the number of stock awards expected to vest. The guidance in ASU 2016-09 is effective for public entities for annual reporting periods beginning after December 15, 2016, including interim periods therein. The Company adopted this ASU on January 1, 2017 and it did not have a material impact on its financial statements. The Company has elected to no longer estimate forfeitures. 
+In December 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topics 230): Restricted Cash (“ASU 2016-18”). The objective of the standard is to require the change during the period in total restricted cash and cash equivalents to be included with cash and cash equivalents when reconciling the beginning-of-period and the end-of-period total amounts shown on the statement of cash flows. The Company adopted this ASU on January 1, 2017 and it did not have a material impact on its financial statements. 
+Note 3 - Revenue Recognition 
+Revenue from contracts with customers 
+Oil sales 
+Under the Company’s oil sales contracts it sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the point of delivery at the net price received. 
+Natural gas sales 
+Under the Company’s natural gas sales processing contracts, it delivers natural gas to a midstream processing entity. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sale of natural gas. The revenue received from the sale of NGLs is included in the natural gas sales. Under these processing agreements, when control of the natural gas changes at the point of delivery, the treatment of gathering and treating fees are recorded net of revenues. Gathering and treating fees have historically been recorded as an expense in lease operating expense in the statement of operations. The Company has modified the presentation of revenues and expenses to include these fees net of revenues. For the twelve months ended December 31, 2018 , $7,646 of gathering and treating fees were recognized and recorded as a reduction to natural gas revenues in the consolidated statement of operations. For the twelve months ended December 31, 2017 and 2016 , $3,433 and $1,727 of gathering and treating fees were recognized and recorded as part of lease operating expense in the consolidated statement of operations, respectively. 
+Accounts receivable from revenues from contracts with customers 
+Net accounts receivable include amounts billed and currently due from revenues from contracts with customers of our oil and natural gas production, which had a balance at December 31, 2018 and 2017 of $87,061 and $70,138 , respectively, and does not currently include an allowance for doubtful accounts. Accounts receivable, net, from oil and natural gas are included in accounts receivable on the consolidated balance sheets. 
+Transaction price allocated to remaining performance obligations 
+For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. 
+Prior period performance obligations 
+The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. 
+69 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Note 4 – Acquisitions and Dispositions 
+2018 Acquisitions 
+On August 31, 2018, the Company completed the acquisition of approximately 28,000 net surface acres in the Spur operating area, located in the Delaware Basin, from Cimarex Energy Company, for $539,519 , including customary purchase price adjustments (the “Delaware Asset Acquisition”). The Company issued debt and equity to fund, in part, the Delaware Asset Acquisition. See Notes 6 and 11 for additional information regarding the Company’s debt obligations and equity offerings. The following table summarizes the estimated acquisition date fair values of the acquisition: 
+Evaluated oil and natural gas properties 
+$ 
+253,089 
+Unevaluated oil and natural gas properties 
+287,000 
+Asset retirement obligations 
+(570 
+) 
+Net assets acquired 
+$ 
+539,519 
+The preliminary purchase price allocations are subject to change based on numerous factors, including the final adjusted purchase price and the final estimated fair value of the assets acquired and liabilities assumed. Any such adjustments to the preliminary estimates of fair value could be material. 
+In addition, the Company completed various acquisitions of additional working interests and mineral rights, and associated production volumes, in the Company’s existing core operating areas within the Permian Basin. In the first quarter of 2018, the Company completed acquisitions within Monarch and WildHorse operating areas for $37,770 , including customary purchase price adjustments. In the fourth quarter of 2018, the Company completed acquisitions of leasehold interests and mineral rights within its WildHorse and Spur operating areas for $87,865 , including customary purchase price adjustments. 
+2017 Acquisitions 
+On February 13, 2017, the Company completed the acquisition of 29,175 gross ( 16,688 net) acres in the Delaware Basin, primarily located in Ward and Pecos Counties, Texas from American Resource Development, LLC, for total cash consideration of $646,559 , excluding customary purchase price adjustments (the “Ameredev Transaction”). The Company funded the cash purchase price with the net proceeds of an equity offering (see Note 11 for additional information regarding the equity offering). The Company obtained an 82% average working interest ( 75% average net revenue interest) in the properties acquired in the Ameredev Transaction. In December 2016, in connection with the execution of the purchase and sale agreement for the Ameredev Transaction, the Company paid a deposit in the amount of $46,138 to a third party escrow agent, which was recorded as Acquisition deposit on the balance sheet as of December 31, 2016. The following table summarizes the estimated acquisition date fair values of the acquisition: 
+Evaluated oil and natural gas properties 
+$ 
+137,368 
+Unevaluated oil and natural gas properties 
+509,359 
+Asset retirement obligations 
+(168 
+) 
+Net assets acquired 
+$ 
+646,559 
+On June 5, 2017, the Company completed the acquisition of 7,031 gross ( 2,488 net) acres in the Delaware Basin, located near the acreage acquired in the Ameredev Transaction discussed above, for $52,014 , including customary purchase price adjustments. The Company funded the cash purchase price with its available cash and proceeds from the issuance of an additional $200,000 of its 6.125% senior notes due 2024 (“6.125% Senior Notes”) (see Note 6 for additional information regarding the Company’s debt obligations). 
+70 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+2016 Acquisitions 
+On October 20, 2016, the Company completed the acquisition of 6,904 gross ( 5,952 net) acres primarily located in Howard County, Texas from Plymouth Petroleum, LLC and additional sellers that exercised their “tag-along” sales rights, for total cash consideration of $339,687 , excluding customary purchase price adjustments (the “Plymouth Transaction”). The Company funded the cash purchase price with the net proceeds of an equity offering (see Note 11 for additional information regarding the equity offering). The Company acquired an 82% average working interest ( 62% average net revenue interest) in the properties acquired in the Plymouth Transaction. The following table summarizes the estimated acquisition date fair values of the net assets acquired in the acquisition: 
+໿ 
+Evaluated oil and natural gas properties 
+$ 
+65,043 
+Unevaluated oil and natural gas properties 
+274,664 
+Asset retirement obligations 
+(20 
+) 
+Net assets acquired 
+$ 
+339,687 
+On May 26, 2016, the Company completed the acquisition of 17,298 gross ( 14,089 net) acres primarily located in Howard County, Texas from BSM Energy LP, Crux Energy LP and Zaniah Energy LP, for total cash consideration of $220,000 and 9.3 million shares of common stock (at an assumed offering price of $11.74 per share, which is the last reported sale price of our common stock on the New York Stock Exchange on that date) for a total purchase price of $329,573 , excluding customary purchase price adjustments (the “Big Star Transaction”). The Company acquired an 81% average working interest ( 61% average net revenue interest) in the properties acquired in the Big Star Transaction. The following table summarizes the estimated acquisition date fair values of the net assets acquired in the acquisition: 
+໿ 
+໿ 
+Evaluated oil and natural gas properties 
+$ 
+96,194 
+Unevaluated oil and natural gas properties 
+233,387 
+Asset retirement obligations 
+(8 
+) 
+Net assets acquired 
+$ 
+329,573 
+During 2016, the Company also closed on various acquisitions in the Midland Basin for an aggregate total purchase price of approximately $73,240 , net of $23,045 in sales of working interest. The acquisitions included the purchase of additional working interest and acreage in the Company’s existing core operating area. 
+Unaudited pro forma financial statements 
+The following unaudited summary pro forma financial information for the periods presented is for illustrative purposes only and does not purport to represent what the Company’s results of operations would have been if the Delaware Asset Acquisition, Ameredev Transaction, Plymouth Transaction, and Big Star Transaction had occurred as presented, or to project the Company’s results of operations for any future periods: 
+Twelve Months Ended December 31, 
+2018 
+(a) 
+2017 
+(a) 
+2016 
+(a) 
+Revenues 
+$ 
+668,759 
+$ 
+472,949 
+$ 
+243,273 
+Income (loss) from operations 
+295,738 
+212,381 
+(39,730 
+) 
+Income (loss) available to common stockholders 
+336,730 
+184,064 
+(82,612 
+) 
+ 
+Net income (loss) per common share: 
+Basic 
+$ 
+1.55 
+$ 
+0.91 
+$ 
+(0.50 
+) 
+Diluted 
+$ 
+1.55 
+$ 
+0.91 
+$ 
+(0.50 
+) 
+(a) 
+The pro forma financial information was prepared assuming the Delaware Asset Acquisition occurred as of January 1, 2017, and the Ameredev Transaction, Plymouth Transaction, and Big Star Transaction occurred as of January 1, 2016. 
+The pro forma adjustments are based on available information and certain assumptions that management believes are reasonable, including revenue, lease operating expenses, production taxes, depreciation, depletion and amortization expense, accretion expense, interest expense and capitalized interest. 
+The properties associated with the Delaware Asset Acquisition, Ameredev Transaction, Big Star Transaction, and the Plymouth Transaction have been commingled with our existing properties and it is impractical to provide the stand-alone operational results related to these properties. 
+71 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Note 5 - Earnings Per Share 
+Basic earnings (loss) per share is computed by dividing income (loss) available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings (loss) per share includes the potential dilutive impact of non-vested restricted shares and unexercised options outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. The following table sets forth the computation of basic and diluted earnings per share: 
+(share amounts in thousands) 
+For the Year Ended December 31, 
+2018 
+2017 
+2016 
+Net income (loss) 
+$ 
+300,360 
+$ 
+120,424 
+$ 
+(91,813 
+) 
+Preferred stock dividends 
+(7,295 
+) 
+(7,295 
+) 
+(7,295 
+) 
+Income (loss) available to common stockholders 
+$ 
+293,065 
+$ 
+113,129 
+$ 
+(99,108 
+) 
+ 
+Weighted average shares outstanding 
+216,941 
+201,526 
+126,258 
+Dilutive impact of restricted stock 
+655 
+576 
+— 
+Weighted average shares outstanding for diluted income (loss) per share (a) 
+217,596 
+202,102 
+126,258 
+ 
+Basic income (loss) per share 
+$ 
+1.35 
+$ 
+0.56 
+$ 
+(0.78 
+) 
+Diluted income (loss) per share 
+$ 
+1.35 
+$ 
+0.56 
+$ 
+(0.78 
+) 
+ 
+Stock options (b) 
+— 
+— 
+15 
+Restricted stock (b) 
+89 
+16 
+— 
+(a) 
+Because the Company reported a net loss available to common stockholders for the year ended December 31, 2016 , no unvested stock awards were included in computing net loss per share because the effect was anti-dilutive. 
+(b) 
+Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive. 
+Note 6 – Borrowings 
+The Company’s borrowings consisted of the following: 
+໿ 
+As of December 31, 
+2018 
+2017 
+Principal components: 
+Senior secured revolving credit facility 
+$ 
+200,000 
+$ 
+25,000 
+6.125% senior unsecured notes due 2024 
+600,000 
+600,000 
+6.375% senior unsecured notes due 2026 
+400,000 
+— 
+Total principal outstanding 
+1,200,000 
+625,000 
+Premium on 6.125% Senior Notes, net of accumulated amortization 
+6,469 
+7,594 
+Unamortized deferred financing costs 
+(16,996 
+) 
+(12,398 
+) 
+Total carrying value of borrowings (a) 
+$ 
+1,189,473 
+$ 
+620,196 
+(a) 
+Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $6,087 and $4,863 as of December 31, 2018 and 2017, respectively. 
+Senior secured revolving credit facility (“Credit Facility”) 
+On May 25, 2017 , the Company entered into the Sixth Amended and Restated Credit Agreement to the Credit Facility with a maturity date of May 25, 2022 . JPMorgan Chase Bank, N.A. is Administrative Agent, and participants include 17 institutional lenders. The total notional amount available under the Credit Facility is $2,000,000 . Amounts borrowed under the Credit Facility may not exceed the borrowing base, which is generally reviewed on a semi-annual basis. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. Concurrent with the execution of the Sixth Amended and Restated Credit Agreement, the Credit Facility’s borrowing base increased to $650,000 , but the Company elected an aggregate commitment amount of $500,000 . On November 7, 2017 , the Credit Facility’s borrowing base increased to $700,000 with a reaffirmed commitment of $500,000 , following the semi-annual review. 
+Effective April 5, 2018 , the Company entered into the first amendment to the Sixth Amended and Restated Credit Agreement to the Credit Facility, which (1) increased the borrowing base to $825,000 , (2) increased the elected commitment amount to $650,000 , (3) amended various covenants and terms to reflect current market trends, and (4) extended the maturity date to May 25, 2023 . 
+72 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Effective September 27, 2018 , the Company entered into the second amendment to the Sixth Amended and Restated Credit Agreement to the Credit Facility, which (1) increased the borrowing base to $1,100,000 , (2) increase the elected commitment amount to $850,000 , and (3) amended various covenants and terms to reflect current market trends. As of December 31, 2018 , the Credit Facility’s borrowing base remained at $1,100,000 with an elected commitment amount of $850,000 . 
+As of December 31, 2018 , there was $200,000 of principal and $17,675 in letters of credit outstanding on the Credit Facility. For the year ended December 31, 2018 , the Credit Facility had a weighted-average interest rate of 3.62% , calculated as the LIBOR plus a tiered rate ranging from 1.25% to 2.25% , which is determined based on utilization of the facility. In addition, the Credit Facility carries a current commitment fee of 0.375% per annum, payable quarterly, on the unused portion of the borrowing base. 
+6.375% Senior Notes 
+On June 7, 2018 , the Company issued $400,000 aggregate principal amount of 6.375% Senior Notes with a maturity date of July 1, 2026 and interest payable semi-annually beginning on January 1, 2019. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $394,000 . The 6.375% Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The subsidiary guarantor is 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor. 
+The Company may redeem the 6.375% Senior Notes in accordance with the following terms: (1) prior to July 1, 2021 , a redemption of up to 35% of the principal in an amount not greater than the net proceeds from certain equity offerings, and within 180 days of the closing date of such equity offerings, at a redemption price of 106.375% of principal, plus accrued and unpaid interest, if any, to the date of the redemption, if at least 65% of the principal will remain outstanding after such redemption; (2) prior to July 1, 2021 , a redemption of all or part of the principal at a price of 100% of principal of the amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of the redemption; and (3) a redemption, in whole or in part, at a redemption price, plus accrued and unpaid interest, if any, to the date of the redemption, (i) of 103.188% of principal if the redemption occurs on or after July 1, 2021, but before July 1, 2022 , and (ii) of 102.125% of principal if the redemption occurs on or after July 1, 2022 , but before July 1, 2023 , and (iii) of 101.063% of principal if the redemption occurs on or after July 1, 2023 , but before July 1, 2024 , and (iv) of 100% of principal if the redemption occurs on or after July 1, 2024 . 
+Following a change of control, each holder of the 6.375% Senior Notes may require the Company to repurchase all or a portion of the 6.375% Senior Notes at a price of 101% of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase. 
+6.125% Senior Notes 
+On October 3, 2016, the Company issued $400,000 aggregate principal amount of 6.125% Senior Notes with a maturity date of October 1, 2024 and interest payable semi-annually beginning on April 1, 2017. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $391,270 . The 6.125% Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The subsidiary guarantor is 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor. 
+On May 19, 2017, the Company issued an additional $200,000 aggregate principal amount of its 6.125% Senior Notes which with the existing $400,000 aggregate principal amount of 6.125% Senior Notes are treated as a single class of notes under the indenture. The net proceeds of the offering, including a premium issue price of 104.125% and after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $206,139 . The Company used the proceeds, in part, to fund an acquisition completed on June 5, 2017 (discussed further in Note 4 ) and for general corporate purposes. 
+The Company may redeem the 6.125% Senior Notes in accordance with the following terms; (1) prior to October 1, 2019 , a redemption of up to 35% of the principal in an amount not greater than the net proceeds from certain equity offerings, and within 180 days of the closing date of such equity offerings, at a redemption price of 106.125% of principal, plus accrued and unpaid interest, if any, to the date of the redemption, if at least 65% of the principal will remain outstanding after such redemption; (2) prior to October 1, 2019 , a redemption of all or part of the principal at a price of 100% of principal of the amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of the redemption; (3) a redemption, in whole or in part, at a redemption price, plus accrued and 
+73 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+unpaid interest, if any, to the date of the redemption, (i) of 104.594% of principal if the redemption occurs on or after October 1, 2019 , but before October 1, 2020 , and (ii) of 103.063% of principal if the redemption occurs on or after October 1, 2020 , but before October 1, 2021 , and (iii) of 101.531% of principal if the redemption occurs on or after October 1, 2021, but before October 1, 2022 , and (iv) of 100% of principal if the redemption occurs on or after October 1, 2022 . 
+Following a change of control, each holder of the 6.125% Senior Notes may require the Company to repurchase all or a portion of the 6.125% Senior Notes at a price of 101% of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase. 
+Term loans 
+The Company historically held a term loan agreement since March 11, 2014. On October 8, 2014, the original term loan was repaid in full using proceeds from a new secured second lien term loan (the “Second Lien Loan”) with a maturity date of October 8, 2021 . On October 11, 2016, the Second Lien Loan was repaid in full at the prepayment rate of 101% using proceeds from the sale of the 6.125% Senior Notes, which resulted in a loss on early extinguishment of debt of $12,883 (inclusive of $3,000 in prepayment fees and $9,883 of unamortized debt issuance costs). 
+Restrictive covenants 
+The Company’s Credit Facility and the indentures governing its 6.125% and 6.375% Senior Notes contain various covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. The Company was in compliance with these covenants at December 31, 2018. 
+Note 7 - Derivative Instruments and Hedging Activities 
+Objectives and strategies for using derivative instruments 
+The Company is exposed to fluctuations in oil and natural gas prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil and natural gas production. The Company utilizes a mix of collars, swaps, put and call options and similar derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes. 
+Counterparty risk and offsetting 
+The use of derivative instruments exposes the Company to the risk that a counterparty will be unable to meet its commitments. While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument; see Note 8 for additional information regarding fair value. 
+The Company executes commodity derivative contracts under master agreements with netting provisions that provide for offsetting assets against liabilities. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement. 
+Financial statement presentation and settlements 
+Settlements of the Company’s derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets. See Note 8 for additional information regarding fair value. 
+Derivatives not designated as hedging instruments 
+The Company records its derivative contracts at fair value in the consolidated balance sheets and records changes in fair value as a gain or loss on derivative contracts in the consolidated statements of operations. Settlements are also recorded as a gain or loss on derivative contracts in the consolidated statements of operations. 
+74 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+The following table reflects the fair value of the Company’s derivative instruments for the periods presented: 
+໿ 
+Balance Sheet Presentation 
+Asset Fair Value 
+Liability Fair Value 
+Net Derivative Fair Value 
+Commodity 
+Classification 
+Line Description 
+12/31/2018 
+12/31/2017 
+12/31/2018 
+12/31/2017 
+12/31/2018 
+12/31/2017 
+Oil 
+Current 
+Fair value of derivatives 
+$ 
+60,097 
+$ 
+— 
+$ 
+(10,480 
+) 
+$ 
+(27,744 
+) 
+$ 
+49,617 
+$ 
+(27,744 
+) 
+Oil 
+Non-current 
+Fair value of derivatives 
+— 
+— 
+(5,672 
+) 
+(1,284 
+) 
+(5,672 
+) 
+(1,284 
+) 
+Natural gas 
+Current 
+Fair value of derivatives 
+5,017 
+406 
+— 
+— 
+5,017 
+406 
+Natural gas 
+Non-current 
+Fair value of derivatives 
+— 
+— 
+(1,768 
+) 
+— 
+(1,768 
+) 
+— 
+Totals 
+$ 
+65,114 
+$ 
+406 
+$ 
+(17,920 
+) 
+$ 
+(29,028 
+) 
+$ 
+47,194 
+$ 
+(28,622 
+) 
+As previously discussed, the Company’s derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated: 
+໿ 
+ 
+For the Year Ended December 31, 2018 
+ 
+Presented without 
+As Presented with 
+ 
+Effects of Netting 
+Effects of Netting 
+Effects of Netting 
+Current assets: Fair value of derivatives 
+78,091 
+(12,977 
+) 
+65,114 
+ 
+Current liabilities: Fair value of derivatives 
+(23,457 
+) 
+12,977 
+(10,480 
+) 
+Long-term liabilities: Fair value of derivatives 
+(7,440 
+) 
+— 
+(7,440 
+) 
+໿ 
+ 
+For the Year Ended December 31, 2017 
+ 
+Presented without 
+As Presented with 
+ 
+Effects of Netting 
+Effects of Netting 
+Effects of Netting 
+Current assets: Fair value of derivatives 
+406 
+— 
+406 
+Current liabilities: Fair value of derivatives 
+(27,744 
+) 
+— 
+(27,744 
+) 
+Long-term liabilities: Fair value of derivatives 
+(1,284 
+) 
+— 
+(1,284 
+) 
+For the periods indicated, the Company recorded the following related to its derivatives in the consolidated statement of operations as gain or loss on derivative contracts: 
+໿ 
+ 
+For the Year Ended December 31, 
+ 
+2018 
+2017 
+2016 
+Oil derivatives 
+Net gain (loss) on settlements 
+$ 
+(27,510 
+) 
+$ 
+(9,067 
+) 
+$ 
+17,801 
+Net gain (loss) on fair value adjustments 
+72,973 
+(11,426 
+) 
+(37,543 
+) 
+Total gain (loss) on oil derivatives 
+$ 
+45,463 
+$ 
+(20,493 
+) 
+$ 
+(19,742 
+) 
+Natural gas derivatives 
+Net gain on settlements 
+$ 
+238 
+$ 
+594 
+$ 
+102 
+Net gain (loss) on fair value adjustments 
+2,843 
+998 
+(593 
+) 
+Total gain (loss) on natural gas derivatives 
+$ 
+3,081 
+$ 
+1,592 
+$ 
+(491 
+) 
+ 
+Total gain (loss) on oil & natural gas derivatives 
+$ 
+48,544 
+$ 
+(18,901 
+) 
+$ 
+(20,233 
+) 
+75 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Derivative positions 
+Listed in the tables below are the outstanding oil and natural gas derivative contracts as of December 31, 2018 : 
+໿ 
+For the Full Year of 
+For the Full Year of 
+Oil contracts (WTI) 
+2019 
+2020 
+Puts 
+Total volume (Bbls) 
+912,500 
+— 
+Weighted average price per Bbl 
+$ 
+65.00 
+$ 
+— 
+Put spreads 
+Total volume (Bbls) 
+912,500 
+— 
+Weighted average price per Bbl 
+Floor (long put) 
+$ 
+65.00 
+$ 
+— 
+Floor (short put) 
+$ 
+42.50 
+$ 
+— 
+Collar contracts combined with short puts (three-way collars) 
+Total volume (Bbls) 
+4,564,000 
+— 
+Weighted average price per Bbl 
+Ceiling (short call) 
+$ 
+67.62 
+$ 
+— 
+Floor (long put) 
+$ 
+56.60 
+$ 
+— 
+Floor (short put) 
+$ 
+43.60 
+$ 
+— 
+Oil contracts (Midland basis differential) 
+Swap contracts 
+Total volume (Bbls) 
+4,746,500 
+4,024,000 
+Weighted average price per Bbl 
+$ 
+(4.72 
+) 
+$ 
+(1.51 
+) 
+Natural gas contracts (Henry Hub) 
+Collar contracts (two-way collars) 
+Total volume (MMBtu) 
+8,282,500 
+— 
+Weighted average price per MMBtu 
+Ceiling (short call) 
+$ 
+3.46 
+$ 
+— 
+Floor (long put) 
+$ 
+2.91 
+$ 
+— 
+Natural gas contracts (Waha basis differential) 
+Swap contracts 
+Total volume (MMBtu) 
+11,321,000 
+4,758,000 
+Weighted average price per MMBtu 
+$ 
+(1.23 
+) 
+$ 
+(1.12 
+) 
+Note 8 - Fair Value Measurements 
+The fair value hierarchy included in GAAP gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable, and these valuations have the lowest priority. 
+Fair value of financial instruments 
+Cash, cash equivalents, and restricted investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments. 
+Debt. The carrying amount of the Company’s floating-rate debt approximated fair value because the interest rates were variable and reflective of market rates. 
+76 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+2018 
+2017 
+Carrying Value 
+Fair Value 
+Carrying Value 
+Fair Value 
+Credit Facility (a) 
+$ 
+200,000 
+$ 
+200,000 
+$ 
+25,000 
+$ 
+25,000 
+6.125% Senior Notes (b) 
+595,788 
+558,000 
+595,196 
+618,000 
+6.375% Senior Notes (b) 
+393,685 
+372,000 
+— 
+— 
+Total 
+$ 
+1,189,473 
+$ 
+1,130,000 
+$ 
+620,196 
+$ 
+643,000 
+(a) 
+Floating-rate debt. 
+(b) 
+The fair value was based upon Level 2 inputs. See Note 6 for additional information about the Company’s 6.125% and 6.375% Senior Notes. 
+Assets and liabilities measured at fair value on a recurring basis 
+Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheet. The following methods and assumptions were used to estimate fair value: 
+Commodity derivative instruments. The fair value of commodity derivative instruments is derived using an income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. The Company believes that the majority of the inputs used to calculate the commodity derivative instruments fall within Level 2 of the fair value hierarchy based on the wide availability of quoted market prices for similar commodity derivative contracts. See Note 7 for additional information regarding the Company’s derivative instruments. 
+The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis: 
+December 31, 2018 
+Classification 
+Level 1 
+Level 2 
+Level 3 
+Total 
+Assets 
+Derivative financial instruments 
+Fair value of derivatives 
+$ 
+— 
+$ 
+65,114 
+$ 
+— 
+$ 
+65,114 
+Liabilities 
+Derivative financial instruments 
+Fair value of derivatives 
+— 
+(17,920 
+) 
+— 
+(17,920 
+) 
+Total net assets 
+$ 
+— 
+$ 
+47,194 
+$ 
+— 
+$ 
+47,194 
+ 
+December 31, 2017 
+Classification 
+Level 1 
+Level 2 
+Level 3 
+Total 
+Assets 
+Derivative financial instruments 
+Fair value of derivatives 
+$ 
+— 
+$ 
+406 
+$ 
+— 
+$ 
+406 
+Liabilities 
+Derivative financial instruments 
+Fair value of derivatives 
+— 
+(29,028 
+) 
+— 
+(29,028 
+) 
+Total net liabilities 
+$ 
+— 
+$ 
+(28,622 
+) 
+$ 
+— 
+$ 
+(28,622 
+) 
+Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis 
+Acquisitions. The Company determines the fair value of the assets acquired and liabilities assumed using the income approach based on expected discounted future cash flows from estimated reserve quantities, costs to produce and develop reserves, and oil and natural gas forward prices. The future net revenues are discounted using a weighted average cost of capital. The discounted future net revenues of proved undeveloped and probable reserves are reduced by an additional reserve adjustment factor to compensate for the inherent risk of estimating the value of unevaluated properties. The fair value measurements were based on Level 1, Level 2 and Level 3 inputs. 
+Note 9 – Employee Benefit Plans 
+Savings and Protection Plan (“401(k) Plan”) 
+The 401(k) Plan provides employees with the option to defer receipt of a portion of their compensation, and the Company may, at its discretion, match a portion of the employee’s deferral with cash. The Company may also elect, at its discretion, to contribute a non-matching amount in cash and Company common stock to employees. The amounts held under the 401(k) Plan are invested in various funds maintained by a third party in accordance with the directions of each employee. An employee is fully vested, including Company discretionary contributions, immediately upon participation in the 401(k) Plan. The total amounts contributed by the Company were $2,082 , $1,292 and $1,018 in the years 2018 , 2017 and 2016 , respectively. Of those amounts contributed, the value of common stock contributed for each period was $600 , $313 , and $277 , respectively. 
+77 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Note 10 - Share-Based Compensation 
+The Company grants various forms of share-based compensation awards to employees of the Company and its subsidiaries and to non-employee members of the Board of Directors. At December 31, 2018 , shares available for future share-based awards, including stock options or restricted stock grants, under the Company’s only active plan, the 2018 Plan, were 9,806,953 . 
+2011 Omnibus Incentive Plan (the “2011 Plan”) 
+The 2011 Plan, which became effective May 12, 2011 and as amended through May 14, 2015, authorized and reserved for issuance 5,141,000 shares. As of May 10, 2018, no more shares will be issued from the 2011 Plan and the remaining 1,322,742 shares authorized and available for issuance under the 2011 Plan transferred into the 2018 Omnibus Incentive Plan (the “2018 Plan”). Shares, which would otherwise become available for issuance under the 2011 Plan as a result of vesting and/or forfeiture of any equity awards existing prior to the effective date of the 2018 Plan, will increase the authorized shares available to the 2018 Plan. 
+RSU equity awards . RSU equity awards issued under the 2011 Plan may be subject to various vesting, accelerated vesting, and forfeiture provisions upon the occurrence of certain events. RSU equity awards under the 2011 Plan generally vest over time but may also be subject to attaining specified performance metrics and may vest immediately or cliff vest at a specified date. The Company will recognize expense ratably over the requisite service (i.e. vesting) period for both cliff and ratably vesting awards. 
+For performance-based RSU equity awards, the Company recognizes expense based on the fair value of the awards at the grant date. Awards with a performance-based provision do not allow for the reversal of previously recognized expense, even if the market metric is not achieved and no shares ultimately vest or are awarded. Performance-based RSU equity awards that vest are based on a calculation that compares the Company’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between 0% and 200% of the base units awarded. 
+Cash-settled RSU awards. Certain of the Company’s RSU awards require cash settlement. Cash-settled RSU awards under the 2011 Plan are accounted for as liabilities as the Company is contractually obligated to settle these awards in cash. Changes in the fair value of cash-settleable awards are recorded as adjustments to compensation expense. 
+A significant portion of the Company’s cash-settled RSU awards include a performance-based vesting condition that determines the actual number of units that will ultimately vest. The number of RSUs that vest is based on a calculation that compares the Company’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between 0% and 200% of the base units awarded. The fair value of the Company’s performance-based RSU awards is calculated using a Monte Carlo valuation model, which considers such inputs as the Company’s and its peer group’s stock prices, a risk-free interest rate, and an estimated volatility for the Company and its peer group. 
+2018 Omnibus Incentive Plan (the “2018 Plan”) 
+The 2018 Plan, which became effective May 10, 2018 following shareholder approval, authorized and reserved for issuance 9.4 million shares of common stock, which may be issued upon exercise of vested stock options and/or the vesting of any other share-based equity award that is granted under this plan. The 2018 Plan is the Company’s only active plan, and included a provision at inception whereby all remaining, un-issued and authorized shares from the 2011 Plan became issuable under the 2018 Plan. This transfer provision resulted in the transfer of an additional 1,322,742 shares into the 2018 Plan, increasing the quantity authorized and reserved for issuance under the 2018 Plan to 10,722,742 at the inception of the 2018 Plan. Another provision provided that shares, which would otherwise become available for issuance under the 2011 Plan as a result of vesting and/or forfeiture of any equity awards existing as of the effective date of the 2018 Plan, would also increase the authorized shares available to the 2018 Plan. 
+RSU equity awards . RSU equity awards issued under the 2018 Plan may be subject to various vesting, accelerated vesting, and forfeiture provisions upon the occurrence of certain events. RSU equity awards under the 2018 Plan generally vest over time but may also be subject to attaining specified performance metrics and may vest immediately or cliff vest at a specified date. The Company will recognize expense on the grant date for any immediately vesting awards, while it will recognize expense ratably over the requisite service (i.e. vesting) period for both cliff and ratably vesting awards. 
+For performance-based RSU equity awards, the Company recognizes expense based on the fair value of the awards at the grant date. Awards with a performance-based provision do not allow for the reversal of previously recognized expense, even if the market metric is not achieved and no shares ultimately vest or are awarded. Performance-based RSU equity awards that vest are based on a calculation that compares the Company’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between 0% and 200% of the base units awarded. 
+78 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Cash-settled RSU awards. Certain of the Company’s RSU awards require cash settlement. Cash-settled RSU awards under the 2011 Plan are accounted for as liabilities as the Company is contractually obligated to settle these awards in cash. Changes in the fair value of cash-settleable awards are recorded as adjustments to compensation expense. 
+A significant portion of the Company’s cash-settled RSU awards include a performance-based vesting condition that determines the actual number of units that will ultimately vest. The number of RSUs that vest is based on a calculation that compares the Company’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between 0% and 200% of the base units awarded. The fair value of the Company’s performance-based RSU awards is calculated using a Monte Carlo valuation model, which considers such inputs as the Company’s and its peer group’s stock prices, a risk-free interest rate, and an estimated volatility for the Company and its peer group. 
+The following table presents share-based compensation expense for each respective period: 
+໿ 
+ 
+For the Year Ended December 31, 
+ 
+2018 
+2017 
+2016 
+Share-based compensation cost for: 
+Equity-based 
+Liability-based 
+Equity-based 
+Liability-based 
+Equity-based 
+Liability-based 
+RSU equity awards (a) 
+$ 
+9,460 
+$ 
+— 
+$ 
+10,225 
+$ 
+— 
+$ 
+4,536 
+$ 
+— 
+Cash-settleable RSU awards (a) 
+— 
+336 
+— 
+4,294 
+— 
+12,285 
+Total share-based compensation cost (b) 
+$ 
+9,460 
+$ 
+336 
+$ 
+10,225 
+$ 
+4,294 
+$ 
+4,536 
+$ 
+12,285 
+(a) 
+Includes the settlement of the outstanding share-based award agreements of the Company’s former Chief Executive Officer, resulting in $6,351 recorded on the Consolidated Statements of Operations as settled share-based awards for the year ended December 31, 2017. 
+(b) 
+The portion of this share-based compensation cost that was included in general and administrative expense totaled $6,362 , $4,966 and $9,547 for the years ended December 31, 2018 , 2017 and 2016 , respectively, and the portion capitalized to oil and gas properties was $3,434 , $3,202 and $7,274 , for the years ended December 31, 2018 , 2017 , and 2016 , respectively. 
+The following table presents the unrecognized compensation cost for the indicated periods: 
+ 
+December 31, 
+Unrecognized compensation cost related to: 
+2018 
+2017 
+2016 
+Unvested RSU equity awards 
+$ 
+15,720 
+$ 
+13,158 
+$ 
+7,276 
+Unvested cash-settleable RSU awards 
+1,822 
+3,776 
+8,948 
+The Company’s unrecognized compensation cost related to unvested RSU equity awards and cash-settleable RSU awards is expected to be recognized over a weighted-average period of two years. 
+The following table summarizes the Company’s liability for cash-settled RSU awards for the periods indicated: 
+ 
+December 31, 
+Consolidated Balance Sheets Classification 
+2018 
+2017 
+Cash-settleable RSU awards (current) 
+$ 
+1,390 
+$ 
+4,621 
+Cash-settleable RSU awards (non-current) 
+2,067 
+3,490 
+Total cash-settleable RSU awards 
+$ 
+3,457 
+$ 
+8,111 
+Stock Options 
+The Company issued no stock options for the past three years and all existing options expired by year end December 31, 2017. As of December 31, 2016 , the Company had 15,000 options outstanding and exercisable at a weighted average exercise price per option of $14.37 , with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 0.3 years . 
+79 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Restricted Stock Units 
+The following table represents unvested stock-settleable restricted stock activity for the year ended December 31, 2018 : 
+ 
+Weighted average 
+(shares in 000s) 
+Number of Shares 
+Grant-Date Fair Value per Share 
+Years Over Which Expense is Expected to be Recognized 
+Outstanding at the beginning of the period 
+1,790 
+$ 
+11.54 
+Granted (a) 
+872 
+13.89 
+Vested (b) 
+(506 
+) 
+9.56 
+Forfeited 
+(53 
+) 
+11.43 
+Outstanding at the end of the period 
+2,103 
+$ 
+13.24 
+1.85 
+(a) 
+Includes 208 performance-based RSUs that will vest at a range of 0% - 200% . 
+(b) 
+The fair value of shares vested was $6,344 . 
+For the year ended December 31, 2017 , the Company granted 1,173,094 RSUs with a weighted average grant-date fair value of $12.25 per share. The fair value of shares vested during 2017 was $9,045 . For the year ended December 31, 2016 , the Company granted 684,090 RSUs with a weighted average grant-date fair value of $12.63 per share. The fair value of shares vested during 2016 was $2,608 . 
+As of December 31, 2018 , the Company had the following cash-settleable RSUs outstanding (including those that are not based on a market condition): 
+(shares in 000s) 
+Base Units Outstanding 
+Potential Minimum Units Vesting 
+Potential Maximum Units Vesting 
+Vesting in 2019 
+190 
+17 
+364 
+Vesting in 2020 
+323 
+— 
+645 
+Vesting in 2021 
+— 
+— 
+— 
+Other 
+146 
+146 
+146 
+Total cash-settleable RSUs 
+659 
+163 
+1,155 
+For the year ended December 31, 2018 , 207,261 performance-based cash-settled RSUs, subject to the peer performance-based vesting described above, vested at between 100% to 163% of their issued units, depending on the date of the vesting, resulting in cash payments of $89 in 2018 and payable amounts of $1,296 in 2019 . Also during 2018 , 129,753 non-performance-based cash settled RSUs vested, resulting in cash payments of $1,834 in 2018 . During 2017 , 335,471 performance-based cash-settled RSUs subject to the peer performance-based vesting described above vested at between 142% to 200% of their underlying issued units, depending on the date of the vesting, resulting in cash payments of $3,986 in 2017 and $3,062 in 2018 . Also during 2017 , 43,031 non-performance-based cash settled RSUs vested, resulting in cash payments of $526 in 2017 . 
+Note 11 – Equity Transactions 
+10% Series A Cumulative Preferred Stock (“Preferred Stock”) 
+Holders of the Company’s Preferred Stock are entitled to receive, when, as and if declared by the Company’s Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10% per annum of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share). Dividends are payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by our Company’s Board of Directors. Preferred Stock dividends were $7,295 for each year in 2018 , 2017 and 2016 . 
+The Preferred Stock has no stated maturity and is not subject to any sinking fund or other mandatory redemption. The Company may, at its option, redeem the Preferred Stock, in whole or in part, at any time on or after May 30, 2018, by paying $50.00 per share, plus any accrued and unpaid dividends to the redemption date. 
+Following a change of control in which the Company or the acquirer no longer have a class of common securities listed on a national exchange, the Company will have the option to redeem the Preferred Stock, in whole but not in part for $50.00 per share in cash plus accrued and unpaid dividends (whether or not declared) to the redemption date. If the Company does not exercise its option to redeem the Preferred Stock upon such change of control, the holders of the Preferred Stock have the option to convert the Preferred Stock into a number of shares of the Company’s common stock based on the value of the common stock on the date of the change of control as 
+80 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+determined under the certificate of designations for the Preferred Stock. If the change of control occurred on December 31, 2018 , and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of $6.49 as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately 7.7 shares of common stock. If the Company exercises its redemption rights relating to shares of Preferred Stock, the holders of Preferred Stock will not have the conversion right described above. 
+On February 4, 2016, the Company exchanged a total of 120 thousand shares of Preferred Stock for 719 thousand shares of common stock. As of December 31, 2018 , the Company had 1,458,948 shares of its Preferred Stock issued and outstanding. 
+Common Stock 
+On May 30, 2018, the Company completed an underwritten public offering of 25.3 million shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and offering costs) of approximately $287,988 . The Company used proceeds from the offering to partially fund the Delaware Asset Acquisition completed in the third quarter, described in Note 4. 
+On December 19, 2016, the Company completed an underwritten public offering of 40 million shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $634,934 . Proceeds from the offering were used to substantially fund the Ameredev Transaction, described in Note 4 . 
+On September 6, 2016, the Company completed an underwritten public offering of 29.9 million shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $421,864 . Proceeds from the offering were used to substantially fund the Plymouth Transaction, described in Note 4 . 
+On May 26, 2016, the Company issued 9.3 million shares of common stock to partially fund the Big Star Transaction, described in Note 4 , at an assumed offering price of $11.74 per share, which is the last reported sale price of our common stock on the New York Stock Exchange on that date. 
+On April 25, 2016, the Company completed an underwritten public offering of 25.3 million shares of its common stock for total net proceeds (after the underwriter’s discounts and commissions and estimated offering expenses) of approximately $205,869 . Proceeds from the offering were used to fund the Big Star Transaction, described in Note 4 , and other working interest acquisitions. 
+On March 9, 2016, the Company completed an underwritten public offering of 15.3 million shares of its common stock for total net proceeds (after the underwriting discounts and estimated offering costs) of approximately $94,948 . Proceeds from the offering were used to pay down the balance on the Company’s Credit Facility and for general corporate purposes. 
+81 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Note 12 - Income Taxes 
+The following table presents Callon’s deferred tax assets and liabilities with respect to its carryforwards and other temporary differences: 
+ 
+As of December 31, 
+2018 
+2017 
+Deferred tax asset (a) 
+Federal net operating loss carryforward 
+$ 
+151,497 
+$ 
+97,437 
+Interest expense carryforward (b) 
+7,335 
+— 
+Statutory depletion carryforward 
+5,381 
+5,381 
+Alternative minimum tax credit carryforward (b) 
+— 
+52 
+Asset retirement obligations 
+2,347 
+572 
+Derivatives asset 
+— 
+6,186 
+Unvested RSU equity awards 
+2,751 
+1,749 
+Other 
+991 
+2,401 
+Deferred tax asset before valuation allowance 
+170,302 
+113,778 
+Deferred tax liability (a) 
+Oil and natural gas properties 
+169,682 
+54,264 
+Derivatives liability 
+10,184 
+— 
+Total deferred tax liability 
+179,866 
+54,264 
+Net deferred tax asset (liability) before valuation allowance 
+(9,564 
+) 
+59,514 
+Less: Valuation allowance 
+— 
+(60,919 
+) 
+Net deferred tax liability 
+$ 
+(9,564 
+) 
+$ 
+(1,405 
+) 
+(a) 
+Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The 2017 Tax Act lowered the U.S. federal corporate tax rate from 35% to 21%, which caused the Company to remeasure its deferred income tax assets and liabilities at the new rate. As of December 31, 2018 and 2017 , the Company’s tax rate applied was 21%. As a result of the change in the applied tax rate on our deferred tax assets and liabilities, in 2017 the Company recorded a $40,611 reduction in our net deferred tax assets with a corresponding reduction in our valuation allowance. 
+(b) 
+The 2017 Tax Act revised the rules regarding the deductibility of net interest expense incurred in tax years beginning after 2017, with non-deductible amounts being carried forward to future taxable years. 
+(c) 
+The 2017 Tax Act repealed the Alternative Minimum Tax (“AMT”) effective for years beginning after December 31, 2017. The result had an immaterial impact in income. 
+U.S. federal net operating loss (“NOL”) utilization was changed by the 2017 Tax Act for losses incurred in tax years beginning after December 31, 2017. Post-2017 NOLs do not have an expiration period, but may only offset 80% of the Company’s taxable income in any year of utilization. As of December 31, 2018 , Post-2017 NOLs amounted to $58,298 . If not utilized, the Company’s existing federal NOL carryforwards, unaffected by the 2017 Tax Act, will expire as follows: 
+ 
+Year Expiring 
+ 
+Total 
+2019-2024 
+2025-2027 
+2028-2030 
+2031-2033 
+2034-2038 
+Federal NOL carryforwards 
+$ 
+662,712 
+$ 
+115,387 
+$ 
+39,714 
+$ 
+32,111 
+$ 
+22,164 
+$ 
+453,336 
+As a result of a historical write-down of oil and natural gas properties in 2016, discussed in Notes 2 and Supplemental Information on Oil and Natural Gas Operations , the Company had incurred a cumulative three year loss. Because of the impact the cumulative loss had on the determination of the recoverability of deferred tax assets through future earnings, the Company assessed the ability to realize its deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, the Company established a valuation allowance for the net deferred tax asset. As of December 31, 2017, the valuation allowance was $60,919 . During 2018, the Company’s tax position transitioned from a net deferred tax asset position to a net deferred tax liability position, thereby unwinding the valuation allowance balance to $0 as of December 31, 2018 . 
+The Company had no significant unrecognized tax benefits at December 31, 2018 . Accordingly, the Company does not have any interest or penalties related to uncertain tax positions. However, if interest or penalties were to be incurred related to uncertain tax positions, such amounts would be recognized in income tax expense. 
+The Company provides for income taxes at a statutory rate of 21% adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses, restricted stock windfalls, and state income taxes. The following table presents a reconciliation of the reported amount of income tax expense to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income from continuing operations: 
+໿ 
+82 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+ 
+For the Year Ended December 31, 
+Components of income tax rate reconciliation 
+2018 
+2017 
+2016 
+Income tax expense computed at the statutory federal income tax rate 
+21 
+% 
+35 
+% 
+35 
+% 
+State taxes net of federal expense 
+1 
+% 
+1 
+% 
+— 
+% 
+Section 162(m) 
+1 
+% 
+— 
+% 
+(1 
+)% 
+Valuation allowance 
+(20 
+)% 
+(35 
+)% 
+(34 
+)% 
+Effective income tax rate 
+3 
+% 
+1 
+% 
+— 
+% 
+ 
+For the Year Ended December 31, 
+Components of income tax expense 
+2018 
+2017 
+2016 
+Current federal income tax benefit 
+$ 
+— 
+$ 
+(48 
+) 
+$ 
+(104 
+) 
+Deferred federal income tax (benefit) expense 
+3,594 
+(45 
+) 
+— 
+Deferred state income tax expense 
+4,516 
+1,366 
+90 
+Total income tax (benefit) expense 
+$ 
+8,110 
+$ 
+1,273 
+$ 
+(14 
+) 
+໿ 
+. 
+Note 13 - Asset Retirement Obligations 
+The table below summarizes the activity for the Company’s asset retirement obligations: 
+ 
+For the Year Ended December 31, 
+2018 
+2017 
+Asset retirement obligations at January 1, 2018 and 2017, respectively 
+$ 
+6,020 
+$ 
+6,661 
+Accretion expense 
+874 
+677 
+Liabilities incurred 
+1,543 
+278 
+Liabilities settled 
+(1,288 
+) 
+(711 
+) 
+Dispositions 
+(614 
+) 
+— 
+Revisions to estimate 
+7,757 
+(885 
+) 
+Asset retirement obligations at end of period 
+14,292 
+6,020 
+Less: Current asset retirement obligations 
+(3,887 
+) 
+(1,295 
+) 
+Long-term asset retirement obligations at December 31, 2018 and 2017, respectively 
+$ 
+10,405 
+$ 
+4,725 
+2018 
+• 
+Liabilities incurred include additions from acquisitions, primarily the Delaware Asset Acquisition completed in the third quarter of 2018, as well as additions from new wells drilled during the year. 
+• 
+Liabilities settled include the retirement of 26 wells in 2018 . 
+• 
+Dispositions are primarily attributable to the sale of oil and gas properties in the second quarter of 2018 . 
+• 
+Revisions to estimates were due to changes in plugging cost estimates, timing of abandonment activities, and changes in working interest of producing wells. 
+2017 
+• 
+Liabilities incurred were primarily a result of additions from new wells drilled during the year. 
+• 
+Liabilities settled include the retirement of 18 wells in 2017 . 
+• 
+Revisions to estimates were due to changes in timing of abandonment activities. 
+Certain of the Company’s operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded on the Consolidated Balance Sheets at December 31, 2018 and 2017 as long-term restricted investments were $3,424 and $3,372 , respectively. These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties. 
+83 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Note 14 – Other 
+Commitments and contingencies 
+The Company is involved in various claims and lawsuits incidental to its business. In the opinion of management, the ultimate liability hereunder, if any, will not have a material adverse effect on the financial position or results of operations of the Company. 
+The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment are not expected to have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies hereunder, and claims for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities. 
+Operating leases 
+As of December 31, 2018 , the Company had contracts for five horizontal drilling rigs. The contract terms, as amended effective as of July 9, 2018, will end on various dates between July 2019 and February 2021. All of the drilling rig contracts provide for early termination, with penalties calculated at a reduced daily rate. 
+Other commitments 
+In March 2018, the Company entered into a contract for dedicated fracturing and pump down perforating crews, which was effective on April 16, 2018 for a two -year period. The agreement was amended effective October 16, 2018 to reflect updated market conditions and to extend the contract expiration date to December 31, 2021. 
+In August 2018, the Company executed a firm transportation agreement for dedicated capacity on a new pipeline system that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard, Ward, Reagan and Upton counties to multiple marketing points in the Permian Basin. Subject to completion of the new pipeline system, which will have delivery points in several locations along the Gulf Coast, we will have a long-term commitment that will apply applicable tariff rates to our 15,000 Bbls per day commitment for the term of the agreement. Barrels may be transported to multiple delivery points along the Gulf Coast and may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. 
+Subsequent Event 
+In January 2019, Callon Petroleum Operating Company executed a crude oil sales contract that provides further dedicated capacity on several pipeline systems that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard, Ward, and Reagan counties and will have delivery points in several locations along the Gulf Coast, providing the Company with the potential benefit of access to an international weighted average sales price. We will have a long-term 10,000 Bbls per day commitment for the term of the agreement, and may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. 
+໿ 
+84 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Supplemental Information on Oil and Natural Gas Operations (Unaudited) 
+Estimated Reserves 
+The Company’s proved oil and natural gas reserves at December 31, 2018 , 2017 and 2016 have been estimated by DeGolyer and MacNaughton, the Company’s current independent petroleum and geological firm (the “Reserve Engineering Firm”). The reserves were prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions. 
+There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only, and should not be deemed exact. In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company’s oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves. 
+Extrapolation of performance history and material balance estimates were utilized by the Company’s Reserve Engineering Firm to project future recoverable reserves for the producing properties where sufficient history existed to suggest performance trends and where these methods were applicable to the subject reservoirs. The projections for the remaining producing properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to nonproducing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production, and to a small extent, horizontal PDP and PUD categories. 
+The following tables disclose changes in the estimated net quantities of oil and natural gas reserves, all of which are located onshore within the continental United States: 
+໿ 
+For the Year Ended December 31, 
+Proved developed and undeveloped reserves: 
+2018 
+2017 
+2016 
+Oil (MBbls): 
+Beginning of period 
+107,072 
+71,145 
+43,348 
+Purchase of reserves in place 
+30,756 
+8,388 
+25,054 
+Sale of reserves in place 
+— 
+— 
+(1,718 
+) 
+Extensions and discoveries 
+67,763 
+39,267 
+14,479 
+Revisions to previous estimates 
+(8,982 
+) 
+(1,548 
+) 
+(4,544 
+) 
+Reclassifications due to changes in development plan 
+(7,069 
+) 
+(3,623 
+) 
+(1,194 
+) 
+Production 
+(9,443 
+) 
+(6,557 
+) 
+(4,280 
+) 
+End of period 
+180,097 
+107,072 
+71,145 
+Natural Gas (MMcf): 
+Beginning of period 
+179,410 
+122,611 
+65,537 
+Purchase of reserves in place 
+53,563 
+12,711 
+36,474 
+Sale of reserves in place 
+— 
+— 
+(2,765 
+) 
+Extensions and discoveries 
+103,149 
+48,648 
+17,194 
+Revisions to previous estimates 
+41,767 
+18,121 
+16,842 
+Reclassifications due to changes in development plan 
+(11,976 
+) 
+(11,785 
+) 
+(2,913 
+) 
+Production 
+(15,447 
+) 
+(10,896 
+) 
+(7,758 
+) 
+End of period 
+350,466 
+179,410 
+122,611 
+Total (MBOE): 
+Beginning of period 
+136,974 
+91,580 
+54,271 
+Purchase of reserves in place 
+39,683 
+10,507 
+31,133 
+Sale of reserves in place 
+— 
+— 
+(2,179 
+) 
+Extensions and discoveries 
+84,955 
+47,375 
+17,345 
+Revisions to previous estimates 
+(2,021 
+) 
+1,472 
+(1,737 
+) 
+Reclassifications due to changes in development plan 
+(9,065 
+) 
+(5,587 
+) 
+(1,680 
+) 
+Production 
+(12,018 
+) 
+(8,373 
+) 
+(5,573 
+) 
+End of period 
+238,508 
+136,974 
+91,580 
+85 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+For the Year Ended December 31, 
+Proved developed reserves: 
+2018 
+2017 
+2016 
+Oil (MBbls): 
+Beginning of period 
+51,920 
+32,920 
+22,257 
+End of period 
+92,202 
+51,920 
+32,920 
+Natural gas (MMcf): 
+Beginning of period 
+104,389 
+61,871 
+38,157 
+End of period 
+218,417 
+104,389 
+61,871 
+MBOE: 
+Beginning of period 
+69,318 
+43,232 
+28,617 
+End of period 
+128,605 
+69,318 
+43,232 
+Proved undeveloped reserves: 
+Oil (MBbls): 
+Beginning of period 
+55,152 
+38,225 
+21,091 
+End of period 
+87,895 
+55,152 
+38,225 
+Natural gas (MMcf): 
+Beginning of period 
+75,021 
+60,740 
+27,380 
+End of period 
+132,049 
+75,021 
+60,740 
+MBOE: 
+Beginning of period 
+67,656 
+48,348 
+25,654 
+End of period 
+109,903 
+67,656 
+48,348 
+Total proved reserves: 
+Oil (MBbls): 
+Beginning of period 
+107,072 
+71,145 
+43,348 
+End of period 
+180,097 
+107,072 
+71,145 
+Natural gas (MMcf): 
+Beginning of period 
+179,410 
+122,611 
+65,537 
+End of period 
+350,466 
+179,410 
+122,611 
+MBOE: 
+Beginning of period 
+136,974 
+91,580 
+54,271 
+End of period 
+238,508 
+136,974 
+91,580 
+Total Proved Reserves 
+The Company ended 2018 with estimated net proved reserves of 238,508 MBOE, representing a 74% increase over 2017 year-end estimated net proved reserves of 136,974 MBOE. The Company added 124,638 MBOE primarily from the Delaware Asset Acquisition completed third quarter of 2018 and development efforts in the Permian Basin, where it drilled a total of 70 gross ( 57.5 net) wells. This increase was offset by 2018 production, negative revisions of previous estimates of 2,021 MBOE primarily related to technical revisions of proved undeveloped reserves, and reclassifications of proved undeveloped reserves of 9,065 MBOE from 19 PUD locations primarily due to acreage trades and changes in our development plan, including larger pad development concepts and co-development of zones. These changes resulted in the anticipated drilling of PUD locations being moved beyond five years from initial booking. 
+The Company ended 2017 with estimated net proved reserves of 136,974 MBOE, representing a 50% increase over 2016 year-end estimated net proved reserves of 91,580 MBOE. The Company added 57,881 MBOE primarily from the Company’s acquisition and development efforts in the Permian Basin, where it drilled a total of 49 gross ( 38.2 net) wells. This increase was primarily offset by 2017 production, revisions of previous estimates, and reclassifications of PUD locations from our development and drilling plan. The Company reclassified 13 PUD locations as a result of a change in the Company’s development and drilling plans within its operating areas and the removal of certain proved developed vertical well locations. 
+The Company ended 2016 with estimated net proved reserves of 91,580 MBOE, representing a 69% increase over 2015 year-end estimated net proved reserves of 54,271 MBOE. The Company added 48,477 MBOE primarily from the Company’s acquisition and development efforts in the Permian Basin, where it drilled a total of 29 gross ( 20.9 net) wells. This increase was primarily offset by 11,168 MBOE related to divestitures, 2016 production, revisions primarily due to pricing, and reclassifications of 4 PUD locations as a result of a change in the Company’s development and dilling plans within its operating areas. 
+86 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Capitalized Costs 
+Capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows: 
+As of December 31, 
+2018 
+2017 
+Oil and natural gas properties: 
+Evaluated properties 
+$ 
+4,585,020 
+$ 
+3,429,570 
+Unevaluated properties 
+1,404,513 
+1,168,016 
+Total oil and natural gas properties 
+5,989,533 
+4,597,586 
+Accumulated depreciation, depletion, amortization and impairment 
+(2,270,675 
+) 
+(2,084,095 
+) 
+Total oil and natural gas properties capitalized 
+$ 
+3,718,858 
+$ 
+2,513,491 
+Costs Incurred 
+Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows: 
+For the Year Ended December 31, 
+2018 
+2017 
+2016 
+Acquisition costs: 
+Evaluated properties 
+$ 
+347,305 
+$ 
+156,340 
+$ 
+228,832 
+Unevaluated properties 
+466,816 
+499,295 
+536,540 
+Development costs 
+259,410 
+148,254 
+111,065 
+Exploration costs 
+323,458 
+239,453 
+38,612 
+Total costs incurred 
+$ 
+1,396,989 
+$ 
+1,043,342 
+$ 
+915,049 
+Standardized Measure 
+The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2018 . You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Prices are based on the preceding 12 -months’ average price based on closing prices on the first day of each month. The following table summarizes the average 12 -month oil and natural gas prices net of differentials for the respective periods: 
+໿ 
+2018 
+2017 
+2016 
+Average 12-month price, net of differentials, per barrel of oil (a) 
+$ 
+58.40 
+$ 
+49.48 
+$ 
+40.03 
+Average 12-month price, net of differentials, per Mcf of natural gas (b) 
+$ 
+3.64 
+$ 
+3.47 
+$ 
+2.71 
+(a) 
+Includes adjustments to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality. 
+(b) 
+Includes a high Btu content of separator natural gas and adjustments to reflect the Btu content, transportation charges and other fees specific to the individual properties. 
+87 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate. 
+໿ 
+Standardized Measure 
+For the Year Ended December 31, 
+2018 
+2017 
+2016 
+Future cash inflows 
+$ 
+11,794,080 
+$ 
+5,920,328 
+$ 
+3,180,005 
+Future costs 
+Production 
+(2,923,959 
+) 
+(1,692,871 
+) 
+(974,667 
+) 
+Development and net abandonment 
+(1,429,787 
+) 
+(680,948 
+) 
+(384,117 
+) 
+Future net inflows before income taxes 
+7,440,334 
+3,546,509 
+1,821,221 
+Future income taxes (a) 
+(782,470 
+) 
+(166,985 
+) 
+(1,602 
+) 
+Future net cash flows 
+6,657,864 
+3,379,524 
+1,819,619 
+10% discount factor 
+(3,716,571 
+) 
+(1,822,842 
+) 
+(1,009,787 
+) 
+Standardized measure of discounted future net cash flows 
+$ 
+2,941,293 
+$ 
+1,556,682 
+$ 
+809,832 
+໿ 
+(a) 
+As of December 31, 2018 , 2017 , and 2016 the Company’s statutory tax rate applied was 21%, 21%, and 35%, respectively. 
+ 
+Changes in Standardized Measure 
+ 
+For the Year Ended December 31, 
+ 
+2018 
+2017 
+2016 
+Standardized measure at the beginning of the period 
+$ 
+1,556,682 
+$ 
+809,832 
+$ 
+570,890 
+Sales and transfers, net of production costs 
+(481,306 
+) 
+(294,172 
+) 
+(150,628 
+) 
+Net change in sales and transfer prices, net of production costs 
+222,802 
+176,234 
+(103,136 
+) 
+Net change due to purchases and sales of in place reserves 
+554,697 
+129,454 
+260,859 
+Extensions, discoveries, and improved recovery, net of future production and development costs incurred 
+1,093,773 
+635,000 
+180,228 
+Changes in future development cost 
+40,483 
+36,983 
+82,320 
+Revisions of quantity estimates 
+(167,096 
+) 
+(79,325 
+) 
+(35,938 
+) 
+Accretion of discount 
+157,676 
+80,983 
+57,091 
+Net change in income taxes 
+(187,841 
+) 
+(20,073 
+) 
+16 
+Changes in production rates, timing and other 
+151,423 
+81,766 
+(51,870 
+) 
+Aggregate change 
+1,384,611 
+746,850 
+238,942 
+Standardized measure at the end of period 
+$ 
+2,941,293 
+$ 
+1,556,682 
+$ 
+809,832 
+88 
+Notes to the Consolidated Financial Statements 
+(All dollar amounts in thousands, except per share and per unit data) 
+Supplemental Quarterly Financial Information (Unaudited) 
+2018 
+First Quarter 
+Second Quarter 
+Third Quarter 
+Fourth Quarter 
+Total revenues 
+$ 
+127,440 
+$ 
+137,075 
+$ 
+161,214 
+$ 
+161,895 
+Income from operations 
+60,986 
+67,400 
+72,811 
+58,333 
+Net income 
+55,761 
+50,474 
+37,931 
+156,194 
+Income available to common shares 
+53,937 
+48,650 
+36,108 
+154,370 
+Income per common share - basic 
+$ 
+0.27 
+$ 
+0.23 
+$ 
+0.16 
+$ 
+0.68 
+Income per common share - diluted 
+$ 
+0.27 
+$ 
+0.23 
+$ 
+0.16 
+$ 
+0.68 
+2017 
+First Quarter 
+Second Quarter 
+Third Quarter 
+Fourth Quarter 
+Total revenues 
+$ 
+81,363 
+$ 
+82,283 
+$ 
+84,614 
+$ 
+118,214 
+Income from operations 
+32,249 
+23,743 
+31,426 
+54,028 
+Net income 
+47,129 
+33,390 
+17,081 
+22,824 
+Income available to common shares 
+45,305 
+31,566 
+15,257 
+21,001 
+Income per common share - basic 
+$ 
+0.23 
+$ 
+0.16 
+$ 
+0.08 
+$ 
+0.10 
+Income per common share - diluted 
+$ 
+0.22 
+$ 
+0.16 
+$ 
+0.08 
+$ 
+0.10 
+໿ 
+89 
+ITEM 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure 
+None. 
+ITEM 9A. Controls and Procedures 
+Disclosure controls and procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) performed an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2018 . 
+Management’s report on internal control over financial reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. generally accepted accounting principles. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2018 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission (2013 framework) (the COSO criteria). Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2018 . 
+Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+The Company’s independent registered public accounting firm, Grant Thornton, LLP, has issued an attestation report regarding its assessment of the Company’s internal control over financial reporting as of December 31, 2018 , presented preceding the Company’s financial statements included in Part II, Item 8 of this 2018 Annual Report on Form 10-K. Additionally, the financial statements for the years ended December 31, 2017 and 2016, covered in this 2018 Annual Report on Form 10-K, have also been audited by the Company’s independent registered public accounting firm, whose report is presented preceding the their report on the Company’s internal control over financial reporting, included in Part II, Item 8. 
+Changes in internal control over financial reporting . There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting. 
+ITEM 9B. Other Information 
+On February 22, 2019, the Board adopted the Amended and Restated Bylaws (as amended and restated, the “Bylaws”) in connection with its regular review of the Company’s corporate governance structure. The indemnification provisions, which limit the liability of our directors, officers, and employees have been amended to, among other things, clarify and update the directors, officers, and employees’ entitlement to indemnification and entitlement to advancement of expenses, and clarify that directors, officers, and employees who bring claims against the Company are not entitled to indemnification or expense advancement unless such claim was authorized in advance by the Board. 
+In addition, the Bylaws were also amended to, among other things: 
+• 
+Modify the advance notification procedures for a shareholder to make director nominations and other proposals of business at annual meetings of the shareholders in order to, among other things, specify the disclosures that shareholders must provide when submitting proposals and director nominations for consideration. 
+• 
+Provide that the chairman of a shareholder meeting may adjourn any meeting of shareholders for any reason, whether or not there is a quorum present. 
+• 
+Designate the Court of Chancery of the State of Delaware as the exclusive forum for certain legal actions and proceedings involving the Company. 
+• 
+Amend provisions relating to meetings of the shareholders and special meetings of the shareholders, including updating the scheduling and location of the meetings, adding disclosure of record holders entitled to vote at the meeting, covering the 
+90 
+procedures for postponing, rescheduling or cancelling a previously called special meeting and governing the Chairman of the Board’s ability to adjourn meetings without notice. 
+• 
+Make other administrative, procedural, clarifying and conforming changes. 
+The foregoing description is qualified in its entirety by reference to the Bylaws, a copy of which are filed as Exhibit 3.3 to this 2018 Annual Report on Form 10-K and incorporated herein by reference. 
+91 
+PART III. 
+ITEM 10. Directors, Executive Officers and Corporate Governance 
+For information concerning Item 10, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 9, 2019 , which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+The Company has adopted a code of ethics that applies to the Company’s officers, directors, employees, agents and representatives and includes a code of ethics for senior financial officers that applies to the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer. The full text of such code of ethics has been posted on the Company’s website at www.callon.com, and is available free of charge in print to any shareholder who requests it. Request for copies should be addressed to the Secretary at mailing address 1401 Enclave Parkway, Suite 600, Houston, TX 77077. 
+ITEM 11. Executive Compensation 
+For information concerning Item 11, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 9, 2019 , which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+For information concerning the security ownership of certain beneficial owners and management, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 9, 2019 , which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+ITEM 13. Certain Relationships and Related Transactions and Director Independence 
+For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 9, 2019 , which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+ITEM 14. Principal Accountant Fees and Services 
+For information concerning Item 14, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 9, 2019 , which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+92 
+PART IV. 
+ITEM 15. Exhibits 
+The following is an index to the financial statements and financial statement schedules that are filed in Part II, Item 8 of this report on Form 10-K. 
+໿ 
+Incorporated by reference (File No. 001-14039, unless otherwise indicated) 
+Exhibit Number 
+Description 
+Form 
+Exhibit 
+Filing Date 
+2.1 
+Purchase and Sale Agreement, dated May 23, 2018, between Cimarex Energy Co, Prize Energy Resources, Inc., and Magnum Hunter Production, Inc. and Callon Petroleum Operating Company 
+8-K 
+2.1 
+05/24/2018 
+3.1 
+Certificate of Incorporation of the Company, as amended through May 12, 2016 
+10-Q 
+3.1 
+11/03/2016 
+3.2 
+(a) 
+Amended and Restated Bylaws of the Company 
+4.1 
+Specimen Common Stock Certificate 
+10-K 
+4.1 
+02/28/2018 
+4.2 
+Certificate for the Company’s 10.00% Series A Cumulative Preferred Stock 
+8-A 
+4.1 
+05/23/2013 
+4.3 
+Registration Rights Agreement, dated May 26, 2016, among Callon Petroleum Company and each of the Persons set forth on Schedule A therein 
+8-K 
+10.1 
+05/31/2016 
+4.4 
+Certificate of Designation of Rights and Preferences of 10.00% Series A Cumulative Preferred Stock 
+8-A 
+3.5 
+05/23/2013 
+4.5 
+Indenture of 6.125% Senior Notes Due 2024, dated as of October 3, 2016, among Callon Petroleum Company, the Guarantors party thereto and U.S. Bank National Association, as Trustee 
+8-K 
+4.1 
+10/04/2016 
+4.6 
+Registration Rights Agreement of 6.125% Senior Notes Due 2024, dated October 3, 2016, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P. Morgan Securities LLC, as representative of the Initial Purchasers named on Annex E thereto 
+8-K 
+4.2 
+10/04/2016 
+4.7 
+Registration Rights Agreement of 6.125% Senior Notes Due 2024, dated May 24, 2017, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P. Morgan Securities LLC, as representative of the Initial Purchasers named on Annex E thereto 
+8-K 
+4.1 
+05/24/2017 
+4.8 
+Indenture of 6.375% Senior Notes Due 2026, dated as of June 7, 2018, among Callon Petroleum Company, the Guarantors party thereto and U.S. Bank National Association, as Trustee 
+8-K 
+4.1 
+06/07/2018 
+4.9 
+Registration Rights Agreement of 6.375% Senior Notes Due 2026, dated June 7, 2018, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P. Morgan Securities LLC, as representative of the Initial Purchasers named on Annex E thereto 
+8-K 
+4.2 
+06/07/2018 
+10.1 
+(b) 
+Callon Petroleum Company 2011 Omnibus Incentive Plan 
+DEF 14A 
+A 
+03/21/2011 
+10.2 
+(b) 
+Form of Callon Petroleum Company Restricted Stock Unit Award Agreement, adopted on March 12, 2015 
+10-K 
+10.16 
+03/03/2016 
+10.3 
+(b) 
+Form of Callon Petroleum Company Phantom Share Award Agreement for performance-based awards settleable in cash and stock, granted to officers of the Company, adopted on March 12, 2015 
+10-K 
+10.17 
+03/03/2016 
+10.4 
+(b) 
+Form of Callon Petroleum Company Phantom Share Award Agreement for time-based restricted stock units settleable in cash, granted to officers of the Company, adopted on March 12, 2015 
+10-K 
+10.18 
+03/03/2016 
+10.5 
+(b) 
+First Amendment to the Callon Petroleum Company 2011 Omnibus Incentive Plan 
+10-Q 
+10.1 
+11/05/2015 
+10.6 
+Sixth Amended and Restated Credit Agreement, dated May 31, 2017, among Callon Petroleum Company, JPMorgan Chase Bank, National Association, as administrative agent and the Lenders party thereto 
+10-Q 
+10.1 
+08/02/2017 
+10.7 
+Amendment No. 1 to the Sixth Amended and Restated Credit Agreement, dated April 5, 2018, among Callon Petroleum Company, JPMorgan Chase Bank, National Association, as administrative agent and the Lenders party thereto 
+8-K 
+10.1 
+04/06/2018 
+10.8 
+Amendment No. 2 to the Sixth Amended and Restated Credit Agreement, dated September 27, 2018, among Callon Petroleum Company, JPMorgan Chase Bank, National Association, as administrative agent and the Lenders party thereto 
+8-K 
+10.1 
+09/28/2018 
+10.9 
+Purchase Agreement, dated May 19, 2017, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P.Morgan Securities, LLC, as representatives of the Initial Purchasers 
+8-K 
+10.1 
+05/24/2017 
+10.10 
+Amended and Restated Deferred Compensation Plan for Outside Directors - Callon Petroleum Company, dated as of May 10, 2017 and effective as of May 1, 2017 
+10-K 
+10.11 
+02/28/2018 
+10.11 
+Purchase Agreement of 6.375% Senior Notes Due 2026, dated as of May 31, 208, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P. Morgan Securities LLC, as representative of the Initial Purchases named on Schedule 1 thereto 
+8-K 
+10.1 
+06/01/2018 
+10.12 
+(b) 
+Callon Petroleum Company 2018 Omnibus Incentive Plan 
+DEF 14A 
+A 
+03/23/2018 
+10.13 
+(b) 
+Form of Callon Petroleum Company Director Restricted Stock Unit Award Agreement, adopted on May 10, 2018 under the 2018 Omnibus Incentive Plan 
+10-Q 
+10.4 
+08/07/2018 
+10.14 
+(b) 
+Form of Callon Petroleum Company Employee Restricted Stock Unit Award Agreement, adopted on May 10, 2018 under the 2018 Omnibus Incentive Plan 
+10-Q 
+10.5 
+08/07/2018 
+10.15 
+(b) 
+Form of Callon Petroleum Company Employee Cash-Settleable Performance Share Award Agreement, adopted on May 10, 2018 under the 2018 Omnibus Incentive Plan 
+10-Q 
+10.6 
+08/07/2018 
+93 
+10.16 
+(b) 
+Form of Callon Petroleum Company Employee Stock-Settleable Performance Share Award Agreement, adopted on May 10, 2018 under the 2018 Omnibus Incentive Plan 
+10-Q 
+10.7 
+08/07/2018 
+10.17 
+(a)(b) 
+Form of Change in Control Severance Compensation Agreement, dated as of January 1, 2019, by and between Callon Petroleum Company and its executive officers 
+10.18 
+(a)(b) 
+Change in Control Severance Compensation Agreement, dated as of January 1, 2019, by and between Joseph C. Gatto, Jr., and Callon Petroleum Company 
+10.19 
+(a) 
+Separation Agreement, dated January 2, 2019, by and between Gary A. Newberry and Callon Petroleum Company 
+10.20 
+(a)(b) 
+Form of Callon Petroleum Company Employee Restricted Stock Unit Award Agreement, adopted on January 31, 2019 under the 2018 Omnibus Incentive Plan 
+10.21 
+(a)(b) 
+Form of Callon Petroleum Officer Cash-Settleable Performance Share Award Agreement, adopted on January 31, 2019 under the 2018 Omnibus Incentive Plan 
+10.22 
+(a)(b) 
+Form of Callon Petroleum Company Officer Stock-Settleable Performance Share Award Agreement, adopted on January 31, 2019 under the 2018 Omnibus Incentive Plan 
+10.23 
+(a)b) 
+Form of Callon Petroleum Company Officer Restricted Stock Unit Award Agreement, adopted on January 31, 2019 under the 2018 Omnibus Incentive Plan 
+21.1 
+(a) 
+Subsidiaries of the Company 
+23.1 
+(a) 
+Consent of Grant Thornton LLP 
+23.2 
+(a) 
+Consent of DeGolyer and MacNaughton, Inc. 
+31.1 
+(a) 
+Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a) 
+31.2 
+(a) 
+Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a) 
+32.1 
+(c) 
+Section 1350 Certifications of Chief Executive and Financial Officers pursuant to Rule 13(a)-14(b) 
+99.1 
+(a) 
+Reserve Report Summary prepared by DeGolyer and MacNaughton, Inc. as of December 31, 2018 
+(a) 
+Filed herewith. 
+(b) 
+Indicates management compensatory plan, contract, or arrangement. 
+(c) 
+Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, except to the extent that the registrant specifically incorporates it by reference. 
+94 
+ITEM 16. Form 10-K Summary 
+Not applicable. 
+95 
+SIGNATURES 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+Callon Petroleum Company 
+/s/ James P. Ulm, II 
+Date: 
+February 26, 2019 
+By: James P. Ulm, II 
+Chief Financial Officer (principal financial officer) 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+/s/ Joseph C. Gatto, Jr. 
+Date: 
+February 26, 2019 
+Joseph C. Gatto, Jr. (principal executive officer) 
+ 
+ 
+/s/ James P. Ulm, II 
+Date: 
+February 26, 2019 
+James P. Ulm, II (principal financial officer) 
+ 
+ 
+/s/ Mitzi P. Conn 
+Date: 
+February 26, 2019 
+Mitzi P. Conn (principal accounting officer) 
+ 
+ 
+/s/ L. Richard Flury 
+Date: 
+February 26, 2019 
+L. Richard Flury (chairman of the board of directors) 
+ 
+ 
+/s/ Barbara J. Faulkenberry 
+Date: 
+February 26, 2019 
+Barbara J. Faulkenberry (director) 
+ 
+ 
+/s/ Anthony J. Nocchiero 
+Date: 
+February 26, 2019 
+Anthony J. Nocchiero (director) 
+ 
+ 
+/s/ Larry D. McVay 
+Date: 
+February 26, 2019 
+Larry McVay (director) 
+ 
+ 
+/s/ Matthew R. Bob 
+Date: 
+February 26, 2019 
+Matthew R. Bob (director) 
+ 
+ 
+/s/ James M. Trimble 
+Date: 
+February 26, 2019 
+James M. Trimble (director) 
+ 
+ 
+/s/ Michael L. Finch 
+Date: 
+February 26, 2019 
+Michael L. Finch (director) 
+ 
+96
\ No newline at end of file
diff --git a/raw/filings/0000928022/2018/0000928022-19-000044/filing_metadata.csv b/raw/filings/0000928022/2018/0000928022-19-000044/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..218adae14c7714b8badf0c77eb3e2ff77aef4580
--- /dev/null
+++ b/raw/filings/0000928022/2018/0000928022-19-000044/filing_metadata.csv
@@ -0,0 +1,2 @@
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+0000928022,CPE,Callon Petroleum Co,10-K,2019-02-27,2018-12-31,2019-02-26T23:08:34.000Z,0000928022-19-000044,a4q18form10k.htm,10-K,13880408,1,0,https://www.sec.gov/Archives/edgar/data/928022/000092802219000044/a4q18form10k.htm,https://www.sec.gov/Archives/edgar/data/928022/000092802219000044/,2018,2018,1
diff --git a/raw/filings/0000928022/2018/0000928022-19-000044/item1.txt b/raw/filings/0000928022/2018/0000928022-19-000044/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000928022/2018/0000928022-19-000044/item13.txt b/raw/filings/0000928022/2018/0000928022-19-000044/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..d7c38b9f650d0eed1e581527d2c4e7bccc9c7bbc
--- /dev/null
+++ b/raw/filings/0000928022/2018/0000928022-19-000044/item13.txt
@@ -0,0 +1,2 @@
+ITEM 13. Certain Relationships and Related Transactions and Director Independence 
+For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 9, 2019 , which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2018/0000928022-19-000044/item9a.txt b/raw/filings/0000928022/2018/0000928022-19-000044/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..c945ba6e8ec4cee4e473be71c1195913183b25fe
--- /dev/null
+++ b/raw/filings/0000928022/2018/0000928022-19-000044/item9a.txt
@@ -0,0 +1,6 @@
+ITEM 9A. Controls and Procedures 
+Disclosure controls and procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) performed an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2018 . 
+Management’s report on internal control over financial reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. generally accepted accounting principles. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2018 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission (2013 framework) (the COSO criteria). Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2018 . 
+Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+The Company’s independent registered public accounting firm, Grant Thornton, LLP, has issued an attestation report regarding its assessment of the Company’s internal control over financial reporting as of December 31, 2018 , presented preceding the Company’s financial statements included in Part II, Item 8 of this 2018 Annual Report on Form 10-K. Additionally, the financial statements for the years ended December 31, 2017 and 2016, covered in this 2018 Annual Report on Form 10-K, have also been audited by the Company’s independent registered public accounting firm, whose report is presented preceding the their report on the Company’s internal control over financial reporting, included in Part II, Item 8. 
+Changes in internal control over financial reporting . There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2018/0000928022-19-000044/rp_note.txt b/raw/filings/0000928022/2018/0000928022-19-000044/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000928022/2018/0000928022-19-000044/rpt_disclosure.txt b/raw/filings/0000928022/2018/0000928022-19-000044/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..ce99198e8dab14ee44de4f2b684db554a9c8a0b0
--- /dev/null
+++ b/raw/filings/0000928022/2018/0000928022-19-000044/rpt_disclosure.txt
@@ -0,0 +1,7 @@
+Certain Relationships and Related Party Transactions 
+The Audit Committee charter provides that the Audit Committee shall review and approve all related party transactions. A transaction will be considered a “related party transaction” if the transaction would be required to be disclosed under Item 404 of Regulation S-K. In addition, our Code provides that an officer’s or a director’s conflict of interest with Callon may only be waived if the Nominating and Corporate Governance Committee approves the waiver and the full Board ratifies the waiver. 
+For the fiscal year ended 2019, Austin Weant, who is the son of Jerry Weant, our former Vice President of Land, received $162,400 in total compensation as an employee of the Company, which is consistent with market compensation for his services. In addition, Austin Weant was eligible to participate in all benefit plans and programs available generally to the Company’s employees. 
+Except for the foregoing, as of December 31, 2019, we are not aware of any related party transactions with our executive officers that require disclosure under Item 404 of Regulation S-K. 
+Shareholders’ Proposals and Director Nominations for the 2021 Annual Meeting 
+In order for a proposal to be considered for inclusion in the proxy statement for the 2021 Annual Meeting of Shareholders (the “2021 Annual Meeting”) pursuant to Rule 14a-8 of the Exchange Act, such proposal must be received by the Secretary of the Company at our principal executive offices no later than [•], 2020 (assuming the date of the 2021 Annual Meeting has not been changed by more than 30 days from the date of this year’s Annual Meeting), and must otherwise be in compliance with the requirements of the SEC’s proxy rules. If the date of the 2021 Annual meeting has been changed by more than 30 days from the date of this Annual Meeting, then the deadline is a reasonable time before we begin to print and send our proxy materials for the 2021 Annual Meeting. 
+For a shareholder proposal to be introduced for consideration at the 2021 Annual Meeting but not intended to be considered for inclusion in the Company's proxy statement and form of proxy relating to such meeting (i.e. not pursuant to Rule 14a-8 of the Exchange Act), including shareholder nominations for candidates for election as directors, a shareholder must provide written notice of such proposal to Company not later than 120 days nor earlier than 150 days before the date of the 2021 Annual Meeting. Any such notice must describe the shareholder proposal in reasonable detail and otherwise comply with the requirements set forth in our bylaws.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2019/0000928022-20-000031/filing.txt b/raw/filings/0000928022/2019/0000928022-20-000031/filing.txt
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+utreg:D 
+iso4217:USD 
+utreg:Boe 
+cpe:Simulations 
+utreg:MBoe 
+cpe:contract 
+cpe:well 
+utreg:MMBoe 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+FORM 10-K 
+☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the fiscal year ended December 31, 2019 
+or 
+☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the transition period from ____________ to ____________ 
+Commission File Number 001-14039 
+Callon Petroleum Co mpany 
+(Exact Name of Registrant as Specified in Its Charter) 
+_______________________________________________ 
+໿ 
+Delaware 
+64-0844345 
+State or Other Jurisdiction of 
+Incorporation or Organization 
+I.R.S. Employer Identification No. 
+One Briarlake Plaza 
+2000 W. Sam Houston Parkway S., Suite 2000 
+Houston, 
+Texas 
+77042 
+Address of Principal Executive Offices 
+Zip Code 
+281 - 589-5200 
+(Registrant’s Telephone Number, Including Area Code) 
+Title of Each Class 
+Securities registered pursuant to Section 12(b) of the Act: 
+Name of Each Exchange on Which Registered 
+Common Stock, $0.01 par value 
+CPE 
+New York Stock Exchange 
+Securities registered pursuant to section 12 (g) of the Act: None 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐ 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒ 
+Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ 
+Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐ 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act: 
+Large accelerated filer 
+☒ 
+Accelerated filer 
+☐ 
+Non-accelerated filer 
+☐ 
+Smaller reporting company 
+☐ 
+Emerging growth company 
+☐ 
+. 
+If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ 
+The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2019 was approximately $ 1.5 billion. 
+The Registrant had 396,684,449 shares of common stock outstanding as of February 21, 2020 . 
+DOCUMENTS INCORPORATED BY REFERENCE 
+Portions of the definitive Proxy Statement of Callon Petroleum Company (to be filed no later than 120 days after December 31, 2019 ) relating to the Annual Meeting of Stockholders to be held on May 14, 2020 , which are incorporated into Part III of this Form 10-K. 
+TABLE OF CONTENTS 
+Special Note Regarding Forward Looking Statements 
+3 
+Glossary of Certain Terms 
+5 
+Part I 
+Items 1 and 2. 
+Business and Properties 
+7 
+Oil and Natural Gas Properties 
+9 
+Proved Oil and Gas Reserves 
+10 
+Capital Budget 
+13 
+Drilling Activity 
+13 
+Productive Wells 
+14 
+Production Volumes, Average Sales Prices and Operating Costs 
+15 
+Major Customers 
+16 
+Leasehold Acreage 
+16 
+Other 
+16 
+Regulations 
+18 
+Commitments and Contingencies 
+26 
+Available Information 
+26 
+Item 1A. 
+Risk Factors 
+27 
+Item 1B. 
+Unresolved Staff Comments 
+39 
+Item 3. 
+Legal Proceedings 
+39 
+Item 4. 
+Mine Safety Disclosures 
+39 
+Part II 
+Item 5. 
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+40 
+Performance Graph 
+41 
+Item 6. 
+Selected Financial Data 
+42 
+Item 7. 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+43 
+General 
+43 
+Overview 
+43 
+Results of Operations 
+44 
+Liquidity and Capital Resources 
+48 
+Summary of Critical Accounting Policies 
+53 
+Item 7A. 
+Quantitative and Qualitative Disclosures About Market Risk 
+56 
+Item 8. 
+Financial Statements and Supplementary Data 
+58 
+Reports of Independent Registered Public Accounting Firm 
+59 
+Consolidated Balance Sheets 
+63 
+Consolidated Statements of Operations 
+64 
+Consolidated Statements of Stockholders’ Equity 
+65 
+Consolidated Statements of Cash Flows 
+66 
+Notes to Consolidated Financial Statements 
+67 
+Supplemental Information on Oil and Natural Gas Operations (Unaudited) 
+97 
+Supplemental Quarterly Financial Information (Unaudited) 
+102 
+Item 9. 
+Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+103 
+Item 9A. 
+Controls and Procedures 
+103 
+Item 9B. 
+Other Information 
+103 
+Part III 
+Item 10. 
+Directors, Executive Officers and Corporate Governance 
+104 
+Item 11. 
+Executive Compensation 
+104 
+Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+104 
+Item 13. 
+Certain Relationships and Related Transactions and Director Independence 
+104 
+Item 14. 
+Principal Accountant Fees and Services 
+104 
+Part IV. 
+Item 15. 
+Exhibits 
+105 
+Item 16. 
+Form 10-K Summary 
+108 
+Signatures 
+109 
+2 
+Special Note Regarding Forward Looking Statements 
+This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”), as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements in this Form 10-K by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions. 
+All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future are forward-looking statements, including such things as: 
+• 
+matters relating to the acquisition of Carrizo Oil & Gas, Inc. (“Carrizo”); 
+• 
+our oil and natural gas reserve quantities, and the discounted present value of these reserves; 
+• 
+the amount and nature of our capital expenditures; 
+• 
+our future drilling and development plans and our potential drilling locations; 
+• 
+the timing and amount of future capital and operating costs; 
+• 
+production decline rates from our wells being greater than expected; 
+• 
+commodity price risk management activities and the impact on our average realized prices; 
+• 
+business strategies and plans of management; 
+• 
+our ability to consummate and efficiently integrate recent acquisitions; and 
+• 
+prospect development and property acquisitions. 
+We caution you that the forward-looking statements contained in this Annual Report on Form 10-K (this “2019 Annual Report on Form 10-K”) are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. We disclose these and other important factors that could cause our actual results to differ materially from our expectations under “Risk Factors” in Item 1A of Part I in this 2019 Annual Report on Form 10-K. These factors include: 
+• 
+general economic conditions including the availability of credit and access to existing lines of credit; 
+• 
+the volatility of oil and natural gas prices; 
+• 
+the uncertainty of estimates of oil and natural gas reserves; 
+• 
+impairments; 
+• 
+the impact of competition; 
+• 
+the availability and cost of seismic, drilling and other equipment, waste and water disposal infrastructure, and personnel; 
+• 
+operating hazards inherent in the exploration for and production of oil and natural gas; 
+• 
+difficulties encountered during the exploration for and production of oil and natural gas; 
+• 
+the potential impact of future drilling on production from existing wells 
+• 
+difficulties encountered in delivering oil and natural gas to commercial markets; 
+• 
+changes in customer demand and producers’ supply; 
+• 
+the uncertainty of our ability to attract capital and obtain financing on favorable terms; 
+• 
+compliance with, or the effect of changes in, the extensive governmental regulations regarding the oil and natural gas business including those related to climate change and greenhouse gases; 
+• 
+the impact of government regulation, including regulation of hydraulic fracturing and water disposal wells; 
+• 
+any increase in severance or similar taxes; 
+• 
+the financial impact of accounting regulations and critical accounting policies; 
+• 
+the comparative cost of alternative fuels; 
+• 
+credit risk relating to the risk of loss as a result of non-performance by our counterparties; 
+• 
+cyberattacks on the Company or on systems and infrastructure used by the oil and natural gas industry; 
+• 
+weather conditions; 
+• 
+risks associated with acquisitions, including the acquisition of Carrizo (the “Carrizo Acquisition” or the “Merger”); 
+• 
+failure to realize the expected benefits of the Carrizo Acquisition; 
+• 
+any litigation relating to the Carrizo Acquisition; and 
+• 
+any other factors listed in the reports we have filed and may file with the SEC. 
+Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Additional risks or uncertainties that are not currently known to us, that we currently deem to be immaterial, or that could apply to any company could also materially adversely affect our business, financial condition, or future results. Any forward-looking statement speaks only as of the date of which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except required by applicable law. 
+3 
+In addition, we caution that reserve engineering is a process of estimating oil and natural gas accumulated underground and cannot be measured exactly. Accuracy of reserve estimates depend on a number of factors including data available at the point in time, engineering interpretation of the data, and assumptions used by the reserve engineers as it relates to price and cost estimates and recoverability. New results of drilling, testing, and production history may result in revisions of previous estimates and, if significant, would impact future development plans. As such, reserve estimates may differ from actual results of oil and natural gas quantities ultimately recovered. 
+Except as required by applicable law, all forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. 
+4 
+GLOSSARY OF CERTAIN TERMS 
+All defined terms under Rule 4-10(a) of Regulation S-X shall have their prescribed meanings when used in this report. As used in this document: 
+• 
+ARO : asset retirement obligation. 
+• 
+ASU : accounting standards update. 
+• 
+Bbl or Bbls : barrel or barrels of oil or natural gas liquids. 
+• 
+Boe : barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of natural gas. The ratio of one barrel of oil or NGLs to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas. 
+• 
+Boe/d : Boe per day. 
+• 
+BLM : Bureau of Land Management. 
+• 
+Btu : a British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit. 
+• 
+Completion : the process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency. 
+• 
+Cushing : an oil delivery point that serves as the benchmark oil price for West Texas Intermediate. 
+• 
+Development well : A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. 
+• 
+EPA : United States Environmental Protection Agency. 
+• 
+Exploratory well : A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. 
+• 
+FASB : Financial Accounting Standards Board. 
+• 
+GAAP : Generally Accepted Accounting Principles in the United States. 
+• 
+GHG : greenhouse gases. 
+• 
+Henry Hub : a natural gas pipeline delivery point that serves as the benchmark natural gas price underlying NYMEX natural gas futures contracts. 
+• 
+Horizontal drilling : a drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at an angle within a specified interval. 
+• 
+ICE: Intercontinental Exchange. 
+• 
+LIBOR : London Interbank Offered Rate. 
+• 
+LOE : lease operating expense. 
+• 
+MBbls : thousand barrels of oil. 
+• 
+MBoe : thousand Boe. 
+• 
+Mcf : thousand cubic feet of natural gas. 
+• 
+MEH : Magellan East Houston, a delivery point in Houston, Texas that serves as a benchmark for crude oil. 
+• 
+MMBoe : million Boe. 
+• 
+MMBtu : million Btu. 
+• 
+MMcf : million cubic feet of natural gas. 
+• 
+NGL or NGLs : natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams. 
+• 
+Non-productive well : A well that is found to be incapable of producing oil or gas in sufficient quantities to justify completion, or upon completion, the economic operation of an oil or gas well. 
+• 
+NYMEX : New York Mercantile Exchange. 
+• 
+Oil : includes crude oil and condensate. 
+• 
+OPEC : Organization of Petroleum Exporting Countries. 
+• 
+PDPs : proved developed producing reserves. 
+• 
+Productive well : A well that is found to be capable of producing oil or gas in sufficient quantities to justify completion as an oil or gas well. 
+• 
+Proved developed producing reserves: Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. 
+• 
+Proved reserves: Those reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time. 
+5 
+The area of the reservoir considered as proved includes all of the following: 
+a. The area identified by drilling and limited by fluid contacts, if any, and 
+b. 
+Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. 
+Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when both of the following occur: 
+a. 
+Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based, and 
+b. The project has been approved for development by all necessary parties and entities, including governmental entities. 
+Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12‑month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. 
+• 
+Proved undeveloped reserves: Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. Under no circumstances shall estimates of proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty. 
+• 
+PUDs : proved undeveloped reserves. 
+• 
+PV-10 (Non-GAAP) : the present value of estimated future gross revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date indicated (unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure of discounted future net cash flows calculation, it does provide an indicative representation of the relative value of the Company on a comparative basis to other companies from period to period. This is a non-GAAP measure. See “Items 1 and 2 - Business and Properties - Proved Oil and Gas Reserves - Reconciliation of Standardized Measure of Discounted Future Net Cash Flows (GAAP) to PV-10 (Non-GAAP)”. 
+• 
+Realized price : the cash market price less all expected quality, transportation and demand adjustments. 
+• 
+Royalty interest : an interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development. 
+• 
+RSU : restricted stock units. 
+• 
+SEC : United States Securities and Exchange Commission. 
+• 
+Waha : a natural gas delivery point in West Texas that serves as the benchmark for natural gas. 
+• 
+Working interest : an operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations. 
+• 
+WTI : West Texas Intermediate grade crude oil, used as a pricing benchmark for sales contracts and NYMEX oil futures contracts. 
+With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross. 
+6 
+PART I. 
+ITEMS 1 and 2 – Business and Properties 
+Overview 
+Callon Petroleum Company has been engaged in the exploration, development, acquisition and production of oil and natural gas properties since 1950. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. We were incorporated in the state of Delaware in 1994. 
+We are an independent oil and natural gas company focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas. Our activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger Permian Basin in West Texas. In 2019, though our acquisition of Carrizo, we double our core acreage position in the Delaware Basin and entered the Eagle Ford Shale. Our primary operations in the Permian Basin reflect a high-return, oil-weighted drilling inventory with multiple prospective horizontal development intervals and are complemented by a well-established and repeatable free cash flow generating business in the Eagle Ford Shale. 
+Major Developments in 2019 
+Merger with Carrizo Oil & Gas, Inc. On December 20, 2019, we completed our acquisition of Carrizo, in an all-stock transaction. The addition of Carrizo’s assets increased our portfolio to: (i) over 116,000 net acres in the Permian Basin, which doubled our footprint in the Southern Delaware Basin and (ii) expanded our portfolio to include over 76,000 net acres in the mature, high-margin, free cash flow generating Eagle Ford Shale. 
+Ranger Divestiture. On June 12, 2019, we completed our divestiture of certain non-core assets in the southern Midland Basin (the “Ranger Divestiture”) for net cash proceeds of $244.9 million. The transaction also provided for potential additional contingent consideration to be paid to us of up to $60.0 million based on West Texas Intermediate average annual pricing over a three-year period. The divestiture encompassed the Ranger operating area in the southern Midland Basin which included approximately 9,850 net Wolfcamp acres with an average 66% working interest. 
+See “ Note 4 - Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for further discussion. 
+Financing and Liquidity Activity. In connection with the Carrizo Acquisition, we entered into a credit agreement with a syndicate of lenders (the “Credit Facility”), which has a maximum credit amount of $5.0 billion . As of December 31, 2019, the borrowing base under the Credit Facility was $2.5 billion , with an elected commitment amount of $2.0 billion. During 2019, we also redeemed the remaining outstanding 10% Series A Cumulative Preferred Stock (“Preferred Stock”) for a total redemption price of $73.0 million . 
+See “ Note 7 – Borrowings” and “ Note 11 – Stockholders’ Equity” of the Notes to our Consolidated Financial Statements for further discussion. 
+Operational Activity. Our drilling activity during 2019 was predominantly associated with the horizontal development of several prospective intervals in the Permian Basin, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales, as well as the Eagle Ford Shale, which we entered into in late 2019 as a result of the Carrizo Acquisition. As a result of our horizontal development efforts and contributions from acquisitions, our net daily production for the year ended December 31, 2019 as compared to the prior year grew approximately 26% to 41,331 Boe/d (approximately 77% oil). For the year ended December 31, 2019 , our estimated proved reserves were 540.0 MMBoe, an increase of 126% as compared to the year ended December 31, 2018 primarily as a result of the merger with Carrizo described above, and included proved oil reserves of 346.4 MMBbls ( 64% of total proved reserves). Approximately 43% of our 2019 year-end estimated proved reserves were classified as proved developed. 
+We intend to grow our reserves and production through the drilling and development of our multi-year inventory of identified drilling locations. We will also seek to grow our inventory of locations through delineation of emerging zones and selective “bolt-on” acquisition and leasing programs in areas complementary to our core operating areas. 
+Our Business Strategy 
+Our principal objective is to enhance shareholder value through capital efficient growth in proved reserves and associated production and cash flows while acting as a responsible corporate citizen in the areas in which we operate. Key elements of the execution of this strategy include: 
+• 
+Optimizing the development of our multi-zone resource base through thoughtful plans of development that are educated by extensive analysis of subsurface data and empirical well results; 
+• 
+Maintaining strong cash margins per unit of production through cost management and proactive investment in production infrastructure; 
+7 
+• 
+Improving the capital efficiency of our operations in terms of both well productivity and capital outlays, including supporting facilities; 
+• 
+Maturing our asset base into a sustainable operating model for profitable reinvestment of cash flows for attractive, long-term returns on capital; 
+• 
+Growing our inventory of well locations through delineation of emerging targets on our existing acreage positions and selective acquisitions of leasehold rights and mineral interests in areas complementary to our existing core operating areas; and 
+• 
+Preserving a strong financial position, focusing on appropriate capital allocation decisions under various commodity pricing scenarios, prudent risk management and generating free cash flow to reduce leverage. 
+Our Strengths 
+We believe the following attributes position Callon to achieve its objectives: 
+• 
+Strong Foundation - Reputation as a safe and responsible operator built over several decades in the oil and gas industry; 
+• 
+Quality Assets - High quality Permian Basin asset base with several years of proven well results from multiple target zones that benefit from early investments in critical supporting infrastructure including sustainable investments in water recycling and a more mature asset base in the Eagle Ford Shale which has lower operational risk and generates predictable, repeatable well results; 
+• 
+Operational Control - High degree of operational control that allows us to efficiently maximize value through long-term and daily decisions that drive our strategy; 
+• 
+Talented Workforce - Seasoned employee base that has continued to benefit from the hiring of quality employees across various disciplines, as well as the integration of employees from the Carrizo Acquisition, that have been integrated into our unifying culture. 
+8 
+Oil and Natural Gas Properties 
+Summary of 2019 Proved Reserves, Production and Drilling by Region 
+Permian Basin 
+Eagle Ford Shale 
+Total 
+Proved reserves (1) 
+Crude oil (MBbls) 
+237,413 
+108,948 
+346,361 
+Natural gas (MMcf) 
+656,594 
+100,540 
+757,134 
+NGLs (MBbls) 
+50,128 
+17,334 
+67,462 
+Total proved reserves (MBoe) 
+396,973 
+143,039 
+540,012 
+Proved reserves by classification (MBoe) 
+Proved developed 
+164,503 
+66,474 
+230,977 
+Proved undeveloped 
+232,470 
+76,565 
+309,035 
+Total proved reserves (MBoe) 
+396,973 
+143,039 
+540,012 
+Percent of proved developed reserves 
+71 
+% 
+29 
+% 
+100 
+% 
+Percent of proved undeveloped reserves 
+75 
+% 
+25 
+% 
+100 
+% 
+Percent of total reserves 
+74 
+% 
+26 
+% 
+100 
+% 
+Production volumes (1)(2) 
+Total 
+Per Day (2) 
+Total 
+Per Day (2) 
+Total 
+Per Day (2) 
+Crude oil (MBbls and Bbls/d) 
+11,365 
+31,136 
+300 
+821 
+11,665 
+31,957 
+Natural gas (MMcf and Mcf/d) 
+19,484 
+53,381 
+234 
+640 
+19,718 
+54,021 
+NGLs (MBbls and Bbls/d) 
+93 
+254 
+42 
+116 
+135 
+370 
+Total production volumes (MBoe and Boe/d) 
+14,705 
+40,287 
+381 
+1,044 
+15,086 
+41,331 
+Percent of total production 
+97 
+% 
+3 
+% 
+100 
+% 
+Permian Basin 
+Eagle Ford Shale 
+Total 
+Operated Well Data 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Year Ended December 31, 2019 
+Drilled (2) 
+61 
+53.7 
+2 
+2.0 
+63 
+55.7 
+Completed (2) 
+55 
+47.1 
+— 
+— 
+55 
+47.1 
+December 31, 2019 
+Drilled but uncompleted 
+28 
+25.0 
+36 
+32.7 
+64 
+57.7 
+Producing 
+810 
+702.6 
+599 
+539.7 
+1,409 
+1,242.3 
+(1) 
+The estimated proved reserves acquired in the Carrizo Acquisition and production associated with such reserves are presented on a three-stream basis and include NGLs, whereas, all other estimated proved reserve and production volumes are on a two-stream basis. 
+(2) 
+Includes activity from the Carrizo Acquisition subsequent to the December 20, 2019 closing date. 
+Regional Overview 
+Permian Basin 
+As of December 31, 2019 , we owned 173,922 gross ( 116,784 net) acres in the Permian Basin, all of which was located in the Midland and Delaware Basins. Average net production from our Permian Basin properties increased approximately 22% to 40,287 Boe/d in 2019 from 32,926 Boe/d in 2018 . In the fourth quarter of 2019, we closed on the Carrizo Acquisition which added approximately 45,000 net acres in the Delaware Basin to our portfolio. We currently expect to direct the majority of our 2020 Capital Budget, as defined below, towards opportunities in the Permian Basin. 
+Eagle Ford Shale 
+We acquired our Eagle Ford properties, primarily located in LaSalle County and, to a lesser extent, in McMullen, Frio and Atascosa counties in Texas, through the Carrizo Acquisition. As of December 31, 2019 , we held interests in approximately 90,560 gross ( 76,234 net) acres. 
+9 
+Proved Oil and Gas Reserves 
+The following table sets forth summary information with respect to our estimated proved reserves, standardized measure of discounted future net cash flows and PV-10 for the years ended December 31, 2019 , 2018, and 2017. The estimated proved reserves obtained as a result of the Carrizo Acquisition were prepared by Ryder Scott Company, L.P. (“Ryder Scott”), the independent third party reserve engineers historically retained by Carrizo. All other estimated proved reserves for each respective year were prepared by DeGolyer and MacNaughton (“D&M”), Callon’s independent third party reserve engineers (together with Ryder Scott, the “Reserve Engineering Firms”). For further information concerning D&M’s and Ryder Scott’s estimates of our proved reserves as of December 31, 2019 , see the reserve reports included as exhibits to this 2019 Annual Report on Form 10-K. The prices used in the calculation of our estimated proved reserves and PV-10 were based on the average realized prices for sales of oil, natural gas liquids (“NGLs”), and natural gas on the first calendar day of each month during the year (“12-Month Average Realized Price”) in accordance with SEC rules. 
+As of December 31, 
+2019 
+2018 
+2017 
+Proved developed reserves (1) 
+Crude oil (MBbls) 
+152,687 
+92,202 
+51,920 
+Natural gas (MMcf) 
+320,676 
+218,417 
+104,389 
+NGLs (MBbls) 
+24,844 
+— 
+— 
+Total proved developed reserves (MBoe) 
+230,977 
+128,605 
+69,318 
+Proved undeveloped reserves (1) 
+Crude oil (MBbls) 
+193,674 
+87,895 
+55,152 
+Natural gas (MMcf) 
+436,458 
+132,049 
+75,021 
+NGLs (MBbls) 
+42,618 
+— 
+— 
+Total proved undeveloped reserves (MBoe) 
+309,035 
+109,903 
+67,656 
+Total proved reserves (1) 
+Crude oil (MBbls) 
+346,361 
+180,097 
+107,072 
+Natural gas (MMcf) 
+757,134 
+350,466 
+179,410 
+NGLs (MBbls) 
+67,462 
+— 
+— 
+Total proved reserves (MBoe) 
+540,012 
+238,508 
+136,974 
+Proved developed reserves % 
+43 
+% 
+54 
+% 
+51 
+% 
+Proved undeveloped reserves % 
+57 
+% 
+46 
+% 
+49 
+% 
+Average realized prices 
+Crude oil ($/Bbl) 
+$53.90 
+$58.40 
+$49.48 
+Natural gas ($/Mcf) 
+$1.55 
+$3.64 
+$3.47 
+NGLs ($/Bbl) 
+$15.58 
+— 
+— 
+Standardized measure of discounted future net cash flows (GAAP) (in millions) 
+$4,951.0 
+$2,941.3 
+$1,556.7 
+PV-10 (Non-GAAP): 
+Proved developed PV-10 
+$3,246.8 
+$2,222.0 
+$1,030.3 
+Proved undeveloped PV-10 
+2,122.8 
+927.2 
+546.4 
+Total PV-10 (Non-GAAP) 
+$5,369.6 
+$3,149.2 
+$1,576.8 
+(1) 
+The estimated proved reserves acquired in the Carrizo Acquisition are presented on a three-stream basis and include NGLs, whereas, all other estimated proved reserve volumes are on a two-stream basis. 
+10 
+Reconciliation of Standardized Measure of Discounted Future Net Cash Flows (GAAP) to PV-10 (Non-GAAP) 
+We believe that the presentation of PV-10 provides greater comparability when evaluating oil and gas companies due to the many factors unique to each individual company that impact the amount and timing of future income taxes. In addition, we believe that PV-10 is widely used by investors and analysts as a basis for comparing the relative size and value of our proved reserves to other oil and gas companies. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company’s financial or operating performance presented in accordance with GAAP. The definition of PV-10 as defined in “Glossary of Certain Terms” may differ significantly from the definitions used by other companies to compute similar measures. As a result, PV-10 as defined may not be comparable to similar measures provided by other companies. A reconciliation of the standardized measure of discounted future net cash flows to PV-10 is presented below. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of our proved oil and gas reserves. 
+As of December 31, 
+2019 
+2018 
+2017 
+(In millions) 
+Standardized measure of discounted future net cash flows (GAAP) 
+$4,951.0 
+$2,941.3 
+$1,556.7 
+Add: present value of future income taxes discounted at 10% per annum 
+418.6 
+207.9 
+20.1 
+PV-10 (Non-GAAP) 
+$5,369.6 
+$3,149.2 
+$1,576.8 
+Proved Reserves 
+As of December 31, 2019, our estimated proved reserves totaled 540.0 MMBoe, an increase of 126% from the prior year end, and included 346.4 MMBbls of oil, 757.1 Bcf of natural gas and 67.5 MMBbls of NGLs with a standardized measure of discounted future net cash flows of $5.0 billion (1) . Oil constituted approximately 64% of our total estimated proved reserves and approximately 66% of our total estimated proved developed reserves. We added 59.4 MMBoe of new reserves in extensions and discoveries through our development efforts in our operating areas, of which 17.1 MMBoe were proved developed at a cost of $226.3 million, where we drilled a total of 63 gross (55.7 net) wells. We purchased reserves in place of 326.8 MMBoe associated with the Carrizo Acquisition. Sales of reserves in place of 32.5 MMBoe primarily included 18.6 MMBoe of proved developed reserves and 8.5 MMBoe of PUD reserves associated with the Ranger Divestiture. See “ Note 4 - Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for further discussion of the Carrizo Acquisition and the Ranger Divestiture. 
+Our net revisions of previous estimates were primarily related to revisions of proved undeveloped reserves. We reduced our estimated proved reserves through total net revisions of 37.2 MMBoe due to the following factors: 
+• 
+21.7 MMBoe from the observed impact of well spacing tests on producing wells and the related impact on PUD reserve estimates as we advance larger scale development concepts across our multi-zone inventory; 
+• 
+9.8 MMBoe from the reclassifications of PUDs within our optimized development plans that were moved outside of the five-year development window. The primary driver of these changes in our previous development plan was the Carrizo Acquisition which afforded the opportunity to reallocate capital across the combined portfolio in an effort to increase capital efficiency and resulting cash flow generation; and 
+• 
+5.7 MMBoe from the adverse effect of pricing and other economic factors 
+The following table provides a summary of the changes in our proved reserves for the year ended December 31, 2019. 
+Total 
+(MBoe) 
+Proved reserves as of December 31, 2018 
+238,508 
+Extensions and discoveries 
+59,424 
+Revisions to previous estimates 
+(37,216 
+) 
+Purchase of reserves in place (1) 
+326,838 
+Sales of reserves in place 
+(32,456 
+) 
+Production 
+(15,086 
+) 
+Proved reserves as of December 31, 2019 
+540,012 
+(1) 
+The estimated proved reserves acquired in the Carrizo Acquisition are presented on a three-stream basis and include NGLs, whereas, all other estimated proved reserve volumes are on a two-stream basis. 
+11 
+Proved Undeveloped Reserves 
+Annually, we review our PUDs to ensure appropriate plans exist for development of this reserve category. PUD reserves are recorded only if we have plans to convert these reserves into PDPs within five years of the date they are first recorded. Our development plans include the allocation of capital to projects included within our 2020 Capital Budget, as defined below, and, in subsequent years, the allocation of capital within our long-range business plan to convert PUDs to PDPs within this five year period. 
+The Company had extensions and discoveries of 42.4 MMBoe for our PUDs that were due to additional offset locations associated with our drilling program. During 2019, we acquired 201.5 MMBoe of PUD locations associated with the Carrizo Acquisition and had sales of reserves in place of 11.2 MMBoe of PUDs which was primarily a result of the Ranger Divestiture. 
+We had net revisions of 23.0 MMBoe to PUDs in 2019. These revisions reflect the impact of well spacing tests on certain PUD estimates and reclassifications of certain PUDs within our optimized development plans that were moved outside of the five-year development window as well as the adverse effect of pricing and other economic factors. The primary driver of the changes in our previous development plan was the Carrizo Acquisition which afforded the opportunity to reallocate capital across the combined portfolio in an effort to increase capital efficiency and resulting cash flow generation. 
+During 2019, we converted 11.0 MMBoe of PUDs that were booked as PUDs as of December 31, 2018 to proved developed at a total cost of $103.9 million, or $9.45 per Boe. We converted an additional 2.5 MMBoe of PUDs that were booked as PUDs during 2019 to proved developed at a total cost of $28.6 million, or $11.44 per Boe. Although our PUD conversion was below 20% for 2019, we currently estimate that we will convert approximately 50% of our PUDs as of December 31, 2019 in 2020 and 2021. 
+During 2019, we also incurred $15.9 million on PUDs that were drilled but uncompleted as of December 31, 2019. As of December 31, 2019, we had 32.2 MMBoe of PUDs associated with drilled but uncompleted wells, of which 29.3 MMBoe were associated with the Carrizo Acquisition. All of the reserves associated with drilled but uncompleted wells are scheduled to be completed in 2020. We expect to incur approximately $203.0 million of capital expenditures to complete these wells. 
+At December 31, 2019, we did not have any reserves that have remained undeveloped for five or more years since the date of their initial booking and all PUD locations are scheduled to be developed within five years of their initial booking. 
+Qualifications of Technical Persons 
+In accordance with the Standards Pertaining to Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers, D&M prepared approximately 40% of our estimates of proved reserves as of December 31, 2019 and 100% of our proved reserves as of December 31, 2018 and 2017. Ryder Scott prepared the estimates of proved reserves associated with the Carrizo Acquisition, which comprised approximately 60% of our proved reserves as of December 31, 2019. The technical persons responsible for preparing the reserves estimates meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Neither D&M nor Ryder Scott owns an interest in our properties and neither is employed on a contingent fee basis. 
+Our internal reserve engineer has over 20 years of experience in the petroleum industry and extensive experience in the estimation of reserves and the review of reserve reports prepared by third party engineering firms. Compliance as it relates to reporting the Company’s reserves is the responsibility of our Chief Operating Officer, who is also our principal engineer. He has over 30 years of operations and industry experience and holds B.S. and Ph.D. degrees in Petroleum Engineering, in addition to a M.S. in Environmental and Planning Engineering, and is experienced in asset evaluation and management. 
+Internal Controls Over Reserve Estimation Process 
+The primary inputs to the reserve estimation process are comprised of technical information, financial data, production data, and ownership interest. All field and reservoir technical information is assessed for validity when the internal reserve engineer holds technical meetings with our geoscientists, operations, and land personnel to discuss field performance and to validate future development plans. The other inputs used in the reserve estimation process, including, but not limited to, future capital expenditures, commodity price differentials, production costs, and ownership percentages are subject to internal controls over financial reporting and are assessed for effectiveness annually. 
+To further enhance the control environment over the reserve estimation process, our Strategic Planning and Reserves Committee, an independent committee of the Company’s board of directors (the “Board of Directors”), assists management and the Board of Directors with its oversight of the integrity of the determination of our oil and natural gas reserves and the work of the Reserve Engineering Firms. The Strategic Planning and Reserves Committee’s charter also specifies that it shall perform, in consultation with the Company’s management and senior reserves and reservoir engineering personnel, the following responsibilities: 
+• 
+Oversee the appointment, qualification, independence, compensation and retention of the Reserve Engineering Firms engaged by the Company (including resolution of material disagreements between management and the Reserve Engineering Firms regarding reserve determination) for the purpose of preparing or issuing an annual reserve report. The Strategic Planning and 
+12 
+Reserves Committee shall review any proposed changes in the appointment of the Reserve Engineering Firms, determine the reasons for such proposal, and whether there have been any disputes between the Reserve Engineering Firms and management. 
+• 
+Review the Company’s significant reserves engineering principles and any material changes thereto, and any proposed changes in reserves engineering standards and principles which have, or may have, a material impact on the Company’s reserves disclosure. 
+• 
+Review with management and the Reserve Engineering Firms the proved reserves of the Company, and, if appropriate, the probable reserves, possible reserves and the total reserves of the Company, including: (i) reviewing significant changes from prior period reports; (ii) reviewing key assumptions used or relied upon by the Reserve Engineering Firms; (iii) evaluating the quality of the reserve estimates prepared by both the Reserve Engineering Firms and the Company relative to the Company’s peers in the industry; and (iv) reviewing any material reserves adjustments and significant differences between the Company’s and Reserve Engineering Firms’ estimates. 
+• 
+If the Strategic Planning and Reserves Committee deems it necessary, it shall meet in executive session with the Reserve Engineering Firms to discuss the oil and gas reserve determination process and related public disclosures, and any other matters of concern in respect of the evaluation of the reserves. 
+During our last fiscal year, we filed no reports with other federal agencies which contain an estimate of proved reserves. 
+See “Item 8. Financial Statements and Supplementary Data - Supplemental Information on Oil and Natural Gas Operations” for additional information regarding our estimated proved reserves and the present value of estimated future net revenues from these proved reserves. 
+Capital Budget 
+Our Board approved operational capital expenditure budget for 2020 has been established at $975.0 million (the “2020 Capital Budget”), which includes running an average of eight to nine drilling rigs and an average of three completion crews. Approximately 10-15% of the 2020 Capital Budget is comprised of infrastructure and facilities capital. As part of our 2020 operated horizontal drilling program, we expect to drill approximately 165 gross operated wells and complete approximately 160 gross operated wells. 
+Our revenues, earnings, liquidity and ability to grow are substantially dependent on the prices we receive for, and our ability to develop, our reserves of oil and natural gas. We believe the long-term outlook for our business is favorable due to our resource base, low cost structure, financial strength, risk management, and disciplined investment of capital. We monitor current and expected market conditions, including the commodity price environment, and our liquidity needs and may adjust our capital investment plan accordingly. 
+Drilling Activity 
+The following table sets forth our operated and non-operated drilling activity for the years ended December 31, 2019 , 2018 and 2017 . In the table, “gross” refers to the total wells in which we have a working interest and “net” refers to gross wells multiplied by our working interest therein. As defined by the SEC, the number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. For definitions of exploratory wells, development wells, productive wells, and non-productive wells, see “—Glossary of Certain Terms”. 
+Years Ended December 31, 
+2019 (1) 
+2018 
+2017 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Exploratory Wells - Productive 
+56 
+36.7 
+55 
+44.7 
+33 
+26.5 
+Exploratory Wells - Non-productive 
+— 
+— 
+— 
+— 
+1 
+1.0 
+Development Wells - Productive 
+15 
+11.6 
+15 
+12.8 
+15 
+10.7 
+Development Wells - Non-productive 
+— 
+— 
+— 
+— 
+— 
+— 
+(1) 
+Includes activity from the Carrizo Acquisition subsequent to the December 20, 2019 closing date. 
+13 
+Productive Wells 
+The following table sets forth the number of productive crude oil and natural gas wells in which we owned an interest as of December 31, 2019 . 
+Crude Oil 
+Natural Gas 
+Total 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Permian Basin - Operated 
+727 
+631.0 
+90 
+78.1 
+817 
+709.1 
+Permian Basin - Non-operated 
+119 
+13.1 
+63 
+3.0 
+182 
+16.1 
+Total Permian Basin 
+846 
+644.1 
+153 
+81.1 
+999 
+725.2 
+Eagle Ford Shale - Operated 
+609 
+548.0 
+2 
+1.8 
+611 
+549.8 
+Eagle Ford Shale - Non-operated 
+15 
+1.3 
+23 
+3.5 
+38 
+4.8 
+Total Eagle Ford Shale 
+624 
+549.3 
+25 
+5.3 
+649 
+554.6 
+Total 
+1,470 
+1,193.4 
+178 
+86.4 
+1,648 
+1,279.8 
+14 
+Production Volumes, Average Sales Prices and Operating Costs 
+The following tables set forth certain information regarding the production volumes and average sales prices received for, and average production costs associated with, the Company’s sale of oil and natural gas for the periods indicated. 
+Years Ended December 31, 
+2019 (1) 
+2018 
+2017 
+Total production (2) 
+Oil (MBbls) 
+11,665 
+9,443 
+6,557 
+Natural gas (MMcf) 
+19,718 
+15,447 
+10,896 
+NGLs (MBbls) 
+135 
+— 
+— 
+Total barrels of oil equivalent (MBoe) 
+15,086 
+12,018 
+8,373 
+Daily production volumes by product (2) 
+Oil (Bbls/d) 
+31,957 
+25,871 
+17,964 
+Natural gas (Mcf/d) 
+54,021 
+42,321 
+29,852 
+NGLs (Bbls/d) 
+370 
+— 
+— 
+Total barrels of oil equivalent (Boe/d) 
+41,331 
+32,926 
+22,940 
+Daily production volumes by region (2) 
+Permian Basin 
+40,287 
+32,926 
+22,940 
+Eagle Ford Shale 
+1,044 
+— 
+— 
+Total barrels of oil equivalent (Boe/d) 
+41,331 
+32,926 
+22,940 
+Years Ended December 31, 
+2019 (1) 
+2018 
+2017 
+Revenues (in thousands) 
+Oil 
+$633,107 
+$530,898 
+$322,374 
+Natural gas 
+36,390 
+56,726 
+44,100 
+NGLs 
+2,075 
+— 
+— 
+Total revenues 
+$671,572 
+$587,624 
+$366,474 
+Operating costs (in thousands) 
+Lease operating expense 
+$91,827 
+$69,180 
+$49,907 
+Production taxes 
+42,651 
+35,755 
+22,396 
+Total operating costs 
+$134,478 
+$104,935 
+$72,303 
+Average realized sales price (excluding impact of settled derivatives) 
+Oil (per Bbl) 
+$54.27 
+$56.22 
+$49.16 
+Natural gas (per Mcf) 
+1.85 
+3.67 
+4.05 
+NGL (per Bbl) 
+15.37 
+— 
+— 
+Total (per Boe) 
+$44.52 
+$48.90 
+$43.77 
+Average realized sales price (including impact of settled derivatives) 
+Oil (per Bbl) 
+$53.31 
+$53.31 
+$47.78 
+Natural gas (per Mcf) 
+2.22 
+3.69 
+4.10 
+NGL (per Bbl) 
+15.37 
+— 
+— 
+Total (per Boe) 
+$44.27 
+$46.63 
+$42.76 
+Operating costs per Boe 
+Lease operating expense 
+$6.09 
+$5.76 
+$5.96 
+Production taxes 
+2.83 
+2.98 
+2.67 
+Total (per Boe) 
+$8.92 
+$8.74 
+$8.63 
+(1) 
+Includes activity from the Carrizo Acquisition subsequent to the December 20, 2019 closing date. 
+(2) 
+The production associated with reserves acquired in the Carrizo Acquisition is presented on a three-stream basis and include NGLs, whereas, all other production volumes are on a two-stream basis. 
+15 
+Major Customers 
+Our production is sold generally on month-to-month contracts at prevailing market prices. The following table presents customers that represented 10% or more of our total revenues for at least one of the periods presented: 
+Years Ended December 31, 
+2019 
+2018 
+2017 
+Rio Energy International, Inc. 
+26% 
+28% 
+17% 
+Enterprise Crude Oil, LLC 
+19% 
+14% 
+18% 
+Plains Marketing, L.P. 
+15% 
+21% 
+29% 
+Shell Trading Company 
+10% 
+* 
+* 
+* - Less than 10% for the respective year. 
+Because alternative purchasers of oil and natural gas are readily available, we believe that the loss of any of these purchasers would not result in a material adverse effect on our ability to sell future oil and natural gas production. In order to mitigate potential exposure to credit risk, we may require from time to time for our customers to provide financial security. 
+Leasehold Acreage 
+The following table shows our approximate developed and undeveloped leasehold acreage as of December 31, 2019 . Developed acreage refers to acreage on which wells have been completed to a point that would permit production of oil and gas in commercial quantities. Undeveloped acreage refers to acreage on which wells have not been drilled or completed to a point that would permit production of oil and gas in commercial quantities whether or not the acreage contains proved reserves. 
+໿ 
+Developed Acreage 
+Undeveloped Acreage 
+Total Acreage 
+Net Undeveloped Acreage Expiring 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+2020 
+2021 
+2022 
+Permian Basin (1) 
+137,786 
+97,352 
+36,136 
+19,432 
+173,922 
+116,784 
+13,765 
+1,903 
+981 
+Eagle Ford Shale (2) 
+75,864 
+64,146 
+14,696 
+12,088 
+90,560 
+76,234 
+1,357 
+— 
+300 
+Other (3) 
+2,123 
+174 
+79,615 
+57,070 
+81,738 
+57,244 
+— 
+1,234 
+48,504 
+Total 
+215,773 
+161,672 
+130,447 
+88,590 
+346,220 
+250,262 
+15,122 
+3,137 
+49,785 
+(1) 
+Approximately 16%, 81% and 39% of the acreage expiring in 2020, 2021 and 2022, respectively, will be developed prior to expiration or extended by lease extension payments. The acreage expiring in 2020 is primarily in our Alpine High area, which was acquired as part of the Carrizo Acquisition, where, along with the other remaining acreage, we have no current development plans. 
+(2) 
+Approximately 87% and 100% of the acreage expiring in 2020 and 2022, respectively, will be developed prior to expiration or extended by lease extension payments. We have no current development plans for the remaining expiring acreage as of December 31, 2019 . 
+(3) 
+Other includes non-core acreage principally located in Texas. We have no current development plans with this acreage as of December 31, 2019 . 
+Our lease agreements generally terminate if producing wells have not been drilled on the acreage within their primary term or an extension thereof (a period that can be from three to five years depending on the area). The percentage of net undeveloped acreage expiring in 2020, 2021 and 2022 assumes that no producing wells have been drilled on acreage within their primary term or have been extended. We manage our lease expirations to ensure that we do not experience unintended material expirations. Our leasehold management efforts include scheduling drilling in order to hold leases by production or timely exercising our contractual rights to extend the terms of leases by continuous operations or the payment of lease extension payments and delay rentals. We may choose to allow some leases to expire that are no longer part of our development plans. 
+The proved undeveloped reserves associated with acreage expiring over the next three years are not material to the Company. 
+Other 
+Industry Segment and Geographic Information 
+For segment reporting purposes, the Company considers all of the current development and operating areas to be one reportable segment: the development and production of oil and natural gas. All of the Company’s assets are located within the United States and all operations are located within Texas. All of the production revenues generated from operations are contracted and sold to customers located in the United States. 
+16 
+Title to Properties 
+The Company believes that the title to its oil and natural gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of such properties. The Company’s properties are potentially subject to one or more of the following: 
+• 
+royalties and other burdens and obligations, express or implied, under oil and natural gas leases; 
+• 
+overriding royalties and other burdens created by us or our predecessors in title; 
+• 
+a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements; farm-out agreements, production sales contracts and other agreements that may affect the properties or their titles; 
+• 
+back-ins and reversionary interests existing under purchase agreements and leasehold assignments; 
+• 
+liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual liens under operating agreements; 
+• 
+pooling, unitization and communitization agreements, declarations and orders; and 
+• 
+easements, restrictions, rights-of-way and other matters that commonly affect property. 
+To the extent that such burdens and obligations affect the Company’s rights to production revenues, these characteristics have been taken into account in calculating Callon’s net revenue interests and in estimating the size and value of its reserves. The Company believes that the burdens and obligations affecting our properties are typical within the industry for properties of the kind owned by Callon. 
+Seasonality of Business 
+Weather conditions and seasonality affect the demand for and prices of, oil and natural gas. Due to these fluctuations, results of operations for quarterly interim periods may not be indicative of the results realized on an annual basis. 
+Competition 
+The Company operates in the oil and natural gas industry, which is highly competitive. The Company’s business experiences strong competition from a number of parties that may range from small independent producers to major integrated companies. Competition affects the Company’s ability to acquire additional properties and resources necessary to develop assets. In higher commodity pricing environments, competition also exists in the form of contracting for drilling, pumping, and workover equipment, and securing skilled personnel to both develop and operate existing assets. Many of the competitors mentioned above may be able to pay for more sought-after properties or access equipment, infrastructure, or personnel. The industry also experiences, from time to time, shortages in resources such as the availability of drilling and workover rigs, other equipment, pipes and materials, infrastructures, and skilled personnel, all of which can delay development, exploration, and workover activities as well as result in significant cost increases. 
+Insurance 
+In accordance with industry practice, the Company maintains insurance against some, but not all, of the operating risks to which its business is exposed. While not all inclusive, the Company’s insurance policies generally protect against bodily injury and property damage, pollution and other environmental damages, employee benefits, employee injury and control of well insurance for its exploration and production operations. 
+The Company enters into master service agreements with its third-party contractors, including hydraulic fracturing contractors, in which they agree to indemnify the Company for injuries and deaths of the service provider’s employees, as well as contractors and subcontractors hired by the service provider. Similarly, the Company generally agrees to indemnify each third-party contractor against claims made by employees of the Company and the Company’s other contractors. Additionally, each party generally is responsible for damage to its own property. The Company re-evaluates the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and natural gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. While based on the Company’s risk analysis we believe that we are properly insured, no assurance can be given that the Company will be able to maintain insurance in the future at rates that it considers reasonable. In such circumstances, the Company may elect to self-insure or maintain only catastrophic coverage for certain risks in the future. 
+Corporate Offices 
+The Company’s headquarters are located in Houston, Texas, in a building with office space leased by the Company. We own office buildings in Natchez, Mississippi and Dilley and Pecos, Texas and lease and own offices in the Midland, Texas area. Because alternative locations to our leased spaces are readily available, the replacement of any of our leased offices would not result in material expenditures . 
+Employees 
+With the addition of employees from the Carrizo Acquisition that closed on December 20, 2019, Callon had 475 employees as of December 31, 2019 . None of the Company’s employees are currently represented by a union, and the Company believes that it has good relations with its employees. 
+17 
+Regulations 
+General. Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. Legislation and regulation affecting the entire oil and natural gas industry is continuously being reviewed for potential revision. Some of these requirements carry substantial penalties for failure to comply. 
+Exploration and Production . Our operations are subject to federal, state and local regulations that include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds and letters of credit) covering drilling and well operations. Other activities subject to regulation are: 
+• 
+the location and spacing of wells; 
+• 
+the method of drilling and completing and operating wells; 
+• 
+the rate and method of production; 
+• 
+the surface use and restoration of properties upon which wells are drilled and other exploration activities; 
+• 
+notice to surface owners and other third parties; 
+• 
+the venting or flaring of natural gas; 
+• 
+the plugging and abandoning of wells; 
+• 
+the discharge of contaminants into water and the emission of contaminants into air; 
+• 
+the disposal of fluids used or other wastes obtained in connection with operations; 
+• 
+the marketing, transportation and reporting of production; and 
+• 
+the valuation and payment of royalties. 
+Our sales of oil and natural gas are affected by the availability, terms and cost of pipeline transportation. The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation. If these regulations change, we could face higher transmission costs for our production and, possibly, reduced access to transmission capacity. 
+Various proposals and proceedings that might affect the petroleum industry are pending before Congress, federal administrative agencies such as the Federal Energy Regulatory Commission (“FERC”), various state and administrative agencies and legislatures, and the courts. Historically, the industry has been heavily regulated and we can offer you no assurance that the less stringent regulatory approach recently pursued by the FERC and state administrative agencies and Congress will continue nor can we predict what effect such proposals or proceedings may have on our operations. 
+We do not currently anticipate that compliance with existing laws and regulations governing exploration and production will have a significantly adverse effect upon our capital expenditures, earnings or competitive position. 
+Environmental Matters and Regulation. Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the U.S. Environmental Protection Agency (the “EPA”), issue regulations which often require difficult and costly compliance measures. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relating to our owned or operated facilities. Violations of environmental laws could result in administrative, civil or criminal fines and injunctive relief. The strict and joint and several liability nature of certain such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons, air emissions or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. In recent years, the oil and natural gas exploration and production industry has been the subject of increasing scrutiny and regulation by environmental authorities. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. Although such laws and regulations can increase the cost of planning, designing, installing and operating our facilities, it is anticipated that, absent the occurrence of an extraordinary event, compliance with them will not have a material effect upon our operations, capital expenditures, earnings or competitive position in the marketplace. 
+Waste Handling. The Resource Conservation and Recovery Act (“RCRA”), as amended, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent 
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+requirements. Although most wastes associated with the exploration, development and production of oil and natural gas are exempt from regulation as hazardous wastes under RCRA and its state analogs, it is possible that some wastes we generate presently or in the future may be subject to regulation under RCRA and state analogs. Additionally, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Additionally, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, the EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA was required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations was not necessary. On April 23, 2019, the EPA determined that a revision of the regulations was not necessary. If the EPA proposes a rulemaking for revised oil and gas waste regulations in the future, any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. 
+Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of wastes associated with oil and natural gas exploration and production could increase our costs to manage and dispose of such wastes. 
+Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), imposes joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes. 
+Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we have generated and will generate wastes that may fall within CERCLA’s definition of hazardous substance and may have disposed of these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum. We may also be the owner or operator of sites on which hazardous substances have been released. To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under CERCLA; we also do not know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties. In the event contamination is discovered at a site on which we are or have been an owner or operator or to which we sent hazardous substances, we could be liable for the costs of investigation and remediation and natural resources damages. 
+We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating, waste disposal, and water disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including offsite locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination or groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination. 
+Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, the Safe Drinking Water Act, the Oil Pollution Act (“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States (a term broadly defined to include, among other things, certain wetlands), as well as state waters for analogous state programs. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or applicable state analog. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit from the U.S. Army Corps of Engineers. The EPA issued a final rule on the federal jurisdictional reach over waters of the United States in 2015, which was repealed by the EPA on October 22, 2019. On January 23, 2020, the EPA and the U.S. Army Corps of Engineers issued a final rule re-defining the term “waters of the United States” as applied under the Clean Water Act and narrowing the scope of waters subject to 
+19 
+federal regulation. The rule is the subject of various legal challenges, creating uncertainty regarding federal jurisdiction over waters of the United States. 
+The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. 
+The Oil Pollution Act is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters. 
+Noncompliance with the Clean Water Act or the OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws. 
+Air Emissions. The federal Clean Air Act, as amended, and comparable state and local laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and modified and existing facilities may be required to obtain additional permits. As a result, we may need to incur capital costs in order to remain in compliance. Obtaining or renewing permits also has the potential to delay the development of oil and natural gas projects. Federal and state regulatory agencies can impose administrative, civil and criminal penalties and seek injunctive relief for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. 
+On June 3, 2016, the EPA expanded its regulatory coverage in the oil and natural gas industry with additional regulated equipment categories, and the addition of new rules limiting methane emissions from new or modified sites and equipment. Although the EPA attempted to suspend enforcement of the methane rule, this action was ruled improper by the U.S. Court of Appeals for the D.C. Circuit on July 2, 2017. Subsequently, in September 2018, the EPA issued a proposed rulemaking that could substantially change the obligations associated with methane emissions, limiting obligations for the oil and natural gas industry. Separately, in August 2019, the EPA issued proposed amendments that would that would rescind requirements related to the regulation of methane emissions from the oil and natural gas industry. Neither rulemaking has been finalized and, therefore, future obligations continue to remain uncertain under the Clean Air Act. 
+Climate Change. Numerous reports from scientific and governmental bodies such as the United Nations Intergovernmental Panel on Climate Change have expressed heightened concerns about the impacts of human activity, especially fossil fuel combustion, on the global climate. In turn, governments and civil society are increasingly focused on limiting the emissions of GHGs, including emissions of carbon dioxide from the use of oil and natural gas. 
+In December 2015, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change resulted in 195 countries, including the United States, coming together to develop the so-called “Paris Agreement,” which calls for the parties to undertake “ambitious efforts” to limit the average global temperature. The Agreement went into effect on November 4, 2016, and establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. The United States formally announced its intent to withdraw from the Paris Agreement on November 4, 2019, which withdrawal will become effective on November 4, 2020. Certain U.S. city and state governments have announced their intention to satisfy their proportionate obligations under the Paris Agreement. In addition, legislation has from time to time been introduced in Congress that would establish measures restricting GHG emissions in the United States, and a number of states have begun taking actions to control and/or reduce emissions of GHGs. 
+Any legislation or regulatory programs at the federal, state, or city levels designed to reduce GHG emissions could increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Moreover, incentives to conserve energy or use alternative energy sources, such as policies designed to increase utilization of zero-emissions or electric vehicles, as a means of addressing climate change could reduce demand for the oil and natural gas we produce. 
+In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions. Although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. 
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+The EPA has established GHG reporting requirements for certain sources in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissions. Although these requirements do not limit the amount of GHGs that can be emitted, they do require us to incur costs to monitor, keep records of, and report GHG emissions associated with our operations. 
+Parties concerned about the potential effects of climate change have also directed their attention at sources of financing for energy companies, which has resulted in certain financial institutions, funds and other capital providers restricting or eliminating their investment in oil and natural gas activities. In addition, some parties have initiated public nuisance claims under federal or state common law against certain companies involved in the production of oil and natural gas. Although our business is not a party to any such litigation, we could be named in actions making similar allegations, which could lead to costs and materially impact our financial condition in an adverse way. 
+Finally, most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce significant physical effects, such as increased frequency and severity of droughts, storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced or cause us to incur significant costs in preparing for or responding to the effects of climatic events themselves. Potential adverse effects could include disruption of our production activities, including, for example, damages to our facilities from winds or floods or increases in our costs of operation or reductions in the efficiency of our operations, as well as potentially increased costs for insurance coverages in the aftermath of such effects. 
+Regulation of Hydraulic Fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act (“SDWA”) regulates the underground injection of substances through the Underground Injection Control (“UIC”) program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions and not at the federal level, as the SDWA expressly excludes regulation of these fracturing activities (except where diesel is a component of the fracturing fluid, as further discussed below). Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing has been proposed in past legislative sessions but has not passed. 
+The EPA, however, issued guidance on permitting hydraulic fracturing that uses fluids containing diesel fuel under the UIC program, specifically as “Class II” UIC wells. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. This report could result in additional regulatory scrutiny that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and business. Further, on June 28, 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. 
+On June 3, 2016, the EPA adopted regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package included New Source Performance Standards (“NSPS”) for hydraulically fractured natural gas and oil wells to address emissions of sulfur dioxide, volatile organic compounds (“VOCs”) and methane, with a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule sought to achieve a 95% reduction in VOCs and methane emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured gas and newly constructed or refractured oil wells. The rules also established specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. Notably, on October 15, 2018, the EPA published a proposed rule that would make a series of revisions to the 2016 NSPS; these revisions have yet to be finalized. Separately, on August 28, 2019, the EPA published a proposed rule that would that would rescind requirements related to the regulation of methane emissions from the oil and gas industry; these revisions have yet to be finalized. 
+On March 20, 2015, the U.S. Bureau of Land Management (the “BLM”) finalized a rule regulating hydraulic fracturing activities on federal lands, including requirements for disclosure, wellbore integrity and handling of flowback water; however, on December 29, 2017, the BLM issued a rescission of the hydraulic fracturing rule. This rescission and the rule as promulgated are subject to ongoing litigation. Additionally, on November 18, 2016, the BLM finalized limitations on methane emissions from venting and flaring and leaking equipment from oil and natural gas activities on public lands, but on September 28, 2018 issued a final rule repealing certain provisions of the 2016 rule and reinstating the pre-2016 regulations; a lawsuit challenging the September 2018 rule revision is pending. 
+Several states, including Texas, and some municipalities, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, Texas law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) for disclosure on a website and also file the list of chemicals with the Texas Railroad 
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+Commission (the “RRC”) with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the RRC. 
+Additionally, some states, localities and local regulatory districts have adopted or have considered adopting regulations to limit, and in some cases impose a moratorium on, hydraulic fracturing or other restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; or restrictions on access to, and usage of, water. Further, there has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the U.S. implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations of harm. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of potential federal or state legislation governing hydraulic fracturing. In light of concerns about seismic activity being triggered by the injection of produced waters into underground wells, certain regulators are also considering additional requirements related to seismic safety for hydraulic fracturing activities. A 2015 U.S. Geological Survey report identified eight states with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. Any regulation that restricts our ability to dispose of produced waters or increases the cost of doing business could cause curtailed or decreased demand for our services and have a material adverse effect on our business. 
+Surface Damage Statutes (“SDAs”) . In addition, a number of states and some tribal nations have enacted SDAs. These laws are designed to compensate for damage caused by oil and gas development operations. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain binding requirements for payments by the operator to surface owners/users in connection with exploration and operating activities in addition to bonding requirements to compensate for damages to the surface as a result of such activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs. 
+National Environmental Policy Act . Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act (“NEPA”), which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Recent litigation by environmental non-governmental organizations has alleged that the Environmental Assessments for certain oil and natural gas projects violated NEPA by failing to account for climate change and the greenhouse gas emissions impacts of such projects. On January 10, 2020, the Council on Environmental Quality issued a proposed rule designed to streamline approvals for projects under NEPA. Among other revisions, the proposed rule would redefine environmental “effects” or “impacts” as the effects “that are reasonably foreseeable and have a reasonably close causal relationship to the proposed action or alternatives.” The proposed rule would also eliminate the current “direct,” “indirect,” or “cumulative” categories of effects. This rulemaking process is ongoing. To the extent that our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects. 
+Endangered Species Act. The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ or its habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A final rule amending how critical habitat and suitable habitat areas are designated under the ESA was finalized by the U.S. Fish and Wildlife Service in 2016. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. If the Company was to have a portion of its leases designated as critical or suitable habitat or a protected species were located on a lease, it may adversely impact the value of the affected leases. 
+Other Regulation of the Oil and Natural Gas Industry. The oil and natural gas industry is extensively regulated by numerous federal, state and local agencies and authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other similar companies in the industry with similar types, quantities and locations of production. 
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+The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas is subject to federal regulation, by the FERC which regulates the terms, conditions and rates for interstate transportation and storage service and various other matters. State regulations govern the rates, terms, and conditions of service associated with access to interstate oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transportation in some circumstances may also affect the intrastate transportation of oil and natural gas. 
+Although oil and natural gas sales prices are currently unregulated, the federal government historically has been active in the area of oil and natural gas sales regulation. We cannot predict whether new legislation to regulate oil and natural gas sales might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of natural gas, condensate, oil and natural gas liquids are not currently regulated and are made at market prices. 
+Exports of US Oil Production and Natural Gas Production . In December 2015, the federal government ended its decades-old prohibition of exports of oil produced in the lower 48 states of the US. As a result, exports of U.S. oil have increased significantly, reinforcing the general perception in the industry that the end of the U.S. export ban was positive for producers of U.S. oil. In addition, the U.S. Department of Energy authorizes exports of natural gas, including exports of natural gas by pipelines connecting U.S. natural gas production to pipelines in Mexico, and the export of liquefied natural gas (“LNG”) through LNG export facilities, the construction and operation of which are regulated by FERC. Since 2016, natural gas produced in the lower 48 states of the U.S. has been exported as LNG from export facilities in the U.S. Gulf Coast region. LNG export capacity has steadily increased in recent years, and is expected to continue increasing due to numerous export facilities that are currently being developed. The industry generally believes that this sustained growth in exports will be a positive development for producers of U.S. natural gas. 
+Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following: 
+• 
+the location of wells; 
+• 
+the method of drilling and casing wells; 
+• 
+the timing of construction or drilling activities, including seasonal wildlife closures; 
+• 
+the rates of production or “allowables”; 
+• 
+the surface use and restoration of properties upon which wells are drilled; 
+• 
+the plugging and abandoning of wells; and 
+• 
+notice to, and consultation with, surface owners and other third parties. 
+State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affecting the economics of production from these wells or to limit the number of locations we can drill. 
+Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Some state agencies and municipalities require bonds or other financial assurances to support those obligations. 
+Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production and have it transported. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”). Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for “first sales,” which include all of our sales of our own production. 
+Under the Energy Policy Act of 2005 (“EPAct”) Congress amended the NGA and NGPA to give FERC substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess civil penalties up to $1.0 million per day for each violation. This maximum penalty authority has been and will continue to be adjusted periodically to account for inflation. EPAct also amended the NGA to authorize FERC to “facilitate transparency in markets for the sale or transportation of physical natural gas in interstate commerce,” pursuant to which authorization FERC now requires natural gas wholesale market participants, including a number of entities that may not otherwise be subject to FERC’s traditional NGA jurisdiction, to report information 
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+annually to FERC concerning their natural gas sales and purchases. FERC requires any wholesale market participant that sells 2.2 million MMBtus or more annually in “reportable” natural gas sales to provide a report, known as FERC Form 552, to FERC. Reportable natural gas sales include sales of natural gas that utilize a daily or monthly gas price index, contribute to index price formation, or could contribute to index price formation, such as fixed price transactions for next-day or next-month delivery. 
+FERC also regulates interstate natural gas transportation rates, terms and conditions of service, and the terms under which we as a shipper may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and for the release of our excess, if any, natural gas pipeline capacity. In 1985, FERC began promulgating a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate natural gas pipeline companies are required to provide non-unduly discriminatory transportation services to all shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases, sales, and transportation that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities. 
+Under FERC’s current regulatory regime, interstate transportation services must be provided on an open-access, non-unduly discriminatory basis at cost-based rates or negotiated rates, both of which are subject to FERC approval. The FERC also allows jurisdictional gas pipeline companies to charge market-based rates if the transportation market at issue is sufficiently competitive. The FERC-regulated tariffs, under which interstate pipelines provide such open-access transportation service, contain strict limits on the means by which a shipper releases its pipeline capacity to another potential shipper, which provisions require compliance with FERC’s “shipper-must-have-title” rule. Violations by a shipper (i.e., a pipeline customer) of FERC’s capacity release rules or shipper-must-have-title rule could subject a shipper to substantial penalties from FERC. 
+With respect to its regulation of natural gas pipelines under the NGA, FERC has not generally required the applicant for construction of a new interstate natural gas pipeline to provide information concerning the GHG emissions resulting from the activities of the proposed pipeline’s customers. In August 2017, the U.S. Circuit Court of Appeals for the DC Circuit issued a decision remanding a natural gas pipeline certificate application to FERC, and required FERC to revise its environmental impact statement for the proposed pipeline to analyze potential GHG emission from the specific downstream power plants that the pipeline was designed to serve. To date, FERC has declined to analyze potential upstream GHG emissions that could result from the activities of natural gas producers and marketers, like the Company, to be served by proposed interstate natural gas pipeline projects. However, the scope of FERC’s obligation to analyze the environmental impacts of proposed interstate natural gas pipeline projects, including the upstream indirect impacts of related natural gas production activity, remains subject to ongoing litigation and contested administrative proceedings at the FERC and in the courts. 
+Gathering service, which occurs on pipeline facilities located upstream of FERC-jurisdictional interstate transportation services, is regulated by the states onshore and in state waters. Under NGA section 1(b), gathering facilities are exempt from FERC’s jurisdiction. FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, and FERC applies this test on a case-by-case basis. Depending on changes in the function performed by particular pipeline facilities, FERC has in the past reclassified certain FERC-jurisdictional transportation facilities as non-jurisdictional gathering facilities and FERC has reclassified certain non-jurisdictional gathering facilities as FERC-jurisdictional transportation facilities. Any such changes could result in an increase to our costs of transporting gas to point-of-sale locations. 
+The pipelines used to gather and transport natural gas being produced by the Company are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In addition, PHMSA had initially considered regulations regarding, among other things, the designation of additional high consequence areas along pipelines, minimum requirements for leak detection systems, installation of emergency flow restricting devices, and revision of valve spacing requirements. In October 2019, PHMSA finalized new safety regulations for hazardous liquid pipelines, including a requirement that operators inspect affected pipelines following extreme weather events or natural disasters, that all hazardous liquid pipelines have a system for detecting leaks and that pipelines in high consequence areas be capable of accommodating in-line inspection tools within twenty years. In addition, PHMSA is in the process of finalizing a rulemaking with respect to gathering lines, but the contents and timing of any final rule for gathering lines are uncertain. 
+Oil and NGLs Sales and Transportation. Sales of oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. 
+The Company’s sales of oil and natural gas liquids are also affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by FERC under the Interstate Commerce Act (“ICA”). FERC has implemented a simplified and generally applicable ratemaking methodology for interstate 
+24 
+oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil and natural gas liquid transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors. 
+Further, interstate common carrier oil pipelines must provide service on a non-duly discriminatory basis under the ICA, which is administered by FERC. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors. 
+In addition, FERC issued a declaratory order in November 2017, involving a marketing affiliate of an oil pipeline, which held that certain arrangements between an oil pipeline and its marketing affiliate would violate the ICA’s anti-discrimination provisions. FERC held that providing transportation service to affiliates at what is essentially the variable cost of the movement, while requiring non-affiliated shippers to pay the filed tariff rate, would violate the ICA. Rehearing has been sought of this FERC order by various parties. Due to the pending rehearing of the order and its recency, the Company cannot currently determine the impact this FERC order may have on oil pipelines, their marketing affiliates, and the price of oil and other liquids transported by such pipelines. 
+Any transportation of the Company’s oil, natural gas liquids and purity components (ethane, propane, butane, iso-butane, and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts 171-180, including Emergency Orders by the FRA regulations initially established on May 8, 2015 by PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids; PHMSA regulations were subsequently amended to remove certain requirements on September 25, 2018. 
+State Regulation. Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill. 
+The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us. 
+Financial Regulations, Including Regulations Enacted Under the Dodd-Frank Act . The U.S. Commodities and Futures Exchange Commission (“CFTC”) holds authority to monitor certain segments of the physical and futures energy commodities market including oil and natural gas. With regard to physical purchases and sales of natural gas and other energy commodities, and any related hedging activities that the Company undertakes, the Company is thus required to observe anti-market manipulation and disruptive trading practices laws and related regulations enforced by the FERC and/or the CFTC. The CFTC also holds substantial enforcement authority, including the ability to assess civil penalties. 
+Congress adopted comprehensive financial reform legislation in 2010, establishing federal oversight and regulation of the over-the-counter derivative market and entities that participate in that market. The legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), required the CFTC and the U.S. Securities and Exchange Commission (“SEC”) to promulgate rules and regulations implementing the legislation, including regulations that affecting derivatives contracts that the Company uses to hedge its exposure to price volatility. 
+While the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas remain pending, including a proposal to set position limits for certain futures and options contracts in various commodities and for swaps that are their economic equivalents. The CFTC also has proposed, but not yet finalized, a rule regarding the capital posting requirements for swap dealers and major swap market participants. The Company cannot, at this time, predict the timing or contents of any final rules the CFTC may enact with regard to either rulemaking proceeding. Any final rule in either proceeding could impact the Company’s ability to enter into financial derivative transactions to hedge or mitigate exposure to commodity price volatility and other commercial risks affecting our business. 
+Worker Health and Safety . We are subject to a number of federal and state laws and regulations, including OSHA, and comparable state statutes, the purpose of which are to protect the health and safety of workers. In 2016, there were substantial revisions to the regulations under OSHA that may have impact to our operations. These changes include among other items; record keeping and reporting, revised crystalline silica standard (which requires the oil and gas industry to implement engineering controls and work practices to limit exposures 
+25 
+below the new limits by June 23, 2021), naming oil and gas as a high hazard industry and requirements for a safety and health management system. In addition, OSHA’s hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations, and that this information be provided to employees, state and local government authorities and citizens. 
+Commitments and Contingencies 
+The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment will not have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies included, and claims for damages to property, employees, other persons, and the environment resulting from the Company’s operations could have on its activities. See “ Note 17 - Commitments and Contingencies” of the Notes to our Consolidated Financial Statements for additional information. 
+Available Information 
+We make available free of charge on our website (www.callon.com) our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the SEC. 
+We also make available within the “About Callon” section of our website our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and Audit, Compensation, Strategic Planning and Reserves, and Nominating and Corporate Governance Committee Charters, which have been approved by our Board of Directors. We will make timely disclosure on our website of any change to, or waiver from, the Code of Business Conduct and Ethics for our principal executive and senior financial officers. A copy of our Code of Business Conduct and Ethics is also available, free of charge by writing us at: General Counsel, Callon Petroleum Company, 2000 W. Sam Houston Parkway South, Suite 2000, Houston, TX 77042. 
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+ITEM 1A. Risk Factors 
+Risks Related to the Oil & Natural Gas Industry 
+Oil and natural gas prices are volatile, and substantial or extended declines in prices may adversely affect our results of operations and financial condition . Our success is highly dependent on prices for oil and natural gas, which have in recent years been, and we expect will continue to be, extremely volatile. During the five years ended December 31, 2019, NYMEX WTI prices ranged from a high of $77.41 per barrel on June 27, 2018 to a low of $26.19 per barrel on February 11, 2016, and NYMEX Henry Hub prices ranged from a high of $6.24 per MMBtu on January 2, 2018 to a low of $1.49 per MMBtu on March 4, 2016. The prices of oil and natural gas depend on factors we cannot control, such as macro-economic conditions, levels of production, domestic and worldwide inventories, demand for oil and natural gas, the capacity of U.S. and international refiners to use U.S. supplies of oil, natural gas and NGLs, relative price and availability of alternative forms of energy, actions by non-governmental organizations, OPEC and other countries, legislative and regulatory actions, technology developments impacting energy consumption and energy supply, and weather. These factors make it extremely difficult to predict future oil, natural gas and NGLs price movements with any certainty. We make price assumptions that are used for planning purposes, and a significant portion of our cash outlays, including rent, salaries and noncancelable capital commitments, are largely fixed in nature. Accordingly, if commodity prices are below the expectations on which these commitments were based, our financial results are likely to be adversely and disproportionately affected because these cash outlays are not variable in the short term and cannot be quickly reduced to respond to unanticipated decreases in commodity prices. 
+In general, prices of oil, natural gas, and NGLs affect the following aspects of our business: 
+• 
+our revenues, cash flows, earnings and returns; 
+• 
+our ability to attract capital to finance our operations and the cost of the capital; 
+• 
+the amount we are allowed to borrow under our Credit Facility; 
+• 
+the profit or loss we incur in exploring for and developing our reserves; and 
+• 
+the value of our oil and natural gas properties. 
+A substantial or extended decline in commodity prices may also reduce the amount of oil and natural gas that we can produce economically and cause a significant portion of our development projects to become uneconomic. This may result in our having to make significant downward adjustments to our estimated proved reserves. A reduction in production could also result in a shortfall in expected cash flows and require us to reduce capital spending, which could negatively affect our ability to replace our production and our future rate of growth, or require us to borrow funds to cover any such shortfall, which we may be unable to obtain at such time on satisfactory terms. As a result, a substantial or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. 
+If oil and natural gas prices remain depressed for extended periods of time, we may be required to make significant downward adjustments to the carrying value of our oil and natural gas properties. Under the full cost method, which we use to account for our oil and natural gas properties, the net capitalized costs of our oil and natural gas properties may not exceed the PV-10 of our estimated proved reserves, using the 12-Month Average Realized Price, plus the lower of cost or fair market value of our unproved properties. If such net capitalized costs exceed this limit, we must charge the amount of the excess to earnings. This type of charge will not affect our cash flows, but will reduce the book value of our stockholders’ equity. We review the carrying value of our properties quarterly and once incurred, a write-down of oil and natural gas properties is not reversible at a later date, even if prices increase. See “ Note 2 - Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements as well as the Supplemental Information on Oil and Natural Gas Operations for additional information. 
+Competitive industry conditions may negatively affect our ability to conduct operations. We compete with numerous other companies in virtually all facets of our business. Our competitors in development, exploration, acquisitions and production include major integrated oil and gas companies and smaller independents as well as numerous financial buyers. Some of our competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources permit. We also compete for the materials, equipment, personnel and services that are necessary for the exploration, development and operation of our properties. Our ability to increase reserves in the future will be dependent on our ability to select and acquire suitable prospects for future exploration and development. 
+The unavailability or high cost of drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could materially and adversely affect our operations and profitability. From time to time, our industry experiences a shortage of drilling rigs, equipment, supplies, water or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, during periods in which the levels of exploration and production increase, the demand for, and wages and costs of, drilling rig crews and other experienced personnel, oilfield services and equipment typically also increase, while the quality of these services and equipment may suffer. 
+All of our producing properties are located in the Permian Basin of West Texas and the Eagle Ford Shale of South Texas, making us vulnerable to risks associated with operating in only two geographic regions. As a result of this concentration, as compared to 
+27 
+companies that have a more diversified portfolio of properties, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services, or market limitations or interruption of the processing or transportation of oil, natural gas or NGLs. Such delays, interruptions or limitations could have a material adverse effect on our financial condition and results of operations. In addition, the effect of fluctuations on supply and demand may be more pronounced within specific geographic oil and natural gas producing areas, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. 
+We may be unable to integrate successfully the operations of recent acquisitions with our operations, and we may not realize all the anticipated benefits of these acquisitions. We have completed, and may in the future complete, acquisitions that include undeveloped acreage. We can offer no assurance that we will achieve the desired profitability from our acquisitions, including the Carrizo Acquisition, or from any acquisitions we may complete in the future. In addition, failure to integrate recent and future acquisitions successfully could adversely affect our financial condition and results of operations. 
+Our acquisitions, including the recently completed Carrizo Acquisition, may involve numerous risks, including those relating to: 
+• 
+operating a larger, more complex combined organization and adding operations; 
+• 
+assimilating the assets and operations of the acquired business, especially if the assets acquired are in a new geographic area; 
+• 
+acquired oil and natural gas reserves not being of the anticipated magnitude or as developed as anticipated; 
+• 
+the loss of significant key employees, including from the acquired business; 
+• 
+the inability to obtain satisfactory title to the assets we acquire; 
+• 
+a decrease in our liquidity if we use a portion of our available cash to finance acquisitions; 
+• 
+a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions; 
+• 
+the diversion of management’s attention from other business concerns, which could result in, among other things, performance shortfalls; 
+• 
+the failure to realize expected profitability or growth; 
+• 
+the failure to realize expected synergies and cost savings; 
+• 
+coordinating geographically disparate organizations, systems and facilities; 
+• 
+coordinating or consolidating corporate and administrative functions; 
+• 
+inconsistencies in standards, controls, procedures and policies; and 
+• 
+integrating relationships with customers, vendors and business partners. 
+Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. With respect to the Carrizo Acquisition in particular, we have incurred a number of costs associated with completing the Carrizo acquisition and expect to continue to incur significant costs to integrate the business of Carrizo. The elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of our two companies, may not initially offset integration-related costs or achieve a net benefit in the near term or at all. 
+If we consummate any future acquisition, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions. The inability to effectively manage the integration of acquisitions could reduce our focus on current operations, which in turn, could negatively impact our future results of operations. 
+We may fail to fully identify problems with any properties we acquire, and as such, assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities. We are actively seeking to acquire additional acreage in Texas or other regions in the future. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, adequacy of title, operating and capital costs, and potential environmental and other liabilities. Although we conduct a review that we believe is consistent with industry practices, we can give no assurance that we have identified or will identify all existing or potential problems associated with such properties or that we will be able to mitigate any problems we do identify. Such assessments are inexact and their accuracy is inherently uncertain. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface, title and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms. 
+Restrictions on our ability to obtain, recycle and dispose of water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner. Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to secure water from local land owners and other third party sources for use in our operations. If drought conditions were to occur or demand for water were to outpace supply, our ability to obtain water could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. Along with the risks of other extreme 
+28 
+weather events, drought risk, in particular, is likely increased by climate change. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows. In addition, significant amounts of water are produced in our operations. Inadequate access to or availability of water recycling or water disposal facilities could adversely affect our production volumes or significantly increase the cost of our operations. 
+Factors beyond our control, including the availability and capacity of gas processing facilities and pipelines and other transportation operations owned and operated by third parties, affect the marketability of our production. The ability to market oil and natural gas from our wells depends upon numerous factors beyond our control. A significant factor in our ability to market our production is the availability and capacity of gas processing facilities and pipeline and other transportation operations, including trucking services, owned and operated by third parties. These facilities and services may be temporarily unavailable to us due to market conditions, physical or mechanical disruption, weather, lack of contracted capacity, pipeline safety issues, or other reasons. In addition, in certain newer development areas, processing and transportation facilities and services may not be sufficient to accommodate potential production and it may be necessary for new interstate and intrastate pipelines and gathering systems to be built. Our failure to obtain access to processing and transportation facilities and services on acceptable terms could materially harm our business. We may be required to shut in wells for lack of a market or because of inadequate or unavailable processing or transportation capacity. If that were to occur, we would be unable to realize revenue from those wells until transportation arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells, we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. If we were required to shut in our production for long periods of time due to lack of transportation capacity, it would have a material adverse effect on our business, financial condition, results of operations and cash flows. 
+Other factors that affect our ability to market our production include: 
+• 
+the extent of domestic production and imports/exports of oil and natural gas; 
+• 
+federal regulations authorizing exports of liquefied natural gas (“LNG”), the development of new LNG export facilities under construction in the U.S. Gulf Coast region, and the first LNG exports from such facilities; 
+• 
+the construction of new pipelines capable of exporting U.S. natural gas to Mexico and transporting Eagle Ford Shale and Permian Basin oil production to the Gulf Coast; 
+• 
+the proximity of hydrocarbon production to pipelines; 
+• 
+the demand for oil and natural gas by utilities and other end users; 
+• 
+the availability of alternative fuel sources; 
+• 
+the effects of inclement weather; and 
+• 
+state and federal regulation of oil, natural gas and NGL marketing and transportation. 
+We have entered into firm transportation contracts that require us to pay fixed sums of money regardless of quantities actually shipped. If we are unable to deliver the minimum quantities of production, such requirements could adversely affect our results of operations, financial position, and liquidity. We have entered into firm transportation agreements for a portion of our production in certain areas in order to improve our ability, and that of our purchasers, to successfully market our production. We may also enter into firm transportation arrangements for additional production in the future. These firm transportation agreements may be more costly than interruptible or short-term transportation agreements. Additionally, these agreements obligate us to pay fees on minimum volumes regardless of actual throughput. If we have insufficient production to meet the minimum volumes, the requirements to pay for quantities not delivered could have an impact on our results of operations, financial position, and liquidity. 
+Our estimated reserves are based on interpretations and assumptions that may be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. This Annual Report contains estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves. The process of estimating oil and natural gas reserves is complex and requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. These assumptions include those required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. 
+Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from the estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this 2019 Annual Report on Form 10-K. Additionally, estimates of reserves and future cash flows may be subject to material downward or upward revisions, based on production history, development drilling and exploration activities and prices of oil and natural gas. 
+You should not assume that any PV-10 of our estimated proved reserves contained in this 2019 Annual Report on Form 10-K represents the market value of our oil and natural gas reserves. We base the PV-10 from our estimated proved reserves at December 31, 2019 on the 12-Month Average Realized Price and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures, the rate and timing of production, and changes in governmental regulations or taxes. Recovery of PUDs generally requires significant 
+29 
+capital expenditures and successful drilling operations. Our reserve estimates include the assumption that we will make significant capital expenditures to develop these PUDs and the actual costs, development schedule, and results associated with these properties may not be as estimated. In addition, the discount factor used to calculate PV-10 may not be appropriate based on our cost of capital from time to time and the risks associated with our business and the oil and gas industry. 
+Unless we replace our oil and gas reserves, our reserves and production will decline. Our future oil and gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our production, revenues, reserve quantities and cash flows will decline. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. We may not be successful in finding, developing or acquiring additional reserves, and our efforts may not be economic. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be limited to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. 
+Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could prevent them from being drilled or delay their drilling. Our management team has identified drilling locations as an estimation of our future development activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these identified drilling locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, availability and cost of drilling, completion and production services and equipment, lease expirations, regulatory approvals, and other factors discussed in these risk factors. Because of these uncertain factors, we do not know if the identified drilling locations will ever be drilled or if we will be able to produce oil or natural gas from these drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the identified locations are located, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified. 
+Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns. Exploration, development, drilling and production activities are subject to many risks. We may invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that any leasehold acreage acquired will be profitably developed, that new wells drilled will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, including wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, we may not be successful in controlling our drilling and production costs to improve our overall return and wells that are profitable may not achieve our targeted rate of return. Wells may have production decline rates that are greater than anticipated. Future drilling and completion efforts may impact production from existing wells, and parent-child effects may impact future well productivity as a result of timing, spacing proximity or other factors. Failure to conduct our oil and gas operations in a profitable manner may result in write-downs of our proved reserves quantities, impairment of our oil and gas properties, and a write-down in the carrying value of our unproved properties, and over time may adversely affect our growth, revenues and cash flows. 
+The development of our PUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. Developing PUDs requires significant capital expenditures, successful drilling operations, and a substantial amount of our proved reserves are PUDs which may not be ultimately developed or produced. Approximately 57% of our total estimated proved reserves as of December 31, 2019 , were PUDs. The reserve data included in the reserve reports of our independent petroleum engineers assume significant capital expenditures will be made to develop such reserves. We cannot be certain that the estimated capital expenditures to develop these reserves are accurate, that development will occur as scheduled, or that the results of such development will be as estimated. We may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including: unexpected drilling conditions; pressure or irregularities in formations; lack of proximity to and shortage of capacity of transportation facilities; equipment failures or accidents and shortages or delays in the availability of drilling rigs, equipment, personnel and services; and compliance with governmental requirements. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the future net revenues of our estimated PUDs and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves. 
+The results of our planned development programs in new or emerging shale development areas and formations may be subject to more uncertainties than programs in more established areas and formations, and may not meet our expectations for reserves or production. The results of our horizontal drilling efforts in emerging areas and formations of the Permian Basin are generally more uncertain than drilling results in areas that are more developed and have more established production from horizontal formations. Because emerging areas and associated target formations have limited or no production history, we are less able to rely on past drilling results in those areas as a basis to predict our future drilling results. In addition, horizontal wells drilled in shale formations, as distinguished from vertical wells, utilize multilateral wells and stacked laterals, all of which are subject to well spacing, density and proration requirements of the Texas Railroad Commission (the “RRC”), which requirements could adversely impact our ability to maximize the efficiency of our horizontal wells related to reservoir drainage over time. Further, access to adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more challenging in new or emerging areas. If our drilling results in these areas are less than anticipated or we are unable to execute our drilling program in these areas because of capital constraints, access to 
+30 
+gathering systems and takeaway capacity or otherwise, or natural gas and oil prices decline, our investment in these areas may not be as economic as we anticipate, we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future. 
+Our operations are subject to operating hazards that may adversely impact our ability to conduct business, and we may not be fully insured against all such operating risks. The operating hazards in exploring for and producing oil and natural gas include: encountering unexpected subsurface conditions that cause damage to equipment or personal injury, including loss of life; equipment failures that curtail or stop production or cause severe damage to or destruction of property, natural resources or other equipment; blowouts or other damages to the productive formations of our reserves that require a well to be re-drilled or other corrective action to be taken; and storms and other extreme weather conditions that cause damages to our production facilities or wells. Because of these or other events, we could experience environmental hazards, including release of oil and natural gas from spills, natural gas leaks, accidental leakage of toxic or hazardous materials, such as petroleum liquids, drilling fluids or fracturing fluids, including chemical additives, underground migration, and ruptures. If we experience any of these problems, we could incur substantial losses in excess of our insurance coverage. 
+The occurrence of a significant event or claim, not fully insured or indemnified against, could have a material adverse effect on our financial condition and operations. In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. Also, no assurance can be given that we will be able to maintain insurance in the future at rates we consider reasonable to cover our possible losses from operating hazards and we may elect no or minimal insurance coverage. 
+Multi-well pad drilling may result in volatility in our operating results. We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production. In addition, problems affecting a single well could adversely affect production from all of the wells on the pad, which would further cause delays in the scheduled commencement of production or interruptions in ongoing production. These delays or interruptions may cause volatility in our operating results. Further, any delay, reduction or curtailment of our development and producing operations due to operational delays caused by multi-well pad drilling could result in the loss of acreage through lease expirations. 
+The loss of key personnel could adversely affect our ability to operate. We depend, and will continue to depend in the foreseeable future, on the services of our senior officers and other key employees, as well as other third-party consultants with extensive experience and expertise in evaluating and analyzing drilling prospects and producing oil and natural gas and maximizing production from oil and natural gas properties. Our ability to retain our senior officers, other key employees, and third party consultants, many of whom are not subject to employment agreements, is important to our future success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business. 
+We may not be able to keep pace with technological developments in our industry. The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected. 
+Our business could be negatively affected by security threats. A cyberattack or similar incident could occur and result in information theft, data corruption, operational disruption, damage to our reputation or financial loss. The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, manage operations, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Our technologies, systems, networks, seismic data, reserves information or other proprietary information, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or could otherwise lead to the disruption of our business operations or other operational disruptions in our exploration or production operations. Cyberattacks are becoming more sophisticated and certain cyber incidents, such as surveillance, may remain undetected for an extended period and could lead to disruptions in critical systems or the unauthorized release of confidential or otherwise protected information. These events could lead to financial losses from remedial actions, loss of business, disruption of operations, damage to our reputation or potential liability. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyberattack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. Cyber incidents have increased, and the U.S. government has issued warnings indicating that energy assets may be specific targets of cybersecurity threats. Our systems and insurance coverage for protecting against cybersecurity risks may not be sufficient. Further, as cyberattacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyberattacks. 
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+We face various risks associated with increased activism against oil and natural gas exploration and development activities. Opposition toward oil and natural gas drilling and development activity has been growing globally and is particularly pronounced in the United States. Companies in the oil and natural gas industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, human rights, environmental matters, sustainability, and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain operations such as drilling and development. 
+Risks Related to Financial Position 
+Our business requires significant capital expenditures and we may not be able to obtain needed capital or financing on satisfactory terms or at all . We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Historically, we have funded our capital expenditures through a combination of cash flows from operations, borrowings from financial institutions, the sale of public debt and equity securities and asset dispositions. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, participation of non-operating working interest owners, the cost and availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. 
+If the borrowing base under our Credit Facility or our revenues decrease, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. The failure to obtain additional financing on terms acceptable to us, or at all, could result in a curtailment of our development activities and could adversely affect our business, financial condition and results of operations. 
+Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects. As of December 31, 2019, we had aggregate outstanding indebtedness of approximately $3.2 billion . As a result of the Carrizo Acquisition, our level of indebtedness has significantly increased. Our amount of indebtedness could affect our operations in many ways, including: 
+• 
+requiring us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities; 
+• 
+limiting management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; 
+• 
+increasing our vulnerability to downturns and adverse developments in our business and the economy; 
+• 
+limiting our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness; 
+• 
+making it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; 
+• 
+making us vulnerable to increases in interest rates as our indebtedness under our Credit Facility may vary with prevailing interest rates; 
+• 
+placing us at a competitive disadvantage relative to competitors with lower levels of indebtedness or less restrictive terms governing their indebtedness; and 
+• 
+making it more difficult for us to satisfy our obligations under our senior notes or other debt and increasing the risk that we may default on our debt obligations. 
+Restrictive covenants in the agreements governing our indebtedness may limit our ability to respond to changes in market conditions or pursue business opportunities. Our Credit Facility and the indentures governing our senior notes contain restrictive covenants that limit our ability to, among other things: incur additional indebtedness; make investments; merge or consolidate with another entity; pay dividends or make certain other payments; hedge future production or interest rates; create liens that secure indebtedness; sell assets; or engage in certain other transactions without the prior consent of the lenders. As a result of these covenants, we are limited in the manner in which we conduct our business and we may be unable to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business. 
+In addition, our Credit Facility requires us to maintain certain financial ratios and to make certain required payments of principal, premium, if any, and interest. If we fail to comply with these provisions or other financial and operating covenants in the Credit Facility or the indentures governing our senior notes, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our Credit Facility could elect to terminate their commitments thereunder, cease making further loans and institute foreclosure proceedings against our assets; and we could be forced into bankruptcy or liquidation. 
+Our borrowings under our Credit Facility expose us to interest rate risk. Our earnings are exposed to interest rate risk associated with borrowings under our Credit Facility, which bear interest at a rate elected by us that is based on the prime, LIBOR or federal funds rate plus margins ranging from 0.25% to 2.25% depending on the interest rate used and the amount of the loan outstanding in relation to the borrowing base. 
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+The borrowing base under our Credit Facility may be reduced below the amount of borrowings outstanding thereunder. The borrowing base under our Credit Facility is currently $2.5 billion, with an elected commitment amount of $2.0 billion , and as of December 31, 2019, we had an aggregate principal balance of $1.3 billion outstanding thereunder. Our borrowing base is subject to redeterminations semi-annually, and a future decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations may cause us to not be able to access adequate funding under the Credit Facility. If our borrowing base were to be reduced, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness. In addition, we cannot borrow amounts above the elected commitments, even if the borrowing base is greater, without new commitments being obtained from the lenders for such incremental amounts above the elected commitments. In the event the amount outstanding under our Credit Facility exceeds the elected commitments, we must repay such amounts immediately in cash. In the event the amount outstanding under our Credit Facility exceeds the redetermined borrowing base, we are required to either (i) grant liens on additional oil and gas properties (not previously evaluated in determining such borrowing base) with a value equal to or greater than such excess, (ii) repay such excess borrowings over six monthly installments, or (iii) elect a combination of options in clauses (i) and (ii). We may not have sufficient funds to make any required repayment. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, an event of default would occur under our Credit Facility. 
+We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful. Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to certain financial, economic, competitive and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. 
+If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Also, we may not be able to consummate dispositions at such time on terms acceptable to us or at all, and the proceeds of any such dispositions may not be adequate to meet such debt service obligations. Furthermore, any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. In addition, the terms of existing or future debt instruments may restrict us from adopting some of these alternatives. For example, our Credit Facility currently restricts our ability to dispose of assets and our use of the proceeds from such disposition. 
+Any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. 
+We cannot be certain that we will be able to maintain or improve our leverage position. An element of our business strategy involves maintaining a disciplined approach to financial management. However, we are also seeking to acquire, exploit and develop additional reserves that may require the incurrence of additional indebtedness. Although we will seek to maintain or improve our leverage position, our ability to maintain or reduce our level of indebtedness depends on a variety of factors, including future performance and our future debt financing needs. General economic conditions, oil and natural gas prices and financial, business and other factors will also affect our ability to maintain or improve our leverage position. Many of these factors are beyond our control. 
+Our hedging program may limit potential gains from increases in commodity prices, result in losses, or be inadequate to protect us against continuing and prolonged declines in commodity prices. We enter into arrangements to hedge a portion of our production from time to time to reduce our exposure to fluctuations in oil and natural gas prices and to achieve more predictable cash flow. Our hedges at December 31, 2019 are in the form of collars, swaps, put and call options, basis swaps, and other structures placed with the commodity trading branches of certain national banking institutions and with certain other commodity trading groups. These hedging arrangements may limit the benefit we could receive from increases in the market or spot prices for oil and natural gas. We cannot be certain that the hedging transactions we have entered into, or will enter into, will adequately protect us from continuing and prolonged declines in oil and natural gas prices. To the extent that oil and natural gas prices remain at current levels or decline further, we would not be able to hedge future production at the same pricing level as our current hedges and our results of operations and financial condition may be negatively impacted. 
+In addition, in a typical hedge transaction, we will have the right to receive from the other parties to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the other parties this difference multiplied by the quantity hedged regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements even though such payments are not offset by sales of physical production. 
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+Our hedging transactions expose us to counterparty credit risk. Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract, particularly during periods of falling commodity prices. Disruptions in the financial markets or other factors outside our control could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform, and even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending on market conditions at the time. If the creditworthiness of any of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss. 
+The inability of one or more of our customers to meet their obligations to us may adversely affect our financial results . Our principal exposure to credit risk is through receivables resulting from the sale of our oil and natural gas production, advances to joint interest parties and joint interest receivables. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. The largest purchaser of our oil and natural gas accounted for approximately 26% of our total revenues for the year ended December 31, 2019 . The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. 
+Our ability to use our existing net operating loss carryforwards or other tax attributes could be limited. A portion of our NOL carryforward balance was generated prior to the effective date of new limitations on utilization of NOLs imposed by the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) and are allowable as a deduction against 100 percent of taxable income in future years but will start to expire in the tax year 2035. The remainder was generated following such effective date and thus are allowable as a deduction against 80 percent of taxable income in future years and do not expire. Utilization of any NOL carryforwards depends on many factors, including our ability to generate future taxable income, which cannot be assured. In addition, Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”), generally imposes, upon the occurrence of an ownership change (discussed below), an annual limitation on the amount of our pre-ownership change NOLs we can utilize to offset our taxable income in any taxable year (or portion thereof) ending after such ownership change. The limitation is generally equal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax exempt rate. In general, an ownership change occurs if there is a cumulative increase in our ownership of more than 50 percentage points by one or more “5% shareholders” (as defined in the Internal Revenue Code of 1986, as amended) at any time during a rolling three-year period. The Company has reduced the total recorded NOL balance and associated deferred tax asset for the NOLs to the amount expected to be fully utilizable before they expire. Future ownership changes or future regulatory changes could further limit our ability to utilize our NOLs. To the extent we are not able to offset our future income with our NOLs, this could adversely affect our operating results and cash flows once we attain profitability. 
+Unanticipated changes in effective tax rates or adverse outcomes resulting from examination of our income or other tax returns could adversely affect our financial condition and results of operations. 
+We are subject to income taxes in the U. S., and our domestic tax assets and liabilities are subject to the allocation of expenses in differing jurisdictions. Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including: 
+• 
+changes in the valuation of our deferred tax assets and liabilities; 
+• 
+expected timing and amount of the release of any tax valuation allowances; 
+• 
+tax effects of stock-based compensation; 
+• 
+costs related to intercompany restructurings; 
+• 
+changes in tax laws, regulations or interpretations thereof; or 
+• 
+lower than anticipated future earnings in our taxing jurisdictions. 
+In addition, we may be subject to audits of our income, sales and other transaction taxes by U.S. federal and state authorities. Outcomes from these audits could have an adverse effect on our financial condition and results of operations. 
+Adverse changes in our credit rating may affect our borrowing capacity and borrowing terms. Our outstanding debt is periodically rated by nationally recognized credit rating agencies. The credit ratings are based on our operating performance, liquidity and leverage ratios, overall financial position, and other factors viewed by the credit rating agencies as relevant to our industry and the economic outlook. Our credit rating may affect the amount of capital we can access, as well as the terms of any financing we may obtain. Because we rely in part on debt financing to fund growth, adverse changes in our credit rating may have a negative effect on our future growth. 
+A negative shift in investor sentiment of the oil and gas industry could adversely affect our ability to raise debt and equity capital. Certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition, some investors, including investment advisors and certain sovereign wealth funds, pension funds, university endowments and family foundations, have stated policies to disinvest in the oil and gas sector based on their social and environmental considerations. Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas production and related infrastructure projects. Such developments, including environmental activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also potentially result in a reduction of available capital funding for potential development projects, impacting our future financial results. 
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+Legal and Regulatory Risks 
+We are subject to stringent and complex federal, state and local laws and regulations which require compliance that could result in substantial costs, delays or penalties. Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. For a discussion of the material regulations applicable to us, see “Business and Properties—Regulations.” These laws and regulations may: 
+• 
+require that we acquire permits before commencing drilling; 
+• 
+regulate the spacing of wells and unitization and pooling of properties; 
+• 
+impose limitations on production or operational, emissions control and other conditions on our activities; 
+• 
+restrict the substances that can be released into the environment or used in connection with drilling and production activities or restrict the disposal of waste from our operations; 
+• 
+limit or prohibit drilling activities on protected areas, such as wetlands and wilderness; 
+• 
+impose penalties or other sanctions for accidental or unpermitted spills or releases from our operations; or 
+• 
+require measures to remediate or mitigate pollution and environmental impacts from current and former operations, such as cleaning up spills or dismantling abandoned production facilities. 
+Significant expenditures may be required to comply with governmental laws and regulations applicable to us. In addition, failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, permit revocations, requirements for additional pollution controls or injunctions limiting or prohibiting operations. 
+The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal, state and local agencies frequently revise environmental laws and regulations, and such changes could result in increased costs for environmental compliance, such as emissions control, permitting, or waste handling, storage, transport, remediation or disposal for the oil and natural gas industry and could have a significant impact on our operating costs. In general, the oil and natural gas industry recently has been the subject of increased legislative and regulatory attention with respect to public health and environmental matters. Even if regulatory burdens temporarily ease, the historic trend of more expansive and stricter environmental legislation and regulations may continue in the long-term. 
+Further, under these laws and regulations, we could be liable for costs of investigation, removal and remediation, damages to and loss of use of natural resources, loss of profits or impairment of earning capacity, property damages, costs of increased public services, as well as administrative, civil and criminal fines and penalties, and injunctive relief. Certain environmental statutes, including the RCRA, CERCLA, OPA and analogous state laws and regulations, impose strict, joint and several liability for costs required to investigate, clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released (i.e., liability may be imposed regardless of whether the current owner or operator was responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time the release or contamination occurred). We could also be affected by more stringent laws and regulations adopted in the future, including any related to climate change, engine and other equipment emissions, GHGs and hydraulic fracturing. Under common law, we could be liable for injuries to people and property. We maintain limited insurance coverage for sudden and accidental environmental damages. We do not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Also, we do not believe that insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability in excess of our insurance coverage or we may be required to curtail or cease production from properties in the event of environmental incidents. 
+Federal legislation and state and local legislative and regulatory initiatives relating to hydraulic fracturing and water disposal wells could result in increased costs and additional operating restrictions or delays. Hydraulic fracturing is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production and is typically regulated by state oil and gas commissions. However, from time to time, the U.S. Congress has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing. Legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and to require federal permitting and regulatory control of hydraulic fracturing but has not passed. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, in February 2014, the EPA published permitting guidance addressing the use of diesel fuel in hydraulic fracturing operations, and issued an interpretive memorandum clarifying that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act. The EPA has also published air emission standards for certain equipment, processes and activities across the oil and natural gas sector, although the EPA proposed amendments in August 2019 that would rescind requirements related to the regulation of methane emissions. Additionally, the BLM published a final rule in March 2015 containing disclosure requirements and other mandates for hydraulic fracturing on federal and Indian lands. Although the BLM subsequently rescinded the rule in December 2017, the rescission has been challenged in federal court by several environmental groups and states. In November 2016, the BLM also issued rules to limit methane emissions from new and existing oil and gas operations on federal lands, but subsequently relaxed and rescinded certain requirements of the rules in September 2018; a lawsuit challenging the September 2018 rule revision is pending. 
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+In some areas of Texas, including the Eagle Ford Shale and Permian Basin, there has been concern that certain formations into which disposal wells are injecting produced waters could become over-pressured after many years of injection, and the RRC is reviewing the data to determine whether any regulatory action is necessary to address this issue. If the RRC were to decline to issue permits for, or limit the volumes of, new injection wells into the formations that we currently utilize, we may be required to seek alternative methods of disposing of produced waters, including injecting into deeper formations, which could increase our costs. 
+Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, impose additional requirements on hydraulic fracturing activities or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For example, Texas law requires the chemical components used in the hydraulic fracturing process, as well as the volume of water used, must be disclosed to the RRC and the public. Furthermore, the RRC issued the “well integrity rule” in May 2013, which includes testing and reporting requirements, such as (i) the requirement to submit to the RRC cementing reports after well completion or cessation of drilling, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. Additionally, in October 2014, the RRC adopted a rule requiring applicants for certain new water disposal wells to conduct seismic activity searches using the U.S. Geological Survey to determine the potential for earthquakes within a circular area of 100 square miles. The rule also clarifies the RRC’s authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The RRC has used this authority to deny permits for waste disposal wells. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of drilling in general or hydraulic fracturing in particular. 
+In December 2016, the EPA released its final report “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States.” This report concludes that hydraulic fracturing can impact drinking water resources in certain circumstances but also noted that certain data gaps and uncertainties limited EPA’s ability to fully characterize the severity of impacts or calculate the national frequency of impacts on drinking water resources from activities in the hydraulic fracturing water cycle. This study could result in additional regulatory scrutiny that could restrict our ability to perform hydraulic fracturing and increase our costs of compliance and doing business. 
+There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, water usage and the potential for impacts to surface water, groundwater and the environment generally, and a number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. Several states and municipalities have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances. If new laws or regulations that significantly restrict hydraulic fracturing or water disposal wells are adopted, such laws could make it more difficult or costly for us to drill for and produce oil and natural gas as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements, permitting delays and potential increases in costs. These changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing. 
+Climate change legislation or regulations restricting emissions of GHG, changes in the availability of financing for fossil fuel companies, and physical effects from climate change could adversely impact our operating costs and demand for the oil and natural gas we produce. In recent years, federal, state and local governments have taken steps to reduce emissions of GHGs. The EPA has finalized a series of GHG monitoring, reporting and emissions control rules, and the U.S. Congress has, from time to time, considered adopting legislation to reduce emissions. Several states have already taken measures to reduce emissions of GHGs primarily through the development of GHG emission inventories or regional GHG cap-and-trade programs. While we are subject to certain federal GHG monitoring and reporting requirements, our operations currently are not adversely impacted by existing federal, state and local climate change initiatives. For a description of existing and proposed GHG rules and regulations, see “Regulations.” 
+In December 2015, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change resulted in 195 countries, including the United States, coming together to develop the Paris Agreement, which calls for the parties to undertake “ambitious efforts” to limit the average global temperature. The Agreement went into effect on November 4, 2016, and establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. The United States formally announced its intent to withdraw from the Paris Agreement on November 4, 2019, which withdrawal will become effective on November 4, 2020. Certain U.S. city and state governments have announced their intention to satisfy their proportionate obligations under the Paris Agreement. A number of states have begun taking actions to control or reduce emissions of GHGs. Restrictions on GHG emissions that may be imposed could adversely affect the oil and gas industry. The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Moreover, incentives or requirements to conserve energy, use alternative energy sources, reduce GHG emissions in product supply chains, and increase demand for low-carbon 
+36 
+fuel or zero-emissions vehicles, could reduce demand for the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations. 
+In addition, fuel conservation measures, alternative fuel requirements and increasing consumer demand for alternatives to oil and natural gas could reduce demand for oil and natural gas. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could impact our business activities, operations and ability to access capital. Furthermore, some parties have initiated public nuisance claims under federal or state common law against certain companies involved in the production of oil and natural gas. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other liabilities. Although our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition. 
+Finally, most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce significant physical effects, such as increased frequency and severity of droughts, storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced or cause us to incur significant costs in preparing for or responding to the effects of climatic events themselves. Potential adverse effects could include disruption of our production activities, including, for example, damages to our facilities from winds or floods or increases in our costs of operation or reductions in the efficiency of our operations, as well as potentially increased costs for insurance coverages in the aftermath of such effects. 
+Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) establishes federal oversight and regulation of over-the-counter derivatives and requires the U.S. Commodity Futures Trading Commission (the “CFTC”) and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the over-the-counter market. 
+Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas, including the scope of relevant definitions or exemptions, remain pending. In one of the CFTC’s rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC has proposed but not yet finalized position limits for certain futures and options contracts in various commodities and for swaps that are their economic equivalents (with exemptions for certain bona fide hedging transactions). Similarly, the CFTC has proposed but not yet finalized a rule regarding the capital that a swap dealer or major swap participant is required to post with respect to its swap business. The CFTC issued a final rule on margin requirements for uncleared swap transactions in January 2016, which it amended in November 2018. The final rule as amended includes an exemption for certain commercial end-users that enter into uncleared swaps in order to hedge bona fide commercial risks affecting their business. In addition, the CFTC has issued a final rule authorizing an exception from the requirement to use cleared exchanges (rather than hedging over-the-counter) for commercial end-users who use swaps to hedge their commercial risks. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations. All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business. 
+It is not possible at this time to predict the timing or contents of the CFTC’s final rules on position limits or capital requirements. Depending on our ability to satisfy the CFTC’s requirements for the various exemptions available for a commercial end-user using swaps to hedge or mitigate its commercial risks, the final rules may provide beneficial exemptions or may require us to comply with position limits and other limitations with respect to our financial derivative activities. When a final rule on capital requirements is issued, the Dodd-Frank Act may require our current counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which could increase the cost to us of entering into such derivatives. The Dodd-Frank Act may also require our current counterparties to financial derivative transactions to cease their current business as hedge providers or spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. These potential changes could reduce the liquidity of the financial derivatives markets which would reduce the ability of commercial end-users like us to hedge or mitigate their exposure to commodity price volatility. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of future swaps relative to the terms of our existing financial derivative contracts, and reduce the availability of derivatives to protect against commercial risks we encounter. 
+In addition, federal banking regulators have adopted new capital requirements for certain regulated financial institutions in connection with the Basel III Accord. The Federal Reserve Board also issued proposed regulations on September 30, 2016, proposing to impose higher risk-weighted capital requirements on financial institutions active in physical commodities, such as oil and natural gas. If and when these proposed regulations are fully implemented, financial institutions subject to these higher capital requirements may require that we provide cash or other collateral with respect to our obligations under the financial derivatives and other contracts in order to reduce the amount of capital such financial institutions may have to maintain. Alternatively, financial institutions subject to these capital requirements may require premiums to enter into derivatives and other physical commodity transactions to compensate for the additional capital costs for these transactions. Rules implementing the Basel III Accord and higher risk-weighted capital requirements could materially 
+37 
+reduce our liquidity and increase the cost of derivative contracts and other physical commodity contracts (including through requirements to post collateral which could adversely affect our available capital for other commercial operations purposes). 
+If we reduce our use of derivative contracts as a result of any of the foregoing new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Our revenues could be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations, or cash flows. 
+Tax laws and regulations may change over time, and the recently passed comprehensive tax reform bill could adversely affect our business and financial condition. On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Act that significantly reforms the Internal Revenue Code of 1986, as amended (the “Code”). The Tax Act, among other things, (i) permanently reduces the U.S. corporate income tax rate, (ii) repeals the corporate alternative minimum tax, (iii) eliminates the deduction for certain domestic production activities, (iv) imposes new limitations on the utilization of net operating losses, and (v) provides for more general changes to the taxation of corporations, including changes to cost recovery rules and to the deductibility of interest expense, which may impact the taxation of oil and gas companies. The Tax Act is complex and far-reaching and we cannot predict with certainty the resulting impact its enactment has on us. The ultimate impact of the Tax Act may differ from our estimates due to changes in interpretations and assumptions made by us as well as additional regulatory guidance that may be issued and any such changes in interpretations or assumptions could adversely affect our business and financial condition. See “ Note 12 - Income Taxes” to our consolidated financial statements included elsewhere in this 2019 Annual Report on Form 10-K for additional information. 
+In addition, from time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws, including (i) the elimination of the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties and (iii) an extension of the amortization period for certain geological and geophysical expenditures. While these specific changes were not included in the Tax Act, no accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. The elimination of such U.S. federal tax deductions, as well as any other changes to or the imposition of new federal, state, local or non-U.S. taxes (including the imposition of, or increases in production, severance or similar taxes) could adversely affect our business and financial condition. 
+We may be subject to the actions of activist shareholders. We have been the subject of an activist shareholder in the past. Responding to shareholder activism can be costly and time-consuming, disrupt our operations and divert the attention of management and our employees from executing our business plan. Activist campaigns can create perceived uncertainties as to our future direction, strategy or leadership and may result in the loss of potential business opportunities, harm our ability to attract new investors, customers and joint venture partners and cause our stock price to experience periods of volatility or stagnation. Moreover, if individuals are elected to our Board of Directors with a specific agenda, our ability to effectively and timely implement our current initiatives, retain and attract experienced executives and employees and execute on our long-term strategy may be adversely affected. 
+Risks Related to our Common Stock 
+Our bylaws designate the Court of Chancery of the State of Delaware (the “Court of Chancery”) as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our shareholders, which could limit our shareholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, or other employees. Our bylaws provide that, unless we consent in writing to the selection of an alternative forum, the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action or proceeding asserting a claim for breach of a fiduciary duty owed by any current or former director, officer, or other employee of our company to us or our shareholders, (iii) any action or proceeding asserting a claim against us or any current or former director, officer, or other employee of our company arising pursuant to any provision of the Delaware General Corporate Law (the “DGCL”) or our charter or bylaws (as each may be amended from time to time), (iv) any action or proceeding asserting a claim against us or any current or former director, officer, or other employee of our company governed by the internal affairs doctrine, or (v) any action or proceeding as to which the DGCL confers jurisdiction on the Court of Chancery shall be the Court of Chancery or, if and only if the Court of Chancery lacks subject matter jurisdiction, any state court located within the State of Delaware or, if and only if such state courts lack subject matter jurisdiction, the federal district court for the District of Delaware, in all cases to the fullest extent permitted by law and subject to the court’s having personal jurisdiction over the indispensable parties named as defendants. 
+Our exclusive forum provision is not intended to apply to claims arising under the Securities Act or the Exchange Act. To the extent the provision could be construed to apply to such claims, there is uncertainty as to whether a court would enforce the forum selection provision with respect to such claims, and in any event, our shareholders would not be deemed to have waived our compliance with federal securities laws and the rules and regulations thereunder. 
+Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock is deemed to have received notice of and consented to the foregoing forum selection provision. This provision may limit our shareholders’ ability to bring a claim in a judicial forum that they find favorable for disputes with us or our directors, officers, or other employees, which may discourage such lawsuits. 
+38 
+Alternatively, if a court were to find this choice of forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect its business, financial condition, prospects, or results of operations. 
+Provisions of our charter documents and Delaware law may inhibit a takeover, which could limit the price investors might be willing to pay in the future for our common stock. Provisions in our certificate of incorporation and bylaws may have the effect of delaying or preventing an acquisition of the Company or a merger in which we are not the surviving company and may otherwise prevent or slow changes in our Board of Directors and management. In addition, because we are incorporated in Delaware, we are governed by the provisions of Section 203 of the DGCL. These provisions could discourage an acquisition of the Company or other change in control transactions and thereby negatively affect the price that investors might be willing to pay in the future for our common stock. 
+We have no current plans to pay cash dividends on our common stock. Our Credit Facility and the indentures governing our senior notes limit our ability to pay dividends and make other distributions. We have no current plans to pay dividends on our common stock and any future determination as to the declaration and payment of cash dividends will be at the discretion of our Board of Directors and will depend upon our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors deemed relevant by our Board of Directors at the time of such determination. Consequently, unless we revise our dividend plans, a shareholder’s only opportunity to achieve a return on its investment in us will be by selling its shares of our common stock at a price greater than the shareholder paid for it. There is no guarantee that the price of our common stock that will prevail in the market will exceed the price at which a shareholder purchased its shares of our common stock. 
+Future sales of our common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of our common stock or other securities may dilute a shareholder’s ownership in us. In the future, we may issue securities to raise capital. We may also acquire interests in other companies by using any combination of cash and our common stock or other securities convertible into, or exchangeable for, or that represent the right to receive, our common stock. Any of these events may dilute your ownership interest in our company, reduce our earnings per share or have an adverse impact on the price of our common stock. In addition, secondary sales of a substantial amount of our common stock in the public market, or the perception that these sales may occur, could reduce the market price of our common stock. Any such reduction in the market price of our common stock could impair our ability to raise additional capital through the sale of our securities. 
+ITEM 1B. Unresolved Staff Comments 
+None. 
+ITEM 3. Legal Proceedings 
+We are a defendant in various legal proceedings and claims, which arise in the ordinary course of our business. While the outcome of these events cannot be predicted with certainty, we believe that the ultimate resolution of any such actions will not have a material effect on our financial position or results of operations. 
+ITEM 4. Mine Safety Disclosures 
+Not applicable. 
+39 
+PART II. 
+ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+Market Information 
+Our common stock trades on the New York Stock Exchange under the symbol “CPE”. 
+໿ 
+Holders 
+As of February 21, 2020 the Company had approximately 2,597 common stockholders of record. 
+Dividends 
+We have not paid any cash dividends on our common stock to date and presently do not expect to declare or pay any cash dividends on our common stock in the foreseeable future as we intend to reinvest our cash flows and earnings into our business and pay down debt. The declaration and payment of dividends is subject to the discretion of our Board of Directors and to certain limitations imposed under Delaware corporate law and the agreements governing our debt obligations. The timing, amount and form of dividends, if any, will depend on, among other things, our results of operations, financial condition, cash requirements and other factors deemed relevant by our Board of Directors. In addition, certain of our debt facilities contain restrictions on the payment of dividends to the holders of our common stock. 
+40 
+Performance Graph 
+The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the performance of the Company’s common stock relative to a broad-based stock performance index and a peer group of companies. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. 
+The graph below compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the Standard & Poor’s 500 Index (“S&P 500 Index”) and a peer group of companies to which we compare our performance from December 31, 2014 through December 31, 2019 . The companies in the peer group include Cimarex Energy Co., Centennial Resource Development, Inc., Magnolia Oil & Gas Corporation, Matador Resources, Inc., Oasis Petroleum, Inc., Parsley Energy, Inc., PDC Energy, Inc., QEP Resources, Inc., SM Energy Company, Whiting Petroleum Corporation, and WPX Energy, Inc. 
+The stock performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing 
+Comparison of Five Year Cumulative Total Return 
+Assumes Initial Investment of $100 
+December 31, 2019 
+Years Ended December 31, 
+Company/Market/Peer Group 
+2014 
+2015 
+2016 
+2017 
+2018 
+2019 
+Callon Petroleum Company 
+$100 
+$153 
+$282 
+$223 
+$119 
+$89 
+S&P 500 Index - Total Returns 
+100 
+101 
+114 
+138 
+132 
+174 
+Peer Group 
+100 
+74 
+125 
+98 
+67 
+56 
+໿ 
+41 
+ITEM 6. Selected Financial Data 
+The following table sets forth, as of the dates and for the periods indicated, selected financial information about the Company. The financial information for each of the five years in the period ended December 31, 2019 has been derived from our audited Consolidated Financial Statements for such periods. The information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and Notes thereto. The following information is not necessarily indicative of our future results. 
+໿ 
+Years Ended December 31, 
+2019 
+2018 
+2017 
+2016 
+2015 
+Statement of Operations Data (1) 
+(In thousands, except per share amounts) 
+Oil, natural gas, and NGL revenue 
+$671,572 
+$587,624 
+$366,474 
+$200,851 
+$137,512 
+Total operating expenses 
+498,914 
+328,094 
+225,028 
+248,328 
+346,622 
+Income (loss) from operations 
+172,658 
+259,530 
+141,446 
+(47,477 
+) 
+(209,110 
+) 
+Income (loss) available to common stockholders (2) 
+67,928 
+300,360 
+120,424 
+(99,108 
+) 
+(248,034 
+) 
+Income (loss) available to common stockholders per common share: 
+Basic 
+$0.24 
+$1.35 
+$0.56 
+($0.78 
+) 
+($3.77 
+) 
+Diluted 
+$0.24 
+$1.35 
+$0.56 
+($0.78 
+) 
+($3.77 
+) 
+Weighted average common shares outstanding: 
+Basic 
+233,140 
+216,941 
+201,526 
+126,258 
+65,708 
+Diluted 
+233,550 
+217,596 
+202,102 
+126,258 
+65,708 
+Statement of Cash Flows Data 
+Net cash provided by operating activities 
+$476,316 
+$467,654 
+$229,891 
+$120,774 
+$89,319 
+Net cash used in investing activities 
+(388,389 
+) 
+(1,324,057 
+) 
+(1,072,532 
+) 
+(866,287 
+) 
+(259,160 
+) 
+Net cash provided by (used in) financing activities 
+(90,637 
+) 
+844,459 
+217,643 
+1,397,282 
+170,097 
+Balance Sheet Data 
+Total oil and natural gas properties 
+$6,669,118 
+$3,718,858 
+$2,513,491 
+$1,475,401 
+$711,386 
+Total assets 
+7,194,838 
+3,979,173 
+2,693,296 
+2,267,587 
+788,594 
+Long-term debt (3) 
+3,186,109 
+1,189,473 
+620,196 
+390,219 
+328,565 
+Stockholders’ equity 
+3,223,308 
+2,445,208 
+1,855,966 
+1,733,402 
+362,758 
+Proved Reserves Data (4) 
+Oil (MBbls) 
+346,361 
+180,097 
+107,072 
+71,145 
+43,348 
+Natural gas (MMcf) 
+757,134 
+350,466 
+179,410 
+122,611 
+65,537 
+NGLs (MBbls) 
+67,462 
+— 
+— 
+— 
+— 
+Total proved reserves (MBoe) 
+540,012 
+238,508 
+136,974 
+91,580 
+54,271 
+Standardized measure of discounted future net cash flows 
+$4,951,026 
+$2,941,293 
+$1,556,682 
+$809,832 
+$570,890 
+(1) 
+Includes activity from the Carrizo Acquisition subsequent to the December 20, 2019 closing date. 
+(2) 
+Net loss for 2015 included the recognition of a write-down of oil and natural gas properties of $208.4 million as a result of the ceiling test limitation and $108.8 million of income tax expense related to the recognition of a valuation allowance. Net loss for 2016 included the recognition of a write-down of oil and natural gas properties of $95.8 million as a result of the ceiling test limitation. 
+(3) 
+See “ Note 7 - Borrowings” of the Notes to our Consolidated Financial Statements for additional information. 
+(4) 
+The estimated proved reserves acquired in the Carrizo Acquisition are presented on a three-stream basis and include NGLs, whereas, all other estimated proved reserve volumes are on a two-stream basis. 
+42 
+ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+A discussion and analysis of the Company’s financial condition and results of operations for the year ended December 31, 2017 can be found in “Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” of its Annual Report on Form 10-K for the year ended December 31, 2018, which was filed with the SEC on February 27, 2019 and is incorporated herein by reference. 
+General 
+The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the accompanying audited consolidated financial statements, information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results, which are included in various parts of this filing. 
+Our website address is www.callon.com. All of our filings with the SEC are available free of charge through our website as soon as reasonably practicable after we file them with, or furnish them to, the SEC. Information on our website does not form part of this 2019 Annual Report on Form 10-K. 
+We are an independent oil and natural gas company incorporated in the State of Delaware in 1994, but our roots go back nearly 70 years to our Company’s establishment in 1950. We are focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas. Our activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger Permian Basis in West Texas. In 2019, though our acquisition of Carrizo, we doubled our core acreage position in the Delaware Basin and entered the Eagle Ford Shale. 
+Our operating culture is centered on responsible development of hydrocarbon resources, safety and the environment, which we believe strengthens our operational performance. Our drilling activity is predominantly focused on the horizontal development of several prospective intervals in the Permian Basin, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales, and more recently as a result of the Carrizo Acquisition, the Eagle Ford Shale. We have assembled a multi-year inventory of potential horizontal well locations and intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps. 
+Overview 
+Significant Accomplishments in 2019 
+• 
+On December 20, 2019, we completed the Carrizo Acquisition which increased our portfolio to: (i) over 116,000 net acres in the Permian Basin, which doubled our footprint in the Southern Delaware Basin and (ii) expanded our portfolio to include over 76,000 net acres in the mature, high-margin, free cash flow generating Eagle Ford Shale. 
+• 
+In connection with the Carrizo Acquisition, we entered into the Credit Facility, which has a maximum credit amount of $5.0 billion . As of December 31, 2019, the borrowing base under the Credit Facility was $2.5 billion , with an elected commitment amount of $2.0 billion. 
+• 
+During 2019, we completed divestitures of non-core assets for aggregate net proceeds of $294.4 million . In addition, we could receive cash for settlements of our contingent consideration arrangement of up to $60.0 million if crude oil prices exceed specified thresholds for each of the years of 2019 through 2021. 
+• 
+Our total production in 2019 increased by 26% to 15.1 MMBoe ( 77% oil) as compared to 2018 . 
+• 
+On July 18, 2019, we redeemed all of the outstanding Preferred Stock for $73.0 million . 
+• 
+For the year ended December 31, 2019, we drilled 63 gross ( 55.7 net) horizontal wells, completed 55 gross ( 47.1 net) horizontal wells and had, as of December 31, 2019, 64 gross ( 57.7 net) horizontal wells awaiting completion. 
+• 
+Estimated proved reserves as of December 31, 2019 were 540.0 MMBoe ( 64% oil), with 43% classified as proved developed. 
+Reserves Growth 
+As of December 31, 2019 , our estimated proved reserves increased 126% to 540.0 MMBoe compared to 238.5 MMBoe of estimated proved reserves at year-end 2018 . Our significant growth in proved reserves was primarily attributable to the Carrizo Acquisition, along with our horizontal development efforts. Our estimated proved reserves at year-end 2019 and 2018 were 64% and 76% oil, respectively. 
+43 
+Results of Operations 
+The following table sets forth certain operating information with respect to the Company’s oil and natural gas operations for the periods indicated: 
+໿ 
+Years Ended December 31, 
+2019 (1) 
+2018 
+$ Change 
+% Change 
+Total production (2) 
+Oil (MBbls) 
+11,665 
+9,443 
+2,222 
+24 
+% 
+Natural gas (MMcf) 
+19,718 
+15,447 
+4,271 
+28 
+% 
+NGLs (MBbls) 
+135 
+— 
+135 
+100 
+% 
+Total barrels of oil equivalent (MBoe) 
+15,086 
+12,018 
+3,068 
+26 
+% 
+Total daily production (Boe/d) 
+41,331 
+32,926 
+8,405 
+26 
+% 
+Oil as % of total daily production 
+77 
+% 
+79 
+% 
+Average realized sales price (excluding impact of settled derivatives) 
+Oil (per Bbl) 
+$54.27 
+$56.22 
+($1.95 
+) 
+(3 
+%) 
+Natural gas (per Mcf) 
+1.85 
+3.67 
+(1.82 
+) 
+(50 
+%) 
+NGLs (per Bbl) 
+15.37 
+— 
+15.37 
+100 
+% 
+Total (per Boe) 
+44.52 
+48.90 
+(4.38 
+) 
+(9 
+%) 
+Average realized sales price (including impact of settled derivatives) 
+Oil (per Bbl) 
+$53.31 
+$53.31 
+$— 
+— 
+% 
+Natural gas (per Mcf) 
+2.22 
+3.69 
+(1.47 
+) 
+(40 
+%) 
+NGLs (per Bbl) 
+15.37 
+— 
+15.37 
+100 
+% 
+Total (per Boe) 
+44.27 
+46.63 
+(2.36 
+) 
+(5 
+%) 
+Revenues (in thousands) 
+Oil 
+$633,107 
+$530,898 
+$102,209 
+19 
+% 
+Natural gas 
+36,390 
+56,726 
+(20,336 
+) 
+(36 
+%) 
+NGLs 
+2,075 
+— 
+2,075 
+100 
+% 
+Total revenues 
+$671,572 
+$587,624 
+$83,948 
+14 
+% 
+Additional per Boe data 
+Lease operating expense (3) 
+6.09 
+5.76 
+0.33 
+6 
+% 
+Production taxes 
+2.83 
+2.98 
+(0.15 
+) 
+(5 
+%) 
+Benchmark prices (4) 
+WTI (per Bbl) 
+$56.98 
+$65.23 
+($8.25 
+) 
+(13 
+%) 
+Henry Hub (per Mcf) 
+2.56 
+3.15 
+(0.59 
+) 
+(19 
+%) 
+(1) 
+Includes activity from the Carrizo Acquisition subsequent to the December 20, 2019 closing date. 
+(2) 
+The production associated with reserves acquired in the Carrizo Acquisition are presented on a three-stream basis and include NGLs, whereas, all other reserve volumes are on a two-stream basis. 
+(3) 
+Excludes gathering and treating expense. 
+(4) 
+Reflects calendar average daily spot market prices. 
+44 
+Revenues 
+The following table is intended to reconcile the change in oil, natural gas, NGLs, and total revenue for the period presented by reflecting the effect of changes in volume and in the underlying commodity prices. 
+Oil 
+Natural Gas 
+NGLs 
+Total 
+(In thousands) 
+Revenues for the year ended December 31, 2018 
+$530,898 
+$56,726 
+$— 
+$587,624 
+Volume increase (decrease) 
+124,869 
+15,683 
+2,075 
+142,627 
+Price increase (decrease) 
+(22,660 
+) 
+(36,019 
+) 
+— 
+(58,679 
+) 
+Net increase (decrease) 
+102,209 
+(20,336 
+) 
+2,075 
+83,948 
+Revenues for the year ended December 31, 2019 (1)(2) 
+$633,107 
+$36,390 
+$2,075 
+$671,572 
+(1) 
+Includes activity from the Carrizo Acquisition subsequent to the December 20, 2019 closing date. 
+(2) 
+The revenues associated with production from reserves acquired in the Carrizo Acquisition are presented on a three-stream basis and include NGLs, whereas, all other revenue is presented on a two-stream basis. 
+Commodity Prices 
+The prices for oil, natural gas, and NGLs remain extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and actions by OPEC and other countries and government actions. Prices of oil, natural gas, and NGLs will affect the following aspects of our business: 
+• 
+our revenues, cash flows and earnings; 
+• 
+the amount of oil and natural gas that we are economically able to produce; 
+• 
+our ability to attract capital to finance our operations and cost of the capital; 
+• 
+the amount we are allowed to borrow under the Credit Facility; and 
+• 
+the value of our oil and natural gas properties. 
+Oil revenue 
+For the year ended December 31, 2019 , oil revenues of $633.1 million increased $102.2 million , or 19% , compared to revenues of $530.9 million for the year ended December 31, 2018 . The increase in oil revenue was primarily attributable to a 24% increase in production, partially offset by a 3% decrease in the average realized sales price, which declined to $54.27 per Bbl from $56.22 per Bbl. The increase in production was comprised of 3.2 MMBbls attributable to wells placed on production as a result of our horizontal drilling program, partially offset by normal and expected declines from our existing wells. 
+Natural gas revenue 
+Natural gas revenues decreased $20.3 million , or 36% , during the year ended December 31, 2019 to $36.4 million as compared to $56.7 million for the year ended December 31, 2018 . The decrease primarily relates to an approximate 50% decrease in the average price realized, which declined to $1.85 per Mcf from $3.67 per Mcf. The decrease was partially offset by a 28% increase in natural gas volumes. The increase in production was comprised of 4.6 Bcf attributable to wells placed on production as a result of our horizontal drilling program, partially offset by normal and expected declines from our existing wells. 
+NGL revenue 
+We recognized NGL revenues of $2.1 million as a result of the recent Carrizo Acquisition. 
+Operating Expenses 
+໿ 
+Years Ended December 31, 
+Per 
+Per 
+Total Change 
+Boe Change 
+2019 
+Boe 
+2018 
+Boe 
+$ 
+% 
+$ 
+% 
+(In thousands, except per Boe and % amounts) 
+Lease operating expenses 
+$91,827 
+$6.09 
+$69,180 
+$5.76 
+$22,647 
+33 
+% 
+$0.33 
+6 
+% 
+Production taxes 
+42,651 
+2.83 
+35,755 
+2.98 
+6,896 
+19 
+% 
+(0.15 
+) 
+(5 
+%) 
+Depreciation, depletion and amortization 
+240,642 
+15.95 
+182,783 
+15.21 
+57,859 
+32 
+% 
+0.74 
+5 
+% 
+General and administrative 
+45,331 
+3.00 
+35,293 
+2.94 
+10,038 
+28 
+% 
+0.06 
+2 
+% 
+Merger and integration expenses 
+74,363 
+4.93 
+— 
+— 
+74,363 
+100 
+% 
+4.93 
+100 
+% 
+Settled share-based awards 
+3,024 
+0.20 
+— 
+— 
+3,024 
+100 
+% 
+0.20 
+100 
+% 
+໿ 
+45 
+Lease operating expenses. These are daily costs incurred to extract oil and natural gas and maintain our producing properties. Such costs also include maintenance, repairs, gas treating fees, salt water disposal, insurance and workover expenses related to our oil and natural gas properties. 
+Lease operating expenses for the year ended December 31, 2019 increased by 33% to $91.8 million compared to $69.2 million for the same period of 2018 , primarily due to production volumes increasing 26% . Lease operating expense per Boe for the year ended December 31, 2019 increased to $6.09 compared to $5.76 for the same period of 2018 primarily due to increased non-operated activity related to previous acquisitions and workovers. 
+Production taxes. Production taxes include severance and ad valorem taxes. In general, severance taxes are based upon current year commodity prices whereas ad valorem taxes are based upon prior year commodity prices. Severance taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. In the counties where our production is located, we are also subject to ad valorem taxes, which are generally based on the taxing jurisdictions’ valuation of our oil and gas properties. We benefit from tax credits and exemptions in our various taxing jurisdictions where available. 
+For the year ended December 31, 2019 , production taxes increased 19% to $42.7 million compared to $35.8 million for the same period in 2018 , due to an increase in severance taxes based on higher production volumes as well as an increase in ad valorem taxes due to a higher valuation of our oil and gas properties by the taxing jurisdictions and previous acquisitions. On a per Boe basis, production taxes for the year ended December 31, 2019 decreased by 5% compared to the same period of 2018 . Also, production taxes as a percentage of total revenues for the year ended December 31, 2019 increased to 6.4% compared to 6.1% for the same period of 2018 , due to higher ad valorem taxes as a result of higher valuations of our oil and gas properties during 2019 . 
+Depreciation, depletion and amortization (“DD&A”). Under the full cost accounting method, we capitalize costs within a cost center and then systematically amortize those costs on an equivalent unit-of-production method based on production and estimated proved gas reserve quantities. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to twenty years. 
+For the year ended December 31, 2019 , DD&A increased 32% to $240.6 million from $182.8 million compared to the same period of 2018 . The increase is primarily attributable to a 26% increase in production, as discussed above, and a 5% increase in our DD&A per Boe rate. For the year ended December 31, 2019 , DD&A per Boe increased to $15.95 compared to $15.21 for the same period of 2018 . 
+General and administrative, net of amounts capitalized (“G&A”). G&A for the year ended December 31, 2019 increased to $45.3 million compared to $35.3 million for the same period of 2018 . G&A for the periods indicated include the following: 
+Years Ended December 31, 
+2019 
+2018 
+$ Change 
+% Change 
+(In thousands, except % amounts) 
+G&A 
+$37,174 
+$28,710 
+$8,464 
+29 
+% 
+Share-based compensation 
+7,043 
+6,224 
+819 
+13 
+% 
+Fair value adjustments of cash-settled RSU awards 
+672 
+359 
+313 
+87 
+% 
+Fair value adjustments of cash-settled stock appreciation rights 
+442 
+— 
+442 
+100 
+% 
+Total G&A expenses 
+$45,331 
+$35,293 
+$10,038 
+28 
+% 
+Merger and integration expense. For the year ended December 31, 2019 , the Company incurred $74.4 million of expenses associated with the Carrizo Acquisition. See “ Note 4 – Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for additional information regarding the merger with Carrizo. 
+Settled share-based awards. During the first quarter of 2019, the Company settled certain of the outstanding share-based award agreements of two former officers of the Company, resulting in $3.0 million recorded on the consolidated statements of operations. 
+Other Income and Expenses 
+Years Ended December 31, 
+2019 
+2018 
+$ Change 
+% Change 
+(In thousands, except % amounts) 
+Interest expense 
+$81,399 
+$58,651 
+$22,748 
+39 
+% 
+Capitalized interest 
+(78,492 
+) 
+(56,151 
+) 
+(22,341 
+) 
+40 
+% 
+Interest expense, net of capitalized amounts 
+2,907 
+2,500 
+407 
+16 
+% 
+(Gain) loss on derivative contracts 
+$62,109 
+($48,544 
+) 
+$110,653 
+(228 
+%) 
+໿ 
+Interest expense, net of capitalized amounts. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under our Credit Facility or with term debt. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to our lender in interest expense, net of capitalized amounts. In addition, we 
+46 
+include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees in interest expense. 
+Interest expense, net of capitalized amounts, incurred during the year ended December 31, 2019 increased $0.4 million to $2.9 million compared to $2.5 million for the same period of 2018 . 
+Loss on extinguishment of debt. During December 2019, in connection with the Carrizo Acquisition, we entered into a new credit facility and simultaneously terminated our prior credit facility. As a result of terminating the prior credit facility, we recorded a loss on extinguishment of debt of $4.9 million , which was comprised solely of the write-off of unamortized deferred financing costs associated with the prior credit facility. See “ Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information. 
+Gain (loss) on derivative contracts. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in commodity prices. This amount represents the (i) gain (loss) related to fair value adjustments on our open derivative contracts and (ii) gains (losses) on settlements of derivative contracts for positions that have settled within the period. 
+For the year ended December 31, 2019 , the net loss on derivative contracts was $62.1 million , compared to a $48.5 million net gain in 2018 . The net gain (loss) on derivative contracts for the periods indicated includes the following: 
+໿ 
+Years Ended December 31, 
+ 
+2019 
+2018 
+Change 
+(In thousands) 
+Oil derivatives 
+Net gain (loss) on settlements 
+($11,188 
+) 
+($27,510 
+) 
+$16,322 
+Net gain (loss) on fair value adjustments 
+(62,125 
+) 
+72,973 
+(135,098 
+) 
+Total gain (loss) on oil derivatives 
+($73,313 
+) 
+$45,463 
+($118,776 
+) 
+Natural gas derivatives 
+Net gain (loss) on settlements 
+$7,399 
+$238 
+$7,161 
+Net gain (loss) on fair value adjustments 
+1,490 
+2,843 
+(1,353 
+) 
+Total gain (loss) on natural gas derivatives 
+$8,889 
+$3,081 
+$5,808 
+Contingent consideration arrangements 
+Net gain (loss) on fair value adjustments 
+$2,315 
+$— 
+$2,315 
+Total gain (loss) on derivative contracts 
+($62,109 
+) 
+$48,544 
+($110,653 
+) 
+See “ Note 8 - Derivative Instruments and Hedging Activities” and “ Note 9 - Fair Value Measurements” of the Notes to our Consolidated Financial Statements for additional information. 
+Income tax expense. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. When appropriate based on our analysis, we record a valuation allowance for deferred tax assets when it is more likely than not that the deferred tax assets will not be realized. 
+The Company recorded income tax expense of $35.3 million for the year ended December 31, 2019 compared to $8.1 million for the same period of 2018 . The change in income tax is primarily related to the change in the Company’s tax position in the current period, as the Company no longer maintains a valuation allowance against its deferred tax assets. Current period income tax expense is comprised of both deferred federal and state income tax expense. 
+Preferred stock dividends. Holders of our Preferred Stock were entitled to receive, when, as and if declared by our Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10% per annum of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share). 
+Preferred stock dividends for the year ended December 31, 2019 decreased 45% to $4.0 million compared to $7.3 million in 2018 . The decrease is attributable to the redemption of our preferred stock in July 2019. See “ Note 11 – Stockholders’ Equity” of the Notes to our Consolidated Financial Statements for additional information. 
+Loss on redemption of preferred stock. As a result of the redemption of our Preferred Stock mentioned above, we recognized an $8.3 million loss due to the excess of the $73.0 million redemption price over the $64.7 million redemption date carrying value. See “ Note 11 – Stockholders’ Equity” of the Notes to our Consolidated Financial Statements for additional information. 
+47 
+Liquidity and Capital Resources 
+Our primary uses of capital have historically been for the acquisition, development, and exploration of oil and natural gas properties. Our capital program could vary depending upon factors, including, but not limited to, the availability of drilling rigs and completion crews, the cost of completion services, acquisitions and divestitures of oil and gas properties, land and industry partner issues, our available cash flow and financing, success of drilling programs, weather delays, commodity prices, market conditions, the acquisition of leases with drilling commitments and other factors. 
+Historically, our primary sources of capital have been cash flows from operations, borrowings under our revolving credit facility, proceeds from the issuance of debt securities and public equity offerings, and non-core asset dispositions. As we pursue reserves and production growth, we regularly consider which resources, including debt and equity financings, are available to meet our future financial obligations, planned capital expenditures and liquidity requirements. 
+Overview of Cash Flow Activities. For the year ended December 31, 2019 , cash and cash equivalents decreased $2.7 million to $13.3 million compared to $16.1 million at December 31, 2018 . 
+Years Ended December 31, 
+2019 
+2018 
+(In thousands) 
+Net cash provided by operating activities 
+$476,316 
+$467,654 
+Net cash used in investing activities 
+(388,389 
+) 
+(1,324,057 
+) 
+Net cash provided by (used in) financing activities 
+(90,637 
+) 
+844,459 
+Net change in cash and cash equivalents 
+($2,710 
+) 
+($11,944 
+) 
+Operating activities. Net cash provided by operating activities was $476.3 million and $467.7 million for the years ended December 31, 2019 and 2018, respectively. The change in operating activities was predominantly attributable to the following: 
+• 
+An increase in revenue due to higher production volumes, offset by a decrease in realized pricing; 
+• 
+An offsetting increase in operating expenses as a result of higher production volumes; 
+• 
+An offsetting increase in cash G&A expense due to increase personnel costs, and; 
+• 
+Changes related to timing of working capital payments and receipts. 
+Production, realized prices, and operating expenses are discussed below in Results of Operations. See “ Note 8 – Derivative Instruments and Hedging Activities” and “Note 9 – Fair Value Measurements” of the Notes to our Consolidated Financial Statements for a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation. 
+Investing activities. Net cash used in investing activities was $388.4 million and $1,324.1 million for the years ended December 31, 2019 and 2018, respectively. The change in investing activities was primarily attributable to the following: 
+• 
+A $285.4 million increase in proceeds received from the sale of non-core assets as compared to the year ended December 31, 2018. 
+• 
+A $676.5 million decrease in acquisitions. 
+• 
+A $29.4 million increase in capital expenditures due to increased activity from our 2019 development program, focused on multi-well pads, as well as additional investments in facilities and infrastructure. 
+Our investing activities, on a cash basis, include the following for the periods indicated: 
+Years Ended December 31, 
+2019 
+2018 
+$ Change 
+(In thousands) 
+Operational expenditures 
+$520,614 
+$537,514 
+($16,900 
+) 
+Seismic, leasehold and other 
+8,984 
+8,555 
+429 
+Capitalized general and administrative costs 
+31,612 
+24,383 
+7,229 
+Capitalized interest 
+79,330 
+40,721 
+38,609 
+Total capital expenditures (1) 
+$640,540 
+$611,173 
+$29,367 
+Acquisitions 
+$42,266 
+$718,793 
+($676,527 
+) 
+Proceeds from the sale of assets 
+(294,417 
+) 
+(9,009 
+) 
+(285,408 
+) 
+Additions to other assets 
+— 
+3,100 
+(3,100 
+) 
+Total investing activities 
+$388,389 
+$1,324,057 
+($935,668 
+) 
+(1) 
+Includes activity from the Carrizo Acquisition subsequent to the December 20, 2019 closing date. 
+48 
+On an accrual basis, which is the methodology used for establishing our annual capital budget, operational expenditures for the year ended December 31, 2019 were $506.1 million . Inclusive of seismic, leasehold and other, capitalized general and administrative, and capitalized interest costs, total capital expenditures for the year ended December 31, 2019 were $629.7 million . 
+General and administrative expenses and capitalized interest are discussed below in Results of Operations. See “ Note 4 – Acquisitions and Divestitures” and “ Note 17 – Commitments and Contingencies” of the Notes to our Consolidated Financial Statements for additional information on significant acquisitions and drilling rig leases. 
+Financing activities. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under our credit facility, term debt and equity offerings. For the year ended December 31, 2019 , net cash used in financing activities was $90.6 million compared to net cash provided by financing activities of $844.5 million during the same period of 2018 . The change in net cash provided by (used in) financing activities was primarily attributable to the following: 
+• 
+Repayment of Carrizo’s credit facility and funded the redemption of preferred stock upon closing the Carrizo Acquisition. 
+• 
+Redemption of Preferred Stock for approximately $73.0 million in 2019. 
+• 
+Completed an underwritten public offering of 25.3 million shares of common stock for total estimated net proceeds of approximately $288.0 million in 2018. 
+• 
+Issuance of Senior Notes due 2026, as defined below, for $394.0 million in net proceeds in 2018 in conjunction with the Delaware Asset Acquisition. 
+Net cash provided by (used in) financing activities includes the following for the periods indicated: 
+ 
+Years Ended December 31, 
+ 
+2019 
+2018 
+$ Change 
+(In thousands) 
+Net borrowings on Credit Facility 
+$1,560,400 
+$175,000 
+$1,385,400 
+Repayment of Prior Credit Facility 
+(475,400 
+) 
+— 
+(475,400 
+) 
+Repayment of Carrizo credit facility 
+(853,549 
+) 
+— 
+(853,549 
+) 
+Repayment of Carrizo preferred stock 
+(220,399 
+) 
+— 
+(220,399 
+) 
+Issuance of 6.375% Senior Notes due 2026 
+— 
+400,000 
+(400,000 
+) 
+Issuance of common stock 
+— 
+287,988 
+(287,988 
+) 
+Payment of preferred stock dividends 
+(3,997 
+) 
+(7,295 
+) 
+3,298 
+Redemption of preferred stock 
+(73,017 
+) 
+— 
+(73,017 
+) 
+Payment of deferred financing costs 
+(22,480 
+) 
+(9,430 
+) 
+(13,050 
+) 
+Tax withholdings related to restricted stock units 
+(2,195 
+) 
+(1,804 
+) 
+(391 
+) 
+Net cash provided by (used in) financing activities 
+($90,637 
+) 
+$844,459 
+($935,096 
+) 
+See “ Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information about the Company’s debt. See “ Note 11 – Stockholders’ Equity” of the Notes to our Consolidated Financial Statements for additional information about the Company’s equity offerings and the redemption of our Preferred Stock. 
+Senior Secured Credit Facility. Upon consummation of the Merger on December 20, 2019, the Company terminated the Sixth Amended and Restated Credit Agreement to the Credit Facility (the “Prior Credit Facility”) and entered into the credit agreement with a syndicate of lenders (the “Credit Facility”). The Credit Facility provides for interest-only payments until December 20, 2024 (subject to springing maturity dates of (i) January 14, 2023 if the 6.25% Senior Notes are outstanding at such time and (ii) July 2, 2024 if the 6.125% Senior Notes are outstanding at such time), when the Credit Facility matures and any outstanding borrowings are due. The maximum credit amount under the Credit Facility is $5.0 billion . The borrowing base under the Credit Facility is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. The capitalized terms which hare not defined in this description of the revolving credit facility shall have the meaning given to such terms in the credit agreement. 
+As of December 31, 2019, the borrowing base under the Credit Facility was $2.5 billion , with an elected commitment amount of $2.0 billion, and borrowings outstanding of $1.3 billion . The weighted average interest rate of our outstanding borrowings was 3.56% . The Company also had $17.7 million in letters of credit outstanding under the Credit Facility as of December 31, 2019. 
+Effective April 5, 2018 , the Company entered into the first amendment to the Prior Credit Facility, as defined below, which (1) increased the borrowing base to $825.0 million , (2) increased the elected commitment amount to $650.0 million , (3) amended various covenants and terms to reflect current market trends, and (4) extended the maturity date to May 25, 2023 . 
+Effective September 27, 2018 , the Company entered into the second amendment to the Prior Credit Facility, which (1) increased the borrowing base to $1.1 billion , (2) increase the elected commitment amount to $850.0 million , and (3) amended various covenants and terms to reflect current market trends. 
+49 
+Each of the first and second amendments to the Prior Credit Facility were terminated in conjunction with the termination of the Prior Credit Facility. 
+See “ Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information. 
+Senior Notes 
+Upon consummation of the Merger, we became successor-in-interest to the indenture governing Carrizo’s 8.25% Senior Notes due 2025 (the “ 8.25% Senior Notes”) and the 6.25% Senior Notes due 2023 (the “ 6.25% Senior Notes”). Both the 8.25% Senior Notes and the 6.25% Senior Notes are guaranteed on a senior unsecured basis by our wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The assumed Senior Notes are described below along with Callon’s legacy Senior Notes. 
+6.375% Senior Notes. On June 7, 2018 , we issued $400.0 million aggregate principal amount of 6.375% Senior Notes due 2026 (the “ 6.375% Senior Notes”), which mature on July 1, 2026 and have interest payable semi-annually each January 1 and July 1. The net proceeds from the offering of approximately $394.0 million, after deducting initial purchasers’ discounts and estimated offering expenses, were used to fund a portion of the Delaware Asset Acquisition, described below. The 6.375% Senior Notes are guaranteed on a senior unsecured basis by our wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The subsidiary guarantor is 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor. 
+6.125% Senior Notes. On October 3, 2016, we issued $400.0 million aggregate principal amount of 6.125% Senior Notes with a maturity date of October 1, 2024 and interest payable semi-annually each April 1 and October 1. The 6.125% Senior Notes are guaranteed on a senior unsecured basis by our wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. On May 19, 2017, we issued an additional $200.0 million aggregate principal amount of 6.125% Senior Notes which, with the existing $400.0 million aggregate principal amount of 6.125% Senior Notes, are treated as a single class of notes under the indenture. 
+8.25% Senior Notes. The 8.25% Senior Notes have an aggregate principal amount of $250.0 million, mature on July 15, 2025 and have interest payable semi-annually each January 15 and July 15. Before July 15, 2020, we may, at our option, redeem all or a portion of the 8.25% Senior Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, we may redeem all or a portion of the 8.25% Senior Notes at redemption prices decreasing annually from 106.188% to 100% of the principal amount redeemed plus accrued and unpaid interest. 
+6.25% Senior Notes. The 6.25% Senior Notes have an aggregate principal amount of $650.0 million, mature on April 15, 2023 and have interest payable semi-annually each April 15 and October 15. We may redeem all or a portion of the 6.25% Senior Notes at redemption prices decreasing from 103.125% to 100% of the principal amount on April 15, 2021, plus accrued and unpaid interest. 
+See “ Note 7 - Borrowings” of the Notes to our Consolidated Financial Statements for additional information about our Senior Notes. 
+Preferred Stock. Holders of the Preferred Stock were entitled to receive, when, as and if declared by the Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10% per annum of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share). Dividends were payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by the Board of Directors. Preferred Stock dividends were $4.0 million and $7.3 million for the years ended December 31, 2019 and 2018 , respectively. 
+On June 18, 2019, we announced we had given notice for the redemption (the “Redemption”) of all outstanding shares of the Preferred Stock. On July 18, 2019 (the “Redemption Date”), the Preferred Stock were redeemed at a redemption price equal to $50.00 per share, plus an amount equal to all accrued and unpaid dividends in an amount equal to $0.24 per share, for a total redemption price of $50.24 per share or $73.0 million (the “Redemption Price”). We recognized an $8.3 million loss on the redemption due to the excess of the $73.0 million redemption price over the $64.7 million redemption date carrying value of the Preferred Stock. 
+After the Redemption Date, the Preferred Stock were no longer deemed outstanding, dividends on the Preferred Stock ceased to accrue, and all rights of the holders with respect to such Preferred Stock were terminated, except the right of the holders to receive the Redemption Price, without interest. 
+See “ Note 11 - Stockholders’ Equity” of the Notes to our Consolidated Financial Statements for additional discussion. 
+50 
+2020 Capital Plan and Outlook 
+Our 2020 Capital Budget has been established at $975.0 million, which includes running an average of eight to nine drilling rig sand an average of three completion crews. Approximately 10-15% of the 2020 Capital Budget is comprised of infrastructure and facilities capital. As part of our 2020 operated horizontal drilling program, we expect to drill approximately 165 gross operated wells and complete approximately 160 gross operated wells. We currently expect to direct the majority of our 2020 Capital Budget towards opportunities in the Permian Basin. Additionally, we may consider divesting certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth, provided we are able to divest such assets on terms that are acceptable to us. 
+Our revenues, earnings, liquidity and ability to grow are substantially dependent on the prices we receive for, and our ability to develop our proved reserves. We believe the long-term outlook for our business is favorable due to our resource base, low cost structure, financial strength, risk management, and disciplined investment of capital. We monitor current and expected market conditions, including the commodity price environment, and our liquidity needs and may adjust our capital investment plan accordingly. 
+Contractual Obligations 
+The following table includes our current contractual obligations and purchase commitments as of December 31, 2019 : 
+Payments due by Period 
+< 1 Year 
+Years 2 - 3 
+Years 4 - 5 
+> 5 Years 
+Total 
+(In thousands) 
+6.25% Senior Notes (1) 
+$— 
+$— 
+$650,000 
+$— 
+$650,000 
+6.125% Senior Notes (1) 
+— 
+— 
+600,000 
+— 
+600,000 
+8.25% Senior Notes (1) 
+— 
+— 
+— 
+250,000 
+250,000 
+6.375% Senior Notes (1) 
+— 
+— 
+— 
+400,000 
+400,000 
+Credit Facility (2) 
+— 
+— 
+1,285,000 
+— 
+1,285,000 
+Interest expense and other fees related to debt commitments (3) 
+172,821 
+345,642 
+283,218 
+71,625 
+873,306 
+Drilling rig leases (4) 
+33,441 
+3,249 
+— 
+— 
+36,690 
+Operating leases 
+12,423 
+12,762 
+8,319 
+17,902 
+51,406 
+Delivery commitments (5) 
+9,563 
+24,417 
+23,970 
+39,298 
+97,248 
+Produced water disposal commitments (6) 
+14,947 
+26,901 
+5,957 
+1,840 
+49,645 
+Asset retirement obligations (7) 
+468 
+314 
+565 
+48,386 
+49,733 
+Other commitments 
+1,240 
+844 
+159 
+— 
+2,243 
+Total contractual obligations 
+$244,903 
+$414,129 
+$2,857,188 
+$829,051 
+$4,345,271 
+(1) 
+Includes the outstanding principal amount only. 
+(2) 
+The Credit Facility has a maturity date of December 20, 2024, subject to springing maturity dates as discussed above. See “ Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information. 
+(3) 
+Includes estimated cash payments on the 6.25% Senior Notes, 6.125% Senior Notes, 8.25% Senior Notes, 6.375% Senior Notes, the Credit Facility and commitment fees calculated based on the unused portion of lender commitments as of December 31, 2019, at the applicable commitment fee rate. 
+(4) 
+Drilling rig leases represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a party on December 31, 2019 . The value in the table represents the gross amount that we are committed to pay. However, we will record our proportionate share based on our working interest in our consolidated financial statements as incurred. See “ Note 17 – Commitments and Contingencies” of the Notes to our Consolidated Financial Statements for additional information related to the Company’s drilling rig leases. 
+(5) 
+Delivery commitments represent contractual obligations we have entered into for certain gathering, processing and transportation service agreements which require minimum volumes of natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any natural gas. 
+(6) 
+Produced water disposal commitments represent contractual obligations we have entered into for certain service agreements which require minimum volumes of produced water to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water. 
+(7) 
+Amounts represent our estimates of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See “ Note 14 – Asset Retirement Obligations” of the Notes to our Consolidated Financial Statements for additional information. 
+51 
+Other commitments 
+In July 2019, the Company executed a crude oil sales contract that provides dedicated capacity on a new pipeline system that originates in Midland County, Texas and will have delivery points in several locations along the Gulf Coast. We will have a long-term 5,000 Bbls per day commitment for the term of the agreement and will apply applicable tariff rates to those quantities. Barrels may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. 
+In June 2019, the Company executed a firm transportation agreement for dedicated capacity on a new pipeline system that originates in Midland, Texas and terminates in Houston, Texas. Subject to completion of the new pipeline system, which will have delivery points in several locations along the Gulf Coast, we will have a long-term commitment that will apply applicable tariff rates to our quantities committed that average 10,000 Bbls per day for the term of the agreement. Barrels may be transported to multiple delivery points along the Gulf Coast and may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. 
+In January 2019, the Company executed a crude oil sales contract that provides further dedicated capacity on several pipeline systems that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard and Ward counties, Texas and will have delivery points in several locations along the Gulf Coast, providing the Company with the potential benefit of access to an international weighted average sales price. We will have a long-term 10,000 Bbls per day commitment for the term of the agreement, and may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. 
+In August 2018, the Company executed a firm transportation agreement for dedicated capacity on a new pipeline system that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard and Ward counties, Texas to multiple marketing points in the Permian Basin. Subject to completion of the new pipeline system, which will have delivery points in several locations along the Gulf Coast, we will have a long-term commitment that will apply applicable tariff rates to our 15,000 Bbls per day commitment for the term of the agreement. Barrels may be transported to multiple delivery points along the Gulf Coast and may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. 
+In March 2018, the Company entered into a contract for dedicated fracturing and pump down perforating crews, which was effective on April 16, 2018 for a two -year period. The agreement was amended effective October 16, 2018 to reflect updated market conditions and to extend the contract expiration date to December 31, 2021. 
+52 
+Summary of Critical Accounting Policies 
+The following summarizes our critical accounting policies. See a complete list of significant accounting policies in “ Note 2 – Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements. 
+Use of Estimates 
+The preparation of financial statements in conformity with GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating DD&A of proved oil and natural gas property costs, the present value of estimated future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated timing of cash outflows underlying asset retirement obligations. There are numerous uncertainties inherent in the estimation of proved oil and gas reserves and in the projection of future rates of production and the timing of development expenditures. Other significant estimates are involved in determining asset retirement obligations, acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of commodity derivative assets and liabilities, fair values of contingent consideration arrangements, grant date fair value of stock-based awards, and contingency, litigation, and environmental liabilities. Actual results could differ from those estimates. 
+Oil and natural gas properties 
+Oil and natural gas properties are accounted for using the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration and development activities are capitalized as oil and gas properties. The internal cost of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities are capitalized to either evaluated or unevaluated oil and gas properties based on the type of activity. Internal costs related to production and similar activities are expensed as incurred. 
+Proceeds from the sale or disposition of evaluated and unevaluated oil and gas properties are accounted for as a reduction of evaluated oil and gas property costs, unless the sale significantly alters the relationship between capitalized costs and proved reserves in which case a gain or loss is recognized. For the years ended December 31, 2019 and 2018, we did not have any sales of oil and gas properties that significantly altered such relationship. 
+Capitalized oil and gas property costs within a cost center are amortized on an equivalent unit-of-production method, converting natural gas to barrels of oil equivalent at the ratio of six thousand cubic feet of gas to one barrel of oil, which represents their approximate relative energy content. The equivalent unit-of-production amortization rate is computed on a quarterly basis by dividing current quarter production by proved oil and gas reserves at the beginning of the quarter then applying such amortization rate to evaluated oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. 
+Excluded from this amortization are costs associated with unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties or we determine that these costs have been impaired. We assesses properties on an individual basis or as a group and considers the following factors, among others, to determine if these costs have been impaired: exploration program and intent to drill, remaining lease term, and the assignment of proved reserves. Geological and geophysical costs not associated with specific prospects are recorded to evaluated oil and gas property costs as incurred. The amount of interest costs capitalized is determined on a quarterly basis based on the average balance of unproved properties and the weighted average interest rate of outstanding borrowings. Capitalized interest cannot exceed gross interest expense. 
+Write-down of Evaluated Properties 
+At the end of each quarter, the net book value of oil and gas properties, less related deferred income taxes, are limited to the “cost center ceiling” equal to (i) the sum of (a) the present value of estimated future net revenues from proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves computed using a discount factor of 10%, (b) the costs of unevaluated properties not being amortized, and (c) the lower of cost or estimated fair value of unevaluated properties included in the costs being amortized; less (ii) related income tax effects. Any excess of the net book value of oil and gas properties, less related deferred income taxes, over the cost center ceiling is recognized as an write-down of evaluated oil and gas properties. A write-down recognized in one period may not be reversed in a subsequent period even if higher commodity prices in the future result in a cost center ceiling in excess of the net book value of oil and gas properties, less related deferred income taxes. 
+The estimated future net revenues used in the cost center ceiling are calculated using the 12-Month Average Realized Price, held flat for the life of the production, except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of commodity derivative instruments as we elected not to meet the criteria to qualify for hedge accounting treatment. 
+53 
+Details of the 12-Month Average Realized Price of crude oil for the years ended December 31, 2019 and 2018 are summarized in the table below: 
+Years Ended December 31, 
+2019 
+2018 
+Write-down of evaluated oil and natural gas properties (In thousands) 
+$— 
+$— 
+Crude Oil 12-Month Average Realized Price ($/Bbl) - Beginning of period 
+$58.40 
+$49.48 
+Crude Oil 12-Month Average Realized Price ($/Bbl) - End of period 
+$53.90 
+$58.40 
+Crude Oil 12-Month Average Realized Price percentage increase (decrease) 
+(8%) 
+18% 
+The table below presents various pricing scenarios to demonstrate the sensitivity of our December 31, 2019 cost center ceiling to changes in 12-month average benchmark crude oil and natural gas prices underlying the 12-Month Average Realized Prices. The sensitivity analysis is as of December 31, 2019 and, accordingly, does not consider drilling and completion activity, acquisitions or dispositions of oil and gas properties, production, changes in crude oil and natural gas prices, and changes in development and operating costs occurring subsequent to December 31, 2019 that may require revisions to estimates of proved reserves. See also Part I, “Item 1A. Risk Factors—If oil and natural gas prices remain depressed for extended periods of time, we could be required to make significant downward adjustments to the carrying value of our oil and natural gas properties.” 
+12-Month Average 
+Realized Prices 
+Excess of cost center ceiling over net book value, less related deferred income taxes 
+Increase (decrease) of cost center ceiling over net book value, less related deferred income taxes 
+Full Cost Pool Scenarios 
+Crude Oil 
+($/Bbl) 
+Natural Gas 
+($/Mcf) 
+(In millions) 
+(In millions) 
+December 31, 2019 Actual 
+$53.90 
+$1.55 
+$631 
+Crude Oil and Natural Gas Price Sensitivity 
+Crude Oil and Natural Gas +10% 
+$59.47 
+$1.85 
+$1,456 
+$825 
+Crude Oil and Natural Gas -10% 
+$48.33 
+$1.25 
+($369) 
+($1,000) 
+Crude Oil Price Sensitivity 
+Crude Oil +10% 
+$59.47 
+$1.55 
+$1,378 
+$747 
+Crude Oil -10% 
+$48.33 
+$1.55 
+($270) 
+($901) 
+Natural Gas Price Sensitivity 
+Natural Gas +10% 
+$53.90 
+$1.85 
+$702 
+$71 
+Natural Gas -10% 
+$53.90 
+$1.25 
+$546 
+($85) 
+We estimate that the first quarter of 2020 cost center ceiling will exceed the net book value, less related deferred income taxes, resulting in no write-down of evaluate oil and gas properties. This estimate of the first quarter of 2020 cost center ceiling test is based on an estimated 12-Month Average Realized Price of crude oil of $56.09 per barrel as of March 31, 2020, which is based on the average realized price for sales of crude oil on the first calendar day of each month for the first 11 months and an estimate for the twelfth month based on a quoted forward price. 
+Both of these estimates assume that all other inputs and assumptions are as of December 31, 2019, other than the price of crude oil, and remain unchanged. As such, drilling and completion activity, acquisitions or dispositions of oil and gas properties, production, and changes in development and operating costs occurring subsequent to December 31, 2019 may require revisions to estimates of proved reserves, which would impact the calculation of the cost center ceiling. 
+Estimating reserves and present value of estimated future net cash flows 
+Estimates of quantities of proved oil and natural gas reserves, including the discounted present value of estimated future net cash flows from such reserves at the end of each quarter, are based on numerous assumptions, which are likely to change over time. These assumptions include: 
+• 
+the prices at which the Company can sell its production in the future. Oil, natural gas, and NGL prices are volatile, but we are required to assume that they remain constant, using the 12-Month Average Realized Price. In general, higher oil, natural gas, and NGL prices will increase quantities of estimated proved reserves and the present value of estimated future net cash flows from such reserves, while lower prices will decrease these amounts; and 
+54 
+• 
+the costs to develop and produce the Company’s reserves and the costs to dismantle its production facilities when reserves are depleted. These costs are likely to change over time, but we are required to assume that they remain constant. Increases in costs will reduce estimated proved reserves and the present value of estimated future net cash flows, while decreases in costs will increase such amounts. 
+Changes in these prices and/or costs will affect the present value of estimated future net cash flows more than the estimated proved reserves for the Company’s properties that have relatively short productive lives. If oil, natural gas, and NGL prices remain at current levels or decline further, it will have a negative impact on the present value of estimated future net cash flows and the estimated quantities of proved reserves. 
+In addition, the process of estimating proved oil and natural gas reserves requires that the Company’s independent and internal reserve engineers exercise judgment based on available geological, geophysical and technical information. We have described the risks associated with reserve estimation and the volatility of oil and natural gas prices under Part I, “Item 1A. Risk Factors.” 
+Asset retirement obligations 
+We record an estimate of the fair value of liabilities for obligations associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Estimates involved in determining asset retirement obligations include the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a credit-adjusted risk-free discount rate and an inflation factor in order to determine the present value of the asset retirement obligation. The present value of the asset retirement obligations is accreted each period and the increase to the obligation is reported in “Depreciation, depletion and amortization” in the consolidated statements of operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to evaluated properties in the consolidated balance sheets. See “ Note 14 - Asset Retirement Obligations” of the Notes to our Consolidated Financial Statements for additional information. 
+Estimating the future plugging and abandonment costs of wells and related facilities requires management to make estimates and judgments because most of the obligations are many years in the future and asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. 
+Derivative Instruments 
+To manage oil and natural gas price risk on a portion of our planned future production, we have historically utilized commodity derivative instruments (including collars, swaps, put and call options and other structures) on approximately 40% to 60% of our projected production volumes in any given year. We do not use these instruments for speculative purposes. Settlements of derivative contracts are generally based on the difference between the contract price and prices specified in the derivative instrument and a NYMEX price or other futures index price. 
+Our derivative positions are carried at their fair value on the balance sheet with changes in fair value recorded through earnings. The estimated fair value of our derivative contracts is based upon current forward market prices on NYMEX and in the case of collars and floors, the time value of options. For additional information regarding derivatives and their fair values, see “ Note 8 - Derivative Instruments and Hedging Activities” and “ Note 9 - Fair Value Measurements” of the Notes to our Consolidated Financial Statements and “Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk - Commodity Price Risk”. 
+Income taxes 
+The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices). The Company had no valuation allowance as of December 31, 2019 and 2018. See “ Note 12 - Income Taxes” of the Notes to our Consolidated Financial Statements for additional information regarding income taxes. 
+Accounting Standards Updates 
+See “ Note 2 - Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements for information discussion of recent accounting pronouncements issued by the Financial Accounting Standards Board. 
+Off-balance Sheet Arrangements 
+We had no off-balance sheet arrangements as of December 31, 2019 . 
+55 
+ITEM 7A. Quantitative and Qualitative Disclosures about Market Risk 
+We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer credit risk. We mitigate these risks through a program of risk management including the use of commodity derivative instruments. 
+Commodity price risk 
+The Company’s revenues are derived from the sale of its oil and natural gas production. The prices for oil and natural gas remain volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and government actions. From time to time, the Company enters into derivative financial instruments to manage oil and natural gas price risk, related both to NYMEX benchmark prices and regional basis differentials. The total volumes which we hedge through use of our derivative instruments varies from period to period; however, generally our objective is to hedge approximately 40% to 60% of our anticipated internally forecast production for the next 12 to 24 months, subject to the covenants under our Credit Facility. Our hedge policies and objectives may change significantly with movements in commodities prices or futures prices. 
+As of December 31, 2019 , for the full year of 2020 , the Company had 18,017,900 Bbls of fixed price oil hedges across NYMEX WTI, ICE Brent and Argus WTI-Houston benchmarks. The Company also had 8,476,700 Bbls of WTI Midland-Cushing oil basis hedges and 1,439,205 Bbls of WTI Houston-Cushing oil basis hedges. Additionally, for the full year of 2020 , the Company had 7,320,000 MMBtus of fixed price NYMEX natural gas hedges and 21,596,000 MMBtus of Waha natural gas basis hedges. See “ Note 8 - Derivative Instruments and Hedging Activities” of the Notes to our Consolidated Financial Statements for a description of the Company’s outstanding derivative contracts as of December 31, 2019 . 
+The Company may utilize fixed price swaps, which reduce the Company’s exposure to decreases in commodity prices and limit the benefit the Company might otherwise have received from any increases in commodity prices. Swap contracts may also be enhanced by the simultaneous sale of call or put options to effectively increase the effective swap price as a result of the receipt of premiums from the option sales. 
+The Company may utilize price collars to reduce the risk of changes in oil and natural gas prices. Under these arrangements, no payments are due by either party as long as the applicable market price is above the floor price (purchased put option) and below the ceiling price (sold call option) set in the collar. If the price falls below the floor, the counter-party to the collar pays the difference to the Company, and if the price rises above the ceiling, the counterparty receives the difference from the Company. Additionally, the Company may sell put (or call) options at a price lower than the floor price (or higher than the ceiling price) in conjunction with a collar (three-way collar) and use the proceeds to increase either or both the floor or ceiling prices. In a three-way collar, to the extent that realized prices are below the floor price of the sold put option (or above the ceiling price of the sold call option), the Company’s net realized benefit from the three-way collar will be reduced on a dollar-for-dollar basis. 
+The Company may purchase put and call options, which reduce the Company’s exposure to decreases in oil and natural gas prices while allowing realization of the full benefit from any increases in oil and natural gas prices. If the price falls below the floor, the counterparty pays the difference to the Company. 
+The Company enters into these various agreements from time to time to reduce the effects of volatile oil and natural gas prices and does not enter into derivative transactions for speculative purposes. Presently, none of the Company’s derivative positions are designated as hedges for accounting purposes. 
+Interest rate risk 
+The Company is subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility. As of December 31, 2019 , the Company had $1.3 billion outstanding under the Credit Facility with a weighted average interest rate of 3.56% . An increase or decrease of 1.00% in the interest rate would have a corresponding increase or decrease in our annual net income of approximately $12.9 million based on the balance outstanding at December 31, 2019 . See “ Note 7 - Borrowings” of the Notes to our Consolidated Financial Statements for more information on the Company’s interest rates on our Credit Facility. 
+Counterparty and customer credit risk 
+The Company’s principal exposures to credit risk are through receivables from the sale of our oil and natural gas production, joint interest receivables and receivables resulting from derivative financial contracts. 
+The Company markets its oil and natural gas production to energy marketing companies. We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. For the year ended December 31, 2019 , four purchasers accounted for more than 10% of our revenue: Rio Energy International, Inc. ( 26% ); Enterprise Crude Oil, LLC ( 19% ); Plains Marketing, L.P. ( 15% ); and Shell Trading Company ( 10% ). The inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In order to mitigate potential exposure to credit risk, we may require from time to time for our customers to provide financial security. At December 31, 2019 our total receivables from the sale of our oil and natural gas production were approximately $165.3 million . 
+56 
+Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have or intend to drill. We have little ability to control whether these entities will participate in our wells. At December 31, 2019 , our joint interest receivables were approximately $42.5 million . 
+Our oil and natural gas commodity derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. Most of the counterparties on our commodity derivative instruments currently in place are lenders under our Credit Facility. We are likely to enter into additional commodity derivative instruments with these or other lenders under our Credit Facility, representing institutions with investment grade ratings. We have existing International Swap Dealers Association Master Agreements (“ISDA Agreements”) with our commodity derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of offset upon the occurrence of defined acts of default by either us or a counterparty to a commodity derivative, whereby the party not in default may offset all commodity derivative liabilities owed to the defaulting party against all commodity derivative asset receivables from the defaulting party. At December 31, 2019 , we had a net commodity derivative liability position of $24.8 million . 
+57 
+ITEM 8. Financial Statements and Supplementary Data 
+Page 
+Reports of Independent Registered Public Accounting Firm 
+59 
+Consolidated Balance Sheets as of December 31, 2019 and 2018 
+63 
+Consolidated Statements of Operations for the Years Ended December 31, 2019, 2018 and 2017 
+64 
+Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2019, 2018 and 2017 
+65 
+Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017 
+66 
+Notes to Consolidated Financial Statements 
+67 
+58 
+Report of Independent Registered Public Accounting Firm 
+Board of Directors and Stockholders 
+Callon Petroleum Company 
+Opinion on the financial statements 
+We have audited the accompanying consolidated balance sheets of Callon Petroleum Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2019 and 2018, the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 28, 2020 expressed an unqualified opinion. 
+Change in accounting principle 
+As discussed in Note 2 to the consolidated financial statements, the Company has changed its method of accounting for leases in the year ended December 31, 2019 due to the adoption of FASB Accounting Standards Codification Topic 842, Leases . 
+Basis for opinion 
+These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. 
+Critical Audit Matters 
+T he critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. 
+Depletion expense and impairment of oil and gas properties impacted by the Company’s estimation of proved reserves 
+As described further in Note 2 to the financial statements, the Company accounts for its oil and gas properties using the full cost method of accounting which requires management to make estimates of proved reserve volumes and future net revenues to record depletion expense and assess its oil and gas properties for potential impairment. To estimate the volume of proved reserves and future net revenue, management makes significant estimates and assumptions including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected with reasonable certainty to be economical under the appropriate pricing assumptions required in the estimation of depletion expense and potential impairment assessment. We identified the estimation of proved reserves of oil and gas properties as a critical audit matter. 
+59 
+The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain inputs and assumptions, which require a high degree of subjectivity, necessary to estimate the volume and future net revenues of the Company’s proved reserves could have a significant impact on the measurement of depletion expense and potential impairment. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment. 
+Our audit procedures related to the estimation of proved reserves included the following, among others. 
+• 
+We tested the design and operating effectiveness of controls relating to management’s estimation of proved reserves for the purpose of estimating depletion expense and assessing the Company’s oil and gas properties for potential impairment. 
+• 
+We evaluated the independence, objectivity, and professional qualifications of the Company’s reserve engineers, made inquiries of those specialists regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the reserve report prepared by the Company’s specialists. 
+• 
+To the extent key inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, including, but not limited to: historical pricing differentials, operating costs, estimated capital costs, and ownership interests, we tested management’s process for determining the assumptions, including examining the underlying support on a sample basis. Specifically, our audit procedures involved testing management’s assumptions by performing the following: 
+• 
+Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials; 
+• 
+Tested models used to estimate the future operating costs in the reserve report and compared amounts to historical operating costs; 
+• 
+Evaluated the method used to determine the future capital costs and compared estimated future capital expenditures used in the reserve report to amounts expended for recently drilled and completed wells; 
+• 
+Tested the working and net revenue interests used in the reserve report by inspecting land and division order records; 
+• 
+Evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s ability to fund and intent to develop the proved undeveloped properties; and 
+• 
+Applied analytical procedures to the reserve report forecasted production by comparing to historical actual results, and to the prior year reserve report. 
+Fair value of oil and gas properties acquired impacted by the Company’s estimation of proved reserves 
+As described in Note 4 to the financial statements, the Company acquired Carrizo Oil & Gas, Inc. which requires management to make estimates of fair values associated with proved reserve volumes. To estimate the volume of proved reserves and future net revenue, management makes significant estimates and assumptions including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected with reasonable certainty to be economical under the appropriate pricing assumptions required in the estimation of fair value. We identified the estimation of proved reserves of oil and gas properties acquired as a critical audit matter. 
+The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain inputs and assumptions, which require a high degree of subjectivity, necessary to estimate the volume and future net revenues of the Company’s proved reserves could have a significant impact on the measurement of fair value. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment. 
+Our audit procedures related to the estimation of proved reserves included the following, among others. 
+• 
+We tested the design and operating effectiveness of controls relating to management’s estimation of proved reserves for the purpose of estimating the fair value assigned to proved properties. 
+• 
+We evaluated the independence, objectivity, and professional qualifications of the Company’s reserve engineers, made inquiries of those specialists regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the reserve report prepared by those specialists. 
+• 
+We evaluated the independence, objectivity, and professional qualifications of the Company’s valuation specialists, made inquiries of those valuation specialists regarding the process followed and judgments made to determine the fair value associated with proved reserve volumes, and read the valuation report prepared by the external specialists. 
+60 
+• 
+To the extent key sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records or other third party information, including, but not limited to: historical pricing differentials, operating costs, estimated capital costs, and ownership interests, we tested management’s process for determining the assumptions, including examining the underlying support on a sample basis. Specifically, our audit procedures involved testing management’s assumptions by performing the following: 
+• 
+Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials; 
+• 
+Tested models used to estimate the future operating costs in the acquisition reserve report and compared amounts to historical operating costs; 
+• 
+Evaluated the method used to determine the future capital costs and compared estimated future capital expenditures used in the valuation reserve report to amounts expended for recently drilled and completed wells; 
+• 
+Evaluated the working and net revenue interests used in the reserve report by inspecting land and division order records; 
+• 
+Evaluated the risk adjustments applied to proved reserve volumes by comparing against industry accepted factors; 
+• 
+Evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s ability to fund and intent to develop the proved undeveloped properties; and 
+• 
+Applied analytical procedures to the reserve report forecasted production by comparing to historical actual results, and to the prior year reserve report. 
+/s/ GRANT THORNTON LLP 
+We have served as the Company’s auditor since 2016. 
+Houston, Texas 
+February 28, 2020 
+61 
+Report of Independent Registered Public Accounting Firm 
+Board of Directors and Stockholders 
+Callon Petroleum Company 
+Opinion on internal control over financial reporting 
+We have audited the internal control over financial reporting of Callon Petroleum Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2019, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2019, and our report dated February 28, 2020 expressed an unqualified opinion on those financial statements. 
+Basis for opinion 
+The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s report on internal control over financial reporting (“Management’s Report”). Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+Our audit of, and opinion on, the Company’s internal control over financial reporting does not include the internal control over financial reporting of Carrizo Oil & Gas, Inc., a wholly-owned subsidiary, whose financial statements reflect total assets and revenues constituting 43 and 4 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2019. As indicated in Management’s Report, Carrizo Oil & Gas, Inc. was acquired during 2019. Management’s assertion on the effectiveness of the Company’s internal control over financial reporting excluded internal control over financial reporting of Carrizo Oil & Gas, Inc. 
+Definition and limitations of internal control over financial reporting 
+A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+/s/ GRANT THORNTON LLP 
+Houston, Texas 
+February 28, 2020 
+62 
+Callon Petroleum Company 
+Consolidated Balance Sheets 
+(In thousands, except par and share data) 
+December 31, 
+2019 
+2018 
+ASSETS 
+Current assets: 
+Cash and cash equivalents 
+$ 13,341 
+$ 16,051 
+Accounts receivable, net 
+209,463 
+131,720 
+Fair value of derivatives 
+26,056 
+65,114 
+Other current assets 
+19,814 
+9,740 
+Total current assets 
+268,674 
+222,625 
+Oil and natural gas properties, full cost accounting method: 
+Evaluated properties, net 
+4,682,994 
+2,314,345 
+Unevaluated properties 
+1,986,124 
+1,404,513 
+Total oil and natural gas properties, net 
+6,669,118 
+3,718,858 
+Operating lease right-of-use assets 
+63,908 
+— 
+Other property and equipment, net 
+35,253 
+21,901 
+Deferred tax asset 
+115,720 
+— 
+Deferred financing costs 
+22,233 
+6,087 
+Fair value of derivatives 
+9,216 
+— 
+Other assets, net 
+10,716 
+9,702 
+Total assets 
+$ 7,194,838 
+$ 3,979,173 
+LIABILITIES AND STOCKHOLDERS’ EQUITY 
+Current liabilities: 
+Accounts payable and accrued liabilities 
+$ 511,622 
+$ 285,849 
+Operating lease liabilities 
+42,858 
+— 
+Fair value of derivatives 
+71,197 
+10,480 
+Other current liabilities 
+26,570 
+18,587 
+Total current liabilities 
+652,247 
+314,916 
+Long-term debt 
+3,186,109 
+1,189,473 
+Operating lease liabilities 
+37,088 
+— 
+Asset retirement obligations 
+48,860 
+10,405 
+Deferred tax liability 
+— 
+9,564 
+Fair value of derivatives 
+32,695 
+7,440 
+Other long-term liabilities 
+14,531 
+2,167 
+Total liabilities 
+3,971,530 
+1,533,965 
+Commitments and contingencies 
+Stockholders’ equity: 
+Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation 
+preference, 2,500,000 shares authorized: 0 and 1,458,948 shares outstanding, 
+respectively 
+— 
+15 
+Common stock, $0.01 par value, 525,000,000 and 300,000,000 shares authorized, 
+respective; 396,600,022 and 227,582,575 shares outstanding, respectively 
+3,966 
+2,276 
+Capital in excess of par 
+3,198,076 
+2,477,278 
+Retained earnings (Accumulated deficit) 
+21,266 
+( 34,361 
+) 
+Total stockholders’ equity 
+3,223,308 
+2,445,208 
+Total liabilities and stockholders’ equity 
+$ 7,194,838 
+$ 3,979,173 
+The accompanying notes are an integral part of these consolidated financial statements. 
+63 
+Callon Petroleum Company 
+Consolidated Statements of Operations 
+(In thousands, except per share data) 
+For the Year Ended December 31, 
+2019 
+2018 
+2017 
+Operating Revenues: 
+Oil 
+$ 633,107 
+$ 530,898 
+$ 322,374 
+Natural gas 
+36,390 
+56,726 
+44,100 
+Natural gas liquids 
+2,075 
+— 
+— 
+Total operating revenues 
+671,572 
+587,624 
+366,474 
+Operating Expenses: 
+Lease operating 
+91,827 
+69,180 
+49,907 
+Production taxes 
+42,651 
+35,755 
+22,396 
+Depreciation, depletion and amortization 
+240,642 
+182,783 
+116,391 
+General and administrative 
+45,331 
+35,293 
+27,067 
+Merger and integration expenses 
+74,363 
+— 
+— 
+Settled share-based awards 
+3,024 
+— 
+6,351 
+Other operating expense 
+1,076 
+5,083 
+2,916 
+Total operating expenses 
+498,914 
+328,094 
+225,028 
+Income From Operations 
+172,658 
+259,530 
+141,446 
+Other (Income) Expenses: 
+Interest expense, net of capitalized amounts 
+2,907 
+2,500 
+2,159 
+(Gain) loss on derivative contracts 
+62,109 
+( 48,544 
+) 
+18,901 
+Loss on extinguishment of debt 
+4,881 
+— 
+— 
+Other income 
+( 468 
+) 
+( 2,896 
+) 
+( 1,311 
+) 
+Total other (income) expense 
+69,429 
+( 48,940 
+) 
+19,749 
+Income Before Income Taxes 
+103,229 
+308,470 
+121,697 
+Income tax expense 
+35,301 
+8,110 
+1,273 
+Net Income 
+$ 67,928 
+$ 300,360 
+$ 120,424 
+Preferred stock dividends 
+( 3,997 
+) 
+( 7,295 
+) 
+( 7,295 
+) 
+Loss on redemption of preferred stock 
+( 8,304 
+) 
+— 
+— 
+Income Available to Common Stockholders 
+$ 55,627 
+$ 293,065 
+$ 113,129 
+Income Available to Common Stockholders Per Common Share: 
+Basic 
+$ 0.24 
+$ 1.35 
+$ 0.56 
+Diluted 
+$ 0.24 
+$ 1.35 
+$ 0.56 
+Weighted Average Common Shares Outstanding: 
+Basic 
+233,140 
+216,941 
+201,526 
+Diluted 
+233,550 
+217,596 
+202,102 
+The accompanying notes are an integral part of these consolidated financial statements. 
+64 
+Callon Petroleum Company 
+Consolidated Statements of Stockholders’ Equity 
+(In thousands, except share amounts) 
+Retained 
+Preferred 
+Common 
+Capital in 
+Earnings 
+Total 
+Stock 
+Stock 
+Excess 
+(Accumulated 
+Stockholders' 
+Shares 
+$ 
+Shares 
+$ 
+of Par 
+Deficit) 
+Equity 
+Balance at 12/31/2016 
+1,459 
+$ 15 
+201,041 
+$ 2,010 
+$ 2,171,514 
+($ 440,137 
+) 
+$ 1,733,402 
+Net income 
+— 
+— 
+— 
+— 
+— 
+120,424 
+120,424 
+Shares issued pursuant to employee benefit plans 
+— 
+— 
+26 
+— 
+311 
+— 
+311 
+Restricted stock 
+— 
+— 
+769 
+8 
+9,098 
+— 
+9,106 
+Common stock issued 
+— 
+— 
+— 
+— 
+18 
+— 
+18 
+Impact of forfeiture estimate 
+— 
+— 
+— 
+— 
+418 
+( 418 
+) 
+— 
+Preferred stock dividend 
+— 
+— 
+— 
+— 
+— 
+( 7,295 
+) 
+( 7,295 
+) 
+Balance at 12/31/2017 
+1,459 
+$ 15 
+201,836 
+$ 2,018 
+$ 2,181,359 
+($ 327,426 
+) 
+$ 1,855,966 
+Net income 
+— 
+— 
+— 
+— 
+— 
+300,360 
+300,360 
+Shares issued pursuant to employee benefit plans 
+— 
+— 
+45 
+— 
+533 
+— 
+533 
+Restricted stock 
+— 
+— 
+402 
+5 
+7,651 
+— 
+7,656 
+Common stock issued 
+— 
+— 
+25,300 
+253 
+287,735 
+— 
+287,988 
+Preferred stock dividend 
+— 
+— 
+— 
+— 
+— 
+( 7,295 
+) 
+( 7,295 
+) 
+Balance at 12/31/2018 
+1,459 
+$ 15 
+227,583 
+$ 2,276 
+$ 2,477,278 
+($ 34,361 
+) 
+$ 2,445,208 
+Net income 
+— 
+— 
+— 
+— 
+— 
+67,928 
+67,928 
+Shares issued pursuant to employee benefit plans 
+— 
+— 
+24 
+— 
+154 
+— 
+154 
+Restricted stock 
+— 
+— 
+779 
+8 
+11,622 
+— 
+11,630 
+Common stock issued for Carrizo Acquisition 
+— 
+— 
+168,214 
+1,682 
+763,691 
+— 
+765,373 
+Common stock warrants reissued for Carrizo Acquisition 
+— 
+— 
+— 
+— 
+10,029 
+— 
+10,029 
+Preferred stock dividend 
+— 
+— 
+— 
+— 
+— 
+( 3,997 
+) 
+( 3,997 
+) 
+Preferred stock redemption 
+( 1,459 
+) 
+( 15 
+) 
+— 
+— 
+( 64,698 
+) 
+— 
+( 64,713 
+) 
+Loss on redemption of preferred stock 
+— 
+— 
+— 
+— 
+— 
+( 8,304 
+) 
+( 8,304 
+) 
+Balance at 12/31/2019 
+— 
+$ — 
+396,600 
+$ 3,966 
+$ 3,198,076 
+$ 21,266 
+$ 3,223,308 
+The accompanying notes are an integral part of these consolidated financial statements. 
+65 
+Callon Petroleum Company 
+Consolidated Statements of Cash Flows 
+(In thousands) 
+Years Ended December 31, 
+2019 
+2018 
+2017 
+Cash flows from operating activities: 
+Net income 
+$ 67,928 
+$ 300,360 
+$ 120,424 
+Adjustments to reconcile net income to net cash provided by operating activities: 
+Depreciation, depletion and amortization 
+245,936 
+185,605 
+118,728 
+Amortization of non-cash debt related items 
+2,907 
+2,483 
+2,150 
+Deferred income tax expense 
+35,301 
+8,110 
+1,273 
+(Gain) loss on derivative contracts 
+62,109 
+( 48,544 
+) 
+18,901 
+Cash paid for commodity derivative settlements, net 
+( 3,789 
+) 
+( 27,272 
+) 
+( 8,472 
+) 
+(Gain) loss on sale of other property and equipment 
+( 90 
+) 
+( 144 
+) 
+62 
+Non-cash loss on early extinguishment of debt 
+4,881 
+— 
+— 
+Non-cash expense related to equity share-based awards 
+9,767 
+6,289 
+8,254 
+Change in the fair value of liability share-based awards 
+1,624 
+375 
+3,288 
+Payments to settle asset retirement obligations 
+( 4,148 
+) 
+( 1,469 
+) 
+( 2,047 
+) 
+Payments for cash-settled restricted stock unit awards 
+( 1,425 
+) 
+( 4,990 
+) 
+( 13,173 
+) 
+Changes in current assets and liabilities: 
+Accounts receivable 
+( 35,071 
+) 
+( 17,351 
+) 
+( 44,495 
+) 
+Other current assets 
+( 4,166 
+) 
+( 7,601 
+) 
+108 
+Current liabilities 
+86,438 
+74,311 
+30,947 
+Other 
+8,114 
+( 2,508 
+) 
+( 6,057 
+) 
+Net cash provided by operating activities 
+476,316 
+467,654 
+229,891 
+Cash flows from investing activities: 
+Capital expenditures 
+( 640,540 
+) 
+( 611,173 
+) 
+( 419,839 
+) 
+Acquisitions 
+( 42,266 
+) 
+( 718,793 
+) 
+( 718,456 
+) 
+Acquisition deposit 
+— 
+— 
+45,238 
+Proceeds from sales of assets 
+294,417 
+9,009 
+20,525 
+Additions to other assets 
+— 
+( 3,100 
+) 
+— 
+Net cash used in investing activities 
+( 388,389 
+) 
+( 1,324,057 
+) 
+( 1,072,532 
+) 
+Cash flows from financing activities: 
+Borrowings on senior secured revolving credit facility 
+2,455,900 
+500,000 
+25,000 
+Payments on senior secured revolving credit facility 
+( 895,500 
+) 
+( 325,000 
+) 
+— 
+Payment to terminate Prior Credit Facility 
+( 475,400 
+) 
+— 
+— 
+Repayment of Carrizo’s senior secured revolving credit facility 
+( 853,549 
+) 
+— 
+— 
+Repayment of Carrizo’s preferred stock 
+( 220,399 
+) 
+— 
+— 
+Issuance of 6.125% Senior Notes due 2024 
+— 
+— 
+200,000 
+Premium on the issuance of 6.125% Senior Notes due 2024 
+— 
+— 
+8,250 
+Issuance of 6.375% Senior Notes due 2026 
+— 
+400,000 
+— 
+Issuance of common stock 
+— 
+287,988 
+— 
+Payment of preferred stock dividends 
+( 3,997 
+) 
+( 7,295 
+) 
+( 7,295 
+) 
+Payment of deferred financing costs 
+( 22,480 
+) 
+( 9,430 
+) 
+( 7,194 
+) 
+Tax withholdings related to restricted stock units 
+( 2,195 
+) 
+( 1,804 
+) 
+( 1,118 
+) 
+Redemption of preferred stock 
+( 73,017 
+) 
+— 
+— 
+Net cash provided by (used in) financing activities 
+( 90,637 
+) 
+844,459 
+217,643 
+Net change in cash and cash equivalents 
+( 2,710 
+) 
+( 11,944 
+) 
+( 624,998 
+) 
+Balance, beginning of period 
+16,051 
+27,995 
+652,993 
+Balance, end of period 
+$ 13,341 
+$ 16,051 
+$ 27,995 
+The accompanying notes are an integral part of these consolidated financial statements. 
+66 
+Draft 1 
+INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+1. 
+Description of Business 
+11. 
+Stockholders’ Equity 
+2. 
+Summary of Significant Accounting Policies 
+12. 
+Income Taxes 
+3. 
+Revenue Recognition 
+13. 
+Leases 
+4. 
+Acquisitions and Divestitures 
+14. 
+Asset Retirement Obligations 
+5. 
+Property and Equipment, Net 
+15. 
+Accounts Receivable , Net 
+6. 
+Earnings Per Share 
+16. 
+Accounts Payable and Accrued Liabilities 
+7. 
+Borrowings 
+17. 
+Commitments and Contingencies 
+8. 
+Derivative Instruments and Hedging Activities 
+18. 
+Subsequent Events (Unaudited) 
+9. 
+Fair Value Measurements 
+19. 
+Supplemental Information on Oil and Natural Gas Operations (Unaudited) 
+10. 
+Share-Based Compensation 
+20. 
+Supplemental Quarterly Financial Information (Unaudited) 
+Note 1 – Description of Business 
+Callon Petroleum Company is an independent oil and natural gas company established in 1950. The Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. 
+Callon is an independent oil and natural gas company focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas. The Company’s activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger Permian Basin in West Texas. In 2019, through its acquisition of Carrizo Oil & Gas, Inc. (“Carrizo”), the Company doubled its core acreage position in the Delaware Basin and entered the Eagle Ford Shale. The Company’s primary operations in the Permian Basin reflect a high-return, oil-weighted drilling inventory with multiple prospective horizontal development intervals and are complemented by a well-established and repeatable free cash flow generating business in the Eagle Ford Shale. 
+Note 2 – Summary of Significant Accounting Policies 
+Basis of Presentation and Principles of Consolidation 
+The consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and are presented in accordance with U.S. generally accepted accounting principles (“GAAP”). The Company proportionately consolidates its undivided interests in oil and gas properties as well as investments in unincorporated entities, such as partnerships and limited liability companies where the Company, as a partner or member, has undivided interests in the oil and gas properties. In the opinion of management, the accompanying audited consolidated financial statements reflect all adjustments, including normal recurring adjustments and all intercompany account balance and transaction eliminations, necessary to present fairly the Company’s financial position, results of its operations and cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation. 
+Use of Estimates 
+The preparation of financial statements in conformity with GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating depreciation, depletion and amortization (“DD&A”) of proved oil and gas property costs, the present value of estimated future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated timing of cash outflows underlying asset retirement obligations. There are numerous uncertainties inherent in the estimation of proved oil and gas reserves and in the projection of future rates of production and the timing of development expenditures. Other significant estimates are involved in determining asset retirement obligations, acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of commodity derivative assets and liabilities, fair values of contingent consideration arrangements, grant date fair value of stock-based awards, and contingency, litigation, and environmental liabilities. Actual results could differ from those estimates. 
+Cash and Cash Equivalents 
+The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. 
+67 
+Accounts Receivable, Net 
+Accounts receivable, net consists primarily of receivables from oil, natural gas, and NGL purchasers and joint interest owners in properties the Company operates. The Company generally has the right to withhold future revenue distributions to recover past due receivables from joint interest owners. Generally, the Company’s oil, natural gas, and NGL receivables are collected within 30 to 90 days. The Company’s allowance for doubtful accounts and bad debt expense was immaterial for all period presented. 
+Concentration of Credit Risk and Major Customers 
+The concentration of accounts receivable from entities in the oil and gas industry may impact the Company’s overall credit risk such that these entities may be similarly affected by changes in economic and other industry conditions. The Company does not believe the loss of any one of its purchasers would materially affect its ability to sell the oil and gas it produces as other purchasers are available in its primary areas of activity. The Company had the following major customers that represented 10% or more of its total revenues for at least one of the periods presented: 
+Years Ended December 31, 
+2019 
+2018 
+2017 
+Rio Energy International, Inc. 
+26 % 
+28 % 
+17 % 
+Enterprise Crude Oil, LLC 
+19 % 
+14 % 
+18 % 
+Plains Marketing, L.P. 
+15 % 
+21 % 
+29 % 
+Shell Trading Company 
+10 % 
+* 
+* 
+* - Less than 10% for the applicable year. 
+The Company’s counterparties to its commodity derivative instruments include lenders under the Company’s credit agreement (“Lender Counterparty”) as well as counterparties who are not lenders under the Company’s credit agreement (“Non-Lender Counterparty”). As each Lender Counterparty has an investment grade credit rating and the Company has obtained a guaranty from each Non-Lender Counterparty’s parent company which has an investment grade credit rating, the Company believes it does not have significant credit risk with its commodity derivative instrument counterparties. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each Lender Counterparty and each Non-Lender Counterparty’s parent company. The Company executes its derivative instruments with multiple counterparties to minimize its credit exposure to any individual counterparty. 
+Oil and Natural Gas Properties 
+The Company uses the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration, and development activities are capitalized as oil and gas properties. Internal costs that are directly related to acquisition, exploration, and development activities, including salaries, benefits, and stock-based compensation, are capitalized to either evaluated or unevaluated oil and gas properties based on the type of activity. Internal costs related to production and similar activities are expensed as incurred. 
+Proceeds from the sale or disposition of evaluated and unevaluated oil and natural gas properties are accounted for as a reduction of evaluated oil and gas property costs unless the sale significantly alters the relationship between capitalized costs and proved reserves, in which case a gain or loss is recognized. For the years ended December 31, 2019, 2018 and 2017, the Company did not have any sales of oil and gas properties that significantly altered such relationship. 
+Capitalized oil and gas property costs are amortized on an equivalent unit-of-production method, converting natural gas to barrels of oil equivalent at the ratio of six thousand cubic feet of gas to one barrel of oil, which represents their approximate relative energy content. The equivalent unit-of-production depletion rate is computed on a quarterly basis by dividing current quarter production by proved oil and gas reserves at the beginning of the quarter then applying such amortization rate to evaluated oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values. 
+Excluded from this amortization are costs associated with unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties or the Company determines that these costs have been impaired. The Company assesses properties on an individual basis or as a group and considers the following factors, among others, to determine if these costs have been impaired: exploration program and intent to drill, remaining lease term, and the assignment of proved reserves. Geological and geophysical costs not associated with specific prospects are recorded to evaluated oil and gas property costs as incurred. The amount of interest costs capitalized is determined on a quarterly basis based on the average balance of unproved properties and the weighted average interest rate of outstanding borrowings. Capitalized interest cannot exceed gross interest expense. 
+68 
+Under full cost accounting rules, the Company reviews the net book value of its oil and gas properties each quarter. Under these rules, the net book value of oil and gas properties, less related deferred income taxes, are limited to the “cost center ceiling” equal to (i) the sum of (a) the present value of estimated future net revenues from proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves computed using a discount factor of 10 % , (b) the costs of unevaluated properties not being amortized, and (c) the lower of cost or estimated fair value of unevaluated properties included in the costs being amortized; less (ii) related income tax effects. Any excess of the net book value of oil and gas properties, less related deferred income taxes, over the cost center ceiling is recognized as a write-down of evaluated oil and gas properties. A write-down recognized in one period may not be reversed in a subsequent period even if higher commodity prices in the future result in a cost center ceiling in excess of the net book value of oil and gas properties, less related deferred income taxes. 
+The estimated future net revenues used in the cost center ceiling are calculated using the average realized prices for sales of oil, NGLs, and natural gas on the first calendar day of each month during the 12-month period prior to the end of the current quarter (“12-Month Average Realized Price”), held flat for the life of the production, except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of commodity derivative instruments as the Company elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. The Company did no t recognize a write-down of evaluated oil and natural gas properties for the years ended December 31, 2019, 2018, and 2017. 
+Other Property and Equipment 
+The Company depreciates its other property and equipment using the straight-line method based on estimated useful lives of three to twenty years. Depreciation expense of $ 0.7 million, $ 1.1 million and $ 0.9 million relating to other property and equipment was included in “General and administrative expense” in the consolidated statements of operations for the years ended December 31, 2019 , 2018 and 2017 , respectively. The Company reviews its other property and equipment for impairment when indicators of impairment exist. 
+Deferred Financing Costs 
+Deferred financing costs associated with the Company’s senior notes are classified as a reduction of the related senior notes carrying value on the consolidated balance sheets and are amortized to interest expense using the straight-line method over the terms of the related senior notes. Deferred financing costs associated with the revolving credit facility are classified in “Other long-term assets” in the consolidated balance sheets and are amortized to interest expense using the straight-line method over the term of the facility. Amortization of deferred financing costs, net of amortization of premiums, of $ 2.9 million , $ 2.5 million and $ 2.2 million were recorded for the years ended December 31, 2019 , 2018 and 2017 , respectively. 
+Asset Retirement Obligations 
+The Company records an estimate of the fair value of liabilities for obligations associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Estimates involved in determining asset retirement obligations include the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a credit-adjusted risk-free discount rate and an inflation factor in order to determine the present value of the asset retirement obligation. The present value of the asset retirement obligations is accreted each period and the increase to the obligation is reported in “Depreciation, depletion and amortization” in the consolidated statements of operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to evaluated properties in the consolidated balance sheets. See “ Note 14 - Asset Retirement Obligations” for additional information. 
+Derivative Instruments 
+The Company uses commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of its forecasted sales of production and achieve a more predictable level of cash flow. All commodity derivative instruments are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. The Company nets its commodity derivative instrument fair value amounts executed with the same counterparty to a single asset or liability pursuant to International Swap Dealers Association Master Agreements (“ISDAs”), which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The Company does not enter into commodity derivative instruments for speculative purposes. 
+The Company is also party to contingent consideration arrangements that include obligations to pay or rights to receive additional consideration if commodity prices exceed specified thresholds during certain periods in the future. These contingent consideration assets and liabilities are required to be bifurcated and accounted for separately as derivative instruments as they are not considered to be clearly and closely related to the host contract, and recognized at their acquisition or divestiture date fair value in the consolidated balance sheets. 
+The Company has elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. As such, all gains and losses as a result of changes in the fair value of commodity derivative instruments, as well as its contingent consideration arrangements, are recognized as “(Gain) loss on derivative contracts” in the consolidated statements of operations in the period in which 
+69 
+the changes occur. See “ Note 8 - Derivative Instruments and Hedging Activities” and “ Note 9 - Fair Value Measurements” for further discussion. 
+Revenue Recognition 
+The Company recognizes revenues from the sales of oil and natural gas to its customers and presents them disaggregated on the Company’s consolidated statements of operations. Revenue is recognized at the point in time when control of the product transfers to the customer. Revenue accruals are recorded monthly and are based on estimated production delivered to a purchaser and the expected price to be received. Variances between estimates and the actual amounts received are recorded in the month payment is received. See “ Note 3 - Revenue Recognition” for further discussion. 
+Income Taxes 
+Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are recognized at the end of each reporting period for the future tax consequences of cumulative temporary differences between the tax basis of assets and liabilities and their reported amounts in the Company’s consolidated financial statements based on existing tax laws and enacted statutory tax rates applicable to the periods in which the temporary differences are expected to affect taxable income. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards and tax credit carryforwards. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering all available evidence (both positive and negative) to determine whether it is more likely than not that all or a portion of the deferred tax assets will not be realized and a valuation allowance is required. As of December 31, 2019 and 2018, the Company did no t have a valuation allowance against its deferred tax assets. See “ Note 12 - Income Taxes” for further discussion. 
+Share-Based Compensation 
+The Company grants restricted stock unit awards that may be settled in common stock (“RSU Equity Awards”) or cash (“Cash-Settled RSU Awards”), some of which are subject to achievement of certain performance conditions. In addition, as a result of the Merger, all stock appreciation rights to be settled in cash (“Cash SARs”) previously granted by Carrizo that were outstanding as of closing were canceled and converted into a vested Cash SAR covering shares of the Company’s common stock. Share-based compensation expense is recognized as “General and administrative expense” in the consolidated statements of operations. The Company accounts for forfeitures of equity-based incentive awards as they occur. See “ Note 10 - Share-Based Compensation” for further details of the awards discussed below. 
+RSU Equity Awards and Cash-Settled RSU Awards. Share-based compensation expense for RSU Equity Awards is based on the grant-date fair value and recognized over the vesting period (generally three years for employees and one year for non-employee directors) using the straight-line method. For RSU Equity Awards with vesting terms subject to a performance condition, share-based compensation expense is based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model with the estimated value recognized over the vesting period (generally three years ). Cash-Settled RSU Awards subject to a performance condition that the Company expects or is required to settle in cash, are accounted for as liabilities with share-based compensation expense based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model, with the estimated fair value recognized over the vesting period (generally three years ). 
+Cash SARs. Cash SARs previously granted by Carrizo that were outstanding at closing of the Merger were canceled and converted into a Cash SAR covering shares of the Company’s common stock, with the conversion calculated as prescribed in the agreement governing the Merger. The Cash SARs were recorded at their acquisition date fair value, which was determined using a Black-Scholes-Merton option pricing model, with the fair value liability subsequently remeasured at the end of each reporting period. The liability for Cash SARs is classified as “Other current liabilities” in the consolidated balance sheets as all outstanding awards are vested. The Cash SARs will expire between one and seven years , depending on the date of grant. 
+70 
+Supplemental Cash Flow Information 
+The following table sets forth supplemental cash flow information for the periods indicated: 
+Years Ended December 31, 
+2019 
+2018 
+2017 
+(In thousands) 
+Interest paid, net of capitalized amounts 
+$ — 
+$ — 
+$ — 
+Income taxes paid (1) 
+— 
+— 
+— 
+Cash paid for amounts included in the measurement of lease liabilities: 
+Operating cash flows from operating leases 
+$ 3,414 
+$ — 
+$ — 
+Investing cash flows from operating leases 
+32,529 
+— 
+— 
+Non-cash investing and financing activities: 
+Change in accrued capital expenditures 
+($ 31,475 
+) 
+($ 52,757 
+) 
+($ 39,532 
+) 
+Change in asset retirement costs 
+13,559 
+8,730 
+( 607 
+) 
+Contingent consideration arrangement 
+8,512 
+— 
+— 
+ROU assets obtained in exchange for lease liabilities: 
+Operating leases 
+$ 66,914 
+$— 
+$— 
+Financing leases 
+2,197 
+— 
+— 
+(1) 
+The Company did no t pay any federal income tax for any of the years in the three year period ending December 31, 2019 . 
+Earnings per Share 
+The Company’s basic net income attributable to common shareholders per common share is based on the weighted average number of shares of common stock outstanding for the period. Diluted net income attributable to common shareholders per common share is calculated using the treasury stock method and is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the year which include RSU Equity Awards and common stock warrants. See “ Note 6 - Earnings Per Share” for further discussion. 
+Industry Segment and Geographic Information 
+The Company operates in one industry segment, which is the exploration, development, and production of crude oil, NGLs, and natural gas. All of the Company’s operations are located in the United States and currently all revenues are attributable to customers located in the United States. 
+Recently Adopted Accounting Standards 
+Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification. In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842. In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements. In March 2019, the FASB issued ASU No. 2019-01, Leases (Topic 842): Codification Improvements. Together these related amendments to GAAP represent ASC Topic 842, Leases (“ASC 842”). 
+Effective January 1, 2019, the Company adopted ASU 842, using the modified retrospective approach and did not have a cumulative-effect adjustment in retained earnings as a result of the adoption. ASC 842 requires lessees to recognize a liability representing the obligation to make lease payments and a related right-of-use (“ROU”) asset for virtually all lease transactions and disclose key quantitative and qualitative information about leasing arrangements. However, ASC 842 does not apply to leases to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained. The Company engaged a third-party consultant to assist with assessing its existing contracts, as well as future potential contracts, and to determine the impact of its application on its consolidated financial statements and related disclosures. The contract evaluation process included review of drilling rig contracts, office facility leases, compressors, field vehicles and equipment, general corporate leased equipment, and other existing arrangements to support its operations that may contain a lease component. 
+Upon adoption, the Company implemented policy elections and practical expedients which include the following: 
+• 
+package of practical expedients which allows the Company to forego reassessing contracts that commenced prior to adoption that were properly evaluated under legacy lease accounting guidance 
+• 
+excluding ROU assets and lease liabilities for leases with terms that are less than one year; 
+• 
+combining lease and non-lease components and accounting for them as a single lease (elected by asset class); 
+• 
+excluding land easements that existed or expired prior to adoption; and 
+71 
+• 
+policy election that eliminates the need for adjusting prior period comparable financial statements prepared under legacy lease accounting guidance. 
+Through the implementation process, the Company evaluated each of its lease arrangements and enhanced its systems to track and calculate additional information required upon adoption of this standard. Adoption of ASC 842 did not materially change the Company’s consolidated statements of operations or consolidated statements of cash flows. See “ Note 13 - Leases” for further discussion. 
+Recently Issued ASUs 
+None that are expected to have a material impact on our financial statements. 
+Note 3 – Revenue Recognition 
+Revenue from contracts with customers 
+Oil sales 
+Under the Company’s oil sales contracts it sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the point of delivery at the net price received. 
+Natural gas sales 
+Under the Company’s natural gas sales processing contracts, it delivers natural gas to a midstream processing entity. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sale of natural gas. The revenue received from the sale of NGLs associated with certain contracts is included in natural gas sales. Under these processing agreements, when control of the natural gas changes at the point of delivery, the treatment of gathering and treating fees are recorded net of revenues. For other contracts that were assumed in the Carrizo Acquisition, defined below, where the Company maintains control throughout processing, the Company records NGL revenue separately on its consolidated statement of operations and presents the gathering a treating fees as an expense recorded in lease operating expense. 
+For the majority of the Company’s natural gas sales processing contracts, gathering and treating fees have historically been recorded as an expense in lease operating expense in the statement of operations. The Company modified the presentation of revenues and expenses to include these fees net of revenues effective January 1, 2018 upon adopting ASC 606 - Revenue from Contracts with Customers. For the years ended December 31, 2019 and 2018, $ 10.5 million and $ 7.6 million of gathering and treating fees were recognized and recorded as a reduction to natural gas revenues in the consolidated statement of operations, respectively. For the year ended December 31, 2017 , $ 3.4 million of gathering and treating fees were recognized and recorded as part of lease operating expense in the consolidated statement of operations. 
+Accounts receivable from revenues from contracts with customers 
+Net accounts receivable include amounts billed and currently due from revenues from contracts with customers of our oil and natural gas production, which had a balance at December 31, 2019 and 2018 of $ 165.3 million and $ 87.1 million, respectively, and are presented in “Accounts receivable, net” in the consolidated balance sheets. The increase from December 31, 2018 is primarily due to the Carrizo Acquisition. 
+Transaction price allocated to remaining performance obligations 
+For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. 
+Prior period performance obligations 
+The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. 
+72 
+Note 4 – Acquisitions and Divestitures 
+2019 Acquisitions and Divestitures 
+Carrizo Oil & Gas, Inc. Merger. On December 20, 2019, the Company completed its acquisition of Carrizo in an all-stock transaction (the “Merger” or the “Carrizo Acquisition”). Under the terms of the Merger, each outstanding share of Carrizo common stock was converted into 1.75 shares of the Company’s common stock. The Company issued approximately 168.2 million shares of common stock at a price of $ 4.55 per share, resulting in total consideration paid by the Company to the former Carrizo shareholders of approximately $ 765.4 million . In connection with the closing of the Merger, the Company funded the redemption of Carrizo’s 8.875 % Preferred Stock, repaid the outstanding principal under Carrizo’s revolving credit facility and assumed all of Carrizo’s senior notes. See “ Note 7 - Borrowings” for further details. 
+The Merger was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. Certain data necessary to complete the purchase price allocation is not yet available, including final tax returns that provide the underlying tax basis of Carrizo’s assets and liabilities. The company expects to complete the purchase price allocation during the 12-month period following the acquisition date. 
+The following table sets forth the Company’s preliminary allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date. 
+Preliminary Purchase 
+Price Allocation 
+(In thousands) 
+Consideration: 
+Fair value of the Company’s common stock issued 
+$ 765,373 
+Total consideration 
+$ 765,373 
+Liabilities: 
+Accounts payable 
+$ 37,657 
+Revenues and royalties payable 
+52,449 
+Operating lease liabilities - current 
+29,924 
+Fair value of derivatives - current 
+61,015 
+Other current liabilities 
+82,084 
+Long-term debt 
+1,984,135 
+Operating lease liabilities - non-current 
+30,070 
+Asset retirement obligation 
+26,151 
+Fair value of derivatives - non-current 
+26,960 
+Other long-term liabilities 
+17,260 
+Common stock warrants 
+10,029 
+Total liabilities assumed 
+$ 2,357,734 
+Assets: 
+Accounts receivable, net 
+$ 48,479 
+Fair value of derivatives - current 
+17,451 
+Other current assets 
+4,945 
+Evaluated oil and natural gas properties 
+2,133,280 
+Unevaluated properties 
+682,928 
+Other property and equipment 
+9,614 
+Fair value of derivatives - non-current 
+4,518 
+Deferred tax asset 
+159,320 
+Operating lease right-of-use-assets 
+59,994 
+Other long term assets 
+2,578 
+Total assets acquired 
+$ 3,123,107 
+Approximately $ 28.6 million of revenues and $ 7.0 million of direct operating expenses attributed to the Carrizo Acquisition are included in the Company’s consolidated statements of operations for the period from the closing date on December 20, 2019 through December 31, 2019. 
+73 
+Pro Forma Operating Results (Unaudited). The following unaudited pro forma combined condensed financial data for the years ended December 31, 2019 and 2018 was derived from the historical financial statements of the Company giving effect to the Merger, as if it had occurred on January 1, 2018. The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for Carrizo’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) the Company’s common stock issued to convert Carrizo’s outstanding shares of common stock and equity awards as of the closing date of the Merger, (ii) the depletion of Carrizo’s fair-valued proved oil and natural gas properties and (iii) the estimated tax impacts of the pro forma adjustments. 
+Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company of approximately $ 58.8 million for the year ended December 31, 2019 and acquisition-related costs incurred by Carrizo that totaled approximately $ 15.6 million for the year ended December 31, 2019. The pro forma results of operations do not include any cost savings or other synergies that may result from the Merger or any estimated costs that have been or will be incurred by the Company to integrate the Carrizo assets. The pro forma financial data does not include the pro forma results of operations for any other acquisitions made during the periods presented, as they were primarily acreage acquisitions and their results were not deemed material. 
+The pro forma consolidated statements of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Merger taken place on January 1, 2018 and is not intended to be a projection of future results. 
+Years Ended December 31, 
+2019 
+2018 
+(In thousands) 
+Revenues 
+$ 1,620,357 
+$ 1,661,171 
+Income from operations 
+614,668 
+767,628 
+Net income 
+369,777 
+734,527 
+Basic earnings per common share 
+0.89 
+$ 1.87 
+Diluted earnings per common share 
+0.89 
+$ 1.87 
+During 2019, in conjunction with the Carrizo Acquisition, the Company incurred costs totaling $ 74.4 million comprised of severance costs of $ 28.8 million and other merger and integration expenses of $ 45.6 million . As of December 31, 2019, $ 52.4 million remained accrued and is included as a component of “Accounts payable and accrued liabilities” in the consolidated balance sheets. 
+Ranger Divestiture. In the second quarter of 2019, the Company completed its divestiture of certain non-core assets in the southern Midland Basin (the “Ranger Divestiture”) for net cash proceeds of $ 244.9 million. The transaction also provided for potential additional contingent consideration of up to $ 60.0 million based on West Texas Intermediate average annual pricing over a three-year period. See “ Note 8 - Derivative Instruments and Hedging Activities” and “ Note 9 - Fair Value Measurements” for further discussion of this contingent consideration arrangement. The divestiture encompasses the Ranger operating area in the southern Midland Basin which includes approximately 9,850 net Wolfcamp acres with an average 66 % working interest. The net cash proceeds were recognized as a reduction of evaluated oil and gas properties with no gain or loss recognized. 
+74 
+2018 Acquisitions and Divestitures 
+On August 31, 2018, the Company completed the acquisition of approximately 28,000 net surface acres in the Spur operating area, located in the Delaware Basin, from Cimarex Energy Company, for a net cash consideration of approximately $ 539.5 million (the “Delaware Asset Acquisition”). The Company funded the Delaware Asset Acquisition with net proceeds from both the common stock offering completed on May 30, 2018 and the issuance of the 6.375 % Senior Notes. See “ Note 7 - Borrowings” and “ Note 11 - Stockholders’ Equity” for further details of these offerings. 
+The Delaware Asset Acquisition was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The following table sets forth the Company’s allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date. 
+Purchase Price Allocation 
+(In thousands) 
+Assets 
+Oil and natural gas properties 
+Evaluated properties 
+$ 253,089 
+Unevaluated properties 
+287,000 
+Total oil and natural gas properties 
+$ 540,089 
+Total assets acquired 
+$ 540,089 
+Liabilities 
+Asset retirement obligations 
+($ 570 
+) 
+Total liabilities assumed 
+($ 570 
+) 
+Net Assets Acquired 
+$ 539,519 
+Approximately $ 27.3 million of revenues and $ 9.9 million of direct operating expenses attributed to the Delaware Asset Acquisition are included in the Company’s consolidated statements of operations for the period from the closing date on August 31, 2018 through December 31, 2018 . 
+Pro Forma Operating Results (Unaudited). The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the years ended December 31, 2018 and 2017 , assuming the Delaware Asset Acquisition had been completed as of January 1, 2017, including adjustments to reflect the acquisition date fair values assigned to the assets acquired and liabilities assumed. The pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The Company believes the assumptions used provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Delaware Asset Acquisition. 
+Years Ended December 31, 
+2018 
+2017 
+(In thousands) 
+Revenues 
+$ 669,236 
+$ 469,896 
+Income from operations 
+299,090 
+209,723 
+Net income 
+324,318 
+181,406 
+Basic earnings per common share 
+$ 1.49 
+$ 0.90 
+Diluted earnings per common share 
+$ 1.49 
+$ 0.90 
+Other. In addition, the Company completed various acquisitions of additional working interests and mineral rights, and associated production volumes, in the Company’s existing core operating areas within the Permian Basin. In the first quarter of 2018, the Company completed acquisitions within Monarch and WildHorse operating areas for aggregate net cash consideration of approximately $ 37.8 million. In the fourth quarter of 2018, the Company completed acquisitions of leasehold interests and mineral rights within its WildHorse and Spur operating areas for net cash consideration of approximately $ 87.9 million. 
+The Company did not have any material divestitures for the year ended December 31, 2018. 
+75 
+2017 Acquisitions and Divestitures 
+Ameredev Acquisition. On February 13, 2017, the Company completed the acquisition of 29,175 gross ( 16,688 net) acres in the Delaware Basin, primarily located in Ward and Pecos Counties, Texas from American Resource Development, LLC, for total cash consideration of $ 646.6 million, excluding customary purchase price adjustments (the “Ameredev Acquisition”). The Company partially funded the Ameredev Acquisition with net proceeds from the common stock offering completed on December 19, 2016. The Company obtained an 82 % average working interest ( 75 % average net revenue interest) in the properties acquired in the Ameredev Acquisition. 
+The Ameredev Acquisition was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The following table sets forth the Company’s allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date. 
+Purchase Price Allocation 
+(In thousands) 
+Assets 
+Oil and natural gas properties 
+Evaluated properties 
+$ 137,368 
+Unevaluated properties 
+509,359 
+Total oil and natural gas properties 
+$ 646,727 
+Total assets acquired 
+$ 646,727 
+Liabilities 
+Asset retirement obligations 
+($ 168 
+) 
+Total liabilities assumed 
+($ 168 
+) 
+Net Assets Acquired 
+$ 646,559 
+Approximately $ 36.1 million of revenues and $ 8.5 million of direct operating expenses attributed to the Ameredev Acquisition are included in the Company’s consolidated statements of operations for the period from the closing date on February 13, 2017 through December 31, 2017 . 
+Pro Forma Operating Results (Unaudited). The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the year ended December 31, 2017, assuming the Ameredev Acquisition had been completed as of January 1, 2016, including adjustments to reflect the acquisition date fair values assigned to the assets acquired and liabilities assumed. The pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The Company believes the assumptions used provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Ameredev Acquisition. 
+Year Ended December 31, 2017 
+(In thousands) 
+Revenues 
+$ 369,527 
+Income from operations 
+144,104 
+Net income 
+115,787 
+Basic earnings per common share 
+$ 0.57 
+Diluted earnings per common share 
+$ 0.57 
+Other. On June 5, 2017, the Company completed the acquisition of 7,031 gross ( 2,488 net) acres in the Delaware Basin, located near the acreage acquired in the Ameredev Acquisition discussed above, for aggregate net cash consideration of approximately $ 52.0 million. The Company funded the cash purchase price with available cash and proceeds from the issuance of an additional $ 200.0 million of its 6.125 % Senior Notes. See “ Note 7 - Borrowings” for further details of this offering. 
+The Company did not have any material divestitures for the year ended December 31, 2017. 
+76 
+Note 5 – Property and Equipment, Net 
+As of December 31, 2019 and 2018 , total property and equipment, net consisted of the following: 
+As of December 31, 
+2019 
+2018 
+Oil and natural gas properties, full cost accounting method 
+(In thousands) 
+Evaluated properties 
+$ 7,203,482 
+$ 4,585,020 
+Accumulated depreciation, depletion, amortization and impairments 
+( 2,520,488 
+) 
+( 2,270,675 
+) 
+Net evaluated oil and natural gas properties 
+4,682,994 
+2,314,345 
+Unevaluated properties 
+Unevaluated leasehold and seismic costs 
+1,843,725 
+1,316,190 
+Capitalized interest 
+142,399 
+88,323 
+Total unevaluated properties 
+1,986,124 
+1,404,513 
+Total oil and natural gas properties, net 
+$ 6,669,118 
+$ 3,718,858 
+Other property and equipment 
+$ 67,202 
+$ 38,463 
+Accumulated depreciation 
+( 31,949 
+) 
+( 16,562 
+) 
+Other property and equipment, net 
+$ 35,253 
+$ 21,901 
+The Company capitalized internal costs of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities totaling $ 36.2 million , $ 28.0 million and $ 20.3 million for the years ended December 31, 2019 , 2018 and 2017 , respectively. The Company capitalized interest costs to unproved properties totaling $ 78.5 million , $ 56.2 million and $ 33.8 million for the years ended December 31, 2019 , 2018 and 2017 , respectively. 
+Unevaluated property costs not subject to amortization as of December 31, 2019 consisted of the following: 
+2019 
+2018 
+2017 
+2016 
+Total 
+(In thousands) 
+Acquisition costs 
+$ 682,413 
+$ 383,238 
+$ 577,959 
+$ 115,833 
+$ 1,759,443 
+Exploration costs 
+43,174 
+22,384 
+18,724 
+— 
+84,282 
+Capitalized interest 
+78,492 
+56,151 
+7,756 
+— 
+142,399 
+Total unevaluated properties 
+$ 804,079 
+$ 461,773 
+$ 604,439 
+$ 115,833 
+$ 1,986,124 
+77 
+Note 6 – Earnings Per Share 
+Basic earnings (loss) per share is computed by dividing income available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings per share includes the potential dilutive impact of non-vested restricted shares outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. The following table sets forth the computation of basic and diluted earnings per share: 
+Years Ended December 31, 
+2019 
+2018 
+2017 
+(In thousands, except per share amounts) 
+Net income 
+$ 67,928 
+$ 300,360 
+$ 120,424 
+Preferred stock dividends 
+( 3,997 
+) 
+( 7,295 
+) 
+( 7,295 
+) 
+Loss on redemption of preferred stock 
+( 8,304 
+) 
+— 
+— 
+Income available to common stockholders 
+$ 55,627 
+$ 293,065 
+$ 113,129 
+ 
+Basic weighted average common shares outstanding 
+233,140 
+216,941 
+201,526 
+Dilutive impact of restricted stock 
+410 
+655 
+576 
+Diluted weighted average common shares outstanding 
+233,550 
+217,596 
+202,102 
+ 
+Income Available to Common Stockholders Per Common Share 
+Basic 
+$ 0.24 
+$ 1.35 
+$ 0.56 
+Diluted 
+$ 0.24 
+$ 1.35 
+$ 0.56 
+ 
+Restricted stock (1) 
+998 
+89 
+16 
+(1) 
+Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive. 
+Note 7 – Borrowings 
+The Company’s borrowings consisted of the following: 
+໿ 
+As of December 31, 
+2019 
+2018 
+(In thousands) 
+Senior Secured Revolving Credit Facility due 2024 
+$ 1,285,000 
+$ 200,000 
+6.25% Senior Notes due 2023 (1) 
+650,000 
+— 
+6.125% Senior Notes due 2024 
+600,000 
+600,000 
+8.25% Senior Notes due 2025 (1) 
+250,000 
+— 
+6.375% Senior Notes due 2026 
+400,000 
+400,000 
+Total principal outstanding 
+3,185,000 
+1,200,000 
+Unamortized premium for 6.125% Senior Notes 
+5,344 
+6,469 
+Unamortized premium for 6.25% Senior Notes 
+4,838 
+— 
+Unamortized premium for 8.25% Senior Notes 
+5,286 
+— 
+Unamortized deferred financing costs for Senior Notes 
+( 14,359 
+) 
+( 16,996 
+) 
+Total carrying value of borrowings (2) 
+$ 3,186,109 
+$ 1,189,473 
+(1) 
+As a result of the Merger, the Company became successor-in-interest to the indenture governing the 6.25 % Senior Notes and 8.25 % Senior Notes. 
+(2) 
+Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $ 22.2 million and $ 6.1 million as of December 31, 2019 and 2018 , respectively. 
+Senior Secured Revolving Credit Facility 
+On May 25, 2017, the Company entered into the Sixth Amended and Restated Credit Agreement to the Credit Facility (the “Prior Credit Facility”) with a syndicate of lenders. The Prior Credit Facility provided for interest-only payments until May 25, 2023 , when the Prior Credit Facility would mature and any outstanding borrowings would become due. The maximum credit amount under the Prior Credit Facility was $ 2.0 billion. 
+78 
+Effective May 1, 2019, the Company entered into the third amendment to the Prior Credit Facility to, among other things: (i) reaffirm the borrowing base at $ 1.1 billion, excluding the Ranger assets sold; and (ii) amend various covenants and terms to reflect current market trends. 
+As a result of entering into the Credit Facility, as defined below, the Company terminated the Prior Credit Facility. As a result of terminating the Prior Credit Facility, the Company recorded a loss on extinguishment of debt of $ 4.9 million , which was comprised solely of the write-off of unamortized deferred financing costs associated with the Prior Credit Facility. 
+On December 20, 2019, upon consummation of the Merger, the Company entered into the credit agreement with a syndicate of lenders (the “Credit Facility”). The Credit Facility provides for interest-only payments until December 20, 2024 (subject to springing maturity dates of (i) January 14, 2023 if the 6.25 % Senior Notes are outstanding at such time and (ii) July 2, 2024 if the 6.125 % Senior Notes are outstanding at such time), when the Credit Facility matures and any outstanding borrowings are due. The maximum credit amount under the Credit Facility is $ 5.0 billion . The borrowing base under the Credit Facility is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. The capitalized terms which are not defined in this description of the revolving credit facility shall have the meaning given to such terms in the credit agreement. 
+As of December 31, 2019, the borrowing base under the Credit Facility was $ 2.5 billion , with an elected commitment amount of $ 2.0 billion , and borrowings outstanding of $ 1.3 billion at a weighted average interest rate of 3.56 % . The Company also had $ 17.7 million in letters of credit outstanding under the Credit Facility. 
+Borrowings outstanding under the credit agreement bear interest at the Company’s option at either (i) a base rate for a base rate loan plus a margin between 0.25 % to 1.25 % , where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.50 % and the adjusted LIBO rate plus 1.00 % , or (ii) an adjusted LIBO rate for a Eurodollar loan plus a margin between 1.25 % to 2.25 % . At any time the Leverage Ratio, as defined in the credit agreement, is greater than 3.00 to 1.00, the base rate and Eurodollar loans are increased 0.25 % . The Company also incurs commitment fees at rates ranging between 0.375 % to 0.500 % as set forth in the table below on the unused portion of lender commitments, which are included in “Interest expense, net” in the consolidated statements of operations. 
+6.375 % Senior Notes 
+On June 7, 2018 , the Company issued $ 400.0 million aggregate principal amount of 6.375 % Senior Notes due 2026 (the “ 6.375 % Senior Notes”), which mature on July 1, 2026 and have interest payable semi-annually each January 1 and July 1. The Company used the net proceeds from the offering of approximately $ 394.0 million, after deducting initial purchasers’ discounts and estimated offering expenses, to fund a portion of the Delaware Asset Acquisition described above. The 6.375 % Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The subsidiary guarantor is 100 % owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor. 
+The Company may redeem the 6.375 % Senior Notes in accordance with the following terms: (1) prior to July 1, 2021 , a redemption of up to 35 % of the principal in an amount not greater than the net proceeds from certain equity offerings, and within 180 days of the closing date of such equity offerings, at a redemption price of 106.375 % of principal, plus accrued and unpaid interest, if any, to the date of the redemption, if at least 65 % of the principal will remain outstanding after such redemption; (2) prior to July 1, 2021 , a redemption of all or part of the principal at a price of 100 % of principal of the amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of the redemption; and (3) a redemption, in whole or in part, at a redemption price, plus accrued and unpaid interest, if any, to the date of the redemption, (i) of 103.188 % of principal if the redemption occurs on or after July 1, 2021, but before July 1, 2022 , and (ii) of 102.125 % of principal if the redemption occurs on or after July 1, 2022 , but before July 1, 2023 , and (iii) of 101.063 % of principal if the redemption occurs on or after July 1, 2023 , but before July 1, 2024 , and (iv) of 100 % of principal if the redemption occurs on or after July 1, 2024 . 
+Following a change of control, each holder of the 6.375 % Senior Notes may require the Company to repurchase all or a portion of the 6.375 % Senior Notes at a price of 101 % of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase. 
+6.125 % Senior Notes 
+On October 3, 2016, the Company issued $ 400.0 million aggregate principal amount of 6.125 % Senior Notes due 2024 (the “ 6.125 % Senior Notes), which mature on October 1, 2024 and have interest payable semi-annually each April 1 and October 1. The 6.125 % Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The subsidiary guarantor is 100 % owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor. 
+79 
+On May 19, 2017, the Company issued an additional $ 200.0 million aggregate principal amount of its 6.125 % Senior Notes which with the existing $ 400.0 million aggregate principal amount of 6.125 % Senior Notes are treated as a single class of notes under the indenture. The Company used a portion of the net proceeds from the offering of approximately $ 206.1 million, including a premium issue price of 104.125 % and after deducting initial purchasers’ discounts and estimated offering expenses, to fund the acquisition completed on June 5, 2017 with the remainder for general corporate purposes. 
+The Company may redeem all or a portion of the 6.125 % Senior Notes at redemption prices decreasing from 104.594 % to 100 % of the principal amount on October 1, 2022 , plus accrued and unpaid interest. 
+Following a change of control, each holder of the 6.125 % Senior Notes may require the Company to repurchase all or a portion of the 6.125 % Senior Notes at a price of 101 % of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase. 
+Senior Notes Assumed in Merger 
+On December 20, 2019, upon consummation of the Merger, the Company became successor-in-interest to the indenture governing the 8.25 % Senior Notes due 2025 (the “ 8.25 % Senior Notes”) and the 6.25 % Senior Notes due 2023 (the “ 6.25 % Senior Notes”). Both the 8.25 % Senior Notes and the 6.25 % Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. 
+8.25 % Senior Notes. The 8.25 % Senior Notes mature on July 15, 2025 and have interest payable semi-annually each January 15 and July 15. Before July 15, 2020, the Company may, at its option, redeem all or a portion of the 8.25 % Senior Notes at 100 % of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, the Company may redeem all or a portion of the 8.25 % Senior Notes at redemption prices decreasing annually from 106.188 % to 100 % of the principal amount redeemed plus accrued and unpaid interest. 
+6.25 % Senior Notes. The 6.25 % Senior Notes mature on April 15, 2023 and have interest payable semi-annually each April 15 and October 15. The Company may redeem all or a portion of the 6.25 % Senior Notes at redemption prices decreasing from 103.125 % to 100 % of the principal amount on April 15, 2021, plus accrued and unpaid interest. 
+If a Change of Control (as defined in the indenture governing the 8.25 % Senior Notes and the 6.25 % Senior Notes) occurs, the Company may be required by holders to repurchase the 8.25 % Senior Notes and the 6.25 % Senior Notes for cash at a price equal to 101 % of the principal amount purchased, plus any accrued and unpaid interest. The indenture governing the 8.25 % Senior Notes and the 6.25 % Senior Notes contains covenants that, among other things, limit the Company’s ability and the ability of its restricted subsidiaries to: pay distributions on, purchase or redeem the Company’s capital stock or redeem the Company’s subordinated debt; make investments; incur or guarantee additional indebtedness or issue certain types of equity securities; create certain liens; sell assets; consolidate, merge or transfer all or substantially all of the Company’s assets; enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; engage in transactions with affiliates; and create unrestricted subsidiaries. The indenture governing the 8.25 % Senior Notes and the 6.25 % Senior Notes also contains customary events of default, including those related to failure to comply with the terms of the 8.25 % Senior Notes and the 6.25 % Senior Notes, certain cross defaults of other indebtedness and mortgages, and certain failures to pay final judgments. 
+Restrictive covenants 
+The Company’s credit facility and the indentures governing its senior notes contain various covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. The Company was in compliance with these covenants at December 31, 2019 . 
+Note 8 – Derivative Instruments and Hedging Activities 
+Objectives and strategies for using derivative instruments 
+The Company is exposed to fluctuations in oil and natural gas prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil and natural gas production. The Company utilizes a mix of collars, swaps, and put and call options to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes. 
+Counterparty risk and offsetting 
+The use of derivative instruments exposes the Company to the risk that a counterparty will be unable to meet its commitments. While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right 
+80 
+of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument. “See Note 9 - Fair Value Measurements” for further discussion. 
+The Company executes commodity derivative contracts under master agreements with netting provisions that provide for offsetting assets against liabilities. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer, or terminate the arrangement. 
+Financial statement presentation and settlements 
+Settlements of the Company’s commodity derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets. See “ Note 9 - Fair Value Measurements” for additional information regarding fair value. 
+Contingent consideration arrangements 
+Ranger Divestiture. The Company’s Ranger Divestiture provides for potential contingent consideration to be received by the Company if commodity prices exceed specified thresholds in each of the next several years. See “Note 4 - Acquisitions and Divestitures” and “ Note 9 - Fair Value Measurements” for further discussion. This contingent consideration arrangement is summarized in the table below (in thousands except for per Bbl amounts): 
+Year 
+Threshold (1) 
+Contingent 
+Receipt - 
+Annual 
+Threshold (1) 
+Contingent 
+Receipt - 
+Annual 
+Period 
+Cash Flow 
+Occurs 
+Statement of 
+Cash Flows Presentation 
+Remaining Contingent 
+Receipt - 
+Aggregate Limit (3) 
+Divestiture 
+Date 
+Fair Value 
+$ 8,512 
+Pending Settlement 
+2019 
+Greater than $60/Bbl, less than $65/Bbl 
+$ — 
+Equal to or greater than $65/Bbl 
+$ — 
+1Q20 
+N/A 
+Remaining Potential Settlements 
+2020-2021 
+Greater than $60/Bbl, less than $65/Bbl 
+$ 9,000 
+Equal to or greater than $65/Bbl 
+$ 20,833 
+(2) 
+(2) 
+$ 60,000 
+(1) 
+The price used to determine whether the specified thresholds have been met is the average of the final monthly settlements for each month during each annual period end for NYMEX Light Sweet Crude Oil Futures, as reported by the CME Group Inc. 
+(2) 
+Cash received for settlements of contingent consideration arrangements are classified as cash flows from financing activities up to the divestiture date fair value with any excess classified as cash flows from operating activities. Therefore, if the commodity price threshold is reached, $ 8.5 million of the next contingent receipt will be presented in cash flows from financing activities with the remainder, as well as all subsequent contingent receipts, presented in cash flows from operating activities. 
+(3) 
+The specified pricing threshold for 2019 was not met. As such, approximately $ 41.5 million remains for potential settlements in future years. 
+As a result of the Carrizo Acquisition, the Company assumed all contingent consideration arrangements previously entered into by Carrizo. These contingent consideration arrangements are summarized below: 
+Contingent ExL Consideration 
+Year 
+Threshold (1) 
+Period 
+Cash Flow 
+Occurs 
+Statement of 
+Cash Flows Presentation 
+Contingent 
+Payment - 
+Annual 
+Remaining Contingent 
+Payments - 
+Aggregate Limit 
+Acquisition 
+Date 
+Fair Value 
+(In thousands) 
+($ 69,171 
+) 
+Pending Settlement 
+2019 
+$ 50.00 
+1Q20 
+Investing 
+($ 50,000 
+) 
+Remaining Potential Settlements 
+2020-2021 
+$ 50.00 
+(2) 
+(2) 
+($ 50,000 
+) 
+($ 75,000 
+) 
+(3) 
+(1) 
+The price used to determine whether the specified threshold for each year has been met is the average daily closing spot price per barrel of WTI crude oil as measured by the U.S. Energy Information Administration (“U.S. EIA”). 
+(2) 
+Cash paid for settlements of contingent consideration arrangements are classified as cash flows from financing activities up to the acquisition date fair value with any excess classified as cash flows from operating activities. Therefore, if the commodity price threshold is reached, all of the next contingent payment will be presented in cash flows from financing activities. 
+81 
+(3) 
+In January 2020, the Company paid $ 50.0 million as the specified pricing threshold was met. Only $ 25.0 million remains for potential settlements in future years. 
+Additionally, as part of the Carrizo Acquisition, the Company acquired contingent consideration arrangements where the Company could receive payments if certain pricing thresholds are met, which range between $ 53.00 - $ 60.00 per barrel of oil or $ 3.18 - $ 3.30 per MMBtu of natural gas. In January 2020, the Company received $ 10.0 million as the specified pricing thresholds were met for certain of the contingent consideration arrangements. As such, the aggregate limit of the remaining contingent receipts is $ 13.0 million and would be settled in January 2021 based on the specified pricing thresholds for 2020. 
+See “ Note 18 - Subsequent Events” for further discussion of the Company’s actual settlements of its contingent consideration arrangements subsequent to December 31, 2019. 
+Derivatives not designated as hedging instruments 
+The Company records its derivative instruments at fair value in the consolidated balance sheets and records changes in fair value as “(Gain) loss on derivative contracts” in the consolidated statements of operations. Settlements are also recorded as a gain or loss on derivative contracts in the consolidated statements of operations. 
+As previously discussed, the Company’s commodity derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated: 
+໿ 
+ 
+As of December 31, 2019 
+ 
+Presented without 
+As Presented with 
+ 
+Effects of Netting 
+Effects of Netting 
+Effects of Netting 
+(In thousands) 
+Commodity derivative instruments 
+$ 26,849 
+($ 17,511 
+) 
+$ 9,338 
+Contingent consideration arrangements 
+16,718 
+— 
+16,718 
+Fair value of derivatives - current 
+$ 43,567 
+($ 17,511 
+) 
+$ 26,056 
+Commodity derivative instruments 
+— 
+— 
+— 
+Contingent consideration arrangements 
+9,216 
+— 
+9,216 
+Fair value of derivatives - non current 
+$ 9,216 
+$ — 
+$ 9,216 
+Commodity derivative instruments 
+($ 38,708 
+) 
+$ 17,511 
+($ 21,197 
+) 
+Contingent consideration arrangements 
+( 50,000 
+) 
+— 
+( 50,000 
+) 
+Fair value of derivatives - current 
+($ 88,708 
+) 
+$ 17,511 
+($ 71,197 
+) 
+Commodity derivative instruments 
+( 12,935 
+) 
+— 
+( 12,935 
+) 
+Contingent consideration arrangements 
+( 19,760 
+) 
+— 
+( 19,760 
+) 
+Fair value of derivatives - non current 
+($ 32,695 
+) 
+$ — 
+($ 32,695 
+) 
+ 
+As of December 31, 2018 
+ 
+Presented without 
+As Presented with 
+ 
+Effects of Netting 
+Effects of Netting 
+Effects of Netting 
+(In thousands) 
+Fair value of derivatives - current 
+$ 78,091 
+($ 12,977 
+) 
+$ 65,114 
+Fair value of derivatives - current 
+($ 23,457 
+) 
+$ 12,977 
+($ 10,480 
+) 
+Fair value of derivatives - non current 
+( 7,440 
+) 
+— 
+( 7,440 
+) 
+82 
+The components of “(Gain) loss on derivative contracts” are as follows for the respective periods: 
+໿ 
+ 
+Years Ended December 31, 
+ 
+2019 
+2018 
+2017 
+(In thousands) 
+Oil derivatives 
+Net gain (loss) on settlements 
+($ 11,188 
+) 
+($ 27,510 
+) 
+($ 9,067 
+) 
+Net gain (loss) on fair value adjustments 
+( 62,125 
+) 
+72,973 
+( 11,426 
+) 
+Total gain (loss) on oil derivatives 
+( 73,313 
+) 
+45,463 
+( 20,493 
+) 
+Natural gas derivatives 
+Net gain (loss) on settlements 
+7,399 
+238 
+594 
+Net gain (loss) on fair value adjustments 
+1,490 
+2,843 
+998 
+Total gain (loss) on natural gas derivatives 
+8,889 
+3,081 
+1,592 
+Contingent consideration arrangements 
+Net gain (loss) on fair value adjustments 
+2,315 
+— 
+— 
+Total gain (loss) on derivative contracts 
+($ 62,109 
+) 
+$ 48,544 
+($ 18,901 
+) 
+83 
+Derivative positions 
+Listed in the tables below are the outstanding oil and natural gas derivative contracts as of December 31, 2019 : 
+For the Full Year of 
+For the Full Year of 
+Oil contracts (WTI) 
+2020 
+2021 
+Collar contracts with short puts (three-way collars) 
+Total volume (Bbls) 
+13,176,000 
+— 
+Weighted average price per Bbl 
+Ceiling (short call) 
+$ 65.28 
+$ 
+— 
+Floor (long put) 
+$ 55.38 
+$ 
+— 
+Floor (short put) 
+$ 45.08 
+$ 
+— 
+Short call contracts 
+Total volume (Bbls) 
+1,674,450 
+(1 
+) 
+4,825,300 
+(1) 
+Weighted average price per Bbl 
+$ 75.98 
+$ 63.62 
+Swap contracts 
+Total volume (Bbls) 
+1,303,900 
+— 
+Weighted average price per Bbl 
+$ 55.19 
+$ — 
+Swap contracts with short puts 
+Total volume (Bbls) 
+2,196,000 
+— 
+Weighted average price per Bbl 
+Swap 
+$ 56.06 
+$ — 
+Floor (short put) 
+$ 42.50 
+$ — 
+Oil contracts (Brent ICE) 
+Collar contracts with short puts (three-way collars) 
+Total volume (Bbls) 
+837,500 
+— 
+Weighted average price per Bbl 
+Ceiling (short call) 
+$ 70.00 
+$ — 
+Floor (long put) 
+$ 58.24 
+$ — 
+Floor (short put) 
+$ 50.00 
+$ — 
+Oil contracts (Midland basis differential) 
+Swap contracts 
+Total volume (Bbls) 
+8,476,700 
+4,015,100 
+Weighted average price per Bbl 
+($ 1.47 
+) 
+$ 0.40 
+Oil contracts (Argus Houston MEH basis differential) 
+Swap contracts 
+Total volume (Bbls) 
+1,439,205 
+— 
+Weighted average price per Bbl 
+$ 2.40 
+$ — 
+Oil contracts (Argus Houston MEH swaps) 
+Swap contracts 
+Total volume (Bbls) 
+504,500 
+— 
+Weighted average price per Bbl 
+$ 58.22 
+$ — 
+Natural gas contracts (Henry Hub) 
+Collar contracts (three-way collars) 
+Total volume (MMBtu) 
+3,660,000 
+— 
+Weighted average price per MMBtu 
+Ceiling (short call) 
+$ 2.75 
+$ — 
+Floor (long put) 
+$ 2.50 
+$ — 
+Floor (short put) 
+$ 2.00 
+$ — 
+Swap contracts 
+Total volume (MMBtu) 
+3,660,000 
+— 
+Weighted average price per MMBtu 
+$ 2.48 
+$ — 
+Short call contracts 
+Total volume (MMBtu) 
+12,078,000 
+7,300,000 
+Weighted average price per MMBtu 
+$ 3.50 
+$ 3.09 
+Natural gas contracts (Waha basis differential) 
+Swap contracts 
+Total volume (MMBtu) 
+21,596,000 
+— 
+Weighted average price per MMBtu 
+($ 1.04 
+) 
+$ — 
+(1) 
+Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars. 
+84 
+Draft 1 
+Note 9 – Fair Value Measurements 
+Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: 
+Level 1 – Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities. 
+Level 2 – Other inputs that are observable directly or indirectly such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. 
+Level 3 – Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities. 
+Fair value of financial instruments 
+Cash, cash equivalents, and restricted investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments. 
+Debt. The carrying amount of borrowings outstanding under the Credit Facility approximate fair value as the borrowings bear interest at variable rates and are reflective of market rates. The following table presents the principal amounts of the Company’s senior notes with the fair values measured using quoted secondary market trading prices which are designated as Level 2 within the valuation hierarchy. See “ Note 7 - Borrowings” for further discussion. 
+2019 
+2018 
+Principal Amount 
+Fair Value 
+Principal Amount 
+Fair Value 
+(In thousands) 
+6.25% Senior Notes 
+$ 650,000 
+$ 658,125 
+$ — 
+$ — 
+6.125% Senior Notes 
+600,000 
+611,130 
+600,000 
+558,000 
+8.25% Senior Notes 
+250,000 
+256,250 
+— 
+— 
+6.375% Senior Notes 
+400,000 
+405,424 
+400,000 
+372,000 
+Total 
+$ 1,900,000 
+$ 1,930,929 
+$ 1,000,000 
+$ 930,000 
+Assets and liabilities measured at fair value on a recurring basis 
+Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheet. The following methods and assumptions were used to estimate fair value: 
+Commodity derivative instruments. The fair value of commodity derivative instruments is derived using a third-party income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the commodity derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for commodity derivative assets and an estimate of the Company’s default risk for commodity derivative liabilities. As the inputs in the model are substantially observable over the term of the commodity derivative contract and there is a wide availability of quoted market prices for similar commodity derivative contracts, the Company designates its commodity derivative instruments as Level 2 within the fair value hierarchy. See “ Note 8 - Derivative Instruments and Hedging Activities” for further discussion. 
+Contingent consideration arrangements - embedded derivative financial instruments. The embedded options within the contingent consideration arrangements are considered financial instruments under ASC 815. The Company engages a third-party valuation specialist using an option pricing model approach to measure the fair value of the embedded options on a recurring basis. The valuation includes significant inputs such as forward oil price curves, time to expiration, and implied volatility. The model provides for the probability that the specified pricing thresholds would be met for each settlement period, estimates undiscounted payouts, and risk adjusts for the discount rates inclusive of adjustments for each of the counterparty’s credit quality. As these inputs are substantially observable for the full term of the contingent consideration arrangements, the inputs are considered Level 2 inputs within the fair value hierarchy. See “ Note 8 - Derivative Instruments and Hedging Activities” for further discussion. 
+85 
+Draft 1 
+The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2019 and 2018 : 
+December 31, 2019 
+Level 1 
+Level 2 
+Level 3 
+(In thousands) 
+Assets 
+Commodity derivative instruments 
+$ — 
+$ 9,338 
+$ — 
+Contingent consideration arrangements 
+— 
+25,934 
+— 
+Liabilities 
+Commodity derivative instruments 
+— 
+( 34,132 
+) 
+— 
+Contingent consideration arrangements 
+— 
+( 69,760 
+) 
+— 
+Total net assets (liabilities) 
+$ — 
+($ 68,620 
+) 
+$ — 
+ 
+December 31, 2018 
+Level 1 
+Level 2 
+Level 3 
+(In thousands) 
+Assets 
+Commodity derivative instruments 
+$ — 
+$ 65,114 
+$ — 
+Liabilities 
+Commodity derivative instruments 
+— 
+( 17,920 
+) 
+— 
+Total net liabilities (liabilities) 
+$ — 
+$ 47,194 
+$ — 
+Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis 
+Acquisitions. The fair value of assets acquired and liabilities assumed, other than the contingent consideration arrangements which are discussed above, are measured as of the acquisition date by a third-party valuation specialist using the income approach based on inputs that are not observable in the market and are therefore designated as Level 3 inputs. Significant inputs include expected discounted future cash flows from estimated reserve quantities, estimates for timing and costs to produce and develop reserves, oil and natural gas forward prices, and a risk adjusted discount rate. See “Note 4 - Acquisitions and Divestitures” for additional discussion. 
+Asset retirement obligations. The Company measures the fair value of asset retirement obligations as of the date a well begins drilling or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 within the valuation hierarchy. Significant inputs to the fair value measurement of asset retirement obligations include estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates. See “ Note 14 - Asset Retirement Obligations” for additional discussion. 
+Note 10 – Share-Based Compensation 
+2018 Omnibus Incentive Plan 
+The 2018 Omnibus Incentive Plan, which became effective May 10, 2018 following shareholder approval (the “2018 Plan”), authorized and reserved for issuance 9,400,000 shares of common stock, which may be issued upon exercise of vested stock options and/or the vesting of any other share-based equity award that is granted under this plan. The 2018 Plan replaced the 2011 Omnibus Incentive Plan (the “Prior Plan”), and included a provision at inception whereby all remaining, un-issued and authorized shares from the Prior Plan became issuable under the 2018 Plan. This transfer provision resulted in the transfer of an additional 1,322,742 shares into the 2018 Plan, increasing the quantity authorized and reserved for issuance under the 2018 Plan to 10,722,742 at the inception of the 2018 Plan. Another provision provided that shares, which would otherwise become available for issuance under the Prior Plan as a result of vesting and/or forfeiture of any equity awards existing as of the effective date of the 2018 Plan, would also increase the authorized shares available to the 2018 Plan. As a result of the Merger, the 2018 Plan was amended and restated to incorporate the 2017 Incentive Plan of Carrizo Oil & Gas, Inc. (the “Carrizo Plan”), including outstanding awards under the Carrizo Plan and shares available to grant to the former employees of Carrizo which were converted to shares of the Company by applying the conversion ratio of 1.75 shares of the Company per one share of Carrizo (the “Amended and Restated 2018 Plan”). At December 31, 2019 , there were 13,814,216 shares available for future share-based awards under the Amended and Restated 2018 Plan. 
+86 
+RSU Equity Awards 
+The following table summarizes RSU Equity Award activity for the years ended December 31, 2019 , 2018 and 2017 : 
+RSU Equity Awards (in thousands) 
+Weighted Average Grant-Date Fair Value per Share 
+For the Year Ended December 31, 2017 
+Unvested at the beginning of the period 
+1,448 
+$ 10.81 
+Granted (1) (2) 
+1,173 
+$ 12.25 
+Vested (3) 
+( 797 
+) 
+$ 11.35 
+Forfeited 
+( 34 
+) 
+$ 9.57 
+Unvested at the end of the period 
+1,790 
+$ 11.54 
+For the Year Ended December 31, 2018 
+Unvested at the beginning of the period 
+1,790 
+$ 11.54 
+Granted (1) 
+872 
+$ 13.89 
+Vested (3) 
+( 506 
+) 
+$ 9.56 
+Forfeited 
+( 53 
+) 
+$ 11.43 
+Unvested at the end of the period 
+2,103 
+$ 13.24 
+For the Year Ended December 31, 2019 
+Unvested at the beginning of the period 
+2,103 
+$ 13.24 
+Granted (1) 
+1,881 
+$ 8.60 
+Vested (3) 
+( 1,062 
+) 
+$ 12.35 
+Forfeited 
+( 227 
+) 
+$ 10.59 
+Unvested at the end of the period 
+2,695 
+$ 10.57 
+(1) 
+Includes 399,425 , 208,000 and 89,000 target performance-based RSU Equity Awards that will vest at a range of 0 % - 200 % for the years ended December 31, 2019 , 2018 and 2017 , respectively. 
+(2) 
+Includes 73,000 performance based RSU Equity Awards that were granted and subsequently vested at 142 % of target at issuance in 2017. 
+(3) 
+The fair value of shares vested was $ 7.3 million , $ 6.3 million and $ 9.0 million during the years ended December 31, 2019 , 2018 and 2017 , respectively. 
+Performance-based RSU Equity Awards that vest are based on a calculation that compares the Company’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between 0 % and 200 % of the base units awarded. The following table summarizes the shares that vested and did not vest as a result of the Company’s performance as compared to its peers. 
+Years Ended December 31, 
+Performance-based Equity Awards 
+2019 
+2018 
+2017 
+Vesting Multiplier 
+100 
+% 
+142 
+% 
+142% - 200% 
+Target 
+88,790 
+83,002 
+258,406 
+Vested at end of performance period 
+88,790 
+117,862 
+441,232 
+Did not vest at end of performance period 
+— 
+— 
+— 
+87 
+The Company recognizes expense for performance-based RSU Equity Awards based on the fair value of the awards at the grant date. Awards with a performance-based provision do not allow for the reversal of previously recognized expense, even if the market metric is not achieved and no shares ultimately vest. For the years ended December 31, 2019 , 2018 and 2017 , the grant date fair value of the performance-based RSU Equity Awards, calculated using a Monte Carlo simulation, was $ 4.3 million , $ 3.5 million , and $ 2.6 million , respectively. The following table summarizes the assumptions used and the resulting grant date fair value per performance-based RSU Equity Award granted during the years ended December 31, 2019 , 2018 and 2017 : 
+Years Ended December 31, 
+Performance-based Awards 
+2019 
+2018 
+2017 
+Number of simulations 
+100,000 
+100,000 
+100,000 
+Expected term (in years) 
+2.9 
+2.6 
+2.6 
+Expected volatility 
+47.9 
+% 
+51.6 
+% 
+65.3 
+% 
+Risk-free interest rate 
+2.4 
+% 
+2.6 
+% 
+1.5 
+% 
+Dividend yield 
+— 
+% 
+— 
+% 
+— 
+% 
+Grant date fair value per performance-based RSU Equity Award 
+$ 10.78 
+$ 16.66 
+$ 16.06 
+As of December 31, 2019 , unrecognized compensation costs related to unvested RSU Equity Awards were $ 15.1 million and will be recognized over a weighted average period of 1.3 years. 
+Cash-Settled RSU A wards 
+The table below summarizes the Cash-Settled RSU Award activity for the years ended December 31, 2019 , 2018 and 2017 : 
+Cash-Settled RSU Awards 
+(in thousands) 
+Weighted Average Grant-Date Fair Value per Share 
+For the Year Ended December 31, 2017 
+Unvested at the beginning of the period 
+734 
+$ 8.87 
+Granted 
+283 
+$ 12.13 
+Vested 
+( 379 
+) 
+$ 9.61 
+Forfeited 
+( 13 
+) 
+$ 9.54 
+Unvested at the end of the period 
+625 
+$ 9.88 
+For the Year Ended December 31, 2018 
+Unvested at the beginning of the period 
+625 
+$ 9.88 
+Granted 
+348 
+$ 14.16 
+Vested 
+( 276 
+) 
+$ 9.04 
+Forfeited 
+( 19 
+) 
+$ 12.05 
+Unvested at the end of the period 
+678 
+$ 12.36 
+For the Year Ended December 31, 2019 
+Unvested at the beginning of the period 
+678 
+$ 12.36 
+Granted 
+424 
+$ 8.14 
+Vested 
+( 164 
+) 
+$ 12.02 
+Forfeited 
+( 83 
+) 
+$ 11.58 
+Unvested at the end of the period 
+855 
+$ 10.41 
+All of the Company’s outstanding Cash-Settled RSU Awards include a performance-based vesting condition that determines the actual number of units that will ultimately vest. The number of Cash-Settled RSU Awards that vest is based on a calculation that compares the Company’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between 0 % and 200 % of the base units awarded. 
+For the year ended December 31, 2019 , 147,492 performance-based Cash-Settled RSU Awards vested at 100 % of their issued units, resulting in a payable amount of $ 0.7 million in 2020 . Also during 2019 , 16,600 non-performance-based Cash-Settled RSU Awards vested, resulting in cash payments of $ 0.1 million in 2019 . 
+For the year ended December 31, 2018 , 207,261 performance-based Cash-Settled RSU Awards subject to the peer performance-based vesting described above, vested between 100 % to 163 % of their issued units, depending on the date of the vesting, resulting in cash payments of $ 0.1 million in 2018 and $ 1.3 million in 2019 . Also during 2018 , 129,753 non-performance-based Cash-Settled RSU Awards vested, resulting in cash payments of $ 1.8 million during 2018 . 
+88 
+The following table summarizes the Company’s liability for Cash-Settled RSU Awards and the classification in the consolidated balance sheets for the periods indicated: 
+ 
+December 31, 
+2019 
+2018 
+Other current liabilities 
+$ 966 
+$ 1,390 
+Other long-term liabilities 
+2,089 
+2,067 
+Total Cash-Settled RSU Awards 
+$ 3,055 
+$ 3,457 
+As of December 31, 2019 , the Company had the following performance-based Cash-Settled RSU Awards outstanding: 
+Target Awards Outstanding 
+Potential Minimum Units Vesting 
+Potential Maximum Units Vesting 
+(In thousands) 
+Vesting in 2020 
+292 
+— 
+586 
+Vesting in 2021 
+373 
+— 
+745 
+Vesting in 2022 
+— 
+— 
+— 
+Other 
+24 
+24 
+24 
+Total Cash-Settled RSU Awards 
+689 
+24 
+1,355 
+As of December 31, 2019 , unrecognized compensation costs related to unvested Cash-Settled RSU Awards were $ 1.1 million and will be recognized over a weighted average period of 1.5 years. 
+Cash-Settled SARs 
+As a result of the Merger, Cash SARs previously granted by Carrizo that were outstanding at closing of the Merger were canceled and converted into a Cash SAR covering shares of the Company’s common stock, with the conversion calculated as prescribed in the agreement governing the Merger. The table below summarizes the Cash SAR activity for the year ended December 31, 2019 . 
+Stock Appreciation Rights 
+Weighted 
+Average 
+Exercise 
+Prices 
+Weighted Average Remaining Life 
+(In years) 
+Aggregate Intrinsic Value 
+(In millions) 
+For the Year Ended December 31, 2019 
+Outstanding, beginning of period 
+— 
+$ — 
+Granted 
+— 
+$ — 
+Reissued 
+3,677,955 
+$ 10.03 
+Exercised 
+— 
+$ — 
+Forfeited 
+— 
+$ — 
+Expired 
+— 
+$ — 
+Outstanding, end of period 
+3,677,955 
+$ 10.03 
+4.4 
+$ — 
+Vested, end of period 
+3,677,955 
+$ 10.03 
+0 
+$ — 
+Vested and exercisable, end of period 
+— 
+$ — 
+0 
+$ — 
+The acquisition date fair value of the Cash SARs, calculated using the Black-Scholes-Merton option pricing model was $ 4.6 million . The following table summarizes the assumptions used, the resulting acquisition date fair value per Cash SAR, and the expiration dates for the grants that occurred during periods presented below: 
+2019 
+2018 
+2017 
+2016 
+Fair Value Inputs 
+Expected term (in years) 
+5.4 
+4.5 
+1.9 
+1.1 
+Expected volatility 
+60.7 
+% 
+56.9 
+% 
+58.6 
+% 
+68.1 
+% 
+Risk-free interest rate 
+1.7 
+% 
+1.7 
+% 
+1.6 
+% 
+1.5 
+% 
+Dividend yield 
+— 
+% 
+— 
+% 
+— 
+% 
+— 
+% 
+Acquisition date fair value per Cash SAR 
+$ 2.11 
+$ 1.42 
+$ 0.21 
+$ 0.10 
+Expiration date 
+March 17, 2026 
+March 17, 2025 
+March 23, 2022 
+March 17, 2021 
+The liability for Cash SARs as of December 31, 2019 was $ 5.0 million , all of which was classified as “Other current liabilities” in the consolidated balance sheets in the respective period. Changes to the fair value of the Cash SARs are included in “General and 
+89 
+administrative” in the consolidated statements of operations. As all Cash SARs are vested, there is no unrecognized compensation costs as of December 31, 2019 . 
+Share-Based Compensation Expense, Net 
+The following table presents share-based compensation expense for each respective period: 
+Years Ended December 31, 
+2019 
+2018 
+2017 
+Share-based compensation cost for: 
+Equity 
+Liability 
+Equity 
+Liability 
+Equity 
+Liability 
+RSU Equity Awards (1) 
+$ 14,322 
+$ — 
+$ 9,460 
+$ — 
+$ 10,225 
+$ — 
+Cash-Settled RSU Awards (1) 
+— 
+1,021 
+— 
+336 
+— 
+4,294 
+Cash SARs 
+— 
+443 
+— 
+— 
+— 
+— 
+Total share-based compensation cost (2) 
+$ 14,322 
+$ 1,464 
+$ 9,460 
+$ 336 
+$ 10,225 
+$ 4,294 
+(1) 
+Includes the settlement of the outstanding share-based award agreements of the Company’s former Chief Executive Officer, resulting in $ 6.4 million recorded on the consolidated statements of operations as settled share-based awards for the year ended December 31, 2017. 
+(2) 
+The portion of this share-based compensation cost that was included in “General and administrative” totaled $ 11.1 million , $ 6.4 million and $ 5.0 million for the years ended December 31, 2019 , 2018 and 2017 , respectively, and the portion capitalized to oil and gas properties was $ 4.7 million , $ 3.4 million and $ 3.2 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively. 
+Note 11 – Stockholders’ Equity 
+Increase in Authorized Common Shares 
+As a result of the Carrizo Acquisition, the shareholders approved an amendment to the Company’s Certificate of Incorporation to increase the number of authorized shares of common stock from 300,000,000 to 525,000,000 . 
+10 % Series A Cumulative Preferred Stock (“Preferred Stock”) 
+Holders of the Company’s Preferred Stock were entitled to receive, when, as and if declared by the Company’s board of directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10 % per annum of the $ 50.00 liquidation preference per share (equivalent to $ 5.00 per annum per share). Dividends were payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by the Board of Directors. Preferred Stock dividends were $ 4.0 million, $ 7.3 million and $ 7.3 million for years ended December 31, 2019 , 2018 and 2017 , respectively. 
+On June 18, 2019, the Company announced it had given notice for the redemption (the “Redemption”) of all outstanding shares of the Preferred Stock. On July 18, 2019 (the “Redemption Date”), the Preferred Stock were redeemed at a redemption price equal to $ 50.00 per share, plus an amount equal to all accrued and unpaid dividends in an amount equal to $ 0.24 per share, for a total redemption price of $ 50.24 per share or $ 73.0 million (the “Redemption Price”). The Company recognized an $ 8.3 million loss on the redemption due to the excess of the $ 73.0 million redemption price over the $ 64.7 million redemption date carrying value of the Preferred Stock. 
+After the Redemption Date, the Preferred Stock were no longer deemed outstanding, dividends on the Preferred Stock ceased to accrue, and all rights of the holders with respect to such Preferred Stock were terminated, except the right of the holders to receive the Redemption Price, without interest. 
+Common Stock Offerings 
+On May 30, 2018, the Company completed an underwritten public offering of 25.3 million shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and offering costs) of approximately $ 288.0 million . The Company used proceeds from the offering to partially fund the Delaware Asset Acquisition completed in the third quarter of 2018. See “ Note 4 - Acquisitions and Divestitures” for further discussion of the Delaware Asset Acquisition. 
+On December 19, 2016, the Company completed an underwritten public offering of 40.0 million shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $ 634.9 million . Proceeds from the offering were used to partially fund the Ameredev Acquisition. See “ Note 4 - Acquisitions and Divestitures” for further discussion of the Ameredev Acquisition. 
+90 
+Note 12 – Income Taxes 
+The components of the Company’s income tax expense are as follows: 
+ 
+Years Ended December 31, 
+2019 
+2018 
+2017 
+(In thousands) 
+Current 
+Federal 
+$ — 
+$ — 
+($ 48 
+) 
+State 
+220 
+— 
+— 
+Total current income tax expense (benefit) 
+220 
+— 
+( 48 
+) 
+Deferred 
+Federal 
+33,584 
+3,594 
+( 45 
+) 
+State 
+1,497 
+4,516 
+1,366 
+Total deferred income tax expense 
+35,081 
+8,110 
+1,321 
+Total income tax expense 
+$ 35,301 
+$ 8,110 
+$ 1,273 
+A reconciliation of the income tax expense calculated at the federal statutory rate of 21% in 2019 and 2018 and 35% in 2017, to income tax expense is as follows: 
+ 
+Years Ended December 31, 
+2019 
+2018 
+2017 
+Income before income taxes 
+$ 103,229 
+$ 308,470 
+$ 121,697 
+Income tax expense computed at the statutory federal income tax rate 
+21,678 
+64,779 
+42,594 
+State income tax expense, net of federal benefit 
+1,253 
+3,568 
+1,273 
+Equity based compensation 
+1,222 
+( 494 
+) 
+— 
+Non-deductible compensation 
+90 
+1,209 
+— 
+Non-deductible merger expenses 
+5,537 
+— 
+— 
+Statutory depletion carryforward 
+5,381 
+— 
+— 
+Other 
+140 
+168 
+— 
+Change in valuation allowance 
+— 
+( 61,120 
+) 
+( 42,594 
+) 
+Income tax expense 
+$ 35,301 
+$ 8,110 
+$ 1,273 
+At December 31, 2019, the Company recorded a tax expense of $ 5.5 million associated with non-deductible merger expenses from the Carrizo Acquisition which primarily relate to non-deductible executive compensation expenses and transaction costs that are inherently facilitative in nature and permanently capitalized for tax purposes. 
+The Company recorded an income tax expense of $ 5.4 million related to the statutory depletion carryforward of $ 24.9 million . The percentage depletion deductions are in excess of the Company’s net depletable basis and can be carried forward indefinitely. The tax benefit for the special deduction will be recognized in the year the carryforward is deducted on the federal tax return. 
+91 
+As of December 31, 2019 and 2018, the net deferred income tax assets and liabilities are comprised of the following: 
+ 
+As of December 31, 
+2019 
+2018 
+(In thousands) 
+Deferred tax assets 
+Federal net operating loss carryforward 
+$ 110,703 
+$ 151,497 
+Interest expense carryforward 
+— 
+7,335 
+Statutory depletion carryforward 
+— 
+5,381 
+Asset retirement obligations 
+9,981 
+2,347 
+Derivative asset 
+14,823 
+— 
+Unvested RSU equity awards 
+4,928 
+2,751 
+Operating lease right-of-use assets 
+29,897 
+— 
+Other 
+10,445 
+991 
+Total deferred tax assets 
+$ 180,777 
+$ 170,302 
+Deferred income tax valuation allowance 
+— 
+— 
+Net deferred tax assets 
+$ 180,777 
+$ 170,302 
+Deferred tax liability 
+Oil and natural gas properties 
+($ 38,546 
+) 
+($ 169,682 
+) 
+Derivative liability 
+— 
+( 10,184 
+) 
+Operating lease liabilities 
+( 26,511 
+) 
+— 
+Total deferred tax liability 
+($ 65,057 
+) 
+($ 179,866 
+) 
+Net deferred tax asset (liability) 
+$ 115,720 
+($ 9,564 
+) 
+For federal income tax purposes, the Carrizo Acquisition qualified as a tax-free merger whereby the Company acquired carryover tax basis in Carrizo’s assets and liabilities. The Company recorded an opening balance sheet deferred tax asset of $ 159.3 million related to tax attributes acquired from Carrizo. The acquired income tax attributes primarily consist of future deductions related to oil and gas properties, derivative assets, and federal net operating losses (“NOLs”). The acquired NOLs are subject to an annual limitation under Internal Revenue Code Section 382 and the Company reduced the total NOL balance and associated deferred tax asset for the NOLs to the amount expected to be fully utilized prior to expirations. The Company expects that these tax attributes will be fully utilized prior to expiration. 
+Due to the issuance of common stock associated with the Carrizo acquisition, the Company incurred a cumulative ownership change and as such, the Company’s NOLs prior to the acquisition are subject to an annual limitation under Internal Revenue Code Section 382. At December 31, 2019, the Company had approximately $ 527.2 million of NOLs, including $ 288.2 million acquired from Carrizo, of which approximately $ 496.5 million expire between 2035 and 2037 and $ 30.7 million have an indefinite carryforward life. The Company expects that the NOL balance will be fully utilized prior to expiration. 
+Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that the Company’s net deferred tax assets will be utilized prior to their expiration. At December 31, 2019, management considered all factors including the expected reversal of deferred tax liabilities (including the impact of available carryforward periods), historical operating income tax planning strategies and projected future taxable income and determined that it is more likely than not that the Company will realize its remaining deferred tax assets. 
+The Company had no significant unrecognized tax benefits at December 31, 2019 . Accordingly, the Company does not have any interest or penalties related to uncertain tax positions. However, if interest or penalties were to be incurred related to uncertain tax positions, such amounts would be recognized in income tax expense. In the Company’s major tax jurisdictions, the earliest year open to examination is 2015. 
+Note 13 – L eases 
+The Company determines if an arrangement is a lease at inception of the contract and, if the contract is determined to be a lease, classifies the lease as an operating or financing lease. The Company recognizes an operating or financing lease on its consolidated balance sheets as a lease liability, which represents the present value of the Company’s obligation to make lease payments arising from the lease, with a related ROU asset, which represents the Company’s right to use the underlying asset for the lease term. The Company’s operating leases typically do not provide an implicit interest rate, therefore, the Company utilizes its incremental borrowing rate to calculate the present value of the lease payments based on information available at inception of the contract. 
+Lease expense for operating leases is recognized on a straight-line basis over the lease term. Lease expense for financing leases is comprised of interest expense on the financing lease liability and the amortization of the associated ROU asset, which is recognized on a straight- 
+92 
+line basis over the lease term. Variable lease expense that is not dependent on an index or rate is not included in the operating or financing lease liability or ROU asset and is recognized in the period in which the obligation for those payments is incurred. 
+Types of Leases 
+The Company currently has leases associated with contracts for drilling rigs, office space, and the use of well equipment, vehicles, information technology infrastructure, and other office equipment, with the significant lease types described in more detail below. 
+Drilling Rigs . The Company enters into contracts for drilling rigs with third parties to support its development plan. These contracts are typically for one to three years and can be extended upon mutual agreement with the third party by providing written notice at least thirty days prior to the end of the primary contractual term. The Company exercises its discretion in choosing whether or not to extend these contracts on a drilling rig by drilling rig basis as a result of evaluating the conditions that exist at the time the contract expires, such as availability of drilling rigs and the Company’s development plan. The Company has determined that it cannot conclude with reasonable certainty that it will choose to extend the contract past its primary term. As such, the Company uses the primary term in its calculation of the lease liability and ROU asset. The Company classifies its drilling rigs as operating leases and capitalizes the costs of the drilling rigs to oil and gas properties. 
+Office Space . The Company leases office space from third parties for its corporate office and certain field locations. These leases have non-cancelable terms between one to fifteen years . The Company has determined that it cannot conclude with reasonable certainty that it will exercise any option to extend the contract past the non-cancelable term. As such, the Company uses the non-cancelable term in its calculation of the lease liability and ROU asset. The Company classifies its leases for office space as operating leases with the costs recognized as “General and administrative” in its consolidated statements of operations. 
+Well Equipment . The Company rents compressors from third parties to facilitate the flow of production from its drilling operations to market. These contracts range from less than one year to three years for the primary term and continue thereafter on a month to month basis subject to cancellation by either party with thirty days’ notice. The Company classifies the compressors as operating leases with a lease term equal to the primary term for those contracts that have a primary term greater than one year. After the primary term, each party has a substantive right to terminate the lease, therefore, enforceable rights and obligations do not exist subsequent to the primary term. For those contracts that are less than one year, the Company has concluded that they represent short-term operating leases and therefore, an operating lease liability and ROU asset is not recorded in the consolidated balance sheets. These lease payments are recognized as “Lease operating” in the Company’s statements of operations. 
+The tables below, which present the components of lease costs and supplemental balance sheet information are presented on a gross basis. Other joint owners in the properties operated by the Company generally pay for their working interest share of costs associated with drilling rigs and well equipment. 
+The table below presents the components of the Company’s lease costs for the year ended December 31, 2019. 
+Year Ended December 31, 2019 
+(In thousands) 
+Components of Lease Costs 
+Finance lease costs 
+$ 92 
+Amortization of right-of-use assets (1) 
+82 
+Interest on lease liabilities (2) 
+10 
+Operating lease cost (3) 
+38,076 
+Impairment of Operating lease ROU assets (4) 
+16,209 
+Short-term lease cost (5) 
+3,640 
+Variable lease costs (6) 
+— 
+Total lease costs 
+$ 58,017 
+(1) 
+Included as a component of “Depreciation, depletion and amortization” in the consolidated statements of operations. 
+(2) 
+Included as a component of “Interest expense, net of capitalized amounts” in the consolidated statements of operations. 
+(3) 
+For the year ended December 31, 2019, approximately $ 34.9 million are costs associated with drilling rigs and are capitalized to “Evaluated properties, net” in the consolidated balance sheets and the other remaining operating lease costs are components of “General and administrative” and “Lease operating” in the consolidated statements of operations. 
+(4) 
+In conjunction with the Carrizo Acquisition, the Company evaluated certain of its office leases for impairment as the determination was made in 2019 that certain corporate offices would be consolidated. Upon evaluation, the Company recorded an impairment of certain of its Operating lease ROU assets of $ 16.2 million which is a component of “Merger and integration expenses” in the consolidated statements of operations. 
+(5) 
+Short-term lease cost excludes expenses related to leases with a contract term of one month or less. 
+(6) 
+Variable lease costs include additional payments that were not included in the initial measurement of the lease liability and related ROU asset for lease agreements with terms greater than 12 months. Variable lease costs primarily consist of incremental usage associated with drilling rigs. 
+93 
+The table below presents supplemental balance sheet information for the Company’s leases as of December 31, 2019. 
+Year Ended December 31, 2019 
+(In thousands) 
+Leases 
+Operating leases: 
+Operating lease ROU assets 
+$ 63,908 
+Current operating lease liabilities 
+$ 42,858 
+Long-term operating lease liabilities 
+37,088 
+Total operating lease liabilities 
+79,946 
+Financing leases: 
+Other property and equipment 
+$ 2,197 
+Accumulated depreciation 
+( 82 
+) 
+Other property and equipment, net 
+2,115 
+Current financing lease liabilities 
+$ 1,334 
+Long-term financing lease liabilities 
+807 
+Total financing lease liabilities 
+2,141 
+The table below presents the weighted average remaining lease terms and weighted average discounts rates for the Company’s leases as of December 31, 2019. 
+December 31, 2019 
+Weighted Average Remaining Lease Terms (In years) 
+Operating leases 
+4.3 
+Financing leases 
+2.1 
+Weighted Average Discount Rate 
+Operating leases 
+5.5 
+% 
+Financing leases 
+9.4 
+% 
+The table below presents the maturity of the Company’s lease liabilities as of December 31, 2019. 
+Operating Leases 
+Financing Leases 
+(In thousands) 
+2020 
+$ 45,864 
+$ 1,475 
+2021 
+11,648 
+275 
+2022 
+4,363 
+234 
+2023 
+4,209 
+233 
+2024 
+4,110 
+38 
+Thereafter 
+17,902 
+— 
+Total lease payments 
+88,096 
+2,255 
+Less imputed interest 
+8,150 
+114 
+Total lease liabilities 
+$ 79,946 
+$ 2,141 
+94 
+Note 14 – Asset Retirement Obligations 
+The table below summarizes the activity for the Company’s asset retirement obligations: 
+ 
+Years Ended December 31, 
+2019 
+2018 
+(In thousands) 
+Asset retirement obligations, beginning of period 
+$ 14,292 
+$ 6,020 
+Accretion expense 
+945 
+874 
+Liabilities incurred 
+615 
+973 
+Increase due to acquisition of oil and gas properties 
+26,107 
+570 
+Liabilities settled 
+( 3,394 
+) 
+( 1,288 
+) 
+Dispositions 
+( 1,776 
+) 
+( 614 
+) 
+Revisions to estimates 
+12,944 
+7,757 
+Asset retirement obligations, end of period 
+49,733 
+14,292 
+Less: Current asset retirement obligations 
+( 873 
+) 
+( 3,887 
+) 
+Non-current asset retirement obligations 
+$ 48,860 
+$ 10,405 
+Certain of the Company’s operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded on the consolidated balance sheets at December 31, 2019 and 2018 as long-term restricted investments were $ 3.5 million and $ 3.4 million , respectively, and are presented in “Other assets, net.” These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties. 
+Note 15 – Accounts Receivable, Net 
+As of December 31, 
+2019 
+2018 
+(In thousands) 
+Oil and natural gas receivables 
+$ 165,275 
+$ 87,062 
+Joint interest receivables 
+42,493 
+42,373 
+Other receivables 
+3,231 
+3,150 
+Total 
+210,999 
+132,585 
+Allowance for doubtful accounts 
+( 1,536 
+) 
+( 865 
+) 
+Total accounts receivable, net 
+$ 209,463 
+$ 131,720 
+Note 16 – Accounts Payable and Accrued Liabilities 
+As of December 31, 
+2019 
+2018 
+(In thousands) 
+Accounts payable 
+$ 238,758 
+$ 83,412 
+Revenues payable 
+145,816 
+94,114 
+Accrued capital expenditures 
+61,950 
+83,658 
+Accrued interest 
+36,295 
+24,665 
+Accrued severance (1) 
+28,803 
+— 
+Total accounts payable and accrued liabilities 
+$ 511,622 
+$ 285,849 
+(1) See “Note 4 - Acquisitions and Divestitures” for further information regarding the Carrizo Acquisition. 
+Note 17 – Commitments and Contingencies 
+The Company is involved in various claims and lawsuits incidental to its business. In the opinion of management, the ultimate liability hereunder, if any, will not have a material adverse effect on the financial position or results of operations of the Company. 
+The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment are not expected to have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies hereunder, and claims for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities. The table below presents total minimum commitments 
+95 
+associated with long-term, non-cancelable leases, drilling rig contracts and gathering, processing and transportation service agreements, which require minimum volumes of natural gas or produced water to be delivered, as of December 31, 2019 . 
+2020 
+2021 
+2022 
+2023 
+2024 
+2025 and Thereafter 
+Total 
+(In thousands) 
+Operating leases 
+$ 12,423 
+$ 8,399 
+$ 4,363 
+$ 4,209 
+$ 4,110 
+$ 17,902 
+$ 51,406 
+Drilling rig contracts (1) 
+33,441 
+3,249 
+— 
+— 
+— 
+— 
+36,690 
+Delivery commitments (2) 
+9,563 
+13,437 
+10,980 
+11,553 
+12,417 
+39,298 
+97,248 
+Produced water disposal commitments (3) 
+14,947 
+14,968 
+11,933 
+4,387 
+1,570 
+1,840 
+49,645 
+Total 
+$ 70,374 
+$ 40,053 
+$ 27,276 
+$ 20,149 
+$ 18,097 
+$ 59,040 
+$ 234,989 
+(1) 
+Drilling rig contracts represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will generally be billed for their working interest share of such costs. 
+(2) 
+Delivery commitments represent contractual obligations we have entered into for certain gathering, processing and transportation service agreements which require minimum volumes of natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any natural gas. 
+(3) 
+Produced water disposal commitments represent contractual obligations we have entered into for certain service agreements which require minimum volumes of produced water to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water. 
+Operating leases 
+As of December 31, 2019 , the Company had contracts for nine horizontal drilling rigs. The contract terms will end on various dates between January 2020 and May 2021. 
+Other commitments 
+In July 2019, the Company executed a crude oil sales contact that provides dedicated capacity on a new pipeline system that originates in Midland County, Texas and will have delivery points in several locations along the Gulf Coast. The Company will have a long-term 5,000 Bbls per day commitment for the term of the agreement and will apply applicable tariff rates to those quantities. Barrels may include volumes produced by the Company and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. 
+In June 2019, the Company executed a firm transportation agreement for dedicated capacity on a new pipeline system that originates in Midland, Texas and terminates in Houston, Texas. Subject to completion of the new pipeline system, which will have delivery points in several locations along the Gulf Coast, the Company will have a long-term commitment that will apply applicable tariff rates to our quantities committed that average 10,000 Bbls per day for the term of the agreement. Barrels may be transported to multiple delivery points along the Gulf Coast and may include volumes produced by the Company and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. 
+In January 2019, the Company executed a crude oil sales contract that provides further dedicated capacity on several pipeline systems that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard and Ward Counties, Texas and will have delivery points in several locations along the Gulf Coast, providing the Company with the potential benefit of access to an international weighted average sales price. The Company will have a long-term 10,000 Bbls per day commitment for the term of the agreement, and may include volumes produced by the Company and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. 
+In August 2018, the Company executed a firm transportation agreement for dedicated capacity on a new pipeline system that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard and Ward Counties, Texas to multiple marketing points in the Permian Basin. Subject to completion of the new pipeline system, which will have delivery points in several locations along the Gulf Coast, the Company will have a long-term commitment that will apply applicable tariff rates to our 15,000 Bbls per day commitment for the term of the agreement. Barrels may be transported to multiple delivery points along the Gulf Coast and may include volumes produced by the Company and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. 
+In March 2018, the Company entered into a contract for dedicated fracturing and pump down perforating crews, which was effective on April 16, 2018 for a two -year period. The agreement was amended effective October 16, 2018 to reflect updated market conditions and to extend the contract expiration date to December 31, 2021. 
+96 
+Note 18 – Subsequent Events (Unaudited) 
+Contingent Consideration Arrangements 
+For the year ended December 31, 2019 , the specified pricing thresholds related certain of the contingent consideration arrangements acquired in the Carrizo Acquisition were exceeded. As a result, in January 2020, the Company paid $ 50.0 million and received $ 10.0 million from settlement of a portion of these contingent consideration arrangements. 
+Note 19 - Supplemental Information on Oil and Natural Gas Operations (Unaudited) 
+Estimated Reserves 
+The estimated proved reserves obtained as a result of the Carrizo Acquisition were prepared by Ryder Scott Company, L.P. (“Ryder Scott”), the independent third party reserve engineers historically retained by Carrizo. All other estimated proved reserves for each respective year were prepared by DeGolyer and MacNaughton (“D&M”), Callon’s independent third party reserve engineers (together with Ryder Scott, the “Reserve Engineering Firms”). The reserves were prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions. 
+There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only, and should not be deemed exact. In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company’s oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves. 
+Extrapolation of performance history and material balance estimates were utilized by the Company’s Reserve Engineering Firms to project future recoverable reserves for the producing properties where sufficient history existed to suggest performance trends and where these methods were applicable to the subject reservoirs. The projections for the remaining producing properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to nonproducing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production, and to a small extent, horizontal PDP and PUD categories. 
+97 
+The following tables disclose changes in the estimated quantities of proved reserves, all of which are located onshore within the continental United States: 
+໿ 
+Years Ended December 31, 
+Proved reserves 
+2019 
+2018 
+2017 
+Oil (MBbls) 
+Beginning of period 
+180,097 
+107,072 
+71,145 
+Purchase of reserves in place 
+183,382 
+30,756 
+8,388 
+Sales of reserves in place 
+( 17,980 
+) 
+— 
+— 
+Extensions and discoveries 
+45,663 
+67,763 
+39,267 
+Revisions to previous estimates 
+( 33,136 
+) 
+( 16,051 
+) 
+( 5,171 
+) 
+Production 
+( 11,665 
+) 
+( 9,443 
+) 
+( 6,557 
+) 
+End of period 
+346,361 
+180,097 
+107,072 
+Natural Gas (MMcf) 
+Beginning of period 
+350,466 
+179,410 
+122,611 
+Purchase of reserves in place 
+455,158 
+53,563 
+12,711 
+Sale of reserves in place 
+( 86,856 
+) 
+— 
+— 
+Extensions and discoveries 
+82,566 
+103,149 
+48,648 
+Revisions to previous estimates 
+( 24,482 
+) 
+29,791 
+6,336 
+Production 
+( 19,718 
+) 
+( 15,447 
+) 
+( 10,896 
+) 
+End of period 
+757,134 
+350,466 
+179,410 
+NGLs (MBbls) 
+Beginning of period 
+— 
+— 
+— 
+Purchase of reserves in place 
+67,597 
+— 
+— 
+Production 
+( 135 
+) 
+— 
+— 
+End of period 
+67,462 
+— 
+— 
+Total (MBoe) 
+Beginning of period 
+238,508 
+136,974 
+91,580 
+Purchase of reserves in place 
+326,838 
+39,683 
+10,507 
+Sale of reserves in place 
+( 32,456 
+) 
+— 
+— 
+Extensions and discoveries 
+59,424 
+84,955 
+47,375 
+Revisions to previous estimates 
+( 37,216 
+) 
+( 11,086 
+) 
+( 4,115 
+) 
+Production 
+( 15,086 
+) 
+( 12,018 
+) 
+( 8,373 
+) 
+End of period 
+540,012 
+238,508 
+136,974 
+98 
+Years Ended December 31, 
+Proved developed reserves: 
+2019 
+2018 
+2017 
+Oil (MBbls) 
+Beginning of period 
+92,202 
+51,920 
+32,920 
+End of period 
+152,687 
+92,202 
+51,920 
+Natural gas (MMcf) 
+Beginning of period 
+218,417 
+104,389 
+61,871 
+End of period 
+320,676 
+218,417 
+104,389 
+NGLs (MBbls) 
+Beginning of period 
+— 
+— 
+— 
+End of period 
+24,844 
+— 
+— 
+Total proved developed reserves (MBoe) 
+Beginning of period 
+128,605 
+69,318 
+43,232 
+End of period 
+230,977 
+128,605 
+69,318 
+Proved undeveloped reserves 
+Oil (MBbls) 
+Beginning of period 
+87,895 
+55,152 
+38,225 
+End of period 
+193,674 
+87,895 
+55,152 
+Natural gas (MMcf) 
+Beginning of period 
+132,049 
+75,021 
+60,740 
+End of period 
+436,458 
+132,049 
+75,021 
+NGLs (MBbls) 
+Beginning of period 
+— 
+— 
+— 
+End of period 
+42,618 
+— 
+— 
+Total proved undeveloped reserves (MBoe) 
+Beginning of period 
+109,903 
+67,656 
+48,348 
+End of period 
+309,035 
+109,903 
+67,656 
+Total proved reserves 
+Oil (MBbls) 
+Beginning of period 
+180,097 
+107,072 
+71,145 
+End of period 
+346,361 
+180,097 
+107,072 
+Natural gas (MMcf) 
+Beginning of period 
+350,466 
+179,410 
+122,611 
+End of period 
+757,134 
+350,466 
+179,410 
+NGLs (MBbls) 
+Beginning of period 
+— 
+— 
+— 
+End of period 
+67,462 
+— 
+— 
+Total proved reserves (MBoe) 
+Beginning of period 
+238,508 
+136,974 
+91,580 
+End of period 
+540,012 
+238,508 
+136,974 
+Total Proved Reserves 
+The Company ended 2019 with estimated proved reserves of 540.0 MMBoe, representing a 126 % increase over 2018 year-end estimated proved reserves of 238.5 MMBoe. The Company added 386.3 MMBoe primarily from the Carrizo Acquisition completed in the fourth quarter of 2019 and development efforts in the Permian Basin, where it drilled a total of 61 gross ( 53.7 net) wells. This increase was offset by 2019 production, sales of reserves of 32.5 MMBoe, which are primarily related to the Ranger Divestiture, and negative revisions of previous estimates of 37.2 MMBoe. The negative revisions include 9.8 MMBoe from the reclassifications of PUDs within our optimized our development plans that were moved outside of the five-year development window. The primary driver of these changes in our previous development plan was the Carrizo Acquisition which allowed the Company to reallocate capital across the combined portfolio in an effort to increase capital efficiency and resulting cash flow generation. The remaining negative revisions were primarily from the observed impact of well spacing tests on producing wells and the related impact on reserve estimates as the Company advanced larger scale development concepts across its multi-zone inventory as well as the adverse effect of pricing and other economic factors. 
+The Company ended 2018 with estimated net proved reserves of 238.5 MMBoe, representing a 74 % increase over 2017 year-end estimated net proved reserves of 137.0 MMBoe. The Company added 124.6 MMBoe primarily from the Delaware Asset Acquisition completed third quarter of 2018 and development efforts in the Permian Basin, where it drilled a total of 70 gross ( 57.5 net) wells. This increase was offset by 2018 production, negative revisions of previous estimates of 2.0 MMBoe primarily related to technical revisions of proved undeveloped reserves, and reclassifications of proved undeveloped reserves of 9.1 MMBoe from 19 PUD locations primarily due to 
+99 
+acreage trades and changes in our development plan, including larger pad development concepts and co-development of zones. These changes resulted in the anticipated drilling of PUD locations being moved beyond five years from initial booking. 
+The Company ended 2017 with estimated net proved reserves of 137.0 MMBoe, representing a 50 % increase over 2016 year-end estimated net proved reserves of 91.6 MMBoe. The Company added 57.9 MMBoe primarily from the Company’s acquisition and development efforts in the Permian Basin, where it drilled a total of 49 gross ( 38.2 net) wells. This increase was primarily offset by 2017 production, revisions of previous estimates, and reclassifications of PUD locations from our development and drilling plan. The Company reclassified 13 PUD locations as a result of a change in the Company’s development and drilling plans within its operating areas and the removal of certain proved developed vertical well locations. 
+Capitalized Costs 
+Capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows: 
+As of December 31, 
+2019 
+2018 
+Oil and natural gas properties: 
+(In thousands) 
+Evaluated properties 
+$ 7,203,482 
+$ 4,585,020 
+Unevaluated properties 
+1,986,124 
+1,404,513 
+Total oil and natural gas properties 
+9,189,606 
+5,989,533 
+Accumulated depreciation, depletion, amortization and impairment 
+( 2,520,488 
+) 
+( 2,270,675 
+) 
+Total oil and natural gas properties capitalized 
+$ 6,669,118 
+$ 3,718,858 
+Costs Incurred 
+Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows: 
+Years Ended December 31, 
+2019 
+2018 
+2017 
+Acquisition costs: 
+(In thousands) 
+Evaluated properties 
+$ 49,572 
+$ 347,305 
+$ 156,340 
+Unevaluated properties 
+107,347 
+466,816 
+499,295 
+Development costs 
+189,259 
+259,410 
+148,254 
+Exploration costs 
+309,013 
+323,458 
+239,453 
+Total costs incurred 
+$ 655,191 
+$ 1,396,989 
+$ 1,043,342 
+Standardized Measure 
+The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2019 . You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Proved reserve estimates and future cash flows are based on the average realized prices for sales of oil, natural gas, and NGLs on the first calendar day of each month during the year. The following average realized prices were used in the calculation of proved reserves and the standardized measure of discounted future net cash flows. 
+໿ 
+Years Ended December 31, 
+2019 
+2018 
+2017 
+Oil ($/Bbl) (1) 
+$ 53.90 
+$ 58.40 
+$ 49.48 
+Natural gas ($/Mcf) (2) 
+$ 1.55 
+$ 3.64 
+$ 3.47 
+NGLs ($/Bbl) 
+$ 15.58 
+$ — 
+$ — 
+(1) 
+Includes adjustments to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality. 
+(2) 
+Includes a high Btu content of separator natural gas and adjustments to reflect the Btu content, transportation charges and other fees specific to the individual properties. 
+100 
+Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate. 
+໿ 
+Standardized Measure 
+For the Year Ended December 31, 
+2019 
+2018 
+2017 
+(In thousands) 
+Future cash inflows 
+$ 20,891,469 
+$ 11,794,080 
+$ 5,920,328 
+Future costs 
+Production 
+( 6,717,088 
+) 
+( 2,923,959 
+) 
+( 1,692,871 
+) 
+Development and net abandonment 
+( 3,058,861 
+) 
+( 1,429,787 
+) 
+( 680,948 
+) 
+Future net inflows before income taxes 
+11,115,520 
+7,440,334 
+3,546,509 
+Future income taxes 
+( 941,768 
+) 
+( 782,470 
+) 
+( 166,985 
+) 
+Future net cash flows 
+10,173,752 
+6,657,864 
+3,379,524 
+10% discount factor 
+( 5,222,726 
+) 
+( 3,716,571 
+) 
+( 1,822,842 
+) 
+Standardized measure of discounted future net cash flows 
+$ 4,951,026 
+$ 2,941,293 
+$ 1,556,682 
+໿ 
+ 
+Changes in Standardized Measure 
+ 
+For the Year Ended December 31, 
+ 
+2019 
+2018 
+2017 
+(In thousands) 
+Standardized measure at the beginning of the period 
+$ 2,941,293 
+$ 1,556,682 
+$ 809,832 
+Sales and transfers, net of production costs 
+( 579,744 
+) 
+( 481,306 
+) 
+( 294,172 
+) 
+Net change in sales and transfer prices, net of production costs 
+( 387,970 
+) 
+222,802 
+176,234 
+Net change due to purchases of in place reserves 
+2,975,296 
+554,697 
+129,454 
+Net change due to sales of in place reserves 
+( 303,526 
+) 
+— 
+— 
+Extensions, discoveries, and improved recovery, net of future production and development costs incurred 
+607,146 
+1,001,873 
+635,000 
+Changes in future development cost 
+205,398 
+40,483 
+( 8,148 
+) 
+Previously estimated development costs incurred 
+134,037 
+91,900 
+45,131 
+Revisions of quantity estimates 
+( 420,488 
+) 
+( 167,096 
+) 
+( 79,325 
+) 
+Accretion of discount 
+314,921 
+157,676 
+80,983 
+Net change in income taxes 
+( 210,641 
+) 
+( 187,841 
+) 
+( 20,073 
+) 
+Changes in production rates, timing and other 
+( 324,696 
+) 
+151,423 
+81,766 
+Aggregate change 
+2,009,733 
+1,384,611 
+746,850 
+Standardized measure at the end of period 
+$ 4,951,026 
+$ 2,941,293 
+$ 1,556,682 
+101 
+Draft 1 
+Note 20 - Supplemental Quarterly Financial Information (Unaudited) 
+The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2019 and 2018: 
+2019 
+First Quarter (2) 
+Second Quarter (3) 
+Third Quarter (4) 
+Fourth Quarter (5) 
+(In thousands, except per share amounts) 
+Total operating revenues 
+$ 153,047 
+$ 167,052 
+$ 155,378 
+$ 196,095 
+Income from operations 
+43,225 
+58,509 
+52,544 
+18,380 
+Net income (loss) 
+( 19,543 
+) 
+55,180 
+55,834 
+( 23,543 
+) 
+Income (loss) available to common stockholders 
+( 21,367 
+) 
+53,357 
+47,180 
+( 23,543 
+) 
+Income (loss) available to common stockholders per common share (1) 
+Basic 
+($ 0.09 
+) 
+$ 0.23 
+$ 0.21 
+($ 0.09 
+) 
+Diluted 
+($ 0.09 
+) 
+$ 0.23 
+$ 0.21 
+($ 0.09 
+) 
+2018 
+First Quarter 
+Second Quarter (6) 
+Third Quarter (7) 
+Fourth Quarter (8) 
+(In thousands, except per share amounts) 
+Total operating revenues 
+$ 127,440 
+$ 137,075 
+$ 161,214 
+$ 161,895 
+Income from operations 
+60,986 
+67,400 
+72,811 
+58,333 
+Net income 
+55,761 
+50,474 
+37,931 
+156,194 
+Income available to common stockholders 
+53,937 
+48,650 
+36,108 
+154,370 
+Income available to common stockholders per common share (1) 
+Basic 
+$ 0.27 
+$ 0.23 
+$ 0.16 
+$ 0.68 
+Diluted 
+$ 0.27 
+$ 0.23 
+$ 0.16 
+$ 0.68 
+(1) 
+The sum of quarterly income (loss) available to common stockholders per common share does not agree with the total year income (loss) available to common stockholders per common share as each computation is based on the weighted average of common shares outstanding during the period. 
+(2) 
+First quarter of 2019 included the following: 
+a. $ 67.3 million loss on derivative contracts 
+(3) 
+Second quarter of 2019 included the following: 
+a. $ 14.0 million gain on derivative contracts 
+(4) 
+Third quarter of 2019 included the following: 
+a. $ 21.8 million gain on derivative contracts 
+b. $ 5.9 million of merger and integration costs associated with the merger with Carrizo 
+c. $ 8.3 million loss on redemption of Preferred Stock 
+(5) 
+Fourth quarter of 2019 included the following: 
+a. Activity from the Carrizo Acquisition subsequent to the December 20, 2019 closing date. 
+b. $ 68.4 million of merger and integration costs associated with the merger with Carrizo 
+c. $ 30.7 million loss on derivative contracts 
+d. $ 4.9 million loss on extinguishment of debt 
+(6) 
+Second quarter of 2018 included the following: 
+a. $ 16.6 million loss on derivative contracts 
+(7) 
+Third quarter of 2018 included the following: 
+a. $ 34.3 million loss on derivative contracts 
+(8) 
+Fourth quarter of 2018 included the following: 
+a. 103.9 million gain on derivative contracts 
+102 
+ITEM 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure 
+None. 
+ITEM 9A. Controls and Procedures 
+Disclosure controls and procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) performed an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2019 . 
+Management’s report on internal control over financial reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. generally accepted accounting principles. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2019 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission (2013 framework) (the COSO criteria). Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2019 . Management’s evaluation of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of the entities acquired in the merger with Carrizo on December 20, 2019. Carrizo’s total assets and total operating revenue represented approximately 40% of the Company’s consolidated total assets at December 31, 2019 and 4% of the Company’s consolidated total operating revenue for the year ended December 31, 2019 . 
+Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+The Company’s independent registered public accounting firm, Grant Thornton, LLP, has issued an attestation report regarding its assessment of the Company’s internal control over financial reporting as of December 31, 2019 , presented preceding the Company’s financial statements included in Part II, Item 8 of this 2019 Annual Report on Form 10-K. Additionally, the financial statements for the years ended December 31, 2018 and 2017 , covered in this 2019 Annual Report on Form 10-K, have also been audited by the Company’s independent registered public accounting firm, whose report is presented preceding the their report on the Company’s internal control over financial reporting, included in Part II, Item 8. 
+Changes in internal control over financial reporting . As noted under “ Management’s report on internal control over financial reporting ”, management’s evaluation of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of the entities acquired in the merger with Carrizo on December 20, 2019. Under guidelines established by the SEC, companies are permitted to exclude acquisitions from their assessment of internal control over financial reporting during the first year of an acquisition while integrating the acquired company. The Company is in the process of integrating Carrizo’s and our internal controls over financial reporting. As a result of these integration activities, certain controls will be evaluated and may be changed. Except as noted above, there were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting. 
+ITEM 9B. Other Information 
+None. 
+103 
+PART III. 
+ITEM 10. Directors, Executive Officers and Corporate Governance 
+For information concerning Item 10, see the definitive proxy statement of Callon relating to the Annual Meeting of Stockholders to be held on May 14, 2020 , which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+The Company has adopted a code of ethics that applies to the Company’s officers, directors, employees, agents and representatives and includes a code of ethics for senior financial officers that applies to the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer. The full text of such code of ethics has been posted on the Company’s website at www.callon.com, and is available free of charge in print to any shareholder who requests it. Request for copies should be addressed to the Secretary at mailing address 2000 W. Sam Houston Parkway South, Suite 2000, Houston, TX 77042. 
+ITEM 11. Executive Compensation 
+For information concerning Item 11, see the definitive proxy statement of Callon relating to the Annual Meeting of Stockholders to be held on May 14, 2020 , which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+For information concerning the security ownership of certain beneficial owners and management, see the definitive proxy statement of Callon relating to the Annual Meeting of Stockholders to be held on May 14, 2020 , which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+ITEM 13. Certain Relationships and Related Transactions and Director Independence 
+For information concerning Item 13, see the definitive proxy statement of Callon relating to the Annual Meeting of Stockholders to be held on May 14, 2020 , which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+ITEM 14. Principal Accountant Fees and Services 
+For information concerning Item 14, see the definitive proxy statement of Callon relating to the Annual Meeting of Stockholders to be held on May 14, 2020 , which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+104 
+PART IV. 
+ITEM 15. Exhibits 
+The following is an index to the financial statements and financial statement schedules that are filed in Part II, Item 8 of this report on Form 10-K. 
+Incorporated by reference (File No. 001-14039, unless otherwise indicated) 
+Exhibit Number 
+Description 
+Form 
+Exhibit 
+Filing Date 
+2.1 
+Purchase and Sale Agreement, dated May 23, 2018, between Cimarex Energy Co, Prize Energy Resources, Inc., and Magnum Hunter Production, Inc. and Callon Petroleum Operating Company 
+8-K 
+2.1 
+05/24/2018 
+2.2 
+(d) 
+Purchase and Sale Agreement between Callon Petroleum Operating Company and Sequitur Permian, LLC dated April 8, 2019 
+8-K 
+2.1 
+06/13/2019 
+2.3 
+(d) 
+Agreement and Plan of Merger, dated as of July 14, 2019, by and between Callon Petroleum Company and Carrizo Oil & Gas, Inc. 
+8-K 
+2.1 
+07/15/2019 
+2.4 
+Amendment No. 1 to Agreement and Plan of Merger, dated August 19, 2019, by and between Callon Petroleum Company and Carrizo Oil & Gas, Inc. 
+10-Q 
+2.2 
+11/05/2019 
+2.5 
+Amendment No. 2 to Agreement and Plan of Merger, dated November 13, 2019, by and between Callon Petroleum Company and Carrizo Oil & Gas, Inc. 
+8-K 
+2.1 
+11/14/2019 
+3.1 
+Certificate of Incorporation of the Company, as amended through May 12, 2016 
+10-Q 
+3.1 
+11/03/2016 
+3.2 
+Certificate of Amendment to the Certificate of Incorporation of Callon, effective December 20, 2019 
+8-K 
+3.1 
+12/20/2019 
+3.3 
+Amended and Restated Bylaws of the Company 
+10-K 
+3.2 
+02/27/2019 
+4.1 
+Specimen Common Stock Certificate 
+10-K 
+4.1 
+02/28/2018 
+4.2 
+(a) 
+Description of Common Stock 
+4.3 
+Indenture of 6.125% Senior Notes Due 2024, dated as of October 3, 2016, among Callon Petroleum Company, the Guarantors party thereto and U.S. Bank National Association, as Trustee 
+8-K 
+4.1 
+10/04/2016 
+4.4 
+First Supplemental Indenture, dated December 20, 2019, among Callon, the Guarantors named therein and U.S. Bank National Association, as trustee 
+8-K 
+4.3 
+12/20/2019 
+4.5 
+Registration Rights Agreement of 6.125% Senior Notes Due 2024, dated October 3, 2016, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P. Morgan Securities LLC, as representative of the Initial Purchasers named on Annex E thereto 
+8-K 
+4.2 
+10/04/2016 
+4.6 
+Registration Rights Agreement of 6.125% Senior Notes Due 2024, dated May 24, 2017, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P. Morgan Securities LLC, as representative of the Initial Purchasers named on Annex E thereto 
+8-K 
+4.1 
+05/24/2017 
+4.7 
+Indenture of 6.375% Senior Notes Due 2026, dated as of June 7, 2018, among Callon Petroleum Company, the Guarantors party thereto and U.S. Bank National Association, as Trustee 
+8-K 
+4.1 
+06/07/2018 
+4.8 
+First Supplemental Indenture, dated December 20, 2019, among Callon, the Guarantors named therein and U.S. Bank National Association, as trustee 
+8-K 
+4.4 
+12/20/2019 
+4.9 
+Registration Rights Agreement of 6.375% Senior Notes Due 2026, dated June 7, 2018, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P. Morgan Securities LLC, as representative of the Initial Purchasers named on Annex E thereto 
+8-K 
+4.2 
+06/07/2018 
+4.10 
+Indenture, dated May 28, 2008, among Carrizo Oil & Gas, Inc., the subsidiaries named therein and Wells Fargo Bank, National Association, as trustee 
+8-K(File No. 000-29187-87) 
+4.1 
+05/28/2008 
+4.11 
+Sixteenth Supplemental Indenture, dated April 28, 2015, among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee 
+8-K(File No. 000-29187-87) 
+4.2 
+04/28/2015 
+4.12 
+Eighteenth Supplemental Indenture, dated May 20, 2015, among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee 
+8-K(File No. 000-29187-87) 
+4.2 
+05/22/2015 
+4.13 
+Twentieth Supplemental Indenture, dated July 14, 2017, among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee 
+8-K(File No. 000-29187-87) 
+4.2 
+07/14/2017 
+4.14 
+Twenty-First Supplemental Indenture, dated December 20, 2019, among Callon, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee 
+8-K 
+4.1 
+12/20/2019 
+4.15 
+Twenty-Second Supplemental Indenture, dated December 20, 2019, among Callon, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee 
+8-K 
+4.2 
+12/20/2019 
+4.16 
+Warrant Agreement, dated as of December 20, 2019, between Callon and American Stock Transfer And Trust Company, LLC, as warrant agent 
+8-K 
+4.5 
+12/20/2019 
+10.1 
+(d) 
+Credit Agreement, dated December 20, 2019, among Callon, JPMorgan Chase Bank, National Association, as administrative agent, and the lenders party thereto 
+8-K 
+10.1 
+12/20/2019 
+10.2 
+(b) 
+Callon Petroleum Company 2011 Omnibus Incentive Plan 
+DEF 14A 
+A 
+03/21/2011 
+10.3 
+(b) 
+Form of Callon Petroleum Company Restricted Stock Unit Award Agreement, adopted on March 12, 2015 
+10-K 
+10.16 
+03/03/2016 
+10.4 
+(b) 
+First Amendment to the Callon Petroleum Company 2011 Omnibus Incentive Plan 
+10-Q 
+10.1 
+11/05/2015 
+105 
+10.5 
+Amended and Restated Deferred Compensation Plan for Outside Directors - Callon Petroleum Company, dated as of May 10, 2017 and effective as of May 1, 2017 
+10-K 
+10.11 
+02/28/2018 
+10.6 
+(b) 
+Callon Petroleum Company 2018 Omnibus Incentive Plan 
+DEF 14A 
+A 
+03/23/2018 
+10.7 
+(a) 
+Amended and Restated 2018 Omnibus Incentive Plan 
+10.8 
+(b) 
+Form of Callon Petroleum Company Director Restricted Stock Unit Award Agreement, adopted on May 10, 2018 under the 2018 Omnibus Incentive Plan 
+10-Q 
+10.4 
+08/07/2018 
+10.9 
+(b) 
+Form of Callon Petroleum Company Employee Restricted Stock Unit Award Agreement, adopted on May 10, 2018 under the 2018 Omnibus Incentive Plan 
+10-Q 
+10.5 
+08/07/2018 
+10.10 
+(b) 
+Form of Callon Petroleum Company Employee Cash-Settleable Performance Share Award Agreement, adopted on May 10, 2018 under the 2018 Omnibus Incentive Plan 
+10-Q 
+10.6 
+08/07/2018 
+10.11 
+(b) 
+Form of Callon Petroleum Company Employee Stock-Settleable Performance Share Award Agreement, adopted on May 10, 2018 under the 2018 Omnibus Incentive Plan 
+10-Q 
+10.7 
+08/07/2018 
+10.12 
+(b) 
+Form of Change in Control Severance Compensation Agreement, dated as of January 1, 2019, by and between Callon Petroleum Company and its executive officers 
+10-K 
+10.17 
+02/27/2019 
+10.13 
+(b) 
+Change in Control Severance Compensation Agreement, dated as of January 1, 2019, by and between Joseph C. Gatto, Jr., and Callon Petroleum Company 
+10-K 
+10.18 
+02/27/2019 
+10.14 
+(b) 
+Carrizo Oil & Gas, Inc. Change in Control Severance Plan effective February 14, 2019 
+10-K(File No. 000-29187-87) 
+10.15 
+03/01/2019 
+10.15 
+Separation Agreement, dated January 2, 2019, by and between Gary A. Newberry and Callon Petroleum Company 
+10-K 
+10.19 
+02/27/2019 
+10.16 
+Separation Agreement, dated March 13, 2019, by and between Jerry A. Weant and Callon Petroleum Company 
+10-Q 
+10.1 
+05/07/2019 
+10.17 
+(b) 
+Form of Callon Petroleum Company Employee Restricted Stock Unit Award Agreement, adopted on January 31, 2019 under the 2018 Omnibus Incentive Plan 
+10-K 
+10.20 
+02/27/2019 
+10.18 
+(b) 
+Form of Callon Petroleum Officer Cash-Settleable Performance Share Award Agreement, adopted on January 31, 2019 under the 2018 Omnibus Incentive Plan 
+10-K 
+10.21 
+02/27/2019 
+10.19 
+(b) 
+Form of Callon Petroleum Company Officer Stock-Settleable Performance Share Award Agreement, adopted on January 31, 2019 under the 2018 Omnibus Incentive Plan 
+10-K 
+10.22 
+02/27/2019 
+10.20 
+(b) 
+Form of Callon Petroleum Company Officer Restricted Stock Unit Award Agreement, adopted on January 31, 2019 under the 2018 Omnibus Incentive Plan 
+10-K 
+10.23 
+02/27/2019 
+10.21 
+(b) 
+2017 Incentive Plan of Carrizo Oil &Gas, Inc. 
+8-K(File No. 000-29187-87) 
+10.1 
+05/16/2019 
+10.22 
+(a) 
+Form of Callon Petroleum Company Employee Restricted Stock Unit Award Agreement, adopted on January 31, 2020 under the Amended & Restated 2018 Omnibus Incentive Plan 
+10.23 
+(a) 
+Form of Callon Petroleum Officer Cash-Settleable Performance Share Award Agreement, adopted on January 31, 2020 under the Amended & Restated 2018 Omnibus Incentive Plan 
+10.24 
+(a) 
+Form of Callon Petroleum Company Officer Stock-Settleable Performance Share Award Agreement, adopted on January 31, 2020 under the Amended & Restated 2018 Omnibus Incentive Plan 
+10.25 
+(a) 
+Form of Callon Petroleum Company Officer Restricted Stock Unit Award Agreement, adopted on January 31, 2020 under the Amended & Restated 2018 Omnibus Incentive Plan 
+21.1 
+(a) 
+Subsidiaries of the Company 
+23.1 
+(a) 
+Consent of Grant Thornton LLP 
+23.2 
+(a) 
+Consent of DeGolyer and MacNaughton, Inc. 
+23.3 
+(a) 
+Consent of Ryder Scott Company, L.P. 
+31.1 
+(a) 
+Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a) 
+31.2 
+(a) 
+Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a) 
+32.1 
+(c) 
+Section 1350 Certifications of Chief Executive and Financial Officers pursuant to Rule 13(a)-14(b) 
+99.1 
+(a) 
+Reserve Report Summary prepared by DeGolyer and MacNaughton, Inc. as of December 31, 2019 
+99.2 
+(a) 
+Reserve Report Summary prepared by Ryder Scott Company, L.P. as of December 31, 2019 
+101.INS 
+(a) 
+XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. 
+101.SCH 
+(a) 
+Inline XBRL Taxonomy Extension Schema Document 
+101.CAL 
+(a) 
+Inline XBRL Taxonomy Extension Calculation Linkbase Document. 
+101.DEF 
+(a) 
+Inline XBRL Taxonomy Extension Definition Linkbase Document. 
+101.LAB 
+(a) 
+Inline XBRL Taxonomy Extension Label Linkbase Document. 
+101.PRE 
+(a) 
+Inline XBRL Taxonomy Extension Presentation Linkbase Document. 
+104 
+(a) 
+Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. 
+(a) 
+Filed herewith. 
+(b) 
+Indicates management compensatory plan, contract, or arrangement. 
+(c) 
+Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be 
+106 
+deemed to be incorporated by reference into any filing under the Securities Act of 1933, except to the extent that the registrant specifically incorporates it by reference. 
+(d) 
+Certain schedules and similar attachments have been omitted pursuant to Item 601(a)(5) of Regulation S-K. Callon agrees to furnish a supplemental copy of any omitted schedule or attachment to the SEC upon request. 
+107 
+ITEM 16. Form 10-K Summary 
+Not applicable. 
+108 
+SIGNATURES 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+Callon Petroleum Company 
+/s/ James P. Ulm, II 
+Date: 
+February 28, 2020 
+By: James P. Ulm, II 
+Chief Financial Officer (principal financial officer) 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+/s/ Joseph C. Gatto, Jr. 
+Date: 
+February 28, 2020 
+Joseph C. Gatto, Jr. (principal executive officer) 
+ 
+ 
+/s/ James P. Ulm, II 
+Date: 
+February 28, 2020 
+James P. Ulm, II (principal financial officer) 
+ 
+ 
+/s/ Gregory F. Conaway 
+Date: 
+February 28, 2020 
+Gregory F. Conaway (principal accounting officer) 
+ 
+/s/ L. Richard Flury 
+Date: 
+February 28, 2020 
+L. Richard Flury (chairman of the board of directors) 
+ 
+/s/ Frances Aldrich Sevilla-Sacasa 
+Date: 
+February 28, 2020 
+Frances Aldrich Sevilla-Sacasa (director) 
+ 
+/s/ Matthew R. Bob 
+Date: 
+February 28, 2020 
+Matthew R. Bob (director) 
+ 
+/s/ Barbara J. Faulkenberry 
+Date: 
+February 28, 2020 
+Barbara J. Faulkenberry (director) 
+ 
+/s/ Michael L. Finch 
+Date: 
+February 28, 2020 
+Michael L. Finch (director) 
+ 
+/s/ S.P. Johnson IV 
+Date: 
+February 28, 2020 
+S.P. Johnson IV (director) 
+ 
+/s/ Larry D. McVay 
+Date: 
+February 28, 2020 
+Larry D. McVay (director) 
+ 
+/s/ Anthony J. Nocchiero 
+Date: 
+February 28, 2020 
+Anthony J. Nocchiero (director) 
+ 
+/s/ James M. Trimble 
+Date: 
+February 28, 2020 
+James M. Trimble (director) 
+ 
+/s/ Steven A. Webster 
+Date: 
+February 28, 2020 
+Steven A. Webster (director) 
+ 
+109
\ No newline at end of file
diff --git a/raw/filings/0000928022/2019/0000928022-20-000031/filing_metadata.csv b/raw/filings/0000928022/2019/0000928022-20-000031/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..8ed6adbcbdefff89402fba9ae82e935581cc39df
--- /dev/null
+++ b/raw/filings/0000928022/2019/0000928022-20-000031/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000928022,CPE,Callon Petroleum Co,10-K,2020-02-28,2019-12-31,2020-02-28T21:41:11.000Z,0000928022-20-000031,a4q19form10k.htm,10-K,20588786,1,1,https://www.sec.gov/Archives/edgar/data/928022/000092802220000031/a4q19form10k.htm,https://www.sec.gov/Archives/edgar/data/928022/000092802220000031/,2019,2019,1
diff --git a/raw/filings/0000928022/2019/0000928022-20-000031/item1.txt b/raw/filings/0000928022/2019/0000928022-20-000031/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000928022/2019/0000928022-20-000031/item13.txt b/raw/filings/0000928022/2019/0000928022-20-000031/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..5b42fb2358217cb1b3d4f6dafa6ae4028bf40d46
--- /dev/null
+++ b/raw/filings/0000928022/2019/0000928022-20-000031/item13.txt
@@ -0,0 +1,2 @@
+ITEM 13. Certain Relationships and Related Transactions and Director Independence 
+For information concerning Item 13, see the definitive proxy statement of Callon relating to the Annual Meeting of Stockholders to be held on May 14, 2020 , which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2019/0000928022-20-000031/item9a.txt b/raw/filings/0000928022/2019/0000928022-20-000031/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..ca06aebbea10e30ccf20a1376bc50d0747b91bc0
--- /dev/null
+++ b/raw/filings/0000928022/2019/0000928022-20-000031/item9a.txt
@@ -0,0 +1,6 @@
+ITEM 9A. Controls and Procedures 
+Disclosure controls and procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) performed an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2019 . 
+Management’s report on internal control over financial reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. generally accepted accounting principles. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2019 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission (2013 framework) (the COSO criteria). Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2019 . Management’s evaluation of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of the entities acquired in the merger with Carrizo on December 20, 2019. Carrizo’s total assets and total operating revenue represented approximately 40% of the Company’s consolidated total assets at December 31, 2019 and 4% of the Company’s consolidated total operating revenue for the year ended December 31, 2019 . 
+Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+The Company’s independent registered public accounting firm, Grant Thornton, LLP, has issued an attestation report regarding its assessment of the Company’s internal control over financial reporting as of December 31, 2019 , presented preceding the Company’s financial statements included in Part II, Item 8 of this 2019 Annual Report on Form 10-K. Additionally, the financial statements for the years ended December 31, 2018 and 2017 , covered in this 2019 Annual Report on Form 10-K, have also been audited by the Company’s independent registered public accounting firm, whose report is presented preceding the their report on the Company’s internal control over financial reporting, included in Part II, Item 8. 
+Changes in internal control over financial reporting . As noted under “ Management’s report on internal control over financial reporting ”, management’s evaluation of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of the entities acquired in the merger with Carrizo on December 20, 2019. Under guidelines established by the SEC, companies are permitted to exclude acquisitions from their assessment of internal control over financial reporting during the first year of an acquisition while integrating the acquired company. The Company is in the process of integrating Carrizo’s and our internal controls over financial reporting. As a result of these integration activities, certain controls will be evaluated and may be changed. Except as noted above, there were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2019/0000928022-20-000031/rp_note.txt b/raw/filings/0000928022/2019/0000928022-20-000031/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000928022/2019/0000928022-20-000031/rpt_disclosure.txt b/raw/filings/0000928022/2019/0000928022-20-000031/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..a27097e1447823efdde938be53831fb58908068f
--- /dev/null
+++ b/raw/filings/0000928022/2019/0000928022-20-000031/rpt_disclosure.txt
@@ -0,0 +1,13 @@
+Certain Relationships and Related Party Transactions 
+The Audit Committee charter provides that the Audit Committee shall review and approve all related party transactions. A transaction will be considered a “related party transaction” if the transaction would be required to be disclosed under Item 404 of Regulation S-K. In addition, our Code provides that an officer’s or a director’s conflict of interest with Callon may only be waived if the N&ESG Committee approves the waiver and the full Board ratifies the waiver. 
+We are not aware of any related party transactions with our executive officers that require disclosure under Item 404 of Regulation S-K. 
+Shareholders’ Proposals and Director Nominations for the 2022 Annual Meeting 
+In order for a proposal to be considered for inclusion in the proxy statement for the 2022 Annual Meeting of Shareholders (the “2022 Annual Meeting”) pursuant to Rule 14a-8 of the Exchange Act, such proposal must be received by the Secretary of the Company at our principal executive offices no later than December 10, 2021 (assuming the date of the 2022 Annual Meeting has not been changed by more than 30 days from the date of this year’s Annual Meeting), and must otherwise be in compliance with the requirements of the SEC’s proxy rules. If the date of the 2022 Annual Meeting has been changed by more than 30 days from the date of this Annual Meeting, then the deadline is a reasonable time before we begin to print and send our proxy materials for the 2022 Annual Meeting. 
+For a shareholder proposal to be introduced for consideration at the 2022 Annual Meeting but not intended to be considered for inclusion in the Company's proxy statement and form of proxy relating to such meeting (i.e. not pursuant to Rule 14a-8 of the Exchange Act), including shareholder nominations for candidates for election as directors, a shareholder must provide written notice of such proposal to Company not later than 120 days nor earlier than 150 days before the date of the 2022 Annual Meeting. Any such notice must describe the shareholder proposal in reasonable detail and otherwise comply with the requirements set forth in our bylaws. 
+Nominating Process 
+In accordance with our certificate of incorporation, any shareholder may nominate a person for election to the Board upon delivery of written notice to us of such nomination. Such notice must be sent as provided in our certificate of incorporation on or before the deadline set forth in our certificate of incorporation, and must otherwise comply with the procedures set forth in our certificate of incorporation. For nominations, the Board will consider individuals identified by shareholders on the same basis as nominees identified from other sources. A submission recommending a nominee should include: 
+• Sufficient biographical information to allow the N&ESG Committee to evaluate the qualifications of a potential nominee in light of the director nomination procedures and criteria and any other information that would be required to be disclosed in solicitations of proxies for the election of directors; 
+• An indication as to whether the proposed nominee will meet the requirements for independence under NYSE and SEC guidelines; 
+• A description of all direct and indirect compensation and other material monetary agreements, arrangements, and understandings during the past three years, and any other material relationships, between or among the nominating shareholder or beneficial owner and each proposed nominee; 
+• A completed and signed questionnaire, representation, and agreement, pursuant to our bylaws, with respect to each nominee for election or re-election to the Board; and 
+• The proposed nominee’s written consent to serve if nominated and elected.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2020/0000928022-21-000021/filing.txt b/raw/filings/0000928022/2020/0000928022-21-000021/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..731b98245ee0bfd6f6824a20d778e22419347b30
--- /dev/null
+++ b/raw/filings/0000928022/2020/0000928022-21-000021/filing.txt
@@ -0,0 +1,3219 @@
+cpe-20201231 
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+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+FORM 10-K 
+☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the fiscal year ended December 31 , 2020 
+or 
+☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the transition period from ____________ to ____________ 
+Commission File Number 001-14039 
+Callon Petroleum Co mpany 
+(Exact Name of Registrant as Specified in Its Charter) 
+_______________________________________________ 
+Delaware 64-0844345 
+State or Other Jurisdiction of 
+Incorporation or Organization I.R.S. Employer Identification No. 
+One Briarlake Plaza 
+2000 W. Sam Houston Parkway S., Suite 2000 
+Houston, Texas 77042 
+Address of Principal Executive Offices Zip Code 
+281 - 589-5200 
+(Registrant’s Telephone Number, Including Area Code) 
+Title of Each Class Securities registered pursuant to Section 12(b) of the Act: Name of Each Exchange on Which Registered 
+Common Stock, $0.01 par value CPE New York Stock Exchange 
+Securities registered pursuant to section 12 (g) of the Act: None 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐ 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒ 
+Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ 
+Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐ 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act: 
+Large accelerated filer ☐ Accelerated filer ☒ Non-accelerated filer ☐ 
+Smaller reporting company ☐ Emerging growth company ☐ 
+. 
+If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ 
+Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ 
+The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2020 was approximately $ 443.3 million. 
+The Registrant had 46,153,710 shares of common stock outstanding as of February 23, 2021 . 
+DOCUMENTS INCORPORATED BY REFERENCE 
+Portions of the definitive proxy statement of Callon Petroleum Company (to be filed no later than 120 days after December 31, 2020) relating to the 2021 Annual Meeting of Shareholders, which are incorporated into Part III of this Form 10-K. 
+TABLE OF CONTENTS 
+Special Note Regarding Forward - Looking Statements 
+3 
+Glossary of Certain Terms 
+5 
+Part I 
+Items 1 and 2. 
+Business and Properties 
+7 
+Oil and Natural Gas Properties 
+9 
+Proved Oil and Gas Reserves 
+10 
+Capital Budget 
+14 
+Drilling Activity 
+15 
+Productive Wells 
+15 
+Production Volumes, Average Sales Prices and Operating Costs 
+16 
+Major Customers 
+19 
+Leasehold Acreage 
+19 
+Other 
+20 
+Regulations 
+21 
+Commitments and Contingencies 
+30 
+Available Information 
+30 
+Item 1A. 
+Risk Factors 
+31 
+Item 1B. 
+Unresolved Staff Comments 
+44 
+Item 3. 
+Legal Proceedings 
+44 
+Item 4. 
+Mine Safety Disclosures 
+44 
+Part II 
+Item 5. 
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+45 
+Performance Graph 
+46 
+Item 6. 
+Selected Financial Dat a 
+47 
+Item 7. 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+47 
+General 
+47 
+Overview 
+47 
+Results of Operations 
+49 
+Liquidity and Capital Resources 
+55 
+Summary of Critical Accounting Policies 
+61 
+Item 7A. 
+Quantitative and Qualitative Disclosures About Market Risk 
+64 
+Item 8. 
+Financial Statements and Supplementary Data 
+67 
+Reports of Independent Registered Public Accounting Firm 
+68 
+Consolidated Balance Sheets 
+71 
+Consolidated Statements of Operations 
+72 
+Consolidated Statements of Stockholders’ Equity 
+73 
+Consolidated Statements of Cash Flows 
+74 
+Notes to Consolidated Financial Statements 
+75 
+Supplemental Information on Oil and Natural Gas Operations (Unaudited) 
+110 
+Supplemental Quarterly Financial Information (Unaudited) 
+114 
+Item 9. 
+Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+115 
+Item 9A. 
+Controls and Procedures 
+115 
+Item 9B. 
+Other Information 
+116 
+Part III 
+Item 10. 
+Directors, Executive Officers and Corporate Governance 
+116 
+Item 11. 
+Executive Compensation 
+116 
+Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+116 
+Item 13. 
+Certain Relationships and Related Transactions and Director Independence 
+116 
+Item 14. 
+Principal Accountant Fees and Services 
+116 
+Part IV. 
+Item 15. 
+Exhibits 
+117 
+Item 16. 
+Form 10-K Summary 
+119 
+Signatures 
+120 
+2 
+Special Note Regarding Forward-Looking Statements 
+This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”), as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements in this Form 10-K by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions. 
+All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future are forward-looking statements, including such things as: 
+• our oil and natural gas reserve quantities, and the discounted present value of these reserves; 
+• the amount and nature of our capital expenditures; 
+• our future drilling and development plans and our potential drilling locations; 
+• the timing and amount of future capital and operating costs; 
+• production decline rates from our wells being greater than expected; 
+• commodity price risk management activities and the impact on our average realized prices; 
+• business strategies and plans of management; 
+• our ability to efficiently integrate recent acquisitions; and 
+• prospect development and property acquisitions. 
+We caution you that the forward-looking statements contained in this Annual Report on Form 10-K (this “2020 Annual Report on Form 10-K”) are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. We disclose these and other important factors that could cause our actual results to differ materially from our expectations under “Risk Factors” in Item 1A of Part I in this 2020 Annual Report on Form 10-K. These factors include: 
+• the volatility of oil and natural gas prices or a prolonged period of low oil or natural gas prices; 
+• general economic conditions, including the availability of credit and access to existing lines of credit; 
+• changes in the supply of and demand for oil and natural gas, including as a result of the COVID-19 pandemic and various governmental actions taken to mitigate its impact or actions by, or disputes among, members of OPEC and other oil and natural gas producing countries, such as Russia, with respect to production levels or other matters related to the price of oil; 
+• the uncertainty of estimates of oil and natural gas reserves; 
+• impairments; 
+• the impact of competition; 
+• the availability and cost of seismic, drilling and other equipment, waste and water disposal infrastructure, and personnel; 
+• operating hazards inherent in the exploration for and production of oil and natural gas; 
+• difficulties encountered during the exploration for and production of oil and natural gas; 
+• the potential impact of future drilling on production from existing wells 
+• difficulties encountered in delivering oil and natural gas to commercial markets; 
+• the uncertainty of our ability to attract capital and obtain financing on favorable terms; 
+• compliance with, or the effect of changes in, the extensive governmental regulations regarding the oil and natural gas business including those related to climate change and greenhouse gases; 
+• the impact of government regulation, including regulation of hydraulic fracturing and water disposal wells; 
+• any increase in severance or similar taxes; 
+• the financial impact of accounting regulations and critical accounting policies; 
+• the comparative cost of alternative fuels; 
+• credit risk relating to the risk of loss as a result of non-performance by our counterparties; 
+• cyberattacks on the Company or on systems and infrastructure used by the oil and natural gas industry; 
+• weather conditions; and 
+• risks associated with acquisitions, including the acquisition of Carrizo Oil & Gas, Inc. (the “Carrizo Acquisition” or the “Merger”). 
+Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Additional risks or uncertainties that are not currently known to us, that we currently deem to be immaterial, or that could apply to any company could also materially adversely affect our business, financial condition, or future results. Any forward-looking statement speaks only as of the date of which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except required by applicable law. 
+In addition, we caution that reserve engineering is a process of estimating oil and natural gas accumulated underground and cannot be measured exactly. Accuracy of reserve estimates depend on a number of factors including data available at the point in time, 
+3 
+engineering interpretation of the data, and assumptions used by the reserve engineers as it relates to price and cost estimates and recoverability. New results of drilling, testing, and production history may result in revisions of previous estimates and, if significant, would impact future development plans. As such, reserve estimates may differ from actual results of oil and natural gas quantities ultimately recovered. 
+Except as required by applicable law, all forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. 
+4 
+GLOSSARY OF CERTAIN TERMS 
+All defined terms under Rule 4-10(a) of Regulation S-X shall have their prescribed meanings when used in this report. As used in this document: 
+• ARO : asset retirement obligation. 
+• ASU : accounting standards update. 
+• Bbl or Bbls : barrel or barrels of oil or natural gas liquids. 
+• Boe : barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of natural gas. The ratio of one barrel of oil or NGLs to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas. 
+• Boe/d : Boe per day. 
+• Btu : a British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit. 
+• Completion : the process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency. 
+• Cushing : an oil delivery point that serves as the benchmark oil price for West Texas Intermediate. 
+• Development well : A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. 
+• EPA : United States Environmental Protection Agency. 
+• Exploratory well : a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. 
+• Extension well : a well drilled to extend the limits of a known reservoir. 
+• FASB : Financial Accounting Standards Board. 
+• GAAP : Generally Accepted Accounting Principles in the United States. 
+• GHG : greenhouse gases. 
+• Henry Hub : a natural gas pipeline delivery point that serves as the benchmark natural gas price underlying NYMEX natural gas futures contracts. 
+• Horizontal drilling : a drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at an angle within a specified interval. 
+• ICE: Intercontinental Exchange. 
+• LIBOR : London Interbank Offered Rate. 
+• LOE : lease operating expense. 
+• MBbls : thousand barrels of oil. 
+• MBoe : thousand Boe. 
+• Mcf : thousand cubic feet of natural gas. 
+• MEH : Magellan East Houston, a delivery point in Houston, Texas that serves as a benchmark for crude oil. 
+• MMBoe : million Boe. 
+• MMBtu : million Btu. 
+• MMcf : million cubic feet of natural gas. 
+• NGL or NGLs : natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams. 
+• Non-productive well : A well that is found to be incapable of producing oil or gas in sufficient quantities to justify completion, or upon completion, the economic operation of an oil or gas well. 
+• NYMEX : New York Mercantile Exchange. 
+• Oil : includes crude oil and condensate. 
+• OPEC : Organization of Petroleum Exporting Countries. 
+• PDPs : proved developed producing reserves. 
+• Productive well : A well that is found to be capable of producing oil or gas in sufficient quantities to justify completion as an oil or gas well. 
+• Proved developed producing reserves: Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. 
+• Proved reserves: Those reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time. 
+5 
+The area of the reservoir considered as proved includes all of the following: 
+a. The area identified by drilling and limited by fluid contacts, if any, and 
+b. Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. 
+Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when both of the following occur: 
+a. Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based, and 
+b. The project has been approved for development by all necessary parties and entities, including governmental entities. 
+Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12‑month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. 
+• Proved undeveloped reserves: Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. Under no circumstances shall estimates of proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty. 
+• PUDs : proved undeveloped reserves. 
+• PV-10 (Non-GAAP) : the present value of estimated future gross revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date indicated (unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure of discounted future net cash flows calculation, it does provide an indicative representation of the relative value of the Company on a comparative basis to other companies from period to period. This is a non-GAAP measure. See “Items 1 and 2 - Business and Properties - Proved Oil and Gas Reserves - Reconciliation of Standardized Measure of Discounted Future Net Cash Flows (GAAP) to PV-10 (Non-GAAP)”. 
+• Realized price : the cash market price less all expected quality, transportation and demand adjustments. 
+• Royalty interest : an interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development. 
+• RSU : restricted stock units. 
+• SEC : United States Securities and Exchange Commission. 
+• Waha : a natural gas delivery point in West Texas that serves as the benchmark for natural gas. 
+• Working interest : an operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations. 
+• WTI : West Texas Intermediate grade crude oil, used as a pricing benchmark for sales contracts and NYMEX oil futures contracts. 
+With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross. 
+6 
+PART I. 
+ITEMS 1 and 2 – Business and Properties 
+Overview 
+Callon Petroleum Company has been engaged in the exploration, development, acquisition and production of oil and natural gas properties since 1950. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. 
+We are an independent oil and natural gas company focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas. Our activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger Permian Basin in West Texas, as well as the Eagle Ford, which we entered into through our acquisition of Carrizo Oil & Gas, Inc. (“Carrizo”) in late 2019. Our primary operations in the Permian reflect a high-return, oil-weighted drilling inventory with multiple prospective horizontal development intervals and are complemented by a well-established and repeatable cash flow generating business in the Eagle Ford. 
+Major Developments in 2020 
+COVID-19 Outbreak and Global Industry Downturn. The worldwide outbreak of COVID-19 in 2020, the uncertainty regarding the impact of COVID-19 and various governmental actions taken to mitigate the impact of COVID-19 have resulted in an unprecedented decline in demand for oil and natural gas. At the same time, the decision by Saudi Arabia in March 2020 to drastically reduce export prices and increase oil production followed by curtailment agreements among OPEC and other countries such as Russia further increased uncertainty and volatility around global oil supply-demand dynamics. As a result, there is an excess supply of oil in the United States, which could continue for a sustained period; this is in addition to recent and continued excess supply of natural gas in the United States. This excess supply, in turn, resulted in transportation and storage capacity constraints in the United States during 2020, although these constraints have recently lessened and inventories have declined from peak levels. 
+The COVID-19 outbreak and its development into a pandemic in March 2020 have required that we take precautionary measures intended to help minimize the risk to our business, employees, customers, suppliers and the communities in which we operate. Our operational employees continue to work on site. However, we have taken various precautionary measures with respect to such operational employees such as requiring them to verify they have not experienced any symptoms consistent with COVID-19, or been in close contact with someone showing such symptoms, before reporting to the work site, being prepared to quarantine any operational employees who have shown signs of COVID-19 (regardless of whether such employee has been confirmed to be infected), and, while at the work site, imposing safety protocols in accordance with the guidelines released by the Centers for Disease Control and Prevention. In addition, a large portion of our non-operational employees are now working remotely, and we have established COVID-19 specific safety protocols for those working from the office. We have not yet experienced any material operational disruptions (including disruptions from our suppliers and service providers) as a result of the COVID-19 outbreak. 
+Financing and Liquidity Updates 
+• As of December 31, 2020, our senior secured revolving credit facility (“Credit Facility”) had a borrowing base and elected commitment amount of $1.6 billion and borrowings outstanding of $985.0 million. 
+• On November 13, 2020, we completed an exchange with certain holders of our 6.25% Senior Notes due 2023 (the “6.25% Senior Notes”), 6.125% Senior Notes due 2024 (the “6.125% Senior Notes”), 8.25% Senior Notes due 2025 (the “8.25% Senior Notes”), and 6.375% Senior Notes due 2026 (the “6.375% Senior Notes” and together with the 6.25% Senior Notes, the 6.125% Senior Notes and 8.25% Senior Notes, the “Senior Unsecured Notes”) to exchange $389.0 million of aggregate principal amount of Senior Unsecured Notes for $216.7 million of our 9.00% Second Lien Senior Secured Notes due 2025 (the “November 2020 Second Lien Notes”) and warrants for 1.75 million shares of common stock (the “November 2020 Warrants”). 
+• On September 30, 2020, we issued $300.0 million in aggregate principal amount of our 9.00% Second Lien Senior Secured Notes due 2025 (“September 2020 Second Lien Notes” and together with the November 2020 Second Lien Notes the “Second Lien Notes”) and warrants for 7.3 million shares of common stock (“September 2020 Warrants”) for proceeds, net of issuance costs, of approximately $288.6 million. 
+See “Note 7 – Borrowings”, “Note 8 - Derivative Instruments and Hedging Activities” and “Note 11 – Stockholders’ Equity” of the Notes to our Consolidated Financial Statements for further discussion. 
+Divestitures. On September 30, 2020, we sold an undivided 2.0% (on an 8/8ths basis) overriding royalty interest, proportionately reduced to our net revenue interest, in and to our operated leases, excluding certain interests (“ORRI Transaction”). On November 2, 2020, we also closed on a sale of substantially all of our non-operated assets. We received combined net proceeds of approximately $165.4 million, which was used to repay borrowings outstanding under the Credit Facility. 
+7 
+See “Note 4 – Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for further discussion. 
+Reverse Stock Split. On August 7, 2020 following approval by our shareholders at the June 8, 2020 annual meeting of shareholders of an amendment to our Certificate of Incorporation to effect a reverse stock split, our Board of Directors approved a reverse stock split of our common stock at a ratio of 1-for-10 and a proportionate reduction in the number of authorized shares of our common stock. Our common stock began trading on a split-adjusted basis on August 10, 2020 upon opening of the markets. See “Note 11 – Stockholders’ Equity” of the Notes to our Consolidated Financial Statements for further discussion. 
+Operational Activity. Due to the decline in crude oil prices in 2020 and ongoing uncertainty regarding the oil supply-demand macro environment, we reduced our development plan in order to preserve capital, including the temporary cessation of all drilling and completion activities for most of the second and third quarters of 2020. We reactivated two completion crews, one each in the Eagle Ford and Permian, both of which completed previously drilled multi-well projects during September. Subsequently, one of the two completion crews was released and three drilling rigs resumed operations, two restarting operations in the Permian during September and the third reactivated in the Eagle Ford during October. This reduction in activity resulted in our actual 2020 operational capital expenditures to be approximately 50% of our original operational capital budget for 2020 of $975.0 million. 
+During the year ended December 31, 2020, we drilled 91 gross (86.0 net) wells and completed 90 gross (81.4 net) wells. Our net daily production was 101,620 Boe/d (approximately 63% oil), an increase of approximately 146% when compared to the year ended December 31, 2019, primarily as a result of the properties acquired in the Carrizo Acquisition in late 2019 as well as our developmental activities during the year. For the year ended December 31, 2020, our estimated proved reserves were 475.9 MMBoe and included proved oil reserves of 289.5 MMBbls (61% of total proved reserves). Approximately 45% of our 2020 year-end estimated proved reserves were classified as proved developed. See “— Summary of 2020 Proved Reserves, Production and Drilling by Region” below for additional details. 
+Our Business Strategy 
+Our principal objective is to enhance shareholder value through capital efficient development of our proved reserves, management of our operating costs, and maximization of cash flows while acting as a responsible corporate citizen in the areas in which we operate. Key elements of the execution of this strategy include: 
+• Improving the capital efficiency of our operations in terms of both well productivity and capital outlays, including supporting facilities; 
+• Optimizing the development of our multi-zone resource base through thoughtful plans of life of field development that are informed by extensive analysis of subsurface data and empirical well results; 
+• Maturing our asset base into a sustainable operating model for profitable reinvestment of cash flows for attractive, long-term returns on capital; 
+• Maintaining strong cash margins per unit of production through cost management and proactive investment in production infrastructure; 
+• Enhancing our financial position, focusing on appropriate capital allocation decisions under various commodity pricing scenarios, prudent risk management and generating free cash flow to reduce leverage; 
+• Maximizing and preserving our inventory of well locations through selective delineation of emerging targets on our existing acreage positions and scaled development of proven areas to minimize potential degradation of future drilling locations; and 
+• Integrating sustainable business practices that minimize our impact on the environment, empower and develop a diverse workforce, and enrich our communities. 
+Our Strengths 
+We believe the following attributes position Callon to achieve its objectives: 
+• Strong Foundation - Reputation as a safe and responsible operator built over several decades in the oil and gas industry; 
+• Quality Assets - High quality Permian asset base with several years of proven well results from multiple target zones that benefit from early investments in critical supporting infrastructure including sustainable investments in water recycling and a more mature asset base in the Eagle Ford which has lower operational risk and generates repeatable, profitable well results; 
+• Operational Control - High degree of operational control that allows us to efficiently maximize value through daily and long-term decisions that drive our strategy; 
+• Talented Workforce - Seasoned employee base that has benefited from the addition of employees from the Carrizo Acquisition, who have been integrated into our collaborative culture; 
+8 
+• Sustainable Business Practices - Focus on value creation in a responsible manner by utilizing an operating philosophy that provides our employees a safe workplace while at the same time conducting operations in a manner that is environmentally sensitive and community aware. See our Sustainability Report published on our company website (www.callon.com) for performance highlights and additional information. Information contained in our Sustainability Report is not incorporated by reference into, and does not constitute a part of, this 2020 Annual Report on Form 10-K. 
+Oil and Natural Gas Properties 
+Summary of 2020 Proved Reserves, Production and Drilling by Region 
+Permian Eagle Ford Total 
+Proved reserves 
+Crude oil (MBbls) 215,572 73,915 289,487 
+Natural gas (MMcf) 477,160 64,438 541,598 
+NGLs (MBbls) 84,369 11,757 96,126 
+Total proved reserves (MBoe) 379,467 96,412 475,879 
+Proved reserves by classification (MBoe) 
+Proved developed 164,660 47,265 211,925 
+Proved undeveloped 214,807 49,147 263,954 
+Total proved reserves (MBoe) 379,467 96,412 475,879 
+Percent of proved developed reserves 78 % 22 % 100 % 
+Percent of proved undeveloped reserves 81 % 19 % 100 % 
+Percent of total reserves 80 % 20 % 100 % 
+Production volumes Total Per Day Total Per Day Total Per Day 
+Crude oil (MBbls and Bbls/d) 14,113 38,560 9,430 25,765 23,543 64,325 
+Natural gas (MMcf and Mcf/d) 32,087 87,669 8,714 23,809 40,801 111,478 
+NGLs (MBbls and Bbls/d) 5,390 14,727 1,460 3,989 6,850 18,716 
+Total production volumes (MBoe and Boe/d) 24,851 67,899 12,342 33,721 37,193 101,620 
+Percent of total production 67 % 33 % 100 % 
+Permian Eagle Ford Total 
+Operated Well Data Gross Net Gross Net Gross Net 
+Drilled 52 47.3 39 38.7 91 86.0 
+Completed 52 46.9 38 34.5 90 81.4 
+As of December 31, 2020 
+Drilled but uncompleted 28 25.3 37 36.8 65 62.1 
+Producing 846 738.3 650 582.3 1,496 1,320.6 
+Regional Overview 
+Permian 
+As of December 31, 2020, our acreage position comprised 130,349 gross (106,371 net) acres in the Permian, all of which was located in the Midland and Delaware Basins. Average net production from our Permian properties increased approximately 69% to 67,899 Boe/d in 2020 from 40,287 Boe/d in 2019, primarily as a result of the Carrizo Acquisition. We currently expect to direct the majority of our 2021 Capital Budget, as defined below, towards opportunities in the Permian. 
+Eagle Ford 
+We acquired our Eagle Ford properties, primarily located in LaSalle County and, to a lesser extent, in McMullen, Frio and Atascosa counties in Texas, through the Carrizo Acquisition in late 2019. As of December 31, 2020, we held interests in approximately 90,079 gross (73,683 net) acres. Average net production from our Eagle Ford properties was 33,721 Boe/d in 2020. 
+9 
+Proved Oil and Gas Reserves 
+The following table sets forth summary information with respect to our estimated proved reserves, standardized measure of discounted future net cash flows and PV-10 for the years ended December 31, 2020, 2019, and 2018. For each year in the table below, the estimated proved reserves were prepared by DeGolyer and MacNaughton (“D&M”), Callon’s independent third party reserve engineers, with the exception of the estimated proved reserves in 2019 obtained as a result of the Carrizo Acquisition in late 2019, which were prepared by Ryder Scott Company, L.P. (“Ryder Scott”), the independent third party reserve engineers historically retained by Carrizo. For further information concerning D&M’s estimates of our proved reserves as of December 31, 2020, see the reserve report included as an exhibit to this 2020 Annual Report on Form 10-K. The prices used in the calculation of our estimated proved reserves and PV-10 were based on the average realized prices for sales of oil, NGLs, and natural gas on the first calendar day of each month during the year (“12-Month Average Realized Price”) in accordance with SEC rules. 
+As of December 31, 
+2020 2019 2018 
+Proved developed reserves (1)(2) 
+Crude oil (MBbls) 128,923 152,687 92,202 
+Natural gas (MMcf) 238,119 320,676 218,417 
+NGLs (MBbls) 43,315 24,844 — 
+Total proved developed reserves (MBoe) 211,925 230,977 128,605 
+Proved undeveloped reserves (1)(2) 
+Crude oil (MBbls) 160,564 193,674 87,895 
+Natural gas (MMcf) 303,479 436,458 132,049 
+NGLs (MBbls) 52,811 42,618 — 
+Total proved undeveloped reserves (MBoe) 263,954 309,035 109,903 
+Total proved reserves (1)(2) 
+Crude oil (MBbls) 289,487 346,361 180,097 
+Natural gas (MMcf) 541,598 757,134 350,466 
+NGLs (MBbls) 96,126 67,462 — 
+Total proved reserves (MBoe) 475,879 540,012 238,508 
+Proved developed reserves % 45 % 43 % 54 % 
+Proved undeveloped reserves % 55 % 57 % 46 % 
+12-Month Average Realized Prices 
+Crude oil ($/Bbl) $37.44 $53.90 $58.40 
+Natural gas ($/Mcf) $1.02 $1.55 $3.64 
+NGLs ($/Bbl) $11.10 $15.58 $— 
+Standardized measure of discounted future net cash flows (GAAP) (in millions) $2,310.4 $4,951.0 $2,941.3 
+PV-10 (Non-GAAP) (in millions): 
+Proved developed PV-10 $1,577.3 $3,246.8 $2,222.0 
+Proved undeveloped PV-10 767.7 2,122.8 927.2 
+Total PV-10 (Non-GAAP) $2,345.0 $5,369.6 $3,149.2 
+(1) Effective January 1, 2020, certain of our natural gas processing agreements were modified to allow us to take title to NGLs resulting from the processing of our natural gas. As a result, reserve volumes for NGLs and natural gas are presented separately for periods subsequent to January 1, 2020. For periods prior to January 1, 2020, except for reserve volumes specifically associated with Carrizo, we presented our reserve volumes for NGLs with natural gas. 
+(2) Includes the proved reserves associated with the Carrizo Acquisition for the years ended December 31, 2020 and 2019. 
+Reconciliation of Standardized Measure of Discounted Future Net Cash Flows (GAAP) to PV-10 (Non-GAAP) 
+We believe that the presentation of PV-10 provides greater comparability when evaluating oil and gas companies due to the many factors unique to each individual company that impact the amount and timing of future income taxes. In addition, we believe that PV-10 is widely used by investors and analysts as a basis for comparing the relative size and value of our proved reserves to other oil and gas companies. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company’s financial or operating performance presented in accordance with GAAP. The 
+10 
+definition of PV-10 as defined in “Glossary of Certain Terms” may differ significantly from the definitions used by other companies to compute similar measures. As a result, PV-10 as defined may not be comparable to similar measures provided by other companies. A reconciliation of the standardized measure of discounted future net cash flows to PV-10 is presented below. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of our proved oil and gas reserves. 
+As of December 31, 
+2020 2019 2018 
+(In millions) 
+Standardized measure of discounted future net cash flows (GAAP) $2,310.4 $4,951.0 $2,941.3 
+Add: present value of future income taxes discounted at 10% per annum 34.6 418.6 207.9 
+PV-10 (Non-GAAP) $2,345.0 $5,369.6 $3,149.2 
+Proved Reserves 
+Our reserve estimates are conducted from fundamental petrophysical, geological, engineering, financial and accounting data. Reserves are estimated based on production decline analysis, analogy to producing offsets, detailed reservoir modeling, volumetric calculations or a combination of these methods, in all cases having regard to economic considerations and using technologies that have been demonstrated in the field to yield repeatable and consistent results as defined in the SEC regulations. To establish reasonable certainty of our proved reserves estimates, including material additions to our proved reserves, we use certain technologies and economic data, including production and well test data, historical well costs and operating data, geologic and seismic data, and subsurface information obtained through wellbores such as electrical logs, radioactive logs, reservoir core samples, fluid samples, and static and dynamic pressure information. Non-producing reserves are estimated by analogy to producing offsets, with consideration given to a development plan approved by Callon’s management. 
+As of December 31, 2020, our estimated proved reserves totaled 475.9 MMBoe, a decrease of 12% from the prior year end, and included 289.5 MMBbls of oil, 541.6 Bcf of natural gas and 96.1 MMBbls of NGLs with a standardized measure of discounted future net cash flows of $2.3 billion. Oil constituted approximately 61% of our total estimated proved reserves as well as our total estimated proved developed reserves. The following table provides a summary of the changes in our proved reserves for the year ended December 31, 2020. 
+Total 
+(MBoe) 
+Proved reserves as of December 31, 2019 540,012 
+Extensions and discoveries 41,407 
+Revisions to previous estimates (52,227) 
+Sales of reserves in place (16,120) 
+Production (37,193) 
+Proved reserves as of December 31, 2020 475,879 
+Further details of the changes in our proved reserves for the year ended December 31, 2020 are as follows: 
+• Extensions and discoveries. We added 41.4 MMBoe of new reserves in extensions and discoveries through our development efforts in our operating areas. See the table below for the impact of extensions and discoveries on total proved and proved undeveloped reserves for 2020: 
+Extensions and discoveries Total 
+(MBoe) 
+Total proved 41,407 
+Proved undeveloped 29,698 
+Difference (Proved developed producing) (1) 
+11,709 
+(1) These extensions and discoveries were not recognized as proved undeveloped reserves in a prior period, but rather were recognized directly as proved developed producing reserves as there was not an offset proved developed producing location at the time of drilling in order to classify as a proved undeveloped location. 
+We incurred costs of $77.5 million for the extensions and discoveries associated with proved developed producing wells during 2020. 
+11 
+• Revisions to previous estimates. The table below shows the components of the net negative revisions of previous estimates of 52.2 MMBoe. 
+Total 
+(MBoe) 
+Pricing (1) 
+(26,254) 
+Performance (2) 
+(24,210) 
+PUDs removed due to changes in development plan (3) 
+(23,923) 
+NGL yield (4) 
+14,658 
+Assumptions for operational expenses (5) 
+7,502 
+Total revisions to previous estimates (52,227) 
+(1) Primarily as a result of the change in 12-Month Average Realized Price of crude oil, which decreased by approximately 31% as compared to December 31, 2019. Included in the decrease in the table above was 2.1 MMBoe associated with proved developed producing wells and 0.8 MMBoe associated with proved undeveloped wells that were no longer economic at December 31, 2020 as a result of the decrease in the 12-Month Average Realized Price of crude oil. 
+(2) Primarily related to reductions in anticipated hydrocarbon recoveries resulting from observed well performance over longer production timeframes during the testing of various full field development plan concepts. 
+(3) Removed primarily as a result of changes in anticipated well densities as we develop our properties in an effort to increase capital efficiency and cash flow generation. 
+(4) Volumetric impact from presenting NGLs and natural gas separately due to the modification of certain of our natural gas processing agreements which allow us to take title to NGLs resulting from the processing of our natural gas subsequent to January 1, 2020. For periods prior to January 1, 2020, except for reserve volumes specifically associated with Carrizo, we presented our reserve volumes for NGLs with natural gas. 
+(5) Reduced assumptions for operational expenses as we continued to improve our field practices during the integration of the properties acquired from Carrizo. 
+• Sales of reserves in place. The 16.1 MMBoe of sales of reserves in place were primarily associated with the ORRI Transaction and the sale of substantially all of our non-operated assets. See “Note 4 - Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for further discussion. 
+Proved Undeveloped Reserves 
+Annually, we review our PUDs to ensure appropriate plans exist for development of this reserve category. PUD reserves are recorded only if we have plans to convert these reserves into PDPs within five years of the date they are first recorded. Our development plans include the allocation of capital to projects included within our 2021 Capital Budget, as defined below, and, in subsequent years, the allocation of capital within our long-range business plan to convert PUDs to PDPs within this five-year period. The following table provides a summary of the changes in our PUDs for the year ended December 31, 2020. 
+Total 
+(MBoe) 
+PUDs as of December 31, 2019 309,036 
+Extensions and discoveries 29,698 
+Revisions to previous estimates (27,220) 
+Sales of reserves in place (6,158) 
+Converted to proved developed (41,402) 
+PUDs as of December 31, 2020 263,954 
+• Extensions and discoveries. We added 29.7 MMBoe of new reserves in extensions and discoveries as a result of additional offset locations associated with our drilling program. 
+12 
+• Revisions to previous estimates. The table below shows the components of the net negative revisions of previous estimates of 27.2 MMBoe. 
+Total 
+(MBoe) 
+PUDs removed due to changes in development plan (1) 
+(23,923) 
+Pricing (2) 
+(7,101) 
+NGL yield (3) 
+4,648 
+Performance (4) 
+(4,280) 
+Assumptions for operational expenses (5) 
+3,436 
+Total revisions to previous estimates (27,220) 
+(1) Removed primarily as a result of changes in anticipated well densities as we develop our properties in an effort to increase capital efficiency and cash flow generation. 
+(2) Primarily as a result of the change in 12-Month Average Realized Price of crude oil which decreased by approximately 31% as compared to December 31, 2019. Included in the decrease in the table above was 0.8 MMBoe associated with proved undeveloped wells that were no longer economic at December 31, 2020. 
+(3) Volumetric impact from presenting NGLs and natural gas separately due to the modification of certain of our natural gas processing agreements which allow us to take title to NGLs resulting from the processing of our natural gas subsequent to January 1, 2020. For periods prior to January 1, 2020, except for reserve volumes specifically associated with Carrizo, we presented our reserve volumes for NGLs with natural gas. 
+(4) Primarily related to reductions in anticipated hydrocarbon recoveries resulting from observed well performance over longer production timeframes during the testing of various full field development plan concepts. 
+(5) Reduced assumptions for operational expenses as we continued to improve our field practices during the integration of the properties acquired from Carrizo. 
+• Sales of reserves in place. The 6.2 MMBoe of sales of reserves in place were primarily associated with the ORRI Transaction. See “Note 4 - Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for further discussion. 
+• Converted to proved developed. During 2020, we converted 41.4 MMBoe of PUDs that were booked as PUDs as of December 31, 2019 to proved developed at a cost of $224.4 million, or $5.42 per Boe. During 2020, our PUD conversion was below 20% primarily as a result of the significant decrease in operational capital expenditures, which included the temporary cessation of all drilling and completion activities for most of the second and third quarters of 2020, due to declines in crude oil prices in 2020 and ongoing uncertainty regarding the oil supply-demand macro-economic environment. We currently estimate that we will convert between 40% and 45% of our PUDs as of December 31, 2020 in 2021 and 2022. 
+During 2020, we also incurred $76.4 million on PUDs that were drilled but uncompleted as of December 31, 2020. As of December 31, 2020, we had 25.3 MMBoe of PUDs associated with drilled but uncompleted wells. All of the reserves associated with drilled but uncompleted wells are scheduled to be completed in 2021. We expect to incur approximately $126.0 million of capital expenditures to complete these wells. 
+At December 31, 2020, we did not have any reserves that have remained undeveloped for five or more years since the date of their initial booking and all PUD locations are scheduled to be developed within five years of their initial booking. 
+Qualifications of Technical Persons 
+In accordance with the Standards Pertaining to Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers, D&M prepared 100% of our estimates of proved reserves as of December 31, 2020 and 2018 and 40% of our proved reserves as of December 31, 2019. Ryder Scott prepared the estimates of proved reserves associated with the Carrizo Acquisition, which comprised approximately 60% of our proved reserves as of December 31, 2019. D&M is a respected company in the reservoir engineering field and provides petroleum property analysis for other upstream companies. The technical persons responsible for preparing the reserves estimates meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Neither D&M nor Ryder Scott owns an interest in our properties, and neither is employed on a contingent fee basis. 
+Our internal director of reserves has over 20 years of experience in the petroleum industry and extensive experience in the estimation of reserves and the review of reserve reports prepared by third party engineering firms. Compliance as it relates to reporting the Company’s reserves is the responsibility of our Chief Operating Officer, who is also our principal engineer. He has over 30 years of operations and industry experience and holds B.S. and Ph.D. degrees in Petroleum Engineering, in addition to a M.S. in Environmental and Planning Engineering, and is experienced in asset evaluation and management. 
+13 
+Internal Controls Over Reserve Estimation Process 
+The primary inputs to the reserve estimation process are comprised of technical information, financial data, production data, and ownership interest. All field and reservoir technical information is assessed for validity when the internal reserve engineer holds technical meetings with our geoscientists, operations, and land personnel to discuss field performance and to validate future development plans. The other inputs used in the reserve estimation process, including, but not limited to, future capital expenditures, commodity price differentials, production costs, and ownership percentages are subject to internal controls over financial reporting and are assessed for effectiveness annually. 
+To further enhance the control environment over the reserve estimation process, our Strategic Planning and Reserves Committee, an independent committee of the Company’s board of directors (the “Board of Directors”), assists management and the Board of Directors with its oversight of the integrity of the determination of our oil and natural gas reserves and the work of the independent third party reserve engineers. The Strategic Planning and Reserves Committee’s charter also specifies that it shall perform, in consultation with the Company’s management and senior reserves and reservoir engineering personnel, the following responsibilities: 
+• Oversee the appointment, qualification, independence, compensation and retention of the independent third party reserve engineers engaged by the Company (including resolution of material disagreements between management and the independent third party reserve engineers regarding reserve determination) for the purpose of preparing or issuing an annual reserve report. The Strategic Planning and Reserves Committee shall review any proposed changes in the appointment of the independent third party reserve engineers, determine the reasons for such proposal, and whether there have been any disputes between the independent third party reserve engineers and management. 
+• Review the Company’s significant reserves engineering principles and any material changes thereto, and any proposed changes in reserves engineering standards and principles which have, or may have, a material impact on the Company’s reserves disclosure. 
+• Review with management and the independent third party reserve engineers the proved reserves of the Company, and, if appropriate, the probable reserves, possible reserves and the total reserves of the Company, including: (i) reviewing significant changes from prior period reports; (ii) reviewing key assumptions used or relied upon by the independent third party reserve engineers; (iii) evaluating the quality of the reserve estimates prepared by the independent third party reserve engineers and the Company relative to the Company’s peers in the industry; and (iv) reviewing any material reserves adjustments and significant differences between the Company’s and independent third party reserve engineers’ estimates. 
+• If the Strategic Planning and Reserves Committee deems it necessary, it shall meet in executive session with the independent third party reserve engineers to discuss the oil and gas reserve determination process and related public disclosures, and any other matters of concern in respect of the evaluation of the reserves. 
+During our last fiscal year, we filed no reports with other federal agencies which contain an estimate of proved reserves. 
+See “Item 8. Financial Statements and Supplementary Data - Supplemental Information on Oil and Natural Gas Operations” for additional information regarding our estimated proved reserves and the present value of estimated future net revenues from these proved reserves. 
+Capital Budget 
+Our Board approved an operational capital budget for expenditures of up to $430.0 million (the “2021 Capital Budget”), with approximately 80% directed towards drilling, completion, and equipment expenditures. Our scaled development plan for 2021 will continue to employ our life of field development philosophy and benefit from our balanced capital deployment strategy. The 2021 Capital Budget leverages the structural savings and operational efficiencies achieved during 2020 from shared best practices following the integration of Callon and Carrizo. Approximately 70% of the 2021 Capital Budget is allocated towards development in the Permian with the remaining 30% towards development in the Eagle Ford. As part of our 2021 operated horizontal drilling program, we expect to drill approximately 55 to 65 gross operated wells and complete approximately 90 to 100 gross operated wells. 
+Our revenues, earnings, and liquidity are substantially dependent on the prices we receive for, and our ability to develop, our reserves of oil and natural gas. We believe that we are positioned to execute on our strategy even during downturns in the industry due to our resource base, low cost structure, risk management, and disciplined investment of capital. We monitor current and expected market conditions, including the commodity price environment, and our liquidity needs and may adjust our capital investment plan accordingly. 
+14 
+Drilling Activity 
+The following table sets forth our operated and non-operated drilling activity for the years ended December 31, 2020, 2019, and 2018. In the table, “gross” refers to the total wells in which we have a working interest and “net” refers to gross wells multiplied by our working interest therein. As defined by the SEC, the number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. For definitions of exploratory wells, extension wells, development wells, productive wells, and non-productive wells, see “—Glossary of Certain Terms”. 
+Years Ended December 31, 
+2020 
+2019 (1) 
+2018 
+Gross Net Gross Net Gross Net 
+Exploratory Wells - Productive (2) 
+22 16.0 56 36.7 55 44.7 
+Exploratory Wells - Non-productive — — — — — — 
+Development Wells - Productive 73 66.0 15 11.6 15 12.8 
+Development Wells - Non-productive — — — — — — 
+(1) Includes activity on properties acquired in the Carrizo Acquisition subsequent to the December 20, 2019 closing date. 
+(2) These wells are extension wells. While these wells were drilled on undeveloped acreage targeting formations which in prior periods were not recognized as proved undeveloped due to inadequate evidence using reliable technology to provide reasonably certain results with consistency and repeatability, there were no new field or new reservoir discoveries pursuant to the definition of an exploratory well. 
+Productive Wells 
+The following table sets forth the number of productive crude oil and natural gas wells in which we owned an interest as of December 31, 2020. 
+Crude Oil Natural Gas Total 
+Gross Net Gross Net Gross Net 
+Permian - Operated 763 665.5 116 101.2 879 766.7 
+Permian - Non-operated (1) 
+5 0.9 15 0.7 20 1.6 
+Total Permian 768 666.4 131 101.9 899 768.3 
+Eagle Ford - Operated 647 579.8 3 2.5 650 582.3 
+Eagle Ford - Non-operated (1) 
+13 0.8 — — 13 0.8 
+Total Eagle Ford 660 580.6 3 2.5 663 583.1 
+Total 1,428 1,247.0 134 104.4 1,562 1,351.4 
+(1) On November 2, 2020, we sold substantially all of our non-operated assets for net proceeds of $29.6 million, subject to post-closing adjustments. 
+15 
+Production Volumes, Average Sales Prices and Operating Costs 
+The following tables set forth certain information regarding the production volumes and average sales prices received for, and average production costs associated with, our sales of oil and natural gas for the periods indicated. 
+Years Ended December 31, 
+2020 
+2019 (1) 
+2018 
+Total production (2) 
+Oil (MBbls) 
+Permian 14,113 11,365 9,443 
+Eagle Ford 9,430 300 — 
+Total oil (MBbls) 23,543 11,665 9,443 
+Natural gas (MMcf) 
+Permian 32,087 19,484 15,477 
+Eagle Ford 8,714 234 — 
+Total natural gas (MMcf) 40,801 19,718 15,447 
+NGLs (MBbls) 
+Permian 5,390 93 — 
+Eagle Ford 1,460 42 — 
+Total NGLs (MBbls) 6,850 135 — 
+Total production (MBoe) 
+Permian 24,851 14,705 12,018 
+Eagle Ford 12,342 381 — 
+Total barrels of oil equivalent (MBoe) 37,193 15,086 12,018 
+Daily production volumes by product (2) 
+Oil (Bbls/d) 
+Permian 38,560 31,136 25,871 
+Eagle Ford 25,765 821 — 
+Total oil (Bbls/d) 64,325 31,957 25,871 
+Natural gas (Mcf/d) 
+Permian 87,669 53,381 42,321 
+Eagle Ford 23,809 640 — 
+Total natural gas (Mcf/d) 111,478 54,021 42,321 
+NGLs (Bbls/d) 
+Permian 14,727 254 — 
+Eagle Ford 3,989 116 — 
+Total NGLs (Bbls/d) 18,716 370 — 
+Total production (Boe/d) 
+Permian 67,899 40,287 32,926 
+Eagle Ford 33,721 1,044 — 
+Total barrels of oil equivalent (Boe/d) 101,620 41,331 32,926 
+16 
+Years Ended December 31, 
+2020 
+2019 (1) 
+2018 
+Revenues (in thousands) (2) 
+Oil 
+Permian $525,412 $615,235 $530,898 
+Eagle Ford 325,255 17,872 — 
+Total oil 850,667 633,107 530,898 
+Natural gas 
+Permian 33,815 35,818 56,726 
+Eagle Ford 18,051 572 — 
+Total natural gas 51,866 36,390 56,726 
+NGLs 
+Permian 64,201 1,542 — 
+Eagle Ford 17,094 533 — 
+Total NGLs 81,295 2,075 — 
+Total revenues 
+Permian 623,428 652,595 587,624 
+Eagle Ford 360,400 18,977 — 
+Total revenues $983,828 $671,572 $587,624 
+Operating costs (in thousands) 
+Lease operating expense 
+Permian $117,017 $88,636 $69,180 
+Eagle Ford 77,084 3,191 — 
+Total lease operating expense 194,101 91,827 69,180 
+Production and ad valorem taxes 
+Permian 39,584 41,777 35,755 
+Eagle Ford 23,054 874 — 
+Total production and ad valorem taxes 62,638 42,651 35,755 
+Gathering, transportation and processing 
+Permian 56,856 — — 
+Eagle Ford 20,453 — — 
+Total gathering, transportation and processing 77,309 — — 
+Total operating costs 
+Permian 213,457 130,413 104,935 
+Eagle Ford 120,591 4,065 — 
+Total operating costs $334,048 $134,478 $104,935 
+17 
+Years Ended December 31, 
+2020 
+2019 (1) 
+2018 
+Average realized sales price (2) (excluding impact of settled derivatives) 
+Oil (per Bbl) 
+Permian $37.23 $54.13 $56.22 
+Eagle Ford 34.49 59.57 — 
+Total oil (per Bbl) 36.13 54.27 56.22 
+Natural gas (per Mcf) 
+Permian 1.05 1.84 3.67 
+Eagle Ford 2.07 2.44 — 
+Total natural gas (per Mcf) 1.27 1.85 3.67 
+NGL (per Bbl) 
+Permian 11.91 16.58 — 
+Eagle Ford 11.71 12.69 — 
+Total NGL (per Bbl) 11.87 15.37 — 
+Total average realized sales price (per Boe) 
+Permian 25.09 44.38 48.90 
+Eagle Ford 29.20 49.81 — 
+Total average realized sales price (per Boe) $26.45 $44.52 $48.90 
+Average realized sales price (2) (including impact of settled derivatives) 
+Oil (per Bbl) $40.19 $53.31 $53.31 
+Natural gas (per Mcf) 1.28 2.22 3.69 
+NGL (per Bbl) 11.87 15.37 — 
+Total average realized sales price (per Boe) $29.03 $44.27 $46.63 
+Operating costs per Boe 
+Lease operating expense 
+Permian $4.71 $6.03 $5.76 
+Eagle Ford 6.25 8.38 — 
+Total lease operating expense 5.22 6.09 5.76 
+Production and ad valorem taxes 
+Permian 1.59 2.84 2.98 
+Eagle Ford 1.87 2.29 — 
+Total production and ad valorem taxes 1.68 2.83 2.98 
+Gathering, transportation and processing 
+Permian 2.29 — — 
+Eagle Ford 1.66 — — 
+Total gathering, transportation and processing 2.08 — — 
+Total operating costs 
+Permian 8.59 8.87 8.74 
+Eagle Ford 9.77 10.67 — 
+Total operating costs (per Boe) $8.98 $8.92 $8.74 
+(1) Includes activity on properties acquired in the Carrizo Acquisition subsequent to the December 20, 2019 closing date. 
+(2) Effective January 1, 2020, certain of our natural gas processing agreements were modified to allow us to take title to NGLs resulting from the processing of our natural gas. As a result, sales volumes, prices, and revenues for NGLs and natural gas are presented separately for periods subsequent to January 1, 2020. For periods prior to January 1, 2020, except for sales volumes, prices, and revenues specifically associated with Carrizo, we presented our sales volumes, prices, and revenues for NGLs with natural gas. 
+18 
+Major Customers 
+Our production is sold generally on month-to-month contracts at prevailing market prices. The following table presents customers that represented 10% or more of our total revenues for at least one of the periods presented: 
+Years Ended December 31, 
+2020 2019 2018 
+Shell Trading Company 31% 10% * 
+Valero Energy 23% * * 
+Rio Energy International, Inc. * 26% 28% 
+Enterprise Crude Oil, LLC * 19% 14% 
+Plains Marketing, L.P. * 15% 21% 
+* - Less than 10% for the respective years. 
+Because alternative purchasers of oil and natural gas are readily available, we believe that the loss of any of these purchasers would not result in a material adverse effect on our ability to sell future oil and natural gas production. In order to mitigate potential exposure to credit risk, we may require from time to time for our customers to provide financial security. 
+Leasehold Acreage 
+The following table shows our approximate developed and undeveloped leasehold acreage as of December 31, 2020. Developed acreage refers to acreage on which wells have been completed to a point that would permit production of oil and gas in commercial quantities. Undeveloped acreage refers to acreage on which wells have not been drilled or completed to a point that would permit production of oil and gas in commercial quantities whether or not the acreage contains proved reserves. 
+Developed Acreage Undeveloped Acreage Total Acreage Net Undeveloped Acreage Expiring 
+Gross Net Gross Net Gross Net 2021 2022 2023 
+Permian (1) 
+121,099 100,645 9,250 5,726 130,349 106,371 1,839 1,510 83 
+Eagle Ford (2) 
+77,830 65,311 12,249 8,372 90,079 73,683 47 300 8 
+Other (3) 
+2,080 122 75,993 57,070 78,073 57,192 1,234 48,504 6,393 
+Total 201,009 166,078 97,492 71,168 298,501 237,246 3,120 50,314 6,484 
+(1) Based on our current plans, approximately 56%, 2% and 24% of the acreage expiring in 2021, 2022 and 2023, respectively, will be developed prior to expiration or extended by lease extension payments. 
+(2) Based on our current plans, approximately 100% of the acreage expiring in 2021, 2022 and 2023 will be developed prior to expiration or extended by lease extension payments. 
+(3) Consists of non-core acreage principally located in Texas. We have no current development plans and no proved undeveloped reserves associated with this acreage as of December 31, 2020. 
+Our lease agreements generally terminate if producing wells have not been drilled on the acreage within their primary term or an extension thereof (a period that is generally from three to five years depending on the area). The percentage of net undeveloped acreage expiring in 2021, 2022 and 2023 assumes that no producing wells have been drilled on acreage within their primary term or have been extended. We manage our lease expirations to ensure that we do not experience unintended material loss of acreage or depths. Our leasehold management efforts include scheduling drilling in order to hold leases by production or timely exercising our contractual rights to extend the terms of leases by continuous operations or the payment of lease extension payments and delay rentals. We may choose to allow some leases to expire that are no longer part of our development plans. 
+The proved undeveloped reserves associated with acreage expiring over the next three years are not material to the Company. 
+Human Capital 
+Callon employs a talented workforce that is integral to our success, and we are committed to the safety, health, and development of each team member. The Callon culture is defined by our values of responsibility, integrity, drive, respect and excellence. These core values are a reflection of our ideals as individuals and direct our actions as a company. 
+Callon’s key human capital management objectives are to attract, retain and develop talent to deliver on our strategy. Due to the technical nature of our business, our success depends on a highly skilled workforce in multiple disciplines including engineering, geology, operations, land, information technology and various other corporate functions. To support the attraction and retention of top talent, our human resources programs are designed to keep our employees safe and healthy, engage employees with an inclusive workplace, reward and support employees through competitive pay and benefit programs, and develop talent to prepare them for 
+19 
+critical roles and leadership positions. During 2020, our human capital priorities were focused on the post-merger integration of the Callon and Carrizo workforces and the health and safety of our employees as we adapted to the challenges of COVID-19. 
+As of December 31, 2020, Callon had 303 permanent, full-time employees. None of our employees are currently represented by a union, and we believe that we have good relations with our employees. 
+We focus on the following in supporting our human capital: 
+• Inclusion and Diversity - We believe that diversity of backgrounds and perspectives contributes to an innovative workforce and an enriching environment for our employees. Callon is firmly committed to fostering an inclusive, respectful environment and providing equal opportunity to all qualified persons in our hiring, development, and compensation practices. As of December 31, 2020, approximately 36% of our permanent, full-time employees represented minorities and 18% were female. 
+• Health and Safety - Protecting our employees, contractors and communities is a core value at Callon and our top priority. Our Operations Management System (“OMS”) establishes clear expectations for operating safely and responsibly throughout the lifecycle of our business. We identify and mitigate safety risks and integrate a culture of safety by operating according to OMS standards, processes, and procedures. Additionally, we share our Safety and Environmental Policy with all employees and contractors which includes each individual’s authorization and responsibility to stop work on any activity without the threat or fear of job reprisal. To reinforce accountability for safety results, our Board of Directors included safety performance as a factor in our 2020 annual bonus program. Importantly, during the COVID-19 pandemic, our continuing focus on health and safety enabled us to preserve business continuity without sacrificing our commitment to keeping our employees and their families safe. 
+• Employee Compensation, Benefits and Wellness - Our compensation and benefits programs provide a package designed to attract, retain and motivate employees. In addition to competitive base salaries, we provide a variety of short-term and long-term incentive compensation programs to reward performance relative to key financial and ESG metrics. Callon invests in the health and well-being of our employees and their families by paying 100% of the premiums for our health care plan, which includes telemedicine and an Employee Assistance Program. We also offer comprehensive benefit options including retirement savings plans, life and disability insurance, health savings accounts, flexible spending accounts, and a charitable matching program. 
+• Employee Development - We believe that a key element in our future success, as well as the retention of our employees, is our investment in the development of our team members. Callon fosters an entrepreneurial workplace where employees can expand their skill sets and experience by direct engagement and collaboration with leaders at all levels. Additionally, we offer in-house training programs across our workforce and also invest in our emerging leaders by sponsoring them for prominent leadership development programs. Our development programs also focus on goal setting and feedback to support all of our employees in reaching their personal goals. 
+For additional information, please see our Sustainability Report published on our company website (www.callon.com). Information contained in our Sustainability Report is not incorporated by reference into, and does not constitute a part of, this 2020 Annual Report on Form 10-K. 
+Other 
+Industry Segment and Geographic Information 
+For segment reporting purposes, the Company considers all of the current development and operating areas to be one reportable segment: the development and production of oil and natural gas. All of the Company’s assets are located within the United States and all operations are located within Texas. All of the production revenues generated from operations are contracted and sold to customers located in the United States. 
+Title to Properties 
+The Company believes that the title to its oil and natural gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of such properties. Nevertheless, we can be involved in title disputes from time to time which may result in litigation. The Company’s properties are potentially subject to one or more of the following: 
+• royalties and other burdens and obligations, express or implied, under oil and natural gas leases; 
+• overriding royalties and other burdens created by us or our predecessors in title; 
+• a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements; farm-out agreements, production sales contracts and other agreements that may affect the properties or their titles; 
+• back-ins and reversionary interests existing under various agreements and as a result of unleased minerals or non-participating owners; 
+20 
+• liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual liens under operating agreements; 
+• pooling, unitization and communitization agreements, declarations and orders, production allocation agreements; and 
+• easements, restrictions, rights-of-way and other matters that commonly affect property. 
+To the extent that such burdens and obligations affect the Company’s rights to production revenues, these characteristics have been taken into account in calculating Callon’s net revenue interests and in estimating the size and value of its estimated proved reserves. The Company believes that the burdens and obligations affecting our properties are typical within the industry for properties of the kind owned by Callon. 
+Seasonality of Business 
+Weather conditions and seasonality affect the demand for and prices of, oil and natural gas. Due to these fluctuations, results of operations for quarterly interim periods may not be indicative of the results realized on an annual basis. 
+Competition 
+The Company operates in the oil and natural gas industry, which is highly competitive. The Company’s business experiences strong competition from a number of parties that may range from small independent producers to major integrated companies. Competition affects the Company’s ability to acquire additional properties and resources necessary to develop assets. In higher commodity pricing environments, competition also exists in the form of contracting for drilling, pumping, and workover equipment, and securing skilled personnel to both develop and operate existing assets. Many of the competitors mentioned above may be able to pay for more sought-after properties or access equipment, infrastructure, or personnel. The industry also experiences, from time to time, shortages in resources such as the availability of drilling and workover rigs, other equipment, pipes and materials, infrastructures, and skilled personnel, all of which can delay development, exploration, and workover activities as well as result in significant cost increases. 
+Insurance 
+In accordance with industry practice, the Company maintains insurance against some, but not all, of the operating risks to which its business is exposed. While not all inclusive, the Company’s insurance policies generally protect against bodily injury and property damage, pollution and other environmental damages, employee benefits, employee injury and control of well insurance for its exploration and production operations. 
+The Company enters into master service agreements with its third-party contractors, including hydraulic fracturing contractors, in which they agree to indemnify the Company for injuries and deaths of the service provider’s employees, as well as contractors and subcontractors hired by the service provider. Similarly, the Company generally agrees to indemnify each third-party contractor against claims made by employees of the Company and the Company’s other contractors. Additionally, each party generally is responsible for damage to its own property. The Company re-evaluates the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and natural gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. While based on the Company’s risk analysis we believe that we are properly insured, no assurance can be given that the Company will be able to maintain insurance in the future at rates that it considers reasonable. In such circumstances, the Company may elect to self-insure or maintain only catastrophic coverage for certain risks in the future. 
+Corporate Offices 
+The Company’s headquarters are located in Houston, Texas, in a building with office space leased by the Company. We own office buildings in Dilley and Pecos, Texas and lease and own offices in the Midland, Texas area. Because alternative locations to our leased spaces are readily available, the replacement of any of our leased offices would not result in material expenditures . 
+Regulations 
+General. Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. Legislation and regulation affecting the entire oil and natural gas industry is continuously being reviewed for potential revision. Some of these requirements carry substantial penalties for failure to comply. 
+Exploration and Production . Our operations are subject to federal, state and local regulations that include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds and letters of credit) covering drilling and well operations. Other activities subject to regulation are: 
+• the location and spacing of wells; 
+• the method of drilling and completing and operating wells; 
+• the rate and method of production; 
+• the surface use and restoration of properties upon which wells are drilled and other exploration activities; 
+• notice to surface owners and other third parties; 
+21 
+• the venting or flaring of natural gas; 
+• the plugging and abandoning of wells; 
+• the discharge of contaminants into water and the emission of contaminants into air; 
+• the disposal of fluids used or other wastes obtained in connection with operations; 
+• the marketing, transportation and reporting of production; and 
+• the valuation and payment of royalties. 
+Our sales of oil and natural gas are affected by the availability, terms and cost of pipeline transportation. The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation. If these regulations change, we could face higher transmission costs for our production and, possibly, reduced access to transmission capacity. To the extent it may be necessary for new interstate natural gas pipelines to be built, there may be a more stringent regulatory approach at the Federal Energy Regulatory Commission (“FERC”), which could impact our ability to obtain new interstate pipeline transportation capacity. 
+Various proposals and proceedings that might affect the petroleum industry are pending before Congress, federal administrative agencies such as FERC, various state and administrative agencies and legislatures, and the courts. Historically, the industry has been heavily regulated and we can offer you no assurance that the less stringent regulatory approach recently pursued by the FERC and state administrative agencies and Congress will continue nor can we predict what effect such proposals or proceedings may have on our operations. 
+We do not currently anticipate that compliance with existing laws and regulations governing exploration and production will have a significantly adverse effect upon our capital expenditures, earnings or competitive position. 
+Environmental Matters and Regulation. Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the U.S. Environmental Protection Agency (the “EPA”), issue regulations which often require difficult and costly compliance measures. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relating to our owned or operated facilities. Violations of environmental laws could result in administrative, civil or criminal fines and injunctive relief. The strict and joint and several liability nature of certain such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons, air emissions or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. In recent years, the oil and natural gas exploration and production industry has been the subject of increasing scrutiny and regulation by environmental authorities. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. Although such laws and regulations can increase the cost of planning, designing, installing and operating our facilities, it is anticipated that, absent the occurrence of an extraordinary event, compliance with them will not have a material effect upon our operations, capital expenditures, earnings or competitive position in the marketplace. 
+Waste Handling. The Resource Conservation and Recovery Act (“RCRA”), as amended, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of oil and natural gas are exempt from regulation as hazardous wastes under RCRA and its state analogs, it is possible that some wastes we generate presently or in the future may be subject to regulation under RCRA and state analogs. Additionally, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Additionally, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, the EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA was required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations was not necessary. On April 23, 2019, the EPA determined that a revision of the regulations was not necessary. If the EPA proposes a 
+22 
+rulemaking for revised oil and gas waste regulations in the future, any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. 
+Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of wastes associated with oil and natural gas exploration and production could increase our costs to manage and dispose of such wastes. 
+Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), imposes joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes. 
+Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we have generated and will generate wastes that may fall within CERCLA’s definition of hazardous substance and may have disposed of these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum. We may also be the owner or operator of sites on which hazardous substances have been released. To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under CERCLA; we also do not know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties. In the event contamination is discovered at a site on which we are or have been an owner or operator or to which we sent hazardous substances, we could be liable for the costs of investigation and remediation and natural resources damages. 
+We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating, waste disposal, and water disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including offsite locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination or groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination. 
+Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, the Safe Drinking Water Act, the Oil Pollution Act (“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States (a term broadly defined to include, among other things, certain wetlands), as well as state waters for analogous state programs. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or applicable state analog. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit from the U.S. Army Corps of Engineers. The EPA issued a final rule on the federal jurisdictional reach over waters of the United States in 2015, which was repealed by the EPA on October 22, 2019. On January 23, 2020, the EPA and the U.S. Army Corps of Engineers issued the Navigable Waters Protection Rule re-defining the term “waters of the United States” as applied under the Clean Water Act and narrowing the scope of waters subject to federal regulation. The rule is the subject of various legal challenges, and a federal district court in Colorado stayed implementation of the rule. The stay is limited to application of the rule in Colorado; the rule has taken effect in all other states. At President Biden’s direction, the EPA and the U.S. Army Corps of Engineers requested the litigation be stayed while the agencies review the rule. The ongoing litigation creates uncertainty regarding federal jurisdiction over waters of the United States. 
+The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. 
+23 
+The Oil Pollution Act is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters. 
+Noncompliance with the Clean Water Act or the OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws. 
+Air Emissions. The federal Clean Air Act, as amended, and comparable state and local laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and modified and existing facilities may be required to obtain additional permits. As a result, we may need to incur capital costs in order to remain in compliance. Obtaining or renewing permits also has the potential to delay the development of oil and natural gas projects. Federal and state regulatory agencies can impose administrative, civil and criminal penalties and seek injunctive relief for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. 
+On June 3, 2016, the EPA expanded its regulatory coverage in the oil and natural gas industry with additional regulated equipment categories, and the addition of new rules limiting methane emissions from new or modified sites and equipment. Although the EPA attempted to suspend enforcement of the methane rule, this action was ruled improper by the U.S. Court of Appeals for the D.C. Circuit on July 2, 2017. Subsequently, in September 2020, the EPA finalized the Reconsideration Rule that substantially changed the obligations associated with methane emissions, limiting obligations for the oil and natural gas industry. On January 20, 2021, President Biden issued an Executive Order directing the EPA to rescind the Reconsideration Rule by September 2021. Separately, in September 2020, the EPA finalized amendments known as the Review Rule that would rescind requirements related to the regulation of methane emissions from the oil and natural gas industry. Both rules are subject to ongoing litigation, and therefore, future obligations continue to remain uncertain under the Clean Air Act. 
+Climate Change. Numerous reports from scientific and governmental bodies such as the United Nations Intergovernmental Panel on Climate Change have expressed heightened concerns about the impacts of human activity, especially fossil fuel combustion, on the global climate. In turn, governments and civil society are increasingly focused on limiting the emissions of GHGs, including emissions of carbon dioxide from the use of oil and natural gas. 
+In December 2015, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change resulted in 195 countries, including the United States, coming together to develop the so-called “Paris Agreement,” which calls for the parties to undertake “ambitious efforts” to limit the average global temperature. The Agreement went into effect on November 4, 2016, and establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. The United States formally announced its intent to withdraw from the Paris Agreement on November 4, 2019, which withdrawal was effective on November 4, 2020. On January 20, 2021, President Biden issued written notification to the United Nations of the United States’ intention to rejoin the Paris Agreement, which became effective on February 19, 2021. In addition, certain U.S. city and state governments announced their intention to continue to satisfy their proportionate obligations under the Paris Agreement. In addition, legislation has from time to time been introduced in Congress that would establish measures restricting GHG emissions in the United States, and a number of states have begun taking actions to control and/or reduce emissions of GHGs. 
+Any legislation or regulatory programs at the federal, state, or city levels designed to reduce GHG emissions could increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Moreover, incentives to conserve energy or use alternative energy sources, such as policies designed to increase utilization of zero-emissions or electric vehicles, as a means of addressing climate change could reduce demand for the oil and natural gas we produce. 
+In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions. Although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. 
+The EPA has established GHG reporting requirements for certain sources in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissions. Although these requirements do not limit the amount of GHGs that can be emitted, they do require us to incur costs to monitor, keep records of, and report GHG emissions associated with our operations. 
+Parties concerned about the potential effects of climate change have also directed their attention at sources of financing for energy companies, which has resulted in certain financial institutions, funds and other capital providers restricting or eliminating their 
+24 
+investment in oil and natural gas activities. In addition, some parties have initiated public nuisance claims under federal or state common law against certain companies involved in the production of oil and natural gas. Although our business is not a party to any such litigation, we could be named in actions making similar allegations, which could lead to costs and materially impact our financial condition in an adverse way. 
+Finally, most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce significant physical effects, such as increased frequency and severity of droughts, storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced or cause us to incur significant costs in preparing for or responding to the effects of climatic events themselves. Potential adverse effects could include disruption of our production activities, including, for example, damages to our facilities from winds or floods or increases in our costs of operation or reductions in the efficiency of our operations, as well as potentially increased costs for insurance coverages in the aftermath of such effects. 
+Regulation of Hydraulic Fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act (“SDWA”) regulates the underground injection of substances through the Underground Injection Control (“UIC”) program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions and not at the federal level, as the SDWA expressly excludes regulation of these fracturing activities (except where diesel is a component of the fracturing fluid, as further discussed below). Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing has been proposed in past legislative sessions but has not passed. 
+The EPA, however, issued guidance on permitting hydraulic fracturing that uses fluids containing diesel fuel under the UIC program, specifically as “Class II” UIC wells. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. This report could result in additional regulatory scrutiny that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and business. Further, on June 28, 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants, and after a legal challenge by environmental groups, in July 2019, the EPA declined to revise the rules. 
+On June 3, 2016, the EPA adopted regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package included New Source Performance Standards (“NSPS”) for hydraulically fractured natural gas and oil wells to address emissions of sulfur dioxide, volatile organic compounds (“VOCs”) and methane, with a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule sought to achieve a 95% reduction in VOCs and methane emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured gas and newly constructed or refractured oil wells. 
+Several states, including Texas, and some municipalities, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, Texas law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) for disclosure on a website and also file the list of chemicals with the Texas Railroad Commission (the “RRC”) with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the RRC. 
+Additionally, some states, localities and local regulatory districts have adopted or have considered adopting regulations to limit, and in some cases impose a moratorium on, hydraulic fracturing or other restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; or restrictions on access to, and usage of, water. Further, there has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the U.S. implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations of harm. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and 
+25 
+abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of potential federal or state legislation governing hydraulic fracturing. In light of concerns about seismic activity being triggered by the injection of produced waters into underground wells, certain regulators are also considering additional requirements related to seismic safety for hydraulic fracturing activities. A 2015 U.S. Geological Survey report identified eight states with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. Any regulation that restricts our ability to dispose of produced waters or increases the cost of doing business could cause curtailed or decreased demand for our services and have a material adverse effect on our business. 
+Surface Damage Statutes (“SDAs”) . In addition, a number of states and some tribal nations have enacted SDAs. These laws are designed to compensate for damage caused by oil and gas development operations. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain binding requirements for payments by the operator to surface owners/users in connection with exploration and operating activities in addition to bonding requirements to compensate for damages to the surface as a result of such activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs. 
+National Environmental Policy Act . Oil and natural gas exploration and production activities requiring federal permits may be subject to the National Environmental Policy Act (“NEPA”), which requires federal agencies to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will evaluate the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a detailed Environmental Impact Statement that must be made available for public review and comment. Recent litigation by environmental non-governmental organizations has alleged that the Environmental Assessments for certain oil and natural gas projects violated NEPA by failing to account for climate change and the greenhouse gas emissions impacts of such projects. On July 16, 2020, the Council on Environmental Quality revised NEPA’s implementing regulations in an effort designed to streamline project approvals. Among other revisions, the rules redefines environmental “effects” or “impacts” as the effects “that are reasonably foreseeable and have a reasonably close causal relationship to the proposed action or alternatives.” The rule also eliminated the current “direct,” “indirect,” or “cumulative” categories of effects. The new regulations are subject to ongoing litigation in several federal district courts and future implementation of the regulations is unclear. To the extent that our current exploration and production activities, as well as proposed exploration and development plans, require federal permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects. 
+Endangered Species Act and Migratory Bird Treaty Act. The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ or its habitat. The U.S. Fish and Wildlife Service (the “FWS”) must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. In August 2019, the FWS and National Marine Fisheries Service issued three rules amending implementation of the ESA regulations revising, among other things, the process for listing species and designating critical habitat. A coalition of states and environmental groups have challenged the three rules and the litigation remains pending. In addition, on December 18, 2020, the FWS amended its regulations governing critical habitat designations. We anticipate the rule will be subject to litigation. A final rule amending how critical habitat and suitable habitat areas are designated under the ESA was finalized by the U.S. Fish and Wildlife Service in 2016. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”), which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit. This prohibition covers most bird species in the U.S. On January 7, 2021, the Department of the Interior finalized a rule limiting application of the MBTA, however, the Department of the Interior under President Biden delayed the effective date of the rule and opened a public comment period for further review. Future implementation of the rules implementing the Endangered Species Act and the MBTA are uncertain. If the Company was to have a portion of its leases designated as critical or suitable habitat or a protected species were located on a lease, it may adversely impact the value of the affected leases. 
+Other Regulation of the Oil and Natural Gas Industry. The oil and natural gas industry is extensively regulated by numerous federal, state and local agencies and authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other similar companies in the industry with similar types, quantities and locations of production. 
+The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas is subject to federal regulation by FERC which regulates the terms, conditions and rates for interstate transportation and 
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+storage service and various other matters. State regulations govern the rates, terms, and conditions of service associated with access to intrastate oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transportation in some circumstances may also affect the intrastate transportation of oil and natural gas. 
+Although oil and natural gas sales prices are currently unregulated, the federal government historically has been active in the area of oil and natural gas sales regulation. We cannot predict whether new legislation to regulate oil and natural gas sales might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of natural gas, condensate, oil and natural gas liquids are not currently regulated and are made at market prices. 
+Exports of U.S. Oil Production and Natural Gas Production . In December 2015, the federal government ended its decades-old prohibition of exports of oil produced in the lower 48 states of the U.S. As a result, exports of U.S. oil have increased significantly, reinforcing the general perception in the industry that the end of the U.S. export ban was positive for producers of U.S. oil. In addition, the U.S. Department of Energy authorizes exports of natural gas, including exports of natural gas by pipelines connecting U.S. natural gas production to pipelines in Mexico, and the export of liquefied natural gas (“LNG”) through LNG export facilities, the construction and operation of which are regulated by FERC. Since 2016, natural gas produced in the lower 48 states of the U.S. has been exported as LNG from export facilities in the U.S. Gulf Coast region. LNG export capacity has steadily increased in recent years, and is expected to continue increasing due to numerous export facilities that are currently being developed. The industry generally believes that this sustained growth in exports will be a positive development for producers of U.S. natural gas. 
+Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following: 
+• the location of wells; 
+• the method of drilling and casing wells; 
+• the timing of construction or drilling activities, including seasonal wildlife closures; 
+• the rates of production or “allowables”; 
+• the surface use and restoration of properties upon which wells are drilled; 
+• the plugging and abandoning of wells; and 
+• notice to, and consultation with, surface owners and other third parties. 
+State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas without a permit and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affecting the economics of production from these wells or to limit the number of locations we can drill. 
+Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Some state agencies and municipalities require bonds or other financial assurances to support those obligations. 
+Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production and have it transported. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”). Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for “first sales,” which include all of our sales of our own production. 
+Under the Energy Policy Act of 2005 (“EPAct”) Congress amended the NGA and NGPA to give FERC substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess civil penalties up to $1.0 million per day for each violation. This maximum penalty authority has been and will continue to be adjusted periodically to account for inflation. EPAct also amended the NGA to authorize FERC to “facilitate transparency in markets for the sale or transportation of physical natural gas in interstate commerce,” pursuant to which authorization FERC now requires natural gas wholesale market participants, including a number of entities that may not otherwise be subject to FERC’s traditional NGA jurisdiction, to report information annually to FERC concerning their natural gas sales and purchases. FERC requires any wholesale 
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+market participant that sells 2.2 million MMBtus or more annually in “reportable” natural gas sales to provide a report, known as FERC Form 552, to FERC. Reportable natural gas sales include sales of natural gas that utilize a daily or monthly gas price index, contribute to index price formation, or could contribute to index price formation, such as fixed price transactions for next-day or next-month delivery. 
+FERC also regulates interstate natural gas transportation rates, terms and conditions of service, and the terms under which we as a shipper may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and for the release of our excess, if any, natural gas pipeline capacity. In 1985, FERC began promulgating a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate natural gas pipeline companies are required to provide non-unduly discriminatory transportation services to all shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases, sales, and transportation that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated. With the new administration, we are expecting a reversal of the less stringent regulatory approach pursued by FERC and Congress during the Trump administration. Additionally, we cannot determine what effect, if any, future regulatory changes might have on our natural gas related activities. 
+Under FERC’s current regulatory regime, interstate transportation services must be provided on an open-access, non-unduly discriminatory basis at cost-based rates or negotiated rates, both of which are subject to FERC approval. FERC also allows jurisdictional gas pipeline companies to charge market-based rates if the transportation market at issue is sufficiently competitive. The FERC-regulated tariffs, under which interstate pipelines provide such open-access transportation service, contain strict limits on the means by which a shipper releases its pipeline capacity to another potential shipper, which provisions include compliance with FERC’s “shipper-must-have-title” rule. Violations by a shipper (i.e., a pipeline customer) of FERC’s capacity release rules, including the shipper-must-have-title rule could subject a shipper to substantial penalties from FERC. 
+With respect to its regulation of natural gas pipelines under the NGA, FERC has not generally required the applicant for construction of a new interstate natural gas pipeline to provide information concerning the GHG emissions resulting from the activities of the proposed pipeline’s customers. In August 2017, the U.S. Circuit Court of Appeals for the DC Circuit issued a decision remanding a natural gas pipeline certificate application to FERC, and required FERC to revise its environmental impact statement for the proposed pipeline to analyze potential GHG emission from the specific downstream power plants that the pipeline was designed to serve. To date, FERC has declined to analyze potential upstream GHG emissions that could result from the activities of natural gas producers and marketers, like the Company, to be served by proposed interstate natural gas pipeline projects. However, the scope of FERC’s obligation to analyze the environmental impacts of proposed interstate natural gas pipeline projects, including the upstream indirect impacts of related natural gas production activity, remains subject to ongoing litigation and contested administrative proceedings at FERC and in the courts. 
+Gathering service, which occurs on pipeline facilities located upstream of FERC-jurisdictional interstate transportation services, is regulated by the states onshore and in state waters. Under NGA section 1(b), gathering facilities are exempt from FERC’s jurisdiction. FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, and FERC applies this test on a case-by-case basis. Depending on changes in the function performed by particular pipeline facilities, FERC has in the past reclassified certain FERC-jurisdictional transportation facilities as non-jurisdictional gathering facilities and FERC has reclassified certain non-jurisdictional gathering facilities as FERC-jurisdictional transportation facilities. Any such changes could result in an increase to our costs of transporting gas to point-of-sale locations. 
+The pipelines used to gather and transport natural gas being produced by the Company are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In addition, PHMSA had initially considered regulations regarding, among other things, the designation of additional high consequence areas along pipelines, minimum requirements for leak detection systems, installation of emergency flow restricting devices, and revision of valve spacing requirements. In October 2019, PHMSA finalized new safety regulations for hazardous liquid pipelines, including a requirement that operators inspect affected pipelines following extreme weather events or natural disasters, that all hazardous liquid pipelines have a system for detecting leaks and that pipelines in high consequence areas be capable of accommodating in-line inspection tools within twenty years. In addition, PHMSA is in the process of finalizing a rulemaking with respect to gathering lines, but the contents and timing of any final rule for gathering lines are uncertain. In December 2020, Congress passed the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2020 (“PIPES Act of 2020”). In addition to reauthorizing PHMSA, the PIPES Act of 2020 directs the Secretary of Transportation to update or promulgate regulations addressing the safety of certain gas pipeline, gathering, distribution and LNG facilities. Until these future regulations are proposed, it is not possible to determine how they will affect our business. 
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+Oil and NGLs Sales and Transportation. Sales of oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. 
+The Company’s sales of oil and natural gas liquids are also affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by FERC under the Interstate Commerce Act (“ICA”). FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil and natural gas liquid transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors. 
+Further, interstate common carrier oil pipelines must provide service on a non-duly discriminatory basis under the ICA, which is administered by FERC. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors. 
+In addition, FERC issued a declaratory order in November 2017, involving a marketing affiliate of an oil pipeline, which held that certain arrangements between an oil pipeline and its marketing affiliate would violate the ICA’s anti-discrimination provisions. FERC held that providing transportation service to affiliates at what is essentially the variable cost of the movement, while requiring non-affiliated shippers to pay the filed tariff rate, would violate the ICA. Rehearing has been sought of this FERC order by various parties. Due to the pending rehearing of the order and its recency, the Company cannot currently determine the impact this FERC order may have on oil pipelines, their marketing affiliates, and the price of oil and other liquids transported by such pipelines. 
+Any transportation of the Company’s oil, natural gas liquids and purity components (ethane, propane, butane, iso-butane, and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts 171-180, including Emergency Orders by the FRA regulations initially established on May 8, 2015 by PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids; PHMSA regulations were subsequently amended to remove certain requirements on September 25, 2018. In July 2020, PHMSA promulgated a final rule allowing bulk transportation of LNG by rail. The rule also incorporates additional safety requirements. 
+State Regulation. Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill. 
+The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us. 
+Financial Regulations, Including Regulations Enacted Under the Dodd-Frank Act . The U.S. Commodities and Futures Exchange Commission (the “CFTC”) holds authority to monitor certain segments of the physical and futures energy commodities market including oil and natural gas. With regard to physical purchases and sales of natural gas and other energy commodities, and any related hedging activities that the Company undertakes, the Company is thus required to observe anti-market manipulation and disruptive trading practices laws and related regulations enforced by FERC and/or the CFTC. The CFTC also holds substantial enforcement authority, including the ability to assess civil penalties. 
+Congress adopted comprehensive financial reform legislation in 2010, establishing federal oversight and regulation of the over-the-counter derivative market and entities that participate in that market. The legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), required the CFTC and the U.S. Securities and Exchange Commission (“SEC”) to promulgate rules and regulations implementing the legislation, including regulations that affect derivatives contracts that the Company uses to hedge its exposure to price volatility. 
+While the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas remain pending. The Company cannot, at this time, predict the timing or contents of any final rules the CFTC may enact with regard to any applicable rulemaking 
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+proceeding. Any final rule in either proceeding could impact the Company’s ability to enter into financial derivative transactions to hedge or mitigate exposure to commodity price volatility and other commercial risks affecting our business. 
+Worker Health and Safety . We are subject to a number of federal and state laws and regulations, including OSHA, and comparable state statutes, the purpose of which are to protect the health and safety of workers. In 2016, there were substantial revisions to the regulations under OSHA that may have impact to our operations. These changes include among other items; record keeping and reporting, revised crystalline silica standard (which requires the oil and gas industry to implement engineering controls and work practices to limit exposures below the new limits by June 23, 2021), naming oil and gas as a high hazard industry and requirements for a safety and health management system. In addition, OSHA’s hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations, and that this information be provided to employees, state and local government authorities and citizens. 
+Commitments and Contingencies 
+The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment will not have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies included, and claims for damages to property, employees, other persons, and the environment resulting from the Company’s operations could have on its activities. See “Note 17 - Commitments and Contingencies” of the Notes to our Consolidated Financial Statements for additional information. 
+Available Information 
+We make available free of charge on our website (www.callon.com) our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the SEC. 
+We also make available within the “About Callon” section of our website our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and Audit, Compensation, Strategic Planning and Reserves, and Nominating, Environmental, Social and Governance Committee Charters, which have been approved by our Board of Directors. We will make timely disclosure on our website of any change to, or waiver from, the Code of Business Conduct and Ethics for our principal executive and senior financial officers. A copy of our Code of Business Conduct and Ethics is also available, free of charge by writing us at: General Counsel, Callon Petroleum Company, 2000 W. Sam Houston Parkway South, Suite 2000, Houston, TX 77042. 
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+ITEM 1A. Risk Factors 
+Risks Related to the Oil & Natural Gas Industry 
+Oil and natural gas prices are volatile, and substantial or extended declines in prices may adversely affect our results of operations and financial condition. Our success is highly dependent on prices for oil and natural gas, which have in recent years been, and we expect will continue to be, extremely volatile. During the five years ended December 31, 2020, NYMEX WTI prices ranged from a high of $77.41 per barrel on June 27, 2018 to a low of -$36.98 per barrel on April 20, 2020, and NYMEX Henry Hub prices ranged from a high of $6.24 per MMBtu on January 2, 2018 to a low of $1.33 per MMBtu on September 21, 2020. Prices were particularly volatile in 2020 as a result of multiple significant factors impacting supply and demand in the global oil and natural gas markets, including those relating to the COVID-19 global pandemic. In 2020, NYMEX WTI crude oil ranged from a high of $63.27 per barrel to a low of -$36.98 per barrel, and the Henry Hub spot market price of gas ranged from a high of $3.14 per MMBtu to a low of $1.33 per MMBtu. The prices of oil and natural gas depend on factors we cannot control, such as macro-economic conditions, levels of production, domestic and worldwide inventories, demand for oil and natural gas, the capacity of U.S. and international refiners to use U.S. supplies of oil, natural gas and NGLs, relative price and availability of alternative forms of energy, actions by non-governmental organizations, OPEC and other countries, legislative and regulatory actions, technology developments impacting energy consumption and energy supply, and weather. These factors make it extremely difficult to predict future oil, natural gas and NGLs price movements with any certainty. We make price assumptions that are used for planning purposes, and a significant portion of our cash outlays, including rent, salaries and non-cancelable capital commitments, are largely fixed in nature. Accordingly, if commodity prices are below the expectations on which these commitments were based, our financial results are likely to be adversely and disproportionately affected because these cash outlays are not variable in the short term and cannot be quickly reduced to respond to unanticipated decreases in commodity prices. 
+In general, prices of oil, natural gas, and NGLs affect the following aspects of our business: our revenues, cash flows, earnings and returns; our ability to attract capital to finance our operations and the cost of the capital; the amount we are allowed to borrow under our Credit Facility; the profit or loss we incur in exploring for and developing our reserves; and the value of our oil and natural gas properties. 
+A substantial or extended decline in commodity prices may also reduce the amount of oil and natural gas that we can produce economically and cause a significant portion of our development projects to become uneconomic. This may result in our having to make significant downward adjustments to our estimated proved reserves. A reduction in production could also result in a shortfall in expected cash flows and require us to reduce capital spending, which could negatively affect our ability to replace our production and our future rate of growth, or require us to borrow funds to cover any such shortfall, which we may be unable to obtain at such time on satisfactory terms. 
+Due to the commodity price environment, in 2020, we reduced our development plan in order to preserve capital, including the temporary cessation of all drilling and completion activities for most of the second and third quarters of 2020. A sustained period of weakness in oil, natural gas and NGLs prices, and the resultant effects of such prices on our drilling economics and ability to raise capital, will require us to reevaluate and further postpone or eliminate additional drilling. Additionally, as of December 31, 2020, approximately 30% of our total net acreage was not held by production and we had undeveloped leases representing 1% and 21% of our total net acreage scheduled to expire during 2021 and 2022, respectively, in each case assuming no exercise of lease extension options where applicable. The net acreage scheduled to expire in 2022 is substantially comprised of non-core acreage principally located in Texas. If we are required to further curtail our drilling program, we may be unable to continue to hold such leases that are scheduled to expire, which may further reduce our reserves. As a result, if oil, natural gas and/or NGL prices experience a sustained period of weakness, our future business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures may be materially and adversely affected. 
+If oil and natural gas prices remain depressed for extended periods of time, we may be required to make significant downward adjustments to the carrying value of our oil and natural gas properties. Under the full cost method, which we use to account for our oil and natural gas properties, the net capitalized costs of our oil and natural gas properties may not exceed the PV-10 of our estimated proved reserves, using the 12-Month Average Realized Price, plus the lower of cost or fair market value of our unproved properties. If such net capitalized costs exceed this limit, we must charge the amount of the excess to earnings. This type of charge will not affect our cash flows, but will reduce the book value of our stockholders’ equity. We review the carrying value of our properties quarterly and once incurred, an impairment of evaluated oil and natural gas properties is not reversible at a later date, even if prices increase. See “Note 2 - Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements as well as the Supplemental Information on Oil and Natural Gas Operations for additional information. 
+A negative shift in investor sentiment of the oil and gas industry could adversely affect our ability to raise debt and equity capital. Certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition, some investors, including investment advisors and certain sovereign wealth funds, pension funds, university endowments and family foundations, have stated policies to disinvest in the oil and gas sector based on their social and environmental considerations. Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas production and related infrastructure projects. Such developments, including environmental activism and initiatives aimed at limiting 
+31 
+climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also potentially result in a reduction of available capital funding for potential development projects, impacting our future financial results. 
+We face various risks associated with increased activism against oil and natural gas exploration and development activities. Opposition toward oil and natural gas drilling and development activity has been growing globally and is particularly pronounced in the United States. Companies in the oil and natural gas industry are often the target of activist efforts from both individuals and non- governmental organizations regarding safety, human rights, climate change, environmental matters, sustainability, and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain operations such as drilling and development. 
+The unavailability or high cost of drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could materially and adversely affect our operations and profitability. From time to time, our industry experiences a shortage of drilling rigs, equipment, supplies, water or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, during periods in which the levels of exploration and production increase, the demand for, and wages and costs of, drilling rig crews and other experienced personnel, oilfield services and equipment typically also increase, while the quality of these services and equipment may suffer. 
+An excess supply of oil and natural gas may in the future cause us to reduce production and shut-in our wells, any of which could adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures. As a result of the COVID-19 pandemic and the effects of actions by, or disputes among or between, oil and natural gas producing countries, there is an excess supply of oil, NGLs, and natural gas in the United States, which could continue for a sustained period. This excess supply, in turn, resulted in transportation and storage capacity constraints in the United States in 2020. If, in the future, our transportation or storage arrangements become constrained or unavailable, we may incur significant operational costs if there is an increase in price for services or we may be required to shut-in or curtail production or flare our natural gas. If we were required to shut-in wells, we might also be obligated to pay certain demand charges for gathering and processing services and firm transportation charges for pipeline capacity we have reserved. Further, any prolonged shut-in of our wells may result in materially decreased well productivity once we are able to resume operations, and any cessation of drilling and development of our acreage could result in the expiration, in whole or in part, of our leases. All of these impacts may adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures. 
+Risks Related to the COVID-19 Pandemic 
+The COVID-19 pandemic, and various governmental actions taken to mitigate its impact, have materially adversely affected, and any future outbreak of any other highly infectious or contagious diseases may materially adversely affect, our business, financial position, results of operations, and cash flows. The COVID-19 pandemic, and various governmental actions taken to mitigate its impact, have negatively impacted the global economy, disrupted global supply chains, created significant volatility and disruption of financial and commodity markets, and resulted in an unprecedented decline in demand for oil and natural gas, which has materially adversely affected our business, financial position, results of operations, and cash flows and exacerbated the potential negative impact from many of the other risks described herein, including those relating to our financial position and debt obligations. Also, for example, the pandemic has increased volatility and caused negative pressure in the capital markets; as a result, we may experience difficulty accessing the capital or financing needed to fund our operations, which have substantial capital requirements, on satisfactory terms or at all, compounding liquidity risks associated with a material reduction in our revenues and cash flows as a result of the decline in demand due to the COVID-19 pandemic. 
+We expect the COVID-19 pandemic and related economic repercussions to continue to materially and adversely affect our business, financial condition, results of operations, and cash flows. However, the extent of the impact of the COVID-19 pandemic on our business and our operational and financial performance, including our ability to execute our business strategies and initiatives in the expected time frame, is uncertain and depends on various factors that we cannot predict, including the following: the severity and duration of the pandemic; governmental, business and other actions in response to the pandemic; the impact of the pandemic on economic activity; the response of the overall economy and the financial markets; the demand for oil and natural gas, which may be reduced on a prolonged or permanent basis due to a structural shift in the global economy in the way people work, travel, and interact, or in connection with a global recession or depression; any impairment in the value of our tangible or intangible assets which could be recorded as a result of a weaker economic conditions or commodity prices; and the potential effects on our internal controls, including those over financial reporting, as a result of changes in working environments, such as shelter-in-place and similar orders that are applicable to our employees and business partners, among others. There are no comparable recent events that provide guidance as to the effect the COVID-19 pandemic may have, and as a result, the ultimate impact of the pandemic is highly uncertain and subject to change. 
+Operational Risks 
+Our operations are subject to operating hazards inherent to our industry that may adversely impact our ability to conduct business, and we may not be fully insured against all such operating risks. The operating hazards in exploring for and producing oil and natural gas include: encountering unexpected subsurface conditions that cause damage to equipment or personal injury, 
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+including loss of life; equipment failures that curtail or stop production or cause severe damage to or destruction of property, natural resources or other equipment; blowouts or other damages to the productive formations of our reserves that require a well to be re-drilled or other corrective action to be taken; and storms and other extreme weather conditions that cause damages to our production facilities or wells. Because of these or other events, we could experience environmental hazards, including release of oil and natural gas from spills, natural gas leaks, accidental leakage of toxic or hazardous materials, such as petroleum liquids, drilling fluids or fracturing fluids, including chemical additives, underground migration, and ruptures. If we experience any of these problems, we could incur substantial losses in excess of our insurance coverage. 
+The occurrence of a significant event or claim, not fully insured or indemnified against, could have a material adverse effect on our financial condition and operations. In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. Also, no assurance can be given that we will be able to maintain insurance in the future at rates we consider reasonable to cover our possible losses from operating hazards and we may elect no or minimal insurance coverage. 
+Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns. Exploration, development, drilling and production activities are subject to many risks. We may invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that any leasehold acreage acquired will be profitably developed, that new wells drilled will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, including wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, we may not be successful in controlling our drilling and production costs to improve our overall return and wells that are profitable may not achieve our targeted rate of return. Wells may have production decline rates that are greater than anticipated. Future drilling and completion efforts may impact production from existing wells, and parent-child effects may impact future well productivity as a result of timing, spacing proximity or other factors. Failure to conduct our oil and gas operations in a profitable manner may result in write- downs of our proved reserves quantities, impairment of our oil and gas properties, and a write-down in the carrying value of our unproved properties, and over time may adversely affect our growth, revenues and cash flows. 
+Multi-well pad drilling may result in volatility in our operating results. We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production. In addition, problems affecting a single well could adversely affect production from all of the wells on the pad, which would further cause delays in the scheduled commencement of production or interruptions in ongoing production. These delays or interruptions may cause volatility in our operating results. Further, any delay, reduction or curtailment of our development and producing operations due to operational delays caused by multi-well pad drilling could result in the loss of acreage through lease expirations. 
+Restrictions on our ability to obtain, recycle and dispose of water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner. Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to secure water from local land owners and other third party sources for use in our operations. If drought conditions were to occur or demand for water were to outpace supply, our ability to obtain water could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. Along with the risks of other extreme weather events, drought risk, in particular, is likely increased by climate change. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows. In addition, significant amounts of water are produced in our operations. Inadequate access to or availability of water recycling or water disposal facilities could adversely affect our production volumes or significantly increase the cost of our operations. 
+Risks Related to Marketing and Transportation 
+Factors beyond our control, including the availability and capacity of gas processing facilities and pipelines and other transportation operations owned and operated by third parties, affect the marketability of our production. The ability to market oil and natural gas from our wells depends upon numerous factors beyond our control. A significant factor in our ability to market our production is the availability and capacity of gas processing facilities and pipeline and other transportation operations, including trucking services, owned and operated by third parties. These facilities and services may be temporarily unavailable to us due to market conditions, physical or mechanical disruption, weather, lack of contracted capacity, pipeline safety issues, or other reasons. In addition, in certain newer development areas, processing and transportation facilities and services may not be sufficient to accommodate potential production and it may be necessary for new interstate and intrastate pipelines and gathering systems to be built. Our failure to obtain access to processing and transportation facilities and services on acceptable terms could materially harm our business. We may be required to shut in wells for lack of a market or because of inadequate or unavailable processing or transportation capacity. If that were to occur, we would be unable to realize revenue from those wells until transportation arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells, we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. If we were required to shut in our production for long periods of time due to lack of transportation capacity, it would have a material adverse effect on our business, financial condition, results of operations and cash flows. 
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+Other factors that affect our ability to market our production include: 
+• the extent of domestic production and imports/exports of oil and natural gas; 
+• federal regulations authorizing exports of LNG, the development of new LNG export facilities under construction in the U.S. Gulf Coast region, and the first LNG exports from such facilities; 
+• the construction of new pipelines capable of exporting U.S. natural gas to Mexico and transporting Eagle Ford and Permian oil production to the Gulf Coast; 
+• the proximity of hydrocarbon production to pipelines; 
+• the demand for oil and natural gas by utilities and other end users; 
+• the availability of alternative fuel sources; 
+• the effects of inclement weather; and 
+• state and federal regulation of oil, natural gas and NGL marketing and transportation. 
+We have entered into firm transportation contracts that require us to pay fixed sums of money regardless of quantities actually shipped. If we are unable to deliver the minimum quantities of production, such requirements could adversely affect our results of operations, financial position, and liquidity. We have entered into firm transportation agreements for a portion of our production in certain areas in order to improve our ability, and that of our purchasers, to successfully market our production. We may also enter into firm transportation arrangements for additional production in the future. These firm transportation agreements may be more costly than interruptible or short-term transportation agreements. Additionally, these agreements obligate us to pay fees on minimum volumes regardless of actual throughput. If we have insufficient production to meet the minimum volumes, the requirements to pay for quantities not delivered could have an impact on our results of operations, financial position, and liquidity. 
+Risks Related to Our Reserves and Drilling Locations 
+Our estimated reserves are based on interpretations and assumptions that may be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. This Annual Report contains estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves. The process of estimating oil and natural gas reserves is complex and requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. These assumptions include those required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. 
+Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from the estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this 2020 Annual Report on Form 10-K. Additionally, estimates of reserves and future cash flows may be subject to material downward or upward revisions, based on production history, development drilling and exploration activities and prices of oil and natural gas. 
+You should not assume that any PV-10 of our estimated proved reserves contained in this 2020 Annual Report on Form 10-K represents the market value of our oil and natural gas reserves. We base the PV-10 from our estimated proved reserves at December 31, 2020 on the 12-Month Average Realized Price and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures, the rate and timing of production, and changes in governmental regulations or taxes. Recovery of PUDs generally requires significant capital expenditures and successful drilling operations. Our reserve estimates include the assumption that we will make significant capital expenditures to develop these PUDs and the actual costs, development schedule, and results associated with these properties may not be as estimated. In addition, the discount factor used to calculate PV-10 may not be appropriate based on our cost of capital from time to time and the risks associated with our business and the oil and gas industry. 
+Unless we replace our oil and gas reserves, our reserves and production will decline. Our future oil and gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our production, revenues, reserve quantities and cash flows will decline. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. We may not be successful in finding, developing or acquiring additional reserves, and our efforts may not be economic. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be limited to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. 
+Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could prevent them from being drilled or delay their drilling. Our management team has identified drilling locations as an estimation of our future development activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these identified drilling locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, availability and cost of drilling, completion and production services and equipment, lease expirations, regulatory approvals, and other factors discussed in these risk factors. Because of these uncertain factors, we do not know if the identified drilling locations will ever be drilled or if we will be able to produce oil or natural gas from these drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres 
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+on which some of the identified locations are located, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified. 
+The development of our PUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. Developing PUDs requires significant capital expenditures and successful drilling operations, and a substantial amount of our proved reserves are PUDs which may not be ultimately developed or produced. Approximately 55% of our total estimated proved reserves as of December 31, 2020 were PUDs. The reserve data included in the reserve reports of our independent petroleum engineers assume significant capital expenditures will be made to develop such reserves. We cannot be certain that the estimated capital expenditures to develop these reserves are accurate, that development will occur as scheduled, or that the results of such development will be as estimated. We may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including: unexpected drilling conditions; pressure or irregularities in formations; lack of proximity to and shortage of capacity of transportation facilities; equipment failures or accidents and shortages or delays in the availability of drilling rigs, equipment, personnel and services; the availability of capital; and compliance with governmental requirements. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the future net revenues of our estimated PUDs and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves. 
+Risks Related to Technology 
+We may not be able to keep pace with technological developments in our industry. The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected. 
+Our business could be negatively affected by security threats. A cyberattack or similar incident could occur and result in information theft, data corruption, operational disruption, damage to our reputation or financial loss. The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, manage operations, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Our technologies, systems, networks, seismic data, reserves information or other proprietary information, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or could otherwise lead to the disruption of our business operations or other operational disruptions in our exploration or production operations. Cyberattacks are becoming more sophisticated and certain cyber incidents, such as surveillance, may remain undetected for an extended period and could lead to disruptions in critical systems or the unauthorized release of confidential or otherwise protected information. These events could lead to financial losses from remedial actions, loss of business, disruption of operations, damage to our reputation or potential liability. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyberattack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. Cyber incidents have increased, and the U.S. government has issued warnings indicating that energy assets may be specific targets of cybersecurity threats. Our systems and insurance coverage for protecting against cybersecurity risks may not be sufficient. Further, as cyberattacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyberattacks. 
+Risks Related to Our Indebtedness and Financial Position 
+Our business requires significant capital expenditures and we may not be able to obtain needed capital or financing on satisfactory terms or at all. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Historically, we have funded our capital expenditures through a combination of cash flows from operations, borrowings from financial institutions, the sale of public debt and equity securities and asset dispositions. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, participation of non-operating working interest owners, the cost and availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. 
+If the ability to borrow under our Credit Facility or our cash flows from operations decrease, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. The failure to obtain additional financing on terms acceptable to us, or at all, could result in a curtailment of our development activities and could adversely affect our business, financial condition and results of operations. 
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+Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects. As of December 31, 2020, we had aggregate outstanding indebtedness of approximately $3.0 billion. Our amount of indebtedness could affect our operations in many ways, including: 
+• requiring us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities; 
+• limiting management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; 
+• increasing our vulnerability to downturns and adverse developments in our business and the economy; 
+• limiting our ability to access the capital markets to raise capital on favorable terms, to borrow under our Credit Facility or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness; 
+• making it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; 
+• making us vulnerable to increases in interest rates as our indebtedness under our Credit Facility may vary with prevailing interest rates; 
+• placing us at a competitive disadvantage relative to competitors with lower levels of indebtedness or less restrictive terms governing their indebtedness; and 
+• making it more difficult for us to satisfy our obligations under our senior notes or other debt and increasing the risk that we may default on our debt obligations. 
+Restrictive covenants in the agreements governing our indebtedness may limit our ability to respond to changes in market conditions or pursue business opportunities. Our Credit Facility and the indentures governing our senior notes contain restrictive covenants that limit our ability to, among other things: incur additional indebtedness including secured indebtedness; make investments; merge or consolidate with another entity; pay dividends or make certain other payments; hedge future production or interest rates; create liens that secure indebtedness; repurchase securities; sell assets; or engage in certain other transactions without the prior consent of the holders or lenders. As a result of these covenants, we are limited in the manner in which we conduct our business and we may be unable to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business. 
+In addition, our Credit Facility requires us to maintain certain financial ratios and to make certain required payments of principal, premium, if any, and interest. If we fail to comply with these provisions or other financial and operating covenants in the Credit Facility or the indentures governing our senior notes, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our Credit Facility could elect to terminate their commitments thereunder, cease making further loans and institute foreclosure proceedings against our assets; and we could be forced into bankruptcy or liquidation. 
+Adverse changes in our credit rating may affect our borrowing capacity and borrowing terms. Our outstanding debt is periodically rated by nationally recognized credit rating agencies. The credit ratings are based on our operating performance, liquidity and leverage ratios, overall financial position, and other factors viewed by the credit rating agencies as relevant to our industry and the economic outlook. Our credit rating may affect the amount of capital we can access, as well as the terms of any financing we may obtain. Because we rely in part on debt financing to fund growth, adverse changes in our credit rating may have a negative effect on our future growth. 
+Our borrowings under our Credit Facility expose us to interest rate risk. Our earnings are exposed to interest rate risk associated with borrowings under our Credit Facility, which bear interest at a rate elected by us that is based on the prime, LIBOR or federal funds rate plus margins ranging from 1.00% to 3.00% depending on the interest rate used and the amount of the loan outstanding in relation to the borrowing base. 
+The ability to borrow under our Credit Facility may be restricted to an amount below the amount of borrowings outstanding thereunder or to a lesser amount than what we expect due to future borrowing base reductions or restrictions contained in our other debt agreements. The borrowing base and elected commitment amount under our Credit Facility is currently $1.6 billion, and as of December 31, 2020, we had an aggregate principal balance of $985.0 million outstanding thereunder. Our borrowing base is subject to redeterminations semi-annually, and a future decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations may cause us to not be able to access adequate funding under the Credit Facility. The lenders have sole discretion in determining the amount of the borrowing base and may cause our borrowing base to be redetermined to a materially lower amount, including to below our outstanding borrowings as of such redetermination. In addition, our other debt agreements contain restrictions on the incurrence of additional debt and liens which could limit our ability to borrow under our Credit Facility. If our borrowing base were to be reduced, or if covenants in our indentures restrict our ability to access funding under the Credit Facility, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness. In addition, we cannot borrow amounts above the elected commitments, even if the borrowing base is greater, without 
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+new commitments being obtained from the lenders for such incremental amounts above the elected commitments. In the event the amount outstanding under our Credit Facility exceeds the elected commitments, we must repay such amounts immediately in cash. In the event the amount outstanding under our Credit Facility exceeds the redetermined borrowing base, we are required to either (i) grant liens on additional oil and gas properties (not previously evaluated in determining such borrowing base) with a value equal to or greater than such excess, (ii) repay such excess borrowings over six monthly installments, or (iii) elect a combination of options in clauses (i) and (ii). We may not have sufficient funds to make any required repayment. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, an event of default would occur under our Credit Facility. 
+We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful. Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to certain financial, economic, competitive and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. 
+If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Also, we may not be able to consummate dispositions at such time on terms acceptable to us or at all, and the proceeds of any such dispositions may not be adequate to meet such debt service obligations. Furthermore, any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. In addition, the terms of existing or future debt instruments may restrict us from adopting some of these alternatives. For example, our Credit Facility currently restricts our ability to dispose of assets and our use of the proceeds from such disposition. 
+Any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. 
+We cannot be certain that we will be able to maintain or improve our leverage position. An element of our business strategy involves maintaining a disciplined approach to financial management. However, we are also seeking to acquire, exploit and develop additional reserves that may require the incurrence of additional indebtedness. Although we will seek to maintain or improve our leverage position, our ability to maintain or reduce our level of indebtedness depends on a variety of factors, including future performance and our future debt financing needs. General economic conditions, oil and natural gas prices and financial, business and other factors will also affect our ability to maintain or improve our leverage position. Many of these factors are beyond our control. 
+Risks Related to Acquisitions 
+We may be unable to integrate successfully the operations of acquisitions with our operations, and we may not realize all the anticipated benefits of these acquisitions. We have completed, and may in the future complete, acquisitions that include undeveloped acreage. We can offer no assurance that we will achieve the desired profitability from our acquisitions, including the Carrizo Acquisition, or from any acquisitions we may complete in the future. In addition, failure to integrate future acquisitions successfully could adversely affect our financial condition and results of operations. 
+Our acquisitions may involve numerous risks, including those related to: 
+• operating a larger, more complex combined organization and adding operations; 
+• assimilating the assets and operations of the acquired business, especially if the assets acquired are in a new geographic area; 
+• acquired oil and natural gas reserves not being of the anticipated magnitude or as developed as anticipated; 
+• the loss of significant key employees, including from the acquired business; 
+• the inability to obtain satisfactory title to the assets we acquire; 
+• a decrease in our liquidity if we use a portion of our available cash to finance acquisitions; 
+• a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions; 
+• the diversion of management’s attention from other business concerns, which could result in, among other things, performance shortfalls; 
+• the failure to realize expected profitability or growth; 
+• the failure to realize expected synergies and cost savings; 
+• coordinating geographically disparate organizations, systems and facilities; 
+• coordinating or consolidating corporate and administrative functions; 
+• inconsistencies in standards controls, procedures and policies; and 
+• integrating relationships with customers, vendors and business partners. 
+Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. The elimination of duplicative costs, as well as the 
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+realization of other efficiencies related to the integration of our two companies, may not initially offset integration-related costs or achieve a net benefit in the near term or at all. 
+If we consummate any future acquisitions, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions. The inability to effectively manage the integration of acquisitions could reduce our focus on current operations, which in turn, could negatively impact our future results of operations. 
+We may fail to fully identify problems with any properties we acquire, and as such, assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities. We are actively seeking to acquire additional acreage in Texas or other regions in the future. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, adequacy of title, operating and capital costs, and potential environmental and other liabilities. Although we conduct a review that we believe is consistent with industry practices, we can give no assurance that we have identified or will identify all existing or potential problems associated with such properties or that we will be able to mitigate any problems we do identify. Such assessments are inexact and their accuracy is inherently uncertain. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface, title and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms. 
+Risks Related to Our Hedging Program 
+Our hedging program may limit potential gains from increases in commodity prices, result in losses, or be inadequate to protect us against continuing and prolonged declines in commodity prices. We enter into arrangements to hedge a portion of our production from time to time to reduce our exposure to fluctuations in oil and natural gas prices and to achieve more predictable cash flow. Our hedges at December 31, 2020 are in the form of collars, swaps, put and call options, basis swaps, and other structures placed with the commodity trading branches of certain national banking institutions and with certain other commodity trading groups. These hedging arrangements may limit the benefit we could receive from increases in the market or spot prices for oil and natural gas. We cannot be certain that the hedging transactions we have entered into, or will enter into, will adequately protect us from continuing and prolonged declines in oil and natural gas prices. To the extent that oil and natural gas prices remain at current levels or decline further, we would not be able to hedge future production at the same pricing level as our current hedges and our results of operations and financial condition may be negatively impacted. 
+In addition, in a typical hedge transaction, we will have the right to receive from the other parties to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the other parties this difference multiplied by the quantity hedged regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements even though such payments are not offset by sales of physical production. 
+Our production is not fully hedged, and we are exposed to fluctuations in oil, natural gas and NGL prices and will be affected by continuing and prolonged declines in oil, natural gas and NGL prices. Our production is not fully hedged, and we are exposed to fluctuations in oil, natural gas and NGL prices and will be affected by continuing and prolonged declines in oil, natural gas and NGL prices. The total volumes which we hedge through use of our derivative instruments varies from period to period; however, generally our objective is to hedge approximately 60% of our anticipated internally forecast production for the next 12 to 24 months, subject to the covenants under our revolving credit facility. We intend to continue to hedge our production, but we may not be able to do so at favorable prices. Accordingly, our revenues and cash flows are subject to increased volatility and may be subject to significant reduction in prices which would have a material negative impact on our results of operations. 
+Our hedging transactions expose us to counterparty credit risk. Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract, particularly during periods of falling commodity prices. Disruptions in the financial markets or other factors outside our control could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform, and even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending on market conditions at the time. If the creditworthiness of any of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss. 
+Legal and Regulatory Risks 
+We are subject to stringent and complex federal, state and local laws and regulations which require compliance that could result in substantial costs, delays or penalties. Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. For a discussion of the material regulations applicable to us, see “Business and Properties—Regulations.” These laws and regulations may: 
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+• require that we acquire permits before commencing drilling; 
+• regulate the spacing of wells and unitization and pooling of properties; 
+• impose limitations on production or operational, emissions control and other conditions on our activities; 
+• restrict the substances that can be released into the environment or used in connection with drilling and production activities or restrict the disposal of waste from our operations; 
+• limit or prohibit drilling activities on protected areas, such as wetlands and wilderness; 
+• impose penalties or other sanctions for accidental or unpermitted spills or releases from our operations; or 
+• require measures to remediate or mitigate pollution and environmental impacts from current and former operations, such as cleaning up spills or decommissioning abandoned wells and production facilities. 
+Significant expenditures may be required to comply with governmental laws and regulations applicable to us. In addition, failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, permit revocations, requirements for additional pollution controls or injunctions limiting or prohibiting operations. 
+The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal, state and local agencies frequently revise environmental laws and regulations, and such changes could result in increased costs for environmental compliance, such as emissions control, permitting, or waste handling, storage, transport, remediation or disposal for the oil and natural gas industry and could have a significant impact on our operating costs. In general, the oil and natural gas industry recently has been the subject of increased legislative and regulatory attention with respect to public health and environmental matters. Even if regulatory burdens temporarily ease, the historic trend of more expansive and stricter environmental legislation and regulations may continue in the long-term. 
+Further, under these laws and regulations, we could be liable for costs of investigation, removal and remediation, damages to and loss of use of natural resources, loss of profits or impairment of earning capacity, property damages, costs of increased public services, as well as administrative, civil and criminal fines and penalties, and injunctive relief. Certain environmental statutes, including RCRA, CERCLA, OPA and analogous state laws and regulations, impose strict, joint and several liability for costs required to investigate, clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released (i.e., liability may be imposed regardless of whether the current owner or operator was responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time the release or contamination occurred). We could also be affected by more stringent laws and regulations adopted in the future, including any related to climate change, engine and other equipment emissions, GHGs and hydraulic fracturing. Under common law, we could be liable for injuries to people and property. We maintain limited insurance coverage for sudden and accidental environmental damages. We do not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Also, we do not believe that insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability in excess of our insurance coverage or we may be required to curtail or cease production from properties in the event of environmental incidents. 
+Federal legislation and state and local legislative and regulatory initiatives relating to hydraulic fracturing and water disposal wells could result in increased costs and additional operating restrictions or delays. Hydraulic fracturing is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production and is typically regulated by state oil and gas commissions. However, from time to time, the U.S. Congress has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing. Legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and to require federal permitting and regulatory control of hydraulic fracturing but has not passed. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, in February 2014, the EPA published permitting guidance addressing the use of diesel fuel in hydraulic fracturing operations, and issued an interpretive memorandum clarifying that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act. The EPA has also published air emission standards for certain equipment, processes and activities across the oil and natural gas sector, although the EPA finalized amendments in September 2020 that rescind requirements related to the regulation of methane emissions, known as the Reconsideration Rule. On January 20, 2021, President Biden issued an Executive Order directing the EPA to rescind the Reconsideration Rule by September 2021. Separately, in September 2020, the EPA finalized the Review Rule, rescinding requirements related to the regulations of methane emissions from the oil and natural gas industry. Both rules are subject to ongoing litigation; therefore, the scope of future obligations continues to remain uncertain. As a result, future implementation of methane rules by the EPA is uncertain at this time. However, given the long-term trend towards increasing regulation, future federal regulation of methane and other greenhouse gas emissions from the oil and gas industry remains a possibility. 
+In some areas of Texas, including the Eagle Ford and Permian, there has been concern that certain formations into which disposal wells are injecting produced waters could become over-pressured after many years of injection, and the RRC is reviewing the data to determine whether any regulatory action is necessary to address this issue. If the RRC were to decline to issue permits for, or limit the volumes of, new injection wells into the formations that we currently utilize, we may be required to seek alternative methods of disposing of produced waters, including injecting into deeper formations, which could increase our costs. 
+39 
+Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, impose additional requirements on hydraulic fracturing activities or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For example, Texas law requires the chemical components used in the hydraulic fracturing process, as well as the volume of water used, must be disclosed to the RRC and the public. Furthermore, the RRC issued the “well integrity rule” in May 2013, which includes testing and reporting requirements, such as (i) the requirement to submit to the RRC cementing reports after well completion or cessation of drilling, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. Additionally, in October 2014, the RRC adopted a rule requiring applicants for certain new water disposal wells to conduct seismic activity searches using the U.S. Geological Survey to determine the potential for earthquakes within a circular area of 100 square miles. The rule also clarifies the RRC’s authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The RRC has used this authority to deny permits for waste disposal wells. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of drilling in general or hydraulic fracturing in particular. 
+In December 2016, the EPA released its final report “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States.” This report concludes that hydraulic fracturing can impact drinking water resources in certain circumstances but also noted that certain data gaps and uncertainties limited EPA’s ability to fully characterize the severity of impacts or calculate the national frequency of impacts on drinking water resources from activities in the hydraulic fracturing water cycle. This study could result in additional regulatory scrutiny that could restrict our ability to perform hydraulic fracturing and increase our costs of compliance and doing business. 
+There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, water usage and the potential for impacts to surface water, groundwater and the environment generally, and a number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. Several states and municipalities have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances. If new laws or regulations that significantly restrict hydraulic fracturing or water disposal wells are adopted, such laws could make it more difficult or costly for us to drill for and produce oil and natural gas as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements, permitting delays and potential increases in costs. These changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing. 
+Climate change legislation or regulations restricting emissions of GHG, changes in the availability of financing for fossil fuel companies, and physical effects from climate change could adversely impact our operating costs and demand for the oil and natural gas we produce. In recent years, federal, state and local governments have taken steps to reduce emissions of GHGs. The EPA has finalized a series of GHG monitoring, reporting and emissions control rules, and the U.S. Congress has, from time to time, considered adopting legislation to reduce emissions. Several states have already taken measures to reduce emissions of GHGs primarily through the development of GHG emission inventories or regional GHG cap-and-trade programs. While we are subject to certain federal GHG monitoring and reporting requirements, our operations currently are not adversely impacted by existing federal, state and local climate change initiatives. For a description of existing and proposed GHG rules and regulations, see “Business and Properties—Regulations.” 
+In December 2015, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change resulted in nearly 200 countries, including the United States, coming together to develop the Paris Agreement, which calls for the parties to undertake “ambitious efforts” to limit the average global temperature. The Agreement went into effect on November 4, 2016, and establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. The United States formally announced its intent to withdraw from the Paris Agreement on November 4, 2019, which withdrawal became effective on November 4, 2020. On January 20, 2021, President Biden issued written notification to the United Nations of the United States’ intention to rejoin the Paris Agreement, which became effective on February 19, 2021. In addition, certain U.S. city and state governments announced their intention to continue to satisfy their proportionate obligations under the Paris Agreement. A number of states have begun taking actions to control or reduce emissions of GHGs. Restrictions on GHG emissions that may be imposed could adversely affect the oil and gas industry. The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Moreover, incentives or requirements to conserve energy, use alternative energy sources, reduce GHG emissions in product supply chains, and increase demand for low-carbon fuel or zero-emissions vehicles, could reduce demand for the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations. 
+40 
+In addition, fuel conservation measures, alternative fuel requirements and increasing consumer demand for alternatives to oil and natural gas could reduce demand for oil and natural gas. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could impact our business activities, operations and ability to access capital. Furthermore, some parties have initiated public nuisance claims under federal or state common law against certain companies involved in the production of oil and natural gas. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other liabilities. Although our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition. 
+Finally, most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce significant physical effects, such as increased frequency and severity of droughts, storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced or cause us to incur significant costs in preparing for or responding to the effects of climatic events themselves. Potential adverse effects could include disruption of our production activities, including, for example, damages to our facilities from winds or floods or increases in our costs of operation or reductions in the efficiency of our operations, as well as potentially increased costs for insurance coverages in the aftermath of such effects. 
+Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. Title VII of the Dodd-Frank Act establishes federal oversight and regulation of over-the-counter derivatives and requires the CFTC and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the over-the-counter market. 
+Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas, including the scope of relevant definitions or exemptions, remain pending. The CFTC issued a final rule on margin requirements for uncleared swap transactions in January 2016, which it amended in November 2018. The final rule as amended includes an exemption for certain commercial end-users that enter into uncleared swaps in order to hedge bona fide commercial risks affecting their business. In addition, the CFTC has issued a final rule authorizing an exception from the requirement to use cleared exchanges (rather than hedging over-the-counter) for commercial end-users who use swaps to hedge their commercial risks. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations. On January 24, 2020, U.S. banking regulators published a new approach for calculating the quantum of exposure of derivative contracts under their regulatory capital rules. This approach to measuring exposure is referred to as the standardized approach for counterparty credit risk or SA-CCR. It requires certain financial institutions to comply with significantly increased capital requirements for over-the-counter commodity derivatives beginning on January 1, 2022. In addition, on September 15, 2020, the CFTC issued a final rule regarding the capital a swap dealer or major swap participant is required to set aside with respect to its swap business, which has a compliance date of October 6, 2021. These two sets of regulations and the increased capital requirements they place on certain financial institutions may reduce the number of products and counterparties in the over-the-counter derivatives market available to us and could result in significant additional costs being passed through to end-users like us. On January 14, 2021, the CFTC published a final rule on position limits for certain commodities futures and their economically equivalent swaps, though like several other rules there is a bona fide hedging exemption to the application of such rule. All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business. 
+Depending on our ability to satisfy the CFTC’s requirements for the various exemptions available for a commercial end-user using swaps to hedge or mitigate its commercial risks, the final rules may provide beneficial exemptions and/or may require us to comply with position limits and other limitations with respect to our financial derivative activities. After the compliance date for the final rule on capital requirements, the Dodd-Frank Act may require our current counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which could increase the cost to us of entering into such derivatives. The Dodd-Frank Act may also require our current counterparties to financial derivative transactions to cease their current business as hedge providers or spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. These potential changes could reduce the liquidity of the financial derivatives markets which would reduce the ability of commercial end-users like us to hedge or mitigate their exposure to commodity price volatility. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of future swaps relative to the terms of our existing financial derivative contracts, and reduce the availability of derivatives to protect against commercial risks we encounter. 
+If we reduce our use of derivative contracts as a result of any of the foregoing new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Our revenues could be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations, or cash flows. 
+Tax Risks 
+Our ability to use our existing net operating loss (“NOL”) carryforwards or other tax attributes could be limited. A significant portion of our NOL carryforward balance was generated prior to the effective date of new limitations on utilization of NOLs imposed 
+41 
+by the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) and are allowable as a deduction against 100% of taxable income in future years, but will start to expire in the 2035 taxable year. The remainder were generated following such effective date, and thus generally allowable as a deduction against 80% of taxable income in future years (with an exception to this rule due to the enactment of the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”), whereby the utilization of NOLs has been temporarily expanded for taxable years beginning before 2021). Utilization of any NOL carryforwards depends on many factors, including our ability to generate future taxable income, which cannot be assured. In addition, Section 382 (“Section 382”) of the Internal Revenue Code of 1986, as amended (the “Code”), generally imposes, upon the occurrence of an ownership change (discussed below), an annual limitation on the amount of our pre-ownership change NOLs we can utilize to offset our taxable income in any taxable year (or portion thereof) ending after such ownership change. The limitation is generally equal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax exempt rate. In general, an ownership change occurs if there is a cumulative increase in our ownership of more than 50 percentage points by one or more “5% shareholders” (as defined in the Code) at any time during a rolling three-year period. Future ownership changes and/or future regulatory changes could further limit our ability to utilize our NOLs. To the extent we are not able to offset our future income with our NOLs, this could adversely affect our operating results and cash flows once we attain profitability. 
+Unanticipated changes in effective tax rates or adverse outcomes resulting from examination of our income or other tax returns could adversely affect our financial condition and results of operations. We are subject to income taxes in the U. S., and our domestic tax assets and liabilities are subject to the allocation of expenses in differing jurisdictions. Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including the following: changes in the valuation of our deferred tax assets and liabilities; expected timing and amount of the release of any tax valuation allowances; tax effects of stock-based compensation; costs related to intercompany restructurings; changes in tax laws, regulations or interpretations thereof; or lower than anticipated future earnings in our taxing jurisdictions. In addition, we may be subject to audits of our income, sales and other transaction taxes by U.S. federal and state authorities. Outcomes from these audits could have an adverse effect on our financial condition and results of operations. 
+Tax laws and regulations may change over time and such changes could adversely affect our business and financial condition. From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws, including (i) the elimination of the immediate deduction for intangible drilling and development costs, (ii) changes to a depletion allowance for oil and natural gas properties, (iii) the implementation of a carbon tax, (iv) an extension of the amortization period for certain geological and geophysical expenditures, (v) changes to tax rates and (vi) the introduction of a minimum tax. While these specific changes were not included in the Tax Act or the CARES Act, no accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. The elimination of such U.S. federal tax deductions, as well as any other changes to or the imposition of new federal, state, local or non-U.S. taxes (including the imposition of, or increases in production, severance or similar taxes) could adversely affect our business and financial condition. 
+Other Material Risks 
+Competitive industry conditions may negatively affect our ability to conduct operations. We compete with numerous other companies in virtually all facets of our business. Our competitors in development, exploration, acquisitions and production include major integrated oil and gas companies and smaller independents as well as numerous financial buyers. Some of our competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources permit. We also compete for the materials, equipment, personnel and services that are necessary for the exploration, development and operation of our properties. Our ability to increase reserves in the future will be dependent on our ability to select and acquire suitable prospects for future exploration and development. 
+All of our producing properties are located in the Permian of West Texas and the Eagle Ford of South Texas, making us vulnerable to risks associated with operating in only two geographic regions. As a result of this concentration, as compared to companies that have a more diversified portfolio of properties, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services, or market limitations or interruption of the processing or transportation of oil, natural gas or NGLs. Such delays, interruptions or limitations could have a material adverse effect on our financial condition and results of operations. In addition, the effect of fluctuations on supply and demand may be more pronounced within specific geographic oil and natural gas producing areas, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. 
+The results of our planned development programs in new or emerging shale development areas and formations may be subject to more uncertainties than programs in more established areas and formations, and may not meet our expectations for reserves or production. The results of our horizontal drilling efforts in emerging areas and formations of the Permian are generally more uncertain than drilling results in areas that are more developed and have more established production from horizontal formations. Because emerging areas and associated target formations have limited or no production history, we are less able to rely on past drilling results in those areas as a basis to predict our future drilling results. In addition, horizontal wells drilled in shale formations, as distinguished from vertical wells, utilize multilateral wells and stacked laterals, all of which are subject to well spacing, density and proration requirements of the RRC, which requirements could adversely impact our ability to maximize the efficiency of our 
+42 
+horizontal wells related to reservoir drainage over time. Further, access to adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more challenging in new or emerging areas. If our drilling results in these areas are less than anticipated or we are unable to execute our drilling program in these areas because of capital constraints, access to gathering systems and takeaway capacity or otherwise, or natural gas and oil prices decline, our investment in these areas may not be as economic as we anticipate, we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future. 
+The loss of key personnel could adversely affect our ability to operate. We depend, and will continue to depend in the foreseeable future, on the services of our senior officers and other key employees, as well as other third-party consultants with extensive experience and expertise in evaluating and analyzing drilling prospects and producing oil and natural gas and maximizing production from oil and natural gas properties. Our ability to retain our senior officers, other key employees, and third party consultants, many of whom are not subject to employment agreements, is important to our future success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business. 
+The inability of one or more of our customers to meet their obligations to us may adversely affect our financial results. Our principal exposure to credit risk is through receivables resulting from the sale of our oil and natural gas production, advances to joint interest parties and joint interest receivables. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. The largest purchaser of our oil and natural gas accounted for approximately 31% of our total revenues for the year ended December 31, 2020. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. 
+Our bylaws designate the Court of Chancery of the State of Delaware (the “Court of Chancery”) as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our shareholders, which could limit our shareholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, or other employees. Our bylaws provide that, unless we consent in writing to the selection of an alternative forum, the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action or proceeding asserting a claim for breach of a fiduciary duty owed by any current or former director, officer, or other employee of our company to us or our shareholders, (iii) any action or proceeding asserting a claim against us or any current or former director, officer, or other employee of our company arising pursuant to any provision of the Delaware General Corporate Law (the “DGCL”) or our charter or bylaws (as each may be amended from time to time), (iv) any action or proceeding asserting a claim against us or any current or former director, officer, or other employee of our company governed by the internal affairs doctrine, or (v) any action or proceeding as to which the DGCL confers jurisdiction on the Court of Chancery shall be the Court of Chancery or, if and only if the Court of Chancery lacks subject matter jurisdiction, any state court located within the State of Delaware or, if and only if such state courts lack subject matter jurisdiction, the federal district court for the District of Delaware, in all cases to the fullest extent permitted by law and subject to the court’s having personal jurisdiction over the indispensable parties named as defendants. 
+Our exclusive forum provision is not intended to apply to claims arising under the Securities Act or the Exchange Act. To the extent the provision could be construed to apply to such claims, there is uncertainty as to whether a court would enforce the forum selection provision with respect to such claims, and in any event, our shareholders would not be deemed to have waived our compliance with federal securities laws and the rules and regulations thereunder. 
+Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock is deemed to have received notice of and consented to the foregoing forum selection provision. This provision may limit our shareholders’ ability to bring a claim in a judicial forum that they find favorable for disputes with us or our directors, officers, or other employees, which may discourage such lawsuits. Alternatively, if a court were to find this choice of forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect its business, financial condition, prospects, or results of operations. 
+Provisions of our charter documents and Delaware law may inhibit a takeover, which could limit the price investors might be willing to pay in the future for our common stock. Provisions in our certificate of incorporation and bylaws may have the effect of delaying or preventing an acquisition of the Company or a merger in which we are not the surviving company and may otherwise prevent or slow changes in our Board of Directors and management. In addition, because we are incorporated in Delaware, we are governed by the provisions of Section 203 of the DGCL. These provisions could discourage an acquisition of the Company or other change in control transactions and thereby negatively affect the price that investors might be willing to pay in the future for our common stock. 
+We have no current plans to pay cash dividends on our common stock. Our Credit Facility and the indentures governing our senior notes limit our ability to pay dividends and make other distributions. We have no current plans to pay dividends on our common stock and any future determination as to the declaration and payment of cash dividends will be at the discretion of our Board of Directors and will depend upon our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors deemed relevant by our Board of Directors at the time of such determination. Consequently, unless we revise our dividend plans, a shareholder’s only opportunity to achieve a return on its investment in us will be by selling its shares of our common stock at a price greater than the shareholder paid for it. There is no guarantee that the price of our common stock that will prevail in the market will exceed the price at which a shareholder purchased its shares of our common stock. 
+43 
+General Risk Factors 
+We may be subject to the actions of activist shareholders. We have been the subject of an activist shareholder in the past. Responding to shareholder activism can be costly and time-consuming, disrupt our operations and divert the attention of management and our employees from executing our business plan. Activist campaigns can create perceived uncertainties as to our future direction, strategy or leadership and may result in the loss of potential business opportunities, harm our ability to attract new investors, customers and joint venture partners and cause our stock price to experience periods of volatility or stagnation. Moreover, if individuals are elected to our Board of Directors with a specific agenda, our ability to effectively and timely implement our current initiatives, retain and attract experienced executives and employees and execute on our long-term strategy may be adversely affected. 
+Future sales of our common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of our common stock or other securities may dilute a shareholder’s ownership in us. In the future, we may issue securities to raise capital. We may also acquire interests in other companies by using any combination of cash and our common stock or other securities convertible into, or exchangeable for, or that represent the right to receive, our common stock. Any of these events may dilute your ownership interest in our company, reduce our earnings per share or have an adverse impact on the price of our common stock. In addition, secondary sales of a substantial amount of our common stock in the public market, or the perception that these sales may occur, could reduce the market price of our common stock. Any such reduction in the market price of our common stock could impair our ability to raise additional capital through the sale of our securities. 
+ITEM 1B. Unresolved Staff Comments 
+None. 
+ITEM 3. Legal Proceedings 
+We are a defendant in various legal proceedings and claims, which arise in the ordinary course of our business. While the outcome of these events cannot be predicted with certainty, we believe that the ultimate resolution of any such actions will not have a material effect on our financial position or results of operations. 
+ITEM 4. Mine Safety Disclosures 
+Not applicable. 
+44 
+PART II. 
+ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+Market Information 
+Our common stock trades on the New York Stock Exchange (“NYSE”) under the symbol “CPE”. 
+Reverse Stock Split 
+On August 7, 2020, the Board of Directors effected a reverse stock split of the Company’s outstanding shares of common stock at a ratio of 1-for-10 and proportionately reduced the total number of authorized shares of the Company’s common stock pursuant to an amendment to the Company’s Certificate of Incorporation, which was approved by the Company’s shareholders at the Company’s annual meeting of shareholders on June 8, 2020. The reverse stock split became effective as of the close of business on August 7, 2020. The Company’s common stock began trading on a split-adjusted basis on the NYSE at the market open on August 10, 2020. All share and per share amounts in this Annual Report on Form 10-K for periods prior to August 7, 2020 have been retroactively adjusted to reflect the reverse stock split. The par value of the common stock was not adjusted as a result of the reverse stock split. 
+Holders 
+As of February 19, 2021 the Company had approximately 1,569 common stockholders of record. 
+Dividends 
+We have not paid any cash dividends on our common stock to date and presently do not expect to declare or pay any cash dividends on our common stock as we intend to reinvest our cash flows and earnings into our business and pay down debt. The declaration and payment of dividends is subject to the discretion of our Board of Directors and to certain limitations imposed under Delaware corporate law and the agreements governing our debt obligations. The timing, amount and form of dividends, if any, will depend on, among other things, our results of operations, financial condition, cash requirements and other factors deemed relevant by our Board of Directors. In addition, certain of our debt facilities contain restrictions on the payment of dividends to the holders of our common stock. 
+45 
+Performance Graph 
+The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the performance of the Company’s common stock relative to a broad-based stock performance index and a peer group of companies. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. 
+The graph below compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the Standard & Poor’s 500 Index (“S&P 500 Index”) and a peer group of companies to which we compare our performance from December 31, 2015 through December 31, 2020. The companies in the peer group include Cimarex Energy Co., Centennial Resource Development, Inc., Magnolia Oil & Gas Corporation, Matador Resources, Inc., Parsley Energy, Inc., PDC Energy, Inc., QEP Resources, Inc., SM Energy Company, and WPX Energy, Inc. 
+The stock performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing 
+Comparison of Five Year Cumulative Total Return 
+Assumes Initial Investment of $100 
+December 31, 2020 
+Years Ended December 31, 
+Company/Market/Peer Group 2015 2016 2017 2018 2019 2020 
+Callon Petroleum Company $100 $184 $146 $78 $58 $16 
+S&P 500 Index - Total Returns 100 112 136 130 172 203 
+Peer Group 100 168 143 94 88 54 
+46 
+ITEM 6. Selected Financial Data 
+None. 
+ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+A discussion and analysis of the Company’s financial condition and results of operations for the year ended December 31, 2018 can be found in “Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” of its Annual Report on Form 10-K for the year ended December 31, 2019, which was filed with the SEC on February 28, 2020. 
+General 
+The following management’s discussion and analysis describes the principal factors affecting our results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying audited consolidated financial statements, information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results, which are included in various parts of this filing. 
+All of our filings with the SEC are available free of charge through our website (www.callon.com) as soon as reasonably practicable after we file them with, or furnish them to, the SEC. Information on our website does not form part of this 2020 Annual Report on Form 10-K. 
+We are an independent oil and natural gas company incorporated in the State of Delaware in 1994, but our roots go back over 70 years to our Company’s establishment in 1950. We are focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas. Our activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger Permian Basin in West Texas, as well as the Eagle Ford, which we entered into through the Carrizo Acquisition in late 2019. 
+Our operating culture is centered on responsible development of hydrocarbon resources, safety and the environment, which we believe strengthens our operational performance. Our drilling activity is predominantly focused on the horizontal development of several prospective intervals in the Permian, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales, and the Eagle Ford. We have assembled a multi-year inventory of potential horizontal well locations and intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and through acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps. 
+Recent Developments 
+February Winter Storm 
+In February 2021, severe winter storms affected field operations in both the Permian and Eagle Ford resulting in the shut-in of nearly 100% of our operated production. Currently, we have returned nearly all of our Eagle Ford and Midland Basin wells to production and expect to have all of our Delaware well production returned by the end of February. The impact to our drilling and completion operations were not significant enough to alter our expectations for the full year development schedule. 
+COVID-19 Outbreak and Global Industry Downturn 
+The worldwide outbreak of COVID-19 in 2020, the uncertainty regarding the impact of COVID-19 and various governmental actions taken to mitigate the impact of COVID-19, have resulted in an unprecedented decline in demand for oil and natural gas. At the same time, the decision by Saudi Arabia in March 2020 to drastically reduce export prices and increase oil production followed by curtailment agreements among OPEC and other countries such as Russia further increased uncertainty and volatility around global oil supply-demand dynamics. These dual demand and supply shocks caused oil prices to collapse at the end of the first quarter of 2020 as well as created an excess supply of oil in the United States, which could continue for a sustained period; this is in addition to recent and continued excess supply of natural gas in the United States. This excess supply, in turn, resulted in transportation and storage capacity constraints in the United States during 2020, although these constraints have recently lessened and inventories have declined from peak levels. 
+Our expectation is that commodity prices, which are the most significant factors impacting our profitability, will remain cyclical and volatile. While commodity prices have recently increased to pre-COVID-19 levels, there is no assurance of how long they will remain at these levels. 
+2020 Highlights 
+Operational 
+• Our total production in 2020 increased by 147% to 37.2 MMBoe (63% oil) as compared to 2019 primarily as a result of the Carrizo Acquisition in late 2019 and wells placed on production during 2020 as a result of our horizontal drilling program. 
+47 
+• Although our actual 2020 operational capital expenditures were approximately 50% or our original operational capital budget as a result of COVID-19 and the macro-economic environment, we drilled 91 gross (86.0 net) horizontal well and completed 90 gross (81.4 net) horizontal wells for the year ended December 31, 2020 and had, as of December 31, 2020, 65 gross (62.1 net) horizontal wells awaiting completion. 
+• Estimated proved reserves as of December 31, 2020 were 475.9 MMBoe (61% oil), with 45% classified as proved developed. 
+Financing 
+• On November 13, 2020, we exchanged $389.0 million of aggregate principal amount of our existing Senior Unsecured Notes for $216.7 million aggregate principal amount of November 2020 Second Lien Notes and 1.75 million November 2020 Warrants. This exchange resulted in the removal of approximately $172.3 million from the long-term debt balance in our consolidated balance sheets. 
+• On September 30, 2020, we issued $300.0 million of aggregate principal amount of September 2020 Second Lien Notes and 7.3 million September 2020 Warrants for proceeds, net of issuance costs, of approximately $288.6 million. 
+• As of December 31, 2020, our Credit Facility had a borrowing base and elected commitment amount of $1.6 billion and $985.0 million of borrowings outstanding as compared to borrowings outstanding as of December 31, 2019 of $1.3 billion. 
+Divestitures 
+• On September 30, 2020, we sold an undivided 2.0% (on an 8/8ths basis) overriding royalty interest, proportionately reduced to our net revenue interest, in and to our operated leases, excluding certain interests (“ORRI Transaction”) for net proceeds of $135.8 million, which were used to repay borrowings outstanding under the Credit Facility. 
+• On November 2, 2020, we sold substantially all of our non-operated assets for net proceeds of $29.6 million, subject to post-closing adjustments, which were used to r epay borrowings outstanding under the Credit Facility. 
+48 
+Results of Operations 
+The following table sets forth certain operating information with respect to the Company’s oil and natural gas operations for the periods indicated: 
+Years Ended December 31, 
+2020 
+2019 (1) 
+$ Change % Change 
+Total production (2) 
+Oil (MBbls) 
+Permian 14,113 11,365 2,748 24 % 
+Eagle Ford 9,430 300 9,130 3,043 % 
+Total oil (MBbls) 23,543 11,665 11,878 102 % 
+Natural gas (MMcf) 
+Permian 32,087 19,484 12,603 65 % 
+Eagle Ford 8,714 234 8,480 3,624 % 
+Total natural gas (MMcf) 40,801 19,718 21,083 107 % 
+NGLs (MBbls) 
+Permian 5,390 93 5,297 5,696 % 
+Eagle Ford 1,460 42 1,418 3,376 % 
+Total NGLs (MBbls) 6,850 135 6,715 4,974 % 
+Total production (MBoe) 
+Permian 24,851 14,705 10,146 69 % 
+Eagle Ford 12,342 381 11,961 3,139 % 
+Total barrels of oil equivalent (MBoe) 37,193 15,086 22,107 147 % 
+Total daily production (Boe/d) 101,620 41,331 60,289 146 % 
+Oil as % of total daily production 63 % 77 % 
+Benchmark prices (3) 
+WTI (per Bbl) $39.38 $56.98 ($17.60) (31 %) 
+Henry Hub (per Mcf) 2.13 2.56 (0.43) (17 %) 
+Average realized sales price (excluding impact of settled derivatives) 
+Oil (per Bbl) 
+Permian $37.23 $54.13 ($16.90) (31 %) 
+Eagle Ford 34.49 59.57 (25.08) (42 %) 
+Total oil (per Bbl) 36.13 54.27 (18.14) (33 %) 
+Natural gas (per Mcf) 
+Permian 1.05 1.84 (0.79) (43 %) 
+Eagle Ford 2.07 2.44 (0.37) (15 %) 
+Total natural gas (per Mcf) 1.27 1.85 (0.58) (31 %) 
+NGL (per Bbl) 
+Permian 11.91 16.58 (4.67) (28 %) 
+Eagle Ford 11.71 12.69 (0.98) (8 %) 
+Total NGL (per Bbl) 11.87 15.37 (3.50) (23 %) 
+Total average realized sales price (per Boe) 
+Permian 25.09 44.38 (19.29) (43 %) 
+Eagle Ford 29.20 49.81 (20.61) (41 %) 
+Total average realized sales price (per Boe) $26.45 $44.52 ($18.07) (41 %) 
+49 
+Years Ended December 31, 
+2020 
+2019 (1) 
+$ Change % Change 
+Average realized sales price (including impact of settled derivatives) 
+Oil (per Bbl) $40.19 $53.31 ($13.12) (25 %) 
+Natural gas (per Mcf) 1.28 2.22 (0.94) (42 %) 
+NGLs (per Bbl) 11.87 15.37 (3.50) (23 %) 
+Total average realized sales price (per Boe) $29.03 $44.27 ($15.24) (34 %) 
+Revenues (in thousands) 
+Oil 
+Permian $525,412 $615,235 ($89,823) (15 %) 
+Eagle Ford 325,255 17,872 307,383 1,720 % 
+Total oil 850,667 633,107 217,560 34 % 
+Natural gas 
+Permian 33,815 35,818 (2,003) (6 %) 
+Eagle Ford 18,051 572 17,479 3,056 % 
+Total natural gas 51,866 36,390 15,476 43 % 
+NGLs 
+Permian 64,201 1,542 62,659 4,063 % 
+Eagle Ford 17,094 533 16,561 3,107 % 
+Total NGLs 81,295 2,075 79,220 3,818 % 
+Total revenues 
+Permian 623,428 652,595 (29,167) (4 %) 
+Eagle Ford 360,400 18,977 341,423 1,799 % 
+Total revenues $983,828 $671,572 $312,256 46 % 
+Additional per Boe data 
+Lease operating expense 
+Permian $4.71 $6.03 ($1.32) (22 %) 
+Eagle Ford 6.25 8.38 (2.13) (25 %) 
+Total lease operating expense $5.22 $6.09 ($0.87) (14 %) 
+Production and ad valorem taxes 
+Permian $1.59 $2.84 ($1.25) (44 %) 
+Eagle Ford 1.87 2.29 (0.42) (18 %) 
+Total production and ad valorem taxes $1.68 $2.83 ($1.15) (41 %) 
+Gathering, transportation and processing 
+Permian $2.29 $— $2.29 100 % 
+Eagle Ford 1.66 — 1.66 100 % 
+Total gathering, transportation and processing $2.08 $— $2.08 100 % 
+(1) Includes activity on properties acquired in the Carrizo Acquisition subsequent to the December 20, 2019 closing date. 
+(2) Effective January 1, 2020, certain of our natural gas processing agreements were modified to allow us to take title to NGLs resulting from the processing of our natural gas. As a result, reserve volumes for NGLs and natural gas are presented separately for periods subsequent to January 1, 2020. For periods prior to January 1, 2020, except for reserve volumes specifically associated with Carrizo, we presented our reserve volumes for NGLs with natural gas. 
+(3) Reflects calendar average daily spot market prices. 
+50 
+Revenues 
+The following table reconciles the changes in oil, natural gas, NGLs, and total revenue for the period presented by reflecting the effect of changes in volume and in the underlying commodity prices. 
+Oil Natural Gas NGLs Total 
+(In thousands) 
+Revenues for the year ended December 31, 2019 (1)(3) 
+$633,107 $36,390 $2,075 $671,572 
+Volume increase (decrease) 644,776 38,912 103,212 786,900 
+Price increase (decrease) (427,216) (23,436) (23,992) (474,644) 
+Net increase (decrease) 217,560 15,476 79,220 312,256 
+Revenues for the year ended December 31, 2020 (2)(3) 
+$850,667 $51,866 $81,295 $983,828 
+Percent of total revenues 87 % 5 % 8 % 
+(1) Includes activity on properties acquired in the Carrizo Acquisition subsequent to the December 20, 2019 closing date. 
+(2) Effective January 1, 2020, certain of our natural gas processing agreements were modified to allow us to take title to NGLs resulting from the processing of our natural gas. As a result, reserve volumes for NGLs and natural gas are presented separately for periods subsequent to January 1, 2020. For periods prior to January 1, 2020, except for reserve volumes specifically associated with Carrizo, we presented our reserve volumes for NGLs with natural gas. 
+(3) Excludes sales of oil and gas purchased from third parties and sold to our customers. 
+Commodity Prices 
+The prices for oil, natural gas, and NGLs remain extremely volatile primarily due to the underlying supply and demand concerns as a result of COVID-19 as well as the actions taken by OPEC and other countries as described above. This volatility was shown in the price of oil which ranged from a low of -$36.98 per Bbl to $63.27 per Bbl. Prices of oil, natural gas, and NGLs will affect the following aspects of our business: 
+• our revenues, cash flows and earnings; 
+• the amount of oil and natural gas that we are economically able to produce; 
+• our ability to attract capital to finance our operations and cost of the capital; 
+• the amount we are allowed to borrow under the Credit Facility; and 
+• the value of our oil and natural gas properties. 
+Period over Period Variances 
+The change in absolute value for the year ended December 31, 2020 as compared to the year ended December 31, 2019 can be primarily attributed to the Carrizo Acquisition which closed in December 2019. The Carrizo Acquisition had a material impact to our reported results of operations. In order to provide a more meaningful basis for comparison, we focused our discussion on per unit metrics and only expanded on changes in absolute value where appropriate. 
+Oil revenue 
+For the year ended December 31, 2020, oil revenues of $850.7 million increased $217.6 million, or 34%, compared to revenues of $633.1 million for the year ended December 31, 2019. The increase in oil revenue was primarily attributable to a 102% increase in production, partially offset by a 33% decrease in the average realized sales price, which declined to $36.13 per Bbl from $54.27 per Bbl. The increase in production was comprised of 9.5 MMBbls attributable to wells that were acquired in the Carrizo Acquisition and 5.7 MMBbls attributable to wells placed on production as a result of our horizontal drilling program, partially offset by normal and expected declines from our existing wells. 
+Natural gas revenue 
+Natural gas revenues increased $15.5 million, or 43%, during the year ended December 31, 2020 to $51.9 million as compared to $36.4 million for the year ended December 31, 2019. The increase primarily relates to an approximate 107% increase in natural gas volumes, partially offset by a 31% decrease in the average price realized, which declined to $1.27 per Mcf from $1.85 per Mcf. The increase in production was comprised of 23.8 Bcf attributable to wells that were acquired in the Carrizo Acquisition and 6.8 Bcf attributable to wells placed on production as a result of our horizontal drilling program, partially offset by normal and expected declines from our existing wells. 
+51 
+NGL revenue 
+NGL revenues increased $79.2 million during the year ended December 31, 2020 to $81.3 million. The increase was due to certain of our natural gas processing agreements being modified effective January 1, 2020, to allow us to take title to NGLs resulting from the processing of our natural gas. As a result, sales volumes, prices, and revenues for NGLs and natural gas are presented separately for periods subsequent to January 1, 2020. For periods prior to January 1, 2020, except for sales volumes, prices, and revenues specifically associated with Carrizo, sales and reserve volumes, prices, and revenues for NGLs were presented with natural gas. 
+Operating Expenses 
+Years Ended December 31, 
+Per Per Total Change Boe Change 
+2020 Boe 2019 Boe $ % $ % 
+(In thousands, except per Boe and % amounts) 
+Lease operating expenses $194,101 $5.22 $91,827 $6.09 $102,274 111 % ($0.87) (14 %) 
+Production and ad valorem taxes 62,638 1.68 42,651 2.83 19,987 47 % (1.15) (41 %) 
+Gathering, transportation and processing 77,309 2.08 — — 77,309 100 % 2.08 100 % 
+Depreciation, depletion and amortization 480,631 12.92 240,642 15.95 239,989 100 % (3.03) (19 %) 
+General and administrative 37,187 1.00 45,331 3.00 (8,144) (18 %) (2.00) (67 %) 
+Impairment of evaluated oil and gas properties 2,547,241 68.48 — — 2,547,241 100 % 68.48 100 % 
+Merger and integration expenses 28,482 0.77 74,363 4.93 (45,881) (62 %) (4.16) (84 %) 
+Lease operating expenses. These are daily costs incurred to extract oil and natural gas and maintain our producing properties. Such costs also include maintenance, repairs, gas treating fees, salt water disposal, insurance and workover expenses related to our oil and natural gas properties. 
+Lease operating expenses for the year ended December 31, 2020 increased by 111% to $194.1 million compared to $91.8 million for the same period of 2019, primarily due to production volumes increasing 147%. Lease operating expense per Boe for the year ended December 31, 2020 decreased to $5.22 compared to $6.09 for the same period of 2019 primarily due to continuing improvement of managing our field operating costs during the integration of the properties acquired from Carrizo as well as lower repairs and maintenance activities and workover expenses. 
+Production and valorem taxes. In general, severance taxes are based upon current year commodity prices whereas ad valorem taxes are based upon prior year commodity prices. Severance taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. We benefit from tax credits and exemptions in our various taxing jurisdictions where available and applicable. In the counties where our production is located, we are also subject to ad valorem taxes, which are generally based on the taxing jurisdictions’ valuation of our oil and gas properties. 
+For the year ended December 31, 2020, production and ad valorem taxes increased 47% to $62.6 million compared to $42.7 million for the same period in 2019, which is primarily related to a 46% increase in total revenues which increased production taxes and the inclusion of the properties from the Carrizo Acquisition in the property valuations for ad valorem taxes. Production and ad valorem taxes as a percentage of total revenues remained consistent for the year ended December 31, 2020 as compared to the year ended December 31, 2019 at 6.4%. Although production taxes as a percentage of total revenues decreased from the year ended December 31, 2019 due to the contribution of the Carrizo Acquisition assets which carried lower effective production tax rates as a result of the impacts of natural gas and NGL marketing deductions and exemptions, this was offset by an increase in ad valorem tax as a percentage of revenue during the year ended December 31, 2020 due to the timing of the property tax valuations compared to the significant decrease in the price of crude oil affecting our revenues during 2020. 
+Gathering, transportation and processing expenses. Gathering, transportation and processing costs for the year ended December 31, 2020 were $77.3 million. No expense was recognized for gathering, transportation and processing costs during the same period of 2019. The change is due to the assumption of the processing agreements assumed in the Carrizo Acquisition and certain contract modifications effective January 1, 2020. As such, the Company now records contractual fees associated with gathering, processing, treating and compression, as well as any transportation fees incurred to deliver the product to the purchaser, as gathering, transportation and processing expense. These fees were historically recorded as a reduction of revenue depending on when control transferred to the purchaser. 
+52 
+Depreciation, depletion and amortization (“DD&A”). Under the full cost accounting method, we capitalize costs within a cost center and then systematically amortize those costs on an equivalent unit-of-production method based on production and estimated proved oil and gas reserve quantities. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from two to twenty years. The following table sets forth the components of our depreciation, depletion and amortization for the periods indicated: 
+Years Ended December 31, 
+2020 2019 
+Amount Per Boe Amount Per Boe 
+(In thousands, except per Boe) 
+DD&A of evaluated oil and gas properties $471,074 $12.66 $239,679 $15.89 
+Depreciation of other property and equipment 3,548 0.10 18 — 
+Amortization of other assets 2,686 0.07 — — 
+Accretion of asset retirement obligations 3,323 0.09 945 0.06 
+DD&A $480,631 $12.92 $240,642 $15.95 
+For the year ended December 31, 2020, DD&A increased 100% to $480.6 million from $240.6 million compared to the same period of 2019. The additional DD&A was primarily related to an increase in DD&A of evaluated oil and gas properties, which was primarily attributable to a 147% increase in production, as discussed above, partially offset by lower DD&A rates between the periods. For the year ended December 31, 2020, DD&A per Boe decreased to $12.92 compared to $15.95 for the same period of 2019 primarily as a result of the impairments of evaluated oil and gas properties that were recognized during 2020 as well as the Carrizo Acquisition which contributed to an increase in our proved reserves at a lower relative cost per Boe than our historical DD&A rate. 
+General and administrative, net of amounts capitalized (“G&A”). G&A for the year ended December 31, 2020 decreased to $37.2 million compared to $45.3 million for the same period of 2019, primarily due to cost saving initiatives and a decrease in the fair value of the cash-settled restricted stock units and cash-settled stock appreciation rights partially offset by increased headcount of the combined companies. 
+Impairment of evaluated oil and gas properties. We recognized an impairment of evaluated oil and gas properties of $2.5 billion for the year ended December 31, 2020, due primarily to declines in the 12-Month Average Realized Price of crude oil of 31%. There was no impairment of evaluated oil and gas properties for the year ended December 31, 2019. See “Note 5 - Property and Equipment, Net” of the Notes to our Consolidated Financial Statements for further discussion. 
+Merger and integration expense. For the year ended December 31, 2020, the Company incurred expenses associated with the Carrizo Acquisition of $28.5 million as compared to $74.4 million for the same period of 2019. See “Note 4 – Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for additional information regarding the Carrizo Acquisition. 
+Other Income and Expenses 
+Years Ended December 31, 
+2020 2019 $ Change % Change 
+(In thousands, except % amounts) 
+Interest expense $182,928 $81,399 $101,529 125 % 
+Capitalized interest (88,599) (78,492) (10,107) 13 % 
+Interest expense, net of capitalized amounts 94,329 2,907 91,422 3,145 % 
+(Gain) loss on derivative contracts 27,773 62,109 (34,336) (55 %) 
+(Gain) loss on extinguishment of debt (170,370) 4,881 (175,251) (3,590 %) 
+Interest expense, net of capitalized amounts. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under our Credit Facility or with term debt. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to our lender in interest expense, net of capitalized amounts. In addition, we include the amortization of deferred financing costs (including origination and amendment fees), 
+53 
+commitment fees and annual agency fees in interest expense. The following table sets forth the components of our interest expense, net of capitalized amounts for the periods indicated: 
+Years Ended December 31, 
+2020 2019 Change 
+(In thousands) 
+Interest expense on Credit Facility $45,912 $14,422 $31,490 
+Interest expense on Second Lien Notes 9,188 — 9,188 
+Interest expense on Senior Notes 120,313 64,061 56,252 
+Amortization of debt issuance costs, premiums, and discounts 7,325 2,902 4,423 
+Other interest expense 190 14 176 
+Capitalized interest (88,599) (78,492) (10,107) 
+Interest expense, net of capitalized amounts $94,329 $2,907 $91,422 
+Interest expense, net of capitalized amounts, incurred during the year ended December 31, 2020 increased $91.4 million to $94.3 million compared to $2.9 million for the same period of 2019. The increase is primarily due to debt that was assumed as a result of the Carrizo Acquisition and the issuance of the Second Lien Notes during 2020 partially offset by an increase in capitalized interest as a result of an increase in the balance of unevaluated properties as a result of the Carrizo Acquisition. 
+(Gain) loss on derivative contracts. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in commodity prices. This amount represents the (i) (gain) loss related to fair value adjustments on our open derivative contracts and (ii) (gains) losses on settlements of derivative contracts for positions that have settled within the period. The net (gain) loss on derivative contracts for the periods indicated includes the following: 
+Years Ended December 31, 
+2020 2019 Change 
+(In thousands) 
+(Gain) loss on oil derivatives ($48,031) $73,313 ($121,344) 
+(Gain) loss on natural gas derivatives 14,883 (8,889) 23,772 
+(Gain) loss on NGL derivatives 2,426 — 2,426 
+(Gain) loss on contingent consideration arrangements 2,976 (2,315) 5,291 
+(Gain) loss on September 2020 Warrants liability 55,519 — 55,519 
+(Gain) loss on derivative contracts $27,773 $62,109 ($34,336) 
+See “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” of the Notes to our Consolidated Financial Statements for additional information. 
+(Gain) loss on extinguishment of debt. During November 2020, in connection with the exchange of $389.0 million of our Senior Unsecured Notes for the November 2020 Second Lien Notes, we recorded a gain on extinguishment of debt of $170.4 million, which consisted of the carrying values of the Senior Unsecured Notes exchanged less the aggregate principal amount of the November 2020 Second Lien Notes issued, net of the associated debt discount of $9.1 million, which was based on the November 2020 Second Lien Notes’ allocated fair value on the exchange date. During December 2019, in connection with the Carrizo Acquisition, we entered into a new credit facility and simultaneously terminated our prior credit facility. As a result of terminating the prior credit facility, we recorded a loss on extinguishment of debt of $4.9 million, which was comprised solely of the write-off of unamortized deferred financing costs associated with the prior credit facility. See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information. 
+Sales and cost of purchased oil and gas. For the year ended December 31, 2020, we recorded sales of purchased oil and gas of $49.3 million and cost of purchased oil and gas of $51.8 million related to commodities purchased from third parties and sold to our customers. No sales or cost of purchased oil and gas occurred during the same periods of 2019. 
+Income tax expense. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. When appropriate, based on our analysis, we record a valuation allowance for deferred tax assets when it is more likely than not that the deferred tax assets will not be realized. 
+We recorded income tax expense of $122.1 million for the year ended December 31, 2020 compared to $35.3 million for the same period of 2019. The increase in income tax expense is due to the recording of a valuation allowance during the year ended 
+54 
+December 31, 2020. See “Note 12 – Income Taxes” of the Notes to our Consolidated Financial Statements for additional information regarding the valuation allowance. 
+Preferred stock dividends. On July 18, 2019, we redeemed all outstanding shares of Preferred Stock, after which, the Preferred Stock was no longer deemed outstanding and dividends ceased to accrue. As such, we did not make any Preferred Stock dividend payments during the year ended December 31, 2020. Preferred Stock dividends of $4.0 million were paid during the year ended December, 31, 2019. See “Note 11 – Stockholders’ Equity” of the Notes to our Consolidated Financial Statements for additional information. 
+Loss on redemption of preferred stock. As a result of the redemption of our Preferred Stock mentioned above, we recognized an $8.3 million loss due to the excess of the $73.0 million redemption price over the $64.7 million redemption date carrying value during 2019. See “Note 11 – Stockholders’ Equity” of the Notes to our Consolidated Financial Statements for additional information. 
+Liquidity and Capital Resources 
+2021 Capital Budget and Funding Strategy. Our primary uses of capital are for the exploration and development of our oil and natural gas properties. Our 2021 Capital Budget has been established at up to $430.0 million, with approximately 80% directed towards drilling, completion, and equipment expenditures. Our scaled development plan for 2021 will continue to employ our life of field development philosophy and benefit from our balanced capital deployment strategy. The 2021 Capital Budget leverages the structural savings and operational efficiencies achieved during 2020 from shared best practices following the integration of Callon and Carrizo. Approximately 70% of the 2021 Capital Budget is allocated towards development in the Permian with the remaining 30% towards development in the Eagle Ford. As part of our 2021 operated horizontal drilling program, we expect to drill approximately 55 to 65 gross operated wells and complete approximately 90 to 100 gross operated wells. 
+Because we are the operator of a high percentage of our properties, we can control the amount and timing of our capital expenditures. We can choose to defer or accelerate a portion of our planned capital expenditures depending on various factors, including, but not limited to, continued depressed commodity prices, market conditions, our available liquidity and financing, acquisitions and divestitures of oil and gas properties, the availability of drilling rigs and completion crews, the cost of completion services, success of drilling programs, land and industry partner issues, weather delays, the acquisition of leases with drilling commitments, and other factors. We plan to execute a more moderated capital expenditure program through reduced reinvestment rates and balanced capital deployment for a more consistent cash flow generation and will be focused to further enhance our multi-zone, scale development program while leveraging a robust drilled, but uncompleted backlog to drive capital efficiency. 
+The following table is a summary of our 2020 capital expenditures (1) : 
+Three Months Ended Year Ended 
+March 31, 2020 June 30, 2020 September 30, 2020 December 31, 2020 December 31, 2020 
+(In millions) 
+Operational capital $277.6 $85.1 $38.4 $87.5 $488.6 
+Capitalized interest 24.0 20.9 20.7 23.0 88.6 
+Capitalized G&A 7.4 8.9 10.2 8.9 35.4 
+Total $309.0 $114.9 $69.3 $119.4 $612.6 
+(1) Capital expenditures, presented on an accrual basis, includes facilities, equipment, seismic, and land, but excludes asset retirement costs. 
+We continually evaluate our capital expenditure needs and compare them to our capital resources. Due to the decline in crude oil prices and ongoing uncertainty regarding the oil supply-demand macro environment, we reduced our development plan in order to preserve capital, including the temporary cessation of all drilling and completion activities for most of the second and third quarters of 2020. We reactivated two completion crews, one each in the Eagle Ford and Permian, both of which completed previously drilled multi-well projects during September. Subsequently, one of the two completion crews was released and three drilling rigs resumed operations, two restarting operations in the Permian during September and the third reactivated in the Eagle Ford during October. This reduction in activity resulted in our actual 2020 operational capital expenditures to be approximately 50% of our original operational capital budget for 2020 of $975.0 million. 
+Historically, our primary sources of capital have been cash flows from operations, borrowings under our revolving credit facility, proceeds from the issuance of debt securities and public equity offerings, and non-core asset dispositions. We regularly consider which resources, including debt and equity financings, are available to meet our future financial obligations, planned capital expenditures and liquidity requirements. In addition, depending upon our actual and anticipated sources and uses of liquidity, prevailing market conditions and other factors, we may, from time to time, seek to retire or repurchase our outstanding debt or equity securities through cash purchases in the open market or through privately negotiated transactions or otherwise. The amounts involved in any such transactions, individually or in aggregate, may be material. During 2020, to help manage our future financing cash outflows and liquidity position, we completed the exchange of $389.0 million of aggregate principal amount of our existing Senior Unsecured Notes 
+55 
+for $216.7 million aggregate principal amount of November 2020 Second Lien Notes and 1.75 million November 2020 Warrants. This exchange resulted in the removal of approximately $172.3 million from the long-term debt balance in our consolidated balance sheets and also reduced future interest payments. 
+We may consider divesting certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth or enter into joint venture agreements, provided we are able to divest such assets or enter into joint venture agreements on terms that are acceptable to us. During 2020, we entered into the ORRI Transaction and sold substantially all of our non-operated assets for combined net proceeds of $165.4 million, which were used to repay borrowings outstanding under the Credit Facility. 
+Overview of Cash Flow Activities. For the year ended December 31, 2020, cash and cash equivalents increased $6.9 million to $20.2 million compared to $13.3 million at December 31, 2019. 
+Years Ended December 31, 
+2020 
+2019 (1) 
+(In thousands) 
+Net cash provided by operating activities $559,775 $476,316 
+Net cash used in investing activities (529,883) (388,389) 
+Net cash used in financing activities (22,997) (90,637) 
+Net change in cash and cash equivalents $6,895 ($2,710) 
+(1) Includes activity on properties acquired in the Carrizo Acquisition subsequent to the December 20, 2019 closing date. 
+Operating activities. Net cash provided by operating activities was $559.8 million and $476.3 million for the years ended December 31, 2020 and 2019, respectively. The increase in operating activities was predominantly attributable to the following: 
+• An increase in revenue due to higher production volumes, offset by a decrease in realized pricing; 
+• A decrease in merger and integration expenses; 
+• An offsetting increase in operating expenses as a result of higher production volumes; and 
+• Changes related to timing of working capital payments and receipts. 
+Production, realized prices, and operating expenses are discussed above in Results of Operations. See “Note 8 – Derivative Instruments and Hedging Activities” and “Note 9 – Fair Value Measurements” of the Notes to our Consolidated Financial Statements for a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation. 
+Investing activities. Net cash used in investing activities was $529.9 million and $388.4 million for the years ended December 31, 2020 and 2019, respectively. The increase in investing activities was primarily attributable to the following: 
+• A decrease in proceeds from sales of assets to $179.5 million during the year ended December 31, 2020, which were primarily associated with the ORRI Transaction and the sale of substantially all of our non-operated assets, compared to proceeds from sales of assets of $294.4 million for the year ended December 31, 2019; 
+• Partially offset by a $42.3 million decrease in acquisitions; and 
+• Net cash payments of $40.0 million associated with contingent considerations arrangements acquired in the Carrizo Acquisition that were paid in January 2020. 
+Financing activities. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under the Credit Facility, term debt and equity offerings. For the year ended December 31, 2020, net cash used in financing activities was $23.0 million compared to net cash used in financing activities of $90.6 million during 2019. The decrease in net cash used in financing activities was primarily attributable to the following: 
+• Issuance of the September 2020 Second Lien Notes and September 2020 Warrants for net proceeds of approximately $288.6 million; 
+• Repayment of approximately $300.0 million on the Credit Facility during 2020; 
+• Repayment of Carrizo’s credit facility and funding the redemption of preferred stock upon closing the Carrizo Acquisition in 2019; and 
+• Redemption of Preferred Stock for approximately $73.0 million in 2019. 
+See “Note 7 – Borrowings”, “Note 10 – Share-Based Compensation”, and “Note 11 – Stockholders’ Equity” of the Notes to our Consolidated Financial Statements for additional information regarding our debt and equity transactions. 
+Credit Facility. On December 20, 2019, upon consummation of the Merger, we entered into the Credit Facility which provides for interest-only payments until December 20, 2024 (subject to springing maturity dates of (i) January 14, 2023 if the 6.25% Senior Notes are outstanding at such time, (ii) July 2, 2024 if the 6.125% Senior Notes are outstanding at such time, and (iii) if the Second Lien 
+56 
+Notes are outstanding at such time, the date which is 182 days prior to the maturity of any of the 6.25% Senior Notes or the 6.125% Senior Notes, in each case, to the extent a principal amount of more than $100.0 million with respect to each such issuance is outstanding as of such date), when the Credit Facility matures and any outstanding borrowings are due. The maximum credit amount under the Credit Facility is $5.0 billion. The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The Credit Facility is secured by first preferred mortgages covering our major producing properties. As of December 31, 2020, the borrowing base and elected commitment amount under the revolving credit facility was $1.6 billion, with borrowings outstanding of $985.0 million at a weighted average interest rate of 2.73%, and letters of credit outstanding of $25.2 million. 
+Our Credit Facility contains certain covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. Under the Credit Facility, we must maintain the following financial covenants determined as of the last day of the quarter, each as described above: (1) a Secured Leverage Ratio of no more than 3.00 to 1.00 and (2) a Current Ratio of not less than 1.00 to 1.00. We were in compliance with these covenants at December 31, 2020. 
+The Credit Facility also places restrictions on us and certain of our subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of our common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters. 
+See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information including details of the first, second, and third amendments to the Credit Facility. 
+Second Lien Notes. On September 30, 2020, we issued $300.0 million in aggregate principal amount of our September 2020 Second Lien Notes and 7.3 million September 2020 Warrants for aggregate consideration of $294.0 million. The Company used the proceeds, net of issuance costs, of approximately $288.6 million to repay borrowings outstanding under the Credit Facility. See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information. 
+Senior Unsecured Notes Exchange. On November 13, 2020, we closed on the exchange of $389.0 million of aggregate principal amount of the Senior Unsecured Notes for $216.7 million aggregate principal amount of November 2020 Second Lien Notes at a weighted average exchange ratio of approximately $557 per $1,000 of principal exchanged and approximately 1.75 million November 2020 Warrants. As a result of the exchange, we recognized a gain on extinguishment of debt of $170.4 million in our consolidated statement of operations, which consisted of the carrying values of the Senior Unsecured Notes exchanged less the aggregate principal amount of the November 2020 Second Lien Notes issued, net of the associated debt discount of $9.1 million, which was based on the November 2020 Second Lien Notes’ allocated fair value on the exchange date. See “Note 7 - Borrowings” of the Notes to our Consolidated Financial Statements for additional information about the exchange. 
+Even considering the downturn in commodity prices as well as a drop in demand as a result of COVID-19, we expect to have sufficient liquidity to pay interest on our Credit Facility, Second Lien Notes, and Senior Unsecured Notes as well as to fund our development program. Upon a redetermination, if any borrowings in excess of the revised borrowing base were outstanding, we could be forced to immediately repay a portion of the borrowings outstanding under the credit agreement. Additionally, if a low commodity price environment were to persist for an extended period, our ability to remain in compliance with our restrictive financial covenants in our Credit Facility and our indentures could be challenged. If we are unable to remain in compliance with our restrictive financial covenants, we could be subject to lender elections for default resolution. 
+57 
+Hedging. As of February 19, 2021, we had the following outstanding oil, natural gas and NGL derivative contracts: 
+For the Full Year of For the Full Year of 
+Oil contracts (WTI) 2021 2022 
+Swap contracts 
+Total volume (Bbls) 1,827,000 — 
+Weighted average price per Bbl $43.54 $— 
+Collar contracts 
+Total volume (Bbls) 11,202,775 1,355,000 
+Weighted average price per Bbl 
+Ceiling (short call) $47.80 $60.00 
+Floor (long put) $39.95 $45.00 
+Short call contracts 
+Total volume (Bbls) 4,825,300 (1) — 
+Weighted average price per Bbl $63.62 $— 
+Short call swaption contracts 
+Total volume (Bbls) 455,000 (2) 1,825,000 (2) 
+Weighted average price per Bbl $47.00 $52.18 
+Oil contracts (ICE Brent) 
+Swap contracts 
+Total volume (Bbls) 505,000 (3) — 
+Weighted average price per Bbl $37.34 $— 
+Collar contracts 
+Total volume (Bbls) 730,000 — 
+Weighted average price per Bbl 
+Ceiling (short call) $50.00 $— 
+Floor (long put) $45.00 $— 
+Oil contracts (Midland basis differential) 
+Swap contracts 
+Total volume (Bbls) 3,022,900 — 
+Weighted average price per Bbl $0.26 $— 
+Oil contracts (Argus Houston MEH) 
+Swap contracts 
+Total volume (Bbls) 450,000 — 
+Weighted average price per Bbl $46.50 $— 
+Collar contracts 
+Total volume (Bbls) 409,500 — 
+Weighted average price per Bbl 
+Ceiling (short call) $47.00 $— 
+Floor (long put) $41.00 $— 
+(1) Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars. 
+(2) The short call swaption contracts have exercise expiration dates as follows: 455,000 Bbls expire on March 31, 2021 and 1,825,000 Bbls expire on December 31, 2021. 
+(3) In January 2021, we paid approximately $3.1 million to terminate 184,000 Bbls of ICE Brent swaps. Additionally, in February 2021, we executed offsetting ICE Brent swaps on 159,300 Bbls, resulting in a locked-in loss of approximately $2.9 million which we will pay as the applicable contracts settle. 
+58 
+For the Full Year of For the Full Year of 
+Natural gas contracts (Henry Hub) 2021 2022 
+Swap contracts 
+Total volume (MMBtu) 11,123,000 — 
+Weighted average price per MMBtu $2.60 $— 
+Collar contracts (three-way collars) 
+Total volume (MMBtu) 1,350,000 — 
+Weighted average price per MMBtu 
+Ceiling (short call) $2.70 $— 
+Floor (long put) $2.42 $— 
+Floor (short put) $2.00 $— 
+Collar contracts (two-way collars) 
+Total volume (MMBtu) 9,550,000 1,800,000 
+Weighted average price per MMBtu 
+Ceiling (short call) $3.04 $3.88 
+Floor (long put) $2.59 $2.78 
+Short call contracts 
+Total volume (MMBtu) 7,300,000 (1) — 
+Weighted average price per MMBtu $3.09 $— 
+Natural gas contracts (Waha basis differential) 
+Swap contracts 
+Total volume (MMBtu) 16,425,000 — 
+Weighted average price per MMBtu ($0.42) $— 
+(1) Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars. 
+For the Full Year of 
+NGL contracts (OPIS Mont Belvieu Purity Ethane) 2021 
+Swap contracts 
+Total volume (Bbls) 1,825,000 
+Weighted average price per Bbl $7.62 
+Preferred Stock. On June 18, 2019, we announced we had given notice for the redemption (the “Redemption”) of all outstanding shares of the Preferred Stock. On July 18, 2019 (the “Redemption Date”), the Preferred Stock were redeemed at a redemption price equal to $50.00 per share, plus an amount equal to all accrued and unpaid dividends in an amount equal to $0.24 per share, for a total redemption price of $50.24 per share or $73.0 million (the “Redemption Price”). We recognized an $8.3 million loss on the redemption due to the excess of the $73.0 million redemption price over the $64.7 million redemption date carrying value of the Preferred Stock. After the Redemption Date, the Preferred Stock were no longer deemed outstanding, dividends on the Preferred Stock ceased to accrue, and all rights of the holders with respect to such Preferred Stock were terminated, except the right of the holders to receive the Redemption Price, without interest. We paid $4.0 million for Preferred Stock dividends for the year ended December 31, 2019. See “Note 11 - Stockholders’ Equity” of the Notes to our Consolidated Financial Statements for additional discussion. 
+59 
+Contractual Obligations 
+The following table includes our current contractual obligations and purchase commitments as of December 31, 2020: 
+Payments due by Period 
+< 1 Year Years 2 - 3 Years 4 - 5 > 5 Years Total 
+(In thousands) 
+Credit Facility (1) 
+$— $— $985,000 $— $985,000 
+9.00% Second Lien Senior Secured Notes (2) 
+— — 516,659 — 516,659 
+6.25% Senior Notes (2) 
+— 542,720 — — 542,720 
+6.125% Senior Notes (2) 
+— — 460,241 — 460,241 
+8.25% Senior Notes (2) 
+— — 187,238 — 187,238 
+6.375% Senior Notes (2) 
+— — — 320,783 320,783 
+Interest expense and other fees related to debt commitments (3) 
+174,387 331,815 198,714 20,450 725,366 
+Drilling rig leases (4) 
+4,317 — — — 4,317 
+Operating leases (5) 
+10,601 10,454 8,894 14,139 44,088 
+Delivery commitments (6) 
+12,401 22,533 24,868 39,291 99,093 
+Produced water disposal commitments (7) 
+21,355 29,095 12,242 741 63,433 
+Asset retirement obligations (8) 
+1,881 587 6,827 49,795 59,090 
+Total contractual obligations $224,942 $937,204 $2,400,683 $445,199 $4,008,028 
+(1) The Credit Facility has a maturity date of December 20, 2024, subject to springing maturity dates as discussed above. See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information. 
+(2) Includes the outstanding principal amount only. 
+(3) Includes estimated cash payments on the 9.00% Second Lien Senior Secured Notes, 6.25% Senior Notes, 6.125% Senior Notes, 8.25% Senior Notes, 6.375% Senior Notes, the Credit Facility and commitment fees calculated based on the unused portion of lender commitments as of December 31, 2020, at the applicable commitment fee rate. 
+(4) Drilling rig leases represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a party on December 31, 2020. The value in the table represents the gross amount that we are committed to pay. However, we will record our proportionate share based on our working interest in our consolidated financial statements as incurred. In January 2021, we extended one of our drilling rig contracts for a term of one year. The gross contractual obligation for this extended drilling rig contract is approximately $5.5 million and is not included in the table above as it was entered into subsequent to December 31, 2020. See “Note 17 – Commitments and Contingencies” of the Notes to our Consolidated Financial Statements for additional information related to our drilling rig leases. 
+(5) Operating leases primarily consist of contracts for office space. See “Note 13 – Leases” of the Notes to our Consolidated Financial Statements for additional information. 
+(6) Delivery commitments represent contractual obligations we have entered into for certain gathering, processing and transportation service agreements which require minimum volumes of oil or natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any oil or natural gas. 
+(7) Produced water disposal commitments represent contractual obligations we have entered into for certain service agreements which require minimum volumes of produced water to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water. 
+(8) Amounts represent our estimates of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See “Note 14 – Asset Retirement Obligations” of the Notes to our Consolidated Financial Statements for additional information. 
+60 
+Other commitments 
+The following table includes our current oil sales contracts and firm transportation agreements as of December 31, 2020: 
+Type of Commitment (1) 
+Region Execution Date Start Date End Date Committed 
+Volumes (Bbls/d) 
+Oil sales contract Eagle Ford November 2020 January 2021 December 2021 10,000 
+Oil sales contract Permian August 2020 August 2020 December 2021 7,500 
+Oil sales contract Permian July 2019 August 2021 July 2026 5,000 
+Oil sales contract Permian June 2019 January 2020 December 2024 10,000 
+Oil sales contract Permian August 2018 April 2020 March 2022 15,000 
+Firm transportation agreement (2)(3) 
+Permian June 2019 August 2020 July 2030 10,000 
+Firm transportation agreement (2) 
+Permian August 2018 April 2020 March 2027 15,000 
+(1) For each of the commitments shown in the table above, the committed barrels may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. We expect to fulfill these delivery commitments with our existing production or through the purchases of third-party commodities. 
+(2) Each of the firm transportation agreements shown in the table above grant us access to delivery points in several locations along the Gulf Coast. 
+(3) The committed volumes shown in the table above for this particular firm transportation agreement are average volumes. For the terms of August 2020-July 2023, August 2023-July 2027 and August 2027-July 2030, the committed volumes are 7,500 Bbls/d, 10,000 Bbls/d and 12,500 Bbls/d, respectively. 
+Summary of Critical Accounting Policies 
+The following summarizes our critical accounting policies. See a complete list of significant accounting policies in “Note 2 – Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements. 
+Use of estimates 
+The preparation of financial statements in conformity with GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating DD&A of evaluated oil and natural gas property costs, the present value of estimated future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated timing of cash outflows underlying asset retirement obligations. There are numerous uncertainties inherent in the estimation of proved oil and gas reserves and in the projection of future rates of production and the timing of development expenditures. Other significant estimates are involved in determining asset retirement obligations, acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of commodity derivative assets and liabilities, fair values of contingent consideration arrangements, grant date fair value of stock-based awards, and contingency, litigation, and environmental liabilities. Actual results could differ from those estimates. 
+Oil and natural gas properties 
+Oil and natural gas properties are accounted for using the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration and development activities are capitalized as oil and gas properties. The internal cost of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities are capitalized to either evaluated or unevaluated oil and gas properties based on the type of activity. Internal costs related to production and similar activities are expensed as incurred. 
+Proceeds from the sale or disposition of evaluated and unevaluated oil and gas properties are accounted for as a reduction of evaluated oil and gas property costs, unless the sale significantly alters the relationship between capitalized costs and estimated proved reserves in which case a gain or loss is recognized. For the years ended December 31, 2020, 2019, and 2018, we did not have any sales of oil and gas properties that significantly altered such relationship. 
+Capitalized oil and gas property costs are amortized on an equivalent unit-of-production method, converting natural gas to barrels of oil equivalent at the ratio of six thousand cubic feet of gas to one barrel of oil, which represents their approximate relative energy content. The equivalent unit-of-production depletion rate is computed on a quarterly basis by dividing current quarter production by estimated proved oil and gas reserves at the beginning of the quarter then applying such depletion rate to evaluated oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values. 
+61 
+Excluded from this amortization are costs associated with unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties or we determine that these costs have been impaired. We assess properties on an individual basis or as a group and consider the following factors, among others, to determine if these costs have been impaired: exploration program and intent to drill, remaining lease term, and the assignment of proved reserves. As a result of the downturn in the oil and gas industry as well as in the broader macroeconomic environment in 2020, we analyzed our unevaluated leasehold giving consideration to our updated exploration program as well as to the remaining lease term of certain unevaluated leaseholds. As a result, we impaired $229.6 million unevaluated leasehold costs and transferred these costs to evaluated properties during the year ended December 31, 2020. 
+Geological and geophysical costs not associated with specific prospects are recorded to evaluated oil and gas property costs as incurred. The amount of interest costs capitalized is determined on a quarterly basis based on the average balance of unevaluated properties and the weighted average interest rate of outstanding borrowings. Capitalized interest cannot exceed gross interest expense. 
+At the end of each quarter, the net book value of oil and gas properties, less related deferred income taxes, are limited to the “cost center ceiling” equal to (i) the sum of (a) the present value of estimated future net revenues from estimated proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the estimated proved reserves computed using a discount factor of 10%, (b) the costs of unevaluated properties not being amortized, and (c) the lower of cost or estimated fair value of unevaluated properties included in the costs being amortized; less (ii) related income tax effects. Any excess of the net book value of oil and gas properties, less related deferred income taxes, over the cost center ceiling is recognized as an impairment of evaluated oil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even if higher commodity prices in the future result in a cost center ceiling in excess of the net book value of oil and gas properties, less related deferred income taxes. 
+The estimated future net revenues used in the cost center ceiling are calculated using the average realized prices for sales of oil, NGLs, and natural gas on the first calendar day of each month during the 12-month period prior to the end of the quarter (the “12-Month Average Realized Price”), held flat for the life of the production, except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of commodity derivative instruments as we elected not to meet the criteria to qualify for hedge accounting treatment. 
+Primarily as a result of the significant reduction in the 12-Month Average Realized Price of oil, we recognized impairments of evaluated oil and gas properties of $2.5 billion for the year December 31, 2020. We did not recognize impairments of evaluated oil and gas properties for the years ended December 31, 2019 and 2018. Details of the 12-Month Average Realized Price of crude oil for the years ended December 31, 2020, 2019, and 2018 are summarized in the table below: 
+Years Ended December 31, 
+2020 2019 2018 
+Impairment of evaluated oil and natural gas properties (In thousands) $2,547,241 $— $— 
+Beginning of period 12-Month Average Realized Price ($/Bbl) $53.90 $58.40 $49.48 
+End of period 12-Month Average Realized Price ($/Bbl) $37.44 $53.90 $58.40 
+Percent increase (decrease) in 12-Month Average Realized Price (31 %) (8 %) 18 % 
+The decrease in the 12-Month Average Realized Price as of December 31, 2020 reduced our proved oil and gas reserve volumes by approximately 26.2 MMBoe. This reduction was primarily attributable to proved developed reserves of producing wells and proved undeveloped reserves with shorter economic lives. Volumes associated with locations of proved undeveloped reserves that were no longer economic and removed from proved reserves as a result of the decrease in the 12-Month Average Realized Price as of December 31, 2020 were less than 1.0 MMBoe. 
+Our current forecast for the first quarter of 2021 includes the following: 
+• Estimated 12-Month Average Realized Price based on the first calendar day of each month oil and gas prices available for the 11 months ended February 1, 2021 and an estimate for the twelfth month based on a quoted forward price; 
+• Estimated range of the first quarter of 2021 cost center ceiling, at the high end, that would exceed the net book value of oil and gas properties, resulting in no impairment in the carrying value of evaluated oil and gas properties, and at the low end, would result in an impairment in the carrying value of evaluated oil and gas properties of $100.0 million; 
+• No proved undeveloped reserves that would no longer be economic and would be removed from proved reserves as of March 31, 2021; and 
+• Assumes that all other inputs and assumptions are as of December 31, 2020, other than the price of crude oil, natural gas, and NGLs, and remain unchanged. 
+Drilling and completion activity, acquisitions or dispositions of oil and gas properties, production, and changes in development and operating costs occurring subsequent to December 31, 2020 may require revisions to estimates of proved reserves, which would impact the calculation of the cost center ceiling described above. Further impairments in subsequent quarters may occur if the trailing 
+62 
+12-month commodity prices continue to be lower than the comparable trailing 12-month commodity prices applicable to 2020. Based on the current outlook for future commodity prices, we do not believe that those prices, if realized, would have a significant adverse impact on our proved oil and gas reserves volumes. 
+In addition, the process of estimating proved oil and gas reserves requires that the Company’s independent and internal reserve engineers exercise judgment based on available geological, geophysical and technical information. We have described the risks associated with reserve estimation and the volatility of oil and natural gas prices under Part I, “Item 1A. Risk Factors.” 
+The table below presents various pricing scenarios to demonstrate the sensitivity of our December 31, 2020 cost center ceiling to changes in 12-month average benchmark crude oil and natural gas prices underlying the 12-Month Average Realized Prices. The sensitivity analysis is as of December 31, 2020 and, accordingly, does not consider drilling and completion activity, acquisitions or dispositions of oil and gas properties, production, changes in crude oil and natural gas prices, and changes in development and operating costs occurring subsequent to December 31, 2020 that may require revisions to estimates of proved reserves. See also Part I, “Item 1A. Risk Factors—If oil and natural gas prices remain depressed for extended periods of time, we may be required to make significant downward adjustments to the carrying value of our oil and natural gas properties.” 
+12-Month Average 
+Realized Prices Excess (deficit) of cost center ceiling over net book value, less related deferred income taxes Increase (decrease) of cost center ceiling over net book value, less related deferred income taxes 
+Full Cost Pool Scenarios Crude Oil 
+($/Bbl) Natural Gas 
+($/Mcf) (In millions) (In millions) 
+December 31, 2020 Actual $37.44 $1.02 $— 
+Crude Oil and Natural Gas Price Sensitivity 
+Crude Oil and Natural Gas +10% $41.40 $1.21 $640 $640 
+Crude Oil and Natural Gas -10% $33.49 $0.81 ($632) ($632) 
+Crude Oil Price Sensitivity 
+Crude Oil +10% $41.40 $1.02 $602 $602 
+Crude Oil -10% $33.49 $1.02 ($588) ($588) 
+Natural Gas Price Sensitivity 
+Natural Gas +10% $37.44 $1.21 $48 $48 
+Natural Gas -10% $37.44 $0.81 ($50) ($50) 
+Asset retirement obligations 
+We record an estimate of the fair value of liabilities for obligations associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Estimates involved in determining asset retirement obligations include the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a credit-adjusted risk-free discount rate and an inflation factor in order to determine the present value of the asset retirement obligation. The present value of the asset retirement obligations is accreted each period and the increase to the obligations is reported in “Depreciation, depletion and amortization” in the consolidated statements of operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to evaluated oil and gas properties in the consolidated balance sheets. See “Note 14 - Asset Retirement Obligations” of the Notes to our Consolidated Financial Statements for additional information. 
+Estimating the future plugging and abandonment costs of wells and related facilities requires management to make estimates and judgments because most of the obligations are many years in the future and asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. 
+Derivative instruments 
+We use commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of our forecasted sales of production and achieve a more predictable level of cash flow. We do not use these instruments for speculative or trading purposes. Settlements of derivative contracts are generally based on the difference between the contract price and prices specified in the derivative instrument and a NYMEX price or other futures index price. 
+63 
+Our commodity derivative instruments, as well as our contingent consideration arrangements, are carried at their fair value in the consolidated balance sheets with all gains and losses as a result of changes in the fair value recognized in the consolidated statements of operations in the period in which the changes occur. The estimated fair value of our derivative contracts is based upon current forward market prices on NYMEX and in the case of collars and floors, the time value of options. For additional information regarding our derivatives instruments and their fair values, see “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” of the Notes to our Consolidated Financial Statements and “Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk - Commodity Price Risk”. 
+Income taxes 
+The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. 
+Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that our net deferred tax assets will be utilized prior to their expiration. A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and a net deferred tax asset position at December 31, 2020, driven primarily by impairments of evaluated oil and gas properties recognized beginning in the second quarter of 2020 and continuing through the end of the year, which limits the ability to consider other subjective evidence such as our potential for future growth. Beginning in the second quarter of 2020 and continuing through the end of 2020, based on the evaluation of the evidence available, we concluded that it is more likely than not that the net deferred tax assets will not be realized. As a result, we recorded a valuation allowance of $639.2 million, reducing the net deferred tax assets as of December 31, 2020 to zero. 
+We will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until we can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead us to conclude that it is more likely than not our net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in crude oil prices, and taxable events that could result from one or more transactions. The valuation allowance does not preclude us from utilizing the tax attributes if we recognize taxable income. As long as we continue to conclude that the valuation allowance against our net deferred tax assets is necessary, we will have no significant deferred income tax expense or benefit. See “Note 12 - Income Taxes” of the Notes to our Consolidated Financial Statements for additional discussion. 
+Our ability to utilize our federal net operating losses (“NOLs”) to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of stock by 5% shareholders and the offering of stock by us during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of Callon. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of our taxable income that can be offset by these carryforwards. The limitation is generally equal to the product of (i) the fair market value of the equity of Callon multiplied by (ii) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains inherent in the assets sold. Due to the issuance of common stock associated with the Carrizo Acquisition, we incurred a cumulative ownership change and as such, our NOLs prior to the acquisition are subject to an annual limitation under Internal Revenue Code Section 382. 
+Recently Adopted and Recently Issued Accounting Pronouncements 
+See “Note 2 - Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements for information discussion of recent accounting pronouncements issued by the Financial Accounting Standards Board. 
+Off-balance Sheet Arrangements 
+We had no off-balance sheet arrangements as of December 31, 2020. 
+ITEM 7A. Quantitative and Qualitative Disclosures about Market Risk 
+We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer credit risk. We mitigate these risks through a program of risk management including the use of commodity derivative instruments. 
+Commodity price risk 
+Our revenues are derived from the sale of our oil, natural gas, and NGL production. The prices for oil, natural gas, and NGLs remain extremely volatile primarily due to the underlying supply and demand concerns as a result of COVID-19 as well as the actions taken 
+64 
+by OPEC and other countries as described above. This volatility was shown in the price of oil which ranged from a low of -$36.98 per Bbl to $63.27 per Bbl. 
+The following table sets forth oil, natural gas and NGL revenues for the year ended December 31, 2020 as well as the impact on the oil, natural gas and NGL revenues assuming a 10% increase or decrease in our average realized sales prices for oil, natural gas and NGLs, excluding the impact of commodity derivative settlements: 
+Year Ended December 31, 2020 
+Oil Natural Gas NGLs Total 
+(In thousands) 
+Revenues $850,667 $51,866 $81,295 $983,828 
+Impact of a 10% fluctuation in average realized prices $85,067 $5,187 $8,129 $98,383 
+From time to time, we enter into derivative financial instruments to manage oil, natural gas and NGL price risk, related both to NYMEX benchmark prices and regional basis differentials. The total volumes we hedge through use of our derivative instruments varies from period to period. Generally, our objective is to hedge approximately 60% of our anticipated internally forecasted production for the next 12 to 24 months, subject to the covenants under our Credit Facility. Our hedge policies and objectives may change significantly with movements in commodities prices or futures prices. 
+As of December 31, 2020, for the full year of 2021, we had 14,547,575 Bbls of fixed price oil hedges across NYMEX WTI, ICE Brent and Argus WTI-Houston benchmarks. We also had 3,022,900 Bbls of WTI Midland-Cushing oil basis hedges. Additionally, for the full year of 2021, we had 22,023,000 MMBtus of fixed price NYMEX natural gas hedges and 16,425,000 MMBtus of Waha natural gas basis hedges. See “Note 8 - Derivative Instruments and Hedging Activities” of the Notes to our Consolidated Financial Statements for a description of our outstanding derivative contracts as of December 31, 2020. 
+We may utilize fixed price swaps, which reduce our exposure to decreases in commodity prices, but limits the benefit we might otherwise have received from any increases in commodity prices. Swap contracts may also be enhanced by the simultaneous sale of call or put options to effectively increase the effective swap price as a result of the receipt of premiums from the option sales. 
+We also may utilize price collars to reduce the risk of changes in oil and natural gas prices. Under these arrangements, no payments are due by either party as long as the applicable market price is above the floor price (purchased put option) and below the ceiling price (sold call option) set in the collar. If the price falls below the floor, the counterparty to the collar pays the difference to us, and if the price rises above the ceiling, the counterparty receives the difference from us. Additionally, we may sell put options at a price lower than the floor price in conjunction with a collar (three-way collar) and use the proceeds to increase either/both the floor or ceiling prices. In a three-way collar, to the extent that realized prices are below the floor price of the sold put option (or above the ceiling price of the sold call option), our net realized benefit from the three-way collar will be reduced on a dollar-for-dollar basis. 
+We may purchase put options, which reduce our exposure to decreases in oil and natural gas prices while allowing realization of the full benefit from any increases in oil and natural gas prices. If the price falls below the floor, the counterparty pays the difference to us. 
+We enter into these various agreements from time to time to reduce the effects of volatile oil, natural gas and NGL prices and do not enter into derivative transactions for speculative or trading purposes. Presently, none of our derivative positions are designated as hedges for accounting purposes. 
+Interest rate risk 
+We are subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility. As of December 31, 2020, we had $985.0 million outstanding under the Credit Facility with a weighted average interest rate of 2.73%. An increase or decrease of 1.00% in the interest rate would have a corresponding increase or decrease in our interest expense of approximately $9.9 million based on the balance outstanding at December 31, 2020. See “Note 7 - Borrowings” of the Notes to our Consolidated Financial Statements for more information on our Credit Facility. 
+Counterparty and customer credit risk 
+Our principal exposures to credit risk are through receivables from the sale of our oil and natural gas production, joint interest receivables and receivables resulting from derivative financial contracts. 
+We market our oil, natural gas and NGL production to energy marketing companies and are subject to credit risk due to the concentration of our oil, natural gas and NGL receivables with several significant customers. For the year ended December 31, 2020, two purchasers accounted for more than 10% of our revenue: Shell Trading Company (31%) and Valero Energy (23%). The inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In order to mitigate potential exposure to credit risk, we may require from time to time for our customers to provide financial security. We are generally paid by our purchasers within 30 to 90 days after the month of production and currently do not believe that we have 
+65 
+a risk of not collecting. At December 31, 2020, our total receivables from the sale of our oil, natural gas and NGL production were approximately $100.3 million. 
+Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have or intend to drill. We have little ability to control whether these entities will participate in our wells. We generally have the right to withhold future revenue distributions to recover past due receivables from joint interest owners. The allowance for credit losses related to our joint interest receivables is immaterial. At December 31, 2020, our joint interest receivables were approximately $11.5 million. 
+Our oil, natural gas and NGL commodity derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. All of the counterparties of our commodity derivative instruments currently in place are lenders under our Credit Facility. We are likely to enter into additional commodity derivative instruments with these or other lenders under our Credit Facility, representing institutions with investment grade ratings. We have existing International Swap Dealers Association Master Agreements (“ISDA Agreements”) with our commodity derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of offset upon the occurrence of defined acts of default by either us or a counterparty to a commodity derivative, whereby the party not in default may offset all commodity derivative liabilities owed to the defaulting party against all commodity derivative asset receivables from the defaulting party. At December 31, 2020, we had a net commodity derivative liability position of $96.1 million. 
+66 
+ITEM 8. Financial Statements and Supplementary Data 
+Page 
+Reports of Independent Registered Public Accounting Firm 
+68 
+Consolidated Balance Sheets as of December 31, 2020 and 2019 
+71 
+Consolidated Statements of Operations for the Years Ended December 31, 2020, 2019 and 2018 
+72 
+Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2020, 2019 and 2018 
+73 
+Consolidated Statements of Cash Flows for the Years Ended December 31, 2020, 2019 and 2018 
+74 
+Notes to Consolidated Financial Statements 
+75 
+67 
+Report of Independent Registered Public Accounting Firm 
+Board of Directors and Shareholders 
+Callon Petroleum Company 
+Opinion on the financial statements 
+We have audited the accompanying consolidated balance sheets of Callon Petroleum Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2020 and 2019, the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2020, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2020, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 25, 2021 expressed an unqualified opinion. 
+Basis for opinion 
+These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. 
+Critical Audit Matter 
+The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. 
+Depletion expense and impairment of oil and gas properties impacted by the Company’s estimation of proved reserves 
+As described further in Note 2 to the financial statements, the Company accounts for its oil and gas properties using the full cost method of accounting which requires management to make estimates of proved reserve volumes and future net revenues to record depletion expense and assess its oil and gas properties for potential impairment. To estimate the volume of proved reserves and future net revenue, management makes significant estimates and assumptions including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected with reasonable certainty to be economical under the appropriate pricing assumptions required in the estimation of depletion expense and potential impairment assessment. We identified the estimation of proved reserves of oil and gas properties as a critical audit matter. 
+The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain inputs and assumptions, which require a high degree of subjectivity, necessary to estimate the volume and future net revenues of the Company’s proved reserves could have a significant impact on the measurement of depletion expense and potential impairment. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment. 
+Our audit procedures related to the estimation of proved reserves included the following, among others. 
+• We tested the design and operating effectiveness of controls relating to management’s estimation of proved reserves for the purpose of estimating depletion expense and assessing the Company’s oil and gas properties for potential impairment. 
+68 
+• We evaluated the independence, objectivity, and professional qualifications of the Company’s reserve engineers, made inquiries of those specialists regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the reserve report prepared by the Company’s specialists. 
+• To the extent key inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, including, but not limited to: historical pricing differentials, operating costs, estimated capital costs, and ownership interests, we tested management’s process for determining the assumptions, including examining the underlying support on a sample basis. Specifically, our audit procedures involved testing management’s assumptions by performing the following: 
+◦ Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials; 
+◦ Tested models used to estimate the future operating costs in the reserve report and compared amounts to historical operating costs; 
+◦ Evaluated the method used to determine the future capital costs and compared estimated future capital expenditures used in the reserve report to amounts expended for recently drilled and completed wells; 
+◦ Tested the working and net revenue interests used in the reserve report by inspecting land and division order records; 
+◦ Evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s ability to fund and intent to develop the proved undeveloped properties; and 
+◦ Applied analytical procedures to the reserve report forecasted production by comparing to historical actual results, and to the prior year reserve report. 
+/s/ GRANT THORNTON LLP 
+We have served as the Company’s auditor since 2016. 
+Houston, Texas 
+February 25, 2021 
+69 
+Report of Independent Registered Public Accounting Firm 
+Board of Directors and Shareholders 
+Callon Petroleum Company 
+Opinion on internal control over financial reporting 
+We have audited the internal control over financial reporting of Callon Petroleum Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2020, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2020, and our report dated February 25, 2021 expressed an unqualified opinion on those financial statements. 
+Basis for opinion 
+The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s report on internal control over financial reporting (“Management’s Report”). Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+Definition and limitations of internal control over financial reporting 
+A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+/s/ GRANT THORNTON LLP 
+Houston, Texas 
+February 25, 2021 
+70 
+Callon Petroleum Company 
+Consolidated Balance Sheets 
+(In thousands, except par and share data) 
+December 31, 
+2020 2019 
+ASSETS 
+Current assets: 
+Cash and cash equivalents $ 20,236 $ 13,341 
+Accounts receivable, net 133,109 209,463 
+Fair value of derivatives 921 26,056 
+Other current assets 24,103 19,814 
+Total current assets 178,369 268,674 
+Oil and natural gas properties, full cost accounting method: 
+Evaluated properties, net 2,355,710 4,682,994 
+Unevaluated properties 1,733,250 1,986,124 
+Total oil and natural gas properties, net 4,088,960 6,669,118 
+Operating lease right-of-use assets 22,526 63,908 
+Other property and equipment, net 31,640 35,253 
+Deferred tax asset — 115,720 
+Deferred financing costs 23,643 22,233 
+Other assets, net 17,730 19,932 
+Total assets $ 4,362,868 $ 7,194,838 
+LIABILITIES AND STOCKHOLDERS’ EQUITY 
+Current liabilities: 
+Accounts payable and accrued liabilities $ 345,365 $ 490,442 
+Operating lease liabilities 13,175 42,858 
+Fair value of derivatives 97,060 71,197 
+Other current liabilities 41,508 47,750 
+Total current liabilities 497,108 652,247 
+Long-term debt 2,969,264 3,186,109 
+Operating lease liabilities 27,576 37,088 
+Asset retirement obligations 57,209 48,860 
+Fair value of derivatives 88,046 32,695 
+Other long-term liabilities 12,663 14,531 
+Total liabilities 3,651,866 3,971,530 
+Commitments and contingencies 
+Stockholders’ equity: 
+Common stock, $ 0.01 par value, 52,500,000 shares authorized; 39,758,817 and 
+39,659,001 shares outstanding, respectively (1) 
+398 3,966 
+Capital in excess of par 3,222,959 3,198,076 
+Retained earnings (Accumulated deficit) ( 2,512,355 ) 21,266 
+Total stockholders’ equity 711,002 3,223,308 
+Total liabilities and stockholders’ equity $ 4,362,868 $ 7,194,838 
+(1) All share amounts (except par value) have been retroactively adjusted for the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 – Stockholders’ Equity” for additional information. 
+The accompanying notes are an integral part of these consolidated financial statements. 
+71 
+Callon Petroleum Company 
+Consolidated Statements of Operations 
+(In thousands, except per share data) 
+For the Year Ended December 31, 
+2020 2019 2018 
+Operating Revenues: 
+Oil $ 850,667 $ 633,107 $ 530,898 
+Natural gas 51,866 36,390 56,726 
+Natural gas liquids 81,295 2,075 — 
+Sales of purchased oil and gas 49,319 — — 
+Total operating revenues 1,033,147 671,572 587,624 
+Operating Expenses: 
+Lease operating 194,101 91,827 69,180 
+Production and ad valorem taxes 62,638 42,651 35,755 
+Gathering, transportation and processing 77,309 — — 
+Cost of purchased oil and gas 51,766 — — 
+Depreciation, depletion and amortization 480,631 240,642 182,783 
+General and administrative 37,187 45,331 35,293 
+Impairment of evaluated oil and gas properties 2,547,241 — — 
+Merger and integration expenses 28,482 74,363 — 
+Other operating 10,644 4,100 5,083 
+Total operating expenses 3,489,999 498,914 328,094 
+Income (Loss) From Operations ( 2,456,852 ) 172,658 259,530 
+Other (Income) Expenses: 
+Interest expense, net of capitalized amounts 94,329 2,907 2,500 
+(Gain) loss on derivative contracts 27,773 62,109 ( 48,544 ) 
+(Gain) loss on extinguishment of debt ( 170,370 ) 4,881 — 
+Other (income) expense 2,983 ( 468 ) ( 2,896 ) 
+Total other (income) expense ( 45,285 ) 69,429 ( 48,940 ) 
+Income (Loss) Before Income Taxes ( 2,411,567 ) 103,229 308,470 
+Income tax expense ( 122,054 ) ( 35,301 ) ( 8,110 ) 
+Net Income (Loss) ($ 2,533,621 ) $ 67,928 $ 300,360 
+Preferred stock dividends — ( 3,997 ) ( 7,295 ) 
+Loss on redemption of preferred stock — ( 8,304 ) — 
+Income (Loss) Available to Common Stockholders ($ 2,533,621 ) $ 55,627 $ 293,065 
+Income (Loss) Available to Common Stockholders 
+Per Common Share (1) : 
+Basic ($ 63.79 ) $ 2.39 $ 13.50 
+Diluted ($ 63.79 ) $ 2.38 $ 13.46 
+Weighted Average Common Shares Outstanding (1) : 
+Basic 39,718 23,313 21,703 
+Diluted 39,718 23,340 21,773 
+(1) All share and per share amounts have been retroactively adjusted for the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 – Stockholders’ Equity” for additional information. 
+The accompanying notes are an integral part of these consolidated financial statements. 
+72 
+Callon Petroleum Company 
+Consolidated Statements of Stockholders’ Equity 
+(In thousands, except share amounts) 
+Retained 
+Preferred Common Capital in Earnings Total 
+Stock Stock Excess (Accumulated Stockholders' 
+Shares $ 
+Shares (1) 
+$ of Par Deficit) Equity 
+Balance at 12/31/2017 1,459 $ 15 20,183 $ 2,018 $ 2,181,359 ($ 327,426 ) $ 1,855,966 
+Net income — — — — — 300,360 300,360 
+Shares issued pursuant to employee benefit plans — — 4 — 533 — 533 
+Restricted stock — — 40 5 7,651 — 7,656 
+Common stock issued — — 2,530 253 287,735 — 287,988 
+Preferred stock dividend — — — — — ( 7,295 ) ( 7,295 ) 
+Balance at 12/31/2018 1,459 $ 15 22,757 $ 2,276 $ 2,477,278 ($ 34,361 ) $ 2,445,208 
+Net income — — — — — 67,928 67,928 
+Shares issued pursuant to employee benefit plans — — 2 — 154 — 154 
+Restricted stock — — 79 8 11,622 — 11,630 
+Common stock issued for Carrizo Acquisition — — 16,821 1,682 763,691 — 765,373 
+Common stock warrants reissued in conjunction with Carrizo Acquisition — — — — 10,029 — 10,029 
+Preferred stock dividend — — — — — ( 3,997 ) ( 3,997 ) 
+Preferred stock redemption ( 1,459 ) ( 15 ) — — ( 64,698 ) — ( 64,713 ) 
+Loss on redemption of preferred stock — — — — — ( 8,304 ) ( 8,304 ) 
+Balance at 12/31/2019 — $ — 39,659 $ 3,966 $ 3,198,076 $ 21,266 $ 3,223,308 
+Net loss — — — — — ( 2,533,621 ) ( 2,533,621 ) 
+Restricted stock — — 100 10 12,213 — 12,223 
+Reverse stock split — — — ( 3,578 ) 3,578 — — 
+Issuance of common stock warrants — — — — 9,109 — 9,109 
+Other — — — — ( 17 ) — ( 17 ) 
+Balance at 12/31/2020 — $ — 39,759 $ 398 $ 3,222,959 ($ 2,512,355 ) $ 711,002 
+(1) All share amounts have been retroactively adjusted for the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 – Stockholders’ Equity” for additional information. 
+The accompanying notes are an integral part of these consolidated financial statements. 
+73 
+Callon Petroleum Company 
+Consolidated Statements of Cash Flows 
+(In thousands) 
+Years Ended December 31, 
+2020 2019 2018 
+Cash flows from operating activities: 
+Net income (loss) ($ 2,533,621 ) $ 67,928 $ 300,360 
+Adjustments to reconcile net income (loss) to net cash provided by operating activities: 
+Depreciation, depletion and amortization 480,631 245,936 185,605 
+Impairment of evaluated oil and gas properties 2,547,241 — — 
+Amortization of non-cash debt related items 3,901 2,907 2,483 
+Deferred income tax expense 118,607 35,301 8,110 
+(Gain) loss on derivative contracts 27,773 62,109 ( 48,544 ) 
+Cash received (paid) for commodity derivative settlements, net 98,870 ( 3,789 ) ( 27,272 ) 
+(Gain) loss on early extinguishment of debt ( 170,370 ) 4,881 — 
+Non-cash expense related to equity share-based awards 6,773 9,767 6,289 
+Change in the fair value of liability share-based awards ( 4,110 ) 1,624 375 
+Payments for cash-settled restricted stock unit awards ( 770 ) ( 1,425 ) ( 4,990 ) 
+Other, net 7,857 ( 90 ) ( 144 ) 
+Changes in current assets and liabilities: 
+Accounts receivable 75,770 ( 35,071 ) ( 17,351 ) 
+Other current assets ( 6,550 ) ( 4,166 ) ( 7,601 ) 
+Accounts payable and accrued liabilities ( 92,227 ) 82,290 72,842 
+Other — 8,114 ( 2,508 ) 
+Net cash provided by operating activities 559,775 476,316 467,654 
+Cash flows from investing activities: 
+Capital expenditures ( 677,154 ) ( 640,540 ) ( 611,173 ) 
+Acquisitions — ( 42,266 ) ( 718,793 ) 
+Proceeds from sales of assets 178,970 294,417 9,009 
+Cash paid for settlements of contingent consideration arrangements, net ( 40,000 ) — — 
+Other, net 8,301 — ( 3,100 ) 
+Net cash used in investing activities ( 529,883 ) ( 388,389 ) ( 1,324,057 ) 
+Cash flows from financing activities: 
+Borrowings on Credit Facility 5,353,000 2,455,900 500,000 
+Payments on Credit Facility ( 5,653,000 ) ( 895,500 ) ( 325,000 ) 
+Payment to terminate Prior Credit Facility — ( 475,400 ) — 
+Repayment of Carrizo’s senior secured revolving credit facility — ( 853,549 ) — 
+Repayment of Carrizo’s preferred stock — ( 220,399 ) — 
+Issuance of 9.00 % Second Lien Senior Secured Notes due 2025 
+300,000 — — 
+Discount on the issuance of 9.00 % Second Lien Senior Secured Notes due 2025 
+( 35,270 ) — — 
+Issuance of September 2020 Warrants 23,909 — — 
+Issuance of 6.375 % Senior Notes due 2026 
+— — 400,000 
+Issuance of common stock — — 287,988 
+Payment of preferred stock dividends — ( 3,997 ) ( 7,295 ) 
+Payment of deferred financing and debt exchange costs ( 10,811 ) ( 22,480 ) ( 9,430 ) 
+Tax withholdings related to restricted stock units ( 509 ) ( 2,195 ) ( 1,804 ) 
+Redemption of preferred stock — ( 73,017 ) — 
+Other, net ( 316 ) — — 
+Net cash provided by (used in) financing activities ( 22,997 ) ( 90,637 ) 844,459 
+Net change in cash and cash equivalents 6,895 ( 2,710 ) ( 11,944 ) 
+Balance, beginning of period 13,341 16,051 27,995 
+Balance, end of period $ 20,236 $ 13,341 $ 16,051 
+The accompanying notes are an integral part of these consolidated financial statements. 
+74 
+INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+1. 
+Description of Business 
+11. Stockholders’ Equity 
+2. 
+Summary of Significant Accounting Policies 
+12. 
+Income Taxes 
+3. Revenue Recognition 13. 
+Leases 
+4. 
+Acquisitions and Divestitures 
+14. 
+Asset Retirement Obligations 
+5. Property and Equipment, Net 15. 
+Accounts Receivable , Net 
+6. 
+Earnings Per Share 
+16. Accounts Payable and Accrued Liabilities 
+7. 
+Borrowings 
+17. Commitments and Contingencies 
+8. 
+Derivative Instruments and Hedging Activities 
+18. Subsequent Events (Unaudited) 
+9. 
+Fair Value Measurements 
+19. 
+Supplemental Information on Oil and Natural Gas Operations (Unaudited) 
+10. 
+Share-Based Compensation 
+20. 
+Supplemental Quarterly Financial Information (Unaudited) 
+Note 1 – Description of Business 
+Callon Petroleum Company is an independent oil and natural gas company established in 1950. The Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. 
+Callon’s focus is on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas. The Company’s activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger Permian Basin in West Texas, as well as the Eagle Ford, which the Company entered into through its acquisition of Carrizo Oil & Gas, Inc. (“Carrizo”) in late 2019. The Company’s primary operations in the Permian reflect a high-return, oil-weighted drilling inventory with multiple prospective horizontal development intervals and are complemented by a well-established and repeatable cash flow generating business in the Eagle Ford. 
+Note 2 – Summary of Significant Accounting Policies 
+Basis of Presentation and Principles of Consolidation 
+The consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and are presented in accordance with U.S. GAAP. The Company proportionately consolidates its undivided interests in oil and gas properties as well as investments in unincorporated entities, such as partnerships and limited liability companies where the Company, as a partner or member, has undivided interests in the oil and gas properties. In the opinion of management, the accompanying audited consolidated financial statements reflect all adjustments, including normal recurring adjustments and all intercompany account balance and transaction eliminations, necessary to present fairly the Company’s financial position, results of its operations and cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation. 
+Use of Estimates 
+The preparation of financial statements in conformity with U.S. GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating depreciation, depletion and amortization (“DD&A”) of evaluated oil and gas property costs, the present value of estimated future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated timing of cash outflows underlying asset retirement obligations. There are numerous uncertainties inherent in the estimation of proved oil and gas reserves and in the projection of future rates of production and the timing of development expenditures. Other significant estimates are involved in determining asset retirement obligations, acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of commodity derivative assets and liabilities, fair values of contingent consideration arrangements, fair value of second lien notes upon issuance, grant date fair value of stock-based awards, and contingency, litigation, and environmental liabilities. Actual results could differ from those estimates. 
+Cash and Cash Equivalents 
+The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. 
+75 
+Accounts Receivable, Net 
+Accounts receivable, net consists primarily of receivables from oil, natural gas, and NGL purchasers and joint interest owners in properties the Company operates. The Company generally has the right to withhold future revenue distributions to recover past due receivables from joint interest owners. Generally, the Company’s oil, natural gas, and NGL receivables are collected within 30 to 90 days. The Company’s allowance for credit losses and bad debt expense was immaterial for all periods presented. 
+Concentration of Credit Risk and Major Customers 
+The concentration of accounts receivable from entities in the oil and gas industry may impact the Company’s overall credit risk such that these entities may be similarly affected by changes in economic and other industry conditions. The Company does not believe the loss of any one of its purchasers would materially affect its ability to sell the oil and gas it produces as other purchasers are available in its primary areas of activity. The Company had the following major customers that represented 10% or more of its total revenues for at least one of the periods presented: 
+Years Ended December 31, 
+2020 2019 2018 
+Shell Trading Company 31 % 10 % * 
+Valero Energy 23 % * * 
+Rio Energy International, Inc. * 26 % 28 % 
+Enterprise Crude Oil, LLC * 19 % 14 % 
+Plains Marketing, L.P. * 15 % 21 % 
+* - Less than 10% for the applicable year. 
+The Company’s counterparties to its commodity derivative instruments include lenders under the Company’s credit agreement (“Lender Counterparty”) as well as counterparties who are not lenders under the Company’s credit agreement (“Non-Lender Counterparty”). As each Lender Counterparty has an investment grade credit rating and the Company has obtained a guaranty from each Non-Lender Counterparty’s parent company, which has an investment grade credit rating, the Company believes it does not have significant credit risk with its commodity derivative instrument counterparties. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each Lender Counterparty and each Non-Lender Counterparty’s parent company. The Company executes its derivative instruments with multiple counterparties to minimize its credit exposure to any individual counterparty. 
+Oil and Natural Gas Properties 
+The Company uses the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration, and development activities are capitalized as oil and gas properties. Internal costs that are directly related to acquisition, exploration, and development activities, including salaries, benefits, and stock-based compensation, are capitalized to either evaluated or unevaluated oil and gas properties based on the type of activity. Internal costs related to production and similar activities are expensed as incurred. 
+Proceeds from the sale or disposition of evaluated and unevaluated oil and natural gas properties are accounted for as a reduction of evaluated oil and gas property costs unless the sale significantly alters the relationship between capitalized costs and estimated proved reserves, in which case a gain or loss is recognized. For the years ended December 31, 2020, 2019 and 2018, the Company did not have any sales of oil and gas properties that significantly altered such relationship. 
+From time to time, the Company exchanges undeveloped acreage with third parties. The exchanges are recorded at fair value and the difference is accounted for as an adjustment of capitalized costs with no gain or loss recognized pursuant to the rules governing full cost accounting, unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas. 
+Capitalized oil and gas property costs are amortized on an equivalent unit-of-production method, converting natural gas to barrels of oil equivalent at the ratio of six thousand cubic feet of gas to one barrel of oil, which represents their approximate relative energy content. The equivalent unit-of-production depletion rate is computed on a quarterly basis by dividing current quarter production by estimated proved oil and gas reserves at the beginning of the quarter then applying such depletion rate to evaluated oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values. 
+Excluded from this amortization are costs associated with unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties or the Company determines that these costs have been impaired. The Company assesses 
+76 
+properties on an individual basis or as a group and considers the following factors, among others, to determine if these costs have been impaired: exploration program and intent to drill, remaining lease term, and the assignment of proved reserves. As a result of the downturn in the oil and gas industry as well as in the broader macroeconomic environment in 2020, the Company analyzed its unevaluated leasehold giving consideration to its updated exploration program as well as to the remaining lease term of certain unevaluated leaseholds. As a result, the Company impaired $ 229.6 million unevaluated leasehold costs and transferred these costs to evaluated properties during the year ended December 31, 2020. 
+Geological and geophysical costs not associated with specific prospects are recorded to evaluated oil and gas property costs as incurred. The amount of interest costs capitalized is determined on a quarterly basis based on the average balance of unevaluated properties and the weighted average interest rate of outstanding borrowings. Capitalized interest cannot exceed gross interest expense. 
+Under full cost accounting rules, the Company reviews the net book value of its oil and gas properties each quarter. Under these rules, the net book value of oil and gas properties, less related deferred income taxes, are limited to the “cost center ceiling” equal to (i) the sum of (a) the present value of estimated future net revenues from estimated proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the estimated proved oil and gas reserves computed using a discount factor of 10 %, (b) the costs of unevaluated properties not being amortized, and (c) the lower of cost or estimated fair value of unevaluated properties included in the costs being amortized; less (ii) related income tax effects. Any excess of the net book value of oil and gas properties, less related deferred income taxes, over the cost center ceiling is recognized as an impairment of evaluated oil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even if higher commodity prices in the future result in a cost center ceiling in excess of the net book value of oil and gas properties, less related deferred income taxes. 
+The estimated future net revenues used in the cost center ceiling are calculated using the average realized prices for sales of oil, NGLs, and natural gas on the first calendar day of each month during the 12-month period prior to the end of the current quarter (“12-Month Average Realized Price”), held flat for the life of the production, except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of commodity derivative instruments as the Company elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. Primarily as a result of the 31 % decrease in the 12-Month Average Realized Price of oil, the Company recognized impairments of evaluated oil and gas properties of $ 2.5 billion for the year December 31, 2020. The Company did no t recognize impairments of evaluated oil and gas properties for the years ended December 31, 2019 and 2018. 
+Depreciation of other property and equipment is recognized using the straight-line method based on estimated useful lives ranging from two to twenty years. 
+Deferred Financing Costs 
+Deferred financing costs associated with the Company’s senior notes and second lien notes are classified as a reduction of the related senior notes or second lien notes carrying value on the consolidated balance sheets and are amortized to interest expense using the effective interest method over the terms of the related debt. Deferred financing costs associated with the revolving credit facility are classified in “Other long-term assets” in the consolidated balance sheets and are amortized to interest expense using the straight-line method over the term of the facility. 
+Asset Retirement Obligations 
+The Company records an estimate of the fair value of liabilities for obligations associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Estimates involved in determining asset retirement obligations include the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a credit-adjusted risk-free discount rate and an inflation factor in order to determine the present value of the asset retirement obligation. The present value of the asset retirement obligations is accreted each period and the increase to the obligation is reported in “Depreciation, depletion and amortization” in the consolidated statements of operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to evaluated oil and gas properties in the consolidated balance sheets. See “Note 14 - Asset Retirement Obligations” for additional information. 
+Derivative Instruments 
+The Company uses commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of its forecasted sales of production and achieve a more predictable level of cash flow. All commodity derivative instruments are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. The Company nets its commodity derivative instrument fair value amounts executed with the same counterparty to a single asset or liability pursuant to International Swap Dealers Association Master Agreements (“ISDAs”), which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The Company does not enter into commodity derivative instruments for speculative or trading purposes. 
+77 
+The Company is also party to contingent consideration arrangements that include obligations to pay or rights to receive additional consideration if commodity prices exceed specified thresholds during certain periods in the future. These contingent consideration assets and liabilities are required to be bifurcated and accounted for separately as derivative instruments as they are not considered to be clearly and closely related to the host contract, and recognized at their acquisition or divestiture date fair value in the consolidated balance sheets. 
+The Company has elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. As such, all gains and losses as a result of changes in the fair value of commodity derivative instruments, as well as its contingent consideration arrangements, are recognized as “(Gain) loss on derivative contracts” in the consolidated statements of operations in the period in which the changes occur. See “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” for further discussion. 
+Revenue Recognition 
+The Company recognizes revenues from the sales of oil, natural gas, and NGLs to its customers and presents them disaggregated on the Company’s consolidated statements of operations. Revenue is recognized at the point in time when control of the product transfers to the customer. Revenue accruals are recorded monthly and are based on estimated production delivered to a purchaser and the expected price to be received. Variances between estimates and the actual amounts received are recorded in the month payment is received. See “Note 3 - Revenue Recognition” for further discussion. 
+Income Taxes 
+Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are recognized at the end of each reporting period for the future tax consequences of cumulative temporary differences between the tax basis of assets and liabilities and their reported amounts in the Company’s consolidated financial statements based on existing tax laws and enacted statutory tax rates applicable to the periods in which the temporary differences are expected to affect taxable income. U.S. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards and tax credit carryforwards. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering all available evidence (both positive and negative) to determine whether it is more likely than not that all or a portion of the deferred tax assets will not be realized and a valuation allowance is required. See “Note 12 - Income Taxes” for further discussion of the deferred tax asset valuation allowance. 
+Share-Based Compensation 
+The Company grants restricted stock unit awards that may be settled in common stock (“RSU Equity Awards”) or cash (“Cash-Settled RSU Awards”), some of which are subject to achievement of certain performance conditions. Share-based compensation expense is recognized as “General and administrative expense” in the consolidated statements of operations. The Company accounts for forfeitures of equity-based incentive awards as they occur. See “Note 10 - Share-Based Compensation” for further details of the awards discussed below. 
+RSU Equity Awards and Cash-Settled RSU Awards. Share-based compensation expense for RSU Equity Awards is based on the grant-date fair value and recognized over the vesting period (generally three years for employees and one year for non-employee directors) using the straight-line method. For RSU Equity Awards with vesting terms subject to a performance condition, share-based compensation expense is based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model with the estimated value recognized over the vesting period (generally three years ). Cash-Settled RSU Awards subject to a performance condition that the Company expects or is required to settle in cash, are accounted for as liabilities with share-based compensation expense based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model, with the estimated fair value recognized over the vesting period (generally three years ). 
+Cash SARs. Stock appreciation rights to be settled in cash (“Cash SARs”) previously granted by Carrizo that were outstanding at closing of the Merger were canceled and converted into a Cash SAR covering shares of the Company’s common stock, with the conversion calculated as prescribed in the agreement governing the Merger. The Cash SARs were recorded at their acquisition date fair value, which was determined using a Black-Scholes-Merton option pricing model, with the fair value liability subsequently remeasured at the end of each reporting period. The liability for Cash SARs is classified as “Other current liabilities” in the consolidated balance sheets as all outstanding awards are vested. The Cash SARs will expire between one and six years , depending on the date of grant. 
+78 
+Supplemental Cash Flow Information 
+The following table sets forth supplemental cash flow information for the periods indicated: 
+Years Ended December 31, 
+2020 2019 2018 
+(In thousands) 
+Interest paid, net of capitalized amounts $ 91,269 $ — $ — 
+Income taxes paid (1) 
+— — — 
+Cash paid for amounts included in the measurement of lease liabilities: 
+Operating cash flows from operating leases $ 44,314 $ 3,414 $ — 
+Investing cash flows from operating leases 24,234 32,529 — 
+Non-cash investing and financing activities: 
+Change in accrued capital expenditures ($ 64,465 ) ($ 31,475 ) ($ 52,757 ) 
+Change in asset retirement costs 8,605 13,559 8,730 
+Contingent consideration arrangement — 8,512 — 
+ROU assets obtained in exchange for lease liabilities: 
+Operating leases $ 8,070 $ 66,914 $ — 
+Financing leases — 2,197 — 
+(1) The Company did no t pay any federal income tax for any of the years in the three year period ending December 31, 2020. 
+Earnings per Share 
+The Company’s basic net income (loss) attributable to common shareholders per common share is based on the weighted average number of shares of common stock outstanding for the period. Diluted net income (loss) attributable to common shareholders per common share is calculated using the treasury stock method and is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the year which include RSU Equity Awards and common stock warrants. When a loss attributable to common shareholders per common share exists, all potentially dilutive common shares outstanding are anti-dilutive and therefore excluded from the calculation of diluted weighted average shares outstanding. See “Note 6 - Earnings Per Share” for further discussion. 
+Industry Segment and Geographic Information 
+The Company operates in one industry segment, which is the exploration, development, and production of crude oil, natural gas, and NGLs. All of the Company’s operations are located in the United States and currently all revenues are attributable to customers located in the United States. 
+Recently Adopted Accounting Standards 
+Credit Losses. In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, followed by other related ASUs that provided targeted improvements (collectively “ASU 2016-13”). ASU 2016-13 provides financial statement users with more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. The guidance is to be applied using a modified retrospective method and is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. The Company adopted ASU 2016-13 on January 1, 2020. The adoption of ASU 2016-13 did not have a material impact to the Company’s consolidated financial statements or disclosures. 
+Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification. In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842. In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements. In March 2019, the FASB issued ASU No. 2019-01, Leases (Topic 842): Codification Improvements. Together these related amendments to GAAP represent ASC Topic 842, Leases (“ASC 842”). 
+Effective January 1, 2019, the Company adopted ASU 842, using the modified retrospective approach and did not have a cumulative-effect adjustment in retained earnings as a result of the adoption. ASC 842 requires lessees to recognize a liability representing the obligation to make lease payments and a related right-of-use (“ROU”) asset for virtually all lease transactions and disclose key quantitative and qualitative information about leasing arrangements. However, ASC 842 does not apply to leases to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained. The Company engaged a third-party consultant to assist with assessing its existing contracts, as well as future potential contracts, and to determine the impact of its application on its consolidated financial statements and related 
+79 
+disclosures. The contract evaluation process included review of drilling rig contracts, office facility leases, compressors, field vehicles and equipment, general corporate leased equipment, and other existing arrangements to support its operations that may contain a lease component. 
+Upon adoption, the Company implemented policy elections and practical expedients which include the following: 
+• package of practical expedients which allows the Company to forego reassessing contracts that commenced prior to adoption that were properly evaluated under legacy lease accounting guidance 
+• excluding ROU assets and lease liabilities for leases with terms that are less than one year; 
+• combining lease and non-lease components and accounting for them as a single lease (elected by asset class); 
+• excluding land easements that existed or expired prior to adoption; and 
+• policy election that eliminates the need for adjusting prior period comparable financial statements prepared under legacy lease accounting guidance. 
+Through the implementation process, the Company evaluated each of its lease arrangements and enhanced its systems to track and calculate additional information required upon adoption of this standard. Adoption of ASC 842 did not materially change the Company’s consolidated statements of operations or consolidated statements of cash flows. See “Note 13 - Leases” for further discussion. 
+Recently Issued Accounting Standards 
+In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”) followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021 to provide clarifying guidance regarding the scope of Topic 848. ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. Generally, the guidance is to be applied as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. ASU 2020-04 and ASU 2021-01 are effective for all entities through December 31, 2022. As of December 31, 2020, the Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and ASU 2021-01. Please refer to “Note 7 – Borrowings” for discussion of the use of the adjusted LIBO rate in connection with borrowings under the Credit Facility. 
+Note 3 – Revenue Recognition 
+Revenue from contracts with customers 
+Oil sales 
+Under the Company’s oil sales contracts it sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the point of delivery at the net price received. 
+Natural gas and NGL sales 
+Effective January 1, 2020, certain of our natural gas processing agreements were modified to allow the Company to take title to NGLs resulting from the processing of our natural gas. As a result, sales and reserve volumes, prices, and revenues for NGLs and natural gas are presented separately for periods subsequent to January 1, 2020. For periods prior to January 1, 2020, except for sales and reserve volumes, prices, and revenues specifically associated with Carrizo, sales and reserve volumes, prices, and revenues for NGLs were presented with natural gas. 
+Under the Company’s natural gas sales processing contracts, it delivers natural gas to a midstream processing entity which gathers and processes the natural gas and remits proceeds to the Company for the resulting sale of NGLs and residue gas. The Company evaluates whether the processing entity is the principal or the agent in the transaction for each of our natural gas processing agreements and have concluded that we maintain control through processing or we have the right to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. We recognize revenue when control transfers to the purchaser at the delivery point based on the contractual index price received. 
+Contractual fees associated with gathering, processing, treating and compression, as well as any transportation fees incurred to deliver the product to the purchaser, for the majority of the Company’s natural gas processing agreements were previously recorded as a reduction of revenue. As a result of the modifications to certain of the Company’s natural gas processing agreements, as well as the natural gas processing agreements assumed in the Carrizo Acquisition, the Company now recognizes revenue for natural gas and NGLs on a gross basis with gathering, transportation and processing fees recognized separately as “Gathering, transportation and 
+80 
+processing” in its consolidated statements of operations as the Company maintains control throughout processing. These changes impact the comparability of 2020 with prior periods. For the years ended December 31, 2019 and 2018, $ 10.5 million and $ 7.6 million of gathering, transportation, and processing fees were recognized as a reduction to natural gas revenues in the consolidated statement of operations. 
+Oil and gas purchase and sale arrangements 
+Sales of purchased oil and gas represent revenues the Company receives from sales of commodities purchased from a third-party. The Company recognizes these revenues and the purchase of the third-party commodities, as well as any costs associated with the purchase, on a gross basis, as the Company acts as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer. 
+Accounts receivable from revenues from contracts with customers 
+Net accounts receivable include amounts billed and currently due from revenues from contracts with customers of our oil and natural gas production, which had a balance at December 31, 2020 and 2019 of $ 100.3 million and $ 165.3 million, respectively, and are presented in “Accounts receivable, net” in the consolidated balance sheets. The decrease from December 31, 2019 is primarily due to the lower realized price of oil. 
+Transaction price allocated to remaining performance obligations 
+For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. 
+Prior period performance obligations 
+The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. 
+Note 4 – Acquisitions and Divestitures 
+2020 Acquisitions and Divestitures 
+ORRI Transaction. On September 30, 2020, the Company sold an undivided 2.0 % (on an 8/8ths basis) overriding royalty interest, proportionately reduced to the Company’s net revenue interest, in and to the Company’s operated leases, excluding certain interests to Chambers Minerals, LLC, a private investment vehicle managed by Kimmeridge Energy, for an aggregate purchase price of $ 140.0 million (“ORRI Transaction”), with an effective date of October 1, 2020. After adjusting for costs associated with the sale, the net proceeds of $ 135.8 million were used to repay borrowings outstanding under the Credit Facility. 
+Non-Operated Working Interest Transaction. On November 2, 2020, the Company sold substantially all of its non-operated assets for net proceeds of approximately $ 29.6 million, which were used to repay borrowings outstanding under the Credit Facility. The transaction had an effective date of September 1, 2020 and is subject to post-closing adjustments. 
+The aggregate net proceeds for each of the 2020 divestitures discussed above were recognized as a reduction of evaluated oil and gas properties with no gain or loss recognized as the divestitures did not significantly alter the relationship between capitalized costs and estimated proved reserves. 
+The Company did not have any material acquisitions for the year ended December 31, 2020. 
+81 
+2019 Acquisitions and Divestitures 
+Carrizo Oil & Gas, Inc. Merger. On December 20, 2019, the Company completed its acquisition of Carrizo in an all-stock transaction (the “Merger” or the “Carrizo Acquisition”). Under the terms of the Merger, each outstanding share of Carrizo common stock was converted into 1.75 shares of the Company’s common stock. The Company issued approximately 168.2 million shares of common stock at a price of $ 4.55 per share, resulting in total consideration paid by the Company to the former Carrizo shareholders of approximately $ 765.4 million. In connection with the closing of the Merger, the Company funded the redemption of Carrizo’s 8.875 % Preferred Stock, repaid the outstanding principal under Carrizo’s revolving credit facility and assumed all of Carrizo’s senior notes. See “Note 7 - Borrowings” for further details. 
+The Merger was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values with information available at that time. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. 
+The following table sets forth the Company’s final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date. 
+Final Purchase 
+Price Allocation 
+(In thousands) 
+Consideration: 
+Fair value of the Company’s common stock issued $ 765,373 
+Total consideration $ 765,373 
+Liabilities: 
+Accounts payable $ 37,657 
+Revenues and royalties payable 52,449 
+Operating lease liabilities - current 29,924 
+Fair value of derivatives - current 61,015 
+Other current liabilities 88,346 
+Long-term debt 1,984,135 
+Operating lease liabilities - non-current 30,070 
+Asset retirement obligation 26,151 
+Fair value of derivatives - non-current 26,960 
+Other long-term liabilities 17,887 
+Common stock warrants 10,029 
+Total liabilities assumed $ 2,364,623 
+Assets: 
+Accounts receivable, net $ 48,479 
+Fair value of derivatives - current 17,451 
+Other current assets 11,640 
+Evaluated oil and natural gas properties 2,133,280 
+Unevaluated properties 679,900 
+Other property and equipment 9,614 
+Fair value of derivatives - non-current 4,518 
+Deferred tax asset 162,629 
+Operating lease right-of-use-assets 59,907 
+Other long term assets 2,578 
+Total assets acquired $ 3,129,996 
+During the measurement period, the Company made adjustments to certain of the assets acquired and liabilities assumed, primarily due to the final tax returns of Carrizo which provided the underlying tax basis of Carrizo’s assets and liabilities. Approximately $ 556.2 million of revenues and $ 200.9 million of direct operating expenses attributed to the Carrizo Acquisition were included in the Company’s consolidated statements of operations for the year ended December 31, 2020. For the period from the closing date of the Carrizo Acquisition on December 20, 2019 through December 31, 2019, approximately $ 28.6 million of revenues and $ 7.0 million of 
+82 
+direct operating expenses were included in the Company’s consolidated statements of operations for the year ended December 31, 2019. 
+Pro Forma Operating Results (Unaudited). The following unaudited pro forma combined condensed financial data for the years ended December 31, 2019 and 2018 was derived from the historical financial statements of the Company giving effect to the Merger, as if it had occurred on January 1, 2018. The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for Carrizo’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) the Company’s common stock issued to convert Carrizo’s outstanding shares of common stock and equity awards as of the closing date of the Merger, (ii) the depletion of Carrizo’s fair-valued proved oil and natural gas properties and (iii) the estimated tax impacts of the pro forma adjustments. 
+Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company of approximately $ 58.8 million for the year ended December 31, 2019 and acquisition-related costs incurred by Carrizo that totaled approximately $ 15.6 million for the year ended December 31, 2019. The pro forma results of operations do not include any cost savings or other synergies that may result from the Merger or any estimated costs that have been or will be incurred by the Company to integrate the Carrizo assets. The pro forma financial data does not include the pro forma results of operations for any other acquisitions made during the periods presented, as they were primarily acreage acquisitions and their results were not deemed material. 
+The pro forma consolidated statements of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Merger taken place on January 1, 2018 and is not intended to be a projection of future results. 
+Years Ended December 31, 
+2019 2018 
+(In thousands) 
+Revenues $ 1,620,357 $ 1,661,171 
+Income from operations 614,668 767,628 
+Net income 369,777 734,527 
+Basic earnings per common share $ 0.89 $ 1.87 
+Diluted earnings per common share $ 0.89 $ 1.87 
+In conjunction with the Carrizo Acquisition, the Company incurred costs totaling $ 28.5 million and $ 74.4 million for the years ended December 31, 2020 and 2019, respectively, comprised of severance costs of $ 6.2 million and $ 28.8 million for the years ended December 31, 2020 and 2019, respectively, and other merger and integration expenses of $ 22.3 million and $ 45.6 million for the years ended December 31, 2020 and 2019, respectively. Through December 31, 2020, the Company has incurred cumulative costs associated with the Carrizo Acquisition of $ 102.9 million comprised of severance costs of $ 35.8 million and other merger and integration expenses of $ 67.1 million. As of December 31, 2020 and 2019, $ 5.7 million and $ 52.4 million, respectively, remained accrued and is included as a component of “Accounts payable and accrued liabilities” in the consolidated balance sheets. 
+Ranger Divestiture. In the second quarter of 2019, the Company completed its divestiture of certain non-core assets in the southern Midland Basin (the “Ranger Divestiture”) for net cash proceeds of $ 244.9 million. The transaction also provided for potential additional contingent consideration in payments of up to $ 60.0 million based on West Texas Intermediate average annual pricing over a three-year period. See “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” for further discussion of this contingent consideration arrangement. The divestiture encompasses the Ranger operating area in the southern Midland Basin which included approximately 9,850 net Wolfcamp acres with an average 66 % working interest. The net cash proceeds were recognized as a reduction of evaluated oil and gas properties with no gain or loss recognized as the divestitures did not significantly alter the relationship between capitalized costs and estimated proved reserves. 
+2018 Acquisitions and Divestitures 
+On August 31, 2018, the Company completed the acquisition of approximately 28,000 net surface acres in the Spur operating area, located in the Delaware Basin, from Cimarex Energy Company, for a net cash consideration of approximately $ 539.5 million (the “Delaware Asset Acquisition”). The Company funded the Delaware Asset Acquisition with net proceeds from both the common stock 
+83 
+offering completed on May 30, 2018 and the issuance of the 6.375 % Senior Notes. See “Note 7 - Borrowings” and “Note 11 - Stockholders’ Equity” for further details of these offerings. 
+The Delaware Asset Acquisition was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The following table sets forth the Company’s final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date. 
+Purchase Price Allocation 
+(In thousands) 
+Assets 
+Oil and natural gas properties 
+Evaluated properties $ 253,089 
+Unevaluated properties 287,000 
+Total oil and natural gas properties $ 540,089 
+Total assets acquired $ 540,089 
+Liabilities 
+Asset retirement obligations ($ 570 ) 
+Total liabilities assumed ($ 570 ) 
+Net Assets Acquired $ 539,519 
+Approximately $ 27.3 million of revenues and $ 9.9 million of direct operating expenses attributed to the Delaware Asset Acquisition are included in the Company’s consolidated statements of operations for the period from the closing date on August 31, 2018 through December 31, 2018 . 
+Pro Forma Operating Results (Unaudited). The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the year ended December 31, 2018, assuming the Delaware Asset Acquisition had been completed as of January 1, 2017, including adjustments to reflect the acquisition date fair values assigned to the assets acquired and liabilities assumed. The pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The Company believes the assumptions used provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Delaware Asset Acquisition. 
+Year Ended December 31, 2018 
+(In thousands) 
+Revenues $ 669,236 
+Income from operations 299,090 
+Net income 324,318 
+Basic earnings per common share $ 1.49 
+Diluted earnings per common share $ 1.49 
+Other. In addition, the Company completed various acquisitions of additional working interests and mineral rights, and associated production volumes, in the Company’s existing core operating areas within the Permian. In the first quarter of 2018, the Company completed acquisitions within Monarch and WildHorse operating areas for aggregate net cash consideration of approximately $ 37.8 million. In the fourth quarter of 2018, the Company completed acquisitions of leasehold interests and mineral rights within its WildHorse and Spur operating areas for net cash consideration of approximately $ 87.9 million. 
+The Company did not have any material divestitures for the year ended December 31, 2018. 
+84 
+Note 5 – Property and Equipment, Net 
+As of December 31, 2020 and 2019, total property and equipment, net consisted of the following: 
+As of December 31, 
+2020 2019 
+Oil and natural gas properties, full cost accounting method (In thousands) 
+Evaluated properties $ 7,894,513 $ 7,203,482 
+Accumulated depreciation, depletion, amortization and impairments ( 5,538,803 ) ( 2,520,488 ) 
+Evaluated properties, net 2,355,710 4,682,994 
+Unevaluated properties 
+Unevaluated leasehold and seismic costs 1,532,304 1,843,725 
+Capitalized interest 200,946 142,399 
+Total unevaluated properties 1,733,250 1,986,124 
+Total oil and natural gas properties, net $ 4,088,960 $ 6,669,118 
+Other property and equipment $ 60,287 $ 67,202 
+Accumulated depreciation ( 28,647 ) ( 31,949 ) 
+Other property and equipment, net $ 31,640 $ 35,253 
+The Company capitalized internal costs of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities totaling $ 36.2 million for the years ended December 31, 2020, 2019, and $ 28.0 million for the year ended December 31, 2018, respectively. The Company capitalized interest costs to unproved properties totaling $ 88.6 million, $ 78.5 million and $ 56.2 million for the years ended December 31, 2020, 2019 and 2018, respectively. 
+Impairment of Evaluated Oil and Gas Properties 
+Primarily as a result of the significant reduction in the 12-Month Average Realized Price of crude oil, the Company recognized impairments of evaluated oil and gas properties of $ 2.5 billion for the year December 31, 2020. The Company did not recognize impairments of evaluated oil and gas properties for the years ended December 31, 2019 and 2018. 
+Details of the 12-Month Average Realized Price of crude oil for the years ended December 31, 2020, 2019, and 2018 are summarized in the table below: 
+Years Ended December 31, 
+2020 2019 2018 
+Impairment of evaluated oil and natural gas properties (In thousands) $ 2,547,241 $ — $ — 
+Beginning of period 12-Month Average Realized Price ($/Bbl) $ 53.90 $ 58.40 $ 49.48 
+End of period 12-Month Average Realized Price ($/Bbl) $ 37.44 $ 53.90 $ 58.40 
+Percent increase (decrease) in 12-Month Average Realized Price ( 31 %) ( 8 %) 18 % 
+The Company currently estimates the range of the first quarter of 2021 cost center ceiling, at the high end, would exceed the net book value of oil and gas properties, resulting in no impairment in the carrying value of evaluated oil and gas properties, and at the low end, would result in an impairment in the carrying value of evaluated oil and gas properties of $ 100.0 million. This is based on an estimated 12-Month Average Realized price of crude oil of approximately $ 40.23 per Bbl as of March 31, 2021, which is based on the average realized price for sales of crude oil on the first calendar day of each month for the first 11 months and an estimate for the twelfth month based on a quoted forward price. Declines in the 12-Month Average Realized Price of crude oil in subsequent quarters could result in a lower present value of the estimated future net revenues from proved oil and gas reserves and may result in additional impairments of evaluated oil and gas properties. 
+As a result of the downturn in the oil and gas industry as well as in the broader macroeconomic environment in 2020, the Company analyzed its unevaluated leasehold giving consideration to its updated exploration program as well as to the remaining lease term of certain unevaluated leaseholds. As a result of this analysis, the Company impaired $ 229.6 million unevaluated leasehold costs and transferred to evaluated properties during the year ended December 31, 2020. 
+Unevaluated property costs not subject to amortization as of December 31, 2020 were incurred in the following periods: 
+2020 2019 2018 2017 and Prior Total 
+(In thousands) 
+Unevaluated property costs $ 113,078 $ 680,456 $ 439,478 $ 500,238 $ 1,733,250 
+85 
+Note 6 – Earnings Per Share 
+Basic earnings (loss) per share is computed by dividing income available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings per share includes the potential dilutive impact of non-vested restricted shares and unexercised warrants outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. For the year ended December 31, 2020, the Company reported a loss available to common stockholders. As a result, the calculation of diluted weighted average common shares outstanding excluded all potentially dilutive common shares outstanding. 
+The following table sets forth the computation of basic and diluted earnings per share: 
+Years Ended December 31, 
+2020 2019 2018 
+(In thousands, except per share amounts) 
+Net income (loss) ($ 2,533,621 ) $ 67,928 $ 300,360 
+Preferred stock dividends (1) 
+— ( 3,997 ) ( 7,295 ) 
+Loss on redemption of preferred stock — ( 8,304 ) — 
+Income (loss) available to common stockholders ($ 2,533,621 ) $ 55,627 $ 293,065 
+Basic weighted average common shares outstanding (2) 
+39,718 23,313 21,703 
+Dilutive impact of restricted stock (2) 
+— 27 70 
+Diluted weighted average common shares outstanding (2) 
+39,718 23,340 21,773 
+Income (Loss) Available to Common Stockholders Per Common Share (2) 
+Basic ($ 63.79 ) $ 2.39 $ 13.50 
+Diluted ($ 63.79 ) $ 2.38 $ 13.46 
+Restricted stock (2)(3) 
+581 90 16 
+Warrants (2)(3) 
+2,564 9 0 
+(1) The Company redeemed all outstanding shares of its 10 % Series A Cumulative Preferred Stock (“Preferred Stock”) on July 18, 2019 and all dividends ceased to accrue upon redemption. 
+(2) Shares and per share data have been retroactively adjusted to reflect the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 – Stockholders’ Equity” for additional information. 
+(3) Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive. 
+86 
+Note 7 – Borrowings 
+The Company’s borrowings consisted of the following: 
+As of December 31, 
+2020 2019 
+(In thousands) 
+Senior Secured Revolving Credit Facility due 2024 $ 985,000 $ 1,285,000 
+9.00 % Second Lien Senior Secured Notes due 2025 
+516,659 — 
+6.25 % Senior Notes due 2023 
+542,720 650,000 
+6.125 % Senior Notes due 2024 
+460,241 600,000 
+8.25 % Senior Notes due 2025 
+187,238 250,000 
+6.375 % Senior Notes due 2026 
+320,783 400,000 
+Total principal outstanding 3,012,641 3,185,000 
+Unamortized discount on Second Lien Notes ( 41,820 ) — 
+Unamortized premium for 6.25 % Senior Notes 
+2,917 4,838 
+Unamortized premium for 6.125 % Senior Notes 
+3,236 5,344 
+Unamortized premium for 8.25 % Senior Notes 
+3,240 5,286 
+Unamortized deferred financing costs for Second Lien Notes ( 3,931 ) — 
+Unamortized deferred financing costs for Senior Notes ( 7,019 ) ( 14,359 ) 
+Total carrying value of borrowings (1) 
+$ 2,969,264 $ 3,186,109 
+(1) Excludes unamortized deferred financing costs related to the Company’s Credit Facility of $ 23.6 million and $ 22.2 million as of December 31, 2020 and 2019, respectively, which are classified in “Deferred financing costs” in the consolidated balance sheets. 
+Senior Secured Revolving Credit Facility 
+On December 20, 2019, upon consummation of the Merger, the Company entered into the senior secured revolving credit facility with a syndicate of lenders (the “Credit Facility”). The credit agreement governing the Credit Facility provides for interest-only payments until December 20, 2024 (subject to springing maturity dates of (i) January 14, 2023 if the 6.25 % Senior Notes due 2023 (the “ 6.25 % Senior Notes”) are outstanding at such time, (ii) July 2, 2024 if the 6.125 % Senior Notes due 2024 (the “ 6.125 % Senior Notes”) are outstanding at such time, and (iii) if the Second Lien Notes, defined below, are outstanding at such time, the date which is 182 days prior to the maturity of any of the 6.25 % Senior Notes or the 6.125 % Senior Notes, in each case, to the extent a principal amount of more than $ 100.0 million with respect to each such issuance is outstanding as of such date), when the Credit Facility matures and any outstanding borrowings are due. The maximum credit amount under the Credit Facility is $ 5.0 billion. 
+On December 31, 2020, the borrowing base and the elected commitment amount under the revolving credit facility was $ 1.6 billion, with borrowings outstanding of $ 985.0 million at a weighted average interest rate of 2.73 %, and letters of credit outstanding of $ 25.2 million. The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. The capitalized terms which are not defined in this description of the Credit Facility shall have the meaning given to such terms in the credit agreement. 
+On May 7, 2020, the Company entered into the first amendment to its credit agreement governing the Credit Facility. The amendment included, but was not limited to the following: 
+• Established a new borrowing base as a result of the spring 2020 scheduled redetermination in the amount of $ 1.7 billion and reduced the elected commitments to $ 1.7 billion, which were subsequently revised as described below; 
+• Permits the incurrence of, among other things, new second lien notes in 2020 exchanged for unsecured notes in an aggregate principal amount of up to $ 400.0 million without triggering a reduction in the borrowing base so long as any such second lien notes are subject to an intercreditor agreement providing that the liens securing the second lien notes rank junior to the liens securing the credit agreement; 
+• Provides that testing of the Leverage Ratio is suspended until March 31, 2022, as of which testing date and the last day of each fiscal quarter ending thereafter, such ratio may not exceed 4.00 to 1.00; 
+• Provides for testing of the Secured Leverage Ratio that may not exceed 3.00 to 1.00 on a quarterly basis beginning with the quarter ended March 31, 2020 through the quarter ending December 31, 2021; and 
+• Provided that the testing of the Current Ratio was suspended until September 30, 2020, as of which testing date and the last day of each fiscal quarter ending thereafter, such ratio may not be less than 1.00 to 1.00 
+On September 30, 2020, the Company entered into the second amendment to its credit agreement governing the Credit Facility. The amendment, among other things, reaffirmed the $ 1.7 billion borrowing base as a result of the fall 2020 scheduled redetermination. 
+87 
+Also on September 30, 2020, the Company entered into the third amendment to its credit agreement governing the Credit Facility. The amendment included, but was not limited to the following: 
+• Established a new borrowing base of $ 1.6 billion and reduced the elected commitments to $ 1.6 billion in connection with the issuance of the September 2020 Second Lien Notes and September 2020 Warrants, described below, and the ORRI Transaction; 
+• Permitted the issuance of the $ 300.0 million of September 2020 Second Lien Notes as contemplated by the Purchase Agreement, described below, without triggering a reduction in the borrowing base; 
+• Extends through the end of 2021 the time period during which second lien notes issued in exchange for unsecured notes may be issued without triggering a reduction in the borrowing base; and 
+• If the Second Lien Notes are outstanding at such time, caused the maturity of the Credit Facility to spring forward to a date which is 182 days prior to the maturity of any of the 6.25 % Senior Notes or the 6.125 % Senior Notes, in each case, to the extent a principal amount of more than $ 100.0 million with respect to each such issuance is outstanding as of such date. 
+Borrowings outstanding under the credit agreement bear interest at the Company’s option at either (i) a base rate for a base rate loan plus a margin between 1.00 % to 2.00 %, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.50 % and the adjusted LIBO rate plus 1.00 %, or (ii) an adjusted LIBO rate for a Eurodollar loan plus a margin between 2.00 % to 3.00 %. The Company also incurs commitment fees at rates ranging between 0.375 % to 0.500 % on the unused portion of lender commitments, which are included in “Interest expense, net” in the consolidated statements of operations. 
+The Company terminated the Sixth Amended and Restated Credit Agreement to the Credit Facility (the “Prior Credit Facility”), which was entered into on May 25, 2017, upon entering into the Credit Facility described above. As a result of terminating the Prior Credit Facility, the Company recorded a loss on extinguishment of debt of $ 4.9 million, which was comprised solely of the write-off of unamortized deferred financing costs associated with the Prior Credit Facility. 
+Second Lien Notes 
+On September 30, 2020, the Company entered into a Purchase Agreement (the “Purchase Agreement”) where it issued (i) $ 300.0 million in aggregate principal amount of its 9.00 % Second Lien Senior Secured Notes due 2025 (the “September 2020 Second Lien Notes”) and (ii) warrants for 7.3 million shares of the Company’s common stock, with a term of five years and an exercise price of $ 5.60 per share, exercisable only on a net share settlement basis (the “September 2020 Warrants”), for aggregate consideration of $ 294.0 million. The Company used the proceeds, net of issuance costs, of approximately $ 288.6 million to repay borrowings outstanding under the Credit Facility. The Company also entered into a registration rights agreement with the purchaser of the September 2020 Second Lien Notes. 
+Net proceeds were allocated to the September 2020 Warrants based on their fair value on the date of issuance with the remaining net proceeds allocated to the September 2020 Second Lien Notes. The fair value of the September 2020 Warrants was calculated by a third-party valuation specialist using a Black-Scholes-Merton option pricing model, incorporating the following assumptions at the issuance date: 
+Issuance Date Fair Value Assumptions 
+Exercise price $ 5.60 
+Expected term (in years) 5.0 
+Expected volatility 116.3 % 
+Risk-free interest rate 0.3 % 
+Dividend yield — % 
+See “Note 9 - Fair Value Measurements” for further discussion. 
+The September 2020 Second Lien Notes will mature on the earlier of (i) April 1, 2025 and (ii) 91 days prior to the maturity date of any outstanding unsecured notes in a principal amount at or greater than $ 100.0 million and have interest payable semi-annually each April 1 and October 1, commencing on April 1, 2021. 
+The Company may redeem the September 2020 Second Lien Notes in accordance with the following terms: (1) prior to October 1, 2022, a redemption of up to 35 % of the principal in an amount not greater than the net proceeds from certain equity offerings, and within 180 days of the closing date of such equity offerings, at a redemption price of 109.00 % of principal, plus accrued and unpaid interest, if any, to, but excluding, the date of redemption, if at least 65 % of the principal will remain outstanding after such redemption; (2) prior to October 1, 2022, a redemption of all or part of the principal at a price of 100 % of the principal amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to, but excluding, the date of redemption; and (3) subsequent to October 1, 2022, a redemption, in whole or in part, at redemption prices decreasing annually from 105.00 % to 100 % of the principal amount redeemed plus accrued and unpaid interest. 
+88 
+Upon the occurrence of certain change of control events, each holder of the September 2020 Second Lien Notes may require the Company to repurchase all or a portion of the September 2020 Second Lien Notes at a price of 101 % of the principal amount repurchased, plus accrued and unpaid interest, if any, to, but excluding, the date of repurchase. 
+Senior Unsecured Notes Exchange 
+On November 2, 2020, the Company entered into an Exchange Agreement (the “Exchange Agreement”) by and among the Company and certain holders (the “Holders”) of the Company’s 6.25 % Senior Notes, 6.125 % Senior Notes, 8.25 % Senior Notes, and 6.375 % Senior Notes (each as defined in this footnote and together the “Senior Unsecured Notes”). Upon closing on November 13, 2020, pursuant to the Exchange Agreement, the Company agreed to exchange $ 389.0 million of aggregate principal amount of the Senior Unsecured Notes held by the Holders for $ 216.7 million aggregate principal amount of newly issued 9.00 % Second Lien Senior Secured Notes due 2025 (the “November 2020 Second Lien Notes” and together with the September 2020 Second Lien Notes the “Second Lien Notes”) at a weighted average exchange ratio of approximately $ 557 per $1,000 of principal exchanged. The November 2020 Second Lien Notes were issued under the Company’s indenture dated as of September 30, 2020. Pursuant to the Exchange Agreement, the Company also agreed to issue to the Holders warrants for approximately 1.75 million shares of the Company’s common stock, with a term of five years and an exercise price of $ 5.60 per share, exercisable only on a net share settlement basis (the “November 2020 Warrants”). 
+The Company assessed the debt exchange to determine whether it should be accounted for pursuant to Financial Accounting Standards Board’s Accounting Standard Codification (“ASC”) Topic 470-60, Troubled Debt Restructurings by Debtors, or pursuant to ASC Topic 470-50, Modifications and Extinguishments (“ASC 470-50”). This assessment requires judgments to be made with respect to whether or not an entity is experiencing financial difficulty. It was determined that the Company was not experiencing financial difficulty and could obtain funds at market rates similar to other non-troubled debtors, therefore the Company accounted for the exchange as an extinguishment of debt in accordance with ASC 470-50. As the November 2020 Second Lien Notes were issued with the November 2020 Warrants, the $ 216.7 million aggregate principal amount was allocated between the November 2020 Second Lien Notes and the November 2020 Warrants based on their relative fair values at the exchange date. This resulted in $ 207.6 million allocated to the November 2020 Second Lien Notes and $ 9.1 million allocated to the November 2020 Warrants. The Company recognized a gain on the extinguishment of debt of $ 170.4 million in its consolidated statement of operations, which consisted of the carrying values of the Senior Unsecured Notes exchanged less the aggregate principal amount of the November 2020 Second Lien Notes issued, net of the associated debt discount of $ 9.1 million, which was based on the November 2020 Second Lien Notes’ allocated fair value on the exchange date. 
+The fair value of the November 2020 Second Lien Notes was calculated by a third-party valuation specialist using a discounted cash flow model. Significant inputs into the calculation included the redemption premiums, described below, as well as redemption assumptions provided by the Company. The fair value of the November 2020 Warrants was calculated using a Black-Scholes-Merton option pricing model, incorporating the following assumptions at the issuance date: 
+Issuance Date Fair Value Assumptions 
+Exercise price $ 5.60 
+Expected term (in years) 4.9 
+Expected volatility 98.4 % 
+Risk-free interest rate 0.4 % 
+Dividend yield — % 
+Senior Unsecured Notes 
+6.25 % Senior Notes. The Company’s 6.25 % Senior Notes, which were assumed upon consummation of the Merger, mature on April 15, 2023 and have interest payable semi-annually each April 15 and October 15. The Company may redeem all or a portion of the 6.25 % Senior Notes at redemption prices decreasing from 103.125 % to 100 % of the principal amount on April 15, 2021, plus accrued and unpaid interest. Following a change of control, each holder of the 6.25 % Senior Notes may require the Company to repurchase the 6.25 % Senior Notes for cash at a price equal to 101 % of the principal amount purchased, plus any accrued and unpaid interest. 
+6.125 % Senior Notes. The Company’s 6.125 % Senior Notes mature on October 1, 2024 and have interest payable semi-annually each April 1 and October 1. The Company may redeem all or a portion of the 6.125 % Senior Notes at redemption prices decreasing from 104.594 % to 100 % of the principal amount on October 1, 2022, plus accrued and unpaid interest. Following a change of control, each holder of the 6.125 % Senior Notes may require the Company to repurchase all or a portion of the 6.125 % Senior Notes at a price of 101 % of principal of the amount repurchased, plus accrued and unpaid interest. 
+8.25 % Senior Notes. The Company’s 8.25 % Senior Notes due 2025 (the “8.25% Senior Notes”), which were assumed upon consummation of the Merger, mature on July 15, 2025 and have interest payable semi-annually each January 15 and July 15. Since July 15, 2020, the Company may redeem all or a portion of the 8.25 % Senior Notes at redemption prices decreasing annually from 106.188 % to 100 % of the principal amount redeemed plus accrued and unpaid interest. Following a change of control, each holder of 
+89 
+the 8.25 % Senior Notes may require the Company to repurchase the 8.25 % Senior Notes for cash at a price equal to 101 % of the principal amount purchased, plus any accrued and unpaid interest. 
+6.375 % Senior Notes. On June 7, 2018, the Company issued $ 400.0 million aggregate principal amount of 6.375 % Senior Notes due 2026 (the “ 6.375 % Senior Notes”), which mature on July 1, 2026 and have interest payable semi-annually each January 1 and July 1. The Company used the net proceeds from the offering of approximately $ 394.0 million, after deducting initial purchasers’ discounts and estimated offering expenses, to fund a portion of the Delaware Asset Acquisition described above. 
+The Company may redeem the 6.375 % Senior Notes in accordance with the following terms: (1) prior to July 1, 2021, a redemption of up to 35 % of the principal in an amount not greater than the net proceeds from certain equity offerings, and within 180 days of the closing date of such equity offerings, at a redemption price of 106.375 % of principal, plus accrued and unpaid interest, if any, to the date of the redemption, if at least 65 % of the principal will remain outstanding after such redemption; (2) prior to July 1, 2021, a redemption of all or part of the principal at a price of 100 % of principal of the amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of the redemption; and (3) subsequent to July 1, 2021, a redemption, in whole or in part, at redemption prices decreasing annually from 103.188 % to 100 % of the principal amount redeemed plus accrued and unpaid interest. Following a change of control, each holder of the 6.375 % Senior Notes may require the Company to repurchase all or a portion of the 6.375 % Senior Notes at a price of 101 % of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase. 
+Each of the Senior Unsecured Notes described above are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The subsidiary guarantor is 100 % owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor. 
+Restrictive covenants 
+The Company’s credit agreement contains certain covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. 
+Under the credit agreement, the Company must maintain the following financial covenants determined as of the last day of the quarter, each as described above: (1) a Secured Leverage Ratio of no more than 3.00 to 1.00 and (2) a Current Ratio of not less than 1.00 to 1.00. The Company was in compliance with these covenants at December 31, 2020. 
+The credit agreement and the indentures governing our Senior Unsecured Notes also place restrictions on the Company and certain of its subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters. 
+The credit agreement and indentures are subject to customary events of default. If an event of default occurs and is continuing, the holders or lenders may elect to accelerate amounts due (except in the case of a bankruptcy event of default, in which case such amounts will automatically become due and payable). 
+Note 8 – Derivative Instruments and Hedging Activities 
+Objectives and strategies for using derivative instruments 
+The Company is exposed to fluctuations in oil, natural gas and NGL prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil, natural gas and NGL production. The Company utilizes a mix of collars, swaps, and put and call options to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes. 
+Counterparty risk and offsetting 
+The Company typically has numerous commodity derivative instruments outstanding with a counterparty that were executed at various dates, for various contract types, commodities and time periods. This often results in both commodity derivative asset and liability positions with that counterparty. The Company nets its commodity derivative instrument fair values executed with the same counterparty to a single asset or liability pursuant to International Swap Dealers Association Master Agreements (“ISDA Agreements”), which provide for net settlement over the term of the contract and in the event of default or termination of the contract. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement. 
+As of December 31, 2020, the Company has outstanding commodity derivative instruments with sixteen counterparties to minimize its credit exposure to any individual counterparty. All of the counterparties to the Company’s commodity derivative instruments are also lenders under the Company’s credit agreement. Therefore, each of the Company’s counterparties allow the Company to satisfy any 
+90 
+need for margin obligations associated with commodity derivative instruments where the Company is in a net liability position with the collateral securing the credit agreement, thus eliminating the need for independent collateral posting. 
+Because each of the Company’s counterparties has an investment grade credit rating, the Company believes it does not have significant credit risk and accordingly does not currently require its counterparties to post collateral to support the net asset positions of its commodity derivative instruments. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each counterparty. 
+While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument. See “Note 9 - Fair Value Measurements” for further discussion. 
+Financial statement presentation and settlements 
+Settlements of the Company’s commodity derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets. See “Note 9 - Fair Value Measurements” for additional information regarding fair value. 
+Contingent consideration arrangements 
+Ranger Divestiture. The Company’s Ranger Divestiture provides for potential contingent consideration to be received by the Company if commodity prices exceed specified thresholds for the next year. See “Note 4 - Acquisitions and Divestitures” and “Note 9 - Fair Value Measurements” for further discussion. This contingent consideration arrangement is summarized in the table below (in thousands except for per Bbl amounts): 
+Year 
+Threshold (1) 
+Contingent 
+Receipt - 
+Annual 
+Threshold (1) 
+Contingent 
+Receipt - 
+Annual Period 
+Cash Flow 
+Occurs Statement of 
+Cash Flows Presentation 
+Remaining Contingent 
+Receipt - 
+Aggregate Limit (3) 
+Remaining Potential Settlement 2021 
+Greater than $ 60 /Bbl, less than $ 65 /Bbl 
+$ 9,000 
+Equal to or greater than $ 65 /Bbl 
+$ 20,833 
+(2) 
+(2) 
+$ 20,833 
+(1) The price used to determine whether the specified thresholds have been met is the average of the final monthly settlements for each month during each annual period end for NYMEX Light Sweet Crude Oil Futures, as reported by the CME Group Inc. 
+(2) Cash received for settlements of contingent consideration arrangements are classified as cash flows from financing activities up to the divestiture date fair value with any excess classified as cash flows from operating activities. Therefore, if the commodity price threshold is reached, $ 8.5 million of the next contingent receipt will be presented in cash flows from financing activities with the remainder presented in cash flows from operating activities. 
+(3) The specified pricing threshold for both 2019 and 2020 was not met. As such, approximately $ 20.8 million remains for potential settlements in future years. 
+As a result of the Carrizo Acquisition, the Company assumed all contingent consideration arrangements previously entered into by Carrizo. These contingent consideration arrangements are summarized below: 
+Contingent ExL Consideration 
+Year 
+Threshold (1) 
+Period 
+Cash Flow 
+Occurs Statement of 
+Cash Flows Presentation Contingent 
+Payment - 
+Annual Remaining Contingent 
+Payments - 
+Aggregate Limit 
+(In thousands) 
+Remaining Potential Settlement 2021 $ 50.00 
+(2) 
+(2) 
+($ 25,000 ) ($ 25,000 ) 
+(3) 
+(1) The price used to determine whether the specified threshold for each year has been met is the average daily closing spot price per barrel of WTI crude oil as measured by the U.S. Energy Information Administration (“U.S. EIA”). 
+(2) Cash paid for settlements of contingent consideration arrangements are classified as cash flows from investing activities up to the acquisition date fair value with any excess classified as cash flows from operating activities. In January 2020, the Company paid $ 50.0 million as the specified pricing threshold for 2019 was met. Therefore, if the commodity price threshold is reached in 2021, $ 19.2 million of the next contingent payment will be presented in cash flows from investing activities with the remainder presented in cash flows from operating activities. 
+(3) The specified pricing threshold for 2020 was not met. Only $ 25.0 million remains for potential settlements in future years. 
+91 
+Additionally, as part of the Carrizo Acquisition, the Company acquired other contingent consideration arrangements where the Company could receive payments if certain pricing thresholds were met in 2019 and 2020, which ranged between $ 53.00 - $ 60.00 per barrel of oil or $ 3.18 - $ 3.30 per MMBtu of natural gas. The specified pricing thresholds for each of these other contingent consideration arrangements for 2020 were not met, therefore there were no payments from the contingent consideration arrangements acquired in the Carrizo Acquisition in January 2021. In January 2020, the Company received $ 10.0 million as the specified pricing thresholds for 2019 were met for certain of the contingent consideration arrangements. These cash receipts are classified as cash flows from investing activities in the consolidated statements of cash flows. Each of these other contingent consideration arrangements acquired in the Carrizo Acquisition expired at the end of the 2020. 
+Warrants 
+The Company determined that the September 2020 Warrants issued with the September 2020 Second Lien Notes are required to be accounted for as a derivative instrument. The September 2020 Warrants are exercisable only on a net share settlement basis. The Company records the September 2020 Warrants as a liability on its consolidated balance sheet measured at fair value as a component of “Fair value of derivatives” with gains and losses as a result of changes in the fair value of the September 2020 Warrants recorded as “(Gain) loss on derivative contracts” in the consolidated statements of operations in the period in which the changes occur. Upon issuance, the Company recorded a liability for the September 2020 Warrants of $ 23.9 million and as of December 31, 2020, the liability for the September 2020 Warrants was $ 79.4 million. See “Note 18 - Subsequent Events” for further discussion. 
+Derivatives not designated as hedging instruments 
+The Company records its derivative instruments at fair value in the consolidated balance sheets and records changes in fair value as “(Gain) loss on derivative contracts” in the consolidated statements of operations. Settlements are also recorded as a gain or loss on derivative contracts in the consolidated statements of operations. As previously discussed, the Company’s commodity derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated: 
+As of December 31, 2020 
+Presented without As Presented with 
+Effects of Netting Effects of Netting Effects of Netting 
+(In thousands) 
+Assets 
+Commodity derivative instruments $ 21,156 ($ 20,235 ) $ 921 
+Contingent consideration arrangements — — — 
+Fair value of derivatives - current $ 21,156 ($ 20,235 ) $ 921 
+Commodity derivative instruments $ — $ — $ — 
+Contingent consideration arrangements 1,816 — 1,816 
+Other assets, net $ 1,816 $ — $ 1,816 
+Liabilities 
+Commodity derivative instruments ($ 117,295 ) $ 20,235 ($ 97,060 ) 
+Contingent consideration arrangements — — — 
+Fair value of derivatives - current ($ 117,295 ) $ 20,235 ($ 97,060 ) 
+Commodity derivative instruments $ — $ — $ — 
+Contingent consideration arrangements ( 8,618 ) — ( 8,618 ) 
+September 2020 Warrants liability ( 79,428 ) — ( 79,428 ) 
+Fair value of derivatives - non current ($ 88,046 ) $ — ($ 88,046 ) 
+92 
+As of December 31, 2019 
+Presented without As Presented with 
+Effects of Netting Effects of Netting Effects of Netting 
+(In thousands) 
+Assets 
+Commodity derivative instruments $ 26,849 ($ 17,511 ) $ 9,338 
+Contingent consideration arrangements 16,718 — 16,718 
+Fair value of derivatives - current $ 43,567 ($ 17,511 ) $ 26,056 
+Commodity derivative instruments $ — $ — $ — 
+Contingent consideration arrangements 9,216 — 9,216 
+Other assets, net $ 9,216 $ — $ 9,216 
+Liabilities 
+Commodity derivative instruments ($ 38,708 ) $ 17,511 ($ 21,197 ) 
+Contingent consideration arrangements ( 50,000 ) — ( 50,000 ) 
+Fair value of derivatives - current ($ 88,708 ) $ 17,511 ($ 71,197 ) 
+Commodity derivative instruments ($ 12,935 ) — ($ 12,935 ) 
+Contingent consideration arrangements ( 19,760 ) — ( 19,760 ) 
+Fair value of derivatives - non current ($ 32,695 ) $ — ($ 32,695 ) 
+The components of “(Gain) loss on derivative contracts” are as follows for the respective periods: 
+Years Ended December 31, 
+2020 2019 2018 
+(In thousands) 
+(Gain) loss on oil derivatives ($ 48,031 ) $ 73,313 ($ 45,463 ) 
+(Gain) loss on natural gas derivatives 14,883 ( 8,889 ) ( 3,081 ) 
+(Gain) loss on NGL derivatives 2,426 — — 
+(Gain) loss on contingent consideration arrangements 2,976 ( 2,315 ) — 
+(Gain) loss on September 2020 Warrants liability 55,519 — — 
+(Gain) loss on derivative contracts $ 27,773 $ 62,109 ($ 48,544 ) 
+The components of “Cash (paid) received for commodity derivative settlements” and “Cash paid for settlements of contingent consideration arrangements, net” are as follows for the respective periods: 
+Years Ended December 31, 
+2020 2019 2018 
+(In thousands) 
+Cash flows from operating activities 
+Cash (paid) received on oil derivatives $ 98,723 ($ 11,188 ) ($ 27,510 ) 
+Cash (paid) received on natural gas derivatives 147 7,399 238 
+Cash (paid) received for commodity derivative settlements $ 98,870 ($ 3,789 ) ($ 27,272 ) 
+Cash flows from investing activities 
+Cash paid for settlements of contingent consideration arrangements, net ($ 40,000 ) $ — $ — 
+93 
+Derivative positions 
+Listed in the tables below are the outstanding oil, natural gas and NGL derivative contracts as of December 31, 2020: 
+For the Full Year of 
+Oil contracts (WTI) 2021 
+Swap contracts 
+Total volume (Bbls) 1,827,000 
+Weighted average price per Bbl $ 43.54 
+Collar contracts 
+Total volume (Bbls) 10,282,775 
+Weighted average price per Bbl 
+Ceiling (short call) $ 46.69 
+Floor (long put) $ 39.28 
+Short call contracts 
+Total volume (Bbls) 4,825,300 (1) 
+Weighted average price per Bbl $ 63.62 
+Short call swaption contracts 
+Total volume (Bbls) 1,375,000 (2) 
+Weighted average price per Bbl $ 49.01 
+Oil contracts (ICE Brent) 
+Swap contracts 
+Total volume (Bbls) 848,300 
+Weighted average price per Bbl $ 37.36 
+Collar contracts 
+Total volume (Bbls) 730,000 
+Weighted average price per Bbl 
+Ceiling (short call) $ 50.00 
+Floor (long put) $ 45.00 
+Oil contracts (Midland basis differential) 
+Swap contracts 
+Total volume (Bbls) 3,022,900 
+Weighted average price per Bbl $ 0.26 
+Oil contracts (Argus Houston MEH) 
+Swap contracts 
+Total volume (Bbls) 450,000 
+Weighted average price per Bbl $ 46.50 
+Collar contracts 
+Total volume (Bbls) 409,500 
+Weighted average price per Bbl 
+Ceiling (short call) $ 47.00 
+Floor (long put) $ 41.00 
+(1) Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars. 
+(2) The short call swaption contracts have exercise expiration dates as follows: 455,000 Bbls expire on March 31, 2021, 460,000 Bbls expire on June 30, 2021 and 460,000 Bbls expire on September 30, 2021. 
+94 
+For the Full Year of 
+Natural gas contracts (Henry Hub) 2021 
+Swap contracts 
+Total volume (MMBtu) 11,123,000 
+Weighted average price per MMBtu $ 2.60 
+Collar contracts (three-way collars) 
+Total volume (MMBtu) 1,350,000 
+Weighted average price per MMBtu 
+Ceiling (short call) $ 2.70 
+Floor (long put) $ 2.42 
+Floor (short put) $ 2.00 
+Collar contracts (two-way collars) 
+Total volume (MMBtu) 9,550,000 
+Weighted average price per MMBtu 
+Ceiling (short call) $ 3.04 
+Floor (long put) $ 2.59 
+Short call contracts 
+Total volume (MMBtu) 7,300,000 (1) 
+Weighted average price per MMBtu $ 3.09 
+Natural gas contracts (Waha basis differential) 
+Swap contracts 
+Total volume (MMBtu) 16,425,000 
+Weighted average price per MMBtu ($ 0.42 ) 
+(1) Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars. 
+For the Full Year of 
+NGL contracts (OPIS Mont Belvieu Purity Ethane) 2021 
+Swap contracts 
+Total volume (Bbls) 1,825,000 
+Weighted average price per Bbl $ 7.62 
+Note 9 – Fair Value Measurements 
+Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: 
+Level 1 – Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities. 
+Level 2 – Other inputs that are observable directly or indirectly such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. 
+Level 3 – Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities. 
+Fair value of financial instruments 
+Cash, cash equivalents, and restricted investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments. 
+Debt. The carrying amount of borrowings outstanding under the Credit Facility approximates fair value as the borrowings bear interest at variable rates and are reflective of market rates. As of December 31, 2020, the Company determined that its Second Lien Notes met the requirements to be designated as Level 2 in the valuation hierarchy due to the availability of quoted secondary market trading prices resulting in the transfer out of Level 3. The following table presents the principal amounts of the Company’s Second Lien Notes 
+95 
+and Senior Unsecured Notes with the fair values measured using quoted secondary market trading prices which are designated as Level 2 within the valuation hierarchy. See “Note 7 - Borrowings” for further discussion. 
+December 31, 2020 December 31, 2019 
+Principal Amount Fair Value Principal Amount Fair Value 
+(In thousands) 
+9.00% Second Lien Senior Secured Notes $ 516,659 $ 470,160 $ — $ — 
+6.25% Senior Notes 
+542,720 344,627 650,000 658,125 
+6.125% Senior Notes 460,241 260,036 600,000 611,130 
+8.25% Senior Notes 187,238 100,172 250,000 256,250 
+6.375% Senior Notes 320,783 161,995 400,000 405,424 
+Total $ 2,027,641 $ 1,336,990 $ 1,900,000 $ 1,930,929 
+Assets and liabilities measured at fair value on a recurring basis 
+Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheet. The following methods and assumptions were used to estimate fair value: 
+Commodity derivative instruments. The fair value of commodity derivative instruments is derived using a third-party income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the commodity derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for commodity derivative assets and an estimate of the Company’s default risk for commodity derivative liabilities. As the inputs in the model are substantially observable over the term of the commodity derivative contract and there is a wide availability of quoted market prices for similar commodity derivative contracts, the Company designates its commodity derivative instruments as Level 2 within the fair value hierarchy. See “Note 8 - Derivative Instruments and Hedging Activities” for further discussion. 
+Contingent consideration arrangements - embedded derivative financial instruments. The embedded options within the contingent consideration arrangements are considered financial instruments under ASC 815. The Company engages a third-party valuation specialist using an option pricing model approach to measure the fair value of the embedded options on a recurring basis. The valuation includes significant inputs such as forward oil price curves, time to expiration, and implied volatility. The model provides for the probability that the specified pricing thresholds would be met for each settlement period, estimates undiscounted payouts, and risk adjusts for the discount rates inclusive of adjustments for each of the counterparty’s credit quality. As these inputs are substantially observable for the full term of the contingent consideration arrangements, the inputs are considered Level 2 inputs within the fair value hierarchy. See “Note 8 - Derivative Instruments and Hedging Activities” for further discussion. 
+96 
+The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2020 and 2019: 
+December 31, 2020 
+Level 1 Level 2 Level 3 
+(In thousands) 
+Assets 
+Commodity derivative instruments $ — $ 921 $ — 
+Contingent consideration arrangements — 1,816 — 
+Liabilities 
+Commodity derivative instruments — ( 97,060 ) — 
+Contingent consideration arrangements — ( 8,618 ) — 
+September 2020 Warrants — — ( 79,428 ) 
+Total net assets (liabilities) $ — ($ 102,941 ) ($ 79,428 ) 
+December 31, 2019 
+Level 1 Level 2 Level 3 
+(In thousands) 
+Assets 
+Commodity derivative instruments $ — $ 9,338 $ — 
+Contingent consideration arrangements — 25,934 — 
+Liabilities 
+Commodity derivative instruments — ( 34,132 ) — 
+Contingent consideration arrangements — ( 69,760 ) — 
+Total net liabilities (liabilities) $ — ($ 68,620 ) $ — 
+September 2020 Warrants. The fair value of the September 2020 Warrants was calculated by a third-party valuation specialist using a Black-Scholes-Merton option pricing model. As historical volatility is a significant input into the model, the September 2020 Warrants are designated as Level 3 within the valuation hierarchy. See “Note 7 - Borrowings” and “Note 8 - Derivative Instruments and Hedging Activities” for additional details regarding the September 2020 Warrants. 
+The following table presents a reconciliation of the change in the fair value of the liability related to the September 2020 Warrants for the year ended December 31, 2020. 
+Year Ended December 31, 2020 
+(In thousands) 
+Beginning of period $ — 
+Recognition of issuance date fair value 23,909 
+(Gain) loss on changes in fair value 55,519 
+Transfers into (out of) Level 3 — 
+End of period $ 79,428 
+Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis 
+Acquisitions. The fair value of assets acquired and liabilities assumed, other than the contingent consideration arrangements which are discussed above, are measured as of the acquisition date by a third-party valuation specialist using a combination of income and market approaches, which are not observable in the market and are therefore designated as Level 3 inputs. Significant inputs include expected discounted future cash flows from estimated reserve quantities, estimates for timing and costs to produce and develop reserves, oil and natural gas forward prices, and a risk adjusted discount rate. See “Note 4 - Acquisitions and Divestitures” for additional discussion. 
+Asset retirement obligations. The Company measures the fair value of asset retirement obligations as of the date a well begins drilling or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 within the valuation hierarchy. Significant inputs to the fair value measurement of asset retirement obligations include estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates. See “Note 14 - Asset Retirement Obligations” for additional discussion. 
+97 
+Note 10 – Share-Based Compensation 
+All share and per share numbers included in this footnote, except for those disclosed in “— 2018 Omnibus Incentive Plan” below, have been adjusted for the reverse stock split. See “Note 11 - Stockholders’ Equity” for discussion of the reverse stock split and reduction in authorized shares. 
+2020 Omnibus Incentive Plan 
+At the Company’s annual meeting of shareholders on June 8, 2020, shareholders approved the 2020 Omnibus Incentive Plan (the “2020 Plan”), which replaced the 2018 Omnibus Incentive Plan (the “2018 Plan”). From the effective date of the 2020 Plan, no further awards may be granted under the 2018 Plan, however, awards previously granted under the 2018 Plan will remain outstanding in accordance with their terms. Effective August 7, 2020, in connection with the reverse stock split and reduction in authorized shares, the Board of Directors approved and adopted an amendment to the 2020 Plan to proportionately adjust the limitations on awards that may be granted. At December 31, 2020, there were 2,002,463 shares available for future share-based awards under the 2020 Plan. 
+2018 Omnibus Incentive Plan 
+The 2018 Plan, which became effective May 10, 2018 following shareholder approval, authorized and reserved for issuance 9,400,000 shares of common stock, which may be issued upon exercise of vested stock options and/or the vesting of any other share-based equity award that is granted under this plan. The 2018 Plan replaced the 2011 Omnibus Incentive Plan (the “Prior Plan”), and included a provision at inception whereby all remaining, un-issued and authorized shares from the Prior Plan became issuable under the 2018 Plan. This transfer provision resulted in the transfer of an additional 1,322,742 shares into the 2018 Plan, increasing the quantity authorized and reserved for issuance under the 2018 Plan to 10,722,742 at the inception of the 2018 Plan. Another provision provided that shares, which would otherwise become available for issuance under the Prior Plan as a result of vesting and/or forfeiture of any equity awards existing as of the effective date of the 2018 Plan, would also increase the authorized shares available to the 2018 Plan. As a result of the Merger, the 2018 Plan was amended and restated to incorporate the 2017 Incentive Plan of Carrizo Oil & Gas, Inc. (the “Carrizo Plan”), including outstanding awards under the Carrizo Plan and shares available to grant to the former employees of Carrizo which were converted to shares of the Company by applying the conversion ratio of 1.75 shares of the Company per one share of Carrizo (the “Amended and Restated 2018 Plan”). 
+RSU Equity Awards 
+The following table summarizes RSU Equity Award activity for the years ended December 31, 2020, 2019 and 2018: 
+RSU Equity Awards (in thousands) Weighted Average Grant-Date Fair Value per Share 
+For the Year Ended December 31, 2018 
+Unvested at the beginning of the period 179 $ 115.36 
+Granted (1) 
+87 $ 144.86 
+Vested (2) 
+( 51 ) $ 103.83 
+Forfeited ( 5 ) $ 114.32 
+Unvested at the end of the period 210 $ 130.39 
+For the Year Ended December 31, 2019 
+Unvested at the beginning of the period 210 $ 130.39 
+Granted (1) 
+188 $ 85.96 
+Vested (2) 
+( 106 ) $ 126.75 
+Forfeited ( 23 ) $ 110.55 
+Unvested at the end of the period 269 $ 102.48 
+For the Year Ended December 31, 2020 
+Unvested at the beginning of the period 269 $ 102.48 
+Granted (1) 
+562 $ 21.07 
+Vested (2) 
+( 132 ) $ 105.14 
+Forfeited ( 22 ) $ 96.84 
+Unvested at the end of the period 677 $ 34.57 
+(1) Includes 111.2 thousand, 39.9 thousand and 20.8 thousand target performance-based RSU Equity Awards for the years ended December 31, 2020, 2019 and 2018, respectively. 
+(2) The fair value of shares vested was $ 1.6 million, $ 7.3 million and $ 6.3 million during the years ended December 31, 2020, 2019 and 2018, respectively. 
+98 
+Grant activity for the years ended December 31, 2020, 2019 and 2018 primarily consisted of RSU Equity Awards granted to executives and employees as part of the annual grant of long-term equity incentive awards. 
+The number of outstanding performance-based RSU Equity Awards that can vest is based on a calculation that compares the Company’s total shareholder return (“TSR”) to the same calculated return of a group of peer companies selected by the Company and can range between 0 % and 300 % of the target units for the awards granted in 2020 and between 0 % and 200 % of the target units for the awards granted in 2018 and 2019. The increase in the maximum amount of performance-based RSU Equity Awards that can vest for the awards granted in 2020 is due to an absolute TSR modifier, which was added as a second factor in the calculation, in addition to the relative TSR multiplier. While the absolute TSR modifier could increase the number of awards that vest, the number of awards that vest could also be reduced if the absolute TSR is less than 5 % over the performance period. 
+The following table summarizes the shares that vested and did not vest as a result of the Company’s performance as compared to its peers. 
+Years Ended December 31, 
+Performance-based Equity Awards 2020 2019 2018 
+Vesting Multiplier 
+50 % - 100 % 
+100 % 142 % 
+Target 21,920 8,878 8,300 
+Vested at end of performance period 11,372 8,878 11,786 
+Did not vest at end of performance period 10,548 — — 
+The Company recognizes expense for performance-based RSU Equity Awards based on the fair value of the awards at the grant date. Awards with a performance-based provision do not allow for the reversal of previously recognized expense, even if the market metric is not achieved and no shares ultimately vest. For the years ended December 31, 2020, 2019 and 2018, the grant date fair value of the performance-based RSU Equity Awards, calculated using a Monte Carlo simulation, was $ 3.4 million, $ 4.3 million, and $ 3.5 million, respectively. The following table summarizes the assumptions used and the resulting grant date fair value per performance-based RSU Equity Award granted during the years ended December 31, 2020, 2019 and 2018: 
+Performance-based Awards June 29, 2020 January 31, 2020 January 31, 2019 May 10, 2018 
+Expected term (in years) 2.5 2.9 2.9 2.6 
+Expected volatility 113.2 % 54.8 % 47.9 % 51.6 % 
+Risk-free interest rate 0.2 % 1.3 % 2.4 % 2.6 % 
+Dividend yield — % — % — % — % 
+As of December 31, 2020, unrecognized compensation costs related to unvested RSU Equity Awards were $ 13.5 million and will be recognized over a weighted average period of 1.7 years. 
+99 
+Cash-Settled RSU A wards 
+The table below summarizes the Cash-Settled RSU Award activity for the years ended December 31, 2020, 2019 and 2018: 
+Cash-Settled RSU Awards 
+(in thousands) Weighted Average Grant-Date Fair Value per Share 
+For the Year Ended December 31, 2018 
+Unvested at the beginning of the period 61 $ 123.82 
+Granted 35 $ 164.77 
+Vested ( 28 ) $ 116.67 
+Forfeited ( 2 ) $ 161.50 
+Unvested at the end of the period 66 $ 147.59 
+For the Year Ended December 31, 2019 
+Unvested at the beginning of the period 66 $ 147.59 
+Granted 44 $ 105.08 
+Vested ( 16 ) $ 155.29 
+Forfeited ( 8 ) $ 145.71 
+Unvested at the end of the period 86 $ 124.22 
+For the Year Ended December 31, 2020 
+Unvested at the beginning of the period 86 $ 124.22 
+Granted 142 $ 26.84 
+Vested ( 16 ) $ 160.39 
+Did not vest at end of performance period ( 16 ) $ 163.55 
+Forfeited — $ — 
+Unvested at the end of the period 196 $ 47.56 
+Grant activity primarily consisted of Cash-Settled RSU Awards to executives as part of the annual grant of long-term equity incentive awards that occurred in the first half of each of the years presented in the table above. These awards cliff vest after an approximate three-year performance period. 
+The Company’s outstanding Cash-Settled RSU Awards include the same performance-based vesting conditions as the performance-based RSU Equity Awards, which are described above. Additionally, the assumptions used to calculate the grant date fair value per Cash-Settled RSU Award granted for each of the respective periods presented are the same as the performance-based RSU Equity Awards presented above. 
+For the years ended December 31, 2020, 2019 and 2018, Cash-Settled RSU Awards vested resulting in cash payments of $ 0.2 million, $ 0.8 million and $ 3.2 million, respectively. 
+The following table summarizes the Company’s liability for Cash-Settled RSU Awards and the classification in the consolidated balance sheets for the periods indicated: 
+December 31, 
+2020 2019 
+(In thousands) 
+Other current liabilities $ 182 $ 966 
+Other long-term liabilities 1,336 2,089 
+Total Cash-Settled RSU Awards $ 1,518 $ 3,055 
+As of December 31, 2020, the Company had the following performance-based Cash-Settled RSU Awards outstanding: 
+Target Awards Outstanding Potential Minimum Units Vesting Potential Maximum Units Vesting 
+(In thousands) 
+Vesting in 2021 35 — 70 
+Vesting in 2022 111 — 334 
+Other 50 50 50 
+Total Cash-Settled RSU Awards 196 50 454 
+As of December 31, 2020, unrecognized compensation costs related to unvested Cash-Settled RSU Awards were $ 1.5 million and will be recognized over a weighted average period of 1.9 years. 
+100 
+Cash-Settled SARs 
+As a result of the Merger, Cash SARs previously granted by Carrizo that were outstanding at closing of the Merger were canceled and converted into a Cash SAR covering shares of the Company’s common stock, with the conversion calculated as prescribed in the agreement governing the Merger. The table below summarizes the Cash SAR activity for the year ended December 31, 2020. 
+Stock Appreciation Rights 
+(in thousands) Weighted 
+Average 
+Exercise 
+Prices Weighted Average Remaining Life 
+(In years) Aggregate Intrinsic Value 
+(In millions) 
+For the Year Ended December 31, 2019 
+Outstanding, beginning of period — $ — 
+Granted — $ — 
+Reissued 368 $ 100.34 
+Exercised — $ — 
+Forfeited — $ — 
+Expired — $ — 
+Outstanding, end of period 368 $ 100.34 4.4 $ — 
+Vested, end of period 368 $ 100.34 — $ — 
+Vested and exercisable, end of period — $ — — $ — 
+For the Year Ended December 31, 2020 
+Outstanding, beginning of period 368 $ 100.34 
+Granted — $ — 
+Exercised — $ — 
+Forfeited — $ — 
+Expired — $ — 
+Outstanding, end of period 368 $ 100.34 3.4 $ — 
+Vested, end of period 368 $ 100.34 — $ — 
+Vested and exercisable, end of period — $ — — $ — 
+The acquisition date fair value of the Cash SARs, calculated using the Black-Scholes-Merton option pricing model was $ 4.6 million. The following table summarizes the assumptions used, the resulting acquisition date fair value per Cash SAR, and the expiration dates for the grants that occurred during periods presented below: 
+2019 2018 2017 2016 
+Expected term (in years) 5.4 4.5 1.9 1.1 
+Expected volatility 60.7 % 56.9 % 58.6 % 68.1 % 
+Risk-free interest rate 1.7 % 1.7 % 1.6 % 1.5 % 
+Dividend yield — % — % — % — % 
+Expiration date March 17, 2026 March 17, 2025 March 23, 2022 March 17, 2021 
+The liabilities for Cash SARs as of December 31, 2020 and 2019 were $ 1.7 million and $ 5.0 million, respectively, all of which were classified as “Other current liabilities” in the consolidated balance sheets in the respective periods. Changes to the fair value of the Cash SARs are included in “General and administrative” in the consolidated statements of operations. As all Cash SARs are vested, there is no unrecognized compensation costs as of December 31, 2020. 
+101 
+Share-Based Compensation Expense, Net 
+Share-based compensation expense associated with the RSU Equity Awards, Cash-Settled RSU Awards, and Cash SARs, net of amounts capitalized, is included in “General and administrative” in the consolidated statements of operations. The following table presents share-based compensation expense (benefit), net for each respective period: 
+Years Ended December 31, 
+2020 2019 2018 
+RSU Equity Awards $ 13,030 $ 14,322 $ 9,460 
+Cash-Settled RSU Awards ( 771 ) 1,021 336 
+Cash SARs ( 3,344 ) 443 — 
+8,915 15,786 9,796 
+Less: amounts capitalized to oil and gas properties ( 6,252 ) ( 4,704 ) ( 3,434 ) 
+Total share-based compensation expense, net $ 2,663 $ 11,082 $ 6,362 
+Note 11 – Stockholders’ Equity 
+November 2020 Warrants 
+The Company issued approximately 1.75 million November 2020 Warrants in conjunction with the November 2020 Second Lien Notes that were issued in the senior unsecured note exchange described above. The Company determined that the November 2020 Warrants qualify as freestanding financial instruments, but meet the scope exception in ASC 815 - Derivatives and Hedging as they are indexed to the Company’s common stock. As such, the November 2020 Warrants meet the applicable criteria for equity classification and are reflected in additional paid in capital in the consolidated balance sheets. See “Note 7 - Borrowings” and “Note 18 - Subsequent Events” for additional information. 
+Reverse Stock Split 
+On August 7, 2020, the Board of Directors effected a reverse stock split of the Company’s outstanding shares of common stock at a ratio of 1-for-10 and reduced the total number of authorized shares of the Company’s common stock pursuant to an amendment to the Company’s Certificate of Incorporation, which was approved by the Company’s shareholders at the Company’s annual meeting of shareholders on June 8, 2020. The reverse stock split became effective as of the close of business on August 7, 2020. The Company’s common stock began trading on a split-adjusted basis on the NYSE at the market open on August 10, 2020. The par value of the common stock was not adjusted as a result of the reverse stock split. 
+The reverse stock split was intended to, among other things, increase the per share trading price of the Company’s common shares to satisfy the $1.00 minimum closing price requirement for continued listing on the NYSE. As a result of the reverse stock split, each 10 pre-split shares of common stock outstanding were automatically combined into one issued and outstanding share of common stock. The fractional shares that resulted from the reverse stock split were canceled by paying cash in lieu of the fair value. The number of outstanding shares of common stock were reduced from 397,479,684 as of August 7, 2020 to 39,746,967 shares. The total number of shares of common stock that the Company is authorized to issue was reduced from 525,000,000 to 52,500,000 shares. All share and per share amounts, except par value per share, in the accompanying consolidated financial statements and notes thereto were retroactively adjusted for all periods presented to give effect to this reverse stock split, including reclassifying an amount equal to the reduction in par value of common stock to additional paid-in capital in the current period. 
+10 % Series A Cumulative Preferred Stock (“Preferred Stock”) 
+On June 18, 2019, the Company announced it had given notice for the redemption (the “Redemption”) of all outstanding shares of the Preferred Stock. On July 18, 2019 (the “Redemption Date”), the Preferred Stock were redeemed at a redemption price equal to $ 50.00 per share, plus an amount equal to all accrued and unpaid dividends in an amount equal to $ 0.24 per share, for a total redemption price of $ 50.24 per share or $ 73.0 million (the “Redemption Price”). The Company recognized an $ 8.3 million loss on the redemption due to the excess of the $ 73.0 million redemption price over the $ 64.7 million redemption date carrying value of the Preferred Stock. After the Redemption Date, the Preferred Stock were no longer deemed outstanding, dividends on the Preferred Stock ceased to accrue, and all rights of the holders with respect to such Preferred Stock were terminated, except the right of the holders to receive the Redemption Price, without interest. As such, no Preferred Stock dividends were paid during 2020. The Company paid Preferred Stock dividends of $ 4.0 million and $ 7.3 million for years ended December 31, 2019 and 2018, respectively. 
+Common Stock Offerings 
+On May 30, 2018, the Company completed an underwritten public offering of 25.3 million shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and offering costs) of approximately $ 288.0 million. The Company used proceeds from the offering to partially fund the Delaware Asset Acquisition completed in the third quarter of 2018. See “Note 4 - Acquisitions and Divestitures” for further discussion of the Delaware Asset Acquisition. 
+102 
+Note 12 – Income Taxes 
+The components of the Company’s income tax expense are as follows: 
+Years Ended December 31, 
+2020 2019 2018 
+(In thousands) 
+Current 
+Federal $ — $ — $ — 
+State 3,447 220 — 
+Total current income tax expense 3,447 220 — 
+Deferred 
+Federal 126,903 33,584 3,594 
+State ( 8,296 ) 1,497 4,516 
+Total deferred income tax expense 118,607 35,081 8,110 
+Total income tax expense $ 122,054 $ 35,301 $ 8,110 
+A reconciliation of the income tax expense calculated at the federal statutory rate of 21% to income tax expense is as follows: 
+Years Ended December 31, 
+2020 2019 2018 
+(In thousands) 
+Income (loss) before income taxes ($ 2,411,567 ) $ 103,229 $ 308,470 
+Income tax expense (benefit) computed at the statutory federal income tax rate ( 506,429 ) 21,678 64,779 
+State income tax expense (benefit), net of federal benefit ( 11,827 ) 1,253 3,568 
+Equity based compensation 2,746 1,222 ( 494 ) 
+Non-deductible compensation — 90 1,209 
+Non-deductible merger expenses — 5,537 — 
+Statutory depletion carryforward — 5,381 — 
+Other ( 1,621 ) 140 168 
+Change in valuation allowance 639,185 — ( 61,120 ) 
+Income tax expense $ 122,054 $ 35,301 $ 8,110 
+The income tax expense of $ 122.1 million for the year ended December 31, 2020 is primarily due to the valuation allowance recorded against the Company’s net deferred tax assets. See “— Deferred Tax Asset Valuation Allowance” below for additional details. 
+At December 31, 2019, the Company recorded a tax expense of $ 5.5 million associated with non-deductible merger expenses from the Carrizo Acquisition which primarily relate to non-deductible executive compensation expenses and transaction costs that are inherently facilitative in nature and permanently capitalized for tax purposes. 
+103 
+As of December 31, 2020 and 2019, the net deferred income tax assets and liabilities are comprised of the following: 
+As of December 31, 
+2020 2019 
+(In thousands) 
+Deferred tax assets 
+Oil and natural gas properties $ 431,142 $ — 
+Federal net operating loss carryforward 141,308 110,703 
+Derivative asset 39,378 14,823 
+Operating lease right-of-use assets 8,567 29,897 
+Asset retirement obligations 10,134 9,981 
+Unvested RSU equity awards 1,962 4,928 
+Other 11,430 10,445 
+Total deferred tax assets $ 643,921 $ 180,777 
+Deferred income tax valuation allowance ( 639,185 ) — 
+Net deferred tax assets $ 4,736 $ 180,777 
+Deferred tax liability 
+Oil and natural gas properties $ — ($ 38,546 ) 
+Derivative liability — — 
+Operating lease liabilities ( 4,736 ) ( 26,511 ) 
+Total deferred tax liability ($ 4,736 ) ($ 65,057 ) 
+Net deferred tax asset (liability) $ — $ 115,720 
+Deferred Tax Asset Valuation Allowance 
+Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that the Company’s net deferred tax assets will be utilized prior to their expiration. A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and a net deferred tax asset position at December 31, 2020, driven primarily by the impairments of evaluated oil and gas properties recognized beginning in the second quarter of 2020 and continuing through the rest of 2020. This limits the ability to consider other subjective evidence such as the Company’s potential for future growth. Beginning in the second quarter of 2020 and continuing through the rest of 2020, based on the evaluation of the evidence available, the Company concluded that it is more likely than not that the net deferred tax assets will not be realized. As a result, the Company has recorded a valuation allowance of $ 639.2 million, reducing the net deferred tax assets as of December 31, 2020 to zero . 
+The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until the Company can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead the Company to conclude that it is more likely than not its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in crude oil prices, and taxable events that could result from one or more future potential transactions. The valuation allowance does not preclude the Company from utilizing the tax attributes if the Company recognizes taxable income. As long as the Company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, the Company will have no significant deferred income tax expense or benefit. 
+Carrizo Acquisition 
+For federal income tax purposes, the Carrizo Acquisition qualified as a tax-free merger whereby the Company acquired carryover tax basis in Carrizo’s assets and liabilities. The Company recorded an opening balance sheet deferred tax asset of $ 162.6 million related to tax attributes acquired from Carrizo. The acquired income tax attributes primarily consist of future deductions related to oil and gas properties, derivative assets, and federal net operating losses (“NOLs”). The acquired NOLs are subject to an annual limitation under Internal Revenue Code Section 382, as described below, and the Company reduced the total NOL balance and associated deferred tax asset for the NOLs to the amount that was expected at that time to be fully utilized prior to expirations. See above for discussion of the valuation allowance against the Company’s net deferred tax assets. 
+Due to the issuance of common stock associated with the Carrizo acquisition, the Company incurred a cumulative ownership change and as such, the Company’s NOLs prior to the acquisition are subject to an annual limitation under Internal Revenue Code Section 382. At December 31, 2020, the Company had approximately $ 672.9 million of NOLs, including $ 284.1 million acquired from Carrizo. $ 414.9 million expire between 2035 and 2037 and $ 258.0 million have an indefinite carryforward life. 
+104 
+The Company had no significant unrecognized tax benefits at December 31, 2020. Accordingly, the Company does not have any interest or penalties related to uncertain tax positions. However, if interest or penalties were to be incurred related to uncertain tax positions, such amounts would be recognized in income tax expense. In the Company’s major tax jurisdictions, the earliest year open to examination is 2016. 
+Note 13 – Leases 
+The Company determines if an arrangement is a lease at inception of the contract and, if the contract is determined to be a lease, classifies the lease as an operating or financing lease. The Company recognizes an operating or financing lease on its consolidated balance sheets as a lease liability, which represents the present value of the Company’s obligation to make lease payments arising from the lease, with a related ROU asset, which represents the Company’s right to use the underlying asset for the lease term. The Company’s operating leases typically do not provide an implicit interest rate, therefore, the Company utilizes its incremental borrowing rate to calculate the present value of the lease payments based on information available at inception of the contract. 
+Lease expense for operating leases is recognized on a straight-line basis over the lease term. Lease expense for financing leases is comprised of interest expense on the financing lease liability and the amortization of the associated ROU asset, which is recognized on a straight-line basis over the lease term. Variable lease expense that is not dependent on an index or rate is not included in the operating or financing lease liability or ROU asset and is recognized in the period in which the obligation for those payments is incurred. 
+Types of Leases 
+The Company currently has leases associated with contracts for office space, drilling rigs, and the use of well equipment, vehicles, information technology infrastructure, and other office equipment, with the significant lease types described in more detail below. 
+Drilling Rigs . The Company enters into contracts for drilling rigs with third parties to support its development plan. These contracts are typically for one to three years and can be extended upon mutual agreement with the third party by providing written notice at least thirty days prior to the end of the primary contractual term. The Company exercises its discretion in choosing whether or not to extend these contracts on a drilling rig by drilling rig basis as a result of evaluating the conditions that exist at the time the contract expires, such as availability of drilling rigs and the Company’s development plan. The Company has determined that it cannot conclude with reasonable certainty that it will choose to extend the contract past its primary term. As such, the Company uses the primary term in its calculation of the lease liability and ROU asset. The Company classifies its drilling rigs as operating leases and capitalizes the costs of the drilling rigs to oil and gas properties. 
+Office Space . The Company leases office space from third parties for its corporate office and certain field locations. These leases have non-cancelable terms between one to fifteen years . The Company has determined that it cannot conclude with reasonable certainty that it will exercise any option to extend the contract past the non-cancelable term. As such, the Company uses the non-cancelable term in its calculation of the lease liability and ROU asset. The Company classifies its leases for office space as operating leases with the costs recognized as “General and administrative” in its consolidated statements of operations. 
+Well Equipment . The Company rents compressors from third parties to facilitate the flow of production from its drilling operations to market. These contracts range from less than one year to three years for the primary term and continue thereafter on a month to month basis subject to cancellation by either party with thirty days’ notice. The Company classifies the compressors as operating leases with a lease term equal to the primary term for those contracts that have a primary term greater than one year. After the primary term, each party has a substantive right to terminate the lease, therefore, enforceable rights and obligations do not exist subsequent to the primary term. For those contracts that are less than one year, the Company has concluded that they represent short-term operating leases and therefore, an operating lease liability and ROU asset is not recorded in the consolidated balance sheets. These lease payments are recognized as “Lease operating” in the Company’s statements of operations. 
+The tables below, which present the components of lease costs and supplemental balance sheet information are presented on a gross basis. Other joint owners in the properties operated by the Company generally pay for their working interest share of costs associated with drilling rigs and well equipment. 
+105 
+The table below presents the components of the Company’s lease costs for the year ended December 31, 2020. 
+Years Ended December 31, 
+2020 2019 
+(In thousands) 
+Components of Lease Costs 
+Finance lease costs $ 1,489 $ 92 
+Amortization of right-of-use assets (1) 
+1,348 82 
+Interest on lease liabilities (2) 
+141 10 
+Operating lease cost (3) 
+46,888 38,076 
+Impairment of Operating lease ROU assets (4) 
+3,575 16,209 
+Short-term lease cost (5) 
+1,821 3,640 
+Variable lease costs (6) 
+259 — 
+Total lease costs $ 54,032 $ 58,017 
+(1) Included as a component of “Depreciation, depletion and amortization” in the consolidated statements of operations. 
+(2) Included as a component of “Interest expense, net of capitalized amounts” in the consolidated statements of operations. 
+(3) For the years ended December 31, 2020 and 2019, approximately $ 34.2 million and $ 34.9 million, respectively, are costs associated with drilling rigs. These costs were capitalized to “Evaluated properties, net” in the consolidated balance sheets and the other remaining operating lease costs were components of “General and administrative” and “Lease operating” in the consolidated statements of operations. 
+(4) As a result of the downturn in economic conditions in conjunction with our ongoing effort to consolidate various office locations due to the Carrizo Acquisition, the Company evaluated certain of its office leases for impairment. Upon evaluation, the Company recorded impairments of certain of its Operating lease ROU assets for the years ended December 31, 2020 and 2019 of $ 3.6 million and $ 16.2 million, respectively, which are a component of “Merger and integration expenses” in the consolidated statements of operations. 
+(5) Short-term lease cost excludes expenses related to leases with a contract term of one month or less. 
+(6) Variable lease costs include additional payments that were not included in the initial measurement of the lease liability and related ROU asset for lease agreements with terms greater than 12 months. Variable lease costs primarily consist of incremental usage associated with drilling rigs. 
+The table below presents supplemental balance sheet information for the Company’s operating leases. The Company’s financing leases are immaterial. 
+As of December 31, 
+2020 2019 
+(In thousands) 
+Leases 
+Operating leases: 
+Operating lease ROU assets $ 22,526 $ 63,908 
+Current operating lease liabilities $ 13,175 $ 42,858 
+Long-term operating lease liabilities 27,576 37,088 
+Total operating lease liabilities $ 40,751 $ 79,946 
+The table below presents the weighted average remaining lease terms and weighted average discounts rates for the Company’s leases as of December 31, 2020. 
+December 31, 2020 
+Weighted Average Remaining Lease Terms (In years) 
+Operating leases 6.2 
+Financing leases 3.0 
+Weighted Average Discount Rate 
+Operating leases 5.5 % 
+Financing leases 6.7 % 
+106 
+The table below presents the maturity of the Company’s lease liabilities as of December 31, 2020. 
+Operating Leases Financing Leases 
+(In thousands) 
+2021 $ 14,918 $ 314 
+2022 5,443 250 
+2023 5,011 233 
+2024 4,936 39 
+2025 3,958 — 
+Thereafter 14,139 — 
+Total lease payments 48,405 836 
+Less imputed interest ( 7,654 ) ( 78 ) 
+Total lease liabilities $ 40,751 $ 758 
+Note 14 – Asset Retirement Obligations 
+The table below summarizes the activity for the Company’s asset retirement obligations: 
+Years Ended December 31, 
+2020 2019 
+(In thousands) 
+Asset retirement obligations, beginning of period $ 49,733 $ 14,292 
+Accretion expense 3,323 945 
+Liabilities incurred 3,895 615 
+Increase due to acquisition of oil and gas properties — 26,107 
+Liabilities settled ( 2,220 ) ( 3,394 ) 
+Dispositions ( 351 ) ( 1,776 ) 
+Revisions to estimates 4,710 12,944 
+Asset retirement obligations, end of period 59,090 49,733 
+Less: Current asset retirement obligations ( 1,881 ) ( 873 ) 
+Non-current asset retirement obligations $ 57,209 $ 48,860 
+Certain of the Company’s operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded on the consolidated balance sheets at December 31, 2020 and 2019 as long-term restricted investments were $ 3.5 million , and are presented in “Other assets, net.” These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties. 
+Note 15 – Accounts Receivable, Net 
+As of December 31, 
+2020 2019 
+(In thousands) 
+Oil and natural gas receivables $ 100,257 $ 165,275 
+Joint interest receivables 11,530 39,114 
+Other receivables 24,191 6,610 
+Total 135,978 210,999 
+Allowance for credit losses ( 2,869 ) ( 1,536 ) 
+Total accounts receivable, net $ 133,109 $ 209,463 
+107 
+Note 16 – Accounts Payable and Accrued Liabilities 
+As of December 31, 
+2020 2019 
+(In thousands) 
+Accounts payable $ 101,231 $ 217,578 
+Revenues payable 162,762 145,816 
+Accrued capital expenditures 32,493 61,950 
+Accrued interest 45,033 36,295 
+Accrued severance (1) 
+3,846 28,803 
+Total accounts payable and accrued liabilities $ 345,365 $ 490,442 
+(1) See “Note 4 - Acquisitions and Divestitures” for further information regarding the Carrizo Acquisition. 
+Note 17 – Commitments and Contingencies 
+The Company is involved in various claims and lawsuits incidental to its business. In the opinion of management, the ultimate liability hereunder, if any, will not have a material adverse effect on the financial position or results of operations of the Company. 
+The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment are not expected to have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies hereunder, and claims for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities. 
+The table below presents total minimum commitments associated with long-term, non-cancelable leases, drilling rig contracts and gathering, processing and transportation service agreements, which require minimum volumes of oil, natural gas, or produced water to be delivered, as of December 31, 2020. 
+2021 2022 2023 2024 2025 2026 and Thereafter Total 
+(In thousands) 
+Operating leases (1) 
+$ 10,601 $ 5,443 $ 5,011 $ 4,936 $ 3,958 $ 14,139 $ 44,088 
+Drilling rig contracts (2) 
+4,317 — — — — — 4,317 
+Delivery commitments (3) 
+12,401 10,980 11,553 12,451 12,417 39,291 99,093 
+Produced water disposal commitments (4) 
+21,355 18,320 10,775 7,975 4,267 741 63,433 
+Total $ 48,674 $ 34,743 $ 27,339 $ 25,362 $ 20,642 $ 54,171 $ 210,931 
+(1) Operating leases primarily consist of contracts for office space. See “Note 13 – Leases” for additional information. 
+(2) Drilling rig contracts represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will generally be billed for their working interest share of such costs. In January 2021, the Company extended one of its drilling rig contracts for a term of one year . The gross contractual obligation for this extended drilling rig contract is approximately $ 5.5 million and is not included in the table above as it was entered into subsequent to December 31, 2020. 
+(3) Delivery commitments represent contractual obligations the Company has entered into for certain gathering, processing and transportation service agreements which require minimum volumes of oil or natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any oil or natural gas. 
+(4) Produced water disposal commitments represent contractual obligations the Company has entered into for certain service agreements which require minimum volumes of produced water to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water. 
+Operating leases 
+As of December 31, 2020, the Company had contracts for two horizontal drilling rigs. The contract terms will end on various dates between March 2021 and May 2021. 
+108 
+Other commitments 
+The following table includes the Company’s current oil sales contracts and firm transportation agreements as of December 31, 2020: 
+Type of Commitment (1) 
+Region Execution Date Start Date End Date Committed 
+Volumes (Bbls/d) 
+Oil sales contract Eagle Ford November 2020 January 2021 December 2021 10,000 
+Oil sales contract Permian August 2020 August 2020 December 2021 7,500 
+Oil sales contract Permian July 2019 August 2021 July 2026 5,000 
+Oil sales contract Permian June 2019 January 2020 December 2024 10,000 
+Oil sales contract Permian August 2018 April 2020 March 2022 15,000 
+Firm transportation agreement (2)(3) 
+Permian June 2019 August 2020 July 2030 10,000 
+Firm transportation agreement (2) 
+Permian August 2018 April 2020 March 2027 15,000 
+(1) For each of the commitments shown in the table above, the committed barrels may include volumes produced by the Company and other third-party working, royalty, and overriding royalty interest owners whose volumes the Company markets on their behalf. 
+(2) Each of the firm transportation agreements shown in the table above grant the Company access to delivery points in several locations along the Gulf Coast. 
+(3) The committed volumes shown in the table above for this particular firm transportation agreement are average volumes. For the terms of August 2020-July 2023, August 2023-July 2027 and August 2027-July 2030, the committed volumes are 7,500 Bbls/d, 10,000 Bbls/d and 12,500 Bbls/d, respectively. 
+Note 18 – Subsequent Events (Unaudited) 
+Hedging 
+Subsequent to December 31, 2020, the Company entered into the following derivative contracts: 
+For the Full Year of For the Full Year of 
+Oil contracts (WTI) 2021 2022 
+Collar contracts 
+Total volume (Bbls) 920,000 1,355,000 
+Weighted average price per Bbl 
+Ceiling (short call) $ 60.18 $ 60.00 
+Floor (long put) $ 47.50 $ 45.00 
+Short call swaption contracts 1 
+Total volume (Bbls) — 1,825,000 (2) 
+Weighted average price per Bbl $ — $ 52.18 
+(1) In February 2021, the Company terminated a total of 920,000 Bbls of short call swaption contracts for the second half of 2021 and simultaneously executed the full year 2022 short call swaption contracts shown in the table above. 
+(2) The short call swaption contracts shown in the table above have exercise expiration dates of December 31, 2021. 
+For the Full Year of 
+Natural gas contracts (Henry Hub) 2022 
+Collar contracts (two-way collars) 
+Total volume (MMBtu) 1,800,000 
+Weighted average price per MMBtu 
+Ceiling (short call) $ 3.88 
+Floor (long put) $ 2.78 
+Additionally, in January 2021, the Company paid approximately $ 3.1 million to terminate 184,000 Bbls of crude ICE Brent swaps. In February 2021, the Company executed offsetting crude ICE Brent swaps on 159,300 Bbls, resulting in a locked-in loss of approximately $ 2.9 million which the Company will pay as the applicable contracts settle. 
+Exercise of Warrants 
+In January and February 2021, certain entities that were issued September 2020 Warrants and November 2020 Warrants provided notice and exercised their outstanding warrants. As a result of these exercises, the Company issued a total of 6.4 million shares of its common stock in exchange for 8.4 million outstanding warrants determined on a net share settlement basis. The exercise of the September 2020 Warrants also resulted in settlement of the associated derivative liability which at December 31, 2020 was $ 79.4 million. 
+109 
+Note 19 - Supplemental Information on Oil and Natural Gas Operations (Unaudited) 
+Estimated Reserves 
+For each year in the table below, the estimated proved reserves were prepared by DeGolyer and MacNaughton (“D&M”), Callon’s independent third party reserve engineers, with the exception of the estimated proved reserves in 2019 obtained as a result of the Carrizo Acquisition, which were prepared by Ryder Scott Company, L.P. (“Ryder Scott”), the independent third party reserve engineers historically retained by Carrizo. The reserves were prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions. 
+There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only, and should not be deemed exact. In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company’s oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves. 
+Extrapolation of performance history and material balance estimates were utilized by the Company’s both D&M and Ryder Scott to project future recoverable reserves for the producing properties where sufficient history existed to suggest performance trends and where these methods were applicable to the subject reservoirs. The projections for the remaining producing properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to nonproducing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production, and to a small extent, horizontal PDP and PUD categories. 
+The following tables disclose changes in the estimated quantities of proved reserves, all of which are located onshore within the continental United States: 
+Years Ended December 31, 
+Proved reserves 2020 2019 2018 
+Oil (MBbls) 
+Beginning of period 346,361 180,097 107,072 
+Purchase of reserves in place — 183,382 30,756 
+Sales of reserves in place ( 9,673 ) ( 17,980 ) — 
+Extensions and discoveries 25,678 45,663 67,763 
+Revisions to previous estimates ( 49,336 ) ( 33,136 ) ( 16,051 ) 
+Production ( 23,543 ) ( 11,665 ) ( 9,443 ) 
+End of period 289,487 346,361 180,097 
+Natural Gas (MMcf) 
+Beginning of period 757,134 350,466 179,410 
+Purchase of reserves in place — 455,158 53,563 
+Sale of reserves in place ( 20,389 ) ( 86,856 ) — 
+Extensions and discoveries 44,282 82,566 103,149 
+Revisions to previous estimates ( 198,628 ) ( 24,482 ) 29,791 
+Production ( 40,801 ) ( 19,718 ) ( 15,447 ) 
+End of period 541,598 757,134 350,466 
+NGLs (MBbls) 
+Beginning of period 67,462 — — 
+Purchase of reserves in place — 67,597 — 
+Sale of reserves in place ( 3,049 ) — — 
+Extensions and discoveries 8,349 — — 
+Revisions to previous estimates 30,214 — — 
+Production ( 6,850 ) ( 135 ) — 
+End of period 96,126 67,462 — 
+Total (MBoe) 
+Beginning of period 540,012 238,508 136,974 
+Purchase of reserves in place — 326,838 39,683 
+Sale of reserves in place ( 16,120 ) ( 32,456 ) — 
+Extensions and discoveries 41,407 59,424 84,955 
+Revisions to previous estimates ( 52,227 ) ( 37,216 ) ( 11,086 ) 
+Production ( 37,193 ) ( 15,086 ) ( 12,018 ) 
+End of period 475,879 540,012 238,508 
+110 
+Years Ended December 31, 
+Proved developed reserves 2020 2019 2018 
+Oil (MBbls) 
+Beginning of period 152,687 92,202 51,920 
+End of period 128,923 152,687 92,202 
+Natural gas (MMcf) 
+Beginning of period 320,676 218,417 104,389 
+End of period 238,119 320,676 218,417 
+NGLs (MBbls) 
+Beginning of period 24,844 — — 
+End of period 43,315 24,844 — 
+Total proved developed reserves (MBoe) 
+Beginning of period 230,977 128,605 69,318 
+End of period 211,925 230,977 128,605 
+Proved undeveloped reserves 
+Oil (MBbls) 
+Beginning of period 193,674 87,895 55,152 
+End of period 160,564 193,674 87,895 
+Natural gas (MMcf) 
+Beginning of period 436,458 132,049 75,021 
+End of period 303,479 436,458 132,049 
+NGLs (MBbls) 
+Beginning of period 42,618 — — 
+End of period 52,811 42,618 — 
+Total proved undeveloped reserves (MBoe) 
+Beginning of period 309,035 109,903 67,656 
+End of period 263,954 309,035 109,903 
+Total proved reserves 
+Oil (MBbls) 
+Beginning of period 346,361 180,097 107,072 
+End of period 289,487 346,361 180,097 
+Natural gas (MMcf) 
+Beginning of period 757,134 350,466 179,410 
+End of period 541,598 757,134 350,466 
+NGLs (MBbls) 
+Beginning of period 67,462 — — 
+End of period 96,126 67,462 — 
+Total proved reserves (MBoe) 
+Beginning of period 540,012 238,508 136,974 
+End of period 475,879 540,012 238,508 
+Total Proved Reserves 
+For the year ended December 31, 2020, the Company’s net decrease in proved reserves of 64.1 MMBoe was primarily due to the following: 
+• Increase of 41.4 MMBoe through extensions and discoveries through our development efforts in our operating areas, of which 11.7 MMBoe were proved developed reserves; 
+• Decrease of 52.2 MMBoe for revisions of previous estimates that were primarily comprised of: 
+◦ 26.2 MMBoe reduction due to the change in 12-Month Average Realized Price of crude oil which decreased by approximately 31 % as compared to December 31, 2019. Included in the decrease are 2.1 MMBoe associated with proved developed producing wells and 0.8 MMBoe associated with proved undeveloped wells that were no longer economic at December 31, 2020 as a result of the decrease in the 12-Month Average Realized Price of crude oil; 
+111 
+◦ 24.2 MMBoe reduction due to anticipated hydrocarbon recoveries resulting from observed well performance over longer production timeframes during the testing of various full field development plan concepts; 
+◦ 24.0 MMBoe reduction due to PUDs that were removed primarily as a result of changes in anticipated well densities as the Company develops its properties in an effort to increase capital efficiency and cash flow generation; 
+◦ 14.7 MMBoe increase due to the volumetric impact from presenting NGLs and natural gas separately due to the modification of certain of the Company’s natural gas processing agreements which allow it to take title to NGLs resulting from the processing of its natural gas subsequent to January 1, 2020. For periods prior to January 1, 2020, except for reserve volumes specifically associated with Carrizo, the Company presented its reserve volumes for NGLs with natural gas; 
+◦ 7.5 MMBoe increase due to reduced assumptions for operational expenses as the Company continues to improve its field practices during the integration of the properties acquired from Carrizo; 
+• Decrease of 16.1 MMBoe for sales of reserves in place primarily associated with the ORRI Transaction and the sale of substantially all of the Company’s non-operated assets; and 
+• Decrease of 37.2 MMBoe for production. 
+For the year ended December 31, 2019, the Company’s net increase in proved reserves of 301.5 MMBoe was primarily due to the following: 
+• Increase of 326.8 MMBoe for purchases of reserves in place related to the acquisition of Carrizo Oil & Gas, Inc. in late 2019; 
+• Increase of 59.4 MMBoe through extensions and discoveries through our development efforts in our operating areas, of which 17.1 MMBoe were proved developed reserves; 
+• Decrease of 32.5 MMBoe as a result of sales of reserves in place, primarily associated with our Ranger Divestiture which totaled 27.1 MMBoe; 
+• Decrease of 37.2 MMBoe for revisions of previous estimates that were primarily comprised of: 
+◦ 21.7 MMBoe reduction due to the observed impact of well spacing tests on producing wells and the related impact on PUD reserve estimates, primarily in the Midland Basin, as the Company advances larger scale development concepts across its multi-zone inventory; 
+◦ 9.8 MMBoe reduction due to reclassifications of PUDs within the Company’s development plans, primarily related to certain fields within the Company’s Delaware Basin acreage, that were moved outside of the five-year development window primarily driven by the acquisition of Carrizo Oil & Gas, Inc. in December 2019, which afforded us the opportunity to reallocate capital across the combined portfolio in an effort to increase capital efficiency through larger scale development concepts as well as preserve our co-development philosophy to optimize resource capture from multiple zones; 
+◦ 5.7 MMBoe reduction due to pricing; and 
+• Decrease of 15.1 MMBoe for production. 
+For the year ended December 31, 2018, the Company’s net increase in proved reserves of 101.5 MMBoe was primarily due to the following: 
+• Increase of 85.0 MMBoe through extensions and discoveries, 28.2 MMBoe of which were proved developed reserves, as a result of development efforts in the Permian where the Company drilled 70 gross ( 57.5 net) wells; 
+• Increase of 39.7 MMBoe for purchases of reserves in place, of which 29.8 MMBoe were proved developed reserves, primarily related to the Company’s acquisition from Cimarex Energy Company in August 2018; 
+• Decrease of 11.1 MMBoe for revisions of previous estimates that were primarily comprised of: 
+◦ 9.1 MMBoe reduction due to reclassifications of PUDs within the Company’s development plans that were moved outside of the five-year development window primarily driven by larger pad development concepts and co-development of zones; 
+◦ 2.0 MMBoe related to technical revisions of PUDs; and 
+• Decrease of 12.0 MMBoe for production. 
+112 
+Capitalized Costs 
+Capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows: 
+As of December 31, 
+2020 2019 
+Oil and natural gas properties: (In thousands) 
+Evaluated properties $ 7,894,513 $ 7,203,482 
+Unevaluated properties 1,733,250 1,986,124 
+Total oil and natural gas properties 9,627,763 9,189,606 
+Accumulated depreciation, depletion, amortization and impairment ( 5,538,803 ) ( 2,520,488 ) 
+Total oil and natural gas properties capitalized $ 4,088,960 $ 6,669,118 
+Costs Incurred 
+Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows: 
+Years Ended December 31, 
+2020 2019 2018 
+Acquisition costs: (In thousands) 
+Evaluated properties $ — $ 49,572 $ 347,305 
+Unevaluated properties 30,696 107,347 466,816 
+Development costs 379,900 189,259 259,410 
+Exploration costs 122,865 309,013 323,458 
+Total costs incurred $ 533,461 $ 655,191 $ 1,396,989 
+Standardized Measure 
+The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2020. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Proved reserve estimates and future cash flows are based on the average realized prices for sales of oil, natural gas, and NGLs on the first calendar day of each month during the year. The following average realized prices were used in the calculation of proved reserves and the standardized measure of discounted future net cash flows. 
+Years Ended December 31, 
+2020 2019 2018 
+Oil ($/Bbl) $ 37.44 $ 53.90 $ 58.40 
+Natural gas ($/Mcf) $ 1.02 $ 1.55 $ 3.64 
+NGLs ($/Bbl) $ 11.10 $ 15.58 $ — 
+Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10 % annual discount rate. 
+Standardized Measure 
+For the Year Ended December 31, 
+2020 2019 2018 
+(In thousands) 
+Future cash inflows $ 12,458,033 $ 20,891,469 $ 11,794,080 
+Future costs 
+Production ( 5,433,496 ) ( 6,717,088 ) ( 2,923,959 ) 
+Development and net abandonment ( 2,204,301 ) ( 3,058,861 ) ( 1,429,787 ) 
+Future net inflows before income taxes 4,820,236 11,115,520 7,440,334 
+Future income taxes ( 65,405 ) ( 941,768 ) ( 782,470 ) 
+Future net cash flows 4,754,831 10,173,752 6,657,864 
+10% discount factor ( 2,444,441 ) ( 5,222,726 ) ( 3,716,571 ) 
+Standardized measure of discounted future net cash flows $ 2,310,390 $ 4,951,026 $ 2,941,293 
+113 
+Changes in Standardized Measure 
+For the Year Ended December 31, 
+2020 2019 2018 
+(In thousands) 
+Standardized measure at the beginning of the period $ 4,951,026 $ 2,941,293 $ 1,556,682 
+Sales and transfers, net of production costs ( 649,781 ) ( 579,744 ) ( 481,306 ) 
+Net change in sales and transfer prices, net of production costs ( 2,719,579 ) ( 387,970 ) 222,802 
+Net change due to purchases of in place reserves — 2,975,296 554,697 
+Net change due to sales of in place reserves ( 202,928 ) ( 303,526 ) — 
+Extensions, discoveries, and improved recovery, net of future production and development costs incurred 250,759 607,146 1,001,873 
+Changes in future development cost 361,008 205,398 40,483 
+Previously estimated development costs incurred 318,470 134,037 91,900 
+Revisions of quantity estimates ( 671,800 ) ( 420,488 ) ( 167,096 ) 
+Accretion of discount 536,958 314,921 157,676 
+Net change in income taxes 383,999 ( 210,641 ) ( 187,841 ) 
+Changes in production rates, timing and other ( 247,742 ) ( 324,696 ) 151,423 
+Aggregate change ( 2,640,636 ) 2,009,733 1,384,611 
+Standardized measure at the end of period $ 2,310,390 $ 4,951,026 $ 2,941,293 
+Note 20 - Supplemental Quarterly Financial Information (Unaudited) 
+The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2020 and 2019: 
+2020 
+First Quarter (3) 
+Second Quarter (4) 
+Third Quarter (5) 
+Fourth Quarter (6) 
+(In thousands, except per share amounts) 
+Total operating revenues $ 289,919 $ 157,234 $ 290,026 $ 295,968 
+Income (loss) from operations 47,860 ( 1,361,676 ) ( 629,707 ) ( 513,329 ) 
+Net income (loss) 216,565 ( 1,564,731 ) ( 680,384 ) ( 505,071 ) 
+Income (loss) available to common stockholders 216,565 ( 1,564,731 ) ( 680,384 ) ( 505,071 ) 
+Income (loss) available to common stockholders per common share (1)(2) 
+Basic $ 5.46 ($ 39.41 ) ($ 17.12 ) ($ 12.71 ) 
+Diluted $ 5.46 ($ 39.41 ) ($ 17.12 ) ($ 12.71 ) 
+2019 
+First Quarter (7) 
+Second Quarter (8) 
+Third Quarter (9) 
+Fourth Quarter (10) 
+(In thousands, except per share amounts) 
+Total operating revenues $ 153,047 $ 167,052 $ 155,378 $ 196,095 
+Income from operations 43,225 58,509 52,544 18,380 
+Net income (loss) ( 19,543 ) 55,180 55,834 ( 23,543 ) 
+Income (loss) available to common stockholders ( 21,367 ) 53,357 47,180 ( 23,543 ) 
+Income (loss) available to common stockholders per common share (1) (2) 
+Basic ($ 0.94 ) $ 2.34 $ 2.07 ($ 0.95 ) 
+Diluted ($ 0.94 ) $ 2.34 $ 2.07 ($ 0.95 ) 
+(1) The sum of quarterly income (loss) available to common stockholders per common share does not agree with the total year income (loss) available to common stockholders per common share as each computation is based on the weighted average of common shares outstanding during the period. 
+(2) Income (loss) available to common stockholders per common share has been retroactively adjusted to reflect the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 - Stockholders’ Equity” for additional information. 
+114 
+(3) First quarter of 2020 included the following: 
+a. $ 252.0 million gain on derivative contracts 
+b. $ 15.8 million of merger and integration expenses associated with the merger with Carrizo 
+(4) Second quarter of 2020 included the following: 
+a. $ 1.3 billion impairment of evaluated oil and gas properties 
+b. $ 127.0 million loss on derivative contracts 
+c. $ 8.1 million of merger and integration expenses associated with the merger with Carrizo 
+(5) Third quarter of 2020 included the following: 
+a. $ 685.0 million impairment of evaluated oil and gas properties 
+b. $ 27.0 million loss on derivative contracts 
+c. $ 2.5 million of merger and integration expenses associated with the merger with Carrizo 
+(6) Fourth quarter of 2020 included the following: 
+a. $ 585.8 million impairment of evaluated oil and gas properties 
+b. $ 125.7 million loss on derivative contracts 
+c. $ 1.6 million of merger and integration expenses associated with the merger with Carrizo 
+d. $ 170.4 million gain on extinguishment of debt 
+(7) First quarter of 2019 included the following: 
+a. $ 67.3 million loss on derivative contracts 
+(8) Second quarter of 2019 included the following: 
+a. $ 14.0 million gain on derivative contracts 
+(9) Third quarter of 2019 included the following: 
+a. $ 21.8 million gain on derivative contracts 
+b. $ 5.9 million of merger and integration expenses associated with the merger with Carrizo 
+c. $ 8.3 million loss on redemption of Preferred Stock 
+(10) Fourth quarter of 2019 included the following: 
+a. Activity from the Carrizo Acquisition subsequent to the December 20, 2019 closing date. 
+b. $ 68.4 million of merger and integration expenses associated with the merger with Carrizo 
+c. $ 30.7 million loss on derivative contracts 
+d. $ 4.9 million loss on extinguishment of debt 
+ITEM 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure 
+None. 
+ITEM 9A. Controls and Procedures 
+Disclosure controls and procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) performed an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2020. 
+Management’s report on internal control over financial reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. generally accepted accounting principles. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2020 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission (2013 framework) (the COSO criteria). Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2020. 
+Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+115 
+The Company’s independent registered public accounting firm, Grant Thornton, LLP, has issued an attestation report regarding its assessment of the Company’s internal control over financial reporting as of December 31, 2020, presented preceding the Company’s financial statements included in Part II, Item 8 of this 2020 Annual Report on Form 10-K. Additionally, the financial statements for the years ended December 31, 2019 and 2018, covered in this 2020 Annual Report on Form 10-K, have also been audited by the Company’s independent registered public accounting firm, whose report is presented preceding the their report on the Company’s internal control over financial reporting, included in Part II, Item 8. 
+Changes in internal control over financial reporting . There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting. 
+ITEM 9B. Other Information 
+None. 
+PART III. 
+ITEM 10. Directors, Executive Officers and Corporate Governance 
+The information required by this item is incorporated herein by reference to the definitive proxy statement (the “2021 Proxy Statement”) for our 2021 annual meeting of shareholders. The 2021 Proxy Statement will be filed with the SEC not later than 120 days subsequent to December 31, 2020. 
+The Company has adopted a code of ethics that applies to the Company’s officers, directors, employees, agents and representatives and includes a code of ethics for senior financial officers that applies to the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer. The full text of such code of ethics has been posted on the Company’s website at www.callon.com, and is available free of charge in print to any shareholder who requests it. Request for copies should be addressed to the Secretary at mailing address 2000 W. Sam Houston Parkway South, Suite 2000, Houston, TX 77042. 
+ITEM 11. Executive Compensation 
+The information required by this item is incorporated herein by reference to the 2021 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2020. 
+ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+The information required by this item is incorporated herein by reference to the 2021 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2020. 
+ITEM 13. Certain Relationships and Related Transactions and Director Independence 
+The information required by this item is incorporated herein by reference to the 2021 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2020. 
+ITEM 14. Principal Accountant Fees and Services 
+The information required by this item is incorporated herein by reference to the 2021 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2020. 
+116 
+PART IV. 
+ITEM 15. Exhibits 
+The following is an index to the financial statements and financial statement schedules that are filed in Part II, Item 8 of this report on Form 10-K. 
+Incorporated by reference (File No. 001-14039, unless otherwise indicated) 
+Exhibit Number Description Form Exhibit Filing 
+Date 
+2.1 (d) 
+Purchase and Sale Agreement, dated May 23, 2018, between Cimarex Energy Co, Prize Energy Resources, Inc., and Magnum Hunter Production, Inc. and Callon Petroleum Operating Company 
+8-K 2.1 05/24/2018 
+2.2 (d) 
+Purchase and Sale Agreement between Callon Petroleum Operating Company and Sequitur Permian, LLC dated April 8, 2019 
+8-K 2.1 06/13/2019 
+2.3 (d) 
+Agreement and Plan of Merger, dated as of July 14, 2019, by and between Callon Petroleum Company and Carrizo Oil & Gas, Inc. 
+8-K 2.1 07/15/2019 
+2.4 
+Amendment No. 1 to Agreement and Plan of Merger, dated August 19, 2019, by and between Callon Petroleum Company and Carrizo Oil & Gas, Inc. 
+10-Q 2.2 11/05/2019 
+2.5 
+Amendment No. 2 to Agreement and Plan of Merger, dated November 13, 2019, by and between Callon Petroleum Company and Carrizo Oil & Gas, Inc. 
+8-K 2.1 11/14/2019 
+3.1 
+Certificate of Incorporation of the Company, as amended through May 12, 2016 
+10-Q 3.1 11/03/2016 
+3.2 
+Certificate of Amendment to the Certificate of Incorporation of Callon, effective December 20, 2019 
+8-K 3.1 12/20/2019 
+3.3 
+Certificate of Amendment to the Certificate of Incorporation of Callon, effective August 7, 2020 
+8-K 3.1 08/07/2020 
+3.4 
+Amended and Restated Bylaws of the Company 
+10-K 3.2 02/27/2019 
+4.1 
+Specimen Common Stock Certificate 
+10-K 4.1 02/28/2018 
+4.2 (a) 
+Description of Common Stock 
+4.3 
+Indenture of 6.125% Senior Notes Due 2024, dated as of October 3, 2016, among Callon Petroleum Company, the Guarantors party thereto and U.S. Bank National Association, as Trustee 
+8-K 4.1 10/04/2016 
+4.4 
+First Supplemental Indenture, dated December 20, 2019, among Callon, the Guarantors named therein and U.S. Bank National Association, as trustee 
+8-K 4.3 12/20/2019 
+4.5 
+Registration Rights Agreement of 6.125% Senior Notes Due 2024, dated October 3, 2016, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P. Morgan Securities LLC, as representative of the Initial Purchasers named on Annex E thereto 
+8-K 4.2 10/04/2016 
+4.6 
+Registration Rights Agreement of 6.125% Senior Notes Due 2024, dated May 24, 2017, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P. Morgan Securities LLC, as representative of the Initial Purchasers named on Annex E thereto 
+8-K 4.1 05/24/2017 
+4.7 
+Indenture of 6.375% Senior Notes Due 2026, dated as of June 7, 2018, among Callon Petroleum Company, the Guarantors party thereto and U.S. Bank National Association, as Trustee 
+8-K 4.1 06/07/2018 
+4.8 
+First Supplemental Indenture, dated December 20, 2019, among Callon, the Guarantors named therein and U.S. Bank National Association, as trustee 
+8-K 4.4 12/20/2019 
+4.9 
+Registration Rights Agreement of 6.375% Senior Notes Due 2026, dated June 7, 2018, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P. Morgan Securities LLC, as representative of the Initial Purchasers named on Annex E thereto 
+8-K 4.2 06/07/2018 
+4.10 
+Indenture, dated May 28, 2008, among Carrizo Oil & Gas, Inc., the subsidiaries named therein and Wells Fargo Bank, National Association, as trustee 
+8-K(File No. 000-29187-87) 4.1 05/28/2008 
+4.11 
+Sixteenth Supplemental Indenture, dated April 28, 2015, among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee 
+8-K(File No. 000-29187-87) 4.2 04/28/2015 
+4.12 
+Eighteenth Supplemental Indenture, dated May 20, 2015, among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee 
+8-K(File No. 000-29187-87) 4.2 05/22/2015 
+4.13 
+Twentieth Supplemental Indenture, dated July 14, 2017, among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee 
+8-K(File No. 000-29187-87) 4.2 07/14/2017 
+4.14 
+Twenty-First Supplemental Indenture, dated December 20, 2019, among Callon, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee 
+8-K 4.1 12/20/2019 
+4.15 
+Twenty-Second Supplemental Indenture, dated December 20, 2019, among Callon, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee 
+8-K 4.2 12/20/2019 
+4.16 
+Warrant Agreement, dated as of December 20, 2019, between Callon and American Stock Transfer And Trust Company, LLC, as warrant agent 
+8-K 4.5 12/20/2019 
+4.17 
+Indenture among the Company, the guarantors named therein and U.S. Bank National Association, as trustee and collateral agent, dated September 30, 2020 
+8-K 4.1 10/01/2020 
+117 
+4.18 
+Registration Rights Agreement between the Company and Chambers Investments, LLC, dated September 30, 2020 
+8-K 4.2 10/01/2020 
+4.19 
+Warrant Agreement between the Company and American Stock Transfer and Trust Company, LLC, as warrant agent, dated September 30, 2020 
+8-K 4.3 10/01/2020 
+10.1 (d) 
+Credit Agreement, dated December 20, 2019, among Callon, JPMorgan Chase Bank, National Association, as administrative agent, and the lenders party thereto 
+8-K 10.1 12/20/2019 
+10.2 (d) 
+First Amendment to Credit Agreement among Callon, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and the lender parties thereto, dated May 7, 2020 
+10-Q 10.1 05/11/2020 
+10.3 
+Second Amendment to Credit Agreement among Callon, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and the lender parties thereto, dated September 30, 2020 
+8-K 10.2 10/01/2020 
+10.4 
+Third Amendment to Credit Agreement among Callon, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and the lender parties thereto, dated September 30, 2020 
+8-K 10.3 10/01/2020 
+10.5 (b) 
+Amended and Restated Deferred Compensation Plan for Outside Directors - Callon Petroleum Company, dated as of May 10, 2017 and effective as of May 1, 2017 
+10-K 10.11 02/28/2018 
+10.6 (b) 
+Callon Petroleum Company 2018 Omnibus Incentive Plan 
+DEF 14A A 03/23/2018 
+10.7 (b) 
+Amended and Restated 2018 Omnibus Incentive Plan 
+10-K 10.7 02/27/2020 
+10.8 (b) 
+Form of Callon Petroleum Company Director Restricted Stock Unit Award Agreement, adopted on May 10, 2018 under the 2018 Omnibus Incentive Plan 
+10-Q 10.4 08/07/2018 
+10.9 (b) 
+Form of Callon Petroleum Company Employee Restricted Stock Unit Award Agreement, adopted on May 10, 2018 under the 2018 Omnibus Incentive Plan 
+10-Q 10.5 08/07/2018 
+10.10 (b) 
+Form of Change in Control Severance Compensation Agreement, dated as of January 1, 2019, by and between Callon Petroleum Company and its executive officers 
+10-K 10.17 02/27/2019 
+10.11 (b) 
+Change in Control Severance Compensation Agreement, dated as of January 1, 2019, by and between Joseph C. Gatto, Jr., and Callon Petroleum Company 
+10-K 10.18 02/27/2019 
+10.12 (b) 
+Carrizo Oil & Gas, Inc. Change in Control Severance Plan effective February 14, 2019 
+10-K(File No. 000-29187-87) 10.15 03/01/2019 
+10.13 (b) 
+Form of Callon Petroleum Company Employee Restricted Stock Unit Award Agreement, adopted on January 31, 2019 under the 2018 Omnibus Incentive Plan 
+10-K 10.20 02/27/2019 
+10.14 (b) 
+Form of Callon Petroleum Officer Cash-Settleable Performance Share Award Agreement, adopted on January 31, 2019 under the 2018 Omnibus Incentive Plan 
+10-K 10.21 02/27/2019 
+10.15 (b) 
+Form of Callon Petroleum Company Officer Stock-Settleable Performance Share Award Agreement, adopted on January 31, 2019 under the 2018 Omnibus Incentive Plan 
+10-K 10.22 02/27/2019 
+10.26 (b) 
+Form of Callon Petroleum Company Officer Restricted Stock Unit Award Agreement, adopted on January 31, 2019 under the 2018 Omnibus Incentive Plan 
+10-K 10.23 02/27/2019 
+10.17 (b) 
+2017 Incentive Plan of Carrizo Oil &Gas, Inc. 
+8-K(File No. 000-29187-87) 10.1 05/16/2019 
+10.18 (b) 
+Form of Callon Petroleum Company Employee Restricted Stock Unit Award Agreement, adopted on January 31, 2020 under the Amended & Restated 2018 Omnibus Incentive Plan 
+10-K 10.22 02/27/2020 
+10.19 (b) 
+Form of Callon Petroleum Officer Cash-Settleable Performance Share Award Agreement, adopted on January 31, 2020 under the Amended & Restated 2018 Omnibus Incentive Plan 
+10-K 10.23 02/27/2020 
+10.20 (b) 
+Form of Callon Petroleum Company Officer Stock-Settleable Performance Share Award Agreement, adopted on January 31, 2020 under the Amended & Restated 2018 Omnibus Incentive Plan 
+10-K 10.24 02/27/2020 
+10.21 (b) 
+Form of Callon Petroleum Company Officer Restricted Stock Unit Award Agreement, adopted on January 31, 2020 under the Amended & Restated 2018 Omnibus Incentive Plan 
+10-K 10.25 02/27/2020 
+10.22 (b) 
+Callon Petroleum Company 2020 Omnibus Incentive Plan 
+DEF 14A B 04/28/2020 
+10.23 (b) 
+Form of Callon Petroleum Company Employee Restricted Stock Unit Award Agreement, adopted on June 8, 2020, under the 2020 Omnibus Incentive Plan 
+10-Q 10.3 08/05/2020 
+10.24 (b) 
+Form of Callon Petroleum Company Director Restricted Stock Unit Award Agreement, adopted on June 8, 2020, under the 2020 Omnibus Incentive Plan 
+10-Q 10.4 08/05/2020 
+10.25 (b) 
+Form of Callon Petroleum Company Officer Cash Retention Award Agreement, adopted on September 30, 2020, under the 2020 Omnibus Incentive Plan 
+10-Q 10.4 11/03/2020 
+10.26 (b) 
+Form of Callon Petroleum Company Officer Cash Incentive Award Agreement, adopted on September 30, 2020, under the 2020 Omnibus Incentive Plan 
+10-Q 10.5 11/03/2020 
+10.27 (d) 
+Purchase Agreement among the Company, Chambers Investments, LLC and the guarantors named therein, dated September 30, 2020 
+8-K 10.1 10/01/2020 
+10.28 (a)(d) 
+Exchange Agreement among the Company and the holders of the Company’s senior notes party thereto, dated November 2, 2020 
+10.29 (a)(b) 
+Deferred Compensation Plan for Outside Directors, as Amended and Restated as of January 1, 2021 
+21.1 (a) 
+Subsidiaries of the Company 
+22.1 (a) 
+Subsidiary Guarantors 
+23.1 (a) 
+Consent of Grant Thornton LLP 
+118 
+23.2 (a) 
+Consent of DeGolyer and MacNaughton, Inc. 
+31.1 (a) 
+Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a) 
+31.2 (a) 
+Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a) 
+32.1 (c) 
+Section 1350 Certifications of Chief Executive and Financial Officers pursuant to Rule 13(a)-14(b) 
+99.1 (a) 
+Reserve Report Summary prepared by DeGolyer and MacNaughton, Inc. as of December 31, 2020 
+101.INS (a) XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. 
+101.SCH (a) Inline XBRL Taxonomy Extension Schema Document 
+101.CAL (a) Inline XBRL Taxonomy Extension Calculation Linkbase Document. 
+101.DEF (a) Inline XBRL Taxonomy Extension Definition Linkbase Document. 
+101.LAB (a) Inline XBRL Taxonomy Extension Label Linkbase Document. 
+101.PRE (a) Inline XBRL Taxonomy Extension Presentation Linkbase Document. 
+104 (a) Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. 
+(a) Filed herewith. 
+(b) Indicates management compensatory plan, contract, or arrangement. 
+(c) Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, except to the extent that the registrant specifically incorporates it by reference. 
+(d) Certain schedules and similar attachments have been omitted pursuant to Item 601(a)(5) of Regulation S-K. Callon agrees to furnish a supplemental copy of any omitted schedule or attachment to the SEC upon request. 
+ITEM 16. Form 10-K Summary 
+None. 
+119 
+SIGNATURES 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+Callon Petroleum Company 
+/s/ James P. Ulm, II Date: February 25, 2021 
+By: James P. Ulm, II 
+Chief Financial Officer (principal financial officer) 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+/s/ Joseph C. Gatto, Jr. Date: February 25, 2021 
+Joseph C. Gatto, Jr. (principal executive officer) 
+/s/ James P. Ulm, II Date: February 25, 2021 
+James P. Ulm, II (principal financial officer) 
+/s/ Gregory F. Conaway Date: February 25, 2021 
+Gregory F. Conaway (principal accounting officer) 
+/s/ L. Richard Flury Date: February 25, 2021 
+L. Richard Flury (chairman of the board of directors) 
+/s/ Frances Aldrich Sevilla-Sacasa Date: February 25, 2021 
+Frances Aldrich Sevilla-Sacasa (director) 
+/s/ Matthew R. Bob Date: February 25, 2021 
+Matthew R. Bob (director) 
+/s/ Barbara J. Faulkenberry Date: February 25, 2021 
+Barbara J. Faulkenberry (director) 
+/s/ Michael L. Finch Date: February 25, 2021 
+Michael L. Finch (director) 
+/s/ S.P. Johnson IV Date: February 25, 2021 
+S.P. Johnson IV (director) 
+/s/ Larry D. McVay Date: February 25, 2021 
+Larry D. McVay (director) 
+/s/ Anthony J. Nocchiero Date: February 25, 2021 
+Anthony J. Nocchiero (director) 
+/s/ James M. Trimble Date: February 25, 2021 
+James M. Trimble (director) 
+/s/ Steven A. Webster Date: February 25, 2021 
+Steven A. Webster (director) 
+120
\ No newline at end of file
diff --git a/raw/filings/0000928022/2020/0000928022-21-000021/filing_metadata.csv b/raw/filings/0000928022/2020/0000928022-21-000021/filing_metadata.csv
new file mode 100644
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+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000928022,CPE,Callon Petroleum Co,10-K,2021-02-25,2020-12-31,2021-02-25T21:45:05.000Z,0000928022-21-000021,cpe-20201231.htm,10-K,19721152,1,1,https://www.sec.gov/Archives/edgar/data/928022/000092802221000021/cpe-20201231.htm,https://www.sec.gov/Archives/edgar/data/928022/000092802221000021/,2020,2020,1
diff --git a/raw/filings/0000928022/2020/0000928022-21-000021/item1.txt b/raw/filings/0000928022/2020/0000928022-21-000021/item1.txt
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diff --git a/raw/filings/0000928022/2020/0000928022-21-000021/item13.txt b/raw/filings/0000928022/2020/0000928022-21-000021/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..314aad97a21e5f6472aba6cee542a89858510edd
--- /dev/null
+++ b/raw/filings/0000928022/2020/0000928022-21-000021/item13.txt
@@ -0,0 +1,2 @@
+ITEM 13. Certain Relationships and Related Transactions and Director Independence 
+The information required by this item is incorporated herein by reference to the 2021 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2020.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2020/0000928022-21-000021/item9a.txt b/raw/filings/0000928022/2020/0000928022-21-000021/item9a.txt
new file mode 100644
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--- /dev/null
+++ b/raw/filings/0000928022/2020/0000928022-21-000021/item9a.txt
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+ITEM 9A. Controls and Procedures 
+Disclosure controls and procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) performed an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2020. 
+Management’s report on internal control over financial reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. generally accepted accounting principles. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2020 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission (2013 framework) (the COSO criteria). Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2020. 
+Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+115 
+The Company’s independent registered public accounting firm, Grant Thornton, LLP, has issued an attestation report regarding its assessment of the Company’s internal control over financial reporting as of December 31, 2020, presented preceding the Company’s financial statements included in Part II, Item 8 of this 2020 Annual Report on Form 10-K. Additionally, the financial statements for the years ended December 31, 2019 and 2018, covered in this 2020 Annual Report on Form 10-K, have also been audited by the Company’s independent registered public accounting firm, whose report is presented preceding the their report on the Company’s internal control over financial reporting, included in Part II, Item 8. 
+Changes in internal control over financial reporting . There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2020/0000928022-21-000021/rp_note.txt b/raw/filings/0000928022/2020/0000928022-21-000021/rp_note.txt
new file mode 100644
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diff --git a/raw/filings/0000928022/2020/0000928022-21-000021/rpt_disclosure.txt b/raw/filings/0000928022/2020/0000928022-21-000021/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..a27097e1447823efdde938be53831fb58908068f
--- /dev/null
+++ b/raw/filings/0000928022/2020/0000928022-21-000021/rpt_disclosure.txt
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+Certain Relationships and Related Party Transactions 
+The Audit Committee charter provides that the Audit Committee shall review and approve all related party transactions. A transaction will be considered a “related party transaction” if the transaction would be required to be disclosed under Item 404 of Regulation S-K. In addition, our Code provides that an officer’s or a director’s conflict of interest with Callon may only be waived if the N&ESG Committee approves the waiver and the full Board ratifies the waiver. 
+We are not aware of any related party transactions with our executive officers that require disclosure under Item 404 of Regulation S-K. 
+Shareholders’ Proposals and Director Nominations for the 2022 Annual Meeting 
+In order for a proposal to be considered for inclusion in the proxy statement for the 2022 Annual Meeting of Shareholders (the “2022 Annual Meeting”) pursuant to Rule 14a-8 of the Exchange Act, such proposal must be received by the Secretary of the Company at our principal executive offices no later than December 10, 2021 (assuming the date of the 2022 Annual Meeting has not been changed by more than 30 days from the date of this year’s Annual Meeting), and must otherwise be in compliance with the requirements of the SEC’s proxy rules. If the date of the 2022 Annual Meeting has been changed by more than 30 days from the date of this Annual Meeting, then the deadline is a reasonable time before we begin to print and send our proxy materials for the 2022 Annual Meeting. 
+For a shareholder proposal to be introduced for consideration at the 2022 Annual Meeting but not intended to be considered for inclusion in the Company's proxy statement and form of proxy relating to such meeting (i.e. not pursuant to Rule 14a-8 of the Exchange Act), including shareholder nominations for candidates for election as directors, a shareholder must provide written notice of such proposal to Company not later than 120 days nor earlier than 150 days before the date of the 2022 Annual Meeting. Any such notice must describe the shareholder proposal in reasonable detail and otherwise comply with the requirements set forth in our bylaws. 
+Nominating Process 
+In accordance with our certificate of incorporation, any shareholder may nominate a person for election to the Board upon delivery of written notice to us of such nomination. Such notice must be sent as provided in our certificate of incorporation on or before the deadline set forth in our certificate of incorporation, and must otherwise comply with the procedures set forth in our certificate of incorporation. For nominations, the Board will consider individuals identified by shareholders on the same basis as nominees identified from other sources. A submission recommending a nominee should include: 
+• Sufficient biographical information to allow the N&ESG Committee to evaluate the qualifications of a potential nominee in light of the director nomination procedures and criteria and any other information that would be required to be disclosed in solicitations of proxies for the election of directors; 
+• An indication as to whether the proposed nominee will meet the requirements for independence under NYSE and SEC guidelines; 
+• A description of all direct and indirect compensation and other material monetary agreements, arrangements, and understandings during the past three years, and any other material relationships, between or among the nominating shareholder or beneficial owner and each proposed nominee; 
+• A completed and signed questionnaire, representation, and agreement, pursuant to our bylaws, with respect to each nominee for election or re-election to the Board; and 
+• The proposed nominee’s written consent to serve if nominated and elected.
\ No newline at end of file
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+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+FORM 10-K 
+☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the fiscal year ended December 31 , 2021 
+or 
+☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the transition period from ____________ to ____________ 
+Commission File Number 001-14039 
+Callon Petroleum Co mpany 
+(Exact Name of Registrant as Specified in Its Charter) 
+_______________________________________________ 
+Delaware 64-0844345 
+State or Other Jurisdiction of 
+Incorporation or Organization I.R.S. Employer Identification No. 
+One Briarlake Plaza 
+2000 W. Sam Houston Parkway S., Suite 2000 
+Houston, Texas 77042 
+Address of Principal Executive Offices Zip Code 
+281 - 589-5200 
+(Registrant’s Telephone Number, Including Area Code) 
+Title of Each Class Securities registered pursuant to Section 12(b) of the Act: Name of Each Exchange on Which Registered 
+Common Stock, $0.01 par value CPE New York Stock Exchange 
+Securities registered pursuant to section 12 (g) of the Act: None 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐ 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒ 
+Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ 
+Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐ 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act: 
+Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ☐ 
+Smaller reporting company ☐ Emerging growth company ☐ 
+. 
+If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ 
+Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ 
+The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2021 was approximately $ 2.6 billion. 
+The Registrant had 61,493,753 shares of common stock outstanding as of February 18, 2022 . 
+DOCUMENTS INCORPORATED BY REFERENCE 
+Portions of the definitive proxy statement of Callon Petroleum Company (to be filed no later than 120 days after December 31, 2021) relating to the 2022 Annual Meeting of Shareholders, which are incorporated into Part III of this Form 10-K. 
+TABLE OF CONTENTS 
+Special Note Regarding Forward - Looking Statements 
+3 
+Glossary of Certain Terms 
+4 
+Part I 
+Items 1 and 2. 
+Business and Properties 
+6 
+Oil and Natural Gas Properties 
+8 
+Proved Oil and Gas Reserves 
+8 
+Capital Budget 
+13 
+Drilling Activity 
+13 
+Productive Wells 
+13 
+Production Volumes, Average Sales Prices and Operating Costs 
+14 
+Major Customers 
+15 
+Leasehold Acreage 
+15 
+Human Capital 
+15 
+Other 
+16 
+Regulations 
+17 
+Commitments and Contingencies 
+26 
+Available Information 
+26 
+Item 1A. 
+Risk Factors 
+27 
+Item 1B. 
+Unresolved Staff Comments 
+41 
+Item 3. 
+Legal Proceedings 
+41 
+Item 4. 
+Mine Safety Disclosures 
+41 
+Part II 
+Item 5. 
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+42 
+Performance Graph 
+42 
+Item 6. 
+Reserved 
+44 
+Item 7. 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+44 
+General 
+44 
+Highlights 
+44 
+Results of Operations 
+45 
+Liquidity and Capital Resources 
+49 
+Critical Accounting Estimates 
+51 
+Item 7A. 
+Quantitative and Qualitative Disclosures About Market Risk 
+54 
+Item 8. 
+Financial Statements and Supplementary Data 
+56 
+Reports of Independent Registered Public Accounting Firm 
+57 
+Consolidated Balance Sheets 
+61 
+Consolidated Statements of Operations 
+62 
+Consolidated Statements of Stockholders’ Equity 
+63 
+Consolidated Statements of Cash Flows 
+64 
+Notes to Consolidated Financial Statements 
+65 
+Supplemental Information on Oil and Natural Gas Operations (Unaudited) 
+94 
+Item 9. 
+Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+98 
+Item 9A. 
+Controls and Procedures 
+98 
+Item 9B. 
+Other Information 
+99 
+Item 9 C . 
+Disclosure Regarding Foreign Jurisdictions that Prevent Inspections 
+99 
+Part III 
+Item 10. 
+Directors, Executive Officers and Corporate Governance 
+99 
+Item 11. 
+Executive Compensation 
+99 
+Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+99 
+Item 13. 
+Certain Relationships and Related Transactions and Director Independence 
+99 
+Item 14. 
+Principal Accountant Fees and Services 
+99 
+Part IV. 
+Item 15. 
+Exhibits and Financial Statement Schedules 
+100 
+Item 16. 
+Form 10-K Summary 
+102 
+Signatures 
+103 
+2 
+Special Note Regarding Forward-Looking Statements 
+This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements in this Form 10-K by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions. 
+All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future are forward-looking statements, including such things as: 
+• our oil and natural gas reserve quantities, and the discounted present value of these reserves; 
+• the amount and nature of our capital expenditures; 
+• our future drilling and development plans and our potential drilling locations; 
+• the timing and amount of future capital and operating costs; 
+• production decline rates from our wells being greater than expected; 
+• commodity price risk management activities and the impact on our average realized prices; 
+• business strategies and plans of management; 
+• our ability to efficiently integrate recent acquisitions; and 
+• prospect development and property acquisitions. 
+We caution you that the forward-looking statements contained in this Annual Report on Form 10-K (this “2021 Annual Report on Form 10-K”) are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. We disclose these and other important factors that could cause our actual results to differ materially from our expectations under “Risk Factors” in Item 1A of Part I in this 2021 Annual Report on Form 10-K. These factors include: 
+• the volatility of oil, natural gas and NGL prices or a prolonged period of low oil, natural gas or NGL prices; 
+• general economic conditions, including the availability of credit and access to existing lines of credit; 
+• changes in the supply of and demand for oil and natural gas, including as a result of the COVID-19 pandemic and various governmental actions taken to mitigate its impact or actions by, or disputes among, members of OPEC and other oil and natural gas producing countries, such as Russia, with respect to production levels or other matters related to the price of oil; 
+• the uncertainty of estimates of oil and natural gas reserves; 
+• impairments; 
+• the impact of competition; 
+• the availability and cost of seismic, drilling, completions and other equipment, waste and water disposal infrastructure, and personnel; 
+• operating hazards inherent in the exploration for and production of oil and natural gas; 
+• difficulties encountered during the exploration for and production of oil and natural gas; 
+• the potential impact of future drilling on production from existing wells 
+• difficulties encountered in delivering oil and natural gas to commercial markets; 
+• the uncertainty of our ability to attract capital and obtain financing on favorable terms; 
+• compliance with, or the effect of changes in, the extensive governmental regulations regarding the oil and natural gas business including those related to climate change and greenhouse gases; 
+• the impact of government regulation, including regulation of hydraulic fracturing and water disposal wells; 
+• any increase in severance or similar taxes; 
+• the financial impact of accounting regulations and critical accounting policies; 
+• the comparative cost of alternative fuels; 
+• credit risk relating to the risk of loss as a result of non-performance by our counterparties; 
+• cyberattacks on the Company or on systems and infrastructure used by the oil and natural gas industry; 
+• weather conditions; and 
+• risks associated with acquisitions. 
+Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Additional risks or uncertainties that are not currently known to us, that we currently deem to be immaterial, or that could apply to any company could also materially adversely affect our business, financial condition, or future results. Any forward-looking statement speaks only as of the date of which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. 
+In addition, we caution that reserve engineering is a process of estimating oil and natural gas accumulated underground and cannot be measured exactly. Accuracy of reserve estimates depend on a number of factors including data available at the point in time, 
+3 
+engineering interpretation of the data, and assumptions used by the reserve engineers as it relates to price and cost estimates and recoverability. New results of drilling, testing, and production history may result in revisions of previous estimates and, if significant, would impact future development plans. As such, reserve estimates may differ from actual results of oil and natural gas quantities ultimately recovered. 
+Except as required by applicable law, all forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. 
+GLOSSARY OF CERTAIN TERMS 
+All defined terms under Rule 4-10(a) of Regulation S-X shall have their prescribed meanings when used in this report. As used in this document: 
+• 12-Month Average Realized Price : Average realized prices for sales of oil, NGLs, and natural gas on the first calendar day of each month during a trailing 12-month period. 
+• ASU : Accounting standards update. 
+• Bbl or Bbls : Barrel or barrels of oil or natural gas liquids. 
+• Boe : Barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of natural gas. The ratio of one barrel of oil or NGLs to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. 
+• Boe/d : Boe per day. 
+• Btu : British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit. 
+• Completion : The installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency. 
+• Cushing : An oil delivery point that serves as the benchmark oil price for West Texas Intermediate. 
+• Development well : A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. 
+• EPA : United States Environmental Protection Agency. 
+• Exploratory well : A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. 
+• Extension well : A well drilled to extend the limits of a known reservoir. 
+• FASB : Financial Accounting Standards Board. 
+• GAAP : Accounting principles generally accepted in the United States. 
+• GHG : Greenhouse gases. 
+• Henry Hub : Natural gas pipeline delivery point that serves as the benchmark natural gas price underlying NYMEX natural gas futures contracts. 
+• Horizontal drilling : A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at an angle within a specified interval. 
+• ICE: Intercontinental Exchange. 
+• LIBOR : London Interbank Offered Rate. 
+• LOE : Lease operating expense. 
+• MBbls : Thousand barrels of oil. 
+• MBoe : Thousand Boe. 
+• Mcf : Thousand cubic feet of natural gas. 
+• MEH : Magellan East Houston, a delivery point in Houston, Texas that serves as a benchmark for crude oil. 
+• MMBoe : Million Boe. 
+• MMBtu : Million Btu. 
+• MMcf : Million cubic feet of natural gas. 
+• NGL or NGLs : Natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams. 
+• Non-productive well : A well that is found to be incapable of producing oil or gas in sufficient quantities to justify completion, or upon completion, the economic operation of an oil or gas well. 
+• NYMEX : New York Mercantile Exchange. 
+• Oil : Includes crude oil and condensate. 
+• OPEC : Organization of Petroleum Exporting Countries. 
+• Productive well : A well that is found to be capable of producing oil or gas in sufficient quantities to justify completion as an oil or gas well. 
+4 
+• Proved developed producing reserves (“PDPs”): Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. 
+• Proved reserves: Those reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12‑month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. 
+• Proved undeveloped reserves (“PUDs”): Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. 
+• PV-10 (Non-GAAP): Present value of estimated future gross revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date indicated (unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure of discounted future net cash flows calculation, it does provide an indicative representation of the relative value of the Company on a comparative basis to other companies from period to period. See “Items 1 and 2. Business and Properties - Proved Oil and Gas Reserves - Reconciliation of Standardized Measure of Discounted Future Net Cash Flows (GAAP) to PV-10 (Non-GAAP)”. 
+• Realized price : The cash market price less all expected quality, transportation and demand adjustments. 
+• Royalty interest : An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development. 
+• SEC : United States Securities and Exchange Commission. 
+• Waha : A natural gas delivery point in West Texas that serves as the benchmark for natural gas. 
+• Working interest : An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations. 
+• WTI : West Texas Intermediate grade crude oil, used as a pricing benchmark for sales contracts and NYMEX oil futures contracts. 
+With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross. 
+5 
+PART I. 
+ITEMS 1 and 2. Business and Properties 
+Overview 
+Callon Petroleum Company has been engaged in the exploration, development, acquisition and production of oil and natural gas properties since 1950. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. 
+We are an independent oil and natural gas company focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas. Our activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger Permian Basin in West Texas, as well as the Eagle Ford in South Texas. Our primary operations in the Permian reflect a high-return, oil-weighted drilling inventory with multiple prospective horizontal development intervals and are complemented by a well-established and repeatable cash flow-generating business in the Eagle Ford. 
+Major Developments in 2021 
+Financing and Liquidity Highlights 
+• We decreased our total outstanding long-term debt principal balance by approximately 10% to $2.7 billion as of December 31, 2021, from $3.0 billion as of December 31, 2020. 
+• As of December 31, 2021, our senior secured revolving credit facility (“Credit Facility”) had a borrowing base and elected commitment amount of $1.6 billion with borrowings outstanding of $785.0 million, representing less than 50% of our borrowing base. 
+• On November 5, 2021, we completed the exchange of $197.0 million in aggregate principal amount of our 9.00% Second Lien Senior Secured Notes due 2025 (the “Second Lien Notes”) for 5.5 million shares of our common stock (the “Second Lien Note Exchange”). 
+• On July 6, 2021, we issued $650.0 million in aggregate principal amount of our 8.00% senior unsecured notes due 2028 (the “8.00% Senior Notes”) in a private placement for proceeds of approximately $638.1 million, net of underwriting discounts and commissions and offering costs. We used a portion of the net proceeds from the 8.00% Senior Notes to redeem all $542.7 million of our outstanding 6.25% Senior Notes due 2023 (the “6.25% Senior Notes”) and the remaining proceeds to partially repay amounts outstanding under our Credit Facility. 
+See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for further discussion. 
+Primexx Acquisition. On October 1, 2021, we completed the acquisition of certain producing oil and gas properties, undeveloped acreage and associated infrastructure assets in the Delaware Basin from Primexx Resource Development, LLC and BPP Acquisition, LLC (the “Primexx Acquisition”) for total consideration of $880.8 million. Additionally, certain interest owners exercised their option to sell their interest in the properties included in the Primexx Acquisition to us for consideration structured similarly to the Primexx Acquisition, for an incremental purchase price totaling approximately $33.1 million. These transactions added approximately 37,000 net acres to our portfolio in the Permian Basin. See “Note 4 – Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for further discussion. 
+Non-Core Asset Divestitures. During 2021, we completed divestitures of certain non-core assets in the Delaware Basin, Midland Basin and Eagle Ford Shale as well as the divestiture of certain non-core water infrastructure for total net proceeds of $181.8 million, subject to post-closing adjustments, and up to $18.0 million of incremental contingent consideration . See “Note 4 – Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for further discussion. 
+Operational Activity. During the year ended December 31, 2021, we drilled 68 gross (61.3 net) wells and completed 112 gross (103.8 net) wells. Our net daily production was 95,599 Boe/d (approximately 64% oil), a decrease of approximately 6% when compared to the year ended December 31, 2020, primarily as a result of the divestitures that occurred during 2021 as well as normal production decline, partially offset by production resulting from our developmental activities during the year as well as production from the properties acquired in the Primexx Acquisition. For the year ended December 31, 2021, our estimated proved reserves were 484.6 MMBoe and included proved oil reserves of 290.3 MMBbls (60% of total proved reserves). Approximately 57% of our 2021 year-end estimated proved reserves were classified as proved developed. See “— Summary of 2021 Proved Reserves, Production and Drilling by Region” below for additional details. 
+6 
+Our Business Strategy 
+Our principal objective is to enhance shareholder value through capital efficient development of our proved reserves, management of our operating costs, and maximization of cash flows while acting as a responsible corporate citizen in the areas in which we operate. Key elements of the execution of this strategy include: 
+• Optimizing the development of our multi-zone resource base through thoughtful plans for life of field development that are informed by extensive analysis of subsurface data and empirical well results; 
+• Improving the capital efficiency of our operations in terms of both well productivity and capital outlays, including supporting facilities; 
+• Maintaining strong cash margins per unit of production through cost management and proactive investment in production infrastructure; 
+• Maximizing and preserving our inventory of well locations through selective delineation of emerging targets on our existing acreage positions and scaled development of proven areas to minimize potential degradation of future drilling locations; 
+• Integrating sustainable business practices that minimize our impact on the environment, empower and develop a diverse workforce, and enrich our communities; and 
+• Enhancing our financial position, focusing on appropriate capital allocation decisions under various commodity pricing scenarios, prudent risk management and generating free cash flow to reduce leverage. 
+Our Strengths 
+We believe the following attributes position Callon to achieve its objectives: 
+• Strong Foundation - Reputation as a safe and responsible operator built over several decades in the oil and gas industry; 
+• Quality Assets - High quality Permian asset base with several years of proven well results from multiple target zones that benefit from early investments in critical supporting infrastructure including sustainable investments in water recycling and a more mature asset base in the Eagle Ford which has lower operational risk and generates repeatable, profitable well results; 
+• Operational Control - High degree of operational control that allows us to efficiently maximize value through daily and long-term decisions that drive our strategy; 
+• Talented Workforce - Dedicated and experienced employee base working within a collaborative culture to achieve both personal and collective goals; and 
+• Sustainable Business Practices - Focus on value creation in a responsible manner by utilizing an operating philosophy that provides our employees a safe workplace while at the same time conducting operations in a manner that seeks to reduce our impact on the environment. See our Sustainability Report published on our company website (www.callon.com) for performance highlights and additional information. Information contained in our Sustainability Report is not incorporated by reference into, and does not constitute a part of, this 2021 Annual Report on Form 10-K. 
+7 
+Oil and Natural Gas Properties 
+Summary of 2021 Proved Reserves, Production and Drilling by Region 
+Permian Eagle Ford Total 
+Proved reserves 
+Crude oil (MBbls) 235,450 54,846 290,296 
+Natural gas (MMcf) 523,435 53,892 577,327 
+NGLs (MBbls) 88,707 9,397 98,104 
+Total proved reserves (MBoe) 411,396 73,225 484,621 
+Proved reserves by classification (MBoe) 
+Proved developed 222,105 51,878 273,983 
+Proved undeveloped 189,291 21,347 210,638 
+Total proved reserves (MBoe) 411,396 73,225 484,621 
+Percent of proved developed reserves 81 % 19 % 100 % 
+Percent of proved undeveloped reserves 90 % 10 % 100 % 
+Percent of total reserves 85 % 15 % 100 % 
+Production volumes Total Per Day Total Per Day Total Per Day 
+Crude oil (MBbls and Bbls/d) 14,475 39,658 7,749 21,229 22,224 60,887 
+Natural gas (MMcf and Mcf/d) 29,682 81,320 7,704 21,107 37,386 102,427 
+NGLs (MBbls and Bbls/d) 5,155 14,123 1,284 3,518 6,439 17,641 
+Total production volumes (MBoe and Boe/d) 24,577 67,334 10,317 28,265 34,894 95,599 
+Percent of total production 70 % 30 % 100 % 
+Permian Eagle Ford Total 
+Operated Well Data Gross Net Gross Net Gross Net 
+Drilled 54 47.5 14 13.8 68 61.3 
+Completed 67 59.0 45 44.8 112 103.8 
+As of December 31, 2021 
+Drilled but uncompleted 21 19.4 6 5.8 27 25.2 
+Producing 738 654.3 588 532.8 1,326 1,187.1 
+Proved Oil and Gas Reserves 
+The following table sets forth summary information with respect to our estimated proved reserves, standardized measure of discounted future net cash flows and PV-10 for the years ended December 31, 2021, 2020, and 2019. For each year in the table below, the estimated proved reserves were prepared by DeGolyer and MacNaughton (“D&M”), Callon’s independent third party reserve engineers, with the exception of the estimated proved reserves in 2019 obtained as a result of the Carrizo Acquisition in late 2019, which were prepared by Ryder Scott Company, L.P. (“Ryder Scott”), the independent third party reserve engineers historically retained by Carrizo. For further information concerning D&M’s estimates of our proved reserves as of December 31, 2021, see the reserve report included as an exhibit to this 2021 Annual Report on Form 10-K. In accordance with SEC rules, we used the 12-Month Average Realized Price of oil, NGLs, and natural gas in the calculation of our estimated proved reserves and PV-10. 
+8 
+As of December 31, 
+2021 2020 2019 
+Proved developed reserves (1) 
+Crude oil (MBbls) 162,886 128,923 152,687 
+Natural gas (MMcf) 332,266 238,119 320,676 
+NGLs (MBbls) 55,720 43,315 24,844 
+Total proved developed reserves (MBoe) 273,983 211,925 230,977 
+Proved undeveloped reserves (1) 
+Crude oil (MBbls) 127,410 160,564 193,674 
+Natural gas (MMcf) 245,061 303,479 436,458 
+NGLs (MBbls) 42,384 52,811 42,618 
+Total proved undeveloped reserves (MBoe) 210,638 263,954 309,035 
+Total proved reserves (1) 
+Crude oil (MBbls) 290,296 289,487 346,361 
+Natural gas (MMcf) 577,327 541,598 757,134 
+NGLs (MBbls) 98,104 96,126 67,462 
+Total proved reserves (MBoe) 484,621 475,879 540,012 
+Proved developed reserves % 57 % 45 % 43 % 
+Proved undeveloped reserves % 43 % 55 % 57 % 
+12-Month Average Realized Prices 
+Crude oil ($/Bbl) $65.44 $37.44 $53.90 
+Natural gas ($/Mcf) $3.31 $1.02 $1.55 
+NGLs ($/Bbl) $29.19 $11.10 $15.58 
+Standardized measure of discounted future net cash flows (GAAP) (in millions) $6,250.8 $2,310.4 $4,951.0 
+PV-10 (Non-GAAP) (in millions): 
+Proved developed PV-10 $4,502.6 $1,577.3 $3,246.8 
+Proved undeveloped PV-10 2,548.7 767.7 2,122.8 
+Total PV-10 (Non-GAAP) $7,051.3 $2,345.0 $5,369.6 
+(1) Effective January 1, 2020, certain of our natural gas processing agreements were modified to allow us to take title to NGLs resulting from the processing of our natural gas. As a result, reserve volumes for NGLs and natural gas are presented separately for periods subsequent to January 1, 2020. For periods prior to January 1, 2020, except for reserve volumes specifically associated with Carrizo, we presented our reserve volumes for NGLs with natural gas. 
+Reconciliation of Standardized Measure of Discounted Future Net Cash Flows (GAAP) to PV-10 (Non-GAAP) 
+We believe that the presentation of PV-10 provides greater comparability when evaluating oil and gas companies due to the many factors unique to each individual company that impact the amount and timing of future income taxes. In addition, we believe that PV-10 is widely used by investors and analysts as a basis for comparing the relative size and value of our proved reserves to other oil and gas companies. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company’s financial or operating performance presented in accordance with GAAP. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of our proved oil and gas reserves. 
+As of December 31, 
+2021 2020 2019 
+(In millions) 
+Standardized measure of discounted future net cash flows (GAAP) $6,250.8 $2,310.4 $4,951.0 
+Add: present value of future income taxes discounted at 10% per annum 800.5 34.6 418.6 
+PV-10 (Non-GAAP) $7,051.3 $2,345.0 $5,369.6 
+9 
+Proved Reserves 
+Our reserve estimates are conducted from fundamental petrophysical, geological, engineering, financial and accounting data. Reserves are estimated based on production decline analysis, analogy to producing offsets, detailed reservoir modeling, volumetric calculations or a combination of these methods, in all cases having regard to economic considerations and using technologies that have been demonstrated in the field to yield repeatable and consistent results as defined in the SEC regulations. To establish reasonable certainty of our proved reserves estimates, including material additions to our proved reserves, we use certain technologies and economic data, including production and well test data, historical well costs and operating data, geologic and seismic data, and subsurface information obtained through wellbores such as electrical logs, radioactive logs, reservoir core samples, fluid samples, and static and dynamic pressure information. Non-producing reserves are estimated by analogy to producing offsets, with consideration given to a development plan approved by Callon’s management. 
+As of December 31, 2021, our estimated proved reserves totaled 484.6 MMBoe, an increase of 2% from the prior year end, and included 290.3 MMBbls of oil, 577.3 Bcf of natural gas and 98.1 MMBbls of NGLs with a standardized measure of discounted future net cash flows of $6.3 billion. Oil constituted approximately 60% of our total estimated proved reserves as well as our total estimated proved developed reserves. The following table provides a summary of the changes in our proved reserves for the year ended December 31, 2021. 
+Total 
+(MBoe) 
+Proved reserves as of December 31, 2020 
+475,879 
+Extensions and discoveries 36,180 
+Revisions to previous estimates (14,181) 
+Purchase of reserves in place 57,652 
+Sales of reserves in place (36,015) 
+Production (34,894) 
+Proved reserves as of December 31, 2021 
+484,621 
+Further details of the changes in our proved reserves for the year ended December 31, 2021 are as follows: 
+• Extensions and Discoveries. We added 36.2 MMBoe of new reserves in extensions and discoveries through our development efforts in our operating areas. See the table below for the impact of extensions and discoveries on total proved and proved undeveloped reserves for 2021: 
+Extensions and discoveries Total 
+(MBoe) 
+Total proved 36,180 
+Proved undeveloped 26,044 
+Difference (Proved developed producing) (1) 
+10,136 
+(1) These extensions and discoveries were not recognized as proved undeveloped reserves in a prior period, but rather were recognized directly as proved developed producing reserves as there was not an offset proved developed producing location at the time of drilling in order to classify as a proved undeveloped location. 
+We incurred costs of $87.0 million for the extensions and discoveries associated with proved developed producing wells and $52.7 million on facilities associated with proved developed producing wells during 2021. 
+• Revisions to Previous Estimates. The table below shows the components of the net negative revisions of previous estimates of 14.2 MMBoe. 
+Total 
+(MBoe) 
+Pricing (1) 
+27,932 
+PUDs removed due to changes in development plan (2) 
+(29,016) 
+Performance (3) 
+(13,097) 
+Total revisions to previous estimates (14,181) 
+(1) Primarily as a result of the change in 12-Month Average Realized Price of crude oil, which increased approximately 75% as compared to December 31, 2020. 
+(2) Removed primarily as a result of changes in anticipated well densities as we develop our properties in an effort to increase capital efficiency and cash flow generation as well as changes in our development plans, primarily due to the Primexx Acquisition, which resulted in PUDs being moved outside of the five-year development window. 
+10 
+(3) Primarily related to reductions in anticipated hydrocarbon recoveries resulting from observed well performance over longer production timeframes during the testing of various full field development plan concepts. 
+• Purchase of Reserves in Place. The 57.7 MMBoe of purchases of reserves in place was associated with the Primexx Acquisition. See “Note 4 - Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for further discussion. 
+• Sales of Reserves in Place. The 36.0 MMBoe of sales of reserves in place were primarily associated with the divestitures of non-core assets in the Western Delaware Basin in the second quarter of 2021 and the Eagle Ford Shale and Midland Basin in the fourth quarter of 2021. See “Note 4 - Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for further discussion. 
+Proved Undeveloped Reserves 
+Annually, we review our PUDs to ensure appropriate plans exist for development of this reserve category. PUD reserves are recorded only if we have plans to convert these reserves into PDPs within five years of the date they are first recorded. Our development plans include the allocation of capital to projects included within our 2022 Capital Budget, as defined below, and, in subsequent years, the allocation of capital within our long-range business plan to convert PUDs to PDPs within this five-year period. The following table provides a summary of the changes in our PUDs for the year ended December 31, 2021. 
+Total 
+(MBoe) 
+PUDs as of December 31, 2020 
+263,954 
+Extensions and discoveries 26,044 
+Revisions to previous estimates (34,235) 
+Purchases of reserves in place 14,960 
+Sales of reserves in place (21,205) 
+Converted to proved developed (38,880) 
+PUDs as of December 31, 2021 
+210,638 
+• Extensions and Discoveries. We added 26.0 MMBoe of new reserves in extensions and discoveries as a result of additional offset locations associated with our drilling program. 
+• Revisions to Previous Estimates. The table below shows the components of the net negative revisions of previous estimates of 34.2 MMBoe. 
+Total 
+(MBoe) 
+Pricing (1) 
+3,541 
+PUDs removed due to changes in development plan (2) 
+(29,016) 
+Performance (3) 
+(8,760) 
+Total revisions to previous estimates (34,235) 
+(1) Primarily as a result of the change in 12-Month Average Realized Price of crude oil, which increased by approximately 75% as compared to December 31, 2020. 
+(2) Removed primarily as a result of changes in anticipated well densities as we develop our properties in an effort to increase capital efficiency and cash flow generation as well as changes in our development plans, primarily due to the Primexx Acquisition, which resulted in PUDs being moved outside of the five-year development window. 
+(3) Primarily related to reductions in anticipated hydrocarbon recoveries resulting from observed well performance over longer production timeframes during the testing of various full field development plan concepts. 
+• Sales of Reserves in Place. The 21.2 MMBoe of sales of reserves in place were associated with the divestitures of non-core assets in the Eagle Ford Shale and Midland Basin in the fourth quarter of 2021. See “Note 4 - Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for further discussion. 
+• Converted to Proved Developed. During 2021, we converted 38.9 MMBoe of PUDs that were booked as PUDs as of December 31, 2020 to proved developed at a cost of $210.2 million, or $5.41 per Boe. During 2021, our PUD conversion was below 20% primarily as a result of the removal of PUDs due to the changes in development plans discussed above. We currently estimate that we will convert over 50% of our PUDs as of December 31, 2021 in 2022 and 2023. 
+During 2021, we also incurred $47.0 million on PUDs that were drilled but uncompleted as of December 31, 2021. As of December 31, 2021, we had 9.0 MMBoe of PUDs associated with drilled but uncompleted wells. All of the reserves associated with drilled but uncompleted wells are scheduled to be completed in 2022. We expect to incur approximately $43.3 million of capital expenditures to 
+11 
+complete these wells. We also incurred $72.9 million on wells in progress and $20.5 million converting PUDs that were included in divestitures in 2021. 
+At December 31, 2021, we did not have any reserves that have remained undeveloped for five or more years since the date of their initial booking and all PUD locations are scheduled to be developed within five years of their initial booking. 
+Qualifications of Technical Persons 
+In accordance with the Standards Pertaining to Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers, D&M prepared 100% of our estimates of proved reserves as of December 31, 2021 and 2020 and 40% of our proved reserves as of December 31, 2019. Ryder Scott prepared the estimates of proved reserves associated with the Carrizo Acquisition, which comprised approximately 60% of our proved reserves as of December 31, 2019. D&M is a respected company in the reservoir engineering field and provides petroleum property analysis for other upstream companies. The technical persons responsible for preparing the reserves estimates meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Neither D&M nor Ryder Scott owns an interest in our properties, and neither is employed on a contingent fee basis. 
+Our internal director of reserves has over 20 years of experience in the petroleum industry and extensive experience in the estimation of reserves and the review of reserve reports prepared by third party engineering firms. Compliance as it relates to reporting the Company’s reserves is the responsibility of our Chief Operating Officer, who is also our principal engineer. He has over 30 years of operations and industry experience and holds B.S. and Ph.D. degrees in Petroleum Engineering, in addition to a M.S. in Environmental and Planning Engineering, and is experienced in asset evaluation and management. 
+Internal Controls Over Reserve Estimation Process 
+The primary inputs to the reserve estimation process are comprised of technical information, financial data, production data, and ownership interest. All field and reservoir technical information is assessed for validity when the internal reserve engineer holds technical meetings with our geoscientists, operations, and land personnel to discuss field performance and to validate future development plans. The other inputs used in the reserve estimation process, including, but not limited to, future capital expenditures, commodity price differentials, production costs, and ownership percentages are subject to internal controls over financial reporting and are assessed for effectiveness annually. 
+To further enhance the control environment over the reserve estimation process, our Operations and Reserves Committee, an independent committee of the Company’s board of directors (the “Board of Directors”), assists management and the Board of Directors with its oversight of the integrity of the determination of our oil and natural gas reserves and the work of the independent third party reserve engineers. The Operations and Reserves Committee’s charter also specifies that it shall perform, in consultation with the Company’s management and senior reserves and reservoir engineering personnel, the following responsibilities: 
+• Oversee the appointment, qualification, independence, compensation and retention of the independent third party reserve engineers engaged by the Company (including resolution of material disagreements between management and the independent third party reserve engineers regarding reserve determination) for the purpose of preparing or issuing an annual reserve report. The Operations and Reserves Committee shall review any proposed changes in the appointment of the independent third party reserve engineers, determine the reasons for such proposal, and whether there have been any disputes between the independent third party reserve engineers and management. 
+• Review the Company’s significant reserves engineering principles and any material changes thereto, and any proposed changes in reserves engineering standards and principles which have, or may have, a material impact on the Company’s reserves disclosure. 
+• Review with management and the independent third party reserve engineers the proved reserves of the Company, and, if appropriate, the probable reserves, possible reserves and the total reserves of the Company, including: (i) reviewing significant changes from prior period reports; (ii) reviewing key assumptions used or relied upon by the independent third party reserve engineers; (iii) evaluating the quality of the reserve estimates prepared by the independent third party reserve engineers and the Company relative to the Company’s peers in the industry; and (iv) reviewing any material reserves adjustments and significant differences between the Company’s and independent third party reserve engineers’ estimates. 
+• If the Operations and Reserves Committee deems it necessary, it shall meet in executive session with the independent third party reserve engineers to discuss the oil and gas reserve determination process and related public disclosures, and any other matters of concern in respect of the evaluation of the reserves. 
+During our last fiscal year, we filed no reports with other federal agencies which contain an estimate of proved reserves. 
+See “Item 8. Financial Statements and Supplementary Data - Supplemental Information on Oil and Natural Gas Operations” for additional information regarding our estimated proved reserves and the present value of estimated future net revenues from these proved reserves. 
+12 
+Capital Budget 
+Our Board approved an operational capital budget for expenditures of $725.0 million (the “2022 Capital Budget”), with approximately 80% directed towards drilling, completion, and equipment expenditures. Our scaled development plan for 2022 will continue to employ our life of field development strategy, whereby capital is allocated towards full development plans of depletion and optimal usage of infrastructure. Over 85% of the 2022 Capital Budget is allocated to development in the Permian with the balance for development in the Eagle Ford. 
+Our revenues, earnings, and liquidity are substantially dependent on the prices we receive for, and our ability to develop, our reserves of oil and natural gas. We believe that we are positioned to execute on our strategy even during downturns in the industry due to our resource base, low cost structure, risk management, and disciplined investment of capital. We monitor current and expected market conditions, including the commodity price environment, and our liquidity needs and may adjust our capital investment plan accordingly. 
+Drilling Activity 
+The following table sets forth our operated and non-operated drilling activity for the years ended December 31, 2021, 2020, and 2019. As defined by the SEC, the number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. For definitions of exploratory wells, extension wells, development wells, productive wells, and non-productive wells, see “—Glossary of Certain Terms.” 
+Years Ended December 31, 
+2021 2020 
+2019 (1) 
+Gross Net Gross Net Gross Net 
+Extension Wells - Productive 19 17.2 22 16.0 56 36.7 
+Extension Wells - Non-productive — — — — — — 
+Development Wells - Productive 93 86.7 73 66.0 15 11.6 
+Development Wells - Non-productive — — — — — — 
+(1) Includes activity on properties acquired in the Carrizo Acquisition subsequent to the December 20, 2019 closing date. 
+Productive Wells 
+The following table sets forth the number of productive crude oil and natural gas wells in which we owned an interest as of December 31, 2021. 
+Crude Oil Natural Gas Total 
+Gross Net Gross Net Gross Net 
+Permian - Operated 919 814.8 99 84.9 1,018 899.7 
+Permian - Non-operated 46 5.7 6 0.6 52 6.3 
+Total Permian 965 820.5 105 85.5 1,070 906.0 
+Eagle Ford - Operated 532 480.2 77 69.7 609 549.9 
+Eagle Ford - Non-operated 13 0.8 — — 13 0.8 
+Total Eagle Ford 545 481.0 77 69.7 622 550.7 
+Total 1,510 1,301.5 182 155.2 1,692 1,456.7 
+13 
+Production Volumes, Average Sales Prices and Operating Costs 
+The following tables set forth certain information regarding the production volumes and average sales prices received for, and average production costs associated with, our sales of oil, natural gas and NGLs for the periods indicated. For further details, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations”. 
+Years Ended December 31, 
+2021 2020 
+2019 (1) 
+Total production (2) 
+Oil (MBbls) 
+Permian 14,475 14,113 11,365 
+Eagle Ford 7,749 9,430 300 
+Total oil 22,224 23,543 11,665 
+Natural gas (MMcf) 
+Permian 29,682 32,087 19,484 
+Eagle Ford 7,704 8,714 234 
+Total natural gas 37,386 40,801 19,718 
+NGLs (MBbls) 
+Permian 5,155 5,390 93 
+Eagle Ford 1,284 1,460 42 
+Total NGLs 6,439 6,850 135 
+Total production (MBoe) 
+Permian 24,577 24,851 14,705 
+Eagle Ford 10,317 12,342 381 
+Total barrels of oil equivalent 34,894 37,193 15,086 
+Average realized sales price (2) (excluding impact of derivative settlements) 
+Oil (per Bbl) $68.22 $36.13 $54.27 
+Natural gas (per Mcf) 3.78 1.27 1.85 
+NGL (per Bbl) 30.11 11.87 15.37 
+Total average realized sales price (per Boe) $53.06 $26.45 $44.52 
+Operating costs per Boe 
+Lease operating expense $5.82 $5.22 $6.09 
+Production and ad valorem taxes $2.87 $1.68 $2.83 
+Gathering, transportation and processing $2.32 $2.08 $— 
+(1) Includes activity on properties acquired in the Carrizo Acquisition subsequent to the December 20, 2019 closing date. 
+(2) Effective January 1, 2020, certain of our natural gas processing agreements were modified to allow us to take title to NGLs resulting from the processing of our natural gas. As a result, sales volumes and prices for NGLs and natural gas are presented separately for periods subsequent to January 1, 2020. For periods prior to January 1, 2020, except for sales volumes and prices specifically associated with Carrizo, we presented our sales volumes and prices for NGLs with natural gas. 
+14 
+Major Customers 
+Our production is sold generally on month-to-month contracts at prevailing market prices. The following table presents customers that represented 10% or more of our total revenues for at least one of the periods presented: 
+Years Ended December 31, 
+2021 2020 2019 
+Shell Trading Company 20% 31% 10% 
+Trafigura Trading, LLC 15 * * 
+Occidental Energy Marketing, Inc. 13 * * 
+Valero Marketing and Supply Company 13 23 * 
+Rio Energy International, Inc. * * 26 
+Enterprise Crude Oil, LLC * * 19 
+Plains Marketing, L.P. * * 15 
+* - Less than 10% for the respective years. 
+Because alternative purchasers of oil and natural gas are readily available, we believe that the loss of any of these purchasers would not result in a material adverse effect on our ability to sell future oil and natural gas production. In order to mitigate potential exposure to credit risk, we may require from time to time for our customers to provide financial security. 
+Leasehold Acreage 
+The following table shows our approximate developed and undeveloped leasehold acreage as of December 31, 2021. Developed acreage refers to acreage on which wells have been completed to a point that would permit production of oil and gas in commercial quantities. Undeveloped acreage refers to acreage on which wells have not been drilled or completed to a point that would permit production of oil and gas in commercial quantities whether or not the acreage contains proved reserves. 
+Developed Acreage Undeveloped Acreage Total Acreage Net Undeveloped Acreage Expiring 
+Gross Net Gross Net Gross Net 2022 2023 2024 
+Permian (1) 
+151,368 128,777 9,555 6,363 160,923 135,140 2,439 157 256 
+Eagle Ford (2) 
+63,431 52,553 2,553 445 65,984 52,998 20 — — 
+Other (3) 
+2,080 122 71,059 55,837 73,139 55,959 48,504 3,398 2,994 
+Total 216,879 181,452 83,167 62,645 300,046 244,097 50,963 3,555 3,250 
+(1) Based on our current plans, approximately 67%, 76% and 63% of the acreage expiring in 2022, 2023 and 2024, respectively, will be developed prior to expiration or extended by lease extension payments. 
+(2) Based on our current plans, approximately 100% of the acreage expiring in 2022 will be developed prior to expiration or extended by lease extension payments. 
+(3) Consists of non-core acreage principally located in Texas. We have no current development plans and no proved undeveloped reserves associated with this acreage as of December 31, 2021. 
+Our lease agreements generally terminate if producing wells have not been drilled on the acreage within their primary term or an extension thereof (a period that is generally from three to five years depending on the area). The percentage of net undeveloped acreage expiring in 2022, 2023 and 2024 assumes that no producing wells have been drilled on acreage within their primary term or have been extended. We manage our lease expirations to ensure that we do not experience unintended material loss of acreage or depths. Our leasehold management efforts include scheduling drilling in order to hold leases by production or timely exercising our contractual rights to extend the terms of leases by continuous operations or the payment of lease extension payments and delay rentals. We may choose to allow some leases to expire that are no longer part of our development plans. 
+The proved undeveloped reserves associated with acreage expiring over the next three years are not material to the Company. 
+Human Capital 
+Callon employs a talented workforce that is integral to our success, and we are committed to the safety, health, and development of each team member. The Callon culture is defined by our values of responsibility, integrity, drive, respect and excellence. These core values are a reflection of our ideals as individuals and direct our actions as a company. 
+Callon’s key human capital management objectives are to attract, retain and develop talent to deliver on our strategy. Due to the technical nature of our business, our success depends on a highly skilled workforce in multiple disciplines including engineering, geology, operations, land, information technology and various other corporate functions. To support the attraction and retention of top talent, our human resources programs are designed to keep our employees safe and healthy, engage employees with an inclusive 
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+workplace, reward and support employees through competitive pay and benefit programs, and develop talent to support personal growth and prepare employees for high impact roles and leadership positions. 
+As of December 31, 2021, Callon had 322 permanent, full-time employees. None of our employees are currently represented by a union, and we believe that we have good relations with our employees. 
+We focus on the following in supporting our human capital: 
+• Inclusion and Diversity - We believe that diversity of backgrounds and perspectives contributes to an innovative workforce and an enriching environment for our employees. Callon is firmly committed to fostering an inclusive, respectful environment and providing equal opportunity to all qualified persons in our hiring, development, and compensation practices. As of December 31, 2021, approximately 37% of our permanent, full-time employees were minorities, 21% were female, and 35% of above-field employees were female. We continually seek to expand diversity in our workforce, and in 2021, 37% of our newly hired employees represented minorities and 40% were female. 
+• Health and Safety - Protecting our employees, contractors and communities is a core value at Callon and our top priority. Our Operations Management System (“OMS”) establishes clear expectations for operating safely and responsibly throughout the lifecycle of our business. We identify and mitigate safety risks and integrate a culture of safety by operating according to OMS standards, processes, and procedures. Additionally, we share our Safety and Environmental Policy with all employees and contractors which includes each individual’s authorization and responsibility to stop work on any activity without the threat or fear of job reprisal. To reinforce accountability for safety results, our Board of Directors included safety performance as a factor in our 2021 annual bonus program. 
+• Employee Compensation, Benefits and Wellness - Our compensation and benefits programs provide a package designed to attract, retain and motivate employees. In addition to competitive base salaries, we provide a variety of short-term and long-term incentive compensation programs to reward performance relative to key financial, operational, and ESG metrics. Callon invests in the health and well-being of our employees and their families by paying 100% of the premiums for our health care plan, which includes telemedicine and an Employee Assistance Program. We also offer comprehensive benefit options including a retirement savings plan, life and disability insurance, health savings accounts, flexible spending accounts, and a charitable matching program. 
+• Employee Development - We believe that ongoing investment in the development of our team members is key to our future success, as well as the retention of our employees. Callon fosters an entrepreneurial workplace where employees can expand their skill sets and experience by direct engagement and collaboration with leaders at all levels. Additionally, we offer tuition assistance and access to various training programs, including a monthly in-house leadership development program in 2021. Our leaders support all of our employees in reaching their personal goals through ongoing feedback and development conversations. 
+For additional information, please see our Sustainability Report published on our company website (www.callon.com). 
+Other 
+Industry Segment and Geographic Information 
+For segment reporting purposes, Callon considers all of the current development and operating areas to be one reportable segment: the development and production of oil and natural gas. All of our assets are located within the United States and all operations are located within Texas. All of the production revenues generated from operations are contracted and sold to customers located in the United States. 
+Title to Properties 
+We believe that the title to our oil and natural gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of such properties. Nevertheless, we can be involved in title disputes from time to time which may result in litigation. Our properties are potentially subject to burdens such as royalty, overriding royalty, working and other outstanding interests customary in the industry. To the extent that such burdens and obligations affect our rights to production revenues, these characteristics have been taken into account in calculating our net revenue interests and in estimating the size and value of our estimated proved reserves. We believe that the burdens and obligations affecting our properties are typical within the industry for properties of the kind owned by Callon. 
+Seasonality of Business 
+Weather conditions and seasonality affect the demand for and prices of, oil and natural gas. Due to these fluctuations, results of operations for quarterly interim periods may not be indicative of the results realized on an annual basis. 
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+Competition 
+We operate in the oil and natural gas industry, which is highly competitive. Our business experiences strong competition from a number of parties that may range from small independent producers to major integrated companies. Competition affects our ability to acquire additional properties and resources necessary to develop assets. In higher commodity pricing environments, competition also exists in the form of contracting for drilling, pumping, and workover equipment, and securing skilled personnel to both develop and operate existing assets. Many of the competitors mentioned above may be able to pay for more sought-after properties or access equipment, infrastructure, or personnel. The industry also experiences, from time to time, shortages in resources such as the availability of drilling and workover rigs, other equipment, pipes and materials, infrastructures, and skilled personnel, all of which can delay development, exploration, and workover activities as well as result in significant cost increases. 
+Insurance 
+In accordance with industry practice, we maintain insurance against some of the operating risks to which our business is exposed. While not all inclusive, our insurance policies generally protect against bodily injury and property damage, pollution and other environmental damages, employee benefits, employee injury and control of well insurance for our exploration and production operations. 
+We enter into master service agreements with our third-party contractors, including hydraulic fracturing contractors, in which they agree to indemnify us for injuries and deaths of the service provider’s employees, as well as contractors and subcontractors hired by the service provider. Similarly, we generally agree to indemnify each third-party contractor against claims made by our employees and our other contractors. Additionally, each party generally is responsible for damage to its own property. We reevaluate the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and natural gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. While we believe that we are properly insured based on our risk analysis, no assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable. In such circumstances, we may elect to self-insure or maintain only catastrophic coverage for certain risks in the future. 
+Corporate Offices 
+Our headquarters are located in Houston, Texas, in a building with office space that we lease. We own office buildings in Dilley and Pecos, Texas and lease and own offices in the Midland, Texas area. Because alternative locations to our leased spaces are readily available, the replacement of any of our leased offices would not result in material expenditures . 
+Regulations 
+General. Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities at the federal, state, and local levels. Some of these requirements carry substantial penalties for failure to comply. Legislation and regulation affecting the entire oil and natural gas industry is continuously being reviewed for potential revision, and various proposals and proceedings that might affect the industry are pending before Congress, federal administrative agencies such as the Federal Energy Regulatory Commission (“FERC”), various state and administrative agencies and legislatures, and the courts. We cannot predict what effect such proposals or proceedings may have on our operations, capital expenditures, earnings or competitive position. 
+Exploration and Production . Our operations are subject to federal, state and local regulations that include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds and letters of credit) covering drilling and well operations. Other activities subject to regulation are: 
+• the location and spacing of wells; 
+• the method of drilling and completing and operating wells; 
+• the rate and method of production; 
+• the surface use and restoration of properties upon which wells are drilled and other exploration activities; 
+• notice to surface owners and other third parties; 
+• the venting or flaring of natural gas; 
+• the plugging and abandoning of wells; 
+• the discharge of contaminants into water and the emission of contaminants into air; 
+• the disposal of fluids used or other wastes obtained in connection with operations; 
+• the marketing, transportation and reporting of production; and 
+• the valuation and payment of royalties. 
+We do not currently anticipate that compliance with existing laws and regulations governing exploration and production will have a significantly adverse effect upon our capital expenditures, operations, earnings or competitive position. 
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+Environmental Matters and Regulation. Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to the protection of the environment and natural resources. Numerous federal, state and local governmental agencies, such as the U.S. Environmental Protection Agency (the “EPA”), issue regulations which often require difficult and costly compliance measures. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent, monitor for or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relating to our owned or operated facilities. Violations of environmental laws could result in administrative, civil or criminal fines and injunctive relief. The strict and joint and several liability nature of certain such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons, air emissions or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. In recent years, the oil and natural gas exploration and production industry has been the subject of increasing scrutiny and regulation by environmental authorities. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. Although such laws and regulations can increase the cost of planning, designing, installing and operating our facilities, it is anticipated that, absent the occurrence of an extraordinary event, compliance with them will not have a material effect upon our operations, capital expenditures, earnings or competitive position in the marketplace. 
+Waste Handling. The Resource Conservation and Recovery Act (“RCRA”), as amended, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of oil and natural gas are exempt from regulation as hazardous wastes under RCRA and its state analogs, it is possible that some wastes we generate presently or in the future may be subject to regulation under RCRA and state analogs. Additionally, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” If the EPA proposes a rulemaking for revised oil and gas waste regulations in the future, any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. 
+Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of wastes associated with oil and natural gas exploration and production could increase our costs to manage and dispose of such wastes. 
+Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), imposes strict, joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the release occurred and anyone who disposed of or arranged for the disposal of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes. 
+Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we have generated and will generate wastes that may fall within CERCLA’s definition of hazardous substance and may have disposed of these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum. We may also be the owner or operator of sites on which hazardous substances have been released. To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under CERCLA; we also do not know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties. In the event 
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+contamination is discovered at a site on which we are or have been an owner or operator or to which we sent hazardous substances, we could be liable for the costs of investigation and remediation and natural resources damages. 
+We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating, waste disposal, and water disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including offsite locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination or groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination. 
+Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, the Safe Drinking Water Act, the Oil Pollution Act (“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States (a term broadly defined to include, among other things, certain wetlands), as well as state waters for analogous state programs. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or applicable state analog. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit from the U.S. Army Corps of Engineers (the “Corps”). The EPA and the Corps issued a final rule on the federal jurisdictional reach over waters of the United States in 2015, which never took effect before being replaced by the Navigable Waters Protection Rule (the “NWPR”) in December 2019. A coalition of states and cities, environmental groups, and agricultural groups challenged the NWPR, which was vacated by a federal district court in August 2021. The EPA is undergoing a rulemaking process to redefine the definition of waters of the United States; in the interim, the EPA is utilizing the pre-2015 definition. 
+The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. 
+The Oil Pollution Act is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters. 
+Noncompliance with the Clean Water Act or the OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws. 
+Air Emissions. The federal Clean Air Act, as amended (the “CAA”), and comparable state and local laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and modified and existing facilities may be required to obtain additional permits. As a result, we may need to incur capital costs in order to remain in compliance. Obtaining or renewing permits also has the potential to delay the development of oil and natural gas projects. Federal and state regulatory agencies can impose administrative, civil and criminal penalties and seek injunctive relief for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. 
+In June 2016, the EPA finalized regulations establishing New Source Performance Standards, known as Subpart OOOOa, for methane and volatile organic compounds from new and modified oil and natural gas production and natural gas processing and transmission facilities. In September 2020, the EPA finalized two sets of amendments to the 2016 Subpart OOOOa standards. The first, known as the 2020 Technical Rule, reduced the 2016 rule’s fugitive emissions monitoring requirements and expanded exceptions to pneumatic pump requirements, among other changes. The second, known as the 2020 Policy Rule, rescinded the methane-specific requirements for certain oil and natural gas sources in the production and processing segments. On January 20, 2021, President Biden issued an Executive Order directing the EPA to rescind the 2020 Technical Rule by September 2021 and consider revising the 2020 Policy Rule. On June 30, 2021, President Biden signed a Congressional Review Act (the “CRA”) resolution passed by Congress that revoked the 2020 Policy Rule. The CRA did not address the 2020 Technical Rule. 
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+Further, on November 15, 2021, the EPA issued a proposed rule intended to reduce methane emissions from oil and gas sources. The proposed rule would make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the CAA (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities). In addition, the proposed rule would establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA. Under the proposed rule, states would have three years to develop their compliance plan for existing sources and the regulations for new sources would take effect immediately upon issuance of a final rule. The EPA is expected to issue both a supplemental proposed rule, which may expand or modify the current proposed rule, and final rule by the end of 2022. 
+As a result of these regulatory changes, the scope of any final methane regulations or the costs for complying with federal methane regulations are uncertain. However, any new regulations could result in stricter permitting requirements, which in turn could delay or impair our ability to obtain air emission permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. 
+Climate Change. Numerous reports from scientific and governmental bodies such as the Sixth Assessment Report of the Intergovernmental Panel on Climate Change have expressed heightened concerns about the impacts of human activity, especially fossil fuel combustion, on the global climate. In turn, governments and civil society are increasingly focused on limiting the emissions of GHGs, including emissions of carbon dioxide from the use of oil and natural gas. 
+In December 2015, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change (“UNFCCC”) resulted in 195 countries, including the United States, coming together to develop the so-called “Paris Agreement,” which calls for the parties to undertake “ambitious efforts” to limit the average global temperature. The Agreement went into effect on November 4, 2016, and establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. On June 1, 2017, President Trump announced that the U.S. would withdraw from the Paris Agreement and completed the process of withdrawing from the Paris Agreement on November 4, 2020. However, on January 20, 2021, President Biden issued written notification to the United Nations of the United States’ intention to rejoin the Paris Agreement, which became effective on February 19, 2021. In addition, in September 2021, President Biden publicly announced the Global Methane Pledge, a pact that aims to reduce global methane emissions at least 30% below 2020 levels by 2030. Since its formal launch at the 26th Conference of the Parties of the UNFCCC (“COP26”), over 100 countries have joined the pledge. COP26 concluded with the finalization of the Glasgow Climate Pact (the “Glasgow Pact”), which stated long-term global goals (including those in the Paris Agreement) to limit the increase in the global average temperature and emphasized reductions in GHG emissions. International commitments, re-entry into the Paris Agreement and President Biden’s executive orders may result in the development of additional regulations or changes to existing regulations. 
+Congress has from time to time considered legislation to reduce emissions of GHGs, but no new federal laws have been adopted in recent years. However, the United States House of Representatives passed H.R. 5376, known as the Build Back Better Act, on November 3, 2021. The House version of the bill targets methane from oil and gas sources by proposing to implement fees for excess methane leaking from wells, storage sites, and pipelines as well as fees for new producing and non-producing oil and gases leases and off-shore pipelines. 
+Any legislation or regulatory programs at the federal, state, or city levels designed to reduce GHG emissions could increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. At the federal level, although no comprehensive climate change legislation has been implemented to date, such legislation has periodically been introduced in the U.S. Congress and may be proposed or adopted in the future. The likelihood of such legislation has increased under the current administration. Moreover, incentives to conserve energy or use alternative energy sources, such as policies designed to increase utilization of zero-emissions or electric vehicles, as a means of addressing climate change could reduce demand for the oil and natural gas we produce. 
+In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions. Although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. 
+The EPA has established GHG reporting requirements for certain sources in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissions. Although these requirements do not limit the amount of GHGs that can be emitted, they do require us to incur costs to monitor, keep records of, and report GHG emissions associated with our operations. 
+Parties concerned about the potential effects of climate change have also directed their attention at sources of financing for energy companies, which has resulted in certain financial institutions, funds and other capital providers restricting or eliminating their investment in oil and natural gas activities. In addition, some parties have initiated public nuisance claims under federal or state common law against certain companies involved in the production of oil and natural gas. Although our business is not a party to any 
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+such litigation, we could be named in actions making similar allegations, which could lead to costs and materially impact our financial condition in an adverse way. 
+Finally, most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce significant physical effects, such as increased frequency and severity of droughts, storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced or cause us to incur significant costs in preparing for or responding to the effects of climatic events themselves. Potential adverse effects could include disruption of our production activities, including, for example, damages to our facilities from winds or floods or increases in our costs of operation or reductions in the efficiency of our operations, as well as potentially increased costs for insurance coverages in the aftermath of such effects. 
+Regulation of Hydraulic Fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act (“SDWA”) regulates the underground injection of substances through the Underground Injection Control (“UIC”) program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions and not at the federal level, as the SDWA expressly excludes regulation of these fracturing activities (except where diesel is a component of the fracturing fluid, as further discussed below). Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing has been proposed in past legislative sessions but has not passed. 
+The EPA, however, issued guidance on permitting hydraulic fracturing that uses fluids containing diesel fuel under the UIC program, specifically as “Class II” UIC wells. The EPA evaluated the potential impacts of hydraulic fracturing on drinking water resources and concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Further, the EPA prohibits the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. 
+Several states, including Texas, and some municipalities, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, Texas law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) for disclosure on a website and also file the list of chemicals with the Texas Railroad Commission (the “RRC”) with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the RRC. 
+Additionally, some states, localities and local regulatory districts have adopted or have considered adopting regulations to limit, and in some cases impose a moratorium on, hydraulic fracturing or other restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; or restrictions on access to, and usage of, water. Further, there has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the U.S. implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations of harm. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of potential federal or state legislation governing hydraulic fracturing. In light of concerns about seismic activity being triggered by the injection of produced waters into underground wells, certain regulators are also considering additional requirements related to seismic safety for hydraulic fracturing activities. For example, the RRC recently announced an indefinite suspension of certain deep oil and gas wastewater disposal activities in portions of west Texas due to seismicity concerns. The U.S. Geological Survey has identified eight states with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. Any regulation that restricts our ability to dispose of produced waters or increases the cost of doing business could cause curtailed or decreased demand for our services and have a material adverse effect on our business. 
+Surface Damage Statutes (“SDAs”) . In addition, a number of states and some tribal nations have enacted SDAs. These laws are designed to compensate for damage caused by oil and gas development operations. Most SDAs contain entry notification and 
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+negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain binding requirements for payments by the operator to surface owners/users in connection with exploration and operating activities in addition to bonding requirements to compensate for damages to the surface as a result of such activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs. 
+National Environmental Policy Act . Oil and natural gas exploration and production activities requiring federal permits may be subject to the National Environmental Policy Act (“NEPA”), which requires federal agencies to evaluate major federal actions having the potential to significantly impact the human environment. In the course of such evaluations, an agency will evaluate the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a detailed Environmental Impact Statement that must be made available for public review and comment. Recent litigation by environmental non-governmental organizations has alleged that the Environmental Assessments for certain oil and natural gas projects violated NEPA by failing to account for climate change and the greenhouse gas emissions impacts of such projects. On July 16, 2020, the Council on Environmental Quality revised NEPA’s implementing regulations in an effort designed to streamline project approvals. Among other revisions, the rules redefines environmental “effects” or “impacts” as the effects “that are reasonably foreseeable and have a reasonably close causal relationship to the proposed action or alternatives.” The rule also eliminated the current “direct,” “indirect,” or “cumulative” categories of effects. The new regulations are subject to ongoing litigation in several federal district courts, which has been stayed pending an ongoing review of the 2020 rule. On October 6, 2021, the Council on Environmental Quality announced its Phase 1 rule, the first of two planned rules to roll back the 2020 rule. To the extent that our current exploration and production activities, as well as proposed exploration and development plans, require federal permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects. 
+Endangered Species Act and Migratory Bird Treaty Act. The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ or its habitat. The U.S. Fish and Wildlife Service (the “FWS”) must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. In August 2019, the FWS and National Marine Fisheries Service (“NMFS”) issued three rules amending implementation of the ESA regulations revising, among other things, the process for listing species and designating critical habitat. A coalition of states and environmental groups have challenged the three rules and the litigation remains pending. In addition, on December 18, 2020, the FWS amended its regulations governing critical habitat designations; the amended regulations are subject to ongoing litigation. In June 2021, the FWS and NMFS announced plans to begin rulemaking processes to rescind these rules. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”), which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit. This prohibition covers most bird species in the U.S. On January 7, 2021, the Department of the Interior finalized a rule limiting application of the MBTA; however, the Department of the Interior revoked the rule in October 2021 and issued an advance notice of proposed rulemaking seeking comment on the Department’s plan to develop regulations that authorize incidental take under certain prescribed conditions. Future implementation of the rules implementing the Endangered Species Act and the MBTA are uncertain. If the Company was to have a portion of its leases designated as critical or suitable habitat or a protected species were located on a lease, it may adversely impact the value of the affected leases. 
+Other Regulation of the Oil and Natural Gas Industry. The oil and natural gas industry is extensively regulated by numerous federal, state and local agencies and authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other similar companies in the industry with similar types, quantities and locations of production. 
+The availability, terms, conditions and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas is subject to federal regulation by FERC which regulates the terms, conditions and rates for interstate transportation and storage service and various other matters. State regulations govern the rates, terms, and conditions of service associated with access to intrastate oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transportation in some circumstances may also affect the intrastate transportation of oil and natural gas. 
+Although oil, natural gas, condensate, and NGL sales prices are currently unregulated, the federal government historically has been active in the area of oil and natural gas sales regulation. We cannot predict whether new legislation to regulate oil and natural gas sales might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of natural gas, condensate, oil and natural gas liquids are not currently regulated and are made at market prices. 
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+Exports of U.S. Oil Production and Natural Gas Production . In December 2015, the federal government ended its decades-old prohibition of exports of oil produced in the lower 48 states of the U.S. As a result, exports of U.S. oil have increased significantly, reinforcing the general perception in the industry that the end of the U.S. export ban was positive for producers of U.S. oil. In addition, the U.S. Department of Energy authorizes exports of natural gas, including exports of natural gas by pipelines connecting U.S. natural gas production to pipelines in Mexico, and the export of liquefied natural gas (“LNG”) through LNG export facilities, the construction and operation of which are regulated by FERC. Since 2016, natural gas produced in the lower 48 states of the U.S. has been exported as LNG from export facilities in the U.S. Gulf Coast region. LNG export capacity has steadily increased in recent years, and is expected to continue increasing due to numerous export facilities that are currently being developed. The industry generally believes that this sustained growth in exports will be a positive development for producers of U.S. natural gas. 
+Drilling and Production. State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas without a permit and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affecting the economics of production from these wells or to limit the number of locations we can drill. 
+Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Some state agencies and municipalities require bonds or other financial assurances to support those obligations. 
+Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production and have it transported. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”). Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for “first sales” of natural gas, which include all of our sales of our own production. 
+Under the Energy Policy Act of 2005 (“EPAct 2005”) Congress amended the NGA and NGPA to give FERC substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess civil penalties up to $1.0 million per day for each violation. This maximum penalty authority has been and will continue to be adjusted periodically to account for inflation. FERC also has authority to order the disgorgement of any ill-gotten gains. EPAct also amended the NGA to authorize FERC to facilitate transparency in markets for the sale or transportation of physical natural gas in interstate commerce, pursuant to which authorization FERC now requires natural gas wholesale market participants, including a number of entities that may not otherwise be subject to FERC’s traditional NGA jurisdiction, to report information annually to FERC concerning their natural gas sales and purchases. FERC requires any wholesale market participant that sells 2.2 million MMBtus or more annually in “reportable” natural gas sales to provide a report, known as FERC Form 552, to FERC. Reportable natural gas sales include sales of natural gas that utilize a daily or monthly gas price index, contribute to index price formation, or could contribute to index price formation, such as fixed price transactions for next-day or next-month delivery. 
+FERC also regulates interstate natural gas transportation rates, terms and conditions of service, and the terms under which we as a shipper may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and for the release of our excess, if any, natural gas pipeline capacity. In 1985, FERC began promulgating a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate natural gas pipeline companies are required to provide non-unduly discriminatory transportation services to all shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases, sales, and transportation that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated. We cannot determine what effect, if any, future regulatory changes might have on our natural gas related activities. 
+Under FERC’s current regulatory regime, interstate transportation services must be provided on an open-access, not unduly discriminatory basis at cost-based rates or negotiated rates, both of which are subject to FERC approval. FERC also allows jurisdictional gas pipeline companies to charge market-based rates if the transportation market at issue is sufficiently competitive. The FERC-regulated tariffs, under which interstate pipelines provide such open-access transportation service, contain strict limits on the 
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+means by which a shipper releases its pipeline capacity to another potential shipper, which provisions include compliance with FERC’s “shipper-must-have-title” rule. Violations by a shipper (i.e., a pipeline customer) of FERC’s capacity release rules, including the shipper-must-have-title rule, could subject a shipper to substantial penalties and disgorgement of any ill-gotten gains. 
+With respect to its regulation of natural gas pipelines under the NGA, FERC traditionally has not required the applicant for construction and operation of a new interstate natural gas pipeline to provide information concerning the GHG emissions resulting from the activities of the proposed pipeline’s customers. In August 2017, the U.S. Circuit Court of Appeals for the DC Circuit issued a decision remanding a natural gas pipeline certificate application to FERC, and required FERC to revise its environmental impact statement for the proposed pipeline to analyze potential GHG emission from the specific downstream power plants that the pipeline was designed to serve. In March 2021, FERC assessed the significance of a project’s GHG emissions and those emissions’ contribution to climate change. FERC compared the project’s reasonably foreseeable GHG emissions to the total GHG emissions of the United States to assess the project’s share of contribution to national GHG levels. FERC announced that it will also consider state GHG emission reduction targets, to the extent a state has such targets. Finally, FERC noted that it will consider “all appropriate evidence” in future proceedings. However, the scope of FERC’s obligation to analyze the environmental impacts of proposed interstate natural gas pipeline projects, including the upstream indirect impacts of related natural gas production activity, remains subject to ongoing litigation and contested administrative proceedings at FERC and in the courts. 
+Gathering service, which occurs on pipeline facilities located upstream of FERC-jurisdictional interstate transportation services, is regulated by the states onshore and in state waters. Under NGA section 1(b), gathering facilities are exempt from FERC’s jurisdiction. FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transportation function, and FERC applies this test on a case-by-case basis. Depending on changes in the function performed by particular pipeline facilities, FERC has in the past reclassified certain FERC-jurisdictional transportation facilities as non-jurisdictional gathering facilities and FERC has reclassified certain non-jurisdictional gathering facilities as FERC-jurisdictional transportation facilities. Any such changes could result in an increase to our costs of transporting gas to point-of-sale locations. 
+The pipelines used to gather and transport natural gas being produced by the Company are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Act of 1992, as reauthorized and amended, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, the Securing America’s Future Energy: Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016, and the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2019. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In addition, PHMSA had initially considered regulations regarding, among other things, the designation of additional high consequence areas along pipelines, minimum requirements for leak detection systems, installation of emergency flow restricting devices, and revision of valve spacing requirements. In October 2019, PHMSA finalized new safety regulations for hazardous liquid pipelines, including a requirement that operators inspect affected pipelines following extreme weather events or natural disasters, that all hazardous liquid pipelines have a system for detecting leaks and that pipelines in high consequence areas be capable of accommodating in-line inspection tools within twenty years. In addition, PHMSA is in the process of finalizing a rulemaking with respect to gathering lines, but the contents and timing of any final rule for gathering lines are uncertain. In December 2020, Congress passed the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2020 (“PIPES Act of 2020”). In addition to reauthorizing PHMSA, the PIPES Act of 2020 directs the Secretary of Transportation to update or promulgate regulations addressing the safety of certain gas pipeline, gathering, distribution and LNG facilities. On November 15, 2021, PHMSA issued a final rule that expands PHMSA’s safety regulations to more than 400,000 miles of onshore gas gathering pipelines that were previously exempt from PHMSA’s rules. Petitions for reconsideration of this final rule have been filed. Other regulations stemming from the PIPES Act of 2020 are still proceeding through the rulemaking process. 
+Oil, Condensate and NGLs Sales and Transportation. Sales of oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. 
+The Company’s sales of oil and natural gas liquids are affected by the availability, terms, conditions and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by FERC under the Interstate Commerce Act (“ICA”). FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. If the regulations relating to the price, terms and conditions for access to pipeline transportation change, we could face higher transportation costs for our production and, possibly, reduced access to transportation capacity. To the extent it may be necessary for new interstate natural gas pipelines to be built, there may be a more stringent regulatory approach at FERC, which could impact our ability to obtain new interstate pipeline transportation capacity. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil and natural gas liquid transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors. 
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+Further, interstate common carrier oil pipelines must provide service on a not unduly discriminatory basis under the ICA, which is administered by FERC. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors. 
+In addition, FERC issued a declaratory order in November 2017, involving a marketing affiliate of an oil pipeline, which held that certain arrangements between an oil pipeline and its marketing affiliate would violate the ICA’s anti-discrimination provisions. FERC held that providing transportation service to affiliates at what is essentially the variable cost of the movement, while requiring non-affiliated shippers to pay the filed tariff rate, would violate the ICA. At this time, the Company cannot currently determine the impact this FERC order may have on oil pipelines, their marketing affiliates, and the price of oil and other liquids transported by such pipelines. 
+Any transportation of the Company’s oil, natural gas liquids and purity components (ethane, propane, butane, iso-butane, and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts 171-180, including Emergency Orders by the FRA regulations initially established on May 8, 2015 by PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids; PHMSA regulations were subsequently amended to remove certain requirements on September 25, 2018. In July 2020, PHMSA promulgated a final rule allowing bulk transportation of LNG by rail. The rule also incorporates additional safety requirements. In November 2021, PHMSA issued a notice of proposed rulemaking, seeking to suspend this final rule. 
+State Regulation. Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill. 
+The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us. 
+Financial Regulations, Including Regulations Enacted Under the Dodd-Frank Act . The U.S. Commodities and Futures Exchange Commission (the “CFTC”) holds authority to monitor certain segments of the physical and futures energy commodities market including oil and natural gas. With regard to physical purchases and sales of natural gas and other energy commodities, and any related hedging activities that the Company undertakes, the Company is thus required to observe anti-market manipulation and disruptive trading practices laws and related regulations enforced by FERC and/or the CFTC. The CFTC also holds substantial enforcement authority, including the ability to assess civil penalties. 
+Congress adopted comprehensive financial reform legislation in 2010, establishing federal oversight and regulation of the over-the-counter derivative market and entities that participate in that market. The legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), required the CFTC and the U.S. Securities and Exchange Commission (“SEC”) to promulgate rules and regulations implementing the legislation, including regulations that affect derivatives contracts that the Company uses to hedge its exposure to price volatility. 
+While the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas remain pending. The Company cannot, at this time, predict the timing or contents of any final rules the CFTC may enact with regard to any applicable rulemaking proceeding. Any final rule in either proceeding could impact the Company’s ability to enter into financial derivative transactions to hedge or mitigate exposure to commodity price volatility and other commercial risks affecting our business. 
+Worker Health and Safety . We are subject to a number of federal and state laws and regulations, including OSHA, and comparable state statutes, the purpose of which are to protect the health and safety of workers. In 2016, there were substantial revisions to the regulations under OSHA that may have impact to our operations. These changes include among other items; record keeping and reporting, revised crystalline silica standard (which requires the oil and gas industry to implement engineering controls and work practices to limit exposures below the new limits by June 23, 2021), naming oil and gas as a high hazard industry and requirements for a safety and health management system. In addition, OSHA’s hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations, and that this information be provided to employees, state and local government authorities and citizens. 
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+Commitments and Contingencies 
+Our activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, we believe that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment will not have a material effect upon our capital expenditures, earnings or our competitive position with respect to our existing assets and operations. We cannot predict what effect additional regulation or legislation, enforcement policies included, and claims for damages to property, employees, other persons, and the environment resulting from our operations could have on its activities. See “Note 17 - Commitments and Contingencies” of the Notes to our Consolidated Financial Statements for additional information. 
+Available Information 
+We make available free of charge on our website (www.callon.com) our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the SEC. 
+We also make available within the “About Callon — Governance” section of our website our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and Audit, Compensation, Nominating and ESG, and Operations and Reserves Committee Charters, which have been approved by our Board of Directors. We will make timely disclosure on our website of any change to, or waiver from, the Code of Business Conduct and Ethics for our principal executive and senior financial officers. A copy of our Code of Business Conduct and Ethics is also available, free of charge by writing us at: General Counsel, Callon Petroleum Company, 2000 W. Sam Houston Parkway South, Suite 2000, Houston, TX 77042. 
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+ITEM 1A. Risk Factors 
+Risks Related to the Oil & Natural Gas Industry 
+Oil and natural gas prices are volatile, and substantial or extended declines in prices may adversely affect our results of operations and financial condition. Our success is highly dependent on prices for oil and natural gas, which have in recent years been, and we expect will continue to be, extremely volatile. During the five years ended December 31, 2021, NYMEX WTI prices ranged from a high of $85.64 per barrel on October 26, 2021 to a low of -$36.98 per barrel on April 20, 2020, and NYMEX Henry Hub prices ranged from a high of $23.86 per MMBtu on February 17, 2021 to a low of $1.33 per MMBtu on September 21, 2020. Prices were particularly volatile in 2020 and 2021, with five-year highs occurring in 2021 and five-year lows occurring in 2020, as a result of multiple significant factors impacting supply and demand in the global oil and natural gas markets, including those relating to the COVID-19 global pandemic. The prices of oil and natural gas depend on factors we cannot control, such as macro-economic conditions, levels of production, domestic and worldwide inventories, demand for oil and natural gas, the capacity of U.S. and international refiners to use U.S. supplies of oil, natural gas and NGLs, relative price and availability of alternative forms of energy, actions by non-governmental organizations, OPEC and other countries, legislative and regulatory actions, technology developments impacting energy consumption and energy supply, and weather. These factors make it extremely difficult to predict future oil, natural gas and NGLs price movements with any certainty. We make price assumptions that are used for planning purposes, and a significant portion of our cash outlays, including rent, salaries and non-cancelable capital commitments, are largely fixed in nature. Accordingly, if commodity prices are below the expectations on which these commitments were based, our financial results are likely to be adversely and disproportionately affected because these cash outlays are not variable in the short term and cannot be quickly reduced to respond to unanticipated decreases in commodity prices. 
+In general, prices of oil, natural gas, and NGLs affect the following aspects of our business: our revenues, cash flows, earnings and returns; our ability to attract capital to finance our operations and the cost of the capital; the amount we are allowed to borrow under our Credit Facility; the profit or loss we incur in exploring for and developing our reserves; and the value of our oil and natural gas properties. 
+A substantial or extended decline in commodity prices may also reduce the amount of oil and natural gas that we can produce economically and cause a significant portion of our development projects to become uneconomic. This may result in our having to make significant downward adjustments to our estimated proved reserves. A reduction in production could also result in a shortfall in expected cash flows and require us to reduce capital spending, which could negatively affect our ability to replace our production and our future rate of growth, or require us to borrow funds to cover any such shortfall, which we may be unable to obtain at such time on satisfactory terms. Additionally, a sustained period of weakness in oil, natural gas and NGLs prices, and the resultant effects of such prices on our drilling economics and ability to raise capital, would require us to reevaluate and postpone or eliminate additional drilling. 
+Additionally, as of December 31, 2021, approximately 26% of our total net acreage was not held by production, and we had undeveloped leases representing 20% and 1% of our total net acreage scheduled to expire during 2022 and 2023, respectively, in each case assuming no exercise of lease extension options where applicable. The net acreage scheduled to expire in 2022 is substantially comprised of non-core acreage principally located in Texas. If we are required to further curtail our drilling program, we may be unable to continue to hold such leases that are scheduled to expire, which may further reduce our reserves. As a result, if oil, natural gas and/or NGL prices experience a sustained period of weakness, our future business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures may be materially and adversely affected. 
+If oil and natural gas prices remain depressed for extended periods of time, we may be required to make significant downward adjustments to the carrying value of our oil and natural gas properties. Under the full cost method, which we use to account for our oil and natural gas properties, the net capitalized costs of our oil and natural gas properties may not exceed the PV-10 of our estimated proved reserves, using the 12-Month Average Realized Prices, plus the lower of cost or fair market value of our unproved properties. If such net capitalized costs exceed this limit, we must charge the amount of the excess to earnings. This type of charge will not affect our cash flows, but will reduce the book value of our stockholders’ equity. We review the carrying value of our properties quarterly and once incurred, an impairment of evaluated oil and natural gas properties is not reversible at a later date, even if prices increase. See “Note 2 - Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements as well as the Supplemental Information on Oil and Natural Gas Operations for additional information. 
+A negative shift in investor sentiment of the oil and gas industry could adversely affect our ability to raise debt and equity capital. Certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition, some investors, including investment advisors and certain sovereign wealth funds, pension funds, university endowments and family foundations, have stated policies to disinvest in the oil and gas sector based on their social and environmental considerations. Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas production and related infrastructure projects. Such developments, including environmental, social and governance (“ESG”) activism 
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+and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also potentially result in a reduction of available capital funding for potential development projects, impacting our future financial results. 
+We face various risks associated with increased activism against oil and natural gas exploration and development activities. Opposition toward oil and natural gas drilling and development activity has been growing globally and is particularly pronounced in the United States. Companies in the oil and natural gas industry are often the target of activist efforts from both individuals and non- governmental organizations regarding safety, human rights, climate change, environmental matters, sustainability, and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain operations such as drilling and development. Activism could materially and adversely impact our ability to operate our business and raise capital. 
+The unavailability or high cost of drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could materially and adversely affect our operations and profitability. From time to time, during periods of increasing oil and natural gas prices and in periods in which the levels of exploration and production increase, our industry experiences a shortage of drilling and workover rigs, other equipment, pipes, materials and supplies, water and qualified personnel. As a result of such shortage, the costs and delivery times of rigs, equipment and supplies often increase substantially, as well as the wages and costs of drilling rig crews and other experienced personnel and oilfield services, while the quality of these services and equipment may suffer. This impact may be magnified to the extent that the Company's ability to participate in the commodity price increases is limited by its derivative risk management activities. Cost increases in and shortages of such resources may also result from a variety of other factors beyond our control, such as general inflationary pressures, transportation constraints, and increases in the cost of necessary inputs such as electricity, steel and other raw materials, including as a result of increased tariffs or geopolitical issues. 
+An excess supply of oil and natural gas may in the future cause us to reduce production and shut-in our wells, any of which could adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures. An excess supply of oil and natural gas may result in transportation and storage capacity constraints. If, in the future, our transportation or storage arrangements become constrained or unavailable, we may incur significant operational costs if there is an increase in price for services or we may be required to shut-in or curtail production or flare our natural gas. If we were required to shut-in wells, we might also be obligated to pay certain demand charges for gathering and processing services and firm transportation charges for pipeline capacity we have reserved. Further, any prolonged shut-in of our wells may result in materially decreased well productivity once we are able to resume operations, and any cessation of drilling and development of our acreage could result in the expiration, in whole or in part, of our leases. All of these impacts may adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures. 
+Risks Related to the COVID-19 Pandemic 
+The COVID-19 pandemic, and various governmental actions taken to mitigate its impact, materially adversely affected, and any future outbreak of any other highly infectious or contagious diseases may materially adversely affect, our business, financial position, results of operations, and cash flows. The COVID-19 pandemic, and various governmental actions taken to mitigate its impact, have negatively impacted the global economy, disrupted global supply chains, and created significant volatility and disruption of financial and commodity markets, as well as resulted in an unprecedented decline in demand for oil and natural gas during 2020, which materially adversely affected our business, financial position, results of operations, and cash flows and exacerbated the potential negative impact from many of the other risks described herein, including those relating to our financial position and debt obligations. The pandemic has also increased volatility and, from time to time, caused negative pressure in the capital markets; as a result, in the future, we may experience difficulty accessing the capital or financing needed to fund our operations, which have substantial capital requirements, on satisfactory terms or at all, compounding liquidity risks associated with a material reduction in our revenues and cash flows as a result of any future declines in demand due to the COVID-19 pandemic or any future pandemic. 
+We expect the COVID-19 pandemic and related economic repercussions to continue to affect our business, financial condition, results of operations, and cash flows. However, the extent of the impact of the COVID-19 pandemic on our business and our operational and financial performance, including our ability to execute our business strategies and initiatives in the expected time frame, is uncertain and depends on various factors that we cannot predict, including the following: the severity and duration of the pandemic; governmental, business and other actions in response to the pandemic; the impact of the pandemic on economic activity; the response of the overall economy and the financial markets; the demand for oil and natural gas, which may be reduced on a prolonged or permanent basis due to a structural shift in the global economy in the way people work, travel, and interact, or in connection with a global recession or depression; any impairment in the value of our tangible or intangible assets which could be recorded as a result of a weaker economic conditions or commodity prices; and the potential effects on our internal controls, including those over financial reporting, as a result of changes in working environments, such as shelter-in-place and similar orders that are applicable to our 
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+employees and business partners, among others. The challenges to working caused by the COVID-19 pandemic and related restrictions may have an impact on our employees’ wellness, which could impact employee retention, productivity and our culture. In addition, we may experience employee turnover as seen with companies throughout the U.S. economy. There are no comparable recent events that provide guidance as to the effect the COVID-19 pandemic may have, and as a result, the ultimate impact of the pandemic is highly uncertain and subject to change. 
+Operational Risks 
+Our operations are subject to operating hazards inherent to our industry that may adversely impact our ability to conduct business, and we may not be fully insured against all such operating risks. The operating hazards in exploring for and producing oil and natural gas include: encountering unexpected subsurface conditions that cause damage to equipment or personal injury, including loss of life; equipment failures that curtail or stop production or cause severe damage to or destruction of property, natural resources or other equipment; blowouts or other damages to the productive formations of our reserves that require a well to be re-drilled or other corrective action to be taken; and storms and other extreme weather conditions that cause damages to our production facilities or wells. Because of these or other events, we could experience environmental hazards, including release of oil and natural gas from spills, natural gas leaks, accidental leakage of toxic or hazardous materials, such as petroleum liquids, drilling fluids or fracturing fluids, including chemical additives, underground migration, and ruptures. If we experience any of these problems, we could incur substantial losses in excess of our insurance coverage. 
+The occurrence of a significant event or claim, not fully insured or indemnified against, could have a material adverse effect on our financial condition and operations. In accordance with industry practice, we maintain insurance against some of the operating risks to which our business is exposed. Also, no assurance can be given that we will be able to maintain insurance in the future at rates we consider reasonable to cover our possible losses from operating hazards and we may elect no or minimal insurance coverage. 
+Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns. Exploration, development, drilling and production activities are subject to many risks. We may invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that any leasehold acreage acquired will be profitably developed, that new wells drilled will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, including wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, we may not be successful in controlling our drilling and production costs to improve our overall return and wells that are profitable may not achieve our targeted rate of return. Wells may have production decline rates that are greater than anticipated. Future drilling and completion efforts may impact production from existing wells, and parent-child effects may impact future well productivity as a result of timing, spacing proximity or other factors. Failure to conduct our oil and gas operations in a profitable manner may result in write- downs of our proved reserves quantities, impairment of our oil and gas properties, and a write-down in the carrying value of our unproved properties, and over time may adversely affect our growth, revenues and cash flows. 
+Multi-well pad drilling may result in volatility in our operating results. We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production. In addition, problems affecting a single well could adversely affect production from all of the wells on the pad, which would further cause delays in the scheduled commencement of production or interruptions in ongoing production. These delays or interruptions may cause volatility in our operating results. Further, any delay, reduction or curtailment of our development and producing operations due to operational delays caused by multi-well pad drilling could result in the loss of acreage through lease expirations. 
+Restrictions on our ability to obtain, recycle and dispose of water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner. Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to secure water from local land owners and other third party sources for use in our operations. If drought conditions were to occur or demand for water were to outpace supply, our ability to obtain water could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. Along with the risks of other extreme weather events, drought risk, in particular, is likely increased by climate change. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows. In addition, significant amounts of water are produced in our operations. Inadequate access to or availability of water recycling or water disposal facilities could adversely affect our production volumes or significantly increase the cost of our operations. 
+Risks Related to Marketing and Transportation 
+Factors beyond our control, including the availability and capacity of gas processing facilities and pipelines and other transportation operations owned and operated by third parties, affect the marketability of our production. The ability to market oil and natural gas from our wells depends upon numerous factors beyond our control. A significant factor in our ability to market our production is the availability and capacity of gas processing facilities and pipeline and other transportation operations, 
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+including trucking services, owned and operated by third parties. These facilities and services may be temporarily unavailable to us due to market conditions, physical or mechanical disruption, weather, lack of contracted capacity, available manpower, pipeline safety issues, or other reasons. In certain newer development areas, processing and transportation facilities and services may not be sufficient to accommodate potential production and it may be necessary for new interstate and intrastate pipelines and gathering systems to be built. In addition, we or parties that we utilize might not be able to connect new wells that we complete to pipelines. Our failure to obtain access to processing and transportation facilities and services in a timely manner and on acceptable terms could materially harm our business. We may be required to shut in wells for lack of a market or because of inadequate or unavailable processing or transportation capacity. If that were to occur, we would be unable to realize revenue from those wells until transportation arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells, we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. If we were required to shut in our production for long periods of time due to lack of transportation capacity, it would have a material adverse effect on our business, financial condition, results of operations and cash flows. 
+Other factors that affect our ability to market our production include: 
+• the extent of domestic production and imports/exports of oil and natural gas; 
+• federal regulations authorizing exports of LNG, the development of new LNG export facilities under construction in the U.S. Gulf Coast region, and the first LNG exports from such facilities; 
+• the construction of new pipelines capable of exporting U.S. natural gas to Mexico and transporting Eagle Ford and Permian oil production to the Gulf Coast; 
+• the proximity of hydrocarbon production to pipelines; 
+• the demand for oil and natural gas by utilities and other end users; 
+• the availability of alternative fuel sources; 
+• the effects of inclement weather; and 
+• state and federal regulation of oil, natural gas and NGL marketing and transportation. 
+We have entered into firm transportation contracts that require us to pay fixed sums of money regardless of quantities actually shipped. If we are unable to deliver the minimum quantities of production, such requirements could adversely affect our results of operations, financial position, and liquidity. We have entered into firm transportation agreements for a portion of our production in certain areas in order to improve our ability, and that of our purchasers, to successfully market our production. We may also enter into firm transportation arrangements for additional production in the future. These firm transportation agreements may be more costly than interruptible or short-term transportation agreements. Additionally, these agreements obligate us to pay fees on minimum volumes regardless of actual throughput. If we have insufficient production to meet the minimum volumes, the requirements to pay for quantities not delivered could have an impact on our results of operations, financial position, and liquidity. 
+Risks Related to Our Reserves and Drilling Locations 
+Our estimated reserves are based on interpretations and assumptions that may be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. This 2021 Annual Report on Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves. The process of estimating oil and natural gas reserves is complex and requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. These assumptions include those required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. 
+Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from the estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this 2021 Annual Report on Form 10-K. Additionally, estimates of reserves and future cash flows may be subject to material downward or upward revisions, based on production history, development drilling and exploration activities and prices of oil and natural gas. 
+You should not assume that any PV-10 of our estimated proved reserves contained in this 2021 Annual Report on Form 10-K represents the market value of our oil and natural gas reserves. We base the PV-10 from our estimated proved reserves at December 31, 2021 on the 12-Month Average Realized Prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures, the rate and timing of production, and changes in governmental regulations or taxes. Recovery of PUDs generally requires significant capital expenditures and successful drilling operations. Our reserve estimates include the assumption that we will make significant capital expenditures to develop these PUDs and the actual costs, development schedule, and results associated with these properties may not be as estimated. In addition, the discount factor used to calculate PV-10 may not be appropriate based on our cost of capital from time to time and the risks associated with our business and the oil and gas industry. 
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+Unless we replace our oil and gas reserves, our reserves and production will decline. Our future oil and gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our production, revenues, reserve quantities and cash flows will decline. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. We may not be successful in finding, developing or acquiring additional reserves, and our efforts may not be economic. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be limited to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. 
+Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could prevent them from being drilled or delay their drilling. Our management team has identified drilling locations as an estimation of our future development activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these identified drilling locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, availability and cost of drilling, completion and production services and equipment, lease expirations, regulatory approvals, and other factors discussed in these risk factors. Because of these uncertain factors, we do not know if the identified drilling locations will ever be drilled or if we will be able to produce oil or natural gas from these drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the identified locations are located, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified. 
+The development of our PUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. Developing PUDs requires significant capital expenditures and successful drilling operations, and a substantial amount of our proved reserves are PUDs which may not be ultimately developed or produced. Approximately 43% of our total estimated proved reserves as of December 31, 2021 were PUDs. The reserve data included in the reserve reports of our independent petroleum engineers assume significant capital expenditures will be made to develop such reserves. We cannot be certain that the estimated capital expenditures to develop these reserves are accurate, that development will occur as scheduled, or that the results of such development will be as estimated. We may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including: unexpected drilling conditions; pressure or irregularities in formations; lack of proximity to and shortage of capacity of transportation facilities; equipment failures or accidents and shortages or delays in the availability of drilling rigs, equipment, personnel and services; the availability of capital; and compliance with governmental requirements. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the future net revenues of our estimated PUDs and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves. 
+Risks Related to Technology 
+We may not be able to keep pace with technological developments in our industry. The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected. 
+Our business could be negatively affected by security threats. A cyberattack or similar incident could occur and result in information theft, data corruption, operational disruption, damage to our reputation or financial loss. The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, manage operations, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Our technologies, systems, networks, seismic data, reserves information or other proprietary information, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or could otherwise lead to the disruption of our business operations or other operational disruptions in our exploration or production operations. Cyberattacks are becoming more sophisticated and certain cyber incidents, such as surveillance, may remain undetected for an extended period and could lead to disruptions in critical systems or the unauthorized release of confidential or otherwise protected information. These events could lead to financial losses from remedial actions, loss of business, disruption of operations, damage to our reputation or potential liability. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyberattack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. Cyber incidents have increased, and the U.S. government has issued warnings indicating that energy assets may be specific targets of cybersecurity threats. Our systems and 
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+insurance coverage for protecting against cybersecurity risks may not be sufficient. Further, as cyberattacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyberattacks. 
+Risks Related to Our Indebtedness and Financial Position 
+Our business requires significant capital expenditures. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. We intend to fund our capital expenditures through a combination of cash flows from operations and, if needed, borrowings from financial institutions, the sale of debt and equity securities, and asset divestitures. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, participation of non-operating working interest owners, the cost and availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. 
+If the ability to borrow under our Credit Facility or our cash flows from operations decrease, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. The failure to obtain additional financing on terms acceptable to us, or at all, could result in a curtailment of our development activities and could adversely affect our business, financial condition and results of operations. 
+Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects. As of December 31, 2021, we had aggregate outstanding indebtedness of approximately $2.7 billion. Our amount of indebtedness could affect our operations in many ways, including: 
+• requiring us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities as well as any potential returns to shareholders; 
+• limiting management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; 
+• increasing our vulnerability to downturns and adverse developments in our business and the economy; 
+• limiting our ability to access the capital markets to raise capital on favorable terms, to borrow under our Credit Facility or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness; 
+• making it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; 
+• making us vulnerable to increases in interest rates as our indebtedness under our Credit Facility may vary with prevailing interest rates; 
+• placing us at a competitive disadvantage relative to competitors with lower levels of indebtedness or less restrictive terms governing their indebtedness; and 
+• making it more difficult for us to satisfy our obligations under our senior notes or other debt and increasing the risk that we may default on our debt obligations. 
+Restrictive covenants in the agreements governing our indebtedness may limit our ability to respond to changes in market conditions or pursue business opportunities. Our Credit Facility and the indentures governing our second lien senior secured notes and senior notes contain restrictive covenants that limit our ability to, among other things: incur additional indebtedness including secured indebtedness; make investments; merge or consolidate with another entity; pay dividends or make certain other payments; hedge future production or interest rates; create liens that secure indebtedness; repurchase securities; sell assets; or engage in certain other transactions without the prior consent of the holders or lenders. As a result of these covenants, we are limited in the manner in which we conduct our business and we may be unable to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business. 
+In addition, our Credit Facility requires us to maintain certain financial ratios and to make certain required payments of principal, premium, if any, and interest. If we fail to comply with these provisions or other financial and operating covenants in the Credit Facility or the indentures governing our senior notes, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our Credit Facility could elect to terminate their commitments thereunder, cease making further loans and institute foreclosure proceedings against our assets; and we could be forced into bankruptcy or liquidation. 
+Adverse changes in our credit rating may affect our borrowing capacity and borrowing terms. Our outstanding debt is periodically rated by nationally recognized credit rating agencies. The credit ratings are based on our operating performance, liquidity and leverage ratios, overall financial position, and other factors viewed by the credit rating agencies as relevant to our industry and the economic outlook. Our credit rating may affect the amount and timing of availability of capital we can access, as well as the terms of 
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+any financing we may obtain. Because we rely in part on debt financing to fund growth, adverse changes in our credit rating may have a negative effect on our future growth. 
+Our borrowings under our Credit Facility expose us to interest rate risk. Our borrowings under our Credit Facility make us vulnerable to increases in interest rates as they bear interest at a rate elected by us that is based on the prime, LIBOR or federal funds rate plus margins ranging from 1.00% to 3.00%, depending on the interest rate used and the amount of the loan outstanding in relation to the borrowing base. LIBOR is the subject of national, international and other regulatory guidance and proposals for reform and is currently being phased-out. At this time, it is not possible to predict how markets will respond to alternative reference rates, and the overall financial markets may be disrupted as a result of the phase-out or replacement of LIBOR. The consequences of these developments with respect to the phase-out of LIBOR cannot be predicted, but could include an increase in the cost of our borrowings under our Credit Facility. 
+The ability to borrow under our Credit Facility may be restricted to an amount below the amount of borrowings outstanding thereunder or to a lesser amount than what we expect due to future borrowing base reductions or restrictions contained in our other debt agreements. The borrowing base and elected commitment amount under our Credit Facility is currently $1.6 billion, and as of December 31, 2021, we had an aggregate principal balance of $785.0 million outstanding thereunder. Our borrowing base is subject to redeterminations semi-annually, and a future decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations may cause us to not be able to access adequate funding under the Credit Facility. The lenders have sole discretion in determining the amount of the borrowing base and may cause our borrowing base to be redetermined to a materially lower amount, including to below our outstanding borrowings as of such redetermination. In addition, our other debt agreements contain restrictions on the incurrence of additional debt and liens which could limit our ability to borrow under our Credit Facility. If our borrowing base were to be reduced, or if covenants in our indentures restrict our ability to access funding under the Credit Facility, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness. In addition, we cannot borrow amounts above the elected commitments, even if the borrowing base is greater, without new commitments being obtained from the lenders for such incremental amounts above the elected commitments. In the event the amount outstanding under our Credit Facility exceeds the elected commitments, we must repay such amounts immediately in cash. In the event the amount outstanding under our Credit Facility exceeds the redetermined borrowing base, we are required to either (i) grant liens on additional oil and gas properties (not previously evaluated in determining such borrowing base) with a value equal to or greater than such excess, (ii) repay such excess borrowings over six monthly installments, or (iii) elect a combination of options in clauses (i) and (ii). We may not have sufficient funds to make any required repayment. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, an event of default would occur under our Credit Facility. 
+We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful. Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to certain financial, economic, competitive and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. 
+If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Also, we may not be able to consummate dispositions at such time on terms acceptable to us or at all, and the proceeds of any such dispositions may not be adequate to meet such debt service obligations. Furthermore, any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. In addition, the terms of existing or future debt instruments may restrict us from adopting some of these alternatives. For example, our Credit Facility currently restricts our ability to dispose of assets and our use of the proceeds from such disposition. 
+Any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. 
+We cannot be certain that we will be able to maintain or improve our leverage position. An element of our business strategy involves maintaining a disciplined approach to financial management. However, we are also seeking to acquire, exploit and develop additional reserves that may require the incurrence of additional indebtedness. Although we will seek to maintain or improve our leverage position, our ability to maintain or reduce our level of indebtedness depends on a variety of factors, including future performance and our future debt financing needs. General economic conditions, oil and natural gas prices and financial, business and other factors will also affect our ability to maintain or improve our leverage position. Many of these factors are beyond our control. 
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+Risks Related to Acquisitions 
+We may be unable to integrate successfully the operations of acquisitions with our operations, and we may not realize all the anticipated benefits of these acquisitions. We have completed, and may in the future complete, acquisitions that include undeveloped acreage. We can offer no assurance that we will achieve the desired profitability from our recent acquisitions, including the Primexx Acquisition, or from any acquisitions we may complete in the future. In addition, failure to integrate future acquisitions successfully could adversely affect our financial condition and results of operations. 
+Our acquisitions may involve numerous risks, including those related to: 
+• operating a larger, more complex combined organization and adding operations; 
+• assimilating the assets and operations of the acquired business, especially if the assets acquired are in a new geographic area; 
+• acquired oil and natural gas reserves not being of the anticipated magnitude or as developed as anticipated; 
+• the loss of significant key employees, including from the acquired business; 
+• the inability to obtain satisfactory title to the assets we acquire; 
+• a decrease in our liquidity if we use a portion of our available cash to finance acquisitions; 
+• a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions; 
+• the diversion of management’s attention from other business concerns, which could result in, among other things, performance shortfalls; 
+• the failure to realize expected profitability or growth; 
+• the failure to realize expected synergies and cost savings; 
+• coordinating geographically disparate organizations, systems, data, and facilities; 
+• coordinating or consolidating corporate and administrative functions; 
+• inconsistencies in standards controls, procedures and policies; and 
+• integrating relationships with customers, vendors and business partners. 
+Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. The elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of our two companies, may not initially offset integration-related costs or achieve a net benefit in the near term or at all. 
+If we consummate any future acquisitions, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions. The inability to effectively manage the integration of acquisitions could reduce our focus on current operations, which in turn, could negatively impact our future results of operations. 
+We may fail to fully identify problems with any properties we acquire, and as such, assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities. We are actively seeking to acquire additional acreage in Texas or other regions in the future. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, adequacy of title, operating and capital costs, and potential environmental and other liabilities. Although we conduct a review that we believe is consistent with industry practices, we can give no assurance that we have identified or will identify all existing or potential problems associated with such properties or that we will be able to mitigate any problems we do identify. Such assessments are inexact and their accuracy is inherently uncertain. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface, title and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms. 
+Risks Related to Our Hedging Program 
+Our hedging program may limit potential gains from increases in commodity prices, result in losses, or be inadequate to protect us against continuing and prolonged declines in commodity prices. We enter into arrangements to hedge a portion of our production from time to time to reduce our exposure to fluctuations in oil, natural gas, and NGL prices and to achieve more predictable cash flow. Our hedges at December 31, 2021 are in the form of collars, swaps, put and call options, basis swaps, and other structures placed with the commodity trading branches of certain banking institutions and with certain other commodity trading groups. These hedging arrangements may limit the benefit we could receive from increases in the market or spot prices for oil, natural gas, and NGLs. We cannot be certain that the hedging transactions we have entered into, or will enter into, will adequately protect us from continuing and prolonged declines in oil, natural gas, and NGL prices. To the extent that oil, natural gas, and NGL prices remain at current levels or decline further, we would not be able to hedge future production at the same pricing level as our current hedges and our results of operations and financial condition may be negatively impacted. 
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+In addition, in a typical hedge transaction, we will have the right to receive from the other parties to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the other parties this difference multiplied by the quantity hedged regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements even though such payments are not offset by sales of physical production. 
+Our production is not fully hedged, and we are exposed to fluctuations in oil, natural gas and NGL prices and will be affected by continuing and prolonged declines in oil, natural gas and NGL prices. Our production is not fully hedged, and we are exposed to fluctuations in oil, natural gas and NGL prices and will be affected by continuing and prolonged declines in oil, natural gas and NGL prices. The total volumes which we hedge through use of our derivative instruments varies from period to period and takes into account our view of current and future market conditions in order to provide greater certainty of cash flows to meet our debt service costs and capital program. We generally hedge for the next 12 to 24 months, subject to the covenants under our Credit Facility. We intend to continue to hedge our production, but we may not be able to do so at favorable prices. Accordingly, our revenues and cash flows are subject to increased volatility and may be subject to significant reduction in prices which would have a material negative impact on our results of operations. 
+Our hedging transactions expose us to counterparty credit risk. Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract, particularly during periods of falling commodity prices. Disruptions in the financial markets or other factors outside our control could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform, and even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending on market conditions at the time. If the creditworthiness of any of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss. 
+Legal and Regulatory Risks 
+We are subject to stringent and complex federal, state and local laws and regulations which require compliance that could result in substantial costs, delays or penalties. Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. For a discussion of the material regulations applicable to us, see “Business and Properties—Regulations.” These laws and regulations may: 
+• require that we acquire permits before commencing drilling; 
+• regulate the spacing of wells and unitization and pooling of properties; 
+• impose limitations on production or operational, emissions control and other conditions on our activities; 
+• restrict the substances that can be released into the environment or used in connection with drilling and production activities or restrict the disposal of waste from our operations; 
+• limit or prohibit drilling activities on protected areas, such as wetlands and wilderness; 
+• impose penalties or other sanctions for accidental or unpermitted spills or releases from our operations; or 
+• require measures to remediate or mitigate pollution and environmental impacts from current and former operations, such as cleaning up spills or decommissioning abandoned wells and production facilities. 
+Significant expenditures may be required to comply with governmental laws and regulations applicable to us. In addition, failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, permit revocations, requirements for additional pollution controls or injunctions limiting or prohibiting operations. 
+The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal, state and local agencies frequently revise environmental laws and regulations, and such changes could result in increased costs for environmental compliance, such as emissions monitoring and control, permitting, or waste handling, storage, transport, remediation or disposal for the oil and natural gas industry and could have a significant impact on our operating costs. In general, the oil and natural gas industry recently has been the subject of increased legislative and regulatory attention with respect to public health and environmental matters. Even if regulatory burdens temporarily ease from time to time, the historic trend of more expansive and stricter environmental legislation and regulations may continue in the long-term. 
+Further, under these laws and regulations, we could be liable for costs of investigation, removal and remediation, damages to and loss of use of natural resources, loss of profits or impairment of earning capacity, property damages, costs of increased public services, as well as administrative, civil and criminal fines and penalties, and injunctive relief. Certain environmental statutes, including RCRA, CERCLA, OPA and analogous state laws and regulations, impose strict, joint and several liability for costs required to investigate, clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released (i.e., liability may be imposed regardless of whether the current owner or operator was responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time the release or contamination occurred). We could also be affected by more stringent laws and regulations adopted in the future, including any related to climate change, engine and other 
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+equipment emissions, GHGs and hydraulic fracturing. Under common law, we could be liable for injuries to people and property. We maintain limited insurance coverage for sudden and accidental environmental damages. We do not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Also, we do not believe that insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability in excess of our insurance coverage or we may be required to curtail or cease production from properties in the event of environmental incidents. 
+Federal legislation and state and local legislative and regulatory initiatives relating to hydraulic fracturing and water disposal wells could result in increased costs and additional operating restrictions or delays. Hydraulic fracturing is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production and is typically regulated by state oil and gas commissions. However, from time to time, the U.S. Congress has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing. Legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and to require federal permitting and regulatory control of hydraulic fracturing but has not passed. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA regulates hydraulic fracturing with fluids containing diesel fuel under the UIC program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act. The EPA has recently taken steps to strengthen its methane standards, including most recently in November 2021, when the EPA issued a proposed rule intended to reduce methane emissions from oil and gas sources. The proposed rule would make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the CAA (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities). In addition, the proposed rule would establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by EPA. Under the proposed rule, states would have three years to develop their compliance plan for existing sources and the regulations for new sources would take effect immediately upon issuance of a final rule. The EPA is expected to issue both a supplemental proposed rule, which may expand or modify the current proposed rule, and final rule by the end of 2022. The scope of future obligations remains uncertain; however, given the long-term trend towards increasing regulation, future federal regulation of methane and other greenhouse gas emissions from the oil and gas industry remains a possibility. 
+In some areas of Texas, including the Eagle Ford and Permian, there has been concern that certain formations into which disposal wells are injecting produced waters could become over-pressured after many years of injection, and the RRC is reviewing the data to determine whether any regulatory action is necessary to address this issue. If the RRC were to decline to issue permits for, or impose new limits on the volumes of, injection wells into the formations that we currently utilize, we may be required to seek alternative methods of disposing of produced waters, including injecting into deeper formations, which could increase our costs. 
+Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, impose additional requirements on hydraulic fracturing activities or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For example, Texas law requires the chemical components used in the hydraulic fracturing process, as well as the volume of water used, must be disclosed to the RRC and the public. The RRC’s “well integrity rule” includes testing and reporting requirements, such as (i) the requirement to submit to the RRC cementing reports after well completion or cessation of drilling, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. Additionally, the RRC rules require applicants for certain new water disposal wells to conduct seismic activity searches using the U.S. Geological Survey to determine the potential for earthquakes within a circular area of 100 square miles. Further, the RRC has authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The RRC has used this authority to deny permits for, and limit volumes for, disposal wells. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of drilling in general or hydraulic fracturing in particular. 
+The EPA issued the “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States” report, concluding that hydraulic fracturing can impact drinking water resources in certain circumstances but also noted that certain data gaps and uncertainties limited EPA’s ability to fully characterize the severity of impacts or calculate the national frequency of impacts on drinking water resources from activities in the hydraulic fracturing water cycle. This study could result in additional regulatory scrutiny that could restrict our ability to perform hydraulic fracturing and increase our costs of compliance and doing business. 
+There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, water usage and the potential for impacts to surface water, groundwater and the environment generally, and a number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. Several states and municipalities have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances. If new laws or regulations that significantly restrict hydraulic fracturing or water 
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+disposal wells are adopted, such laws could make it more difficult or costly for us to drill for and produce oil and natural gas as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements, permitting delays and potential increases in costs. These changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing. 
+Climate change legislation or regulations restricting emissions of GHG, changes in the availability of financing for fossil fuel companies, and physical effects from climate change could adversely impact our operating costs and demand for the oil and natural gas we produce. In recent years, federal, state and local governments have taken steps to reduce emissions of GHGs. The EPA has finalized a series of GHG monitoring, reporting and emissions control rules and proposed additional rules, and the U.S. Congress has, from time to time, considered adopting legislation to reduce or tax emissions. Several states have already taken measures to reduce emissions of GHGs primarily through the development of GHG emission inventories or regional GHG cap-and-trade programs. While we are subject to certain federal GHG monitoring and reporting requirements, our operations currently are not adversely impacted by existing federal, state and local climate change initiatives. For a description of some existing and proposed GHG rules and regulations, see “Business and Properties—Regulations.” 
+In December 2015, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change resulted in nearly 200 countries, including the United States, coming together to develop the Paris Agreement, which calls for the parties to undertake “ambitious efforts” to limit the average global temperature. The Agreement went into effect on November 4, 2016, and establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. On June 1, 2017, President Trump announced that the U.S. would withdraw from the Paris Agreement and completed the process of withdrawing from the Paris Agreement on November 4, 2020. However, on January 20, 2021, President Biden issued written notification to the United Nations of the United States’ intention to rejoin the Paris Agreement, which became effective on February 19, 2021. In addition, in September 2021, President Biden publicly announced the Global Methane Pledge, a pact that aims to reduce global methane emissions at least 30% below 2020 levels by 2030. Since its formal launch at the COP26, over 100 countries have joined the pledge. The COP26 concluded with the finalization of the Glasgow Pact, which stated long-term global goals (including those in the Paris Agreement) to limit the increase in the global average temperature and emphasized reductions in GHG emissions. In addition, a number of states have begun taking actions to control or reduce emissions of GHGs. Restrictions on GHG emissions that may be imposed could adversely affect the oil and gas industry. The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Moreover, incentives or requirements to conserve energy, use alternative energy sources, reduce GHG emissions in product supply chains, and increase demand for low-carbon fuel or zero-emissions vehicles, could reduce demand for the oil and natural gas we produce. International commitments, re-entry into the Paris Agreement, and President Biden’s executive orders may result in the development of additional regulations or changes to existing regulations. At the federal level, although no comprehensive climate change legislation has been implemented to date, such legislation has periodically been introduced in the U.S. Congress and may be proposed or adopted in the future. The likelihood of such legislation has increased due to the current administration. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations. 
+In addition, fuel conservation measures, alternative fuel requirements and increasing consumer demand for alternatives to oil and natural gas could reduce demand for oil and natural gas. Such activism and initiatives aimed at limiting climate change and reducing air pollution could impact our business activities, operations and ability to access capital. Furthermore, some parties have initiated public nuisance claims under federal or state common law against certain companies involved in the production of oil and natural gas. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other liabilities. Although our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition. 
+Finally, most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere and climate change may produce significant physical effects on weather conditions, such as increased frequency and severity of droughts, storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced or cause us to incur significant costs in preparing for or responding to the effects of climatic events themselves. Potential adverse effects could include disruption of our production activities, including, for example, damages to our facilities from winds or floods, increases in our costs of operation, or reductions in the efficiency of our operations, impacts on our personnel, supply chain, or distribution chain, as well as potentially increased costs for insurance coverages in the aftermath of such effects. Our ability to mitigate 
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+the adverse physical impacts of climate change depends in part upon our disaster preparedness and response and business continuity planning. 
+Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. Title VII of the Dodd-Frank Act establishes federal oversight and regulation of over-the-counter derivatives and requires the CFTC and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the over-the-counter market. 
+Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas, including the scope of relevant definitions or exemptions, remain pending. The CFTC issued a final rule on margin requirements for uncleared swap transactions in January 2016, which it amended in November 2018. The final rule as amended includes an exemption for certain commercial end-users that enter into uncleared swaps in order to hedge bona fide commercial risks affecting their business. In addition, the CFTC has issued a final rule authorizing an exception from the requirement to use cleared exchanges (rather than hedging over-the-counter) for commercial end-users who use swaps to hedge their commercial risks. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations. On January 24, 2020, U.S. banking regulators published a new approach for calculating the quantum of exposure of derivative contracts under their regulatory capital rules. This approach to measuring exposure is referred to as the standardized approach for counterparty credit risk or SA-CCR. It requires certain financial institutions to comply with significantly increased capital requirements for over-the-counter commodity derivatives beginning on January 1, 2022. In addition, on September 15, 2020, the CFTC issued a final rule regarding the capital a swap dealer or major swap participant is required to set aside with respect to its swap business, which has a compliance date of October 6, 2021. These two sets of regulations and the increased capital requirements they place on certain financial institutions may reduce the number of products and counterparties in the over-the-counter derivatives market available to us and could result in significant additional costs being passed through to end-users like us. On January 14, 2021, the CFTC published a final rule on position limits for certain commodities futures and their economically equivalent swaps, though like several other rules there is a bona fide hedging exemption to the application of such rule. All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business. 
+Depending on our ability to satisfy the CFTC’s requirements for the various exemptions available for a commercial end-user using swaps to hedge or mitigate its commercial risks, the final rules may provide beneficial exemptions and/or may require us to comply with position limits and other limitations with respect to our financial derivative activities. After the compliance date for the final rule on capital requirements, the Dodd-Frank Act may require our current counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which could increase the cost to us of entering into such derivatives. The Dodd-Frank Act may also require our current counterparties to financial derivative transactions to cease their current business as hedge providers or spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. These potential changes could reduce the liquidity of the financial derivatives markets which would reduce the ability of commercial end-users like us to hedge or mitigate their exposure to commodity price volatility. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of future swaps relative to the terms of our existing financial derivative contracts, and reduce the availability of derivatives to protect against commercial risks we encounter. 
+If we reduce our use of derivative contracts as a result of any of the foregoing new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Our revenues could be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations, or cash flows. 
+Tax Risks 
+Our ability to use our existing net operating loss (“NOL”) carryforwards or other tax attributes could be limited. A significant portion of our NOL carryforward balance was generated prior to the effective date of limitations on utilization of NOLs imposed by the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) and are allowable as a deduction against 100% of taxable income in future years, but will start to expire in the 2035 taxable year. The remainder were generated following such effective date, and thus generally allowable as a deduction against 80% of taxable income in future years (with an exception to this rule due to the enactment of the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”), whereby the utilization of NOLs was temporarily expanded for taxable years beginning before 2021). Utilization of any NOL carryforwards depends on many factors, including our ability to generate future taxable income, which cannot be assured. In addition, Section 382 (“Section 382”) of the Internal Revenue Code of 1986, as amended (the “Code”), generally imposes, upon the occurrence of an ownership change (discussed below), an annual limitation on the amount of our pre-ownership change NOLs we can utilize to offset our taxable income in any taxable year (or portion thereof) ending after such ownership change. The limitation is generally equal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax exempt rate. In general, an ownership change occurs if there is a cumulative increase in our ownership of more than 50 percentage points by one or more “5% shareholders” (as defined in the Code) at any time 
+38 
+during a rolling three-year period. Future ownership changes and/or future regulatory changes could further limit our ability to utilize our NOLs. To the extent we are not able to offset our future income with our NOLs, this could adversely affect our operating results and cash flows once we attain profitability. 
+Unanticipated changes in effective tax rates or adverse outcomes resulting from examination of our income or other tax returns could adversely affect our financial condition and results of operations. We are subject to income taxes in the U. S., and our domestic tax assets and liabilities are subject to the allocation of expenses in differing jurisdictions. Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including the following: changes in the valuation of our deferred tax assets and liabilities; expected timing and amount of the release of any tax valuation allowances; tax effects of stock-based compensation; costs related to intercompany restructurings; changes in tax laws, regulations or interpretations thereof; or lower than anticipated future earnings in our taxing jurisdictions. In addition, we may be subject to audits of our income, sales and other transaction taxes by U.S. federal and state authorities. Outcomes from these audits could have an adverse effect on our financial condition and results of operations. 
+Tax laws and regulations may change over time and such changes could adversely affect our business and financial condition. From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws, including (i) the elimination of the immediate deduction for intangible drilling and development costs, (ii) changes to a depletion allowance for oil and natural gas properties, (iii) the implementation of a carbon tax, (iv) an extension of the amortization period for certain geological and geophysical expenditures, (v) changes to tax rates, and (vi) the introduction of a minimum tax. While these specific changes were not included in the Tax Act or the CARES Act, no accurate prediction can be made as to whether any such legislative changes or other changes (such as those contained in the Build Back Better Act) will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. The elimination of U.S. federal tax deductions, as well as any other changes to or the imposition of new federal, state, local or non-U.S. taxes (including the imposition of, or increases in production, severance or similar taxes) could adversely affect our business and financial condition. 
+Other Material Risks 
+Competitive industry conditions may negatively affect our ability to conduct operations. We compete with numerous other companies in virtually all facets of our business. Our competitors in development, exploration, acquisitions and production include major integrated oil and gas companies and smaller independents as well as numerous financial buyers. Some of our competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources permit. We also compete for the materials, equipment, personnel and services that are necessary for the exploration, development and operation of our properties. Our ability to increase reserves in the future will be dependent on our ability to select and acquire suitable prospects for future exploration and development. 
+All of our producing properties are located in the Permian of West Texas and the Eagle Ford of South Texas, making us vulnerable to risks associated with operating in only two geographic regions. As a result of this concentration, as compared to companies that have a more diversified portfolio of properties, we may be disproportionately exposed to the impact of regional supply and demand factors, severe weather, delays or interruptions of production from wells in this area caused by governmental regulation, specific taxes or other regulatory legislation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services, or market limitations or interruption of the processing or transportation of oil, natural gas or NGLs. Such delays, interruptions or limitations could have a material adverse effect on our financial condition and results of operations. In addition, the effect of fluctuations on supply and demand may be more pronounced within specific geographic oil and natural gas producing areas, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. 
+The results of our planned development programs in new or emerging shale development areas and formations may be subject to more uncertainties than programs in more established areas and formations, and may not meet our expectations for reserves or production. The results of our horizontal drilling efforts in emerging areas and formations of the Permian are generally more uncertain than drilling results in areas that are more developed and have more established production from horizontal formations. Because emerging areas and associated target formations have limited or no production history, we are less able to rely on past drilling results in those areas as a basis to predict our future drilling results. In addition, horizontal wells drilled in shale formations, as distinguished from vertical wells, utilize multilateral wells and stacked laterals, all of which are subject to well spacing, density and proration requirements of the RRC, which requirements could adversely impact our ability to maximize the efficiency of our horizontal wells related to reservoir drainage over time. Further, access to adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more challenging in new or emerging areas. If our drilling results in these areas are less than anticipated or we are unable to execute our drilling program in these areas because of capital constraints, access to gathering systems and takeaway capacity or otherwise, or natural gas and oil prices decline, our investment in these areas may not be as economic as we anticipate, we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future. 
+39 
+The loss of key personnel, or inability to employ a sufficient number of qualified personnel, could adversely affect our ability to operate. We depend, and will continue to depend in the foreseeable future, on the services of our senior officers and other key employees, as well as other third-party consultants with extensive experience and expertise in evaluating and analyzing drilling prospects and producing oil and natural gas and maximizing production from oil and natural gas properties. Our ability to retain our senior officers, other key employees, and third party consultants, many of whom are not subject to employment agreements, is important to our future success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business. Also, we may experience employee turnover or labor shortages if our business requirements, compensation, benefits and/or perquisites are inconsistent with the expectations of current or prospective employees, or if workers pursue employment in fields with less volatility than in the energy industry. If we are unsuccessful in our efforts to attract and retain sufficient qualified personnel on terms acceptable to us, or do so at rates necessary to maintain our competitive position, our business could be adversely affected. 
+The inability of one or more of our customers to meet their obligations to us may adversely affect our financial results. Our principal exposure to credit risk is through receivables resulting from the sale of our oil and natural gas production, advances to joint interest parties and joint interest receivables. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. The largest purchaser of our oil and natural gas accounted for approximately 20% of our total revenues for the year ended December 31, 2021. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. 
+Our bylaws designate the Court of Chancery of the State of Delaware (the “Court of Chancery”) as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our shareholders, which could limit our shareholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, or other employees. Our bylaws provide that, unless we consent in writing to the selection of an alternative forum, the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action or proceeding asserting a claim for breach of a fiduciary duty owed by any current or former director, officer, or other employee of our company to us or our shareholders, (iii) any action or proceeding asserting a claim against us or any current or former director, officer, or other employee of our company arising pursuant to any provision of the Delaware General Corporate Law (the “DGCL”) or our charter or bylaws (as each may be amended from time to time), (iv) any action or proceeding asserting a claim against us or any current or former director, officer, or other employee of our company governed by the internal affairs doctrine, or (v) any action or proceeding as to which the DGCL confers jurisdiction on the Court of Chancery shall be the Court of Chancery or, if and only if the Court of Chancery lacks subject matter jurisdiction, any state court located within the State of Delaware or, if and only if such state courts lack subject matter jurisdiction, the federal district court for the District of Delaware, in all cases to the fullest extent permitted by law and subject to the court’s having personal jurisdiction over the indispensable parties named as defendants. 
+Our exclusive forum provision is not intended to apply to claims arising under the Securities Act or the Exchange Act. To the extent the provision could be construed to apply to such claims, there is uncertainty as to whether a court would enforce the forum selection provision with respect to such claims, and in any event, our shareholders would not be deemed to have waived our compliance with federal securities laws and the rules and regulations thereunder. 
+Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock is deemed to have received notice of and consented to the foregoing forum selection provision. This provision may limit our shareholders’ ability to bring a claim in a judicial forum that they find favorable for disputes with us or our directors, officers, or other employees, which may discourage such lawsuits. Alternatively, if a court were to find this choice of forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect its business, financial condition, prospects, or results of operations. 
+Provisions of our charter documents and Delaware law may inhibit a takeover, which could limit the price investors might be willing to pay in the future for our common stock. Provisions in our certificate of incorporation and bylaws may have the effect of delaying or preventing an acquisition of the Company or a merger in which we are not the surviving company and may otherwise prevent or slow changes in our Board of Directors and management. In addition, because we are incorporated in Delaware, we are governed by the provisions of Section 203 of the DGCL. These provisions could discourage an acquisition of the Company or other change in control transactions and thereby negatively affect the price that investors might be willing to pay in the future for our common stock. 
+We have no current plans to pay cash dividends on our common stock. Our Credit Facility and the indentures governing our senior notes limit our ability to pay dividends and make other distributions. We have no current plans to pay dividends on our common stock and any future determination as to the declaration and payment of cash dividends will be at the discretion of our Board of Directors and will depend upon our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors deemed relevant by our Board of Directors at the time of such determination. Consequently, unless we revise our dividend plans, a shareholder’s only opportunity to achieve a return on its investment in us will be by selling its shares of 
+40 
+our common stock at a price greater than the shareholder paid for it. There is no guarantee that the price of our common stock that will prevail in the market will exceed the price at which a shareholder purchased its shares of our common stock. 
+General Risk Factors 
+We may be subject to the actions of activist shareholders. We have been the subject of an activist shareholder in the past. Responding to shareholder activism can be costly and time-consuming, disrupt our operations and divert the attention of management and our employees from executing our business plan. Activist campaigns can create perceived uncertainties as to our future direction, strategy or leadership and may result in the loss of potential business opportunities, harm our ability to attract new investors, customers and joint venture partners and cause our stock price to experience periods of volatility or stagnation. Moreover, if individuals are elected to our Board of Directors with a specific agenda, our ability to effectively and timely implement our current initiatives, retain and attract experienced executives and employees and execute on our long-term strategy may be adversely affected. 
+Future sales of our common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of our common stock or other securities may dilute a shareholder’s ownership in us. In the future, we may continue to issue securities to raise capital. We may also continue to acquire interests in other companies by using any combination of cash and our common stock or other securities convertible into, or exchangeable for, or that represent the right to receive, our common stock. Any of these events may dilute your ownership interest in our company, reduce our earnings per share or have an adverse impact on the price of our common stock. In addition, secondary sales of a substantial amount of our common stock in the public market, or the perception that these sales may occur, could reduce the market price of our common stock. Any such reduction in the market price of our common stock could impair our ability to raise additional capital through the sale of our securities. 
+ITEM 1B. Unresolved Staff Comments 
+None. 
+ITEM 3. Legal Proceedings 
+We are a defendant in various legal proceedings and claims, which arise in the ordinary course of our business. While the outcome of these events cannot be predicted with certainty, we believe that the ultimate resolution of any such actions will not have a material effect on our financial position or results of operations. 
+ITEM 4. Mine Safety Disclosures 
+Not applicable. 
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+PART II. 
+ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+Market Information 
+Our common stock trades on the New York Stock Exchange (“NYSE”) under the symbol “CPE”. 
+Reverse Stock Split 
+On August 7, 2020, the Board of Directors effected a reverse stock split of the Company’s outstanding shares of common stock at a ratio of 1-for-10 and proportionately reduced the total number of authorized shares from 525,000,000 to 52,500,000 shares. The Company’s common stock began trading on a split-adjusted basis on the NYSE at the market open on August 10, 2020. All share and per share amounts in this Annual Report on Form 10-K for periods prior to August 7, 2020 have been retroactively adjusted to reflect the reverse stock split. The par value of the common stock was not adjusted as a result of the reverse stock split. 
+Holders 
+As of February 18, 2022 the Company had approximately 1,182 common stockholders of record. 
+Dividends 
+We have not paid any cash dividends on our common stock to date and our near-term focus is to reinvest our cash flows and earnings into our business and continue to pay down debt. However, we continuously monitor many internal and external factors as we consider when, or if, we should implement shareholder return programs. These factors include our current and projected financial performance; our debt metrics, covenants and absolute amounts borrowed; commodity price outlooks; cash requirements; corporate and strategic plans; macroeconomic indicators; among other items. Ultimately, the timing, amount and form of future dividends, if any, is subject to the discretion of our Board of Directors and to certain limitations imposed under Delaware corporate law and the agreements governing our debt obligations. 
+Performance Graph 
+The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the performance of the Company’s common stock relative to a broad-based stock performance index and a peer group of companies. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. 
+The stock price performance graph compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the Standard & Poor’s 500 Index (“S&P 500 Index”) and a peer group of companies to which we compare our performance from December 31, 2016 through December 31, 2021. The companies in the peer group include Centennial Resource Development, Inc., Laredo Petroleum, Inc., Magnolia Oil & Gas Corporation, Matador Resources, Inc., PDC Energy, Inc., Ranger Oil Corporation and SM Energy Company. The Company’s historical stock prices used in the graph below have been retroactively adjusted to reflect the Company’s 1-for-10 reverse stock split effective August 7, 2020. 
+The stock price performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that the Company specifically incorporates it by reference into such filing 
+42 
+Comparison of Five Year Cumulative Total Return 
+Assumes Initial Investment of $100 
+December 31, 2021 
+Years Ended December 31, 
+Company/Market/Peer Group 2016 2017 2018 2019 2020 2021 
+Callon Petroleum Company $100 $79 $42 $31 $9 $31 
+S&P 500 Index - Total Returns 100 122 116 153 181 233 
+Peer Group 100 85 63 51 26 85 
+Unregistered Sales of Equity Securities and Use of Proceeds 
+Pursuant to the closing of the Primexx Acquisition, the Company issued 8.84 million shares of the Company’s common stock as a portion of the total consideration for the assets acquired. Also pursuant to the Primexx PSAs, certain interest owners exercised their option to sell their interest in the properties included in the Primexx Acquisition to the Company for consideration equal to 0.2 million shares of the Company’s common stock. 
+Pursuant to the closing of the Second Lien Note Exchange, the Company exchanged $197.0 million of its outstanding Second Lien Notes for a notional amount of approximately $223.1 million of its common stock, which equated to 5.5 million shares. 
+All shares issued pursuant to the Primexx Acquisition and the Second Lien Note Exchange were issued in reliance upon the exemption from the registration requirements of the Securities Act provided by Section 4(a)(2) of the Securities Act as sales by an issuer not involving any public offering. The issuance of such shares in connection with the Primexx Acquisition and the Second Lien Note Exchange did not involve a public offering for purposes of Section 4(a)(2) because of, among other things, it was being made only to accredited investors, and in connection therewith, the Company did not engage in general solicitation or advertising with regard to the issuance of such shares. 
+43 
+ITEM 6. Reserved 
+ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+The following management’s discussion and analysis describes the principal factors affecting our results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying audited consolidated financial statements, information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results, which are included in various parts of this filing. 
+A discussion and analysis of the Company’s financial condition and results of operations for the year ended December 31, 2019 can be found in “Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” of its Annual Report on Form 10-K for the year ended December 31, 2020, which was filed with the SEC on February 25, 2021. 
+General 
+We are an independent oil and natural gas company focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas. Our activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger Permian Basin in West Texas, as well as the Eagle Ford in South Texas. Our operating culture is centered on responsible development of hydrocarbon resources, safety and the environment, which we believe strengthens our operational performance. Our drilling activity is predominantly focused on the horizontal development of several prospective intervals in the Permian, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales, and the Eagle Ford. We have assembled a multi-year inventory of potential horizontal well locations and intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and through acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps. 
+Financial and Operational Highlights 
+For discussion of our significant financial and operational highlights for the year ended December 31, 2021, please see “Part 1. Items 1 and 2. Business and Properties — Overview — Major Developments in 2021”. 
+44 
+Results of Operations 
+The following table sets forth certain operating information with respect to the Company’s oil and natural gas operations for the periods indicated: 
+Years Ended December 31, 
+2021 2020 $ Change % Change 
+Total production 
+Oil (MBbls) 
+Permian 14,475 14,113 362 3 % 
+Eagle Ford 7,749 9,430 (1,681) (18 %) 
+Total oil 22,224 23,543 (1,319) (6 %) 
+Natural gas (MMcf) 
+Permian 29,682 32,087 (2,405) (7 %) 
+Eagle Ford 7,704 8,714 (1,010) (12 %) 
+Total natural gas 37,386 40,801 (3,415) (8 %) 
+NGLs (MBbls) 
+Permian 5,155 5,390 (235) (4 %) 
+Eagle Ford 1,284 1,460 (176) (12 %) 
+Total NGLs 6,439 6,850 (411) (6 %) 
+Total production (MBoe) 
+Permian 24,577 24,851 (274) (1 %) 
+Eagle Ford 10,317 12,342 (2,025) (16 %) 
+Total barrels of oil equivalent 34,894 37,193 (2,299) (6 %) 
+Total daily production (Boe/d) 95,599 101,620 (6,021) (6 %) 
+Oil as % of total daily production 64 % 63 % 1 % 
+Benchmark prices (1) 
+WTI (per Bbl) $67.94 $39.38 $28.56 73 % 
+Henry Hub (per Mcf) 3.72 2.13 1.59 75 % 
+Average realized sales price (excluding impact of derivative settlements) 
+Oil (per Bbl) 
+Permian $68.20 $37.23 $30.97 83 % 
+Eagle Ford 68.27 34.49 33.78 98 % 
+Total oil 68.22 36.13 32.09 89 % 
+Natural gas (per Mcf) 
+Permian 3.69 1.05 2.64 251 % 
+Eagle Ford 4.13 2.07 2.06 100 % 
+Total natural gas 3.78 1.27 2.51 198 % 
+NGL (per Bbl) 
+Permian 30.60 11.91 18.69 157 % 
+Eagle Ford 28.12 11.71 16.41 140 % 
+Total NGL 30.11 11.87 18.24 154 % 
+Total average realized sales price (per Boe) 
+Permian 51.05 25.09 25.96 103 % 
+Eagle Ford 57.86 29.20 28.66 98 % 
+Total average realized sales price $53.06 $26.45 $26.61 101 % 
+45 
+Years Ended December 31, 
+2021 2020 $ Change % Change 
+Revenues (in thousands) 
+Oil 
+Permian $987,195 $525,412 $461,783 88 % 
+Eagle Ford 529,030 325,255 203,775 63 % 
+Total oil 1,516,225 850,667 665,558 78 % 
+Natural gas 
+Permian 109,640 33,815 75,825 224 % 
+Eagle Ford 31,853 18,051 13,802 76 % 
+Total natural gas 141,493 51,866 89,627 173 % 
+NGLs 
+Permian 157,757 64,201 93,556 146 % 
+Eagle Ford 36,104 17,094 19,010 111 % 
+Total NGLs 193,861 81,295 112,566 138 % 
+Total revenues 
+Permian 1,254,592 623,428 631,164 101 % 
+Eagle Ford 596,987 360,400 236,587 66 % 
+Total revenues $1,851,579 $983,828 $867,751 88 % 
+Additional per Boe data 
+Lease operating expense 
+Permian $5.27 $4.71 $0.56 12 % 
+Eagle Ford 7.13 6.25 0.88 14 % 
+Total lease operating expense $5.82 $5.22 $0.60 11 % 
+Production and ad valorem taxes 
+Permian $2.75 $1.59 $1.16 73 % 
+Eagle Ford 3.16 1.87 1.29 69 % 
+Total production and ad valorem taxes $2.87 $1.68 $1.19 71 % 
+Gathering, transportation and processing 
+Permian $2.54 $2.29 $0.25 11 % 
+Eagle Ford 1.80 1.66 0.14 8 % 
+Total gathering, transportation and processing $2.32 $2.08 $0.24 12 % 
+(1) Reflects calendar average daily spot market prices. 
+46 
+Revenues 
+The following table reconciles the changes in oil, natural gas, NGLs, and total revenue for the period presented by reflecting the effect of changes in volume and in the underlying commodity prices. 
+Oil Natural Gas NGLs Total 
+(In thousands) 
+Revenues for the year ended December 31, 2020 (1) 
+$850,667 $51,866 $81,295 $983,828 
+Volume increase (decrease) (47,659) (4,342) (4,878) (56,879) 
+Price increase (decrease) 713,217 93,969 117,444 924,630 
+Net increase (decrease) 665,558 89,627 112,566 867,751 
+Revenues for the year ended December 31, 2021 (1) 
+$1,516,225 $141,493 $193,861 $1,851,579 
+Percent of total revenues 82 % 8 % 10 % 
+(1) Excludes sales of oil and gas purchased from third parties and sold to our customers. 
+Revenues for the year ended December 31, 2021, of $1.9 billion increased $867.8 million, or 88%, compared to revenues of $983.8 million for the year ended December 31, 2020. The increase was primarily attributable to a 101% increase in the average realized sales price which rose to $53.06 per Boe from $26.45 per Boe as well as revenue attributable to wells that were acquired in the Primexx Acquisition. The increase in the average realized sales price was partially offset by a 6% decrease in production, which was primarily due to the divestitures that occurred during 2021 as well as normal production decline, partially offset by production resulting from our developmental activities during the year as well as production from the properties acquired in the Primexx Acquisition. 
+Operating Expenses 
+Years Ended December 31, 
+Per Per Total Change Boe Change 
+2021 Boe 2020 Boe $ % $ % 
+(In thousands, except per Boe and % amounts) 
+Lease operating $203,141 $5.82 $194,101 $5.22 $9,040 5 % $0.60 11 % 
+Production and ad valorem taxes 100,160 2.87 62,638 1.68 37,522 60 % 1.19 71 % 
+Gathering, transportation and processing 80,970 2.32 77,309 2.08 3,661 5 % 0.24 12 % 
+Depreciation, depletion and amortization 356,556 10.22 480,631 12.92 (124,075) (26 %) (2.70) (21 %) 
+General and administrative 50,483 1.45 37,187 1.00 13,296 36 % 0.45 45 % 
+Impairment of evaluated oil and gas properties — — 2,547,241 68.48 (2,547,241) (100 %) (68.48) (100 %) 
+Merger, integration and transaction 14,289 0.41 28,482 0.77 (14,193) (50 %) (0.36) (47 %) 
+Lease Operating Expenses. Lease operating expenses for the year ended December 31, 2021 increased by 5% to $203.1 million compared to $194.1 million for the same period of 2020, primarily due to operating expenses attributable to wells that were acquired in the Primexx Acquisition, partially offset by a reduction in certain operating expenses such as repairs and maintenance and equipment rentals. Lease operating expense per Boe for the year ended December 31, 2021 increased to $5.82 compared to $5.22 for the same period of 2020 primarily due to the wells that were acquired in the Primexx Acquisition, as discussed above, higher costs driven by the recent increase in inflation, as well as the distribution of fixed costs spread over lower production volumes. 
+Production and Ad Valorem Taxes. For the year ended December 31, 2021, production and ad valorem taxes increased 60% to $100.2 million compared to $62.6 million for the same period of 2020, which is primarily related to an 88% increase in total revenues which increased production taxes. The impact of the increase in production taxes described above was partially offset by a decrease in ad valorem taxes due to lower property tax valuations for 2021 as a result of lower commodity prices during 2020. Production and ad valorem taxes as a percentage of total revenues decreased to 5.4% for the year ended December 31, 2021, as compared to 6.4% of total revenues for the same period of 2020, primarily due to lower property tax valuations for 2021 as discussed above. 
+Gathering, Transportation and Processing Expenses. Gathering, transportation and processing costs for the year ended December 31, 2021 increased by 5% to $81.0 million compared to $77.3 million for the same period of 2020, which was primarily related to new oil transportation agreements that were in place for the full year of 2021 as compared to a partial year in 2020, partially offset by a 6% decrease in production volumes between the two periods as discussed above. 
+47 
+Depreciation, Depletion and Amortization (“DD&A”). The following table sets forth the components of our depreciation, depletion and amortization for the periods indicated: 
+Years Ended December 31, 
+2021 2020 
+Amount Per Boe Amount Per Boe 
+(In thousands, except per Boe) 
+DD&A of evaluated oil and gas properties $347,199 $9.95 $471,074 $12.66 
+Depreciation of other property and equipment 1,950 0.06 3,548 0.10 
+Amortization of other assets 3,664 0.10 2,686 0.07 
+Accretion of asset retirement obligations 3,743 0.11 3,323 0.09 
+DD&A $356,556 $10.22 $480,631 $12.92 
+For the year ended December 31, 2021, DD&A decreased to $356.6 million from $480.6 million for the same period of 2020. The decrease in DD&A was primarily the result of the impairments of evaluated oil and gas properties that were recognized during 2020 as well as a production decrease of 6% as discussed above. 
+General and Administrative, Net of Amounts Capitalized (“G&A”). G&A for the year ended December 31, 2021 increased to $50.5 million compared to $37.2 million for the same period of 2020, primarily due to an increase in the fair value of Cash-Settled RSU Awards and Cash SARs as a result of the significant increase in our stock price between the two periods as well as higher compensation costs. 
+Impairment of Evaluated Oil and Gas Properties. We did not recognize an impairment of evaluated oil and gas properties for the year ended December 31, 2021. Impairments of evaluated oil and gas properties of $2.5 billion were recognized for the year ended December 31, 2020, primarily due to declines in the 12-Month Average Realized Price of crude oil. See “Note 5 - Property and Equipment, Net” of the Notes to our Consolidated Financial Statements for further discussion. 
+Merger, Integration and Transaction Expenses. For the year ended December 31, 2021, we incurred merger, integration and transaction expenses of $14.3 million, which were associated with the Primexx Acquisition, as compared to $28.5 million for 2020, which were related to the Carrizo Acquisition. See “Note 4 – Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for additional information regarding the Primexx Acquisition and the Carrizo Acquisition. 
+Other Income and Expenses 
+Interest Expense, Net of Capitalized Amounts. The following table sets forth the components of our interest expense, net of capitalized amounts for the periods indicated: 
+Years Ended December 31, 
+2021 2020 Change 
+(In thousands) 
+Interest expense on Senior Unsecured Notes $107,784 $120,313 ($12,529) 
+Interest expense on Second Lien Notes 43,791 9,188 34,603 
+Interest expense on Credit Facility 31,647 45,912 (14,265) 
+Amortization of debt issuance costs, premiums and discounts 18,309 7,325 10,984 
+Other interest expense 128 190 (62) 
+Capitalized interest (99,647) (88,599) (11,048) 
+Interest expense, net of capitalized amounts $102,012 $94,329 $7,683 
+Interest expense, net of capitalized amounts, incurred during the year ended December 31, 2021 increased $7.7 million to $102.0 million compared to $94.3 million for the same period of 2020. The increase is primarily due to the issuance of the Second Lien Notes at the end of the third quarter of 2020 as well as amortization of the discount associated with those Second Lien Notes. These increases were partially offset by the reduction in Senior Unsecured Notes outstanding as a result of the exchange of Senior Unsecured Notes for Second Lien Notes which occurred during the fourth quarter of 2020, lower borrowings on the Credit Facility, and an increase in capitalized interest. 
+48 
+(Gain) Loss on Derivative Contracts. The net (gain) loss on derivative contracts for the periods indicated includes the following: 
+Years Ended December 31, 
+2021 2020 Change 
+(In thousands) 
+(Gain) loss on oil derivatives $429,156 ($48,031) $477,187 
+(Gain) loss on natural gas derivatives 33,621 14,883 18,738 
+(Gain) loss on NGL derivatives 6,768 2,426 4,342 
+(Gain) loss on contingent consideration arrangements (2,635) 2,976 (5,611) 
+(Gain) loss on September 2020 Warrants liability 55,390 55,519 (129) 
+(Gain) loss on derivative contracts $522,300 $27,773 $494,527 
+See “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” of the Notes to our Consolidated Financial Statements for additional information. 
+(Gain) Loss on Extinguishment of Debt. During November 2021, in connection with the exchange of $197.0 million of our Second Lien Notes for 5.5 million shares of our common stock, we recorded a loss on extinguishment of debt of $43.4 million, which consisted of the notional amount of common stock issued less the aggregate principal amount of the Second Lien Notes exchanged, net of a pro-rata write-off of associated unamortized discount of $16.9 million and fees incurred. Additionally, during July 2021, we redeemed all of our 6.25% Senior Notes and recorded a gain on extinguishment of debt of $2.4 million, which was primarily related to writing off the remaining unamortized premium associated with the 6.25% Senior Notes. 
+During November 2020, in connection with the exchange of $389.0 million of our Senior Unsecured Notes for the Second Lien Notes, we recorded a gain on extinguishment of debt of $170.4 million, which consisted of the carrying values of the Senior Unsecured Notes exchanged less the aggregate principal amount of the Second Lien Notes issued, net of the associated debt discount of $9.1 million, which was based on the Second Lien Notes’ allocated fair value on the exchange date. 
+See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information. 
+Income Tax Expense. We recorded income tax expense of $0.2 million for the year ended December 31, 2021 compared to $122.1 million for the same period of 2020. Since the second quarter of 2020, we have concluded that it is more likely than not that the net deferred tax assets will not be realized and have recorded a full valuation allowance against our deferred tax assets, which still remained as of December 31, 2021. See “Note 12 – Income Taxes” of the Notes to our Consolidated Financial Statements for additional information regarding the valuation allowance. 
+Liquidity and Capital Resources 
+2022 Capital Budget and Funding Strategy. Our 2022 Capital Budget has been established at $725.0 million, with over 85% allocated towards development in the Permian with the balance towards development in the Eagle Ford. Because we are the operator of a high percentage of our properties, we can control the amount and timing of our capital expenditures. We plan to execute a moderated capital expenditure program through reduced reinvestment rates and balanced capital deployment for a more consistent cash flow generation and will be focused to further enhance our multi-zone, scaled development program to drive capital efficiency. See “Items 1 and 2. Business and Properties - Capital Budget” for additional details. 
+The following table is a summary of our 2021 capital expenditures (1) : 
+Three Months Ended Year Ended 
+March 31, 2021 June 30, 2021 September 30, 2021 December 31, 2021 December 31, 2021 
+(In millions) 
+Operational capital $95.6 $138.3 $115.0 $159.7 $508.6 
+Capitalized interest 24.0 23.9 26.1 25.6 99.6 
+Capitalized G&A 11.2 12.1 10.4 13.7 47.4 
+Total $130.8 $174.3 $151.5 $199.0 $655.6 
+(1) Capital expenditures, presented on an accrual basis, includes drilling, completions, facilities, and equipment, and excludes land, seismic, and asset retirement costs. 
+We believe that existing cash and cash equivalents, any positive cash flows from operations and available borrowings under our revolving credit facility will be sufficient to support working capital, capital expenditures and other cash requirements for at least the next 12 months and, based on our current expectations, for the foreseeable future thereafter. Our future capital requirements, both near-term and long-term, will depend on many factors, including, but not limited to, commodity prices, market conditions, our available liquidity and financing, acquisitions and divestitures of oil and gas properties, the availability of drilling rigs and completion crews, the cost of completion services, success of drilling programs, land and industry partner issues, weather delays, the acquisition 
+49 
+of leases with drilling commitments, and other factors. We regularly consider which resources, including debt and equity financings, are available to meet our future financial obligations, planned capital expenditures and liquidity requirements. 
+In addition, depending upon our actual and anticipated sources and uses of liquidity, prevailing market conditions and other factors, we may, from time to time, seek to retire or repurchase our outstanding debt or equity securities through cash purchases in the open market or through privately negotiated transactions or otherwise. The amounts involved in any such transactions, individually or in aggregate, may be material. During 2021, to help manage our future financing cash outflows and liquidity position, we completed the exchange of $197.0 million of aggregate principal amount of our 9.00% Second Lien Senior Secured Notes for 5.5 million shares of our common stock, which reduced the long-term debt balance in our consolidated balance sheets and also reduced future interest payments. 
+We may consider divesting certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth or enter into joint venture agreements, provided we are able to divest such assets or enter into joint venture agreements on terms that are acceptable to us. During 2021, we sold certain non-core assets in the Delaware Basin, Eagle Ford Shale and Midland Basin for combined net proceeds of $181.8 million, which were used to repay borrowings outstanding under the Credit Facility. 
+Overview of Cash Flow Activities. For the year ended December 31, 2021, cash and cash equivalents decreased $10.3 million to $9.9 million compared to $20.2 million at December 31, 2020. 
+Years Ended December 31, 
+2021 2020 
+(In thousands) 
+Net cash provided by operating activities $974,143 $559,775 
+Net cash used in investing activities (876,400) (529,883) 
+Net cash used in financing activities (108,097) (22,997) 
+Net change in cash and cash equivalents ($10,354) $6,895 
+Operating Activities. Net cash provided by operating activities was $974.1 million and $559.8 million for the years ended December 31, 2021 and 2020, respectively. The increase in operating activities was primarily attributable to the following: 
+• An increase in revenue due to an increase in realized pricing; and 
+• Changes related to timing of working capital payments and receipts; offset by 
+• Increase in cash paid for commodity derivative settlements. 
+Investing Activities. Net cash used in investing activities was $876.4 million and $529.9 million for the years ended December 31, 2021 and 2020, respectively. The increase in investing activities was primarily attributable to the following: 
+• A $480.8 million increase in acquisitions due to the Primexx acquisition; offset by 
+• A decrease in capital expenditures. 
+Financing Activities. For the year ended December 31, 2021, net cash used in financing activities was $108.1 million compared to $23.0 million during 2020. The increase in net cash used in financing activities was primarily attributable to the following: 
+• Redemption of the 6.25% Senior Notes in July 2021; and 
+• Repayments on the Credit Facility; offset by 
+• The issuance of $650.0 million of 8.00% Senior Notes in July 2021 
+Credit Facility. As of December 31, 2021, our Credit Facility had a maximum credit amount of $5.0 billion, a borrowing base and elected commitment amount of $1.6 billion, with borrowings outstanding of $785.0 million at a weighted-average interest rate of 2.65%, and letters of credit outstanding of $24.0 million. The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. On November 1, 2021, we entered into the fifth amendment to our credit agreement governing the Credit Facility which, among other things, reaffirmed the borrowing base and elected commitment amount of $1.6 billion as a result of the fall 2021 scheduled redetermination. 
+Our Credit Facility contains certain covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. Under the Credit Facility, we currently must maintain the following financial covenants determined as of the last day of the quarter: (1) commencing on March 31, 2020 and for each quarter ending on or prior to December 31, 2021, a Secured Leverage Ratio of no more than 3.00 to 1.00; (2) commencing March 31, 2022 and for each quarter ending thereafter, a Leverage Ratio of no more than 4.00 to 1.00; and (3) a Current Ratio of not less than 1.00 to 1.00. We were in compliance with these covenants at December 31, 2021. 
+50 
+Second Lien Note Exchange. On November 5, 2021, we closed on the agreement with Chambers Investments, LLC (“Kimmeridge”), a private investment vehicle managed by Kimmeridge Energy Management, LLC, to exchange $197.0 million of our outstanding Second Lien Notes, for a notional amount of approximately $223.1 million of our common stock, which equated to 5.5 million shares. 
+8.00% Senior Notes and Redemption of 6.25% Senior Notes. On July 6, 2021, we issued $650.0 million aggregate principal amount of 8.00% Senior Notes due 2028 in a private placement for proceeds of approximately $638.1 million, net of underwriting discounts and commissions and offering costs. The 8.00% Senior Notes mature on August 1, 2028 and interest is payable semi-annually each February 1 and August 1, commencing on February 1, 2022. On June 21, 2021, we delivered a redemption notice with respect to all $542.7 million of our outstanding 6.25% Senior Notes due 2023, which became redeemable on July 21, 2021. We used a portion of the net proceeds from the 8.00% Senior Notes to redeem all of our outstanding 6.25% Senior Notes and the remaining proceeds to partially repay amounts outstanding under the Credit Facility. 
+See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information on our long-term debt. 
+Material Cash Requirements 
+As of December 31, 2021, we have financial obligations associated with our outstanding long-term debt, including interest payments and principal repayments. See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for further discussion of the contractual commitments under our debt agreements, including the timing of principal repayments. Additionally, we have operational obligations associated with long-term, non-cancelable leases, drilling rig contracts, frac service contracts, gathering, processing and transportation service agreements, and estimates of future asset retirement obligations. See “Note 14 – Asset Retirement Obligations” and “Note 17 – Commitments and Contingencies” of the Notes to our Consolidated Financial Statements for additional details. 
+We estimate that the combination of our sources of capital, as discussed above, will continue to be adequate to fund our short- and long-term contractual obligations. 
+Other Commitments 
+The following table includes our current oil sales contracts and firm transportation agreements as of December 31, 2021: 
+Type of Commitment (1) 
+Region Execution Date Start Date End Date Committed 
+Volumes (Bbls/d) 
+Oil sales contract Permian October 2021 January 2022 December 2022 7,500 
+Oil sales contract Permian July 2019 August 2021 July 2026 5,000 
+Oil sales contract Permian June 2019 January 2020 December 2024 10,000 
+Oil sales contract Permian August 2018 April 2020 March 2022 15,000 
+Firm transportation agreement (2)(3) 
+Permian June 2019 August 2020 July 2030 10,000 
+Firm transportation agreement (2) 
+Permian August 2018 April 2020 March 2027 15,000 
+(1) For each of the commitments shown in the table above, the committed barrels may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. We expect to fulfill these delivery commitments with our existing production or through the purchases of third-party commodities. 
+(2) Each of the firm transportation agreements shown in the table above grant us access to delivery points in several locations along the Gulf Coast. 
+(3) The committed volumes shown in the table above for this particular firm transportation agreement are average volumes. For the terms of August 2020-July 2023, August 2023-July 2027 and August 2027-July 2030, the committed volumes are 7,500 Bbls/d, 10,000 Bbls/d and 12,500 Bbls/d, respectively. 
+Critical Accounting Estimates 
+For discussion regarding our significant accounting policies, see “Note 2 – Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements. 
+Use of Estimates 
+The preparation of financial statements in conformity with GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating DD&A of evaluated oil and natural gas property costs, the present value of estimated future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated timing of cash outflows underlying asset retirement obligations. There are numerous uncertainties inherent in the estimation of proved oil and gas reserves and in the projection of future rates of production and the timing of development expenditures. Other 
+51 
+significant estimates are involved in determining asset retirement obligations, acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of commodity derivative assets and liabilities, fair values of contingent consideration arrangements, grant date fair value of stock-based awards, and contingency, litigation, and environmental liabilities. Actual results could differ from those estimates. 
+Oil and Natural Gas Properties 
+Oil and natural gas properties are accounted for using the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration and development activities are capitalized as oil and gas properties. 
+Capitalized oil and gas property costs are amortized on an equivalent unit-of-production method whereby the depletion rate is computed on a quarterly basis by dividing current quarter production by estimated proved oil and gas reserves at the beginning of the quarter then applying such depletion rate to evaluated oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values. Each quarter, a full cost ceiling test is performed to determine whether an impairment to our evaluated oil and gas properties should be recorded. 
+The estimated future net revenues used in the cost center ceiling are calculated using the 12-Month Average Realized Price of oil, NGLs, and natural gas, held flat for the life of the production, except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of commodity derivative instruments as we elected not to meet the criteria to qualify for hedge accounting treatment. Details of the 12-Month Average Realized Price of crude oil for the years ended December 31, 2021, 2020, and 2019 as well as impairments of evaluated oil and natural gas properties are summarized in the table below: 
+Years Ended December 31, 
+2021 2020 2019 
+Impairment of evaluated oil and natural gas properties (In thousands) $— $2,547,241 $— 
+Beginning of period 12-Month Average Realized Price ($/Bbl) $37.44 $53.90 $58.40 
+End of period 12-Month Average Realized Price ($/Bbl) $65.44 $37.44 $53.90 
+Percent increase (decrease) in 12-Month Average Realized Price 75 % (31 %) (8 %) 
+The process of estimating proved oil and gas reserves requires that our independent and internal reserve engineers exercise judgment based on available geological, geophysical and technical information. Additionally, operating costs, production and ad valorem taxes, and future development costs are estimated based on current costs. A significant change to our estimated volumes of oil and gas reserves as well as changes to the estimates of prices and costs could have an impact on the depletion rate calculation as well as the estimated future net revenues used in the cost center ceiling. We have described the risks associated with reserve estimation and the volatility of oil and natural gas prices under Part I, “Item 1A. Risk Factors.” 
+52 
+The table below presents various pricing scenarios to demonstrate the sensitivity of our December 31, 2021 cost center ceiling to changes in 12-month average benchmark crude oil and natural gas prices underlying the 12-Month Average Realized Prices. The sensitivity analysis is as of December 31, 2021 and, accordingly, does not consider drilling and completion activity, acquisitions or dispositions of oil and gas properties, production, changes in crude oil and natural gas prices, and changes in development and operating costs occurring subsequent to December 31, 2021 that may require revisions to estimates of proved reserves. See also Part I, “Item 1A. Risk Factors—If oil and natural gas prices remain depressed for extended periods of time, we may be required to make significant downward adjustments to the carrying value of our oil and natural gas properties.” 
+12-Month Average 
+Realized Prices Excess (deficit) of cost center ceiling over net book value, less related deferred income taxes Increase (decrease) of cost center ceiling over net book value, less related deferred income taxes 
+Full Cost Pool Scenarios Crude Oil 
+($/Bbl) Natural Gas 
+($/Mcf) (In millions) (In millions) 
+December 31, 2021 Actual $65.44 $3.31 $2,905 
+Crude Oil and Natural Gas Price Sensitivity 
+Crude Oil and Natural Gas +10% $72.10 $3.68 $3,783 $878 
+Crude Oil and Natural Gas -10% $58.78 $2.95 $2,027 ($878) 
+Crude Oil Price Sensitivity 
+Crude Oil +10% $72.10 $3.31 $3,711 $806 
+Crude Oil -10% $58.78 $3.31 $2,099 ($806) 
+Natural Gas Price Sensitivity 
+Natural Gas +10% $65.44 $3.68 $2,977 $72 
+Natural Gas -10% $65.44 $2.95 $2,833 ($72) 
+Derivative Instruments 
+We use commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of our forecasted sales of production and achieve a more predictable level of cash flow. We do not use these instruments for speculative or trading purposes. Settlements of derivative contracts are generally based on the difference between the contract price and prices specified in the derivative instrument and a NYMEX price or other futures index price. The estimated fair value of our derivative contracts is based upon current forward market prices on NYMEX and in the case of collars and floors, the time value of options. For additional information regarding our derivatives instruments and their fair values, see “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” of the Notes to our Consolidated Financial Statements. 
+Our financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments as a result of the volatility of oil and gas prices. See “Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk - Commodity Price Risk” for the impact on the fair values of our derivative instruments assuming a 10% increase and decrease in the underlying forward oil and gas price curves as of December 31, 2021. 
+Income Taxes 
+The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. 
+Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that our net deferred tax assets will be utilized prior to their expiration. A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and a net deferred tax asset position at December 31, 2021, driven primarily by impairments of evaluated oil and gas properties recognized beginning in the second quarter of 2020 and continuing through the fourth quarter of 2020, which limits the ability to consider other subjective evidence such as our potential for future growth. Since the second quarter of 2020, based on the evaluation of the evidence available, we concluded that it is more likely than not that the net deferred tax assets will not be realized. As of December 31, 2021, a valuation allowance continues to be in place which reduces the net deferred tax assets to zero. 
+53 
+We will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until we can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead us to conclude that it is more likely than not our net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in crude oil prices, and taxable events that could result from one or more transactions. The valuation allowance does not preclude us from utilizing the tax attributes if we recognize taxable income. As long as we continue to conclude that the valuation allowance against our net deferred tax assets is necessary, we will have no significant deferred income tax expense or benefit. See “Note 12 - Income Taxes” of the Notes to our Consolidated Financial Statements for additional discussion. 
+Our ability to utilize our federal net operating losses (“NOLs”) to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of stock by 5% shareholders and the offering of stock by us during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of Callon. In the event of an ownership change, Section 382 of the Code (“Section 382”) imposes an annual limitation on the amount of our taxable income that can be offset by these carryforwards. The limitation is generally equal to the product of (i) the fair market value of the equity of Callon multiplied by (ii) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains inherent in the assets sold. Due to the issuance of common stock associated with the Carrizo Acquisition, we incurred a cumulative ownership change and as such, our NOLs prior to the acquisition are subject to an annual limitation under Section 382. 
+Recently Adopted and Recently Issued Accounting Pronouncements 
+See “Note 2 - Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements for information discussion of recent accounting pronouncements issued by the Financial Accounting Standards Board. 
+ITEM 7A. Quantitative and Qualitative Disclosures about Market Risk 
+We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer credit risk. We mitigate these risks through a program of risk management including the use of commodity derivative instruments. 
+Commodity Price Risk 
+Our revenues are derived from the sale of our oil, natural gas, and NGL production. The prices for oil, natural gas, and NGLs remain volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, government actions, economic conditions, and weather conditions. 
+From time to time, we enter into derivative financial instruments to manage oil, natural gas and NGL price risk, related both to NYMEX benchmark prices and regional basis differentials. The total volumes we hedge through use of our derivative instruments varies from period to period and takes into account our view of current and future market conditions in order to provide greater certainty of cash flows to meet our debt service costs and capital program. We generally hedge for the next 12 to 24 months, subject to the covenants under our Credit Facility. Our hedge policies and objectives may change significantly with movements in commodities prices or futures prices. 
+We may utilize fixed price swaps, which reduce our exposure to decreases in commodity prices, but limits the benefit we might otherwise have received from any increases in commodity prices. Swap contracts may also be enhanced by the simultaneous sale of call or put options to effectively increase the effective swap price as a result of the receipt of premiums from the option sales. 
+We also may utilize price collars to reduce the risk of changes in oil and natural gas prices. Under these arrangements, no payments are due by either party as long as the applicable market price is above the floor price (purchased put option) and below the ceiling price (sold call option) set in the collar. If the price falls below the floor, the counterparty to the collar pays the difference to us, and if the price rises above the ceiling, the counterparty receives the difference from us. Additionally, we may sell put options at a price lower than the floor price in conjunction with a collar (three-way collar) and use the proceeds to increase either or both the floor or ceiling prices. In a three-way collar, to the extent that realized prices are below the floor price of the sold put option (or above the ceiling price of the sold call option), our net realized benefit from the three-way collar will be reduced on a dollar-for-dollar basis. 
+We may purchase put options, which reduce our exposure to decreases in oil and natural gas prices while allowing realization of the full benefit from any increases in oil and natural gas prices. If the price falls below the floor, the counterparty pays the difference to us. 
+We enter into these various agreements from time to time to reduce the effects of volatile oil, natural gas and NGL prices and do not enter into derivative transactions for speculative or trading purposes. Presently, none of our derivative positions are designated as hedges for accounting purposes. 
+54 
+The following table sets forth the fair values as of December 31, 2021, excluding deferred premium obligations, as well as the impact on the fair values assuming a 10% increase and decrease in the underlying forward oil and gas price curves as of December 31, 2021: 
+Year Ended December 31, 2021 
+Oil Natural Gas NGLs Total 
+(In thousands) 
+Fair value (liability) asset as of December 31, 2021 (1) 
+($132,896) ($3,203) $890 ($135,209) 
+Impact of a 10% increase in forward commodity prices ($236,007) ($7,186) ($1,664) ($244,857) 
+Impact of a 10% decrease in forward commodity prices ($41,019) $666 $3,445 ($36,908) 
+(1) Spot prices for crude, natural gas and NGLs were $75.21, $3.73 and $39.13, respectively, as of December 31, 2021. 
+Interest Rate Risk 
+We are subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility. As of December 31, 2021, we had $785.0 million outstanding under the Credit Facility with a weighted average interest rate of 2.65%. An increase or decrease of 1.00% in the interest rate would have a corresponding increase or decrease in our annual interest expense of approximately $7.9 million, based on the balance outstanding as of December 31, 2021. See “Note 7 - Borrowings” of the Notes to our Consolidated Financial Statements for more information on our Credit Facility. 
+Counterparty and Customer Credit Risk 
+Our principal exposures to credit risk are through receivables from the sale of our oil, natural gas and NGL production, joint interest receivables and receivables resulting from derivative financial contracts. 
+For the year ended December 31, 2021, four purchasers each accounted for more than 10% of our revenue. The inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In order to mitigate potential exposure to credit risk, we may require from time to time for our customers to provide financial security. We are generally paid by our purchasers within 30 to 90 days after the month of production and currently do not believe that we have a risk of not collecting. 
+Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have or intend to drill. We have little ability to control whether these entities will participate in our wells. We generally have the right to withhold future revenue distributions to recover past due receivables from joint interest owners. 
+See “Note 8 - Derivative Instruments and Hedging Activities” of the Notes to our Consolidated Financial Statements for discussion of counterparty credit risk associated with our commodity derivative arrangements. 
+55 
+ITEM 8. Financial Statements and Supplementary Data 
+Page 
+Reports of Independent Registered Public Accounting Firm (PCAOB ID Number 248 ) 
+57 
+Consolidated Balance Sheets as of December 31, 2021 and 2020 
+61 
+Consolidated Statements of Operations for the Years Ended December 31, 2021, 2020 and 2019 
+62 
+Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2021, 2020 and 2019 
+63 
+Consolidated Statements of Cash Flows for the Years Ended December 31, 2021, 2020 and 2019 
+64 
+Notes to Consolidated Financial Statements 
+65 
+56 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+Board of Directors and Shareholders 
+Callon Petroleum Company 
+Opinion on the financial statements 
+We have audited the accompanying consolidated balance sheets of Callon Petroleum Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2021 and 2020, the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2021, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 24, 2022 expressed an unqualified opinion. 
+Basis for opinion 
+These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. 
+Critical audit matters 
+The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. 
+The development of estimated proved reserves used in the calculation of depletion, depreciation and amortization expense and evaluation for impairment under the full cost method of accounting 
+As described further in Note 2 to the financial statements, the Company accounts for its oil and gas properties using the full cost method of accounting which requires management to make estimates of proved reserve volumes and future net revenues to record depletion expense and assess its oil and gas properties for potential impairment. To estimate the volume of proved reserves and future net revenue, management makes significant estimates and assumptions including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected with reasonable certainty to be economical under the appropriate pricing assumptions required in the estimation of depletion expense and potential impairment assessment. We identified the estimation of proved reserves of oil and gas properties as a critical audit matter. 
+The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain inputs and assumptions necessary to estimate the volumes and future net revenues of the Company’s proved reserves require a high degree of subjectivity and could have a significant impact on the measurement of depletion expense and potential impairment. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment. 
+Our audit procedures related to the estimation of proved reserves included the following, among others. 
+57 
+• We tested the design and operating effectiveness of controls relating to management’s estimation of proved reserves for the purpose of estimating depletion expense and assessing the Company’s oil and gas properties for potential impairment. 
+• We evaluated the independence, objectivity, and professional qualifications of the Company’s reserve engineers, made inquiries of those specialists regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the reserve report prepared by the Company’s specialists. 
+• To the extent key inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, including, but not limited to historical pricing differentials, operating costs, estimated development costs, and ownership interests, we tested management’s process for determining the assumptions, including examining the underlying support on a sample basis. Specifically, our audit procedures involved testing management’s assumptions by performing the following: 
+◦ We compared the estimated pricing differentials used in the reserve report to prices realized by the Company related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials 
+◦ We tested models used to estimate the future operating costs in the reserve report and compared amounts to historical operating costs 
+◦ We evaluated the method used to determine estimated future development costs used in the reserve report and compared management’s estimate to amounts expended for recently drilled and completed wells to ascertain its reasonableness 
+◦ We tested the working and net revenue interests used in the reserve report by inspecting land and division order records 
+◦ We evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s ability and intent to develop the proved undeveloped properties, and 
+◦ We applied analytical procedures to production forecasts in the reserve report by comparing to historical actual results and to the prior year reserve report. 
+Estimate of the fair value of oil and gas properties and related proved and unproved reserves associated with the Primexx Acquisition 
+As described further in Note 4 to the financial statements, the Company acquired certain producing oil & natural gas assets and undeveloped acreage from Primexx Resource Development, LLC and BPP Acquisition, LLC (collectively, “Primexx,” the “Primexx Acquisition”), which required management to make estimates of the fair value associated with proved and unproved reserves and related discounted net cash flows. To estimate the volumes of proved and unproved reserves and the associated discounted net cash flows, management makes significant estimates and assumptions including forecasting the production decline rate of proved and unproved properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped and unproved properties. In addition, the estimation of proved and unproved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved and unproved reserves to determine if wells are expected with reasonable certainty to be economical under the appropriate pricing assumptions required in the estimation of fair value. Significant inputs to the estimate of proved and unproved reserves include estimates of future production volumes, future operating and development costs, future commodity prices and a weighted average cost of capital rate. The estimates of proved and unproved reserves have been developed by specialists, specifically reservoir engineers (referred to as management’s specialists). We identified the estimation of proved and unproved reserves oil and gas properties acquired as a critical audit matter. 
+The principal consideration for our determination that the estimation of proved and unproved reserves is a critical audit matter is that changes in certain inputs and assumptions necessary to estimate the volume and future discounted cash flows of the Company’s proved and unproved reserves require a high degree of subjectivity and could have a significant impact on the measurement of fair value. In turn, auditing those inputs and assumptions required subjective and complex audit judgment. 
+Our audit procedures related to the estimation of proved and unproved reserves included the following, among others. 
+• We tested the design and operating effectiveness of controls relating to management’s estimation of proved and unproved reserves acquired for the purpose of estimating fair value. 
+• We evaluated the independence, objectivity, and professional qualifications of the Company’s reserve engineers, made inquiries of those specialists regarding the process followed and judgments made to estimate the Company’s proved and unproved reserve volumes, and read the reserve report prepared by those specialists. 
+• We evaluated the independence, objectivity, and professional qualifications of the Company’s external valuation specialists, made inquiries of those valuation specialists regarding the process followed and judgements made to determine the fair value associated with proved and unproved reserve volumes, utilized our valuation specialists to assist in evaluating the appropriateness of the inputs and methodology used in the cash flow model (including future commodity prices and weighted average cost of capital), and read the valuation report prepared by the external specialists. 
+• To the extent key sensitive inputs and assumptions used to determine proved and unproved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records or other seller provided information, including, but not limited to historical pricing differentials, operating costs, estimated development costs, and ownership 
+58 
+interests, we tested management’s process for determining the assumptions, including examining the underlying support on a sample basis. Specifically, our audit procedures involved testing management’s assumptions by performing the following: 
+◦ We compared the estimated pricing differentials used in the reserve report to historical prices realized by Primexx 
+◦ We tested models used to estimate the future operating costs in the acquisition reserve report and compared amounts to historical operating costs 
+◦ We evaluated the method used to determine estimated future development costs used in the reserve report and compared management’s estimate to amounts expended for recently drilled and completed wells 
+◦ We tested the working and net revenue interests used in the reserve report by inspecting land and division order records 
+◦ We evaluated the risk adjustments applied to proved and unproved reserve volumes by comparing against industry accepted factors 
+◦ We evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report examining historical conversion rates and support for the Company’s ability and intent to develop the proved undeveloped and unproved properties; and 
+◦ We applied analytical procedures to production forecasts in the reserve report by comparing to historical actual results, and to the prior year reserve report. 
+/s/ GRANT THORNTON LLP 
+We have served as the Company’s auditor since 2016. 
+Houston, Texas 
+February 24, 2022 
+59 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+Board of Directors and Shareholders 
+Callon Petroleum Company 
+Opinion on internal control over financial reporting 
+We have audited the internal control over financial reporting of Callon Petroleum Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2021, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2021, and our report dated February 24, 2022 expressed an unqualified opinion on those financial statements. 
+Basis for opinion 
+The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s report. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+Definition and limitations of internal control over financial reporting 
+A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+/s/ GRANT THORNTON LLP 
+Houston, Texas 
+February 24, 2022 
+60 
+Callon Petroleum Company 
+Consolidated Balance Sheets 
+(In thousands, except par and share amounts) 
+December 31, 
+2021 2020 
+ASSETS 
+Current assets: 
+Cash and cash equivalents $ 9,882 $ 20,236 
+Accounts receivable, net 232,436 133,109 
+Fair value of derivatives 22,381 921 
+Other current assets 30,745 24,103 
+Total current assets 295,444 178,369 
+Oil and natural gas properties, full cost accounting method: 
+Evaluated properties, net 3,352,821 2,355,710 
+Unevaluated properties 1,812,827 1,733,250 
+Total oil and natural gas properties, net 5,165,648 4,088,960 
+Other property and equipment, net 28,128 31,640 
+Deferred financing costs 18,125 23,643 
+Other assets, net 40,158 40,256 
+Total assets $ 5,547,503 $ 4,362,868 
+LIABILITIES AND STOCKHOLDERS’ EQUITY 
+Current liabilities: 
+Accounts payable and accrued liabilities $ 569,991 $ 341,519 
+Fair value of derivatives 185,977 97,060 
+Other current liabilities 116,523 58,529 
+Total current liabilities 872,491 497,108 
+Long-term debt 2,694,115 2,969,264 
+Asset retirement obligations 54,458 57,209 
+Fair value of derivatives 11,409 88,046 
+Other long-term liabilities 49,262 40,239 
+Total liabilities 3,681,735 3,651,866 
+Commitments and contingencies 
+Stockholders’ equity: 
+Common stock, $ 0.01 par value, 78,750,000 and 52,500,000 shares authorized; 
+61,370,684 and 39,758,817 shares outstanding, respectively 
+614 398 
+Capital in excess of par value 4,012,358 3,222,959 
+Accumulated deficit ( 2,147,204 ) ( 2,512,355 ) 
+Total stockholders’ equity 1,865,768 711,002 
+Total liabilities and stockholders’ equity $ 5,547,503 $ 4,362,868 
+The accompanying notes are an integral part of these consolidated financial statements. 
+61 
+Callon Petroleum Company 
+Consolidated Statements of Operations 
+(In thousands, except per share amounts) 
+For the Year Ended December 31, 
+2021 2020 2019 
+Operating Revenues: 
+Oil $ 1,516,225 $ 850,667 $ 633,107 
+Natural gas 141,493 51,866 36,390 
+Natural gas liquids 193,861 81,295 2,075 
+Sales of purchased oil and gas 193,451 49,319 — 
+Total operating revenues 2,045,030 1,033,147 671,572 
+Operating Expenses: 
+Lease operating 203,141 194,101 91,827 
+Production and ad valorem taxes 100,160 62,638 42,651 
+Gathering, transportation and processing 80,970 77,309 — 
+Cost of purchased oil and gas 201,088 51,766 — 
+Depreciation, depletion and amortization 356,556 480,631 240,642 
+General and administrative 50,483 37,187 45,331 
+Impairment of evaluated oil and gas properties — 2,547,241 — 
+Merger, integration and transaction 14,289 28,482 74,363 
+Other operating 3,366 10,644 4,100 
+Total operating expenses 1,010,053 3,489,999 498,914 
+Income (Loss) From Operations 1,034,977 ( 2,456,852 ) 172,658 
+Other (Income) Expenses: 
+Interest expense, net of capitalized amounts 102,012 94,329 2,907 
+Loss on derivative contracts 522,300 27,773 62,109 
+(Gain) loss on extinguishment of debt 41,040 ( 170,370 ) 4,881 
+Other (income) expense 4,294 2,983 ( 468 ) 
+Total other (income) expense 669,646 ( 45,285 ) 69,429 
+Income (Loss) Before Income Taxes 365,331 ( 2,411,567 ) 103,229 
+Income tax expense ( 180 ) ( 122,054 ) ( 35,301 ) 
+Net Income (Loss) $ 365,151 ($ 2,533,621 ) $ 67,928 
+Preferred stock dividends — — ( 3,997 ) 
+Loss on redemption of preferred stock — — ( 8,304 ) 
+Income (Loss) Available to Common Stockholders $ 365,151 ($ 2,533,621 ) $ 55,627 
+Income (Loss) Available to Common Stockholders 
+Per Common Share: 
+Basic $ 7.51 ($ 63.79 ) $ 2.39 
+Diluted $ 7.26 ($ 63.79 ) $ 2.38 
+Weighted Average Common Shares Outstanding: 
+Basic 48,612 39,718 23,313 
+Diluted 50,311 39,718 23,340 
+The accompanying notes are an integral part of these consolidated financial statements. 
+62 
+Callon Petroleum Company 
+Consolidated Statements of Stockholders’ Equity 
+(In thousands) 
+Retained 
+Preferred Common Capital in Earnings Total 
+Stock Stock Excess (Accumulated Stockholders’ 
+Shares $ Shares $ of Par Deficit) Equity 
+Balance at 12/31/2018 1,459 $ 15 22,757 $ 2,276 $ 2,477,278 ($ 34,361 ) $ 2,445,208 
+Net income — — — — — 67,928 67,928 
+Shares issued pursuant to employee benefit plans — — 2 — 154 — 154 
+Restricted stock — — 79 8 11,622 — 11,630 
+Common stock issued for Carrizo Acquisition — — 16,821 1,682 763,691 — 765,373 
+Common stock warrants reissued in conjunction with Carrizo Acquisition — — — — 10,029 — 10,029 
+Preferred stock dividend — — — — — ( 3,997 ) ( 3,997 ) 
+Preferred stock redemption ( 1,459 ) ( 15 ) — — ( 64,698 ) — ( 64,713 ) 
+Loss on redemption of preferred stock — — — — — ( 8,304 ) ( 8,304 ) 
+Balance at 12/31/2019 — $ — 39,659 $ 3,966 $ 3,198,076 $ 21,266 $ 3,223,308 
+Net loss — — — — — ( 2,533,621 ) ( 2,533,621 ) 
+Restricted stock — — 100 10 12,213 — 12,223 
+Reverse stock split — — — ( 3,578 ) 3,578 — — 
+Issuance of common stock warrants — — — — 9,109 — 9,109 
+Other — — — — ( 17 ) — ( 17 ) 
+Balance at 12/31/2020 — $ — 39,759 $ 398 $ 3,222,959 ($ 2,512,355 ) $ 711,002 
+Net income — — — — — 365,151 365,151 
+Restricted stock — — 156 2 10,949 — 10,951 
+Warrant exercises — — 6,913 69 134,748 — 134,817 
+Common stock issued for Primexx Acquisition — — 9,030 90 420,610 — 420,700 
+Common stock issued for Second Lien Notes Exchange — — 5,513 55 223,092 — 223,147 
+Balance at 12/31/2021 — $ — 61,371 $ 614 $ 4,012,358 ($ 2,147,204 ) $ 1,865,768 
+The accompanying notes are an integral part of these consolidated financial statements. 
+63 
+Callon Petroleum Company 
+Consolidated Statements of Cash Flows 
+(In thousands) 
+Years Ended December 31, 
+2021 2020 2019 
+Cash flows from operating activities: 
+Net income (loss) $ 365,151 ($ 2,533,621 ) $ 67,928 
+Adjustments to reconcile net income (loss) to net cash provided by operating activities: 
+Depreciation, depletion and amortization 356,556 480,631 245,936 
+Impairment of evaluated oil and gas properties — 2,547,241 — 
+Amortization of non-cash debt related items, net 10,124 3,901 2,907 
+Deferred income tax expense — 118,607 35,301 
+Loss on derivative contracts 522,300 27,773 62,109 
+Cash received (paid) for commodity derivative settlements, net ( 395,097 ) 98,870 ( 3,789 ) 
+(Gain) loss on extinguishment of debt 41,040 ( 170,370 ) 4,881 
+Non-cash expense related to share-based awards 12,923 2,663 11,391 
+Other, net 11,037 7,087 ( 1,515 ) 
+Changes in current assets and liabilities: 
+Accounts receivable ( 86,402 ) 75,770 ( 35,071 ) 
+Other current assets ( 10,399 ) ( 6,550 ) ( 4,166 ) 
+Accounts payable and accrued liabilities 146,910 ( 92,227 ) 82,290 
+Other, net — — 8,114 
+Net cash provided by operating activities 974,143 559,775 476,316 
+Cash flows from investing activities: 
+Capital expenditures ( 578,487 ) ( 664,231 ) ( 640,540 ) 
+Acquisition of oil and gas properties ( 493,732 ) ( 12,923 ) ( 42,266 ) 
+Proceeds from sales of assets 188,101 178,970 294,417 
+Cash paid for settlements of contingent consideration arrangements, net — ( 40,000 ) — 
+Other, net 7,718 8,301 — 
+Net cash used in investing activities ( 876,400 ) ( 529,883 ) ( 388,389 ) 
+Cash flows from financing activities: 
+Borrowings on Credit Facility 2,140,500 5,353,000 2,455,900 
+Payments on Credit Facility ( 2,340,500 ) ( 5,653,000 ) ( 895,500 ) 
+Issuance of 8.00 % Senior Notes due 2028 
+650,000 — — 
+Redemption of 6.25 % Senior Notes 
+( 542,755 ) — — 
+Issuance of 9.00 % Second Lien Senior Secured Notes due 2025 
+— 300,000 — 
+Discount on the issuance of 9.00 % Second Lien Senior Secured Notes due 2025 
+— ( 35,270 ) — 
+Issuance of September 2020 Warrants — 23,909 — 
+Payment to terminate Prior Credit Facility — — ( 475,400 ) 
+Repayment of Carrizo’s senior secured revolving credit facility — — ( 853,549 ) 
+Repayment of Carrizo’s preferred stock — — ( 220,399 ) 
+Payment of preferred stock dividends — — ( 3,997 ) 
+Payment of deferred financing and debt exchange costs ( 12,672 ) ( 10,811 ) ( 22,480 ) 
+Tax withholdings related to restricted stock units ( 2,280 ) ( 509 ) ( 2,195 ) 
+Redemption of preferred stock — — ( 73,017 ) 
+Other, net ( 390 ) ( 316 ) — 
+Net cash used in financing activities ( 108,097 ) ( 22,997 ) ( 90,637 ) 
+Net change in cash and cash equivalents ( 10,354 ) 6,895 ( 2,710 ) 
+Balance, beginning of period 20,236 13,341 16,051 
+Balance, end of period $ 9,882 $ 20,236 $ 13,341 
+The accompanying notes are an integral part of these consolidated financial statements. 
+64 
+INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+1. 
+Description of Business 
+10. 
+Share-Based Compensation 
+2. 
+Summary of Significant Accounting Policies 
+11. 
+Stockholders’ Equity 
+3. 
+Revenue Recognition 
+12. 
+Income Taxes 
+4. 
+Acquisitions and Divestitures 
+13. 
+Leases 
+5. 
+Property and Equipment, Net 
+14. 
+Asset Retirement Obligations 
+6. 
+Earnings Per Share 
+15. 
+Accounts Receivable , Net 
+7. 
+Borrowings 
+16. 
+Accounts Payable and Accrued Liabilities 
+8. 
+Derivative Instruments and Hedging Activities 
+17. 
+Commitments and Contingencies 
+9. 
+Fair Value Measurements 
+18. 
+Supplemental Information on Oil and Natural Gas Operations (Unaudited) 
+Note 1 – Description of Business 
+Callon Petroleum Company is an independent oil and natural gas company focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. 
+The Company’s activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger Permian Basin in West Texas, as well as the Eagle Ford in South Texas. The Company’s primary operations in the Permian reflect a high-return, oil-weighted drilling inventory with multiple prospective horizontal development intervals and are complemented by a well-established and repeatable cash flow-generating business in the Eagle Ford. 
+Note 2 – Summary of Significant Accounting Policies 
+Basis of Presentation and Principles of Consolidation 
+The consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and are presented in accordance with U.S. GAAP. The Company proportionately consolidates its undivided interests in oil and gas properties as well as investments in unincorporated entities, such as partnerships and limited liability companies where the Company, as a partner or member, has undivided interests in the oil and gas properties. In the opinion of management, the accompanying audited consolidated financial statements reflect all adjustments, including normal recurring adjustments, necessary to present fairly the Company’s financial position, results of its operations and cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation. Such reclassifications did not have a material impact on prior period financial statements. The Company evaluates events subsequent to the balance sheet date through the date the financial statements are issued. 
+Use of Estimates 
+The preparation of financial statements in conformity with U.S. GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating depreciation, depletion and amortization (“DD&A”) of evaluated oil and gas property costs, the present value of estimated future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated timing of cash outflows underlying asset retirement obligations. There are numerous uncertainties inherent in the estimation of proved oil and gas reserves and in the projection of future rates of production and the timing of development expenditures. Other significant estimates are involved in determining asset retirement obligations, acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of commodity derivative assets and liabilities, fair values of contingent consideration arrangements, fair value of second lien notes upon issuance, grant date fair value of stock-based awards, and contingency, litigation, and environmental liabilities. Actual results could differ from those estimates. 
+Cash and Cash Equivalents 
+The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. 
+Accounts Receivable, Net 
+Accounts receivable, net consists primarily of receivables from oil, natural gas, and NGL purchasers and joint interest owners in properties the Company operates. The Company generally has the right to withhold future revenue distributions to recover past due receivables from joint interest owners. Generally, the Company’s oil, natural gas, and NGL receivables are collected within 30 to 90 days. The Company’s allowance for credit losses and bad debt expense was immaterial for all periods presented. 
+65 
+Concentration of Credit Risk and Major Customers 
+The concentration of accounts receivable from entities in the oil and gas industry may impact the Company’s overall credit risk such that these entities may be similarly affected by changes in economic and other industry conditions. The Company does not believe the loss of any one of its purchasers would materially affect its ability to sell the oil and gas it produces as other purchasers are available in its primary areas of activity. The Company had the following major customers that represented 10% or more of its total revenues for at least one of the periods presented: 
+Years Ended December 31, 
+2021 2020 2019 
+Shell Trading Company 20 % 31 % 10 % 
+Trafigura Trading, LLC 15 * * 
+Occidental Energy Marketing, Inc. 13 * * 
+Valero Marketing and Supply Company 13 23 * 
+Rio Energy International, Inc. * * 26 
+Enterprise Crude Oil, LLC * * 19 
+Plains Marketing, L.P. * * 15 
+* - Less than 10% for the applicable year. 
+See “Note 8 - Derivative Instruments and Hedging Activities” for discussion of credit risk related with the Company’s commodity derivative counterparties. 
+Oil and Natural Gas Properties 
+The Company uses the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration, and development activities are capitalized as oil and gas properties. Internal costs that are directly related to acquisition, exploration, and development activities, including salaries, benefits, and stock-based compensation, are capitalized to either evaluated or unevaluated oil and gas properties based on the type of activity. Internal costs related to production and similar activities are expensed as incurred. 
+Proceeds from divestitures of evaluated and unevaluated oil and natural gas properties are accounted for as a reduction of evaluated oil and gas property costs unless the sale significantly alters the relationship between capitalized costs and estimated proved reserves, in which case a gain or loss is recognized. For the years ended December 31, 2021, 2020 and 2019, the Company did not have any sales of oil and gas properties that significantly altered such relationship. 
+From time to time, the Company exchanges undeveloped acreage with third parties. The exchanges are recorded at fair value and the difference is accounted for as an adjustment of capitalized costs with no gain or loss recognized pursuant to the rules governing full cost accounting, unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas. 
+Capitalized oil and gas property costs are amortized on an equivalent unit-of-production method, converting natural gas to barrels of oil equivalent at the ratio of six thousand cubic feet of gas to one barrel of oil, which represents their approximate relative energy content. The equivalent unit-of-production depletion rate is computed on a quarterly basis by dividing current quarter production by estimated proved oil and gas reserves at the beginning of the quarter then applying such depletion rate to evaluated oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values. 
+Excluded from this amortization are costs associated with unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. Unevaluated property costs are transferred to evaluated property costs when the proved reserves have been assigned to the properties or the Company determines that these costs have been impaired. The Company assesses properties on an individual basis or as a group and considers the following factors, among others, to determine if these costs have been impaired: exploration program and intent to drill, remaining lease term, and the assignment of proved reserves. Geological and geophysical costs not associated with specific prospects are recorded to evaluated oil and gas property costs as incurred. The amount of interest costs capitalized is determined on a quarterly basis based on the average balance of unevaluated properties and the weighted average interest rate of outstanding borrowings. 
+Under full cost accounting rules, the Company reviews the net book value of its oil and gas properties each quarter. Under these rules, the net book value of oil and gas properties, less related deferred income taxes, are limited to the “cost center ceiling” equal to (i) the sum of (a) the present value of estimated future net revenues from estimated proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the estimated proved oil and gas reserves computed using a discount factor of 10 %, (b) the costs of unevaluated properties not being amortized, and (c) the lower of cost or estimated fair value of unevaluated properties included in the costs being amortized; less (ii) related income tax effects. Any excess of the net book value of oil and gas 
+66 
+properties, less related deferred income taxes, over the cost center ceiling is recognized as an impairment of evaluated oil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even if higher commodity prices in the future result in a cost center ceiling in excess of the net book value of oil and gas properties, less related deferred income taxes. 
+The estimated future net revenues used in the cost center ceiling are calculated using the 12-Month Average Realized Price of oil, NGLs, and natural gas, held flat for the life of the production, except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of commodity derivative instruments as the Company elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. The Company did no t recognize impairments of evaluated oil and gas properties for the years ended December 31, 2021 and 2019. Primarily as a result of a 31 % decrease in the 12-Month Average Realized Price of oil, the Company recognized impairments of evaluated oil and gas properties of $ 2.5 billion for the year ended December 31, 2020. 
+Depreciation of other property and equipment is recognized using the straight-line method based on estimated useful lives ranging from two to twenty years . 
+Deferred Financing Costs 
+Deferred financing costs associated with the Second Lien Notes and the Unsecured Senior Notes, both defined below, are classified as a reduction of the related carrying value on the consolidated balance sheets and are amortized to interest expense using the effective interest method over the terms of the related debt. Deferred financing costs associated with the Credit Facility, as defined below, are classified in “Other long-term assets” in the consolidated balance sheets and are amortized to interest expense using the straight-line method over the term of the facility. 
+Asset Retirement Obligations 
+The Company records an estimate of the fair value of liabilities for obligations associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Estimates involved in determining asset retirement obligations include the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a credit-adjusted risk-free discount rate and an inflation factor in order to determine the present value of the asset retirement obligation. The present value of the asset retirement obligations is accreted each period and the increase to the obligation is reported in “Depreciation, depletion and amortization” in the consolidated statements of operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to evaluated oil and gas properties in the consolidated balance sheets. See “Note 14 - Asset Retirement Obligations” for additional information. 
+Derivative Instruments 
+The Company uses commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of its forecasted sales of production and achieve a more predictable level of cash flow. The Company does not enter into commodity derivative instruments for speculative or trading purposes. All commodity derivative instruments are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. The Company nets its commodity derivative instrument fair value amounts executed with the same counterparty to a single asset or liability pursuant to International Swap Dealers Association Master Agreements (“ISDA Agreements”), which provide for net settlement over the term of the contract and in the event of default or termination of the contract. 
+Settlements of the Company’s commodity derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets. See “Note 9 - Fair Value Measurements” for additional information regarding fair value. 
+The Company is also party to contingent consideration arrangements that include obligations to pay or rights to receive additional consideration if commodity prices exceed specified thresholds during certain periods in the future. These contingent consideration assets and liabilities are required to be bifurcated and accounted for separately as derivative instruments as they are not considered to be clearly and closely related to the host contract, and recognized at their acquisition or divestiture date fair value in the consolidated balance sheets. 
+The Company has elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. As such, all gains and losses as a result of changes in the fair value of commodity derivative instruments, as well as its contingent consideration arrangements, are recognized as “(Gain) loss on derivative contracts” in the consolidated statements of operations in the period in which the changes occur. See “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” for further discussion. 
+67 
+Revenue Recognition 
+The Company recognizes revenues from the sales of oil, natural gas, and NGLs to its customers and presents them disaggregated on the Company’s consolidated statements of operations. Revenue is recognized at the point in time when control of the product transfers to the customer. 
+For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. 
+The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. See “Note 3 - Revenue Recognition” for further discussion. 
+Income Taxes 
+Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are recognized at the end of each reporting period for the future tax consequences of cumulative temporary differences between the tax basis of assets and liabilities and their reported amounts in the Company’s consolidated financial statements based on existing tax laws and enacted statutory tax rates applicable to the periods in which the temporary differences are expected to affect taxable income. U.S. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards and tax credit carryforwards. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering all available evidence (both positive and negative) to determine whether it is more likely than not that all or a portion of the deferred tax assets will not be realized and a valuation allowance is required. See “Note 12 - Income Taxes” for further discussion. 
+Share-Based Compensation 
+The Company grants restricted stock unit awards that may be settled in common stock (“RSU Equity Awards”) or cash (“Cash-Settled RSU Awards”), some of which are subject to achievement of certain performance conditions. Share-based compensation expense is recognized as “General and administrative expense” in the consolidated statements of operations. The Company accounts for forfeitures of equity-based incentive awards as they occur. See “Note 10 - Share-Based Compensation” for further details of the awards discussed below. 
+RSU Equity Awards and Cash-Settled RSU Awards. Share-based compensation expense for RSU Equity Awards is based on the grant-date fair value and recognized over the vesting period (generally three years for employees and one year for non-employee directors) using the straight-line method. For RSU Equity Awards with vesting terms subject to a performance condition, share-based compensation expense is based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model with the estimated value recognized over the vesting period (generally three years ). Cash-Settled RSU Awards subject to a performance condition that the Company expects or is required to settle in cash, are accounted for as liabilities with share-based compensation expense based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model, with the estimated fair value recognized over the vesting period (generally three years ). 
+Cash SARs. Stock appreciation rights to be settled in cash (“Cash SARs”) are remeasured at fair value at the end of each reporting period with the change in fair value recorded as share-based compensation expense. The liability for Cash SARs is classified as “Other current liabilities” in the consolidated balance sheets as all outstanding awards are vested. The Cash SARs outstanding will expire between one year and five years , depending on the date of grant. 
+68 
+Supplemental Cash Flow Information 
+The following table sets forth supplemental cash flow information for the periods indicated: 
+Years Ended December 31, 
+2021 2020 2019 
+(In thousands) 
+Interest paid, net of capitalized amounts $ 85,042 $ 91,269 $ — 
+Income taxes paid (1) 
+— — — 
+Cash paid for amounts included in the measurement of lease liabilities: 
+Operating cash flows from operating leases $ 26,681 $ 44,314 $ 3,414 
+Investing cash flows from operating leases 18,598 24,234 32,529 
+Non-cash investing and financing activities: 
+Change in accrued capital expenditures $ 63,444 ($ 64,465 ) ($ 31,475 ) 
+Change in asset retirement costs 2,905 8,605 13,559 
+Contingent consideration arrangement — — 8,512 
+ROU assets obtained in exchange for lease liabilities: 
+Operating leases $ 24,301 $ 8,070 $ 66,914 
+Financing leases — — 2,197 
+(1) The Company did no t pay any federal income tax for any of the years in the three year period ending December 31, 2021. 
+Earnings per Share 
+The Company’s basic net income (loss) attributable to common shareholders per common share is based on the weighted average number of shares of common stock outstanding for the period. Diluted net income (loss) attributable to common shareholders per common share is calculated using the treasury stock method and is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the year which include RSU Equity Awards and common stock warrants. When a loss attributable to common shareholders per common share exists, all potentially dilutive common shares outstanding are anti-dilutive and therefore excluded from the calculation of diluted weighted average shares outstanding. See “Note 6 - Earnings Per Share” for further discussion. 
+Industry Segment and Geographic Information 
+The Company operates in one industry segment, which is the exploration, development, and production of crude oil, natural gas, and NGLs. All of the Company’s operations are located in the United States and currently all revenues are attributable to customers located in the United States. 
+Recently Adopted Accounting Standards 
+Income Taxes. In December 2019, the FASB released ASU No. 2019-12 (“ASU 2019-12”), Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes, which removes certain exceptions for recognizing deferred taxes for investments, performing intraperiod allocation and calculating income taxes in interim periods. The ASU also adds guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of a consolidated group. The amended standard is effective for fiscal years beginning after December 15, 2020, with early adoption permitted. The Company adopted ASU 2019-12 on January 1, 2021. The adoption of ASU 2019-12 did not have a material impact to the Company’s consolidated financial statements or disclosures. 
+Credit Losses. In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, followed by other related ASUs that provided targeted improvements (collectively “ASU 2016-13”). ASU 2016-13 provides financial statement users with more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. The guidance is to be applied using a modified retrospective method and is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. The Company adopted ASU 2016-13 on January 1, 2020. The adoption of ASU 2016-13 did not have a material impact to the Company’s consolidated financial statements or disclosures. 
+Recently Issued Accounting Standards 
+In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”) followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021 to provide clarifying guidance regarding the scope of Topic 848. ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) 
+69 
+reference rate reform on financial reporting. Generally, the guidance is to be applied as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. ASU 2020-04 and ASU 2021-01 are effective for all entities through December 31, 2022. As of December 31, 2021, the Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and ASU 2021-01. Please refer to “Note 7 – Borrowings” for discussion of the use of the adjusted LIBO rate in connection with borrowings under the Credit Facility. 
+In August 2020, the FASB issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40) (“ASU 2020-06”). ASU 2020-06 was issued to reduce the complexity associated with accounting for certain financial instruments with characteristics of liabilities and equity. The guidance is to be applied using either a modified retrospective or a fully retrospective method. ASU 2020-06 is effective for fiscal years beginning after December 15, 2021, with early adoption permitted. The Company will adopt ASU 2020-06 effective January 1, 2022. The adoption of ASU 2020-06 is not expected to have a material impact on the Company’s consolidated financial statements or disclosures. 
+Note 3 – Revenue Recognition 
+Revenue from contracts with customers 
+Oil sales 
+Under the Company’s oil sales contracts it sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the point of delivery at the net price received. The Company has certain oil sales that occur at market locations downstream of the production area. Given the structure of these arrangements and where control transfers, the Company separately recognizes fees and other deductions incurred prior to control transfer as “Gathering, transportation and processing” in its consolidated statements of operations. 
+Natural gas and NGL sales 
+Effective January 1, 2020, certain of our natural gas processing agreements were modified to allow the Company to take title to NGLs resulting from the processing of our natural gas. As a result, sales and reserve volumes, prices, and revenues for NGLs and natural gas are presented separately for periods subsequent to January 1, 2020. For periods prior to January 1, 2020, except for sales and reserve volumes, prices, and revenues specifically associated with Carrizo, sales and reserve volumes, prices, and revenues for NGLs were presented with natural gas. 
+Under the Company’s natural gas sales processing contracts, it delivers natural gas to a midstream processing entity which gathers and processes the natural gas and remits proceeds to the Company for the resulting sale of NGLs and residue gas. The Company evaluates whether the processing entity is the principal or the agent in the transaction for each of our natural gas processing agreements and have concluded that the Company maintains control through processing or has the right to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. The Company recognizes revenue when control transfers to the purchaser at the delivery point based on the contractual index price received. 
+The Company recognizes revenue for natural gas and NGLs on a gross basis with gathering, transportation and processing fees recognized separately as “Gathering, transportation and processing” in its consolidated statements of operations as the Company maintains control throughout processing. 
+Oil and gas purchase and sale arrangements 
+Sales of purchased oil and gas represent revenues the Company receives from sales of commodities purchased from a third-party. The Company recognizes these revenues and the purchase of the third-party commodities, as well as any costs associated with the purchase, on a gross basis, as the Company acts as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer. 
+Accounts Receivable from Revenues from Contracts with Customers 
+Net accounts receivable include amounts billed and currently due from revenues from contracts with customers of our oil and natural gas production, which had a balance at December 31, 2021 and 2020 of $ 171.8 million and $ 100.3 million, respectively, and are presented in “Accounts receivable, net” in the consolidated balance sheets. 
+Note 4 – Acquisitions and Divestitures 
+2021 Acquisitions and Divestitures 
+Primexx Acquisition. On October 1, 2021, the Company closed on the acquisition of certain producing oil and gas properties, undeveloped acreage and associated infrastructure assets in the Delaware Basin from Primexx Resource Development, LLC 
+70 
+(“Primexx”) and BPP Acquisition, LLC (“BPP”) for an adjusted purchase price of approximately $ 444.8 million in cash, inclusive of the deposit paid at signing, 8.84 million shares of the Company’s common stock and approximately $ 25.2 million paid upon final closing for total consideration of $ 880.8 million (the “Primexx Acquisition”). The Company funded the cash portion of the total consideration with borrowings under its Credit Facility, as defined below. Of the 8.84 million shares of the Company’s common stock issued upon closing, 2.6 million shares were held in escrow pursuant to the purchase and sale agreements with Primexx and BPP (collectively, the “Primexx PSAs”). Additionally, 50 % of the shares held in escrow will be released six months after the closing date, and the remaining shares will be released twelve months after the closing date, in each case subject to holdback for the satisfaction of any applicable indemnification claims that may be made under the Primexx PSAs. 
+Also, pursuant to the Primexx PSAs, certain interest owners exercised their option to sell their interest in the properties included in the Primexx Acquisition to the Company for consideration structured similarly to the Primexx Acquisition, for an incremental purchase price totaling approximately $ 33.1 million, net of customary purchase price adjustments, of which $ 22.4 million closed during the fourth quarter of 2021 and the remaining $ 10.7 million closed in early January 2022. 
+The Primexx Acquisition was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values with information available at that time. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. Certain data necessary to complete the purchase price allocation is not yet available. The Company expects to complete the purchase price allocation during the 12-month period following the acquisition date. 
+The following table sets forth the Company’s preliminary allocation of the total estimated consideration of $ 903.2 million to the assets acquired and liabilities assumed as of the acquisition date. 
+Preliminary Purchase 
+Price Allocation 
+(In thousands) 
+Assets: 
+Other current assets $ 10,213 
+Evaluated oil and natural gas properties 677,372 
+Unevaluated properties 275,783 
+Total assets acquired $ 963,368 
+Liabilities: 
+Suspense payable $ 16,447 
+Other current liabilities 32,350 
+Asset retirement obligation 1,898 
+Other long-term liabilities 9,425 
+Total liabilities assumed $ 60,120 
+Total consideration $ 903,248 
+Approximately $ 114.3 million of revenues and $ 32.1 million of direct operating expenses attributed to the Primexx Acquisition are included in the Company’s consolidated statements of operations for the period from the closing date on October 1, 2021 through December 31, 2021. 
+Pro Forma Operating Results (Unaudited). The following unaudited pro forma combined condensed financial data for the years ended December 31, 2021 and 2020 was derived from the historical financial statements of the Company giving effect to the Primexx Acquisition, as if it had occurred on January 1, 2020. The below information reflects pro forma adjustments for the issuance of the Company’s common stock and the borrowings under the Credit Facility as total consideration, as well as pro forma adjustments based on available information and certain assumptions that the Company believes provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Primexx Acquisition. 
+71 
+The pro forma consolidated statements of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Primexx Acquisition taken place on January 1, 2020 and is not intended to be a projection of future results. 
+Years Ended December 31, 
+2021 2020 
+(In thousands) 
+Revenues $ 2,287,012 $ 1,228,735 
+Income (loss) from operations 1,145,995 ( 3,072,237 ) 
+Net income (loss) 477,192 ( 3,151,443 ) 
+Basic earnings per common share $ 8.28 ($ 64.65 ) 
+Diluted earnings per common share $ 8.04 ($ 64.65 ) 
+Non-Core Asset Divestitures . During the second quarter of 2021, the Company completed its divestitures of certain non-core assets in the Delaware Basin for net proceeds of $ 29.6 million. The divestitures were primarily comprised of natural gas producing properties in the Western Delaware Basin as well as a small undeveloped acreage position. 
+On November 19, 2021, the Company closed on its divestiture of certain non-core assets in the Eagle Ford Shale, comprised of producing properties as well as an undeveloped acreage position, for net proceeds of $ 93.4 million, subject to post-closing adjustments. 
+In the fourth quarter of 2021, the Company closed on the divestiture of certain non-core assets in the Midland Basin, comprised of producing properties as well as an undeveloped acreage position for net proceeds of $ 30.9 million , subject to post-closing adjustments. 
+On October 28, 2021, the Company closed on the divestiture of certain non-core water infrastructure for net proceeds of $ 27.9 million, subject to post-closing adjustments, as well as up to $ 18.0 million of incremental contingent consideration based on completed lateral length for wells in a specified area. 
+The aggregate net proceeds for each of the 2021 divestitures discussed above were recognized as a reduction of evaluated oil and gas properties with no gain or loss recognized as the divestitures did not significantly alter the relationship between capitalized costs and estimated proved reserves. 
+2020 Divestitures 
+ORRI Transaction. On September 30, 2020, the Company sold an undivided 2.0 % (on an 8/8ths basis) overriding royalty interest, proportionately reduced to the Company’s net revenue interest, in and to the Company’s operated leases, excluding certain interests to Chambers Minerals, LLC, a private investment vehicle managed by Kimmeridge Energy, for net proceeds of $ 135.8 million (“ORRI Transaction”), which were used to repay borrowings outstanding under the Credit Facility. 
+Non-Operated Working Interest Transaction. On November 2, 2020, the Company sold substantially all of its non-operated assets for net proceeds of approximately $ 29.6 million, which were used to repay borrowings outstanding under the Credit Facility. The transaction had an effective date of September 1, 2020 and is subject to post-closing adjustments. 
+The aggregate net proceeds for each of the 2020 divestitures discussed above were recognized as a reduction of evaluated oil and gas properties with no gain or loss recognized as the divestitures did not significantly alter the relationship between capitalized costs and estimated proved reserves. 
+2019 Acquisitions and Divestitures 
+Carrizo Oil & Gas, Inc. Merger. On December 20, 2019, the Company completed its acquisition of Carrizo in an all-stock transaction (the “Merger” or the “Carrizo Acquisition”). Under the terms of the Merger, each outstanding share of Carrizo common stock was converted into 1.75 shares of the Company’s common stock. The Company issued approximately 168.2 million shares of common stock resulting in total consideration paid by the Company to the former Carrizo shareholders of approximately $ 765.4 million. In connection with the closing of the Merger, the Company funded the redemption of Carrizo’s 8.875 % Preferred Stock, repaid the outstanding principal under Carrizo’s revolving credit facility and assumed all of Carrizo’s senior notes. See “Note 7 - Borrowings” for further details. 
+The Merger was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values with information available at that time. 
+For the period from the closing date of the Carrizo Acquisition on December 20, 2019 through December 31, 2019, approximately $ 28.6 million of revenues and $ 7.0 million of direct operating expenses were included in the Company’s consolidated statements of operations for the year ended December 31, 2019. 
+72 
+Pro Forma Operating Results (Unaudited). The following unaudited pro forma combined condensed financial data for the year ended December 31, 2019 was derived from the historical financial statements of the Company giving effect to the Merger, as if it had occurred on January 1, 2018. The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for Carrizo’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) the Company’s common stock issued to convert Carrizo’s outstanding shares of common stock and equity awards as of the closing date of the Merger, (ii) the depletion of Carrizo’s fair-valued proved oil and natural gas properties and (iii) the estimated tax impacts of the pro forma adjustments. 
+Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company of approximately $ 58.8 million for the year ended December 31, 2019 and acquisition-related costs incurred by Carrizo that totaled approximately $ 15.6 million for the year ended December 31, 2019. The pro forma results of operations do not include any cost savings or other synergies that may result from the Merger or any estimated costs that have been or will be incurred by the Company to integrate the Carrizo assets. The pro forma financial data does not include the pro forma results of operations for any other acquisitions made during the periods presented, as they were primarily acreage acquisitions and their results were not deemed material. 
+The pro forma consolidated statements of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Merger taken place on January 1, 2018 and is not intended to be a projection of future results. 
+Year Ended December 31, 2019 
+(In thousands) 
+Revenues $ 1,620,357 
+Income from operations 614,668 
+Net income 369,777 
+Basic earnings per common share $ 0.89 
+Diluted earnings per common share $ 0.89 
+In conjunction with the Carrizo Acquisition, the Company incurred costs totaling $ 28.5 million and $ 74.4 million for the years ended December 31, 2020 and 2019, respectively, comprised of severance costs of $ 6.2 million and $ 28.8 million for the years ended December 31, 2020 and 2019, respectively, and other merger and integration expenses of $ 22.3 million and $ 45.6 million for the years ended December 31, 2020 and 2019, respectively. 
+Ranger Divestiture. In the second quarter of 2019, the Company completed its divestiture of certain non-core assets in the southern Midland Basin (the “Ranger Divestiture”) for net cash proceeds of $ 244.9 million. The transaction also provided for potential additional contingent consideration in payments of up to $ 60.0 million based on West Texas Intermediate average annual pricing over a three-year period. See “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” for further discussion of this contingent consideration arrangement. The divestiture encompasses the Ranger operating area in the southern Midland Basin which included approximately 9,850 net Wolfcamp acres with an average 66 % working interest. The net cash proceeds were recognized as a reduction of evaluated oil and gas properties with no gain or loss recognized as the divestitures did not significantly alter the relationship between capitalized costs and estimated proved reserves. 
+Note 5 – Property and Equipment, Net 
+As of December 31, 2021 and 2020, total property and equipment, net consisted of the following: 
+As of December 31, 
+2021 2020 
+Oil and natural gas properties, full cost accounting method (In thousands) 
+Evaluated properties $ 9,238,823 $ 7,894,513 
+Accumulated depreciation, depletion, amortization and impairments ( 5,886,002 ) ( 5,538,803 ) 
+Evaluated properties, net 3,352,821 2,355,710 
+Unevaluated properties 
+Unevaluated leasehold and seismic costs 1,557,453 1,532,304 
+Capitalized interest 255,374 200,946 
+Total unevaluated properties 1,812,827 1,733,250 
+Total oil and natural gas properties, net $ 5,165,648 $ 4,088,960 
+Other property and equipment $ 58,367 $ 60,287 
+Accumulated depreciation ( 30,239 ) ( 28,647 ) 
+Other property and equipment, net $ 28,128 $ 31,640 
+73 
+The Company capitalized internal costs of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities totaling $ 47.4 million for the year ended December 31, 2021 and $ 36.2 million for the years ended December 31, 2020 and 2019. 
+The Company capitalized interest costs to unproved properties totaling $ 99.6 million, $ 88.6 million and $ 78.5 million for the years ended December 31, 2021, 2020 and 2019, respectively. 
+Impairment of Evaluated Oil and Gas Properties 
+The Company did no t recognize impairments of evaluated oil and gas properties for the years ended December 31, 2021 and 2019. Primarily as a result of the significant reduction in the 12-Month Average Realized Price of crude oil, the Company recognized impairments of evaluated oil and gas properties of $ 2.5 billion for the year December 31, 2020. 
+Details of the 12-Month Average Realized Price of crude oil for the years ended December 31, 2021, 2020, and 2019 are summarized in the table below: 
+Years Ended December 31, 
+2021 2020 2019 
+Impairment of evaluated oil and natural gas properties (In thousands) $ — $ 2,547,241 $ — 
+Beginning of period 12-Month Average Realized Price ($/Bbl) $ 37.44 $ 53.90 $ 58.40 
+End of period 12-Month Average Realized Price ($/Bbl) $ 65.44 $ 37.44 $ 53.90 
+Percent increase (decrease) in 12-Month Average Realized Price 75 % ( 31 %) ( 8 %) 
+Unevaluated property costs not subject to amortization as of December 31, 2021 were incurred in the following periods: 
+2021 2020 2019 2018 and Prior Total 
+(In thousands) 
+Unevaluated property costs $ 401,403 $ 113,079 $ 479,836 $ 818,509 $ 1,812,827 
+Note 6 – Earnings Per Share 
+Basic earnings (loss) per share is computed by dividing income (loss) available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings per share includes the potential dilutive impact of non-vested restricted shares and unexercised warrants outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. For the year ended December 31, 2020, the Company reported a loss available to common stockholders. As a result, the calculation of diluted weighted average common shares outstanding excluded all potentially dilutive common shares outstanding. 
+74 
+The following table sets forth the computation of basic and diluted earnings per share: 
+Years Ended December 31, 
+2021 2020 2019 
+(In thousands, except per share amounts) 
+Net Income (Loss) $ 365,151 ($ 2,533,621 ) $ 67,928 
+Preferred stock dividends (1) 
+— — ( 3,997 ) 
+Loss on redemption of preferred stock — — ( 8,304 ) 
+Income (Loss) Available to Common Stockholders $ 365,151 ($ 2,533,621 ) $ 55,627 
+Basic weighted average common shares outstanding 48,612 39,718 23,313 
+Dilutive impact of restricted stock 296 — 27 
+Dilutive impact of warrants 1,403 — — 
+Diluted weighted average common shares outstanding 50,311 39,718 23,340 
+Income (Loss) Available to Common Stockholders Per Common Share 
+Basic $ 7.51 ($ 63.79 ) $ 2.39 
+Diluted $ 7.26 ($ 63.79 ) $ 2.38 
+Restricted stock (2) 
+7 581 90 
+Warrants (2) 
+481 2,564 9 
+(1) The Company redeemed all outstanding shares of its 10 % Series A Cumulative Preferred Stock (“Preferred Stock”) on July 18, 2019 and all dividends ceased to accrue upon redemption. 
+(2) Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive. 
+Note 7 – Borrowings 
+The Company’s borrowings consisted of the following: 
+As of December 31, 
+2021 2020 
+(In thousands) 
+6.25 % Senior Notes due 2023 
+$ — $ 542,720 
+6.125 % Senior Notes due 2024 
+460,241 460,241 
+Senior Secured Revolving Credit Facility due 2024 785,000 985,000 
+9.00 % Second Lien Senior Secured Notes due 2025 
+319,659 516,659 
+8.25 % Senior Notes due 2025 
+187,238 187,238 
+6.375 % Senior Notes due 2026 
+320,783 320,783 
+8.00 % Senior Notes due 2028 
+650,000 — 
+Total principal outstanding 2,722,921 3,012,641 
+Unamortized premium on 6.25 % Senior Notes 
+— 2,917 
+Unamortized premium on 6.125 % Senior Notes 
+2,373 3,236 
+Unamortized discount on Second Lien Notes ( 14,852 ) ( 41,820 ) 
+Unamortized premium on 8.25 % Senior Notes 
+2,477 3,240 
+Unamortized deferred financing costs for Second Lien Notes ( 2,910 ) ( 3,931 ) 
+Unamortized deferred financing costs for Senior Notes ( 15,894 ) ( 7,019 ) 
+Total carrying value of borrowings (1) 
+$ 2,694,115 $ 2,969,264 
+(1) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $ 18.1 million and $ 23.6 million as of December 31, 2021 and 2020, respectively, which are classified in “Deferred financing costs” in the consolidated balance sheets. 
+Senior Secured Revolving Credit Facility 
+The Company has a senior secured revolving credit facility with a syndicate of lenders (the “Credit Facility”) that, as of December 31, 2021, had a maximum credit amount of $ 5.0 billion, a borrowing base and elected commitment amount of $ 1.6 billion, with borrowings outstanding of $ 785.0 million at a weighted-average interest rate of 2.65 %, and letters of credit outstanding of $ 24.0 million. The credit agreement governing the Credit Facility provides for interest-only payments until December 20, 2024 (subject to remaining springing maturity dates of (i) July 2, 2024 if the 6.125 % Senior Notes due 2024 (the “ 6.125 % Senior Notes”) 
+75 
+are outstanding at such time, and (ii) if the Second Lien Notes, as defined below, are outstanding at such time, the date which is 182 days prior to the maturity of any of the 6.125 % Senior Notes, to the extent a principal amount of more than $ 100.0 million with respect to each such issuance is outstanding as of such date), when the credit agreement matures and any outstanding borrowings are due. The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. 
+On May 3, 2021, the Company entered into the fourth amendment to its credit agreement governing the Credit Facility, which, among other things, (a) reaffirmed, as of the date of the fourth amendment, the borrowing base and the elected commitment amount of $ 1.6 billion; and (b) permits, subject to certain liquidity and free cash flow metrics, the prepayment, repurchase or redemption, commencing on April 1, 2021, of up to an aggregate amount of $ 100.0 million of Junior Debt (as defined in the credit agreement governing the Credit Facility), which includes the Senior Unsecured Notes (as defined below) and the Second Lien Notes (as defined below). 
+On November 1, 2021, the Company entered into the fifth amendment to its credit agreement governing the Credit Facility, which, among other things, reaffirmed, as of the date of the fifth amendment, the borrowing base and elected commitment amount of $ 1.6 billion. 
+Borrowings outstanding under the credit agreement bear interest at the Company’s option at either (i) a base rate for a base rate loan plus a margin between 1.00 % to 2.00 %, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.50 % and the adjusted LIBO rate plus 1.00 %, or (ii) an adjusted LIBO rate for a Eurodollar loan plus a margin between 2.00 % to 3.00 %. The Company also incurs commitment fees at rates ranging between 0.375 % to 0.500 % on the unused portion of lender commitments, which are included in “Interest expense, net of capitalized amounts” in the consolidated statements of operations. 
+Second Lien Notes 
+Exchange. On November 5, 2021, the Company closed on its transaction with Chambers Investments, LLC (“Kimmeridge”), a private investment vehicle managed by Kimmeridge Energy Management, LLC, to exchange $ 197.0 million of its outstanding Second Lien Notes for a notional amount of approximately $ 223.1 million of the Company’s common stock. The value of equity to be delivered was based on the optional redemption language in the indenture for the Second Lien Notes. The price of the Company’s common stock used to calculate the shares issued was based on the 10 -day volume-weighted average price as of August 2, 2021 and equated to 5.5 million shares. As a result of the Second Lien Note Exchange, the Company recognized a loss on the extinguishment of debt of approximately $ 43.4 million in its consolidated statement of operations for the year ended December 31, 2021, calculated as the notional amount of common stock issued less aggregate principal amount of Second Lien Notes exchanged, net of a pro-rata write-off of associated unamortized discount of $ 16.9 million and fees incurred. 
+Issuance. On September 30, 2020, the Company issued (i) $ 300.0 million in aggregate principal amount of 9.00 % Second Lien Senior Secured Notes due 2025 (the “September 2020 Second Lien Notes”) and (ii) warrants for 7.3 million shares of the Company’s common stock, with a term of five years and an exercise price of $ 5.60 per share, exercisable only on a net share settlement basis (the “September 2020 Warrants”). Net proceeds were allocated to the September 2020 Warrants based on their fair value on the date of issuance with the remaining net proceeds allocated to the September 2020 Second Lien Notes. The fair value of the September 2020 Warrants was calculated by a third-party valuation specialist using a Black-Scholes-Merton option pricing model, incorporating the following assumptions at the issuance date: 
+Issuance Date Fair Value Assumptions 
+Exercise price $ 5.60 
+Expected term (in years) 5.0 
+Expected volatility 116.3 % 
+Risk-free interest rate 0.3 % 
+Dividend yield — % 
+See “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” for further discussion of the September 2020 Warrants. 
+On November 2, 2020, in connection with the Senior Unsecured Notes exchange described below, the Company issued (i) $ 216.7 million in aggregate principal amount of 9.00 % Second Lien Senior Secured Notes due 2025 (the “November 2020 Second Lien Notes” and together with the September 2020 Second Lien Notes, the “Second Lien Notes”) and (ii) warrants for approximately 1.75 million shares of the Company’s common stock, with a term of five years and an exercise price of $ 5.60 per share, exercisable only on a net share settlement basis (the “November 2020 Warrants”). The fair value of the November 2020 Second Lien Notes was calculated by a third-party valuation specialist using a discounted cash flow model. Significant inputs into the calculation included the redemption premiums, described below, as well as redemption assumptions provided by the Company. The fair value of the November 
+76 
+2020 Warrants was calculated using a Black-Scholes-Merton option pricing model, incorporating the following assumptions at the issuance date: 
+Issuance Date Fair Value Assumptions 
+Exercise price $ 5.60 
+Expected term (in years) 4.9 
+Expected volatility 98.4 % 
+Risk-free interest rate 0.4 % 
+Dividend yield — % 
+As the November 2020 Second Lien Notes were issued with the November 2020 Warrants, the $ 216.7 million aggregate principal amount was allocated between the November 2020 Second Lien Notes and the November 2020 Warrants based on their relative fair values at the exchange date. This resulted in $ 207.6 million allocated to the November 2020 Second Lien Notes and $ 9.1 million allocated to the November 2020 Warrants. 
+The Second Lien Notes will mature on the earlier of (i) April 1, 2025 and (ii) 91 days prior to the maturity date of any outstanding unsecured notes in a principal amount at or greater than $ 100.0 million and have interest payable semi-annually each April 1 and October 1, commencing on April 1, 2021. 
+The Company may redeem the Second Lien Notes in accordance with the following terms: (1) prior to October 1, 2022, a redemption of up to 35 % of the principal in an amount not greater than the net proceeds from certain equity offerings, and within 180 days of the closing date of such equity offerings, at a redemption price of 109.00 % of principal, plus accrued and unpaid interest, if any, to, but excluding, the date of redemption, if at least 65 % of the principal will remain outstanding after such redemption; (2) prior to October 1, 2022, a redemption of all or part of the principal at a price of 100 % of the principal amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to, but excluding, the date of redemption; and (3) subsequent to October 1, 2022, a redemption, in whole or in part, at redemption prices decreasing annually from 105.00 % to 100 % of the principal amount redeemed plus accrued and unpaid interest. 
+Upon the occurrence of certain change of control events, each holder of the Second Lien Notes may require the Company to repurchase all or a portion of the Second Lien Notes at a price of 101 % of the principal amount repurchased, plus accrued and unpaid interest, if any, to, but excluding, the date of repurchase. 
+Senior Unsecured Notes 
+8.00 % Senior Notes. On July 6, 2021, the Company issued $ 650.0 million aggregate principal amount of 8.00 % Senior Notes due 2028 (the “ 8.00 % Senior Notes”) in a private placement for proceeds of approximately $ 638.1 million, net of underwriting discounts and commissions and offering costs. The 8.00 % Senior Notes mature on August 1, 2028 and interest is payable semi-annually each February 1 and August 1, commencing on February 1, 2022. 
+At any time prior to August 1, 2024, the Company may, from time to time, redeem up to 35 % of the aggregate principal amount of the 8.00 % Senior Notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 108.00 % of the principal amount, plus accrued and unpaid interest, if any, to, but excluding, the date of redemption, if at least 65 % of the aggregate principal amount of the 8.00 % Senior Notes remains outstanding after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. Prior to August 1, 2024, the Company may, at its option, on any one or more occasions, redeem all or a portion of the 8.00 % Senior Notes at 100.00 % of the principal amount plus an applicable make-whole premium and accrued and unpaid interest. On or after August 1, 2024, the Company may redeem all or a portion of the 8.00 % Senior Notes at redemption prices decreasing annually from 104.00 % to 100.00 % of the principal amount redeemed plus accrued and unpaid interest. Upon the occurrence of certain kinds of change of control, the Company must make an offer to repurchase all or a portion of each holder’s 8.00 % Senior Notes for cash at a price equal to 101 % of the aggregate principal amount, plus accrued and unpaid interest. 
+Redemption of 6.25 % Senior Notes. On June 21, 2021, the Company delivered a redemption notice with respect to all $ 542.7 million of its outstanding 6.25 % Senior Notes due 2023 (the “ 6.25 % Senior Notes”), which became redeemable on July 21, 2021. The Company used a portion of the net proceeds from the 8.00 % Senior Notes to redeem all of its outstanding 6.25 % Senior Notes and the remaining proceeds to partially repay amounts outstanding under the Credit Facility. The Company recognized a gain on extinguishment of debt of approximately $ 2.4 million in its consolidated statements of operations for the year ended December 31, 2021, which was primarily related to writing off the remaining unamortized premium associated with the 6.25 % Senior Notes. 
+Senior Unsecured Notes Exchange. On November 13, 2020, the Company closed on the agreement by and among the Company and certain holders (the “Holders”) of the Company’s 6.25 % Senior Notes, 6.125 % Senior Notes, 8.25 % Senior Notes, and 6.375 % Senior Notes (each as defined in this footnote and together the “Senior Unsecured Notes”) to exchange $ 389.0 million of aggregate principal 
+77 
+amount of the Senior Unsecured Notes held by the Holders for $ 216.7 million aggregate principal amount of Second Lien Notes, as further described above. 
+The Company assessed the debt exchange to determine whether it should be accounted for pursuant to the FASB’s Accounting Standard Codification (“ASC”) Topic 470-60, Troubled Debt Restructurings by Debtors, or pursuant to ASC Topic 470-50, Modifications and Extinguishments (“ASC 470-50”). This assessment requires judgments to be made with respect to whether or not an entity is experiencing financial difficulty. It was determined that the Company was not experiencing financial difficulty and could obtain funds at market rates similar to other non-troubled debtors, therefore the Company accounted for the exchange as an extinguishment of debt in accordance with ASC 470-50. The Company recognized a gain on the extinguishment of debt of $ 170.4 million in its consolidated statement of operations for the year ended December 31, 2020, which consisted of the carrying values of the Senior Unsecured Notes exchanged less the aggregate principal amount of the November 2020 Second Lien Notes issued, net of associated unamortized debt discount of $ 9.1 million, which was based on the November 2020 Second Lien Notes’ allocated fair value on the exchange date. 
+6.125 % Senior Notes. The Company’s 6.125 % Senior Notes mature on October 1, 2024 and have interest payable semi-annually each April 1 and October 1. The Company may redeem all or a portion of the 6.125 % Senior Notes at redemption prices decreasing annually from 104.594 % to 100 % of the principal amount plus accrued and unpaid interest. Following a change of control, each holder of the 6.125 % Senior Notes may require the Company to repurchase all or a portion of the 6.125 % Senior Notes at a price of 101 % of principal of the amount repurchased, plus accrued and unpaid interest. 
+8.25 % Senior Notes. The Company’s 8.25 % Senior Notes due 2025 (the “8.25% Senior Notes”), which were assumed upon consummation of the Merger, mature on July 15, 2025 and have interest payable semi-annually each January 15 and July 15. The Company may redeem all or a portion of the 8.25 % Senior Notes at redemption prices decreasing annually from 106.188 % to 100 % of the principal amount redeemed plus accrued and unpaid interest. Following a change of control, each holder of the 8.25 % Senior Notes may require the Company to repurchase the 8.25 % Senior Notes for cash at a price equal to 101 % of the principal amount purchased, plus any accrued and unpaid interest. 
+6.375 % Senior Notes. On June 7, 2018, the Company issued $ 400.0 million aggregate principal amount of 6.375 % Senior Notes due 2026 (the “ 6.375 % Senior Notes”), which mature on July 1, 2026 and have interest payable semi-annually each January 1 and July 1. 
+Since July 1, 2021, the Company may redeem all or a portion of the 6.375 % Senior Notes at redemption prices decreasing annually from 103.188 % to 100 % of the principal amount redeemed plus accrued and unpaid interest. Following a change of control, each holder of the 6.375 % Senior Notes may require the Company to repurchase all or a portion of the 6.375 % Senior Notes at a price of 101 % of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase. 
+Each of the Senior Unsecured Notes described above are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The subsidiary guarantor is 100 % owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor. 
+Restrictive Covenants 
+The Company’s credit agreement governing the Credit Facility contains certain covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. 
+Under the credit agreement, the Company must maintain the following financial covenants determined as of the last day of the quarter: (1) commencing on March 31, 2020 and for each quarter ending on or prior to December 31, 2021, a Secured Leverage Ratio (as defined in the credit agreement governing the Credit Facility) of no more than 3.00 to 1.00 and (2) commencing March 31, 2022 and for each quarter ending thereafter, a Leverage Ratio (as defined in the credit agreement governing the Credit Facility) of no more than 4.00 to 1.00; and (3) a Current Ratio (as defined in the credit agreement governing the Credit Facility) of not less than 1.00 to 1.00. The Company was in compliance with these covenants at December 31, 2021. 
+The credit agreement governing the Credit Facility and the indentures governing the Company’s Senior Unsecured Notes also place restrictions on the Company and certain of its subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters. 
+The credit agreement and indentures are subject to customary events of default. If an event of default occurs and is continuing, the holders or lenders may elect to accelerate amounts due (except in the case of a bankruptcy event of default, in which case such amounts will automatically become due and payable). 
+78 
+Note 8 – Derivative Instruments and Hedging Activities 
+Objectives and Strategies for Using Derivative Instruments 
+The Company is exposed to fluctuations in oil, natural gas and NGL prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil, natural gas and NGL production. The Company utilizes a mix of collars, swaps, and put and call options to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes. 
+Counterparty Risk and Offsetting 
+The Company typically has numerous commodity derivative instruments outstanding with a counterparty that were executed at various dates, for various contract types, commodities and time periods. This often results in both commodity derivative asset and liability positions with that counterparty. The Company nets its commodity derivative instrument fair values executed with the same counterparty to a single asset or liability pursuant to ISDA Agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement. 
+As of December 31, 2021, the Company has outstanding commodity derivative instruments with ten counterparties to minimize its credit exposure to any individual counterparty. All of the counterparties to the Company’s commodity derivative instruments are also lenders under the Company’s credit agreement. Therefore, each of the Company’s counterparties allow the Company to satisfy any need for margin obligations associated with commodity derivative instruments where the Company is in a net liability position with the collateral securing the credit agreement, thus eliminating the need for independent collateral posting. 
+Because each of the Company’s counterparties has an investment grade credit rating, the Company believes it does not have significant credit risk and accordingly does not currently require its counterparties to post collateral to support the net asset positions of its commodity derivative instruments. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each counterparty. 
+While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument. See “Note 9 - Fair Value Measurements” for further discussion. 
+Contingent Consideration Arrangements 
+Ranger Divestiture. The Company’s Ranger Divestiture provided for potential contingent consideration to be received by the Company if the average of the final monthly settlements for each month of 2021 for NYMEX Light Sweet Crude Oil Futures exceeded the pricing threshold of $ 60.00 for the year 2021. See “Note 4 - Acquisitions and Divestitures” and “Note 9 - Fair Value Measurements” for further discussion. As the specified pricing threshold for 2021 was met, in March 2022, the Company will receive $ 20.8 million, of which $ 8.5 million will be presented in cash flows from financing activities with the remaining $ 12.3 million presented in cash flows from operating activities. The Ranger Divestiture contingent consideration expired at the end of 2021. 
+Carrizo Acquisition Contingent Consideration. As a result of the Carrizo Acquisition, the Company acquired the Contingent ExL Consideration where the Company could be required to remit payments if the average daily closing spot price of WTI crude oil exceeded the pricing threshold of $ 50.00 for each of the years 2019, 2020 and 2021. The specified pricing threshold for 2020 was not met, therefore there was no payment made for the Contingent ExL Consideration in January 2021. In January 2020, the Company paid $ 50.0 million as the specified pricing threshold for 2019 was met. This cash payment is classified as cash flows from investing activities in the consolidated statements of cash flows. Additionally, as the specified pricing threshold for 2021 was met, in January 2022, the Company paid $ 25.0 million, of which $ 19.2 million will be presented in cash flows from investing activities with the remaining $ 5.8 million presented in cash flows from operating activities. The Contingent ExL Consideration expired at the end of 2021. 
+Additionally, as part of the Carrizo Acquisition, the Company acquired other contingent consideration arrangements where the Company could receive payments if certain pricing thresholds were met in 2019 and 2020, which ranged between $ 53.00 - $ 60.00 per barrel of oil or $ 3.18 - $ 3.30 per MMBtu of natural gas. The specified pricing thresholds for each of these other contingent consideration arrangements for 2020 were not met, therefore there were no payments from the contingent consideration arrangements acquired in the Carrizo Acquisition in January 2021. In January 2020, the Company received $ 10.0 million as the specified pricing thresholds for 2019 were met for certain of the contingent consideration arrangements. These cash receipts are classified as cash flows 
+79 
+from investing activities in the consolidated statements of cash flows. Each of these other contingent consideration arrangements acquired in the Carrizo Acquisition expired at the end of 2020. 
+Warrants 
+The Company determined that the September 2020 Warrants, as defined above in “Note 7 - Borrowings”, were required to be accounted for as a derivative instrument. The Company recorded the September 2020 Warrants as a liability on its consolidated balance sheet measured at fair value as a component of “Fair value of derivatives” with gains and losses as a result of changes in the fair value of the September 2020 Warrants recorded as “(Gain) loss on derivative contracts” in the consolidated statements of operations in the period in which the changes occur. See “Note 7 - Borrowings” and “Note 9 - Fair Value Measurements” for additional details. 
+In February 2021, holders of the September 2020 Warrants provided notice and exercised all of their outstanding warrants. As a result of this exercise, the Company issued 5.6 million shares of its common stock in exchange for all of the outstanding September 2020 Warrants. The exercise of the September 2020 Warrants resulted in settlement of the associated derivative liability, which was $ 134.8 million at the time of exercise, and the fair value of the September 2020 Warrants at exercise, less the par value of the shares of common stock issued in the exercise, was reclassified to “Capital in excess of par value” in the consolidated balance sheets. 
+Financial Statement Presentation and Settlements 
+The Company records its derivative instruments at fair value in the consolidated balance sheets and records changes in fair value as “(Gain) loss on derivative contracts” in the consolidated statements of operations. Settlements are also recorded as “(Gain) loss on derivative contracts” in the consolidated statements of operations. The Company presents the fair value of derivative contracts on a net basis in the consolidated balance sheet as they are subject to master netting arrangements. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated: 
+As of December 31, 2021 
+Presented without As Presented with 
+Effects of Netting Effects of Netting Effects of Netting 
+(In thousands) 
+Assets 
+Commodity derivative instruments $ 25,469 ($ 23,921 ) $ 1,548 
+Contingent consideration arrangements 20,833 — 20,833 
+Fair value of derivatives - current $ 46,302 ($ 23,921 ) $ 22,381 
+Commodity derivative instruments $ 1,119 ($ 869 ) $ 250 
+Contingent consideration arrangements — — — 
+Other assets, net $ 1,119 ($ 869 ) $ 250 
+Liabilities 
+Commodity derivative instruments (1) 
+($ 184,898 ) $ 23,921 ($ 160,977 ) 
+Contingent consideration arrangements ( 25,000 ) — ( 25,000 ) 
+Fair value of derivatives - current ($ 209,898 ) $ 23,921 ($ 185,977 ) 
+Commodity derivative instruments ($ 12,278 ) $ 869 ($ 11,409 ) 
+Contingent consideration arrangements — — — 
+Fair value of derivatives - non current ($ 12,278 ) $ 869 ($ 11,409 ) 
+(1) Includes approximately $ 2.9 million of deferred premiums, which will be paid as the applicable contracts settle. 
+80 
+As of December 31, 2020 
+Presented without As Presented with 
+Effects of Netting Effects of Netting Effects of Netting 
+(In thousands) 
+Assets 
+Commodity derivative instruments $ 21,156 ($ 20,235 ) $ 921 
+Contingent consideration arrangements — — — 
+Fair value of derivatives - current $ 21,156 ($ 20,235 ) $ 921 
+Commodity derivative instruments $ — $ — $ — 
+Contingent consideration arrangements 1,816 — 1,816 
+Other assets, net $ 1,816 $ — $ 1,816 
+Liabilities 
+Commodity derivative instruments (1) 
+($ 117,295 ) $ 20,235 ($ 97,060 ) 
+Contingent consideration arrangements — — — 
+Fair value of derivatives - current ($ 117,295 ) $ 20,235 ($ 97,060 ) 
+Commodity derivative instruments $ — $ — $ — 
+Contingent consideration arrangements ( 8,618 ) — ( 8,618 ) 
+September 2020 Warrants liability ( 79,428 ) — ( 79,428 ) 
+Fair value of derivatives - non current ($ 88,046 ) $ — ($ 88,046 ) 
+(1) Includes approximately $ 11.2 million of deferred premiums, which will be paid as the applicable contracts settle. 
+The components of “(Gain) loss on derivative contracts” are as follows for the respective periods: 
+Years Ended December 31, 
+2021 2020 2019 
+(In thousands) 
+(Gain) loss on oil derivatives $ 429,156 ($ 48,031 ) $ 73,313 
+(Gain) loss on natural gas derivatives 33,621 14,883 ( 8,889 ) 
+(Gain) loss on NGL derivatives 6,768 2,426 — 
+(Gain) loss on contingent consideration arrangements ( 2,635 ) 2,976 ( 2,315 ) 
+(Gain) loss on September 2020 Warrants liability 55,390 55,519 — 
+(Gain) loss on derivative contracts $ 522,300 $ 27,773 $ 62,109 
+The components of “Cash received (paid) for commodity derivative settlements, net” and “Cash paid for settlements of contingent consideration arrangements, net” are as follows for the respective periods: 
+Years Ended December 31, 
+2021 2020 2019 
+(In thousands) 
+Cash flows from operating activities 
+Cash received (paid) on oil derivatives ($ 350,340 ) $ 98,723 ($ 11,188 ) 
+Cash received (paid) on natural gas derivatives ( 34,576 ) 147 7,399 
+Cash received (paid) on NGL derivatives ( 10,181 ) — — 
+Cash received (paid) for commodity derivative settlements, net ($ 395,097 ) $ 98,870 ($ 3,789 ) 
+Cash flows from investing activities 
+Cash paid for settlements of contingent consideration arrangements, net $ — ($ 40,000 ) $ — 
+81 
+Derivative Positions 
+Listed in the tables below are the outstanding oil, natural gas and NGL derivative contracts as of December 31, 2021: 
+For the Full Year For the Full Year 
+Oil Contracts (WTI) 2022 2023 
+Swap Contracts 
+Total volume (Bbls) 5,891,000 497,000 
+Weighted average price per Bbl $ 61.61 $ 70.01 
+Collar Contracts 
+Total volume (Bbls) 7,097,500 — 
+Weighted average price per Bbl 
+Ceiling (short call) $ 67.70 $ — 
+Floor (long put) $ 56.15 $ — 
+Short Call Swaption Contracts 1 
+Total volume (Bbls) — 1,825,000 
+Weighted average price per Bbl $ — $ 72.00 
+Oil Contracts (Midland Basis Differential) 
+Swap Contracts 
+Total volume (Bbls) 2,372,500 — 
+Weighted average price per Bbl $ 0.50 $ — 
+Oil Contracts (Argus Houston MEH) 
+Collar Contracts 
+Total volume (Bbls) 452,500 — 
+Weighted average price per Bbl 
+Ceiling (short call) $ 63.15 $ — 
+Floor (long put) $ 51.25 $ — 
+(1) The 2023 short call swaption contracts have exercise expiration dates of December 30, 2022. 
+For the Full Year 
+Natural Gas Contracts (Henry Hub) 2022 
+Swap Contracts 
+Total volume (MMBtu) 7,320,000 
+Weighted average price per MMBtu $ 3.08 
+Collar Contracts 
+Total volume (MMBtu) 7,880,000 
+Weighted average price per MMBtu 
+Ceiling (short call) $ 3.91 
+Floor (long put) $ 3.08 
+Natural Gas Contracts (Waha Basis Differential) 
+Swap Contracts 
+Total volume (MMBtu) 5,475,000 
+Weighted average price per MMBtu ($ 0.21 ) 
+82 
+For the Full Year 
+NGL Contracts (OPIS Mont Belvieu Purity Ethane) 2022 
+Swap Contracts 
+Total volume (Bbls) 378,000 
+Weighted average price per Bbl $ 15.70 
+NGL Contracts (OPIS Mont Belvieu Non-TET Propane) 
+Swap Contracts 
+Total volume (Bbls) 252,000 
+Weighted average price per Bbl $ 48.43 
+NGL Contracts (OPIS Mont Belvieu Non-TET Butane) 
+Swap Contracts 
+Total volume (Bbls) 99,000 
+Weighted average price per Bbl $ 54.39 
+NGL Contracts (OPIS Mont Belvieu Non-TET Isobutane) 
+Swap Contracts 
+Total volume (Bbls) 54,000 
+Weighted average price per Bbl $ 54.29 
+Note 9 – Fair Value Measurements 
+Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: 
+Level 1 – Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities. 
+Level 2 – Other inputs that are observable directly or indirectly such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. 
+Level 3 – Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities. 
+Fair Value of Financial Instruments 
+Cash, Cash Equivalents, and Restricted Investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments. 
+Debt. The carrying amount of borrowings outstanding under the Credit Facility approximates fair value as the borrowings bear interest at variable rates and are reflective of market rates. The following table presents the principal amounts of the Company’s Second Lien Notes and Senior Unsecured Notes with the fair values measured using quoted secondary market trading prices which are designated as Level 2 within the valuation hierarchy. See “Note 7 - Borrowings” for further discussion. 
+December 31, 2021 December 31, 2020 
+Principal Amount Fair Value Principal Amount Fair Value 
+(In thousands) 
+6.25 % Senior Notes 
+$ — $ — $ 542,720 $ 344,627 
+6.125 % Senior Notes 
+460,241 455,639 460,241 260,036 
+9.00 % Second Lien Notes 
+319,659 343,633 516,659 470,160 
+8.25 % Senior Notes 
+187,238 184,429 187,238 100,172 
+6.375 % Senior Notes 
+320,783 309,556 320,783 161,995 
+8.00 % Senior Notes 
+650,000 663,000 — — 
+Total $ 1,937,921 $ 1,956,257 $ 2,027,641 $ 1,336,990 
+Assets and Liabilities Measured at Fair Value on a Recurring Basis 
+Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheet. The following methods and assumptions were used to estimate fair value: 
+83 
+Commodity Derivative Instruments. The fair value of commodity derivative instruments is derived using a third-party income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the commodity derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for commodity derivative assets and an estimate of the Company’s default risk for commodity derivative liabilities. As the inputs in the model are substantially observable over the term of the commodity derivative contract and there is a wide availability of quoted market prices for similar commodity derivative contracts, the Company designates its commodity derivative instruments as Level 2 within the fair value hierarchy. See “Note 8 - Derivative Instruments and Hedging Activities” for further discussion. 
+Contingent Consideration Arrangements - Embedded Derivative Financial Instruments. The embedded options within the contingent consideration arrangements are considered financial instruments under ASC 815. The Company engages a third-party valuation specialist using an option pricing model approach to measure the fair value of the embedded options on a recurring basis. The valuation includes significant inputs such as forward oil price curves, time to expiration, and implied volatility. The model provides for the probability that the specified pricing thresholds would be met for each settlement period, estimates undiscounted payouts, and risk adjusts for the discount rates inclusive of adjustments for each of the counterparty’s credit quality. As these inputs are substantially observable for the full term of the contingent consideration arrangements, the inputs are considered Level 2 inputs within the fair value hierarchy. See “Note 8 - Derivative Instruments and Hedging Activities” for further discussion. 
+The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2021 and 2020: 
+December 31, 2021 
+Level 1 Level 2 Level 3 
+(In thousands) 
+Assets 
+Commodity derivative instruments $ — $ 1,798 $ — 
+Contingent consideration arrangements — 20,833 — 
+Liabilities 
+Commodity derivative instruments (1) 
+— ( 172,386 ) — 
+Contingent consideration arrangements — ( 25,000 ) — 
+Total net assets (liabilities) $ — ($ 174,755 ) $ — 
+December 31, 2020 
+Level 1 Level 2 Level 3 
+(In thousands) 
+Assets 
+Commodity derivative instruments $ — $ 921 $ — 
+Contingent consideration arrangements — 1,816 — 
+Liabilities 
+Commodity derivative instruments (2) 
+— ( 97,060 ) — 
+Contingent consideration arrangements — ( 8,618 ) — 
+September 2020 Warrants — — ( 79,428 ) 
+Total net assets (liabilities) $ — ($ 102,941 ) ($ 79,428 ) 
+(1) Includes approximately $ 2.9 million of deferred premiums which will be paid as the applicable contracts settle. 
+(2) Includes approximately $ 11.2 million of deferred premiums which will be paid as the applicable contracts settle. 
+September 2020 Warrants. The fair value of the September 2020 Warrants was calculated using a Black Scholes-Merton option pricing model. As historical volatility is a significant input into the model, the September 2020 Warrants were designated as Level 3 within the valuation hierarchy. 
+In February 2021, holders of the September 2020 Warrants provided notice and exercised all of their outstanding warrants. The exercise of the September 2020 Warrants resulted in settlement of the associated derivative liability of $ 134.8 million. See “Note 7 - Borrowings” and “Note 8 - Derivative Instruments and Hedging Activities” for additional details regarding the September 2020 Warrants. 
+84 
+The following table presents a reconciliation of the change in the fair value of the liability related to the September 2020 Warrants, which was designated as Level 3 within the valuation hierarchy, for the years ended December 31, 2021 and 2020. 
+Years Ended December 31, 
+2021 2020 
+(In thousands) 
+Beginning of period $ 79,428 $ — 
+Recognition of issuance date fair value — 23,909 
+(Gain) loss on changes in fair value (1) 
+55,390 55,519 
+Transfers into (out of) Level 3 ( 134,818 ) — 
+End of period $ — $ 79,428 
+(1) Included in “(Gain) loss on derivative contracts” in the consolidated statements of operations. 
+Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis 
+Acquisitions. The fair value of assets acquired and liabilities assumed, other than the contingent consideration arrangements which are discussed above, are measured as of the acquisition date by a third-party valuation specialist using a combination of income and market approaches, which are not observable in the market and are therefore designated as Level 3 inputs. Significant inputs include expected discounted future cash flows from estimated reserve quantities, estimates for timing and costs to produce and develop reserves, oil and natural gas forward prices, and a risk adjusted discount rate. See “Note 4 - Acquisitions and Divestitures” for additional discussion. 
+Asset Retirement Obligations. The Company measures the fair value of asset retirement obligations as of the date a well begins drilling or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 within the valuation hierarchy. Significant inputs to the fair value measurement of asset retirement obligations include estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities, restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates. See “Note 14 - Asset Retirement Obligations” for additional discussion. 
+Note 10 – Share-Based Compensation 
+2020 Omnibus Incentive Plan 
+Shares-based awards are granted under the 2020 Omnibus Incentive Plan (the “2020 Plan”), which replaced the 2018 Omnibus Incentive Plan (the “2018 Plan”). From the effective date of the 2020 Plan, no further awards may be granted under the 2018 Plan, however, awards previously granted under the 2018 Plan will remain outstanding in accordance with their terms. At December 31, 2021, there were 1,619,272 shares available for future share-based awards under the 2020 Plan. 
+RSU Equity Awards 
+The following table summarizes RSU Equity Award activity for the year ended December 31, 2021: 
+RSU Equity Awards (in thousands) Weighted Average Grant-Date Fair Value per Share 
+Unvested at the beginning of the year 677 $ 34.57 
+Granted 643 $ 38.59 
+Vested ( 224 ) $ 43.97 
+Forfeited ( 128 ) $ 42.40 
+Unvested at the end of the year 968 $ 34.04 
+Grant activity for the year ended December 31, 2021, 2020 and 2019 primarily consisted of RSU Equity Awards granted to executives and employees as part of the annual grant of long-term equity incentive awards with a weighted average grant date fair value of $ 38.59 , $ 21.07 and $ 85.96 , respectively. 
+For outstanding performance-based RSU Equity Awards, the number of performance-based RSU Equity Awards that can vest is based on a calculation that compares the Company’s total shareholder return (“TSR”) to the same calculated return of a group of peer companies selected by the Company and can range between 0 % and 300 % of the target units for the awards granted in 2020 and between 0 % and 200 % of the target units for the awards granted in 2019. The increase in the maximum amount of performance-based RSU Equity Awards that can vest for the awards granted in 2020 is due to an absolute TSR modifier, which was added as a second factor in the calculation, in addition to the relative TSR multiplier. While the absolute TSR modifier could increase the number of 
+85 
+awards that vest, the number of awards that vest could also be reduced if the absolute TSR is less than 5 % over the performance period. No performance-based RSU Equity Awards were granted during 2021. 
+The following table summarizes the shares that vested and did not vest as a result of the Company’s performance as compared to its peers. 
+Years Ended December 31, 
+Performance-based Equity Awards 2021 2020 2019 
+Vesting Multiplier 50 % 
+50 % - 100 % 
+100 % 
+Target 28,356 21,920 8,878 
+Vested at end of performance period 14,177 11,372 8,878 
+Did not vest at end of performance period 14,179 10,548 — 
+The Company recognizes expense for performance-based RSU Equity Awards based on the fair value of the awards at the grant date. Awards with a performance-based provision do not allow for the reversal of previously recognized expense, even if the market metric is not achieved and no shares ultimately vest. For the years ended December 31, 2020 and 2019, the grant date fair value of the performance-based RSU Equity Awards, calculated using a Monte Carlo simulation, was $ 3.4 million and $ 4.3 million, respectively. The following table summarizes the assumptions used and the resulting grant date fair value per performance-based RSU Equity Award granted during the years ended December 31, 2020 and 2019: 
+Performance-based Awards June 29, 2020 January 31, 2020 January 31, 2019 
+Expected term (in years) 2.5 2.9 2.9 
+Expected volatility 113.2 % 54.8 % 47.9 % 
+Risk-free interest rate 0.2 % 1.3 % 2.4 % 
+Dividend yield — % — % — % 
+The aggregate fair value of RSU Equity Awards that vested during the years ended December 31, 2021, 2020 and 2019 was $ 8.7 million, $ 1.6 million and $ 7.3 million, respectively. As of December 31, 2021, unrecognized compensation costs related to unvested RSU Equity Awards were $ 21.2 million and will be recognized over a weighted average period of 2.0 years. 
+Cash-Settled Awards 
+Cash-Settled RSU Awards. The table below summarizes the Cash-Settled RSU Award activity for the year ended December 31, 2021: 
+Cash-Settled RSU Awards 
+(in thousands) Weighted Average Grant-Date Fair Value per Share 
+Unvested at the beginning of the year 196 $ 47.56 
+Granted (1) 
+3 $ 36.71 
+Vested ( 14 ) $ 107.93 
+Did not vest at end of performance period ( 14 ) $ 107.93 
+Forfeited ( 24 ) $ 54.57 
+Unvested at the end of the year 147 $ 34.60 
+(1) Includes 3.2 thousand units associated with deferrals of certain non-employee director compensation pursuant to the terms of the Amended and Restated Deferred Compensation Plan for Outside Directors. 
+No Cash-Settled RSU Awards were granted to employees during the year ended December 31, 2021. Grant activity during the years ended December 31, 2020 and 2019 primarily consisted of Cash-Settled RSU Awards to executives as part of the annual grant of long-term equity incentive awards. These awards cliff vest after an approximate three-year performance period. The weighted average grant date fair value of Cash-Settled RSU Awards was $ 36.71 , $ 26.84 and $ 105.08 for the years ended December 31, 2021, 2020 and 2019, respectively. 
+The Company’s outstanding Cash-Settled RSU Awards include the same performance-based vesting conditions as the performance-based RSU Equity Awards, which are described above. Additionally, the assumptions used to calculate the grant date fair value per Cash-Settled RSU Award granted during the years ended December 31, 2020 and 2019 are the same as the performance-based RSU Equity Awards presented above. 
+For the years ended December 31, 2021, 2020 and 2019, Cash-Settled RSU Awards vested resulting in cash payments of $ 0.7 million, $ 0.2 million and $ 0.8 million, respectively. As of December 31, 2021, unrecognized compensation costs related to unvested Cash-Settled RSU Awards were $ 2.7 million and will be recognized over a weighted average period of 1.0 years. 
+86 
+Cash-Settled SARs. The table below summarizes the Cash SAR activity for the year ended December 31, 2021. 
+Stock Appreciation Rights 
+(in thousands) Weighted 
+Average 
+Exercise 
+Prices Weighted Average Remaining Life 
+(In years) Aggregate Intrinsic Value 
+(In millions) 
+Outstanding, beginning of the year 368 $ 100.34 
+Granted — $ — 
+Exercised — $ — 
+Forfeited — $ — 
+Expired ( 65 ) $ 156.00 
+Outstanding, end of the year 303 $ 88.37 3.1 $ — 
+Vested, end of the year 303 $ 88.37 — $ — 
+Vested and exercisable, end of the year — $ — — $ — 
+As all Cash SARs are vested, there is no unrecognized compensation costs as of December 31, 2021. The acquisition date fair value of the Cash SARs in 2019, calculated using the Black-Scholes-Merton option pricing model, was $ 4.6 million. The following table summarizes the assumptions used and the expiration date for the grants that occurred during the period presented below: 
+Cash SARs 2019 
+Expected term (in years) 5.4 
+Expected volatility 60.7 % 
+Risk-free interest rate 1.7 % 
+Dividend yield — % 
+Expiration date March 17, 2026 
+The following table summarizes the classification in the consolidated balance sheets of the Company’s cash-settled awards for the periods indicated: 
+December 31, 
+2021 2020 
+(In thousands) 
+Cash SARs $ 7,884 $ 1,670 
+Cash-Settled RSU Awards 1,382 182 
+Other current liabilities 9,266 1,852 
+Cash-Settled RSU Awards 6,366 1,336 
+Other long-term liabilities 6,366 1,336 
+Total Cash-Settled RSU Awards $ 15,632 $ 3,188 
+Share-Based Compensation Expense, Net 
+Share-based compensation expense associated with the RSU Equity Awards, Cash-Settled RSU Awards, and Cash SARs, net of amounts capitalized, is included in “General and administrative” in the consolidated statements of operations. The following table presents share-based compensation expense (benefit), net for each respective period: 
+Years Ended December 31, 
+2021 2020 2019 
+RSU Equity Awards $ 13,230 $ 13,030 $ 14,322 
+Cash-Settled RSU Awards 6,412 ( 771 ) 1,021 
+Cash SARs 6,215 ( 3,344 ) 443 
+25,857 8,915 15,786 
+Less: amounts capitalized to oil and gas properties ( 12,934 ) ( 6,252 ) ( 4,704 ) 
+Total share-based compensation expense, net $ 12,923 $ 2,663 $ 11,082 
+87 
+Note 11 – Stockholders’ Equity 
+Second Lien Note Exchange 
+On November 3, 2021, at a special meeting of shareholders, the Company obtained the requisite shareholder approval for the issuance 
+of approximately 5.5 million shares of the Company’s common stock in exchange for an aggregate of $ 197.0 million principal amount of Second Lien Notes. The Exchange was completed on November 5, 2021 and the exchanged Second Lien Notes were immediately cancelled. See “Note 7 - Borrowings” for discussion of the exchange of Second Lien Notes for Company common stock. 
+Primexx Acquisition 
+During the fourth quarter of 2021, the Company issued approximately 9.0 million shares of common stock in connection with the Primexx Acquisition, inclusive of the shares of common stock issued to those certain interest owners who exercised their option to sell their interest in the properties included in the Primexx Acquisition. See “Note 4 - Acquisitions and Divestitures” for additional details. 
+November 2020 Warrants 
+The Company issued approximately 1.75 million November 2020 Warrants in conjunction with the November 2020 Second Lien Notes that were issued in the senior unsecured note exchange described above. The Company determined that the November 2020 Warrants qualify as freestanding financial instruments, but meet the scope exception in ASC 815 - Derivatives and Hedging as they are indexed to the Company’s common stock. As such, the November 2020 Warrants meet the applicable criteria for equity classification and are reflected in additional paid in capital in the consolidated balance sheets. See “Note 7 - Borrowings” for additional information. 
+Warrant Exercises 
+During the year ended December 31, 2021, holders of the September 2020 Warrants and November 2020 Warrants provided notice and exercised all outstanding warrants. As a result of the exercises, the Company issued a total of 6.9 million shares of its common stock in exchange for 9.0 million outstanding warrants determined on a net shares settlement basis. See “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” for additional details regarding the September 2020 Warrants. As of December 31, 2021, no September 2020 or November 2020 Warrants were outstanding. 
+Increase in Authorized Common Shares 
+The Company filed an amendment to its certificate of incorporation, which became effective on May 14, 2021, to increase the number 
+of authorized shares of common stock from 52,500,000 to 78,750,000 , as approved by the Company’s shareholders at the 2021 Annual Meeting of Shareholders on May 14, 2021. 
+Reverse Stock Split 
+On August 7, 2020, the Board of Directors effected a reverse stock split of the Company’s outstanding shares of common stock at a ratio of 1-for-10 and proportionately reduced the total number of authorized shares from 525,000,000 to 52,500,000 shares. All share and per share amounts, except par value per share, in the consolidated financial statements and notes in the 2020 Annual Report on Form 10-K were retroactively adjusted for all periods presented to give effect to this reverse stock split. 
+10 % Series A Cumulative Preferred Stock (“Preferred Stock”) 
+On July 18, 2019, all outstanding shares of Preferred Stock were redeemed at a total redemption price of $ 73.0 million. The Company recognized an $ 8.3 million loss on the redemption due to the excess of the $ 73.0 million redemption price over the $ 64.7 million redemption date carrying value of the Preferred Stock. 
+88 
+Note 12 – Income Taxes 
+The components of the Company’s income tax expense are as follows: 
+Years Ended December 31, 
+2021 2020 2019 
+(In thousands) 
+Current 
+Federal $ — $ — $ — 
+State 180 3,447 220 
+Total current income tax expense 180 3,447 220 
+Deferred 
+Federal — 126,903 33,584 
+State — ( 8,296 ) 1,497 
+Total deferred income tax expense — 118,607 35,081 
+Total income tax expense $ 180 $ 122,054 $ 35,301 
+A reconciliation of the income tax expense calculated at the federal statutory rate of 21 % to income tax expense is as follows: 
+Years Ended December 31, 
+2021 2020 2019 
+(In thousands) 
+Income (loss) before income taxes $ 365,331 ($ 2,411,567 ) $ 103,229 
+Income tax expense (benefit) computed at the statutory federal income tax rate 76,720 ( 506,429 ) 21,678 
+State income tax expense (benefit), net of federal benefit 2,905 ( 11,827 ) 1,253 
+Non-deductible expenses related to capital structure transactions ( 11,875 ) — — 
+Non-deductible compensation 1,100 — 90 
+Equity based compensation 564 2,746 1,222 
+Non-deductible merger expenses — — 5,537 
+Statutory depletion carryforward — — 5,381 
+Other 9,147 ( 1,621 ) 140 
+Change in valuation allowance ( 78,381 ) 639,185 — 
+Income tax expense $ 180 $ 122,054 $ 35,301 
+The income tax expense of $ 0.2 million for the year ended December 31, 2021 is primarily due to the valuation allowance recorded against the Company’s net deferred tax assets. See “— Deferred Tax Asset Valuation Allowance” below for additional details. 
+89 
+As of December 31, 2021 and 2020, the net deferred income tax assets and liabilities are comprised of the following: 
+As of December 31, 
+2021 2020 
+(In thousands) 
+Deferred tax assets 
+Oil and natural gas properties $ 238,203 $ 431,142 
+Federal net operating loss carryforward 221,900 141,308 
+Net interest expense limitation 36,171 — 
+Derivative asset 30,826 39,378 
+Operating lease right-of-use assets 8,650 8,567 
+Asset retirement obligations 12,244 10,134 
+Unvested RSU equity awards 4,939 1,962 
+Other 12,892 11,430 
+Total deferred tax assets $ 565,825 $ 643,921 
+Deferred income tax valuation allowance ( 560,804 ) ( 639,185 ) 
+Net deferred tax assets $ 5,021 $ 4,736 
+Deferred tax liability 
+Operating lease liabilities ($ 5,021 ) ($ 4,736 ) 
+Total deferred tax liability ($ 5,021 ) ($ 4,736 ) 
+Net deferred tax asset (liability) $ — $ — 
+Deferred Tax Asset Valuation Allowance 
+Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that the Company’s net deferred tax assets will be utilized prior to their expiration. A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and a net deferred tax asset position at December 31, 2021, driven primarily by the impairments of evaluated oil and gas properties recognized beginning in the second quarter of 2020 and continuing through the fourth quarter of 2020. This limits the ability to consider other subjective evidence such as the Company’s potential for future growth. Since the second quarter of 2020, based on the evaluation of the evidence available, the Company concluded that it is more likely than not that the net deferred tax assets will not be realized. As of December 31, 2021, the valuation allowance balance is $ 560.8 million, reducing the net deferred tax assets to zero . 
+The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until the Company can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead the Company to conclude that it is more likely than not its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in crude oil prices, and taxable events that could result from one or more future potential transactions. The valuation allowance does not preclude the Company from utilizing the tax attributes if the Company recognizes taxable income. As long as the Company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, the Company will have no significant deferred income tax expense or benefit. 
+Federal Net Operating Losses (“NOLs”) & Interest Limitation Carryforwards 
+Due to the issuance of common stock associated with the Carrizo Acquisition, the Company incurred a cumulative ownership change and as such, the Company’s NOLs prior to the acquisition are subject to an annual limitation under Internal Revenue Code Section 382. At December 31, 2021, the Company had approximately $ 1.1 billion of NOLs of which $ 414.9 million expire between 2035 and 2037 and $ 641.8 million have an indefinite carryforward life. The Company also has a net interest expense carryforward of $ 172.2 million under Section 163(j) of the Code, subject to indefinite carryforward. 
+Uncertain Tax Positions 
+The Company had no significant unrecognized tax benefits at December 31, 2021. Accordingly, the Company does not have any interest or penalties related to uncertain tax positions. However, if interest or penalties were to be incurred related to uncertain tax positions, such amounts would be recognized in income tax expense. In the Company’s major tax jurisdictions, the earliest year open to examination is 2017. 
+Note 13 – Leases 
+The Company currently has leases associated with contracts for office space, drilling rigs, and the use of well equipment, vehicles, information technology infrastructure, and other office equipment. The tables below, which present the components of lease costs and 
+90 
+supplemental balance sheet information are presented on a gross basis. Other joint owners in the properties operated by the Company generally pay for their working interest share of costs associated with drilling rigs and well equipment. 
+The table below presents the components of the Company’s lease costs for the year ended December 31, 2021. 
+Years Ended December 31, 
+2021 2020 2019 
+(In thousands) 
+Components of Lease Costs 
+Finance lease costs $ 277 $ 1,489 $ 92 
+Amortization of right-of-use assets (1) 
+237 1,348 82 
+Interest on lease liabilities (2) 
+40 141 10 
+Operating lease cost (3) 
+37,734 46,888 38,076 
+Impairment of Operating lease ROU assets (4) 
+— 3,575 16,209 
+Short-term lease cost (5) 
+347 1,821 3,640 
+Variable lease costs (6) 
+284 259 — 
+Total lease costs $ 38,642 $ 54,032 $ 58,017 
+(1) Included as a component of “Depreciation, depletion and amortization” in the consolidated statements of operations. 
+(2) Included as a component of “Interest expense, net of capitalized amounts” in the consolidated statements of operations. 
+(3) For the years ended December 31, 2021, 2020 and 2019, approximately $ 23.0 million, $ 34.2 million and $ 34.9 million, respectively, are costs associated with drilling rigs. These costs were capitalized to “Evaluated properties, net” in the consolidated balance sheets and the other remaining operating lease costs were components of “General and administrative” and “Lease operating” in the consolidated statements of operations. 
+(4) As a result of the downturn in economic conditions in conjunction with the Company’s ongoing effort to consolidate various office locations due to the Carrizo Acquisition, the Company evaluated certain of its office leases for impairment. Upon evaluation, the Company recorded impairments of certain of its Operating lease ROU assets for the years ended December 31, 2021, 2020 and 2019 of zero , $ 3.6 million and $ 16.2 million, respectively, which are a component of “Merger and integration expenses” in the consolidated statements of operations. 
+(5) Short-term lease cost excludes expenses related to leases with a contract term of one month or less. 
+(6) Variable lease costs include additional payments that were not included in the initial measurement of the lease liability and related ROU asset for lease agreements with terms greater than 12 months. Variable lease costs primarily consist of incremental usage associated with drilling rigs. 
+The table below presents supplemental balance sheet information for the Company’s operating leases. The Company’s financing leases are immaterial. 
+As of December 31, 
+2021 2020 
+(In thousands) 
+Leases 
+Operating leases: 
+Operating lease ROU assets $ 23,884 $ 22,526 
+Current operating lease liabilities $ 17,599 $ 13,175 
+Long-term operating lease liabilities 23,547 27,576 
+Total operating lease liabilities $ 41,146 $ 40,751 
+The table below presents the weighted average remaining lease terms and weighted average discounts rates for the Company’s leases as of December 31, 2021. 
+December 31, 2021 
+Weighted Average Remaining Lease Terms (In years) 
+Operating leases 5.1 
+Financing leases 2.2 
+Weighted Average Discount Rate 
+Operating leases 5.6 % 
+Financing leases 6.6 % 
+91 
+The table below presents the maturity of the Company’s lease liabilities as of December 31, 2021. 
+Operating Leases Financing Leases 
+(In thousands) 
+2022 $ 18,981 $ 250 
+2023 5,031 233 
+2024 4,939 39 
+2025 3,958 — 
+2026 3,805 — 
+Thereafter 10,334 — 
+Total lease payments 47,048 522 
+Less imputed interest ( 5,902 ) ( 36 ) 
+Total lease liabilities $ 41,146 $ 486 
+Note 14 – Asset Retirement Obligations 
+The table below summarizes the activity for the Company’s asset retirement obligations: 
+Years Ended December 31, 
+2021 2020 
+(In thousands) 
+Asset retirement obligations, beginning of period $ 59,090 $ 49,733 
+Accretion expense 3,743 3,323 
+Liabilities incurred 1,826 3,895 
+Increase due to acquisition of oil and gas properties 1,898 — 
+Liabilities settled ( 1,769 ) ( 2,220 ) 
+Dispositions ( 7,262 ) ( 351 ) 
+Revisions to estimates ( 819 ) 4,710 
+Asset retirement obligations, end of period 56,707 59,090 
+Less: Current asset retirement obligations ( 2,249 ) ( 1,881 ) 
+Non-current asset retirement obligations $ 54,458 $ 57,209 
+Certain of the Company’s operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded on the consolidated balance sheets at December 31, 2021 and 2020 as long-term restricted investments were $ 3.5 million , and are presented in “Other assets, net.” These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties. 
+Note 15 – Accounts Receivable, Net 
+As of December 31, 
+2021 2020 
+(In thousands) 
+Oil and natural gas receivables $ 171,837 $ 100,257 
+Joint interest receivables 13,751 11,530 
+Other receivables 49,053 24,191 
+Total 234,641 135,978 
+Allowance for credit losses ( 2,205 ) ( 2,869 ) 
+Total accounts receivable, net $ 232,436 $ 133,109 
+Note 16 – Accounts Payable and Accrued Liabilities 
+As of December 31, 
+2021 2020 
+(In thousands) 
+Accounts payable $ 151,836 $ 101,231 
+Revenues and royalties payable 294,143 162,762 
+Accrued capital expenditures 64,412 32,493 
+Accrued interest 59,600 45,033 
+Total accounts payable and accrued liabilities $ 569,991 $ 341,519 
+92 
+Note 17 – Commitments and Contingencies 
+The Company is involved in various claims and lawsuits incidental to its business. In the opinion of management, the ultimate liability hereunder, if any, will not have a material adverse effect on the financial position or results of operations of the Company. 
+The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment are not expected to have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies hereunder, and claims for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities. 
+The table below presents total minimum commitments associated with long-term, non-cancelable leases, drilling rig contracts and gathering, processing and transportation service agreements, which require minimum volumes of oil, natural gas, or produced water to be delivered, as of December 31, 2021. 
+2022 2023 2024 2025 2026 2027 and 
+Thereafter Total 
+(In thousands) 
+Operating leases (1) 
+$ 5,482 $ 5,031 $ 4,939 $ 3,958 $ 3,805 $ 10,334 $ 33,549 
+Drilling rig and frac service commitments (2) 
+53,473 — — — — — 53,473 
+Delivery commitments (3) 
+11,004 11,607 12,516 12,482 12,482 27,187 87,278 
+Produced water disposal commitments (4) 
+14,447 9,664 8,532 4,509 569 113 37,834 
+Total $ 84,406 $ 26,302 $ 25,987 $ 20,949 $ 16,856 $ 37,634 $ 212,134 
+(1) Operating leases primarily consist of contracts for office space. 
+(2) Drilling rig and frac service commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will generally be billed for their working interest share of such costs. 
+(3) Delivery commitments represent contractual obligations the Company has entered into for certain gathering, processing and transportation service agreements which require minimum volumes of oil or natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any oil or natural gas. 
+(4) Produced water disposal commitments represent contractual obligations the Company has entered into for certain service agreements which require minimum volumes of produced water to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water. 
+Operating Leases 
+As of December 31, 2021, the Company had contracts for six horizontal drilling rigs. The contract terms will end on various dates between January 2022 and November 2022. 
+Other Commitments 
+The following table includes the Company’s current oil sales contracts and firm transportation agreements as of December 31, 2021: 
+Type of Commitment (1) 
+Region Execution Date Start Date End Date Committed 
+Volumes (Bbls/d) 
+Oil sales contract Permian October 2021 January 2022 December 2022 7,500 
+Oil sales contract Permian July 2019 August 2021 July 2026 5,000 
+Oil sales contract Permian June 2019 January 2020 December 2024 10,000 
+Oil sales contract Permian August 2018 April 2020 March 2022 15,000 
+Firm transportation agreement (2)(3) 
+Permian June 2019 August 2020 July 2030 10,000 
+Firm transportation agreement (2) 
+Permian August 2018 April 2020 March 2027 15,000 
+(1) For each of the commitments shown in the table above, the committed barrels may include volumes produced by the Company and other third-party working, royalty, and overriding royalty interest owners whose volumes the Company markets on their behalf. 
+(2) Each of the firm transportation agreements shown in the table above grant the Company access to delivery points in several locations along the Gulf Coast. 
+(3) The committed volumes shown in the table above for this particular firm transportation agreement are average volumes. For the terms of August 2020-July 2023, August 2023-July 2027 and August 2027-July 2030, the committed volumes are 7,500 Bbls/d, 10,000 Bbls/d and 12,500 Bbls/d, respectively. 
+93 
+Note 18 - Supplemental Information on Oil and Natural Gas Operations (Unaudited) 
+Estimated Reserves 
+For each year in the table below, the estimated proved reserves were prepared by DeGolyer and MacNaughton (“D&M”), Callon’s independent third party reserve engineers, with the exception of the estimated proved reserves in 2019 obtained as a result of the Carrizo Acquisition, which were prepared by Ryder Scott Company, L.P. (“Ryder Scott”), the independent third party reserve engineers historically retained by Carrizo. The reserves were prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions. 
+There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only, and should not be deemed exact. In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company’s oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves. 
+Extrapolation of performance history and material balance estimates were utilized by the Company’s both D&M and Ryder Scott to project future recoverable reserves for the producing properties where sufficient history existed to suggest performance trends and where these methods were applicable to the subject reservoirs. The projections for the remaining producing properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to non-producing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production, and to a small extent, horizontal PDP and PUD categories. 
+The following tables disclose changes in the estimated quantities of proved reserves, all of which are located onshore within the continental United States: 
+Years Ended December 31, 
+Proved reserves 2021 2020 2019 
+Oil (MBbls) 
+Beginning of period 289,487 346,361 180,097 
+Purchase of reserves in place 35,045 — 183,382 
+Sales of reserves in place ( 24,019 ) ( 9,673 ) ( 17,980 ) 
+Extensions and discoveries 22,520 25,678 45,663 
+Revisions to previous estimates ( 10,514 ) ( 49,336 ) ( 33,136 ) 
+Production ( 22,223 ) ( 23,543 ) ( 11,665 ) 
+End of period 290,296 289,487 346,361 
+Natural Gas (MMcf) 
+Beginning of period 541,598 757,134 350,466 
+Purchase of reserves in place 73,445 — 455,158 
+Sale of reserves in place ( 34,837 ) ( 20,389 ) ( 86,856 ) 
+Extensions and discoveries 37,896 44,282 82,566 
+Revisions to previous estimates ( 3,389 ) ( 198,628 ) ( 24,482 ) 
+Production ( 37,386 ) ( 40,801 ) ( 19,718 ) 
+End of period 577,327 541,598 757,134 
+NGLs (MBbls) 
+Beginning of period 96,126 67,462 — 
+Purchase of reserves in place 10,366 — 67,597 
+Sale of reserves in place ( 6,191 ) ( 3,049 ) — 
+Extensions and discoveries 7,345 8,349 — 
+Revisions to previous estimates ( 3,103 ) 30,214 — 
+Production ( 6,439 ) ( 6,850 ) ( 135 ) 
+End of period 98,104 96,126 67,462 
+Total (MBoe) 
+Beginning of period 475,879 540,012 238,508 
+Purchase of reserves in place 57,652 — 326,838 
+Sale of reserves in place ( 36,015 ) ( 16,120 ) ( 32,456 ) 
+Extensions and discoveries 36,180 41,407 59,424 
+Revisions to previous estimates ( 14,181 ) ( 52,227 ) ( 37,216 ) 
+Production ( 34,894 ) ( 37,193 ) ( 15,086 ) 
+End of period 484,621 475,879 540,012 
+94 
+Years Ended December 31, 
+Proved developed reserves 2021 2020 2019 
+Oil (MBbls) 
+Beginning of period 128,923 152,687 92,202 
+End of period 162,886 128,923 152,687 
+Natural gas (MMcf) 
+Beginning of period 238,119 320,676 218,417 
+End of period 332,266 238,119 320,676 
+NGLs (MBbls) 
+Beginning of period 43,315 24,844 — 
+End of period 55,720 43,315 24,844 
+Total proved developed reserves (MBoe) 
+Beginning of period 211,925 230,977 128,605 
+End of period 273,983 211,925 230,977 
+Proved undeveloped reserves 
+Oil (MBbls) 
+Beginning of period 160,564 193,674 87,895 
+End of period 127,410 160,564 193,674 
+Natural gas (MMcf) 
+Beginning of period 303,479 436,458 132,049 
+End of period 245,061 303,479 436,458 
+NGLs (MBbls) 
+Beginning of period 52,811 42,618 — 
+End of period 42,384 52,811 42,618 
+Total proved undeveloped reserves (MBoe) 
+Beginning of period 263,954 309,035 109,903 
+End of period 210,638 263,954 309,035 
+Total proved reserves 
+Oil (MBbls) 
+Beginning of period 289,487 346,361 180,097 
+End of period 290,296 289,487 346,361 
+Natural gas (MMcf) 
+Beginning of period 541,598 757,134 350,466 
+End of period 577,327 541,598 757,134 
+NGLs (MBbls) 
+Beginning of period 96,126 67,462 — 
+End of period 98,104 96,126 67,462 
+Total proved reserves (MBoe) 
+Beginning of period 475,879 540,012 238,508 
+End of period 484,621 475,879 540,012 
+95 
+Total Proved Reserves 
+For the year ended December 31, 2021, the Company’s net increase in proved reserves of 8.7 MMBoe was primarily due to the following: 
+• Increase of 36.2 MMBoe through extensions and discoveries through our development efforts in our operating areas, of which 10.1 MMBoe were proved developed reserves; 
+• Decrease of 14.2 MMBoe for revisions of previous estimates that were primarily comprised of: 
+◦ 27.9 MMBoe increase primarily due to the change in 12-Month Average Realized Price of crude oil which increased by approximately 75 % as compared to December 31, 2020; offset by 
+◦ 29.0 MMBoe reduction due to PUDs that were removed primarily as a result of changes in anticipated well densities as we develop our properties in an effort to increase capital efficiency and cash flow generation as well as changes in our development plans, primarily due to the Primexx Acquisition, which resulted in PUDs being moved outside of the five-year development window; 
+◦ 13.1 MMBoe reduction due to reductions in anticipated hydrocarbon recoveries resulting from observed well performance over longer production timeframes during the testing of various full field development plan concepts. 
+• Increase of 57.7 MMBoe for purchase of reserves in place associated with the Primexx Acquisition; 
+• Decrease of 36.0 MMBoe for sales of reserves in place associated with the Western Delaware Basin, Eagle Ford, and Midland non-core asset sales; and 
+• Decrease of 34.9 MMBoe for production. 
+For the year ended December 31, 2020, the Company’s net decrease in proved reserves of 64.1 MMBoe was primarily due to the following: 
+• Increase of 41.4 MMBoe through extensions and discoveries through our development efforts in our operating areas, of which 11.7 MMBoe were proved developed reserves; 
+• Decrease of 52.2 MMBoe for revisions of previous estimates that were primarily comprised of: 
+◦ 26.2 MMBoe reduction due to the change in 12-Month Average Realized Price of crude oil which decreased by approximately 31 % as compared to December 31, 2019. Included in the decrease are 2.1 MMBoe associated with proved developed producing wells and 0.8 MMBoe associated with proved undeveloped wells that were no longer economic at December 31, 2020 as a result of the decrease in the 12-Month Average Realized Price of crude oil; 
+◦ 24.2 MMBoe reduction due to anticipated hydrocarbon recoveries resulting from observed well performance over longer production timeframes during the testing of various full field development plan concepts; 
+◦ 24.0 MMBoe reduction due to PUDs that were removed primarily as a result of changes in anticipated well densities as the Company develops its properties in an effort to increase capital efficiency and cash flow generation; 
+◦ 14.7 MMBoe increase due to the volumetric impact from presenting NGLs and natural gas separately due to the modification of certain of the Company’s natural gas processing agreements which allow it to take title to NGLs resulting from the processing of its natural gas subsequent to January 1, 2020. For periods prior to January 1, 2020, except for reserve volumes specifically associated with Carrizo, the Company presented its reserve volumes for NGLs with natural gas; 
+◦ 7.5 MMBoe increase due to reduced assumptions for operational expenses as the Company continues to improve its field practices during the integration of the properties acquired from Carrizo; 
+• Decrease of 16.1 MMBoe for sales of reserves in place primarily associated with the ORRI Transaction and the sale of substantially all of the Company’s non-operated assets; and 
+• Decrease of 37.2 MMBoe for production. 
+For the year ended December 31, 2019, the Company’s net increase in proved reserves of 301.5 MMBoe was primarily due to the following: 
+• Increase of 326.8 MMBoe for purchases of reserves in place related to the acquisition of Carrizo Oil & Gas, Inc. in late 2019; 
+• Increase of 59.4 MMBoe through extensions and discoveries through our development efforts in our operating areas, of which 17.1 MMBoe were proved developed reserves; 
+96 
+• Decrease of 32.5 MMBoe as a result of sales of reserves in place, primarily associated with our Ranger Divestiture which totaled 27.1 MMBoe; 
+• Decrease of 37.2 MMBoe for revisions of previous estimates that were primarily comprised of: 
+◦ 21.7 MMBoe reduction due to the observed impact of well spacing tests on producing wells and the related impact on PUD reserve estimates, primarily in the Midland Basin, as the Company advances larger scale development concepts across its multi-zone inventory; 
+◦ 9.8 MMBoe reduction due to reclassifications of PUDs within the Company’s development plans, primarily related to certain fields within the Company’s Delaware Basin acreage, that were moved outside of the five-year development window primarily driven by the acquisition of Carrizo Oil & Gas, Inc. in December 2019, which afforded us the opportunity to reallocate capital across the combined portfolio in an effort to increase capital efficiency through larger scale development concepts as well as preserve our co-development philosophy to optimize resource capture from multiple zones; 
+◦ 5.7 MMBoe reduction due to pricing; and 
+• Decrease of 15.1 MMBoe for production. 
+Capitalized Costs 
+Capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows: 
+As of December 31, 
+2021 2020 
+Oil and natural gas properties: (In thousands) 
+Evaluated properties $ 9,238,823 $ 7,894,513 
+Unevaluated properties 1,812,827 1,733,250 
+Total oil and natural gas properties 11,051,650 9,627,763 
+Accumulated depreciation, depletion, amortization and impairment ( 5,886,002 ) ( 5,538,803 ) 
+Total oil and natural gas properties capitalized $ 5,165,648 $ 4,088,960 
+Costs Incurred 
+Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows: 
+Years Ended December 31, 
+2021 2020 2019 
+Acquisition costs: (In thousands) 
+Evaluated properties $ 677,250 $ — $ 49,572 
+Unevaluated properties 301,404 30,696 107,347 
+Development costs 396,181 379,900 189,259 
+Exploration costs 137,989 122,865 309,013 
+Total costs incurred $ 1,512,824 $ 533,461 $ 655,191 
+Standardized Measure 
+The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2021. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Proved reserve estimates and future cash flows are based on the average realized prices for sales of oil, natural gas, and NGLs on the first calendar day of each month during the year. The following average realized prices were used in the calculation of proved reserves and the standardized measure of discounted future net cash flows. 
+Years Ended December 31, 
+2021 2020 2019 
+Oil ($/Bbl) $ 65.44 $ 37.44 $ 53.90 
+Natural gas ($/Mcf) $ 3.31 $ 1.02 $ 1.55 
+NGLs ($/Bbl) $ 29.19 $ 11.10 $ 15.58 
+97 
+Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10 % annual discount rate. 
+Standardized Measure 
+For the Year Ended December 31, 
+2021 2020 2019 
+(In thousands) 
+Future cash inflows $ 23,775,358 $ 12,458,033 $ 20,891,469 
+Future costs 
+Production ( 8,038,362 ) ( 5,433,496 ) ( 6,717,088 ) 
+Development and net abandonment ( 1,927,789 ) ( 2,204,301 ) ( 3,058,861 ) 
+Future net inflows before income taxes 13,809,207 4,820,236 11,115,520 
+Future income taxes ( 1,481,005 ) ( 65,405 ) ( 941,768 ) 
+Future net cash flows 12,328,202 4,754,831 10,173,752 
+10% discount factor ( 6,077,447 ) ( 2,444,441 ) ( 5,222,726 ) 
+Standardized measure of discounted future net cash flows $ 6,250,755 $ 2,310,390 $ 4,951,026 
+Changes in Standardized Measure 
+For the Year Ended December 31, 
+2021 2020 2019 
+(In thousands) 
+Standardized measure at the beginning of the period $ 2,310,390 $ 4,951,026 $ 2,941,293 
+Sales and transfers, net of production costs ( 1,466,413 ) ( 649,781 ) ( 579,744 ) 
+Net change in sales and transfer prices, net of production costs 4,336,078 ( 2,719,579 ) ( 387,970 ) 
+Net change due to purchases of in place reserves 797,327 — 2,975,296 
+Net change due to sales of in place reserves ( 105,376 ) ( 202,928 ) ( 303,526 ) 
+Extensions, discoveries, and improved recovery, net of future production and development costs incurred 583,976 250,759 607,146 
+Changes in future development cost ( 81,480 ) 361,008 205,398 
+Previously estimated development costs incurred 209,078 318,470 134,037 
+Revisions of quantity estimates ( 104,572 ) ( 671,800 ) ( 420,488 ) 
+Accretion of discount 234,495 536,958 314,921 
+Net change in income taxes ( 765,956 ) 383,999 ( 210,641 ) 
+Changes in production rates, timing and other 303,208 ( 247,742 ) ( 324,696 ) 
+Aggregate change 3,940,365 ( 2,640,636 ) 2,009,733 
+Standardized measure at the end of period $ 6,250,755 $ 2,310,390 $ 4,951,026 
+ITEM 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure 
+None. 
+ITEM 9A. Controls and Procedures 
+Disclosure Controls and Procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) performed an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2021. 
+Changes in Internal Control Over Financial Reporting . There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting. 
+Management’s Report on Internal Control Over Financial Reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. GAAP. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an 
+98 
+evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2021 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission (2013 framework) (the COSO criteria). Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2021. 
+Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+The Company’s independent registered public accounting firm, Grant Thornton, LLP, has issued an attestation report regarding its assessment of the Company’s internal control over financial reporting as of December 31, 2021, presented preceding the Company’s financial statements included in Part II, Item 8 of this 2021 Annual Report on Form 10-K. 
+ITEM 9B. Other Information 
+None. 
+ITEM 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections 
+Not applicable. 
+PART III. 
+ITEM 10. Directors, Executive Officers and Corporate Governance 
+The information required by this item is incorporated herein by reference to the definitive proxy statement (the “2022 Proxy Statement”) for our 2022 annual meeting of shareholders. The 2022 Proxy Statement will be filed with the SEC not later than 120 days subsequent to December 31, 2021. 
+The Company has adopted a code of ethics that applies to the Company’s officers, directors, employees, agents and representatives and includes a code of ethics for senior financial officers that applies to the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer. The full text of such code of ethics has been posted on the Company’s website at www.callon.com. 
+ITEM 11. Executive Compensation 
+The information required by this item is incorporated herein by reference to the 2022 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2021. 
+ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+The information required by this item is incorporated herein by reference to the 2022 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2021. 
+ITEM 13. Certain Relationships and Related Transactions and Director Independence 
+The information required by this item is incorporated herein by reference to the 2022 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2021. 
+ITEM 14. Principal Accountant Fees and Services 
+The information required by this item is incorporated herein by reference to the 2022 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2021. 
+99 
+PART IV. 
+ITEM 15. Exhibits and Financial Statement Schedules 
+(a) Documents filed as part of this 2021 Annual Report on Form 10-K: 
+(1) Financial Statements 
+See index to Financial Statements and Supplementary Data on page 56 . 
+(2) Financial Statement Schedules 
+All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto. 
+(3) Exhibits 
+Incorporated by reference (File No. 001-14039, unless otherwise indicated) 
+Exhibit Number Description Form Exhibit Filing 
+Date 
+2.1 (d) 
+Purchase and Sale Agreement between Callon Petroleum Operating Company and Sequitur Permian, LLC dated April 8, 2019 
+8-K 2.1 06/13/2019 
+2.2 (d) 
+Agreement and Plan of Merger, dated as of July 14, 2019, by and between Callon Petroleum Company and Carrizo Oil & Gas, Inc. 
+8-K 2.1 07/15/2019 
+2.3 
+Amendment No. 1 to Agreement and Plan of Merger, dated August 19, 2019, by and between Callon Petroleum Company and Carrizo Oil & Gas, Inc. 
+10-Q 2.2 11/05/2019 
+2.4 
+Amendment No. 2 to Agreement and Plan of Merger, dated November 13, 2019, by and between Callon Petroleum Company and Carrizo Oil & Gas, Inc. 
+8-K 2.1 11/14/2019 
+3.1 
+Certificate of Incorporation of the Company, as amended through May 12, 2016 
+10-Q 3.1 11/03/2016 
+3.2 
+Certificate of Amendment to the Certificate of Incorporation of Callon, effective December 20, 2019 
+8-K 3.1 12/20/2019 
+3.3 
+Certificate of Amendment to the Certificate of Incorporation of Callon, effective August 7, 2020 
+8-K 3.1 08/07/2020 
+3.4 
+Certificate of Amendment to the Certificate of Incorporation of Callon, effective May 14 , 202 1 
+8-K 3.1 05/14/2021 
+3.5 
+Amended and Restated Bylaws of the Company 
+10-K 3.2 02/27/2019 
+4.1 
+Specimen Common Stock Certificate 
+10-K 4.1 02/28/2018 
+4.2 
+Description of Common Stock 
+10-K 4.2 02/25/2021 
+4.3 
+Indenture of 6.125% Senior Notes Due 2024, dated as of October 3, 2016, among Callon Petroleum Company, the Guarantors party thereto and U.S. Bank National Association, as Trustee 
+8-K 4.1 10/04/2016 
+4.4 
+First Supplemental Indenture, dated December 20, 2019, among Callon, the Guarantors named therein and U.S. Bank National Association, as trustee 
+8-K 4.3 12/20/2019 
+4.5 
+Registration Rights Agreement of 6.125% Senior Notes Due 2024, dated October 3, 2016, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P. Morgan Securities LLC, as representative of the Initial Purchasers named on Annex E thereto 
+8-K 4.2 10/04/2016 
+4.6 
+Registration Rights Agreement of 6.125% Senior Notes Due 2024, dated May 24, 2017, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P. Morgan Securities LLC, as representative of the Initial Purchasers named on Annex E thereto 
+8-K 4.1 05/24/2017 
+4.7 
+Indenture of 6.375% Senior Notes Due 2026, dated as of June 7, 2018, among Callon Petroleum Company, the Guarantors party thereto and U.S. Bank National Association, as Trustee 
+8-K 4.1 06/07/2018 
+4.8 
+First Supplemental Indenture, dated December 20, 2019, among Callon, the Guarantors named therein and U.S. Bank National Association, as trustee 
+8-K 4.4 12/20/2019 
+4.9 
+Registration Rights Agreement of 6.375% Senior Notes Due 2026, dated June 7, 2018, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P. Morgan Securities LLC, as representative of the Initial Purchasers named on Annex E thereto 
+8-K 4.2 06/07/2018 
+4.10 
+Indenture, dated May 28, 2008, among Carrizo Oil & Gas, Inc., the subsidiaries named therein and Wells Fargo Bank, National Association, as trustee 
+8-K(File No. 000-29187-87) 4.1 05/28/2008 
+4.11 
+Eighteenth Supplemental Indenture, dated May 20, 2015, among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee 
+8-K(File No. 000-29187-87) 4.2 05/22/2015 
+4.12 
+Twentieth Supplemental Indenture, dated July 14, 2017, among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee 
+8-K(File No. 000-29187-87) 4.2 07/14/2017 
+4.13 
+Twenty-First Supplemental Indenture, dated December 20, 2019, among Callon, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee 
+8-K 4.1 12/20/2019 
+4.14 
+Twenty-Second Supplemental Indenture, dated December 20, 2019, among Callon, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee 
+8-K 4.2 12/20/2019 
+100 
+4.15 
+Warrant Agreement, dated as of December 20, 2019, between Callon and American Stock Transfer And Trust Company, LLC, as warrant agent 
+8-K 4.5 12/20/2019 
+4.16 
+Indenture, dated as of July 6, 2021, by and among the Company, Callon Petroleum Operating Company, Callon (Eagle Ford) LLC, Callon (Niobrara) LLC, Callon (Permian) LLC, Callon (Permian) Minerals LLC, Callon (Utica) LLC, Callon Marcellus Holding, Inc. and U.S. Bank National Association, as trustee 
+8-K 4.1 07/07/2021 
+4.17 (a) 
+Registration Rights Agreement among Callon Petroleum Company, Callon Petroleum Operating Company and Primexx Resource Development, LLC, dated October 1, 2021 
+4.18 (a) 
+Registration Rights Agreement among Callon Petroleum Company, Callon Petroleum Operating Company and BPP Acquisition, LLC, dated October 1, 2021 
+4.19 
+Registration Rights Agreement , by and between the Company and Chambers Investment, LLC, dated November 5, 2021 
+8-K 4.1 11/08/2021 
+10.1 (d) 
+Credit Agreement, dated December 20, 2019, among Callon, JPMorgan Chase Bank, National Association, as administrative agent, and the lenders party thereto 
+8-K 10.1 12/20/2019 
+10.2 (d) 
+First Amendment to Credit Agreement among Callon, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and the lender parties thereto, dated May 7, 2020 
+10-Q 10.1 05/11/2020 
+10.3 
+Second Amendment to Credit Agreement among Callon, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and the lender parties thereto, dated September 30, 2020 
+8-K 10.2 10/01/2020 
+10.4 
+Third Amendment to Credit Agreement among Callon, JPMorgan Chase Bank, N.A., as administrative agent, the guarantors party thereto and the lender parties thereto, dated September 30, 2020 
+8-K 10.3 10/01/2020 
+10.5 
+Fourth Amendment , dated May 3, 2021, to the Credit Agreement by and between Callon Petroleum Company and JP Morgan Chase Bank, N.A., as administrative agent, and the lender parties thereto 
+10-Q 10.6 05/06/2021 
+10.6 
+F if th Amendment, dated November 1 , 2021, to the Credit Agreement by and between Callon Petroleum Company and JPMorgan Chase Bank, N.A., as administrative agent, and the lender parties thereto 
+10-Q 10.3 11/04/2021 
+10.7 (b) 
+Amended and Restated Deferred Compensation Plan for Outside Directors - Callon Petroleum Company, dated as of May 10, 2017 and effective as of May 1, 2017 
+10-K 10.11 02/28/2018 
+10.8 (b) 
+Callon Petroleum Company 2018 Omnibus Incentive Plan 
+DEF 14A A 03/23/2018 
+10.9 (b) 
+Amended and Restated 2018 Omnibus Incentive Plan 
+10-K 10.7 02/27/2020 
+10.10 (b) 
+Form of Callon Petroleum Company Officer Restricted Stock Unit Award Agreement, adopted on January 31, 2019 under the 2018 Omnibus Incentive Plan 
+10-K 10.23 02/27/2019 
+10.11 (b) 
+Form of Callon Petroleum Company Officer Cash-Settleable Performance Share Award Agreement, adopted on January 31, 2020 under the Amended & Restated 2018 Omnibus Incentive Plan 
+10-K 10.23 02/27/2020 
+10.12 (b) 
+Form of Callon Petroleum Company Officer Stock-Settleable Performance Share Award Agreement, adopted on January 31, 2020 under the Amended & Restated 2018 Omnibus Incentive Plan 
+10-K 10.24 02/27/2020 
+10.13 (b) 
+Form of Callon Petroleum Company Officer Restricted Stock Unit Award Agreement, adopted on January 31, 2020 under the Amended & Restated 2018 Omnibus Incentive Plan 
+10-K 10.25 02/27/2020 
+10.14 (b) 
+Callon Petroleum Company 2020 Omnibus Incentive Plan 
+DEF 14A B 04/28/2020 
+10.15 (b) 
+First Amendment to Callon Petroleum Company 2020 Omnibus Incentive Plan 
+8-K 10.5 04/16/2021 
+10.16 (b) 
+Form of Callon Petroleum Company Employee Restricted Stock Unit Award Agreement, adopted on June 8, 2020, under the 2020 Omnibus Incentive Plan 
+10-Q 10.3 08/05/2020 
+10.17 (b) 
+Form of Callon Petroleum Company Director Restricted Stock Unit Award Agreement, adopted on June 8, 2020, under the 2020 Omnibus Incentive Plan 
+10-Q 10.4 08/05/2020 
+10.18 (b) 
+Form of Callon Petroleum Company Officer Cash Retention Award Agreement, adopted on September 30, 2020, under the 2020 Omnibus Incentive Plan 
+10-Q 10.4 11/03/2020 
+10.19 (b) 
+Form of Callon Petroleum Company Officer Cash Incentive Award Agreement, adopted on September 30, 2020, under the 2020 Omnibus Incentive Plan 
+10-Q 10.5 11/03/2020 
+10.20 (b) 
+Deferred Compensation Plan for Outside Directors, as Amended and Restated as of January 1, 2021 
+10-K 10.29 02/25/2021 
+10.21 (b) 
+Form of Callon Petroleum Company Restricted Stock Unit Award Agreement, adopted on March 12 , 20 21 under the 20 20 Omnibus Incentive Plan 
+8-K 10.1 04/16/2021 
+10.22 (b) 
+Form of Callon Petroleum Company Cash Performance Unit Award Agreement, adopted on March 12, 2021 under the 2020 Omnibus Incentive Plan 
+8-K 10.2 04/16/2021 
+10.23 (b) 
+Form of Change in Control Severance Compensation Agreement, dated as of April 16 , 2021 , by and between Callon Petroleum Company and its executive officers 
+8-K 10.3 04/16/2021 
+10.24 (b) 
+Change in Control Severance Compensation Agreement, dated as of April 16, 2021, by and between Callon Petroleum Company and Joseph C. Gatto, Jr. 
+8-K 10.4 04/16/2021 
+10.25 (b) 
+Separation Agreement, dated July 22 , 2021, by and between J ames “ Jim ” Ulm, II and Callon Petroleum Company 
+10-Q 10.1 11/04/2021 
+10.26 (b) 
+Consulting Agreement, dated July 22, 2021, by and between James “Jim” Ulm, II and Callon Petroleum Company 
+10-Q 10.2 11/04/2021 
+101 
+10.27 
+Purchase Agreement, dated as of June 21, 2021, among Callon Petroleum Company , the Guarantors and BofA Securities, Inc., as representative of the several initial purchasers 
+8-K 10.1 06/22/2021 
+10.28 
+Exchange Agreement, among the Company and Chambers Investments, LLC , dated August 3, 2021 
+8-K 10.1 08/05/2021 
+10.29 
+F orm of Voting Agreement between the Company and the executive officer or director named therein, dated as of August 3, 2021 
+8-K 10.2 08/05/2021 
+10.30 
+Purchase and Sale Agreement by and among Callon Petroleum Company, Callon Petroleum Operating Company, and Primexx Resource Development, LLC dated August 3, 2021 
+8-K 10.1 08/05/2021 
+10.31 
+Purchase and Sale Agreement by and among Callon Petroleum Company, Callon Petroleum Operating Company, and BPP Acquisition, LLC dated August 3, 2021 
+8-K 10.2 08/05/2021 
+21.1 (a) 
+Subsidiaries of the Company 
+22.1 (a) 
+Subsidiary Guarantors 
+23.1 (a) 
+Consent of Grant Thornton LLP 
+23.2 (a) 
+Consent of DeGolyer and MacNaughton, Inc. 
+31.1 (a) 
+Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a) 
+31.2 (a) 
+Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a) 
+32.1 (c) 
+Section 1350 Certifications of Chief Executive and Financial Officers pursuant to Rule 13(a)-14(b) 
+99.1 (a) 
+Reserve Report Summary prepared by DeGolyer and MacNaughton, Inc. as of December 31, 2021 
+101.INS (a) XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. 
+101.SCH (a) Inline XBRL Taxonomy Extension Schema Document 
+101.CAL (a) Inline XBRL Taxonomy Extension Calculation Linkbase Document. 
+101.DEF (a) Inline XBRL Taxonomy Extension Definition Linkbase Document. 
+101.LAB (a) Inline XBRL Taxonomy Extension Label Linkbase Document. 
+101.PRE (a) Inline XBRL Taxonomy Extension Presentation Linkbase Document. 
+104 (a) Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. 
+(a) Filed herewith. 
+(b) Indicates management compensatory plan, contract, or arrangement. 
+(c) Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, except to the extent that the registrant specifically incorporates it by reference. 
+(d) Certain schedules and similar attachments have been omitted pursuant to Item 601(a)(5) of Regulation S-K. Callon agrees to furnish a supplemental copy of any omitted schedule or attachment to the SEC upon request. 
+ITEM 16. Form 10-K Summary 
+None. 
+102 
+SIGNATURES 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+Callon Petroleum Company 
+/s/ Kevin Haggard Date: February 24, 2022 
+By: Kevin Haggard 
+Chief Financial Officer (principal financial officer) 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+/s/ Joseph C. Gatto, Jr. Date: February 24, 2022 
+Joseph C. Gatto, Jr. (principal executive officer) 
+/s/ Kevin Haggard Date: February 24, 2022 
+Kevin Haggard (principal financial officer) 
+/s/ Gregory F. Conaway Date: February 24, 2022 
+Gregory F. Conaway (principal accounting officer) 
+/s/ L. Richard Flury Date: February 24, 2022 
+L. Richard Flury (chairman of the board of directors) 
+/s/ Frances Aldrich Sevilla-Sacasa Date: February 24, 2022 
+Frances Aldrich Sevilla-Sacasa (director) 
+/s/ Matthew R. Bob Date: February 24, 2022 
+Matthew R. Bob (director) 
+/s/ Barbara J. Faulkenberry Date: February 24, 2022 
+Barbara J. Faulkenberry (director) 
+/s/ Michael L. Finch Date: February 24, 2022 
+Michael L. Finch (director) 
+/s/ Larry D. McVay Date: February 24, 2022 
+Larry D. McVay (director) 
+/s/ Anthony J. Nocchiero Date: February 24, 2022 
+Anthony J. Nocchiero (director) 
+/s/ Mary Shafer-Malicki Date: February 24, 2022 
+Mary Shafer-Malicki (director) 
+/s/ James M. Trimble Date: February 24, 2022 
+James M. Trimble (director) 
+/s/ Steven A. Webster Date: February 24, 2022 
+Steven A. Webster (director) 
+103
\ No newline at end of file
diff --git a/raw/filings/0000928022/2021/0000928022-22-000027/filing_metadata.csv b/raw/filings/0000928022/2021/0000928022-22-000027/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..3f1f550850f78b6807f5ff239fa0cf13297814e6
--- /dev/null
+++ b/raw/filings/0000928022/2021/0000928022-22-000027/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000928022,CPE,Callon Petroleum Co,10-K,2022-02-24,2021-12-31,2022-02-24T21:10:31.000Z,0000928022-22-000027,cpe-20211231.htm,10-K,17556495,1,1,https://www.sec.gov/Archives/edgar/data/928022/000092802222000027/cpe-20211231.htm,https://www.sec.gov/Archives/edgar/data/928022/000092802222000027/,2021,2021,1
diff --git a/raw/filings/0000928022/2021/0000928022-22-000027/item1.txt b/raw/filings/0000928022/2021/0000928022-22-000027/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000928022/2021/0000928022-22-000027/item13.txt b/raw/filings/0000928022/2021/0000928022-22-000027/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..cf244990680a30b10692b3b296f919d46c180828
--- /dev/null
+++ b/raw/filings/0000928022/2021/0000928022-22-000027/item13.txt
@@ -0,0 +1,2 @@
+ITEM 13. Certain Relationships and Related Transactions and Director Independence 
+The information required by this item is incorporated herein by reference to the 2022 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2021.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2021/0000928022-22-000027/item9a.txt b/raw/filings/0000928022/2021/0000928022-22-000027/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e8b3e78eebdddb8898c43b53c24b9a04970e1d29
--- /dev/null
+++ b/raw/filings/0000928022/2021/0000928022-22-000027/item9a.txt
@@ -0,0 +1,8 @@
+ITEM 9A. Controls and Procedures 
+Disclosure Controls and Procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) performed an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2021. 
+Changes in Internal Control Over Financial Reporting . There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting. 
+Management’s Report on Internal Control Over Financial Reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. GAAP. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an 
+98 
+evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2021 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission (2013 framework) (the COSO criteria). Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2021. 
+Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+The Company’s independent registered public accounting firm, Grant Thornton, LLP, has issued an attestation report regarding its assessment of the Company’s internal control over financial reporting as of December 31, 2021, presented preceding the Company’s financial statements included in Part II, Item 8 of this 2021 Annual Report on Form 10-K.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2021/0000928022-22-000027/rp_note.txt b/raw/filings/0000928022/2021/0000928022-22-000027/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000928022/2021/0000928022-22-000027/rpt_disclosure.txt b/raw/filings/0000928022/2021/0000928022-22-000027/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..70a1350b4bb229db8124f489e140ddcd1a618d23
--- /dev/null
+++ b/raw/filings/0000928022/2021/0000928022-22-000027/rpt_disclosure.txt
@@ -0,0 +1,7 @@
+Certain Relationships and Related Party Transactions 
+The Audit Committee charter provides that the Audit Committee shall review and approve all related party transactions. A transaction will be considered a “related party transaction” if the transaction would be required to be disclosed under Item 404 of Regulation S-K. In addition, our Code provides that an officer’s or a director’s conflict of interest with Callon may only be waived if the Audit Committee approves the waiver and the full Board ratifies the waiver. 
+We are not aware of any related party transactions that require disclosure under Item 404 of Regulation S-K. 
+Shareholders’ Proposals and Director Nominations for the 2024 Annual Meeting 
+In order for a proposal to be considered for inclusion in the proxy statement for the 2024 Annual Meeting of Shareholders (the “2024 Annual Meeting”) pursuant to Rule 14a-8 of the Exchange Act, such proposal must be received by the Secretary of the Company at our principal executive office no later than November 13, 2023 (assuming the date of the 2024 Annual Meeting has not been changed by more than 30 days from the date of this year’s Annual Meeting), and must otherwise be in compliance with the requirements of the SEC’s proxy rules. If the date of the 2024 Annual Meeting is changed by more than 30 days from the date of this Annual Meeting, then the deadline is a reasonable time before we begin to print and send our proxy materials for the 2024 Annual Meeting. 
+For a shareholder proposal to be introduced for consideration at the 2024 Annual Meeting but not intended to be considered for inclusion in the Company's proxy statement and form of proxy relating to such meeting (i.e., not pursuant to Rule 14a-8 of the Exchange Act), including shareholder nominations for candidates for election as directors, a shareholder must provide written notice of such proposal to Company not later than 120 days nor earlier than 150 days before the date of the 2024 Annual Meeting. Any such notice must describe the shareholder proposal in reasonable detail and otherwise comply with the requirements set forth in our bylaws. In addition to satisfying the notice, informational and other requirements contained in our 
+bylaws, shareholders who intend to solicit proxies in support of director nominees other than the Company’s nominees must provide notice that sets forth the information required by Rule 14a-19 of the Exchange Act, which notice must be postmarked or
\ No newline at end of file
diff --git a/raw/filings/0000928022/2022/0000928022-23-000017/filing.txt b/raw/filings/0000928022/2022/0000928022-23-000017/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e367739879fcfec8766c2d1b8c8f9bdfc9356480
--- /dev/null
+++ b/raw/filings/0000928022/2022/0000928022-23-000017/filing.txt
@@ -0,0 +1,2514 @@
+cpe-20221231 
+0000928022 2022 FY FALSE P2Y P2Y http://fasb.org/us-gaap/2022#OtherAssetsNoncurrent http://fasb.org/us-gaap/2022#DerivativeLiabilitiesCurrent http://fasb.org/us-gaap/2022#DerivativeLiabilitiesNoncurrent http://fasb.org/us-gaap/2022#OtherAssetsNoncurrent http://fasb.org/us-gaap/2022#DerivativeLiabilitiesCurrent http://fasb.org/us-gaap/2022#DerivativeLiabilitiesNoncurrent 0.1 http://fasb.org/us-gaap/2022#OtherAssetsNoncurrent http://fasb.org/us-gaap/2022#OtherAssetsNoncurrent http://fasb.org/us-gaap/2022#OtherLiabilitiesCurrent http://fasb.org/us-gaap/2022#OtherLiabilitiesCurrent http://fasb.org/us-gaap/2022#OtherLiabilitiesNoncurrent http://fasb.org/us-gaap/2022#OtherLiabilitiesNoncurrent http://fasb.org/us-gaap/2022#OtherLiabilitiesNoncurrent 0000928022 2022-01-01 2022-12-31 0000928022 2022-06-30 iso4217:USD 0000928022 2023-02-17 xbrli:shares 0000928022 2022-12-31 0000928022 2021-12-31 iso4217:USD xbrli:shares 0000928022 us-gaap:OilAndGasExplorationAndProductionMember 2022-01-01 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+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+FORM 10-K 
+☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the fiscal year ended December 31 , 2022 
+or 
+☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the transition period from ____________ to ____________ 
+Commission File Number 001-14039 
+Callon Petroleum Co mpany 
+(Exact Name of Registrant as Specified in Its Charter) 
+_______________________________________________ 
+Delaware 64-0844345 
+State or Other Jurisdiction of 
+Incorporation or Organization I.R.S. Employer Identification No. 
+One Briarlake Plaza 
+2000 W. Sam Houston Parkway S., Suite 2000 
+Houston, Texas 77042 
+Address of Principal Executive Offices Zip Code 
+281 - 589-5200 
+(Registrant’s Telephone Number, Including Area Code) 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of Each Class Trading Symbol Name of Each Exchange on Which Registered 
+Common Stock, $0.01 par value CPE New York Stock Exchange 
+Securities registered pursuant to section 12(g) of the Act: None 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐ 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒ 
+Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ 
+Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐ 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act: 
+Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ☐ 
+Smaller reporting company ☐ Emerging growth company ☐ 
+If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ 
+Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ 
+If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐ 
+Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐ 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ 
+The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2022 was approximately $ 2.4 billion. 
+The registrant had 61,625,170 shares of common stock outstanding as of February 17, 2023 . 
+DOCUMENTS INCORPORATED BY REFERENCE 
+Portions of the definitive proxy statement of Callon Petroleum Company (to be filed no later than 120 days after December 31, 2022) relating to the 2023 Annual Meeting of Shareholders are incorporated into Part III of this Form 10-K. 
+TABLE OF CONTENTS 
+Special Note Regarding Forward - Looking Statements 
+3 
+Glossary of Certain Terms 
+3 
+Part I 
+Items 1 and 2. 
+Business and Properties 
+6 
+Proved Oil and Gas Reserves 
+8 
+Capital Budget 
+11 
+Drilling Activity 
+12 
+Productive Wells 
+12 
+Production Volumes, Average Sales Prices and Operating Costs 
+13 
+Major Customers 
+13 
+Leasehold Acreage 
+14 
+Human Capital 
+14 
+Other 
+15 
+Regulations 
+16 
+Commitments and Contingencies 
+24 
+Available Information 
+25 
+Item 1A. 
+Risk Factors 
+26 
+Item 1B. 
+Unresolved Staff Comments 
+44 
+Item 3. 
+Legal Proceedings 
+44 
+Item 4. 
+Mine Safety Disclosures 
+44 
+Part II 
+Item 5. 
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+45 
+Performance Graph 
+45 
+Item 6. 
+Reserved 
+47 
+Item 7. 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+47 
+General 
+47 
+Financial and Operational Highlights 
+47 
+Results of Operations 
+48 
+Liquidity and Capital Resources 
+52 
+Critical Accounting Estimates 
+54 
+Item 7A. 
+Quantitative and Qualitative Disclosures About Market Risk 
+55 
+Item 8. 
+Financial Statements and Supplementary Data 
+57 
+Reports of Independent Registered Public Accounting Firm 
+58 
+Consolidated Balance Sheets 
+61 
+Consolidated Statements of Operations 
+62 
+Consolidated Statements of Stockholders’ Equity 
+63 
+Consolidated Statements of Cash Flows 
+64 
+Notes to Consolidated Financial Statements 
+65 
+Supplemental Information on Oil and Natural Gas Operations (Unaudited) 
+88 
+Item 9. 
+Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+93 
+Item 9A. 
+Controls and Procedures 
+93 
+Item 9B. 
+Other Information 
+94 
+Item 9 C . 
+Disclosure Regarding Foreign Jurisdictions that Prevent Inspections 
+94 
+Part III 
+Item 10. 
+Directors, Executive Officers and Corporate Governance 
+94 
+Item 11. 
+Executive Compensation 
+94 
+Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+94 
+Item 13. 
+Certain Relationships and Related Transactions and Director Independence 
+94 
+Item 14. 
+Principal Accountant Fees and Services 
+94 
+Part IV. 
+Item 15. 
+Exhibits and Financial Statement Schedules 
+95 
+Item 16. 
+Form 10-K Summary 
+97 
+Signatures 
+98 
+2 
+SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS 
+This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements in this Form 10-K by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions. 
+All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future are forward-looking statements, including such things as: 
+• our oil and natural gas reserve quantities and the discounted present value of these reserves; 
+• the amount and nature of our capital expenditures; 
+• our future drilling and development plans and our potential drilling locations; 
+• the timing and amount of future capital and operating costs; 
+• production decline rates from our wells being greater than expected; 
+• commodity price risk management activities and the impact on our average realized prices; 
+• business strategies and plans of management; 
+• our ability to efficiently integrate recent acquisitions; and 
+• prospect development and property acquisitions. 
+We caution you that the forward-looking statements contained in this Annual Report on Form 10-K (this “2022 Annual Report on Form 10-K”) are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. We disclose these and other important factors that could cause our actual results to differ materially from our expectations under “Risk Factors” in Part I, Item 1A of this 2022 Annual Report on Form 10-K. 
+Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Additional risks or uncertainties that are not currently known to us, that we currently deem to be immaterial, or that could apply to any company could also materially adversely affect our business, financial condition, or future results. Any forward-looking statement speaks only as of the date of which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. 
+In addition, we caution that reserve engineering is a process of estimating oil and natural gas accumulated underground and cannot be measured exactly. Accuracy of reserve estimates depend on a number of factors including data available at the point in time, engineering interpretation of the data, and assumptions used by the reserve engineers as it relates to price and cost estimates and recoverability. New results of drilling, testing, and production history may result in revisions of previous estimates and, if significant, would impact future development plans. As such, reserve estimates may differ from actual results of oil and natural gas quantities ultimately recovered. 
+Except as required by applicable law, all forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. 
+GLOSSARY OF CERTAIN TERMS 
+All defined terms under Rule 4-10(a) of Regulation S-X shall have their prescribed meanings when used in this report. As used in this document: 
+• 12-Month Average Realized Price : Average realized prices for sales of oil, NGLs, and natural gas on the first calendar day of each month during a trailing 12-month period. 
+• ASU : Accounting standards update. 
+• Bbl or Bbls : Barrel or barrels of oil or NGLs. 
+• Boe : Barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of natural gas. The ratio of one barrel of oil or NGLs to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas and does not represent the economic equivalency of oil and NGLs to natural gas. 
+• Boe/d : Boe per day. 
+• Btu : British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit. 
+• Completion : The installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency. 
+3 
+• Development well : A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. 
+• EPA : United States Environmental Protection Agency. 
+• ESG: Environmental, social and governance. 
+• Exploratory well : A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. 
+• Extension well : A well drilled to extend the limits of a known reservoir. 
+• FASB : Financial Accounting Standards Board. 
+• GAAP : Accounting principles generally accepted in the United States. 
+• GHG : Greenhouse gases. 
+• Henry Hub : Natural gas pipeline delivery point that serves as the benchmark natural gas price underlying NYMEX natural gas futures contracts. 
+• Horizontal drilling : A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at an angle within a specified interval. 
+• HSC: Houston Ship Channel, a delivery point in Houston, Texas that serves as a benchmark price for natural gas. 
+• LIBOR : London Interbank Offered Rate. 
+• LOE : Lease operating expense. 
+• MBbls : Thousand barrels of oil. 
+• MBoe : Thousand Boe. 
+• Mcf : Thousand cubic feet of natural gas. 
+• MMBoe : Million Boe. 
+• MMBtu : Million Btu. 
+• MMcf : Million cubic feet of natural gas. 
+• NGL or NGLs : Natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams. 
+• Non-productive well : A well that is found to be incapable of producing oil or gas in sufficient quantities to justify completion, or upon completion, the economic operation of an oil or gas well. 
+• NYMEX : New York Mercantile Exchange. 
+• Oil : Includes crude oil and condensate. 
+• OPEC : Organization of Petroleum Exporting Countries. 
+• Productive well : A well that is found to be capable of producing oil or gas in sufficient quantities to justify completion as an oil or gas well. 
+• Proved developed producing reserves (“PDPs”): Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. 
+• Proved reserves: Those reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12‑month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. 
+• Proved undeveloped reserves (“PUDs”): Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. 
+• PV-10 (Non-GAAP): Present value of estimated future gross revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date indicated (unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure of discounted future net cash flows calculation, it does provide an indicative representation of the relative value of the Company on a comparative basis to other 
+4 
+companies from period to period. See “Items 1 and 2. Business and Properties — Proved Oil and Gas Reserves — Reconciliation of Standardized Measure of Discounted Future Net Cash Flows (GAAP) to PV-10 (Non-GAAP)”. 
+• Realized price : The cash market price less all expected quality, transportation and demand adjustments. 
+• Royalty interest : An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development. 
+• SEC : United States Securities and Exchange Commission. 
+• SOFR: Secured Overnight Financing Rate 
+• Waha : A natural gas delivery point in West Texas that serves as the benchmark for natural gas. 
+• Working interest : An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations. 
+• WTI : West Texas Intermediate grade crude oil, used as a pricing benchmark for sales contracts and NYMEX oil futures contracts. 
+With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross. 
+5 
+PART I. 
+ITEMS 1 and 2. Business and Properties 
+Overview 
+Callon Petroleum Company has been engaged in the exploration, development, acquisition and production of oil and natural gas properties since 1950. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. 
+We are an independent oil and natural gas company focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas. Our activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger Permian Basin in West Texas, as well as the Eagle Ford in South Texas. Our primary operations in the Permian reflect a high-return, oil-weighted drilling inventory with multiple prospective horizontal development intervals and are complemented by a well-established, cash flow-generating business in the Eagle Ford. 
+Major Developments in 2022 
+Financing and Liquidity Highlights 
+• Decreased our total outstanding long-term debt principal balance by approximately 17% to $2.3 billion as of December 31, 2022, from $2.7 billion as of December 31, 2021. 
+• On June 24, 2022, we issued $600.0 million in aggregate principal amount of 7.5% senior unsecured notes due 2030 (the “7.5% Senior Notes”) for proceeds of approximately $588.0 million, net of initial purchasers’ discounts and commissions. Also on June 24, 2022, we used the proceeds from the offering of the 7.5% Senior Notes, along with borrowings under our credit facility, to redeem all of our outstanding 6.125% Senior Notes due 2024 (the “6.125% Senior Notes”) and 9.0% Second Lien Senior Secured Notes due 2025 (the “Second Lien Notes”). 
+• On October 19, 2022, we entered into the Amended & Restated Credit Agreement (the “Credit Agreement” and the senior secured revolving credit facility thereunder, the “Credit Facility”) on substantially similar terms as those in the credit agreement governing our prior credit facility. The Credit Agreement, among other things, extended maturity until October 19, 2027, established a borrowing base of $2.0 billion, with an elected commitment amount of $1.5 billion, replaced all provisions and related definitions regarding LIBOR with a SOFR based benchmark rate, and decreased the maximum leverage ratio from 4.00 to 1.00 to 3.50 to 1.00. 
+• Reduced the borrowings outstanding under our Credit Facility from $785.0 million as of December 31, 2021 to $503.0 million as of December 31, 2022. 
+See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for further discussion. 
+Operational Activity. The following tables present our net daily production, as well as our operated drilling and completion activity for the year ended December 31, 2022 along with our drilled but uncompleted and producing wells as of December 31, 2022. 
+Permian Eagle Ford Total 
+Production volumes 
+Crude oil (Bbls/d) 49,427 15,338 64,765 
+Natural gas (Mcf/d) 97,313 16,733 114,046 
+NGLs (Bbls/d) 17,600 2,881 20,481 
+Total production volumes (Boe/d) 83,246 21,008 104,254 
+Percent of total production 80 % 20 % 100 % 
+Permian Eagle Ford Total 
+Operated Well Data Gross Net Gross Net Gross Net 
+Drilled 94 85.4 20 17.6 114 103.0 
+Completed 80 71.1 26 23.4 106 94.5 
+As of December 31, 2022 
+Drilled but uncompleted 34 32.0 — — 34 32.0 
+Producing 755 663.7 604 544.3 1,359 1,208.0 
+6 
+Our Business Strategy 
+Our strategy is to create value for our shareholders through the safe and capital-efficient development of our oil and gas properties, which we call our “Life of Field” co-development model. Our people work to safely reduce our operating costs, maximize our cash flows and empower the communities in which our people live and work. The key elements of our strategy include: 
+• We employ a “Life of Field” co-development model that enhances the value of our asset base and helps ensure capital efficiency, free cash flow generation, and ultimately long-term value creation. Utilizing our extensive database of subsurface information, we have demonstrated an ability to enhance returns today, while mitigating risks associated with future infill developments; 
+• We strive to create new capital efficiencies across the enterprise. Human, technology, and capital resources are carefully applied to our highest long-term return opportunities and our teams are incentivized to create value by safely lowering costs, improving well productivity and improving our returns on capital; 
+• We integrate sustainable business practices that aim to minimize our impact on the environment, empower and develop a diverse workforce, and enrich our communities; and 
+• We enhance our financial position, focus on appropriate capital allocation decisions under various commodity pricing scenarios, effectively manage risks to ensure cash flows to fund our development programs and maintain and improve our balance sheet. 
+Our Strengths 
+The following attributes position us to achieve our objectives: 
+• Oily Asset Portfolio – We have a deep inventory of high-quality drilling locations in the Permian and Eagle Ford with a high percentage of oil and liquids hydrocarbons. The plays are located in Texas, which has a regulatory environment that encourages the timely development of the state’s natural resources. In addition, our developments are located in proximity to infrastructure and price-advantaged markets along the Texas Gulf Coast; 
+• Proven Operator with a History of Maximizing Value – We are stewards of the resource and believe our “Life of Field” co-development model has been a differentiator in the industry. We believe it optimizes the long-term value of our inventory, mitigates future degradation risks associated with infill drilling and generates capital efficiencies. We consistently deploy our capital to large-scale projects and carefully select the dedicated service providers required to execute our programs effectively. In addition, we have proven our ability to identify, acquire, and integrate acquisitions in our areas of focus while creating incremental value through realizing synergies; 
+• Returns-Driven Strategy to Generate Free Cash Flow – We have a demonstrated track record of capital discipline, investing less than our annual cash flow with capital spending governed by defined economic thresholds focused on capital efficiencies to enhance long-term returns. We proactively hedge a portion of our production to manage the variability in cash flows and have also secured capacity on oil and natural gas pipelines to improve our ability to market our production; and 
+• ESG Focus – We have proven our ability to create value responsibly. Our compensation programs incentivize the right behaviors to ensure a safe workplace while minimizing the impact of our operations on the environment. 
+◦ Environment. We are committed to environmental stewardship and have established goals to achieve meaningful reductions for both carbon and methane emissions. 
+◦ Social. We foster an entrepreneurial workplace where individuals are encouraged and empowered to share their ideas and perspectives and to develop and implement plans to bring those ideas to fruition. We embrace a culture of diversity and inclusion, where individuals feel respected, heard, and empowered. 
+◦ Governance. We are committed to effective and sustainable corporate governance, which we believe promotes the long-term interests of stakeholders. We have a board with a high level of diversity, including in skills and perspectives, that allows them to perform their strategic and oversight roles satisfactorily for our stakeholders. In addition, our compensation programs incorporate metrics that align with our ESG goals. 
+7 
+Proved Oil and Gas Reserves 
+The following table sets forth summary information with respect to our estimated proved reserves, standardized measure of discounted future net cash flows and PV-10 for the years ended December 31, 2022, 2021, and 2020. The estimated proved reserves in the table below were prepared by DeGolyer and MacNaughton (“D&M”), Callon’s independent third-party reserve engineers. For further information concerning D&M’s estimates of our proved reserves as of December 31, 2022, see the reserve report included as an exhibit to this 2022 Annual Report on Form 10-K. In accordance with SEC rules, we used the 12-Month Average Realized Price of oil, NGLs, and natural gas in the calculation of our estimated proved reserves and PV-10. 
+As of December 31, 
+2022 2021 2020 
+Proved developed reserves 
+Crude oil (MBbls) 170,866 162,886 128,923 
+Natural gas (MMcf) 351,278 332,266 238,119 
+NGLs (MBbls) 63,788 55,720 43,315 
+Total proved developed reserves (MBoe) 293,200 273,983 211,925 
+Proved undeveloped reserves 
+Crude oil (MBbls) 104,743 127,410 160,564 
+Natural gas (MMcf) 241,565 245,061 303,479 
+NGLs (MBbls) 41,321 42,384 52,811 
+Total proved undeveloped reserves (MBoe) 186,325 210,638 263,954 
+Total proved reserves 
+Crude oil (MBbls) 275,609 290,296 289,487 
+Natural gas (MMcf) 592,843 577,327 541,598 
+NGLs (MBbls) 105,109 98,104 96,126 
+Total proved reserves (MBoe) 479,525 484,621 475,879 
+Proved developed reserves % 61 % 57 % 45 % 
+Proved undeveloped reserves % 39 % 43 % 55 % 
+12-Month Average Realized Prices 
+Crude oil ($/Bbl) $95.02 $65.44 $37.44 
+Natural gas ($/Mcf) $5.75 $3.31 $1.02 
+NGLs ($/Bbl) $36.40 $29.19 $11.10 
+Standardized measure of discounted future net cash flows (GAAP) (in millions) $9,004.1 $6,250.8 $2,310.4 
+PV-10 (Non-GAAP) (in millions): 
+Proved developed PV-10 $7,122.9 $4,502.6 $1,577.3 
+Proved undeveloped PV-10 3,411.9 2,548.7 767.7 
+Total PV-10 (Non-GAAP) $10,534.8 $7,051.3 $2,345.0 
+Reconciliation of Standardized Measure of Discounted Future Net Cash Flows (GAAP) to PV-10 (Non-GAAP) 
+We believe that the presentation of PV-10 provides greater comparability when evaluating oil and gas companies due to the many factors unique to each individual company that impact the amount and timing of future income taxes. In addition, we believe that PV-10 is widely used by investors and analysts as a basis for comparing the relative size and value of our proved reserves to other oil and gas companies. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company’s financial or operating performance presented in accordance with GAAP. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of our proved oil and gas reserves. 
+As of December 31, 
+2022 2021 2020 
+(In millions) 
+Standardized measure of discounted future net cash flows (GAAP) $9,004.1 $6,250.8 $2,310.4 
+Add: present value of future income taxes discounted at 10% per annum 1,530.7 800.5 34.6 
+PV-10 (Non-GAAP) $10,534.8 $7,051.3 $2,345.0 
+8 
+Proved Reserves 
+Our reserve estimates are conducted from fundamental petrophysical, geological, engineering, financial and accounting data. Reserves are estimated based on production decline analysis, analogy to producing offsets, detailed reservoir modeling, volumetric calculations or a combination of these methods, in all cases having regard to economic considerations and using technologies that have been demonstrated in the field to yield repeatable and consistent results as defined in the SEC regulations. To establish reasonable certainty of our proved reserves estimates, including material additions to our proved reserves, we use certain technologies and economic data, including production and well test data, historical well costs and operating data, geologic and seismic data, and subsurface information obtained through wellbores such as electrical logs, radioactive logs, reservoir core samples, fluid samples, and static and dynamic pressure information. Non-producing reserves are estimated by analogy to producing offsets, with consideration given to a development plan approved by Callon’s management. 
+The following table presents our estimated proved reserves of December 31, 2022. 
+Permian Eagle Ford Total 
+Proved reserves 
+Crude oil (MBbls) 227,293 48,316 275,609 
+Natural gas (MMcf) 537,780 55,063 592,843 
+NGLs (MBbls) 95,362 9,747 105,109 
+Total proved reserves (MBoe) 412,285 67,240 479,525 
+Percent of proved developed reserves 82 % 18 % 100 % 
+Percent of proved undeveloped reserves 92 % 8 % 100 % 
+The following table provides a summary of the changes in our proved reserves for the year ended December 31, 2022. 
+Total 
+(MBoe) 
+Proved reserves as of December 31, 2021 
+484,621 
+Extensions and discoveries 67,961 
+Revisions to previous estimates (31,645) 
+Sales of reserves in place (3,359) 
+Production (38,053) 
+Proved reserves as of December 31, 2022 
+479,525 
+Further details of the changes in our proved reserves for the year ended December 31, 2022 are as follows: 
+• Extensions and Discoveries. We added 68.0 MMBoe of new reserves in extensions and discoveries through our development efforts in our operating areas. See the table below for the impact of extensions and discoveries on total proved and proved undeveloped reserves for 2022: 
+Extensions and discoveries Total 
+(MBoe) 
+Total proved 67,961 
+Proved undeveloped 59,231 
+Difference (Proved developed producing) (1) 
+8,730 
+(1) These extensions and discoveries were not recognized as proved undeveloped reserves in a prior period, but rather were recognized directly as proved developed producing reserves as there was not an offset proved developed producing location at the time of drilling in order to classify as a proved undeveloped location. 
+We incurred costs of $115.5 million for the extensions and discoveries associated with proved developed producing wells and $44.7 million on facilities associated with existing proved developed producing wells during 2022. 
+9 
+• Revisions to Previous Estimates. Net negative revisions of previous estimates of 31.6 MMBoe primarily consist of: 
+◦ 44.4 MMBoe reduction due to PUD locations that were reclassified to unproved reserve categories, all of which were in the Permian. Certain PUDs were moved outside of their five-year development window as we continue to refine our future development plans for the Permian, including increased application of our “Life of Field” co-development model. This development model focuses on optimization of the value of a reservoir system through concurrent, co-development of multiple target zones within the system utilizing larger scale projects. As a result, we believe the model contributes to more consistent capital efficiency of our well inventory over time and our broader Permian development program is now being targeted for larger project sizes, accompanied by longer associated cycle times, based on our testing and delineation efforts during 2022; 
+◦ 13.1 MMBoe reduction primarily due to higher operating costs; offset by 
+◦ 13.7 MMBoe increase primarily due to the change in 12-Month Average Realized Price of crude oil which increased by approximately 45% as compared to December 31, 2021; and 
+◦ 12.2 MMBoe increase primarily due to better results than previously forecasted on certain wells turned to production during 2022 in both the Permian and Eagle Ford. 
+• Sales of Reserves in Place. The 3.4 MMBoe of sales of reserves in place were primarily associated with the divestitures of non-core assets primarily in the Western Delaware Basin. 
+Proved Undeveloped Reserves 
+Annually, we review our PUDs to ensure appropriate plans exist for development of this reserve category. PUD reserves are recorded only if we have plans to convert these reserves into PDPs within five years of the date they are first recorded. Our development plans include the allocation of capital to projects included within our 2023 Capital Budget, as defined below, and, in subsequent years, the allocation of capital within our long-range business plan to convert PUDs to PDPs within this five-year period. The following table provides a summary of the changes in our PUDs for the year ended December 31, 2022. 
+Total 
+(MBoe) 
+PUDs as of December 31, 2021 
+210,638 
+Extensions and discoveries 59,231 
+Revisions to previous estimates (39,843) 
+Converted to proved developed (43,701) 
+PUDs as of December 31, 2022 
+186,325 
+• Extensions and Discoveries. We added 59.2 MMBoe of new reserves in extensions and discoveries, all in the Permian, as a result of additional offset locations associated with our drilling program. 
+• Revisions to Previous Estimates. Net negative revisions of previous estimates of 39.8 MMBoe primarily consist of: 
+◦ 44.4 MMBoe reduction due to PUDs that were removed primarily as a result of changes in our development plans as described above; 
+◦ 2.9 MMBoe reduction primarily due to higher operating costs; offset by 
+◦ 2.6 MMBoe increase primarily due to the change in 12-Month Average Realized Price of crude oil which increased by approximately 45% as compared to December 31, 2021; and 
+◦ 4.9 MMBoe increase primarily due to increased anticipated hydrocarbon recoveries resulting from observed well performance over longer production timeframes during the testing of various full field development plan concepts. 
+• Converted to Proved Developed. During 2022, we converted 43.7 MMBoe of PUDs that were booked as PUDs as of December 31, 2021 to proved developed at a cost of $445.9 million, or $10.20 per Boe. 
+During 2022, we also incurred $153.9 million on PUDs that were drilled but uncompleted as of December 31, 2022. As of December 31, 2022, we had 23.2 MMBoe of PUDs associated with drilled but uncompleted wells. All of the reserves associated with drilled but uncompleted wells are scheduled to be completed in 2023, and we expect to incur approximately $122.3 million of capital expenditures to complete these wells. We also incurred $65.9 million on wells in progress in 2022. 
+At December 31, 2022, we did not have any reserves that have remained undeveloped for five or more years since the date of their initial booking and all PUD locations are scheduled to be developed within five years of their initial booking. 
+10 
+Qualifications of Technical Persons 
+In accordance with the Standards Pertaining to Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers, D&M prepared 100% of our estimates of proved reserves as of December 31, 2022, 2021, and 2020. D&M is a respected company in the reservoir engineering field and provides petroleum property analysis for other upstream companies. The technical persons responsible for preparing the reserves estimates meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. D&M does not own an interest in our properties and is not employed on a contingent fee basis. 
+Our internal director of reserves has over 20 years of experience in the petroleum industry and extensive experience in the estimation of reserves and the review of reserve reports prepared by third-party engineering firms. Compliance as it relates to reporting the Company’s reserves is the responsibility of our Chief Operating Officer, who is also our principal engineer. He has over 30 years of operations and industry experience and holds B.S. and Ph.D. degrees in Petroleum Engineering, in addition to a M.S. in Environmental and Planning Engineering, and is experienced in asset evaluation and management. 
+Internal Controls Over Reserve Estimation Process 
+The primary inputs to the reserve estimation process are comprised of technical information, financial data, production data, and ownership interest. All field and reservoir technical information is assessed for validity when the internal reserve engineer holds technical meetings with our geoscientists, operations, and land personnel to discuss field performance and to validate future development plans. The other inputs used in the reserve estimation process, including, but not limited to, future capital expenditures, commodity price differentials, production costs, and ownership percentages are subject to internal controls over financial reporting and are assessed for effectiveness annually. 
+To further enhance the control environment over the reserve estimation process, our Operations and Reserves Committee, an independent committee of the Company’s board of directors (the “Board of Directors”), assists management and the Board of Directors with its oversight of the integrity of the determination of our oil and natural gas reserves and the work of the independent third-party reserve engineers. The Operations and Reserves Committee’s charter also specifies that it shall perform, in consultation with the Company’s management and senior reserves and reservoir engineering personnel, the following responsibilities: 
+• Oversee the appointment, qualification, independence, compensation and retention of the independent third-party reserve engineers engaged by the Company (including resolution of material disagreements between management and the independent third-party reserve engineers regarding reserve determination) for the purpose of preparing or issuing an annual reserve report. The Operations and Reserves Committee shall review any proposed changes in the appointment of the independent third-party reserve engineers, determine the reasons for such proposal, and whether there have been any disputes between the independent third-party reserve engineers and management. 
+• Review the Company’s significant reserves engineering principles and any material changes thereto, and any proposed changes in reserves engineering standards and principles which have, or may have, a material impact on the Company’s reserves disclosure. 
+• Review with management and the independent third-party reserve engineers the proved reserves of the Company, and, if appropriate, the probable reserves, possible reserves and the total reserves of the Company, including: (i) reviewing significant changes from prior period reports; (ii) reviewing key assumptions used or relied upon by the independent third-party reserve engineers; (iii) evaluating the quality of the reserve estimates prepared by the independent third-party reserve engineers and the Company relative to the Company’s peers in the industry; and (iv) reviewing any material reserves adjustments and significant differences between the Company’s and independent third-party reserve engineers’ estimates. 
+• If the Operations and Reserves Committee deems it necessary, it shall meet in executive session with the independent third-party reserve engineers to discuss the oil and gas reserve determination process and related public disclosures, and any other matters of concern in respect of the evaluation of the reserves. 
+During our last fiscal year, we filed no reports with other federal agencies which contain an estimate of proved reserves. 
+See “Note 18 – Supplemental Information on Oil and Natural Gas Operations” of the Notes to our Consolidated Financial Statements for additional information regarding our estimated proved reserves and the present value of estimated future net revenues from these proved reserves. 
+Capital Budget 
+Our Board approved a capital budget for $1.0 billion (the “2023 Capital Budget”), with approximately 80% directed towards drilling, completion, and equipment expenditures. Our scaled development plan for 2023 will continue to employ our “Life of Field” co-development model, whereby capital is allocated towards full field development plans of depletion and optimal usage of infrastructure. Over 80% of the 2023 Capital Budget is allocated to development in the Permian with the balance for development in the Eagle Ford. 
+11 
+Our revenues, earnings, and liquidity are substantially dependent on the prices we receive for, and our ability to develop, our reserves of oil and natural gas. We believe that we are positioned to execute on our strategy even during downturns in the industry due to our resource base, low-cost structure, risk management, and disciplined investment of capital. We monitor current and expected market conditions, including the commodity price environment, and our liquidity needs and may adjust our capital investment plan accordingly. 
+Drilling Activity 
+The following table sets forth our operated and non-operated drilling activity for the years ended December 31, 2022, 2021, and 2020. As defined by the SEC, the number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. For definitions of exploratory wells, extension wells, development wells, productive wells, and non-productive wells, see “Glossary of Certain Terms.” 
+Years Ended December 31, 
+2022 2021 2020 
+Gross Net Gross Net Gross Net 
+Extension Wells - Productive 20 17.7 19 17.2 22 16.0 
+Extension Wells - Non-productive — — — — — — 
+Development Wells - Productive 86 76.8 93 86.7 73 66.0 
+Development Wells - Non-productive — — — — — — 
+Productive Wells 
+The following table sets forth the number of productive crude oil and natural gas wells in which we owned an interest as of December 31, 2022. 
+Crude Oil Natural Gas Total 
+Gross Net Gross Net Gross Net 
+Permian - Operated 956 841.0 99 84.1 1,055 925.1 
+Permian - Non-operated 47 5.8 1 0.1 48 5.9 
+Total Permian 1,003 846.8 100 84.2 1,103 931.0 
+Eagle Ford - Operated 543 489.8 87 76.0 630 565.8 
+Eagle Ford - Non-operated 17 0.2 — — 17 0.2 
+Total Eagle Ford 560 490.0 87 76.0 647 566.0 
+Total 1,563 1,336.8 187 160.2 1,750 1,497.0 
+12 
+Production Volumes, Average Sales Prices and Operating Costs 
+The following tables set forth certain information regarding the production volumes and average sales prices received for, and average production costs associated with, our sales of oil, natural gas and NGLs for the periods indicated. For further details, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations”. 
+Years Ended December 31, 
+2022 2021 2020 
+Total production 
+Oil (MBbls) 
+Permian 18,041 14,475 14,113 
+Eagle Ford 5,598 7,749 9,430 
+Total oil 23,639 22,224 23,543 
+Natural gas (MMcf) 
+Permian 35,519 29,682 32,087 
+Eagle Ford 6,108 7,704 8,714 
+Total natural gas 41,627 37,386 40,801 
+NGLs (MBbls) 
+Permian 6,424 5,155 5,390 
+Eagle Ford 1,052 1,284 1,460 
+Total NGLs 7,476 6,439 6,850 
+Total production (MBoe) 
+Permian 30,385 24,577 24,851 
+Eagle Ford 7,668 10,317 12,342 
+Total barrels of oil equivalent 38,053 34,894 37,193 
+Average realized sales price (excluding impact of derivative settlements) 
+Oil (per Bbl) $95.72 $68.22 $36.13 
+Natural gas (per Mcf) 5.59 3.78 1.27 
+NGL (per Bbl) 34.84 30.11 11.87 
+Total average realized sales price (per Boe) $72.42 $53.06 $26.45 
+Operating costs per Boe 
+Lease operating expense $7.63 $5.82 $5.22 
+Production and ad valorem taxes $4.20 $2.87 $1.68 
+Gathering, transportation and processing $2.55 $2.32 $2.08 
+Major Customers 
+We market the majority of the production from properties we operate on account of both ourselves and that of the other working interest owners in these properties. We generally sell our production to purchasers at prevailing market prices, which in certain cases are adjusted for contractual differentials, under contracts ranging from terms of one month to multiple years. The following table presents customers that represented 10% or more of our oil, natural gas and NGL revenues for at least one of the periods presented: 
+Years Ended December 31, 
+2022 (1) 
+2021 (1) 
+2020 (1) 
+Valero Marketing and Supply Company 15% 13% 23% 
+Rio Energy International, Inc. 12 * * 
+Shell Trading Company * 20 31 
+Trafigura Trading, LLC * 15 * 
+Occidental Energy Marketing, Inc. * 13 * 
+(1) The customers that represented over 10% of our sales of purchased oil and gas were Vitol Inc., for the years ended December 31, 2022, 2021 and 2020, and Plains Marketing, L.P., for the year ended December 31, 2022. 
+* - Less than 10% for the respective years. 
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+Because alternative purchasers of oil and natural gas are readily available, we believe that the loss of any of these purchasers would not result in a material adverse effect on our ability to sell future oil and natural gas production. In order to mitigate potential exposure to credit risk, we may require our customers to provide financial security. 
+Leasehold Acreage 
+The following table shows our approximate developed and undeveloped leasehold acreage as of December 31, 2022. Developed acreage refers to acreage on which wells have been completed to a point that would permit production of oil and gas in commercial quantities. Undeveloped acreage refers to acreage on which wells have not been drilled or completed to a point that would permit production of oil and gas in commercial quantities whether or not the acreage contains proved reserves. 
+Developed Acreage Undeveloped Acreage Total Acreage Net Undeveloped Acreage Expiring 
+Gross Net Gross Net Gross Net 2023 2024 2025 
+Permian (1) 
+146,238 124,078 5,459 3,015 151,697 127,093 525 964 430 
+Eagle Ford 61,526 51,624 2,719 275 64,245 51,899 32 — 21 
+Other (2) 
+2,019 62 15,845 7,393 17,864 7,455 3,398 2,994 — 
+Total 209,783 175,764 24,023 10,683 233,806 186,447 3,955 3,958 451 
+(1) Based on our current plans, approximately 99%, 61% and 58% of the acreage expiring in the Permian in 2023, 2024 and 2025, respectively, will be developed prior to expiration or extended by lease extension payments. 
+(2) Consists of non-core acreage principally located in Presidio County, Texas. We have no current development plans and no proved undeveloped reserves associated with this acreage as of December 31, 2022. 
+Our lease agreements generally terminate if producing wells have not been drilled on the acreage within their primary term or an extension thereof (a period that is generally from three to five years depending on the area). The percentage of net undeveloped acreage expiring in 2023, 2024 and 2025 assumes that no producing wells have been drilled on acreage within their primary term or have been extended. We manage our lease expirations to ensure that we do not experience unintended material loss of acreage or depths. Our leasehold management efforts include scheduling drilling in order to hold leases by production or timely exercising our contractual rights to extend the terms of leases by continuous operations or the payment of lease extension payments and delay rentals. We may choose to allow some leases to expire that are no longer part of our development plans. 
+The proved undeveloped reserves associated with acreage expiring over the next three years are not material to the Company. 
+Human Capital 
+Callon employs a talented workforce that is integral to our success, and we are committed to the safety, health, and development of each team member. The Callon culture is defined by our values of responsibility, integrity, drive, respect and excellence. These core values are a reflection of our ideals as individuals and direct our actions as a company. 
+Callon’s key human capital management objectives are to attract, retain and develop talent to deliver on our strategy. Due to the technical nature of our business, our success depends on a highly skilled workforce in multiple disciplines including engineering, geology, operations, land, information technology, accounting and various other corporate functions. To support the attraction and retention of top talent, our human resources programs are designed to keep our employees safe and healthy, engage employees with an inclusive workplace, reward and support employees through competitive pay and benefit programs, and develop talent to support personal growth and prepare employees for high impact roles and leadership positions. 
+As of December 31, 2022, Callon had 354 permanent, full-time employees. None of our employees are currently represented by a union, and we believe that we have good relations with our employees. 
+We focus on the following in supporting our human capital: 
+• Inclusion and Diversity – We believe that diversity of backgrounds and perspectives contributes to an innovative workforce and an enriching environment for our employees. Callon is firmly committed to fostering an inclusive, respectful environment and providing equal opportunity to all qualified persons in our hiring, development, and compensation practices. As of December 31, 2022, approximately 41% of our permanent, full-time employees identified as a racial or ethnic minority, 22% were female, and 32% of non-field employees were female. We seek to expand diversity in our workforce, and in 2022, 50% of our newly hired employees identified as a racial or ethnic minority and 36% were female. 
+• Health and Safety – Protecting our employees, contractors and communities is a core value at Callon and a top priority. Our Operations Management System (“OMS”) establishes clear expectations for operating safely and responsibly throughout the lifecycle of our business. We seek to identify and mitigate safety risks and integrate a culture of safety by operating according to OMS standards, processes, and procedures. Additionally, we share our Safety and Environmental Policy with all employees and contractors; the policy includes each individual’s authorization and responsibility to stop work on any activity 
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+for safety reasons without the threat or fear of job reprisal. To reinforce accountability for safety results, our Board of Directors included safety performance as a factor in our 2022 annual bonus program. 
+• Employee Compensation, Benefits and Wellness – Our compensation and benefits programs provide a package designed to attract, retain and motivate employees. In addition to competitive base salaries, we provide a variety of short-term and long-term incentive compensation programs to reward performance relative to key financial, operational, and ESG metrics. Callon invests in the health and well-being of our employees and their families by paying 100% of the premiums for our health care plan. We also offer comprehensive benefit options including a retirement savings plan, life and disability insurance, health savings accounts, flexible spending accounts, and a charitable matching program. 
+• Employee Development – We believe that ongoing investment in the development of our team members is key to our future success, as well as the retention of our employees. Callon fosters an entrepreneurial workplace where employees can expand their skill sets and experience by direct engagement and collaboration with leaders at all levels. Additionally, we offer tuition assistance and access to various training programs, including a monthly in-house leadership development program. Our leaders seek to support all of our employees in reaching their personal goals through ongoing feedback and development conversations. 
+For additional information, please see our Sustainability Report published on our company website (www.callon.com). Information contained in our Sustainability Report is not incorporated by reference into, and does not constitute a part of, this 2022 Annual Report on Form 10-K. 
+Other 
+Industry Segment and Geographic Information 
+For segment reporting purposes, Callon considers all of the current development and operating areas to be one reportable segment: the development and production of oil and natural gas. All of our assets are located within the United States and all operations are located within Texas. 
+Title to Properties 
+We believe that the title to our oil and natural gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of such properties. Nevertheless, we can be involved in title disputes from time to time which may result in litigation. Our properties are potentially subject to burdens such as royalty, overriding royalty, working and other outstanding interests customary in the industry. To the extent that such burdens and obligations affect our rights to production revenues, these characteristics have been taken into account in calculating our net revenue interests and in estimating the size and value of our estimated proved reserves. We believe that the burdens and obligations affecting our properties are typical within the industry for properties of the kind owned by Callon. 
+Seasonality of Business 
+Weather conditions and seasonality affect the demand for, and prices of, oil and natural gas. Due to these fluctuations, results of operations for quarterly interim periods may not be indicative of the results realized on an annual basis. 
+Competition 
+We operate in the oil and natural gas industry, which is highly competitive. Our business experiences strong competition from a number of parties that may range from small independent producers to major integrated companies. Competition affects our ability to acquire additional properties and resources necessary to develop assets. In higher commodity pricing environments, competition also exists in the form of contracting for drilling, pumping, and workover equipment, and securing skilled personnel to both develop and operate existing assets. Many of our competitors may be able to pay for more sought-after properties or access equipment, infrastructure, or personnel. The industry also experiences, from time to time, shortages in resources such as the availability of drilling and workover rigs, other equipment, pipes and materials, infrastructures, and skilled personnel, all of which can delay development, exploration, and workover activities as well as result in significant cost increases. 
+Insurance 
+In accordance with industry practice, we maintain insurance against some of the operating risks to which our business is exposed. While not all inclusive, our insurance policies generally protect against bodily injury and property damage, pollution and other environmental damages, employee benefits, employee injury and control of well insurance for our exploration and production operations. 
+We enter into master service agreements with our third-party contractors, including hydraulic fracturing contractors, in which they agree to indemnify us for injuries and deaths of the service provider’s employees, as well as contractors and subcontractors hired by 
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+the service provider. Similarly, we generally agree to indemnify each third-party contractor against claims made by our employees and our other contractors. Additionally, each party generally is responsible for damage to its own property. We reevaluate the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and natural gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. While we believe that we are properly insured based on our risk analysis, no assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable. In such circumstances, we may elect to self-insure or maintain only catastrophic coverage for certain risks in the future. 
+Corporate Offices 
+Our headquarters are located in Houston, Texas, in buildings with office space that we lease. We own office buildings in Dilley and Pecos, Texas and lease and own offices in the Midland, Texas area. Because alternative locations to our leased spaces are readily available, the replacement of any of our leased offices would not result in material expenditures . 
+Regulations 
+General. Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities at the federal, state, and local levels. Some of these requirements carry substantial penalties for failure to comply. Legislation and regulation affecting the entire oil and natural gas industry is continuously being reviewed for potential revision, and various proposals and proceedings that might affect the industry are pending before Congress, federal administrative agencies such as the Federal Energy Regulatory Commission (“FERC”), various state and administrative agencies and legislatures, and the courts. We cannot predict what effect such proposals or proceedings may have on our operations, capital expenditures, earnings or competitive position. 
+Exploration and Production . Our operations are subject to federal, state and local regulations that include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds and letters of credit) covering drilling and well operations. Other activities subject to regulation are: 
+• the location and spacing of wells; 
+• the method of drilling and completing and operating wells; 
+• the rate and method of production; 
+• the surface use and restoration of properties upon which wells are drilled and other exploration activities; 
+• notice to surface owners and other third parties; 
+• the venting or flaring of natural gas; 
+• the plugging and abandoning of wells; 
+• the discharge of contaminants into water and the emission of contaminants into air; 
+• the disposal of fluids used or other wastes obtained in connection with operations; 
+• the marketing, transportation and reporting of production; and 
+• the valuation and payment of royalties. 
+We do not currently anticipate that compliance with existing laws and regulations governing exploration and production will have a significantly adverse effect upon our capital expenditures, operations, earnings or competitive position. 
+Environmental Matters and Regulation. Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to the protection of the environment and natural resources. Numerous federal, state and local governmental agencies, such as the U.S. Environmental Protection Agency (the “EPA”), issue regulations which often require difficult and costly compliance measures. These laws and regulations may require the acquisition of a permit before drilling commences; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities; limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas; require action to prevent, monitor for or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits; result in the suspension or revocation of necessary permits, licenses and authorizations; require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relating to our owned or operated facilities. Violations of environmental laws could result in administrative, civil or criminal fines and injunctive relief. The strict and joint and several liability nature of certain such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons, air emissions or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. In recent years, the oil and natural gas exploration and production industry has been the subject of increasing scrutiny and regulation by environmental authorities. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect 
+16 
+from compliance with these environmental requirements. Although such laws and regulations can increase the cost of planning, designing, installing and operating our facilities, it is anticipated that, absent the occurrence of an extraordinary event, compliance with them will not have a material effect upon our operations, capital expenditures, earnings or competitive position in the marketplace. 
+Waste Handling. The Resource Conservation and Recovery Act (“RCRA”), as amended, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of oil and natural gas are exempt from regulation as hazardous wastes under RCRA and its state analogs, it is possible that some wastes we generate presently or in the future may be subject to regulation under RCRA and state analogs. Additionally, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” If the EPA proposes a rulemaking for revised oil and gas waste regulations in the future, any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. 
+Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of wastes associated with oil and natural gas exploration and production could increase our costs to manage and dispose of such wastes. 
+Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), imposes strict, joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the release occurred and anyone who disposed of or arranged for the disposal of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes. 
+Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we have generated and will generate wastes that may fall within CERCLA’s definition of hazardous substance and may have disposed of these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum. We may also be the owner or operator of sites on which hazardous substances have been released. To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under CERCLA; we also do not know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties. In the event contamination is discovered at a site on which we are or have been an owner or operator or to which we sent hazardous substances, we could be liable for the costs of investigation and remediation and natural resources damages. 
+We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating, waste disposal, and water disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including offsite locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination or groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination. 
+Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, the Safe Drinking Water Act, the Oil Pollution Act (“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States (a term broadly defined to include, among other things, certain wetlands), as well as state waters for analogous state programs. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or applicable state analog. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an 
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+appropriately issued permit from the U.S. Army Corps of Engineers (the “Corps”). The EPA and the Corps issued a final rule on the federal jurisdictional reach over waters of the United States in 2015 that never took effect before being replaced by the Navigable Waters Protection Rule (the “NWPR”) in December 2019. A coalition of states and cities, environmental groups, and agricultural groups challenged the NWPR, and it was vacated by a federal district court in August 2021. The EPA is undergoing a two-phase rulemaking process to redefine the definition of waters of the United States and that process could be impacted by the U.S. Supreme Court’s upcoming decision in Sackett v. EPA, a case regarding the proper test in determining whether wetlands qualify as navigable waters of the United States. A final rule, known as “Rule 1,” was announced by the EPA and the Corps in December 2022. The EPA and the Corps are expected to propose a second rule, known as “Rule 2,” further refining Rule 1 by November 2023 and issue a final rule by July 2024. 
+The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. 
+The Oil Pollution Act is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters. 
+Noncompliance with the Clean Water Act or the OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws. 
+Air Emissions. The federal Clean Air Act, as amended (the “CAA”), and comparable state and local laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and modified and existing facilities may be required to obtain additional permits. As a result, we may need to incur capital costs in order to remain in compliance. Obtaining or renewing permits also has the potential to delay the development of oil and natural gas projects. Federal and state regulatory agencies can impose administrative, civil and criminal penalties and seek injunctive relief for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. 
+In June 2016, the EPA finalized regulations establishing New Source Performance Standards, known as Subpart OOOOa, for methane and volatile organic compounds from new and modified oil and natural gas production and natural gas processing and transmission facilities. In September 2020, the EPA finalized two sets of amendments to the 2016 Subpart OOOOa standards. The first, known as the 2020 Technical Rule, reduced the 2016 rule’s fugitive emissions monitoring requirements and expanded exceptions to pneumatic pump requirements, among other changes. The second, known as the 2020 Policy Rule, rescinded the methane-specific requirements for certain oil and natural gas sources in the production and processing segments. On January 20, 2021, President Biden issued an Executive Order directing the EPA to rescind the 2020 Technical Rule by September 2021 and consider revising the 2020 Policy Rule. On June 30, 2021, President Biden signed a Congressional Review Act (the “CRA”) resolution passed by Congress that revoked the 2020 Policy Rule. The CRA did not address the 2020 Technical Rule. 
+Further, on November 15, 2021, the EPA issued a proposed rule intended to reduce methane emissions from oil and gas sources. The proposed rule would make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the CAA (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities). In addition, the proposed rule would establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA. Under the proposed rule, states would have three years to develop their compliance plan for existing sources and the regulations for new sources would take effect immediately upon issuance of a final rule. On November 11, 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule. Among other things, the November 2022 supplemental proposed rule removes an emissions monitoring exemption for small wellhead-only sites and creates a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters.” The EPA is expected to issue a final rule by August 2023. 
+As a result of these regulatory changes, the scope of any final methane regulations or the costs for complying with federal methane regulations are uncertain. However, any new regulations could result in stricter permitting requirements, which in turn could delay or 
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+impair our ability to obtain air emission permits and could result in increased expenditures for pollution control equipment, the costs of which could be significant. 
+Climate Change. Numerous reports from scientific and governmental bodies such as the Sixth Assessment Report of the Intergovernmental Panel on Climate Change have expressed heightened concerns about the impacts of human activity, especially fossil fuel combustion, on the global climate. In turn, governments and civil society are increasingly focused on limiting the emissions of GHGs, including emissions of carbon dioxide from the use of oil and natural gas. 
+At the international level, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change (“UNFCCC”) resulted in nearly 200 countries, including the United States, coming together to develop the Paris Agreement, intended to nationally determine their contributions and set GHG emission reduction goals every five years beginning in 2020. In 2020, the U.S. withdrew from the Paris Agreement. However, in February 2021, the current administration rejoined the Paris Agreement and later announced a target for the U.S. to achieve a 50% to 52% reduction from 2005 levels in economy-wide GHG emissions by 2030. In addition, in September 2021, President Biden publicly announced the Global Methane Pledge, a pact that aims to reduce global methane emissions at least 30% below 2020 levels by 2030, including “all feasible reductions” in the energy sector. Since its formal launch at the 26th Conference of the Parties of the UNFCCC (“COP26”), over 150 countries have joined the pledge. Most recently, at the 27th conference of parties (“COP27”), President Biden announced the EPA’s proposed standards to reduce methane emissions from existing oil and gas sources, and agreed, in conjunction with the European Union and a number of other partner countries, to develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. Various state and local governments have also publicly committed to furthering the goals of the Paris Agreement. International commitments, re-entry into the Paris Agreement and President Biden’s executive orders may result in the development of additional regulations or changes to existing regulations. 
+While the Biden Administration has pursued executive actions to address climate change, and while Congress has from time to time considered legislation to reduce emissions of GHGs, no new comprehensive federal laws regulating the emission of GHGs or directly imposing a price on carbon have been adopted in recent years. However, such legislation has periodically been introduced in the U.S. Congress and may be proposed or adopted in the future. In addition, many state and local leaders have intensified or stated their intent to intensify efforts to support international climate commitments and treaties, in addition to developing programs that are aimed at reducing GHG emissions by means of cap and trade programs, carbon taxes, or encouraging the use of renewable energy or alternative low-carbon fuels. 
+Any legislation or regulatory programs at the federal, state, or city levels designed to reduce GHG emissions could increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. At the federal level, the $1 trillion legislative infrastructure package passed by Congress in November 2021 includes a number of climate-focused spending initiatives targeted at climate resilience, enhanced response and preparation for extreme weather events, and clean energy and transportation investments. The Inflation Reduction Act of 2022 (“IRA 2022”) also provides significant funding and incentives for research and development of low-carbon energy production methods, carbon capture, and other programs directed at addressing climate change. 
+In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions. Although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. 
+The EPA has established GHG reporting requirements for certain sources in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissions. Although these requirements do not limit the amount of GHGs that can be emitted, they do require us to incur costs to monitor, keep records of, and report GHG emissions associated with our operations. 
+Additionally, on March 21, 2022, the SEC issued a proposed rule regarding the enhancement and standardization of mandatory climate-related disclosures for investors. The proposed rule would require registrants to include certain climate-related disclosures in their registration statements and periodic reports, including, but not limited to, information about the registrant’s governance of climate-related risks and relevant risk management processes; climate-related risks that are reasonably likely to have a material impact on the registrant’s business, results of operations, or financial condition and their actual and likely climate-related impacts on the registrant’s business strategy, model, and outlook; climate-related targets, goals and transition plan (if any); certain climate-related financial statement metrics in a note to their audited financial statements; Scope 1 and Scope 2 GHG emissions; and Scope 3 GHG emissions and intensity, if material, or if the registrant has set a GHG emissions reduction target, goal or plan that includes Scope 3 GHG emissions. Although the proposed rule’s ultimate date of effectiveness and the final form and substance of these requirements is not yet known and the ultimate scope and impact on our business is uncertain, compliance with the proposed rule, if finalized, may result in increased legal, accounting and financial compliance costs, make some activities more difficult, time-consuming and costly, and place strain on our personnel, systems and resources. 
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+Regulation of Hydraulic Fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act (“SDWA”) regulates the underground injection of substances through the Underground Injection Control (“UIC”) program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions and not at the federal level, as the SDWA expressly excludes regulation of these fracturing activities (except where diesel is a component of the fracturing fluid, as further discussed below). Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing has been proposed in past legislative sessions but has not passed. 
+The EPA, however, issued guidance on permitting hydraulic fracturing that uses fluids containing diesel fuel under the UIC program, specifically as “Class II” UIC wells. The EPA evaluated the potential impacts of hydraulic fracturing on drinking water resources and concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Further, the EPA prohibits the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. 
+Several states, including Texas, and some municipalities, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, Texas law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) for disclosure on a website and also file the list of chemicals with the Texas Railroad Commission (the “RRC”) with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the RRC. 
+Additionally, some states, localities and local regulatory districts have adopted or have considered adopting regulations to limit, and in some cases impose a moratorium on, hydraulic fracturing or other restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; or restrictions on access to, and usage of, water. Further, there has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the U.S. implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations of harm. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of potential federal or state legislation governing hydraulic fracturing. In light of concerns about seismic activity being triggered by the injection of produced waters into underground wells, certain regulators are also considering additional requirements related to seismic safety for hydraulic fracturing activities. For example, the RRC has created several “seismic response areas” in west Texas and limited certain deep oil and gas wastewater disposal activities in portions of west Texas due to seismicity concerns. The U.S. Geological Survey has identified eight states with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. Any regulation that restricts our ability to dispose of produced waters or increases the cost of doing business could cause curtailed or decreased demand for our services and have a material adverse effect on our business. 
+Surface Damage Statutes (“SDAs”) . In addition, a number of states and some tribal nations have enacted SDAs. These laws are designed to compensate for damage caused by oil and gas development operations. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain binding requirements for payments by the operator to surface owners/users in connection with exploration and operating activities in addition to bonding requirements to compensate for damages to the surface as a result of such activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs. 
+National Environmental Policy Act . Oil and natural gas exploration and production activities requiring federal permits may be subject to the National Environmental Policy Act (“NEPA”), which requires federal agencies to evaluate major federal actions having the potential to significantly impact the human environment. In the course of such evaluations, an agency will evaluate the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a detailed Environmental Impact Statement that must be made available for public review and comment. Recent litigation by environmental non-governmental organizations has alleged that the Environmental Assessments for certain oil and natural gas projects violated NEPA by failing to account for climate 
+20 
+change and the greenhouse gas emissions impacts of such projects. On July 16, 2020, the Council on Environmental Quality revised NEPA’s implementing regulations in an effort designed to streamline project approvals. The new regulations were subject to litigation in several federal district courts and were stayed pending an ongoing review of the 2020 rule. On October 6, 2021, the Council on Environmental Quality announced its Phase 1 rule, the first of two planned rules to roll back the 2020 rule, which was finalized on April 20, 2022. The Phase 1 final rule generally restores certain regulatory provisions that were in effect prior to the 2020 rule. To the extent that our current exploration and production activities, as well as proposed exploration and development plans, require federal permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects. 
+Endangered Species Act and Migratory Bird Treaty Act. The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or its habitat. The U.S. Fish and Wildlife Service (the “FWS”) must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. In August 2019, the FWS and National Marine Fisheries Service (“NMFS”) issued three rules amending implementation of the ESA regulations revising, among other things, the process for listing species and designating critical habitat. A coalition of states and environmental groups have challenged these rules. In addition, on December 18, 2020, the FWS amended its regulations governing critical habitat designations, which were also subject to litigation. In June and July 2022, the FWS issued final rules rescinding the regulations defining “habitat” and governing critical habitat exclusions. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”), which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit. This prohibition covers most bird species in the U.S. On January 7, 2021, the Department of the Interior finalized a rule limiting application of the MBTA; however, the Department of the Interior revoked the rule in October 2021 and issued an advance notice of proposed rulemaking seeking comment on the Department’s plan to develop regulations that authorize incidental take under certain prescribed conditions. The notice of proposed rulemaking is expected in March 2023 and is expected to be finalized by the end of 2023. Future implementation of the rules implementing the Endangered Species Act and the MBTA are uncertain. If the Company was to have a portion of its leases designated as critical or suitable habitat or a protected species were located on a lease, it may adversely impact the value of the affected leases. There is also increasing interest in nature-related matters beyond protected species, such as general biodiversity, which may similarly require us or our customers to incur costs or take other measures which may adversely impact our business or operations. 
+Other Regulation of the Oil and Natural Gas Industry. The oil and natural gas industry is extensively regulated by numerous federal, state and local agencies and authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other similar companies in the industry with similar types, quantities and locations of production. 
+The availability, terms, conditions and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas is subject to federal regulation by FERC which regulates the terms, conditions and rates for interstate transportation and storage service and various other matters. State regulations govern the rates, terms, and conditions of service associated with access to intrastate oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transportation in some circumstances may also affect the intrastate transportation of oil and natural gas. 
+Although oil, natural gas, condensate, and NGL sales prices are currently unregulated, the federal government historically has been active in the area of oil and natural gas sales regulation. We cannot predict whether new legislation to regulate oil and natural gas sales might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of natural gas, condensate, oil and NGLs are not currently regulated and are made at market prices. 
+Exports of U.S. Oil Production and Natural Gas Production . In December 2015, the federal government ended its decades-old prohibition of exports of oil produced in the lower 48 states of the U.S. As a result, exports of U.S. oil have increased significantly, reinforcing the general perception in the industry that the end of the U.S. export ban was positive for producers of U.S. oil. In addition, the U.S. Department of Energy authorizes exports of natural gas, including exports of natural gas by pipelines connecting U.S. natural gas production to pipelines in Mexico, and the export of liquefied natural gas (“LNG”) through LNG export facilities, the construction and operation of which are regulated by FERC. Since 2016, natural gas produced in the lower 48 states of the U.S. has been exported as LNG from export facilities in the U.S. Gulf Coast region. LNG export capacity has steadily increased in recent years and is expected to continue increasing due to numerous export facilities that are currently being developed. The industry generally believes that this sustained growth in exports will be a positive development for producers of U.S. natural gas. 
+21 
+Drilling and Production. State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas without a permit and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or may limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affecting the economics of production from these wells or to limit the number of locations we can drill. 
+Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Some state agencies and municipalities require bonds or other financial assurances to support those obligations. 
+Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production and have it transported. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”). Since 1978, various federal laws have been enacted that have resulted in the complete removal of all price and non-price controls for “first sales” of natural gas, which include all of our sales of our own production. 
+Under the Energy Policy Act of 2005 (“EPAct 2005”) Congress amended the NGA and NGPA to give FERC substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess civil penalties up to $1.0 million per day for each violation. This maximum penalty authority has been and will continue to be adjusted periodically to account for inflation. FERC also has authority to order the disgorgement of any ill-gotten gains. EPAct 2005 also amended the NGA to authorize FERC to facilitate transparency in markets for the sale or transportation of physical natural gas in interstate commerce, pursuant to which authorization FERC now requires natural gas wholesale market participants, including a number of entities that may not otherwise be subject to FERC’s traditional NGA jurisdiction, to report information annually to FERC concerning their natural gas sales and purchases. FERC requires any wholesale market participant that sells or purchases 2.2 million MMBtus or more annually in “reportable” natural gas sales to provide a report, known as FERC Form 552, to FERC. Reportable natural gas sales include sales of natural gas that utilize a daily or monthly gas price index, contribute to index price formation, or could contribute to index price formation, such as fixed price transactions for next-day or next-month delivery. 
+FERC also regulates interstate natural gas transportation rates, terms and conditions of service, and the terms under which we as a shipper may use interstate natural gas pipeline capacity. Such regulations affect the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and for the release of our excess, if any, natural gas pipeline capacity. In 1985, FERC began promulgating a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate natural gas pipeline companies are required to provide non-unduly discriminatory transportation services to all shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases, sales, and transportation that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated. We cannot determine what effect, if any, future regulatory changes might have on our natural gas related activities. 
+Under FERC’s current regulatory regime, interstate transportation services must be provided on an open-access, not unduly discriminatory basis at cost-based rates or negotiated rates, both of which are subject to FERC approval. FERC also allows jurisdictional gas pipeline companies to charge market-based rates if the transportation market at issue is sufficiently competitive. The FERC-regulated tariffs, under which interstate pipelines provide such open-access transportation service, contain strict limits on the means by which a shipper releases its pipeline capacity to another potential shipper, and provisions under such tariffs include compliance with FERC’s “shipper-must-have-title” rule. Violations by a shipper (i.e., a pipeline customer) of FERC’s capacity release rules, including the shipper-must-have-title rule, could subject a shipper to substantial penalties and disgorgement of any ill-gotten gains. 
+With respect to its regulation of natural gas pipelines under the NGA, FERC traditionally has not required the applicant for construction and operation of a new interstate natural gas pipeline to provide information concerning the GHG emissions resulting from the activities of the proposed pipeline’s customers. In August 2017, the U.S. Circuit Court of Appeals for the D.C. Circuit issued a decision remanding a natural gas pipeline certificate application to FERC and required FERC to revise its environmental impact statement for the proposed pipeline to analyze potential GHG emission from the specific downstream power plants that the pipeline 
+22 
+was designed to serve. In March 2021, FERC assessed the significance of a project’s GHG emissions and those emissions’ contribution to climate change. FERC compared the project’s reasonably foreseeable GHG emissions to the total GHG emissions of the United States to assess the project’s share of contribution to national GHG levels. FERC announced that it will also consider state GHG emission reduction targets, to the extent a state has such targets. Finally, FERC noted that it will consider “all appropriate evidence” in future proceedings. In February 2022, as redesignated in March 2022, FERC issued a draft interim policy statement on the consideration of GHG emissions in natural gas certification proceedings, which would consider reasonably foreseeable emissions. The draft interim policy statement proposed a significant shift and expansion in FERC’s review of GHG emissions in pipeline certificate proceedings. FERC has not issued a final order on the draft interim policy statement. The scope of FERC’s obligation to analyze the environmental impacts of proposed interstate natural gas pipeline projects, including the upstream indirect impacts of related natural gas production activity, remains subject to ongoing litigation and contested administrative proceedings at FERC and in the courts. 
+Gathering service, which occurs on pipeline facilities located upstream of FERC-jurisdictional interstate transportation services, is regulated by the states onshore and in state waters. Under NGA section 1(b), gathering facilities are exempt from FERC’s jurisdiction. FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transportation function, and FERC applies this test on a case-by-case basis. Depending on changes in the function performed by particular pipeline facilities, FERC has in the past reclassified certain FERC-jurisdictional transportation facilities as non-jurisdictional gathering facilities and FERC has reclassified certain non-jurisdictional gathering facilities as FERC-jurisdictional transportation facilities. Any such changes could result in an increase to our costs of transporting gas to point-of-sale locations. 
+The pipelines used to gather and transport natural gas being produced by the Company are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Act of 1992, as reauthorized and amended, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, the Securing America’s Future Energy: Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016, and the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2019. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In addition, PHMSA had initially considered regulations regarding, among other things, the designation of additional high consequence areas along pipelines, minimum requirements for leak detection systems, installation of emergency flow restricting devices, and revision of valve spacing requirements. In October 2019, PHMSA finalized new safety regulations for hazardous liquid pipelines, including a requirement that operators inspect affected pipelines following extreme weather events or natural disasters, that all hazardous liquid pipelines have a system for detecting leaks and that pipelines in high consequence areas be capable of accommodating in-line inspection tools within twenty years. In addition, PHMSA is in the process of finalizing a rulemaking with respect to gathering lines, but the contents and timing of any final rule for gathering lines are uncertain. In December 2020, Congress passed the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2020 (“PIPES Act of 2020”). In addition to reauthorizing PHMSA, the PIPES Act of 2020 directs the Secretary of Transportation to update or promulgate regulations addressing the safety of certain gas pipeline, gathering, distribution and LNG facilities. On November 15, 2021, PHMSA issued a final rule that expands PHMSA’s safety regulations to more than 400,000 miles of onshore gas gathering pipelines that were previously exempt from PHMSA’s rules. While PHMSA has issued final rules for some of the regulations stemming from the PIPES Act of 2020, others are still proceeding through the rulemaking process. 
+Oil, Condensate and NGLs Sales and Transportation. Sales of oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. The Federal Trade Commission does have anti-market manipulation authority with respect to wholesale sales of oil under the Energy Independence and Security Act of 2007 and its petroleum market manipulation rule. 
+The Company’s sales of oil and NGLs are affected by the availability, terms, conditions and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil and NGLs by pipelines are regulated by FERC under the Interstate Commerce Act (“ICA”). FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and NGL pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and NGL pipeline rates. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. If the regulations relating to the price, terms and conditions for access to pipeline transportation change, we could face higher transportation costs for our production and, possibly, reduced access to transportation capacity. To the extent it may be necessary for new interstate natural gas pipelines to be built, there may be a more stringent regulatory approach at FERC, which could impact our ability to obtain new interstate pipeline transportation capacity. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil and NGL transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors. 
+Further, interstate common carrier oil pipelines must provide service on a not unduly discriminatory basis under the ICA, which is administered by FERC. Under this open access standard, common carriers must offer service to all shippers requesting service on the 
+23 
+same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors. 
+In addition, FERC issued a declaratory order in November 2017, involving a marketing affiliate of an oil pipeline, and such order held that certain arrangements between an oil pipeline and its marketing affiliate would violate the ICA’s anti-discrimination provisions. FERC held that providing transportation service to affiliates at what is essentially the variable cost of the movement, while requiring non-affiliated shippers to pay the filed tariff rate, would violate the ICA. In December 2022, FERC issued an order denying rehearing and clarifying the scope of its holding in the November 2017 declaratory order and how it will assess whether future marketing affiliate transactions violate the ICA. Concurrently with the December 2022 order, FERC issued a proposed policy statement to revise its policy for evaluating whether contractual committed transportation service between oil pipelines and their affiliates complies with the ICA. At this time, the Company cannot currently determine the impact this FERC order and proposed policy statement may have on oil pipelines, their marketing affiliates, and the price of oil and other liquids transported by such pipelines. 
+Any transportation of the Company’s oil, NGLs and purity components (ethane, propane, butane, iso-butane, and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts 171-180, including Emergency Orders by the FRA regulations initially established on May 8, 2015 by PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids; PHMSA regulations were subsequently amended to remove certain requirements on September 25, 2018. In July 2020, PHMSA promulgated a final rule allowing bulk transportation of LNG by rail. The rule also incorporates additional safety requirements. In November 2021, PHMSA issued a notice of proposed rulemaking, seeking to suspend this final rule. 
+State Regulation. Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill. 
+The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us. 
+Financial Regulations, Including Regulations Enacted Under the Dodd-Frank Act . The U.S. Commodities and Futures Exchange Commission (the “CFTC”) holds authority to monitor certain segments of the physical and futures energy commodities market including oil and natural gas. With regard to physical purchases and sales of natural gas and other energy commodities, and any related hedging activities that the Company undertakes, the Company is thus required to observe anti-market manipulation and disruptive trading practices laws and related regulations enforced by the CFTC. The CFTC also holds substantial enforcement authority, including the ability to assess civil penalties. 
+Congress adopted comprehensive financial reform legislation in 2010, establishing federal oversight and regulation of the over-the-counter derivative market and entities that participate in that market. The legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), required the CFTC and the U.S. Securities and Exchange Commission (“SEC”) to promulgate rules and regulations implementing the legislation, including regulations that affect derivatives contracts that the Company uses to hedge its exposure to price volatility. 
+While the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas remain pending. The Company cannot, at this time, predict the timing or contents of any final rules the CFTC may enact with regard to any applicable rulemaking proceeding. Any final rule in either proceeding could impact the Company’s ability to enter into financial derivative transactions to hedge or mitigate exposure to commodity price volatility and other commercial risks affecting our business. 
+Worker Health and Safety . We are subject to a number of federal and state laws and regulations, including OSHA, and comparable state statutes, the purpose of which are to protect the health and safety of workers. In addition, OSHA’s hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations, and that this information be provided to employees, state and local government authorities and citizens. 
+Commitments and Contingencies 
+Our activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, we believe that, absent the occurrence of an extraordinary event, compliance with existing 
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+federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment will not have a material effect upon our capital expenditures, earnings or our competitive position with respect to our existing assets and operations. We cannot predict what effect additional regulation or legislation, enforcement policies included, and claims for damages to property, employees, other persons, and the environment resulting from our operations could have on its activities. See “Note 17 – Commitments and Contingencies” of the Notes to our Consolidated Financial Statements for additional information. 
+Available Information 
+We make available free of charge on our website (www.callon.com) our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the SEC. 
+We also make available within the “About Callon — Governance” section of our website our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and Audit, Compensation, Nominating and ESG, and Operations and Reserves Committee Charters, which have been approved by our Board of Directors. We will make timely disclosure on our website of any change to, or waiver from, the Code of Business Conduct and Ethics for our principal executive and senior financial officers. A copy of our Code of Business Conduct and Ethics is also available, free of charge by writing us at: General Counsel, Callon Petroleum Company, 2000 W. Sam Houston Parkway South, Suite 2000, Houston, TX 77042. 
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+ITEM 1A. Risk Factors 
+Our operations and financial results are subject to various risks and uncertainties, including but not limited to those described below. Our business could also be affected by additional risks and uncertainties not currently known to us or that we currently deem to be immaterial. If any of these risks actually occur, it could materially harm our business, financial condition or results of operations or impair our ability to implement business plans or complete development activities as scheduled. In that case, the market price of our common stock could decline. The following risk factors are summarized as risks related to the oil and natural gas industry, operational risks, marketing and transportation, reserves and drilling locations, technology, indebtedness and financial position, acquisitions, our hedging program, legal and regulatory, tax, other material risks and general risks. 
+Risks Related to the Oil & Natural Gas Industry 
+• 
+Oil and natural gas prices are volatile, and substantial or extended declines in prices may adversely affect our results of operations and financial condition. 
+• 
+If oil and natural gas prices remain depressed for extended periods of time, we may be required to make significant downward adjustments to the carrying value of our oil and natural gas properties. 
+• 
+Our business is subject to climate-related transition risks, including evolving climate change legislation, fuel conservation measures, technological advances and negative shift in market perception towards the oil and natural gas industry, which could result in increased operating expenses and capital costs, financial risks and potential reduction in demand for oil and natural gas. 
+• 
+Negative public perception of the oil and gas industry could have a material and adverse effect on us. 
+• 
+Increased scrutiny of ESG matters could have an adverse effect on our business, financial condition and results of operations and damage our reputation. 
+• 
+The unavailability or high cost of drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could materially and adversely affect our operations and profitability. 
+• 
+An excess supply of oil and natural gas in the market may in the future cause us to reduce production and shut-in our wells, any of which could adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures. 
+Operational Risks 
+• 
+Our operations are dependent on third-party service providers. 
+• 
+Our operations are subject to operating hazards inherent to our industry that may adversely impact our ability to conduct business, and we may not be fully insured against all such operating risks. 
+• 
+We are subject to physical risks arising from climate change, which may have a negative impact on our business and results of operations. 
+• 
+Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns. 
+• 
+Multi-well pad drilling may result in volatility in our operating results. 
+• 
+Restrictions on our ability to obtain, recycle and dispose of water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner. 
+Risks Related to Marketing and Transportation 
+• 
+Factors beyond our control, including the availability and capacity of gas processing facilities and pipelines and other transportation operations owned and operated by third parties, affect the marketability of our production. 
+• 
+We have entered into firm transportation contracts that require us to pay fixed sums of money regardless of quantities actually shipped. If we are unable to deliver the minimum quantities of production, such requirements could adversely affect our results of operations, financial position, and liquidity. 
+Risks Related to Our Reserves and Drilling Locations 
+• 
+Our estimated reserves are based on interpretations and assumptions that may be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. 
+• 
+Unless we replace our oil and gas reserves, our reserves and production will decline. 
+• 
+Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could prevent them from being drilled or delay their drilling. 
+• 
+The development of our PUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. 
+Risks Related to Technology 
+• 
+We may not be able to keep pace with technological developments in our industry. 
+26 
+• 
+Our business could be negatively affected by security threats. A cyberattack or similar incident could occur and result in information theft, data corruption, operational disruption, damage to our reputation or financial loss. 
+Risks Related to Our Indebtedness and Financial Position 
+• 
+Our business requires significant capital expenditures. 
+• 
+Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects. 
+• 
+Restrictive covenants in the agreements governing our indebtedness may limit our ability to respond to changes in market conditions or pursue business opportunities. 
+• 
+Adverse changes in our credit rating may affect our borrowing capacity and borrowing terms. 
+• 
+Our borrowings under our Credit Facility expose us to interest rate risk. 
+• 
+The ability to borrow under our Credit Facility may be restricted to an amount below the amount of borrowings outstanding thereunder or to a lesser amount than what we expect due to future borrowing base reductions or restrictions contained in our other debt agreements. 
+• 
+We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful. 
+• 
+We cannot be certain that we will be able to maintain or improve our leverage position. 
+Risks Related to Acquisitions 
+• 
+We may be unable to integrate successfully the operations of acquisitions with our operations, and we may not realize all the anticipated benefits of these acquisitions. 
+• 
+We may fail to fully identify problems with any properties we acquire, and as such, assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities. 
+Risks Related to Our Hedging Program 
+• 
+Our hedging program may limit potential gains from increases in commodity prices, result in losses, or be inadequate to protect us against continuing and prolonged declines in commodity prices. 
+• 
+Our production is not fully hedged, and we are exposed to fluctuations in oil, natural gas and NGL prices and will be affected by continuing and prolonged declines in oil, natural gas and NGL prices. 
+• 
+Our hedging transactions expose us to counterparty credit risk. 
+Legal and Regulatory Risks 
+• 
+We are subject to stringent and complex federal, state and local laws and regulations which require compliance that could result in substantial costs, delays or penalties. 
+• 
+Federal legislation and state and local legislative and regulatory initiatives relating to hydraulic fracturing and water disposal wells could result in increased costs and additional operating restrictions or delays. 
+• 
+Climate change legislation or regulations restricting emissions of GHG or requiring the reporting of GHG emissions or climate-related information could adversely impact our operating costs and demand for the oil and natural gas we produce. 
+• 
+Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. 
+Tax Risks 
+• 
+Our ability to use our existing net operating loss (“NOL”) carryforwards or other tax attributes could be limited. 
+• 
+Unanticipated changes in effective tax rates or adverse outcomes resulting from examination of our income or other tax returns could adversely affect our financial condition and results of operations. 
+• 
+Tax laws may change over time and such changes could adversely affect our business and financial condition. 
+Other Material Risks 
+• 
+Competitive industry conditions may negatively affect our ability to conduct operations. 
+• 
+All of our producing properties are located in the Permian of West Texas and the Eagle Ford of South Texas, making us vulnerable to risks associated with operating in only two geographic regions. 
+• 
+The results of our planned development programs in new or emerging shale development areas and formations may be subject to more uncertainties than programs in more established areas and formations and may not meet our expectations for reserves or production. 
+• 
+The loss of key personnel, or inability to employ a sufficient number of qualified personnel, could adversely affect our ability to operate. 
+• 
+The inability of one or more of our customers to meet their obligations to us may adversely affect our financial results. 
+27 
+• 
+The COVID-19 pandemic, and various governmental actions taken to mitigate its impact, materially adversely affected, and any future outbreak of any other highly infectious or contagious diseases may materially adversely affect, our business, financial position, results of operations, and cash flows. 
+• 
+Our bylaws designate the Court of Chancery of the State of Delaware (the “Court of Chancery”) as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our shareholders, which could limit our shareholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, or other employees. 
+• 
+Provisions of our charter documents and Delaware law may inhibit a takeover, which could limit the price investors might be willing to pay in the future for our common stock. 
+• 
+We do not currently pay cash dividends on our common stock. 
+General Risk Factors 
+• 
+Declining general economic, business or industry conditions and inflation may have a material adverse effect on our results of operations, liquidity and financial condition. 
+• 
+We may be subject to the actions of activist shareholders. 
+• 
+Future sales of our common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of our common stock or other securities may dilute a shareholder’s ownership in us. 
+Risks Related to the Oil & Natural Gas Industry 
+Oil and natural gas prices are volatile, and substantial or extended declines in prices may adversely affect our results of operations and financial condition. Our success is highly dependent on prices for oil and natural gas, which have in recent years been, and we expect will continue to be, extremely volatile. During the three years ended December 31, 2022, NYMEX WTI prices ranged from a high of $123.64 per barrel on March 8, 2022 to a low of -$36.98 per barrel on April 20, 2020, and NYMEX Henry Hub prices ranged from a high of $23.86 per MMBtu on February 17, 2021 to a low of $1.33 per MMBtu on September 21, 2020. Prices were particularly volatile in 2020 and 2021, with five-year highs occurring in 2021 and five-year lows occurring in 2020, as a result of multiple significant factors impacting supply and demand in the global oil and natural gas markets, including those relating to the COVID-19 global pandemic. The prices of oil and natural gas depend on factors we cannot control, such as macro-economic conditions, levels of production, domestic and worldwide inventories, demand for oil and natural gas, the capacity of U.S. and international refiners to use U.S. supplies of oil, natural gas and NGLs, relative price and availability of alternative forms of energy, actions by non-governmental organizations, OPEC and other countries, legislative and regulatory actions, trade embargoes or sanctions, technology developments impacting energy consumption and energy supply, and weather. These factors make it extremely difficult to predict future oil, natural gas and NGLs price movements with any certainty. We make price assumptions that are used for planning purposes, and a significant portion of our cash outlays, including rent, salaries and non-cancelable capital commitments, are largely fixed in nature. Accordingly, if commodity prices are below the expectations on which these commitments were based, our financial results are likely to be adversely and disproportionately affected because these cash outlays are not variable in the short term and cannot be quickly reduced to respond to unanticipated decreases in commodity prices. 
+In general, prices of oil, natural gas, and NGLs affect the following aspects of our business: our revenues, cash flows, earnings and returns; our ability to attract capital to finance our operations and the cost of the capital; the amount we are allowed to borrow under our Credit Facility; the profit or loss we incur in exploring for and developing our reserves; and the value of our oil and natural gas properties. 
+A substantial or extended decline in commodity prices may also reduce the amount of oil and natural gas that we can produce economically and cause a significant portion of our development projects to become uneconomic. This may result in our having to make significant downward adjustments to our estimated proved reserves. A reduction in production could also result in a shortfall in expected cash flows and require us to reduce capital spending, which could negatively affect our ability to replace our production and our future rate of growth, or require us to borrow funds to cover any such shortfall, which we may be unable to obtain at such time on satisfactory terms. Additionally, a sustained period of weakness in oil, natural gas and NGLs prices, and the resultant effects of such prices on our drilling economics and ability to raise capital, would require us to reevaluate and postpone or eliminate additional drilling. 
+Additionally, if we are required to curtail our drilling program, we may be unable to continue to hold leases that are scheduled to expire, which may further reduce our reserves. As a result, if oil, natural gas and/or NGL prices experience a sustained period of weakness, our future business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures may be materially and adversely affected. 
+If oil and natural gas prices remain depressed for extended periods of time, we may be required to make significant downward adjustments to the carrying value of our oil and natural gas properties. Under the full cost method, which we use to account for our oil and natural gas properties, the net capitalized costs of our oil and natural gas properties may not exceed the PV-10 of our estimated proved reserves, using the 12-Month Average Realized Prices, plus the lower of cost or fair market value of our unproved properties. If such net capitalized costs exceed this limit, we must charge the amount of the excess to earnings. This type of charge will 
+28 
+not affect our cash flows, but will reduce the book value of our stockholders’ equity. We review the carrying value of our properties quarterly and once incurred, an impairment of evaluated oil and natural gas properties is not reversible at a later date, even if prices increase. See “Note 2 – Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements as well as the Supplemental Information on Oil and Natural Gas Operations for additional information. 
+Our business is subject to climate-related transition risks, including evolving climate change legislation, fuel conservation measures, technological advances and negative shift in market perception towards the oil and natural gas industry, which could result in increased operating expenses and capital costs, financial risks and potential reduction in demand for oil and natural gas. Increasing attention from governmental and regulatory bodies, investors, consumers, industry and other stakeholders on combating climate change, together with changes in consumer and industrial/commercial behavior, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary climate-related disclosures, preferences and attitudes with respect to the generation and consumption of energy, the use of hydrocarbons, and the use of products manufactured with, or powered by, hydrocarbons, may result in the enactment of climate change-related regulations, policies and initiatives (at the government, regulator, corporate and/or investor community levels), including alternative energy requirements, new fuel consumption standards, energy conservation and emissions reductions measures and responsible energy development; technological advances with respect to the generation, transmission, storage and consumption of energy (including advances in wind, solar and hydrogen power, as well as battery technology); increased availability of, and increased demand from consumers and industry for, energy sources other than oil and natural gas (including wind, solar, nuclear, and geothermal sources as well as electric vehicles); and development of, and increased demand from consumers and industry for, lower-emission products and services (including electric vehicles and renewable residential and commercial power supplies) as well as more efficient products and services. For further discussions regarding risk related to technological developments, see “—We may not be able to keep pace with technological developments in our industry.” These developments may in the future adversely affect the demand for products manufactured with, or powered by, petroleum products, as well as the demand for, and in turn the prices of, oil and natural gas products. Such developments may also adversely impact, among other things, our stock price and access to capital markets, and the availability to us of necessary third-party services and facilities that we rely on, which may increase our operational costs and adversely affect our ability to successfully carry out our business strategy. Climate change-related developments may also impact the market prices of or our access to raw materials such as energy and water and therefore result in increased costs to our business. 
+More broadly, the enactment of climate change-related regulations, policies and initiatives across the market at the government, corporate, and/or investor community levels may in the future result in increases in our compliance costs and other operating costs and have other adverse effects (e.g., greater potential for governmental investigations or litigation). For further discussion regarding the risks posed to us by climate change-related regulations, policies and initiatives and by negative public perception of the oil and gas industry, see the discussions below in “—Negative public perception of the oil and gas industry could have a material and adverse effect on us,” and “—Climate change legislation or regulations restricting emissions of GHG, changes in the availability of financing for fossil fuel companies and physical effects from climate change could adversely impact our operating costs and demand for the oil and natural gas we produce.” 
+Negative public perception of the oil and gas industry could have a material and adverse effect on us. Opposition toward oil and natural gas drilling and development activity has been growing globally and is particularly pronounced in the United States. Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about climate change may lead to increased reputational and litigation risk and regulatory, legislative and judicial scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. Companies in the oil and natural gas industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, human rights, climate change, environmental matters, sustainability, and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain operations such as drilling and development. Activism could materially and adversely impact our ability to operate our business and raise capital. The foregoing factors may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. In addition, various officials and candidates at the federal, state and local levels, have made climate-related pledges or proposed banning hydraulic fracturing altogether. 
+In addition, some parties have initiated public nuisance claims under federal or state common law against certain companies involved in the production of oil and natural gas, or claims alleging that the companies have been aware of the adverse effects of climate change for some time but failed to adequately disclose such impacts to their investors or customer. Although our business is not a party to any such litigation, we could be named in actions making similar allegations, which could lead to costs and materially impact our financial condition in an adverse way. 
+Negative perceptions regarding our industry and reputational risks may also in the future adversely affect our ability to successfully carry out our business strategy by adversely affecting our access to capital. Certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. Parties concerned about the potential effects of climate change have directed their attention at sources of financing for energy companies, which has resulted in certain financial institutions, 
+29 
+funds and other capital providers restricting or eliminating their investment in oil and natural gas activities. More broadly, some investors, including investment advisors and certain sovereign wealth funds, pension funds, university endowments and family foundations, have stated policies to disinvest in the oil and gas sector based on their social and environmental considerations. Further, certain investment banks and asset managers based both domestically and internationally have announced that they are adopting climate change guidelines for their banking and investing activities. Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas production and related infrastructure projects. Institutional lenders who provide financing to companies in the energy sector have also become more attentive to sustainable lending practices, and some may elect not to provide traditional energy producers or companies that support such producers with funding. Such developments, including ESG activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also potentially result in a reduction of available capital funding for potential development projects, impacting our future financial results. 
+Increased scrutiny of ESG matters could have an adverse effect on our business, financial condition and results of operations and damage our reputation. In recent years, companies across all industries are facing increasing scrutiny from a variety of stakeholders, including investor advocacy groups, proxy advisory firms, certain institutional investors and lenders, investment funds and other influential investors and rating agencies, related to their ESG and sustainability practices. If we do not adapt to or comply with investor or other stakeholder expectations and standards on ESG matters (or meet sustainability goals and targets that we have set), as they continue to evolve, or if we are perceived to have not responded appropriately or quickly enough to growing concern for ESG and sustainability issues, regardless of whether there is a regulatory or legal requirement to do so, we may suffer from reputational damage and our business, financial condition and/or stock price could be materially and adversely affected. 
+In addition, the Company’s continuing efforts to research, establish, accomplish and accurately report on the implementation of our ESG strategy, including any specific ESG objectives, may also create additional operational risks and expenses and expose us to reputational, legal and other risks. While we create and publish voluntary disclosures regarding ESG matters from time to time, some of the statements in those voluntary disclosures may be based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital. 
+Further, our operations, projects and growth opportunities require us to have strong relationships with various key stakeholders, including our shareholders, employees, suppliers, customers, local communities and others. We may face pressure from stakeholders, many of whom are increasingly focused on climate change, to prioritize sustainable energy practices, reduce our carbon footprint and promote sustainability while at the same time remaining a successfully operating public company. If we do not successfully manage expectations across these varied stakeholder interests, it could erode stakeholder trust and thereby affect our brand and reputation. Such erosion of confidence could negatively impact our business through decreased demand and growth opportunities, delays in projects, increased legal action and regulatory oversight, adverse press coverage and other adverse public statements, difficulty hiring and retaining top talent, difficulty obtaining necessary approvals and permits from governments and regulatory agencies on a timely basis and on acceptable terms and difficulty securing investors and access to capital. 
+The unavailability or high cost of drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could materially and adversely affect our operations and profitability. From time to time, during periods of increasing oil and natural gas prices and in periods in which the levels of exploration and production increase, our industry experiences a shortage of drilling and workover rigs, other equipment, pipes, materials and supplies, water and qualified personnel. As a result of such shortage, the costs and delivery times of rigs, equipment and supplies often increase substantially, as well as the wages and costs of drilling rig crews and other experienced personnel and oilfield services, while the quality of these services and equipment may suffer. This impact may be magnified to the extent that the Company's ability to participate in the commodity price increases is limited by its derivative risk management activities. Cost increases in and shortages of such resources may also result from a variety of other factors beyond our control, such as general inflationary pressures, transportation constraints, and increases in the cost of necessary inputs such as electricity, steel and other raw materials, including as a result of increased tariffs or geopolitical issues. 
+An excess supply of oil and natural gas in the market may in the future cause us to reduce production and shut-in our wells, any of which could adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures. An excess supply of oil and natural gas in the market may result in transportation and storage capacity constraints. If, in the future, our transportation or storage arrangements become constrained or unavailable, we may incur significant 
+30 
+operational costs if there is an increase in price for services or we may be required to shut-in or curtail production or flare our natural gas. If we were required to shut-in wells, we might also be obligated to pay certain demand charges for gathering and processing services and firm transportation charges for pipeline capacity we have reserved. Further, any prolonged shut-in of our wells may result in materially decreased well productivity once we are able to resume operations, and any cessation of drilling and development of our acreage could result in the expiration, in whole or in part, of our leases. All of these impacts may adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures. 
+Operational Risks 
+Our operations are dependent on third-party service providers. We contract with third-party service providers to support our operations. These contracted services are generally provided pursuant to master services agreements entered into between the third-party service providers and our operating subsidiaries. Although we have our own employees, our ability to conduct operations and generate revenues is dependent on the availability and performance of those third-party service providers and their compliance with the terms of their respective master service agreements. We cannot guarantee that we will be successful in either retaining the services of our current third-party service providers or contracting with alternative service providers in the event that our current contractors discontinue providing services to us or fail to meet their obligations under their respective master services agreements. Any failure to retain the services of our current service providers or locate alternatives will negatively affect our ability to generate revenues and continue and expand our operations. 
+Our operations are subject to operating hazards inherent to our industry that may adversely impact our ability to conduct business, and we may not be fully insured against all such operating risks. The operating hazards in exploring for and producing oil and natural gas include: encountering unexpected subsurface conditions that cause damage to equipment or personal injury, including loss of life; equipment failures that curtail or stop production or cause severe damage to or destruction of property, natural resources or other equipment; blowouts or other damages to the productive formations of our reserves that require a well to be re-drilled or other corrective action to be taken; and storms and other extreme weather conditions that cause damages to our production facilities or wells. Because of these or other events, we could experience environmental hazards, including release of oil and natural gas from spills, natural gas leaks, accidental leakage of toxic or hazardous materials, such as petroleum liquids, drilling fluids or fracturing fluids, including chemical additives, underground migration, and ruptures. If we experience any of these problems, we could incur substantial losses in excess of our insurance coverage. 
+The occurrence of a significant event or claim, not fully insured or indemnified against, could have a material adverse effect on our financial condition and operations. In accordance with industry practice, we maintain insurance against some of the operating risks to which our business is exposed. Also, no assurance can be given that we will be able to maintain insurance in the future at rates we consider reasonable to cover our possible losses from operating hazards and we may elect no or minimal insurance coverage. 
+We are subject to physical risks arising from climate change, which may have a negative impact on our business and results of operations. Most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere and climate change may produce significant physical effects on weather conditions, such as increased frequency and severity of droughts, storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for oil or natural gas products or cause us to incur significant costs in preparing for or responding to the effects of climatic events themselves, which may not be fully insured. Potential adverse effects could include disruption of our production activities, including, for example, damages to our facilities from winds or floods, increases in our costs of operation, or reductions in the efficiency of our operations, impacts on our personnel, supply chain, or distribution chain, as well as potentially increased costs for insurance coverages in the aftermath of such effects. Any of these effects could have an adverse effect on our assets and operations. Our ability to mitigate the adverse physical impacts of climate change depends in part upon our disaster preparedness and response and business continuity planning. Further, energy needs could increase or decrease as a result of extreme weather conditions depending on the duration and magnitude of any such climate changes. Increased energy use due to weather changes may require us to invest in additional equipment to serve increased demand. A decrease in energy use due to weather changes may affect our financial condition through decreased revenues. The effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations. 
+Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns. Exploration, development, drilling and production activities are subject to many risks. We may invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that any leasehold acreage acquired will be profitably developed, that new wells drilled will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, including wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other 
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+costs. In addition, we may not be successful in controlling our drilling and production costs to improve our overall return and wells that are profitable may not achieve our targeted rate of return. Wells may have production decline rates that are greater than anticipated. Future drilling and completion efforts may impact production from existing wells, and parent-child effects may impact future well productivity as a result of timing, spacing proximity or other factors. Failure to conduct our oil and gas operations in a profitable manner may result in write-downs of our proved reserves quantities, impairment of our oil and gas properties, and a write-down in the carrying value of our unproved properties, and over time may adversely affect our growth, revenues and cash flows. 
+Multi-well pad drilling may result in volatility in our operating results. We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production. In addition, problems affecting a single well could adversely affect production from all of the wells on the pad, which would further cause delays in the scheduled commencement of production or interruptions in ongoing production. These delays or interruptions may cause volatility in our operating results. Further, any delay, reduction or curtailment of our development and producing operations due to operational delays caused by multi-well pad drilling could result in the loss of acreage through lease expirations. 
+Restrictions on our ability to obtain, recycle and dispose of water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner. Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to secure water from local landowners and other third-party sources for use in our operations. If drought conditions were to occur or demand for water were to outpace supply, our ability to obtain water could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. Along with the risks of other extreme weather events, drought risk, in particular, is likely increased by climate change. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows. In addition, significant amounts of water are produced in our operations. Inadequate access to or availability of water recycling or water disposal facilities could adversely affect our production volumes or significantly increase the cost of our operations. 
+Risks Related to Marketing and Transportation 
+Factors beyond our control, including the availability and capacity of gas processing facilities and pipelines and other transportation operations owned and operated by third parties, affect the marketability of our production. The ability to market oil and natural gas from our wells depends upon numerous factors beyond our control. A significant factor in our ability to market our production is the availability and capacity of gas processing facilities and pipeline and other transportation operations, including trucking services, owned and operated by third parties. These facilities and services may be temporarily unavailable to us due to market conditions, physical or mechanical disruption, weather, lack of contracted capacity, available manpower, pipeline safety issues, or other reasons. In certain newer development areas, processing and transportation facilities and services may not be sufficient to accommodate potential production and it may be necessary for new interstate and intrastate pipelines and gathering systems to be built. In addition, we or parties that we utilize might not be able to connect new wells that we complete to pipelines. Our failure to obtain access to processing and transportation facilities and services in a timely manner and on acceptable terms could materially harm our business. We may be required to shut in wells for lack of a market or because of inadequate or unavailable processing or transportation capacity. If that were to occur, we would be unable to realize revenue from those wells until transportation arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells, we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. If we were required to shut in our production for long periods of time due to lack of transportation capacity, it would have a material adverse effect on our business, financial condition, results of operations and cash flows. 
+Other factors that affect our ability to market our production include: 
+• the extent of domestic production and imports/exports of oil and natural gas; 
+• federal regulations authorizing exports of LNG, the development of new LNG export facilities under construction in the U.S. Gulf Coast region, and the timing of the first LNG exports from such facilities; 
+• the construction of new pipelines capable of exporting U.S. natural gas to Mexico and transporting Eagle Ford and Permian oil production to the Gulf Coast; 
+• the proximity of hydrocarbon production to pipelines and gathering infrastructure; 
+• the demand for oil and natural gas by utilities and other end users; 
+• the availability of alternative fuel sources; 
+• the effects of inclement weather, including the effects of chronic and acute climate events associated with the effects of global climate change; and 
+• state and federal regulation of oil, natural gas and NGL marketing and transportation. 
+We have entered into firm transportation contracts that require us to pay fixed sums of money regardless of quantities actually shipped. If we are unable to deliver the minimum quantities of production, such requirements could adversely affect our results of operations, financial position, and liquidity. We have entered into firm transportation agreements for a portion of our 
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+production in certain areas in order to improve our ability, and that of our purchasers, to successfully market our production. We may also enter into firm transportation arrangements for additional production in the future. These firm transportation agreements may be more costly than interruptible or short-term transportation agreements. Additionally, these agreements obligate us to pay fees on minimum volumes regardless of actual throughput. If we have insufficient production to meet the minimum volumes, the requirements to pay for quantities not delivered could have an impact on our results of operations, financial position, and liquidity. 
+Risks Related to Our Reserves and Drilling Locations 
+Our estimated reserves are based on interpretations and assumptions that may be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. This 2022 Annual Report on Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves. The process of estimating oil and natural gas reserves is complex and requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. These assumptions include those required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. 
+Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from the estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this 2022 Annual Report on Form 10-K. Additionally, estimates of reserves and future cash flows may be subject to material downward or upward revisions, based on production history, development drilling and exploration activities and prices of oil and natural gas. 
+You should not assume that any PV-10 of our estimated proved reserves contained in this 2022 Annual Report on Form 10-K represents the market value of our oil and natural gas reserves. We base the PV-10 from our estimated proved reserves at December 31, 2022 on the 12-Month Average Realized Prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures, the rate and timing of production, and changes in governmental regulations or taxes. Recovery of PUDs generally requires significant capital expenditures and successful drilling operations. Our reserve estimates include the assumption that we will make significant capital expenditures to develop these PUDs and the actual costs, development schedule, and results associated with these properties may not be as estimated. In addition, the discount factor used to calculate PV-10 may not be appropriate based on our cost of capital from time to time and the risks associated with our business and the oil and gas industry. 
+Unless we replace our oil and gas reserves, our reserves and production will decline. Our future oil and gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our production, revenues, reserve quantities and cash flows will decline. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. We may not be successful in finding, developing or acquiring additional reserves, and our efforts may not be economic. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be limited to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. 
+Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could prevent them from being drilled or delay their drilling. Our management team has identified drilling locations as an estimation of our future development activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these identified drilling locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, availability and cost of drilling, completion and production services and equipment, lease expirations, regulatory approvals, and other factors discussed in these risk factors. Because of these uncertain factors, we do not know if the identified drilling locations will ever be drilled or if we will be able to produce oil or natural gas from these drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the identified locations are located, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified. 
+The development of our PUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. Developing PUDs requires significant capital expenditures and successful drilling operations, and a substantial amount of our proved reserves are PUDs which may not be ultimately developed or produced. Approximately 39% of our total estimated proved reserves as of December 31, 2022 were PUDs. The reserve data included in the reserve reports of our independent petroleum engineers assume significant capital expenditures will be made to develop such reserves. We cannot be certain that the estimated capital expenditures to develop these reserves are accurate, that development will occur as scheduled, or that the results of such development will be as estimated. We may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including: unexpected drilling conditions; pressure or irregularities in formations; lack of proximity to and shortage of capacity of transportation facilities; equipment failures or accidents and shortages or delays in the availability of drilling rigs, equipment, personnel and services; the availability of capital; and compliance with governmental requirements. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the future net revenues of our estimated PUDs 
+33 
+and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves. 
+Risks Related to Technology 
+We may not be able to keep pace with technological developments in our industry. The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, including technological advances in fuel economy and energy generation devices or other technological advances that could reduce demand for oil and natural gas, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement new technologies at substantial costs. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected. 
+Our business could be negatively affected by security threats. A cyberattack or similar incident could occur and result in information theft, data corruption, operational disruption, damage to our reputation or financial loss. The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing, transportation and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, manage operations, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third-party partners. Our technologies, systems, networks, seismic data, reserves information or other proprietary information, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or could otherwise lead to the disruption of our business operations or other operational disruptions in our exploration or production operations. Cyberattacks are becoming more sophisticated and certain cyber incidents, such as surveillance, may remain undetected for an extended period and could lead to disruptions in critical systems or the unauthorized release of confidential or otherwise protected information. These events could lead to financial losses from remedial actions, loss of business, disruption of operations, damage to our reputation or potential liability. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyberattack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. Cyber incidents have increased, and the U.S. government has issued warnings indicating that energy assets may be specific targets of cybersecurity threats. Our systems and insurance coverage for protecting against cybersecurity risks may not be sufficient. Further, as cyberattacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyberattacks. 
+Risks Related to Our Indebtedness and Financial Position 
+Our business requires significant capital expenditures. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. We intend to fund our capital expenditures through a combination of cash flows from operations and, if needed, borrowings from financial institutions, the sale of debt and equity securities, and asset divestitures. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, participation of non-operating working interest owners, the cost and availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. 
+If the ability to borrow under our Credit Facility or our cash flows from operations decrease, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. The failure to obtain additional financing on terms acceptable to us, or at all, could result in a curtailment of our development activities and could adversely affect our business, financial condition and results of operations. 
+Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects. As of December 31, 2022, we had aggregate outstanding indebtedness of approximately $2.3 billion. Our amount of indebtedness could affect our operations in many ways, including: 
+• requiring us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to fund our operations and other business activities as well as any potential returns to shareholders; 
+• limiting management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; 
+• increasing our vulnerability to downturns and adverse developments in our business and the economy; 
+• limiting our ability to access the capital markets to raise capital on favorable terms, to borrow under our Credit Facility or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness; 
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+• making it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; 
+• making us vulnerable to increases in interest rates as the interest we pay on our indebtedness under our Credit Facility varies with prevailing interest rates; 
+• placing us at a competitive disadvantage relative to competitors with lower levels of indebtedness or less restrictive terms governing their indebtedness; and 
+• making it more difficult for us to satisfy our obligations under our senior notes or other debt and increasing the risk that we may default on our debt obligations. 
+Restrictive covenants in the agreements governing our indebtedness may limit our ability to respond to changes in market conditions or pursue business opportunities. Our Credit Facility and the indentures governing our senior notes contain restrictive covenants that limit our ability to, among other things: incur additional indebtedness including secured indebtedness; make investments; merge or consolidate with another entity; pay dividends or make certain other payments; hedge future production or interest rates; create liens that secure indebtedness; repurchase securities; sell assets; or engage in certain other transactions without the prior consent of the holders or lenders. As a result of these covenants, we are limited in the manner in which we conduct our business and we may be unable to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business. 
+In addition, our Credit Facility requires us to maintain certain financial ratios and to make certain required payments of principal, premium, if any, and interest. If we fail to comply with these provisions or other financial and operating covenants in the Credit Facility or the indentures governing our senior notes, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our Credit Facility could elect to terminate their commitments thereunder, cease making further loans and institute foreclosure proceedings against our assets; and we could be forced into bankruptcy or liquidation. 
+Adverse changes in our credit rating may affect our borrowing capacity and borrowing terms. Our outstanding debt is periodically rated by nationally recognized credit rating agencies. The credit ratings are based on our operating performance, liquidity and leverage ratios, overall financial position, and other factors viewed by the credit rating agencies as relevant to our industry and the economic outlook. Our credit rating may affect the amount and timing of availability of capital we can access, as well as the terms of any financing we may obtain. Because we rely in part on debt financing to fund growth, adverse changes in our credit rating may have a negative effect on our future growth. 
+Our borrowings under our Credit Facility expose us to interest rate risk. Our borrowings under our Credit Facility make us vulnerable to increases in interest rates as they bear interest at a rate elected by us that is based on the prime, SOFR or federal funds rate plus margins ranging from 0.75% to 2.75%, depending on the rate used and the amount of the loan outstanding in relation to the elected commitment. 
+The ability to borrow under our Credit Facility may be restricted to an amount below the amount of borrowings outstanding thereunder or to a lesser amount than what we expect due to future borrowing base reductions or restrictions contained in our other debt agreements. The borrowing base and elected commitment amount under our Credit Facility is currently $2.0 billion and $1.5 billion, respectively, and as of December 31, 2022, we had an aggregate principal balance of $503.0 million outstanding thereunder. Our borrowing base is subject to redeterminations semi-annually, and a future decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations may cause us to not be able to access adequate funding under the Credit Facility. The lenders have sole discretion in determining the amount of the borrowing base and may cause our borrowing base to be redetermined to a materially lower amount, including to below our outstanding borrowings as of such redetermination. In addition, our other debt agreements contain restrictions on the incurrence of additional debt and liens which could limit our ability to borrow under our Credit Facility. If our borrowing base were to be reduced, or if covenants in our indentures restrict our ability to access funding under the Credit Facility, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness. In addition, we cannot borrow amounts above the elected commitments, even if the borrowing base is greater, without new commitments being obtained from the lenders for such incremental amounts above the elected commitments. In the event the amount outstanding under our Credit Facility exceeds the elected commitments, we must repay such amounts immediately in cash. In the event the amount outstanding under our Credit Facility exceeds the redetermined borrowing base, we are required to either (i) grant liens on additional oil and gas properties (not previously evaluated in determining such borrowing base) with a value equal to or greater than such excess, (ii) repay such excess borrowings over six monthly installments, or (iii) elect a combination of options in clauses (i) and (ii). We may not have sufficient funds to make any required repayment. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, an event of default would occur under our Credit Facility. 
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+We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful. Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to certain financial, economic, competitive and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. 
+If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Also, we may not be able to consummate dispositions at such time on terms acceptable to us or at all, and the proceeds of any such dispositions may not be adequate to meet such debt service obligations. Furthermore, any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. In addition, the terms of existing or future debt instruments may restrict us from adopting some of these alternatives. For example, our Credit Facility currently restricts our ability to dispose of assets and our use of the proceeds from such disposition. 
+Any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. 
+We cannot be certain that we will be able to maintain or improve our leverage position. An element of our business strategy involves maintaining a disciplined approach to financial management. However, we are also seeking to acquire, exploit and develop additional reserves that may require the incurrence of additional indebtedness. Although we will seek to maintain or improve our leverage position, our ability to maintain or reduce our level of indebtedness depends on a variety of factors, including future performance and our future debt financing needs. General economic conditions, oil and natural gas prices and financial, business and other factors will also affect our ability to maintain or improve our leverage position. Many of these factors are beyond our control. 
+Risks Related to Acquisitions 
+We may be unable to integrate successfully the operations of acquisitions with our operations, and we may not realize all the anticipated benefits of these acquisitions. We have completed, and may in the future complete, acquisitions that include undeveloped acreage. We can offer no assurance that we will achieve the desired profitability from our recent acquisitions or from any acquisitions we may complete in the future. In addition, failure to integrate future acquisitions successfully could adversely affect our financial condition and results of operations. 
+Our acquisitions may involve numerous risks, including those related to: 
+• operating a larger, more complex combined organization and adding operations; 
+• assimilating the assets, data, and operations of the acquired business, especially if the assets acquired are in a new geographic area; 
+• acquired oil and natural gas reserves not being of the anticipated magnitude or as developed as anticipated; 
+• the loss of significant key employees, including from the acquired business; 
+• the inability to obtain satisfactory title to the assets we acquire; 
+• a decrease in our liquidity if we use a portion of our available cash to finance acquisitions; 
+• a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions; 
+• the diversion of management’s attention from other business concerns, which could result in, among other things, performance shortfalls; 
+• the failure to realize expected profitability or growth; 
+• the failure to realize expected synergies and cost savings; 
+• coordinating geographically disparate organizations, systems, data, and facilities; 
+• coordinating or consolidating corporate and administrative functions; 
+• inconsistencies in standards controls, procedures and policies; and 
+• integrating relationships with customers, vendors and business partners. 
+Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. The elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of our two companies, may not initially offset integration-related costs or achieve a net benefit in the near term or at all. 
+If we consummate any future acquisitions, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions. The inability to effectively manage the integration of acquisitions could reduce our focus on current operations, which in turn, could negatively impact our future results of operations. 
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+We may fail to fully identify problems with any properties we acquire, and as such, assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities. We look to acquire additional acreage in Texas or other regions. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, adequacy of title, operating and capital costs, and potential environmental and other liabilities. Although we conduct a review that we believe is consistent with industry practices, we can give no assurance that we have identified or will identify all existing or potential problems associated with such properties or that we will be able to mitigate any problems we do identify. Such assessments are inexact and their accuracy is inherently uncertain. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface, title and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms. 
+Risks Related to Our Hedging Program 
+Our hedging program may limit potential gains from increases in commodity prices, result in losses, or be inadequate to protect us against continuing and prolonged declines in commodity prices. We enter into arrangements to hedge a portion of our production from time to time to reduce our exposure to fluctuations in oil, natural gas, and NGL prices and to achieve more predictable cash flow. Our hedges at December 31, 2022 are in the form of collars, swaps, put and call options, basis swaps, and other structures placed with the commodity trading branches of certain banking institutions and with certain other commodity trading groups. These hedging arrangements may limit the benefit we could receive from increases in the market or spot prices for oil, natural gas, and NGLs. We cannot be certain that the hedging transactions we have entered into, or will enter into, will adequately protect us from continuing and prolonged declines in oil, natural gas, and NGL prices. To the extent that oil, natural gas, and NGL prices remain at current levels or decline further, we would not be able to hedge future production at the same pricing level as our current hedges and our results of operations and financial condition may be negatively impacted. 
+Our production is not fully hedged, and we are exposed to fluctuations in oil, natural gas and NGL prices and will be affected by continuing and prolonged declines in oil, natural gas and NGL prices. The total volumes which we hedge through use of our derivative instruments varies from period to period and takes into account our view of current and future market conditions in order to provide greater certainty of cash flows to meet our debt service costs and capital program. We generally hedge for the next 12 to 24 months. We intend to continue to hedge our production, but we may not be able to do so at favorable prices. Accordingly, our revenues and cash flows are subject to increased volatility and may be subject to significant reduction in prices which would have a material negative impact on our results of operations. 
+Our hedging transactions expose us to counterparty credit risk. Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract, particularly during periods of falling commodity prices. Disruptions in the financial markets or other factors outside our control could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform, and even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending on market conditions at the time. If the creditworthiness of any of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss. 
+Legal and Regulatory Risks 
+We are subject to stringent and complex federal, state and local laws and regulations which require compliance that could result in substantial costs, delays or penalties. Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. For a discussion of the material regulations applicable to us, see “Business and Properties — Regulations.” These laws and regulations may: 
+• require that we acquire permits before commencing drilling; 
+• regulate the spacing of wells and unitization and pooling of properties; 
+• impose limitations on production or operational, emissions control and other conditions on our activities; 
+• restrict the substances that can be released into the environment or used in connection with drilling and production activities or restrict the disposal of waste from our operations; 
+• limit or prohibit drilling activities on protected areas, such as wetlands and wilderness; 
+• impose requirements to protect our employees and mitigate safety risks; 
+• impose penalties or other sanctions for accidental or unpermitted spills or releases from our operations; or 
+• require measures to remediate or mitigate pollution and environmental impacts from current and former operations, such as cleaning up spills or decommissioning abandoned wells and production facilities. 
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+Significant expenditures may be required to comply with governmental laws and regulations applicable to us. In addition, failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, permit revocations, requirements for additional pollution controls or injunctions limiting or prohibiting operations. 
+The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal, state and local agencies frequently review, revise and supplement environmental laws and regulations, and such changes could result in increased costs for environmental compliance, such as emissions monitoring and control, permitting, or waste handling, storage, transport, remediation or disposal for the oil and natural gas industry and could have a significant impact on our operating costs. In general, the oil and natural gas industry recently has been the subject of increased legislative and regulatory attention with respect to public health and environmental matters. Even if regulatory burdens temporarily ease from time to time, the historic trend of more expansive and stricter environmental legislation and regulations may continue in the long-term. 
+Further, under these laws and regulations, we could be liable for costs of investigation, removal and remediation, damages to and loss of use of natural resources, loss of profits or impairment of earning capacity, property damages, costs of increased public services, as well as administrative, civil and criminal fines and penalties, and injunctive relief. Certain environmental statutes, including RCRA, CERCLA, OPA and analogous state laws and regulations, impose strict, joint and several liability for costs required to investigate, clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released (i.e., liability may be imposed regardless of whether the current owner or operator was responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time the release or contamination occurred). We could also be affected by more stringent laws and regulations adopted in the future, including any related to climate change, engine and other equipment emissions, GHGs and hydraulic fracturing. Under common law, we could be liable for injuries to people and property. We maintain limited insurance coverage for sudden and accidental environmental damages. We do not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Also, we do not believe that insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability in excess of our insurance coverage or we may be required to curtail or cease production from properties in the event of environmental incidents. 
+Federal legislation and state and local legislative and regulatory initiatives relating to hydraulic fracturing and water disposal wells could result in increased costs and additional operating restrictions or delays. Hydraulic fracturing is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production and is typically regulated by state oil and gas commissions. However, from time to time, the U.S. Congress has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing. Legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and to require federal permitting and regulatory control of hydraulic fracturing but has not passed. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA regulates hydraulic fracturing with fluids containing diesel fuel under the UIC program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act. The EPA has recently taken steps to strengthen its methane standards, including most recently in November 2021 and 2022, when the EPA issued a proposed rule and supplemental rule intended to reduce methane emissions from oil and gas sources. The November 2021 rule would make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the CAA (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities). In addition, the November 2021 rule would establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by EPA. States would have three years to develop their compliance plan for existing sources and the regulations for new sources would take effect immediately upon issuance of a final rule. Additionally, on November 11, 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule. Among other things, the November 2022 supplemental proposed rule removes an emissions monitoring exemption for small wellhead-only sites and creates a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters.” The EPA is expected to issue a final rule by August 2023. The scope of future obligations remains uncertain; however, given the long-term trend towards increasing regulation, future federal regulation of methane and other greenhouse gas emissions from the oil and gas industry remains a possibility. 
+In some areas of Texas, including the Eagle Ford and Permian, there has been concern that certain formations into which disposal wells are injecting produced waters could become over-pressured after many years of injection, and the RRC is reviewing the data to determine whether any regulatory action is necessary to address this issue. If the RRC were to decline to issue permits for, or impose new limits on the volumes of, injection wells into the formations that we currently utilize, we may be required to seek alternative methods of disposing of produced waters, including injecting into deeper formations, which could increase our costs. 
+Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, impose additional requirements on hydraulic fracturing activities or otherwise require the public disclosure of 
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+chemicals used in the hydraulic fracturing process. For example, Texas law requires the chemical components used in the hydraulic fracturing process, as well as the volume of water used, must be disclosed to the RRC and the public. The RRC’s “well integrity rule” includes testing and reporting requirements, such as (i) the requirement to submit to the RRC cementing reports after well completion or cessation of drilling and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. Additionally, the RRC rules require applicants for certain new water disposal wells to conduct seismic activity searches using the U.S. Geological Survey to determine the potential for earthquakes within a circular area of 100 square miles. Further, the RRC has authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The RRC has used this authority to deny permits for, and limit volumes for, disposal wells. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of drilling in general or hydraulic fracturing in particular. 
+The EPA has also issued the “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States” report, concluding that hydraulic fracturing can impact drinking water resources in certain circumstances but also noted that certain data gaps and uncertainties limited EPA’s ability to fully characterize the severity of impacts or calculate the national frequency of impacts on drinking water resources from activities in the hydraulic fracturing water cycle. This study could result in additional regulatory scrutiny that could restrict our ability to perform hydraulic fracturing and increase our costs of compliance and doing business. 
+There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, water usage and the potential for impacts to surface water, groundwater and the environment generally, and a number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. Several states and municipalities have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances. If new laws or regulations that significantly restrict hydraulic fracturing or water disposal wells are adopted, such laws could make it more difficult or costly for us to drill for and produce oil and natural gas as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements, permitting delays and potential increases in costs. These changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing. 
+Climate change legislation or regulations restricting emissions of GHG or requiring the reporting of GHG emissions or climate-related information could adversely impact our operating costs and demand for the oil and natural gas we produce. In recent years, federal, state and local governments have taken steps to reduce emissions of GHGs. The EPA has finalized a series of GHG monitoring, reporting and emissions control rules and proposed additional rules, and the U.S. Congress has, from time to time, considered adopting legislation to reduce or tax emissions. Several states have already taken measures to reduce emissions of GHGs primarily through the development of GHG emission inventories or regional GHG cap-and-trade programs. While we are subject to certain federal GHG monitoring and reporting requirements, our operations currently are not adversely impacted by existing federal, state and local climate change initiatives. For a description of some existing and proposed GHG rules and regulations, see “Business and Properties—Regulations.” 
+At the international level, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change resulted in nearly 200 countries, including the United States, coming together to develop the Paris Agreement, which intended to nationally determine their contributions and set GHG emission reduction goals every five years beginning in 2020. The Agreement went into effect on November 4, 2016 and establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. In 2020, the United States withdrew from the Paris Agreement. However, in February 2021, the current administration rejoined the Paris Agreement and later announced a target for the U.S. to achieve a 50% to 52% reduction from 2005 levels in economy-wide GHG emissions by 2030. In addition, in September 2021, President Biden publicly announced the Global Methane Pledge, a pact that aims to reduce global methane emissions at least 30% below 2020 levels by 2030, including “all feasible reductions” in the energy sector. Since its formal launch at the COP26, over 150 countries have joined the pledge. Most recently, at the 27th conference of parties (“COP27”), President Biden announced the EPA’s proposed standards to reduce methane emissions from existing oil and gas sources, and agreed, in conjunction with the European Union and a number of other partner countries, to develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. Various state and local governments have also publicly committed to furthering the goals of the Paris Agreement. In addition, a number of states have begun taking actions to control or reduce emissions of GHGs. 
+Restrictions on GHG emissions that may be imposed could adversely affect the oil and gas industry. The adoption of legislation or regulatory programs to reduce GHG emissions or that require the reporting of GHG emissions or other climate-related information could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements, and to monitor and report on GHG emissions. Any GHG 
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+emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Moreover, incentives or requirements to conserve energy, use alternative energy sources, reduce GHG emissions in product supply chains, and increase demand for low-carbon fuel or zero-emissions vehicles, could reduce demand for the oil and natural gas we produce. International commitments, re-entry into the Paris Agreement, and President Biden’s executive orders may result in the development of additional regulations or changes to existing regulations. At the federal level, although no comprehensive climate change legislation regulating the emission of GHGs or directly imposing a price on carbon has been implemented to date, such legislation has periodically been introduced in the U.S. Congress and may be proposed or adopted in the future. The $1 trillion legislative infrastructure package passed by Congress in November 2021 includes a number of climate-focused spending initiatives targeted at climate resilience, enhanced response and preparation for extreme weather events and clean energy and transportation investments. The IRA 2022 also provides significant funding and incentives for research and development of low-carbon energy production methods, carbon capture and other programs directed at addressing climate change. Additionally, the SEC issued a proposed rule in March 2022 that would mandate extensive disclosure of climate-related data, risks and opportunities, including financial impacts, physical and transition risks, related governance and strategy and GHG emissions, for certain public companies. We cannot predict the costs of implementation or any potential adverse impacts resulting from the rulemaking. To the extent this rulemaking is finalized as proposed, we could incur increased costs relating to the assessment and disclosure of climate-related risks. We may also face increased litigation risks related to disclosures made pursuant to the rule if finalized as proposed. In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon-intensive sectors. Consequently, legislation and regulatory programs to reduce or require reporting relating to GHG emissions could have an adverse effect on our business, financial condition and results of operations. 
+In addition, fuel conservation measures, alternative fuel requirements and increasing consumer demand for alternatives to oil and natural gas could reduce demand for oil and natural gas, and activism, litigation and initiatives aimed at limiting climate change and reducing air pollution could impact our business activities, operations and ability to access capital. For further discussion on transition risks related to climate change legislation and regulation, see “—Our business is subject to climate-related transition risks, including evolving climate change legislation, fuel conservation measures, technological advances and negative shift in market perception towards the oil and natural gas industry could result in increased operating expenses and capital costs, financial risks and potential reduction in demand for oil and natural gas” and “—Negative public perception of the oil and gas industry could have a material and adverse effect on us.” 
+Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. Title VII of the Dodd-Frank Act establishes federal oversight and regulation of over-the-counter derivatives and requires the CFTC and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the over-the-counter market. 
+Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas, including the scope of relevant definitions or exemptions, remain pending. The CFTC issued a final rule on margin requirements for uncleared swap transactions in January 2016, which it amended in November 2018. The final rule as amended includes an exemption for certain commercial end-users that enter into uncleared swaps in order to hedge bona fide commercial risks affecting their business. In addition, the CFTC has issued a final rule authorizing an exception from the requirement to use cleared exchanges (rather than hedging over-the-counter) for commercial end-users who use swaps to hedge their commercial risks. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations. On January 24, 2020, U.S. banking regulators published a new approach for calculating the quantum of exposure of derivative contracts under their regulatory capital rules. This approach to measuring exposure is referred to as the standardized approach for counterparty credit risk or SA-CCR. It requires certain financial institutions to comply with significantly increased capital requirements for over-the-counter commodity derivatives. In addition, on September 15, 2020, the CFTC issued a final rule regarding the capital a swap dealer or major swap participant is required to set aside with respect to its swap business. These two sets of regulations and the increased capital requirements they place on certain financial institutions may reduce the number of products and counterparties in the over-the-counter derivatives market available to us and could result in significant additional costs being passed through to end-users like us. On January 14, 2021, the CFTC published a final rule on position limits for certain commodities futures and their economically equivalent swaps, though like several other rules there is a bona fide hedging exemption to the application of such rule. All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business. 
+Depending on our ability to satisfy the CFTC’s requirements for the various exemptions available for a commercial end-user using swaps to hedge or mitigate its commercial risks, the final rules may provide beneficial exemptions and/or may require us to comply with position limits and other limitations with respect to our financial derivative activities. The Dodd-Frank Act may require our current counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which could increase the cost to us of entering into such derivatives. The Dodd-Frank Act may also require our current counterparties to financial 
+40 
+derivative transactions to cease their current business as hedge providers or spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. These potential changes could reduce the liquidity of the financial derivatives markets which would reduce the ability of commercial end-users like us to hedge or mitigate their exposure to commodity price volatility. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of future swaps relative to the terms of our existing financial derivative contracts, and reduce the availability of derivatives to protect against commercial risks we encounter. 
+If we reduce our use of derivative contracts as a result of any of the foregoing new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Our revenues could be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations, or cash flows. 
+Tax Risks 
+Our ability to use our existing net operating loss (“NOL”) carryforwards or other tax attributes could be limited. A portion of our NOL carryforward balance was generated prior to the effective date of limitations on utilization of NOLs imposed by the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) and are allowable as a deduction against 100% of taxable income in future years, but will start to expire in the 2034 taxable year. The remainder were generated following such effective date and, thus, generally allowable as a deduction against 80% of taxable income in future years (with an exception to this rule due to the enactment of the Coronavirus Aid, Relief, and Economic Security Act, whereby the utilization of NOLs was temporarily expanded for taxable years beginning before 2021). Utilization of any NOL carryforwards depends on many factors, including our ability to generate future taxable income, which cannot be assured. In addition, Section 382 (“Section 382”) of the Internal Revenue Code of 1986, as amended (the “Code”), generally imposes, upon the occurrence of an ownership change (discussed below), an annual limitation on the amount of our pre-ownership change NOLs we can utilize to offset our taxable income in any taxable year (or portion thereof) ending after such ownership change. The limitation is generally equal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate. In general, an ownership change occurs if there is a cumulative increase in our ownership of more than 50 percentage points by one or more “5% shareholders” (as defined in the Code) at any time during a rolling three-year period. Future ownership changes and/or future regulatory changes could further limit our ability to utilize our NOLs. To the extent we are not able to offset our future income with our NOLs, this could adversely affect our operating results and cash flows once we attain profitability. 
+Unanticipated changes in effective tax rates or adverse outcomes resulting from examination of our income or other tax returns could adversely affect our financial condition and results of operations. We are subject to income taxes in the U. S., and our domestic tax assets and liabilities are subject to the allocation of expenses in differing jurisdictions. Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including the following: changes in the valuation of our deferred tax assets and liabilities; expected timing and amount of the release of any tax valuation allowances; tax effects of stock-based compensation; costs related to intercompany restructurings; changes in tax laws, regulations or interpretations thereof; or lower than anticipated future earnings in our taxing jurisdictions. In addition, we may be subject to audits of our income, sales and other transaction taxes by U.S. federal and state authorities. Outcomes from these audits could have an adverse effect on our financial condition and results of operations. 
+Tax laws may change over time and such changes could adversely affect our business and financial condition. From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws, including (i) the elimination of the immediate deduction for intangible drilling and development costs, (ii) changes to a depletion allowance for oil and natural gas properties, (iii) the implementation of a carbon tax, (iv) an extension of the amortization period for certain geological and geophysical expenditures, (v) changes to tax rates, and (vi) the introduction of a minimum tax. While these specific changes were not included in recent legislation such as the IRA 2022, no accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. The elimination of U.S. federal tax deductions, as well as any other changes to or the imposition of new federal, state, local or non-U.S. taxes (including the imposition of, or increases in production, severance or similar taxes) could adversely affect our business and financial condition. 
+Other Material Risks 
+Competitive industry conditions may negatively affect our ability to conduct operations. We compete with numerous other companies in virtually all facets of our business. Our competitors in development, exploration, acquisitions and production include major integrated oil and gas companies and smaller independents as well as numerous financial buyers. Some of our competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources permit. We also compete for the materials, equipment, personnel and services that are necessary for the exploration, development and operation of our properties. Our ability to increase reserves in the future will be dependent on our ability to select and acquire suitable prospects for future exploration and development. 
+41 
+All of our producing properties are located in the Permian of West Texas and the Eagle Ford of South Texas, making us vulnerable to risks associated with operating in only two geographic regions. As a result of this concentration, as compared to companies that have a more diversified portfolio of properties, we may be disproportionately exposed to the impact of regional supply and demand factors, severe weather, delays or interruptions of production from wells in this area caused by governmental regulation, specific taxes or other regulatory legislation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services, or market limitations or interruption of the processing or transportation of oil, natural gas or NGLs. Such delays, interruptions or limitations could have a material adverse effect on our financial condition and results of operations. In addition, the effect of fluctuations on supply and demand may be more pronounced within specific geographic oil and natural gas producing areas, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. 
+The results of our planned development programs in new or emerging shale development areas and formations may be subject to more uncertainties than programs in more established areas and formations and may not meet our expectations for reserves or production. The results of our horizontal drilling efforts in emerging areas and formations of the Permian are generally more uncertain than drilling results in areas that are more developed and have more established production from horizontal formations. Because emerging areas and associated target formations have limited or no production history, we are less able to rely on past drilling results in those areas as a basis to predict our future drilling results. In addition, horizontal wells drilled in shale formations, as distinguished from vertical wells, utilize multilateral wells and stacked laterals, all of which are subject to well spacing, density and proration requirements of the RRC, which requirements could adversely impact our ability to maximize the efficiency of our horizontal wells related to reservoir drainage over time. Further, access to adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more challenging in new or emerging areas. If our drilling results in these areas are less than anticipated or we are unable to execute our drilling program in these areas because of capital constraints, access to gathering systems and takeaway capacity or otherwise, or natural gas and oil prices decline, our investment in these areas may not be as economic as we anticipate, we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future. 
+The loss of key personnel, or inability to employ a sufficient number of qualified personnel, could adversely affect our ability to operate. We depend, and will continue to depend in the foreseeable future, on the services of our senior officers and other key employees, as well as other third-party consultants with extensive experience and expertise in evaluating and analyzing drilling prospects and producing oil and natural gas and maximizing production from oil and natural gas properties. Our ability to retain our senior officers, other key employees, and third-party consultants, many of whom are not subject to employment agreements, is important to our future success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business. Also, we may experience employee turnover or labor shortages if our business requirements, compensation, benefits and/or perquisites are inconsistent with the expectations of current or prospective employees, or if workers pursue employment in fields with less volatility than in the energy industry. If we are unsuccessful in our efforts to attract and retain sufficient qualified personnel on terms acceptable to us, or do so at rates necessary to maintain our competitive position, our business could be adversely affected. 
+The inability of one or more of our customers to meet their obligations to us may adversely affect our financial results. Our principal exposure to credit risk is through receivables resulting from the sale of our oil and natural gas production, advances to joint interest parties and joint interest receivables. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. The largest purchaser of our oil and natural gas accounted for approximately 15% of our total revenues for the year ended December 31, 2022. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. 
+The COVID-19 pandemic, and various governmental actions taken to mitigate its impact, materially adversely affected, and any future outbreak of any other highly infectious or contagious diseases may materially adversely affect, our business, financial position, results of operations, and cash flows. The COVID-19 pandemic, and various governmental actions taken to mitigate its impact, have negatively impacted the global economy, disrupted global supply chains, and created significant volatility and disruption of financial and commodity markets. The pandemic has also increased volatility and, from time to time, caused negative pressure in the capital markets; as a result, in the future, we may experience difficulty accessing the capital or financing needed to fund our operations, which have substantial capital requirements, on satisfactory terms or at all, compounding liquidity risks associated with a material reduction in our revenues and cash flows as a result of any future declines in demand due to the COVID-19 pandemic or any future pandemic. 
+While we expect the COVID-19 pandemic and related economic repercussions to continue to affect our business, financial condition, results of operations, and cash flows, the extent of the impact of the COVID-19 pandemic on our business and our operational and financial performance, including our ability to execute our business strategies and initiatives in the expected time frame, is uncertain and depends on various factors that we cannot predict. There are no comparable recent events that provide guidance as to the effect the COVID-19 pandemic may have, and as a result, the ultimate impact of the pandemic is highly uncertain and subject to change. 
+42 
+Our bylaws designate the Court of Chancery of the State of Delaware (the “Court of Chancery”) as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our shareholders, which could limit our shareholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, or other employees. Our bylaws provide that, unless we consent in writing to the selection of an alternative forum, the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action or proceeding asserting a claim for breach of a fiduciary duty owed by any current or former director, officer, or other employee of our company to us or our shareholders, (iii) any action or proceeding asserting a claim against us or any current or former director, officer, or other employee of our company arising pursuant to any provision of the Delaware General Corporate Law (the “DGCL”) or our charter or bylaws (as each may be amended from time to time), (iv) any action or proceeding asserting a claim against us or any current or former director, officer, or other employee of our company governed by the internal affairs doctrine, or (v) any action or proceeding as to which the DGCL confers jurisdiction on the Court of Chancery shall be the Court of Chancery or, if and only if the Court of Chancery lacks subject matter jurisdiction, any state court located within the State of Delaware or, if and only if such state courts lack subject matter jurisdiction, the federal district court for the District of Delaware, in all cases to the fullest extent permitted by law and subject to the court’s having personal jurisdiction over the indispensable parties named as defendants. 
+Our exclusive forum provision is not intended to apply to claims arising under the Securities Act or the Exchange Act. To the extent the provision could be construed to apply to such claims, there is uncertainty as to whether a court would enforce the forum selection provision with respect to such claims, and in any event, our shareholders would not be deemed to have waived our compliance with federal securities laws and the rules and regulations thereunder. 
+Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock is deemed to have received notice of and consented to the foregoing forum selection provision. This provision may limit our shareholders’ ability to bring a claim in a judicial forum that they find favorable for disputes with us or our directors, officers, or other employees, which may discourage such lawsuits. Alternatively, if a court were to find this choice of forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect its business, financial condition, prospects, or results of operations. 
+Provisions of our charter documents and Delaware law may inhibit a takeover, which could limit the price investors might be willing to pay in the future for our common stock. Provisions in our certificate of incorporation and bylaws may have the effect of delaying or preventing an acquisition of the Company or a merger in which we are not the surviving company and may otherwise prevent or slow changes in our Board of Directors and management. In addition, because we are incorporated in Delaware, we are governed by the provisions of Section 203 of the DGCL. These provisions could discourage an acquisition of the Company or other change in control transactions and thereby negatively affect the price that investors might be willing to pay in the future for our common stock. 
+We do not currently pay cash dividends on our common stock. We do not currently pay dividends on our common stock and any future determination as to the declaration and payment of cash dividends will be at the discretion of our Board of Directors and will depend upon our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors deemed relevant by our Board of Directors at the time of such determination. Consequently, a shareholder’s only current opportunity to achieve a return on its investment in us will be by selling its shares of our common stock at a price greater than the shareholder paid for it. There is no guarantee that the price of our common stock that will prevail in the market will exceed the price at which a shareholder purchased its shares of our common stock. 
+General Risk Factors 
+Declining general economic, business or industry conditions and inflation may have a material adverse effect on our results of operations, liquidity and financial condition. Concerns over global economic conditions, energy costs, supply chain disruptions, increased demand, labor shortages associated with a fully employed U.S. labor force, geopolitical issues, inflation, the availability and cost of credit and the United States financial market and other factors have contributed to increased economic uncertainty and diminished expectations for the global economy. Although inflation in the United States had been relatively low for many years, there was a significant increase in inflation beginning in the second half of 2021, which has continued into 2022, due to a substantial increase in money supply, a stimulative fiscal policy, a significant rebound in consumer demand as COVID-19 restrictions were relaxed, the Russia-Ukraine war and worldwide supply chain disruptions resulting from the economic contraction caused by COVID-19 and lockdowns followed by a rapid recovery. Inflation rose from 5.4% in June 2021 to 7.0% in December 2021 to 8.2% in September 2022. As of December 31, 2022, inflation was at 6.5%. Though we incorporated inflationary factors into our 2022 business plan, inflation has outpaced those original assumptions. We continue to undertake actions and implement plans to strengthen our supply chain to address these pressures and protect the requisite access to commodities and services. Nevertheless, we expect for the foreseeable future to experience supply chain constraints and inflationary pressure on our cost structure. Principally, commodity costs for steel and chemicals required for drilling, higher transportation and fuel costs and wage increases have increased our operating costs for the year ended December 31, 2022 compared to the same period in 2021. We also may face shortages of these commodities and labor, which may prevent us from executing our development plan. These supply chain constraints and inflationary pressures will 
+43 
+likely continue to adversely impact our operating costs and, if we are unable to manage our supply chain, it may impact our ability to procure materials and equipment in a timely and cost-effective manner, if at all, which could impact our ability to distribute available cash and result in reduced margins and production delays and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected. 
+We are taking actions to mitigate supply chain and inflationary pressures. We are working closely with suppliers and contractors to ensure availability of supplies on site, especially fuel, steel and chemical suppliers which are critical to many of our operations. However, these mitigation efforts may not succeed or may be insufficient. 
+In addition, continued hostilities related to the Russian invasion of Ukraine and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. These factors and other factors, combined with volatile commodity prices, and declining business and consumer confidence may contribute to an economic slowdown and a recession. Recent growing concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our business, financial condition and results of operations. 
+We may be subject to the actions of activist shareholders. We have been the subject of an activist shareholder in the past. Responding to shareholder activism can be costly and time-consuming, disrupt our operations and divert the attention of management and our employees from executing our business plan. Activist campaigns can create perceived uncertainties as to our future direction, strategy or leadership and may result in the loss of potential business opportunities, harm our ability to attract new investors, customers and joint venture partners and cause our stock price to experience periods of volatility or stagnation. Moreover, if individuals are elected to our Board of Directors with a specific agenda, our ability to effectively and timely implement our current initiatives, retain and attract experienced executives and employees and execute on our long-term strategy may be adversely affected. 
+Future sales of our common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of our common stock or other securities may dilute a shareholder’s ownership in us. In the future, we may continue to issue securities to raise capital. We may also continue to acquire interests in other companies by using any combination of cash and our common stock or other securities convertible into, or exchangeable for, or that represent the right to receive, our common stock. Any of these events may dilute your ownership interest in our company, reduce our earnings per share or have an adverse impact on the price of our common stock. In addition, secondary sales of a substantial amount of our common stock in the public market, or the perception that these sales may occur, could reduce the market price of our common stock. Any such reduction in the market price of our common stock could impair our ability to raise additional capital through the sale of our securities. 
+ITEM 1B. Unresolved Staff Comments 
+None. 
+ITEM 3. Legal Proceedings 
+We are a party in various legal proceedings and claims, which arise in the ordinary course of our business. While the outcome of these events cannot be predicted with certainty, we believe that the ultimate resolution of any such actions will not have a material effect on our financial position or results of operations. 
+In January 2022, we received a Notice of Violation from the EPA related to the CAA. The enforcement action will likely result in monetary sanctions yet-to-be specified and corrective actions, which may increase our development costs and/or operating costs. We are unable to predict the ultimate outcome of this matter at this time, however, we believe that any penalties, mitigation costs, or corrective actions that may result from this matter will not have a material adverse effect on our consolidated financial position, results of operations, or cash flows. 
+ITEM 4. Mine Safety Disclosures 
+Not applicable. 
+44 
+PART II. 
+ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+Market Information 
+Our common stock trades on the New York Stock Exchange (“NYSE”) under the symbol “CPE.” 
+Holders 
+As of February 17, 2023 the Company had approximately 1,083 common stockholders of record. 
+Dividends 
+We have not paid any cash dividends on our common stock to date. However, we continuously monitor many internal and external factors as we consider when, or if, we should implement shareholder return programs. These factors include our current and projected financial performance; our debt metrics, covenants and absolute amounts borrowed; commodity price outlooks; cash requirements; corporate and strategic plans; and macroeconomic indicators. Ultimately, the timing, amount and form of shareholder return programs, if any, is subject to the discretion of our Board of Directors and to certain limitations imposed under Delaware corporate law and the agreements governing our debt obligations. 
+Performance Graph 
+The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the performance of the Company’s common stock relative to a broad-based stock performance index and an industry specific stock index. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. 
+In 2022, the Company chose to compare its cumulative total return against a published industry index, the Standard & Poor’s Oil & Gas Exploration and Production Select Industry Index (“XOP Index”), instead of a Company selected peer group. The XOP Index includes a larger group of peers to align with the industry and provide a broader comparison of stock price performance. The Company’s previous peer group consisted of Magnolia Oil & Gas Corporation, Matador Resources Company, PDC Energy, Inc., Permian Resources Corporation, Ranger Oil Corporation, SM Energy Company and Vital Energy, Inc. 
+The stock price performance graph compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the Standard & Poor’s 500 Index (“S&P 500 Index”), a broad market index, the XOP Index, an index focused on the U.S. oil and gas exploration and production industry, and the previous peer group to which we compare our performance from December 31, 2017 through December 31, 2022. The Company’s historical stock prices used in the graph below have been retroactively adjusted to reflect the Company’s 1-for-10 reverse stock split effective August 7, 2020. 
+45 
+The stock price performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that the Company specifically incorporates it by reference into such filing. 
+Comparison of Five Year Cumulative Total Return 
+Assumes Initial Investment of $100 
+December 31, 2022 
+46 
+ITEM 6. Reserved 
+ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+The following management’s discussion and analysis describes the principal factors affecting our results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying audited consolidated financial statements, information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results, which are included in various parts of this filing. 
+A discussion and analysis of the Company’s financial condition and results of operations for the year ended December 31, 2020 can be found in “Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” of its Annual Report on Form 10-K for the year ended December 31, 2021, which was filed with the SEC on February 24, 2022. 
+General 
+We are an independent oil and natural gas company focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas. Our activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger Permian Basin in West Texas, as well as the Eagle Ford in South Texas. Our operating culture is centered on responsible development of hydrocarbon resources, safety and the environment, which we believe strengthens our operational performance. Our drilling activity is predominantly focused on the horizontal development of several prospective intervals in the Permian, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales, and in the Eagle Ford. We have assembled a multi-year inventory of potential horizontal well locations and intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and through acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps. 
+Financial and Operational Highlights 
+For discussion of our significant financial and operational highlights for the year ended December 31, 2022, please see “Part I. Items 1 and 2. Business and Properties — Overview — Major Developments in 2022”. 
+47 
+Results of Operations 
+Production 
+Years Ended December 31, 
+2022 2021 $ Change % Change 
+Total production 
+Oil (MBbls) 
+Permian 18,041 14,475 3,566 25 % 
+Eagle Ford 5,598 7,749 (2,151) (28 %) 
+Total oil 23,639 22,224 1,415 6 % 
+Natural gas (MMcf) 
+Permian 35,519 29,682 5,837 20 % 
+Eagle Ford 6,108 7,704 (1,596) (21 %) 
+Total natural gas 41,627 37,386 4,241 11 % 
+NGLs (MBbls) 
+Permian 6,424 5,155 1,269 25 % 
+Eagle Ford 1,052 1,284 (232) (18 %) 
+Total NGLs 7,476 6,439 1,037 16 % 
+Total production (MBoe) 
+Permian 30,385 24,577 5,808 24 % 
+Eagle Ford 7,668 10,317 (2,649) (26 %) 
+Total barrels of oil equivalent 38,053 34,894 3,159 9 % 
+Total daily production (Boe/d) 104,254 95,599 8,655 9 % 
+Oil as % of total daily production 62 % 64 % (2 %) 
+Natural gas as % of total daily production 18 % 18 % — % 
+NGLs as % of total daily production 20 % 18 % 2 % 
+The increase in production for the year ended December 31, 2022 compared to the same period of 2021 was primarily due to new wells acquired in the Primexx Acquisition as well as new wells placed on production, partially offset by normal production decline as well as non-core asset divestitures which occurred primarily in the fourth quarter of 2021. 
+48 
+Pricing 
+Years Ended December 31, 
+2022 2021 $ Change % Change 
+Benchmark prices (1) 
+WTI (per Bbl) $94.26 $67.94 $26.32 39 % 
+Henry Hub (per Mcf) 6.54 3.72 2.82 76 % 
+Average realized sales price (excluding impact of derivative settlements) 
+Oil (per Bbl) 
+Permian $95.58 $68.20 $27.38 40 % 
+Eagle Ford 96.15 68.27 27.88 41 % 
+Total oil 95.72 68.22 27.50 40 % 
+Natural gas (per Mcf) 
+Permian 5.44 3.69 1.75 47 % 
+Eagle Ford 6.47 4.13 2.34 57 % 
+Total natural gas 5.59 3.78 1.81 48 % 
+NGL (per Bbl) 
+Permian 35.18 30.60 4.58 15 % 
+Eagle Ford 32.80 28.12 4.68 17 % 
+Total NGL 34.84 30.11 4.73 16 % 
+Total average realized sales price (per Boe) 
+Permian 70.55 51.05 19.50 38 % 
+Eagle Ford 79.84 57.86 21.98 38 % 
+Total average realized sales price $72.42 $53.06 $19.36 36 % 
+(1) Reflects calendar average daily spot market prices. 
+Revenues 
+Oil Natural Gas NGLs Total 
+(In thousands) 
+Revenues for the year ended December 31, 2021 (1) 
+$1,516,225 $141,493 $193,861 $1,851,579 
+Volume increase 96,538 16,051 31,221 143,810 
+Price increase 649,884 75,137 35,390 760,411 
+Net increase 746,422 91,188 66,611 904,221 
+Revenues for the year ended December 31, 2022 (1) 
+$2,262,647 $232,681 $260,472 $2,755,800 
+Percent of total revenues 82 % 8 % 10 % 
+(1) Excludes sales of oil and gas purchased from third parties and sold to our customers. 
+Operating Expenses 
+Lease Operating Expenses 
+Years Ended December 31, 
+2022 2021 Total Change Boe Change 
+Amount Per Boe Amount Per Boe $ % $ % 
+(In thousands, except per Boe and % amounts) 
+Permian $218,040 $7.18 $129,563 $5.27 $88,477 68 % $1.91 36 % 
+Eagle Ford 72,446 9.45 73,578 7.13 (1,132) (2 %) 2.32 33 % 
+Lease operating $290,486 $7.63 $203,141 $5.82 $87,345 43 % $1.81 31 % 
+The increase in lease operating expenses, as well as lease operating expenses per Boe, for the year ended December 31, 2022 compared to the same period of 2021 was primarily due to the increase in production from wells acquired in the Primexx Acquisition, increases in certain operating expenses such as fuel, power and chemicals, and overall cost inflation. 
+49 
+Production and Ad Valorem Taxes 
+Years Ended December 31, 
+2022 2021 Total Change Boe Change 
+Amount Per Boe Amount Per Boe $ % $ % 
+(In thousands, except per Boe and % amounts) 
+Permian $122,957 $4.05 $67,596 $2.75 $55,361 82 % $1.30 47 % 
+Eagle Ford 36,963 4.82 32,564 3.16 4,399 14 % 1.66 53 % 
+Production and ad valorem taxes $159,920 $4.20 $100,160 $2.87 $59,760 60 % $1.33 46 % 
+Production and ad valorem taxes as a percentage of total revenues 5.8% 5.4% 0.4% 
+The increase in production and ad valorem taxes for the year ended December 31, 2022 compared to the same period of 2021 was primarily related to a 49% increase in total revenues which increased production taxes, as well as an increase in ad valorem taxes due to higher property tax valuations as a result of higher commodity prices during 2021 compared to 2020. The increase in production and ad valorem taxes as a percentage of total revenues for the year ended December 31, 2022 compared to the same period of 2021 was primarily due to an increase in ad valorem taxes during the year ended December 31, 2022 as discussed above. 
+Gathering, Transportation and Processing Expenses 
+Years Ended December 31, 
+2022 2021 Total Change Boe Change 
+Amount Per Boe Amount Per Boe $ % $ % 
+(In thousands, except per Boe and % amounts) 
+Permian $82,459 $2.71 $62,371 $2.54 $20,088 32 % $0.17 7 % 
+Eagle Ford 14,443 1.88 18,599 1.80 (4,156) (22 %) 0.08 4 % 
+Gathering, transportation and processing $96,902 $2.55 $80,970 $2.32 $15,932 20 % $0.23 10 % 
+The increase in gathering, transportation and processing expenses for the year ended December 31, 2022 compared to the same period of 2021 was primarily related to the 9% increase in production volumes between the two periods as well as rate adjustments on certain firm transportation agreements. See “Note 17 – Commitments and Contingencies” of the Notes to our Consolidated Financial Statements for additional details on our firm transportation agreements. 
+Depreciation, Depletion and Amortization (“DD&A”) 
+The following table sets forth the components of our DD&A for the periods indicated: 
+Years Ended December 31, 
+2022 2021 Total Change Boe Change 
+Amount Per Boe Amount Per Boe $ % $ % 
+(In thousands, except per Boe and % amounts) 
+DD&A of evaluated oil and gas properties $457,873 $12.03 $347,199 $9.95 $110,674 32 % $2.08 21 % 
+Depreciation of other property and equipment 1,685 0.04 1,950 0.06 (265) (14 %) (0.02) (33 %) 
+Amortization of other assets 2,962 0.08 3,664 0.10 (702) (19 %) (0.02) (20 %) 
+Accretion of asset retirement obligations 3,997 0.11 3,743 0.11 254 7 % — — % 
+DD&A $466,517 $12.26 $356,556 $10.22 $109,961 31 % $2.04 20 % 
+The increase in DD&A for the year ended December 31, 2022 compared to the same period of 2021 was primarily attributable to a production increase of 9% as well as the addition of properties acquired in the Primexx Acquisition. 
+General and Administrative, Net of Amounts Capitalized (“G&A”) 
+Years Ended December 31, 
+2022 2021 Total Change Boe Change 
+Amount Per Boe Amount Per Boe $ % $ % 
+(In thousands, except per Boe and % amounts) 
+General and administrative $57,393 $1.51 $50,483 $1.45 $6,910 14 % $0.06 4 % 
+The increase in G&A for the year ended December 31, 2022 compared to the same period of 2021 was primarily due to an increase in employee-related costs between the two periods, partially offset by a decrease in the fair value of cash settled awards as a result of the decrease in our stock price between the two periods. 
+50 
+Other Income and Expenses 
+Interest Expense, Net of Capitalized Amounts 
+The following table sets forth the components of our interest expense, net of capitalized amounts for the periods indicated: 
+Years Ended December 31, 
+2022 2021 Change 
+(In thousands) 
+Interest expense on Senior Unsecured Notes $124,694 $107,784 $16,910 
+Interest expense on Second Lien Notes 13,825 43,791 (29,966) 
+Interest expense on credit facility 36,860 31,647 5,213 
+Amortization of debt issuance costs, premiums and discounts 12,333 18,309 (5,976) 
+Other interest expense 80 128 (48) 
+Capitalized interest (108,125) (99,647) (8,478) 
+Interest expense, net of capitalized amounts $79,667 $102,012 ($22,345) 
+The decrease in interest expense, net of capitalized amounts for the year ended December 31, 2022 compared to the same period of 2021 is primarily due to the reduction in interest expense and the write-off of the discount associated with the Second Lien Notes exchange in November 2021 and an increase in capitalized interest, partially offset by an increase in interest expense related to the issuance of the 8.0% Senior Notes in July 2021 and the issuance of the 7.5% Senior Notes in June 2022. See “Note 7 – Borrowings” of the Notes to Consolidated Financial Statements for additional information regarding the Second Lien Notes exchange. 
+Loss on Derivative Contracts 
+The net loss on derivative contracts for the periods indicated includes the following: 
+Years Ended December 31, 
+2022 2021 Change 
+(In thousands) 
+Loss on oil derivatives $287,379 $429,156 ($141,777) 
+Loss on natural gas derivatives 38,803 33,621 5,182 
+Loss on NGL derivatives 4,771 6,768 (1,997) 
+Gain on contingent consideration arrangements — (2,635) 2,635 
+Loss on September 2020 Warrants liability (1) 
+— 55,390 (55,390) 
+Loss on derivative contracts $330,953 $522,300 ($191,347) 
+(1) A detailed discussion of our September 2020 Warrants can be found in “Part II, Item 8. Financial Statements and Supplementary Data, Note 7 – Borrowings” of our Annual Report on Form 10-K for the year ended December 31, 2021, which was filed with the SEC on February 24, 2022. 
+See “Note 8 – Derivative Instruments and Hedging Activities” and “Note 9 – Fair Value Measurements” of the Notes to our Consolidated Financial Statements for additional information. 
+(Gain) Loss on Extinguishment of Debt. For the year ended December 31, 2022, we recognized loss on extinguishment of debt of $45.7 million as a result of the redemptions of the 6.125% Senior Notes and Second Lien Notes and the termination of our Prior Credit Facility. 
+For the year ended December 31, 2021, we recognized a net loss on extinguishment of debt of $41.0 million as a result of the exchange of Second Lien Notes for 5.5 million shares of our common stock and the redemption of all of our 6.25% Senior Notes. 
+See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information. 
+Sales and Cost of Purchased Oil and Gas. For the years ended December 31, 2022 and 2021, we recorded sales of purchased oil and gas of $475.2 million and $193.5 million, respectively, and cost of purchased oil and gas of $478.4 million and $201.1 million, respectively, related to commodities purchased from third parties and sold to our customers. See “Note 3 – Revenue Recognition” of the Notes to our Consolidated Financial Statements for additional information. 
+Income Tax Expense. We recorded income tax expense of $11.8 million for the year ended December 31, 2022 compared to $0.2 million for the same period of 2021. Since the second quarter of 2020, we have concluded that it is more likely than not that the net deferred tax assets will not be realized and have recorded a full valuation allowance against our deferred tax assets. As long as we continue to conclude that the valuation allowance is necessary, we do not expect to have significant deferred income tax expense or benefit. See “Note 12 – Income Taxes” of the Notes to our Consolidated Financial Statements for further discussion. 
+51 
+Liquidity and Capital Resources 
+Outlook . Oil prices continue to remain volatile, as the NYMEX oil price closed the year down over 30% from the highs seen during the second quarter of 2022. We expect to continue to see volatility in oil prices, as well as natural gas and NGL prices. We also expect to continue to experience inflationary cost pressures in 2023 on many different service items including labor, materials, power and equipment. 
+2023 Capital Budget and Funding Strategy. Our primary uses of capital are for the exploration and development of our oil and natural gas properties. Our 2023 Capital Budget has been established at $1.0 billion, with over 80% allocated towards development in the Permian with the balance towards development in the Eagle Ford. Because we are the operator of a high percentage of our properties, we can control the well design and the development pace associated with our capital expenditures. We plan to execute a moderated capital expenditure program through reduced reinvestment rates and balanced capital deployment for more consistent cash flow generation and to drive capital efficiency through an enhanced multi-zone, scaled development program. See “Items 1 and 2. Business and Properties — Capital Budget” for additional details. 
+The following table is a summary of our 2022 capital expenditures (1) : 
+Three Months Ended Year Ended 
+March 31, 2022 June 30, 2022 September 30, 2022 December 31, 2022 December 31, 2022 
+(In millions) 
+Operational capital $157.4 $237.8 $254.6 $191.7 $841.5 
+Capitalized interest 25.5 26.3 27.5 28.8 108.1 
+Capitalized G&A 11.6 11.3 12.7 13.2 48.8 
+Total $194.5 $275.4 $294.8 $233.7 $998.4 
+(1) Capital expenditures, presented on an accrual basis, includes drilling, completions, facilities, and equipment, and excludes land, seismic, and asset retirement costs. 
+We believe that existing cash and cash equivalents, cash flows from operations and available borrowings under our credit facility will be sufficient to support working capital, capital expenditures and other cash requirements for at least the next 12 months and, based on our current expectations, for the foreseeable future thereafter. Our future capital requirements, both near-term and long-term, will depend on many factors, including, but not limited to, commodity prices, market conditions, our available liquidity and financing, acquisitions and divestitures of oil and gas properties, the availability of drilling rigs and completion crews, the cost of completion services, success of drilling programs, land and industry partner issues, weather delays, the acquisition of leases with drilling commitments, and other factors. 
+Historically, our primary sources of capital have been cash flows from operations, borrowings under our credit facility, proceeds from the issuance of debt securities and public equity offerings, and non-core asset dispositions. We regularly consider which resources, including cash flows from operations and debt and equity financings, are available to meet our future financial obligations, planned capital expenditures and liquidity requirements. In addition, we may consider divesting certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth or enter into joint venture agreements, provided we are able to divest such assets or enter into joint venture agreements on terms that are acceptable to us. 
+Depending upon our actual and anticipated sources and uses of liquidity, prevailing market conditions and other factors, we may, from time to time, seek to retire or repurchase our outstanding debt or equity securities through cash purchases in the open market or through privately negotiated transactions or otherwise. The amounts involved in any such transactions, individually or in aggregate, may be material. 
+Overview of Cash Flow Activities. For the year ended December 31, 2022, cash and cash equivalents decreased $6.5 million to $3.4 million compared to $9.9 million at December 31, 2021. 
+Years Ended December 31, 
+2022 2021 
+(In thousands) 
+Net cash provided by operating activities $1,501,517 $974,143 
+Net cash used in investing activities (999,027) (876,400) 
+Net cash used in financing activities (508,977) (108,097) 
+Net change in cash and cash equivalents ($6,487) ($10,354) 
+52 
+Operating Activities. Net cash provided by operating activities was $1.5 billion and $974.1 million for the years ended December 31, 2022 and 2021, respectively. The increase in net cash provided by operating activities was primarily attributable to the following: 
+• An increase of $904.2 million in total revenue, which excludes sales of oil and gas purchased from third parties and sold to our custome rs, primarily driven by a 36% increase in total average realized sales price, as well as a 9% increase in production volumes; offset by 
+• An increase in cash outflows of $127.0 million related to timing of working capital payments and receipts; and 
+• Increase in cash paid for commodity derivative settlements of $98.6 million. 
+Investing Activities. Net cash used in investing activities was $999.0 million and $876.4 million for the years ended December 31, 2022 and 2021, respectively. The increase in investing activities was primarily attributable to the following: 
+• An increase in operational capital expenditures of $414.5 million; and 
+• A decrease in sales of non-core oil and gas properties of $161.0 million; offset by 
+• A decrease in acquisitions of $465.5 million due to the Primexx acquisition during 2021. 
+Financing Activities. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under our credit facility, term debt and equity offerings. For the year ended December 31, 2022, net cash used in financing activities was $509.0 million compared to $108.1 million during 2021. The increase in net cash used in financing activities was primarily attributable to the following: 
+• Redemption of the Second Lien Notes of $339.5 million; and 
+• Repayments in excess of borrowings of $82.0 million on the credit facility. 
+See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information on our debt transactions. 
+Credit Facility. As of December 31, 2022, our Credit Facility had a maximum credit amount of $5.0 billion, a borrowing base of $2.0 billion and an elected commitment amount of $1.5 billion, with borrowings outstanding of $503.0 million at a weighted-average interest rate of 6.56%, and letters of credit outstanding of $16.4 million. 
+See “Note 7 – Borrowings” for additional information related to the Prior Credit Facility and the Credit Facility. 
+Income Taxes. Due to the issuance of common stock associated with the Carrizo Acquisition, the Company incurred a cumulative ownership change, and as such, the Company’s NOLs prior to the acquisition are subject to a combined annual limitation under Internal Revenue Code (the “IRC”) Section 382 in the amount of $32.2 million, which is comprised of $15.7 million of Carrizo’s NOLs and $16.5 million of Callon’s NOLs. At December 31, 2022, the Company had approximately $1.7 billion of NOLs, some of which i) are subject to annual limitation under Section 382, ii) are subject to the IRC’s 80% taxable income limitation rule, or iii) expire between 2034 and 2037, as summarized in the table below. 
+Subject to Annual Limitation Under Section 382 Subject to IRC’s 80% Taxable Income Limitation Years of Expiration NOL Balance 
+(In millions) 
+Yes Yes N/A $647.6 
+No Yes N/A 666.5 
+Yes No 2034 to 2037 399.2 
+$1,713.3 
+Additionally, the Company also has a net interest expense carryforward of $355.4 million under Section 163(j) of the Code, which has an indefinite life. 
+Material Cash Requirements 
+As of December 31, 2022, we have financial obligations associated with our outstanding long-term debt, including interest payments and principal repayments. See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for further discussion of the contractual commitments under our debt agreements, including the timing of principal repayments. Additionally, we have operational obligations associated with long-term, non-cancelable leases, drilling rig contracts, frac service contracts, gathering, processing and transportation service agreements and other purchase obligations as well as estimates of future asset retirement obligations. See “Note 14 – Asset Retirement Obligations” and “Note 17 – Commitments and Contingencies” of the Notes to our Consolidated Financial Statements for additional details. 
+We estimate that the combination of our sources of capital, as discussed above, will continue to be adequate to fund our short- and long-term contractual obligations. 
+53 
+Critical Accounting Estimates 
+For discussion regarding our significant accounting policies, see “Note 2 – Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements. We have outlined below the policies identified as being critical to the understanding of our business and results of operations and that require the application of significant management judgment. 
+Use of Estimates 
+The preparation of financial statements in conformity with GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets and liabilities and revenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating DD&A of evaluated oil and natural gas property costs, the present value of estimated future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated timing of cash outflows underlying asset retirement obligations. There are numerous uncertainties inherent in the estimation of proved oil and gas reserves and in the projection of future rates of production and the timing of development expenditures. Other significant estimates are involved in determining asset retirement obligations, acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of commodity derivative assets and liabilities, and litigation liabilities. Actual results could differ from those estimates. 
+Oil and Natural Gas Properties 
+Oil and natural gas properties are accounted for using the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration and development activities are capitalized as oil and gas properties. Capitalized oil and gas property costs are amortized on an equivalent unit-of-production method whereby the depletion rate is computed on a quarterly basis by dividing current quarter production by estimated proved oil and gas reserves at the beginning of the quarter then applying such depletion rate to evaluated oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values. Each quarter, a full cost ceiling test is performed to determine whether an impairment to our evaluated oil and gas properties should be recorded. 
+The process of estimating proved oil and gas reserves requires that our independent and internal reserve engineers exercise judgment based on available geological, geophysical and technical information. Additionally, operating costs, production and ad valorem taxes, and future development costs are estimated based on current costs. A significant change to our estimated volumes of oil and gas reserves as well as changes to the estimates of prices and costs could have an impact on the depletion rate calculation as well as the estimated future net revenues used in the cost center ceiling. 
+The table below presents various pricing scenarios to demonstrate the sensitivity of our December 31, 2022 cost center ceiling to changes in 12-month average benchmark crude oil and natural gas prices underlying the 12-Month Average Realized Prices. The sensitivity analysis is as of December 31, 2022 and, accordingly, does not consider drilling and completion activity, acquisitions or dispositions of oil and gas properties, production, changes in crude oil and natural gas prices, and changes in development and operating costs occurring subsequent to December 31, 2022 that may require revisions to estimates of proved reserves. We have described the risks associated with reserve estimation and the volatility of oil and natural gas prices under Part I, “Item 1A. Risk Factors.” 
+12-Month Average 
+Realized Prices Excess of cost center ceiling over net book value, less related deferred income taxes Increase (decrease) of cost center ceiling over net book value, less related deferred income taxes 
+Full Cost Pool Scenarios Crude Oil 
+($/Bbl) Natural Gas 
+($/Mcf) (In millions) (In millions) 
+December 31, 2022 Actual 
+$95.02 $5.75 $5,111 
+Crude Oil and Natural Gas Price Sensitivity 
+Crude Oil and Natural Gas +10% $104.39 $6.38 $6,323 $1,212 
+Crude Oil and Natural Gas -10% $85.65 $5.11 $3,899 ($1,212) 
+Crude Oil Price Sensitivity 
+Crude Oil +10% $104.39 $5.75 $6,191 $1,080 
+Crude Oil -10% $85.65 $5.75 $4,031 ($1,080) 
+Natural Gas Price Sensitivity 
+Natural Gas +10% $95.02 $6.38 $5,243 $132 
+Natural Gas -10% $95.02 $5.11 $4,979 ($132) 
+54 
+Derivative Instruments 
+We use commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of our forecasted sales of production and achieve a more predictable level of cash flow. We do not use these instruments for speculative or trading purposes. Settlements of derivative contracts are generally based on the difference between the contract price and prices specified in the derivative instrument and a NYMEX price or other futures index price. The estimated fair value of our derivative contracts is based upon current forward market prices on NYMEX and in the case of collars and floors, the time value of options. For additional information regarding our derivatives instruments and their fair values, see “Note 8 – Derivative Instruments and Hedging Activities” and “Note 9 – Fair Value Measurements” of the Notes to our Consolidated Financial Statements. 
+Our financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments as a result of the volatility of oil and gas prices. See “Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk” for the impact on the fair values of our derivative instruments assuming a 10% increase and decrease in the underlying forward oil and gas price curves as of December 31, 2022. 
+Income Taxes 
+The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. 
+Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that our net deferred tax assets will be utilized prior to their expiration. A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and a net deferred tax asset position at December 31, 2022, driven primarily by impairments of evaluated oil and gas properties recognized beginning in the second quarter of 2020 and continuing through the fourth quarter of 2020. This limits the ability to consider other subjective evidence such as our potential for future growth. Since the second quarter of 2020, based on the evaluation of the evidence available, we concluded that it is more likely than not that the net deferred tax assets will not be realized. As a result, we have recorded a valuation allowance, reducing the net deferred tax assets as of December 31, 2022 to zero. 
+We currently believe it is reasonably possible we could achieve a three-year cumulative level of profitability within the next 12 months, which would enhance our ability to conclude that it is more likely than not that the deferred tax assets would be realized and support a release of substantially all or a portion of the valuation allowance. However, the exact timing and amount of the release is unknown at this time. We will continue to evaluate whether the valuation allowance is needed in future reporting periods based on available information each reporting period. As long as we continue to conclude that the valuation allowance against our net deferred tax assets is necessary, we will have no significant deferred income tax expense or benefit. The valuation allowance does not preclude us from utilizing the tax attributes if we recognize taxable income. See “Note 12 – Income Taxes” of the Notes to our Consolidated Financial Statements for additional discussion. 
+Recently Adopted and Recently Issued Accounting Pronouncements 
+See “Note 2 – Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements for information discussion of recent accounting pronouncements issued by the Financial Accounting Standards Board. 
+ITEM 7A. Quantitative and Qualitative Disclosures about Market Risk 
+We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer credit risk. We mitigate these risks through a program of risk management including the use of commodity derivative instruments. 
+Commodity Price Risk 
+Our revenues are derived from the sale of our oil, natural gas, and NGL production. The prices for oil, natural gas, and NGLs remain volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, government actions, economic conditions, and weather conditions. 
+From time to time, we enter into derivative financial instruments to manage oil, natural gas and NGL price risk, related both to NYMEX benchmark prices and regional basis differentials. The total volumes we hedge through use of our derivative instruments varies from period to period and takes into account our view of current and future market conditions in order to provide greater certainty of cash flows to meet our debt service costs and capital program. We generally hedge for the next 12 to 24 months, subject to the covenants under our Credit Facility. Our hedge policies and objectives may change significantly with movements in commodities prices or futures prices. 
+55 
+We may utilize fixed price swaps, which reduce our exposure to decreases in commodity prices, but limit the benefit we might otherwise have received from any increases in commodity prices. Swap contracts may also be enhanced by the simultaneous sale of call or put options to effectively increase the effective swap price as a result of the receipt of premiums from the option sales. 
+We also may utilize price collars to reduce the risk of changes in oil and natural gas prices. Under these arrangements, no payments are due by either party as long as the applicable market price is above the floor price (purchased put option) and below the ceiling price (sold call option) set in the collar. If the price falls below the floor, the counterparty to the collar pays the difference to us, and if the price rises above the ceiling, the counterparty receives the difference from us. Additionally, we may sell put options at a price lower than the floor price in conjunction with a collar (three-way collar) and use the proceeds to increase either or both the floor or ceiling prices. In a three-way collar, to the extent that realized prices are below the floor price of the sold put option (or above the ceiling price of the sold call option), our net realized benefit from the three-way collar will be reduced on a dollar-for-dollar basis. 
+Additionally, we may enter into basis swap contracts which fix the basis differentials between the index price at which the Company sells its production and the relevant NYMEX benchmark price used in swap or collar contracts. 
+We may purchase put options, which reduce our exposure to decreases in oil and natural gas prices while allowing realization of the full benefit from any increases in oil and natural gas prices. If the price falls below the floor, the counterparty pays the difference to us. 
+We enter into these various agreements from time to time to reduce the effects of volatile oil, natural gas and NGL prices and do not enter into derivative transactions for speculative or trading purposes. Presently, none of our derivative positions are designated as hedges for accounting purposes. 
+The following table sets forth the fair values of our commodity derivative instruments as of December 31, 2022 as well as the impact on the fair values assuming a 10% increase and decrease in the underlying forward oil and gas price curves as of December 31, 2022: 
+Year Ended December 31, 2022 
+Oil Natural Gas Total 
+(In thousands) 
+Fair value asset (liability) as of December 31, 2022 (1) 
+($18,077) $18,261 $184 
+Impact of a 10% increase in forward commodity prices ($58,535) $17,539 ($40,996) 
+Impact of a 10% decrease in forward commodity prices $20,080 $19,057 $39,137 
+(1) Spot prices for oil and natural gas were $80.33 and $4.48, respectively, as of December 30, 2022. 
+Interest Rate Risk 
+We are subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility. As of December 31, 2022, we had $503.0 million outstanding under the Credit Facility with a weighted average interest rate of 6.56%. An increase or decrease of 1.00% in the interest rate would have a corresponding increase or decrease in our annual interest expense of approximately $5.0 million, based on the balance outstanding as of December 31, 2022. See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for more information on our Credit Facility. 
+Counterparty and Customer Credit Risk 
+Our principal exposures to credit risk are through receivables from the sale of our oil, natural gas and NGL production, joint interest receivables and receivables resulting from derivative financial contracts. 
+For the year ended December 31, 2022, two purchasers each accounted for more than 10% of our oil, natural gas, and NGL revenues. The inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In order to mitigate potential exposure to credit risk, we may require our customers to provide financial security. We are generally paid by our purchasers within 30 to 90 days after the month of production and currently do not believe that we have a risk of not collecting. 
+Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have or intend to drill. We have little ability to control whether these entities will participate in our wells. We generally have the right to withhold future revenue distributions to recover past due receivables from joint interest owners. As of December 31, 2022, our joint interest receivables were approximately $16.8 million and we had no material past due balances. 
+See “Note 8 – Derivative Instruments and Hedging Activities” of the Notes to our Consolidated Financial Statements for discussion of counterparty credit risk associated with our commodity derivative arrangements. 
+56 
+ITEM 8. Financial Statements and Supplementary Data 
+Page 
+Reports of Independent Registered Public Accounting Firm (PCAOB ID Number 248 ) 
+58 
+Consolidated Balance Sheets as of December 31, 2022 and 2021 
+61 
+Consolidated Statements of Operations for the Years Ended December 31, 2022, 2021 and 2020 
+62 
+Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2022, 2021 and 2020 
+63 
+Consolidated Statements of Cash Flows for the Years Ended December 31, 2022, 2021 and 2020 
+64 
+Notes to Consolidated Financial Statements 
+65 
+57 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+Board of Directors and Shareholders 
+Callon Petroleum Company 
+Opinion on the financial statements 
+We have audited the accompanying consolidated balance sheets of Callon Petroleum Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2022 and 2021, the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2022, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, in conformity with accounting principles generally accepted in the United States of America. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2022, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 23, 2023 expressed an unqualified opinion. 
+Basis for opinion 
+These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. 
+Critical audit matters 
+The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. 
+The development of estimated proved reserves used in the calculation of depletion, depreciation and amortization expense under the full cost method of accounting 
+As described further in Note 2 to the financial statements, the Company accounts for its oil and gas properties using the full cost method of accounting which requires management to make estimates of proved reserve volumes and future net revenues to record depletion expense. To estimate the volume of proved reserves and future net revenue, management makes significant estimates and assumptions including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected with reasonable certainty to be economical under the appropriate pricing assumptions required in the estimation of depletion expense. We identified the estimation of proved reserves of oil and gas properties as a critical audit matter. 
+The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain inputs and assumptions necessary to estimate the volumes and future net revenues of the Company’s proved reserves require a high degree of subjectivity and could have a significant impact on the measurement of depletion expense. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment. 
+58 
+Our audit procedures related to the estimation of proved reserves included the following, among others. 
+• We tested the design and operating effectiveness of controls relating to management’s estimation of proved reserves for the purpose of estimating depletion expense. 
+• We evaluated the independence, objectivity, and professional qualifications of the Company’s reserve engineers, made inquiries of those specialists regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the reserve report prepared by the Company’s specialists. 
+• To the extent key inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, including, but not limited to historical pricing differentials, operating costs, estimated development costs, and ownership interests, we tested management’s process for determining the assumptions, including examining the underlying support on a sample basis. Specifically, our audit procedures involved testing management’s assumptions by performing the following: 
+◦ We compared the estimated pricing differentials used in the reserve report to prices realized by the Company related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials 
+◦ We tested models used to estimate the future operating costs in the reserve report and compared amounts to historical operating costs 
+◦ We evaluated the method used to determine estimated future development costs used in the reserve report and compared management’s estimate to amounts expended for recently drilled and completed wells to ascertain its reasonableness 
+◦ We tested the working and net revenue interests used in the reserve report by inspecting land and division order records 
+◦ We evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s ability and intent to develop the proved undeveloped properties, and 
+◦ We applied analytical procedures to production forecasts in the reserve report by comparing to historical actual results and to the prior year reserve report. 
+/s/ GRANT THORNTON LLP 
+We have served as the Company’s auditor since 2016. 
+Houston, Texas 
+February 23, 2023 
+59 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+Board of Directors and Shareholders 
+Callon Petroleum Company 
+Opinion on internal control over financial reporting 
+We have audited the internal control over financial reporting of Callon Petroleum Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2022, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2022, and our report dated February 23, 2023 expressed an unqualified opinion on those financial statements. 
+Basis for opinion 
+The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s report. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+Definition and limitations of internal control over financial reporting 
+A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+/s/ GRANT THORNTON LLP 
+Houston, Texas 
+February 23, 2023 
+60 
+Callon Petroleum Company 
+Consolidated Balance Sheets 
+(In thousands, except par and share amounts) 
+December 31, 
+2022 2021 
+ASSETS 
+Current assets: 
+Cash and cash equivalents $ 3,395 $ 9,882 
+Accounts receivable, net 237,128 232,436 
+Fair value of derivatives 21,332 22,381 
+Other current assets 35,783 30,745 
+Total current assets 297,638 295,444 
+Oil and natural gas properties, full cost accounting method: 
+Evaluated properties, net 4,023,603 3,352,821 
+Unevaluated properties 1,711,306 1,812,827 
+Total oil and natural gas properties, net 5,734,909 5,165,648 
+Other property and equipment, net 26,152 28,128 
+Deferred financing costs 18,822 18,125 
+Other assets, net 68,560 40,158 
+Total assets $ 6,146,081 $ 5,547,503 
+LIABILITIES AND STOCKHOLDERS’ EQUITY 
+Current liabilities: 
+Accounts payable and accrued liabilities $ 536,233 $ 569,991 
+Fair value of derivatives 16,197 185,977 
+Other current liabilities 150,384 116,523 
+Total current liabilities 702,814 872,491 
+Long-term debt 2,241,295 2,694,115 
+Asset retirement obligations 53,892 54,458 
+Fair value of derivatives 13,415 11,409 
+Other long-term liabilities 49,243 49,262 
+Total liabilities 3,060,659 3,681,735 
+Commitments and contingencies 
+Stockholders’ equity: 
+Common stock, $ 0.01 par value, 130,000,000 and 78,750,000 shares authorized; 
+61,621,518 and 61,370,684 shares outstanding, respectively 
+616 614 
+Capital in excess of par value 4,022,194 4,012,358 
+Accumulated deficit ( 937,388 ) ( 2,147,204 ) 
+Total stockholders’ equity 3,085,422 1,865,768 
+Total liabilities and stockholders’ equity $ 6,146,081 $ 5,547,503 
+The accompanying notes are an integral part of these consolidated financial statements. 
+61 
+Callon Petroleum Company 
+Consolidated Statements of Operations 
+(In thousands, except per share amounts) 
+For the Year Ended December 31, 
+2022 2021 2020 
+Operating Revenues: 
+Oil $ 2,262,647 $ 1,516,225 $ 850,667 
+Natural gas 232,681 141,493 51,866 
+Natural gas liquids 260,472 193,861 81,295 
+Sales of purchased oil and gas 475,164 193,451 49,319 
+Total operating revenues 3,230,964 2,045,030 1,033,147 
+Operating Expenses: 
+Lease operating 290,486 203,141 194,101 
+Production and ad valorem taxes 159,920 100,160 62,638 
+Gathering, transportation and processing 96,902 80,970 77,309 
+Cost of purchased oil and gas 478,445 201,088 51,766 
+Depreciation, depletion and amortization 466,517 356,556 480,631 
+General and administrative 57,393 50,483 37,187 
+Impairment of evaluated oil and gas properties — — 2,547,241 
+Merger, integration and transaction 769 14,289 28,482 
+Total operating expenses 1,550,432 1,006,687 3,479,355 
+Income From Operations 1,680,532 1,038,343 ( 2,446,208 ) 
+Other (Income) Expenses: 
+Interest expense, net of capitalized amounts 79,667 102,012 94,329 
+Loss on derivative contracts 330,953 522,300 27,773 
+(Gain) loss on extinguishment of debt 45,658 41,040 ( 170,370 ) 
+Other (income) expense 2,645 7,660 13,627 
+Total other (income) expense 458,923 673,012 ( 34,641 ) 
+Income (Loss) Before Income Taxes 1,221,609 365,331 ( 2,411,567 ) 
+Income tax expense ( 11,793 ) ( 180 ) ( 122,054 ) 
+Net Income (Loss) $ 1,209,816 $ 365,151 ($ 2,533,621 ) 
+Net Income (Loss) Per Common Share: 
+Basic $ 19.63 $ 7.51 ($ 63.79 ) 
+Diluted $ 19.54 $ 7.26 ($ 63.79 ) 
+Weighted Average Common Shares Outstanding: 
+Basic 61,620 48,612 39,718 
+Diluted 61,904 50,311 39,718 
+The accompanying notes are an integral part of these consolidated financial statements. 
+62 
+Callon Petroleum Company 
+Consolidated Statements of Stockholders’ Equity 
+(In thousands) 
+Retained 
+Common Capital in Earnings Total 
+Stock Excess (Accumulated Stockholders’ 
+Shares $ of Par Deficit) Equity 
+Balance at 12/31/2019 39,659 $ 3,966 $ 3,198,076 $ 21,266 $ 3,223,308 
+Net loss — — — ( 2,533,621 ) ( 2,533,621 ) 
+Restricted stock units 100 10 12,213 — 12,223 
+Reverse stock split — ( 3,578 ) 3,578 — — 
+Issuance of common stock warrants — — 9,109 — 9,109 
+Other — — ( 17 ) — ( 17 ) 
+Balance at 12/31/2020 39,759 $ 398 $ 3,222,959 ($ 2,512,355 ) $ 711,002 
+Net income — — — 365,151 365,151 
+Restricted stock units 156 2 10,949 — 10,951 
+Warrant exercises 6,913 69 134,748 — 134,817 
+Common stock issued for Primexx Acquisition 9,030 90 420,610 — 420,700 
+Common stock issued for Second Lien Notes Exchange 5,513 55 223,092 — 223,147 
+Balance at 12/31/2021 61,371 $ 614 $ 4,012,358 ($ 2,147,204 ) $ 1,865,768 
+Net income — — — 1,209,816 1,209,816 
+Restricted stock units 266 3 8,735 — 8,738 
+Common stock issued for Primexx Acquisition ( 15 ) ( 1 ) 1,101 — 1,100 
+Balance at 12/31/2022 61,622 $ 616 $ 4,022,194 ($ 937,388 ) $ 3,085,422 
+The accompanying notes are an integral part of these consolidated financial statements. 
+63 
+Callon Petroleum Company 
+Consolidated Statements of Cash Flows 
+(In thousands) 
+Years Ended December 31, 
+2022 2021 2020 
+Cash flows from operating activities: 
+Net income (loss) $ 1,209,816 $ 365,151 ($ 2,533,621 ) 
+Adjustments to reconcile net income (loss) to net cash provided by operating activities: 
+Depreciation, depletion and amortization 466,517 356,556 480,631 
+Impairment of evaluated oil and gas properties — — 2,547,241 
+Amortization of non-cash debt related items, net 5,280 10,124 3,901 
+Deferred income tax expense 4,279 — 118,607 
+Loss on derivative contracts 330,953 522,300 27,773 
+Cash received (paid) for commodity derivative settlements, net ( 493,714 ) ( 395,097 ) 98,870 
+(Gain) loss on extinguishment of debt 45,658 41,040 ( 170,370 ) 
+Non-cash expense related to share-based awards 2,507 12,923 2,663 
+Other, net 7,136 11,037 7,087 
+Changes in current assets and liabilities: 
+Accounts receivable ( 3,480 ) ( 86,402 ) 75,770 
+Other current assets ( 15,392 ) ( 10,399 ) ( 6,550 ) 
+Accounts payable and accrued liabilities ( 58,043 ) 146,910 ( 92,227 ) 
+Net cash provided by operating activities 1,501,517 974,143 559,775 
+Cash flows from investing activities: 
+Capital expenditures ( 992,985 ) ( 578,487 ) ( 664,231 ) 
+Acquisition of oil and gas properties ( 28,253 ) ( 493,732 ) ( 12,923 ) 
+Proceeds from sales of assets 27,093 188,101 178,970 
+Cash paid for settlement of contingent consideration arrangement ( 19,171 ) — ( 40,000 ) 
+Other, net 14,289 7,718 8,301 
+Net cash used in investing activities ( 999,027 ) ( 876,400 ) ( 529,883 ) 
+Cash flows from financing activities: 
+Borrowings on credit facility 3,286,000 2,140,500 5,353,000 
+Payments on credit facility ( 3,568,000 ) ( 2,340,500 ) ( 5,653,000 ) 
+Issuance of senior notes 600,000 650,000 — 
+Redemption of senior notes ( 467,287 ) ( 542,755 ) — 
+Redemption of 9.0 % Second Lien Senior Secured Notes due 2025 
+( 339,507 ) — — 
+Issuance of 9.0 % Second Lien Senior Secured Notes due 2025 
+— — 300,000 
+Discount on the issuance of 9.0 % Second Lien Senior Secured Notes due 2025 
+— — ( 35,270 ) 
+Issuance of September 2020 Warrants — — 23,909 
+Payment of deferred financing costs ( 21,898 ) ( 12,672 ) ( 10,811 ) 
+Other, net 1,715 ( 2,670 ) ( 825 ) 
+Net cash used in financing activities ( 508,977 ) ( 108,097 ) ( 22,997 ) 
+Net change in cash and cash equivalents ( 6,487 ) ( 10,354 ) 6,895 
+Balance, beginning of period 9,882 20,236 13,341 
+Balance, end of period $ 3,395 $ 9,882 $ 20,236 
+The accompanying notes are an integral part of these consolidated financial statements. 
+64 
+INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+1. 
+Description of Business 
+10. 
+Share-Based Compensation 
+2. 
+Summary of Significant Accounting Policies 
+11. 
+Stockholders’ Equity 
+3. 
+Revenue Recognition 
+12. 
+Income Taxes 
+4. 
+Acquisitions and Divestitures 
+13. 
+Leases 
+5. 
+Property and Equipment, Net 
+14. 
+Asset Retirement Obligations 
+6. 
+Earnings Per Share 
+15. 
+Accounts Receivable , Net 
+7. 
+Borrowings 
+16. 
+Accounts Payable and Accrued Liabilities 
+8. 
+Derivative Instruments and Hedging Activities 
+17. 
+Commitments and Contingencies 
+9. 
+Fair Value Measurements 
+18. 
+Supplemental Information on Oil and Natural Gas Operations (Unaudited) 
+Note 1 – Description of Business 
+Callon Petroleum Company is an independent oil and natural gas company focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. 
+The Company’s activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger Permian Basin in West Texas, as well as the Eagle Ford in South Texas. The Company’s primary operations in the Permian reflect a high-return, oil-weighted drilling inventory with multiple prospective horizontal development intervals and are complemented by a well-established, cash flow-generating business in the Eagle Ford. 
+Note 2 – Summary of Significant Accounting Policies 
+Basis of Presentation and Principles of Consolidation 
+The consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and are presented in accordance with U.S. GAAP. The Company proportionately consolidates its undivided interests in oil and gas properties as well as investments in unincorporated entities, such as partnerships and limited liability companies where the Company, as a partner or member, has undivided interests in the oil and gas properties. In the opinion of management, the accompanying audited consolidated financial statements reflect all adjustments, including normal recurring adjustments, necessary to present fairly the Company’s financial position, results of its operations and cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation. Such reclassifications did not have a material impact on prior period financial statements. The Company evaluates events subsequent to the balance sheet date through the date the financial statements are issued. 
+Use of Estimates 
+The preparation of financial statements in conformity with U.S. GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating depreciation, depletion and amortization (“DD&A”) of evaluated oil and gas property costs, the present value of estimated future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated timing of cash outflows underlying asset retirement obligations. There are numerous uncertainties inherent in the estimation of proved oil and gas reserves and in the projection of future rates of production and the timing of development expenditures. Other significant estimates are involved in determining asset retirement obligations, acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of commodity derivative assets and liabilities, and litigation liabilities. Actual results could differ from those estimates. 
+Cash and Cash Equivalents 
+The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. 
+Accounts Receivable, Net 
+Accounts receivable, net consists primarily of receivables from oil, natural gas, and NGL purchasers and joint interest owners in properties the Company operates. The Company generally has the right to withhold future revenue distributions to recover past due receivables from joint interest owners. Generally, the Company’s oil, natural gas, and NGL receivables are collected within 30 to 90 days. The Company’s allowance for credit losses and bad debt expense was immaterial for all periods presented. 
+65 
+Concentration of Credit Risk and Major Customers 
+The concentration of accounts receivable from entities in the oil and gas industry may impact the Company’s overall credit risk such that these entities may be similarly affected by changes in economic and other industry conditions. The Company does not believe the loss of any one of its purchasers would materially affect its ability to sell the oil and gas it produces as other purchasers are available in its primary areas of activity. The Company had the following major customers that represented 10% or more of its oil, natural gas and NGL revenues for at least one of the periods presented: 
+Years Ended December 31, 
+2022 (1) 
+2021 (1) 
+2020 (1) 
+Valero Marketing and Supply Company 15 % 13 % 23 % 
+Rio Energy International, Inc. 12 * * 
+Shell Trading Company * 20 31 
+Trafigura Trading, LLC * 15 * 
+Occidental Energy Marketing, Inc. * 13 * 
+(1) The customers that represented over 10% of the Company’s sales of purchased oil and gas were Vitol Inc., for the years ended December 31, 2022, 2021 and 2020, and Plains Marketing, L.P., for the year ended December 31, 2022. 
+* - Less than 10% for the applicable year. 
+See “Note 8 – Derivative Instruments and Hedging Activities” for discussion of credit risk related with the Company’s commodity derivative counterparties. 
+Oil and Natural Gas Properties 
+The Company uses the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration, and development activities are capitalized as oil and gas properties. Internal costs that are directly related to acquisition, exploration, and development activities, including salaries, benefits, and stock-based compensation, are capitalized to either evaluated or unevaluated oil and gas properties based on the type of activity. Internal costs related to production and similar activities are expensed as incurred. 
+Proceeds from divestitures of evaluated and unevaluated oil and natural gas properties are accounted for as a reduction of evaluated oil and gas property costs unless the sale significantly alters the relationship between capitalized costs and estimated proved reserves, in which case a gain or loss is recognized. For the years ended December 31, 2022, 2021 and 2020, the Company did not have any sales of oil and gas properties that significantly altered such relationship. 
+From time to time, the Company exchanges undeveloped acreage with third parties. The exchanges are recorded at fair value and the difference is accounted for as an adjustment of capitalized costs with no gain or loss recognized pursuant to the rules governing full cost accounting, unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas, and NGLs. 
+Capitalized oil and gas property costs are amortized on an equivalent unit-of-production method, converting natural gas to barrels of oil equivalent at the ratio of six thousand cubic feet of gas to one barrel of oil, which represents their approximate relative energy content. The equivalent unit-of-production depletion rate is computed on a quarterly basis by dividing current quarter production by estimated proved oil and gas reserves at the beginning of the quarter then applying such depletion rate to evaluated oil and gas property costs, which include estimated asset retirement costs, less accumulated amortization, plus estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values. 
+Excluded from this amortization are costs associated with unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. Unevaluated property costs are transferred to evaluated property costs when the proved reserves have been assigned to the properties or the Company determines that these costs have been impaired. The Company assesses properties on an individual basis or as a group and considers, among other things, the exploration program and intent to drill, as well as remaining lease term to determine if these costs have been impaired. Geological and geophysical costs not associated with specific prospects are recorded to evaluated oil and gas property costs as incurred. The amount of interest costs capitalized is determined on a quarterly basis based on the average balance of unevaluated properties and the weighted average interest rate of outstanding borrowings. 
+Under full cost accounting rules, the Company reviews the net book value of its oil and gas properties each quarter. Under these rules, the net book value of oil and gas properties, less related deferred income taxes, are limited to the “cost center ceiling” equal to (i) the sum of (a) the present value of estimated future net revenues from estimated proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the estimated proved oil and gas reserves computed using a discount factor of 10 %, (b) the costs of unevaluated properties not being amortized, and (c) the lower of cost or estimated fair value of unevaluated properties included in the costs being amortized; less (ii) related income tax effects. Any excess of the net book value of oil and gas 
+66 
+properties, less related deferred income taxes, over the cost center ceiling is recognized as an impairment of evaluated oil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even if higher commodity prices in the future result in a cost center ceiling in excess of the net book value of oil and gas properties, less related deferred income taxes. 
+The estimated future net revenues used in the cost center ceiling are calculated using the 12-Month Average Realized Price of oil, NGLs, and natural gas, held flat for the life of the production, except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of commodity derivative instruments as the Company elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. The Company did no t recognize impairments of evaluated oil and gas properties for the years ended December 31, 2022 and 2021. Primarily as a result of a 31 % decrease in the 12-Month Average Realized Price of oil, the Company recognized impairments of evaluated oil and gas properties of $ 2.5 billion for the year ended December 31, 2020. 
+Depreciation of other property and equipment is recognized using the straight-line method based on estimated useful lives ranging from two to twenty years . 
+Deferred Financing Costs 
+Deferred financing costs associated with the Unsecured Senior Notes and previously with the Second Lien Notes, both defined below, are classified as a reduction of the related carrying value on the consolidated balance sheets and are amortized to interest expense using the effective interest method over the terms of the related debt. Deferred financing costs associated with the Credit Facility, as defined below, are classified in “Other long-term assets” in the consolidated balance sheets and are amortized to interest expense using the straight-line method over the term of the facility. 
+Asset Retirement Obligations 
+The Company records an estimate of the fair value of liabilities for obligations associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Estimates involved in determining asset retirement obligations include the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a credit-adjusted risk-free discount rate and an inflation factor in order to determine the present value of the asset retirement obligation. The present value of the asset retirement obligations is accreted each period and the increase to the obligation is reported in “Depreciation, depletion and amortization” in the consolidated statements of operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to evaluated oil and gas properties in the consolidated balance sheets. See “Note 14 – Asset Retirement Obligations” for additional information. 
+Derivative Instruments 
+The Company uses commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of its forecasted sales of production and achieve a more predictable level of cash flow. The Company does not enter into commodity derivative instruments for speculative or trading purposes. All commodity derivative instruments are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. The Company nets its commodity derivative instrument fair value amounts executed with the same counterparty to a single asset or liability pursuant to International Swap Dealers Association Master Agreements (“ISDA Agreements”), which provide for net settlement over the term of the contract and in the event of default or termination of the contract. 
+Settlements of the Company’s commodity derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets. See “Note 9 – Fair Value Measurements” for additional information regarding fair value. 
+The Company has elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. As such, all gains and losses as a result of changes in the fair value of commodity derivative instruments are recognized as “(Gain) loss on derivative contracts” in the consolidated statements of operations in the period in which the changes occur. See “Note 8 – Derivative Instruments and Hedging Activities” and “Note 9 – Fair Value Measurements” for further discussion. 
+Revenue Recognition 
+The Company recognizes revenues from the sales of oil, natural gas, and NGLs to its customers and presents them disaggregated on the Company’s consolidated statements of operations. Revenue is recognized at the point in time when control of the product transfers to the customer. 
+For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company is not required to disclose the transaction price allocated to remaining 
+67 
+performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. 
+The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. See “Note 3 – Revenue Recognition” for further discussion. 
+Income Taxes 
+Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are recognized at the end of each reporting period for the future tax consequences of cumulative temporary differences between the tax basis of assets and liabilities and their reported amounts in the Company’s consolidated financial statements based on existing tax laws and enacted statutory tax rates applicable to the periods in which the temporary differences are expected to affect taxable income. U.S. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards and tax credit carryforwards. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering all available evidence (both positive and negative) to determine whether it is more likely than not that all or a portion of the deferred tax assets will not be realized and a valuation allowance is required. See “Note 12 – Income Taxes” for further discussion. 
+Share-Based Compensation 
+The Company grants restricted stock unit awards that may be settled in common stock (“RSU Equity Awards”) or cash (“Cash-Settled RSU Awards”), some of which are subject to achievement of certain performance conditions. Share-based compensation expense is recognized as “General and administrative expense” in the consolidated statements of operations. The Company accounts for forfeitures of equity-based incentive awards as they occur. See “Note 10 – Share-Based Compensation” for further details of the awards discussed below. 
+RSU Equity Awards and Cash-Settled RSU Awards. Share-based compensation expense for RSU Equity Awards is based on the grant-date fair value and recognized over the vesting period (generally three years for employees and one year for non-employee directors) using the straight-line method. For RSU Equity Awards with vesting terms subject to a performance condition, share-based compensation expense is based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model with the estimated value recognized over the vesting period (generally three years ). Cash-Settled RSU Awards subject to a performance condition that the Company expects, or is required, to settle in cash are accounted for as liabilities with share-based compensation expense based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model, with the estimated fair value recognized over the vesting period (generally three years ). 
+Cash SARs. Stock appreciation rights to be settled in cash (“Cash SARs” and together with Cash-Settled RSU Awards, the “Cash-Settled Awards”) are remeasured at fair value at the end of each reporting period with the change in fair value recorded as share-based compensation expense. The liability for Cash SARs is classified as “Other current liabilities” in the consolidated balance sheets as all outstanding awards are vested. The Cash SARs outstanding will expire between two and three years , depending on the date of grant. 
+68 
+Supplemental Cash Flow Information 
+The following table sets forth supplemental cash flow information for the periods indicated: 
+Years Ended December 31, 
+2022 2021 2020 
+(In thousands) 
+Interest paid, net of capitalized amounts $ 82,390 $ 85,042 $ 91,269 
+Income taxes paid (1) 
+— — — 
+Cash paid for amounts included in the measurement of lease liabilities: 
+Operating cash flows from operating leases $ 7,096 $ 26,681 $ 44,314 
+Investing cash flows from operating leases 32,060 18,598 24,234 
+Non-cash investing and financing activities: 
+Change in accrued capital expenditures $ 12,096 $ 63,444 ($ 64,465 ) 
+Change in asset retirement costs 6,500 2,905 8,605 
+ROU assets obtained in exchange for lease liabilities: 
+Operating leases $ 56,291 $ 24,301 $ 8,070 
+Financing leases — — — 
+(1) The Company did no t pay any federal income tax for any of the years in the three-year period ending December 31, 2022. For the years ended December 31, 2022, 2021, and 2020, the Company paid approximately $ 0.2 million, $ 3.2 million, and $ 1.5 million, respectively, in state income taxes. 
+Earnings per Share 
+The Company’s basic net income (loss) per common share is based on the weighted average number of shares of common stock outstanding for the period. Diluted net income (loss) per common share is calculated using the treasury stock method and is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the year which include RSU Equity Awards and common stock warrants. When a net loss per common share exists, all potentially dilutive common shares outstanding are anti-dilutive and are therefore excluded from the calculation of diluted weighted average shares outstanding. See “Note 6 – Earnings Per Share” for further discussion. 
+Industry Segment and Geographic Information 
+The Company operates in one industry segment, which is the exploration, development, and production of crude oil, natural gas, and NGLs, and all of the Company’s operations are located in the United States. 
+Recently Adopted Accounting Standards 
+Debt . In August 2020, the FASB issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40) (“ASU 2020-06”). ASU 2020-06 was issued to reduce the complexity associated with accounting for certain financial instruments with characteristics of liabilities and equity. The guidance is to be applied using either a modified retrospective or a fully retrospective method. ASU 2020-06 is effective for fiscal years beginning after December 15, 2021, with early adoption permitted. The Company adopted ASU 2020-06 on January 1, 2022. The adoption of ASU 2020-06 did not have a material impact to the Company’s consolidated financial statements or disclosures. 
+Recently Issued Accounting Standards 
+In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”) followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021 to provide clarifying guidance regarding the scope of Topic 848. ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. Generally, the guidance is to be applied as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. ASU 2020-04 and ASU 2021-01 are effective for all entities through December 31, 2022. In December 2022, the FASB issued ASU 2022-06 which extend the effective date through December 31, 2024. As of December 31, 2022, the Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and ASU 2021-01. Please refer to “Note 7 – Borrowings” for discussion of the Credit Agreement (as defined below) recently entered into which replaced all provisions and related definitions regarding LIBOR with SOFR . 
+69 
+Note 3 – Revenue Recognition 
+Revenue from contracts with customers 
+Oil sales 
+Under the Company’s oil sales contracts it sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the point of delivery at the net price received. The Company has certain oil sales that occur at market locations downstream of the production area. Given the structure of these arrangements and where control transfers, the Company separately recognizes fees and other deductions incurred prior to control transfer as “Gathering, transportation and processing” in its consolidated statements of operations. 
+Natural gas and NGL sales 
+Under the Company’s natural gas sales processing contracts, it delivers natural gas to a midstream processing entity which gathers and processes the natural gas and either remits proceeds to the Company for the resulting sale of NGLs and residue gas or, in take in-kind arrangements, provides the Company the resulting NGLs and/or residue gas for sale to downstream customers. The Company evaluates whether the processing entity is the principal or the agent in the transaction for each of our natural gas processing agreements and have concluded that the Company maintains control through processing or has the right to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. The Company recognizes revenue when control transfers to the purchaser at the delivery point based on the contractual index price received. 
+The Company recognizes revenue for natural gas and NGLs on a gross basis with gathering, transportation and processing fees recognized separately as “Gathering, transportation and processing” in its consolidated statements of operations as the Company maintains control throughout processing. 
+Oil and gas purchase and sale arrangements 
+The Company proactively evaluates development plans and looks to enter into pipeline transportation contracts to mitigate market exposures and help ensure certainty of flow for its oil and gas production, in some cases multiple years in advance of development. Additionally, as the Company looks to optimize its operations and reduce exposures, in certain instances, the Company purchases oil and gas from third parties which is utilized to fulfill portions of its pipeline commitments. Sales of purchased oil and gas represent revenues the Company receives from sales of commodities purchased from a third-party. The Company recognizes these revenues and the purchase of the third-party commodities, as well as any costs associated with the purchase, on a gross basis, as the Company acts as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer. 
+Accounts Receivable from Revenues from Contracts with Customers 
+Net accounts receivable include amounts billed and currently due from revenues from contracts with customers of our oil and natural gas production, which had a balance at December 31, 2022 and 2021 of $ 174.1 million and $ 171.8 million, respectively, and are presented in “Accounts receivable, net” in the consolidated balance sheets. 
+Note 4 – Acquisitions and Divestitures 
+2022 Acquisitions and Divestitures 
+The Company did not have any material acquisitions or divestitures for the year ended December 31, 2022. 
+2021 Acquisitions and Divestitures 
+Primexx Acquisition 
+On October 1, 2021, the Company closed on the acquisition of certain producing oil and gas properties, undeveloped acreage and associated infrastructure assets in the Delaware Basin from Primexx Resource Development, LLC (“Primexx”) and BPP Acquisition, LLC (“BPP”) for an adjusted purchase price of approximately $ 444.8 million in cash, inclusive of the deposit paid at signing, 8.84 million shares of the Company’s common stock and approximately $ 25.2 million paid upon final closing for total consideration of $ 877.0 million (the “Primexx Acquisition”). The Company funded the cash portion of the total consideration with borrowings under its credit facility. Of the 8.84 million shares of the Company’s common stock issued upon closing, 2.6 million shares were held in escrow pursuant to the purchase and sale agreements with Primexx and BPP (collectively, the “Primexx PSAs”). Pursuant to the Primexx PSAs, 1.3 million of the shares held in escrow were released to the sellers six months after the closing date, which was on April 1, 2022. In early October 2022, the remaining 1.2 million shares were released to the sellers, net of shares that were released to the Company for the satisfaction of indemnification claims made under the Primexx PSAs and subsequently retired. 
+Also, pursuant to the Primexx PSAs, certain interest owners exercised their option to sell their interest in the properties included in the Primexx Acquisition to the Company for consideration structured similarly to the Primexx Acquisition, for an incremental purchase 
+70 
+price totaling approximately $ 31.8 million, net of customary purchase price adjustments, of which $ 22.4 million closed during the fourth quarter of 2021 and the remaining $ 9.4 million closed during the first quarter of 2022. 
+The Primexx Acquisition was accounted for as a business combination; therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values with information available at that time. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. 
+The following table sets forth the Company’s final allocation of the purchase price of $ 908.9 million to the assets acquired and liabilities assumed as of the acquisition date. 
+Final Purchase 
+Price Allocation 
+(In thousands) 
+Assets: 
+Other current assets $ 8,174 
+Evaluated oil and natural gas properties 695,838 
+Unevaluated properties 278,370 
+Total assets acquired $ 982,382 
+Liabilities: 
+Suspense payable $ 16,447 
+Other current liabilities 45,745 
+Asset retirement obligation 1,898 
+Other long-term liabilities 9,425 
+Total liabilities assumed $ 73,515 
+Total consideration $ 908,867 
+Approximately $ 570.7 million of revenues and $ 141.2 million of direct operating expenses attributed to the Primexx Acquisition were included in the Company’s consolidated statements of operations for the year ended December 31, 2022 . For the period from the closing date of the Primexx Acquisition on October 1, 2021 through December 31, 2021, approximately $ 114.3 million of revenues and $ 32.1 million of direct operating expenses were included in the Company’s consolidated statements of operations for the year ended December 31, 2021. 
+Pro Forma Operating Results (Unaudited). The following unaudited pro forma combined condensed financial data for the years ended December 31, 2021 and 2020 was derived from the historical financial statements of the Company giving effect to the Primexx Acquisition, as if it had occurred on January 1, 2020. The below information reflects pro forma adjustments for the issuance of the Company’s common stock and the borrowings under the Credit Facility as total consideration, as well as pro forma adjustments based on available information and certain assumptions that the Company believes provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Primexx Acquisition. 
+The pro forma consolidated statements of operations data has been included for comparative purposes only, is not necessarily indicative of the results that might have occurred had the Primexx Acquisition taken place on January 1, 2020 and is not intended to be a projection of future results. 
+Years Ended December 31, 
+2021 2020 
+(In thousands) 
+Revenues $ 2,294,893 $ 1,228,735 
+Income (loss) from operations 1,151,493 ( 3,072,237 ) 
+Net income (loss) 482,690 ( 3,151,443 ) 
+Basic earnings per common share $ 8.37 ($ 64.65 ) 
+Diluted earnings per common share $ 8.13 ($ 64.65 ) 
+71 
+Non-Core Asset Divestitures 
+During the second quarter of 2021, the Company completed its divestitures of certain non-core assets in the Delaware Basin for net proceeds of $ 29.6 million. The divestitures were primarily comprised of natural gas producing properties in the Western Delaware Basin as well as a small undeveloped acreage position. 
+On November 19, 2021, the Company closed on its divestiture of certain non-core assets in the Eagle Ford Shale, comprised of producing properties as well as an undeveloped acreage position, for net proceeds of $ 91.9 million. 
+In the fourth quarter of 2021, the Company closed on the divestiture of certain non-core assets in the Midland Basin, comprised of producing properties as well as an undeveloped acreage position for net proceeds of $ 30.5 million. 
+On October 28, 2021, the Company closed on the divestiture of certain non-core water infrastructure for net proceeds of $ 27.9 million, as well as up to $ 18.0 million of incremental contingent consideration based on completed lateral length for wells in a specified area. 
+The aggregate net proceeds for each of the 2021 divestitures discussed above were recognized as a reduction of evaluated oil and gas properties with no gain or loss recognized as the divestitures did not significantly alter the relationship between capitalized costs and estimated proved reserves. 
+2020 Divestitures 
+ORRI Transaction. On September 30, 2020, the Company sold an undivided 2.0 % (on an 8/8ths basis) overriding royalty interest, proportionately reduced to the Company’s net revenue interest, in and to the Company’s operated leases, excluding certain interests to Chambers Minerals, LLC, a private investment vehicle managed by Kimmeridge Energy, for net proceeds of $ 135.8 million (“ORRI Transaction”), which were used to repay borrowings outstanding under the Credit Facility. 
+Non-Operated Working Interest Transaction. On November 2, 2020, the Company sold substantially all of its non-operated assets for net proceeds of approximately $ 29.6 million, which were used to repay borrowings outstanding under the Credit Facility. The transaction had an effective date of September 1, 2020 and is subject to post-closing adjustments. 
+The aggregate net proceeds for each of the 2020 divestitures discussed above were recognized as a reduction of evaluated oil and gas properties with no gain or loss recognized as the divestitures did not significantly alter the relationship between capitalized costs and estimated proved reserves. 
+Note 5 – Property and Equipment, Net 
+As of December 31, 2022 and 2021, total property and equipment, net consisted of the following: 
+As of December 31, 
+2022 2021 
+Oil and natural gas properties, full cost accounting method (In thousands) 
+Evaluated properties $ 10,367,478 $ 9,238,823 
+Accumulated depreciation, depletion, amortization and impairments ( 6,343,875 ) ( 5,886,002 ) 
+Evaluated properties, net 4,023,603 3,352,821 
+Unevaluated properties 
+Unevaluated leasehold and seismic costs 1,392,327 1,557,453 
+Capitalized interest 318,979 255,374 
+Total unevaluated properties 1,711,306 1,812,827 
+Total oil and natural gas properties, net $ 5,734,909 $ 5,165,648 
+Other property and equipment $ 40,530 $ 58,367 
+Accumulated depreciation ( 14,378 ) ( 30,239 ) 
+Other property and equipment, net $ 26,152 $ 28,128 
+The Company capitalized internal costs of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities totaling $ 48.8 million, $ 47.4 million, and $ 36.2 million for the years ended December 31, 2022, 2021 and 2020, respectively. 
+The Company capitalized interest costs to unproved properties totaling $ 108.1 million, $ 99.6 million and $ 88.6 million for the years ended December 31, 2022, 2021 and 2020, respectively. 
+72 
+Impairment of Evaluated Oil and Gas Properties 
+The Company did no t recognize impairments of evaluated oil and gas properties for the years ended December 31, 2022 and 2021. Primarily as a result of the significant reduction in the 12-Month Average Realized Price of oil, the Company recognized impairments of evaluated oil and gas properties of $ 2.5 billion for the year ended December 31, 2020. 
+Details of the 12-Month Average Realized Price of oil for the years ended December 31, 2022, 2021, and 2020 are summarized in the table below: 
+Years Ended December 31, 
+2022 2021 2020 
+Impairment of evaluated oil and natural gas properties (In thousands) $ — $ — $ 2,547,241 
+Beginning of period 12-Month Average Realized Price ($/Bbl) $ 65.44 $ 37.44 $ 53.90 
+End of period 12-Month Average Realized Price ($/Bbl) $ 95.02 $ 65.44 $ 37.44 
+Percent increase (decrease) in 12-Month Average Realized Price 45 % 75 % ( 31 %) 
+Unevaluated property costs not subject to amortization as of December 31, 2022 were incurred in the following periods: 
+2022 2021 2020 2019 and Prior Total 
+(In thousands) 
+Unevaluated property costs $ 141,944 $ 401,403 $ 113,078 $ 1,054,881 $ 1,711,306 
+Note 6 – Earnings Per Share 
+Basic earnings (loss) per share is computed by dividing net income (loss) by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings per share includes the potential dilutive impact of non-vested restricted stock units and unexercised warrants outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. For the year ended December 31, 2020, the Company reported a net loss. As a result, the calculation of diluted weighted average common shares outstanding excluded all potentially dilutive common shares outstanding. 
+The following table sets forth the computation of basic and diluted earnings per share: 
+Years Ended December 31, 
+2022 2021 2020 
+(In thousands, except per share amounts) 
+Net Income (Loss) $ 1,209,816 $ 365,151 ($ 2,533,621 ) 
+Basic weighted average common shares outstanding 61,620 48,612 39,718 
+Dilutive impact of restricted stock units 284 296 — 
+Dilutive impact of warrants — 1,403 — 
+Diluted weighted average common shares outstanding 61,904 50,311 39,718 
+Net Income (Loss) Per Common Share 
+Basic $ 19.63 $ 7.51 ($ 63.79 ) 
+Diluted $ 19.54 $ 7.26 ($ 63.79 ) 
+Restricted stock units (1) 
+30 7 581 
+Warrants (1) 
+455 481 2,564 
+(1) Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive. 
+73 
+Note 7 – Borrowings 
+The Company’s borrowings consisted of the following: 
+As of December 31, 
+2022 2021 
+(In thousands) 
+6.125 % Senior Notes due 2024 
+— 460,241 
+9.0 % Second Lien Senior Secured Notes due 2025 
+— 319,659 
+8.25 % Senior Notes due 2025 
+187,238 187,238 
+6.375 % Senior Notes due 2026 
+320,783 320,783 
+Senior Secured Revolving Credit Facility due 2027 503,000 785,000 
+8.0 % Senior Notes due 2028 
+650,000 650,000 
+7.5 % Senior Notes due 2030 
+600,000 — 
+Total principal outstanding 2,261,021 2,722,921 
+Unamortized premium on 6.125 % Senior Notes 
+— 2,373 
+Unamortized discount on 9.0 % Second Lien Notes 
+— ( 14,852 ) 
+Unamortized premium on 8.25 % Senior Notes 
+1,715 2,477 
+Unamortized deferred financing costs for 9.0 % Second Lien Notes 
+— ( 2,910 ) 
+Unamortized deferred financing costs for Senior Unsecured Notes ( 21,441 ) ( 15,894 ) 
+Total carrying value of borrowings (1) 
+$ 2,241,295 $ 2,694,115 
+(1) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $ 18.8 million and $ 18.1 million as of December 31, 2022 and 2021, respectively, which are classified in “Deferred financing costs” in the consolidated balance sheets. 
+Senior Secured Revolving Credit Facility 
+On December 20, 2019, upon consummation of the acquisition of Carrizo Oil & Gas, Inc. (the “Merger” or the “Carrizo Acquisition”), the Company entered into the credit agreement with a syndicate of lenders (the “Prior Credit Facility”). The Prior Credit Facility provided for interest-only payments until December 20, 2024, when the Prior Credit Facility would mature and any outstanding borrowings would become due. The maximum credit amount under the Prior Credit Facility was $ 5.0 billion. 
+On May 2, 2022, as part of the Company’s spring 2022 redetermination, the borrowing base and elected commitment amount of $ 1.6 billion was reaffirmed for the Prior Credit Facility. 
+On October 19, 2022, the Company entered into the Amended & Restated Credit Agreement (the “Credit Agreement” and the senior secured revolving credit facility thereunder, the “Credit Facility”) on substantially similar terms as those in the credit agreement governing the Prior Credit Facility. The Credit Agreement, among other things, extended the term to provide for interest-only payments until October 19, 2027 when the Credit Agreement matures and any outstanding borrowings are due, established a borrowing base of $ 2.0 billion, with an elected commitment amount of $ 1.5 billion, replaced all provisions and related definitions regarding LIBOR with SOFR, and decreased the maximum leverage ratio from 4.00 to 1.00 to 3.50 to 1.00. 
+As a result of entering into the Credit Facility, as defined below, the Company recognized a loss on extinguishment of debt of $ 3.2 million, which was comprised solely of the write-off of certain of the unamortized deferred financing costs associated with the Prior Credit Facility. 
+As of December 31, 2022, the borrowing base under the Credit Facility was $ 2.0 billion, with an elected commitment amount of $ 1.5 billion, and borrowings outstanding of $ 503.0 million at a weighted-average interest rate of 6.56 %, and letters of credit outstanding of $ 16.4 million. 
+Borrowings outstanding under the Credit Agreement bear interest at the Company’s option at either (i) a base rate for a base rate loan plus a margin between 0.75 % to 1.75 %, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.50 %, and the SOFR plus 0.1 % (“Adjusted SOFR”) for a one month period plus 1.00 %, or (ii) an Adjusted SOFR plus a margin between 1.75 % to 2.75 %. The Company also incurs commitment fees at rates ranging between 0.375 % to 0.500 % on the unused portion of lender commitments, which are included in “Interest expense, net of capitalized amounts” in the consolidated statements of operations. 
+The borrowing base under the Credit Agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the Credit Agreement, which in each case may reduce the amount of the borrowing base. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. 
+74 
+Senior Unsecured Notes 
+7.5 % Senior Notes . On June 24, 2022, the Company issued and sold $ 600.0 million in aggregate principal amount of 7.5 % senior unsecured notes due 2030 (the “ 7.5 % Senior Notes”) in a private placement for proceeds of approximately $ 588.0 million, net of initial purchasers’ discounts and commissions. The 7.5 % Senior Notes mature on June 15, 2030, and interest is payable semi-annually each June 15 and December 15, commencing on December 15, 2022. 
+At any time prior to June 15, 2025, the Company may, from time to time, redeem up to 35 % of the aggregate principal amount of the 7.5 % Senior Notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 107.5 % of the principal amount, plus accrued and unpaid interest, if any, to, but excluding, the date of redemption, if at least 65 % of the aggregate principal amount of the 7.5 % Senior Notes remains outstanding after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. Prior to June 15, 2025, the Company may, at its option, on any one or more occasions, redeem all or a portion of the 7.5 % Senior Notes at 100.0 % of the principal amount plus an applicable make-whole premium and accrued and unpaid interest. On or after June 15, 2025, the Company may redeem all or a portion of the 7.5 % Senior Notes at redemption prices decreasing annually from 103.75 % to 100.0 % of the principal amount redeemed plus accrued and unpaid interest. Upon the occurrence of certain kinds of change of control that are accompanied by a ratings decline, each holder of the 7.5 % Senior Notes may require the Company to repurchase all or a portion of such holder’s 7.5 % Senior Notes for cash at a price equal to 101 % of the aggregate principal amount, plus accrued and unpaid interest. 
+Redemption of 6.125 % Senior Notes and 9.0 % Second Lien Notes. On June 24, 2022, the Company used the proceeds from the offering of the 7.5 % Senior Notes, along with borrowings under its credit facility, to redeem all of its outstanding 6.125 % Senior Notes and 9.0 % Second Lien Notes (the “Second Lien Notes”). The Company recognized a loss on extinguishment of debt of approximately $ 42.4 million in its consolidated statements of operations as a result of the redemptions, which primarily related to redemption premiums and to the write-off of the remaining unamortized premium associated with the 6.125 % Senior Notes, partially offset by the write-offs of the remaining unamortized discount associated with the Second Lien Notes and deferred financing costs. 
+8.0 % Senior Notes. On July 6, 2021, the Company issued $ 650.0 million aggregate principal amount of 8.0 % Senior Notes due 2028 (the “ 8.0 % Senior Notes”) in a private placement for proceeds of approximately $ 638.1 million, net of underwriting discounts and commissions and offering costs. The 8.0 % Senior Notes mature on August 1, 2028 and have interest payable semi-annually each February 1 and August 1. 
+At any time prior to August 1, 2024, the Company may, from time to time, redeem up to 35 % of the aggregate principal amount of the 8.0 % Senior Notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 108.0 % of the principal amount, plus accrued and unpaid interest, if any, to, but excluding, the date of redemption, if at least 65 % of the aggregate principal amount of the 8.0 % Senior Notes remains outstanding after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. Prior to August 1, 2024, the Company may, at its option, on any one or more occasions, redeem all or a portion of the 8.0 % Senior Notes at 100.0 % of the principal amount plus an applicable make-whole premium and accrued and unpaid interest. On or after August 1, 2024, the Company may redeem all or a portion of the 8.0 % Senior Notes at redemption prices decreasing annually from 104.0 % to 100.0 % of the principal amount redeemed plus accrued and unpaid interest. Upon the occurrence of certain kinds of change of control, the Company must make an offer to repurchase all or a portion of each holder’s 8.0 % Senior Notes for cash at a price equal to 101 % of the aggregate principal amount, plus accrued and unpaid interest. 
+8.25 % Senior Notes. The Company’s 8.25 % Senior Notes due 2025 (the “ 8.25 % Senior Notes”) mature on July 15, 2025 and have interest payable semi-annually each January 15 and July 15. Since July 15, 2022, the Company may redeem all or a portion of the 8.25 % Senior Notes at redemption prices decreasing annually from 102.063 % to 100 % of the principal amount redeemed plus accrued and unpaid interest. Following a change of control, each holder of the 8.25 % Senior Notes may require the Company to repurchase the 8.25 % Senior Notes for cash at a price equal to 101 % of the principal amount purchased, plus any accrued and unpaid interest. 
+6.375 % Senior Notes. The Company’s 6.375 % Senior Notes due 2026 (the “ 6.375 % Senior Notes”) mature on July 1, 2026 and have interest payable semi-annually each January 1 and July 1. Since July 1, 2022, the Company may redeem all or a portion of the 6.375 % Senior Notes at redemption prices decreasing annually from 102.125 % to 100 % of the principal amount redeemed plus accrued and unpaid interest. Following a change of control, each holder of the 6.375 % Senior Notes may require the Company to repurchase all or a portion of the 6.375 % Senior Notes at a price of 101 % of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase. 
+Each of the Senior Unsecured Notes described above are guaranteed on a senior unsecured basis by the Company’s wholly owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The subsidiary guarantor is 100 % owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor. 
+75 
+Second Lien Notes 
+Exchange. On November 5, 2021, the Company closed on its transaction with Chambers Investments, LLC, a private investment vehicle managed by Kimmeridge Energy Management, LLC, to exchange $ 197.0 million of its outstanding Second Lien Notes for a notional amount of approximately $ 223.1 million of the Company’s common stock. The value of equity to be delivered was based on the optional redemption language in the indenture for the Second Lien Notes. The price of the Company’s common stock used to calculate the shares issued was based on the 10 -day volume-weighted average price as of August 2, 2021 and equated to 5.5 million shares. As a result of the Second Lien Note Exchange, the Company recognized a loss on the extinguishment of debt of approximately $ 43.4 million in its consolidated statement of operations for the year ended December 31, 2021 , calculated as the notional amount of common stock issued less aggregate principal amount of Second Lien Notes exchanged, net of a pro-rata write-off of associated unamortized discount of $ 16.9 million and fees incurred. 
+Covenants 
+The Company’s Credit Facility and the indentures governing the 8.25 % Senior Notes, the 6.375 % Senior Notes, the 8.0 % Senior Notes, and the 7.5 % Senior Notes (collectively, the “Senior Unsecured Notes”) limit the Company and certain of its subsidiaries with respect to the amount of additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters, along with maintenance of certain financial ratios. 
+Under the Credit Agreement, the Company must maintain the following financial covenants determined as of the last day of the quarter: (1) a Leverage Ratio (as defined in the credit agreement governing the Credit Facility) of no more than 3.50 to 1.00 and (2) a Current Ratio (as defined in the credit agreement governing the Credit Facility) of not less than 1.00 to 1.00. The Company was in compliance with these covenants at December 31, 2022. 
+The Credit Agreement and indentures are subject to customary events of default. If an event of default occurs and is continuing, the holders or lenders may elect to accelerate amounts due (except in the case of a bankruptcy event of default, in which case such amounts will automatically become due and payable). 
+Note 8 – Derivative Instruments and Hedging Activities 
+Objectives and Strategies for Using Derivative Instruments 
+The Company is exposed to fluctuations in oil, natural gas and NGL prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil, natural gas and NGL production. The Company utilizes a mix of collars, swaps, put and call options, and basis differential swaps to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes. 
+Counterparty Risk and Offsetting 
+The Company typically has numerous commodity derivative instruments outstanding with a counterparty that were executed at various dates, for various contract types, commodities and time periods. This often results in both commodity derivative asset and liability positions with that counterparty. The Company nets its commodity derivative instrument fair values executed with the same counterparty to a single asset or liability pursuant to ISDA Agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement. 
+The Company strives to minimize its credit exposure to any individual counterparty and, as such, the Company had outstanding commodity derivative instruments with eight counterparties as of December 31, 2022. All of the counterparties to the Company’s commodity derivative instruments are also lenders under the Company’s Credit Agreement. Therefore, each of the Company’s counterparties allow the Company to satisfy any need for margin obligations associated with commodity derivative instruments where the Company is in a net liability position with the collateral securing the Credit Agreement, thus eliminating the need for independent collateral posting. 
+Because each of the Company’s counterparties has an investment grade credit rating, the Company believes it does not have significant credit risk and accordingly does not currently require its counterparties to post collateral to support the net asset positions of its commodity derivative instruments. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each counterparty. 
+While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject 
+76 
+to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument. See “Note 9 – Fair Value Measurements” for further discussion. 
+Contingent Consideration Arrangements 
+In the second quarter of 2019, the Company completed its divestiture of certain non-core assets in the southern Midland Basin. Additionally, on December 20, 2019, the Company completed the Carrizo Acquisition. Both of these transactions included potential additional contingent consideration if certain specified pricing thresholds were met through the end of 2021. Those pricing thresholds were met for 2021, resulting in a cash receipt and cash payment, respectively, during the first quarter of 2022. Cash received or paid for settlements of contingent consideration arrangements are classified as cash flows from financing activities or cash flows from investing activities, respectively, up to the divestiture or acquisition date fair value, respectively, with any excess classified as cash flows from operating activities. As a result, the Company received $ 20.8 million, of which $ 8.5 million is presented in cash flows from financing activities with the remaining $ 12.3 million presented in cash flows from operating activities, and paid $ 25.0 million, of which $ 19.2 million is presented in cash flows from investing activities with the remaining $ 5.8 million presented in cash flows from operating activities. Both of these contingent consideration arrangements were completed as of the end of 2021. 
+Financial Statement Presentation and Settlements 
+The Company records its derivative instruments at fair value in the consolidated balance sheets and records changes in fair value, as well as settlements during the period, as “(Gain) loss on derivative contracts” in the consolidated statements of operations. The Company presents the fair value of derivative contracts on a net basis in the consolidated balance sheets as they are subject to master netting arrangements. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated: 
+As of December 31, 2022 
+Presented without As Presented with 
+Effects of Netting Effects of Netting Effects of Netting 
+(In thousands) 
+Derivative Assets 
+Fair value of derivatives - current $ 51,984 ($ 30,652 ) $ 21,332 
+Other assets, net $ 1,343 ($ 889 ) $ 454 
+Derivative Liabilities 
+Fair value of derivatives - current ($ 46,849 ) $ 30,652 ($ 16,197 ) 
+Fair value of derivatives - non current ($ 14,304 ) $ 889 ($ 13,415 ) 
+As of December 31, 2021 
+Presented without As Presented with 
+Effects of Netting Effects of Netting Effects of Netting 
+(In thousands) 
+Assets 
+Commodity derivative instruments $ 25,469 ($ 23,921 ) $ 1,548 
+Contingent consideration arrangements 20,833 — 20,833 
+Fair value of derivatives - current $ 46,302 ($ 23,921 ) $ 22,381 
+Commodity derivative instruments $ 1,119 ($ 869 ) $ 250 
+Other assets, net $ 1,119 ($ 869 ) $ 250 
+Liabilities 
+Commodity derivative instruments (1) 
+($ 184,898 ) $ 23,921 ($ 160,977 ) 
+Contingent consideration arrangements ( 25,000 ) — ( 25,000 ) 
+Fair value of derivatives - current ($ 209,898 ) $ 23,921 ($ 185,977 ) 
+Commodity derivative instruments ($ 12,278 ) $ 869 ($ 11,409 ) 
+Fair value of derivatives - non current ($ 12,278 ) $ 869 ($ 11,409 ) 
+(1) Includes approximately $ 2.9 million of deferred premiums, which were paid as the applicable contracts settled. 
+77 
+The components of “Loss on derivative contracts” are as follows for the respective periods: 
+Years Ended December 31, 
+2022 2021 2020 
+(In thousands) 
+(Gain) loss on oil derivatives $ 287,379 $ 429,156 ($ 48,031 ) 
+Loss on natural gas derivatives 38,803 33,621 14,883 
+Loss on NGL derivatives 4,771 6,768 2,426 
+(Gain) loss on contingent consideration arrangements — ( 2,635 ) 2,976 
+Loss on September 2020 Warrants liability (1) 
+— 55,390 55,519 
+Loss on derivative contracts $ 330,953 $ 522,300 $ 27,773 
+(1) A detailed discussion of the Company’s September 2020 Warrants can be found in “Part II, Item 8. Financial Statements and Supplementary Data, Note 7 – Borrowings” of its Annual Report on Form 10-K for the year ended December 31, 2021, which was filed with the SEC on February 24, 2022. 
+The components of “Cash received (paid) for commodity derivative settlements, net” and “Cash received (paid) for settlements of contingent consideration arrangements, net” are as follows for the respective periods: 
+Years Ended December 31, 
+2022 2021 2020 
+(In thousands) 
+Cash flows from operating activities 
+Cash received (paid) on oil derivatives ($ 429,017 ) ($ 350,340 ) $ 98,723 
+Cash received (paid) on natural gas derivatives ( 60,914 ) ( 34,576 ) 147 
+Cash paid on NGL derivatives ( 3,783 ) ( 10,181 ) — 
+Cash received (paid) for commodity derivative settlements, net ($ 493,714 ) ($ 395,097 ) $ 98,870 
+Cash received for settlements of contingent consideration arrangements, net $ 6,492 $ — $ — 
+Cash flows from investing activities 
+Cash paid for settlement of contingent consideration arrangement ($ 19,171 ) $ — ($ 40,000 ) 
+Cash flows from financing activities 
+Cash received for settlement of contingent consideration arrangement $ 8,512 $ — $ — 
+78 
+Derivative Positions 
+Listed in the tables below are the outstanding oil and natural gas derivative contracts as of December 31, 2022: 
+For the Full Year For the Full Year 
+Oil Contracts (WTI) 2023 2024 
+Swap Contracts 
+Total volume (Bbls) 1,541,500 — 
+Weighted average price per Bbl $ 79.87 $ — 
+Collar Contracts (Three-Way Collars) 
+Total volume (Bbls) 1,825,000 — 
+Weighted average price per Bbl 
+Ceiling (short call) $ 90.00 $ — 
+Floor (long put) $ 70.00 $ — 
+Floor (short put) $ 50.00 $ — 
+Collar Contracts (Two-Way Collars) 
+Total volume (Bbls) 2,365,000 — 
+Weighted average price per Bbl 
+Ceiling (short call) $ 88.26 $ — 
+Floor (long put) $ 72.22 $ — 
+Short Call Swaption Contracts (1) 
+Total volume (Bbls) — 1,830,000 
+Weighted average price per Bbl $ — $ 80.30 
+(1) The 2024 short call swaption contracts have exercise expiration dates of December 29, 2023. 
+For the Full Year For the Full Year 
+Natural Gas Contracts (Henry Hub) 2023 2024 
+Swap Contracts 
+Total volume (MMBtu) 2,140,000 — 
+Weighted average price per MMBtu $ 5.11 $ — 
+Collar Contracts 
+Total volume (MMBtu) 8,780,000 — 
+Weighted average price per MMBtu 
+Ceiling (short call) $ 6.52 $ — 
+Floor (long put) $ 4.37 $ — 
+Natural Gas Contracts (Waha Basis Differential) 
+Swap Contracts 
+Total volume (MMBtu) 6,080,000 — 
+Weighted average price per MMBtu ($ 0.75 ) $ — 
+Natural Gas Contracts (HSC Basis Differential) 
+Swap Contracts 
+Total volume (MMBtu) 7,300,000 7,320,000 
+Weighted average price per MMBtu ($ 0.27 ) ($ 0.45 ) 
+Note 9 – Fair Value Measurements 
+Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: 
+Level 1 – Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities. 
+Level 2 – Other inputs that are observable directly or indirectly, such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. 
+79 
+Level 3 – Unobservable inputs for which there is little or no market data and for which the Company makes its own assumptions about how market participants would price the assets and liabilities. 
+Fair Value of Financial Instruments 
+Cash, Cash Equivalents, and Restricted Investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments. 
+Debt. The carrying amount of borrowings outstanding under the Credit Facility approximates fair value as the borrowings bear interest at variable rates and are reflective of market rates. The following table presents the principal amounts of the Company’s Second Lien Notes and Senior Unsecured Notes with the fair values measured using quoted secondary market trading prices which are designated as Level 2 within the valuation hierarchy. See “Note 7 – Borrowings” for further discussion. 
+December 31, 2022 December 31, 2021 
+Principal Amount Fair Value Principal Amount Fair Value 
+(In thousands) 
+6.125 % Senior Notes 
+$ — $ — $ 460,241 $ 455,639 
+9.0 % Second Lien Notes 
+— — 319,659 343,633 
+8.25 % Senior Notes 
+187,238 186,719 187,238 184,429 
+6.375 % Senior Notes 
+320,783 301,732 320,783 309,556 
+8.0 % Senior Notes 
+650,000 616,935 650,000 663,000 
+7.5 % Senior Notes 
+600,000 550,812 — — 
+Total $ 1,758,021 $ 1,656,198 $ 1,937,921 $ 1,956,257 
+Assets and Liabilities Measured at Fair Value on a Recurring Basis 
+Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheets. The following methods and assumptions were used to estimate fair value: 
+Commodity Derivative Instruments. The fair value of commodity derivative instruments is derived using a third-party income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the commodity derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for commodity derivative assets and an estimate of the Company’s default risk for commodity derivative liabilities. As the inputs in the model are substantially observable over the term of the commodity derivative contract and as there is a wide availability of quoted market prices for similar commodity derivative contracts, the Company designates its commodity derivative instruments as Level 2 within the fair value hierarchy. See “Note 8 – Derivative Instruments and Hedging Activities” for further discussion. 
+The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2022 and 2021: 
+December 31, 2022 
+Level 1 Level 2 Level 3 
+(In thousands) 
+Commodity derivative assets $ — $ 21,786 $ — 
+Commodity derivative liabilities $ — ($ 29,612 ) $ — 
+December 31, 2021 
+Level 1 Level 2 Level 3 
+(In thousands) 
+Assets 
+Commodity derivative instruments $ — $ 1,798 $ — 
+Contingent consideration arrangements — 20,833 — 
+Liabilities 
+Commodity derivative instruments (1) 
+— ( 172,386 ) — 
+Contingent consideration arrangements — ( 25,000 ) — 
+Total net assets (liabilities) $ — ($ 174,755 ) $ — 
+(1) Includes approximately $ 2.9 million of deferred premiums which will be paid as the applicable contracts settle. 
+There were no transfers between any of the fair value levels during any period presented. 
+80 
+Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis 
+Acquisitions. The fair value of assets acquired and liabilities assumed are measured as of the acquisition date by a third-party valuation specialist using a combination of income and market approaches, which are not observable in the market and are therefore designated as Level 3 inputs. Significant inputs include expected discounted future cash flows from estimated reserve quantities, estimates for timing and costs to produce and develop reserves, oil and natural gas forward prices, and a risk adjusted discount rate. See “Note 4 – Acquisitions and Divestitures” for additional discussion. 
+Asset Retirement Obligations. The Company measures the fair value of asset retirement obligations as of the date a well begins drilling or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and that, therefore, are designated as Level 3 within the valuation hierarchy. Significant inputs to the fair value measurement of asset retirement obligations include estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities, restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates. See “Note 14 – Asset Retirement Obligations” for additional discussion. 
+Note 10 – Share-Based Compensation 
+2020 Omnibus Incentive Plan 
+Shares-based awards are granted under the 2020 Omnibus Incentive Plan (the “2020 Plan”), which replaced the 2018 Omnibus Incentive Plan (the “2018 Plan”). From the effective date of the 2020 Plan, no further awards may be granted under the 2018 Plan; however, awards previously granted under the 2018 Plan will remain outstanding in accordance with their terms. At December 31, 2022, there were 1,703,829 shares available for future share-based awards under the 2020 Plan. 
+RSU Equity Awards 
+The following table summarizes RSU Equity Award activity for the year ended December 31, 2022: 
+RSU Equity Awards (In thousands) Weighted Average Grant-Date Fair Value per Share 
+Unvested at the beginning of the year 968 $ 34.04 
+Granted 396 $ 57.85 
+Vested ( 376 ) $ 35.32 
+Forfeited ( 188 ) $ 35.95 
+Unvested at the end of the year 800 $ 44.79 
+Grant activity for the years ended December 31, 2022, 2021 and 2020 primarily consisted of RSU Equity Awards granted to executives and employees as part of the annual grant of long-term equity incentive awards with a weighted average grant date fair value of $ 57.85 , $ 38.59 and $ 21.07 , respectively. 
+For performance-based RSU Equity Awards granted in 2020 that vested on December 31, 2022, the number of performance-based RSU Equity Awards that could vest was based on a calculation that compares the Company’s total shareholder return (“TSR”) to the same calculated return of a group of peer companies selected by the Company and can range between 0 % and 300 % of the target units. No performance-based RSU Equity Awards were granted during 2022 and 2021. 
+The following table summarizes the shares that vested and did not vest as a result of the Company’s performance as compared to its peers. 
+Years Ended December 31, 
+Performance-based Equity Awards 2022 2021 2020 
+Vesting Multiplier 18 % 50 % 
+50 % - 100 % 
+Target 86,455 28,356 21,920 
+Vested at end of performance period 15,559 14,177 11,372 
+Did not vest at end of performance period 70,896 14,179 10,548 
+The Company recognizes expense for performance-based RSU Equity Awards based on the fair value of the awards at the grant date. Awards with a performance-based provision do not allow for the reversal of previously recognized expense, even if the market metric is not achieved and no shares ultimately vest. For the year ended December 31, 2020, the grant date fair value of the performance-based RSU Equity Awards, calculated using a Monte Carlo simulation, was $ 3.4 million. The following table 
+81 
+summarizes the assumptions used and the resulting grant date fair value per performance-based RSU Equity Award granted during the year ended December 31, 2020: 
+Performance-based Awards June 29, 2020 January 31, 2020 
+Expected term (in years) 2.5 2.9 
+Expected volatility 113.2 % 54.8 % 
+Risk-free interest rate 0.2 % 1.3 % 
+Dividend yield — % — % 
+The aggregate fair value of RSU Equity Awards that vested during the years ended December 31, 2022, 2021 and 2020 was $ 22.4 million, $ 8.7 million and $ 1.6 million, respectively. As of December 31, 2022, unrecognized compensation costs related to unvested RSU Equity Awards were $ 23.9 million and will be recognized over a weighted average period of 1.9 years. 
+Cash-Settled Awards 
+As of December 31, 2022 and 2021, the Company had a total liability of $ 6.5 million and $ 15.6 million, respectively, for the outstanding Cash-Settled Awards. 
+Share-Based Compensation Expense, Net 
+Share-based compensation expense associated with the RSU Equity Awards, Cash-Settled RSU Awards, and Cash SARs, net of amounts capitalized, is included in “General and administrative” in the consolidated statements of operations. The following table presents share-based compensation expense (benefit), net for each respective period: 
+Years Ended December 31, 
+2022 2021 2020 
+(In thousands) 
+RSU Equity Awards $ 15,535 $ 13,230 $ 13,030 
+Cash-Settled Awards ( 7,493 ) 12,627 ( 4,115 ) 
+8,042 25,857 8,915 
+Less: amounts capitalized to oil and gas properties ( 5,535 ) ( 12,934 ) ( 6,252 ) 
+Total share-based compensation expense, net $ 2,507 $ 12,923 $ 2,663 
+Note 11 – Stockholders’ Equity 
+Increase in Authorized Common Shares 
+The Company filed an amendment to its certificate of incorporation, that became effective on May 25, 2022 to increase the number of authorized shares of common stock from 78,750,000 to 130,000,000 , as approved by the Company’s shareholders at the 2022 Annual Meeting of Shareholders on May 25, 2022. 
+Second Lien Note Exchange 
+On November 3, 2021, at a special meeting of shareholders, the Company obtained the requisite shareholder approval for the issuance of approximately 5.5 million shares of the Company’s common stock in exchange for an aggregate of $ 197.0 million principal amount of Second Lien Notes. The exchange was completed on November 5, 2021 and the exchanged Second Lien Notes were immediately cancelled. See “Note 7 – Borrowings” for discussion of the exchange of Second Lien Notes for Company common stock. 
+Primexx Acquisition 
+During the fourth quarter of 2021, the Company issued approximately 9.0 million shares of common stock in connection with the Primexx Acquisition, inclusive of the shares of common stock issued to those certain interest owners who exercised their option to sell their interest in the properties included in the Primexx Acquisition. See “Note 4 – Acquisitions and Divestitures” for additional details. 
+Warrant Exercises 
+During the year ended December 31, 2021, holders of the September 2020 Warrants and November 2020 Warrants provided notice and exercised all outstanding warrants. As a result of the exercises in 2021, the Company issued a total of 6.9 million shares of its common stock in exchange for 9.0 million outstanding warrants determined on a net shares settlement basis. A detailed discussion of the Company’s September 2020 Warrants and November 2020 Warrants can be found in “Part II, Item 8. Financial Statements and Supplementary Data, Note 7 – Borrowings” of its Annual Report on Form 10-K for the year ended December 31, 2021, which was filed with the SEC on February 24, 2022. As of December 31, 2022 and December 31, 2021, no September 2020 or November 2020 Warrants were outstanding. 
+82 
+Note 12 – Income Taxes 
+The components of the Company’s income tax expense are as follows: 
+Years Ended December 31, 
+2022 2021 2020 
+(In thousands) 
+Current 
+Federal $ 2,977 $ — $ — 
+State 4,537 180 3,447 
+Total current income tax expense 7,514 180 3,447 
+Deferred 
+Federal — — 126,903 
+State 4,279 — ( 8,296 ) 
+Total deferred income tax expense 4,279 — 118,607 
+Total income tax expense $ 11,793 $ 180 $ 122,054 
+A reconciliation of the income tax expense calculated at the federal statutory rate of 21 % to income tax expense is as follows: 
+Years Ended December 31, 
+2022 2021 2020 
+(In thousands) 
+Income (loss) before income taxes $ 1,221,609 $ 365,331 ($ 2,411,567 ) 
+Income tax expense (benefit) computed at the statutory federal income tax rate 256,538 76,720 ( 506,429 ) 
+State income tax expense (benefit), net of federal benefit 11,393 2,905 ( 11,827 ) 
+Non-deductible expenses related to capital structure transactions ( 2,896 ) ( 11,875 ) — 
+Equity based compensation ( 1,496 ) 564 2,746 
+Other ( 1,223 ) 10,247 ( 1,621 ) 
+Change in valuation allowance ( 250,523 ) ( 78,381 ) 639,185 
+Income tax expense $ 11,793 $ 180 $ 122,054 
+The income tax expense of $ 11.8 million for the year ended December 31, 2022 is lower than as calculated using the federal statutory rate primarily due to the valuation allowance recorded against the Company’s net deferred tax assets. See “— Deferred Tax Asset Valuation Allowance” below for additional details. 
+83 
+As of December 31, 2022 and 2021, the net deferred income tax assets and liabilities are comprised of the following: 
+As of December 31, 
+2022 2021 
+(In thousands) 
+Deferred tax assets 
+Oil and natural gas properties $ — $ 238,203 
+Federal net operating loss carryforward 359,784 221,900 
+Net interest expense limitation 74,628 36,171 
+Derivative instruments 12,758 30,826 
+Operating lease right-of-use assets 13,180 8,650 
+Asset retirement obligations 13,049 12,244 
+Unvested RSU equity awards 5,391 4,939 
+Other 11,675 12,892 
+Total deferred tax assets $ 490,465 $ 565,825 
+Deferred income tax valuation allowance ( 310,281 ) ( 560,804 ) 
+Net deferred tax assets $ 180,184 $ 5,021 
+Deferred tax liability 
+Oil and natural gas properties ($ 174,578 ) $ — 
+Operating lease liabilities ( 9,885 ) ( 5,021 ) 
+Total deferred tax liability ($ 184,463 ) ($ 5,021 ) 
+Net deferred tax asset (liability) ($ 4,279 ) $ — 
+Deferred Tax Asset Valuation Allowance 
+Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that the Company’s net deferred tax assets will be utilized prior to their expiration. A significant item of objective negative evidence considered was the cumulative historical three-year pre-tax loss and a net deferred tax asset position at December 31, 2022, driven primarily by the impairments of evaluated oil and gas properties recognized beginning in the second quarter of 2020 and continuing through the fourth quarter of 2020. This limits the ability to consider other subjective evidence such as the Company’s potential for future growth. Since the second quarter of 2020, based on the evaluation of the evidence available, the Company concluded that it is more likely than not that the net deferred tax assets will not be realized. As of December 31, 2022, the valuation allowance balance is $ 310.3 million, reducing the net deferred tax assets to zero . 
+The Company currently believes it is reasonably possible it could achieve a three-year cumulative level of profitability within the next 12 months, which would enhance its ability to conclude that it is more likely than not that the deferred tax assets would be realized and support a release of substantially all or a portion of the valuation allowance. However, the exact timing and amount of the release is unknown at this time. The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods based on available information each reporting period. As long as the Company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, the Company will have no significant deferred income tax expense or benefit. The valuation allowance does not preclude the Company from utilizing the tax attributes if it recognizes taxable income. 
+Inflation Reduction Act 
+On August 16, 2022, the Inflation Reduction Act (the “IRA”) was enacted into law and includes significant changes relating to tax, climate change, energy, and health care. The provisions within the IRA, among other things, include (i) a new 15% corporate alternative minimum tax on corporations with average annual adjusted financial statement income over a three-year period in excess of $1.0 billion, (ii) a new nondeductible 1% excise tax on the value of certain stock that a company repurchases, and (iii) various tax incentives for energy and climate initiatives. Each of these provisions are effective for tax years beginning after December 31, 2022. The Department of the Treasury is expected to publish regulations relevant to many aspects of the IRA. The Company is currently awaiting such guidance and continues to evaluate the effect of the new law to its future cash flows and financial results. The Company does not currently believe this will have a material impact on its cash taxes or income tax expense for the 2023 tax year. 
+Federal Net Operating Losses (“NOLs”) & Interest Limitation Carryforwards 
+At December 31, 2022, the Company had approximately $ 1.7 billion of NOLs and a net interest expense carryforward of $ 355.4 million under Section 163(j) of the Code. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” for additional details. 
+84 
+Uncertain Tax Positions 
+The Company had no significant unrecognized tax benefits at December 31, 2022. Accordingly, the Company does not have any interest or penalties related to uncertain tax positions. However, if interest or penalties were to be incurred related to uncertain tax positions, such amounts would be recognized in income tax expense. In the Company’s major tax jurisdictions, the earliest year open to examination is 2018. 
+Note 13 – Leases 
+The Company currently has leases associated with contracts for office space, drilling rigs, and the use of well equipment, vehicles, information technology infrastructure, and other office equipment. The tables below, which present the components of lease costs and supplemental balance sheet information, are presented on a gross basis. Other joint owners in the properties operated by the Company generally pay for their working interest share of costs associated with drilling rigs and well equipment. 
+The table below presents the components of the Company’s lease costs for the year ended December 31, 2022. 
+Years Ended December 31, 
+2022 2021 2020 
+(In thousands) 
+Components of Lease Costs 
+Finance lease costs $ 228 $ 277 $ 1,489 
+Amortization of right-of-use assets (1) 
+203 237 1,348 
+Interest on lease liabilities (2) 
+25 40 141 
+Operating lease cost (3) 
+38,803 37,734 46,888 
+Impairment of Operating lease ROU assets (4) 
+— — 3,575 
+Short-term lease cost (5) 
+19,426 347 1,821 
+Variable lease costs (6) 
+2,098 284 259 
+Total lease costs $ 60,555 $ 38,642 $ 54,032 
+(1) Included as a component of “Depreciation, depletion and amortization” in the consolidated statements of operations. 
+(2) Included as a component of “Interest expense, net of capitalized amounts” in the consolidated statements of operations. 
+(3) For the years ended December 31, 2022, 2021 and 2020, approximately $ 33.3 million, $ 23.0 million and $ 34.2 million, respectively, are costs associated with drilling rigs. These costs were capitalized to “Evaluated properties, net” in the consolidated balance sheets and the other remaining operating lease costs were components of “General and administrative” and “Lease operating” in the consolidated statements of operations. 
+(4) As a result of the downturn in economic conditions in conjunction with the Company’s ongoing effort to consolidate various office locations due to the Carrizo Acquisition, the Company evaluated certain of its office leases for impairment. Upon evaluation, the Company recorded impairments of certain of its operating lease ROU assets for the year ended December 31, 2020 of $ 3.6 million, which are a component of “Merger, integration and transaction expenses” in the consolidated statements of operations. 
+(5) Short-term lease cost primarily consists of drilling rigs with contract terms of less than one year. 
+(6) Variable lease costs include additional payments that were not included in the initial measurement of the lease liability and related ROU asset for lease agreements with terms greater than 12 months. Variable lease costs primarily consist of incremental usage associated with drilling rigs. 
+The table below presents supplemental balance sheet information for the Company’s operating leases. The Company’s financing leases are immaterial. 
+As of December 31, 
+2022 2021 
+(In thousands) 
+Leases 
+Operating leases: 
+Operating lease ROU assets $ 47,018 $ 23,884 
+Current operating lease liabilities $ 40,809 $ 17,599 
+Long-term operating lease liabilities 21,882 23,547 
+Total operating lease liabilities $ 62,691 $ 41,146 
+85 
+The table below presents the weighted average remaining lease terms and weighted average discounts rates for the Company’s leases as of December 31, 2022. 
+December 31, 2022 
+Weighted Average Remaining Lease Terms (In years) 
+Operating leases 3.0 
+Financing leases 1.2 
+Weighted Average Discount Rate 
+Operating leases 6.2 % 
+Financing leases 6.6 % 
+The table below presents the maturity of the Company’s lease liabilities as of December 31, 2022. 
+Operating Leases Financing Leases 
+(In thousands) 
+2023 $ 43,158 $ 233 
+2024 6,815 39 
+2025 4,366 — 
+2026 3,805 — 
+2027 3,846 — 
+Thereafter 6,488 — 
+Total lease payments 68,478 272 
+Less imputed interest ( 5,787 ) ( 12 ) 
+Total lease liabilities $ 62,691 $ 260 
+Note 14 – Asset Retirement Obligations 
+The table below summarizes the activity for the Company’s asset retirement obligations: 
+Years Ended December 31, 
+2022 2021 
+(In thousands) 
+Asset retirement obligations, beginning of period $ 56,707 $ 59,090 
+Accretion expense 3,997 3,743 
+Liabilities incurred 669 1,826 
+Increase due to acquisition of oil and gas properties — 1,898 
+Liabilities settled ( 2,008 ) ( 1,769 ) 
+Dispositions ( 4,760 ) ( 7,262 ) 
+Revisions to estimates 5,830 ( 819 ) 
+Asset retirement obligations, end of period 60,435 56,707 
+Less: Current asset retirement obligations ( 6,543 ) ( 2,249 ) 
+Non-current asset retirement obligations $ 53,892 $ 54,458 
+Certain of the Company’s operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded on the consolidated balance sheets at December 31, 2022 and 2021 as long-term restricted investments were $ 3.5 million , and are presented in “Other assets, net.” These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties. 
+Note 15 – Accounts Receivable, Net 
+As of December 31, 
+2022 2021 
+(In thousands) 
+Oil and natural gas receivables $ 174,107 $ 171,837 
+Joint interest receivables 16,778 13,751 
+Other receivables 48,277 49,053 
+Total 239,162 234,641 
+Allowance for credit losses ( 2,034 ) ( 2,205 ) 
+Total accounts receivable, net $ 237,128 $ 232,436 
+86 
+Note 16 – Accounts Payable and Accrued Liabilities 
+As of December 31, 
+2022 2021 
+(In thousands) 
+Accounts payable $ 191,133 $ 151,836 
+Revenues and royalties payable 244,408 294,143 
+Accrued capital expenditures 58,395 64,412 
+Accrued interest 42,297 59,600 
+Total accounts payable and accrued liabilities $ 536,233 $ 569,991 
+Note 17 – Commitments and Contingencies 
+The Company is involved in various claims and lawsuits incidental to its business. In the opinion of management, the ultimate liability hereunder, if any, will not have a material adverse effect on the financial position or results of operations of the Company. 
+The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment are not expected to have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies hereunder, and claims for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities. 
+The table below presents total minimum commitments associated with long-term, non-cancelable leases, drilling rig contracts, frac service contracts, gathering, processing and transportation service agreements which require minimum volumes of oil, natural gas, or produced water to be delivered and other purchase obligations, as of December 31, 2022. 
+2023 2024 2025 2026 2027 2028 and 
+Thereafter Total 
+(In thousands) 
+Office space $ 5,294 $ 5,210 $ 5,364 $ 9,423 $ 9,595 $ 55,966 $ 90,852 
+Drilling rig and frac service commitments (1) 
+251,314 — — — — — 251,314 
+Delivery commitments (2) 
+14,775 26,202 27,264 27,264 22,898 105,848 224,251 
+Produced water disposal commitments (3) 
+9,665 8,532 4,509 569 113 — 23,388 
+Purchase obligations (4) 
+10,748 8,988 8,988 8,988 8,988 13,017 59,717 
+Other operating leases 2,095 1,612 408 — — — 4,115 
+Total $ 293,891 $ 50,544 $ 46,533 $ 46,244 $ 41,594 $ 174,831 $ 653,637 
+(1) Drilling rig and frac service commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will generally be billed for their working interest share of such costs. 
+(2) Delivery commitments represent contractual obligations the Company has entered into for certain gathering, processing and transportation service agreements which require minimum volumes of oil or natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any oil or natural gas. 
+(3) Produced water disposal commitments represent contractual obligations the Company has entered into for certain service agreements which require minimum volumes of produced water to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water. 
+(4) Purchase obligations represent multi-year energy purchase agreements the Company has entered into to lock in rates for electricity utilized in its operations. Under these contracts, the Company is obligated to purchase a minimum supply of electricity at a fixed price. If the Company does not utilize the minimum amounts of electricity on a monthly basis, the supplier would sell the underutilized quantity at the then market price. The amounts in the table above reflect the aggregate undiscounted financial commitments pursuant to these purchase agreements. 
+87 
+Other Commitments 
+The following table includes the Company’s current oil sales contracts and firm transportation agreements as of December 31, 2022: 
+Type of Commitment (1) 
+Region Start Date End Date Committed 
+Volumes (Bbls/d) 
+Oil sales contract (2) 
+Permian January 2023 December 2023 13,750 
+Oil sales contract (3) 
+Permian January 2023 December 2023 8,550 
+Oil sales contract Permian April 2022 March 2023 5,000 
+Oil sales contract Permian February 2022 January 2027 5,000 
+Oil sales contract Permian January 2020 December 2024 10,000 
+Firm transportation agreement (4)(5) 
+Permian August 2020 July 2030 10,800 
+Firm transportation agreement (4) 
+Permian April 2020 March 2027 15,000 
+(1) For each of the commitments shown in the table above, the committed barrels may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. We expect to fulfill these delivery commitments with our existing production or through the purchases of third-party commodities. 
+(2) The committed volumes shown in the table above for this particular oil sales contract are average volumes. For the terms of January 2023-March 2023 and April 2023-December 2023, the committed volumes are 10,000 Bbls/d and 15,000 Bbls/d, respectively. 
+(3) The committed volumes shown in the table above for this particular oil sales contract are average volumes. For the terms of January 2023-July 2023 and August 2023-December 2023, the committed volumes are 7,500 Bbls/d and 10,000 Bbls/d, respectively. 
+(4) Each of the firm transportation agreements shown in the table above grant us access to delivery points in several locations along the Gulf Coast. The costs associated with these agreements are recorded to “Gathering, transportation and processing” in the Company’s consolidated statements of operations. 
+(5) The committed volumes shown in the table above for this particular firm transportation agreement are average volumes. For the terms of August 2020-July 2023, August 2023-July 2027 and August 2027-July 2030, the committed volumes are 7,500 Bbls/d, 10,000 Bbls/d and 12,500 Bbls/d, respectively. 
+The following table includes the Company’s current natural gas firm transportation agreements as of December 31, 2022: 
+Type of Commitment (1)(2) 
+Region Start Date End Date Committed 
+Volumes (MMBtu/d) 
+Firm transportation agreement Permian October 2023 September 2033 50,000 
+Firm transportation agreement Permian October 2023 September 2033 15,000 
+Firm transportation agreement Permian July 2024 June 2034 10,000 
+(1) For each of the commitments shown in the table above, the committed MMBtus may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. We expect to fulfill these delivery commitments with our existing production or through the purchases of third-party commodities. 
+(2) Each of the firm transportation agreements shown in the table above grant us access to delivery points in several locations along the Gulf Coast. The costs associated with these agreements are recorded to “Gathering, transportation and processing” in the Company’s consolidated statements of operations. 
+Note 18 – Supplemental Information on Oil and Natural Gas Operations (Unaudited) 
+Estimated Reserves 
+For each year in the table below, the estimated proved reserves were prepared by DeGolyer and MacNaughton (“D&M”), Callon’s independent third-party reserve engineers. The reserves were prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions. 
+There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only and should not be deemed exact. In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company’s oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves. 
+Extrapolation of performance history and material balance estimates were utilized by D&M to project future recoverable reserves for the producing properties where sufficient history existed to suggest performance trends and where these methods were applicable to the subject reservoirs. The projections for the remaining producing properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to non-producing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production and, to a small extent, horizontal PDP and PUD categories. 
+88 
+The following tables disclose changes in the estimated quantities of proved reserves, all of which are located onshore within the continental United States: 
+Years Ended December 31, 
+Proved reserves 2022 2021 2020 
+Oil (MBbls) 
+Beginning of period 290,296 289,487 346,361 
+Extensions and discoveries 41,064 22,520 25,678 
+Revisions to previous estimates ( 31,163 ) ( 10,514 ) ( 49,336 ) 
+Purchase of reserves in place — 35,045 — 
+Sales of reserves in place ( 949 ) ( 24,019 ) ( 9,673 ) 
+Production ( 23,639 ) ( 22,223 ) ( 23,543 ) 
+End of period 275,609 290,296 289,487 
+Natural Gas (MMcf) 
+Beginning of period 577,327 541,598 757,134 
+Extensions and discoveries 75,801 37,896 44,282 
+Revisions to previous estimates ( 11,155 ) ( 3,389 ) ( 198,628 ) 
+Purchase of reserves in place — 73,445 — 
+Sale of reserves in place ( 7,503 ) ( 34,837 ) ( 20,389 ) 
+Production ( 41,627 ) ( 37,386 ) ( 40,801 ) 
+End of period 592,843 577,327 541,598 
+NGLs (MBbls) 
+Beginning of period 98,104 96,126 67,462 
+Extensions and discoveries 14,264 7,345 8,349 
+Revisions to previous estimates 1,376 ( 3,103 ) 30,214 
+Purchase of reserves in place — 10,366 — 
+Sale of reserves in place ( 1,159 ) ( 6,191 ) ( 3,049 ) 
+Production ( 7,476 ) ( 6,439 ) ( 6,850 ) 
+End of period 105,109 98,104 96,126 
+Total (MBoe) 
+Beginning of period 484,621 475,879 540,012 
+Extensions and discoveries 67,961 36,180 41,407 
+Revisions to previous estimates ( 31,645 ) ( 14,181 ) ( 52,227 ) 
+Purchase of reserves in place — 57,652 — 
+Sale of reserves in place ( 3,359 ) ( 36,015 ) ( 16,120 ) 
+Production ( 38,053 ) ( 34,894 ) ( 37,193 ) 
+End of period 479,525 484,621 475,879 
+89 
+Years Ended December 31, 
+Proved developed reserves 2022 2021 2020 
+Oil (MBbls) 
+Beginning of period 162,886 128,923 152,687 
+End of period 170,866 162,886 128,923 
+Natural gas (MMcf) 
+Beginning of period 332,266 238,119 320,676 
+End of period 351,278 332,266 238,119 
+NGLs (MBbls) 
+Beginning of period 55,720 43,315 24,844 
+End of period 63,788 55,720 43,315 
+Total proved developed reserves (MBoe) 
+Beginning of period 273,983 211,925 230,977 
+End of period 293,200 273,983 211,925 
+Proved undeveloped reserves 
+Oil (MBbls) 
+Beginning of period 127,410 160,564 193,674 
+End of period 104,743 127,410 160,564 
+Natural gas (MMcf) 
+Beginning of period 245,061 303,479 436,458 
+End of period 241,565 245,061 303,479 
+NGLs (MBbls) 
+Beginning of period 42,384 52,811 42,618 
+End of period 41,321 42,384 52,811 
+Total proved undeveloped reserves (MBoe) 
+Beginning of period 210,638 263,954 309,035 
+End of period 186,325 210,638 263,954 
+Total proved reserves 
+Oil (MBbls) 
+Beginning of period 290,296 289,487 346,361 
+End of period 275,609 290,296 289,487 
+Natural gas (MMcf) 
+Beginning of period 577,327 541,598 757,134 
+End of period 592,843 577,327 541,598 
+NGLs (MBbls) 
+Beginning of period 98,104 96,126 67,462 
+End of period 105,109 98,104 96,126 
+Total proved reserves (MBoe) 
+Beginning of period 484,621 475,879 540,012 
+End of period 479,525 484,621 475,879 
+90 
+Total Proved Reserves 
+For the year ended December 31, 2022, the Company’s net decrease in proved reserves of 5.1 MMBoe was primarily due to the following: 
+• Increase of 68.0 MMBoe through extensions and discoveries through the Company’s development efforts in its operating areas, of which 8.7 MMBoe were proved developed reserves; 
+• Decrease of 31.6 MMBoe for revisions of previous estimates that were primarily comprised of: 
+◦ 44.4 MMBoe reduction due to PUD locations that were reclassified to unproved reserve categories, all of which were in the Permian. Certain PUDs were moved outside of their five-year development window as the Company continues to refine its future development plans for the Permian, including increased application of its “Life of Field” co-development model. This development model focuses on optimization of the value of a reservoir system through concurrent, co-development of multiple target zones within the system utilizing larger scale projects. As a result, the Company believes the model contributes to more consistent capital efficiency of its well inventory over time and its broader Permian development program is now being targeted for larger project sizes, accompanied by longer associated cycle times, based on its testing and delineation efforts during 2022; 
+◦ 13.1 MMBoe reduction primarily due to higher operating costs; offset by 
+◦ 13.7 MMBoe increase primarily due to the change in 12-Month Average Realized Price of crude oil which increased by approximately 45 % as compared to December 31, 2021; 
+◦ 12.2 MMBoe increase primarily due to better results than previously forecasted on certain wells turned to production during 2022 in both the Permian and Eagle Ford. 
+• Decrease of 3.4 MMBoe for sales of reserves in place primarily associated with the divestitures of non-core assets primarily in the Western Delaware Basin; and 
+• Decrease of 38.1 MMBoe for production. 
+For the year ended December 31, 2021, the Company’s net increase in proved reserves of 8.7 MMBoe was primarily due to the following: 
+• Increase of 36.2 MMBoe through extensions and discoveries through the Company’s development efforts in its operating areas, of which 10.1 MMBoe were proved developed reserves; 
+• Decrease of 14.2 MMBoe for revisions of previous estimates that were primarily comprised of: 
+◦ 27.9 MMBoe increase primarily due to the change in 12-Month Average Realized Price of crude oil which increased by approximately 75 % as compared to December 31, 2020; offset by 
+◦ 29.0 MMBoe reduction due to PUDs that were removed primarily as a result of changes in anticipated well densities as the Company develops its properties in an effort to increase capital efficiency and cash flow generation as well as changes in its development plans, primarily due to the Primexx Acquisition, which resulted in PUDs being moved outside of the five-year development window; 
+◦ 13.1 MMBoe reduction due to reductions in anticipated hydrocarbon recoveries resulting from observed well performance over longer production timeframes during the testing of various full field development plan concepts. 
+• Increase of 57.7 MMBoe for purchase of reserves in place associated with the Primexx Acquisition; 
+• Decrease of 36.0 MMBoe for sales of reserves in place associated with the Western Delaware Basin, Eagle Ford, and Midland non-core asset sales; and 
+• Decrease of 34.9 MMBoe for production. 
+For the year ended December 31, 2020, the Company’s net decrease in proved reserves of 64.1 MMBoe was primarily due to the following: 
+• Increase of 41.4 MMBoe through extensions and discoveries through the Company’s development efforts in its operating areas, of which 11.7 MMBoe were proved developed reserves; 
+• Decrease of 52.2 MMBoe for revisions of previous estimates that were primarily comprised of: 
+◦ 26.2 MMBoe reduction due to the change in 12-Month Average Realized Price of crude oil which decreased by approximately 31 % as compared to December 31, 2019. Included in the decrease are 2.1 MMBoe associated with 
+91 
+proved developed producing wells and 0.8 MMBoe associated with proved undeveloped wells that were no longer economic at December 31, 2020 as a result of the decrease in the 12-Month Average Realized Price of crude oil; 
+◦ 24.2 MMBoe reduction due to anticipated hydrocarbon recoveries resulting from observed well performance over longer production timeframes during the testing of various full field development plan concepts; 
+◦ 24.0 MMBoe reduction due to PUDs that were removed primarily as a result of changes in anticipated well densities as the Company develops its properties in an effort to increase capital efficiency and cash flow generation; 
+◦ 14.7 MMBoe increase due to the volumetric impact from presenting NGLs and natural gas separately due to the modification of certain of the Company’s natural gas processing agreements which allow it to take title to NGLs resulting from the processing of its natural gas subsequent to January 1, 2020. For periods prior to January 1, 2020, except for reserve volumes specifically associated with Carrizo, the Company presented its reserve volumes for NGLs with natural gas; 
+◦ 7.5 MMBoe increase due to reduced assumptions for operational expenses as the Company continues to improve its field practices during the integration of the properties acquired from Carrizo; 
+• Decrease of 16.1 MMBoe for sales of reserves in place primarily associated with the ORRI Transaction and the sale of substantially all of the Company’s non-operated assets; and 
+• Decrease of 37.2 MMBoe for production. 
+Capitalized Costs 
+Capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows: 
+As of December 31, 
+2022 2021 
+Oil and natural gas properties: (In thousands) 
+Evaluated properties $ 10,367,478 $ 9,238,823 
+Unevaluated properties 1,711,306 1,812,827 
+Total oil and natural gas properties 12,078,784 11,051,650 
+Accumulated depreciation, depletion, amortization and impairments ( 6,343,875 ) ( 5,886,002 ) 
+Total oil and natural gas properties, net $ 5,734,909 $ 5,165,648 
+Costs Incurred 
+Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows: 
+Years Ended December 31, 
+2022 2021 2020 
+Acquisition costs: (In thousands) 
+Evaluated properties $ — $ 677,250 $ — 
+Unevaluated properties 32,548 301,404 30,696 
+Development costs 742,991 396,181 379,900 
+Exploration costs 133,080 137,989 122,865 
+Total costs incurred $ 908,619 $ 1,512,824 $ 533,461 
+Standardized Measure 
+The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2022. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Proved reserve estimates and future cash flows are based on the average realized prices for sales of oil, natural gas, and NGLs on the first calendar day of each 
+92 
+month during the year. The following average realized prices were used in the calculation of proved reserves and the standardized measure of discounted future net cash flows. 
+Years Ended December 31, 
+2022 2021 2020 
+Oil ($/Bbl) $ 95.02 $ 65.44 $ 37.44 
+Natural gas ($/Mcf) $ 5.75 $ 3.31 $ 1.02 
+NGLs ($/Bbl) $ 36.40 $ 29.19 $ 11.10 
+Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10 % annual discount rate. 
+Standardized Measure 
+For the Year Ended December 31, 
+2022 2021 2020 
+(In thousands) 
+Future cash inflows $ 33,424,190 $ 23,775,358 $ 12,458,033 
+Future costs 
+Production ( 10,702,897 ) ( 8,038,362 ) ( 5,433,496 ) 
+Development and net abandonment ( 2,326,789 ) ( 1,927,789 ) ( 2,204,301 ) 
+Future net inflows before income taxes 20,394,504 13,809,207 4,820,236 
+Future income taxes ( 3,000,300 ) ( 1,481,005 ) ( 65,405 ) 
+Future net cash flows 17,394,204 12,328,202 4,754,831 
+10% discount factor ( 8,390,068 ) ( 6,077,447 ) ( 2,444,441 ) 
+Standardized measure of discounted future net cash flows $ 9,004,136 $ 6,250,755 $ 2,310,390 
+Changes in Standardized Measure 
+For the Year Ended December 31, 
+2022 2021 2020 
+(In thousands) 
+Standardized measure at the beginning of the period $ 6,250,755 $ 2,310,390 $ 4,951,026 
+Sales and transfers, net of production costs ( 2,208,492 ) ( 1,466,413 ) ( 649,781 ) 
+Net change in sales and transfer prices, net of production costs 4,168,425 4,336,078 ( 2,719,579 ) 
+Net change due to purchases of in place reserves — 797,327 — 
+Net change due to sales of in place reserves ( 36,389 ) ( 105,376 ) ( 202,928 ) 
+Extensions, discoveries, and improved recovery, net of future production and development costs incurred 1,338,286 583,976 250,759 
+Changes in future development cost ( 257,344 ) ( 81,480 ) 361,008 
+Previously estimated development costs incurred 289,207 209,078 318,470 
+Revisions of quantity estimates ( 215,828 ) ( 104,572 ) ( 671,800 ) 
+Accretion of discount 705,127 234,495 536,958 
+Net change in income taxes ( 730,185 ) ( 765,956 ) 383,999 
+Changes in production rates, timing and other ( 299,426 ) 303,208 ( 247,742 ) 
+Aggregate change 2,753,381 3,940,365 ( 2,640,636 ) 
+Standardized measure at the end of period $ 9,004,136 $ 6,250,755 $ 2,310,390 
+ITEM 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure 
+None. 
+ITEM 9A. Controls and Procedures 
+Disclosure Controls and Procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) performed an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2022. 
+93 
+Changes in Internal Control Over Financial Reporting . There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting. 
+Management’s Report on Internal Control Over Financial Reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. GAAP. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2022 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission (2013 framework) (the COSO criteria). Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2022. 
+Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+The Company’s independent registered public accounting firm, Grant Thornton LLP, has issued an attestation report regarding its assessment of the Company’s internal control over financial reporting as of December 31, 2022, presented preceding the Company’s financial statements included in Part II, Item 8 of this 2022 Annual Report on Form 10-K. 
+ITEM 9B. Other Information 
+None. 
+ITEM 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections 
+Not applicable. 
+PART III. 
+ITEM 10. Directors, Executive Officers and Corporate Governance 
+The information required by this item is incorporated herein by reference to the definitive proxy statement (the “2023 Proxy Statement”) for our 2023 annual meeting of shareholders. The 2023 Proxy Statement will be filed with the SEC not later than 120 days subsequent to December 31, 2022. 
+The Company has adopted a code of ethics that applies to the Company’s officers, directors, employees, agents and representatives and includes a code of ethics for senior financial officers that applies to the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer. The full text of such code of ethics has been posted on the Company’s website at www.callon.com. 
+ITEM 11. Executive Compensation 
+The information required by this item is incorporated herein by reference to the 2023 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2022. 
+ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+The information required by this item is incorporated herein by reference to the 2023 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2022. 
+ITEM 13. Certain Relationships and Related Transactions and Director Independence 
+The information required by this item is incorporated herein by reference to the 2023 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2022. 
+ITEM 14. Principal Accountant Fees and Services 
+The information required by this item is incorporated herein by reference to the 2023 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2022. 
+94 
+PART IV. 
+ITEM 15. Exhibits and Financial Statement Schedules 
+(a) Documents filed as part of this 2022 Annual Report on Form 10-K: 
+(1) Financial Statements 
+See index to Financial Statements and Supplementary Data on page 57 . 
+(2) Financial Statement Schedules 
+All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto. 
+(3) Exhibits 
+Incorporated by reference (File No. 001-14039, unless otherwise indicated) 
+Exhibit Number Description Form Exhibit Filing 
+Date 
+2.1 (d) 
+Agreement and Plan of Merger, dated as of July 14, 2019, by and between Callon Petroleum Company and Carrizo Oil & Gas, Inc. 
+8-K 2.1 07/15/2019 
+2.2 
+Amendment No. 1 to Agreement and Plan of Merger, dated August 19, 2019, by and between Callon Petroleum Company and Carrizo Oil & Gas, Inc. 
+10-Q 2.2 11/05/2019 
+2.3 
+Amendment No. 2 to Agreement and Plan of Merger, dated November 13, 2019, by and between Callon Petroleum Company and Carrizo Oil & Gas, Inc. 
+8-K 2.1 11/14/2019 
+3.1 
+Certificate of Incorporation of the Company, as amended through May 12, 2016 
+10-Q 3.1 11/03/2016 
+3.2 
+Certificate of Amendment to the Certificate of Incorporation of Callon, effective December 20, 2019 
+8-K 3.1 12/20/2019 
+3.3 
+Certificate of Amendment to the Certificate of Incorporation of Callon, effective August 7, 2020 
+8-K 3.1 08/07/2020 
+3.4 
+Certificate of Amendment to the Certificate of Incorporation of Callon, effective May 14, 2021 
+8-K 3.1 05/14/2021 
+3.5 
+Certificate of Amendment to the Certificate of Incorporation of Callon, effective May 25 , 202 2 
+8-K 3.1 05/25/2022 
+3.6 
+Amended and Restated Bylaws of the Company 
+10-K 3.2 02/27/2019 
+4.1 
+Specimen Common Stock Certificate 
+10-K 4.1 02/28/2018 
+4.2 
+Description of Common Stock 
+10-K 4.2 02/25/2021 
+4.3 
+Indenture of 6.375% Senior Notes Due 2026, dated as of June 7, 2018, among Callon Petroleum Company, the Guarantors party thereto and U.S. Bank National Association, as Trustee 
+8-K 4.1 06/07/2018 
+4.4 
+First Supplemental Indenture, dated December 20, 2019, among Callon, the Guarantors named therein and U.S. Bank National Association, as trustee 
+8-K 4.4 12/20/2019 
+4.5 
+Registration Rights Agreement of 6.375% Senior Notes Due 2026, dated June 7, 2018, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P. Morgan Securities LLC, as representative of the Initial Purchasers named on Annex E thereto 
+8-K 4.2 06/07/2018 
+4.6 
+Indenture, dated May 28, 2008, among Carrizo Oil & Gas, Inc., the subsidiaries named therein and Wells Fargo Bank, National Association, as trustee 
+8-K (File No. 000-29187-87) 4.1 05/28/2008 
+4.7 
+Twentieth Supplemental Indenture, dated July 14, 2017, among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee 
+8-K (File No. 000-29187-87) 4.2 07/14/2017 
+4.8 
+Twenty-First Supplemental Indenture, dated December 20, 2019, among Callon, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee 
+8-K 4.1 12/20/2019 
+4.9 
+Twenty-Second Supplemental Indenture, dated December 20, 2019, among Callon, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee 
+8-K 4.2 12/20/2019 
+4.10 
+Warrant Agreement, dated as of December 20, 2019, between Callon and American Stock Transfer And Trust Company, LLC, as warrant agent 
+8-K 4.5 12/20/2019 
+4.11 
+Indenture, dated as of July 6, 2021, by and among the Company, Callon Petroleum Operating Company, Callon (Eagle Ford) LLC, Callon (Niobrara) LLC, Callon (Permian) LLC, Callon (Permian) Minerals LLC, Callon (Utica) LLC, Callon Marcellus Holding, Inc. and U.S. Bank National Association, as trustee 
+8-K 4.1 07/07/2021 
+4.12 
+Registration Rights Agreement among Callon Petroleum Company, Callon Petroleum Operating Company and Primexx Resource Development, LLC, dated October 1, 2021 
+10-K 4.17 02/24/2022 
+4.13 
+Registration Rights Agreement among Callon Petroleum Company, Callon Petroleum Operating Company and BPP Acquisition, LLC, dated October 1, 2021 
+10-K 4.18 02/24/2022 
+4.14 
+Registration Rights Agreement, by and between the Company and Chambers Investment, LLC, dated November 5, 2021 
+8-K 4.1 11/08/2021 
+95 
+4.15 
+Indenture, dated as of June 24, 2022, by and among Callon Petrol eu m Company, Callon Petroleum Operating Company, Callon (Permian) LLC, Callon (Eagle Ford) LLC, Callon (Permian) Minerals LLC, Callon (Niobrara) LLC, Callon (Utica) LLC and Callon Marcellus Holding, Inc. and U.S. Bank Trust Company, National Association, as trustee 
+8-K 4.1 06/24/2022 
+10.1 (d) 
+Amended & Restated Credit Agreement, dated as of October 19, 2022, by and among the Company, JPMorgan Chase Bank, N.A., as administrative agent for the lenders party thereto, and the other lenders party thereto 
+8-K 10.1 10/24/2022 
+10.2 (b) 
+Amended and Restated Deferred Compensation Plan for Outside Directors - Callon Petroleum Company, dated as of May 10, 2017 and effective as of May 1, 2017 
+10-K 10.11 02/28/2018 
+10.3 (b) 
+Amended and Restated 2018 Omnibus Incentive Plan 
+10-K 10.7 02/27/2020 
+10.4 (b) 
+Form of Callon Petroleum Company Officer Restricted Stock Unit Award Agreement, adopted on January 31, 2019 under the 2018 Omnibus Incentive Plan 
+10-K 10.23 02/27/2019 
+10.5 (b) 
+Form of Callon Petroleum Company Officer Cash-Settleable Performance Share Award Agreement, adopted on January 31, 2020 under the Amended & Restated 2018 Omnibus Incentive Plan 
+10-K 10.23 02/27/2020 
+10.6 (b) 
+Form of Callon Petroleum Company Officer Stock-Settleable Performance Share Award Agreement, adopted on January 31, 2020 under the Amended & Restated 2018 Omnibus Incentive Plan 
+10-K 10.24 02/27/2020 
+10.7 (b) 
+Form of Callon Petroleum Company Officer Restricted Stock Unit Award Agreement, adopted on January 31, 2020 under the Amended & Restated 2018 Omnibus Incentive Plan 
+10-K 10.25 02/27/2020 
+10.8 (b) 
+Callon Petroleum Company 2020 Omnibus Incentive Plan 
+DEF 14A B 04/28/2020 
+10.9 (b) 
+First Amendment to Callon Petroleum Company 2020 Omnibus Incentive Plan 
+8-K 10.5 04/16/2021 
+10.10 (b) 
+Form of Callon Petroleum Company Employee Restricted Stock Unit Award Agreement, adopted on June 8, 2020, under the 2020 Omnibus Incentive Plan 
+10-Q 10.3 08/05/2020 
+10.11 (b) 
+Form of Callon Petroleum Company Director Restricted Stock Unit Award Agreement, adopted on June 8, 2020, under the 2020 Omnibus Incentive Plan 
+10-Q 10.4 08/05/2020 
+10.12 (b) 
+Form of Callon Petroleum Company Officer Cash Retention Award Agreement, adopted on September 30, 2020, under the 2020 Omnibus Incentive Plan 
+10-Q 10.4 11/03/2020 
+10.13 (b) 
+Form of Callon Petroleum Company Officer Cash Incentive Award Agreement, adopted on September 30, 2020, under the 2020 Omnibus Incentive Plan 
+10-Q 10.5 11/03/2020 
+10.14 (b) 
+Deferred Compensation Plan for Outside Directors, as Amended and Restated as of January 1, 2021 
+10-K 10.29 02/25/2021 
+10.15 (b) 
+Form of Callon Petroleum Company Restricted Stock Unit Award Agreement, adopted on March 12, 2021 under the 2020 Omnibus Incentive Plan 
+8-K 10.1 04/16/2021 
+10.16 (b) 
+Form of Callon Petroleum Company Cash Performance Unit Award Agreement, adopted on March 12, 2021 under the 2020 Omnibus Incentive Plan 
+8-K 10.2 04/16/2021 
+10.17 (b) 
+Form of Amendment, adopted on September 21, 2022, to Callon Petroleum Company Cash Performance Unit Award Agreement, originally adopted on March 12, 2021 under the 2020 Omnibus Incentive Plan 
+10-Q 10.3 11/03/2022 
+10.18 (b) 
+Form of Callon Petroleum Company Returns Program Cash Incentive Award Agreement, adopted on March 9, 2022 under the 2020 Omnibus Incentive Plan 
+10-Q 10.1 05/05/2022 
+10.19 (b) 
+Form of Amendment, adopted on September 21, 2022, to Callon Petroleum Company Returns Program Cash Incentive Award Agreement, originally adopted on March 9, 2022 under the 2020 Omnibus Incentive Plan 
+10-Q 10.4 11/03/2022 
+10.20 (b) 
+Form of Callon Petroleum Company Business Sustainability Cash Incentive Award Agreement, adopted on March 9, 2022 under the 2020 Omnibus Incentive Plan 
+10-Q 10.2 05/05/2022 
+10.21 (b) 
+Form of Amendment, adopted on September 21, 2022, to Callon Petroleum Company Business Sustainability Cash Incentive Award Agreement, originally adopted on March 9, 2022 under the 2020 Omnibus Incentive Plan 
+10-Q 10.5 11/03/2022 
+10.22 (b) 
+Callon Petroleum Company Executive Severance Pay Plan 
+10-Q 10.1 11/03/2022 
+10.23 (b) 
+Callon Executive Change in Control Severance Compensation Plan 
+10-Q 10.2 11/03/2022 
+21.1 (a) 
+Subsidiaries of the Company 
+22.1 (a) 
+Subsidiary Guarantors 
+23.1 (a) 
+Consent of Grant Thornton LLP 
+23.2 (a) 
+Consent of DeGolyer and MacNaughton, Inc. 
+31.1 (a) 
+Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a) 
+31.2 (a) 
+Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a) 
+32.1 (c) 
+Section 1350 Certifications of Chief Executive and Financial Officers pursuant to Rule 13(a)-14(b) 
+99.1 (a) 
+Reserve Report Summary prepared by DeGolyer and MacNaughton, Inc. as of December 31, 2022 
+101.INS (a) XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. 
+101.SCH (a) Inline XBRL Taxonomy Extension Schema Document 
+101.CAL (a) Inline XBRL Taxonomy Extension Calculation Linkbase Document. 
+96 
+101.DEF (a) Inline XBRL Taxonomy Extension Definition Linkbase Document. 
+101.LAB (a) Inline XBRL Taxonomy Extension Label Linkbase Document. 
+101.PRE (a) Inline XBRL Taxonomy Extension Presentation Linkbase Document. 
+104 (a) Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. 
+(a) Filed herewith. 
+(b) Indicates management compensatory plan, contract, or arrangement. 
+(c) Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, except to the extent that the registrant specifically incorporates it by reference. 
+(d) Certain schedules and similar attachments have been omitted pursuant to Item 601(a)(5) of Regulation S-K. Callon agrees to furnish a supplemental copy of any omitted schedule or attachment to the SEC upon request. 
+ITEM 16. Form 10-K Summary 
+None. 
+97 
+SIGNATURES 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+Callon Petroleum Company 
+/s/ Kevin Haggard Date: February 23, 2023 
+By: Kevin Haggard 
+Chief Financial Officer (principal financial officer) 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+/s/ Joseph C. Gatto, Jr. Date: February 23, 2023 
+Joseph C. Gatto, Jr. (principal executive officer) 
+/s/ Kevin Haggard Date: February 23, 2023 
+Kevin Haggard (principal financial officer) 
+/s/ Gregory F. Conaway Date: February 23, 2023 
+Gregory F. Conaway (principal accounting officer) 
+/s/ L. Richard Flury Date: February 23, 2023 
+L. Richard Flury (chairman of the board of directors) 
+/s/ Frances Aldrich Sevilla-Sacasa Date: February 23, 2023 
+Frances Aldrich Sevilla-Sacasa (director) 
+/s/ Matthew R. Bob Date: February 23, 2023 
+Matthew R. Bob (director) 
+/s/ Barbara J. Faulkenberry Date: February 23, 2023 
+Barbara J. Faulkenberry (director) 
+/s/ Anthony J. Nocchiero Date: February 23, 2023 
+Anthony J. Nocchiero (director) 
+/s/ Mary Shafer-Malicki Date: February 23, 2023 
+Mary Shafer-Malicki (director) 
+/s/ James M. Trimble Date: February 23, 2023 
+James M. Trimble (director) 
+/s/ Steven A. Webster Date: February 23, 2023 
+Steven A. Webster (director) 
+98
\ No newline at end of file
diff --git a/raw/filings/0000928022/2022/0000928022-23-000017/filing_metadata.csv b/raw/filings/0000928022/2022/0000928022-23-000017/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..80657bda03359620855c754e4ebc7ef3b7f32ff6
--- /dev/null
+++ b/raw/filings/0000928022/2022/0000928022-23-000017/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000928022,CPE,Callon Petroleum Co,10-K,2023-02-23,2022-12-31,2023-02-23T21:14:02.000Z,0000928022-23-000017,cpe-20221231.htm,10-K,14974567,1,1,https://www.sec.gov/Archives/edgar/data/928022/000092802223000017/cpe-20221231.htm,https://www.sec.gov/Archives/edgar/data/928022/000092802223000017/,2022,2022,1
diff --git a/raw/filings/0000928022/2022/0000928022-23-000017/item1.txt b/raw/filings/0000928022/2022/0000928022-23-000017/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000928022/2022/0000928022-23-000017/item13.txt b/raw/filings/0000928022/2022/0000928022-23-000017/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..f0b4237bb0be70ee7f4e7aa213d04a0d32db839c
--- /dev/null
+++ b/raw/filings/0000928022/2022/0000928022-23-000017/item13.txt
@@ -0,0 +1,2 @@
+ITEM 13. Certain Relationships and Related Transactions and Director Independence 
+The information required by this item is incorporated herein by reference to the 2023 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2022.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2022/0000928022-23-000017/item9a.txt b/raw/filings/0000928022/2022/0000928022-23-000017/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..3f2ae818c8d28680148cbd926b7fd1e4af588332
--- /dev/null
+++ b/raw/filings/0000928022/2022/0000928022-23-000017/item9a.txt
@@ -0,0 +1,7 @@
+ITEM 9A. Controls and Procedures 
+Disclosure Controls and Procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) performed an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2022. 
+93 
+Changes in Internal Control Over Financial Reporting . There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting. 
+Management’s Report on Internal Control Over Financial Reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. GAAP. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2022 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission (2013 framework) (the COSO criteria). Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2022. 
+Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+The Company’s independent registered public accounting firm, Grant Thornton LLP, has issued an attestation report regarding its assessment of the Company’s internal control over financial reporting as of December 31, 2022, presented preceding the Company’s financial statements included in Part II, Item 8 of this 2022 Annual Report on Form 10-K.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2022/0000928022-23-000017/rp_note.txt b/raw/filings/0000928022/2022/0000928022-23-000017/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000928022/2022/0000928022-23-000017/rpt_disclosure.txt b/raw/filings/0000928022/2022/0000928022-23-000017/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..70a1350b4bb229db8124f489e140ddcd1a618d23
--- /dev/null
+++ b/raw/filings/0000928022/2022/0000928022-23-000017/rpt_disclosure.txt
@@ -0,0 +1,7 @@
+Certain Relationships and Related Party Transactions 
+The Audit Committee charter provides that the Audit Committee shall review and approve all related party transactions. A transaction will be considered a “related party transaction” if the transaction would be required to be disclosed under Item 404 of Regulation S-K. In addition, our Code provides that an officer’s or a director’s conflict of interest with Callon may only be waived if the Audit Committee approves the waiver and the full Board ratifies the waiver. 
+We are not aware of any related party transactions that require disclosure under Item 404 of Regulation S-K. 
+Shareholders’ Proposals and Director Nominations for the 2024 Annual Meeting 
+In order for a proposal to be considered for inclusion in the proxy statement for the 2024 Annual Meeting of Shareholders (the “2024 Annual Meeting”) pursuant to Rule 14a-8 of the Exchange Act, such proposal must be received by the Secretary of the Company at our principal executive office no later than November 13, 2023 (assuming the date of the 2024 Annual Meeting has not been changed by more than 30 days from the date of this year’s Annual Meeting), and must otherwise be in compliance with the requirements of the SEC’s proxy rules. If the date of the 2024 Annual Meeting is changed by more than 30 days from the date of this Annual Meeting, then the deadline is a reasonable time before we begin to print and send our proxy materials for the 2024 Annual Meeting. 
+For a shareholder proposal to be introduced for consideration at the 2024 Annual Meeting but not intended to be considered for inclusion in the Company's proxy statement and form of proxy relating to such meeting (i.e., not pursuant to Rule 14a-8 of the Exchange Act), including shareholder nominations for candidates for election as directors, a shareholder must provide written notice of such proposal to Company not later than 120 days nor earlier than 150 days before the date of the 2024 Annual Meeting. Any such notice must describe the shareholder proposal in reasonable detail and otherwise comply with the requirements set forth in our bylaws. In addition to satisfying the notice, informational and other requirements contained in our 
+bylaws, shareholders who intend to solicit proxies in support of director nominees other than the Company’s nominees must provide notice that sets forth the information required by Rule 14a-19 of the Exchange Act, which notice must be postmarked or
\ No newline at end of file
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+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+FORM 10-K 
+☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the fiscal year ended December 31 , 2023 
+or 
+☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the transition period from ____________ to ____________ 
+Commission File Number 001-14039 
+Callon Petroleum Co mpany 
+(Exact Name of Registrant as Specified in Its Charter) 
+_______________________________________________ 
+Delaware 64-0844345 
+State or Other Jurisdiction of 
+Incorporation or Organization I.R.S. Employer Identification No. 
+One Briarlake Plaza 
+2000 W. Sam Houston Parkway S., Suite 2000 
+Houston, Texas 77042 
+Address of Principal Executive Offices Zip Code 
+281 - 589-5200 
+(Registrant’s Telephone Number, Including Area Code) 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of Each Class Trading Symbol Name of Each Exchange on Which Registered 
+Common Stock, $0.01 par value CPE New York Stock Exchange 
+Securities registered pursuant to section 12(g) of the Act: None 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐ 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒ 
+Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ 
+Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐ 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act: 
+Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ☐ 
+Smaller reporting company ☐ Emerging growth company ☐ 
+If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ 
+Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ 
+If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐ 
+Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐ 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ 
+The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2023 was approximately $ 2.1 billion. 
+The registrant had 66,508,277 shares of common stock outstanding as of February 16, 2024 . 
+DOCUMENTS INCORPORATED BY REFERENCE 
+Portions of the definitive proxy statement of Callon Petroleum Company relating to the 2024 Annual Meeting of Shareholders are incorporated into Part III of this Form 10-K. Such definitive proxy statement or an amendment to this Annual Report on Form 10-K will be filed no later than 120 days after December 31, 2023 
+TABLE OF CONTENTS 
+Special Note Regarding Forward - Looking Statements 
+3 
+Glossary of Certain Terms 
+3 
+Part I 
+Items 1 and 2. 
+Business and Properties 
+6 
+Proved Oil and Gas Reserves 
+9 
+Drilling Activity 
+13 
+Productive Wells 
+13 
+Production Volumes, Average Sales Prices and Operating Costs 
+14 
+Major Customers 
+15 
+Leasehold Acreage 
+15 
+Human Capital 
+15 
+Other 
+16 
+Regulations 
+17 
+Commitments and Contingencies 
+26 
+Available Information 
+26 
+Item 1A. 
+Risk Factors 
+27 
+Item 1B. 
+Unresolved Staff Comments 
+47 
+Item 1 C . 
+C ybersecurity 
+48 
+Item 3. 
+Legal Proceedings 
+49 
+Item 4. 
+Mine Safety Disclosures 
+49 
+Part II 
+Item 5. 
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+50 
+Item 6. 
+Reserved 
+51 
+Item 7. 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+51 
+General 
+51 
+Financial and Operational Highlights 
+51 
+Results of Operations 
+52 
+Liquidity and Capital Resources 
+56 
+Critical Accounting Estimates 
+57 
+Item 7A. 
+Quantitative and Qualitative Disclosures About Market Risk 
+59 
+Item 8. 
+Financial Statements and Supplementary Data 
+61 
+Reports of Independent Registered Public Accounting Firm 
+62 
+Consolidated Balance Sheets 
+66 
+Consolidated Statements of Operations 
+67 
+Consolidated Statements of Stockholders’ Equity 
+68 
+Consolidated Statements of Cash Flows 
+69 
+Notes to Consolidated Financial Statements 
+70 
+Supplemental Information on Oil and Natural Gas Operations (Unaudited) 
+100 
+Item 9. 
+Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+105 
+Item 9A. 
+Controls and Procedures 
+105 
+Item 9B. 
+Other Information 
+106 
+Item 9 C . 
+Disclosure Regarding Foreign Jurisdictions that Prevent Inspections 
+106 
+Part III 
+Item 10. 
+Directors, Executive Officers and Corporate Governance 
+106 
+Item 11. 
+Executive Compensation 
+106 
+Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+106 
+Item 13. 
+Certain Relationships and Related Transactions and Director Independence 
+106 
+Item 14. 
+Principal Accountant Fees and Services 
+106 
+Part IV. 
+Item 15. 
+Exhibits and Financial Statement Schedules 
+107 
+Item 16. 
+Form 10-K Summary 
+109 
+Signatures 
+110 
+2 
+SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS 
+This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements in this Form 10-K by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions. 
+All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future are forward-looking statements, including statements about: 
+• our oil and natural gas reserve quantities and the discounted present value of these reserves; 
+• the amount and nature of our capital expenditures; 
+• our future drilling and development plans and our potential drilling locations; 
+• the timing and amount of future capital and operating costs; 
+• production decline rates from our wells being greater than expected; 
+• commodity price risk management activities and the impact on our average realized prices; 
+• business strategies and plans of management; 
+• our ability to efficiently integrate recent acquisitions; 
+• prospect development and property acquisitions; and 
+• the pending merger with APA Corporation. 
+We caution you that the forward-looking statements contained in this Annual Report on Form 10-K (this “2023 Annual Report on Form 10-K”) are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. We disclose these and other important factors that could cause our actual results to differ materially from our expectations under “Risk Factors” in Part I, Item 1A of this 2023 Annual Report on Form 10-K. 
+Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Additional risks or uncertainties that are not currently known to us, that we currently deem to be immaterial, or that could apply to any company could also materially adversely affect our business, financial condition, or future results. Any forward-looking statement speaks only as of the date of which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. 
+In addition, we caution that reserve engineering is a process of estimating oil and natural gas accumulated underground and cannot be measured exactly. Accuracy of reserve estimates depend on a number of factors including data available at the point in time, engineering interpretation of the data, and assumptions used by the reserve engineers as it relates to price and cost estimates and recoverability. New results of drilling, testing, and production history may result in revisions of previous estimates and, if significant, would impact future development plans. As such, reserve estimates may differ from actual results of oil and natural gas quantities ultimately recovered. 
+Except as required by applicable law, all forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. 
+GLOSSARY OF CERTAIN TERMS 
+All defined terms under Rule 4-10(a) of Regulation S-X shall have their prescribed meanings when used in this report. As used in this document: 
+• 12-Month Average Realized Price : Average realized prices for sales of oil, NGLs, and natural gas on the first calendar day of each month during a trailing 12-month period. 
+• ASU : Accounting standards update. 
+• Bbl or Bbls : Barrel or barrels of oil or NGLs. 
+• Boe : Barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of natural gas. The ratio of one barrel of oil or NGLs to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas and does not represent the economic equivalency of oil and NGLs to natural gas. 
+• Boe/d : Boe per day. 
+• Btu : British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit. 
+• Completion : The installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency. 
+3 
+• Development well : A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. 
+• EPA : United States Environmental Protection Agency. 
+• ESG: Environmental, social and governance. 
+• Exploratory well : A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. 
+• Extension well : A well drilled to extend the limits of a known reservoir. 
+• FASB : Financial Accounting Standards Board. 
+• GAAP : Accounting principles generally accepted in the United States. 
+• GHG : Greenhouse gases. 
+• Henry Hub : Natural gas pipeline delivery point that serves as the benchmark natural gas price underlying NYMEX natural gas futures contracts. 
+• Horizontal drilling : A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at an angle within a specified interval. 
+• HSC: Houston Ship Channel, a delivery point in Houston, Texas that serves as a benchmark price for natural gas. 
+• LIBOR : London Interbank Offered Rate. 
+• LOE : Lease operating expense. 
+• MBbls : Thousand barrels of oil. 
+• MBoe : Thousand Boe. 
+• Mcf : Thousand cubic feet of natural gas. 
+• MMBoe : Million Boe. 
+• MMBtu : Million Btu. 
+• MMcf : Million cubic feet of natural gas. 
+• NGL or NGLs : Natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams. 
+• Non-productive well : A well that is found to be incapable of producing oil or gas in sufficient quantities to justify completion, or upon completion, the economic operation of an oil or gas well. 
+• NYMEX : New York Mercantile Exchange. 
+• Oil : Includes crude oil and condensate. 
+• OPEC : Organization of Petroleum Exporting Countries. 
+• Productive well : A well that is found to be capable of producing oil or gas in sufficient quantities to justify completion as an oil or gas well. 
+• Proved developed producing reserves (“PDPs”): Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. 
+• Proved reserves: Those reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12‑month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. 
+• Proved undeveloped reserves (“PUDs”): Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. 
+• PV-10 (Non-GAAP): Present value of estimated future gross revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date indicated (unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure of discounted future net cash flows calculation, it does provide an indicative representation of the relative value of the Company on a comparative basis to other 
+4 
+companies from period to period. See “Items 1 and 2. Business and Properties — Proved Oil and Gas Reserves — Reconciliation of Standardized Measure of Discounted Future Net Cash Flows (GAAP) to PV-10 (Non-GAAP)”. 
+• Realized price : The cash market price less all expected quality, transportation and demand adjustments. 
+• Royalty interest : An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development. 
+• SEC : United States Securities and Exchange Commission. 
+• SOFR: Secured Overnight Financing Rate 
+• Waha : A natural gas delivery point in West Texas that serves as the benchmark for natural gas. 
+• Working interest : An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations. 
+• WTI : West Texas Intermediate grade crude oil, used as a pricing benchmark for sales contracts and NYMEX oil futures contracts. 
+With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross. 
+5 
+PART I. 
+ITEMS 1 and 2. Business and Properties 
+Overview 
+Callon Petroleum Company has been engaged in the exploration, development, acquisition and production of oil and natural gas properties since 1950. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. 
+We are an independent oil and natural gas company focused on the acquisition, exploration and sustainable development of high-quality assets in the Permian Basin in West Texas. Our activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger Permian Basin in West Texas. Our primary operations in the Permian reflect a high-return, oil-weighted drilling inventory with multiple prospective horizontal development intervals. 
+In the first quarter of 2023, we voluntarily changed our method of accounting for oil and gas exploration and development activities from the full cost method to the successful efforts method of accounting. Accordingly, the financial information for prior periods has been recast to reflect retrospective application of the successful efforts method of accounting, as prescribed by the FASB ASC 932 “Extractive Activities — Oil and Gas.” See “Note 2 — Summary of Significant Accounting Policies” and “Note 3 — Change in Accounting Principle” of the Notes to our Consolidated Financial Statements for additional discussion. 
+Merger Agreement 
+On January 3, 2024, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) with APA Corporation (“APA”) and Astro Comet Merger Sub Corp., a wholly owned subsidiary of APA (“Merger Sub”). The Merger Agreement provides that, among other things and subject to the terms and conditions of the Merger Agreement, (i) Merger Sub will be merged with and into Callon (the “Merger”), with Callon surviving and continuing as the surviving corporation in the Merger, and (ii) at the effective time of the Merger (the “Effective Time”), each outstanding share of common stock of Callon (other than Excluded Shares (as defined in the Merger Agreement)) will be converted into the right to receive, without interest, 1.0425 shares of common stock of APA (the “Exchange Ratio”), with cash in lieu of fractional shares. 
+Our board of directors (the “Board of Directors”) has unanimously (i) determined that the Merger Agreement and the transactions contemplated thereby are in the best interests of, and advisable to, Callon and Callon shareholders, (ii) approved and declared advisable the Merger Agreement and the transactions contemplated thereby, (iii) resolved to recommend that Callon stockholders approve the Merger Agreement and the transactions contemplated thereby, and (iv) approved the execution, delivery and performance by Callon of the Merger Agreement and the consummation of the transactions contemplated thereby. 
+The completion of the Merger is subject to satisfaction or waiver of certain customary mutual closing conditions, including (i) the receipt of the required approvals from Callon shareholders and APA shareholders, (ii) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the “HSR Act”), (iii) the absence of any governmental order or law prohibiting consummation of the Merger, (iv) the effectiveness of the registration statement on Form S-4 to be filed by APA, pursuant to which the shares of APA common stock to be issued in connection with the Merger will be registered with the SEC, and (v) the APA common stock to be issued pursuant to the Merger Agreement being authorized for listing on the Nasdaq Stock Market. The obligation of each party to consummate the Merger is also conditioned upon the other party’s representations and warranties being true and correct (subject to certain materiality exceptions), the other party having performed in all material respects its obligations under the Merger Agreement and the non-occurrence of any material adverse effect with respect to the other party since the date of the Merger Agreement. 
+The Merger Agreement contains certain termination rights for each of APA and Callon, and in certain circumstances, a termination fee would be payable by the terminating party. 
+If the Merger is consummated, our common stock will be delisted from the New York Stock Exchange (the “NYSE”) and deregistered under the Exchange Act, and Callon will cease to be a publicly traded company. 
+For additional information related to the Merger, refer to the filings made with the SEC in connection with such transaction. We have prepared this 2023 Annual Report on Form 10-K as if we are going to remain an independent company. If the Merger is consummated, many of the forward-looking statements contained in this 2023 Annual Report on Form 10-K will no longer be applicable. 
+Major Developments in 2023 
+Financing and Liquidity Highlights 
+• Decreased our total outstanding long-term debt principal balance by approximately 14% to $1.9 billion as of December 31, 2023, from $2.3 billion as of December 31, 2022. 
+6 
+• On August 2, 2023, we used borrowings under the Credit Facility to redeem all $187.2 million of our outstanding 8.25% Senior Notes due 2025 (“8.25% Senior Notes”). We recognized a gain on extinguishment of debt of approximately $1.2 million in our consolidated statements of operations, which primarily related to the remaining unamortized premium. 
+• On October 31, 2023, the borrowing base of $2.0 billion and elected commitment amount of $1.5 billion were reaffirmed as part of the Company’s fall 2023 redetermination . 
+• Reduced the borrowings outstanding under our Credit Facility from $503.0 million as of December 31, 2022 to $365.0 million as of December 31, 2023. 
+See “Note 8 – Borrowings” of the Notes to our Consolidated Financial Statements for further discussion. 
+Eagle Ford Divestiture. On July 3, 2023, we closed on the sale of all our oil and gas properties in the Eagle Ford to Ridgemar Energy Operating, LLC (the “Eagle Ford Divestiture) for total consideration of approximately $549.6 million , and up to $45.0 million of incremental contingent consideration. 
+Percussion Acquisition. Concurrent with the closing of the Eagle Ford Divestiture, we completed the acquisition of certain producing oil and gas properties, undeveloped acreage and associated infrastructure assets in the Delaware Basin from Percussion Petroleum Management II, LLC (the “Percussion Acquisition”) for total consideration of $457.3 million , and up to $62.5 million of incremental contingent consideration. 
+See “Note 5 – Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for further discussion of both the Percussion Acquisition and Eagle Ford Divestiture. 
+Share Repurchase Program. During 2023, we initiated a share repurchase program (the “Share Repurchase Program”) whereby we repurchased and retired approximately 1.7 million shares of common stock in the third and fourth quarters at a weighted average purchase price of $33.59 per common share for a total cost of $55.5 million. See “Note 12 — Stockholders’ Equity” of the Notes to our Consolidated Financial Statements for additional details. Pursuant to the Merger Agreement, we are restricted from making further repurchases under such program without APA’s approval. 
+Operational Activity. The following tables present our net daily production, as well as our operated drilling and completion activity for the year ended December 31, 2023 along with our drilled but uncompleted and producing wells as of December 31, 2023. 
+Permian Eagle Ford Total 
+Production volumes 
+Crude oil (Bbls/d) 53,858 6,117 59,975 
+Natural gas (Mcf/d) 119,007 7,320 126,327 
+NGLs (Bbls/d) 20,695 1,252 21,947 
+Total production volumes (Boe/d) 94,388 8,589 102,977 
+Percent of total production 92 % 8 % 100 % 
+Permian Eagle Ford Total 
+Operated Well Data Gross Net Gross Net Gross Net 
+Drilled 97 86.8 9 6.0 106 92.8 
+Turned In-Line 
+105 94.0 3 2.4 108 96.4 
+As of December 31, 2023 
+Drilled But Uncompleted 
+32 29.6 — — 32 29.6 
+Producing 917 815.1 — — 917 815.1 
+Our Business Strategy 
+Our strategy is to create value for our shareholders through the safe and capital-efficient development of our oil and gas properties, which we call our “Life of Field” co-development model. Our people work to safely reduce our operating costs, maximize our cash flows and empower the communities in which our people live and work. The key elements of our strategy include: 
+• We employ a “Life of Field” co-development model that enhances the value of our asset base and helps ensure capital efficiency, free cash flow generation, and ultimately long-term value creation. Utilizing our extensive database of subsurface information, we have demonstrated an ability to enhance returns today, while mitigating risks associated with future infill developments; 
+7 
+• We strive to create new capital efficiencies across the enterprise. Human, technology, and capital resources are carefully applied to our highest long-term return opportunities and our teams are incentivized to create value by safely lowering costs, improving well productivity and improving our returns on capital; 
+• We integrate sustainable business practices that aim to minimize our impact on the environment, empower and develop a diverse workforce, and enrich our communities; and 
+• We enhance our financial position, focus on appropriate capital allocation decisions under various commodity pricing scenarios, effectively manage risks to ensure cash flows to fund our development programs and maintain and improve our balance sheet. 
+Our Strengths 
+The following attributes position us to achieve our objectives: 
+• Oily Asset Portfolio – We have a deep inventory of high-quality drilling locations in the Permian with a high percentage of oil and liquids hydrocarbons. We operate solely in Texas, which has a regulatory environment that encourages the timely development of the state’s natural resources. In addition, our developments are located in proximity to infrastructure as well as long haul take-away pipeline capacity which allows us to achieve advantaged pricing; 
+• Proven Operator with a History of Maximizing Value – We are stewards of the resource and believe our “Life of Field” co-development model has been a differentiator in the industry. We believe it optimizes the long-term value of our inventory, mitigates future degradation risks associated with infill drilling and generates capital efficiencies. We consistently deploy our capital to large-scale projects and carefully select the dedicated service providers required to execute our programs effectively. In addition, we have proven our ability to identify, acquire, and integrate acquisitions in our areas of focus while creating incremental value through realizing synergies; 
+• Returns-Driven Strategy to Generate Free Cash Flow – We have a demonstrated track record of capital discipline, investing less than our annual cash flow with capital spending governed by defined economic thresholds focused on capital efficiencies to enhance long-term returns. We proactively hedge a portion of our production to manage the variability in cash flows and have also secured capacity on oil and natural gas pipelines to improve our ability to market our production; and 
+• ESG Focus – We have proven our ability to create value responsibly. We believe our compensation programs incentivize the right behaviors to help ensure a safe workplace while mitigating the impact of our operations on the environment. 
+◦ Environment. We are committed to environmental stewardship and have established goals to achieve meaningful reductions for certain carbon and methane emissions. 
+◦ Social. We foster an entrepreneurial workplace where individuals are encouraged and empowered to share their ideas and perspectives and to develop and implement plans to bring those ideas to fruition. We embrace a culture of diversity and inclusion, where individuals feel respected, heard, and empowered. 
+◦ Governance. We are committed to effective and sustainable corporate governance, which we believe promotes the long-term interests of stakeholders. We have a board with a high level of diversity, including in skills and perspectives, that allows them to perform their strategic and oversight roles satisfactorily for our stakeholders. In addition, our compensation programs incorporate metrics that align with our ESG goals. 
+8 
+Proved Oil and Gas Reserves 
+The following table sets forth summary information with respect to our estimated proved reserves, standardized measure of discounted future net cash flows and PV-10 for the years ended December 31, 2023, 2022, and 2021. The estimated proved reserves in the table below were prepared by DeGolyer and MacNaughton (“D&M”), Callon’s independent third-party reserve engineers. For further information concerning D&M’s estimates of our proved reserves as of December 31, 2023, see the reserve report included as an exhibit to this 2023 Annual Report on Form 10-K. In accordance with SEC rules, we used the 12-Month Average Realized Price of oil, NGLs, and natural gas in the calculation of our estimated proved reserves and PV-10. 
+As of December 31, 
+2023 2022 2021 
+Proved developed reserves 
+Crude oil (MBbls) 149,898 170,866 162,886 
+Natural gas (MMcf) 376,070 351,278 332,266 
+NGLs (MBbls) 65,891 63,788 55,720 
+Total proved developed reserves (MBoe) 278,467 293,200 273,983 
+Proved undeveloped reserves 
+Crude oil (MBbls) 89,362 104,743 127,410 
+Natural gas (MMcf) 185,423 241,565 245,061 
+NGLs (MBbls) 34,777 41,321 42,384 
+Total proved undeveloped reserves (MBoe) 155,043 186,325 210,638 
+Total proved reserves 
+Crude oil (MBbls) 239,260 275,609 290,296 
+Natural gas (MMcf) 561,493 592,843 577,327 
+NGLs (MBbls) 100,668 105,109 98,104 
+Total proved reserves (MBoe) 433,510 479,525 484,621 
+Proved developed reserves % 64 % 61 % 57 % 
+Proved undeveloped reserves % 36 % 39 % 43 % 
+12-Month Average Realized Prices 
+Crude oil ($/Bbl) $78.17 $95.02 $65.44 
+Natural gas ($/Mcf) $1.53 $5.75 $3.31 
+NGLs ($/Bbl) $22.27 $36.40 $29.19 
+Standardized measure of discounted future net cash flows (GAAP) (in millions) $5,434.2 $9,004.1 $6,250.8 
+PV-10 (Non-GAAP) (in millions): 
+Proved developed PV-10 $4,294.9 $7,122.9 $4,502.6 
+Proved undeveloped PV-10 1,594.7 3,411.9 2,548.7 
+Total PV-10 (Non-GAAP) $5,889.6 $10,534.8 $7,051.3 
+Reconciliation of Standardized Measure of Discounted Future Net Cash Flows (GAAP) to PV-10 (Non-GAAP) 
+We believe that the presentation of PV-10 provides greater comparability when evaluating oil and gas companies due to the many factors unique to each individual company that impact the amount and timing of future income taxes. In addition, we believe that PV-10 is widely used by investors and analysts as a basis for comparing the relative size and value of our proved reserves to other oil and gas companies. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company’s financial or operating performance presented in accordance with GAAP. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of our proved oil and gas reserves. 
+As of December 31, 
+2023 2022 2021 
+(In millions) 
+Standardized measure of discounted future net cash flows (GAAP) $5,434.2 $9,004.1 $6,250.8 
+Add: present value of future income taxes discounted at 10% per annum 455.4 1,530.7 800.5 
+PV-10 (Non-GAAP) $5,889.6 $10,534.8 $7,051.3 
+9 
+Proved Reserves 
+Our reserve estimates are conducted from fundamental petrophysical, geological, engineering, financial and accounting data. Reserves are estimated based on production decline analysis, analogy to producing offsets, detailed reservoir modeling, volumetric calculations or a combination of these methods, in all cases having regard to economic considerations and using technologies that have been demonstrated in the field to yield repeatable and consistent results as defined in the SEC regulations. To establish reasonable certainty of our proved reserves estimates, including material additions to our proved reserves, we use certain technologies and economic data, including production and well test data, historical well costs and operating data, geologic and seismic data, and subsurface information obtained through wellbores such as electrical logs, radioactive logs, reservoir core samples, fluid samples, and static and dynamic pressure information. Non-producing reserves are estimated by analogy to producing offsets, with consideration given to a development plan approved by Callon’s management. 
+The following table presents our estimated proved reserves of December 31, 2023. 
+Total 
+Proved reserves 
+Crude oil (MBbls) 239,260 
+Natural gas (MMcf) 561,493 
+NGLs (MBbls) 100,668 
+Total proved reserves (MBoe) 433,510 
+The following table provides a summary of the changes in our proved reserves for the year ended December 31, 2023. 
+Total 
+(MBoe) 
+Proved reserves as of December 31, 2022 
+479,525 
+Extensions and discoveries 68,005 
+Revisions to previous estimates (23,927) 
+Purchase of reserves in place 55,352 
+Sales of reserves in place (65,759) 
+Removed for five-year rule (42,099) 
+Production (37,587) 
+Proved reserves as of December 31, 2023 
+433,510 
+Further details of the changes in our proved reserves for the year ended December 31, 2023 are as follows: 
+• Extensions and Discoveries. We added 68.0 MMBoe of new reserves in extensions and discoveries through our development efforts in our operating areas. See the table below for the impact of extensions and discoveries on total proved and proved undeveloped reserves for 2023: 
+Extensions and discoveries Total 
+(MBoe) 
+Total proved 68,005 
+Proved undeveloped 65,502 
+Difference (Proved developed producing) (1) 
+2,503 
+(1) These extensions and discoveries were not recognized as proved undeveloped reserves in a prior period, but rather were recognized directly as proved developed producing reserves in 2023 as there was not a directly offsetting proved developed producing location at the time of drilling to allow classification as a proved undeveloped location. 
+We incurred costs of $54.9 million for the extensions and discoveries associated with proved developed producing wells during 2023. 
+• Revisions to Previous Estimates. Net negative revisions of previous estimates of 23.9 MMBoe primarily consist of: 
+◦ 10.8 MMBoe reduction from the removal of PUD locations due to revised development spacing and changes in lateral lengths, primarily in our Delaware West operating area, as we focus on the ongoing optimization of the value of the reservoir system through co-development of multiple target zones within the system utilizing larger scale projects and extended lateral lengths; 
+◦ 10.7 MMBoe reduction primarily due to the change in 12-Month Average Realized Price of crude oil which decreased by approximately 18% as compared to December 31, 2022; and 
+10 
+◦ 2.4 MMBoe reduction primarily due to higher operating costs as well as lower than expected recoveries from wells turned to production during 2023 primarily in the Delaware West portion of our Permian acreage. 
+• Purchase of Reserves in Place. The 55.4 MMBoe of purchase of reserves in place was associated with the Percussion Acquisition. 
+• Sales of Reserves in Place. The 65.8 MMBoe of sales of reserves in place were primarily associated with the Eagle Ford Divestiture. 
+• Removed due to five-year rule. 42.1 MMBoe reduction due to PUD locations that were reclassified to unproved reserve categories as we adjusted our future Permian Basin development and capital allocation plans following the Eagle Ford Divestiture and the concurrent Percussion Acquisition, resulting in previously scheduled PUDs, primarily in the Delaware West operating area that is more weighted to natural gas volumes, now forecast to be developed outside of the five-year period from initial booking. 
+Proved Undeveloped Reserves 
+Annually, we review our PUDs to ensure appropriate plans exist for development of this reserve category. PUD reserves are recorded only if we have plans to convert these reserves into PDPs within five years of the date they are first recorded. Our development plans include the allocation of capital to projects included within our 2024 Capital Budget, as defined below, and, in subsequent years, the allocation of capital within our long-range business plan to convert PUDs to PDPs within this five-year period. The following table provides a summary of the changes in our PUDs for the year ended December 31, 2023. 
+Total 
+(MBoe) 
+PUDs as of December 31, 2022 
+186,325 
+Extensions and discoveries 65,502 
+Revisions to previous estimates (4,664) 
+Purchases of reserves in place 22,358 
+Sales of reserves in place (15,470) 
+Removed for five-year rule (42,099) 
+Converted to proved developed (56,909) 
+PUDs as of December 31, 2023 
+155,043 
+• Extensions and Discoveries. We added 65.5 MMBoe of new reserves in extensions and discoveries as a result of additional offset locations associated with our drilling program. 
+• Revisions to Previous Estimates. Net negative revisions of previous estimates of 4.7 MMBoe primarily consist of: 
+◦ 10.8 MMBoe reduction from the removal of PUD locations due to revised development spacing and changes in lateral lengths, primarily in our Delaware West operating area, as we focus on the ongoing optimization of the value of the reservoir system through co-development of multiple target zones within the system utilizing larger scale projects and extended lateral lengths; 
+◦ 1.7 MMBoe decrease primarily due to the change in 12-Month Average Realized Price of crude oil which decreased by approximately 18% as compared to December 31, 2022; offset by 
+◦ 7.8 MMBoe increase primarily due to increased anticipated hydrocarbon recoveries resulting from observed well performance over longer production timeframes during the testing of various full field development plan concepts. 
+• Purchase of Reserves in Place. The 22.4 MMBoe of purchase of reserves in place was associated with the Percussion Acquisition. 
+• Sales of Reserves in Place. The 15.5 MMBoe of sales of reserves in place were primarily associated with the Eagle Ford divestiture. 
+• Removed for five-year rule. 42.1 MMBoe reduction due to PUDs that were reclassified to unproved reserve categories as described above. 
+• Converted to Proved Developed. During 2023, we converted 56.9 MMBoe of PUDs that were booked as PUDs as of December 31, 2022 to proved developed at a cost of $578.0 million, or $10.16 per Boe. 
+During 2023, we also incurred $119.4 million on PUDs, representing an estimated 17.3 MMBoe, that were drilled but uncompleted as of December 31, 2023. All of the reserves associated with these drilled but uncompleted wells are scheduled to be completed in 2024, and we expect to incur approximately $121.1 million of additional capital expenditures to complete these wells. Separately, we 
+11 
+incurred $73.2 million primarily on additional wells that were in the process of being drilled at year end 2023 as well as $47.5 million on the Eagle Ford properties before the divestiture date. 
+At December 31, 2023, we did not have any reserves that have remained undeveloped for five or more years since the date of their initial booking and all PUD locations are scheduled to be developed within five years of their initial booking. 
+Qualifications of Technical Persons 
+In accordance with the Standards Pertaining to Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers, D&M prepared 100% of our estimates of proved reserves as of December 31, 2023, 2022, and 2021. D&M is a respected company in the reservoir engineering field and provides petroleum property analysis for other upstream companies. The technical persons responsible for preparing the reserves estimates meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. D&M does not own an interest in our properties and is not employed on a contingent fee basis. 
+Our internal director of reserves has over 20 years of experience in the petroleum industry and extensive experience in the estimation of reserves and the review of reserve reports prepared by third-party engineering firms. Compliance as it relates to reporting our reserves is the responsibility of our Chief Operating Officer, who is also our principal engineer. He has over 20 years of operations and industry experience and holds a B.S. degree in Petroleum and Geosystems Engineering. 
+Internal Controls Over Reserve Estimation Process 
+The primary inputs to the reserve estimation process are comprised of technical information, financial data, production data, and ownership interest. All field and reservoir technical information is assessed for validity when the internal reserve engineer holds technical meetings with our geoscientists, operations, and land personnel to discuss field performance and to validate future development plans. The other inputs used in the reserve estimation process, including, but not limited to, future capital expenditures, commodity price differentials, production costs, and ownership percentages are subject to internal controls over financial reporting and are assessed for effectiveness annually. 
+To further enhance the control environment over the reserve estimation process, our Operations and Reserves Committee, an independent committee of the Board of Directors, assists management and the Board of Directors with its oversight of the integrity of the determination of our oil and natural gas reserves and the work of the independent third-party reserve engineers. The Operations and Reserves Committee’s charter also specifies that it shall perform, in consultation with the Company’s management and senior reserves and reservoir engineering personnel, the following responsibilities: 
+• Oversee the appointment, qualification, independence, compensation and retention of the independent third-party reserve engineers engaged by the Company (including resolution of material disagreements between management and the independent third-party reserve engineers regarding reserve determination) for the purpose of preparing or issuing an annual reserve report. The Operations and Reserves Committee shall review any proposed changes in the appointment of the independent third-party reserve engineers, determine the reasons for such proposal, and whether there have been any disputes between the independent third-party reserve engineers and management. 
+• Review the Company’s significant reserves engineering principles and any material changes thereto, and any proposed changes in reserves engineering standards and principles which have, or may have, a material impact on the Company’s reserves disclosure. 
+• Review with management and the independent third-party reserve engineers the proved reserves of the Company, and, if appropriate, the probable reserves, possible reserves and the total reserves of the Company, including: (i) reviewing significant changes from prior period reports; (ii) reviewing key assumptions used or relied upon by the independent third-party reserve engineers; (iii) evaluating the quality of the reserve estimates prepared by the independent third-party reserve engineers and the Company relative to the Company’s peers in the industry; and (iv) reviewing any material reserves adjustments and significant differences between the Company’s and independent third-party reserve engineers’ estimates. 
+• If the Operations and Reserves Committee deems it necessary, it shall meet in executive session with the independent third-party reserve engineers to discuss the oil and gas reserve determination process and related public disclosures, and any other matters of concern in respect of the evaluation of the reserves. 
+During our last fiscal year, we filed no reports with other federal agencies which contain an estimate of proved reserves. 
+See “Note 20 – Supplemental Information on Oil and Natural Gas Operations” of the Notes to our Consolidated Financial Statements for additional information regarding our estimated proved reserves and the present value of estimated future net revenues from these proved reserves. 
+12 
+Drilling Activity 
+The following table sets forth our operated and non-operated drilling activity for the years ended December 31, 2023, 2022, and 2021. As defined by the SEC, the number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. For definitions of exploratory wells, extension wells, development wells, productive wells, and non-productive wells, see “Glossary of Certain Terms.” 
+Years Ended December 31, 
+2023 2022 2021 
+Gross Net Gross Net Gross Net 
+Extension Wells - Productive 7 5.5 20 17.7 19 17.2 
+Extension Wells - Non-productive — — — — — — 
+Development Wells - Productive 122 92.6 86 76.8 93 86.7 
+Development Wells - Non-productive — — — — — — 
+Productive Wells 
+The following table sets forth the number of productive crude oil and natural gas wells in which we owned an interest as of December 31, 2023. 
+Crude Oil Natural Gas Total 
+Gross Net Gross Net Gross Net 
+Operated 
+1,115 1,002.1 128 109.4 1,243 1,111.5 
+Non-operated 
+236 11.9 — — 236 11.9 
+Total 
+1,351 1,014.0 128 109.4 1,479 1,123.4 
+13 
+Production Volumes, Average Sales Prices and Operating Costs 
+The following tables set forth certain information regarding the production volumes and average sales prices received for, and average production costs associated with, our sales of oil, natural gas and NGLs for the periods indicated. For further details, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations”. 
+Years Ended December 31, 
+2023 2022 2021 
+Total production 
+Oil (MBbls) 
+Permian 19,658 18,041 14,475 
+Eagle Ford 2,233 5,598 7,749 
+Total oil 21,891 23,639 22,224 
+Natural gas (MMcf) 
+Permian 43,437 35,519 29,682 
+Eagle Ford 2,672 6,108 7,704 
+Total natural gas 46,109 41,627 37,386 
+NGLs (MBbls) 
+Permian 7,554 6,424 5,155 
+Eagle Ford 457 1,052 1,284 
+Total NGLs 8,011 7,476 6,439 
+Total production (MBoe) 
+Permian 34,452 30,385 24,577 
+Eagle Ford 3,135 7,668 10,317 
+Total barrels of oil equivalent 37,587 38,053 34,894 
+Average realized sales price (excluding impact of derivative settlements) 
+Oil (per Bbl) $77.52 $95.72 $68.22 
+Natural gas (per Mcf) 1.79 5.59 3.78 
+NGL (per Bbl) 21.77 34.84 30.11 
+Total average realized sales price (per Boe) $51.98 $72.42 $53.06 
+Operating costs per Boe 
+Lease operating expense $8.07 $7.63 $5.82 
+Production and ad valorem taxes $3.02 $4.20 $2.87 
+Gathering, transportation and processing $2.88 $2.55 $2.32 
+14 
+Major Customers 
+We market the majority of the production from properties we operate on account of both ourselves and that of the other working interest owners in these properties. We generally sell our production to purchasers at prevailing market prices, which in certain cases are adjusted for contractual differentials, under contracts ranging from terms of one month to multiple years. The following table presents customers that represented 10% or more of our oil, natural gas and NGL revenues for at least one of the periods presented: 
+Years Ended December 31, 
+2023 (1) 
+2022 (1) 
+2021 (1) 
+Vitol Inc. 13% * * 
+Plains Marketing, L.P. 12 * * 
+Rio Energy International, Inc. 12 12% * 
+BP Products North America, Inc. 12 * * 
+Valero Marketing and Supply Company * 15 13% 
+Shell Trading Company * * 20 
+Trafigura Trading, LLC * * 15 
+Occidental Energy Marketing, Inc. * * 13 
+(1) The customers that represented over 10% of our sales of purchased oil and gas were Vitol Inc. and Plains Marketing, L.P., for the years ended December 31, 2023, and 2022, and Vitol Inc., for the year ended December 31, 2021. 
+* - Less than 10% for the respective years. 
+Because alternative purchasers of oil and natural gas are readily available, we believe that the loss of any of these purchasers would not result in a material adverse effect on our ability to sell future oil and natural gas production. In order to mitigate potential exposure to credit risk, we may require our customers to provide financial security. 
+Leasehold Acreage 
+The following table shows our approximate developed and undeveloped leasehold acreage as of December 31, 2023. Developed acreage refers to acreage on which wells have been completed to a point that would permit production of oil and gas in commercial quantities. Undeveloped acreage refers to acreage on which wells have not been drilled or completed to a point that would permit production of oil and gas in commercial quantities whether or not the acreage contains proved reserves. 
+Developed Acreage Undeveloped Acreage Total Acreage Net Undeveloped Acreage Expiring 
+Gross Net Gross Net Gross Net 2024 2025 2026 
+Permian (1) 
+159,881 131,619 12,561 9,084 172,442 140,703 737 6,062 1,218 
+Other (2) 
+1,983 34 8,957 4,022 10,940 4,056 2,994 — — 
+Total 161,864 131,653 21,518 13,106 183,382 144,759 3,731 6,062 1,218 
+(1) Based on our current plans, approximately 100%, 97% and 28% of the acreage expiring in the Permian in 2024, 2025 and 2026, respectively, will be developed prior to expiration or extended by lease extension payments. 
+(2) Consists of non-core acreage principally located in Presidio County, Texas. We have no current development plans, no proved undeveloped reserves, and no unproved property costs associated with this acreage as of December 31, 2023. 
+Our lease agreements generally terminate if producing wells have not been drilled on the acreage within their primary term or an extension thereof (a period that is generally from three to five years depending on the area). The percentage of net undeveloped acreage expiring in 2024, 2025 and 2026 assumes that no producing wells have been drilled on acreage within their primary term or have been extended. We manage our lease expirations to ensure that we do not experience unintended material loss of acreage or depths. Our leasehold management efforts include scheduling drilling in order to hold leases by production or timely exercising our contractual rights to extend the terms of leases by continuous operations or the payment of lease extension payments and delay rentals. We may choose to allow some leases to expire that are no longer part of our development plans. 
+The proved undeveloped reserves associated with acreage expiring over the next three years are not material to the Company. 
+Human Capital 
+Callon employs a talented workforce that is integral to our success, and we are committed to the safety, health, and development of each team member. The Callon culture is defined by our values of responsibility, integrity, drive, respect and excellence. These core values are a reflection of our ideals as individuals and direct our actions as a company. 
+15 
+Callon’s key human capital management objectives are to attract, retain and develop talent to deliver on our strategy. Due to the technical nature of our business, our success depends on a highly skilled workforce in multiple disciplines including engineering, geology, operations, land, information technology, accounting and various other corporate functions. To support the attraction and retention of top talent, our human resources programs are designed to keep our employees safe and healthy, engage employees with an inclusive workplace, reward and support employees through competitive pay and benefit programs, and develop talent to support personal growth and prepare employees for high impact roles and leadership positions. 
+As of December 31, 2023, Callon had 281 permanent, full-time employees. None of our employees are currently represented by a union, and we believe that we have good relations with our employees. 
+We focus on the following in supporting our human capital: 
+• Inclusion and Diversity – We believe that diversity of backgrounds and perspectives contributes to an innovative workforce and an enriching environment for our employees. Callon is firmly committed to fostering an inclusive, respectful environment and providing equal opportunity to all qualified persons in our hiring, development, and compensation practices. As of December 31, 2023, approximately 43% of our permanent, full-time employees identified as a racial or ethnic minority, 25% were female, and 33% of non-field employees were female. We seek to support diversity in our workforce, and in 2023, 53% of our newly hired employees identified as a racial or ethnic minority and 27% were female. 
+• Health and Safety – Protecting our employees, contractors and communities is a core value at Callon and a top priority. Our Operations Management System (“OMS”) establishes clear expectations for operating safely and responsibly throughout the lifecycle of our business. We seek to identify and mitigate safety risks and integrate a culture of safety by operating according to OMS standards, processes, and procedures. Additionally, we share our Safety and Environmental Policy with all employees and contractors; the policy includes each individual’s authorization and responsibility to stop work on any activity for safety reasons without the threat or fear of job reprisal. To reinforce accountability for safety results, our Board of Directors included safety performance as a factor in our 2023 annual bonus program. 
+• Employee Compensation, Benefits and Wellness – Our compensation and benefits programs provide a package designed to attract, retain and motivate employees. In addition to competitive base salaries, we provide a variety of short-term and long-term incentive compensation programs to reward performance relative to key financial, operational, and ESG metrics. Callon invests in the health and well-being of our employees and their families by paying 100% of the premiums for our health care plan. We also offer comprehensive benefit options including a retirement savings plan, life and disability insurance, health savings accounts, flexible spending accounts, and a charitable matching program. 
+• Employee Development – We believe that ongoing investment in the development of our team members is key to our future success, as well as the retention of our employees. Callon fosters an entrepreneurial workplace where employees can expand their skill sets and experience by direct engagement and collaboration with leaders at all levels. Additionally, we offer tuition assistance and access to various training programs, including a monthly in-house leadership development program. Our leaders seek to support all of our employees in reaching their personal goals through ongoing feedback and development conversations. 
+For additional information, please see our Sustainability Report published on our company website (www.callon.com). Information contained in our Sustainability Report is not incorporated by reference into, and does not constitute a part of, this 2023 Annual Report on Form 10-K. 
+Other 
+Industry Segment and Geographic Information 
+For segment reporting purposes, Callon considers all of the current development and operating areas to be one reportable segment: the development and production of oil and natural gas. All of our assets are located within the United States and all operations are located within Texas. 
+Title to Properties 
+We believe that the title to our oil and natural gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of such properties. Nevertheless, we can be involved in title disputes from time to time which may result in litigation. Our properties are potentially subject to burdens such as royalty, overriding royalty, working and other outstanding interests customary in the industry. To the extent that such burdens and obligations affect our rights to production revenues, these characteristics have been taken into account in calculating our net revenue interests and in estimating the size and value of our estimated proved reserves. We 
+16 
+believe that the burdens and obligations affecting our properties are typical within the industry for properties of the kind owned by Callon. 
+Seasonality of Business 
+Weather conditions and seasonality affect our ability to produce, the demand for, and prices of, oil and natural gas. Due to these fluctuations, results of operations for quarterly interim periods may not be indicative of the results realized on an annual basis. 
+Competition 
+We operate in the oil and natural gas industry, which is highly competitive. Our business experiences strong competition from a number of parties that may range from small independent producers to major integrated companies. Competition affects our ability to acquire additional properties and resources necessary to develop assets. In higher commodity pricing environments, competition also exists in the form of contracting for drilling, pumping, and workover equipment, and securing skilled personnel to both develop and operate existing assets. Many of our competitors may be able to pay for more sought-after properties or access equipment, infrastructure, or personnel. The industry also experiences, from time to time, shortages in resources such as the availability of drilling and workover rigs, other equipment, pipes and materials, infrastructures, and skilled personnel, all of which can delay development, exploration, and workover activities as well as result in significant cost increases. 
+Insurance 
+In accordance with industry practice, we maintain insurance against some of the operating risks to which our business is exposed. While not all inclusive, our insurance policies generally protect against bodily injury and property damage, pollution and other environmental damages, employee benefits, employee injury and control of well insurance for our exploration and production operations. 
+We enter into master service agreements with our third-party contractors, including hydraulic fracturing contractors, in which they agree to indemnify us for injuries and deaths of the service provider’s employees, as well as contractors and subcontractors hired by the service provider. Similarly, we generally agree to indemnify each third-party contractor against claims made by our employees and our other contractors. Additionally, each party generally is responsible for damage to its own property. We reevaluate the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and natural gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. While we believe that we are properly insured based on our risk analysis, no assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable. In such circumstances, we may elect to self-insure or maintain only catastrophic coverage for certain risks in the future. 
+Corporate Offices 
+Our headquarters are located in Houston, Texas, in office space that we lease. We own office buildings in Pecos, Texas and lease and own offices in the Midland, Texas area. Because alternative locations to our leased spaces are readily available, the replacement of any of our leased offices would not result in material expenditures . 
+Regulations 
+General. Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities at the federal, state, and local levels. Some of these requirements carry substantial penalties for failure to comply. Legislation and regulation affecting the entire oil and natural gas industry is continuously being reviewed for potential revision, and various proposals and proceedings that might affect the industry are pending before Congress, federal administrative agencies such as the Federal Energy Regulatory Commission (“FERC”), various state and administrative agencies and legislatures, and the courts. We cannot predict what effect such proposals or proceedings may have on our operations, capital expenditures, earnings or competitive position. 
+Exploration and Production . Our operations are subject to federal, state and local regulations that include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds and letters of credit) covering drilling and well operations. Other activities subject to regulation are: 
+• the location and spacing of wells; 
+• the method of drilling and completing and operating wells; 
+• the rate and method of production; 
+• the surface use and restoration of properties upon which wells are drilled and other exploration activities; 
+• notice to surface owners and other third parties; 
+• the venting or flaring of natural gas; 
+• the plugging and abandoning of wells; 
+• the discharge of contaminants into water and the emission of contaminants into air; 
+• the disposal of fluids used or other wastes obtained in connection with operations; 
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+• the marketing, transportation and reporting of production; and 
+• the valuation and payment of royalties. 
+We do not currently anticipate that compliance with existing laws and regulations governing exploration and production will have a significantly adverse effect upon our capital expenditures, operations, earnings or competitive position. 
+Environmental Matters and Regulation. Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to the protection of the environment and natural resources. Numerous federal, state and local governmental agencies, such as the U.S. Environmental Protection Agency (the “EPA”), issue regulations which often require difficult and costly compliance measures. These laws and regulations may require the acquisition of a permit before drilling commences; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities; limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas; require action to prevent, monitor for or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits; result in the suspension or revocation of necessary permits, licenses and authorizations; require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relating to our owned or operated facilities. Violations of environmental laws could result in administrative, civil or criminal fines and injunctive relief. The strict and joint and several liability nature of certain such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons, air emissions or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. In recent years, the oil and natural gas exploration and production industry has been the subject of increasing scrutiny and regulation by environmental authorities. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. Although such laws and regulations can increase the cost of planning, designing, installing and operating our facilities, it is anticipated that, absent the occurrence of an extraordinary event, compliance with them will not have a material effect upon our operations, capital expenditures, earnings or competitive position in the marketplace. 
+Waste Handling. The Resource Conservation and Recovery Act (“RCRA”), as amended, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of oil and natural gas are exempt from regulation as hazardous wastes under RCRA and its state analogs, it is possible that some wastes we generate presently or in the future may be subject to regulation under RCRA and state analogs. Additionally, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” If the EPA proposes a rulemaking for revised oil and gas waste regulations in the future, any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. 
+Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of wastes associated with oil and natural gas exploration and production could increase our costs to manage and dispose of such wastes. 
+Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), imposes strict, joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the release occurred and anyone who disposed of or arranged for the disposal of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes. 
+Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we have generated and will generate wastes that may fall within CERCLA’s definition of hazardous substance and may have disposed of 
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+these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum. We may also be the owner or operator of sites on which hazardous substances have been released. To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under CERCLA; we also do not know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties. In the event contamination is discovered at a site on which we are or have been an owner or operator or to which we sent hazardous substances, we could be liable for the costs of investigation and remediation and natural resources damages. 
+We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating, waste disposal, and water disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including offsite locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination or groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination. 
+Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, the Safe Drinking Water Act, the Oil Pollution Act (“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into waters of the United States (“WOTUS”) (a term broadly defined to include, among other things, certain wetlands), as well as state waters for analogous state programs. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or applicable state analog. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit from the U.S. Army Corps of Engineers (the “Corps”). The EPA and the Corps issued a final rule on the federal jurisdictional reach over waters of the United States in 2015 that never took effect before being replaced by the Navigable Waters Protection Rule (the “NWPR”) in 2020. A coalition of states and cities, environmental groups, and agricultural groups challenged the NWPR, and it was vacated by a federal district court in August 2021. In January 2023, the EPA and the Corps issued a final rule that based the definition of WOTUS on the pre-2015 definition. Separately, in May 2023, the U.S. Supreme Court’s decision in Sackett v. EPA narrowed federal jurisdiction over wetlands to “traditional navigable waters” and wetlands or other waters that have a “continuous surface connection” with or are otherwise indistinguishable from traditional navigable water. In September 2023, the EPA and the Corps published a direct-to-final rule that conforms the regulatory definition of WOTUS to the Supreme Court’s May 2023 decision in Sackett. 
+The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. 
+The Oil Pollution Act is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters. 
+Noncompliance with the Clean Water Act or the OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws. 
+Air Emissions. The federal Clean Air Act, as amended (the “CAA”), and comparable state and local laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and modified and existing facilities may be required to obtain additional permits. As a result, we may need to incur capital costs in order to remain in compliance. Obtaining or renewing permits also has the potential to delay the development of oil and natural gas projects. Federal and state regulatory agencies can impose administrative, civil and criminal penalties and seek injunctive relief for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. 
+19 
+In November 2021, the EPA issued a proposed rule under the CAA’s New Source Performance Standards, known as Subpart OOOOa, intended to reduce methane emissions from new and existing oil and gas sources. The proposed rule would make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the CAA (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities). In addition, the proposed rule would establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA. In November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule. Among other things, the November 2022 supplemental proposed rule removes an emissions monitoring exemption for small wellhead-only sites and creates a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters.” In December 2023, the EPA announced a final rule, which, among other things, requires the phase out of routine flaring of natural gas from newly constructed wells (with some exceptions) and routine leak monitoring at all well sites and compressor stations. Notably, the EPA updated the applicability date for Subparts OOOOb and OOOOc to December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later compliance deadlines under state plans. The final rule gives states, along with federal tribes that wish to regulate existing sources, two years to develop and submit their plans for reducing methane emissions from existing sources. The final emissions guidelines under Subpart OOOOc provide three years from the plan submission deadline for existing sources to comply. 
+Compliance with these or any new regulations could result in stricter permitting requirements, which in turn could delay or impair our ability to obtain air emission permits and could result in increased expenditures for pollution control equipment, the costs of which could be significant. 
+Climate Change. Numerous reports from scientific and governmental bodies such as the Sixth Assessment Report of the Intergovernmental Panel on Climate Change have expressed heightened concerns about the impacts of human activity, especially fossil fuel combustion, on the global climate. In turn, governments and civil society are increasingly focused on limiting the emissions of GHGs, including emissions of carbon dioxide from the use of oil and natural gas. 
+At the international level, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change (“UNFCCC”) resulted in nearly 200 countries, including the United States, coming together to develop the Paris Agreement, intended to nationally determine their contributions and set GHG emission reduction goals every five years beginning in 2020. In February 2021, as a party to the Paris Agreement, the U.S. announced a target to achieve a 50% to 52% reduction from 2005 levels in economy-wide GHG emissions by 2030. In addition, in September 2021, President Biden publicly announced the Global Methane Pledge, a pact that aims to reduce global methane emissions at least 30% below 2020 levels by 2030, including “all feasible reductions” in the energy sector. Since its formal launch at the 26th Conference of the Parties of the UNFCCC (“COP26”), over 150 countries have joined the pledge. At the 27th conference of parties (“COP27”), President Biden announced the EPA’s supplemental proposed rule to reduce methane emissions from existing oil and gas sources, and agreed, in conjunction with the European Union and a number of other partner countries, to develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. Most recently, at the 28th conference of the parties (“COP28”), nearly 200 countries, including the United States, agreed to transition away from fossil fuels while accelerating action in this decade to achieve net zero greenhouse gas emissions by 2050. Various state and local governments have also publicly committed to furthering the goals of the Paris Agreement. International commitments, re-entry into the Paris Agreement and President Biden’s executive orders may result in the development of additional regulations or changes to existing regulations. 
+While the Biden Administration has pursued executive actions to address climate change, and while Congress has from time to time considered legislation to reduce emissions of GHGs, no new comprehensive federal laws regulating the emission of GHGs or directly imposing a price on carbon have been adopted in recent years. However, such legislation has periodically been introduced in the U.S. Congress and may be proposed or adopted in the future, and energy legislation and other regulatory initiatives have been proposed that are relevant to GHG emissions issues. For example, the Inflation Reduction Act of 2022 (“IRA”), which appropriates significant funding for renewable energy initiatives and, for the first time, imposes a fee on GHG emissions from certain oil and gas facilities, was signed into law in August 2022. The IRA amends the CAA to include a Methane Emissions and Waste Reduction Incentive Program, which requires the EPA to impose a “waste emissions charge” on certain natural gas and oil sources that are already required to report under the EPA’s Greenhouse Gas Reporting Program. To implement the program, the IRA requires revisions to GHG reporting regulations for petroleum and natural gas systems (Subpart W) by 2024. In July 2023, the EPA proposed to expand the scope of the Greenhouse Gas Reporting Program for petroleum and natural gas facilities, as required by the IRA. Among other things, the proposed rule would expand the emissions events that are subject to reporting requirements to include “other large release events” and apply reporting requirements to certain new sources and sectors. The rule is expected to be finalized in the spring of 2024 and become effective on January 1, 2025 in advance of the deadline for GHG reporting for 2024 (March 2025). The fee imposed under the Methane Emissions and Waste Reduction Incentive Program for 2024 would be $900 per ton emitted over annual methane emissions thresholds, and would increase to $1,200 in 2025, and $1,500 in 2026. In addition, many state and local governments have intensified or stated their intent to intensify efforts to support international climate commitments and treaties, in addition to developing programs 
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+that are aimed at reducing GHG emissions by means of cap and trade programs, carbon taxes, the development of greenhouse gas inventories or encouraging the use of renewable energy or alternative low-carbon fuels. 
+Any legislation or regulatory programs at the federal, state, or city levels designed to reduce GHG emissions could increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. 
+The EPA has established GHG reporting requirements for certain sources in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissions. Although these requirements do not limit the amount of GHGs that can be emitted, they do require us to incur costs to monitor, keep records of, and report GHG emissions associated with our operations. 
+Additionally, in March 2022, the SEC issued a proposed rule regarding the enhancement and standardization of mandatory climate-related disclosures for investors. The proposed rule would require registrants to include certain climate-related disclosures in their registration statements and periodic reports, including, but not limited to, information about the registrant’s governance of climate-related risks and relevant risk management processes; climate-related risks that are reasonably likely to have a material impact on the registrant’s business, results of operations, or financial condition and their actual and likely climate-related impacts on the registrant’s business strategy, model, and outlook; climate-related targets, goals and transition plan (if any); certain climate-related financial statement metrics in a note to their audited financial statements; Scope 1 and Scope 2 GHG emissions; and Scope 3 GHG emissions and intensity, if material, or if the registrant has set a GHG emissions reduction target, goal or plan that includes Scope 3 GHG emissions. A final rule is anticipated in April 2024. Although the proposed rule’s ultimate date of effectiveness and the final form and substance of these requirements is not yet known and the ultimate scope and impact on our business is uncertain, compliance with the proposed rule, if finalized, may result in increased legal, accounting and financial compliance costs, make some activities more difficult, time-consuming and costly, and place strain on our personnel, systems and resources. 
+Regulation of Hydraulic Fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act (“SDWA”) regulates the underground injection of substances through the Underground Injection Control (“UIC”) program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions and not at the federal level, as the SDWA expressly excludes regulation of these fracturing activities (except where diesel is a component of the fracturing fluid, as further discussed below). Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing has been proposed in past legislative sessions but has not passed. 
+The EPA, however, issued guidance on permitting hydraulic fracturing that uses fluids containing diesel fuel under the UIC program, specifically as “Class II” UIC wells. The EPA evaluated the potential impacts of hydraulic fracturing on drinking water resources and concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Further, the EPA prohibits the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. 
+Several states, including Texas, and some municipalities, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, Texas law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) for disclosure on a website and also file the list of chemicals with the Texas Railroad Commission (the “RRC”) with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the RRC. 
+Additionally, some states, localities and local regulatory districts have adopted or have considered adopting regulations to limit, and in some cases impose a moratorium on, hydraulic fracturing or other restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; or restrictions on access to, and usage of, water. Further, there has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the U.S. implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations of harm. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and 
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+abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of potential federal or state legislation governing hydraulic fracturing. In light of concerns about seismic activity being triggered by the injection of produced waters into underground wells, certain regulators are also considering additional requirements related to seismic safety for hydraulic fracturing activities. For example, the RRC has created several “seismic response areas” in west Texas and limited certain deep oil and gas wastewater disposal activities in portions of west Texas due to seismicity concerns. The U.S. Geological Survey has identified eight states with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. Any regulation that restricts our ability to dispose of produced waters or increases the cost of doing business could cause curtailed or decreased demand for our services and have a material adverse effect on our business. 
+Surface Damage Statutes (“SDAs”) . In addition, a number of states and some tribal nations have enacted SDAs. These laws are designed to compensate for damage caused by oil and gas development operations. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain binding requirements for payments by the operator to surface owners/users in connection with exploration and operating activities in addition to bonding requirements to compensate for damages to the surface as a result of such activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs. 
+National Environmental Policy Act . Oil and natural gas exploration and production activities requiring federal permits may be subject to the National Environmental Policy Act (“NEPA”), which requires federal agencies to evaluate major federal actions having the potential to significantly impact the human environment. In the course of such evaluations, an agency will evaluate the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a detailed Environmental Impact Statement that must be made available for public review and comment. Recent litigation by environmental non-governmental organizations has alleged that the Environmental Assessments for certain oil and natural gas projects violated NEPA by failing to account for climate change and the greenhouse gas emissions impacts of such projects. In July 2020, the Council on Environmental Quality revised NEPA’s implementing regulations in an effort designed to streamline project approvals. The new regulations were subject to litigation in several federal district courts and were stayed pending an ongoing review of the 2020 rule. In October 2021, the Council on Environmental Quality announced its Phase 1 rule, the first of two planned rules to roll back the 2020 rule, which was finalized in April 2022. The Phase 1 final rule generally restores certain regulatory provisions that were in effect prior to the 2020 rule. In July 2023, the Council on Environmental Quality proposed a Phase 2 rule that would accelerate NEPA reviews while maintaining consideration of relevant environmental, climate change and environmental justice effects. The final rule is expected in April 2024. To the extent that our current exploration and production activities, as well as proposed exploration and development plans, require federal permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects. 
+Endangered Species Act and Migratory Bird Treaty Act. The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or its habitat. The U.S. Fish and Wildlife Service (the “FWS”) must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”), which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit. This prohibition covers most bird species in the U.S. In January 2021, the Department of the Interior finalized a rule limiting application of the MBTA; however, the Department of the Interior revoked the rule in October 2021 and issued an advance notice of proposed rulemaking seeking comment on the Department’s plan to develop regulations that authorize incidental take under certain prescribed conditions. The notice of proposed rulemaking was anticipated in November 2023, with final action expected in April 2024, but the FWS instead announced in November 2023 that it had received additional technical comments that require further review. As a result, future amendments to the rules implementing the ESA and the MBTA are uncertain. If the Company was to have a portion of its leases designated as critical or suitable habitat or a protected species were located on a lease, it may adversely impact the value of the affected leases. There is also increasing interest in nature-related matters beyond protected species, such as general biodiversity, which may similarly require us or our customers to incur costs or take other measures which may adversely impact our business or operations. 
+Other Regulation of the Oil and Natural Gas Industry. The oil and natural gas industry is extensively regulated by numerous federal, state and local agencies and authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any 
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+differently or to any greater or lesser extent than they affect other similar companies in the industry with similar types, quantities and locations of production. 
+The availability, terms, conditions and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas is subject to federal regulation by FERC which regulates the terms, conditions and rates for interstate transportation and storage service and various other matters. State regulations govern the rates, terms, and conditions of service associated with access to intrastate oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transportation in some circumstances may also affect the intrastate transportation of oil and natural gas. 
+Although oil, natural gas, condensate, and NGL sales prices are currently unregulated, the federal government historically has been active in the area of oil and natural gas sales regulation. We cannot predict whether new legislation to regulate oil and natural gas sales might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of natural gas, condensate, oil and NGLs are not currently regulated and are made at market prices. 
+Exports of U.S. Oil Production and Natural Gas Production . In December 2015, the federal government ended its decades-old prohibition of exports of oil produced in the lower 48 states of the U.S. As a result, exports of U.S. oil have increased significantly, reinforcing the general perception in the industry that the end of the U.S. export ban was positive for producers of U.S. oil. In addition, the U.S. Department of Energy authorizes exports of natural gas, including exports of natural gas by pipelines connecting U.S. natural gas production to pipelines in Mexico, and the export of liquefied natural gas (“LNG”) through LNG export facilities, the construction and operation of which are regulated by FERC. Since 2016, natural gas produced in the lower 48 states of the U.S. has been exported as LNG from export facilities in the U.S. Gulf Coast region. LNG export capacity has steadily increased in recent years and is expected to continue increasing due to numerous export facilities that are currently being developed. The industry generally believes that this sustained growth in exports will be a positive development for producers of U.S. natural gas. 
+Drilling and Production. State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas without a permit and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or may limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affecting the economics of production from these wells or to limit the number of locations we can drill. 
+Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Some state agencies and municipalities require bonds or other financial assurances to support those obligations. 
+Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production and have it transported. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”). Since 1978, various federal laws have been enacted that have resulted in the complete removal of all price and non-price controls for “first sales” of natural gas, which include all of our sales of our own production. 
+Under the Energy Policy Act of 2005 (“EPAct 2005”) Congress amended the NGA and NGPA to give FERC substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess civil penalties up to $1.0 million per day for each violation. This maximum penalty authority has been and will continue to be adjusted periodically to account for inflation. FERC also has authority to order the disgorgement of any ill-gotten gains. EPAct 2005 also amended the NGA to authorize FERC to facilitate transparency in markets for the sale or transportation of physical natural gas in interstate commerce, pursuant to which authorization FERC now requires natural gas wholesale market participants, including a number of entities that may not otherwise be subject to FERC’s traditional NGA jurisdiction, to report information annually to FERC concerning their natural gas sales and purchases. FERC requires any wholesale market participant that sells or purchases 2.2 million MMBtus or more annually in “reportable” natural gas sales to provide a report, known as FERC Form 552, to FERC. Reportable natural gas sales include sales of natural gas that utilize a daily or monthly gas price index, contribute to index price formation, or could contribute to index price formation, such as fixed price transactions for next-day or next-month delivery. 
+23 
+FERC also regulates interstate natural gas transportation rates, terms and conditions of service, and the terms under which we as a shipper may use interstate natural gas pipeline capacity. Such regulations affect the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and for the release of our excess, if any, natural gas pipeline capacity. In 1985, FERC began promulgating a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate natural gas pipeline companies are required to provide non-unduly discriminatory transportation services to all shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases, sales, and transportation that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated. We cannot determine what effect, if any, future regulatory changes might have on our natural gas related activities. 
+Under FERC’s current regulatory regime, interstate transportation services must be provided on an open-access, not unduly discriminatory basis at cost-based rates or negotiated rates, both of which are subject to FERC approval. FERC also allows jurisdictional gas pipeline companies to charge market-based rates if the transportation market at issue is sufficiently competitive. The FERC-regulated tariffs, under which interstate pipelines provide such open-access transportation service, contain strict limits on the means by which a shipper releases its pipeline capacity to another potential shipper, and provisions under such tariffs include compliance with FERC’s “shipper-must-have-title” rule. Violations by a shipper (i.e., a pipeline customer) of FERC’s capacity release rules, including the shipper-must-have-title rule, could subject a shipper to substantial penalties and disgorgement of any ill-gotten gains. 
+With respect to its regulation of natural gas pipelines under the NGA, FERC traditionally has not required the applicant for construction and operation of a new interstate natural gas pipeline to provide information concerning the GHG emissions resulting from the activities of the proposed pipeline’s customers. In August 2017, the U.S. Circuit Court of Appeals for the D.C. Circuit issued a decision remanding a natural gas pipeline certificate application to FERC and required FERC to revise its environmental impact statement for the proposed pipeline to analyze potential GHG emission from the specific downstream power plants that the pipeline was designed to serve. In March 2021, FERC assessed the significance of a project’s GHG emissions and those emissions’ contribution to climate change. FERC compared the project’s reasonably foreseeable GHG emissions to the total GHG emissions of the United States to assess the project’s share of contribution to national GHG levels. FERC announced that it will also consider state GHG emission reduction targets, to the extent a state has such targets. Finally, FERC noted that it will consider “all appropriate evidence” in future proceedings. In February 2022, as redesignated in March 2022, FERC issued a draft interim policy statement on the consideration of GHG emissions in natural gas certification proceedings, which would consider reasonably foreseeable emissions. The draft interim policy statement proposed a significant shift and expansion in FERC’s review of GHG emissions in pipeline certificate proceedings. FERC has not issued a final order on the draft interim policy statement. The scope of FERC’s obligation to analyze the environmental impacts of proposed interstate natural gas pipeline projects, including the upstream indirect impacts of related natural gas production activity, remains subject to ongoing litigation and contested administrative proceedings at FERC and in the courts. 
+Gathering service, which occurs on pipeline facilities located upstream of FERC-jurisdictional interstate transportation services, is regulated by the states onshore and in state waters. Under NGA section 1(b), gathering facilities are exempt from FERC’s jurisdiction. FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transportation function, and FERC applies this test on a case-by-case basis. Depending on changes in the function performed by particular pipeline facilities, FERC has in the past reclassified certain FERC-jurisdictional transportation facilities as non-jurisdictional gathering facilities and FERC has reclassified certain non-jurisdictional gathering facilities as FERC-jurisdictional transportation facilities. Any such changes could result in an increase to our costs of transporting gas to point-of-sale locations. 
+The pipelines used to gather and transport natural gas being produced by the Company are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Act of 1992, as reauthorized and amended, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, the Securing America’s Future Energy: Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016, and the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2019. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In addition, PHMSA had initially considered regulations regarding, among other things, the designation of additional high consequence areas along pipelines, minimum requirements for leak detection systems, installation of emergency flow restricting devices, and revision of valve spacing requirements. In October 2019, PHMSA finalized new safety regulations for hazardous liquid pipelines, including a requirement that operators inspect affected pipelines following extreme weather events or natural disasters, that all hazardous liquid pipelines have a system for detecting leaks and that pipelines in high consequence areas be capable of accommodating in-line inspection tools within twenty years. In addition, PHMSA is in the process of finalizing a rulemaking with respect to gathering lines, but the contents and timing of any final rule for gathering lines are uncertain. In December 2020, Congress passed the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2020 (“PIPES Act of 2020”). In addition to reauthorizing PHMSA, the PIPES Act of 2020 directs the Secretary of Transportation to update or promulgate regulations 
+24 
+addressing the safety of certain gas pipeline, gathering, distribution and LNG facilities. On November 15, 2021, PHMSA issued a final rule that expands PHMSA’s safety regulations to more than 400,000 miles of onshore gas gathering pipelines that were previously exempt from PHMSA’s rules. While PHMSA has issued final rules for some of the regulations stemming from the PIPES Act of 2020, others are still proceeding through the rulemaking process. 
+Oil, Condensate and NGLs Sales and Transportation. Sales of oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. The Federal Trade Commission does have anti-market manipulation authority with respect to wholesale sales of oil under the Energy Independence and Security Act of 2007 and its petroleum market manipulation rule. 
+The Company’s sales of oil and NGLs are affected by the availability, terms, conditions and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil and NGLs by pipelines are regulated by FERC under the Interstate Commerce Act (“ICA”). FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and NGL pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and NGL pipeline rates. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. If the regulations relating to the price, terms and conditions for access to pipeline transportation change, we could face higher transportation costs for our production and, possibly, reduced access to transportation capacity. To the extent it may be necessary for new interstate natural gas pipelines to be built, there may be a more stringent regulatory approach at FERC, which could impact our ability to obtain new interstate pipeline transportation capacity. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil and NGL transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors. 
+Further, interstate common carrier oil pipelines must provide service on a not unduly discriminatory basis under the ICA, which is administered by FERC. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors. 
+In addition, FERC issued a declaratory order in November 2017, involving a marketing affiliate of an oil pipeline, and such order held that certain arrangements between an oil pipeline and its marketing affiliate would violate the ICA’s anti-discrimination provisions. FERC held that providing transportation service to affiliates at what is essentially the variable cost of the movement, while requiring non-affiliated shippers to pay the filed tariff rate, would violate the ICA. In December 2022, FERC issued an order denying rehearing and clarifying the scope of its holding in the November 2017 declaratory order and how it will assess whether future marketing affiliate transactions violate the ICA. Concurrently with the December 2022 order, FERC issued a proposed policy statement to revise its policy for evaluating whether contractual committed transportation service between oil pipelines and their affiliates complies with the ICA. At this time, the Company cannot currently determine the impact this FERC order and proposed policy statement may have on oil pipelines, their marketing affiliates, and the price of oil and other liquids transported by such pipelines. 
+State Regulation. Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill. 
+The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us. 
+Financial Regulations, Including Regulations Enacted Under the Dodd-Frank Act . The U.S. Commodities and Futures Exchange Commission (the “CFTC”) holds authority to monitor certain segments of the physical and futures energy commodities market including oil and natural gas. With regard to physical purchases and sales of natural gas and other energy commodities, and any related hedging activities that the Company undertakes, the Company is thus required to observe anti-market manipulation and disruptive trading practices laws and related regulations enforced by the CFTC. The CFTC also holds substantial enforcement authority, including the ability to assess civil penalties. 
+Congress adopted comprehensive financial reform legislation in 2010, establishing federal oversight and regulation of the over-the-counter derivative market and entities that participate in that market. The legislation, known as the Dodd-Frank Wall Street Reform 
+25 
+and Consumer Protection Act (“Dodd-Frank Act”), required the CFTC and the SEC to promulgate rules and regulations implementing the legislation, including regulations that affect derivatives contracts that the Company uses to hedge its exposure to price volatility. 
+While the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas remain pending. The Company cannot, at this time, predict the timing or contents of any final rules the CFTC may enact with regard to any applicable rulemaking proceeding. Any final rule in either proceeding could impact the Company’s ability to enter into financial derivative transactions to hedge or mitigate exposure to commodity price volatility and other commercial risks affecting our business. 
+Worker Health and Safety . We are subject to a number of federal and state laws and regulations, including OSHA, and comparable state statutes, the purpose of which are to protect the health and safety of workers. In addition, OSHA’s hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations, and that this information be provided to employees, state and local government authorities and citizens. 
+Commitments and Contingencies 
+Our activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, we believe that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment will not have a material effect upon our capital expenditures, earnings or our competitive position with respect to our existing assets and operations. We cannot predict what effect additional regulation or legislation, enforcement policies included, and claims for damages to property, employees, other persons, and the environment resulting from our operations could have on its activities. See “Note 18 – Commitments and Contingencies” of the Notes to our Consolidated Financial Statements for additional information. 
+Available Information 
+We make available free of charge on our website (www.callon.com) our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the SEC. 
+We also make available within the “About Callon — Governance” section of our website our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and Audit, Compensation, Nominating and ESG, and Operations and Reserves Committee Charters, which have been approved by our Board of Directors. We will make timely disclosure on our website of any change to, or waiver from, the Code of Business Conduct and Ethics for our principal executive and senior financial officers. A copy of our Code of Business Conduct and Ethics is also available, free of charge by writing us at: General Counsel, Callon Petroleum Company, 2000 W. Sam Houston Parkway South, Suite 2000, Houston, TX 77042. 
+26 
+ITEM 1A. Risk Factors 
+Our operations and financial results are subject to various risks and uncertainties, including but not limited to those described below. Our business could also be affected by additional risks and uncertainties not currently known to us or that we currently deem to be immaterial. If any of these risks actually occur, it could materially harm our business, financial condition or results of operations or impair our ability to implement business plans or complete development activities as scheduled. In that case, the market price of our common stock could decline. Below is a summary of the principal risks associated with an investment in the Company. This summary should not be relied upon as an exhaustive list of the material risks facing our business. 
+Risks Related to the Merger 
+• 
+While the Merger Agreement is in effect, we are subject to certain interim covenants. 
+• 
+The announcement and pendency of the Merger may result in disruptions to our business, and the Merger could divert management’s attention, disrupt our relationships with third parties and employees, and result in negative publicity or legal proceedings, any of which could negatively impact our operating results and ongoing business. 
+• 
+The Merger may not be completed within the expected timeframe, or at all, for a variety of reasons, including the possibility that the Merger Agreement is terminated, and the failure to complete the Merger could adversely affect our business, results of operations, financial condition and the market price of our common stock. 
+• 
+The Merger Agreement limits Callon’s ability to pursue alternatives to the Merger, may discourage certain other companies from making a favorable alternative transaction proposal, and, in specified circumstances, could require Callon to pay APA a termination fee. 
+• 
+Because the market price of APA common stock will fluctuate, Callon shareholders cannot be sure of the value of the shares of APA common stock they will receive in the Merger. In addition, because the Exchange Ratio is fixed, the number of shares of APA common stock to be received by Callon shareholders in the Merger will not change between now and the time the Merger is completed to reflect changes in the trading prices of APA common Stock or Callon common stock. 
+Risks Related to the Oil & Natural Gas Industry 
+• 
+Oil and natural gas prices are volatile, and substantial or extended declines in prices may adversely affect our results of operations and financial condition. 
+• 
+If oil and natural gas prices remain depressed for extended periods of time, we may be required to make significant downward adjustments to the net book value of our oil and natural gas properties. 
+• 
+Our business is subject to climate-related transition risks, including evolving climate change legislation, fuel conservation measures, technological advances and negative shift in market perception towards the oil and natural gas industry, which could result in increased operating expenses and capital costs, financial risks and potential reduction in demand for oil and natural gas. 
+• 
+Negative public perception of the oil and gas industry could have a material and adverse effect on us. 
+• 
+Increased scrutiny of ESG matters could have an adverse effect on our business, financial condition and results of operations and damage our reputation. 
+• 
+The unavailability or high cost of drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could materially and adversely affect our operations and profitability. 
+• 
+An excess supply of oil and natural gas in the market may in the future cause us to reduce production and shut-in our wells, any of which could adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures. 
+Operational Risks 
+• 
+Our operations are dependent on third-party service providers. 
+• 
+Our operations are subject to operating hazards inherent to our industry that may adversely impact our ability to conduct business, and we may not be fully insured against all such operating risks. 
+• 
+We are subject to physical risks arising from climate change, which may have a negative impact on our business and results of operations. 
+• 
+Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns. 
+• 
+Multi-well pad drilling may result in volatility in our operating results. 
+• 
+Restrictions on our ability to obtain, recycle and dispose of water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner. 
+Risks Related to Marketing and Transportation 
+• 
+Factors beyond our control, including the availability and capacity of gas processing facilities and pipelines and other transportation operations owned and operated by third parties, affect the marketability of our production. 
+• 
+We have entered into firm transportation contracts that require us to pay fixed sums of money regardless of quantities actually shipped. If we are unable to deliver the minimum quantities of production, such requirements could adversely affect our results of operations, financial position, and liquidity. 
+Risks Related to Our Reserves and Drilling Locations 
+• 
+Our estimated reserves are based on interpretations and assumptions that may be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. 
+• 
+Unless we replace our oil and gas reserves, our reserves and production will decline. 
+• 
+Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could prevent them from being drilled or delay their drilling. 
+27 
+• 
+The development of our PUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. 
+Risks Related to Technology 
+• 
+We may not be able to keep pace with technological developments in our industry. 
+• 
+Our business could be negatively affected by security threats. A cyberattack or similar incident could occur and result in information theft, data corruption, operational disruption, damage to our reputation or financial loss. 
+Risks Related to Our Indebtedness and Financial Position 
+• 
+Our business requires significant capital expenditures. 
+• 
+Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects. 
+• 
+Restrictive covenants in the agreements governing our indebtedness may limit our ability to respond to changes in market conditions or pursue business opportunities. 
+• 
+Adverse changes in our credit rating may affect our borrowing capacity and borrowing terms. 
+• 
+Our borrowings under our Credit Facility expose us to interest rate risk. 
+• 
+The ability to borrow under our Credit Facility may be restricted to an amount below the amount of borrowings outstanding thereunder or to a lesser amount than what we expect due to future borrowing base reductions or restrictions contained in our other debt agreements. 
+• 
+We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful. 
+• 
+We cannot be certain that we will be able to maintain or improve our leverage position. 
+Risks Related to Acquisitions 
+• 
+We may be unable to integrate successfully the operations of acquisitions with our operations, and we may not realize all the anticipated benefits of these acquisitions. 
+• 
+We may fail to fully identify problems with any properties we acquire, and as such, assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities. 
+Risks Related to Our Hedging Program 
+• 
+Our hedging program may limit potential gains from increases in commodity prices, result in losses, or be inadequate to protect us against continuing and prolonged declines in commodity prices. 
+• 
+Our production is not fully hedged, and we are exposed to fluctuations in oil, natural gas and NGL prices and will be affected by continuing and prolonged declines in oil, natural gas and NGL prices. 
+• 
+Our hedging transactions expose us to counterparty credit risk. 
+Legal and Regulatory Risks 
+• 
+We are subject to stringent and complex federal, state and local laws and regulations which require compliance that could result in substantial costs, delays or penalties. 
+• 
+Federal legislation and state and local legislative and regulatory initiatives relating to hydraulic fracturing and water disposal wells could result in increased costs and additional operating restrictions or delays. 
+• 
+Climate change legislation or regulations restricting emissions of GHG or requiring the reporting of GHG emissions or climate-related information could adversely impact our operating costs and demand for the oil and natural gas we produce. 
+• 
+Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. 
+Tax Risks 
+• 
+Our ability to use our existing net operating loss (“NOL”) carryforwards or other tax attributes could be limited. 
+• 
+Unanticipated changes in effective tax rates or adverse outcomes resulting from examination of our income or other tax returns could adversely affect our financial condition and results of operations. 
+• 
+Tax laws may change over time and such changes could adversely affect our business and financial condition. 
+Other Material Risks 
+• 
+Competitive industry conditions may negatively affect our ability to conduct operations. 
+• 
+All of our producing properties are located in the Permian of West Texas, making us vulnerable to risks associated with operating in only one geographic region. 
+• 
+The results of our planned development programs in new or emerging shale development areas and formations may be subject to more uncertainties than programs in more established areas and formations and may not meet our expectations for reserves or production. 
+• 
+The loss of key personnel, or inability to employ a sufficient number of qualified personnel, could adversely affect our ability to operate. 
+• 
+The inability of one or more of our customers to meet their obligations to us may adversely affect our financial results. 
+• 
+Our bylaws designate the Court of Chancery of the State of Delaware (the “Court of Chancery”) as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our shareholders, which could limit our shareholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, or other employees. 
+• 
+Provisions of our charter documents and Delaware law may inhibit a takeover, which could limit the price investors might be willing to pay in the future for our common stock. 
+• 
+We do not currently pay cash dividends on our common stock. 
+General Risk Factors 
+28 
+• 
+Declining general economic, business or industry conditions and inflation may have a material adverse effect on our results of operations, liquidity and financial condition. 
+• 
+We may be subject to the actions of activist shareholders. 
+• 
+Future sales of our common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of our common stock or other securities may dilute a shareholder’s ownership in us. 
+Risks Related to the Merger 
+While the Merger Agreement is in effect, we are subject to certain interim covenants. The Merger Agreement generally requires us to operate our business in the ordinary course, subject to certain exceptions, including as required by applicable law, pending consummation of the Merger, and subjects us to customary interim operating covenants that restrict us, without APA’s approval (such approval not to be unreasonably conditioned, withheld or delayed), from taking certain specified actions until the Merger is completed or the Merger Agreement is terminated in accordance with its terms. These restrictions could prevent us from pursuing certain business opportunities that may arise prior to the consummation of the Merger and may affect our ability to execute our business strategies and attain financial and other goals and may impact our financial condition, results of operations and cash flows. 
+The announcement and pendency of the Merger may result in disruptions to our business, and the Merger could divert management's attention, disrupt our relationships with third parties and employees, and result in negative publicity or legal proceedings, any of which could negatively impact our operating results and ongoing business. In connection with the pending Merger, our current and prospective employees may experience uncertainty about their future roles with us following the Merger, which may materially adversely affect our ability to attract and retain key personnel and other employees while the Merger is pending. Key employees may depart prior to the consummation of the Merger because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with us following the Merger. 
+The proposed Merger may cause disruptions to our business or business relationships with our existing and potential suppliers and other business partners, and this could have an adverse impact on our results of operations. Parties with which we have business relationships may experience uncertainty as to the future of such relationships and may delay or defer certain business decisions, seek alternative relationships with third parties, or seek to negotiate changes to or alter their present business relationships with us. Parties with whom we otherwise may have sought to establish business relationships may seek alternative relationships with third parties. 
+The pursuit of the proposed Merger has placed an increased burden on management and internal resources, which may have a negative impact on our ongoing business. It also diverts management’s time and attention from the day-to-day operation of our business, which could adversely affect our financial results. In addition, we have incurred and will continue to incur other significant costs, expenses and fees for professional services and other transaction costs in connection with the proposed Merger, and many of these fees and costs are payable regardless of whether or not the pending Merger is consummated. 
+Any of the foregoing, individually or in combination, could materially and adversely affect our business, our financial condition and our results of operations and prospects. 
+The Merger may not be completed within the expected timeframe, or at all, for a variety of reasons, including the possibility that the Merger Agreement is terminated, and the failure to complete the Merger could adversely affect our business, results of operations, financial condition and the market price of our common stock. There can be no assurance that the Merger will be completed in the expected timeframe or at all. The Merger Agreement contains a number of customary closing conditions that must be satisfied or waived prior to the completion of the Merger, including, among others, (i) the receipt of the required approvals from Callon shareholders and APA shareholders and (ii) the absence of any governmental order or law prohibiting consummation of the Merger. 
+Many of the conditions to completion of the merger are not within either Callon’s or APA’s control. If any of these closing conditions are not satisfied or waived prior to October 3, 2024 (or such date as extended pursuant to the terms set forth in the Merger Agreement), it is possible that the Merger Agreement may be terminated. The Merger Agreement also provides both Callon and APA with certain termination rights. Furthermore, the requirements for obtaining the required clearances and approvals could delay the completion of the Merger for a significant period of time or prevent the Merger from occurring. There can be no assurance that all required regulatory approvals will be obtained or obtained prior to the termination date. 
+If the Merger is not consummated within the expected time frame or at all, we may be subject to a number of material risks. The price of our common stock may decline to the extent that current market prices reflect a market assumption that the Merger will be completed. In addition, some costs, expenses and fees related to the Merger must be paid whether or not the Merger is completed, and we have incurred, and will continue to incur, significant costs, expenses and fees for professional services and other transaction costs in connection with the proposed Merger, as well as the direction of management resources towards the Merger, for which we will have received little or no benefit if the closing of the Merger does not occur. We may also experience negative reactions from our shareholders and other investors, employees and other parties with which we maintain business relationships. In addition, if the Merger Agreement is terminated, in specified circumstances, we may be required to pay a termination fee. If the Merger is not 
+29 
+consummated, there can be no assurance that any other transaction acceptable to us will be offered or that our business, prospects or results of operations will not be adversely affected. 
+Litigation relating to the Merger could result in an injunction preventing the completion of the Merger and/or substantial costs to us. Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into acquisition, merger or other business combination agreements. Even if such a lawsuit is without merit, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on our liquidity and financial condition. Such lawsuits could also seek, among other things, injunctive relief or other equitable relief, including a request to enjoin us and APA from consummating the Merger. 
+The Merger Agreement limits Callon’s ability to pursue alternatives to the Merger, may discourage certain other companies from making a favorable alternative transaction proposal, and, in specified circumstances, could require Callon to pay APA a termination fee. The Merger Agreement contains certain provisions that restrict each of APA’s and Callon’s ability to initiate, solicit, knowingly encourage, or knowingly facilitate any inquiry or the making of any proposal or offer that constitutes, or would reasonably be expected to result in, a competing proposal with respect to APA or Callon, as applicable, and APA and Callon have each agreed to certain terms and conditions relating to their ability to engage in, continue, or otherwise participate in any discussions with respect to, provide any third party confidential information with respect to, or enter into any acquisition agreement with respect to certain unsolicited proposals that constitute or are reasonably likely to lead to a competing proposal. The Merger Agreement further provides that under specified circumstances, including after receipt of certain alternative acquisition proposals, each of APA and Callon may be required to pay the other a cash termination fee equal to $170 million (if APA is the payor) or $85 million (if Callon is the payor). These and other provisions in the Merger Agreement could discourage a potential third party acquirer or other strategic transaction partner that might have an interest in acquiring all or a significant portion of Callon from considering or pursuing an alternative transaction with Callon or proposing such a transaction, even if it were prepared to pay consideration with a higher per share value than the total value proposed to be paid or received in the Merger. These provisions might also result in a potential third-party acquirer or other strategic transaction partner proposing to pay a lower price than it might otherwise have proposed to pay because of the added expense of the termination fee or expense reimbursement that may become payable in certain circumstances. 
+Even if the Merger is completed, the combined company may fail to realize the anticipated benefits of the Merger and the integration of the businesses and operations of APA and Callon may not be as successful as anticipated. The success of the Merger will depend, in part, on the combined company’s ability to realize the anticipated benefits and cost savings from combining our and APA’s businesses, and there can be no assurance that the combined company will be able to successfully integrate us or otherwise realize the expected benefits of the Merger. Difficulties in integrating us into the combined company may result in the combined company performing differently than expected, in operational challenges or in the failure to realize anticipated expense-related efficiencies. Potential difficulties that may be encountered in the integration process include harmonizing the companies’ operating practices, employee development and compensation programs, internal controls, and other policies, procedures, and processes; maintaining existing agreements with customers, providers, and vendors or business partners and avoiding delays in entering into new agreements with prospective customers, providers, and vendors or business partners; addressing possible differences in business backgrounds, corporate cultures, and management philosophies; consolidating the companies’ operating, administrative, and information technology infrastructure and financial systems; and coordinating distribution and marketing efforts. 
+Completion of the Merger may trigger change in control or other provisions in certain agreements to which Callon is a party. If APA and Callon are unable to negotiate waivers of those provisions, the counterparties may exercise their rights and remedies under the agreements, potentially terminating the agreements, or seeking monetary damages. Even if APA and Callon are able to negotiate waivers, the counterparties may require a fee for such waivers or seek to renegotiate the agreements on terms less favorable to Callon. 
+Our shareholders will have a reduced ownership and voting interest after the Merger and will exercise less influence over the policies of the combined company than they now have on the policies of Callon. Immediately after the Merger is completed, it is expected that our current shareholders will own approximately 19% of APA’s outstanding common stock and current APA shareholders will own approximately 81% of APA’s outstanding common stock. As a result, our current shareholders will have less influence on the management and policies of the combined company than they now have on the management and policies of Callon. 
+Because the market price of APA common stock will fluctuate, Callon shareholders cannot be sure of the value of the shares of APA common stock they will receive in the Merger. In addition, because the Exchange Ratio is fixed, the number of shares of APA common stock to be received by Callon shareholders in the Merger will not change between now and the time the Merger is completed to reflect changes in the trading prices of APA common Stock or Callon common stock. As a result of the Merger, each eligible share of Callon common stock will be converted automatically into the right to receive, without interest, 1.0425 shares of APA common stock, with cash paid in lieu of the issuance of any fractional shares of APA common stock. The Exchange Ratio is fixed, which means that it will not change between now and the closing date, regardless of whether the market price of either APA common stock or Callon common stock changes. Therefore, the value of the Merger consideration will depend on the market price of APA common stock at the Effective Time. The market price of APA common stock has fluctuated since the date of the announcement of the parties’ entry into the Merger Agreement and will continue to fluctuate. 
+30 
+The market price of shares of APA common stock may decline in the future as a result of the sale of shares of APA common stock held by former Callon shareholders or APA’s other shareholders. Following their receipt of shares of APA common stock as consideration in the Merger, our shareholders may seek to sell the shares of APA common stock delivered to them, and the Merger Agreement contains no restriction on the ability of our shareholders to sell such shares of APA common stock following completion of the Merger. Other shareholders of APA may also seek to sell shares of APA common stock held by them following, or in anticipation of, completion of the Merger. These sales (or the perception that these sales may occur), coupled with the increase in the outstanding number of shares of APA common stock to be issued in the Merger, may affect the market for, and the market price of, APA common stock in an adverse manner. 
+Risks Related to the Oil & Natural Gas Industry 
+Oil and natural gas prices are volatile, and substantial or extended declines in prices may adversely affect our results of operations and financial condition. Our success is highly dependent on prices for oil and natural gas, which have in recent years been, and we expect will continue to be, extremely volatile. During the three years ended December 31, 2023, NYMEX WTI prices ranged from a high of $123.64 per barrel on March 8, 2022 to a low of $47.47 per barrel on January 4, 2021, and NYMEX Henry Hub prices ranged from a high of $23.86 per MMBtu on February 17, 2021 to a low of $1.74 per MMBtu on June 2, 2023. Prices were particularly volatile in 2020 and 2021, with five-year highs occurring in 2021 and five-year lows occurring in 2020, as a result of multiple significant factors impacting supply and demand in the global oil and natural gas markets, including those relating to the COVID-19 global pandemic. The prices of oil and natural gas depend on factors we cannot control, such as macro-economic conditions, levels of production, domestic and worldwide inventories, demand for oil and natural gas, the capacity of U.S. and international refiners to use U.S. supplies of oil, natural gas and NGLs, relative price and availability of alternative forms of energy, actions by non-governmental organizations, OPEC and other countries, legislative and regulatory actions, trade embargoes or sanctions, technology developments impacting energy consumption and energy supply, and weather. These factors make it extremely difficult to predict future oil, natural gas and NGLs price movements with any certainty. We make price assumptions that are used for planning purposes, and a significant portion of our cash outlays, including rent, salaries and non-cancelable capital commitments, are largely fixed in nature. Accordingly, if commodity prices are below the expectations on which these commitments were based, our financial results are likely to be adversely and disproportionately affected because these cash outlays are not variable in the short term and cannot be quickly reduced to respond to unanticipated decreases in commodity prices. 
+In general, prices of oil, natural gas, and NGLs affect the following aspects of our business: our revenues, cash flows, earnings and returns; our ability to attract capital to finance our operations and the cost of the capital; the amount we are allowed to borrow under our Credit Facility; the profit or loss we incur in exploring for and developing our reserves; and the value of our oil and natural gas properties. 
+A substantial or extended decline in commodity prices may also reduce the amount of oil and natural gas that we can produce economically and cause a significant portion of our development projects to become uneconomic. This may result in our having to make significant downward adjustments to our estimated proved reserves. A reduction in production could also result in a shortfall in expected cash flows and require us to reduce capital spending, which could negatively affect our ability to replace our production and our future rate of growth, or require us to borrow funds to cover any such shortfall, which we may be unable to obtain at such time on satisfactory terms. Additionally, a sustained period of weakness in oil, natural gas and NGLs prices, and the resultant effects of such prices on our drilling economics and ability to raise capital, would require us to reevaluate and postpone or eliminate additional drilling. 
+Additionally, if we are required to curtail our drilling program, we may be unable to continue to hold leases that are scheduled to expire, which may further reduce our reserves. As a result, if oil, natural gas and/or NGL prices experience a sustained period of weakness, our future business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures may be materially and adversely affected. 
+If oil and natural gas prices remain depressed for extended periods of time, we may be required to make significant downward adjustments to the net book value of our oil and natural gas properties. Under the successful efforts method, we review our proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their net book value may have occurred. In addition, we evaluate significant unproved oil and gas property costs for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or changes in future plans to develop acreage. Unproved oil and gas properties that are not individually significant are aggregated by asset group, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on our historical experience or other information, including current drilling plans and existing geological data. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the net book value of our oil and gas properties, which may result in a decrease in the amount available under the Credit Facility. See “Note 2 – Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements as well as the Supplemental Information on Oil and Natural Gas Operations for additional information. 
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+Our business is subject to climate-related transition risks, including evolving climate change legislation, fuel conservation measures, technological advances and negative shift in market perception towards the oil and natural gas industry, which could result in increased operating expenses and capital costs, financial risks and potential reduction in demand for oil and natural gas. Increasing attention from governmental and regulatory bodies, investors, consumers, industry and other stakeholders on combating climate change, together with changes in consumer and industrial/commercial behavior, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary climate-related disclosures, preferences and attitudes with respect to the generation and consumption of energy, the use of hydrocarbons, and the use of products manufactured with, or powered by, hydrocarbons, may result in the enactment of climate change-related regulations, policies and initiatives (at the government, regulator, corporate and/or investor community levels), including alternative energy requirements, new fuel consumption standards, energy conservation and emissions reductions measures and responsible energy development; technological advances with respect to the generation, transmission, storage and consumption of energy (including advances in wind, solar and hydrogen power, as well as battery technology); increased availability of, and increased demand from consumers and industry for, energy sources other than oil and natural gas (including wind, solar, nuclear, and geothermal sources as well as electric vehicles); and development of, and increased demand from consumers and industry for, lower-emission products and services (including electric vehicles and renewable residential and commercial power supplies) as well as more efficient products and services. For further discussions regarding risk related to technological developments, see “—We may not be able to keep pace with technological developments in our industry.” These developments may in the future adversely affect the demand for products manufactured with, or powered by, petroleum products, as well as the demand for, and in turn the prices of, oil and natural gas products. Such developments may also adversely impact, among other things, our revenues, stock price and access to capital markets, and the availability to us of necessary third-party services and facilities that we rely on, which may increase our operational costs and adversely affect our ability to successfully carry out our business strategy. Climate change-related developments may also impact the market prices of or our access to raw materials such as energy and water and therefore result in increased costs to our business. 
+More broadly, the enactment of climate change-related regulations, policies and initiatives across the market at the government, corporate, and/or investor community levels may in the future result in increases in our compliance costs and other operating costs and have other adverse effects (e.g., greater potential for governmental investigations or litigation). For further discussion regarding the risks posed to us by climate change-related regulations, policies and initiatives, negative public perception of the oil and gas industry, and increasing scrutiny of ESG matters, see the discussions below in “—Negative public perception of the oil and gas industry could have a material and adverse effect on us,” “—Increased scrutiny of ESG matters could have an adverse effect on our business, financial condition and results of operations and damage our reputation,” and “—Climate change legislation or regulations restricting emissions of GHG or requiring the reporting of GHG emissions or climate-related information could adversely impact our operating costs and demand for the oil and natural gas we produce.” 
+Negative public perception of the oil and gas industry could have a material and adverse effect on us. Opposition toward oil and natural gas drilling and development activity has been growing globally and is particularly pronounced in the United States. Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about climate change may lead to increased reputational and litigation risk and regulatory, legislative and judicial scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. Companies in the oil and natural gas industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, human rights, climate change, environmental matters, sustainability, and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain operations such as drilling and development. Activism could materially and adversely impact our ability to operate our business and raise capital. The foregoing factors may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. In addition, various officials and candidates at the federal, state and local levels, have made climate-related pledges or proposed banning hydraulic fracturing altogether. 
+In addition, some parties have initiated public nuisance claims under federal or state common law against certain companies involved in the production of oil and natural gas, or claims alleging that the companies have been aware of the adverse effects of climate change for some time but failed to adequately disclose such impacts to their investors or customers. Although our business is not a party to any such litigation, we could be named in actions making similar allegations, which could lead to costs and materially impact our financial condition in an adverse way. 
+Negative perceptions regarding our industry and reputational risks may also in the future adversely affect our ability to successfully carry out our business strategy by adversely affecting our access to capital. Certain segments of the investor community have developed negative sentiment towards investing in our industry. Parties concerned about the potential effects of climate change have directed their attention at sources of financing for energy companies, which has resulted in certain financial institutions, funds and other capital providers restricting or eliminating their investment in oil and natural gas activities. There is also a risk that financial institutions may be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector, and some investors, including investment advisors and certain sovereign wealth funds, pension funds, university endowments and family foundations, have stated policies to disinvest in the oil and gas sector based on their social and environmental considerations. Further, 
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+certain investment banks and asset managers based both domestically and internationally have announced that they are adopting climate change guidelines for their banking and investing activities. Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas production and related infrastructure projects. Institutional lenders who provide financing to companies in the energy sector have also become more attentive to sustainable lending practices, and some may elect not to provide traditional energy producers or companies that support such producers with funding. Such developments, including ESG activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also potentially result in an increase in our expenses and a reduction of revenues and available capital funding for potential development projects, impacting our future financial results. 
+Increased scrutiny of ESG matters could have an adverse effect on our business, financial condition and results of operations and damage our reputation. In recent years, companies across all industries are facing increasing scrutiny from a variety of stakeholders, including investor advocacy groups, proxy advisory firms, certain institutional investors and lenders, investment funds and other influential investors and rating agencies, related to their ESG and sustainability practices. If we do not adapt to or comply with investor or other stakeholder expectations and standards on ESG matters (or meet sustainability goals and targets that we have set), as they continue to evolve, or if we are perceived to have not responded appropriately or quickly enough to growing concern for ESG and sustainability issues, regardless of whether there is a regulatory or legal requirement to do so, we may suffer from reputational damage and our business, financial condition and/or stock price could be materially and adversely affected. 
+In addition, the Company’s continuing efforts to research, establish, accomplish and accurately report on the implementation of our ESG strategy, including any specific ESG objectives, may also create additional operational risks and expenses and expose us to reputational, legal and other risks. While we create and publish voluntary disclosures regarding ESG matters from time to time, some of the statements in those voluntary disclosures may be based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. Further, failure or a perception (whether or not valid) of failure to implement our ESG strategy or achieve sustainability goals and targets we have set, including emissions reduction goals, could damage our reputation, causing our investors or consumers to lose confidence in our Company, and negatively impact our business. Our continuing efforts to research, establish, accomplish and accurately report on the implementation of our ESG strategy, including any ESG goals, may also create additional operational risks and expenses and expose us to reputational, legal and other risks. For example, growing interest on the part of investors and regulators in ESG factors and increased demand for, and scrutiny of, ESG-related disclosure by stakeholders has also increased the risk that companies could be perceived as, or accused of, making inaccurate or misleading statements regarding their ESG-related claims, goal, targets, efforts or initiatives, often referred to as "greenwashing." Such perception or accusation could damage our reputation and result in litigation or regulatory actions. In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital. 
+Further, our operations, projects and growth opportunities require us to have strong relationships with various key stakeholders, including our shareholders, employees, suppliers, customers, local communities and others. We may face pressure from stakeholders, many of whom are increasingly focused on climate change, to prioritize sustainable energy practices, reduce our carbon footprint and promote sustainability while at the same time remaining a successfully operating public company. If we do not successfully manage expectations across these varied stakeholder interests, it could erode stakeholder trust and thereby affect our brand and reputation. Such erosion of confidence could negatively impact our business through decreased demand and growth opportunities, delays in projects, increased legal action and regulatory oversight, adverse press coverage and other adverse public statements, difficulty hiring and retaining top talent, difficulty obtaining necessary approvals and permits from governments and regulatory agencies on a timely basis and on acceptable terms and difficulty securing investors and access to capital. 
+The unavailability or high cost of drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could materially and adversely affect our operations and profitability. From time to time, during periods of increasing oil and natural gas prices and in periods in which the levels of exploration and production increase, our industry experiences a shortage of drilling and workover rigs, other equipment, pipes, materials and supplies, water and qualified personnel. As a result of such shortage, the costs and delivery times of rigs, equipment and supplies often increase substantially, as well as the wages and costs of drilling rig crews and other experienced personnel and oilfield services, while the quality of these services and equipment may suffer. This impact may be magnified to the extent that the Company's ability to participate in the commodity price increases is limited by its derivative risk management activities. Cost increases in and shortages of such resources may also result from a variety of other factors beyond our control, such as general inflationary pressures, transportation constraints, 
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+and increases in the cost of necessary inputs such as electricity, steel and other raw materials, including as a result of increased tariffs or geopolitical issues. 
+An excess supply of oil and natural gas in the market may in the future cause us to reduce production and shut-in our wells, any of which could adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures. An excess supply of oil and natural gas in the market may result in transportation and storage capacity constraints. If, in the future, our transportation or storage arrangements become constrained or unavailable, we may incur significant operational costs if there is an increase in price for services or we may be required to shut-in or curtail production or flare our natural gas. If we were required to shut-in wells, we might also be obligated to pay certain demand charges for gathering and processing services and firm transportation charges for pipeline capacity we have reserved. Further, any prolonged shut-in of our wells may result in materially decreased well productivity once we are able to resume operations, and any cessation of drilling and development of our acreage could result in the expiration, in whole or in part, of our leases. All of these impacts may adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures. 
+Operational Risks 
+Our operations are dependent on third-party service providers. We contract with third-party service providers to support our operations. These contracted services are generally provided pursuant to master services agreements entered into between the third-party service providers and our operating subsidiaries. Although we have our own employees, our ability to conduct operations and generate revenues is dependent on the availability and performance of those third-party service providers and their compliance with the terms of their respective master service agreements. We cannot guarantee that we will be successful in either retaining the services of our current third-party service providers or contracting with alternative service providers in the event that our current contractors discontinue providing services to us or fail to meet their obligations under their respective master services agreements. Any failure to retain the services of our current service providers or locate alternatives will negatively affect our ability to generate revenues and continue and expand our operations. 
+Our operations are subject to operating hazards inherent to our industry that may adversely impact our ability to conduct business, and we may not be fully insured against all such operating risks. The operating hazards in exploring for and producing oil and natural gas include: encountering unexpected subsurface conditions that cause damage to equipment or personal injury, including loss of life; equipment failures that curtail or stop production or cause severe damage to or destruction of property, natural resources or other equipment; blowouts or other damages to the productive formations of our reserves that require a well to be re-drilled or other corrective action to be taken; and storms and other extreme weather conditions that cause damages to our production facilities or wells. Because of these or other events, we could experience environmental hazards, including release of oil and natural gas from spills, natural gas leaks, accidental leakage of toxic or hazardous materials, such as petroleum liquids, drilling fluids or fracturing fluids, including chemical additives, underground migration, and ruptures. If we experience any of these problems, we could incur substantial losses in excess of our insurance coverage. 
+The occurrence of a significant event or claim, not fully insured or indemnified against, could have a material adverse effect on our financial condition and operations. In accordance with industry practice, we maintain insurance against some of the operating risks to which our business is exposed. Also, no assurance can be given that we will be able to maintain insurance in the future at rates we consider reasonable to cover our possible losses from operating hazards and we may elect no or minimal insurance coverage. 
+We are subject to physical risks arising from climate change, which may have a negative impact on our business and results of operations. Most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere and climate change may produce significant physical effects on weather conditions, such as increased frequency and severity of droughts, storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for oil or natural gas products or cause us to incur significant costs in preparing for or responding to the effects of climatic events themselves, which may not be fully insured. Potential adverse effects could include disruption of our production activities, including, for example, damages to our facilities from winds or floods, increases in our costs of operation, or reductions in the efficiency of our operations, impacts on our workforce, supply chain, or distribution chain, as well as potentially increased costs for or difficulty procuring consistent levels of insurance coverages in the aftermath of such effects. The physical effects of climate change may generally result in reduced availability of relevant insurance coverage on the market. Any of these effects could have an adverse effect on our assets and operations. Our ability to mitigate the adverse physical impacts of climate change depends in part upon our disaster preparedness and response and business continuity planning. Further, energy needs could increase or decrease as a result of extreme weather conditions depending on the duration and magnitude of any such climate changes. Increased energy use due to weather changes may require us to invest in additional equipment to serve increased demand. A decrease in energy use due to weather changes may affect our financial condition through decreased revenues. The effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have 
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+on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations. 
+Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns. Exploration, development, drilling and production activities are subject to many risks. We may invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that any leasehold acreage acquired will be profitably developed, that new wells drilled will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, including wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, we may not be successful in controlling our drilling and production costs to improve our overall return and wells that are profitable may not achieve our targeted rate of return. Wells may have production decline rates that are greater than anticipated. Future drilling and completion efforts may impact production from existing wells, and parent-child effects may impact future well productivity as a result of timing, spacing proximity or other factors. Failure to conduct our oil and gas operations in a profitable manner may result in write-downs of our proved reserves quantities, impairment of our oil and gas properties, and a write-down in the net book value of our unproved properties, and over time may adversely affect our growth, revenues and cash flows. 
+Multi-well pad drilling may result in volatility in our operating results. We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production. In addition, problems affecting a single well could adversely affect production from all of the wells on the pad, which would further cause delays in the scheduled commencement of production or interruptions in ongoing production. These delays or interruptions may cause volatility in our operating results. Further, any delay, reduction or curtailment of our development and producing operations due to operational delays caused by multi-well pad drilling could result in the loss of acreage through lease expirations. 
+Restrictions on our ability to obtain, recycle and dispose of water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner. Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to secure water from local landowners and other third-party sources for use in our operations. If drought conditions were to occur or demand for water were to outpace supply, our ability to obtain water could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. Along with the risks of other extreme weather events, drought risk, in particular, is likely increased by climate change. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows. In addition, significant amounts of water are produced in our operations. Inadequate access to or availability of water recycling or water disposal facilities could adversely affect our production volumes or significantly increase the cost of our operations. 
+Risks Related to Marketing and Transportation 
+Factors beyond our control, including the availability and capacity of gas processing facilities and pipelines and other transportation operations owned and operated by third parties, affect the marketability of our production. The ability to market oil and natural gas from our wells depends upon numerous factors beyond our control. A significant factor in our ability to market our production is the availability and capacity of gas processing facilities and pipeline and other transportation operations, including trucking services, owned and operated by third parties. These facilities and services may be temporarily unavailable to us due to market conditions, physical or mechanical disruption, weather, lack of contracted capacity, available manpower, pipeline safety issues, or other reasons. In certain newer development areas, processing and transportation facilities and services may not be sufficient to accommodate potential production and it may be necessary for new interstate and intrastate pipelines and gathering systems to be built. In addition, we or parties that we utilize might not be able to connect new wells that we complete to pipelines. Our failure to obtain access to processing and transportation facilities and services in a timely manner and on acceptable terms could materially harm our business. We may be required to shut in wells for lack of a market or because of inadequate or unavailable processing or transportation capacity. If that were to occur, we would be unable to realize revenue from those wells until transportation arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells, we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. If we were required to shut in our production for long periods of time due to lack of transportation capacity, it would have a material adverse effect on our business, financial condition, results of operations and cash flows. 
+Other factors that affect our ability to market our production include: 
+• the extent of domestic production and imports/exports of oil and natural gas; 
+• federal regulations authorizing exports of LNG, the development of new LNG export facilities under construction in the U.S. Gulf Coast region, and the timing of the first LNG exports from such facilities; 
+• the construction of new pipelines capable of exporting U.S. natural gas to Mexico and transporting Permian oil production to the Gulf Coast; 
+• the proximity of hydrocarbon production to pipelines and gathering infrastructure; 
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+• the demand for oil and natural gas by utilities and other end users; 
+• the availability of alternative fuel sources; 
+• the effects of inclement weather, including the effects of chronic and acute climate events associated with the effects of global climate change; and 
+• state and federal regulation of oil, natural gas and NGL marketing and transportation. 
+We have entered into firm transportation contracts that require us to pay fixed sums of money regardless of quantities actually shipped. If we are unable to deliver the minimum quantities of production, such requirements could adversely affect our results of operations, financial position, and liquidity. We have entered into firm transportation agreements for a portion of our production in certain areas in order to improve our ability, and that of our purchasers, to successfully market our production. We may also enter into firm transportation arrangements for additional production in the future. These firm transportation agreements may be more costly than interruptible or short-term transportation agreements. Additionally, these agreements obligate us to pay fees on minimum volumes regardless of actual throughput. If we have insufficient production to meet the minimum volumes, the requirements to pay for quantities not delivered could have an impact on our results of operations, financial position, and liquidity. 
+Risks Related to Our Reserves and Drilling Locations 
+Our estimated reserves are based on interpretations and assumptions that may be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. This 2023 Annual Report on Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves. The process of estimating oil and natural gas reserves is complex and requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. These assumptions include those required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. 
+Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from the estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this 2023 Annual Report on Form 10-K. Additionally, estimates of reserves and future cash flows may be subject to material downward or upward revisions, based on production history, development drilling and exploration activities and prices of oil and natural gas. 
+You should not assume that any PV-10 of our estimated proved reserves contained in this 2023 Annual Report on Form 10-K represents the market value of our oil and natural gas reserves. We base the PV-10 from our estimated proved reserves at December 31, 2023 on the 12-Month Average Realized Prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures, the rate and timing of production, and changes in governmental regulations or taxes. Recovery of PUDs generally requires significant capital expenditures and successful drilling operations. Our reserve estimates include the assumption that we will make significant capital expenditures to develop these PUDs and the actual costs, development schedule, and results associated with these properties may not be as estimated. In addition, the discount factor used to calculate PV-10 may not be appropriate based on our cost of capital from time to time and the risks associated with our business and the oil and gas industry. 
+Unless we replace our oil and gas reserves, our reserves and production will decline. Our future oil and gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our production, revenues, reserve quantities and cash flows will decline. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. We may not be successful in finding, developing or acquiring additional reserves, and our efforts may not be economic. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be limited to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. 
+Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could prevent them from being drilled or delay their drilling. Our management team has identified drilling locations as an estimation of our future development activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these identified drilling locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, availability and cost of drilling, completion and production services and equipment, lease expirations, regulatory approvals, and other factors discussed in these risk factors. Because of these uncertain factors, we do not know if the identified drilling locations will ever be drilled or if we will be able to produce oil or natural gas from these drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the identified locations are located, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified. 
+The development of our PUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. Developing PUDs requires significant capital expenditures and successful drilling operations, and a substantial amount of 
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+our proved reserves are PUDs which may not be ultimately developed or produced. Approximately 36% of our total estimated proved reserves as of December 31, 2023 were PUDs. The reserve data included in the reserve reports of our independent petroleum engineers assume significant capital expenditures will be made to develop such reserves. We cannot be certain that the estimated capital expenditures to develop these reserves are accurate, that development will occur as scheduled, or that the results of such development will be as estimated. We may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including: unexpected drilling conditions; pressure or irregularities in formations; lack of proximity to and shortage of capacity of transportation facilities; equipment failures or accidents and shortages or delays in the availability of drilling rigs, equipment, personnel and services; the availability of capital; and compliance with governmental requirements. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the future net revenues of our estimated PUDs and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves. 
+Risks Related to Technology 
+We may not be able to keep pace with technological developments in our industry. The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, including technological advances in fuel economy and energy generation devices or other technological advances that could reduce demand for oil and natural gas, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement new technologies at substantial costs. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected. 
+Our business could be negatively affected by security threats. A cyberattack or similar incident could occur and result in information theft, data corruption, operational disruption, damage to our reputation or financial loss. The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing, transportation and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, manage operations, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third-party partners. Our technologies, systems, networks, seismic data, reserves information or other proprietary information, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or could otherwise lead to the disruption of our business operations or other operational disruptions in our exploration or production operations. Cyberattacks are becoming more sophisticated and certain cyber incidents, such as surveillance, may remain undetected for an extended period and could lead to disruptions in critical systems or the unauthorized release of confidential or otherwise protected information. These events could lead to financial losses from remedial actions, loss of business, disruption of operations, damage to our reputation or potential liability. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyberattack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. Cyber incidents have increased, and the U.S. government has issued warnings indicating that energy assets may be specific targets of cybersecurity threats. Our systems and insurance coverage for protecting against cybersecurity risks may not be sufficient. Further, as cyberattacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyberattacks. 
+Risks Related to Our Indebtedness and Financial Position 
+Our business requires significant capital expenditures. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. We intend to fund our capital expenditures through a combination of cash flows from operations and, if needed, borrowings from financial institutions, the sale of debt and equity securities, and asset divestitures. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, participation of non-operating working interest owners, the cost and availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. 
+If the ability to borrow under our Credit Facility or our cash flows from operations decrease, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. The failure to obtain additional financing on terms acceptable to us, or at all, could result in a curtailment of our development activities and could adversely affect our business, financial condition and results of operations. 
+Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects. As of December 31, 2023, we had aggregate outstanding indebtedness of approximately $1.9 billion. Our amount of indebtedness could affect our operations in many ways, including: 
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+• requiring us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to fund our operations and other business activities as well as any potential returns to shareholders; 
+• limiting management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; 
+• increasing our vulnerability to downturns and adverse developments in our business and the economy; 
+• limiting our ability to access the capital markets to raise capital on favorable terms, to borrow under our Credit Facility or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness; 
+• making it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; 
+• making us vulnerable to increases in interest rates as the interest we pay on our indebtedness under our Credit Facility varies with prevailing interest rates; 
+• placing us at a competitive disadvantage relative to competitors with lower levels of indebtedness or less restrictive terms governing their indebtedness; and 
+• making it more difficult for us to satisfy our obligations under our senior notes or other debt and increasing the risk that we may default on our debt obligations. 
+Restrictive covenants in the agreements governing our indebtedness may limit our ability to respond to changes in market conditions or pursue business opportunities. Our Credit Facility and the indentures governing our senior notes contain restrictive covenants that limit our ability to, among other things: incur additional indebtedness including secured indebtedness; make investments; merge or consolidate with another entity; pay dividends or make certain other payments; hedge future production or interest rates; create liens that secure indebtedness; repurchase securities; sell assets; or engage in certain other transactions without the prior consent of the holders or lenders. As a result of these covenants, we are limited in the manner in which we conduct our business and we may be unable to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business. 
+In addition, our Credit Facility requires us to maintain certain financial ratios and to make certain required payments of principal, premium, if any, and interest. If we fail to comply with these provisions or other financial and operating covenants in the Credit Facility or the indentures governing our senior notes, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our Credit Facility could elect to terminate their commitments thereunder, cease making further loans and institute foreclosure proceedings against our assets; and we could be forced into bankruptcy or liquidation. 
+Adverse changes in our credit rating may affect our borrowing capacity and borrowing terms. Our outstanding debt is periodically rated by nationally recognized credit rating agencies. The credit ratings are based on our operating performance, liquidity and leverage ratios, overall financial position, and other factors viewed by the credit rating agencies as relevant to our industry and the economic outlook. Our credit rating may affect the amount and timing of availability of capital we can access, as well as the terms of any financing we may obtain. Because we rely in part on debt financing to fund growth, adverse changes in our credit rating may have a negative effect on our future growth. 
+Our borrowings under our Credit Facility expose us to interest rate risk. Our borrowings under our Credit Facility make us vulnerable to increases in interest rates as they bear interest at a rate elected by us that is based on the prime, SOFR or federal funds rate plus margins ranging from 0.75% to 2.75%, depending on the rate used and the amount of the loan outstanding in relation to the elected commitment. 
+The ability to borrow under our Credit Facility may be restricted to an amount below the amount of borrowings outstanding thereunder or to a lesser amount than what we expect due to future borrowing base reductions or restrictions contained in our other debt agreements. The borrowing base and elected commitment amount under our Credit Facility is currently $2.0 billion and $1.5 billion, respectively, and as of December 31, 2023, we had an aggregate principal balance of $365.0 million outstanding thereunder. Our borrowing base is subject to redeterminations semi-annually, and a future decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations may cause us to not be able to access adequate funding under the Credit Facility. The lenders have sole discretion in determining the amount of the borrowing base and may cause our borrowing base to be redetermined to a materially lower amount, including to below our outstanding borrowings as of such redetermination. In addition, our other debt agreements contain restrictions on the incurrence of additional debt and liens which could limit our ability to borrow under our Credit Facility. If our borrowing base were to be reduced, or if covenants in our indentures restrict our ability to access funding under the Credit Facility, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness. In addition, we cannot borrow amounts above the elected commitments, even if the borrowing base is greater, without new commitments being obtained from the lenders for such incremental amounts above the elected commitments. In the event the amount outstanding under our Credit Facility exceeds the elected commitments, we must repay such amounts 
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+immediately in cash. In the event the amount outstanding under our Credit Facility exceeds the redetermined borrowing base, we are required to either (i) grant liens on additional oil and gas properties (not previously evaluated in determining such borrowing base) with a value equal to or greater than such excess, (ii) repay such excess borrowings over six monthly installments, or (iii) elect a combination of options in clauses (i) and (ii). We may not have sufficient funds to make any required repayment. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, an event of default would occur under our Credit Facility. 
+We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful. Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to certain financial, economic, competitive and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. 
+If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Also, we may not be able to consummate dispositions at such time on terms acceptable to us or at all, and the proceeds of any such dispositions may not be adequate to meet such debt service obligations. Furthermore, any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. In addition, the terms of existing or future debt instruments may restrict us from adopting some of these alternatives. For example, our Credit Facility currently restricts our ability to dispose of assets and our use of the proceeds from such disposition. 
+Any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. 
+We cannot be certain that we will be able to maintain or improve our leverage position. An element of our business strategy involves maintaining a disciplined approach to financial management. However, we are also seeking to acquire, exploit and develop additional reserves that may require the incurrence of additional indebtedness. Although we will seek to maintain or improve our leverage position, our ability to maintain or reduce our level of indebtedness depends on a variety of factors, including future performance and our future debt financing needs. General economic conditions, oil and natural gas prices and financial, business and other factors will also affect our ability to maintain or improve our leverage position. Many of these factors are beyond our control. 
+Risks Related to Acquisitions 
+We may be unable to integrate successfully the operations of acquisitions with our operations, and we may not realize all the anticipated benefits of these acquisitions. We have completed, and may in the future complete, acquisitions that include undeveloped acreage. We can offer no assurance that we will achieve the desired profitability from our recent acquisitions or from any acquisitions we may complete in the future. In addition, failure to integrate future acquisitions successfully could adversely affect our financial condition and results of operations. 
+Our acquisitions may involve numerous risks, including those related to: 
+• operating a larger, more complex combined organization and adding operations; 
+• assimilating the assets, data, and operations of the acquired business, especially if the assets acquired are in a new geographic area; 
+• acquired oil and natural gas reserves not being of the anticipated magnitude or as developed as anticipated; 
+• the loss of significant key employees, including from the acquired business; 
+• the inability to obtain satisfactory title to the assets we acquire; 
+• a decrease in our liquidity if we use a portion of our available cash to finance acquisitions; 
+• a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions; 
+• the diversion of management’s attention from other business concerns, which could result in, among other things, performance shortfalls; 
+• the failure to realize expected profitability or growth; 
+• the failure to realize expected synergies and cost savings; 
+• coordinating geographically disparate organizations, systems, data, and facilities; 
+• coordinating or consolidating corporate and administrative functions; 
+• inconsistencies in standards controls, procedures and policies; and 
+• integrating relationships with customers, vendors and business partners. 
+Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. The elimination of duplicative costs, as well as the 
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+realization of other efficiencies related to the integration of our two companies, may not initially offset integration-related costs or achieve a net benefit in the near term or at all. 
+If we consummate any future acquisitions, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions. The inability to effectively manage the integration of acquisitions could reduce our focus on current operations, which in turn, could negatively impact our future results of operations. 
+We may fail to fully identify problems with any properties we acquire, and as such, assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities. We look to acquire additional acreage in Texas or other regions. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, adequacy of title, operating and capital costs, and potential environmental and other liabilities. Although we conduct a review that we believe is consistent with industry practices, we can give no assurance that we have identified or will identify all existing or potential problems associated with such properties or that we will be able to mitigate any problems we do identify. Such assessments are inexact and their accuracy is inherently uncertain. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface, title and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms. 
+Risks Related to Our Hedging Program 
+Our hedging program may limit potential gains from increases in commodity prices, result in losses, or be inadequate to protect us against continuing and prolonged declines in commodity prices. We enter into arrangements to hedge a portion of our production from time to time to reduce our exposure to fluctuations in oil, natural gas, and NGL prices and to achieve more predictable cash flow. Our hedges at December 31, 2023 are in the form of collars, swaps, put and call options, basis swaps, and other structures placed with the commodity trading branches of certain banking institutions. These hedging arrangements may limit the benefit we could receive from increases in the market or spot prices for oil, natural gas, and NGLs. We cannot be certain that the hedging transactions we have entered into, or will enter into, will adequately protect us from continuing and prolonged declines in oil, natural gas, and NGL prices. To the extent that oil, natural gas, and NGL prices remain at current levels or decline further, we would not be able to hedge future production at the same pricing level as our current hedges and our results of operations and financial condition may be negatively impacted. 
+Our production is not fully hedged, and we are exposed to fluctuations in oil, natural gas and NGL prices and will be affected by continuing and prolonged declines in oil, natural gas and NGL prices. The total volumes which we hedge through use of our derivative instruments varies from period to period and takes into account our view of current and future market conditions in order to provide greater certainty of cash flows to meet our debt service costs and capital program. We generally hedge for the next 12 to 24 months. We intend to continue to hedge our production, but we may not be able to do so at favorable prices. Accordingly, our revenues and cash flows are subject to increased volatility and may be subject to significant reduction in prices which would have a material negative impact on our results of operations. 
+Our hedging transactions expose us to counterparty credit risk. Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract, particularly during periods of falling commodity prices. Disruptions in the financial markets or other factors outside our control could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform, and even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending on market conditions at the time. If the creditworthiness of any of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss. 
+Legal and Regulatory Risks 
+We are subject to stringent and complex federal, state and local laws and regulations which require compliance that could result in substantial costs, delays or penalties. Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. For a discussion of the material regulations applicable to us, see “Business and Properties — Regulations.” These laws and regulations may: 
+• require that we acquire permits before commencing drilling; 
+• regulate the spacing of wells and unitization and pooling of properties; 
+• impose limitations on production or operational, emissions control and other conditions on our activities; 
+• restrict the substances that can be released into the environment or used in connection with drilling and production activities or restrict the disposal of waste from our operations; 
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+• limit or prohibit drilling activities on protected areas, such as wetlands and wilderness; 
+• impose requirements to protect our employees and mitigate safety risks; 
+• impose penalties or other sanctions for accidental or unpermitted spills or releases from our operations; or 
+• require measures to remediate or mitigate pollution and environmental impacts from current and former operations, such as cleaning up spills or decommissioning abandoned wells and production facilities. 
+Significant expenditures may be required to comply with governmental laws and regulations applicable to us. In addition, failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, permit revocations, requirements for additional pollution controls or injunctions limiting or prohibiting operations. 
+The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal, state and local agencies frequently review, revise and supplement environmental laws and regulations, and such changes could result in increased costs for environmental compliance, such as emissions monitoring and control, permitting, waste handling, storage, transport, remediation or disposal for the oil and natural gas industry and could have a significant impact on our operating costs. In general, the oil and natural gas industry recently has been the subject of increased legislative and regulatory attention with respect to public health and environmental matters. Even if regulatory burdens temporarily ease from time to time, the historic trend of more expansive and stricter environmental legislation and regulations may continue in the long-term. 
+Further, under these laws and regulations, we could be liable for costs of investigation, removal and remediation, damages to and loss of use of natural resources, loss of profits or impairment of earning capacity, property damages, costs of increased public services, as well as administrative, civil and criminal fines and penalties, and injunctive relief. Certain environmental statutes, including RCRA, CERCLA, OPA and analogous state laws and regulations, impose strict, joint and several liability for costs required to investigate, clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released (i.e., liability may be imposed regardless of whether the current owner or operator was responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time the release or contamination occurred). We could also be affected by more stringent laws and regulations adopted in the future, including any related to climate change, engine and other equipment emissions, GHGs and hydraulic fracturing. Under common law, we could be liable for injuries to people and property. We maintain limited insurance coverage for sudden and accidental environmental damages. We do not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Also, we do not believe that insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability in excess of our insurance coverage or we may be required to curtail or cease production from properties in the event of environmental incidents. 
+Federal legislation and state and local legislative and regulatory initiatives relating to hydraulic fracturing and water disposal wells could result in increased costs and additional operating restrictions or delays. Hydraulic fracturing is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production and is typically regulated by state oil and gas commissions. However, from time to time, the U.S. Congress has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing. Legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and to require federal permitting and regulatory control of hydraulic fracturing but has not passed. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA regulates hydraulic fracturing with fluids containing diesel fuel under the UIC program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act. The EPA has recently taken steps to strengthen its methane standards. The November 2021 rule intended to make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the CAA (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities). In addition, the November 2021 rule would establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by EPA. Additionally, in November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule. Among other things, the November 2022 supplemental proposed rule removes an emissions monitoring exemption for small wellhead-only sites and creates a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters.” In December 2023, the EPA announced a final rule, which, among other things, requires the phase out of routine flaring of natural gas from newly constructed wells (with some exceptions) and routine leak monitoring at all well sites and compressor stations. Notably, the EPA updated the applicability date for Subparts OOOOb and OOOOc to December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later compliance deadlines under state plans. The final rule gives states, along with federal tribes that wish to regulate existing sources, two years to develop and submit their plans for reducing methane emissions from existing sources. The final emissions guidelines under Subpart OOOOc provide three years from the plan submission deadline for existing sources to comply. We may incur significant operational costs associated with compliance with these and any new regulations. 
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+In some areas of Texas, including the Permian, there has been concern that certain formations into which disposal wells are injecting produced waters could become over-pressured after many years of injection, and the RRC is reviewing the data to determine whether any regulatory action is necessary to address this issue. If the RRC were to decline to issue permits for, or impose new limits on the volumes of, injection wells into the formations that we currently utilize, we may be required to seek alternative methods of disposing of produced waters, including injecting into deeper formations, which could increase our costs. 
+Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, impose additional requirements on hydraulic fracturing activities or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For example, Texas law requires the chemical components used in the hydraulic fracturing process, as well as the volume of water used, must be disclosed to the RRC and the public. The RRC’s “well integrity rule” includes testing and reporting requirements, such as (i) the requirement to submit to the RRC cementing reports after well completion or cessation of drilling and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. Additionally, the RRC rules require applicants for certain new water disposal wells to conduct seismic activity searches using the U.S. Geological Survey to determine the potential for earthquakes within a circular area of 100 square miles. Further, the RRC has authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The RRC has used this authority to deny permits for, and limit volumes for, disposal wells. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of drilling in general or hydraulic fracturing in particular. 
+The EPA has also issued the “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States” report, concluding that hydraulic fracturing can impact drinking water resources in certain circumstances but also noted that certain data gaps and uncertainties limited EPA’s ability to fully characterize the severity of impacts or calculate the national frequency of impacts on drinking water resources from activities in the hydraulic fracturing water cycle. This study could result in additional regulatory scrutiny that could restrict our ability to perform hydraulic fracturing and increase our costs of compliance and doing business. 
+There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, water usage and the potential for impacts to surface water, groundwater and the environment generally, and a number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. Several states and municipalities have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances. If new laws or regulations that significantly restrict hydraulic fracturing or water disposal wells are adopted, such laws could make it more difficult or costly for us to drill for and produce oil and natural gas as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements, permitting delays and potential increases in costs. These changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing. 
+Climate change legislation or regulations restricting emissions of GHG or requiring the reporting of GHG emissions or climate-related information could adversely impact our operating costs and demand for the oil and natural gas we produce. In recent years, federal, state and local governments have taken steps to reduce emissions of GHGs. The EPA has finalized a series of GHG monitoring, reporting and emissions control rules and proposed additional rules, and the U.S. Congress has, from time to time, considered adopting legislation to reduce or tax emissions. Several states have already taken measures to reduce emissions of GHGs primarily through the development of GHG emission inventories or regional GHG cap-and-trade programs. For a description of some existing and proposed GHG rules and regulations, see “Business and Properties—Regulations.” 
+In 2021, as a party to the Paris Agreement, the U.S. announced a target for the U.S. to achieve a 50% to 52% reduction from 2005 levels in economy-wide GHG emissions by 2030. In addition, in September 2021, President Biden publicly announced the Global Methane Pledge, a pact that aims to reduce global methane emissions at least 30% below 2020 levels by 2030, including “all feasible reductions” in the energy sector. Since its formal launch at the COP26, over 150 countries have joined the pledge. At the 27th conference of parties (“COP27”), President Biden announced the EPA’s supplemental proposed rule to reduce methane emissions from existing oil and gas sources, and agreed, in conjunction with the European Union and a number of other partner countries, to develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. At COP28, member countries entered into an agreement that calls for actions toward achieving, at a global scale, a tripling of renewable energy capacity and doubling energy efficiency improvements by 2030. The goals of the agreement, among other things, are to accelerate efforts toward the phase-down of unabated coal power, phase out inefficient fossil fuel subsidies, and take other measures that drive the transition away from fossil fuels in energy systems. Various state and local governments have also publicly committed to furthering the goals of the Paris Agreement. In addition, a number of states have begun taking actions to control or reduce emissions of GHGs. 
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+Restrictions on GHG emissions that may be imposed could adversely affect the oil and gas industry. The adoption of legislation or regulatory programs to reduce or control GHG emissions or that require the reporting of GHG emissions or other climate-related information could result in increased operational complexity, production delays, increased potential for regulatory fines and penalties, and require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements, and to monitor and report on GHG emissions. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Moreover, incentives or requirements to conserve energy, use alternative energy sources, reduce GHG emissions in product supply chains, and increase demand for low-carbon fuel or zero-emissions vehicles, could reduce demand for the oil and natural gas we produce. International commitments, re-entry into the Paris Agreement, and President Biden’s executive orders may result in the development of additional regulations or changes to existing regulations. At the federal level, although no comprehensive climate change legislation regulating the emission of GHGs or directly imposing a price on carbon has been implemented to date, such legislation has periodically been introduced in the U.S. Congress and may be proposed or adopted in the future, and energy legislation and other regulatory initiatives have been proposed that are relevant to GHG emissions issues. The $1 trillion legislative infrastructure package passed by Congress in November 2021 includes a number of climate-focused spending initiatives targeted at climate resilience, enhanced response and preparation for extreme weather events and clean energy and transportation investments. The IRA also provides significant funding and incentives for research and development of low-carbon energy production methods, carbon capture and other programs directed at addressing climate change. For example, the IRA imposes a fee on GHG emissions from certain oil and gas facilities. The IRA amends the CAA to include a Methane Emissions and Waste Reduction Incentive Program, which requires the EPA to impose a “waste emissions charge” on certain natural gas and oil sources that are already required to report under the EPA’s Greenhouse Gas Reporting Program. To implement the program, the IRA requires revisions to GHG reporting regulations for petroleum and natural gas systems (Subpart W) by 2024. In July 2023, the EPA proposed to expand the scope of the Greenhouse Gas Reporting Program for petroleum and natural gas facilities, as required by the IRA. Among other things, the proposed rule would expand the emissions events that are subject to reporting requirements to include “other large release events” and apply reporting requirements to certain new sources and sectors. The rule is expected to be finalized in the spring of 2024 and become effective on January 1, 2025 in advance of the deadline for GHG reporting for 2024 (March 2025). The fee imposed under the Methane Emissions and Waste Reduction Incentive Program for 2024 would be $900 per ton emitted over annual methane emissions thresholds, and would increase to $1,200 in 2025, and $1,500 in 2026. The emissions fee and funding provisions of the law could increase operating costs within the oil and gas industry and accelerate the transition away from fossil fuels, which could in turn adversely affect our and our customers’ business and results of operations. Additionally, the SEC issued a proposed rule in March 2022 that would mandate extensive disclosure of climate-related data, risks and opportunities, including financial impacts, physical and transition risks, related governance and strategy and GHG emissions, for certain public companies, and a final rule is anticipated in April 2024. We cannot predict the costs of implementation or any potential adverse impacts resulting from the rulemaking. To the extent this rulemaking is finalized as proposed, we could incur increased costs relating to the assessment and disclosure of climate-related risks. We may also face increased litigation risks related to disclosures made pursuant to the rule if finalized as proposed. In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon-intensive sectors. Consequently, legislation and regulatory programs to reduce or require reporting relating to GHG emissions or other climate-related information could have an adverse effect on our business, financial condition and results of operations. 
+In addition, fuel conservation measures, alternative fuel requirements and increasing consumer demand for alternatives to oil and natural gas could reduce demand for oil and natural gas, and activism, litigation and initiatives aimed at limiting climate change and reducing air pollution could impact our business activities, operations and ability to access capital. For further discussion on transition risks related to climate change legislation and regulation, see “—Our business is subject to climate-related transition risks, including evolving climate change legislation, fuel conservation measures, technological advances and negative shift in market perception towards the oil and natural gas industry could result in increased operating expenses and capital costs, financial risks and potential reduction in demand for oil and natural gas” and “—Negative public perception of the oil and gas industry could have a material and adverse effect on us.” 
+Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. Title VII of the Dodd-Frank Act establishes federal oversight and regulation of over-the-counter derivatives and requires the CFTC and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the over-the-counter market. 
+Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas, including the scope of relevant definitions or exemptions, remain pending. The CFTC issued a final rule on margin requirements for uncleared swap transactions in January 2016, which it amended in November 2018. The final rule as amended includes an exemption for certain commercial end-users that enter into uncleared swaps in order to hedge bona fide commercial risks affecting their business. In addition, the CFTC has issued a final rule authorizing an exception from the requirement to use cleared exchanges (rather than hedging over-the-counter) for commercial end-users who use swaps to hedge their commercial risks. The Dodd-Frank Act also 
+43 
+imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations. On January 24, 2020, U.S. banking regulators published a new approach for calculating the quantum of exposure of derivative contracts under their regulatory capital rules. This approach to measuring exposure is referred to as the standardized approach for counterparty credit risk or SA-CCR. It requires certain financial institutions to comply with significantly increased capital requirements for over-the-counter commodity derivatives. In addition, on September 15, 2020, the CFTC issued a final rule regarding the capital a swap dealer or major swap participant is required to set aside with respect to its swap business. These two sets of regulations and the increased capital requirements they place on certain financial institutions may reduce the number of products and counterparties in the over-the-counter derivatives market available to us and could result in significant additional costs being passed through to end-users like us. On January 14, 2021, the CFTC published a final rule on position limits for certain commodities futures and their economically equivalent swaps, though like several other rules there is a bona fide hedging exemption to the application of such rule. All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business. 
+Depending on our ability to satisfy the CFTC’s requirements for the various exemptions available for a commercial end-user using swaps to hedge or mitigate its commercial risks, the final rules may provide beneficial exemptions and/or may require us to comply with position limits and other limitations with respect to our financial derivative activities. The Dodd-Frank Act may require our current counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which could increase the cost to us of entering into such derivatives. The Dodd-Frank Act may also require our current counterparties to financial derivative transactions to cease their current business as hedge providers or spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. These potential changes could reduce the liquidity of the financial derivatives markets which would reduce the ability of commercial end-users like us to hedge or mitigate their exposure to commodity price volatility. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of future swaps relative to the terms of our existing financial derivative contracts, and reduce the availability of derivatives to protect against commercial risks we encounter. 
+If we reduce our use of derivative contracts as a result of any of the foregoing new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Our revenues could be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations, or cash flows. 
+Tax Risks 
+Our ability to use our existing net operating loss (“NOL”) carryforwards or other tax attributes could be limited. A significant portion of our NOL carryforward balance was generated prior to the effective date of limitations on utilization of NOLs imposed by the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) and are allowable as a deduction against 100% of taxable income in future years, but will start to expire in the 2035 taxable year. The remainder were generated following such effective date and, thus, generally allowable as a deduction against 80% of taxable income in future years (with an exception to this rule due to the enactment of the Coronavirus Aid, Relief, and Economic Security Act, whereby the utilization of NOLs was temporarily expanded for taxable years beginning before 2021). Utilization of any NOL carryforwards depends on many factors, including our ability to generate future taxable income, which cannot be assured. In addition, Section 382 (“Section 382”) of the Internal Revenue Code of 1986, as amended (the “Code”), generally imposes, upon the occurrence of an ownership change (discussed below), an annual limitation on the amount of our pre-ownership change NOLs we can utilize to offset our taxable income in any taxable year (or portion thereof) ending after such ownership change. The limitation is generally equal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate. In general, an ownership change occurs if there is a cumulative increase in our ownership of more than 50 percentage points by one or more “5% shareholders” (as defined in the Code) at any time during a rolling three-year period. Future ownership changes and/or future regulatory changes could further limit our ability to utilize our NOLs. To the extent we are not able to offset our future income with our NOLs, this could adversely affect our operating results and cash flows once we attain profitability. 
+Unanticipated changes in effective tax rates or adverse outcomes resulting from examination of our income or other tax returns could adversely affect our financial condition and results of operations. We are subject to income taxes in the U. S., and our domestic tax assets and liabilities are subject to the allocation of expenses in differing jurisdictions. Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including the following: changes in the valuation of our deferred tax assets and liabilities; expected timing and amount of the release of any tax valuation allowances; tax effects of stock-based compensation; costs related to intercompany restructurings; changes in tax laws, regulations or interpretations thereof; or lower than anticipated future earnings in our taxing jurisdictions. In addition, we may be subject to audits of our income, sales and other transaction taxes by U.S. federal and state authorities. Outcomes from these audits could have an adverse effect on our financial condition and results of operations. 
+Tax laws may change over time and such changes could adversely affect our business and financial condition. From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws, 
+44 
+including (i) the elimination of the immediate deduction for intangible drilling and development costs, (ii) changes to a depletion allowance for oil and natural gas properties, (iii) the implementation of a carbon tax, (iv) an extension of the amortization period for certain geological and geophysical expenditures, (v) changes to tax rates, and (vi) the introduction of a minimum tax. While these specific changes were not included in recent legislation such as the IRA, no accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. The elimination of U.S. federal tax deductions, as well as any other changes to or the imposition of new federal, state, local or non-U.S. taxes (including the imposition of, or increases in production, severance or similar taxes) could adversely affect our business and financial condition. 
+Other Material Risks 
+Competitive industry conditions may negatively affect our ability to conduct operations. We compete with numerous other companies in virtually all facets of our business. Our competitors in development, exploration, acquisitions and production include major integrated oil and gas companies and smaller independents as well as numerous financial buyers. Some of our competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources permit. We also compete for the materials, equipment, personnel and services that are necessary for the exploration, development and operation of our properties. Our ability to increase reserves in the future will be dependent on our ability to select and acquire suitable prospects for future exploration and development. 
+All of our producing properties are located in the Permian of West Texas, making us vulnerable to risks associated with operating in only one geographic region. As a result of this concentration, as compared to companies that have a more diversified portfolio of properties, we may be disproportionately exposed to the impact of regional supply and demand factors, severe weather, water shortages and other disruptions to climate patterns, delays or interruptions of production from wells in this area caused by governmental regulation, specific taxes or other regulatory legislation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services, or market limitations or interruption of the processing or transportation of oil, natural gas or NGLs. Such delays, interruptions or limitations could have a material adverse effect on our financial condition and results of operations. In addition, the effect of fluctuations on supply and demand may be more pronounced within specific geographic oil and natural gas producing areas, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. 
+The results of our planned development programs in new or emerging shale development areas and formations may be subject to more uncertainties than programs in more established areas and formations and may not meet our expectations for reserves or production. The results of our horizontal drilling efforts in emerging areas and formations of the Permian are generally more uncertain than drilling results in areas that are more developed and have more established production from horizontal formations. Because emerging areas and associated target formations have limited or no production history, we are less able to rely on past drilling results in those areas as a basis to predict our future drilling results. In addition, horizontal wells drilled in shale formations, as distinguished from vertical wells, utilize multilateral wells and stacked laterals, all of which are subject to well spacing, density and proration requirements of the RRC, which requirements could adversely impact our ability to maximize the efficiency of our horizontal wells related to reservoir drainage over time. Further, access to adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more challenging in new or emerging areas. If our drilling results in these areas are less than anticipated or we are unable to execute our drilling program in these areas because of capital constraints, access to gathering systems and takeaway capacity or otherwise, or natural gas and oil prices decline, our investment in these areas may not be as economic as we anticipate, we could incur material write-downs of unproved properties and the value of our undeveloped acreage could decline in the future. 
+The loss of key personnel, or inability to employ a sufficient number of qualified personnel, could adversely affect our ability to operate. We depend, and will continue to depend in the foreseeable future, on the services of our senior officers and other key employees, as well as other third-party consultants with extensive experience and expertise in evaluating and analyzing drilling prospects and producing oil and natural gas and maximizing production from oil and natural gas properties. Our ability to retain our senior officers, other key employees, and third-party consultants, many of whom are not subject to employment agreements, is important to our future success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business. Also, we may experience employee turnover or labor shortages if our business requirements, compensation, benefits and/or perquisites are inconsistent with the expectations of current or prospective employees, or if workers pursue employment in fields with less volatility than in the energy industry. If we are unsuccessful in our efforts to attract and retain sufficient qualified personnel on terms acceptable to us, or do so at rates necessary to maintain our competitive position, our business could be adversely affected. 
+The inability of one or more of our customers to meet their obligations to us may adversely affect our financial results. Our principal exposure to credit risk is through receivables resulting from the sale of our oil and natural gas production, advances to joint interest parties and joint interest receivables. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. The largest purchaser of our oil and natural gas accounted for approximately 13% of 
+45 
+our total revenues for the year ended December 31, 2023. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. 
+Our bylaws designate the Court of Chancery of the State of Delaware (the “Court of Chancery”) as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our shareholders, which could limit our shareholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, or other employees. Our bylaws provide that, unless we consent in writing to the selection of an alternative forum, the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action or proceeding asserting a claim for breach of a fiduciary duty owed by any current or former director, officer, or other employee of our company to us or our shareholders, (iii) any action or proceeding asserting a claim against us or any current or former director, officer, or other employee of our company arising pursuant to any provision of the Delaware General Corporate Law (the “DGCL”) or our charter or bylaws (as each may be amended from time to time), (iv) any action or proceeding asserting a claim against us or any current or former director, officer, or other employee of our company governed by the internal affairs doctrine, or (v) any action or proceeding as to which the DGCL confers jurisdiction on the Court of Chancery shall be the Court of Chancery or, if and only if the Court of Chancery lacks subject matter jurisdiction, any state court located within the State of Delaware or, if and only if such state courts lack subject matter jurisdiction, the federal district court for the District of Delaware, in all cases to the fullest extent permitted by law and subject to the court’s having personal jurisdiction over the indispensable parties named as defendants. 
+Our exclusive forum provision is not intended to apply to claims arising under the Securities Act or the Exchange Act. To the extent the provision could be construed to apply to such claims, there is uncertainty as to whether a court would enforce the forum selection provision with respect to such claims, and in any event, our shareholders would not be deemed to have waived our compliance with federal securities laws and the rules and regulations thereunder. 
+Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock is deemed to have received notice of and consented to the foregoing forum selection provision. This provision may limit our shareholders’ ability to bring a claim in a judicial forum that they find favorable for disputes with us or our directors, officers, or other employees, which may discourage such lawsuits. Alternatively, if a court were to find this choice of forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect its business, financial condition, prospects, or results of operations. 
+Provisions of our charter documents and Delaware law may inhibit a takeover, which could limit the price investors might be willing to pay in the future for our common stock. Provisions in our certificate of incorporation and bylaws may have the effect of delaying or preventing an acquisition of the Company or a merger in which we are not the surviving company and may otherwise prevent or slow changes in our Board of Directors and management. In addition, because we are incorporated in Delaware, we are governed by the provisions of Section 203 of the DGCL. These provisions could discourage an acquisition of the Company or other change in control transactions and thereby negatively affect the price that investors might be willing to pay in the future for our common stock. 
+We do not currently pay cash dividends on our common stock. We do not currently pay dividends on our common stock and any future determination as to the declaration and payment of cash dividends will be at the discretion of our Board of Directors and will depend upon our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors deemed relevant by our Board of Directors at the time of such determination. Consequently, a shareholder’s only current opportunity to achieve a return on its investment in us will be by selling its shares of our common stock at a price greater than the shareholder paid for it. There is no guarantee that the price of our common stock that will prevail in the market will exceed the price at which a shareholder purchased its shares of our common stock. 
+General Risk Factors 
+Declining general economic, business or industry conditions and inflation may have a material adverse effect on our results of operations, liquidity and financial condition. Concerns over global economic conditions, energy costs, supply chain disruptions, increased demand, labor shortages associated with a fully employed U.S. labor force, geopolitical issues, inflation, the availability and cost of credit and the United States financial market and other factors have contributed to increased economic uncertainty and diminished expectations for the global economy. Although inflation in the United States had been relatively low for many years, there was a significant increase in inflation beginning in the second half of 2021, which has continued into 2022, 2023 and thus far into 2024 (although it has begun to moderate) due to a substantial increase in money supply, a stimulative fiscal policy, a significant rebound in consumer demand as COVID-19 restrictions were relaxed, the Russia-Ukraine war and worldwide supply chain disruptions resulting from the economic contraction caused by COVID-19 and lockdowns followed by a rapid recovery. We continue to undertake actions and implement plans to strengthen our supply chain to address these pressures and protect the requisite access to commodities and services, and we are working closely with suppliers and contractors to ensure availability of supplies on site, especially fuel, steel and chemical suppliers which are critical to many of our operations. However, these mitigation efforts may not succeed or may be insufficient, and we expect for the foreseeable future to experience supply chain constraints and inflationary pressure on our cost structure. Principally, commodity costs for steel and chemicals required for drilling, higher transportation and fuel costs and wage 
+46 
+increases have increased our operating costs for the year ended December 31, 2023 compared to 2022, which was higher as compared to 2021. We also may face shortages of these commodities and labor, which may prevent us from executing our development plan. These supply chain constraints and inflationary pressures will likely continue to adversely impact our operating costs and, if we are unable to manage our supply chain, it may impact our ability to procure materials and equipment in a timely and cost-effective manner, if at all, which could impact our ability to distribute available cash and result in reduced margins and production delays and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected. 
+We are taking actions to mitigate supply chain and inflationary pressures. 
+In addition, continued hostilities related to the Russian invasion of Ukraine, the conflict in Israel and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. These factors and other factors, combined with volatile commodity prices, and declining business and consumer confidence may contribute to an economic slowdown and a recession. Recent growing concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our business, financial condition and results of operations. 
+We may be subject to the actions of activist shareholders. We have been the subject of an activist shareholder in the past. Responding to shareholder activism can be costly and time-consuming, disrupt our operations and divert the attention of management and our employees from executing our business plan. Activist campaigns can create perceived uncertainties as to our future direction, strategy or leadership and may result in the loss of potential business opportunities, harm our ability to attract new investors, customers and joint venture partners and cause our stock price to experience periods of volatility or stagnation. Moreover, if individuals are elected to our Board of Directors with a specific agenda, our ability to effectively and timely implement our current initiatives, retain and attract experienced executives and employees and execute on our long-term strategy may be adversely affected. 
+Future sales of our common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of our common stock or other securities may dilute a shareholder’s ownership in us. In the future, we may continue to issue securities to raise capital. We may also continue to acquire interests in other companies by using any combination of cash and our common stock or other securities convertible into, or exchangeable for, or that represent the right to receive, our common stock. Any of these events may dilute your ownership interest in our company, reduce our earnings per share or have an adverse impact on the price of our common stock. In addition, secondary sales of a substantial amount of our common stock in the public market, or the perception that these sales may occur, could reduce the market price of our common stock. Any such reduction in the market price of our common stock could impair our ability to raise additional capital through the sale of our securities. 
+ITEM 1B. Unresolved Staff Comments 
+None. 
+47 
+ITEM 1C. Cybersecurity 
+The Board of Directors recognizes the critical importance of maintaining the trust and confidence of our suppliers, customers, other business partners and employees. The Board of Directors is actively involved in oversight of the Company’s risk management program, and cybersecurity represents an important component of the Company’s overall approach to enterprise risk management (“ERM”). The Company’s cybersecurity policies, standards, processes, and practices are fully integrated into the Company’s ERM program and are based on recognized frameworks established by the National Institute of Standards and Technology. In general, the Company seeks to address cybersecurity risks through a comprehensive, cross-functional approach that is focused on preserving the confidentiality, security, and availability of the information that the Company collects and stores by identifying, preventing, and mitigating any cybersecurity threats and effectively responding to cybersecurity incidents should they occur. 
+As of the date of this 2023 Annual Report on Form 10-K, the Company is not aware of any cybersecurity threats that have materially affected or are reasonably likely to materially affect the Company, including its business strategy, results of operations, or financial condition. However, as discussed under “Item 1A. Risk Factors,” specifically the risk titled “Our business could be negatively affected by security threats. A cyberattack or similar incident could occur and result in information theft, data corruption, operational disruption, damage to our reputation or financial loss,” the sophistication of cyberattacks continues to increase, and the preventative actions the Company takes to reduce the risk of cyber incidents and protect its systems and information may be insufficient. Accordingly, no matter how well the Company’s controls are designed or implemented, it will not be able to anticipate all security breaches, and it may not be able to implement effective preventive measures against such security breaches in a timely manner. In light of these risks, the Company has also developed cybersecurity detection and response protocols as described below to attempt to mitigate the impact in the event of a breach. 
+Risk Management and Strategy 
+As one of the critical elements of the Company’s overall ERM approach, the Company’s cybersecurity program is focused on the following key areas: 
+• Governance – The Board of Directors has responsibility for oversight of cybersecurity risk management and regularly interacts with the Company’s ERM function, the Company’s Chief Information Officer (“CIO”), and other members of management. 
+• Collaborative Approach – The Company has implemented a comprehensive, cross-functional approach to identifying, preventing, and mitigating cybersecurity threats and incidents, while also implementing controls and procedures that provide for the prompt escalation of certain cybersecurity incidents so that decisions regarding the public disclosure and reporting of such incidents can be made by management in a timely manner. The Company also collaborates with others in the industry and actively participates in a specific oil and gas threat intelligence group with weekly meetings and up-to-date threat notices. 
+• Technical Safeguards – The Company deploys technical safeguards that are designed to protect its information systems from cybersecurity threats, including firewalls, intrusion prevention and detection systems, anti-malware software and access controls, which are evaluated and improved through vulnerability assessments and cybersecurity threat intelligence. The Company performs an annual penetration test for identification of any vulnerabilities; in 2023, this test was performed by a third-party audit firm. 
+• Incident Response and Recovery Planning – The Company has established and maintains comprehensive incident response and recovery plans that address the Company’s response to a cybersecurity incident, and such plans are tested and evaluated on a regular basis, with the participation of executive officers and employees in our IT, legal and operations departments. 
+• Third-Party Risk Management – The Company maintains a comprehensive, risk-based approach to identifying and overseeing cybersecurity risks presented by third parties, including vendors, service providers and other external users of the Company’s systems, as well as the systems of third parties that could adversely impact our business. In 2023, the Company completed a comprehensive review of certain third-party providers that have access to the Company’s data, such as banks, and SaaS vendors, and implemented a third-party risk management service which (i) allows for comprehensive vendor assessments with risk scoring, (ii) informs risk decisions with increased visibility and cybersecurity ratings, (iii) continuously monitors for vendor breaches and other significant events via various data feeds, and (iv) allows for collaboration with vendors to assess and remediate risk. 
+• Education and Awareness – The Company provides regular, mandatory training for personnel regarding cybersecurity threats as a means to equip the Company’s personnel with effective tools to address cybersecurity threats, and to communicate the Company’s evolving information security policies, standards, processes, and practices. In addition to our annual required training, the Company promotes awareness through regular phishing simulations and educational opportunities, including an FBI-led training in 2023. 
+The Company engages in the periodic assessment and testing of the Company’s policies, standards, processes, and practices that are designed to address cybersecurity threats and incidents. These efforts include a wide range of activities, including audits, assessments, tabletop exercises, threat modeling, vulnerability management, and other exercises focused on evaluating the effectiveness of our 
+48 
+cybersecurity measures and planning. The Company regularly engages third parties to perform assessments on our cybersecurity measures, including information security maturity and risk assessments, audits and independent reviews of our information security control environment and operating effectiveness. The results of such assessments, audits and reviews are reported to the Board of Directors, and the Company adjusts its cybersecurity policies, standards, processes, and practices as necessary based on the information provided by these assessments, audits, and reviews. 
+Governance 
+The Board of Directors oversees the Company’s ERM program, including the management of risks arising from cybersecurity threats. On an annual basis, the Board of Directors discusses the Company’s approach to cybersecurity risk management with the CIO. The Board of Directors also receives regular presentations and reports on cybersecurity risks, which address a wide range of topics including recent developments, evolving standards, vulnerability assessments, third-party and independent reviews, the threat environment, technological trends and information security considerations arising with respect to the Company’s peers and third parties. 
+The CIO, in coordination with the Company’s executive team, works collaboratively across the Company to implement a program designed to protect the Company’s information systems from cybersecurity threats and to promptly respond to any cybersecurity incidents in accordance with the Company’s incident response and recovery plans. To facilitate the success of the Company’s cybersecurity risk management program, multidisciplinary teams throughout the Company are deployed to address cybersecurity threats and to respond to cybersecurity incidents. Through ongoing communications with these teams, the CIO oversees the monitoring, prevention, detection, mitigation, and remediation of cybersecurity threats and incidents, and reports such threats and incidents to the Board of Directors when appropriate. The CIO is supported by, among others, a Cybersecurity Architect who is a Certified Information Systems Security Professional (CISSP) and an Application Director who is Certified in Risk and Information Systems Control. 
+Angelina C. Day has served as the Company’s Vice President and CIO since July 2022. In this role, she is responsible for all aspects of information technology, including cybersecurity. Prior to joining the Company, Ms. Day was IT Director at EP Energy Corporation, an independent E&P company, from May 2012 until March 2022, where she oversaw the information technology and security functions. Prior to EP Energy, Ms. Day held various roles with increasing responsibility in technology and leadership at El Paso Corporation. Ms. Day has over 20 years of energy, technology and risk management experience. She is also a member of the Houston CIO Community (Evanta) Governing Body, an organization that fosters collaboration and knowledge sharing across the Houston CIO community. Ms. Day holds a B.B.A. in Computer Information Systems from the University of Houston Downtown. 
+Supporting our CIO in assessing and managing the Company’s material risks from cybersecurity threats are the Company’s COO, CFO, and General Counsel, each of whom have over 20 years of experience managing risks at the Company and at similar companies, including risks arising from cybersecurity threats. 
+ITEM 3. Legal Proceedings 
+We are a party in various legal proceedings and claims, which arise in the ordinary course of our business. While the outcome of these events cannot be predicted with certainty, we believe that the ultimate resolution of any such actions will not have a material effect on our financial position or results of operations. 
+As previously reported in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2022, in January 2022, we received a Notice of Violation from the United States Environmental Protection Agency (the “EPA”) related to the Clean Air Act. As previously reported in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2023, to resolve the alleged violations, on June 9, 2023, we agreed to a Consent Agreement and Final Order (“CAFO”) with the EPA, which became effective June 20, 2023. The CAFO assessed a civil penalty in the amount of approximately $1.3 million and requires us to perform certain actions over the course of the next year, including facility reviews, additional monitoring, and the submission of a final letter report in June 2024. We have begun implementing the requirements of the CAFO. We believe that the settlement was in the best interests of the Company and its shareholders to avoid the uncertainty, risk, expense, and distraction of protracted litigation. 
+ITEM 4. Mine Safety Disclosures 
+Not applicable. 
+49 
+PART II. 
+ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+Market Information 
+Our common stock trades on the NYSE under the symbol “CPE.” 
+Holders 
+As of February 16, 2024 the Company had approximately 1,002 common stockholders of record. 
+Issuer Repurchases of Equity Securities 
+Our common stock repurchase activity for the year ended December 31, 2023 was as follows: 
+Period 
+Total Number of Shares Purchased 
+Average Price Paid Per Share (1) 
+Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs 
+Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (2) 
+$300,000,000 
+July 1 - July 31, 2023 
+— $— — $300,000,000 
+August 1 - August 31, 2023 
+81,574 $36.22 81,574 $297,045,600 
+September 1 - September 30, 2023 
+305,145 $39.38 305,145 $285,027,986 
+October 1 - October 31, 2023 — $— — $285,027,986 
+November 1 - November 30, 2023 942,536 $32.89 942,536 $254,028,104 
+December 1 - December 31, 2023 322,397 $29.47 322,397 $244,528,169 
+Total 
+1,651,652 $33.59 1,651,652 
+(1) The average price paid per share excludes any fees, commissions and expenses paid to repurchase stock. 
+(2) On May 3, 2023, we announced that on May 2, 2023, the Board of Directors approved the Share Repurchase Program pursuant to which we are authorized to repurchase up to $300.0 million of our outstanding common stock through the second quarter of 2025. Repurchases under the Share Repurchase Program may be made, from time to time, in amounts and at prices we deem appropriate and will be subject to a variety of factors, including the market price of our common stock, general market and economic conditions and applicable legal requirements. The Share Repurchase Program will expire on June 30, 2025 but may be suspended, modified or discontinued by the Board of Directors at any time without prior notice. 
+We are restricted from making share repurchases during the period between the execution of the Merger Agreement and the Effective Time (or, if applicable, the termination date) without APA’s approval pursuant to covenants of Callon included within the Merger Agreement. 
+Dividends 
+We have not paid any cash dividends on our common stock to date. However, we continuously monitor many internal and external factors as we consider when, or if, we should implement shareholder return programs. These factors include our current and projected financial performance; our debt metrics, covenants and absolute amounts borrowed; commodity price outlooks; cash requirements; corporate and strategic plans; and macroeconomic indicators. In addition, the Merger Agreement contains certain restrictions that limit our ability to pay dividends. Ultimately, the timing, amount and form of shareholder return programs, if any, is subject to the discretion of our Board of Directors and to certain limitations imposed under Delaware corporate law and the agreements governing our debt obligations. 
+50 
+ITEM 6. Reserved 
+ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+The following management’s discussion and analysis describes the principal factors affecting our results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying audited consolidated financial statements, information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results, which are included in various parts of this filing. 
+A discussion and analysis of the Company’s financial condition and results of operations for the year ended December 31, 2021 can be found in “Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” of its Annual Report on Form 10-K for the year ended December 31, 2022, which was filed with the SEC on February 23, 2023. 
+Financial information for all prior periods has been recast to reflect the retrospective application of the successful efforts method of accounting, as discussed under “Note 2 — Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in this Form 10-K. 
+General 
+We are an independent oil and natural gas company focused on the acquisition, exploration and sustainable development of high-quality assets in the Permian Basin in West Texas. Our operating culture is centered on responsible development of hydrocarbon resources, safety and the environment, which we believe strengthens our operational performance. Our drilling activity is predominantly focused on the horizontal development of several prospective intervals in the Permian, including multiple layers of the Wolfcamp and Bone Springs formations and the Spraberry shale. We have assembled a decade-plus inventory of potential horizontal well locations and intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and through the acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps. 
+Merger Agreement 
+On January 3, 2024, we entered into the Merger Agreement, which provides that, among other things and subject to the terms and conditions therein, (i) Merger Sub will be merged with and into Callon, with Callon surviving and continuing as the surviving corporation in the Merger and becoming a subsidiary of APA, and (ii) at the Effective Time, each outstanding share of common stock of Callon (other than Excluded Shares (as defined in the Merger Agreement)) will be converted into the right to receive, without interest, 1.0425 shares of common stock of APA, with cash in lieu of fractional shares. 
+The completion of the Merger is subject to satisfaction or waiver of certain customary mutual closing conditions, and the Merger Agreement contains certain termination rights for each of APA and Callon. In certain circumstances, a termination fee would be payable by the terminating party. 
+If the Merger is consummated, our common stock will be delisted from the NYSE and deregistered under the Securities Exchange Act of 1934, and Callon will cease to be a publicly traded company. 
+For additional discussion of the Merger, please see “Part I. Items 1 and 2. Business and Properties — Merger Agreement.” 
+Financial and Operational Highlights 
+For discussion of our significant financial and operational highlights for the year ended December 31, 2023, please see “Part I. Items 1 and 2. Business and Properties — Major Developments in 2023”. 
+51 
+Results of Operations 
+Production 
+Years Ended December 31, 
+2023 2022 $ Change % Change 
+Total production 
+Oil (MBbls) 
+Permian 19,658 18,041 1,617 9 % 
+Eagle Ford 2,233 5,598 (3,365) (60 %) 
+Total oil 21,891 23,639 (1,748) (7 %) 
+Natural gas (MMcf) 
+Permian 43,437 35,519 7,918 22 % 
+Eagle Ford 2,672 6,108 (3,436) (56 %) 
+Total natural gas 46,109 41,627 4,482 11 % 
+NGLs (MBbls) 
+Permian 7,554 6,424 1,130 18 % 
+Eagle Ford 457 1,052 (595) (57 %) 
+Total NGLs 8,011 7,476 535 7 % 
+Total production (MBoe) 
+Permian 34,452 30,385 4,067 13 % 
+Eagle Ford 3,135 7,668 (4,533) (59 %) 
+Total barrels of oil equivalent 37,587 38,053 (466) (1 %) 
+Total daily production (Boe/d) 102,977 104,254 (1,277) (1 %) 
+Percent of total daily production 
+Oil 
+58 % 62 % (4 %) 
+Natural gas 
+21 % 18 % 3 % 
+NGLs 
+21 % 20 % 1 % 
+The decrease in production for the year ended December 31, 2023 compared to the same period of 2022 was primarily due to the Eagle Ford Divestiture, oil volumes that were negatively impacted by weather-related power and midstream disruptions in the third quarter, and normal production decline, partially offset by the Percussion Acquisition. 
+52 
+Pricing 
+Years Ended December 31, 
+2023 2022 $ Change % Change 
+Benchmark prices (1) 
+WTI (per Bbl) $77.64 $94.26 ($16.62) (18 %) 
+Henry Hub (per Mcf) 2.67 6.54 (3.87) (59 %) 
+Average realized sales price (excluding impact of derivative settlements) 
+Oil (per Bbl) 
+Permian $77.81 $95.58 ($17.77) (19 %) 
+Eagle Ford 75.01 96.15 (21.14) (22 %) 
+Total oil 77.52 95.72 (18.20) (19 %) 
+Natural gas (per Mcf) 
+Permian 1.74 5.44 (3.70) (68 %) 
+Eagle Ford 2.64 6.47 (3.83) (59 %) 
+Total natural gas 1.79 5.59 (3.80) (68 %) 
+NGL (per Bbl) 
+Permian 21.86 35.18 (13.32) (38 %) 
+Eagle Ford 20.26 32.80 (12.54) (38 %) 
+Total NGL 21.77 34.84 (13.07) (38 %) 
+Total average realized sales price (per Boe) 
+Permian 51.38 70.55 (19.17) (27 %) 
+Eagle Ford 58.63 79.84 (21.21) (27 %) 
+Total average realized sales price $51.98 $72.42 ($20.44) (28 %) 
+(1) Reflects calendar average daily spot market prices. 
+Revenues 
+Oil Natural Gas NGLs Total 
+(In thousands) 
+Revenues for the year ended December 31, 2022 (1) 
+$2,262,647 $232,681 $260,472 $2,755,800 
+Volume increase (decrease) 
+(167,313) 25,053 18,640 (123,620) 
+Price decrease 
+(398,308) (175,266) (104,705) (678,279) 
+Net decrease 
+(565,621) (150,213) (86,065) (801,899) 
+Revenues for the year ended December 31, 2023 (1) 
+$1,697,026 $82,468 $174,407 $1,953,901 
+Percent of total revenues 87 % 4 % 9 % 
+(1) Excludes sales of oil and gas purchased from third parties and sold to our customers. 
+The decrease in revenues for the year ended December 31, 2023 compared to the same period of 2022 was primarily due to a 28% decrease in the average realized sales price, which decreased to $51.98 per Boe from $72.42 per Boe, as shown above. 
+Operating Expenses 
+Lease Operating Expenses 
+Years Ended December 31, 
+2023 2022 Total Change Boe Change 
+Amount Per Boe Amount Per Boe $ % $ % 
+(In thousands, except per Boe and % amounts) 
+Permian $270,836 $7.86 $218,040 $7.18 $52,796 24 % $0.68 9 % 
+Eagle Ford 32,527 10.38 72,446 9.45 (39,919) (55 %) 0.93 10 % 
+Lease operating $303,363 $8.07 $290,486 $7.63 $12,877 4 % $0.44 6 % 
+53 
+The increase in lease operating expenses, as well as lease operating expenses per Boe, for the year ended December 31, 2023 compared to the same period of 2022 was primarily due to increases in certain operating expenses such as saltwater disposal and fuel and power. 
+Production and Ad Valorem Taxes 
+Years Ended December 31, 
+2023 2022 Total Change Boe Change 
+Amount Per Boe Amount Per Boe $ % $ % 
+(In thousands, except per Boe and % amounts) 
+Permian $101,035 $2.93 $122,957 $4.05 ($21,922) (18 %) ($1.12) (28 %) 
+Eagle Ford 12,477 3.98 36,963 4.82 (24,486) (66 %) (0.84) (17 %) 
+Production and ad valorem taxes $113,512 $3.02 $159,920 $4.20 ($46,408) (29 %) ($1.18) (28 %) 
+Percent of total revenues 
+5.8% 5.8% —% 
+The decrease in production and ad valorem taxes for the year ended December 31, 2023 compared to the same period of 2022 was primarily related to a 29% decrease in total revenues which decreased production taxes, partially offset by an increase in ad valorem taxes due to higher expected property tax valuations as a result of higher commodity prices during 2022 compared to 2021. The increase in production and ad valorem taxes as a percentage of total revenues for the year ended December 31, 2023 compared to the same period of 2022 was primarily due to an increase in ad valorem taxes during the year ended December 31, 2023, as discussed above, with a decrease in total revenues during the year ended December 31, 2023. 
+Gathering, Transportation and Processing Expenses 
+Years Ended December 31, 
+2023 2022 Total Change Boe Change 
+Amount Per Boe Amount Per Boe $ % $ % 
+(In thousands, except per Boe and % amounts) 
+Permian $101,975 $2.96 $82,459 $2.71 $19,516 24 % $0.25 9 % 
+Eagle Ford 6,246 1.99 14,443 1.88 (8,197) (57 %) 0.11 6 % 
+Gathering, transportation and processing $108,221 $2.88 $96,902 $2.55 $11,319 12 % $0.33 13 % 
+The increase in gathering, transportation and processing expenses, as well as the increase in gathering, transportation and processing expenses per Boe, for the year ended December 31, 2023 compared to the same period of 2022 was primarily related to new gathering agreements put into place during the year ended December 31, 2023. 
+Exploration Expenses 
+Years Ended December 31, 
+2023 2022 Total Change Boe Change 
+Amount Per Boe Amount Per Boe $ % $ % 
+(In thousands, except per Boe and % amounts) 
+Exploration 
+$9,143 $0.24 $9,703 $0.25 ($560) (6 %) ($0.01) (4 %) 
+For the year ended December 31, 2023 compared to the same period in 2022, exploration expense, as well as exploration expense per Boe, decreased by an immaterial amount. 
+Depreciation, Depletion and Amortization (“DD&A”). The following table sets forth the components of our DD&A for the periods indicated: 
+Years Ended December 31, 
+2023 2022 Total Change Boe Change 
+Amount Per Boe Amount Per Boe $ % $ % 
+(In thousands, except per Boe and % amounts) 
+DD&A of proved oil and gas properties 
+$527,966 $14.05 $485,585 $12.76 $42,381 9 % $1.29 10 % 
+Depreciation of other property and equipment 1,461 0.04 1,685 0.04 (224) (13 %) — — % 
+Amortization of other assets 2,341 0.06 2,962 0.08 (621) (21 %) (0.02) (25 %) 
+Accretion of asset retirement obligations 3,893 0.10 3,997 0.11 (104) (3 %) (0.01) (9 %) 
+DD&A $535,661 $14.25 $494,229 $12.99 $41,432 8 % $1.26 10 % 
+54 
+The increase in DD&A and DD&A per Boe for the year ended December 31, 2023 compared to the same period of 2022 was primarily attributable to higher proved oil and gas property balances as a result of the capital expenditures throughout 2023, partially offset by the cessation of depletion on the assets associated with the Eagle Ford Divestiture as a result of being classified as assets held for sale during the second quarter of 2023. 
+See “Note 5 - Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for additional details regarding the Eagle Ford Divestiture. 
+General and Administrative (“G&A”) 
+Years Ended December 31, 
+2023 2022 Total Change Boe Change 
+Amount Per Boe Amount Per Boe $ % $ % 
+(In thousands, except per Boe and % amounts) 
+General and administrative $115,344 $3.07 $97,996 $2.58 $17,348 18 % $0.49 19 % 
+The increase in G&A for the year ended December 31, 2023 compared to the same period of 2022 was primarily due to an increase in employee-related costs as well as an increase in stock compensation expense between the two periods. 
+Impairment of Oil and Gas Properties. We recognized an impairment of proved oil and gas properties in the second quarter of 2023 of $406.9 million as the fair value less cost to sell was less than the carrying amount of the net assets associated with the Eagle Ford Divestiture that were classified as assets held for sale. We recognized an impairment of unproved oil and gas properties in the fourth quarter of 2022 of $2.2 million due to certain leases approaching the end of their lease terms with no future plans to develop the acreage. 
+Other Income and Expenses 
+Interest Expense. The following table sets forth the components of our interest expense for the periods indicated: 
+Years Ended December 31, 
+2023 2022 Change 
+(In thousands) 
+Interest expense on Senior Notes $126,575 $124,694 $1,881 
+Interest expense on second lien notes — 13,825 (13,825) 
+Interest expense on Credit Facility 41,907 36,860 5,047 
+Amortization of debt issuance costs, premiums and discounts 10,790 12,333 (1,543) 
+Other interest expense 33 80 (47) 
+Interest expense $179,305 $187,792 ($8,487) 
+Interest expense for the year ended December 31, 2023 was $179.3 million, a decrease as compared to the same period of 2022 as a result of the redemption of our 9.0% second lien notes in June 2022 and our 8.25% Senior Notes, partially offset by an increase in interest expense due to the issuance of our 7.5% Senior Notes due 2030 in June 2022 as well as increases in interest rates on our outstanding borrowings under the Credit Facility. 
+See “Note 8 - Borrowings” of the Notes to our Consolidated Financial Statements for additional details. 
+(Gain) Loss on Derivative Contracts. The net (gain) loss on derivative contracts for the periods indicated includes the following: 
+Years Ended December 31, 
+2023 2022 Change 
+(In thousands) 
+(Gain) loss on oil derivatives ($22,371) $287,379 ($309,750) 
+(Gain) loss on natural gas derivatives (4,990) 38,803 (43,793) 
+Loss on NGL derivatives 2,663 4,771 (2,108) 
+Loss on contingent consideration arrangements 5,800 — 5,800 
+(Gain) loss on derivative contracts ($18,898) $330,953 ($349,851) 
+See “Note 9 – Derivative Instruments and Hedging Activities” and “Note 10 – Fair Value Measurements” of the Notes to our Consolidated Financial Statements for additional information. 
+(Gain) Loss on Extinguishment of Debt. For the year ended December 31, 2023, we recognized a gain on extinguishment of debt of $1.2 million as a result of the redemption of the 8.25% Senior Notes. 
+55 
+For the year ended December 31, 2022, we recognized a loss on extinguishment of debt of $45.7 million as a result of the redemptions of the 6.125% senior notes and second lien notes and the termination of our Prior Credit Facility. 
+See “Note 8 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information. 
+Sales and Cost of Purchased Oil and Gas. We purchase oil and gas from third parties in order to fulfill portions of our pipeline commitments. For the years ended December 31, 2023 and 2022, we recorded sales of purchased oil and gas of $389.1 million and $475.2 million, respectively, and cost of purchased oil and gas of $399.2 million and $478.4 million, respectively, related to commodities purchased from third parties and sold to our customers. 
+Income Tax Expense. We recorded income tax benefit of $189.8 million for the year ended December 31, 2023 compared to income tax expense of $13.8 million for the same period of 2022. The changes from the statutory income tax rate for the year ended December 31, 2023 is a result of releasing the valuation allowance that was in place against our net deferred tax assets. See “Note 13 – Income Taxes” of the Notes to our Consolidated Financial Statements for further discussion. 
+Liquidity and Capital Resources 
+Pricing Outlook. Oil prices continue to remain volatile as the daily NYMEX benchmark price for oil ranged between approximately $67 and $94 per barrel during 2023. Overall for 2023, the average price of $78 per barrel remained significantly below the average of $95 per barrel for 2022. Additionally, during 2023, the daily NYMEX benchmark price for natural gas decreased approximately 59% from the average for 2022 to $2.67 per Mcf. We expect to continue to see volatility in oil prices, as well as natural gas and NGL prices. 
+Capital Efficiency Outlook. We recently transitioned to a business unit design in our operations group to improve focus on capital efficiency and capital allocation. We have identified structural drilling efficiency gains from well design changes and expect to continue to identify incremental structural efficiency gains as we move into 2024. The identified improvements are expected to reduce our 2024 average total well costs, including facilities, by at least 15%. 
+Sources and Uses of Cash. Our primary uses of capital are for the exploration and development of our oil and natural gas properties. Because we are the operator of a high percentage of our properties, we can control the well design and the development pace associated with our capital expenditures. We plan our capital expenditure program to achieve disciplined reinvestment rates to drive capital efficiency through an enhanced multi-zone, scaled development program. 
+We believe that existing cash and cash equivalents, cash flows from operations and available borrowings under our credit facility will be sufficient to support working capital, capital expenditures and other cash requirements for at least the next 12 months and, based on our current expectations, for the foreseeable future thereafter. Our future capital requirements, both near-term and long-term, will depend on many factors, including, but not limited to, commodity prices, market conditions, our available liquidity and financing, acquisitions and divestitures of oil and gas properties, the availability of drilling rigs and completion crews, the cost of completion services, success of drilling programs, land and industry partner issues, weather delays, the acquisition of leases with drilling commitments, and other factors. 
+Historically, our primary sources of capital have been cash flows from operations, borrowings under our credit facility, proceeds from the issuance of debt securities and public equity offerings, and asset dispositions. Up to the completion of the Merger, our liquidity requirements will remain funded by our cash flow from operations, borrowings under our credit facility and certain other capital activities allowed under the Merger Agreement. In particular, we are subject to restrictions under the Merger Agreement on assuming additional debt, issuing additional equity or debt, repurchasing equity, making certain capital expenditures, and entering into certain acquisition, disposition and leasing transactions, among other restrictions. 
+Overview of Cash Flow Activities. For the year ended December 31, 2023, cash and cash equivalents decreased $0.1 million to $3.3 million compared to $3.4 million at December 31, 2022. 
+Years Ended December 31, 
+2023 2022 
+(In thousands) 
+Net cash provided by operating activities $1,092,529 $1,355,673 
+Net cash used in investing activities (707,311) (853,183) 
+Net cash used in financing activities (385,288) (508,977) 
+Net change in cash and cash equivalents ($70) ($6,487) 
+Operating Activities. Net cash provided by operating activities was $1.1 billion and $1.4 billion for the years ended December 31, 2023 and 2022, respectively. The decrease in net cash provided by operating activities was primarily attributable to the following: 
+• A decrease in revenue primarily driven by a 28% decrease in total average realized sales price; partially offset by 
+• A decrease in the cash paid for commodity derivative settlements. 
+56 
+Investing Activities. Net cash used in investing activities was $707.3 million and $853.2 million for the years ended December 31, 2023 and 2022, respectively. The change in net cash used in investing activities was primarily attributable to proceeds from the Eagle Ford Divestiture and a decrease in cash paid for the settlement of contingent consideration agreements, partially offset by cash paid for the Percussion Acquisition and an increase in operational capital expenditures. 
+Financing Activities. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under our Credit Facility, term debt and equity offerings. For the year ended December 31, 2023, net cash used in financing activities was $385.3 million compared to $509.0 million during 2022. The change was primarily attributable to the redemption of the 8.25% Senior Notes and the initiation of our Share Repurchase Program during 2023 compared to the redemptions of the 6.125% Senior Notes and Second Lien Notes, partially offset by the issuance of the 7.5% Senior Notes in 2022. 
+Credit Facility. As of December 31, 2023, our Credit Facility had a maximum credit amount of $5.0 billion, a borrowing base of $2.0 billion and an elected commitment amount of $1.5 billion, with borrowings outstanding of $365.0 million at a weighted-average interest rate of 7.54%, and letters of credit outstanding of $21.4 million. 
+Redemption of 8.25% Senior Notes. On August 2, 2023, we redeemed all $187.2 million of our outstanding 8.25% Senior Notes using borrowings under our Credit Facility. See “Note 8 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information on our long-term debt. 
+Income Taxes. Due to the issuance of common stock pursuant to the acquisition of Carrizo Oil & Gas, Inc. (“Carrizo”), the Company incurred a cumulative ownership change, and as such, the Company’s NOLs prior to the acquisition are subject to a combined annual limitation under Internal Revenue Code (the “IRC”) Section 382 in the amount of $32.2 million, which is comprised of $15.7 million of Carrizo’s NOLs and $16.5 million of Callon’s NOLs. At December 31, 2023, the Company had approximately $2.0 billion of NOLs, some of which i) are subject to annual limitation under Section 382, ii) are subject to the IRC’s 80% taxable income limitation rule, or iii) expire between 2034 and 2037, as summarized in the table below. 
+Subject to Annual Limitation Under Section 382 Subject to IRC’s 80% Taxable Income Limitation Years of Expiration NOL Balance 
+(In millions) 
+Yes Yes N/A $710.0 
+No Yes N/A 841.5 
+Yes No 2034 to 2037 399.3 
+$1,950.8 
+The Company also has a net interest expense carryforward of $401.0 million under Section 163(j) of the Code, subject to indefinite carryforward. 
+Material Cash Requirements. As of December 31, 2023, we have financial obligations associated with our outstanding long-term debt, including interest payments and principal repayments. See “Note 8 – Borrowings” of the Notes to our Consolidated Financial Statements for further discussion of the contractual commitments under our debt agreements, including the timing of principal repayments. Additionally, we have operational obligations associated with long-term, non-cancelable leases, drilling rig contracts, frac service contracts, gathering, processing and transportation service agreements and other purchase obligations as well as estimates of future asset retirement obligations. See “Note 15 – Asset Retirement Obligations” and “Note 18 – Commitments and Contingencies” of the Notes to our Consolidated Financial Statements for additional details. 
+We estimate that the combination of our sources of capital, as discussed above, will continue to be adequate to fund our short- and long-term contractual obligations. 
+Critical Accounting Estimates 
+For discussion regarding our significant accounting policies, see “Note 2 – Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements. We have outlined below the policies identified as being critical to the understanding of our business and results of operations and that require the application of significant management judgment. 
+Recast Financial Information for Change in Accounting Principle 
+In the first quarter of 2023, we voluntarily changed our method of accounting for our oil and gas exploration and development activities from the full cost method to the successful efforts method of accounting. Accordingly, the financial information for prior periods has been recast to reflect retrospective application of the successful efforts method, as prescribed by the FASB ASC 932 
+57 
+“Extractive Activities — Oil and Gas.” See “Note 2 — Summary of Significant Accounting Policies” and “Note 3 — Change in Accounting Principle” of the Notes to our Consolidated Financial Statements for additional discussion. 
+Use of Estimates 
+The preparation of financial statements in conformity with GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets and liabilities and revenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating DD&A of proved oil and natural gas property costs, the present value of estimated future net revenues, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated timing of cash outflows underlying asset retirement obligations. There are numerous uncertainties inherent in the estimation of proved oil and gas reserves and in the projection of future rates of production and the timing of development expenditures. Other significant estimates are involved in determining asset retirement obligations, acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of commodity derivative assets and liabilities, and litigation liabilities. Actual results could differ from those estimates. 
+Oil and Natural Gas Properties 
+Oil and natural gas properties are accounted for using the successful efforts method of accounting under which drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities in the field, associated with development wells are capitalized to proved oil and gas properties and are depleted on an asset group basis (properties aggregated based on geographical and geological characteristics) using the units-of-production method based on estimated proved developed oil and gas reserves. Acquired proved properties and proved leasehold acquisition costs are depleted on the same asset group basis using the units-of-production method based on estimated total proved oil and gas reserves. The calculation of depletion expense takes into consideration estimated asset retirement costs, net of estimated salvage values. Proved oil and gas properties are assessed for impairment on an asset group basis whenever events and circumstances indicate that there could be a possible decline in the recoverability of the net book value of such property. 
+The process of estimating proved oil and gas reserves requires that our independent and internal reserve engineers exercise judgment based on available geological, geophysical and technical information. Additionally, operating costs, production and ad valorem taxes, and future development costs are estimated based on current costs. A significant change to our estimated volumes of oil and gas reserves as well as changes to the estimates of prices and costs could have an impact on the depletion rate calculation as well as result in an impairment of oil and gas properties. 
+Impairment of Oil and Natural Gas Properties 
+We assess our proved oil and gas properties for impairment on an asset group basis whenever events and circumstances indicate that there could be a possible decline in the recoverability of the net book value of such property. We estimate the expected future net cash flows of our proved oil and gas properties and compare these undiscounted cash flows to the net book value of the proved oil and gas properties to determine if the net book value is recoverable. If the net book value exceeds the estimated undiscounted future net cash flows, we will recognize an impairment to reduce the net book value of the proved oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future development costs and operating costs, and discount rates, which are based on a weighted average cost of capital. Fair value estimates are based on projected financial information which we believe to be reasonably likely to occur, as of the date that the impairment is measured. See “Note 5 — Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for details of the impairment of $406.9 million recorded in the second quarter of 2023 associated with the assets held for sale classification resulting from the agreement to sell all of our interests of Callon (Eagle Ford) LLC to Ridgemar Energy Operating, LLC. We recognized an impairment of unproved oil and gas properties in the fourth quarter of 2022 of $2.2 million due to certain leases approaching the end of their lease terms with no future plans to develop the acreage. 
+We evaluate significant unproved oil and gas property costs for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or changes in future plans to develop acreage. Unproved oil and gas properties that are not individually significant are aggregated by asset group, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on our historical experience or other information, including current drilling plans and existing geological data. 
+Derivative Instruments 
+We use commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of our forecasted sales of production and achieve a more predictable level of cash flow. We do not use these instruments for speculative or trading purposes. Settlements of derivative contracts are generally based on the difference between the contract price and prices specified in the derivative instrument and a NYMEX price or other futures index price. The estimated fair value of our derivative contracts is based upon current forward market prices on NYMEX and in the case of collars and floors, the time value of options. For additional 
+58 
+information regarding our derivatives instruments and their fair values, see “Note 9 – Derivative Instruments and Hedging Activities” and “Note 10 – Fair Value Measurements” of the Notes to our Consolidated Financial Statements. 
+Our financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments as a result of the volatility of oil and gas prices. See “Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk” for the impact on the fair values of our derivative instruments assuming a 10% increase and decrease in the underlying forward oil and gas price curves as of December 31, 2023. 
+Income Taxes 
+The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. 
+Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that our net deferred tax assets will be utilized prior to their expiration. As previously disclosed in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022, beginning in the second quarter of 2020 and through the fourth quarter of 2022, we maintained a valuation allowance against our net deferred tax assets. Considering all available evidence (both positive and negative), we concluded that it is more likely than not that the deferred tax assets would be realized and released the valuation allowance in the first quarter of 2023. This release resulted in deferred income tax benefit of $187.3 million for the year ended December 31, 2023. See “Note 13 – Income Taxes” of the Notes to our Consolidated Financial Statements for additional discussion. 
+Recently Adopted and Recently Issued Accounting Pronouncements 
+See “Note 2 – Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements for information discussion of recent accounting pronouncements issued by the Financial Accounting Standards Board. 
+ITEM 7A. Quantitative and Qualitative Disclosures about Market Risk 
+We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer credit risk. We mitigate these risks through a program of risk management including the use of commodity derivative instruments. 
+Commodity Price Risk 
+Our revenues are derived from the sale of our oil, natural gas, and NGL production. The prices for oil, natural gas, and NGLs remain volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, government actions, economic conditions, and weather conditions. 
+From time to time, we enter into derivative financial instruments to manage oil, natural gas and NGL price risk, related both to NYMEX benchmark prices and regional basis differentials. The total volumes we hedge through use of our derivative instruments varies from period to period and takes into account our view of current and future market conditions in order to provide greater certainty of cash flows to meet our debt service costs and capital program. We generally hedge for the next 12 to 24 months, subject to the covenants under our Credit Facility. Our hedge policies and objectives may change significantly with movements in commodities prices or futures prices. 
+We may utilize fixed price swaps, which reduce our exposure to decreases in commodity prices, but limit the benefit we might otherwise have received from any increases in commodity prices. Swap contracts may also be enhanced by the simultaneous or subsequent sale or purchase of call or put options to effectively increase the effective swap price as a result of the receipt of premiums from the option sales. 
+We also may utilize price collars to reduce the risk of changes in oil and natural gas prices. Under these arrangements, no payments are due by either party as long as the applicable market price is above the floor price (purchased put option) and below the ceiling price (sold call option) set in the collar. If the price falls below the floor, the counterparty to the collar pays the difference to us, and if the price rises above the ceiling, the counterparty receives the difference from us. Additionally, we may sell put options at a price lower than the floor price in conjunction with a collar (three-way collar) and use the proceeds to increase either or both the floor or ceiling prices. In a three-way collar, to the extent that realized prices are below the floor price of the sold put option (or above the ceiling price of the sold call option), our net realized benefit from the three-way collar will be reduced on a dollar-for-dollar basis. 
+Additionally, we may enter into basis swap contracts which fix the basis differentials between the index price at which the Company sells its production and the relevant NYMEX benchmark price used in swap or collar contracts. 
+We may purchase put options, which reduce our exposure to decreases in oil and natural gas prices while allowing realization of the full benefit from any increases in oil and natural gas prices. If the price falls below the floor, the counterparty pays the difference to us. 
+59 
+We enter into these various agreements from time to time to reduce the effects of volatile oil, natural gas and NGL prices and do not enter into derivative transactions for speculative or trading purposes. Presently, none of our derivative positions are designated as hedges for accounting purposes. 
+The following table sets forth the fair values of our commodity derivative instruments as of December 31, 2023 as well as the impact on the fair values assuming a 10% increase and decrease in the underlying forward oil and gas price curves as of December 31, 2023: 
+Year Ended December 31, 2023 
+Oil Natural Gas NGLs Total 
+(In thousands) 
+Fair value asset (liability) as of December 31, 2023 (1) 
+$4,237 ($414) ($426) $3,397 
+Impact of a 10% increase in forward commodity prices ($14,830) ($1,022) ($777) ($16,629) 
+Impact of a 10% decrease in forward commodity prices $21,040 $263 ($75) $21,228 
+(1) Spot prices for oil and natural gas were $71.71 and $2.51, respectively, as of December 31, 2023. 
+Interest Rate Risk 
+We are subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility. As of December 31, 2023, we had $365.0 million outstanding under the Credit Facility with a weighted average interest rate of 7.54%. An increase or decrease of 1.00% in the interest rate would have a corresponding increase or decrease in our annual interest expense of approximately $3.7 million, based on the balance outstanding as of December 31, 2023. See “Note 8 – Borrowings” of the Notes to our Consolidated Financial Statements for more information on our Credit Facility. 
+Counterparty and Customer Credit Risk 
+Our principal exposures to credit risk are through receivables from the sale of our oil, natural gas and NGL production, joint interest receivables and receivables resulting from derivative financial contracts. 
+For the year ended December 31, 2023, four purchasers each accounted for more than 10% of our oil, natural gas, and NGL revenues. The inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In order to mitigate potential exposure to credit risk, we may require our customers to provide financial security. We are generally paid by our purchasers within 30 to 90 days after the month of production and currently do not believe that we have a risk of not collecting. 
+Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have or intend to drill. We have little ability to control whether these entities will participate in our wells. We generally have the right to withhold future revenue distributions to recover past due receivables from joint interest owners. As of December 31, 2023, our joint interest receivables were approximately $34.6 million and we had no material past due balances. 
+See “Note 9 – Derivative Instruments and Hedging Activities” of the Notes to our Consolidated Financial Statements for discussion of counterparty credit risk associated with our commodity derivative arrangements. 
+60 
+ITEM 8. Financial Statements and Supplementary Data 
+Page 
+Reports of Independent Registered Public Accounting Firm (PCAOB ID Number 248 ) 
+62 
+Consolidated Balance Sheets as of December 31, 2023 and 2022 
+66 
+Consolidated Statements of Operations for the Years Ended December 31, 2023, 2022 and 2021 
+67 
+Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2023, 2022 and 2021 
+68 
+Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021 
+69 
+Notes to Consolidated Financial Statements 
+70 
+61 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+Board of Directors and Shareholders 
+Callon Petroleum Company 
+Opinion on internal control over financial reporting 
+We have audited the internal control over financial reporting of Callon Petroleum Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2023, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2023, and our report dated February 26, 2024 expressed an unqualified opinion on those financial statements. 
+Basis for opinion 
+The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+Definition and limitations of internal control over financial reporting 
+A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+/s/ GRANT THORNTON LLP 
+Houston, Texas 
+February 26, 2024 
+62 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+Board of Directors and Shareholders 
+Callon Petroleum Company 
+Opinion on the financial statements 
+We have audited the accompanying consolidated balance sheets of Callon Petroleum Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2023 and 2022, the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 26, 2024 expressed an unqualified opinion. 
+Change in accounting principle 
+As discussed in Note 3 to the consolidated financial statements, the Company changed the method in which it accounts for oil and natural gas exploration and development activities from the full cost method to the successful efforts method in 2023. This matter is also discussed below as a critical audit matter. 
+Basis for opinion 
+These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. 
+Critical audit matters 
+The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. 
+The development of estimated proved reserves used in the calculation of depletion, depreciation and amortization expense (DD&A) under the successful efforts method of accounting and the valuation of crude oil and natural gas properties in the 2023 Percussion Acquisition (herein referred to as “the crude oil and natural gas reserves”) 
+As described further in Note 2 to the financial statements, the Company accounts for its oil and gas properties using the successful efforts method of accounting which requires management to make estimates of proved reserve volumes and future net revenues to record DD&A expense. Additionally, as described in Note 4 to the financial statements, the Company acquired significant oil and natural gas properties during the year through the Percussion Acquisition. To estimate the volume of proved reserves and future net revenue, management makes significant estimates and assumptions including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected with reasonable certainty to be economical under the appropriate pricing assumptions required in the estimation of DD&A expense. For acquired reserves, management also utilizes an estimated fair value pricing model in determining the corresponding value of proved reserves. 
+63 
+We identified the estimation of proved reserves of oil and natural gas properties, including proved reserves in the Percussion Acquisition, due to its impact on DD&A expense and acquisition accounting, as a critical audit matter. 
+The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain inputs and assumptions necessary to estimate the volumes and future net revenues of the Company’s proved reserves require a high degree of subjectivity and could have a significant impact on the measurement of DD&A expense and acquisition accounting. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment. 
+Our audit procedures related to the estimation of proved reserves included the following, among others. 
+• We tested the design and operating effectiveness of controls relating to management’s estimation of proved reserves for the purpose of estimating DD&A expense and management’s estimation of fair value of the acquired oil and natural gas properties in the Percussion Acquisition. 
+• We evaluated the independence, objectivity, and professional qualifications of the Company’s reserve engineers, made inquiries of those specialists regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the reserve report prepared by the Company’s specialists. 
+• To the extent key inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, including, but not limited to historical pricing differentials, operating costs, estimated development costs, and ownership interests, we tested management’s process for determining the assumptions, including examining the underlying support on a sample basis. Specifically, our audit procedures involved testing management’s assumptions by performing the following: 
+◦ We compared the estimated pricing differentials used in the reserve report to prices realized by the Company related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials 
+◦ We tested models used to estimate the future operating costs in the reserve report and compared amounts to historical operating costs 
+◦ We evaluated the method used to determine estimated future development costs used in the reserve report and compared management’s estimate to amounts expended for recently drilled and completed wells to ascertain its reasonableness 
+◦ We tested the working and net revenue interests used in the reserve report by inspecting land and division order records 
+◦ We evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s ability and intent to develop the proved undeveloped properties, 
+◦ We evaluated the reasonableness of the Company’s classification of reserves as proved or unproved, and 
+◦ We applied analytical procedures to production forecasts in the reserve report by comparing to historical actual results and to the prior year reserve report. 
+◦ As it relates to the recording of the acquisition date values of crude oil and natural gas properties in the Percussion Acquisition, we utilized a valuation specialist to evaluate the appropriateness of forecasted pricing used in the reserve report by comparing the pricing forecast to published product pricing on the acquisition closing date; 
+◦ As it relates to the recording of the acquisition date values of crude oil and natural gas properties in the Percussion Acquisition, we utilized a valuation specialist to evaluate whether the Company’s valuation methodology was reasonable and for certain inputs and assumptions, evaluated the process used to develop the estimate and developed an independent expectation of the estimate to evaluate its reasonableness; 
+◦ As it relates to the recording of the acquisition date values of crude oil and natural gas properties in the Percussion Acquisition, we evaluated the appropriateness of the future operating cost and capital expenditure assumptions used in the reserve report by comparing forecasted amounts to historical operating costs and capital expenditures of similarly located properties; 
+◦ As it relates to the recording of the acquisition date values of crude oil and natural gas properties in the Percussion Acquisition, we compared, on a sample basis, the working and net revenue interests used in the reserve report to the purchase and sale agreement; and 
+◦ As it relates to the recording of the acquisition date values of crude oil and natural gas properties in the Percussion Acquisition, we evaluated, on a sample basis, the appropriateness of management’s estimated future production volumes of proved developed producing properties to subsequent actual production results and management’s estimated future production volumes of proved undeveloped properties by comparing the estimated ultimate recovery per foot to producing wells in the field. 
+Change in Accounting Principle from the Full Cost Method to the Successful Efforts Method 
+As described above and in Note 3 to the financial statements, during the first quarter of 2023, the Company voluntarily changed its method of accounting for oil and natural gas exploration and development activities from the full cost method to the successful efforts method. Accordingly, financial information for prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. As a result of its change in accounting principle, management recorded significant impairments to its proved oil and natural gas properties, and made significant adjustments to DD&A expense, in historical periods to arrive at the recast financial information. As described in Note 2, under the successful efforts method of accounting, drilling and completion costs, including lease and well equipment, intangible development costs, and operation support facilities in the field, associated with the development wells, are capitalized to proved oil and gas properties and are depleted on an asset group basis (properties aggregated 
+64 
+based on geological features or stratigraphic conditions, such as a reservoir or field) using the units-of-production method based on estimated proved developed oil and gas reserves. As further disclosed by management, estimates of oil and natural gas reserves and their fair values used in determining impairment under the successful efforts method of accounting are impacted by, future commodity prices, future production estimates, estimated future development and operating costs, and discount rates, which are based on a weighted average cost of capital. The estimation of reserves requires significant assumptions by management and is also impacted by management’s judgments and estimates regarding the financial performance of wells with proved reserves to determine if wells are expected with reasonable certainty to be economical under the appropriate pricing assumptions required in the measurement of DD&A expense and impairment. We identified the change in accounting principle from the full cost method to the successful efforts method of accounting, due to its impacts on DD&A expense and impairment, as a critical audit matter. 
+The principal considerations for our determination that performing procedures relating to the change in accounting principle from the full cost method to the successful efforts method is a critical audit matter are there was significant judgment by management, including the use of specialists, when developing the estimates of proved oil and natural gas reserves for purposes of reflecting the retrospective application of the successful efforts method, including the calculation of DD&A expense and the calculation of impairment charges recorded to prior periods. This in turn led to a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating the significant assumptions used in developing those estimates. In addition, the audit effort involved the use of professionals with specialized skill and knowledge in evaluating the audit evidence obtained from these procedures. 
+Our audit procedures related to the change in accounting principle from full cost method to successful efforts method included the following, among others. 
+• We tested the design and operating effectiveness of controls related to management’s application of the successful efforts method of accounting to historical periods, inclusive of those related to the determination of reserves in measuring DD&A expense and impairment. 
+• We evaluated the Company’s asset groupings under the successful efforts method of accounting based on geological conditions and stratigraphic features. 
+• We tested the allocation of properties to each asset group within the Company’s historical accounting records and reserve databases, and the assignment of such costs to leasehold and acquisition, and all other tangible and intangible drilling categories which impact the determination of DD&A expense and impairment. 
+• We evaluated the independence, objectivity, and professional qualifications of the Company’s reserve engineers, made inquiries of those specialists regarding the process followed and judgments made to estimate the Company’s proved reserve volumes. 
+• We compared the historical reserve databases used for calculating DD&A expense under the full cost method of accounting to those used in calculating DD&A expense under the successful efforts method of accounting for consistency, as adjusted for the grouping of assets under the successful efforts method of accounting. 
+• To the extent key inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions in measuring impairment under the successful efforts method of accounting are derived from the Company’s accounting records, including, but not limited to historical pricing differentials, operating costs, estimated development costs, and ownership interests, we tested management’s process for determining the assumptions, including examining the underlying support on a sample basis, or to those utilized in the preparation of reserve reports in previously audited periods. Specifically, our audit procedures involved testing management’s assumptions by performing the following: 
+◦ We tested forward commodity pricing used in establishing reserve estimates with the assistance of our valuation specialist; 
+◦ We tested the working and revenue interests used in the reserve report by comparing to historical accounting records; 
+◦ We compared the estimated pricing differential used in the reserve reports to historical accounting records, as adjusted to reflect expected future conditions as applicable; 
+◦ We evaluated the risk adjustments applied to proved undeveloped reserve volumes by comparing against industry accepted factors; 
+◦ We compared future development and operating costs against the Company’s historical estimates and accounting records; 
+◦ We compared future production estimates against historical future production estimates; 
+◦ We evaluated the reasonableness of the weighted average cost of capital; and 
+◦ We applied analytical procedures to production forecasts in the fair value reserve report by comparing to forecasts established in the historical SEC case reserve report used for DD&A expense determinations. 
+/s/ GRANT THORNTON LLP 
+We have served as the Company’s auditor since 2016. 
+Houston, Texas 
+February 26, 2024 
+65 
+Callon Petroleum Company 
+Consolidated Balance Sheets 
+(In thousands, except par and share amounts) 
+December 31, 
+2023 
+2022* 
+ASSETS 
+Current assets: 
+Cash and cash equivalents $ 3,325 $ 3,395 
+Accounts receivable, net 206,791 237,128 
+Fair value of derivatives 11,857 21,332 
+Other current assets 30,154 35,783 
+Total current assets 252,127 297,638 
+Oil and natural gas properties, successful efforts accounting method: 
+Proved properties, net 5,086,973 4,851,529 
+Unproved properties 1,063,033 1,225,768 
+Total oil and natural gas properties, net 6,150,006 6,077,297 
+Other property and equipment, net 26,784 26,152 
+Deferred income taxes 180,963 — 
+Other assets, net 101,596 87,382 
+Total assets $ 6,711,476 $ 6,488,469 
+LIABILITIES AND STOCKHOLDERS’ EQUITY 
+Current liabilities: 
+Accounts payable and accrued liabilities $ 526,446 $ 536,233 
+Fair value of derivatives 24,147 16,197 
+Other current liabilities 96,369 150,384 
+Total current liabilities 646,962 702,814 
+Long-term debt 1,918,655 2,241,295 
+Asset retirement obligations 42,653 53,892 
+Fair value of derivatives 29,880 13,415 
+Other long-term liabilities 81,965 51,272 
+Total liabilities 2,720,115 3,062,688 
+Commitments and contingencies 
+Stockholders’ equity: 
+Common stock, $ 0.01 par value, 130,000,000 shares authorized; 66,474,525 and 
+61,621,518 shares outstanding, respectively 
+665 616 
+Capital in excess of par value 4,186,524 4,022,194 
+Accumulated deficit ( 195,828 ) ( 597,029 ) 
+Total stockholders’ equity 3,991,361 3,425,781 
+Total liabilities and stockholders’ equity $ 6,711,476 $ 6,488,469 
+* Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. 
+The accompanying notes are an integral part of these consolidated financial statements. 
+66 
+Callon Petroleum Company 
+Consolidated Statements of Operations 
+(In thousands, except per share amounts) 
+For the Year Ended December 31, 
+2023 
+2022* 
+2021* 
+Operating Revenues: 
+Oil $ 1,697,026 $ 2,262,647 $ 1,516,225 
+Natural gas 82,468 232,681 141,493 
+Natural gas liquids 174,407 260,472 193,861 
+Sales of purchased oil and gas 389,083 475,164 193,451 
+Total operating revenues 2,342,984 3,230,964 2,045,030 
+Operating Expenses: 
+Lease operating 303,363 290,486 203,141 
+Production and ad valorem taxes 113,512 159,920 100,160 
+Gathering, transportation and processing 108,221 96,902 80,970 
+Exploration 9,143 9,703 6,470 
+Cost of purchased oil and gas 399,242 478,445 201,088 
+Depreciation, depletion and amortization 535,661 494,229 388,612 
+Impairment of oil and gas properties 406,898 2,201 52,295 
+Gain on sale of oil and gas properties ( 23,476 ) — — 
+General and administrative 115,344 97,996 91,605 
+Merger, integration and transaction 11,198 769 14,289 
+Total operating expenses 1,979,106 1,630,651 1,138,630 
+Income From Operations 363,878 1,600,313 906,400 
+Other (Income) Expenses: 
+Interest expense 179,305 187,792 201,659 
+(Gain) loss on derivative contracts ( 18,898 ) 330,953 522,300 
+(Gain) loss on extinguishment of debt ( 1,238 ) 45,658 41,040 
+Other (income) expense ( 6,684 ) 2,645 7,660 
+Total other (income) expense 152,485 567,048 772,659 
+Income Before Income Taxes 211,393 1,033,265 133,741 
+Income tax benefit (expense) 189,808 ( 13,822 ) ( 180 ) 
+Net Income $ 401,201 $ 1,019,443 $ 133,561 
+Net Income Per Common Share: 
+Basic $ 6.20 $ 16.54 $ 2.75 
+Diluted $ 6.19 $ 16.47 $ 2.65 
+Weighted Average Common Shares Outstanding: 
+Basic 64,692 61,620 48,612 
+Diluted 64,852 61,904 50,311 
+* Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. 
+The accompanying notes are an integral part of these consolidated financial statements. 
+67 
+Callon Petroleum Company 
+Consolidated Statements of Stockholders’ Equity 
+(In thousands) 
+Common Capital in Total 
+Stock Excess Accumulated Stockholders’ 
+Shares $ of Par Deficit Equity 
+Previously reported at December 31, 2020 39,759 $ 398 $ 3,222,959 ($ 2,512,355 ) $ 711,002 
+Effect of change in accounting principle — — — 762,322 762,322 
+Balance at December 31, 2020 as recast* 39,759 $ 398 $ 3,222,959 ($ 1,750,033 ) $ 1,473,324 
+Net income — — — 133,561 133,561 
+Restricted stock units 156 2 10,949 — 10,951 
+Warrant exercises 6,913 69 134,748 — 134,817 
+Common stock issued for Primexx Acquisition 9,030 90 420,610 — 420,700 
+Common stock issued for Second Lien Notes Exchange 5,513 55 223,092 — 223,147 
+Balance at December 31, 2021* 61,371 $ 614 $ 4,012,358 ($ 1,616,472 ) $ 2,396,500 
+Net income — — — 1,019,443 1,019,443 
+Restricted stock units 266 3 8,735 — 8,738 
+Common stock issued for Primexx Acquisition ( 15 ) ( 1 ) 1,101 — 1,100 
+Balance at December 31, 2022* 61,622 $ 616 $ 4,022,194 ($ 597,029 ) $ 3,425,781 
+Net income — — — 401,201 401,201 
+Restricted stock units 272 3 11,033 — 11,036 
+Common stock issued for Percussion Acquisition 6,233 62 208,785 — 208,847 
+Repurchase and retirement of common stock ( 1,652 ) ( 16 ) ( 55,488 ) — ( 55,504 ) 
+Balance at December 31, 2023 66,475 $ 665 $ 4,186,524 ($ 195,828 ) $ 3,991,361 
+* Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. 
+The accompanying notes are an integral part of these consolidated financial statements. 
+68 
+Callon Petroleum Company 
+Consolidated Statements of Cash Flows 
+(In thousands) 
+Years Ended December 31, 
+2023 
+2022* 
+2021* 
+Cash flows from operating activities: 
+Net income $ 401,201 $ 1,019,443 $ 133,561 
+Adjustments to reconcile net income to net cash provided by operating activities: 
+Depreciation, depletion and amortization 535,661 494,229 388,612 
+Impairment of oil and gas properties 406,898 2,201 52,295 
+Amortization of non-cash debt related items, net 10,790 12,332 20,033 
+Deferred income tax (benefit) expense ( 187,270 ) 6,308 — 
+(Gain) loss on derivative contracts ( 18,898 ) 330,953 522,300 
+Cash received (paid) for commodity derivative settlements, net 2,922 ( 493,714 ) ( 395,097 ) 
+Gain on sale of oil and gas properties ( 23,476 ) — — 
+(Gain) loss on extinguishment of debt ( 1,238 ) 45,658 41,040 
+Non-cash expense related to share-based awards 11,413 8,042 25,857 
+Other, net 5,387 7,136 11,037 
+Changes in current assets and liabilities: 
+Accounts receivable 48,285 ( 3,480 ) ( 86,402 ) 
+Other current assets ( 16,462 ) ( 15,392 ) ( 10,399 ) 
+Accounts payable and accrued liabilities ( 82,684 ) ( 58,043 ) 146,910 
+Net cash provided by operating activities 1,092,529 1,355,673 849,747 
+Cash flows from investing activities: 
+Capital expenditures ( 968,982 ) ( 848,688 ) ( 454,361 ) 
+Acquisition of oil and gas properties ( 287,939 ) ( 26,706 ) ( 493,462 ) 
+Proceeds from sales of assets 553,222 27,093 188,101 
+Cash paid for settlement of contingent consideration arrangement — ( 19,171 ) — 
+Other, net ( 3,612 ) 14,289 7,718 
+Net cash used in investing activities ( 707,311 ) ( 853,183 ) ( 752,004 ) 
+Cash flows from financing activities: 
+Borrowings on credit facility 3,513,000 3,286,000 2,140,500 
+Payments on credit facility ( 3,651,000 ) ( 3,568,000 ) ( 2,340,500 ) 
+Issuance of 7.5 % Senior Notes due 2030 
+— 600,000 650,000 
+Redemption of 8.25 % Senior Notes due 2025 
+( 187,238 ) — — 
+Redemption of 6.125 % Senior Notes due 2024 
+— ( 467,287 ) ( 542,755 ) 
+Redemption of 9.0 % Second Lien Senior Secured Notes due 2025 
+— ( 339,507 ) — 
+Payment of deferred financing costs ( 922 ) ( 21,898 ) ( 12,672 ) 
+Cash paid to repurchase common stock ( 55,505 ) — — 
+Other, net ( 3,623 ) 1,715 ( 2,670 ) 
+Net cash used in financing activities ( 385,288 ) ( 508,977 ) ( 108,097 ) 
+Net change in cash and cash equivalents ( 70 ) ( 6,487 ) ( 10,354 ) 
+Balance, beginning of period 3,395 9,882 20,236 
+Balance, end of period $ 3,325 $ 3,395 $ 9,882 
+* Financial information for the prior periods has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. 
+The accompanying notes are an integral part of these consolidated financial statements. 
+69 
+INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+1. 
+Description of Business 
+11. 
+Compensation Plans 
+2. 
+Summary of Significant Accounting Policies 
+12. 
+Stockholders’ Equity 
+3. 
+Change in Accounting Principle 
+13. 
+Income Taxes 
+4. 
+Revenue Recognition 
+14. 
+Leases 
+5. 
+Acquisitions and Divestitures 
+15. 
+Asset Retirement Obligations 
+6. 
+Property and Equipment, Net 
+16. 
+Accounts Receivable , Net 
+7. 
+Earnings Per Share 
+17. 
+Accounts Payable and Accrued Liabilities 
+8. 
+Borrowings 
+18. 
+Commitments and Contingencies 
+9. 
+Derivative Instruments and Hedging Activities 
+19. 
+S ubsequent Event s 
+10. 
+Fair Value Measurements 
+20. 
+Supplemental Information on Oil and Natural Gas Operations (Unaudited) 
+Note 1 – Description of Business 
+Callon Petroleum Company is an independent oil and natural gas company focused on the acquisition, exploration and sustainable development of high-quality assets in the Permian Basin in West Texas. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. 
+Merger Agreement 
+On January 3, 2024, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with APA Corporation (“APA”) and Astro Comet Merger Sub Corp., a wholly owned subsidiary of APA (“Merger Sub”). The Merger Agreement provides that, among other things and subject to the terms and conditions of the Merger Agreement, (i) Merger Sub will be merged with and into Callon (the “Merger”), with Callon surviving and continuing as the surviving corporation in the Merger, and (ii) at the effective time of the Merger (the “Effective Time”), each outstanding share of common stock of Callon (other than Excluded Shares (as defined in the Merger Agreement)) will be converted into the right to receive, without interest, 1.0425 shares of common stock of APA, with cash in lieu of fractional shares. 
+The Company’s board of directors (the “Board of Directors”) has unanimously (i) determined that the Merger Agreement and the transactions contemplated thereby are in the best interests of, and advisable to, Callon and Callon shareholders, (ii) approved and declared advisable the Merger Agreement and the transactions contemplated thereby, (iii) resolved to recommend that Callon stockholders approve the Merger Agreement and the transactions contemplated thereby, and (iv) approved the execution, delivery and performance by Callon of the Merger Agreement and the consummation of the transactions contemplated thereby. 
+The completion of the Merger is subject to satisfaction or waiver of certain customary mutual closing conditions, including (i) the receipt of the required approvals from Callon shareholders and APA shareholders, (ii) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the “HSR Act”), (iii) the absence of any governmental order or law prohibiting consummation of the Merger, (iv) the effectiveness of the registration statement on Form S-4 to be filed by APA, pursuant to which the shares of APA common stock to be issued in connection with the Merger will be registered with the SEC, and (v) the APA common stock to be issued pursuant to the Merger Agreement being authorized for listing on the Nasdaq Stock Market. The obligation of each party to consummate the Merger is also conditioned upon the other party’s representations and warranties being true and correct (subject to certain materiality exceptions), the other party having performed in all material respects its obligations under the Merger Agreement and the non-occurrence of any material adverse effect with respect to the other party since the date of the Merger Agreement. 
+The Merger Agreement contains certain termination rights for each of APA and Callon, and in certain circumstances, a termination fee would be payable by the terminating party. 
+If the Merger is consummated, the Company’s common stock will be delisted from the New York Stock Exchange (the “NYSE”) and deregistered under the Securities Exchange Act of 1934, and Callon will cease to be a publicly traded company. 
+For additional information related to the Merger, refer to the filings made with the SEC in connection with such transaction. The Company has prepared this 2023 Annual Report on Form 10-K as if it is going to remain an independent company. If the Merger is consummated, many of the forward-looking statements contained in this 2023 Annual Report on Form 10-K will no longer be applicable. 
+70 
+Note 2 – Summary of Significant Accounting Policies 
+Basis of Presentation and Principles of Consolidation 
+The consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and are presented in accordance with U.S. GAAP. The Company proportionately consolidates its undivided interests in oil and gas properties as well as investments in unincorporated entities, such as partnerships and limited liability companies where the Company, as a partner or member, has undivided interests in the oil and gas properties. In the opinion of management, the accompanying audited consolidated financial statements reflect all adjustments, including normal recurring adjustments, necessary to present fairly the Company’s financial position, results of its operations and cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation. Such reclassifications did not have a material impact on prior period financial statements. The Company evaluates events subsequent to the balance sheet date through the date the financial statements are issued. 
+Use of Estimates 
+The preparation of financial statements in conformity with U.S. GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating depreciation, depletion and amortization (“DD&A”) of proved oil and gas property costs, evaluation of oil and gas properties for impairment, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated timing of cash outflows underlying asset retirement obligations. There are numerous uncertainties inherent in the estimation of proved oil and gas reserves and in the projection of future rates of production and the timing of development expenditures. Other significant estimates are involved in determining asset retirement obligations, acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of commodity derivative assets and liabilities, and litigation liabilities. Actual results could differ from those estimates. 
+Recast Financial Information for Change in Accounting Principle 
+In the first quarter of 2023, the Company voluntarily changed its method of accounting for its oil and gas exploration and development activities from the full cost method to the successful efforts method of accounting. Accordingly, the financial information for prior periods has been recast to reflect retrospective application of the successful efforts method, as prescribed by the FASB Accounting Standards Codification (“ASC”) 932 “Extractive Activities — Oil and Gas.” Although the full cost method of accounting continues to be an accepted alternative, the successful efforts method of accounting is the generally preferred method of the SEC and, because it is more widely used in the industry, the Company expects the change to improve the comparability of its financial statements to its peers. The Company also believes the successful efforts method provides a more representational depiction of assets and operating results and provides for its investments in oil and natural gas properties to be assessed for impairment in accordance with ASC Topic 360 “Property Plant and Equipment,” rather than valuations based on prices and costs prescribed under the full cost method as of the balance sheet date. As required by ASC 250 “Accounting Changes and Error Corrections,” the Company has presented the accumulated effect of the change in accounting principle as a change in the beginning balance of retained earnings (accumulated deficit) of the earliest period presented in the consolidated financial statements. For detailed information regarding the effects of the change to the successful efforts method, see “Note 3 — Change in Accounting Principle.” 
+Cash and Cash Equivalents 
+The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Company maintains cash and cash equivalents in bank deposit accounts and money market funds that may not be fully federally insured. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts. 
+Accounts Receivable, Net 
+Accounts receivable, net consists primarily of receivables from oil, natural gas, and NGL purchasers and joint interest owners in properties the Company operates. The Company generally has the right to withhold future revenue distributions to recover past due receivables from joint interest owners. Generally, the Company’s oil, natural gas, and NGL receivables are collected within 30 to 90 days. The Company’s allowance for credit losses and bad debt expense was immaterial for all periods presented. 
+Concentration of Credit Risk and Major Customers 
+The concentration of accounts receivable from entities in the oil and gas industry may impact the Company’s overall credit risk such that these entities may be similarly affected by changes in economic and other industry conditions. The Company does not believe the loss of any one of its purchasers would materially affect its ability to sell the oil and gas it produces as other purchasers are available 
+71 
+in its primary areas of activity. The Company had the following major customers that represented 10% or more of its oil, natural gas and NGL revenues for at least one of the periods presented: 
+Years Ended December 31, 
+2023 (1) 
+2022 (1) 
+2021 (1) 
+Vitol Inc. 13 % * * 
+Plains Marketing, L.P. 12 * * 
+Rio Energy International, Inc. 12 12 % * 
+BP Products North America, Inc. 12 * * 
+Valero Marketing and Supply Company * 15 13 % 
+Shell Trading Company * * 20 
+Trafigura Trading, LLC * * 15 
+Occidental Energy Marketing, Inc. * * 13 
+(1) The customers that represented over 10% of the Company’s sales of purchased oil and gas were Vitol Inc. and Plains Marketing, L.P., for the years ended December 31, 2023 and 2022, and Vitol Inc. for the year ended December 31, 2021. 
+* - Less than 10% for the respective years. 
+See “Note 9 – Derivative Instruments and Hedging Activities” for discussion of credit risk related with the Company’s commodity derivative counterparties. 
+Oil and Natural Gas Properties 
+Proved Oil and Natural Gas Properties. The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method, drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities in the field, associated with development wells are capitalized to proved oil and gas properties and are depleted on an asset group basis (properties aggregated based on geographical and geological characteristics) using the units-of-production method based on estimated proved developed oil and gas reserves. Acquired proved properties and proved leasehold acquisition costs are depleted on the same asset group basis using the units-of-production method based on estimated total proved oil and gas reserves. The calculation of depletion expense takes into consideration estimated asset retirement costs, net of estimated salvage values. 
+Proved oil and gas properties are assessed for impairment on an asset group basis whenever events and circumstances indicate that there could be a possible decline in the recoverability of the net book value of such property. The Company estimates the expected future net cash flows of its proved oil and gas properties and compares these undiscounted cash flows to the net book value of the proved oil and gas properties to determine if the net book value is recoverable. If the net book value exceeds the estimated undiscounted future net cash flows, the Company will recognize an impairment to reduce the net book value of the proved oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future development costs and operating costs, and discount rates, which are based on a weighted average cost of capital. See “Note 5 — Acquisitions and Divestitures” for details of the impairment recorded in the second quarter of 2023 associated with the sale of all the Company’s interests of Callon (Eagle Ford) LLC to Ridgemar Energy Operating, LLC. There were no impairments of proved oil and gas properties for the years ended December 31, 2022 and 2021. 
+The partial sale of a proved property within an existing asset group is accounted for as a normal retirement and no net gain or loss on divestiture is recognized as long as the treatment does not significantly alter the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A net gain or loss on divestiture is recognized in the consolidated statements of operations for all other sales of proved properties. 
+Unproved Oil and Natural Gas Properties. Unproved oil and gas properties consist of costs incurred in obtaining a mineral interest or a right in a property such as a lease, in addition to broker fees, recording fees and other similar costs. Leasehold costs are classified as unproved until proved reserves are discovered on or otherwise attributed to the property, at which time the related unproved oil and gas property costs are reclassified to proved oil and gas properties and depleted on an asset group basis using the units-of-production method based on estimated total proved oil and gas reserves. 
+The Company evaluates significant unproved oil and gas property costs for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or changes in future plans to develop acreage. Unproved oil and gas properties that are not individually significant are aggregated by asset group, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on the Company’s historical experience or other information, including current drilling plans and existing geological data. Impairment and amortization of unproved oil and gas properties are recognized as “Impairment of oil and gas properties” in the consolidated statements of operations. 
+72 
+Exploratory. Exploratory costs, including personnel and other internal costs, geological and geophysical expenses and delay rentals for oil and gas leases, are expensed as incurred. Exploratory well costs are initially capitalized pending the determination of whether proved reserves have been discovered. If proved reserves are discovered, exploratory well costs are capitalized as proved oil and gas properties. If proved reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. 
+Capitalized Interest. The Company capitalizes interest on expenditures made in connection with exploration and development projects that meet certain thresholds and are not subject to current amortization. For projects that meet these thresholds, interest is capitalized only for the period that activities are in process to bring the projects to their intended use. Capitalized interest cannot exceed interest expense for the period capitalized. During the years ended December 31, 2023, 2022 and 2021, the Company did not have any projects that met the thresholds, therefore, had no capitalized interest. 
+Depreciation of other property and equipment is recognized using the straight-line method based on estimated useful lives ranging from two to twenty years . 
+Deferred Financing Costs 
+Deferred financing costs associated with the Unsecured Senior Notes and previously with the Second Lien Notes, both defined below, are classified as a reduction of the related carrying value on the consolidated balance sheets and are amortized to interest expense using the effective interest method over the terms of the related debt. Deferred financing costs associated with the Credit Facility, as defined below, are classified in “Other assets, net” in the consolidated balance sheets and are amortized to interest expense using the straight-line method over the term of the facility. 
+Asset Retirement Obligations 
+The Company records an estimate of the fair value of liabilities for obligations associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Estimates involved in determining asset retirement obligations include the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a credit-adjusted risk-free discount rate and an inflation factor in order to determine the present value of the asset retirement obligation. The present value of the asset retirement obligations is accreted each period and the increase to the obligation is reported in “Depreciation, depletion and amortization” in the consolidated statements of operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to proved oil and gas properties in the consolidated balance sheets. See “Note 15 – Asset Retirement Obligations” for additional information. 
+Derivative Instruments 
+The Company uses commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of its forecasted sales of production and achieve a more predictable level of cash flow. The Company does not enter into commodity derivative instruments for speculative or trading purposes. All commodity derivative instruments are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. The Company nets its commodity derivative instrument fair value amounts executed with the same counterparty to a single asset or liability pursuant to International Swap Dealers Association Master Agreements (“ISDA Agreements”), which provide for net settlement over the term of the contract and in the event of default or termination of the contract. 
+Settlements of the Company’s commodity derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets. See “Note 10 – Fair Value Measurements” for additional information regarding fair value. 
+The Company has elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. As such, all gains and losses as a result of changes in the fair value of commodity derivative instruments are recognized as “(Gain) loss on derivative contracts” in the consolidated statements of operations in the period in which the changes occur. See “Note 9 – Derivative Instruments and Hedging Activities” and “Note 10 – Fair Value Measurements” for further discussion. 
+Revenue Recognition 
+The Company recognizes revenues from the sales of oil, natural gas, and NGLs to its customers and presents them disaggregated on the Company’s consolidated statements of operations. Revenue is recognized at the point in time when control of the product transfers to the customer. 
+73 
+For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. 
+The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. See “Note 4 – Revenue Recognition” for further discussion. 
+Income Taxes 
+Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are recognized at the end of each reporting period for the future tax consequences of cumulative temporary differences between the tax basis of assets and liabilities and their reported amounts in the Company’s consolidated financial statements based on existing tax laws and enacted statutory tax rates applicable to the periods in which the temporary differences are expected to affect taxable income. U.S. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards and tax credit carryforwards. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering all available evidence (both positive and negative) to determine whether it is more likely than not that all or a portion of the deferred tax assets will not be realized and a valuation allowance is required. See “Note 13 – Income Taxes” for further discussion. 
+Share-Based Compensation 
+The Company grants restricted stock unit awards that may be settled in common stock (“RSU Equity Awards”) or cash (“Cash-Settled RSU Awards”), some of which are subject to achievement of certain performance conditions. Share-based compensation expense is recognized as “General and administrative expense” in the consolidated statements of operations. The Company accounts for forfeitures of equity-based incentive awards as they occur. See “Note 11 – Compensation Plans” for further details of the awards discussed below. 
+RSU Equity Awards and Cash-Settled RSU Awards. Share-based compensation expense for RSU Equity Awards is based on the grant-date fair value and recognized over the vesting period (generally three years for employees and one year for non-employee directors) using the straight-line method. For RSU Equity Awards with vesting terms subject to a performance condition, share-based compensation expense is based on the fair value measured at the grant date as calculated using a Monte Carlo pricing model with the estimated value recognized over the vesting period (generally three years ). Cash-Settled RSU awards that the Company expects, or is required, to settle in cash are accounted for as liabilities with share-based compensation expense based on the fair value measured at each reporting period, with the estimated fair value recognized over the vesting period. 
+Cash SARs. Stock appreciation rights to be settled in cash (“Cash SARs” and together with Cash-Settled RSU Awards, the “Cash-Settled Awards”) are remeasured at fair value at the end of each reporting period with the change in fair value recorded as share-based compensation expense. The liability for Cash SARs is classified as “Other current liabilities” in the consolidated balance sheets as all outstanding awards are vested. The Cash SARs outstanding will expire in 2025 and 2026. 
+Share Repurchase Program 
+The Company repurchases shares of its common stock from time to time under a program authorized by the Board of Directors. The Company retires shares acquired through share repurchases and returns those shares to the status of authorized but unissued. The repurchased and retired shares are recorded as a reduction to “Common stock” and “Capital in excess of par value” in the consolidated balance sheets. See “Note 12 — Stockholders’ Equity” for further discussion. 
+74 
+Supplemental Cash Flow Information 
+The following table sets forth supplemental cash flow information for the periods indicated: 
+Years Ended December 31, 
+2023 
+2022* 
+2021* 
+(In thousands) 
+Interest paid 
+$ 175,076 $ 192,220 $ 168,235 
+Income taxes paid (1) 
+4,477 — — 
+Cash paid for amounts included in the measurement of lease liabilities: 
+Operating cash flows from operating leases $ 7,735 $ 7,096 $ 26,681 
+Investing cash flows from operating leases 42,765 32,060 18,598 
+Non-cash investing and financing activities: 
+Change in accrued capital expenditures ($ 4,251 ) $ 11,696 $ 63,903 
+Change in asset retirement costs 10,636 6,500 2,905 
+ROU assets obtained in exchange for lease liabilities: 
+Operating leases $ 46,098 $ 56,291 $ 24,301 
+Financing leases — — — 
+* Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. 
+(1) The Company did no t pay or receive a refund for any federal income tax for the years ended December 31, 2022, and 2021. For the years ended December 31, 2023, 2022 and 2021, the Company had net payments of approximately $ 4.7 million, $ 0.2 million, and $ 3.2 million, respectively, in state income taxes. 
+Earnings per Share 
+The Company’s basic net income (loss) per common share is based on the weighted average number of shares of common stock outstanding for the period. Diluted net income (loss) per common share is calculated using the treasury stock method and is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the year which include RSU Equity Awards and common stock warrants. When a net loss per common share exists, all potentially dilutive common shares outstanding are anti-dilutive and are therefore excluded from the calculation of diluted weighted average shares outstanding. See “Note 7 – Earnings Per Share” for further discussion. 
+Industry Segment and Geographic Information 
+The Company operates in one industry segment, which is the exploration, development, and production of crude oil, natural gas, and NGLs. All of the Company’s operations are located in the United States and currently all revenues are attributable to customers located in the United States. 
+Recently Adopted Accounting Standards 
+As of December 31, 2023, and through the filing of this report, no new accounting standards have been issued and not yet adopted that are applicable to the Company and that would have a material effect on the Company’s consolidated financial statements and related disclosures. 
+Recently Issued Accounting Standards 
+In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”) followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021 to provide clarifying guidance regarding the scope of Topic 848. ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. Generally, the guidance is to be applied as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. ASU 2020-04 and ASU 2021-01 are effective for all entities through December 31, 2022. In December 2022, the FASB issued ASU 2022-06 which extends the effective date through December 31, 2024. As of December 31, 2023, the Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and ASU 2021-01. Please refer to “Note 8 – Borrowings” for discussion of the Credit Agreement (as defined below) which references SOFR. 
+75 
+Note 3 – Change in Accounting Principle 
+In the first quarter of 2023, the Company voluntarily changed its method of accounting for oil and natural gas exploration and development activities from the full cost method to the successful efforts method. Accordingly, financial information for prior periods has been recast to reflect retrospective application of the successful efforts method. In general, under successful efforts, exploration costs such as exploratory dry holes, exploratory geophysical and geological costs, delay rentals, unproved leasehold impairments and exploration overhead are expensed as incurred as opposed to being capitalized under the full cost method of accounting. The successful efforts method also provides for the assessment of potential proved oil and gas property impairments by comparing the net book value of proved oil and gas properties to associated estimated undiscounted future net cash flows. If the net book value exceeds the estimated undiscounted future net cash flows, an impairment is recorded to reduce the net book value to fair value. Under the full cost method of accounting, an impairment would be required if the net book value of oil and natural gas properties exceeds a full cost ceiling using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months. In addition, gains or losses, if applicable, are recognized more frequently on the divestitures of oil and gas properties under the successful efforts method, as opposed to an adjustment to the net book value of the oil and gas properties under the full cost method. 
+The “Impairment of oil and gas properties” and “Gain on sale of oil and gas properties” line items presented in the tables below are in connection with the sale of all of the Company’s interests of Callon (Eagle Ford) LLC to Ridgemar Energy Operating, LLC. See “Note 5 — Acquisitions and Divestitures” for additional details. 
+The following tables present the effects of the change to the successful efforts method in the consolidated balance sheets: 
+As of December 31, 2023 
+Under 
+Full Cost Changes Under Successful Efforts 
+(In thousands) 
+Oil and natural gas properties: 
+Proved properties $ 11,661,279 ($ 2,004,174 ) $ 9,657,105 
+Accumulated depreciation, depletion, amortization and impairments ( 6,881,323 ) 2,311,191 ( 4,570,132 ) 
+Unproved properties 1,559,952 ( 496,919 ) 1,063,033 
+Total oil and gas properties, net 6,339,908 ( 189,902 ) 6,150,006 
+Deferred income taxes 136,144 44,819 180,963 
+Total assets $ 6,856,559 ($ 145,083 ) $ 6,711,476 
+Stockholders’ equity: 
+Accumulated deficit ( 50,745 ) ( 145,083 ) ( 195,828 ) 
+Total stockholders' equity 4,136,444 ( 145,083 ) 3,991,361 
+Total liabilities and stockholders' equity $ 6,856,559 ($ 145,083 ) $ 6,711,476 
+As of December 31, 2022 
+Under 
+Full Cost Changes Under Successful Efforts 
+(In thousands) 
+Oil and natural gas properties: 
+Proved properties $ 10,367,478 ($ 1,099,343 ) $ 9,268,135 
+Accumulated depreciation, depletion, amortization and impairments ( 6,343,875 ) 1,927,269 ( 4,416,606 ) 
+Unproved properties 1,711,306 ( 485,538 ) 1,225,768 
+Total oil and gas properties, net 5,734,909 342,388 6,077,297 
+Total assets $ 6,146,081 $ 342,388 $ 6,488,469 
+Deferred income taxes (1) 
+4,279 2,029 6,308 
+Stockholders’ equity: 
+Accumulated deficit ( 937,388 ) 340,359 ( 597,029 ) 
+Total stockholders' equity 3,085,422 340,359 3,425,781 
+Total liabilities and stockholders' equity $ 6,146,081 $ 342,388 $ 6,488,469 
+(1) Included in “Other long-term liabilities” in the consolidated balance sheets. 
+76 
+The following tables present the effects of the change to the successful efforts method in the consolidated statements of operations: 
+Year Ended December 31, 2023 
+Under 
+Full Cost Changes Under Successful Efforts 
+(In thousands, except per share amounts) 
+Operating Expenses: 
+Exploration $ — $ 9,143 $ 9,143 
+Depreciation, depletion and amortization 545,144 ( 9,483 ) 535,661 
+Impairment of oil and gas properties — 406,898 406,898 
+Gain on sale of oil and gas properties — ( 23,476 ) ( 23,476 ) 
+General and administrative 77,464 37,880 115,344 
+Income From Operations 784,840 ( 420,962 ) 363,878 
+Other Expenses: 
+Interest expense 67,977 111,328 179,305 
+Income Before Income Taxes 743,683 ( 532,290 ) 211,393 
+Income tax benefit 142,960 46,848 189,808 
+Net Income $ 886,643 ($ 485,442 ) $ 401,201 
+Net Income Per Common Share: 
+Basic $ 13.71 $ 6.20 
+Diluted $ 13.67 $ 6.19 
+Year Ended December 31, 2022 
+Under 
+Full Cost Changes Under Successful Efforts 
+(In thousands, except per share amounts) 
+Operating Expenses: 
+Exploration $ — $ 9,703 $ 9,703 
+Depreciation, depletion and amortization 466,517 27,712 494,229 
+Impairment of oil and gas properties — 2,201 2,201 
+General and administrative 57,393 40,603 97,996 
+Income From Operations 1,680,532 ( 80,219 ) 1,600,313 
+Other Expenses: 
+Interest expense 79,667 108,125 187,792 
+Income Before Income Taxes 1,221,609 ( 188,344 ) 1,033,265 
+Income tax expense ( 11,793 ) ( 2,029 ) ( 13,822 ) 
+Net Income $ 1,209,816 ($ 190,373 ) $ 1,019,443 
+Net Income Per Common Share: 
+Basic $ 19.63 $ 16.54 
+Diluted $ 19.54 $ 16.47 
+77 
+Year Ended December 31, 2021 
+Under 
+Full Cost Changes Under Successful Efforts 
+(In thousands, except per share amounts) 
+Operating Expenses: 
+Exploration $ — $ 6,470 $ 6,470 
+Depreciation, depletion and amortization 356,556 32,056 388,612 
+Impairment of oil and gas properties — 52,295 52,295 
+General and administrative 50,483 41,122 91,605 
+Income From Operations 1,038,343 ( 131,943 ) 906,400 
+Other Expenses: 
+Interest expense 102,012 99,647 201,659 
+Income Before Income Taxes 365,331 ( 231,590 ) 133,741 
+Income tax expense ( 180 ) — ( 180 ) 
+Net Income $ 365,151 ($ 231,590 ) $ 133,561 
+Net Income Per Common Share: 
+Basic $ 7.51 $ 2.75 
+Diluted $ 7.26 $ 2.65 
+The following tables present the effects of the change to the successful efforts method in the consolidated statements of cash flows: 
+Year Ended December 31, 2023 
+Under 
+Full Cost Changes Under Successful Efforts 
+(In thousands) 
+Cash flows from operating activities: 
+Net income $ 886,643 ($ 485,442 ) $ 401,201 
+Adjustments to reconcile net income to net cash provided by operating activities: 
+Depreciation, depletion and amortization 545,144 ( 9,483 ) 535,661 
+Impairment of oil and gas properties — 406,898 406,898 
+Amortization of non-cash debt related items, net 4,064 6,726 10,790 
+Deferred income tax benefit ( 140,422 ) ( 46,848 ) ( 187,270 ) 
+Gain on sale of oil and gas properties — ( 23,476 ) ( 23,476 ) 
+Non-cash expense related to share-based awards 4,019 7,394 11,413 
+Net cash provided by operating activities 1,236,760 ( 144,231 ) 1,092,529 
+Cash flows from investing activities: 
+Capital expenditures ( 1,104,070 ) 135,088 ( 968,982 ) 
+Acquisition of oil and gas properties ( 297,082 ) 9,143 ( 287,939 ) 
+Net cash used in investing activities ( 851,542 ) 144,231 ( 707,311 ) 
+Net change in cash and cash equivalents ( 70 ) — ( 70 ) 
+Balance, beginning of period 3,395 — 3,395 
+Balance, end of period $ 3,325 $ — $ 3,325 
+78 
+Year Ended December 31, 2022 
+Under 
+Full Cost Changes Under Successful Efforts 
+(In thousands) 
+Cash flows from operating activities: 
+Net income $ 1,209,816 ($ 190,373 ) $ 1,019,443 
+Adjustments to reconcile net income to net cash provided by operating activities: 
+Depreciation, depletion and amortization 466,517 27,712 494,229 
+Impairment of oil and gas properties 
+— 2,201 2,201 
+Amortization of non-cash debt related items, net 5,280 7,052 12,332 
+Deferred income tax expense 4,279 2,029 6,308 
+Non-cash expense related to share-based awards 2,507 5,535 8,042 
+Net cash provided by operating activities 1,501,517 ( 145,844 ) 1,355,673 
+Cash flows from investing activities: 
+Capital expenditures ( 992,985 ) 144,297 ( 848,688 ) 
+Acquisition of oil and gas properties ( 28,253 ) 1,547 ( 26,706 ) 
+Net cash used in investing activities ( 999,027 ) 145,844 ( 853,183 ) 
+Net change in cash and cash equivalents ( 6,487 ) — ( 6,487 ) 
+Balance, beginning of period 9,882 — 9,882 
+Balance, end of period $ 3,395 $ — $ 3,395 
+Year Ended December 31, 2021 
+Under 
+Full Cost Changes Under Successful Efforts 
+(In thousands) 
+Cash flows from operating activities: 
+Net income $ 365,151 ($ 231,590 ) $ 133,561 
+Adjustments to reconcile net income to net cash provided by operating activities: 
+Depreciation, depletion and amortization 356,556 32,056 388,612 
+Impairment of oil and gas properties 
+— 52,295 52,295 
+Amortization of non-cash debt related items, net 10,124 9,909 20,033 
+Deferred income tax expense — — — 
+Non-cash expense related to share-based awards 12,923 12,934 25,857 
+Net cash provided by operating activities 974,143 ( 124,396 ) 849,747 
+Cash flows from investing activities: 
+Capital expenditures ( 578,487 ) 124,126 ( 454,361 ) 
+Acquisition of oil and gas properties ( 493,732 ) 270 ( 493,462 ) 
+Net cash used in investing activities ( 876,400 ) 124,396 ( 752,004 ) 
+Net change in cash and cash equivalents ( 10,354 ) — ( 10,354 ) 
+Balance, beginning of period 20,236 — 20,236 
+Balance, end of period $ 9,882 $ — $ 9,882 
+The following tables present the effects of the change to the successful efforts method in the consolidated statements of stockholders’ equity: 
+As of December 31, 2023 
+Under 
+Full Cost Changes Under Successful Efforts 
+(In thousands) 
+Accumulated deficit ($ 50,745 ) ($ 145,083 ) ($ 195,828 ) 
+Total stockholders’ equity $ 4,136,444 ($ 145,083 ) $ 3,991,361 
+79 
+As of December 31, 2022 
+Under 
+Full Cost Changes Under Successful Efforts 
+(In thousands) 
+Accumulated deficit ($ 937,388 ) $ 340,359 ($ 597,029 ) 
+Total stockholders’ equity $ 3,085,422 $ 340,359 $ 3,425,781 
+As of December 31, 2021 
+Under 
+Full Cost Changes Under Successful Efforts 
+(In thousands) 
+Accumulated deficit ($ 2,147,204 ) $ 530,732 ($ 1,616,472 ) 
+Total stockholders’ equity $ 1,865,768 $ 530,732 $ 2,396,500 
+Note 4 – Revenue Recognition 
+Revenue from contracts with customers 
+Oil Sales 
+Under the Company’s oil sales contracts, it sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the point of delivery at the net price received. The Company has certain oil sales that occur at market locations downstream of the production area. Given the structure of these arrangements and where control transfers, the Company separately recognizes fees and other deductions incurred prior to control transfer as “Gathering, transportation and processing” in its consolidated statements of operations. 
+Natural Gas and NGL Sales 
+Under the Company’s natural gas sales processing contracts, it delivers natural gas to a midstream processing entity which gathers and processes the natural gas and either remits proceeds to the Company for the resulting sale of NGLs and residue gas or, in take in-kind arrangements, provides the Company the resulting NGLs and/or residue gas for sale to downstream customers. The Company evaluates whether the processing entity is the principal or the agent in the transaction for each of our natural gas processing agreements and have concluded that the Company maintains control through processing or has the right to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. The Company recognizes revenue when control transfers to the purchaser at the delivery point based on the contractual index price received. 
+The Company recognizes revenue for natural gas and NGLs on a gross basis with gathering, transportation and processing fees recognized separately as “Gathering, transportation and processing” in its consolidated statements of operations as the Company maintains control throughout processing. 
+Oil and Gas Purchase and Sale Arrangements 
+The Company proactively evaluates development plans and looks to enter into pipeline transportation contracts to mitigate market exposures and help ensure certainty of flow for its oil and gas production, in some cases multiple years in advance of development. Additionally, as the Company looks to optimize its operations and reduce exposures, in certain instances, the Company purchases oil and gas from third parties which is utilized to fulfill portions of its pipeline commitments. Sales of purchased oil and gas represent revenues the Company receives from sales of commodities purchased from a third-party. The Company recognizes these revenues and the purchase of the third-party commodities, as well as any costs associated with the purchase, on a gross basis, as the Company acts as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer. As of December 31, 2023 and 2022, receivables from the sales of purchased oil and gas were $ 33.9 million and $ 30.5 million, respectively, and are presented in “Accounts receivable, net” in the consolidated balance sheets. As of December 31, 2023 and 2022, amounts owed for purchases of oil and gas were $ 34.8 million and $ 31.1 million, respectively, and are presented in “Other current liabilities” in the consolidated balance sheets. 
+Accounts Receivable from Revenues from Contracts with Customers 
+Net accounts receivable include amounts billed and currently due from revenues from contracts with customers of our oil and natural gas production, which had a balance at December 31, 2023 and 2022 of $ 132.3 million and $ 174.1 million, respectively, and are presented in “Accounts receivable, net” in the consolidated balance sheets. 
+80 
+Note 5 – Acquisitions and Divestitures 
+2023 Acquisitions and Divestitures 
+Eagle Ford Divestiture 
+On May 3, 2023, the Company entered into an agreement with Ridgemar Energy Operating, LLC (“Ridgemar”) for the sale of all its oil and gas properties in the Eagle Ford (the “Eagle Ford Divestiture”) for consideration of $ 655.0 million in cash, subject to customary purchase price adjustments, as well as contingent consideration where the Company could receive up to $ 45.0 million if the WTI price of oil exceeds certain thresholds in 2024 (“Contingent Eagle Ford Consideration”). See “Note 9 — Derivative Instruments and Hedging Activities” for further discussion of the Contingent Eagle Ford Consideration. Upon signing, Ridgemar paid approximately $ 49.1 million as a deposit into a third-party escrow account. The transaction was structured as the acquisition by Ridgemar of 100 % of the limited liability company interests of the Company’s wholly owned subsidiary, Callon (Eagle Ford) LLC. 
+During the second quarter of 2023, the Company classified the assets and liabilities associated with the Eagle Ford Divestiture as held for sale, and recorded an impairment of $ 406.9 million against properties associated with the Eagle Ford Divestiture as the fair value less cost to sell was less than the carrying amount of the net assets. On July 3, 2023, the Company closed the Eagle Ford Divestiture. The Eagle Ford Divestiture has an adjusted purchase price of approximately $ 549.6 million in cash, inclusive of the deposit paid at signing. As a result, the Company recorded a gain on sale of assets of $ 23.5 million in the third quarter of 2023. 
+Percussion Acquisition 
+On May 3, 2023, the Company entered into an agreement (the “Percussion Agreement”) with Percussion Petroleum Management II, LLC (“Percussion”) for the purchase of its oil and gas properties in the Delaware Basin (the “Percussion Acquisition”) for consideration of $ 475.0 million, which consisted of $ 255.0 million in cash, inclusive of the repayment of Percussion’s indebtedness of approximately $ 220.0 million, and $ 210.0 million of shares of the Company’s common stock, subject to customary purchase price adjustments. Upon signing, the Company paid $ 36.0 million as a deposit into a third-party escrow account. The transaction was structured as the acquisition by Callon Petroleum Operating Company of 100 % of the limited liability company interests of Percussion’s wholly owned subsidiary, Percussion Petroleum Operating II, LLC (“Percussion Operating”). 
+On July 3, 2023, the Company closed the Percussion Acquisition. The Percussion Acquisition has an adjusted purchase price of approximately $ 248.5 million in cash, inclusive of the deposit paid at signing and the repayment of Percussion Operating’s indebtedness of approximately $ 220.0 million, and approximately 6.2 million shares of the Company’s common stock for total consideration of $ 457.3 million . The Company funded the cash portion of the total consideration with proceeds from the Eagle Ford Divestiture. Additionally, the Company assumed Percussion Operating’s (as defined below) existing hedges and transportation contract liabilities, and could have to pay up to $ 62.5 million if the WTI price of oil exceeds certain thresholds in 2023, 2024, and 2025 (“Percussion Earn-Out Obligation”). See “Note 9 - Derivative Instruments and Hedging Activities” for further discussion of the Percussion Earn-Out Obligation. 
+The Percussion Acquisition was accounted for as a business combination; therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values with information available at that time. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. Certain data necessary to complete the purchase price allocation is not yet available. The Company expects to complete the purchase price allocation during the 12-month period following the acquisition date. 
+81 
+The following table sets forth the Company’s preliminary allocation of the total estimated consideration of $ 457.3 million to the assets acquired and liabilities assumed as of the acquisition date. 
+Preliminary Purchase 
+Price Allocation 
+(In thousands) 
+Assets: 
+Accounts receivable, net 
+$ 30,135 
+Proved properties, net 
+490,330 
+Unproved properties 
+52,475 
+Total assets acquired $ 572,940 
+Liabilities: 
+Accounts payable and accrued liabilities 
+$ 42,585 
+Fair value of derivatives - current 
+20,660 
+Other current liabilities 11,471 
+Asset retirement obligations 
+2,323 
+Fair value of derivatives - long-term 
+27,979 
+Other long-term liabilities 10,619 
+Total liabilities assumed $ 115,637 
+Total consideration $ 457,303 
+Approximately $ 131.0 million of revenues and $ 32.5 million of direct operating expenses attributed to the assets acquired in the Percussion Acquisition are included in the Company’s consolidated statements of operations for the period from the closing date on July 3, 2023 through December 31, 2023. 
+Pro Forma Operating Results (Unaudited). The following unaudited pro forma combined condensed financial data for the years ended December 31, 2023 and 2022 was derived from the historical financial statements of the Company and gives effect to the Percussion Acquisition, as if it had occurred on January 1, 2022. The below information reflects pro forma adjustments for the issuance of the Company’s common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Percussion Acquisition. 
+The pro forma consolidated statements of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Percussion Acquisition taken place on January 1, 2022 and is not intended to be a projection of future results. 
+Year ended December 31, 
+2023 2022* 
+(In thousands, except per share amounts) 
+Revenues $ 2,480,799 $ 3,603,315 
+Income from operations 434,369 1,840,018 
+Net income 529,869 1,123,754 
+Basic earnings per common share $ 8.19 $ 16.56 
+Diluted earnings per common share $ 8.17 $ 16.49 
+* Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. 
+2022 Acquisitions and Divestitures 
+The Company did not have any material acquisitions or divestitures for the year ended December 31, 2022. 
+2021 Acquisitions and Divestitures 
+Primexx Acquisition 
+On October 1, 2021, the Company closed on the acquisition of certain producing oil and gas properties, undeveloped acreage and associated infrastructure assets in the Delaware Basin from Primexx Resource Development, LLC (“Primexx”) and BPP Acquisition, 
+82 
+LLC (“BPP”) for an adjusted purchase price of approximately $ 444.8 million in cash, inclusive of the deposit paid at signing, 8.84 million shares of the Company’s common stock and approximately $ 25.2 million paid upon final closing for total consideration of $ 877.0 million (the “Primexx Acquisition”). The Company funded the cash portion of the total consideration with borrowings under its credit facility. Of the 8.84 million shares of the Company’s common stock issued upon closing, 2.6 million shares were held in escrow pursuant to the purchase and sale agreements with Primexx and BPP (collectively, the “Primexx PSAs”). Pursuant to the Primexx PSAs, 1.3 million of the shares held in escrow were released to the sellers six months after the closing date, which was on April 1, 2022. In early October 2022, the remaining 1.2 million shares were released to the sellers, net of shares that were released to the Company for the satisfaction of indemnification claims made under the Primexx PSAs and subsequently retired. 
+Also, pursuant to the Primexx PSAs, certain interest owners exercised their option to sell their interest in the properties included in the Primexx Acquisition to the Company for consideration structured similarly to the Primexx Acquisition, for an incremental purchase price totaling approximately $ 31.8 million, net of customary purchase price adjustments, of which $ 22.4 million closed during the fourth quarter of 2021 and the remaining $ 9.4 million closed during the first quarter of 2022. 
+The Primexx Acquisition was accounted for as a business combination; therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values with information available at that time. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. 
+The following table sets forth the Company’s final allocation of the purchase price of $ 908.9 million to the assets acquired and liabilities assumed as of the acquisition date. 
+Final Purchase 
+Price Allocation 
+(In thousands) 
+Assets: 
+Other current assets $ 8,174 
+Proved properties, net 
+695,838 
+Unproved properties 
+278,370 
+Total assets acquired $ 982,382 
+Liabilities: 
+Suspense payable $ 16,447 
+Other current liabilities 45,745 
+Asset retirement obligation 1,898 
+Other long-term liabilities 9,425 
+Total liabilities assumed $ 73,515 
+Total consideration $ 908,867 
+Approximately $ 570.7 million of revenues and $ 141.2 million of direct operating expenses attributed to the Primexx Acquisition were included in the Company’s consolidated statements of operations for the year ended December 31, 2022 . For the period from the closing date of the Primexx Acquisition on October 1, 2021 through December 31, 2021, approximately $ 114.3 million of revenues and $ 32.1 million of direct operating expenses were included in the Company’s consolidated statements of operations for the year ended December 31, 2021. 
+Pro Forma Operating Results (Unaudited). The following unaudited pro forma combined condensed financial data for the years ended December 31, 2021 and 2020 was derived from the historical financial statements of the Company giving effect to the Primexx Acquisition, as if it had occurred on January 1, 2020. The below information reflects pro forma adjustments for the issuance of the Company’s common stock and the borrowings under the Credit Facility as total consideration, as well as pro forma adjustments based on available information and certain assumptions that the Company believes provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Primexx Acquisition. 
+83 
+The pro forma consolidated statements of operations data has been included for comparative purposes only, is not necessarily indicative of the results that might have occurred had the Primexx Acquisition taken place on January 1, 2020 and is not intended to be a projection of future results. 
+Year Ended December 31, 2021 
+(In thousands, except per share amounts) 
+Revenues $ 2,294,893 
+Income (loss) from operations 1,151,493 
+Net income (loss) 482,690 
+Basic earnings per common share $ 8.37 
+Diluted earnings per common share $ 8.13 
+Non-Core Asset Divestitures 
+During the second quarter of 2021, the Company completed its divestitures of certain non-core assets in the Delaware Basin for net proceeds of $ 29.6 million. The divestitures were primarily comprised of natural gas producing properties in the Western Delaware Basin as well as a small undeveloped acreage position. 
+On November 19, 2021, the Company closed on its divestiture of certain non-core assets in the Eagle Ford Shale, comprised of producing properties as well as an undeveloped acreage position, for net proceeds of $ 91.9 million. 
+In the fourth quarter of 2021, the Company closed on the divestiture of certain non-core assets in the Midland Basin, comprised of producing properties as well as an undeveloped acreage position for net proceeds of $ 30.5 million. 
+On October 28, 2021, the Company closed on the divestiture of certain non-core water infrastructure for net proceeds of $ 27.9 million, as well as up to $ 18.0 million of incremental contingent consideration based on completed lateral length for wells in a specified area. 
+The aggregate net proceeds for each of the 2021 divestitures discussed above were recognized as a reduction of proved oil and gas properties with no gain or loss recognized as the divestitures did not significantly alter the relationship between capitalized costs and estimated proved reserves. 
+Note 6 – Property and Equipment, Net 
+As of December 31, 2023 and 2022, total property and equipment, net consisted of the following: 
+As of December 31, 
+2023 
+2022* 
+Oil and natural gas properties, successful efforts accounting method 
+(In thousands) 
+Proved properties 
+$ 9,657,105 $ 9,268,135 
+Accumulated depreciation, depletion, amortization and impairments ( 4,570,132 ) ( 4,416,606 ) 
+Proved properties, net 
+5,086,973 4,851,529 
+Unproved properties 
+1,063,033 1,225,768 
+Total oil and natural gas properties, net $ 6,150,006 $ 6,077,297 
+Other property and equipment $ 41,011 $ 40,530 
+Accumulated depreciation ( 14,227 ) ( 14,378 ) 
+Other property and equipment, net $ 26,784 $ 26,152 
+* Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. 
+84 
+Capitalized Exploratory Well Cost 
+The following table reflects the changes in capitalized exploratory costs pending the determination of proved reserves and included in unproved properties for the periods presented: 
+Years Ended December 31, 
+2023 
+2022* 
+2021* 
+(In thousands) 
+Beginning of period 
+$ — $ 19,640 $ 13,768 
+Additions pending the determination of proved reserves 
+29,687 47,711 49,294 
+Reclassifications to proved properties 
+( 29,401 ) ( 67,351 ) ( 43,422 ) 
+End of period 
+$ 286 $ — $ 19,640 
+* Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. 
+For the years ended December 31, 2023, 2022 and 2021, the Company did no t have any exploratory well costs capitalized for a period greater than one year after drilling. 
+Impairment of Oil and Gas Properties 
+The Company recognized an impairment of proved oil and gas properties for the year ended December 31, 2023 of $ 406.9 million as the fair value less cost to sell was less than the carrying amount of the net assets associated with the Eagle Ford Divestiture. See “Note 5 - Acquisitions and Divestitures” for further discussion of the Eagle Ford Divestiture. The Company recognized an impairment of unproved oil and gas properties in the fourth quarter of 2022 of $ 2.2 million due to certain leases approaching the end of their lease terms with no future plans to develop the acreage. 
+Note 7 – Earnings Per Share 
+Basic earnings (loss) per share is computed by dividing net income (loss) by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings per share includes the potential dilutive impact of non-vested restricted stock units and unexercised warrants outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. 
+The following table sets forth the computation of basic and diluted earnings per share: 
+Years Ended December 31, 
+2023 
+2022* 
+2021* 
+(In thousands, except per share amounts) 
+Net Income $ 401,201 $ 1,019,443 $ 133,561 
+Basic weighted average common shares outstanding 64,692 61,620 48,612 
+Dilutive impact of restricted stock units 160 284 296 
+Dilutive impact of warrants — — 1,403 
+Diluted weighted average common shares outstanding 64,852 61,904 50,311 
+Net Income Per Common Share 
+Basic $ 6.20 $ 16.54 $ 2.75 
+Diluted $ 6.19 $ 16.47 $ 2.65 
+Restricted stock units (1) 
+64 30 7 
+Warrants (1) 
+481 455 481 
+* Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. 
+(1) Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive. 
+85 
+Note 8 – Borrowings 
+The Company’s borrowings consisted of the following: 
+As of December 31, 
+2023 2022 
+(In thousands) 
+8.25 % Senior Notes due 2025 
+$ — $ 187,238 
+6.375 % Senior Notes due 2026 
+320,783 320,783 
+Senior Secured Revolving Credit Facility due 2027 365,000 503,000 
+8.0 % Senior Notes due 2028 
+650,000 650,000 
+7.5 % Senior Notes due 2030 
+600,000 600,000 
+Total principal outstanding 1,935,783 2,261,021 
+Unamortized premium on 8.25 % Senior Notes 
+— 1,715 
+Unamortized deferred financing costs for Senior Unsecured Notes ( 17,128 ) ( 21,441 ) 
+Long-term debt (1) 
+$ 1,918,655 $ 2,241,295 
+(1) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $ 12.8 million and $ 18.8 million as of December 31, 2023 and 2022, respectively, which are classified in “Other assets, net” in the consolidated balance sheets. 
+Senior Secured Revolving Credit Facility 
+On December 20, 2019, upon consummation of the acquisition of Carrizo Oil & Gas, Inc. (the “Carrizo Acquisition”), the Company entered into the credit agreement with a syndicate of lenders (the “Prior Credit Facility”). The Prior Credit Facility provided for interest-only payments until December 20, 2024, when the Prior Credit Facility would mature and any outstanding borrowings would become due. The maximum credit amount under the Prior Credit Facility was $ 5.0 billion. 
+On October 19, 2022, the Company entered into the Amended & Restated Credit Agreement (the “Credit Agreement” and the senior secured revolving credit facility thereunder, the “Credit Facility”) on substantially similar terms as those in the credit agreement governing the Prior Credit Facility. The Credit Agreement, among other things, extended the term to provide for interest-only payments until October 19, 2027 when the Credit Agreement matures and any outstanding borrowings are due, established a borrowing base of $ 2.0 billion, with an elected commitment amount of $ 1.5 billion, replaced all provisions and related definitions regarding LIBOR with SOFR, and decreased the maximum leverage ratio from 4.00 to 1.00 to 3.50 to 1.00. As of December 31, 2023, the borrowing base under the Credit Facility was $ 2.0 billion, with an elected commitment amount of $ 1.5 billion, and borrowings outstanding of $ 365.0 million at a weighted-average interest rate of 7.54 %, and letters of credit outstanding of $ 21.4 million. 
+Borrowings outstanding under the Credit Agreement bear interest at the Company’s option at either (i) a base rate for a base rate loan plus a margin between 0.75 % to 1.75 %, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.50 %, and the SOFR plus 0.1 % (“Adjusted SOFR”) for a one month period plus 1.00 %, or (ii) an Adjusted SOFR plus a margin between 1.75 % to 2.75 %. The Company also incurs commitment fees at rates ranging between 0.375 % to 0.500 % on the unused portion of lender commitments, which are included in “Interest expense” in the consolidated statements of operations. 
+The borrowing base under the Credit Agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the Credit Agreement, which in each case may reduce the amount of the borrowing base. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. On October 31, 2023, as part of the Company’s fall 2023 redetermination, the borrowing base of $ 2.0 billion and elected commitment amount of $ 1.5 billion was reaffirmed. 
+Senior Unsecured Notes 
+Redemption of 8.25 % Senior Notes. On August 2, 2023, the Company used borrowings under the Credit Facility to redeem all $ 187.2 million of its outstanding 8.25 % Senior Notes due 2025 (the “ 8.25 % Senior Notes”). The Company recognized a gain on extinguishment of debt of approximately $ 1.2 million in its consolidated statements of operations, which primarily related to the remaining unamortized premium. 
+7.5 % Senior Notes. On June 24, 2022, the Company issued and sold $ 600.0 million in aggregate principal amount of 7.5 % senior unsecured notes due 2030 (the “ 7.5 % Senior Notes”) in a private placement for proceeds of approximately $ 588.0 million, net of initial purchasers’ discounts and commissions. The 7.5 % Senior Notes mature on June 15, 2030, and interest is payable semi-annually each June 15 and December 15, commencing on December 15, 2022. 
+At any time prior to June 15, 2025, the Company may, from time to time, redeem up to 35 % of the aggregate principal amount of the 7.5 % Senior Notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 107.5 % of the principal amount, plus accrued and unpaid interest, if any, to, but excluding, the date of redemption, if at least 65 % of 
+86 
+the aggregate principal amount of the 7.5 % Senior Notes remains outstanding after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. Prior to June 15, 2025, the Company may, at its option, on any one or more occasions, redeem all or a portion of the 7.5 % Senior Notes at 100.0 % of the principal amount plus an applicable make-whole premium and accrued and unpaid interest. On or after June 15, 2025, the Company may redeem all or a portion of the 7.5 % Senior Notes at redemption prices decreasing annually from 103.75 % to 100.0 % of the principal amount redeemed plus accrued and unpaid interest. Upon the occurrence of certain kinds of change of control that are accompanied by a ratings decline, each holder of the 7.5 % Senior Notes may require the Company to repurchase all or a portion of such holder’s 7.5 % Senior Notes for cash at a price equal to 101 % of the aggregate principal amount, plus accrued and unpaid interest. 
+8.0 % Senior Notes. On July 6, 2021, the Company issued $ 650.0 million aggregate principal amount of 8.0 % Senior Notes due 2028 (the “ 8.0 % Senior Notes”) in a private placement for proceeds of approximately $ 638.1 million, net of underwriting discounts and commissions and offering costs. The 8.0 % Senior Notes mature on August 1, 2028 and have interest payable semi-annually each February 1 and August 1. 
+At any time prior to August 1, 2024, the Company may, from time to time, redeem up to 35 % of the aggregate principal amount of the 8.0 % Senior Notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 108.0 % of the principal amount, plus accrued and unpaid interest, if any, to, but excluding, the date of redemption, if at least 65 % of the aggregate principal amount of the 8.0 % Senior Notes remains outstanding after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. Prior to August 1, 2024, the Company may, at its option, on any one or more occasions, redeem all or a portion of the 8.0 % Senior Notes at 100.0 % of the principal amount plus an applicable make-whole premium and accrued and unpaid interest. On or after August 1, 2024, the Company may redeem all or a portion of the 8.0 % Senior Notes at redemption prices decreasing annually from 104.0 % to 100.0 % of the principal amount redeemed plus accrued and unpaid interest. Upon the occurrence of certain kinds of change of control, the Company must make an offer to repurchase all or a portion of each holder’s 8.0 % Senior Notes for cash at a price equal to 101 % of the aggregate principal amount, plus accrued and unpaid interest. 
+6.375 % Senior Notes. The Company’s 6.375 % Senior Notes due 2026 (the “ 6.375 % Senior Notes”) mature on July 1, 2026 and have interest payable semi-annually each January 1 and July 1. Since July 1, 2022, the Company may redeem all or a portion of the 6.375 % Senior Notes at redemption prices decreasing annually from 102.125 % to 100 % of the principal amount redeemed plus accrued and unpaid interest. Following a change of control, each holder of the 6.375 % Senior Notes may require the Company to repurchase all or a portion of the 6.375 % Senior Notes at a price of 101 % of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase. 
+Each of the Senior Unsecured Notes described above are guaranteed on a senior unsecured basis by the Company’s wholly owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The subsidiary guarantor is 100 % owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor. 
+Covenants 
+The Credit Agreement and the indentures governing the 6.375 % Senior Notes, the 8.0 % Senior Notes, and the 7.5 % Senior Notes (collectively, the “Senior Unsecured Notes”) limit the Company and certain of its subsidiaries with respect to the amount of additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters, along with maintenance of certain financial ratios. 
+Under the Credit Agreement, the Company must maintain the following financial covenants determined as of the last day of the quarter: (1) a Leverage Ratio (as defined in the Credit Agreement) of no more than 3.50 to 1.00 and (2) a Current Ratio (as defined in the Credit Agreement) of not less than 1.00 to 1.00. The Company was in compliance with these covenants at December 31, 2023. 
+The Credit Agreement and indentures are subject to customary events of default. If an event of default occurs and is continuing, the holders or lenders may elect to accelerate amounts due (except in the case of a bankruptcy event of default, in which case such amounts will automatically become due and payable). 
+Note 9 – Derivative Instruments and Hedging Activities 
+Objectives and Strategies for Using Derivative Instruments 
+The Company is exposed to fluctuations in oil, natural gas and NGL prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil, natural gas and NGL production. The Company utilizes a mix of collars, swaps, put and call options, and basis differential swaps to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes. 
+87 
+Counterparty Risk and Offsetting 
+The Company typically has numerous commodity derivative instruments outstanding with a counterparty that were executed at various dates, for various contract types, commodities and time periods. This often results in both commodity derivative asset and liability positions with that counterparty. The Company nets its commodity derivative instrument fair values executed with the same counterparty to a single asset or liability pursuant to ISDA Agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement. 
+The Company strives to minimize its credit exposure to any individual counterparty and, as such, the Company had outstanding commodity derivative instruments with nine counterparties as of December 31, 2023. All of the counterparties to the Company’s commodity derivative instruments are also lenders under the Company’s Credit Facility. Therefore, each of the Company’s counterparties allow the Company to satisfy any need for margin obligations associated with commodity derivative instruments where the Company is in a net liability position with the collateral securing the Credit Agreement, thus eliminating the need for independent collateral posting. 
+Because each of the Company’s counterparties has an investment grade credit rating, the Company believes it does not have significant credit risk and accordingly does not currently require its counterparties to post collateral to support the net asset positions of its commodity derivative instruments. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each counterparty. 
+While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument. See “Note 10 – Fair Value Measurements” for further discussion. 
+Contingent Consideration Arrangements 
+Percussion Earn-Out Obligation. As a result of the Percussion Acquisition, the Company assumed an earn-out obligation from Percussion Operating, where the Company could be required to pay up to $ 62.5 million in the aggregate if the average daily settlement price of WTI crude oil exceeds $ 60.00 per barrel for each of the 2023, 2024, and 2025 calendar years. The specified threshold for 2023 was met and the Company paid $ 12.5 million in January 2024, which will be classified as cash flows from investing activities in the consolidated statements of cash flows in 2024. 
+Contingent Eagle Ford Consideration. As a result of the Eagle Ford Divestiture, the Company received a contingent consideration arrangement from Ridgemar. The Company could receive up to $ 45.0 million if the average daily settlement price of WTI crude oil for 2024 is at least $ 80.00 per barrel. If the average daily settlement price of WTI crude oil for 2024 is less than $ 80.00 per barrel but at least $ 75.00 per barrel, then the Company would receive $ 20.0 million. 
+The Company determined that the Percussion Earn-Out Obligation and Contingent Eagle Ford Consideration receipt were not clearly and closely related to the Percussion Acquisition and Eagle Ford Divestiture membership interest purchase agreements, and therefore bifurcated these embedded features and recorded these derivatives at their acquisition date fair value and divestiture date fair value of $ 34.9 million and $ 10.9 million, respectively, in the consolidated financial statements. As of December 31, 2023, the estimated fair values of the Percussion Earn-Out Obligation and Contingent Eagle Ford Consideration were $ 42.4 million and $ 12.6 million, respectively, and are presented in “Fair value of derivatives” in the consolidated balance sheets. 
+Ranger Divestiture and Carrizo Acquisition Contingent Consideration . In the second quarter of 2019, the Company completed its divestiture of certain non-core assets in the southern Midland Basin. Additionally, on December 20, 2019, the Company completed the Carrizo Acquisition. Both of these transactions included potential additional contingent consideration if certain specified pricing thresholds were met through the end of 2021. Those pricing thresholds were met for 2021, resulting in a cash receipt and cash payment, respectively, during the first quarter of 2022. Cash received or paid for settlements of contingent consideration arrangements are classified as cash flows from financing activities or cash flows from investing activities, respectively, up to the divestiture or acquisition date fair value, respectively, with any excess classified as cash flows from operating activities. As a result, the Company received $ 20.8 million, of which $ 8.5 million is presented in cash flows from financing activities with the remaining $ 12.3 million presented in cash flows from operating activities, and paid $ 25.0 million, of which $ 19.2 million is presented in cash flows from 
+88 
+investing activities with the remaining $ 5.8 million presented in cash flows from operating activities. Both of these contingent consideration arrangements were completed as of the end of 2021. 
+Financial Statement Presentation and Settlements 
+The Company records its derivative instruments at fair value in the consolidated balance sheets and records changes in fair value, as well as settlements during the period, as “(Gain) loss on derivative contracts” in the consolidated statements of operations. The Company presents the fair value of derivative contracts on a net basis in the consolidated balance sheets as they are subject to master netting arrangements. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated: 
+As of December 31, 2023 
+Presented without As Presented with 
+Effects of Netting Effects of Netting Effects of Netting 
+(In thousands) 
+Derivative Assets 
+Commodity derivative instruments $ 25,813 ($ 13,956 ) $ 11,857 
+Fair value of derivatives - current $ 25,813 ($ 13,956 ) $ 11,857 
+Commodity derivative instruments $ — $ — $ — 
+Contingent consideration arrangements 12,580 — 12,580 
+Other assets, net 
+$ 12,580 $ — $ 12,580 
+Derivative Liabilities 
+Commodity derivative instruments (1) 
+($ 25,603 ) $ 13,956 ($ 11,647 ) 
+Contingent consideration arrangements ( 12,500 ) — ( 12,500 ) 
+Fair value of derivatives - current ($ 38,103 ) $ 13,956 ($ 24,147 ) 
+Commodity derivative instruments $ — $ — $ — 
+Contingent consideration arrangements ( 29,880 ) — ( 29,880 ) 
+Fair value of derivatives - non-current 
+($ 29,880 ) $ — ($ 29,880 ) 
+(1) Includes approximately $ 4.1 million of deferred premiums, which will be paid as the applicable contracts settled. 
+As of December 31, 2022 
+Presented without As Presented with 
+Effects of Netting Effects of Netting Effects of Netting 
+(In thousands) 
+Derivative Assets 
+Fair value of derivatives - current $ 51,984 ($ 30,652 ) $ 21,332 
+Other assets, net 
+$ 1,343 ($ 889 ) $ 454 
+Derivative Liabilities 
+Fair value of derivatives - current ($ 46,849 ) $ 30,652 ($ 16,197 ) 
+Fair value of derivatives - non-current 
+($ 14,304 ) $ 889 ($ 13,415 ) 
+The components of “(Gain) loss on derivative contracts” are as follows for the respective periods: 
+Years Ended December 31, 
+2023 2022 2021 
+(In thousands) 
+(Gain) loss on oil derivatives ($ 22,371 ) $ 287,379 $ 429,156 
+(Gain) loss on natural gas derivatives 
+( 4,990 ) 38,803 33,621 
+Loss on NGL derivatives 2,663 4,771 6,768 
+(Gain) loss on contingent consideration arrangements 5,800 — ( 2,635 ) 
+Loss on September 2020 Warrants liability (1) 
+— — 55,390 
+(Gain) loss on derivative contracts ($ 18,898 ) $ 330,953 $ 522,300 
+(1) A detailed discussion of the Company’s September 2020 Warrants can be found in “Part II, Item 8. Financial Statements and Supplementary Data, Note 7 – Borrowings” of its Annual Report on Form 10-K for the year ended December 31, 2021, which was filed with the SEC on February 24, 2022. 
+89 
+The components of “Cash received (paid) for commodity derivative settlements, net” and “Cash received (paid) for settlements of contingent consideration arrangements, net” are as follows for the respective periods: 
+Years Ended December 31, 
+2023 2022 2021 
+(In thousands) 
+Cash flows from operating activities 
+Cash paid on oil derivatives ($ 14,626 ) ($ 429,017 ) ($ 350,340 ) 
+Cash received (paid) on natural gas derivatives 18,109 ( 60,914 ) ( 34,576 ) 
+Cash paid on NGL derivatives ( 561 ) ( 3,783 ) ( 10,181 ) 
+Cash received (paid) for commodity derivative settlements, net $ 2,922 ($ 493,714 ) ($ 395,097 ) 
+Cash received for settlements of contingent consideration arrangements, net (1) $ — $ 6,492 $ — 
+Cash flows from investing activities 
+Cash paid for settlement of contingent consideration arrangement $ — ($ 19,171 ) $ — 
+Cash flows from financing activities 
+Cash received for settlement of contingent consideration arrangement $ — $ 8,512 $ — 
+Derivative Positions 
+Listed in the tables below are the outstanding oil, natural gas, and NGL derivative contracts as of December 31, 2023: 
+For the Full Year 
+Oil Contracts (WTI) 2024 
+Deferred Premium Put Contracts (1)(2) 
+Total volume (Bbls) 1,076,300 
+Weighted average price per Bbl $ 81.66 
+Three-Way Collar Contracts 
+Total volume (Bbls) 3,963,025 
+Weighted average price per Bbl 
+Ceiling (short call) $ 78.86 
+Floor (long put) $ 58.16 
+Floor (short put) $ 48.16 
+(1) Deferred premium put contracts are a combination of a short fixed price swap and a long call option which then performs as a long put position. 
+(2) Premiums associated with the Company’s deferred premium puts were approximately $ 4.1 million, which will be paid as the applicable contracts settle. 
+90 
+For the Full Year 
+Natural Gas Contracts (Henry Hub) 2024 
+Collar Contracts 
+Total volume (MMBtu) 8,598,557 
+Weighted average price per MMBtu 
+Ceiling (short call) $ 3.89 
+Floor (long put) $ 3.00 
+Natural Gas Contracts (Waha Basis Differential) 
+Swap Contracts 
+Total volume (MMBtu) 7,320,000 
+Weighted average price per MMBtu ($ 1.06 ) 
+Natural Gas Contracts (HSC Basis Differential) 
+Swap Contracts 
+Total volume (MMBtu) 14,640,000 
+Weighted average price per MMBtu ($ 0.42 ) 
+For the Full Year 
+NGL Contracts (Mont Belvieu Normal Butane) 
+2024 
+Swap Contracts 
+Total volume (Bbls) 72,105 
+Weighted average price per Bbl $ 33.18 
+NGL Contracts (Mont Belvieu Isobutane) 
+Swap Contracts 
+Total volume (Bbls) 23,462 
+Weighted average price per Bbl $ 33.18 
+Note 10 – Fair Value Measurements 
+Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: 
+Level 1 – Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities. 
+Level 2 – Other inputs that are observable directly or indirectly, such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. 
+Level 3 – Unobservable inputs for which there is little or no market data and for which the Company makes its own assumptions about how market participants would price the assets and liabilities. 
+Fair Value of Financial Instruments 
+Cash, Cash Equivalents, and Restricted Investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments. 
+Debt. The carrying amount of borrowings outstanding under the Credit Facility approximates fair value as the borrowings bear interest at variable rates and are reflective of market rates. The following table presents the principal amounts of the Senior Notes with the fair values measured using quoted secondary market trading prices which are designated as Level 2 within the valuation hierarchy. 
+December 31, 2023 December 31, 2022 
+Principal Amount Fair Value Principal Amount Fair Value 
+(In thousands) 
+8.25 % Senior Notes 
+$ — $ — $ 187,238 $ 186,719 
+6.375 % Senior Notes 
+320,783 320,119 320,783 301,732 
+8.0 % Senior Notes 
+650,000 665,164 650,000 616,935 
+7.5 % Senior Notes 
+600,000 606,414 600,000 550,812 
+Total $ 1,570,783 $ 1,591,697 $ 1,758,021 $ 1,656,198 
+91 
+Assets and Liabilities Measured at Fair Value on a Recurring Basis 
+Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheets. The following methods and assumptions were used to estimate fair value: 
+Commodity Derivative Instruments. The fair value of commodity derivative instruments is derived using a third-party income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the commodity derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for commodity derivative assets and an estimate of the Company’s default risk for commodity derivative liabilities. As the inputs in the model are substantially observable over the term of the commodity derivative contract and as there is a wide availability of quoted market prices for similar commodity derivative contracts, the Company designates its commodity derivative instruments as Level 2 within the fair value hierarchy. See “Note 9 – Derivative Instruments and Hedging Activities” for further discussion. 
+Contingent Consideration Arrangements - Embedded Derivative Financial Instruments. The embedded options within the contingent consideration arrangements are considered financial instruments under ASC 815. The Company engages a third-party valuation specialist using an option pricing model approach to measure the fair value of the embedded options on a recurring basis. The valuation includes significant inputs such as forward oil price curves, time to expiration, and implied volatility. The model provides for the probability that the specified pricing thresholds would be met for each settlement period, estimates undiscounted payouts, and risk adjusts for the discount rates inclusive of adjustments for each of the counterparty’s credit quality. As these inputs are substantially observable for the full term of the contingent consideration arrangements, the inputs are considered Level 2 inputs within the fair value hierarchy. See “Note 9 - Derivative Instruments and Hedging Activities” for further discussion. 
+The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2023 and 2022: 
+December 31, 2023 
+Level 1 Level 2 Level 3 
+(In thousands) 
+Derivative Assets 
+Commodity derivative assets $ — $ 11,857 $ — 
+Contingent consideration arrangements — 12,580 — 
+Total net assets 
+$ — $ 24,437 $ — 
+Derivative Liabilities 
+Commodity derivative liabilities (1) 
+$ — ($ 11,647 ) $ — 
+Contingent consideration arrangements — ( 42,380 ) — 
+Total net assets (liabilities) $ — ($ 54,027 ) $ — 
+December 31, 2022 
+Level 1 Level 2 Level 3 
+(In thousands) 
+Commodity derivative assets 
+$ — $ 21,786 $ — 
+Commodity derivative liabilities 
+$ — ($ 29,612 ) $ — 
+(1) Includes approximately $ 4.1 million of deferred premiums, which will be paid as the applicable contracts settled. 
+There were no transfers between any of the fair value levels during any period presented. 
+Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis 
+Acquisitions. The fair value of assets acquired and liabilities assumed are measured as of the acquisition date by a third-party valuation specialist using a combination of income and market approaches, which are not observable in the market and are therefore designated as Level 3 inputs. Significant inputs include expected discounted future cash flows from estimated reserve quantities, estimates for timing and costs to produce and develop reserves, oil and natural gas forward prices, and a risk adjusted discount rate. See “Note 5 – Acquisitions and Divestitures” for additional discussion. 
+Asset Retirement Obligations. The Company measures the fair value of asset retirement obligations as of the date a well begins drilling or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and that, therefore, are designated as Level 3 within the valuation hierarchy. Significant inputs to the fair value measurement of asset retirement obligations include estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities, restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates. See “Note 15 – Asset Retirement Obligations” for additional discussion. 
+92 
+Note 11 – Compensation Plans 
+2020 Omnibus Incentive Plan 
+Shares-based awards are granted under the 2020 Omnibus Incentive Plan (the “2020 Plan”), which replaced the 2018 Omnibus Incentive Plan (the “2018 Plan”). From the effective date of the 2020 Plan, no further awards may be granted under the 2018 Plan; however, awards previously granted under the 2018 Plan will remain outstanding in accordance with their terms. At December 31, 2023, there were 1,326,047 shares available for future share-based awards under the 2020 Plan. 
+RSU Equity Awards 
+The following table summarizes RSU Equity Award activity for the year ended December 31, 2023: 
+RSU Equity Awards (In thousands) Weighted Average Grant-Date Fair Value per Share 
+Unvested at the beginning of the year 800 $ 44.79 
+Granted 654 $ 34.33 
+Vested ( 374 ) $ 39.89 
+Forfeited ( 225 ) $ 42.75 
+Unvested at the end of the year 855 $ 39.46 
+Grant activity for the years ended December 31, 2023, 2022 and 2021 primarily consisted of RSU Equity Awards granted to executives and employees as part of the annual grant of long-term equity incentive awards with a weighted average grant date fair value of $ 34.33 , $ 57.85 and $ 38.59 , respectively. 
+For performance-based RSU Equity Awards vested on December 31, 2022 and December 31, 2021, the number of performance-based RSU Equity Awards that could vest was based on a calculation that compares the Company’s TSR to the same calculated return of a group of peer companies selected by the Company and can range between 0 % and 300 % and 0 % and 200 % of the target units, respectively. No performance-based RSU Equity Awards vested during 2023. 
+The following table summarizes the shares that vested and did not vest as a result of the Company’s performance as compared to its peers. 
+Years Ended December 31, 
+Performance-based Equity Awards 2022 2021 
+Vesting Multiplier 18 % 50 % 
+Target 86,455 28,356 
+Vested at end of performance period 15,559 14,177 
+Did not vest at end of performance period 70,896 14,179 
+The aggregate fair value of RSU Equity Awards that vested during the years ended December 31, 2023, 2022 and 2021 was $ 12.5 million, $ 22.4 million and $ 8.7 million, respectively. As of December 31, 2023, unrecognized compensation costs related to unvested RSU Equity Awards were $ 22.1 million and will be recognized over a weighted average period of 1.7 years. 
+Cash-Settled Awards 
+As of December 31, 2023 and 2022, the Company had a total liability of $ 2.2 million and $ 6.5 million, respectively, for the outstanding Cash-Settled Awards. 
+93 
+Share-Based Compensation Expense, Net 
+Share-based compensation expense associated with the RSU Equity Awards, Cash-Settled Awards is included in “General and administrative” in the consolidated statements of operations. The following table presents share-based compensation expense (benefit), net for each respective period: 
+Years Ended December 31, 
+2023 
+2022* 
+2021* 
+(In thousands) 
+RSU Equity Awards expense 
+$ 14,658 $ 15,535 $ 13,230 
+Cash-Settled Awards (benefit) expense 
+( 3,245 ) ( 7,493 ) 12,627 
+Total share-based compensation expense, net 
+$ 11,413 $ 8,042 $ 25,857 
+* Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. 
+401(k) Plan 
+The Company has a defined contribution plan (“401(k) Plan”) that is subject to the Employee Retirement Income Security Act of 1974. The 401(k) Plan allows eligible employees to contribute 1 % to 100 % of their qualified annual earnings, as defined by the 401(k) Plan, up to the contribution limits established under the Internal Revenue Code (the “IRC”). The Company matches 100 % of each employee’s contributions, up to 6 % of the employee’s eligible compensation, and may make additional contributions as may be determined by the Company’s Board of Directors. The Company’s contributions to the 401(k) Plan were $ 3.6 million, $ 3.0 million, and $ 2.2 million for the years ended December 31, 2023, 2022, and 2021, respectively. 
+Note 12 – Stockholders’ Equity 
+Share Repurchase Program 
+On May 2, 2023, the Board of Directors approved a share repurchase program (the “Share Repurchase Program”), pursuant to which the Company is authorized to repurchase up to $ 300.0 million of its outstanding common stock through the second quarter of 2025. Repurchases under the Share Repurchase Program may be made, from time to time, in amounts and at prices the Company deems appropriate and will be subject to a variety of factors, including the market price of the Company’s common stock, general market and economic conditions and applicable legal requirements. The Share Repurchase Program may be suspended, modified or discontinued by the Board of Directors at any time without prior notice. Pursuant to the Merger Agreement, we are restricted from making further repurchases under such program without APA’s approval. 
+During the year ended December 31, 2023, the Company repurchased and retired 1.7 million shares of common stock at a weighted average purchase price of $ 33.59 per common share for a total cost of approximately $ 55.5 million. As of December 31, 2023, the remaining authorized repurchase amount under the Share Repurchase Program was $ 244.5 million. 
+Percussion Acquisition 
+During the year ended December 31, 2023, the Company issued approximately 6.2 million shares of common stock in connection with the Percussion Acquisition. See “Note 5 – Acquisitions and Divestitures” for additional details. 
+Second Lien Note Exchange 
+On November 3, 2021, at a special meeting of shareholders, the Company obtained the requisite shareholder approval for the issuance of approximately 5.5 million shares of the Company’s common stock in exchange for an aggregate of $ 197.0 million principal amount of Second Lien Notes. The exchange was completed on November 5, 2021 and the exchanged Second Lien Notes were immediately cancelled. 
+Primexx Acquisition 
+During the fourth quarter of 2021, the Company issued approximately 9.0 million shares of common stock in connection with the Primexx Acquisition, inclusive of the shares of common stock issued to those certain interest owners who exercised their option to sell their interest in the properties included in the Primexx Acquisition. See “Note 5 – Acquisitions and Divestitures” for additional details. 
+Warrant Exercises 
+During the year ended December 31, 2021, holders of the September 2020 Warrants and November 2020 Warrants provided notice and exercised all outstanding warrants. As a result of the exercises in 2021, the Company issued a total of 6.9 million shares of its common stock in exchange for 9.0 million outstanding warrants determined on a net shares settlement basis. A detailed discussion of the Company’s September 2020 Warrants and November 2020 Warrants can be found in “Part II, Item 8. Financial Statements and 
+94 
+Supplementary Data, Note 7 – Borrowings” of its Annual Report on Form 10-K for the year ended December 31, 2021, which was filed with the SEC on February 24, 2022. As of December 31, 2023, December 31, 2022 and December 31, 2021, no September 2020 or November 2020 Warrants were outstanding. 
+Note 13 – Income Taxes 
+The components of the Company’s income tax expense are as follows: 
+Years Ended December 31, 
+2023 
+2022* 
+2021* 
+(In thousands) 
+Current 
+Federal ($ 2,271 ) $ 2,977 $ — 
+State ( 266 ) 4,537 180 
+Total current income tax expense (benefit) 
+( 2,537 ) 7,514 180 
+Deferred 
+Federal ( 188,911 ) — — 
+State 1,640 6,308 — 
+Total deferred income tax expense (benefit) 
+( 187,271 ) 6,308 — 
+Total income tax expense (benefit) 
+($ 189,808 ) $ 13,822 $ 180 
+* Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. 
+A reconciliation of the income tax expense calculated at the federal statutory rate of 21 % to income tax expense is as follows: 
+Years Ended December 31, 
+2023 
+2022* 
+2021* 
+(In thousands) 
+Income before income taxes 
+$ 211,393 $ 1,033,265 $ 133,741 
+Income tax expense computed at the statutory federal income tax rate 
+44,393 216,986 28,086 
+State income tax expense (benefit), net of federal benefit 1,430 11,393 2,905 
+Non-deductible expenses related to capital structure transactions — ( 2,896 ) ( 11,875 ) 
+Equity based compensation 385 ( 1,496 ) 564 
+Other 2,364 ( 1,223 ) 10,247 
+Change in valuation allowance ( 238,380 ) ( 208,942 ) ( 29,747 ) 
+Income tax expense (benefit) 
+($ 189,808 ) $ 13,822 $ 180 
+* Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. 
+The income tax benefit of $ 189.8 million for the year ended December 31, 2023 differs from income tax expense as calculated using the federal statutory rate primarily as a result of releasing the valuation allowance that was recorded against the Company’s net deferred tax assets. See “— Deferred Tax Asset Valuation Allowance” below for additional details. 
+95 
+As of December 31, 2023 and 2022, the net deferred income tax assets and liabilities are comprised of the following: 
+As of December 31, 
+2023 
+2022* 
+(In thousands) 
+Deferred tax assets 
+Federal net operating loss carryforward and credits 
+$ 412,401 $ 359,784 
+Net interest expense limitation 84,202 74,628 
+Derivative instruments 6,507 12,758 
+Operating lease right-of-use assets 15,724 13,180 
+Asset retirement obligations 10,165 13,049 
+Unvested RSU equity awards 6,214 5,391 
+Other 4,260 11,675 
+Total deferred tax assets $ 539,473 $ 490,465 
+Deferred income tax valuation allowance — ( 238,380 ) 
+Net deferred tax assets $ 539,473 $ 252,085 
+Deferred tax liability 
+Oil and natural gas properties ($ 346,050 ) ($ 248,508 ) 
+Operating lease liabilities ( 12,460 ) ( 9,885 ) 
+Total deferred tax liability ($ 358,510 ) ($ 258,393 ) 
+Net deferred tax asset (liability) $ 180,963 ($ 6,308 ) 
+* Financial information for the prior period has been recast to reflect retrospective application of the successful efforts method of accounting. See “Note 2 - Summary of Significant Accounting Policies” for additional information. 
+Deferred Tax Asset Valuation Allowance 
+Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that the Company’s net deferred tax assets will be utilized prior to their expiration. Beginning in the second quarter of 2020 and through the fourth quarter of 2022, the Company maintained a valuation allowance against its net deferred tax assets. Considering all available evidence (both positive and negative), the Company concluded that it was more likely than not that the deferred tax assets would be realized and released the valuation allowance in the first quarter of 2023. This release resulted in deferred income tax benefit of $ 187.3 million for the year ended December 31, 2023. 
+Federal Net Operating Losses (“NOLs”) & Interest Limitation Carryforwards 
+Due to the issuance of common stock pursuant to the acquisition of Carrizo, the Company incurred a cumulative ownership change, and as such, the Company’s NOLs prior to the acquisition are subject to a combined annual limitation under the IRC Section 382 in the amount of $ 32.2 million, which is comprised of $ 15.7 million of Carrizo’s NOLs and $ 16.5 million of Callon’s NOLs. At December 31, 2023, the Company had approximately $ 2.0 billion of NOLs of which $ 399.3 million expire between 2034 and 2037 and $ 1.5 billion have an indefinite carryforward life. The Company also has a net interest expense carryforward of $ 401.0 million under Section 163(j) of the Code, subject to indefinite carryforward. 
+Uncertain Tax Positions 
+During 2023, the Company recorded a $ 4.1 million reserve for unrecognized tax benefits related to estimated current year research and development tax credits. If recognized, the net tax benefit of $ 4.1 million would not have a material effect on the Company's effective tax rate. The Company recognized an immaterial amount of interest associated with the uncertain tax position in income tax expense. 
+In the Company’s major tax jurisdictions, the earliest year open to examination is 2019. 
+Note 14 – Leases 
+The Company currently has leases associated with contracts for office space, drilling rigs, and the use of well equipment, vehicles, information technology infrastructure, and other office equipment. The tables below, which present the components of lease costs and 
+96 
+supplemental balance sheet information, are presented on a gross basis. Other joint owners in the properties operated by the Company generally pay for their working interest share of costs associated with drilling rigs and well equipment. 
+The table below presents the components of the Company’s lease costs for the year ended December 31, 2023. 
+Years Ended December 31, 
+2023 2022 2021 
+(In thousands) 
+Components of Lease Costs 
+Finance lease costs $ 262 $ 228 $ 277 
+Amortization of right-of-use assets (1) 
+251 203 237 
+Interest on lease liabilities (2) 
+11 25 40 
+Operating lease cost (3) 
+49,502 38,803 37,734 
+Short-term lease cost (4) 
+24,860 19,426 347 
+Variable lease costs (5) 
+3,327 2,098 284 
+Total lease costs $ 77,951 $ 60,555 $ 38,642 
+(1) Included as a component of “Depreciation, depletion and amortization” in the consolidated statements of operations. 
+(2) Included as a component of “Interest expense” in the consolidated statements of operations. 
+(3) For the years ended December 31, 2023, 2022 and 2021, approximately $ 42.1 million, $ 33.3 million and $ 23.0 million, respectively, are costs associated with drilling rigs. These costs were capitalized to “Proved properties, net” in the consolidated balance sheets and the other remaining operating lease costs were components of “General and administrative” and “Lease operating” in the consolidated statements of operations. 
+(4) Short-term lease cost primarily consists of drilling rigs with contract terms of less than one year. 
+(5) Variable lease costs include additional payments that were not included in the initial measurement of the lease liability and related ROU asset for lease agreements with terms greater than 12 months. Variable lease costs primarily consist of incremental usage associated with drilling rigs. 
+The table below presents supplemental balance sheet information for the Company’s operating leases including the line item in the consolidated balance sheets where each is presented. The Company’s financing leases are immaterial. 
+As of December 31, 
+2023 2022 
+(In thousands) 
+Leases 
+Operating leases: 
+Other assets, net - Operating lease ROU assets 
+$ 59,268 $ 47,018 
+Other current liabilities - Current operating lease liabilities 
+$ 22,070 $ 40,809 
+Other long-term liabilities - Long-term operating lease liabilities 
+52,723 21,882 
+Total operating lease liabilities $ 74,793 $ 62,691 
+The table below presents the weighted average remaining lease terms and weighted average discounts rates for the Company’s leases as of December 31, 2023. 
+December 31, 2023 
+Weighted Average Remaining Lease Terms (In years) 
+Operating leases 7.9 
+Financing leases 0.2 
+Weighted Average Discount Rate 
+Operating leases 8.9 % 
+Financing leases 6.6 % 
+97 
+The table below presents the maturity of the Company’s lease liabilities as of December 31, 2023. 
+Operating Leases Financing Leases 
+(In thousands) 
+2024 $ 27,207 $ 38 
+2025 8,066 — 
+2026 9,439 — 
+2027 9,526 — 
+2028 9,645 — 
+Thereafter 42,528 — 
+Total lease payments 106,411 38 
+Less imputed interest ( 31,618 ) — 
+Total lease liabilities $ 74,793 $ 38 
+Note 15 – Asset Retirement Obligations 
+The table below summarizes the activity for the Company’s asset retirement obligations: 
+Years Ended December 31, 
+2023 2022 
+(In thousands) 
+Asset retirement obligations, beginning of period $ 60,435 $ 56,707 
+Accretion expense 3,465 3,997 
+Liabilities incurred 2,379 669 
+Increase due to acquisition of oil and gas properties 2,323 — 
+Liabilities settled ( 4,228 ) ( 2,008 ) 
+Dispositions ( 25,551 ) ( 4,760 ) 
+Revisions to estimates 8,256 5,830 
+Asset retirement obligations, end of period 47,079 60,435 
+Less: Current asset retirement obligations ( 4,426 ) ( 6,543 ) 
+Non-current asset retirement obligations $ 42,653 $ 53,892 
+Certain of the Company’s operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded on the consolidated balance sheets at December 31, 2023 and 2022 as long-term restricted investments were $ 3.5 million , and are presented in “Other assets, net.” These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties. 
+Note 16 – Accounts Receivable, Net 
+As of December 31, 
+2023 2022 
+(In thousands) 
+Oil and natural gas receivables $ 132,332 $ 174,107 
+Joint interest receivables 34,555 16,778 
+Other receivables 41,072 48,277 
+Total 207,959 239,162 
+Allowance for credit losses ( 1,168 ) ( 2,034 ) 
+Total accounts receivable, net $ 206,791 $ 237,128 
+Note 17 – Accounts Payable and Accrued Liabilities 
+As of December 31, 
+2023 2022 
+(In thousands) 
+Accounts payable $ 204,339 $ 191,133 
+Revenues and royalties payable 226,804 244,408 
+Accrued capital expenditures 59,599 58,395 
+Accrued interest 35,704 42,297 
+Total accounts payable and accrued liabilities $ 526,446 $ 536,233 
+98 
+Note 18 – Commitments and Contingencies 
+The Company is involved in various claims and lawsuits incidental to its business. In the opinion of management, the ultimate liability hereunder, if any, will not have a material adverse effect on the financial position or results of operations of the Company. 
+The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment are not expected to have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies hereunder, and claims for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities. 
+The table below presents total minimum commitments associated with long-term, non-cancelable leases, drilling rig contracts, frac service contracts, gathering, processing and transportation service agreements which require minimum volumes of oil, natural gas, or produced water to be delivered and other purchase obligations, as of December 31, 2023. 
+2024 2025 2026 2027 2028 2029 and 
+Thereafter Total 
+(In thousands) 
+Office space $ 5,203 $ 6,280 $ 9,409 $ 9,526 $ 9,645 $ 41,883 $ 81,946 
+Drilling rig and frac service commitments (1) 
+41,875 — — — — — 41,875 
+Pipeline transportation commitments (2) 
+34,155 35,196 35,196 25,553 23,202 85,143 238,445 
+Produced water disposal commitments (3) 
+8,532 4,509 569 113 — — 13,723 
+Purchase obligations (4) 
+9,004 8,980 8,980 8,980 9,004 4,030 48,978 
+Other operating leases 3,098 1,786 30 — — 646 5,560 
+Total $ 101,867 $ 56,751 $ 54,184 $ 44,172 $ 41,851 $ 131,702 $ 430,527 
+(1) Drilling rig and frac service commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will generally be billed for their working interest share of such costs. 
+(2) Pipeline transportation commitments represent contractual obligations the Company has entered into for certain gathering, processing and transportation service agreements which require minimum volumes of oil or natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any oil or natural gas. 
+(3) Produced water disposal commitments represent contractual obligations the Company has entered into for certain service agreements which require minimum volumes of produced water to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water. 
+(4) Purchase obligations represent multi-year energy purchase agreements the Company has entered into to lock in rates for electricity utilized in its operations. Under these contracts, the Company is obligated to purchase a minimum supply of electricity at a fixed price. If the Company does not utilize the minimum amounts of electricity on a monthly basis, the supplier would sell the underutilized quantity at the then market price. The amounts in the table above reflect the aggregate undiscounted financial commitments pursuant to these purchase agreements. 
+Other Commitments 
+The following table includes the Company’s current oil sales contracts and firm transportation agreements as of December 31, 2023: 
+Type of Commitment (1) 
+Start Date End Date Committed 
+Volumes (Bbls/d) 
+Oil sales contract 
+January 2024 
+March 2024 
+10,000 
+Oil sales contract 
+January 2024 
+December 2024 15,000 
+Oil sales contract 
+February 2022 
+January 2027 
+5,000 
+Oil sales contract January 2020 December 2024 10,000 
+Firm transportation agreement (2)(3) 
+August 2020 July 2030 11,140 
+Firm transportation agreement (2) 
+April 2020 March 2027 15,000 
+Firm transportation agreement (2) 
+April 2020 March 2027 10,000 
+(1) For each of the commitments shown in the table above, the committed barrels may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. We expect to fulfill these delivery commitments with our existing production or through the purchases of third-party commodities. 
+(2) Each of the firm transportation agreements shown in the table above grant us access to delivery points in several locations along the Gulf Coast. The costs associated with these agreements are recorded to “Gathering, transportation and processing” in the Company’s consolidated statements of operations. 
+99 
+(3) The committed volumes shown in the table above for this particular firm transportation agreement are average volumes. For the terms of August 2023-July 2027 and August 2027-July 2030, the committed volumes are 10,000 Bbls/d and 12,500 Bbls/d, respectively. 
+The following table includes the Company’s current natural gas firm transportation agreements as of December 31, 2023: 
+Type of Commitment (1)(2) 
+Start Date End Date Committed 
+Volumes (MMBtu/d) 
+Firm transportation agreement October 2023 September 2033 50,000 
+Firm transportation agreement October 2023 September 2033 15,000 
+Firm transportation agreement July 2024 June 2034 10,000 
+(1) For each of the commitments shown in the table above, the committed MMBtus may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. We expect to fulfill these delivery commitments with our existing production or through the purchases of third-party commodities. 
+(2) Each of the firm transportation agreements shown in the table above grant us access to delivery points in several locations along the Gulf Coast. The costs associated with these agreements are recorded to “Gathering, transportation and processing” in the Company’s consolidated statements of operations. 
+Note 19 – Subsequent Events (Unaudited) 
+On January 3, 2024, the Company entered into the Merger Agreement with APA and Merger Sub. See “Note 1 - Description of Business” for further discussion. 
+Note 20 – Supplemental Information on Oil and Natural Gas Operations (Unaudited) 
+Estimated Reserves 
+For each year in the table below, the estimated proved reserves were prepared by DeGolyer and MacNaughton (“D&M”), Callon’s independent third-party reserve engineers. The reserves were prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions. 
+There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only and should not be deemed exact. In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company’s oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves. 
+Extrapolation of performance history and material balance estimates were utilized by D&M to project future recoverable reserves for the producing properties where sufficient history existed to suggest performance trends and where these methods were applicable to the subject reservoirs. The projections for the remaining producing properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to non-producing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production and, to a small extent, horizontal PDP and PUD categories. 
+100 
+The following tables disclose changes in the estimated quantities of proved reserves, all of which are located onshore within the continental United States: 
+Years Ended December 31, 
+Proved reserves 2023 2022 2021 
+Oil (MBbls) 
+Beginning of period 275,609 290,296 289,487 
+Extensions and discoveries 40,684 41,064 22,520 
+Revisions to previous estimates ( 28,278 ) ( 31,163 ) ( 10,514 ) 
+Purchase of reserves in place 38,731 — 35,045 
+Sales of reserves in place ( 47,336 ) ( 949 ) ( 24,019 ) 
+Removed for five-year rule ( 18,259 ) — — 
+Production ( 21,891 ) ( 23,639 ) ( 22,223 ) 
+End of period 239,260 275,609 290,296 
+Natural Gas (MMcf) 
+Beginning of period 592,843 577,327 541,598 
+Extensions and discoveries 75,616 75,801 37,896 
+Revisions to previous estimates 24,206 ( 11,155 ) ( 3,389 ) 
+Purchase of reserves in place 42,802 — 73,445 
+Sale of reserves in place ( 53,317 ) ( 7,503 ) ( 34,837 ) 
+Removed for five-year rule ( 74,548 ) — — 
+Production ( 46,109 ) ( 41,627 ) ( 37,386 ) 
+End of period 561,493 592,843 577,327 
+NGLs (MBbls) 
+Beginning of period 105,109 98,104 96,126 
+Extensions and discoveries 14,718 14,264 7,345 
+Revisions to previous estimates 317 1,376 ( 3,103 ) 
+Purchase of reserves in place 9,487 — 10,366 
+Sale of reserves in place ( 9,537 ) ( 1,159 ) ( 6,191 ) 
+Removed for five-year rule ( 11,415 ) — — 
+Production ( 8,011 ) ( 7,476 ) ( 6,439 ) 
+End of period 100,668 105,109 98,104 
+Total (MBoe) 
+Beginning of period 479,525 484,621 475,879 
+Extensions and discoveries 68,005 67,961 36,180 
+Revisions to previous estimates ( 23,927 ) ( 31,645 ) ( 14,181 ) 
+Purchase of reserves in place 55,352 — 57,652 
+Sale of reserves in place ( 65,759 ) ( 3,359 ) ( 36,015 ) 
+Removed for five-year rule ( 42,099 ) — — 
+Production ( 37,587 ) ( 38,053 ) ( 34,894 ) 
+End of period 433,510 479,525 484,621 
+101 
+Years Ended December 31, 
+Proved developed reserves 2023 2022 2021 
+Oil (MBbls) 
+Beginning of period 170,866 162,886 128,923 
+End of period 149,898 170,866 162,886 
+Natural gas (MMcf) 
+Beginning of period 351,278 332,266 238,119 
+End of period 376,070 351,278 332,266 
+NGLs (MBbls) 
+Beginning of period 63,788 55,720 43,315 
+End of period 65,891 63,788 55,720 
+Total proved developed reserves (MBoe) 
+Beginning of period 293,200 273,983 211,925 
+End of period 278,467 293,200 273,983 
+Proved undeveloped reserves 
+Oil (MBbls) 
+Beginning of period 104,743 127,410 160,564 
+End of period 89,362 104,743 127,410 
+Natural gas (MMcf) 
+Beginning of period 241,565 245,061 303,479 
+End of period 185,423 241,565 245,061 
+NGLs (MBbls) 
+Beginning of period 41,321 42,384 52,811 
+End of period 34,777 41,321 42,384 
+Total proved undeveloped reserves (MBoe) 
+Beginning of period 186,325 210,638 263,954 
+End of period 155,043 186,325 210,638 
+Total proved reserves 
+Oil (MBbls) 
+Beginning of period 275,609 290,296 289,487 
+End of period 239,260 275,609 290,296 
+Natural gas (MMcf) 
+Beginning of period 592,843 577,327 541,598 
+End of period 561,493 592,843 577,327 
+NGLs (MBbls) 
+Beginning of period 105,109 98,104 96,126 
+End of period 100,668 105,109 98,104 
+Total proved reserves (MBoe) 
+Beginning of period 479,525 484,621 475,879 
+End of period 433,510 479,525 484,621 
+Total Proved Reserves 
+For the year ended December 31, 2023, the Company’s net decrease in proved reserves of 46.0 MMBoe was primarily due to the following: 
+• Increase of 68.0 MMBoe through extensions and discoveries through the Company’s development efforts in its operating areas, of which 2.5 MMBoe were proved developed reserves; 
+• Decrease of 23.9 MMBoe for revisions of previous estimates that were primarily comprised of: 
+◦ 10.8 MMBoe reduction from the removal of PUD locations due to revised development spacing and changes in lateral lengths, primarily in the Company’s Delaware West operating area, as it focuses on the ongoing optimization of the value of the reservoir system through co-development of multiple target zones within the system utilizing larger scale projects and extended lateral lengths; 
+◦ 10.7 MMBoe reduction primarily due to the change in 12-Month Average Realized Price of crude oil which decreased by approximately 18 % as compared to December 31, 2022; and 
+102 
+◦ 2.4 MMBoe reduction primarily due to higher operating costs as well as lower than expected recoveries from wells turned to production primarily in the western portion of our Permian acreage during 2023. 
+• Increase of 55.4 MMBoe for purchase of reserves in place associated with the Percussion Acquisition; 
+• Decrease of 65.8 MMBoe for sales of reserves in place primarily associated with the Eagle Ford Divestiture; 
+• Decrease of 42.1 MMBoe reduction due to PUD locations that were reclassified to unproved reserve categories as the Company adjusted its future Permian Basin development and capital allocation plans following the Eagle Ford Divestiture and the concurrent Percussion Acquisition, resulting in previously scheduled PUDs, primarily in the Delaware West operating area that is more weighted to natural gas volumes, now forecast to be developed outside of the five-year period from initial booking; and 
+• Decrease of 37.6 MMBoe for production. 
+For the year ended December 31, 2022, the Company’s net decrease in proved reserves of 5.1 MMBoe was primarily due to the following: 
+• Increase of 68.0 MMBoe through extensions and discoveries through the Company’s development efforts in its operating areas, of which 8.7 MMBoe were proved developed reserves; 
+• Decrease of 31.6 MMBoe for revisions of previous estimates that were primarily comprised of: 
+◦ 44.4 MMBoe reduction due to PUD locations that were reclassified to unproved reserve categories, all of which were in the Permian. Certain PUDs were moved outside of their five-year development window as we continue to refine our future development plans for the Permian, including increased application of our “Life of Field” co-development model. This development model focuses on optimization of the value of a reservoir system through concurrent, co-development of multiple target zones within the system utilizing larger scale projects. As a result, we believe the model contributes to more consistent capital efficiency of our well inventory over time and our broader Permian development program is now being targeted for larger project sizes, accompanied by longer associated cycle times, based on our testing and delineation efforts during 2022; 
+◦ 13.1 MMBoe reduction primarily due to higher operating costs; offset by 
+◦ 13.7 MMBoe increase primarily due to the change in 12-Month Average Realized Price of crude oil which increased by approximately 45 % as compared to December 31, 2021; 
+◦ 12.2 MMBoe increase primarily due to better results than previously forecasted on certain wells turned to production during 2022 in both the Permian and Eagle Ford. 
+• Decrease of 3.4 MMBoe for sales of reserves in place primarily associated with the divestitures of non-core assets primarily in the Western Delaware Basin; and 
+• Decrease of 38.1 MMBoe for production. 
+For the year ended December 31, 2021, the Company’s net increase in proved reserves of 8.7 MMBoe was primarily due to the following: 
+• Increase of 36.2 MMBoe through extensions and discoveries through the Company’s development efforts in its operating areas, of which 10.1 MMBoe were proved developed reserves; 
+• Decrease of 14.2 MMBoe for revisions of previous estimates that were primarily comprised of: 
+◦ 27.9 MMBoe increase primarily due to the change in 12-Month Average Realized Price of crude oil which increased by approximately 75 % as compared to December 31, 2020; offset by 
+◦ 29.0 MMBoe reduction due to PUDs that were removed primarily as a result of changes in anticipated well densities as the Company develops its properties in an effort to increase capital efficiency and cash flow generation as well as changes in its development plans, primarily due to the Primexx Acquisition, which resulted in PUDs being moved outside of the five-year development window; 
+◦ 13.1 MMBoe reduction due to reductions in anticipated hydrocarbon recoveries resulting from observed well performance over longer production timeframes during the testing of various full field development plan concepts. 
+• Increase of 57.7 MMBoe for purchase of reserves in place associated with the Primexx Acquisition; 
+• Decrease of 36.0 MMBoe for sales of reserves in place associated with the Western Delaware Basin, Eagle Ford, and Midland non-core asset sales; and 
+103 
+• Decrease of 34.9 MMBoe for production. 
+Capitalized Costs 
+Capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows: 
+As of December 31, 
+2023 2022 
+Oil and natural gas properties: (In thousands) 
+Proved properties $ 9,657,105 $ 9,268,135 
+Unproved properties 1,063,033 1,225,768 
+Total oil and natural gas properties 10,720,138 10,493,903 
+Accumulated depreciation, depletion, amortization and impairment ( 4,570,132 ) ( 4,416,606 ) 
+Total oil and natural gas properties capitalized $ 6,150,006 $ 6,077,297 
+Costs Incurred 
+Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows: 
+Years Ended December 31, 
+2023 2022 2021 
+Acquisition costs: (In thousands) 
+Proved properties $ 503,433 $ — $ 677,250 
+Unproved properties 78,144 32,548 301,404 
+Development costs 872,808 742,991 396,181 
+Exploration costs 113,782 133,080 137,989 
+Total costs incurred $ 1,568,167 $ 908,619 $ 1,512,824 
+Standardized Measure 
+The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2023. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Proved reserve estimates and future cash flows are based on the average realized prices for sales of oil, natural gas, and NGLs on the first calendar day of each month during the year. The following average realized prices were used in the calculation of proved reserves and the standardized measure of discounted future net cash flows. 
+Years Ended December 31, 
+2023 2022 2021 
+Oil ($/Bbl) $ 78.17 $ 95.02 $ 65.44 
+Natural gas ($/Mcf) $ 1.53 $ 5.75 $ 3.31 
+NGLs ($/Bbl) $ 22.27 $ 36.40 $ 29.19 
+104 
+Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10 % annual discount rate. 
+Standardized Measure 
+For the Year Ended December 31, 
+2023 2022 2021 
+(In thousands) 
+Future cash inflows $ 21,804,152 $ 33,424,190 $ 23,775,358 
+Future costs 
+Production ( 8,850,777 ) ( 10,702,897 ) ( 8,038,362 ) 
+Development and net abandonment ( 1,943,594 ) ( 2,326,789 ) ( 1,927,789 ) 
+Future net inflows before income taxes 11,009,781 20,394,504 13,809,207 
+Future income taxes ( 936,057 ) ( 3,000,300 ) ( 1,481,005 ) 
+Future net cash flows 10,073,724 17,394,204 12,328,202 
+10% discount factor ( 4,639,540 ) ( 8,390,068 ) ( 6,077,447 ) 
+Standardized measure of discounted future net cash flows $ 5,434,184 $ 9,004,136 $ 6,250,755 
+Changes in Standardized Measure 
+For the Year Ended December 31, 
+2023 2022 2021 
+(In thousands) 
+Standardized measure at the beginning of the period $ 9,004,136 $ 6,250,755 $ 2,310,390 
+Sales and transfers, net of production costs ( 1,428,805 ) ( 2,208,492 ) ( 1,466,413 ) 
+Net change in sales and transfer prices, net of production costs ( 3,387,434 ) 4,168,425 4,336,078 
+Net change due to purchases of in place reserves 868,016 — 797,327 
+Net change due to sales of in place reserves ( 1,724,612 ) ( 36,389 ) ( 105,376 ) 
+Extensions, discoveries, and improved recovery, net of future production and development costs incurred 702,960 1,338,286 583,976 
+Changes in future development cost 21,705 ( 257,344 ) ( 81,480 ) 
+Previously estimated development costs incurred 570,765 289,207 209,078 
+Revisions of quantity estimates ( 1,217,925 ) ( 215,828 ) ( 104,572 ) 
+Accretion of discount 1,053,483 705,127 234,495 
+Net change in income taxes 1,075,309 ( 730,185 ) ( 765,956 ) 
+Changes in production rates, timing and other ( 103,414 ) ( 299,426 ) 303,208 
+Aggregate change ( 3,569,952 ) 2,753,381 3,940,365 
+Standardized measure at the end of period $ 5,434,184 $ 9,004,136 $ 6,250,755 
+ITEM 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure 
+None. 
+ITEM 9A. Controls and Procedures 
+Disclosure Controls and Procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) performed an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2023. 
+Changes in Internal Control Over Financial Reporting . There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting. 
+Management’s Report on Internal Control Over Financial Reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. GAAP. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an 
+105 
+evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2023 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission (2013 framework) (the COSO criteria). Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2023. 
+Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+The Company’s independent registered public accounting firm, Grant Thornton, LLP, has issued an attestation report regarding its assessment of the Company’s internal control over financial reporting as of December 31, 2023, presented preceding the Company’s financial statements included in Part II, Item 8 of this 2023 Annual Report on Form 10-K. 
+ITEM 9B. Other Information 
+None . 
+ITEM 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections 
+Not applicable. 
+PART III. 
+ITEM 10. Directors, Executive Officers and Corporate Governance 
+The information required by this item is incorporated herein by reference to the definitive proxy statement (the “2024 Proxy Statement”) for our 2024 annual meeting of shareholders. In the event the 2024 Proxy Statement is not filed with the SEC in the 120-day period after December 31, 2023, the information required by this item will be included in an amendment to this 2023 Annual Report on Form 10-K that will be filed by the Company not later than the end of such 120-day period. 
+The Company has adopted a code of ethics that applies to the Company’s officers, directors, employees, agents and representatives and includes a code of ethics for senior financial officers that applies to the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer. The full text of such code of ethics has been posted on the Company’s website at www.callon.com. 
+ITEM 11. Executive Compensation 
+The information required by this item is incorporated herein by reference to the 2024 Proxy Statement. In the event the 2024 Proxy Statement is not filed with the SEC in the 120-day period after December 31, 2023, the information required by this item will be included in an amendment to this 2023 Annual Report on Form 10-K that will be filed by the Company not later than the end of such 120-day period. 
+ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+The information required by this item is incorporated herein by reference to the 2024 Proxy Statement. In the event the 2024 Proxy Statement is not filed with the SEC in the 120-day period after December 31, 2023, the information required by this item will be included in an amendment to this 2023 Annual Report on Form 10-K that will be filed by the Company not later than the end of such 120-day period. 
+ITEM 13. Certain Relationships and Related Transactions and Director Independence 
+The information required by this item is incorporated herein by reference to the 2024 Proxy Statement. In the event the 2024 Proxy Statement is not filed with the SEC in the 120-day period after December 31, 2023, the information required by this item will be included in an amendment to this 2023 Annual Report on Form 10-K that will be filed by the Company not later than the end of such 120-day period. 
+ITEM 14. Principal Accountant Fees and Services 
+The information required by this item is incorporated herein by reference to the 2024 Proxy Statement. In the event the 2024 Proxy Statement is not filed with the SEC in the 120-day period after December 31, 2023, the information required by this item will be included in an amendment to this 2023 Annual Report on Form 10-K that will be filed by the Company not later than the end of such 120-day period. 
+106 
+PART IV. 
+ITEM 15. Exhibits and Financial Statement Schedules 
+(a) Documents filed as part of this 2023 Annual Report on Form 10-K: 
+(1) Financial Statements 
+See index to Financial Statements and Supplementary Data on page 61 . 
+(2) Financial Statement Schedules 
+All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto. 
+(3) Exhibits 
+Incorporated by reference (File No. 001-14039, unless otherwise indicated) 
+Exhibit Number Description Form Exhibit Filing 
+Date 
+2.1 (d) 
+Agreement and Plan of Merger, dated as of July 14, 2019, by and between Callon Petroleum Company and Carrizo Oil & Gas, Inc. 
+8-K 2.1 07/15/2019 
+2.2 
+Amendment No. 1 to Agreement and Plan of Merger, dated August 19, 2019, by and between Callon Petroleum Company and Carrizo Oil & Gas, Inc. 
+10-Q 2.2 11/05/2019 
+2.3 
+Amendment No. 2 to Agreement and Plan of Merger, dated November 13, 2019, by and between Callon Petroleum Company and Carrizo Oil & Gas, Inc. 
+8-K 2.1 11/14/2019 
+2.4 
+(d) 
+Membership Interest Purchase Agreement by and among Percussion Petroleum Management II, LLC, Percussion Petroleum Operating II, LLC, Callon Petroleum Operating Company and Callon Petroleum Company dated May 3, 2023 
+8-K 
+10.1 
+05/08/2023 
+2.5 
+(d) 
+Membership Interest Purchase Agreement by and among Callon Petroleum Operating Company, Callon (Eagle Ford) LLC and Ridgemar Energy Operating, LLC dated May 3, 2023 
+8-K 
+10.2 
+05/08/2023 
+2.6 
+(d) 
+Agreement and Plan of Merger, dated as of January 3, 2024, by and among APA Corporation, Astro Comet Merger Sub Corp., and Callon Petroleum Company 
+8-K 
+2.1 
+01/04/2024 
+3.1 
+Certificate of Incorporation of the Company, as amended through May 12, 2016 
+10-Q 3.1 11/03/2016 
+3.2 
+Certificate of Amendment to the Certificate of Incorporation of Callon, effective December 20, 2019 
+8-K 3.1 12/20/2019 
+3.3 
+Certificate of Amendment to the Certificate of Incorporation of Callon, effective August 7, 2020 
+8-K 3.1 08/07/2020 
+3.4 
+Certificate of Amendment to the Certificate of Incorporation of Callon, effective May 14, 2021 
+8-K 3.1 05/14/2021 
+3.5 
+Certificate of Amendment to the Certificate of Incorporation of Callon, effective May 25, 2022 
+8-K 3.1 05/25/2022 
+3.6 
+Amended and Restated Bylaws of the Company 
+10-K 3.2 02/27/2019 
+4.1 
+Specimen Common Stock Certificate 
+10-K 4.1 02/28/2018 
+4.2 (a) 
+Description of Common Stock 
+4.3 
+Indenture of 6.375% Senior Notes Due 2026, dated as of June 7, 2018, among Callon Petroleum Company, the Guarantors party thereto and U.S. Bank National Association, as Trustee 
+8-K 4.1 06/07/2018 
+4.4 
+First Supplemental Indenture, dated December 20, 2019, among Callon, the Guarantors named therein and U.S. Bank National Association, as trustee 
+8-K 4.4 12/20/2019 
+4.5 
+Registration Rights Agreement of 6.375% Senior Notes Due 2026, dated June 7, 2018, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P. Morgan Securities LLC, as representative of the Initial Purchasers named on Annex E thereto 
+8-K 4.2 06/07/2018 
+4.6 
+Warrant Agreement, dated as of December 20, 2019, between Callon and American Stock Transfer And Trust Company, LLC, as warrant agent 
+8-K 4.5 12/20/2019 
+4.7 
+Indenture, dated as of July 6, 2021, by and among the Company, Callon Petroleum Operating Company, Callon (Eagle Ford) LLC, Callon (Niobrara) LLC, Callon (Permian) LLC, Callon (Permian) Minerals LLC, Callon (Utica) LLC, Callon Marcellus Holding, Inc. and U.S. Bank National Association, as trustee 
+8-K 4.1 07/07/2021 
+4.8 
+Registration Rights Agreement among Callon Petroleum Company, Callon Petroleum Operating Company and Primexx Resource Development, LLC, dated October 1, 2021 
+10-K 4.17 02/24/2022 
+4.9 
+Registration Rights Agreement among Callon Petroleum Company, Callon Petroleum Operating Company and BPP Acquisition, LLC, dated October 1, 2021 
+10-K 4.18 02/24/2022 
+4.10 
+Registration Rights Agreement, by and between the Company and Chambers Investment, LLC, dated November 5, 2021 
+8-K 4.1 11/08/2021 
+4.11 
+Indenture, dated as of June 24, 2022, by and among Callon Petroleum Company, Callon Petroleum Operating Company, Callon (Permian) LLC, Callon (Eagle Ford) LLC, Callon (Permian) Minerals LLC, Callon (Niobrara) LLC, Callon (Utica) LLC and Callon Marcellus Holding, Inc. and U.S. Bank Trust Company, National Association, as trustee 
+8-K 4.1 06/24/2022 
+107 
+4.12 
+Registration Rights Agreement by and between Callon Petroleum Company and Percussion Petroleum Management II, LLC, dated July 3, 2023 
+8-K 
+4.1 
+07/07/2023 
+4.13 
+Second Supplemental Indenture of 6.375% Senior Notes Due 2026, dated July 3, 2023, among Callon Petroleum Company, Callon Permian II, LLC and U.S. Bank Trust Company, National Association, as Trustee 
+10-Q 
+4.2 
+08/02/2023 
+4.14 
+First Supplemental Indenture of 8.00% Senior Notes Due 2028, dated July 3, 2023, among Callon Petroleum Company, Callon Permian II, LLC and U.S. Bank Trust Company, National Association, as Trustee 
+10-Q 
+4.3 
+08/02/2023 
+4.15 
+First Supplemental Indenture of 7.500% Senior Notes Due 2030, dated July 3, 2023, among Callon Petroleum Company, Callon Permian II, LLC and U.S. Bank Trust Company, National Association, as Trustee 
+10-Q 
+4.4 
+08/02/2023 
+10.1 (d) 
+Amended & Restated Credit Agreement, dated as of October 19, 2022, by and among the Company, JPMorgan Chase Bank, N.A., as administrative agent for the lenders party thereto, and the other lenders party thereto 
+8-K 10.1 10/24/2022 
+10.2 (b) 
+Amended and Restated Deferred Compensation Plan for Outside Directors - Callon Petroleum Company, dated as of May 10, 2017 and effective as of May 1, 2017 
+10-K 10.11 02/28/2018 
+10.3 (b) 
+Amended and Restated 2018 Omnibus Incentive Plan 
+10-K 10.7 02/27/2020 
+10.4 (b) 
+Form of Callon Petroleum Company Officer Restricted Stock Unit Award Agreement, adopted on January 31, 2019 under the 2018 Omnibus Incentive Plan 
+10-K 10.23 02/27/2019 
+10.5 (b) 
+Form of Callon Petroleum Company Officer Cash-Settleable Performance Share Award Agreement, adopted on January 31, 2020 under the Amended & Restated 2018 Omnibus Incentive Plan 
+10-K 10.23 02/27/2020 
+10.6 (b) 
+Form of Callon Petroleum Company Officer Stock-Settleable Performance Share Award Agreement, adopted on January 31, 2020 under the Amended & Restated 2018 Omnibus Incentive Plan 
+10-K 10.24 02/27/2020 
+10.7 (b) 
+Form of Callon Petroleum Company Officer Restricted Stock Unit Award Agreement, adopted on January 31, 2020 under the Amended & Restated 2018 Omnibus Incentive Plan 
+10-K 10.25 02/27/2020 
+10.8 (b) 
+Callon Petroleum Company 2020 Omnibus Incentive Plan 
+DEF 14A B 04/28/2020 
+10.9 (b) 
+First Amendment to Callon Petroleum Company 2020 Omnibus Incentive Plan 
+8-K 10.5 04/16/2021 
+10.10 (b) 
+Form of Callon Petroleum Company Employee Restricted Stock Unit Award Agreement, adopted on June 8, 2020, under the 2020 Omnibus Incentive Plan 
+10-Q 10.3 08/05/2020 
+10.11 (b) 
+Form of Callon Petroleum Company Director Restricted Stock Unit Award Agreement, adopted on June 8, 2020, under the 2020 Omnibus Incentive Plan 
+10-Q 10.4 08/05/2020 
+10.12 (b) 
+Form of Callon Petroleum Company Officer Cash Retention Award Agreement, adopted on September 30, 2020, under the 2020 Omnibus Incentive Plan 
+10-Q 10.4 11/03/2020 
+10.13 (b) 
+Form of Callon Petroleum Company Officer Cash Incentive Award Agreement, adopted on September 30, 2020, under the 2020 Omnibus Incentive Plan 
+10-Q 10.5 11/03/2020 
+10.14 (b) 
+Deferred Compensation Plan for Outside Directors, as Amended and Restated as of January 1, 2021 
+10-K 10.29 02/25/2021 
+10.15 (b) 
+Form of Callon Petroleum Company Restricted Stock Unit Award Agreement, adopted on March 12, 2021 under the 2020 Omnibus Incentive Plan 
+8-K 10.1 04/16/2021 
+10.16 (b) 
+Form of Callon Petroleum Company Cash Performance Unit Award Agreement, adopted on March 12, 2021 under the 2020 Omnibus Incentive Plan 
+8-K 10.2 04/16/2021 
+10.17 (b) 
+Form of Amendment, adopted on September 21, 2022, to Callon Petroleum Company Cash Performance Unit Award Agreement, originally adopted on March 12, 2021 under the 2020 Omnibus Incentive Plan 
+10-Q 10.3 11/03/2022 
+10.18 (b) 
+Form of Callon Petroleum Company Returns Program Cash Incentive Award Agreement, adopted on March 9, 2022 under the 2020 Omnibus Incentive Plan 
+10-Q 10.1 05/05/2022 
+10.19 (b) 
+Form of Amendment, adopted on September 21, 2022, to Callon Petroleum Company Returns Program Cash Incentive Award Agreement, originally adopted on March 9, 2022 under the 2020 Omnibus Incentive Plan 
+10-Q 10.4 11/03/2022 
+10.20 (b) 
+Form of Callon Petroleum Company Business Sustainability Cash Incentive Award Agreement, adopted on March 9, 2022 under the 2020 Omnibus Incentive Plan 
+10-Q 10.2 05/05/2022 
+10.21 (b) 
+Form of Amendment, adopted on September 21, 2022, to Callon Petroleum Company Business Sustainability Cash Incentive Award Agreement, originally adopted on March 9, 2022 under the 2020 Omnibus Incentive Plan 
+10-Q 10.5 11/03/2022 
+10.22 
+(b) 
+Form of Callon Petroleum Company Market Stock Unit Award Agreement, adopted on April 26, 2023, under the 2020 Omnibus Incentive Plan 
+10-Q 10.1 08/02/2023 
+10.23 
+(b) 
+Callon Petroleum Company Executive Severance Pay Plan 
+10-Q 10.1 11/03/2022 
+10.24 
+(b) 
+Callon Executive Change in Control Severance Compensation Plan 
+10-Q 10.2 11/03/2022 
+10.25 
+(b) 
+Separation Agreement, dated July 5, 2023, by and between Jeffrey S. Balmer and Callon Petroleum Company 
+10-Q 10.1 11/01/2023 
+10.26 
+(b) 
+Consulting Agreement, dated July 5, 2023, by and between Jeffrey S. Balmer and Callon Petroleum Company 
+10-Q 10.2 11/01/2023 
+21.1 (a) 
+Subsidiaries of the Company 
+22.1 (a) 
+Subsidiary Guarantors 
+108 
+23.1 (a) 
+Consent of Grant Thornton LLP 
+23.2 (a) 
+Consent of DeGolyer and MacNaughton, Inc. 
+31.1 (a) 
+Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a) 
+31.2 (a) 
+Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a) 
+32.1 (c) 
+Section 1350 Certifications of Chief Executive and Financial Officers pursuant to Rule 13(a)-14(b) 
+97.1 
+(a) 
+C allon Petroleum Company Clawback Policy 
+99.1 (a) 
+Reserve Report Summary prepared by DeGolyer and MacNaughton, Inc. as of December 31, 202 3 
+101.INS (a) XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. 
+101.SCH (a) Inline XBRL Taxonomy Extension Schema Document 
+101.CAL (a) Inline XBRL Taxonomy Extension Calculation Linkbase Document. 
+101.DEF (a) Inline XBRL Taxonomy Extension Definition Linkbase Document. 
+101.LAB (a) Inline XBRL Taxonomy Extension Label Linkbase Document. 
+101.PRE (a) Inline XBRL Taxonomy Extension Presentation Linkbase Document. 
+104 (a) Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. 
+(a) Filed herewith. 
+(b) Indicates management compensatory plan, contract, or arrangement. 
+(c) Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, except to the extent that the registrant specifically incorporates it by reference. 
+(d) Certain schedules and similar attachments have been omitted pursuant to Item 601(a)(5) of Regulation S-K. Callon agrees to furnish a supplemental copy of any omitted schedule or attachment to the SEC upon request. 
+ITEM 16. Form 10-K Summary 
+None. 
+109 
+SIGNATURES 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+Callon Petroleum Company 
+/s/ Kevin Haggard Date: February 26, 2024 
+By: Kevin Haggard 
+Chief Financial Officer (principal financial officer) 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+/s/ Joseph C. Gatto, Jr. Date: February 26, 2024 
+Joseph C. Gatto, Jr. (principal executive officer) 
+/s/ Kevin Haggard Date: February 26, 2024 
+Kevin Haggard (principal financial officer) 
+/s/ Gregory F. Conaway Date: February 26, 2024 
+Gregory F. Conaway (principal accounting officer) 
+/s/ Matthew R. Bob Date: February 26, 2024 
+Matthew R. Bob (chairman of the board of directors) 
+/s/ Frances Aldrich Sevilla-Sacasa Date: February 26, 2024 
+Frances Aldrich Sevilla-Sacasa (director) 
+/s/ James E. Craddock 
+Date: February 26, 2024 
+James E. Craddock (director) 
+/s/ Barbara J. Faulkenberry Date: February 26, 2024 
+Barbara J. Faulkenberry (director) 
+/s/ Anthony J. Nocchiero Date: February 26, 2024 
+Anthony J. Nocchiero (director) 
+/s/ Mary Shafer-Malicki Date: February 26, 2024 
+Mary Shafer-Malicki (director) 
+/s/ Steven A. Webster Date: February 26, 2024 
+Steven A. Webster (director) 
+110
\ No newline at end of file
diff --git a/raw/filings/0000928022/2023/0000928022-24-000031/filing_metadata.csv b/raw/filings/0000928022/2023/0000928022-24-000031/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..dd87bab9f448f8b434c740ffd1af296e3abc4580
--- /dev/null
+++ b/raw/filings/0000928022/2023/0000928022-24-000031/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000928022,CPE,Callon Petroleum Co,10-K,2024-02-26,2023-12-31,2024-02-26T21:23:43.000Z,0000928022-24-000031,cpe-20231231.htm,10-K,16402164,1,1,https://www.sec.gov/Archives/edgar/data/928022/000092802224000031/cpe-20231231.htm,https://www.sec.gov/Archives/edgar/data/928022/000092802224000031/,2023,2023,1
diff --git a/raw/filings/0000928022/2023/0000928022-24-000031/item1.txt b/raw/filings/0000928022/2023/0000928022-24-000031/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..3ecdb09115069c0bb78d876c539d9875ca013574
--- /dev/null
+++ b/raw/filings/0000928022/2023/0000928022-24-000031/item1.txt
@@ -0,0 +1,77 @@
+Item 1 C . 
+C ybersecurity 
+48 
+Item 3. 
+Legal Proceedings 
+49 
+Item 4. 
+Mine Safety Disclosures 
+49 
+Part II 
+Item 5. 
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+50 
+Item 6. 
+Reserved 
+51 
+Item 7. 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+51 
+General 
+51 
+Financial and Operational Highlights 
+51 
+Results of Operations 
+52 
+Liquidity and Capital Resources 
+56 
+Critical Accounting Estimates 
+57 
+Item 7A. 
+Quantitative and Qualitative Disclosures About Market Risk 
+59 
+Item 8. 
+Financial Statements and Supplementary Data 
+61 
+Reports of Independent Registered Public Accounting Firm 
+62 
+Consolidated Balance Sheets 
+66 
+Consolidated Statements of Operations 
+67 
+Consolidated Statements of Stockholders’ Equity 
+68 
+Consolidated Statements of Cash Flows 
+69 
+Notes to Consolidated Financial Statements 
+70 
+Supplemental Information on Oil and Natural Gas Operations (Unaudited) 
+100 
+Item 9. 
+Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+105 
+Item 9A. 
+Controls and Procedures 
+105 
+Item 9B. 
+Other Information 
+106 
+Item 9 C . 
+Disclosure Regarding Foreign Jurisdictions that Prevent Inspections 
+106 
+Part III 
+Item 10. 
+Directors, Executive Officers and Corporate Governance 
+106 
+Item 11. 
+Executive Compensation 
+106 
+Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+106 
+Item 13. 
+Certain Relationships and Related Transactions and Director Independence 
+106 
+Item 14. 
+Principal Accountant Fees and Services 
+106
\ No newline at end of file
diff --git a/raw/filings/0000928022/2023/0000928022-24-000031/item13.txt b/raw/filings/0000928022/2023/0000928022-24-000031/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..fc46c047f41799a64465d793817b4663e20eb32c
--- /dev/null
+++ b/raw/filings/0000928022/2023/0000928022-24-000031/item13.txt
@@ -0,0 +1,2 @@
+ITEM 13. Certain Relationships and Related Transactions and Director Independence 
+The information required by this item is incorporated herein by reference to the 2024 Proxy Statement. In the event the 2024 Proxy Statement is not filed with the SEC in the 120-day period after December 31, 2023, the information required by this item will be included in an amendment to this 2023 Annual Report on Form 10-K that will be filed by the Company not later than the end of such 120-day period.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2023/0000928022-24-000031/item9a.txt b/raw/filings/0000928022/2023/0000928022-24-000031/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..48f15799e9fbeee3b861a8a1769b87ab2b63ed48
--- /dev/null
+++ b/raw/filings/0000928022/2023/0000928022-24-000031/item9a.txt
@@ -0,0 +1,8 @@
+ITEM 9A. Controls and Procedures 
+Disclosure Controls and Procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) performed an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2023. 
+Changes in Internal Control Over Financial Reporting . There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting. 
+Management’s Report on Internal Control Over Financial Reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. GAAP. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an 
+105 
+evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2023 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission (2013 framework) (the COSO criteria). Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2023. 
+Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+The Company’s independent registered public accounting firm, Grant Thornton, LLP, has issued an attestation report regarding its assessment of the Company’s internal control over financial reporting as of December 31, 2023, presented preceding the Company’s financial statements included in Part II, Item 8 of this 2023 Annual Report on Form 10-K.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2023/0000928022-24-000031/rp_note.txt b/raw/filings/0000928022/2023/0000928022-24-000031/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000928022/2023/0000928022-24-000031/rpt_disclosure.txt b/raw/filings/0000928022/2023/0000928022-24-000031/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0001092662/2014/0001092662-15-000024/filing.txt b/raw/filings/0001092662/2014/0001092662-15-000024/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..252dfdef2676a2be75fa279776658fe973221980
--- /dev/null
+++ b/raw/filings/0001092662/2014/0001092662-15-000024/filing.txt
@@ -0,0 +1,3022 @@
+10-K
+1
+form10_k.htm
+FORM 10-K FOR 2014
+UNITED STATES 
+Securities and Exchange Commission 
+Washington, D.C. 20549 
+FORM 10-K 
+[X] 
+ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the fiscal year ended December 31, 2014 
+or 
+[ ] 
+TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the transition period from _______ to ______ . 
+Commission File No. 0-30379 
+CHEMBIO DIAGNOSTICS, INC. 
+(Exact name of registrant as specified in its charter) 
+Nevada 
+88-0425691 
+(State or other jurisdiction of incorporation or organization) 
+(I.R.S. Employer Identification No.) 
+3661 Horseblock Road, Medford, NY 
+11763 
+(Address of principal executive offices) 
+(Zip Code) 
+Registrant's telephone number, including area code (631) 924-1135 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of each class 
+Name of each exchange on which registered 
+None 
+None 
+Securities registered pursuant to section 12(g) of the Act: 
+Common Stock, $0.01 par value 
+(Title of Class) 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes __ No X 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes __ No X 
+Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No__ 
+Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes X No __ 
+Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. 
+Large accelerated filer [ ] 
+Accelerated filer [ ] 
+Non-accelerated filer [ ] 
+Smaller reporting company [X] 
+(Do not check if a smaller reporting company) 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes __ No _X_ 
+As of the last business day of the Company's most recently completed second fiscal quarter, the aggregate market value of voting and non-voting common equity held by non-affiliates* was $29,000,000. 
+As of March 2, 2015, the registrant had 9,627,248 common shares outstanding. 
+* Without asserting that any of the issuer's directors or executive officers, or the entities that own more than five percent of the outstanding shares of the Registrant's common stock, are affiliates, the shares of which they are beneficial owners have not been included in shares held by non-affiliates solely for this calculation. 
+TABLE OF CONTENTS 
+Page 
+PART I 
+ITEM 1. 
+BUSINESS 
+2 
+ITEM 1A. 
+RISK FACTORS 
+16 
+ITEM 2. 
+PROPERTIES 
+21 
+ITEM 3. 
+LEGAL PROCEEDINGS 
+21 
+ITEM 4 . 
+MINE SAFETY DISCLOSURES 
+21 
+PART II 
+ITEM 5. 
+MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+21 
+ITEM 6. 
+SELECTED FINANCIAL DATA 
+22 
+ITEM 7. 
+MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+23 
+ITEM 8. 
+FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+31 
+ITEM 9. 
+CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. 
+31 
+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+31 
+ITEM 9B. 
+OTHER INFORMATION 
+31 
+PART III 
+ITEM 10. 
+DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
+32 
+ITEM 11. 
+EXECUTIVE COMPENSATION 
+34 
+ITEM 12. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+37 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+40 
+ITEM 14. 
+PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+41 
+PART IV 
+ITEM 15. 
+EXHIBITS, FINANCIAL STATEMENT SCHEDULES 
+42 
+SIGNATURES 
+43 
+PART I 
+ITEM 1. 
+BUSINESS 
+FORWARD-LOOKING STATEMENTS 
+This report contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, and Section 27A of the Securities Act of 1933. Any statements contained in this report that are not statements of historical fact may be forward-looking statements. When we use the words "intends," "estimates," "predicts," "potential," "continues," "anticipates," "plans," "expects," "believes," "should," "could," "may," "will" or the negative of these terms or other comparable terminology, we are identifying forward-looking statements. Forward-looking statements involve risks and uncertainties, which may cause our actual results, performance or achievements to be materially different from those expressed or implied by forward-looking statements. These factors include our research and development activities, distributor channels, market demand for our products, compliance with regulatory impositions; and our capital needs. Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance or achievements. 
+Except as may be required by applicable law, we do not undertake or intend to update or revise our forward-looking statements, and we assume no obligation to update any forward-looking statements contained in this report as a result of new information or future events or developments. Thus, you should not assume that our silence over time means that actual events are bearing out as expressed or implied in such forward-looking statements. You should carefully review and consider the various disclosures we make in this report and our other reports filed with the Securities and Exchange Commission that attempt to advise interested parties of the risks, uncertainties and other factors that may affect our business. 
+For further information about these and other risks, uncertainties and factors, please review the disclosure included in this report under "Part I, Item 1A, Risk Factors." 
+Our Business 
+General 
+The Company (Chembio Diagnostics, Inc. and its wholly-owned subsidiary, Chembio Diagnostic Systems, Inc., are collectively referred to herein as the "Company") develops, manufactures, markets and licenses rapid point-of-care diagnostic tests (POCTs) that detect infectious diseases. The Company's main products presently commercially available are rapid tests for the detection of HIV 1/2 antibodies, and a multiplex rapid test for the detection of HIV and Syphilis antibodies. The HIV 1/2 rapid tests employ in-licensed and proprietary lateral flow technologies (see "Our Rapid Test Technologies"), can be used with all blood matrices as samples, and are manufactured in a standard cassette format, a dipstick format, and a proprietary barrel format. The tests employing the cassette and proprietary barrel formats were approved by the FDA in 2006. The barrel format is exclusively distributed by a distributor in the United States and by Chembio and its designated distributors outside the United States. The Cassette format is distributed by Chembio and its designated distributors worldwide. Our latest generation HIV 1/2 rapid antibody detection test incorporates our patented Dual Path Platform® (DPP®) POCT technology, and this POCT platform does not require in-licensing. The DPP® HIV 1/2 Assay detects antibodies to HIV 1 & 2 in oral fluid samples as well as in all blood matrices. We have sold this product in Brazil since 2009 where it was approved by ANVISA, through our agreement with the Oswaldo Cruz Foundation ("FIOCRUZ"), and we received United States FDA regulatory approval for this product in December 2012 and CLIA waiver in October 2014. We launched it in the United States under Chembio's brand in the fourth quarter of 2014. 
+2 
+Our product pipeline, which currently includes a multiplex rapid test for earlier detection of HIV by detecting P-24 antigen as well as antibodies, a test for Hepatitis-C, and a multiplex test that detects HIV and Syphilis specific antibodies (which we are already selling outside the U.S.), is based on this DPP® technology for which we were issued a United States patent in 2007 and for which additional patent protection has issued or is pending in a number of other countries. With the patented DPP® and the lateral flow platform, we participate in the estimated $8 billion point-of-care market segment of the estimated nearly $50 billion global in-vitro diagnostic market that has an overall growth rate exceeding 3% per annum. POCTs, by providing prompt and early diagnosis, can reduce patient stays, lower overall costs, improve therapeutic interventions and improve patient outcomes. POCTs can also prevent needless hospital admissions, simplify testing procedures, avoid delays from central lab batching, and eliminate the need for return visits. 
+In the areas of infectious and sexually transmitted diseases (such as HIV and syphilis), the utility of a rapid point–of-care (POC) test, particularly in identifying patients unaware of their disease status, has been well established. Large and growing markets have been established for these kinds of tests, initially in high prevalence regions where they are indispensable for large scale prevention and treatment programs. More recently introduced in the United States in 2004, rapid HIV tests now also present a significant segment of the U.S. market for HIV clinical testing, which is still dominated by laboratory tests. We have focused our product development activity within areas where the availability of rapid, point-of-care screening, diagnostic, or confirmatory results can improve health outcomes. More generally we believe there is and will continue to be a growing demand for diagnostic products that can provide accurate, actionable diagnostic information in a rapid, cost-effective manner at the point of care. 
+PRODUCTS 
+Lateral Flow Rapid HIV Tests 
+All three of our lateral flow rapid HIV antibody detection tests are qualitative "yes/no" tests for the detection of antibodies to HIV 1 & 2 with visually interpreted results (one line "negative"; one line "positive") available within approximately 15 minutes. The tests are simple to use, have a shelf life of 24 months, and do not require refrigeration. The tests differ principally only in the method of test procedure, convenience and cost. One of our FDA-approved lateral flow HIV tests incorporates a proprietary plastic "barrel" device that houses the lateral flow strip. This barrel format enables collection of samples directly (usually from a finger-stick whole blood sample) into the barrel's capillary tip. A sealed unitized buffer vial, assembled onto the top of the barrel, is removed and seated into a stand; the seal is then pierced by the barrel's capillary tip, thereby initiating the upward flow of the resulting sample-buffer solution through a filter, up into the vertical device's chamber and onto the lateral flow strip. This results in a unique unitized and closed device system that can reduce the chance of exposure to potentially infectious samples. 
+In January 2015, the Company entered into an agreement with StatSure Diagnostic Systems, Inc. (SDS) to acquire SDS' interest in the barrel device format, also known as Chembio's SURE CHECK® HIV 1/2 Assay, effective June 1, 2016. Beginning June 1, 2016, Chembio will own full rights related to the SURE CHECK® HIV 1/2 Assay, including sales, marketing, distribution and trademark rights, subject to the terms of the existing marketing and distribution agreement with Alere, Inc., which grants Alere U.S. marketing and distribution rights through May 31, 2016. Prior to this newly-executed agreement between SDS and Chembio, SDS has owned a 50 percent interest in the rights to the SURE CHECK® HIV 1/2 Assay that would have continued after May 31, 2016, also subject to the existing marketing and distribution agreement with Alere. The new agreement with SDS also resolves all other matters between Chembio and SDS, including their respective sharing ratios, until June 1, 2016, concerning net revenues from sale of the SURE CHECK® product outside the U.S. 
+The Company's SURE CHECK® HIV 1/2 Assay is marketed exclusively in the U.S. as Clearview® Complete. Outside the U.S., Chembio markets the SURE CHECK® HIV 1/2 Assay primarily through distributors. The SURE CHECK® HIV 1/2 Assay is Food & Drug Administration (FDA) approved, CLIA-waived, European CE-marked, and has been pre-qualified by the World Health Organization (WHO). Results are obtained in 15 minutes via a 2.5uL blood sample (i.e., fingerstick, serum, plasma, or venipuncture whole blood). The assay is stable at room temperature and provides 99.7% sensitivity and 99.9% specificity. 
+3 
+Our other FDA-approved lateral flow HIV test uses a more conventional rectangular plastic cassette format that houses the lateral flow strip. In this case, a sample is transferred by use of a separately provided transfer device ("loop") into a sample well or port of the cassette that houses the lateral flow strip, which is positioned horizontally or flat. 
+Our third lateral flow HIV test, the HIV 1/2 STAT PAK® Dipstick, is our most cost competitive and compact format. It does not have any plastic housing so that 30 test strips can be packaged into a small vial that is ideal for transporting into remote settings. The test procedure is similar to the cassette format except that a user-applied adhesive backing is provided as a more cost-effective and compact "surface" on which to run the test. 
+Regulatory Status of the lateral flow HIV tests 
+The FDA approved our Pre-Market Applications (hereinafter "PMA"; see "Governmental Regulations" and Glossary) in April 2006 for our SURE CHECK® HIV 1/2 (and also now Alere Clearview® Complete HIV 1/2) and for our HIV 1/2 STAT-PAK® products. Waivers under the Clinical Laboratory Improvement Act (hereinafter "CLIA"; see Governmental Regulations) were granted by the FDA for these two FDA-approved products in 2006 and 2007, respectively. A CLIA waiver is required in order for health care providers to administer these tests in the settings where they are most suited and needed, such as public health testing clinics, hospital emergency rooms and physicians' offices. The SURE CHECK® and HIV 1/2 STAT-PAK® products received CE Marks in July 2013 and March 2014, respectively, and the CE Marking for the DPP® HIV 1/2 Assay described below is expected in 2015. We have also updated our filing for CE Marking to reflect the new tradename of STAT-VIEW® HIV 1 / 2 Assay for sale in the EU market. Our HIV 1/2 STAT-PAK® Dipstick, although not FDA-approved, qualifies under FDA export regulations [See Government Regulation] to sell to customers outside the United States, subject to any required approval by the importing country. CE Mark has not been pursued for this product. 
+All three of our lateral flow HIV tests have qualified for procurement under the President's Emergency Plan for AIDS Relief ("PEPFAR"). The cassette and dipstick versions of the STAT-PAK® and the SURE CHECK® assays are also pre-qualified by the World Health Organization (WHO) for procurements by the second largest global program, known as the Global Fund, as well as other related programs funded by agencies affiliated with the United Nations, such as UNICEF and UNITAIDS (see Glossary), through qualification with the WHO bulk procurement scheme. 
+DPP® HIV 1/2 Assay 
+As in the case of our lateral flow HIV tests, our DPP® HIV 1/2 Assay is also a qualitative "yes/no" test for the detection of antibodies to HIV 1& 2, delivers visual results within as little as 15 minutes, is simple to use, has a shelf life of 23 months, and does not require refrigeration. This product, which is our first FDA-approved product incorporating our patented DPP® technology, can be used with oral fluid samples, as well as with all blood matrices. This product also incorporates our patent-pending oral fluid collection and storage system that enables samples to be fully extracted in buffer solution before application to the test device, and also enables the extracted sample to be stored and retested or potentially tested for multiple conditions in future product applications. Clinical and laboratory studies demonstrated the ability of the test to accurately detect the presence of antibodies in individuals down to two years of age. Studies have also shown this product to have improved performance compared with all of the current FDA-approved CLIA-waived lateral flow rapid tests, even including our own lateral flow tests. FDA-approved label claims include sensitivity/specificity on oral fluid and finger-stick whole blood of 98.9%/99.9% and 99.9%/100% respectively. Oral fluid sensitivity was 100% among HIV-positive patients not taking anti-retroviral medication. 
+4 
+Regulatory Status of the DPP® HIV 1/2 Assay 
+In December 2012, we received FDA approval of our Pre-Marketing Approval. In October of 2014 the FDA granted CLIA waiver status. 
+The DPP® HIV 1/2 Assay product is qualified for procurement under the President's Emergency Plan for AIDS Relief ("PEPFAR") for use with all sample matrices, and we are pursuing WHO qualification in order to enable procurement of this product by the Global Fund and United Nations agencies, including programs underwritten by them. In October 2014, we completed a three-day on-site inspection by the WHO as follow-up to pre-qualification activities of our products with no major non-conformances noted during the audit. The WHO laboratory evaluation for the blood matrix is complete, while oral fluid is in progress and expected to be complete in 2015. We are also pursuing CE Marking, anticipated during 2015, as stated above. 
+In June 2010, ANVISA approved the DPP® HIV 1/2 Assay that is being marketed in Brazil through our collaboration with the Oswaldo Cruz Foundation, Brazil's leading public health institute (see Oswaldo Cruz Foundation OEM DPP® Agreements). Since this time, we have sold and marketed millions of DPP HIV tests to Brazil through this partnership. 
+DPP® HIV-Syphilis Multiplex Test 
+This product, launched in 2013, allows for the detection of antibodies to both HIV and Syphilis on a single test device within approximately 15 minutes. In certain global/public health settings (see Target Markets), this product may provide a more convenient and cost effective means of rapid detecting both markers in a single test procedure at the point of care as compared with performing separate rapid tests for each indication. This product takes advantage of the multiplexing feature of DPP® which provides for a more robust reaction between the sample and biomarkers being tested for (HIV and Syphilis antibodies in this case), resulting in a greater ability by the user to visually interpret test results. We launched this product in Mexico in the fourth quarter of 2013 as a unitized product, meaning that each test kit was separately packaged to include each of the other components necessary to run this test, as compared with other configurations where a test kit of 20 or 30 devices is accompanied by one bottle of running buffer. The initial results of this launch have been very positive, and we experienced good results in Mexico during 2014 from the program. Building on this initial success, we continue to pursue commercialization efforts for this product in a number of additional international markets, where there is a great need to detect Mother-to-Child-Transmission of HIV and Syphilis globally. According to the CDC website, "approximately 370,000 babies are born with HIV, mostly in sub-Saharan Africa. Without treatment, more than half of these children will die before the age of 2. Through key interventions, such as routinely testing pregnant women for HIV, providing antiretroviral medications to HIV-infected pregnant women and their exposed infants, and promoting safe infant feeding practices, mother-to-child transmission of HIV can be decreased from about 35% to less than 5%. Another prominent cause of infant mortality is untreated maternal syphilis, which still accounts for more than 500,000 stillbirths and infant deaths annually despite the fact that these deaths could be prevented through routine detection and treatment of syphilis during antenatal care". 
+Regulatory Status of the DPP® HIV-Syphilis Test 
+DPP® HIV-Syphilis – We have developed this product for international and U.S. marketing. For the international market, the product has been registered in Mexico, and successfully launched and sold in this region. 
+In February 2015, this product was granted approval from the Brazilian ANVISA. We have submitted this product both for evaluation by the CDC, acting on behalf of the United States Agency of International Development, and the WHO, which has accepted this product to be evaluated for pre-qualification in its global procurement scheme. In October 2014, WHO conducted a three-day audit of our facilities as follow up to pre-qualification activities for the DPP HIV-Syphilis Assay, including other products submitted for pre-qualification through WHO. No major non-conformances were identified during this audit, and we continue to work with WHO to obtain pre-qualification approval status for this device. 
+5 
+We continue to pursue an FDA submission for this product, and are in the progress of studies to evaluate a version that has been developed for the US market, to meet the performance requirements for a combination test to detect both HIV and Syphilis, including a "reverse" algorithm that is currently in clinical use in the United States for syphilis testing. 
+DPP® TECHNOLOGY & DEVELOPMENT: 
+This year marked a critical year for Chembio in executing our strategy to leverage our DPP® intellectual property and product development and manufacturing experience to create new collaborations where Chembio serves as an exclusive development and manufacturing partner. Examples of such collaboration include the following: 
+· 
+In October 2014, Chembio entered into an exclusive agreement with Integrated BioTherapeutics, Inc. (IBT), a biotechnology company focused on the discovery of novel vaccines and therapeutics for emerging infectious diseases. Under the terms of the agreement, Chembio will combine its patented DPP ® technology with IBT's proprietary Ebola reagents to develop POC diagnostic tests for Ebola and febrile illness. Since announcing the partnership with IBT, the Company has made the following progress to develop DPP ® Ebola and DPP ® Febrile Illness Assays: 
+o 
+Developed DPP ® Ebola Assays in Chembio's Research & Development facilities. 
+o 
+Successfully tested DPP ® Ebola Assays in high containment (BSL4) laboratory, using wild type (real) Ebola virus, via IBT's partner in Canada. 
+o 
+Signed a Research Collaboration Agreement with the Centers for Disease Control and Prevention (CDC) to develop and validate DPP ® Ebola and DPP ® Febrile Illness Assays. 
+o 
+Continued to evaluate its DPP® Ebola test at CDC laboratory in Atlanta, GA, with an estimate of having product for field evaluation in 2Q of 2015. 
+o 
+Submitted DPP ® Ebola pre-qualification application to World Health Organization (WHO) as well as Emergenct Use Authorization (EUA) for FDA 
+o 
+Contacted numerous organizations for Ebola funding, to accelerate the potential development, and potential manufacturing and supply, of DPP ® Ebola and DPP ® Febrile Illness Assays, to include both Ebola and Malaria. 
+· 
+The Company entered into an agreement to develop a POC diagnostic test for dengue fever virus, the DPP ® Dengue Fever Assay, which would be able to detect IgG/IGM and NS1 antigens in October 2014. 
+· 
+A partnership with an international diagnostics company to develop a POC diagnostic test for the early detection and monitoring of a specific type of cancer. The cancer project represents the first application of the DPP ® technology outside the infectious disease field, also announced in October 2014. 
+· 
+The Company entered into a follow-on, milestone-based development agreement with a private contracting organization acting on behalf of the United States Centers for Disease Control and Prevention (CDC), for a multiplex POC influenza immunity test utilizing Chembio's patented Dual Path Platform (DPP ® ) technology. 
+· 
+In January 2015, Chembio entered into an agreement with the Concussion Science Group (CSG) Division of Perseus Science Group LLC, to utilize Chembio's patented DPP ® technology to develop a POC diagnostic test for traumatic brain injury (TBI), including sports-related concussion. Under terms of the agreement, CSG's patented biomarker will be combined with Chembio's proprietary DPP ® platform to develop a semi-quantitative or quantitative point-of-care test to diagnose TBI. CSG has agreed to pay Chembio milestone development payments during 2015. 
+6 
+· 
+In January 2015, Chembio was awarded a grant from the Bill & Melinda Gates Foundation to expedite the feasibility testing and development of a DPP ® Malaria POC rapid diagnostic to accurately identify individuals infected with Plasmodium falciparum parasite. Chembio's DPP ® technology was selected for this grant due to its exceptional sensitivity and potential to aid the foundation in its goal of eradicating malaria. To achieve this goal, diagnostics must be capable of detecting the malaria parasite in infected, but asymptomatic people. Current POC rapid diagnostics tests lack sufficient sensitivity to identify all individuals with transmissible infections. 
+Additionally, Chembio's product pipeline includes a multiplex test that detects P24 HIV antigen as well as HIV 1/2 antibodies, and a rapid test for the detection of Hepatitis-C antibodies. These products are currently in development to meet the performance claims required for the U.S. market. 
+PARTNERS INVOLVED IN MARKETING OUR PRODUCTS 
+Alere 
+On September 29, 2006, we executed marketing and license agreements with Alere. The marketing agreements (the Barrel Agreement and the Cassette Agreement) provide Alere with a 10-year exclusive right (until May 31, 2016) to market our rapid HIV tests in the United States under Alere's brands. The agreements also provide Chembio a non-exclusive license to certain Alere lateral flow patents that may be applicable to our lateral flow products, including for manufacture of the HIV tests in the United States for sales outside the United States and even for sale in the United States should Alere enter the U.S. market with a competitive rapid HIV test product and in such case we choose to market our products directly as provided in the agreements in such event of a competitive rapid HIV test product. Simultaneous with the execution of the agreements, we also settled litigation with StatSure Diagnostics, Inc. (SDS), that had been ongoing relating to the proprietary barrel device which is incorporated into one of our two FDA-approved rapid HIV tests (See Lateral Flow HIV Tests above). SDS, pursuant to the settlement, is a party to the 3-way Barrel Agreement. As a result, until now, it is through the agreements with Alere that we have been participating in the growth of the rapid HIV test market in the United States. 
+In late July 2013, we received notice from Alere that it intends to commercialize its own rapid HIV test (see Competition), which test had just received FDA approval as a moderate complexity product (i.e. not CLIA-waived though this was granted in late 2014), in the United States. Under the Barrel Agreement and the Cassette Agreement such product is considered to be a Permitted Competing Product (PCP). Each of the two aforementioned agreements provides that, in the case of notice of a PCP, Chembio may make certain elections (jointly with SDS in the case of the Barrel Agreement), or elect to continue each agreement without taking any further action. Under the Cassette Agreement, Chembio may, at any time, terminate such agreement, which termination would become effective 60 days after the date notice was made. Under the Barrel Agreement, Chembio and SDS may jointly issue a non-exclusivity notice, which notice shall be effective immediately. In the event that Chembio (and SDS) makes this election with respect to either (or both) of these products, Chembio could sell that respective (or both) product(s) in the United States market under Chembio/SDS brands and in such case, the lateral flow license that Chembio has from Alere for international sales would be expanded to include sales in the United States. See Lateral Flow Technology and Reagent Licenses. In April 2014, the Company gave notice to Alere of its intent to terminate the Cassette Agreement and 60 days later, the Company began marketing in the United States under the Chembio brand of HIV 1/2 STAT-PAK® assay. The barrel product continues to be marketed exclusively by Alere in the U.S only. 
+We have developed our own sales and marketing departments for the sales of our products in the U.S. We have appointed distributors internationally for our lateral flow HIV tests. Our largest markets outside the U.S. for our lateral flow HIV rapid tests are certain countries in Africa, Asia, and South America, as well as Mexico. Internationally, most of the demand for our products is based on governmental and non-governmental prevention and treatment efforts. Given this, these programs can and do often result in large orders, but also can result in periods of relatively lower demand, based on the variations associated with this kind of demand. 
+7 
+OEM DPP® Products 
+Oswaldo Cruz Foundation OEM DPP® Agreements 
+During 2008-2010 we signed five separate agreements, each of which is titled and constitutes a "Technology Transfer Agreement", with the Oswaldo Cruz Foundation (FIOCRUZ) in Brazil. FIOCRUZ includes the Institute of Technology on Immunobiologicals/Bio- Manguinhos, which is the FIOCRUZ unit that produces vaccines and diagnostic kits. FIOCRUZ and Bio-Manguinhos are referred to herein interchangeably. Each of the five agreements relates to a different specific product or group of products based on our DPP® technology. FIOCRUZ is the leading public health organization in Brazil, and it is affiliated with Brazil's Ministry of Health, which is its principal client. It has extensive research, educational and manufacturing facilities for drugs and vaccines, as well as for diagnostic products. 
+Each of the agreements grants to FIOCRUZ the right, but not the obligation, to earn the right to request a technology transfer to be able to license and manufacture that product on its own. FIOCRUZ is not required to earn this right, but if it desires to do so, then it needs to purchase a stated amount of the product as set forth in the respective agreement for that product. 
+During 2010 and 2011, all of the initial products contemplated under the five agreements were approved for marketing by the applicable regulatory agencies in Brazil. The agreements between the Company and FIOCRUZ are unique examples of technology transfer collaborations between a private sector rapid test manufacturer and a public health organization. The five products categories for which FIOCRUZ can earn a separate right to request a technology transfer for that product only are: DPP® products for HIV screening, HIV Confirmatory, Leishmaniasis, Leptospirosis and Syphilis. Each technology transfer, and the provision by Chembio of the information and training that is required for this to occur, will occur only if FIOCRUZ purchases from Chembio the amount of that product that is specified in the respective agreement for that product. The actual amount of purchases for each product is totally at the discretion and option of FIOCRUZ and may be more or less than the amount needed to qualify for a technology transfer. 
+More specifically, the five agreements, although separate and independent of one another, are structurally similar according to the following: 
+· 
+Each agreement states: "the object of this Agreement is for the Transfer of Technology from Chembio to Bio-Manguinhos, the license by Chembio to Bio-Manguinhos [of] the Chembio Patents applied or granted in Brazil or other Mercosur countries for the term of the patents and the transfer of all the technical information related to the DPP technology and the process to obtain the product by the DPP® technology. This Agreement contemplates the scientific and technological co-operation between Chembio and Bio-Manguinhos for such activities so that Bio-Manguinhos will be able to manufacture the Product in Brazil." 
+· 
+Each agreement provides that Chembio will supply free of charge to Bio-Manguinhos prototypes of the product to demonstrate performance characteristics that are necessary for evaluation by the Brazilian Ministry of Health and for registration with ANVISA. ANVISA is the Agencia Nacional de Vigliancia Sanitaria, or the National Sanitary Vigilance Agency. The number of prototypes ranges from 15,000 to 45,000 in the various agreements. 
+· 
+Each agreement provides that the prototypes will be utilized both for a performance study that follows a protocol prepared and approved by Bio-Manguinhos and the Brazilian Ministry of Health, and also will be used for studies in Brazil for the registration procedures at ANVISA. Bio-Manguinhos will then apply to ANVISA to register the product. Within 120 days of the registration of the product with ANVISA, Bio-Manguinhos will make an advance technology transfer payment to Chembio (the "Advance Payment"), in an amount specified in that particular agreement. All five of the Advance Payments provided for in the agreements were made in 2010 and 2011. 
+· 
+At such time, if any, that the product for a particular agreement has been successfully registered with ANVISA, then Bio-Manguinhos has the right to qualify for the full technology transfer for that product by purchasing the amount of the product, and at the price, specified in the agreement. 
+· 
+Bio-Manguinhos is not required to purchase any amount of any product. For each product, it only needs to purchase that product, in the amount specified in the agreement, only if it desires to be able to complete the technology transfer process in order to manufacture and sell that product on its own. Chembio does not have recourse against Bio-Manguinhos if Bio-Manguinhos does not purchase the qualifying purchase amount of any product. In that case, Chembio can only suspend further phases of the technology transfer, attempt to renegotiate the agreement, and/or retain any amounts previously paid by Bio-Manguinhos. Chembio cannot force Bio-Manguinhos to purchase any amount of any product. 
+· 
+As a result of the terms of these agreements, Bio-Manguinhos has never been required to, and is not now required to, purchase any amount of any of the products. 
+· 
+As of December 31, 2014 Bio-Manguinhos had earned the status described below with respect to each of the five products: 
+1. 
+With respect to Chembio's DPP® HIV1/2 Screen test, Bio-Manguinhos had qualified to request the technology transfer. It has requested, and has received, the technology transfer information. Bio-Manguinhos purchased $880,175 of this product in 2011, and $4,990,840 in 2012, all of which applied to the qualifying amount to obtain the right to the technology transfer (the "Qualifying Amount") for this product. In 2013, Bio-Manguinhos made $291,235 of purchases that applied to the Qualifying Amount for this product, and $3,320,010 of purchases in excess of the Qualifying Amount. In 2014, Bio-Manguinhos made $4,799,250 of purchases in excess of the Qualifying Amount. 
+2. 
+With respect to Chembio's Canine Leishmania test, Bio-Manguinhos had qualified to request the technology transfer and did so request. Submission of the technology transfer information is in process at this time. Bio-Manguinhos purchased $2,000,817 of this product in 2011 and $99,183 of this product in 2012 that applied to the Qualifying Amount. In addition, Bio-Manguinhos made purchases in excess of the Qualifying Amount equal to $1,314,117 in 2012, $1,736,700 in 2013 and $2,394,000 in 2014. 
+3. 
+a. 
+With respect to the three variations of Chembio's DPP® Syphilis test, all of which are covered by a single agreement, Bio-Manguinhos had qualified to request the technology transfer with respect to Trep only, and intends to do so in the near future. Bio-Manguinhos purchased $1,194,250 of this product in 2011 and $165,750 of this product in 2012 that applied to the Qualifying Amount. In addition, Bio-Manguinhos made purchases in excess of the Qualifying Amount equal to $2,817,750 in 2012, $646,340 in 2013 and $4,617,891 in 2014. 
+b. 
+With respect to the two variations of Chembio's Screen & Confirm Test, Bio-Manguinhos had not made any purchases in 2011, 2012, 2013 or 2014, and therefore had not qualified to request the technology transfer for either of them. In order to qualify, Bio-Manguinhos would need to purchase an additional $2.2 million of one of these tests, and an additional $2.08 million of the other test. 
+4. 
+With respect to Chembio's DPP® Confirmatory test, Bio-Manguinhos had not qualified to request the technology transfer. Bio-Manguinhos made purchases of $560,000 of this product in 2011, $819,000 in 2012, $390,000 in 2013 and $390,000 in 2014, all of which applied to the Qualifying Amount. In order to qualify for the technology transfer, Bio-Manguinhos would need to purchase an additional $195,000 of this product. 
+5. 
+With respect to Chembio's DPP® Leptospirosis test, Bio-Manguinhos had not qualified to request the technology transfer. Bio-Manguinhos made purchases of $135,000 of this product in 2011, and it made -0- purchases in 2012, $45,000 in 2013 and it made -0- purchases in 2014. In order to qualify for the technology transfer, Bio-Manguinhos would need to purchase an additional $225,000 of this product. 
+8 
+· 
+As stated above, Bio-Manguinhos is not obligated to make any purchases. After the specified level of sales for a particular product has been achieved, FIOCRUZ may request that the technology for that product be transferred to FIOCRUZ together with an exclusive license to produce and sell that product in a defined territory. The license is to provide that Chembio will receive a royalty on all sales. Chembio does not release the amount of this royalty because it could have an adverse effect on negotiations concerning royalties in potential transactions with other parties. 
+· 
+All the agreements expire five years after the date of the technology transfer. If terminated earlier by default of FIOCRUZ, FIOCRUZ must stop all activity; if terminated earlier by default of Chembio, or if terminated by natural expiry, FIOCRUZ can continue to produce and commercialize the product without paying royalties. 
+Other OEM And License Agreements Related to DPP® Technology 
+In addition to our agreement with FIOCRUZ, we have entered into certain other OEM and License agreements with other parties with respect to certain products that we have developed based on our DPP® technology. In 2008 we entered into a product development and license agreement with Bio-Rad Laboratories, Inc. (Bio-Rad), a leading multinational life sciences company, for the first ever POC test for the confirmation of HIV (reflex test used after initial screening test(s) are positive). This product utilizes our DPP® technology, capitalizing on its multiplexing advantages, and is much simpler to perform than the legacy confirmatory platform, known as western blot, which requires a substantial amount of technical training and hands-on time and which is more expensive to manufacture and distribute. This product was CE marked and was launched by Bio-Rad in the second quarter of 2013 in Europe under their Geenius® brand; and an FDA PMA approval was received in 2014. 
+In 2013 we entered into collaboration with Labtest, a private company in Brazil, for the distribution of a number of products in Brazil that would be co-branded with Labtest and Chembio trademarks. Under this agreement, upon request from Labtest, for which there is no requirement, Chembio will sell the appropriate DPP® components to Labtest for further manufacture and assembly in Brazil. 
+In February 2014, Chembio entered into a technology transfer and license agreement with RVR Diagnostics SDN BHD ("RVR"), a privately-held company in Malaysia. The agreement supports Chembio's strategy of establishing a market presence in Asia, in collaboration with RVR as a licensee, distributor, and contract manufacturer. The agreements grant exclusive distribution rights to RVR in certain countries in the region and enable RVR to manufacture Chembio's DPP® HIV 1/2 Assay and DPP® HIV-Syphilis Assay and potentially other products developed by Chembio incorporating its patented DPP® technology, such as Dengue, as indicated in the DPP® Technology & Development section. 
+Our Rapid Test Technologies 
+All of our commercially available current products employ either in-licensed lateral flow technology or our own patented Dual Path Platform (DPP®) technology. Both lateral flow technology and DPP® allow the development of accurate, low cost, easy-to-perform, single-use diagnostic tests for rapid, visual detection of specific antigen-antibody complexes on a test strip. These formats provide a test that is simple (requires neither electricity nor expensive equipment for test execution or reading, nor skilled personnel for test interpretation), rapid (turnaround time approximately 15 minutes), safe (minimizes handling of potentially infected specimens), non-invasive (requires 5-20 micro liters of whole blood easily obtained with a finger prick, or alternatively, serum or plasma), stable (24 months at room temperature storage in the case of our HIV tests), and highly reproducible. 
+We believe that products developed using DPP® technology can provide superior diagnostic performance as compared with products that use lateral flow technology. The reason for this is that one of the major differences between the two platforms is that in DPP® samples are allowed to incubate with the target analyte in the test zone before introduction of the labeling reagent/conjugate, whereas in lateral flow, samples are combined with the labeling reagent to form a complex before coming in contact with the target analyte. We believe that this complex can compromise test performance. Also, because of the usage in DPP® of a separately connected sample strip, the control and delivery of sample material is substantially improved. This feature is critical in the development of multiplex tests, as well as tests that involve viscous sample material (such as oral fluid) that can be impeded when forced to combine with labeling reagents before migration on the test strip to the test zone area. 
+Multiplexing is significantly improved as a result of the design of DPP® and this provides a significant advantage. For example, the HIV confirmatory test we developed for Bio-Rad that is described above employs six different markers related to various epitopes of the HIV antigen. We have a number of other products in development, including those being developed in sponsored development programs that involve the use of multiple (e.g. eight) test bands. Although all of these products could be visually read, we can also use handheld and desktop readers with our DPP® products to objectively measure, quantify, record and report DPP® test results. Certain of the products we have and/or are developing incorporate some of these readers, and we are developing other products that may be used with or will require use of a reader. Also, platforms can incorporate labeling reagents that cannot be visually read except by employing a reader, such as fluorescence, though no products are currently utilizing such reagents. 
+We are pursuing additional capabilities and technologies that will complement our current product portfolio and business strategy. This activity includes pursing development, license or acquisition of diagnostic technologies that complement our existing platforms, proprietary biomarkers that can result in new product applications of our existing platforms, and new platforms that would complement our commercial strategy. 
+Target Markets 
+Rapid HIV Tests 
+A large percentage of individuals that are HIV positive worldwide are unaware of their status. Part of the reason for this is that even those that do get tested in public health settings will often not return or call back for their test results when samples have to be sent out to a laboratory which can take up to several days to process. The increased availability, greater efficacy and reduced costs for anti-retroviral treatments (ARVs) for HIV has increased the demand for testing, as the stigma associated with the disease is lessened, and the ability to resume normal activities is substantially improved, providing a positive message to those potentially infected. The impact that rapid HIV testing has had on prevention efforts has in turn increased the demand for testing, particularly by public health programs worldwide, which have also become more effective in reducing the number of annual new infections in many, but by no means, all high prevalence regions. 
+Despite less attention to HIV by the media as compared with prior years, there are still approximately 50,000 new diagnoses of HIV infection in the United States each year, according to the CDC. CDC estimates that approximately 1.1 million individuals in the U.S. are living with HIV, with an estimated 1 of 6 of these U.S. individuals, or almost 16%, unaware that they are infected. It is transmissions from these 250,000 infected people that are reported to account for the majority of all new infections per year. Part of the reason for this is that even those individuals that do get tested in public health settings will often not return or call back for their test results if their blood samples have to be sent out to and tested in a laboratory and then reported back, a process which can take up to several days to complete. Making more people aware of their HIV status at the point-of-care reduces the number of HIV transmissions. 
+Rapid HIV testing in the United States has now developed into an estimated 7.5 million test market at an average price of $10, or a total of $75 million. Public health programs, currently funded by grants distributed to states by the CDC, account for an estimated 45% of the market, with hospitals (40%) and doctor's offices (15%) comprising the other estimated market segments. Chembio's lateral flow rapid HIV tests, the cassette and barrel, together represent approximately a 25% share of this market. Orasure Technologies, Inc., which was the first FDA-approved rapid HIV test, has lost nearly half its market share, now estimated to be approximately 55%. Trinity Biotech has an estimated 15% market share and Biolytical Laboratories, Medmira and Bio-Rad share the remaining 5%. 
+9 
+In 2006, the outlook for HIV testing was given a big boost with the release by the CDC of new recommendations for HIV testing. These new CDC recommendations were/are that an HIV test should be given as a routine test like any other for all patients between 13 and 64 years of age, regardless of risk, with an opt-out screening option and focused testing procedural (pre- and post-test counseling) guidelines. Though not mandatory, gradual adoption in whole or in part of the 2006 CDC recommendations by a number of states continues to have an increasing impact. Finally, in 2013, the United States Preventive Services Task Force ("USPSTF") fully embraced these CDC routine HIV testing recommendations. This USPSTF recommendation, which was given an A grade under their recommendation grading system based on the benefits of this practice and the nearly 600,000 AIDS-related deaths in the United States, requires insurance coverage under the Affordable Care Act (the "ACA") as a preventive screening test without any co-payment required. We expect this to result in an increase in HIV testing in the United States in the coming years, which we believe will include point-of-care HIV testing utilizing the Company's products. Although as stated above currently most public health testing in the United States is funded by grants allocated to high prevalence areas by the CDC, we believe this will shift to an insurance-funded model under the ACA in the years to come, increasing the amount of testing done in doctor's offices and community health centers. 
+In the international market , we sell our products directly and through distributors to large screening programs overseen by ministries of health and NGOs, most but not all of which are funded by large bi-lateral and multi-lateral AIDS relief programs, the largest of which is the U.S. President's Emergency Plan for AIDS Relief (PEPFAR). Established by President George Bush as a 5-year $15 billion program in 2003, PEPFAR was reauthorized in 2008 and again in 2013. In 2012 PEPFAR directly supported HIV testing and counseling for more than 11 million pregnant women, and testing and counseling for more than 49 million people overall. The U.S. is also the first and largest donor to the Global Fund to Fight AIDS, Tuberculosis and Malaria. To date, the U.S. has provided more than $7 billion to the Fund. 
+In December 2013 President Obama signed into law the PEPFAR Stewardship and Oversight Act, which is the most recent reauthorization of PEPFAR. However, unlike the 2008 PEPFAR authorization, which authorized approximately $45 billion, the new law doesn't authorize a specific dollar amount for funding. Nevertheless it is widely anticipated that PEPFAR will continue to enjoy strong funding; the FY14 budget had $6 billion for global HIV/AIDS assistance, including $4 billion for PEPFAR. 
+Chembio, with its four U.S.-manufactured rapid HIV tests, all of which are FDA-approved, is recognized as a reputable and dependable supplier of high quality products that are available at reasonably competitive prices. As a result, certain of our products have been selected in the testing protocols in countries (national algorithms) that are large beneficiaries of PEPFAR and the Global Fund. As mentioned above, these programs can and do often result in large orders, but also can result in periods of relatively lower demand, based on the variations associated with this kind of demand. Also, even though the United States taxpayer is funding the largest share of global AIDS relief, U.S. companies do not receive any preference for these procurements, and therefore must compete with foreign suppliers that manufacture competitive products with lower costs, including those related to quality, regulatory, intellectual property, and costs of manufacturing. 
+Oral fluid testing is an established alternative to blood testing for diagnostic tests, including HIV tests. It is also often patient preferred, providing a more comfortable, less invasive test. In certain public health clinics, staffs choose not to handle blood specimens; thus, oral sample collection provides a viable alternative. The most well-established market for oral fluid HIV testing is the United States. Given the premium price required for an oral fluid test as compared with blood tests, the higher volume programs will not specify an oral fluid test. However, segments of these programs may want to have an oral fluid testing option, and certain programs that have greater resources may also choose to incorporate oral fluid testing into the testing protocol. 
+There is also now an over-the-counter market for HIV self-testing in the United States. Orasure Technologies Inc. received FDA approval for an over-the-counter (self-testing) version of its previously professional-market-approved (test performed on an individual by a health care professional) HIV test. The FDA approval was granted in July 2012, and Orasure has been investing heavily in developing this market. Initial results after over two years of marketing are well below expectations. The costs for such over-the-counter approval, including primarily the associated clinical trials, are estimated to be at least $5 million and they may take two to three years to complete, not to mention the cost of distribution. Orasure's initial results are not convincing of a large market, although this possibility remains. If it appears that there is an attractive market, we believe we are very well positioned to participate in this market. 
+Rapid HIV-Syphilis Test 
+There are significant risks relating to transmission of Syphilis from a pregnant mother to child, just as there are for transmission of HIV. Therefore we believe there is a significant opportunity to improve prevention efforts in pregnant mother to child transmission testing programs (PMTCT) that are currently not doing any or nearly enough testing for syphilis even though they are testing for HIV. In the United States, we believe there is also a significant need for this product in some of the highest HIV prevalence populations, such as among men that have sex with men (MSM), as data show high degrees of HIV and Syphilis co-infection in this segment of the population. 
+Marketing Strategy: 
+Our marketing strategy is to: 
+o 
+Market our DPP® HIV 1/2 Assay, HIV 1/2 STAT-PAK® Assay and future DPP® based new products in the US through our internal sales and marketing organization and selected channel partners (e.g., McKesson/PSS, Fisher Healthcare, Henry Schein, etc.). Chembio, following the June 2014 termination of the STAT-PAK® agreement with Alere, does not have to share any portion of the net sales proceeds for STAT-PAK® with Alere, except for the 8.5% lateral flow royalties which was applicable to the sales of the products only until February 2015 when the applicable lateral flow patent of Alere's expired. This decision resulted in incurring expenditures related to hiring sales representatives, establishing agreements and associated discounts with distributors, incurring advertising and marketing expenditures, warehousing, customer service and technical support. If Alere's new competitive product is indeed successful, our ability to retain a significant share of the market that has been established for our products may be enhanced by our having control of the marketing of our products, rather than having Alere sell our products. We are leveraging the same sales force for U.S. Sales of DPP® HIV 1/2 Assay. 
+o 
+We will support, review and assess the marketing and distribution efforts of our rapid HIV barrel test by Alere in the U.S. 
+o 
+Outside the U.S., we will market our products primarily through commercial collaborators and distribution partners. 
+o 
+Leverage our DPP® intellectual property and product development and manufacturing experience to continue creating new collaborations where Chembio can be the exclusive development and manufacturing partner supporting leading marketing organizations. 
+o 
+Establish strong distribution relationships for our Chembio-branded products in the U.S and abroad, and establish a direct sales and marketing organization that is focused in the public health market segment, and that utilizes distributors for other market segments, primarily the acute care market which, together with public health, are the main market segments for rapid HIV tests in the United States. We believe that creation of a Chembio public health brand and marketing organization is fundamental to the creation of shareholder value over the long term. 
+During 2014 we increased our commercial activities and efforts in Africa, Europe and Asia for our HIV tests and product pipeline. We believe these efforts will enable us to be more closely engaged with opportunities to engage with customers and partners and to participate in the national testing algorithms that are established and revised from time to time by countries that are beneficiaries of PEPFAR, Global Fund and/or other bilateral or multilateral donor funding. In Europe, where there are a larger percentage of HIV positive people unaware of their status than in the United States, we believe that there is an emerging public health outreach opportunity, and there are relatively few strong competitors that are CE-marked. Most recently we have established new sales and marketing positions in the Company to support our efforts to increase brand awareness globally and to lead our direct sales effort in the U.S. market. 
+10 
+Competition 
+The diagnostics industry is a multi-billion dollar international industry and is intensely competitive. Many of our competitors are substantially larger and have greater financial, research, manufacturing and marketing resources. 
+Industry competition in general is based on the following: 
+· 
+Scientific and technological capability; 
+· 
+Proprietary know-how; 
+· 
+The ability to develop and market products and processes; 
+· 
+The ability to obtain FDA or other required regulatory approvals; 
+· 
+The ability to manufacture products that meet applicable FDA requirements, (i.e. FDA's Quality System Regulations) (see Governmental Regulation section); 
+· 
+The ability to manufacture products cost-effectively; 
+· 
+Access to adequate capital; 
+· 
+The ability to attract and retain qualified personnel; and 
+· 
+The availability of patent protection. 
+We believe our scientific and technological capabilities and our proprietary know-how relating to our in-licensed lateral flow technology rapid tests and to our proprietary know-how related to our patented DPP® technology, particularly for the development and manufacture of tests for the detection of antibodies to infectious diseases such as HIV, are very strong. 
+Our ability to develop and market other products is in large measure dependent on our having additional resources and/or collaborative relationships. Some of our product development efforts have been funded on a project or milestone basis. We believe that our proprietary know-how in lateral flow technology and in our DPP® technology has been instrumental in our obtaining the collaborations we have and that we continue to pursue. We believe that the patent protection that we have with our DPP® technology enhances our ability to develop more profitable collaborative relationships and to license out the technology. However there are a number of competitive technologies used and/or seeking to be used in point-of-care settings. These technologies may be based on immunoassay principles such as the Company's products or other technologies, such as molecular-based technologies. 
+We launched our FDA-approved DPP® HIV 1/2 Assay, which test also can be used either oral fluid or blood samples, in the U.S. market under a Chembio brand in the fourth quarter of 2014. Orasure Technologies manufactures the only other rapid, oral fluid HIV test that is FDA-approved, and Orasure has enjoyed this position for approximately 10 years. Orasure has lost a significant share of this market as certain customers have been indifferent to using blood or oral fluid samples, because the blood tests, including those made/marketed by Chembio and marketed by Alere, are priced lower and/or are as or more accurate than the performance of Orasure's product on blood samples. Orasure has primarily retained those customers for whom the oral fluid sample feature is a strong preference, and this is an estimated $35 million business for Orasure. Although we believe we can capture a meaningful portion of this Orasure market share, we also anticipate that Orasure will defend this business aggressively. 
+In 2006 Alere acquired a division from Abbott Diagnostic located in Japan that manufactured and marketed a rapid HIV test product line called Determine®. The Determine® format is was developed for developing world and remote settings and, central to the needs of that market, the format is essentially a test strip that is integrated into a thin foil wrapper that, when opened, the underside of the wrapper serves as the test surface for applying the blood sample and performing the test. This design reduces costs and shipping weights and volumes and is an advantage for the developing world markets it has served. Some of the disadvantages of the platform are the amount of blood sample that is needed (50 microliters versus 2.5, 5 and 10 for our lateral flow barrel, lateral flow cassette, and DPP® products respectively), the open nature of the test surface, and the absence of a true control that differentiates biological from other kinds of samples. 
+The so-called "3 rd generation" version of this product has been marketed for many years and is the leading rapid HIV test that is used in a large majority of the national algorithms of countries funded by PEPFAR and the Global Fund, as well as many other countries in the world. That product is not FDA-approved though it is CE-marked. The newest Determine® HIV version, which was developed and manufactured at Alere's subsidiary in Israel, Orgenics, is the so-called "4 th Generation" version Determine® test. According to its claims, this product detects HIV antibodies and P24 HIV antigens. Since the P24 antigen is known to occur in HIV-positive individuals' blood samples before antibodies do, based on its performance claims, the 4 th generation Determine® test is therefore able to detect HIV infection earlier than tests that solely rely on antibody detection. Chembio's tests, as well as all of the other currently FDA-approved rapid HIV tests, only detect antibodies. There are however laboratory tests that are FDA-approved that are "4 th generation" tests, but they are of course neither rapid nor point-of-care. 
+11 
+The initial "4 th generation" Alere Determine® rapid test product that was also CE-marked and that Alere launched internationally some years ago has not been successfully commercialized to the best of our knowledge and at least certain published studies were not favorable for this product. However the 4 th generation product that is now FDA-approved was apparently modified as compared to the initial international version of it, and it may perform more satisfactorily. Alere received FDA approval of this modified product in August 2013 and CLIA-waiver for it in the fourth quarter of 2014. We believe the price that Alere is charging for this product may be substantially higher than our and our competitors' antibody tests, as the antigen claim avails some customers of an additional reimbursement code. Moreover there is support by a number of key opinion leaders for the public health value of such 4th generation tests, and if Alere is able to successfully launch this product, it represents a significant competitive threat to Chembio as well as to each of the other rapid HIV test manufacturers (Orasure and Trinity primarily). 
+During 2011 Biolytical, Inc. of Vancouver, Canada received FDA approval and in 2012 received CLIA waiver of a flow-through rapid HIV test called "INSTI". The technology used in the INSTI test, flow-through, is older than lateral flow, and it requires handling of multiple components (3 vials of solution) to perform the test in multiple steps. However, these steps can be accomplished in less than ten minutes, and the actual test results occur in only one minute after those steps are completed. Therefore sample-to-result time is shorter than any of the competitive products. There are settings where that reduced total test time, despite the multiple steps required, may be a distinct advantage, and we believe Biolytical has made some progress in penetrating certain public health markets. 
+Although we have no specific knowledge of any other competitors' products that are a competitive threat to our products, or that will render our products obsolete, if we fail to maintain and enhance our competitive position or fail to introduce new products and product features, our customers may decide to use the products developed by our competitors, which could result in a loss of revenues and cash flow. 
+Research and Development 
+During 2014 and 2013, we spent $4.8 million and $5.8 million, respectively, on research and development (including regulatory activities). These expenses were in part underwritten by funding from R&D and milestones revenues of $1.7 million in 2014 and $2.0 million in 2013. All of our new product development activities involve employment of our DPP® technology. These activities include completing development of certain products and making significant progress toward the development of additional products. 
+Employees 
+At December 31, 2014, we employed approximately 166 people. We have entered into employment contracts with our Chief Executive Officer and President, John J. Sperzel, our Chief Operating Officer, Sharon Klugewicz, and our Chief Science and Technology Officer, Javan Esfandiari. Due to the specific knowledge and experience of these executives regarding the industry, technology and market, the loss of the services of any one of them would likely have a material adverse effect on the Company. The contract with Ms. Klugewicz, has a term of two years ending May 2015. The contract with Mr. Esfandiari has a term of three years ending March 2016. We have obtained a key man insurance policy for Mr. Esfandiari. The contract with Mr. Sperzel provides that Mr. Sperzel will serve as the Chief Executive Officer and President of the Company through March 2017. 
+Governmental Regulation 
+The manufacturing and marketing of the Company's existing and proposed diagnostic products are regulated by the United States Food and Drug Administration ("FDA"), United States Department of Agriculture ("USDA"), certain state and local agencies, and/or comparable regulatory bodies in other countries. These regulations govern almost all aspects of development, production and marketing, including product testing, authorizations to market, labeling, promotion, manufacturing and record keeping. The Company's FDA and USDA regulated products require some form of action by each agency before they can be marketed in the United States, and, after approval or clearance, the Company must continue to comply with other FDA requirements applicable to marketed products, e.g. Quality Systems (for medical devices). Failure to comply with the FDA's requirements can lead to significant penalties, both before and after approval or clearance. 
+There are two review procedures by which medical devices can receive FDA clearance or approval. Some products may qualify for clearance under Section 510(k) of the Federal Food, Drug and Cosmetic Act, in which the manufacturer provides a pre-market notification that it intends to begin marketing the product, and shows that the product is substantially equivalent to another legally marketed product (i.e., that it has the same intended use and is as safe and effective as a legally marketed device and does not raise different questions of safety and effectiveness). In some cases, the submission must include data from human clinical studies. Marketing may commence when the FDA issues a clearance letter finding such substantial equivalence. FDA clearance of our DPP® Syphilis Screen & Confirm test will be by means of a 510(k) submission. 
+If the medical device does not qualify for the 510(k) procedure (either because it is not substantially equivalent to a legally marketed device or because it is required by statute and the FDA's implementing regulations have an approved application), the FDA must approve a Pre-Marketing Application ("PMA") before marketing can begin. PMA's must demonstrate, among other matters, that the medical device provides a reasonable assurance of safety and effectiveness. A PMA application is typically a complex submission, including the results of non-clinical and clinical studies. Preparing a PMA application is a much more expensive, detailed and time-consuming process as compared with a 510(K) pre-market notification. The Company has approved PMAs for the two rapid HIV tests now marketed by Alere Medical as Clearview® Complete HIV 1-2 and Clearview® HIV 1-2 STAT PAK®. 
+FDA approval of our DPP® HIV screening assay for use with oral fluid or blood samples was achieved by means of a PMA application. The Clinical Laboratory Improvement Act of 1988 ("CLIA") prohibits laboratories from performing in-vitro tests for the purpose of providing information for the diagnosis, prevention or treatment of any disease or impairment of, or the assessment of, the health of human beings unless there is in effect for such laboratories a certificate issued by the United States Department of Health and Human Services (via the FDA) applicable to the category of examination or procedure performed. Although a certificate is not required for the Company, it considers the applicability of the requirements of CLIA in the design and development of its products. The statutory definition of "laboratory" is very broad, and many of our customers are considered labs. A CLIA waiver will remove certain quality control and other requirements that must be met for certain customers to use the Company's products and this is critical to the marketability of a product into the point-of-care diagnostics market. The Company has received a CLIA waiver for each of the two lateral flow rapid HIV tests now marketed in the U.S. The CLIA waiver was granted by the FDA for HIV 1/2 STAT-PAK® on November 20, 2006 and for the Clearview® Complete HIV 1/2 on October 22, 2007. In 2008 the FDA revised its CLIA waiver requirements so that an additional prospective trial need be conducted in order to demonstrate clinical utility by showing that the device is capable of identifying new infections when used by untrained users. Our DPP® HIV 1/2 test received CLIA waiver in October of 2014. 
+In addition, the FDA regulates the export of medical devices that have not been approved for marketing in the United States. The Federal Food, Drug and Cosmetic Act contain general requirements for any medical device that may not be sold in the United States and is intended for export. Specifically, a medical device intended for export is not deemed to be adulterated or misbranded if the product: (1) complies with the specifications of the foreign purchaser; (2) is not in conflict with the laws of the country to which it is intended for export; (3) is prominently labeled on the outside of the shipping package that it is intended for export; and (4) is not sold or offered for sale in the United States. However, the Federal Food, Drug and Cosmetic Act does permit the export of devices to any country in the world, if the device complies with the laws of the importing country and has valid marketing authorization in one of several "listed" countries under the theory that these listed countries have sophisticated mechanisms for the review of medical devices for safety and effectiveness. 
+The Company is also subject to regulations in foreign countries governing products, human clinical trials and marketing, and may need to obtain approval or evaluations by international public health agencies, such as the World Health Organization, in order to sell diagnostic products in certain countries. Approval processes vary from country to country, and the length of time required for approval or to obtain other clearances may in some cases be longer than that required for United States governmental approvals. On the other hand, the fact that our HIV diagnostic tests are of value in the AIDS epidemic may lead to some government process being expedited. The extent of potentially adverse governmental regulation affecting Chembio that might arise from future legislative or administrative action cannot be predicted. 
+12 
+Environmental Laws 
+To date, we have not encountered any costs relating to compliance with any environmental laws. 
+Intellectual Property 
+Intellectual Property Strategy 
+Our intellectual property strategy is to: (1) build our own intellectual property portfolio around our DPP® technology; (2) pursue licenses, trade secrets and know-how within the area of rapid point-of-care testing, and (3) develop and acquire proprietary positions to reagents and new hardware platforms for the development and manufacture of rapid diagnostic tests. 
+The Company has obtained patent coverage on the DPP® technology, including four U.S. patents, and patents in China, Malaysia, Eurasia, Mexico, Singapore, Japan, Australia, Indonesia, Korea and the U.K. Additional patent applications on the DPP® technology are pending in the U.S., as well as in many foreign countries such as Brazil, Canada, the European Union, India, Israel, and South Africa. Patents have also been filed on extensions to the DPP® product line concept such as 4th generation assays. The four U.S. patents are as follows: 
+U.S. Patent No. 
+Issued 
+Expires 
+Nature 
+Type 
+Description 
+7,189,522 
+3/13/2007 
+3/11/2025 
+test device 
+utility 
+a test device for determining the presence 
+of a ligand in a sample 
+7,682,801 
+3/23/2010 
+3/11/2025 
+test device 
+and method 
+utility 
+a test device and a method for determining 
+the presence of a ligand in a sample 
+7,879,597 
+2/1/2011 
+3/11/2025 
+test device 
+utility 
+a test device for determining multiple 
+ligands in a sample 
+8,507,259 
+8/13/2013 
+3/11/2025 
+test device 
+utility 
+a test device for determining the 
+presence of a ligand in a sample 
+The Company also licenses a group of lateral flow technology patents from Alere. Our lateral flow products, which are primarily our STAT-PAK®, SURE CHECK®, and DIPSTICK® product lines, may incorporate methods that are claimed under one of the patents licensed from Alere that we use in our tests. That U.S. Patent #6,485,982 is also referred to as the Charlton patent, which patent expired on February 3, 2015. This patent describes a test device and method for a colored particle immunoassay that determines the presence of an analyte in a sample. 
+The Company has also filed for patents and obtained some patents in the U.S. for other inventions such as its multiple host species veterinary TB test, and patent applications for the other inventions are in various stages from being recently filed and not yet examined, to already examined and allowed but not yet issued. The Company selectively and strategically foreign files its patent applications based on a number of economic and strategic factors related to the invention. 
+Trademarks 
+The Company has filed and obtained trademarks for its products including DPP®, SURE CHECK® and STAT-PAK® and also for the SampleTainer® used in certain DPP® products. The DPP® trademark is also registered under the European convention (ECT). The Company recently filed a trademark for STAT-VIEW®, to market the barrel product in Europe. 
+Trade Secrets and Know-How 
+We believe that we have developed a substantial body of trade secrets and know-how relating to the development and manufacture of lateral flow and DPP® based diagnostic tests, including but not limited to the sourcing and optimization of materials for such tests, and how to maximize sensitivity, speed-to-result, specificity, stability and reproducibility. The Company possesses proprietary know-how to develop tests for multiple conditions using colored latex. Our buffer formulations enable extremely long shelf lives of our rapid HIV and other tests and we believe that this provides us with an important competitive advantage. 
+Lateral Flow Technology and Reagent Licenses 
+As part of the agreements executed in 2006 with Alere for the marketing of our HIV tests, we were granted non-exclusive licenses to certain lateral flow patents for certain products manufactured and marketed by Chembio including but not limited to our lateral flow HIV tests. This license allows us to produce, market and sell assays using lateral flow technologies specifically including our STAT-PAK®, SURE CHECK®, DIPSTICK®, and veterinary product lines. Under this license agreement, we pay royalties to Alere ranging from 5% to 8½%, depending upon the country in which the products are sold. Even though the relevant patent has expired in most other jurisdictions, or were never issued in markets where we have sold these products, our manufacture of the products in the United States has required that we pay royalties under this license, which has been a substantial expense. In 2014 our lateral flow royalty expense to Alere was $182,000, and since 2007 we have incurred a total of $2.83 million in lateral flow royalty expenses. As of February 3, 2015 this royalty expense was no longer payable as the applicable patent expires at that time. 
+Although we believe our DPP® is outside of the scope of all lateral flow patents of which we are aware, we consult with patent counsel, and seek licenses and/or redesigns of products that we believe to be in the best interests of the Company and our stockholders. Because of the costs and other negative consequences of time-consuming patent litigation, we often attempt to obtain a license on reasonable terms. Nevertheless there is no assurance that the Alere lateral flow patents we have licensed will not be challenged or that other patents containing claims relevant to the Company's lateral flow or DPP® products will not be granted to third parties and that licenses to such patents, will be available on reasonable terms, if any. In the past Alere has aggressively enforced its lateral flow intellectual property, although some of the main patents will expire within the next couple of years and we are not aware of any patent enforcement litigation that is ongoing with respect to the Alere lateral flow intellectual property. 
+Regardless, the DPP® technology provides us with our own intellectual property. We believe it provides us with a freedom to operate, and that it also enables tests to be developed with improved sensitivity as compared with comparable tests on lateral flow platforms. The Company has signed and anticipates signing new development projects based upon the DPP® technology that will provide new manufacturing and marketing opportunities. We have filed other patent applications that we believe will strengthen the DPP® intellectual property and have also filed for patent protection for certain other point-of-care technologies or applications thereof. 
+The peptides used in our rapid HIV tests were patented by Adaltis Inc. and were licensed to us under a 10-year non-exclusive license agreement dated August 30, 2002. However, in connection with Adaltis' bankruptcy, during the third quarter of 2009 we bought out all of our remaining obligations under that agreement. We also have licensed the antigens used in other tests including our Syphilis, Tuberculosis, Leptospirosis, Leishmaniasis and Chagas tests, and we may enter other license agreements. In prior years we concluded license agreements related to intellectual property rights owned by the United States associated with HIV- 1, and during the first quarter of 2008 we entered into a sub-license agreement for HIV-2 with Bio-Rad Laboratories N.A., the exclusive licensee of the Pasteur Institute's HIV-2 intellectual property estate. 
+13 
+Corporate History 
+On May 5, 2004, we completed a merger with Trading Solutions, Inc. through which Chembio Diagnostic Systems Inc. became our wholly-owned subsidiary, and through which the management and business of Chembio Diagnostic Systems Inc. became our management and business. As part of this transaction, we changed our name to Chembio Diagnostics, Inc. In 2003, we had sold our prior business, and as a result, we had no specific business immediately prior to the merger. 
+Since the formation of Chembio Diagnostic Systems Inc. in 1985, it has been involved in developing, manufacturing, selling and distributing in-vitro diagnostic tests, including rapid tests beginning in 1995, for a number of conditions in humans and animals. 
+On March 12, 2004, we implemented a 1-for-17 reverse split of our common stock. All references in this Form 10-K to shares of our common stock have been adjusted to reflect this reverse split. 
+On May 30, 2012, the Company effected a 1-for-8 reverse split of its common stock. This was done to allow the Company to move to the NASDAQ trading market from the OTCQB market, which occurred on June 7, 2012. As a result of the stock split, the outstanding 63,967,263 common shares were reduced to 7,995,918 outstanding common shares on May 30, 2012. The effect of this reverse stock split also has been retroactively reflected for all periods in these financial statements. 
+14 
+Glossary 
+AIDS 
+Acquired Immunodeficiency Syndrome. AIDS is caused by the Human Immunodeficiency Virus, HIV. 
+ALGORITHM (parallel or serial) 
+For rapid HIV testing this refers both to method or protocol (in developing countries to date) for using rapid tests from different manufacturers in combination to screen and confirm patients at the point-of-care, and may also refer to the specific tests that have been selected by an agency or ministry of health to be used in this way. A parallel algorithm uses two screening tests from different manufacturers and a tie-breaker test only if there is a discrepancy between the screening tests results. A serial algorithm only uses a second confirmatory test if there is a positive result from the screening test, meaning that the number of confirmatory tests used is equal to the positivity rate in the testing venue. A tie-breaker test resolves discrepancies between the screen and the confirmatory test. 
+ANTIBODY 
+A protein which is a natural part of the human immune system produced by specialized cells to neutralize antigens, including viruses and bacteria that invade the body. Each antibody producing cell manufactures a unique antibody that is directed against, binds to and eliminates one, and only one, specific type of antigen. 
+ANTIGEN 
+Any substance which, upon entering the body, stimulates the immune system leading to the formation of antibodies. Among the more common antigens are bacteria, pollens, toxins, and viruses. 
+ANVISA 
+The National Health Surveillance Agency of Brazil 
+ARVs 
+Anti-retroviral medications developed to fight AIDS 
+CDC 
+United States Centers for Disease Control and Prevention 
+CLIA waiver 
+Clinical Laboratory Improvement Act designation that allows simple tests to be performed in point-of-care settings such as doctor's offices, walk-in clinics and emergency rooms. 
+DIAGNOSTIC 
+Pertaining to the determination of the nature or cause of a disease or condition. Also refers to reagents or procedures used in diagnosis to measure proteins in a clinical sample. 
+FIOCRUZ 
+The Oswaldo Cruz Foundation of Brazil 
+FDA 
+United States Food and Drug Administration 
+IgG 
+IgG or Immunoglobulin are proteins found in human blood. This protein is called an "antibody" and is an important part of the body's defense against disease. When the body is attacked by harmful bacteria or viruses, antibodies help fight these invaders. 
+NGO 
+Non-Governmental Organization 
+OTC 
+Over-the-Counter 
+PEPFAR 
+The President's Emergency Plan for AIDS Relief 
+PMA 
+Pre-Marketing Approval –FDA approval classification for a medical device that is not substantially equivalent to a legally marketed device or is otherwise required by statute to have an approved application. Rapid HIV tests must have an approved PMA application before marketing of such a product can begin. 
+PROTOCOL 
+A procedure pursuant to which an immunodiagnostic test is performed on a particular specimen in order to obtain the desired reaction. 
+REAGENT 
+A chemical added to a sample under investigation in order to cause a chemical or biological reaction which will enable measurement or identification of a target substance. 
+RETROVIRAL 
+A type of virus which contains the enzyme Reverse Transcriptase and is capable of transforming infected cells to produce diseases in the host such as AIDS. 
+SENSITIVITY 
+Refers to the ability of an assay to detect and measure small quantities of a substance of interest. The greater the sensitivity, the smaller the quantity of the substance of interest the assay can detect. Also refers to the likelihood of detecting the antigen when present. 
+SPECIFICITY 
+The ability of an assay to distinguish between similar materials. The greater the specificity, the better an assay is at identifying a substance in the presence of substances of similar makeup. 
+USDA 
+U.S Department of Agriculture 
+WHO 
+World Health Organization 
+15 
+ITEM 1A. 
+RISK FACTORS 
+You should carefully consider each of the following risk factors and all of the other information provided in this Prospectus before purchasing our Common Stock. The risks described below are those we currently believe may materially affect us. An investment in our Common Stock involves a high degree of risk, and should be considered only by persons who can afford the loss of their entire investment. 
+Risks related to our industry, business and strategy 
+Because we may not be able to obtain or maintain the necessary regulatory approvals for some of our products, we may not generate revenues in the amounts we expect, or in the amounts necessary to continue our business. Our existing products as well as our manufacturing facility must meet quality standards and are subject to inspection by a number of domestic regulatory and other governmental and non-governmental agencies. 
+All of our proposed and existing products are subject to regulation in the U.S. by the U.S. Food and Drug Administration, the U.S. Department of Agriculture and/or other domestic and international governmental, public health agencies, regulatory bodies or non-governmental organizations. In particular, we are subject to strict governmental controls on the development, manufacture, labeling, distribution and marketing of our products. The process of obtaining required approvals or clearances varies according to the nature of, and uses for, a specific product. These processes can involve lengthy and detailed laboratory testing, human or animal clinical trials, sampling activities, and other costly, time-consuming procedures. The submission of an application to a regulatory authority does not guarantee that the authority will grant an approval or clearance for that product. Each authority may impose its own requirements and can delay or refuse to grant approval or clearance, even though a product has been approved in another country. 
+The time taken to obtain approval or clearance varies depending on the nature of the application and may result in the passage of a significant period of time from the date of submission of the application. Delays in the approval or clearance processes increase the risk that we will not succeed in introducing or selling the subject products, and we may determine to devote our resources to different products. 
+Changes in government regulations could increase our costs and could require us to undergo additional trials or procedures, or could make it impractical or impossible for us to market our products for certain uses, in certain markets, or at all. 
+Changes in government regulations may adversely affect our financial condition and results of operations because we may have to incur additional expenses if we are required to change or implement new testing, manufacturing and control procedures. If we are required to devote resources to develop such new procedures, we may not have sufficient resources to devote to research and development, marketing, or other activities that are critical to our business. 
+We can manufacture and sell our products only if we comply with regulations and quality standards established by government agencies such as the FDA and the USDA as well as by non-governmental organizations such as the ISO and WHO. We have implemented a quality system that is intended to comply with applicable regulations. Although FDA approval is not required for the export of our products, there are export regulations promulgated by the FDA that specifically relate to the export of our products that require compliance with FDA quality system regulation ("QSRs") and that also require meeting certain documentary requirements regarding the approval of the product in export markets. Although we believe that we meet the regulatory standards required for the export of our products, these regulations could change in a manner that could adversely impact our ability to export our products. 
+16 
+Our products may not be able to compete with new diagnostic products or existing products developed by well-established competitors, which would negatively affect our business. 
+The diagnostic industry is focused on the testing of biological specimens in a laboratory or at the point-of-care and is highly competitive and rapidly changing. Some of our principal competitors may have considerably greater financial, technical and marketing resources than we do. Several companies produce diagnostic tests that compete directly with our testing product line, including but not limited to, Orasure Technologies, Alere and Trinity Biotech. Furthermore these and/or other companies have or may have products incorporating molecular and/or other advanced technologies that over time could directly compete with our testing product line. As new products incorporating new technologies enter the market, our products may become obsolete or a competitor's products may be more effective or more effectively marketed and sold. 
+There are competing products that could significantly reduce our U.S. sales of rapid HIV tests. 
+In 2006 Alere, Inc. acquired a division from Abbott Diagnostic located in Japan that manufactured and marketed a rapid HIV test product line called Determine®. The Determine® format was developed for the developing world and remote settings and, central to the needs of that market. The format is essentially a test strip that is integrated into a thin foil wrapper. When opened, the underside of the wrapper serves as the test surface for applying the blood sample and performing the test. This design reduces costs and shipping weights and volumes and provides an advantage for the developing world markets it serves. Some of the disadvantages of the platform are the amount of blood sample that is needed (50 microliters versus 2.5, 5 and 10 for our lateral flow barrel, lateral flow cassette, and DPP® products respectively), the open nature of the test surface, and the absence of a true control that differentiates biological from other kinds of samples. 
+The so-called "3 rd generation" version of this product has been marketed for many years and is the leading rapid HIV test that is used in a large majority of the national algorithms of countries funded by PEPFAR and the Global Fund, as well as many other countries in the world. That product is not FDA-approved though it is CE marked. The newest Determine® HIV version, which was developed and manufactured by Alere's subsidiary in Israel, Orgenics, is the so-called "4 th Generation" version Determine® test. According to its claims, this product detects HIV antibodies and P24 HIV antigens. Because the P24 antigen is known to occur in HIV-positive individuals' blood samples before antibodies do, the 4 th generation Determine® test is designed to detect HIV infection earlier than tests that solely rely on antibody detection. Chembio's tests, as well as all of the other currently FDA-approved rapid HIV tests, only detect antibodies. There are however laboratory tests that are FDA-approved that are "4th generation" tests, but they are of course neither rapid nor point-of-care. 
+The initial "4 th generation" Alere Determine® rapid test product that was also CE marked and that Alere launched internationally some years ago has not been successfully commercialized to the best of our knowledge and at least certain published studies were not favorable for this product. However the 4 th generation product that is now FDA-approved was apparently modified as compared to the initial international version, and it may perform more satisfactorily. Alere received FDA approval of this modified product in August 2013 and is seeking CLIA waiver for it. Alere is also aggressively pursuing development of the market for this product in anticipation of receiving CLIA waiver. Although the product can now be sold to moderate complexity certified laboratories, there is very limited supply of the product thus far, and there is no assessment thus far concerning the actual performance of this product in the hands of customers. We believe the price that Alere is charging for this product is substantially higher than our antibody tests, as well as those of our competitors, as the antigen claim provides some customers of an additional reimbursement code. Moreover there is support by a number of key opinion leaders for the public health value of such 4th generation tests, and if Alere is able to successfully launch this product, it represents a significant competitive threat to Chembio as well as to each of the other rapid HIV test manufacturers (Orasure and Trinity primarily). 
+During 2011, Biolytical, Inc. of Vancouver, Canada received FDA approval and in 2012 received CLIA waiver of a flow-through rapid HIV test called "INSTI". The flow-through technology used in the INSTI test is older than lateral flow, and requires handling of multiple components (3 vials of solution) to perform the test in multiple steps. However, these steps can be accomplished in less than ten minutes, and the actual test results occur in only one minute after those steps are completed. Therefore sample-to-result time is shorter than any of the competitive products. The product also has good performance claims. There are settings where that reduced total test time, despite the multiple steps required, may be a distinct advantage, and we believe Biolytical has made some progress in penetrating certain public health markets. 
+Therefore, even though our lateral flow products currently enjoy a substantial market share in the U.S. rapid HIV test market, and we have an additional rapid HIV test, the DPP® HIV 1/2 Assay, there a number of risks and uncertainties concerning current and anticipated developments in this market. Although we have no specific knowledge of any other new product that is a significant competitive threat to our products, or that will render our products obsolete, if we fail to maintain and enhance our competitive position or fail to introduce new products and product features, our customers may decide to use products developed by our competitors, which could result in a loss of revenues and cash flow. 
+More generally, the point-of-care diagnostics industry is undergoing rapid technological changes, with frequent introductions of new technology-driven products and services. As new technologies become introduced into the point-of-care diagnostic testing market, we may be required to commit considerable additional efforts, time and resources to enhance our current product portfolio or develop new products. We may not have the available time and resources to accomplish this, and many of our competitors have substantially greater financial and other resources to invest in technological improvements. We may not be able to effectively implement new technology-driven products and services or be successful in marketing these products and services to our customers, which would materially harm our operating results. 
+Although we own our DPP® patent, lateral flow technology is still a competitive platform to DPP®, and lateral flow technology has a lower cost of manufacture than DPP® products. Although the DPP® platform has shown improved sensitivity as compared with conventional lateral flow platforms in a number of studies, several factors go into the development and performance attributes of products. Therefore the ability of our products to successfully compete will depend on several other factors including but not limited to our having a patented rapid test platform technology, that differentiate DPP® from lateral flow as well as from other diagnostic platform technologies. 
+We believe that our DPP® is outside of the scope of currently issued patents in the field of lateral flow technology, thereby offering the possibility of greater freedom to operate. However there can be no assurance that our patents or our products incorporating the patent claims will not be challenged at some time in the future. 
+Our use of third-party suppliers, some of which may constitute our sole supply source, for certain important product components presents a risk that could have negative consequences for other business. 
+A number of our components and critical raw materials are provided by third-party suppliers, some of which may be sole-source suppliers, which impacts our ability to manufacture or sell product if our suppliers cannot or will not deliver those materials in a timely fashion, or at all, due to an interruption in their supply, quality or technical issues, or any other reason. If this occurs, we could incur substantial expense and time to be able to reestablish the appropriate quality, cost, regulatory and market-acceptance circumstances needed for commercial success. Even with the needed expense and time, we may not be able to reestablish any or all of these factors. The absence of any one or more of these factors could prevent us from being able to commercially produce and market the affected product or products. 
+New developments in health treatments or new non-diagnostic products may reduce or eliminate the demand for our products. 
+The development and commercialization of products outside of the diagnostics industry could adversely affect sales of our products. For example, the development of a safe and effective vaccine to HIV or treatments for other diseases or conditions that our products are designed to detect, could reduce, or eventually eliminate the demand for our HIV or other diagnostic products and result in a loss of revenues. 
+We may not have sufficient resources to effectively introduce and market our products, which could materially harm our operating results. 
+Introducing and achieving market acceptance for our rapid HIV tests and other new products will require substantial marketing efforts and will require us and/or our contract partners, sales agents, and/or distributors to make significant expenditures of time and money. In some instances we will be significantly or totally reliant on the marketing efforts and expenditures of our contract partners, sales agents, and/or distributors. If they do not have or commit the expertise and resources to effectively market the products that we manufacture, our operating results will be materially harmed. 
+17 
+The success of our business depends on, in addition to the market success of our products, our ability to raise additional capital through the sale of debt or equity or through borrowing, and we may not be able to raise capital or borrow funds on attractive terms and/or in amounts necessary to continue our business, or at all. 
+We were profitable for five consecutive years through 2013. Nevertheless, prior to 2009 we sustained significant operating losses since 2004, and we incurred an operating loss for 2014. As of December 31, 2014, we had a stockholders' equity of $19.7 million and a working capital surplus of $12.4 million. We estimate that our resources are sufficient to fund our needs through the end of 2015 and beyond. Nevertheless we have already made, and may continue to make, significant financial commitments to invest in our sales and marketing organization, regulatory approvals, research and development including new technologies, and production capacity, including expanded facilities. 
+Our liquidity and cash requirements will depend on several factors. These factors include (1) the level of revenues; (2) the extent to which, if any, that revenue level improves operating cash flows; (3) our investments in research and development, facilities, marketing, regulatory approvals, and other investments it may determine to make; and (4) our investment in capital equipment and the extent to which it improves cash flow through operating efficiencies. There are no assurances that we will generate positive cash flow for 2015 or, in the alternative, be successful in raising sufficient capital to fund our needs after 2015. 
+Our U.S. market sales are difficult to predict in 2015 given (i) the introduction of a new rapid test by Alere, and the uncertainty as to whether or to what extent it will be successful in taking away sales of our products; and (ii) our early June 2014 termination of the agreement with a third party for exclusive distribution of our cassette product in the U.S. As a result of this termination, we expect to continue to experience higher average revenue per unit, and a lower volume of U.S. sales, of the cassette product. Higher revenue per unit is anticipated because we previously sold the cassette product to the exclusive U.S. distributor at a significantly lower price than the price at which the distributor resold the product to customers (including re-sellers and distributors) in the United States. However this could occur only after any inventory that the exclusive U.S. distributor had accumulated of our product was consumed, which has taken several months. In addition, in marketing this product directly, we are incurring substantial costs associated with establishing a sales and marketing organization and in establishing channel distribution partners. 
+We believe that underlying demand for HIV rapid testing in the United States remains strong, and that the restoration of some of the funding cutbacks from sequestration and the implementation of the Affordable Care Act and of the United States Preventive Services Task Force recommendations will have a positive impact on the development of the market. Further, our products are well established and relied upon by a large installed base of customers over many years of use in the U.S. global market, and we believe this is a strong advantage. We also believe that our DPP® HIV 1/2 Assay for which CLIA waiver was obtained in October 2014, for use with oral fluid or bloods samples will be able to serve new customers that were previously unavailable to us with our lateral flow blood tests. However, development of new customers with this product is costly and time-consuming. 
+We are attempting to increase international sales of our products, and we have invested in additional resources in connection with this effort; but as we have experienced, the nature of international business is such that it can be volatile from period to period, depending on ordering patterns of donor-funded programs. 
+Furthermore, a number of factors can slow or prevent sales increases or cause sales decreases, or substantially increase the cost of achieving sales assuming they are achieved. These factors include: 
+· 
+economic conditions and the absence of or reduction in available funding sources; 
+· 
+regulatory requirements and customs regulations; 
+· 
+cultural and political differences; 
+· 
+foreign exchange rates, currency fluctuations and tariffs; 
+· 
+dependence on and difficulties in managing international distributors or representatives; 
+· 
+the creditworthiness of foreign entities; 
+· 
+difficulties in foreign accounts receivable collection; 
+· 
+competition 
+· 
+pricing; and 
+· 
+any inability we may have in maintaining or increasing revenues. 
+If we are unable to maintain or increase our revenues from domestic and/or international customers, our operating results will be materially harmed. 
+Although we have an ethics and anti-corruption policy in place, and have no knowledge or reason to know of any practices by our employees, agents or distributors that could be construed as in violation of such policies, our business includes sales of products to countries where there is or may be widespread corruption. 
+Chembio has a policy in place prohibiting its employees, distributors and agents from engaging in corrupt business practices, including activities prohibited by the United States Foreign Corrupt Practices Act (the "FCPA"). Nevertheless, because we work through independent sales agents and distributors (and do not have any employees or subsidiaries) outside the United States, we do not have control over the day-to-day activities of such independent agents and distributors. In addition, in the donor-funded markets in Africa where we sell our products, there is significant oversight from PEPFAR, the Global Fund, and advisory committees comprised of technical experts concerning the development and establishment of national testing protocols. This is a process that includes an overall assessment of a product which includes extensive product performance evaluations including five active collaborations and manufacturer's quality systems, as well as price and delivery. In Brazil, where we have had a total of six product collaborations with FIOCRUZ, the programs through which our products may be deployed are all funded by the Brazilian Ministry of Health. Although FIOCRUZ is affiliated with the Brazilian Ministry of Health, and is its sole customer, FIOCRUZ is not the exclusive supplier for the Ministry of Health. However, because each of our collaborations with FIOCRUZ incorporates a technology transfer aspect, we believe we have a competitive advantage versus other suppliers to the Brazilian Ministry of Health, assuming other aspects of our product offering through FIOCRUZ are otherwise competitive in comparison. We have no knowledge or reason to know of any activities by our employees, distributors or sales agents of any actions which could be in violation of the FCPA, although there can be no assurance of this. 
+We rely on trade secret laws and agreements with our key employees and other third parties to protect our proprietary rights, and we cannot be sure that these laws or agreements adequately protect our rights. 
+We believe that factors such as the technological and creative skills of our personnel, strategic relationships, new product developments, frequent product enhancements and name recognition are essential to our success. All of our management personnel are bound by non-disclosure agreements. If personnel leave our employment, in some cases we would be required to protect our intellectual property rights pursuant to common law theories which may be less protective than provisions of employment, non-competition or non-disclosure agreements. 
+We seek to protect our proprietary products under trade secret and copyright laws, enter into license agreements for various materials and methods employed in our products, and enter into strategic relationships for distribution of the products. These strategies afford only limited protection. We currently have some foreign patents issued, and we are seeking additional patent protection in several other foreign jurisdictions for our DPP® technology. We have licenses to reagents (antigens and peptides) used in several of our products and products under development. Despite our efforts to protect our proprietary assets, and respect the intellectual property rights of others, we participate in several markets where intellectual property rights protections are of little or no value. This can place our products and our company at a competitive disadvantage. 
+18 
+Despite the efforts we make to protect our confidential information, such as entering into confidentiality agreements in connection with new business opportunities, unauthorized parties may attempt to copy aspects of our products or to obtain information that we regard as proprietary. We may be required to expend substantial resources in asserting or protecting our intellectual property rights, or in defending suits related to intellectual property rights. Disputes regarding intellectual property rights could substantially delay product development or commercialization activities because some of our available funds would be diverted away from our business activities. Disputes regarding intellectual property rights might include state, federal or foreign court litigation as well as patent interference, patent reexamination, patent reissue, or trademark opposition proceedings in the U.S. Patent and Trademark Office. 
+To facilitate development and commercialization of a proprietary technology base, we may need to obtain additional licenses to patents or other proprietary rights from other parties. Obtaining and maintaining these licenses, which may not be available, may require the payment of up-front fees and royalties. In addition, if we are unable to obtain these types of licenses, our product development and commercialization efforts may be delayed or precluded. 
+Our continued growth depends on retaining our current key employees and attracting additional qualified personnel, and we may not be able to do so. 
+Our success will depend to a large extent upon the skills and experience of our executive officers, management and sales, marketing, operations and scientific staff. We may not be able to attract or retain qualified employees in the future due to the intense competition for qualified personnel among medical products businesses, geographic considerations, our ability to offer competitive compensation, relocation packages, benefits, and/or other reasons. 
+If we are not able to attract and retain the necessary personnel to accomplish our business objectives, we may experience constraints that will adversely affect our ability to effectively manufacture, sell and market our products to meet the demands of our strategic partners in a timely fashion, or to support internal research and development programs. Although we believe we will be successful in attracting and retaining qualified personnel, competition for experienced scientists and other personnel from numerous companies and academic and other research institutions may limit our ability to do so on acceptable terms. 
+We have entered into employment contracts with our Chief Executive Officer, John Sperzel, our Chief Operating Officer, Sharon Klugewicz, and our Chief Scientist & Technology Officer , Javan Esfandiari. Due to the specific knowledge and experience of these executives regarding the industry, technology and market, the loss of the services of any one of them could have a material adverse effect on the Company. The contract with Mr. Sperzel has a term of three years ending March 2017. The contract with Ms. Klugewicz has a term of two years ending May 2015. The contract with Mr. Esfandiari has a term of three years ending March 2016. The Company has obtained a key man insurance policy on Mr. Esfandiari. The contract with Mr. Sperzel provides that Mr. Sperzel will serve as the Chief Executive Officer and as a Director of the Company through March 13, 2017. 
+We believe our success depends in part on the continued funding of and our ability to participate in large testing programs in the U.S. and worldwide. Funding of these and or similar programs may be reduced, discontinued and/or we may not be able to participate for other reasons. 
+We believe it to be in our best interests to meaningfully participate in large testing programs. Moreover many of these programs are funded by governments and other donors, and there can be no assurance that funding will not be reduced or completely discontinued. Participation in these programs also requires alignment and engagement with the many other participants in these programs, including the World Health Organization, U.S. Center for Disease Control, U.S. Agency for International Development, foreign governments and their agencies, non-governmental organizations, and HIV service organizations. If we are unsuccessful in our efforts to participate in these programs, our operating results could be materially harmed. 
+In December 2013 President Obama signed into law the PEPFAR Stewardship and Oversight Act, which is the most recent reauthorization of PEPFAR. However, unlike the 2008 PEPFAR authorization, which authorized approximately $45 billion in funding, the new law does not authorize a specific dollar amount for funding. Nevertheless it is widely anticipated that PEPFAR will continue to enjoy strong funding; the FY14 budget has $6 billion for global HIV/AIDS assistance, including $4 billion for PEPFAR. 
+To the extent that we are unable to collect our outstanding accounts receivable, our operating results could be materially harmed. 
+There may be circumstances and timing that require us to accept payment terms, including delayed payment terms, from distributors or customers, which, if not satisfied, could cause financial losses. 
+We generally accept payment terms which require us to ship product before the contract price has been paid fully, and there also are circumstances pursuant to which we may accept further delayed payment terms pursuant to which we may continue to deliver product. To the extent that these circumstances result in significant accounts receivables and those accounts receivables are not paid on a timely basis, or are not paid at all, especially if concentrated in one or two customers, we could suffer financial losses. 
+Although we were profitable from 2009 through 2013, we incurred a net loss for 2014 and cannot be certain that we will be able to sustain profitability in the future. 
+From the inception of Chembio Diagnostic Systems, Inc. in 1985 through the period ended December 31, 2008, we incurred net losses. We were then profitable each year from 2009 through 2013. In 2014, we made substantial expenditures for sales and marketing, regulatory submissions, product development, production and warehouse capacity, and other purposes, and we incurred a net operating loss. Our ability to re-achieve profitability in the future will primarily depend on our ability to increase sales of our products based on having made the aforementioned expenditures to reduce production and other costs, and to successfully introduce new products and enhanced versions of our existing products into the marketplace. If we are unable to increase our revenues at a rate that is sufficient to achieve profitability, or adequately control and reduce our operating costs, our operating results would be materially harmed. 
+19 
+To the extent that we are unable to obtain sufficient product liability insurance or that we incur product liability exposure that is not covered by our product liability insurance, our operating results could be materially harmed. 
+We may be held liable if any of our products, or any product which is made with the use or incorporation of any of the technologies belonging to us, causes injury of any type or is found otherwise unsuitable during product testing, manufacturing, marketing, sale or use. We have obtained product liability insurance even though we have never received a product liability claim, and have generally not seen product liability claims for screening tests that are accompanied by appropriate disclaimers. Nevertheless, in the event there is a claim, this insurance may not fully cover our potential liabilities. In addition, as we attempt to bring new products to market, we may need to increase our product liability coverage which could be a significant additional expense that we may not be able to afford. If we are unable to obtain sufficient insurance coverage at an acceptable cost to protect us, we may be forced to abandon efforts to commercialize our products or those of our strategic partners, which would reduce our revenues. 
+Risks related to our Common Stock 
+Our Common Stock continues to be illiquid, so investors may not be able to sell as much stock as they want at prevailing market prices. 
+The average daily trading volume of our Common Stock on the NASDAQ market was approximately 109,000 shares per day over the three months ended December 31, 2014 as compared with approximately 40,500 shares per day over the three months ended December 31, 2013. The liquidity of our stock depends on several factors, including but not limited to the financial results of the Company and overall market conditions, so it is not possible to predict whether this level of liquidity will continue, be sustained, or decrease. 
+Decreased trading volume in our stock would make it more difficult for investors to sell their shares in the public market at any given time at prevailing prices. 
+Our management and larger stockholders exercise significant control over the Company. 
+As of December 31, 2014, our named executive officers, directors and 5% stockholders beneficially owned approximately 23.1% of our voting power, which includes two large investors that beneficially owns approximately 10.9% and 6.4%, respectively of the outstanding stock. For the foreseeable future, and assuming these ownership percentages continue to apply, to the extent that these parties vote similarly, they may be able to exercise significant control over many matters requiring approval by the board of directors or our stockholders. As a result, they may be able to: 
+· 
+control the composition of our board of directors; 
+· 
+control our management and policies; 
+· 
+determine the outcome of significant corporate transactions, including changes in control that may be beneficial to stockholders; and 
+· 
+act in each of their own interests, which may conflict with or differ from the interests of each other or the interests of the other stockholders. 
+20 
+ITEM 2. 
+PROPERTIES 
+Our manufacturing, administrative offices and research facilities are located in Medford, New York. In addition we have warehousing space as well as some additional administrative offices located in Holbrook, New York. We lease approximately 39,660 square feet of industrial space in Medford for $27,305 per month. The space is utilized for research and development activities (approximately 4,160 square feet), offices (approximately 3,100 square feet) and production (approximately 32,400 square feet). The lease term expires on April 30, 2017. The lease provides for annual increases of two and one-half percent each year starting May 1, 2015. We lease approximately 21,450 square feet of industrial space in Holbrook for $14,657 per month. The space is utilized for offices (approximately 2,500 square feet) and warehousing (approximately 18,950 square feet). The lease term expires on April 30, 2018. The lease provides for annual increases of three percent each year starting March 1, 2015. The Company believes this space should be sufficient for its needs in the foreseeable future. 
+ITEM 3. 
+LEGAL PROCEEDINGS 
+From time to time, we may be involved in litigation relating to claims arising out of our operations in the normal course of business. We know of no material, existing or pending legal proceedings against us, nor are we involved as a plaintiff in any material proceeding or pending litigation. There are no proceedings in which any of our directors, officers or affiliates, or any registered or beneficial shareholder, is an adverse party or has a material interest that is adverse to our interest. 
+ITEM 4. 
+MINE SAFETY DISCLOSURES 
+Not Applicable. 
+PART II 
+ITEM 5. 
+MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+Market Information 
+Our stock is quoted on the NASDAQ, under the symbol "CEMI." The table below sets forth the high and low bid prices per share of our common stock for each quarter of our two most recently completed fiscal years. These prices represent inter-dealer quotations without retail markup, markdown, or commission and may not necessarily represent actual transactions. 
+Fiscal Year 2014 
+High Bid 
+Low Bid 
+First Quarter 
+$ 
+3.88 
+$ 
+2.81 
+Second Quarter 
+$ 
+3.56 
+$ 
+2.81 
+Third Quarter 
+$ 
+3.85 
+$ 
+3.02 
+Fourth Quarter 
+$ 
+5.19 
+$ 
+3.40 
+Fiscal Year 2013 
+High Bid 
+Low Bid 
+First Quarter 
+$ 
+5.75 
+$ 
+4.61 
+Second Quarter 
+$ 
+5.10 
+$ 
+4.10 
+Third Quarter 
+$ 
+5.32 
+$ 
+3.00 
+Fourth Quarter 
+$ 
+3.95 
+$ 
+3.19 
+Holders 
+As of March 1, 2015, there were approximately 142 record owners of our common stock. 
+Dividends 
+The Company has never paid cash dividends on its common stock and has no plans to do so in the foreseeable future. 
+Recent Sales of Unregistered Securities 
+Not applicable. 
+21 
+ITEM 6. 
+SELECTED FINANCIAL DATA 
+Presented in this table are selected financial data for the past five years ended December 31, 2014. 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+SELECTED HISTORICAL FINANCIAL DATA 
+As of and For the Years Ended 
+Statement of Operations Data: 
+December 31, 2014 
+December 31, 2013 
+December 31, 2012 
+December 31, 2011 
+December 31, 2010 
+TOTAL REVENUES 
+$ 
+27,645,284 
+$ 
+29,549,609 
+$ 
+25,610,595 
+$ 
+19,388,036 
+$ 
+16,704,703 
+GROSS MARGIN (1) 
+10,814,023 
+39 
+% 
+12,300,159 
+42 
+% 
+10,789,991 
+42 
+% 
+9,390,303 
+48 
+% 
+8,100,699 
+48 
+% 
+OPERATING COSTS: 
+Research and development expenses (1) 
+4,832,537 
+17 
+% 
+5,834,249 
+20 
+% 
+4,486,302 
+18 
+% 
+4,878,119 
+25 
+% 
+2,586,308 
+15 
+% 
+Selling, general and administrative expenses (1) 
+7,531,739 
+27 
+% 
+5,461,083 
+18 
+% 
+4,851,587 
+19 
+% 
+3,424,297 
+18 
+% 
+2,940,721 
+18 
+% 
+12,364,276 
+11,295,332 
+9,337,889 
+8,302,416 
+5,527,029 
+INCOME (LOSS) FROM OPERATIONS 
+(1,550,253 
+) 
+1,004,827 
+1,452,102 
+1,087,887 
+2,573,670 
+OTHER INCOME (EXPENSES): 
+132 
+12,943 
+(1,584 
+) 
+(12,325 
+) 
+(14,503 
+) 
+INCOME (LOSS) BEFORE INCOME TAXES (1) 
+(1,550,121 
+) 
+-6 
+% 
+1,017,770 
+3 
+% 
+1,450,518 
+6 
+% 
+1,075,562 
+6 
+% 
+2,559,167 
+15 
+% 
+Income tax (benefit) provision 
+(412,918 
+) 
+486,952 
+509,237 
+(5,133,229 
+) 
+- 
+NET INCOME (LOSS) 
+$ 
+(1,137,203 
+) 
+$ 
+530,818 
+$ 
+941,281 
+$ 
+6,208,791 
+$ 
+2,559,167 
+Basic income (loss) per share 
+$ 
+(0.12 
+) 
+$ 
+0.06 
+$ 
+0.12 
+$ 
+0.79 
+$ 
+0.33 
+Diluted income (loss) per share 
+$ 
+(0.12 
+) 
+$ 
+0.06 
+$ 
+0.11 
+$ 
+0.73 
+$ 
+0.29 
+Weighted average number of shares outstanding, basic 
+9,530,320 
+8,994,080 
+7,986,030 
+7,874,807 
+7,762,858 
+Weighted average number of shares outstanding, diluted 
+9,530,320 
+9,519,968 
+8,614,944 
+8,556,284 
+8,865,114 
+Balance Sheet Data: 
+Working capital 
+$ 
+12,372,169 
+$ 
+4,221,011 
+$ 
+7,630,368 
+$ 
+6,133,956 
+$ 
+4,560,277 
+Total assets 
+25,010,192 
+24,486,592 
+17,335,150 
+15,485,744 
+9,086,174 
+Total liabilities 
+5,286,030 
+4,309,490 
+3,460,630 
+2,991,110 
+3,277,230 
+Shareholders' equity 
+19,724,162 
+20,177,102 
+13,874,520 
+12,494,634 
+5,808,944 
+(1) percentage shown reflects the percentage of total revenues 
+22 
+ITEM 7. 
+MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+Overview 
+This discussion and analysis should be read in conjunction with the accompanying Consolidated Financial Statements and related notes. Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of any contingent liabilities at the financial statement date and reported amounts of revenue and expenses during the reporting period. On an ongoing basis, we review our estimates and assumptions. Our estimates are based on our historical experience and other assumptions that we believe to be reasonable under the circumstances. Actual results are likely to differ from those estimates under different assumptions or conditions, but we do not believe such differences will materially affect our financial position or results of operations. Our critical accounting policies, the policies we believe are most important to the presentation of our financial statements and require the most difficult, subjective and complex judgments, are outlined below in ''Critical Accounting Policies,'' and have not changed significantly. 
+In addition, certain statements made in this report may constitute "forward-looking statements". These forward-looking statements involve known or unknown risks, uncertainties and other factors that may cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. These factors include, among others, 1) our ability to obtain necessary regulatory approvals for our products; and 2) our ability to increase revenues and operating income, which is dependent upon our ability to develop and sell our products, general economic conditions, demand for our products, and other factors. You can identify forward-looking statements by terminology such as "may," "could", "will," "should," "expects," "intends," "plans," "anticipates," "believes," "estimates," "predicts," "potential," "continues" or the negative of these terms or other comparable terminology. Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance or achievements. 
+Except as may be required by applicable law, we do not undertake or intend to update or revise our forward-looking statements, and we assume no obligation to update any forward-looking statements contained in this report as a result of new information or future events or developments. Thus, you should not assume that our silence over time means that actual events are bearing out as expressed or implied in such forward-looking statements. You should carefully review and consider the various disclosures we make in this report and our other reports filed with the Securities and Exchange Commission that attempt to advise interested parties of the risks, uncertainties and other factors that may affect our business. 
+All of the Company's future products that are currently being developed are based on its patented Dual Path Platform (DPP®), which is a unique diagnostic point-of-care platform that has certain advantages over lateral flow technology. The Company has completed development of several products that employ the DPP® technology which are currently marketed under Chembio's label (DPP® HIV 1/2 Screening Assay and DPP® HIV 1/2 –Syphilis Assay), or which may be marketed pursuant to private label license or distribution agreements such as those with the Oswaldo Cruz Foundation ("FIOCRUZ"), Labtest, RVR and Bio-Rad. 
+Research and development ("R&D"), milestone, and grant and royalty revenues for the year ended December 31, 2014 decreased to $1,696,000 from $2,034,000 in the prior-year, which was the result of a winding down of grants in 2014 over 2013. R&D expenses in the year of 2014 were $4.83 million, compared with $5.83 million in the prior-year. 
+Research & Development Activities 
+Ebola Point-of-Care (POC) Test : In October 2014, we signed an agreement with Integrated BioTherapeutics, Inc. (IBT), to develop, validate, and commercialize a POC Ebola assay for the diagnostic market. This work involves applying IBT's Ebola reagents with Chembio's proprietary DPP® technology to generate a multiplexed unitary assay to diagnose Ebola, including the potential of a febrile illness multiplex test for expanded applications. The outcome of preliminary feasibility testing is encouraging. We are working closely with the CDC laboratory in Atlanta, GA, and estimate we will have product available for field evaluation in 2Q of 2015. Additionally, we have applied for pre-qualification application to World Health Organization (WHO) as well as Emergency Use Authorization (EUA) with the FDA. We continue to seek funding for this project to accelerate development and potential supply. 
+Cancer POC Test : We have entered into a partnership with an international diagnostics company to develop a POC diagnostic test for the early detection and monitoring of a specific type of cancer. The cancer project represents the first application of the DPP ® technology outside of the infectious disease field, as announced in October 2014. This scope of the agreement involves product development of an existing assay, utilizing Chembio's DPP® technology. The goal is to optimize the existing lateral flow assay design, conduct verification and validation studies, and to produce pilot lots to support preclinical studies. Under the terms of the agreement, neither Chembio's partner nor the specific type of cancer is being disclosed. 
+DPP® HIV-Syphilis: We have developed and launched a version of this product for international sale. Studies have been initiated to evaluate a version of this test that has been developed for the US market, to meet the performance requirements for a combination test to detect both HIV and Syphilis, including a "reverse" algorithm that is currently in clinical use in the United States for syphilis testing. 
+DPP® Dengue Development: Based on our 2013 experience developing a DPP ® Febrile Illness Assay in partnership with a U.S. government agency, we signed an agreement to develop a stand-alone DPP ® Dengue Fever Assay which would be able to detect IgG/IGM and NS1 antigens. The goal is to conduct verification and validation studies, as well as produce pilot lots, to support preclinical studies. Under the terms of the agreement, Chembio's partner is not being disclosed. 
+DPP® FLU Immunostatus Assay – The Company entered into a follow-on, milestone-based development agreement in November 2014 with a private contracting organization acting on behalf of the United States Centers for Disease Control and Prevention (CDC), for a multiplex POC influenza immunity test utilizing Chembio's patented Dual Path Platform (DPP ® ) technology. 
+DPP® Brain Injury Test : Chembio entered into an agreement with the Concussion Science Group (CSG) Division of Perseus Science Group LLC, to utilize Chembio's patented DPP ® technology to develop a POC diagnostic test for traumatic brain injury (TBI), including sports-related concussion. Under terms of the agreement, CSG's patented biomarker will be combined with Chembio's proprietary DPP ® platform to develop a semi-quantitative or quantitative point-of-care test to diagnose TBI. CSG has agreed to pay Chembio milestone development payments during 2015. 
+DPP ® Malaria POC Rapid Test : Chembio was awarded a grant from the Bill & Melinda Gates Foundation in January 2015 to expedite the feasibility testing and development of a DPP ® Malaria POC rapid diagnostic to accurately identify individuals infected with Plasmodium falciparum parasite. Chembio's DPP ® technology was selected for this grant due to its exceptional sensitivity and potential to aid the foundation in its goal of eradicating malaria. To achieve this goal, diagnostics must be capable of detecting the malaria parasite in infected, but asymptomatic people. Current POC rapid diagnostics tests lack sufficient sensitivity to identify all individuals with transmissible infections. 
+Additionally, Chembio's product pipeline includes a multiplex test that detects P24 HIV antigen as well as HIV 1/2 antibodies, and a rapid test for the detection of Hepatitis-C antibodies. These products are currently in development to meet the performance claims required for the U.S. market. 
+23 
+Regulatory Activities 
+DPP® HIV 1/2 Screening Assay for Use with oral fluid or blood samples – We received Food and Drug Administration (FDA) approval of our Pre-Marketing Application (PMA) for this product in December 2012. In October 2014 , the FDA granted the waiver for DPP® HIV 1/2 Assay for Oral Fluid, Fingerstick Whole Blood and Venous Whole Blood under the Clinical Laboratory Improvement Amendments of 1988 (CLIA) regulations. 
+DPP® HIV-Syphilis – We have developed this product for international and U.S. marketing. For the international market, the product has been registered in Mexico, and successfully launched and sold in this region. In February 2015, this product was granted approval from the Brazilian ANVISA. We have submitted this product both for evaluation by the CDC, acting on behalf of the United States Agency of International Development, and the WHO, which has accepted this product to be evaluated for pre-qualification in its global procurement scheme. In October 2014, WHO conducted a three day audit of our facilities as follow up to pre-qualification activities for the DPP® HIV-Syphilis Assay, including other products submitted for pre-qualification through WHO. No major non-conformances were identified during this audit, and we continue to work with WHO to obtain pre-qualification approval status for this device. We continue to pursue an FDA submission for this product, and are in the progress of studies to evaluate a version that has been developed for the US market, to meet the performance requirements for a combination test to detect both HIV and Syphilis, including a "reverse" algorithm that is currently in clinical use in the United States for syphilis testing. 
+There can be no assurance that any of the aforementioned Research & Development and/or Regulatory products or activities will result in any product approvals or commercialization, nor that any of the existing research and development activities, or any new potential development programs or collaborations will materialize or that they will meet regulatory or any other technical requirements and specifications, and/or that if continued, will result in completed products, or that such products, if they are successfully completed, can or will be successfully commercialized. 
+Recent Events 
+On January 19, 2015, the Company entered into a 2015 Omnibus Agreement (the "Omnibus Agreement") with StatSure Diagnostic Systems, Inc. ("SDS") to acquire certain rights from, and to settle certain matters with, SDS. Prior to execution of the Omnibus Agreement, SDS owned 50 percent of the rights to the SURE CHECK® HIV 1/2 Assay (the "Barrel Product") pursuant to the "2-Way Agreement", as defined below, and subject to the "3-Way Agreement", as defined below. The "2-Way Agreement" is defined as the Joint HIV Barrel Product Commercialization Agreement, dated as of September 29, 2006, as amended, between Chembio and SDS, that establishes the respective rights of Chembio and SDS concerning the Barrel Product. The "3-Way Agreement" is defined as the HIV Barrel License, Marketing And Distribution Agreement, dated as of September 29, 2006, as amended, among Chembio, SDS and Alere Inc. ("Alere"), which grants to Alere exclusive U.S. marketing and distribution rights, through May 31, 2016, to the Barrel Product. 
+Pursuant to the Omnibus Agreement, beginning June 1, 2016, Chembio will own full rights to the SURE CHECK® HIV 1/2 Assay, including a perpetual, non-exclusive, transferable, sub-assignable license, and including sales, marketing, distribution and trademark rights, subject to the terms of the 3-Way Agreement. Chembio paid $400,000 to SDS in exchange for these rights. In addition certain amounts owed by SDS to Chembio were exchanged for manufacturing equipment owned by SDS. The license will be amortized over its useful life and the equipment will be depreciated over its excepted life. 
+For all sales of the Barrel Product made by Chembio outside the United States from July 1, 2014 until the close of business on May 31, 2016, SDS will receive an amount equal to 30% of Chembio's net sales. For all sales of the Barrel Product made by SDS outside the U.S. prior to the close of business on May 31, 2016, Chembio will receive an amount equal to 30% of SDS' net sales. Calculation of "net sales" will be based on the amount of revenues received, reduced by costs, royalties and sales commissions incurred. Until the close of business on May 31, 2016, each of Chembio and SDS will continue to receive payments from Alere under the terms of the 3-Way Agreement for sales of the Barrel Product by Alere. 
+The 3-Way Agreement will continue to remain in effect pursuant to its terms. The 2-Way Agreement was terminated pursuant to the provisions of the Omnibus Agreement. 
+Also under the terms of the Omnibus Agreement, SDS and Chembio agreed to resolve all other matters between them, including matters set forth in the complaint recently filed by SDS against Chembio in the United States District Court for the Eastern District of New York. 
+24 
+RESULTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2014 AS COMPARED WITH THE YEAR ENDED DECEMBER 31, 2013 
+Income : 
+For the year ended December 31, 2014, Loss before income taxes was $(1,550,000) compared to Income before taxes of $1,018,000 for the year ended December 31, 2013. Net Loss for the 2014 period was $(1,137,000) as compared to a Net Income of $531,000 for 2013. The change from Net Income to Net Loss is primarily attributable to decreased revenues, decreased gross margin, and increased operating expenses. Gross margin decreased in the year ended December 31, 2014 as compared with the year ended December 31, 2013, by $1,486,000, or 12.1%. This decreased gross margin and increased operating expenses, the most significant of which were an increase in wages and related expenses of $940,000, an increase in commissions of $530,000, consulting expenses of $171,000, marketing materials of $279,000, stock-based compensation of $169,000, travel and entertainment of $130,000 and change in bad debt allowance of $61,000, partially offset by decreased clinical trial expenses of $1,310,000, accounted for most of the change in Net Loss. 
+Revenues: 
+Selected Product Categories: 
+For the years ended 
+December 31, 2014 
+December 31, 2013 
+$ Change 
+% Change 
+Lateral Flow HIV Tests and Components 
+$ 
+9,518,242 
+$ 
+20,248,364 
+$ 
+(10,730,122 
+) 
+-52.99 
+% 
+DPP® Tests and Components 
+15,655,680 
+6,592,660 
+9,063,020 
+137.47 
+% 
+Other 
+775,847 
+674,762 
+101,085 
+14.98 
+% 
+Net Product Sales 
+25,949,769 
+27,515,786 
+(1,566,017 
+) 
+-5.69 
+% 
+License and royalty revenue 
+23,257 
+4,906 
+18,351 
+374.05 
+% 
+R&D, milestone and grant revenue 
+1,672,258 
+2,028,917 
+(356,659 
+) 
+-17.58 
+% 
+Total Revenues 
+$ 
+27,645,284 
+$ 
+29,549,609 
+$ 
+(1,904,325 
+) 
+-6.44 
+% 
+Revenues for our lateral flow HIV tests and related components during the year ended December 31, 2014 decreased by approximately $10,730,000 from the same period in 2013. This was primarily attributable to decreased sales to South America, of approximately $6,500,000, decreased sales to the U.S. of $1,890,000, and decreased sales to Africa of $2,255,000. Revenues for our DPP® products during the year ended December 31, 2014 increased by approximately $9,063,000 over the same period in 2013, primarily for sales in Brazil to FIOCRUZ. The decrease in R&D, and in milestone and grant revenue, was primarily due to a reduction in revenue from certain development projects that were nearing completion during the period, partially offset by $1,125,000 in revenue from the license contract we signed in February 2014 with RVR Diagnostics. R&D revenues include funds, recognized on an "as expenses are incurred" basis, from a Phase II NIH grant for Leptospirosis, which was effective as of June 1, 2009, and from a Phase II grant for Tuberculosis, which was effective March 1, 2011, as well as a development contract with Battelle entered into in the fourth quarter of 2014. 
+Gross Margin: 
+Gross Margin related to Net Product Sales: 
+For the years ended 
+December 31, 2014 
+December 31, 2013 
+$ Change 
+% Change 
+Gross Margin per Statement of Operations 
+$ 
+10,814,023 
+$ 
+12,300,159 
+$ 
+(1,486,136 
+) 
+-12.08 
+% 
+Less: R&D, milestone, grant, license and royalties 
+1,695,515 
+2,033,823 
+(338,308 
+) 
+-16.63 
+% 
+Gross Margin from Net Product Sales 
+$ 
+9,118,508 
+$ 
+10,266,336 
+$ 
+(1,147,828 
+) 
+-11.18 
+% 
+Product Gross Margin % 
+35.14 
+% 
+37.31 
+% 
+The overall gross margin dollar decrease of $1,486,000 included a $1,148,000 decrease in gross margin from net product sales and a $338,000 decrease in non-product revenues. The decrease in net product sales gross margin of $1,148,000 is primarily attributable to the change in product mix compared to 2013, particularly the reduction of sales to our U.S. distributor in the third and fourth quarters which were at much higher margins. The net product sales gross margin decrease is comprised of two components, one is the decreased change in margin percentage of 2.2% which contributed $564,000 to the decrease, and the other is the decrease in product sales of $1,566,000, which at the 37.3% margin contributed the balance of $584,000. The 2.2% decrease in the percentage, from 37.3% in 2013 to 35.1% in 2014, was primarily due to a larger amount of unapplied overhead along with the reduced sales to our U.S. distributor. 
+25 
+Research and Development: 
+This category includes costs incurred for product research and development, regulatory approvals, technical support, evaluations and registrations. 
+Selected expense lines: 
+For the years ended 
+December 31, 2014 
+December 31, 2013 
+$ Change 
+% Change 
+Clinical and Regulatory Affairs: 
+Wages and related costs 
+$ 
+448,852 
+$ 
+436,088 
+$ 
+12,764 
+2.93 
+% 
+Consulting 
+29,741 
+53,493 
+(23,752 
+) 
+-44.40 
+% 
+Stock-based compensation 
+3,231 
+19,478 
+(16,247 
+) 
+-83.41 
+% 
+Clinical trials 
+205,589 
+1,515,212 
+(1,309,623 
+) 
+-86.43 
+% 
+Other 
+93,780 
+82,852 
+10,928 
+13.19 
+% 
+Total Regulatory 
+781,193 
+2,107,123 
+(1,325,930 
+) 
+-62.93 
+% 
+R&D Other than Regulatory: 
+Wages and related costs 
+2,456,514 
+2,224,882 
+231,632 
+10.41 
+% 
+Consulting 
+123,965 
+106,155 
+17,810 
+16.78 
+% 
+Stock-based compensation 
+41,306 
+86,023 
+(44,717 
+) 
+-51.98 
+% 
+Materials and supplies 
+1,021,516 
+975,503 
+46,013 
+4.72 
+% 
+Other 
+408,043 
+334,563 
+73,480 
+21.96 
+% 
+Total other than Regulatory 
+4,051,344 
+3,727,126 
+324,218 
+8.70 
+% 
+Total Research and Development 
+$ 
+4,832,537 
+$ 
+5,834,249 
+$ 
+(1,001,712 
+) 
+-17.17 
+% 
+Expenses for Clinical & Regulatory Affairs for the year ended December 31, 2014 decreased by $1,326,000 as compared to the same period in 2013. This was primarily due to a decrease of $1,309,000 in clinical trial expenses. 
+R&D expenses other than Clinical & Regulatory Affairs increased by $324,000 in the year ended December 31, 2014, as compared with the same period in 2013. The increases were primarily related to an increase in wages and related costs, and in material and supplies, to support our sponsored research and internal development programs. 
+Selling, General and Administrative Expense: 
+Selected expense lines: 
+For the years ended 
+December 31, 2014 
+December 31, 2013 
+$ Change 
+% Change 
+Wages and related costs 
+$ 
+2,763,370 
+$ 
+2,068,173 
+$ 
+695,197 
+33.61 
+% 
+Consulting 
+456,658 
+279,688 
+176,970 
+63.27 
+% 
+Commissions 
+1,432,567 
+902,393 
+530,174 
+58.75 
+% 
+Stock-based compensation 
+399,334 
+169,502 
+229,832 
+135.59 
+% 
+Marketing materials 
+345,426 
+112,326 
+233,100 
+207.52 
+% 
+Investor relations/investment bankers 
+168,410 
+214,786 
+(46,376 
+) 
+-21.59 
+% 
+Legal, accounting and compliance 
+662,522 
+621,429 
+41,093 
+6.61 
+% 
+Travel, entertainment and trade shows 
+320,280 
+190,698 
+129,582 
+67.95 
+% 
+Bad debt allowance (recovery) 
+28,000 
+(33,450 
+) 
+61,450 
+-183.71 
+% 
+Other 
+955,172 
+935,538 
+19,634 
+2.10 
+% 
+Total S, G &A 
+$ 
+7,531,739 
+$ 
+5,461,083 
+$ 
+2,070,656 
+37.92 
+% 
+Selling, general and administrative expenses for the year ended December 31, 2014, increased by $2,071,000 as compared with the same period in 2013, a 37.9% increase. This increase resulted primarily from increases in wages and related costs, which for 2014 included the development of a sales and marketing team and the COO (not included in the first six months of 2013), consulting expenses, the cost of the CEO search, and commissions due to increased sales to Brazil, which were partially offset by a decrease in investor relations/investment bankers. 
+26 
+Other Income and Expense: 
+For the years ended 
+December 31, 2014 
+December 31, 2013 
+$ Change 
+% Change 
+Other income (expense) 
+$ 
+(5,707 
+) 
+$ 
+7,500 
+$ 
+(13,207 
+) 
+-176.09 
+% 
+Interest income 
+$ 
+5,839 
+$ 
+5,778 
+$ 
+61 
+1.06 
+% 
+Interest expense 
+- 
+(335 
+) 
+335 
+-100.00 
+% 
+Total Other Income and (Expense) 
+$ 
+132 
+$ 
+12,943 
+$ 
+(12,811 
+) 
+-98.98 
+% 
+Other income (expense) for the year ended December 31, 2014 decreased approximately $13,000, primarily due to a loss on the sales of a fixed asset of $5,700 from a gain on the sale of a fixed asset $7,500 in the same period in 2013. 
+Income tax (benefit) provision: 
+For the year ended December 31, 2014 the Company recognized a $(413,000) income tax benefit and increased its deferred tax assets by $(403,000). For the year ended December 31, 2013, the Company charged $487,000 to income tax expense and reduced the deferred tax asset by $458,000. The effective tax rate used to recognize the benefit in 2014 was 26.6% compared to a 47.8% rate used in 2013 to record the amount charged. In both years non-deductible expenses for tax purposes accounted for most of the difference from the standard 34% U.S. tax rate. The Company maintains a full valuation allowance on research and development tax credits. 
+MATERIAL CHANGES IN FINANCIAL CONDITION 
+Selected Changes in Financial Condition 
+As of 
+December 31, 2014 
+December 31, 2013 
+$ Change 
+% Change 
+Cash and cash equivalents 
+$ 
+4,614,538 
+$ 
+9,650,275 
+$ 
+(5,035,737 
+) 
+-52.18 
+% 
+Accounts receivable, net of allowance for doubtful accounts of $52,000 and $24,000 at December 31, 2014 and 2013, respectively 
+8,338,889 
+4,592,121 
+3,746,768 
+81.59 
+% 
+Inventories 
+3,638,299 
+3,188,726 
+449,573 
+14.10 
+% 
+Fixed assets, net of accumulated depreciation 
+2,797,929 
+1,978,232 
+819,697 
+41.44 
+% 
+Deposits and other assets 
+245,870 
+44,367 
+201,503 
+454.17 
+% 
+Deferred tax asset, net of valuation allowance 
+4,031,302 
+3,590,207 
+441,095 
+12.29 
+% 
+Accounts payable and accrued liabilities 
+4,946,030 
+4,309,490 
+636,540 
+14.77 
+% 
+Deferred revenue 
+340,000 
+- 
+340,000 
+100.00 
+% 
+Cash decreased by $5,036,000 from December 31, 2013, primarily due to net cash used in operating activities for the year of 2014. In addition there were increases in accounts receivable, net of allowance, of $3,747,000, inventories of $450,000, fixed assets of $1,488,000 before depreciation, deposits and other assets of $202,000 and deferred taxes of $441,000. We experienced an increase in accounts payable and accrued liabilities of $637,000 and deferred revenue of $340,000. 
+The increase in accounts receivable was primarily attributable to the higher amount of credit sales at the end of December 2014 versus December of 2013 as well as some extended terms granted to certain customers. The increase in inventories is due to an increase in a component used in our products while a vendor refurbishes their facility. The increase in fixed assets is primarily due to the new warehouse facility. The increase in deposits and other assets is due to additional rental deposits and related capitalized expenses. Deferred tax asset increase is related to the provision for income tax benefit. 
+27 
+LIQUIDITY AND CAPITAL RESOURCES 
+For the years ended 
+December 31, 2014 
+December 31, 2013 
+$ Change 
+% Change 
+Net cash (used in) provided by operating activities 
+$ 
+(3,820,299 
+) 
+$ 
+2,277,614 
+$ 
+(6,097,913 
+) 
+-267.73 
+% 
+Net cash used in investing activities 
+(1,452,601 
+) 
+(885,609 
+) 
+(566,992 
+) 
+64.02 
+% 
+Net cash provided by financing activities 
+237,163 
+5,306,411 
+(5,069,248 
+) 
+-95.53 
+% 
+(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS 
+$ 
+(5,035,737 
+) 
+$ 
+6,698,416 
+$ 
+(11,734,153 
+) 
+17-5.18 
+% 
+The Company's cash decreased as of December 31, 2014 by $5,036,000 from December 31, 2013, primarily due to net cash used in operating activities and investing activities for year of 2014. 
+The cash used in operations in 2014 was $3,820,000, primarily due to an increase in accounts receivable of $3,775,000, an increase in inventories of $450,000, an increase in other assets of $279,000, a decrease in prepaid and other current assets of $33,000, and a net loss net of non-cash items of $326,000, partially offset by an increase in accounts payable and other accrued liabilities of $637,000 and an increase in deferred revenue of $340,000. Net loss net of non-cash items includes net loss of $1,137,000, $403,000 in benefit for income taxes, partially offset by $739,000 in depreciation and amortization, an increase in allowance for doubtful accounts of $28,000, and $447,000 in share-based compensation. The use of cash from investing activities is primarily the purchase of fixed assets. The increase in cash from financing activities was proceeds from option exercises. 
+Fixed Asset Commitments 
+As of December 31, 2014, the Company had paid deposits on various pieces of equipment aggregating $20,000 which is reflected in Other Assets on the balance sheet. The Company is further committed to additional equipment-purchase obligation of $9,000 as various milestones are achieved by the various vendors. 
+28 
+RECENT DEVELOPMENTS AND CHEMBIO'S PLAN OF OPERATIONS FOR THE NEXT TWELVE MONTHS 
+During 2014, Chembio began executing a strategy designed to position the Company for future growth. This strategy impacts the entire Chembio business, including commercial operations, manufacturing operations, product development, research collaborations, and regulatory affairs. 
+Our first step took place in April 2014, when we made an important decision to terminate our existing U.S. HIV 1/2 STAT-PAK ® distribution agreement in June 2014. We then established the first ever Chembio U.S. sales and marketing team. In October 2014, we achieved a significant milestone when the FDA granted a CLIA waiver for our lead product, the point-of-care DPP® HIV 1/2 Assay, for use with oral fluid or blood samples. This waiver, for the first time, granted us the opportunity to market the DPP® HIV 1/2 Assay to the broad healthcare community. To support our direct sales and marketing initiative, and to ensure a successful launch of this product, we established agreements with a number of premier distribution partners (e.g., McKesson/PSS, Fisher Healthcare, Henry Schein, Medline) for the distribution of both DPP ® HIV 1/2 and HIV 1/2 STAT-PAK ® Assays in the U.S. Looking ahead to 2015, we expect to further expand our commercialization team and distribution partnerships in order to build on the sales initiative we created in 2014. 
+Another important achievement during 2014 was our strong performance in Latin America, where we saw significant uptake of our DPP ® HIV 1/2, DPP ® Syphilis and our combination DPP ® HIV-Syphilis Assays. Thanks to the support of our long-term commercial partners in this region, we had very considerable sales growth in Brazil and Mexico during the year, with sales in Brazil increasing nearly 90% as compared to the prior year, which helped us achieve 137% growth in DPP ® sales as compared to 2013. It is important to note that interest in our DPP ® HIV-Syphilis Assay has been significant from healthcare agencies around the world, leading us to believe that this product will continue to represent a great growth opportunity in Latin America and throughout the world. 
+On the operational front, Chembio made important investments in 2014, which we expect to contribute to our success in 2015 and beyond. In May 2014, we established a Chembio warehouse and distribution center in Holbrook, NY and made improvements to our manufacturing facility in Medford, NY. Our partnership with RVR (Malaysia) continues to progress according to key milestones and we expect the facility in Kuala Lumpur to begin production of commercial product in 2015. 
+During the year, we made the decision to streamline our internal product development pipeline to focus on four key projects that we believe are most likely to result in high-value assays that will address critical needs. These programs include a multiplex test that detects HIV and Syphilis specific antibodies (which we are already selling internationally), a multiplex rapid test for earlier detection of HIV by detecting P-24 antigen as well as antibodies, a test for Hepatitis-C, and improvements to our oral fluid detection technology. These projects are all based on our DPP ® technology for which we were issued a United States patent in 2007 and for which additional patent protection has issued or is pending in a number of other countries. We believe these programs will create the next generation of Chembio-branded products and fuel our continued growth at home and abroad. 
+Another key element to our strategy in 2014 was partnering. During the last 6 months, we entered into a number of important research collaborations that leverage our patented DPP ® platform technology to develop diagnostics for some of the most serious diseases and health crises worldwide. These partnerships involve the development of DPP ® tests for certain febrile illnesses (e.g., malaria, dengue fever, Ebola), traumatic brain injury (including sports-related concussion), flu immunostatus, and a specific form of cancer. We are proud to be working along side some of the world's leading and most influential health organizations in these endeavors, including the Centers for Disease Control and Prevention (CDC) and the Bill & Melinda Gates Foundation. In each of these collaborations, our objective is to develop new and valuable products that will be commercialized via Chembio's sales teams and distributor partners globally. 
+We are happy to report that in 2014 and early 2015 we received a number of key regulatory approvals that will further facilitate our plan for growth. In October, the FDA granted a CLIA Waiver for our lead product, the point-of-care DPP ® HIV 1/2 Assay, for use with oral fluid or blood samples. The HIV 1/2 STAT-PAK® Assay received CE Mark in March 2014 and we have updated our filing for CE Marking to reflect the new trade name of STAT-VIEW ® HIV 1/2 Assay (formerly SURE CHECK ® ) for sale in the EU market. The CE Marking for the DPP ® HIV 1/2 Assay is expected in 2015. In February 2015, the DPP ® HIV-Syphilis Assay was granted approval from the Brazilian ANVISA. Recently, we submitted the DPP ® HIV-Syphilis Assay for evaluation by both the CDC, acting on behalf of the United States Agency of International Development, and the WHO, which has accepted this product to be evaluated for pre-qualification in its global procurement scheme. 
+We believe 2015 will mark a number of significant events for the Company, including further development of the newly-formed U.S. sales team, the ex-US commercial expansion of the DPP ® HIV-Syphilis Assay, the pursuit of a DPP ® HIV-Syphilis Assay for the U.S. market, and progress on key product development and research initiatives that will strengthen DPP ® as a branded platform technology. We are optimistic that, the strategy we implemented in 2014 will strengthen our base business in POC infectious disease testing, create new opportunities to leverage our patented DPP ® technology, advance our key development programs and commercial partnerships, and establish the foundation for a successful 2015 and beyond. 
+29 
+Critical Accounting Policies and Estimates 
+The preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ materially from those estimates. 
+We believe that there are several accounting policies that are critical to understanding our historical and future performance, as these policies affect the reported amounts of revenue and the more significant areas involving management's judgments and estimates. These significant accounting policies relate to revenue recognition, research and development costs, valuation of inventory, valuation of long-lived assets and income taxes. These policies, and the related procedures, are described in detail below. 
+Revenue Recognition – 
+We recognize revenue for product sales in accordance with ASC 605, Revenue is recognized when there is persuasive evidence of an arrangement, delivery has occurred or services have been rendered, the sales price is determinable, and collectability is reasonably assured. Revenue typically is recognized at time of shipment. Sales are recorded net of discounts, rebates and returns. 
+For certain contracts, we recognize revenue from R&D, milestone and grant revenues when earned. Grants are invoiced after expenses are incurred. Revenues from projects or grants funded in advance are deferred until earned. 
+For certain collaborative research projects, we recognize revenue by defining milestones at the inception of the agreement and applying the milestone method of revenue recognition for relevant contracts. 
+Stock-Based Compensation – 
+We recognize the fair value of equity-based awards as compensation expense in our statement of operations. The fair value of our stock option awards was estimated using a Black-Scholes option valuation model. This valuation model's computations incorporate highly subjective assumptions, such as the expected stock price volatility and the estimated life of each award. The fair value of the options, after considering the effect of expected forfeitures, is then amortized, generally on a straight-line basis, over the related vesting period of the option. The fair value of our restricted shares is based on the market value of the shares at the date of grant and is recognized on a straight-line basis over the related vesting period of the award. 
+Research & Development Costs – 
+Research and development activities consist primarily of new product development, continuing engineering for existing products, regulatory and clinical trial costs. Costs related to research and development efforts on existing or potential products are expensed as incurred. 
+Valuation of Inventories – 
+Inventories are stated at the lower of cost or market, using the first-in, first-out method (FIFO) to determine cost. Our policy is to periodically evaluate the market value of the inventory and the stage of product life cycle, and record a reserve for any inventory considered slow moving or obsolete. For example, each additional 1% of obsolete inventory would reduce such inventory by approximately $36,000. 
+Allowance for doubtful accounts – 
+Our policy is to review our accounts receivable on a periodic basis, no less than monthly. On a quarterly basis an analysis is made of the adequacy of our allowance for doubtful accounts and adjustments are made accordingly. The current allowance is approximately 1% of accounts receivable. For example each additional 1% of accounts receivable that becomes uncollectible would reduce such balance of accounts receivable by approximately $83,000. 
+Income Taxes – 
+Income taxes are accounted for under ASC 740 authoritative guidance ("Guidance") which requires the asset and liability method of accounting for deferred income taxes. Deferred tax assets and liabilities are determined based on the difference between the financial statement and tax bases of assets and liabilities. Deferred tax assets or liabilities at the end of each period are determined using the tax rate expected to be in effect when taxes are actually paid or recovered. 
+The Guidance also requires that a valuation allowance be established when it is more likely than not that all or a portion of a deferred tax asset will not be realized. A review of all available positive and negative evidence needs to be considered, including a company's current and past performance, the market environment in which the company operates, length of carryback and carryforward periods and existing contracts that will result in future profits. Prior to 2011 and through September 30, 2011, the Company had a full valuation allowance recorded against deferred tax assets since it was not more likely than not that the Company would realize the benefits of such deferred tax assets. During 2011, the Company determined based upon the guidance under ASC 740 that it was more likely than not that it would realize the benefit of such deferred tax assets. As result, the Company reversed the valuation allowance previously recorded against the deferred tax assets. The Company still maintains a full valuation allowance on research and development tax credits 
+The Guidance also prescribes a comprehensive model for recognizing, measuring, presenting and disclosing in the consolidated financial statements tax positions taken or expected to be taken on a tax return, including a decision whether to file or not to file in a particular jurisdiction. 
+The above listing is not intended to be a comprehensive list of all of our accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by accounting principles, generally accepted in the United States of America, with no need for management's judgment in their application. There are also areas in which management's judgment in selecting any viable alternative would not produce a materially different result. See our audited financial statements and notes thereto which contain accounting policies and other disclosures required by accounting principles generally accepted in the United States of America. 
+30 
+ITEM 8. 
+FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+The Consolidated Financial Statements and schedules that constitute Item 8 are attached at the end of this Annual Report on Form 10-K. An index to these Financial Statements and schedules is also included on page F-1 of this Annual Report on Form 10-K. 
+ITEM 9. 
+CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. 
+Not Applicable. 
+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+(a) Disclosure Controls and Procedures. Under the supervision and with the participation of our senior management, consisting of our chief executive officer and our chief financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), as of the end of the period covered by this report (the "Evaluation Date"). Based on that evaluation, the Company's management, including our chief executive officer and chief financial officer, concluded that as of the Evaluation Date our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports that we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. Our disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in our Exchange Act reports is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure. 
+Management's Annual Report on Internal Control Over Financial Reporting. The Company's management is responsible for establishing and maintaining an adequate system of internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f)). Our internal control over financial reporting is a process, under the supervision of our chief executive officer and chief financial officer, designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States. These internal controls over financial reporting processes include policies and procedures that: 
+a. 
+Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company; 
+b. 
+Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and 
+c. 
+Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance of achieving their control objectives. 
+In evaluating the effectiveness of our internal control over financial reporting, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Based on this evaluation, our Chief Executive and Chief Financial Officers concluded that our internal control over financial reporting was effective as of December 31, 2014. 
+This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. 
+Management's report was not subject to attestation by our registered public accounting firm pursuant to the rules of the Securities and Exchange Commission that permit the Company to provide only management's report in this annual report. 
+(b) Changes in Internal Control over Financial Reporting. There were no changes in our internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Rule 13a-15 or Rule 15d-15 under the Exchange Act that occurred during the Company's last fiscal quarter of the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+ITEM 9B. 
+OTHER INFORMATION 
+Not applicable. 
+31 
+PART III 
+ITEM 10. 
+DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
+Directors and Executive Officers 
+John J. Sperzel (51), President, Chief Executive Officer and Director. Mr. Sperzel was appointed Chief Executive Officer and President of Chembio Diagnostics, Inc. and a member of our Board in March 2014. Prior to joining the Company, Mr. Sperzel, was the President and CEO of International Technidyne Corporation (ITC) from September 2011 to December 2013. Mr. Sperzel served as President at Axis-Shield from September 2004 to September 2011. He also has held senior leadership positions at Bayer Diagnostics (Siemens Dx), Instrumentation Laboratory, and Boehringer Mannheim Diagnostics (Roche Dx). Mr. Sperzel graduated from Plymouth State College in New Hampshire, with a B.S. in Business Administration/Management. He currently serves as an advisor to the board of the Diagnostic Marketing Association, and was the president of the board of that Association in 2007. Mr. Sperzel's knowledge of, and experience in, the Company's specific business and its industry sector, together with the continuing current knowledge that he is accumulating about the Company in his position as CEO of the Company, made him an excellent candidate for serving on the Board. 
+Richard J. Larkin (58), Chief Financial Officer. Mr. Larkin was appointed as Chief Financial Officer of Chembio Diagnostics, Inc. upon consummation of the merger in 2004. Mr. Larkin oversees our financial activities and information systems. Mr. Larkin has been the Chief Financial Officer of Chembio Diagnostic Systems Inc. since September 2003. Prior to joining Chembio Diagnostic Systems Inc., Mr. Larkin served as CFO at Visual Technology Group ("VTG") from May 2000 to September 2003, and also led VTG's consultancy program that provided hands-on expertise in all aspects of financial service, including the initial assessment of client financial reporting requirements within an Enterprise Resource Planning (Manufacturing) environment through training and implementation. Prior to joining VTG, he served as CFO at Protex International Corporation from May 1987 to January 2000. Mr. Larkin holds a BBA in Accounting from Dowling College and is a member of the American Institute of Certified Public Accountants. 
+Javan Esfandiari (48), Chief Science and Technology Officer. Mr. Esfandiari joined Chembio Diagnostic Systems, Inc, in 2000. Mr. Esfandiari co-founded, and became a co-owner of Sinovus Biotech AB where he served as Director of Research and Development concerning lateral flow technology until Chembio Diagnostic Systems Inc. acquired Sinovus Biotech AB in 2000. From 1993 to 1997, Mr. Esfandiari was Director of Research and Development with On-Site Biotech/National Veterinary Institute, Uppsala, Sweden, which was working in collaboration with Sinovus Biotech AB on development of veterinary lateral flow technology. Mr. Esfandiari received his B.Sc. in Clinical Chemistry and his M. Sc. in Molecular Biology from Lund University, Sweden. He has published articles in various veterinary journals and has co-authored articles on tuberculosis serology with Dr. Lyashchenko. 
+Sharon Klugewicz (47), Chief Operating Officer. Prior to joining the Company in September 2012, Ms. Klugewicz, served as Senior Vice President, Scientific & Laboratory Services at Pall Corporation (NYSE:PLL), a world leader in filtration, separation and purification technologies. Prior to that, Ms. Klugewicz held a number of positions at Pall Corporation over her 20-year tenure there, including in the Pall Life Sciences Division, in Marketing Product Management, and Field Technical Services, which included a position as Senior Vice President, Global Quality Operations. Ms. Klugewicz holds an M.S. in Biochemistry from Adelphi University and a B.S. in Neurobiology from Stony Brook University. 
+Dr. Gary Meller M.D. (64), Director. Dr. Meller was elected to our Board of Directors on March 15, 2005, and currently serves on the Board's Audit, and Nominating And Corporate Governance Committees, including as Chairman of the Audit Committee. Dr. Meller has been the president of CommSense Inc., a healthcare business development company, since 2001. CommSense Inc. works with clients in Europe, Asia, North America, and the Middle East on medical information technology, medical records, pharmaceutical product development and financing, health services operations and strategy, and new product and new market development. From 1999 until 2001 Dr. Meller was the executive vice president, North America, of NextEd Ltd., a leading internet educational services company in the Asia Pacific region. Dr. Meller also was a limited partner and a member of the Advisory Board of Crestview Capital Master LLC, which was our largest shareholder. Dr. Meller is a graduate of the University of New Mexico School of Medicine and has an MBA from the Harvard Business School. Dr. Meller's experience in the medical field both domestic and foreign (especially his experience with CommSense Inc.) as well as his financing experience make him an excellent candidate for serving on the board. 
+Kathy Davis (58), Director and Chair of the Board. Ms. Davis was elected to the Board in May 2007, and was elected in March 2014 to serve as Chair of the Board. She currently serves on the Board's Audit, Compensation, and Nominating And Corporate Governance Committees, including as Chair of the Nominating And Corporate Governance Committee. In 2014, Ms. Davis also served on the Board's CEO Search Committee, and in 2013 she served on the Board's Special Committee for handling certain strategic opportunities. Since January 2007, Ms. Davis has been the owner of Davis Design Group LLC, a company that provides analytical and visual tools for public policy design. Previously, from February 2005 to December 2006, she served as the Chief Executive Officer of Global Access Point, a start-up company with products for data transport, data processing, and data storage network and hub facilities. From October 2003 to January 2005, Ms. Davis was Lieutenant Governor of the State of Indiana, and from January 2000 to October 2003 was Controller of the City of Indianapolis. From 1989 to 2003, Ms. Davis held leadership positions with agencies and programs in the State of Indiana including State Budget Director, Secretary of Family & Social Services Administration, and Deputy Commissioner of Transportation. From 1982 to 1989 Ms. Davis held increasingly senior positions with Cummins Engine, where she managed purchasing, manufacturing, engineering, and assembly of certain engine product lines. Ms. Davis also led the startup of and initial investments by a $50 million Indiana state technology fund, serves on the not-for-profit boards of Noble of Indiana,
+Lumina Foundation for Education, Indianapolis Foundation, Central Indiana Community Foundation, Western Governor's University Indiana, and Indiana University School of Public and Environmental Affairs. She holds a Bachelor of Science in Mechanical Engineering from the Massachusetts Institute of Technology and an MBA from Harvard Business School. Ms. Davis has varied experience in business, political and financial areas that made her an excellent candidate for serving on the Board. 
+Dr. Barbara DeBuono M.D., M.P.H., (59), Director . Dr. DeBuono, who was elected to the Company's Board of Directors in June 2011, currently serves on the Board's Compensation and Nominating And Corporate Governance Committees, including as Chair of the Compensation Committee. Ms. DeBuono is a renowned expert in public health innovation, health policy, education and research. She currently serves as a consultant to both public and private entities involved in healthcare, healthcare policy and healthcare products. From May 2011 to January 31,2012., Dr. DeBuono served as President and CEO of ORBIS International, which is dedicated to saving sight and eliminating avoidable blindness worldwide with headquarters in New York City. Previously, from 2009-2011, Dr. DeBuono was Chief Medical Officer, Partner and Global Director of Health and Social Marketing at Porter Novelli, and from 2000-2008 she was Executive Director, Public Health and Government at Pfizer Inc. Dr. DeBuono has served as Commissioner of Health for the state of New York and as Director of Health in Rhode Island and she was honored by the CDC Foundation in 2005 as one of five Public Health Heroes nationwide. She serves as adjunct professor at The George Washington University School of Public Health, and is a co-founder of The MAIA Foundation, a charity dedicated to women's health in sub-Saharan Africa. A Fellow of the American College of Physicians, Dr. DeBuono received her B.A. from the University of Rochester, her M.D. from the University of Rochester School of Medicine, and a Masters in Public Health (M.P.H.) from Harvard University School of Public Health. Dr. DeBuono's experience in and knowledge of, both domestic and international, public health services, public health innovations, and the medical field make her an excellent candidate for serving on the board. 
+32 
+Dr. Peter Kissinger, Ph.D. (70), Director. Dr. Kissinger, who was elected to the Company's Board of Directors in June 2011 , currently serves on the Company's Audit, and Compensation Committees. Dr. Kissinger is a scientist, entrepreneur and academic, with a multi-faceted career in biotechnology and biomedical technologies. He is the founder of Bioanalytical Systems, Inc. (NASDAQ: BASI), which he led from 1974-2007, and is Professor of Chemistry at Purdue University, West Lafayette, Indiana. Dr. Kissinger's academic research has involved the study of modern liquid chromatography techniques, and in vivo methodology for drug metabolism and the neurosciences. Dr. Kissinger has published more than 240 scientific papers and is a Fellow of the American Association of Pharmaceutical Scientists and the American Association for the Advancement of Science. In 2005, he became the Chairman of Prosolia, which markets mass spectrometry innovations for life science, industrial and homeland security applications. In 2007, he and Candice Kissinger founded Phlebotics, Inc., a medical device company focused on diagnostic information for intensive care medicine. He is a columnist for the trade publication Drug Discovery News. Dr. Kissinger received a B.S. in Chemistry from Union College, Schenectady, N.Y. and a Ph.D. in Analytical Chemistry from the University of North Carolina in Chapel Hill. Dr. Kissinger has knowledge of and experience in biotechnology and biomedical technologies as well as publicly-traded companies, all of which make him an excellent candidate for serving on the board. 
+Section 16(a) Beneficial Ownership Reporting Compliances 
+Section 16(a) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), requires the Company's directors, executive officers and beneficial owners of more than 10% of the Company's common stock to file with the Securities and Exchange Commission initial reports of ownership and reports of changes in ownership of common stock and other equity securities of the Company. The Company believes that during the year ended December 31, 2014, each person who was an officer, director and beneficial owner of more than 10% of the Company's common stock complied with all Section 16(a) filing requirements . 
+Code of Ethics 
+The Company has adopted a code of ethics that applies to its principal executive officer, principal financial officer, principal accounting officer, controller, and persons performing similar functions. A copy of the Company's code of ethics is available on the Company's website at www.chembio.com. 
+Identification of Audit Committee; Audit Committee Financial Expert 
+The Company's board of directors has established an audit committee. Katherine L. Davis, Dr. Pete Kissinger and Dr. Gary Meller each serves on the audit committee, with Dr. Meller serving as chairman. The Company's board of directors has determined that Dr. Meller is an audit committee financial expert and is independent. 
+33 
+ITEM 11. 
+EXECUTIVE COMPENSATION 
+The following table summarizes all compensation recorded by the Company in each of the last two completed fiscal years for our principal executive officer and our two most highly compensated executive officers other than our principal executive officer whose annual compensation exceeded $100,000. 
+Name / 
+Salary 1 
+Bonus 2 
+Stock 
+Option Awards 3 
+All Other Compensation 6 
+Total 
+Principal 
+($) 
+($) 
+Awards 
+($) 
+($) 
+($) 
+Position 
+Year 
+($) 
+John J. Sperzel 4 
+2014 
+$ 
+298,558 
+$ 
+- 
+$ 
+- 
+$ 
+669,625 
+$ 
+- 
+$ 
+968,183 
+CEO 
+2013 
+n/a 
+n/a 
+n/a 
+n/a 
+n/a 
+n/a 
+Lawrence A. Siebert 5, 7 
+2014 
+$ 
+84,703 
+$ 
+87,000 
+$ 
+- 
+$ 
+- 
+$ 
+147,462 
+$ 
+319,165 
+CEO 
+2013 
+$ 
+290,000 
+$ 
+50,750 
+$ 
+- 
+$ 
+21,610 
+$ 
+10,240 
+$ 
+372,600 
+Javan Esfandiari 
+2014 
+$ 
+315,000 
+$ 
+90,000 
+$ 
+- 
+$ 
+- 
+$ 
+9,825 
+$ 
+414,825 
+CSTO 
+2013 
+$ 
+292,462 
+$ 
+44,625 
+$ 
+- 
+$ 
+141,078 
+$ 
+8,697 
+$ 
+486,862 
+Sharon Klugewicz 
+2014 
+$ 
+259,616 
+$ 
+75,000 
+$ 
+- 
+$ 
+- 
+$ 
+4,182 
+$ 
+338,798 
+COO 
+2013 
+$ 
+233,642 
+$ 
+5,950 
+$ 
+- 
+$ 
+18,551 
+$ 
+3,542 
+$ 
+261,685 
+1 Salary is total base salary. John Sperzel's salary reflects his base pay from commencement of his employment on March 13, 2014 until the end of 2014. 
+2 Bonuses earned in 2014 were partially based on reaching certain objectives, which included revenue dollar levels and operating profit levels. Additional amounts earned were discretionary. 
+3 The estimated fair value of any option or common stock granted was determined in accordance with ASC 718, "Stock-Based Payment". 
+4 Mr. Sperzel also serves as a director on the Company's board of directors. Mr. Sperzel does not receive any compensation for this director role. 
+5 Mr. Siebert also served as a director on the Company's board of directors until March 13, 2014. Mr. Siebert did not receive any compensation for this director role. 
+6 Other compensation includes an employer match to 401(K) contributions and car allowances where applicable. 
+7 Mr. Siebert served as Chief Ececutive Officer of the Company until March 13, 2014, for which he received a salary at the annual rate of $290,000. From March 13, 2014 to September 13, 2014, Mr. Siebert was a consultant to the Company pursuant to a six-month agreement for which he received total compensation of $145,000. These consulting fees are included in the table under "All Other Compensation". 
+Mr. Sperzel. Effective March 13, 2014 (the "Effective Date"), the Company entered into an Employment Agreement with John J. Sperzel III to serve as the Company's CEO for a term of three years. Mr. Sperzel's annual base salary is $375,000, with the possibility of a discretionary, performance-based annual cash bonus of up to 40% of his base salary. The Employment Agreement also provides for a grant of 250,000 options to purchase shares of the Company's common stock, 43,132 of which will be incentive stock options under the Company's 2008 Stock Incentive Plan (the "Plan"), and 206,868 of which will be non-qualified stock options. The options will become exercisable at the rate of 50,000 shares per year for each of the first through the fifth anniversary of the Effective Date. In the event Mr. Sperzel's employment is terminated by reason of disability or for "cause," as defined in the Employment Agreement, all compensation, including his base salary, his right to receive a performance bonus, and the vesting of any unvested options, will cease as of his termination date, and Mr. Sperzel will receive no severance benefits. If the Company terminates Mr. Sperzel's employment without cause or Mr. Sperzel terminates his employment for a reasonable basis, as defined in the Employment Agreement (which includes involuntary termination within a six-month period upon a "Change of Control"), then the Company will pay Mr. Sperzel his base salary for a period of six months as severance and all of his unvested stock options immediately shall become vested. The Employment Agreement also contains provisions prohibiting Mr. Sperzel from (i) soliciting the Company's employees for a period of 24 months following his termination, (ii) soliciting the Company's customers, agents, or other sources of distribution of the Company's business for a period of twelve months following his termination, and (iii) except where termination is involuntary upon a "Change in Control," engaging or participating in any business that directly competes with the business activities of the Company in any market in which the Company is in business or plans to do business during the period in which he is entitled to severance, or for a period of six months if he is not entitled to severance payments under the Employment Agreement. The foregoing description of the Employment Agreement is qualified in its entirety by reference to the full text of the Employment Agreement. 
+Mr. Esfandiari. The Company entered into an employment agreement effective March 5, 2013 (the "Employment Agreement"), with Mr. Esfandiari to continue as the Company's Senior Vice President of Research and Development for an additional term of three years through March 5, 2016. Mr. Esfandiari's salary under the Employment Agreement is $300,000 for the first year, with possible increases for the second year and /or for the third year. Mr. Esfandiari is eligible for a performance-based bonus of up to 50% of his base salary for each respective year, which is in the same proportions as described below under "Executive Bonus Plan". The Company also granted Mr. Esfandiari, pursuant to the Company's 2008 Stock Incentive Plan, incentive stock options to purchase 30,000 shares of the Company's common stock. The price per share of these options is equal to the fair market value of the Company's common stock as of the close of the market on March 5, 2013, which is the date on which the Agreement was effective. Of these stock options, options to purchase 10,000 shares vest on each of the first three anniversaries of the effective date of the Employment Agreement. Mr. Esfandiari is eligible to participate in any profit sharing, stock option, retirement plan, medical and/or hospitalization plan, and/or other benefit plans except for disability and life insurance that the Company may from time to time place in effect for the Company's executives during the term of Mr. Esfandiari's employment agreement. If Mr. Esfandiari's employment agreement is terminated by the Company without cause, or if Mr. Esfandiari terminates his employment agreement for a reasonable basis, as defined in the Employment Agreement, including within 12 months of a change in control, the Company is required to pay as severance Mr. Esfandiari's salary for twelve months. 
+Ms. Klugewicz. The Company entered into an employment agreement dated May 22, 2013 with Ms. Klugewicz (the "Employment Agreement"), effective May 22, 2013 (the "Effective Date"). The Agreement provides that she will serve as the Company's COO for a term of two years. Ms. Klugewicz will receive an annual salary of $250,000, with the option of a discretionary, performance-based annual cash bonus of up to 37.5% of her base salary. The Employment Agreement also provides for a grant of 5,000 options to purchase shares of the Company's common stock, vesting at a rate of 2,500 shares on each of the first and second anniversaries of the Effective Date. In the event Ms. Klugewicz's employment is terminated by reason of disability or for "cause", as defined in the Employment Agreement, all compensation including her base salary, her right to receive a performance bonus, and the vesting of any unvested options, will cease as of her termination date, and Ms. Klugewicz will receive no severance benefits. If the Company terminates Ms. Klugewicz's employment without cause or Ms. Klugewicz terminates her employment for a reasonable basis, as defined in the Employment Agreement (which definition includes involuntary termination within a six-month period upon a "Change of Control"), then the Company will pay Ms. Klugewicz her base salary for a period of six months as severance, and all her unvested stock options shall immediately become vested. The Employment Agreement also contains provisions prohibiting Ms. Klugewicz from (i) soliciting the Company's employees for a period of twenty-four months following her termination, (ii) soliciting the Company's customers, agents, or other sources of distribution of the Company's business for a period of twelve months following her termination, and (iii) for a period of twelve months following termination of this Agreement, except where termination is involuntary upon a "Change in Control," engaging or participating in any business that directly competes with the business activities of the Company in any market in which the Company is in business or plans to do business. The foregoing description of the Employment Agreement is qualified in its entirety by reference to the full text of the Employment Agreement. 
+Neither Mr. Larkin, Mr. Ippolito, Mr. Lambotte nor Mr. Steele has an employment contract with the Company. 
+Executive Bonus Plan 
+The Company has established a bonus plan for its executives who do not have a contract. For the fiscal year ended December 31, 2014, there were three executives eligible for this bonus plan. Each executive can earn up to 25% of that executive's salary in the form of a cash bonus. The Compensation Committee determined that 80% of the executive's bonus will be quantitative factors, based on the budget, and the other 20%, which will be based on other factors, will be discretionary. For 2014, the quantitative 80% portion of the plan called for attaining certain revenue goals, and for attaining certain operating profit goals. 
+34 
+OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END 2014 
+Option Awards 
+Stock Awards 
+Name 
+Number of Securities Underlying Unexercised Options Exercisable (#) 
+Number of Securities Underlying Unexercised Options Unexercisable 
+(#) 
+Option Exercise Price 
+($) 
+Option Expiration Date 
+Option Vesting Date 
+Number of Shares of Stock That Have Not Vested 
+(#) 
+Market Value of Shares of Stock That Have Not Vested 
+($) 
+Foot- 
+note 
+John J. Sperzel 
+25,000 
+3.4163 
+3/21/2021 
+3/13/2015 
+5 
+25,000 
+3.4163 
+3/21/2021 
+3/13/2015 
+2 
+18,132 
+3.4163 
+3/21/2021 
+3/13/2016 
+5 
+31,868 
+3.4163 
+3/21/2021 
+3/13/2016 
+2 
+50,000 
+3.4163 
+3/21/2021 
+3/13/2017 
+2 
+50,000 
+3.4163 
+3/21/2021 
+3/13/2018 
+2 
+50,000 
+3.4163 
+3/21/2021 
+3/13/2019 
+2 
+Javan Esfandiari 
+10,000 
+5.44 
+3/5/2018 
+3/5/2014 
+1 
+10,000 
+5.44 
+3/5/2018 
+3/5/2015 
+1 
+10,000 
+5.44 
+3/5/2018 
+3/5/2016 
+1 
+4,765 
+5.56 
+2/26/2018 
+2/26/2013 
+4 
+7,969 
+4.00 
+2/16/2017 
+2/16/2012 
+3 
+12,500 
+2.16 
+3/4/2015 
+3/5/2013 
+1 
+12,500 
+2.16 
+3/4/2015 
+3/5/2012 
+1 
+12,500 
+2.16 
+3/4/2015 
+3/5/2010 
+1 
+Sharon Klugewicz 
+2,500 
+4.50 
+5/22/2018 
+5/22/2014 
+1 
+2,500 
+4.50 
+5/22/2018 
+5/22/2015 
+1 
+630 
+5.56 
+2/26/2018 
+2/26/2013 
+4 
+12,000 
+4.45 
+9/4/2017 
+9/4/2013 
+5 
+12,000 
+4.45 
+9/4/2017 
+9/4/2014 
+5 
+12,000 
+4.45 
+9/4/2017 
+9/4/2015 
+5 
+1 Options issued in connection with an employment contract and under the 2008 Stock Incentive Plan. 
+2 Options issued in connection with the start of employment with the Company and not under a Plan. 
+3 On February 16, 2012, the Company determined to grant on February 16, 2012, to certain employees of the Company, options to purchase an aggregate of 203,125 shares of the Company's common stock. The exercise price for these options was the last traded market price for the Company's common stock on February 16, 2012, which was $4.00 per share. The options become exercisable on the effective date of the grant. Each option granted will expire and terminate, if not exercised sooner, upon the earlier to occur of (a) 30 days after termination of the employee's employment with the Company or (b) the fifth anniversary of the effective date of grant. 
+4 On February 26, 2013, the Company determined to grant on February 26, 20123 to certain employees of the Company, options to purchase an aggregate of 16,360 shares of the Company's common stock. The exercise price for these options was the last traded market price for the Company's common stock on February 26, 2013, which was $5.56 per share. The options become exercisable on the effective date of the grant. Each option granted will expire and terminate, if not exercised sooner, upon the earlier to occur of (a) 30 days after termination of the employee's employment with the Company or (b) the fifth anniversary of the effective date of grant. 
+5 Options issued in connection with the start of employment with the Company and under the 2008 Stock Incentive Plan. 
+35 
+Director Compensation 
+Effective January 1, 2015, all non-employee directors are paid $25,000 annual fee in semi-annual payments, and once every five years, on the date of the annual meeting of shareholders at which directors are elected or re-elected (every 5 years), receive stock options to acquire, subject to vesting as described below, 46,875 shares of the Company's common stock, with an exercise price equal to the market price on the date of the grant. Stock options to acquire 9,375 shares become exercisable on the date of grant, and options to acquire an additional 9,375 shares become exercisable on the date of each of the four succeeding annual meetings of shareholders if and to the extent that the non-employee director is reelected as a director at each such annual meeting. Begining in April 2014, the non-employee board chair was paid a monthly fee of $6,500, and as of January 1, 2015, this monthly fee was adjusted to $4,167. The audit committee chair is paid an annual fee of $2,500, paid semi-annually. In addition, the non-employee directors are paid $1,000 for each board of directors' meeting attended, and paid $500 for each telephonic board of directors meeting. The non-employee directors who are members of a committee of the board of directors are paid $500 for each committee meeting attended, or $750 for each committee meeting attended if that non-employee director is the committee chair. Directors also may be paid for serving on ad hoc committees of the Board. 
+DIRECTOR COMPENSATION 
+Name 
+Fees Earned or Paid in Cash 
+($) 1 
+Option Awards 
+($) 2 
+Total 
+($) 
+Katherine L. Davis 
+$ 
+105,750 
+$ 
+80,822 
+$ 
+186,752 
+Barbara DeBuono 
+52,000 
+- 
+52,500 
+Pete Kissinger 
+46,500 
+- 
+46,500 
+Gary Meller 
+31,000 
+80,822 
+111,822 
+1 Fees earned or paid in cash represents a yearly fee and fees for meeting expenses: (a) Ms. Davis received an $18,000 annual fee as a member of the board of directors, a $6,500 monthly fee as chair since April 2014 aggregating $58,500, $18,000 in fees as a member of the CEO Search Committee and $11,250 in meeting fees earned during 2014; (b) Dr. DeBuono received an $18,000 annual fee as a member of the board of directors, $24,000 in fees as chairperson of the CEO Search Committee and 10,000 in meeting fees; (c) Dr. Kissinger received an $18,000 annual fee as a member of the board of directors, $18,000 in fees as a member of the CEO Search Committee and $10,500 in meeting fees; (d) Dr. Meller received an $18,000 annual fee as a member of the board of directors, $2,500 in fees as chairperson of the Audit Committee and $10,500 in meeting fees. 
+2 Each non-employee member of the board of directors is granted, once every five years, the right to purchase 46,875 shares of the company's common stock with an exercise price equal to the market price on the date of the grant as part of annual non-employee board compensation. One-fifth of these options are exercisable on the date of grant, one-fifth become exercisable on the first anniversary of the date of grant, and additional one-fifths become exercisable on the second through fourth anniversaries of the date of grant. The fair value of options at the date of grant was estimated using the Black-Scholes option pricing model. 
+Compensation Committee Interlocks and Insider Participation 
+No executive officer of the Company served as a member of the Board of any other public company during the year ended December 31, 2014. No member of the Compensation Committee served as an executive officer of any other public company during the year ended December 31, 2014. No interlocking relationship exists between the members of our Compensation Committee and the Board or compensation committee of any other company. As of March 1, 2015, the members of the Compensation Committee were Dr. Barbara DeBuono (Chairman), Katherine Davis, and Dr. Peter Kissinger, each of whom is deemed by the Board of Directors to be independent. 
+36 
+ITEM 12. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+The following table sets forth certain information regarding the beneficial ownership of our common stock by each person or entity known by us to be the beneficial owner of more than 5% of the outstanding shares of common stock, each of our directors, each of our "named executive officers", and all of our directors and executive officers as a group as of March 1, 2015. 
+Name and Address of 
+Beneficial Owner 
+Amount and Nature 
+of Beneficial 
+Ownership 
+Percent of Class 
+John J. Sperzel (1) 
+3661 Horseblock Road 
+Medford, NY 11763 
+50,000 
+0.52% 
+Esfandiari, Javan (2) 
+3661 Horseblock Road 
+Medford, NY 11763 
+144,844 
+1.50% 
+Larkin, Richard (3) 
+3661 Horseblock Road 
+Medford, NY 11763 
+66,514 
+.69% 
+Ippolito, Tom (4) 
+3661 Horseblock Road 
+Medford, NY 11763 
+38,916 
+.40% 
+Steele, Michael (5) 
+3661 Horseblock Road 
+Medford, NY 11763 
+24,785 
+.26% 
+Klugewicz, Sharon (6) 
+3661 Horseblock Road 
+Medford, NY 11763 
+37,130 
+.38% 
+Meller, Gary (7) 
+3661 Horseblock Road 
+Medford, NY 11763 
+114,375 
+1.19% 
+Davis, Katherine L. (8) 
+3661 Horseblock Road 
+Medford, NY 11763 
+67,671 
+.70% 
+DeBuono, Barbara (9) 
+3661 Horseblock Road 
+Medford, NY 11763 
+39,454 
+.41% 
+Kissinger, Peter (10) 
+3661 Horseblock Road 
+Medford, NY 11763 
+41,254 
+.43% 
+GROUP (11) 
+623,143 
+6.29% 
+Wellington Management Company, LLP 
+280 Congress Street 
+Boston, MA 02210 
+1,050,280 
+10.91% 
+Norman H. Pessin 
+366 Madison Ave, 14 th Floor 
+New York, NY 10017 
+616,476 
+6.40% 
+37 
+Beneficial ownership is determined in accordance with the Rule 13d-3(a) of the Securities Exchange Act of 1934, as amended, and generally includes voting or investment power with respect to securities. Except as subject to community property laws, where applicable, the person named above has sole voting and investment power with respect to all shares of our common stock shown as beneficially owned by that person. 
+The beneficial ownership percent in the table is calculated with respect to the number of shares (9,627,248) of the Company's common stock outstanding as of March 1, 2015; and with respect to each stockholder, the denominator is the sum of the number of common shares outstanding and the number, if any, of outstanding options included in that stockholder's beneficial ownership. Each stockholder's beneficial ownership is calculated as the number of shares of common stock owned plus the number of shares of common stock into which any preferred stock, warrants, options or other convertible securities owned by that stockholder can be converted within 60 days. 
+The term "named executive officer" refers to our principal executive officer, our two most highly compensated executive officers other than the principal executive officer who were serving as executive officers at the end of 2014, and two additional individuals for whom disclosure would have been provided but for the fact that the individuals were not serving as executive officers of the Company at the end of 2014. 
+(1) 
+Includes 50,000 shares issuable upon exercise of options exercisable within 60 days. Does not include 200,000 shares issuable upon exercise of options that are not exercisable within the next 60 days. 
+(2) 
+Includes 32,734 shares issuable upon exercise of options exercisable within 60 days. Does not include 10,000 shares issuable upon exercise of options that are not exercisable within the next 60 days. 
+(3) 
+Includes 23,217 shares issuable upon exercise of options exercisable within 60 days. 
+(4) 
+Includes 20,399 shares issuable upon exercise of options exercisable within 60 days. 
+(5) 
+Includes 24,785 shares issuable upon exercise of options exercisable within 60 days. Does not include 12,000 shares issuable upon exercise of options that are not exercisable within the next 60 days. 
+(6) 
+Includes 27,130 shares issuable upon exercise of options exercisable within 60 days. Does not include 14,500 shares issuable upon exercise of options that are not exercisable within the next 60 days. 
+(7) 
+Includes 9,375 shares issuable upon exercise of options exercisable within 60 days. Does not include 37,500 shares issuable upon exercise of options that are not exercisable within the next 60 days. 
+(8) 
+Includes 9,375 shares issuable upon exercise of options exercisable within 60 days. Does not include 37,500 shares issuable upon exercise of options that are not exercisable within the next 60 days. 
+(9) 
+Includes 39,454 shares issuable upon exercise of options exercisable within 60 days. Does not include 9,375 shares issuable upon exercise of options that are not exercisable within the next 60 days. 
+(10) 
+Includes 39,454 shares issuable upon exercise of options exercisable within 60 days. Does not include 9,375 shares issuable upon exercise of options that are not exercisable within the next 60 days. 
+(11) 
+Includes footnotes (1)-(10). 
+38 
+Equity Compensation Plan Information 
+Combined Equity Compensation Plans - Information as of December 31, 2014 
+Plan Category 
+Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights 
+Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights 
+Number of Securities Remaining Available for Future Issuance under Equity Compensation Plans (Excluding Securities Reflected in Column (a) 
+(a) 
+(b) 
+(c) 
+Equity compensation plans approved by security holders 1 
+691,869 
+$ 
+3.66 
+728,173 
+Equity compensation plans not approved by security holders 
+- 
+- 
+- 
+Total 
+691,869 
+$ 
+3.66 
+728,173 
+1 The "Number of Securities to be Issued Upon Exercise of Outstanding Warrants and Rights" represents 355,251 from the 2008 Stock Incentive Plan, 129,750 under the 2014 Stock Incentive Plan and 206,868 issued outside of the Plans. The 2008 Stock Incentive Plan was increased by 125,000 units at the Annual Stockholder meeting held September 23, 2011. The "Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans" represents 57,923 from the 2008 Stock Incentive Plan and 670,250 under the 2014 Stock Incentive Plan. 
+39 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE. 
+The executive officers of the Company are as follows: John J. Sperzel, president, chief executive officer and member of the board of directors of the Company, Sharon Klugewicz, chief operating officer, Richard J. Larkin, chief financial officer of the Company, and Javan Esfandiari, Chief Science and Technology Officer of the Company. 
+On February 25, 2013, the Company granted options to purchase the following numbers of shares of the Company's common stock set forth below to the executive officers of the Company named below. The exercise price for these options was the last traded market price for the Company's common stock on February 26, 2013, which was $5.56 per option. The options become exercisable on the effective date of the grant. Each option granted will expire and terminate, if not exercised sooner, upon the earlier to occur of (a) 30 days after termination of the employee's employment with the Company or (b) the fifth anniversary of the effective date of grant. 
+Name of Executive Officer 
+Number of Shares of Common Stock Options 
+Richard Bruce - Vice President of Operations 
+1,520 
+Javan Esfandiari – Executive Vice President of R&D 
+4,765 
+Tom Ippolito - Vice President of Regulatory Affairs, QA & QC 
+1,775 
+Richard J. Larkin – Chief Financial Officer 
+1,670 
+Lawrence A. Siebert – Chief Executive Officer 
+5,215 
+Michael Steele – Vice President of Sales and Marketing 
+785 
+Sharon Klugewicz – Vice President of QA/QC 
+630 
+The Company entered into an employment agreement effective March 5, 2013, with Mr. Esfandiari to continue as the Company's Senior Vice President of Research and Development for an additional term of three years through March 5, 2016. The Company also entered into an employment agreement effective May 22, 2013, with Ms. Klugewicz to serve as Chief Operating Officer for a term of two years. On March 13, 2014, Mr. Siebert, the former Chief Executive Officer, retired from the Company and entered into a six-month Consulting Agreement with the Company. On March 13, 2014, the Company entered into an employment agreement (the "Employment Agreement") with John J. Sperzel III to serve as its Chief Executive Officer beginning on March 13, 2014. See Item 11 for additional information. 
+Director Independence 
+Our common stock trades on the NASDAQ. Accordingly, we are subject to the corporate the governance standards of NASDAQ, which require, among other things, that the majority of the board of directors be independent. We define an "independent" director in accordance with the NASDAQ Global Market's requirements for independent directors. Under this definition, we have determined that each of Katherine Davis, Barbara DeBuono, Peter Kissinger, and Gary Meller currently qualify as independent directors. We do not list this "independent" definition on our internet website. 
+40 
+ITEM 14. 
+PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+Audit Fees 
+For the years ended December 31, 2014 and 2013 the Company engaged BDO USA, LLP as its independent accounting firm to perform an audit of the Company's annual financial statements included on Form 10-K, including reviews of the quarterly financial statements and assistance with and review of documents filed with the SEC, for $128,000 and $159,950 respectively in fees. 
+Audit-Related Fees 
+For the years ended December 31, 2014 and 2013, the Company's independent accounting firm, BDO USA, LLP, did not provide the Company with any assurance and related services reasonably related to the performance of the audit or review of the Company's financial statements that are not reported above under "Audit Fees." 
+Tax Fees 
+For the years ended December 31, 2014 and 2013, the Company's independent accounting firm, BDO USA, LLP, billed the Company $18,350 and $17,500, respectively for professional services for tax compliance, tax advice and tax planning. 
+All Other Fees 
+For the years ended December 31, 2014 and 2013, the Company's independent accounting firm, BDO USA, LLP, did not provide the Company with any services for other matters. 
+Audit Committee Pre-Approval Policies 
+The Audit Committee approves in advance all audit and non-audit services performed by the independent accounting firm. There are no other specific policies or procedures relating to the pre-approval of services performed by the independent accounting firm. 
+41 
+ITEM 15. 
+EXHIBITS INDEX 
+Number 
+Description 
+3.1 
+Articles of Incorporation, as amended. (1) 
+3.2 
+Amended and Restated Bylaws. (2) 
+4.1 
+Form of Employee Option Agreement, for 1999 Plan. (3) 
+4.2 
+1999 Equity Incentive Plan, as amended. (4) 
+4.3 
+2008 Stock Incentive Plan, as amended. (4) 
+4.4 
+Form of Option, for 2008 Stock Incentive Plan (5) 
+4.5 
+2014 Stock Incentive Plan (6) 
+4.6 
+Form of Option, for 2014 Stock Incentive Plan (7) 
+4.7 
+Rights Agreement, dated March 8, 2010 (8) 
+4.8 
+Form of Warrant (to be filed by amendment) 
+10.1* 
+Employment Agreement dated March 13, 2014 with John J. Sperzel III (5) 
+10.2* 
+Employment Agreement dated March 5, 2013 with Javan Esfandiari (9). 
+10.3* 
+Employment Agreement dated May 22, 2013 with Sharon Klugewicz (10) 
+10.3 
+HIV Barrel License, Marketing and Distribution Agreement, dated as of September 29, 2006, by and among the Registrant, Alere and StatSure. (11) 
+10.4 
+HIV Cassette License, Marketing and Distribution Agreement, dated as of September 29, 2006, between the Registrant and Alere. (11) 
+10.5 
+Non-Exclusive License, Marketing and Distribution Agreement, dated as of September 29, 2006, between the Registrant and Alere. (11) 
+10.6 
+Joint HIV Barrel Product Commercialization Agreement, dated as of September 29, 2006, between the Registrant and StatSure. (11) 
+10.8 
+Secured Revolving Demand Note, dated as of April 30, 2013, by and among the Registrant, Chembio Diagnostics Systems, Inc. and HSBC Bank, NA (10) 
+10.9 
+Loan and Security Agreement, dated as of April 30, 2013, by and among the Registrant, Chembio Diagnostics Systems, Inc. and HSBC Bank, NA (10) 
+10.10 
+2015 Omnibus Agreement 
+14.1 
+Ethics Policy (12) 
+21 
+List of Subsidiaries 
+23.1 
+Consent of BDO USA, LLP, Independent Registered Public Accountants. 
+31.1 
+Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+31.2 
+Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+32 
+Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 
+101.INS 
+XBRL Instance Document 
+101.SCH 
+XBRL Taxonomy Extension Schema Document 
+101.CAL 
+XBRL Taxonomy Extension Calculation Linkbase Document 
+101.DEF 
+XBRL Taxonomy Definition Linkbase Document 
+101.LAB 
+XBRL Taxonomy Label Linkbase Document 
+101.PRE 
+XBRL Taxonomy Presentation Linkbase Document 
+1 
+Incorporated by reference to the Registrant's annual report on Form 10-KSB filed with the Commission on March 31, 2005. 
+2 
+Incorporated by reference to the Registrant's registration statement on Form SB-2 (File No. 333-85787) filed with the Commission on August 23, 1999 and the Registrant's Forms 8-K filed on May 14, 2004, December 20, 2007 and April 18, 2008. 
+3 
+Incorporated by reference to the Registrant's annual report on Form 10-KSB filed with the Commission on March 12, 2008. 
+4 
+Incorporated by reference to the Registrant's definitive proxy statement on Schedule 14A filed with the Commission on Auguust 3, 2012. 
+5 
+Incorporated by reference to the Registrant's Quarterly Report on Form 10-Q filed with the Commission on May 8, 2014. 
+6 
+Incorporated by reference to the Registrant's definitive proxy statement on Schedule 14A filed with the Commission on April 29, 2014. 
+7 
+Incorporated by reference to the Registrant's Quarterly Report on Form 10-Q filed with the Commission on August 7, 2014. 
+8 
+Incorporated by reference to the Registrant's registration statement on Form 8-A filed with the Commission on March 11, 2010. 
+9 
+Incorporated by reference to the Registrant's Annual Report on Form 10-K filed with the Commission on March 7, 2013. 
+10 
+Incorporated by reference to the Registrant's Quarterly Report on Form 10-Q filed with the Commission on August 8, 2013. 
+11 
+Incorporated by reference to the Registrant's Current Report on Form 8-K filed with the Commission on October 5, 2006. 
+12 
+Incorporated by reference to the Registrant's Annual Report on Form 10-KSB filed with the Commission on March 30, 2006. 
+(*) 
+An asterisk (*) beside an exhibit number indicates the exhibit contains a management contract, compensatory plan or arrangement which is required to be identified in this report. 
+42 
+SIGNATURES 
+In accordance with Section 13 or 15(d) of the Exchange Act, the registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+CHEMBIO DIAGNOSTICS, INC. 
+Date: March 5, 2015 
+By 
+/s/ John J. Sperzel 
+John J. Sperzel 
+President, Chief Executive Officer and 
+Member of the Board 
+In accordance with the requirements of the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+Signatures 
+Title 
+Date 
+/s/ John J. Sperzel 
+Chief Executive Officer, President and 
+March 5, 2015 
+John J. Sperzel 
+Member Of The Board 
+(Principal Executive Officer) 
+/s/ Richard J. Larkin 
+Chief Financial Officer (Principal Financial & 
+March 5, 2015 
+Richard J. Larkin 
+Accounting Officer) 
+/s/ Gary Meller 
+Director 
+March 5, 2015 
+Gary Meller 
+/s/ Katherine L. Davis 
+Director & Chair of the Board 
+March 5, 2015 
+Katherine L. Davis 
+/s/ Peter T. Kissinger 
+Director 
+March 5, 2015 
+Peter T. Kissinger 
+/s/ Barbara DeBuono 
+Director 
+March 5, 2015 
+Barbara DeBuono 
+43 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+Index to Consolidated Financial Statements 
+—INDEX— 
+Page(s) 
+Report of Independent Registered Public Accounting Firm 
+F-1 
+Consolidated Financial Statements: 
+Balance Sheets December 31, 2014 and 2013 
+F-2 
+Statements of Operations for each of the years ended December 31, 2014 and 2013 
+F-3 
+Statements of Changes in Stockholders' Equity for each of the years ended December 31, 2014 and 2013 
+F-4 
+Statements of Cash Flows for each of the years ended December 31, 2014 and 2013 
+F-5 
+Notes to Consolidated Financial Statements 
+F-6 - F-19 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+Board of Directors and Stockholders of 
+Chembio Diagnostics, Inc. 
+Medford, New York 
+We have audited the accompanying consolidated balance sheets of Chembio Diagnostics, Inc. and Subsidiary (the "Company") as of December 31, 2014 and 2013 and the related consolidated statements of operations, changes in stockholders' equity and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. 
+We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. 
+In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Chembio Diagnostics, Inc. and Subsidiary as of December 31, 2014 and 2013, and the consolidated results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. 
+BDO USA, LLP 
+/s/ BDO USA, LLP 
+Melville, New York 
+March 5, 2015 
+F-1 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+CONSOLIDATED BALANCE SHEETS 
+AS OF 
+- ASSETS - 
+December 31, 2014 
+December 31, 2013 
+CURRENT ASSETS: 
+Cash and cash equivalents 
+$ 
+4,614,538 
+$ 
+9,650,275 
+Accounts receivable, net of allowance for doubtful accounts of $52,000 and $24,000 at December 31, 2014 and 2013, respectively 
+8,338,889 
+4,592,121 
+Inventories 
+3,638,299 
+3,188,726 
+Prepaid expenses and other current assets 
+1,066,473 
+1,099,379 
+TOTAL CURRENT ASSETS 
+17,658,199 
+18,530,501 
+FIXED ASSETS , net of accumulated depreciation 
+2,797,929 
+1,978,232 
+OTHER ASSETS: 
+Deferred tax asset, net of valuation allowance 
+4,031,302 
+3,590,207 
+License agreements, net of current portion 
+256,875 
+326,875 
+Deposits on manufacturing equipment 
+20,017 
+16,410 
+Deposits and other assets 
+245,870 
+44,367 
+TOTAL ASSETS 
+$ 
+25,010,192 
+$ 
+24,486,592 
+- LIABILITIES AND STOCKHOLDERS' EQUITY - 
+CURRENT LIABILITIES: 
+Accounts payable and accrued liabilities 
+$ 
+4,946,030 
+$ 
+4,309,490 
+Deferred revenue 
+340,000 
+- 
+TOTAL CURRENT LIABILITIES 
+5,286,030 
+4,309,490 
+TOTAL LIABILITIES 
+5,286,030 
+4,309,490 
+COMMITMENTS AND CONTINGENCIES 
+STOCKHOLDERS' EQUITY: 
+Preferred stock – 10,000,000 shares authorized, none outstanding 
+- 
+- 
+Common stock - $.01 par value; 100,000,000 shares authorized, 9,611,139 and 9,324,783 shares issued and outstanding for 2014 and 2013, respectively 
+96,112 
+93,248 
+Additional paid-in capital 
+47,556,426 
+46,875,027 
+Accumulated deficit 
+(27,928,376 
+) 
+(26,791,173 
+) 
+TOTAL STOCKHOLDERS' EQUITY 
+19,724,162 
+20,177,102 
+TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY 
+$ 
+25,010,192 
+$ 
+$ 24,486,592 
+See accompanying notes to condensed consolidated financial statements 
+F-2 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+CONSOLIDATED STATEMENTS OF OPERATIONS 
+FOR THE YEARS ENDED 
+For the years ended 
+December 31, 2014 
+December 31, 2013 
+REVENUES: 
+Net product sales 
+$ 
+25,949,769 
+$ 
+27,515,786 
+License and royalty revenue 
+23,257 
+4,906 
+R&D, milestone and grant revenue 
+1,672,258 
+2,028,917 
+TOTAL REVENUES 
+27,645,284 
+29,549,609 
+Cost of product sales 
+16,831,261 
+17,249,450 
+GROSS MARGIN 
+10,814,023 
+12,300,159 
+OPERATING EXPENSES: 
+Research and development expenses 
+4,832,537 
+5,834,249 
+Selling, general and administrative expenses 
+7,531,739 
+5,461,083 
+12,364,276 
+11,295,332 
+(LOSS) INCOME FROM OPERATIONS 
+(1,550,253 
+) 
+1,004,827 
+OTHER: 
+Other income 
+(5,707 
+) 
+7,500 
+Interest income 
+5,839 
+5,778 
+Interest expense 
+- 
+(335 
+) 
+132 
+12,943 
+(LOSS) INCOME BEFORE INCOME TAXES (BENEFIT) 
+(1,550,121 
+) 
+1,017,770 
+Income tax (benefit) provision 
+(412,918 
+) 
+486,952 
+NET (LOSS) INCOME 
+$ 
+(1,137,203 
+) 
+$ 
+530,818 
+Basic earnings per share 
+$ 
+(0.12 
+) 
+$ 
+0.06 
+Diluted earnings per share 
+$ 
+(0.12 
+) 
+$ 
+0.06 
+Weighted average number of shares outstanding, basic 
+9,530,320 
+8,994,080 
+Weighted average number of shares outstanding, diluted 
+9,530,320 
+9,519,968 
+See accompanying notes to condensed consolidated financial statements 
+F-3 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY 
+FOR THE YEARS ENDED DECEMBER 31, 2014 AND 2013 
+Common Stock 
+Additional Paid 
+in Capital 
+Accumulated 
+Deficit 
+Total 
+Shares 
+Amount 
+Amount 
+Amount 
+Amount 
+Balance at December 31, 2012 
+8,036,232 
+$ 
+80,362 
+$ 
+41,116,149 
+$ 
+(27,321,991 
+) 
+$ 
+13,874,520 
+Common Stock: 
+New Stock from Offering 
+1,200,000 
+12,000 
+5,396,462 
+- 
+5,408,462 
+Options: 
+Exercised 
+88,551 
+886 
+30,546 
+- 
+31,432 
+Stock option compensation 
+- 
+- 
+331,870 
+- 
+331,870 
+Net income 
+- 
+- 
+- 
+530,818 
+530,818 
+Balance at December 31, 2013 
+9,324,783 
+$ 
+93,248 
+$ 
+46,875,027 
+$ 
+(26,791,173 
+) 
+$ 
+20,177,102 
+Options: 
+Exercised 
+286,356 
+2,864 
+234,299 
+- 
+237,163 
+Stock option compensation 
+- 
+- 
+447,100 
+- 
+447,100 
+Net loss 
+- 
+- 
+- 
+(1,137,203 
+) 
+(1,137,203 
+) 
+Balance at December 31, 2014 
+9,611,139 
+$ 
+96,112 
+$ 
+47,556,426 
+$ 
+(27,928,376 
+) 
+$ 
+19,724,162 
+See accompanying notes to consolidated financial statements 
+F-4 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+FOR THE YEARS ENDED 
+December 31, 2014 
+December 31, 2013 
+CASH FLOWS FROM OPERATING ACTIVITIES: 
+Cash received from customers and grants 
+$ 
+23,898,516 
+$ 
+29,778,845 
+Cash paid to suppliers and employees 
+(27,724,654 
+) 
+(27,506,674 
+) 
+Interest received 
+5,839 
+5,778 
+Interest paid 
+- 
+(335 
+) 
+Net cash (used in) provided by operating activities 
+(3,820,299 
+) 
+2,277,614 
+CASH FLOWS FROM INVESTING ACTIVITIES: 
+Acquisition of and deposits on fixed assets 
+(1,452,601 
+) 
+(885,609 
+) 
+Net cash used in investing activities 
+(1,452,601 
+) 
+(885,609 
+) 
+CASH FLOWS FROM FINANCING ACTIVITIES: 
+Proceeds from option and warrant exercises 
+237,163 
+31,432 
+Proceeds from sale of common stock, net 
+- 
+5,408,462 
+Payment of loan obligation 
+- 
+(133,483 
+) 
+Net cash provided by financing activities 
+237,163 
+5,306,411 
+(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS 
+(5,035,737 
+) 
+6,698,416 
+Cash and cash equivalents - beginning of the period 
+9,650,275 
+2,951,859 
+Cash and cash equivalents - end of the period 
+$ 
+4,614,538 
+$ 
+9,650,275 
+RECONCILIATION OF NET (LOSS) INCOME TO NET CASH (USED IN) PROVIDED BY OPERATING ACTIVITIES: 
+Net (Loss) Income 
+$ 
+(1,137,203 
+) 
+$ 
+530,818 
+Adjustments: 
+Depreciation and amortization 
+739,297 
+607,822 
+Provision for (benefit from) deferred taxes 
+(403,375 
+) 
+458,154 
+Provision for (recovery of) doubtful accounts 
+28,000 
+(34,000 
+) 
+Share based compensation 
+447,100 
+331,870 
+Changes in assets and liabilities: 
+Accounts receivable 
+(3,774,768 
+) 
+263,236 
+Inventories 
+(449,573 
+) 
+(700,655 
+) 
+Prepaid expenses and other current assets 
+32,906 
+(159,583 
+) 
+Deposits and other assets 
+(279,223 
+) 
+(2,391 
+) 
+Accounts payable and accrued liabilities 
+636,540 
+1,005,567 
+Customer deposits and deferred revenue 
+340,000 
+(23,224 
+) 
+Net cash (used in) provided by operating activities 
+$ 
+(3,820,299 
+) 
+$ 
+2,277,614 
+Supplemental disclosures for non-cash investing and financing activities: 
+Deposits on manufacturing equipment transferred to fixed assets 
+$ 
+603,627 
+$ 
+521,561 
+See accompanying notes to condensed consolidated financial statements 
+F-5 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2014 AND 2013 
+NOTE 1 — DESCRIPTION OF BUSINESS: 
+Chembio Diagnostics, Inc. and its subsidiary, Chembio Diagnostic Systems, Inc. (collectively, the "Company" or "Chembio"), develop, manufacture, and market rapid diagnostic tests that detect infectious diseases. The Company's main lateral flow products are three rapid tests for the detection of HIV antibodies in whole blood, serum and plasma samples, two of which were approved by the FDA in 2006; the third is sold for export only. Lateral Flow Rapid HIV tests represented nearly 37% of the Company's product revenues in 2014. The Company's products based on its patented DPP® platform represented approximately 60% of the Company's product revenues in 2014. The Company also has other rapid tests that together represented approximately 3% of sales in 2014. The Company's products are sold to medical laboratories and hospitals, governmental and public health entities, non-governmental organizations, medical professionals and retail establishments both domestically and internationally. Chembio's products are sold under the Company's STAT-PAK®, SURE CHECK® or DPP® registered trademarks, or under the private labels of its marketing partners, for example the Clearview® label owned by Alere, Inc. ("Alere"), which is the Company's exclusive marketing partner for one of its rapid HIV lateral flow test products in the United States. These products employ lateral flow technologies that are proprietary and/or licensed to the Company. All of the Company's products that are currently being developed are based on its patented Dual Path Platform (DPP®), which is a unique diagnostic point-of-care platform that has certain advantages over lateral flow technology. In December 2012, the Company received FDA approval for its DPP® HIV 1/2 Assay for the detection of HIV antibodies in saliva, whole blood, serum and plasma samples, which was CLIA-Waived in October 2014. 
+NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES: 
+(a) 
+Principles of Consolidation: 
+The consolidated financial statements include the accounts of the Company and its wholly owned subsidiary. All intercompany transactions and balances have been eliminated in consolidation. 
+(b) 
+Use of Estimates: 
+The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make assumptions and estimates that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods covered thereby. Actual results could differ from these estimates. Judgments and estimates of uncertainties are required in applying the Company's accounting policies in certain areas. The following are some of the areas requiring significant judgments and estimates: determinations of the useful lives of assets, estimates of allowances for doubtful accounts, inventory reserves, stock-based compensation and deferred tax assets. 
+(c) 
+Fair Value of Financial Instruments: 
+The carrying value for cash and cash equivalents, accounts receivable and accounts payable, approximate fair value because of the immediate or short-term maturity of these financial instruments. 
+(d) 
+Statements of Cash Flows: 
+For purposes of the statements of cash flows, the Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents. 
+F-6 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2014 AND 2013 
+(e) 
+Concentrations of Credit Risk: 
+Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of temporary cash investments and trade receivables. The Company places its temporary cash instruments with well-known financial institutions and, at times, may maintain balances in excess of the FDIC insurance limit. The Company monitors the credit ratings of the financial institutions to mitigate this risk. Concentration of credit risk with respect to trade receivables is principally mitigated by the Company's ability to obtain letters of credit from certain foreign customers, and its diverse customer base both in number of customers and geographic locations. As of December 31, 2014, we have a significant concentration of outstanding credit with one customer in Brazil. We currently do not require collateral for accounts receivable. 
+(f) 
+Inventories: 
+Inventories, consisting of material, labor and manufacturing overhead, are stated at the lower of cost or market. Cost is determined on the first-in, first-out method. 
+(g) 
+Fixed Assets: 
+Fixed assets are stated at cost, less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the respective assets, which range from three to seven years. Leasehold improvements are amortized over the useful life of the asset or the lease term, whichever is shorter. Deposits paid for fixed assets are capitalized and not depreciated until the related asset is placed in service. 
+(h) 
+License Agreement: 
+In February 2008, the Company entered into a sublicense agreement for which it had initially recorded an asset of $1,000,000. This asset is being expensed over an estimated economic life of ten years, based on the expected lifespan of our then current HIV products. The current portion of this asset is $100,000 as of December 31, 2014 and 2013 and is reported in prepaid expenses and other current assets. The long-term portion as of December 31, 2014 and 2013 is $200,000 and $300,000, respectively and is reflected in other assets on the consolidated balance sheet. 
+(i) 
+Impairment of Long-Lived Assets and Intangible Assets 
+Long-lived assets to be held and used are analyzed for impairment whenever events or changes in circumstances indicate that the related carrying amounts may not be recoverable. The Company evaluates at each balance sheet date whether events and circumstances have occurred that indicate possible impairment. If there are indications of impairment, the Company uses future undiscounted cash flows of the related asset or asset grouping over the remaining life in measuring whether the assets are recoverable. In the event such cash flows are not expected to be sufficient to recover the recorded asset values, the assets are written down to their estimated fair value. We believe that the carrying values of our long-lived tangible and intangible assets were realizable at December 31, 2014 and 2013, respectively. 
+(j) 
+Revenue Recognition: 
+The Company recognizes revenue for product sales in accordance with ASC 605, revenue is recognized when there is persuasive evidence of an arrangement, delivery has occurred or services have been rendered, the sales price is fixed and determinable, and collectability is reasonably assured. Revenue typically is recognized at time of shipment. Sales are recorded net of discounts, rebates and returns. 
+F-7 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2014 AND 2013 
+For certain contracts, the Company recognizes revenue from non-milestone contracts and grant revenues when earned. Grants are invoiced after expenses are incurred. Revenues from projects or grants funded in advance are deferred until earned. 
+The Company follows Financial Accounting Standards Board ("FASB") issued authoritative guidance ("guidance") prospectively for the recognition of revenue under the milestone method. The Company applies the milestone method of revenue recognition for certain collaborative research projects defining milestones at the inception of the agreement. 
+(k) 
+Research and Development: 
+Research and development (R&D) costs are expensed as incurred. 
+(l) 
+Stock-Based Compensation: 
+Stock-based compensation expense is calculated using the Black-Scholes valuation model based on awards ultimately expected to vest, reduced for forfeitures, and expensed on a straight-line basis over the requisite service period of the grant. 
+(m) 
+I ncome Taxes: 
+The Company accounts for income taxes under an asset and liability approach which recognizes deferred tax assets and liabilities based on the difference between the financial statement carrying amounts and the tax bases of assets and liabilities using enacted tax rates in effect in the years in which the differences are expected to reverse. 
+The Company follows a more-likely-than-not threshold for financial statement recognition and measurement of a tax position taken, or expected to be taken, in a tax return. The guidance relates to, among other things, classification, accounting for interest and penalties associated with tax positions, and disclosure requirements. Any interest and penalties accrued related to uncertain tax positions will be recorded in tax expense. 
+(n) 
+Earnings Per Share 
+The following weighted average shares were used for the computation of basic and diluted earnings per share: 
+For the years ended 
+December 31, 2014 
+December 31, 2013 
+Basic 
+9,530,320 
+8,994,080 
+- 
+- 
+Diluted 
+9,530,320 
+9,519,968 
+Basic earnings per share is computed by dividing net earnings attributable to common stockholders by the weighted-average number of common shares outstanding for the period. Diluted earnings per share for the year ended December 31, 2014 and 2013 reflects the potential dilution from the exercise or conversion of other securities into common stock. 
+The following securities, presented on a common share equivalent basis, have been used in the diluted per share computations: 
+For the years ended 
+December 31, 2014 
+December 31, 2013 
+1999, 2008 and 2014 Plan Stock Options 
+- 
+525,888 
+There were 798,475 and 169,662 options and warrants outstanding as of December 31, 2014 and 2013, respectively, which were not included in the calculation of diluted income per share for the years ended because their effect would have been anti-dilutive. 
+F-8 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2014 AND 2013 
+(o) 
+Recent Accounting Pronouncements Affecting the Company: 
+In May 2014, the FASB issued Accounting Standards Update No. 2014-09, "Revenue from Contracts with Customers" ("ASU 2014-09"), which supersedes nearly all existing revenue recognition guidance under accounting principles generally accepted in United States ("U.S. GAAP"). The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing U.S. GAAP. 
+The standard is effective for annual periods beginning after December 15, 2016, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients; or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We are currently evaluating the impact of our pending adoption of ASU 2014-09 on our consolidated financial statements and have not yet determined the method by which we will adopt the standard in 2017. 
+NOTE 3 — INVENTORIES: 
+Inventories consist of the following at: 
+December 31, 2014 
+December 31, 2013 
+Raw materials 
+$ 
+2,323,863 
+$ 
+1,710,627 
+Work in process 
+346,494 
+464,481 
+Finished goods 
+967,942 
+1,013,618 
+$ 
+3,638,299 
+$ 
+3,188,726 
+NOTE 4 — FIXED ASSETS: 
+Fixed assets consist of the following at: 
+December 31, 2014 
+December 31, 2013 
+Machinery and equipment 
+$ 
+3,508,944 
+$ 
+3,158,265 
+Furniture and fixtures 
+388,040 
+352,923 
+Computer and telephone equipment 
+315,916 
+167,045 
+Leasehold improvements 
+1,955,817 
+1,016,783 
+Automobiles 
+- 
+37,061 
+6,168,717 
+4,732,077 
+Less accumulated depreciation and amortization 
+(3,370,788 
+) 
+(2,753,845 
+) 
+$ 
+2,797,929 
+$ 
+1,978,232 
+There were no capital leases at the end of December 31, 2014. Fixed assets at December 31, 2014 also include $315,000 in equipment, which has been delivered and set-up but is undergoing validation and as such is currently not being depreciated. Depreciation expense for the 2014 and 2013 years aggregated $616,943 and $505,000, respectively. 
+As of December 31, 2014 and 2013, the Company had paid deposits on various pieces of equipment aggregating $20,017 and $16,410, respectively. The Company is further committed to an additional obligation of $9,000 as various milestones are achieved by the various vendors. 
+NOTE 5 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES: 
+Accounts payable and accrued liabilities consist of the following at: 
+December 31, 2014 
+December 31, 2013 
+Accounts payable – suppliers 
+$ 
+1,980,120 
+$ 
+1,815,369 
+Accrued commissions 
+947,451 
+371,905 
+Accrued royalties / license fees 
+1,034,062 
+1,028,286 
+Accrued payroll 
+106,487 
+328,564 
+Accrued vacation 
+219,924 
+203,444 
+Accrued bonuses 
+265,500 
+317,372 
+Accrued expenses – other 
+392,486 
+244,550 
+TOTAL 
+$ 
+4,946,030 
+$ 
+4,309,490 
+F-9 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2014 AND 2013 
+NOTE 6 — DEFERRED RESEARCH AND DEVELOPMENT REVENUE: 
+The Company recognizes income from R&D milestones when those milestones are reached and non-milestone contracts and grants when earned. Grants are invoiced after expenses are incurred. Any projects or grants funded in advance are deferred until earned. As of December 31, 2014, there were $340,000 unearned advanced revenues. 
+NOTE 7 — TERM NOTE, REVOLVING DEMAND NOTE, VEHICLE FINANCING AND LICENSE FEE PAYABLE: 
+On April 30, 2013, the Company entered into a new demand loan agreement ("Demand Note") with HSBC Bank, USA ("HSBC"). The Demand Note allows the Company to draw on the line from time to time an amount up to an aggregate of $2,000,000 outstanding at any one time. The accrued interest on the Demand Note is payable monthly at an interest rate equal to one-quarter percent above prime per annum. The Company can repay any or all of the principal balance outstanding at any time. This is a demand note for which the bank lender can demand repayment of the entire loan, with accrued interest, at any time. The loan is subject to annual reviews, as well as an annual 30-day clean-up, during which there can be no amounts outstanding. 
+The Security Agreement, related to the Demand Note, contains covenants that place restrictions on the Company's operations, including covenants relating to mergers, debt restrictions, capital expenditures, tangible net worth, net profit, leverage, fixed charge coverage, employee loan restrictions, distribution restrictions (common stock and preferred stock), dividend restrictions, restrictions on lease payments to affiliates, restrictions on changes in business, asset sale restrictions, restrictions on acquisitions and intercompany transactions, and restrictions on fundamental changes in the Company and in its business. 
+The Company currently maintains its operating, payroll, and primary cash accounts at HSBC. As of December 31, 2014, nothing had been drawn down on the Demand Note and all covenants were met. 
+NOTE 8 — INCOME TAXES: 
+The (benefit from) provision for income taxes for the years ended December 31, 2014 and 2013, is comprised of the following: 
+2014 
+2013 
+Current 
+Federal 
+$ 
+(16,119 
+) 
+$ 
+27,175 
+State 
+6,576 
+1,623 
+Total current (benefit) provision 
+(9,543 
+) 
+28,798 
+Deferred 
+Federal 
+(449,452 
+) 
+454,439 
+State 
+46,077 
+3,715 
+Total deferred (benefit) provision 
+(403,375 
+) 
+458,154 
+Total (benefit) provision 
+$ 
+(412,918 
+) 
+$ 
+486,952 
+F-10 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2014 AND 2013 
+The Company had an ownership change as described in Internal Revenue Code Sec. 382 during 2004 ("2004 change"). As a result, the Company's net operating losses prior to the 2004 change of $5,832,516 were subject to an annual limitation of $150,608 and for the first five (5) years are entitled to a BIG (Built-In-Gains) of $488,207 per year. These net operating losses expire in 2018 through 2024. 
+The Company had a second ownership change during 2006 ("2006 change"). The net operating losses incurred between the 2004 change and the 2006 change of $8,586,861 were subject to an annual limitation of $1,111,831 and for the first five (5) years are entitled to a BIG of $1,756,842 per year. These net operating losses expire in 2018 through 2028. 
+After applying the above limitations, at December 31, 2014, the Company has post-change net operating loss carry-forwards of approximately $11,696,561 which expire between 2020 and 2034. In addition the Company has research and development tax credit carryforwards of approximately $1,175,725 for the year ended December 31, 2014, which expire between 2025 and 2034. 
+2014 
+2013 
+Current assets 
+Inventory reserves 
+$ 
+311,931 
+$ 
+307,080 
+Accrued expenses 
+286,616 
+329,187 
+Net current deferred asset 
+$ 
+598,547 
+$ 
+636,267 
+Noncurrent assets 
+Net operating loss carry-forwards 
+$ 
+3,986,618 
+$ 
+3,616,089 
+Research and development credit 
+1,175,725 
+1,052,166 
+Other credits 
+107,967 
+124,413 
+Other 
+149,923 
+107,808 
+Gross noncurrent deferred tax assets 
+5,420,233 
+4,900,476 
+Depreciation 
+(213,206 
+) 
+(258,103 
+) 
+Noncurrent deferred tax assets 
+5,207,027 
+4,642,373 
+Less valuation allowances 
+(1,175,725 
+) 
+(1,052,166 
+) 
+Net noncurrent deferred tax assets 
+$ 
+4,031,302 
+$ 
+3,590,207 
+A reconciliation of the Federal statutory rate to the effective rate applicable to income (loss) before income taxes is as follows: 
+Year Ending December 31, 
+2014 
+2013 
+Federal income tax at statutory rates 
+(34.00)% 
+34.00% 
+State income taxes, net of federal benefit 
+.28% 
+0.47% 
+Nondeductible expenses 
+4.54% 
+10.27% 
+Change in valuation allowance 
+9.47% 
+33.48% 
+Tax credits 
+(9.47)% 
+(33.48)% 
+Change in tax rates 
+1.96% 
+3.10% 
+Other 
+.58% 
+(0.01)% 
+Income tax (benefit) 
+(26.64)% 
+47.83% 
+Interest and penalties, if any, related to income tax liabilities are included in income tax expense. As of December 31, 2014, the Company does not have a liability for uncertain tax positions. 
+The Company files Federal and New York state income tax returns. Tax years for fiscal 2011 through 2013 are open and potentially subject to examination by the federal and New York state taxing authorities. 
+F-11 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2014 AND 2013 
+NOTE 9 — STOCKHOLDERS' EQUITY: 
+(a) 
+Common Stock 
+During 2014, options to purchase 318,750 shares of the Company's common stock were exercised, either for cash or cashless into 286,356 shares of common stock at an exercise price of $1.04. 
+The Company closed on an underwritten public offering of 1,200,000 shares of its common stock at $5.00 per share on April 3, 2013. The net proceeds of the offering, after deducting the underwriters' discounts and other offering expenses payable by the Company, was approximately $5,408,000. 
+During 2013, options to purchase 88,551 shares of the Company's common stock were exercised at exercise prices ranging from of $1.04 to $1.76. 
+(b) 
+Preferred Stock 
+The Company has 10,000,000 shares of preferred stock authorized and none outstanding. These shares can become issuable upon an approved resolution by the board of directors and the filing of a Certificate of Designation with the state of Nevada. 
+(c) 
+Options 
+During the fourth quarter of 2014, the Company issued 36,000 options to purchase common stock to a newly-hired vice-president of the Company. The options are exercisable in three equal annual installments starting on the first anniversary of the date of issue. The options issued have an exercise price of $4.35 per share, which was the last traded price of the common stock on the day issued. The options expire five years from date of issue. 
+During the second quarter of 2014 the Company issued options to two of its directors pursuant to the Company's compensation policy for directors. Each director was issued 46,875 options to purchase common stock. The options are exercisable in five equal annual installments starting on the date of issue. The options issued have an exercise price of $3.480 per share, which was the last traded price of the common stock on the day issued. The options expire five years from date of issue. 
+The Company entered into an employment agreement, effective March 13, 2014 ("Employment Agreement"), with Mr. Sperzel to serve as the Company's Chief Executive Officer, which included issuing incentive and non-incentive stock options to purchase 250,000 shares of the Company's common stock. The options become exercisable in five equal annual installments starting on the first anniversary of the effective date of the Employment Agreement. The exercise price for these options was to be equal to the volume-weighted average trading price for the Company's common stock on March 13, 2014, which was $3.416 per share. The options expire seven years from date of issue. 
+The Company entered into an employment agreement effective May 22, 2013 ("Employment Agreement"), with Ms. Klugewicz to serve as the Company's Chief Operating Officer, which included issuing incentive stock options to purchase 5,000 shares of the Company's common stock. The options become exercisable in two equal annual installments starting on the first anniversary of the date of issue. The exercise price for these options was to be equal to the last traded price for the Company's common stock on May 22, 2013, which was $4.50 per share. Each option granted will expire and terminate, if not exercised sooner, upon the earlier to occur of (a) 30 days after termination of the employee's employment with the Company or (b) the fifth anniversary of the effective date of the grant. 
+On February 26, 2013, the Company issued 16,360 options to purchase common stock to executives of the Company as part of their 2012 bonus. The options are exercisable immediately at $5.56 per share, which was the last traded price of the common stock on that day, and they expire five years from the date of issue. 
+F-12 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2014 AND 2013 
+The Company entered into an employment agreement effective March 5, 2013 ("Employment Agreement"), with Mr. Esfandiari to continue as the Company's Senior Vice President of Research and Development, which included issuing incentive stock options to purchase 30,000 shares of the Company's common stock. The options become exercisable in three equal annual installments starting on the first anniversary of the date of issue. The exercise price for these options was to be equal to the last traded price for the Company's common stock on March 5, 2013, which was $5.44 per share. Each option granted will expire and terminate, if not exercised sooner, upon the earlier to occur of (a) 30 days after termination of the employee's employment with the Company or (b) the fifth anniversary of the effective date of the grant. 
+(d) 
+Warrants 
+As of December 31, 2014 and 2013, the Company had no warrants outstanding to purchase shares of common stock. 
+NOTE 10 — RIGHTS AGREEMENT: 
+In March 2010, the Company entered into a Rights Agreement (the "Rights Agreement") between the Company and Action Stock Transfer Corp., as Rights Agent. Pursuant to the Rights Agreement, the Company declared a dividend distribution of one preferred share purchase right (a "Right") for each outstanding share of Common Stock, $0.01 par value (the "Common Stock"), of the Company. The Board of Directors set the payment date for the distribution of the Rights as March 8, 2010, and the Rights were distributed to the Company's shareholders of record on that date. The description and terms of the Rights are set forth in the Rights Agreement. 
+Rights Initially Not Exercisable. The Rights are not exercisable until a Distribution Date. Until a Right is exercised, the holder thereof, as such, will have no rights as a shareholder of the Company, including, without limitation, the right to vote or to receive dividends. 
+Separation and Distribution of Rights . The Rights will be evidenced by the certificates for shares of Common Stock registered in the names of the holders thereof, and not by separate rights certificates until the earlier to occur of (i) the close of business on the tenth business day following a public announcement that an Acquiring Person (as defined in the Rights Agreement) acquired a Combined Ownership (as defined in the Rights Agreement) of 15% or more of the outstanding shares of the Common Stock (the "Shares Acquisition Date") or (ii) the later of (A) the close of business on the tenth business day (or such later date as may be determined by action of the Board of Directors prior to such time as any person or group of affiliated or associated persons becomes an Acquiring Person) after the date that a tender or exchange offer or intention to commence a tender or exchange offer by any person is first published, announced, sent or given within the meaning of Rule 14d-4(A) under the Securities Exchange Act of 1934, as amended, the consummation of which would result in any person having Combined Ownership of 15% or more of the outstanding shares of the Common Stock, or (B) if such a tender or exchange offer has been published, announced, sent or given before the date of the Rights Agreement, then the close of business on the tenth business day after the date the Rights Agreement was entered into (or such later date as may be determined by action of the Board of Directors prior to such time as any person becomes an Acquiring Person); (the earlier of such dates referred to in (i) and (ii), which date may include any such date that is after the date of the Rights Agreement but prior to the issuance of the Rights, being called the "Distribution Date"). 
+F-13 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2014 AND 2013 
+NOTE 11 — EMPLOYEE STOCK OPTION PLAN: 
+The Company has a 1999 Stock Option Plan ("SOP") originally covering 187,500 shares of Common Stock. Under the terms of the SOP, the Compensation Committee of the Company's board is authorized to grant incentive options to key employees and to grant non-qualified options to key employees and key individuals. The options become exercisable at such times and under such conditions as determined by the Compensation Committee. The SOP was amended at the Company's 2005 stockholders' meeting. The number of options under the SOP was increased to cover 375,000 shares of common stock. It was also amended to allow independent directors to be eligible for grants under the portion of the SOP concerning non-qualified options. As of December 31, 2014, there were no outstanding options under this SOP. No additional options may be issued under the SOP more than 10 years after its adoption 
+Effective June 3, 2008, the Company's stockholders voted to approve the 2008 Stock Incentive Plan ("SIP"), with 625,000 shares of Common Stock available to be issued. At the Annual Stockholder meeting on September 22, 2011 the Company's stockholders voted to approve an increase to the shares of Common Stock issuable under the SIP by 125,000 to 750,000. Under the terms of the SIP, the Compensation Committee of the Company's Board has the discretion to select the persons to whom awards are to be granted. Awards can be stock options, restricted stock and/or restricted stock units. The awards become vested at such times and under such conditions as determined by the Compensation Committee. As of December 31, 2014, there were 336,826 options exercised, 355,251 options outstanding and 57,923 options still available to be issued under the SIP. 
+Effective June 19, 2014, the Company's stockholders voted to approve the 2014 Stock Incentive Plan ("SIP14"), with 800,000 shares of Common Stock available to be issued. Under the terms of the SIP14, the Compensation Committee of the Company's Board has the discretion to select the persons to whom awards are to be granted. Awards can be stock options, restricted stock and/or restricted stock units. The awards become vested at such times and under such conditions as determined by the Compensation Committee. As of December 31, 2014, there were no options exercised, 129,750 options outstanding and 670,250 options still available to be issued under the SIP14. 
+The Company's results for the years ended December 31, 2014 and 2013 include stock-based compensation expense totaling $447,100 and $332,000, respectively. Such amounts have been included in the Consolidated Statements of Operations within cost of goods sold ($700 and $78,000, respectively), research and development ($44,500 and $106,000, respectively) and selling, general and administrative expenses ($401,900 and $148,000, respectively). In accordance with ASC 718 the Company has not recorded a deferred tax asset related to the net operating losses resulting from the exercise of disqualifying stock options in the accompanying financial statements. The cumulative amount of unrecognized tax benefits at December 31, 2014 was immaterial, and if the Company is able to utilize this benefit in the future it would result in a credit to additional paid-in capital. 
+Stock option compensation expense in the years ended December 31, 2014 and 2013 represents the estimated fair value of options outstanding which is being amortized on a straight-line basis over the requisite vesting period of the entire award. 
+The weighted average estimated fair value of stock options granted in the years ended December 31, 2014 and 2013 was $3.52 and $3.99 per share, respectively. The fair value of options at the date of grant was estimated using the Black-Scholes option pricing model. The expected volatility is based upon historical volatility of our stock and other contributing factors. The expected term is based on the Company's historical experience with similar type options. 
+F-14 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2014 AND 2013 
+The weighted-average assumptions made in calculating the fair values of options are as follows: 
+For the years ended 
+December 31, 2014 
+December 31, 2013 
+Expected term (in years) 
+4.5-6.3 
+4-5 
+Expected volatility 
+61.50-96.10% 
+99.60-115.77% 
+Expected dividend yield 
+n/a 
+n/a 
+Risk-free interest rate 
+.83-1.52% 
+.34-0.34% 
+The Company granted 379,750 new options during the year ended December 31, 2014 to employees at an average exercise price of $3.52 per share. 
+The following table provides stock options activity for the year ended December 31, 2014: 
+Stock Options 
+Number of 
+Shares 
+Weighted 
+Average 
+Exercise Price per 
+Share 
+Weighted 
+Average 
+Remaining 
+Contractual 
+Term 
+Aggregate Intrinsic 
+Value 
+Outstanding at December 31, 2013 
+656,398 
+$ 
+2.57 
+1.65 years 
+$ 
+801,888 
+Granted 
+379,750 
+$ 
+3.52 
+Exercised 
+318,750 
+$ 
+1.04 
+$ 
+341,729 
+Forfeited/expired/cancelled 
+25,529 
+$ 
+3.17 
+Outstanding at December 31, 2014 
+691,869 
+$ 
+3.66 
+3.97 years 
+$ 
+334,636 
+Exercisable at December 31, 2014 
+265,619 
+$ 
+3.67 
+1.94 years 
+$ 
+158,149 
+The following table summarizes information about stock options outstanding at December 31, 2014: 
+Stock Options Outstanding 
+Stock Options Exercisable 
+Range of 
+Exercise 
+Prices 
+Shares 
+Average 
+Remaining 
+Contract Life 
+(Year) 
+Weighted 
+Average 
+Exercise 
+Price 
+Aggregate 
+Intrinsic 
+Value 
+Shares 
+Weighted 
+Average 
+Exercise 
+Price 
+Aggregate 
+Intrinsic 
+Value 
+$ 0.000 to 3.500 
+475,000 
+4.50 
+$ 
+3.21 
+$ 
+332,500 
+131,250 
+$ 
+2.71 
+$ 
+157,500 
+3.501 to 4.500 
+153,744 
+2.54 
+4.28 
+- 
+103,244 
+4.24 
+- 
+4.501 to 8.000 
+75,625 
+2.90 
+5.30 
+- 
+43,625 
+5.28 
+- 
+Total 
+704,369 
+3.90 
+$ 
+3.67 
+$ 
+332,500 
+278,119 
+$ 
+3.68 
+$ 
+157,500 
+As of December 31, 2014, there was $631,000 of net unrecognized compensation cost related to stock options that are not vested, which is expected to be recognized over a weighted average period of approximately 2.38 years. The total fair value of shares vested during the years ended December 31, 2014 and 2013, was $283,000 and $118,000, respectively. 
+F-15 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2014 AND 2013 
+NOTE 12 — GEOGRAPHIC INFORMATION AND ECONOMIC DEPENDENCY: 
+FASB Guidance establishes standards for the way that business enterprises report information about operating segments in financial statements and requires that those enterprises report selected information. It also establishes standards for related disclosures about product and services, geographic areas, and major customers. 
+The Company produces only one group of similar products known collectively as "rapid medical tests". Management believes that it operates in a single business segment. Net sales by geographic area are as follows: 
+For the years ended 
+December 31, 2014 
+December 31, 2013 
+Africa 
+$ 
+2,097,353 
+$ 
+4,352,731 
+Asia 
+96,061 
+115,889 
+Europe 
+191,947 
+99,146 
+North America 
+11,134,691 
+9,730,557 
+South America 
+12,429,717 
+13,217,463 
+$ 
+25,949,769 
+$ 
+27,515,786 
+Sales to Africa decreased in 2014 primarily due to decreased sales in Uganda by approximately $1,672,000, Nigeria by approximately $226,000 and Ethiopia by approximately $70,000. Sales in Asia decreased slightly by $20,000. European sales increased by $93,000. Sales increased in 2014 to North America from increased sales to Mexico of $3,233,000 and were partially offset by decreased sales in the U.S of approximately $1,889,000 million. Sales decreased in 2014 to South America were primarily from decreased sales from an order which did not repeat in 2014 of $6,464,000 and were partially offset by increased sales in Brazil of approximately $5,803,000. 
+NOTE 13 — COMMITMENTS AND CONTINGENCIES: 
+Employment Contracts: 
+The Company has contracts with three key employees. The contracts call for salaries presently aggregating $929,500 per year. One contract expires in May 2015, one expires in March 2016 and one contract expires in March 2017. The following table is a schedule of future minimum salary commitments: 
+2015 
+$ 
+794,000 
+2016 
+426,000 
+2017 
+78,000 
+Pension Plan: 
+The Company has a 401(k) plan established for its employees. Effective January 1, 2011 the Company elected to match 40% of the first 5% (or 2% of salary) that an employee contributes to their 401(k) plan. Expenses related to this matching contribution aggregated $82,750 and $83,000 for the years ended December 31, 2014 and 2013, respectively. 
+Obligations Under Operating Leases: 
+The Company leases industrial space used for office, R&D and manufacturing facilities, currently with a monthly rent of $27,305. The current lease expires on April 30, 2017. The lease provides for annual increases of 2 1/2 percent each year starting May 1, 2015. In February of 2014, the Company entered into a lease, effective March 1, 2014, for another facility located a short distance from its current facility currently with a monthly rent of $14,658. The space will be used primarily for warehousing and provides for additional office space. The lease expires on April 30, 2018. The lease provides for annual increases of three percent each year starting March 1, 2015. 
+F-16 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2014 AND 2013 
+The following is a schedule of future minimum rental commitments (assuming no increases): 
+Years ending December 31, 
+2015 
+$ 
+513,414 
+2016 
+527,151 
+2017 
+306,018 
+2018 
+64,067 
+$ 
+1,410,650 
+Rent expense was $476,000 and $250,700 for the years ended December 31, 2014 and 2013, respectively. 
+Economic Dependency: 
+The following table delineates sales the Company had to customers in excess of 10% of total sales for the periods indicated: 
+For the years ended 
+Accounts 
+Receivable As of 
+December 31, 2014 
+December 31, 2013 
+December 31, 2014 
+December 31, 2013 
+Sales 
+% of 
+Sales 
+Sales 
+% of 
+Sales 
+Customer 1 
+$ 
+6,618,251 
+26 
+% 
+$ 
+8,894,969 
+32 
+% 
+$ 
+386,270 
+$ 
+547,888 
+Customer 2 
+3,455,402 
+13 
+% 
+* 
+* 
+138,335 
+209,166 
+Customer 3 
+12,253,526 
+47 
+% 
+6,449,385 
+23 
+% 
+6,230,886 
+2,064,940 
+Customer 4 
+* 
+* 
+6,745,939 
+25 
+% 
+* 
+* 
+In the table above the asterisk (*) indicates that sales to the customer did not exceed 10% for the period indicated. 
+The following table delineates purchases the Company had with vendors in excess of 10% of total purchases for the periods indicated. 
+For the years ended 
+Accounts 
+Payable As of 
+December 31, 2014 
+December 31, 2013 
+December 31, 2014 
+December 31, 2013 
+Purchases 
+% of 
+Purc. 
+Purchases 
+% of 
+Purc. 
+Vendor 1 
+$ 
+1,331,647 
+14 
+% 
+$ 
+1,114,810 
+10 
+% 
+$ 
+200,855 
+$ 
+84,161 
+Vendor 2 
+1,594,838 
+17 
+% 
+$ 
+0 
+0 
+% 
+- 
+- 
+In the table above the asterisk (*) indicates that purchases from the vendor did not exceed 10% for the period indicated. 
+The Company currently buys materials which are purchased under intellectual property rights agreements and are important components in its products. Management believes that other suppliers could provide similar materials on comparable terms. A change in suppliers, however, could cause a delay in manufacturing and a possible loss of sales, which would affect operating results adversely. 
+F-17 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2014 AND 2013 
+NOTE 14 — COLLABORATIVE RESEARCH AND DEVELOPMENT AGREEMENTS: 
+In 2014 and 2013, the Company earned $1,672,258 million and $2,028,917 million, respectively, from research revenues and milestones. The Company is now involved in additional feasibility and development contracts related to its DPP® technology. The total expended on R&D in 2014 and 2013, was approximately $4.0 million and $3.7 million, respectively. 
+a. 
+National Institutes of Health (NIH) Grant: 
+In March 2011, the Company received a $2,850,000 million, 3-year grant from the United States National Institutes of Health to complete development of a test for Tuberculosis. Grants are invoiced after expenses are incurred. The Company earned, for the years ended December 31, 2014 and 2013, $388,000 and $1,089,000, respectively from this grant. The Company has earned $2,850,000 from this grant from inception through December 31, 2014, of which $1,019,000 was paid to sub-contractors. 
+b. 
+Battelle/CDC DPP® Influenza Immunity Test: 
+In November 2014, the Company entered into a follow-on, milestone-based development agreement bringing the total up to $1,239,000 based on Chembio's previous successful initial development of a multiplex rapid point-of-care ("POC") influenza immunity test utilizing its patented Dual Path Platform (DPP®) technology. The follow on agreement contemplates a period of approximately six months in which the follow-on development activity is to be completed. For the years ended Decmber 31, 2014 and 2013, the Company earned $115,000 and $643,500, respectively from this grant. The Company has earned $1,036,000 from this grant from inception through December 31, 2014. 
+c. 
+Cooperative research agreement with a U.S. government agency: 
+In May 2013, the Company was awarded a cooperative research agreement with a U.S. government agency for up to $883,000 for an 8 month development project to develop rapid POC diagnostic tests for five infectious diseases associated with febrile illness. For the years ended Decmber 31, 2014 and 2013, the Company earned $117,000 and $766,000, respectively from this grant. The Company has earned $883,000 from this grant from inception through December 31, 2014. 
+d. RVR DPP® technology transfer agreement 
+In February 2014, the Company entered into a technology transfer agreement with RVR Diagnostics for $1,500,000. The agreement was modified in September 2014. Per the agreement, as modified, the Company earned $1,125,000 in milestone payments during 2014. 
+e. RVR Dengue agreement 
+In October 2014, he Company entered into a development agreement with RVR Diagnostics for $300,000. Revenue for this agreement is being recognized under a proportional performance method. As of December 31, 2014 the Company earned $60,000 from this agreement. 
+Governmental Regulation: 
+All of the Company's existing and proposed diagnostic products are regulated by the United States Food and Drug Administration (FDA), United States Department of Agriculture, certain state and local agencies, and/or comparable regulatory bodies in other countries. Most aspects of development, production, and marketing, including product testing, authorizations to market, labeling, promotion, manufacturing, and record keeping are subject to review. After marketing approval has been granted, Chembio must continue to comply with governmental regulations. Failure to comply with these regulations can result in significant penalties. 
+F-18 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2014 AND 2013 
+NOTE 15 — SUBSEQUENT EVENTS: 
+On January 19, 2015, Chembio entered into a 2015 Omnibus Agreement (the "Omnibus Agreement") with StatSure Diagnostic Systems, Inc. ("SDS") to acquire certain rights from, and to settle certain matters with, SDS. 
+Pursuant to the Omnibus Agreement, beginning June 1, 2016, Chembio will own full rights to the SURE CHECK® HIV 1/2 Assay, including a perpetual, non-exclusive, transferable, sub-assignable license, and including sales, marketing, distribution and trademark rights, subject to the terms of the 3-Way Agreement. Chembio paid $400,000 to SDS in exchange for these rights. In addition certain amounts owed by SDS to Chembio were exchanged for manufacturing equipment owned by SDS. The license will be amortized over its useful life and the equipment will be depreciated over its excepted life. 
+F-19
\ No newline at end of file
diff --git a/raw/filings/0001092662/2014/0001092662-15-000024/filing_metadata.csv b/raw/filings/0001092662/2014/0001092662-15-000024/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..deb451040c879f9c1e8817dc20b98ce40d04e6f6
--- /dev/null
+++ b/raw/filings/0001092662/2014/0001092662-15-000024/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0001092662,CEMI,"CHEMBIO DIAGNOSTICS, INC.",10-K,2015-03-05,2014-12-31,2015-03-05T13:20:36.000Z,0001092662-15-000024,form10_k.htm,FORM 10-K FOR 2014,7436092,1,0,https://www.sec.gov/Archives/edgar/data/1092662/000109266215000024/form10_k.htm,https://www.sec.gov/Archives/edgar/data/1092662/000109266215000024/,2014,2014,1
diff --git a/raw/filings/0001092662/2014/0001092662-15-000024/item1.txt b/raw/filings/0001092662/2014/0001092662-15-000024/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..b51da36a842fb5bddcfa8b4dcf7f71202881245b
--- /dev/null
+++ b/raw/filings/0001092662/2014/0001092662-15-000024/item1.txt
@@ -0,0 +1,295 @@
+ITEM 1. 
+BUSINESS 
+FORWARD-LOOKING STATEMENTS 
+This report contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, and Section 27A of the Securities Act of 1933. Any statements contained in this report that are not statements of historical fact may be forward-looking statements. When we use the words "intends," "estimates," "predicts," "potential," "continues," "anticipates," "plans," "expects," "believes," "should," "could," "may," "will" or the negative of these terms or other comparable terminology, we are identifying forward-looking statements. Forward-looking statements involve risks and uncertainties, which may cause our actual results, performance or achievements to be materially different from those expressed or implied by forward-looking statements. These factors include our research and development activities, distributor channels, market demand for our products, compliance with regulatory impositions; and our capital needs. Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance or achievements. 
+Except as may be required by applicable law, we do not undertake or intend to update or revise our forward-looking statements, and we assume no obligation to update any forward-looking statements contained in this report as a result of new information or future events or developments. Thus, you should not assume that our silence over time means that actual events are bearing out as expressed or implied in such forward-looking statements. You should carefully review and consider the various disclosures we make in this report and our other reports filed with the Securities and Exchange Commission that attempt to advise interested parties of the risks, uncertainties and other factors that may affect our business. 
+For further information about these and other risks, uncertainties and factors, please review the disclosure included in this report under "Part I, Item 1A, Risk Factors." 
+Our Business 
+General 
+The Company (Chembio Diagnostics, Inc. and its wholly-owned subsidiary, Chembio Diagnostic Systems, Inc., are collectively referred to herein as the "Company") develops, manufactures, markets and licenses rapid point-of-care diagnostic tests (POCTs) that detect infectious diseases. The Company's main products presently commercially available are rapid tests for the detection of HIV 1/2 antibodies, and a multiplex rapid test for the detection of HIV and Syphilis antibodies. The HIV 1/2 rapid tests employ in-licensed and proprietary lateral flow technologies (see "Our Rapid Test Technologies"), can be used with all blood matrices as samples, and are manufactured in a standard cassette format, a dipstick format, and a proprietary barrel format. The tests employing the cassette and proprietary barrel formats were approved by the FDA in 2006. The barrel format is exclusively distributed by a distributor in the United States and by Chembio and its designated distributors outside the United States. The Cassette format is distributed by Chembio and its designated distributors worldwide. Our latest generation HIV 1/2 rapid antibody detection test incorporates our patented Dual Path Platform® (DPP®) POCT technology, and this POCT platform does not require in-licensing. The DPP® HIV 1/2 Assay detects antibodies to HIV 1 & 2 in oral fluid samples as well as in all blood matrices. We have sold this product in Brazil since 2009 where it was approved by ANVISA, through our agreement with the Oswaldo Cruz Foundation ("FIOCRUZ"), and we received United States FDA regulatory approval for this product in December 2012 and CLIA waiver in October 2014. We launched it in the United States under Chembio's brand in the fourth quarter of 2014. 
+2 
+Our product pipeline, which currently includes a multiplex rapid test for earlier detection of HIV by detecting P-24 antigen as well as antibodies, a test for Hepatitis-C, and a multiplex test that detects HIV and Syphilis specific antibodies (which we are already selling outside the U.S.), is based on this DPP® technology for which we were issued a United States patent in 2007 and for which additional patent protection has issued or is pending in a number of other countries. With the patented DPP® and the lateral flow platform, we participate in the estimated $8 billion point-of-care market segment of the estimated nearly $50 billion global in-vitro diagnostic market that has an overall growth rate exceeding 3% per annum. POCTs, by providing prompt and early diagnosis, can reduce patient stays, lower overall costs, improve therapeutic interventions and improve patient outcomes. POCTs can also prevent needless hospital admissions, simplify testing procedures, avoid delays from central lab batching, and eliminate the need for return visits. 
+In the areas of infectious and sexually transmitted diseases (such as HIV and syphilis), the utility of a rapid point–of-care (POC) test, particularly in identifying patients unaware of their disease status, has been well established. Large and growing markets have been established for these kinds of tests, initially in high prevalence regions where they are indispensable for large scale prevention and treatment programs. More recently introduced in the United States in 2004, rapid HIV tests now also present a significant segment of the U.S. market for HIV clinical testing, which is still dominated by laboratory tests. We have focused our product development activity within areas where the availability of rapid, point-of-care screening, diagnostic, or confirmatory results can improve health outcomes. More generally we believe there is and will continue to be a growing demand for diagnostic products that can provide accurate, actionable diagnostic information in a rapid, cost-effective manner at the point of care. 
+PRODUCTS 
+Lateral Flow Rapid HIV Tests 
+All three of our lateral flow rapid HIV antibody detection tests are qualitative "yes/no" tests for the detection of antibodies to HIV 1 & 2 with visually interpreted results (one line "negative"; one line "positive") available within approximately 15 minutes. The tests are simple to use, have a shelf life of 24 months, and do not require refrigeration. The tests differ principally only in the method of test procedure, convenience and cost. One of our FDA-approved lateral flow HIV tests incorporates a proprietary plastic "barrel" device that houses the lateral flow strip. This barrel format enables collection of samples directly (usually from a finger-stick whole blood sample) into the barrel's capillary tip. A sealed unitized buffer vial, assembled onto the top of the barrel, is removed and seated into a stand; the seal is then pierced by the barrel's capillary tip, thereby initiating the upward flow of the resulting sample-buffer solution through a filter, up into the vertical device's chamber and onto the lateral flow strip. This results in a unique unitized and closed device system that can reduce the chance of exposure to potentially infectious samples. 
+In January 2015, the Company entered into an agreement with StatSure Diagnostic Systems, Inc. (SDS) to acquire SDS' interest in the barrel device format, also known as Chembio's SURE CHECK® HIV 1/2 Assay, effective June 1, 2016. Beginning June 1, 2016, Chembio will own full rights related to the SURE CHECK® HIV 1/2 Assay, including sales, marketing, distribution and trademark rights, subject to the terms of the existing marketing and distribution agreement with Alere, Inc., which grants Alere U.S. marketing and distribution rights through May 31, 2016. Prior to this newly-executed agreement between SDS and Chembio, SDS has owned a 50 percent interest in the rights to the SURE CHECK® HIV 1/2 Assay that would have continued after May 31, 2016, also subject to the existing marketing and distribution agreement with Alere. The new agreement with SDS also resolves all other matters between Chembio and SDS, including their respective sharing ratios, until June 1, 2016, concerning net revenues from sale of the SURE CHECK® product outside the U.S. 
+The Company's SURE CHECK® HIV 1/2 Assay is marketed exclusively in the U.S. as Clearview® Complete. Outside the U.S., Chembio markets the SURE CHECK® HIV 1/2 Assay primarily through distributors. The SURE CHECK® HIV 1/2 Assay is Food & Drug Administration (FDA) approved, CLIA-waived, European CE-marked, and has been pre-qualified by the World Health Organization (WHO). Results are obtained in 15 minutes via a 2.5uL blood sample (i.e., fingerstick, serum, plasma, or venipuncture whole blood). The assay is stable at room temperature and provides 99.7% sensitivity and 99.9% specificity. 
+3 
+Our other FDA-approved lateral flow HIV test uses a more conventional rectangular plastic cassette format that houses the lateral flow strip. In this case, a sample is transferred by use of a separately provided transfer device ("loop") into a sample well or port of the cassette that houses the lateral flow strip, which is positioned horizontally or flat. 
+Our third lateral flow HIV test, the HIV 1/2 STAT PAK® Dipstick, is our most cost competitive and compact format. It does not have any plastic housing so that 30 test strips can be packaged into a small vial that is ideal for transporting into remote settings. The test procedure is similar to the cassette format except that a user-applied adhesive backing is provided as a more cost-effective and compact "surface" on which to run the test. 
+Regulatory Status of the lateral flow HIV tests 
+The FDA approved our Pre-Market Applications (hereinafter "PMA"; see "Governmental Regulations" and Glossary) in April 2006 for our SURE CHECK® HIV 1/2 (and also now Alere Clearview® Complete HIV 1/2) and for our HIV 1/2 STAT-PAK® products. Waivers under the Clinical Laboratory Improvement Act (hereinafter "CLIA"; see Governmental Regulations) were granted by the FDA for these two FDA-approved products in 2006 and 2007, respectively. A CLIA waiver is required in order for health care providers to administer these tests in the settings where they are most suited and needed, such as public health testing clinics, hospital emergency rooms and physicians' offices. The SURE CHECK® and HIV 1/2 STAT-PAK® products received CE Marks in July 2013 and March 2014, respectively, and the CE Marking for the DPP® HIV 1/2 Assay described below is expected in 2015. We have also updated our filing for CE Marking to reflect the new tradename of STAT-VIEW® HIV 1 / 2 Assay for sale in the EU market. Our HIV 1/2 STAT-PAK® Dipstick, although not FDA-approved, qualifies under FDA export regulations [See Government Regulation] to sell to customers outside the United States, subject to any required approval by the importing country. CE Mark has not been pursued for this product. 
+All three of our lateral flow HIV tests have qualified for procurement under the President's Emergency Plan for AIDS Relief ("PEPFAR"). The cassette and dipstick versions of the STAT-PAK® and the SURE CHECK® assays are also pre-qualified by the World Health Organization (WHO) for procurements by the second largest global program, known as the Global Fund, as well as other related programs funded by agencies affiliated with the United Nations, such as UNICEF and UNITAIDS (see Glossary), through qualification with the WHO bulk procurement scheme. 
+DPP® HIV 1/2 Assay 
+As in the case of our lateral flow HIV tests, our DPP® HIV 1/2 Assay is also a qualitative "yes/no" test for the detection of antibodies to HIV 1& 2, delivers visual results within as little as 15 minutes, is simple to use, has a shelf life of 23 months, and does not require refrigeration. This product, which is our first FDA-approved product incorporating our patented DPP® technology, can be used with oral fluid samples, as well as with all blood matrices. This product also incorporates our patent-pending oral fluid collection and storage system that enables samples to be fully extracted in buffer solution before application to the test device, and also enables the extracted sample to be stored and retested or potentially tested for multiple conditions in future product applications. Clinical and laboratory studies demonstrated the ability of the test to accurately detect the presence of antibodies in individuals down to two years of age. Studies have also shown this product to have improved performance compared with all of the current FDA-approved CLIA-waived lateral flow rapid tests, even including our own lateral flow tests. FDA-approved label claims include sensitivity/specificity on oral fluid and finger-stick whole blood of 98.9%/99.9% and 99.9%/100% respectively. Oral fluid sensitivity was 100% among HIV-positive patients not taking anti-retroviral medication. 
+4 
+Regulatory Status of the DPP® HIV 1/2 Assay 
+In December 2012, we received FDA approval of our Pre-Marketing Approval. In October of 2014 the FDA granted CLIA waiver status. 
+The DPP® HIV 1/2 Assay product is qualified for procurement under the President's Emergency Plan for AIDS Relief ("PEPFAR") for use with all sample matrices, and we are pursuing WHO qualification in order to enable procurement of this product by the Global Fund and United Nations agencies, including programs underwritten by them. In October 2014, we completed a three-day on-site inspection by the WHO as follow-up to pre-qualification activities of our products with no major non-conformances noted during the audit. The WHO laboratory evaluation for the blood matrix is complete, while oral fluid is in progress and expected to be complete in 2015. We are also pursuing CE Marking, anticipated during 2015, as stated above. 
+In June 2010, ANVISA approved the DPP® HIV 1/2 Assay that is being marketed in Brazil through our collaboration with the Oswaldo Cruz Foundation, Brazil's leading public health institute (see Oswaldo Cruz Foundation OEM DPP® Agreements). Since this time, we have sold and marketed millions of DPP HIV tests to Brazil through this partnership. 
+DPP® HIV-Syphilis Multiplex Test 
+This product, launched in 2013, allows for the detection of antibodies to both HIV and Syphilis on a single test device within approximately 15 minutes. In certain global/public health settings (see Target Markets), this product may provide a more convenient and cost effective means of rapid detecting both markers in a single test procedure at the point of care as compared with performing separate rapid tests for each indication. This product takes advantage of the multiplexing feature of DPP® which provides for a more robust reaction between the sample and biomarkers being tested for (HIV and Syphilis antibodies in this case), resulting in a greater ability by the user to visually interpret test results. We launched this product in Mexico in the fourth quarter of 2013 as a unitized product, meaning that each test kit was separately packaged to include each of the other components necessary to run this test, as compared with other configurations where a test kit of 20 or 30 devices is accompanied by one bottle of running buffer. The initial results of this launch have been very positive, and we experienced good results in Mexico during 2014 from the program. Building on this initial success, we continue to pursue commercialization efforts for this product in a number of additional international markets, where there is a great need to detect Mother-to-Child-Transmission of HIV and Syphilis globally. According to the CDC website, "approximately 370,000 babies are born with HIV, mostly in sub-Saharan Africa. Without treatment, more than half of these children will die before the age of 2. Through key interventions, such as routinely testing pregnant women for HIV, providing antiretroviral medications to HIV-infected pregnant women and their exposed infants, and promoting safe infant feeding practices, mother-to-child transmission of HIV can be decreased from about 35% to less than 5%. Another prominent cause of infant mortality is untreated maternal syphilis, which still accounts for more than 500,000 stillbirths and infant deaths annually despite the fact that these deaths could be prevented through routine detection and treatment of syphilis during antenatal care". 
+Regulatory Status of the DPP® HIV-Syphilis Test 
+DPP® HIV-Syphilis – We have developed this product for international and U.S. marketing. For the international market, the product has been registered in Mexico, and successfully launched and sold in this region. 
+In February 2015, this product was granted approval from the Brazilian ANVISA. We have submitted this product both for evaluation by the CDC, acting on behalf of the United States Agency of International Development, and the WHO, which has accepted this product to be evaluated for pre-qualification in its global procurement scheme. In October 2014, WHO conducted a three-day audit of our facilities as follow up to pre-qualification activities for the DPP HIV-Syphilis Assay, including other products submitted for pre-qualification through WHO. No major non-conformances were identified during this audit, and we continue to work with WHO to obtain pre-qualification approval status for this device. 
+5 
+We continue to pursue an FDA submission for this product, and are in the progress of studies to evaluate a version that has been developed for the US market, to meet the performance requirements for a combination test to detect both HIV and Syphilis, including a "reverse" algorithm that is currently in clinical use in the United States for syphilis testing. 
+DPP® TECHNOLOGY & DEVELOPMENT: 
+This year marked a critical year for Chembio in executing our strategy to leverage our DPP® intellectual property and product development and manufacturing experience to create new collaborations where Chembio serves as an exclusive development and manufacturing partner. Examples of such collaboration include the following: 
+· 
+In October 2014, Chembio entered into an exclusive agreement with Integrated BioTherapeutics, Inc. (IBT), a biotechnology company focused on the discovery of novel vaccines and therapeutics for emerging infectious diseases. Under the terms of the agreement, Chembio will combine its patented DPP ® technology with IBT's proprietary Ebola reagents to develop POC diagnostic tests for Ebola and febrile illness. Since announcing the partnership with IBT, the Company has made the following progress to develop DPP ® Ebola and DPP ® Febrile Illness Assays: 
+o 
+Developed DPP ® Ebola Assays in Chembio's Research & Development facilities. 
+o 
+Successfully tested DPP ® Ebola Assays in high containment (BSL4) laboratory, using wild type (real) Ebola virus, via IBT's partner in Canada. 
+o 
+Signed a Research Collaboration Agreement with the Centers for Disease Control and Prevention (CDC) to develop and validate DPP ® Ebola and DPP ® Febrile Illness Assays. 
+o 
+Continued to evaluate its DPP® Ebola test at CDC laboratory in Atlanta, GA, with an estimate of having product for field evaluation in 2Q of 2015. 
+o 
+Submitted DPP ® Ebola pre-qualification application to World Health Organization (WHO) as well as Emergenct Use Authorization (EUA) for FDA 
+o 
+Contacted numerous organizations for Ebola funding, to accelerate the potential development, and potential manufacturing and supply, of DPP ® Ebola and DPP ® Febrile Illness Assays, to include both Ebola and Malaria. 
+· 
+The Company entered into an agreement to develop a POC diagnostic test for dengue fever virus, the DPP ® Dengue Fever Assay, which would be able to detect IgG/IGM and NS1 antigens in October 2014. 
+· 
+A partnership with an international diagnostics company to develop a POC diagnostic test for the early detection and monitoring of a specific type of cancer. The cancer project represents the first application of the DPP ® technology outside the infectious disease field, also announced in October 2014. 
+· 
+The Company entered into a follow-on, milestone-based development agreement with a private contracting organization acting on behalf of the United States Centers for Disease Control and Prevention (CDC), for a multiplex POC influenza immunity test utilizing Chembio's patented Dual Path Platform (DPP ® ) technology. 
+· 
+In January 2015, Chembio entered into an agreement with the Concussion Science Group (CSG) Division of Perseus Science Group LLC, to utilize Chembio's patented DPP ® technology to develop a POC diagnostic test for traumatic brain injury (TBI), including sports-related concussion. Under terms of the agreement, CSG's patented biomarker will be combined with Chembio's proprietary DPP ® platform to develop a semi-quantitative or quantitative point-of-care test to diagnose TBI. CSG has agreed to pay Chembio milestone development payments during 2015. 
+6 
+· 
+In January 2015, Chembio was awarded a grant from the Bill & Melinda Gates Foundation to expedite the feasibility testing and development of a DPP ® Malaria POC rapid diagnostic to accurately identify individuals infected with Plasmodium falciparum parasite. Chembio's DPP ® technology was selected for this grant due to its exceptional sensitivity and potential to aid the foundation in its goal of eradicating malaria. To achieve this goal, diagnostics must be capable of detecting the malaria parasite in infected, but asymptomatic people. Current POC rapid diagnostics tests lack sufficient sensitivity to identify all individuals with transmissible infections. 
+Additionally, Chembio's product pipeline includes a multiplex test that detects P24 HIV antigen as well as HIV 1/2 antibodies, and a rapid test for the detection of Hepatitis-C antibodies. These products are currently in development to meet the performance claims required for the U.S. market. 
+PARTNERS INVOLVED IN MARKETING OUR PRODUCTS 
+Alere 
+On September 29, 2006, we executed marketing and license agreements with Alere. The marketing agreements (the Barrel Agreement and the Cassette Agreement) provide Alere with a 10-year exclusive right (until May 31, 2016) to market our rapid HIV tests in the United States under Alere's brands. The agreements also provide Chembio a non-exclusive license to certain Alere lateral flow patents that may be applicable to our lateral flow products, including for manufacture of the HIV tests in the United States for sales outside the United States and even for sale in the United States should Alere enter the U.S. market with a competitive rapid HIV test product and in such case we choose to market our products directly as provided in the agreements in such event of a competitive rapid HIV test product. Simultaneous with the execution of the agreements, we also settled litigation with StatSure Diagnostics, Inc. (SDS), that had been ongoing relating to the proprietary barrel device which is incorporated into one of our two FDA-approved rapid HIV tests (See Lateral Flow HIV Tests above). SDS, pursuant to the settlement, is a party to the 3-way Barrel Agreement. As a result, until now, it is through the agreements with Alere that we have been participating in the growth of the rapid HIV test market in the United States. 
+In late July 2013, we received notice from Alere that it intends to commercialize its own rapid HIV test (see Competition), which test had just received FDA approval as a moderate complexity product (i.e. not CLIA-waived though this was granted in late 2014), in the United States. Under the Barrel Agreement and the Cassette Agreement such product is considered to be a Permitted Competing Product (PCP). Each of the two aforementioned agreements provides that, in the case of notice of a PCP, Chembio may make certain elections (jointly with SDS in the case of the Barrel Agreement), or elect to continue each agreement without taking any further action. Under the Cassette Agreement, Chembio may, at any time, terminate such agreement, which termination would become effective 60 days after the date notice was made. Under the Barrel Agreement, Chembio and SDS may jointly issue a non-exclusivity notice, which notice shall be effective immediately. In the event that Chembio (and SDS) makes this election with respect to either (or both) of these products, Chembio could sell that respective (or both) product(s) in the United States market under Chembio/SDS brands and in such case, the lateral flow license that Chembio has from Alere for international sales would be expanded to include sales in the United States. See Lateral Flow Technology and Reagent Licenses. In April 2014, the Company gave notice to Alere of its intent to terminate the Cassette Agreement and 60 days later, the Company began marketing in the United States under the Chembio brand of HIV 1/2 STAT-PAK® assay. The barrel product continues to be marketed exclusively by Alere in the U.S only. 
+We have developed our own sales and marketing departments for the sales of our products in the U.S. We have appointed distributors internationally for our lateral flow HIV tests. Our largest markets outside the U.S. for our lateral flow HIV rapid tests are certain countries in Africa, Asia, and South America, as well as Mexico. Internationally, most of the demand for our products is based on governmental and non-governmental prevention and treatment efforts. Given this, these programs can and do often result in large orders, but also can result in periods of relatively lower demand, based on the variations associated with this kind of demand. 
+7 
+OEM DPP® Products 
+Oswaldo Cruz Foundation OEM DPP® Agreements 
+During 2008-2010 we signed five separate agreements, each of which is titled and constitutes a "Technology Transfer Agreement", with the Oswaldo Cruz Foundation (FIOCRUZ) in Brazil. FIOCRUZ includes the Institute of Technology on Immunobiologicals/Bio- Manguinhos, which is the FIOCRUZ unit that produces vaccines and diagnostic kits. FIOCRUZ and Bio-Manguinhos are referred to herein interchangeably. Each of the five agreements relates to a different specific product or group of products based on our DPP® technology. FIOCRUZ is the leading public health organization in Brazil, and it is affiliated with Brazil's Ministry of Health, which is its principal client. It has extensive research, educational and manufacturing facilities for drugs and vaccines, as well as for diagnostic products. 
+Each of the agreements grants to FIOCRUZ the right, but not the obligation, to earn the right to request a technology transfer to be able to license and manufacture that product on its own. FIOCRUZ is not required to earn this right, but if it desires to do so, then it needs to purchase a stated amount of the product as set forth in the respective agreement for that product. 
+During 2010 and 2011, all of the initial products contemplated under the five agreements were approved for marketing by the applicable regulatory agencies in Brazil. The agreements between the Company and FIOCRUZ are unique examples of technology transfer collaborations between a private sector rapid test manufacturer and a public health organization. The five products categories for which FIOCRUZ can earn a separate right to request a technology transfer for that product only are: DPP® products for HIV screening, HIV Confirmatory, Leishmaniasis, Leptospirosis and Syphilis. Each technology transfer, and the provision by Chembio of the information and training that is required for this to occur, will occur only if FIOCRUZ purchases from Chembio the amount of that product that is specified in the respective agreement for that product. The actual amount of purchases for each product is totally at the discretion and option of FIOCRUZ and may be more or less than the amount needed to qualify for a technology transfer. 
+More specifically, the five agreements, although separate and independent of one another, are structurally similar according to the following: 
+· 
+Each agreement states: "the object of this Agreement is for the Transfer of Technology from Chembio to Bio-Manguinhos, the license by Chembio to Bio-Manguinhos [of] the Chembio Patents applied or granted in Brazil or other Mercosur countries for the term of the patents and the transfer of all the technical information related to the DPP technology and the process to obtain the product by the DPP® technology. This Agreement contemplates the scientific and technological co-operation between Chembio and Bio-Manguinhos for such activities so that Bio-Manguinhos will be able to manufacture the Product in Brazil." 
+· 
+Each agreement provides that Chembio will supply free of charge to Bio-Manguinhos prototypes of the product to demonstrate performance characteristics that are necessary for evaluation by the Brazilian Ministry of Health and for registration with ANVISA. ANVISA is the Agencia Nacional de Vigliancia Sanitaria, or the National Sanitary Vigilance Agency. The number of prototypes ranges from 15,000 to 45,000 in the various agreements. 
+· 
+Each agreement provides that the prototypes will be utilized both for a performance study that follows a protocol prepared and approved by Bio-Manguinhos and the Brazilian Ministry of Health, and also will be used for studies in Brazil for the registration procedures at ANVISA. Bio-Manguinhos will then apply to ANVISA to register the product. Within 120 days of the registration of the product with ANVISA, Bio-Manguinhos will make an advance technology transfer payment to Chembio (the "Advance Payment"), in an amount specified in that particular agreement. All five of the Advance Payments provided for in the agreements were made in 2010 and 2011. 
+· 
+At such time, if any, that the product for a particular agreement has been successfully registered with ANVISA, then Bio-Manguinhos has the right to qualify for the full technology transfer for that product by purchasing the amount of the product, and at the price, specified in the agreement. 
+· 
+Bio-Manguinhos is not required to purchase any amount of any product. For each product, it only needs to purchase that product, in the amount specified in the agreement, only if it desires to be able to complete the technology transfer process in order to manufacture and sell that product on its own. Chembio does not have recourse against Bio-Manguinhos if Bio-Manguinhos does not purchase the qualifying purchase amount of any product. In that case, Chembio can only suspend further phases of the technology transfer, attempt to renegotiate the agreement, and/or retain any amounts previously paid by Bio-Manguinhos. Chembio cannot force Bio-Manguinhos to purchase any amount of any product. 
+· 
+As a result of the terms of these agreements, Bio-Manguinhos has never been required to, and is not now required to, purchase any amount of any of the products. 
+· 
+As of December 31, 2014 Bio-Manguinhos had earned the status described below with respect to each of the five products: 
+1. 
+With respect to Chembio's DPP® HIV1/2 Screen test, Bio-Manguinhos had qualified to request the technology transfer. It has requested, and has received, the technology transfer information. Bio-Manguinhos purchased $880,175 of this product in 2011, and $4,990,840 in 2012, all of which applied to the qualifying amount to obtain the right to the technology transfer (the "Qualifying Amount") for this product. In 2013, Bio-Manguinhos made $291,235 of purchases that applied to the Qualifying Amount for this product, and $3,320,010 of purchases in excess of the Qualifying Amount. In 2014, Bio-Manguinhos made $4,799,250 of purchases in excess of the Qualifying Amount. 
+2. 
+With respect to Chembio's Canine Leishmania test, Bio-Manguinhos had qualified to request the technology transfer and did so request. Submission of the technology transfer information is in process at this time. Bio-Manguinhos purchased $2,000,817 of this product in 2011 and $99,183 of this product in 2012 that applied to the Qualifying Amount. In addition, Bio-Manguinhos made purchases in excess of the Qualifying Amount equal to $1,314,117 in 2012, $1,736,700 in 2013 and $2,394,000 in 2014. 
+3. 
+a. 
+With respect to the three variations of Chembio's DPP® Syphilis test, all of which are covered by a single agreement, Bio-Manguinhos had qualified to request the technology transfer with respect to Trep only, and intends to do so in the near future. Bio-Manguinhos purchased $1,194,250 of this product in 2011 and $165,750 of this product in 2012 that applied to the Qualifying Amount. In addition, Bio-Manguinhos made purchases in excess of the Qualifying Amount equal to $2,817,750 in 2012, $646,340 in 2013 and $4,617,891 in 2014. 
+b. 
+With respect to the two variations of Chembio's Screen & Confirm Test, Bio-Manguinhos had not made any purchases in 2011, 2012, 2013 or 2014, and therefore had not qualified to request the technology transfer for either of them. In order to qualify, Bio-Manguinhos would need to purchase an additional $2.2 million of one of these tests, and an additional $2.08 million of the other test. 
+4. 
+With respect to Chembio's DPP® Confirmatory test, Bio-Manguinhos had not qualified to request the technology transfer. Bio-Manguinhos made purchases of $560,000 of this product in 2011, $819,000 in 2012, $390,000 in 2013 and $390,000 in 2014, all of which applied to the Qualifying Amount. In order to qualify for the technology transfer, Bio-Manguinhos would need to purchase an additional $195,000 of this product. 
+5. 
+With respect to Chembio's DPP® Leptospirosis test, Bio-Manguinhos had not qualified to request the technology transfer. Bio-Manguinhos made purchases of $135,000 of this product in 2011, and it made -0- purchases in 2012, $45,000 in 2013 and it made -0- purchases in 2014. In order to qualify for the technology transfer, Bio-Manguinhos would need to purchase an additional $225,000 of this product. 
+8 
+· 
+As stated above, Bio-Manguinhos is not obligated to make any purchases. After the specified level of sales for a particular product has been achieved, FIOCRUZ may request that the technology for that product be transferred to FIOCRUZ together with an exclusive license to produce and sell that product in a defined territory. The license is to provide that Chembio will receive a royalty on all sales. Chembio does not release the amount of this royalty because it could have an adverse effect on negotiations concerning royalties in potential transactions with other parties. 
+· 
+All the agreements expire five years after the date of the technology transfer. If terminated earlier by default of FIOCRUZ, FIOCRUZ must stop all activity; if terminated earlier by default of Chembio, or if terminated by natural expiry, FIOCRUZ can continue to produce and commercialize the product without paying royalties. 
+Other OEM And License Agreements Related to DPP® Technology 
+In addition to our agreement with FIOCRUZ, we have entered into certain other OEM and License agreements with other parties with respect to certain products that we have developed based on our DPP® technology. In 2008 we entered into a product development and license agreement with Bio-Rad Laboratories, Inc. (Bio-Rad), a leading multinational life sciences company, for the first ever POC test for the confirmation of HIV (reflex test used after initial screening test(s) are positive). This product utilizes our DPP® technology, capitalizing on its multiplexing advantages, and is much simpler to perform than the legacy confirmatory platform, known as western blot, which requires a substantial amount of technical training and hands-on time and which is more expensive to manufacture and distribute. This product was CE marked and was launched by Bio-Rad in the second quarter of 2013 in Europe under their Geenius® brand; and an FDA PMA approval was received in 2014. 
+In 2013 we entered into collaboration with Labtest, a private company in Brazil, for the distribution of a number of products in Brazil that would be co-branded with Labtest and Chembio trademarks. Under this agreement, upon request from Labtest, for which there is no requirement, Chembio will sell the appropriate DPP® components to Labtest for further manufacture and assembly in Brazil. 
+In February 2014, Chembio entered into a technology transfer and license agreement with RVR Diagnostics SDN BHD ("RVR"), a privately-held company in Malaysia. The agreement supports Chembio's strategy of establishing a market presence in Asia, in collaboration with RVR as a licensee, distributor, and contract manufacturer. The agreements grant exclusive distribution rights to RVR in certain countries in the region and enable RVR to manufacture Chembio's DPP® HIV 1/2 Assay and DPP® HIV-Syphilis Assay and potentially other products developed by Chembio incorporating its patented DPP® technology, such as Dengue, as indicated in the DPP® Technology & Development section. 
+Our Rapid Test Technologies 
+All of our commercially available current products employ either in-licensed lateral flow technology or our own patented Dual Path Platform (DPP®) technology. Both lateral flow technology and DPP® allow the development of accurate, low cost, easy-to-perform, single-use diagnostic tests for rapid, visual detection of specific antigen-antibody complexes on a test strip. These formats provide a test that is simple (requires neither electricity nor expensive equipment for test execution or reading, nor skilled personnel for test interpretation), rapid (turnaround time approximately 15 minutes), safe (minimizes handling of potentially infected specimens), non-invasive (requires 5-20 micro liters of whole blood easily obtained with a finger prick, or alternatively, serum or plasma), stable (24 months at room temperature storage in the case of our HIV tests), and highly reproducible. 
+We believe that products developed using DPP® technology can provide superior diagnostic performance as compared with products that use lateral flow technology. The reason for this is that one of the major differences between the two platforms is that in DPP® samples are allowed to incubate with the target analyte in the test zone before introduction of the labeling reagent/conjugate, whereas in lateral flow, samples are combined with the labeling reagent to form a complex before coming in contact with the target analyte. We believe that this complex can compromise test performance. Also, because of the usage in DPP® of a separately connected sample strip, the control and delivery of sample material is substantially improved. This feature is critical in the development of multiplex tests, as well as tests that involve viscous sample material (such as oral fluid) that can be impeded when forced to combine with labeling reagents before migration on the test strip to the test zone area. 
+Multiplexing is significantly improved as a result of the design of DPP® and this provides a significant advantage. For example, the HIV confirmatory test we developed for Bio-Rad that is described above employs six different markers related to various epitopes of the HIV antigen. We have a number of other products in development, including those being developed in sponsored development programs that involve the use of multiple (e.g. eight) test bands. Although all of these products could be visually read, we can also use handheld and desktop readers with our DPP® products to objectively measure, quantify, record and report DPP® test results. Certain of the products we have and/or are developing incorporate some of these readers, and we are developing other products that may be used with or will require use of a reader. Also, platforms can incorporate labeling reagents that cannot be visually read except by employing a reader, such as fluorescence, though no products are currently utilizing such reagents. 
+We are pursuing additional capabilities and technologies that will complement our current product portfolio and business strategy. This activity includes pursing development, license or acquisition of diagnostic technologies that complement our existing platforms, proprietary biomarkers that can result in new product applications of our existing platforms, and new platforms that would complement our commercial strategy. 
+Target Markets 
+Rapid HIV Tests 
+A large percentage of individuals that are HIV positive worldwide are unaware of their status. Part of the reason for this is that even those that do get tested in public health settings will often not return or call back for their test results when samples have to be sent out to a laboratory which can take up to several days to process. The increased availability, greater efficacy and reduced costs for anti-retroviral treatments (ARVs) for HIV has increased the demand for testing, as the stigma associated with the disease is lessened, and the ability to resume normal activities is substantially improved, providing a positive message to those potentially infected. The impact that rapid HIV testing has had on prevention efforts has in turn increased the demand for testing, particularly by public health programs worldwide, which have also become more effective in reducing the number of annual new infections in many, but by no means, all high prevalence regions. 
+Despite less attention to HIV by the media as compared with prior years, there are still approximately 50,000 new diagnoses of HIV infection in the United States each year, according to the CDC. CDC estimates that approximately 1.1 million individuals in the U.S. are living with HIV, with an estimated 1 of 6 of these U.S. individuals, or almost 16%, unaware that they are infected. It is transmissions from these 250,000 infected people that are reported to account for the majority of all new infections per year. Part of the reason for this is that even those individuals that do get tested in public health settings will often not return or call back for their test results if their blood samples have to be sent out to and tested in a laboratory and then reported back, a process which can take up to several days to complete. Making more people aware of their HIV status at the point-of-care reduces the number of HIV transmissions. 
+Rapid HIV testing in the United States has now developed into an estimated 7.5 million test market at an average price of $10, or a total of $75 million. Public health programs, currently funded by grants distributed to states by the CDC, account for an estimated 45% of the market, with hospitals (40%) and doctor's offices (15%) comprising the other estimated market segments. Chembio's lateral flow rapid HIV tests, the cassette and barrel, together represent approximately a 25% share of this market. Orasure Technologies, Inc., which was the first FDA-approved rapid HIV test, has lost nearly half its market share, now estimated to be approximately 55%. Trinity Biotech has an estimated 15% market share and Biolytical Laboratories, Medmira and Bio-Rad share the remaining 5%. 
+9 
+In 2006, the outlook for HIV testing was given a big boost with the release by the CDC of new recommendations for HIV testing. These new CDC recommendations were/are that an HIV test should be given as a routine test like any other for all patients between 13 and 64 years of age, regardless of risk, with an opt-out screening option and focused testing procedural (pre- and post-test counseling) guidelines. Though not mandatory, gradual adoption in whole or in part of the 2006 CDC recommendations by a number of states continues to have an increasing impact. Finally, in 2013, the United States Preventive Services Task Force ("USPSTF") fully embraced these CDC routine HIV testing recommendations. This USPSTF recommendation, which was given an A grade under their recommendation grading system based on the benefits of this practice and the nearly 600,000 AIDS-related deaths in the United States, requires insurance coverage under the Affordable Care Act (the "ACA") as a preventive screening test without any co-payment required. We expect this to result in an increase in HIV testing in the United States in the coming years, which we believe will include point-of-care HIV testing utilizing the Company's products. Although as stated above currently most public health testing in the United States is funded by grants allocated to high prevalence areas by the CDC, we believe this will shift to an insurance-funded model under the ACA in the years to come, increasing the amount of testing done in doctor's offices and community health centers. 
+In the international market , we sell our products directly and through distributors to large screening programs overseen by ministries of health and NGOs, most but not all of which are funded by large bi-lateral and multi-lateral AIDS relief programs, the largest of which is the U.S. President's Emergency Plan for AIDS Relief (PEPFAR). Established by President George Bush as a 5-year $15 billion program in 2003, PEPFAR was reauthorized in 2008 and again in 2013. In 2012 PEPFAR directly supported HIV testing and counseling for more than 11 million pregnant women, and testing and counseling for more than 49 million people overall. The U.S. is also the first and largest donor to the Global Fund to Fight AIDS, Tuberculosis and Malaria. To date, the U.S. has provided more than $7 billion to the Fund. 
+In December 2013 President Obama signed into law the PEPFAR Stewardship and Oversight Act, which is the most recent reauthorization of PEPFAR. However, unlike the 2008 PEPFAR authorization, which authorized approximately $45 billion, the new law doesn't authorize a specific dollar amount for funding. Nevertheless it is widely anticipated that PEPFAR will continue to enjoy strong funding; the FY14 budget had $6 billion for global HIV/AIDS assistance, including $4 billion for PEPFAR. 
+Chembio, with its four U.S.-manufactured rapid HIV tests, all of which are FDA-approved, is recognized as a reputable and dependable supplier of high quality products that are available at reasonably competitive prices. As a result, certain of our products have been selected in the testing protocols in countries (national algorithms) that are large beneficiaries of PEPFAR and the Global Fund. As mentioned above, these programs can and do often result in large orders, but also can result in periods of relatively lower demand, based on the variations associated with this kind of demand. Also, even though the United States taxpayer is funding the largest share of global AIDS relief, U.S. companies do not receive any preference for these procurements, and therefore must compete with foreign suppliers that manufacture competitive products with lower costs, including those related to quality, regulatory, intellectual property, and costs of manufacturing. 
+Oral fluid testing is an established alternative to blood testing for diagnostic tests, including HIV tests. It is also often patient preferred, providing a more comfortable, less invasive test. In certain public health clinics, staffs choose not to handle blood specimens; thus, oral sample collection provides a viable alternative. The most well-established market for oral fluid HIV testing is the United States. Given the premium price required for an oral fluid test as compared with blood tests, the higher volume programs will not specify an oral fluid test. However, segments of these programs may want to have an oral fluid testing option, and certain programs that have greater resources may also choose to incorporate oral fluid testing into the testing protocol. 
+There is also now an over-the-counter market for HIV self-testing in the United States. Orasure Technologies Inc. received FDA approval for an over-the-counter (self-testing) version of its previously professional-market-approved (test performed on an individual by a health care professional) HIV test. The FDA approval was granted in July 2012, and Orasure has been investing heavily in developing this market. Initial results after over two years of marketing are well below expectations. The costs for such over-the-counter approval, including primarily the associated clinical trials, are estimated to be at least $5 million and they may take two to three years to complete, not to mention the cost of distribution. Orasure's initial results are not convincing of a large market, although this possibility remains. If it appears that there is an attractive market, we believe we are very well positioned to participate in this market. 
+Rapid HIV-Syphilis Test 
+There are significant risks relating to transmission of Syphilis from a pregnant mother to child, just as there are for transmission of HIV. Therefore we believe there is a significant opportunity to improve prevention efforts in pregnant mother to child transmission testing programs (PMTCT) that are currently not doing any or nearly enough testing for syphilis even though they are testing for HIV. In the United States, we believe there is also a significant need for this product in some of the highest HIV prevalence populations, such as among men that have sex with men (MSM), as data show high degrees of HIV and Syphilis co-infection in this segment of the population. 
+Marketing Strategy: 
+Our marketing strategy is to: 
+o 
+Market our DPP® HIV 1/2 Assay, HIV 1/2 STAT-PAK® Assay and future DPP® based new products in the US through our internal sales and marketing organization and selected channel partners (e.g., McKesson/PSS, Fisher Healthcare, Henry Schein, etc.). Chembio, following the June 2014 termination of the STAT-PAK® agreement with Alere, does not have to share any portion of the net sales proceeds for STAT-PAK® with Alere, except for the 8.5% lateral flow royalties which was applicable to the sales of the products only until February 2015 when the applicable lateral flow patent of Alere's expired. This decision resulted in incurring expenditures related to hiring sales representatives, establishing agreements and associated discounts with distributors, incurring advertising and marketing expenditures, warehousing, customer service and technical support. If Alere's new competitive product is indeed successful, our ability to retain a significant share of the market that has been established for our products may be enhanced by our having control of the marketing of our products, rather than having Alere sell our products. We are leveraging the same sales force for U.S. Sales of DPP® HIV 1/2 Assay. 
+o 
+We will support, review and assess the marketing and distribution efforts of our rapid HIV barrel test by Alere in the U.S. 
+o 
+Outside the U.S., we will market our products primarily through commercial collaborators and distribution partners. 
+o 
+Leverage our DPP® intellectual property and product development and manufacturing experience to continue creating new collaborations where Chembio can be the exclusive development and manufacturing partner supporting leading marketing organizations. 
+o 
+Establish strong distribution relationships for our Chembio-branded products in the U.S and abroad, and establish a direct sales and marketing organization that is focused in the public health market segment, and that utilizes distributors for other market segments, primarily the acute care market which, together with public health, are the main market segments for rapid HIV tests in the United States. We believe that creation of a Chembio public health brand and marketing organization is fundamental to the creation of shareholder value over the long term. 
+During 2014 we increased our commercial activities and efforts in Africa, Europe and Asia for our HIV tests and product pipeline. We believe these efforts will enable us to be more closely engaged with opportunities to engage with customers and partners and to participate in the national testing algorithms that are established and revised from time to time by countries that are beneficiaries of PEPFAR, Global Fund and/or other bilateral or multilateral donor funding. In Europe, where there are a larger percentage of HIV positive people unaware of their status than in the United States, we believe that there is an emerging public health outreach opportunity, and there are relatively few strong competitors that are CE-marked. Most recently we have established new sales and marketing positions in the Company to support our efforts to increase brand awareness globally and to lead our direct sales effort in the U.S. market. 
+10 
+Competition 
+The diagnostics industry is a multi-billion dollar international industry and is intensely competitive. Many of our competitors are substantially larger and have greater financial, research, manufacturing and marketing resources. 
+Industry competition in general is based on the following: 
+· 
+Scientific and technological capability; 
+· 
+Proprietary know-how; 
+· 
+The ability to develop and market products and processes; 
+· 
+The ability to obtain FDA or other required regulatory approvals; 
+· 
+The ability to manufacture products that meet applicable FDA requirements, (i.e. FDA's Quality System Regulations) (see Governmental Regulation section); 
+· 
+The ability to manufacture products cost-effectively; 
+· 
+Access to adequate capital; 
+· 
+The ability to attract and retain qualified personnel; and 
+· 
+The availability of patent protection. 
+We believe our scientific and technological capabilities and our proprietary know-how relating to our in-licensed lateral flow technology rapid tests and to our proprietary know-how related to our patented DPP® technology, particularly for the development and manufacture of tests for the detection of antibodies to infectious diseases such as HIV, are very strong. 
+Our ability to develop and market other products is in large measure dependent on our having additional resources and/or collaborative relationships. Some of our product development efforts have been funded on a project or milestone basis. We believe that our proprietary know-how in lateral flow technology and in our DPP® technology has been instrumental in our obtaining the collaborations we have and that we continue to pursue. We believe that the patent protection that we have with our DPP® technology enhances our ability to develop more profitable collaborative relationships and to license out the technology. However there are a number of competitive technologies used and/or seeking to be used in point-of-care settings. These technologies may be based on immunoassay principles such as the Company's products or other technologies, such as molecular-based technologies. 
+We launched our FDA-approved DPP® HIV 1/2 Assay, which test also can be used either oral fluid or blood samples, in the U.S. market under a Chembio brand in the fourth quarter of 2014. Orasure Technologies manufactures the only other rapid, oral fluid HIV test that is FDA-approved, and Orasure has enjoyed this position for approximately 10 years. Orasure has lost a significant share of this market as certain customers have been indifferent to using blood or oral fluid samples, because the blood tests, including those made/marketed by Chembio and marketed by Alere, are priced lower and/or are as or more accurate than the performance of Orasure's product on blood samples. Orasure has primarily retained those customers for whom the oral fluid sample feature is a strong preference, and this is an estimated $35 million business for Orasure. Although we believe we can capture a meaningful portion of this Orasure market share, we also anticipate that Orasure will defend this business aggressively. 
+In 2006 Alere acquired a division from Abbott Diagnostic located in Japan that manufactured and marketed a rapid HIV test product line called Determine®. The Determine® format is was developed for developing world and remote settings and, central to the needs of that market, the format is essentially a test strip that is integrated into a thin foil wrapper that, when opened, the underside of the wrapper serves as the test surface for applying the blood sample and performing the test. This design reduces costs and shipping weights and volumes and is an advantage for the developing world markets it has served. Some of the disadvantages of the platform are the amount of blood sample that is needed (50 microliters versus 2.5, 5 and 10 for our lateral flow barrel, lateral flow cassette, and DPP® products respectively), the open nature of the test surface, and the absence of a true control that differentiates biological from other kinds of samples. 
+The so-called "3 rd generation" version of this product has been marketed for many years and is the leading rapid HIV test that is used in a large majority of the national algorithms of countries funded by PEPFAR and the Global Fund, as well as many other countries in the world. That product is not FDA-approved though it is CE-marked. The newest Determine® HIV version, which was developed and manufactured at Alere's subsidiary in Israel, Orgenics, is the so-called "4 th Generation" version Determine® test. According to its claims, this product detects HIV antibodies and P24 HIV antigens. Since the P24 antigen is known to occur in HIV-positive individuals' blood samples before antibodies do, based on its performance claims, the 4 th generation Determine® test is therefore able to detect HIV infection earlier than tests that solely rely on antibody detection. Chembio's tests, as well as all of the other currently FDA-approved rapid HIV tests, only detect antibodies. There are however laboratory tests that are FDA-approved that are "4 th generation" tests, but they are of course neither rapid nor point-of-care. 
+11 
+The initial "4 th generation" Alere Determine® rapid test product that was also CE-marked and that Alere launched internationally some years ago has not been successfully commercialized to the best of our knowledge and at least certain published studies were not favorable for this product. However the 4 th generation product that is now FDA-approved was apparently modified as compared to the initial international version of it, and it may perform more satisfactorily. Alere received FDA approval of this modified product in August 2013 and CLIA-waiver for it in the fourth quarter of 2014. We believe the price that Alere is charging for this product may be substantially higher than our and our competitors' antibody tests, as the antigen claim avails some customers of an additional reimbursement code. Moreover there is support by a number of key opinion leaders for the public health value of such 4th generation tests, and if Alere is able to successfully launch this product, it represents a significant competitive threat to Chembio as well as to each of the other rapid HIV test manufacturers (Orasure and Trinity primarily). 
+During 2011 Biolytical, Inc. of Vancouver, Canada received FDA approval and in 2012 received CLIA waiver of a flow-through rapid HIV test called "INSTI". The technology used in the INSTI test, flow-through, is older than lateral flow, and it requires handling of multiple components (3 vials of solution) to perform the test in multiple steps. However, these steps can be accomplished in less than ten minutes, and the actual test results occur in only one minute after those steps are completed. Therefore sample-to-result time is shorter than any of the competitive products. There are settings where that reduced total test time, despite the multiple steps required, may be a distinct advantage, and we believe Biolytical has made some progress in penetrating certain public health markets. 
+Although we have no specific knowledge of any other competitors' products that are a competitive threat to our products, or that will render our products obsolete, if we fail to maintain and enhance our competitive position or fail to introduce new products and product features, our customers may decide to use the products developed by our competitors, which could result in a loss of revenues and cash flow. 
+Research and Development 
+During 2014 and 2013, we spent $4.8 million and $5.8 million, respectively, on research and development (including regulatory activities). These expenses were in part underwritten by funding from R&D and milestones revenues of $1.7 million in 2014 and $2.0 million in 2013. All of our new product development activities involve employment of our DPP® technology. These activities include completing development of certain products and making significant progress toward the development of additional products. 
+Employees 
+At December 31, 2014, we employed approximately 166 people. We have entered into employment contracts with our Chief Executive Officer and President, John J. Sperzel, our Chief Operating Officer, Sharon Klugewicz, and our Chief Science and Technology Officer, Javan Esfandiari. Due to the specific knowledge and experience of these executives regarding the industry, technology and market, the loss of the services of any one of them would likely have a material adverse effect on the Company. The contract with Ms. Klugewicz, has a term of two years ending May 2015. The contract with Mr. Esfandiari has a term of three years ending March 2016. We have obtained a key man insurance policy for Mr. Esfandiari. The contract with Mr. Sperzel provides that Mr. Sperzel will serve as the Chief Executive Officer and President of the Company through March 2017. 
+Governmental Regulation 
+The manufacturing and marketing of the Company's existing and proposed diagnostic products are regulated by the United States Food and Drug Administration ("FDA"), United States Department of Agriculture ("USDA"), certain state and local agencies, and/or comparable regulatory bodies in other countries. These regulations govern almost all aspects of development, production and marketing, including product testing, authorizations to market, labeling, promotion, manufacturing and record keeping. The Company's FDA and USDA regulated products require some form of action by each agency before they can be marketed in the United States, and, after approval or clearance, the Company must continue to comply with other FDA requirements applicable to marketed products, e.g. Quality Systems (for medical devices). Failure to comply with the FDA's requirements can lead to significant penalties, both before and after approval or clearance. 
+There are two review procedures by which medical devices can receive FDA clearance or approval. Some products may qualify for clearance under Section 510(k) of the Federal Food, Drug and Cosmetic Act, in which the manufacturer provides a pre-market notification that it intends to begin marketing the product, and shows that the product is substantially equivalent to another legally marketed product (i.e., that it has the same intended use and is as safe and effective as a legally marketed device and does not raise different questions of safety and effectiveness). In some cases, the submission must include data from human clinical studies. Marketing may commence when the FDA issues a clearance letter finding such substantial equivalence. FDA clearance of our DPP® Syphilis Screen & Confirm test will be by means of a 510(k) submission. 
+If the medical device does not qualify for the 510(k) procedure (either because it is not substantially equivalent to a legally marketed device or because it is required by statute and the FDA's implementing regulations have an approved application), the FDA must approve a Pre-Marketing Application ("PMA") before marketing can begin. PMA's must demonstrate, among other matters, that the medical device provides a reasonable assurance of safety and effectiveness. A PMA application is typically a complex submission, including the results of non-clinical and clinical studies. Preparing a PMA application is a much more expensive, detailed and time-consuming process as compared with a 510(K) pre-market notification. The Company has approved PMAs for the two rapid HIV tests now marketed by Alere Medical as Clearview® Complete HIV 1-2 and Clearview® HIV 1-2 STAT PAK®. 
+FDA approval of our DPP® HIV screening assay for use with oral fluid or blood samples was achieved by means of a PMA application. The Clinical Laboratory Improvement Act of 1988 ("CLIA") prohibits laboratories from performing in-vitro tests for the purpose of providing information for the diagnosis, prevention or treatment of any disease or impairment of, or the assessment of, the health of human beings unless there is in effect for such laboratories a certificate issued by the United States Department of Health and Human Services (via the FDA) applicable to the category of examination or procedure performed. Although a certificate is not required for the Company, it considers the applicability of the requirements of CLIA in the design and development of its products. The statutory definition of "laboratory" is very broad, and many of our customers are considered labs. A CLIA waiver will remove certain quality control and other requirements that must be met for certain customers to use the Company's products and this is critical to the marketability of a product into the point-of-care diagnostics market. The Company has received a CLIA waiver for each of the two lateral flow rapid HIV tests now marketed in the U.S. The CLIA waiver was granted by the FDA for HIV 1/2 STAT-PAK® on November 20, 2006 and for the Clearview® Complete HIV 1/2 on October 22, 2007. In 2008 the FDA revised its CLIA waiver requirements so that an additional prospective trial need be conducted in order to demonstrate clinical utility by showing that the device is capable of identifying new infections when used by untrained users. Our DPP® HIV 1/2 test received CLIA waiver in October of 2014. 
+In addition, the FDA regulates the export of medical devices that have not been approved for marketing in the United States. The Federal Food, Drug and Cosmetic Act contain general requirements for any medical device that may not be sold in the United States and is intended for export. Specifically, a medical device intended for export is not deemed to be adulterated or misbranded if the product: (1) complies with the specifications of the foreign purchaser; (2) is not in conflict with the laws of the country to which it is intended for export; (3) is prominently labeled on the outside of the shipping package that it is intended for export; and (4) is not sold or offered for sale in the United States. However, the Federal Food, Drug and Cosmetic Act does permit the export of devices to any country in the world, if the device complies with the laws of the importing country and has valid marketing authorization in one of several "listed" countries under the theory that these listed countries have sophisticated mechanisms for the review of medical devices for safety and effectiveness. 
+The Company is also subject to regulations in foreign countries governing products, human clinical trials and marketing, and may need to obtain approval or evaluations by international public health agencies, such as the World Health Organization, in order to sell diagnostic products in certain countries. Approval processes vary from country to country, and the length of time required for approval or to obtain other clearances may in some cases be longer than that required for United States governmental approvals. On the other hand, the fact that our HIV diagnostic tests are of value in the AIDS epidemic may lead to some government process being expedited. The extent of potentially adverse governmental regulation affecting Chembio that might arise from future legislative or administrative action cannot be predicted. 
+12 
+Environmental Laws 
+To date, we have not encountered any costs relating to compliance with any environmental laws. 
+Intellectual Property 
+Intellectual Property Strategy 
+Our intellectual property strategy is to: (1) build our own intellectual property portfolio around our DPP® technology; (2) pursue licenses, trade secrets and know-how within the area of rapid point-of-care testing, and (3) develop and acquire proprietary positions to reagents and new hardware platforms for the development and manufacture of rapid diagnostic tests. 
+The Company has obtained patent coverage on the DPP® technology, including four U.S. patents, and patents in China, Malaysia, Eurasia, Mexico, Singapore, Japan, Australia, Indonesia, Korea and the U.K. Additional patent applications on the DPP® technology are pending in the U.S., as well as in many foreign countries such as Brazil, Canada, the European Union, India, Israel, and South Africa. Patents have also been filed on extensions to the DPP® product line concept such as 4th generation assays. The four U.S. patents are as follows: 
+U.S. Patent No. 
+Issued 
+Expires 
+Nature 
+Type 
+Description 
+7,189,522 
+3/13/2007 
+3/11/2025 
+test device 
+utility 
+a test device for determining the presence 
+of a ligand in a sample 
+7,682,801 
+3/23/2010 
+3/11/2025 
+test device 
+and method 
+utility 
+a test device and a method for determining 
+the presence of a ligand in a sample 
+7,879,597 
+2/1/2011 
+3/11/2025 
+test device 
+utility 
+a test device for determining multiple 
+ligands in a sample 
+8,507,259 
+8/13/2013 
+3/11/2025 
+test device 
+utility 
+a test device for determining the 
+presence of a ligand in a sample 
+The Company also licenses a group of lateral flow technology patents from Alere. Our lateral flow products, which are primarily our STAT-PAK®, SURE CHECK®, and DIPSTICK® product lines, may incorporate methods that are claimed under one of the patents licensed from Alere that we use in our tests. That U.S. Patent #6,485,982 is also referred to as the Charlton patent, which patent expired on February 3, 2015. This patent describes a test device and method for a colored particle immunoassay that determines the presence of an analyte in a sample. 
+The Company has also filed for patents and obtained some patents in the U.S. for other inventions such as its multiple host species veterinary TB test, and patent applications for the other inventions are in various stages from being recently filed and not yet examined, to already examined and allowed but not yet issued. The Company selectively and strategically foreign files its patent applications based on a number of economic and strategic factors related to the invention. 
+Trademarks 
+The Company has filed and obtained trademarks for its products including DPP®, SURE CHECK® and STAT-PAK® and also for the SampleTainer® used in certain DPP® products. The DPP® trademark is also registered under the European convention (ECT). The Company recently filed a trademark for STAT-VIEW®, to market the barrel product in Europe. 
+Trade Secrets and Know-How 
+We believe that we have developed a substantial body of trade secrets and know-how relating to the development and manufacture of lateral flow and DPP® based diagnostic tests, including but not limited to the sourcing and optimization of materials for such tests, and how to maximize sensitivity, speed-to-result, specificity, stability and reproducibility. The Company possesses proprietary know-how to develop tests for multiple conditions using colored latex. Our buffer formulations enable extremely long shelf lives of our rapid HIV and other tests and we believe that this provides us with an important competitive advantage. 
+Lateral Flow Technology and Reagent Licenses 
+As part of the agreements executed in 2006 with Alere for the marketing of our HIV tests, we were granted non-exclusive licenses to certain lateral flow patents for certain products manufactured and marketed by Chembio including but not limited to our lateral flow HIV tests. This license allows us to produce, market and sell assays using lateral flow technologies specifically including our STAT-PAK®, SURE CHECK®, DIPSTICK®, and veterinary product lines. Under this license agreement, we pay royalties to Alere ranging from 5% to 8½%, depending upon the country in which the products are sold. Even though the relevant patent has expired in most other jurisdictions, or were never issued in markets where we have sold these products, our manufacture of the products in the United States has required that we pay royalties under this license, which has been a substantial expense. In 2014 our lateral flow royalty expense to Alere was $182,000, and since 2007 we have incurred a total of $2.83 million in lateral flow royalty expenses. As of February 3, 2015 this royalty expense was no longer payable as the applicable patent expires at that time. 
+Although we believe our DPP® is outside of the scope of all lateral flow patents of which we are aware, we consult with patent counsel, and seek licenses and/or redesigns of products that we believe to be in the best interests of the Company and our stockholders. Because of the costs and other negative consequences of time-consuming patent litigation, we often attempt to obtain a license on reasonable terms. Nevertheless there is no assurance that the Alere lateral flow patents we have licensed will not be challenged or that other patents containing claims relevant to the Company's lateral flow or DPP® products will not be granted to third parties and that licenses to such patents, will be available on reasonable terms, if any. In the past Alere has aggressively enforced its lateral flow intellectual property, although some of the main patents will expire within the next couple of years and we are not aware of any patent enforcement litigation that is ongoing with respect to the Alere lateral flow intellectual property. 
+Regardless, the DPP® technology provides us with our own intellectual property. We believe it provides us with a freedom to operate, and that it also enables tests to be developed with improved sensitivity as compared with comparable tests on lateral flow platforms. The Company has signed and anticipates signing new development projects based upon the DPP® technology that will provide new manufacturing and marketing opportunities. We have filed other patent applications that we believe will strengthen the DPP® intellectual property and have also filed for patent protection for certain other point-of-care technologies or applications thereof. 
+The peptides used in our rapid HIV tests were patented by Adaltis Inc. and were licensed to us under a 10-year non-exclusive license agreement dated August 30, 2002. However, in connection with Adaltis' bankruptcy, during the third quarter of 2009 we bought out all of our remaining obligations under that agreement. We also have licensed the antigens used in other tests including our Syphilis, Tuberculosis, Leptospirosis, Leishmaniasis and Chagas tests, and we may enter other license agreements. In prior years we concluded license agreements related to intellectual property rights owned by the United States associated with HIV- 1, and during the first quarter of 2008 we entered into a sub-license agreement for HIV-2 with Bio-Rad Laboratories N.A., the exclusive licensee of the Pasteur Institute's HIV-2 intellectual property estate. 
+13 
+Corporate History 
+On May 5, 2004, we completed a merger with Trading Solutions, Inc. through which Chembio Diagnostic Systems Inc. became our wholly-owned subsidiary, and through which the management and business of Chembio Diagnostic Systems Inc. became our management and business. As part of this transaction, we changed our name to Chembio Diagnostics, Inc. In 2003, we had sold our prior business, and as a result, we had no specific business immediately prior to the merger. 
+Since the formation of Chembio Diagnostic Systems Inc. in 1985, it has been involved in developing, manufacturing, selling and distributing in-vitro diagnostic tests, including rapid tests beginning in 1995, for a number of conditions in humans and animals. 
+On March 12, 2004, we implemented a 1-for-17 reverse split of our common stock. All references in this Form 10-K to shares of our common stock have been adjusted to reflect this reverse split. 
+On May 30, 2012, the Company effected a 1-for-8 reverse split of its common stock. This was done to allow the Company to move to the NASDAQ trading market from the OTCQB market, which occurred on June 7, 2012. As a result of the stock split, the outstanding 63,967,263 common shares were reduced to 7,995,918 outstanding common shares on May 30, 2012. The effect of this reverse stock split also has been retroactively reflected for all periods in these financial statements. 
+14 
+Glossary 
+AIDS 
+Acquired Immunodeficiency Syndrome. AIDS is caused by the Human Immunodeficiency Virus, HIV. 
+ALGORITHM (parallel or serial) 
+For rapid HIV testing this refers both to method or protocol (in developing countries to date) for using rapid tests from different manufacturers in combination to screen and confirm patients at the point-of-care, and may also refer to the specific tests that have been selected by an agency or ministry of health to be used in this way. A parallel algorithm uses two screening tests from different manufacturers and a tie-breaker test only if there is a discrepancy between the screening tests results. A serial algorithm only uses a second confirmatory test if there is a positive result from the screening test, meaning that the number of confirmatory tests used is equal to the positivity rate in the testing venue. A tie-breaker test resolves discrepancies between the screen and the confirmatory test. 
+ANTIBODY 
+A protein which is a natural part of the human immune system produced by specialized cells to neutralize antigens, including viruses and bacteria that invade the body. Each antibody producing cell manufactures a unique antibody that is directed against, binds to and eliminates one, and only one, specific type of antigen. 
+ANTIGEN 
+Any substance which, upon entering the body, stimulates the immune system leading to the formation of antibodies. Among the more common antigens are bacteria, pollens, toxins, and viruses. 
+ANVISA 
+The National Health Surveillance Agency of Brazil 
+ARVs 
+Anti-retroviral medications developed to fight AIDS 
+CDC 
+United States Centers for Disease Control and Prevention 
+CLIA waiver 
+Clinical Laboratory Improvement Act designation that allows simple tests to be performed in point-of-care settings such as doctor's offices, walk-in clinics and emergency rooms. 
+DIAGNOSTIC 
+Pertaining to the determination of the nature or cause of a disease or condition. Also refers to reagents or procedures used in diagnosis to measure proteins in a clinical sample. 
+FIOCRUZ 
+The Oswaldo Cruz Foundation of Brazil 
+FDA 
+United States Food and Drug Administration 
+IgG 
+IgG or Immunoglobulin are proteins found in human blood. This protein is called an "antibody" and is an important part of the body's defense against disease. When the body is attacked by harmful bacteria or viruses, antibodies help fight these invaders. 
+NGO 
+Non-Governmental Organization 
+OTC 
+Over-the-Counter 
+PEPFAR 
+The President's Emergency Plan for AIDS Relief 
+PMA 
+Pre-Marketing Approval –FDA approval classification for a medical device that is not substantially equivalent to a legally marketed device or is otherwise required by statute to have an approved application. Rapid HIV tests must have an approved PMA application before marketing of such a product can begin. 
+PROTOCOL 
+A procedure pursuant to which an immunodiagnostic test is performed on a particular specimen in order to obtain the desired reaction. 
+REAGENT 
+A chemical added to a sample under investigation in order to cause a chemical or biological reaction which will enable measurement or identification of a target substance. 
+RETROVIRAL 
+A type of virus which contains the enzyme Reverse Transcriptase and is capable of transforming infected cells to produce diseases in the host such as AIDS. 
+SENSITIVITY 
+Refers to the ability of an assay to detect and measure small quantities of a substance of interest. The greater the sensitivity, the smaller the quantity of the substance of interest the assay can detect. Also refers to the likelihood of detecting the antigen when present. 
+SPECIFICITY 
+The ability of an assay to distinguish between similar materials. The greater the specificity, the better an assay is at identifying a substance in the presence of substances of similar makeup. 
+USDA 
+U.S Department of Agriculture 
+WHO 
+World Health Organization 
+15
\ No newline at end of file
diff --git a/raw/filings/0001092662/2014/0001092662-15-000024/item13.txt b/raw/filings/0001092662/2014/0001092662-15-000024/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..69f66c69de0c5b5d5091d560ea4a3e07e8305a5d
--- /dev/null
+++ b/raw/filings/0001092662/2014/0001092662-15-000024/item13.txt
@@ -0,0 +1,24 @@
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE. 
+The executive officers of the Company are as follows: John J. Sperzel, president, chief executive officer and member of the board of directors of the Company, Sharon Klugewicz, chief operating officer, Richard J. Larkin, chief financial officer of the Company, and Javan Esfandiari, Chief Science and Technology Officer of the Company. 
+On February 25, 2013, the Company granted options to purchase the following numbers of shares of the Company's common stock set forth below to the executive officers of the Company named below. The exercise price for these options was the last traded market price for the Company's common stock on February 26, 2013, which was $5.56 per option. The options become exercisable on the effective date of the grant. Each option granted will expire and terminate, if not exercised sooner, upon the earlier to occur of (a) 30 days after termination of the employee's employment with the Company or (b) the fifth anniversary of the effective date of grant. 
+Name of Executive Officer 
+Number of Shares of Common Stock Options 
+Richard Bruce - Vice President of Operations 
+1,520 
+Javan Esfandiari – Executive Vice President of R&D 
+4,765 
+Tom Ippolito - Vice President of Regulatory Affairs, QA & QC 
+1,775 
+Richard J. Larkin – Chief Financial Officer 
+1,670 
+Lawrence A. Siebert – Chief Executive Officer 
+5,215 
+Michael Steele – Vice President of Sales and Marketing 
+785 
+Sharon Klugewicz – Vice President of QA/QC 
+630 
+The Company entered into an employment agreement effective March 5, 2013, with Mr. Esfandiari to continue as the Company's Senior Vice President of Research and Development for an additional term of three years through March 5, 2016. The Company also entered into an employment agreement effective May 22, 2013, with Ms. Klugewicz to serve as Chief Operating Officer for a term of two years. On March 13, 2014, Mr. Siebert, the former Chief Executive Officer, retired from the Company and entered into a six-month Consulting Agreement with the Company. On March 13, 2014, the Company entered into an employment agreement (the "Employment Agreement") with John J. Sperzel III to serve as its Chief Executive Officer beginning on March 13, 2014. See Item 11 for additional information. 
+Director Independence 
+Our common stock trades on the NASDAQ. Accordingly, we are subject to the corporate the governance standards of NASDAQ, which require, among other things, that the majority of the board of directors be independent. We define an "independent" director in accordance with the NASDAQ Global Market's requirements for independent directors. Under this definition, we have determined that each of Katherine Davis, Barbara DeBuono, Peter Kissinger, and Gary Meller currently qualify as independent directors. We do not list this "independent" definition on our internet website. 
+40
\ No newline at end of file
diff --git a/raw/filings/0001092662/2014/0001092662-15-000024/item9a.txt b/raw/filings/0001092662/2014/0001092662-15-000024/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..eb61983170d3ceaa5cf29362ea24d0d0dc98e344
--- /dev/null
+++ b/raw/filings/0001092662/2014/0001092662-15-000024/item9a.txt
@@ -0,0 +1,15 @@
+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+(a) Disclosure Controls and Procedures. Under the supervision and with the participation of our senior management, consisting of our chief executive officer and our chief financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), as of the end of the period covered by this report (the "Evaluation Date"). Based on that evaluation, the Company's management, including our chief executive officer and chief financial officer, concluded that as of the Evaluation Date our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports that we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. Our disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in our Exchange Act reports is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure. 
+Management's Annual Report on Internal Control Over Financial Reporting. The Company's management is responsible for establishing and maintaining an adequate system of internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f)). Our internal control over financial reporting is a process, under the supervision of our chief executive officer and chief financial officer, designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States. These internal controls over financial reporting processes include policies and procedures that: 
+a. 
+Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company; 
+b. 
+Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and 
+c. 
+Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance of achieving their control objectives. 
+In evaluating the effectiveness of our internal control over financial reporting, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Based on this evaluation, our Chief Executive and Chief Financial Officers concluded that our internal control over financial reporting was effective as of December 31, 2014. 
+This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. 
+Management's report was not subject to attestation by our registered public accounting firm pursuant to the rules of the Securities and Exchange Commission that permit the Company to provide only management's report in this annual report. 
+(b) Changes in Internal Control over Financial Reporting. There were no changes in our internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Rule 13a-15 or Rule 15d-15 under the Exchange Act that occurred during the Company's last fiscal quarter of the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
\ No newline at end of file
diff --git a/raw/filings/0001092662/2014/0001092662-15-000024/rp_note.txt b/raw/filings/0001092662/2014/0001092662-15-000024/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0001092662/2014/0001092662-15-000024/rpt_disclosure.txt b/raw/filings/0001092662/2014/0001092662-15-000024/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..69f66c69de0c5b5d5091d560ea4a3e07e8305a5d
--- /dev/null
+++ b/raw/filings/0001092662/2014/0001092662-15-000024/rpt_disclosure.txt
@@ -0,0 +1,24 @@
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE. 
+The executive officers of the Company are as follows: John J. Sperzel, president, chief executive officer and member of the board of directors of the Company, Sharon Klugewicz, chief operating officer, Richard J. Larkin, chief financial officer of the Company, and Javan Esfandiari, Chief Science and Technology Officer of the Company. 
+On February 25, 2013, the Company granted options to purchase the following numbers of shares of the Company's common stock set forth below to the executive officers of the Company named below. The exercise price for these options was the last traded market price for the Company's common stock on February 26, 2013, which was $5.56 per option. The options become exercisable on the effective date of the grant. Each option granted will expire and terminate, if not exercised sooner, upon the earlier to occur of (a) 30 days after termination of the employee's employment with the Company or (b) the fifth anniversary of the effective date of grant. 
+Name of Executive Officer 
+Number of Shares of Common Stock Options 
+Richard Bruce - Vice President of Operations 
+1,520 
+Javan Esfandiari – Executive Vice President of R&D 
+4,765 
+Tom Ippolito - Vice President of Regulatory Affairs, QA & QC 
+1,775 
+Richard J. Larkin – Chief Financial Officer 
+1,670 
+Lawrence A. Siebert – Chief Executive Officer 
+5,215 
+Michael Steele – Vice President of Sales and Marketing 
+785 
+Sharon Klugewicz – Vice President of QA/QC 
+630 
+The Company entered into an employment agreement effective March 5, 2013, with Mr. Esfandiari to continue as the Company's Senior Vice President of Research and Development for an additional term of three years through March 5, 2016. The Company also entered into an employment agreement effective May 22, 2013, with Ms. Klugewicz to serve as Chief Operating Officer for a term of two years. On March 13, 2014, Mr. Siebert, the former Chief Executive Officer, retired from the Company and entered into a six-month Consulting Agreement with the Company. On March 13, 2014, the Company entered into an employment agreement (the "Employment Agreement") with John J. Sperzel III to serve as its Chief Executive Officer beginning on March 13, 2014. See Item 11 for additional information. 
+Director Independence 
+Our common stock trades on the NASDAQ. Accordingly, we are subject to the corporate the governance standards of NASDAQ, which require, among other things, that the majority of the board of directors be independent. We define an "independent" director in accordance with the NASDAQ Global Market's requirements for independent directors. Under this definition, we have determined that each of Katherine Davis, Barbara DeBuono, Peter Kissinger, and Gary Meller currently qualify as independent directors. We do not list this "independent" definition on our internet website. 
+40
\ No newline at end of file
diff --git a/raw/filings/0001092662/2015/0001092662-16-000121/filing.txt b/raw/filings/0001092662/2015/0001092662-16-000121/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..6dcefaa4d37a2eec07b527f815750b42aa669577
--- /dev/null
+++ b/raw/filings/0001092662/2015/0001092662-16-000121/filing.txt
@@ -0,0 +1,3040 @@
+10-K
+1
+form10_k.htm
+FORM 10-K FOR 2014
+UNITED STATES 
+Securities and Exchange Commission 
+Washington, D.C. 20549 
+FORM 10-K 
+[X] 
+ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the fiscal year ended December 31, 2015 
+or 
+[ ] 
+TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the transition period from _______ to ______ . 
+Commission File No. 0-30379 
+CHEMBIO DIAGNOSTICS, INC. 
+(Exact name of registrant as specified in its charter) 
+Nevada 
+88-0425691 
+(State or other jurisdiction of incorporation or organization) 
+(I.R.S. Employer Identification No.) 
+3661 Horseblock Road, Medford, NY 
+11763 
+(Address of principal executive offices) 
+(Zip Code) 
+Registrant's telephone number, including area code (631) 924-1135 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of each class 
+Name of each exchange on which registered 
+None 
+None 
+Securities registered pursuant to section 12(g) of the Act: 
+Common Stock, $0.01 par value 
+(Title of Class) 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes __ No X 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes __ No X 
+Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No__ 
+Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes X No __ 
+Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. 
+Large accelerated filer [ ] 
+Accelerated filer [ ] 
+Non-accelerated filer [ ] 
+Smaller reporting company [X] 
+(Do not check if a smaller reporting company) 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes __ No _X_ 
+As of the last business day of the Company's most recently completed second fiscal quarter, the aggregate market value of voting and non-voting common equity held by non-affiliates* was $47,000,000. 
+As of March 2, 2015, the registrant had 9,628,248 common shares outstanding. 
+* Without asserting that any of the issuer's directors or executive officers, or the entities that own more than five percent of the outstanding shares of the Registrant's common stock, are affiliates, the shares of which they are beneficial owners have not been included in shares held by non-affiliates solely for this calculation. 
+TABLE OF CONTENTS 
+Page 
+PART I 
+ITEM 1. 
+BUSINESS 
+2 
+ITEM 1A. 
+RISK FACTORS 
+12 
+ITEM 2. 
+PROPERTIES 
+16 
+ITEM 3. 
+LEGAL PROCEEDINGS 
+16 
+ITEM 4 . 
+MINE SAFETY DISCLOSURES 
+16 
+PART II 
+ITEM 5. 
+MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+16 
+ITEM 6. 
+SELECTED FINANCIAL DATA 
+17 
+ITEM 7. 
+MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+18 
+ITEM 8. 
+FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+27 
+ITEM 9. 
+CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. 
+27 
+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+27 
+ITEM 9B. 
+OTHER INFORMATION 
+27 
+PART III 
+ITEM 10. 
+DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
+28 
+ITEM 11. 
+EXECUTIVE COMPENSATION 
+30 
+ITEM 12. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+33 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+35 
+ITEM 14. 
+PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+35 
+PART IV 
+ITEM 15. 
+EXHIBITS, FINANCIAL STATEMENT SCHEDULES 
+36 
+SIGNATURES 
+37 
+PART I 
+ITEM 1. 
+BUSINESS 
+FORWARD-LOOKING STATEMENTS 
+This report contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, and Section 27A of the Securities Act of 1933. Any statements contained in this report that are not statements of historical fact may be forward-looking statements. When we use the words "intends," "estimates," "predicts," "potential," "continues," "anticipates," "plans," "expects," "believes," "should," "could," "may," "will" or the negative of these terms or other comparable terminology, we are identifying forward-looking statements. Forward-looking statements involve risks and uncertainties, which may cause our actual results, performance or achievements to be materially different from those expressed or implied by forward-looking statements. These factors include our research and development activities, distributor channels, market demand for our products, compliance with regulatory impositions; and our capital needs. Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance or achievements. 
+Except as may be required by applicable law, we do not undertake or intend to update or revise our forward-looking statements, and we assume no obligation to update any forward-looking statements contained in this report as a result of new information or future events or developments. Thus, you should not assume that our silence over time means that actual events are bearing out as expressed or implied in such forward-looking statements. You should carefully review and consider the various disclosures we make in this report and our other reports filed with the Securities and Exchange Commission that attempt to advise interested parties of the risks, uncertainties and other factors that may affect our business. 
+We provide free of charge on our website at www.chembio.com our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable. Members of the public may read and copy any materials we file with the SEC at the SEC's Public Reference Room at 100 F Street, NE, and Washington, DC 20549. Members of the public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800–SEC–0330. The Internet address of the Commission is www.sec.gov. That website contains reports, proxy and information statements and other information regarding issuers, like Chembio, that file electronically with the Commission. Visitors to the Commission's website may access such information by searching the EDGAR database. 
+For further information about these and other risks, uncertainties and factors, please review the disclosure included in this report under "Part I, Item 1A, Risk Factors." 
+Our Business 
+General 
+The Company (Chembio Diagnostics, Inc. and its wholly-owned subsidiary Chembio Diagnostic Systems, Inc. are collectively referred to herein as the "Company") develops, manufactures, markets and licenses rapid point-of-care diagnostic tests (POCTs) that detect infectious diseases. The Company's main products presently commercially available are rapid tests for the detection of HIV 1/2 antibodies, and a multiplex rapid test for the detection of HIV and Syphilis antibodies. The HIV 1/2 rapid tests employ in-licensed and proprietary lateral flow technologies (see "Our Rapid Test Technologies"), can be used with all blood matrices as samples, and are manufactured in a standard cassette format, a dipstick format, and a proprietary barrel format. The tests employing the cassette and proprietary barrel formats were approved by the FDA in 2006. The barrel format is exclusively distributed by a distributor in the United States and by Chembio and its designated distributors outside the United States. The exclusive U.S. distribution agreement for the barrel product terminates in accordance with its terms on May 31, 2016. Chembio and any newly designated distributors will distribute the product in the U.S. after May 31, 2016. The Cassette format is distributed by Chembio and its designated distributors worldwide. Our latest generation HIV 1/2 rapid antibody detection test incorporates our patented Dual Path Platform® (DPP®) POCT technology, and this POCT platform does not require in-licensing. The DPP® HIV 1/2 Assay detects antibodies to HIV 1 & 2 in oral fluid samples as well as in all blood matrices. We have sold this product in Brazil since 2009 where it was approved by ANVISA, through our agreement with the Oswaldo Cruz Foundation ("FIOCRUZ"), and we received United States FDA regulatory approval for this product in December 2012 and CLIA waiver in October 2014. We launched it in the United States under Chembio's brand in the fourth quarter of 2014. 
+Our product pipeline, which currently includes a multiplex rapid test for earlier detection of HIV by detecting P-24 antigen as well as antibodies, a test for Hepatitis-C, and a multiplex test that detects HIV and Syphilis specific antibodies (which we are already selling outside the U.S.), is based on this DPP® technology for which we were issued a United States patent in 2007 and for which additional patent protection has issued or is pending in a number of other countries. With the patented DPP® and the lateral flow platform, we participate in the estimated $8 billion point-of-care market segment of the estimated nearly $50 billion global in-vitro diagnostic market that has an overall growth rate exceeding 3% per annum. POCTs, by providing prompt and early diagnosis, can reduce patient stays, lower overall costs, improve therapeutic interventions and improve patient outcomes. POCTs can also prevent needless hospital admissions, simplify testing procedures, avoid delays from central lab batching, and eliminate the need for return visits. 
+In the areas of infectious and sexually transmitted diseases (such as HIV and syphilis), the utility of a rapid point–of-care (POC) test, particularly in identifying patients unaware of their disease status, has been well established. Large and growing markets have been established for these kinds of tests, initially in high prevalence regions where they are indispensable for large scale prevention and treatment programs. More recently introduced in the United States in 2004, rapid HIV tests now also present a significant segment of the U.S. market for HIV clinical testing, which is still dominated by laboratory tests. We have focused our product development activity within areas where the availability of rapid, point-of-care screening, diagnostic, or confirmatory results can improve health outcomes. More generally we believe there is and will continue to be a growing demand for diagnostic products that can provide accurate, actionable diagnostic information in a rapid, cost-effective manner at the point of care. 
+PRODUCTS 
+Lateral Flow Rapid HIV Tests 
+All three of our lateral flow rapid HIV antibody detection tests are qualitative "yes/no" tests for the detection of antibodies to HIV 1 & 2 with visually interpreted results (one line "negative"; one line "positive") available within approximately 15 minutes. The tests are simple to use, have a shelf life of 24 months, and do not require refrigeration. The tests differ principally only in the method of test procedure, convenience and cost. One of our FDA-approved lateral flow HIV tests incorporates a proprietary plastic "barrel" device that houses the lateral flow strip. This barrel format enables collection of samples directly (usually from a finger-stick whole blood sample) into the barrel's capillary tip. A sealed unitized buffer vial, assembled onto the top of the barrel, is removed and seated into a stand; the seal is then pierced by the barrel's capillary tip, thereby initiating the upward flow of the resulting sample-buffer solution through a filter, up into the vertical device's chamber and onto the lateral flow strip. This results in a unique unitized and closed device system that can reduce the chance of exposure to potentially infectious samples. 
+In January 2015, the Company entered into an agreement with StatSure Diagnostic Systems, Inc. (SDS) to acquire SDS' interest in the barrel device format, also known as Chembio's SURE CHECK® HIV 1/2 Assay, effective June 1, 2016. Beginning June 1, 2016, Chembio will own full rights related to the SURE CHECK® HIV 1/2 Assay, including sales, marketing, distribution and trademark rights, subject to the terms of the existing marketing and distribution agreement with Alere, Inc., which grants Alere U.S. marketing and distribution rights through May 31, 2016. Prior to this newly-executed agreement between SDS and Chembio, SDS has owned a 50 percent interest in the rights to the SURE CHECK® HIV 1/2 Assay that would have continued after May 31, 2016, also subject to the existing marketing and distribution agreement with Alere. The new agreement with SDS also resolves all other matters between Chembio and SDS, including their respective sharing ratios, until June 1, 2016, concerning net revenues from sale of the SURE CHECK® product outside the U.S. 
+2 
+The Company's SURE CHECK® HIV 1/2 Assay is marketed exclusively in the U.S. as Clearview® Complete pursuant to an exclusive distribution agreement that terminates in accordance with its terms on May 31, 2016. After May 31, 2016, it will be marketed in the U.S. as Sure Check® HIV 1/2 Assay. Outside the U.S., Chembio markets the SURE CHECK® HIV 1/2 Assay primarily through distributors. The SURE CHECK® HIV 1/2 Assay is Food & Drug Administration (FDA) approved, CLIA-waived, European CE-marked, and has been pre-qualified by the World Health Organization (WHO). Results are obtained in 15 minutes via a 2.5uL blood sample (i.e., fingerstick, serum, plasma, or venipuncture whole blood). The assay is stable at room temperature and provides 99.7% sensitivity and 99.9% specificity. 
+Our other FDA-approved lateral flow HIV test uses a more conventional rectangular plastic cassette format that houses the lateral flow strip. In this case, a sample is transferred by use of a separately provided transfer device ("loop") into a sample well or port of the cassette that houses the lateral flow strip, which is positioned horizontally or flat. 
+Our third lateral flow HIV test, the HIV 1/2 STAT PAK® Dipstick, is our most cost competitive and compact format. It does not have any plastic housing so that 30 test strips can be packaged into a small vial that is ideal for transporting into remote settings. The test procedure is similar to the cassette format except that a user-applied adhesive backing is provided as a more cost-effective and compact "surface" on which to run the test. 
+Regulatory Status of the lateral flow HIV tests 
+The FDA approved our Pre-Market Applications (hereinafter "PMA"; see "Governmental Regulations" and Glossary) in April 2006 for our SURE CHECK® HIV 1/2 (and also now Alere Clearview® Complete HIV 1/2) and for our HIV 1/2 STAT-PAK® products. Waivers under the Clinical Laboratory Improvement Act (hereinafter "CLIA"; see Governmental Regulations) were granted by the FDA for these two FDA-approved products in 2006 and 2007, respectively. A CLIA waiver is required in order for health care providers to administer these tests in the settings where they are most suited and needed, such as public health testing clinics, hospital emergency rooms and physicians' offices. The SURE CHECK® and HIV 1/2 STAT-PAK® products received CE Marks in July 2013 and March 2014, respectively, and the CE Marking for the DPP® HIV 1/2 Assay received in May 2015. We have also updated our filing for CE Marking to reflect the new tradename of STAT-VIEW® HIV 1 / 2 Assay for sale in the EU market. Our HIV 1/2 STAT-PAK® Dipstick, although not FDA-approved, qualifies under FDA export regulations [See Government Regulation] to sell to customers outside the United States, subject to any required approval by the importing country. CE Mark has not been pursued for this product. 
+All three of our lateral flow HIV tests have qualified for procurement under the President's Emergency Plan for AIDS Relief ("PEPFAR"). The cassette and dipstick versions of the STAT-PAK® and the SURE CHECK® assays are also pre-qualified by the World Health Organization (WHO) for procurements by the second largest global program, known as the Global Fund, as well as other related programs funded by agencies affiliated with the United Nations, such as UNICEF and UNITAIDS (see Glossary), through qualification with the WHO bulk procurement scheme. 
+DPP® HIV 1/2 Assay 
+As in the case of our lateral flow HIV tests, our DPP® HIV 1/2 Assay is also a qualitative "yes/no" test for the detection of antibodies to HIV 1& 2, delivers visual results within as little as 15 minutes, is simple to use, has a shelf life of 23 months, and does not require refrigeration. This product, which is our first FDA-approved product incorporating our patented DPP® technology, can be used with oral fluid samples, as well as with all blood matrices. This product also incorporates our patent-pending oral fluid collection and storage system that enables samples to be fully extracted in buffer solution before application to the test device, and also enables the extracted sample to be stored and retested or potentially tested for multiple conditions in future product applications. Clinical and laboratory studies demonstrated the ability of the test to accurately detect the presence of antibodies in individuals down to two years of age. Studies have also shown this product to have improved performance compared with all of the current FDA-approved CLIA-waived lateral flow rapid tests, even including our own lateral flow tests. FDA-approved label claims include sensitivity/specificity on oral fluid and finger-stick whole blood of 98.9%/99.9% and 99.9%/100% respectively. Oral fluid sensitivity was 100% among HIV-positive patients not taking anti-retroviral medication. 
+Regulatory Status of the DPP® HIV 1/2 Assay 
+In December 2012, we received FDA approval of our Pre-Marketing Approval. In October of 2014 the FDA granted CLIA-waiver status. 
+The DPP® HIV 1/2 Assay product is qualified for procurement under the President's Emergency Plan for AIDS Relief ("PEPFAR") for use with all sample matrices, and we are pursuing WHO qualification in order to enable procurement of this product by the Global Fund and United Nations agencies, including programs underwritten by them. In October 2014, we completed a three-day on-site inspection by the WHO as follow-up to pre-qualification activities of our products with no major non-conformances noted during the audit. The WHO laboratory evaluation for the blood matrix is complete, while oral fluid is in progress and expected to be complete in 2016. In May 2015 we received approval for a CE Mark for the DPP® HIV 1/2 Assay for Oral Fluid, Serum, Plasma, Fingerstick Whole Blood and Venous Whole Blood. 
+In June 2010, ANVISA approved the DPP® HIV 1/2 Assay that is being marketed in Brazil through our collaboration with the Oswaldo Cruz Foundation, Brazil's leading public health institute (see Oswaldo Cruz Foundation OEM DPP® Agreements). Since this time, we have sold and marketed millions of DPP® HIV tests to Brazil through this partnership. 
+DPP® HIV-Syphilis Multiplex Test 
+This product, launched in 2013, allows for the detection of antibodies to both HIV and Syphilis on a single test device within approximately 15 minutes. In certain global/public health settings (see Target Markets), this product may provide a more convenient and cost-effective means of rapid detecting both markers in a single test procedure at the point of care as compared with performing separate rapid tests for each indication. This product takes advantage of the multiplexing feature of DPP® which provides for a more robust reaction between the sample and biomarkers being tested for (HIV and Syphilis antibodies in this case), resulting in a greater ability by the user to visually interpret test results. We launched this product in Mexico in the fourth quarter of 2013 as a unitized product, meaning that each test kit was separately packaged to include each of the other components necessary to run this test, as compared with other configurations where a test kit of 20 or 30 devices is accompanied by one bottle of running buffer. The initial results of this launch have been very positive, and we experienced good results in Mexico during 2014 from the program. Building on this initial success, we continue to pursue commercialization efforts for this product in a number of additional international markets, where there is a great need to detect Mother-to-Child-Transmission of HIV and Syphilis globally. According to the CDC website, "approximately 370,000 babies are born with HIV, mostly in sub-Saharan Africa. Without treatment, more than half of these children will die before the age of 2. Through key interventions, such as routinely testing pregnant women for HIV, providing antiretroviral medications to HIV-infected pregnant women and their exposed infants, and promoting safe infant feeding practices, mother-to-child transmission of HIV can be decreased from about 35% to less than 5%. Another prominent cause of infant mortality is untreated maternal syphilis, which still accounts for more than 500,000 stillbirths and infant deaths annually despite the fact that these deaths could be prevented through routine detection and treatment of syphilis during antenatal care". 
+Regulatory Status of the DPP® HIV-Syphilis Test 
+DPP® HIV-Syphilis – We have developed this product for international and U.S. marketing. For the international market, the product has been registered in Mexico, and successfully launched and sold in this region. 
+In February 2015, this product was granted approval from the Brazilian ANVISA. We have submitted this product both for evaluation by the CDC, acting on behalf of the United States Agency of International Development, and the WHO, which has accepted this product to be evaluated for pre-qualification in its global procurement scheme. In October 2014, WHO conducted a three-day audit of our facilities as follow up to pre-qualification activities for the DPP HIV-Syphilis Assay, including other products submitted for pre-qualification through WHO. No major non-conformances were identified during this audit, and we continue to work with WHO to obtain pre-qualification approval status for this device. 
+We are developing a U.S. version of the DPP® HIV-Syphilis Assay, designed to meet the performance requirements for the "reverse" algorithm that is currently in clinical use for syphilis testing in the United States. We have completed our pre-clinical studies for this product with encouraging results, and are in the final stages of clinical site selection for our U.S. clinical studies. We plan to begin this clinical trial in the U.S. during first quarter of 2016, and expect that the trial will be completed in six to nine months from initiation. 
+3 
+DPP® TECHNOLOGY & DEVELOPMENT 
+Chembio is executing its strategy to leverage the DPP® intellectual property and product development and manufacturing experience to create new collaborations where Chembio serves as an exclusive development and manufacturing partner. Examples of such collaboration include the following: 
+· 
+The Company entered into an agreement to develop a POC diagnostic test for dengue fever virus, the DPP® Dengue Fever Assay, which would be able to detect IgG/IGM and NS1 antigens in October 2014. 
+· 
+A collaboration also announced in October 2014, with an international diagnostics company to develop a POC diagnostic test for the early detection and monitoring of a specific type of cancer. At that time, the cancer project represented the first application of the DPP® technology outside the infectious disease field. 
+· 
+The Company entered into a follow-on, milestone-based development agreement with a private contracting organization acting on behalf of the United States Centers for Disease Control and Prevention (CDC), for a multiplex POC influenza immunity test utilizing Chembio's patented Dual Path Platform (DPP® ) technology. 
+· 
+In January 2015, Chembio entered into an agreement with the Concussion Science Group (CSG) Division of Perseus Science Group LLC, to utilize Chembio's patented DPP® technology to develop a POC diagnostic test for traumatic brain injury (TBI), including sports-related concussion. Under terms of the agreement, CSG's patented biomarker will be combined with Chembio's proprietary DPP® platform to develop a semi-quantitative or quantitative point-of-care test to diagnose TBI. CSG agreed to pay Chembio milestone development payments during 2015. 
+· 
+In January 2015, Chembio was awarded a grant from The Bill & Melinda Gates Foundation to expedite the feasibility testing and development of a DPP® Malaria POC rapid diagnostic to accurately identify individuals infected with Plasmodium falciparum parasite. Chembio's DPP® technology was selected for this grant due to its exceptional sensitivity and potential to aid the foundation in its goal of eradicating malaria. To achieve this goal, diagnostics must be capable of detecting the malaria parasite in infected, but asymptomatic, people. Current POC rapid diagnostics tests lack sufficient sensitivity to identify all individuals with transmissible infections. 
+· 
+In October 2015, Chembio was awarded a grant from the Paul G. Allen Foundation to develop a POC test to identify multiple life-threatening febrile illnesses. Under the $2.1 million dollar grant, Chembio will use its patented DPP® technology to develop a DPP® Fever Panel Assay, a POC multiplex assay to simultaneously detect Malaria, Dengue, Ebola, Lassa and Marburg. The multiplex assay that is planned to be designed to include a quality control test band and seven tests bands with specific antibodies to detect different pathogens, including multiple serotypes of the same pathogen: Malaria PAN-PLDH antigen (Plasmodium falciparum, Plasmodium vivax, Plasmodium malariae, Plasmodium ovale), Malaria Falciparum HRP2 antigen, Ebola Virus PAN (Zaire, Sudan, Bundibugyo Virus), Marburg Virus, Lassa Virus, Dengue Virus (Dengue 1, Dengue 2, Dengue 3, Dengue 4) and Chikungunya Virus. In many parts of the world, these diseases are commonly misdiagnosed, resulting in a delay of treatment or failure to properly treat the underlying infection. Misdiagnosis may be due to the fact that these diseases have similar symptoms that are difficult to distinguish. Currently available POC diagnostics lack the ability to test for multiple diseases simultaneously. Further, existing POC diagnostics may lack the sensitivity and specificity required to detect infected but asymptomatic patients - information that is critical for preventing the spread of disease. 
+· 
+Also in October 2015, Chembio signed an agreement with opTricon (Berlin, Germany), a leading developer of mobile analysis devices for rapid diagnostic tests. Through this exclusive agreement, subject to certain terms, and covering the fields of sexually transmitted diseases, certain "fever" diseases, and a specific form of cancer, Chembio will launch the DPP® Micro Reader, a point-of-care instrument designed specifically to complement Chembio's patented DPP® technology as applied to those diseases. The DPP® Micro Reader will include an innovative image sensor to provide a quantitative interpretation of diagnostic results when combined with Chembio's proprietary DPP® immunoassay technology. Using a state-of-the-art camera system, the DPP® Micro Reader is designed to provide definitive diagnostic results for low analyte concentrations, which may otherwise result in faint or ambiguous test results. In addition, the DPP® Micro Reader will provide customers with various options to capture, record, transmit and store test results. With one-button operation, the palm-sized and battery-operated DPP® Micro Reader is simple, fast, portable and cost-effective. 
+PARTNERS INVOLVED IN MARKETING OUR PRODUCTS 
+Alere 
+On September 29, 2006, we executed marketing and license agreements with Alere. The marketing agreements (the Barrel Agreement and the Cassette Agreement) provide Alere with a 10-year exclusive right (until May 31, 2016) to market our rapid HIV tests in the United States under Alere's brands. The agreements also provide Chembio a non-exclusive license to certain Alere lateral flow patents that may be applicable to our lateral flow products, including for manufacture of the HIV tests in the United States for sales outside the United States and even for sale in the United States should Alere enter the U.S. market with a competitive rapid HIV test product and in such case we choose to market our products directly as provided in the agreements in such event of a competitive rapid HIV test product. Simultaneous with the execution of the agreements, we also settled litigation with StatSure Diagnostics, Inc. (SDS), that had been ongoing relating to the proprietary barrel device which is incorporated into one of our two FDA-approved rapid HIV tests (See Lateral Flow HIV Tests above). SDS, pursuant to the settlement, is a party to the 3-way Barrel Agreement. As a result, until now, it is through the agreements with Alere that we have been participating in the growth of the rapid HIV test market in the United States. 
+In late July 2013, we received notice from Alere that it intends to commercialize its own rapid HIV test (see Competition), which test had just received FDA approval as a moderate complexity product (i.e. not CLIA-waived though this was granted in late 2014), in the United States. Under the Barrel Agreement and the Cassette Agreement such product is considered to be a Permitted Competing Product (PCP). Each of the two aforementioned agreements provides that, in the case of notice of a PCP, Chembio may make certain elections (jointly with SDS in the case of the Barrel Agreement), or elect to continue each agreement without taking any further action. Under the Cassette Agreement, Chembio may, at any time, terminate such agreement, which termination would become effective 60 days after the date notice was made. Under the Barrel Agreement, Chembio and SDS may jointly issue a non-exclusivity notice, which notice shall be effective immediately. In the event that Chembio makes this election with respect to the cassette product, or that both Chembio and SDS make this election with respect to the cassette product, then the electing party or parties could sell that respective product in the United States market under its own brand, and in such case, the lateral flow license that Chembio has from Alere for international sales would be expanded to include sales in the United States. See Lateral Flow Technology and Reagent Licenses. In April 2014, the Company gave notice to Alere of its intent to terminate the Cassette Agreement and 60 days later, the Company began marketing in the United States under the Chembio brand of HIV 1/2 STAT-PAK® assay. The barrel product continues to be marketed exclusively by Alere in the U.S only, although on May 31, 2016, the Barrel Agreement will expire pursuant to its terms, and Chembio will also market the barrel product in the U.S. under the brand of SureCheck® HIV 1/2 Assay. 
+We have developed our own sales and marketing departments for the sales of our products in the U.S. We have appointed distributors internationally for our lateral flow HIV tests. Our largest markets outside the U.S. for our lateral flow HIV rapid tests are certain countries in Africa, Asia, and South America, as well as Mexico. Internationally, most of the demand for our products is based on governmental and non-governmental prevention and treatment efforts. Given this, these programs can and do often result in large orders, but also can result in periods of relatively lower demand, based on the variations associated with this kind of demand. 
+4 
+OEM DPP® Products 
+Oswaldo Cruz Foundation OEM DPP® Agreements 
+During 2008-2010 we signed five separate agreements, each of which is titled and constitutes a "Technology Transfer Agreement", with the Oswaldo Cruz Foundation (FIOCRUZ) in Brazil. FIOCRUZ includes the Institute of Technology on Immunobiologicals/Bio- Manguinhos, which is the FIOCRUZ unit that produces vaccines and diagnostic kits. FIOCRUZ and Bio-Manguinhos are referred to herein interchangeably. Each of the five agreements relates to a different specific product or group of products based on our DPP® technology. FIOCRUZ is the leading public health organization in Brazil, and it is affiliated with Brazil's Ministry of Health, which is its principal client. It has extensive research, educational and manufacturing facilities for drugs and vaccines, as well as for diagnostic products. 
+Each of the agreements grants to FIOCRUZ the right, but not the obligation, to earn the right to request a technology transfer to be able to license and manufacture that product on its own. FIOCRUZ is not required to earn this right, but if it desires to do so, then it needs to purchase a stated amount of the product as set forth in the respective agreement for that product. 
+During 2010 and 2011, all of the initial products contemplated under the five agreements were approved for marketing by the applicable regulatory agencies in Brazil. The agreements between the Company and FIOCRUZ are unique examples of technology transfer collaborations between a private sector rapid test manufacturer and a public health organization. The five products categories for which FIOCRUZ can earn a separate right to request a technology transfer for that product only are: DPP® products for HIV screening, HIV Confirmatory, Leishmaniasis, Leptospirosis and Syphilis. Each technology transfer, and the provision by Chembio of the information and training that is required for this to occur, will occur only if FIOCRUZ purchases from Chembio the amount of that product that is specified in the respective agreement for that product. The actual amount of purchases for each product is totally at the discretion and option of FIOCRUZ and may be more or less than the amount needed to qualify for a technology transfer. 
+More specifically, the five agreements, although separate and independent of one another, are structurally similar according to the following: 
+· 
+Each agreement states: "the object of this Agreement is for the Transfer of Technology from Chembio to Bio-Manguinhos, the license by Chembio to Bio-Manguinhos for the Chembio Patents applied or granted in Brazil or other Mercosur countries for the term of the patents and the transfer of all the technical information related to the DPP® technology and the process to obtain the product by the DPP® technology. This Agreement contemplates the scientific and technological co-operation between Chembio and Bio-Manguinhos for such activities so that Bio-Manguinhos will be able to manufacture the Product in Brazil." 
+· 
+Each agreement provides that Chembio will supply free of charge to Bio-Manguinhos prototypes of the product to demonstrate performance characteristics that are necessary for evaluation by the Brazilian Ministry of Health and for registration with ANVISA. ANVISA is the Agencia Nacional de Vigilancia Sanitaria, or the National Sanitary Vigilance Agency. The number of prototypes ranges from 15,000 to 45,000 in the various agreements. 
+· 
+Each agreement provides that the prototypes will be utilized both for a performance study that follows a protocol prepared and approved by Bio-Manguinhos and the Brazilian Ministry of Health, and also will be used for studies in Brazil for the registration procedures at ANVISA. Bio-Manguinhos will then apply to ANVISA to register the product. Within 120 days of the registration of the product with ANVISA, Bio-Manguinhos will make an advance technology transfer payment to Chembio (the "Advance Payment"), in an amount specified in that particular agreement. All five of the Advance Payments provided for in the agreements were made in 2010 and 2011. 
+· 
+At such time, if any, that the product for a particular agreement has been successfully registered with ANVISA, then Bio-Manguinhos has the right to qualify for the full technology transfer for that product by purchasing the amount of the product, and at the price, specified in the agreement. 
+· 
+Bio-Manguinhos is not required to purchase any amount of any product. For each product, it only needs to purchase that product, in the amount specified in the agreement, only if it desires to be able to complete the technology transfer process in order to manufacture and sell that product on its own. Chembio does not have recourse against Bio-Manguinhos if Bio-Manguinhos does not purchase the qualifying purchase amount of any product. In that case, Chembio can only suspend further phases of the technology transfer, attempt to renegotiate the agreement, and/or retain any amounts previously paid by Bio-Manguinhos. Chembio cannot force Bio-Manguinhos to purchase any amount of any product. 
+· 
+As a result of the terms of these agreements, Bio-Manguinhos has never been required to, and is not now required to, purchase any amount of any of the products. 
+· 
+As of December 31, 2015 Bio-Manguinhos had earned the status described below with respect to each of the five products: 
+1. 
+With respect to Chembio's DPP® HIV1/2 Screen test, Bio-Manguinhos had qualified to request the technology transfer. It has requested, and has received, the technology transfer information. Bio-Manguinhos purchased $880,175, $4,990,840 and $291,235 of this product in 2011, 2012 and 2013, respectively, all of which applied to the qualifying amount to obtain the right to the technology transfer (the "Qualifying Amount") for this product. In 2013, 2014 and 2015, Bio-Manguinhos made $3,320,010, $4,799,250 and $5,410,350, respectively, of purchases in excess of the Qualifying Amount. 
+2. 
+With respect to Chembio's Canine Leishmania test, Bio-Manguinhos had qualified to request the technology transfer and did so request. Submission of the technology transfer information is in process at this time. Bio-Manguinhos purchased $2,000,817 and $99,183 of this product in 2011 and 2012 respectively, of this product in that applied to the Qualifying Amount. In addition, Bio-Manguinhos made purchases in excess of the Qualifying Amount equal to $1,314,117, $1,736,700, $2,394,000 and $3,772,482 in 2012, 2013, 2014 and 2015, respectively. 
+5 
+3. 
+a. 
+With respect to the three variations of Chembio's DPP® Syphilis test, all of which are covered by a single agreement, Bio-Manguinhos had qualified to request the technology transfer with respect to Trep only, and intends to do so in the near future. Bio-Manguinhos purchased $1,194,250, $165,750 of this product in 2011 and 2012, respectively that applied to the Qualifying Amount. In addition, Bio-Manguinhos made purchases in excess of the Qualifying Amount equal to $2,817,750, $646,340, $4,617,891 and $833,631 in 2012, 2013, 2014 and 2015, respectively. 
+b. 
+With respect to the two variations of Chembio's Screen & Confirm Test, Bio-Manguinhos had not made any purchases in 2011, 2012, 2013, 2014 or 2015, and therefore had not qualified to request the technology transfer for either of them. This agreement was terminated in December 2015. 
+c. 
+This syphilis agreement was terminated during the fourth quarter of 2015. 
+4. 
+With respect to Chembio's DPP® Confirmatory test, Bio-Manguinhos had not qualified to request the technology transfer. Bio-Manguinhos made purchases of $560,000, $819,000, $390,000, $390,000 and $156,000 of this product in 2011, 2012, 2013, 2014 and 2015 respectively, all of which applied to the Qualifying Amount. In order to qualify for the technology transfer, Bio-Manguinhos would need to purchase an additional $39,000 of this product. 
+5. 
+With respect to Chembio's DPP® Leptospirosis test, Bio-Manguinhos had not qualified to request the technology transfer. Bio-Manguinhos made purchases of $135,000 of this product in 2011, and it made -0- purchases in 2012, $45,000 in 2013 and it made -0- purchases in 2014 and -0- in 2015. In order to qualify for the technology transfer, Bio-Manguinhos would need to purchase an additional $225,000 of this product. 
+· 
+As stated above, Bio-Manguinhos is not obligated to make any purchases. After the specified level of sales for a particular product has been achieved, FIOCRUZ may request that the technology for that product be transferred to FIOCRUZ together with an exclusive license to produce and sell that product in a defined territory. The license is to provide that Chembio will receive a royalty on all sales. Chembio does not release the amount of this royalty because it could have an adverse effect on negotiations concerning royalties in potential transactions with other parties. 
+· 
+All the agreements expire five years after the date of the technology transfer. If terminated earlier by default of FIOCRUZ, FIOCRUZ must stop all activity; if terminated earlier by default of Chembio, or if terminated by natural expiry, FIOCRUZ can continue to produce and commercialize the product without paying royalties. 
+Other OEM And License Agreements Related to DPP® Technology 
+In addition to our agreements with FIOCRUZ, we have entered into certain OEM and license agreements with other parties with respect to certain products that we have developed based on our DPP® technology. In 2008 we entered into a product development and license agreement with Bio-Rad Laboratories, Inc. (Bio-Rad), a leading multinational life sciences company, for the first ever POC test for the confirmation of HIV (reflex test used after initial screening test(s) are positive). This product utilizes our DPP® technology, capitalizing on its multiplexing advantages, and is much simpler to perform than the legacy confirmatory platform, known as western blot, which requires a substantial amount of technical training and hands-on time and which is more expensive to manufacture and distribute. This product was CE marked and was launched by Bio-Rad in the second quarter of 2013 in Europe under their Geenius® brand; and an FDA PMA approval was received in 2014. 
+In 2013 we entered into collaboration with Labtest, a private company in Brazil, for the distribution of a number of products in Brazil that would be co-branded with Labtest and Chembio trademarks. Under this agreement, upon request from Labtest, for which there is no requirement, Chembio will sell the appropriate DPP® components to Labtest for further manufacture and assembly in Brazil. 
+In February 2014, Chembio entered into a technology transfer and license agreement with RVR Diagnostics SDN BHD ("RVR"), a privately-held company in Malaysia. The agreement supports Chembio's strategy of establishing a market presence in Asia, in collaboration with RVR as a licensee, distributor, and contract manufacturer, depending on the circumstances. The agreements grant exclusive distribution rights to RVR in certain countries in the region and enable RVR to manufacture Chembio's DPP® HIV 1/2 Assay and DPP® HIV-Syphilis Assay, and potentially other products developed by Chembio, such as Dengue, incorporating its patented DPP® technology as indicated in the DPP® Technology & Development section above. 
+Our Rapid Test Technologies 
+All of our commercially available current products employ either in-licensed lateral flow technology or our own patented Dual Path Platform (DPP®) technology. Both lateral flow technology and DPP® allow the development of accurate, low cost, easy-to-perform, single-use diagnostic tests for rapid, visual detection of specific antigen-antibody complexes on a test strip. These formats provide a test that is simple (requires neither electricity nor expensive equipment for test execution or reading, nor skilled personnel for test interpretation), rapid (turnaround time approximately 15 minutes), safe (minimizes handling of potentially infected specimens), non-invasive (requires 5-20 micro liters of whole blood easily obtained with a finger prick, or alternatively, serum or plasma), stable (24 months at room temperature storage in the case of our HIV tests), and highly reproducible. 
+We believe that products developed using DPP® technology can provide superior diagnostic performance as compared with products that use lateral flow technology. The reason for this is that one of the major differences between the two platforms is that in DPP® samples are allowed to incubate with the target analyte in the test zone before introduction of the labeling reagent/conjugate, whereas in lateral flow, samples are combined with the labeling reagent to form a complex before coming in contact with the target analyte. We believe that this complex can compromise test performance. Also, because of the usage in DPP® of a separately connected sample strip, the control and delivery of sample material is substantially improved. This feature is critical in the development of multiplex tests, as well as tests that involve viscous sample material (such as oral fluid) that can be impeded when forced to combine with labeling reagents before migration on the test strip to the test zone area. 
+Multiplexing is significantly improved as a result of the design of DPP® and this provides a significant advantage. For example, the HIV confirmatory test we developed for Bio-Rad that is described above employs six different markers related to various epitopes of the HIV antigen. We have a number of other products in development, including those being developed in sponsored development programs that involve the use of multiple (e.g. eight) test bands. Although all of these products could be visually read, we can also use handheld and desktop readers with our DPP® products to objectively measure, quantify, record and report DPP® test results. Certain of the products we have and/or are developing incorporate some of these readers, and we are developing other products that may be used with or will require use of a reader. Also, platforms can incorporate labeling reagents that cannot be visually read except by employing a reader, such as fluorescence, though no products are currently utilizing such reagents. 
+We are pursuing additional capabilities and technologies that will complement our current product portfolio and business strategy. This activity includes pursing development, license or acquisition of diagnostic technologies that complement our existing platforms, proprietary biomarkers that can result in new product applications of our existing platforms, and new platforms that would complement our commercial strategy. 
+6 
+Target Markets 
+Rapid HIV Tests 
+A large percentage of individuals that are HIV positive worldwide are unaware of their status. Part of the reason for this is that even those that do get tested in public health settings will often not return or call back for their test results when samples have to be sent out to a laboratory which can take up to several days to process. The increased availability, greater efficacy and reduced costs for anti-retroviral treatments (ARVs) for HIV has increased the demand for testing, as the stigma associated with the disease is lessened, and the ability to resume normal activities is substantially improved, providing a positive message to those potentially infected. The impact that rapid HIV testing has had on prevention efforts has in turn increased the demand for testing, particularly by public health programs worldwide, which have also become more effective in reducing the number of annual new infections in many, but by no means all, high prevalence regions. 
+Despite less attention to HIV by the media as compared with prior years, there are still approximately 50,000 new diagnoses of HIV infection in the United States each year, according to the CDC. CDC estimates that approximately 1.1 million individuals in the U.S. are living with HIV, with an estimated 1 of 8 of these U.S. individuals, or almost 13%, unaware that they are infected. It is transmissions from these infected people that are reported to account for the majority of all new infections per year. Part of the reason for this is that even those individuals that do get tested in public health settings will often not return or call back for their test results if their blood samples have to be sent out to and tested in a laboratory and then reported back, a process which can take up to several days to complete. Making more people aware of their HIV status at the point-of-care reduces the number of HIV transmissions. 
+Rapid HIV testing in the United States has now developed into an estimated 7.5 million test market at an average price of $10, or a total of $75 million. Public health programs, currently funded by grants distributed to states by the CDC, account for an estimated 45% of the market, with hospitals (40%) and doctor ' s offices (15%) comprising the other estimated market segments. Chembio ' s rapid HIV tests represent approximately a 20% share of this market. OraSure Technologies, Inc., which was the first FDA-approved rapid HIV test, maintains approximately 50% of this market. Trinity Biotech has an estimated 15% market share and Alere, Biolytical Laboratories, Medmira and Bio-Rad share the remaining 10%. 
+In 2006, the outlook for HIV testing was given a big boost with the release by the CDC of new recommendations for HIV testing. These new CDC recommendations were/are that an HIV test should be given as a routine test like any other for all patients between 13 and 64 years of age, regardless of risk, with an opt-out screening option and focused testing procedural (pre- and post-test counseling) guidelines. Though not mandatory, gradual adoption in whole or in part of the 2006 CDC recommendations by a number of states continues to have an increasing impact. Finally, in 2013, the United States Preventive Services Task Force ( " USPSTF " ) fully embraced these CDC routine HIV testing recommendations. This USPSTF recommendation, which was given an A grade under their recommendation grading system based on the benefits of this practice and the nearly 600,000 AIDS-related deaths in the United States, requires insurance coverage under the Affordable Care Act (the " ACA " ) as a preventive screening test without any co-payment required. We expect this to result in an increase in HIV testing in the United States in the coming years, which we believe will include point-of-care HIV testing utilizing the Company ' s products. Although as stated above, currently most public health testing in the United States is funded by grants allocated to high prevalence areas by the CDC, we believe this will shift to an insurance-funded model under the ACA in the years to come, increasing the amount of testing done in doctor ' s offices and community health centers. 
+In the international market, we sell our products directly and through distributors to large screening programs overseen by ministries of health and NGOs, most but not all of which are funded by large bi-lateral and multi-lateral AIDS relief programs, the largest of which is the U.S. President ' s Emergency Plan for AIDS Relief (PEPFAR). Established by President George Bush as a 5-year $15 billion program in 2003, PEPFAR was reauthorized in 2008 and again in 2013. In 2012 PEPFAR directly supported HIV testing and counseling for more than 11 million pregnant women, and testing and counseling for more than 49 million people overall. The U.S. is also the first and largest donor to the Global Fund to Fight AIDS, Tuberculosis and Malaria. To date, the U.S. has provided more than $7 billion to the Fund. 
+In December 2013 President Obama signed into law the PEPFAR Stewardship and Oversight Act, which is the most recent reauthorization of PEPFAR. However, unlike the 2008 PEPFAR authorization, which authorized approximately $45 billion, the new law doesn ' t authorize a specific dollar amount for funding. Nevertheless it is widely anticipated that PEPFAR will continue to enjoy strong funding; the FY14 budget had $6 billion for global HIV/AIDS assistance, including $4 billion for PEPFAR. 
+Chembio, with its four U.S.-manufactured rapid HIV tests, all of which are FDA-approved, is recognized as a reputable and dependable supplier of high quality products that are available at reasonably competitive prices. As a result, certain of our products have been selected in the testing protocols in countries (national algorithms) that are large beneficiaries of PEPFAR and the Global Fund. As mentioned above, these programs can and do often result in large orders, but also can result in periods of relatively lower demand, based on the variations associated with this kind of demand. Also, even though the United States taxpayer is funding the largest share of global AIDS relief, U.S. companies do not receive any preference for these procurements, and therefore must compete with foreign suppliers that manufacture competitive products with lower costs, including those related to quality, regulatory, intellectual property, and costs of manufacturing. 
+Oral fluid testing is an established alternative to blood testing for diagnostic tests, including HIV tests. It is also often patient preferred, providing a more comfortable, less invasive test. In certain public health clinics, staffs choose not to handle blood specimens; thus, oral sample collection provides a viable alternative. The most well-established market for oral fluid HIV testing is the United States. Given the premium price required for an oral fluid test as compared with blood tests, the higher volume programs will not specify an oral fluid test. However, segments of these programs may want to have an oral fluid testing option, and certain programs that have greater resources may also choose to incorporate oral fluid testing into the testing protocol. 
+There is also now an over-the-counter market for HIV self-testing in the United States. OraSure Technologies Inc. received FDA approval for an over-the-counter (self-testing) version of its previously professional-market-approved (test performed on an individual by a health care professional) HIV test. The FDA approval was granted in July 2012, and OraSure has been investing heavily in developing this market. Initial results after over two years of marketing are well below expectations. The costs for such over-the-counter approval, including primarily the associated clinical trials, are estimated to be at least $5 million and they may take two to three years to complete, not to mention the cost of distribution. OraSure ' s initial results are not convincing of a large market, although this possibility remains. If it appears that there is an attractive market, we believe we are very well positioned to participate in this market. 
+Rapid HIV-Syphilis Test 
+There are significant risks relating to transmission of Syphilis from a pregnant mother to child, just as there are for transmission of HIV. Therefore we believe there is a significant opportunity to improve prevention efforts in pregnant mother to child transmission testing programs (PMTCT) that are currently not doing any or nearly enough testing for syphilis even though they are testing for HIV. In the United States, we believe there is also a significant need for this product in some of the highest HIV prevalence populations, such as among men that have sex with men (MSM), as data show high degrees of HIV and Syphilis co-infection in this segment of the population. 
+7 
+Marketing Strategy 
+Our marketing strategy is to: 
+· 
+Market our DPP® HIV 1/2 Assay, HIV 1/2 STAT-PAK® Assay and future DPP® based new products in the US through our internal sales and marketing organization and selected channel partners (e.g., McKesson/PSS, Fisher Healthcare, Henry Schein, etc.). Chembio, following the June 2014 termination of the STAT-PAK® agreement with Alere, does not have to share any portion of the net sales proceeds for STAT-PAK® with Alere. This decision resulted in incurring expenditures related to hiring sales representatives, establishing agreements and associated discounts with distributors, incurring advertising and marketing expenditures, warehousing, customer service and technical support. If Alere's new competitive product is indeed successful, our ability to retain a significant share of the market that has been established for our products may be enhanced by our having control of the marketing of our products, rather than relying on Alere to sell both our products while it is also selling its own competing product. We are leveraging the same sales force for U.S. Sales of DPP® HIV 1/2 Assay. 
+· 
+We will support, review and assess the marketing and distribution efforts of our rapid HIV barrel test in the U.S. 
+· 
+Outside the U.S., we will market our products primarily through commercial collaborators and distribution partners. 
+· 
+Leverage our DPP® intellectual property and product development and manufacturing experience to continue creating new collaborations where Chembio can be the exclusive development and manufacturing partner supporting leading marketing organizations. 
+· 
+Establish strong distribution relationships for our Chembio-branded products in the U.S and abroad, and establish a direct sales and marketing organization that is focused in the public health market segment, and that utilizes distributors for other market segments, primarily the acute care market which, together with public health, are the main market segments for rapid HIV tests in the United States. We believe that creation of a Chembio public health brand and marketing organization is fundamental to the creation of shareholder value over the long-term. 
+We have increased our commercial activities and efforts in Africa, Europe and Asia for our HIV tests and product pipeline. We believe these efforts will enable us to be more closely engaged with opportunities to engage with customers and partners and to participate in the national testing algorithms that are established and revised from time to time by countries that are beneficiaries of PEPFAR, Global Fund and/or other bilateral or multilateral donor funding. In Europe, where there are a larger percentage of HIV positive people unaware of their status than in the United States, we believe that there is an emerging public health outreach opportunity, and there are relatively few strong competitors that are CE-marked. Most recently we have established new sales and marketing positions in the Company to support our efforts to increase brand awareness globally and to lead our direct sales effort in the U.S. market. 
+Competition 
+The diagnostics industry is a multi-billion dollar international industry and is intensely competitive. Many of our competitors are substantially larger and have greater financial, research, manufacturing and marketing resources. Industry competition in general is based on the following: 
+· 
+Scientific and technological capability; 
+· 
+Proprietary know-how; 
+· 
+The ability to develop and market products and processes; 
+· 
+The ability to obtain FDA or other required regulatory approvals; 
+· 
+The ability to manufacture products that meet applicable FDA requirements, (i.e. FDA ' s Quality System Regulations) (see Governmental Regulation section); 
+· 
+The ability to manufacture products cost-effectively; 
+· 
+Access to adequate capital; 
+· 
+The ability to attract and retain qualified personnel; and 
+· 
+The availability of patent protection. 
+We believe our scientific and technological capabilities and our proprietary know-how relating to our in-licensed lateral flow technology rapid tests and to our proprietary know-how related to our patented DPP® technology, particularly for the development and manufacture of tests for the detection of antibodies to infectious diseases such as HIV, are very strong. 
+Our ability to develop and market other products is in large measure dependent on our having additional resources and/or collaborative relationships. Some of our product development efforts have been funded on a project or milestone basis. We believe that our proprietary know-how in lateral flow technology and in our DPP® technology has been instrumental in our obtaining the collaborations we have and that we continue to pursue. We believe that the patent protection that we have with our DPP® technology enhances our ability to develop more profitable collaborative relationships and to license out the technology. However there are a number of competitive technologies used and/or seeking to be used in point-of-care settings. These technologies may be based on immunoassay principles such as the Company ' s products or other technologies, such as molecular-based technologies. 
+We launched our FDA-approved DPP® HIV 1/2 Assay, which test also can be used with either oral fluid or blood samples, in the U.S. market under a Chembio brand in the fourth quarter of 2014. OraSure Technologies manufactures the only other rapid, oral fluid HIV test that is FDA-approved, and OraSure has enjoyed this position for approximately 10 years. OraSure has lost a significant share of this market as certain customers have been indifferent to using blood or oral fluid samples, because the blood tests, including those made/marketed by Chembio and marketed by Alere, are priced lower and/or are as or more accurate than the performance of OraSure ' s product on blood samples. OraSure has primarily retained those customers for whom the oral fluid sample feature is a strong preference, and this is an estimated $35 million business for OraSure. Although we believe we can capture a meaningful portion of this OraSure market share, we also anticipate that OraSure will defend this business aggressively. 
+8 
+In 2006 Alere acquired a division from Abbott Diagnostic located in Japan that manufactured and marketed a rapid HIV test product line called Determine®. The Determine® format was developed for the developing world and remote settings and, central to the needs of that market, the format is essentially a test strip that is integrated into a thin foil wrapper that, when opened, the underside of the wrapper serves as the test surface for applying the blood sample and performing the test. This design reduces costs and shipping weights and volumes and is an advantage for the developing world markets it has served. Some of the disadvantages of the platform are the amount of blood sample that is needed (50 microliters versus 2.5, 5 and 10 for our lateral flow barrel, lateral flow cassette, and DPP® products respectively), the open nature of the test surface, and the absence of a true control that differentiates biological from other kinds of samples. 
+The so-called " 3rd generation " version of this product has been marketed for many years and is the leading rapid HIV test that is used in a large majority of the national algorithms of countries funded by PEPFAR and the Global Fund, as well as many other countries in the world. That product is not FDA-approved though it is CE-marked. The newest Determine® HIV version, which was developed and manufactured at Alere ' s subsidiary in Israel, Orgenics, is the so-called " 4th Generation " version Determine® test. According to its claims, this product detects HIV antibodies and P24 HIV antigens. Since the P24 antigen is known to occur in HIV-positive individuals ' blood samples before antibodies do, based on its performance claims, the 4th generation Determine® test is therefore able to detect HIV infection earlier than tests that solely rely on antibody detection. Chembio ' s tests, as well as all of the other currently FDA-approved rapid HIV tests, only detect antibodies. There are however laboratory tests that are FDA-approved that are " 4th generation " tests, but they are of course neither rapid nor point-of-care. 
+The initial " 4th generation " Alere Determine® rapid test product that was also CE-marked and that Alere launched internationally some years ago has not been successfully commercialized to the best of our knowledge and at least certain published studies were not favorable for this product. However the 4th generation product that is now FDA-approved was apparently modified as compared to the initial international version of it, and it may perform more satisfactorily. Alere received FDA approval of this modified product in August 2013 and CLIA-waiver for it in the fourth quarter of 2014. There is support by a number of key opinion leaders for the public health value of such 4th generation tests, and it represents a significant competitive threat to Chembio as well as to each of the other rapid HIV test manufacturers (OraSure and Trinity primarily). 
+During 2011 Biolytical, Inc. of Vancouver, Canada received FDA approval and in 2012 received CLIA waiver of a flow-through rapid HIV test called " INSTI " . The technology used in the INSTI test, flow-through, is older than lateral flow, and it requires handling of multiple components (3 vials of solution) to perform the test in multiple steps. However, these steps can be accomplished in less than ten minutes, and the actual test results occur in only one minute after those steps are completed. Therefore sample-to-result time is shorter than any of the competitive products. There are settings where that reduced total test time, despite the multiple steps required, may be a distinct advantage, and we believe Biolytical has made some progress in penetrating certain public health markets. 
+Although we have no specific knowledge of any other competitors ' products that are a competitive threat to our products, or that will render our products obsolete, if we fail to maintain and enhance our competitive position or fail to introduce new products and product features, our customers may decide to use the products developed by our competitors, which could result in a loss of revenues and cash flow. 
+Research and Development 
+During 2015 and 2014, we spent $6.4 million and $4.8 million, respectively, on research and development (including regulatory activities). These expenses were in part underwritten by funding from R&D and milestones revenues of $2.3 million in 2015 and $1.7 million in 2014. All of our new product development activities involve employment of our DPP® technology. These activities include completing development of certain products and making significant progress toward the development of additional products. 
+Employees 
+At December 31, 2015, we employed approximately155 people. We have entered into employment contracts with our Chief Executive Officer and President, John J. Sperzel, our Chief Operating Officer, Sharon Klugewicz, and our Chief Science and Technology Officer, Javan Esfandiari. Due to the specific knowledge and experience of these executives regarding the industry, technology and market, the loss of the services of any one of them would likely have a material adverse effect on the Company. The contract with Ms. Klugewicz, has a term of two years ending May 2017. The contract with Mr. Esfandiari has a term of three years ending March 2016. The Company and Mr. Esfandiari currently are discussing terms for renewal of his employment agreement. We have obtained a key man insurance policy for Mr. Esfandiari. The contract with Mr. Sperzel provides that Mr. Sperzel will serve as the Chief Executive Officer and President of the Company through March 2017. 
+Governmental Regulation 
+The manufacturing and marketing of the Company ' s existing and proposed diagnostic products are regulated by the United States Food and Drug Administration ( " FDA " ), United States Department of Agriculture ( " USDA " ), certain state and local agencies, and/or comparable regulatory bodies in other countries. These regulations govern almost all aspects of development, production and marketing, including product testing, authorizations to market, labeling, promotion, manufacturing and record keeping. The Company ' s FDA and USDA regulated products require some form of action by each agency before they can be marketed in the United States, and, after approval or clearance, the Company must continue to comply with other FDA requirements applicable to marketed products, e.g. Quality Systems (for medical devices). Failure to comply with the FDA ' s requirements can lead to significant penalties, both before and after approval or clearance. 
+There are two review procedures by which medical devices can receive FDA clearance or approval. Some products may qualify for clearance under Section 510(k) of the Federal Food, Drug and Cosmetic Act, in which the manufacturer provides a pre-market notification that it intends to begin marketing the product, and shows that the product is substantially equivalent to another legally marketed product (i.e., that it has the same intended use and is as safe and effective as a legally marketed device and does not raise different questions of safety and effectiveness). In some cases, the submission must include data from human clinical studies. Marketing may commence when the FDA issues a clearance letter finding such substantial equivalence. FDA clearance of our DPP® Syphilis Screen & Confirm test will be by means of a 510(k) submission. 
+If the medical device does not qualify for the 510(k) procedure (either because it is not substantially equivalent to a legally marketed device or because it is required by statute and the FDA ' s implementing regulations have an approved application), the FDA must approve a Pre-Marketing Application ( " PMA " ) before marketing can begin. PMA ' s must demonstrate, among other matters, that the medical device provides a reasonable assurance of safety and effectiveness. A PMA application is typically a complex submission, including the results of non-clinical and clinical studies. Preparing a PMA application is a much more expensive, detailed and time-consuming process as compared with a 510(K) pre-market notification. The Company has approved PMAs for the two rapid HIV tests now marketed in the U.S.: both our HIV 1/2 STAT-PAK® and also our test that currently is marketed in the U.S. by Alere Medical as Clearview® Complete HIV 1/2 and Clearview® HIV 1/2 STAT PAK®. 
+FDA approval of our DPP® HIV screening assay for use with oral fluid or blood samples also was achieved by means of a PMA application. The Clinical Laboratory Improvement Act of 1988 ( " CLIA " ) prohibits laboratories from performing in-vitro tests for the purpose of providing information for the diagnosis, prevention or treatment of any disease or impairment of, or the assessment of, the health of human beings unless there is in effect for such laboratories a certificate issued by the United States Department of Health and Human Services (via the FDA) applicable to the category of examination or procedure performed. Although a certificate is not required for the Company, it considers the applicability of the requirements of CLIA in the design and development of its products. The statutory definition of " laboratory " is very broad, and many of our customers are considered labs. A CLIA waiver will remove certain quality control and other requirements that must be met for certain customers to use the Company ' s products and this is critical to the marketability of a product into the point-of-care diagnostics market. The Company has received a CLIA waiver for each of the two lateral flow rapid HIV tests now marketed in the U.S. The CLIA waiver was granted by the FDA for HIV 1/2 STAT-PAK® on November 20, 2006 and for the Clearview® Complete HIV 1/2 on October 22, 2007. In 2008 the FDA revised its CLIA waiver requirements so that an additional prospective trial need be conducted in order to demonstrate clinical utility by showing that the device is capable of identifying new infections when used by untrained users. Our DPP® HIV 1/2 test received CLIA waiver in October of 2014. 
+9 
+In addition, the FDA regulates the export of medical devices that have not been approved for marketing in the United States. The Federal Food, Drug and Cosmetic Act contains general requirements for any medical device that may not be sold in the United States and is intended for export. Specifically, a medical device intended for export is not deemed to be adulterated or misbranded if the product: (1) complies with the specifications of the foreign purchaser; (2) is not in conflict with the laws of the country to which it is intended for export; (3) is prominently labeled on the outside of the shipping package that it is intended for export; and (4) is not sold or offered for sale in the United States. However, the Federal Food, Drug and Cosmetic Act does permit the export of devices to any country in the world, if the device complies with the laws of the importing country and has valid marketing authorization in one of several " listed " countries under the theory that these listed countries have sophisticated mechanisms for the review of medical devices for safety and effectiveness. 
+The Company is also subject to regulations in foreign countries governing products, human clinical trials and marketing, and may need to obtain approval or evaluations by international public health agencies, such as the World Health Organization, in order to sell diagnostic products in certain countries. Approval processes vary from country to country, and the length of time required for approval or to obtain other clearances may in some cases be longer than that required for United States governmental approvals. On the other hand, the fact that our HIV diagnostic tests are of value in the AIDS epidemic may lead to some government process being expedited. The extent of potentially adverse governmental regulation affecting Chembio that might arise from future legislative or administrative action cannot be predicted. 
+Environmental Laws 
+To date, we have not encountered any costs relating to compliance with any environmental laws. 
+Intellectual Property 
+Intellectual Property Strategy 
+Our intellectual property strategy is to: (1) build our own intellectual property portfolio around our DPP® technology; (2) pursue licenses, trade secrets and know-how within the area of rapid point-of-care testing, and (3) develop and acquire proprietary positions to reagents and new hardware platforms for the development and manufacture of rapid diagnostic tests. 
+The Company has obtained patent coverage on the DPP® technology, including four U.S. patents, and patents in China, Malaysia, Eurasia, Mexico, Singapore, Japan, Australia, Indonesia, Korea and the U.K. Additional patent applications on the DPP® technology are pending in the U.S., as well as in many foreign countries such as Brazil, Canada, the European Union, India, Israel, and South Africa. Patents have also been filed on extensions to the DPP® product line concept, such as 4th generation assays. The four U.S. patents are as follows: 
+U.S. Patent No. 
+Issued 
+Expires 
+Nature 
+Type 
+Description 
+7,189,522 
+3/13/2007 
+3/11/2025 
+test device 
+utility 
+a test device for determining the presence of a ligand in a sample 
+7,682,801 
+3/23/2010 
+3/11/2025 
+test device 
+and method 
+utility 
+a test device and a method for determining 
+the presence of a ligand in a sample 
+7,879,597 
+2/1/2011 
+3/11/2025 
+test device 
+utility 
+a test device for determining multiple 
+ligands in a sample 
+8,507,259 
+8/13/2013 
+3/11/2025 
+test device 
+utility 
+a test device for determining the 
+presence of a ligand in a sample 
+The Company has also filed for patents and obtained some patents in the U.S. for other inventions, such as its multiple host species veterinary TB test, and patent applications for the other inventions are in various stages from being recently filed and not yet examined, to already examined and allowed but not yet issued. The Company selectively and strategically foreign files its patent applications based on a number of economic and strategic factors related to the invention. 
+Trademarks 
+The Company has filed and obtained trademarks for its products, including DPP®, SURE CHECK® and STAT-PAK®, and also for the SampleTainer® used in certain DPP® products. The DPP® trademark is also registered under the European convention (ECT). The Company recently filed a trademark for STAT-VIEW®, to market the barrel product in Europe. 
+Trade Secrets and Know-How 
+We believe that we have developed a substantial body of trade secrets and know-how relating to the development and manufacture of lateral flow and DPP®-based diagnostic tests, including but not limited to the sourcing and optimization of materials for such tests, and how to maximize sensitivity, speed-to-result, specificity, stability and reproducibility. The Company possesses proprietary know-how to develop tests for multiple conditions using colored latex. Our buffer formulations enable extremely long shelf lives of our rapid HIV and other tests and we believe that this provides us with an important competitive advantage. 
+Lateral Flow Technology and Reagent Licenses 
+As part of the agreements executed in 2006 with Alere for the marketing of our HIV tests, we were granted non-exclusive licenses to certain lateral flow patents for certain products manufactured and marketed by Chembio including but not limited to our lateral flow HIV tests. This license allows us to produce, market and sell assays using lateral flow technologies specifically including our STAT-PAK®, SURE CHECK®, DIPSTICK®, and veterinary product lines. Under this license agreement, prior to February 3, 2015, we paid royalties to Alere ranging from 5% to 8½%, depending upon the country in which the products are sold. Even though the relevant patent has expired in most other jurisdictions, or were never issued in markets where we have sold these products, our manufacture of the products in the United States has required that we pay royalties under this license, which has been a substantial expense. In 2015 our lateral flow royalty expense to Alere was $30,000, and since 2007 we have incurred a total of $2.87 million in lateral flow royalty expenses. As of February 3, 2015 this royalty expense was no longer payable as the applicable patent expired at that time. 
+Although we believe our DPP® is outside of the scope of all lateral flow patents of which we are aware, we consult with patent counsel, and seek licenses and/or redesigns of products that we believe to be in the best interests of the Company and our stockholders. Because of the costs and other negative consequences of time-consuming patent litigation, we often attempt to obtain a license on reasonable terms. Nevertheless there is no assurance that the Alere lateral flow patents we have licensed will not be challenged or that other patents containing claims relevant to the Company's lateral flow or DPP® products will not be granted to third parties and that licenses to such patents, will be available on reasonable terms, if any. In the past Alere has aggressively enforced its lateral flow intellectual property, although some of the main patents have expired and we are not aware of any patent enforcement litigation that is ongoing with respect to the Alere lateral flow intellectual property. 
+Regardless, the DPP® technology provides us with our own intellectual property. We believe it provides us with a freedom to operate, and that it also enables tests to be developed with improved sensitivity as compared with comparable tests on lateral flow platforms. The Company has signed and anticipates signing new development projects based upon the DPP® technology that will provide new manufacturing and marketing opportunities. We have filed other patent applications that we believe will strengthen the DPP® intellectual property and have also filed for patent protection for certain other point-of-care technologies or applications thereof. 
+The peptides used in our rapid HIV tests were patented by Adaltis Inc. and were licensed to us under a 10-year non-exclusive license agreement dated August 30, 2002. However, in connection with Adaltis' bankruptcy, during the third quarter of 2009 we bought out all of our remaining obligations under that agreement. We also have licensed the antigens used in other tests including our Syphilis, Tuberculosis, Leptospirosis, Leishmaniasis and Chagas tests, and we may enter other license agreements. In prior years we concluded license agreements related to intellectual property rights owned by the United States associated with HIV- 1, and during the first quarter of 2008 we entered into a sub-license agreement for HIV-2 with Bio-Rad Laboratories N.A., the exclusive licensee of the Pasteur Institute's HIV-2 intellectual property estate. 
+10 
+Corporate History 
+On May 5, 2004, we completed a merger with Trading Solutions, Inc. through which Chembio Diagnostic Systems Inc. became our wholly-owned subsidiary, and through which the management and business of Chembio Diagnostic Systems Inc. became our management and business. As part of this transaction, we changed our name to Chembio Diagnostics, Inc. In 2003, we had sold our prior business, and as a result, we had no specific business immediately prior to the merger. 
+Since the formation of Chembio Diagnostic Systems Inc. in 1985, it has been involved in developing, manufacturing, selling and distributing in-vitro diagnostic tests, including rapid tests beginning in 1995, for a number of conditions in humans and animals. 
+On March 12, 2004, we implemented a 1-for-17 reverse split of our common stock. All references herein to shares of our common stock have been adjusted to reflect this reverse split. 
+On May 30, 2012, the Company effected a 1-for-8 reverse split of its common stock. This was done to allow the Company to move to the NASDAQ trading market from the OTCQB market, which occurred on June 7, 2012. As a result of the stock split, the outstanding 63,967,263 common shares were reduced to 7,995,918 outstanding common shares on May 30, 2012. The effect of this reverse stock split also has been retroactively reflected for all periods in these financial statements. 
+Stockholder Rights Agreement 
+On March 8, 2016, the Company entered into a Rights Agreement (the "Rights Agreement") between the Company and Action Stock Transfer Corp., as Rights Agent. Pursuant to the Rights Agreement, the Company declared a dividend distribution of one Preferred Share Purchase Right (a "Right") for each outstanding share of common stock, par value $0.01 (the "Common Stock"), of the Company, in the manner described below. The Board of Directors set the payment date for the distribution of the Rights as March 8, 2016, and the Rights were distributed to the Company's shareholders of record on that date. The description and terms of the Rights are set forth in the Rights Agreement. 
+Rights Initially Not Exercisable. The Rights are not exercisable until a Distribution Date. Until a Right is exercised, the holder thereof, as such, has no rights as a shareholder of the Company, including, without limitation, the right to vote or to receive dividends. 
+Separation and Distribution of Rights . The Rights are to be evidenced by the certificates for shares of Common Stock registered in the names of the holders thereof, and not by separate rights certificates until the earlier to occur of (i) the close of business on the tenth business day following a public announcement that an Acquiring Person (as defined in the Rights Agreement) has acquired a Combined Ownership (as defined in the Rights Agreement) of 20% or more of the outstanding shares of the Common Stock (the "Shares Acquisition Date") or (ii) the later of (A) the close of business on the tenth business day (or such later date as may be determined by action of the Board of Directors prior to such time as any person or group of affiliated or associated persons becomes an Acquiring Person) after the date that a tender or exchange offer or intention to commence a tender or exchange offer by any person is first published, announced, sent or given within the meaning of Rule 14d-4(A) under the Securities Exchange Act of 1934, as amended, the consummation of which would result in any person having Combined Ownership of 20% or more of the outstanding shares of the Common Stock, or (B) if such a tender or exchange offer has been published, announced, sent or given before the date of the Rights Agreement, then the close of business on the tenth business day after the date the Rights Agreement was entered into (or such later date as may be determined by action of the Board of Directors prior to such time as any person becomes an Acquiring Person); (the earlier of such dates referred to in (i) and (ii), which date may include any such date that is after the date of the Rights Agreement but prior to the issuance of the Rights, being called the "Distribution Date"). 
+Glossary 
+AIDS 
+Acquired Immunodeficiency Syndrome. AIDS is caused by the Human Immunodeficiency Virus, HIV. 
+ALGORITHM (parallel or serial) 
+For rapid HIV testing this refers both to method or protocol (in developing countries to date) for using rapid tests from different manufacturers in combination to screen and confirm patients at the point-of-care, and may also refer to the specific tests that have been selected by an agency or ministry of health to be used in this way. A parallel algorithm uses two screening tests from different manufacturers and a tie-breaker test only if there is a discrepancy between the screening tests results. A serial algorithm only uses a second confirmatory test if there is a positive result from the screening test, meaning that the number of confirmatory tests used is equal to the positivity rate in the testing venue. A tie-breaker test resolves discrepancies between the screen and the confirmatory test. 
+ANTIBODY 
+A protein which is a natural part of the human immune system produced by specialized cells to neutralize antigens, including viruses and bacteria that invade the body. Each antibody producing cell manufactures a unique antibody that is directed against, binds to and eliminates one, and only one, specific type of antigen. 
+ANTIGEN 
+Any substance which, upon entering the body, stimulates the immune system leading to the formation of antibodies. Among the more common antigens are bacteria, pollens, toxins, and viruses. 
+ANVISA 
+The National Health Surveillance Agency of Brazil 
+ARVs 
+Anti-retroviral medications developed to fight AIDS 
+CDC 
+United States Centers for Disease Control and Prevention 
+CLIA waiver 
+Clinical Laboratory Improvement Act designation that allows simple tests to be performed in point-of-care settings such as doctor's offices, walk-in clinics and emergency rooms. 
+DIAGNOSTIC 
+Pertaining to the determination of the nature or cause of a disease or condition. Also refers to reagents or procedures used in diagnosis to measure proteins in a clinical sample. 
+FIOCRUZ 
+The Oswaldo Cruz Foundation of Brazil 
+FDA 
+United States Food and Drug Administration 
+IgG 
+IgG or Immunoglobulin are proteins found in human blood. This protein is called an "antibody" and is an important part of the body's defense against disease. When the body is attacked by harmful bacteria or viruses, antibodies help fight these invaders. 
+NGO 
+Non-Governmental Organization 
+OTC 
+Over-the-Counter 
+PEPFAR 
+The President's Emergency Plan for AIDS Relief 
+PMA 
+Pre-Marketing Approval –FDA approval classification for a medical device that is not substantially equivalent to a legally marketed device or is otherwise required by statute to have an approved application. Rapid HIV tests must have an approved PMA application before marketing of such a product can begin. 
+PROTOCOL 
+A procedure pursuant to which an immunodiagnostic test is performed on a particular specimen in order to obtain the desired reaction. 
+REAGENT 
+A chemical added to a sample under investigation in order to cause a chemical or biological reaction which will enable measurement or identification of a target substance. 
+RETROVIRAL 
+A type of virus which contains the enzyme Reverse Transcriptase and is capable of transforming infected cells to produce diseases in the host such as AIDS. 
+SENSITIVITY 
+Refers to the ability of an assay to detect and measure small quantities of a substance of interest. The greater the sensitivity, the smaller the quantity of the substance of interest the assay can detect. Also refers to the likelihood of detecting the antigen when present. 
+SPECIFICITY 
+The ability of an assay to distinguish between similar materials. The greater the specificity, the better an assay is at identifying a substance in the presence of substances of similar makeup. 
+USDA 
+U.S Department of Agriculture 
+WHO 
+World Health Organization 
+11 
+ITEM 1A. 
+RISK FACTORS 
+You should carefully consider each of the following risk factors and all of the other information provided in this Form 10-K before purchasing our Common Stock. The risks described below are those we currently believe may materially affect us. An investment in our Company involves a high degree of risk, and should be considered only by persons who can afford the loss of their entire investment. 
+Risks related to our industry, business and strategy 
+Because we may not be able to obtain or maintain the necessary regulatory approvals for some of our products, we may not generate revenues in the amounts we expect, or in the amounts necessary to continue our business. Our existing products as well as our manufacturing facility must meet quality standards and are subject to inspection by a number of domestic regulatory and other governmental and non-governmental agencies. 
+All of our proposed and existing products are subject to regulation in the U.S. by the U.S. Food and Drug Administration, the U.S. Department of Agriculture and/or other domestic and international governmental, public health agencies, regulatory bodies or non-governmental organizations. In particular, we are subject to strict governmental controls on the development, manufacture, labeling, distribution and marketing of our products. The process of obtaining required approvals or clearances varies according to the nature of, and uses for, a specific product. These processes can involve lengthy and detailed laboratory testing, human or animal clinical trials, sampling activities, and other costly, time-consuming procedures. The submission of an application to a regulatory authority does not guarantee that the authority will grant an approval or clearance for that product. Each authority may impose its own requirements and can delay or refuse to grant approval or clearance, even though a product has been approved in another country. 
+The time taken to obtain approval or clearance varies depending on the nature of the application and may result in the passage of a significant period of time from the date of submission of the application. Delays in the approval or clearance processes increase the risk that we will not succeed in introducing or selling the subject products, and we may determine to devote our resources to different products. 
+Changes in government regulations could increase our costs and could require us to undergo additional trials or procedures, or could make it impractical or impossible for us to market our products for certain uses, in certain markets, or at all. 
+Changes in government regulations may adversely affect our financial condition and results of operations because we may have to incur additional expenses if we are required to change or implement new testing, manufacturing and control procedures. If we are required to devote resources to develop such new procedures, we may not have sufficient resources to devote to research and development, marketing, or other activities that are critical to our business. 
+We can manufacture and sell our products only if we comply with regulations and quality standards established by government agencies such as the FDA and the USDA as well as by non-governmental organizations such as the ISO and WHO. We have implemented a quality system that is intended to comply with applicable regulations. Although FDA approval is not required for the export of our products, there are export regulations promulgated by the FDA that specifically relate to the export of our products that require compliance with FDA quality system regulation ("QSRs") and that also require meeting certain documentary requirements regarding the approval of the product in export markets. Although we believe that we meet the regulatory standards required for the export of our products, these regulations could change in a manner that could adversely impact our ability to export our products. 
+Our products may not be able to compete with new diagnostic products or existing products developed by well-established competitors, which would negatively affect our business. 
+The diagnostic industry is focused on the testing of biological specimens in a laboratory or at the point-of-care and is highly competitive and rapidly changing. Some of our principal competitors may have considerably greater financial, technical and marketing resources than we do. Several companies produce diagnostic tests that compete directly with our testing product line, including but not limited to, OraSure Technologies, Alere and Trinity Biotech. Furthermore these and/or other companies have or may have products incorporating molecular and/or other advanced technologies that over time could directly compete with our testing product line. As new products incorporating new technologies enter the market, our products may become obsolete or a competitor's products may be more effective or more effectively marketed and sold. 
+There are competing products that could significantly reduce our U.S. sales of rapid HIV tests. 
+In 2006 Alere, Inc. acquired a division from Abbott Diagnostic located in Japan that manufactured and marketed a rapid HIV test product line called Determine®. The Determine® format was developed for the developing world and remote settings and, central to the needs of that market. The format is essentially a test strip that is integrated into a thin foil wrapper. When opened, the underside of the wrapper serves as the test surface for applying the blood sample and performing the test. This design reduces costs and shipping weights and volumes and provides an advantage for the developing world markets it serves. Some of the disadvantages of the platform are the amount of blood sample that is needed (50 microliters versus 2.5, 5 and 10 for our lateral flow barrel, lateral flow cassette, and DPP® products respectively), the open nature of the test surface, and the absence of a true control that differentiates biological from other kinds of samples. 
+The so-called "3rd generation" version of this product has been marketed for many years and is the leading rapid HIV test that is used in a large majority of the national algorithms of countries funded by PEPFAR and the Global Fund, as well as many other countries in the world. That product is not FDA-approved though it is CE marked. The newest Determine® HIV version, which was developed and manufactured by Alere's subsidiary in Israel, Orgenics, is the so-called "4th Generation" version Determine® test. According to its claims, this product detects HIV antibodies and P24 HIV antigens. Because the P24 antigen is known to occur in HIV-positive individuals' blood samples before antibodies do, the 4th generation Determine® test is designed to detect HIV infection earlier than tests that solely rely on antibody detection. Chembio's tests, as well as all of the other currently FDA-approved rapid HIV tests, only detect antibodies. There are however laboratory tests that are FDA-approved that are "4th generation" tests, but they are of course neither rapid nor point-of-care. 
+The initial "4th generation" Alere Determine® rapid test product that was also CE marked and that Alere launched internationally some years ago has not been successfully commercialized to the best of our knowledge and at least certain published studies were not favorable for this product. However the 4th generation product that is now FDA-approved was apparently modified as compared to the initial international version, and it may perform more satisfactorily. Alere received FDA approval of this modified product in August 2013 and CLIA waiver for it in December 2014. Alere is also aggressively pursuing development of the market for this product. Moreover there is support by a number of key opinion leaders for the public health value of such 4th generation tests, and this product represents a significant competitive threat to Chembio as well as to each of the other rapid HIV test manufacturers (OraSure and Trinity primarily). 
+During 2011, Biolytical, Inc. of Vancouver, Canada received FDA approval and in 2012 received CLIA waiver of a flow-through rapid HIV test called "INSTI". The flow-through technology used in the INSTI test is older than lateral flow, and requires handling of multiple components (3 vials of solution) to perform the test in multiple steps. However, these steps can be accomplished in less than ten minutes, and the actual test results occur in only one minute after those steps are completed. Therefore sample-to-result time is shorter than any of the competitive products. The product also has good performance claims. There are settings where that reduced total test time, despite the multiple steps required, may be a distinct advantage, and we believe Biolytical has made some progress in penetrating certain public health markets. 
+Therefore, even though our lateral flow products currently enjoy a substantial market share in the U.S. rapid HIV test market, and we have an additional rapid HIV test, the DPP® HIV 1/2 Assay, there a number of risks and uncertainties concerning current and anticipated developments in this market. Although we have no specific knowledge of any other new product that is a significant competitive threat to our products, or that will render our products obsolete, if we fail to maintain and enhance our competitive position or fail to introduce new products and product features, our customers may decide to use products developed by our competitors, which could result in a loss of revenues and cash flow. 
+12 
+More generally, the point-of-care diagnostics industry is undergoing rapid technological changes, with frequent introductions of new technology-driven products and services. As new technologies become introduced into the point-of-care diagnostic testing market, we may be required to commit considerable additional efforts, time and resources to enhance our current product portfolio or develop new products. We may not have the available time and resources to accomplish this, and many of our competitors have substantially greater financial and other resources to invest in technological improvements. We may not be able to effectively implement new technology-driven products and services or be successful in marketing these products and services to our customers, which would materially harm our operating results. 
+Although we own our DPP® patent, lateral flow technology is still a competitive platform to DPP®, and lateral flow technology has a lower cost of manufacture than DPP® products. Although the DPP® platform has shown improved sensitivity as compared with conventional lateral flow platforms in a number of studies, several factors go into the development and performance attributes of products. Therefore the ability of our products to successfully compete will depend on several other factors, including but not limited to our having a patented rapid test platform technology that differentiates DPP® from lateral flow as well as from other diagnostic platform technologies. 
+We believe that our DPP® is outside of the scope of currently issued patents in the field of lateral flow technology, thereby offering the possibility of greater freedom to operate. However there can be no assurance that our patents or our products incorporating the patent claims will not be challenged at some time in the future. 
+Our use of third-party suppliers, some of which may constitute our sole supply source, for certain important product components presents a risk that could have negative consequences for other business. 
+A number of our components and critical raw materials are provided by third-party suppliers, some of which may be sole-source suppliers, which impacts our ability to manufacture or sell product if our suppliers cannot or will not deliver those materials in a timely fashion, or at all, due to an interruption in their supply, quality or technical issues, or any other reason. If this occurs, we could incur substantial expense and time to be able to reestablish the appropriate quality, cost, regulatory and market-acceptance circumstances needed for commercial success. Even with the needed expense and time, we may not be able to reestablish any or all of these factors. The absence of any one or more of these factors could prevent us from being able to commercially produce and market the affected product or products. 
+New developments in health treatments or new non-diagnostic products may reduce or eliminate the demand for our products. 
+The development and commercialization of products outside of the diagnostics industry could adversely affect sales of our products. For example, the development of a safe and effective vaccine to HIV or treatments for other diseases or conditions that our products are designed to detect, could reduce or eventually eliminate the demand for our HIV or other diagnostic products and result in a loss of revenues. 
+We may not have sufficient resources to effectively introduce and market our products, which could materially harm our operating results. 
+Introducing and achieving market acceptance for our rapid HIV tests and other new products will require substantial marketing efforts and will require us and/or our contract partners, sales agents, and/or distributors to make significant expenditures of time and money. In some instances we will be significantly or totally reliant on the marketing efforts and expenditures of our contract partners, sales agents, and/or distributors. If they do not have or commit the expertise and resources to effectively market the products that we manufacture, our operating results will be materially harmed. 
+The success of our business depends on, in addition to the market success of our products, our ability to raise additional capital through the sale of debt or equity or through borrowing, and we may not be able to raise capital or borrow funds on attractive terms and/or in amounts necessary to continue our business, or at all. 
+We were profitable for five consecutive years through 2013. Nevertheless, prior to 2009 we sustained significant operating losses since 2004, and we incurred an operating loss for 2014 and 2015. We estimate that our resources are sufficient to fund our needs through the end of 2016 and beyond. Nevertheless we have already made, and may continue to make, significant financial commitments to invest in our sales and marketing organization, regulatory approvals, research and development including new technologies, and production capacity, including expanded facilities. 
+Our liquidity and cash requirements will depend on several factors. These factors include (1) the level of revenues; (2) the extent to which, if any, that revenue level improves operating cash flows; (3) our investments in research and development, facilities, marketing, regulatory approvals, and other investments we may determine to make; and (4) our investment in capital equipment and the extent to which it improves cash flow through operating efficiencies. There are no assurances that we will generate positive cash flow for 2016 or, in the alternative, be successful in raising sufficient capital to fund our needs after 2016. 
+Our U.S. market sales are difficult to predict in 2016 given (i) our early June 2014 termination of the agreement with a third party for exclusive distribution of our cassette product in the U.S; and (ii) the impending May 31, 2016 termination of the agreement with a third party for exclusive distribution of our barrel product in the U.S. As a result of these terminations, we expect to continue to experience higher average revenue per unit, and a lower volume of U.S. sales, of the cassette and barrel products. Higher revenue per unit is anticipated because we previously sold these products to the exclusive U.S. distributor at a significantly lower price than the price at which the distributor resold these products to customers (including re-sellers and distributors) in the United States. However at this point with respect to the barrel product, this can occur only after any inventory that the exclusive U.S. distributor has accumulated is consumed, which may take several months. In addition, in marketing these products directly, we are incurring substantial costs associated with developing our sales and marketing organization and channel distribution partners. 
+We believe that underlying demand for HIV rapid testing in the United States remains strong, and that the restoration of some of the funding cutbacks from sequestration and the implementation of the Affordable Care Act and of the United States Preventive Services Task Force recommendations will have a positive impact on the development of the market. Further, our products are well established and relied upon by a large installed base of customers over many years of use in the U.S. global market, and we believe this is a strong advantage. We also believe that our DPP® HIV 1/2 Assay for which CLIA waiver was obtained in October 2014, for use with oral fluid or bloods samples will be able to serve new customers that were previously unavailable to us with our lateral flow blood tests. However, development of new customers with this product is costly and time-consuming. 
+We are attempting to increase international sales of our products, and we have invested in additional resources in connection with this effort; but as we have experienced, the nature of international business is such that it can be volatile from period to period, depending on ordering patterns of donor-funded programs. 
+Furthermore, a number of factors can slow or prevent sales increases or cause sales decreases, or substantially increase the cost of achieving sales assuming they are achieved. These factors include: 
+· 
+economic conditions and the absence of or reduction in available funding sources; 
+· 
+regulatory requirements and customs regulations; 
+· 
+cultural and political differences; 
+· 
+foreign exchange rates, currency fluctuations and tariffs; 
+· 
+dependence on and difficulties in managing international distributors or representatives; 
+· 
+the creditworthiness of foreign entities; 
+· 
+difficulties in foreign accounts receivable collection; 
+· 
+competition 
+· 
+pricing; and 
+· 
+any inability we may have in maintaining or increasing revenues. 
+If we are unable to maintain or increase our revenues from domestic and/or international customers, our operating results will be materially harmed. 
+13 
+Although we have an ethics and anti-corruption policy in place, and have no knowledge or reason to know of any practices by our employees, agents or distributors that could be construed as in violation of such policies, our business includes sales of products to countries where there is or may be widespread corruption. 
+Chembio has a policy in place prohibiting its employees, distributors and agents from engaging in corrupt business practices, including activities prohibited by the United States Foreign Corrupt Practices Act (the "FCPA"). Nevertheless, because we work through independent sales agents and distributors (and do not have any employees or subsidiaries) outside the United States, we do not have control over the day-to-day activities of such independent agents and distributors. In addition, in the donor-funded markets in Africa where we sell our products, there is significant oversight from PEPFAR, the Global Fund, and advisory committees comprised of technical experts concerning the development and establishment of national testing protocols. This is a process that includes an overall assessment of a product which includes extensive product performance evaluations including five active collaborations and manufacturer's quality systems, as well as price and delivery. In Brazil, where we have had a total of six product collaborations with FIOCRUZ, the programs through which our products may be deployed are all funded by the Brazilian Ministry of Health. Although FIOCRUZ is affiliated with the Brazilian Ministry of Health, and is its sole customer, FIOCRUZ is not the exclusive supplier for the Ministry of Health. However, because each of our previous collaborations with FIOCRUZ incorporates a technology transfer aspect, we believe we have a competitive advantage versus other suppliers to the Brazilian Ministry of Health, assuming other aspects of our product offering through FIOCRUZ are otherwise competitive in comparison. We have no knowledge or reason to know of any activities by our employees, distributors or sales agents of any actions which could be in violation of the FCPA, although there can be no assurance of this. 
+We rely on trade secret laws and agreements with our key employees and other third parties to protect our proprietary rights, and we cannot be sure that these laws or agreements adequately protect our rights. 
+We believe that factors such as the technological and creative skills of our personnel, strategic relationships, new product developments, frequent product enhancements and name recognition are essential to our success. All of our management personnel are bound by non-disclosure agreements. If personnel leave our employment, in some cases we would be required to protect our intellectual property rights pursuant to common law theories which may be less protective than provisions of employment, non-competition or non-disclosure agreements. 
+We seek to protect our proprietary products under trade secret and copyright laws, enter into license agreements for various materials and methods employed in our products, and enter into strategic relationships for distribution of the products. These strategies afford only limited protection. We currently have some foreign patents issued, and we are seeking additional patent protection in several other foreign jurisdictions for our DPP® technology. We have licenses to reagents (antigens and peptides) used in several of our products and products under development. Despite our efforts to protect our proprietary assets, and respect the intellectual property rights of others, we participate in several markets where intellectual property rights protections are of little or no value. This can place our products and our company at a competitive disadvantage. 
+Despite the efforts we make to protect our confidential information, such as entering into confidentiality agreements in connection with new business opportunities, unauthorized parties may attempt to copy aspects of our products or to obtain information that we regard as proprietary. We may be required to expend substantial resources in asserting or protecting our intellectual property rights, or in defending suits related to intellectual property rights. Disputes regarding intellectual property rights could substantially delay product development or commercialization activities because some of our available funds would be diverted away from our business activities. Disputes regarding intellectual property rights might include state, federal or foreign court litigation as well as patent interference, patent reexamination, patent reissue, or trademark opposition proceedings in the U.S. Patent and Trademark Office. 
+To facilitate development and commercialization of a proprietary technology base, we may need to obtain additional licenses to patents or other proprietary rights from other parties. Obtaining and maintaining these licenses, which may not be available, may require the payment of up-front fees and royalties. In addition, if we are unable to obtain these types of licenses, our product development and commercialization efforts may be delayed or precluded. 
+Our continued growth depends on retaining our current key employees and attracting additional qualified personnel, and we may not be able to do so. 
+Our success will depend to a large extent upon the skills and experience of our executive officers, management and sales, marketing, operations and scientific staff. We may not be able to attract or retain qualified employees in the future due to the intense competition for qualified personnel among medical products businesses, geographic considerations, our ability to offer competitive compensation, relocation packages, benefits, and/or other reasons. 
+If we are not able to attract and retain the necessary personnel to accomplish our business objectives, we may experience constraints that will adversely affect our ability to effectively manufacture, sell and market our products to meet the demands of our strategic partners in a timely fashion, or to support internal research and development programs. Although we believe we will be successful in attracting and retaining qualified personnel, competition for experienced scientists and other personnel from numerous companies and academic and other research institutions may limit our ability to do so on acceptable terms. 
+We have entered into employment contracts with our Chief Executive Officer, John Sperzel, our Chief Operating Officer, Sharon Klugewicz, and our Chief Scientist & Technology Officer, Javan Esfandiari. Due to the specific knowledge and experience of these executives regarding the industry, technology and market, the loss of the services of any one of them could have a material adverse effect on the Company. The contract with Mr. Sperzel has a term of three years ending March 2017. The contract with Ms. Klugewicz has a term of two years ending May 2017. The contract with Mr. Esfandiari has a term of three years ending March 2016. The Company and Mr. Esfandiari currently are discussing terms for renewal of his employment agreement. The Company has obtained a key man insurance policy on Mr. Esfandiari. The contract with Mr. Sperzel provides that Mr. Sperzel will serve as the Chief Executive Officer and as a Director of the Company through March 13, 2017. 
+We believe our success depends in part on the continued funding of and our ability to participate in large testing programs in the U.S. and worldwide. Funding of these and or similar programs may be reduced, discontinued and/or we may not be able to participate for other reasons. 
+We believe it to be in our best interests to meaningfully participate in large testing programs. Moreover many of these programs are funded by governments and other donors, and there can be no assurance that funding will not be reduced or completely discontinued. Participation in these programs also requires alignment and engagement with the many other participants in these programs, including the World Health Organization, U.S. Center for Disease Control, U.S. Agency for International Development, foreign governments and their agencies, non-governmental organizations, and HIV service organizations. If we are unsuccessful in our efforts to participate in these programs, our operating results could be materially harmed. 
+In December 2013 President Obama signed into law the PEPFAR Stewardship and Oversight Act, which is the most recent reauthorization of PEPFAR. However, unlike the 2008 PEPFAR authorization, which authorized approximately $45 billion in funding, the new law does not authorize a specific dollar amount for funding. Nevertheless it is widely anticipated that PEPFAR will continue to enjoy strong funding; the FY14 budget has $6 billion for global HIV/AIDS assistance, including $4 billion for PEPFAR. 
+14 
+To the extent that we are unable to collect our outstanding accounts receivable, our operating results could be materially harmed. 
+There may be circumstances and timing that require us to accept payment terms, including delayed payment terms, from distributors or customers, which, if not satisfied, could cause financial losses. 
+We generally accept payment terms which require us to ship product before the contract price has been paid fully, and there also are circumstances pursuant to which we may accept further delayed payment terms pursuant to which we may continue to deliver product. To the extent that these circumstances result in significant accounts receivables and those accounts receivables are not paid on a timely basis, or are not paid at all, especially if concentrated in one or two customers, we could suffer financial losses. 
+Although we were profitable from 2009 through 2013, we incurred a net loss for 2014 and 2015 and cannot be certain that we will be able to sustain profitability in the future. 
+From the inception of Chembio Diagnostic Systems, Inc. in 1985 through the period ended December 31, 2008, we incurred net losses. We were then profitable each year from 2009 through 2013. In 2014 and 2015, we made substantial expenditures for sales and marketing, regulatory submissions, product development, production and warehouse capacity, and other purposes, and we incurred a net operating loss. Our ability to re-achieve profitability in the future will primarily depend on our ability to increase sales of our products based on having made the aforementioned expenditures to reduce production and other costs, and to successfully introduce new products and enhanced versions of our existing products into the marketplace. If we are unable to increase our revenues at a rate that is sufficient to achieve profitability, or adequately control and reduce our operating costs, our operating results would be materially harmed. 
+To the extent that we are unable to obtain sufficient product liability insurance or that we incur product liability exposure that is not covered by our product liability insurance, our operating results could be materially harmed. 
+We may be held liable if any of our products, or any product which is made with the use or incorporation of any of the technologies belonging to us, causes injury of any type or is found otherwise unsuitable during product testing, manufacturing, marketing, sale or use. We have obtained product liability insurance even though we have never received a product liability claim, and have generally not seen product liability claims for screening tests that are accompanied by appropriate disclaimers. Nevertheless, in the event there is a claim, this insurance may not fully cover our potential liabilities. In addition, as we attempt to bring new products to market, we may need to increase our product liability coverage which could be a significant additional expense that we may not be able to afford. If we are unable to obtain sufficient insurance coverage at an acceptable cost to protect us, we may be forced to abandon efforts to commercialize our products or those of our strategic partners, which would reduce our revenues. 
+Risks related to our Common Stock 
+Our Common Stock continues to be illiquid, so investors may not be able to sell as much stock as they want at prevailing market prices. 
+The average daily trading volume of our Common Stock on the NASDAQ market was approximately 21,600 shares per day over the three months ended December 31, 2015 as compared with approximately 109,000 shares per day over the three months ended December 31, 2014. The liquidity of our stock depends on several factors, including but not limited to the financial results of the Company and overall market conditions, so it is not possible to predict whether this level of liquidity will continue, be sustained, or decrease. 
+Decreased trading volume in our stock would make it more difficult for investors to sell their shares in the public market at any given time at prevailing prices. Our management and larger stockholders exercise significant control over the Company. 
+Our management and larger stockholders exercise significant control over the Company. 
+As of December 31, 2015, our named executive officers, directors and 5% stockholders beneficially owned approximately 24.0% of our voting power, which includes two large investors that beneficially owns approximately 11.4% and 9.2%, respectively of the outstanding stock. For the foreseeable future, and assuming these ownership percentages continue to apply, to the extent that these parties vote similarly, they may be able to exercise significant control over many matters requiring approval by the board of directors or our stockholders. As a result, they may be able to: 
+· 
+control the composition of our board of directors; 
+· 
+control our management and policies; 
+· 
+determine the outcome of significant corporate transactions, including changes in control that may be beneficial to stockholders; and 
+· 
+act in each of their own interests, which may conflict with or differ from the interests of each other or the interests of the other stockholders. 
+15 
+ITEM 2. 
+PROPERTIES 
+Our manufacturing, administrative offices and research facilities are located in Medford, New York. In addition we have warehousing space as well as some additional administrative offices located in Holbrook, New York. We lease approximately 39,660 square feet of industrial space in Medford for $27,988 per month. The space is utilized for research and development activities (approximately 5,440 square feet), offices (approximately 2,640 square feet) and production (approximately 31,580 square feet). The lease term expires on April 30, 2017. The lease provides for annual increases of two and one-half percent each year starting May 1, 2015. We lease approximately 21,450 square feet of industrial space in Holbrook for $15,097 per month. The space is utilized for offices (approximately 2,500 square feet) and warehousing (approximately 18,950 square feet). The lease term expires on April 30, 2018. The lease provides for annual increases of three percent each year starting March 1, 2015. The Company believes this space should be sufficient for its needs in the foreseeable future. 
+ITEM 3. 
+LEGAL PROCEEDINGS 
+From time to time, we may be involved in litigation relating to claims arising out of our operations in the normal course of business. We know of no material, existing or pending legal proceedings against us, nor are we involved as a plaintiff in any material proceeding or pending litigation. There are no proceedings in which any of our directors, officers or affiliates, or any registered or beneficial shareholder, is an adverse party or has a material interest that is adverse to our interest. 
+ITEM 4. 
+MINE SAFETY DISCLOSURES 
+Not Applicable. 
+PART II 
+ITEM 5. 
+MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+Market Information 
+Our stock is quoted on the NASDAQ, under the symbol "CEMI." The table below sets forth the high and low bid prices per share of our common stock for each quarter of our two most recently completed fiscal years. These prices represent inter-dealer quotations without retail markup, markdown, or commission and may not necessarily represent actual transactions. 
+Fiscal Year 2015 
+High Bid 
+Low Bid 
+First Quarter 
+$ 
+4.18 
+$ 
+3.41 
+Second Quarter 
+$ 
+5.21 
+$ 
+3.90 
+Third Quarter 
+$ 
+5.19 
+$ 
+2.85 
+Fourth Quarter 
+$ 
+5.48 
+$ 
+3.48 
+Fiscal Year 2014 
+High Bid 
+Low Bid 
+First Quarter 
+$ 
+3.88 
+$ 
+2.81 
+Second Quarter 
+$ 
+3.56 
+$ 
+2.81 
+Third Quarter 
+$ 
+3.85 
+$ 
+3.02 
+Fourth Quarter 
+$ 
+5.19 
+$ 
+3.40 
+Holders 
+As of March 1, 2016, there were approximately 139 record owners of our common stock. 
+Dividends 
+The Company has never paid cash dividends on its common stock and has no plans to do so in the foreseeable future. 
+Recent Sales of Unregistered Securities 
+Not applicable. 
+16 
+ITEM 6. 
+SELECTED FINANCIAL DATA 
+Presented in this table are selected financial data for the past five years ended December 31, 2015. 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+SELECTED HISTORICAL FINANCIAL DATA 
+As of and For the Years Ended 
+Statement of Operations Data: 
+December 31, 2015 
+December 31, 2014 
+December 31, 2013 
+December 31, 2012 
+December 31, 2011 
+TOTAL REVENUES 
+$ 
+24,255,485 
+$ 
+27,645,284 
+$ 
+29,549,609 
+$ 
+25,610,595 
+$ 
+19,388,036 
+GROSS MARGIN (1) 
+10,486,827 
+43 
+% 
+10,814,023 
+39 
+% 
+12,300,159 
+42 
+% 
+10,789,991 
+42 
+% 
+9,390,303 
+48 
+% 
+OPERATING COSTS: 
+Research and development expenses (1) 
+6,377,839 
+26 
+% 
+4,832,537 
+17 
+% 
+5,834,249 
+20 
+% 
+4,486,302 
+18 
+% 
+4,878,119 
+25 
+% 
+Selling, general and administrative expenses (1) 
+7,663,035 
+32 
+% 
+7,531,739 
+27 
+% 
+5,461,083 
+18 
+% 
+4,851,587 
+19 
+% 
+3,424,297 
+18 
+% 
+14,405,874 
+12,364,276 
+11,295,332 
+9,337,889 
+8,302,416 
+INCOME (LOSS) FROM OPERATIONS 
+(3,554,047 
+) 
+(1,550,253 
+) 
+1,004,827 
+1,452,102 
+1,087,887 
+OTHER INCOME (EXPENSES): 
+(3,238 
+) 
+132 
+12,943 
+(1,584 
+) 
+(12,325 
+) 
+INCOME (LOSS) BEFORE INCOME TAXES (1) 
+(3,557,285 
+) 
+(15 
+%) 
+(1,550,121 
+) 
+(6 
+%) 
+1,017,770 
+3 
+% 
+1,450,518 
+6 
+% 
+1,075,562 
+6 
+% 
+Income tax provision (benefit) 
+(1,160,243 
+) 
+(412,918 
+) 
+486,952 
+509,237 
+(5,133,229 
+) 
+NET INCOME (LOSS) 
+$ 
+(2,397,042 
+) 
+$ 
+(1,137,203 
+) 
+$ 
+530,818 
+$ 
+941,281 
+$ 
+6,208,791 
+Basic income (loss) per share 
+$ 
+(0.25 
+) 
+$ 
+(0.12 
+) 
+$ 
+0.06 
+$ 
+0.12 
+$ 
+0.79 
+Diluted income (loss) per share 
+$ 
+(0.25 
+) 
+$ 
+(0.12 
+) 
+$ 
+0.06 
+$ 
+0.11 
+$ 
+0.73 
+Weighted average number of shares outstanding, basic 
+9,626,028 
+9,530,320 
+8,994,080 
+7,986,030 
+7,874,807 
+Weighted average number of shares outstanding, diluted 
+9,626,028 
+9,530,320 
+9,519,968 
+8,614,944 
+8,556,284 
+Balance Sheet Data: 
+Working capital 
+$ 
+9,479,968 
+$ 
+12,372,169 
+$ 
+4,221,011 
+$ 
+7,630,368 
+$ 
+6,133,956 
+Total assets 
+20,816,344 
+25,010,192 
+24,486,592 
+17,335,150 
+15,485,744 
+Total liabilities 
+3,154,838 
+5,286,030 
+4,309,490 
+3,460,630 
+2,991,110 
+Shareholders' equity 
+17,661,506 
+19,724,162 
+20,177,102 
+13,874,520 
+12,494,634 
+(1) percentage shown reflects the percentage of total revenues 
+17 
+ITEM 7. 
+MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+Overview 
+This discussion and analysis should be read in conjunction with the accompanying Consolidated Financial Statements and related notes. Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of any contingent liabilities at the financial statement date and reported amounts of revenue and expenses during the reporting period. On an ongoing basis, we review our estimates and assumptions. Our estimates are based on our historical experience and other assumptions that we believe to be reasonable under the circumstances. Actual results are likely to differ from those estimates under different assumptions or conditions, but we do not believe such differences will materially affect our financial position or results of operations. Our critical accounting policies, the policies we believe are most important to the presentation of our financial statements and require the most difficult, subjective and complex judgments, are outlined below in ''Critical Accounting Policies,'' and have not changed significantly. 
+In addition, certain statements made in this report may constitute "forward-looking statements". These forward-looking statements involve known or unknown risks, uncertainties and other factors that may cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. These factors include, among others, 1) our ability to obtain necessary regulatory approvals for our products; and 2) our ability to increase revenues and operating income, which is dependent upon our ability to develop and sell our products, general economic conditions, demand for our products, and other factors. You can identify forward-looking statements by terminology such as "may," "could", "will," "should," "expects," "intends," "plans," "anticipates," "believes," "estimates," "predicts," "potential," "continues" or the negative of these terms or other comparable terminology. Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance or achievements. 
+Except as may be required by applicable law, we do not undertake or intend to update or revise our forward-looking statements, and we assume no obligation to update any forward-looking statements contained in this report as a result of new information or future events or developments. Thus, you should not assume that our silence over time means that actual events are bearing out as expressed or implied in such forward-looking statements. You should carefully review and consider the various disclosures we make in this report and our other reports filed with the Securities and Exchange Commission that attempt to advise interested parties of the risks, uncertainties and other factors that may affect our business. 
+All of the Company's future products that are currently being developed are based on its patented Dual Path Platform (DPP®), which is a unique diagnostic point-of-care platform that has certain advantages over lateral flow technology. The Company has completed development of several products that employ the DPP® technology which are currently marketed under Chembio's label (DPP® HIV 1/2 Screening Assay and DPP® HIV 1/2 –Syphilis Assay), or which may be marketed pursuant to private label license or distribution agreements such as those with the Oswaldo Cruz Foundation ("FIOCRUZ") and Bio-Rad. 
+Research and development ("R&D"), milestone, and grant and royalty revenues for the year ended December 31, 2015 increased to $2,369,000 from $1,696,000 in the prior-year, which was the result of additional grants awarded in 2015 over 2014. R&D expenses in the year of 2015 were $6.38 million, compared with $4.83 million in the prior-year. 
+Research & Development Activities 
+Sexually Transmitted Disease 
+· 
+DPP® HIV-Syphilis Assay: The DPP® HIV-Syphilis Assay is a rapid, point-of-care (POC), multiplex test for the simultaneous detection of antibodies to HIV and to Treponema Pallidum (TP) bacteria (the causative agent of syphilis). This novel combination assay was developed to address the growing concern among public health officials regarding the rising co-infection rates of HIV and syphilis as well as mother-to-child transmission (MTCT) of HIV and syphilis. The product was successfully launched in Mexico during 2014, and received approval for commercial use by the Brazilian regulatory agency, Agência Nacional de Vigilância Sanitária (ANVISA). The DPP® HIV-Syphilis Assay is the only test cleared for commercialization in Brazil for rapid, POC detection of both HIV 1/2 and syphilis. We are developing a U.S. version of the DPP® HIV-Syphilis Assay, designed to meet the performance requirements for the "reverse" algorithm that is currently in clinical use for syphilis testing in the United States. We have completed our pre-clinical studies for this product with encouraging results, and are in the final stages of clinical site selection for our U.S. clinical studies. We plan to begin this clinical trial in the U.S. during first quarter of 2016, and expect that the trial will be completed in six to nine months from initiation. 
+Fever Disease 
+· 
+DPP® Malaria Assay: The DPP® Malaria Assay is a rapid, POC, multiplex test for the simultaneous detection of plasmodium falciparum and other plasmodium infections. In January 2015, we received a grant from The Bill & Melinda Gates Foundation to expedite the development and feasibility testing of a POC DPP® Malaria Assay. The Company recently completed this project, which compared the new DPP ® Malaria Assay to the world's leading currently-available POC malaria assay. Based on initial testing, the new DPP ® Malaria Assay met the major objective of the feasibility project: a ten-fold improvement in sensitivity. Given these results, we plan to develop and commercialize a family of DPP® Malaria Assays. 
+· 
+DPP® Fever Panel Assay: The DPP® Fever Panel Assay is a rapid, POC, multiplex test for the simultaneous detection of Malaria, Dengue, Chikungunya, Zika, Ebola, Lassa, and Marburg. In October 2015, we received a $2.1 million grant from the Paul G. Allen Ebola Program, to develop the DPP® Fever Panel Assay and a follow-on grant to add a test for the detection of Zika virus. We plan to be ready for field testing in the fourth quarter of 2016. 
+· 
+DPP® Ebola Assay and DPP® Malaria-Ebola Assay: The DPP® Ebola Assay is a rapid POC test for the detection of Ebola and the DPP® Malaria-Ebola Assay is a rapid, POC, multiplex test for the simultaneous detection of Malaria and Ebola. In October 2014, we announced plans to develop, validate, and commercialize POC DPP ® Assays for Ebola and Febrile Illness. We completed the development of the DPP® Ebola Assay and submitted it for Emergency Use Authorization (EUA) with the Food & Drug Administration (FDA) and World Health Organization (WHO). During the third and fourth quarters of 2015, we sold DPP® Ebola and DPP® Malaria-Ebola Assays to the Centers for Disease Control & Prevention (CDC) for field studies in West Africa, which is ongoing. 
+· 
+DPP® Dengue Fever Assay: The DPP® Dengue Fever Assay is a rapid, POC, multiplex test for the simultaneous detection of IgG/IgM and NS1 antigens. We are currently conducting verification and validation studies, and we anticipate the production of pilot lots, to support preclinical studies. We anticipate starting pre-clinical studies in the second quarter of 2016. This program is fully funded by a partner. However, under the terms of our agreement, Chembio's partner is not being disclosed. 
+· 
+DPP® Zika Assays: The DPP® Zika Assay is a rapid POC stand-alone test for the simultaneous detection of IgG/IgM antibodies and the DPP® Dengue/Chikungunya/Zika Assay is a rapid, POC, multiplex test for the simultaneous detection of IgG/IgM antibodies. 
+· 
+In February 2016, we received a $550,000 grant from the Paul G. Allen Family Foundation to develop the DPP® Zika Assays, which we plan to be ready for field testing in 2016. 
+18 
+Technology Collaboration 
+· 
+DPP® Cancer Assay: The DPP® Cancer Assay is a rapid, POC, multiplex test for the early detection and monitoring of a specific type of cancer. In October 2014, we entered into collaboration with an international diagnostics company to develop a POC diagnostic test for a specific type of cancer. This program is fully funded by a partner. However, under the terms of the agreement, neither Chembio's partner nor the specific type of cancer is being disclosed. The cancer project represents an application of the DPP® technology outside of the infectious disease field, and the scope of the agreement involves product development of a quantitative, reader-based cancer assay for two cancer markers, utilizing Chembio's DPP® technology and DPP® Micro Reader. During the third quarter of 2015, we completed successful feasibility, and our partner agreed to fund continued development of the DPP® Cancer Assay. 
+· 
+DPP® Traumatic Brain Injury Assay: The DPP® Traumatic Brain Injury Assay is a rapid POC test for the detection of traumatic brain injury (TBI) and sports-related concussion. In January 2015, we entered into an agreement with the Concussion Science Group (CSG) Division of Perseus Science Group LLC, to combine CSG's patented biomarker with our proprietary DPP® platform and DPP® Micro Reader, to develop a semi-quantitative or quantitative POC test, to diagnose TBI. In May 2015, an Informational Meeting was conducted at the FDA to present the technology and intended use, as well to initiate dialogue regarding the regulatory pathway for this product. The DPP® Traumatic Brain Injury Assay is in the feasibility stage. We are currently working with several hospitals to finalize institutional review board (IRB) agreements and develop the plan for conducting initial studies of the DPP® Traumatic Brain Injury Assay using patient samples. 
+· 
+DPP® FLU Immunostatus Assay: The DPP® FLU Immunostatus Assay is a rapid, POC, multiplex influenza immunity test. In November 2014, we entered into a follow-on, milestone-based development agreement with a contracting organization acting on behalf of the U.S. government, for a multiplex POC influenza immunity test utilizing our patented DPP® technology. We successfully completed the product development of a 7-band multiplex DPP® Flu Immunostatus Assay with a digital reader during the first quarter of 2015 and subsequently applied for additional funding in response to a new request for proposal (RFP) from the U.S. Government, for which we expect a response in the second quarter of 2016. 
+Regulatory Activities 
+DPP® HIV 1/2 Assay: In May 2015 we received approval for a CE Mark for the DPP® HIV 1/2 Assay for Oral Fluid, Serum, Plasma, Fingerstick Whole Blood and Venous Whole Blood. The Chembio DPP® HIV 1/2 Assay for rapid, POC detection of HIV is now cleared for commercialization and sale within the 28 member states of the European Union . 
+DPP® HIV-Syphilis: The DPP® HIV-Syphilis Assay is a rapid, POC, multiplex test for the simultaneous detection of antibodies to HIV and to Treponema Pallidum (TP) bacteria (the causative agent of syphilis). This novel combination assay was developed to address the growing concern among public health officials regarding the rising co-infection rates of HIV and syphilis as well as mother-to-child transmission (MTCT) of HIV and syphilis. The product was successfully launched in Mexico during 2014, and received approval for commercial use by the Brazilian regulatory agency, Agência Nacional de Vigilância Sanitária (ANVISA). The DPP® HIV-Syphilis Assay is the only test cleared for commercialization in Brazil for rapid, POC detection of both HIV 1/2 and syphilis. In December 2015, the application by way of technical file was submitted to the Notified Body for CE Mark consideration to commercialize within the European Union . 
+We have developed a U.S. version of the DPP® HIV-Syphilis Assay, designed to meet the performance requirements for the "reverse" algorithm that is currently in clinical use for syphilis testing in the United States. We have completed our pre-clinical studies for this product with encouraging results, and have identified clinical sites for our U.S. clinical studies. We plan to begin this clinical trial in the U.S. during first quarter of 2016, and expect that the trial will be completed in six to nine months from initiation. 
+There can be no assurance that any of the aforementioned Research & Development and/or Regulatory products or activities will result in any product approvals or commercialization, nor that any of the existing research and development activities, or any new potential development programs or collaborations will materialize or that they will meet regulatory or any other technical requirements and specifications, and/or that if continued, will result in completed products, or that such products, if they are successfully completed, can or will be successfully commercialized. 
+Recent Events 
+On February 19, 2016, the Company announced it had been awarded a $550,000 grant from philanthropist and entrepreneur Paul G. Allen to immediately initiate development of simple, cost-effective POC diagnostic tests to identify Zika virus and related febrile illnesses. The grant is managed by Mr. Allen's company, Vulcan Inc., and the funds come from the Paul G. Allen Family Foundation. 
+On March 7, 2016, the Company announced plans to collaborate with Bio-Manguinhos/Fiocruz to undertake to develop, register and commercialize POC DPP® Zika Assays for Brazil. The Company has developed a prototype DPP® Zika Assay and prototype DPP® Zika/Dengue/Chikungunya Assay, and we hope to receive additional funding, along with the grant mentioned above, to accelerate the development and testing of our DPP® Zika Assays. The Company anticipates receiving significant orders for DPP® Zika Assays in 2016. 
+19 
+RESULTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2015 AS COMPARED WITH THE YEAR ENDED DECEMBER 31, 2014 
+Income : 
+For the year ended December 31, 2015, Loss before income taxes was $(3,557,000) compared to Loss before income taxes of $(1,550,000) for the year ended December 31, 2014. Net Loss for the 2015 period was $(2,397,000) as compared to a Net Loss of $(1,137,000) for 2014. The change in Net Loss is primarily attributable to decreased revenue and gross margin, and increased operating expenses. Gross margin decreased in the year ended December 31, 2015 as compared with the year ended December 31, 2014, by $327,000, or 3.0%. The increased operating expenses, the most significant of which were an increase in wages and related expenses of $779,000, an increase in materials and supplies for R&D of $758,000, and increased clinical trial expenses of $161,000 , partially offset by decreased commission expenses of $141,000, accounted for most of the change in Net Loss. 
+Revenues: 
+Selected Product Categories: 
+For the years ended 
+December 31, 2015 
+December 31, 2014 
+$ Change 
+% Change 
+Lateral Flow HIV Tests and Components 
+$ 
+9,957,882 
+$ 
+9,518,242 
+$ 
+439,640 
+4.62 
+% 
+DPP ® Tests and Components 
+11,265,876 
+15,655,680 
+(4,389,804 
+) 
+-28.04 
+% 
+Other 
+662,930 
+775,847 
+(112,917 
+) 
+-14.55 
+% 
+Net Product Sales 
+21,886,688 
+25,949,769 
+(4,063,081 
+) 
+-15.66 
+% 
+License and royalty revenue 
+52,753 
+23,257 
+29,496 
+126.83 
+% 
+R&D, milestone and grant revenue 
+2,316,044 
+1,672,258 
+643,786 
+38.50 
+% 
+Total Revenues 
+$ 
+24,255,485 
+$ 
+27,645,284 
+$ 
+(3,389,799 
+) 
+-12.26 
+% 
+Revenues for our lateral flow HIV tests and related components during the year ended December 31, 2015 increased by approximately $440,000 from the same period in 2014. This was primarily attributable to increased sales to Africa, of approximately $1,576,000 and increased sales to Europe of $973,000, partially offset by decreased sales to the U.S. of $1,604,000, and decreased sales to Mexico of $458,000. Revenues for our DPP® products during the year ended December 31, 2015 decreased by approximately $4,390,000 over the same period in 2014, primarily for decreases in sales in Mexico of $3,455,000 and decreases in sales in Brazil to FIOCRUZ of $2,112,000, partially offset by increased sales in the U.S. of $1,011,000. The increase in R&D, and in milestone and grant revenue, was primarily due to revenues from certain development projects that were awarded during the period. R&D revenues include funds, recognized on an "as expenses are incurred" basis or on a milestone basis, from various grants, see footnote 14 of our financial statements. 
+Gross Margin: 
+Gross Margin related to Net Product Sales: 
+For the years ended 
+December 31, 2015 
+December 31, 2014 
+$ Change 
+% Change 
+Gross Margin per Statement of Operations 
+$ 
+10,486,827 
+$ 
+10,814,023 
+$ 
+(327,196 
+) 
+-3.03 
+% 
+Less: R&D, milestone, grant, license and royalties 
+2,368,797 
+1,695,515 
+673,282 
+39.71 
+% 
+Gross Margin from Net Product Sales 
+$ 
+8,118,030 
+$ 
+9,118,508 
+$ 
+(1,000,478 
+) 
+-10.97 
+% 
+Product Gross Margin % 
+37.09 
+% 
+35.14 
+% 
+The overall gross margin dollar decrease of $327,000 included a $1,000,000 decrease in gross margin from net product sales and a $673,000 increase in non-product revenues. The decrease in net product sales gross margin of $1,000,000 is primarily attributable to the change in product sales compared to 2014. The net product sales gross margin decrease is comprised of two components, one is the decrease in product sales of $4,063,000, which at the 35.1% margin contributed $1,428,000 to the decrease, and the other is the increased change in margin percentage of 2.0% which contributed the balance of $427,000. The 2.0% increase in the percentage, from 35.1% in 2014 to 37.1% in 2015, was primarily due to increased efficiencies from our operations excellence program. 
+20 
+Research and Development: 
+This category includes costs incurred for clinical and regulatory affairs and for product research and development. 
+Selected expense lines: 
+For the years ended 
+December 31, 2015 
+December 31, 2014 
+$ Change 
+% Change 
+Clinical and Regulatory Affairs: 
+Wages and related costs 
+$ 
+490,802 
+$ 
+448,852 
+$ 
+41,950 
+9.35 
+% 
+Consulting 
+44,135 
+29,741 
+14,394 
+48.40 
+% 
+Stock-based compensation 
+- 
+3,231 
+(3,231 
+) 
+-100.00 
+% 
+Clinical trials 
+366,469 
+205,589 
+160,880 
+78.25 
+% 
+Other 
+80,960 
+93,780 
+(12,820 
+) 
+-13.67 
+% 
+Total Regulatory 
+982,366 
+781,193 
+201,173 
+25.75 
+% 
+R&D Other than Regulatory: 
+Wages and related costs 
+2,896,226 
+2,456,514 
+439,712 
+17.90 
+% 
+Consulting 
+128,117 
+123,965 
+4,152 
+3.35 
+% 
+Stock-based compensation 
+62,713 
+41,306 
+21,407 
+51.83 
+% 
+Materials and supplies 
+1,779,046 
+1,021,516 
+757,530 
+74.16 
+% 
+Other 
+529,371 
+408,043 
+121,328 
+29.73 
+% 
+Total other than Regulatory 
+5,395,473 
+4,051,344 
+1,344,129 
+33.18 
+% 
+Total Research and Development 
+$ 
+6,377,839 
+$ 
+4,832,537 
+$ 
+1,545,302 
+31.98 
+% 
+Expenses for Clinical and Regulatory Affairs for the year ended December 31, 2015 increased by $201,000 as compared to the same period in 2014. This was primarily due to an increase of $161,000 in clinical trial expenses and increased wages and related costs of $42,000. 
+R&D expenses other than Clinical & Regulatory Affairs increased by $1,344,000 in the year ended December 31, 2015, as compared with the same period in 2014. The increases were primarily related to an increase in wages and related costs, and in material and supplies, to support our sponsored research and internal development programs. 
+Selling, General and Administrative Expense: 
+Selected expense lines: 
+For the years ended 
+December 31, 2015 
+December 31, 2014 
+$ Change 
+% Change 
+Wages and related costs 
+$ 
+3,060,407 
+$ 
+2,763,370 
+$ 
+297,037 
+10.75 
+% 
+Consulting 
+311,488 
+456,658 
+(145,170 
+) 
+-31.79 
+% 
+Commissions 
+1,291,453 
+1,432,567 
+(141,114 
+) 
+-9.85 
+% 
+Stock-based compensation 
+271,674 
+399,334 
+(127,660 
+) 
+-31.97 
+% 
+Marketing materials 
+223,445 
+345,426 
+(121,981 
+) 
+-35.31 
+% 
+Investor relations/investment bankers 
+204,198 
+168,410 
+35,788 
+21.25 
+% 
+Legal, accounting and compliance 
+879,887 
+662,522 
+217,365 
+32.81 
+% 
+Travel, entertainment and trade shows 
+448,599 
+320,280 
+128,319 
+40.06 
+% 
+Bad debt allowance (recovery) 
+- 
+28,000 
+(28,000 
+) 
+-100.00 
+% 
+Other 
+971,884 
+955,172 
+16,712 
+1.75 
+% 
+Total S, G &A 
+$ 
+7,663,035 
+$ 
+7,531,739 
+$ 
+131,296 
+1.74 
+% 
+Selling, general and administrative expenses for the year ended December 31, 2015, increased by $131,000 as compared with the same period in 2014, a 1.7% increase. This increase resulted primarily from increases in wages and related costs and travel expenses, which for 2015 included the continued development of a sales and marketing team over 2014, professional fees and in investor relations/investment bankers, which were partially offset by decreases in consulting, commissions (due to decreased sales to Brazil), stock-based compensation, and marketing materials. 
+21 
+Other Income and Expense: 
+For the years ended 
+December 31, 2015 
+December 31, 2014 
+$ Change 
+% Change 
+Other (expense) 
+$ 
+(4,814 
+) 
+$ 
+(5,707 
+) 
+$ 
+893 
+15.65 
+% 
+Interest income 
+2,412 
+5,839 
+(3,427 
+) 
+-58.69 
+% 
+Interest expense 
+(836 
+) 
+- 
+(836 
+) 
+100.00 
+% 
+- 
+- 
+- 
+Total Other Income and (Expense) 
+$ 
+(3,238 
+) 
+$ 
+132 
+$ 
+(3,370 
+) 
+-2,553.03 
+% 
+Other (expense) for the year ended December 31, 2015 decreased approximately $3,400, primarily due to decreased interest income, compared to the same period in 2014. 
+Income tax provision (benefit): 
+For the year ended December 31, 2015 the Company recognized a $(1,160,000) income tax benefit and increased its deferred tax assets by $(1,160,000). For the year ended December 31, 2014, the Company recognized a $(413,000) income tax benefit and increased its deferred tax assets by $(403,000). The effective tax rate used to recognize the benefit in 2015 was 32.0% compared to a 26.6% rate used in 2014 to record the amount charged. In both years non-deductible expenses for tax purposes accounted for most of the difference from the standard 34% U.S. tax rate. The Company maintains a full valuation allowance on research and development tax credits 
+MATERIAL CHANGES IN FINANCIAL CONDITION 
+Selected Changes in Financial Condition 
+As of 
+December 31, 2015 
+December 31, 2014 
+$ Change 
+% Change 
+Cash and cash equivalents 
+$ 
+5,376,931 
+$ 
+4,614,538 
+$ 
+762,393 
+16.52 
+% 
+Accounts receivable, net of allowance for doubtful accounts of $52,000 and $52,000 at December 31, 2015 and 2014, respectively 
+2,422,971 
+8,338,889 
+(5,915,918 
+) 
+-70.94 
+% 
+Prepaid expenses and other current assets 
+1,256,879 
+1,066,473 
+190,406 
+17.85 
+% 
+Fixed assets, net of accumulated depreciation 
+2,374,308 
+2,797,929 
+(423,621 
+) 
+-15.14 
+% 
+License agreements, net of current portion 
+100,000 
+256,875 
+(156,875 
+) 
+-61.07 
+% 
+Deferred tax asset, net of valuation allowance 
+5,467,143 
+4,031,302 
+1,435,841 
+35.62 
+% 
+Accounts payable and accrued liabilities 
+2,801,432 
+4,946,030 
+(2,144,598 
+) 
+-43.36 
+% 
+Cash increased by $762,000 from December 31,2014, primarily due to net cash provided by operating activities for the year of 2015. In addition there were decreases in accounts receivable, net of allowance, of $5,916,000, fixed assets of $424,000 after depreciation, license agreements of $157,000, accounts payable and accrued liabilities of $2,145,000, and increases in non-current deferred tax asset of $1,436,000 and in prepaid expenses of $190,000. 
+The decrease in accounts receivable was primarily attributable to the lower amount of credit sales at the end of December 2015 versus December 2014. The decrease in fixed assets is primarily due to depreciation. The increase in prepaid and other current assets is due to the current portion of additional licenses. Deferred tax asset decrease is related to recording of a valuation allowance. 
+22 
+LIQUIDITY AND CAPITAL RESOURCES 
+For the years ended 
+December 31, 2015 
+December 31, 2014 
+$ Change 
+% Change 
+Net cash provided by (used in) operating activities 
+$ 
+1,792,978 
+$ 
+(3,820,299 
+) 
+$ 
+5,613,277 
+146.93 
+% 
+Net cash used in investing activities 
+(1,030,585 
+) 
+(1,452,601 
+) 
+422,016 
+29.05 
+% 
+Net cash provided by financing activities 
+- 
+237,163 
+(237,163 
+) 
+-100.00 
+% 
+INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 
+$ 
+762,393 
+$ 
+(5,035,737 
+) 
+$ 
+5,798,130 
+115.14 
+% 
+The Company's cash increased as of December 31, 2015 by $762,000 from December 31, 2014, primarily due to net cash provided by operating activities and partially offset by cash used in investing activities for year of 2015. 
+The cash provided by operations in 2015 was $1,793,000, primarily due to a decrease in accounts receivable of $5,916,000, a decrease in inventories of $60,000 and an increase in deferred revenue of $13,000, partially offset by an increase in prepaid and other current assets of $191,000, a decrease in accounts payable and other accrued liabilities of $2,145,000 and a net loss net of non-cash items of $1,861,000. Net loss net of non-cash items includes net loss of $2,397,000, $1,171,000 in income tax benefit, partially offset by $1,373,000 in depreciation and amortization, and $334,000 in share-based compensation. The use of cash from investing activities is primarily the purchase of fixed assets and acquisition of licenses. 
+Fixed Asset Commitments 
+As of December 31, 2015, the Company had paid deposits on various pieces of equipment aggregating $30,918 which is reflected in Other Assets on the balance sheet. The Company is further committed to additional equipment-purchase obligation of $31,000 as various milestones are achieved by the various vendors. 
+23 
+RECENT DEVELOPMENTS AND CHEMBIO'S PLAN OF OPERATIONS FOR THE NEXT TWELVE MONTHS 
+During 2015, Chembio took important strategic steps to expand our patented DPP® technology to new markets. While the Company continues to strengthen its sexually transmitted disease business, we are also building robust product pipelines in two new areas: fever disease and technology collaborations. As sexually transmitted disease products continue to make important contributions to our business, we believe our new fever disease portfolio and technology collaborations will pave the way for future growth. 
+Sexually Transmitted Diseases 
+In the U.S. during 2015, Chembio recorded an increase in lateral flow sales of approximately $440,000 and an increase of DPP ® sales of more than $1.0 million (primarily as a result of sales to the CDC for DPP ® Malaria-Ebola and DPP ® Ebola Assays), as compared to the respective U.S. sales in 2014. We are optimistic about the increasing demand for our products in the U.S. We will also have full control of SURE CHECK ® HIV Assay, effective June 1, 2016, to add to our U.S. commercial efforts. 
+In Latin America, we experienced a decline in sales in 2015 due primarily to a $3.5 million decrease in sales of DPP ® HIV-Syphilis Assay in Mexico, related to excess inventory from 2014, and a $2.1 million decrease in sales of DPP ® HIV Assay in Brazil. We expect that our recently announced DPP ® Zika Assay program will expand our sales in this region, and given our initial indications for 2016, we believe Latin America will continue to be a strong market for Chembio. 
+In Europe, Chembio's partners, AAZ and BioSure, launched sales of Chembio's SURE CHECK ® HIV 1/2 self-testing kits in the U.K. and France, respectively. The launch of these private-label, self-testing kits in Europe was a great success, and we received kit orders that totaled approximately $1.0 million in 2015. HIV continues to pose a significant threat in Europe, and European health agencies aggressively promote the importance of testing for HIV. We believe our SURE CHECK ® HIV 1/2 product is particularly well-suited for the emerging European self-testing segment, given its ability to provide simple, fast and reliable detection of antibodies to HIV 1 and HIV 2. 
+Another important advancement in our sexually transmitted disease business during 2015 is the progress made with our DPP ® HIV-Syphilis Assay for the U.S. market. It is an important corporate priority to be the first-to-market in the U.S. with an HIV-Syphilis combination test. While the Company is already successfully marketing a DPP® HIV-Syphilis combo assay in Latin America, regulatory standards require additional enhancements for the U.S. market and completion of a clinical trial. We will initiate this clinical trial in the first quarter of 2016. We anticipate that the trial will be completed in six to nine months and cost between $1.0 and $1.5 million. We are also in the process of submitting the technical dossier for CE Mark which will allow us to commercialize the DPP ® HIV-Syphilis Assay in Europe. 
+Fever Disease 
+In response to the Ebola outbreak in West Africa, our fever disease business was initiated in Q4 2014, and expanded rapidly through 2015. Today we are collaborating with several of the world's leading health organizations with the goal of containing the spread of fever diseases around the globe through accurate and early diagnosis. In the last year, our fever disease product portfolio has grown to include the following highly differentiated products: 
+· 
+The DPP ® Fever Panel Assay which is funded by the Paul G. Allen Ebola Program, is a point-of-care (POC) test for the simultaneous detection of Malaria, Dengue Fever, Chikungunya, Zika, Ebola, Lassa and Marburg; 
+· 
+The DPP ® Malaria-Ebola and DPP ® Ebola Assays which were developed through a research collaboration agreement with the Centers for Disease Control and Prevention (CDC), are currently being field tested in West Africa; 
+· 
+The DPP ® Dengue Fever Assays which have been funded by an undisclosed entity, are currently being field tested in Asia; 
+· 
+The DPP ® Malaria Assay which has been funded by The Bill and Melinda Gates Foundation, is 10-times more sensitive than the current world-leading POC malaria test; and, 
+· 
+The recently-announced DPP ® Zika Assay, which has received initial funding from the Paul G. Allen Family Foundation. 
+· 
+The recently-announced plans to collaborate with Bio-Manguinhos/Fiocruz to undertake development of POC Zika tests for the Ministry of Health in Brazil. 
+As we are excited by each of these programs, the DPP ® Fever Panel Assay and the DPP ® Zika Assay in particular highlight the power, versatility and broad applicability of our DPP ® technology, and we believe both of these products to be truly groundbreaking. Our DPP ® Fever Panel Assay will be the first POC diagnostic test capable of testing for multiple fever diseases simultaneously. We believe this product will significantly improve the diagnosis and care for people in regions where there is regular exposure to fever diseases and their causes. The sensitivity, specificity and multiplexing capability of the DPP ® technology uniquely suits it for the fever disease market. Many of these diseases are present in the same regions with nearly identical symptoms. These factors make it difficult to make an accurate diagnosis and often delay appropriate treatment. Today, many available POC diagnostics are limited by their lack of the sensitivity and specificity required to identify asymptomatic patients. Further, there are currently no POC diagnostics capable of testing for multiple diseases simultaneously. For these reasons, Chembio is prioritizing development of our DPP ® Fever Panel Assay. 
+Our new DPP ® Zika Assay development also showcases the exceptional versatility and broad applicability of our DPP ® technology. In February, the World Health Organization (WHO) declared the Zika virus a 'public health emergency of international concern,' and today the virus has spread to more than twenty countries. In response to the outbreak, we began exploring the feasibility of a POC DPP ® Zika Assay. We are fortunate that the Paul G. Allen Family Foundation, recognizing the urgency of the matter, moved swiftly to provide Chembio with a grant to support the initiation of the project. We are pleased to report that in a few short weeks, we have developed a prototype assay and are in discussions with a number of agencies, all of which are interested in supporting the rapid development of this critical product. While this program is in the early stages, we hope that success with the DPP ® Zika Assay, like our DPP ® Ebola Assay, will further demonstrate Chembio's ability to rapidly and effectively deploy our DPP ® technology to address the world's most serious health threats with POC treatment in a practical and efficient manner. The Company anticipates receiving significant orders for DPP® Zika Assays in 2016. 
+Technology Collaborations 
+Chembio's technology collaborations represent another important business area for the Company. In the fourth quarter of 2014, we signed collaborative agreements for both the development of the DPP ® Cancer Assay for a specific form of cancer, and also for the DPP ® Flu Immunostatus Assay. In 2015, we added two more important new collaborations for the development of the DPP ® Traumatic Brain Injury Assay and the DPP ® Micro Reader. 
+We are pleased with the progress made with each of these programs in 2015. The DPP ® Cancer Assay, which is funded by an undisclosed entity, targets a specific form of cancer. During 2015, we successfully completed the feasibility phase of the program and moved into the product development stage, which is also funded by an undisclosed entity. The results to-date with this program have been highly encouraging. With success, we are hopeful that we'll be able to find additional applications for our DPP ® technology in the broader oncology market. 
+We also made important advances with our DPP® Traumatic Brain Injury Assay program during the year. This project, which is funded by Perseus Science Group, LLC, is in the feasibility phase. We are currently working with several hospitals to finalize institutional review board (IRB) agreements and develop the plan for conducting initial studies of the DPP® Traumatic Brain Injury Assay using patient samples. 
+24 
+We are awaiting response on the most recent multi-year grant proposal for completion of the DPP® Flu Immunostatus Assay, a multiplex assay to monitor 9 different seasonal and pandemic flu viruses. 
+An addtional new technology collaboration was signed in the fourth quarter of 2015 with opTricon, a leading developer of mobile analysis devices for rapid diagnostic tests. Through our exclusive agreement, Chembio will launch the DPP ® Micro Reader to complement a number of our proprietary assays for sexually transmitted diseases, certain fever diseases, and a specific form of cancer. We are particularly excited about offering this technology in combination with our assays. Using a state-of-the-art camera system, the DPP ® Micro Reader is designed to provide definitive diagnostic results for low analyte concentrations, which may otherwise result in faint or ambiguous test results. In addition, the DPP ® Micro Reader will provide customers with various options to capture, record, transmit and store test results. Because the DPP ® Micro Reader is simple, fast, palm-sized, battery-operated and cost-effective compared to traditional POC assay readers, it is unique in its attractiveness and utility, and we believe it will be well-received by the market. We are working to develop a suite of DPP ® Assay-Reader kits, and we look forward to commercialization of these innovative and versatile diagnostic systems. 
+2015 was an exciting and transformative time for Chembio. During the year, we significantly expanded the horizon for the utility of our DPP ® technology. This has led us to new and exciting applications beyond HIV to fever disease, brain injury, cancer and more. And in a short amount of time, we gained the attention of, and funding from, world-leading health organizations such as The Bill and Melinda Gates Foundation, the Paul G. Allen Family Foundation, the Centers for Disease Control and Prevention and Perseus Science who have aligned with Chembio and selected the DPP ® technology to address some of the world's most serious diagnostic obstacles. The events and opportunities of 2015 have considerably changed Chembio by significantly expanding the potential application and markets for our DPP ® technology. For many diseases, infections or conditions that requires exceptional sensitivity, specificity and/or the ability to multiplex, we believe our DPP ® technology may become the development platform of choice. Looking ahead to 2016, we will continue to advance each of our development programs, and look for new opportunities and applications. 
+25 
+Critical Accounting Policies and Estimates 
+The preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ materially from those estimates. 
+We believe that there are several accounting policies that are critical to understanding our historical and future performance, as these policies affect the reported amounts of revenue and the more significant areas involving management's judgments and estimates. These significant accounting policies relate to revenue recognition, research and development costs, valuation of inventory, valuation of long-lived assets and income taxes. These policies, and the related procedures, are described in detail below. 
+Revenue Recognition – 
+We recognize revenue for product sales in accordance with ASC 605, Revenue is recognized when there is persuasive evidence of an arrangement, delivery has occurred or services have been rendered, the sales price is determinable, and collectability is reasonably assured. Revenue typically is recognized at time of shipment. Sales are recorded net of discounts, rebates and returns. 
+For certain contracts, we recognize revenue from R&D, milestone and grant revenues when earned. Grants are invoiced after expenses are incurred. Revenues from projects or grants funded in advance are deferred until earned. 
+For certain collaborative research projects, we recognize revenue by defining milestones at the inception of the agreement and applying the milestone method of revenue recognition for relevant contracts. 
+Stock-Based Compensation – 
+We recognize the fair value of equity-based awards as compensation expense in our statement of operations. The fair value of our stock option awards was estimated using a Black-Scholes option valuation model. This valuation model's computations incorporate highly subjective assumptions, such as the expected stock price volatility and the estimated life of each award. The fair value of the options, after considering the effect of expected forfeitures, is then amortized, generally on a straight-line basis, over the related vesting period of the option. The fair value of our restricted shares is based on the market value of the shares at the date of grant and is recognized on a straight-line basis over the related vesting period of the award. 
+Research & Development Costs – 
+Research and development activities consist primarily of new product development, continuing engineering for existing products, regulatory and clinical trial costs. Costs related to research and development efforts on existing or potential products are expensed as incurred. 
+Valuation of Inventories – 
+Inventories are stated at the lower of cost or market, using the first-in, first-out method (FIFO) to determine cost. Our policy is to periodically evaluate the market value of the inventory and the stage of product life cycle, and record a reserve for any inventory considered slow moving or obsolete. For example, each additional 1% of obsolete inventory would reduce such inventory by approximately $36,000. 
+Allowance for doubtful accounts – 
+Our policy is to review our accounts receivable on a periodic basis, no less than monthly. On a quarterly basis an analysis is made of the adequacy of our allowance for doubtful accounts and adjustments are made accordingly. The current allowance is approximately 2% of accounts receivable. For example each additional 1% of accounts receivable that becomes uncollectible would reduce such balance of accounts receivable by approximately $24,000. 
+Income Taxes – 
+Income taxes are accounted for under ASC 740 authoritative guidance ("Guidance") which requires the asset and liability method of accounting for deferred income taxes. Deferred tax assets and liabilities are determined based on the difference between the financial statement and tax bases of assets and liabilities. Deferred tax assets or liabilities at the end of each period are determined using the tax rate expected to be in effect when taxes are actually paid or recovered. 
+The Guidance also requires that a valuation allowance be established when it is more likely than not that all or a portion of a deferred tax asset will not be realized. A review of all available positive and negative evidence needs to be considered, including a company's current and past performance, the market environment in which the company operates, length of carryback and carryforward periods and existing contracts that will result in future profits. The Company believes that it will be able to utilize its net operating loss carryforwards and has recorded a deferred tax asset. The Company still maintains a full valuation allowance on research and development tax credits. 
+The Guidance also prescribes a comprehensive model for recognizing, measuring, presenting and disclosing in the consolidated financial statements tax positions taken or expected to be taken on a tax return, including a decision whether to file or not to file in a particular jurisdiction. 
+The above listing is not intended to be a comprehensive list of all of our accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by accounting principles, generally accepted in the United States of America, with no need for management's judgment in their application. There are also areas in which management's judgment in selecting any viable alternative would not produce a materially different result. See our audited financial statements and notes thereto which contain accounting policies and other disclosures required by accounting principles generally accepted in the United States of America. 
+26 
+ITEM 8. 
+FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+The Consolidated Financial Statements and schedules that constitute Item 8 are attached at the end of this Annual Report on Form 10-K. An index to these Financial Statements and schedules is also included on page F-1 of this Annual Report on Form 10-K. 
+ITEM 9. 
+CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. 
+Not Applicable. 
+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+(a) Disclosure Controls and Procedures. Under the supervision and with the participation of our senior management, consisting of our chief executive officer and our chief financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), as of the end of the period covered by this report (the "Evaluation Date"). Based on that evaluation, the Company's management, including our chief executive officer and chief financial officer, concluded that as of the Evaluation Date our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports that we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. Our disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in our Exchange Act reports is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure. 
+Management's Annual Report on Internal Control Over Financial Reporting. The Company's management is responsible for establishing and maintaining an adequate system of internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f)). Our internal control over financial reporting is a process, under the supervision of our chief executive officer and chief financial officer, designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States. These internal controls over financial reporting processes include policies and procedures that: 
+a. 
+Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company; 
+b. 
+Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and 
+c. 
+Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance of achieving their control objectives. 
+In evaluating the effectiveness of our internal control over financial reporting, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework 2013. Based on this evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective as of December 31, 2015. 
+This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. 
+Management's report was not subject to attestation by our registered public accounting firm pursuant to the rules of the Securities and Exchange Commission that permit the Company to provide only management's report in this annual report. 
+(b) Changes in Internal Control over Financial Reporting. There were no changes in our internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Rule 13a-15 or Rule 15d-15 under the Exchange Act that occurred during the Company's last fiscal quarter of the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+ITEM 9B. 
+OTHER INFORMATION 
+Not applicable. 
+27 
+PART III 
+ITEM 10. 
+DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
+Directors and Executive Officers 
+John J. Sperzel (52), President, Chief Executive Officer and Director. Mr. Sperzel was appointed Chief Executive Officer and President of Chembio Diagnostics, Inc. and a member of our Board in March 2014. Prior to joining the Company, Mr. Sperzel, was the President and CEO of International Technidyne Corporation (ITC) from September 2011 to December 2013. Mr. Sperzel served as President at Axis-Shield from September 2004 to September 2011. He also has held senior leadership positions at Bayer Diagnostics (Siemens Dx), Instrumentation Laboratory, and Boehringer Mannheim Diagnostics (Roche Dx). Mr. Sperzel graduated from Plymouth State College in New Hampshire, with a B.S. in Business Administration/Management. He currently serves on the board of directors of Diadexus, Inc., a company which the common stock is registered under the Securities Exchange Act of 1934, and as an advisor to the board of the Diagnostic Marketing Association, and was the president of the board of that Association in 2007. Mr. Sperzel's knowledge of, and experience in, the Company's specific business and its industry sector, together with the continuing current knowledge that he is accumulating about the Company in his position as CEO of the Company, made him an excellent candidate for serving on the Board. 
+Richard J. Larkin (59), Chief Financial Officer. Mr. Larkin was appointed as Chief Financial Officer of Chembio Diagnostics, Inc. upon consummation of the merger in 2004. Mr. Larkin oversees our financial activities and information systems. Mr. Larkin has been the Chief Financial Officer of Chembio Diagnostic Systems Inc. since September 2003. Prior to joining Chembio Diagnostic Systems Inc., Mr. Larkin served as CFO at Visual Technology Group ("VTG") from May 2000 to September 2003, and also led VTG's consultancy program that provided hands-on expertise in all aspects of financial service, including the initial assessment of client financial reporting requirements within an Enterprise Resource Planning (Manufacturing) environment through training and implementation. Prior to joining VTG, he served as CFO at Protex International Corporation from May 1987 to January 2000. Mr. Larkin holds a BBA in Accounting from Dowling College and is a member of the American Institute of Certified Public Accountants. 
+Javan Esfandiari (49), Chief Science and Technology Officer. Mr. Esfandiari joined Chembio Diagnostic Systems, Inc, in 2000. Mr. Esfandiari co-founded, and became a co-owner of Sinovus Biotech AB where he served as Director of Research and Development concerning lateral flow technology until Chembio Diagnostic Systems Inc. acquired Sinovus Biotech AB in 2000. From 1993 to 1997, Mr. Esfandiari was Director of Research and Development with On-Site Biotech/National Veterinary Institute, Uppsala, Sweden, which was working in collaboration with Sinovus Biotech AB on development of veterinary lateral flow technology. Mr. Esfandiari received his B.Sc. in Clinical Chemistry and his M. Sc. in Molecular Biology from Lund University, Sweden. He has published articles in various veterinary journals and has co-authored articles on tuberculosis serology with Dr. Lyashchenko. 
+Sharon Klugewicz (48), Chief Operating Officer. Prior to joining the Company in September 2012, Ms. Klugewicz, served as Senior Vice President, Scientific & Laboratory Services at Pall Corporation (NYSE:PLL), a world leader in filtration, separation and purification technologies. Prior to that, Ms. Klugewicz held a number of positions at Pall Corporation over her 20-year tenure there, including in the Pall Life Sciences Division, in Marketing Product Management, and Field Technical Services, which included a position as Senior Vice President, Global Quality Operations. Ms. Klugewicz holds an M.S. in Biochemistry from Adelphi University and a B.S. in Neurobiology from Stony Brook University. 
+Dr. Gary Meller M.D. (65), Director. Dr. Meller was elected to our Board of Directors on March 15, 2005, and currently serves on the Board's Audit, and Nominating And Corporate Governance Committees, including as Chairman of the Audit Committee. Dr. Meller has been the president of CommSense Inc., a healthcare business development company, since 2001. CommSense Inc. works with clients in Europe, Asia, North America, and the Middle East on medical information technology, medical records, pharmaceutical product development and financing, health services operations and strategy, and new product and new market development. From 1999 until 2001 Dr. Meller was the executive vice president, North America, of NextEd Ltd., a leading internet educational services company in the Asia Pacific region. Dr. Meller also was a limited partner and a member of the Advisory Board of Crestview Capital Master LLC, which was our largest shareholder. Dr. Meller is a graduate of the University of New Mexico School of Medicine and has an MBA from the Harvard Business School. Dr. Meller's experience in the medical field both domestic and foreign (especially his experience with CommSense Inc.) as well as his financing experience make him an excellent candidate for serving on the board. 
+Kathy Davis (59), Director and Chair of the Board. Ms. Davis was elected to the Board in May 2007, and was elected in March 2014 to serve as Chair of the Board. She currently serves on the Board's Audit, Compensation, and Nominating And Corporate Governance Committees, including as Chair of the Nominating And Corporate Governance Committee. In 2014, Ms. Davis also served on the Board's CEO Search Committee, and in 2013 she served on the Board's Special Committee for handling certain strategic opportunities. Since January 2007, Ms. Davis has been the owner of Davis Design Group LLC, a company that provides analytical and visual tools for public policy design. As of January 1 2016 Ms. Davis serves as Systems Advisor to the Mayor of Indianapolis. Previously, from February 2005 to December 2006, she served as the Chief Executive Officer of Global Access Point, a start-up company with products for data transport, data processing, and data storage network and hub facilities. From October 2003 to January 2005, Ms. Davis was Lieutenant Governor of the State of Indiana, and from January 2000 to October 2003 was Controller of the City of Indianapolis. From 1989 to 2003, Ms. Davis held leadership positions with agencies and programs in the State of Indiana including State Budget Director, Secretary of Family & Social Services Administration, and Deputy Commissioner of Transportation. From 1982 to 1989 Ms. Davis held increasingly senior positions with Cummins Engine, where she managed purchasing, manufacturing, engineering, and assembly of certain engine product lines. Ms. Davis also led the startup of and initial investments by a $50 million Indiana state technology fund, serves on the not-for-profit boards of Noble of Indiana, Lumina Foundation for Education, Indianapolis Foundation, Central Indiana Community Foundation, Western Governor's University Indiana, and Indiana University School of Public and Environmental Affairs. She holds a Bachelor of Science in Mechanical Engineering from the Massachusetts Institute of Technology and an MBA from Harvard Business School. Ms. Davis has varied experience in business, political and financial areas that made her an excellent candidate for serving on the Board. 
+Dr. Barbara DeBuono M.D., M.P.H., (60), Director . Dr. DeBuono, who was elected to the Company's Board of Directors in June 2011, currently serves on the Board's Compensation and Nominating And Corporate Governance Committees, including as Chair of the Compensation Committee. Ms. DeBuono is a renowned expert in public health innovation, health policy, education and research. She currently serves as a consultant to both public and private entities involved in healthcare, healthcare policy and healthcare products. From May 2011 to January 31,2012., Dr. DeBuono served as President and CEO of ORBIS International, which is dedicated to saving sight and eliminating avoidable blindness worldwide with headquarters in New York City. Previously, from 2009-2011, Dr. DeBuono was Chief Medical Officer, Partner and Global Director of Health and Social Marketing at Porter Novelli, and from 2000-2008 she was Executive Director, Public Health and Government at Pfizer Inc. Dr. DeBuono has served as Commissioner of Health for the state of New York and as Director of Health in Rhode Island and she was honored by the CDC Foundation in 2005 as one of five Public Health Heroes nationwide. She serves as adjunct professor at The George Washington University School of Public Health, and is a co-founder of The MAIA Foundation, a charity dedicated to women's health in sub-Saharan Africa. A Fellow of the American College of Physicians, Dr. DeBuono received her B.A. from the University of Rochester, her M.D. from the University of Rochester School of Medicine, and a Masters in Public Health (M.P.H.) from Harvard University School of Public Health. Dr. DeBuono's experience in and knowledge of, both domestic and international, public health services, public health innovations, and the medical field make her an excellent candidate for serving on the board. 
+28 
+Dr. Peter Kissinger, Ph.D. (71), Director. Dr. Kissinger, who was elected to the Company's Board of Directors in June 2011 , currently serves on the Company's Audit, and Compensation Committees. Dr. Kissinger is a scientist, entrepreneur and academic, with a multi-faceted career in biotechnology and biomedical technologies. He is the founder of Bioanalytical Systems, Inc. (NASDAQ: BASI), which he led from 1974-2007, and is Professor of Chemistry at Purdue University, West Lafayette, Indiana. Dr. Kissinger's academic research has involved the study of modern liquid chromatography techniques, and in vivo methodology for drug metabolism and the neurosciences. Dr. Kissinger has published more than 240 scientific papers and is a Fellow of the American Association of Pharmaceutical Scientists and the American Association for the Advancement of Science. In 2005, he became the Chairman of Prosolia, which markets mass spectrometry innovations for life science, industrial and homeland security applications. In 2007, he and Candice Kissinger founded Phlebotics, Inc., a medical device company focused on diagnostic information for intensive care medicine. He is a columnist for the trade publication Drug Discovery News. Dr. Kissinger received a B.S. in Chemistry from Union College, Schenectady, N.Y. and a Ph.D. in Analytical Chemistry from the University of North Carolina in Chapel Hill. Dr. Kissinger has knowledge of and experience in biotechnology and biomedical technologies as well as publicly-traded companies, all of which make him an excellent candidate for serving on the board. 
+Section 16(a) Beneficial Ownership Reporting Compliances 
+Section 16(a) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), requires the Company's directors, executive officers and beneficial owners of more than 10% of the Company's common stock to file with the Securities and Exchange Commission initial reports of ownership and reports of changes in ownership of common stock and other equity securities of the Company. The Company believes that during the year ended December 31, 2015, each person who was an officer, director and beneficial owner of more than 10% of the Company's common stock complied with all Section 16(a) filing requirements . 
+Code of Ethics 
+The Company has adopted a code of ethics that applies to its principal executive officer, principal financial officer, controller, and persons performing similar functions. A copy of the Company's code of ethics is available on the Company's website at www.chembio.com. 
+Identification of Audit Committee; Audit Committee Financial Expert 
+The Company's board of directors has established an audit committee. Katherine L. Davis, Dr. Pete Kissinger and Dr. Gary Meller each serves on the audit committee, with Dr. Meller serving as chairman. The Company's board of directors has determined that, based on his past experience, Dr. Meller is an audit committee financial expert and is independent. 
+29 
+ITEM 11. 
+EXECUTIVE COMPENSATION 
+The following table summarizes all compensation recorded by the Company in each of the last two completed fiscal years for our principal executive officer and our two most highly compensated executive officers other than our principal executive officer whose annual compensation exceeded $100,000. 
+Name / 
+Salary 1 
+Bonus 2 
+Stock 
+Option Awards 3 
+All Other Compensation 5 
+Total 
+Principal 
+($) 
+($) 
+Awards 
+($) 
+($) 
+($) 
+Position 
+Year 
+($) 
+John J. Sperzel 4 
+2015 
+$ 
+375,000 
+$ 
+70,000 
+$ 
+- 
+$ 
+- 
+$ 
+- 
+$ 
+445,000 
+CEO 
+2014 
+$ 
+298,558 
+$ 
+- 
+$ 
+- 
+$ 
+669,625 
+$ 
+- 
+$ 
+968,183 
+Javan Esfandiari 
+2015 
+$ 
+304,130 
+$ 
+60,000 
+$ 
+- 
+$ 
+- 
+$ 
+10,520 
+$ 
+374,650 
+CSTO 
+2014 
+$ 
+315,000 
+$ 
+90,000 
+$ 
+- 
+$ 
+- 
+$ 
+9,825 
+$ 
+414,825 
+Sharon Klugewicz 
+2015 
+$ 
+259,000 
+$ 
+40,000 
+$ 
+- 
+$ 
+- 
+$ 
+5,180 
+$ 
+304,180 
+COO 
+2014 
+$ 
+259,616 
+$ 
+75,000 
+$ 
+- 
+$ 
+- 
+$ 
+4,182 
+$ 
+338,798 
+1 Salary is total base salary. John Sperzel's 2014 salary reflects his base pay from commencement of his employment on March 13, 2014 until the end of 2014. 
+2 Bonuses earned in 2015 and 2014 were partially based on reaching certain objectives, which included revenue dollar levels and operating profit levels. Additional amounts earned were discretionary. 
+3 The estimated fair value of any option or common stock granted was determined in accordance with ASC 718, "Stock-Based Payment". 
+4 Mr. Sperzel also serves as a director on the Company's board of directors. Mr. Sperzel does not receive any compensation for this director role. 
+5 Other compensation includes an employer match to 401(K) contributions and car allowances where applicable. 
+Employment Agreements 
+Mr. Sperzel. Effective March 13, 2014 (the "Effective Date"), the Company entered into an Employment Agreement with John J. Sperzel III to serve as the Company's CEO for a term of three years. Mr. Sperzel's annual base salary is $375,000, with the possibility of a discretionary, performance-based annual cash bonus of up to 40% of his base salary. The Employment Agreement also provides for a grant of 250,000 options to purchase shares of the Company's common stock, 43,132 of which will be incentive stock options under the Company's 2008 Stock Incentive Plan (the "Plan"), and 206,868 of which will be non-qualified stock options. The options will become exercisable at the rate of 50,000 shares per year for each of the first through the fifth anniversary of the Effective Date. In the event Mr. Sperzel's employment is terminated by reason of disability or for "cause," as defined in the Employment Agreement, all compensation, including his base salary, his right to receive a performance bonus, and the vesting of any unvested options, will cease as of his termination date, and Mr. Sperzel will receive no severance benefits. If the Company terminates Mr. Sperzel's employment without cause or Mr. Sperzel terminates his employment for a reasonable basis, as defined in the Employment Agreement (which includes involuntary termination within a six-month period upon a "Change of Control"), then the Company will pay Mr. Sperzel his base salary for a period of six months as severance and all of his unvested stock options immediately shall become vested. The Employment Agreement also contains provisions prohibiting Mr. Sperzel from (i) soliciting the Company's employees for a period of 24 months following his termination, (ii) soliciting the Company's customers, agents, or other sources of distribution of the Company's business for a period of twelve months following his termination, and (iii) except where termination is involuntary upon a "Change in Control," engaging or participating in any business that directly competes with the business activities of the Company in any market in which the Company is in business or plans to do business during the period in which he is entitled to severance, or for a period of six months if he is not entitled to severance payments under the Employment Agreement. The foregoing description of the Employment Agreement is qualified in its entirety by reference to the full text of the Employment Agreement. 
+Mr. Esfandiari. The Company entered into an employment agreement effective March 5, 2013 (the "Employment Agreement"), with Mr. Esfandiari to continue as the Company's Chief Scientific and Technology Officer for an additional term of three years through March 5, 2016. The Company and Mr. Esfandiari currently are discussing terms for renewal of his employment agreement. Mr. Esfandiaris's salary under the Employment Agreement is $304,500 for the year ended March 5, 2016, and he is eligible for a performance-based bonus of up to 50% of his base salary for each year, which is in the same proportions as described below under "Executive Bonus Plan". The Company also granted Mr. Esfandiari, pursuant to the Company's 2008 Stock Incentive Plan, incentive stock options to purchase 30,000 shares of the Company's common stock. The price per share of these options is equal to the fair market value of the Company's common stock as of the close of the market on March 5, 2013, which is the trading date on which the Agreement was entered into. Of these stock options, options to purchase 10,000 shares vest on each of the first three anniversaries of the effective date of the Employment Agreement. Mr. Esfandiari is eligible to participate in any profit sharing, stock option, retirement plan, medical and/or hospitalization plan, and/or other benefit plans except for disability and life insurance that the Company may from time to time place in effect for the Company's executives during the term of Mr. Esfandiari's employment agreement. If Mr. Esfandiari's employment agreement is terminated by the Company without cause, or if Mr. Esfandiari terminates his employment agreement for a reasonable basis, as defined in the Employment Agreement, including within 12 months of a change in control, the Company is required to pay as severance Mr. Esfandiari's salary for twelve months. 
+Ms. Klugewicz. The Company entered into an employment agreement dated May 22, 2015 with Ms. Klugewicz (the "Employment Agreement"), effective May 22, 2015 (the "Effective Date"). The Agreement provides that she will serve as the Company's COO for a term of two years. Ms. Klugewicz will receive an annual salary of $265,000, with the option of a discretionary, performance-based annual cash bonus of up to 37.5% of her base salary. In the event Ms. Klugewicz's employment is terminated by reason of disability or for "cause", as defined in the Employment Agreement, all compensation including her base salary, her right to receive a performance bonus, and the vesting of any unvested options, will cease as of her termination date, and Ms. Klugewicz will receive no severance benefits. If the Company terminates Ms. Klugewicz's employment without cause or Ms. Klugewicz terminates her employment for a reasonable basis, as defined in the Employment Agreement (which definition includes involuntary termination within a six-month period upon a "Change of Control"), then the Company will pay Ms. Klugewicz her base salary for a period of six months as severance, and all her unvested stock options shall immediately become vested. The Employment Agreement also contains provisions prohibiting Ms. Klugewicz from (i) soliciting the Company's employees for a period of twenty-four months following her termination, (ii) soliciting the Company's customers, agents, or other sources of distribution of the Company's business for a period of twelve months following her termination, and (iii) for a period of twelve months following termination of this Agreement, except where termination is involuntary upon a "Change in Control," engaging or participating in any business that directly competes with the business activities of the Company in any market in which the Company is in business or plans to do business. The foregoing description of the Employment Agreement is qualified in its entirety by reference to the full text of the Employment Agreement. 
+None of the other officers of the Company has an employment contract with the Company. 
+30 
+Executive Bonus Plan 
+The Company has established a bonus plan for its executives who do not have a contract. For the fiscal year ended December 31, 2015, there were four executives eligible for this bonus plan. Each executive can earn up to 25% of that executive's salary in the form of a cash bonus. The Compensation Committee determined that 80% of the executive's bonus will be quantitative factors, based on the budget, and the other 20%, which will be based on other factors, will be discretionary. For 2015, the quantitative 80% portion of the plan called for attaining certain revenue goals, and for attaining certain operating profit goals. 
+OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END 2015 
+Option Awards 
+Stock Awards 
+Name 
+Number of Securities Underlying Unexercised Options Exercisable (#) 
+Number of Securities Underlying Unexercised Options Unexercisable 
+(#) 
+Option Exercise Price 
+($) 
+Option Expiration Date 
+Option Vesting Date 
+Number of Shares of Stock That Have Not Vested 
+(#) 
+Market Value of Shares of Stock That Have Not Vested 
+($) 
+Foot- 
+note 
+John J. Sperzel 
+25,000 
+3.4163 
+3/21/2021 
+3/13/2015 
+5 
+25,000 
+3.4163 
+3/21/2021 
+3/13/2015 
+2 
+18,132 
+3.4163 
+3/21/2021 
+3/13/2016 
+5 
+31,868 
+3.4163 
+3/21/2021 
+3/13/2016 
+2 
+50,000 
+3.4163 
+3/21/2021 
+3/13/2017 
+2 
+50,000 
+3.4163 
+3/21/2021 
+3/13/2018 
+2 
+50,000 
+3.4163 
+3/21/2021 
+3/13/2019 
+2 
+Javan Esfandiari 
+10,000 
+5.44 
+3/5/2018 
+3/5/2014 
+1 
+10,000 
+5.44 
+3/5/2018 
+3/5/2015 
+1 
+10,000 
+5.44 
+3/5/2018 
+3/5/2016 
+1 
+4,765 
+5.56 
+2/26/2018 
+2/26/2013 
+4 
+7,969 
+4.00 
+2/16/2017 
+2/16/2012 
+3 
+12,500 
+2.16 
+3/4/2015 
+3/5/2013 
+1 
+12,500 
+2.16 
+3/4/2015 
+3/5/2012 
+1 
+12,500 
+2.16 
+3/4/2015 
+3/5/2010 
+1 
+Sharon Klugewicz 
+2,500 
+4.50 
+5/22/2018 
+5/22/2014 
+1 
+2,500 
+4.50 
+5/22/2018 
+5/22/2015 
+1 
+630 
+5.56 
+2/26/2018 
+2/26/2013 
+4 
+12,000 
+4.45 
+9/4/2017 
+9/4/2013 
+5 
+12,000 
+4.45 
+9/4/2017 
+9/4/2014 
+5 
+12,000 
+4.45 
+9/4/2017 
+9/4/2015 
+5 
+1 Options issued in connection with an employment contract and under the 2008 Stock Incentive Plan. 
+2 Options issued in connection with the start of employment with the Company and not under a Plan. 
+3 On February 16, 2012, the Company determined to grant on February 16, 2012, to certain employees of the Company, options to purchase an aggregate of 203,125 shares of the Company's common stock. The exercise price for these options was the last traded market price for the Company's common stock on February 16, 2012, which was $4.00 per share. The options become exercisable on the effective date of the grant. Each option granted will expire and terminate, if not exercised sooner, upon the earlier to occur of (a) 30 days after termination of the employee's employment with the Company or (b) the fifth anniversary of the effective date of grant. 
+4 On February 26, 2013, the Company determined to grant on February 26, 2013 to certain employees of the Company, options to purchase an aggregate of 16,360 shares of the Company's common stock. The exercise price for these options was the last traded market price for the Company's common stock on February 26, 2013, which was $5.56 per share. The options become exercisable on the effective date of the grant. Each option granted will expire and terminate, if not exercised sooner, upon the earlier to occur of (a) 30 days after termination of the employee's employment with the Company or (b) the fifth anniversary of the effective date of grant. 
+5 Options issued in connection with the start of employment with the Company and under the 2008 Stock Incentive Plan. 
+31 
+Director Compensation 
+Effective January 1, 2015, all non-employee directors are paid $25,000 annual fee in semi-annual payments. In addition, once every five years, on the date of the annual meeting of shareholders at which a director is elected or re-elected (every 5 years), that director receives stock options to acquire, subject to vesting as described below, 46,875 shares of the Company's common stock, with an exercise price equal to the market price on the date of the grant. Stock options to acquire 9,375 shares become exercisable on the date of grant, and options to acquire an additional 9,375 shares become exercisable on the date of each of the four succeeding annual meetings of shareholders if and to the extent that the non-employee director is reelected as a director at each such annual meeting. [These options grants also are described in note 1 below.] Beginning in April 2014, the non-employee board chair was paid a monthly fee of $6,500, and as of January 1, 2015, this monthly fee was adjusted to $4,167. The audit committee chair is paid an annual fee of $2,500, paid semi-annually. In addition, the non-employee directors are paid $1,000 for each board of directors' meeting attended, and paid $500 for each telephonic board of directors meeting. The non-employee directors who are members of a committee of the board of directors are paid $500 for each committee meeting attended, or $750 for each committee meeting attended if that non-employee director is the committee chair. Directors also may be paid for serving on ad hoc committees of the Board. 
+DIRECTOR COMPENSATION 
+Name 
+Fees Earned or Paid in Cash 
+($) 1 
+Option Awards 
+($) 2 
+Total 
+($) 
+Katherine L. Davis 
+$ 
+82,500 
+$ 
+- 
+$ 
+82,500 
+Barbara DeBuono 
+30,250 
+- 
+30,250 
+Pete Kissinger 
+48,500 
+- 
+48,500 
+Gary Meller 
+58,500 
+- 
+58,500 
+1 Fees earned or paid in cash represents a yearly fee and fees for meeting expenses: (a) Ms. Davis received a $25,000 annual fee as a member of the board of directors, a $4,167 monthly fee as chair aggregating $50,000 and $7,500 in meeting fees earned during 2015; (b) Dr. DeBuono received a $25,000 annual fee as a member of the board of directors and 5,250 in meeting fees; (c) Dr. Kissinger received a $25,000 annual fee as a member of the board of directors, $18,000 in fees as a member of a Special Committee and $5,500 in meeting fees; (d) Dr. Meller received a $25,000 annual fee as a member of the board of directors, $2,500 in fees as chairperson of the Audit Committee, $24,000 in fees as a member of a Special Committee and $7,000 in meeting fees. 
+2 Each non-employee member of the board of directors is granted, once every five years, options to purchase 46,875 shares of the company's common stock with an exercise price equal to the market price on the date of the grant as part of annual non-employee board compensation. One-fifth of these options are exercisable on the date of grant, one-fifth become exercisable on the first anniversary of the date of grant, and additional one-fifths become exercisable on the second through fourth anniversaries of the date of grant. The fair value of options at the date of grant was estimated using the Black-Scholes option pricing model. 
+Compensation Committee Interlocks and Insider Participation 
+No executive officer of the Company served as a member of the Board of any other public company during the year ended December 31, 2015, except for Mr. Sperzel who serves on the Board of Directors of Diadexus, Inc. No member of the Compensation Committee served as an executive officer of any other public company during the year ended December 31, 2015. No interlocking relationship exists between the members of our Compensation Committee and the Board or compensation committee of any other company. As of March 1, 2015, the members of the Compensation Committee were Dr. Barbara DeBuono (Chairman), Katherine Davis, and Dr. Peter Kissinger, each of whom is deemed by the Board of Directors to be independent. 
+32 
+ITEM 12. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+The following table sets forth certain information regarding the beneficial ownership of our common stock by each person or entity known by us to be the beneficial owner of more than 5% of the outstanding shares of common stock, each of our directors, each of our "named executive officers", and all of our directors and executive officers as a group as of March 1, 2016. 
+Name and Address of 
+Beneficial Owner 
+Amount and Nature 
+of Beneficial Ownership 
+Percent of Class 
+John J. Sperzel (1) 
+3661 Horseblock Road 
+Medford, NY 11763 
+100,000 
+1.03% 
+Esfandiari, Javan (2) 
+3661 Horseblock Road 
+Medford, NY 11763 
+134,844 
+1.39% 
+Larkin, Richard (3) 
+3661 Horseblock Road 
+Medford, NY 11763 
+66,514 
+.69% 
+Ippolito, Tom (4) 
+3661 Horseblock Road 
+Medford, NY 11763 
+38,916 
+.40% 
+Steele, Michael (5) 
+3661 Horseblock Road 
+Medford, NY 11763 
+36,785 
+.38% 
+Lambotte, Paul (6) 
+3661 Horseblock Road 
+Medford, NY 11763 
+51,630 
+.53% 
+Klugewicz, Sharon (7) 
+3661 Horseblock Road 
+Medford, NY 11763 
+12,000 
+.12% 
+Meller, Gary (8) 
+3661 Horseblock Road 
+Medford, NY 11763 
+123,750 
+1.28% 
+Davis, Katherine L. (9) 
+3661 Horseblock Road 
+Medford, NY 11763 
+77,046 
+.80% 
+DeBuono, Barbara (10) 
+3661 Horseblock Road 
+Medford, NY 11763 
+46,188 
+.48% 
+Kissinger, Peter (11) 
+3661 Horseblock Road 
+Medford, NY 11763 
+50,629 
+.52% 
+GROUP (12) 
+738,302 
+7.36% 
+Wellington Management Company, LLP 
+280 Congress Street 
+Boston, MA 02210 
+1,092,780 
+11.35% 
+Norman H. Pessin 
+366 Madison Ave, 14 th Floor 
+New York, NY 10017 
+884,087 
+9.18% 
+Beneficial ownership is determined in accordance with the Rule 13d-3(a) of the Securities Exchange Act of 1934, as amended, and generally includes voting or investment power with respect to securities. Except as subject to community property laws, where applicable, the person named above has sole voting and investment power with respect to all shares of our common stock shown as beneficially owned by that person. 
+33 
+The beneficial ownership percent in the table is calculated with respect to the number of shares (9,628,248) of the Company's common stock outstanding as of March 1, 2016. With respect to each stockholder, the denominator is the sum of the number of common shares outstanding and the number, if any, of outstanding options included in that stockholder's beneficial ownership. Each stockholder's beneficial ownership is calculated as the number of shares of common stock owned plus the number of shares of common stock into which any preferred stock, warrants, options or other convertible securities owned by that stockholder can be converted within 60 days. 
+The term "named executive officer" refers to our principal executive officer, our two most highly compensated executive officers other than the principal executive officer who were serving as executive officers at the end of 2015, and two additional individuals for whom disclosure would have been provided but for the fact that the individuals were not serving as executive officers of the Company at the end of 2015. 
+(1) 
+Includes 100,000 shares issuable upon exercise of options exercisable within 60 days. Does not include 150,000 shares issuable upon exercise of options that are not exercisable within the next 60 days. 
+(2) 
+Includes 42,734 shares issuable upon exercise of options exercisable within 60 days. 
+(3) 
+Includes 23,217 shares issuable upon exercise of options exercisable within 60 days. 
+(4) 
+Includes 20,399 shares issuable upon exercise of options exercisable within 60 days. 
+(5) 
+Includes 36,785 shares issuable upon exercise of options exercisable within 60 days. 
+(6) 
+Includes 41,630 shares issuable upon exercise of options exercisable within 60 days. 
+(7) 
+Includes 12,000 shares issuable upon exercise of options exercisable within 60 days. Does not include 24,000 shares issuable upon exercise of options that are not exercisable within the next 60 days. 
+(8) 
+Includes 18,750 shares issuable upon exercise of options exercisable within 60 days. Does not include 28,125 shares issuable upon exercise of options that are not exercisable within the next 60 days. 
+(9) 
+Includes 18,750 shares issuable upon exercise of options exercisable within 60 days. Does not include 28,125 shares issuable upon exercise of options that are not exercisable within the next 60 days. 
+(10) 
+Includes 48,829 shares issuable upon exercise of options exercisable within 60 days. 
+(11) 
+Includes 45,188 shares issuable upon exercise of options exercisable within 60 days. 
+(12) 
+Includes footnotes (1)-(10). 
+Equity Compensation Plan Information 
+Combined Equity Compensation Plans - Information as of December 31, 2015 
+Plan Category 
+Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights 
+Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights 
+Number of Securities Remaining Available for Future Issuance under Equity Compensation Plans (Excluding Securities Reflected in Column (a) 
+(a) 
+(b) 
+(c) 
+Equity compensation plans approved by security holders 1 
+649,478 
+$ 
+3.75 
+753,455 
+Equity compensation plans not approved by security holders 
+- 
+- 
+- 
+Total 
+649,478 
+$ 
+3.75 
+753,455 
+1 The "Number of Securities to be Issued Upon Exercise of Outstanding Warrants and Rights" represents 312,860 from the 2008 Stock Incentive Plan, 129,750 under the 2014 Stock Incentive Plan and 206,868 issued outside of the Plans. The 2008 Stock Incentive Plan was increased by 125,000 units at the Annual Stockholder meeting held September 23, 2011. The "Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans" represents 83,205 from the 2008 Stock Incentive Plan and 670,250 under the 2014 Stock Incentive Plan. 
+34 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE. 
+The executive officers of the Company are as follows: John J. Sperzel, president, chief executive officer and member of the board of directors of the Company, Sharon Klugewicz, chief operating officer, Richard J. Larkin, chief financial officer of the Company, and Javan Esfandiari, chief science and technology officer of the Company. 
+The Company entered into an employment agreement effective March 5, 2013, with Mr. Esfandiari to continue as the Company's Chief Scientific and Technology Officer for an additional term of three years through March 5, 2016. The Company also entered into an employment agreement effective May 22, 2015, with Ms. Klugewicz to serve as Chief Operating Officer for a term of two years. On March 13, 2014, Mr. Siebert, the former Chief Executive Officer, retired from the Company and entered into a six-month Consulting Agreement with the Company. On March 13, 2014, the Company entered into an employment agreement (the "Employment Agreement") with John J. Sperzel III to serve as its Chief Executive Officer beginning on March 13, 2014 for a term of three years. See Item 11 for additional information. 
+Director Independence 
+Our common stock trades on the NASDAQ. Accordingly, we are subject to the corporate the governance standards of NASDAQ, which require, among other things, that the majority of the board of directors be independent. We define an "independent" director in accordance with the NASDAQ Global Market's requirements for independent directors. Under this definition, we have determined that each of Katherine Davis, Barbara DeBuono, Peter Kissinger, and Gary Meller currently qualify as independent directors. We do not list this "independent" definition on our internet website. 
+ITEM 14. 
+PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+Audit Fees 
+For the years ended December 31, 2015 and 2014 the Company engaged BDO USA, LLP as its independent accounting firm to perform an audit of the Company's annual financial statements included on Form 10-K, including reviews of the quarterly financial statements and assistance with and review of documents filed with the SEC, for $161,000 and $128,000 respectively in fees. 
+Audit-Related Fees 
+For the years ended December 31, 2015 and 2014, the Company's independent accounting firm, BDO USA, LLP, did not provide the Company with any assurance and related services reasonably related to the performance of the audit or review of the Company's financial statements that are not reported above under "Audit Fees." 
+Tax Fees 
+For the years ended December 31, 2015 and 2014, the Company's independent accounting firm, BDO USA, LLP, billed the Company $23,600 and $18,350, respectively for professional services for tax compliance, tax advice and tax planning. 
+All Other Fees 
+For the year ended December 31, 2015, the Company's independent accounting firm, BDO USA, LLP, billed the Company $69,600 for services in connection with other matters. For the year ended December 31, 2014, the Company's independent accounting firm, BDO USA, LLP, did not provide the Company with any services for other matters. 
+Audit Committee Pre-Approval Policies 
+The Audit Committee approves in advance all audit and non-audit services performed by the independent accounting firm. There are no other specific policies or procedures relating to the pre-approval of services performed by the independent accounting firm. 
+35 
+ITEM 15. 
+EXHIBITS INDEX 
+Number 
+Description 
+3.1 
+Articles of Incorporation, as amended. (1) 
+3.2 
+Amended and Restated Bylaws. (2) 
+4.1 
+2008 Stock Incentive Plan, as amended. (3) 
+4.2 
+Form of Option, for 2008 Stock Incentive Plan (4) 
+4.3 
+2014 Stock Incentive Plan (5) 
+4.4 
+Form of Option, for 2014 Stock Incentive Plan (6) 
+4.5 
+Rights Agreement, dated March 8, 2010 (7) 
+4.6 
+Form of Warrant (to be filed by amendment) 
+4.7 
+Rights Agreement, dated March 8, 2016 (14) 
+4.8 
+Form of Warrant (to be filed by amendment) 
+10.1* 
+Employment Agreement dated March 13, 2014 with John J. Sperzel III (4) 
+10.2* 
+Employment Agreement dated March 5, 2013 with Javan Esfandiari (8) 
+10.3* 
+Employment Agreement dated June 12, 2015 with Sharon Klugewicz (9) 
+10.3 
+HIV Barrel License, Marketing and Distribution Agreement, dated as of September 29, 2006, by and among the Registrant, Alere and StatSure. (10) 
+10.4 
+HIV Cassette License, Marketing and Distribution Agreement, dated as of September 29, 2006, between the Registrant and Alere. (10) 
+10.5 
+Non-Exclusive License, Marketing and Distribution Agreement, dated as of September 29, 2006, between the Registrant and Alere. (10) 
+10.6 
+Joint HIV Barrel Product Commercialization Agreement, dated as of September 29, 2006, between the Registrant and StatSure. (10) 
+10.8 
+Secured Revolving Demand Note, dated as of April 30, 2013, by and among the Registrant, Chembio Diagnostics Systems, Inc. and HSBC Bank, NA (11) 
+10.9 
+Loan and Security Agreement, dated as of April 30, 2013, by and among the Registrant, Chembio Diagnostics Systems, Inc. and HSBC Bank, NA (11) 
+10.10 
+2015 Omnibus Agreement (12) 
+14.1 
+Ethics Policy (13) 
+21 
+List of Subsidiaries 
+23.1 
+Consent of BDO USA, LLP, Independent Registered Public Accountants. 
+31.1 
+Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+31.2 
+Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+32 
+Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 
+101.INS 
+XBRL Instance Document 
+101.SCH 
+XBRL Taxonomy Extension Schema Document 
+101.CAL 
+XBRL Taxonomy Extension Calculation Linkbase Document 
+101.DEF 
+XBRL Taxonomy Definition Linkbase Document 
+101.LAB 
+XBRL Taxonomy Label Linkbase Document 
+101.PRE 
+XBRL Taxonomy Presentation Linkbase Document 
+1 
+Incorporated by reference to the Registrant's Quarterly Report on Form 10-Q filed with the Commission on July 29, 2010. 
+2 
+Incorporated by reference to the Registrant's registration statement on Form SB-2 (File No. 333-85787) filed with the Commission on August 23, 1999 and the Registrant's Forms 8-K filed on May 14, 2004, December 20, 2007 and April 18, 2008. 
+3 
+Incorporated by reference to the Registrant's definitive proxy statement on Schedule 14A filed with the Commission on August 3, 2012. 
+4 
+Incorporated by reference to the Registrant's Quarterly Report on Form 10-Q filed with the Commission on May 8, 2014. 
+5 
+Incorporated by reference to the Registrant's definitive proxy statement on Schedule 14A filed with the Commission on April 29, 2014. 
+6 
+Incorporated by reference to the Registrant's Quarterly Report on Form 10-Q filed with the Commission on August 7, 2014. 
+7 
+Incorporated by reference to the Registrant's registration statement on Form 8-A filed with the Commission on March 11, 2010. 
+8 
+Incorporated by reference to the Registrant's Annual Report on Form 10-K filed with the Commission on March 7, 2013. 
+9 
+Incorporated by reference to the Registrant's Current Report on Form 8-K filed with the Commission on June 17, 2015. 
+10 
+Incorporated by reference to the Registrant's Current Report on Form 8-K filed with the Commission on October 5, 2006. 
+11 
+Incorporated by reference to the Registrant's Quarterly Report on Form 10-Q filed with the Commission on August 8, 2013. 
+12 
+Incorporated by reference to the Registrant's Annual Report on Form 10-K filed with the Commission on March 5, 2015. 
+13 
+Incorporated by reference to the Registrant's Annual Report on Form 10-KSB filed with the Commission on March 30, 2006. 
+(*) 
+An asterisk (*) beside an exhibit number indicates the exhibit contains a management contract, compensatory plan or arrangement which is required to be identified in this report. 
+36 
+SIGNATURES 
+In accordance with Section 13 or 15(d) of the Exchange Act, the registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+CHEMBIO DIAGNOSTICS, INC. 
+Date: March 8, 2016 
+By 
+/s/ John J. Sperzel 
+John J. Sperzel 
+President, Chief Executive Officer and 
+Member of the Board 
+In accordance with the requirements of the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+Signatures 
+Title 
+Date 
+/s/ John J. Sperzel 
+Chief Executive Officer, President and 
+March 8, 2016 
+John J. Sperzel 
+Member Of The Board 
+(Principal Executive Officer) 
+/s/ Richard J. Larkin 
+Chief Financial Officer (Principal Financial & 
+March 8, 2016 
+Richard J. Larkin 
+Accounting Officer) 
+/s/ Gary Meller 
+Director 
+March 8, 2016 
+Gary Meller 
+/s/ Katherine L. Davis 
+Director & Chair of the Board 
+March 8, 2016 
+Katherine L. Davis 
+/s/ Peter T. Kissinger 
+Director 
+March 8, 2016 
+Peter T. Kissinger 
+/s/ Barbara DeBuono 
+Director 
+March 8, 2016 
+Barbara DeBuono 
+37 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+Index to Consolidated Financial Statements 
+—INDEX— 
+Page(s) 
+Report of Independent Registered Public Accounting Firm 
+F-1 
+Consolidated Financial Statements: 
+Balance Sheets December 31, 2015 and 2014 
+F-2 
+Statements of Operations for each of the years ended December 31, 2015 and 2014 
+F-3 
+Statements of Changes in Stockholders' Equity for each of the years ended December 31, 2015 and 2014 
+F-4 
+Statements of Cash Flows for each of the years ended December 31, 2015 and 2014 
+F-5 
+Notes to Consolidated Financial Statements 
+F-6 - F-19 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+Board of Directors and Stockholders of 
+Chembio Diagnostics, Inc. 
+Medford, New York 
+We have audited the accompanying consolidated balance sheets of Chembio Diagnostics, Inc. and Subsidiary (the "Company") as of December 31, 2015 and 2014 and the related consolidated statements of operations, changes in stockholders' equity and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. 
+We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. 
+In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Chembio Diagnostics, Inc. and Subsidiary as of December 31, 2015 and 2014, and the consolidated results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. 
+BDO USA, LLP 
+/s/ BDO USA, LLP 
+Melville, New York 
+March 8, 2016 
+F-1 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+CONSOLIDATED BALANCE SHEETS 
+AS OF 
+- ASSETS - 
+December 31, 2015 
+December 31, 2014 
+CURRENT ASSETS: 
+Cash and cash equivalents 
+$ 
+5,376,931 
+$ 
+4,614,538 
+Accounts receivable, net of allowance for doubtful accounts of $52,000 and $52,000 at December 31, 2015 and 2014, respectively 
+2,422,971 
+8,338,889 
+Inventories 
+3,578,025 
+3,638,299 
+Prepaid expenses and other current assets 
+1,256,879 
+1,066,473 
+TOTAL CURRENT ASSETS 
+12,634,806 
+17,658,199 
+FIXED ASSETS , net of accumulated depreciation 
+2,374,308 
+2,797,929 
+OTHER ASSETS: 
+Deferred tax asset, net of valuation allowance 
+5,467,143 
+4,031,302 
+License agreements, net of current portion 
+100,000 
+256,875 
+Deposits on manufacturing equipment 
+30,918 
+20,017 
+Deposits and other assets 
+209,169 
+245,870 
+TOTAL ASSETS 
+$ 
+20,816,344 
+$ 
+25,010,192 
+- LIABILITIES AND STOCKHOLDERS' EQUITY - 
+CURRENT LIABILITIES: 
+Accounts payable and accrued liabilities 
+$ 
+2,801,432 
+$ 
+4,946,030 
+Deferred revenue 
+353,406 
+340,000 
+TOTAL CURRENT LIABILITIES 
+3,154,838 
+5,286,030 
+TOTAL LIABILITIES 
+3,154,838 
+5,286,030 
+COMMITMENTS AND CONTINGENCIES (Note 13) 
+STOCKHOLDERS' EQUITY: 
+Preferred stock – 10,000,000 shares authorized, none outstanding 
+- 
+- 
+Common stock - $.01 par value; 100,000,000 shares authorized, 9,628,248 and 9,611,139 shares issued and outstanding for 2015 and 2014, respectively 
+96,282 
+96,112 
+Additional paid-in capital 
+47,890,642 
+47,556,426 
+Accumulated deficit 
+(30,325,418 
+) 
+(27,928,376 
+) 
+TOTAL STOCKHOLDERS' EQUITY 
+17,661,506 
+19,724,162 
+TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY 
+$ 
+20,816,344 
+$ 
+$ 25,010,192 
+See accompanying notes to condensed consolidated financial statements 
+F-2 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+CONSOLIDATED STATEMENTS OF OPERATIONS 
+For the years ended 
+December 31, 2015 
+December 31, 2014 
+REVENUES: 
+Net product sales 
+$ 
+21,886,688 
+$ 
+25,949,769 
+License and royalty revenue 
+52,753 
+23,257 
+R&D, milestone and grant revenue 
+2,316,044 
+1,672,258 
+TOTAL REVENUES 
+24,255,485 
+27,645,284 
+Cost of product sales 
+13,768,658 
+16,831,261 
+GROSS MARGIN 
+10,486,827 
+10,814,023 
+OPERATING EXPENSES: 
+Research and development expenses 
+6,377,839 
+4,832,537 
+Selling, general and administrative expenses 
+7,663,035 
+7,531,739 
+14,040,874 
+12,364,276 
+LOSS FROM OPERATIONS 
+(3,554,047 
+) 
+(1,550,253 
+) 
+OTHER INCOME (EXPENSE): 
+Other expense 
+(4,814 
+) 
+(5,707 
+) 
+Interest income 
+2,412 
+5,839 
+Interest expense 
+(836 
+) 
+- 
+(3,238 
+) 
+132 
+LOSS BEFORE INCOME TAXES (BENEFIT) 
+(3,557,285 
+) 
+(1,550,121 
+) 
+Income tax provision (benefit) 
+(1,160,243 
+) 
+(412,918 
+) 
+NET LOSS 
+$ 
+(2,397,042 
+) 
+$ 
+(1,137,203 
+) 
+Basic loss per share 
+$ 
+(0.25 
+) 
+$ 
+(0.12 
+) 
+Diluted loss per share 
+$ 
+(0.25 
+) 
+$ 
+(0.12 
+) 
+Weighted average number of shares outstanding, basic 
+9,626,028 
+9,530,320 
+Weighted average number of shares outstanding, diluted 
+9,626,028 
+9,530,320 
+See accompanying notes to condensed consolidated financial statements 
+F-3 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY 
+FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014 
+Common Stock 
+Additional Paid 
+in Capital 
+Accumulated 
+Deficit 
+Total 
+Shares 
+Amount 
+Amount 
+Amount 
+Amount 
+Balance at December 31, 2013 
+9,324,783 
+$ 
+93,248 
+$ 
+46,875,027 
+$ 
+(26,791,173 
+) 
+$ 
+20,177,102 
+Common Stock: 
+New Stock from Offering 
+- 
+- 
+- 
+- 
+- 
+Options: 
+Exercised 
+286,356 
+2,864 
+234,299 
+- 
+237,163 
+Stock option compensation 
+- 
+- 
+447,100 
+- 
+447,100 
+Net loss 
+- 
+- 
+- 
+(1,137,203 
+) 
+(1,137,203 
+) 
+Balance at December 31, 2014 
+9,611,139 
+$ 
+96,112 
+$ 
+47,556,426 
+$ 
+(27,928,376 
+) 
+$ 
+19,724,162 
+Options: 
+Exercised 
+17,109 
+170 
+(170 
+) 
+- 
+- 
+Stock option compensation 
+- 
+- 
+334,386 
+- 
+334,386 
+Net loss 
+- 
+- 
+- 
+(2,397,042 
+) 
+(2,397,042 
+) 
+Balance at December 31, 2015 
+9,628,248 
+$ 
+96,282 
+$ 
+47,890,642 
+$ 
+(30,325,418 
+) 
+$ 
+17,661,506 
+See accompanying notes to consolidated financial statements 
+F-4 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2015 AND 2014 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+FOR THE YEARS ENDED 
+December 31, 2015 
+December 31, 2014 
+CASH FLOWS FROM OPERATING ACTIVITIES: 
+Cash received from customers and grants 
+$ 
+30,174,083 
+$ 
+23,898,516 
+Cash paid to suppliers and employees 
+(28,382,681 
+) 
+(27,724,654 
+) 
+Interest received 
+2,412 
+5,839 
+Interest paid 
+(836 
+) 
+- 
+Net cash provided by (used in) operating activities 
+1,792,978 
+(3,820,299 
+) 
+CASH FLOWS FROM INVESTING ACTIVITIES: 
+Acquisition of license 
+(550,000 
+) 
+- 
+Acquisition of and deposits on fixed assets 
+(480,585 
+) 
+(1,452,601 
+) 
+Net cash used in investing activities 
+(1,030,585 
+) 
+(1,452,601 
+) 
+CASH FLOWS FROM FINANCING ACTIVITIES: 
+Proceeds from option and warrant exercises 
+- 
+237,163 
+Proceeds from credit line 
+700,000 
+- 
+Repayment of credit line 
+(700,000 
+) 
+- 
+Payment of capital lease obligation 
+- 
+- 
+Net cash provided by financing activities 
+- 
+237,163 
+(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS 
+762,393 
+(5,035,737 
+) 
+Cash and cash equivalents - beginning of the period 
+4,614,538 
+9,650,275 
+Cash and cash equivalents - end of the period 
+$ 
+5,376,931 
+$ 
+4,614,538 
+RECONCILIATION OF NET LOSS TO NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES: 
+Net Loss 
+$ 
+(2,397,042 
+) 
+$ 
+(1,137,203 
+) 
+Adjustments: 
+Depreciation and amortization 
+1,372,563 
+739,297 
+Provision for (benefit from) deferred taxes 
+(1,170,969 
+) 
+(403,375 
+) 
+Provision for (recovery of) doubtful accounts 
+- 
+28,000 
+Share based compensation 
+334,386 
+447,100 
+Changes in assets and liabilities: 
+Accounts receivable 
+5,915,918 
+(3,774,768 
+) 
+Inventories 
+60,274 
+(449,573 
+) 
+Prepaid expenses and other current assets 
+(190,960 
+) 
+32,906 
+Deposits and other assets 
+- 
+(279,223 
+) 
+Accounts payable and accrued liabilities 
+(2,144,598 
+) 
+636,540 
+Customer deposits and deferred revenue 
+13,406 
+340,000 
+Net cash provided by (used in) operating activities 
+$ 
+1,792,978 
+$ 
+(3,820,299 
+) 
+Supplemental disclosures for non-cash investing and financing activities: 
+Deposits on manufacturing equipment transferred to fixed assets 
+$ 
+20,017 
+$ 
+603,627 
+See accompanying notes to condensed consolidated financial statements 
+F-5 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2015 AND 2014 
+NOTE 1 — DESCRIPTION OF BUSINESS: 
+Chembio Diagnostics, Inc. and its subsidiary, Chembio Diagnostic Systems, Inc. (collectively, the "Company" or "Chembio"), develop, manufacture, and market rapid diagnostic tests that detect infectious diseases. The Company's main lateral flow products are three rapid tests for the detection of HIV antibodies in whole blood, serum and plasma samples, two of which were approved by the FDA in 2006; the third is sold for export only. Lateral Flow Rapid HIV tests represented nearly 46% of the Company's product revenues in 2015. The Company's products based on its patented DPP® platform represented approximately 51% of the Company's product revenues in 2015. The Company also has other rapid tests that together represented approximately 3% of sales in 2015. The Company's products are sold to medical laboratories and hospitals, governmental and public health entities, non-governmental organizations, medical professionals and retail establishments both domestically and internationally. Chembio's products are sold under the Company's STAT-PAK®, SURE CHECK® or DPP® registered trademarks, or under the private labels of its marketing partners, for example the Clearview® label owned by Alere, Inc. ("Alere"), which is the Company's exclusive marketing partner for one of its rapid HIV lateral flow test products in the United States. All of the Company's products that are currently being developed are based on its patented Dual Path Platform (DPP®), which is a unique diagnostic point-of-care platform that has certain advantages over lateral flow technology. In December 2012, the Company received FDA approval for its DPP® HIV 1/2 Assay for the detection of HIV antibodies in saliva, whole blood, serum and plasma samples, which was CLIA-Waived in October 2014. 
+NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES: 
+(a) 
+Principles of Consolidation: 
+The consolidated financial statements include the accounts of the Company and its wholly owned subsidiary. All intercompany transactions and balances have been eliminated in consolidation. 
+(b) 
+Use of Estimates: 
+The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make assumptions and estimates that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods covered thereby. Actual results could differ from these estimates. Judgments and estimates of uncertainties are required in applying the Company's accounting policies in certain areas. The following are some of the areas requiring significant judgments and estimates: determinations of the useful lives of assets, estimates of allowances for doubtful accounts, inventory reserves, stock-based compensation and deferred tax assets. 
+(c) 
+Fair Value of Financial Instruments: 
+The carrying value for cash and cash equivalents, accounts receivable and accounts payable, approximate fair value because of the immediate or short-term maturity of these financial instruments. 
+(d) 
+Statements of Cash Flows: 
+For purposes of the statements of cash flows, the Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents. 
+(e) 
+Concentrations of Credit Risk: 
+Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of temporary cash investments and trade receivables. The Company places its temporary cash instruments with well-known financial institutions and, at times, may maintain balances in excess of the FDIC insurance limit. The Company monitors the credit ratings of the financial institutions to mitigate this risk. Concentration of credit risk with respect to trade receivables is principally mitigated by the Company's ability to obtain letters of credit from certain foreign customers, and its diverse customer base both in number of customers and geographic locations. As of December 31, 2014, we had a significant concentration of outstanding credit with one customer in Brazil. We currently do not require collateral for accounts receivable. 
+F-6 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2015 AND 2014 
+(f) 
+Inventories: 
+Inventories, consisting of material, labor and manufacturing overhead, are stated at the lower of cost or market. Cost is determined on the first-in, first-out method. 
+(g) 
+Fixed Assets: 
+Fixed assets are stated at cost, less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the respective assets, which range from three to seven years. Leasehold improvements are amortized over the useful life of the asset or the lease term, whichever is shorter. Deposits paid for fixed assets are capitalized and not depreciated until the related asset is placed in service. 
+(h) 
+License Agreements: 
+In February 2008, the Company entered into a sublicense agreement for which it had initially recorded an asset of $1,000,000. This asset is being expensed over an estimated economic life of ten years, based on the expected lifespan of our then current HIV products. The current portion of this asset is $100,000 as of December 31, 2015 and 2014 and is reported in prepaid expenses and other current assets. The long-term portion as of December 31, 2015 and 2014 is $100,000 and $200,000, respectively and is reflected in other assets on the consolidated balance sheet. 
+In January 2015, the Company entered into a sublicense agreement for which it had initially recorded an asset of $400,000. This asset is being expensed over the life of the patent of 22 months. The current portion of this asset is $181,818 as of December 31, 2015 and is reported in prepaid expenses. 
+In August 2015, the Company entered into a sublicense agreement for which it had initially recorded an asset of $100,000. This asset is being validated and will be expensed over the estimated economic life of the product(s) which will utilize this sublicense. This asset as of December 31, 2015, is reported in prepaid expenses. 
+(i) 
+Impairment of Long-Lived Assets and Intangible Assets 
+Long-lived assets to be held and used are analyzed for impairment whenever events or changes in circumstances indicate that the related carrying amounts may not be recoverable. The Company evaluates at each balance sheet date whether events and circumstances have occurred that indicate possible impairment. If there are indications of impairment, the Company uses future undiscounted cash flows of the related asset or asset grouping over the remaining life in measuring whether the assets are recoverable. In the event such cash flows are not expected to be sufficient to recover the recorded asset values, the assets are written down to their estimated fair value. We believe that the carrying values of our long-lived tangible and intangible assets were realizable at December 31, 2015 and 2014, respectively. 
+(j) 
+Revenue Recognition: 
+The Company recognizes revenue for product sales in accordance with ASC 605, revenue is recognized when there is persuasive evidence of an arrangement, delivery has occurred or services have been rendered, the sales price is fixed and determinable, and collectability is reasonably assured. Revenue typically is recognized at time of shipment. Sales are recorded net of discounts, rebates and returns. 
+For certain contracts, the Company recognizes revenue from non-milestone contracts and grant revenues when earned. Grants are invoiced after expenses are incurred. Revenues from projects or grants funded in advance are deferred until earned. 
+The Company follows Financial Accounting Standards Board ("FASB") issued authoritative guidance ("guidance") prospectively for the recognition of revenue under the milestone method. The Company applies the milestone method of revenue recognition for certain collaborative research projects defining milestones at the inception of the agreement. 
+F-7 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2015 AND 2014 
+(k) 
+Research and Development: 
+Research and development (R&D) costs are expensed as incurred. 
+(l) 
+Stock-Based Compensation: 
+Stock-based compensation expense is calculated using the Black-Scholes valuation model based on awards ultimately expected to vest, reduced for forfeitures, and expensed on a straight-line basis over the requisite service period of the grant. 
+(m) 
+I ncome Taxes: 
+The Company accounts for income taxes under an asset and liability approach which recognizes deferred tax assets and liabilities based on the difference between the financial statement carrying amounts and the tax bases of assets and liabilities using enacted tax rates in effect in the years in which the differences are expected to reverse. 
+The Company follows a more-likely-than-not threshold for financial statement recognition and measurement of a tax position taken, or expected to be taken, in a tax return. The guidance relates to, among other things, classification, accounting for interest and penalties associated with tax positions, and disclosure requirements. Any interest and penalties accrued related to uncertain tax positions will be recorded in tax expense. 
+The Company assesses the realizability of its net deferred tax assets on an annual basis. If, after considering all relevant positive and negative evidence, it is more likely than not that some portion or all of the net deferred tax assets will not be realized, the Company would reduce the net deferred tax assets by a valuation allowance. The realization of the net deferred tax assets is dependent on several factors, including the generation of sufficient taxable income prior to the expiration of net operating loss carryforwards. 
+(n) 
+Loss Per Share 
+The following weighted average shares were used for the computation of basic and diluted earnings per share: 
+For the years ended 
+December 31, 2015 
+December 31, 2014 
+Basic 
+9,626,028 
+9,530,320 
+- 
+- 
+Diluted 
+9,626,028 
+9,530,320 
+Basic loss per share is computed by dividing net loss attributable to common stockholders by the weighted-average number of common shares outstanding for the period. Diluted loss per share for the year ended December 31, 2015 and 2014 reflects the potential dilution from the exercise or conversion of other securities into common stock, if dilutive. 
+The following securities, presented on a common share equivalent basis, have been used in the diluted per share computations: 
+For the years ended 
+December 31, 2015 
+December 31, 2014 
+1999, 2008 and 2014 Plan Stock Options 
+- 
+- 
+There were 658,631 and 798,475 options and warrants outstanding as of December 31, 2015 and 2014, respectively, which were not included in the calculation of diluted income per share for the years ended because their effect would have been anti-dilutive. 
+F-8 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2015 AND 2014 
+(o) 
+Recent Accounting Pronouncements Affecting the Company: 
+In May 2014, the FASB issued Accounting Standards Update No. 2014-09, "Revenue from Contracts with Customers" ("ASU 2014-09"), which supersedes nearly all existing revenue recognition guidance under accounting principles generally accepted in United States ("U.S. GAAP"). The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing U.S. GAAP. 
+The standard is effective for annual periods beginning after December 15, 2016, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients; or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We are currently evaluating the impact of our pending adoption of ASU 2014-09 on our consolidated financial statements and have not yet determined the method by which we will adopt the standard in 2018. 
+In November 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-17, Income Taxes (Topic 740) Balance Sheet Classification of Deferred Assets. This ASU is intended to simplify the presentation of deferred taxes on the balance sheet and will require an entity to present all deferred tax assets and deferred tax liabilities as non-current on the balance sheet. Under the current guidance, entities are required to separately present deferred taxes as current or non-current. Netting deferred tax assets and deferred tax liabilities by tax jurisdiction will still be required under the new guidance. This guidance will be effective for Chembio beginning in 2018, with early adoption permitted. The Company does not believe this new accounting standard update will have a material impact on its consolidated financial statements. 
+In February 2016, the FASB issued Accounting Standards Update ("ASU") 2016-02, which amends the ASC and creates Topic 842, Leases. Topic 842 will require lessees to recognize lease assets and lease liabilities for those leases classified as operating leases under previous US GAAP on the balance sheet. This guidance is effective for annual periods beginning after December 15, 2018 and early adoption is permitted. The Company is currently assessing the impact on its consolidated financial position and results of operations. 
+NOTE 3 — INVENTORIES: 
+Inventories consist of the following at: 
+December 31, 2015 
+December 31, 2014 
+Raw materials 
+$ 
+2,248,371 
+$ 
+2,323,863 
+Work in process 
+370,340 
+346,494 
+Finished goods 
+959,314 
+967,942 
+$ 
+3,578,025 
+$ 
+3,638,299 
+NOTE 4 — FIXED ASSETS: 
+Fixed assets consist of the following at: 
+December 31, 2015 
+December 31, 2014 
+Machinery and equipment 
+$ 
+3,862,698 
+$ 
+3,508,944 
+Furniture and fixtures 
+436,588 
+388,040 
+Computer and telephone equipment 
+326,170 
+315,916 
+Leasehold improvements 
+2,012,945 
+1,955,817 
+6,638,401 
+6,168,717 
+Less accumulated depreciation and amortization 
+(4,264,093 
+) 
+(3,370,788 
+) 
+$ 
+2,374,308 
+$ 
+2,797,929 
+F-9 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2015 AND 2014 
+There were no capital leases at the end of December 31, 2015. Fixed assets at December 31, 2015 also include $100,000 in equipment, which has been delivered and set-up but is undergoing validation and as such is currently not being depreciated. Depreciation expense for the 2015 and 2014 years aggregated $893,305 and $616,943, respectively. 
+As of December 31, 2015 and 2014, the Company had paid deposits on various pieces of equipment aggregating $30,918 and $20,017, respectively. The Company is further committed to an additional obligation of $31,008 as various milestones are achieved by the various vendors. 
+NOTE 5 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES: 
+Accounts payable and accrued liabilities consist of the following at: 
+December 31, 2015 
+December 31, 2014 
+Accounts payable – suppliers 
+$ 
+1,260,520 
+$ 
+1,980,120 
+Accrued commissions 
+129,192 
+947,451 
+Accrued royalties / license fees 
+732,301 
+1,034,062 
+Accrued payroll 
+146,962 
+106,487 
+Accrued vacation 
+244,810 
+219,924 
+Accrued bonuses 
+177,700 
+265,500 
+Accrued expenses – other 
+109,947 
+392,486 
+TOTAL 
+$ 
+2,801,432 
+$ 
+4,946,030 
+NOTE 6 — DEFERRED RESEARCH AND DEVELOPMENT REVENUE: 
+The Company recognizes income from R&D milestones when those milestones are reached and non-milestone contracts and grants when earned. Grants are invoiced after expenses are incurred. Any projects or grants funded in advance are deferred until earned. As of December 31, 2015 and 2014, there were $353,406 and $340,000 unearned advanced revenues, respectively. 
+NOTE 7 — TERM NOTE, REVOLVING DEMAND NOTE, VEHICLE FINANCING AND LICENSE FEE PAYABLE: 
+On April 30, 2013, the Company entered into a new demand loan agreement ("Demand Note") with HSBC Bank, USA ("HSBC"). The Demand Note allowed the Company to draw on the line from time to time an amount up to an aggregate of $2,000,000 outstanding at any one time. The accrued interest on the Demand Note was payable monthly at an interest rate equal to one-quarter percent above prime per annum. The Company could repay any or all of the principal balance outstanding at any time. This was a demand note for which the bank lender could demand repayment of the entire loan, with accrued interest, at any time. The loan was subject to annual reviews, as well as an annual 30-day clean-up, during which there could be no amounts outstanding. In January 2016 HSBC notified the Company that it could no longer extend the credit and the Demand Note was cancelled. 
+The Security Agreement, related to the Demand Note, contained covenants that placed restrictions on the Company's operations, including covenants relating to mergers, debt restrictions, capital expenditures, tangible net worth, net profit, leverage, fixed charge coverage, employee loan restrictions, distribution restrictions (common stock and preferred stock), dividend restrictions, restrictions on lease payments to affiliates, restrictions on changes in business, asset sale restrictions, restrictions on acquisitions and intercompany transactions, and restrictions on fundamental changes in the Company and in its business. 
+The Company currently maintains its operating, payroll, and primary cash accounts at HSBC. During the year ended December 31, 2015, the Company had drawn down an aggregate of $700,000 on the Demand Note and each withdrawal was paid back within 30 days and all covenants were met. 
+F-10 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2015 AND 2014 
+NOTE 8 — INCOME TAXES: 
+The (benefit from) provision for income taxes for the years ended December 31, 2015 and 2014, is comprised of the following: 
+2015 
+2014 
+Current 
+Federal 
+$ 
+- 
+$ 
+(16,119 
+) 
+State 
+10,726 
+6,576 
+Total current (benefit) provision 
+10,726 
+(9,543 
+) 
+Deferred 
+Federal 
+(1,171,865 
+) 
+(449,452 
+) 
+State 
+896 
+46,077 
+Total deferred (benefit) provision 
+(1,170,969 
+) 
+(403,375 
+) 
+Total (benefit) provision 
+$ 
+(1,160,243 
+) 
+$ 
+(412,918 
+) 
+The Company had an ownership change as described in Internal Revenue Code Sec. 382 during 2004 ("2004 change"). As a result, the Company's net operating losses prior to the 2004 change of $5,832,516 were subject to an annual limitation of $150,608 and for the first five (5) years are entitled to a BIG (Built-In-Gains) of $488,207 per year. These net operating losses expire in 2018 through 2024. 
+The Company had a second ownership change during 2006 ("2006 change"). The net operating losses incurred between the 2004 change and the 2006 change of $8,586,861 were subject to an annual limitation of $1,111,831 and for the first five (5) years are entitled to a BIG of $1,756,842 per year. These net operating losses expire in 2018 through 2028. 
+After applying the above limitations, at December 31, 2015, the Company has post-change net operating loss carry-forwards of approximately $15,815,108 which expire between 2020 and 2035. In addition the Company has research and development tax credit carryforwards of approximately $1,518,414 for the year ended December 31, 2015, which expire between 2025 and 2035. 
+2015 
+2014 
+Current assets 
+Inventory reserves 
+$ 
+242,532 
+$ 
+311,931 
+Accrued expenses 
+91,143 
+286,616 
+Current deferred tax assets 
+333,675 
+598,547 
+Less valuation allowances 
+- 
+- 
+Net current deferred asset 
+$ 
+333,675 
+$ 
+598,547 
+Noncurrent assets 
+Net operating loss carry-forwards 
+$ 
+5,365,401 
+$ 
+3,986,618 
+Research and development credit 
+1,518,414 
+1,175,725 
+Other credits 
+97,339 
+107,967 
+Other 
+210,553 
+149,923 
+Gross noncurrent deferred tax assets 
+7,191,707 
+5,420,233 
+Depreciation 
+(206,150 
+) 
+(213,206 
+) 
+Noncurrent deferred tax assets 
+6,985,557 
+5,207,027 
+Less valuation allowances 
+(1,518,414 
+) 
+(1,175,725 
+) 
+Net noncurrent deferred tax assets 
+$ 
+5,467,143 
+$ 
+4,031,302 
+F-11 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2015 AND 2014 
+A reconciliation of the Federal statutory rate to the effective rate applicable to income (loss) before income taxes is as follows: 
+Year Ending December 31, 
+2015 
+2014 
+Federal income tax at statutory rates 
+(34.00)% 
+(34.00)% 
+State income taxes, net of federal benefit 
+.23% 
+0.28% 
+Nondeductible expenses 
+1.38% 
+4.54% 
+Change in valuation allowance 
+9.46% 
+9.47% 
+Tax credits 
+(9.46)% 
+(9.47)% 
+Change in tax rates 
+.00% 
+1.96% 
+Other 
+.34% 
+0.58% 
+Income tax (benefit) 
+(32.05)% 
+(26.64)% 
+Interest and penalties, if any, related to income tax liabilities are included in income tax expense. As of December 31, 2015, the Company does not have a liability for uncertain tax positions. 
+The Company files Federal and state income tax returns. Tax years for fiscal 2012 through 2014 are open and potentially subject to examination by the federal and state taxing authorities. 
+NOTE 9 — STOCKHOLDERS' EQUITY: 
+(a) 
+Common Stock 
+During 2015, options to purchase 41,141 shares of the Company's common stock were exercised on a cashless basis into 17,109 shares of common stock at exercise prices ranging from $2.16 to $3.60 . 
+During 2014, options to purchase 318,750 shares of the Company's common stock were exercised, either for cash or cashless into 286,356 shares of common stock at an exercise price of $1.04. 
+(b) 
+Preferred Stock 
+The Company has 10,000,000 shares of preferred stock authorized and none outstanding. These shares can become issuable upon an approved resolution by the board of directors and the filing of a Certificate of Designation with the state of Nevada. 
+(c) 
+Options 
+During 2015, the Company did not issue options to purchase common stock. 
+During the fourth quarter of 2014, the Company issued 36,000 options to purchase common stock to a newly-hired vice-president of the Company. The options are exercisable in three equal annual installments starting on the first anniversary of the date of issue. The options issued have an exercise price of $4.35 per share, which was the last traded price of the common stock on the day issued. The options expire five years from date of issue. 
+During the second quarter of 2014 the Company issued options to two of its directors pursuant to the Company's compensation policy for directors. Each director was issued 46,875 options to purchase common stock. The options become exercisable in five equal annual installments starting on the date of issue. The options issued have an exercise price of $3.480 per share, which was the last traded price of the common stock on the day issued. The options expire five years from date of issue. 
+F-12 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2015 AND 2014 
+The Company entered into an employment agreement, effective March 13, 2014 ("Employment Agreement"), with Mr. Sperzel to serve as the Company's Chief Executive Officer, which included issuing incentive and non-incentive stock options to purchase 250,000 shares of the Company's common stock. The options become exercisable in five equal annual installments starting on the first anniversary of the effective date of the Employment Agreement. The exercise price for these options was to be equal to the volume-weighted average trading price for the Company's common stock on March 13, 2014, which was $3.416 per share. The options expire seven years from date of issue. 
+(d) 
+Warrants 
+As of December 31, 2015 and 2014, the Company had no warrants outstanding to purchase shares of common stock. 
+NOTE 10 — RIGHTS AGREEMENT: 
+In March 2010, the Company entered into a Rights Agreement (the "Rights Agreement") between the Company and Action Stock Transfer Corp., as Rights Agent. The Rights Agreement expired at the end of November 2015. Pursuant to the Rights Agreement, the Company declared a dividend distribution of one preferred share purchase right (a "Right") for each outstanding share of Common Stock, $0.01 par value (the "Common Stock"), of the Company. The Board of Directors set the payment date for the distribution of the Rights as March 8, 2010, and the Rights were distributed to the Company's shareholders of record on that date. The description and terms of the Rights are set forth in the Rights Agreement. 
+Rights Initially Not Exercisable. The Rights were not exercisable until a Distribution Date. Until a Right was exercised, the holder thereof, as such, would have no rights as a shareholder of the Company, including, without limitation, the right to vote or to receive dividends. 
+Separation and Distribution of Rights . The Rights were to be evidenced by the certificates for shares of Common Stock registered in the names of the holders thereof, and not by separate rights certificates until the earlier to occur of (i) the close of business on the tenth business day following a public announcement that an Acquiring Person (as defined in the Rights Agreement) acquired a Combined Ownership (as defined in the Rights Agreement) of 15% or more of the outstanding shares of the Common Stock (the "Shares Acquisition Date") or (ii) the later of (A) the close of business on the tenth business day (or such later date as may be determined by action of the Board of Directors prior to such time as any person or group of affiliated or associated persons becomes an Acquiring Person) after the date that a tender or exchange offer or intention to commence a tender or exchange offer by any person is first published, announced, sent or given within the meaning of Rule 14d-4(A) under the Securities Exchange Act of 1934, as amended, the consummation of which would result in any person having Combined Ownership of 15% or more of the outstanding shares of the Common Stock, or (B) if such a tender or exchange offer has been published, announced, sent or given before the date of the Rights Agreement, then the close of business on the tenth business day after the date the Rights Agreement was entered into (or such later date as may be determined by action of the Board of Directors prior to such time as any person becomes an Acquiring Person); (the earlier of such dates referred to in (i) and (ii), which date may include any such date that is after the date of the Rights Agreement but prior to the issuance of the Rights, being called the "Distribution Date"). 
+NOTE 11 — EMPLOYEE STOCK OPTION PLAN: 
+Effective June 3, 2008, the Company's stockholders voted to approve the 2008 Stock Incentive Plan ("SIP"), with 625,000 shares of Common Stock available to be issued. At the Annual Stockholder meeting on September 22, 2011 the Company's stockholders voted to approve an increase to the shares of Common Stock issuable under the SIP by 125,000 to 750,000. Under the terms of the SIP, the Compensation Committee of the Company's Board has the discretion to select the persons to whom awards are to be granted. Awards can be stock options, restricted stock and/or restricted stock units. The awards become vested at such times and under such conditions as determined by the Compensation Committee. As of December 31, 2015, there were 353,935 options exercised, 312,860 options outstanding and 83,205 options still available to be issued under the SIP. 
+F-13 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2015 AND 2014 
+Effective June 19, 2014, the Company's stockholders voted to approve the 2014 Stock Incentive Plan ("SIP14"), with 800,000 shares of Common Stock available to be issued. Under the terms of the SIP14, the Compensation Committee of the Company's Board has the discretion to select the persons to whom awards are to be granted. Awards can be stock options, restricted stock and/or restricted stock units. The awards become vested at such times and under such conditions as determined by the Compensation Committee. As of December 31, 2015, there were no options exercised, 129,750 options outstanding and 670,250 options still available to be issued under the SIP14. 
+The Company's results for the years ended December 31, 2015 and 2014 include stock-based compensation expense totaling $334,400 and $447,100, respectively. Such amounts have been included in the Consolidated Statements of Operations within cost of goods sold ($- and $700, respectively), research and development ($62,700 and $44,500, respectively) and selling, general and administrative expenses ($271,700 and $401,900, respectively). In accordance with ASC 718 the Company has not recorded a deferred tax asset related to the net operating losses resulting from the exercise of disqualifying stock options in the accompanying financial statements. The cumulative amount of unrecognized tax benefits at December 31, 2015 was immaterial, and if the Company is able to utilize this benefit in the future it would result in a credit to additional paid-in capital. 
+Stock option compensation expense in the years ended December 31, 2015 and 2014 represents the estimated fair value of options outstanding which is being amortized on a straight-line basis over the requisite vesting period of the entire award. 
+The Company did not grant any stock options during the year ended December 31, 2015. The weighted average estimated fair value of stock options granted in the year ended December 31, 2014 was $3.52 per share. The fair value of options at the date of grant was estimated using the Black-Scholes option pricing model. The expected volatility is based upon historical volatility of our stock and other contributing factors. The expected term is based on the Company's historical experience with similar type options. 
+The weighted-average assumptions made in calculating the fair values of options are as follows: 
+For the year ended 
+December 31, 2014 
+Expected term (in years) 
+4.50-6.30 
+Expected volatility 
+61.50-96.10% 
+Expected dividend yield 
+n/a 
+Risk-free interest rate 
+.83-1.52% 
+The Company granted no new options during the year ended December 31, 2015 to employees. 
+The following table provides stock options activity for the year ended December 31, 2015: 
+Stock Options 
+Number of 
+Shares 
+Weighted 
+Average 
+Exercise Price per 
+Share 
+Weighted 
+Average 
+Remaining 
+Contractual 
+Term 
+Aggregate Intrinsic 
+Value 
+Outstanding at December 31, 2014 
+691,869 
+$ 
+3.66 
+3.97 years 
+$ 
+334,636 
+Granted 
+- 
+$ 
+- 
+Exercised 
+41,141 
+$ 
+2.25 
+Forfeited/expired/cancelled 
+1,250 
+$ 
+4.30 
+Outstanding at December 31, 2015 
+649,478 
+$ 
+3.75 
+3.21 years 
+$ 
+1,032,362 
+Exercisable at December 31, 2015 
+359,228 
+$ 
+3.89 
+2.03 years 
+$ 
+522,039 
+F-14 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2015 AND 2014 
+The following table summarizes information about stock options outstanding at December 31, 2015: 
+Stock Options Outstanding 
+Stock Options Exercisable 
+Range of 
+Exercise 
+Prices 
+Shares 
+Average 
+Remaining 
+Contract Life 
+(Year) 
+Weighted 
+Average 
+Exercise 
+Price 
+Aggregate 
+Intrinsic 
+Value 
+Shares 
+Weighted 
+Average 
+Exercise 
+Price 
+Aggregate 
+Intrinsic 
+Value 
+0.0000 to 3.000 
+92,063 
+0.73 
+$ 
+2.80 
+$ 
+232,919 
+92,063 
+$ 
+2.80 
+$ 
+232,919 
+3.0001 to 3.500 
+343,750 
+4.73 
+3.43 
+651,863 
+87,500 
+3.44 
+165,060 
+3.5001 to 4.000 
+15,720 
+1.05 
+3.95 
+21,689 
+15,720 
+3.95 
+21,689 
+4.0001 to 4.500 
+122,320 
+1.87 
+4.37 
+117,971 
+98,320 
+4.37 
+94,451 
+4.5001 to 6.000 
+75,625 
+1.90 
+5.30 
+7,920.00 
+65,625 
+5.28 
+7,920 
+Total 
+649,478 
+3.21 
+$ 
+3.75 
+$ 
+1,032,362 
+359,228 
+$ 
+3.89 
+$ 
+522,039 
+As of December 31, 2015, there was $297,000 of net unrecognized compensation cost related to stock options that are not vested, which is expected to be recognized over a weighted average period of approximately 2.05 years. The total fair value of shares vested during the years ended December 31, 2015 and 2014, was $357,000 and $283,000, respectively. 
+NOTE 12 — GEOGRAPHIC INFORMATION AND ECONOMIC DEPENDENCY: 
+FASB Guidance establishes standards for the way that business enterprises report information about operating segments in financial statements and requires that those enterprises report selected information. It also establishes standards for related disclosures about product and services, geographic areas, and major customers. 
+Sales to Africa increased in 2015 primarily due to increased sales in Uganda by approximately $1,344,500, and Nigeria by approximately $287,500. Sales in Asia increased slightly by $76,200. European sales increased by $972,500. Sales decreased in 2015 to North America from decreased sales to Mexico of $3,913,400 and by decreased sales in the U.S from approximately $7,208,000 to $6,563,000. Sales decreases in 2015 to South America were primarily from decreased sales in Brazil from approximately $12,253,500 to $10,141,800 
+The Company produces only one group of similar products known collectively as "rapid medical tests". Management believes that it operates in a single business segment. Net sales by geographic area are as follows: 
+For the years ended 
+December 31, 2015 
+December 31, 2014 
+Africa 
+$ 
+3,673,199 
+$ 
+2,097,353 
+Asia 
+172,250 
+96,061 
+Europe 
+1,164,476 
+191,947 
+North America 
+6,525,951 
+11,134,691 
+South America 
+10,350,812 
+12,429,717 
+$ 
+21,886,688 
+$ 
+25,949,769 
+Sales to Africa increased in 2015 primarily due to increased sales in Uganda by approximately $1,344,500, and Nigeria by approximately $287,500. Sales in Asia increased slightly by $76,200. European sales increased by $972,500. Sales decreased in 2015 to North America from decreased sales to Mexico of $3,913,400 and by decreased sales in the U.S from approximately $7,208,000 to $6,563,000. Sales decreases in 2015 to South America were primarily from decreased sales in Brazil from approximately $12,253,500 to $10,141,800. 
+F-15 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2015 AND 2014 
+NOTE 13 — COMMITMENTS AND CONTINGENCIES: 
+Employment Contracts: 
+The Company has contracts with three key employees. The contracts call for salaries presently aggregating $944,500 per year. One contract expires in May 2017, one expires in March 2016 and one contract expires in March 2017. The following table is a schedule of future minimum salary commitments: 
+2016 
+$ 
+690,800 
+2017 
+181,200 
+Pension Plan: 
+The Company has a 401(k) plan established for its employees. Effective January 1, 2011 the Company elected to match 40% of the first 5% (or 2% of salary) that an employee contributes to their 401(k) plan. Expenses related to this matching contribution aggregated $90,915 and $82,750 for the years ended December 31, 2015 and 2014, respectively. 
+Obligations Under Operating Leases: 
+The Company leases industrial space used for office, R&D and manufacturing facilities, currently with a monthly rent of $27,988. The current lease expires on April 30, 2017. The lease provides for annual increases of 2 1/2 percent each year starting May 1, 2016. In February of 2014, the Company entered into a lease, effective March 1, 2014, for another facility located a short distance from its current facility currently with a monthly rent of $15,097. The space is used primarily for warehousing and provides for additional office space. The lease expires on April 30, 2018. The lease provides for annual increases of three percent each year starting March 1, 2016. 
+The following is a schedule of future minimum rental commitments (assuming no increases): 
+Years ending December 31, 
+2016 
+$ 
+527,151 
+2017 
+306,018 
+2018 
+64,067 
+$ 
+897,236 
+Rent expense was $511,900 and $476,000 for the years ended December 31, 2015 and 2014, respectively. 
+Economic Dependency: 
+The following table delineates sales the Company had to customers in excess of 10% of total sales for the periods indicated: 
+For the years ended 
+Accounts 
+Receivable As of 
+December 31, 2015 
+December 31, 2014 
+December 31, 2015 
+December 31, 2014 
+Sales 
+% of 
+Sales 
+Sales 
+% of 
+Sales 
+Customer 1 
+$ 
+10,132,512 
+46 
+% 
+$ 
+12,253,526 
+47 
+% 
+$ 
+775,209 
+$ 
+6,230,886 
+Customer 2 
+4,526,908 
+21 
+% 
+6,618,251 
+26 
+% 
+700,656 
+386,270 
+F-16 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2015 AND 2014 
+The following table delineates purchases the Company had with vendors in excess of 10% of total purchases for the periods indicated. 
+For the years ended 
+Accounts 
+Payable As of 
+December 31, 2015 
+December 31, 2014 
+December 31, 2015 
+December 31, 2014 
+Purchases 
+% of 
+Purc. 
+Purchases 
+% of 
+Purc. 
+Vendor 1 
+$ 
+794,536 
+11 
+% 
+$ 
+1,331,647 
+14 
+% 
+$ 
+90,075 
+$ 
+200,855 
+Vendor 2 
+* 
+* 
+$ 
+1,594,838 
+17 
+% 
+* 
+- 
+In the table above the asterisk (*) indicates that purchases from the vendor did not exceed 10% for the period indicated. 
+The Company currently buys materials which are purchased under intellectual property rights agreements and are important components in its products. Management believes that other suppliers could provide similar materials on comparable terms. A change in suppliers, however, could cause a delay in manufacturing and a possible loss of sales, which would affect operating results adversely. 
+NOTE 14 — COLLABORATIVE RESEARCH AND DEVELOPMENT AGREEMENTS: 
+In 2015 and 2014, the Company earned $2,316,044 million and $1,672,258 million, respectively, from research revenues and milestones. The Company is now involved in additional feasibility and development contracts related to its DPP® technology. The total expended on R&D, excluding regulatory, in 2015 and 2014, was approximately $5.4 million and $4.1 million, respectively. 
+a. 
+National Institutes of Health (NIH) Grant: 
+In March 2011, the Company received a $2.9 million, three-year grant from the United States National Institutes of Health to complete development of a test for Tuberculosis. Grants are invoiced after expenses are incurred. The Company earned, for the years ended December 31, 2015 and 2014, $- and $388,000, respectively from this grant. The Company has earned $2,850,000 from this grant from inception through December 31, 2015, of which $1,019,000 was paid to sub-contractors. 
+b. 
+Battelle/CDC DPP® Influenza Immunity Test: 
+In November 2014, the Company entered into a follow-on, milestone-based development agreement bringing the total up to $1,253,100 based on Chembio's previous successful initial development of a multiplex rapid point-of-care ("POC") influenza immunity test utilizing its patented Dual Path Platform (DPP®) technology. The follow-on agreement contemplates a period of approximately six months in which the follow-on development activity is to be completed. For the years ended December 31, 2015 and 2014, the Company earned $216,850 and $115,000, respectively from this grant. The Company has earned $1,253,100 from this grant from inception through December 31, 2015. 
+c. 
+Cooperative research agreement with a U.S. government agency: 
+In May 2013, the Company was awarded a cooperative research agreement with a U.S. government agency for up to $883,000 for an eight-month development project to develop rapid POC diagnostic tests for five infectious diseases associated with febrile illness. For the years ended December 31, 2015 and 2014, the Company earned $- and $117,000, respectively from this grant. The Company has earned $883,000 from this grant from inception through December 31, 2015. 
+F-17 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2015 AND 2014 
+d. RVR DPP® technology transfer agreement: 
+In February 2014, the Company entered into a technology transfer agreement with RVR Diagnostics for $1,500,000. The agreement was modified in September 2014 and September 2015. Per the agreement, as modified, the Company earned $125,000 and $1,125,000 in milestone payments during 2015 and 2014. The Company has earned $1,250,000 from this grant from inception through December 31, 2015. 
+e. Dengue agreement: 
+In October 2014, the Company entered into a development agreement with an international diagnostics company for $300,000. Revenue for this agreement is being recognized under a proportional performance method. For the years ended December 31, 2015 and 2014, the Company earned $240,000 and $60,000, respectively from this grant. The Company has earned $300,000 from this grant from inception through December 31, 2015. 
+f. 
+Brain Injury agreement: 
+In January 2015, the Company entered into a technology development agreement with Perseus Science Group LLC for $946,000. Revenue for this agreement is being recognized under a proportional performance method. The Company earned $469,600 for the year ended December 31, 2015 from this agreement. 
+g. 
+Malaria agreement: 
+In January 2015, the Company was awarded a grant from The Bill & Melinda Gates Foundation for $307,000. The Company earned $307,000 for the year ended December 31, 2015 from this agreement. 
+h. 
+Cancer agreement: 
+In October 2014, the Company entered into a technology development agreement with an international diagnostics company for $320,000. Revenue for this agreement is being recognized under a proportional performance method. The Company earned $205,000 for the year ended December 31, 2015 from this agreement. 
+i. 
+Fever panel agreement: 
+In October 2015, the Company entered into an agreement with Paul G. Allen Ebola Program for $2,118,265. Revenue for this agreement is being recognized under a proportional performance method. The Company earned $408,500 for the year ended December 31, 2015 from this agreement. 
+Governmental Regulation: 
+All of the Company's existing and proposed diagnostic products are regulated by the United States Food and Drug Administration (FDA), United States Department of Agriculture, certain state and local agencies, and/or comparable regulatory bodies in other countries. Most aspects of development, production, and marketing, including product testing, authorizations to market, labeling, promotion, manufacturing, and record keeping are subject to review. After marketing approval has been granted, Chembio must continue to comply with governmental regulations. Failure to comply with these regulations can result in significant penalties. 
+NOTE 15 — SUBSEQUENT EVENTS: 
+February 19, 2016, the Company announced it had been awarded a $550,000 grant from philanthropist and entrepreneur Paul G. Allen to immediately initiate development of simple, cost-effective POC diagnostic tests to identify Zika virus and related febrile illnesses. The grant is managed by Mr. Allen's company, Vulcan Inc., and the funds come from the Paul G. Allen Family Foundation. 
+On March 7, 2016, the Company announced plans to collaborate with Bio-Manguinhos/Fiocruz to undertake to develop, register and commercialize POC DPP® Zika Assays for Brazil. The Company has developed a prototype DPP® Zika Assay and prototype DPP® Zika/Dengue/Chikungunya Assay, and we hope to receive additional funding, along with the grant mentioned above, to accelerate the development and testing of our DPP® Zika Assays. The Company anticipates receiving significant orders for DPP® Zika Assays in 2016. 
+On March 8, 2016, the Company entered into a Rights Agreement (the "Rights Agreement") between the Company and Action Stock Transfer Corp., as Rights Agent. Pursuant to the Rights Agreement, the Company declared a dividend distribution of one preferred share purchase right (a "Right") for each outstanding share of Common Stock, $0.01 par value (the "Common Stock"), of the Company, in the manner described below. The Board of Directors set the payment date for the distribution of the Rights as March 8, 2016, and the Rights were distributed to the Company's shareholders of record on that date. The description and terms of the Rights are set forth in the Rights Agreement. 
+F-18 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2015 AND 2014 
+Rights Initially Not Exercisable. The Rights are not exercisable until a Distribution Date. Until a Right is exercised, the holder thereof, as such, has no rights as a shareholder of the Company, including, without limitation, the right to vote or to receive dividends. 
+Separation and Distribution of Rights . The Rights are to be evidenced by the certificates for shares of Common Stock registered in the names of the holders thereof, and not by separate rights certificates until the earlier to occur of (i) the close of business on the tenth business day following a public announcement that an Acquiring Person (as defined in the Rights Agreement) has acquired a Combined Ownership (as defined in the Rights Agreement) of 20% or more of the outstanding shares of the Common Stock (the "Shares Acquisition Date") or (ii) the later of (A) the close of business on the tenth business day (or such later date as may be determined by action of the Board of Directors prior to such time as any person or group of affiliated or associated persons becomes an Acquiring Person) after the date that a tender or exchange offer or intention to commence a tender or exchange offer by any person is first published, announced, sent or given within the meaning of Rule 14d-4(A) under the Securities Exchange Act of 1934, as amended, the consummation of which would result in any person having Combined Ownership of 20% or more of the outstanding shares of the Common Stock, or (B) if such a tender or exchange offer has been published, announced, sent or given before the date of the Rights Agreement, then the close of business on the tenth business day after the date the Rights Agreement was entered into (or such later date as may be determined by action of the Board of Directors prior to such time as any person becomes an Acquiring Person); (the earlier of such dates referred to in (i) and (ii), which date may include any such date that is after the date of the Rights Agreement but prior to the issuance of the Rights, being called the "Distribution Date"). 
+F-19
\ No newline at end of file
diff --git a/raw/filings/0001092662/2015/0001092662-16-000121/filing_metadata.csv b/raw/filings/0001092662/2015/0001092662-16-000121/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..885a834aeda42c1b5e0faf3c10eb6dd2567d3819
--- /dev/null
+++ b/raw/filings/0001092662/2015/0001092662-16-000121/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0001092662,CEMI,"CHEMBIO DIAGNOSTICS, INC.",10-K,2016-03-08,2015-12-31,2016-03-08T13:17:20.000Z,0001092662-16-000121,form10_k.htm,FORM 10-K FOR 2014,5823919,1,0,https://www.sec.gov/Archives/edgar/data/1092662/000109266216000121/form10_k.htm,https://www.sec.gov/Archives/edgar/data/1092662/000109266216000121/,2015,2015,1
diff --git a/raw/filings/0001092662/2015/0001092662-16-000121/item1.txt b/raw/filings/0001092662/2015/0001092662-16-000121/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..1f0b592f135ab7f0926be974c5b5c267798164ba
--- /dev/null
+++ b/raw/filings/0001092662/2015/0001092662-16-000121/item1.txt
@@ -0,0 +1,284 @@
+ITEM 1. 
+BUSINESS 
+FORWARD-LOOKING STATEMENTS 
+This report contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, and Section 27A of the Securities Act of 1933. Any statements contained in this report that are not statements of historical fact may be forward-looking statements. When we use the words "intends," "estimates," "predicts," "potential," "continues," "anticipates," "plans," "expects," "believes," "should," "could," "may," "will" or the negative of these terms or other comparable terminology, we are identifying forward-looking statements. Forward-looking statements involve risks and uncertainties, which may cause our actual results, performance or achievements to be materially different from those expressed or implied by forward-looking statements. These factors include our research and development activities, distributor channels, market demand for our products, compliance with regulatory impositions; and our capital needs. Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance or achievements. 
+Except as may be required by applicable law, we do not undertake or intend to update or revise our forward-looking statements, and we assume no obligation to update any forward-looking statements contained in this report as a result of new information or future events or developments. Thus, you should not assume that our silence over time means that actual events are bearing out as expressed or implied in such forward-looking statements. You should carefully review and consider the various disclosures we make in this report and our other reports filed with the Securities and Exchange Commission that attempt to advise interested parties of the risks, uncertainties and other factors that may affect our business. 
+We provide free of charge on our website at www.chembio.com our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable. Members of the public may read and copy any materials we file with the SEC at the SEC's Public Reference Room at 100 F Street, NE, and Washington, DC 20549. Members of the public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800–SEC–0330. The Internet address of the Commission is www.sec.gov. That website contains reports, proxy and information statements and other information regarding issuers, like Chembio, that file electronically with the Commission. Visitors to the Commission's website may access such information by searching the EDGAR database. 
+For further information about these and other risks, uncertainties and factors, please review the disclosure included in this report under "Part I, Item 1A, Risk Factors." 
+Our Business 
+General 
+The Company (Chembio Diagnostics, Inc. and its wholly-owned subsidiary Chembio Diagnostic Systems, Inc. are collectively referred to herein as the "Company") develops, manufactures, markets and licenses rapid point-of-care diagnostic tests (POCTs) that detect infectious diseases. The Company's main products presently commercially available are rapid tests for the detection of HIV 1/2 antibodies, and a multiplex rapid test for the detection of HIV and Syphilis antibodies. The HIV 1/2 rapid tests employ in-licensed and proprietary lateral flow technologies (see "Our Rapid Test Technologies"), can be used with all blood matrices as samples, and are manufactured in a standard cassette format, a dipstick format, and a proprietary barrel format. The tests employing the cassette and proprietary barrel formats were approved by the FDA in 2006. The barrel format is exclusively distributed by a distributor in the United States and by Chembio and its designated distributors outside the United States. The exclusive U.S. distribution agreement for the barrel product terminates in accordance with its terms on May 31, 2016. Chembio and any newly designated distributors will distribute the product in the U.S. after May 31, 2016. The Cassette format is distributed by Chembio and its designated distributors worldwide. Our latest generation HIV 1/2 rapid antibody detection test incorporates our patented Dual Path Platform® (DPP®) POCT technology, and this POCT platform does not require in-licensing. The DPP® HIV 1/2 Assay detects antibodies to HIV 1 & 2 in oral fluid samples as well as in all blood matrices. We have sold this product in Brazil since 2009 where it was approved by ANVISA, through our agreement with the Oswaldo Cruz Foundation ("FIOCRUZ"), and we received United States FDA regulatory approval for this product in December 2012 and CLIA waiver in October 2014. We launched it in the United States under Chembio's brand in the fourth quarter of 2014. 
+Our product pipeline, which currently includes a multiplex rapid test for earlier detection of HIV by detecting P-24 antigen as well as antibodies, a test for Hepatitis-C, and a multiplex test that detects HIV and Syphilis specific antibodies (which we are already selling outside the U.S.), is based on this DPP® technology for which we were issued a United States patent in 2007 and for which additional patent protection has issued or is pending in a number of other countries. With the patented DPP® and the lateral flow platform, we participate in the estimated $8 billion point-of-care market segment of the estimated nearly $50 billion global in-vitro diagnostic market that has an overall growth rate exceeding 3% per annum. POCTs, by providing prompt and early diagnosis, can reduce patient stays, lower overall costs, improve therapeutic interventions and improve patient outcomes. POCTs can also prevent needless hospital admissions, simplify testing procedures, avoid delays from central lab batching, and eliminate the need for return visits. 
+In the areas of infectious and sexually transmitted diseases (such as HIV and syphilis), the utility of a rapid point–of-care (POC) test, particularly in identifying patients unaware of their disease status, has been well established. Large and growing markets have been established for these kinds of tests, initially in high prevalence regions where they are indispensable for large scale prevention and treatment programs. More recently introduced in the United States in 2004, rapid HIV tests now also present a significant segment of the U.S. market for HIV clinical testing, which is still dominated by laboratory tests. We have focused our product development activity within areas where the availability of rapid, point-of-care screening, diagnostic, or confirmatory results can improve health outcomes. More generally we believe there is and will continue to be a growing demand for diagnostic products that can provide accurate, actionable diagnostic information in a rapid, cost-effective manner at the point of care. 
+PRODUCTS 
+Lateral Flow Rapid HIV Tests 
+All three of our lateral flow rapid HIV antibody detection tests are qualitative "yes/no" tests for the detection of antibodies to HIV 1 & 2 with visually interpreted results (one line "negative"; one line "positive") available within approximately 15 minutes. The tests are simple to use, have a shelf life of 24 months, and do not require refrigeration. The tests differ principally only in the method of test procedure, convenience and cost. One of our FDA-approved lateral flow HIV tests incorporates a proprietary plastic "barrel" device that houses the lateral flow strip. This barrel format enables collection of samples directly (usually from a finger-stick whole blood sample) into the barrel's capillary tip. A sealed unitized buffer vial, assembled onto the top of the barrel, is removed and seated into a stand; the seal is then pierced by the barrel's capillary tip, thereby initiating the upward flow of the resulting sample-buffer solution through a filter, up into the vertical device's chamber and onto the lateral flow strip. This results in a unique unitized and closed device system that can reduce the chance of exposure to potentially infectious samples. 
+In January 2015, the Company entered into an agreement with StatSure Diagnostic Systems, Inc. (SDS) to acquire SDS' interest in the barrel device format, also known as Chembio's SURE CHECK® HIV 1/2 Assay, effective June 1, 2016. Beginning June 1, 2016, Chembio will own full rights related to the SURE CHECK® HIV 1/2 Assay, including sales, marketing, distribution and trademark rights, subject to the terms of the existing marketing and distribution agreement with Alere, Inc., which grants Alere U.S. marketing and distribution rights through May 31, 2016. Prior to this newly-executed agreement between SDS and Chembio, SDS has owned a 50 percent interest in the rights to the SURE CHECK® HIV 1/2 Assay that would have continued after May 31, 2016, also subject to the existing marketing and distribution agreement with Alere. The new agreement with SDS also resolves all other matters between Chembio and SDS, including their respective sharing ratios, until June 1, 2016, concerning net revenues from sale of the SURE CHECK® product outside the U.S. 
+2 
+The Company's SURE CHECK® HIV 1/2 Assay is marketed exclusively in the U.S. as Clearview® Complete pursuant to an exclusive distribution agreement that terminates in accordance with its terms on May 31, 2016. After May 31, 2016, it will be marketed in the U.S. as Sure Check® HIV 1/2 Assay. Outside the U.S., Chembio markets the SURE CHECK® HIV 1/2 Assay primarily through distributors. The SURE CHECK® HIV 1/2 Assay is Food & Drug Administration (FDA) approved, CLIA-waived, European CE-marked, and has been pre-qualified by the World Health Organization (WHO). Results are obtained in 15 minutes via a 2.5uL blood sample (i.e., fingerstick, serum, plasma, or venipuncture whole blood). The assay is stable at room temperature and provides 99.7% sensitivity and 99.9% specificity. 
+Our other FDA-approved lateral flow HIV test uses a more conventional rectangular plastic cassette format that houses the lateral flow strip. In this case, a sample is transferred by use of a separately provided transfer device ("loop") into a sample well or port of the cassette that houses the lateral flow strip, which is positioned horizontally or flat. 
+Our third lateral flow HIV test, the HIV 1/2 STAT PAK® Dipstick, is our most cost competitive and compact format. It does not have any plastic housing so that 30 test strips can be packaged into a small vial that is ideal for transporting into remote settings. The test procedure is similar to the cassette format except that a user-applied adhesive backing is provided as a more cost-effective and compact "surface" on which to run the test. 
+Regulatory Status of the lateral flow HIV tests 
+The FDA approved our Pre-Market Applications (hereinafter "PMA"; see "Governmental Regulations" and Glossary) in April 2006 for our SURE CHECK® HIV 1/2 (and also now Alere Clearview® Complete HIV 1/2) and for our HIV 1/2 STAT-PAK® products. Waivers under the Clinical Laboratory Improvement Act (hereinafter "CLIA"; see Governmental Regulations) were granted by the FDA for these two FDA-approved products in 2006 and 2007, respectively. A CLIA waiver is required in order for health care providers to administer these tests in the settings where they are most suited and needed, such as public health testing clinics, hospital emergency rooms and physicians' offices. The SURE CHECK® and HIV 1/2 STAT-PAK® products received CE Marks in July 2013 and March 2014, respectively, and the CE Marking for the DPP® HIV 1/2 Assay received in May 2015. We have also updated our filing for CE Marking to reflect the new tradename of STAT-VIEW® HIV 1 / 2 Assay for sale in the EU market. Our HIV 1/2 STAT-PAK® Dipstick, although not FDA-approved, qualifies under FDA export regulations [See Government Regulation] to sell to customers outside the United States, subject to any required approval by the importing country. CE Mark has not been pursued for this product. 
+All three of our lateral flow HIV tests have qualified for procurement under the President's Emergency Plan for AIDS Relief ("PEPFAR"). The cassette and dipstick versions of the STAT-PAK® and the SURE CHECK® assays are also pre-qualified by the World Health Organization (WHO) for procurements by the second largest global program, known as the Global Fund, as well as other related programs funded by agencies affiliated with the United Nations, such as UNICEF and UNITAIDS (see Glossary), through qualification with the WHO bulk procurement scheme. 
+DPP® HIV 1/2 Assay 
+As in the case of our lateral flow HIV tests, our DPP® HIV 1/2 Assay is also a qualitative "yes/no" test for the detection of antibodies to HIV 1& 2, delivers visual results within as little as 15 minutes, is simple to use, has a shelf life of 23 months, and does not require refrigeration. This product, which is our first FDA-approved product incorporating our patented DPP® technology, can be used with oral fluid samples, as well as with all blood matrices. This product also incorporates our patent-pending oral fluid collection and storage system that enables samples to be fully extracted in buffer solution before application to the test device, and also enables the extracted sample to be stored and retested or potentially tested for multiple conditions in future product applications. Clinical and laboratory studies demonstrated the ability of the test to accurately detect the presence of antibodies in individuals down to two years of age. Studies have also shown this product to have improved performance compared with all of the current FDA-approved CLIA-waived lateral flow rapid tests, even including our own lateral flow tests. FDA-approved label claims include sensitivity/specificity on oral fluid and finger-stick whole blood of 98.9%/99.9% and 99.9%/100% respectively. Oral fluid sensitivity was 100% among HIV-positive patients not taking anti-retroviral medication. 
+Regulatory Status of the DPP® HIV 1/2 Assay 
+In December 2012, we received FDA approval of our Pre-Marketing Approval. In October of 2014 the FDA granted CLIA-waiver status. 
+The DPP® HIV 1/2 Assay product is qualified for procurement under the President's Emergency Plan for AIDS Relief ("PEPFAR") for use with all sample matrices, and we are pursuing WHO qualification in order to enable procurement of this product by the Global Fund and United Nations agencies, including programs underwritten by them. In October 2014, we completed a three-day on-site inspection by the WHO as follow-up to pre-qualification activities of our products with no major non-conformances noted during the audit. The WHO laboratory evaluation for the blood matrix is complete, while oral fluid is in progress and expected to be complete in 2016. In May 2015 we received approval for a CE Mark for the DPP® HIV 1/2 Assay for Oral Fluid, Serum, Plasma, Fingerstick Whole Blood and Venous Whole Blood. 
+In June 2010, ANVISA approved the DPP® HIV 1/2 Assay that is being marketed in Brazil through our collaboration with the Oswaldo Cruz Foundation, Brazil's leading public health institute (see Oswaldo Cruz Foundation OEM DPP® Agreements). Since this time, we have sold and marketed millions of DPP® HIV tests to Brazil through this partnership. 
+DPP® HIV-Syphilis Multiplex Test 
+This product, launched in 2013, allows for the detection of antibodies to both HIV and Syphilis on a single test device within approximately 15 minutes. In certain global/public health settings (see Target Markets), this product may provide a more convenient and cost-effective means of rapid detecting both markers in a single test procedure at the point of care as compared with performing separate rapid tests for each indication. This product takes advantage of the multiplexing feature of DPP® which provides for a more robust reaction between the sample and biomarkers being tested for (HIV and Syphilis antibodies in this case), resulting in a greater ability by the user to visually interpret test results. We launched this product in Mexico in the fourth quarter of 2013 as a unitized product, meaning that each test kit was separately packaged to include each of the other components necessary to run this test, as compared with other configurations where a test kit of 20 or 30 devices is accompanied by one bottle of running buffer. The initial results of this launch have been very positive, and we experienced good results in Mexico during 2014 from the program. Building on this initial success, we continue to pursue commercialization efforts for this product in a number of additional international markets, where there is a great need to detect Mother-to-Child-Transmission of HIV and Syphilis globally. According to the CDC website, "approximately 370,000 babies are born with HIV, mostly in sub-Saharan Africa. Without treatment, more than half of these children will die before the age of 2. Through key interventions, such as routinely testing pregnant women for HIV, providing antiretroviral medications to HIV-infected pregnant women and their exposed infants, and promoting safe infant feeding practices, mother-to-child transmission of HIV can be decreased from about 35% to less than 5%. Another prominent cause of infant mortality is untreated maternal syphilis, which still accounts for more than 500,000 stillbirths and infant deaths annually despite the fact that these deaths could be prevented through routine detection and treatment of syphilis during antenatal care". 
+Regulatory Status of the DPP® HIV-Syphilis Test 
+DPP® HIV-Syphilis – We have developed this product for international and U.S. marketing. For the international market, the product has been registered in Mexico, and successfully launched and sold in this region. 
+In February 2015, this product was granted approval from the Brazilian ANVISA. We have submitted this product both for evaluation by the CDC, acting on behalf of the United States Agency of International Development, and the WHO, which has accepted this product to be evaluated for pre-qualification in its global procurement scheme. In October 2014, WHO conducted a three-day audit of our facilities as follow up to pre-qualification activities for the DPP HIV-Syphilis Assay, including other products submitted for pre-qualification through WHO. No major non-conformances were identified during this audit, and we continue to work with WHO to obtain pre-qualification approval status for this device. 
+We are developing a U.S. version of the DPP® HIV-Syphilis Assay, designed to meet the performance requirements for the "reverse" algorithm that is currently in clinical use for syphilis testing in the United States. We have completed our pre-clinical studies for this product with encouraging results, and are in the final stages of clinical site selection for our U.S. clinical studies. We plan to begin this clinical trial in the U.S. during first quarter of 2016, and expect that the trial will be completed in six to nine months from initiation. 
+3 
+DPP® TECHNOLOGY & DEVELOPMENT 
+Chembio is executing its strategy to leverage the DPP® intellectual property and product development and manufacturing experience to create new collaborations where Chembio serves as an exclusive development and manufacturing partner. Examples of such collaboration include the following: 
+· 
+The Company entered into an agreement to develop a POC diagnostic test for dengue fever virus, the DPP® Dengue Fever Assay, which would be able to detect IgG/IGM and NS1 antigens in October 2014. 
+· 
+A collaboration also announced in October 2014, with an international diagnostics company to develop a POC diagnostic test for the early detection and monitoring of a specific type of cancer. At that time, the cancer project represented the first application of the DPP® technology outside the infectious disease field. 
+· 
+The Company entered into a follow-on, milestone-based development agreement with a private contracting organization acting on behalf of the United States Centers for Disease Control and Prevention (CDC), for a multiplex POC influenza immunity test utilizing Chembio's patented Dual Path Platform (DPP® ) technology. 
+· 
+In January 2015, Chembio entered into an agreement with the Concussion Science Group (CSG) Division of Perseus Science Group LLC, to utilize Chembio's patented DPP® technology to develop a POC diagnostic test for traumatic brain injury (TBI), including sports-related concussion. Under terms of the agreement, CSG's patented biomarker will be combined with Chembio's proprietary DPP® platform to develop a semi-quantitative or quantitative point-of-care test to diagnose TBI. CSG agreed to pay Chembio milestone development payments during 2015. 
+· 
+In January 2015, Chembio was awarded a grant from The Bill & Melinda Gates Foundation to expedite the feasibility testing and development of a DPP® Malaria POC rapid diagnostic to accurately identify individuals infected with Plasmodium falciparum parasite. Chembio's DPP® technology was selected for this grant due to its exceptional sensitivity and potential to aid the foundation in its goal of eradicating malaria. To achieve this goal, diagnostics must be capable of detecting the malaria parasite in infected, but asymptomatic, people. Current POC rapid diagnostics tests lack sufficient sensitivity to identify all individuals with transmissible infections. 
+· 
+In October 2015, Chembio was awarded a grant from the Paul G. Allen Foundation to develop a POC test to identify multiple life-threatening febrile illnesses. Under the $2.1 million dollar grant, Chembio will use its patented DPP® technology to develop a DPP® Fever Panel Assay, a POC multiplex assay to simultaneously detect Malaria, Dengue, Ebola, Lassa and Marburg. The multiplex assay that is planned to be designed to include a quality control test band and seven tests bands with specific antibodies to detect different pathogens, including multiple serotypes of the same pathogen: Malaria PAN-PLDH antigen (Plasmodium falciparum, Plasmodium vivax, Plasmodium malariae, Plasmodium ovale), Malaria Falciparum HRP2 antigen, Ebola Virus PAN (Zaire, Sudan, Bundibugyo Virus), Marburg Virus, Lassa Virus, Dengue Virus (Dengue 1, Dengue 2, Dengue 3, Dengue 4) and Chikungunya Virus. In many parts of the world, these diseases are commonly misdiagnosed, resulting in a delay of treatment or failure to properly treat the underlying infection. Misdiagnosis may be due to the fact that these diseases have similar symptoms that are difficult to distinguish. Currently available POC diagnostics lack the ability to test for multiple diseases simultaneously. Further, existing POC diagnostics may lack the sensitivity and specificity required to detect infected but asymptomatic patients - information that is critical for preventing the spread of disease. 
+· 
+Also in October 2015, Chembio signed an agreement with opTricon (Berlin, Germany), a leading developer of mobile analysis devices for rapid diagnostic tests. Through this exclusive agreement, subject to certain terms, and covering the fields of sexually transmitted diseases, certain "fever" diseases, and a specific form of cancer, Chembio will launch the DPP® Micro Reader, a point-of-care instrument designed specifically to complement Chembio's patented DPP® technology as applied to those diseases. The DPP® Micro Reader will include an innovative image sensor to provide a quantitative interpretation of diagnostic results when combined with Chembio's proprietary DPP® immunoassay technology. Using a state-of-the-art camera system, the DPP® Micro Reader is designed to provide definitive diagnostic results for low analyte concentrations, which may otherwise result in faint or ambiguous test results. In addition, the DPP® Micro Reader will provide customers with various options to capture, record, transmit and store test results. With one-button operation, the palm-sized and battery-operated DPP® Micro Reader is simple, fast, portable and cost-effective. 
+PARTNERS INVOLVED IN MARKETING OUR PRODUCTS 
+Alere 
+On September 29, 2006, we executed marketing and license agreements with Alere. The marketing agreements (the Barrel Agreement and the Cassette Agreement) provide Alere with a 10-year exclusive right (until May 31, 2016) to market our rapid HIV tests in the United States under Alere's brands. The agreements also provide Chembio a non-exclusive license to certain Alere lateral flow patents that may be applicable to our lateral flow products, including for manufacture of the HIV tests in the United States for sales outside the United States and even for sale in the United States should Alere enter the U.S. market with a competitive rapid HIV test product and in such case we choose to market our products directly as provided in the agreements in such event of a competitive rapid HIV test product. Simultaneous with the execution of the agreements, we also settled litigation with StatSure Diagnostics, Inc. (SDS), that had been ongoing relating to the proprietary barrel device which is incorporated into one of our two FDA-approved rapid HIV tests (See Lateral Flow HIV Tests above). SDS, pursuant to the settlement, is a party to the 3-way Barrel Agreement. As a result, until now, it is through the agreements with Alere that we have been participating in the growth of the rapid HIV test market in the United States. 
+In late July 2013, we received notice from Alere that it intends to commercialize its own rapid HIV test (see Competition), which test had just received FDA approval as a moderate complexity product (i.e. not CLIA-waived though this was granted in late 2014), in the United States. Under the Barrel Agreement and the Cassette Agreement such product is considered to be a Permitted Competing Product (PCP). Each of the two aforementioned agreements provides that, in the case of notice of a PCP, Chembio may make certain elections (jointly with SDS in the case of the Barrel Agreement), or elect to continue each agreement without taking any further action. Under the Cassette Agreement, Chembio may, at any time, terminate such agreement, which termination would become effective 60 days after the date notice was made. Under the Barrel Agreement, Chembio and SDS may jointly issue a non-exclusivity notice, which notice shall be effective immediately. In the event that Chembio makes this election with respect to the cassette product, or that both Chembio and SDS make this election with respect to the cassette product, then the electing party or parties could sell that respective product in the United States market under its own brand, and in such case, the lateral flow license that Chembio has from Alere for international sales would be expanded to include sales in the United States. See Lateral Flow Technology and Reagent Licenses. In April 2014, the Company gave notice to Alere of its intent to terminate the Cassette Agreement and 60 days later, the Company began marketing in the United States under the Chembio brand of HIV 1/2 STAT-PAK® assay. The barrel product continues to be marketed exclusively by Alere in the U.S only, although on May 31, 2016, the Barrel Agreement will expire pursuant to its terms, and Chembio will also market the barrel product in the U.S. under the brand of SureCheck® HIV 1/2 Assay. 
+We have developed our own sales and marketing departments for the sales of our products in the U.S. We have appointed distributors internationally for our lateral flow HIV tests. Our largest markets outside the U.S. for our lateral flow HIV rapid tests are certain countries in Africa, Asia, and South America, as well as Mexico. Internationally, most of the demand for our products is based on governmental and non-governmental prevention and treatment efforts. Given this, these programs can and do often result in large orders, but also can result in periods of relatively lower demand, based on the variations associated with this kind of demand. 
+4 
+OEM DPP® Products 
+Oswaldo Cruz Foundation OEM DPP® Agreements 
+During 2008-2010 we signed five separate agreements, each of which is titled and constitutes a "Technology Transfer Agreement", with the Oswaldo Cruz Foundation (FIOCRUZ) in Brazil. FIOCRUZ includes the Institute of Technology on Immunobiologicals/Bio- Manguinhos, which is the FIOCRUZ unit that produces vaccines and diagnostic kits. FIOCRUZ and Bio-Manguinhos are referred to herein interchangeably. Each of the five agreements relates to a different specific product or group of products based on our DPP® technology. FIOCRUZ is the leading public health organization in Brazil, and it is affiliated with Brazil's Ministry of Health, which is its principal client. It has extensive research, educational and manufacturing facilities for drugs and vaccines, as well as for diagnostic products. 
+Each of the agreements grants to FIOCRUZ the right, but not the obligation, to earn the right to request a technology transfer to be able to license and manufacture that product on its own. FIOCRUZ is not required to earn this right, but if it desires to do so, then it needs to purchase a stated amount of the product as set forth in the respective agreement for that product. 
+During 2010 and 2011, all of the initial products contemplated under the five agreements were approved for marketing by the applicable regulatory agencies in Brazil. The agreements between the Company and FIOCRUZ are unique examples of technology transfer collaborations between a private sector rapid test manufacturer and a public health organization. The five products categories for which FIOCRUZ can earn a separate right to request a technology transfer for that product only are: DPP® products for HIV screening, HIV Confirmatory, Leishmaniasis, Leptospirosis and Syphilis. Each technology transfer, and the provision by Chembio of the information and training that is required for this to occur, will occur only if FIOCRUZ purchases from Chembio the amount of that product that is specified in the respective agreement for that product. The actual amount of purchases for each product is totally at the discretion and option of FIOCRUZ and may be more or less than the amount needed to qualify for a technology transfer. 
+More specifically, the five agreements, although separate and independent of one another, are structurally similar according to the following: 
+· 
+Each agreement states: "the object of this Agreement is for the Transfer of Technology from Chembio to Bio-Manguinhos, the license by Chembio to Bio-Manguinhos for the Chembio Patents applied or granted in Brazil or other Mercosur countries for the term of the patents and the transfer of all the technical information related to the DPP® technology and the process to obtain the product by the DPP® technology. This Agreement contemplates the scientific and technological co-operation between Chembio and Bio-Manguinhos for such activities so that Bio-Manguinhos will be able to manufacture the Product in Brazil." 
+· 
+Each agreement provides that Chembio will supply free of charge to Bio-Manguinhos prototypes of the product to demonstrate performance characteristics that are necessary for evaluation by the Brazilian Ministry of Health and for registration with ANVISA. ANVISA is the Agencia Nacional de Vigilancia Sanitaria, or the National Sanitary Vigilance Agency. The number of prototypes ranges from 15,000 to 45,000 in the various agreements. 
+· 
+Each agreement provides that the prototypes will be utilized both for a performance study that follows a protocol prepared and approved by Bio-Manguinhos and the Brazilian Ministry of Health, and also will be used for studies in Brazil for the registration procedures at ANVISA. Bio-Manguinhos will then apply to ANVISA to register the product. Within 120 days of the registration of the product with ANVISA, Bio-Manguinhos will make an advance technology transfer payment to Chembio (the "Advance Payment"), in an amount specified in that particular agreement. All five of the Advance Payments provided for in the agreements were made in 2010 and 2011. 
+· 
+At such time, if any, that the product for a particular agreement has been successfully registered with ANVISA, then Bio-Manguinhos has the right to qualify for the full technology transfer for that product by purchasing the amount of the product, and at the price, specified in the agreement. 
+· 
+Bio-Manguinhos is not required to purchase any amount of any product. For each product, it only needs to purchase that product, in the amount specified in the agreement, only if it desires to be able to complete the technology transfer process in order to manufacture and sell that product on its own. Chembio does not have recourse against Bio-Manguinhos if Bio-Manguinhos does not purchase the qualifying purchase amount of any product. In that case, Chembio can only suspend further phases of the technology transfer, attempt to renegotiate the agreement, and/or retain any amounts previously paid by Bio-Manguinhos. Chembio cannot force Bio-Manguinhos to purchase any amount of any product. 
+· 
+As a result of the terms of these agreements, Bio-Manguinhos has never been required to, and is not now required to, purchase any amount of any of the products. 
+· 
+As of December 31, 2015 Bio-Manguinhos had earned the status described below with respect to each of the five products: 
+1. 
+With respect to Chembio's DPP® HIV1/2 Screen test, Bio-Manguinhos had qualified to request the technology transfer. It has requested, and has received, the technology transfer information. Bio-Manguinhos purchased $880,175, $4,990,840 and $291,235 of this product in 2011, 2012 and 2013, respectively, all of which applied to the qualifying amount to obtain the right to the technology transfer (the "Qualifying Amount") for this product. In 2013, 2014 and 2015, Bio-Manguinhos made $3,320,010, $4,799,250 and $5,410,350, respectively, of purchases in excess of the Qualifying Amount. 
+2. 
+With respect to Chembio's Canine Leishmania test, Bio-Manguinhos had qualified to request the technology transfer and did so request. Submission of the technology transfer information is in process at this time. Bio-Manguinhos purchased $2,000,817 and $99,183 of this product in 2011 and 2012 respectively, of this product in that applied to the Qualifying Amount. In addition, Bio-Manguinhos made purchases in excess of the Qualifying Amount equal to $1,314,117, $1,736,700, $2,394,000 and $3,772,482 in 2012, 2013, 2014 and 2015, respectively. 
+5 
+3. 
+a. 
+With respect to the three variations of Chembio's DPP® Syphilis test, all of which are covered by a single agreement, Bio-Manguinhos had qualified to request the technology transfer with respect to Trep only, and intends to do so in the near future. Bio-Manguinhos purchased $1,194,250, $165,750 of this product in 2011 and 2012, respectively that applied to the Qualifying Amount. In addition, Bio-Manguinhos made purchases in excess of the Qualifying Amount equal to $2,817,750, $646,340, $4,617,891 and $833,631 in 2012, 2013, 2014 and 2015, respectively. 
+b. 
+With respect to the two variations of Chembio's Screen & Confirm Test, Bio-Manguinhos had not made any purchases in 2011, 2012, 2013, 2014 or 2015, and therefore had not qualified to request the technology transfer for either of them. This agreement was terminated in December 2015. 
+c. 
+This syphilis agreement was terminated during the fourth quarter of 2015. 
+4. 
+With respect to Chembio's DPP® Confirmatory test, Bio-Manguinhos had not qualified to request the technology transfer. Bio-Manguinhos made purchases of $560,000, $819,000, $390,000, $390,000 and $156,000 of this product in 2011, 2012, 2013, 2014 and 2015 respectively, all of which applied to the Qualifying Amount. In order to qualify for the technology transfer, Bio-Manguinhos would need to purchase an additional $39,000 of this product. 
+5. 
+With respect to Chembio's DPP® Leptospirosis test, Bio-Manguinhos had not qualified to request the technology transfer. Bio-Manguinhos made purchases of $135,000 of this product in 2011, and it made -0- purchases in 2012, $45,000 in 2013 and it made -0- purchases in 2014 and -0- in 2015. In order to qualify for the technology transfer, Bio-Manguinhos would need to purchase an additional $225,000 of this product. 
+· 
+As stated above, Bio-Manguinhos is not obligated to make any purchases. After the specified level of sales for a particular product has been achieved, FIOCRUZ may request that the technology for that product be transferred to FIOCRUZ together with an exclusive license to produce and sell that product in a defined territory. The license is to provide that Chembio will receive a royalty on all sales. Chembio does not release the amount of this royalty because it could have an adverse effect on negotiations concerning royalties in potential transactions with other parties. 
+· 
+All the agreements expire five years after the date of the technology transfer. If terminated earlier by default of FIOCRUZ, FIOCRUZ must stop all activity; if terminated earlier by default of Chembio, or if terminated by natural expiry, FIOCRUZ can continue to produce and commercialize the product without paying royalties. 
+Other OEM And License Agreements Related to DPP® Technology 
+In addition to our agreements with FIOCRUZ, we have entered into certain OEM and license agreements with other parties with respect to certain products that we have developed based on our DPP® technology. In 2008 we entered into a product development and license agreement with Bio-Rad Laboratories, Inc. (Bio-Rad), a leading multinational life sciences company, for the first ever POC test for the confirmation of HIV (reflex test used after initial screening test(s) are positive). This product utilizes our DPP® technology, capitalizing on its multiplexing advantages, and is much simpler to perform than the legacy confirmatory platform, known as western blot, which requires a substantial amount of technical training and hands-on time and which is more expensive to manufacture and distribute. This product was CE marked and was launched by Bio-Rad in the second quarter of 2013 in Europe under their Geenius® brand; and an FDA PMA approval was received in 2014. 
+In 2013 we entered into collaboration with Labtest, a private company in Brazil, for the distribution of a number of products in Brazil that would be co-branded with Labtest and Chembio trademarks. Under this agreement, upon request from Labtest, for which there is no requirement, Chembio will sell the appropriate DPP® components to Labtest for further manufacture and assembly in Brazil. 
+In February 2014, Chembio entered into a technology transfer and license agreement with RVR Diagnostics SDN BHD ("RVR"), a privately-held company in Malaysia. The agreement supports Chembio's strategy of establishing a market presence in Asia, in collaboration with RVR as a licensee, distributor, and contract manufacturer, depending on the circumstances. The agreements grant exclusive distribution rights to RVR in certain countries in the region and enable RVR to manufacture Chembio's DPP® HIV 1/2 Assay and DPP® HIV-Syphilis Assay, and potentially other products developed by Chembio, such as Dengue, incorporating its patented DPP® technology as indicated in the DPP® Technology & Development section above. 
+Our Rapid Test Technologies 
+All of our commercially available current products employ either in-licensed lateral flow technology or our own patented Dual Path Platform (DPP®) technology. Both lateral flow technology and DPP® allow the development of accurate, low cost, easy-to-perform, single-use diagnostic tests for rapid, visual detection of specific antigen-antibody complexes on a test strip. These formats provide a test that is simple (requires neither electricity nor expensive equipment for test execution or reading, nor skilled personnel for test interpretation), rapid (turnaround time approximately 15 minutes), safe (minimizes handling of potentially infected specimens), non-invasive (requires 5-20 micro liters of whole blood easily obtained with a finger prick, or alternatively, serum or plasma), stable (24 months at room temperature storage in the case of our HIV tests), and highly reproducible. 
+We believe that products developed using DPP® technology can provide superior diagnostic performance as compared with products that use lateral flow technology. The reason for this is that one of the major differences between the two platforms is that in DPP® samples are allowed to incubate with the target analyte in the test zone before introduction of the labeling reagent/conjugate, whereas in lateral flow, samples are combined with the labeling reagent to form a complex before coming in contact with the target analyte. We believe that this complex can compromise test performance. Also, because of the usage in DPP® of a separately connected sample strip, the control and delivery of sample material is substantially improved. This feature is critical in the development of multiplex tests, as well as tests that involve viscous sample material (such as oral fluid) that can be impeded when forced to combine with labeling reagents before migration on the test strip to the test zone area. 
+Multiplexing is significantly improved as a result of the design of DPP® and this provides a significant advantage. For example, the HIV confirmatory test we developed for Bio-Rad that is described above employs six different markers related to various epitopes of the HIV antigen. We have a number of other products in development, including those being developed in sponsored development programs that involve the use of multiple (e.g. eight) test bands. Although all of these products could be visually read, we can also use handheld and desktop readers with our DPP® products to objectively measure, quantify, record and report DPP® test results. Certain of the products we have and/or are developing incorporate some of these readers, and we are developing other products that may be used with or will require use of a reader. Also, platforms can incorporate labeling reagents that cannot be visually read except by employing a reader, such as fluorescence, though no products are currently utilizing such reagents. 
+We are pursuing additional capabilities and technologies that will complement our current product portfolio and business strategy. This activity includes pursing development, license or acquisition of diagnostic technologies that complement our existing platforms, proprietary biomarkers that can result in new product applications of our existing platforms, and new platforms that would complement our commercial strategy. 
+6 
+Target Markets 
+Rapid HIV Tests 
+A large percentage of individuals that are HIV positive worldwide are unaware of their status. Part of the reason for this is that even those that do get tested in public health settings will often not return or call back for their test results when samples have to be sent out to a laboratory which can take up to several days to process. The increased availability, greater efficacy and reduced costs for anti-retroviral treatments (ARVs) for HIV has increased the demand for testing, as the stigma associated with the disease is lessened, and the ability to resume normal activities is substantially improved, providing a positive message to those potentially infected. The impact that rapid HIV testing has had on prevention efforts has in turn increased the demand for testing, particularly by public health programs worldwide, which have also become more effective in reducing the number of annual new infections in many, but by no means all, high prevalence regions. 
+Despite less attention to HIV by the media as compared with prior years, there are still approximately 50,000 new diagnoses of HIV infection in the United States each year, according to the CDC. CDC estimates that approximately 1.1 million individuals in the U.S. are living with HIV, with an estimated 1 of 8 of these U.S. individuals, or almost 13%, unaware that they are infected. It is transmissions from these infected people that are reported to account for the majority of all new infections per year. Part of the reason for this is that even those individuals that do get tested in public health settings will often not return or call back for their test results if their blood samples have to be sent out to and tested in a laboratory and then reported back, a process which can take up to several days to complete. Making more people aware of their HIV status at the point-of-care reduces the number of HIV transmissions. 
+Rapid HIV testing in the United States has now developed into an estimated 7.5 million test market at an average price of $10, or a total of $75 million. Public health programs, currently funded by grants distributed to states by the CDC, account for an estimated 45% of the market, with hospitals (40%) and doctor ' s offices (15%) comprising the other estimated market segments. Chembio ' s rapid HIV tests represent approximately a 20% share of this market. OraSure Technologies, Inc., which was the first FDA-approved rapid HIV test, maintains approximately 50% of this market. Trinity Biotech has an estimated 15% market share and Alere, Biolytical Laboratories, Medmira and Bio-Rad share the remaining 10%. 
+In 2006, the outlook for HIV testing was given a big boost with the release by the CDC of new recommendations for HIV testing. These new CDC recommendations were/are that an HIV test should be given as a routine test like any other for all patients between 13 and 64 years of age, regardless of risk, with an opt-out screening option and focused testing procedural (pre- and post-test counseling) guidelines. Though not mandatory, gradual adoption in whole or in part of the 2006 CDC recommendations by a number of states continues to have an increasing impact. Finally, in 2013, the United States Preventive Services Task Force ( " USPSTF " ) fully embraced these CDC routine HIV testing recommendations. This USPSTF recommendation, which was given an A grade under their recommendation grading system based on the benefits of this practice and the nearly 600,000 AIDS-related deaths in the United States, requires insurance coverage under the Affordable Care Act (the " ACA " ) as a preventive screening test without any co-payment required. We expect this to result in an increase in HIV testing in the United States in the coming years, which we believe will include point-of-care HIV testing utilizing the Company ' s products. Although as stated above, currently most public health testing in the United States is funded by grants allocated to high prevalence areas by the CDC, we believe this will shift to an insurance-funded model under the ACA in the years to come, increasing the amount of testing done in doctor ' s offices and community health centers. 
+In the international market, we sell our products directly and through distributors to large screening programs overseen by ministries of health and NGOs, most but not all of which are funded by large bi-lateral and multi-lateral AIDS relief programs, the largest of which is the U.S. President ' s Emergency Plan for AIDS Relief (PEPFAR). Established by President George Bush as a 5-year $15 billion program in 2003, PEPFAR was reauthorized in 2008 and again in 2013. In 2012 PEPFAR directly supported HIV testing and counseling for more than 11 million pregnant women, and testing and counseling for more than 49 million people overall. The U.S. is also the first and largest donor to the Global Fund to Fight AIDS, Tuberculosis and Malaria. To date, the U.S. has provided more than $7 billion to the Fund. 
+In December 2013 President Obama signed into law the PEPFAR Stewardship and Oversight Act, which is the most recent reauthorization of PEPFAR. However, unlike the 2008 PEPFAR authorization, which authorized approximately $45 billion, the new law doesn ' t authorize a specific dollar amount for funding. Nevertheless it is widely anticipated that PEPFAR will continue to enjoy strong funding; the FY14 budget had $6 billion for global HIV/AIDS assistance, including $4 billion for PEPFAR. 
+Chembio, with its four U.S.-manufactured rapid HIV tests, all of which are FDA-approved, is recognized as a reputable and dependable supplier of high quality products that are available at reasonably competitive prices. As a result, certain of our products have been selected in the testing protocols in countries (national algorithms) that are large beneficiaries of PEPFAR and the Global Fund. As mentioned above, these programs can and do often result in large orders, but also can result in periods of relatively lower demand, based on the variations associated with this kind of demand. Also, even though the United States taxpayer is funding the largest share of global AIDS relief, U.S. companies do not receive any preference for these procurements, and therefore must compete with foreign suppliers that manufacture competitive products with lower costs, including those related to quality, regulatory, intellectual property, and costs of manufacturing. 
+Oral fluid testing is an established alternative to blood testing for diagnostic tests, including HIV tests. It is also often patient preferred, providing a more comfortable, less invasive test. In certain public health clinics, staffs choose not to handle blood specimens; thus, oral sample collection provides a viable alternative. The most well-established market for oral fluid HIV testing is the United States. Given the premium price required for an oral fluid test as compared with blood tests, the higher volume programs will not specify an oral fluid test. However, segments of these programs may want to have an oral fluid testing option, and certain programs that have greater resources may also choose to incorporate oral fluid testing into the testing protocol. 
+There is also now an over-the-counter market for HIV self-testing in the United States. OraSure Technologies Inc. received FDA approval for an over-the-counter (self-testing) version of its previously professional-market-approved (test performed on an individual by a health care professional) HIV test. The FDA approval was granted in July 2012, and OraSure has been investing heavily in developing this market. Initial results after over two years of marketing are well below expectations. The costs for such over-the-counter approval, including primarily the associated clinical trials, are estimated to be at least $5 million and they may take two to three years to complete, not to mention the cost of distribution. OraSure ' s initial results are not convincing of a large market, although this possibility remains. If it appears that there is an attractive market, we believe we are very well positioned to participate in this market. 
+Rapid HIV-Syphilis Test 
+There are significant risks relating to transmission of Syphilis from a pregnant mother to child, just as there are for transmission of HIV. Therefore we believe there is a significant opportunity to improve prevention efforts in pregnant mother to child transmission testing programs (PMTCT) that are currently not doing any or nearly enough testing for syphilis even though they are testing for HIV. In the United States, we believe there is also a significant need for this product in some of the highest HIV prevalence populations, such as among men that have sex with men (MSM), as data show high degrees of HIV and Syphilis co-infection in this segment of the population. 
+7 
+Marketing Strategy 
+Our marketing strategy is to: 
+· 
+Market our DPP® HIV 1/2 Assay, HIV 1/2 STAT-PAK® Assay and future DPP® based new products in the US through our internal sales and marketing organization and selected channel partners (e.g., McKesson/PSS, Fisher Healthcare, Henry Schein, etc.). Chembio, following the June 2014 termination of the STAT-PAK® agreement with Alere, does not have to share any portion of the net sales proceeds for STAT-PAK® with Alere. This decision resulted in incurring expenditures related to hiring sales representatives, establishing agreements and associated discounts with distributors, incurring advertising and marketing expenditures, warehousing, customer service and technical support. If Alere's new competitive product is indeed successful, our ability to retain a significant share of the market that has been established for our products may be enhanced by our having control of the marketing of our products, rather than relying on Alere to sell both our products while it is also selling its own competing product. We are leveraging the same sales force for U.S. Sales of DPP® HIV 1/2 Assay. 
+· 
+We will support, review and assess the marketing and distribution efforts of our rapid HIV barrel test in the U.S. 
+· 
+Outside the U.S., we will market our products primarily through commercial collaborators and distribution partners. 
+· 
+Leverage our DPP® intellectual property and product development and manufacturing experience to continue creating new collaborations where Chembio can be the exclusive development and manufacturing partner supporting leading marketing organizations. 
+· 
+Establish strong distribution relationships for our Chembio-branded products in the U.S and abroad, and establish a direct sales and marketing organization that is focused in the public health market segment, and that utilizes distributors for other market segments, primarily the acute care market which, together with public health, are the main market segments for rapid HIV tests in the United States. We believe that creation of a Chembio public health brand and marketing organization is fundamental to the creation of shareholder value over the long-term. 
+We have increased our commercial activities and efforts in Africa, Europe and Asia for our HIV tests and product pipeline. We believe these efforts will enable us to be more closely engaged with opportunities to engage with customers and partners and to participate in the national testing algorithms that are established and revised from time to time by countries that are beneficiaries of PEPFAR, Global Fund and/or other bilateral or multilateral donor funding. In Europe, where there are a larger percentage of HIV positive people unaware of their status than in the United States, we believe that there is an emerging public health outreach opportunity, and there are relatively few strong competitors that are CE-marked. Most recently we have established new sales and marketing positions in the Company to support our efforts to increase brand awareness globally and to lead our direct sales effort in the U.S. market. 
+Competition 
+The diagnostics industry is a multi-billion dollar international industry and is intensely competitive. Many of our competitors are substantially larger and have greater financial, research, manufacturing and marketing resources. Industry competition in general is based on the following: 
+· 
+Scientific and technological capability; 
+· 
+Proprietary know-how; 
+· 
+The ability to develop and market products and processes; 
+· 
+The ability to obtain FDA or other required regulatory approvals; 
+· 
+The ability to manufacture products that meet applicable FDA requirements, (i.e. FDA ' s Quality System Regulations) (see Governmental Regulation section); 
+· 
+The ability to manufacture products cost-effectively; 
+· 
+Access to adequate capital; 
+· 
+The ability to attract and retain qualified personnel; and 
+· 
+The availability of patent protection. 
+We believe our scientific and technological capabilities and our proprietary know-how relating to our in-licensed lateral flow technology rapid tests and to our proprietary know-how related to our patented DPP® technology, particularly for the development and manufacture of tests for the detection of antibodies to infectious diseases such as HIV, are very strong. 
+Our ability to develop and market other products is in large measure dependent on our having additional resources and/or collaborative relationships. Some of our product development efforts have been funded on a project or milestone basis. We believe that our proprietary know-how in lateral flow technology and in our DPP® technology has been instrumental in our obtaining the collaborations we have and that we continue to pursue. We believe that the patent protection that we have with our DPP® technology enhances our ability to develop more profitable collaborative relationships and to license out the technology. However there are a number of competitive technologies used and/or seeking to be used in point-of-care settings. These technologies may be based on immunoassay principles such as the Company ' s products or other technologies, such as molecular-based technologies. 
+We launched our FDA-approved DPP® HIV 1/2 Assay, which test also can be used with either oral fluid or blood samples, in the U.S. market under a Chembio brand in the fourth quarter of 2014. OraSure Technologies manufactures the only other rapid, oral fluid HIV test that is FDA-approved, and OraSure has enjoyed this position for approximately 10 years. OraSure has lost a significant share of this market as certain customers have been indifferent to using blood or oral fluid samples, because the blood tests, including those made/marketed by Chembio and marketed by Alere, are priced lower and/or are as or more accurate than the performance of OraSure ' s product on blood samples. OraSure has primarily retained those customers for whom the oral fluid sample feature is a strong preference, and this is an estimated $35 million business for OraSure. Although we believe we can capture a meaningful portion of this OraSure market share, we also anticipate that OraSure will defend this business aggressively. 
+8 
+In 2006 Alere acquired a division from Abbott Diagnostic located in Japan that manufactured and marketed a rapid HIV test product line called Determine®. The Determine® format was developed for the developing world and remote settings and, central to the needs of that market, the format is essentially a test strip that is integrated into a thin foil wrapper that, when opened, the underside of the wrapper serves as the test surface for applying the blood sample and performing the test. This design reduces costs and shipping weights and volumes and is an advantage for the developing world markets it has served. Some of the disadvantages of the platform are the amount of blood sample that is needed (50 microliters versus 2.5, 5 and 10 for our lateral flow barrel, lateral flow cassette, and DPP® products respectively), the open nature of the test surface, and the absence of a true control that differentiates biological from other kinds of samples. 
+The so-called " 3rd generation " version of this product has been marketed for many years and is the leading rapid HIV test that is used in a large majority of the national algorithms of countries funded by PEPFAR and the Global Fund, as well as many other countries in the world. That product is not FDA-approved though it is CE-marked. The newest Determine® HIV version, which was developed and manufactured at Alere ' s subsidiary in Israel, Orgenics, is the so-called " 4th Generation " version Determine® test. According to its claims, this product detects HIV antibodies and P24 HIV antigens. Since the P24 antigen is known to occur in HIV-positive individuals ' blood samples before antibodies do, based on its performance claims, the 4th generation Determine® test is therefore able to detect HIV infection earlier than tests that solely rely on antibody detection. Chembio ' s tests, as well as all of the other currently FDA-approved rapid HIV tests, only detect antibodies. There are however laboratory tests that are FDA-approved that are " 4th generation " tests, but they are of course neither rapid nor point-of-care. 
+The initial " 4th generation " Alere Determine® rapid test product that was also CE-marked and that Alere launched internationally some years ago has not been successfully commercialized to the best of our knowledge and at least certain published studies were not favorable for this product. However the 4th generation product that is now FDA-approved was apparently modified as compared to the initial international version of it, and it may perform more satisfactorily. Alere received FDA approval of this modified product in August 2013 and CLIA-waiver for it in the fourth quarter of 2014. There is support by a number of key opinion leaders for the public health value of such 4th generation tests, and it represents a significant competitive threat to Chembio as well as to each of the other rapid HIV test manufacturers (OraSure and Trinity primarily). 
+During 2011 Biolytical, Inc. of Vancouver, Canada received FDA approval and in 2012 received CLIA waiver of a flow-through rapid HIV test called " INSTI " . The technology used in the INSTI test, flow-through, is older than lateral flow, and it requires handling of multiple components (3 vials of solution) to perform the test in multiple steps. However, these steps can be accomplished in less than ten minutes, and the actual test results occur in only one minute after those steps are completed. Therefore sample-to-result time is shorter than any of the competitive products. There are settings where that reduced total test time, despite the multiple steps required, may be a distinct advantage, and we believe Biolytical has made some progress in penetrating certain public health markets. 
+Although we have no specific knowledge of any other competitors ' products that are a competitive threat to our products, or that will render our products obsolete, if we fail to maintain and enhance our competitive position or fail to introduce new products and product features, our customers may decide to use the products developed by our competitors, which could result in a loss of revenues and cash flow. 
+Research and Development 
+During 2015 and 2014, we spent $6.4 million and $4.8 million, respectively, on research and development (including regulatory activities). These expenses were in part underwritten by funding from R&D and milestones revenues of $2.3 million in 2015 and $1.7 million in 2014. All of our new product development activities involve employment of our DPP® technology. These activities include completing development of certain products and making significant progress toward the development of additional products. 
+Employees 
+At December 31, 2015, we employed approximately155 people. We have entered into employment contracts with our Chief Executive Officer and President, John J. Sperzel, our Chief Operating Officer, Sharon Klugewicz, and our Chief Science and Technology Officer, Javan Esfandiari. Due to the specific knowledge and experience of these executives regarding the industry, technology and market, the loss of the services of any one of them would likely have a material adverse effect on the Company. The contract with Ms. Klugewicz, has a term of two years ending May 2017. The contract with Mr. Esfandiari has a term of three years ending March 2016. The Company and Mr. Esfandiari currently are discussing terms for renewal of his employment agreement. We have obtained a key man insurance policy for Mr. Esfandiari. The contract with Mr. Sperzel provides that Mr. Sperzel will serve as the Chief Executive Officer and President of the Company through March 2017. 
+Governmental Regulation 
+The manufacturing and marketing of the Company ' s existing and proposed diagnostic products are regulated by the United States Food and Drug Administration ( " FDA " ), United States Department of Agriculture ( " USDA " ), certain state and local agencies, and/or comparable regulatory bodies in other countries. These regulations govern almost all aspects of development, production and marketing, including product testing, authorizations to market, labeling, promotion, manufacturing and record keeping. The Company ' s FDA and USDA regulated products require some form of action by each agency before they can be marketed in the United States, and, after approval or clearance, the Company must continue to comply with other FDA requirements applicable to marketed products, e.g. Quality Systems (for medical devices). Failure to comply with the FDA ' s requirements can lead to significant penalties, both before and after approval or clearance. 
+There are two review procedures by which medical devices can receive FDA clearance or approval. Some products may qualify for clearance under Section 510(k) of the Federal Food, Drug and Cosmetic Act, in which the manufacturer provides a pre-market notification that it intends to begin marketing the product, and shows that the product is substantially equivalent to another legally marketed product (i.e., that it has the same intended use and is as safe and effective as a legally marketed device and does not raise different questions of safety and effectiveness). In some cases, the submission must include data from human clinical studies. Marketing may commence when the FDA issues a clearance letter finding such substantial equivalence. FDA clearance of our DPP® Syphilis Screen & Confirm test will be by means of a 510(k) submission. 
+If the medical device does not qualify for the 510(k) procedure (either because it is not substantially equivalent to a legally marketed device or because it is required by statute and the FDA ' s implementing regulations have an approved application), the FDA must approve a Pre-Marketing Application ( " PMA " ) before marketing can begin. PMA ' s must demonstrate, among other matters, that the medical device provides a reasonable assurance of safety and effectiveness. A PMA application is typically a complex submission, including the results of non-clinical and clinical studies. Preparing a PMA application is a much more expensive, detailed and time-consuming process as compared with a 510(K) pre-market notification. The Company has approved PMAs for the two rapid HIV tests now marketed in the U.S.: both our HIV 1/2 STAT-PAK® and also our test that currently is marketed in the U.S. by Alere Medical as Clearview® Complete HIV 1/2 and Clearview® HIV 1/2 STAT PAK®. 
+FDA approval of our DPP® HIV screening assay for use with oral fluid or blood samples also was achieved by means of a PMA application. The Clinical Laboratory Improvement Act of 1988 ( " CLIA " ) prohibits laboratories from performing in-vitro tests for the purpose of providing information for the diagnosis, prevention or treatment of any disease or impairment of, or the assessment of, the health of human beings unless there is in effect for such laboratories a certificate issued by the United States Department of Health and Human Services (via the FDA) applicable to the category of examination or procedure performed. Although a certificate is not required for the Company, it considers the applicability of the requirements of CLIA in the design and development of its products. The statutory definition of " laboratory " is very broad, and many of our customers are considered labs. A CLIA waiver will remove certain quality control and other requirements that must be met for certain customers to use the Company ' s products and this is critical to the marketability of a product into the point-of-care diagnostics market. The Company has received a CLIA waiver for each of the two lateral flow rapid HIV tests now marketed in the U.S. The CLIA waiver was granted by the FDA for HIV 1/2 STAT-PAK® on November 20, 2006 and for the Clearview® Complete HIV 1/2 on October 22, 2007. In 2008 the FDA revised its CLIA waiver requirements so that an additional prospective trial need be conducted in order to demonstrate clinical utility by showing that the device is capable of identifying new infections when used by untrained users. Our DPP® HIV 1/2 test received CLIA waiver in October of 2014. 
+9 
+In addition, the FDA regulates the export of medical devices that have not been approved for marketing in the United States. The Federal Food, Drug and Cosmetic Act contains general requirements for any medical device that may not be sold in the United States and is intended for export. Specifically, a medical device intended for export is not deemed to be adulterated or misbranded if the product: (1) complies with the specifications of the foreign purchaser; (2) is not in conflict with the laws of the country to which it is intended for export; (3) is prominently labeled on the outside of the shipping package that it is intended for export; and (4) is not sold or offered for sale in the United States. However, the Federal Food, Drug and Cosmetic Act does permit the export of devices to any country in the world, if the device complies with the laws of the importing country and has valid marketing authorization in one of several " listed " countries under the theory that these listed countries have sophisticated mechanisms for the review of medical devices for safety and effectiveness. 
+The Company is also subject to regulations in foreign countries governing products, human clinical trials and marketing, and may need to obtain approval or evaluations by international public health agencies, such as the World Health Organization, in order to sell diagnostic products in certain countries. Approval processes vary from country to country, and the length of time required for approval or to obtain other clearances may in some cases be longer than that required for United States governmental approvals. On the other hand, the fact that our HIV diagnostic tests are of value in the AIDS epidemic may lead to some government process being expedited. The extent of potentially adverse governmental regulation affecting Chembio that might arise from future legislative or administrative action cannot be predicted. 
+Environmental Laws 
+To date, we have not encountered any costs relating to compliance with any environmental laws. 
+Intellectual Property 
+Intellectual Property Strategy 
+Our intellectual property strategy is to: (1) build our own intellectual property portfolio around our DPP® technology; (2) pursue licenses, trade secrets and know-how within the area of rapid point-of-care testing, and (3) develop and acquire proprietary positions to reagents and new hardware platforms for the development and manufacture of rapid diagnostic tests. 
+The Company has obtained patent coverage on the DPP® technology, including four U.S. patents, and patents in China, Malaysia, Eurasia, Mexico, Singapore, Japan, Australia, Indonesia, Korea and the U.K. Additional patent applications on the DPP® technology are pending in the U.S., as well as in many foreign countries such as Brazil, Canada, the European Union, India, Israel, and South Africa. Patents have also been filed on extensions to the DPP® product line concept, such as 4th generation assays. The four U.S. patents are as follows: 
+U.S. Patent No. 
+Issued 
+Expires 
+Nature 
+Type 
+Description 
+7,189,522 
+3/13/2007 
+3/11/2025 
+test device 
+utility 
+a test device for determining the presence of a ligand in a sample 
+7,682,801 
+3/23/2010 
+3/11/2025 
+test device 
+and method 
+utility 
+a test device and a method for determining 
+the presence of a ligand in a sample 
+7,879,597 
+2/1/2011 
+3/11/2025 
+test device 
+utility 
+a test device for determining multiple 
+ligands in a sample 
+8,507,259 
+8/13/2013 
+3/11/2025 
+test device 
+utility 
+a test device for determining the 
+presence of a ligand in a sample 
+The Company has also filed for patents and obtained some patents in the U.S. for other inventions, such as its multiple host species veterinary TB test, and patent applications for the other inventions are in various stages from being recently filed and not yet examined, to already examined and allowed but not yet issued. The Company selectively and strategically foreign files its patent applications based on a number of economic and strategic factors related to the invention. 
+Trademarks 
+The Company has filed and obtained trademarks for its products, including DPP®, SURE CHECK® and STAT-PAK®, and also for the SampleTainer® used in certain DPP® products. The DPP® trademark is also registered under the European convention (ECT). The Company recently filed a trademark for STAT-VIEW®, to market the barrel product in Europe. 
+Trade Secrets and Know-How 
+We believe that we have developed a substantial body of trade secrets and know-how relating to the development and manufacture of lateral flow and DPP®-based diagnostic tests, including but not limited to the sourcing and optimization of materials for such tests, and how to maximize sensitivity, speed-to-result, specificity, stability and reproducibility. The Company possesses proprietary know-how to develop tests for multiple conditions using colored latex. Our buffer formulations enable extremely long shelf lives of our rapid HIV and other tests and we believe that this provides us with an important competitive advantage. 
+Lateral Flow Technology and Reagent Licenses 
+As part of the agreements executed in 2006 with Alere for the marketing of our HIV tests, we were granted non-exclusive licenses to certain lateral flow patents for certain products manufactured and marketed by Chembio including but not limited to our lateral flow HIV tests. This license allows us to produce, market and sell assays using lateral flow technologies specifically including our STAT-PAK®, SURE CHECK®, DIPSTICK®, and veterinary product lines. Under this license agreement, prior to February 3, 2015, we paid royalties to Alere ranging from 5% to 8½%, depending upon the country in which the products are sold. Even though the relevant patent has expired in most other jurisdictions, or were never issued in markets where we have sold these products, our manufacture of the products in the United States has required that we pay royalties under this license, which has been a substantial expense. In 2015 our lateral flow royalty expense to Alere was $30,000, and since 2007 we have incurred a total of $2.87 million in lateral flow royalty expenses. As of February 3, 2015 this royalty expense was no longer payable as the applicable patent expired at that time. 
+Although we believe our DPP® is outside of the scope of all lateral flow patents of which we are aware, we consult with patent counsel, and seek licenses and/or redesigns of products that we believe to be in the best interests of the Company and our stockholders. Because of the costs and other negative consequences of time-consuming patent litigation, we often attempt to obtain a license on reasonable terms. Nevertheless there is no assurance that the Alere lateral flow patents we have licensed will not be challenged or that other patents containing claims relevant to the Company's lateral flow or DPP® products will not be granted to third parties and that licenses to such patents, will be available on reasonable terms, if any. In the past Alere has aggressively enforced its lateral flow intellectual property, although some of the main patents have expired and we are not aware of any patent enforcement litigation that is ongoing with respect to the Alere lateral flow intellectual property. 
+Regardless, the DPP® technology provides us with our own intellectual property. We believe it provides us with a freedom to operate, and that it also enables tests to be developed with improved sensitivity as compared with comparable tests on lateral flow platforms. The Company has signed and anticipates signing new development projects based upon the DPP® technology that will provide new manufacturing and marketing opportunities. We have filed other patent applications that we believe will strengthen the DPP® intellectual property and have also filed for patent protection for certain other point-of-care technologies or applications thereof. 
+The peptides used in our rapid HIV tests were patented by Adaltis Inc. and were licensed to us under a 10-year non-exclusive license agreement dated August 30, 2002. However, in connection with Adaltis' bankruptcy, during the third quarter of 2009 we bought out all of our remaining obligations under that agreement. We also have licensed the antigens used in other tests including our Syphilis, Tuberculosis, Leptospirosis, Leishmaniasis and Chagas tests, and we may enter other license agreements. In prior years we concluded license agreements related to intellectual property rights owned by the United States associated with HIV- 1, and during the first quarter of 2008 we entered into a sub-license agreement for HIV-2 with Bio-Rad Laboratories N.A., the exclusive licensee of the Pasteur Institute's HIV-2 intellectual property estate. 
+10 
+Corporate History 
+On May 5, 2004, we completed a merger with Trading Solutions, Inc. through which Chembio Diagnostic Systems Inc. became our wholly-owned subsidiary, and through which the management and business of Chembio Diagnostic Systems Inc. became our management and business. As part of this transaction, we changed our name to Chembio Diagnostics, Inc. In 2003, we had sold our prior business, and as a result, we had no specific business immediately prior to the merger. 
+Since the formation of Chembio Diagnostic Systems Inc. in 1985, it has been involved in developing, manufacturing, selling and distributing in-vitro diagnostic tests, including rapid tests beginning in 1995, for a number of conditions in humans and animals. 
+On March 12, 2004, we implemented a 1-for-17 reverse split of our common stock. All references herein to shares of our common stock have been adjusted to reflect this reverse split. 
+On May 30, 2012, the Company effected a 1-for-8 reverse split of its common stock. This was done to allow the Company to move to the NASDAQ trading market from the OTCQB market, which occurred on June 7, 2012. As a result of the stock split, the outstanding 63,967,263 common shares were reduced to 7,995,918 outstanding common shares on May 30, 2012. The effect of this reverse stock split also has been retroactively reflected for all periods in these financial statements. 
+Stockholder Rights Agreement 
+On March 8, 2016, the Company entered into a Rights Agreement (the "Rights Agreement") between the Company and Action Stock Transfer Corp., as Rights Agent. Pursuant to the Rights Agreement, the Company declared a dividend distribution of one Preferred Share Purchase Right (a "Right") for each outstanding share of common stock, par value $0.01 (the "Common Stock"), of the Company, in the manner described below. The Board of Directors set the payment date for the distribution of the Rights as March 8, 2016, and the Rights were distributed to the Company's shareholders of record on that date. The description and terms of the Rights are set forth in the Rights Agreement. 
+Rights Initially Not Exercisable. The Rights are not exercisable until a Distribution Date. Until a Right is exercised, the holder thereof, as such, has no rights as a shareholder of the Company, including, without limitation, the right to vote or to receive dividends. 
+Separation and Distribution of Rights . The Rights are to be evidenced by the certificates for shares of Common Stock registered in the names of the holders thereof, and not by separate rights certificates until the earlier to occur of (i) the close of business on the tenth business day following a public announcement that an Acquiring Person (as defined in the Rights Agreement) has acquired a Combined Ownership (as defined in the Rights Agreement) of 20% or more of the outstanding shares of the Common Stock (the "Shares Acquisition Date") or (ii) the later of (A) the close of business on the tenth business day (or such later date as may be determined by action of the Board of Directors prior to such time as any person or group of affiliated or associated persons becomes an Acquiring Person) after the date that a tender or exchange offer or intention to commence a tender or exchange offer by any person is first published, announced, sent or given within the meaning of Rule 14d-4(A) under the Securities Exchange Act of 1934, as amended, the consummation of which would result in any person having Combined Ownership of 20% or more of the outstanding shares of the Common Stock, or (B) if such a tender or exchange offer has been published, announced, sent or given before the date of the Rights Agreement, then the close of business on the tenth business day after the date the Rights Agreement was entered into (or such later date as may be determined by action of the Board of Directors prior to such time as any person becomes an Acquiring Person); (the earlier of such dates referred to in (i) and (ii), which date may include any such date that is after the date of the Rights Agreement but prior to the issuance of the Rights, being called the "Distribution Date"). 
+Glossary 
+AIDS 
+Acquired Immunodeficiency Syndrome. AIDS is caused by the Human Immunodeficiency Virus, HIV. 
+ALGORITHM (parallel or serial) 
+For rapid HIV testing this refers both to method or protocol (in developing countries to date) for using rapid tests from different manufacturers in combination to screen and confirm patients at the point-of-care, and may also refer to the specific tests that have been selected by an agency or ministry of health to be used in this way. A parallel algorithm uses two screening tests from different manufacturers and a tie-breaker test only if there is a discrepancy between the screening tests results. A serial algorithm only uses a second confirmatory test if there is a positive result from the screening test, meaning that the number of confirmatory tests used is equal to the positivity rate in the testing venue. A tie-breaker test resolves discrepancies between the screen and the confirmatory test. 
+ANTIBODY 
+A protein which is a natural part of the human immune system produced by specialized cells to neutralize antigens, including viruses and bacteria that invade the body. Each antibody producing cell manufactures a unique antibody that is directed against, binds to and eliminates one, and only one, specific type of antigen. 
+ANTIGEN 
+Any substance which, upon entering the body, stimulates the immune system leading to the formation of antibodies. Among the more common antigens are bacteria, pollens, toxins, and viruses. 
+ANVISA 
+The National Health Surveillance Agency of Brazil 
+ARVs 
+Anti-retroviral medications developed to fight AIDS 
+CDC 
+United States Centers for Disease Control and Prevention 
+CLIA waiver 
+Clinical Laboratory Improvement Act designation that allows simple tests to be performed in point-of-care settings such as doctor's offices, walk-in clinics and emergency rooms. 
+DIAGNOSTIC 
+Pertaining to the determination of the nature or cause of a disease or condition. Also refers to reagents or procedures used in diagnosis to measure proteins in a clinical sample. 
+FIOCRUZ 
+The Oswaldo Cruz Foundation of Brazil 
+FDA 
+United States Food and Drug Administration 
+IgG 
+IgG or Immunoglobulin are proteins found in human blood. This protein is called an "antibody" and is an important part of the body's defense against disease. When the body is attacked by harmful bacteria or viruses, antibodies help fight these invaders. 
+NGO 
+Non-Governmental Organization 
+OTC 
+Over-the-Counter 
+PEPFAR 
+The President's Emergency Plan for AIDS Relief 
+PMA 
+Pre-Marketing Approval –FDA approval classification for a medical device that is not substantially equivalent to a legally marketed device or is otherwise required by statute to have an approved application. Rapid HIV tests must have an approved PMA application before marketing of such a product can begin. 
+PROTOCOL 
+A procedure pursuant to which an immunodiagnostic test is performed on a particular specimen in order to obtain the desired reaction. 
+REAGENT 
+A chemical added to a sample under investigation in order to cause a chemical or biological reaction which will enable measurement or identification of a target substance. 
+RETROVIRAL 
+A type of virus which contains the enzyme Reverse Transcriptase and is capable of transforming infected cells to produce diseases in the host such as AIDS. 
+SENSITIVITY 
+Refers to the ability of an assay to detect and measure small quantities of a substance of interest. The greater the sensitivity, the smaller the quantity of the substance of interest the assay can detect. Also refers to the likelihood of detecting the antigen when present. 
+SPECIFICITY 
+The ability of an assay to distinguish between similar materials. The greater the specificity, the better an assay is at identifying a substance in the presence of substances of similar makeup. 
+USDA 
+U.S Department of Agriculture 
+WHO 
+World Health Organization 
+11
\ No newline at end of file
diff --git a/raw/filings/0001092662/2015/0001092662-16-000121/item13.txt b/raw/filings/0001092662/2015/0001092662-16-000121/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..4db4733105a4ba14fe77e9ff2688b67447fa74c3
--- /dev/null
+++ b/raw/filings/0001092662/2015/0001092662-16-000121/item13.txt
@@ -0,0 +1,6 @@
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE. 
+The executive officers of the Company are as follows: John J. Sperzel, president, chief executive officer and member of the board of directors of the Company, Sharon Klugewicz, chief operating officer, Richard J. Larkin, chief financial officer of the Company, and Javan Esfandiari, chief science and technology officer of the Company. 
+The Company entered into an employment agreement effective March 5, 2013, with Mr. Esfandiari to continue as the Company's Chief Scientific and Technology Officer for an additional term of three years through March 5, 2016. The Company also entered into an employment agreement effective May 22, 2015, with Ms. Klugewicz to serve as Chief Operating Officer for a term of two years. On March 13, 2014, Mr. Siebert, the former Chief Executive Officer, retired from the Company and entered into a six-month Consulting Agreement with the Company. On March 13, 2014, the Company entered into an employment agreement (the "Employment Agreement") with John J. Sperzel III to serve as its Chief Executive Officer beginning on March 13, 2014 for a term of three years. See Item 11 for additional information. 
+Director Independence 
+Our common stock trades on the NASDAQ. Accordingly, we are subject to the corporate the governance standards of NASDAQ, which require, among other things, that the majority of the board of directors be independent. We define an "independent" director in accordance with the NASDAQ Global Market's requirements for independent directors. Under this definition, we have determined that each of Katherine Davis, Barbara DeBuono, Peter Kissinger, and Gary Meller currently qualify as independent directors. We do not list this "independent" definition on our internet website.
\ No newline at end of file
diff --git a/raw/filings/0001092662/2015/0001092662-16-000121/item9a.txt b/raw/filings/0001092662/2015/0001092662-16-000121/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..b49b3a85fb45ddc5b4feda725dea5c37ec3dad28
--- /dev/null
+++ b/raw/filings/0001092662/2015/0001092662-16-000121/item9a.txt
@@ -0,0 +1,15 @@
+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+(a) Disclosure Controls and Procedures. Under the supervision and with the participation of our senior management, consisting of our chief executive officer and our chief financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), as of the end of the period covered by this report (the "Evaluation Date"). Based on that evaluation, the Company's management, including our chief executive officer and chief financial officer, concluded that as of the Evaluation Date our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports that we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. Our disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in our Exchange Act reports is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure. 
+Management's Annual Report on Internal Control Over Financial Reporting. The Company's management is responsible for establishing and maintaining an adequate system of internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f)). Our internal control over financial reporting is a process, under the supervision of our chief executive officer and chief financial officer, designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States. These internal controls over financial reporting processes include policies and procedures that: 
+a. 
+Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company; 
+b. 
+Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and 
+c. 
+Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance of achieving their control objectives. 
+In evaluating the effectiveness of our internal control over financial reporting, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework 2013. Based on this evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective as of December 31, 2015. 
+This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. 
+Management's report was not subject to attestation by our registered public accounting firm pursuant to the rules of the Securities and Exchange Commission that permit the Company to provide only management's report in this annual report. 
+(b) Changes in Internal Control over Financial Reporting. There were no changes in our internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Rule 13a-15 or Rule 15d-15 under the Exchange Act that occurred during the Company's last fiscal quarter of the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
\ No newline at end of file
diff --git a/raw/filings/0001092662/2015/0001092662-16-000121/rp_note.txt b/raw/filings/0001092662/2015/0001092662-16-000121/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0001092662/2015/0001092662-16-000121/rpt_disclosure.txt b/raw/filings/0001092662/2015/0001092662-16-000121/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..4db4733105a4ba14fe77e9ff2688b67447fa74c3
--- /dev/null
+++ b/raw/filings/0001092662/2015/0001092662-16-000121/rpt_disclosure.txt
@@ -0,0 +1,6 @@
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE. 
+The executive officers of the Company are as follows: John J. Sperzel, president, chief executive officer and member of the board of directors of the Company, Sharon Klugewicz, chief operating officer, Richard J. Larkin, chief financial officer of the Company, and Javan Esfandiari, chief science and technology officer of the Company. 
+The Company entered into an employment agreement effective March 5, 2013, with Mr. Esfandiari to continue as the Company's Chief Scientific and Technology Officer for an additional term of three years through March 5, 2016. The Company also entered into an employment agreement effective May 22, 2015, with Ms. Klugewicz to serve as Chief Operating Officer for a term of two years. On March 13, 2014, Mr. Siebert, the former Chief Executive Officer, retired from the Company and entered into a six-month Consulting Agreement with the Company. On March 13, 2014, the Company entered into an employment agreement (the "Employment Agreement") with John J. Sperzel III to serve as its Chief Executive Officer beginning on March 13, 2014 for a term of three years. See Item 11 for additional information. 
+Director Independence 
+Our common stock trades on the NASDAQ. Accordingly, we are subject to the corporate the governance standards of NASDAQ, which require, among other things, that the majority of the board of directors be independent. We define an "independent" director in accordance with the NASDAQ Global Market's requirements for independent directors. Under this definition, we have determined that each of Katherine Davis, Barbara DeBuono, Peter Kissinger, and Gary Meller currently qualify as independent directors. We do not list this "independent" definition on our internet website.
\ No newline at end of file
diff --git a/raw/filings/0001092662/2016/0001092662-17-000023/filing.txt b/raw/filings/0001092662/2016/0001092662-17-000023/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..1ea6b7c4721496e2c0b3a10a5d075bc6f1dc952c
--- /dev/null
+++ b/raw/filings/0001092662/2016/0001092662-17-000023/filing.txt
@@ -0,0 +1,3470 @@
+10-K
+1
+form10_k.htm
+FORM 10-K FOR 2016
+UNITED STATES 
+Securities and Exchange Commission 
+Washington, D.C. 20549 
+FORM 10-K 
+[X] 
+ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the fiscal year ended December 31, 2016 
+or 
+[ ] 
+TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the transition period from _______ to ______ . 
+Commission File No. 0-30379 
+CHEMBIO DIAGNOSTICS, INC. 
+(Exact name of registrant as specified in its charter) 
+Nevada 
+88-0425691 
+(State or other jurisdiction of incorporation or organization) 
+(I.R.S. Employer Identification No.) 
+3661 Horseblock Road, Medford, NY 
+11763 
+(Address of principal executive offices) 
+(Zip Code) 
+Registrant's telephone number, including area code (631) 924-1135 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of each class 
+Name of each exchange on which registered 
+Common Stock, $0.01 par value 
+Preferred Share Purchase Rights 
+The NASDAQ Stock Market LLC 
+The NASDAQ Stock Market LLC 
+Securities registered pursuant to section 12(g) of the Act: 
+None 
+(Title of Class) 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes __ No X 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes __ No X 
+Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No__ 
+Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes X No __ 
+Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. 
+Large accelerated filer [ ] 
+Accelerated filer [X ] 
+Non-accelerated filer [ ] 
+Smaller reporting company [] 
+(Do not check if a smaller reporting company) 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes __ No _X_ 
+As of the last business day of the Company's most recently completed second fiscal quarter, the aggregate market value of voting and non-voting common equity held by non-affiliates* was 76,422,282. 
+As of March 3, 2017, the registrant had 12,299,122 common shares outstanding. 
+* Without asserting that any of the issuer's directors or executive officers, or the entities that own more than five percent of the outstanding shares of the Registrant's common stock, are affiliates, the shares of which they are beneficial owners have not been included in shares held by non-affiliates solely for this calculation. 
+TABLE OF CONTENTS 
+Page 
+PART I 
+ITEM 1. 
+BUSINESS 
+2 
+ITEM 1A. 
+RISK FACTORS 
+18 
+ITEM 1B. 
+UNRESOLVED STAFF COMMENTS 
+25 
+ITEM 2. 
+PROPERTIES 
+25 
+ITEM 3. 
+LEGAL PROCEEDINGS 
+25 
+ITEM 4 . 
+MINE SAFETY DISCLOSURES 
+25 
+PART II 
+ITEM 5. 
+MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+26 
+ITEM 6. 
+SELECTED FINANCIAL DATA 
+27 
+ITEM 7. 
+MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+28 
+ITEM 7A. 
+QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 
+44 
+ITEM 8. 
+FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+44 
+ITEM 9. 
+CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. 
+44 
+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+44 
+ITEM 9B. 
+OTHER INFORMATION 
+47 
+PART III 
+ITEM 10. 
+DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
+48 
+ITEM 11. 
+EXECUTIVE COMPENSATION 
+48 
+ITEM 12. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+48 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+48 
+ITEM 14. 
+PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+48 
+PART IV 
+ITEM 15. 
+EXHIBITS, FINANCIAL STATEMENT SCHEDULES 
+49 
+ITEM 16. 
+FORM 10-K SUMMARY 
+50 
+SIGNATURES 
+51 
+PART I 
+ITEM 1. 
+BUSINESS 
+FORWARD-LOOKING STATEMENTS 
+This report contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, and Section 27A of the Securities Act of 1933. Any statements contained in this report that are not statements of historical fact may be forward-looking statements. When we use the words "intends," "estimates," "predicts," "potential," "continues," "anticipates," "plans," "expects," "believes," "should," "could," "may," "will" or the negative of these terms or other comparable terminology, we are identifying forward-looking statements. Forward-looking statements involve risks and uncertainties, which may cause our actual results, performance or achievements to be materially different from those expressed or implied by forward-looking statements. These factors include our research and development activities, distributor channels, market demand for our products, compliance with regulatory impositions; and our capital needs. Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance or achievements. 
+Except as may be required by applicable law, we do not undertake or intend to update or revise our forward-looking statements, and we assume no obligation to update any forward-looking statements contained in this report as a result of new information or future events or developments. Thus, you should not assume that our silence over time means that actual events are bearing out as expressed or implied in such forward-looking statements. You should carefully review and consider the various disclosures we make in this report and our other reports filed with the Securities and Exchange Commission that attempt to advise interested parties of the risks, uncertainties and other factors that may affect our business. 
+We provide free of charge on our website at www.chembio.com our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable. Members of the public may read and copy any materials we file with the SEC at the SEC's Public Reference Room at 100 F Street, NE, and Washington, DC 20549. Members of the public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800–SEC–0330. The Internet address of the Commission is www.sec.gov. That website contains reports, proxy and information statements and other information regarding issuers, like Chembio, that file electronically with the Commission. Visitors to the Commission's website may access such information by searching the EDGAR database. 
+For further information about these and other risks, uncertainties and factors, please review the disclosure included in this report under "Part I, Item 1A, Risk Factors." 
+Our Business 
+General 
+The Company (Chembio Diagnostics, Inc. and its wholly-owned subsidiary Chembio Diagnostic Systems, Inc. are collectively referred to herein as the "Company") develops, manufactures, markets and licenses rapid point-of-care diagnostic tests (POCTs) that detect infectious diseases. Our main products currently commercially available are rapid tests for the detection of HIV 1/2 antibodies, and a multiplex rapid test for the detection of HIV and syphilis antibodies. The HIV 1/2 rapid tests employ in-licensed and proprietary lateral flow technologies (see "Our Rapid Test Technologies"), can be used with all blood matrices as samples, and are manufactured in a standard cassette format, a dipstick format, and a proprietary barrel format. The tests employing the cassette and proprietary barrel formats were approved by the FDA in 2006. The barrel format is exclusively distributed by a distributor in the United States and by Chembio and its designated distributors outside the United States. The exclusive U.S. distribution agreement for the barrel product terminated in accordance with its terms on May 31, 2016. Since June 1, 2016, Chembio and its subsequently designated distributors have distributed the product in the U.S. The Cassette format is distributed by Chembio and its designated distributors worldwide. Our latest generation HIV 1/2 rapid antibody detection test incorporates our patented Dual Path Platform® (DPP®) POCT technology, and this POCT platform does not require in-licensing. The DPP® HIV 1/2 Assay detects antibodies to HIV 1 & 2 in oral fluid samples as well as in all blood matrices. [We have sold this product in Brazil since 2009 where it was approved by ANVISA, through our agreement with the Oswaldo Cruz Foundation ("FIOCRUZ"), and we received United States FDA regulatory approval for this product in December 2012 and CLIA waiver in October 2014.] We launched it in the United States under Chembio's brand in the fourth quarter of 2014. 
+2 
+Our product pipeline, which currently includes a multiplex rapid test for earlier detection of HIV by detecting P-24 antigen as well as antibodies, a test for Hepatitis-C, and a multiplex test that detects HIV and Syphilis specific antibodies (which we are already selling outside the U.S.), is based on this DPP® technology for which we were issued a United States patent in 2007 and for which additional patent protection has issued or is pending in a number of other countries. With our patented DPP® and the lateral flow platforms, we participate in the estimated $8 billion point-of-care (POC) market segment of the estimated nearly $50 billion global in-vitro diagnostic market that has an overall growth rate exceeding 3% per annum. POCTs, by providing prompt and early diagnosis, can reduce patient stays, lower overall costs, improve therapeutic interventions and improve patient outcomes. POCTs can also prevent needless hospital admissions, simplify testing procedures, avoid delays from central lab batching, and eliminate the need for return visits. 
+In the areas of infectious and sexually transmitted diseases (such as HIV and syphilis), the utility of a rapid POC test, particularly in identifying patients unaware of their disease status, has been well established. Large and growing markets have been established for these kinds of tests, initially in high prevalence regions where they are indispensable for large scale prevention and treatment programs. More recently introduced in the United States in 2004, rapid HIV tests now also present a significant segment of the U.S. market for HIV clinical testing, which is still dominated by laboratory tests. We have focused our product development activity within areas where the availability of rapid, POC screening, diagnostic, or confirmatory results can improve health outcomes. More generally we believe there is and will continue to be a growing demand for diagnostic products that can provide accurate, actionable diagnostic information in a rapid, cost-effective manner at the point of care. 
+Our Products 
+Lateral Flow Rapid HIV Tests 
+All three of our lateral flow rapid HIV antibody detection tests are qualitative "yes/no" tests for the detection of antibodies to HIV 1 & 2 with visually interpreted results (one line "negative"; one line "positive") available within approximately 15 minutes. The tests are simple to use, have a shelf life of 24 months, and do not require refrigeration. The tests differ principally only in the method of test procedure, convenience and cost. One of our FDA-approved lateral flow HIV tests, SURE CHECK® HIV 1/2 Assay, incorporates a proprietary plastic "barrel" device that houses the lateral flow strip. This barrel format enables collection of samples directly (usually from a finger-stick whole blood sample) into the barrel's capillary tip. A sealed unitized buffer vial, assembled onto the top of the barrel, is removed and seated into a stand; the seal is then pierced by the barrel's capillary tip, thereby initiating the upward flow of the resulting sample-buffer solution through a filter, up into the vertical device's chamber and onto the lateral flow strip. This results in a unique unitized and closed device system that can reduce the chance of exposure to potentially infectious samples. 
+In January 2015, we entered into an agreement with StatSure Diagnostic Systems, Inc. (SDS) to acquire SDS' interest in the barrel device format, also known as Chembio's SURE CHECK® HIV 1/2 Assay, effective June 1, 2016. Beginning June 1, 2016, we owned full rights related to the SURE CHECK® HIV 1/2 Assay, including sales, marketing, distribution and trademark rights, subject to the few still-effective transitional terms of the marketing and distribution agreement with Alere, Inc., which terminated (subject to a few post-termination transitional provisions) on May 31, 2016. Prior to this newly-executed agreement between SDS and Chembio, SDS had owned a 50 percent interest in the rights to the SURE CHECK® HIV 1/2 Assay that would have continued after May 31, 2016, also subject to the then-existing marketing and distribution agreement with Alere. The January 2015 agreement with SDS also resolves all other matters between Chembio and SDS, including their respective sharing ratios, until June 1, 2016, concerning net revenues from sale of the SURE CHECK® product outside the U.S. 
+Prior to June 1, 2016, our SURE CHECK® HIV 1/2 Assay was marketed exclusively in the U.S. as Clearview® Complete pursuant to the agreement with Alere described above. Since June 1, 2016, it has been marketed in the U.S. as Sure Check® HIV 1/2 Assay. Outside the U.S., we continue to market the SURE CHECK® HIV 1/2 Assay primarily through distributors. The SURE CHECK® HIV 1/2 Assay is Food & Drug Administration (FDA) approved, CLIA-waived, European CE-marked, and has been pre-qualified by the World Health Organization (WHO). Results are obtained in 15 minutes via a 2.5uL blood sample (i.e., fingerstick, serum, plasma, or venipuncture whole blood). The assay is stable at room temperature and provides 99.7% sensitivity and 99.9% specificity. 
+Our second FDA-approved lateral flow HIV test, the HIV 1/2 STAT-PAK®, uses a more conventional rectangular plastic cassette format that houses the lateral flow strip. In this case, a sample is transferred by use of a separately provided transfer device ("loop") into a sample well or port of the cassette that houses the lateral flow strip, which is positioned horizontally or flat. 
+Our third lateral flow HIV test, the HIV 1/2 STAT PAK® Dipstick, is our most cost competitive and compact format. It does not have any plastic housing so that 30 test strips can be packaged into a small vial that is ideal for transporting into remote settings. The test procedure is similar to the cassette format except that a user-applied adhesive backing is provided as a more cost-effective and compact "surface" on which to run the test. 
+3 
+Regulatory Status of the lateral flow HIV tests 
+The FDA approved our Pre-Market Applications (hereinafter "PMA"; see "Governmental Regulations" and Glossary) in April 2006 for our SURE CHECK® HIV 1/2 and for our HIV 1/2 STAT-PAK® products. Waivers under the Clinical Laboratory Improvement Act (hereinafter "CLIA"; see Governmental Regulations) were granted by the FDA for these two FDA-approved products in 2006 and 2007, respectively. A CLIA waiver is required in order for health care providers to administer these tests in the settings where they are most suited and needed, such as public health testing clinics, hospital emergency rooms and physicians' offices. The SURE CHECK® and HIV 1/2 STAT-PAK® products received CE Marks in July 2013 and March 2014, respectively, and the CE Marking for the DPP® HIV 1/2 Assay described below was received in June 2015. We have also updated our filing for CE Marking to reflect the new tradename of STAT-VIEW® HIV 1 / 2 Assay for sale in the EU market. Our HIV 1/2 STAT-PAK® Dipstick, although not FDA-approved, qualifies under FDA export regulations [See Government Regulation] to sell to customers outside the United States, subject to any required approval by the importing country. CE Mark has not been pursued for this product. 
+All three of our lateral flow HIV tests have qualified for procurement under the President's Emergency Plan for AIDS Relief ("PEPFAR"). The cassette and dipstick versions of the STAT-PAK® and the SURE CHECK® assays are also pre-qualified by the World Health Organization (WHO) for procurements by the second largest global program, known as the Global Fund, as well as other related programs funded by agencies affiliated with the United Nations, such as UNICEF and UNITAIDS (see Glossary), through qualification with the WHO bulk procurement scheme. 
+DPP® HIV 1/2 Assay 
+As in the case of our lateral flow HIV tests, our DPP® HIV 1/2 Assay is also a qualitative "yes/no" test for the detection of antibodies to HIV 1& 2, delivers visual results within as little as 15 minutes, is simple to use, has a shelf life of 23 months, and does not require refrigeration. This product, which is our first FDA-approved product incorporating our patented DPP® technology, can be used with oral fluid samples, as well as with all blood matrices. This product also incorporates our patent-pending oral fluid collection and storage system that enables samples to be fully extracted in buffer solution before application to the test device, and also enables the extracted sample to be stored and retested or potentially tested for multiple conditions in future product applications. Clinical and laboratory studies demonstrated the ability of the test to accurately detect the presence of antibodies in individuals down to two years of age. Studies have also shown this product to have improved performance compared with all of the current FDA-approved CLIA-waived lateral flow rapid tests, even including our own lateral flow tests. FDA-approved label claims include sensitivity/specificity on oral fluid and finger-stick whole blood of 98.9%/99.9% and 99.9%/100% respectively. Oral fluid sensitivity was 100% among HIV-positive patients not taking anti-retroviral medication. 
+Regulatory Status of the DPP® HIV 1/2 Assay 
+In December 2012, we received FDA approval of our Pre-Marketing Application for our DPP® HIV Assay. In October 2014, the FDA granted CLIA-waiver status for this assay. 
+Our DPP® HIV 1/2 Assay product is qualified for procurement under the President's Emergency Plan for AIDS Relief ("PEPFAR") for use with all sample matrices. In May 2015 we obtained approval for a CE Mark for the DPP® HIV 1/2 Assay for Oral Fluid, Serum, Plasma, Fingerstick Whole Blood and Venous Whole Blood . In 2016, we obtained WHO qualification in order to enable procurement of this product by the Global Fund and United Nations agencies, including programs underwritten by them. 
+Previously, in June 2010, ANVISA approved the DPP® HIV 1/2 Assay that is being marketed in Brazil through our collaboration with the Oswaldo Cruz Foundation, Brazil's leading public health institute (see Oswaldo Cruz Foundation OEM DPP® Agreements). Since that time, we have sold and marketed millions of DPP® HIV tests to Brazil through this partnership. 
+DPP® HIV-Syphilis Multiplex Test 
+This product, launched in 2013, allows for the detection of antibodies to both HIV and syphilis on a single test device within approximately 15 minutes. We believe that in certain global/public health settings (see Target Markets), this product may provide a more convenient and cost-effective means of rapid detecting both markers in a single test procedure at the point of care as compared with performing separate rapid tests for each indication. This product takes advantage of the multiplexing feature of DPP® which provides for a more robust reaction between the sample and biomarkers being tested for (HIV and syphilis antibodies in this case), resulting in a greater ability by the user to visually interpret test results. We launched this product in Mexico in the fourth quarter of 2013 as a unitized product, meaning that each test kit was separately packaged to include each of the other components necessary to run this test, as compared with other configurations where a test kit of 20 or 30 devices is accompanied by one bottle of running buffer. We believe that the initial results of this launch have been very positive, and we experienced good results in Mexico during 2014 from the program. Building on this initial success, we continue to pursue commercialization efforts for this product in a number of additional international markets, where there is a great need to detect Mother-to-Child-Transmission of HIV and Syphilis globally. According to the CDC website, "approximately 370,000 babies are born with HIV, mostly in sub-Saharan Africa. Without treatment, more than half of these children will die before the age of 2. Through key interventions, such as routinely testing pregnant women for HIV, providing antiretroviral medications to HIV-infected pregnant women and their exposed infants, and promoting safe infant feeding practices, mother-to-child transmission of HIV can be decreased from about 35% to less than 5%. Another prominent cause of infant mortality is untreated maternal syphilis, which still accounts for more than 500,000 stillbirths and infant deaths annually despite the fact that these deaths could be prevented through routine detection and treatment of syphilis during antenatal care". 
+4 
+Regulatory Status of the DPP® HIV-Syphilis Test 
+DPP® HIV-Syphilis – We have developed this product for international and U.S. marketing. For the international market, the product has been registered in Mexico, and successfully launched and sold in this region. 
+In February 2015, this product was granted approval from the Brazilian ANVISA. As of December 31, 2016, there have been no sales of the DPP® HIV-Syphilis Assay in Brazil. This product also has been approved by the CDC, acting on behalf of the United States Agency of International Development, (USAID) for its global procurement scheme. 
+We are developing a U.S. version of the DPP® HIV-Syphilis Assay, designed to meet the performance requirements for the "reverse" algorithm that is currently in clinical use for syphilis testing in the United States. We have completed our pre-clinical studies for this product with encouraging results, and are in the final stages of clinical site selection for our U.S. clinical studies. We began this clinical trial in the U.S. in 2016, and expect that the trial will be completed in the first quarter of 2017. 
+DPP® Technology & Development 
+Chembio is executing its strategy to leverage the DPP® intellectual property and product development and manufacturing experience to create new collaborations where Chembio serves as an exclusive development and manufacturing partner. Examples of such collaborations include the following: 
+· 
+We entered into an agreement in October 2014 to develop a POC diagnostic test for dengue fever virus, the DPP® Dengue Fever Assay, which would be able to detect IgG/IGM and NS1 antigens in October 2014. 
+· 
+A collaboration also announced in October 2014, with an international diagnostics company to develop a POC diagnostic test for the early detection and monitoring of a specific type of cancer. At that time, the cancer project represented the first application of the DPP® technology outside the infectious disease field. 
+· 
+We entered into a milestone-based development agreement with a private contracting organization acting on behalf of the CDC, for a multiplex POC influenza immunity test utilizing our patented Dual Path Platform (DPP® ) technology. 
+· 
+In January 2015, we entered into an agreement with the Concussion Science Group (CSG) Division of Perseus Science Group LLC, to utilize our patented DPP® technology to develop a POC diagnostic test for traumatic brain injury (TBI), including sports-related concussions. Under terms of the agreement, CSG's patented biomarker will be combined with our proprietary DPP® platform to develop a semi-quantitative or quantitative point-of-care test to diagnose TBI. CSG agreed to pay Chembio milestone development payments during 2015. 
+· 
+In January 2015, we were awarded a grant from The Bill & Melinda Gates Foundation to expedite the feasibility testing and development of a DPP® Malaria POC rapid diagnostic to accurately identify individuals infected with Plasmodium falciparum parasite. Our DPP® technology was selected for this grant due to its exceptional sensitivity and potential to aid the foundation in its goal of eradicating malaria. To achieve this goal, diagnostics must be capable of detecting the malaria parasite in infected, but asymptomatic, people. Current POC rapid diagnostics tests lack sufficient sensitivity to identify all individuals with transmissible infections. 
+· 
+In October 2015, we were awarded a grant from the Paul G. Allen Foundation to develop a POC test to identify multiple life-threatening febrile illnesses. Under the $2.1 million dollar grant, we are to use our patented DPP® technology to seek to develop a DPP® Fever Panel Assay, a POC multiplex assay to simultaneously detect Malaria, Dengue, Ebola, Lassa and Marburg. The multiplex assay is planned to be designed to include a quality control test band and seven tests bands with specific antibodies to detect different pathogens, including multiple serotypes of the same pathogen: Malaria PAN-PLDH antigen (Plasmodium falciparum, Plasmodium vivax, Plasmodium malariae, Plasmodium ovale), Malaria Falciparum HRP2 antigen, Ebola Virus PAN (Zaire, Sudan, Bundibugyo Virus), Marburg Virus, Lassa Virus, Dengue Virus (Dengue 1, Dengue 2, Dengue 3, Dengue 4) and Chikungunya Virus. In many parts of the world, these diseases are commonly misdiagnosed, resulting in a delay of treatment or failure to properly treat the underlying infection. Misdiagnosis may be due to the fact that these diseases have similar symptoms that are difficult to distinguish. Currently available POC diagnostics lack the ability to test for multiple diseases simultaneously. Further, existing POC diagnostics may lack the sensitivity and specificity required to detect infected but asymptomatic patients - information that is critical for preventing the spread of disease. 
+5 
+· 
+Also in October 2015, we signed an agreement with opTricon (Berlin, Germany), a leading developer of mobile analysis devices for rapid diagnostic tests. Through this exclusive agreement, subject to certain terms, and covering the fields of sexually transmitted diseases, certain "fever" diseases, and a specific form of cancer, we expect to launch the DPP® Micro Reader, a point-of-care instrument designed specifically to complement our patented DPP® technology as applied to those diseases. The DPP® Micro Reader will include an innovative image sensor to provide a quantitative interpretation of diagnostic results when combined with our proprietary DPP® immunoassay technology. Using a state-of-the-art camera system, the DPP® Micro Reader is designed to provide definitive diagnostic results for low analyte concentrations, which may otherwise result in faint or ambiguous test results. In addition, the DPP® Micro Reader will provide customers with various options to capture, record, transmit and store test results. With one-button operation, the palm-sized and battery-operated DPP® Micro Reader is simple, fast, portable and cost-effective. 
+PARTNERS INVOLVED IN MARKETING OUR PRODUCTS 
+Alere 
+On September 29, 2006, we executed marketing and license agreements with Alere. The marketing agreements (the Barrel Agreement and the Cassette Agreement) provide Alere with a 10-year exclusive right (until May 31, 2016) to market our rapid HIV tests in the United States under Alere's brands. The agreements also provide us with a non-exclusive license to certain Alere lateral flow patents that may be applicable to our lateral flow products, including for manufacture of the HIV tests in the United States for sales outside the United States and even for sale in the United States should Alere enter the U.S. market with a competitive rapid HIV test product and in such case we choose to market our products directly as provided in the agreements in such event of a competitive rapid HIV test product. Simultaneous with the execution of the agreements, we also settled litigation with StatSure Diagnostics, Inc. (SDS), that had been ongoing relating to the proprietary barrel device which is incorporated into one of our two FDA-approved rapid HIV tests (See Lateral Flow HIV Tests above). SDS, pursuant to the settlement, is a party to the 3-way Barrel Agreement. As a result, until the dates described below and elsewhere in this report, it is through the agreements with Alere that we were participating in the growth of the rapid HIV test market in the United States. 
+In late July 2013, we received notice from Alere that it intended to commercialize its own rapid HIV test (see Competition), which test had just received FDA approval as a moderate complexity product (i.e. not CLIA-waived though this was granted in late 2014), in the United States. Under the Barrel Agreement and the Cassette Agreement, such product is considered to be a Permitted Competing Product (PCP). Each of the two aforementioned agreements provides that, in the case of notice of a PCP, we may make certain elections (jointly with SDS in the case of the Barrel Agreement), or elect to continue each agreement without taking any further action. Under the Cassette Agreement, we may, at any time, terminate such agreement, which termination would become effective 60 days after the date notice was made. Under the Barrel Agreement, we and SDS may jointly issue a non-exclusivity notice, which notice shall be effective immediately. In the event that we make this election with respect to the cassette product, or that both we and SDS make this election with respect to the cassette product, then the electing party or parties could sell that respective product in the United States market under its own brand, and in such case, the lateral flow license that we have from Alere for international sales would be expanded to include sales in the United States. See Lateral Flow Technology and Reagent Licenses. In April 2014, we gave notice to Alere of our intent to terminate the Cassette Agreement and 60 days later, we began marketing the cassette product in the United States under the Chembio brand of HIV 1/2 STAT-PAK® assay. On May 31, 2016, the Barrel Agreement expired pursuant to its terms, and, given our January 2015 agreement with SDS, we now market the barrel product in the U.S. under the brand of SureCheck® HIV 1/2 Assay. 
+We have developed our own sales and marketing departments for the sales of our products in the U.S. and internationally. We also have appointed distributors in the U.S. and internationally for our lateral flow HIV tests. Our largest markets outside the U.S. for our lateral flow HIV rapid tests are certain countries in Africa, Asia, and South America, as well as Mexico. Internationally, most of the demand for our products is based on governmental and non-governmental prevention and treatment efforts. Given this, these programs can and do often result in large orders, but also can result in periods of relatively lower demand, based on the variations associated with this kind of demand. 
+OEM DPP® Products 
+Oswaldo Cruz Foundation OEM DPP® Agreements 
+During 2008-2010 we signed five separate agreements, each of which is titled and constitutes a "Technology Transfer Agreement", with the Oswaldo Cruz Foundation (FIOCRUZ) in Brazil. FIOCRUZ includes the Institute of Technology on Immunobiologicals/Bio- Manguinhos, which is the FIOCRUZ unit that produces vaccines and diagnostic kits. FIOCRUZ and Bio-Manguinhos are referred to herein interchangeably. Each of the five agreements relates to a different specific product or group of products based on our DPP® technology. FIOCRUZ is the leading public health organization in Brazil, and it is affiliated with Brazil's Ministry of Health, which is its principal client. It has extensive research, educational and manufacturing facilities for drugs and vaccines, as well as for diagnostic products. 
+6 
+Each of the agreements grants to FIOCRUZ the right, but not the obligation, to earn the right to request a technology transfer to be able to license and manufacture that product on its own. FIOCRUZ is not required to earn this right, but if it desires to do so, then it needs to purchase a stated amount of the product as set forth in the respective agreement for that product. 
+During 2010 and 2011, all of the initial products contemplated under the five agreements were approved for marketing by the applicable regulatory agencies in Brazil. The agreements between us and FIOCRUZ are unique examples of technology transfer collaborations between a private sector rapid test manufacturer and a public health organization. The five products categories for which FIOCRUZ can earn a separate right to request a technology transfer for that product only are: DPP® products for HIV screening, HIV Confirmatory, Leishmaniasis, Leptospirosis and Syphilis. Each technology transfer, and the provision by us of the information and training that is required for this to occur, will occur only if FIOCRUZ purchases from us the amount of that product that is specified in the respective agreement for that product. The actual amount of purchases for each product is totally at the discretion and option of FIOCRUZ and may be more or less than the amount needed to qualify for a technology transfer. 
+More specifically, the five agreements, although separate and independent of one another, are structurally similar according to the following: 
+· 
+Each agreement states: "the object of this Agreement is for the Transfer of Technology from Chembio to Bio-Manguinhos, the license by Chembio to Bio-Manguinhos for the Chembio Patents applied or granted in Brazil or other Mercosur countries for the term of the patents and the transfer of all the technical information related to the DPP® technology and the process to obtain the product by the DPP® technology. This Agreement contemplates the scientific and technological co-operation between Chembio and Bio-Manguinhos for such activities so that Bio-Manguinhos will be able to manufacture the Product in Brazil." 
+· 
+Each agreement provides that we will supply free of charge to Bio-Manguinhos prototypes of the product to demonstrate performance characteristics that are necessary for evaluation by the Brazilian Ministry of Health and for registration with ANVISA. ANVISA is the Agencia Nacional de Vigilancia Sanitaria, or the National Sanitary Vigilance Agency. The number of prototypes ranges from 15,000 to 45,000 in the various agreements. 
+· 
+Each agreement provides that the prototypes will be utilized both for a performance study that follows a protocol prepared and approved by Bio-Manguinhos and the Brazilian Ministry of Health, and also will be used for studies in Brazil for the registration procedures at ANVISA. Bio-Manguinhos will then apply to ANVISA to register the product. Within 120 days of the registration of the product with ANVISA, Bio-Manguinhos will make an advance technology transfer payment to us (the "Advance Payment"), in an amount specified in that particular agreement. All five of the Advance Payments provided for in the agreements were made in 2010 and 2011. 
+· 
+At such time, if any, that the product for a particular agreement has been successfully registered with ANVISA, then Bio-Manguinhos has the right to qualify for the full technology transfer for that product by purchasing the amount of the product, and at the price, specified in the agreement. 
+· 
+Bio-Manguinhos is not required to purchase any amount of any product. For each product, it only needs to purchase that product, in the amount specified in the agreement, only if it desires to be able to complete the technology transfer process in order to manufacture and sell that product on its own. We do not have recourse against Bio-Manguinhos if Bio-Manguinhos does not purchase the qualifying purchase amount of any product. In that case, we can only suspend further phases of the technology transfer, attempt to renegotiate the agreement, and/or retain any amounts previously paid by Bio-Manguinhos. We cannot force Bio-Manguinhos to purchase any amount of any product. 
+· 
+As a result of the terms of these agreements, Bio-Manguinhos has never been required to, and is not now required to, purchase any amount of any of the products. 
+· 
+As of December 31, 2016, Bio-Manguinhos had earned the status described below with respect to each of the five products: 
+1. 
+With respect to our DPP® HIV1/2 Screen test, Bio-Manguinhos had qualified to request the technology transfer. It has requested, and has received, the technology transfer information. Bio-Manguinhos purchased $880,175, $4,990,840 and $291,235 of this product in 2011, 2012 and 2013, respectively, all of which applied to the qualifying amount to obtain the right to the technology transfer (the "Qualifying Amount") for this product. In 2013, 2014, 2015 and 2016 Bio-Manguinhos made $3,320,010, $4,799,250, $5,410,350 and $5,900, respectively, of purchases in excess of the Qualifying Amount. 
+2. 
+With respect to our Canine Leishmania test, Bio-Manguinhos had qualified to request the technology transfer and did so request. Submission of the technology transfer information is in process at this time. Bio-Manguinhos purchased $2,000,817 and $99,183 of this product in 2011 and 2012 respectively, of this product in that applied to the Qualifying Amount. In addition, Bio-Manguinhos made purchases in excess of the Qualifying Amount equal to $1,314,117, $1,736,700, $2,394,000, $3,772,482 and $4,221,000 in 2012, 2013, 2014, 2015 and 2016, respectively. 
+7 
+3. 
+a. 
+With respect to the three variations of our DPP® Syphilis test, all of which are covered by a single agreement, Bio-Manguinhos had qualified to request the technology transfer with respect to Trep only, and intends to do so in the near future. Bio-Manguinhos purchased $1,194,250, $165,750 of this product in 2011 and 2012, respectively that applied to the Qualifying Amount. In addition, Bio-Manguinhos made purchases in excess of the Qualifying Amount equal to $2,817,750, $646,340, $4,617,891 and $833,631 in 2012, 2013, 2014 and 2015, respectively no purchases of this product were made in 2016. 
+b. 
+With respect to the two variations of our Screen & Confirm Test, Bio-Manguinhos had not made any purchases in 2011, 2012, 2013, 2014, 2015 or 2016, and therefore had not qualified to request the technology transfer for either of them. This agreement was terminated in December 2015. 
+c. 
+This syphilis agreement was terminated during the fourth quarter of 2015. 
+4. 
+With respect to our DPP® Confirmatory test, Bio-Manguinhos has qualified to request the technology transfer. Bio-Manguinhos made purchases of $560,000, $819,000, $390,000, $390,000, $156,000 and $39,000 of this product in 2011, 2012, 2013, 2014, 2015 and 2016 respectively, all of which applied to the Qualifying Amount. In addition, Bio-Manguinhos made purchases in excess of the Qualifying Amount equal to $485,940 in 2016. 
+5. 
+With respect to our DPP® Leptospirosis test, Bio-Manguinhos had not qualified to request the technology transfer. Bio-Manguinhos made purchases of $135,000 of this product in 2011, and it made -0- purchases in 2012, $45,000 in 2013 and it made -0- purchases in 2014, 2015 and 2016. In order to qualify for the technology transfer, Bio-Manguinhos would need to purchase an additional $225,000 of this product. 
+· 
+As stated above, Bio-Manguinhos is not obligated to make any purchases. After the specified level of sales for a particular product has been achieved, FIOCRUZ may request that the technology for that product be transferred to FIOCRUZ together with an exclusive license to produce and sell that product in a defined territory. The license is to provide that we will receive a royalty on all sales. We do not release the amount of this royalty because it could have an adverse effect on negotiations concerning royalties in potential transactions with other parties. 
+· 
+All the agreements expire five years after the date of the technology transfer. If terminated earlier by default of FIOCRUZ, FIOCRUZ must stop all activity; if terminated earlier because of our default, or if terminated by natural expiry, FIOCRUZ can continue to produce and commercialize the product without paying royalties. 
+Other OEM And License Agreements Related to DPP® Technology 
+In addition to our agreements with FIOCRUZ, we have entered into certain OEM and license agreements with other parties with respect to certain products that we have developed based on our DPP® technology. In 2008 we entered into a product development and license agreement with Bio-Rad Laboratories, Inc. (Bio-Rad), a leading multinational life sciences company, for the first ever POC test for the confirmation of HIV (reflex test used after initial screening test(s) are positive). This product utilizes our DPP® technology, capitalizing on its multiplexing advantages, and is much simpler to perform than the legacy confirmatory platform, known as western blot, which requires a substantial amount of technical training and hands-on time and which is more expensive to manufacture and distribute. This product was CE marked and was launched by Bio-Rad in the second quarter of 2013 in Europe under their Geenius® brand; and an FDA PMA approval was received in 2014. 
+In 2013 we entered into collaboration with Labtest, a private company in Brazil, for the distribution of a number of products in Brazil that would be co-branded with Labtest and Chembio trademarks. Under this agreement, upon request from Labtest, for which there is no requirement, we will sell the appropriate DPP® components to Labtest for further manufacture and assembly in Brazil. 
+In February 2014, we entered into a technology transfer and license agreement with RVR Diagnostics SDN BHD ("RVR"), a privately-held company in Malaysia. The agreement supports our strategy of establishing a market presence in Asia, in collaboration with RVR as a licensee, distributor, and contract manufacturer, depending on the circumstances. The agreements grant exclusive distribution rights to RVR in certain countries in the region and enable RVR to manufacture our DPP® HIV 1/2 Assay and DPP® HIV-Syphilis Assay, and potentially other products that are developed by us, such as Dengue, incorporating its patented DPP® technology as indicated in the DPP® Technology & Development section above. As indicated elsewhere, we acquired RVR in January 2017. 
+Our Rapid Test Technologies 
+All of our commercially available current products employ either in-licensed lateral flow technology or our own patented Dual Path Platform (DPP®) technology. Both lateral flow technology and DPP® allow the development of accurate, low cost, easy-to-perform, single-use diagnostic tests for rapid, visual detection of specific antigen-antibody complexes on a test strip. These formats provide a test that is simple (requires neither electricity nor expensive equipment for test execution or reading, nor skilled personnel for test interpretation), rapid (turnaround time approximately 15 minutes), safe (minimizes handling of potentially infected specimens), non-invasive (requires 5-20 micro liters of whole blood easily obtained with a finger prick, or alternatively, serum or plasma), stable (24 months at room temperature storage in the case of our HIV tests), and highly reproducible. 
+8 
+We believe that products developed using DPP® technology can provide superior diagnostic performance as compared with products that use lateral flow technology. The reason for this is that one of the major differences between the two platforms is that in DPP® samples are allowed to incubate with the target analyte in the test zone before introduction of the labeling reagent/conjugate, whereas in lateral flow, samples are combined with the labeling reagent to form a complex before coming in contact with the target analyte. We believe that this complex can compromise test performance. Also, because of the usage in DPP® of a separately connected sample strip, the control and delivery of sample material is substantially improved. This feature is critical in the development of multiplex tests, as well as tests that involve viscous sample material (such as oral fluid) that can be impeded when forced to combine with labeling reagents before migration on the test strip to the test zone area. 
+Multiplexing is significantly improved as a result of the design of DPP® and this provides a significant advantage. For example, the HIV confirmatory test we developed for Bio-Rad that is described above employs six different markers related to various epitopes of the HIV antigen. We have a number of other products in development, including those being developed in sponsored development programs that involve the use of multiple (e.g. eight) test bands. Although all of these products could be visually read, we can also use handheld and desktop readers with our DPP® products to objectively measure, quantify, record and report DPP® test results. Certain of the products we have and/or are developing incorporate some of these readers, and we are developing other products that may be used with or will require use of a reader. Also, platforms can incorporate labeling reagents that cannot be visually read except by employing a reader, such as fluorescence, though no products are currently utilizing such reagents. 
+We are pursuing additional capabilities and technologies that will complement our current product portfolio and business strategy. This activity includes pursing development, license or acquisition of diagnostic technologies that complement our existing platforms, proprietary biomarkers that can result in new product applications of our existing platforms, and new platforms that would complement our commercial strategy. 
+Target Markets 
+Rapid HIV Tests 
+A large percentage of individuals that are HIV positive worldwide are unaware of their status. Part of the reason for this is that even those that do get tested in public health settings will often not return or call back for their test results when samples have to be sent out to a laboratory which can take up to several days to process. The increased availability, greater efficacy and reduced costs for anti-retroviral treatments (ARVs) for HIV has increased the demand for testing, as the stigma associated with the disease is lessened, and the ability to resume normal activities is substantially improved, providing a positive message to those potentially infected. The impact that rapid HIV testing has had on prevention efforts has in turn increased the demand for testing, particularly by public health programs worldwide, which have also become more effective in reducing the number of annual new infections in many, but by no means all, high prevalence regions. 
+Despite less attention to HIV by the media as compared with prior years, there are still approximately 50,000 new diagnoses of HIV infection in the United States each year, according to the CDC. CDC estimates that approximately 1.1 million individuals in the U.S. are living with HIV, with an estimated 1 of 8 of these U.S. individuals, or almost 13%, unaware that they are infected. It is transmissions from these infected people that are reported to account for the majority of all new infections per year. Part of the reason for this is that even those individuals that do get tested in public health settings will often not return or call back for their test results if their blood samples have to be sent out to and tested in a laboratory and then reported back, a process which can take up to several days to complete. Making more people aware of their HIV status at the point-of-care reduces the number of HIV transmissions. 
+In 2006, the outlook for HIV testing was given a big boost with the release by the CDC of new recommendations for HIV testing. These new CDC recommendations were/are that an HIV test should be given as a routine test like any other for all patients between 13 and 64 years of age, regardless of risk, with an opt-out screening option and focused testing procedural (pre- and post-test counseling) guidelines. Though not mandatory, gradual adoption in whole or in part of the 2006 CDC recommendations by a number of states continues to have an increasing impact. Finally, in 2013, the United States Preventive Services Task Force ( " USPSTF " ) fully embraced these CDC routine HIV testing recommendations. This USPSTF recommendation, which was given an A grade under their recommendation grading system based on the benefits of this practice and the nearly 600,000 AIDS-related deaths in the United States, requires insurance coverage under the Affordable Care Act (the " ACA " ) as a preventive screening test without any co-payment required. Assuming that new legislation does not modify this requirement, of which there is no assurance, we expect this requirement to result in an increase in HIV testing in the United States in the coming years, which we believe will include point-of-care HIV testing utilizing our products. Although as stated above, currently most public health testing in the United States is funded by grants allocated to high prevalence areas by the CDC, we believe this will shift to an insurance-funded model under the ACA in the years to come, increasing the amount of testing done in doctor ' s offices and community health centers. 
+9 
+In the international market, we sell our products directly and through distributors to large screening programs overseen by ministries of health and NGOs, most but not all of which are funded by large bi-lateral and multi-lateral AIDS relief programs, the largest of which is the U.S. President ' s Emergency Plan for AIDS Relief (PEPFAR). Established by President George Bush as a 5-year $15 billion program in 2003, PEPFAR was reauthorized in 2008 and again in 2013. In 2012 PEPFAR directly supported HIV testing and counseling for more than 11 million pregnant women, and testing and counseling for more than 49 million people overall. The U.S. is also the first and largest donor to the Global Fund to Fight AIDS, Tuberculosis and Malaria. To date, the U.S. has provided more than $7 billion to the Fund. 
+In December 2013 President Obama signed into law the PEPFAR Stewardship and Oversight Act, which is the most recent reauthorization of PEPFAR. However, unlike the 2008 PEPFAR authorization, which authorized approximately $45 billion, the new law doesn ' t authorize a specific dollar amount for funding. Nevertheless, it is widely anticipated that PEPFAR will continue to enjoy strong funding; the FY14 budget had $6 billion for global HIV/AIDS assistance, including $4 billion for PEPFAR. 
+With our four U.S.-manufactured rapid HIV tests, all of which are FDA-approved, we are recognized as a reputable and dependable supplier of high quality products that are available at reasonably competitive prices. As a result, certain of our products have been selected in the testing protocols in countries (national algorithms) that are large beneficiaries of PEPFAR and the Global Fund. As mentioned above, these programs can and do often result in large orders, but also can result in periods of relatively lower demand, based on the variations associated with this kind of demand. Also, even though the United States taxpayer is funding the largest share of global AIDS relief, U.S. companies do not receive any preference for these procurements, and therefore must compete with foreign suppliers that manufacture competitive products with lower costs, including those related to quality, regulatory, intellectual property, and costs of manufacturing. 
+Oral fluid testing is an established alternative to blood testing for diagnostic tests, including HIV tests. It is also often patient preferred, providing a more comfortable, less invasive test. In certain public health clinics, staffs choose not to handle blood specimens; thus, oral sample collection provides a viable alternative. The most well-established market for oral fluid HIV testing is the United States. Given the premium price required for an oral fluid test as compared with blood tests, the higher volume programs will not specify an oral fluid test. However, segments of these programs may want to have an oral fluid testing option, and certain programs that have greater resources may also choose to incorporate oral fluid testing into the testing protocol. 
+There is also now an over-the-counter market for HIV self-testing in the United States. OraSure Technologies Inc. received FDA approval for an over-the-counter (self-testing) version of its previously professional-market-approved (test performed on an individual by a health care professional) HIV test. The FDA approval was granted in July 2012, and OraSure has been investing heavily in developing this market. Initial results after over two years of marketing are well below expectations. The costs for such over-the-counter approval, including primarily the associated clinical trials, are estimated to be at least $5 million and they may take two to three years to complete, not to mention the cost of distribution. OraSure's initial results are not convincing of a large market, although this possibility remains. If it appears that there is an attractive market, we believe we are very well positioned to participate in this market. 
+Rapid HIV-Syphilis Test 
+There are significant risks relating to transmission of Syphilis from a pregnant mother to child, just as there are for transmission of HIV. Therefore we believe there is a significant opportunity to improve prevention efforts in pregnant mother to child transmission testing programs (PMTCT) that are currently not doing any or nearly enough testing for syphilis even though they are testing for HIV. In the United States, we believe there is also a significant need for this product in some of the highest HIV prevalence populations, such as among men that have sex with men (MSM), as data show high degrees of HIV and Syphilis co-infection in this segment of the population. 
+10 
+Marketing Strategy 
+Our marketing strategy is to: 
+· 
+Market our DPP® HIV 1/2 Assay, HIV 1/2 STAT-PAK® Assay, our SURE CHECK® HIV 1/2 Assay and future DPP® based new products in the US through our internal sales and marketing organization and selected channel partners (e.g., McKesson/PSS, Fisher Healthcare, Henry Schein, etc.). Following the June 2014 termination of the STAT-PAK® agreement with Alere, and the May 31, 2016 termination of the SURE CHECK® agreement with Alere, we no longer have to share any portion of the net sales proceeds for these products with Alere. These changes resulted in our incurring expenditures related to hiring sales representatives, establishing agreements and associated discounts with distributors, incurring advertising and marketing expenditures, warehousing, customer service and technical support. If Alere's new competitive product is indeed successful, our ability to retain a significant share of the market that has been established for our products may be enhanced by our having control of the marketing of our products, rather than relying on Alere to sell both our products while it is also selling its own competing product. We are leveraging the same sales force for U.S. Sales of our DPP® HIV 1/2 Assay. 
+· 
+Outside the U.S., we will market our products primarily through commercial collaborators and distribution partners. 
+· 
+Leverage our DPP® intellectual property and product development and manufacturing experience to continue creating new collaborations where we can be the exclusive development and manufacturing partner supporting leading marketing organizations. 
+· 
+Establish strong distribution relationships for our Chembio-branded products in the U.S and abroad, and establish a direct sales and marketing organization that is focused in the public health market segment, and that utilizes distributors for other market segments, primarily the acute care market which, together with public health, are the main market segments for rapid HIV tests in the United States. We believe that creation of a Chembio public health brand and marketing organization is fundamental to the creation of shareholder value over the long-term. 
+We have increased our commercial activities and efforts in Africa, Europe and Asia for our HIV tests and product pipeline. We believe these efforts will enable us to be more closely engaged with opportunities to engage with customers and partners and to participate in the national testing algorithms that are established and revised from time to time by countries that are beneficiaries of PEPFAR, Global Fund and/or other bilateral or multilateral donor funding. In Europe, where there are a larger percentage of HIV positive people unaware of their status than in the United States, we believe that there is an emerging public health outreach opportunity, and there are relatively few strong competitors that are CE-marked. Most recently we have established new sales and marketing positions in the Company to support our efforts to increase brand awareness globally and to lead our direct sales effort in the U.S. market. 
+Competition 
+There are several established rapid HIV tests which are already in the marketplace that compete with our lateral flow HIV tests and DPP ® HIV 1/2 Assay. These include OraSure (sold by OraSure Technologies), Alere Determine ® rapid test product (sold by Alere, Inc.), and INSTI (sold by Biolytical, Inc.). Our competitors may have significant advantages over us, including being substantially larger and having greater financial, research, manufacturing and marketing resources. Industry competition in general is based on the following: 
+· 
+Scientific and technological capability; 
+· 
+Proprietary know-how; 
+· 
+The ability to develop and market products and processes; 
+· 
+The ability to obtain FDA or other required regulatory approvals; 
+· 
+The ability to manufacture products that meet applicable FDA requirements, (i.e. FDA ' s Quality System Regulations) (see Governmental Regulation section); 
+· 
+The ability to manufacture products cost-effectively; 
+· 
+Access to adequate capital; 
+· 
+The ability to attract and retain qualified personnel; and 
+· 
+The availability of patent protection. 
+We believe our scientific and technological capabilities and our proprietary know-how relating to our in-licensed lateral flow technology rapid tests and to our proprietary know-how related to our patented DPP® technology, particularly for the development and manufacture of tests for the detection of antibodies to infectious diseases such as HIV, are very strong. 
+11 
+Our ability to develop and market other products is in large measure dependent on our having additional resources and/or collaborative relationships. Some of our product development efforts have been funded on a project or milestone basis. We believe that our proprietary know-how in lateral flow technology and in our DPP® technology has been instrumental in our obtaining the collaborations we have and that we continue to pursue. We believe that the patent protection that we have with our DPP® technology enhances our ability to develop more profitable collaborative relationships and to license out the technology. However there are a number of competitive technologies used and/or seeking to be used in point-of-care settings. These technologies may be based on immunoassay principles such as the Company ' s products or other technologies, such as molecular-based technologies. 
+We launched our FDA-approved DPP® HIV 1/2 Assay, which test also can be used with either oral fluid or blood samples, in the U.S. market under a Chembio brand in the fourth quarter of 2014. OraSure Technologies manufactures the only other rapid, oral fluid HIV test that is FDA-approved, and OraSure has enjoyed this position for approximately 10 years. OraSure has lost a significant share of this market as certain customers have been indifferent to using blood or oral fluid samples, because the blood tests, including those made/marketed by Chembio and marketed by Alere, are priced lower and/or are as or more accurate than the performance of OraSure ' s product on blood samples. OraSure has primarily retained those customers for whom the oral fluid sample feature is a strong preference, and this is an estimated $35 million business for OraSure. Although we believe we can capture a meaningful portion of this OraSure market share, we also anticipate that OraSure will defend this business aggressively. 
+In 2006 Alere acquired a division from Abbott Diagnostic located in Japan that manufactured and marketed a rapid HIV test product line called Determine®. The Determine® format was developed for the developing world and remote settings and, central to the needs of that market, the format is essentially a test strip that is integrated into a thin foil wrapper that, when opened, the underside of the wrapper serves as the test surface for applying the blood sample and performing the test. This design reduces costs and shipping weights and volumes and is an advantage for the developing world markets it has served. Some of the disadvantages of the platform are the amount of blood sample that is needed (50 microliters versus 2.5, 5 and 10 for our lateral flow barrel, lateral flow cassette, and DPP® products respectively), the open nature of the test surface, and the absence of a true control that differentiates biological from other kinds of samples. 
+The so-called " 3rd generation " version of this product has been marketed for many years and is the leading rapid HIV test that is used in a large majority of the national algorithms of countries funded by PEPFAR and the Global Fund, as well as many other countries in the world. That product is not FDA-approved though it is CE-marked. The newest Determine® HIV version, which was developed and manufactured at Alere ' s subsidiary in Israel, Orgenics, is the so-called " 4th Generation " version Determine® test. According to its claims, this product detects HIV antibodies and P24 HIV antigens. Since the P24 antigen is known to occur in HIV-positive individuals ' blood samples before antibodies do, based on its performance claims, the 4th generation Determine® test is therefore able to detect HIV infection earlier than tests that solely rely on antibody detection. Chembio ' s tests, as well as all of the other currently FDA-approved rapid HIV tests, only detect antibodies. There are however laboratory tests that are FDA-approved that are " 4th generation " tests, but they are of course neither rapid nor point-of-care. 
+The initial " 4th generation " Alere Determine® rapid test product that was also CE-marked and that Alere launched internationally some years ago has not been successfully commercialized to the best of our knowledge and at least certain published studies were not favorable for this product. However the 4th generation product that is now FDA-approved was apparently modified as compared to the initial international version of it, and it may perform more satisfactorily. Alere received FDA approval of this modified product in August 2013 and CLIA-waiver for it in the fourth quarter of 2014. There is support by a number of key opinion leaders for the public health value of such 4th generation tests, and it represents a significant competitive threat to Chembio as well as to each of the other rapid HIV test manufacturers (OraSure and Trinity primarily). 
+During 2011 Biolytical, Inc. of Vancouver, Canada received FDA approval and in 2012 received CLIA waiver of a flow-through rapid HIV test called " INSTI " . The technology used in the INSTI test, flow-through, is older than lateral flow, and it requires handling of multiple components (3 vials of solution) to perform the test in multiple steps. However, these steps can be accomplished in less than ten minutes, and the actual test results occur in only one minute after those steps are completed. Therefore sample-to-result time is shorter than any of the competitive products. There are settings where that reduced total test time, despite the multiple steps required, may be a distinct advantage, and we believe Biolytical has made some progress in penetrating certain public health markets. 
+Although we have no specific knowledge of any other competitors ' products that are a competitive threat to our products, or that will render our products obsolete, if we fail to maintain and enhance our competitive position or fail to introduce new products and product features, our customers may decide to use the products developed by our competitors, which could result in a loss of revenues and cash flow. 
+12 
+Research and Development 
+During 2016, 2015 and 2014, we spent $8.4 million, $6.4 million and $4.8, respectively, on research and development (including regulatory activities). These expenses were in part underwritten by funding from R&D and milestones revenues of $3.7 million in 2016, $2.3 million in 2015 and $1.7 million in 2014. All of our new product development activities involve employment of our DPP® technology. These activities include completing development of certain products and making significant progress toward the development of additional products. 
+Employees 
+At December 31, 2016, we employed approximately 131 people. We have entered into employment contracts with our Chief Executive Officer and President, John J. Sperzel, our Chief Operating Officer, Sharon Klugewicz, and our Chief Science and Technology Officer, Javan Esfandiari. Due to the specific knowledge and experience of these executives regarding the industry, technology and market, the loss of the services of any one of them would likely have a material adverse effect on the Company. The contract with Mr. Sperzel has a term of three years ending March 13, 2017. The contract with Ms. Klugewicz, has a term of two years ending May 2017. The contract with Mr. Esfandiari has a term of three years ending March 2019. The Company and Mr. Sperzel currently are discussing terms for renewal of his employment agreement. We have obtained a key man insurance policy for Mr. Esfandiari. 
+Governmental Regulation 
+The manufacturing and marketing of our existing and proposed diagnostic products are regulated by the United States Food and Drug Administration ( " FDA " ), United States Department of Agriculture ( " USDA " ), certain state and local agencies, and/or comparable regulatory bodies in other countries. These regulations govern almost all aspects of development, production and marketing, including product testing, authorizations to market, labeling, promotion, manufacturing and record keeping. The Company ' s FDA and USDA regulated products require some form of action by each agency before they can be marketed in the United States, and, after approval or clearance, the Company must continue to comply with other FDA requirements applicable to marketed products, e.g. Quality Systems (for medical devices). Failure to comply with the FDA ' s requirements can lead to significant penalties, both before and after approval or clearance. 
+There are two review procedures by which medical devices can receive FDA clearance or approval. Some products may qualify for clearance under Section 510(k) of the Federal Food, Drug and Cosmetic Act, in which the manufacturer provides a pre-market notification that it intends to begin marketing the product, and shows that the product is substantially equivalent to another legally marketed product (i.e., that it has the same intended use and is as safe and effective as a legally marketed device and does not raise different questions of safety and effectiveness). In some cases, the submission must include data from human clinical studies. Marketing may commence when the FDA issues a clearance letter finding such substantial equivalence. FDA clearance of our DPP® Syphilis Screen & Confirm test will be by means of a 510(k) submission. 
+If the medical device does not qualify for the 510(k) procedure (either because it is not substantially equivalent to a legally marketed device or because it is required by statute and the FDA ' s implementing regulations have an approved application), the FDA must approve a Pre-Marketing Application ( " PMA " ) before marketing can begin. PMA ' s must demonstrate, among other matters, that the medical device provides a reasonable assurance of safety and effectiveness. A PMA application is typically a complex submission, including the results of non-clinical and clinical studies. Preparing a PMA application is a much more expensive, detailed and time-consuming process as compared with a 510(K) pre-market notification. The Company has approved PMAs for the two rapid HIV tests now marketed in the U.S.: both our HIV 1/2 STAT-PAK® and our SURE CHECK® 1/2 HIV. 
+FDA approval of our DPP® HIV screening assay for use with oral fluid or blood samples also was achieved by means of a PMA application. The Clinical Laboratory Improvement Act of 1988 ( " CLIA " ) prohibits laboratories from performing in-vitro tests for the purpose of providing information for the diagnosis, prevention or treatment of any disease or impairment of, or the assessment of, the health of human beings unless there is in effect for such laboratories a certificate issued by the United States Department of Health and Human Services (via the FDA) applicable to the category of examination or procedure performed. Although a certificate is not required for the Company, it considers the applicability of the requirements of CLIA in the design and development of its products. The statutory definition of " laboratory " is very broad, and many of our customers are considered labs. A CLIA waiver will remove certain quality control and other requirements that must be met for certain customers to use the Company ' s products and this is critical to the marketability of a product into the point-of-care diagnostics market. We have received a CLIA waiver for each of the two lateral flow rapid HIV tests now marketed in the U.S. The CLIA waiver was granted by the FDA for HIV 1/2 STAT-PAK® on November 20, 2006 and for SURE CHECK® HIV 1/2 on October 22, 2007. In 2008 the FDA revised its CLIA waiver requirements so that an additional prospective trial need be conducted in order to demonstrate clinical utility by showing that the device is capable of identifying new infections when used by untrained users. Our DPP® HIV 1/2 test received CLIA waiver in October of 2014. 
+13 
+In addition, the FDA regulates the export of medical devices that have not been approved for marketing in the United States. The Federal Food, Drug and Cosmetic Act contains general requirements for any medical device that may not be sold in the United States and is intended for export. Specifically, a medical device intended for export is not deemed to be adulterated or misbranded if the product: (1) complies with the specifications of the foreign purchaser; (2) is not in conflict with the laws of the country to which it is intended for export; (3) is prominently labeled on the outside of the shipping package that it is intended for export; and (4) is not sold or offered for sale in the United States. However, the Federal Food, Drug and Cosmetic Act does permit the export of devices to any country in the world, if the device complies with the laws of the importing country and has valid marketing authorization in one of several " listed " countries under the theory that these listed countries have sophisticated mechanisms for the review of medical devices for safety and effectiveness. 
+We are also subject to regulations in foreign countries governing products, human clinical trials and marketing, and may need to obtain approval or evaluations by international public health agencies, such as the World Health Organization, in order to sell diagnostic products in certain countries. Approval processes vary from country to country, and the length of time required for approval or to obtain other clearances may in some cases be longer than that required for United States governmental approvals. On the other hand, the fact that our HIV diagnostic tests are of value in the AIDS epidemic may lead to some government process being expedited. The extent of potentially adverse governmental regulation affecting us that might arise from future legislative or administrative action cannot be predicted. 
+Environmental Laws 
+To date, we have not encountered any costs relating to compliance with any environmental laws. 
+Intellectual Property 
+Intellectual Property Strategy 
+Our intellectual property strategy is to: (1) build our own intellectual property portfolio around our DPP® technology; (2) pursue licenses, trade secrets and know-how within the area of rapid point-of-care testing, and (3) develop and acquire proprietary positions to reagents and new hardware platforms for the development and manufacture of rapid diagnostic tests. 
+We have obtained patent coverage on our DPP® technology, including four U.S. patents, and patents in China, Malaysia, Eurasia, Mexico, Singapore, Japan, Australia, Indonesia, Korea and the U.K. Additional patent applications on our DPP® technology are pending in the U.S., as well as in many foreign countries such as Brazil, Canada, the European Union, India, Israel, and South Africa. Patents have also been filed on extensions to the DPP® product line concept, such as 4th generation assays. The four U.S. patents are as follows: 
+U.S. Patent No. 
+Issued 
+Expires 
+Nature 
+Type 
+Description 
+7,189,522 
+3/13/2007 
+3/11/2025 
+test device 
+utility 
+a test device for determining the presence of a ligand in a sample 
+7,682,801 
+3/23/2010 
+3/11/2025 
+test device 
+and method 
+utility 
+a test device and a method for determining 
+the presence of a ligand in a sample 
+7,879,597 
+2/1/2011 
+3/11/2025 
+test device 
+utility 
+a test device for determining multiple 
+ligands in a sample 
+8,507,259 
+8/13/2013 
+3/11/2025 
+test device 
+utility 
+a test device for determining the 
+presence of a ligand in a sample 
+We have also filed for patents and obtained some patents in the U.S. for other inventions, such as its multiple host species veterinary TB test, and patent applications for the other inventions are in various stages from being recently filed and not yet examined, to already examined and allowed but not yet issued. We selectively and strategically foreign files its patent applications based on a number of economic and strategic factors related to the invention. 
+Trademarks 
+We have filed and obtained trademarks for our products, including DPP®, SURE CHECK®, and STAT-PAK® and also for the SampleTainer® used in certain DPP® products. Our DPP® trademark is also registered under the European convention (ECT). We recently filed a trademark for STAT-VIEW®, to market the barrel product in Europe. 
+Trade Secrets and Know-How 
+We believe that we have developed a substantial body of trade secrets and know-how relating to the development and manufacture of lateral flow and DPP®-based diagnostic tests, including but not limited to the sourcing and optimization of materials for such tests, and how to maximize sensitivity, speed-to-result, specificity, stability and reproducibility. We possess proprietary know-how to develop tests for multiple conditions using colored latex. Our buffer formulations enable extremely long shelf lives of our rapid HIV and other tests and we believe that this provides us with an important competitive advantage. 
+14 
+Lateral Flow Technology and Reagent Licenses 
+As part of the agreements executed in 2006 with Alere for the marketing of our HIV tests, we were granted non-exclusive licenses to certain lateral flow patents for certain products manufactured and marketed by us, including but not limited to our lateral flow HIV tests. This license allows us to produce, market and sell assays using lateral flow technologies specifically including our STAT-PAK®, SURE CHECK®, DIPSTICK®, and veterinary product lines. Under this license agreement, prior to February 3, 2015, we paid royalties to Alere ranging from 5% to 8½%, depending upon the country in which the products are sold. Between 2007 and 2015 we incurred a total of $2.87 million in lateral flow royalty expenses. As of February 3, 2015 this royalty expense was no longer payable. 
+Although we believe our DPP® is outside of the scope of all lateral flow patents of which we are aware, we consult with patent counsel, and seek licenses and/or redesigns of products that we believe to be in our best interests. Because of the costs and other negative consequences of time-consuming patent litigation, we often attempt to obtain a license on reasonable terms. Nevertheless there is no assurance that the Alere lateral flow patents we have licensed will not be challenged or that other patents containing claims relevant to our lateral flow or DPP® products will not be granted to third parties and that licenses to such patents, will be available on reasonable terms, if any. In the past Alere has aggressively enforced its lateral flow intellectual property, although some of the main patents have expired and we are not aware of any patent enforcement litigation that is ongoing with respect to the Alere lateral flow intellectual property. 
+Regardless, the DPP® technology provides us with our own intellectual property. We believe it provides us with a freedom to operate, and that it also enables tests to be developed with improved sensitivity as compared with comparable tests on lateral flow platforms. We have signed and anticipate signing new development projects based upon the DPP® technology that will provide new manufacturing and marketing opportunities. We have filed other patent applications that we believe will strengthen the DPP® intellectual property and have also filed for patent protection for certain other point-of-care technologies or applications thereof. 
+The peptides used in our rapid HIV tests were patented by Adaltis Inc. and were licensed to us under a 10-year non-exclusive license agreement dated August 30, 2002. However, in connection with Adaltis' bankruptcy, during the third quarter of 2009 we bought out all of our remaining obligations under that agreement. We also have licensed the antigens used in other tests including our Syphilis, Tuberculosis, Leptospirosis, Leishmaniasis and Chagas tests, and we may enter other license agreements. In prior years we concluded license agreements related to intellectual property rights owned by the United States associated with HIV-1, and during the first quarter of 2008 we entered into a sub-license agreement for HIV-2 with Bio-Rad Laboratories N.A., the exclusive licensee of the Pasteur Institute's HIV-2 intellectual property estate. 
+Corporate Information 
+We are a Nevada corporation that was formed in December 1985. Since inception, we have been involved in developing, manufacturing, selling and distributing medical diagnostic tests, including rapid tests that detect a number of diseases and other conditions in humans and animals. 
+On May 30, 2012, we effected a 1-for-8 reverse split of its common stock. The effect of this reverse stock split also has been retroactively reflected for all periods in these financial statements. 
+Stockholder Rights Agreement 
+On March 8, 2016, we entered into a Rights Agreement (the "Rights Agreement") between us and Action Stock Transfer Corp., as Rights Agent. Pursuant to the Rights Agreement, we declared a dividend distribution of one Preferred Share Purchase Right (a "Right") for each outstanding share of our common stock, par value $0.01 (the "Common Stock"), in the manner described below. The Board of Directors set the payment date for the distribution of the Rights as March 8, 2016, and the Rights were distributed to our shareholders of record on that date. The description and terms of the Rights are set forth in the Rights Agreement. 
+Rights Initially Not Exercisable. The Rights are not exercisable until a Distribution Date. Until a Right is exercised, the holder thereof, as such, has no rights as a shareholder of the Company, including, without limitation, the right to vote or to receive dividends. 
+15 
+Separation and Distribution of Rights . The Rights are to be evidenced by the certificates for shares of Common Stock registered in the names of the holders thereof, and not by separate rights certificates until the earlier to occur of (i) the close of business on the tenth business day following a public announcement that an Acquiring Person (as defined in the Rights Agreement) has acquired a Combined Ownership (as defined in the Rights Agreement) of 20% or more of the outstanding shares of the Common Stock (the "Shares Acquisition Date") or (ii) the later of (A) the close of business on the tenth business day (or such later date as may be determined by action of the Board of Directors prior to such time as any person or group of affiliated or associated persons becomes an Acquiring Person) after the date that a tender or exchange offer or intention to commence a tender or exchange offer by any person is first published, announced, sent or given within the meaning of Rule 14d-4(A) under the Securities Exchange Act of 1934, as amended, the consummation of which would result in any person having Combined Ownership of 20% or more of the outstanding shares of the Common Stock, or (B) if such a tender or exchange offer has been published, announced, sent or given before the date of the Rights Agreement, then the close of business on the tenth business day after the date the Rights Agreement was entered into (or such later date as may be determined by action of the Board of Directors prior to such time as any person becomes an Acquiring Person); (the earlier of such dates referred to in (i) and (ii), which date may include any such date that is after the date of the Rights Agreement but prior to the issuance of the Rights, being called the "Distribution Date"). 
+16 
+Glossary 
+AIDS 
+Acquired Immunodeficiency Syndrome. AIDS is caused by the Human Immunodeficiency Virus, HIV. 
+ALGORITHM (parallel or serial) 
+For rapid HIV testing this refers both to method or protocol (in developing countries to date) for using rapid tests from different manufacturers in combination to screen and confirm patients at the point-of-care, and may also refer to the specific tests that have been selected by an agency or ministry of health to be used in this way. A parallel algorithm uses two screening tests from different manufacturers and a tie-breaker test only if there is a discrepancy between the screening tests results. A serial algorithm only uses a second confirmatory test if there is a positive result from the screening test, meaning that the number of confirmatory tests used is equal to the positivity rate in the testing venue. A tie-breaker test resolves discrepancies between the screen and the confirmatory test. 
+ANTIBODY 
+A protein which is a natural part of the human immune system produced by specialized cells to neutralize antigens, including viruses and bacteria that invade the body. Each antibody producing cell manufactures a unique antibody that is directed against, binds to and eliminates one, and only one, specific type of antigen. 
+ANTIGEN 
+Any substance which, upon entering the body, stimulates the immune system leading to the formation of antibodies. Among the more common antigens are bacteria, pollens, toxins, and viruses. 
+ANVISA 
+The National Health Surveillance Agency of Brazil 
+ARVs 
+Anti-retroviral medications developed to fight AIDS 
+CDC 
+United States Centers for Disease Control and Prevention 
+CLIA waiver 
+Clinical Laboratory Improvement Act designation that allows simple tests to be performed in point-of-care settings such as doctor's offices, walk-in clinics and emergency rooms. 
+DIAGNOSTIC 
+Pertaining to the determination of the nature or cause of a disease or condition. Also refers to reagents or procedures used in diagnosis to measure proteins in a clinical sample. 
+FIOCRUZ 
+The Oswaldo Cruz Foundation of Brazil 
+FDA 
+United States Food and Drug Administration 
+IgG 
+IgG or Immunoglobulin G are proteins found in human blood. This protein is called an "antibody" and is an important part of the body's defense against disease. When the body is attacked by harmful bacteria or viruses, antibodies help fight these invaders. 
+IgM 
+IgM or Immunoglobulin M are proteins found in human blood. This protein is called an "antibody" and is an important part of the body's defense against disease. When the body is attacked by harmful bacteria or viruses, antibodies help fight these invaders. 
+NGO 
+Non-Governmental Organization 
+OTC 
+Over-the-Counter 
+PEPFAR 
+The President's Emergency Plan for AIDS Relief 
+PMA 
+Pre-Marketing Approval –FDA approval classification for a medical device that is not substantially equivalent to a legally marketed device or is otherwise required by statute to have an approved application. Rapid HIV tests must have an approved PMA application before marketing of such a product can begin. 
+PROTOCOL 
+A procedure pursuant to which an immunodiagnostic test is performed on a particular specimen in order to obtain the desired reaction. 
+REAGENT 
+A chemical added to a sample under investigation in order to cause a chemical or biological reaction which will enable measurement or identification of a target substance. 
+RETROVIRAL 
+A type of virus which contains the enzyme Reverse Transcriptase and is capable of transforming infected cells to produce diseases in the host such as AIDS. 
+SENSITIVITY 
+Refers to the ability of an assay to detect and measure small quantities of a substance of interest. The greater the sensitivity, the smaller the quantity of the substance of interest the assay can detect. Also refers to the likelihood of detecting the antigen when present. 
+SPECIFICITY 
+The ability of an assay to distinguish between similar materials. The greater the specificity, the better an assay is at identifying a substance in the presence of substances of similar makeup. 
+USDA 
+U.S Department of Agriculture 
+WHO 
+World Health Organization 
+17 
+ITEM 1A. 
+RISK FACTORS 
+You should carefully consider each of the following risk factors and all of the other information provided in this Form 10-K before purchasing our Common Stock. The risks described below are those we currently believe may materially affect us. An investment in our Company involves a high degree of risk, and should be considered only by persons who can afford the loss of their entire investment. Although we believe that these risks are the most important for you to consider, you should read this section in conjunction with our financial statements, the notes to those financial statements and our management's discussion and analysis of financial condition and results of operations included in our periodic reports and incorporated into this prospectus supplement by reference. 
+Risks related to our industry, business and strategy 
+Because we may not be able to obtain or maintain the necessary regulatory approvals for some of our products, we may not generate revenues in the amounts we expect, or in the amounts necessary to continue our business. Our existing products as well as our manufacturing facility must meet quality standards and are subject to inspection by a number of domestic regulatory and other governmental and non-governmental agencies. 
+All of our proposed and existing products are subject to regulation in the U.S. by the U.S. Food and Drug Administration, the U.S. Department of Agriculture and/or other domestic and international governmental, public health agencies, regulatory bodies or non-governmental organizations. In particular, we are subject to strict governmental controls on the development, manufacture, labeling, distribution and marketing of our products. The process of obtaining required approvals or clearances varies according to the nature of, and uses for, a specific product. These processes can involve lengthy and detailed laboratory testing, human or animal clinical trials, sampling activities, and other costly, time-consuming procedures. The submission of an application to a regulatory authority does not guarantee that the authority will grant an approval or clearance for that product. Each authority may impose its own requirements and can delay or refuse to grant approval or clearance, even though a product has been approved in another country. 
+The time taken to obtain approval or clearance varies depending on the nature of the application and may result in the passage of a significant period of time from the date of submission of the application. Delays in the approval or clearance processes increase the risk that we will not succeed in introducing or selling the subject products, and we may determine to devote our resources to different products. 
+Changes in government regulations could increase our costs and could require us to undergo additional trials or procedures, or could make it impractical or impossible for us to market our products for certain uses, in certain markets, or at all. 
+Changes in government regulations may adversely affect our financial condition and results of operations because we may have to incur additional expenses if we are required to change or implement new testing, manufacturing and control procedures. If we are required to devote resources to develop such new procedures, we may not have sufficient resources to devote to research and development, marketing, or other activities that are critical to our business. 
+We can manufacture and sell our products only if we comply with regulations and quality standards established by government agencies such as the FDA and the USDA as well as by non-governmental organizations such as the ISO and WHO. We have implemented a quality control system that is intended to comply with applicable regulations. Although FDA approval is not required for the export of our products, there are export regulations promulgated by the FDA that specifically relate to the export of our products that require compliance with FDA quality system regulation ("QSRs") and that also require meeting certain documentary requirements regarding the approval of the product in export markets. Although we believe that we meet the regulatory standards required for the export of our products, these regulations could change in a manner that could adversely impact our ability to export our products. 
+Our products may not be able to compete with new diagnostic products or existing products developed by well-established competitors, which would negatively affect our business. 
+The diagnostic industry is focused on the testing of biological specimens in a laboratory or at the point-of-care and is highly competitive and rapidly changing. Some of our principal competitors may have considerably greater financial, technical and marketing resources than we do. Several companies produce diagnostic tests that compete directly with our testing product line, including but not limited to, OraSure Technologies, Alere and Trinity Biotech. Furthermore these and/or other companies have or may have products incorporating molecular and/or other advanced technologies that over time could directly compete with our testing product line. As new products incorporating new technologies enter the market, our products may become obsolete or a competitor's products may be more effective or more effectively marketed and sold. 
+18 
+There are competing products that could significantly reduce our U.S. sales of rapid HIV tests. 
+In 2006 Alere, Inc. acquired a division from Abbott Diagnostic located in Japan that manufactured and marketed a rapid HIV test product line called Determine®. The Determine® format was developed for the developing world and remote settings and, central to the needs of that market. The format is essentially a test strip that is integrated into a thin foil wrapper. When opened, the underside of the wrapper serves as the test surface for applying the blood sample and performing the test. This design reduces costs and shipping weights and volumes and provides an advantage for the developing world markets it serves. Some of the disadvantages of the platform are the amount of blood sample that is needed (50 microliters versus 2.5, 5 and 10 for our lateral flow barrel, lateral flow cassette, and DPP® products respectively), the open nature of the test surface, and the absence of a true control that differentiates biological from other kinds of samples. 
+The so-called "3rd generation" version of this product has been marketed for many years and is the leading rapid HIV test that is used in a large majority of the national algorithms of countries funded by PEPFAR and the Global Fund, as well as many other countries in the world. That product is not FDA-approved though it is CE marked. The newest Determine® HIV version, which was developed and manufactured by Alere's subsidiary in Israel, Orgenics, is the so-called "4th Generation" version Determine® test. According to its claims, this product detects HIV antibodies and P24 HIV antigens. Because the P24 antigen is known to occur in HIV-positive individuals' blood samples before antibodies do, the 4th generation Determine® test is designed to detect HIV infection earlier than tests that solely rely on antibody detection. Chembio's tests, as well as all of the other currently FDA-approved rapid HIV tests, only detect antibodies. There are however laboratory tests that are FDA-approved that are "4th generation" tests, but they are neither rapid nor point-of-care. 
+The initial "4th generation" Alere Determine® rapid test product that was also CE marked and that Alere launched internationally some years ago has not been successfully commercialized to the best of our knowledge and at least certain published studies were not favorable for this product. The 4th generation product that is now FDA-approved was apparently modified as compared to the initial international version, and it may perform more satisfactorily. Alere received FDA approval of this modified product in August 2013 and CLIA waiver for it in December 2014. Alere is also aggressively pursuing development of the market for this product. Moreover there is support by a number of key opinion leaders for the public health value of such 4th generation tests, and this product represents a significant competitive threat to Chembio as well as to each of the other rapid HIV test manufacturers (OraSure and Trinity primarily). 
+During 2011, Biolytical, Inc. of Vancouver, Canada received FDA approval and in 2012 received CLIA waiver of a flow-through rapid HIV test called "INSTI". The flow-through technology used in the INSTI test is older than lateral flow, and requires handling of multiple components (3 vials of solution) to perform the test in multiple steps. However, these steps can be accomplished in less than ten minutes, and the actual test results occur in only one minute after those steps are completed. Therefore sample-to-result time is shorter than any of the competitive products. The product also has good performance claims. There are settings where that reduced total test time, despite the multiple steps required, may be a distinct advantage, and we believe Biolytical has made some progress in penetrating certain public health markets. 
+Therefore, even though our lateral flow products currently enjoy a substantial market share in the U.S. rapid HIV test market, and we have an additional rapid HIV test, the DPP® HIV 1/2 Assay, there a number of risks and uncertainties concerning current and anticipated developments in this market. Although we have no specific knowledge of any other new product that is a significant competitive threat to our products, or that will render our products obsolete, if we fail to maintain and enhance our competitive position or fail to introduce new products and product features, our customers may decide to use products developed by our competitors, which could result in a loss of revenues and cash flow. 
+More generally, the point-of-care diagnostics industry is undergoing rapid technological changes, with frequent introductions of new technology-driven products and services. As new technologies become introduced into the point-of-care diagnostic testing market, we may be required to commit considerable additional efforts, time and resources to enhance our current product portfolio or develop new products. We may not have the available time and resources to accomplish this, and many of our competitors have substantially greater financial and other resources to invest in technological improvements. We may not be able to effectively implement new technology-driven products and services or be successful in marketing these products and services to our customers, which would materially harm our operating results. 
+Although we own our DPP® patent, lateral flow technology is still a competitive platform to DPP®, and lateral flow technology has a lower cost of manufacture than DPP® products. Although the DPP® platform has shown improved sensitivity as compared with conventional lateral flow platforms in a number of studies, several factors go into the development and performance attributes of products. Therefore the ability of our products to successfully compete will depend on several other factors, including but not limited to our having a patented rapid test platform technology that differentiates DPP® from lateral flow as well as from other diagnostic platform technologies. 
+19 
+We believe that our DPP® is outside of the scope of currently issued patents in the field of lateral flow technology, thereby offering the possibility of greater freedom to operate. However there can be no assurance that our patents or our products incorporating the patent claims will not be challenged at some time in the future. 
+Our use of third-party suppliers, some of which may constitute our sole supply source, for certain important product components presents a risk that could have negative consequences for other business. 
+A number of our components and critical raw materials are provided by third-party suppliers, some of which may be sole-source suppliers, which impacts our ability to manufacture or sell certain products if our suppliers cannot or will not deliver those materials in a timely fashion, or at all, due to an interruption in their supply, quality or technical issues, or any other reason. If this occurs, we could incur substantial expense and time to be able to reestablish the appropriate quality, cost, regulatory and market-acceptance circumstances needed for commercial success. Even with the needed expense and time, we may not be able to reestablish any or all of these factors. The absence of any one or more of these factors could prevent us from being able to commercially produce and market the affected product or products. 
+New developments in health treatments or new non-diagnostic products may reduce or eliminate the demand for our products. 
+The development and commercialization of products outside of the diagnostics industry could adversely affect sales of our products. For example, the development of a safe and effective vaccine to HIV or treatments for other diseases or conditions that our products are designed to detect, could reduce or eventually eliminate the demand for our HIV or other diagnostic products and result in a loss of revenues. 
+We may not have sufficient resources to effectively introduce and market our products, which could materially harm our operating results. 
+Introducing and achieving market acceptance for our rapid HIV tests and other new products will require substantial marketing efforts and will require us and/or our contract partners, sales agents, and/or distributors to make significant expenditures of time and money. In some instances we will be significantly or totally reliant on the marketing efforts and expenditures of our contract partners, sales agents, and/or distributors. If they do not have or commit the expertise and resources to effectively market the products that we manufacture, our operating results will be materially harmed. 
+The success of our business depends on, in addition to the market success of our products, our ability to raise additional capital through the sale of debt or equity or through borrowing, and we may not be able to raise capital or borrow funds on attractive terms and/or in amounts necessary to continue our business, or at all. 
+We were profitable for five consecutive years through 2013. Nevertheless, prior to 2009 we sustained significant operating losses since 2004, and we incurred an operating loss for 2014, 2015 and 2016. We estimate that our resources are sufficient to fund our needs through the end of 2017 and beyond. We have already made, and may continue to make, significant financial commitments to invest in our sales and marketing organization, regulatory approvals, research and development including new technologies, and production capacity, including expanded facilities. 
+Our liquidity and cash requirements will depend on several factors. These factors include, among others, (1) the level of revenues; (2) the extent to which, if any, that revenue level improves operating cash flows; (3) our investments in research and development, facilities, marketing, regulatory approvals, and other investments we may determine to make; and (4) our investment in capital equipment and the extent to which it improves cash flow through operating efficiencies. There are no assurances that we will generate positive cash flow for 2017 or, in the alternative, be successful in raising sufficient capital to fund our needs after 2017. 
+Our U.S. market sales are difficult to predict in 2017 given (i) our early June 2014 termination of the agreement with a third party for exclusive distribution of our cassette product in the U.S; and (ii) the May 31, 2016 termination of the agreement with a third party for exclusive distribution of our barrel product in the U.S. As a result of these terminations, we expect to continue to experience higher average revenue per unit, and a lower volume of U.S. sales, of the cassette and barrel products. Higher revenue per unit is anticipated because we previously sold these products to the exclusive U.S. distributor at a significantly lower price than the price at which the distributor resold these products to customers (including re-sellers and distributors) in the United States. However at this point with respect to the barrel product, this can occur only after any inventory that the exclusive U.S. distributor has accumulated is consumed, which may take several months. In addition, in marketing these products directly, we are incurring substantial costs associated with developing our sales and marketing organization and channel distribution partners. 
+20 
+We believe that underlying demand for HIV rapid testing in the United States remains strong, and that the restoration of some of the funding cutbacks from sequestration and the implementation of the Affordable Care Act and of the United States Preventive Services Task Force recommendations will have a positive impact on the development of the market. On the other hand, it is possible that changes to healthcare law in 2017 and thereafter could change this and/or have a negative impact on the market for our products. Further, our products are well established and relied upon by a large installed base of customers over many years of use in the U.S. global market, and we believe this is a strong advantage. We also believe that our DPP® HIV 1/2 Assay for which CLIA waiver was obtained in October 2014, for use with oral fluid or bloods samples will be able to serve new customers that were previously unavailable to us with our lateral flow blood tests. However, development of new customers with this product is costly and time-consuming. 
+We are attempting to increase international sales of our products, and we have invested in additional resources in connection with this effort; but as we have experienced, the nature of international business is such that it can be volatile from period to period, depending on ordering patterns of donor-funded programs. 
+Furthermore, a number of factors can slow or prevent international sales increases or cause international sales decreases, or substantially increase the cost of achieving sales assuming they are achieved. These factors include: 
+· 
+economic conditions and the absence of or reduction in available funding sources; 
+· 
+regulatory requirements and customs regulations; 
+· 
+cultural and political differences; 
+· 
+foreign exchange rates, currency fluctuations and tariffs; 
+· 
+dependence on and difficulties in managing international distributors or representatives; 
+· 
+the creditworthiness of foreign entities; 
+· 
+difficulties in foreign accounts receivable collection; 
+· 
+competition 
+· 
+pricing; and 
+· 
+any inability we may have in maintaining or increasing revenues. 
+If we are unable to maintain or increase our revenues from domestic and/or international customers, our operating results will be materially harmed. 
+Although we have an ethics and anti-corruption policy in place, and have no knowledge or reason to know of any practices by our employees, agents or distributors that could be construed as in violation of such policies, our business includes sales of products to countries where there is or may be widespread corruption. 
+We have a policy in place prohibiting our employees, distributors and agents from engaging in corrupt business practices, including activities prohibited by the United States Foreign Corrupt Practices Act (the "FCPA"). Nevertheless, because we work through independent sales agents and distributors (and do not have any employees or subsidiaries) outside the United States, we do not have control over the day-to-day activities of such independent agents and distributors. In addition, in the donor-funded markets in Africa where we sell our products, there is significant oversight from PEPFAR, the Global Fund, and advisory committees comprised of technical experts concerning the development and establishment of national testing protocols. This is a process that includes an overall assessment of a product which includes extensive product performance evaluations including five active collaborations and manufacturer's quality systems, as well as price and delivery. In Brazil, where we have had a total of six product collaborations with FIOCRUZ, the programs through which our products may be deployed are all funded by the Brazilian Ministry of Health. Although FIOCRUZ is affiliated with the Brazilian Ministry of Health, and is its sole customer, FIOCRUZ is not the exclusive supplier for the Ministry of Health. However, because each of our previous collaborations with FIOCRUZ incorporates a technology transfer aspect, we believe we have a competitive advantage versus other suppliers to the Brazilian Ministry of Health, assuming other aspects of our product offering through FIOCRUZ are otherwise competitive in comparison. We have no knowledge or reason to know of any activities by our employees, distributors or sales agents of any actions which could be in violation of the FCPA, although there can be no assurance of this. 
+21 
+We rely on trade secret laws and agreements with our key employees and other third parties to protect our proprietary rights, and we cannot be sure that these laws or agreements adequately protect our rights. 
+We believe that factors such as the technological and creative skills of our personnel, strategic relationships, new product developments, frequent product enhancements and name recognition are essential to our success. All our management personnel are bound by non-disclosure agreements. If personnel leave our employment, in some cases we would be required to protect our intellectual property rights pursuant to common law theories which may be less protective than provisions of employment, non-competition or non-disclosure agreements. 
+We seek to protect our proprietary products under trade secret and copyright laws, enter into license agreements for various materials and methods employed in our products, and enter into strategic relationships for distribution of the products. These strategies afford only limited protection. We currently have some foreign patents issued, and we are seeking additional patent protection in several other foreign jurisdictions for our DPP® technology. We have licenses to reagents (antigens and peptides) used in several of our products and products under development. Despite our efforts to protect our proprietary assets, and respect the intellectual property rights of others, we participate in several markets where intellectual property rights protections are of little or no value. This can place our products and our company at a competitive disadvantage. 
+Despite the efforts we make to protect our confidential information, such as entering into confidentiality agreements in connection with new business opportunities, unauthorized parties may attempt to copy aspects of our products or to obtain information that we regard as proprietary. We may be required to expend substantial resources in asserting or protecting our intellectual property rights, or in defending suits related to intellectual property rights. Disputes regarding intellectual property rights could substantially delay product development or commercialization activities because some of our available funds would be diverted away from our business activities. Disputes regarding intellectual property rights might include state, federal or foreign court litigation as well as patent interference, patent reexamination, patent reissue, or trademark opposition proceedings in the U.S. Patent and Trademark Office. 
+To facilitate development and commercialization of a proprietary technology base, we may need to obtain additional licenses to patents or other proprietary rights from other parties. Obtaining and maintaining these licenses, which may not be available, may require the payment of up-front fees and royalties. In addition, if we are unable to obtain these types of licenses, our product development and commercialization efforts may be delayed or precluded. 
+Our continued growth depends on retaining our current key employees and attracting additional qualified personnel, and we may not be able to do so. 
+Our success will depend to a large extent upon the skills and experience of our executive officers, management and sales, marketing, operations and scientific staff. We may not be able to attract or retain qualified employees in the future due to the intense competition for qualified personnel among medical products businesses, geographic considerations, our ability to offer competitive compensation, relocation packages, benefits, and/or other reasons. 
+If we are not able to attract and retain the necessary personnel to accomplish our business objectives, we may experience constraints that will adversely affect our ability to effectively manufacture, sell and market our products to meet the demands of our strategic partners in a timely fashion, or to support internal research and development programs. Although we believe we will be successful in attracting and retaining qualified personnel, competition for experienced scientists and other personnel from numerous companies and academic and other research institutions may limit our ability to do so on acceptable terms. 
+We have entered into employment contracts with our Chief Executive Officer, John Sperzel, our Chief Operating Officer, Sharon Klugewicz, and our Chief Scientist & Technology Officer, Javan Esfandiari. Due to the specific knowledge and experience of these executives regarding the industry, technology and market, the loss of the services of any one of them could have a material adverse effect on the Company. The contract with Mr. Sperzel has a term of three years ending March 2017. The contract with Ms. Klugewicz has a term of two years ending May 2017. The contract with Mr. Esfandiari has a term of three years ending March 2019. The Company has obtained a key man insurance policy on Mr. Esfandiari. The Company and Mr. Sperzel currently are discussing terms for renewal of his employment agreement. 
+22 
+We believe our success depends in part on the continued funding of and our ability to participate in large testing programs in the U.S. and worldwide. Funding of these and or similar programs may be reduced, discontinued and/or we may not be able to participate for other reasons. 
+We believe it to be in our best interests to meaningfully participate in large testing programs. Moreover many of these programs are funded by governments and other donors, and there can be no assurance that funding will not be reduced or completely discontinued. Participation in these programs also requires alignment and engagement with the many other participants in these programs, including WHO, CDC, U.S. Agency for International Development, foreign governments and their agencies, non-governmental organizations, and HIV service organizations. If we are unsuccessful in our efforts to participate in these programs, our operating results could be materially harmed. 
+In December 2013 President Obama signed into law the PEPFAR Stewardship and Oversight Act, which is the most recent reauthorization of PEPFAR. However, unlike the 2008 PEPFAR authorization, which authorized approximately $45 billion in funding, the new law does not authorize a specific dollar amount for funding. 
+To the extent that we are unable to collect our outstanding accounts receivable, our operating results could be materially harmed. 
+There may be circumstances and timing that require us to accept payment terms, including delayed payment terms, from distributors or customers, which, if not satisfied, could cause financial losses. 
+We generally accept payment terms which require us to ship product before the contract price has been paid fully, and there also are circumstances pursuant to which we may accept further delayed payment terms pursuant to which we may continue to deliver product. To the extent that these circumstances result in significant accounts receivables and those accounts receivables are not paid on a timely basis, or are not paid at all, especially if concentrated in one or two customers, we could suffer financial losses. 
+Although we were profitable from 2009 through 2013, we incurred a net loss for 2014, 2015 and 2016 and cannot be certain that we will be able to sustain profitability in the future. 
+From the inception of Chembio Diagnostic Systems, Inc. in 1985 through the period ended December 31, 2008, we incurred net losses. We were then profitable each year from 2009 through 2013. In 2014, 2015 and 2016, we made substantial expenditures for sales and marketing, regulatory submissions, product development, production and warehouse capacity, and other purposes, and we incurred a net operating loss. Our ability to re-achieve profitability in the future will primarily depend on our ability to increase sales of our products based on having made the aforementioned expenditures to reduce production and other costs, and to successfully introduce new products and enhanced versions of our existing products into the marketplace. If we are unable to increase our revenues at a rate that is sufficient to achieve profitability, or adequately control and reduce our operating costs, our operating results would be materially harmed. 
+To the extent that we are unable to obtain sufficient product liability insurance or that we incur product liability exposure that is not covered by our product liability insurance, our operating results could be materially harmed. 
+We may be held liable if any of our products, or any product which is made with the use or incorporation of any of the technologies belonging to us, causes injury of any type or is found otherwise unsuitable during product testing, manufacturing, marketing, sale or use. We have obtained product liability insurance even though we have never received a product liability claim, and have generally not seen product liability claims for screening tests that are accompanied by appropriate disclaimers. Nevertheless, in the event there is a claim, this insurance may not fully cover our potential liabilities. In addition, as we attempt to bring new products to market, we may need to increase our product liability coverage which could be a significant additional expense that we may not be able to afford. If we are unable to obtain sufficient insurance coverage at an acceptable cost to protect us, we may be forced to abandon efforts to commercialize our products or those of our strategic partners, which would reduce our revenues. 
+23 
+Risks related to our Common Stock 
+Our Common Stock continues to be illiquid, so investors may not be able to sell as much stock as they want at prevailing market prices. 
+The average daily trading volume of our Common Stock on the NASDAQ market was approximately 19,300 shares per day over the three months ended December 31, 2016 as compared with approximately 21,600 shares per day over the three months ended December 31, 2015. The liquidity of our stock depends on several factors, including but not limited to the financial results of the Company and overall market conditions, so it is not possible to predict whether this level of liquidity will continue, be sustained, or decrease. 
+Decreased trading volume in our stock would make it more difficult for investors to sell their shares in the public market at any given time at prevailing prices. Our management and larger stockholders exercise significant control over the Company. 
+Our management and larger stockholders exercise significant control over the Company. 
+As of December 31, 2016, our named executive officers, directors and 5% stockholders beneficially owned approximately 38.43% of our voting power, which includes four large investors that beneficially own approximately 10.36%, 9.36%, 9.00% and 5.02%, respectively of the outstanding stock. For the foreseeable future, and assuming these ownership percentages continue to apply, to the extent that these parties vote similarly, they may be able to exercise significant control over many matters requiring approval by the board of directors or our stockholders. As a result, they may be able to: 
+· 
+control the composition of our board of directors; 
+· 
+control our management and policies; 
+· 
+determine the outcome of significant corporate transactions, including changes in control that may be beneficial to stockholders; and 
+· 
+act in each of their own interests, which may conflict with or differ from the interests of each other or the interests of the other stockholders. 
+24 
+ITEM 1B. Unresolved Staff Comments. 
+Not Applicable 
+ITEM 2. 
+PROPERTIES 
+Our manufacturing, administrative offices and research facilities are located in Medford, New York. In addition we have warehousing space as well as some additional administrative offices located in Holbrook, New York. We lease approximately 39,660 square feet of industrial space in Medford for $28,688 per month. The space is utilized for research and development activities (approximately 5,440 square feet), offices (approximately 2,640 square feet) and production (approximately 31,580 square feet). The lease term expires on April 30, 2017. The lease provides for annual increases of two and one-half percent each year starting May 1, 2015. We lease approximately 21,450 square feet of industrial space in Holbrook for $15,550 per month. The space is utilized for offices (approximately 2,500 square feet) and warehousing (approximately 18,950 square feet). The lease term expires on April 30, 2018. The lease provides for annual increases of three percent each year starting March 1, 2015. The Company believes this space should be sufficient for its needs in the foreseeable future. 
+ITEM 3. 
+LEGAL PROCEEDINGS 
+From time to time, we may be involved in litigation relating to claims arising out of our operations in the normal course of business. We know of no material, existing or pending legal proceedings against us, nor are we involved as a plaintiff in any material proceeding or pending litigation. There are no proceedings in which any of our directors, officers or affiliates, or any registered or beneficial shareholder, is an adverse party or has a material interest that is adverse to our interest. 
+ITEM 4. 
+MINE SAFETY DISCLOSURES 
+Not Applicable. 
+25 
+PART II 
+ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+Market Information 
+Our stock is listed on the NASDAQ Global Select Market of the NASDAQ Stock Market LLC under the symbol "CEMI." The table below sets forth the high and low prices per share of our common stock for each quarter of our two most recently completed fiscal years. 
+Fiscal Year 2016 
+High 
+Low 
+First Quarter 
+$ 
+6.10 
+$ 
+4.03 
+Second Quarter 
+$ 
+9.40 
+$ 
+5.87 
+Third Quarter 
+$ 
+8.48 
+$ 
+5.08 
+Fourth Quarter 
+$ 
+7.45 
+$ 
+6.10 
+Fiscal Year 2015 
+High 
+Low 
+First Quarter 
+$ 
+4.20 
+$ 
+3.47 
+Second Quarter 
+$ 
+5.25 
+$ 
+4.00 
+Third Quarter 
+$ 
+5.20 
+$ 
+3.33 
+Fourth Quarter 
+$ 
+5.53 
+$ 
+3.90 
+Holders 
+As of March 3, 2017, there were approximately 2,030 record owners of our common stock (including nominee holders such as banks and brokerage firms who hold shares for beneficial owners). 
+Dividends 
+The Company has never paid cash dividends on its common stock and has no plans to do so in the foreseeable future. Any future declaration of dividends will be determined by our Board of Directors in its sole discretion and will depend on, among other things, our earnings, capital requirements, financial condition, prospects and any other factors the Board of Directors may deem relevant. 
+Recent Sales of Unregistered Securities 
+There were no sales of unregistered securities during the year ended December 31, 2016 that were not previously reported on a Quarterly Report on Form 10-Q or a Current Report on Form 10-K. 
+Issuer Purchases of Equity Securities 
+We did not repurchase any of our equity securities during the fourth quarter of the fiscal year ended December 31, 2016. 
+26 
+ITEM 6. 
+SELECTED FINANCIAL DATA 
+The Following selected financial data should be read in connection with Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the consolidated financial statements and notes that are included in this Annual Report on Form 10-K. 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+SELECTED HISTORICAL FINANCIAL DATA 
+As of and For the Years Ended 
+Statement of Operations Data: 
+December 31, 2016 
+December 31, 2015 
+December 31, 2014 
+December 31, 2013 
+December 31, 2012 
+TOTAL REVENUES 
+$ 
+17,868,841 
+$ 
+24,255,485 
+$ 
+27,645,284 
+$ 
+29,549,609 
+$ 
+25,610,595 
+GROSS MARGIN (1) 
+8,451,336 
+47 
+% 
+10,486,827 
+43 
+% 
+10,814,023 
+39 
+% 
+12,300,159 
+42 
+% 
+10,789,991 
+42 
+% 
+OPERATING COSTS: 
+Research and development expenses (1) 
+8,427,554 
+47 
+% 
+6,377,839 
+26 
+% 
+4,832,537 
+17 
+% 
+5,834,249 
+20 
+% 
+4,486,302 
+18 
+% 
+Selling, general and administrative expenses (1) 
+7,595,559 
+43 
+% 
+7,663,035 
+32 
+% 
+7,531,739 
+27 
+% 
+5,461,083 
+18 
+% 
+4,851,587 
+19 
+% 
+16,023,113 
+14,040,874 
+12,364,276 
+11,295,332 
+9,337,889 
+INCOME (LOSS) FROM OPERATIONS 
+(7,571,777 
+) 
+(3,554,047 
+) 
+(1,550,253 
+) 
+1,004,827 
+1,452,102 
+OTHER INCOME (EXPENSES): 
+25,548 
+(3,238 
+) 
+132 
+12,943 
+(1,584 
+) 
+INCOME (LOSS) BEFORE INCOME TAXES (1) 
+(7,546,229 
+) 
+(42 
+)% 
+(3,557,285 
+) 
+(15 
+)% 
+(1,550,121 
+) 
+(6 
+)% 
+1,017,770 
+3 
+% 
+1,450,518 
+6 
+% 
+Income tax provision (benefit) 
+5,800,818 
+(1,160,243 
+) 
+(412,918 
+) 
+486,952 
+509,237 
+NET INCOME (LOSS) 
+$ 
+(13,347,047 
+) 
+$ 
+(2,397,042 
+) 
+$ 
+(1,137,203 
+) 
+$ 
+530,818 
+$ 
+941,281 
+Basic income (loss) per share 
+$ 
+(1.26 
+) 
+$ 
+(0.25 
+) 
+$ 
+(0.12 
+) 
+$ 
+0.06 
+$ 
+0.12 
+Diluted income (loss) per share 
+$ 
+(1.26 
+) 
+$ 
+(0.25 
+) 
+$ 
+(0.12 
+) 
+$ 
+0.06 
+$ 
+0.11 
+Weighted average number of shares outstanding, basic 
+10,622,331 
+9,626,028 
+9,530,320 
+8,994,080 
+7,986,030 
+Weighted average number of shares outstanding, diluted 
+10,622,331 
+9,626,028 
+9,530,320 
+9,519,968 
+8,614,944 
+Balance Sheet Data: 
+Working capital 
+$ 
+14,707,876 
+$ 
+9,479,968 
+$ 
+12,372,169 
+$ 
+14,221,011 
+$ 
+7,630,368 
+Total assets 
+20,575,236 
+20,816,344 
+25,010,192 
+24,486,592 
+17,335,150 
+Total liabilities 
+3,405,650 
+3,154,838 
+5,286,030 
+4,309,490 
+3,460,630 
+Shareholders' equity 
+17,169,586 
+17,661,506 
+19,724,162 
+20,177,102 
+13,874,520 
+(1) percentage shown reflects the percentage of total revenues 
+27 
+ITEM 7. 
+MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+Overview 
+This discussion and analysis should be read in conjunction with the accompanying Consolidated Financial Statements and related notes. Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of any contingent liabilities at the financial statement date and reported amounts of revenue and expenses during the reporting period. On an ongoing basis, we review our estimates and assumptions. Our estimates are based on our historical experience and other assumptions that we believe to be reasonable under the circumstances. Actual results are likely to differ from those estimates under different assumptions or conditions, but we do not believe such differences will materially affect our financial position or results of operations. Our critical accounting policies, the policies we believe are most important to the presentation of our financial statements and require the most difficult, subjective and complex judgments, are outlined below in ''Critical Accounting Policies,'' and have not changed significantly. 
+In addition, certain statements made in this report may constitute "forward-looking statements" 
+These forward-looking statements involve known or unknown risks, uncertainties and other factors that may cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. These factors include, among others, 1) our ability to obtain necessary regulatory approvals for our products; and 2) our ability to increase revenues and operating income, which is dependent upon our ability to develop and sell our products, general economic conditions, demand for our products, and other factors. You can identify forward-looking statements by terminology such as "may," "could", "will," "should," "expects," "intends," "plans," "anticipates," "believes," "estimates," "predicts," "potential," "continues" or the negative of these terms or other comparable terminology. Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance or achievements. 
+Except as may be required by applicable law, we do not undertake or intend to update or revise our forward-looking statements, and we assume no obligation to update any forward-looking statements contained in this report as a result of new information or future events or developments. Thus, you should not assume that our silence over time means that actual events are bearing out as expressed or implied in such forward-looking statements. You should carefully review and consider the various disclosures we make in this report and our other reports filed with the Securities and Exchange Commission that attempt to advise interested parties of the risks, uncertainties and other factors that may affect our business. 
+All of the Company's future products that are currently being developed are based on its patented Dual Path Platform (DPP®), which is a unique diagnostic point-of-care platform that has certain advantages over lateral flow technology. The Company has completed development of several products that employ the DPP® technology. These products are currently marketed under Chembio's label (DPP® HIV 1/2 Screening Assay and DPP® HIV 1/2 –Syphilis Assay), or which may be marketed pursuant to private label license or distribution agreements such as those with the Oswaldo Cruz Foundation ("FIOCRUZ"), and Bio-Rad. 
+Research and development ("R&D"), milestone, and grant and royalty revenues for the years ended December 31, 2016, 2015 and 2014 were $4.19 million, $2.37 million and $1.70 million, respectively, which was the result of grants awarded in 2016, 2015 and 2014. R&D expenses in the years ended December 31, 2016, 2015 and 2014 were $8.43 million, $6.38 million and $4.83 million, respectively. 
+Research & Development Activities 
+Sexually Transmitted Disease 
+· 
+DPP® HIV-Syphilis Assay : The DPP® HIV-Syphilis Assay is a rapid, point-of-care (POC), multiplex test for the simultaneous detection of antibodies to HIV and to Treponema Pallidum (TP) bacteria (the causative agent of syphilis). This novel combination assay was developed to address the growing concern among public health officials regarding the rising co-infection rates of HIV and syphilis as well as mother-to-child transmission (MTCT) of HIV and syphilis. The product received approval by the Mexican regulatory agency (Cofepris) in 2014, received approval by the Brazilian regulatory agency, Agência Nacional de Vigilância Sanitária (ANVISA) in 2015, and received CE mark approval in 2017. We are developing a U.S. version of the DPP® HIV-Syphilis Assay, designed to meet the performance requirements for the "reverse" algorithm that is currently in clinical use for syphilis testing in the United States. The DPP® HIV-SYP Assay clinical trial is on schedule; initiated in the first quarter of 2016 and, at the current enrollment rate, we expect to complete the trial in the first quarter of 2017. Following the completion of the clinical trial, we will file a Premarket Approval Application with the U.S. Food and Drug Administration. 
+28 
+Fever & Tropical Disease 
+· 
+DPP® Malaria Assay : The DPP® Malaria Assay is a rapid, POC, multiplex test for the simultaneous detection of plasmodium falciparum and other plasmodium infections. In January 2015, we received a grant from the Bill & Melinda Gates Foundation to expedite the development and feasibility testing of a POC DPP® Malaria Assay. The Company completed this project, which compared the new DPP ® Malaria Assay to the world's leading currently-available POC malaria assay with favorable results: a ten-fold improvement in sensitivity. In April 2016, we received a second Malaria grant from the Bill & Melinda Gates Foundation to expedite the feasibility testing and development of the world's first oral fluid/saliva POC diagnostic test to simply and accurately identify individuals infected with all species of malaria. We recently completed the feasibility and plan to deliver DPP ® Malaria Assays to a partner of the Bill & Melinda Gates Foundation in March 2017, to commence field evaluation. 
+· 
+DPP® Zika Assay : The DPP® Zika Assay is a rapid POC stand-alone test for the simultaneous detection of IgM/IgG antibodies. In February 2016, we received a grant from The Paul G. Allen Family Foundation to initiate development of the DPP® Zika Assay. During 2016, Chembio announced collaborations with Bio-Manguinhos, the unit of the Oswaldo Cruz Foundation (Fiocruz) responsible for the development and production of vaccines, diagnostics and biopharmaceuticals, primarily to meet the demands of Brazil's national public health system, related to the DPP® Zika Assay. In August 2016, the Company received an award from the U.S. Government (HHS/ASPR/BARDA), granting the Company up to $13.2 million ($5.9 million to develop DPP® Zika Assay and obtain U.S. regulatory approval). The Company filed the following regulatory submissions: U.S. Food and Drug Administration Emergency Use Authorization (EUA), World Health Organization EUA, Brazil's regulatory agency ANVISA, Mexico's regulatory agency Cofepris, and CE mark. The Company obtained CE mark in July 2016, and then began selling in the Caribbean region via its distribution partner, Isla Lab, LLC. In September 2016, the Company received a contract award from CDC to initiate a Zika surveillance program in India, Peru, Guatemala and Haiti, and we began selling the DPP® Zika IgM/IgG Assay to CDC for field testing purposes during the first quarter of 2017. The Company received ANVISA approval (Brazil) for the DPP® Zika IgM/IgG Assay in November 2016 and is working with our Brazilian partner, Bio-Manguinhos, to obtain ANVISA approval for the DPP® Micro Reader. 
+· 
+DPP® Dengue Fever Assay : The DPP® Dengue Fever Assay is a rapid, POC, multiplex test for the simultaneous detection of IgG/IgM and NS1 antigens. During 2016, Chembio announced collaborations with Bio-Manguinhos, the unit of the Oswaldo Cruz Foundation (Fiocruz) responsible for the development and production of vaccines, diagnostics and biopharmaceuticals, primarily to meet the demands of Brazil's national public health system related to the DPP® Dengue Fever Assay. We completed verification and validation studies, and production of pilot lots, to support preclinical studies. Also during 2016, we initiated registration to begin initial commercialization in Southeast Asia, and we believe initial DPP ® Dengue Assay sales will occur in Southeast Asia during Q1 2017. 
+· 
+DPP® Chikungunya Assay : The DPP® Chikungunya Assay is a rapid, POC, multiplex test for the simultaneous detection of IgG/IgM antibodies. During 2016, Chembio announced collaborations with Bio-Manguinhos, the unit of the Oswaldo Cruz Foundation (Fiocruz) responsible for the development and production of vaccines, diagnostics and biopharmaceuticals, primarily to meet the demands of Brazil's national public health system, related to the DPP® Chikungunya Assay. 
+· 
+DPP® Zika/Dengue/Chikungunya Assay : The DPP® Zika/Dengue/Chikungunya Assay is a rapid, POC, multiplex test for the simultaneous detection of IgM/IgG antibodies. In February 2016, we received a grant from The Paul G. Allen Family Foundation to initiate development of the DPP® Zika/Dengue/Chikungunya Assay. During 2016, Chembio announced collaborations with Bio-Manguinhos, the unit of the Oswaldo Cruz Foundation (Fiocruz) responsible for the development and production of vaccines, diagnostics and biopharmaceuticals, primarily to meet the demands of Brazil's national public health system, related to the DPP® Zika/Dengue/Chikungunya Assay. In August 2016, the Company received an award from the U.S. Government (HHS/ASPR/BARDA), granting the Company up to $13.2 million (including an option of $7.3 million to develop DPP® Zika/Dengue/Chikungunya Assay and obtain U.S. regulatory approval). In September 2016, the Company received a contract award from CDC, to initiate a Zika, Dengue, and Chikungunya surveillance program in India, Peru, Guatemala and Haiti and we began selling the DPP® Zika/Dengue/Chikungunya IgM/IgG Assay to CDC for field test purposes during the first quarter of 2017. 
+· 
+DPP® Fever Panel Assay : The DPP® Fever Panel Assay is a rapid, POC, multiplex test for the simultaneous detection of Malaria, Dengue, Chikungunya, Zika, Ebola, Lassa, and Marburg. In October 2015, we received a $2.1 million grant from the Paul G. Allen Ebola Program, to develop the DPP® Fever Panel Assay and a $0.55 million follow-on grant to add a test for the detection of Zika virus. We completed the development of the DPP® Fever Panel Assay in 2016, including the addition of Zika, and we supplied 10,000 tests to FIND, who will initiate evaluation in Peru and Nigeria. 
+29 
+· 
+DPP® Ebola Assay and DPP® Malaria-Ebola Assay : The DPP® Ebola Assay is a rapid POC test for the detection of Ebola, and the DPP® Malaria-Ebola Assay is a rapid, POC, multiplex test for the simultaneous detection of Malaria and Ebola. In October 2014, we announced plans to develop, validate, and commercialize POC DPP ® Assays for Ebola and Febrile Illness. We completed the development of the DPP® Ebola Assay and submitted it for Emergency Use Authorization (EUA) with the Food & Drug Administration (FDA) and World Health Organization (WHO), and we are actively engaged with these regulatory agencies. During the third and fourth quarters of 2015, we sold DPP® Ebola and DPP® Malaria-Ebola Assays to the Centers for Disease Control & Prevention (CDC) for field studies in West Africa, which is ongoing. 
+Technology Collaboration 
+· 
+DPP® Cancer Assay : The DPP® Cancer Assay is a rapid, POC, multiplex test for the early detection and monitoring of a specific type of cancer. In October 2014, we entered into collaboration with an international diagnostics company to develop a POC diagnostic test for a specific type of cancer. This program is fully funded by this partner. However, under the terms of the agreement, neither Chembio's partner nor the specific type of cancer is being disclosed. The cancer project represents an application of the DPP® technology outside of the infectious disease field, and the scope of the agreement involves product development of a quantitative, reader-based cancer assay for two cancer markers, utilizing Chembio's DPP® technology and its DPP® Micro Reader. During the third quarter of 2015, we completed successful feasibility, and our partner agreed to fund continued development of the DPP® Cancer Assay, which development and verification is ongoing. 
+· 
+DPP® Traumatic Brain Injury Assay : The DPP® Traumatic Brain Injury Assay is a rapid POC test for the detection of traumatic brain injury (TBI) and sports-related concussion. In January 2015, we entered into an agreement with the Concussion Science Group (CSG) Division of Perseus Science Group LLC, to combine CSG's patented biomarker with our proprietary DPP® platform and DPP® Micro Reader, to develop a semi-quantitative or quantitative POC test, to diagnose TBI. The DPP® Traumatic Brain Injury Assay is in the feasibility and pre-clinical stage. Under institutional review board (IRB) agreements with multiple hospitals, we are conducting pre-clinical studies of the prototype DPP® Traumatic Brain Injury Assay using patient samples. 
+· 
+DPP® Bovine Tuberculosis : The DPP ® BovidTB Assay is a rapid POC test for the detection of bovine tuberculosis (TB). In September 2016, the Company was awarded a $600,000 grant from the United States Department of Agriculture (USDA) to develop the DPP ® BovidTB Assay. The grant will be managed by the Small Business Innovation Research Program (SBIR) of the National Institute of Food and Agriculture (NIFA), a federal agency within the USDA and the assay will be developed in collaboration with National Animal Disease Center (NADC) and Infectious Disease Research Institute (IDRI). Under the two-year grant, Chembio will use its patented DPP ® technology to undertake to develop a simple, rapid, accurate and cost-effective test for bovine TB in cattle. The DPP ® BovidTB Assay will be designed to provide results within 20 minutes, thereby significantly improving on the time-consuming, tedious and inadequate diagnostic methods currently in use. 
+Regulatory Activities 
+· 
+DPP® HIV-Syphilis Assay: We have developed a U.S. version of the DPP® HIV-Syphilis Assay, designed to meet the performance requirements for the "reverse" algorithm that is currently in clinical use for syphilis testing in the United States. The clinical trial to support the FDA application for approval of the DPP® HIV-Syphilis Assay was initiated during first quarter of 2016 and is expected to be completed in the first quarter of 2017. Following the completion of the clinical trial, we will file a Premarket Approval Application with the U.S. Food and Drug Administration. In January 2017, we received CE mark approval for the DPP® HIV-Syphilis Assay. 
+· 
+DPP® Zika IgM/IgG System : In July of 2016 Chembio obtained a CE Mark for the DPP® Zika IgM/IgG Assay. The DPP® Zika IgM/IgG System, which includes an assay utilizing the patented DPP® technology as well as a digital reader (DPP® Micro Reader), are now cleared for commercialization in European countries as well as the majority of the Caribbean nations, not including U.S. territories. In November of 2016, we received approval from ANVISA, Brazil's regulatory Agency and we are working with our Brazilian partner, Bio-Manguinhos, to obtain ANVISA approval for the DPP® Micro Reader. We have also filed regulatory submissions to U.S. Food and Drug Administration (Emergency Use Authorization), the World Health Organization (Emergency Use Assessment and Listing), and Cofepris (Mexico), and we are actively engaged with these organizations. 
+There can be no assurance that any of the aforementioned Research & Development and/or Regulatory products or activities will result in any product approvals or commercialization, nor that any of the existing research and development activities, or any new potential development programs or collaborations will materialize or that they will meet regulatory or any other technical requirements and specifications, and/or that if continued, will result in completed products, or that such products, if they are successfully completed, can or will be successfully commercialized. 
+30 
+Recent Events 
+On January 9, 2017, the Company announced it completed the acquisition of RVR Diagnostics Sdn Bhd, a Malaysia corporation ("RVR"), pursuant to the previously reported Amended And Restated Stock Purchase Agreement, dated as of December 7, 2016 (the "Stock Purchase Agreement"), by and among Chembio, RVR, Avijit Roy and Magentiren Vajuram. See footnote 16 to Chembio's Consolidated Financial Statements included in this Form 10-K for more information. 
+RESULTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2016 AS COMPARED WITH THE YEAR ENDED DECEMBER 31, 2015 
+Income : 
+For the year ended December 31, 2016, Loss before income taxes was $7,546,000 compared to Loss before income taxes of 
+$3,557,000 for the year ended December 31, 2015. Net Loss for the year ended December 31, 2016 consists not only of the $7,546,000 Loss before income tax described above, but also of the $5,801,000 non-cash income tax provision described below under "Income tax provision (benefit)". Net Loss for the year ended December 31, 2015 consists not only of the $3,557,000 Loss before income tax described above, but also of the $1,160,000 non-cash income tax benefit described below under "Income tax provision (benefit)". The change in Loss before income taxes is primarily attributable to decreased revenue and gross margin, and increased operating expenses. Gross margin decreased in the year ended December 31, 2016 as compared with the year ended December 31, 2015, by $2,035,000, or (19.4)%. The increased operating expenses, the most significant of which were an increase materials and supplies for R&D of $1,512,000, increased clinical trial expenses of $412,000, and an increase in wages and related expenses of $633,000, partially offset by decreased commission expenses of $611,000, accounted for most of the change in Loss before income taxes. 
+Revenues: 
+Selected Product Categories: 
+For the years ended 
+December 31, 2016 
+December 31, 2015 
+$ Change 
+% Change 
+Lateral Flow HIV Tests and Components 
+$ 
+7,943,224 
+$ 
+9,957,882 
+$ 
+(2,014,658 
+) 
+-20.23 
+% 
+DPP ® Tests and Components 
+5,400,893 
+11,265,876 
+(5,864,983 
+) 
+-52.06 
+% 
+Other 
+335,990 
+662,930 
+(326,940 
+) 
+-49.32 
+% 
+Net Product Sales 
+13,680,107 
+21,886,688 
+(8,206,581 
+) 
+-37.50 
+% 
+License and royalty revenue 
+449,685 
+52,753 
+396,932 
+752.43 
+% 
+R&D, milestone and grant revenue 
+3,739,049 
+2,316,044 
+1,423,005 
+61.44 
+% 
+Total Revenues 
+$ 
+17,868,841 
+$ 
+24,255,485 
+$ 
+(6,386,644 
+) 
+-26.33 
+% 
+Revenues for our lateral flow HIV tests and related components during the year ended December 31, 2016 decreased by approximately $2,015,000 from the same period in 2015. This was primarily attributable to decreased sales to Africa of approximately $1,436,000, decreased sales to Europe of $40,000, decreased sales to the U.S. of $1,580,000, partially offset by increased sales to Mexico of $123,000. Revenues for our DPP® products during the year ended December 31, 2016 decreased by approximately $5,865,000 over the same period in 2015, primarily for decreases in sales in Brazil to FIOCRUZ of $5,340,000. The increase in R&D, and in milestone and grant revenue, was primarily due to revenues from certain development projects that were awarded during the period. R&D revenues include funds, recognized on an "as expenses are incurred" basis or on a proportonial performance basis, from various grants, see footnote 14 of our financial statements. 
+Gross Margin: 
+Gross Margin related to Net Product Sales: 
+For the years ended 
+December 31, 2016 
+December 31, 2015 
+$ Change 
+% Change 
+Gross Margin per Statement of Operations 
+$ 
+8,451,336 
+$ 
+10,486,827 
+$ 
+(2,035,491 
+) 
+-19.41 
+% 
+Less: R&D, milestone, grant, license and royalties 
+4,188,734 
+2,368,797 
+1,819,937 
+76.83 
+% 
+Gross Margin from Net Product Sales 
+4,262,602 
+8,118,030 
+$ 
+(3,855,428 
+) 
+-47.49 
+% 
+Product Gross Margin % 
+$ 
+31.16 
+% 
+$ 
+37.09 
+% 
+The overall gross margin dollar decrease of 2,035,000 consisted of a $3,855,000 decrease in gross margin from net product sales and a $1,820,000 increase in non-product revenues. The decrease in net product sales gross margin of $3,855,000 is primarily attributable to the change in product sales compared to 2015. The net product sales gross margin decrease is comprised of two components, one is the decrease in product sales of $8,207,000, which at the 37.1% margin contributed $3,044,000 to the decrease, and the other is the decreased change in margin percentage of 5.9% which contributed the balance of $812,000. The 5.9% decrease in the percentage, from 37.1% in 2015 to 31.2% in 2016, was primarily due to increased overhead as a percentage of products produced, due to the lower volume of sales. 
+31 
+Research and Development: 
+This category includes costs incurred for clinical and regulatory affairs and for product research and development. 
+Selected expense lines: 
+For the years ended 
+December 31, 2016 
+December 31, 2015 
+$ Change 
+% Change 
+Clinical and Regulatory Affairs: 
+Wages and related costs 
+$ 
+569,664 
+$ 
+490,802 
+$ 
+78,862 
+16.07 
+% 
+Consulting 
+40,974 
+44,135 
+(3,161 
+) 
+-7.16 
+% 
+Stock-based compensation 
+- 
+- 
+- 
+100.00 
+% 
+Clinical trials 
+778,921 
+366,469 
+412,452 
+112.55 
+% 
+Other 
+54,851 
+80,960 
+(26,109 
+) 
+-32.25 
+% 
+Total Regulatory 
+1,444,410 
+982,366 
+462,044 
+47.03 
+% 
+R&D Other than Regulatory: 
+Wages and related costs 
+2,951,456 
+2,896,226 
+55,230 
+1.91 
+% 
+Consulting 
+143,321 
+128,117 
+15,204 
+11.87 
+% 
+Stock-based compensation 
+89,246 
+62,713 
+26,533 
+42.31 
+% 
+Materials and supplies 
+3,290,868 
+1,779,046 
+1,511,822 
+84.98 
+% 
+Other 
+508,253 
+529,371 
+(21,118 
+) 
+-3.99 
+% 
+Total other than Regulatory 
+6,983,144 
+5,395,473 
+1,587,671 
+29.43 
+% 
+Total Research and Development 
+$ 
+8,427,554 
+$ 
+6,377,839 
+$ 
+2,049,715 
+32.14 
+% 
+Expenses for Clinical and Regulatory Affairs for the year ended December 31, 2016 increased by $462,000 as compared to the same period in 2015. This was due to an increase of $412,000 in clinical trial expenses and increased wages and related costs of $79,000. 
+R&D expenses other than Clinical & Regulatory Affairs increased by $1,588,000 in the year ended December 31, 2016, as compared with the same period in 2015. The increases were primarily related to an increase in wages and related costs, and in material and supplies, to support our sponsored research and internal development programs. 
+Selling, General and Administrative Expense: 
+Selected expense lines: 
+For the years ended 
+December 31, 2016 
+December 31, 2015 
+$ Change 
+% Change 
+Wages and related costs 
+$ 
+3,559,482 
+$ 
+3,060,407 
+$ 
+499,075 
+16.31 
+% 
+Consulting 
+128,992 
+311,488 
+(182,496 
+) 
+-58.59 
+% 
+Commissions 
+680,545 
+1,291,453 
+(610,908 
+) 
+-47.30 
+% 
+Stock-based compensation 
+214,913 
+271,674 
+(56,761 
+) 
+-20.89 
+% 
+Marketing materials 
+375,739 
+223,445 
+152,294 
+68.16 
+% 
+Investor relations/investment bankers 
+298,675 
+204,198 
+94,477 
+46.27 
+% 
+Legal, accounting and compliance 
+1,086,212 
+879,887 
+206,325 
+23.45 
+% 
+Travel, entertainment and trade shows 
+446,541 
+448,599 
+(2,058 
+) 
+-0.46 
+% 
+Bad debt allowance (recovery) 
+- 
+- 
+- 
+100.00 
+% 
+Other 
+804,460 
+971,884 
+(167,424 
+) 
+-17.23 
+% 
+Total S, G &A 
+$ 
+7,595,559 
+$ 
+7,663,035 
+$ 
+(67,476 
+) 
+-0.88 
+% 
+Selling, general and administrative expenses for the year ended December 31, 2016, decreased by $67,000 as compared with the same period in 2015, a 0.9% decrease. This decrease resulted primarily from decreases in consulting, commissions (due to decreased sales to Brazil), and stock-based compensation, which were partially offset by increases in wages and related costs and travel expenses which for 2016 included the continued development of a sales and marketing team over 2015, marketing materials, professional fees and in investor relations/investment bankers. 
+32 
+Other Income and Expense: 
+For the years ended 
+December 31, 2016 
+December 31, 2015 
+$ Change 
+% Change 
+Other income (expense) 
+$ 
+- 
+$ 
+(4,814 
+) 
+$ 
+4,814 
+-100.00 
+% 
+Interest income 
+25,548 
+2,412 
+23,136 
+959.20 
+% 
+Interest expense 
+- 
+(836 
+) 
+836 
+-100.00 
+% 
+Total Other Income and (Expense) 
+$ 
+25,548 
+$ 
+(3,238 
+) 
+$ 
+28,786 
+889.01 
+% 
+Other income (expense) for the year ended December 31, 2016 increased approximately $29,000, primarily due to interest income, compared to the same period in 2015. 
+Income tax provision (benefit): 
+For the year ended December 31, 2016 the Company recognized a $5,801,000 non-cash income tax provision and decreased its deferred tax assets by $5,801,000 as the Company took a full valuation allowance against its carryforward losses in the second quarter. For the year ended December 31, 2015, the Company recognized a $1,160,000 non-cash income tax benefit and increased its deferred tax assets by $1,160,000. The effective tax rate used to recognize the benefit in 2015 was 32.0% to record the amount charged. In the 2015 year, non-deductible expenses for tax purposes accounted for most of the difference from the standard 34% U.S. tax rate. The Company still maintains a full valuation allowance on research and development tax credits 
+33 
+RESULTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2015 AS COMPARED WITH THE YEAR ENDED DECEMBER 31, 2014 
+Income : 
+For the year ended December 31, 2015, Loss before income taxes was $3,557,000 compared to Loss before income taxes of $1,550,000 for the year ended December 31, 2014. Net Loss for the year ended December 31, 2015 consists not only of the $3,557,000 Loss before income tax described above, but also of the $1,160,000 non-cash income tax benefit described below under "Income tax provision (benefit)". Net Loss for the year ended December 31, 2014 consists not only of the $1,550,000 Loss before income tax described above, but also of the $413,000 non-cash income tax benefit described below under "Income tax provision (benefit)". The change in Loss before income taxes is primarily attributable to decreased revenue and gross margin, and increased operating expenses. Gross margin decreased in the year ended December 31, 2015 as compared with the year ended December 31, 2014, by $327,000, or 3.0%. The increased operating expenses, the most significant of which were an increase in wages and related expenses of $779,000, an increase in materials and supplies for R&D of $758,000, and increased clinical trial expenses of $161,000, partially offset by decreased commission expenses of $141,000, accounted for most of the change in Loss before income taxes. 
+Revenues: 
+Selected Product Categories: 
+For the years ended 
+December 31, 2015 
+December 31, 2014 
+$ Change 
+% Change 
+Lateral Flow HIV Tests and Components 
+$ 
+9,957,882 
+$ 
+9,518,242 
+$ 
+439,640 
+4.62 
+% 
+DPP ® Tests and Components 
+11,265,876 
+15,655,680 
+(4,389,804 
+) 
+-28.04 
+% 
+Other 
+662,930 
+775,847 
+(112,917 
+) 
+-14.55 
+% 
+Net Product Sales 
+21,886,688 
+25,949,769 
+(4,063,081 
+) 
+-15.66 
+% 
+License and royalty revenue 
+52,753 
+23,257 
+29,496 
+126.83 
+% 
+R&D, milestone and grant revenue 
+2,316,044 
+1,672,258 
+643,786 
+38.50 
+% 
+Total Revenues 
+$ 
+24,255,485 
+$ 
+27,645,284 
+$ 
+(3,389,799 
+) 
+-12.26 
+% 
+Revenues for our lateral flow HIV tests and related components during the year ended December 31, 2015 increased by approximately $440,000 from the same period in 2014. This was primarily attributable to increased sales to Africa, of approximately $1,576,000 and increased sales to Europe of $973,000, partially offset by decreased sales to the U.S. of $1,604,000, and decreased sales to Mexico of $458,000. Revenues for our DPP® products during the year ended December 31, 2015 decreased by approximately $4,390,000 over the same period in 2014, primarily for decreases in sales in Mexico of $3,455,000 and decreases in sales in Brazil to FIOCRUZ of $2,112,000, partially offset by increased sales in the U.S. of $1,011,000. The increase in R&D, and in milestone and grant revenue, was primarily due to revenues from certain development projects that were awarded during the period. R&D revenues include funds, recognized on an "as expenses are incurred" basis or on a milestone basis, from various grants, see footnote 14 of our financial statements. 
+Gross Margin: 
+Gross Margin related to Net Product Sales: 
+For the years ended 
+December 31, 2015 
+December 31, 2014 
+$ Change 
+% Change 
+Gross Margin per Statement of Operations 
+$ 
+10,486,827 
+$ 
+10,814,023 
+$ 
+(327,196 
+) 
+-3.03 
+% 
+Less: R&D, milestone, grant, license and royalties 
+2,368,797 
+1,695,515 
+673,282 
+39.71 
+% 
+Gross Margin from Net Product Sales 
+$ 
+8,118,030 
+$ 
+9,118,508 
+$ 
+(1,000,478 
+) 
+-10.97 
+% 
+Product Gross Margin % 
+37.09 
+% 
+35.14 
+% 
+The overall gross margin dollar decrease of $327,000 included a $1,000,000 decrease in gross margin from net product sales and a $673,000 increase in non-product revenues. The decrease in net product sales gross margin of $1,000,000 is primarily attributable to the change in product sales compared to 2014. The net product sales gross margin decrease is comprised of two components, one is the decrease in product sales of $4,063,000, which at the 35.1% margin contributed $1,428,000 to the decrease, and the other is the increased change in margin percentage of 2.0% which contributed the balance of $427,000. The 2.0% increase in the percentage, from 35.1% in 2014 to 37.1% in 2015, was primarily due to increased efficiencies from our operations excellence program. 
+34 
+Research and Development: 
+This category includes costs incurred for clinical and regulatory affairs and for product research and development. 
+Selected expense lines: 
+For the years ended 
+December 31, 2015 
+December 31, 2014 
+$ Change 
+% Change 
+Clinical and Regulatory Affairs: 
+Wages and related costs 
+$ 
+490,802 
+$ 
+448,852 
+$ 
+41,950 
+9.35 
+% 
+Consulting 
+44,135 
+29,741 
+14,394 
+48.40 
+% 
+Stock-based compensation 
+- 
+3,231 
+(3,231 
+) 
+-100.00 
+% 
+Clinical trials 
+366,469 
+205,589 
+160,880 
+78.25 
+% 
+Other 
+80,960 
+93,780 
+(12,820 
+) 
+-13.67 
+% 
+Total Regulatory 
+982,366 
+781,193 
+201,173 
+25.75 
+% 
+R&D Other than Regulatory: 
+Wages and related costs 
+2,896,226 
+2,456,514 
+439,712 
+17.90 
+% 
+Consulting 
+128,117 
+123,965 
+4,152 
+3.35 
+% 
+Stock-based compensation 
+62,713 
+41,306 
+21,407 
+51.83 
+% 
+Materials and supplies 
+1,779,046 
+1,021,516 
+757,530 
+74.16 
+% 
+Other 
+529,371 
+408,043 
+121,328 
+29.73 
+% 
+Total other than Regulatory 
+5,395,473 
+4,051,344 
+1,344,129 
+33.18 
+% 
+Total Research and Development 
+$ 
+6,377,839 
+$ 
+4,832,537 
+$ 
+1,545,302 
+31.98 
+% 
+Expenses for Clinical and Regulatory Affairs for the year ended December 31, 2015 increased by $201,000 as compared to the same period in 2014. This was primarily due to an increase of $161,000 in clinical trial expenses and increased wages and related costs of $42,000. 
+R&D expenses other than Clinical & Regulatory Affairs increased by $1,344,000 in the year ended December 31, 2015, as compared with the same period in 2014. The increases were primarily related to an increase in wages and related costs, and in material and supplies, to support our sponsored research and internal development programs. 
+Selling, General and Administrative Expense: 
+Selected expense lines: 
+For the years ended 
+December 31, 2015 
+December 31, 2014 
+$ Change 
+% Change 
+Wages and related costs 
+$ 
+3,060,407 
+$ 
+2,763,370 
+$ 
+297,037 
+10.75 
+% 
+Consulting 
+311,488 
+456,658 
+(145,170 
+) 
+-31.79 
+% 
+Commissions 
+1,291,453 
+1,432,567 
+(141,114 
+) 
+-9.85 
+% 
+Stock-based compensation 
+271,674 
+399,334 
+(127,660 
+) 
+-31.97 
+% 
+Marketing materials 
+223,445 
+345,426 
+(121,981 
+) 
+-35.31 
+% 
+Investor relations/investment bankers 
+204,198 
+168,410 
+35,788 
+21.25 
+% 
+Legal, accounting and compliance 
+879,887 
+662,522 
+217,365 
+32.81 
+% 
+Travel, entertainment and trade shows 
+448,599 
+320,280 
+128,319 
+40.06 
+% 
+Bad debt allowance (recovery) 
+- 
+28,000 
+(28,000 
+) 
+-100.00 
+% 
+Other 
+971,884 
+955,172 
+16,712 
+1.75 
+% 
+Total S, G &A 
+$ 
+7,663,035 
+$ 
+7,531,739 
+$ 
+131,296 
+1.74 
+% 
+Selling, general and administrative expenses for the year ended December 31, 2015, increased by $131,000 as compared with the same period in 2014, a 1.7% increase. This increase resulted primarily from increases in wages and related costs and travel expenses, which for 2015 included the continued development of a sales and marketing team over 2014, professional fees and in investor relations/investment bankers, which were partially offset by decreases in consulting, commissions (due to decreased sales to Brazil), stock-based compensation, and marketing materials. 
+35 
+Other Income and Expense: 
+For the years ended 
+December 31, 2015 
+December 31, 2014 
+$ Change 
+% Change 
+Other (expense) 
+$ 
+(4,814 
+) 
+$ 
+(5,707 
+) 
+$ 
+893 
+15.65 
+% 
+Interest income 
+$ 
+2,412 
+$ 
+5,839 
+$ 
+(3,427 
+) 
+-58.69 
+% 
+Interest expense 
+(836 
+) 
+- 
+(836 
+) 
+100.00 
+% 
+Total Other Income and (Expense) 
+$ 
+(3,238 
+) 
+$ 
+132 
+$ 
+(3,370 
+) 
+-2,553.03 
+% 
+Other (expense) for the year ended December 31, 2015 decreased approximately $3,400, primarily due to decreased interest income, compared to the same period in 2014. 
+Income tax provision (benefit): 
+For the year ended December 31, 2015 the Company recognized a $(1,160,000) non-cash income tax benefit and increased its deferred tax assets by $(1,160,000). For the year ended December 31, 2014, the Company recognized a $(413,000) non-cash income tax benefit and increased its deferred tax assets by $(413,000). The effective tax rate used to recognize the benefit in 2015 was 32.0% compared to a 26.6% rate used in 2014 to record the amount charged. In both years non-deductible expenses for tax purposes accounted for most of the difference from the standard 34% U.S. tax rate. The Company maintains a full valuation allowance on research and development tax credits. 
+36 
+MATERIAL CHANGES IN FINANCIAL CONDITION 
+Selected Changes in Financial Condition 
+As of 
+December 31, 2016 
+December 31, 2015 
+$ Change 
+% Change 
+Cash and cash equivalents 
+$ 
+10,554,464 
+$ 
+5,376,931 
+$ 
+5,177,533 
+96.29 
+% 
+Accounts receivable, net of allowance for doubtful accounts of $52,000 and $52,000 at December 31, 2016 and 2015, respectively 
+3,383,729 
+2,422,971 
+960,758 
+39.65 
+% 
+Prepaid expenses and other current assets 
+840,145 
+1,256,879 
+(416,734 
+) 
+-33.16 
+% 
+Fixed assets, net of accumulated depreciation 
+1,709,321 
+2,374,308 
+(664,987 
+) 
+-28.01 
+% 
+Deferred tax asset, net of valuation allowance 
+- 
+5,467,143 
+(5,467,143 
+) 
+-100.00 
+% 
+Deposits and other assets 
+720,489 
+209,169 
+511,320 
+244.45 
+% 
+Accounts payable and accrued liabilities 
+3,013,133 
+2,801,432 
+211,701 
+7.56 
+% 
+Deferred revenue 
+392,517 
+353,406 
+39,111 
+11.07 
+% 
+Additional paid-in capital 
+60,721,783 
+47,890,642 
+12,831,141 
+26.79 
+% 
+Cash increased by $5,178,000 from December 31, 2015, primarily due to net cash provided by financing activities for the year of 2016. The Company raised, net of expenses, approximately $12,500,000 which was partially offset by cash used in operating activities for the year of 2016. In addition there were increases in accounts receivable, net of allowance, of $961,000, deposits, accounts payable and accrued liabilities of $212,000 and other assets of $511,000, deferred revenue of $39,000, and decreases in fixed assets of $665,000 after depreciation, prepaid expenses of $417,000, non-current deferred tax asset of $5,467,000, and an increase in additional paid-in-capital of $12,831,000. 
+The accounts receivable increase from December 31, 2015, is primarily due to an increase in December 2016 versus December 2015 sales of approximately $1.50 million, partially offset by lower sales in prior months. The decrease in fixed assets is primarily due to depreciation for the year ending December 2016 versus December 2015. Deferred tax asset decrease is related to recording of a full valuation allowance. 
+LIQUIDITY AND CAPITAL RESOURCES 
+For the years ended 
+December 31, 2016 
+December 31, 2015 
+$ Change 
+% Change 
+Net cash provided by (used in) operating activities 
+$ 
+(6,704,734 
+) 
+$ 
+1,792,978 
+$ 
+(8,497,712 
+) 
+-473.94 
+% 
+Net cash used in investing activities 
+(668,706 
+) 
+(1,030,585 
+) 
+361,879 
+35.11 
+% 
+Net cash provided by financing activities 
+12,550,973 
+- 
+12,550,973 
+100.00 
+% 
+INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 
+$ 
+5,177,533 
+$ 
+762,393 
+$ 
+4,415,140 
+579.12 
+% 
+The Company's cash increased as of December 31, 2016 by $5,178,000 from December 31, 2015, primarily due to net cash provided by operating activities and partially offset by cash used in investing activities for 2016. 
+The cash used in operations in 2016 was $6,705,000, primarily due to the net loss net of non-cash items of $6,103,000 and with an increase in accounts receivable of $961,000, increase in prepaid and other current assets of $136,000, and a decrease in accounts payable and other accrued liabilities of $212,000, partially offset by a decrease in inventories of $243,000, decrease in deposits and other assets of $1,000, and an increase in deferred revenue of $39,000. Net loss net of non-cash items includes net loss of $13,347,000 partially offset by $5,801,000 in income tax provision, $1,139,000 in depreciation and amortization, and $304,000 in share-based compensation. The use of cash from investing activities is primarily the purchase of fixed assets and acquisition of licenses. 
+Fixed Asset Commitments 
+As of December 31, 2016, the Company had paid deposits on various pieces of equipment aggregating $31,900 which is reflected in Deposits on manufacturing equipment on the balance sheet. As of December 31, 2016, the Company was not committed to additional equipment-purchase obligations. 
+37 
+RECENT DEVELOPMENTS AND CHEMBIO'S PLAN OF OPERATIONS FOR THE NEXT TWELVE MONTHS 
+During 2016, Chembio took three important strategic steps which management believes will position the Company for growth. First, the Company continued to expand its product portfolio, leveraging its patented DPP ® technology platform. Second, the Company expanded its global sales and marketing infrastructure, strengthening its U.S. sales leadership and building its first international sales team. Third, the Company expanded its operational capabilities, acquiring a Malaysia-based operation. 
+Expanding Chembio's Product Portfolio 
+For nearly fifteen years, Chembio was primarily focused on POC HIV testing and succeeded in commercializing multiple FDA-approved and CLIA-Waived POC HIV tests. In 2014, the Company made the strategic decision to expand its product portfolio and focus on three initiatives: 1) strengthening its core sexually transmitted disease business, 2) building a highly-differentiated fever and tropical disease business, and 3) establishing technology collaborations to further leverage its patented DPP ® technology platform. 
+1. Strengthening the Company's core sexually transmitted disease business began with the decision to terminate its U.S. distribution agreements for HIV 1/2 Stat-Pak ® Assay in 2014 and SURE CHECK HIV ® 1/2 Assay in 2016, which provided the Company with worldwide commercial control of its legacy POC HIV tests, which are FDA-approved, CLIA-waived, WHO Prequalified and CE marked. The Company leveraged its DPP ® technology platform to develop a DPP® HIV 1/2 Assay, which became FDA-Approved and CLIA-Waived in October 2014 for use with blood and oral fluid, the second such entrant in the U.S. market. Finally, following the introduction of its DPP ® HIV-Syphilis Assay in Latin America, the Company has prioritized the development of a DPP ® HIV-Syphilis Assay for the U.S. market to address the rise in HIV and Syphilis co-infection. 
+2. Building a highly-differentiated fever and tropical disease business began as a response to the 2014-2015 Ebola outbreak in West Africa, which led to the Company's decision to enter the fever and tropical disease market. Today, the Company is developing eight POC fever and tropical disease tests, specifically the following: DPP ® Malaria Assay, DPP ® Zika Assay, DPP ® Dengue Fever Assay, DPP ® Chikungunya Assay, DPP ® Zika/Dengue/Chikungunya Assay, DPP ® Fever Assay (Malaria, Zika, Dengue, Chikungunya, Ebola, Lassa, Marburg), DPP ® Ebola Assay, and DPP ® Ebola-Malaria Assay. The Company's fever and tropical disease products are being developed through collaborations and/or funding's from the Bill & Melinda Gates Foundation, the Paul G. Allen Family Foundation, the Centers for Disease Control and Prevention (CDC), the U.S. Department of Health and Human Services (HHS), the Office of the Assistant Secretary for Preparedness and Response, and the Biomedical Advanced Research and Development Authority (BARDA). 
+3. Establishing technology collaborations to further leverage the Company's patented DPP ® technology platform has allowed the Company to advance the development of novel POC tests in areas with unmet medical needs, such as traumatic brain injury (concussion), a specific form or cancer, and bovine tuberculosis in cattle. The collaborations and external funding can be attributed to the unique characteristics of the Company's DPP ® technology platform as compared to traditional lateral flow technology, such as enhanced sensitivity and specificity, the ability to multiplex, and the ability to provide a semi-quantitative result when combined with Chembio's DPP ® Micro Reader. 
+Expanding Chembio's Sales & Marketing Infrastructure 
+Prior to 2014, Chembio's HIV products were sold through a single, exclusive distribution partner in the U.S. market, the majority of the Company's international sales were limited to a few countries, and the Company had no internal commercialization infrastructure. Between 2014 and 2016, Chembio took important steps to gain control of its HIV products in the U.S. market, ending the longstanding relationship with its previous distribution partner and building its own U.S. sales and marketing team to sell its DPP ® HIV, STAT-PAK ® HIV, and SURE CHECK ® HIV products in the U.S. market. In addition, the Company has partnered with professional distributors such as Fisher, McKesson/PSS, Henry Schein and Medline to establish a geographic coverage model in the U.S. market. 
+To lead this growing infrastructure, Chembio recently appointed two senior executives to direct the expansion of the Company's global commercial operations. Robert Passas, Ph.D., joined the Company in October 2016 as President, EMEA and APAC regions, and is responsible for commercial operations in Europe, the Middle East, Africa, and Asia. Prior to joining the Company, Dr. Passas held positions of increasing responsibility at Abbott, Quidel, The Binding Site, and Trinity Biotech. In his most recent position, he was responsible for worldwide marketing and international sales at Trinity Biotech. 
+Sharon Klugewicz, who most recently served as Chembio's Chief Operating Officer, was promoted to President, Americas region in October 2016, with responsibility for commercial operations in the United States, Latin America, and Canada. Ms. Klugewicz is responsible for sales, marketing, customer support, clinical and regulatory affairs, and quality systems in the Americas, and will be tasked with leading the U.S. commercial team and expanding commercial operations throughout Latin America, the U.S. and Canada. Prior to joining the Company in 2012, she spent 20 years at Pall Corporation where she held positions of increasing responsibility, including Senior Vice President, Scientific and Laboratory Services. 
+38 
+In addition, Chembio has recently hired three international sales executives to oversee commercial expansion in specific regions. Javier Gutman was named Regional Director, Latin America; Kenneth Burns was named Regional Director, Africa; and Mohan Anasalam was named Regional Director, Asia Pacific. Each of these sales executives brings considerable experience to Chembio, and each will focus on increasing product sales, strengthening and expanding the Company's distribution channels, and providing local support to customers and commercial partners in their respective areas of Latin America, Africa and Asia Pacific. 
+Today, led by experienced executives with extensive experience in global diagnostic sales, Chembio is building a world-class commercialization organization with focus on the U.S., Europe, Africa, Asia Pacific and Latin America. 
+Expanding Chembio's Operational Capabilities 
+In November 2016, Chembio announced plans to acquire Malaysia-based RVR Diagnostics ("RVR"), a strategic decision to expand the Company's operational capabilities, increasing manufacturing capacity and establishing a physical presence in Southeast Asia. 
+Previously, in 2014, Chembio entered into two agreements with RVR, a privately-held company in Malaysia. The agreements were intended to build a Chembio presence in Asia and establish RVR as a licensee, distributor and contract manufacturer. Through these agreements, RVR acquired rights to license, manufacture and distribute certain Chembio products in Southeast Asia. Between 2014 and 2016, RVR achieved a number of important milestones under the agreements, including the following: 
+• 
+completed a manufacturing facility capable of producing DPP® Assays and obtained ISO 13485 certification; 
+• 
+provided funding to accelerate the development of Chembio's DPP® Dengue Assay; 
+• 
+received regulatory approval to market and sell products in certain Southeast Asia countries; 
+• 
+obtained RVR Dengue tender award in Malaysia, which resulted in 2016 revenue in excess of US$1 million. 
+In light of the considerable progress made by RVR, and to further support Chembio's global product and commercialization strategies, Chembio acquired RVR in January 2017. As a subsidiary of Chembio, RVR provides an important base of operations, providing additional revenue, a strategically located and cost-effective manufacturing facility, and a path to regulatory access in Southeast Asia that management believes will be an important growth driver. 
+Overview of Chembio's Business 
+Sexually Transmitted Disease: 
+Chembio's sexually transmitted disease product sales decreased during 2016, primarily due to the Company's loss of ongoing DPP® HIV and DPP® Syphilis product sales as a result of a previously disclosed tender offer in Brazil having been awarded to a competitor at an extremely low price point as well as lower sales of HIV products in Africa. Despite the loss of the HIV and Syphilis tender in Brazil, Chembio continues to supply other novel DPP ® products to Bio-Manguinhos/Fiocruz, and the Ministry of Health in Brazil. These products include DPP ® HIV Confirmatory Assay and DPP ® Leishmania Assay. Given Chembio's product portfolio in sexually transmitted disease, coupled with the expansion of our global commercial resources, the Company believes the Unites States, Latin America, Africa, and Asia Pacific will be important current and future markets for its sexually transmitted disease products. 
+In the U.S., sales of the Company's POC HIV Assays showed positive trends. During 2016, U.S. sales of the HIV 1/2 STAT-PAK ® Assay increased 34.7% as compared to 2015. We are also seeing very encouraging U.S. sales of the SURE CHECK ® HIV 1/2 Assay. During the fourth quarter of 2016, U.S. sales of the SURE CHECK ® HIV 1/2 Assay increased by approximately $516,000 or 230.5% as compared to the third quarter of 2016. Our U.S. HIV sales are bolstered by a receipt of a two-year HIV tender for the state of Florida, which the Company was awarded during the fourth quarter of 2016 and of a two-year HIV tender for another state, which the Company was awarded subsequent to the end of 2016. This growth provides evidence that we are effectively rebuilding the U.S. HIV STAT-PAK ® and SURE CHECK ® HIV business, after we took back the U.S. distribution rights to these products in June 2014 and June 2016 respectively. 
+Looking toward 2017 sales of Chembio's sexually transmitted disease products, the Company recently received CE Mark for the DPP ® HIV-Syphilis Assay, clearing the product to be marketed and sold within the member states of the European Union and the Caribbean region, except for Puerto Rico and the U.S. Virgin Islands. The Company continued to advance the clinical trial for its DPP ® HIV-Syphilis Assay for the U.S. market during 2016, which is expected to be completed as planned, in the first quarter of 2017. As we've stated previously, we are striving to be the first-to-market in the U.S. with an HIV-Syphilis combination test. 
+Fever Disease: 
+During 2016, Chembio significantly advanced the development of its fever disease products, including: DPP ® Malaria Assay, DPP ® Dengue Assay, DPP ® Zika Assay, DPP ® Chikungunya Assay, DPP ® Zika/Dengue/Chikungunya Assay, DPP ® Fever Panel Assay, DPP ® Ebola Assay, and DPP ® Malaria/Ebola Assay. Also during 2016, the Company pursued and received numerous grants which fund much of the fever disease development initiatives, including funding from the Paul G. Allen Family Foundation, the Bill & Melinda Gates Foundation, and the U.S. Government (HHS/ASPR/BARDA and CDC). In addition, during the first quarter of 2016, the Company also entered into a collaboration with Bio-Manguinhos/Fiocruz for the development of POC Zika diagnostic tests for Brazil. 
+39 
+Of particular note is the Company's work to develop a much-needed alternative to currently available molecular tests for the Zika virus that have limited utility as they are accurate only during a narrow window of time, approximately one week, between initial Zika virus exposure and the patient's development of detectable antibodies to the virus, a process known as seroconversion. Following seroconversion, antibody tests are recommended to accurately identify Zika virus infections. The DPP ® Zika IgM/IgG Assay is an antibody test that will provide timely results, during the patient consultation. The DPP ® Zika System, which includes the DPP ® Zika IgM/IgG Assay and DPP ® Micro Reader, detects both IgM and IgG antibodies, uses a 10uL fingerstick blood sample, and provides semi-quantitative results in 15 minutes. Though Chembio's Zika program was only initiated in February 2016, by September 2016, the Company was awarded a contract by the CDC for the purchase of POC surveillance diagnostic assays for Zika, Dengue and Chikungunya. Under the terms of the contract, during the first quarter of 2017 Chembio will supply its DPP ® Zika IgM/IgG Assay, DPP ® Zika/Chikungunya/Dengue IgM/IgG Combination Assay, and DPP ® Micro Reader to the CDC, for a surveillance testing pilot program in India, Peru, Guatemala and Haiti. 
+Concurrent with this important development work, Chembio is moving expeditiously to complete regulatory filings that will ultimately determine the availability of our products to the regions in need. In July 2016, a CE Mark was obtained that allowed the Company to begin commercializing the DPP ® Zika IgM/IgG System, which includes an assay utilizing the patented DPP ® technology, as well as a digital reader, the DPP ® Micro Reader, in 17 European countries, including the United Kingdom, Germany, and France, as well as a majority of the Caribbean nations. During the fourth quarter of 2016, Chembio initiated sales of the DPP ® Zika system via its exclusive Caribbean distribution partner, Isla Labs. 
+In November 2016, the Company received approval for commercial use of its DPP ® Zika IgM/IgG Assay by the Brazilian health regulatory agency, Agência Nacional de Vigilância Sanitária (ANVISA), and during the first quarter 2017, the Company was notified of the successful evaluation of the DPP ® Zika system by INCQS, Brazil's National Institute for Quality Control in Health. Brazil has been hardest hit by the Zika virus, where it is estimated that 1.5 million people have been infected with Zika virus and approximately 2,000 babies have been born with microcephaly, a devastating birth defect linked to the Zika virus. For this reason the Company is particularly pleased to receive approval from Brazil's health regulatory agency, and we look forward to initiating sales of our DPP ® Zika IgM/IgG Assay, following ANVISA approval of the DPP ® Micro Reader. There is no assurance of the timing of this approval or that it will occur at all. 
+Beyond these approvals, the Company made multiple other regulatory filings during 2016 for the DPP ® Zika IgM/IgG Assay, including an Emergency Use Authorization (EUA) submission with the U.S. Food and Drug Administration (FDA), an Emergency Use Assessment and Listing (EUAL) with the World Health Organization (WHO), and a submission with Cofepris in Mexico. Supplementing these filings, the Company is engaged fully with these agencies in the hope of facilitating the earliest possible approvals. 
+Technology Collaborations: 
+Chembio currently has the following ongoing technology collaborations: DPP ® Cancer Assay for a specific form of cancer, DPP ® Traumatic Brain Injury Assay, and DPP ® BovidTB Assay. We are pleased to report that we made progress with each of these programs in 2016. 
+The DPP ® Cancer Assay, which is funded by an undisclosed entity, targets a specific form of cancer. We have successfully completed the feasibility phase of the program and moved into the product development stage, which is also funded by the undisclosed entity. The results to-date with this program have been highly encouraging. With success, we are hopeful that we'll be able to find additional applications for our DPP ® technology in the broader oncology market. 
+We also made important advances with our DPP® Traumatic Brain Injury Assay program during 2016. This project, which is funded by Perseus Science Group, LLC, is in the feasibility phase. We recently finalized institutional review board (IRB) agreements with several hospitals and began conducting initial studies of the DPP® Traumatic Brain Injury Assay using patient samples. 
+The DPP ® BovidTB Assay is a rapid POC test for the detection of bovine tuberculosis (TB). In September 2016, the Company was awarded a $600,000 grant from the United States Department of Agriculture (USDA) to develop the DPP ® BovidTB Assay. Under the two-year grant, Chembio will use its patented DPP ® technology in an effort to develop a simple, rapid, accurate and cost-effective test for bovine TB in cattle. The DPP ® BovidTB Assay will be designed to provide results within 20 minutes, thereby significantly improving on the time-consuming, tedious and inadequate diagnostic methods currently in use. 
+40 
+Conclusion 
+During 2016, the Company made significant advances to expand its product portfolio, its sales and marketing infrastructure, and its operational capabilities. 
+The product strategy includes three strategic initiatives: strengthening the Company's core sexually transmitted disease, building a highly-differentiated fever and tropical disease, and establishing technology collaborations to further leverage the Company's patented DPP ® technology platform. Though the Company only initiated its fever disease program in late 2014, sales of two fever disease products were initiated in 2015 (DPP ® Ebola, DPP ® Malaria-Ebola) and expanded in late 2016 (DPP ® Zika Assay). The efficiency with which these products were developed, and regulatory clearances were obtained, speaks to the versatility of the Company's patented DPP ® technology platform, the Company's scientific expertise, and its commitment to fever disease. It further highlights Chembio's ability to succeed with a range of new product opportunities. 
+The commercial strategy shifted from a product supply model, in which the Company relied on others to market and sell its products, to taking critical steps to build a global sales and marketing organization. Prior to 2014, the Company had no sales infrastructure. Today, Chembio has experienced sales leadership guiding the Company's global commercialization plan, with focus on the U.S., Europe, the Middle East, Africa, Asia, and Latin America. The new sales and marketing leadership joined Chembio starting in Q4 of 2016 with 2017 goals of increasing product sales, strengthening and expanding the Company's distribution channels, and providing local support to customers and commercial partners around the world. With several fever and HIV products receiving regulatory approvals in late 2016, there is great optimism for 2017 sales. 
+And the operational strategy was significantly expanded beyond Medford, NY to incorporate Malaysia-based RVR Diagnostics. The acquisition, of RVR provides Chembio with an important base of operations, providing additional revenue, a strategically located and cost-effective manufacturing facility, and a path to regulatory access in Southeast Asia that management believes will be an important growth driver. 
+2016 was an important year for Chembio, but it was merely a starting point for this new global organization. 
+Contractual Obligations and Commercial Commitments 
+The following sets forth our approximate aggregate obligations as of December 31, 2016 for future payments under contracts and other contingent commitments, for the year 2017 and beyond: 
+Payments due by period 
+Contractual Obligations 
+Total 
+Less than one year 
+1 - 3 years 
+3-5 years 
+More than 5 years 
+Operating leases 1 
+$ 
+370,085 
+$ 
+306,018 
+$ 
+64,067 
+$ 
+- 
+$ 
+- 
+Employment contracts 2 
+907,000 
+516,200 
+390,800 
+- 
+- 
+Purchase obligations 3 
+694,725 
+694,725 
+- 
+- 
+- 
+Minimum commitments under contracts 4 
+532,627 
+333,627 
+92,000 
+77,000 
+30,000 
+Total contractual obligations 
+$ 
+2,504,437 
+$ 
+1,850,570 
+$ 
+546,867 
+$ 
+77,000 
+$ 
+30,000 
+1 
+Represents payments required under our operating leases. See Note 13 of the Notes to the consolidated financial statements included herein. 
+2 
+Represents salary payments payable under the terms of employment agreements executed by us with certain executives. See Note 13 of the Notes to the consolidated financial statements included herein. 
+3 
+Represents payments required by non-cancellable purchase orders related to inventory, capital expenditures and other goods or services. 
+4 
+Represents payments required pursuant to certain licensing agreements executed by the Company. These agreements are cancellable within a specified number of days after communication by the Company of its intent to terminate. 
+Off-Balance Sheet Arrangements . 
+We do not have any off-balance sheet arrangements, as defined in Item 303(a)(4)(ii) of Regulation S-K under the Securities Exchange Act of 1934, as amended. 
+41 
+Critical Accounting Policies and Estimates 
+The preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ materially from those estimates. 
+We believe that there are several accounting policies that are critical to understanding our historical and future performance, as these policies affect the reported amounts of revenue and the more significant areas involving management's judgments and estimates. These significant accounting policies relate to revenue recognition, research and development costs, valuation of inventory, valuation of long-lived assets and income taxes. These policies, and the related procedures, are described in detail below. 
+Revenue Recognition – 
+We recognize revenue for product sales in accordance with ASC 605. Revenue is recognized when there is persuasive evidence of an arrangement, delivery has occurred or services have been rendered, the sales price is determinable, and collectability is reasonably assured. Revenue typically is recognized at time of shipment. Sales are recorded net of discounts, rebates and returns. 
+For certain contracts, we recognize revenue from R&D, milestone and grant revenues when earned. Grants are invoiced after expenses are incurred. Revenues from projects or grants funded in advance are deferred until earned. 
+For certain collaborative research projects, we recognize revenue by defining milestones at the inception of the agreement and applying the milestone method of revenue recognition for relevant contracts. 
+Stock-Based Compensation – 
+We recognize the fair value of equity-based awards as compensation expense in our statement of operations. The fair value of our stock option awards was estimated using a Black-Scholes option valuation model. This valuation model's computations incorporate highly subjective assumptions, such as the expected stock price volatility and the estimated life of each award. The fair value of the options, after considering the effect of expected forfeitures, is then amortized, generally on a straight-line basis, over the related vesting period of the option. The fair value of our restricted shares is based on the market value of the shares at the date of grant and is recognized on a straight-line basis over the related vesting period of the award. 
+Research & Development Costs – 
+Research and development activities consist primarily of new product development, continuing engineering for existing products, and regulatory and clinical trial costs. Costs related to research and development efforts on existing or potential products are expensed as incurred. 
+Valuation of Inventories – 
+Inventories are stated at the lower of cost or market, using the first-in, first-out method (FIFO) to determine cost. Our policy is to periodically evaluate the market value of the inventory and the stage of product life cycle, and record a reserve for any inventory considered slow moving or obsolete. For example, each additional 1% of obsolete inventory would reduce such inventory by approximately $35,000. 
+Allowance for doubtful accounts – 
+Our policy is to review our accounts receivable on a periodic basis, no less than monthly. On a quarterly basis an analysis is made of the adequacy of our allowance for doubtful accounts and adjustments are made accordingly. The current allowance is approximately 2% of accounts receivable. For example each additional 1% of accounts receivable that becomes uncollectible would reduce such balance of accounts receivable by approximately $32,000. 
+Income Taxes – 
+Income taxes are accounted for under ASC 740 authoritative guidance ("Guidance") which requires the asset and liability method of accounting for deferred income taxes. Deferred tax assets and liabilities are determined based on the difference between the financial statement and tax bases of assets and liabilities. Deferred tax assets or liabilities at the end of each period are determined using the tax rate expected to be in effect when taxes are actually paid or recovered. 
+42 
+The Guidance also requires that a valuation allowance be established when it is more likely than not that all or a portion of a deferred tax asset will not be realized. A review of all available positive and negative evidence needs to be considered, including a company's current and past performance, the market environment in which the company operates, length of carryback and carryforward periods and existing contracts that will result in future profits. The Company believes that it will not be able to utilize its net operating loss carryforwards and maintains a full valuation allowance. The Company still maintains a full valuation allowance on research and development tax credits. 
+The Guidance also prescribes a comprehensive model for recognizing, measuring, presenting and disclosing in the consolidated financial statements tax positions taken or expected to be taken on a tax return, including a decision whether to file or not to file in a particular jurisdiction. 
+The above listing is not intended to be a comprehensive list of all of our accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by accounting principles generally accepted in the United States of America ("U.S. GAAP"), with no need for management's judgment in their application. There are also areas in which management's judgment in selecting any viable alternative would not produce a materially different result. See our audited financial statements and notes thereto which contain accounting policies and other disclosures required by accounting principles generally accepted in the United States of America. 
+Recent Accounting Pronouncements – 
+In May 2014, the FASB issued Accounting Standards Update No. 2014-09, "Revenue from Contracts with Customers" ("ASU 2014-09"), which supersedes nearly all existing revenue recognition guidance under U.S. GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing U.S. GAAP. 
+The standard is effective for annual periods beginning after December 15, 2017, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients; or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We are currently evaluating the impact of our pending adoption of ASU 2014-09 on our consolidated financial statements and have not yet determined the method by which we will adopt the standard in 2018. The Company has conducted a preliminary analysis of its sales contracts which are based on the shipment of goods to the customer, and currently this new accounting standard will not have a material impact on its consolidated financial statement for our sales contracts. The Company has conducted a preliminary analysis of its current R&D contracts which are currently based on "as expenses are incurred" basis, and currently this new accounting standard will not have a material impact on its consolidated financial statement for our current R&D contracts. 
+In November 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-17, Income Taxes (Topic 740) Balance Sheet Classification of Deferred Assets. This ASU is intended to simplify the presentation of deferred taxes on the balance sheet and will require an entity to present all deferred tax assets and deferred tax liabilities as non-current on the balance sheet. Under the current guidance, entities are required to separately present deferred taxes as current or non-current. Netting deferred tax assets and deferred tax liabilities by tax jurisdiction will still be required under the new guidance. This guidance will be effective for Chembio beginning in 2018, with early adoption permitted. The Company does not believe this new accounting standard update will have a material impact on its consolidated financial statements. 
+In February 2016, the FASB issued Accounting Standards Update ("ASU") 2016-02, which amends the ASC and creates Topic 842, Leases. Topic 842 will require lessees to recognize lease assets and lease liabilities for those leases classified as operating leases under previous US GAAP on the balance sheet. This guidance is effective for annual periods beginning after December 15, 2018 and early adoption is permitted. We are in the initial stages of evaluating the effect of the standard on our financial statements and will continue to evaluate. While not yet in a position to assess the full impact of the application of the new standard, the Company expects that the impact of recording the lease liabilities and the corresponding right-to-use assets will have a significant impact on its total assets and liabilities with a minimal impact on equity. 
+In March 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which will change certain aspects of accounting for share-based payments to employees. ASU 2016-09 is effective for fiscal years (and interim reporting periods within those years) beginning after December 15, 2016. The Company is currently in the initial stages of evaluating the impact of the provisions of ASU 2016-09. We are still evaluating this standard and currently the Company does not believe this new accounting standard will have a material impact on its consolidated financial statement. 
+43 
+ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk. 
+We do not hold any amounts of derivative financial instruments or derivative commodity instruments and, accordingly, we have no material derivative risk to report under this Item. 
+As of December 31, 2016, we did not have any foreign currency exchange contracts or purchase currency options to hedge local currency cash flows. Sales for the year ended December 31, 2016 are in U.S. Dollars (USD). 
+ITEM 8. 
+FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+The Consolidated Financial Statements and schedules that constitute Item 8 are attached at the end of this Annual Report on Form 10-K. An index to these Financial Statements and schedules is also included on page F-1 of this Annual Report on Form 10-K. 
+ITEM 9. 
+CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. 
+Not Applicable. 
+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+(a) Disclosure Controls and Procedures. Under the supervision and with the participation of our senior management, consisting of our chief executive officer and our chief financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")), as of the end of the period covered by this report (the "Evaluation Date"). Based on that evaluation, the Company's management, including our chief executive officer and chief financial officer, concluded that as of the Evaluation Date our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports that we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. Our disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in our Exchange Act reports is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure. 
+Management's Annual Report on Internal Control Over Financial Reporting. The Company's management is responsible for establishing and maintaining an adequate system of internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f)). Our internal control over financial reporting is a process, under the supervision of our chief executive officer and chief financial officer, designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States. These internal controls over financial reporting processes include policies and procedures that: 
+a. 
+Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company; 
+b. 
+Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and 
+c. 
+Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance of achieving their control objectives. 
+44 
+Management's Report on Internal Control over Financial Reporting 
+Management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f). 
+The Company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting can only provide reasonable assurance and may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+Under the supervision and with the participation of our management, including the Chief Executive Officer (CEO) and the Chief Financial Officer (CFO), we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2016, based on the framework and criteria in the 2013 Internal Control – Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on management's evaluation and those criteria, the CEO and CFO concluded that its system of internal control over financial reporting was effective as of December 31, 2016. 
+The Company's independent registered public accounting firm has issued an attestation report on the Company's internal control over financial reporting. 
+Dated: March 7, 2017 /s/ John J. Sperzel 
+John J. Sperzel III 
+Chief Executive Officer 
+Dated: March 7, 2017 /s/ Richard J. Larkin 
+Richard J. Larkin 
+Chief Financial Officer 
+45 
+Report of Independent Registered Public Accounting Firm 
+Board of Directors and Stockholders of 
+Chembio Diagnostics, Inc. 
+Medford, New York 
+We have audited the internal control over financial reporting of Chembio Diagnostics, Inc. and subsidiaries (the "Company") as of December 31, 2016, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting ("Management's Report"). Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. 
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+In our opinion, Chembio Diagnostics, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based COSO criteria. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Chembio Diagnostics, Inc. and subsidiary as of December 31, 2016 and 2015, and the related consolidated statements of operations, comprehensive loss, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2016 and our report dated March 7, 2017 expressed an unqualified opinion thereon. 
+/s/ BDO USA, LLP 
+Melville, New York 
+March 7, 2017 
+46 
+(b) Changes in Internal Control over Financial Reporting. There were no changes in our internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Rule 13a-15 or Rule 15d-15 under the Exchange Act that occurred during the Company's last fiscal quarter of the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+ITEM 9B. 
+OTHER INFORMATION 
+Not applicable. 
+47 
+PART III 
+ITEM 10. 
+DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
+The information required in response to this Item 10 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+ITEM 11. 
+EXECUTIVE COMPENSATION 
+The information required in response to this Item 11 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+ITEM 12. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+The information required in response to this Item 12 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE. 
+The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+ITEM 14. 
+PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+The information required in response to this Item 14 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+48 
+PART IV 
+ITEM 15. 
+EXHIBITS INDEX 
+Number 
+Description 
+3.1 
+Articles of Incorporation, as amended. (1) 
+3.2 
+Bylaws and Bylaw Amendments. (2) 
+3.3 
+Certificate of Designation of Series D Preferred Stock (13) 
+4.1 
+2008 Stock Incentive Plan, as amended . (3) 
+4.2 
+Form of Option, for 2008 Stock Incentive Plan (4) 
+4.3 
+2014 Stock Incentive Plan (5) 
+4.4 
+Form of Option, for 2014 Stock Incentive Plan (6) 
+4.5 
+Rights Agreement, dated as of March 8, 2016 (7) 
+4.6 
+Form of Warrant (to be filed by amendment) 
+10.1* 
+Employment Agreement dated March 13, 2014 with John J. Sperzel III (4) 
+10.2* 
+Employment Agreement dated March 5, 2016 with Javan Esfandiari (8) 
+10.3* 
+Employment Agreement dated June 12, 2015 with Sharon Klugewicz (9) 
+10.4 
+H IV Barrel License, Marketing and Distribution Agreement, dated as of September 29, 2006, by and among the Registrant, Alere and StatSure. (10) 
+10.5 
+HIV Cassette License, Marketing and Distribution Agreement, dated as of September 29, 2006, between the Registrant and Alere. (10) 
+10.6 
+Non-Exclusive License, Marketing and Distribution Agreement, dated as of September 29, 2006, between the Registrant and Alere . (10) 
+10.7 
+Joint HIV Barrel Product Commercialization Agreement, dated as of September 29, 2006, between the Registrant and StatSure . (10) 
+10.8 
+2015 Omnibus Agreement (11) 
+14.1 
+Ethics Policy (12) 
+21 
+List of Subsidiaries 
+23.1 
+Consent of BDO USA, LLP, Independent Registered Public Accountants. 
+31.1 
+Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+31.2 
+Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+32 
+Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 
+101.INS 
+XBRL Instance Document 
+101.SCH 
+XBRL Taxonomy Extension Schema Document 
+101.CAL 
+XBRL Taxonomy Extension Calculation Linkbase Document 
+101.DEF 
+XBRL Taxonomy Definition Linkbase Document 
+101.LAB 
+XBRL Taxonomy Label Linkbase Document 
+101.PRE 
+XBRL Taxonomy Presentation Linkbase Document 
+1 
+Incorporated by reference to the Registrant's Quarterly Report on Form 10-Q filed with the Commission on July 29, 2010. 
+2 
+Incorporated by reference to the Registrant's registration statement on Form SB-2 (File No. 333-85787) filed with the Commission on August 23, 1999 and the Registrant's Forms 8-K filed on May 14, 2004 , December 20, 2007 and April 18, 2008 . 
+3 
+Incorporated by reference to the Registrant's definitive proxy statement on Schedule 14A filed with the Commission on August 3, 2012. 
+4 
+Incorporated by reference to the Registrant's Quarterly Report on Form 10-Q filed with the Commission on May 8, 2014. 
+5 
+Incorporated by reference to the Registrant's definitive proxy statement on Schedule 14A filed with the Commission on April 29, 2014. 
+6 
+Incorporated by reference to the Registrant's Quarterly Report on Form 10-Q filed with the Commission on August 7, 2014. 
+7 
+Incorporated by reference to the Registrant's registration statement on Form 8-A filed with the Commission on April 7, 2016. 
+8 
+Incorporated by reference to the Registrant's Current Report on Form 8-K filed with the Commission on March 14, 2016. 
+9 
+Incorporated by reference to the Registrant's Current Report on Form 8-K filed with the Commission on June 17, 2015. 
+10 
+Incorporated by reference to the Registrant's Current Report on Form 8-K filed with the Commission on October 5, 2006. 
+11 
+Incorporated by reference to the Registrant's Annual Report on Form 10-K filed with the Commission on March 5, 2015. 
+12 
+Incorporated by reference to the Registrant's Annual Report on Form 10-KSB filed with the Commission on March 30, 2006. 
+13 
+Incorporated by reference to the Registrant's Current Report on Form 8-K filed with the Commission on April 7, 2016. 
+(*) 
+An asterisk (*) beside an exhibit number indicates the exhibit contains a management contract, compensatory plan or arrangement which is required to be identified in this report. 
+49 
+ITEM 16. Form 10-K Summary 
+None. 
+50 
+SIGNATURES 
+In accordance with Section 13 or 15(d) of the Exchange Act, the registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+CHEMBIO DIAGNOSTICS, INC. 
+March 7, 2017 
+By 
+/s/ John J. Sperzel 
+John J. Sperzel III 
+President, Chief Executive Officer and 
+Member of the Board 
+In accordance with the requirements of the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+Signatures 
+Title 
+Date 
+/s/ John J. Sperzel 
+Chief Executive Officer, President and 
+March 7, 2017 
+John J. Sperzel III 
+Member Of The Board 
+(Principal Executive Officer) 
+/s/ Richard J. Larkin 
+Chief Financial Officer (Principal Financial & 
+March 7, 2017 
+Richard J. Larkin 
+Accounting Officer) 
+/s/ Gary Meller 
+Director 
+March 7, 2017 
+Gary Meller 
+/s/ Katherine L. Davis 
+Director & Chair of the Board 
+March 7, 2017 
+Katherine L. Davis 
+/s/ Peter T. Kissinger 
+Director 
+March 7, 2017 
+Peter T. Kissinger 
+51 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+Index to Consolidated Financial Statements 
+—INDEX— 
+Page(s) 
+Report of Independent Registered Public Accounting Firm 
+F-1 
+Consolidated Financial Statements: 
+Balance Sheets as of December 31, 2016 and 2015 
+F-2 
+Statements of Operations for each of the years ended December 31, 2016, 2015 and 2014 
+F-3 
+Statements of Changes in Stockholders' Equity for each of the years ended December 31, 2016, 2015 and 2014 
+F-4 
+Statements of Cash Flows for each of the years ended December 31, 2016, 2015 and 2014 
+F-5 
+Notes to Consolidated Financial Statements 
+F-6 - F-19 
+Schedule II - Valuation and Qualifying Accounts 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+Board of Directors and Stockholders of 
+Chembio Diagnostics, Inc. 
+Medford, New York 
+We have audited the accompanying consolidated balance sheets of Chembio Diagnostics, Inc. and Subsidiary (the "Company") as of December 31, 2016 and 2015 and the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 2016. In connection with our audits of the consolidated financial statements, we have also audited the financial statement schedule as listed in the accompanying index. These consolidated financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and schedule based on our audits. 
+We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements and schedule, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements and schedule. We believe that our audits provide a reasonable basis for our opinion. 
+In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Chembio Diagnostics, Inc. and Subsidiary as of December 31, 2016 and 2015, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America. 
+Also, in our opinion the financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Chembio Diagnostics, Inc.'s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control – Integrated Framework 2013 issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 7, 2017 expressed an unqualified opinion thereon. 
+/s/ BDO USA, LLP 
+Melville, New York 
+March 7, 2017 
+F-1 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+CONSOLIDATED BALANCE SHEETS 
+AS OF 
+- ASSETS - 
+December 31, 2016 
+December 31, 2015 
+CURRENT ASSETS: 
+Cash and cash equivalents 
+$ 
+10,554,464 
+$ 
+5,376,931 
+Accounts receivable, net of allowance for doubtful accounts of $52,000 and $52,000 at December 31, 2016 and 2015, respectively 
+3,383,729 
+2,422,971 
+Inventories 
+3,335,188 
+3,578,025 
+Prepaid expenses and other current assets 
+840,145 
+1,256,879 
+TOTAL CURRENT ASSETS 
+18,113,526 
+12,634,806 
+FIXED ASSETS , net of accumulated depreciation 
+1,709,321 
+2,374,308 
+OTHER ASSETS: 
+Deferred tax asset, net of valuation allowance 
+- 
+5,467,143 
+License agreements, net of current portion 
+- 
+100,000 
+Deposits on manufacturing equipment 
+31,900 
+30,918 
+Deposits and other assets 
+720,489 
+209,169 
+TOTAL ASSETS 
+$ 
+20,575,236 
+$ 
+20,816,344 
+- LIABILITIES AND STOCKHOLDERS' EQUITY - 
+CURRENT LIABILITIES: 
+Accounts payable and accrued liabilities 
+$ 
+3,013,133 
+$ 
+2,801,432 
+Deferred revenue 
+392,517 
+353,406 
+TOTAL CURRENT LIABILITIES 
+3,405,650 
+3,154,838 
+TOTAL LIABILITIES 
+3,405,650 
+3,154,838 
+COMMITMENTS AND CONTINGENCIES (Note 13) 
+STOCKHOLDERS' EQUITY: 
+Preferred stock – 10,000,000 shares authorized, none outstanding 
+- 
+- 
+Common stock - $.01 par value; 100,000,000 shares authorized, 12,026,847 and 9,628,248 shares issued and outstanding for 2016 and 2015, respectively 
+120,268 
+96,282 
+Additional paid-in capital 
+60,721,783 
+47,890,642 
+Accumulated deficit 
+(43,672,465 
+) 
+(30,325,418 
+) 
+TOTAL STOCKHOLDERS' EQUITY 
+17,169,586 
+17,661,506 
+TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY 
+$ 
+20,575,236 
+$ 
+$ 20,816,344 
+See accompanying notes to condensed consolidated financial statements 
+F-2 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+CONSOLIDATED STATEMENTS OF OPERATIONS 
+For the years ended 
+December 31, 2016 
+December 31, 2015 
+December 31, 2014 
+REVENUES: 
+Net product sales 
+$ 
+13,680,107 
+$ 
+21,886,688 
+$ 
+25,949,769 
+License and royalty revenue 
+449,685 
+52,753 
+23,257 
+R&D, milestone and grant revenue 
+3,739,049 
+2,316,044 
+1,672,258 
+TOTAL REVENUES 
+17,868,841 
+24,255,485 
+27,645,284 
+Cost of product sales 
+9,417,505 
+13,768,658 
+16,831,261 
+GROSS MARGIN 
+8,451,336 
+10,486,827 
+10,814,023 
+OPERATING EXPENSES: 
+Research and development expenses 
+8,427,554 
+6,377,839 
+4,832,537 
+Selling, general and administrative expenses 
+7,595,559 
+7,663,035 
+7,531,739 
+16,023,113 
+14,040,874 
+12,364,276 
+LOSS FROM OPERATIONS 
+(7,571,777 
+) 
+(3,554,047 
+) 
+(1,550,253 
+) 
+OTHER INCOME (EXPENSE): 
+Other expense 
+- 
+(4,814 
+) 
+(5,707 
+) 
+Interest income 
+25,548 
+2,412 
+5,839 
+Interest expense 
+- 
+(836 
+) 
+- 
+25,548 
+(3,238 
+) 
+132 
+LOSS BEFORE INCOME TAXES (BENEFIT) 
+(7,546,229 
+) 
+(3,557,285 
+) 
+(1,550,121 
+) 
+Income tax provision (benefit) 
+5,800,818 
+(1,160,243 
+) 
+(412,918 
+) 
+NET LOSS 
+$ 
+(13,347,047 
+) 
+$ 
+(2,397,042 
+) 
+$ 
+(1,137,203 
+) 
+Basic loss per share 
+$ 
+$ (1.26 
+) 
+$ 
+(0.25 
+) 
+$ 
+(0.12 
+) 
+Diluted loss per share 
+$ 
+$ (1.26 
+) 
+$ 
+(0.25 
+) 
+$ 
+(0.12 
+) 
+Weighted average number of shares outstanding, basic 
+10,622,331 
+9,626,028 
+9,530,320 
+Weighted average number of shares outstanding, diluted 
+10,622,331 
+9,626,028 
+9,530,320 
+See accompanying notes to condensed consolidated financial statements 
+F-3 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY 
+FOR THE YEARS ENDED DECEMBER 31, 2016, 2015 AND 2014 
+Common Stock 
+Additional Paid- 
+in Capital 
+Accumulated 
+Deficit 
+Total 
+Shares 
+Amount 
+Amount 
+Amount 
+Amount 
+Balance at December 31, 2013 
+9,324,783 
+$ 
+93,248 
+$ 
+46,875,027 
+$ 
+(26,791,173 
+) 
+$ 
+20,177,102 
+Options: 
+Exercised 
+286,356 
+2,864 
+234,299 
+- 
+237,163 
+Stock option compensation 
+- 
+- 
+447,100 
+- 
+447,100 
+Net loss 
+(1,137,203 
+) 
+(1,137,203 
+) 
+Balance at December 31, 2014 
+9,611,139 
+$ 
+96,112 
+$ 
+47,556,426 
+$ 
+(27,928,376 
+) 
+$ 
+19,724,162 
+Options: 
+Exercised 
+17,109 
+170 
+(170 
+) 
+- 
+- 
+Stock option compensation 
+- 
+- 
+334,386 
+- 
+334,386 
+Net loss 
+- 
+- 
+- 
+(2,397,042 
+) 
+(2,397,042 
+) 
+Balance at December 31, 2015 
+9,628,248 
+$ 
+96,282 
+$ 
+47,890,642 
+$ 
+(30,325,418 
+) 
+$ 
+17,661,506 
+Common Stock: 
+New stock from offering 
+2,300,000 
+23,000 
+12,470,398 
+- 
+12,493,398 
+Options: 
+Exercised 
+98,599 
+986 
+56,589 
+- 
+57,575 
+Stock option compensation 
+- 
+- 
+304,154 
+- 
+304,154 
+Net loss 
+- 
+- 
+- 
+(13,347,047 
+) 
+(13,347,047 
+) 
+Balance at December 31, 2016 
+12,026,847 
+$ 
+120,268 
+$ 
+60,721,783 
+$ 
+(43,672,465 
+) 
+$ 
+17,169,586 
+See accompanying notes to consolidated financial statements 
+F-4 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+FOR THE YEARS ENDED 
+December 31, 2016 
+December 31, 2015 
+December 31, 2014 
+CASH FLOWS FROM OPERATING ACTIVITIES: 
+Cash received from customers and grants 
+$ 
+16,947,194 
+$ 
+30,174,083 
+$ 
+23,898,516 
+Cash paid to suppliers and employees 
+(23,677,476 
+) 
+(28,382,681 
+) 
+(27,724,654 
+) 
+Interest received 
+25,548 
+2,412 
+5,839 
+Interest paid 
+- 
+(836 
+) 
+- 
+Net cash provided by (used in) operating activities 
+(6,704,734 
+) 
+1,792,978 
+(3,820,299 
+) 
+CASH FLOWS FROM INVESTING ACTIVITIES: 
+Acquisition of license 
+- 
+(550,000 
+) 
+- 
+Deposit for investment in RVR 
+(550,000 
+) 
+- 
+- 
+Acquisition of and deposits on fixed assets 
+(118,706 
+) 
+(480,585 
+) 
+(1,452,601 
+) 
+Net cash used in investing activities 
+(668,706 
+) 
+(1,030,585 
+) 
+(1,452,601 
+) 
+CASH FLOWS FROM FINANCING ACTIVITIES: 
+Proceeds from option and warrant exercises 
+57,575 
+- 
+237,163 
+Proceeds from credit line 
+- 
+700,000 
+- 
+Repayment of credit line 
+- 
+(700,000 
+) 
+- 
+Proceeds from sale of common stock, net 
+12,493,398 
+- 
+- 
+Net cash provided by financing activities 
+12,550,973 
+- 
+237,163 
+(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS 
+5,177,533 
+762,393 
+(5,035,737 
+) 
+Cash and cash equivalents - beginning of the period 
+5,376,931 
+4,614,538 
+9,650,275 
+Cash and cash equivalents - end of the period 
+$ 
+10,554,464 
+$ 
+5,376,931 
+$ 
+4,614,538 
+RECONCILIATION OF NET LOSS TO NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES: 
+Net Loss 
+$ 
+(13,347,047 
+) 
+$ 
+(2,397,042 
+) 
+$ 
+(1,137,203 
+) 
+Adjustments: 
+Depreciation and amortization 
+1,139,228 
+1,372,563 
+739,297 
+Provision for (benefit from) deferred taxes 
+5,800,818 
+(1,170,969 
+) 
+(403,375 
+) 
+Provision for (recovery of) doubtful accounts 
+- 
+- 
+28,000 
+Share based compensation 
+304,154 
+334,386 
+447,100 
+Changes in assets and liabilities: 
+Accounts receivable 
+(960,758 
+) 
+5,915,918 
+(3,774,768 
+) 
+Inventories 
+242,837 
+60,274 
+(449,573 
+) 
+Prepaid expenses and other current assets 
+(136,258 
+) 
+(190,960 
+) 
+32,906 
+Deposits and other assets 
+1,480 
+- 
+(279,223 
+) 
+Accounts payable and accrued liabilities 
+211,701 
+(2,144,598 
+) 
+636,540 
+Customer deposits and deferred revenue 
+39,111 
+13,406 
+340,000 
+Net cash provided by (used in) operating activities 
+$ 
+(6,704,734 
+) 
+$ 
+1,792,978 
+$ 
+(3,820,299 
+) 
+Supplemental disclosures for non-cash investing and financing activities: 
+Deposits on manufacturing equipment transferred to fixed assets 
+$ 
+- 
+$ 
+20,017 
+$ 
+603,627 
+See accompanying notes to condensed consolidated financial statements 
+F-5 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2016, 2015 AND 2014 
+NOTE 1 — DESCRIPTION OF BUSINESS: 
+Chembio Diagnostics, Inc. and its subsidiary, Chembio Diagnostic Systems, Inc. (collectively, the "Company" or "Chembio"), develop, manufacture, and market rapid diagnostic tests that detect infectious diseases. The Company's main lateral flow products are three rapid tests for the detection of HIV antibodies in whole blood, serum and plasma samples, two of which were approved by the FDA in 2006; the third is sold for export only. Lateral Flow Rapid HIV tests represented nearly 58% of the Company's product revenues in 2016. The Company's products based on its patented DPP® platform represented approximately 40% of the Company's product revenues in 2016. The Company also has other rapid tests that together represented approximately 2% of sales in 2016. The Company's products are sold to medical laboratories and hospitals, governmental and public health entities, non-governmental organizations, medical professionals and retail establishments both domestically and internationally. Chembio's products are sold under the Company's STAT-PAK®, SURE CHECK®, STAT VIEW® or DPP® registered trademarks, or under the private labels of its marketing partners. All of the Company's products that are currently being developed are based on its patented Dual Path Platform (DPP®), which is a unique diagnostic point-of-care platform that has certain advantages over lateral flow technology. In December 2012, the Company received FDA approval for its DPP® HIV 1/2 Assay for the detection of HIV antibodies in saliva, whole blood, serum and plasma samples, which was CLIA-Waived in October 2014. 
+NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES: 
+(a) 
+Principles of Consolidation: 
+The consolidated financial statements include the accounts of the Company and its wholly owned subsidiary. All intercompany transactions and balances have been eliminated in consolidation. 
+(b) 
+Use of Estimates: 
+The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make assumptions and estimates that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods covered thereby. Actual results could differ from these estimates. Judgments and estimates of uncertainties are required in applying the Company's accounting policies in certain areas. The following are some of the areas requiring significant judgments and estimates: determinations of the useful lives of assets, estimates of allowances for doubtful accounts, inventory reserves, stock-based compensation and deferred tax assets. 
+(c) 
+Fair Value of Financial Instruments: 
+The carrying value for cash and cash equivalents, accounts receivable and accounts payable, approximate fair value because of the immediate or short-term maturity of these financial instruments. 
+(d) 
+Statements of Cash Flows: 
+For purposes of the statements of cash flows, the Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents. 
+(e) 
+Concentrations of Credit Risk: 
+Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of temporary cash investments and trade receivables. The Company places its temporary cash instruments with well-known financial institutions and, at times, may maintain balances in excess of the FDIC insurance limit. The Company monitors the credit ratings of the financial institutions to mitigate this risk. Concentration of credit risk with respect to trade receivables is principally mitigated by the Company's ability to obtain letters of credit from certain foreign customers, and its diverse customer base both in number of customers and geographic locations. 
+F-6 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2016, 2015 AND 2014 
+(f) 
+Inventories: 
+Inventories, consisting of material, labor and manufacturing overhead, are stated at the lower of cost or market. Cost is determined on the first-in, first-out method. 
+(g) 
+Fixed Assets: 
+Fixed assets are stated at cost, less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the respective assets, which range from three to seven years. Leasehold improvements are amortized over the useful life of the asset or the lease term, whichever is shorter. Deposits paid for fixed assets are capitalized and not depreciated until the related asset is placed in service. 
+(h) 
+License Agreements: 
+In February 2008, the Company entered into a sublicense agreement for which it had initially recorded an asset of $1,000,000. This asset is being expensed over an estimated economic life of ten years, based on the expected lifespan of our then current HIV products. The current portion of this asset is $100,000 as of December 31, 2016 and 2015 and is reported in prepaid expenses and other current assets. The long-term portion as of December 31, 2016 and 2015 is $- and $100,000, respectively and is reflected in other assets on the consolidated balance sheet. 
+In January 2015, the Company entered into a sublicense agreement for which it had initially recorded an asset of $400,000. This asset is being expensed over the life of the patent of 22 months. The current portion of this asset is $- and $181,818 as of December 31, 2016 and 2015, respectively and is reported in prepaid expenses. The long-term portion as of December 31, 2016 and 2015 is $- and $-, respectively and is reflected in other assets on the consolidated balance sheet. 
+In August 2015, the Company entered into a sublicense agreement for which it had initially recorded an asset of $100,000. This asset is being validated and will be expensed over the estimated economic life of the product(s) which will utilize this sublicense. The current portion of this asset is $100,000 as of December 31, 2016 and 2015 and is reported in prepaid expenses and other current assets. The long-term portion of this asset is $- as of December 31, 2016 and 2015. 
+Amortization expenses for the licenses above for the years ended December 31, 2016, 2015 and 2014 were $357,000, $479,000 and $122,000. 
+(i) 
+Impairment of Long-Lived Assets and Intangible Assets 
+Long-lived assets to be held and used are analyzed for impairment whenever events or changes in circumstances indicate that the related carrying amounts may not be recoverable. The Company evaluates at each balance sheet date whether events and circumstances have occurred that indicate possible impairment. If there are indications of impairment, the Company uses future undiscounted cash flows of the related asset or asset grouping over the remaining life in measuring whether the assets are recoverable. In the event such cash flows are not expected to be sufficient to recover the recorded asset values, the assets are written down to their estimated fair value. We believe that the carrying values of our long-lived tangible and intangible assets were realizable at December 31, 2016 and 2015, respectively. 
+(j) 
+Revenue Recognition: 
+The Company recognizes revenue for product sales in accordance with ASC 605, revenue is recognized when there is persuasive evidence of an arrangement, delivery has occurred or services have been rendered, the sales price is fixed and determinable, and collectability is reasonably assured. Revenue typically is recognized at time of shipment. Sales are recorded net of discounts, rebates and returns. 
+For certain contracts, the Company recognizes revenue from non-milestone contracts and grant revenues when earned. Grants are invoiced after expenses are incurred. Revenues from projects or grants funded in advance are deferred until earned. 
+F-7 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2016, 2015 AND 2014 
+The Company follows Financial Accounting Standards Board ("FASB") Accounting Standards for the recognition of revenue under the milestone method. The Company applies the milestone method of revenue recognition for certain collaborative research projects defining milestones at the inception of the agreement. 
+(k) 
+Research and Development: 
+Research and development (R&D) costs are expensed as incurred. 
+(l) 
+Stock-Based Compensation: 
+Stock-based compensation expense is calculated using the Black-Scholes valuation model based on awards ultimately expected to vest, reduced for forfeitures, and expensed on a straight-line basis over the requisite service period of the grant. 
+(m) 
+I ncome Taxes: 
+The Company accounts for income taxes under an asset and liability approach which recognizes deferred tax assets and liabilities based on the difference between the financial statement carrying amounts and the tax bases of assets and liabilities using enacted tax rates in effect in the years in which the differences are expected to reverse. 
+The Company follows a more-likely-than-not threshold for financial statement recognition and measurement of a tax position taken, or expected to be taken, in a tax return. The guidance relates to, among other things, classification, accounting for interest and penalties associated with tax positions, and disclosure requirements. Any interest and penalties accrued related to uncertain tax positions will be recorded in tax expense. 
+The Company assesses the realizability of its net deferred tax assets on an annual basis. If, after considering all relevant positive and negative evidence, it is more likely than not that some portion or all of the net deferred tax assets will not be realized, the Company would reduce the net deferred tax assets by a valuation allowance. The realization of the net deferred tax assets is dependent on several factors, including the generation of sufficient taxable income prior to the expiration of net operating loss carryforwards. 
+(n) 
+Loss Per Share 
+The following weighted average shares were used for the computation of basic and diluted earnings per share: 
+For the years ended 
+December 31, 2016 
+December 31, 2015 
+December 31, 2014 
+Basic 
+10,622,331 
+9,626,028 
+9,530,320 
+Diluted 
+10,622,331 
+9,626,028 
+9,530,320 
+Basic loss per share is computed by dividing net loss attributable to common stockholders by the weighted-average number of common shares outstanding for the period. Diluted loss per share for the year ended December 31, 2016, 2015 and 2014 reflects the potential dilution from the exercise or conversion of other securities into common stock, if dilutive. 
+The following securities, presented on a common share equivalent basis, have been used in the diluted per share computations: 
+For the years ended 
+December 31, 2016 
+December 31, 2015 
+December 31, 2014 
+1999, 2008 and 2014 Plan Stock Options 
+- 
+- 
+- 
+There were 600,549, 658,631 and 798,475 options and warrants outstanding as of December 31, 2016, 2015 and 2014, respectively, which were not included in the calculation of diluted income per share for the years ended because their effect would have been anti-dilutive. 
+F-8 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2016, 2015 AND 2014 
+(o) 
+Recent Accounting Pronouncements Affecting the Company: 
+In May 2014, the FASB issued Accounting Standards Update No. 2014-09, "Revenue from Contracts with Customers" ("ASU 2014-09"), which supersedes nearly all existing revenue recognition guidance under accounting principles generally accepted in the United States ("U.S. GAAP"). The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing U.S. GAAP. 
+The standard is effective for annual periods beginning after December 15, 2017, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients; or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We are currently evaluating the impact of our pending adoption of ASU 2014-09 on our consolidated financial statements and have not yet determined the method by which we will adopt the standard in 2018. The Company has conducted a preliminary analysis of its sales contracts which are based on the shipment of goods to the customer, and currently this new accounting standard will not have a material impact on its consolidated financial statement for our sales contracts. The Company has conducted a preliminary analysis of its current R&D contracts which are currently based on "as expenses are incurred" basis, and currently this new accounting standard will not have a material impact on its consolidated financial statement for our current R&D contracts. 
+In November 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-17, Income Taxes (Topic 740) Balance Sheet Classification of Deferred Assets. This ASU is intended to simplify the presentation of deferred taxes on the balance sheet and will require an entity to present all deferred tax assets and deferred tax liabilities as non-current on the balance sheet. Under the current guidance, entities are required to separately present deferred taxes as current or non-current. Netting deferred tax assets and deferred tax liabilities by tax jurisdiction will still be required under the new guidance. This guidance will be effective for Chembio beginning in 2018, with early adoption permitted. The Company does not believe this new accounting standard update will have a material impact on its consolidated financial statements. 
+In February 2016, the FASB issued Accounting Standards Update ("ASU") 2016-02, which amends the ASC and creates Topic 842, Leases. Topic 842 will require lessees to recognize lease assets and lease liabilities for those leases classified as operating leases under previous US GAAP on the balance sheet. This guidance is effective for annual periods beginning after December 15, 2018 and early adoption is permitted. We are in the initial stages of evaluating the effect of the standard on our financial statements and will continue to evaluate. While not yet in a position to assess the full impact of the application of the new standard, the Company expects that the impact of recording the lease liabilities and the corresponding right-to-use assets will have a significant impact on its total assets and liabilities with a minimal impact on equity. 
+In March 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which will change certain aspects of accounting for share-based payments to employees. ASU 2016-09 is effective for fiscal years (and interim reporting periods within those years) beginning after December 15, 2016. The Company is currently in the initial stages of evaluating the impact of the provisions of ASU 2016-09. We are still evaluating this standard and currently the Company does not believe this new accounting standard will have a material impact on its consolidated financial statement. 
+NOTE 3 — INVENTORIES: 
+Inventories consist of the following at: 
+December 31, 2016 
+December 31, 2015 
+Raw materials 
+$ 
+1,824,248 
+$ 
+2,248,371 
+Work in process 
+535,320 
+370,340 
+Finished goods 
+975,620 
+959,314 
+$ 
+3,335,188 
+$ 
+3,578,025 
+F-9 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2016, 2015 AND 2014 
+NOTE 4 — FIXED ASSETS: 
+Fixed assets consist of the following at: 
+December 31, 2016 
+December 31, 2015 
+Machinery and equipment 
+$ 
+3,962,051 
+$ 
+3,862,698 
+Furniture and fixtures 
+437,962 
+436,588 
+Computer and telephone equipment 
+343,167 
+326,170 
+Leasehold improvements 
+2,012,945 
+2,012,945 
+6,756,125 
+6,638,401 
+Less accumulated depreciation and amortization 
+(5,046,804 
+) 
+(4,264,093 
+) 
+$ 
+1,709,321 
+$ 
+2,374,308 
+There were no capital leases at the end of December 31, 2016. Fixed assets at December 31, 2016 also include $199,921 in equipment, which has been delivered and set-up but is undergoing validation and as such is currently not being depreciated. Depreciation expense for the 2016, 2015 and 2014 years aggregated $782,711, $893,305 and $616,943, respectively. 
+As of December 31, 2016 and 2015, the Company had paid deposits on various pieces of equipment aggregating $31,900 and $30,918, respectively. 
+NOTE 5 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES: 
+Accounts payable and accrued liabilities consist of the following at: 
+December 31, 2016 
+December 31, 2015 
+Accounts payable – suppliers 
+$ 
+1,437,290 
+$ 
+1,260,520 
+Accrued commissions 
+221,982 
+129,192 
+Accrued royalties / license fees 
+352,660 
+732,301 
+Accrued payroll 
+167,575 
+146,962 
+Accrued vacation 
+289,587 
+244,810 
+Accrued bonuses 
+282,500 
+177,700 
+Accrued expenses – other 
+261,539 
+109,947 
+TOTAL 
+$ 
+3,013,133 
+$ 
+2,801,432 
+NOTE 6 — DEFERRED RESEARCH AND DEVELOPMENT REVENUE: 
+The Company recognizes income from R&D milestones when those milestones are reached and non-milestone contracts and grants when earned. Grants are invoiced after expenses are incurred. Any projects or grants funded in advance are deferred until earned. As of December 31, 2016 and 2015, there were $392,517 and $353,406 unearned advanced revenues, respectively. 
+NOTE 7 — TERM NOTE, REVOLVING DEMAND NOTE, VEHICLE FINANCING AND LICENSE FEE PAYABLE: 
+On April 30, 2013, the Company entered into a new demand loan agreement ("Demand Note") with HSBC Bank, USA ("HSBC"). The Demand Note allowed the Company to draw on the line from time to time an amount up to an aggregate of $2,000,000 outstanding at any one time. The accrued interest on the Demand Note was payable monthly at an interest rate equal to one-quarter percent above prime per annum. The Company could repay any or all of the principal balance outstanding at any time. This was a demand note for which the bank lender could demand repayment of the entire loan, with accrued interest, at any time. The loan was subject to annual reviews, as well as an annual 30-day clean-up, during which there could be no amounts outstanding. In January 2016 HSBC notified the Company that it could no longer extend the credit and the Demand Note was cancelled. 
+The Security Agreement, related to the Demand Note, contained covenants that placed restrictions on the Company's operations, including covenants relating to mergers, debt restrictions, capital expenditures, tangible net worth, net profit, leverage, fixed charge coverage, employee loan restrictions, distribution restrictions (common stock and preferred stock), dividend restrictions, restrictions on lease payments to affiliates, restrictions on changes in business, asset sale restrictions, restrictions on acquisitions and intercompany transactions, and restrictions on fundamental changes in the Company and in its business. 
+The Company currently maintains its operating, payroll, and primary cash accounts at HSBC. 
+F-10 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2016, 2015 AND 2014 
+NOTE 8 — INCOME TAXES: 
+The (benefit from) provision for income taxes for the years ended December 31, 2016 and 2015, is comprised of the following: 
+2016 
+2015 
+2014 
+Current 
+Federal 
+$ 
+- 
+$ 
+- 
+$ 
+(16,119 
+) 
+State 
+- 
+10,726 
+6,576 
+Total current (benefit) provision 
+- 
+10,726 
+(9,543 
+) 
+Deferred 
+Federal 
+5,778,185 
+(1,171,865 
+) 
+(449,452 
+) 
+State 
+22,633 
+896 
+46,077 
+Total deferred (benefit) provision 
+5,800,818 
+(1,170,969 
+) 
+(403,375 
+) 
+Total (benefit) provision 
+$ 
+5,800,818 
+$ 
+(1,160,243 
+) 
+(412,918 
+) 
+The Company had an ownership change as described in Internal Revenue Code Sec. 382 during 2004 ("2004 change"). As a result, the Company's net operating losses prior to the 2004 change of $5,832,516 were subject to an annual limitation of $150,608 and for the first five (5) years are entitled to a BIG (Built-In-Gains) of $488,207 per year. These net operating losses expire in 2018 through 2024. 
+The Company had a second ownership change during 2006 ("2006 change"). The net operating losses incurred between the 2004 change and the 2006 change of $8,586,861 were subject to an annual limitation of $1,111,831 and for the first five (5) years are entitled to a BIG of $1,756,842 per year. These net operating losses expire in 2018 through 2028. 
+After applying the above limitations, at December 31, 2016, the Company has post-change net operating loss carry-forwards of approximately $21,960,362 which expire between 2020 and 2036. In addition the Company has research and development tax credit carryforwards of approximately $1,461,351 for the year ended December 31, 2016, which expire between 2025 and 2036. 
+2016 
+2015 
+Current assets 
+Inventory reserves 
+$ 
+253,380 
+$ 
+242,532 
+Accrued expenses 
+53,140 
+91,143 
+Current deferred tax assets 
+306,520 
+333,675 
+Less valuation allowances 
+(306,520 
+) 
+- 
+Net current deferred asset 
+$ 
+- 
+$ 
+333,675 
+Noncurrent assets 
+Net operating loss carry-forwards 
+$ 
+7,487,937 
+$ 
+5,365,401 
+Research and development credit 
+1,461,351 
+1,518,414 
+Other credits 
+97,339 
+97,339 
+Depreciation 
+31,285 
+(206,150 
+) 
+Other 
+292,556 
+210,553 
+Noncurrent deferred tax assets 
+9,370,468 
+6,985,557 
+Less valuation allowances 
+(9,370,468 
+) 
+(1,518,414 
+) 
+Net noncurrent deferred tax assets 
+$ 
+- 
+$ 
+5,467,143 
+F-11 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2016, 2015 AND 2014 
+A reconciliation of the Federal statutory rate to the effective rate applicable to income (loss) before income taxes is as follows: 
+Year Ending December 31, 
+2016 
+2015 
+2014 
+Federal income tax at statutory rates 
+(34.00)% 
+(34.00)% 
+(34.00)% 
+State income taxes, net of federal benefit 
+.21% 
+0.23% 
+0.28% 
+Nondeductible expenses 
+.57% 
+1.38% 
+4.54% 
+Change in valuation allowance 
+114.81% 
+9.46% 
+9.47% 
+Tax credits 
+.00% 
+(9.46)% 
+(9.47)% 
+Change in tax rates 
+.00% 
+0.00% 
+1.96% 
+Other 
+.04% 
+0.34% 
+0.58% 
+Income tax (benefit) 
+81.63% 
+(32.05)% 
+(26.64)% 
+Interest and penalties, if any, related to income tax liabilities are included in income tax expense. As of December 31, 2016, the Company does not have a liability for uncertain tax positions. 
+The Company files Federal and state income tax returns. Tax years for fiscal 2013 through 2015 are open and potentially subject to examination by the federal and state taxing authorities. 
+NOTE 9 — STOCKHOLDERS' EQUITY: 
+(a) 
+Common Stock 
+In August of 2016, the Company closed on an underwritten public offering of 2,300,000 shares of its common stock at $6.00 per share. The net proceeds of the offering, after deducting the underwriters' discounts and other offering expenses payable by the Company, was approximately $12,493,000. The Company intends to use the net proceeds for business expansion and working capital. 
+During 2016, options to purchase 191,804 shares of the Company's common stock were exercised on a cashless basis into 98,599 shares of common stock at exercise prices ranging from $2.80 to $5.56 by surrendering options and shares of common stock already owned . 
+During 2015, options to purchase 41,141 shares of the Company's common stock were exercised, either for cash or cashless, into 17,109 shares of common stock at exercise prices ranging from $2.16 to $3.60 by paying cash or surrendering options already owned. 
+During 2014, options to purchase 318,750 shares of the Company's common stock were exercised, either for cash or cashless, into 286,356 shares of common stock at an exercise price of $1.04 by paying cash or surrendering options already owned 
+(b) 
+Preferred Stock 
+The Company has 10,000,000 shares of preferred stock authorized and none outstanding. These shares can become issuable upon an approved resolution by the board of directors and the filing of a Certificate of Designation with the state of Nevada. 
+(c) 
+Options 
+During the fourth quarter of 2016, the Company issued options to purchase 36,000 shares of common stock to a newly-hired president of the EMEA and APAC regions. The options are exercisable in three equal annual installments starting on the first anniversary of the date of issue. The options issued have an exercise price of $7.15 per share, which was the last traded price of the common stock on the day issued. The options expire five years from date of issue. 
+During the second quarter of 2016 the Company issued options to purchase 46,875 shares of common stock to one of its directors pursuant to the Company's compensation policy for directors. The options become exercisable in five equal annual installments starting on the date of issue. The options issued have an exercise price of $8.860 per share, which was the last traded price of the common stock on the day issued. The options expire five years from date of issue. 
+F-12 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2016, 2015 AND 2014 
+The Company entered into an employment agreement, effective as of March 5, 2016 (the "Employment Agreement"), with Javan Esfandiari to serve as the Company's Chief Scientific and Technical Officer, for an additional term of three years through March 5, 2019. Pursuant to the Employment Agreement, the Company issued to Mr. Esfandiari incentive and non-qualified stock options to purchase 60,000 shares of the Company's common stock. Of these stock options, options to purchase 20,000 shares vest on each of the first three anniversaries of March 11, 2016 which is the date on which the Employment Agreement was entered into. The exercise price for these options was to be equal to the trading price for the Company's common stock on March 11, 2016, which was $5.64 per share. Each option granted will expire and terminate, if not exercised sooner, upon the earlier to occur of (a) 30 days after termination of Mr. Esfandiari's employment with the Company or (b) the fifth anniversary of the effective date of the grant. 
+During 2015, the Company did not issue options to purchase common stock. 
+During the fourth quarter of 2014, the Company issued options to purchase 36,000 shares of common stock to a newly-hired vice-president of the Company. The options are exercisable in three equal annual installments starting on the first anniversary of the date of issue. The options issued have an exercise price of $4.35 per share, which was the last traded price of the common stock on the day issued. The options expire five years from date of issue. 
+During the second quarter of 2014 the Company issued options to two of its directors pursuant to the Company's compensation policy for directors. Each director was issued options to purchase 46,875 shares of common stock. The options become exercisable in five equal annual installments starting on the date of issue. The options issued have an exercise price of $3.480 per share, which was the last traded price of the common stock on the day issued. The options expire five years from date of issue. 
+The Company entered into an employment agreement, effective March 13, 2014 ("Employment Agreement"), with Mr. Sperzel to serve as the Company's Chief Executive Officer, which included issuing incentive and non-incentive stock options to purchase 250,000 shares of the Company's common stock. The options become exercisable in five equal annual installments starting on the first anniversary of the effective date of the Employment Agreement. The exercise price for these options was to be equal to the volume-weighted average trading price for the Company's common stock on March 13, 2014, which was $3.416 per share. The options expire seven years from date of issue. 
+(d) 
+Warrants 
+As of December 31, 2016 and 2015, the Company had no warrants outstanding to purchase shares of common stock. 
+NOTE 10 — RIGHTS AGREEMENT: 
+In March 2010, the Company entered into a Rights Agreement (the "Rights Agreement") between the Company and Action Stock Transfer Corp., as Rights Agent. The Rights Agreement expired at the end of November 2015. Pursuant to the Rights Agreement, the Company declared a dividend distribution of one preferred share purchase right (a "Right") for each outstanding share of Common Stock, $0.01 par value (the "Common Stock"), of the Company. The Board of Directors set the payment date for the distribution of the Rights as March 8, 2010, and the Rights were distributed to the Company's shareholders of record on that date. The description and terms of the Rights are set forth in the Rights Agreement. 
+Rights Initially Not Exercisable. The Rights were not exercisable until a Distribution Date. Until a Right was exercised, the holder thereof, as such, would have no rights as a shareholder of the Company, including, without limitation, the right to vote or to receive dividends. 
+F-13 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2016, 2015 AND 2014 
+Separation and Distribution of Rights . The Rights were to be evidenced by the certificates for shares of Common Stock registered in the names of the holders thereof, and not by separate rights certificates until the earlier to occur of (i) the close of business on the tenth business day following a public announcement that an Acquiring Person (as defined in the Rights Agreement) acquired a Combined Ownership (as defined in the Rights Agreement) of 20% or more of the outstanding shares of the Common Stock (the "Shares Acquisition Date") or (ii) the later of (A) the close of business on the tenth business day (or such later date as may be determined by action of the Board of Directors prior to such time as any person or group of affiliated or associated persons becomes an Acquiring Person) after the date that a tender or exchange offer or intention to commence a tender or exchange offer by any person is first published, announced, sent or given within the meaning of Rule 14d-4(A) under the Securities Exchange Act of 1934, as amended, the consummation of which would result in any person having Combined Ownership of 20% or more of the outstanding shares of the Common Stock, or (B) if such a tender or exchange offer has been published, announced, sent or given before the date of the Rights Agreement, then the close of business on the tenth business day after the date the Rights Agreement was entered into (or such later date as may be determined by action of the Board of Directors prior to such time as any person becomes an Acquiring Person); (the earlier of such dates referred to in (i) and (ii), which date may include any such date that is after the date of the Rights Agreement but prior to the issuance of the Rights, being called the "Distribution Date"). 
+NOTE 11 — EMPLOYEE STOCK OPTION PLAN: 
+Effective June 3, 2008, the Company's stockholders voted to approve the 2008 Stock Incentive Plan ("SIP"), with 625,000 shares of Common Stock available to be issued. At the Annual Stockholder meeting on September 22, 2011 the Company's stockholders voted to approve an increase to the shares of Common Stock issuable under the SIP by 125,000 to 750,000. Under the terms of the SIP, the Compensation Committee of the Company's Board has the discretion to select the persons to whom awards are to be granted. Awards can be stock options, restricted stock and/or restricted stock units. The awards become vested at such times and under such conditions as determined by the Compensation Committee. As of December 31, 2016, there were 467,685 options exercised, 275,931 options outstanding and 6,384 options still available to be issued under the SIP. 
+Effective June 19, 2014, the Company's stockholders voted to approve the 2014 Stock Incentive Plan ("SIP14"), with 800,000 shares of Common Stock available to be issued. Under the terms of the SIP14, the Compensation Committee of the Company's Board has the discretion to select the persons to whom awards are to be granted. Awards can be stock options, restricted stock and/or restricted stock units. The awards become vested at such times and under such conditions as determined by the Compensation Committee. As of December 31, 2016, there were 12,000 options exercised, 117,750 options outstanding and 670,250 options still available to be issued under the SIP14. 
+The Company's results for the years ended December 31, 2016, 2015 and 2014 include stock-based compensation expense totaling $304,100, $334,400, and $447,100 respectively. Such amounts have been included in the Consolidated Statements of Operations within cost of goods sold ($-, $-, and $700 respectively), research and development ($89,200, $62,700, and $44,500 respectively) and selling, general and administrative expenses ($214,900, $271,700, and $401,900 respectively). In accordance with ASC 718 the Company has not recorded a deferred tax asset related to the net operating losses resulting from the exercise of disqualifying stock options in the accompanying financial statements. 
+Stock option compensation expense in the years ended December 31, 2016, 2015 and 2014 represents the estimated fair value of options outstanding which is being amortized on a straight-line basis over the requisite vesting period of the entire award. 
+The weighted average estimated fair value of stock options granted in the year ended December 31, 2016 was $2.75 per share. The Company did not grant any stock options during the year ended December 31, 2015 . The weighted average estimated fair value of stock options granted in the year ended December 31, 2014 was $3.52 per share. The fair value of options at the date of grant was estimated using the Black-Scholes option pricing model. The expected volatility is based upon historical volatility of our stock and other contributing factors. The expected term is based on the Company's historical experience with similar type options. 
+The weighted-average assumptions made in calculating the fair values of options are as follows: 
+For the year ended 
+December 31, 2016 
+December 31, 2015 
+December 31, 2014 
+Expected term (in years) 
+4.71 
+n/a 
+4.50-6.30 
+Expected volatility 
+45.78 % 
+n/a 
+61.50-96.10% 
+Expected dividend yield 
+n/a 
+n/a 
+n/a 
+Risk-free interest rate 
+0.92 % 
+n/a 
+.83-1.52% 
+F-14 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2016, 2015 AND 2014 
+The Company granted 142,875 new options during the year ended December 31, 2016 to employees and directors. 
+The following table provides stock options activity for the year ended December 31, 2016: 
+Stock Options 
+Number of 
+Shares 
+Weighted 
+Average Exercise Price per Share 
+Weighted Average 
+Remaining Contractual Term 
+Aggregate Intrinsic 
+Value 
+Outstanding at December 31, 2013 
+656,398 
+2.57 
+1.65 years 
+$ 
+801,888 
+Granted 
+379,750 
+3.52 
+Exercised 
+318,750 
+1.04 
+341,729 
+Forfeited/expired/cancelled 
+25,529 
+3.17 
+Outstanding at December 31, 2014 
+691,869 
+3.66 
+3.97 years 
+$ 
+334,636 
+Exercisable at December 31, 2014 
+265,619 
+3.67 
+1.94 years 
+$ 
+158,149 
+Outstanding at December 31, 2014 
+691,869 
+3.66 
+3.97 years 
+$ 
+334,636 
+Granted 
+- 
+- 
+Exercised 
+41,141 
+2.25 
+65,449 
+Forfeited/expired/cancelled 
+1,250 
+4.30 
+Outstanding at December 31, 2015 
+649,478 
+3.75 
+3.21 years 
+$ 
+1,032,362 
+Exercisable at December 31, 2015 
+359,228 
+3.89 
+2.03 years 
+$ 
+522,039 
+Outstanding at December 31, 2015 
+649,478 
+$ 
+3.75 
+3.21 years 
+$ 
+1,032,362 
+Granted 
+142,875 
+$ 
+7.08 
+Exercised 
+191,804 
+$ 
+3.73 
+629,143 
+Forfeited/expired/cancelled 
+- 
+$ 
+- 
+Outstanding at December 31, 2016 
+600,549 
+$ 
+4.55 
+3.43 years 
+$ 
+1,463,052 
+Exercisable at December 31, 2016 
+267,549 
+$ 
+4.14 
+2.66 years 
+$ 
+731,997 
+The following table summarizes information about stock options outstanding at December 31, 2016: 
+Stock Options Outstanding 
+Stock Options Exercisable 
+Range of 
+Exercise 
+Prices 
+Shares 
+Average 
+Remaining 
+Contract Life 
+(Year) 
+Weighted 
+Average 
+Exercise 
+Price 
+Aggregate 
+Intrinsic 
+Value 
+Shares 
+Weighted 
+Average 
+Exercise 
+Price 
+Aggregate 
+Intrinsic 
+Value 
+1 to 2.79999 
+- 
+- 
+$ 
+- 
+$ 
+- 
+- 
+$ 
+- 
+$ 
+- 
+2.8 to 4.59999 
+419,719 
+3.30 
+3.60 
+1,342,788 
+220,219 
+3.71 
+681,333 
+4.6 to 6.39999 
+97,955 
+3.02 
+5.57 
+120,264 
+37,955 
+5.47 
+50,664 
+6.4 to 8.19999 
+36,000 
+4.78 
+7.15 
+- 
+- 
+- 
+- 
+8.2 to 10 
+46,875 
+4.44 
+8.86 
+- 
+9,375 
+8.86 
+- 
+Total 
+600,549 
+3.43 
+$ 
+4.55 
+$ 
+1,463,052 
+267,549 
+$ 
+4.14 
+$ 
+731,997 
+F-15 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2016, 2015 AND 2014 
+As of December 31, 2016, there was $386,000 of net unrecognized compensation cost related to stock options that are not vested, which is expected to be recognized over a weighted average period of approximately 2.32 years. The total fair value of shares vested during the year ended December 31, 2016, was $262,000. 
+NOTE 12 — GEOGRAPHIC INFORMATION AND ECONOMIC DEPENDENCY: 
+FASB Guidance establishes standards for the way that business enterprises report information about operating segments in financial statements and requires that those enterprises report selected information. It also establishes standards for related disclosures about product and services, geographic areas, and major customers. 
+The Company produces only one group of similar products known collectively as "rapid medical tests". Management believes that it operates in a single business segment. Net sales by geographic area are as follows: 
+For the years ended 
+December 31, 2016 
+December 31, 2015 
+December 31, 2014 
+Africa 
+$ 
+2,363,944 
+$ 
+3,673,199 
+$ 
+2,097,353 
+Asia 
+227,564 
+172,250 
+96,061 
+Europe 
+1,131,193 
+1,164,476 
+191,947 
+North America 
+5,082,319 
+6,525,951 
+11,134,691 
+South America 
+4,875,087 
+10,350,812 
+12,429,717 
+$ 
+13,680,107 
+$ 
+21,886,688 
+$ 
+25,949,769 
+Sales to Africa decreased in 2016 primarily due to decreased sales in Uganda by approximately $1,122,400, and Nigeria by approximately $220,900. Sales in Asia increased slightly by $55,300. European sales decreased by $68,600. Sales decreased in 2016 to North America from decreased sales in the U.S by approximately $1,579,800 and partially offset by increased sales to Mexico of $123,200. Sales decreased in 2016 to South America were primarily from decreased sales in Brazil of approximately $5,340,250. 
+Sales to Africa increased in 2015 primarily due to increased sales in Uganda by approximately $1,344,500, and Nigeria by approximately $287,500. Sales in Asia increased slightly by $76,200. European sales increased by $972,500. Sales decreased in 2015 to North America from decreased sales to Mexico of $3,913,400 and by decreased sales in the U.S by approximately $1,545,000. Sales decreased in 2015 to South America were primarily from decreased sales in Brazil of approximately $2,111,700. 
+NOTE 13 — COMMITMENTS AND CONTINGENCIES: 
+Employment Contracts: 
+The Company has contracts with three key employees. The contracts call for salaries presently aggregating $975,000 per year. One contract expires in May 2017, one expires in March 2019 and one contract expires in March 2017. The following table is a schedule of future minimum salary commitments: 
+2017 
+$ 
+516,200 
+2018 
+335,000 
+2019 
+55,800 
+Pension Plan: 
+The Company has a 401(k) plan established for its employees. Effective January 1, 2011 the Company elected to match 40% of the first 5% (or 2% of salary) that an employee contributes to their 401(k) plan. Expenses related to this matching contribution aggregated $96,051, $90,915 and $82,750 for the years ended December 31, 2016, 2015, and 2014 respectively. 
+F-16 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2016, 2015 AND 2014 
+Obligations Under Operating Leases: 
+The Company leases industrial space used for office, R&D and manufacturing facilities, currently with a monthly rent of $28,688. The current lease expires on April 30, 2017. The lease provides for annual increases of 2.50% percent each year starting May 1, 2016. In February of 2014, the Company entered into a lease, effective March 1, 2014, for another facility located a short distance from its current facility currently with a monthly rent of $15,550. The space is used primarily for warehousing and provides for additional office space. The lease expires on April 30, 2018. The lease provides for annual increases of 3.00% percent each year starting March 1, 2016. 
+The following is a schedule of future minimum rental commitments (assuming no increases): 
+Years ending December 31, 
+2017 
+$ 
+306,018 
+2018 
+64,067 
+2019 
+- 
+$ 
+370,085 
+Rent expense was $516,708, $511,900 and $476,000 for the years ended December 31, 2016, 2015, and 2014 respectively. 
+Economic Dependency: 
+The following table delineates sales the Company had to customers in excess of 10% of total sales for the periods indicated: 
+For the years ended 
+Accounts Receivable 
+December 31, 2016 
+December 31, 2015 
+December 31, 2014 
+December 31, 2016 
+December 31, 2015 
+Sales 
+% of Sales 
+Sales 
+% of Sales 
+Sales 
+% of Sales 
+Customer 1 
+$ 
+4,801,577 
+35 
+% 
+$ 
+10,132,512 
+46 
+% 
+$ 
+12,253,526 
+47 
+% 
+$ 
+828,848 
+$ 
+775,209 
+Customer 2 
+1,796,477 
+13 
+% 
+4,526,908 
+21 
+% 
+6,618,251 
+26 
+% 
+- 
+700,656 
+The following table delineates purchases the Company had with vendors in excess of 10% of total purchases for the periods indicated: 
+For the years ended 
+Accounts Payable 
+December 31, 2016 
+December 31, 2015 
+December 31, 2014 
+December 31, 2016 
+December 31, 2015 
+Purchases 
+% of Purc. 
+Purchases 
+% of Purc. 
+Purchases 
+% of Purc. 
+Vendor 1 
+$ 
+652,273 
+11 
+% 
+$ 
+* 
+* 
+$ 
+* 
+* 
+$ 
+26,984 
+$ 
+* 
+Vendor 2 
+* 
+* 
+794,536 
+11 
+% 
+1,331,647 
+14 
+% 
+* 
+90,075 
+In the table above the asterisk (*) indicates that purchases from the vendor did not exceed 10% for the period indicated. 
+The Company currently buys materials which are purchased under intellectual property rights agreements and are important components in its products. Management believes that other suppliers could provide similar materials on comparable terms. A change in suppliers, however, could cause a delay in manufacturing and a possible loss of sales, which would affect operating results adversely. 
+NOTE 14 — COLLABORATIVE RESEARCH AND DEVELOPMENT AGREEMENTS: 
+In 2016, 2015, and 2014 the Company earned $3.7 million, $2.3 million, and $1.7 million, respectively, from research revenues and milestones. The Company is now involved in additional feasibility and development contracts related to its DPP® technology. The total expended on R&D, excluding regulatory, in 2016, 2015, and 2014, was approximately $6.9 million, $5.4 million, and $4.1 million, respectively. 
+F-17 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2016, 2015 AND 2014 
+a. RVR DPP® technology transfer agreement: 
+In February 2014, the Company entered into a technology transfer agreement with RVR Diagnostics for $1,500,000. The agreement was modified in September 2014 and September 2015. Per the agreement, as modified, the Company earned $-, $125,000 and $1,125,000 in milestone payments during 2016, 2015 and 2014. The Company has earned $1,250,000 from this grant from inception through December 31, 2016. See subsequent event note describing the Company's acquistion of RVR Diagnostics in January 2017. 
+b. Dengue agreement: 
+In October 2014, the Company entered into a development agreement with an international diagnostics company for $300,000. Revenue for this agreement is being recognized under a proportional performance method. For the years ended December 31, 2016, 2015 and 2014, the Company earned $-, $240,000 and $60,000, respectively from this grant. The Company has earned $300,000 from this grant from inception through December 31, 2016. 
+c. 
+Brain Injury agreement: 
+In January 2015, the Company entered into a technology development agreement with Perseus Science Group LLC for $946,000 and a follow-on agreement in December 2016 for $350,000. Revenue for this agreement is being recognized under a proportional performance method. The Company earned $297,000 and $469,600 for the year ended December 31, 2016 and 2015, respectively from this agreement. The Company has earned $766,600 from this grant from inception through December 31, 2016. 
+d. 
+Malaria agreement: 
+In January 2015, the Company was awarded a grant from The Bill & Melinda Gates Foundation for $307,000. Revenue for this agreement is being recognized under a proportional performance method. The Company earned $- and $307,000 for the year ended December 31, 2016 and 2015, respectively from this agreement. The Company has earned $307,000 from this grant from inception through December 31, 2016. 
+In April 2016, the Company was awarded a grant from the Bill & Melinda Gates Foundation for $677,944. The Company earned $518,761 for the year ended December 31, 2016 from this agreement, which is the total amount earned from this grant from inception through December 31, 2016. 
+e. 
+Cancer agreement: 
+In October 2014, the Company entered into a technology development agreement with an international diagnostics company for $320,000. Revenue for this agreement is being recognized under a proportional performance method. For the years ended December 31, 2016, 2015 and 2014, the Company earned $65,000, $205,000 and $-, respectively from this grant. The Company has earned $270,000 from this grant from inception through December 31, 2016. 
+f. 
+Fever panel agreement: 
+In October 2015, the Company entered into an agreement with Paul G. Allen Ebola Program for $2,118,265 and a follow-on agreement in February 2016 for $550,000. Revenue for this agreement is being recognized under a proportional performance method. The Company earned $2,259,800 and $408,500 for the year ended December 31, 2016 and 2015, respectively from this agreement. The Company has earned $2,668,265 from this grant from inception through December 31, 2016. 
+g. BARDA Zika agreement: 
+In August 2016, the Company was awarded a grant for $5,933,742 from BARDA, which is part of the U.S. Department of Health And Human Resources. The Company earned $472,700 for the year ended December 31, 2016 from this agreement. The Company earned $472,700 from this grant from inception through December 31, 2016. 
+h. 
+USDA Bovid: 
+In September 2016, the Company entered into an agreement with the USDA for $669,423 to develop a Bovid TB assay. Revenue for this agreement is being recognized under a proportional performance method. The Company earned $121,500 for the year ended December 31, 2016 from this agreement. 
+F-18 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2016, 2015 AND 2014 
+Governmental Regulation: 
+All of the Company's existing and proposed diagnostic products are regulated by the United States Food and Drug Administration (FDA), United States Department of Agriculture, certain state and local agencies, and/or comparable regulatory bodies in other countries. Most aspects of development, production, and marketing, including product testing, authorizations to market, labeling, promotion, manufacturing, and record keeping are subject to review. After marketing approval has been granted, Chembio must continue to comply with governmental regulations. Failure to comply with these regulations can result in significant penalties. 
+NOTE 15 — QUARTERLY FINANCIAL DATA (UNAUDITED) 
+The sum of the earnings per common share may not equal the corresponding annual amounts due to interim quarter rounding. 
+For the Quarters Ended in Fiscal 2016 
+March 31 
+June 30 
+September 30 
+December 31 
+Total revenues 
+$ 
+6,601,099 
+$ 
+3,266,405 
+$ 
+3,746,461 
+$ 
+4,254,876 
+Gross profit 
+3,165,548 
+1,580,305 
+1,952,097 
+1,753,386 
+Net loss 
+(303,590 
+) 
+(8,347,482 
+) 
+(2,138,218 
+) 
+(2,557,757 
+) 
+Basic loss per share 
+(0.03 
+) 
+(0.86 
+) 
+(0.19 
+) 
+(0.21 
+) 
+Diluted loss per share 
+(0.03 
+) 
+(0.86 
+) 
+(0.19 
+) 
+(0.21 
+) 
+For the Quarters Ended in Fiscal 2015 
+March 31 
+June 30 
+September 30 
+December 31 
+Total revenues 
+$ 
+6,231,137 
+$ 
+6,716,158 
+$ 
+6,887,374 
+$ 
+4,420,816 
+Gross profit 
+2,686,618 
+3,019,132 
+2,910,534 
+1,870,543 
+Net loss 
+(646,817 
+) 
+(664,085 
+) 
+(437,157 
+) 
+(648,984 
+) 
+Basic loss per share 
+(0.07 
+) 
+(0.07 
+) 
+(0.05 
+) 
+(0.07 
+) 
+Diluted loss per share 
+(0.07 
+) 
+(0.07 
+) 
+(0.05 
+) 
+(0.07 
+) 
+NOTE 16 — SUBSEQUENT EVENTS: 
+On January 9, 2017, the Company, completed the acquisition of RVR Diagnostics Sdn Bhd, a Malaysia corporation ("RVR"), pursuant to the previously reported Amended And Restated Stock Purchase Agreement, dated as of December 7, 2016 (the "Stock Purchase Agreement"), by and among the Company, RVR, Avijit Roy and Magentiren Vajuram (Messrs. Roy and Vajuram, the "Sellers"). 
+Pursuant to the Stock Purchase Agreement, the Company acquired all of the issued and outstanding common stock and other equity interests of RVR from the Sellers for (i) a cash payment of $1,400,000 and (ii) 269,236 shares of the Company's common stock, of which 7,277 shares are being held back to satisfy certain potential claims under the Stock Purchase Agreement and will become issuable to the Sellers, if at all, on the one-year anniversary of the closing. 
+In addition, the Stock Purchase Agreement provides that the Sellers may become entitled to receive certain milestone payments based on the achievement of performance goals related to sales by RVR during the 12 months ending December 31, 2017. Based on the actual sales achieved by RVR, the Sellers will be entitled to receive (i) a cash milestone payment equal to $100,000 multiplied by the Milestone Proration Amount, for a maximum cash milestone payment of $100,000, and (ii) a stock milestone payment equal to 21,830 shares of the Company's common stock multiplied by the Milestone Proration Amount, with a maximum stock milestone payment of 21,830 shares of the Company's common stock. 
+In connection with the closing of the transaction under the Stock Purchase Agreement, each of the Sellers entered into an employment agreement with RVR, pursuant to which, among other things, each of the Sellers agreed to serve as an employee of RVR for the one-year period following the closing in exchange for a monthly base salary of $10,000. In addition, at the closing, John J. Sperzel III, the Company's President, Chief Executive Officer and a member of the Company's board of directors, Richard J. Larkin, the Company's Chief Financial Officer and Executive Vice President, and Katherine L. Davis, the Company's Chairman of the Board and a member of the Company's board of directors, were appointed as the directors of RVR, with each of the Sellers continuing as the other two directors of RVR. 
+F-19 
+Schedule II 
+Valuation and Qualifying Accounts 
+Additions 
+Description 
+Balance at beginning of period 
+Charged to statement of income 
+Charged to other accounts 
+Deductions 
+Balance at end of period 
+Year ended December 31, 2016 
+Allowance for doubtful accounts 
+$ 
+52,000 
+$ 
+- 
+$ 
+- 
+$ 
+- 
+$ 
+52,000 
+Inventory Reserve 
+$ 
+218,000 
+$ 
+221,478 
+$ 
+- 
+$ 
+194,478 
+$ 
+245,000 
+Year ended December 31, 2015 
+Allowance for doubtful accounts 
+$ 
+52,000 
+$ 
+- 
+$ 
+- 
+$ 
+- 
+$ 
+52,000 
+Inventory Reserve 
+$ 
+218,000 
+$ 
+256,302 
+$ 
+- 
+$ 
+256,302 
+$ 
+218,000 
+Year ended December 31, 2014 
+Allowance for doubtful accounts 
+$ 
+52,000 
+$ 
+- 
+$ 
+- 
+$ 
+- 
+$ 
+52,000 
+Inventory Reserve 
+$ 
+218,000 
+$ 
+274,506 
+$ 
+- 
+$ 
+274,506 
+$ 
+218,000
\ No newline at end of file
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new file mode 100644
index 0000000000000000000000000000000000000000..0cbd824d075dcb4ce9c10d00de97d5364400459b
--- /dev/null
+++ b/raw/filings/0001092662/2016/0001092662-17-000023/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0001092662,CEMI,"CHEMBIO DIAGNOSTICS, INC.",10-K,2017-03-07,2016-12-31,2017-03-07T21:01:27.000Z,0001092662-17-000023,form10_k.htm,FORM 10-K FOR 2016,6610678,1,0,https://www.sec.gov/Archives/edgar/data/1092662/000109266217000023/form10_k.htm,https://www.sec.gov/Archives/edgar/data/1092662/000109266217000023/,2016,2016,1
diff --git a/raw/filings/0001092662/2016/0001092662-17-000023/item1.txt b/raw/filings/0001092662/2016/0001092662-17-000023/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..5ef244851778b866429affb71b055c787f420b63
--- /dev/null
+++ b/raw/filings/0001092662/2016/0001092662-17-000023/item1.txt
@@ -0,0 +1,287 @@
+ITEM 1. 
+BUSINESS 
+FORWARD-LOOKING STATEMENTS 
+This report contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, and Section 27A of the Securities Act of 1933. Any statements contained in this report that are not statements of historical fact may be forward-looking statements. When we use the words "intends," "estimates," "predicts," "potential," "continues," "anticipates," "plans," "expects," "believes," "should," "could," "may," "will" or the negative of these terms or other comparable terminology, we are identifying forward-looking statements. Forward-looking statements involve risks and uncertainties, which may cause our actual results, performance or achievements to be materially different from those expressed or implied by forward-looking statements. These factors include our research and development activities, distributor channels, market demand for our products, compliance with regulatory impositions; and our capital needs. Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance or achievements. 
+Except as may be required by applicable law, we do not undertake or intend to update or revise our forward-looking statements, and we assume no obligation to update any forward-looking statements contained in this report as a result of new information or future events or developments. Thus, you should not assume that our silence over time means that actual events are bearing out as expressed or implied in such forward-looking statements. You should carefully review and consider the various disclosures we make in this report and our other reports filed with the Securities and Exchange Commission that attempt to advise interested parties of the risks, uncertainties and other factors that may affect our business. 
+We provide free of charge on our website at www.chembio.com our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable. Members of the public may read and copy any materials we file with the SEC at the SEC's Public Reference Room at 100 F Street, NE, and Washington, DC 20549. Members of the public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800–SEC–0330. The Internet address of the Commission is www.sec.gov. That website contains reports, proxy and information statements and other information regarding issuers, like Chembio, that file electronically with the Commission. Visitors to the Commission's website may access such information by searching the EDGAR database. 
+For further information about these and other risks, uncertainties and factors, please review the disclosure included in this report under "Part I, Item 1A, Risk Factors." 
+Our Business 
+General 
+The Company (Chembio Diagnostics, Inc. and its wholly-owned subsidiary Chembio Diagnostic Systems, Inc. are collectively referred to herein as the "Company") develops, manufactures, markets and licenses rapid point-of-care diagnostic tests (POCTs) that detect infectious diseases. Our main products currently commercially available are rapid tests for the detection of HIV 1/2 antibodies, and a multiplex rapid test for the detection of HIV and syphilis antibodies. The HIV 1/2 rapid tests employ in-licensed and proprietary lateral flow technologies (see "Our Rapid Test Technologies"), can be used with all blood matrices as samples, and are manufactured in a standard cassette format, a dipstick format, and a proprietary barrel format. The tests employing the cassette and proprietary barrel formats were approved by the FDA in 2006. The barrel format is exclusively distributed by a distributor in the United States and by Chembio and its designated distributors outside the United States. The exclusive U.S. distribution agreement for the barrel product terminated in accordance with its terms on May 31, 2016. Since June 1, 2016, Chembio and its subsequently designated distributors have distributed the product in the U.S. The Cassette format is distributed by Chembio and its designated distributors worldwide. Our latest generation HIV 1/2 rapid antibody detection test incorporates our patented Dual Path Platform® (DPP®) POCT technology, and this POCT platform does not require in-licensing. The DPP® HIV 1/2 Assay detects antibodies to HIV 1 & 2 in oral fluid samples as well as in all blood matrices. [We have sold this product in Brazil since 2009 where it was approved by ANVISA, through our agreement with the Oswaldo Cruz Foundation ("FIOCRUZ"), and we received United States FDA regulatory approval for this product in December 2012 and CLIA waiver in October 2014.] We launched it in the United States under Chembio's brand in the fourth quarter of 2014. 
+2 
+Our product pipeline, which currently includes a multiplex rapid test for earlier detection of HIV by detecting P-24 antigen as well as antibodies, a test for Hepatitis-C, and a multiplex test that detects HIV and Syphilis specific antibodies (which we are already selling outside the U.S.), is based on this DPP® technology for which we were issued a United States patent in 2007 and for which additional patent protection has issued or is pending in a number of other countries. With our patented DPP® and the lateral flow platforms, we participate in the estimated $8 billion point-of-care (POC) market segment of the estimated nearly $50 billion global in-vitro diagnostic market that has an overall growth rate exceeding 3% per annum. POCTs, by providing prompt and early diagnosis, can reduce patient stays, lower overall costs, improve therapeutic interventions and improve patient outcomes. POCTs can also prevent needless hospital admissions, simplify testing procedures, avoid delays from central lab batching, and eliminate the need for return visits. 
+In the areas of infectious and sexually transmitted diseases (such as HIV and syphilis), the utility of a rapid POC test, particularly in identifying patients unaware of their disease status, has been well established. Large and growing markets have been established for these kinds of tests, initially in high prevalence regions where they are indispensable for large scale prevention and treatment programs. More recently introduced in the United States in 2004, rapid HIV tests now also present a significant segment of the U.S. market for HIV clinical testing, which is still dominated by laboratory tests. We have focused our product development activity within areas where the availability of rapid, POC screening, diagnostic, or confirmatory results can improve health outcomes. More generally we believe there is and will continue to be a growing demand for diagnostic products that can provide accurate, actionable diagnostic information in a rapid, cost-effective manner at the point of care. 
+Our Products 
+Lateral Flow Rapid HIV Tests 
+All three of our lateral flow rapid HIV antibody detection tests are qualitative "yes/no" tests for the detection of antibodies to HIV 1 & 2 with visually interpreted results (one line "negative"; one line "positive") available within approximately 15 minutes. The tests are simple to use, have a shelf life of 24 months, and do not require refrigeration. The tests differ principally only in the method of test procedure, convenience and cost. One of our FDA-approved lateral flow HIV tests, SURE CHECK® HIV 1/2 Assay, incorporates a proprietary plastic "barrel" device that houses the lateral flow strip. This barrel format enables collection of samples directly (usually from a finger-stick whole blood sample) into the barrel's capillary tip. A sealed unitized buffer vial, assembled onto the top of the barrel, is removed and seated into a stand; the seal is then pierced by the barrel's capillary tip, thereby initiating the upward flow of the resulting sample-buffer solution through a filter, up into the vertical device's chamber and onto the lateral flow strip. This results in a unique unitized and closed device system that can reduce the chance of exposure to potentially infectious samples. 
+In January 2015, we entered into an agreement with StatSure Diagnostic Systems, Inc. (SDS) to acquire SDS' interest in the barrel device format, also known as Chembio's SURE CHECK® HIV 1/2 Assay, effective June 1, 2016. Beginning June 1, 2016, we owned full rights related to the SURE CHECK® HIV 1/2 Assay, including sales, marketing, distribution and trademark rights, subject to the few still-effective transitional terms of the marketing and distribution agreement with Alere, Inc., which terminated (subject to a few post-termination transitional provisions) on May 31, 2016. Prior to this newly-executed agreement between SDS and Chembio, SDS had owned a 50 percent interest in the rights to the SURE CHECK® HIV 1/2 Assay that would have continued after May 31, 2016, also subject to the then-existing marketing and distribution agreement with Alere. The January 2015 agreement with SDS also resolves all other matters between Chembio and SDS, including their respective sharing ratios, until June 1, 2016, concerning net revenues from sale of the SURE CHECK® product outside the U.S. 
+Prior to June 1, 2016, our SURE CHECK® HIV 1/2 Assay was marketed exclusively in the U.S. as Clearview® Complete pursuant to the agreement with Alere described above. Since June 1, 2016, it has been marketed in the U.S. as Sure Check® HIV 1/2 Assay. Outside the U.S., we continue to market the SURE CHECK® HIV 1/2 Assay primarily through distributors. The SURE CHECK® HIV 1/2 Assay is Food & Drug Administration (FDA) approved, CLIA-waived, European CE-marked, and has been pre-qualified by the World Health Organization (WHO). Results are obtained in 15 minutes via a 2.5uL blood sample (i.e., fingerstick, serum, plasma, or venipuncture whole blood). The assay is stable at room temperature and provides 99.7% sensitivity and 99.9% specificity. 
+Our second FDA-approved lateral flow HIV test, the HIV 1/2 STAT-PAK®, uses a more conventional rectangular plastic cassette format that houses the lateral flow strip. In this case, a sample is transferred by use of a separately provided transfer device ("loop") into a sample well or port of the cassette that houses the lateral flow strip, which is positioned horizontally or flat. 
+Our third lateral flow HIV test, the HIV 1/2 STAT PAK® Dipstick, is our most cost competitive and compact format. It does not have any plastic housing so that 30 test strips can be packaged into a small vial that is ideal for transporting into remote settings. The test procedure is similar to the cassette format except that a user-applied adhesive backing is provided as a more cost-effective and compact "surface" on which to run the test. 
+3 
+Regulatory Status of the lateral flow HIV tests 
+The FDA approved our Pre-Market Applications (hereinafter "PMA"; see "Governmental Regulations" and Glossary) in April 2006 for our SURE CHECK® HIV 1/2 and for our HIV 1/2 STAT-PAK® products. Waivers under the Clinical Laboratory Improvement Act (hereinafter "CLIA"; see Governmental Regulations) were granted by the FDA for these two FDA-approved products in 2006 and 2007, respectively. A CLIA waiver is required in order for health care providers to administer these tests in the settings where they are most suited and needed, such as public health testing clinics, hospital emergency rooms and physicians' offices. The SURE CHECK® and HIV 1/2 STAT-PAK® products received CE Marks in July 2013 and March 2014, respectively, and the CE Marking for the DPP® HIV 1/2 Assay described below was received in June 2015. We have also updated our filing for CE Marking to reflect the new tradename of STAT-VIEW® HIV 1 / 2 Assay for sale in the EU market. Our HIV 1/2 STAT-PAK® Dipstick, although not FDA-approved, qualifies under FDA export regulations [See Government Regulation] to sell to customers outside the United States, subject to any required approval by the importing country. CE Mark has not been pursued for this product. 
+All three of our lateral flow HIV tests have qualified for procurement under the President's Emergency Plan for AIDS Relief ("PEPFAR"). The cassette and dipstick versions of the STAT-PAK® and the SURE CHECK® assays are also pre-qualified by the World Health Organization (WHO) for procurements by the second largest global program, known as the Global Fund, as well as other related programs funded by agencies affiliated with the United Nations, such as UNICEF and UNITAIDS (see Glossary), through qualification with the WHO bulk procurement scheme. 
+DPP® HIV 1/2 Assay 
+As in the case of our lateral flow HIV tests, our DPP® HIV 1/2 Assay is also a qualitative "yes/no" test for the detection of antibodies to HIV 1& 2, delivers visual results within as little as 15 minutes, is simple to use, has a shelf life of 23 months, and does not require refrigeration. This product, which is our first FDA-approved product incorporating our patented DPP® technology, can be used with oral fluid samples, as well as with all blood matrices. This product also incorporates our patent-pending oral fluid collection and storage system that enables samples to be fully extracted in buffer solution before application to the test device, and also enables the extracted sample to be stored and retested or potentially tested for multiple conditions in future product applications. Clinical and laboratory studies demonstrated the ability of the test to accurately detect the presence of antibodies in individuals down to two years of age. Studies have also shown this product to have improved performance compared with all of the current FDA-approved CLIA-waived lateral flow rapid tests, even including our own lateral flow tests. FDA-approved label claims include sensitivity/specificity on oral fluid and finger-stick whole blood of 98.9%/99.9% and 99.9%/100% respectively. Oral fluid sensitivity was 100% among HIV-positive patients not taking anti-retroviral medication. 
+Regulatory Status of the DPP® HIV 1/2 Assay 
+In December 2012, we received FDA approval of our Pre-Marketing Application for our DPP® HIV Assay. In October 2014, the FDA granted CLIA-waiver status for this assay. 
+Our DPP® HIV 1/2 Assay product is qualified for procurement under the President's Emergency Plan for AIDS Relief ("PEPFAR") for use with all sample matrices. In May 2015 we obtained approval for a CE Mark for the DPP® HIV 1/2 Assay for Oral Fluid, Serum, Plasma, Fingerstick Whole Blood and Venous Whole Blood . In 2016, we obtained WHO qualification in order to enable procurement of this product by the Global Fund and United Nations agencies, including programs underwritten by them. 
+Previously, in June 2010, ANVISA approved the DPP® HIV 1/2 Assay that is being marketed in Brazil through our collaboration with the Oswaldo Cruz Foundation, Brazil's leading public health institute (see Oswaldo Cruz Foundation OEM DPP® Agreements). Since that time, we have sold and marketed millions of DPP® HIV tests to Brazil through this partnership. 
+DPP® HIV-Syphilis Multiplex Test 
+This product, launched in 2013, allows for the detection of antibodies to both HIV and syphilis on a single test device within approximately 15 minutes. We believe that in certain global/public health settings (see Target Markets), this product may provide a more convenient and cost-effective means of rapid detecting both markers in a single test procedure at the point of care as compared with performing separate rapid tests for each indication. This product takes advantage of the multiplexing feature of DPP® which provides for a more robust reaction between the sample and biomarkers being tested for (HIV and syphilis antibodies in this case), resulting in a greater ability by the user to visually interpret test results. We launched this product in Mexico in the fourth quarter of 2013 as a unitized product, meaning that each test kit was separately packaged to include each of the other components necessary to run this test, as compared with other configurations where a test kit of 20 or 30 devices is accompanied by one bottle of running buffer. We believe that the initial results of this launch have been very positive, and we experienced good results in Mexico during 2014 from the program. Building on this initial success, we continue to pursue commercialization efforts for this product in a number of additional international markets, where there is a great need to detect Mother-to-Child-Transmission of HIV and Syphilis globally. According to the CDC website, "approximately 370,000 babies are born with HIV, mostly in sub-Saharan Africa. Without treatment, more than half of these children will die before the age of 2. Through key interventions, such as routinely testing pregnant women for HIV, providing antiretroviral medications to HIV-infected pregnant women and their exposed infants, and promoting safe infant feeding practices, mother-to-child transmission of HIV can be decreased from about 35% to less than 5%. Another prominent cause of infant mortality is untreated maternal syphilis, which still accounts for more than 500,000 stillbirths and infant deaths annually despite the fact that these deaths could be prevented through routine detection and treatment of syphilis during antenatal care". 
+4 
+Regulatory Status of the DPP® HIV-Syphilis Test 
+DPP® HIV-Syphilis – We have developed this product for international and U.S. marketing. For the international market, the product has been registered in Mexico, and successfully launched and sold in this region. 
+In February 2015, this product was granted approval from the Brazilian ANVISA. As of December 31, 2016, there have been no sales of the DPP® HIV-Syphilis Assay in Brazil. This product also has been approved by the CDC, acting on behalf of the United States Agency of International Development, (USAID) for its global procurement scheme. 
+We are developing a U.S. version of the DPP® HIV-Syphilis Assay, designed to meet the performance requirements for the "reverse" algorithm that is currently in clinical use for syphilis testing in the United States. We have completed our pre-clinical studies for this product with encouraging results, and are in the final stages of clinical site selection for our U.S. clinical studies. We began this clinical trial in the U.S. in 2016, and expect that the trial will be completed in the first quarter of 2017. 
+DPP® Technology & Development 
+Chembio is executing its strategy to leverage the DPP® intellectual property and product development and manufacturing experience to create new collaborations where Chembio serves as an exclusive development and manufacturing partner. Examples of such collaborations include the following: 
+· 
+We entered into an agreement in October 2014 to develop a POC diagnostic test for dengue fever virus, the DPP® Dengue Fever Assay, which would be able to detect IgG/IGM and NS1 antigens in October 2014. 
+· 
+A collaboration also announced in October 2014, with an international diagnostics company to develop a POC diagnostic test for the early detection and monitoring of a specific type of cancer. At that time, the cancer project represented the first application of the DPP® technology outside the infectious disease field. 
+· 
+We entered into a milestone-based development agreement with a private contracting organization acting on behalf of the CDC, for a multiplex POC influenza immunity test utilizing our patented Dual Path Platform (DPP® ) technology. 
+· 
+In January 2015, we entered into an agreement with the Concussion Science Group (CSG) Division of Perseus Science Group LLC, to utilize our patented DPP® technology to develop a POC diagnostic test for traumatic brain injury (TBI), including sports-related concussions. Under terms of the agreement, CSG's patented biomarker will be combined with our proprietary DPP® platform to develop a semi-quantitative or quantitative point-of-care test to diagnose TBI. CSG agreed to pay Chembio milestone development payments during 2015. 
+· 
+In January 2015, we were awarded a grant from The Bill & Melinda Gates Foundation to expedite the feasibility testing and development of a DPP® Malaria POC rapid diagnostic to accurately identify individuals infected with Plasmodium falciparum parasite. Our DPP® technology was selected for this grant due to its exceptional sensitivity and potential to aid the foundation in its goal of eradicating malaria. To achieve this goal, diagnostics must be capable of detecting the malaria parasite in infected, but asymptomatic, people. Current POC rapid diagnostics tests lack sufficient sensitivity to identify all individuals with transmissible infections. 
+· 
+In October 2015, we were awarded a grant from the Paul G. Allen Foundation to develop a POC test to identify multiple life-threatening febrile illnesses. Under the $2.1 million dollar grant, we are to use our patented DPP® technology to seek to develop a DPP® Fever Panel Assay, a POC multiplex assay to simultaneously detect Malaria, Dengue, Ebola, Lassa and Marburg. The multiplex assay is planned to be designed to include a quality control test band and seven tests bands with specific antibodies to detect different pathogens, including multiple serotypes of the same pathogen: Malaria PAN-PLDH antigen (Plasmodium falciparum, Plasmodium vivax, Plasmodium malariae, Plasmodium ovale), Malaria Falciparum HRP2 antigen, Ebola Virus PAN (Zaire, Sudan, Bundibugyo Virus), Marburg Virus, Lassa Virus, Dengue Virus (Dengue 1, Dengue 2, Dengue 3, Dengue 4) and Chikungunya Virus. In many parts of the world, these diseases are commonly misdiagnosed, resulting in a delay of treatment or failure to properly treat the underlying infection. Misdiagnosis may be due to the fact that these diseases have similar symptoms that are difficult to distinguish. Currently available POC diagnostics lack the ability to test for multiple diseases simultaneously. Further, existing POC diagnostics may lack the sensitivity and specificity required to detect infected but asymptomatic patients - information that is critical for preventing the spread of disease. 
+5 
+· 
+Also in October 2015, we signed an agreement with opTricon (Berlin, Germany), a leading developer of mobile analysis devices for rapid diagnostic tests. Through this exclusive agreement, subject to certain terms, and covering the fields of sexually transmitted diseases, certain "fever" diseases, and a specific form of cancer, we expect to launch the DPP® Micro Reader, a point-of-care instrument designed specifically to complement our patented DPP® technology as applied to those diseases. The DPP® Micro Reader will include an innovative image sensor to provide a quantitative interpretation of diagnostic results when combined with our proprietary DPP® immunoassay technology. Using a state-of-the-art camera system, the DPP® Micro Reader is designed to provide definitive diagnostic results for low analyte concentrations, which may otherwise result in faint or ambiguous test results. In addition, the DPP® Micro Reader will provide customers with various options to capture, record, transmit and store test results. With one-button operation, the palm-sized and battery-operated DPP® Micro Reader is simple, fast, portable and cost-effective. 
+PARTNERS INVOLVED IN MARKETING OUR PRODUCTS 
+Alere 
+On September 29, 2006, we executed marketing and license agreements with Alere. The marketing agreements (the Barrel Agreement and the Cassette Agreement) provide Alere with a 10-year exclusive right (until May 31, 2016) to market our rapid HIV tests in the United States under Alere's brands. The agreements also provide us with a non-exclusive license to certain Alere lateral flow patents that may be applicable to our lateral flow products, including for manufacture of the HIV tests in the United States for sales outside the United States and even for sale in the United States should Alere enter the U.S. market with a competitive rapid HIV test product and in such case we choose to market our products directly as provided in the agreements in such event of a competitive rapid HIV test product. Simultaneous with the execution of the agreements, we also settled litigation with StatSure Diagnostics, Inc. (SDS), that had been ongoing relating to the proprietary barrel device which is incorporated into one of our two FDA-approved rapid HIV tests (See Lateral Flow HIV Tests above). SDS, pursuant to the settlement, is a party to the 3-way Barrel Agreement. As a result, until the dates described below and elsewhere in this report, it is through the agreements with Alere that we were participating in the growth of the rapid HIV test market in the United States. 
+In late July 2013, we received notice from Alere that it intended to commercialize its own rapid HIV test (see Competition), which test had just received FDA approval as a moderate complexity product (i.e. not CLIA-waived though this was granted in late 2014), in the United States. Under the Barrel Agreement and the Cassette Agreement, such product is considered to be a Permitted Competing Product (PCP). Each of the two aforementioned agreements provides that, in the case of notice of a PCP, we may make certain elections (jointly with SDS in the case of the Barrel Agreement), or elect to continue each agreement without taking any further action. Under the Cassette Agreement, we may, at any time, terminate such agreement, which termination would become effective 60 days after the date notice was made. Under the Barrel Agreement, we and SDS may jointly issue a non-exclusivity notice, which notice shall be effective immediately. In the event that we make this election with respect to the cassette product, or that both we and SDS make this election with respect to the cassette product, then the electing party or parties could sell that respective product in the United States market under its own brand, and in such case, the lateral flow license that we have from Alere for international sales would be expanded to include sales in the United States. See Lateral Flow Technology and Reagent Licenses. In April 2014, we gave notice to Alere of our intent to terminate the Cassette Agreement and 60 days later, we began marketing the cassette product in the United States under the Chembio brand of HIV 1/2 STAT-PAK® assay. On May 31, 2016, the Barrel Agreement expired pursuant to its terms, and, given our January 2015 agreement with SDS, we now market the barrel product in the U.S. under the brand of SureCheck® HIV 1/2 Assay. 
+We have developed our own sales and marketing departments for the sales of our products in the U.S. and internationally. We also have appointed distributors in the U.S. and internationally for our lateral flow HIV tests. Our largest markets outside the U.S. for our lateral flow HIV rapid tests are certain countries in Africa, Asia, and South America, as well as Mexico. Internationally, most of the demand for our products is based on governmental and non-governmental prevention and treatment efforts. Given this, these programs can and do often result in large orders, but also can result in periods of relatively lower demand, based on the variations associated with this kind of demand. 
+OEM DPP® Products 
+Oswaldo Cruz Foundation OEM DPP® Agreements 
+During 2008-2010 we signed five separate agreements, each of which is titled and constitutes a "Technology Transfer Agreement", with the Oswaldo Cruz Foundation (FIOCRUZ) in Brazil. FIOCRUZ includes the Institute of Technology on Immunobiologicals/Bio- Manguinhos, which is the FIOCRUZ unit that produces vaccines and diagnostic kits. FIOCRUZ and Bio-Manguinhos are referred to herein interchangeably. Each of the five agreements relates to a different specific product or group of products based on our DPP® technology. FIOCRUZ is the leading public health organization in Brazil, and it is affiliated with Brazil's Ministry of Health, which is its principal client. It has extensive research, educational and manufacturing facilities for drugs and vaccines, as well as for diagnostic products. 
+6 
+Each of the agreements grants to FIOCRUZ the right, but not the obligation, to earn the right to request a technology transfer to be able to license and manufacture that product on its own. FIOCRUZ is not required to earn this right, but if it desires to do so, then it needs to purchase a stated amount of the product as set forth in the respective agreement for that product. 
+During 2010 and 2011, all of the initial products contemplated under the five agreements were approved for marketing by the applicable regulatory agencies in Brazil. The agreements between us and FIOCRUZ are unique examples of technology transfer collaborations between a private sector rapid test manufacturer and a public health organization. The five products categories for which FIOCRUZ can earn a separate right to request a technology transfer for that product only are: DPP® products for HIV screening, HIV Confirmatory, Leishmaniasis, Leptospirosis and Syphilis. Each technology transfer, and the provision by us of the information and training that is required for this to occur, will occur only if FIOCRUZ purchases from us the amount of that product that is specified in the respective agreement for that product. The actual amount of purchases for each product is totally at the discretion and option of FIOCRUZ and may be more or less than the amount needed to qualify for a technology transfer. 
+More specifically, the five agreements, although separate and independent of one another, are structurally similar according to the following: 
+· 
+Each agreement states: "the object of this Agreement is for the Transfer of Technology from Chembio to Bio-Manguinhos, the license by Chembio to Bio-Manguinhos for the Chembio Patents applied or granted in Brazil or other Mercosur countries for the term of the patents and the transfer of all the technical information related to the DPP® technology and the process to obtain the product by the DPP® technology. This Agreement contemplates the scientific and technological co-operation between Chembio and Bio-Manguinhos for such activities so that Bio-Manguinhos will be able to manufacture the Product in Brazil." 
+· 
+Each agreement provides that we will supply free of charge to Bio-Manguinhos prototypes of the product to demonstrate performance characteristics that are necessary for evaluation by the Brazilian Ministry of Health and for registration with ANVISA. ANVISA is the Agencia Nacional de Vigilancia Sanitaria, or the National Sanitary Vigilance Agency. The number of prototypes ranges from 15,000 to 45,000 in the various agreements. 
+· 
+Each agreement provides that the prototypes will be utilized both for a performance study that follows a protocol prepared and approved by Bio-Manguinhos and the Brazilian Ministry of Health, and also will be used for studies in Brazil for the registration procedures at ANVISA. Bio-Manguinhos will then apply to ANVISA to register the product. Within 120 days of the registration of the product with ANVISA, Bio-Manguinhos will make an advance technology transfer payment to us (the "Advance Payment"), in an amount specified in that particular agreement. All five of the Advance Payments provided for in the agreements were made in 2010 and 2011. 
+· 
+At such time, if any, that the product for a particular agreement has been successfully registered with ANVISA, then Bio-Manguinhos has the right to qualify for the full technology transfer for that product by purchasing the amount of the product, and at the price, specified in the agreement. 
+· 
+Bio-Manguinhos is not required to purchase any amount of any product. For each product, it only needs to purchase that product, in the amount specified in the agreement, only if it desires to be able to complete the technology transfer process in order to manufacture and sell that product on its own. We do not have recourse against Bio-Manguinhos if Bio-Manguinhos does not purchase the qualifying purchase amount of any product. In that case, we can only suspend further phases of the technology transfer, attempt to renegotiate the agreement, and/or retain any amounts previously paid by Bio-Manguinhos. We cannot force Bio-Manguinhos to purchase any amount of any product. 
+· 
+As a result of the terms of these agreements, Bio-Manguinhos has never been required to, and is not now required to, purchase any amount of any of the products. 
+· 
+As of December 31, 2016, Bio-Manguinhos had earned the status described below with respect to each of the five products: 
+1. 
+With respect to our DPP® HIV1/2 Screen test, Bio-Manguinhos had qualified to request the technology transfer. It has requested, and has received, the technology transfer information. Bio-Manguinhos purchased $880,175, $4,990,840 and $291,235 of this product in 2011, 2012 and 2013, respectively, all of which applied to the qualifying amount to obtain the right to the technology transfer (the "Qualifying Amount") for this product. In 2013, 2014, 2015 and 2016 Bio-Manguinhos made $3,320,010, $4,799,250, $5,410,350 and $5,900, respectively, of purchases in excess of the Qualifying Amount. 
+2. 
+With respect to our Canine Leishmania test, Bio-Manguinhos had qualified to request the technology transfer and did so request. Submission of the technology transfer information is in process at this time. Bio-Manguinhos purchased $2,000,817 and $99,183 of this product in 2011 and 2012 respectively, of this product in that applied to the Qualifying Amount. In addition, Bio-Manguinhos made purchases in excess of the Qualifying Amount equal to $1,314,117, $1,736,700, $2,394,000, $3,772,482 and $4,221,000 in 2012, 2013, 2014, 2015 and 2016, respectively. 
+7 
+3. 
+a. 
+With respect to the three variations of our DPP® Syphilis test, all of which are covered by a single agreement, Bio-Manguinhos had qualified to request the technology transfer with respect to Trep only, and intends to do so in the near future. Bio-Manguinhos purchased $1,194,250, $165,750 of this product in 2011 and 2012, respectively that applied to the Qualifying Amount. In addition, Bio-Manguinhos made purchases in excess of the Qualifying Amount equal to $2,817,750, $646,340, $4,617,891 and $833,631 in 2012, 2013, 2014 and 2015, respectively no purchases of this product were made in 2016. 
+b. 
+With respect to the two variations of our Screen & Confirm Test, Bio-Manguinhos had not made any purchases in 2011, 2012, 2013, 2014, 2015 or 2016, and therefore had not qualified to request the technology transfer for either of them. This agreement was terminated in December 2015. 
+c. 
+This syphilis agreement was terminated during the fourth quarter of 2015. 
+4. 
+With respect to our DPP® Confirmatory test, Bio-Manguinhos has qualified to request the technology transfer. Bio-Manguinhos made purchases of $560,000, $819,000, $390,000, $390,000, $156,000 and $39,000 of this product in 2011, 2012, 2013, 2014, 2015 and 2016 respectively, all of which applied to the Qualifying Amount. In addition, Bio-Manguinhos made purchases in excess of the Qualifying Amount equal to $485,940 in 2016. 
+5. 
+With respect to our DPP® Leptospirosis test, Bio-Manguinhos had not qualified to request the technology transfer. Bio-Manguinhos made purchases of $135,000 of this product in 2011, and it made -0- purchases in 2012, $45,000 in 2013 and it made -0- purchases in 2014, 2015 and 2016. In order to qualify for the technology transfer, Bio-Manguinhos would need to purchase an additional $225,000 of this product. 
+· 
+As stated above, Bio-Manguinhos is not obligated to make any purchases. After the specified level of sales for a particular product has been achieved, FIOCRUZ may request that the technology for that product be transferred to FIOCRUZ together with an exclusive license to produce and sell that product in a defined territory. The license is to provide that we will receive a royalty on all sales. We do not release the amount of this royalty because it could have an adverse effect on negotiations concerning royalties in potential transactions with other parties. 
+· 
+All the agreements expire five years after the date of the technology transfer. If terminated earlier by default of FIOCRUZ, FIOCRUZ must stop all activity; if terminated earlier because of our default, or if terminated by natural expiry, FIOCRUZ can continue to produce and commercialize the product without paying royalties. 
+Other OEM And License Agreements Related to DPP® Technology 
+In addition to our agreements with FIOCRUZ, we have entered into certain OEM and license agreements with other parties with respect to certain products that we have developed based on our DPP® technology. In 2008 we entered into a product development and license agreement with Bio-Rad Laboratories, Inc. (Bio-Rad), a leading multinational life sciences company, for the first ever POC test for the confirmation of HIV (reflex test used after initial screening test(s) are positive). This product utilizes our DPP® technology, capitalizing on its multiplexing advantages, and is much simpler to perform than the legacy confirmatory platform, known as western blot, which requires a substantial amount of technical training and hands-on time and which is more expensive to manufacture and distribute. This product was CE marked and was launched by Bio-Rad in the second quarter of 2013 in Europe under their Geenius® brand; and an FDA PMA approval was received in 2014. 
+In 2013 we entered into collaboration with Labtest, a private company in Brazil, for the distribution of a number of products in Brazil that would be co-branded with Labtest and Chembio trademarks. Under this agreement, upon request from Labtest, for which there is no requirement, we will sell the appropriate DPP® components to Labtest for further manufacture and assembly in Brazil. 
+In February 2014, we entered into a technology transfer and license agreement with RVR Diagnostics SDN BHD ("RVR"), a privately-held company in Malaysia. The agreement supports our strategy of establishing a market presence in Asia, in collaboration with RVR as a licensee, distributor, and contract manufacturer, depending on the circumstances. The agreements grant exclusive distribution rights to RVR in certain countries in the region and enable RVR to manufacture our DPP® HIV 1/2 Assay and DPP® HIV-Syphilis Assay, and potentially other products that are developed by us, such as Dengue, incorporating its patented DPP® technology as indicated in the DPP® Technology & Development section above. As indicated elsewhere, we acquired RVR in January 2017. 
+Our Rapid Test Technologies 
+All of our commercially available current products employ either in-licensed lateral flow technology or our own patented Dual Path Platform (DPP®) technology. Both lateral flow technology and DPP® allow the development of accurate, low cost, easy-to-perform, single-use diagnostic tests for rapid, visual detection of specific antigen-antibody complexes on a test strip. These formats provide a test that is simple (requires neither electricity nor expensive equipment for test execution or reading, nor skilled personnel for test interpretation), rapid (turnaround time approximately 15 minutes), safe (minimizes handling of potentially infected specimens), non-invasive (requires 5-20 micro liters of whole blood easily obtained with a finger prick, or alternatively, serum or plasma), stable (24 months at room temperature storage in the case of our HIV tests), and highly reproducible. 
+8 
+We believe that products developed using DPP® technology can provide superior diagnostic performance as compared with products that use lateral flow technology. The reason for this is that one of the major differences between the two platforms is that in DPP® samples are allowed to incubate with the target analyte in the test zone before introduction of the labeling reagent/conjugate, whereas in lateral flow, samples are combined with the labeling reagent to form a complex before coming in contact with the target analyte. We believe that this complex can compromise test performance. Also, because of the usage in DPP® of a separately connected sample strip, the control and delivery of sample material is substantially improved. This feature is critical in the development of multiplex tests, as well as tests that involve viscous sample material (such as oral fluid) that can be impeded when forced to combine with labeling reagents before migration on the test strip to the test zone area. 
+Multiplexing is significantly improved as a result of the design of DPP® and this provides a significant advantage. For example, the HIV confirmatory test we developed for Bio-Rad that is described above employs six different markers related to various epitopes of the HIV antigen. We have a number of other products in development, including those being developed in sponsored development programs that involve the use of multiple (e.g. eight) test bands. Although all of these products could be visually read, we can also use handheld and desktop readers with our DPP® products to objectively measure, quantify, record and report DPP® test results. Certain of the products we have and/or are developing incorporate some of these readers, and we are developing other products that may be used with or will require use of a reader. Also, platforms can incorporate labeling reagents that cannot be visually read except by employing a reader, such as fluorescence, though no products are currently utilizing such reagents. 
+We are pursuing additional capabilities and technologies that will complement our current product portfolio and business strategy. This activity includes pursing development, license or acquisition of diagnostic technologies that complement our existing platforms, proprietary biomarkers that can result in new product applications of our existing platforms, and new platforms that would complement our commercial strategy. 
+Target Markets 
+Rapid HIV Tests 
+A large percentage of individuals that are HIV positive worldwide are unaware of their status. Part of the reason for this is that even those that do get tested in public health settings will often not return or call back for their test results when samples have to be sent out to a laboratory which can take up to several days to process. The increased availability, greater efficacy and reduced costs for anti-retroviral treatments (ARVs) for HIV has increased the demand for testing, as the stigma associated with the disease is lessened, and the ability to resume normal activities is substantially improved, providing a positive message to those potentially infected. The impact that rapid HIV testing has had on prevention efforts has in turn increased the demand for testing, particularly by public health programs worldwide, which have also become more effective in reducing the number of annual new infections in many, but by no means all, high prevalence regions. 
+Despite less attention to HIV by the media as compared with prior years, there are still approximately 50,000 new diagnoses of HIV infection in the United States each year, according to the CDC. CDC estimates that approximately 1.1 million individuals in the U.S. are living with HIV, with an estimated 1 of 8 of these U.S. individuals, or almost 13%, unaware that they are infected. It is transmissions from these infected people that are reported to account for the majority of all new infections per year. Part of the reason for this is that even those individuals that do get tested in public health settings will often not return or call back for their test results if their blood samples have to be sent out to and tested in a laboratory and then reported back, a process which can take up to several days to complete. Making more people aware of their HIV status at the point-of-care reduces the number of HIV transmissions. 
+In 2006, the outlook for HIV testing was given a big boost with the release by the CDC of new recommendations for HIV testing. These new CDC recommendations were/are that an HIV test should be given as a routine test like any other for all patients between 13 and 64 years of age, regardless of risk, with an opt-out screening option and focused testing procedural (pre- and post-test counseling) guidelines. Though not mandatory, gradual adoption in whole or in part of the 2006 CDC recommendations by a number of states continues to have an increasing impact. Finally, in 2013, the United States Preventive Services Task Force ( " USPSTF " ) fully embraced these CDC routine HIV testing recommendations. This USPSTF recommendation, which was given an A grade under their recommendation grading system based on the benefits of this practice and the nearly 600,000 AIDS-related deaths in the United States, requires insurance coverage under the Affordable Care Act (the " ACA " ) as a preventive screening test without any co-payment required. Assuming that new legislation does not modify this requirement, of which there is no assurance, we expect this requirement to result in an increase in HIV testing in the United States in the coming years, which we believe will include point-of-care HIV testing utilizing our products. Although as stated above, currently most public health testing in the United States is funded by grants allocated to high prevalence areas by the CDC, we believe this will shift to an insurance-funded model under the ACA in the years to come, increasing the amount of testing done in doctor ' s offices and community health centers. 
+9 
+In the international market, we sell our products directly and through distributors to large screening programs overseen by ministries of health and NGOs, most but not all of which are funded by large bi-lateral and multi-lateral AIDS relief programs, the largest of which is the U.S. President ' s Emergency Plan for AIDS Relief (PEPFAR). Established by President George Bush as a 5-year $15 billion program in 2003, PEPFAR was reauthorized in 2008 and again in 2013. In 2012 PEPFAR directly supported HIV testing and counseling for more than 11 million pregnant women, and testing and counseling for more than 49 million people overall. The U.S. is also the first and largest donor to the Global Fund to Fight AIDS, Tuberculosis and Malaria. To date, the U.S. has provided more than $7 billion to the Fund. 
+In December 2013 President Obama signed into law the PEPFAR Stewardship and Oversight Act, which is the most recent reauthorization of PEPFAR. However, unlike the 2008 PEPFAR authorization, which authorized approximately $45 billion, the new law doesn ' t authorize a specific dollar amount for funding. Nevertheless, it is widely anticipated that PEPFAR will continue to enjoy strong funding; the FY14 budget had $6 billion for global HIV/AIDS assistance, including $4 billion for PEPFAR. 
+With our four U.S.-manufactured rapid HIV tests, all of which are FDA-approved, we are recognized as a reputable and dependable supplier of high quality products that are available at reasonably competitive prices. As a result, certain of our products have been selected in the testing protocols in countries (national algorithms) that are large beneficiaries of PEPFAR and the Global Fund. As mentioned above, these programs can and do often result in large orders, but also can result in periods of relatively lower demand, based on the variations associated with this kind of demand. Also, even though the United States taxpayer is funding the largest share of global AIDS relief, U.S. companies do not receive any preference for these procurements, and therefore must compete with foreign suppliers that manufacture competitive products with lower costs, including those related to quality, regulatory, intellectual property, and costs of manufacturing. 
+Oral fluid testing is an established alternative to blood testing for diagnostic tests, including HIV tests. It is also often patient preferred, providing a more comfortable, less invasive test. In certain public health clinics, staffs choose not to handle blood specimens; thus, oral sample collection provides a viable alternative. The most well-established market for oral fluid HIV testing is the United States. Given the premium price required for an oral fluid test as compared with blood tests, the higher volume programs will not specify an oral fluid test. However, segments of these programs may want to have an oral fluid testing option, and certain programs that have greater resources may also choose to incorporate oral fluid testing into the testing protocol. 
+There is also now an over-the-counter market for HIV self-testing in the United States. OraSure Technologies Inc. received FDA approval for an over-the-counter (self-testing) version of its previously professional-market-approved (test performed on an individual by a health care professional) HIV test. The FDA approval was granted in July 2012, and OraSure has been investing heavily in developing this market. Initial results after over two years of marketing are well below expectations. The costs for such over-the-counter approval, including primarily the associated clinical trials, are estimated to be at least $5 million and they may take two to three years to complete, not to mention the cost of distribution. OraSure's initial results are not convincing of a large market, although this possibility remains. If it appears that there is an attractive market, we believe we are very well positioned to participate in this market. 
+Rapid HIV-Syphilis Test 
+There are significant risks relating to transmission of Syphilis from a pregnant mother to child, just as there are for transmission of HIV. Therefore we believe there is a significant opportunity to improve prevention efforts in pregnant mother to child transmission testing programs (PMTCT) that are currently not doing any or nearly enough testing for syphilis even though they are testing for HIV. In the United States, we believe there is also a significant need for this product in some of the highest HIV prevalence populations, such as among men that have sex with men (MSM), as data show high degrees of HIV and Syphilis co-infection in this segment of the population. 
+10 
+Marketing Strategy 
+Our marketing strategy is to: 
+· 
+Market our DPP® HIV 1/2 Assay, HIV 1/2 STAT-PAK® Assay, our SURE CHECK® HIV 1/2 Assay and future DPP® based new products in the US through our internal sales and marketing organization and selected channel partners (e.g., McKesson/PSS, Fisher Healthcare, Henry Schein, etc.). Following the June 2014 termination of the STAT-PAK® agreement with Alere, and the May 31, 2016 termination of the SURE CHECK® agreement with Alere, we no longer have to share any portion of the net sales proceeds for these products with Alere. These changes resulted in our incurring expenditures related to hiring sales representatives, establishing agreements and associated discounts with distributors, incurring advertising and marketing expenditures, warehousing, customer service and technical support. If Alere's new competitive product is indeed successful, our ability to retain a significant share of the market that has been established for our products may be enhanced by our having control of the marketing of our products, rather than relying on Alere to sell both our products while it is also selling its own competing product. We are leveraging the same sales force for U.S. Sales of our DPP® HIV 1/2 Assay. 
+· 
+Outside the U.S., we will market our products primarily through commercial collaborators and distribution partners. 
+· 
+Leverage our DPP® intellectual property and product development and manufacturing experience to continue creating new collaborations where we can be the exclusive development and manufacturing partner supporting leading marketing organizations. 
+· 
+Establish strong distribution relationships for our Chembio-branded products in the U.S and abroad, and establish a direct sales and marketing organization that is focused in the public health market segment, and that utilizes distributors for other market segments, primarily the acute care market which, together with public health, are the main market segments for rapid HIV tests in the United States. We believe that creation of a Chembio public health brand and marketing organization is fundamental to the creation of shareholder value over the long-term. 
+We have increased our commercial activities and efforts in Africa, Europe and Asia for our HIV tests and product pipeline. We believe these efforts will enable us to be more closely engaged with opportunities to engage with customers and partners and to participate in the national testing algorithms that are established and revised from time to time by countries that are beneficiaries of PEPFAR, Global Fund and/or other bilateral or multilateral donor funding. In Europe, where there are a larger percentage of HIV positive people unaware of their status than in the United States, we believe that there is an emerging public health outreach opportunity, and there are relatively few strong competitors that are CE-marked. Most recently we have established new sales and marketing positions in the Company to support our efforts to increase brand awareness globally and to lead our direct sales effort in the U.S. market. 
+Competition 
+There are several established rapid HIV tests which are already in the marketplace that compete with our lateral flow HIV tests and DPP ® HIV 1/2 Assay. These include OraSure (sold by OraSure Technologies), Alere Determine ® rapid test product (sold by Alere, Inc.), and INSTI (sold by Biolytical, Inc.). Our competitors may have significant advantages over us, including being substantially larger and having greater financial, research, manufacturing and marketing resources. Industry competition in general is based on the following: 
+· 
+Scientific and technological capability; 
+· 
+Proprietary know-how; 
+· 
+The ability to develop and market products and processes; 
+· 
+The ability to obtain FDA or other required regulatory approvals; 
+· 
+The ability to manufacture products that meet applicable FDA requirements, (i.e. FDA ' s Quality System Regulations) (see Governmental Regulation section); 
+· 
+The ability to manufacture products cost-effectively; 
+· 
+Access to adequate capital; 
+· 
+The ability to attract and retain qualified personnel; and 
+· 
+The availability of patent protection. 
+We believe our scientific and technological capabilities and our proprietary know-how relating to our in-licensed lateral flow technology rapid tests and to our proprietary know-how related to our patented DPP® technology, particularly for the development and manufacture of tests for the detection of antibodies to infectious diseases such as HIV, are very strong. 
+11 
+Our ability to develop and market other products is in large measure dependent on our having additional resources and/or collaborative relationships. Some of our product development efforts have been funded on a project or milestone basis. We believe that our proprietary know-how in lateral flow technology and in our DPP® technology has been instrumental in our obtaining the collaborations we have and that we continue to pursue. We believe that the patent protection that we have with our DPP® technology enhances our ability to develop more profitable collaborative relationships and to license out the technology. However there are a number of competitive technologies used and/or seeking to be used in point-of-care settings. These technologies may be based on immunoassay principles such as the Company ' s products or other technologies, such as molecular-based technologies. 
+We launched our FDA-approved DPP® HIV 1/2 Assay, which test also can be used with either oral fluid or blood samples, in the U.S. market under a Chembio brand in the fourth quarter of 2014. OraSure Technologies manufactures the only other rapid, oral fluid HIV test that is FDA-approved, and OraSure has enjoyed this position for approximately 10 years. OraSure has lost a significant share of this market as certain customers have been indifferent to using blood or oral fluid samples, because the blood tests, including those made/marketed by Chembio and marketed by Alere, are priced lower and/or are as or more accurate than the performance of OraSure ' s product on blood samples. OraSure has primarily retained those customers for whom the oral fluid sample feature is a strong preference, and this is an estimated $35 million business for OraSure. Although we believe we can capture a meaningful portion of this OraSure market share, we also anticipate that OraSure will defend this business aggressively. 
+In 2006 Alere acquired a division from Abbott Diagnostic located in Japan that manufactured and marketed a rapid HIV test product line called Determine®. The Determine® format was developed for the developing world and remote settings and, central to the needs of that market, the format is essentially a test strip that is integrated into a thin foil wrapper that, when opened, the underside of the wrapper serves as the test surface for applying the blood sample and performing the test. This design reduces costs and shipping weights and volumes and is an advantage for the developing world markets it has served. Some of the disadvantages of the platform are the amount of blood sample that is needed (50 microliters versus 2.5, 5 and 10 for our lateral flow barrel, lateral flow cassette, and DPP® products respectively), the open nature of the test surface, and the absence of a true control that differentiates biological from other kinds of samples. 
+The so-called " 3rd generation " version of this product has been marketed for many years and is the leading rapid HIV test that is used in a large majority of the national algorithms of countries funded by PEPFAR and the Global Fund, as well as many other countries in the world. That product is not FDA-approved though it is CE-marked. The newest Determine® HIV version, which was developed and manufactured at Alere ' s subsidiary in Israel, Orgenics, is the so-called " 4th Generation " version Determine® test. According to its claims, this product detects HIV antibodies and P24 HIV antigens. Since the P24 antigen is known to occur in HIV-positive individuals ' blood samples before antibodies do, based on its performance claims, the 4th generation Determine® test is therefore able to detect HIV infection earlier than tests that solely rely on antibody detection. Chembio ' s tests, as well as all of the other currently FDA-approved rapid HIV tests, only detect antibodies. There are however laboratory tests that are FDA-approved that are " 4th generation " tests, but they are of course neither rapid nor point-of-care. 
+The initial " 4th generation " Alere Determine® rapid test product that was also CE-marked and that Alere launched internationally some years ago has not been successfully commercialized to the best of our knowledge and at least certain published studies were not favorable for this product. However the 4th generation product that is now FDA-approved was apparently modified as compared to the initial international version of it, and it may perform more satisfactorily. Alere received FDA approval of this modified product in August 2013 and CLIA-waiver for it in the fourth quarter of 2014. There is support by a number of key opinion leaders for the public health value of such 4th generation tests, and it represents a significant competitive threat to Chembio as well as to each of the other rapid HIV test manufacturers (OraSure and Trinity primarily). 
+During 2011 Biolytical, Inc. of Vancouver, Canada received FDA approval and in 2012 received CLIA waiver of a flow-through rapid HIV test called " INSTI " . The technology used in the INSTI test, flow-through, is older than lateral flow, and it requires handling of multiple components (3 vials of solution) to perform the test in multiple steps. However, these steps can be accomplished in less than ten minutes, and the actual test results occur in only one minute after those steps are completed. Therefore sample-to-result time is shorter than any of the competitive products. There are settings where that reduced total test time, despite the multiple steps required, may be a distinct advantage, and we believe Biolytical has made some progress in penetrating certain public health markets. 
+Although we have no specific knowledge of any other competitors ' products that are a competitive threat to our products, or that will render our products obsolete, if we fail to maintain and enhance our competitive position or fail to introduce new products and product features, our customers may decide to use the products developed by our competitors, which could result in a loss of revenues and cash flow. 
+12 
+Research and Development 
+During 2016, 2015 and 2014, we spent $8.4 million, $6.4 million and $4.8, respectively, on research and development (including regulatory activities). These expenses were in part underwritten by funding from R&D and milestones revenues of $3.7 million in 2016, $2.3 million in 2015 and $1.7 million in 2014. All of our new product development activities involve employment of our DPP® technology. These activities include completing development of certain products and making significant progress toward the development of additional products. 
+Employees 
+At December 31, 2016, we employed approximately 131 people. We have entered into employment contracts with our Chief Executive Officer and President, John J. Sperzel, our Chief Operating Officer, Sharon Klugewicz, and our Chief Science and Technology Officer, Javan Esfandiari. Due to the specific knowledge and experience of these executives regarding the industry, technology and market, the loss of the services of any one of them would likely have a material adverse effect on the Company. The contract with Mr. Sperzel has a term of three years ending March 13, 2017. The contract with Ms. Klugewicz, has a term of two years ending May 2017. The contract with Mr. Esfandiari has a term of three years ending March 2019. The Company and Mr. Sperzel currently are discussing terms for renewal of his employment agreement. We have obtained a key man insurance policy for Mr. Esfandiari. 
+Governmental Regulation 
+The manufacturing and marketing of our existing and proposed diagnostic products are regulated by the United States Food and Drug Administration ( " FDA " ), United States Department of Agriculture ( " USDA " ), certain state and local agencies, and/or comparable regulatory bodies in other countries. These regulations govern almost all aspects of development, production and marketing, including product testing, authorizations to market, labeling, promotion, manufacturing and record keeping. The Company ' s FDA and USDA regulated products require some form of action by each agency before they can be marketed in the United States, and, after approval or clearance, the Company must continue to comply with other FDA requirements applicable to marketed products, e.g. Quality Systems (for medical devices). Failure to comply with the FDA ' s requirements can lead to significant penalties, both before and after approval or clearance. 
+There are two review procedures by which medical devices can receive FDA clearance or approval. Some products may qualify for clearance under Section 510(k) of the Federal Food, Drug and Cosmetic Act, in which the manufacturer provides a pre-market notification that it intends to begin marketing the product, and shows that the product is substantially equivalent to another legally marketed product (i.e., that it has the same intended use and is as safe and effective as a legally marketed device and does not raise different questions of safety and effectiveness). In some cases, the submission must include data from human clinical studies. Marketing may commence when the FDA issues a clearance letter finding such substantial equivalence. FDA clearance of our DPP® Syphilis Screen & Confirm test will be by means of a 510(k) submission. 
+If the medical device does not qualify for the 510(k) procedure (either because it is not substantially equivalent to a legally marketed device or because it is required by statute and the FDA ' s implementing regulations have an approved application), the FDA must approve a Pre-Marketing Application ( " PMA " ) before marketing can begin. PMA ' s must demonstrate, among other matters, that the medical device provides a reasonable assurance of safety and effectiveness. A PMA application is typically a complex submission, including the results of non-clinical and clinical studies. Preparing a PMA application is a much more expensive, detailed and time-consuming process as compared with a 510(K) pre-market notification. The Company has approved PMAs for the two rapid HIV tests now marketed in the U.S.: both our HIV 1/2 STAT-PAK® and our SURE CHECK® 1/2 HIV. 
+FDA approval of our DPP® HIV screening assay for use with oral fluid or blood samples also was achieved by means of a PMA application. The Clinical Laboratory Improvement Act of 1988 ( " CLIA " ) prohibits laboratories from performing in-vitro tests for the purpose of providing information for the diagnosis, prevention or treatment of any disease or impairment of, or the assessment of, the health of human beings unless there is in effect for such laboratories a certificate issued by the United States Department of Health and Human Services (via the FDA) applicable to the category of examination or procedure performed. Although a certificate is not required for the Company, it considers the applicability of the requirements of CLIA in the design and development of its products. The statutory definition of " laboratory " is very broad, and many of our customers are considered labs. A CLIA waiver will remove certain quality control and other requirements that must be met for certain customers to use the Company ' s products and this is critical to the marketability of a product into the point-of-care diagnostics market. We have received a CLIA waiver for each of the two lateral flow rapid HIV tests now marketed in the U.S. The CLIA waiver was granted by the FDA for HIV 1/2 STAT-PAK® on November 20, 2006 and for SURE CHECK® HIV 1/2 on October 22, 2007. In 2008 the FDA revised its CLIA waiver requirements so that an additional prospective trial need be conducted in order to demonstrate clinical utility by showing that the device is capable of identifying new infections when used by untrained users. Our DPP® HIV 1/2 test received CLIA waiver in October of 2014. 
+13 
+In addition, the FDA regulates the export of medical devices that have not been approved for marketing in the United States. The Federal Food, Drug and Cosmetic Act contains general requirements for any medical device that may not be sold in the United States and is intended for export. Specifically, a medical device intended for export is not deemed to be adulterated or misbranded if the product: (1) complies with the specifications of the foreign purchaser; (2) is not in conflict with the laws of the country to which it is intended for export; (3) is prominently labeled on the outside of the shipping package that it is intended for export; and (4) is not sold or offered for sale in the United States. However, the Federal Food, Drug and Cosmetic Act does permit the export of devices to any country in the world, if the device complies with the laws of the importing country and has valid marketing authorization in one of several " listed " countries under the theory that these listed countries have sophisticated mechanisms for the review of medical devices for safety and effectiveness. 
+We are also subject to regulations in foreign countries governing products, human clinical trials and marketing, and may need to obtain approval or evaluations by international public health agencies, such as the World Health Organization, in order to sell diagnostic products in certain countries. Approval processes vary from country to country, and the length of time required for approval or to obtain other clearances may in some cases be longer than that required for United States governmental approvals. On the other hand, the fact that our HIV diagnostic tests are of value in the AIDS epidemic may lead to some government process being expedited. The extent of potentially adverse governmental regulation affecting us that might arise from future legislative or administrative action cannot be predicted. 
+Environmental Laws 
+To date, we have not encountered any costs relating to compliance with any environmental laws. 
+Intellectual Property 
+Intellectual Property Strategy 
+Our intellectual property strategy is to: (1) build our own intellectual property portfolio around our DPP® technology; (2) pursue licenses, trade secrets and know-how within the area of rapid point-of-care testing, and (3) develop and acquire proprietary positions to reagents and new hardware platforms for the development and manufacture of rapid diagnostic tests. 
+We have obtained patent coverage on our DPP® technology, including four U.S. patents, and patents in China, Malaysia, Eurasia, Mexico, Singapore, Japan, Australia, Indonesia, Korea and the U.K. Additional patent applications on our DPP® technology are pending in the U.S., as well as in many foreign countries such as Brazil, Canada, the European Union, India, Israel, and South Africa. Patents have also been filed on extensions to the DPP® product line concept, such as 4th generation assays. The four U.S. patents are as follows: 
+U.S. Patent No. 
+Issued 
+Expires 
+Nature 
+Type 
+Description 
+7,189,522 
+3/13/2007 
+3/11/2025 
+test device 
+utility 
+a test device for determining the presence of a ligand in a sample 
+7,682,801 
+3/23/2010 
+3/11/2025 
+test device 
+and method 
+utility 
+a test device and a method for determining 
+the presence of a ligand in a sample 
+7,879,597 
+2/1/2011 
+3/11/2025 
+test device 
+utility 
+a test device for determining multiple 
+ligands in a sample 
+8,507,259 
+8/13/2013 
+3/11/2025 
+test device 
+utility 
+a test device for determining the 
+presence of a ligand in a sample 
+We have also filed for patents and obtained some patents in the U.S. for other inventions, such as its multiple host species veterinary TB test, and patent applications for the other inventions are in various stages from being recently filed and not yet examined, to already examined and allowed but not yet issued. We selectively and strategically foreign files its patent applications based on a number of economic and strategic factors related to the invention. 
+Trademarks 
+We have filed and obtained trademarks for our products, including DPP®, SURE CHECK®, and STAT-PAK® and also for the SampleTainer® used in certain DPP® products. Our DPP® trademark is also registered under the European convention (ECT). We recently filed a trademark for STAT-VIEW®, to market the barrel product in Europe. 
+Trade Secrets and Know-How 
+We believe that we have developed a substantial body of trade secrets and know-how relating to the development and manufacture of lateral flow and DPP®-based diagnostic tests, including but not limited to the sourcing and optimization of materials for such tests, and how to maximize sensitivity, speed-to-result, specificity, stability and reproducibility. We possess proprietary know-how to develop tests for multiple conditions using colored latex. Our buffer formulations enable extremely long shelf lives of our rapid HIV and other tests and we believe that this provides us with an important competitive advantage. 
+14 
+Lateral Flow Technology and Reagent Licenses 
+As part of the agreements executed in 2006 with Alere for the marketing of our HIV tests, we were granted non-exclusive licenses to certain lateral flow patents for certain products manufactured and marketed by us, including but not limited to our lateral flow HIV tests. This license allows us to produce, market and sell assays using lateral flow technologies specifically including our STAT-PAK®, SURE CHECK®, DIPSTICK®, and veterinary product lines. Under this license agreement, prior to February 3, 2015, we paid royalties to Alere ranging from 5% to 8½%, depending upon the country in which the products are sold. Between 2007 and 2015 we incurred a total of $2.87 million in lateral flow royalty expenses. As of February 3, 2015 this royalty expense was no longer payable. 
+Although we believe our DPP® is outside of the scope of all lateral flow patents of which we are aware, we consult with patent counsel, and seek licenses and/or redesigns of products that we believe to be in our best interests. Because of the costs and other negative consequences of time-consuming patent litigation, we often attempt to obtain a license on reasonable terms. Nevertheless there is no assurance that the Alere lateral flow patents we have licensed will not be challenged or that other patents containing claims relevant to our lateral flow or DPP® products will not be granted to third parties and that licenses to such patents, will be available on reasonable terms, if any. In the past Alere has aggressively enforced its lateral flow intellectual property, although some of the main patents have expired and we are not aware of any patent enforcement litigation that is ongoing with respect to the Alere lateral flow intellectual property. 
+Regardless, the DPP® technology provides us with our own intellectual property. We believe it provides us with a freedom to operate, and that it also enables tests to be developed with improved sensitivity as compared with comparable tests on lateral flow platforms. We have signed and anticipate signing new development projects based upon the DPP® technology that will provide new manufacturing and marketing opportunities. We have filed other patent applications that we believe will strengthen the DPP® intellectual property and have also filed for patent protection for certain other point-of-care technologies or applications thereof. 
+The peptides used in our rapid HIV tests were patented by Adaltis Inc. and were licensed to us under a 10-year non-exclusive license agreement dated August 30, 2002. However, in connection with Adaltis' bankruptcy, during the third quarter of 2009 we bought out all of our remaining obligations under that agreement. We also have licensed the antigens used in other tests including our Syphilis, Tuberculosis, Leptospirosis, Leishmaniasis and Chagas tests, and we may enter other license agreements. In prior years we concluded license agreements related to intellectual property rights owned by the United States associated with HIV-1, and during the first quarter of 2008 we entered into a sub-license agreement for HIV-2 with Bio-Rad Laboratories N.A., the exclusive licensee of the Pasteur Institute's HIV-2 intellectual property estate. 
+Corporate Information 
+We are a Nevada corporation that was formed in December 1985. Since inception, we have been involved in developing, manufacturing, selling and distributing medical diagnostic tests, including rapid tests that detect a number of diseases and other conditions in humans and animals. 
+On May 30, 2012, we effected a 1-for-8 reverse split of its common stock. The effect of this reverse stock split also has been retroactively reflected for all periods in these financial statements. 
+Stockholder Rights Agreement 
+On March 8, 2016, we entered into a Rights Agreement (the "Rights Agreement") between us and Action Stock Transfer Corp., as Rights Agent. Pursuant to the Rights Agreement, we declared a dividend distribution of one Preferred Share Purchase Right (a "Right") for each outstanding share of our common stock, par value $0.01 (the "Common Stock"), in the manner described below. The Board of Directors set the payment date for the distribution of the Rights as March 8, 2016, and the Rights were distributed to our shareholders of record on that date. The description and terms of the Rights are set forth in the Rights Agreement. 
+Rights Initially Not Exercisable. The Rights are not exercisable until a Distribution Date. Until a Right is exercised, the holder thereof, as such, has no rights as a shareholder of the Company, including, without limitation, the right to vote or to receive dividends. 
+15 
+Separation and Distribution of Rights . The Rights are to be evidenced by the certificates for shares of Common Stock registered in the names of the holders thereof, and not by separate rights certificates until the earlier to occur of (i) the close of business on the tenth business day following a public announcement that an Acquiring Person (as defined in the Rights Agreement) has acquired a Combined Ownership (as defined in the Rights Agreement) of 20% or more of the outstanding shares of the Common Stock (the "Shares Acquisition Date") or (ii) the later of (A) the close of business on the tenth business day (or such later date as may be determined by action of the Board of Directors prior to such time as any person or group of affiliated or associated persons becomes an Acquiring Person) after the date that a tender or exchange offer or intention to commence a tender or exchange offer by any person is first published, announced, sent or given within the meaning of Rule 14d-4(A) under the Securities Exchange Act of 1934, as amended, the consummation of which would result in any person having Combined Ownership of 20% or more of the outstanding shares of the Common Stock, or (B) if such a tender or exchange offer has been published, announced, sent or given before the date of the Rights Agreement, then the close of business on the tenth business day after the date the Rights Agreement was entered into (or such later date as may be determined by action of the Board of Directors prior to such time as any person becomes an Acquiring Person); (the earlier of such dates referred to in (i) and (ii), which date may include any such date that is after the date of the Rights Agreement but prior to the issuance of the Rights, being called the "Distribution Date"). 
+16 
+Glossary 
+AIDS 
+Acquired Immunodeficiency Syndrome. AIDS is caused by the Human Immunodeficiency Virus, HIV. 
+ALGORITHM (parallel or serial) 
+For rapid HIV testing this refers both to method or protocol (in developing countries to date) for using rapid tests from different manufacturers in combination to screen and confirm patients at the point-of-care, and may also refer to the specific tests that have been selected by an agency or ministry of health to be used in this way. A parallel algorithm uses two screening tests from different manufacturers and a tie-breaker test only if there is a discrepancy between the screening tests results. A serial algorithm only uses a second confirmatory test if there is a positive result from the screening test, meaning that the number of confirmatory tests used is equal to the positivity rate in the testing venue. A tie-breaker test resolves discrepancies between the screen and the confirmatory test. 
+ANTIBODY 
+A protein which is a natural part of the human immune system produced by specialized cells to neutralize antigens, including viruses and bacteria that invade the body. Each antibody producing cell manufactures a unique antibody that is directed against, binds to and eliminates one, and only one, specific type of antigen. 
+ANTIGEN 
+Any substance which, upon entering the body, stimulates the immune system leading to the formation of antibodies. Among the more common antigens are bacteria, pollens, toxins, and viruses. 
+ANVISA 
+The National Health Surveillance Agency of Brazil 
+ARVs 
+Anti-retroviral medications developed to fight AIDS 
+CDC 
+United States Centers for Disease Control and Prevention 
+CLIA waiver 
+Clinical Laboratory Improvement Act designation that allows simple tests to be performed in point-of-care settings such as doctor's offices, walk-in clinics and emergency rooms. 
+DIAGNOSTIC 
+Pertaining to the determination of the nature or cause of a disease or condition. Also refers to reagents or procedures used in diagnosis to measure proteins in a clinical sample. 
+FIOCRUZ 
+The Oswaldo Cruz Foundation of Brazil 
+FDA 
+United States Food and Drug Administration 
+IgG 
+IgG or Immunoglobulin G are proteins found in human blood. This protein is called an "antibody" and is an important part of the body's defense against disease. When the body is attacked by harmful bacteria or viruses, antibodies help fight these invaders. 
+IgM 
+IgM or Immunoglobulin M are proteins found in human blood. This protein is called an "antibody" and is an important part of the body's defense against disease. When the body is attacked by harmful bacteria or viruses, antibodies help fight these invaders. 
+NGO 
+Non-Governmental Organization 
+OTC 
+Over-the-Counter 
+PEPFAR 
+The President's Emergency Plan for AIDS Relief 
+PMA 
+Pre-Marketing Approval –FDA approval classification for a medical device that is not substantially equivalent to a legally marketed device or is otherwise required by statute to have an approved application. Rapid HIV tests must have an approved PMA application before marketing of such a product can begin. 
+PROTOCOL 
+A procedure pursuant to which an immunodiagnostic test is performed on a particular specimen in order to obtain the desired reaction. 
+REAGENT 
+A chemical added to a sample under investigation in order to cause a chemical or biological reaction which will enable measurement or identification of a target substance. 
+RETROVIRAL 
+A type of virus which contains the enzyme Reverse Transcriptase and is capable of transforming infected cells to produce diseases in the host such as AIDS. 
+SENSITIVITY 
+Refers to the ability of an assay to detect and measure small quantities of a substance of interest. The greater the sensitivity, the smaller the quantity of the substance of interest the assay can detect. Also refers to the likelihood of detecting the antigen when present. 
+SPECIFICITY 
+The ability of an assay to distinguish between similar materials. The greater the specificity, the better an assay is at identifying a substance in the presence of substances of similar makeup. 
+USDA 
+U.S Department of Agriculture 
+WHO 
+World Health Organization 
+17
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diff --git a/raw/filings/0001092662/2016/0001092662-17-000023/item13.txt b/raw/filings/0001092662/2016/0001092662-17-000023/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..fe91ac2f674135ad3af95e0173fb91bdaeaadfe2
--- /dev/null
+++ b/raw/filings/0001092662/2016/0001092662-17-000023/item13.txt
@@ -0,0 +1,3 @@
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE. 
+The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.
\ No newline at end of file
diff --git a/raw/filings/0001092662/2016/0001092662-17-000023/item9a.txt b/raw/filings/0001092662/2016/0001092662-17-000023/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..7df33dac656c9504a2ec8b2f963dce680a00995a
--- /dev/null
+++ b/raw/filings/0001092662/2016/0001092662-17-000023/item9a.txt
@@ -0,0 +1,40 @@
+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+(a) Disclosure Controls and Procedures. Under the supervision and with the participation of our senior management, consisting of our chief executive officer and our chief financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")), as of the end of the period covered by this report (the "Evaluation Date"). Based on that evaluation, the Company's management, including our chief executive officer and chief financial officer, concluded that as of the Evaluation Date our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports that we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. Our disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in our Exchange Act reports is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure. 
+Management's Annual Report on Internal Control Over Financial Reporting. The Company's management is responsible for establishing and maintaining an adequate system of internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f)). Our internal control over financial reporting is a process, under the supervision of our chief executive officer and chief financial officer, designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States. These internal controls over financial reporting processes include policies and procedures that: 
+a. 
+Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company; 
+b. 
+Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and 
+c. 
+Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance of achieving their control objectives. 
+44 
+Management's Report on Internal Control over Financial Reporting 
+Management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f). 
+The Company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting can only provide reasonable assurance and may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+Under the supervision and with the participation of our management, including the Chief Executive Officer (CEO) and the Chief Financial Officer (CFO), we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2016, based on the framework and criteria in the 2013 Internal Control – Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on management's evaluation and those criteria, the CEO and CFO concluded that its system of internal control over financial reporting was effective as of December 31, 2016. 
+The Company's independent registered public accounting firm has issued an attestation report on the Company's internal control over financial reporting. 
+Dated: March 7, 2017 /s/ John J. Sperzel 
+John J. Sperzel III 
+Chief Executive Officer 
+Dated: March 7, 2017 /s/ Richard J. Larkin 
+Richard J. Larkin 
+Chief Financial Officer 
+45 
+Report of Independent Registered Public Accounting Firm 
+Board of Directors and Stockholders of 
+Chembio Diagnostics, Inc. 
+Medford, New York 
+We have audited the internal control over financial reporting of Chembio Diagnostics, Inc. and subsidiaries (the "Company") as of December 31, 2016, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting ("Management's Report"). Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. 
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+In our opinion, Chembio Diagnostics, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based COSO criteria. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Chembio Diagnostics, Inc. and subsidiary as of December 31, 2016 and 2015, and the related consolidated statements of operations, comprehensive loss, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2016 and our report dated March 7, 2017 expressed an unqualified opinion thereon. 
+/s/ BDO USA, LLP 
+Melville, New York 
+March 7, 2017 
+46 
+(b) Changes in Internal Control over Financial Reporting. There were no changes in our internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Rule 13a-15 or Rule 15d-15 under the Exchange Act that occurred during the Company's last fiscal quarter of the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
\ No newline at end of file
diff --git a/raw/filings/0001092662/2016/0001092662-17-000023/rp_note.txt b/raw/filings/0001092662/2016/0001092662-17-000023/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0001092662/2016/0001092662-17-000023/rpt_disclosure.txt b/raw/filings/0001092662/2016/0001092662-17-000023/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..01844cf13b79da7483478f6e57124f3a5d29c6b0
--- /dev/null
+++ b/raw/filings/0001092662/2016/0001092662-17-000023/rpt_disclosure.txt
@@ -0,0 +1,16 @@
+Approval of Transactions with Related Persons 
+The Board of Directors reviews all transactions
+involving us in which any of our directors, director nominees, significant stockholders and executive officers and their immediate
+family members are participants to determine whether such person has a direct or indirect material interest in the transaction. 
+All directors, director nominees and executive officers must notify us of any proposed transaction involving us in which such person
+has a direct or indirect material interest. Such proposed transaction is then reviewed by either the Board as a whole or the Audit
+Committee, which determines whether to approve the transaction. After such review, the reviewing body approves the transaction
+only if it determines that the transaction is in, or not inconsistent with, the best interests of the Company and its stockholders. 
+Director Independence 
+Our common stock trades on the NASDAQ. 
+Accordingly, we are subject to the corporate governance standards of NASDAQ, which require, among other things, that a majority
+of the board of directors be independent. We define an "independent" director in accordance with the NASDAQ Global Market's
+requirements for independent directors. Under this definition, we have determined that each of Katherine Davis, Gail Page,
+and Peter Kissinger currently qualifies as an independent director. If John Potthoff is elected to the Board of Directors,
+the Board of Directors believes Dr. Potthoff would qualify as an independent director. We do not list the "independent"
+definition we use on our internet website.
\ No newline at end of file
diff --git a/raw/filings/0001092662/2017/0001092662-18-000013/filing.txt b/raw/filings/0001092662/2017/0001092662-18-000013/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..32d4a69b5e9f13d6c2a961d731bfaa10f92f656f
--- /dev/null
+++ b/raw/filings/0001092662/2017/0001092662-18-000013/filing.txt
@@ -0,0 +1,3475 @@
+10-K
+1
+form10_k.htm
+FORM 10-K FOR 2016
+UNITED STATES 
+Securities and Exchange Commission 
+Washington, D.C. 20549 
+FORM 10-K 
+[X] 
+ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the fiscal year ended December 31, 2017 
+or 
+[ ] 
+TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the transition period from _______ to ______ . 
+Commission File No. 0-30379 
+CHEMBIO DIAGNOSTICS, INC. 
+(Exact name of registrant as specified in its charter) 
+Nevada 
+88-0425691 
+(State or other jurisdiction of incorporation or organization) 
+(I.R.S. Employer Identification No.) 
+3661 Horseblock Road, Medford, NY 
+11763 
+(Address of principal executive offices) 
+(Zip Code) 
+Registrant’s telephone number, including area code (631) 924-1135 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of each class 
+Name of each exchange on which registered 
+Common Stock, $0.01 par value 
+Preferred Share Purchase Rights 
+The NASDAQ Stock Market LLC 
+The NASDAQ Stock Market LLC 
+Securities registered pursuant to section 12(g) of the Act: 
+None 
+(Title of Class) 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes __ No X 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes __ No X 
+Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No__ 
+Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes X No __ 
+Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer", "accelerated filer", "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one): 
+Large accelerated filer [ ] 
+Accelerated filer [X ] 
+Non-accelerated filer [ ] 
+Smaller reporting company [ ] 
+(Do not check if a smaller reporting company) 
+Emerging growth company [ ] 
+If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act [ ] 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes __ No _X_ 
+As of the last business day of the Company’s most recently completed second fiscal quarter, the aggregate market value of voting and non-voting common equity held by non-affiliates* was $56,453,579. 
+As of March 5, 2018, the registrant had 14,162,702 common shares outstanding. 
+* Without asserting that any of the issuer’s directors or executive officers, or the entities that own more than five percent of the outstanding shares of the Registrant’s common stock, are affiliates, the shares of which they are beneficial owners have not been included in shares held by non-affiliates solely for this calculation. 
+TABLE OF CONTENTS 
+Page 
+PART I 
+ITEM 1. 
+BUSINESS 
+2 
+ITEM 1A. 
+RISK FACTORS 
+10 
+ITEM 1B. 
+UNRESOLVED STAFF COMMENTS 
+22 
+ITEM 2. 
+PROPERTIES 
+22 
+ITEM 3. 
+LEGAL PROCEEDINGS 
+22 
+ITEM 4 . 
+MINE SAFETY DISCLOSURES 
+22 
+PART II 
+ITEM 5. 
+MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+23 
+ITEM 6. 
+SELECTED FINANCIAL DATA 
+24 
+ITEM 7. 
+MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+25 
+ITEM 7A. 
+QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 
+31 
+ITEM 8. 
+FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+31 
+ITEM 9. 
+CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. 
+31 
+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+31 
+ITEM 9B. 
+OTHER INFORMATION 
+34 
+PART III 
+ITEM 10. 
+DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
+35 
+ITEM 11. 
+EXECUTIVE COMPENSATION 
+35 
+ITEM 12. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+35 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+35 
+ITEM 14. 
+PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+35 
+PART IV 
+ITEM 15. 
+EXHIBITS, FINANCIAL STATEMENT SCHEDULES 
+36 
+ITEM 16. 
+FORM 10-K SUMMARY 
+36 
+SIGNATURES 
+37 
+Table of Contents 
+PART I 
+ITEM 1. 
+BUSINESS 
+FORWARD-LOOKING STATEMENTS 
+This Annual Report on Form 10-K, including exhibits that are being filed as part of this report, as well as other statements made by Chembio Diagnostics, Inc. (“Chembio”, the “Company”, “we”, “us”, and “our”), contain “forward-looking statements” that include information relating to future events, future financial performance, strategies, expectations, competitive environment and regulation. Words such as “may,” “should,” “could,” “would,” “predicts,” “potential,” “continue,” “expects,” “anticipates,” “future,” “intends,” “plans,” “believes,” “estimates,” and similar expressions, as well as statements in future tense, identify forward-looking statements. 
+These forward-looking statements include such things as: investment objectives and the Company’s ability to make investments in a timely manner on acceptable terms; references to future success of the Company’s products; the Company’s business strategy; estimated future capital expenditures; sales of the Company’s products; competitive strengths and goals; and, other similar matters. 
+These forward-looking statements reflect the Company’s current beliefs and expectations with respect to future events and are based on assumptions and are subject to risks and uncertainties and other factors outside the Company’s control that may cause actual results to differ materially from those projected. Such factors include, but are not limited to, those described under Item 1A entitled “Risk Factors”, matters described elsewhere in this Report, and the following: ability to market and sell products, whether through our internal, direct sales force or third parties; ability to manufacture products in accordance with applicable specifications, performance standards and quality requirements; ability to obtain, and timing and cost of obtaining, necessary regulatory approvals for new products or new indications or applications for existing products; ability to comply with applicable regulatory requirements; ability to effectively resolve warning letters, audit observations and other findings or comments from the FDA or other regulatory entities; changes in relationships, including disputes or disagreements, with strategic partners or other parties and reliance on strategic partners for the performance of critical activities under collaborative arrangements; failure of distributors or other customers to meet purchase forecasts, historic purchase levels or minimum purchase requirements for our products; impact of replacing distributors; inventory levels at distributors and other customers; ability of the Company to achieve its financial and strategic objectives and continue to increase its revenues; ability to identify, complete, integrate and realize the full benefits of future acquisitions; impact of competitors, competing products and technology changes; reduction or deferral of public funding available to customers; competition from new or better technology or lower cost products; ability to develop, commercialize and market new products; market acceptance of our products; changes in market acceptance of products based on product performance or other factors, including changes in testing guidelines, algorithms or other recommendations by the Centers for Disease Control and Prevention and other agencies; ability to fund research and development and other products and operations; ability to obtain and maintain new or existing product distribution channels; reliance on sole supply sources for critical products and components; availability of related products produced by third parties or products required for use of our products; ability to maintain sustained profitability; volatility of the Company’s stock price; uncertainty relating to patent protection and potential patent infringement claims; uncertainty and costs of litigation relating to patents and other intellectual property; availability of licenses to patents or other technology; obstacles to international marketing and manufacturing of products; ability to sell products internationally, including the impact of changes in international funding sources and testing algorithms; adverse movements in foreign currency exchange rates; loss or impairment of sources of capital; ability to attract and retain qualified personnel; exposure to product liability and other types of litigation; changes in international, federal or state laws and regulations; customer consolidations and inventory practices; equipment failures and ability to obtain needed raw materials and components; the impact of terrorist attacks and civil unrest; changes in laws or regulations; global and regional economic conditions, including conditions affecting the credit markets, such as those resulting from the United Kingdom referendum held on June 23, 2016 in which United Kingdom voters approved an exit from the European Union; and general political, business and market conditions. 
+Although the Company believes the expectations reflected in such forward-looking statements are based upon reasonable assumptions, these are only assumptions, and forward-looking statements should not be read as a guarantee of future performance or results and will probably not be accurate indications of when such performance or results will be achieved. Investors are cautioned that forward-looking statements may not be reliable and speak only as of the date they are made and that, except as required by law, the Company undertakes no obligation to update these forward-looking statements to reflect any future events or circumstances. All subsequent written or oral forward-looking statements attributable to the Partnership or to individuals acting on its behalf are expressly qualified in their entirety by this section. 
+Investors should also be aware that while we do, from time to time, communicate with securities analysts, it is against our policy to disclose any material non-public information or other confidential commercial information to securities analysts unless and until we have made it publicly available. Accordingly, stockholders should not assume that we agree with any statement or report issued by any analyst irrespective of the content of the statement or report. Furthermore, we have a policy against issuing or confirming financial forecasts or projections issued by others. Thus, to the extent that reports issued by securities analysts contain any projections, forecasts or opinions, such reports are not the responsibility of the Company. 
+We provide free of charge on our website at www.chembio.com our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable. Additional information about us can also be found on our website. Members of the public may read and copy any materials we file with the SEC at the SEC's Public Reference Room at 100 F Street, NE, and Washington, DC 20549. Members of the public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800–SEC–0330. The Internet address of the Commission is www.sec.gov. That website contains reports, proxy and information statements and other information regarding issuers, like Chembio, that file electronically with the Commission. Visitors to the Commission's website may access such information by searching the EDGAR database. 
+For further information about these and other risks, uncertainties and factors, please review the disclosure included in this report under “Part I, Item 1A, Risk Factors.” 
+Our Business 
+General 
+Chembio Diagnostics develops, manufactures, and commercializes point-of-care (POC) diagnostic tests that are used to detect or monitor diseases. All products that are currently being developed are based on the Company’s patented DPP ® technology, a novel point-of-care diagnostic platform that offers certain customer advantages as compared to traditional lateral flow technology. POC tests, by providing prompt and early diagnosis, can reduce patient stays, lower overall costs, improve therapeutic interventions and improve patient outcomes. POC tests can also prevent needless hospital admissions, simplify testing procedures, avoid delays from central lab batching, and eliminate the need for return visits. 
+Our product commercialization and product development efforts are focused in three areas: sexually transmitted disease, tropical & fever disease, and technology collaborations. In sexually transmitted disease, we are commercializing tests for HIV and Syphilis. In tropical and fever disease, we are commercializing tests for Zika virus, dengue virus, and chikungunya virus, and developing tests for malaria, ebola, lassa, Marburg, leptospirosis, Rickettsia typhi , Burkholderia pseudomallei , and Orientia tsutsugamushi , individually or as part of a fever panel test. Through technology collaborations, we are developing tests for a specific form of cancer, concussion, bovine tuberculosis, and for an undisclosed biomarker, the latter in collaboration with global biopharmaceutical company AstraZeneca. 
+2 
+Table of Contents 
+Large and growing markets have been established for these kinds of tests, initially in high prevalence regions where they are indispensable for large scale prevention and treatment programs. Our product development is focused on areas where the availability of rapid POC screening, diagnostic, or confirmatory results can improve health outcomes. More generally, we believe there is and will continue to be a growing demand for diagnostic products that can provide accurate, actionable diagnostic information in a rapid, cost-effective manner at the point of care. 
+Our products are sold to medical laboratories and hospitals, governmental and public health entities, non-governmental organizations, medical professionals and retail establishments, both domestically and internationally, under our STAT-PAK ® , SURE CHECK ® , STAT-VIEW ® or DPP ® registered trademarks, or under the private labels of our marketing partners. 
+Our Products 
+Products: Commercially Available 
+Following is a summary of our point-of-care products, including regulatory and commercial status: 
+Product 
+Description 
+Regulatory Status 
+Commercial Status 
+DPP ® HIV 1/2 Assay 
+A rapid, point-of-care assay for the detection of HIV-1 and HIV-2 antibodies in finger stick, venous blood, serum, plasma or oral fluid 
+Premarket approval (“PMA”) by U.S. FDA 
+CLIA (Clinical Laboratory Improvement Amendments of 1988) waived 
+CE marked (European Union/Caribbean) 
+World Health Organization (“WHO”) pre-qualification 
+Agência Nacional de Vigilância Sanitária (“ANVISA”) approved (Brazil) 
+Also registered in various other countries 
+Marketed 
+DPP ® HIV-Syphilis Assay 
+A rapid, point-of-care assay for the detection of HIV-1 and HIV-2 antibodies and for antibodies to Treponema pallidum (the causative agent of Syphilis) in finger stick, venous blood, serum or plasma 
+CE marked (European Union/Caribbean) 
+ANVISA approved (Brazil) 
+Also registered in various other countries 
+Marketed 
+DPP ® Syphilis Screen and Confirm Assay 
+A rapid, point-of-care assay for the simultaneous detection of IgG and IgM antibodies to Treponema pallidum (the causative agent of Syphilis) and IgG and IgM antibodies to RPR in finger stick, venous blood, serum or plasma 
+CE marked (European Union/Caribbean) 
+Also registered in various other countries 
+Marketed 
+SURE CHECK ® HIV 1/2 Assay 
+A rapid, point-of-care assay for the detection of HIV-1 and HIV-2 antibodies in finger stick or venous blood 
+PMA approved by U.S. FDA 
+CLIA waived 
+CE marked (European Union/Caribbean) 
+WHO pre-qualification 
+Designated eligible for procurement by Global Fund 
+Also registered in various other countries 
+Marketed 
+HIV 1/2 STAT-PAK ® Assay 
+A rapid, point-of-care assay for the detection of HIV-1 and HIV-2 antibodies in finger stick, venous blood, serum or plasma 
+PMA approved by U.S. FDA 
+CLIA waived 
+CE marked (European Union/Caribbean) 
+WHO pre-qualification 
+Designated eligible for procurement by Global Fund 
+Also registered in various other countries 
+Marketed 
+DPP ® Dengue IgM/IgG Assay 
+A rapid, point-of-care assay for the simultaneous and separate detection of both IgG and IgM antibodies to Dengue virus in finger stick, venous blood, serum or plasma 
+Malaysia Medical Device Authority ("MDA") approved 
+Additional regulatory approvals pending 
+Marketed 
+DPP ® Dengue NS1 Antigen Assay 
+A rapid, point-of-care assay for the detection of NS1 antigen to Dengue virus in finger stick, venous blood, serum or plasma 
+Malaysia MDA approved 
+Additional regulatory approvals pending 
+Marketed 
+3 
+Table of Contents 
+DPP ® Zika IgM Assay 
+A rapid, point-of-care assay for the detection of IgM antibodies to Zika virus in finger stick, venous blood, serum or plasma 
+U.S. FDA Emergency Use Authorized 
+Additional regulatory approvals pending 
+Marketed 
+DPP ® Zika IgM/IgG Assay 
+A rapid, point-of-care assay for the separate and simultaneous detection of IgM and IgG antibodies to Zika virus in finger stick, venous blood, serum or plasma 
+CE marked (European Union/Caribbean) 
+ANVISA approved (Brazil) 
+Additional regulatory approvals pending 
+Marketed 
+DPP ® Chikungunya IgM/IgG Assay 
+A rapid, point-of-care assay for the separate and simultaneous detection of IgM and IgG antibodies to Chikungunya virus in finger stick, venous blood, serum or plasma 
+Malaysia MDA Approved 
+Additional regulatory approvals pending 
+Marketed 
+DPP ® Zika, Dengue, Chikungunya IgM/IgG Assay 
+A rapid, point-of-care assay for the separate and simultaneous detection of IgM and IgG antibodies to Zika, Dengue, Chikungunya virus in finger stick, venous blood, serum or plasma 
+Malaysia MDA Approved 
+Additional regulatory approvals pending 
+Marketed 
+DPP ® Vet TB Assay 
+(Veterinary Application) 
+A rapid, point-of-care assay for the detection of Mycobacterium bovis antibodies in Elk, Red Deer, White-tailed Deer and Fallow Deer 
+USDA approved 
+Marketed 
+Chagas STAT-PAK ® Assay 
+A rapid, point-of-care assay for the detection of antibodies to Trypanosoma cruzi in finger stick, venous blood, serum or plasma 
+CE marked (European Union/Caribbean) 
+Additional regulatory approvals pending 
+Marketed 
+RVR ® Dengue IgM/IgG Assay 
+A rapid, point-of-care assay for the detection of IgM and IgG antibodies to the Dengue virus in finger stick, venous blood serum or plasma 
+Malaysia MDA approved 
+Additional regulatory approvals pending 
+Marketed 
+RVR ® Dengue NS1 Assay 
+A rapid, point-of-care assay for the detection of NS1 antigen to Dengue virus in finger stick, venous blood, serum or plasma 
+Malaysia MDA approved 
+Additional regulatory approvals pending 
+Marketed 
+RVR ® Dengue Combo Assay 
+A rapid, point-of-care assay for the simultaneous and separate detection of IgG and IgM antibodies and NS1 antigen to Dengue virus in finger stick, venous blood, serum or plasma 
+Malaysia MDA approved 
+Additional regulatory approvals pending 
+Marketed 
+Products: Under Clinical Evaluation 
+Following is a summary of our point-of-care products under clinical evaluation, including regulatory and commercial status: 
+Product 
+Description 
+Regulatory Status 
+Commercial Status 
+DPP ® HIV-Syphilis Assay System 
+A rapid, point-of-care assay for the detection of HIV-1 and HIV-2 antibodies and for antibodies to Treponema pallidum (the causative agent of Syphilis) in finger stick, venous blood, serum or plasma 
+Filed Premarket Approval (“PMA”) Application to U.S. FDA 
+Not Marketed 
+DPP ® Malaria/Ebola Assay 
+A rapid, point-of-care assay for the separate and simultaneous detection of Ebola VP40 antigen and Malaria antigen P.f/P.v in finger stick, venous blood, serum or plasma 
+Under clinical evaluation 
+Not Marketed 
+DPP ® Ebola Assay 
+A rapid, point-of-care assay for the detection of Ebola VP40 antigen in finger stick, venous blood, serum or plasma 
+Under clinical evaluation 
+Not Marketed 
+DPP ® Fever Panel Assay - Africa 
+A rapid, point-of-care assay for the separate and simultaneous detection of antigens to Malaria pf/Pan species, Ebola, Lassa Fever, Marburg, Zika, Dengue and Chikungunya in finger stick, venous blood, serum or plasma 
+Under clinical evaluation 
+Not Marketed 
+Products: Under Development 
+Following is a summary of our point-of-care products under development, including regulatory and commercial status: 
+Product 
+Description 
+Regulatory Status 
+Commercial Status 
+DPP ® Malaria Antigen P.f/P.V Assay 
+A rapid, point-of-care assay for the separate detection of Malaria antigen P.F/P.V in finger stick, venous blood, serum or plasma 
+Under development 
+Not Marketed 
+4 
+Table of Contents 
+DPP ® Fever Panel Assay - Asia 
+A rapid, point-of-care assay for the separate and simultaneous detection of antigens to Malaria pf/Pan Rickettsia typhi , Orientia tsutsugamushi , Leptospira Burkholderia pseudomallei , Dengue virus, Chikungunya virus and Zika virus in finger stick, venous blood, serum or plasma 
+Under development 
+Not Marketed 
+DPP ® Undisclosed Biomarker Assay 
+A rapid, semi-quantitative point-of-care assay for an undisclosed novel biomarker in finger stick, venous blood, serum or plasma 
+Under development 
+Not Marketed 
+DPP ® Cancer Assay 
+A rapid, quantitative point-of-care assay for an undisclosed novel biomarker in finger stick, venous blood, serum or plasma 
+Under development 
+Not Marketed 
+DPP ® Concussion Assay 
+A rapid, quantitative point-of-care assay for an undisclosed novel biomarker in finger stick, venous blood, serum or plasma 
+Under development 
+Not Marketed 
+DPP ® BovidTB Assay 
+(Veterinary Application) 
+A rapid, point-of-care assay for the detection of Mycobacterium bovis antibodies in serum of cattle 
+Under development 
+Not Marketed 
+DPP ® Technology & Development 
+The Company’s commercially available products employ either our patented Dual Path Platform (DPP ® ) technology or traditional lateral flow technology. We believe products developed using the Company’s DPP ® technology can provide superior diagnostic performance compared with products that utilize traditional lateral flow technology. 
+Chembio is executing its strategy to leverage the DPP ® intellectual property, as well as the Company’s scientific and operational expertise, to create new collaborations where Chembio will serve as an exclusive development and manufacturing partner. Examples of such collaborations include the following: 
+● 
+In October 2014, we entered into an agreement with an international diagnostics company to develop a POC diagnostic test for the early detection and monitoring of a specific type of cancer. At that time, the cancer project represented the first application of the DPP ® technology outside the infectious disease field. 
+● 
+In January 2015, we entered into an agreement with the Concussion Science Group (CSG) Division of Perseus Science Group LLC to utilize our DPP ® technology to develop a POC diagnostic test for traumatic brain injury (TBI), including sports-related concussions. 
+● 
+In January 2015, we were awarded a grant from The Bill & Melinda Gates Foundation to expedite the feasibility testing and development of a DPP ® Malaria POC rapid diagnostic to accurately identify individuals infected with Plasmodium falciparum parasite. 
+● 
+In October 2015, we were awarded a grant from The Paul G. Allen Family Foundation to develop a POC test to identify multiple life-threatening febrile illnesses. Under the $2.1 million dollar grant, we used our DPP ® technology to develop a DPP ® Fever Panel Assay, a POC multiplex assay to simultaneously detect Malaria, Dengue, Zika, Chikungunya, Ebola, Lassa and Marburg. 
+● 
+In October 2015, we signed an agreement with opTricon (Berlin, Germany), a leading developer of mobile analysis devices for rapid diagnostic tests. The DPP ® Micro Reader provides customers with various options to capture, record, transmit and store test results. With one-button operation, the palm-sized and battery-operated DPP ® Micro Reader is simple, fast, portable, and cost-effective. 
+● 
+In October 2017, we signed a development agreement with AstraZeneca for the development of a quantitative point-of-care assay for a novel biomarker based on our DPP ® assay and DPP ® Micro Reader technologies. 
+Sales, Marketing & Distribution 
+We continue to target the following geographies: United States, Europe, Latin America, Africa and Southeast Asia. We reach our target markets through a combination of direct sales, strategic local distributors and OEM partners. Our efforts are focused on raising awareness of Chembio’s products and technology through global and regional marketing activities such as tradeshows and working with local key opinion leaders, local distributors, and strategic partners. We are also increasing our digital and social media activities to drive awareness of our products. 
+Competition 
+Many of our competitors are significantly larger and have greater financial, research, manufacturing, and marketing resources. Important competitive factors include product quality, analytical performance, ease of use, price, customer service and reputation. Industry competition is based on these and the following additional factors: 
+● 
+Patent protection 
+● 
+Scientific expertise 
+● 
+Ability to develop and market products and processes 
+● 
+Ability to obtain required regulatory approvals 
+● 
+Ability to manufacture cost-effective products that meet applicable regulatory requirements 
+● 
+Access to adequate capital 
+5 
+Table of Contents 
+● 
+Ability to attract and retain qualified personnel 
+We believe our scientific capabilities and proprietary know-how relating to our patented DPP ® technology and lateral flow technology are very strong, particularly for the development and manufacture of tests for the detection of antibodies to infectious diseases such as sexually transmitted diseases, fever and tropical diseases, and other diseases. 
+Our ability to develop and market other products is in large measure dependent on our having additional resources and/or collaborative relationships. Some of our product development efforts have been funded on a project or milestone basis. We believe that our proprietary know-how relating to our patented DPP ® technology has been instrumental in our obtaining the collaborations we have and that we continue to pursue. We believe that our patent protection enhances our ability to both develop more profitable, collaborative relationships and expand licensing revenue. However, there are a number of competitive technologies used and/or seeking to be used by others in point-of-care settings. 
+Although we have no specific knowledge of any other competitors’ products that could render our products obsolete, if we fail to maintain and enhance our competitive position or fail to introduce new products and product features, our customers may decide to use the products developed by our competitors, which could result in a loss of revenues and cash flow. 
+Research and Development 
+During 2017, 2016 and 2015, we spent $8.6 million, $8.4 million and $6.4 million, respectively, on research and development (including regulatory activities). These expenses were in part funded by R&D milestone and grant revenues of $4.0 million in 2017, $3.7 million in 2016 and $2.3 million in 2015. 
+Employees 
+At December 31, 2017, we employed approximately 165 people. 
+Governmental Regulation 
+Certain of our activities are subject to regulatory oversight by the Food & Drug Administration (FDA) under provisions of the Federal Food, Drug, and Cosmetic Act and regulations thereunder, including regulations governing the development, marketing, labeling, promotion, manufacturing, and export of diagnostic products. Our clinical laboratory is subject to oversight by Centers for Medicare and Medicaid Services (CMS) pursuant to CLIA (defined below), as well as agencies in various states. Failure to comply with applicable requirements can lead to sanctions, including withdrawal of products from the market, recalls, refusal to authorize government contracts, product seizures, civil money penalties, injunctions, and criminal prosecution. 
+FDA Approval/Clearance Requirements 
+Unless an exemption applies, each medical device that we market or wish to market in the U.S. must receive 510(k) clearance or Premarket Approval, or “PMA.” Medical devices that receive 510(k) clearance are “cleared” by the FDA to market, distribute, and sell in the United States. Medical devices that obtain a PMA by the FDA are “approved” to market, distribute, and sell in the United States. We cannot be sure that 510(k) clearance or PMA approval will ever be obtained for any products that have not already obtained 510(k) clearance or PMA approval. Descriptions of the PMA and 510(k) clearance processes are provided below. 
+The FDA decides whether a device line must undergo either the 510(k) clearance or PMA based on statutory criteria that utilize a risk-based classification system. PMA is the FDA process of scientific and regulatory review to evaluate the safety and effectiveness of Class III medical devices and, in many cases, Class II medical devices. Class III devices are those that support or sustain human life, are of substantial importance in preventing impairment of human health, or which present a potential, unreasonable risk of illness or injury. The FDA uses these criteria to decide whether a PMA or a 510(k) is appropriate, including the level of risk that the agency perceives is associated with the device and a determination by the agency of whether the product is a type of device that is similar to devices that are already legally marketed. Devices deemed to pose relatively less risk are placed in either Class I or II. In many cases, the FDA requires the manufacturer to submit a 510(k) requesting clearance (also referred to as a premarket notification), unless an exemption applies. The 510(k) must demonstrate that the manufacturer’s proposed device is “substantially equivalent” in intended use and in safety and effectiveness to a legally marketed predicate device. A “predicate device” is a pre-existing medical device to which equivalence can be drawn, that is either in Class I, Class II, or is a Class III device that was in commercial distribution before May 28, 1976, for which the FDA has not yet called for submission of a PMA application. 
+Device classification depends on the device’s intended use and its indications for use. In addition, classification is risk-based, that is, the risk the device poses to the patient and/or the user is a major factor in determining the class to which it is assigned. Class I includes devices with the lowest risk and Class III includes those with the greatest risk. 
+Class I devices are those for which safety and effectiveness can be assured by adherence to the FDA’s general regulatory controls for medical devices, or the General Controls, which include compliance with the applicable portions of the FDA’s quality system regulations, facility registration and product listing, reporting of adverse medical events, and appropriate, truthful and non-misleading labeling, advertising, and promotional materials. Some Class I devices also require premarket clearance by the FDA through the 510(k) process described below. 
+Class II devices are subject to the FDA’s General Controls, and any other special controls as deemed necessary by the FDA to ensure the safety and effectiveness of the device. Premarket review and clearance by the FDA for Class II devices is accomplished through the 510(k) process. Pursuant to the Medical Device User Fee and Modernization Act of 2002 (MDUFMA), as of October 2002, unless a specific exemption applies, 510(k) submissions are subject to user fees. Certain Class II devices are exempt from this premarket review process. 
+Class III includes devices with the greatest risk. Devices in this class must meet all of the requirements in Classes I and II. In addition, Class III devices cannot be marketed until they receive Premarket Approval. 
+The safety and effectiveness of Class III devices cannot be assured solely by the General Controls and the other requirements described above. These devices require formal clinical studies to demonstrate safety and effectiveness. Under MDUFMA, PMA applications (and supplemental premarket approval applications) are subject to significantly higher user fees than 510(k) applications, and they also require considerably more time and resources. 
+Rapid HIV tests intended for diagnostic use are regulated as Class III devices. Responsibility for assuring the safety and effectiveness of these tests lies within the Center for Biologics Evaluation and Research’s Office of Blood Research and Review, with oversight by the Blood Products Advisory Committee (BPAC). Approved Rapid HIV tests must meet the regulations in the 21 CFR 800 series subparts, under the Investigational Device exemption (IDE) and PMA pathways. 
+6 
+Table of Contents 
+Premarket Approval Pathway 
+We manufacture, market, and distribute three rapid HIV tests in the U.S: our HIV 1/2 STAT-PAK ® Assay, SURE CHECK ® HIV 1/2 Assay, and DPP ® HIV 1/2 Assay, all of which have received FDA PMA approval. A PMA application must be submitted if a device cannot be cleared through the 510(k) process. A PMA application must be supported by extensive data including, but not limited to, analytical, preclinical, clinical trials, manufacturing, statutory preapproval inspections, and labeling to demonstrate to the FDA’s satisfaction the safety and effectiveness of the device for its intended use. Before a PMA is submitted, a manufacturer must apply for an investigational device exemption, or “IDE.” If the device presents a “significant risk,” as defined by the FDA, to human health, the FDA requires the device sponsor to file an IDE application with the FDA and obtain IDE approval prior to initiation of enrollment of human subjects for clinical trials. The IDE provides the manufacturer with a legal pathway to perform clinical trials on human subjects where without the IDE, only approved medical devices may be used on human subjects. 
+The IDE application must be supported by appropriate data, such as analytical, animal and laboratory testing results, manufacturing information, and an Investigational Review Board (IRB) approved protocol showing that it is safe to test the device in humans and that the testing protocol is scientifically sound. If the clinical trial design is deemed to have “non-significant risk,” the clinical trial may be eligible for “abbreviated” IDE requirements; and, in some instances, IVD clinical trials may be exempt from the more burdensome IDE requirements if certain labeling requirements are met. 
+A clinical trial may be suspended by either the FDA or the IRB at any time for various reasons, including a belief that the risks to the study participants outweigh the benefits of participation in the study. Even if a study is completed, clinical testing results may not demonstrate the safety and efficacy of the device, or they may be equivocal or otherwise insufficient to obtain approval of the product being tested. After the clinical trials have been completed, if at all, and the clinical trial data and results are collected and organized, a manufacturer may complete a PMA application. 
+After a PMA application is sufficiently complete, the FDA will accept the application and begin an in-depth review of the submitted information. By statute, the FDA has 180 days to review the “accepted application,” although, generally, review of the application can take between one and three years, but it may take significantly longer. During this review period, the FDA may request additional information or clarification of information already provided. Also, during the review period, an advisory panel of experts from outside the FDA may be convened to review and evaluate the application and provide recommendations to the FDA as to the approvability of the device. The preapproval inspections conducted by the FDA include an evaluation of the manufacturing facility to ensure compliance with the Quality Systems Regulations (QSR), as well as inspections of the clinical trial sites by the Bioresearch Monitoring group to evaluate compliance with good clinical practice and human subject protections. New PMA applications or PMA supplements are required for modifications that affect the safety or effectiveness of the device, including, for example, certain types of modifications to the device’s indication for use, manufacturing process, labeling and design. Significant changes to an approved PMA require a 180-day supplement, whereas less substantive changes may utilize a 30-day notice, or a 135-day supplement. Premarket approval supplements often require submission of the same type of information as a premarket approval application, except that the supplement is limited to information needed to support any changes from the device covered by the original premarket approval application, and it may not require as extensive clinical data or the convening of an advisory panel. 
+Our HIV 1/2 STAT-PAK ® Assay PMA application number BP050009/0 and our SURE CHECK ® 1/2 HIV Assay PMA application number BP050010/0 were approved by the FDA on May 25, 2006. Our DPP ® HIV 1/2 Assay PMA application number BP120032/0 was approved by the FDA on December 19, 2012. 
+510(k) Clearance Pathway 
+We do not currently market, distribute, or sell a product that has market clearance by the FDA. However, we are currently developing products that either will or are likely to require an FDA 510(k) clearance, and we anticipate submitting a 510(k) for each such product to demonstrate that such proposed device is substantially equivalent to a respective previously cleared 510(k) device or a device that was in commercial distribution before May 28, 1976, for which the FDA has not yet called for the submission of 510(k). FDA's 510(k) clearance pathway usually takes from three to twelve months but could take longer. In some cases the FDA may require additional information, including clinical data, to make a determination regarding substantial equivalence. 
+If a device receives 510(k) clearance, any modification that could significantly affect its safety or effectiveness, or that would constitute a new or major change in its intended use, will require a new 510(k) clearance or, depending on the modification, a PMA. The FDA requires each device manufacturer to determine whether the proposed change requires submission of a new 510(k) or a PMA, but the FDA can review any such decision and can disagree with a manufacturer’s determination. If the FDA disagrees with a manufacturer’s determination, the FDA can require the manufacturer to cease marketing and/or recall the modified device until 510(k) clearance or PMA of the modified device is obtained. 
+If the FDA requires us to submit a new 510(k) or PMA for any modifications to a previously cleared product, or if we obtain 510(k) clearance for a device in the future, we may be required to submit a separate new 510(k) or PMA application for such modifications. 
+Clinical Laboratory Improvement Amendments of 1988 (CLIA) 
+A manufacturer of a test categorized as moderately complex may request that categorization of the test as waived through a CLIA Waiver by Application (CW) submission to the FDA. When a test is categorized as waived, it may be performed by laboratories with a Certificate of Waiver, such as a physician’s office outreach setting. In a CW submission, the manufacturer provides evidence to the FDA that a test meets the CLIA statutory criteria for waiver, 42 U.S.C. 263a(d)(3). Congress passed CLIA in 1988, which provided CMS authority over all laboratory testing, except research that is performed on humans in the United States. The Division of Laboratory Services, within the Survey and Certification Group, under the CMS, has the responsibility for implementing the CLIA program. 
+The CLIA program is designed to establish quality laboratory testing by ensuring the accuracy, reliability and timeliness of patient test results. Under CLIA, a laboratory is a facility that does laboratory testing on specimens derived from humans and used to provide information for the diagnosis, prevention or treatment of disease, or impairment of, or assessment of health. Under the CLIA program, unless waived, laboratories must be certified by the government, satisfy governmental quality and personnel standards, undergo proficiency testing, be subject to inspections and pay fees. We have received a CLIA waiver for both of our lateral flow rapid HIV tests that we market in the U.S. Specifically, the CLIA waiver was granted by the FDA for HIV 1/2 STAT-PAK ® on November 20, 2006 and for SURE CHECK ® HIV 1/2 on October 22, 2007. In 2008 the FDA revised its CLIA waiver requirements so that an additional prospective trial is required in order to demonstrate clinical utility by showing that the device is capable of identifying new infections when used by untrained users. Our DPP ® HIV 1/2 test received a CLIA waiver under these newer requirements on October 29, 2014. 
+7 
+Table of Contents 
+Pervasive and Continuing FDA Regulation 
+A host of regulatory requirements apply to our approved devices, including the quality system regulation (which requires manufacturers to follow elaborate design, testing, control, documentation and other quality assurance procedures), the Medical Reporting Regulations (MDR) regulations (which require that manufacturers report to the FDA specified types of adverse events involving their products), labeling regulations, and the FDA’s general prohibition against promoting products for unapproved or “off-label” uses. Class II devices also can have special controls such as performance standards, post-market surveillance, patient registries, and FDA guidelines that do not apply to Class I devices. 
+A noncomprehensive list of the regulatory requirements that apply to our approved products classified as medical devices or IVDs includes: 
+· 
+product listing and establishment registration, which helps facilitate FDA inspections and other regulatory action; 
+· 
+QSR, which requires manufacturers, including third-party manufacturers, to follow stringent design, testing, control, documentation and other quality assurance procedures during all aspects of the development and manufacturing process; 
+· 
+labeling regulations and FDA prohibitions against the promotion of products for uncleared, unapproved or off-label use or indication; 
+· 
+clearance of product modifications that could significantly affect safety or efficacy or that would constitute a major change in intended use of one of our cleared devices; 
+· 
+approval of product modifications that affect the safety or effectiveness of one of our cleared devices; 
+· 
+medical device reporting regulations, which require that manufacturers comply with FDA requirements to report if their device may have caused or contributed to a death or serious injury, or has malfunctioned in a way that would likely cause or contribute to a death or serious injury if the malfunction of the device or a similar device were to recur; 
+· 
+post-approval restrictions or conditions, including post-approval study commitments; 
+· 
+post-market surveillance regulations, which apply when necessary to protect the public health or to provide additional safety and effectiveness data for the device; 
+· 
+the FDA’s recall authority, whereby it can ask, or under certain conditions order, device manufacturers to recall from the market a product that is in violation of governing laws and regulations; 
+· 
+regulations pertaining to voluntary recalls; and, 
+· 
+notices of corrections or removals. 
+Our Medford, New York facility is currently registered as an establishment with the FDA. We and any third-party manufacturers are subject to announced and unannounced inspections by the FDA to determine our compliance with quality system regulation and other regulations. 
+21st Century Cures Act 
+The 21st Century Cures Act, enacted in December 2016, contains several sections specific to medical device innovations. The Company believes that implementation of the 21st Century Cures Act may have a positive impact on its businesses by facilitating innovation and/or reducing the regulatory burden imposed on medical device manufacturers. 
+Government Regulation of Medical Devices for Animal Subjects 
+We currently sell, market, or distribute two veterinary devices in the United States: DPP® VetTB Assay for Cervids and DPP® VetTB Assay for Elephants. Diagnostic tests for animal health infectious diseases, including our veterinary devices for the prevention and/or treatment of animal disease, are regulated in the U.S. by the Center for Veterinary Biologics within the United States Department of Agriculture (USDA) Animal and Plant Health Inspection Service (APHIS) under the Virus, Serum, and Toxin Act of 1913. As a requirement, our veterinary devices were approved by APHIS before they could be sold in the U.S. 
+The APHIS regulatory approval process involves the submission of product performance data and manufacturing documentation. Following regulatory approval to market a product, APHIS requires that each lot of product be submitted for review before release to customers. In addition, APHIS requires special approval to market products where test results are used in part for government-mandated disease management programs. 
+Environmental Laws 
+To date, we have not encountered any costs relating to compliance with any environmental laws. 
+Intellectual Property 
+Intellectual Property Strategy 
+Our intellectual property strategy is to: (1) build our own intellectual property portfolio around our DPP ® technology; (2) pursue licenses, trade secrets and know-how within the area of rapid point-of-care testing; and, (3) develop and acquire proprietary positions to certain reagents. 
+8 
+Table of Contents 
+DPP ® Intellectual Property 
+We have obtained patent coverage on our DPP ® technology, including numerous patents in the United States, China, Malaysia, Eurasia, Mexico, Singapore, Japan, Australia, Indonesia, Korea and the U.K. Additional patent applications on our DPP ® technology are pending in the U.S., as well as in many foreign countries such as Brazil, Canada, the European Union, India, Israel, and South Africa. 
+The DPP ® technology provides us with our own intellectual property. We believe it provides us with freedom to operate, which enables us to develop tests with better performance and unmatched capabilities compared with tests built on traditional lateral flow platforms. These advantages have allowed us to enter into multiple technology collaborations based upon the DPP ® technology, which we believe will provide new manufacturing and marketing opportunities. We have filed other patent applications that we believe will strengthen the DPP ® intellectual property and have also filed for patent protection for certain other point-of-care technologies or applications thereof. 
+Trademarks 
+We have filed and obtained trademarks for our products, including DPP ® , SURE CHECK ® , STAT-VIEW ® , and STAT-PAK ® , as well as for the SampleTainer ® , which is used with certain DPP ® products. Our trademarks have been obtained in the United States and certain other countries around the world. 
+Trade Secrets and Know-How 
+We have developed a substantial body of trade secrets and know-how relating to the development and manufacture of lateral flow and DPP ® -based diagnostic tests, including but not limited to the sourcing and optimization of materials for such tests, and methods to maximize sensitivity, speed-to-result, specificity, stability and reproducibility of our tests. We possess proprietary know-how to develop tests for multiple conditions using colored particles. Our formulations enable long shelf lives of our rapid HIV and other tests, providing us with an important competitive advantage. 
+Lateral Flow Technology and Reagent Licenses 
+As of February 3, 2015 the royalty expenses related to certain lateral flow technology expired. These now allow us to produce STAT-PAK ® , SURE CHECK ® , STAT-VIEW ® , DIPSTICK ® , and veterinary product lines free of those royalties. 
+Although we believe our DPP ® IP is outside of the scope of all lateral flow patents of which we are aware, we consult with patent counsel, and seek licenses and/or redesigns of products that we believe to be in our best interests. Because of the costs and other negative consequences of time-consuming patent litigation, we often attempt to obtain a license on reasonable terms. Nevertheless, there is no assurance that the Alere lateral flow patents we have licensed will not be challenged or that other patents containing claims relevant to our lateral flow or DPP ® products will not be granted to third parties and that licenses to such patents, will be available on reasonable terms, if any. 
+The peptides used in our rapid HIV tests were licensed to us by one or more third parties. We also have licensed the antigens used in other tests including our Syphilis, Tuberculosis, Leptospirosis, Leishmaniasis and Chagas tests, and we may enter other license agreements. In prior years, we concluded license agreements related to intellectual property rights owned by the United States associated with HIV-1, and, during the first quarter of 2008, we entered into a sub-license agreement for HIV-2 with Bio-Rad Laboratories N.A., the exclusive licensee of the Pasteur Institute's HIV-2 intellectual property estate. 
+Corporate Information 
+We are a Nevada corporation that was formed in December 1985. Since inception, we have been involved in developing, manufacturing, selling and distributing medical diagnostic tests, including rapid tests that detect a number of diseases and other conditions in humans and animals. 
+Stockholder Rights Agreement 
+On March 8, 2016, we entered into a Rights Agreement (the "Rights Agreement") between us and Action Stock Transfer Corp., as Rights Agent. Pursuant to the Rights Agreement, we declared a dividend distribution of one Preferred Share Purchase Right (a "Right") for each outstanding share of our common stock, par value $0.01 (the "Common Stock"), in the manner described below. The Board of Directors set the payment date for the distribution of the Rights as March 8, 2016, and the Rights were distributed to our shareholders of record on that date. The Rights Agreement also provides that Rights are issued with respect to any shares of our common stock that are newly issued after March 8, 2016, such as with respect to the Company's underwritten public offering in February 2018. The description and terms of the Rights are set forth in the Rights Agreement. 
+Rights Initially Not Exercisable 
+The Rights are not exercisable until a Distribution Date. Until a Right is exercised, the holder thereof, as such, has no rights as a shareholder of the Company, including, without limitation, the right to vote or to receive dividends. 
+Separation and Distribution of Rights 
+The Rights are to be evidenced by the certificates for shares of Common Stock registered in the names of the holders thereof, and not by separate rights certificates until the earlier to occur of (i) the close of business on the tenth business day following a public announcement that an Acquiring Person (as defined in the Rights Agreement) has acquired a Combined Ownership (as defined in the Rights Agreement) of 20% or more of the outstanding shares of the Common Stock (the "Shares Acquisition Date") or (ii) the later of (A) the close of business on the tenth business day (or such later date as may be determined by action of the Board of Directors prior to such time as any person or group of affiliated or associated persons becomes an Acquiring Person) after the date that a tender or exchange offer or intention to commence a tender or exchange offer by any person is first published, announced, sent or given within the meaning of Rule 14d-4(A) under the Securities Exchange Act of 1934, as amended, the consummation of which would result in any person having Combined Ownership of 20% or more of the outstanding shares of the Common Stock, or (B) if such a tender or exchange offer has been published, announced, sent or given before the date of the Rights Agreement, then the close of business on the tenth business day after the date the Rights Agreement was entered into (or such later date as may be determined by action of the Board of Directors prior to such time as any person becomes an Acquiring Person); (the earlier of such dates referred to in (i) and (ii), which date may include any such date that is after the date of the Rights Agreement but prior to the issuance of the Rights, being called the "Distribution Date"). 
+9 
+Table of Contents 
+Glossary 
+AIDS 
+Acquired Immunodeficiency Syndrome. AIDS is caused by the Human Immunodeficiency Virus, HIV. 
+ALGORITHM (parallel or serial) 
+For rapid HIV testing, this refers both to method or protocol (in developing countries to date) for using rapid tests from different manufacturers in combination to screen and confirm patients at the point-of-care, and may also refer to the specific tests that have been selected by an agency or ministry of health to be used in this way. A parallel algorithm uses two screening tests from different manufacturers and a tie-breaker test only if there is a discrepancy between the screening tests results. A serial algorithm only uses a second confirmatory test if there is a positive result from the screening test, meaning that the number of confirmatory tests used is equal to the positivity rate in the testing venue. A tie-breaker test resolves discrepancies between the screen and the confirmatory test. 
+ANTIBODY 
+A protein which is a natural part of the human immune system produced by specialized cells to neutralize antigens, including viruses and bacteria that invade the body. Each antibody-producing cell manufactures a unique antibody that is directed against, binds to and eliminates one, and only one, specific type of antigen. 
+ANTIGEN 
+Any substance which, upon entering the body, stimulates the immune system leading to the formation of antibodies. Among the more common antigens are bacteria, pollens, toxins, and viruses. 
+ANVISA 
+The National Health Surveillance Agency of Brazil. 
+ARVs 
+Anti-retroviral medications developed to fight AIDS. 
+CDC 
+United States Centers for Disease Control and Prevention. 
+CLIA waiver 
+Clinical Laboratory Improvement Act designation that allows simple tests to be performed in point-of-care settings such as doctor’s offices, walk-in clinics and emergency rooms. 
+DIAGNOSTIC 
+Pertaining to the determination of the nature or cause of a disease or condition. Also refers to reagents or procedures used in diagnosis to measure proteins in a clinical sample. 
+FIOCRUZ 
+The Oswaldo Cruz Foundation of Brazil. 
+FDA 
+United States Food and Drug Administration. 
+IgG 
+IgG or Immunoglobulin are proteins found in human blood. This protein is called an “antibody” and is an important part of the body’s defense against disease. When the body is attacked by harmful bacteria or viruses, antibodies help fight these invaders. 
+IgM 
+IgM or Immunoglobulin M are proteins found in human blood. This protein is called an "antibody" and is an important part of the body's defense against disease. When the body is attacked by harmful bacteria or viruses, antibodies help fight these invaders. 
+NGO 
+Non-Governmental Organization. 
+OTC 
+Over-the-Counter. 
+PEPFAR 
+The President’s Emergency Plan for AIDS Relief. 
+PMA 
+Pre-Marketing Approval –FDA approval classification for a medical device that is not substantially equivalent to a legally marketed device or is otherwise required by statute to have an approved application. Rapid HIV tests must have an approved PMA application before marketing of such a product can begin. 
+PROTOCOL 
+A procedure pursuant to which an immunodiagnostic test is performed on a particular specimen in order to obtain the desired reaction. 
+REAGENT 
+A chemical added to a sample under investigation in order to cause a chemical or biological reaction which will enable measurement or identification of a target substance. 
+RETROVIRAL 
+A type of virus which contains the enzyme Reverse Transcriptase and is capable of transforming infected cells to produce diseases in the host such as AIDS. 
+SENSITIVITY 
+Refers to the ability of an assay to detect and measure small quantities of a substance of interest. The greater the sensitivity, the smaller the quantity of the substance of interest the assay can detect. Also refers to the likelihood of detecting the antigen when present. 
+SPECIFICITY 
+The ability of an assay to distinguish between similar materials. The greater the specificity, the better an assay is at identifying a substance in the presence of substances of similar makeup. 
+USDA 
+U.S Department of Agriculture. 
+WHO 
+World Health Organization. 
+ITEM 1A. 
+RISK FACTORS 
+You should carefully consider each of the following risk factors and all of the other information provided in this Form 10-K in considering whether to make or continue to hold an investment in our Common Stock. The risks described below are those we currently believe may materially affect us. An investment in our Company involves a high degree of risk, and should be considered only by persons who can afford the loss of their entire investment. Although we believe that these risks are the most important for you to consider, you should read this section in conjunction with our financial statements, the notes to those financial statements and our management's discussion and analysis of financial condition and results of operations included in our periodic reports and incorporated into this Form 10-K by reference. 
+Risks Related to Our Business 
+There are competing products that could significantly reduce our U.S. sales of rapid HIV tests. 
+In 2006 Alere, Inc. acquired a division from Abbott Diagnostic located in Japan that manufactured and marketed a rapid HIV test product line called Determine®. The Determine® format was developed for the developing world and remote settings and, central to the needs of that market. The format is essentially a test strip that is integrated into a thin foil wrapper. When opened, the underside of the wrapper serves as the test surface for applying the blood sample and performing the test. This design reduces costs and shipping weights and volumes and provides an advantage for the developing world markets it serves. Some of the disadvantages of the platform are the amount of blood sample that is needed (50 microliters versus 2.5, 5 and 10 for our lateral flow barrel, lateral flow cassette, and DPP® products respectively), the open nature of the test surface, and the absence of a true control that differentiates biological from other kinds of samples. 
+The so-called "3rd generation" version of this product has been marketed for many years and is the leading rapid HIV test that is used in a large majority of the national algorithms of countries funded by PEPFAR and the Global Fund, as well as many other countries in the world. That product is not FDA-approved though it is CE marked. The newest Determine® HIV version, which was developed and manufactured by Alere's subsidiary in Israel, Orgenics, is the so-called "4th Generation" version Determine® test. According to its claims, this product detects HIV antibodies and P24 HIV antigens. Because the P24 antigen is known to occur in HIV-positive individuals' blood samples before antibodies do, the 4th generation Determine® test is designed to detect HIV infection earlier than tests that solely rely on antibody detection. Chembio's tests, as well as all of the other currently FDA-approved rapid HIV tests, only detect antibodies. There are however laboratory tests that are FDA-approved that are "4th generation" tests, but they are neither rapid nor point-of-care. 
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+Table of Contents 
+The initial "4th generation" Alere Determine® rapid test product that was also CE marked and that Alere launched internationally some years ago has not been successfully commercialized to the best of our knowledge and at least certain published studies were not favorable for this product. The 4th generation product that is now FDA-approved was apparently modified as compared to the initial international version, and it may perform more satisfactorily. Alere received FDA approval of this modified product in August 2013 and CLIA waiver for it in December 2014. Alere is also aggressively pursuing development of the market for this product. Moreover there is support by a number of key opinion leaders for the public health value of such 4th generation tests, and this product represents a significant competitive threat to Chembio as well as to each of the other rapid HIV test manufacturers (OraSure and Trinity primarily). 
+During 2011, Biolytical, Inc. of Vancouver, Canada received FDA approval and in 2012 received CLIA waiver of a flow-through rapid HIV test called "INSTI". The flow-through technology used in the INSTI test is older than lateral flow, and requires handling of multiple components (3 vials of solution) to perform the test in multiple steps. However, these steps can be accomplished in less than ten minutes, and the actual test results occur in only one minute after those steps are completed. Therefore sample-to-result time is shorter than any of the competitive products. The product also has good performance claims. There are settings where that reduced total test time, despite the multiple steps required, may be a distinct advantage, and we believe Biolytical has made some progress in penetrating certain public health markets. 
+Therefore, even though our lateral flow products currently enjoy a substantial market share in the U.S. rapid HIV test market, and we have an additional rapid HIV test, the DPP® HIV 1/2 Assay, there a number of risks and uncertainties concerning current and anticipated developments in this market. Although we have no specific knowledge of any other new product that is a significant competitive threat to our products, or that will render our products obsolete, if we fail to maintain and enhance our competitive position or fail to introduce new products and product features, our customers may decide to use products developed by our competitors, which could result in a loss of revenues and cash flow. 
+More generally, the point-of-care diagnostics industry is undergoing rapid technological changes, with frequent introductions of new technology-driven products and services. As new technologies become introduced into the point-of-care diagnostic testing market, we may be required to commit considerable additional efforts, time and resources to enhance our current product portfolio or develop new products. We may not have the available time and resources to accomplish this, and many of our competitors have substantially greater financial and other resources to invest in technological improvements. We may not be able to effectively implement new technology-driven products and services or be successful in marketing these products and services to our customers, which would materially harm our operating results. 
+Although we own our DPP® patent, lateral flow technology is still a competitive platform to DPP®, and lateral flow technology has a lower cost of manufacture than DPP® products. Although the DPP® platform has shown improved sensitivity as compared with conventional lateral flow platforms in a number of studies, several factors go into the development and performance attributes of products. Therefore the ability of our products to successfully compete will depend on several other factors, including but not limited to our having a patented rapid test platform technology that differentiates DPP® from lateral flow as well as from other diagnostic platform technologies. 
+We believe that our DPP® is outside of the scope of currently issued patents in the field of lateral flow technology, thereby offering the possibility of greater freedom to operate. However there can be no assurance that our patents or our products incorporating the patent claims will not be challenged at some time in the future. 
+Our Competitors May Develop and Commercialize More Effective or Successful Products, and Our Research, Development and Commercialization Efforts May Not Succeed. 
+We must regularly commit substantial resources to research and development and the commercialization of our new or enhanced products. The research and development process usually takes a long time from inception to commercial launch. During each stage of this process there is a substantial risk that we will not achieve our goals in a timely fashion, or at all, and we may have to abandon a new or enhanced product in which we have invested substantial time and money. We expect to continue to incur significant costs related to our research and development activities. 
+Our products require significant development and investment prior to commercialization, including testing to demonstrate the products performance capabilities, cost-effectiveness or other benefits. We must obtain regulatory approval before most products may be sold and additional development efforts on these products may be required before the products will be reviewed. However, regulatory authorities may not approve these products for commercial sale or may substantially delay or condition such approval. There may be little or no market for the product and entry into or development of new markets for our products may require an investment of substantial resources even if all applicable regulatory approvals are obtained. Furthermore, we may spend a significant amount of money on advertising or other activities and still fail to develop a market for the product. The success of our efforts may be affected by our ability to manufacture products in a cost-effective manner, whether we can obtain necessary intellectual property rights and protection and our ability to obtain reimbursement authorizations in the markets where the product will be sold. Therefore, if we fail to develop and gain commercial acceptance for our products, or if competitors develop more effective products or a greater number of successful new products, customers may decide not to purchase our products. 
+Our Products May Not be Able to Compete With New Diagnostic Products or Existing Products Developed by Well-Established Competitors, Which Would Negatively Affect Our Business. 
+The diagnostic industry is focused on the testing of biological specimens in a laboratory or at the point-of-care and is highly competitive and rapidly changing. Some of our principal competitors may have considerably greater financial, technical and marketing resources than we do. Several companies produce diagnostic tests that compete directly with our testing product line, including but not limited to, OraSure Technologies, Alere and Trinity Biotech. Furthermore these and/or other companies have or may have products incorporating molecular and/or other advanced technologies that over time could directly compete with our testing product line. As new products incorporating new technologies enter the market, our products may become obsolete or a competitor's products may be more effective or more effectively marketed and sold. 
+Our Business Prospects May be Negatively Affected if We Fail to Achieve Our Financial and Strategic Objectives. 
+There is no assurance that we will be successful in implementing our financial and strategic objectives, including our efforts to increase sales of our products. For example, the funds for research, clinical development and other projects have in the past come primarily from our business operations. If the sale of our products slows and we have less money available to fund research and development and clinical programs, we will have to cut certain programs. If adequate financial, personnel, equipment or other resources are not available, we may be required to delay or scale back our business. If our total revenue and gross profits do not correspondingly increase or if our technology, product, clinical and market development efforts are unsuccessful or delayed, our operations will be negatively affected. Furthermore, our failure to successfully introduce new or enhanced products and develop new markets could have a material adverse effect on our business and prospects. 
+Our Future Revenues and Operating Results May be Negatively Affected by the Ongoing Consolidation in the Healthcare Industry. 
+There has been a significant amount of consolidation in the healthcare industry. This consolidation has increased the competition to provide goods and services to customers. In addition, group purchasing organizations and integrated health delivery networks have served to concentrate purchasing decisions for some customers, which has also placed pricing pressure on medical device suppliers. Due to ongoing consolidation, there could be additional pressure on the prices of our products. 
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+Table of Contents 
+Our Continued Growth Depends on Retaining Our Current Key Employees and Attracting Additional Qualified Personnel, and We May Not Be Able to Do So. 
+Our success will depend to a large extent upon the skills and experience of our executive officers, management and sales, marketing, operations and scientific staff. We may not be able to attract or retain qualified employees in the future due to the intense competition for qualified personnel among medical products businesses, geographic considerations, our ability to offer competitive compensation, relocation packages, benefits, and/or other reasons. 
+If we are not able to attract and retain the necessary personnel to accomplish our business objectives, we may experience constraints that will adversely affect our ability to effectively manufacture, sell and market our products to meet the demands of our strategic partners in a timely fashion, or to support internal research and development programs. Although we believe we will be successful in attracting and retaining qualified personnel, competition for experienced scientists and other personnel from numerous companies and academic and other research institutions may limit our ability to do so on acceptable terms. 
+We have entered into employment contracts with our Chief Executive Officer, John Sperzel; our Chief Financial Officer, Neil Goldman; our President of the Americas, Sharon Klugewicz; and our Chief Scientist & Technology Officer , Javan Esfandiari. Due to the specific knowledge and experience of these executives regarding the industry, technology and market, the loss of the services of any one of them could have a material adverse effect on the Company. The contract with Mr. Sperzel expires March 2020. The contract with Mr. Esfandiari has a term of three years ending March 2019. The contract with Ms. Klugewicz expires May 2019. The contract with Mr. Goldman expires December 2018. The Company has obtained a key man insurance policy on Mr. Esfandiari. 
+We May Not Generate the Expected Benefits of Our Acquisitions or Investments and They Could Disrupt Our Ongoing Business, Distract Our Management, Increase Our Expenses and Negatively Affect Our Business. 
+As a way for us to grow our business, we may pursue strategic acquisitions or investments. These activities, and their impact on our business, are subject to many risks, including the following: (i) the benefits expected to be derived from an acquisition or investment may not materialize and could be affected by numerous factors, such as regulatory developments, insurance reimbursement, our inexperience with new businesses or markets, general economic conditions and increased competition; (ii) we may be unable to successfully integrate an acquired company’s personnel, assets, management, information technology systems, accounting policies and practices, products and/or technology into our business; (iii) we may not be able to accurately forecast the performance or ultimate impact of an acquired business; and (iv) an acquisition may result in the incurrence of unexpected expenses, stockholder lawsuits, the dilution of our earnings or our existing stockholders’ percentage ownership, or potential losses from undiscovered liabilities not covered by an indemnification from the seller(s) of the acquired business. 
+If these factors occur, we may be unable to achieve all or a significant part of the benefits expected from an acquisition or investment. This may adversely affect our financial condition, results of operations and ability to grow our business or otherwise achieve our financial and strategic objectives. 
+Third-Party Reimbursement Policies and Potential Cost Constraints Could Negatively Affect Our Business. 
+The list of our product end-users includes hospitals, physicians and other healthcare providers. If these end-users do not receive adequate reimbursement for the cost of our products from their patients’ healthcare insurers or payors, the use of our products could be negatively impacted. Furthermore, the net sales of our products could also be adversely affected by changes in reimbursement policies of government or private healthcare payors. 
+Hospitals, physicians and other healthcare providers who purchase diagnostic products in the United States generally rely on third-party payors, such as private health insurance plans, Medicare and Medicaid, to reimburse all or part of the cost of the product. Due to the overall escalating cost of medical products and services, there is increased pressures on the healthcare industry, both foreign and domestic, to reduce the cost of products and services. Given the efforts to control and reduce healthcare costs in the United States, available levels of reimbursement may change for our existing products or products under development. Third-party reimbursement and coverage may not be available or adequate in either the United States or international markets, current reimbursement amounts may be decreased in the future and future legislation, and regulation or reimbursement policies of third-party payors, may reduce the demand for our products or our ability to sell our products on a profitable basis. 
+To the Extent That We Are Unable to Collect Our Outstanding Accounts Receivable, Our Operating Results Could be Materially Harmed. 
+There may be circumstances and timing that require us to accept payment terms, including delayed payment terms, from distributors or customers, which, if not satisfied, could cause financial losses. 
+We generally accept payment terms which require us to ship product before the contract price has been paid fully, and there also are circumstances pursuant to which we may accept further delayed payment terms pursuant to which we may continue to deliver product. To the extent that these circumstances result in significant accounts receivables and those accounts receivables are not paid on a timely basis, or are not paid at all, especially if concentrated in one or two customers, we could suffer financial losses. 
+The Ongoing Changes in Healthcare Regulation Could Negatively Affect Our Revenues, Business and Financial Condition. 
+There have been several proposed changes in the United States at the federal and state level for comprehensive reforms regarding the payment for, the availability of and reimbursement for healthcare services. These proposals have ranged from fundamentally changing federal and state healthcare reimbursement programs, including providing comprehensive healthcare coverage to the public under government-funded programs, to minor modifications to existing programs. One example is the Patient Protection and Affordable Care Act, the Federal healthcare reform law enacted in 2010 (the “Affordable Care Act”). 
+Healthcare reform initiatives will continue to be proposed, and may reduce healthcare related funding in an effort. It is impossible to predict the ultimate content and timing of any healthcare reform legislation and its resulting impact on us. If significant reforms are made to the healthcare system in the United States, or in other jurisdictions, those reforms may increase our costs or otherwise negatively effect on our financial condition and results of operations. 
+We Believe Our Success Depends In Part on the Continued Funding of and Our Ability to Participate in Large Testing Programs in the U.S. and Worldwide. Funding of These and or Similar Programs May be Reduced, Discontinued and/or We May Not be Able to Participate for Other Reasons. 
+We believe it to be in our best interests to meaningfully participate in large testing programs. Moreover many of these programs are funded by governments and other donors, and there can be no assurance that funding will not be reduced or completely discontinued. Participation in these programs also requires alignment and engagement with the many other participants in these programs, including WHO, CDC, U.S. Agency for International Development, foreign governments and their agencies, non-governmental organizations, and HIV service organizations. If we are unsuccessful in our efforts to participate in these programs, our operating results could be materially harmed. 
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+Table of Contents 
+In December 2013 President Obama signed into law the PEPFAR Stewardship and Oversight Act, which is the most recent reauthorization of PEPFAR. However, unlike the 2008 PEPFAR authorization, which authorized approximately $45 billion in funding, the new law does not authorize a specific dollar amount for funding. 
+Developing Testing Guidelines Could Negatively Affect The Sales of Our Products. 
+Government agencies may issue diagnostic testing guidelines or recommendations, which can alter the usage of our HIV testing products. New laws or guidelines, or changes to existing laws or guidelines, and the manner in which these new or changed laws and guidelines are interpreted and applied, could impact the degree to which our testing products are used. These developments could affect the frequency of testing, the number of people tested and whether the testing products are used broadly for screening large populations or in a more limited capacity. These factors could in turn affect the level of sales of our products and our results of operations. 
+Legislative and Other Regulatory Changes Could Have An Effect On Our Business. 
+The current U.S. Presidential Administration has promised to repeal and replace the Affordable Care Act, expressed concerns with respect to existing trade agreements, and has indicated a desire to make other regulatory changes during his administration. Changes in regulatory or economic conditions or in the laws and policies governing foreign trade, taxes, manufacturing, and development in the United States could impact our business. Economic and regulatory changes could also affect foreign currency exchange rates which, in turn, could affect our reported financial results and our competitiveness on a worldwide basis. 
+Developments Related To The U.K.’s Referendum On Membership in The E.U. Could Adversely Affect Us. 
+On June 23, 2016, the United Kingdom (“U.K.”) voted in favor of leaving the European Union, or E.U. Following this “Brexit” referendum there has been increased political and economic uncertainty, particularly in the U.K. and E.U. and this uncertainty may last for the foreseeable future. Until the terms and timing of the U.K.’s exit from the E.U. are finalized, it will be difficult to predict the impact of Brexit. Our business in the U.K., the E.U. and world-wide could be negatively affected during this period of uncertainty, and perhaps longer. The decision of voters in the U.K. to exit the E.U. could cause volatility in global financial markets, such as global currency exchanges, resulting in a slow-down in economic activity in the U.K., Europe or globally, and result in significant regulatory changes and uncertainty. These events could make it more difficult or costly to sell our products, particularly in the U.K. and Europe, and negatively affect our revenues and results of operations. The Brexit referendum may also influence other countries and result in additional countries deciding to leave the E.U. This in turn could result in additional changes and uncertainty, any or all of which could negatively impact our business. 
+We Could be Exposed To Liability if We Experience Security Breaches or Other Disruptions and it Could Harm Our Reputation and Business . 
+We may be subject to cyber-attacks whereby computer hackers may attempt to access our computer systems or our third party IT service provider’s systems and, if successful, misappropriate personal or confidential information. In addition, a contractor or other third party with whom we do business may attempt to circumvent our security measures or obtain such information, and may purposefully or inadvertently cause a breach involving sensitive information. We will continue to evaluate and implement additional protective measures to reduce the risk and detect cyber incidents, but cyber-attacks are becoming more sophisticated and frequent and the techniques used in such attacks change rapidly. Even though we take cyber-security measures that are continuously reviewed and updated, our information technology networks and infrastructure may still be vulnerable due to sophisticated attacks by hackers or breaches. 
+Even the most well protected IT networks, systems, and facilities remain potentially vulnerable because the techniques used in security breaches are continually evolving and generally are not recognized until launched against a target and, in fact, may not be detected. Any such compromise of our or our third party’s IT service providers’ data security and access, public disclosure, or loss of personal or confidential business information, could result in legal claims proceedings, liability under laws to protect, privacy of personal information, and regulatory penalties, disrupt our operations, require significant management attention and resources to remedy any damages that result, damage our reputation and customers willingness to transact business with us, any of which could adversely affect our business. 
+Our Ability to Efficiently Operate Our Business is Reliant on Information Technology and Any Material Failure, Inadequacy, Interruption or Security Breach of that Technology Could Harm Our Business. 
+We rely heavily on complex information technology systems across our operations and on the internet, including for management of inventory, invoices, purchase orders, shipping, interactions with our third-party logistics provider, revenue and expense accounting, consumer call support, online business, and various other processes and transactions. Our ability to effectively manage our business, coordinate the production, distribution and sale of our products, respond to customer inquiries, and ensure the timely and accurate recording and disclosure of financial information depends significantly on the reliability and capacity of these systems and the internet. 
+If any of the foregoing systems fails to operate effectively, problems with transitioning to upgraded or replacement systems, or disruptions in the operation of the internet, could cause delays in product sales and reduced efficiency of our operations. Significant expenditures could be required to fix any such problem. 
+If There is an Increase in Demand for Our Products, it Could Require Us to Expend Considerable Resources or Harm Our Customer Relationships if We are Unable to Meet That Demand. 
+If there are significant or unexpected increases in the demand for our products, we may not be able to meet that demand without expending additional capital resources. This would increase our capital costs, which could negatively affect our earnings. In addition, new manufacturing equipment or facilities may require FDA approval before they can be used to manufacture our products. To the extent we are unable to obtain or are delayed in obtaining such approvals, our ability to meet the demand for our products could be adversely affected. Furthermore, our suppliers may be unable or unwilling to expend the necessary capital resources or otherwise expand their capacity, which could negatively affect our business. 
+Our business could be negatively affected if we or our suppliers are unable to develop necessary manufacturing capabilities in a timely manner. If we fail to increase production volumes in a cost effective manner or if we experience lower than anticipated yields or production problems as a result of changes that we or our suppliers make in our manufacturing processes to meet increased demand, we could experience shipment delays or interruptions and increased manufacturing costs, which could also have a material adverse effect on our revenues and profitability. 
+If there are unexpected increases in demand for our products, we may be required to obtain additional raw materials in order to manufacture products to meet the increase in demand. However, some raw materials require significant ordering lead time and some are currently obtained from a sole supplier or a limited group of suppliers. It is also possible that one or more of our suppliers may become unwilling or unable to deliver materials to us. Any shortfall in our supply of raw materials and components, or our inability to quickly and cost-effectively obtain alternative sources for this supply, could have a material adverse effect on our ability to meet increased demand for our products. This could negatively affect our total revenues or cost of sales and related profits. 
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+If we are unable to meet customer demand for our products, it could also harm our relationships with our customers and impair our reputation within the industry. This, in turn, could have a material adverse effect on our business. 
+Risks Related to Our Products 
+For Our Business to Succeed in the Future, Our Current and Future Products Must Receive Market Acceptance. 
+The market acceptance and the timing of such acceptance, of our new products or technologies is necessary for our future success. To achieve market acceptance, we and/or our distributors will likely be required to undertake substantial efforts and spend significant funds to inform every one of the existence and perceived benefits of our products. We also may require government funding for the purchase of our products may be needed to help create market acceptance and expand the use of our products. 
+It may be difficult evaluate the market reaction to our products and our marketing efforts for new products may not be successful. The government funding we receive may be limited for new products. As such, there can be no assurance that any products will obtain significant market acceptance and fill the market need that is perceived to exist on a timely basis, or at all. 
+We May Not Have Sufficient Resources to Effectively Introduce and Market Our Products, Which Could Materially Harm Our Operating Results. 
+Introducing and achieving market acceptance for our rapid HIV tests and other new products will require substantial marketing efforts and will require us and/or our contract partners, sales agents, and/or distributors to make significant expenditures of time and money. In some instances we will be significantly or totally reliant on the marketing efforts and expenditures of our contract partners, sales agents, and/or distributors. If they do not have or commit the expertise and resources to effectively market the products that we manufacture, our operating results will be materially harmed. 
+Other Providers of Diagnostic Tests and Sample Collection Products Will Likely Provide Us with Substantial Competition. 
+Our competitors make similar products to ours. A number of our competitors are making investments in technologies and products, and may have a competitive advantage because of their greater financial, technical, research and other resources. Some competitors offer broader product lines and may have greater name recognition than we have. We also face competition from certain of our distributors or former customers that have created or may decide to create, their own products to compete with ours. If our competitors’ products take market share from our products through more effective marketing or competitive pricing, our revenues, margins and operating results could be adversely affected. In addition, our revenues and operating results could be negatively impacted if some of our customers internally develop or acquire their own sample collection devices and use those devices in place of our products in order to reduce costs. 
+New Developments in Health Treatments and Non-Diagnostic Products May Reduce or Eliminate the Demand For Our Products. 
+The development and commercialization of products outside of the diagnostics industry could adversely affect sales of our products. For example, the development of a safe and effective vaccine to HIV or treatments for other diseases or conditions that our products are designed to detect, could reduce or eventually eliminate the demand for our HIV or other diagnostic products and result in a loss of revenues. 
+The Sales Cycles for Our Products Can Be Lengthy, Which Can Cause Variability and Unpredictability in Our Business. 
+Some of our products may require lengthy and unpredictable sales cycles, which makes it more difficult to accurately forecast revenues in a given period and may cause revenues and operating results to vary from period to period. Our products may involve sales to large public and private institutions which may require many levels of approval and may be dependent on economic or political conditions and the availability of grants or funding from government or public health agencies which can vary from period to period. There can be no assurance that purchases or funding from these agencies will occur or continue, especially if current negative economic conditions continue or intensify. As a result, we may expend considerable resources on unsuccessful sales efforts or we may not be able to complete transactions at all or on a schedule and in an amount consistent with our objectives. 
+Our Insurance May be Inadequate to Cover Our Potential Business Risks. 
+We believe that our present product liability and other insurance coverage is sufficient to cover our current estimated exposures, but we cannot be sure that we will not incur liabilities in excess of our policy limits. Although we believe that we will be able to continue to obtain adequate coverage in the future, there is no assurance that we will be able to do so. 
+Due to the Use of Our Products, We May Face Product Liability Claims for Injuries. 
+If any of our products, or any product which is made with the use or incorporation of any of our technologies, causes injury of any type or is found otherwise unsuitable during product testing, manufacturing, marketing, sale or usage, we may subject to liability. We may not be successful in defending any product liability lawsuits brought against us. Regardless of merit or eventual outcome, product liability claims could result in (i) decreased demand for our products; (ii) damage to our image or reputation; (iii) lost revenues; and (iv) incurrence of damages payable to plaintiffs 
+Legal Proceedings May Cause Us to Suffer Monetary Damages or Incur Substantial Costs. 
+In the future we may become involved in various legal proceedings arising out of our businesses. These may include negligence claims, commercial disputes or other lawsuits arising in the ordinary course of business. These lawsuits may result in damages, sometimes in substantial amounts, for commercial or personal injuries allegedly suffered. An adverse ruling or rulings in one or more such lawsuits could result in the termination or modification of a material contract or otherwise have a material adverse effect on our business. 
+Our Customers May Not Adopt Rapid Point-of-Care Diagnostic Testing. 
+Rapid point-of-care tests are beneficial because, among other things, they can be administered by healthcare providers in their own facilities or used by consumers at home without sending samples to central laboratories. But currently the majority of diagnostic tests used by physicians and other healthcare providers in the U.S. are provided by clinical reference laboratories and hospital-based laboratories. In some international markets, such as Europe, diagnostic testing is performed primarily by centralized laboratories. Future sales of our products will depend, in part, on our ability to expand market acceptance of rapid point-of-care testing and successfully compete against laboratory testing methods and products. However, we expect that clinical reference and other hospital-based laboratories will continue to compete vigorously against our rapid point-of-care products. Even if we can demonstrate that our products are more cost effective, save time, or have better performance or other benefits, physicians, other healthcare providers and consumers may resist changing to rapid point-of-care tests and instead may choose to obtain diagnostic results through laboratory tests. If we fail to achieve and expand market acceptance of our rapid point-of-care diagnostic tests with customers, it would have a negative effect on our future sales growth. 
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+If Our Products Do Not Perform Properly, It May Affect Our Revenues, Stock Price and Reputation. 
+Our products may not perform as expected. For example, a defect in one of our diagnostic products or a failure by a customer to follow proper testing procedures may cause the product to report inaccurate information. Identifying the root cause of a product performance or quality issue can be difficult and time consuming. 
+If our products do not to perform in accordance with the applicable label claims or otherwise in accordance with the expectations or needs of our customers, customers may switch to a competing product or otherwise stop using our products, and our revenues could be negatively affected. If this occurs, we may be required to implement holds or product recalls and incur warranty obligations. Furthermore, the poor performance by one or more of our products could have an adverse effect on our reputation, our continuing ability to sell products and the price of our Common Stock. 
+If We Expand Our International Presence, It May Increase Our Risks and Expose Our Business to Regulatory, Cultural or Other Challenges. 
+We will continue to try to increase revenue derived from international sales of our products. There are several of factors that could adversely affect the performance of our business and/or cause us to incur substantially increased costs because of our international presence and sales, including: (i) uncertainty in the application of foreign laws and the interpretation of contracts with foreign parties; (ii) cultural and political differences that favor local competitors or make it difficult to effectively market, sell and gain acceptance of our products; (iii) exchange rates, currency fluctuations, tariffs and other barriers, extended payment terms and dependence on international distributors or representatives; (iv) trade protection measures, trade sanctions and import/export licensing requirements; (v) our inability to obtain or maintain regulatory approvals or registrations for our products; (vi) Economic conditions, political instability, the absence of available funding sources, terrorism, civil unrest, war and natural disasters in foreign countries; (vii) Reduced protection for, or enforcement of, our patents and other intellectual property rights in foreign countries; (viii) our inability to identify international distributors and negotiate acceptable terms for distribution agreements; and (ix) restrictions on our ability to repatriate investments and earnings from foreign operations. 
+Economic, cultural and political conditions and foreign regulatory requirements may slow or prevent the manufacture of our products in countries other than the United States. Interruption of the supply of our products could reduce revenues or cause us to incur significant additional expenses in finding an alternative source of supply. Foreign currency fluctuations and economic conditions in foreign countries could also increase the costs of manufacturing our products in foreign countries. 
+Financial Results, Economic, and Financing Risks 
+The Success of Our Business Depends On, in Addition to the Market Success of Our Products, Our Ability to Raise Additional Capital Through the Sale of Debt or Equity or Through Borrowing, and We May Not be Able to Raise Capital or Borrow Funds on Attractive Terms and/or in Amounts Necessary to Continue Our Business, or At All. 
+We were profitable for five consecutive years through 2013. Nevertheless, prior to 2009 we sustained significant operating losses since 2004, and we incurred an operating loss each year for 2014 through 2017. We estimate that our resources are sufficient to fund our needs through the end of 2018 and beyond. We have already made, and may continue to make, significant financial commitments to invest in our sales and marketing organization, regulatory approvals, research and development including new technologies, and production capacity, including expanded facilities. 
+Our liquidity and cash requirements will depend on several factors. These factors include, among others, (1) the level of revenues; (2) the extent to which, if any, that revenue level improves operating cash flows; (3) our investments in research and development, facilities, marketing, regulatory approvals, and other investments we may determine to make; and (4) our investment in capital equipment and the extent to which it improves cash flow through operating efficiencies. There are no assurances that we will generate positive cash flow for 2018 or, in the alternative, be successful in raising sufficient capital to fund our needs after 2018. 
+Our U.S. market sales are difficult to predict in 2018 given (i) our early June 2014 termination of the agreement with a third party for exclusive distribution of our cassette product in the U.S; and (ii) the May 31, 2016 termination of the agreement with a third party for exclusive distribution of our barrel product in the U.S. As a result of these terminations, we expect to continue to experience higher average revenue per unit, and a lower volume of U.S. sales, of the cassette and barrel products. Higher revenue per unit is anticipated because we previously sold these products to the exclusive U.S. distributor at a significantly lower price than the price at which the distributor resold these products to customers (including re-sellers and distributors) in the United States. However at this point with respect to the barrel product, this can occur only after any inventory that the exclusive U.S. distributor has accumulated is consumed, which may take several months. In addition, in marketing these products directly, we are incurring substantial costs associated with developing our sales and marketing organization and channel distribution partners. 
+We believe that underlying demand for HIV rapid testing in the United States remains strong, and that the restoration of some of the funding cutbacks from sequestration and the implementation of the Affordable Care Act and of the United States Preventive Services Task Force recommendations will have a positive impact on the development of the market. On the other hand, it is possible that changes to healthcare law in 2017 and thereafter could change this and/or have a negative impact on the market for our products. Further, our products are well established and relied upon by a large installed base of customers over many years of use in the U.S. global market, and we believe this is a strong advantage. We also believe that our DPP® HIV 1/2 Assay, for which CLIA waiver was obtained in October 2014, for use with oral fluid or bloods samples will be able to serve new customers that were previously unavailable to us with our lateral flow blood tests. However, development of new customers with this product is costly and time-consuming. 
+If we are unable to maintain or increase our revenues from domestic and/or international customers, our operating results will be materially harmed. 
+Although We Were Profitable From 2009 Through 2013, We Incurred a Net Loss For Each Year From 2014 Through 2017 and Cannot be Certain that We Will be able to Sustain Profitability in the Future. 
+From the inception of Chembio Diagnostic Systems, Inc. in 1985 through the period ended December 31, 2008, we incurred net losses. We were then profitable each year from 2009 through 2013. In 2014, 2015, 2016 and 2017, we made substantial expenditures for sales and marketing, regulatory submissions, product development, production and warehouse capacity, and other purposes, and we incurred a net operating loss. Our ability to re-achieve profitability in the future will primarily depend on our ability to increase sales of our products based on having made the aforementioned expenditures to reduce production and other costs, and to successfully introduce new products and enhanced versions of our existing products into the marketplace. If we are unable to increase our revenues at a rate that is sufficient to achieve profitability, or adequately control and reduce our operating costs, our operating results would be materially harmed. 
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+We Base Our Estimates or Judgments Relating to Critical Accounting Policies on Assumptions That Can Change or Prove to be Incorrect. 
+Our financial statements have been prepared in accordance with accounting principles generally accepted in the United States and our discussion and analysis of financial condition and results of operations is based on such statements. The preparation of financial statements requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. We continuously evaluate significant estimates used in preparing our financial statements, including those related to (i) revenue recognition; (ii) stock-based compensation; (iii) allowance for uncollectible accounts receivable; (iv) customer sales returns and allowances; (v) contingencies; and (vi) income taxes. 
+Our estimates are based on historical experience and various other assumptions that we believe to be reasonable, as set forth in our discussion and analysis of financial condition and results of operations, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these and other estimates if our assumptions change or if actual circumstances differ from those in our assumptions. If our operating results fall below the expectations of securities analysts and investors, the price of our Common Stock may decline. 
+We May Fail to Meet Our Financial Projections and There May be Fluctuations in Our Financial Results. 
+From quarter to quarter and year to year, our operating results can fluctuate, which could cause our growth or financial performance to fail to meet the expectations of investors and securities analysts. Our financial projections are based on a number of assumptions, including the estimated demand for our products. However, sales to our distributors and other customers may not meet expectations because of lower than expected customer demand or other factors, including continued economic volatility and disruption, reduced governmental funding, and other circumstances described elsewhere in this Form 10-K. A variety of factors could also contribute to the variability of our financial results, including infrequent, unusual or unexpected changes in revenues or costs. 
+Different products provide dissimilar contributions to our gross product margin. Accordingly, our operating results could also fluctuate and be negatively affected by the mix of products sold and the relative prices and gross product margin contribution of those products. Failure to achieve operating results consistent with the expectations of investors and securities analysts could adversely affect our reputation and the price of our Common Stock. 
+Our Operating Results May be Negatively Affected by Changes in Foreign Currency Exchange Rates. 
+In the past our exposure to foreign currency exchange rate risk has not been material. Nevertheless, sales of our products are subject to currency risks, since changes in the values of foreign currencies relative to the value of the U.S. Dollar can render our products comparatively more expensive. The fluctuations in the exchange rate could negatively impact international sales of our products, as could changes in the general economic conditions. 
+The revenues and expenses of Chembio Diagnostics Malaysia, one of our subsidiaries, are recorded in Malaysian Ringgit. Revenues and expenses denominated in foreign currencies are translated into U.S. dollars for purposes of reporting our consolidated financial results. Our expectation is that the Chembio Diagnostics Malaysia business will continue to grow and, consequently, our exposure to foreign currency exchange rates may grow as well. 
+Chembio Diagnostics Malaysia’s revenues and expenses and the translation of Chembio Diagnostics Malaysia’s financial results into U.S. Dollars may be negatively affected by fluctuations in the exchange rate. Favorable movement in exchange rates have benefited us in prior periods. However, where there are unfavorable currency exchange rate fluctuations, our consolidated financial statements could be negatively affected. Furthermore, fluctuations in exchange rates could affect year-to-year comparability of operating results. In the past, we have not generally entered into hedging instruments to manage our currency exchange rate risk, but we may need to do so in the future. However, our attempts to hedge against these risks may not be successful. If we are unable to successfully hedge against unfavorable foreign currency exchange rate movements, our consolidated financial results may be adversely impacted. 
+Economic Volatility Around the World Could Adversely Affect Our Results. 
+Volatility in the economy may continue or exist in the future. This could negatively impact our financial performance or those of our customers and suppliers. These circumstances could inhibit our access to liquidity needed to conduct or expand our business. Many of our customers rely on public funding provided by federal, state and local governments, and this funding has been and may continue to be reduced or deferred as a result of economic conditions. These circumstances may adversely impact our customers and suppliers, which, in turn, could adversely affect their ability to purchase our products or supply us with necessary equipment, raw materials or components. Even with the improvement of economic conditions, it may take time for our customers and suppliers to establish new budgets and return to normal purchasing and shipping patterns. We cannot predict the reoccurrence of any economic slowdown or the strength or sustainability of an economic recovery. 
+The New U.S. Tax Cuts and Jobs Act of 2017 and Any Subsequent Tax Law Changes Could Adversely Affect Us. 
+On December 22, 2017, President Trump signed into law the “Tax Cuts and Jobs Act” (TCJA) that significantly reforms the Internal Revenue Code of 1986, as amended. The TCJA includes, among other matters, changes to U.S. federal tax rates, allows for the expensing of capital expenditures, imposes significant additional limitations on the deductibility of interest, and puts into effect the migration from a “worldwide” system of taxation to a territorial system. We do not expect tax reform to have a material impact to our projection of minimal cash taxes or to our net operating losses. Our net deferred tax assets and liabilities will be revalued at the newly enacted U.S. corporate rate of 21 percent, and the impact will be recognized in our tax expense in the year of enactment. We continue to evaluate the TCJA may have on our business. The impact of this tax reform on holders of our common stock is uncertain and could be adverse. In addition, subsequent unforeseen changes in U.S. or other countries’ tax laws could adversely affect us. We urge our stockholders to consult with their legal and tax advisors with respect to the TCJA and the potential tax consequences of investing in our common stock. 
+We May Require Additional Capital in the Future. 
+Our liquidity and ability to meet capital requirements will depend on numerous factors, including, but not limited to, the following: (i) the costs and timing of expansion of sales and marketing activities; (ii) the extent to which we gain or expand market acceptance for existing, new or enhanced products; (iii) the timing and success of the commercial launch of new products; (iv) the success of our research and product development efforts; (v) changes in existing and potential relationships with distributors and other business partners; (vi) the costs involved in obtaining and enforcing patents, proprietary rights and necessary licenses; and (vii) Competing technological and market developments. 
+If we require new financing, we may seek to raise funds by selling equity or other securities or through bank borrowings. There can be no assurance that financing through the sale of securities, bank borrowings or otherwise will be available to us on satisfactory terms, or at all. 
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+Our Business May be Negatively Affected by Terrorist Attacks or Natural Disasters. 
+Terrorist attacks or natural disasters could cause economic instability. These events could negatively affect economic conditions both within and outside the United States and harm demand for our products. The operations of our customers and suppliers could be negatively impacted and eliminate, reduce or delay our customers’ ability to purchase and use our products and our suppliers’ ability to provide raw materials and finished products. 
+Our facilities, including some pieces of manufacturing equipment and our computer systems, may be difficult to replace. Various types of disasters, including fires, earthquakes, floods and acts of terrorism, may affect our facilities and computer systems. In the event our existing facilities or computer systems are affected by man-made or natural disasters, we may have difficulty operating our business and may be unable to manufacture products for sale or meet customer demands or sales projections. If our manufacturing operations were curtailed or shut down entirely, it would seriously harm our business. 
+Risks Related to Intellectual Property 
+Our Success Depends on Our Ability to Protect Our Proprietary Technology. We Rely on Trade Secret Laws and Agreements With Our Key Employees and Other Third Parties to Protect Our Proprietary Rights, and We Cannot be Sure That These Laws or Agreements Adequately Protect Our Rights. 
+Our industry places considerable importance on obtaining patent, trademark and trade secret protection, as well as other intellectual property rights, for new technologies, products and processes. Our success depends, in part, on our ability to develop and maintain a strong intellectual property portfolio or obtain licenses to patents and technologies, both in the United States and in other countries. If we cannot continue to develop, obtain and protect intellectual property rights, our revenues and gross profits could be adversely affected. Moreover, our current and future licenses or other rights to patents and other technologies may not be adequate for the operation of our business. 
+As appropriate, we intend to file patent applications and obtain patent protection for our proprietary technology. These patent applications and patents will cover, as applicable, compositions of matter for our products, methods of making those products, methods of using those products and apparatuses relating to the use or manufacture of those products. However, there have been changes to the patent laws and proposed changes to the rules of the U.S. Patent and Trademark Office, which may impact our ability to protect our technology and enforce our intellectual property rights. For example, in 2011, the U.S. enacted sweeping changes to the U.S. patent system under the Leahy-Smith America Invents Act (the “AIA”), including changes that would transition the U.S. from a “first-to-invent” system to a “first-to-file” system and alter the processes for challenging issued patents. These changes could increase the uncertainties and costs surrounding the prosecution of our patent applications and the enforcement or defense of our issued patents. 
+We believe that factors such as the technological and creative skills of our personnel, strategic relationships, new product developments, frequent product enhancements and name recognition are essential to our success. All our management personnel are bound by non-disclosure agreements. If personnel leave our employment, in some cases we would be required to protect our intellectual property rights pursuant to common law theories which may be less protective than provisions of employment, non-competition or non-disclosure agreements. 
+We seek to protect our proprietary products under trade secret and copyright laws, enter into license agreements for various materials and methods employed in our products, and enter into strategic relationships for distribution of the products. These strategies afford only limited protection. We currently have some foreign patents issued, and we are seeking additional patent protection in several other foreign jurisdictions for our DPP® technology. We have licenses to reagents (antigens and peptides) used in several of our products and products under development. Despite our efforts to protect our proprietary assets, and respect the intellectual property rights of others, we participate in several markets where intellectual property rights protections are of little or no value. This can place our products and our company at a competitive disadvantage. 
+Moreover, issued patents remain in effect for a fixed period and after expiration will not provide protection of the inventions they cover. Once our patents expire, we may be faced with increased competition, which could reduce our revenues. We may also not be able to successfully protect our rights to unpatented trade secrets and know-how. 
+To facilitate development and commercialization of a proprietary technology base, we may need to obtain additional licenses to patents or other proprietary rights from other parties. Obtaining and maintaining these licenses, which may not be available, may require the payment of up-front fees and royalties. In addition, if we are unable to obtain these types of licenses, our product development and commercialization efforts may be delayed or precluded. 
+If We Become Involved in Intellectual Property Disputes, Such Disputes Could Increase Our Costs and Limit or Eliminate Our Ability to Sell Products or Use Certain Technologies. 
+We may be required to expend substantial resources in asserting or protecting our intellectual property rights, or in defending suits related to intellectual property rights. We may seek to enforce our patents or other intellectual property rights through litigation. Such litigation is prevalent and is expected to continue. In our business, there are a large number of patents and patent applications similar to our products, and additional patents may be issued to third parties relating to our product areas. We, our customers or our suppliers may be sued for infringement of patents or misappropriation of other intellectual property rights with respect to one or more of our products. We may also have disputes with parties that license patents to us if we believe the license is no longer needed for our products or the licensed patents are no longer valid or enforceable. 
+There are a large number of patents in our industry, and the claims of these patents appear to overlap in many cases. Therefore there is a significant amount of uncertainty regarding the extent of patent protection and infringement. Companies may have pending patent applications, which are typically confidential for the first eighteen months following filing that cover technologies we incorporate in our products. Accordingly, we may be subjected to substantial damages for past infringement or be required to modify our products or stop selling them if it is ultimately determined that our products infringe a third party’s proprietary rights. In addition, governmental agencies could commence investigations or criminal proceedings against our employees or us relating to claims of misuse or misappropriation of another party’s proprietary rights. 
+If we are involved in litigation or other legal proceedings with respect to patents or other intellectual property and proprietary technology, it could adversely affect our revenues, results of operations, market share and business because (i) it could consume a substantial portion of managerial and financial resources; (ii) its outcome would be uncertain and a court may find that our patents are invalid or unenforceable in response to claims by another party or that the third-party patent claims are valid and infringed by our products; (iii) the pendency of any litigation may in and of itself cause our distributors and customers to reduce or terminate purchases of our products; (iv) a court could award a preliminary and/or permanent injunction, which would prevent us from selling our current or future products; and (v) an adverse outcome could subject us to the loss of the protection of our patents or to liability in the form of past royalty payments, penalties, reimbursement of litigation costs and legal fees, special and punitive damages, or future royalty payments, any of which could significantly affect our future earnings. 
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+Under certain contracts with third parties, we may indemnify the other party if our products or activities have actually or allegedly infringed upon, misappropriated or misused another party’s proprietary rights. Furthermore, our products may contain technology provided to us by third parties, and we may be unable to determine in advance whether such technology infringes the intellectual property rights of a third party. These other parties may also not be required or financially able to indemnify us in the event that an infringement or misappropriation claim is asserted against us. 
+There may also be other types of disputes that we become involved in regarding intellectual property rights, including state, federal or foreign court litigation, and patent interference, patent reissue, patent reexamination, or trademark opposition proceedings in the United States Patent and Trademark Office. Opposition or revocation proceedings could be instituted in a foreign patent office as well. These proceedings permit certain persons to challenge the validity of a patent on the grounds that it was known from the prior art. The filing of such proceedings, or the issuance of an adverse decision in such proceedings, could result in the loss of valuable patent rights that could have a material adverse effect on our business, financial condition, results of operations and growth prospects. 
+Risks Related to Our Third Party Collaborators 
+Our Use of Third-Party Suppliers, Some of Which May Constitute Our Sole Supply Source, for Certain Important Product Components Presents a Risk That Could Have Negative Consequences for Our Business. 
+A number of our components and critical raw materials are provided by third-party suppliers, some of which may be sole-source suppliers, which impacts our ability to manufacture or sell certain products if our suppliers cannot or will not deliver those materials in a timely fashion, or at all, due to an interruption in their supply, quality or technical issues, or any other reason. If this occurs, we could incur substantial expense and time to be able to reestablish the appropriate quality, cost, regulatory and market-acceptance circumstances needed for commercial success. Even with the needed expense and time, we may not be able to reestablish any or all of these factors. The absence of any one or more of these factors could prevent us from being able to commercially produce and market the affected product or products. 
+If Needed, We May Work with Strategic Collaborators to Assist in Developing and Commercializing Our Products. 
+Some business opportunities that require a technology controlled by a third party, a significant level of investment for development and commercialization or a distribution network beyond our existing sales force may necessitate involving one or more strategic collaborators. As part of our strategy for development and commercialization of our products, we may enter into arrangements with distributors or other third-parties. Relying on such collaborative relationships could be risky to our business for a number of reasons, including: (i) we may be required to transfer material rights to such strategic collaborators, licensees and others; (ii) our collaborators may not obtain regulatory approvals necessary to continue the collaborations in a timely manner; (iii) our collaborators may decide to terminate our collaborative arrangement or become insolvent; (iv) our collaborators may develop technologies or components competitive with our products; (v) disagreements with collaborators could result in the termination of the relationship or litigation; and (vi) we may not be able to agree to future collaborative arrangements, or renewals of existing collaborative agreements, on acceptable terms or at all. 
+We expect our collaborators will have an economic motivation to succeed in performing their contractual responsibilities under our agreements, there is no assurance that they will do so. Due to our reliance on strategic agreements, it can make it difficult to accurately forecast our future revenues and operating results. 
+If We Fail to Maintain Existing Distribution Channels, or Develop New Distribution Channels, It May Result in Lower Revenues. 
+We collaborate with laboratories, diagnostic companies and distributors in order to sell our products. The sale of our products depends in large part on our ability to sell products to these customers and on the marketing and distribution abilities of the companies with which we collaborate and work with. 
+By relying on distributors or third-parties to market and sell our products could negatively impact our business for various reasons, including: (i) we may not be able to find suitable distributors for our products on satisfactory terms, or at all; (ii) agreements with distributors may prematurely terminate or may result in litigation between the parties; (iii) our distributors or other customers may not fulfill their contractual obligations and distribute our products in the manner or at the levels we expect; (iv) our distributors may prioritize their own private label products that compete with our products; (v) Our existing distributor relationships or contracts may preclude or limit us from entering into arrangements with other distributors; and (vi) we may not be able to negotiate new or renew existing distribution agreements on acceptable terms, or at all. 
+We will try to maintain and expand our business with distributors and customers and make every effort to require that they fulfill their contractual obligations, but there can be no assurance that such companies will do so or that new distribution channels will be available on satisfactory terms. If we are unable to do so, our business will be negatively impacted. 
+Risks Related to Regulations 
+Because We May Not Be Able to Obtain or Maintain the Necessary Regulatory Approvals for Some of Our Products, We May Not Generate Revenues in the Amounts We Expect, or in the Amounts Necessary to Continue Our Business. Our Existing Products as well as Our Manufacturing Facility Must Meet Quality Standards and are Subject to Inspection by a Number of Domestic Regulatory and Other Governmental and Non-Governmental Agencies. 
+All of our proposed and existing products are subject to regulation in the U.S. by the U.S. Food and Drug Administration, the U.S. Department of Agriculture and/or other domestic and international governmental, public health agencies, regulatory bodies or non-governmental organizations. In particular, we are subject to strict governmental controls on the development, manufacture, labeling, distribution and marketing of our products. The process of obtaining required approvals or clearances varies according to the nature of, and uses for, a specific product. These processes can involve lengthy and detailed laboratory testing, human or animal clinical trials, sampling activities, and other costly, time-consuming procedures. The submission of an application to a regulatory authority does not guarantee that the authority will grant an approval or clearance for that product. Each authority may impose its own requirements and can delay or refuse to grant approval or clearance, even though a product has been approved in another country. 
+The time taken to obtain approval or clearance varies depending on the nature of the application and may result in the passage of a significant period of time from the date of submission of the application. Delays in the approval or clearance processes increase the risk that we will not succeed in introducing or selling the subject products, and we may determine to devote our resources to different products. 
+Changes in government regulations could increase our costs and could require us to undergo additional trials or procedures, or could make it impractical or impossible for us to market our products for certain uses, in certain markets, or at all. 
+18 
+Table of Contents 
+Changes in government regulations may adversely affect our financial condition and results of operations because we may have to incur additional expenses if we are required to change or implement new testing, manufacturing and control procedures. If we are required to devote resources to develop such new procedures, we may not have sufficient resources to devote to research and development, marketing, or other activities that are critical to our business. 
+We can manufacture and sell our products only if we comply with regulations and quality standards established by government agencies such as the FDA and the USDA as well as by non-governmental organizations such as the ISO and WHO. We have implemented a quality control system that is intended to comply with applicable regulations. Although FDA approval is not required for the export of our products, there are export regulations promulgated by the FDA that specifically relate to the export of our products that require compliance with FDA quality system regulation ("QSRs") and that also require meeting certain documentary requirements regarding the approval of the product in export markets. 
+If We Do Not Comply With FDA or Other Regulatory Requirements, We May Be Required to Suspend Production or Sale of Our Products or Institute a Recall Which Could Result in Higher Costs and a Loss of Revenues. 
+FDA Regulations and regulations by other federal, state and foreign regulatory agencies has an effect on many aspects of our operations, and the operations of our suppliers and distributors, including packaging, labeling, manufacturing, adverse event reporting, recalls, distribution, storage, advertising, promotion and record keeping. We are subject to routine inspection by the FDA and other agencies to determine compliance with QSRs and FDA regulatory requirements in the United States and other applicable regulations worldwide, including but not limited to ISO standards. We believe that our facilities and procedures are in material compliance with the FDA requirements and ISO standards, but the regulations may be unclear and are subject to change, and we cannot be sure that the FDA or other regulators will agree with our compliance with these requirements. The FDA and foreign regulatory agencies may require post-marketing testing and surveillance to monitor the performance of approved or cleared products or impose conditions on any product clearances or approvals that could restrict the distribution or commercial applications of those products. Regulatory agencies may impose restrictions on our or our distributors’ advertising and promotional activities or preclude these activities altogether if a noncompliance is believed to exist. In addition, the subsequent discovery of previously unknown problems with a product may result in restrictions on the product or additional regulatory actions, including withdrawal of the product from the market. 
+Our inability to comply with the applicable requirements of the FDA can result in, among other things, 483 notices, warning letters, administrative or judicially imposed sanctions such as injunctions, recall or seizure of products, civil penalties, withdrawal of product registrations, total or partial suspension of production, refusal to grant premarket clearance or PMA approval for devices, marketing clearances or approvals, or criminal prosecution. The ability of our suppliers to supply critical components or materials and of our distributors to sell our products could also be adversely affected if their operations are determined to be out of compliance. Such actions by the FDA and other regulatory bodies could adversely affect our revenues, costs and results of operations. 
+We must frequently make judgment decisions with respect to compliance with applicable laws and regulations. If regulators subsequently disagree with how we have sought to comply with these regulations, we could be subjected to substantial civil and criminal penalties, as well as product recall, seizure or injunction with respect to the sale of our products. Our reputation could be substantially impaired if we are assessed any civil and criminal penalties and limit our ability to manufacture and market our products which could have a material adverse effect on our business. 
+Demand For Our Products May be Affected by FDA Regulation of Laboratory-Developed Tests and Genetic Testing. 
+Regulatory responsibility over instruments, test kits, reagents and other devices used to perform diagnostic testing by clinical laboratories is covered by the FDA. The FDA has previously taken the position that it has regulatory authority over laboratory-developed tests, or LDTs, but has exercised enforcement discretion by not regulating most LDTs performed by high complexity CLIA-certified laboratories. LDTs are tests designed, developed, and performed in-house by a laboratory. These laboratories are subject to CLIA regulation but such laboratories have previously not been subject to regulation by FDA under the agency’s medical device requirements. 
+However, the FDA has announced that it would begin regulating LDTs, and in October 2014 the FDA issued proposed guidance on the regulation of LDTs for public comment. But, on November 18, 2016, the FDA announced that it would not finalize the proposed guidance prior to the end of the Obama administration. On January 13, 2017, the FDA released a discussion paper synthesizing public comments on the 2014 draft guidance documents and outlining a possible approach to regulation of LDTs. The discussion paper has no legal status and does not represent a final version of the LDT draft guidance documents. We cannot predict what policies the Trump administration will adopt with respect to LDTs. If the FDA increases regulation of LDTs, it could make it more difficult for laboratories and other customers to continue offering LDTs that involve genetic or molecular testing. This, in turn, could reduce demand for our products and adversely impact our revenues. 
+In Addition to FDA Requirements, We Are Subject to Several Government Regulations, the Compliance With Which Could Increase Our Costs and Affect Our Operations. 
+In addition to the FDA regulations previously described, laws and regulations in some states may restrict our ability to sell products in those states. 
+We must comply with numerous laws related to safe working conditions, environmental protection, disposal of hazardous substances, fire hazard control, manufacturing practices and labor or employment practices. Compliance with these laws or any new or changed laws regulating our business could result in substantial costs. Due to the number of laws and regulations governing our industry, and the actions of a number of government agencies that could affect our operations, it is impossible to reliably predict the full nature and impact of these laws and regulations. To the extent the costs and procedures associated with complying with these laws and requirements are substantial or it is determined that we do not comply, our business and results of operations could be adversely affected. 
+We May Incur Additional Costs If We Do Not Comply With Privacy, Security and Breach Notification Regulations. 
+We believe we are not a covered entity nor a business associate of a covered entity and the Company is not responsible for complying with the Health Insurance Portability and Accountability Act of 1996, as amended (“HIPAA”). Even though the Company is likely not a covered entity under HIPAA, the Company does have in place administrative, technical and physical safeguards to protect the privacy and security of consumers’ personal information.] The Company is required to comply with varying state privacy, security and breach reporting laws. If we fail to comply with existing or new laws and regulations related to properly transferring data containing consumers’ personal information, we could be subject to monetary fines, civil penalties or criminal sanctions. Also, there are other federal and state laws that protect the privacy and security of consumers’ personal information, and we may be subject to enforcement by various governmental authorities and courts resulting in complex compliance issues. We could incur damages under state laws pursuant to an action brought by a private party for the wrongful use or disclosure of consumers’ personal information. 
+19 
+Table of Contents 
+If We Are Not Able to Manufacture Products in Accordance With Applicable Requirements, It Could Adversely Affect Our Business. 
+Our products must meet detailed specifications, performance standards and quality requirements. As a result, our products and the materials used in their manufacture or assembly undergo regular inspections and quality testing. Factors such as defective materials or processes, mechanical failures, human errors, environmental conditions, changes in materials or production methods, and other events or conditions could cause our products or the materials used to produce or assemble our products to fail inspections and quality testing or otherwise not perform in accordance with our label claims or the expectations of our customers. 
+If we are not able to meet the applicable specifications, performance standards, quality requirements or customer expectations could adversely affect our ability to manufacture and sell our products or comply with regulatory requirements. These events could, in turn, adversely affect our revenues and results of operations. 
+Healthcare Fraud and Abuse Laws Could Adversely Affect Our Business and Results of Operations. 
+There are various federal and state laws targeting fraud and abuse in the healthcare industry that the Company is subject to, including anti-kickback laws, laws constraining the sales, false claims laws, marketing and promotion of medical devices by limiting the kinds of financial arrangements that manufacturers of these products may enter into with physicians, hospitals, laboratories and other potential purchasers of medical devices. There are other laws the Company is subject to that require the Company to report certain transactions between it and healthcare professionals. Violations of these laws are punishable by criminal or civil sanctions, including substantial fines, imprisonment and exclusion from participation in government healthcare programs. Many of the existing requirements are new and have not been definitively interpreted by state authorities or courts, and available guidance is limited. We could face enforcement action and fines and other penalties, and could receive adverse publicity, unless and until we are in full compliance with these laws, all of which could materially harm the Company. Furthermore, changes in or evolving interpretations of these laws, regulations, or administrative or judicial interpretations, may require us to change our business practices or subject our business practices to legal challenges, which could have a material adverse effect on our business, financial condition and results of operations. 
+Our Compliance With Regulations Governing Public Companies is Complex and Expensive. 
+Public companies are subject to various laws and regulations, which have increased the scope, complexity and cost of corporate governance, reporting and disclosure practices. For example, we are subject to the Sarbanes-Oxley Act of 2002, The Dodd-Frank Wall Street Reform and Consumer Protection Act, the requirements of The NASDAQ Global Market, and the SEC’s requirements for public companies to provide financial statements in interactive data format using the eXtensible Business Reporting Language (“XBRL”). The implementation of certain aspects of these laws and regulations has required and will continue to require substantial management time and oversight and may require us to incur significant additional accounting and legal costs. We continually review changes with respect to new and proposed rules and cannot predict or estimate the amount of additional costs, and the timing of such costs, we may incur. There are several interpretations of these laws and regulations, in many cases due to their lack of specificity, and as a result, their application in practice may change as new guidance is provided by regulatory and governing bodies. This may result in continuing uncertainty regarding compliance matters and higher costs. We are committed to maintaining high standards of corporate governance and public disclosure, but if we fail to comply with any of these requirements, legal proceedings may be initiated against us, which may adversely affect our business. 
+Although We Have an Ethics and Anti-Corruption Policy in Place, and Have No Knowledge or Reason to Know of Any Practices by Our Employees, Agents or Distributors That Could be Construed as in Violation of Such Policies, Our Business Includes Sales of Products to Countries Where There is or may be Widespread Corruption. 
+We have a policy in place prohibiting our employees, distributors and agents from engaging in corrupt business practices, including activities prohibited by the United States Foreign Corrupt Practices Act (the "FCPA"). Nevertheless, because we work through independent sales agents and distributors outside the United States, we do not have control over the day-to-day activities of such independent agents and distributors. In addition, in the donor-funded markets in Africa where we sell our products, there is significant oversight from PEPFAR, the Global Fund, and advisory committees comprised of technical experts concerning the development and establishment of national testing protocols. This is a process that includes an overall assessment of a product which includes extensive product performance evaluations including five active collaborations and manufacturer's quality systems, as well as price and delivery. In Brazil, where we have had a total of six product collaborations with FIOCRUZ, the programs through which our products may be deployed are all funded by the Brazilian Ministry of Health. Although FIOCRUZ is affiliated with the Brazilian Ministry of Health, and is its sole customer, FIOCRUZ is not the exclusive supplier for the Ministry of Health. However, because each of our previous collaborations with FIOCRUZ incorporates a technology transfer aspect, we believe we have a competitive advantage versus other suppliers to the Brazilian Ministry of Health, assuming other aspects of our product offering through FIOCRUZ are otherwise competitive in comparison. We have no knowledge or reason to know of any activities by our employees, distributors or sales agents of any actions which could be in violation of the FCPA, although there can be no assurance of this. 
+Risks Related to Our Common Stock 
+Our Common Stock continues to be illiquid, so investors may not be able to sell as much stock as they want at prevailing market prices. 
+The average daily trading volume of our Common Stock on the NASDAQ market was approximately 16,368 shares per day over the three months ended December 31, 2017 as compared with approximately 19,300 shares per day over the three months ended December 31, 2016. The liquidity of our stock depends on several factors, including but not limited to the financial results of the Company and overall market conditions, so it is not possible to predict whether this level of liquidity will continue, be sustained, or decrease. 
+Decreased trading volume in our stock would make it more difficult for investors to sell their shares in the public market at any given time at prevailing prices. Our management and larger stockholders exercise significant control over the Company. 
+The Price of Our Common Stock Could Continue to be Volatile. 
+The price of our Common Stock has been volatile and may be volatile in the future. The following factors, among others, could have a significant impact on the market for our Common Stock: (i) the performance of our business; (ii) clinical results with respect to our products or those of our competitors; (iii) the gain or loss of significant contracts and availability of funding for the purchase of our products; (iv) actions undertaken by the Congress or the Presidential Administration; (v) changes in our relations with our key customers, distributors or suppliers; (vi) developments in patent or other proprietary rights; (vii) litigation or threatened litigation; (viii) general market and economic conditions; (ix) the relatively low trading volume for our Common Stock; (x) changes in competition; (xi) Complaints or concerns about the performance or safety of our products and publicity about those issues, including publicity expressed through social media or otherwise over the internet; (xii) failure to achieve, or changes in, financial estimates by securities analysts and comments or opinions about us by securities analysts or major stockholders; (xiii) announcement of regulatory or enforcement actions by the FDA or other agencies against us, our products or our customers; (xiv) changes in our operating results; and (xv) terrorist attacks, civil unrest, war and national disasters. 
+20 
+Overall, the stock market has experienced price and volume fluctuations that have affected the market price of our Common Stock, as well as the stock of many other similar companies. Such price fluctuations are generally unrelated to the operating performance of the specific companies whose stock is affected. 
+After the volatility in the market price of a company’s stock, class action litigation has occurred against the issuing company. If we were subject to this type of litigation in the future, we could incur substantial costs and the attention and resources of our management could be diverted, each of which could have a material adverse effect on our revenue and earnings. Any adverse determination in this type of litigation could also subject us to significant liabilities. 
+Sales of Our Common Stock by Existing Stockholders, Executive Officers or Directors Could Depress the Market Price of Our Common Stock. 
+If our existing stockholders, officers or directors sell our Common Stock in the public market, or the perception that such sales may occur, it could negatively affect the price of our Common Stock. We are unable to estimate the number of shares of our Common Stock that may actually be resold in the public market since this will depend on the market price for our Common Stock, the individual circumstances of the sellers and other factors. 
+Institutional stockholders own significant amounts of our Common Stock. If one or more of these stockholders sell large portions of their holdings in a relatively short time, the prevailing price of our Common Stock could be negatively affected. In addition, it is possible that one or more of our executive officers or non-employee members of our Board of Directors could sell shares of our Common Stock during an open trading window. These transactions and the perceived reasons for these transactions could have a negative effect on the prevailing market price of our Common Stock. 
+We Do Not Intend to Pay Cash Dividends on Our Common Stock, Therefore an Investor in Our Common Stock Will Benefit Only if the Value of Our Common Stock Increases. 
+We do not expect to pay any cash dividends on our Common Stock and currently intend to retain our earnings, if any, to finance the expansion of our business. Therefore, the success of an investment in our Common Stock will depend entirely upon any future increase in value of our Common Stock. There is no guarantee that our Common Stock will gain value or even maintain the price at which investors purchased their shares. 
+If We and/or Our Independent Registered Public Accounting Firm Conclude That Our Internal Control Over Financial Reporting is Not Effective, Investor Confidence and the Value of Our Common Stock May be Adversely Impacted. 
+The SEC has adopted rules requiring us, as a public company, to include a report in our Annual Reports on Form 10-K that contains an assessment by management of the effectiveness of our internal control over financial reporting. In addition, our independent registered public accounting firm must report on the effectiveness of these internal controls. 
+We believe our internal controls will continue to evolve as our business develops. We continue to review our internal control over financial reporting in an effort to ensure compliance with SEC rules and regulations, any control system, regardless of how well designed and operated, can provide only reasonable assurance that its objectives will be met. In addition, the overall quality of our internal controls may be affected by the internal control over financial reporting implemented by any business we acquire and our ability to assess and successfully integrate the internal controls of any such business. 
+If our independent registered public accounting firm is not satisfied with our internal control over financial reporting or the level at which our controls are documented, designed, implemented, or tested, or if the independent registered public accounting firm interprets the requirements, rules or regulations differently than we do, then it may issue a report noting such dissatisfaction. We also could conclude that our internal control over financial reporting is not effective. These events could result in an adverse reaction in the financial marketplace, which ultimately could negatively impact the market price of our Common Stock. 
+Any Future Issuances of Shares of Our Common Stock by Us Could Harm the Price of Our Common Stock and Our Ability to Raise Funds in New Equity Offerings. 
+Any future sales of a substantial number of our shares of Common Stock or other equity-related securities, or the perception that such sales may occur, could adversely affect the price of our Common Stock, and could impair our ability to raise capital through future offerings of equity or equity-related securities. 
+Table of Contents 
+Our Stockholder Rights Agreement Could Make a Third-Party Acquisition of Us Difficult. 
+Our Stockholder Rights Agreement, which is described above under "BUSINESS: Stockholder Rights Agreement" contain provisions that could make it more difficult for a third party to acquire us, even if doing so would be beneficial to our stockholders. 
+Our Management and Larger Stockholders Exercise Significant Control Over the Company. 
+As of December 31, 2017, our named executive officers, directors and 5% stockholders beneficially owned approximately 44.35% of our voting power, which includes four large investors that beneficially own approximately 13.97%, 10.42%, 7.46%, and 7.09%, respectively of the outstanding stock. For the foreseeable future, and assuming these ownership percentages continue to apply, to the extent that these parties vote similarly, they may be able to exercise significant control over many matters requiring approval by the board of directors or our stockholders. As a result, they may be able to: 
+· 
+control the composition of our board of directors; 
+· 
+control our management and policies; 
+· 
+determine the outcome of significant corporate transactions, including changes in control that may be beneficial to stockholders; and, 
+· 
+act in each of their own interests, which may conflict with or differ from the interests of each other or the interests of the other stockholders. 
+21 
+Table of Contents 
+ITEM 1B. Unresolved Staff Comments. 
+Not Applicable 
+ITEM 2. PROPERTIES 
+Our corporate headquarters and U.S. manufacturing, administrative offices, and research facilities are located in leased space in Medford, New York, together with nearby warehouse space and additional administrative offices in Holbrook, New York. Our Southeast Asia manufacturing, warehouse, and commercial facilities are located in leased space in Kuala Lumpur, Malaysia. We regularly review our real estate portfolio and develop footprint strategies to support our customers’ global plans, while at the same time supporting our technical needs and controlling operating expenses. 
+ITEM 3. LEGAL PROCEEDINGS 
+From time to time, we may be involved in litigation relating to claims arising out of our operations in the normal course of business. We know of no material, existing or pending legal proceedings against us, nor are we involved as a plaintiff in any material proceeding or pending litigation. There are no proceedings in which any of our directors, officers or affiliates, or any registered or beneficial shareholder, is an adverse party or has a material interest that is adverse to our interest. 
+ITEM 4. MINE SAFETY DISCLOSURES 
+Not Applicable. 
+22 
+Table of Contents 
+PART II 
+ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+Market Information 
+Our stock is listed on the NASDAQ Global Select Market of the NASDAQ Stock Market LLC under the symbol “CEMI.” The table below sets forth the high and low prices per share of our common stock for each quarter of our two most recently completed fiscal years. 
+Fiscal Year 2017 
+High 
+Low 
+First Quarter 
+$ 
+6.80 
+$ 
+5.05 
+Second Quarter 
+$ 
+7.04 
+$ 
+5.15 
+Third Quarter 
+$ 
+6.70 
+$ 
+5.75 
+Fourth Quarter 
+$ 
+8.35 
+$ 
+5.90 
+Fiscal Year 2016 
+High 
+Low 
+First Quarter 
+$ 
+6.10 
+$ 
+4.03 
+Second Quarter 
+$ 
+9.40 
+$ 
+5.87 
+Third Quarter 
+$ 
+8.48 
+$ 
+5.08 
+Fourth Quarter 
+$ 
+7.45 
+$ 
+6.10 
+Holders 
+As of March 5, 2018 , there were approximately 1,590 record owners of our common stock (including nominee holders such as banks and brokerage firms who hold shares for beneficial owners). 
+Dividends 
+The Company has never paid cash dividends on its common stock and has no plans to do so in the foreseeable future. Any future declaration of dividends will be determined by our Board of Directors in its sole discretion and will depend on, among other things, our earnings, capital requirements, financial condition, prospects and any other factors the Board of Directors may deem relevant. 
+Recent Sales of Unregistered Securities 
+There were no sales of unregistered securities during the year ended December 31, 2017 that were not previously reported on a Quarterly Report on Form 10-Q or a Current Report on Form 8-K. 
+Issuer Purchases of Equity Securities 
+We did not repurchase any of our equity securities during the fourth quarter of the fiscal year ended December 31, 2017. 
+23 
+Table of Contents 
+ITEM 6. 
+SELECTED FINANCIAL DATA 
+The following selected consolidated financial data were derived from our audited consolidated financial statements and should be read in conjunction with, and are qualified by reference to, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and the consolidated financial statements and notes thereto included elsewhere in this Annual Report on Form 10-K. The financial information presented may not be indicative of our future performance. 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+SELECTED HISTORICAL FINANCIAL DATA 
+As of and For the Years Ended December 31, 
+Statement of Operations Data: 
+2017 (1) 
+(2 
+) 
+2016 (3) 
+(2 
+) 
+2015 
+(2 
+) 
+2014 
+(2 
+) 
+2013 
+(2 
+) 
+TOTAL REVENUES 
+$ 
+24,015,427 
+$ 
+17,868,841 
+$ 
+24,255,485 
+$ 
+27,645,284 
+$ 
+29,549,609 
+COSTS AND EXPENSES: 
+Cost of product sales 
+12,921,157 
+9,417,505 
+13,768,658 
+16,831,261 
+17,249,450 
+Research and development expenses 
+8,555,381 
+36 
+% 
+8,427,554 
+47 
+% 
+6,377,839 
+26 
+% 
+4,832,537 
+17 
+% 
+5,834,249 
+20 
+% 
+Selling, general and administrative expenses 
+9,021,439 
+38 
+% 
+7,595,559 
+43 
+% 
+7,663,035 
+32 
+% 
+7,531,739 
+27 
+% 
+5,461,083 
+18 
+% 
+30,497,977 
+25,440,618 
+27,809,532 
+29,195,537 
+28,544,782 
+INCOME (LOSS) FROM OPERATIONS 
+(6,482,550 
+) 
+(7,571,777 
+) 
+(3,554,047 
+) 
+(1,550,253 
+) 
+1,004,827 
+OTHER INCOME (EXPENSES): 
+22,485 
+25,548 
+(3,238 
+) 
+132 
+12,943 
+INCOME (LOSS) BEFORE INCOME TAXES 
+(6,460,065 
+) 
+(27 
+)% 
+(7,546,229 
+) 
+(42 
+)% 
+(3,557,285 
+) 
+(15 
+)% 
+(1,550,121 
+) 
+(6 
+)% 
+1,017,770 
+3 
+% 
+Income tax provision (benefit) 
+(88,305 
+) 
+5,800,818 
+(1,160,243 
+) 
+(412,918 
+) 
+486,952 
+NET INCOME (LOSS) 
+$ 
+(6,371,760 
+) 
+$ 
+(13,347,047 
+) 
+$ 
+(2,397,042 
+) 
+$ 
+(1,137,203 
+) 
+$ 
+530,818 
+Basic income (loss) per share 
+$ 
+(0.52 
+) 
+$ 
+(1.26 
+) 
+$ 
+(0.25 
+) 
+$ 
+(0.12 
+) 
+$ 
+0.06 
+Diluted income (loss) per share 
+$ 
+(0.52 
+) 
+$ 
+(1.26 
+) 
+$ 
+(0.25 
+) 
+$ 
+(0.12 
+) 
+$ 
+0.06 
+Weighted average number of shares outstanding, basic 
+12,300,031 
+10,622,331 
+9,626,028 
+9,530,320 
+8,994,080 
+Weighted average number of shares outstanding, diluted 
+12,300,031 
+10,622,331 
+9,626,028 
+9,530,320 
+9,519,968 
+Balance Sheet Data: 
+Working capital (4) 
+$ 
+7,757,340 
+$ 
+14,707,876 
+$ 
+9,479,968 
+$ 
+12,372,169 
+$ 
+14,221,011 
+Total assets 
+16,616,021 
+20,575,236 
+20,816,344 
+25,010,192 
+24,486,592 
+Total liabilities 
+3,536,825 
+3,405,650 
+3,154,838 
+5,286,030 
+4,309,490 
+Shareholders' equity 
+13,079,196 
+17,169,586 
+17,661,506 
+19,724,162 
+20,177,102 
+(1) 
+On January 9, 2017, we completed the acquisition of RVR Diagnostics Sdn Bhd, a Malaysia manufacturer and distributor of rapid medical assays, which subsequently changed its name to Chembio Diagnostic Malaysia Sdn Bhd. Accordingly, the acquisition impacts comparability to the results in prior years. 
+(2) 
+Percentage shown reflects the percentage of Total Revenues. 
+(3) 
+In 2016, we completed an underwritten public equity offering and issued 2.3 million common shares that raised approximately $12.5 million, net of underwriting commissions and other expenses. 
+(4) 
+Working capital is calculated as total current assets minus total current liabilities. 
+24 
+Table of Contents 
+ITEM 7. 
+MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+The following management’s discussion and analysis of financial condition and results of operations (“MD&A”) is intended to help you understand the business operations and financial condition of the Company for the three-year period ended December 31, 2017. This discussion should be read in conjunction with Item 8. Financial Statements and Supplementary Data. Our MD&A is presented in six sections: 
+● 
+Executive Overview 
+● 
+Consolidated Results of Operations 
+● 
+Liquidity and Capital Resources 
+● 
+Recent Developments 
+● 
+Significant Accounting Policies and Critical Accounting Estimates 
+● 
+Recently Issued Accounting Pronouncements 
+Executive Overview 
+Our Business 
+Through our wholly-owned subsidiaries, Chembio Diagnostic Systems Inc. and Chembio Diagnostics Malaysia Sdn Bhd, we develop, manufacture, and commercialize point-of-care (“POC”) diagnostic tests that are used to detect or monitor diseases. All products that are currently being developed are based on the Company’s patented DPP ® technology, a novel POC diagnostic platform that offers certain customer advantages as compared to traditional lateral flow technology. Chembio was formed in 1985. 
+Business Strategy 
+Recent accomplishments and highlights: 
+● 
+Achieved total revenue of $24.0 million for full year 2017, an increase of 34% over prior year 
+● 
+Achieved product sales of $19.3 million for full year 2017, an increase of 41% over prior year 
+● 
+Received purchase commitment from Bio-Manguinhos related to DPP® HIV Assays and DPP® Leishmania Assays in Brazil, with a total value of $8.5 million in 2018 
+● 
+Received conditional award from UNICEF to purchase DPP ® Zika System, for a total value of $1.5 million to $4.9 million, in 2018-2019 
+● 
+Submitted PMA Application to the FDA for the DPP® HIV-Syphilis Assay and DPP ® Micro Reader following completion of U.S. clinical trials 
+● 
+Entered collaboration with AstraZeneca to develop a quantitative DPP ® Assay to detect an undisclosed biomarker, from which Chembio will receive up to $2.9 million in R&D funding over 18 months 
+● 
+Won three-year tender from the Ethiopian Pharmaceuticals Fund and Supply Agency to deliver HIV STAT-PAK ® Assay, with a total contract value of $15.8 million between 2018-2020 
+In addition, in February 2018, we strengthened our balance sheet with net proceeds of $11.0 million in capital from an underwritten public offering , which is more fully discussed under “Recent Developments” . 
+Our product commercialization and product development efforts a re focused in three areas: sexually transmitted disease, tropical & fever disease, and technology collaborations. In sexually transmitted disease, we are commercializing tests for HIV and Syphilis. In tropical and fever disease, we are commercializing a test for Zika virus, dengue virus, and chikungunya virus, and developing tests for malaria, ebola, lassa, Marburg, leptospirosis, Rickettsia typhi , Burkholderia pseudomallei , and Orientia tsutsugamushi , individually or as part of a fever panel test. Through technology collaborations, we are developing tests for a specific form of cancer, concussion, bovine tuberculosis, and for an undisclosed biomarker, the latter in collaboration with global biopharmaceutical company AstraZeneca. 
+Large and growing markets have been established for these kinds of tests, initially in high prevalence regions where they are indispensable for large scale prevention and treatment programs. Our product development is focused on areas where the availability of rapid POC screening, diagnostic, or confirmatory results can improve health outcomes. More generally, we believe there is and will continue to be a growing demand for diagnostic products that can provide accurate, actionable diagnostic information in a rapid, cost-effective manner at the point of care. 
+Our products are sold to medical laboratories and hospitals, governmental and public health entities, non-governmental organizations, medical professionals and retail establishments, both domestically and internationally, under our STAT-PAK ® , SURE CHECK ® , STAT-VIEW ® or DPP ® registered trademarks, or under the private labels of our marketing partners. 
+Consolidated Results of Operations 
+2017 compared to 2016 
+The results of operations for the years ended December 31, 2017 and 2016 were as follows: 
+December 31, 2017 
+December 31, 2016 
+TOTAL REVENUES 
+$ 
+24,015,427 
+100 
+% 
+$ 
+17,868,841 
+100 
+% 
+COSTS AND EXPENSES: 
+Cost of product sales 
+12,921,157 
+54 
+% 
+9,417,505 
+53 
+% 
+Research and development expenses 
+8,555,381 
+36 
+% 
+8,427,554 
+47 
+% 
+Selling, general and administrative expenses 
+9,021,439 
+38 
+% 
+7,595,559 
+43 
+% 
+30,497,977 
+25,440,618 
+LOSS FROM OPERATIONS 
+(6,482,550 
+) 
+(7,571,777 
+) 
+OTHER INCOME 
+22,485 
+25,548 
+LOSS BEFORE INCOME TAXES 
+(6,460,065 
+) 
+(27 
+)% 
+(7,546,229 
+) 
+(42 
+)% 
+Income tax (benefit) provision 
+(88,305 
+) 
+5,800,818 
+NET LOSS 
+$ 
+(6,371,760 
+) 
+$ 
+(13,347,047 
+) 
+Percentages in the table reflect the percent of total revenues. 
+25 
+Table of Contents 
+Total Net Revenues 
+Total net revenues during the year ended December 31, 2017 were $24.0 million, an increase of $6.1 million, or 34% compared to 2016. The increase in total net revenues was comprised of the following: 
+● 
+$5.6 million, or 41.2% increase in net product sales, reflecting gains in every region of the world except North America, which in 2016 benefited on a one-time basis from a former U.S. distributor's "end-of-contract purchase" of certain products following our notice of termination of that distribution agreement. The last of those products reached their normal expiration date in February 2018, and the Company has been building its own distribution channels consistent with our commercial strategy. As part of these regional successes and as highlighted above, during 2017, the Company re-secured it s DPP® HIV Assay and DPP® Leishmania Assay sales to Brazil and established both a commercial and lower cost manufacturing footprint with its acquisition of RVR Diagnostics Sdn Bhd (now Chembio Diagnostics Malaysia Sdn Bhd). Refer to Note 2 – Acquisition to the audited consolidated financial statements included herein for further information regarding the acquisition. 
+● 
+$0.5 million, or 12.0% increase in R&D milestone and grant, and license and royalty revenues compared to 2016, reflecting the Company’s continued success in securing governmental, non-governmental, and commercial partnerships, in particular associated with our DPP ® technology platform. 
+Gross Product Margin 
+Cost of sales is primarily comprised of material, labor, manufacturing overhead, depreciation and amortization, and other operating expenses. Gross product margin is net product sales less cost of product sales, and gross product margin percentage is gross product margin as a percentage of net product sales. 
+Gross product margin increased by $2.1 million, or 50.2% compared to 2016. The following schedule calculates gross product margin: 
+For the years ended 
+December 31, 2017 
+December 31, 2016 
+Favorable/ 
+(unfavorable) 
+% Change 
+Net product sales 
+$ 
+19,322,302 
+$ 
+13,680,107 
+$ 
+5,642,195 
+41.2 
+% 
+Less: Cost of product sales 
+(12,921,157 
+) 
+(9,417,505 
+) 
+(3,503,652 
+) 
+37.2 
+% 
+Gross product margin 
+$ 
+6,401,145 
+$ 
+4,262,602 
+$ 
+2,138,543 
+50.2 
+% 
+Gross product margin % 
+33.13 
+% 
+31.16 
+% 
+The $2.1 million increase in gross product margin was comprised of the following: 
+● 
+$1.7 million from favorable product sales volume as described above, and 
+● 
+$0.4 million from favorable product margins, principally related to favorable overhead application. 
+Research and Development 
+This category includes costs incurred for clinical & regulatory affairs and other research & development, as follows: 
+For the years ended 
+December 31, 2017 
+December 31, 2016 
+Favorable/ 
+(unfavorable) 
+% Change 
+Clinical & regulatory affairs 
+$ 
+2,298,206 
+$ 
+1,444,410 
+$ 
+(853,796 
+) 
+(59.1 
+%) 
+Other research & development 
+6,257,175 
+6,983,144 
+725,969 
+10.4 
+% 
+Total Research and Development 
+$ 
+8,555,381 
+$ 
+8,427,554 
+$ 
+(127,827 
+) 
+(1.5 
+%) 
+The increase in clinical & regulatory affairs costs for the year ended December 31, 2017 as compared to 2016 is primarily associated with the Company’s U.S. clinical trial evaluating its DPP ® HIV-Syphilis System, which it completed in December 2017, as discussed above. The decrease in other research & development costs is primarily associated with a reduction in spending on materials & supplies associated with R&D milestone and grant revenue-related projects. 
+Selling, General and Administrative Expense 
+Selling, general and administrative expense (“SG&A”) includes administrative expenses, sales and marketing costs including commissions, and other corporate items. 
+The $1.4 million, or 18.8%, increase in SG&A for the year ended December 31, 2017 as compared to 2016 is primarily associated with increases in the following: $0.7 million compensation, travel, entertainment, and trade show costs associated with the growth in our sales and commercial team, $0.4 million intangible asset amortization related to the acquisition of RVR Diagnostics in January 2017, and $0.3 million corporate regulatory costs. 
+Other Income and Expense 
+Other income and expenses are principally interest income earned on the Company's deposits, which decreased by approximately $3,000 for the year ended December 31, 2017 as compared to 2016. 
+Income Tax Provision 
+For the year ended December 31, 2017 the Company recognized a tax benefit of $88,000 associated with anticipated refunds of accumulated alternative minimum tax (AMT) credits to be received between 2019 and 2021 pursuant to recently enacted tax legislation net of state tax provisions. Accordingly, the benefit had no cash impact in 2017. In 2016, the Company recorded a non-cash income tax provision and decreased its deferred tax assets by $5.8 million as the Company took a full valuation allowance against its carryforward losses. 
+26 
+Table of Contents 
+2016 versus 2015 
+The results of operations for the years ended December 31, 2016 and 2015 were as follows: 
+December 31, 2016 
+December 31, 2015 
+TOTAL REVENUES 
+$ 
+17,868,841 
+100 
+% 
+$ 
+24,255,485 
+100 
+% 
+COSTS AND EXPENSES: 
+Cost of product sales 
+9,417,505 
+53 
+% 
+13,768,658 
+57 
+% 
+Research and development expenses 
+8,427,554 
+47 
+% 
+6,377,839 
+26 
+% 
+Selling, general and administrative expenses 
+7,595,559 
+43 
+% 
+7,663,035 
+32 
+% 
+25,440,618 
+27,809,532 
+LOSS FROM OPERATIONS 
+(7,571,777 
+) 
+(3,554,047 
+) 
+OTHER INCOME 
+25,548 
+(3,238 
+) 
+LOSS BEFORE INCOME TAXES 
+(7,546,229 
+) 
+(42 
+%) 
+(3,557,285 
+) 
+(15 
+%) 
+Income tax provision (benefit) 
+5,800,818 
+(1,160,243 
+) 
+NET LOSS 
+$ 
+(13,347,047 
+) 
+$ 
+(2,397,042 
+) 
+Percentages in the table reflect the percent of total revenues. 
+Total Net Revenues 
+Total net revenues during the year ended December 31, 2016 were $17.9 million, a decrease of $6.4 million, or 26.3% compared to 2015. The decrease in total net revenues was comprised of the following: 
+● 
+$8.2 million, or 37.5% decrease in net product sales compared to 2015, reflecting decreased sales in Brazil and Mexico, partially offset by increased sales in the U.S., which in 2016 benefited on a one-time basis from a former U.S. distributor's "end-of-contract purchase" of certain products following our termination of that distribution agreement. 
+● 
+$1.8 million, or 76.8% increase in R&D milestone and grant revenues compared to 2015, reflecting the Company’s continued success in securing governmental, non-governmental, and commercial partnerships, in particular associated with our DPP ® technology platform. 
+Gross Product Margin 
+Cost of sales is primarily comprised of material, labor, manufacturing overhead, depreciation and amortization, and other operating expenses. Gross product margin is net product sales less cost of product sales, and gross product margin percentage is gross product margin as a percentage of net product sales. 
+Gross product margin fell by $3.9 million, or 47.5% compared to 2015. The following schedule calculates gross product margin: 
+For the years ended 
+December 31, 2016 
+December 31, 2015 
+Favorable/ 
+(unfavorable) 
+% Change 
+Net product sales 
+$ 
+13,680,107 
+$ 
+21,886,688 
+$ 
+(8,206,581 
+) 
+(37.5 
+)% 
+Less: Cost of product sales 
+(9,417,505 
+) 
+(13,768,658 
+) 
+4,351,153 
+(31.6 
+)% 
+Gross product margin 
+$ 
+4,262,602 
+$ 
+8,118,030 
+$ 
+(3,855,428 
+) 
+(47.5 
+)% 
+Gross product margin % 
+31.16 
+% 
+37.09 
+% 
+The $3.9 million decrease in gross product margin was comprised of the following: 
+● 
+$3.0 million from unfavorable product sales volume as described above, and 
+● 
+$0.9 million from unfavorable product margins, reflecting the increased absorption of overhead at lower unit volumes. 
+Research and Development 
+This category includes costs incurred for clinical & regulatory affairs and other research & development, as follows: 
+For the years ended 
+December 31, 2016 
+December 31, 2015 
+Favorable/ 
+(unfavorable) 
+% Change 
+Clinical & regulatory affairs 
+$ 
+1,444,410 
+$ 
+982,366 
+$ 
+(462,044 
+) 
+(47.0 
+)% 
+Other research development 
+6,983,144 
+5,395,473 
+(1,587,671 
+) 
+(29.4 
+)% 
+Total Research and Development 
+$ 
+8,427,554 
+$ 
+6,377,839 
+$ 
+(2,049,715 
+) 
+(32.1 
+)% 
+Expenses for Clinical & Regulatory Affairs increased by $0.5 million for the year ended December 31, 2016, as compared to 2015, primarily related to an increase in clinical trial expenses and additional wages and related costs. 
+Other R&D expenses increased by $1.6 million in the year ended December 31, 2016, as compared to 2015. The increase is primarily related to an increase in wages, benefits, materials, and supplies to support the growth in sponsored research and internal development programs. 
+27 
+Table of Contents 
+Selling, General and Administrative Expense 
+Selling, general and administrative expense (“SG&A”) includes administrative expenses, sales and marketing costs including commissions, and other corporate items. 
+The $0.1 million decrease in SG&A for the year ended December 31, 2016 as compared to 2015 reflects reduced commissions (principally for lower sales in Brazil) and other selling costs related to the lower 2016 sales volume, somewhat offset by increases in wages and travel costs associated with the growth in our sales and commercial team. 
+Other Income and Expense 
+Other income and expenses are principally interest income earned on the Company's deposits, which increased by approximately $29,000 for the year ended December 31, 2016 as compared to 2015, reflecting interest on funds raised in the 2016 public offering. 
+Income Tax Provision 
+For the year ended December 31, 2016, the Company recognized a $5.8 million non-cash income tax provision and decreased its deferred tax assets by a corresponding amount, together with a full valuation allowance. By comparison, for the year ended December 31, 2015, the Company recognized a $1.2 million non-cash income tax benefit and increased its deferred tax assets by a corresponding amount. 
+Liquidity and Capital Resources 
+Overview 
+Our liquidity requirements are primarily to fund our business operations, including capital expenditures and working capital requirements, as well as to fund opportunistic investments that align with our focused business strategy. Our primary sources of liquidity are cash flows from operations, our existing cash balance, and as necessary, additional capital. We will continually explore ways to enhance our capital structure. 
+Acquisition 
+On January 9, 2017, Chembio acquired 100% of the equity interests of RVR Diagnostics Sdn Bhd, a Malaysia manufacturer and distributor of rapid medical assays, for $1.4 million in cash and for common shares with a value at closing of approximately $1.7 million. As further described in Note 2 – Acquisition to the audited consolidated financial statements contained herein, the acquisition was accounted for as a business combination, with the operating results of RVR Diagnostics included within the Company’s operating results from the date of acquisition. The Company financed the cash portion of the acquisition with funds raised in its 2016 public equity offering. After the acquisition, RVR Diagnostics Sdn Bhd changed its name to Chembio Diagnostics Malaysian Sdn Bhd. 
+Government, Non-Governmental Organization, and Non-Profit Programs 
+Chembio commonly seeks research and development programs that may be awarded by government, non-governmental organization (“NGO”), and non-profit entities including private foundations. Chembio currently has or has recently undertaken development programs that are competitively awarded from agencies of the U.S. Federal Government including the U.S. Department of Health and Human Services and U.S. Department of Agriculture, as well as from FIND, the Bill & Melinda Gates Foundation, and The Paul G. Allen Family Foundation. 
+Contractual Commitments 
+The following table summarizes the Company’s expected cash outflows resulting from financial contracts and commitments as of December 31, 2017, with amounts denominated in foreign currencies translated using foreign currency rates as of December 31, 2017. 
+Payments due by period 
+Total 
+Less than one year 
+1 - 3 years 
+3-5 years 
+Thereafter 
+Operating leases 1 
+$ 
+1,058,000 
+$ 
+603,000 
+$ 
+455,000 
+$ 
+- 
+$ 
+- 
+Employment contracts 2 
+1,341,000 
+770,000 
+571,000 
+- 
+- 
+Purchase obligations 3 
+548,000 
+548,000 
+- 
+- 
+- 
+Minimum commitments under contracts 4 
+239,000 
+56,000 
+112,000 
+51,000 
+20,000 
+Total 
+$ 
+3,186,000 
+$ 
+1,977,000 
+$ 
+1,138,000 
+$ 
+51,000 
+$ 
+20,000 
+1 Represents payments required under our operating leases. 
+2 Represents salary payments payable under the terms of employment agreements with certain executives with terms that extend beyond December 31, 2018. 
+3 Represents payments required by non-cancellable purchase orders related to capital expenditures. 
+4 Represents payments required pursuant to certain licensing agreements. Such agreements are cancellable within a specified number of days following notice by the Company. 
+28 
+Table of Contents 
+Cash Flows 
+As of December 31, 2017, we had cash and equivalents of $3.8 million and no outstanding debt except for a $0.1 million seller-financed note payable associated with automated manufacturing equipment. 
+For the years ended 
+December 31, 2017 
+December 31, 2016 
+Favorable/ 
+(unfavorable) 
+% Change 
+Net cash used in operating activities 
+$ 
+(5,034,515 
+) 
+$ 
+(6,704,734 
+) 
+$ 
+1,670,219 
+24.9 
+% 
+Net cash used in investing activities 
+(1,876,954 
+) 
+(668,706 
+) 
+(1,208,248 
+) 
+(180.7 
+)% 
+Net cash provided by financing activities 
+134,280 
+12,550,973 
+(12,416,693 
+) 
+(98.9 
+)% 
+Effect of exhange rate changes on cash 
+13,027 
+- 
+13,027 
+100.0 
+% 
+INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 
+$ 
+(6,764,162 
+) 
+$ 
+5,177,533 
+$ 
+(11,941,695 
+) 
+(230.6 
+)% 
+The Company's cash as of December 31, 2017 decreased by $6.8 million vs. December 31, 2016, primarily due to net cash used in operating and investing activities. 
+Cash used in operating activities in 2017 was $5.1 million, primarily due to the net loss adjusted for non-cash items of $4.9 million and a $1.1 million increase in inventory, offset by a $1.3 million reduction in accounts receivable related to favorable collections. 
+Cash used in investing activities during 2017 related to the acquisition of RVR Diagnostics and the purchase of manufacturing equipment and other fixed assets. 
+During 2016, the Company completed an underwritten registered public offering, whereas no such offering occurred during 2017. Please see the “Recent Developments” section, below, for further information regarding the Company’s February 2018 underwritten registered public offering. 
+Off-Balance Sheet Arrangements 
+The Company does not have any off-balance sheet arrangements, as defined in Item 303(a)(4)(ii) of Regulation S-K under the Securities Exchange Act of 1934, as amended. 
+Recent Developments 
+As described in Note 16 – Subsequent Event to the audited consolidated financial statements included herein, on February 13, 2018, the Company consummated an underwritten registered public offering of 1,783,760 shares of its common stock at a public offering price of $6.75 per share for gross proceeds of approximately $12.0 million. The net proceeds, after underwriting discounts and commissions, and estimated expenses, are approximately $11.0 million. 
+Significant Accounting Policies and Critical Accounting Estimates 
+Our significant accounting policies are described in Note 3 – Significant Accounting Policies to the audited consolidated financial statements included herein. Certain of our accounting policies require the application of significant judgment by management in selecting the appropriate assumptions for calculating financial estimates. By their nature, these judgments are subject to an inherent degree of uncertainty. These judgments are based on our historical experience, terms of existing contracts, our evaluation of trends in the industry, information provided by our customers and information available from other outside sources, as appropriate. We consider an accounting estimate to be critical if: 
+● 
+It requires us to make assumptions about matters that were uncertain at the time we were making the estimate, and 
+● 
+Changes in the estimate or different estimates that we could have selected would have had a material impact on our financial condition or results of operations. 
+The following listing is not intended to be a comprehensive list of all of our accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by accounting principles generally accepted in the United States of America, with no need for management’s judgment in their application. There are also areas in which management’s judgment in selecting any viable alternative would not produce a materially different result. 
+Revenue Recognition 
+We recognize revenue for product sales in accordance with ASC 605. Revenue is recognized when there is persuasive evidence of an arrangement, delivery has occurred or services have been rendered, the sales price is determinable, and collectability is reasonably assured. Revenue typically is recognized at time of shipment. Sales are recorded net of discounts, rebates and returns. 
+For certain contracts, we recognize revenue from R&D, milestone and grant revenues when earned. Grants are invoiced after expenses are incurred. Revenues from projects or grants funded in advance are deferred until earned. For certain collaborative research projects, we recognize revenue by defining milestones at the inception of the agreement and applying the milestone method of revenue recognition for relevant contracts. 
+Stock-Based Compensation 
+We recognize the fair value of equity-based awards as compensation expense in our statement of operations. The fair value of our stock option awards was estimated using a Black-Scholes option valuation model. This valuation model’s computations incorporate highly subjective assumptions, such as the expected stock price volatility and the estimated life of each award. The fair value of the options, after considering the effect of expected forfeitures, is then amortized, generally on a straight-line basis, over the related vesting period of the option. 
+Research & Development Costs 
+Research and development activities consist primarily of new product development, continuing engineering for existing products, and regulatory and clinical trial costs. Costs related to research and development efforts on existing or potential products are expensed as incurred. 
+29 
+Table of Contents 
+Inventories 
+Inventories are stated at the lower of cost or market, using the first-in, first-out method (FIFO) to determine cost. Our policy is to periodically evaluate the market value of the inventory and the stage of product life cycle, and record a reserve for any inventory considered slow moving or obsolete. For example, each additional 1% of obsolete inventory would reduce such inventory by approximately $44,000. 
+Accounts Receivable 
+Our policy is to review our accounts receivable on a periodic basis, no less frequently than monthly. On a quarterly basis an analysis is made of the adequacy of our allowance for doubtful accounts and adjustments are made accordingly. The current allowance is approximately 2% of accounts receivable. For example, each additional 1% of accounts receivable that becomes uncollectible would reduce such balance of accounts receivable by approximately $21,000. 
+Acquisitions 
+In accordance with accounting guidance for the provisions in FASB ASC 805, Business Combinations , we allocate the purchase price of an acquired business to its identifiable assets and liabilities based on estimated fair values. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. In addition, an acquisition may include a contingent consideration component, such as our acquisition agreements for RVR Diagnostics. The fair value of the contingent consideration is estimated as of the date of the acquisition and is recorded as part of the purchase price. This estimate is updated in future periods and any changes in the estimate, which are not considered an adjustment to the purchase price, are recorded in our consolidated statements of operations. 
+We use all available information to estimate fair values. We typically engage outside appraisal firms to assist in the fair value determination of identifiable intangible assets and any other significant assets or liabilities. We adjust the preliminary purchase price allocation, as necessary, up to one year after the acquisition closing date as we obtain more information regarding asset valuations and liabilities assumed. 
+Our purchase price allocation methodology contains uncertainties because it requires management to make assumptions and to apply judgment to estimate the fair value of acquired assets and liabilities. Management estimates the fair value of assets and liabilities based upon quoted market prices, the carrying value of the acquired assets and widely accepted valuation techniques, including discounted cash flows and market multiple analyses. Unanticipated events or circumstances may occur which could affect the accuracy of our fair value estimates, including assumptions regarding industry economic factors and business strategies. 
+Other estimates used in determining fair value include, but are not limited to, future cash flows or income related to intangibles, market rate assumptions, actuarial assumptions for benefit plans and appropriate discount rates. Our estimates of fair value are based upon assumptions believed to be reasonable, but that are inherently uncertain, and therefore, may not be realized. Accordingly, there can be no assurance that the estimates, assumptions, and values reflected in the valuations will be realized, and actual results could vary materially. 
+Goodwill and Intangible Assets 
+We periodically review goodwill for impairment indicators. We review goodwill for impairment annually in the fourth quarter or more frequently if events or changes in circumstances indicate that goodwill might be impaired. The Company performs the goodwill impairment review at the reporting unit level. We perform a qualitative assessment of whether it is more likely than not that a reporting unit's fair value is less than its carrying amount. If not, no further goodwill impairment testing is performed. If so, we perform the step discussed hereafter. Our qualitative assessment involves significant estimates, assumptions, and judgments, including, but not limited to, macroeconomic conditions, industry and market conditions, financial performance of the Company, reporting unit specific events and changes in the Company's share price. 
+If the fair value of the reporting unit is greater than its carrying amount, goodwill is not considered to be impaired. We would recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value, provided the impairment charge does not exceed the total amount of goodwill allocated to the reporting unit. 
+We review indefinite-lived intangible assets for impairment annually or more frequently if events or changes in circumstances indicate the assets might be impaired. Similar to the goodwill assessment described above, the Company first performs a qualitative assessment of whether it is more likely than not that an indefinite-lived intangible asset is impaired. If necessary, the Company then performs a quantitative impairment test by comparing the estimated fair of the asset, based upon its forecasted cash flows, to its carrying value. Other intangible assets with definite lives are amortized over their useful lives and are subject to impairment testing only if events or circumstances indicate that the asset might be impaired, as described above. 
+Income Taxes 
+Income taxes are accounted for under ASC 740 authoritative guidance (“Guidance”), which requires the asset and liability method of accounting for deferred income taxes. Deferred tax assets and liabilities are determined based on the difference between the financial statement and tax bases of assets and liabilities. Deferred tax assets or liabilities at the end of each period are determined using the tax rate expected to be in effect when taxes are actually paid or recovered. 
+The Guidance also requires that a valuation allowance be established when it is more likely than not that all or a portion of a deferred tax asset will not be realized. A review of all available positive and negative evidence needs to be considered, including a company’s current and past performance, the market environment in which the company operates, length of carryback and carryforward periods and existing contracts that will result in future profits. The Company believes that it likely will not be able to utilize its net operating loss carryforwards and maintains a full valuation allowance. The Company maintains a full valuation allowance on research and development tax credits. 
+The Guidance also prescribes a comprehensive model for recognizing, measuring, presenting and disclosing in the consolidated financial statements tax positions taken or expected to be taken on a tax return, including a decision whether to file or not to file in a particular jurisdiction. 
+30 
+Table of Contents 
+Recently Issued Accounting Pronouncements 
+Refer to Note 3 – Significant Accounting Policies to the audited consolidated financial statements included herein for a complete description of recent accounting standards which we have not yet been required to implement which may be applicable to our operations. Additionally, the significant accounting standards that have been adopted during the year ended December 31, 2017 are described. 
+ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk. 
+The Company does not hold any amounts of derivative financial instruments or derivative commodity instruments and, accordingly, has no material derivative risk to report under this Item. As of December 31, 2017, the Company did not have any foreign currency exchange contracts nor purchase currency options to hedge local currency cash flows. 
+We are exposed to market risks from changes in currency exchange rates and certain commodity prices. All sales from our U.S. subsidiary, regardless of the customer location, are denominated in U.S. dollars. Sales denominated in foreign currencies are associated with a portion of the sales from our subsidiary Chembio Diagnostics Malaysia and comprised approximately 6.1% of our total net revenues for the year ended December 31, 2017. 
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+The Consolidated Financial Statements and schedules that constitute Item 8 are attached at the end of this Annual Report on Form 10-K. An index to these Financial Statements and schedules is also included on page F-1 of this Annual Report on Form 10-K. 
+ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. 
+Not Applicable. 
+ITEM 9A. CONTROLS AND PROCEDURES 
+(a) Disclosure Controls and Procedures. Under the supervision and with the participation of our senior management, consisting of our chief executive officer and our chief financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)), as of the end of the period covered by this report (the "Evaluation Date"). Based on that evaluation, the Company’s management, including our chief executive officer and chief financial officer, concluded that as of the Evaluation Date our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports that we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. Our disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in our Exchange Act reports is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure. 
+Management's Annual Report on Internal Control Over Financial Reporting. The Company's management is responsible for establishing and maintaining an adequate system of internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f)). Our internal control over financial reporting is a process, under the supervision of our chief executive officer and chief financial officer, designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States. These internal controls over financial reporting processes include policies and procedures that: 
+a. Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company; 
+b. Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and 
+c. Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance of achieving their control objectives. 
+31 
+Table of Contents 
+Management’s Report on Internal Control over Financial Reporting 
+Management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f). The Company has designed its internal control over financial reporting to provide reasonable assurance on the reliability of financial reporting and the preparation of the consolidated financial statements in accordance with U.S. generally accepted accounting principles. 
+The Company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting can only provide reasonable assurance and may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+Under the supervision and with the participation of our management, including the Chief Executive Officer (CEO) and the Chief Financial Officer (CFO), we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2017, based on the framework and criteria in the 2013 Internal Control – Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on management’s evaluation and those criteria, the CEO and CFO concluded that its system of internal control over financial reporting was effective as of December 31, 2017. 
+BDO USA, LLP, the Company's independent registered public accounting firm that audited the Company's consolidated financial statements included in this report, has issued an attestation report on the effectiveness of the Company's internal control over financial reporting, a copy of which appears on the following page. 
+32 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+Shareholders and Board of Directors 
+Chembio Diagnostics, Inc. 
+Medford, New York 
+Opinion on Internal Control over Financial Reporting 
+We have audited Chembio Diagnostics, Inc.’s (the “Company’s”) internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on the COSO criteria. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company and subsidiaries as of December 31, 2017 and 2016, the related consolidated statements of operations, comprehensive loss, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes and schedule and our report dated March 8, 2018 expressed an unqualified opinion thereon. 
+Basis for Opinion 
+The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying “Item 9A, Management’s Report on Internal Control over Financial Reporting”. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audit of internal control over financial reporting in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+Definition and Limitations of Internal Control over Financial Reporting 
+A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+/s/ BDO USA, LLP 
+New York, NY 
+March 8, 2018 
+33 
+Table of Contents 
+(b) Changes in Internal Control over Financial Reporting. There were no changes in our internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Rule 13a-15 or Rule 15d-15 under the Exchange Act that occurred during the Company’s last fiscal quarter of the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+ITEM 9B. OTHER INFORMATION 
+Not applicable. 
+34 
+Table of Contents 
+PART III 
+ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
+The information required in response to this Item 10 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+ITEM 11. EXECUTIVE COMPENSATION 
+The information required in response to this Item 11 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+The information required in response to this Item 12 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE. 
+The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+The information required in response to this Item 14 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+35 
+Table of Contents 
+PART IV 
+ITEM 15. 
+EXHIBITS INDEX 
+Number 
+Description 
+3.1 
+Articles of Incorporation, as amended. (1) 
+3.2 
+Bylaws and Bylaw Amendments. (2) 
+3.3 
+Certificate of Designation of Series D Preferred Stock (13) 
+4.1 
+2008 Stock Incentive Plan, as amended . (3) 
+4.2 
+Form of Option, for 2008 Stock Incentive Plan (4) 
+4.3 
+2014 Stock Incentive Plan (5) 
+4.4 
+Form of Option, for 2014 Stock Incentive Plan (6) 
+4.5 
+Rights Agreement, dated as of March 8, 2016 (7) 
+4.6 
+Form of Warrant under Rights Agreement (to be filed by amendment) 
+10.1* 
+Employment Agreement dated effective as of March 13, 2017 with John J. Sperzel III (15) 
+10.2* 
+Employment Agreement dated March 5, 2016 with Javan Esfandiari (8) 
+10.3* 
+Employment Agreement effective May 22, 2017 with Sharon Klugewicz (16) 
+10.4* 
+Employment Agreement dated December 18, 2017 with Neil Goldman 
+10.5* 
+Employment Agreement dated January 9, 2017 with Magentiren Vajuram (15) 
+10.6* 
+E mployment Agreement dated January 9, 2017 with Avijit Roy (15) 
+10.7 
+H IV Barrel License, Marketing and Distribution Agreement, dated as of September 29, 2006, by and among the Registrant, Alere and StatSure. (10) 
+10.8 
+HIV Cassette License, Marketing and Distribution Agreement, dated as of September 29, 2006, between the Registrant and Alere. (10) 
+10.9 
+Non-Exclusive License, Marketing and Distribution Agreement, dated as of September 29, 2006, between the Registrant and Alere . (10) 
+10.10 
+Joint HIV Barrel Product Commercialization Agreement, dated as of September 29, 2006, between the Registrant and StatSure . (10) 
+10.11 
+2015 Omnibus Agreement (11) 
+10.12 
+Amended And Restated Stock Purchase Agreement, dated as of December 7, 2016, by and among Chembio Diagnostics, Inc., RVR Diagnostics Sdn Bhd, Avijit Roy and Magentiren Vajuram (14) 
+10.13 
+Underwriting Agreement, dated February 9, 2018, by and between the Registrant and Craig-Hallum Capital Group LLC (17) 
+14.1 
+Ethics Policy (12) 
+23.1 
+Consent of BDO USA, LLP, Independent Registered Public Accounting Firm 
+31.1 
+Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 . 
+31.2 
+Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 . 
+32 
+Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 . 
+101.INS 
+XBRL Instance Document 
+101.SCH 
+XBRL Taxonomy Extension Schema Document 
+101.CAL 
+XBRL Taxonomy Extension Calculation Linkbase Document 
+101.DEF 
+XBRL Taxonomy Definition Linkbase Document 
+101.LAB 
+XBRL Taxonomy Label Linkbase Document 
+101.PRE 
+XBRL Taxonomy Presentation Linkbase Document 
+1 
+Incorporated by reference to the Registrant's Quarterly Report on Form 10-Q filed with the Commission on July 29, 2010. 
+2 
+Incorporated by reference to the Registrant's registration statement on Form SB-2 (File No. 333-85787) filed with the Commission on August 23, 1999 and the Registrant's Forms 8-K filed on May 14, 2004 , December 20, 2007 and April 18, 2008 . 
+3 
+Incorporated by reference to the Registrant's definitive proxy statement on Schedule 14A filed with the Commission on August 3, 2012. 
+4 
+Incorporated by reference to the Registrant's Quarterly Report on Form 10-Q filed with the Commission on May 8, 2014. 
+5 
+Incorporated by reference to the Registrant's definitive proxy statement on Schedule 14A filed with the Commission on April 29, 2014. 
+6 
+Incorporated by reference to the Registrant's Quarterly Report on Form 10-Q filed with the Commission on August 7, 2014. 
+7 
+Incorporated by reference to the Registrant's registration statement on Form 8-A filed with the Commission on April 7, 2016. 
+8 
+Incorporated by reference to the Registrant's Current Report on Form 8-K filed with the Commission on March 14, 2016. 
+9 
+Incorporated by reference to the Registrant's Current Report on Form 8-K filed with the Commission on June 27, 2017. 
+10 
+Incorporated by reference to the Registrant's Current Report on Form 8-K filed with the Commission on October 5, 2006. 
+11 
+Incorporated by reference to the Registrant's Annual Report on Form 10-K filed with the Commission on March 5, 2015. 
+12 
+Incorporated by reference to the Registrant's Annual Report on Form 10-KSB filed with the Commission on March 30, 2006. 
+13 
+Incorporated by reference to the Registrant's Current Report on Form 8-K filed with the Commission on April 7, 2016. 
+14 
+Incorporated by reference to the Registrant's Current Report on Form 8-K filed with the Commission on January 10, 2017. 
+15 
+Incorporated by reference to the Registrant's Quarterly Report on Form 10-Q filed with the Commission on May 9, 2017. 
+16 
+Incorporated by reference to the Registrant's Quarterly Report on Form 10-Q filed with the Commission on November 8, 2017. 
+17 
+Incorporated by reference to the Registrant's Current Report on Form 8-K filed with the Commission on February 13, 2018. 
+(*) 
+An asterisk (*) beside an exhibit number indicates the exhibit contains a management contract, compensatory plan or arrangement which is required to be identified in this report. 
+ITEM 16. Form 10-K Summary 
+None. 
+36 
+Table of Contents 
+SIGNATURES 
+In accordance with Section 13 or 15(d) of the Exchange Act, the registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+CHEMBIO DIAGNOSTICS, INC. 
+March 8, 2017 
+By 
+/s/ John J. Sperzel 
+John J. Sperzel III 
+President, Chief Executive Officer and 
+Member of the Board 
+In accordance with the requirements of the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+Signatures 
+Title 
+Date 
+/s/ John J. Sperzel 
+Chief Executive Officer, President and 
+March 8, 2017 
+John J. Sperzel III 
+Member Of The Board 
+(Principal Executive Officer) 
+/s/ Neil A. Goldman 
+Executive Vice President & Chief Financial Officer 
+March 8, 2017 
+Neil A. Goldman 
+(Principal Financial & Accounting Officer) 
+/s/ Katherine L. Davis 
+Director & Chair of the Board 
+March 8, 2017 
+Katherine L. Davis 
+/s/ Peter T. Kissinger 
+Director 
+March 8, 2017 
+Peter T. Kissinger 
+/s/ Gail S. Page 
+Director 
+March 8, 2017 
+Gail S. Page 
+37 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+Index to Consolidated Financial Statements 
+—INDEX— 
+Page(s) 
+Report of Independent Registered Public Accounting Firm 
+F-1 
+Consolidated Financial Statements: 
+Balance Sheets as of December 31, 2017 and 2016 
+F-2 
+Statements of Operations for each of the years ended December 31, 2017, 2016 and 2015 
+F-3 
+Statements of Comprehensive Loss for each of the years ended December 31, 2017, 2016 and 2015 
+F-4 
+Statements of Changes in Stockholders’ Equity for each of the years ended December 31, 2017, 2016 and 2015 
+F-5 
+Statements of Cash Flows for each of the years ended December 31, 2017, 2016 and 2015 
+F-6 
+Notes to Consolidated Financial Statements 
+F-7 - F-17 
+Schedule II - Valuation and Qualifying Accounts 
+F-18 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+Shareholders and Board of Directors 
+Chembio Diagnostics, Inc. 
+Medford, New York 
+Opinion on the Consolidated Financial Statements 
+We have audited the accompanying consolidated balance sheets of Chembio Diagnostics, Inc. (the “Company”) and subsidiaries as of December 31, 2017 and 2016, the related consolidated statements of operations, comprehensive loss, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes and schedule (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company and subsidiaries at December 31, 2017 and 2016, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) and our report dated March 8, 2018 expressed an unqualified opinion thereon. 
+Basis for Opinion 
+These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. 
+Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. 
+/s/ BDO USA, LLP 
+We have served as the Company's auditor since 2011. 
+New York, NY 
+March 8, 2018 
+F-1 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED BALANCE SHEETS 
+AS OF 
+- ASSETS - 
+December 31, 2017 
+December 31, 2016 
+CURRENT ASSETS: 
+Cash and cash equivalents 
+$ 
+3,790,302 
+$ 
+10,554,464 
+Accounts receivable, net of allowance for doubtful accounts of $42,000 and $52,000 at December 31, 2017 and 2016, respectively 
+2,085,340 
+3,383,729 
+Inventories, net 
+4,423,618 
+3,335,188 
+Prepaid expenses and other current assets 
+554,383 
+840,145 
+TOTAL CURRENT ASSETS 
+10,853,643 
+18,113,526 
+FIXED ASSETS , net of accumulated depreciation 
+1,909,232 
+1,709,321 
+OTHER ASSETS: 
+Intangible assets, net 
+1,597,377 
+- 
+Goodwill 
+1,666,610 
+- 
+Deposits and other assets 
+589,159 
+752,389 
+TOTAL ASSETS 
+$ 
+16,616,021 
+$ 
+20,575,236 
+- LIABILITIES AND STOCKHOLDERS’ EQUITY - 
+CURRENT LIABILITIES: 
+Accounts payable and accrued liabilities 
+$ 
+3,046,303 
+$ 
+3,013,133 
+Deferred revenue 
+50,000 
+392,517 
+TOTAL CURRENT LIABILITIES 
+3,096,303 
+3,405,650 
+OTHER LIABILITIES: 
+Note payable 
+99,480 
+- 
+Deferred tax liability 
+341,042 
+- 
+TOTAL LIABILITIES 
+3,536,825 
+3,405,650 
+COMMITMENTS AND CONTINGENCIES (Note 13) 
+STOCKHOLDERS’ EQUITY: 
+Preferred stock – 10,000,000 shares authorized, none outstanding 
+- 
+- 
+Common stock - $.01 par value; 100,000,000 shares authorized, 12,318,570 and 12,026,847 shares issued and outstanding at December 31, 2017 and 2016, respectively 
+123,185 
+120,268 
+Additional paid-in capital 
+62,821,288 
+60,721,783 
+Accumulated deficit 
+(50,044,225 
+) 
+(43,672,465 
+) 
+Accumulated other comprehensive income 
+178,948 
+- 
+TOTAL STOCKHOLDERS’ EQUITY 
+13,079,196 
+17,169,586 
+TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY 
+$ 
+16,616,021 
+$ 
+20,575,236 
+See accompanying notes to consolidated financial statements 
+F-2 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF OPERATIONS 
+For the years ended 
+December 31, 2017 
+December 31, 2016 
+December 31, 2015 
+REVENUES: 
+Net product sales 
+$ 
+19,322,302 
+$ 
+13,680,107 
+$ 
+21,886,688 
+License and royalty revenue 
+741,534 
+449,685 
+52,753 
+R&D, milestone and grant revenue 
+3,951,591 
+3,739,049 
+2,316,044 
+TOTAL REVENUES 
+24,015,427 
+17,868,841 
+24,255,485 
+COSTS AND EXPENSES: 
+Cost of product sales 
+12,921,157 
+9,417,505 
+13,768,658 
+Research and development expenses 
+8,555,381 
+8,427,554 
+6,377,839 
+Selling, general and administrative expenses 
+9,021,439 
+7,595,559 
+7,663,035 
+30,497,977 
+25,440,618 
+27,809,532 
+LOSS FROM OPERATIONS 
+(6,482,550 
+) 
+(7,571,777 
+) 
+(3,554,047 
+) 
+OTHER INCOME (EXPENSE): 
+Other expense 
+- 
+- 
+(4,814 
+) 
+Interest income 
+25,430 
+25,548 
+2,412 
+Interest expense 
+(2,945 
+) 
+- 
+(836 
+) 
+22,485 
+25,548 
+(3,238 
+) 
+LOSS BEFORE INCOME TAXES (BENEFIT) 
+(6,460,065 
+) 
+(7,546,229 
+) 
+(3,557,285 
+) 
+Income tax provision (benefit) 
+(88,305 
+) 
+5,800,818 
+(1,160,243 
+) 
+NET LOSS 
+$ 
+(6,371,760 
+) 
+$ 
+(13,347,047 
+) 
+$ 
+(2,397,042 
+) 
+Basic loss per share 
+$ 
+$ (0.52 
+) 
+$ 
+(1.26 
+) 
+$ 
+(0.25 
+) 
+Diluted loss per share 
+$ 
+$ (0.52 
+) 
+$ 
+(1.26 
+) 
+$ 
+(0.25 
+) 
+Weighted average number of shares outstanding, basic 
+12,300,031 
+10,622,331 
+9,626,028 
+Weighted average number of shares outstanding, diluted 
+12,300,031 
+10,622,331 
+9,626,028 
+See accompanying notes to consolidated financial statements 
+F-3 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS 
+For the years ended 
+December 31, 2017 
+December 31, 2016 
+December 31, 2015 
+Net loss 
+$ 
+(6,371,760 
+) 
+$ 
+(13,347,047 
+) 
+$ 
+(2,397,042 
+) 
+Other comprehensive income: 
+Foreign currency translation adjustments 
+178,948 
+- 
+- 
+COMPREHENSIVE LOSS 
+$ 
+(6,192,812 
+) 
+$ 
+(13,347,047 
+) 
+$ 
+(2,397,042 
+) 
+See accompanying notes to consolidated financial statements 
+F-4 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY 
+FOR THE YEARS ENDED DECEMBER 31, 2017, 2016 AND 2015 
+Common Stock 
+Additional 
+Paid-in-Capital 
+Accumulated 
+Deficit 
+AOCI 
+Total 
+Shares 
+Amount 
+Amount 
+Amount 
+Amount 
+Amount 
+Balance at December 31, 2014 
+9,611,139 
+$ 
+96,112 
+$ 
+47,556,426 
+$ 
+(27,928,376 
+) 
+$ 
+- 
+$ 
+19,724,162 
+Options: 
+Exercised 
+17,109 
+170 
+(170 
+) 
+- 
+- 
+- 
+Stock option compensation 
+- 
+- 
+334,386 
+- 
+- 
+334,386 
+Net loss 
+(2,397,042 
+) 
+- 
+(2,397,042 
+) 
+Balance at December 31, 2015 
+9,628,248 
+$ 
+96,282 
+$ 
+47,890,642 
+$ 
+(30,325,418 
+) 
+$ 
+- 
+$ 
+17,661,506 
+Common Stock: 
+New stock from offering 
+2,300,000 
+23,000 
+12,470,398 
+- 
+- 
+12,493,398 
+Options: 
+Exercised 
+98,599 
+986 
+56,589 
+- 
+- 
+57,575 
+Stock option compensation 
+- 
+- 
+304,154 
+- 
+- 
+304,154 
+Net loss 
+- 
+- 
+- 
+(13,347,047 
+) 
+- 
+(13,347,047 
+) 
+Balance at December 31, 2016 
+12,026,847 
+$ 
+120,268 
+$ 
+60,721,783 
+$ 
+(43,672,465 
+) 
+$ 
+- 
+$ 
+17,169,586 
+Common Stock: 
+Purchase of RVR Diagnostics Sdn Bhd 
+269,236 
+2,692 
+1,680,033 
+- 
+- 
+1,682,725 
+Options: 
+Exercised 
+22,487 
+225 
+34,575 
+- 
+- 
+34,800 
+Stock option compensation 
+- 
+- 
+384,897 
+- 
+- 
+384,897 
+Comprehensive income 
+- 
+- 
+- 
+- 
+178,948 
+178,948 
+Net loss 
+- 
+- 
+- 
+(6,371,760 
+) 
+- 
+(6,371,760 
+) 
+Balance at December 31, 2017 
+12,318,570 
+$ 
+123,185 
+$ 
+62,821,288 
+$ 
+(50,044,225 
+) 
+$ 
+178,948 
+$ 
+13,079,196 
+See accompanying notes to consolidated financial statements 
+F-5 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+FOR THE YEARS ENDED 
+December 31, 2017 
+December 31, 2016 
+December 31, 2015 
+CASH FLOWS FROM OPERATING ACTIVITIES: 
+Cash received from customers and grants 
+$ 
+24,971,299 
+$ 
+16,947,194 
+$ 
+30,174,083 
+Cash paid to suppliers and employees 
+(30,028,299 
+) 
+(23,677,476 
+) 
+(28,382,681 
+) 
+Interest received 
+22,485 
+25,548 
+2,412 
+Interest paid 
+- 
+- 
+(836 
+) 
+Net cash (used in) provided by operating activities 
+(5,034,515 
+) 
+(6,704,734 
+) 
+1,792,978 
+CASH FLOWS FROM INVESTING ACTIVITIES: 
+Acquisition of license 
+- 
+- 
+(550,000 
+) 
+Purchase of RVR Diagnostics Sdn Bhd 
+(850,000 
+) 
+(550,000 
+) 
+- 
+Acquisition of and deposits on fixed assets 
+(1,026,954 
+) 
+(118,706 
+) 
+(480,585 
+) 
+Net cash used in investing activities 
+(1,876,954 
+) 
+(668,706 
+) 
+(1,030,585 
+) 
+CASH FLOWS FROM FINANCING ACTIVITIES: 
+Proceeds from option and warrant exercises 
+34,800 
+57,575 
+- 
+Proceeds from note payable 
+99,480 
+- 
+- 
+Proceeds from credit line 
+- 
+- 
+700,000 
+Repayment of credit line 
+- 
+- 
+(700,000 
+) 
+Proceeds from sale of common stock, net 
+- 
+12,493,398 
+- 
+Net cash provided by financing activities 
+134,280 
+12,550,973 
+- 
+Effect of exchange rate changes on cash 
+13,027 
+- 
+- 
+(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS 
+(6,764,162 
+) 
+5,177,533 
+762,393 
+Cash and cash equivalents - beginning of the period 
+10,554,464 
+5,376,931 
+4,614,538 
+Cash and cash equivalents - end of the period 
+$ 
+3,790,302 
+$ 
+10,554,464 
+$ 
+5,376,931 
+RECONCILIATION OF NET LOSS TO NET CASH (USED IN) PROVIDED BY OPERATING ACTIVITIES: 
+Net Loss 
+$ 
+(6,371,760 
+) 
+$ 
+(13,347,047 
+) 
+$ 
+(2,397,042 
+) 
+Adjustments: 
+Depreciation and amortization 
+1,276,963 
+1,139,228 
+1,372,563 
+Provision for (benefit from) deferred taxes 
+- 
+5,800,818 
+(1,170,969 
+) 
+Fair value adjustment to contingent consideration 
+(148,000 
+) 
+- 
+- 
+Share based compensation 
+384,897 
+304,154 
+334,386 
+Changes in assets and liabilities: 
+Accounts receivable 
+1,298,389 
+(960,758 
+) 
+5,915,918 
+Inventories 
+(1,088,430 
+) 
+242,837 
+60,274 
+Prepaid expenses and other current assets 
+285,762 
+(136,258 
+) 
+(190,960 
+) 
+Deposits and other assets 
+(512,272 
+) 
+1,480 
+- 
+Accounts payable and accrued liabilities 
+182,453 
+211,701 
+(2,144,598 
+) 
+Deferred revenue 
+(342,517 
+) 
+39,111 
+13,406 
+Net cash (used in) provided by operating activities 
+$ 
+(5,034,515 
+) 
+$ 
+(6,704,734 
+) 
+$ 
+1,792,978 
+Supplemental disclosures for non-cash investing and financing activities: 
+Deposits on manufacturing equipment transferred to fixed assets 
+$ 
+174,399 
+$ 
+- 
+$ 
+20,017 
+Accrual of contingent earn-out 
+148,000 
+- 
+- 
+Issuance of common stock for net assets of business acquired 
+1,682,725 
+- 
+- 
+See accompanying notes to consolidated financial statements 
+F-6 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2017, 2016, AND 2015 
+NOTE 1 — DESCRIPTION OF BUSINESS: 
+Chembio Diagnostics, Inc. and its subsidiaries (collectively, the “Company” or “Chembio”), develop, manufacture, and commercialize point-of-care (POC) diagnostic tests that are used to detect or monitor diseases. All products that are currently being developed are based on the Company’s patented DPP ® technology, a novel point-of-care diagnostic platform that offers certain customer advantages as compared to traditional lateral flow technology. POC tests, by providing prompt and early diagnosis, can reduce patient stays, lower overall costs, improve therapeutic interventions and improve patient outcomes. POC tests can also prevent needless hospital admissions, simplify testing procedures, avoid delays from central lab batching, and eliminate the need for return visits. 
+Our product commercialization and product development efforts are focused in three areas: sexually transmitted disease, tropical & fever disease, and technology collaborations. In sexually transmitted disease, we are commercializing tests for HIV and Syphilis. In tropical and fever disease, we are commercializing a test for Zika virus, and developing tests for malaria, dengue virus, chikungunya virus, ebola, lassa , Marburg, leptospirosis, Rickettsia typhi , Burkholderia pseudomallei , and Orientia tsutsugamushi , individually or as part of fever panel tests. Through technology collaborations, we are developing tests for a specific form of cancer, concussion, bovine tuberculosis, and for an undisclosed biomarker, the latter in collaboration with global biopharmaceutical company AstraZeneca. 
+Large and growing markets have been established for these kinds of tests, initially in high prevalence regions where they are indispensable for large scale prevention and treatment programs. Our product development is focused on areas where the availability of rapid, POC screening, diagnostic, or confirmatory results can improve health outcomes. More generally, we believe there is and will continue to be a growing demand for diagnostic products that can provide accurate, actionable diagnostic information in a rapid, cost-effective manner at the point of care. 
+Our products are sold to medical laboratories and hospitals, governmental and public health entities, non-governmental organizations, medical professionals and retail establishments, both domestically and internationally, under our STAT PAK ® SURE CHECK ® , STAT-VIEW ® or DPP ® registered trademarks, or under the private labels of our marketing partners. 
+The Company routinely enters into arrangements with governmental and non-governmental organizations for the funding of certain research and development efforts. 
+NOTE 2 — ACQUISITION: 
+On January 9, 2017, pursuant to a stock purchase agreement (the "Stock Purchase Agreement), the Company acquired all of the outstanding common stock of RVR Diagnostics Sdn Bhd ("RVR"), a privately-held Malaysia based manufacturing company focused on assembly and sales of rapid medical assays, for $3,231,000. The Company acquired RVR, which subsequently changed its name to Chembio Diagnostics Malaysia Sdn Bhd ("CDM"), to have a better presence in Asia, access to lower cost, shorter approval time of in-country regulatory approvals, and a lower cost assembly operation. 
+Total consideration was: (i) a cash payment of $1,400,000, of which $550,000 was paid as a deposit in December 2016; (ii) 269,236 shares of Chembio's common stock, with a value at closing of $1,683,000, of which 7,277 shares were held back to satisfy certain potential claims under the Stock Purchase Agreement and became issuable to the sellers on the one-year anniversary of the closing; and, a contingent $148,000 milestone payment based on the achievement of performance goals related to sales by CDM during the 12 months ended December 31, 2017. The performance goals were not achieved and the related $148,000 accrual was reversed during the fourth quarter of 2017 and recognized in Selling, general, and administrative expenses associated with the change in fair value. 
+As a result of the consideration paid exceeding the preliminary fair value of the net assets acquired, goodwill in the amount of $1,503,361 was recorded in connection with this acquisition, none of which will be deductible for tax purposes. In addition, the Company recorded $1,800,000 in intangible assets associated with the addition of CDM’s intellectual property, customer base and distribution channels, trade names, order backlog, industry reputation, and management talent and workforce. The Condensed Consolidated Statements of Operations for the year ended December 31, 2017 include $25,000 of transaction costs related to the CDM acquisition, which are reflected as Selling, general and administrative expenses. 
+The acquisition was accounted for using the purchase method of accounting. The following table summarizes the allocation of the purchase price to the estimated fair values of the assets acquired and liabilities assumed on the closing date of January 9, 2017: 
+Amount 
+Property, plant and equipment 
+$ 
+235,141 
+Goodwill 
+1,651,361 
+Deferred tax liability 
+(307,636 
+) 
+Contingent consideration 
+(148,000 
+) 
+Other intangible assets (estimated useful life): 
+Intellectual property (approximate 10 year weighted average) 
+800,000 
+Customer contracts / relationships (approximate 10 year weighted average) 
+700,000 
+Order backlog (3 months) 
+200,134 
+Trade names (approximate 11 year weighted average) 
+100,000 
+Total consideration 
+$ 
+3,231,000 
+The Company calculated the fair value of the fixed assets based on the net book value of CDM as that approximates fair value. The intellectual property, customer contracts and trade names were based on discounted cash flows using management estimates. The order backlog was based on an order that CDM had at the closing that was shipped in the first quarter of 2017, and valued at an estimated net income. 
+F-7 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2017, 2016, AND 2015 
+The following represents unaudited pro forma operating results for the year ended December 31, 2016 as if the operations of CDM had been included in the Company’s Condensed Consolidated Statements of Operations as of January 1, 2016: 
+Pro Forma 
+Total revenues 
+$ 
+19,151,653 
+Net loss 
+$ 
+(13,473,084 
+) 
+Net loss per common share 
+$ 
+(1.26 
+) 
+Diluted net loss per common share 
+$ 
+(1.26 
+) 
+The pro forma financial information includes business combination accounting effects from the acquisition including amortization charges from acquired intangible assets of approximately $398,000. The unaudited pro forma information as presented above is for informational purposes only and is not indicative of the results of operations that would have been achieved if the acquisition had taken place at the beginning of fiscal 2016. CDM's net revenues and pre-tax loss for the year ended December 31, 2017 were approximately $ 1,465,000 and ($406,000), respectively. 
+NOTE 3 — SIGNIFICANT ACCOUNTING POLICIES: 
+(a) 
+Principles of Consolidation: 
+The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries (Chembio Diagnostic Systems, Inc. and Chembio Diagnostics Malaysia Sdn Bhd). All significant intercompany transactions and balances are eliminated in consolidation. 
+(b) 
+Use of Estimates: 
+The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make assumptions and estimates that affect the amounts reported in the consolidated financial statements and accompanying notes. Judgments and estimates of uncertainties are required in applying the Company’s accounting policies in certain areas. Generally, matters subject to estimation and judgment include accounts receivable realization, inventory obsolescence, asset impairments, recognition of revenue persuant to milestones, useful lives of intangible and fixed assets, stock-based compensation, and deferred tax asset valuation allowances. Due to the inherent uncertainty involved in making estimates, actual results reported in future periods may be based upon amounts that differ from those estimates. 
+(c) 
+Fair Value of Financial Instruments: 
+The carrying value for cash and cash equivalents, accounts receivable, and accounts payable, approximate fair value due to the immediate or short-term maturity of these financial instruments. The fair value of the Company's notes payable approximates the recorded value as the rate is based upon the current rates offered to the Company for similar financial instruments. 
+(d) 
+Cash and Cash Equivalents: 
+Cash and cash equivalents are defined as short-term, highly liquid investments with original maturities of three months or less. 
+(e) 
+Concentrations of Credit Risk: 
+Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of temporary cash investments and trade receivables. The Company places its temporary cash instruments with well-known financial institutions and, at times, may maintain balances in excess of the FDIC insurance limit. The Company monitors the credit ratings of the financial institutions to mitigate this risk. Concentration of credit risk with respect to trade receivables is principally mitigated by the Company’s ability to obtain letters of credit from certain foreign customers and its diverse customer base, both in number of customers and geographic locations. 
+(f) 
+Inventories: 
+Inventories, consisting of material, labor and manufacturing overhead, are stated at the lower of cost or net realizable value. Cost is determined on the first-in, first-out method. 
+(g) 
+Fixed Assets: 
+Fixed assets are stated at cost, less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the respective assets, which range from three to seven years. Leasehold improvements are amortized over the useful life of the asset or the lease term, whichever is shorter. Deposits paid for fixed assets are capitalized and not depreciated until the related asset is placed in service. 
+(h) 
+License Agreements: 
+The Company records up-front payments related to sublicense agreements as prepaids and amortizes them over their respective economic life. As of December 31, 2017 and 2016, total prepaids were $100,000 and $237,500, respectively. 
+Amortization expenses for the licenses above for the years ended December 31, 2017, 2016 and 2015 were $137,500 $319,319, and $442,557, respectively. 
+F-8 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2017, 2016, AND 2015 
+(i) 
+Valuation of Long-Lived Assets and Intangible Assets: 
+Long-lived assets to be held and used are analyzed for impairment whenever events or changes in circumstances indicate that the related carrying amounts may not be recoverable. The Company evaluates at each balance sheet date whether events and circumstances have occurred that indicate possible impairment. If there are indications of impairment, the Company uses future undiscounted cash flows of the related asset or asset grouping over the remaining life in measuring whether the assets are recoverable. In the event such cash flows are not expected to be sufficient to recover the recorded asset values, the assets are written down to their estimated fair value. No impairment of long-lived tangible and intangible assets was recorded for the years ended December 31, 2017 and 2016. 
+(j) 
+Revenue Recognition: 
+The Company recognizes revenue for product sales in accordance with ASC 605, whereby revenue is recognized when there is persuasive evidence of an arrangement, delivery has occurred, or services have been rendered, the sales price is fixed and determinable, and collectability is reasonably assured. Revenue typically is recognized at time of shipment. Sales are recorded net of discounts, rebates and returns. 
+For certain contracts, the Company recognizes revenue from non-milestone contracts and grant revenues when earned. Grants are invoiced after expenses are incurred. Revenues from projects or grants funded in advance are deferred until earned. 
+The Company follows the recognition of revenue under the milestone method for certain collaborative research projects defining milestones at the inception of the agreement. 
+In April 2017, the Company entered into a $1.0 million agreement with FIND to develop a simple, point-of-care fever panel assay that can identify multiple life-threatening acute febrile illnesses common in the Asia Pacific region. The Company earned $0.8 million for the year ended December 31, 2017, as R&D, milestone and grant revenue in our Consolidated Statements of Operations. 
+In August 2016, the Company was awarded a grant of $5.9 million from BARDA, which is part of the U.S. Department of Health And Human Resources to develop a rapid Zika virus assay. The Company earned $2.2 million and $2.7 million for the year ended December 31, 2017 and from inception through December 31, 2017, respectively, as R&D, milestone and grant revenue in our Consolidated Statements of Operations. 
+In September 2016, the Company was awarded a $0.7 million contract from the USDA to develop a Bovid TB assay. The Company earned $0.4 million and $0.7 million for the year ended December 31, 2017 and from inception through December 31, 2017, respectively, as R&D, milestone and grant revenue in our Consolidated Statements of Operations. 
+(k) 
+Research and Development: 
+Research and development (R&D) costs are expensed as incurred. 
+(l) 
+Stock-Based Compensation: 
+Stock-based compensation expense is calculated using the Black-Scholes valuation model based on awards ultimately expected to vest, reduced for forfeitures, and expensed on a straight-line basis over the requisite service period of the grant. During 2017, the Company adopted ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting". 
+(m) 
+I ncome Taxes: 
+The Company accounts for income taxes under an asset and liability approach that recognizes deferred tax assets and liabilities based on the difference between the financial statement carrying amounts and the tax bases of assets and liabilities using enacted tax rates in effect in the years in which the differences are expected to reverse. 
+The Company follows a more-likely-than-not threshold for financial statement recognition and measurement of a tax position taken, or expected to be taken, in a tax return. The guidance relates to, among other things, classification, accounting for interest and penalties associated with tax positions, and disclosure requirements. Any interest and penalties accrued related to uncertain tax positions are recorded in tax expense. 
+The Company assesses the realizability of its net deferred tax assets on an annual basis. If, after considering all relevant positive and negative evidence, it is more likely than not that some portion or all of the net deferred tax assets will not be realized, the Company will reduce the net deferred tax assets by a valuation allowance. The realization of net deferred tax assets is dependent on several factors, including the generation of sufficient taxable income prior to the expiration of net operating loss carryforwards. 
+(n) 
+Loss Per Share: 
+Basic loss per share is computed by dividing net loss attributable to common stockholders by the weighted-average number of common shares outstanding for the period. Diluted loss per share for the year ended December 31, 2017, 2016 and 2015 reflects the potential dilution from the exercise or conversion of other securities into common stock, if dilutive. 
+There were 810,670, 600,549 and 658,631 options outstanding as of December 31, 2017, 2016 and 2015, respectively, which were not included in the calculation of diluted income per share for the years ended because their effect would have been anti-dilutive. 
+(o) 
+Goodwill and Intangible Assets: 
+Goodwill represents the excess of the purchase price we paid over the fair value of the net tangible and identifiable intangible assets acquired in our acquisition of CDM in January 2017. Goodwill is not amortized but rather is tested annually as of the first day of the fiscal fourth quarter, or sooner if we believe that indicators of impairment exist. We make a qualitative evaluation about the likelihood of goodwill impairment, which is based on a number of applicable factors. If we conclude that it is more likely than not that the carrying value of the applicable reporting unit is greater than its fair value, then we would recognize an impairment charge for the amount by which the carrying value exceeds the reporting unit’s fair value, provided the impairment charge does not exceed the total amount of goodwill allocated to the reporting unit. 
+For the year ended December 31, 2017, the results of our goodwill impairment analysis did not result in any impairment. 
+F-9 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2017, 2016, AND 2015 
+Following is a table that reflects changes in Goodwill: 
+Beginning balance 1/1/17 
+$ 
+- 
+Acquisition of CDM 
+1,651,361 
+Changes in foreign currency exchange rate 
+15,249 
+Balance at December 31, 2017 
+$ 
+1,666,610 
+In addition, the Company recorded certain intangible assets as part of the CDM acquisition which are as follows as of December 31, 2017: 
+Cost 
+Accumulated Amortization 
+Net Book Value 
+Intellectual property 
+$ 
+886,872 
+$ 
+88,687 
+$ 
+798,185 
+Customer contracts/relationships 
+776,013 
+77,601 
+698,412 
+Order backlog 
+221,867 
+221,867 
+- 
+Trade names 
+110,859 
+10,079 
+100,780 
+$ 
+1,995,611 
+$ 
+398,234 
+$ 
+1,597,377 
+Amortization expense for the year ended December 31, 2017 was $398,234. 
+(p) 
+Foreign Currency Translation: 
+Assets and liabilities of non-U.S. subsidiaries that use a currency other than U.S. dollars as their functional currency are translated to U.S. dollars at end of period currency exchange rates. The consolidated statements of operations of non-U.S. subsidiaries are translated to U.S. dollars at average period currency exchange rates. The effect of translation for non-U.S subsidiaries is generally reported in Other comprehensive income. 
+(q) 
+Recent Accounting Pronouncements Affecting the Company: 
+In May 2014, the Financial Accounting Standards Board (“FASB”) issued converged guidance on recognizing revenue in contracts with customers, ASU 2014-09, Revenue from Contracts with Customers . The intent of the new standard is to improve financial reporting and comparability of revenue globally. The core principle of the standard is for a company to recognize revenue in a manner that depicts the transfer of goods or services to customers in an amount that reflects the consideration which the company expects to receive in exchange for those goods or services. The guidance provides a five-step analysis of transactions to determine when and how revenue is recognized. Other major provisions include capitalization of certain contract costs, consideration of the time value of money in the transaction price, and in certain circumstances, allowing estimates of variable consideration to be recognized before contingencies are resolved. The guidance also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from an entity’s contracts with customers. The standard is effective for the first interim period within annual reporting periods beginning after December 15, 2017. 
+Except for expanded disclosures to be included in our first interim financial statements for the fiscal year end 2018, we have completed our evaluation of the new standard and assessed the impact of adoption on our consolidated financial statements. We reviewed significant open contracts with customers for each revenue stream, and based on our evaluation, revenue recognition under the new standard will not have a material impact on the Company’s consolidated financial statements because: i) product sales revenue is recognized when control of the goods is transferred to the customer (i.e., the date of shipment, which is consistent under ASC 605), and ii) R&D, milestone and grant revenue do not generally constitute exchange transactions and therefore the new standard does not apply. The Company has also assessed its control framework as a result of adopting the new standard and notes minimal, insignificant changes to its systems and other controls processes. 
+The new standard permits two adoption methods under ASU 2014-09. The guidance may be adopted through either retrospective application to all periods presented in the consolidated financial statements (full retrospective) or through a cumulative effect adjustment to retained earnings at the effective date (modified retrospective). The Company adopted the new standard effective January 1, 2018 using the modified retrospective transition method. Under that method, we applied the rules to all contracts existing as of January 1, 2018. We estimated the cumulative effect recorded to the opening balance of retained earnings to be immaterial. 
+The disclosures in our notes to the consolidated financial statements related to revenue recognition will be expanded under the new standard, specifically around the quantitative and qualitative information about performance obligations, changes in contract assets and liabilities, and disaggregation of revenue. The Company expects to make these enhanced disclosures in its interim financial statements for the first quarter of 2018. 
+In November 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-17, Income Taxes (Topic 740) Balance Sheet Classification of Deferred Assets. This ASU is intended to simplify the presentation of deferred taxes on the balance sheet and will require an entity to present all deferred tax assets and deferred tax liabilities as non-current on the balance sheet. Under the current guidance, entities are required to separately present deferred taxes as current or non-current. Netting deferred tax assets and deferred tax liabilities by tax jurisdiction will still be required under the new guidance. This guidance will be effective for Chembio beginning in 2018, with early adoption permitted. The Company does not believe this new accounting standard update will have a material impact on its consolidated financial statements. 
+In February 2016, the FASB issued Accounting Standards Update (“ASU”) 2016-02, which amends the ASC and creates Topic 842, Leases. Topic 842 will require lessees to recognize lease assets and lease liabilities for those leases classified as operating leases under previous US GAAP on the balance sheet. This guidance is effective for annual periods beginning after December 15, 2018 and early adoption is permitted. We are in the initial stages of evaluating the effect of the standard on our financial statements and will continue to evaluate. While not yet in a position to assess the full impact of the application of the new standard, the Company expects that the impact of recording the lease liabilities and the corresponding right-to-use assets will have a significant impact on its total assets and liabilities with a minimal impact on equity. 
+F-10 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2017, 2016, AND 2015 
+In March 2016, the FASB issued authoritative guidance under ASU 2016-09, Compensation-Stock Compensation (Topic 718) Improvements to Employee Share-Based Payment Accounting . ASU 2016-09 provides for simplification of several aspects of the accounting for share-based payment transactions, including income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The Company adopted ASU 2016-09 on January 1, 2017. As the Company has a full valuation allowance against its U.S. net deferred tax assets, the adoption of this standard for recognition of the tax effect of deductions for employee share awards in excess of compensation costs (“windfall”) did not have a material impact on our consolidated financial statements and related disclosures. See Note 8 – Income Taxes, for additional information. Should the full valuation allowance be reversed in future periods, the adoption of this new guidance could introduce more volatility in the calculation of our effective tax rate, depending on the Company’s share price at exercise or vesting of share-based awards as compared to grant date. The other provisions of ASU 2016-09 did not have a material impact on our consolidated financial statements and related disclosures. 
+In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments , which provides guidance related to cash flows presentation and is effective for annual reporting periods beginning after December 15, 2017. The guidance in ASU 2016-15 is generally consistent with our current cash flow classifications, and we do not expect the adoption of this standard will have a material impact on our consolidated financial statements. 
+In January 2017, the FASB issued ASU 2017-04, Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment , which requires an entity to no longer perform a hypothetical purchase price allocation to measure goodwill impairment. Instead, impairment will be measured using the difference between the carrying amount and the fair value of the reporting unit. This update will be effective for annual and interim periods in fiscal years beginning after December 15, 2019. Early adoption is permitted. The Company adopted ASU 2017-04 in the fourth quarter of 2017. The adoption of this standard did not have a material impact on our consolidated financial statements and related disclosures. 
+In May 2017, the FASB issued ASU No. 2017-09, Compensation-Stock Compensation (Topic 718): Scope of Modification Accounting , to provide clarity to which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. This update will be effective for annual periods and interim periods in fiscal years beginning after December 15, 2017 with early adoption permitted. We do not expect the adoption will have a material effect on our consolidated financial statements. 
+NOTE 4 — INVENTORIES: 
+Inventories consist of the following at: 
+December 31, 2017 
+December 31, 2016 
+Raw materials 
+$ 
+1,767,684 
+$ 
+1,824,248 
+Work in process 
+286,413 
+535,320 
+Finished goods 
+2,369,521 
+975,620 
+$ 
+4,423,618 
+$ 
+3,335,188 
+NOTE 5 — FIXED ASSETS: 
+Fixed assets consist of the following at: 
+December 31, 2017 
+December 31, 2016 
+Machinery and equipment 
+$ 
+4,582,759 
+$ 
+3,962,051 
+Furniture and fixtures 
+449,548 
+437,962 
+Computer and telephone equipment 
+422,946 
+343,167 
+Leasehold improvements 
+2,258,779 
+2,012,945 
+7,714,032 
+6,756,125 
+Less accumulated depreciation and amortization 
+(5,804,800 
+) 
+(5,046,804 
+) 
+$ 
+1,909,232 
+$ 
+1,709,321 
+There were no capital leases at the end of December 31, 2017. Fixed assets at December 31, 2017 also include $538,406 in equipment, that is undergoing validation and as such is not yet being depreciated. Depreciation expense for the 2017, 2016 and 2015 years aggregated $727,563, $782,711 and $893,305, respectively. 
+As of December 31, 2017 and 2016, the Company had paid deposits on various pieces of equipment classified within Deposits and Other Assets aggregating $257,455 and $31,900, respectively. 
+NOTE 6 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES: 
+Accounts payable and accrued liabilities consist of the following at: 
+December 31, 2017 
+December 31, 2016 
+Accounts payable – suppliers 
+$ 
+1,494,759 
+$ 
+1,437,290 
+Accrued commissions 
+126,827 
+221,982 
+Accrued royalties / license fees 
+429,297 
+352,660 
+Accrued payroll 
+187,305 
+167,575 
+Accrued vacation 
+309,767 
+289,587 
+Accrued bonuses 
+282,500 
+282,500 
+Accrued expenses - other 
+215,848 
+261,539 
+Total 
+$ 
+3,046,303 
+$ 
+3,013,133 
+F-11 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2017, 2016, AND 2015 
+NOTE 7 — DEFERRED RESEARCH AND DEVELOPMENT REVENUE: 
+The Company recognizes income from R&D milestones when those milestones are reached and non-milestone contracts and grants when earned. These projects are invoiced after expenses are incurred. Any projects or grants funded in advance are deferred until earned. As of December 31, 2017 and 2016, there were $50,000 and $392,517 unearned advanced revenues, respectively. 
+NOTE 8 — INCOME TAXES: 
+The (benefit from) provision for income taxes for the years ended December 31, 2017, 2016, and 2015 is comprised of the following: 
+2017 
+2016 
+2015 
+Current 
+Federal 
+$ 
+(97,339 
+) 
+$ 
+- 
+$ 
+- 
+State 
+9,034 
+- 
+10,726 
+Total current (benefit) provision 
+(88,305 
+) 
+- 
+10,726 
+Deferred 
+Federal 
+- 
+5,778,185 
+(1,171,865 
+) 
+State 
+- 
+22,633 
+896 
+Total deferred (benefit) provision 
+- 
+5,800,818 
+(1,170,969 
+) 
+Total (benefit) provision 
+$ 
+(88,305 
+) 
+$ 
+5,800,818 
+$ 
+(1,160,243 
+) 
+On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) was signed into law making significant changes to the Internal Revenue Code. Changes include, but are not limited to, a corporate tax rate decrease from 34% to 21% effective for tax years beginning after December 31, 2017, the transition of U.S international taxation from a worldwide tax system to a territorial system, and a one-time transition tax on the mandatory deemed repatriation of cumulative foreign earnings as of December 31, 2017. 
+The Tax Act also puts in place new tax laws that will apply prospectively, which include, but are not limited to, (1) implementing a base erosion and anti-abuse tax, (2) generally eliminating U.S.federal income taxes on dividends from foreign subsidiaries, (3) a new provision designed to tax currently in the U.S. global intangible low-taxed income (“GILTI”) of foreign subsidiaries, which allows for the possibility of utilizing foreign tax credits to offset the income tax liability (subject to some limitations), and (4) a lower effective U.S. tax rate on certain revenues from sources outside the U.S. 
+The Company calculated its best estimate of the impact of the Act in accordance with its understanding of the Act and guidance available as of the date of this filing and recorded a $97,339 tax benefit in the period in which the legislation was enacted, related to a credit for alternative minimum taxes (AMT) paid in prior periods. A provisional amount related the remeasurement of certain deferred tax assets and liabilities based on the rates at which they are expected to reverse in the future resulted in a charge of $3,906,774, which was fully offset by an equivalent adjustment to the deferred tax valuation allowance. No provisional amount related to the one-time transition tax on the mandatory deemed repatriation of foreign earnings was deemed necessary. 
+On December 22, 2017, Staff Accounting Bulletin No. 118 (“SAB 118”) was issued to address the application of US GAAP in situations when a registrant does not have the necessary information available, prepared or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects of the Act. In accordance with SAB 118, the Company has determined that the $97,339 benefit recorded which relates to the AMT credit is a provisional amount and a reasonable estimate of December 31, 2017. 
+The Company had an ownership change as described in Internal Revenue Code Sec. 382 during 2004 (“2004 change”). As a result, the Company’s net operating losses prior to the 2004 change of $5,832,516 were subject to an annual limitation of $150,608 and for the first five (5) years are entitled to a BIG (Built-In-Gains) of $488,207 per year. These net operating losses expire in 2020 through 2024. 
+The Company had a second ownership change during 2006 (“2006 change”). The net operating losses incurred between the 2004 change and the 2006 change of $8,586,861 were subject to an annual limitation of $1,111,831 and for the first five (5) years are entitled to a BIG of $1,756,842 per year. These net operating losses expire in 2020 through 2026. 
+After applying the above limitations, at December 31, 2017, the Company has post-change net operating loss carry-forwards of approximately $26,660,530 which expire between 2018 and 2037. In addition the Company has research and development tax credit carryforwards of approximately $1,461,351 for the year ended December 31, 2017, which expire between 2025 and 2037. 
+F-12 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2017, 2016, AND 2015 
+As referenced in Note 2 - Acquisition, the Company acquired the stock of RVR Diagnostics Sdn Bhd, a Malaysia corporation, during the current year. RVR is on tax holiday through December 31, 2018. Accordingly, no taxes nor (benefit) have been provided on RVR results. 
+2017 
+2016 
+Inventory reserves 
+$ 
+244,158 
+$ 
+253,380 
+Accrued expenses 
+102,332 
+53,140 
+Net operating loss carry-forwards 
+5,800,144 
+7,487,937 
+Research and development credit 
+1,918,137 
+1,461,351 
+Other credits 
+- 
+97,339 
+Other 
+167,522 
+292,556 
+Depreciation 
+91,258 
+31,285 
+Deferred tax assets 
+8,323,551 
+9,676,988 
+Intangibles 
+(341,042 
+) 
+- 
+Deferred tax liabilities 
+(341,042 
+) 
+- 
+Net deferred tax assets before valuation allowance 
+7,982,509 
+9,676,988 
+Less valuation allowances 
+(8,323,551 
+) 
+(9,676,988 
+) 
+Net noncurrent deferred tax liabilities 
+$ 
+(341,042 
+) 
+$ 
+- 
+The components of (loss) before income taxes consisted of the following: 
+Year Ending December 31, 
+2017 
+2016 
+2015 
+United States operations 
+$ 
+(6,054,002 
+) 
+$ 
+(7,546,229 
+) 
+$ 
+(3,557,285 
+) 
+International operations 
+(406,063 
+) 
+- 
+- 
+(Loss) before taxes 
+$ 
+(6,460,065 
+) 
+$ 
+(7,546,229 
+) 
+$ 
+(3,557,285 
+) 
+A reconciliation of the Federal statutory rate to the effective rate applicable to loss before income taxes is as follows: 
+Year Ending December 31, 
+2017 
+2016 
+2015 
+Federal income tax at statutory rates 
+(34.00 
+)% 
+(34.00 
+)% 
+(34.00 
+)% 
+State income taxes, net of federal benefit 
+0.09 
+% 
+0.21 
+% 
+0.23 
+% 
+Nondeductible expenses 
+1.04 
+% 
+0.57 
+% 
+1.38 
+% 
+Foreign rate differential 
+2.14 
+% 
+- 
+- 
+Change in valuation allowance 
+99.41 
+% 
+114.81 
+% 
+9.46 
+% 
+Impact of Tax Act on valuation allowance 
+(60.48 
+)% 
+- 
+- 
+AMT refund under Tax Act 
+(1.51 
+)% 
+- 
+- 
+Tax credits 
+(7.07 
+)% 
+0.00 
+% 
+(9.46 
+)% 
+Other 
+(0.99 
+)% 
+0.04 
+% 
+0.34 
+% 
+Income tax (benefit) 
+(1.37 
+)% 
+81.63 
+% 
+(32.05 
+)% 
+Interest and penalties, if any, related to income tax liabilities are included in income tax expense. As of December 31, 2017, the Company does not have a liability for uncertain tax positions. 
+The Company files Federal and state income tax returns. Tax years for fiscal 2014 through 2016 are open and potentially subject to examination by the federal and state taxing authorities. 
+NOTE 9 — STOCKHOLDERS’ EQUITY: 
+(a) 
+Common Stock 
+In August of 2016, the Company closed on an underwritten public offering of 2,300,000 shares of its common stock at $6.00 per share. The net proceeds of the offering, after deducting the underwriters' discounts and other offering expenses payable by the Company, was approximately $12,493,000. 
+During 2017, options to purchase 56,969 shares of the Company’s common stock were exercised for 22,487 shares of common stock at exercise prices ranging from $3.48 to $4.45 by surrendering options and shares of common stock already owned . 
+During 2016, options to purchase 191,804 shares of the Company’s common stock were exercised for 98,599 shares of common stock at exercise prices ranging from $2.80 to $5.56 by paying cash or surrendering options already owned. 
+During 2015, options to purchase 41,141 shares of the Company’s common stock were exercised for 17,109 shares of common stock at exercise prices ranging from $2.16 to $3.60 by paying cash or surrendering options already owned 
+F-13 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2017, 2016, AND 2015 
+(b) 
+Preferred Stock 
+The Company has 10,000,000 shares of preferred stock authorized and none outstanding. These shares can become issuable upon an approved resolution by the board of directors and the filing of a Certificate of Designation with the state of Nevada. 
+(c) 
+Options 
+The Compensation Committee of the Board of Directors may issues options persuant to employee stock option plans that have been approved by the Company's stockholders. 
+(d) 
+Warrants 
+As of December 31, 2017 and 2016, the Company had no warrants outstanding to purchase shares of common stock. 
+NOTE 10 — RIGHTS AGREEMENT: 
+In March 2010, the Company entered into a Rights Agreement (the "Rights Agreement") between the Company and Action Stock Transfer Corp., as Rights Agent. The Rights Agreement expired at the end of November 2015. Pursuant to the Rights Agreement, the Company declared a dividend distribution of one preferred share purchase right (a "Right") for each outstanding share of Common Stock, $0.01 par value (the "Common Stock"), of the Company. The Board of Directors set the payment date for the distribution of the Rights as March 8, 2010, and the Rights were distributed to the Company’s shareholders of record on that date. The description and terms of the Rights are set forth in the Rights Agreement. 
+Rights Initially Not Exercisable. The Rights were not exercisable until a Distribution Date. Until a Right was exercised, the holder thereof, as such, would have no rights as a shareholder of the Company, including, without limitation, the right to vote or to receive dividends. 
+Separation and Distribution of Rights . The Rights were to be evidenced by the certificates for shares of Common Stock registered in the names of the holders thereof, and not by separate rights certificates until the earlier to occur of (i) the close of business on the tenth business day following a public announcement that an Acquiring Person (as defined in the Rights Agreement) acquired a Combined Ownership (as defined in the Rights Agreement) of 20% or more of the outstanding shares of the Common Stock (the "Shares Acquisition Date") or (ii) the later of (A) the close of business on the tenth business day (or such later date as may be determined by action of the Board of Directors prior to such time as any person or group of affiliated or associated persons becomes an Acquiring Person) after the date that a tender or exchange offer or intention to commence a tender or exchange offer by any person is first published, announced, sent or given within the meaning of Rule 14d-4(A) under the Securities Exchange Act of 1934, as amended, the consummation of which would result in any person having Combined Ownership of 20% or more of the outstanding shares of the Common Stock, or (B) if such a tender or exchange offer has been published, announced, sent or given before the date of the Rights Agreement, then the close of business on the tenth business day after the date the Rights Agreement was entered into (or such later date as may be determined by action of the Board of Directors prior to such time as any person becomes an Acquiring Person); (the earlier of such dates referred to in (i) and (ii), which date may include any such date that is after the date of the Rights Agreement but prior to the issuance of the Rights, being called the "Distribution Date"). 
+NOTE 11 — EMPLOYEE STOCK OPTION PLAN: 
+Effective June 3, 2008, the Company’s stockholders voted to approve the 2008 Stock Incentive Plan (“SIP”), with 750,000 shares of Common Stock available to be issued. At the Annual Stockholder meeting on September 22, 2011 the Company’s stockholders voted to approve an increase to the shares of Common Stock issuable under the SIP by 125,000 to 750,000. Under the terms of the SIP, the Compensation Committee of the Company’s Board has the discretion to select the persons to whom awards are to be granted. Awards can be stock options, restricted stock and/or restricted stock units. The awards become vested at such times and under such conditions as determined by the Compensation Committee. As of December 31, 2017, there were 480,172 options exercised, 228,177 options outstanding and 41,651 options still available to be issued under the SIP. 
+Effective June 19, 2014, the Company’s stockholders voted to approve the 2014 Stock Incentive Plan (“SIP14”), with 800,000 shares of Common Stock available to be issued. Under the terms of the SIP14, the Compensation Committee of the Company’s Board has the discretion to select the persons to whom awards are to be granted. Awards can be stock options, restricted stock and/or restricted stock units. The awards become vested at such times and under such conditions as determined by the Compensation Committee. As of December 31, 2017, there were 22,000 options exercised, 375,625 options outstanding and 402,375 options still available to be issued under the SIP14. 
+The Company's results for the years ended December 31, 2017, 2016 and 2015 include stock-based compensation expense totaling $384,897, $304,100, and $334,400 respectively. Such amounts have been included in the Consolidated Statements of Operations within cost of goods sold ($47,000, $-, and $- respectively), research and development ($89,400, $89,200, and $62,700 respectively) and selling, general and administrative expenses ($248,497, $214,900, and $271,700 respectively). 
+Stock option compensation expense in the years ended December 31, 2017, 2016 and 2015 represents the estimated fair value of options outstanding which is being amortized on a straight-line basis over the requisite vesting period of the entire award. 
+The weighted average estimated fair value of stock options granted in the years ended December 31, 2017 and 2016 were $2.77 and $2.75 per share, respectively. The Company did not grant any stock options during the year ended December 31, 2015. The fair value of options at the date of grant was estimated using the Black-Scholes option pricing model. The expected volatility is based upon historical volatility of our stock and other contributing factors. The expected term is based on the Company’s historical experience with similar type options. 
+The weighted-average assumptions made in calculating the fair values of options are as follows for the respective years ended: 
+December 31, 2017 
+December 31, 2016 
+December 31, 2015 
+Expected term (in years) 
+5.48 
+4.71 
+n/a 
+Expected volatility 
+43.31 
+% 
+45.78 
+% 
+n/a 
+Expected dividend yield 
+n/a 
+n/a 
+n/a 
+Risk-free interest rate 
+1.78 
+% 
+0.92 
+% 
+n/a 
+The Company granted 267,875 new options during the year ended December 31, 2017 to employees. 
+F-14 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2017, 2016, AND 2015 
+The following table provides stock options activity for the years ended December 31, 2017, 2016, and 2015: 
+Number of 
+Shares 
+Weighted 
+Average 
+Exercise Price per 
+Share 
+Weighted 
+Average 
+Remaining 
+Contractual 
+Term 
+Aggregate Intrinsic 
+Value 
+Outstanding at December 31, 2014 
+691,869 
+3.66 
+3.97 years 
+$ 
+334,636 
+Granted 
+- 
+- 
+Exercised 
+41,141 
+2.25 
+65,449 
+Forfeited/expired/cancelled 
+1,250 
+4.30 
+Outstanding at December 31, 2015 
+649,478 
+3.75 
+3.21 years 
+$ 
+1,032,362 
+Exercisable at December 31, 2015 
+359,228 
+3.89 
+2.03 years 
+$ 
+522,039 
+Outstanding at December 31, 2015 
+649,478 
+3.75 
+3.21 years 
+$ 
+1,032,362 
+Granted 
+142,875 
+7.08 
+Exercised 
+191,804 
+3.73 
+629,143 
+Forfeited/expired/cancelled 
+- 
+- 
+Outstanding at December 31, 2016 
+600,549 
+4.55 
+3.43 years 
+$ 
+1,463,052 
+Exercisable at December 31, 2016 
+267,549 
+4.14 
+2.66 years 
+$ 
+731,997 
+Outstanding at December 31, 2016 
+600,549 
+$ 
+4.55 
+3.43 years 
+$ 
+1,463,052 
+Granted 
+267,875 
+$ 
+6.40 
+Exercised 
+56,969 
+$ 
+4.19 
+100,018 
+Forfeited/expired/cancelled 
+785 
+$ 
+5.56 
+Outstanding at December 31, 2017 
+810,670 
+$ 
+5.18 
+3.69 years 
+$ 
+2,477,853 
+Exercisable at December 31, 2017 
+371,295 
+$ 
+4.44 
+2.62 years 
+$ 
+1,409,440 
+The following table summarizes information about stock options outstanding at December 31, 2017: 
+Stock Options Outstanding 
+Stock Options Exercisable 
+Range of 
+Exercise 
+Prices 
+Shares 
+Average 
+Remaining 
+Contract Life 
+(Year) 
+Weighted 
+Average 
+Exercise 
+Price 
+Aggregate 
+Intrinsic 
+Value 
+Shares 
+Weighted 
+Average 
+Exercise 
+Price 
+Aggregate 
+Intrinsic 
+Value 
+1 to 2.79999 
+- 
+- 
+$ 
+- 
+$ 
+- 
+- 
+$ 
+- 
+$ 
+- 
+2.8 to 4.59999 
+362,750 
+2.68 
+3.51 
+1,702,125 
+244,000 
+3.55 
+1,135,255 
+4.6 to 6.39999 
+240,045 
+3.56 
+5.73 
+592,678 
+96,545 
+5.49 
+261,585 
+6.4 to 8.19999 
+161,000 
+6.26 
+7.06 
+183,050 
+12,000 
+7.15 
+12,600 
+8.2 to 10 
+46,875 
+3.44 
+8.86 
+- 
+18,750 
+8.86 
+- 
+Total 
+810,670 
+3.69 
+$ 
+5.18 
+$ 
+2,477,853 
+371,295 
+$ 
+4.44 
+$ 
+1,409,440 
+As of December 31, 2017, there was $735,946 of net unrecognized compensation cost related to stock options that are not vested, which is expected to be recognized over a weighted average period of approximately 2.57 years. The total fair value of shares vested during the year ended December 31, 2017, was $380,465. 
+NOTE 12 — GEOGRAPHIC INFORMATION AND ECONOMIC DEPENDENCY: 
+The Company produces only one group of similar products known collectively as “rapid medical tests,” and it operates in a single business segment. Net product sales by geographic area are as follows: 
+For the years ended 
+December 31, 2017 
+December 31, 2016 
+December 31, 2015 
+Africa 
+$ 
+3,568,455 
+$ 
+2,363,944 
+$ 
+3,673,199 
+Asia 
+1,626,750 
+227,564 
+172,250 
+Europe 
+1,763,274 
+1,131,193 
+1,164,476 
+North America 
+3,887,820 
+5,082,319 
+6,525,951 
+South America 
+8,476,003 
+4,875,087 
+10,350,812 
+$ 
+19,322,302 
+$ 
+13,680,107 
+$ 
+21,886,688 
+F-15 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2017, 2016, AND 2015 
+NOTE 13 — COMMITMENTS AND CONTINGENCIES: 
+Employment Contracts: 
+The Company has multi-year contracts with two key employees. The contracts call for salaries presently aggregating $770,000 per year, and they expire in March 2019 and March 2020. The following table is a schedule of future minimum salary commitments: 
+2018 
+$ 
+770,000 
+2019 
+485,500 
+2020 
+85,000 
+Pension Plan: 
+The Company has a 401(k) plan established for its employees whereby it matches 40% of the first 5% (or 2% of salary) that an employee contributes to the plan. Matching contribution expenses totaled $91,150, $96,051 and $90,915 for the years ended December 31, 2017, 2016, and 2015, respectively. 
+Obligations Under Operating Leases: 
+The Company leases industrial space used for office, R&D and manufacturing facilities, currently with a monthly rent of $29,773. The current lease expires on April 30, 2019. The lease provides for annual increases of 2.5% percent each year starting May 1, 2016. In February of 2014, the Company entered into a lease for office and warehouse space, effective March 1, 2014, a short distance from its current facility currently with a monthly rent of $16,017. The space is used primarily for warehousing and provides for additional office space. The lease expires on April 30, 2020. The lease provides for annual increases of 3.0% percent each year starting March 1, 2016. The Company also leases office, warehouse, and manufacturing space in a single building in Kuala Lumpur, Malaysia persuant to two separate leases that each expire on April 30, 2020 and have an additional three year renewal option with combined monthly rent of approximately $3,600. 
+The following is a schedule of future minimum rental commitments for the years ending December 31, 
+2018 
+$ 
+603,335 
+2019 
+371,036 
+2020 
+84,152 
+$ 
+1,058,523 
+Rent expense was $586,730, $516,708 and $511,900 for the years ended December 31, 2017, 2016, and 2015, respectively. 
+Economic Dependency: 
+Customers are considered major customers when net sales exceed 10% of the Company's total net sales for period or outstanding trade receivables exceed 10% of current assets. The Company had the following major customers for the respective periods: 
+For the years ended 
+Accounts Receivable 
+December 31, 2017 
+December 31, 2016 
+December 31, 2015 
+December 31, 2017 
+December 31, 2016 
+Sales 
+% of Sales 
+Sales 
+% of Sales 
+Sales 
+% of Sales 
+Customer 1 
+$ 
+8,065,217 
+42 
+% 
+$ 
+4,801,577 
+35 
+% 
+$ 
+10,132,512 
+46 
+% 
+$ 
+- 
+$ 
+828,848 
+Customer 2 
+- 
+- 
+1,796,477 
+13 
+% 
+4,526,908 
+21 
+% 
+- 
+- 
+The following table delineates purchases the Company had with vendors in excess of 10% of total purchases for the periods indicated: 
+For the years ended 
+Accounts Payable 
+December 31, 2017 
+December 31, 2016 
+December 31, 2015 
+December 31, 2017 
+December 31, 2016 
+Purchases 
+% of Purc. 
+Purchases 
+% of Purc. 
+Purchases 
+% of Purc. 
+Vendor 1 
+$ 
+* 
+* 
+$ 
+652,273 
+11 
+% 
+$ 
+* 
+* 
+$ 
+* 
+$ 
+* 
+Vendor 2 
+746,868 
+12 
+% 
+* 
+* 
+* 
+* 
+* 
+* 
+Vendor 3 
+849,966 
+14 
+% 
+* 
+* 
+* 
+* 
+* 
+* 
+Vendor 4 
+884,698 
+14 
+% 
+* 
+* 
+794,536 
+11 
+% 
+* 
+* 
+In the table above, an asterisk (*) indicates that purchases from the vendor did not exceed 10% for the period indicated. 
+The Company purchases materials pursuant to intellectual property rights agreements that are important components in its products. Management believes that other suppliers could provide similar materials on comparable terms. A change in suppliers, however, could cause a delay in manufacturing and a possible loss of sales, which could adversly affect operating results. 
+F-16 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2017, 2016, AND 2015 
+NOTE 14 — QUARTERLY FINANCIAL DATA (UNAUDITED): 
+The sum of the earnings per common share may not equal the corresponding annual amounts due to interim quarter rounding. 
+For the Quarters Ended in Fiscal 2017 
+March 31 
+June 30 
+September 30 
+December 31 
+Total revenues 
+$ 
+6,325,167 
+$ 
+4,114,814 
+$ 
+7,587,374 
+$ 
+5,988,072 
+Gross product margin 
+2,208,212 
+689,099 
+2,067,934 
+1,435,896 
+Net loss 
+(1,615,574 
+) 
+(2,173,093 
+) 
+(584,661 
+) 
+(1,998,432 
+) 
+Basic loss per share 
+(0.13 
+) 
+(0.18 
+) 
+(0.05 
+) 
+(0.16 
+) 
+Diluted loss per share 
+(0.13 
+) 
+(0.18 
+) 
+(0.05 
+) 
+(0.16 
+) 
+For the Quarters Ended in Fiscal 2016 
+March 31 
+June 30 
+September 30 
+December 31 
+Total revenues 
+$ 
+6,601,099 
+$ 
+3,266,405 
+$ 
+3,746,461 
+$ 
+4,254,876 
+Gross product margin 
+2,481,468 
+347,972 
+707,733 
+725,428 
+Net loss 
+(303,590 
+) 
+(8,347,482 
+) 
+(2,138,218 
+) 
+(2,557,757 
+) 
+Basic loss per share 
+(0.03 
+) 
+(0.86 
+) 
+(0.19 
+) 
+(0.21 
+) 
+Diluted loss per share 
+(0.03 
+) 
+(0.86 
+) 
+(0.19 
+) 
+(0.21 
+) 
+NOTE 15 — NOTE PAYABLE: 
+In September 2017, the Company entered into an agreement with an equipment vendor to purchase automated assembly equipment for approximately $660,000. The terms call for prepayments of 30% down, 60% at time of factory acceptance testing and 10% after delivery. The vendor agreed to lend the Company 15%, 40%, and 10% of each originally scheduled payment, respectively. The Company will pay interest at an annual rate of 12% until delivery. Thirty days after delivery, the Company will begin making monthly payments of principal and interest of approximately $20,150, at an annual rate of 12% over a twenty-four month period. 
+NOTE 16 — SUBSEQUENT EVENT: 
+On February 13, 2018, the Company closed on an underwritten registered public offering of 1,783,760 shares of its common stock at a public offering price of $6.75 per share for gross proceeds of approximately $12.0 million. The net proceeds, after underwriting discounts and commissions, and estimated expenses are approximately $11.0 million. We intend to use the net proceeds for business expansion and working capital, including product development; operational expansion or improvements, such as new automated equipment and a facilities update; clinical trials and other related activities, and sales and marketing. 
+F-17 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+DECEMBER 31, 2017, 2016, AND 2015 
+Schedule II 
+Valuation and Qualifying Accounts 
+Additions 
+Description 
+Balance at beginning of period 
+Charged to statement of income 
+Charged to other accounts 
+Deductions 
+Balance at 
+end of period 
+Year ended December 31, 2017: 
+Allowance for doubtful accounts 
+$ 
+52,000 
+$ 
+- 
+$ 
+- 
+$ 
+10,000 
+$ 
+42,000 
+Inventory Reserve 
+$ 
+245,000 
+$ 
+119,920 
+$ 
+- 
+$ 
+170,137 
+$ 
+194,783 
+Year ended December 31, 2016: 
+Allowance for doubtful accounts 
+$ 
+52,000 
+$ 
+- 
+$ 
+- 
+$ 
+- 
+$ 
+52,000 
+Inventory Reserve 
+$ 
+218,000 
+$ 
+221,478 
+$ 
+- 
+$ 
+194,478 
+$ 
+245,000 
+Year ended December 31, 2015: 
+Allowance for doubtful accounts 
+$ 
+52,000 
+$ 
+- 
+$ 
+- 
+$ 
+- 
+$ 
+52,000 
+Inventory Reserve 
+$ 
+218,000 
+$ 
+256,302 
+$ 
+- 
+$ 
+256,302 
+$ 
+218,000 
+F-18
\ No newline at end of file
diff --git a/raw/filings/0001092662/2017/0001092662-18-000013/filing_metadata.csv b/raw/filings/0001092662/2017/0001092662-18-000013/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..da1af2673fb32b782ec38b9e728e8d08e6f4c1f4
--- /dev/null
+++ b/raw/filings/0001092662/2017/0001092662-18-000013/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0001092662,CEMI,"CHEMBIO DIAGNOSTICS, INC.",10-K,2018-03-08,2017-12-31,2018-03-08T22:23:09.000Z,0001092662-18-000013,form10_k.htm,FORM 10-K FOR 2016,7261958,1,0,https://www.sec.gov/Archives/edgar/data/1092662/000109266218000013/form10_k.htm,https://www.sec.gov/Archives/edgar/data/1092662/000109266218000013/,2017,2017,1
diff --git a/raw/filings/0001092662/2017/0001092662-18-000013/item1.txt b/raw/filings/0001092662/2017/0001092662-18-000013/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..1aa7394248a0c1962d3dfb526df16f898f553b19
--- /dev/null
+++ b/raw/filings/0001092662/2017/0001092662-18-000013/item1.txt
@@ -0,0 +1,354 @@
+ITEM 1. 
+BUSINESS 
+FORWARD-LOOKING STATEMENTS 
+This Annual Report on Form 10-K, including exhibits that are being filed as part of this report, as well as other statements made by Chembio Diagnostics, Inc. (“Chembio”, the “Company”, “we”, “us”, and “our”), contain “forward-looking statements” that include information relating to future events, future financial performance, strategies, expectations, competitive environment and regulation. Words such as “may,” “should,” “could,” “would,” “predicts,” “potential,” “continue,” “expects,” “anticipates,” “future,” “intends,” “plans,” “believes,” “estimates,” and similar expressions, as well as statements in future tense, identify forward-looking statements. 
+These forward-looking statements include such things as: investment objectives and the Company’s ability to make investments in a timely manner on acceptable terms; references to future success of the Company’s products; the Company’s business strategy; estimated future capital expenditures; sales of the Company’s products; competitive strengths and goals; and, other similar matters. 
+These forward-looking statements reflect the Company’s current beliefs and expectations with respect to future events and are based on assumptions and are subject to risks and uncertainties and other factors outside the Company’s control that may cause actual results to differ materially from those projected. Such factors include, but are not limited to, those described under Item 1A entitled “Risk Factors”, matters described elsewhere in this Report, and the following: ability to market and sell products, whether through our internal, direct sales force or third parties; ability to manufacture products in accordance with applicable specifications, performance standards and quality requirements; ability to obtain, and timing and cost of obtaining, necessary regulatory approvals for new products or new indications or applications for existing products; ability to comply with applicable regulatory requirements; ability to effectively resolve warning letters, audit observations and other findings or comments from the FDA or other regulatory entities; changes in relationships, including disputes or disagreements, with strategic partners or other parties and reliance on strategic partners for the performance of critical activities under collaborative arrangements; failure of distributors or other customers to meet purchase forecasts, historic purchase levels or minimum purchase requirements for our products; impact of replacing distributors; inventory levels at distributors and other customers; ability of the Company to achieve its financial and strategic objectives and continue to increase its revenues; ability to identify, complete, integrate and realize the full benefits of future acquisitions; impact of competitors, competing products and technology changes; reduction or deferral of public funding available to customers; competition from new or better technology or lower cost products; ability to develop, commercialize and market new products; market acceptance of our products; changes in market acceptance of products based on product performance or other factors, including changes in testing guidelines, algorithms or other recommendations by the Centers for Disease Control and Prevention and other agencies; ability to fund research and development and other products and operations; ability to obtain and maintain new or existing product distribution channels; reliance on sole supply sources for critical products and components; availability of related products produced by third parties or products required for use of our products; ability to maintain sustained profitability; volatility of the Company’s stock price; uncertainty relating to patent protection and potential patent infringement claims; uncertainty and costs of litigation relating to patents and other intellectual property; availability of licenses to patents or other technology; obstacles to international marketing and manufacturing of products; ability to sell products internationally, including the impact of changes in international funding sources and testing algorithms; adverse movements in foreign currency exchange rates; loss or impairment of sources of capital; ability to attract and retain qualified personnel; exposure to product liability and other types of litigation; changes in international, federal or state laws and regulations; customer consolidations and inventory practices; equipment failures and ability to obtain needed raw materials and components; the impact of terrorist attacks and civil unrest; changes in laws or regulations; global and regional economic conditions, including conditions affecting the credit markets, such as those resulting from the United Kingdom referendum held on June 23, 2016 in which United Kingdom voters approved an exit from the European Union; and general political, business and market conditions. 
+Although the Company believes the expectations reflected in such forward-looking statements are based upon reasonable assumptions, these are only assumptions, and forward-looking statements should not be read as a guarantee of future performance or results and will probably not be accurate indications of when such performance or results will be achieved. Investors are cautioned that forward-looking statements may not be reliable and speak only as of the date they are made and that, except as required by law, the Company undertakes no obligation to update these forward-looking statements to reflect any future events or circumstances. All subsequent written or oral forward-looking statements attributable to the Partnership or to individuals acting on its behalf are expressly qualified in their entirety by this section. 
+Investors should also be aware that while we do, from time to time, communicate with securities analysts, it is against our policy to disclose any material non-public information or other confidential commercial information to securities analysts unless and until we have made it publicly available. Accordingly, stockholders should not assume that we agree with any statement or report issued by any analyst irrespective of the content of the statement or report. Furthermore, we have a policy against issuing or confirming financial forecasts or projections issued by others. Thus, to the extent that reports issued by securities analysts contain any projections, forecasts or opinions, such reports are not the responsibility of the Company. 
+We provide free of charge on our website at www.chembio.com our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable. Additional information about us can also be found on our website. Members of the public may read and copy any materials we file with the SEC at the SEC's Public Reference Room at 100 F Street, NE, and Washington, DC 20549. Members of the public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800–SEC–0330. The Internet address of the Commission is www.sec.gov. That website contains reports, proxy and information statements and other information regarding issuers, like Chembio, that file electronically with the Commission. Visitors to the Commission's website may access such information by searching the EDGAR database. 
+For further information about these and other risks, uncertainties and factors, please review the disclosure included in this report under “Part I, Item 1A, Risk Factors.” 
+Our Business 
+General 
+Chembio Diagnostics develops, manufactures, and commercializes point-of-care (POC) diagnostic tests that are used to detect or monitor diseases. All products that are currently being developed are based on the Company’s patented DPP ® technology, a novel point-of-care diagnostic platform that offers certain customer advantages as compared to traditional lateral flow technology. POC tests, by providing prompt and early diagnosis, can reduce patient stays, lower overall costs, improve therapeutic interventions and improve patient outcomes. POC tests can also prevent needless hospital admissions, simplify testing procedures, avoid delays from central lab batching, and eliminate the need for return visits. 
+Our product commercialization and product development efforts are focused in three areas: sexually transmitted disease, tropical & fever disease, and technology collaborations. In sexually transmitted disease, we are commercializing tests for HIV and Syphilis. In tropical and fever disease, we are commercializing tests for Zika virus, dengue virus, and chikungunya virus, and developing tests for malaria, ebola, lassa, Marburg, leptospirosis, Rickettsia typhi , Burkholderia pseudomallei , and Orientia tsutsugamushi , individually or as part of a fever panel test. Through technology collaborations, we are developing tests for a specific form of cancer, concussion, bovine tuberculosis, and for an undisclosed biomarker, the latter in collaboration with global biopharmaceutical company AstraZeneca. 
+2 
+Table of Contents 
+Large and growing markets have been established for these kinds of tests, initially in high prevalence regions where they are indispensable for large scale prevention and treatment programs. Our product development is focused on areas where the availability of rapid POC screening, diagnostic, or confirmatory results can improve health outcomes. More generally, we believe there is and will continue to be a growing demand for diagnostic products that can provide accurate, actionable diagnostic information in a rapid, cost-effective manner at the point of care. 
+Our products are sold to medical laboratories and hospitals, governmental and public health entities, non-governmental organizations, medical professionals and retail establishments, both domestically and internationally, under our STAT-PAK ® , SURE CHECK ® , STAT-VIEW ® or DPP ® registered trademarks, or under the private labels of our marketing partners. 
+Our Products 
+Products: Commercially Available 
+Following is a summary of our point-of-care products, including regulatory and commercial status: 
+Product 
+Description 
+Regulatory Status 
+Commercial Status 
+DPP ® HIV 1/2 Assay 
+A rapid, point-of-care assay for the detection of HIV-1 and HIV-2 antibodies in finger stick, venous blood, serum, plasma or oral fluid 
+Premarket approval (“PMA”) by U.S. FDA 
+CLIA (Clinical Laboratory Improvement Amendments of 1988) waived 
+CE marked (European Union/Caribbean) 
+World Health Organization (“WHO”) pre-qualification 
+Agência Nacional de Vigilância Sanitária (“ANVISA”) approved (Brazil) 
+Also registered in various other countries 
+Marketed 
+DPP ® HIV-Syphilis Assay 
+A rapid, point-of-care assay for the detection of HIV-1 and HIV-2 antibodies and for antibodies to Treponema pallidum (the causative agent of Syphilis) in finger stick, venous blood, serum or plasma 
+CE marked (European Union/Caribbean) 
+ANVISA approved (Brazil) 
+Also registered in various other countries 
+Marketed 
+DPP ® Syphilis Screen and Confirm Assay 
+A rapid, point-of-care assay for the simultaneous detection of IgG and IgM antibodies to Treponema pallidum (the causative agent of Syphilis) and IgG and IgM antibodies to RPR in finger stick, venous blood, serum or plasma 
+CE marked (European Union/Caribbean) 
+Also registered in various other countries 
+Marketed 
+SURE CHECK ® HIV 1/2 Assay 
+A rapid, point-of-care assay for the detection of HIV-1 and HIV-2 antibodies in finger stick or venous blood 
+PMA approved by U.S. FDA 
+CLIA waived 
+CE marked (European Union/Caribbean) 
+WHO pre-qualification 
+Designated eligible for procurement by Global Fund 
+Also registered in various other countries 
+Marketed 
+HIV 1/2 STAT-PAK ® Assay 
+A rapid, point-of-care assay for the detection of HIV-1 and HIV-2 antibodies in finger stick, venous blood, serum or plasma 
+PMA approved by U.S. FDA 
+CLIA waived 
+CE marked (European Union/Caribbean) 
+WHO pre-qualification 
+Designated eligible for procurement by Global Fund 
+Also registered in various other countries 
+Marketed 
+DPP ® Dengue IgM/IgG Assay 
+A rapid, point-of-care assay for the simultaneous and separate detection of both IgG and IgM antibodies to Dengue virus in finger stick, venous blood, serum or plasma 
+Malaysia Medical Device Authority ("MDA") approved 
+Additional regulatory approvals pending 
+Marketed 
+DPP ® Dengue NS1 Antigen Assay 
+A rapid, point-of-care assay for the detection of NS1 antigen to Dengue virus in finger stick, venous blood, serum or plasma 
+Malaysia MDA approved 
+Additional regulatory approvals pending 
+Marketed 
+3 
+Table of Contents 
+DPP ® Zika IgM Assay 
+A rapid, point-of-care assay for the detection of IgM antibodies to Zika virus in finger stick, venous blood, serum or plasma 
+U.S. FDA Emergency Use Authorized 
+Additional regulatory approvals pending 
+Marketed 
+DPP ® Zika IgM/IgG Assay 
+A rapid, point-of-care assay for the separate and simultaneous detection of IgM and IgG antibodies to Zika virus in finger stick, venous blood, serum or plasma 
+CE marked (European Union/Caribbean) 
+ANVISA approved (Brazil) 
+Additional regulatory approvals pending 
+Marketed 
+DPP ® Chikungunya IgM/IgG Assay 
+A rapid, point-of-care assay for the separate and simultaneous detection of IgM and IgG antibodies to Chikungunya virus in finger stick, venous blood, serum or plasma 
+Malaysia MDA Approved 
+Additional regulatory approvals pending 
+Marketed 
+DPP ® Zika, Dengue, Chikungunya IgM/IgG Assay 
+A rapid, point-of-care assay for the separate and simultaneous detection of IgM and IgG antibodies to Zika, Dengue, Chikungunya virus in finger stick, venous blood, serum or plasma 
+Malaysia MDA Approved 
+Additional regulatory approvals pending 
+Marketed 
+DPP ® Vet TB Assay 
+(Veterinary Application) 
+A rapid, point-of-care assay for the detection of Mycobacterium bovis antibodies in Elk, Red Deer, White-tailed Deer and Fallow Deer 
+USDA approved 
+Marketed 
+Chagas STAT-PAK ® Assay 
+A rapid, point-of-care assay for the detection of antibodies to Trypanosoma cruzi in finger stick, venous blood, serum or plasma 
+CE marked (European Union/Caribbean) 
+Additional regulatory approvals pending 
+Marketed 
+RVR ® Dengue IgM/IgG Assay 
+A rapid, point-of-care assay for the detection of IgM and IgG antibodies to the Dengue virus in finger stick, venous blood serum or plasma 
+Malaysia MDA approved 
+Additional regulatory approvals pending 
+Marketed 
+RVR ® Dengue NS1 Assay 
+A rapid, point-of-care assay for the detection of NS1 antigen to Dengue virus in finger stick, venous blood, serum or plasma 
+Malaysia MDA approved 
+Additional regulatory approvals pending 
+Marketed 
+RVR ® Dengue Combo Assay 
+A rapid, point-of-care assay for the simultaneous and separate detection of IgG and IgM antibodies and NS1 antigen to Dengue virus in finger stick, venous blood, serum or plasma 
+Malaysia MDA approved 
+Additional regulatory approvals pending 
+Marketed 
+Products: Under Clinical Evaluation 
+Following is a summary of our point-of-care products under clinical evaluation, including regulatory and commercial status: 
+Product 
+Description 
+Regulatory Status 
+Commercial Status 
+DPP ® HIV-Syphilis Assay System 
+A rapid, point-of-care assay for the detection of HIV-1 and HIV-2 antibodies and for antibodies to Treponema pallidum (the causative agent of Syphilis) in finger stick, venous blood, serum or plasma 
+Filed Premarket Approval (“PMA”) Application to U.S. FDA 
+Not Marketed 
+DPP ® Malaria/Ebola Assay 
+A rapid, point-of-care assay for the separate and simultaneous detection of Ebola VP40 antigen and Malaria antigen P.f/P.v in finger stick, venous blood, serum or plasma 
+Under clinical evaluation 
+Not Marketed 
+DPP ® Ebola Assay 
+A rapid, point-of-care assay for the detection of Ebola VP40 antigen in finger stick, venous blood, serum or plasma 
+Under clinical evaluation 
+Not Marketed 
+DPP ® Fever Panel Assay - Africa 
+A rapid, point-of-care assay for the separate and simultaneous detection of antigens to Malaria pf/Pan species, Ebola, Lassa Fever, Marburg, Zika, Dengue and Chikungunya in finger stick, venous blood, serum or plasma 
+Under clinical evaluation 
+Not Marketed 
+Products: Under Development 
+Following is a summary of our point-of-care products under development, including regulatory and commercial status: 
+Product 
+Description 
+Regulatory Status 
+Commercial Status 
+DPP ® Malaria Antigen P.f/P.V Assay 
+A rapid, point-of-care assay for the separate detection of Malaria antigen P.F/P.V in finger stick, venous blood, serum or plasma 
+Under development 
+Not Marketed 
+4 
+Table of Contents 
+DPP ® Fever Panel Assay - Asia 
+A rapid, point-of-care assay for the separate and simultaneous detection of antigens to Malaria pf/Pan Rickettsia typhi , Orientia tsutsugamushi , Leptospira Burkholderia pseudomallei , Dengue virus, Chikungunya virus and Zika virus in finger stick, venous blood, serum or plasma 
+Under development 
+Not Marketed 
+DPP ® Undisclosed Biomarker Assay 
+A rapid, semi-quantitative point-of-care assay for an undisclosed novel biomarker in finger stick, venous blood, serum or plasma 
+Under development 
+Not Marketed 
+DPP ® Cancer Assay 
+A rapid, quantitative point-of-care assay for an undisclosed novel biomarker in finger stick, venous blood, serum or plasma 
+Under development 
+Not Marketed 
+DPP ® Concussion Assay 
+A rapid, quantitative point-of-care assay for an undisclosed novel biomarker in finger stick, venous blood, serum or plasma 
+Under development 
+Not Marketed 
+DPP ® BovidTB Assay 
+(Veterinary Application) 
+A rapid, point-of-care assay for the detection of Mycobacterium bovis antibodies in serum of cattle 
+Under development 
+Not Marketed 
+DPP ® Technology & Development 
+The Company’s commercially available products employ either our patented Dual Path Platform (DPP ® ) technology or traditional lateral flow technology. We believe products developed using the Company’s DPP ® technology can provide superior diagnostic performance compared with products that utilize traditional lateral flow technology. 
+Chembio is executing its strategy to leverage the DPP ® intellectual property, as well as the Company’s scientific and operational expertise, to create new collaborations where Chembio will serve as an exclusive development and manufacturing partner. Examples of such collaborations include the following: 
+● 
+In October 2014, we entered into an agreement with an international diagnostics company to develop a POC diagnostic test for the early detection and monitoring of a specific type of cancer. At that time, the cancer project represented the first application of the DPP ® technology outside the infectious disease field. 
+● 
+In January 2015, we entered into an agreement with the Concussion Science Group (CSG) Division of Perseus Science Group LLC to utilize our DPP ® technology to develop a POC diagnostic test for traumatic brain injury (TBI), including sports-related concussions. 
+● 
+In January 2015, we were awarded a grant from The Bill & Melinda Gates Foundation to expedite the feasibility testing and development of a DPP ® Malaria POC rapid diagnostic to accurately identify individuals infected with Plasmodium falciparum parasite. 
+● 
+In October 2015, we were awarded a grant from The Paul G. Allen Family Foundation to develop a POC test to identify multiple life-threatening febrile illnesses. Under the $2.1 million dollar grant, we used our DPP ® technology to develop a DPP ® Fever Panel Assay, a POC multiplex assay to simultaneously detect Malaria, Dengue, Zika, Chikungunya, Ebola, Lassa and Marburg. 
+● 
+In October 2015, we signed an agreement with opTricon (Berlin, Germany), a leading developer of mobile analysis devices for rapid diagnostic tests. The DPP ® Micro Reader provides customers with various options to capture, record, transmit and store test results. With one-button operation, the palm-sized and battery-operated DPP ® Micro Reader is simple, fast, portable, and cost-effective. 
+● 
+In October 2017, we signed a development agreement with AstraZeneca for the development of a quantitative point-of-care assay for a novel biomarker based on our DPP ® assay and DPP ® Micro Reader technologies. 
+Sales, Marketing & Distribution 
+We continue to target the following geographies: United States, Europe, Latin America, Africa and Southeast Asia. We reach our target markets through a combination of direct sales, strategic local distributors and OEM partners. Our efforts are focused on raising awareness of Chembio’s products and technology through global and regional marketing activities such as tradeshows and working with local key opinion leaders, local distributors, and strategic partners. We are also increasing our digital and social media activities to drive awareness of our products. 
+Competition 
+Many of our competitors are significantly larger and have greater financial, research, manufacturing, and marketing resources. Important competitive factors include product quality, analytical performance, ease of use, price, customer service and reputation. Industry competition is based on these and the following additional factors: 
+● 
+Patent protection 
+● 
+Scientific expertise 
+● 
+Ability to develop and market products and processes 
+● 
+Ability to obtain required regulatory approvals 
+● 
+Ability to manufacture cost-effective products that meet applicable regulatory requirements 
+● 
+Access to adequate capital 
+5 
+Table of Contents 
+● 
+Ability to attract and retain qualified personnel 
+We believe our scientific capabilities and proprietary know-how relating to our patented DPP ® technology and lateral flow technology are very strong, particularly for the development and manufacture of tests for the detection of antibodies to infectious diseases such as sexually transmitted diseases, fever and tropical diseases, and other diseases. 
+Our ability to develop and market other products is in large measure dependent on our having additional resources and/or collaborative relationships. Some of our product development efforts have been funded on a project or milestone basis. We believe that our proprietary know-how relating to our patented DPP ® technology has been instrumental in our obtaining the collaborations we have and that we continue to pursue. We believe that our patent protection enhances our ability to both develop more profitable, collaborative relationships and expand licensing revenue. However, there are a number of competitive technologies used and/or seeking to be used by others in point-of-care settings. 
+Although we have no specific knowledge of any other competitors’ products that could render our products obsolete, if we fail to maintain and enhance our competitive position or fail to introduce new products and product features, our customers may decide to use the products developed by our competitors, which could result in a loss of revenues and cash flow. 
+Research and Development 
+During 2017, 2016 and 2015, we spent $8.6 million, $8.4 million and $6.4 million, respectively, on research and development (including regulatory activities). These expenses were in part funded by R&D milestone and grant revenues of $4.0 million in 2017, $3.7 million in 2016 and $2.3 million in 2015. 
+Employees 
+At December 31, 2017, we employed approximately 165 people. 
+Governmental Regulation 
+Certain of our activities are subject to regulatory oversight by the Food & Drug Administration (FDA) under provisions of the Federal Food, Drug, and Cosmetic Act and regulations thereunder, including regulations governing the development, marketing, labeling, promotion, manufacturing, and export of diagnostic products. Our clinical laboratory is subject to oversight by Centers for Medicare and Medicaid Services (CMS) pursuant to CLIA (defined below), as well as agencies in various states. Failure to comply with applicable requirements can lead to sanctions, including withdrawal of products from the market, recalls, refusal to authorize government contracts, product seizures, civil money penalties, injunctions, and criminal prosecution. 
+FDA Approval/Clearance Requirements 
+Unless an exemption applies, each medical device that we market or wish to market in the U.S. must receive 510(k) clearance or Premarket Approval, or “PMA.” Medical devices that receive 510(k) clearance are “cleared” by the FDA to market, distribute, and sell in the United States. Medical devices that obtain a PMA by the FDA are “approved” to market, distribute, and sell in the United States. We cannot be sure that 510(k) clearance or PMA approval will ever be obtained for any products that have not already obtained 510(k) clearance or PMA approval. Descriptions of the PMA and 510(k) clearance processes are provided below. 
+The FDA decides whether a device line must undergo either the 510(k) clearance or PMA based on statutory criteria that utilize a risk-based classification system. PMA is the FDA process of scientific and regulatory review to evaluate the safety and effectiveness of Class III medical devices and, in many cases, Class II medical devices. Class III devices are those that support or sustain human life, are of substantial importance in preventing impairment of human health, or which present a potential, unreasonable risk of illness or injury. The FDA uses these criteria to decide whether a PMA or a 510(k) is appropriate, including the level of risk that the agency perceives is associated with the device and a determination by the agency of whether the product is a type of device that is similar to devices that are already legally marketed. Devices deemed to pose relatively less risk are placed in either Class I or II. In many cases, the FDA requires the manufacturer to submit a 510(k) requesting clearance (also referred to as a premarket notification), unless an exemption applies. The 510(k) must demonstrate that the manufacturer’s proposed device is “substantially equivalent” in intended use and in safety and effectiveness to a legally marketed predicate device. A “predicate device” is a pre-existing medical device to which equivalence can be drawn, that is either in Class I, Class II, or is a Class III device that was in commercial distribution before May 28, 1976, for which the FDA has not yet called for submission of a PMA application. 
+Device classification depends on the device’s intended use and its indications for use. In addition, classification is risk-based, that is, the risk the device poses to the patient and/or the user is a major factor in determining the class to which it is assigned. Class I includes devices with the lowest risk and Class III includes those with the greatest risk. 
+Class I devices are those for which safety and effectiveness can be assured by adherence to the FDA’s general regulatory controls for medical devices, or the General Controls, which include compliance with the applicable portions of the FDA’s quality system regulations, facility registration and product listing, reporting of adverse medical events, and appropriate, truthful and non-misleading labeling, advertising, and promotional materials. Some Class I devices also require premarket clearance by the FDA through the 510(k) process described below. 
+Class II devices are subject to the FDA’s General Controls, and any other special controls as deemed necessary by the FDA to ensure the safety and effectiveness of the device. Premarket review and clearance by the FDA for Class II devices is accomplished through the 510(k) process. Pursuant to the Medical Device User Fee and Modernization Act of 2002 (MDUFMA), as of October 2002, unless a specific exemption applies, 510(k) submissions are subject to user fees. Certain Class II devices are exempt from this premarket review process. 
+Class III includes devices with the greatest risk. Devices in this class must meet all of the requirements in Classes I and II. In addition, Class III devices cannot be marketed until they receive Premarket Approval. 
+The safety and effectiveness of Class III devices cannot be assured solely by the General Controls and the other requirements described above. These devices require formal clinical studies to demonstrate safety and effectiveness. Under MDUFMA, PMA applications (and supplemental premarket approval applications) are subject to significantly higher user fees than 510(k) applications, and they also require considerably more time and resources. 
+Rapid HIV tests intended for diagnostic use are regulated as Class III devices. Responsibility for assuring the safety and effectiveness of these tests lies within the Center for Biologics Evaluation and Research’s Office of Blood Research and Review, with oversight by the Blood Products Advisory Committee (BPAC). Approved Rapid HIV tests must meet the regulations in the 21 CFR 800 series subparts, under the Investigational Device exemption (IDE) and PMA pathways. 
+6 
+Table of Contents 
+Premarket Approval Pathway 
+We manufacture, market, and distribute three rapid HIV tests in the U.S: our HIV 1/2 STAT-PAK ® Assay, SURE CHECK ® HIV 1/2 Assay, and DPP ® HIV 1/2 Assay, all of which have received FDA PMA approval. A PMA application must be submitted if a device cannot be cleared through the 510(k) process. A PMA application must be supported by extensive data including, but not limited to, analytical, preclinical, clinical trials, manufacturing, statutory preapproval inspections, and labeling to demonstrate to the FDA’s satisfaction the safety and effectiveness of the device for its intended use. Before a PMA is submitted, a manufacturer must apply for an investigational device exemption, or “IDE.” If the device presents a “significant risk,” as defined by the FDA, to human health, the FDA requires the device sponsor to file an IDE application with the FDA and obtain IDE approval prior to initiation of enrollment of human subjects for clinical trials. The IDE provides the manufacturer with a legal pathway to perform clinical trials on human subjects where without the IDE, only approved medical devices may be used on human subjects. 
+The IDE application must be supported by appropriate data, such as analytical, animal and laboratory testing results, manufacturing information, and an Investigational Review Board (IRB) approved protocol showing that it is safe to test the device in humans and that the testing protocol is scientifically sound. If the clinical trial design is deemed to have “non-significant risk,” the clinical trial may be eligible for “abbreviated” IDE requirements; and, in some instances, IVD clinical trials may be exempt from the more burdensome IDE requirements if certain labeling requirements are met. 
+A clinical trial may be suspended by either the FDA or the IRB at any time for various reasons, including a belief that the risks to the study participants outweigh the benefits of participation in the study. Even if a study is completed, clinical testing results may not demonstrate the safety and efficacy of the device, or they may be equivocal or otherwise insufficient to obtain approval of the product being tested. After the clinical trials have been completed, if at all, and the clinical trial data and results are collected and organized, a manufacturer may complete a PMA application. 
+After a PMA application is sufficiently complete, the FDA will accept the application and begin an in-depth review of the submitted information. By statute, the FDA has 180 days to review the “accepted application,” although, generally, review of the application can take between one and three years, but it may take significantly longer. During this review period, the FDA may request additional information or clarification of information already provided. Also, during the review period, an advisory panel of experts from outside the FDA may be convened to review and evaluate the application and provide recommendations to the FDA as to the approvability of the device. The preapproval inspections conducted by the FDA include an evaluation of the manufacturing facility to ensure compliance with the Quality Systems Regulations (QSR), as well as inspections of the clinical trial sites by the Bioresearch Monitoring group to evaluate compliance with good clinical practice and human subject protections. New PMA applications or PMA supplements are required for modifications that affect the safety or effectiveness of the device, including, for example, certain types of modifications to the device’s indication for use, manufacturing process, labeling and design. Significant changes to an approved PMA require a 180-day supplement, whereas less substantive changes may utilize a 30-day notice, or a 135-day supplement. Premarket approval supplements often require submission of the same type of information as a premarket approval application, except that the supplement is limited to information needed to support any changes from the device covered by the original premarket approval application, and it may not require as extensive clinical data or the convening of an advisory panel. 
+Our HIV 1/2 STAT-PAK ® Assay PMA application number BP050009/0 and our SURE CHECK ® 1/2 HIV Assay PMA application number BP050010/0 were approved by the FDA on May 25, 2006. Our DPP ® HIV 1/2 Assay PMA application number BP120032/0 was approved by the FDA on December 19, 2012. 
+510(k) Clearance Pathway 
+We do not currently market, distribute, or sell a product that has market clearance by the FDA. However, we are currently developing products that either will or are likely to require an FDA 510(k) clearance, and we anticipate submitting a 510(k) for each such product to demonstrate that such proposed device is substantially equivalent to a respective previously cleared 510(k) device or a device that was in commercial distribution before May 28, 1976, for which the FDA has not yet called for the submission of 510(k). FDA's 510(k) clearance pathway usually takes from three to twelve months but could take longer. In some cases the FDA may require additional information, including clinical data, to make a determination regarding substantial equivalence. 
+If a device receives 510(k) clearance, any modification that could significantly affect its safety or effectiveness, or that would constitute a new or major change in its intended use, will require a new 510(k) clearance or, depending on the modification, a PMA. The FDA requires each device manufacturer to determine whether the proposed change requires submission of a new 510(k) or a PMA, but the FDA can review any such decision and can disagree with a manufacturer’s determination. If the FDA disagrees with a manufacturer’s determination, the FDA can require the manufacturer to cease marketing and/or recall the modified device until 510(k) clearance or PMA of the modified device is obtained. 
+If the FDA requires us to submit a new 510(k) or PMA for any modifications to a previously cleared product, or if we obtain 510(k) clearance for a device in the future, we may be required to submit a separate new 510(k) or PMA application for such modifications. 
+Clinical Laboratory Improvement Amendments of 1988 (CLIA) 
+A manufacturer of a test categorized as moderately complex may request that categorization of the test as waived through a CLIA Waiver by Application (CW) submission to the FDA. When a test is categorized as waived, it may be performed by laboratories with a Certificate of Waiver, such as a physician’s office outreach setting. In a CW submission, the manufacturer provides evidence to the FDA that a test meets the CLIA statutory criteria for waiver, 42 U.S.C. 263a(d)(3). Congress passed CLIA in 1988, which provided CMS authority over all laboratory testing, except research that is performed on humans in the United States. The Division of Laboratory Services, within the Survey and Certification Group, under the CMS, has the responsibility for implementing the CLIA program. 
+The CLIA program is designed to establish quality laboratory testing by ensuring the accuracy, reliability and timeliness of patient test results. Under CLIA, a laboratory is a facility that does laboratory testing on specimens derived from humans and used to provide information for the diagnosis, prevention or treatment of disease, or impairment of, or assessment of health. Under the CLIA program, unless waived, laboratories must be certified by the government, satisfy governmental quality and personnel standards, undergo proficiency testing, be subject to inspections and pay fees. We have received a CLIA waiver for both of our lateral flow rapid HIV tests that we market in the U.S. Specifically, the CLIA waiver was granted by the FDA for HIV 1/2 STAT-PAK ® on November 20, 2006 and for SURE CHECK ® HIV 1/2 on October 22, 2007. In 2008 the FDA revised its CLIA waiver requirements so that an additional prospective trial is required in order to demonstrate clinical utility by showing that the device is capable of identifying new infections when used by untrained users. Our DPP ® HIV 1/2 test received a CLIA waiver under these newer requirements on October 29, 2014. 
+7 
+Table of Contents 
+Pervasive and Continuing FDA Regulation 
+A host of regulatory requirements apply to our approved devices, including the quality system regulation (which requires manufacturers to follow elaborate design, testing, control, documentation and other quality assurance procedures), the Medical Reporting Regulations (MDR) regulations (which require that manufacturers report to the FDA specified types of adverse events involving their products), labeling regulations, and the FDA’s general prohibition against promoting products for unapproved or “off-label” uses. Class II devices also can have special controls such as performance standards, post-market surveillance, patient registries, and FDA guidelines that do not apply to Class I devices. 
+A noncomprehensive list of the regulatory requirements that apply to our approved products classified as medical devices or IVDs includes: 
+· 
+product listing and establishment registration, which helps facilitate FDA inspections and other regulatory action; 
+· 
+QSR, which requires manufacturers, including third-party manufacturers, to follow stringent design, testing, control, documentation and other quality assurance procedures during all aspects of the development and manufacturing process; 
+· 
+labeling regulations and FDA prohibitions against the promotion of products for uncleared, unapproved or off-label use or indication; 
+· 
+clearance of product modifications that could significantly affect safety or efficacy or that would constitute a major change in intended use of one of our cleared devices; 
+· 
+approval of product modifications that affect the safety or effectiveness of one of our cleared devices; 
+· 
+medical device reporting regulations, which require that manufacturers comply with FDA requirements to report if their device may have caused or contributed to a death or serious injury, or has malfunctioned in a way that would likely cause or contribute to a death or serious injury if the malfunction of the device or a similar device were to recur; 
+· 
+post-approval restrictions or conditions, including post-approval study commitments; 
+· 
+post-market surveillance regulations, which apply when necessary to protect the public health or to provide additional safety and effectiveness data for the device; 
+· 
+the FDA’s recall authority, whereby it can ask, or under certain conditions order, device manufacturers to recall from the market a product that is in violation of governing laws and regulations; 
+· 
+regulations pertaining to voluntary recalls; and, 
+· 
+notices of corrections or removals. 
+Our Medford, New York facility is currently registered as an establishment with the FDA. We and any third-party manufacturers are subject to announced and unannounced inspections by the FDA to determine our compliance with quality system regulation and other regulations. 
+21st Century Cures Act 
+The 21st Century Cures Act, enacted in December 2016, contains several sections specific to medical device innovations. The Company believes that implementation of the 21st Century Cures Act may have a positive impact on its businesses by facilitating innovation and/or reducing the regulatory burden imposed on medical device manufacturers. 
+Government Regulation of Medical Devices for Animal Subjects 
+We currently sell, market, or distribute two veterinary devices in the United States: DPP® VetTB Assay for Cervids and DPP® VetTB Assay for Elephants. Diagnostic tests for animal health infectious diseases, including our veterinary devices for the prevention and/or treatment of animal disease, are regulated in the U.S. by the Center for Veterinary Biologics within the United States Department of Agriculture (USDA) Animal and Plant Health Inspection Service (APHIS) under the Virus, Serum, and Toxin Act of 1913. As a requirement, our veterinary devices were approved by APHIS before they could be sold in the U.S. 
+The APHIS regulatory approval process involves the submission of product performance data and manufacturing documentation. Following regulatory approval to market a product, APHIS requires that each lot of product be submitted for review before release to customers. In addition, APHIS requires special approval to market products where test results are used in part for government-mandated disease management programs. 
+Environmental Laws 
+To date, we have not encountered any costs relating to compliance with any environmental laws. 
+Intellectual Property 
+Intellectual Property Strategy 
+Our intellectual property strategy is to: (1) build our own intellectual property portfolio around our DPP ® technology; (2) pursue licenses, trade secrets and know-how within the area of rapid point-of-care testing; and, (3) develop and acquire proprietary positions to certain reagents. 
+8 
+Table of Contents 
+DPP ® Intellectual Property 
+We have obtained patent coverage on our DPP ® technology, including numerous patents in the United States, China, Malaysia, Eurasia, Mexico, Singapore, Japan, Australia, Indonesia, Korea and the U.K. Additional patent applications on our DPP ® technology are pending in the U.S., as well as in many foreign countries such as Brazil, Canada, the European Union, India, Israel, and South Africa. 
+The DPP ® technology provides us with our own intellectual property. We believe it provides us with freedom to operate, which enables us to develop tests with better performance and unmatched capabilities compared with tests built on traditional lateral flow platforms. These advantages have allowed us to enter into multiple technology collaborations based upon the DPP ® technology, which we believe will provide new manufacturing and marketing opportunities. We have filed other patent applications that we believe will strengthen the DPP ® intellectual property and have also filed for patent protection for certain other point-of-care technologies or applications thereof. 
+Trademarks 
+We have filed and obtained trademarks for our products, including DPP ® , SURE CHECK ® , STAT-VIEW ® , and STAT-PAK ® , as well as for the SampleTainer ® , which is used with certain DPP ® products. Our trademarks have been obtained in the United States and certain other countries around the world. 
+Trade Secrets and Know-How 
+We have developed a substantial body of trade secrets and know-how relating to the development and manufacture of lateral flow and DPP ® -based diagnostic tests, including but not limited to the sourcing and optimization of materials for such tests, and methods to maximize sensitivity, speed-to-result, specificity, stability and reproducibility of our tests. We possess proprietary know-how to develop tests for multiple conditions using colored particles. Our formulations enable long shelf lives of our rapid HIV and other tests, providing us with an important competitive advantage. 
+Lateral Flow Technology and Reagent Licenses 
+As of February 3, 2015 the royalty expenses related to certain lateral flow technology expired. These now allow us to produce STAT-PAK ® , SURE CHECK ® , STAT-VIEW ® , DIPSTICK ® , and veterinary product lines free of those royalties. 
+Although we believe our DPP ® IP is outside of the scope of all lateral flow patents of which we are aware, we consult with patent counsel, and seek licenses and/or redesigns of products that we believe to be in our best interests. Because of the costs and other negative consequences of time-consuming patent litigation, we often attempt to obtain a license on reasonable terms. Nevertheless, there is no assurance that the Alere lateral flow patents we have licensed will not be challenged or that other patents containing claims relevant to our lateral flow or DPP ® products will not be granted to third parties and that licenses to such patents, will be available on reasonable terms, if any. 
+The peptides used in our rapid HIV tests were licensed to us by one or more third parties. We also have licensed the antigens used in other tests including our Syphilis, Tuberculosis, Leptospirosis, Leishmaniasis and Chagas tests, and we may enter other license agreements. In prior years, we concluded license agreements related to intellectual property rights owned by the United States associated with HIV-1, and, during the first quarter of 2008, we entered into a sub-license agreement for HIV-2 with Bio-Rad Laboratories N.A., the exclusive licensee of the Pasteur Institute's HIV-2 intellectual property estate. 
+Corporate Information 
+We are a Nevada corporation that was formed in December 1985. Since inception, we have been involved in developing, manufacturing, selling and distributing medical diagnostic tests, including rapid tests that detect a number of diseases and other conditions in humans and animals. 
+Stockholder Rights Agreement 
+On March 8, 2016, we entered into a Rights Agreement (the "Rights Agreement") between us and Action Stock Transfer Corp., as Rights Agent. Pursuant to the Rights Agreement, we declared a dividend distribution of one Preferred Share Purchase Right (a "Right") for each outstanding share of our common stock, par value $0.01 (the "Common Stock"), in the manner described below. The Board of Directors set the payment date for the distribution of the Rights as March 8, 2016, and the Rights were distributed to our shareholders of record on that date. The Rights Agreement also provides that Rights are issued with respect to any shares of our common stock that are newly issued after March 8, 2016, such as with respect to the Company's underwritten public offering in February 2018. The description and terms of the Rights are set forth in the Rights Agreement. 
+Rights Initially Not Exercisable 
+The Rights are not exercisable until a Distribution Date. Until a Right is exercised, the holder thereof, as such, has no rights as a shareholder of the Company, including, without limitation, the right to vote or to receive dividends. 
+Separation and Distribution of Rights 
+The Rights are to be evidenced by the certificates for shares of Common Stock registered in the names of the holders thereof, and not by separate rights certificates until the earlier to occur of (i) the close of business on the tenth business day following a public announcement that an Acquiring Person (as defined in the Rights Agreement) has acquired a Combined Ownership (as defined in the Rights Agreement) of 20% or more of the outstanding shares of the Common Stock (the "Shares Acquisition Date") or (ii) the later of (A) the close of business on the tenth business day (or such later date as may be determined by action of the Board of Directors prior to such time as any person or group of affiliated or associated persons becomes an Acquiring Person) after the date that a tender or exchange offer or intention to commence a tender or exchange offer by any person is first published, announced, sent or given within the meaning of Rule 14d-4(A) under the Securities Exchange Act of 1934, as amended, the consummation of which would result in any person having Combined Ownership of 20% or more of the outstanding shares of the Common Stock, or (B) if such a tender or exchange offer has been published, announced, sent or given before the date of the Rights Agreement, then the close of business on the tenth business day after the date the Rights Agreement was entered into (or such later date as may be determined by action of the Board of Directors prior to such time as any person becomes an Acquiring Person); (the earlier of such dates referred to in (i) and (ii), which date may include any such date that is after the date of the Rights Agreement but prior to the issuance of the Rights, being called the "Distribution Date"). 
+9 
+Table of Contents 
+Glossary 
+AIDS 
+Acquired Immunodeficiency Syndrome. AIDS is caused by the Human Immunodeficiency Virus, HIV. 
+ALGORITHM (parallel or serial) 
+For rapid HIV testing, this refers both to method or protocol (in developing countries to date) for using rapid tests from different manufacturers in combination to screen and confirm patients at the point-of-care, and may also refer to the specific tests that have been selected by an agency or ministry of health to be used in this way. A parallel algorithm uses two screening tests from different manufacturers and a tie-breaker test only if there is a discrepancy between the screening tests results. A serial algorithm only uses a second confirmatory test if there is a positive result from the screening test, meaning that the number of confirmatory tests used is equal to the positivity rate in the testing venue. A tie-breaker test resolves discrepancies between the screen and the confirmatory test. 
+ANTIBODY 
+A protein which is a natural part of the human immune system produced by specialized cells to neutralize antigens, including viruses and bacteria that invade the body. Each antibody-producing cell manufactures a unique antibody that is directed against, binds to and eliminates one, and only one, specific type of antigen. 
+ANTIGEN 
+Any substance which, upon entering the body, stimulates the immune system leading to the formation of antibodies. Among the more common antigens are bacteria, pollens, toxins, and viruses. 
+ANVISA 
+The National Health Surveillance Agency of Brazil. 
+ARVs 
+Anti-retroviral medications developed to fight AIDS. 
+CDC 
+United States Centers for Disease Control and Prevention. 
+CLIA waiver 
+Clinical Laboratory Improvement Act designation that allows simple tests to be performed in point-of-care settings such as doctor’s offices, walk-in clinics and emergency rooms. 
+DIAGNOSTIC 
+Pertaining to the determination of the nature or cause of a disease or condition. Also refers to reagents or procedures used in diagnosis to measure proteins in a clinical sample. 
+FIOCRUZ 
+The Oswaldo Cruz Foundation of Brazil. 
+FDA 
+United States Food and Drug Administration. 
+IgG 
+IgG or Immunoglobulin are proteins found in human blood. This protein is called an “antibody” and is an important part of the body’s defense against disease. When the body is attacked by harmful bacteria or viruses, antibodies help fight these invaders. 
+IgM 
+IgM or Immunoglobulin M are proteins found in human blood. This protein is called an "antibody" and is an important part of the body's defense against disease. When the body is attacked by harmful bacteria or viruses, antibodies help fight these invaders. 
+NGO 
+Non-Governmental Organization. 
+OTC 
+Over-the-Counter. 
+PEPFAR 
+The President’s Emergency Plan for AIDS Relief. 
+PMA 
+Pre-Marketing Approval –FDA approval classification for a medical device that is not substantially equivalent to a legally marketed device or is otherwise required by statute to have an approved application. Rapid HIV tests must have an approved PMA application before marketing of such a product can begin. 
+PROTOCOL 
+A procedure pursuant to which an immunodiagnostic test is performed on a particular specimen in order to obtain the desired reaction. 
+REAGENT 
+A chemical added to a sample under investigation in order to cause a chemical or biological reaction which will enable measurement or identification of a target substance. 
+RETROVIRAL 
+A type of virus which contains the enzyme Reverse Transcriptase and is capable of transforming infected cells to produce diseases in the host such as AIDS. 
+SENSITIVITY 
+Refers to the ability of an assay to detect and measure small quantities of a substance of interest. The greater the sensitivity, the smaller the quantity of the substance of interest the assay can detect. Also refers to the likelihood of detecting the antigen when present. 
+SPECIFICITY 
+The ability of an assay to distinguish between similar materials. The greater the specificity, the better an assay is at identifying a substance in the presence of substances of similar makeup. 
+USDA 
+U.S Department of Agriculture. 
+WHO 
+World Health Organization.
\ No newline at end of file
diff --git a/raw/filings/0001092662/2017/0001092662-18-000013/item13.txt b/raw/filings/0001092662/2017/0001092662-18-000013/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..2121b5c3009e5988e5ae56a840f67991e6abddac
--- /dev/null
+++ b/raw/filings/0001092662/2017/0001092662-18-000013/item13.txt
@@ -0,0 +1,2 @@
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE. 
+The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.
\ No newline at end of file
diff --git a/raw/filings/0001092662/2017/0001092662-18-000013/item9a.txt b/raw/filings/0001092662/2017/0001092662-18-000013/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..5e4bfda3acacc38febe71a9c25ef3a17670fb919
--- /dev/null
+++ b/raw/filings/0001092662/2017/0001092662-18-000013/item9a.txt
@@ -0,0 +1,36 @@
+ITEM 9A. CONTROLS AND PROCEDURES 
+(a) Disclosure Controls and Procedures. Under the supervision and with the participation of our senior management, consisting of our chief executive officer and our chief financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)), as of the end of the period covered by this report (the "Evaluation Date"). Based on that evaluation, the Company’s management, including our chief executive officer and chief financial officer, concluded that as of the Evaluation Date our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports that we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. Our disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in our Exchange Act reports is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure. 
+Management's Annual Report on Internal Control Over Financial Reporting. The Company's management is responsible for establishing and maintaining an adequate system of internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f)). Our internal control over financial reporting is a process, under the supervision of our chief executive officer and chief financial officer, designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States. These internal controls over financial reporting processes include policies and procedures that: 
+a. Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company; 
+b. Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and 
+c. Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance of achieving their control objectives. 
+31 
+Table of Contents 
+Management’s Report on Internal Control over Financial Reporting 
+Management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f). The Company has designed its internal control over financial reporting to provide reasonable assurance on the reliability of financial reporting and the preparation of the consolidated financial statements in accordance with U.S. generally accepted accounting principles. 
+The Company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting can only provide reasonable assurance and may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+Under the supervision and with the participation of our management, including the Chief Executive Officer (CEO) and the Chief Financial Officer (CFO), we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2017, based on the framework and criteria in the 2013 Internal Control – Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on management’s evaluation and those criteria, the CEO and CFO concluded that its system of internal control over financial reporting was effective as of December 31, 2017. 
+BDO USA, LLP, the Company's independent registered public accounting firm that audited the Company's consolidated financial statements included in this report, has issued an attestation report on the effectiveness of the Company's internal control over financial reporting, a copy of which appears on the following page. 
+32 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+Shareholders and Board of Directors 
+Chembio Diagnostics, Inc. 
+Medford, New York 
+Opinion on Internal Control over Financial Reporting 
+We have audited Chembio Diagnostics, Inc.’s (the “Company’s”) internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on the COSO criteria. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company and subsidiaries as of December 31, 2017 and 2016, the related consolidated statements of operations, comprehensive loss, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes and schedule and our report dated March 8, 2018 expressed an unqualified opinion thereon. 
+Basis for Opinion 
+The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying “Item 9A, Management’s Report on Internal Control over Financial Reporting”. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audit of internal control over financial reporting in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+Definition and Limitations of Internal Control over Financial Reporting 
+A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+/s/ BDO USA, LLP 
+New York, NY 
+March 8, 2018 
+33 
+Table of Contents 
+(b) Changes in Internal Control over Financial Reporting. There were no changes in our internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Rule 13a-15 or Rule 15d-15 under the Exchange Act that occurred during the Company’s last fiscal quarter of the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
\ No newline at end of file
diff --git a/raw/filings/0001092662/2017/0001092662-18-000013/rp_note.txt b/raw/filings/0001092662/2017/0001092662-18-000013/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0001092662/2017/0001092662-18-000013/rpt_disclosure.txt b/raw/filings/0001092662/2017/0001092662-18-000013/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..01844cf13b79da7483478f6e57124f3a5d29c6b0
--- /dev/null
+++ b/raw/filings/0001092662/2017/0001092662-18-000013/rpt_disclosure.txt
@@ -0,0 +1,16 @@
+Approval of Transactions with Related Persons 
+The Board of Directors reviews all transactions
+involving us in which any of our directors, director nominees, significant stockholders and executive officers and their immediate
+family members are participants to determine whether such person has a direct or indirect material interest in the transaction. 
+All directors, director nominees and executive officers must notify us of any proposed transaction involving us in which such person
+has a direct or indirect material interest. Such proposed transaction is then reviewed by either the Board as a whole or the Audit
+Committee, which determines whether to approve the transaction. After such review, the reviewing body approves the transaction
+only if it determines that the transaction is in, or not inconsistent with, the best interests of the Company and its stockholders. 
+Director Independence 
+Our common stock trades on the NASDAQ. 
+Accordingly, we are subject to the corporate governance standards of NASDAQ, which require, among other things, that a majority
+of the board of directors be independent. We define an "independent" director in accordance with the NASDAQ Global Market's
+requirements for independent directors. Under this definition, we have determined that each of Katherine Davis, Gail Page,
+and Peter Kissinger currently qualifies as an independent director. If John Potthoff is elected to the Board of Directors,
+the Board of Directors believes Dr. Potthoff would qualify as an independent director. We do not list the "independent"
+definition we use on our internet website.
\ No newline at end of file
diff --git a/raw/filings/0001092662/2018/0001140361-19-005069/filing.txt b/raw/filings/0001092662/2018/0001140361-19-005069/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..0a5946b2bc2b8785d7d7404280cfc2d04eaf163e
--- /dev/null
+++ b/raw/filings/0001092662/2018/0001140361-19-005069/filing.txt
@@ -0,0 +1,3629 @@
+10-K
+1
+form10_k.htm
+UNITED STATES 
+Securities and Exchange Commission 
+Washington, D.C. 20549 
+FORM 10-K 
+[X] 
+ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the fiscal year ended December 31, 2018 
+or 
+[ ] 
+TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the transition period from _______ to
+______ . 
+Commission File No. 0-30379 
+CHEMBIO DIAGNOSTICS, INC. 
+(Exact name of registrant as specified in its charter) 
+Nevada 
+88-0425691 
+(State or other jurisdiction of incorporation or organization) 
+(I.R.S. Employer Identification No.) 
+3661 Horseblock Road, Medford, NY 
+11763 
+(Address of principal executive offices) 
+(Zip Code) 
+Registrant’s telephone number, including area code (631) 924-1135 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of each class 
+Name of each exchange on which registered 
+Common Stock, $0.01 par value 
+The NASDAQ Stock Market LLC 
+Securities registered pursuant to Section 12(g) of the Act: 
+None 
+(Title of Class) 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes __ No X 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes __ No X 
+Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
+during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No__ 
+Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of
+Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes X No __ 
+Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and
+will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an
+emerging growth company. See the definitions of "large accelerated filer", "accelerated filer", "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act. 
+Large accelerated filer [ ] 
+Accelerated filer [X ] 
+Non-accelerated filer [ ] 
+Smaller reporting company [X ] 
+Emerging growth company [ ] 
+If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or
+revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act [ ] 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes __ No X 
+As of the last business day of the registrant's most recently completed second fiscal quarter, the aggregate market value of voting and non-voting common
+equity held by non-affiliates was $154,594,062. 
+As of March 1, 2019, the registrant had 17,166,459 shares of common stock outstanding. 
+Documents Incorporated By Reference 
+Portions of the registrant’s proxy statement for its 2019 annual meeting of stockholders are incorporated by reference in
+Part III of this report. 
+TABLE OF CONTENTS 
+Page 
+PART I 
+ITEM 1. 
+BUSINESS 
+3 
+ITEM 1A. 
+RISK FACTORS 
+9 
+ITEM 2. 
+PROPERTIES 
+21 
+ITEM 3. 
+LEGAL PROCEEDINGS 
+21 
+PART II 
+ITEM 5. 
+MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+22 
+ITEM 7. 
+MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+23 
+ITEM 8. 
+FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+28 
+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+28 
+PART III 
+ITEM 10. 
+DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
+30 
+ITEM 11. 
+EXECUTIVE COMPENSATION 
+30 
+ITEM 12. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+30 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+30 
+ITEM 14. 
+PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+30 
+PART IV 
+ITEM 15. 
+EXHIBITS, FINANCIAL STATEMENT SCHEDULES 
+31 
+SIGNATURES 
+32 
+Unless the context requires otherwise, the words “our,” “our company,” “us,” “we” and similar terms refer to Chembio Diagnostics, Inc. and its consolidated subsidiaries. 
+DPP, SAMPLETAINER, STAT-PAK, STAT-VIEW and SURE CHECK are our registered trademarks. For
+convenience, these trademarks appear in this prospectus supplement without ® symbols, but that practice does not mean that we will not assert, to the fullest extent under applicable law, our rights to the trademarks. This report also
+includes trademarks and service marks owned by other organizations. 
+FORWARD-LOOKING STATEMENTS AND STATISTICAL ESTIMATES 
+This report contains statements reflecting our views
+about our future performance that constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are generally identified through the inclusion of words such as
+“anticipate,” “believe,” “contemplate,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “objective,” “outlook,” “plan,” “potential,” “project,” “seek,” “should,” “strategy,” “target,” “will,” “would” or variations of such words or
+similar expressions. All statements addressing our future operating performance, and statements addressing events and developments that we expect or anticipate will occur in the future, are forward-looking statements within the meaning of the
+Private Securities Litigation Reform Act of 1995. Forward-looking statements are based upon currently available information, operating plans, and projections about future events and trends. 
+This report contains estimates, projections and other
+data concerning our industry, our business, and the markets for our products. Where expressly stated, we obtained this industry, business, market and other data from reports, research surveys, studies and similar data prepared by World Health
+Organization, or WHO. We also include data that we have compiled, obtained, identified or otherwise derived from reports, research surveys, studies and similar data prepared by market research firms and other third parties, industry, medical and
+general publications, government data and similar sources. Other than WHO, we do not expressly refer to the sources from which this data is derived. 
+Forward-looking statements and statistical estimates inherently
+involve risks and uncertainties that could cause actual results to differ materially from those predicted or expressed in this report. These risks and uncertainties include those described below in “Item 1A. Risk Factors.” Investors are cautioned
+not to place undue reliance on any forward-looking statements or statistical estimates, which speak only as of the date they are made. We undertake no obligation to update any forward-looking statement or statistical estimate, whether as a result
+of new information, future events or otherwise. 
+2 
+Table of Contents 
+PART I 
+ITEM 1. 
+BUSINESS 
+Overview 
+We are a leading provider of point-of-care diagnostic products for the detection and
+diagnosis of infectious diseases. We have been expanding our product portfolio based upon our proprietary Dual Path Platform, which we refer to as the DPP technology platform, which uses a small drop of blood from the fingertip to provide
+high-quality, cost-effective diagnostic results in approximately 15 minutes. We seek to build additional revenue streams by entering into technology collaborations with leading global healthcare companies to leverage the DPP platform. 
+Compared with traditional lateral flow technology, the DPP technology platform provides
+enhanced sensitivity and specificity, advanced multiplexing capabilities, and, when used with the DPP Micro Reader, quantitative results. Our DPP test for human immunodeficiency virus, or HIV, provides sensitivity of 99.8% and specificity of 100%,
+and has been approved by the U.S. Food and Drug Administration, or FDA, and cleared as a waived test under the Clinical Laboratory Improvement Amendments of 1988, or CLIA. On November 6, 2018, we completed our acquisition of opTricon GmbH, a
+Berlin-based developer and manufacturer of handheld analyzers for rapid diagnostic tests, which we believe will enable us to promote DPP tests and DPP Micro
+Readers more actively across global markets. 
+We are pursuing three corporate priorities, the key building blocks to drive growth and operating
+efficiency: ( 1) expand our commercialization; (2) advance our research and development pipeline; and (3) prepare for future growth. 
+Industry 
+The DPP technology platform addresses the lateral flow test market, which includes
+infectious diseases, cardiac markers, cholesterol and lipids, pregnancy and fertility, and drugs of abuse. Based on our review of third-party reports and other information, we estimate that the market for lateral flow tests will increase from $5.5
+billion in 2017 to $8.2 billion in 2022, representing a compound annual growth rate of 8.2%. 
+Infectious disease tests constitute the largest, and fastest growing, segment of the
+lateral flow test market. We currently are targeting lateral flow test solutions for three areas of infectious diseases: sexually transmitted disease, mosquito-borne disease and hepatitis. The market for lateral flow infectious disease tests is
+being driven by the high prevalence of infectious diseases globally, an increase in the geriatric population, growing demand for rapid test results, and advancements in multiplexing. Based on our review of third-party reports and other information,
+we estimate that the market for lateral flow infectious disease tests will increase from $1.4 billion in 2017 to $2.3 billion in 2022, representing a compound annual growth rate of 10.7%. 
+Products 
+Our point-of-care infectious disease portfolio is comprised of multiple commercial products, each
+serving unique customer requirements. The key advantages of our products, which are performed with a tiny drop of blood from the fingertip and provide results in approximately 15 minutes, include: 
+• 
+enhanced sensitivity and specificity; 
+• 
+advanced multiplexing; and 
+• 
+quantitative results, when used with DPP Micro Reader. 
+We have obtained U.S. FDA approvals and, directly or through our partners, international
+regulatory approvals for infectious disease tests as follows: 
+Product (Assay) 
+U.S. 
+International 
+DPP HIV 1/2 
+✓ 
+✓ 
+DPP HIV-Syphilis 
+✓ 
+DPP Syphilis Screen & Confirm 
+✓ 
+DPP Zika 
+✓ 
+✓ 
+DPP Leishmaniasis 
+✓ 
+STAT-PAK HIV 1/2 
+✓ 
+✓ 
+STAT-PAK Chagas 
+✓ 
+SURE CHECK HIV 1/2 
+✓ 
+✓ 
+SURE CHECK HIV 1/2 Self Test 
+✓ 
+Organic growth in our core infectious disease business is being driven by: 
+• 
+growth in the overall market for lateral flow infectious disease tests, which we estimate will increase at a
+compound annual growth rate of 10.7% through 2022 (see “--Industry” above); 
+• 
+our increased market penetration in existing markets and channels, including in the United States, Latin America,
+Africa and Europe; 
+• 
+our registration of existing and new products in unchartered countries and regions, such as selected countries in
+Latin America and Southeast Asia; 
+• 
+our entry into new market segments, such as international HIV Self-Testing; and 
+• 
+advances in our product pipeline in infectious disease with key products including a multiplex test for HIV and
+syphilis in the U.S. market and tests for dengue, zika and chikungunya. 
+We market and sell both stand-alone and multiplex tests for sexually transmitted infectious diseases, such as
+HIV and syphilis. HIV and syphilis continue to be major global public health issues. According to WHO estimates: 
+• 
+HIV has claimed more than 35 million lives, including 940,000 in 2017. Approximately 36.9 million were
+living with HIV at the end of 2017, and 1.8 million were newly infected during 2017. 
+• 
+There were 18.0 million prevalent cases of syphilis as of 2012, and 5.6 million new infections were
+estimated to occur annually. 
+• 
+Elimination of
+mother-to-child transmission, or MTCT, of both HIV and syphilis is a global health priority. In 2013, 1.9 million pregnant women were infected with syphilis worldwide. Congenital syphilis contributes significantly to infant
+mortality, accounting for 305,000 annual perinatal deaths worldwide in 2013. Globally, more than 1.4 million pregnant women were infected with HIV as of 2015, and MTCT of HIV is estimated to have resulted in over 150,000 infant cases in
+2015. 
+We are seeking to address the global concerns related to HIV and syphilis co-infection
+through the development of a novel, multiplex test for both HIV and syphilis. We have developed a DPP HIV-Syphilis multiplex test and received regulatory approvals covering a number of international markets, including Brazil, Europe, Malaysia and
+Mexico. In the United States we have completed a DPP HIV-Syphilis clinical trial and filed a Pre-Market Approval Application with the FDA, which is in the review process. We believe we are well-positioned to be the first company to introduce a
+multiplex rapid test for HIV and syphilis in the United States. 
+We also market and sell tests for selected fever and tropical diseases such as
+Chagas, ebola, leishmaniasis and Zika. The market for lateral flow mosquito-borne diseases includes established markets for disease such as dengue and malaria, which WHO estimates together account for more than 600 million annual infections
+worldwide. There are also a number of emerging markets for lateral flow tests for infectious diseases such as burkholderia, chikungunya, lassa, leptospirosis, Marburg, rickettsia and Zika. We are developing tests, using the DPP platform, to detect
+all of the aforementioned fever and tropical diseases, as stand-alone or multiplex tests. 
+Since 2015 we have received over $9 million of funding from some of the world ’ s leading health organizations, which has helped us accelerate the expansion of our pipeline of infectious disease tests. Our collaborators have included Bill
+& Melinda Gates Foundation, The Paul G. Allen Family Foundation, The Oswaldo Cruz Foundation or FIOCRUZ, and the Foundation for Innovative New Diagnostics or FIND, as well as U.S. government agencies such as Centers for Disease Control, or CDC,
+and the Biomedical Advanced Research and Development Authority of the U.S. Department of Health and Human Services or BARDA, and the U.S. Department of Agriculture, or USDA. Many of the tests in our infectious disease pipeline are approaching
+commercialization, and several have received initial regulatory approvals: 
+Product 
+Collaborator 
+Phase I 
+Feasibility 
+Phase II 
+Development 
+Phase III 
+Verification 
+&Validation 
+Phase IV 
+Clinical/ 
+Regulatory 
+Phase V 
+Commercial 
+Launch 
+DPP HIV-Syphilis (US) 
+Self-funded 
+✓ 
+✓ 
+✓ 
+Submitted FDA 
+Q1 2018 
+DPP Dengue (International) 
+Fiocruz 
+✓ 
+✓ 
+✓ 
+Submitted ANVISA 1 
+Q3 2018 
+DPP Dengue NS1 (International) 
+Fiocruz 
+✓ 
+✓ 
+Ongoing 
+DPP Zika (US/International) 
+Fiocruz 
+✓ 
+✓ 
+✓ 
+✓ 
+Received 
+FDA EUA 2 , 
+ANVISA, CE mark 
+DPP Chikungunya (International) 
+Fiocruz 
+✓ 
+✓ 
+✓ 
+✓ 
+Received 
+ANVISA, Malaysia 
+DPP Dengue-Zika- Chikungunya (International) 
+Fiocruz 
+✓ 
+✓ 
+✓ 
+Submitted ANVISA 
+Q3 2018 
+Received 
+Malaysia 
+DPP Malaria (International) 
+Bill & Melinda Gates Foundation 
+✓ 
+✓ 
+Ongoing 
+DPP Ebola (US, International) 
+Centers for Disease Control 
+✓ 
+✓ 
+✓ 
+Received FDA EUA Q4 2018 
+DPP Fever Panel (Africa) 
+The Paul G. Allen Family Foundation 
+✓ 
+✓ 
+✓ 
+Field Testing: 
+Africa, South America 
+DPP Fever Panel (Asia) 
+FIND 
+✓ 
+Ongoing 
+____________________________ 
+1 Ag ê ncia Nacional de Vigil â ncia Sanit á ria (Brazil) 
+2 Emergency Use Authorization 
+Collaborations 
+We are building additional revenue streams by leveraging our patented DPP technology and
+scientific expertise through collaborations. Leading global healthcare organizations have chosen to collaborate with us based on our deep scientific expertise with our proven DPP technology platform and capabilities, our successful record of
+developing DPP tests with a diverse set of collaborators including global commercial companies, governments and non-governmental organizations, and our extensive experience in obtaining regulatory approvals in the United States (FDA), Brazil
+(ANVISA), the European Union (CE mark) and Mexico (Comisión Federal para la Protección contra Riesgos Sanitarios, or COFEPRIS) as well as from WHO (Prequalification, or PQ). 
+Product 
+Collaborator 
+Phase I 
+Feasibility 
+Phase II 
+Development 
+Phase III 
+Verification 
+&Validation 
+Phase IV 
+Clinical/ 
+Regulatory 
+Phase V 
+Commercial 
+Launch 
+DPP Eosinophilic / Respiratory 
+AstraZeneca 
+✓ 
+✓ 
+Ongoing 
+Received CE mark Q4 2018 
+DPP Cancer 
+Undisclosed 
+✓ 
+✓ 
+Ongoing 
+Infectious Disease Portfolio 
+LumiraDx 
+Initiated Q3 2018 
+DPP Concussion 
+Perseus Science 
+✓ 
+Ongoing 
+DPP Bovine Tuberculosis 
+USDA 
+✓ 
+Ongoing 
+DPP Hepatitis C Ab 
+FIND 
+✓ 
+Ongoing 
+DPP Hepatitis C Ag 
+FIND 
+Initiated Q3 2018 
+By leveraging our DPP technology platform, we are creating opportunities
+to expand into new markets such as cancer diagnostics, concussion and traumatic brain injury, and veterinary and we are broadening the application of our technology from point-of-care diagnostics to include companion diagnostics. Research and
+development costs related to the collaborations are fully funded by our collaborators. 
+Sales Channels 
+Our products are sold globally, both directly and through distributors, to hospitals and
+clinics, physician offices, clinical laboratories, public health organizations, government agencies and consumers. Historically we marketed and sold our products only into a handful of countries and regions. In recent years we have hired sales
+executives to begin building our own channels in key markets such as the United States, Europe, Latin America, Africa and Southeast Asia. With sales growth as an underlying objective, we are focused on increasing sales in existing geographies,
+expanding sales into new geographies, and broadening sales coverage in key markets. 
+Automation of U.S. Manufacturing 
+We are automating our U.S. manufacturing processes and expanding our manufacturing
+capacity. During 2018, we took delivery of our first automated manufacturing line. This automated manufacturing line will be used for DPP test production and will allow assembly of various configurations of DPP tests on the line. The automated line
+will have an annual capacity of between five and ten million tests, depending on the test configuration, and will use vision-guided, robotic operation to improve inspection and quality control. As we transition from manual to automated assembly, we
+believe the reduced variable costs will improve product gross margins. 
+3 
+Table of Contents 
+DPP Technology & Development 
+Our commercially available products employ either our patented DPP technology or traditional lateral flow technology. We believe products developed using
+our DPP technology can provide superior diagnostic performance compared with products that utilize traditional lateral flow technology. 
+We are executing our strategy to leverage DPP intellectual property, as well as our scientific and operational expertise, to create new collaborations where
+we will serve as an exclusive development and manufacturing partner. Examples of such collaborations include the following: 
+• 
+In January 2015, we entered into an agreement with the Concussion Science Group (CSG) Division of Perseus Science
+Group LLC to develop a point-of-care diagnostic test for traumatic brain injury, including sports-related concussions, utilizing both our DPP and optical analyzer technologies. 
+• 
+In October 2017, we signed a development agreement with AstraZeneca for the development of a quantitative point-of-care test for eosinophilic
+respiratory disease, utilizing both our DPP and optical analyzer technologies. 
+• 
+In April 2018, we entered into a collaboration agreement with LumiraDx to develop new point-of-care diagnostic tests for infectious diseases. Under terms of the agreement, we receive
+funding from LumiraDx, subject to satisfying certain milestones, to develop certain new point-of-care infectious disease tests. Following the regulatory approval and commercialization of tests in accordance with this agreement,
+Chembio will both sell reagents to, and receive royalty payments from, LumiraDx on sales of all products developed through this collaboration. 
+• 
+In November 2018, we acquired opTricon (Berlin, Germany), a leading developer of handheld optical analyzers rapid diagnostic tests. See
+“Management’s Discussion & Analysis of Financial Condition and Results of Operations—Recent Developments.” 
+Competition 
+Many of our competitors are significantly larger and have greater financial, research, manufacturing, and marketing resources. Important competitive factors
+include product quality, analytical performance, ease of use, price, customer service and reputation. Industry competition is based on these and the following additional factors: 
+• 
+patent protection; 
+• 
+scientific expertise; 
+• 
+ability to develop and market products and processes; 
+• 
+ability to obtain required regulatory approvals; 
+• 
+ability to manufacture cost-effective products that meet applicable regulatory requirements; 
+• 
+access to adequate capital; and, 
+• 
+ability to attract and retain qualified personnel. 
+4 
+Table of Contents 
+We believe our scientific capabilities and proprietary know-how relating to our patented DPP technology and lateral flow technology are very strong,
+particularly for the development and manufacture of tests for the detection of antibodies to infectious diseases, and other diseases. 
+Our ability to develop and market other products is in large measure dependent on our having additional resources and/or collaborative relationships. Some
+of our product development efforts have been funded on a project or milestone basis. We believe that our proprietary know-how relating to our patented DPP technology has been instrumental in our obtaining the collaborations we have and that we
+continue to pursue. We believe that our patent protection enhances our ability to both develop more profitable, collaborative relationships and expand licensing revenue. However, there are a number of competitive technologies used and/or seeking to
+be used by others in point-of-care settings. 
+Although we have no specific knowledge of any other competitors’ products that could render our products obsolete, if we fail to maintain and enhance our
+competitive position or fail to introduce new products and product features, our customers may decide to use the products developed by our competitors, which could result in a loss of revenues and cash flow. 
+Employees 
+As of December 31, 2018, we had 295 full-time equivalent employees, of whom 15 were in administration, 215 were in
+manufacturing, 45 were in research and development, and 20 were in sales and marketing and customer service. Of these employees, approximately 240 were located in the United States, 27 were located in Malaysia, 20 were located in Germany, and 3
+were located in other countries. 
+We have never had a work stoppage, and none of our employees are represented by a labor
+organization or subject to any collective bargaining arrangements. We consider our employee relations to be good. 
+Governmental Regulation 
+Certain of our activities are subject to regulatory oversight by the FDA under provisions of the Federal Food, Drug, and Cosmetic Act
+and regulations thereunder, including regulations governing the development, marketing, labeling, promotion, manufacturing, and export of diagnostic products. Our clinical laboratory customers are subject to oversight by Centers for Medicare and
+Medicaid Services, or CMS, pursuant to CLIA, as well as agencies in various states. Failure to comply with applicable requirements can lead to sanctions, including withdrawal of products from the market, recalls, refusal to authorize government
+contracts, product seizures, civil money penalties, injunctions, and criminal prosecution. 
+FDA Approval/Clearance Requirements 
+Unless an exemption applies, each medical device that we market or wish to market in the United States must receive 510(k) clearance or
+Premarket Approval, or PMA. Medical devices that receive 510(k) clearance are “cleared” by the FDA to market, distribute, and sell in the United States. Medical devices that obtain a PMA by the FDA are “approved” to market, distribute and sell in the
+United States. We cannot be certain that 510(k) clearance or PMA approval will ever be obtained for any products that have not already obtained 510(k) clearance or PMA approval. Descriptions of the PMA and 510(k) clearance processes are provided
+below. 
+The FDA decides whether a device line must undergo either the 510(k) clearance or PMA based on statutory criteria that utilize a
+risk-based classification system. PMA is the FDA process of scientific and regulatory review to evaluate the safety and effectiveness of Class III medical devices and, in many cases, Class II medical devices. Class III devices are those that support
+or sustain human life, are of substantial importance in preventing impairment of human health, or which present a potential, unreasonable risk of illness or injury. The FDA uses these criteria to decide whether a PMA or a 510(k) is appropriate,
+including the level of risk that the agency perceives is associated with the device and a determination by the agency of whether the product is a type of device that is similar to devices that are already legally marketed. Devices deemed to pose
+relatively less risk are placed in either Class I or II. In many cases, the FDA requires the manufacturer to submit a 510(k) requesting clearance (also referred to as a premarket notification), unless an exemption applies. The 510(k) must demonstrate
+that the manufacturer’s proposed device is “substantially equivalent” in intended use and in safety and effectiveness to a legally marketed predicate device. A “predicate device” is a pre-existing medical device to which equivalence can be drawn,
+that is either in Class I or Class II or is a Class III device that was in commercial distribution before May 28, 1976, for which the FDA has not yet called for submission of a PMA application. 
+Device classification depends on the device’s intended use and its indications for use. In addition, classification is risk-based, that
+is, the risk the device poses to the patient and/or the user is a major factor in determining the class to which it is assigned. Class I includes devices with the lowest risk and Class III includes those with the greatest risk. 
+Class I devices are those for
+which safety and effectiveness can be assured by adherence to the FDA’s general regulatory controls for medical devices, or the General Controls, which include compliance with the applicable portions of the FDA’s quality system regulations, facility
+registration and product listing, reporting of adverse medical events, and appropriate, truthful and non-misleading labeling, advertising, and promotional materials. Some Class I devices also require premarket clearance by the FDA through the 510(k)
+process described below. 
+Class II devices are subject to
+the FDA’s General Controls, and any other special controls as deemed necessary by the FDA to ensure the safety and effectiveness of the device. Premarket review and clearance by the FDA for Class II devices is accomplished through the 510(k) process.
+Pursuant to the Medical Device User Fee and Modernization Act of 2002, unless a specific exemption applies, 510(k) submissions are subject to user fees. Certain Class II devices are exempt from this premarket review process. 
+Class III includes devices
+with the greatest risk. Devices in this class must meet all of the requirements in Classes I and II. In addition, Class III devices cannot be marketed until they receive Premarket Approval. 
+The safety and effectiveness of Class III devices cannot be assured solely by the General Controls and the other requirements
+described above. These devices require formal clinical studies to demonstrate safety and effectiveness. Under Medical Device User Fee and Modernization Act of 2002, PMA applications (and supplemental premarket approval applications) are subject to
+significantly higher user fees than 510(k) applications, and they also require considerably more time and resources. 
+Rapid HIV tests intended for diagnostic use are regulated as Class III devices. Responsibility for assuring the safety and
+effectiveness of these tests lies within the Center for Biologics Evaluation and Research’s Office of Blood Research and Review, with oversight by the Blood Products Advisory Committee. Approved rapid HIV tests must meet the regulations in the 21
+CFR 800 series subparts, under the investigational device exemption, or IDE and PMA pathways. 
+5 
+Table of Contents 
+Premarket Approval Pathway 
+We manufacture, market and distribute three rapid HIV tests in the United States. Our HIV 1/2 STAT-PAK Assay, SURE CHECK HIV 1/2
+Assay, and DPP HIV 1/2 Assay all have received FDA PMA approval. A PMA application must be supported by extensive data including, but not limited to, analytical, preclinical, clinical trials, manufacturing, statutory preapproval inspections, and
+labeling to demonstrate to the FDA’s satisfaction the safety and effectiveness of the device for its intended use. Before a PMA is submitted, a manufacturer must apply for an IDE. If the device presents a “significant risk,” as defined by the FDA,
+to human health, the FDA requires the device sponsor to file an IDE application with the FDA and obtain IDE approval prior to initiation of enrollment of human subjects for clinical trials. The IDE provides the manufacturer with a legal pathway to
+perform clinical trials on human subjects where without the IDE, only approved medical devices may be used on human subjects. 
+The IDE application must be supported by appropriate data, such as analytical, animal and laboratory testing results, manufacturing
+information, and an Investigational Review Board (IRB) approved protocol showing that it is safe to test the device in humans and that the testing protocol is scientifically sound. If the clinical trial design is deemed to have “non-significant
+risk,” the clinical trial may be eligible for “abbreviated” IDE requirements. In some instances, clinical trials for in vitro diagnostic medical devices may be exempt from the more burdensome IDE requirements if certain labeling requirements are
+met. 
+A clinical trial may be suspended by either the FDA or the Investigational Review Board at any time for various reasons, including a
+belief that the risks to the study participants outweigh the benefits of participation in the study. Even if a study is completed, clinical testing results may not demonstrate the safety and efficacy of the device, or they may be equivocal or
+otherwise insufficient to obtain approval of the product being tested. After the clinical trials have been completed, if at all, and the clinical trial data and results are collected and organized, a manufacturer may complete a PMA application. 
+After a PMA application is sufficiently complete, the FDA will accept the application and begin an in-depth review of the submitted
+information. By statute, the FDA has 180 days to review the “accepted application,” although, generally, review of the application can take between one and three years, but it may take significantly longer. During this review period, the FDA may
+request additional information or clarification of information already provided. Also, during the review period, an advisory panel of experts from outside the FDA may be convened to review and evaluate the application and provide recommendations to
+the FDA as to the approvability of the device. The preapproval inspections conducted by the FDA include an evaluation of the manufacturing facility to ensure compliance with the FDA's quality systems regulations or QSR, as well as inspections of
+the clinical trial sites by the Bioresearch Monitoring group to evaluate compliance with good clinical practice and human subject protections. New PMA applications or PMA supplements are required for modifications that affect the safety or
+effectiveness of the device, including, for example, certain types of modifications to the device’s indication for use, manufacturing process, labeling and design. Significant changes to an approved PMA require a 180-day supplement, whereas less
+substantive changes may utilize a 30-day notice, or a 135-day supplement. Premarket approval supplements often require submission of the same type of information as a premarket approval application, except that the supplement is limited to
+information needed to support any changes from the device covered by the original premarket approval application, and it may not require as extensive clinical data or the convening of an advisory panel. 
+Our HIV 1/2 STAT-PAK Assay PMA application number BP050009/0 and our SURE CHECK 1/2 HIV Assay PMA application number BP050010/0 were
+approved by the FDA in May 2006. Our DPP HIV 1/2 Assay PMA application number BP120032/0 was approved by the FDA in December 2012. 
+510(k) Clearance Pathway 
+We are currently developing products that either will or are likely to require an FDA 510(k) clearance, and we anticipate submitting
+a 510(k) for each such product to demonstrate that such proposed device is substantially equivalent to a respective previously cleared 510(k) device or a device that was in commercial distribution before May 28, 1976, for which the FDA has not yet
+called for the submission of 510(k). FDA's 510(k) clearance pathway usually takes from three to twelve months but could take longer. In some cases the FDA may require additional information, including clinical data, to make a determination
+regarding substantial equivalence. 
+If a device receives 510(k) clearance, any modification that could significantly affect its safety or effectiveness, or that would
+constitute a new or major change in its intended use, will require a new 510(k) clearance or, depending on the modification, a PMA. The FDA requires each device manufacturer to determine whether the proposed change requires submission of a new
+510(k) or a PMA, but the FDA can review any such decision and can disagree with a manufacturer’s determination. If the FDA disagrees with a manufacturer’s determination, the FDA can require the manufacturer to cease marketing and/or recall the
+modified device until 510(k) clearance or PMA of the modified device is obtained. 
+If the FDA requires us to submit a new 510(k) or PMA for any modifications to a previously cleared product, or if we obtain 510(k)
+clearance for a device in the future, we may be required to submit a separate new 510(k) or PMA application for such modifications. 
+Clinical Laboratory Improvement Amendments of 1988 
+A manufacturer of a test categorized as moderately complex may request that categorization of the test be waived through a CLIA
+Waiver by Application, or CW, submission to the FDA. When a test is categorized as waived, it may be performed by laboratories with a Certificate of Waiver, such as a physician’s office outreach setting. In a CW submission, the manufacturer
+provides evidence to the FDA that a test meets the CLIA statutory criteria for waiver CLIA, a walk-in clinic or an emergency room provides CMS authority over all laboratory testing, except research that is performed on humans in the United States.
+The Division of Laboratory Services, within the Survey and Certification Group under the CMS, has the responsibility for implementing the CLIA program. 
+The CLIA program is designed to establish quality laboratory testing by ensuring the accuracy, reliability and timeliness of patient
+test results. Under CLIA, a laboratory is a facility that does laboratory testing on specimens derived from humans and used to provide information for the diagnosis, prevention or treatment of disease, or impairment of, or assessment of health.
+Under the CLIA program, unless waived, laboratories must be certified by the government, satisfy governmental quality and personnel standards, undergo proficiency testing, be subject to inspections and pay fees. We have received a CLIA waiver for
+all of our lateral flow rapid HIV tests that we market in the United States. Specifically, the CLIA waiver was granted by the FDA for HIV 1/2 STAT-PAK in November 2006,for SURE CHECK HIV 1/2 in October 2007, and for DPP HIV 1/2 in October 2014. 
+6 
+Table of Contents 
+Pervasive and Continuing FDA Regulation 
+A host of regulatory requirements apply to our approved devices, including: the quality system regulation, which requires
+manufacturers to follow elaborate design, testing, control, documentation and other quality assurance procedures; the Medical Reporting Regulations, which require manufacturers to report to the FDA specified types of adverse events involving their
+products; labeling regulations; and the FDA’s general prohibition against promoting products for unapproved or “off-label” uses. Some Class II devices are subject to special controls-such as performance standards, post-market surveillance, patient
+registries, and FDA guidelines-that do not apply to Class I devices. 
+The regulatory requirements that apply to our approved products classified as medical devices include: 
+• 
+product listing and establishment registration, which helps facilitate FDA inspections and other regulatory action; 
+• 
+QSR, which require manufacturers, including third-party manufacturers, to follow stringent design, testing, control, documentation
+and other quality assurance procedures during all aspects of the development and manufacturing process; 
+• 
+labeling regulations and FDA prohibitions against the promotion of products for uncleared, unapproved or
+off-label use or indication; 
+• 
+clearance of product modifications that could significantly affect safety or efficacy or that would constitute a
+major change in intended use of one of our cleared devices; 
+• 
+approval of product modifications that affect the safety or effectiveness of one of our cleared devices; 
+• 
+medical device reporting regulations, which require that manufacturers comply with FDA requirements to report if
+their device may have caused or contributed to a death or serious injury, or has malfunctioned in a way that would likely cause or contribute to a death or serious injury if the malfunction of the device or a similar device were to
+recur; 
+• 
+post-approval restrictions or conditions, including post-approval study commitments; 
+• 
+post-market surveillance regulations, which apply when necessary to protect the public health or to provide
+additional safety and effectiveness data for the device; 
+• 
+the FDA’s recall authority, whereby it can ask, or under certain conditions order, device manufacturers to
+recall from the market a product that is in violation of governing laws and regulations; 
+• 
+regulations pertaining to voluntary recalls; and, 
+• 
+notices of corrections or removals. 
+Our Medford, New York facility is currently registered as an establishment with the FDA. We and any third-party manufacturers are
+subject to announced and unannounced inspections by the FDA to determine our compliance with QSR and other regulations. 
+21st Century Cures Act 
+The 21st Century Cures Act, enacted in December 2016, contains several sections specific to medical device innovations. We believe
+that implementation of the 21st Century Cures Act may have a positive impact on its businesses by facilitating innovation and/or reducing the regulatory burden imposed on medical device manufacturers. 
+Government Regulation of Medical Devices for Animal Subjects 
+We currently sell, market or distribute two veterinary devices in the United States: DPP VetTB Assay for Cervids and DPP VetTB Assay
+for Elephants. Diagnostic tests for animal health infectious diseases, including our veterinary devices for the prevention and/or treatment of animal disease, are regulated in the U.S. by the Center for Veterinary Biologics within the U.S.
+Department of Agriculture Animal and Plant Health Inspection Service, or APHIS, under the Virus, Serum, and Toxin Act of 1913. As a requirement, our veterinary devices were approved by APHIS before they could be sold in the U.S. 
+The APHIS regulatory approval process involves the submission of product performance data and manufacturing documentation. Following
+regulatory approval to market a product, APHIS requires that each lot of product be submitted for review before release to customers. In addition, APHIS requires special approval to market products where test results are used in part for
+government-mandated disease management programs. 
+Environmental Laws 
+We believe that we are in compliance with all foreign, federal, state, and local environmental regulations with
+respect to our manufacturing facilities. The cost of ongoing compliance with such regulations does not have a material effect on our operations. 
+Intellectual Property 
+Intellectual Property Strategy 
+Our intellectual property strategy is to: (1) build our own intellectual property portfolio around our DPP technology and optical analyzers; (2) pursue
+licenses, trade secrets and know-how within the area of rapid point-of-care testing; and, (3) develop and acquire proprietary positions to certain reagents. 
+7 
+Table of Contents 
+DPP ® Intellectual Property 
+We have obtained patent coverage on our DPP technology, including numerous patents in the United States, China, Malaysia, Eurasia, Mexico, Singapore, Japan,
+Australia, Indonesia, Korea and the U.K. Additional patent applications on our DPP technology are pending in the United States, as well as in foreign countries such as Brazil, Canada, the European Union, India, Israel, and South Africa. 
+DPP technology provides us with freedom to operate, which enables us to develop tests with better performance and capabilities compared with tests built on
+traditional lateral flow platforms. These advantages have allowed us to enter into multiple technology collaborations based upon DPP technology, which we believe will provide new manufacturing and marketing opportunities. We have filed additional
+patent applications that we believe will strengthen the DPP intellectual property and have also filed for patent protection for certain other point-of-care technologies or applications thereof. 
+We have also obtained patent coverage on our optical-based analyzer technology in the United States, with patents pending in several foreign countries. 
+Trademarks 
+We have filed and obtained trademarks for our products, including DPP, SURE CHECK, STAT-VIEW, and STAT-PAK, and NEXT GENERATION DPP, as well as for the
+SampleTainer and DPP Micro Reader, which are used with certain DPP products. Our trademarks have been obtained in the United States and certain other countries around the world. 
+Trade Secrets and Know-How 
+We have developed a substantial body of trade secrets and know-how relating to the development and manufacture of lateral flow and DPP-based diagnostic
+tests, including the sourcing and optimization of materials for such tests, and methods to maximize sensitivity, speed-to-result, specificity, stability and reproducibility of our tests. We possess proprietary know-how to develop tests for multiple
+conditions using colored particles. Our formulations enable long shelf lives of our rapid HIV and other tests, providing us with an important competitive advantage. 
+Lateral Flow Technology and Reagent Licenses 
+We seek licenses and/or redesigns of products that we believe to be in our best interests. Because of the costs and other negative consequences of
+time-consuming patent litigation, we often attempt to obtain a license on reasonable terms. 
+The peptides used in our rapid HIV tests were licensed to us by one or more third parties. We also have licensed the antigens used in other tests including
+our Syphilis, Tuberculosis, Leptospirosis, Leishmaniasis and Chagas tests, and we may enter into other license agreements. In prior years, we concluded license agreements related to intellectual property rights owned by the United States associated
+with HIV-1 and a sub-license agreement for HIV-2 with Bio-Rad Laboratories N.A., the exclusive licensee of the Pasteur Institute's HIV-2 intellectual property estate. 
+Available Information 
+We are required to file annual, quarterly and current reports, proxy statements and other
+information with the U.S. Securities and Exchange Commission. The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. 
+Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form
+8-K, proxy statements and amendments to those documents filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, are also available free of charge on our website at www.chembio.com as soon as reasonably
+practicable after such reports are electronically filed with or furnished to the SEC. 
+Investors should note that we currently announce material information to our investors and
+others using filings with the SEC, press releases, public conference calls, webcasts or our website (www.chembio.com), including news and announcements regarding our financial performance, key personnel, our brands and our business strategy.
+Information that we post on our corporate website could be deemed material to investors. We encourage investors to review the information we post on these channels. We may from time to time update the list of channels we will use to communicate
+information that could be deemed material and will post information about any such change on www.chembio.com. The information on our website is not, and shall not be deemed to be, a part hereof or incorporated into this or any of our other filings
+with the SEC. 
+Corporate Information 
+Our principal executive offices are located at 3661 Horseblock Road, Medford, New York
+11763. Our telephone number is (631) 924-1135. Our website address is www.chembio.com. The information contained in, or accessible through, our corporate website does not constitute part of this report. 
+8 
+Table of Contents 
+ITEM 1A. 
+RISK FACTORS 
+You should carefully consider each of the following risk factors and all of the other information provided in this Form 10-K in considering whether
+to make or continue to hold an investment in our Common Stock. The risks described below are those we currently believe may materially affect us. An investment in our Company involves a high degree of risk, and should be considered only by persons
+who can afford the loss of their entire investment. Although we believe that these risks are the most important for you to consider, you should read this section in conjunction with our financial statements, the notes to those financial statements
+and our management's discussion and analysis of financial condition and results of operations included in our periodic reports and incorporated into this Form 10-K by reference. 
+Risks Related to Our Business 
+Important competitive factors for our products include price, quality, performance, ease of use, and customer service. A few large corporations produce a
+wide variety of diagnostic tests and other medical devices and equipment. A larger number of mid-size companies generally compete only in the diagnostic industry and a significant number of small companies produce only a few diagnostic products. As
+a result, the diagnostic test industry is highly fragmented and segmented. 
+9 
+Table of Contents 
+More generally, the point-of-care diagnostics industry is undergoing rapid technological changes, with frequent introductions of new technology-driven
+products and services. As new technologies become introduced into the point-of-care diagnostic testing market, we may be required to commit considerable additional efforts, time and resources to enhance our current product portfolio or develop new
+products. We may not have the available time and resources to accomplish this, and many of our competitors have substantially greater financial and other resources to invest in technological improvements. We may not be able to effectively implement
+new technology-driven products and services or be successful in marketing these products and services to our customers, which would materially harm our operating results. 
+Although we own DPP patents, lateral flow technology is still a competitive platform to DPP, and lateral flow technology has a lower cost of manufacture
+than DPP products. Although the DPP platform has shown improved sensitivity as compared with conventional lateral flow platforms in a number of studies, several factors go into the development and performance attributes of products. Therefore the
+ability of our products to successfully compete will depend on several other factors, including our having a patented rapid test platform technology that differentiates DPP from lateral flow as well as from other diagnostic platform technologies. 
+There can be no assurance that our DPP patents or our products incorporating those patents will not be challenged at some time in the future. 
+Our Competitors may Develop and Commercialize More Effective or Successful Products, and Our Research, Development and Commercialization
+Efforts may not Succeed. 
+We regularly commit substantial resources to research and development and the commercialization of our new or enhanced products. The research and
+development process usually takes a long time from inception to commercial launch. During each stage of this process there is a substantial risk that we will not achieve our goals in a timely fashion, or at all, and we may have to abandon a new or
+enhanced product in which we have invested substantial time and money. We expect to continue to incur significant costs related to our research and development activities. 
+Our products require significant development and investment prior to commercialization, including testing to demonstrate the products' performance
+capabilities, cost-effectiveness or other benefits. We must obtain regulatory approval before most products may be sold and additional development efforts on these products may be required before the products will be reviewed. However, regulatory
+authorities may not approve these products for commercial sale or may substantially delay or condition such approval. There may be little or no market for the product and entry into or development of new markets for our products may require an
+investment of substantial resources even if all applicable regulatory approvals are obtained. Furthermore, we may spend a significant amount of money on advertising or other activities and still fail to develop a market for the product. The success
+of our efforts may be affected by our ability to manufacture products in a cost-effective manner, whether we can obtain necessary intellectual property rights and protection and our ability to obtain reimbursement authorizations in the markets where
+the product will be sold. Therefore, if we fail to develop and gain commercial acceptance for our products, or if competitors develop more effective products or a greater number of successful new products, customers may decide not to purchase our
+products. 
+Our Products may not be Able to Compete with New Diagnostic Products or Existing Products Developed by Well-Established Competitors,
+which would Negatively Affect Our Business. 
+The diagnostic industry is focused on the testing of biological specimens in a laboratory or at the point-of-care and is
+highly competitive and rapidly changing. Important competitive factors for our products include price, quality, performance, ease of use, and customer service. 
+A few large corporations produce a wide variety of diagnostic tests and other medical devices and equipment. A
+larger number of mid-size companies generally compete only in the diagnostic industry and a significant number of small companies produce only a few diagnostic products. As a result, the diagnostic test industry is highly fragmented and segmented. 
+Some of our principal competitors may have considerably greater financial, technical and marketing resources
+than we do. Several companies produce diagnostic tests that compete directly with our testing product line, including Abbott (Alere), OraSure Technologies and Trinity Biotech. Some competitors offer broader product lines and may have greater name
+recognition than we have. These and other companies have or may have products incorporating molecular or other advanced technologies that over time could directly compete with our testing product line. We also face competition from certain of our
+distributors or former customers that have created or may decide to create, their own products to compete with ours. 
+As new products incorporating new technologies enter the market, our products may become obsolete or a
+competitor's products may be more effective or more effectively marketed and sold. If our competitors’ products take market share from our products through more effective marketing or competitive pricing, our revenues, margins and operating results
+could be adversely affected. In addition, our revenues and operating results could be negatively impacted if some of our customers internally develop or acquire their own sample collection devices and use those devices in place of our products in
+order to reduce costs. 
+Our Future Revenues and Operating Results may be Negatively Affected by Ongoing Consolidation in the Healthcare Industry. 
+There has been a significant amount of consolidation in the healthcare industry. This consolidation has increased the competition to provide goods and
+services to customers. In addition, group purchasing organizations and integrated health delivery networks have served to concentrate purchasing decisions for some customers, which has also placed pricing pressure on medical device suppliers. Due to
+ongoing consolidation, there could be additional pressure on the prices of our products. 
+10 
+Table of Contents 
+Our Continued Growth Depends on Retaining Our Current Key Employees and Attracting Additional Qualified Personnel, and We may not be Able
+to do so. 
+Our success depends to a large extent upon the skills and experience of our executive officers, management and sales, marketing, operations and scientific
+staff. We may not be able to attract or retain qualified employees due to the intense competition for qualified personnel among medical products businesses and academic and other research institutions, as well as to geographic considerations, our
+ability to offer competitive compensation, and benefits, and other reasons. 
+If we are not able to attract and retain the necessary qualified personnel to accomplish our business objectives, we may experience constraints that will
+adversely affect our ability to effectively manufacture, sell and market our products to meet the demands of our strategic partners in a timely fashion, or to support internal research and development programs. 
+We have entered into employment contracts with our Chief Executive Officer, John Sperzel; our Chief Financial Officer, Neil Goldman; and our Chief Science &
+Technology Officer, Javan Esfandiari. Due to the specific knowledge and experience of these executives regarding the industry, technology and market generally and to our company specifically, the loss of the services of any one of these executives
+could have a material adverse effect on us. We have not obtained a key man insurance policy on any officer other than Mr. Esfandiari. 
+We may not Generate the Expected Benefits of Our Acquisition of opTricon GmbH, and the
+integration of the Acquisition could Disrupt Our Ongoing Business, Distract Our Management and Increase Our Expenses. 
+We acquired opTricon GmbH, or opTricon, in November 2018 with the expectation that the
+acquisition will result in various benefits, including securing global commercial rights and reducing cost of goods. Achieving the anticipated benefits of the opTricon acquisition is subject to a number of uncertainties, including whether our
+business and the business of opTricon can be integrated in an efficient and effective manner. We cannot assure you that we will be able to accurately forecast the performance or ultimate impact of the opTricon acquisition. 
+It is possible that the integration process could take longer than anticipated and could result
+in the loss of valuable employees, additional and unforeseen expenses, the disruption of our ongoing business, processes and systems, or inconsistencies in standards, controls, procedures, practices, policies and compensation arrangements, any of
+which could adversely affect our ability to achieve the anticipated benefits of the opTricon acquisition. There may be increased risk due to integrating financial reporting and internal control systems. The integration process is subject to a
+number of uncertainties, and no assurance can be given that the anticipated benefits, expense savings and synergies will be realized or, if realized, the timing of their realization. Failure to achieve these anticipated benefits could result in
+increased costs or decreases in the amount of expected revenues and could adversely affect our future business, financial condition, operating results and prospects. 
+We have incurred and will continue to incur non-recurring expenses in connection with the
+opTricon acquisition, including legal, accounting and other expenses. Additional unanticipated costs may be incurred following consummation of the opTricon acquisition in the course of the integration of the business of opTricon into our
+business. We cannot be certain that the realization of efficiencies related to the integration of the two businesses will offset the transaction and integration costs in the near term or any losses from undiscovered liabilities not covered by an
+indemnification from the sellers of opTricon. 
+We may not Generate the Expected Benefits of Future Acquisitions or Investments, and they could Disrupt Our Ongoing Business, Distract
+Our Management, Increase Our Expenses and Negatively Affect Our Business. 
+As a way for us to grow our business, we may pursue strategic acquisitions or investments. These activities, and their impact on our business, are subject
+to many risks, including the following: (i) the benefits expected to be derived from an acquisition or investment may not materialize and could be affected by numerous factors, such as regulatory developments, insurance reimbursement, our
+inexperience with new businesses or markets, general economic conditions and increased competition; (ii) we may be unable to successfully integrate an acquired company’s personnel, assets, management, information technology systems, accounting
+policies and practices, products and/or technology into our business; (iii) we may not be able to accurately forecast the performance or ultimate impact of an acquired business; and (iv) an acquisition may result in the incurrence of unexpected
+expenses, stockholder lawsuits, the dilution of our earnings or our existing stockholders’ percentage ownership, or potential losses from undiscovered liabilities not covered by an indemnification from the seller(s) of the acquired business. 
+If these factors occur, we may be unable to achieve all or a significant part of the benefits expected from an acquisition or investment. This may adversely
+affect our financial condition, results of operations and ability to grow our business or otherwise achieve our financial and strategic objectives. 
+Third-Party Reimbursement Policies and Potential Cost Constraints could Negatively Affect Our Business. 
+The list of our product end-users includes hospitals, physicians and other healthcare providers. If these end-users do not receive adequate reimbursement
+for the cost of our products from their patients’ healthcare insurers or payors, the use of our products could be negatively impacted. Furthermore, the net sales of our products could also be adversely affected by changes in reimbursement policies of
+government or private healthcare payors. 
+Hospitals, physicians and other healthcare providers who purchase diagnostic products in the United States generally rely on third-party payors, such as
+private health insurance plans, Medicare and Medicaid, to reimburse all or part of the cost of the product. Due to the overall escalating cost of medical products and services, there is increased pressures on the healthcare industry, both foreign and
+domestic, to reduce the cost of products and services. Given the efforts to control and reduce healthcare costs in the United States, available levels of reimbursement may change for our existing products or products under development. Third-party
+reimbursement and coverage may not be available or adequate in either the United States or international markets, current reimbursement amounts may be decreased in the future and future legislation, and regulation or reimbursement policies of
+third-party payors, may reduce the demand for our products or our ability to sell our products on a profitable basis. 
+To the Extent that We are Unable to Collect Our Outstanding Accounts Receivable, Our Operating Results could be Materially Harmed. 
+There may be circumstances and timing that require us to accept payment terms, including delayed payment terms, from distributors or customers, which, if
+not satisfied, could cause financial losses. 
+We generally accept payment terms which require us to ship product before the contract price has been paid fully, and there also are circumstances pursuant
+to which we may accept further delayed payment terms pursuant to which we may continue to deliver product. To the extent that these circumstances result in significant accounts receivables and those accounts receivables are not paid on a timely
+basis, or are not paid at all, especially if concentrated in one or two customers, we could suffer financial losses. 
+Ongoing Changes in Healthcare Regulation could Negatively Affect Our Revenues, Business and Financial Condition. 
+There have been several proposed changes in the United States at the federal and state level for comprehensive reforms regarding the payment for, the
+availability of and reimbursement for healthcare services. These proposals have ranged from fundamentally changing federal and state healthcare reimbursement programs, including providing comprehensive healthcare coverage to the public under
+government-funded programs, to minor modifications to existing programs. One example is the Patient Protection and Affordable Care or the Affordable Care Act, the Federal healthcare reform law enacted in 2010. 
+Healthcare reform initiatives will continue to be proposed, and may reduce healthcare related funding in an effort. It is impossible to predict the ultimate
+content and timing of any healthcare reform legislation and its resulting impact on us. If significant reforms are made to the healthcare system in the United States, or in other jurisdictions, those reforms may increase our costs or otherwise
+negatively effect on our financial condition and results of operations. 
+In April 2017, the European Parliament passed the Medical Devices Regulation (Regulation 2017/745), which repeals and replaces the
+European Union Medical Devices Directive and the Active Implantable Medical Devices Directive. Unlike directives, which must be implemented into the national laws of the European Economic Area, which we refer to as the EEA, member States, the
+regulations would be directly applicable, i.e., without the need for adoption of EEA member State laws implementing them, in all EEA member States and are intended to eliminate current differences in the regulation of medical devices among EEA
+member States. The Medical Devices Regulation, among other things, is intended to establish a uniform, transparent, predictable and sustainable regulatory framework across the EEA for medical devices and ensure a high level of safety and health
+while supporting innovation. The Medical Devices Regulation will, however, only become fully applicable three years after publication (in May 2020). Once applicable, the Medical Devices Regulation will, among other things: 
+• 
+strengthen the rules on placing devices on the market and reinforce surveillance once they are
+available; 
+• 
+establish explicit provisions on manufacturers' responsibilities for the follow-up of the quality,
+performance and safety of devices placed on the market; 
+• 
+improve the traceability of medical devices throughout the supply chain to the end-user or patient
+through a unique identification number; 
+• 
+set up a central database to provide patients, healthcare professionals and the public with
+comprehensive information on products available in the EU; and 
+• 
+strengthen rules for the assessment of certain high-risk devices, such as implants, which may have
+to undergo an additional check by experts before they are placed on the market. 
+Once applicable, the Medical Devices Regulation may impose increased compliance obligations for us to access the EU market. 
+We Believe Our Success Depends in Part on the Continued Funding of, and Our Ability to Participate in, Large Testing Programs in the U.S.
+and Worldwide, the Funding of which may be Reduced or Discontinued or Otherwise be Unavailable to Us. 
+We believe it to be in our best interests to meaningfully participate in large testing programs. Moreover many of these programs are funded by governments
+and other donors, and there can be no assurance that funding will not be reduced or completely discontinued. Participation in these programs also requires alignment and engagement with the many other participants in these programs, including WHO,
+CDC, the U.S. Agency for International Development, foreign governments and their agencies, non-governmental organizations, and HIV service organizations. If we are unsuccessful in our efforts to participate in these programs, our operating results
+could be materially harmed. 
+11 
+Table of Contents 
+In December 2013 President Obama signed into law the PEPFAR Stewardship and Oversight Act, which is the most recent reauthorization of PEPFAR. However,
+unlike the 2008 PEPFAR authorization, which authorized approximately $45 billion in funding, the new law did not authorize a specific dollar amount for funding. 
+Developing Testing Guidelines could Negatively Affect Sales of Our Products. 
+Government agencies may issue diagnostic testing guidelines or recommendations, which can alter the usage of our HIV testing products. New laws or
+guidelines, or changes to existing laws or guidelines, and the manner in which these new or changed laws and guidelines are interpreted and applied, could impact the degree to which our testing products are used. These developments could affect the
+frequency of testing, the number of people tested and whether the testing products are used broadly for screening large populations or in a more limited capacity. These factors could in turn affect the level of sales of our products and our results
+of operations. 
+Legislative and Other Regulatory Changes could have an Effect on Our Business. 
+The current U.S. Presidential Administration has promised to repeal and replace the Affordable Care Act, expressed concerns with respect to existing trade
+agreements, and has indicated a desire to make other regulatory changes during his administration. Changes in regulatory or economic conditions or in the laws and policies governing foreign trade, taxes, manufacturing, and development in the United
+States could impact our business. Economic and regulatory changes could also affect foreign currency exchange rates which, in turn, could affect our reported financial results and our competitiveness on a worldwide basis. 
+Developments Related to the U.K.’s Referendum On Membership in the E.U. Could Adversely Affect Us. 
+On June 23, 2016, the United Kingdom voted in favor of leaving the European Union, or E.U. Following this “Brexit” referendum there has been increased
+political and economic uncertainty, particularly in the U.K. and E.U. and this uncertainty may last for the foreseeable future. Until the terms and timing of the U.K.’s exit from the E.U. are finalized, it will be difficult to predict the impact of
+Brexit. Our business in the U.K., the E.U. and world-wide could be negatively affected during this period of uncertainty, and perhaps longer. The decision of voters in the U.K. to exit the E.U. could cause volatility in global financial markets, such
+as global currency exchanges, resulting in a slow-down in economic activity in the U.K., Europe or globally, and result in significant regulatory changes and uncertainty. These events could make it more difficult or costly to sell our products,
+particularly in the U.K. and Europe, and negatively affect our revenues and results of operations. The Brexit referendum may also influence other countries and result in additional countries deciding to leave the E.U. This in turn could result in
+additional changes and uncertainty, any or all of which could negatively impact our business. 
+We could be Exposed to Liability if We Experience Security
+Breaches or Other Disruptions, which could Harm Our Reputation and Business . 
+We may be subject to cyber-attacks whereby computer hackers may attempt to access our computer systems or our third party IT service provider’s systems and,
+if successful, misappropriate personal or confidential information. In addition, a contractor or other third party with whom we do business may attempt to circumvent our security measures or obtain such information, and may purposefully or
+inadvertently cause a breach involving sensitive information. We will continue to evaluate and implement additional protective measures to reduce the risk and detect cyber incidents, but cyber-attacks are becoming more sophisticated and frequent and
+the techniques used in such attacks change rapidly. Even though we take cyber-security measures that are continuously reviewed and updated, our information technology networks and infrastructure may still be vulnerable due to sophisticated attacks by
+hackers or breaches. 
+Even the most well protected IT networks, systems, and facilities remain potentially vulnerable because the techniques used in security breaches are
+continually evolving and generally are not recognized until launched against a target and, in fact, may not be detected. Any such compromise of our or our third party’s IT service providers’ data security and access, public disclosure, or loss of
+personal or confidential business information, could result in legal claims proceedings, liability under laws to protect, privacy of personal information, and regulatory penalties, disrupt our operations, require significant management attention and
+resources to remedy any damages that result, damage our reputation and customers willingness to transact business with us, any of which could adversely affect our business. 
+Our Ability to Efficiently Operate Our Business is Reliant on Information Technology, and Any Material Failure, Inadequacy, Interruption
+or Security Breach of that Technology could Harm Our Business. 
+We rely heavily on complex information technology systems across our operations and on the internet, including for management of inventory, invoices,
+purchase orders, shipping, interactions with our third-party logistics provider, revenue and expense accounting, consumer call support, online business, and various other processes and transactions. Our ability to effectively manage our business,
+coordinate the production, distribution and sale of our products, respond to customer inquiries, and ensure the timely and accurate recording and disclosure of financial information depends significantly on the reliability and capacity of these
+systems and the internet. 
+If any of the foregoing systems fails to operate effectively, problems with transitioning to upgraded or replacement systems, or disruptions in the
+operation of the internet, could cause delays in product sales and reduced efficiency of our operations. Significant expenditures could be required to fix any such problem. 
+If there is an Increase in Demand for Our Products, it could Require Us to Expend Considerable Resources or Harm Our Customer
+Relationships if We are Unable to Meet that Demand. 
+If there are significant or unexpected increases in the demand for our products, we may not be able to meet that demand without expending additional capital
+resources. This would increase our capital costs, which could negatively affect our earnings in the short term. In addition, new manufacturing equipment or facilities may require FDA, WHO, and other regulatory approvals before they can be used to
+manufacture our products. To the extent we are unable to obtain or are delayed in obtaining such approvals, our ability to meet the demand for our products could be adversely affected. Furthermore, our suppliers may be unable or unwilling to expend
+the necessary capital resources or otherwise expand their capacity, which could negatively affect our business. 
+Our business could be negatively affected if we or our suppliers are unable to develop necessary manufacturing capabilities in a timely manner. If we fail
+to increase production volumes in a cost effective manner or if we experience lower than anticipated yields or production problems as a result of changes that we or our suppliers make in our manufacturing processes to meet increased demand, we could
+experience shipment delays or interruptions and increased manufacturing costs, which could also have a material adverse effect on our revenues and profitability. 
+If there are unexpected increases in demand for our products, we may be required to obtain additional raw materials in order to manufacture products to meet
+the increase in demand. However, some raw materials require significant ordering lead time and some are currently obtained from a sole supplier or a limited group of suppliers. It is also possible that one or more of our suppliers may become
+unwilling or unable to deliver materials to us. Any shortfall in our supply of raw materials and components, or our inability to quickly and cost-effectively obtain alternative sources for this supply, could have a material adverse effect on our
+ability to meet increased demand for our products. This could negatively affect our total revenues or cost of sales and related profits. 
+12 
+Table of Contents 
+If we are unable to meet customer demand for our products, it could also harm our relationships with our customers and impair our reputation within the
+industry. This, in turn, could have a material adverse effect on our business. 
+Risks Related to Our Products 
+For Our Business to Succeed in the Future, Our Current and Future Products Must Receive Market Acceptance. 
+Market acceptance and the timing of such acceptance, of our new products or technologies is necessary for our future success. To achieve market acceptance,
+we and our distributors will likely be required to undertake substantial efforts and spend significant funds to inform every one of the existence and perceived benefits of our products. We also may require government funding for the purchase of our
+products to help create market acceptance and expand the use of our products. 
+It may be difficult evaluate the market reaction to our products and our marketing efforts for new products may not be successful. The government funding we
+receive may be limited for new products. As such, there can be no assurance that any products will obtain significant market acceptance and fill the market need that is perceived to exist on a timely basis, or at all. 
+We may not have Sufficient Resources to Effectively Introduce and Market Our Products, which could Materially Harm Our Operating Results. 
+Introducing and achieving market acceptance for our new products will require substantial marketing efforts and will require us and/or our contract
+partners, sales agents, and/or distributors to make significant expenditures of time and money. In some instances we will be significantly or totally reliant on the marketing efforts and expenditures of our contract partners, sales agents, and
+distributors. If they do not have or commit the expertise and resources to effectively market the products that we manufacture, our operating results will be materially harmed. 
+New Developments in Health Treatments and Non-Diagnostic Products may Reduce or Eliminate the Demand for Our Products. 
+The development and commercialization of products outside of the diagnostics industry could adversely affect sales of our products. For example, the
+development of a safe and effective vaccine to HIV or treatments for other diseases or conditions that our products are designed to detect, could reduce or eventually eliminate the demand for our HIV or other diagnostic products and result in a loss
+of revenues. 
+Sales Cycles for Our Products can be Lengthy, which can Cause Variability and Unpredictability in Our Business. 
+Some of our products may require lengthy and unpredictable sales cycles, which makes it more difficult to accurately forecast revenues in a given period and
+may cause revenues and operating results to vary from period to period. Our products may involve sales to large public and private institutions which may require many levels of approval and may be dependent on economic or political conditions and the
+availability of grants or funding from government or public health agencies which can vary from period to period. There can be no assurance that purchases or funding from these agencies will occur or continue, especially if current negative economic
+conditions continue or intensify. As a result, we may expend considerable resources on unsuccessful sales efforts or we may not be able to complete transactions at all or on a schedule and in an amount consistent with our objectives. 
+We May Face Product Liability Claims for Injuries. 
+The testing, manufacturing and marketing of medical diagnostic products involves an inherent risk of product
+liability claims. If we cannot successfully defend ourselves against product liability claims, we may incur substantial liabilities or be required to limit or cease sales of our products. We cannot be sure that we will not incur liabilities in
+excess of the policy limits of our existing product liability insurance coverage or that we will be able to continue to obtain adequate product liability insurance coverage in the future at an acceptable cost, or at all. In addition, a defect in
+the design or manufacture of our products could have a material adverse effect on our reputation in the industry and subject us to claims of liability for injury and otherwise. Any substantial underinsured loss resulting from such a claim could
+have a material adverse effect on our profitability, and the damage to our reputation in the industry could have a material adverse effect on our business. 
+Our Customers may not Adopt Rapid Point-of-Care Diagnostic Testing. 
+Rapid point-of-care tests are beneficial because, among other things, they can be administered by healthcare providers in their own facilities or used by
+consumers at home without sending samples to central laboratories. But currently the majority of diagnostic tests used by physicians and other healthcare providers in the U.S. are provided by clinical reference laboratories and hospital-based
+laboratories. In some international markets, such as Europe, diagnostic testing is performed primarily by centralized laboratories. Future sales of our products will depend, in part, on our ability to expand market acceptance of rapid point-of-care
+testing and successfully compete against laboratory testing methods and products. However, we expect that clinical reference and other hospital-based laboratories will continue to compete vigorously against our rapid point-of-care products. Even if
+we can demonstrate that our products are more cost effective, save time, or have better performance or other benefits, physicians, other healthcare providers and consumers may resist changing to rapid point-of-care tests and instead may choose to
+obtain diagnostic results through laboratory tests. If we fail to achieve and expand market acceptance of our rapid point-of-care diagnostic tests with customers, it would have a negative effect on our future sales growth. 
+Customer Concentration Creates Risks for Our Business. 
+A significant portion of our revenues each year comes from a few large customers. To the extent that such a large
+customer fails to meet its purchase commitments, changes its ordering patterns or business strategy, or otherwise reduces its purchases or stops purchasing our products, or if we experience difficulty in meeting the demand by these customers for
+our products, our revenues and results of operations could be adversely affected. 
+13 
+Table of Contents 
+If Our Products do not Perform Properly, It may Affect Our Revenues, Stock Price and Reputation. 
+Our products may not perform as expected. For example, a defect in one of our diagnostic products or a failure by a customer to follow proper testing
+procedures may cause the product to report inaccurate information. Identifying the root cause of a product performance or quality issue can be difficult and time consuming. 
+If our products do not to perform in accordance with the applicable label claims or otherwise in accordance with the expectations or needs of our customers,
+customers may switch to a competing product or otherwise stop using our products, and our revenues could be negatively affected. If this occurs, we may be required to implement holds or product recalls and incur warranty obligations. Furthermore, the
+poor performance by one or more of our products could have an adverse effect on our reputation, our continuing ability to sell products and the price of our Common Stock. 
+If We Expand Our International Presence, It may Increase Our Risks and Expose Our Business to Regulatory, Cultural or Other Challenges. 
+We will continue to try to increase revenue derived from international sales of our products. There are several of factors that could adversely affect the
+performance of our business and/or cause us to incur substantially increased costs because of our international presence and sales, including: (i) uncertainty in the application of foreign laws and the interpretation of contracts with foreign
+parties; (ii) cultural and political differences that favor local competitors or make it difficult to effectively market, sell and gain acceptance of our products; (iii) exchange rates, currency fluctuations, tariffs and other barriers, extended
+payment terms and dependence on international distributors or representatives; (iv) trade protection measures, trade sanctions and import/export licensing requirements; (v) our inability to obtain or maintain regulatory approvals or registrations for
+our products; (vi) Economic conditions, political instability, the absence of available funding sources, terrorism, civil unrest, war and natural disasters in foreign countries; (vii) Reduced protection for, or enforcement of, our patents and other
+intellectual property rights in foreign countries; (viii) our inability to identify international distributors and negotiate acceptable terms for distribution agreements; and (ix) restrictions on our ability to repatriate investments and earnings
+from foreign operations. 
+Economic, cultural and political conditions and foreign regulatory requirements may slow or prevent the manufacture of our products in countries other than the
+United States. Interruption of the supply of our products could reduce revenues or cause us to incur significant additional expenses in finding an alternative source of supply. Foreign currency fluctuations and economic conditions in foreign
+countries could also increase the costs of manufacturing our products in foreign countries. 
+Financial Results, Economic, and Financing Risks 
+We incurred an operating loss each year from 2014 through 2018. Under our operating plan, we have made, and plan to continue
+to make, significant investments in our production capacity, including in expanding facilities and automating manufacturing, and in our sales and marketing, regulatory approval, and research and development activities. Our ability to achieve
+profitability and generate cash flow in the future will depend on our ability to increase sales of our existing products and to successfully introduce new and enhanced products into the marketplace, all while controlling and managing our expenses
+consistent with our operating plan. 
+If we are unable to increase our revenues and manage our expenses in accordance with our operating plan, our
+operating results would be harmed and we may not be able to generate the cash flow needed to fund the investments in our production capacity and other activities, we will be required to implement one or both of the following: 
+• 
+We could reduce the level, or otherwise delay the timing, of the anticipated investments in our production capacity and
+other activities, which would likely curtail or delay the growth in our business contemplated by our operating plan and could impair or defer our ability to achieve profitability and generate cash flow. 
+• 
+We could raise additional funds through public or private financings, strategic relationships, or other arrangements, to
+the extent funding would be available to us on acceptable terms or at all. If we succeed in raising additional funds through the issuance of equity or convertible securities, then the issuance could result in substantial dilution to
+existing stockholders. Furthermore, the holders of these new securities or debt may have rights, preferences and privileges senior to those of the holders of our Common Stock. 
+In such circumstances, we also would need to forego acquisition opportunities, which could impede our ability to
+grow our business. 
+14 
+Table of Contents 
+We Base Our Estimates or Judgments Relating to Critical Accounting Policies on Assumptions that can Change or Prove to be Incorrect. 
+Our financial statements have been prepared in accordance with accounting principles generally accepted in the United States and our discussion and analysis
+of financial condition and results of operations is based on such statements. The preparation of financial statements requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying
+notes. We continuously evaluate significant estimates used in preparing our financial statements, including those related to (i) revenue recognition; (ii) stock-based compensation; (iii) allowance for uncollectible accounts receivable; (iv) inventory
+reserves and obsolescence; (v) customer sales returns and allowances; (vi) contingencies; and (vii) income taxes. 
+Our estimates are based on historical experience and various other assumptions that we believe to be reasonable, as set forth in our discussion and analysis
+of financial condition and results of operations, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these and
+other estimates if our assumptions change or if actual circumstances differ from those in our assumptions. If our operating results fall below the expectations of securities analysts and investors, the price of our Common Stock may decline. 
+Our Financial Results may Fluctuate. 
+From quarter to quarter and year to year, our operating results can fluctuate, which could cause our growth or financial performance to fail to meet the
+expectations of investors and securities analysts. Sales to our distributors and other customers may not meet expectations because of lower than expected customer demand or other factors, including continued economic volatility and disruption,
+reduced governmental funding, and other circumstances described elsewhere in this report. A variety of factors could also contribute to the variability of our financial results, including infrequent, unusual or unexpected changes in revenues or
+costs. 
+Different products provide dissimilar contributions to our gross product margin. Accordingly, our operating results could also fluctuate and be negatively affected by
+the mix of products sold and the relative prices and gross product margin contribution of those products. Failure to achieve operating results consistent with the expectations of investors and securities analysts could adversely affect our
+reputation and the price of our Common Stock. 
+Our Operating Results may be Negatively Affected by Changes in Foreign Currency Exchange Rates. 
+In the past our exposure to foreign currency exchange rate risk has not been material. Nevertheless, sales of our products are subject to currency risks,
+since changes in the values of foreign currencies relative to the value of the U.S. dollar can render our products comparatively more expensive. The fluctuations in the exchange rate could negatively impact international sales of our products, as
+could changes in the general economic conditions. 
+The revenues and expenses of Chembio Diagnostics Malaysia, one of our subsidiaries, are recorded in Malaysian Ringgit. The revenues and expenses of opTricon
+are recorded in Euros. Revenues and expenses denominated in foreign currencies are translated into U.S. dollars for purposes of reporting our consolidated financial results. Our expectation is that the Chembio Diagnostics Malaysia and opTricon
+businesses will continue to grow and, consequently, our exposure to foreign currency exchange rates may grow as well. 
+Our foreign subsidiaries' revenues and expenses and the translation of their financial results into U.S. dollars may be negatively affected by fluctuations
+in the exchange rate. Favorable movement in exchange rates have benefited us in prior periods. However, where there are unfavorable currency exchange rate fluctuations, our consolidated financial statements could be negatively affected. Furthermore,
+fluctuations in exchange rates could affect year-to-year comparability of operating results. In the past, we have not generally entered into hedging instruments to manage our currency exchange rate risk, but we may need to do so in the future.
+However, our attempts to hedge against these risks may not be successful. If we are unable to successfully hedge against unfavorable foreign currency exchange rate movements, our consolidated financial results may be adversely impacted. 
+Changes in Interpretation or Application of U.S. Generally Accepted Accounting Principles
+may Adversely Affect Our Operating Results. 
+We prepare our financial statements to conform to U.S. generally accepted accounting principles. These principles are subject to interpretation by the Financial
+Accounting Standards Board, the American Institute of Certified Public Accountants, the Public Company Accounting Oversight Board, the Securities and Exchange Commission and various other regulatory or accounting bodies. A change in
+interpretations of, or our application of, these principles can have a significant effect on our reported results and may even affect our reporting of transactions completed before a change is announced. Additionally, as we are required to adopt
+new accounting standards, our methods of accounting for certain items may change, which could cause our results of operations to fluctuate from period to period. For example, upon adoption of Accounting Standards Codification (“ASC”) 606 Revenue
+from Contracts with Customers of the Financial Accounting Standards Board (“FASB”), we now recognize revenue upon transfer of control, which is generally at time of delivery. Under the previous accounting guidance, we recognized revenue upon
+acceptance when and if we had production responsibilities. If circumstances change over time or interpretation of the revenue recognition rules change, we could be required to adjust the timing of recognizing revenue and our financial results
+could suffer. 
+15 
+Table of Contents 
+Our Business may be Negatively Affected by Terrorist Attacks or Natural Disasters. 
+Terrorist attacks or natural disasters could cause economic instability. These events could negatively affect economic conditions both within and outside
+the United States and harm demand for our products. The operations of our customers and suppliers could be negatively impacted and eliminate, reduce or delay our customers’ ability to purchase and use our products and our suppliers’ ability to
+provide raw materials and finished products. 
+Our facilities, including some pieces of manufacturing equipment and our computer systems, may be difficult to replace. Various types of disasters, including
+fires, earthquakes, floods and acts of terrorism, may affect our facilities and computer systems. In the event our existing facilities or computer systems are affected by man-made or natural disasters, we may have difficulty operating our business
+and may be unable to manufacture products for sale or meet customer demands or sales projections. If our manufacturing operations were curtailed or shut down entirely, it would seriously harm our business. 
+We Operate in Countries where there is or may be Widespread Corruption. 
+We have a policy in place prohibiting our employees, distributors and agents from engaging in corrupt business practices,
+including activities prohibited by the U.S. Foreign Corrupt Practices Act. Nevertheless, because we work through independent sales agents and distributors outside the United States, we do not have control over the day-to-day activities of such
+independent agents and distributors. In addition, in the donor-funded markets in Africa where we sell our products, there is significant oversight from PEPFAR, the Global Fund, and advisory committees comprised of technical experts concerning the
+development and establishment of national testing protocols. This is a process that includes an overall assessment of a product which includes extensive product performance evaluations including five active collaborations and manufacturer's
+quality systems, as well as price and delivery. In Brazil, where we have had numerous product collaborations with FIOCRUZ, the programs through which our products may be deployed are all funded by the Brazilian Ministry of Health. Although
+FIOCRUZ is affiliated with the Brazilian Ministry of Health, and is its sole customer, FIOCRUZ is not the exclusive supplier for the Ministry of Health. However, because each of our previous collaborations with FIOCRUZ incorporates a technology
+transfer aspect, we believe we have a competitive advantage versus other suppliers to the Brazilian Ministry of Health, assuming other aspects of our product offering through FIOCRUZ are otherwise competitive in comparison. We have no knowledge
+or reason to know of any activities by our employees, distributors or sales agents of any actions which could be in violation of the FCPA, although there can be no assurance of this. 
+Our subsidiary Chembio Diagnostics Malaysia Sdn. Bhd. is located in Malaysia. There have been numerous high-profile corruption cases, and corruption is one of the
+most problematic factors for doing business in Malaysia. While the Malaysian government has acknowledged the problem, it appears that endemic corruption is continuing and that market-based principles are not applied in cases involving
+individuals with high-level political access. To the extent bribery and similar practices continue to exist in Malaysia, U.S. companies such as ours, which are subject to U.S. laws making it illegal to pay bribes to foreign officials, may make
+us less competitive in winning business in Malaysia when competing with non-U.S. companies. 
+Risks Related to Intellectual Property 
+Our Success Depends on Our Ability to Protect Our Proprietary Technology. We Rely on Trade Secret Laws and Agreements with Our Key
+Employees and Other Third Parties to Protect Our Proprietary Rights, and We cannot be sure that these Laws or Agreements will Adequately Protect Our Rights. 
+Our industry places considerable importance on obtaining patent, trademark and trade secret protection, as well as other intellectual property
+rights, for new technologies, products and processes. Our success depends, in part, on our ability to develop and maintain a strong intellectual property portfolio or obtain licenses to patents and technologies, both in the United States and
+in other countries. If we cannot continue to develop, obtain and protect intellectual property rights, our revenues and gross profits could be adversely affected. Moreover, our current and future licenses or other rights to patents and other
+technologies may not be adequate for the operation of our business. 
+As appropriate, we intend to file patent applications and obtain patent protection for our proprietary technology. These patent applications and patents
+will cover, as applicable, compositions of matter for our products, methods of making those products, methods of using those products and apparatuses relating to the use or manufacture of those products. However, there have been changes to the patent
+laws and proposed changes to the rules of the U.S. Patent and Trademark Office, which may impact our ability to protect our technology and enforce our intellectual property rights. For example, in 2011, the U.S. enacted sweeping changes to the U.S.
+patent system under the Leahy-Smith America Invents Act, including changes that would transition the U.S. from a “first-to-invent” system to a “first-to-file” system and alter the processes for challenging issued patents. These changes could increase
+the uncertainties and costs surrounding the prosecution of our patent applications and the enforcement or defense of our issued patents. 
+We believe that factors such as the technological and creative skills of our personnel, strategic relationships, new product developments, frequent product
+enhancements and name recognition are essential to our success. All our management personnel are bound by non-disclosure agreements. If personnel leave our employment, in some cases we would be required to protect our intellectual property rights
+pursuant to common law theories which may be less protective than provisions of employment, non-competition or non-disclosure agreements. 
+We seek to protect our proprietary products under trade secret and copyright laws, enter into license agreements for various materials and methods employed
+in our products, and enter into strategic relationships for distribution of the products. These strategies afford only limited protection. We currently have some foreign patents issued, and we are seeking additional patent protection in several
+other foreign jurisdictions for our DPP and optical technology. We have licenses to reagents (antigens and peptides) used in several of our products and products under development. Despite our efforts to protect our proprietary assets, and respect
+the intellectual property rights of others, we participate in several markets where intellectual property rights protections are of little or no value. This can place our products and our company at a competitive disadvantage. 
+Moreover, issued patents remain in effect for a fixed period and after expiration will not provide protection of the inventions they cover. Once our patents
+expire, we may be faced with increased competition, which could reduce our revenues. We may also not be able to successfully protect our rights to unpatented trade secrets and know-how. 
+To facilitate development and commercialization of a proprietary technology base, we may need to obtain additional licenses to patents or other proprietary
+rights from other parties. Obtaining and maintaining these licenses, which may not be available, may require the payment of up-front fees and royalties. In addition, if we are unable to obtain these types of licenses, our product development and
+commercialization efforts may be delayed or precluded. 
+Any Future Intellectual Property Disputes could Require Significant and Limit or Eliminate Our Ability to Sell Products or Use Certain
+Technologies. 
+We may be required to expend substantial resources in asserting or protecting our intellectual property rights, or in defending suits related to
+intellectual property rights. We may seek to enforce our patents or other intellectual property rights through litigation. Such litigation is prevalent and is expected to continue. In our business, there are a large number of patents and patent
+applications similar to our products, and additional patents may be issued to third parties relating to our product areas. We, our customers or our suppliers may be sued for infringement of patents or misappropriation of other intellectual property
+rights with respect to one or more of our products. We may also have disputes with parties that license patents to us if we believe the license is no longer needed for our products or the licensed patents are no longer valid or enforceable. 
+There are a large number of patents in our industry, and the claims of these patents appear to overlap in many cases. Therefore there is a significant
+amount of uncertainty regarding the extent of patent protection and infringement. Companies may have pending patent applications, which are typically confidential for the first eighteen months following filing that cover technologies we incorporate
+in our products. Accordingly, we may be subjected to substantial damages for past infringement or be required to modify our products or stop selling them if it is ultimately determined that our products infringe a third party’s proprietary rights. In
+addition, governmental agencies could commence investigations or criminal proceedings against our employees or us relating to claims of misuse or misappropriation of another party’s proprietary rights. 
+If we are involved in litigation or other legal proceedings with respect to patents or other intellectual property and proprietary technology, it could
+adversely affect our revenues, results of operations, market share and business because (1) it could consume a substantial portion of managerial and financial resources; (2) its outcome would be uncertain and a court may find that our patents are
+invalid or unenforceable in response to claims by another party or that the third-party patent claims are valid and infringed by our products; (3) the pendency of any litigation may in and of itself cause our distributors and customers to reduce or
+terminate purchases of our products; (4) a court could award a preliminary and/or permanent injunction, which would prevent us from selling our current or future products; and (5) an adverse outcome could subject us to the loss of the protection of
+our patents or to liability in the form of past royalty payments, penalties, reimbursement of litigation costs and legal fees, special and punitive damages, or future royalty payments, any of which could significantly affect our future earnings. 
+16 
+Table of Contents 
+Under certain contracts with third parties, we may indemnify the other party if our products or activities have actually or allegedly infringed upon,
+misappropriated or misused another party’s proprietary rights. Furthermore, our products may contain technology provided to us by third parties, and we may be unable to determine in advance whether such technology infringes the intellectual property
+rights of a third party. These other parties may also not be required or financially able to indemnify us in the event that an infringement or misappropriation claim is asserted against us. 
+There may also be other types of disputes that we become involved in regarding intellectual property rights, including state, federal or foreign
+court litigation, and patent interference, patent reissue, patent reexamination, or trademark opposition proceedings in the United States Patent and Trademark Office. Opposition or revocation proceedings could be instituted in a foreign patent office
+as well. These proceedings permit certain persons to challenge the validity of a patent on the grounds that it was known from the prior art. The filing of such proceedings, or the issuance of an adverse decision in such proceedings, could result in
+the loss of valuable patent rights that could have a material adverse effect on our business, financial condition, results of operations and growth prospects. 
+Risks Related to Our Third Party Collaborators 
+Our Use of Third-Party Suppliers, some of which may Constitute Our Sole Supply Source, for Certain Important Product Components and
+Materials Presents Risks that Could Have Negative Consequences for Our Business. 
+We purchase certain HIV antigens, a syphilis antigen, the nitrocellulose, and certain other critical components used in our
+STAT-PAK, STAT-VIEW, SURE CHECK and DPP product lines from a sole or limited number of sources. If for any reason these suppliers become unwilling or unable to supply our antigen, nitrocellulose, or other critical component needs, we believe that
+alternative supplies could be obtained at a competitive cost. However, a change in any of the antigens, nitrocellulose or other critical components used in our products would require additional development work and approval by the FDA and other
+regulatory agencies. In addition, it may be difficult to find such an alternate supply source in a reasonable time period or on commercially reasonable terms, if at all. As a result, the termination or limitation of our relationship with one or
+more of these suppliers could require significant time to complete, increase our costs, and disrupt or discontinue our ability to manufacture and sell the affected products. 
+With some of these suppliers, we do not have long-term agreements and instead purchase components and
+materials through a purchase order process. As a result, these suppliers may stop supplying us components and materials, limit the allocation of supply and equipment to us due to increased industry demand, or significantly increase their prices
+at any time with little or no advance notice. Our reliance on a limited number of suppliers could also result in delivery problems, reduced control over product pricing and quality, and our inability to identify and qualify another supplier in a
+timely manner. 
+Moreover, some of these suppliers may experience financial difficulties that could prevent them from supplying
+us with components or subassemblies used in the design and manufacture of our products. In addition, these suppliers may experience manufacturing delays or shut downs due to circumstances beyond their control, such as labor issues, political
+unrest or natural disasters. 
+Any supply deficiencies could materially and adversely affect our ability to fulfill customer orders and our
+results of operations. The availability of critical components and materials from sole- or limited source suppliers could reduce our control over pricing, quality and timely delivery, increase our costs, could disrupt our ability to manufacture
+and sell, and preclude us from manufacturing and selling, certain of our products into one or more markets. Any such event could have a material adverse effect on our results of operations, cash flow and business. 
+We May Work with Strategic Collaborators to Assist in Developing and Commercializing Our Products, which could Limit Rights We Receive
+from the Collaborations and Exposes Us to Other Risks Outside Our Control. 
+Some business opportunities that require a technology controlled by a third party, a significant level of investment for development and commercialization
+or a distribution network beyond our existing sales force may necessitate involving one or more strategic collaborators. As part of our strategy for development and commercialization of our products, we may enter into arrangements with distributors
+or other third-parties. Relying on such collaborative relationships could be risky to our business for a number of reasons, including: (i) we may be required to transfer material rights to such strategic collaborators, licensees and others; (ii) our
+collaborators may not obtain regulatory approvals necessary to continue the collaborations in a timely manner; (iii) our collaborators may decide to terminate our collaborative arrangement or become insolvent; (iv) our collaborators may develop
+technologies or components competitive with our products; (v) disagreements with collaborators could result in the termination of the relationship or litigation; and (vi) we may not be able to agree to future collaborative arrangements, or renewals
+of existing collaborative agreements, on acceptable terms or at all. 
+We expect our collaborators will have an economic motivation to succeed in performing their contractual responsibilities under our agreements, there is no
+assurance that they will do so. Due to our reliance on strategic agreements, it can make it difficult to accurately forecast our future revenues and operating results. 
+Our Ability to Grow Our Business will be Limited if We Fail to Maintain Existing Distribution Channels or Develop New Distribution
+Channels. 
+We collaborate with laboratories, diagnostic companies and distributors in order to sell our products. The sale of our products depends in large part on our
+ability to sell products to these customers and on the marketing and distribution abilities of the companies with which we collaborate and work with. 
+By relying on distributors or third-parties to market and sell our products could negatively impact our business for various reasons, including: (i) we may
+not be able to find suitable distributors for our products on satisfactory terms, or at all; (ii) agreements with distributors may prematurely terminate or may result in litigation between the parties; (iii) our distributors or other customers may
+not fulfill their contractual obligations and distribute our products in the manner or at the levels we expect; (iv) our distributors may prioritize their own private label products that compete with our products; (v) Our existing distributor
+relationships or contracts may preclude or limit us from entering into arrangements with other distributors; and (vi) we may not be able to negotiate new or renew existing distribution agreements on acceptable terms, or at all. 
+We will try to maintain and expand our business with distributors and customers and make every effort to require that they fulfill their
+contractual obligations, but there can be no assurance that such companies will do so or that new distribution channels will be available on satisfactory terms. If we are unable to do so, our business will be negatively impacted. 
+Our U.S. Government Contracts Require Compliance with Numerous Laws and Increases Our Risk and Liability. 
+We are currently receiving funding from the U.S. government related to DPP Zika , and our growth strategy targets sales to U.S. government entities. As a result of our U.S. government funding and potential product sales to the U.S. government, we must comply with
+laws and regulations relating to the award, administration and performance of U.S. government contracts. U.S. government contracts typically contain a number of extraordinary provisions that would not typically be found in commercial contracts
+and which may create a disadvantage and additional risks to us as compared to competitors that do not rely on government contracts. As a U.S. government contractor, we are subject to increased risks of investigation, criminal prosecution and
+other legal actions and liabilities to which purely private sector companies are not. The results of any such actions could adversely impact our business and have an adverse effect on our consolidated financial performance. 
+A violation of specific laws and regulations could result in the imposition of fines and penalties or the termination of our contracts, as well as suspension or
+debarment. The suspension or debarment in any particular case may be limited to the facility, contract or subsidiary involved in the violation or could be applied to our entire enterprise in certain severe circumstances. Even a narrow scope
+suspension or debarment could result in negative publicity that could adversely affect our ability to renew contracts and to secure new contracts, both with the U.S. government and private customers, which could materially and adversely affect
+our business and results of operations. Fines and penalties could be imposed for failing to follow procurement integrity and bidding rules, employing improper billing practices or otherwise failing to follow rules relating to billing on cost-plus
+contracts, receiving or paying kickbacks, or filing false claims, among other potential violations. In addition, we could suffer serious reputational harm and the value of our Common Stock could be negatively affected if allegations of
+impropriety related to such contracts are made against us. 
+Our U.S. Government Contracts are Subject to Future Funding and the Government’s Choice to
+Exercise Options, and may be Terminated at the Government’s Convenience. 
+Our contracts with the U.S. government are subject to future funding and are subject to the right of the
+government to terminate the contracts in whole or in part for its convenience. There is pressure for the U.S. government to reduce spending. The non-appropriation of funds or the termination for the government’s convenience of our contracts could
+negatively affect our financial results. If levels of U.S. government expenditures and authorizations for emerging diseases decrease or shift to programs in areas where we do not offer products or are not developing product candidates, or if the
+U.S. government otherwise declines to exercise its options under its contracts with us, our business, revenues and other operating results would suffer. 
+Risks Related to Regulations 
+Because We may not be Able to Obtain or Maintain the Necessary Regulatory Approvals for Some of Our Products, We may not Generate
+Revenues in the Amounts We Expect, or in the Amounts Necessary to Continue Our Business. Our Existing Products as well as Our Manufacturing Facility Must Meet Quality Standards and are Subject to Inspection by a Number of Domestic Regulatory and
+Other Governmental and Non-Governmental Agencies. 
+All of our proposed and existing products are subject to regulation in the U.S. by the U.S. Food and Drug Administration, the U.S. Department of Agriculture
+and/or other domestic and international governmental, public health agencies, regulatory bodies or non-governmental organizations. In particular, we are subject to strict governmental controls on the development, manufacture, labeling, distribution
+and marketing of our products. The process of obtaining required approvals or clearances varies according to the nature of, and uses for, a specific product. These processes can involve lengthy and detailed laboratory testing, human or animal
+clinical trials, sampling activities, and other costly, time-consuming procedures. The submission of an application to a regulatory authority does not guarantee that the authority will grant an approval or clearance for that product. Each authority
+may impose its own requirements and can delay or refuse to grant approval or clearance, even though a product has been approved in another country. 
+The time taken to obtain approval or clearance varies depending on the nature of the application and may result in the passage of a significant period of
+time from the date of submission of the application. Delays in the approval or clearance processes increase the risk that we will not succeed in introducing or selling the subject products, and we may determine to devote our resources to different
+products. 
+Changes in government regulations could increase our costs and could require us to undergo additional trials or procedures, or could make it impractical or
+impossible for us to market our products for certain uses, in certain markets, or at all. 
+17 
+Table of Contents 
+Changes in government regulations may adversely affect our financial condition and results of operations because we may have to incur additional expenses if
+we are required to change or implement new testing, manufacturing and control procedures. If we are required to devote resources to develop such new procedures, we may not have sufficient resources to devote to research and development, marketing,
+or other activities that are critical to our business. 
+We can manufacture and sell our products only if we comply with regulations and quality standards established by government agencies such as the FDA and the
+U.S. Department of Agriculture as well as by non-governmental organizations such as the ISO and WHO. We have implemented a quality control system that is intended to comply with applicable regulations. Although FDA approval is not required for the
+export of our products, there are export regulations promulgated by the FDA that specifically relate to the export of our products that require compliance with FDA QSRs and that also require meeting certain documentary requirements regarding the
+approval of the product in export markets. 
+If We do not Comply with FDA or Other Regulatory Requirements, We may be Required to Suspend Production or Sale of Our Products or
+Institute a Recall, which could Result in Higher Costs and a Loss of Revenues. 
+Regulations of the FDA and other federal, state and foreign regulatory agencies have significant effects on many aspects of our operations, and the
+operations of our suppliers and distributors, including packaging, labeling, manufacturing, adverse event reporting, recalls, distribution, storage, advertising, promotion and record keeping. We are subject to routine inspection by the FDA and other
+agencies to determine compliance with QSRs and FDA regulatory requirements in the United States and other applicable regulations worldwide, including but not limited to ISO standards. We believe that our facilities and procedures are in material
+compliance with the FDA requirements and ISO standards, but the regulations may be unclear and are subject to change, and we cannot be sure that the FDA or other regulators will agree with our compliance with these requirements. The FDA and foreign
+regulatory agencies may require post-marketing testing and surveillance to monitor the performance of approved or cleared products or impose conditions on any product clearances or approvals that could restrict the distribution or commercial
+applications of those products. Regulatory agencies may impose restrictions on our or our distributors’ advertising and promotional activities or preclude these activities altogether if a noncompliance is believed to exist. In addition, the
+subsequent discovery of previously unknown problems with a product may result in restrictions on the product or additional regulatory actions, including withdrawal of the product from the market. 
+Our inability to comply with the applicable requirements of the FDA can result in, among other things, 483 notices, warning letters, administrative or
+judicially imposed sanctions such as injunctions, recall or seizure of products, civil penalties, withdrawal of product registrations, total or partial suspension of production, refusal to grant premarket clearance or PMA approval for devices,
+marketing clearances or approvals, or criminal prosecution. The ability of our suppliers to supply critical components or materials and of our distributors to sell our products could also be adversely affected if their operations are determined to be
+out of compliance. Such actions by the FDA and other regulatory bodies could adversely affect our revenues, costs and results of operations. 
+We must frequently make judgment decisions with respect to compliance with applicable laws and regulations. If regulators subsequently disagree with how we
+have sought to comply with these regulations, we could be subjected to substantial civil and criminal penalties, as well as product recall, seizure or injunction with respect to the sale of our products. Our reputation could be substantially impaired
+if we are assessed any civil and criminal penalties and limit our ability to manufacture and market our products which could have a material adverse effect on our business. 
+Our Inability to Respond to Changes in Regulatory Requirements could Adversely Affect Our Business. 
+We believe that our products and procedures are in material compliance with all applicable FDA regulations,
+ISO requirements, and other applicable regulatory requirements, but the regulations regarding the manufacture and sale of our products, the QSR and ISO requirements, and other requirements may be unclear and are subject to change. Newly
+promulgated regulations could require changes to our products, necessitate additional clinical trials or procedures, or make it impractical or impossible for us to market our products for certain uses, in certain markets, or at all. The FDA and
+other regulatory authorities also have the ability to change the requirements for obtaining product approval and/or impose new or additional requirements as part of the approval process. These changes or new or additional requirements may occur
+after the completion of substantial clinical work and other costly development activities. The implementation of such changes or new or additional requirements may result in additional clinical trials and substantial additional costs and could
+delay or make it more difficult or complicated to obtain approvals and sell our products. In addition, the FDA may revoke an Emergency Use Authorization under which our products are sold, where it is determined that the underlying health
+emergency no longer exists or warrants such authorization. Such revocation would preclude the sale of our affected products unless and until a further regulatory approval or authorization is obtained. We cannot predict the effect, if any, that
+these changes might have on our business, financial condition or results of operations. 
+Demand for Our Products may be Affected by FDA Regulation of Laboratory-Developed Tests and Genetic Testing. 
+Regulatory responsibility over instruments, test kits, reagents and other devices used to perform diagnostic testing by clinical laboratories is covered by
+the FDA. The FDA has previously taken the position that it has regulatory authority over laboratory-developed tests, or LDTs, but has exercised enforcement discretion by not regulating most LDTs performed by high complexity CLIA-certified
+laboratories. LDTs are tests designed, developed, and performed in-house by a laboratory. These laboratories are subject to CLIA regulation but such laboratories have previously not been subject to regulation by FDA under the agency’s medical device
+requirements. 
+However, the FDA has announced that it would begin regulating LDTs, and in October 2014 the FDA issued proposed guidance on the regulation of LDTs for
+public comment. But, on November 18, 2016, the FDA announced that it would not finalize the proposed guidance prior to the end of the Obama administration. On January 13, 2017, the FDA released a discussion paper synthesizing public comments on the
+2014 draft guidance documents and outlining a possible approach to regulation of LDTs. The discussion paper has no legal status and does not represent a final version of the LDT draft guidance documents. We cannot predict what policies the Trump
+administration will adopt with respect to LDTs. If the FDA increases regulation of LDTs, it could make it more difficult for laboratories and other customers to continue offering LDTs that involve genetic or molecular testing. This, in turn, could
+reduce demand for our products and adversely impact our revenues. 
+In Addition to FDA Requirements, We Are Subject to Several Government Regulations, Compliance with which could Increase Our Costs and
+Affect Our Operations. 
+In addition to the FDA regulations previously described, laws and regulations in some states may restrict our ability to sell products in those states. 
+We must comply with numerous laws related to safe working conditions, environmental protection, disposal of hazardous substances, fire hazard control,
+manufacturing practices and labor or employment practices. Compliance with these laws or any new or changed laws regulating our business could result in substantial costs. Due to the number of laws and regulations governing our industry, and the
+actions of a number of government agencies that could affect our operations, it is impossible to reliably predict the full nature and impact of these laws and regulations. To the extent the costs and procedures associated with complying with these
+laws and requirements are substantial or it is determined that we do not comply, our business and results of operations could be adversely affected. 
+We may Incur Additional Costs if We do not Comply with Privacy, Security and Breach Notification Regulations. 
+We believe that we are not a covered entity nor a business associate of a covered entity and are not responsible for complying with the Health Insurance Portability
+and Accountability Act of 1996, or HIPAA. Even though we likely are not a covered entity under HIPAA, we do have in place administrative, technical and physical safeguards to protect the privacy and security of consumers’ personal information.] We
+are required to comply with varying state privacy, security and breach reporting laws. If we fail to comply with existing or new laws and regulations related to properly transferring data containing consumers’ personal information, we could be
+subject to monetary fines, civil penalties or criminal sanctions. Also, there are other federal and state laws that protect the privacy and security of consumers’ personal information, and we may be subject to enforcement by various governmental
+authorities and courts resulting in complex compliance issues. We could incur damages under state laws pursuant to an action brought by a private party for the wrongful use or disclosure of consumers’ personal information. 
+Failure to Comply With Recent European Data Protection Requirements could Increase Our Costs. 
+The EU has adopted a comprehensive overhaul of its data protection regime from the prior national legislative approach to
+a single European Economic Area Privacy Regulation called the General Data Protection Regulation, or GDPR, which came into effect on May 25, 2018. The new EU data protection regime extends the scope of the EU data protection law to all foreign
+companies processing data of EU residents. It imposes a strict data protection compliance regime with severe penalties of up to the greater of 4% of worldwide turnover and €20 million and includes new rights such as the “portability” of personal
+data. Although the GDPR will apply across the EU without a need for local implementing legislation, as had been the case under the prior data protection regime, local data protection authorities will still have the ability to interpret the GDPR,
+which has the potential to create inconsistencies on a country-by-country basis. We are evaluating these new requirements and implementing a plan to ensure compliance. Complying with the enhanced obligations imposed by the GDPR may result in
+significant costs to our business and require us to amend certain of our business practices. Further, we have no assurances that violations will not occur, particularly given the complexity of the GDPR, as well as the uncertainties that accompany
+new, comprehensive legislation. 
+18 
+Table of Contents 
+If We are not Able to Manufacture Products in Accordance with Applicable Requirements, It could Adversely Affect Our Business. 
+Our products must meet detailed specifications, performance standards and quality requirements. As a result, our products and the materials used in their
+manufacture or assembly undergo regular inspections and quality testing. Factors such as defective materials or processes, mechanical failures, human errors, environmental conditions, changes in materials or production methods, and other events or
+conditions could cause our products or the materials used to produce or assemble our products to fail inspections and quality testing or otherwise not perform in accordance with our label claims or the expectations of our customers. 
+If we are not able to meet the applicable specifications, performance standards, quality requirements or customer expectations could adversely affect our
+ability to manufacture and sell our products or comply with regulatory requirements. These events could, in turn, adversely affect our revenues and results of operations. 
+Healthcare Fraud and Abuse Laws Could Adversely Affect Our Business and Results of Operations. 
+There are various federal and state laws targeting fraud and abuse in the healthcare industry to which we are subject, including anti-kickback laws, laws constraining
+the sales, false claims laws, marketing and promotion of medical devices by limiting the kinds of financial arrangements that manufacturers of these products may enter into with physicians, hospitals, laboratories and other potential purchasers of
+medical devices. There are other laws we are subject to that require us to report certain transactions between it and healthcare professionals. Violations of these laws are punishable by criminal or civil sanctions, including substantial fines,
+imprisonment and exclusion from participation in government healthcare programs. Many of the existing requirements are new and have not been definitively interpreted by state authorities or courts, and available guidance is limited. We could face
+enforcement action and fines and other penalties, and could receive adverse publicity, unless and until we are in full compliance with these laws, all of which could materially harm us. Furthermore, changes in or evolving interpretations of these
+laws, regulations, or administrative or judicial interpretations, may require us to change our business practices or subject our business practices to legal challenges, which could have a material adverse effect on our business, financial condition
+and results of operations. 
+Our Compliance with Regulations Governing Public Companies is Complex and Expensive. 
+Public companies are subject to various laws and regulations, which have increased the scope, complexity and cost of corporate governance, reporting and
+disclosure practices. For example, we are subject to the Sarbanes-Oxley Act of 2002, The Dodd-Frank Wall Street Reform and Consumer Protection Act and the requirements of The NASDAQ Global Market. The implementation of certain aspects of these laws
+and regulations has required and will continue to require substantial management time and oversight and may require us to incur significant additional accounting and legal costs. We continually review changes with respect to new and proposed rules
+and cannot predict or estimate the amount of additional costs, and the timing of such costs, we may incur. There are several interpretations of these laws and regulations, in many cases due to their lack of specificity, and as a result, their
+application in practice may change as new guidance is provided by regulatory and governing bodies. This may result in continuing uncertainty regarding compliance matters and higher costs. We are committed to maintaining high standards of corporate
+governance and public disclosure, but if we fail to comply with any of these requirements, legal proceedings may be initiated against us, which may adversely affect our business. 
+Risks Related to Our Common Stock 
+Our Common Stock has Limited Liquidity, and Investors may not be Able to Sell as Much Stock as They Want at Prevailing Market
+Prices or at all. 
+The liquidity of our Common Stock depends on several factors, including but not limited to our financial results and overall market conditions, so it is not possible
+to predict whether this level of liquidity will continue, be sustained, or decrease. Decreased trading volume in our stock would make it more difficult for investors to sell their shares in the public market at any given time at prevailing prices.
+Our management and larger stockholders exercise significant control over our company. 
+The Price of Our Common Stock could Continue to be Volatile. 
+The price of our Common Stock has been volatile and may be volatile in the future. The following factors, among others, could have a significant impact on
+the market for our Common Stock: (1) the performance of our business; (2) clinical results with respect to our products or those of our competitors; (3) the gain or loss of significant contracts and availability of funding for the purchase of our
+products; (4) actions undertaken by the Congress or the Presidential Administration; (5) changes in our relations with our key customers, distributors or suppliers; (6) developments in patent or other proprietary rights; (7) litigation or threatened
+litigation; (8) general market and economic conditions; (9) the relatively low trading volume for our Common Stock; (10) changes in competition; (11) Complaints or concerns about the performance or safety of our products and publicity about those
+issues, including publicity expressed through social media or otherwise over the internet; (12) failure to achieve, or changes in, financial estimates by securities analysts and comments or opinions about us by securities analysts or major
+stockholders; (13) announcement of regulatory or enforcement actions by the FDA or other agencies against us, our products or our customers; (14) changes in our operating results; and (15) terrorist attacks, civil unrest, war and national disasters. 
+19 
+Table of Contents 
+Overall, the stock market has experienced price and volume fluctuations that have affected the market price of our Common Stock, as well as the stock of
+many other similar companies. Such price fluctuations are generally unrelated to the operating performance of the specific companies whose stock is affected. 
+After the volatility in the market price of a company’s stock, class action litigation has occurred against the issuing company. If we were subject to this
+type of litigation in the future, we could incur substantial costs and the attention and resources of our management could be diverted, each of which could have a material adverse effect on our revenue and earnings. Any adverse determination in this
+type of litigation could also subject us to significant liabilities. 
+Sales of Our Common Stock by Existing Stockholders, Executive Officers or Directors could Depress the Market Price of Our Common Stock. 
+If our existing stockholders, officers or directors sell our Common Stock in the public market, or the perception that such sales may occur, it could
+negatively affect the price of our Common Stock. We are unable to estimate the number of shares of our Common Stock that may actually be resold in the public market since this will depend on the market price for our Common Stock, the individual
+circumstances of the sellers and other factors. 
+Institutional stockholders own significant amounts of our Common Stock. If one or more of these stockholders sell large portions of their holdings in a
+relatively short time, the prevailing price of our Common Stock could be negatively affected. In addition, it is possible that one or more of our executive officers or non-employee members of our Board of Directors could sell shares of our Common
+Stock during an open trading window. These transactions and the perceived reasons for these transactions could have a negative effect on the prevailing market price of our Common Stock. 
+We do not Intend to Pay Cash Dividends on Our Common Stock. 
+We do not expect to pay any cash dividends on our Common Stock and currently intend to retain our earnings, if any, to finance the expansion of our
+business. Therefore, the success of an investment in our Common Stock will depend entirely upon any future increase in value of our Common Stock. There is no guarantee that our Common Stock will gain value or even maintain the price at which
+investors purchased their shares. 
+If We or Our Independent Registered Public Accounting Firm Concludes That Our Internal Control Over Financial Reporting is Not Effective,
+Investor Confidence and the Value of Our Common Stock May be Adversely Impacted. 
+The SEC has adopted rules requiring us, as a public company, to include a report in our Annual Reports on Form 10-K that contains an assessment by
+management of the effectiveness of our internal control over financial reporting. In addition, our independent registered public accounting firm must report on the effectiveness of these internal controls. 
+We believe our internal controls will continue to evolve as our business develops. We continue to review our internal control over financial reporting in an
+effort to ensure compliance with SEC rules and regulations, any control system, regardless of how well designed and operated, can provide only reasonable assurance that its objectives will be met. In addition, the overall quality of our internal
+controls may be affected by the internal control over financial reporting implemented by any business we acquire and our ability to assess and successfully integrate the internal controls of any such business. 
+If our independent registered public accounting firm is not satisfied with our internal control over financial reporting or the level at which our controls
+are documented, designed, implemented, or tested, or if the independent registered public accounting firm interprets the requirements, rules or regulations differently than we do, then it may issue a report noting such dissatisfaction. We also could
+conclude that our internal control over financial reporting is not effective. These events could result in an adverse reaction in the financial marketplace, which ultimately could negatively impact the market price of our Common Stock. 
+Any Future Issuances of Shares of Our Common Stock by Us Could Harm the Price of Our Common Stock and Our Ability to Raise Funds in New
+Equity Offerings. 
+Any future sales of a substantial number of our shares of Common Stock or other equity-related securities, or the perception that such sales may occur,
+could adversely affect the price of our Common Stock, and could impair our ability to raise capital through future offerings of equity or equity-related securities. 
+Our Management and Larger Stockholders Exercise Significant Control Over Us. 
+As of December 31, 2018, our named executive officers, directors and 5% stockholders beneficially owned approximately 14.21% of our voting power, which
+includes 1 large investor that beneficially owns approximately 8.73%, of the outstanding stock. For the foreseeable future, and assuming these ownership percentages continue to apply, to the extent that these parties vote similarly, they may be able
+to exercise significant control over many matters requiring approval by the board of directors or our stockholders. As a result, they may be able to: 
+• 
+control the composition of our board of directors; 
+• 
+control our management and policies; 
+• 
+determine the outcome of significant corporate transactions, including changes in control that may be beneficial to stockholders; and, 
+• 
+act in each of their own interests, which may conflict with or differ from the interests of each other or the interests of the other stockholders. 
+20 
+Table of Contents 
+ITEM 2. 
+PROPERTIES 
+Our corporate headquarters and U.S. manufacturing, administrative offices, and research facilities are located in leased space in Medford, New York, pursuant to a lease covering approximately 39,650 square feet and
+expiring on April 30, 2019. We also lease nearby warehouse space and additional administrative offices in Holbrook, New York, pursuant to a lease covering approximately 21,700 square feet and expiring on April 30, 2020. 
+On February 5, 2019, we entered into a commercial real estate lease for new corporate
+headquarters comprised of 70,000 square feet of office, research and development, and warehouse space located at 555 Wireless Boulevard, Hauppauge, New York. The lease has an initial term of eleven years that can be extended, at our option, for
+two additional terms of five years each. Rent under the lease, which is payable in monthly installments, totals approximately $900,000 for the initial year and then increases by approximately three percent each succeeding year. 
+On February 5, 2019, we also entered into an agreement to sublet the space at Holbrook, New York. The sublease has a term that will (a) commence on the date we
+vacate the premises and (b) terminate on April 29, 2020. The sublessee will pay us 50% of our rent and additional rent payments, which will total approximately $100,000 per year during the term of the sublease. 
+Our European headquarters and Center of Excellence for Optical Technology is located in leased office and manufacturing space in Berlin, Germany.
+Our Southeast Asia manufacturing, warehouse, and commercial facilities are located in leased space in Kuala Lumpur, Malaysia. We regularly review our real estate portfolio and develop footprint strategies to support our customers’ global plans, while
+at the same time supporting our technical needs and controlling operating expenses. 
+ITEM 3. 
+LEGAL PROCEEDINGS 
+From time to time we may become involved in legal proceedings or may be subject to claims arising in
+the ordinary course of our business. Although the results of litigation and claims cannot be predicted with certainty, we currently believe that the final outcome of these ordinary course matters will not have a material adverse effect on our
+business, operating results, financial condition or cash flows. Regardless of the outcome, litigation can have an adverse impact on us because of defense and settlement costs, diversion of management resources and other factors. 
+21 
+Table of Contents 
+PART II 
+ITEM 5. 
+MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+Listing Information 
+Our stock is listed on the NASDAQ Global Select Market of the NASDAQ Stock Market LLC under the symbol “CEMI.” 
+Holders 
+As of March 1, 2019 , there were 132 record owners of our Common Stock (including nominee holders such as banks and brokerage firms who hold shares for beneficial owners). 
+Recent Sales of Unregistered Securities 
+There were no sales of unregistered securities during
+the quarter ended December 31, 2018. 
+Issuer Purchases of Equity Securities 
+We did not repurchase any of our equity securities during the quarter ended December 31, 2018. 
+22 
+Table of Contents 
+ITEM 7. 
+MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+The following discussion and analysis should be read in conjunction with the audited
+consolidated financial statements and related notes included in this report. In addition to historical information, the following discussion contains forward-looking statements that involves risks, uncertainties and assumptions. See “Special Note
+Regarding Forward-Looking Statements” at page [2] of this report. Please read “Item1A. Risk Factors” for a discussion of factors that could cause our actual results to differ materially from our expectations. 
+The following discussion is presented in six sections: 
+• 
+Executive Overview 
+• 
+Consolidated Results of Operations 
+• 
+Liquidity and Capital Resources 
+• 
+Recent Developments 
+• 
+Significant Accounting Policies and Critical Accounting Estimates 
+• 
+Recently Issued Accounting Pronouncements 
+Executive Overview 
+Through our wholly owned subsidiaries, Chembio Diagnostic Systems Inc., Chembio Diagnostics Malaysia Sdn Bhd and opTricon, we develop, manufacture and
+commercialize point-of-care diagnostic tests that are used to detect or diagnose diseases. All products that are currently being developed are based on our patented DPP technology, a novel point-of-care diagnostic platform that offers certain
+customer advantages as compared to traditional lateral flow technology. Chembio was formed in 1985. 
+Recent operational accomplishments and highlights include: 
+• 
+Achieved total revenue of $33.4 million for full year 2018, an increase of 39% over prior year 
+• 
+Achieved product sales of $26.7 million for full year 2018, also an increase of 38% over prior year 
+• 
+Acquired opTricon, a developer and manufacturer of hand-held analyzers that when used in combination with our DPP tests, provide quantitative
+results 
+• 
+Advanced technology collaborations with AstraZeneca, Lumira Dx, FIND and others 
+• 
+Purchased a fully-automated DPP test manufacturing line 
+• 
+Hosted analyst and investor day and introducing five-year targets for $100 million of revenue in 2023 and 50% gross margins for year end 2023 
+We strengthened our balance sheet from underwritten public offerings that generated net proceeds of $10.9 million
+in February 2018 and $16.5 million in November 2018. See “—Recent Developments.” 
+Our product commercialization and product development efforts a re focused in two areas: infectious diseases (which includes both sexually transmitted disease and tropical/fever
+disease) and technology collaborations. In infectious disease, we are commercializing tests for HIV and Syphilis. In tropical and fever disease, we are commercializing tests for dengue virus, Zika virus, chikungunya virus, and ebola virus,
+individually or as part of an advanced multiplex test. We are also developing tests for lassa, Marburg, malaria, leptospirosis, Rickettsia typhi ,
+Burkholderia pseudomallei , and Orientia
+tsutsugamushi , individually or as part of a fever panel test, and hepatitis C. Through technology collaborations, we are developing tests for a specific form of cancer, concussion, bovine tuberculosis, and for eosinophilic respiratory
+disease, the latter in collaboration with global biopharmaceutical company AstraZeneca. 
+Large and growing markets have been established for these kinds of tests, initially in high prevalence regions where they are indispensable for large scale
+prevention and treatment programs. Our product development is focused on areas where the availability of rapid point-of-care screening, diagnostic, or confirmatory results can improve health outcomes. More generally, we believe there is and will
+continue to be a growing demand for diagnostic products that can provide accurate, actionable diagnostic information in a rapid, cost-effective manner at the point of care. 
+Our products are sold to medical laboratories and hospitals, governmental and public health entities, non-governmental organizations, medical professionals
+and retail establishments, both domestically and internationally, under our STAT-PAK, SURE CHECK, STAT-VIEW or DPP registered trademarks, or under the private labels of our marketing partners. 
+Consolidated Results of Operations 
+The results of operations for the years ended December 31, 2018 and 2017 were as follows: 
+Year Ended December 31, 
+2018 
+2017 
+TOTAL REVENUES 
+$ 
+33,409,251 
+100 
+% 
+$ 
+24,015,427 
+100 
+% 
+COSTS AND EXPENSES: 
+Cost of product sales 
+21,427,243 
+64 
+% 
+12,921,157 
+54 
+% 
+Research and development expenses 
+8,526,256 
+26 
+% 
+8,555,381 
+36 
+% 
+Selling, general and administrative expenses 
+11,100,775 
+33 
+% 
+8,963,363 
+37 
+% 
+Acquisition costs 
+337,645 
+1 
+% 
+58,076 
+0 
+% 
+41,391,919 
+124 
+% 
+30,497,977 
+127 
+% 
+LOSS FROM OPERATIONS 
+(7,982,668 
+) 
+(24 
+)% 
+(6,482,550 
+) 
+(27 
+)% 
+OTHER INCOME 
+49,498 
+0 
+% 
+22,485 
+0 
+% 
+LOSS BEFORE INCOME TAXES 
+(7,933,170 
+) 
+(24 
+)% 
+(6,460,065 
+) 
+(27 
+)% 
+Income tax (benefit) provision 
+(67,521 
+) 
+0 
+% 
+(88,305 
+) 
+0 
+% 
+NET LOSS 
+$ 
+(7,865,649 
+) 
+(24 
+)% 
+$ 
+(6,371,760 
+) 
+(27 
+)% 
+Percentages in the table reflect the percent of total revenues. 
+23 
+Table of Contents 
+Total Net Revenues 
+Total net revenues during the year ended December 31, 2018 were $33.4 million, an increase of $9.4 million, or 39% compared to 2017. The increase in total net revenues was comprised of the following: 
+• 
+$7.4 million, or 38% increase in net product sales, reflecting gains in Africa, Latin America, and Europe. Africa benefited from or winning the
+single largest tender in our history for the supply of HIV tests to Ethiopia, together with meaningful commercial successes in other countries. Latin America gains reflect continued growth in Brazil, and Europe reflects the increasing
+trend of HIV self-testing. As part of these regional successes and as highlighted above, during November 2018, we completed the acquisition of opTricon. Refer to Note 2 – Acquisition to the audited consolidated financial statements
+included herein for further information regarding the acquisition. 
+• 
+$2.0 million, or 42% increase in R&D and grant, and license and royalty revenues compared to 2017, reflecting our continued success
+in securing governmental, non-governmental, and commercial partnerships, in particular associated with our DPP technology platform. 
+Gross Product Margin 
+Cost of product sales is primarily comprised of material, labor, manufacturing overhead, depreciation and amortization, and other operating expenses. Gross
+product margin is net product sales less cost of product sales, and gross product margin percentage is gross product margin as a percentage of net product sales. 
+Gross product margin decreased by $1.1 million, or 17% compared to 2017. The following schedule calculates gross product margin: 
+For the years ended 
+December 31, 2018 
+December 31, 2017 
+Favorable/ 
+(unfavorable) 
+% Change 
+(in thousands) 
+Net product sales 
+$ 
+26,741 
+$ 
+19,322 
+$ 
+7,419 
+38.4 
+% 
+Less: Cost of product sales 
+(21,427 
+) 
+(12,921 
+) 
+(8,506 
+) 
+65.8 
+% 
+Gross product margin 
+$ 
+5,314 
+$ 
+6,401 
+$ 
+(1,087 
+) 
+(17.0 
+)% 
+Gross product margin % 
+19.9 
+% 
+33.1 
+% 
+The $1.1 million decrease in gross product margin was comprised of the following: 
+• 
+$2.4 million from favorable product sales volume as described above, and 
+• 
+$3.5 million from unfavorable product margins, related to increased labor (including contract labor) to manually assemble our products and the impact of geographic mix
+on average selling prices. 
+Research and Development 
+This category includes costs incurred for clinical and regulatory affairs and other research and development, as follows: 
+For the years ended 
+December 31, 2018 
+December 31, 2017 
+Favorable/ 
+(unfavorable) 
+% Change 
+(in thousands) 
+Clinical and regulatory affairs 
+$ 
+1,307 
+$ 
+2,298 
+$ 
+991 
+43.1 
+% 
+Other research and development 
+7,219 
+6,257 
+(962 
+) 
+(15.4 
+)% 
+Total research and development 
+$ 
+8,526 
+$ 
+8,555 
+$ 
+29 
+0.3 
+% 
+The decrease in clinical & regulatory affairs costs for 2018 as compared to 2017 is primarily associated with our U.S. clinical trial evaluating our DPP
+HIV-Syphilis System, which we completed in December 2017. The increase in other research and development costs is primarily associated with spending associated with the 45% increase in revenue from externally-funded research and development projects. 
+Selling, General and Administrative Expense 
+Selling, general and administrative expense includes administrative expenses, sales and marketing costs including commissions, and other corporate items.
+The $2.1 million, or 23.8%, increase in selling, general and administrative expenses for the year ended December 31, 2018 as compared to 2017 is associated with increased personnel, sales commissions, and non-cash equity compensation expenses. 
+Acquisition Costs 
+Acquisition costs 
+include legal, due diligence, audit, and related costs associated with acquisitions. The $0.3 million, or 481.4% increase in acquisition costs for the year ended December 31, 2018 as compared to 2017 is associated with spending related to the
+acquisition of opTricon in November 2018. The 2017 costs relate to completion of the acquisition of RVR Diagnostics in January 2017. 
+Other Income and Expense 
+Other income and expenses are principally interest income earned on our deposits, net of interest expense, which increased by approximately $27,000 for 2018
+as compared to 2017. 
+Income Tax Provision 
+For 2018 we recognized a tax benefit of $67,521 primarily attributable to the loss generated by Chembio Diagnostics Malaysia. As of December 31, 2018 and
+2017, our deferred tax assets include a full valuation allowance against our deferred tax assets. 
+24 
+Table of Contents 
+Liquidity and Capital Resources 
+During the year ended December 31, 2018, we funded our business operations, including capital expenditures and working
+capital requirements, principally from $27.5 million of net proceeds from two underwritten public offerings and $3.0 million of non-exchange transaction awards from research and development programs. Our operations used cash flow of $11.8 million.
+As of December 31, 2018, we had no outstanding debt other than a $ 0.4 million seller-financed note payable incurred in connection with our purchase of automated manufacturing
+equipment. 
+We believe our existing cash and cash equivalents and our cash flow from operating activities will be
+sufficient to meet our anticipated cash needs for at least the next twelve months. Our future working capital needs will depend on many factors, including the rate of our business and revenue growth, the timing of our automation of U.S.
+manufacturing, and the timing of investment in our research and development as well as sales and marketing. 
+If we are unable to increase our revenues and manage our expenses in accordance with our operating plan, we may not be
+able to generate the cash flow needed to fund our automation of U.S. manufacturing and our investment in research and development and sales and marketing at the time contemplated by our operating plan. In such an event, we may elect to reduce
+the level, or otherwise delay the timing, of such funding and/or such investments, which would likely curtail or delay the growth in our business contemplated by our operating plan and could impair or defer our ability to achieve profitability
+and generate cash flow. 
+If we do not elect to reduce or delay such funding and/or investments, or if we determine to effect one or
+more acquisitions of businesses, technologies or products, we may be required to seek to raise additional funds through public or private financings, strategic relationships, or other arrangements, to the extent funding would be available to us
+on acceptable terms or at all. If we were to raise additional funds through the issuance of equity or convertible securities, the issuance could result in substantial dilution to existing stockholders, and the holders of these new securities or
+debt may have rights, preferences and privileges senior to those of the holders of our Common Stock. 
+Sources of Funds 
+Equity and Equity-Related Securities. We received net proceeds of $10.9
+million from an underwritten public offering of Common Stock in February 2018 and $16.5 million from an underwritten public offering of Common Stock in November 2018. We do not expect to raise additional capital from a public offering of Common
+Stock in 2019. 
+Research and Development
+Awards. We frequently seek research and development programs that may be awarded by government, non-governmental organizations, and non-profit entities, including private foundations. 
+Since 2015 we have earned over $10.8 million of funding from some of the
+world’s leading health organizations, which has helped us accelerate the expansion of our pipeline of infectious disease tests. Our collaborators have included Bill & Melinda Gates Foundation, The Paul G. Allen Family Foundation, FIOCRUZ
+and FIND, as well as U.S. government agencies such as CDC, BARDA and the U.S. Department of Agriculture. See “Item 1. Business—Products” above. During the year ended December 31, 2018, we recognized grant revenue totaling $3.0 from government,
+non-governmental organizations, and non-profit entities. 
+Working
+Capital . The following table sets forth selected working capital information: 
+December 31, 2018 
+(in thousands) 
+Cash and cash equivalents 
+$ 
+12,525 
+Accounts receivable, net of allowance for doubtful amounts 
+7,374 
+Inventories, net 
+7,851 
+Prepaid expenses and other current assets 
+702 
+Total current assets 
+28,452 
+Less: Total current liabilities 
+(6,519 
+) 
+Working capital 
+$ 
+21,933 
+Our cash and cash equivalents at December 31, 2018 were unrestricted
+and held for working capital purposes. We currently intend to retain all available funds and any future earnings for use in the operation of our business and do not anticipate paying any cash dividends. We have not entered into, and do not expect
+to enter into, investments for trading or speculative purposes. Our accounts receivable balance fluctuates from period to period, which affects our cash flow from operating activities. Fluctuations vary depending on cash collections, client mix,
+and the timing of shipment of our products and the invoicing of our research and development activities. 
+Uses of Funds 
+Cash
+Flow Used in Operating Activities . Our operations used $11.8 million of cash during the year ended December 31, 2018,
+primarily due to the net loss adjusted for non-cash items of $6.4 million, a $5.2 million increase in accounts receivable related to the 39% increase in total revenue, and a $3.1 million increase in inventory, offset by a $2.6 million increase in
+accounts payable and accrued liabilities. 
+Acquisition.
+In November 2018, we acquired all of the equity interests of opTricon for a purchase price of $5.5 million in cash, of which (a) $100,000 was deposited in escrow for a potential purchase price adjustment based on the working
+capital of opTricon and (b) $750,000 was deposited in escrow to satisfy certain claims that we may make against the sellers in accordance with the terms of the related purchase agreement. See “—Recent Developments” below. 
+Capital Expenditures . During the year ended December 31, 2018, we continued to invest in
+manufacturing equipment and other fixed assets. Our capital expenditures totaled $1.5 million in 2018. 
+25 
+Table of Contents 
+Effects of Inflation 
+Inflation and changing prices have not had a material effect
+on our business, and we do not expect that they will materially affect our business in the foreseeable future. Any impact of inflation on cost of revenue and operating expenses, especially employee compensation costs, may not be readily recoverable
+in the price of our product offerings. 
+Off-Balance Sheet Arrangements 
+We do not have any off-balance sheet arrangements, as defined in Item 303(a)(4)(ii) of Regulation S-K under the Securities Exchange Act of 1934. 
+Recent Developments 
+On November 5, 2018, we consummated an underwritten registered public offering of 2,726,000 shares of our Common Stock, including the underwriter's entire
+overallotment option of 355,565 shares, at a public offering price of $6.75 per share, for gross proceeds of approximately $18.4 million. The net proceeds, after underwriting discounts and commissions, and estimated expenses, were approximately
+$16.5 million. 
+On November 6, 2018, we acquired opTricon pursuant to a share purchase agreement dated October 17,
+2018. Under the terms of the purchase agreement, we acquired all of the outstanding equity shares of opTricon for a purchase price of $5.5 million in cash, of which (a) $100,000 was deposited in escrow for a potential purchase price adjustment
+based on the working capital of opTricon and (b) $750,000 was deposited in escrow to satisfy certain claims that we may make against the sellers in accordance with the terms of the purchase agreement. 
+In accordance with the purchase agreement, each of Lutz Melchior and Volker
+Plickert, the founders of opTricon, entered into a managing director services agreement pursuant to which they agreed, among other things, to serve as employees of opTricon through November 5, 2021. 
+opTricon, which is based in Berlin, Germany, is a developer and manufacturer of
+handheld analyzers for rapid diagnostic tests. Since 2015 we and opTricon have been parties to an agreement under which we have collaborated in developing our DPP Micro Reader, a handheld, battery-operated analyzer that uses an innovative image
+sensor to provide, when combined with our DPP tests, a quantitative interpretation of diagnostic results. opTricon will become a Chembio Center-of-Excellence for optical technology and will serve as our European headquarters. As part of its ongoing
+business, opTricon will continue to develop and manufacture handheld analyzers for original equipment manufacturers that do not compete with us. The DPP Micro Reader is included in most of our new product development initiatives and regulatory
+approvals and submissions. As a result of the acquisition, we secured global commercial rights to opTricon’s offerings and technology and will be able to produce DPP Micro Readers at a reduced cost, which we believe will enable us to promote DPP
+tests and DPP Micro Readers more actively across global markets. We cannot assure you that we will achieve the intended benefits from the opTricon acquisition. 
+Significant Accounting Policies and Critical Accounting Estimates 
+Our significant accounting policies are described in Note 3 – Significant Accounting Policies to the audited consolidated financial statements included
+herein. Certain of our accounting policies require the application of significant judgment by management in selecting the appropriate assumptions for calculating financial estimates. By their nature, these judgments are subject to an inherent degree
+of uncertainty. These judgments are based on our historical experience, terms of existing contracts, our evaluation of trends in the industry, information provided by our customers and information available from other outside sources, as appropriate.
+We consider an accounting estimate to be critical if: 
+• 
+It requires us to make assumptions about matters that were uncertain at the time we were making the estimate, and 
+• 
+Changes in the estimate or different estimates that we could have selected would have had a material impact on our financial condition or
+results of operations. 
+The following listing is not intended to be a comprehensive list of all of our accounting policies. In many cases, the accounting treatment of a particular
+transaction is specifically dictated by accounting principles generally accepted in the United States, with no need for management’s judgment in their application. There are also areas in which management’s judgment in selecting any viable
+alternative would not produce a materially different result. 
+Revenue Recognition 
+We recognize revenue for product sales in accordance with FASB ASC 606, Revenue
+from Contracts with Customers . Revenues from product sales are recognized when the customer obtains control of our product, which occurs at a point in time, typically upon tendering to the customer. We expense incremental costs of
+obtaining a contract as and when incurred because the expected amortization period of the asset that it would have recognized is one year or less or the amount is immaterial. Freight and distribution activities on products are performed after the
+customer obtains control of the goods. We have made an accounting policy election to account for shipping and handling activities that occur either when or after goods are tendered to the customer as a fulfillment activity, and therefore recognizes
+freight and distribution expenses in Cost of Product Sales. 
+For certain contracts, we recognize revenue from research and development, milestone and grant revenues when earned. Grants are invoiced after expenses are
+incurred. Revenues from projects or grants funded in advance are deferred until earned. For certain collaborative research projects, we recognize revenue by defining milestones at the inception of the agreement and applying judgement and estimates in
+recognizing revenue for relevant contracts. 
+Stock-Based Compensation 
+We recognize the fair value of equity-based awards as compensation expense in our statement of operations. The fair value of restricted stock and restricted
+stock unit awards are their fair value on the date of grant. The fair value of our stock option awards was estimated using a Black-Scholes option valuation model. This valuation model’s computations incorporate highly subjective assumptions, such as
+the expected stock price volatility and the estimated life of each award. The fair value of equity-based awards, after considering the effect of expected forfeitures, is then amortized, generally on a straight-line basis, over the related vesting
+period of the option. 
+Research and Development Costs 
+Research and development activities consist primarily of new product development, continuing engineering for existing products, and regulatory and clinical
+trial costs. Costs related to research and development efforts on existing or potential products are expensed as incurred. 
+26 
+Table of Contents 
+Inventories 
+Inventories are stated at the lower of cost and net realizable value, using the first-in, first-out method, or FIFO, to determine cost. Our policy is to
+periodically evaluate the market value of the inventory and the stage of product life cycle, and record a reserve for any inventory considered slow moving or obsolete. For example, each additional 1% of obsolete inventory would reduce such inventory
+by approximately $78,000. 
+Accounts Receivable 
+Our policy is to review our accounts receivable on a periodic basis, no less frequently than monthly. On a quarterly basis an analysis is made of the
+adequacy of our allowance for doubtful accounts and adjustments are made accordingly. The current allowance is approximately 0.6% of accounts receivable. For example, each additional 1% of accounts receivable that becomes uncollectible would reduce
+such balance of accounts receivable by approximately $74,000. 
+Acquisitions 
+In accordance with accounting guidance for the provisions in FASB ASC 805, Business Combinations , we allocate the purchase price of an acquired business to its identifiable assets and liabilities based on estimated fair values. The excess of the purchase price over the amount allocated to the
+assets and liabilities, if any, is recorded as goodwill. In addition, an acquisition may include a contingent consideration component. The fair value of the contingent consideration is estimated as of the date of the acquisition and is recorded as
+part of the purchase price. This estimate is updated in future periods and any changes in the estimate, which are not considered an adjustment to the purchase price, are recorded in our consolidated statements of operations. 
+We use all available information to estimate fair values. We typically engage outside appraisal firms to assist in the fair value determination of
+identifiable intangible assets and any other significant assets or liabilities. We adjust the preliminary purchase price allocation, as necessary, up to one year after the acquisition closing date as we obtain more information regarding asset
+valuations and liabilities assumed. 
+Our purchase price allocation methodology contains uncertainties because it requires management to make assumptions and to apply judgment to estimate the
+fair value of acquired assets and liabilities. Management estimates the fair value of assets and liabilities based upon quoted market prices, the carrying value of the acquired assets and widely accepted valuation techniques, including discounted
+cash flows and market multiple analyses. Unanticipated events or circumstances may occur which could affect the accuracy of our fair value estimates, including assumptions regarding industry economic factors and business strategies. 
+Other estimates used in determining fair value include, but are not limited to, future cash flows or income related to intangibles, market rate assumptions,
+actuarial assumptions for benefit plans and appropriate discount rates. Our estimates of fair value are based upon assumptions believed to be reasonable, but that are inherently uncertain, and therefore, may not be realized. Accordingly, there can be
+no assurance that the estimates, assumptions, and values reflected in the valuations will be realized, and actual results could vary materially. 
+Goodwill and Intangible Assets 
+We periodically review goodwill for impairment indicators. We review goodwill for impairment annually in the fourth quarter or more frequently if events or
+changes in circumstances indicate that goodwill might be impaired. We perform the goodwill impairment review at the reporting unit level. We perform a qualitative assessment of whether it is more likely than not that a reporting unit's fair value is
+less than its carrying amount. If not, no further goodwill impairment testing is performed. If so, we perform the step discussed hereafter. Our qualitative assessment involves significant estimates, assumptions, and judgments, including,
+macroeconomic conditions, industry and market conditions, our financial performance, reporting unit specific events and changes in our share price. 
+If the fair value of the reporting unit is greater than
+its carrying amount, goodwill is not considered to be impaired. We would recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value, provided the impairment charge does not exceed the total
+amount of goodwill allocated to the reporting unit. 
+Income Taxes 
+Income taxes are accounted for under FASB ASC 740, Income
+Taxes , authoritative guidance, which we refer to as the Guidance and which requires the asset and liability method of accounting for deferred income taxes. Deferred tax assets and liabilities are determined based on the difference between
+the financial statement and tax bases of assets and liabilities. Deferred tax assets or liabilities at the end of each period are determined using the tax rate expected to be in effect when taxes are actually paid or recovered. 
+The Guidance also requires that a valuation allowance be established when it is more likely than not that all or a portion of a deferred tax asset will not
+be realized. A review of all available positive and negative evidence needs to be considered, including a company’s current and past performance, the market environment in which the company operates, length of carryback and carryforward periods and
+existing contracts that will result in future profits. 
+The Guidance also prescribes a comprehensive model for recognizing, measuring, presenting and disclosing in the consolidated financial statements tax
+positions taken or expected to be taken on a tax return, including a decision whether to file or not to file in a particular jurisdiction. 
+27 
+Table of Contents 
+Recently Issued Accounting Pronouncements 
+Refer to Note 3 – Significant Accounting Policies to the audited consolidated financial statements included herein for a complete description of recent
+accounting standards which we have not yet been required to implement which may be applicable to our operations. Additionally, the significant accounting standards that have been adopted during the year ended December 31, 2018 are described. 
+ITEM 8. 
+FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+The Consolidated Financial Statements and schedules that constitute Item 8 are attached at the end of this report. An index to the Consolidated Financial
+Statements and schedules is also included on page F-1 of this report. 
+ITEM 9A. 
+Controls and Procedures 
+Evaluation of Disclosure Controls and Procedures 
+Our management, with the participation of our Chief Executive Officer
+and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures, as defined by Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of December 31, 2018. Based on the evaluation of our disclosure controls
+and procedures, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2018 at the reasonable assurance level. 
+Management’s Report on Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate
+internal control over financial reporting. Internal control over financial reporting is defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, our
+principal executive and principal financial officers and effected by the board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial
+statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that: 
+• 
+pertain to the maintenance of records that, in reasonable detail, accurately and
+fairly reflect the transactions and dispositions of the assets of the company; 
+• 
+provide reasonable assurance that transactions are recorded as necessary to
+permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made in accordance with authorizations of management and directors of
+the company; and 
+• 
+provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition,
+use or disposition of the company's assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial
+reporting may not prevent or detect misstatements. As a result, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of
+effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate. 
+Our management assessed the effectiveness of our internal control over
+financial reporting as of December 31, 2018. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework (2013). Based on
+its assessment, our management believes that, as of December 31, 2018, our internal control over financial reporting was effective based on those criteria. 
+Previously Identified Material Weaknesses in Internal Control Over Financial
+Reporting 
+None. 
+Changes in Internal Control over Financial Reporting 
+There were no changes in our internal control over financial reporting identified
+in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Securities Exchange Act of 1934 during the period covered by this Annual Report on
+Form 10-K that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting . 
+28 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+Shareholders and Board of Directors 
+Chembio Diagnostics, Inc. 
+Medford, New York 
+Opinion on Internal Control over Financial Reporting 
+We have audited Chembio Diagnostics, Inc.’s (the “Company’s”) internal control over financial reporting as of December 31, 2018, based on criteria
+established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). In our opinion, the Company maintained, in
+all material respects, effective internal control over financial reporting as of December 31, 2018, based on the COSO criteria. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of
+the Company and subsidiaries as of December 31, 2018 and 2017, the related consolidated statements of operations, comprehensive loss, changes in stockholders’ equity, and cash flows for each of the years then ended, and the related notes and our
+report dated March 18, 2019 expressed an unqualified opinion thereon. 
+Basis for Opinion 
+The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of
+internal control over financial reporting, included in the accompanying “Item 9A, Management’s Report on Internal Control over Financial Reporting”. Our responsibility is to express an opinion on the Company’s internal control over financial
+reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with U.S. federal securities laws and the applicable rules and regulations of the
+Securities and Exchange Commission and the PCAOB. 
+We conducted our audit of internal control over financial reporting in accordance with the standards of the PCAOB. Those standards require that we plan and
+perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting,
+assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary
+in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+Definition and Limitations of Internal Control over Financial Reporting 
+A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting
+and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the
+maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of
+financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide
+reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation
+of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+/s/ BDO USA, LLP 
+Melville, NY 
+March 18, 2019 
+29 
+Table of Contents 
+PART III 
+ITEM 10. 
+DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
+The information required in response to this Item 10 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC
+pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+ITEM 11. 
+EXECUTIVE COMPENSATION 
+The information required in response to this Item 11 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC
+pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+ITEM 12. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+The information required in response to this Item 12 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC
+pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE. 
+The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC
+pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+ITEM 14. 
+PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+The information required in response to this Item 14 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC
+pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+30 
+Table of Contents 
+ITEM 15. 
+EXHIBITS, FINANCIAL STATEMENT SCHEDULES 
+(a) See “Item 8. Financial Statements and
+Supplementary Data – Index to Consolidated Financial Statements” above. 
+(b) Exhibits 
+Exhibit No. 
+Description 
+3.1 
+Articles of Incorporation, as amended , of Chembio Diagnostics, Inc. 
+3.2 
+Amended and Restated Bylaws , of Chembio Diagnostics, Inc. 
+10.1(a)* 
+2008 Stock Incentive Plan, as amended 
+10.1(b)* 
+Form of Option for 2008 Stock Incentive Plan 
+10.2(a)* 
+2014 Stock Incentive Plan 
+10.2(b)* 
+Form of Option for 2014 Stock Incentive Plan 
+10.3* 
+Restated Annual
+Incentive Bonus Plan of Chembio Diagnostics, Inc., adopted as of March 15, 2019 
+10.4* 
+Employment Agreement dated March 13, 2017 between Chembio Diagnostics, Inc. and John J. Sperzel III 
+10.5* 
+Employment Agreement dated March 5, 2016 between Chembio Diagnostics, Inc. and Javan Esfandiari 
+10.6* 
+Employment Agreement dated September 14, 2017 between Chembio Diagnostics, Inc. and Sharon Klugewicz 
+10.7(a)* 
+Employment Agreement dated December 18, 2017 between Chembio Diagnostics, Inc. and Neil A. Goldman 
+10.7(b)* 
+Amendment No. 1 dated January 21, 2019 between Chembio Diagnostics, Inc. and Neil A. Goldman, amending Employment Agreement dated December 18, 2017 
+10.8* 
+Offer Letter dated October 19, 2016 between Worldwide Workplace Ireland and Robert Passas, with respect to employment by Chembio Diagnostics
+Systems, Inc. 
+10.9(a) 
+Lease Agreement, dated February 15, 2017, between Horseblock Associates and Chembio Diagnostics, Inc. with respect to 3661 Horseblock Road, Medford, New York, as amended 
+10.9(b) 
+Agreement of Sublease dated February 5, 2019 between Chembio Diagnostic Systems Inc., as sublessor, and Reliance Communications of New Jersey, LLC, as sublessee , with respect to 3661 Horseblock Road, Medford, New York, as amended 
+10.10 
+Lease Agreement, dated February 4, 2013, between Sherwood Corporate Center LLC and Chembio Diagnostics, Inc. with respect to 91-1A Colin Drive, Holbrook, New York, as amended on September 19, 2017 
+10.11 
+Lease Agreement dated February 5, 2019 between Myra Properties, LLC, as lessor, and Chembio Diagnostic Systems Inc., as lessee , with respect to 555
+Wireless Boulevard, Hauppauge, New York. 
+10.12 
+Underwriting Agreement, dated February 9, 2018, between the Registrant and Craig-Hallum Capital Group LLC 
+10.13 
+Underwriting Agreement dated November 1, 2018 between the Registrant and Craig-Hallum Capital Group LLC 
+14.1 
+Ethics Policy 
+21.1 
+List of Subsidiaries of Chembio Diagnostics, Inc. 
+23.1 
+Consent of BDO USA,
+LLP, Independent Registered Public Accounting Firm 
+31.1 
+Certification of the
+Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+31.2 
+Certification of the
+Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+32 
+Certification of Chief
+Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 
+101.INS 
+XBRL Instance Document 
+101.SCH 
+XBRL Taxonomy Extension Schema Document 
+101.CAL 
+XBRL Taxonomy Extension Calculation Linkbase Document 
+101.DEF 
+XBRL Taxonomy Definition Linkbase Document 
+101.LAB 
+XBRL Taxonomy Label Linkbase Document 
+101.PRE 
+XBRL Taxonomy Presentation Linkbase Document 
+* 
+Indicates management contract or compensatory plan. 
+31 
+Table of Contents 
+SIGNATURES 
+In accordance with Section 13 or 15(d) of the Exchange Act, the registrant has caused this report to be signed on its behalf by the
+undersigned, thereunto duly authorized. 
+CHEMBIO DIAGNOSTICS, INC. 
+March 18, 2019 
+By 
+/s/ John J. Sperzel 
+John J. Sperzel III 
+Chief Executive Officer and President 
+In accordance with the requirements of the Exchange Act, this report has been signed below by the following persons on behalf of the
+registrant and in the capacities and on the dates indicated. 
+Signatures 
+Title 
+Date 
+/s/ John J. Sperzel 
+Chief Executive Officer, President and Director 
+March 18, 2019 
+John J. Sperzel III 
+(Principal Executive Officer) 
+/s/ Neil A. Goldman 
+Executive Vice President and Chief Financial Officer 
+March 18, 2019 
+Neil A. Goldman 
+(Principal Financial & Accounting Officer) 
+/s/ Katherine L. Davis 
+Chair of the Board 
+March 18, 2019 
+Katherine L. Davis 
+/s/ Gail S. Page 
+Director 
+March 18, 2019 
+Gail S. Page 
+/s/ Mary Lake Polan 
+Director 
+March 18, 2019 
+Mary Lake Polan 
+/s/ John G. Potthoff 
+Director 
+March 18, 2019 
+John G. Potthoff 
+32 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+Index to Consolidated Financial Statements 
+—INDEX— 
+Page(s) 
+Report of Independent Registered Public Accounting Firm 
+F-1 
+Consolidated Financial Statements: 
+Balance Sheets as of December 31, 2018 and 2017 
+F-2 
+Statements of Operations for the years ended December 31, 2018 and 2017 
+F-3 
+Statements of Comprehensive Loss for the years ended December 31, 2018, and 2017 
+F-4 
+Statements of Changes in Stockholders’ Equity for the years ended December 31, 2018, and 2017 
+F-5 
+Statements of Cash Flows for the years ended December 31, 2018, and 2017 
+F-6 
+Notes to Consolidated Financial Statements 
+F-7 - F-18 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+Shareholders and Board of Directors 
+Chembio Diagnostics, Inc. 
+Medford, New York 
+Opinion on the Consolidated Financial Statements 
+We have audited the accompanying consolidated balance sheets of Chembio Diagnostics, Inc. (the “Company”) and subsidiaries as of December 31, 2018 and 2017, the
+related consolidated statements of operations, comprehensive loss, changes in stockholders’ equity, and cash flows the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion,
+the consolidated financial statements present fairly, in all material respects, the financial position of the Company and subsidiaries at December 31, 2018 and 2017, and the results of their operations and their cash flows for each of the years
+then ended, in conformity with accounting principles generally accepted in the United States of America. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company's internal
+control over financial reporting as of December 31, 2018, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
+Commission (“COSO”) and our report dated March 18, 2019 expressed an unqualified opinion thereon. 
+Basis for Opinion 
+These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s
+consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in
+accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable
+assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial
+statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits
+also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for
+our opinion. 
+/s/ BDO USA, LLP 
+We have served as the Company's auditor since 2011. 
+Melville, NY 
+March 18, 2019 
+F-1 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED BALANCE SHEETS 
+AS OF 
+- ASSETS - 
+December 31, 2018 
+December 31, 2017 
+CURRENT ASSETS: 
+Cash and cash equivalents 
+$ 
+12,524,551 
+$ 
+3,790,302 
+Accounts receivable, net of allowance for doubtful accounts of $42,000 at December 31, 2018 and 2017, respectively 
+7,373,971 
+2,085,340 
+Inventories, net 
+7,851,222 
+4,423,618 
+Prepaid expenses and other current assets 
+702,010 
+554,383 
+TOTAL CURRENT ASSETS 
+28,451,754 
+10,853,643 
+FIXED ASSETS ,
+net of accumulated depreciation 
+2,873,920 
+1,909,232 
+OTHER ASSETS: 
+Intangible assets, net 
+3,884,831 
+1,597,377 
+Goodwill 
+4,983,127 
+1,666,610 
+Deposits and other assets 
+717,551 
+589,159 
+TOTAL ASSETS 
+$ 
+40,911,183 
+$ 
+16,616,021 
+- LIABILITIES AND STOCKHOLDERS’ EQUITY - 
+CURRENT LIABILITIES: 
+Accounts payable and accrued liabilities 
+$ 
+5,888,681 
+$ 
+3,046,303 
+Deferred revenue 
+422,905 
+50,000 
+Current portion of note payable 
+207,694 
+- 
+TOTAL CURRENT LIABILITIES 
+6,519,280 
+3,096,303 
+OTHER LIABILITIES: 
+Note payable 
+171,821 
+99,480 
+Deferred tax liability 
+892,308 
+341,042 
+TOTAL LIABILITIES 
+7,583,409 
+3,536,825 
+COMMITMENTS AND CONTINGENCIES (Note 13) 
+STOCKHOLDERS’ EQUITY: 
+Preferred stock – 10,000,000 shares authorized, none outstanding 
+- 
+- 
+Common stock - $.01 par value; 100,000,000 shares authorized, 17,166,459 and 12,318,570 shares issued and
+outstanding at December 31, 2018 and 2017, respectively 
+171,664 
+123,185 
+Additional paid-in capital 
+90,953,788 
+62,821,288 
+Accumulated deficit 
+(57,909,874 
+) 
+(50,044,225 
+) 
+Accumulated other comprehensive income 
+112,196 
+178,948 
+TOTAL STOCKHOLDERS’ EQUITY 
+33,327,774 
+13,079,196 
+TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY 
+$ 
+40,911,183 
+$ 
+16,616,021 
+See accompanying notes to consolidated financial statements 
+F-2 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF OPERATIONS 
+For the years ended 
+December 31, 2018 
+December 31, 2017 
+REVENUES: 
+Net product sales 
+$ 
+26,741,020 
+$ 
+19,322,302 
+License and royalty revenue 
+948,773 
+741,534 
+R&D and grant revenue 
+5,719,458 
+3,951,591 
+TOTAL REVENUES 
+33,409,251 
+24,015,427 
+COSTS AND EXPENSES: 
+Cost of product sales 
+21,427,243 
+12,921,157 
+Research and development expenses 
+8,526,256 
+8,555,381 
+Selling, general and administrative expenses 
+11,100,775 
+8,963,363 
+Acquisition costs 
+337,645 
+58,076 
+41,391,919 
+30,497,977 
+LOSS FROM OPERATIONS 
+(7,982,668 
+) 
+(6,482,550 
+) 
+OTHER INCOME (EXPENSE): 
+Interest income, net 
+49,498 
+22,485 
+LOSS BEFORE INCOME TAXES (BENEFIT) PROVISION 
+(7,933,170 
+) 
+(6,460,065 
+) 
+Income tax (benefit) provision 
+(67,521 
+) 
+(88,305 
+) 
+NET LOSS 
+$ 
+(7,865,649 
+) 
+$ 
+(6,371,760 
+) 
+Basic loss per share 
+$ 
+$ (0.55 
+) 
+$ 
+(0.52 
+) 
+Diluted loss per share 
+$ 
+$ (0.55 
+) 
+$ 
+(0.52 
+) 
+Weighted average number of shares outstanding, basic 
+14,432,505 
+12,300,031 
+Weighted average number of shares outstanding, diluted 
+14,432,505 
+12,300,031 
+See accompanying notes to consolidated financial statements 
+F-3 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS 
+For the years ended 
+December 31, 2018 
+December 31, 2017 
+Net loss 
+$ 
+(7,865,649 
+) 
+$ 
+(6,371,760 
+) 
+Other comprehensive income: 
+Foreign currency translation adjustments 
+(66,752 
+) 
+178,948 
+COMPREHENSIVE LOSS 
+$ 
+(7,932,401 
+) 
+$ 
+(6,192,812 
+) 
+See accompanying notes to consolidated financial statements 
+F-4 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY 
+FOR THE YEARS ENDED DECEMBER 31, 2018, AND 2017 
+Common Stock 
+Additional 
+Paid-in-Capital 
+Accumulated 
+Deficit 
+AOCI 
+Total 
+Shares 
+Amount 
+Amount 
+Amount 
+Amount 
+Amount 
+Balance at December 31, 2016 
+12,026,847 
+$ 
+120,268 
+$ 
+60,721,783 
+$ 
+(43,672,465 
+) 
+$ 
+- 
+$ 
+17,169,586 
+Common Stock: 
+Purchase of RVR Diagnostics Sdn Bhd 
+269,236 
+2,692 
+1,680,033 
+- 
+- 
+1,682,725 
+Options: 
+Exercised 
+22,487 
+225 
+34,575 
+- 
+- 
+34,800 
+Stock option compensation 
+- 
+- 
+384,897 
+- 
+- 
+384,897 
+Comprehensive income 
+- 
+- 
+- 
+- 
+178,948 
+178,948 
+Net loss 
+- 
+- 
+- 
+(6,371,760 
+) 
+- 
+(6,371,760 
+) 
+Balance at December 31, 2017 
+12,318,570 
+$ 
+123,185 
+$ 
+62,821,288 
+$ 
+(50,044,225 
+) 
+$ 
+178,948 
+$ 
+13,079,196 
+Common Stock: 
+New stock from offerings 
+4,509,760 
+45,098 
+27,431,162 
+- 
+- 
+27,476,260 
+Restricted stock issued 
+266,839 
+2,668 
+(2,668 
+) 
+- 
+- 
+- 
+Restricted stock compensation 
+- 
+- 
+281,249 
+- 
+- 
+281,249 
+Options: 
+Exercised 
+71,290 
+713 
+71,201 
+- 
+- 
+71,914 
+Stock option compensation 
+- 
+- 
+351,556 
+- 
+- 
+351,556 
+Comprehensive loss 
+- 
+- 
+- 
+- 
+(66,752 
+) 
+(66,752 
+) 
+Net loss 
+- 
+- 
+- 
+(7,865,649 
+) 
+- 
+(7,865,649 
+) 
+Balance at December 31, 2018 
+17,166,459 
+$ 
+171,664 
+$ 
+90,953,788 
+$ 
+(57,909,874 
+) 
+$ 
+112,196 
+$ 
+33,327,774 
+See accompanying notes to consolidated financial statements 
+F-5 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+FOR THE YEARS ENDED 
+December 31, 2018 
+December 31, 2017 
+CASH FLOWS FROM OPERATING ACTIVITIES: 
+Cash received from customers and grants 
+$ 
+28,632,084 
+$ 
+24,971,299 
+Cash paid to suppliers and employees 
+(40,452,110 
+) 
+(30,028,299 
+) 
+Income taxes paid 
+(10,913 
+) 
+- 
+Interest received, net 
+69,930 
+22,485 
+Interest paid 
+(20,432 
+) 
+- 
+Net cash used in operating activities 
+(11,781,441 
+) 
+(5,034,515 
+) 
+CASH FLOWS FROM INVESTING ACTIVITIES: 
+Purchase of opTricon GmbH, net of cash acquired 
+(5,491,204 
+) 
+- 
+Purchase of RVR Diagnostics Sdn Bhd, net of cash acquired 
+- 
+(850,000 
+) 
+Acquisition of and deposits on fixed assets 
+(1,467,192 
+) 
+(1,026,954 
+) 
+Net cash used in investing activities 
+(6,958,396 
+) 
+(1,876,954 
+) 
+CASH FLOWS FROM FINANCING ACTIVITIES: 
+Proceeds from option exercises 
+71,914 
+34,800 
+Proceeds from note payable 
+- 
+99,480 
+Payments on note payable 
+(64,481 
+) 
+- 
+Proceeds from sale of common stock, net 
+27,476,260 
+- 
+Net cash provided by financing activities 
+27,483,693 
+134,280 
+Effect of exchange rate changes on cash 
+(9,607 
+) 
+13,027 
+INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 
+8,734,249 
+(6,764,162 
+) 
+Cash and cash equivalents - beginning of the period 
+3,790,302 
+10,554,464 
+Cash and cash equivalents - end of the period 
+$ 
+12,524,551 
+$ 
+3,790,302 
+RECONCILIATION OF NET LOSS TO NET CASH USED IN OPERATING ACTIVITIES: 
+Net Loss 
+$ 
+(7,865,649 
+) 
+$ 
+(6,371,760 
+) 
+Adjustments: 
+Depreciation and amortization 
+902,505 
+1,276,963 
+Fair value adjustment to contingent consideration 
+- 
+(148,000 
+) 
+Share based compensation 
+632,805 
+384,897 
+Change in deferred tax asset 
+(78,432 
+) 
+- 
+Changes in assets and liabilities, net of effects from purchase of opTricon GmbH: 
+Accounts receivable 
+(5,150,072 
+) 
+1,298,389 
+Inventories 
+(3,077,104 
+) 
+(1,088,430 
+) 
+Prepaid expenses and other current assets 
+(118,293 
+) 
+285,762 
+Deposits and other assets 
+- 
+(512,272 
+) 
+Accounts payable and accrued liabilities 
+2,599,894 
+182,453 
+Deferred revenue 
+372,905 
+(342,517 
+) 
+Net cash used in operating activities 
+$ 
+(11,781,441 
+) 
+$ 
+(5,034,515 
+) 
+Supplemental disclosures for non-cash investing and financing activities: 
+Deposits on manufacturing equipment transferred to fixed assets 
+$ 
+257,455 
+$ 
+174,399 
+Deposits and other assets transferred to intangible assets 
+118,899 
+- 
+Seller-financed equipment purchases 
+326,110 
+- 
+Accrual of contingent earn-out 
+- 
+148,000 
+Issuance of common stock for net assets of business acquired 
+- 
+1,682,725 
+See accompanying notes to consolidated financial statements 
+F-6 
+Table of Contents 
+NOTE 1 — DESCRIPTION OF BUSINESS: 
+Chembio Diagnostics, Inc. and its subsidiaries (collectively, the “Company” or “Chembio”), develop, manufacture, and commercialize point-of-care diagnostic tests
+that are used to detect and diagnose diseases. The Company is pursuing three corporate priorities: (1) expand its commercialization, (2) advance its research and development pipeline, and (3) prepare for future growth. 
+All products that are currently being developed are based on the Company’s patented DPP ® technology, a novel point-of-care diagnostic platform that offers certain customer advantages as compared to
+traditional lateral flow technology. 
+The Company’s product commercialization and product development efforts are
+focused on infectious disease testing and technology collaborations. In infectious disease, the Company is commercializing tests for HIV and Syphilis, Zika virus, and developing tests for malaria, dengue virus, chikungunya virus, ebola, lassa ,
+Marburg, leptospirosis, Rickettsia typhi , Burkholderia pseudomallei ,
+and Orientia tsutsugamushi , individually or as part of fever panel tests. Through technology collaborations, the Company is developing tests for a specific
+form of cancer, concussion, bovine tuberculosis, and for eosinophilic respiratory disease, the latter in collaboration with global biopharmaceutical company AstraZeneca. 
+Large and growing markets have been established for these kinds of tests, initially in high prevalence regions where they are indispensable for large scale prevention
+and treatment programs. More generally, the Company believes there is and will continue to be a growing demand for diagnostic products that can provide accurate, actionable diagnostic information in a rapid, cost-effective manner at the point of
+care. 
+The Company’s products are sold to medical laboratories and hospitals, governmental and public health entities, non-governmental organizations, medical
+professionals and retail establishments, both domestically and internationally, under the Company’s STAT PAK ®, SURE CHECK ® , STAT-VIEW ® or DPP ® registered trademarks, or under the private labels of the
+Company’s marketing partners. 
+The Company routinely enters into arrangements with governmental and non-governmental organizations for the funding of certain research and development
+efforts. 
+NOTE 2 — ACQUISITIONS: 
+opTricon 
+On November 6, 2018, pursuant to a share purchase agreement, the Company acquired all of the outstanding shares of opTricon GmbH (“opTricon”), a privately-held
+Germany based developer and manufacturer of handheld analyzers for rapid diagnostic tests, for $5.5 million in cash, subject to routine post-closing adjustments. Since 2015, the Company and opTricon have been parties to an agreement under which
+the Company has collaborated in developing its DPP Micro Reader, a handheld, battery-operated analyzer that uses an innovative image sensor to provide, when combined with the Company’s DPP tests, a quantitative interpretation of diagnostic
+results. The Company purchased opTricon because it believes it will enable it to promote DPP tests and DPP Micro Reader more actively across global markets. The results of opTricon operations have been reflected in the consolidated financial
+statements since November 6, 2018. 
+As a result of the consideration paid exceeding the preliminary fair value of the net assets acquired, goodwill in the
+amount of $3,337,000 was recorded in connection with this acquisition, none of which will be deductible for tax purposes. In addition, the Company recorded $2,260,000 in intangible assets associated with the addition of opTricon’s developed
+technology and customer base. The Consolidated Statements of Operations for the year ended December 31, 2018 include $337,645 of transaction costs related to the opTricon acquisition. 
+The
+acquisition was accounted for using the purchase method of accounting. The following table summarizes the preliminary allocation of the purchase price to the estimated fair values of the assets acquired and liabilities assumed on the closing
+date of November 6, 2018: 
+Amount 
+Net current assets 
+$ 
+404,204 
+Property, plant and equipment 
+125,000 
+Goodwill 
+3,337,000 
+Deferred tax liability 
+(635,000 
+) 
+Other intangible assets (estimated useful life): 
+Developed technology (7 years) 
+1,900,000 
+Customer contracts / relationships (10 years) 
+360,000 
+Total consideration 
+$ 
+5,491,204 
+The Company calculated the fair value of the fixed assets based on the net book value of opTricon as that
+approximates fair value. The developed technology and customer contracts/relationships were based on discounted cash flows using management estimates. 
+As indicated, the allocation of the purchase price shown above is preliminary, pending completion of an analysis of the deferred tax
+liability. Therefore, an adjustment may be required. 
+The following represents unaudited pro forma operating results for the year ended December 31, 2018 as if the operations
+of opTricon had been included in the Company’s Consolidated Statements of Operations as of January 1, 2018: 
+Proforma 
+December 31, 2018 
+Total revenues 
+$ 
+35,442,806 
+Net loss 
+(8,394,074 
+) 
+Net loss per common share 
+$ 
+(0.58 
+) 
+Diluted net loss per common share 
+$ 
+(0.58 
+) 
+The pro forma financial information includes business combination
+accounting effects from the acquisition including amortization charges from acquired intangible assets of opTricon approximately $351,000 for the year ended December 31, 2018. The unaudited pro forma information as presented above is for
+informational purposes only and is not indicative of the results of operations that would have been achieved if the acquisition had taken place at the beginning of fiscal 2018. Included in the proforma table above are opTricon's net revenues
+and pre-tax loss for the year ended December 31, 2018 which were approximately $2,214,000 and $213,000, respectively. opTricon's results of operations from the date of acquisition through December 31, 2018 are immaterial to the Company's
+Consolidated Statements of Operations. 
+RVR Diagnostics 
+On January 9, 2017, pursuant to a stock purchase agreement (the "Stock Purchase Agreement), the Company acquired all of the outstanding common stock of
+RVR Diagnostics Sdn Bhd ("RVR"), a privately-held Malaysia based manufacturing company focused on assembly and sales of rapid medical assays, for $3,231,000. The Company acquired RVR, which subsequently changed its name to Chembio Diagnostics
+Malaysia Sdn Bhd ("CDM"), to have a better presence in Asia, access to lower cost, shorter approval time of in-country regulatory approvals, and a lower cost assembly operation. 
+Total consideration was: (i) a cash payment of $1,400,000, of which $550,000 was paid as a deposit in December 2016; (ii) 269,236 shares of Chembio's
+common stock, with a value at closing of $1,683,000, of which 7,277 shares were held back to satisfy certain potential claims under the Stock Purchase Agreement and became issuable to the sellers on the one-year anniversary of the closing; and, a
+contingent $148,000 milestone payment based on the achievement of performance goals related to sales by CDM during the 12 months ended December 31, 2017. The performance goals were not achieved and the related $148,000 accrual was reversed during
+the fourth quarter of 2017 and recognized in Selling, general, and administrative expenses associated with the change in fair value. 
+As a result of the consideration paid exceeding the preliminary fair value of the net assets acquired, goodwill in the amount of $1,503,361 was recorded
+in connection with this acquisition, none of which will be deductible for tax purposes. In addition, the Company recorded $1,800,000 in intangible assets associated with the addition of CDM’s intellectual property, customer base and distribution
+channels, trade names, order backlog, industry reputation, and management talent and workforce. The Condensed Consolidated Statements of
+Operations for the year ended December 31, 2017 include $25,000 of transaction costs related to the CDM acquisition, which are reflected as Selling, general and administrative expenses. 
+The acquisition was accounted for using the purchase method of accounting. The following table summarizes the allocation of the purchase price to
+the estimated fair values of the assets acquired and liabilities assumed on the closing date of January 9, 2017: 
+Amount 
+Property, plant and equipment 
+$ 
+235,141 
+Goodwill 
+1,651,361 
+Deferred tax liability 
+(307,636 
+) 
+Contingent consideration 
+(148,000 
+) 
+Other intangible assets (estimated useful life): 
+Intellectual property (10 years) 
+800,000 
+Customer contracts / relationships (10 years) 
+700,000 
+Order backlog (3 months) 
+200,134 
+Trade name (11 years) 
+100,000 
+Total consideration 
+$ 
+3,231,000 
+The Company calculated the fair value of the fixed assets based on the net book value of CDM as that approximates fair value. The intellectual property, customer contracts and trade names were based on discounted cash flows using management
+estimates. The order backlog was based on an order that CDM had at the closing that was shipped in the first quarter of 2017, and valued at an estimated net income. 
+CDM's net revenues and pre-tax loss for the year ended December 31, 2017 were approximately $ 1,465,000 and ($406,000), respectively. 
+F-7 
+Table of Contents 
+NOTE 3 — SIGNIFICANT ACCOUNTING POLICIES: 
+(a) 
+Principles of Consolidation: 
+The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany
+transactions and balances are eliminated in consolidation. Certain amounts from prior years have been reclassified to conform to the 2018 presentation. 
+(b) 
+Use of Estimates: 
+The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States requires
+management to make assumptions and estimates that affect the amounts reported in the consolidated financial statements and accompanying notes. Judgments and estimates of uncertainties are required in applying the Company’s accounting policies
+in certain areas. Generally, matters subject to estimation and judgment include accounts receivable realization, inventory obsolescence, asset impairments, recognition of revenue persuant to milestones, useful lives of intangible and fixed
+assets, stock-based compensation, and deferred tax asset valuation allowances. Due to the inherent uncertainty involved in making estimates, actual results reported in future periods may be based upon amounts that differ from those estimates. 
+(c) 
+Fair Value of Financial Instruments: 
+The carrying value for cash and cash equivalents, accounts receivable, and accounts payable, approximate fair value due to the immediate or short-term maturity of these financial instruments. Included in cash and cash equivalents is $4.7
+million and $2.1 million as of December 31, 2018 and 2017, respectively, of money market funds that are Level 1 fair value measurements under the hierarchy. The fair value of the Company's notes payable approximates the recorded value as
+the rate is based upon the current rates offered to the Company for similar financial instruments. 
+Fair value measurements of all financial assets and liabilities that are being measured and reported on a fair value basis are required to be classified and disclosed in one
+of the following three categories: 
+Level 1: 
+Unadjusted quoted prices in active markets that are accessible at the
+measurement date for identical, unrestricted assets or liabilities; 
+Level 2: 
+Quoted prices in markets that are not active, or inputs which are observable,
+either directly or indirectly, for substantially the full term of the asset or liability; and 
+Level 3: 
+Prices or valuation techniques that require inputs that are both significant to
+the fair value measurement and unobservable (i.e., supported by little or no market activity). 
+(d) 
+Cash and Cash Equivalents: 
+Cash and cash equivalents are defined as short-term, highly liquid investments with original maturities of three months or less. 
+(e) 
+Concentrations of Credit Risk: 
+Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of temporary cash investments and
+trade receivables. The Company places its temporary cash instruments with well-known financial institutions and, at times, may maintain balances in excess of the FDIC insurance limit. The Company monitors the credit ratings of the financial
+institutions to mitigate this risk. Concentration of credit risk with respect to trade receivables is principally mitigated by the Company’s ability to obtain letters of credit from certain foreign customers and its diverse customer base,
+both in number of customers and geographic locations. 
+(f) 
+Inventories: 
+Inventories, consisting of material, labor and manufacturing overhead, are stated at the lower of cost and net realizable value. Cost is determined on the
+first-in, first-out method. The Company’s policy is to periodically evaluate the market value of the inventory and the stage of product life cycle, and record a write-down for any inventory considered slow moving or obsolete. 
+(g) 
+Fixed Assets: 
+Fixed assets are stated at cost, less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful
+lives of the respective assets, which range from three to seven years. Leasehold improvements are amortized over the useful life of the asset or the lease term, whichever is shorter. Deposits paid for fixed assets are capitalized and not
+depreciated until the related asset is placed in service. 
+(h) 
+License Agreements: 
+The Company records up-front payments related to sublicense agreements as prepaids and amortizes them over their respective economic life. As of 
+December 31, 2018 and 2017, total prepaids were $100,000 and $100,000, respectively. 
+Amortization expenses for the licenses above for the years ended December 31, 2018, and 2017 were $0, and $137,500, respectively. 
+(i) 
+Valuation of Long-Lived Assets and Intangible Assets: 
+Long-lived assets to be held and used are analyzed for impairment whenever events or changes in circumstances indicate that the related carrying
+amounts may not be recoverable. The Company evaluates at each balance sheet date whether events and circumstances have occurred that indicate possible impairment. If there are indications of impairment, the Company uses future undiscounted
+cash flows of the related asset or asset grouping over the remaining life in measuring whether the assets are recoverable. In the event such cash flows are not expected to be sufficient to recover the recorded asset values, the assets are
+written down to their estimated fair value. No impairment of long-lived tangible and intangible assets was recorded for the years ended December 31, 2018 and 2017. 
+F-8 
+Table of Contents 
+(j) 
+Revenue Recognition: 
+In May 2014, the Financial Accounting Standards Board (“FASB”) issued converged guidance on recognizing revenue in contracts with customers, Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers . The intent of the new standard is to improve financial reporting and comparability of revenue globally. The core principle of the standard is for
+a company to recognize revenue in a manner that depicts the transfer of goods or services to customers in an amount that reflects the consideration which the company expects to receive in exchange for those goods or services. The guidance
+provides a five-step analysis of transactions to determine when and how revenue is recognized. Other major provisions include capitalization of certain contract costs, consideration of the time value of money in the transaction price, and
+in certain circumstances, allowing estimates of variable consideration to be recognized before contingencies are resolved. The guidance also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and
+cash flows arising from an entity’s contracts with customers. 
+The new revenue standards became effective for the Company on January 1, 2018 and were adopted using the modified retrospective
+method. The adoption of the new revenue standards as of January 1, 2018 did not change the Company’s revenue recognition as its revenues continue to be recognized when the customer takes control of its product. As the Company did not
+identify any material accounting changes that impacted the amount of reported revenues with respect to its product revenue, license and royalty revenue, and R&D, milestone and grant revenues, no adjustment to retained earnings was
+required upon adoption. 
+The Company adopted the standards to contracts that were not completed at the date of initial application
+(January 1, 2018). 
+Under the new revenue standards, the Company recognizes revenues when its customer obtains control of promised goods or services,
+in an amount that reflects the consideration which the Company expects to receive in exchange for those goods or services. The Company recognizes revenues following the five-step model prescribed under ASU No. 2014-09: (i) identify
+contract(s) with a customer; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and (v) recognize revenues
+when (or as) the Company satisfies the performance obligation. 
+Product Revenues 
+Revenues from product sales are recognized and commissions are accrued when the customer obtains control of the Company’s product,
+which occurs at a point in time, typically upon tendering to the customer. The Company expenses incremental costs of obtaining a contract as and when incurred because the expected amortization period of the asset that it would have
+recognized is one year or less or the amount is immaterial. Freight and distribution activities on products are performed after the customer obtains control of the goods. The Company has made an accounting policy election to account for
+shipping and handling activities that occur either when or after goods are tendered to the customer as a fulfillment activity, and therefore recognizes freight and distribution expenses in Cost of Product Sales. 
+The Company’s payment terms vary by the type and location of the Company’s customer and products or services offered. Payment terms differ by jurisdiction
+and customer but payment is generally required in a term ranging from 30 to 60 days from date of shipment or satisfaction of the performance obligation. 
+Reserves for Discounts and Allowances 
+Revenues from product sales are recorded net of reserves established for applicable discounts and allowances that are offered
+within contracts with the Company’s customers. The Company’s process for estimating reserves established for these variable consideration components does not differ materially from its historical practices. 
+Product revenue reserves, which are classified as a reduction in product revenues, are generally related to discounts. Estimates of
+variable consideration and the determination of whether to include estimated amounts in the transaction price are based on all information (historical, current and forecasted) that is reasonably available to the Company, taking into
+consideration the type of customer, the type of transaction and the specific facts and circumstances of each arrangement. The transaction price, which includes variable consideration reflecting the impact of discounts and allowances, may
+be subject to constraint and is included in the net sales price only to the extent that it is probable that a significant reversal of the amount of the cumulative revenues recognized will not occur in a future period. Actual amounts may
+ultimately differ from the Company’s estimates. If actual results vary, the Company adjusts these estimates, which could have an effect on earnings in the period of adjustment. 
+Royalty Revenues 
+The Company receives royalty revenues on sales by its licensees of products covered under patents that it owns. The Company does
+not have future performance obligations under these license arrangements. The Company records these revenues based on estimates of the sales that occurred during the relevant period as a component of license and royalty revenues. The
+relevant period estimates of sales are based on interim data provided by licensees and analysis of historical royalties that have been paid to the Company, adjusted for any changes in facts and circumstances, as appropriate. Differences
+between actual and estimated royalty revenues are adjusted for in the period in which they become known, typically the following quarter. Historically, adjustments have not been material when compared to actual amounts paid by licensees. 
+R&D and grant revenue 
+All such contracts are evaluated under the five-step model described above. For certain contracts that represent grants where the
+funder does not meet the definition of a customer, the Company recognizes revenue when earned in accordance with ASC 958. Such contracts are further described under Disaggregation of Revenue , below. Grants are invoiced and revenue is recognized as expenses are incurred as that is the depiction of the timing of the transfer of services. Performance obligations
+generally follow the major phases of product development processes: design feasibility & planning, product development & design optimization, design verification, design validation & process validation, and pivotal studies. 
+Disaggregation of Revenue 
+The following tables disaggregate Total Revenues for the year ended December 31, 2018: 
+Exchange 
+Transactions 
+Non-Exchange 
+Transactions 
+Total 
+Net product sales 
+$ 
+26,741,020 
+$ 
+- 
+$ 
+26,741,020 
+License and royalty revenue 
+948,773 
+- 
+948,773 
+R&D, milestone and grant revenue 
+2,687,210 
+3,032,248 
+5,719,458 
+$ 
+30,377,003 
+$ 
+3,032,248 
+$ 
+33,409,251 
+Exchange transactions are recognized in accordance with ASC 606, while non-exchange transactions are recognized in accordance with ASC 985. 
+F-9 
+Table of Contents 
+Total 
+Africa 
+$ 
+8,605,306 
+Asia 
+1,389,120 
+Europe & Middle East 
+4,726,691 
+Latin America 
+11,722,224 
+United States 
+6,965,910 
+$ 
+33,409,251 
+Contract Liabilities 
+Deferred revenue relates to payments received in advance of performance under the contract. Deferred revenue is recognized as
+revenue as (or when) the Company performs under the contract. At December 31, 2017, the Company reported $50,000 in deferred revenue of which $50,000 was earned and recognized as R&D, milestone and grant revenue during the year ended
+December 31, 2018. At December 31, 2018, the Company reported $422,905 in deferred revenue which is expected to be recognized during the first quarter of 2019. 
+In April 2017, the Company entered into a $1.0 million agreement with FIND to develop a simple, point-of-care fever panel assay that can identify multiple
+life-threatening acute febrile illnesses common in the Asia Pacific region. The Company earned $0.1 million and $0.9 million for the year ended December 31, 2018, and from inception through December 31, 2018, respectively as R&D,
+milestone and grant revenue in the Company’s Consolidated Statements of Operations. 
+In August 2016, the Company was awarded a grant of $5.9 million from BARDA, which is part of the U.S. Department of Health And Human Resources to
+develop a rapid Zika virus assay. The Company earned $2.6 million and $5.3 million for the year ended December 31, 2018 and from inception through December 31, 2018, respectively, as R&D, milestone and grant revenue in the Company’s
+Consolidated Statements of Operations. 
+In September 2016, the Company was awarded a $0.7 million contract from the USDA to develop a Bovid TB assay. The Company earned $0.2 million and
+$0.5 million for the year ended December 31, 2018 and from inception through December 31, 2018, respectively, as R&D, milestone and grant revenue in the Company’s Consolidated Statements of Operations. 
+(k) 
+Research and Development: 
+Research and development (R&D) costs are expensed as incurred. Advance payments for goods and services that will be used in future research and
+development activities are expensed when the activity has been performed or when the goods have been received rather than when the payment is made. 
+(l) 
+Stock-Based Compensation: 
+The fair value of restricted stock and restricted stock unit awards are their fair value on the date of grant. Stock-based compensation expense for
+stock options is calculated using the Black-Scholes valuation model based on awards ultimately expected to vest together with the fair value of restricted stock and restricted stock unit awards, are, reduced for actual forfeitures, and,
+expensed on a straight-line basis over the requisite service period of the grant. During 2017, the Company adopted ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting". 
+(m) 
+I ncome Taxes: 
+The Company accounts for income taxes under an asset and liability approach that recognizes deferred tax assets and liabilities based on the
+difference between the financial statement carrying amounts and the tax bases of assets and liabilities using enacted tax rates in effect in the years in which the differences are expected to reverse. 
+The Company follows a more-likely-than-not threshold for financial statement recognition and measurement of a tax position taken, or expected to be
+taken, in a tax return. The guidance relates to, among other things, classification, accounting for interest and penalties associated with tax positions, and disclosure requirements. Any interest and penalties accrued related to uncertain tax
+positions are recorded in tax expense. 
+The Company assesses the realizability of its net deferred tax assets on an annual basis. If, after considering all relevant positive and negative
+evidence, it is more likely than not that some portion or all of the net deferred tax assets will not be realized, the Company will reduce the net deferred tax assets by a valuation allowance. The realization of net deferred tax assets is
+dependent on several factors, including the generation of sufficient taxable income prior to the expiration of net operating loss carryforwards. 
+(n) 
+Loss Per Share: 
+Basic loss per share is computed by dividing net loss attributable to common stockholders by the weighted-average number of common shares
+outstanding for the period including outstanding restricted stock that by its terms is includible in the calculation. Diluted loss per share for the years ended December 31, 2018, and 2017 reflects the potential dilution from the exercise or
+conversion of other securities into common stock, if dilutive. 
+There were 711,968, and 810,670 options outstanding as of December 31, 2018 and 2017, respectively, which were not included in the calculation of
+diluted income per share for the years ended because their effect would have been anti-dilutive. 
+(o) 
+Goodwill and Intangible Assets: 
+Goodwill represents the excess of the purchase price the Company paid over the fair value of the net tangible and identifiable intangible assets acquired in
+the Company’s acquisition of opTricon in November 2018 and CDM in January 2017. Goodwill is not amortized but rather is tested annually as of the first day of the fiscal fourth quarter, or sooner if the Company believes that indicators of
+impairment exist. The Company makes a qualitative evaluation about the likelihood of goodwill impairment, which is based on a number of applicable factors. If the Company concludes that it is more likely than not that the carrying value of
+the applicable reporting unit is greater than its fair value, then it would recognize an impairment charge for the amount by which the carrying value exceeds the reporting unit’s fair value, provided the impairment charge does not exceed
+the total amount of goodwill allocated to the reporting unit. 
+For the year ended December 31, 2018 and 2017, there was no impairment of goodwill and other intangible assets. 
+F-10 
+Table of Contents 
+Following is a table that reflects changes in Goodwill: 
+Beginning balance 1/1/18 
+$ 
+1,666,610 
+Acquisition of opTricon 
+3,337,000 
+Changes in foreign currency exchange rate 
+(20,483 
+) 
+Balance at December 31, 2018 
+$ 
+4,983,127 
+Intangible assets consist of the following at: 
+Weighted 
+Average 
+Remaining Life 
+December 31, 2018 
+December 31, 2017 
+Cost 
+Accumulated Amortization 
+Net Book Value 
+Cost 
+Accumulated Amortization 
+Net Book Value 
+Intellectual property 
+10 
+$ 
+1,089,688 
+$ 
+173,633 
+$ 
+916,055 
+$ 
+886,872 
+$ 
+88,687 
+$ 
+798,185 
+Developed technology 
+7 
+1,910,315 
+- 
+1,910,315 
+- 
+- 
+- 
+Customer contracts/relationships 
+8 
+1,121,600 
+151,929 
+969,671 
+776,013 
+77,601 
+698,412 
+Order backlog 
+- 
+217,187 
+217,187 
+- 
+221,867 
+221,867 
+- 
+Trade names 
+9 
+108,521 
+19,731 
+88,790 
+110,859 
+10,079 
+100,780 
+$ 
+4,447,311 
+$ 
+562,480 
+$ 
+3,884,831 
+$ 
+1,995,611 
+$ 
+398,234 
+$ 
+1,597,377 
+Amortization expense for the year ended December 31, 2018 and 2017 was $233,734 and $398,234, respectively, and is recorded within Selling,
+General and Administrative expenses. Amortization expense, subject to changes in currency exchange rates, is expected to be $496,512 per year from 2019 through 2023, and total $1,402,271 for all of the years thereafter. 
+(p) 
+Allowance for Doubtful Accounts: 
+The Company records allowances for doubtful accounts for the estimated probable losses on uncollectible accounts receivable. The allowance is based upon the
+credit worthiness of the Company’s customers, the Company’s historical experience, the age of the receivable and current market and economic conditions. Receivables are written off against these allowances in the period they are determined
+to be uncollectible. 
+(q) 
+Acquisition Costs: 
+Acquisition costs include period expenses, primarily professional services, related to acquisition activities. 
+(r) 
+Foreign Currency Translation: 
+The functional currency of a foreign subsidiary is the local currency. Assets and liabilities of foreign subsidiaries that use a currency other than U.S.
+dollars as their functional currency are translated to U.S. dollars at end of period currency exchange rates. The consolidated statements of operations of foreign subsidiaries are translated to U.S. dollars at average period currency
+exchange rates. The effect of translation for foreign subsidiaries is generally reported in Other comprehensive income. Foreign transaction gains are immaterial. 
+(s) 
+Recent Accounting Pronouncements Affecting the Company: 
+In May 2014, the Financial Accounting Standards Board (“FASB”) issued converged guidance on recognizing revenue in contracts with customers, Accounting
+Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers . The intent of the new standard is to improve financial reporting
+and comparability of revenue globally. The core principle of the standard is for a company to recognize revenue in a manner that depicts the transfer of goods or services to customers in an amount that reflects the consideration which the
+company expects to receive in exchange for those goods or services. The guidance provides a five-step analysis of transactions to determine when and how revenue is recognized. Other major provisions include capitalization of certain
+contract costs, consideration of the time value of money in the transaction price, and in certain circumstances, allowing estimates of variable consideration to be recognized before contingencies are resolved. The guidance also requires
+enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from an entity’s contracts with customers. The standard is effective for the first interim period within annual reporting periods
+beginning after December 15, 2017. 
+The Company has completed its evaluation of the new standard and assessed the impact of adoption on its consolidated financial statements. The Company reviewed
+significant open contracts with customers for each revenue stream, and based on its evaluation, revenue recognition under the new standard did not have a material impact on the Company’s consolidated financial statements because: i) product
+sales revenue is recognized when control of the goods is transferred to the customer (i.e., the date of shipment, which is consistent under ASC 605), and ii) R&D and grant revenue historically did not constitute exchange transactions
+and therefore the new standard did not apply to such revenue upon adoption. The Company also assessed its control framework as a result of adopting the new standard and noted minimal, insignificant changes to its systems and other controls
+processes. 
+The new standard permitted two adoption methods under ASU 2014-09. The guidance could be adopted through either retrospective application to all
+periods presented in the consolidated financial statements (full retrospective) or through a cumulative effect adjustment to retained earnings at the effective date (modified retrospective). The Company adopted the new standard effective
+January 1, 2018 using the modified retrospective transition method. Under that method, the Company applied the rules to all contracts existing as of January 1, 2018. The cumulative effect was not material. 
+In November 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 740) Balance Sheet Classification of Deferred
+Assets . This ASU is intended to simplify the presentation of deferred taxes on the balance sheet and will require an entity to present all deferred tax assets and deferred tax liabilities as non-current on the balance sheet. Under
+the current guidance, entities are required to separately present deferred taxes as current or non-current. Netting deferred tax assets and deferred tax liabilities by tax jurisdiction will still be required under the new guidance. This
+guidance became effective for Chembio beginning in 2018. This new accounting standard update did not have a material impact on the Company's consolidated financial statements. 
+In February 2016, the FASB issued ASU No. 2016-02, Leases (“ASU 2016-02”). ASU 2016-02 requires the entity to recognize the assets and liabilities for the rights and obligations created by
+leased assets. Leases will be classified as either finance or operating, with classification affecting expense recognition in the income statement. In July 2018 the FASB issued ASU 2018-10, Codification Improvements to Topic 842, Leases , and ASU 2018-11, Leases (Topic 842)
+Targeted Improvements , which provide supplemental adoption guidance and clarification to ASU 2016-02, and must be adopted concurrently with the adoption of ASU 2016-02, cumulatively referred to as “Topic 842”. Topic 842 is effective
+for the company in the first quarter of 2019, with early adoption permitted, and is to be applied using either a modified retrospective approach, or an optional transition method which allows an entity to apply the new standard at the
+adoption date with a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. 
+The Company will adopt Topic 842 on January 1, 2019 under the optional transition method and elect the short-term lease exception and available practical
+expedients. Under the transition method, the Company will not adjust its comparative period financial information or make the new required lease disclosures for periods before the effective date. Upon adoption, the Company expects the
+consolidated balance sheet to include a right of use asset and liability related to substantially all of the Company’s lease arrangements. While the Company continues to evaluate the effects of adopting the provisions of Topic 842,
+including the impact that this new guidance will have on its processes and controls, the Company expects most existing operating lease commitments will be recognized as operating lease liabilities and right-of-use assets upon adoption. The
+adoption is not expected to be material to the consolidated financial statements, and based on the Company’s ongoing assessment, is expected to increase total assets and total liabilities by no more than approximately $1.5 million, on a
+discounted basis. 
+Please see Note 15 – Subsequent Events, regarding the Company’s
+entering into a commercial real estate lease for a new corporate headquarters and a sublease for one of its current facilities on February 5, 2019. The Company is currently analyzing the impact of Topic 842 on these transactions and expects
+to report on that during the first quarter of 2019. Based on the term and rental cost, the Company expects the application of Topic 842 to these transactions to have a material impact on the Company’s total assets and total liabilities, and
+no impact on the Company’s results of operations or cash flows. 
+F-11 
+Table of Contents 
+In March 2016, the FASB issued authoritative guidance under ASU 2016-09, Compensation-Stock
+Compensation (Topic 718) Improvements to Employee Share-Based Payment Accounting . ASU 2016-09 provides for simplification of several aspects of the accounting for share-based payment transactions, including income tax consequences,
+classification of awards as either equity or liabilities and classification on the statement of cash flows. The Company adopted ASU 2016-09 on January 1, 2017. As the Company has a full valuation allowance against its U.S. net deferred tax
+assets, the adoption of this standard for recognition of the tax effect of deductions for employee share awards in excess of compensation costs (“windfall”) did not have a material impact on its consolidated financial statements and related
+disclosures. See Note 8 – Income Taxes, for additional information. Should the full valuation allowance be reversed in future periods, the adoption of this new guidance could introduce more volatility in the calculation of the Company’s
+effective tax rate, depending on the Company’s share price at exercise or vesting of share-based awards as compared to grant date. The other provisions of ASU 2016-09 did not have a material impact on the Company's consolidated financial
+statements and related disclosures. 
+In August 2016, the FASB issued ASU 2016-15, Statement of Cash
+Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments , which provides guidance related to cash flows presentation. The
+Company adopted ASU 2016-15 in the first quarter of 2018. The guidance in ASU 2016-15 is generally consistent with the Company’s current cash flow classifications, and did not have a material impact on the Company’s consolidated
+financial statements. 
+In January 2017, the FASB issued ASU 2017-04, Intangibles-Goodwill
+and Other (Topic 350): Simplifying the Test for Goodwill Impairment , which requires an entity to no longer perform a hypothetical purchase price allocation to measure goodwill impairment. Instead, impairment will be measured
+using the difference between the carrying amount and the fair value of the reporting unit. This update will be effective for annual and interim periods in fiscal years beginning after December 15, 2019. Early adoption is permitted. The
+Company adopted ASU 2017-04 in the fourth quarter of 2017. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements and related disclosures. 
+In May 2017, the FASB issued ASU No. 2017-09, Compensation-Stock
+Compensation (Topic 718): Scope of Modification Accounting , to provide clarity to which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. The Company adopted ASU 2017-09 in the first quarter of 2018. Adoption did not have a material effect on the Company’s consolidated financial
+statements. 
+In July 2018, the
+FASB issued ASU 2018-08 N ot-for-Profit Entities (Topic 958): Clarifying the Scope and the Accounting Guidance for Contributions Received and
+Contributions Made to clarify the accounting guidance related to contributions made or received. This guidance primarily
+affects not-for-profit entities, although it also applies to businesses to the extent that they make or receive contributions, including grants. ASU 2018-08 clarifies and improves the scope and accounting guidance for both contributions
+received and made in order to assist entities in evaluating if those transactions should be accounted for as contributions under the scope of Topic 958, or as an exchange transaction subject to other guidance. Public entities are required to apply the amendments on
+contributions received and contributions made to annual periods beginning after June 15, 2018, and December 15, 2018, respectively, each including interim periods within those annual periods. Early adoption is permitted, and the Company
+adopted ASU 2018-08 effective as of January 1, 2018. The impact of adoption was immaterial. 
+NOTE 4 — INVENTORIES: 
+Inventories consist of the following at: 
+December 31, 2018 
+December 31, 2017 
+Raw Materials 
+$ 
+2,803,677 
+$ 
+1,767,684 
+Work in Process 
+263,043 
+286,413 
+Finished Goods 
+4,784,502 
+2,369,521 
+$ 
+7,851,222 
+$ 
+4,423,618 
+NOTE 5 — FIXED ASSETS: 
+Fixed assets consist of the following at: 
+December 31, 2018 
+December 31, 2017 
+Machinery and Equipment 
+$ 
+6,070,137 
+$ 
+4,582,759 
+Furniture and Fixtures 
+35,287 
+449,548 
+Computer Equipment 
+435,348 
+422,946 
+Leasehold Improvements 
+2,334,512 
+2,258,779 
+Enterprise Business Systems 
+462,420 
+- 
+Less: Accumulated Depreciation and Amortization 
+(6,463,784 
+) 
+(5,804,800 
+) 
+$ 
+2,873,920 
+$ 
+1,909,232 
+There were no capital leases at the end of December 31, 2018. Fixed assets at December 31, 2018 also include $1,866,126 in equipment that is undergoing
+validation and as such is not yet being depreciated. Depreciation expense for the 2018 and 2017 years totaled $634,261 and $727,563, respectively. 
+As of December 31, 2018 and 2017, the Company had paid deposits on various pieces of equipment classified within Deposits and Other Assets aggregating
+$428,859 and $257,455, respectively. 
+NOTE 6 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES: 
+Accounts payable and accrued liabilities consist of the following at: 
+December 31, 2018 
+December 31, 2017 
+Accounts Payable - suppliers 
+$ 
+3,622,765 
+$ 
+1,494,759 
+Accrued Commissions 
+588,131 
+126,827 
+Accrued Royalties / license fees 
+279,213 
+429,297 
+Accrued Payroll 
+48,867 
+187,305 
+Accrued Vacation 
+264,789 
+309,767 
+Accrued Bonuses 
+494,318 
+282,500 
+Accrued Expenses - Other 
+590,598 
+215,848 
+$ 
+5,888,681 
+$ 
+3,046,303 
+F-12 
+Table of Contents 
+NOTE 7 — DEFERRED RESEARCH AND DEVELOPMENT REVENUE: 
+The Company recognizes income from R&D milestones when those milestones are reached and non-milestone contracts and grants when earned. These
+projects are invoiced after expenses are incurred. Any projects or grants funded in advance are deferred until earned. As of December 31, 2018 and 2017, there were $422,905 and $50,000 unearned advanced revenues, respectively. 
+NOTE 8 — INCOME TAXES: 
+The (benefit from) provision for income taxes for the years ended December 31, 2018 and 2017 is comprised of the following: 
+2018 
+2017 
+Current 
+Federal 
+$ 
+- 
+$ 
+(97,339 
+) 
+State 
+10,914 
+9,034 
+Foreign 
+- 
+- 
+Total current (benefit) provision 
+10,914 
+(88,305 
+) 
+Deferred 
+Federal 
+- 
+- 
+State 
+- 
+- 
+Foreign 
+(78,435 
+) 
+- 
+Total deferred (benefit) provision 
+(78,435 
+) 
+- 
+Total (benefit) provision 
+$ 
+(67,521 
+) 
+$ 
+(88,305 
+) 
+On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) was signed into law making significant changes to the Internal Revenue Code. Changes
+include, but are not limited to, a corporate tax rate decrease from 34% to 21% effective for tax years beginning after December 31, 2017, the transition of U.S international taxation from a worldwide tax system to a territorial system, and a
+one-time transition tax on the mandatory deemed repatriation of cumulative foreign earnings as of December 31, 2017. The Staff of the Securities and Exchange Commission issued Staff Accounting Bulletin No. 118 ("SAB 118") to address the
+application of U.S. GAAP in situations when a registrant does not have the necessary information available, prepared or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects of the Tax
+Act. As a result of the Tax Act, the Company remeasured its U.S. Federal deferred tax assets and liabilities at the rate they are expected to reverse in the future. The Company recorded a cumulative charge of $3,906,774 ($0 in 2018 and
+$3,906,774 in 2017), which was fully offset by an equivalent adjustment to the deferred tax valuation allowance. The Company recorded a cumulative benefit of $97,339 ($0 in 2018 and $97,339 in 2017) related to a credit for alternative minimum
+taxes (AMT) paid in prior years. During 2018, the Company finalized its computation of the impact of the Tax Act with no change to the provisional amount. 
+In January 2018, the FASB released guidance on the accounting for tax on the global intangible low-taxed income ("GILTI") provisions of the Tax Act. The
+GILTI provisions impose a tax on foreign income in excess of a deemed return on tangible assets of foreign corporations. The guidance allows companies to make an accounting policy election to either (1) account for GILTI as a component of tax
+expense in the period in which they are subject to the rules (the period cost method), or (ii) account for GILTI in the Company's measurement of deferred taxes (the deferred method). After completing the analysis of the GILTI provisions, the
+Company elected to account for GILTI using the period cost method. 
+The Company had an ownership change as described in Internal Revenue Code Sec. 382 during 2004 (“2004 change”). As a result, the Company’s net operating
+losses prior to the 2004 change of $5,832,516 were subject to an annual limitation of $150,608 and for the first five (5) years are entitled to a BIG (Built-In-Gains) of $488,207 per year. These net operating losses expire in 2019 through 2024. 
+The Company had a second ownership change during 2006 (“2006 change”). The net operating losses incurred between the 2004 change and the 2006 change of
+$8,586,861 were subject to an annual limitation of $1,111,831 and for the first five (5) years are entitled to a BIG of $1,756,842 per year. These net operating losses expire in 2024 through 2026. 
+After applying the above limitations, at December 31, 2018, the Company has post-change net operating loss carry-forwards of approximately $27,303,044
+which expire between 2019 and 2037 and $5,432,085 which do not expire. In addition the Company has research and development tax credit carryforwards of approximately $1,696,870 for the year ended December 31, 2018, which expire between 2019 and
+2036. 
+F-13 
+Table of Contents 
+The Company has state net operating loss carryforwards of approximately $1,784,554 which expire between 2025 and 2037. The Company has foreign net
+operating loss carryforwards of approximately $586,206 which do not expire. 
+2018 
+2017 
+Inventory reserves 
+$ 
+204,206 
+$ 
+244,158 
+Accrued expenses 
+175,168 
+102,332 
+Net operating loss carry-forwards 
+7,122,576 
+5,800,144 
+Research and development credit 
+1,696,870 
+1,918,137 
+Stock-based compensation 
+215,797 
+167,522 
+Depreciation 
+139,362 
+91,258 
+Total deferred tax assets 
+9,553,979 
+8,323,551 
+Intangibles 
+(968,849 
+) 
+(341,042 
+) 
+Total deferred tax liabilities 
+(968,849 
+) 
+(341,042 
+) 
+Net deferred tax assets before valuation allowance 
+8,585,130 
+7,982,509 
+Less valuation allowances 
+(9,477,438 
+) 
+(8,323,551 
+) 
+Net noncurrent deferred tax liabilities 
+$ 
+(892,308 
+) 
+$ 
+(341,042 
+) 
+The components of (loss) before income taxes consisted of the following: 
+Year Ending December 31, 
+2018 
+2017 
+United States operations 
+$ 
+(7,137,428 
+) 
+$ 
+(6,054,002 
+) 
+International operations 
+(795,742 
+) 
+(406,063 
+) 
+(Loss) before taxes 
+$ 
+(7,933,170 
+) 
+$ 
+(6,460,065 
+) 
+A reconciliation of the Federal statutory rate to the effective rate applicable to loss before income taxes is as follows: 
+Year Ending December 31, 
+2018 
+2017 
+Federal income tax at statutory rates 
+21.00 
+% 
+34.00 
+% 
+State income taxes, net of federal benefit 
+(.10 
+)% 
+(0.09 
+)% 
+Nondeductible expenses 
+(1.58 
+)% 
+(1.04 
+)% 
+Foreign rate differential 
+.36 
+% 
+(2.14 
+)% 
+Change in valuation allowance 
+(18.44 
+)% 
+(99.41 
+)% 
+Impact of Tax Act on valuation allowance 
+- 
+% 
+60.48 
+% 
+AMT refund under Tax Act 
+- 
+% 
+1.51 
+% 
+Tax credits 
+- 
+% 
+7.07 
+% 
+Other 
+(.39 
+)% 
+0.99 
+% 
+Income tax benefit 
+.85 
+% 
+1.37 
+% 
+Interest and penalties, if any, related to income tax liabilities are included in income tax expense. As of December 31, 2018, the Company does not
+have a liability for uncertain tax positions. 
+The Company files Federal and state income tax returns, opTricon files in Germany and CDM files in Malaysia and has been on tax holiday which expired on
+December 31, 2018. With few exceptions, tax years for fiscal 2015 through 2018 are open and potentially subject to examination by federal, state and foreign taxing authorities. 
+NOTE 9 — STOCKHOLDERS’ EQUITY: 
+(a) 
+Common Stock 
+In February 2018, the Company closed on an underwritten registered public offering of 1,783,760 shares of its common stock at $6.75 per share. The net proceeds of the offering, after deducting the
+underwriter’s discounts and other offering expenses payable by the Company, was approximately $10.9 million. 
+In
+November 2018, the Company closed on an underwritten public offering of 2,726,000 shares of its common stock, including the underwriter’s exercise of its overallotment of 355,565 shares, at $6.75 per share. The net proceeds of the offering,
+after deducting the underwriter’s discounts and other offering expenses payable by the Company, was approximately $16.5 million. 
+During 2018, options to purchase 144,947 shares of the Company’s common stock were exercised for 71,290 shares of common stock at exercise prices
+ranging from $3.48 to $5.64 by surrendering options and shares of common stock already owned . 
+During 2017, options to purchase 56,969 shares of the Company’s common stock were exercised for 22,487 shares of common stock at exercise prices ranging
+from $3.48 to $4.45 by surrendering options and shares of common stock already owned. 
+F-14 
+Table of Contents 
+(b) 
+Preferred Stock 
+The Company has 10,000,000 shares of preferred stock authorized and none outstanding. These shares can become issuable upon an approved resolution by
+the board of directors and the filing of a Certificate of Designation with the state of Nevada. 
+(c) 
+Options, Restricted Stock, and Restricted Stock Units 
+The Board of Directors or its Compensation Committee may issue options, restricted stock, and restricted stock units pursuant to employee stock incentive plans
+that have been approved by the Company's stockholders. 
+(d) 
+Warrants 
+As of December 31, 2018 and 2017, the Company had no warrants outstanding to purchase shares of common stock. 
+NOTE 10 — RIGHTS AGREEMENT: 
+In March 2016, the Company entered into a Rights Agreement (the "Rights Agreement") with Action Stock Transfer Corp., as Rights Agent. The Rights Agreement expired
+on March 7, 2019. Pursuant to the Rights Agreement, the Company declared a dividend distribution of one preferred share purchase right (a "Right") for each outstanding share of common stock as of March 8, 2016. 
+Rights Initially Not Exercisable. The Rights were not
+exercisable until a Distribution Date (as defined below). Until a Right was exercised, the holder thereof, as such, would have no rights as a shareholder of the Company, including, without limitation, the right to vote or to receive dividends. 
+Separation and Distribution of Rights . The Rights were
+evidenced by the certificates for common stock, and were not to be evidenced by separate rights certificates until the close of business on the tenth business day (the “Distribution Date”) following either (i) a public announcement that a
+person or group acquired beneficial ownership of 20% or more of the outstanding shares of common stock or (ii) a tender or exchange offer by any person or group is first published, sent or given within the meaning of Rule 14d-3(a) under the
+Securities Exchange Act of 1934, the consummation of which would result in the person or group having beneficial ownership of 20% or more of the outstanding shares of common stock. 
+NOTE 11 — STOCK INCENTIVE PLANS: 
+Effective June 3, 2008, the Company’s stockholders voted to approve the 2008 Stock Incentive Plan (“SIP”), with 625,000 shares of common stock available to be
+issued. At the Annual Stockholder Meeting on September 22, 2011 the Company’s stockholders voted to approve an increase to the shares of common stock issuable under the SIP by 125,000 to 750,000. Under the terms of the SIP, which expired
+during 2018, the Board of Directors or its Compensation Committee had the discretion to select the persons to whom awards were to be granted. Awards could be stock options, restricted stock and/or restricted stock units ("Equity Award Units"). 
+The awards became vested at such times and under such conditions as determined by the Board or its Compensation Committee. Cumulatively through December 31, 2018, there were 508,889 options exercised, and at December 31, 2018, 99,132 options
+were outstanding and no Equity Award Units were available to be issued under the SIP. 
+Effective June 19, 2014, the Company’s stockholders voted to approve the 2014 Stock Incentive Plan (“SIP14”), with 800,000 shares of common stock
+available to be issued. Under the terms of the SIP14, the Board or its Compensation Committee has the discretion to select the persons to whom awards are to be granted. Awards can be in the form of Equity Award Units. The awards become
+vested at such times and under such conditions as determined by the Board or its Compensation Committee. Cumulatively through December 31, 2018, there were 85,407 options exercised, and at December 31, 2018, 405,968 options were outstanding
+and 21,061 Equity Award Units were still available to be issued under the SIP14. During 2018, 266,839 shares of restricted stock and 20,725 restricted stock units were awarded under SIP14. 
+The Company's results for the years ended December 31, 2018 and 2017 include stock-based compensation expense totaling $632,805 and $384,897,
+respectively. Such amounts have been included in the Consolidated Statements of Operations within cost of goods sold ($25,615 and $47,000, respectively), research and development ($78,831 and $89,400, respectively) and selling, general and
+administrative expenses ($528,360 and $248,497, respectively). 
+Stock option compensation expense in the years ended December 31, 2018 and 2017 represents the estimated fair value of options outstanding which is
+being amortized on a straight-line basis over the requisite vesting period of the entire award. 
+The weighted average estimated fair value of stock options granted in the years ended December 31, 2018 and 2017 were $3.76 and $2.77 per share,
+respectively. The fair value of options at the date of grant was estimated using the Black-Scholes option pricing model. The expected volatility is based upon historical volatility of the Company’s stock and other contributing factors. The
+expected term is based on the Company’s historical experience with similar type options. 
+The weighted-average assumptions made in calculating the fair values of options are as follows for the respective years ended: 
+December 31, 2018 
+December 31, 2017 
+Expected term (in years) 
+4.96 
+5.48 
+Expected volatility 
+39.91 
+% 
+43.31 
+% 
+Expected dividend yield 
+n/a 
+n/a 
+Risk-free interest rate 
+2.70 
+% 
+1.78 
+% 
+The Company granted 93,750 new options during the year ended December 31, 2018. 
+F-15 
+Table of Contents 
+The following table provides stock option activity for the years ended December 31, 2018 and 2017: 
+Number of 
+Shares 
+Weighted 
+Average 
+Exercise Price per 
+Share 
+Weighted 
+Average 
+Remaining 
+Contractual 
+Term 
+Aggregate Intrinsic 
+Value 
+Outstanding at December 31, 2016 
+600,549 
+4.55 
+3.43 years 
+$ 
+1,463,052 
+Granted 
+267,875 
+6.40 
+Exercised 
+56,969 
+4.19 
+100,018 
+Forfeited/expired/cancelled 
+785 
+5.56 
+Outstanding at December 31, 2017 
+810,670 
+5.18 
+3.69 years 
+$ 
+2,477,853 
+Exercisable at December 31, 2017 
+371,295 
+4.44 
+2.62 years 
+$ 
+1,409,440 
+Outstanding at December 31, 2017 
+810,670 
+$ 
+5.18 
+3.69 years 
+$ 
+2,477,853 
+Granted 
+93,750 
+$ 
+9.80 
+352,220 
+Exercised 
+144,947 
+$ 
+4.83 
+523,327 
+Forfeited/expired/cancelled 
+47,505 
+$ 
+8.82 
+154,583 
+Outstanding at December 31, 2018 
+711,968 
+$ 
+5.62 
+3.33 years 
+$ 
+687,364 
+Exercisable at December 31, 2018 
+396,799 
+$ 
+4.70 
+2.66 years 
+$ 
+568,956 
+The following table summarizes information about stock options outstanding at December 31, 2018: 
+Stock Options Outstanding 
+Stock Options Exercisable 
+Range of 
+Exercise 
+Prices 
+Shares 
+Outstanding 
+Average 
+Remaining 
+Contract Life 
+(Year) 
+Weighted 
+Average 
+Exercise 
+Price 
+Aggregate 
+Intrinsic 
+Value 
+Shares 
+Exercisable 
+Weighted 
+Average 
+Exercise 
+Price 
+Aggregate 
+Intrinsic 
+Value 
+1 to 2.79999 
+- 
+- 
+$ 
+- 
+$ 
+- 
+- 
+$ 
+- 
+$ 
+- 
+2.8 to 4.59999 
+304,343 
+1.90 
+3.45 
+672,896 
+254,343 
+3.46 
+560,711 
+4.6 to 6.39999 
+152,875 
+3.43 
+5.85 
+14,468 
+58,020 
+5.80 
+8,245 
+6.4 to 8.19999 
+207,875 
+5.05 
+7.31 
+- 
+75,041 
+7.21 
+- 
+8.2 to 12 
+46,875 
+4.60 
+11.45 
+- 
+9,375 
+11.45 
+- 
+Total 
+711,968 
+3.33 
+$ 
+5.62 
+$ 
+687,364 
+396,779 
+$ 
+4.70 
+$ 
+568,956 
+As of December 31, 2018, there was $710,376 of net unrecognized compensation cost related to stock options that are not vested, which is expected to
+be recognized over a weighted average period of approximately 2.45 years. The total fair value of shares vested during the year ended December 31, 2018, was $553,000. 
+The following table summarizes information about restricted stock and restricted stock units outstanding as of December 31, 2018: 
+Number of 
+Shares & Units 
+Weighted 
+Average 
+Grant Date 
+Fair Value 
+Outstanding at December 31, 2017 
+- 
+$ 
+- 
+Granted 
+287,564 
+9.65 
+Exercised 
+- 
+- 
+Forfeited/expired/cancelled 
+- 
+- 
+Outstanding at December 31, 2018 
+287,564 
+9.65 
+Exercisable at December 31, 2018 
+- 
+$ 
+- 
+As of December 31, 2018, there was $1,688,746 of net unrecognized compensation cost related to restricted stock and restricted stock units that are not vested, which is expected to be recognized over a weighted
+average period of approximately 2.5 years. Stock based compensation cost related to restricted stock and restricted stock units recognized during the years ended December 31, 2018 and 2017 was $281,249 and $0, respectively. 
+F-16 
+Table of Contents 
+NOTE 12 — GEOGRAPHIC INFORMATION AND ECONOMIC DEPENDENCY: 
+The Company produces only one group of similar products known collectively as “rapid medical tests,” and it operates in a single business segment.
+Net product sales by geographic area are as follows: 
+For the years ended 
+December 31, 2018 
+December 31, 2017 
+Africa 
+$ 
+8,605,306 
+$ 
+3,568,455 
+Asia 
+1,389,120 
+1,626,750 
+Europe & Middle East 
+2,172,031 
+1,763,274 
+Latin America 
+11,722,224 
+8,476,003 
+United States 
+2,852,339 
+3,887,820 
+$ 
+26,741,020 
+$ 
+19,322,302 
+Long-lived assets by geographic area are as follows: 
+2018 
+2017 
+Asia 
+$ 
+466,185 
+$ 
+472,774 
+Europe & Middle East 
+123,752 
+- 
+United States 
+2,283,983 
+1,436,458 
+$ 
+2,873,920 
+$ 
+1,909,232 
+NOTE 13 — COMMITMENTS, CONTINGENCIES AND CONCENTRATIONS: 
+Employment Contracts: 
+The Company has multi-year contracts with two key employees. The contracts call for salaries presently aggregating $770,000 per year, and they expire
+in March 2019 and March 2020. The following table is a schedule of future minimum salary commitments: 
+2019 
+$ 
+485,493 
+2020 
+85,000 
+Pension Plan: 
+The Company has a 401(k) plan established for its employees whereby it matches 40% of the first 5% (or 2% of salary) that an employee contributes to the
+plan. Matching contribution expenses totaled $94,544 and $91,150 for the years ended December 31, 2018 and 2017, respectively. 
+Obligations Under Operating Leases: 
+The Company leases industrial space used for office, R&D and manufacturing facilities, currently with a monthly rent of $30,140. The current lease
+expires on April 30, 2019. The lease provides for annual increases of 2.5% percent each year starting May 1, 2016. In February of 2014, the Company entered into a lease for office and warehouse space, effective March 1, 2014, a short distance
+from its current facility currently with a monthly rent of $16,709. The space is used primarily for warehousing and provides for additional office space. The lease expires on April 30, 2020. The lease provides for annual increases of 3.0%
+percent each year starting March 1, 2016. The Company also leases office, warehouse, and manufacturing space in a single building in Kuala Lumpur, Malaysia persuant to two separate leases that each expire on April 30, 2020 and have an additional
+three year renewal option with combined monthly rent of approximately $5,400. The Company also leases space in Germany for offices, manufacturing, and center of excellence for optical technology. The lease will automatically renew annually on May
+31. The monthly cost is estimated at $13,445 with yearly increases of 2%. 
+The following is a schedule of future minimum rental commitments for the years ending December 31, 
+2019 
+$ 
+384,308 
+2020 
+88,576 
+2021 
+- 
+$ 
+472,884 
+Rent expense was $653,155 and $586,730 for the years ended December 31, 2018 and 2017, respectively. 
+Economic Dependency: 
+Customers are considered major customers when net sales exceed 10% of the Company's total net sales for period or outstanding trade receivables exceed
+10% of accounts receivable. The Company had the following major customers for the respective periods: 
+For the years ended 
+Accounts Receivable 
+December 31, 2018 
+December 31, 2017 
+December 31, 2018 
+December 31, 2017 
+Sales 
+% of Sales 
+Sales 
+% of Sales 
+Customer 1 
+$ 
+11,171,174 
+42 
+% 
+$ 
+8,065,217 
+42 
+% 
+$ 
+3,499,340 
+$ 
+- 
+Customer 2 
+4,346,640 
+16 
+% 
+- 
+- 
+% 
+1,033,824 
+- 
+The following table delineates purchases the Company had with vendors in excess of 10% of total purchases for the periods indicated: 
+For the years ended 
+Accounts Payable 
+December 31, 2018 
+December 31, 2017 
+December 31, 2018 
+December 31, 2017 
+Purchases 
+% of Purc. 
+Purchases 
+% of Purc. 
+Vendor 1 
+$ 
+* 
+* 
+$ 
+* 
+* 
+$ 
+* 
+$ 
+* 
+Vendor 2 
+* 
+* 
+746,868 
+12 
+% 
+* 
+* 
+Vendor 3 
+* 
+* 
+849,966 
+14 
+% 
+164,312 
+* 
+Vendor 4 
+1,646,614 
+16 
+% 
+884,698 
+14 
+% 
+* 
+* 
+In the tables above, an asterisk (*) indicates that purchases from the vendor did not exceed 10% for the period indicated. 
+The Company purchases materials pursuant to intellectual property rights agreements that are important components in its products. Management believes
+that other suppliers could provide similar materials on comparable terms. A change in suppliers, however, could cause a delay in manufacturing and a possible loss of sales, which could adversely affect operating results. 
+Litigation: 
+From time to time, the Company is involved in certain legal actions arising in the ordinary course of business. The outcomes of such actions, either individually
+or in the aggregate, are not expected to have a material adverse effect on the Company’s future financial position or results of operations. 
+F-17 
+Table of Contents 
+NOTE 14 — NOTE PAYABLE: 
+In September 2017, the Company entered into an agreement with an equipment vendor to purchase automated assembly equipment for approximately
+$660,000. The terms call for prepayments of 30% down, 60% at time of factory acceptance testing and 10% after delivery. The vendor agreed to lend the Company 15%, 40%, and 10% of each originally scheduled payment, respectively. The Company
+will pay interest at an annual rate of 12% until delivery. Beginning in September 2018, the Company began making monthly payments of principal and interest of approximately $20,150, at an annual rate of 12% over a twenty-four month period. 
+NOTE 15 — SUBSEQUENT EVENTS: 
+On February 5, 2019, the Company entered into a commercial real estate lease for a new corporate headquarters comprised of 70,000 square feet of office, research and development, and warehouse space
+in Hauppauge, New York. The lease has an initial term of eleven years that can be extended, at the Company’s option, for two additional terms of five years each. Rent under the lease, which is payable in monthly installments, totals
+approximately $900,000 for the initial year and then increases by approximately three percent each succeeding year. Upon lease inception, the Company provided a security deposit and paid four months base rent that together totaled
+approximately $450,000. The base rent which will be deducted against the rent due following a nine-month free rent period. 
+On February 5, 2019, the Company also entered into an agreement of sublease with an affiliate of the Hauppauge, NY
+facility landlord to sublet the Company’s warehouse space and supplemental administrative office facility in Holbrook, New York. The sublease has a term that will (a) commence on the later of March 18, 2019 and the date the Company vacates
+the premises and (b) terminate on April 29, 2020, which is immediately prior to the termination of the Company’s lease for the facility. The sublessee will pay the Company 50% of the Company’s rent and additional rent payments, which will
+total approximately $100,000 per year during the term of the sublease. 
+F-18
\ No newline at end of file
diff --git a/raw/filings/0001092662/2018/0001140361-19-005069/filing_metadata.csv b/raw/filings/0001092662/2018/0001140361-19-005069/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..deca774c5aae1d312e2326683f8ab041c02eb2f0
--- /dev/null
+++ b/raw/filings/0001092662/2018/0001140361-19-005069/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0001092662,CEMI,"CHEMBIO DIAGNOSTICS, INC.",10-K,2019-03-18,2018-12-31,2019-03-18T10:28:44.000Z,0001140361-19-005069,form10_k.htm,,7567802,1,0,https://www.sec.gov/Archives/edgar/data/1092662/000114036119005069/form10_k.htm,https://www.sec.gov/Archives/edgar/data/1092662/000114036119005069/,2018,2018,1
diff --git a/raw/filings/0001092662/2018/0001140361-19-005069/item1.txt b/raw/filings/0001092662/2018/0001140361-19-005069/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..4d586273978df1d729b7d18529fb73fe2db6a5a4
--- /dev/null
+++ b/raw/filings/0001092662/2018/0001140361-19-005069/item1.txt
@@ -0,0 +1,470 @@
+ITEM 1. 
+BUSINESS 
+Overview 
+We are a leading provider of point-of-care diagnostic products for the detection and
+diagnosis of infectious diseases. We have been expanding our product portfolio based upon our proprietary Dual Path Platform, which we refer to as the DPP technology platform, which uses a small drop of blood from the fingertip to provide
+high-quality, cost-effective diagnostic results in approximately 15 minutes. We seek to build additional revenue streams by entering into technology collaborations with leading global healthcare companies to leverage the DPP platform. 
+Compared with traditional lateral flow technology, the DPP technology platform provides
+enhanced sensitivity and specificity, advanced multiplexing capabilities, and, when used with the DPP Micro Reader, quantitative results. Our DPP test for human immunodeficiency virus, or HIV, provides sensitivity of 99.8% and specificity of 100%,
+and has been approved by the U.S. Food and Drug Administration, or FDA, and cleared as a waived test under the Clinical Laboratory Improvement Amendments of 1988, or CLIA. On November 6, 2018, we completed our acquisition of opTricon GmbH, a
+Berlin-based developer and manufacturer of handheld analyzers for rapid diagnostic tests, which we believe will enable us to promote DPP tests and DPP Micro
+Readers more actively across global markets. 
+We are pursuing three corporate priorities, the key building blocks to drive growth and operating
+efficiency: ( 1) expand our commercialization; (2) advance our research and development pipeline; and (3) prepare for future growth. 
+Industry 
+The DPP technology platform addresses the lateral flow test market, which includes
+infectious diseases, cardiac markers, cholesterol and lipids, pregnancy and fertility, and drugs of abuse. Based on our review of third-party reports and other information, we estimate that the market for lateral flow tests will increase from $5.5
+billion in 2017 to $8.2 billion in 2022, representing a compound annual growth rate of 8.2%. 
+Infectious disease tests constitute the largest, and fastest growing, segment of the
+lateral flow test market. We currently are targeting lateral flow test solutions for three areas of infectious diseases: sexually transmitted disease, mosquito-borne disease and hepatitis. The market for lateral flow infectious disease tests is
+being driven by the high prevalence of infectious diseases globally, an increase in the geriatric population, growing demand for rapid test results, and advancements in multiplexing. Based on our review of third-party reports and other information,
+we estimate that the market for lateral flow infectious disease tests will increase from $1.4 billion in 2017 to $2.3 billion in 2022, representing a compound annual growth rate of 10.7%. 
+Products 
+Our point-of-care infectious disease portfolio is comprised of multiple commercial products, each
+serving unique customer requirements. The key advantages of our products, which are performed with a tiny drop of blood from the fingertip and provide results in approximately 15 minutes, include: 
+• 
+enhanced sensitivity and specificity; 
+• 
+advanced multiplexing; and 
+• 
+quantitative results, when used with DPP Micro Reader. 
+We have obtained U.S. FDA approvals and, directly or through our partners, international
+regulatory approvals for infectious disease tests as follows: 
+Product (Assay) 
+U.S. 
+International 
+DPP HIV 1/2 
+✓ 
+✓ 
+DPP HIV-Syphilis 
+✓ 
+DPP Syphilis Screen & Confirm 
+✓ 
+DPP Zika 
+✓ 
+✓ 
+DPP Leishmaniasis 
+✓ 
+STAT-PAK HIV 1/2 
+✓ 
+✓ 
+STAT-PAK Chagas 
+✓ 
+SURE CHECK HIV 1/2 
+✓ 
+✓ 
+SURE CHECK HIV 1/2 Self Test 
+✓ 
+Organic growth in our core infectious disease business is being driven by: 
+• 
+growth in the overall market for lateral flow infectious disease tests, which we estimate will increase at a
+compound annual growth rate of 10.7% through 2022 (see “--Industry” above); 
+• 
+our increased market penetration in existing markets and channels, including in the United States, Latin America,
+Africa and Europe; 
+• 
+our registration of existing and new products in unchartered countries and regions, such as selected countries in
+Latin America and Southeast Asia; 
+• 
+our entry into new market segments, such as international HIV Self-Testing; and 
+• 
+advances in our product pipeline in infectious disease with key products including a multiplex test for HIV and
+syphilis in the U.S. market and tests for dengue, zika and chikungunya. 
+We market and sell both stand-alone and multiplex tests for sexually transmitted infectious diseases, such as
+HIV and syphilis. HIV and syphilis continue to be major global public health issues. According to WHO estimates: 
+• 
+HIV has claimed more than 35 million lives, including 940,000 in 2017. Approximately 36.9 million were
+living with HIV at the end of 2017, and 1.8 million were newly infected during 2017. 
+• 
+There were 18.0 million prevalent cases of syphilis as of 2012, and 5.6 million new infections were
+estimated to occur annually. 
+• 
+Elimination of
+mother-to-child transmission, or MTCT, of both HIV and syphilis is a global health priority. In 2013, 1.9 million pregnant women were infected with syphilis worldwide. Congenital syphilis contributes significantly to infant
+mortality, accounting for 305,000 annual perinatal deaths worldwide in 2013. Globally, more than 1.4 million pregnant women were infected with HIV as of 2015, and MTCT of HIV is estimated to have resulted in over 150,000 infant cases in
+2015. 
+We are seeking to address the global concerns related to HIV and syphilis co-infection
+through the development of a novel, multiplex test for both HIV and syphilis. We have developed a DPP HIV-Syphilis multiplex test and received regulatory approvals covering a number of international markets, including Brazil, Europe, Malaysia and
+Mexico. In the United States we have completed a DPP HIV-Syphilis clinical trial and filed a Pre-Market Approval Application with the FDA, which is in the review process. We believe we are well-positioned to be the first company to introduce a
+multiplex rapid test for HIV and syphilis in the United States. 
+We also market and sell tests for selected fever and tropical diseases such as
+Chagas, ebola, leishmaniasis and Zika. The market for lateral flow mosquito-borne diseases includes established markets for disease such as dengue and malaria, which WHO estimates together account for more than 600 million annual infections
+worldwide. There are also a number of emerging markets for lateral flow tests for infectious diseases such as burkholderia, chikungunya, lassa, leptospirosis, Marburg, rickettsia and Zika. We are developing tests, using the DPP platform, to detect
+all of the aforementioned fever and tropical diseases, as stand-alone or multiplex tests. 
+Since 2015 we have received over $9 million of funding from some of the world ’ s leading health organizations, which has helped us accelerate the expansion of our pipeline of infectious disease tests. Our collaborators have included Bill
+& Melinda Gates Foundation, The Paul G. Allen Family Foundation, The Oswaldo Cruz Foundation or FIOCRUZ, and the Foundation for Innovative New Diagnostics or FIND, as well as U.S. government agencies such as Centers for Disease Control, or CDC,
+and the Biomedical Advanced Research and Development Authority of the U.S. Department of Health and Human Services or BARDA, and the U.S. Department of Agriculture, or USDA. Many of the tests in our infectious disease pipeline are approaching
+commercialization, and several have received initial regulatory approvals: 
+Product 
+Collaborator 
+Phase I 
+Feasibility 
+Phase II 
+Development 
+Phase III 
+Verification 
+&Validation 
+Phase IV 
+Clinical/ 
+Regulatory 
+Phase V 
+Commercial 
+Launch 
+DPP HIV-Syphilis (US) 
+Self-funded 
+✓ 
+✓ 
+✓ 
+Submitted FDA 
+Q1 2018 
+DPP Dengue (International) 
+Fiocruz 
+✓ 
+✓ 
+✓ 
+Submitted ANVISA 1 
+Q3 2018 
+DPP Dengue NS1 (International) 
+Fiocruz 
+✓ 
+✓ 
+Ongoing 
+DPP Zika (US/International) 
+Fiocruz 
+✓ 
+✓ 
+✓ 
+✓ 
+Received 
+FDA EUA 2 , 
+ANVISA, CE mark 
+DPP Chikungunya (International) 
+Fiocruz 
+✓ 
+✓ 
+✓ 
+✓ 
+Received 
+ANVISA, Malaysia 
+DPP Dengue-Zika- Chikungunya (International) 
+Fiocruz 
+✓ 
+✓ 
+✓ 
+Submitted ANVISA 
+Q3 2018 
+Received 
+Malaysia 
+DPP Malaria (International) 
+Bill & Melinda Gates Foundation 
+✓ 
+✓ 
+Ongoing 
+DPP Ebola (US, International) 
+Centers for Disease Control 
+✓ 
+✓ 
+✓ 
+Received FDA EUA Q4 2018 
+DPP Fever Panel (Africa) 
+The Paul G. Allen Family Foundation 
+✓ 
+✓ 
+✓ 
+Field Testing: 
+Africa, South America 
+DPP Fever Panel (Asia) 
+FIND 
+✓ 
+Ongoing 
+____________________________ 
+1 Ag ê ncia Nacional de Vigil â ncia Sanit á ria (Brazil) 
+2 Emergency Use Authorization 
+Collaborations 
+We are building additional revenue streams by leveraging our patented DPP technology and
+scientific expertise through collaborations. Leading global healthcare organizations have chosen to collaborate with us based on our deep scientific expertise with our proven DPP technology platform and capabilities, our successful record of
+developing DPP tests with a diverse set of collaborators including global commercial companies, governments and non-governmental organizations, and our extensive experience in obtaining regulatory approvals in the United States (FDA), Brazil
+(ANVISA), the European Union (CE mark) and Mexico (Comisión Federal para la Protección contra Riesgos Sanitarios, or COFEPRIS) as well as from WHO (Prequalification, or PQ). 
+Product 
+Collaborator 
+Phase I 
+Feasibility 
+Phase II 
+Development 
+Phase III 
+Verification 
+&Validation 
+Phase IV 
+Clinical/ 
+Regulatory 
+Phase V 
+Commercial 
+Launch 
+DPP Eosinophilic / Respiratory 
+AstraZeneca 
+✓ 
+✓ 
+Ongoing 
+Received CE mark Q4 2018 
+DPP Cancer 
+Undisclosed 
+✓ 
+✓ 
+Ongoing 
+Infectious Disease Portfolio 
+LumiraDx 
+Initiated Q3 2018 
+DPP Concussion 
+Perseus Science 
+✓ 
+Ongoing 
+DPP Bovine Tuberculosis 
+USDA 
+✓ 
+Ongoing 
+DPP Hepatitis C Ab 
+FIND 
+✓ 
+Ongoing 
+DPP Hepatitis C Ag 
+FIND 
+Initiated Q3 2018 
+By leveraging our DPP technology platform, we are creating opportunities
+to expand into new markets such as cancer diagnostics, concussion and traumatic brain injury, and veterinary and we are broadening the application of our technology from point-of-care diagnostics to include companion diagnostics. Research and
+development costs related to the collaborations are fully funded by our collaborators. 
+Sales Channels 
+Our products are sold globally, both directly and through distributors, to hospitals and
+clinics, physician offices, clinical laboratories, public health organizations, government agencies and consumers. Historically we marketed and sold our products only into a handful of countries and regions. In recent years we have hired sales
+executives to begin building our own channels in key markets such as the United States, Europe, Latin America, Africa and Southeast Asia. With sales growth as an underlying objective, we are focused on increasing sales in existing geographies,
+expanding sales into new geographies, and broadening sales coverage in key markets. 
+Automation of U.S. Manufacturing 
+We are automating our U.S. manufacturing processes and expanding our manufacturing
+capacity. During 2018, we took delivery of our first automated manufacturing line. This automated manufacturing line will be used for DPP test production and will allow assembly of various configurations of DPP tests on the line. The automated line
+will have an annual capacity of between five and ten million tests, depending on the test configuration, and will use vision-guided, robotic operation to improve inspection and quality control. As we transition from manual to automated assembly, we
+believe the reduced variable costs will improve product gross margins. 
+3 
+Table of Contents 
+DPP Technology & Development 
+Our commercially available products employ either our patented DPP technology or traditional lateral flow technology. We believe products developed using
+our DPP technology can provide superior diagnostic performance compared with products that utilize traditional lateral flow technology. 
+We are executing our strategy to leverage DPP intellectual property, as well as our scientific and operational expertise, to create new collaborations where
+we will serve as an exclusive development and manufacturing partner. Examples of such collaborations include the following: 
+• 
+In January 2015, we entered into an agreement with the Concussion Science Group (CSG) Division of Perseus Science
+Group LLC to develop a point-of-care diagnostic test for traumatic brain injury, including sports-related concussions, utilizing both our DPP and optical analyzer technologies. 
+• 
+In October 2017, we signed a development agreement with AstraZeneca for the development of a quantitative point-of-care test for eosinophilic
+respiratory disease, utilizing both our DPP and optical analyzer technologies. 
+• 
+In April 2018, we entered into a collaboration agreement with LumiraDx to develop new point-of-care diagnostic tests for infectious diseases. Under terms of the agreement, we receive
+funding from LumiraDx, subject to satisfying certain milestones, to develop certain new point-of-care infectious disease tests. Following the regulatory approval and commercialization of tests in accordance with this agreement,
+Chembio will both sell reagents to, and receive royalty payments from, LumiraDx on sales of all products developed through this collaboration. 
+• 
+In November 2018, we acquired opTricon (Berlin, Germany), a leading developer of handheld optical analyzers rapid diagnostic tests. See
+“Management’s Discussion & Analysis of Financial Condition and Results of Operations—Recent Developments.” 
+Competition 
+Many of our competitors are significantly larger and have greater financial, research, manufacturing, and marketing resources. Important competitive factors
+include product quality, analytical performance, ease of use, price, customer service and reputation. Industry competition is based on these and the following additional factors: 
+• 
+patent protection; 
+• 
+scientific expertise; 
+• 
+ability to develop and market products and processes; 
+• 
+ability to obtain required regulatory approvals; 
+• 
+ability to manufacture cost-effective products that meet applicable regulatory requirements; 
+• 
+access to adequate capital; and, 
+• 
+ability to attract and retain qualified personnel. 
+4 
+Table of Contents 
+We believe our scientific capabilities and proprietary know-how relating to our patented DPP technology and lateral flow technology are very strong,
+particularly for the development and manufacture of tests for the detection of antibodies to infectious diseases, and other diseases. 
+Our ability to develop and market other products is in large measure dependent on our having additional resources and/or collaborative relationships. Some
+of our product development efforts have been funded on a project or milestone basis. We believe that our proprietary know-how relating to our patented DPP technology has been instrumental in our obtaining the collaborations we have and that we
+continue to pursue. We believe that our patent protection enhances our ability to both develop more profitable, collaborative relationships and expand licensing revenue. However, there are a number of competitive technologies used and/or seeking to
+be used by others in point-of-care settings. 
+Although we have no specific knowledge of any other competitors’ products that could render our products obsolete, if we fail to maintain and enhance our
+competitive position or fail to introduce new products and product features, our customers may decide to use the products developed by our competitors, which could result in a loss of revenues and cash flow. 
+Employees 
+As of December 31, 2018, we had 295 full-time equivalent employees, of whom 15 were in administration, 215 were in
+manufacturing, 45 were in research and development, and 20 were in sales and marketing and customer service. Of these employees, approximately 240 were located in the United States, 27 were located in Malaysia, 20 were located in Germany, and 3
+were located in other countries. 
+We have never had a work stoppage, and none of our employees are represented by a labor
+organization or subject to any collective bargaining arrangements. We consider our employee relations to be good. 
+Governmental Regulation 
+Certain of our activities are subject to regulatory oversight by the FDA under provisions of the Federal Food, Drug, and Cosmetic Act
+and regulations thereunder, including regulations governing the development, marketing, labeling, promotion, manufacturing, and export of diagnostic products. Our clinical laboratory customers are subject to oversight by Centers for Medicare and
+Medicaid Services, or CMS, pursuant to CLIA, as well as agencies in various states. Failure to comply with applicable requirements can lead to sanctions, including withdrawal of products from the market, recalls, refusal to authorize government
+contracts, product seizures, civil money penalties, injunctions, and criminal prosecution. 
+FDA Approval/Clearance Requirements 
+Unless an exemption applies, each medical device that we market or wish to market in the United States must receive 510(k) clearance or
+Premarket Approval, or PMA. Medical devices that receive 510(k) clearance are “cleared” by the FDA to market, distribute, and sell in the United States. Medical devices that obtain a PMA by the FDA are “approved” to market, distribute and sell in the
+United States. We cannot be certain that 510(k) clearance or PMA approval will ever be obtained for any products that have not already obtained 510(k) clearance or PMA approval. Descriptions of the PMA and 510(k) clearance processes are provided
+below. 
+The FDA decides whether a device line must undergo either the 510(k) clearance or PMA based on statutory criteria that utilize a
+risk-based classification system. PMA is the FDA process of scientific and regulatory review to evaluate the safety and effectiveness of Class III medical devices and, in many cases, Class II medical devices. Class III devices are those that support
+or sustain human life, are of substantial importance in preventing impairment of human health, or which present a potential, unreasonable risk of illness or injury. The FDA uses these criteria to decide whether a PMA or a 510(k) is appropriate,
+including the level of risk that the agency perceives is associated with the device and a determination by the agency of whether the product is a type of device that is similar to devices that are already legally marketed. Devices deemed to pose
+relatively less risk are placed in either Class I or II. In many cases, the FDA requires the manufacturer to submit a 510(k) requesting clearance (also referred to as a premarket notification), unless an exemption applies. The 510(k) must demonstrate
+that the manufacturer’s proposed device is “substantially equivalent” in intended use and in safety and effectiveness to a legally marketed predicate device. A “predicate device” is a pre-existing medical device to which equivalence can be drawn,
+that is either in Class I or Class II or is a Class III device that was in commercial distribution before May 28, 1976, for which the FDA has not yet called for submission of a PMA application. 
+Device classification depends on the device’s intended use and its indications for use. In addition, classification is risk-based, that
+is, the risk the device poses to the patient and/or the user is a major factor in determining the class to which it is assigned. Class I includes devices with the lowest risk and Class III includes those with the greatest risk. 
+Class I devices are those for
+which safety and effectiveness can be assured by adherence to the FDA’s general regulatory controls for medical devices, or the General Controls, which include compliance with the applicable portions of the FDA’s quality system regulations, facility
+registration and product listing, reporting of adverse medical events, and appropriate, truthful and non-misleading labeling, advertising, and promotional materials. Some Class I devices also require premarket clearance by the FDA through the 510(k)
+process described below. 
+Class II devices are subject to
+the FDA’s General Controls, and any other special controls as deemed necessary by the FDA to ensure the safety and effectiveness of the device. Premarket review and clearance by the FDA for Class II devices is accomplished through the 510(k) process.
+Pursuant to the Medical Device User Fee and Modernization Act of 2002, unless a specific exemption applies, 510(k) submissions are subject to user fees. Certain Class II devices are exempt from this premarket review process. 
+Class III includes devices
+with the greatest risk. Devices in this class must meet all of the requirements in Classes I and II. In addition, Class III devices cannot be marketed until they receive Premarket Approval. 
+The safety and effectiveness of Class III devices cannot be assured solely by the General Controls and the other requirements
+described above. These devices require formal clinical studies to demonstrate safety and effectiveness. Under Medical Device User Fee and Modernization Act of 2002, PMA applications (and supplemental premarket approval applications) are subject to
+significantly higher user fees than 510(k) applications, and they also require considerably more time and resources. 
+Rapid HIV tests intended for diagnostic use are regulated as Class III devices. Responsibility for assuring the safety and
+effectiveness of these tests lies within the Center for Biologics Evaluation and Research’s Office of Blood Research and Review, with oversight by the Blood Products Advisory Committee. Approved rapid HIV tests must meet the regulations in the 21
+CFR 800 series subparts, under the investigational device exemption, or IDE and PMA pathways. 
+5 
+Table of Contents 
+Premarket Approval Pathway 
+We manufacture, market and distribute three rapid HIV tests in the United States. Our HIV 1/2 STAT-PAK Assay, SURE CHECK HIV 1/2
+Assay, and DPP HIV 1/2 Assay all have received FDA PMA approval. A PMA application must be supported by extensive data including, but not limited to, analytical, preclinical, clinical trials, manufacturing, statutory preapproval inspections, and
+labeling to demonstrate to the FDA’s satisfaction the safety and effectiveness of the device for its intended use. Before a PMA is submitted, a manufacturer must apply for an IDE. If the device presents a “significant risk,” as defined by the FDA,
+to human health, the FDA requires the device sponsor to file an IDE application with the FDA and obtain IDE approval prior to initiation of enrollment of human subjects for clinical trials. The IDE provides the manufacturer with a legal pathway to
+perform clinical trials on human subjects where without the IDE, only approved medical devices may be used on human subjects. 
+The IDE application must be supported by appropriate data, such as analytical, animal and laboratory testing results, manufacturing
+information, and an Investigational Review Board (IRB) approved protocol showing that it is safe to test the device in humans and that the testing protocol is scientifically sound. If the clinical trial design is deemed to have “non-significant
+risk,” the clinical trial may be eligible for “abbreviated” IDE requirements. In some instances, clinical trials for in vitro diagnostic medical devices may be exempt from the more burdensome IDE requirements if certain labeling requirements are
+met. 
+A clinical trial may be suspended by either the FDA or the Investigational Review Board at any time for various reasons, including a
+belief that the risks to the study participants outweigh the benefits of participation in the study. Even if a study is completed, clinical testing results may not demonstrate the safety and efficacy of the device, or they may be equivocal or
+otherwise insufficient to obtain approval of the product being tested. After the clinical trials have been completed, if at all, and the clinical trial data and results are collected and organized, a manufacturer may complete a PMA application. 
+After a PMA application is sufficiently complete, the FDA will accept the application and begin an in-depth review of the submitted
+information. By statute, the FDA has 180 days to review the “accepted application,” although, generally, review of the application can take between one and three years, but it may take significantly longer. During this review period, the FDA may
+request additional information or clarification of information already provided. Also, during the review period, an advisory panel of experts from outside the FDA may be convened to review and evaluate the application and provide recommendations to
+the FDA as to the approvability of the device. The preapproval inspections conducted by the FDA include an evaluation of the manufacturing facility to ensure compliance with the FDA's quality systems regulations or QSR, as well as inspections of
+the clinical trial sites by the Bioresearch Monitoring group to evaluate compliance with good clinical practice and human subject protections. New PMA applications or PMA supplements are required for modifications that affect the safety or
+effectiveness of the device, including, for example, certain types of modifications to the device’s indication for use, manufacturing process, labeling and design. Significant changes to an approved PMA require a 180-day supplement, whereas less
+substantive changes may utilize a 30-day notice, or a 135-day supplement. Premarket approval supplements often require submission of the same type of information as a premarket approval application, except that the supplement is limited to
+information needed to support any changes from the device covered by the original premarket approval application, and it may not require as extensive clinical data or the convening of an advisory panel. 
+Our HIV 1/2 STAT-PAK Assay PMA application number BP050009/0 and our SURE CHECK 1/2 HIV Assay PMA application number BP050010/0 were
+approved by the FDA in May 2006. Our DPP HIV 1/2 Assay PMA application number BP120032/0 was approved by the FDA in December 2012. 
+510(k) Clearance Pathway 
+We are currently developing products that either will or are likely to require an FDA 510(k) clearance, and we anticipate submitting
+a 510(k) for each such product to demonstrate that such proposed device is substantially equivalent to a respective previously cleared 510(k) device or a device that was in commercial distribution before May 28, 1976, for which the FDA has not yet
+called for the submission of 510(k). FDA's 510(k) clearance pathway usually takes from three to twelve months but could take longer. In some cases the FDA may require additional information, including clinical data, to make a determination
+regarding substantial equivalence. 
+If a device receives 510(k) clearance, any modification that could significantly affect its safety or effectiveness, or that would
+constitute a new or major change in its intended use, will require a new 510(k) clearance or, depending on the modification, a PMA. The FDA requires each device manufacturer to determine whether the proposed change requires submission of a new
+510(k) or a PMA, but the FDA can review any such decision and can disagree with a manufacturer’s determination. If the FDA disagrees with a manufacturer’s determination, the FDA can require the manufacturer to cease marketing and/or recall the
+modified device until 510(k) clearance or PMA of the modified device is obtained. 
+If the FDA requires us to submit a new 510(k) or PMA for any modifications to a previously cleared product, or if we obtain 510(k)
+clearance for a device in the future, we may be required to submit a separate new 510(k) or PMA application for such modifications. 
+Clinical Laboratory Improvement Amendments of 1988 
+A manufacturer of a test categorized as moderately complex may request that categorization of the test be waived through a CLIA
+Waiver by Application, or CW, submission to the FDA. When a test is categorized as waived, it may be performed by laboratories with a Certificate of Waiver, such as a physician’s office outreach setting. In a CW submission, the manufacturer
+provides evidence to the FDA that a test meets the CLIA statutory criteria for waiver CLIA, a walk-in clinic or an emergency room provides CMS authority over all laboratory testing, except research that is performed on humans in the United States.
+The Division of Laboratory Services, within the Survey and Certification Group under the CMS, has the responsibility for implementing the CLIA program. 
+The CLIA program is designed to establish quality laboratory testing by ensuring the accuracy, reliability and timeliness of patient
+test results. Under CLIA, a laboratory is a facility that does laboratory testing on specimens derived from humans and used to provide information for the diagnosis, prevention or treatment of disease, or impairment of, or assessment of health.
+Under the CLIA program, unless waived, laboratories must be certified by the government, satisfy governmental quality and personnel standards, undergo proficiency testing, be subject to inspections and pay fees. We have received a CLIA waiver for
+all of our lateral flow rapid HIV tests that we market in the United States. Specifically, the CLIA waiver was granted by the FDA for HIV 1/2 STAT-PAK in November 2006,for SURE CHECK HIV 1/2 in October 2007, and for DPP HIV 1/2 in October 2014. 
+6 
+Table of Contents 
+Pervasive and Continuing FDA Regulation 
+A host of regulatory requirements apply to our approved devices, including: the quality system regulation, which requires
+manufacturers to follow elaborate design, testing, control, documentation and other quality assurance procedures; the Medical Reporting Regulations, which require manufacturers to report to the FDA specified types of adverse events involving their
+products; labeling regulations; and the FDA’s general prohibition against promoting products for unapproved or “off-label” uses. Some Class II devices are subject to special controls-such as performance standards, post-market surveillance, patient
+registries, and FDA guidelines-that do not apply to Class I devices. 
+The regulatory requirements that apply to our approved products classified as medical devices include: 
+• 
+product listing and establishment registration, which helps facilitate FDA inspections and other regulatory action; 
+• 
+QSR, which require manufacturers, including third-party manufacturers, to follow stringent design, testing, control, documentation
+and other quality assurance procedures during all aspects of the development and manufacturing process; 
+• 
+labeling regulations and FDA prohibitions against the promotion of products for uncleared, unapproved or
+off-label use or indication; 
+• 
+clearance of product modifications that could significantly affect safety or efficacy or that would constitute a
+major change in intended use of one of our cleared devices; 
+• 
+approval of product modifications that affect the safety or effectiveness of one of our cleared devices; 
+• 
+medical device reporting regulations, which require that manufacturers comply with FDA requirements to report if
+their device may have caused or contributed to a death or serious injury, or has malfunctioned in a way that would likely cause or contribute to a death or serious injury if the malfunction of the device or a similar device were to
+recur; 
+• 
+post-approval restrictions or conditions, including post-approval study commitments; 
+• 
+post-market surveillance regulations, which apply when necessary to protect the public health or to provide
+additional safety and effectiveness data for the device; 
+• 
+the FDA’s recall authority, whereby it can ask, or under certain conditions order, device manufacturers to
+recall from the market a product that is in violation of governing laws and regulations; 
+• 
+regulations pertaining to voluntary recalls; and, 
+• 
+notices of corrections or removals. 
+Our Medford, New York facility is currently registered as an establishment with the FDA. We and any third-party manufacturers are
+subject to announced and unannounced inspections by the FDA to determine our compliance with QSR and other regulations. 
+21st Century Cures Act 
+The 21st Century Cures Act, enacted in December 2016, contains several sections specific to medical device innovations. We believe
+that implementation of the 21st Century Cures Act may have a positive impact on its businesses by facilitating innovation and/or reducing the regulatory burden imposed on medical device manufacturers. 
+Government Regulation of Medical Devices for Animal Subjects 
+We currently sell, market or distribute two veterinary devices in the United States: DPP VetTB Assay for Cervids and DPP VetTB Assay
+for Elephants. Diagnostic tests for animal health infectious diseases, including our veterinary devices for the prevention and/or treatment of animal disease, are regulated in the U.S. by the Center for Veterinary Biologics within the U.S.
+Department of Agriculture Animal and Plant Health Inspection Service, or APHIS, under the Virus, Serum, and Toxin Act of 1913. As a requirement, our veterinary devices were approved by APHIS before they could be sold in the U.S. 
+The APHIS regulatory approval process involves the submission of product performance data and manufacturing documentation. Following
+regulatory approval to market a product, APHIS requires that each lot of product be submitted for review before release to customers. In addition, APHIS requires special approval to market products where test results are used in part for
+government-mandated disease management programs. 
+Environmental Laws 
+We believe that we are in compliance with all foreign, federal, state, and local environmental regulations with
+respect to our manufacturing facilities. The cost of ongoing compliance with such regulations does not have a material effect on our operations. 
+Intellectual Property 
+Intellectual Property Strategy 
+Our intellectual property strategy is to: (1) build our own intellectual property portfolio around our DPP technology and optical analyzers; (2) pursue
+licenses, trade secrets and know-how within the area of rapid point-of-care testing; and, (3) develop and acquire proprietary positions to certain reagents. 
+7 
+Table of Contents 
+DPP ® Intellectual Property 
+We have obtained patent coverage on our DPP technology, including numerous patents in the United States, China, Malaysia, Eurasia, Mexico, Singapore, Japan,
+Australia, Indonesia, Korea and the U.K. Additional patent applications on our DPP technology are pending in the United States, as well as in foreign countries such as Brazil, Canada, the European Union, India, Israel, and South Africa. 
+DPP technology provides us with freedom to operate, which enables us to develop tests with better performance and capabilities compared with tests built on
+traditional lateral flow platforms. These advantages have allowed us to enter into multiple technology collaborations based upon DPP technology, which we believe will provide new manufacturing and marketing opportunities. We have filed additional
+patent applications that we believe will strengthen the DPP intellectual property and have also filed for patent protection for certain other point-of-care technologies or applications thereof. 
+We have also obtained patent coverage on our optical-based analyzer technology in the United States, with patents pending in several foreign countries. 
+Trademarks 
+We have filed and obtained trademarks for our products, including DPP, SURE CHECK, STAT-VIEW, and STAT-PAK, and NEXT GENERATION DPP, as well as for the
+SampleTainer and DPP Micro Reader, which are used with certain DPP products. Our trademarks have been obtained in the United States and certain other countries around the world. 
+Trade Secrets and Know-How 
+We have developed a substantial body of trade secrets and know-how relating to the development and manufacture of lateral flow and DPP-based diagnostic
+tests, including the sourcing and optimization of materials for such tests, and methods to maximize sensitivity, speed-to-result, specificity, stability and reproducibility of our tests. We possess proprietary know-how to develop tests for multiple
+conditions using colored particles. Our formulations enable long shelf lives of our rapid HIV and other tests, providing us with an important competitive advantage. 
+Lateral Flow Technology and Reagent Licenses 
+We seek licenses and/or redesigns of products that we believe to be in our best interests. Because of the costs and other negative consequences of
+time-consuming patent litigation, we often attempt to obtain a license on reasonable terms. 
+The peptides used in our rapid HIV tests were licensed to us by one or more third parties. We also have licensed the antigens used in other tests including
+our Syphilis, Tuberculosis, Leptospirosis, Leishmaniasis and Chagas tests, and we may enter into other license agreements. In prior years, we concluded license agreements related to intellectual property rights owned by the United States associated
+with HIV-1 and a sub-license agreement for HIV-2 with Bio-Rad Laboratories N.A., the exclusive licensee of the Pasteur Institute's HIV-2 intellectual property estate. 
+Available Information 
+We are required to file annual, quarterly and current reports, proxy statements and other
+information with the U.S. Securities and Exchange Commission. The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. 
+Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form
+8-K, proxy statements and amendments to those documents filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, are also available free of charge on our website at www.chembio.com as soon as reasonably
+practicable after such reports are electronically filed with or furnished to the SEC. 
+Investors should note that we currently announce material information to our investors and
+others using filings with the SEC, press releases, public conference calls, webcasts or our website (www.chembio.com), including news and announcements regarding our financial performance, key personnel, our brands and our business strategy.
+Information that we post on our corporate website could be deemed material to investors. We encourage investors to review the information we post on these channels. We may from time to time update the list of channels we will use to communicate
+information that could be deemed material and will post information about any such change on www.chembio.com. The information on our website is not, and shall not be deemed to be, a part hereof or incorporated into this or any of our other filings
+with the SEC. 
+Corporate Information 
+Our principal executive offices are located at 3661 Horseblock Road, Medford, New York
+11763. Our telephone number is (631) 924-1135. Our website address is www.chembio.com. The information contained in, or accessible through, our corporate website does not constitute part of this report. 
+8 
+Table of Contents
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@@ -0,0 +1,4 @@
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE. 
+The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC
+pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.
\ No newline at end of file
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@@ -0,0 +1,70 @@
+ITEM 9A. 
+Controls and Procedures 
+Evaluation of Disclosure Controls and Procedures 
+Our management, with the participation of our Chief Executive Officer
+and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures, as defined by Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of December 31, 2018. Based on the evaluation of our disclosure controls
+and procedures, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2018 at the reasonable assurance level. 
+Management’s Report on Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate
+internal control over financial reporting. Internal control over financial reporting is defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, our
+principal executive and principal financial officers and effected by the board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial
+statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that: 
+• 
+pertain to the maintenance of records that, in reasonable detail, accurately and
+fairly reflect the transactions and dispositions of the assets of the company; 
+• 
+provide reasonable assurance that transactions are recorded as necessary to
+permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made in accordance with authorizations of management and directors of
+the company; and 
+• 
+provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition,
+use or disposition of the company's assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial
+reporting may not prevent or detect misstatements. As a result, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of
+effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate. 
+Our management assessed the effectiveness of our internal control over
+financial reporting as of December 31, 2018. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework (2013). Based on
+its assessment, our management believes that, as of December 31, 2018, our internal control over financial reporting was effective based on those criteria. 
+Previously Identified Material Weaknesses in Internal Control Over Financial
+Reporting 
+None. 
+Changes in Internal Control over Financial Reporting 
+There were no changes in our internal control over financial reporting identified
+in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Securities Exchange Act of 1934 during the period covered by this Annual Report on
+Form 10-K that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting . 
+28 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+Shareholders and Board of Directors 
+Chembio Diagnostics, Inc. 
+Medford, New York 
+Opinion on Internal Control over Financial Reporting 
+We have audited Chembio Diagnostics, Inc.’s (the “Company’s”) internal control over financial reporting as of December 31, 2018, based on criteria
+established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). In our opinion, the Company maintained, in
+all material respects, effective internal control over financial reporting as of December 31, 2018, based on the COSO criteria. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of
+the Company and subsidiaries as of December 31, 2018 and 2017, the related consolidated statements of operations, comprehensive loss, changes in stockholders’ equity, and cash flows for each of the years then ended, and the related notes and our
+report dated March 18, 2019 expressed an unqualified opinion thereon. 
+Basis for Opinion 
+The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of
+internal control over financial reporting, included in the accompanying “Item 9A, Management’s Report on Internal Control over Financial Reporting”. Our responsibility is to express an opinion on the Company’s internal control over financial
+reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with U.S. federal securities laws and the applicable rules and regulations of the
+Securities and Exchange Commission and the PCAOB. 
+We conducted our audit of internal control over financial reporting in accordance with the standards of the PCAOB. Those standards require that we plan and
+perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting,
+assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary
+in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+Definition and Limitations of Internal Control over Financial Reporting 
+A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting
+and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the
+maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of
+financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide
+reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation
+of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+/s/ BDO USA, LLP 
+Melville, NY 
+March 18, 2019 
+29 
+Table of Contents 
+PART III
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+Material Related-Party Transactions with Directors 
+None 
+Family Relationships with Executive Officers or Other Directors 
+None 
+Shares Pledged by Directors 
+None 
+3 
+Contents 
+Approval of 2019 Omnibus Incentive Plan 
+We are asking stockholders to approve our 2019 Omnibus Incentive Plan to, among other things, reserve
+2,400,000 shares of common stock for awards under the plan. 
+Ratification of Appointment of Independent Auditor for 2019 
+We are asking stockholders to ratify the audit committee’s retention of BDO USA, LLP, an independent
+registered public accounting firm, as our independent auditor to examine and report on our consolidated financial statements for the fiscal year ending December 31, 2019. 
+Advisory Vote on 2018 Executive Compensation 
+In accordance with rules of the Securities and Exchange Commission or SEC, we are asking stockholders for an advisory vote —
+known as a “say-on-pay” vote — of the 2018 compensation of our “named executive officers” as set forth in the compensation tables, related narrative discussion and other disclosures under “Executive Compensation” in this Proxy
+Statement. The following table provides information concerning the compensation paid for 2018 and 2017 to our named executive officers during 2018: 
+Name and Principal Position 
+Year 
+Salary ($) 
+Bonus($)(1) 
+Equity 
+Awards ($)(2) 
+All Other 
+Compensation($)(3) 
+Total($) 
+John J. Sperzel III 
+2018 
+$416,847 
+$89,250 
+$950,000 
+— 
+$1,456,097 
+Chief Executive Officer and President 
+2017 
+415,137 
+63,750 
+62,998 
+— 
+541,885 
+Neil A. Goldman 
+2018 
+294,231 
+50,400 
+300,000 
+$2,769 
+647,400 
+Executive Vice President, Chief Financial Officer 
+2017 
+5,769 
+— 
+423,882 
+— 
+224,638 
+Javan Esfandiari 
+2018 
+357,807 
+72,450 
+375,000 
+7,391 
+812,648 
+Executive Vice President, 
+Chief Science and Technology Officer 
+2017 
+342,308 
+51,750 
+9,652 
+5,900 
+347,244 
+(1) 
+Based on reaching revenue targets, satisfying individual objectives, and, in 2017, reaching an operating income (loss)
+target and discretionary grants. 
+(2) 
+Determined in accordance with the Financial Accounting Standards Board’s Accounting Standards Codification Topic 718, Compensation—Stock Compensation . 
+(3) 
+Comprised of employer matching payments to 401(k) contributions and, in 2017, a car allowance. 
+Advisory Vote on Frequency of Future Advisory Votes on Executive Compensation 
+In accordance with rules of the SEC, we are asking stockholders for an advisory vote – known as
+a “say-on-frequency” vote – on how frequently they would like to cast an advisory “say-on-pay” vote on the compensation of our named executive officers. The board of directors recommends an annual advisory “say-on-pay” vote.
+SEC rules require that we submit a “say-on-frequency” vote to stockholders every six years 
+4 
+Contents 
+Questions and Answers about the Annual Meeting 
+Q: 
+When and where will the Annual Meeting be held? 
+A: 
+This year the Annual Meeting of Stockholders of Chembio Diagnostics, Inc., which we refer to as the Annual Meeting, will be held at 555 Wireless Boulevard,
+Hauppauge, New York beginning at 10 a.m., Eastern time, on Tuesday, June 18, 2019. 
+Q: 
+What materials have been prepared for stockholders in connection with the Annual Meeting? 
+A: 
+We are furnishing you and other stockholders of record with the following proxy materials: 
+• 
+our 2018 Annual Report to Stockholders, which we refer to as the 2018 Annual Report and which includes our Annual Report on Form 10‑K for the fiscal year
+ended December 31, 2018 (including our audited consolidated financial statements for 2017 and 2018); 
+• 
+this Proxy Statement for the 2019 Annual Meeting, which we refer to as this Proxy Statement and which also includes a letter from our Chief Executive
+Officer and President to stockholders and a Notice of 2019 Annual Meeting of Stockholders; and 
+• 
+a Notice of Internet Availability of Proxy Materials, which we refer to as the Notice of Internet Availability, which includes a control number for use in
+submitting proxies. 
+These materials were first mailed to stockholders, and made available on the Internet, on or about
+April 30, 2019. 
+If, in accordance with the instructions provided in the Notice of Internet Availability, you request a
+printed set of proxy materials, you will receive by mail, at no charge, printed copies of the 2018 Annual Report, this Proxy Statement, a proxy card for the Annual Meeting and a pre-addressed envelope to be used to return the completed proxy
+card. If, in accordance with the instructions provided in the Notice of Internet Availability, you request that a set of proxy materials be emailed to you, you will receive by email, at no charge, electronic copies of the 2018 Annual Report and
+this Proxy Statement. 
+Q: 
+Why was I mailed a Notice of Internet Availability rather than a printed set of proxy materials? 
+A: 
+In accordance with rules adopted by the SEC, we are furnishing the proxy materials to stockholders by providing access via the Internet, instead of mailing
+printed copies. This process expedites the delivery of proxy materials to our stockholders, lowers our costs and reduces the environmental impact of the Annual Meeting. The Notice of Internet Availability tells you how to access and
+review the proxy materials on the Internet and how to vote on the Internet. It also provides instructions you may follow to request paper or emailed copies of the proxy materials. 
+Q: 
+Are the proxy materials available via the Internet? 
+A: 
+You can access and review the proxy materials for the Annual Meeting at www.chembio.com/investors/proxy .
+In order to submit your proxies, however, you will need to refer to the Notice of Internet Availability sent to you with this Proxy Statement or a proxy card mailed to you upon your request to obtain your control number and other
+personal information needed to vote by proxy or in person. 
+5 
+Contents 
+Q: 
+What is a proxy? 
+A: 
+The term “proxy,” when used with respect to stockholder, refers to either a person or persons legally authorized to act on the stockholder’s behalf or a
+format that allows the stockholder to vote without being physically present at the Annual Meeting. 
+Because it is important that as many stockholders as possible be represented at
+the Annual Meeting, the board of directors is asking that you review this Proxy Statement carefully and then vote by following the instructions set forth on the Notice of Internet Availability or the proxy card. In voting prior to the Annual
+Meeting, you will deliver your proxy to the Proxy Committee, which means you will authorize the Proxy Committee to vote your shares at the Annual Meeting in the way you instruct. The Proxy Committee consists of John J. Sperzel III and Neil A.
+Goldman. All shares represented by valid proxies will be voted in accordance with the stockholder’s specific instructions. 
+Q: 
+What matters will the stockholders vote on at the Annual Meeting? 
+A: 
+Proposal 
+Election of the following five director nominees: 
+• 
+Katherine L.
+Davis 
+• 
+Gail S. Page 
+• 
+Mary Lake Polan 
+• 
+John G.
+Potthoff 
+• 
+John J. Sperzel III 
+Proposal 
+Approval of 2019 Omnibus Incentive Plan 
+Proposal 
+Ratification of appointment of our independent auditor for 2019 
+Proposal 
+Approval, as an advisory vote, of 2018 executive compensation as disclosed in this Proxy Statement 
+Proposal 
+Approval, as an advisory vote, of the frequency of future advisory votes on executive compensation 
+Q: 
+Who can vote at the Annual Meeting? 
+A: 
+Stockholders of record of common stock at 5 p.m., Eastern time, on April 26, 2019, the record date, will be entitled to vote at the Annual Meeting. As
+of the record date, there were outstanding a total of 17,166,459 shares of common stock, each of which will be entitled to one vote on each proposal. As a result, up to a total of 17,166,459 votes can be cast on each proposal. 
+Q: 
+What is a stockholder of record? 
+A: 
+A stockholder of record is a stockholder whose ownership of common stock is reflected directly on the books and records of our transfer agent,
+Broadridge Corporate Issuer Solutions, Inc. 
+Q: 
+What does it mean for a broker or other nominee to hold shares in “street name”? 
+A: 
+If you beneficially own shares held in an account with a broker, bank or similar organization, that organization is the stockholder of record and is
+considered to hold those shares in “street name.” An organization that holds your beneficially owned shares in street name will vote in accordance with the instructions you provide. If you do not provide the organization with
+specific voting instructions with respect to a proposal, the organization’s authority to vote your shares will, under the rules of the Nasdaq Global Market or Nasdaq, depend upon whether the proposal is considered a “routine”
+or a non-routine matter. 
+• 
+The organization generally may vote your beneficially owned shares on routine items for which you have not provided voting instructions to the
+organization. The only routine matter expected to be voted on at the Annual Meeting is the ratification of the appointment of our independent auditor for 2019 (Proposal 3). 
+6 
+Contents 
+• 
+The organization generally may not vote on non-routine matters, including Proposals 1, 2, 4 and 5. Instead, it will inform the inspector of election
+that it does not have the authority to vote on those matters. This is referred to as a “broker non-vote.” 
+For the purpose of determining a quorum, we will treat as present at the Annual Meeting any
+proxies that are voted on any of the four proposals to be acted upon by the stockholders, including abstentions or proxies containing broker non-votes. 
+Q: 
+How do I vote my shares if I do not attend the Annual Meeting? 
+A: 
+If you are a stockholder of record, you may vote prior to the Annual Meeting as follows: 
+• 
+Via the Internet: 
+You may vote via the Internet by going
+to www.aalvote.com/CEMI or scanning the QR code on the Notice of Internet Availability, in accordance
+with the voting instructions on the Notice of Internet Availability and the proxy card. Internet voting is available 24 hours a day until 11:59 p.m., Eastern time, on June 17, 2019. You will be given the opportunity to confirm
+that your instructions have been recorded properly. 
+• 
+By Telephone : 
+You may vote by calling +1 (866)
+804-9616 and following the instructions provided on the telephone line. Telephone voting is available 24 hours a day until 11:59 p.m., Eastern
+time, on June 17, 2019. Easy-to-follow voice prompts will allow you to vote your shares and confirm that your instructions have been recorded properly. 
+• 
+By Mail : 
+If you obtain a proxy card by mail, you may vote by returning the completed and signed
+proxy card in a postage-paid return envelope that will be provided with the proxy card. 
+If you
+hold shares in street name, you may vote by following the voting instructions provided by your bank, broker or other nominee. In general, you may vote prior to the Annual Meeting as follows: 
+• 
+Via the Internet: 
+You may vote via the Internet by going
+to www.ProxyVote.com o r scanning the QR code on the Notice of Internet Availability, in accordance with the voting instructions on the Notice of
+Internet Availability and the proxy card. Internet voting is available 24 hours a day until 11:59 p.m., Eastern time, on June 17, 2019. You will be given the opportunity to confirm that your instructions have been recorded
+properly. 
+For your information, voting via the Internet is the least expensive for us,
+followed by telephone voting, with voting by mail being the most expensive. 
+Q: 
+Can I vote at the Annual Meeting? 
+A: 
+If you are a stockholder of record, you may vote in person at the Annual Meeting, whether
+or not you previously voted. If your shares are held in street name, you must obtain a written proxy, executed in your favor, from the stockholder of record to be able to vote at the Annual Meeting. 
+Q: 
+May I change my vote or revoke my proxy? 
+A: 
+If you are a stockholder of record and previously delivered a proxy, you may subsequently change or revoke your proxy at any time before it is
+exercised by: 
+• 
+voting via the Internet or telephone at a later time; 
+• 
+submitting a completed and signed proxy card with a later date; or 
+• 
+voting at the Annual Meeting. 
+If you are a beneficial owner of shares held in street name, you should contact your bank, broker
+or other nominee for instructions as to whether, and how, you can change or revoke your proxy. 
+7 
+Contents 
+Q: 
+What happens if I do not give specific voting instructions? 
+A: 
+If you are a stockholder of record and you return a proxy card without giving specific voting instructions, the Proxy Committee will vote your shares
+in the manner recommended by the board on all five proposals presented in this Proxy Statement and as the Proxy Committee may determine in its discretion on any other matters properly presented for a vote at the Annual
+Meeting. 
+If you are a beneficial owner of shares held
+in street name and do not provide specific voting instructions to the broker, bank or other organization that is the stockholder of record of your shares, the organization generally may vote on routine, but not non-routine, matters. The
+only routine matter expected to be voted on at the Annual Meeting is the ratification of the appointment of our independent auditor for 2019 (Proposal 3). If the organization does not receive instructions from you on how to vote your
+shares on one or more of Proposals 1, 2, 4 and 5, your shares will be subject to a broker non-vote and no vote will be cast on those matters. See “ Q. What does it mean for a broker or other nominee to hold shares in ‘street name’? ” above.” 
+Q: 
+What if other matters are presented at the Ann ual M eeting? 
+A: 
+If a stockholder of record provides a proxy by voting in any manner described in this Proxy Statement, the Proxy Committee will have the discretion to
+vote on any matters, other than the five proposals presented in this Proxy Statement, that are properly presented for consideration at the Annual Meeting. We do not know of any other matters to be presented for consideration
+at the Annual Meeting. 
+8 
+Contents 
+Vote Required for Election or Approval 
+Our only voting securities are the outstanding shares of common stock. As of the record date, which is 5 p.m.,
+Eastern time, on April 26, 2019, there were outstanding 17,166,459 shares of common stock, each of which will be entitled to one vote on each proposal. Based on the number of votes for each share common stock, up to a total of 17,166,459 votes can be cast on each proposal. 
+Only stockholders of record as of the record date will be entitled to notice of, and to vote at, the Annual
+Meeting. A majority of the issued and outstanding shares of common stock entitled to vote, represented either in person or by proxy, constitutes a quorum at the Annual Meeting. For the purpose of determining a quorum, we will treat as
+present at the Annual Meeting any proxies that are voted on any matter to be acted upon by the stockholders, as well as abstentions or any proxies containing broker non-votes. 
+Election of Directors 
+The affirmative vote of a plurality of votes cast by shares entitled to vote and present in person or represented by proxy
+at the Annual Meeting at which a quorum is present is required to elect each director. Votes to “abstain” will not be counted for the purpose of determining whether a director is elected. Similarly, broker non‑votes will not
+have any effect on the outcome of the election of directors, since broker non-votes are not counted as “votes cast.” 
+Approval of 2019 Omnibus Incentive Plan 
+Our 2019 Omnibus Incentive Plan must be affirmatively approved by a majority of the votes entitled to be cast and present
+in person or represented by proxy at the Annual Meeting. Abstentions will count as votes against this proposal because shares with respect to which a stockholder abstains will be deemed present and entitled to vote. Broker
+non-votes will have no effect on the outcome of this proposal because broker non-votes are not counted as “votes cast.” 
+Ratification of Appointment of Independent Auditor for 2019 
+The ratification of BDO USA, LLP as our independent auditor for the year ending December 31, 2019 must be approved by
+affirmative votes constituting a majority of the votes entitled to be voted and present in person or represented by proxy at the Annual Meeting. Abstentions will count as votes against this proposal, because shares with respect
+to which the stockholder abstains will be deemed present and entitled to vote. Because this proposal is considered a routine matter, discretionary votes by brokers will be counted. 
+Approval of 2018 Executive Compensation on an Advisory Basis 
+The advisory “say-on-pay” vote to approve our 2018 executive compensation must be approved by affirmative votes
+constituting a majority of the votes entitled to be cast and present in person or represented by proxy at the Annual Meeting. Abstentions will count as votes against this proposal, because shares with respect to which the
+stockholder abstains will be deemed present and entitled to vote. Broker non-votes will have no effect on the outcome of this proposal, because broker non-votes are not counted as “votes cast.” 
+Approval of Frequency of Future Advisory “Say-on-Pay” Votes on an Advisory Basis 
+The advisory “say-on-frequency” vote on the frequency of future advisory “say-in-pay” votes on executive compensation must
+be approved by affirmative votes constituting a majority of the votes entitled to be voted and present in person or represented by proxy at the Annual Meeting. As a result, any votes not cast, whether by abstention, broker
+non-votes or otherwise, will not affect the outcome of this proposal, except to the extent that the failure to vote for a particular frequency period may result in another frequency period receiving a larger proportion of the
+votes cast. 
+9 
+Contents 
+Proposal 
+— Election of
+Directors 
+At the Annual Meeting, stockholders will elect the entire board of directors to serve for the ensuing year and
+until their successors are elected and qualified. The board has designated as nominees for election the five persons named below, each of whom currently serves as a director. 
+Shares of common stock that are voted as recommended by the board will be voted in favor of the election as
+directors of the nominees named below. If any nominee becomes unavailable for any reason or if a vacancy should occur before the election, which we do not anticipate, the shares represented by a duly completed proxy may be voted in favor
+of such other person as may be determined by the Proxy Committee. 
+Director Qualifications 
+The board of directors has determined that, as a whole, it
+must have the right mix of characteristics, skills and diversity to provide effective oversight of our company. I n selecting directors, the board seeks to
+achieve a mix of directors that enhances the diversity of background, skills and experience on the board, including with respect to age, gender, international background, ethnicity and specialized experience. Directors should have
+relevant expertise and experience and be able to offer advice and guidance to our chief executive officer based on that expertise and experience. Also, a majority of directors should be independent under applicable Nasdaq listing
+standards, board and committee guidelines, and applicable laws and regulations. Each director is also expected to have: 
+• 
+a high standard of personal and professional ethics, integrity and values; 
+• 
+the training, experience and ability to make and oversee policy in business, government and/or education sectors; 
+• 
+the willingness and ability to keep an open mind when considering matters affecting our interests and the interests of its constituents; 
+• 
+the willingness and ability to devote the required time and effort to effectively fulfill the duties and responsibilities related to board and
+committee membership; 
+• 
+the willingness and ability to serve on the board for multiple terms, if nominated and elected, to enable development of a deeper understanding of our
+business affairs; 
+• 
+the willingness not to engage in activities or interests that may create a conflict of interest with a director’s responsibilities and duties to us
+and our constituents; and 
+• 
+the willingness to act in the best interests of our company and our constituents, and objectively assess board, committee and management performance. 
+Identifying and
+Evaluating Nominees for Directors 
+When the board of directors or its nominating and corporate governance committee identifies a need to add a new director with
+specific qualifications or to fill a vacancy on the board, the chair of the nominating and corporate governance committee will initiate a search, seeking input from other directors and senior management, review any candidates that the
+nominating and corporate governance committee has previously identified, and, if necessary, hire a search firm. The nominating and corporate governance committee then will identify the initial list of candidates who satisfy the specific
+criteria and otherwise qualify for membership on the board. Based on a satisfactory outcome of those interviews, the nominating and corporate governance committee will make its recommendation on the candidate to the board. 
+10 
+Contents 
+Information
+Concerning Nominees for Election as Directors 
+The information appearing in the following table sets forth, for each nominee for election as a director: 
+• 
+the nominee’s professional experience for at least the past five years; 
+• 
+the year in which the nominee first became one of our directors; 
+• 
+each standing committee of the board of directors on which the nominee currently serves; 
+• 
+the nominee’s age as of the record date for the Annual Meeting; 
+• 
+the relevant skills the nominee possesses that qualify him or her for nomination to the board; and 
+• 
+directorships held by each nominee presently and at any time during the past five years at any public company or registered investment company. 
+Katherine L. Davis 
+Chembio Board Service: 
+• Tenure: 12 years 
+• Chair of the Board 
+• Committees: 
+○ Audit 
+○ Nominating and Corporate Governance 
+Age: 62 
+INDEPENDENT 
+Professional Experience 
+• 
+Chair of the Board since March 2014, and a director since 2007 
+• 
+Owner of Davis Design Group LLC, a provider of analytical and visual tools for public policy
+design, since 2007 
+• 
+Chief Executive Officer of Global Access Point, a start-up company with products for data
+transport, data processing, and data storage network and hub facilities, from 2005 to 2006 
+• 
+Lieutenant Governor of the State of Indiana from 2003 to 2005 
+• 
+Controller of the City of Indianapolis from 2000 to 2003 
+• 
+Financial Advisor to the Mayor of Indianapolis since January 2016 
+Gail S. Page 
+Chembio Board Service 
+• Tenure: 2 years 
+• Committees: 
+○ Audit 
+○ Compensation (Chair) 
+○ Nominating and Corporate Governance 
+Age: 63 
+INDEPENDENT 
+Professional Experience 
+• 
+Director since July 2017 
+• 
+Venture Partner at Turret Capital Management, L.P., an international healthcare-focused
+investment manage-ment fund, since September 2018 
+• 
+Managing Partner and founder of Vineyard Investment Advisors, LLC, a firm assisting with new
+product and services development, from 2014 to November 2018 
+• 
+Co-founder and director of Consortia Health Holdings LLC, a rehabilitation services provider
+focused on pelvic disorders, from 2013 to June 2018 
+• 
+President, Chief Executive Officer and director of Vermillion, Inc., a developer and
+manufacturer of novel diagnostic blood tests, from 2006 to 2012 
+• 
+Executive Vice President and Chief Operating Officer of Luminex Corporation, a developer of
+testing solutions for life science applications, from 2000 to 2003 
+• 
+Senior Vice President of Roche Biomedical Laboratories, Inc. / Laboratory Corporation of America, a healthcare
+diagnostic company, from 1988 to 2000 
+Education 
+• 
+Masters in Business Administration degree from Harvard Business School 
+• 
+Bachelor of Science degree in mechanical engineering from the Massachusetts Institute of
+Technology 
+Education 
+• 
+Bachelor of Science degree in Medical Technology from the University of Florida 
+• 
+Completed executive management program at the Kellogg School in Chicago 
+Relevant Skills 
+• 
+Leadership 
+• 
+Governance 
+• 
+Policy / Government 
+Relevant Skills 
+• 
+Industry 
+• 
+Leadership 
+• 
+Finance 
+11 
+Contents 
+Mary Lake Polan 
+Chembio Board Service: 
+• Tenure: 7 months 
+• Committees: 
+○ Compensation 
+○ Nominating and Corporate Governance (Chair) 
+Age: 75 
+INDEPENDENT 
+John G. Potthoff 
+Chembio Board Service 
+• Tenure: 10 months 
+• Committees: 
+○ Audit (Chair) 
+○ Compensation 
+Age: 51 
+INDEPENDENT 
+Professional Experience 
+• 
+Director since August 2018 
+• 
+Clinical Professor in the Department of Clinical Obstetrics, Gynecology and Reproductive
+Sciences at Yale University School of Medicine since 2014 
+• 
+Adjunct Professor in Obstetrics and Gynecology department at Columbia University School
+of Medicine from 2007 to 2014 
+• 
+Visiting Professor in Obstetrics and Gynecology department at Columbia University School
+of Medicine from 2005 to 2007 
+• 
+Chair of Department of Obstetrics and Gynecology at Stanford University School of
+Medicine from 1990 to 2005 
+• 
+Chair of Scientific Advisory Board in Women’s Health for the Procter and Gamble Company
+since 1997 
+• 
+Managing Director of Golden Seeds, an angel investing group investing in women-led
+companies, since 2007 
+• 
+Author of more than 130 books, articles and chapters in her areas of research 
+Professional Experience 
+• 
+Director since May 2018 
+• 
+Chief Executive Officer, co-founder and director of Elligo Health Research, a clinical research
+company, since March 2016 
+• 
+President and Chief Executive Officer of Theorem Clinical Research Inc., a global contract
+research organization providing comprehensive clinical services, from 2011 until its acquisition by Chiltern International in September 2015 
+• 
+Chief Operating Officer of INC Research Holdings, Inc. from its acquisition of Tanistry, Inc.
+in 2001 until its acquisition by private equity investors in 2010 
+• 
+Chief Executive Officer and founder of Tanistry, Inc., a contract research organization focused
+on the central nervous system, from 2000 to 2001 
+Education 
+• 
+Master of Public Health (Maternal and Child Health Program) degree from the University of
+California, Berkeley 
+• 
+Medical Doctor degree from Yale University School of Medicine 
+• 
+Doctor of Philosophy degree in Molecular Biophysics and Biochemistry from Yale University
+School of Medicine 
+• 
+Bachelor of Arts degree from Connecticut College 
+Education 
+• 
+Bachelor of Arts degree in Psychology from the University of Texas-Austin 
+• 
+Master of Arts degree in Psychology from the University of Texas-Austin 
+• 
+Doctor of Philosophy degree in Psychology from the University of Texas-Austin 
+Relevant Skills 
+• 
+Industry 
+• 
+Leadership 
+• 
+Governance 
+Relevant Skills 
+• 
+Finance 
+• 
+Industry 
+• 
+Leadership 
+Other Public Company Board Service 
+• 
+Motif Bio plc (AIM/NASDAQ:MTFB), a clinical-stage biopharmaceutical company specializing in
+developing novel antibiotics, since 2004 
+• 
+Quidel Corporation (NASDAQ:QDEL), a developer of point-of-care diagnostic solutions, since
+1993 
+12 
+Contents 
+John J. Sperzel III 
+Chembio Board Service: 
+• Tenure: 5 years 
+Age: 55 
+Professional Experience 
+• 
+Chief Executive Officer, President and Director since March 2014 
+• 
+Chief Executive Officer and President of International Technidyne Corporation, a
+developer of point-of-care cardiovascular diagnostic testing solutions, from 2011 to 2013 
+• 
+President of Axis-Shield Diagnostics Ltd. (subsequently acquired by Abbott
+Laboratories), a developer of point-of-care immunoassay testing solutions, from 2004 to 2011 
+• 
+Vice President of Worldwide Marketing and Business Development of Bayer Diagnostics
+(subsequently acquired by Siemens), a developer of point-of-care diagnostic testing solutions, from 2000 to 2004. 
+• 
+Vice President of Instrumentation Laboratory, a developer of laboratory hemostasis and
+critical care diagnostic testing solutions, from 1997 to 2000 
+• 
+Vice President and numerous commercial roles at Boehringer Mannheim Corp. (subsequently acquired by Roche), a developer
+of point-of care diagnostic testing solutions, from 1987 to 1997. 
+Education 
+• 
+Bachelor of Science degree in Business Administration/Management from Plymouth State
+College 
+Relevant Skills 
+• 
+Industry 
+• 
+Leadership 
+• 
+Innovation 
+The board of directors recommends a vote 
+FOR 
+each of the five nominees for election as directors. 
+13 
+Contents 
+Proposal 
+— Approval of 2019 Omnibus Incentive Plan 
+Background 
+On April 29, 2019, the board of directors approved, subject to stockholder approval, the Chembio Diagnostics, Inc. 2019
+Omnibus Incentive Plan, or the 2019 Plan. If the 2019 Plan is approved by our stockholders, it will authorize the issuance of up to 2,400,000 shares of common stock. The 2019 Plan will supersede and replace our 2014 Stock Incentive
+Plan, or the Prior Plan, and no new awards will be granted under the Prior Plan. Any awards outstanding under the Prior Plan on the date of stockholder approval of the 2019 Plan will remain subject to and be paid under the Prior Plan,
+and any shares subject to outstanding awards under the Prior Plan that subsequently expire, terminate, or are surrendered or forfeited for any reason without issuance of shares will automatically become available for issuance under the
+2019 Plan. 
+The board recommends that stockholders approve the 2019 Plan. The purposes of the 2019 Plan are to enhance our
+ability to attract and retain highly qualified officers, non-employee directors, key employees and consultants, and to motivate those service providers to serve Chembio and to expend maximum effort to improve our business results and
+earnings of the company, by providing to those service providers an opportunity to acquire or increase a direct proprietary interest in our operations and future success. The 2019 Plan also will allow us to promote greater ownership in
+our company by the service providers in order to align the service providers’ interests more closely with the interests of our stockholders. Stockholder approval of the 2019 Plan will also enable us to grant awards under the 2019 Plan
+that are designed to qualify for special tax treatment under Section 422 of the Internal Revenue Code of 1986, or the Code. 
+As described under “Executive Compensation—Outstanding Equity Awards at 2018 Fiscal Year-End,” on November 11,
+2018, the compensation committee, based in part on advice from its independent compensation consultant, approved the grant to John Sperzel, our Chief Executive Officer and President, of a restricted stock award for 375,000 shares of
+common stock that would be subject to time vesting in full on November 11, 2022. Because fewer than 375,000 shares of common stock were then available under the Prior Plan, this proposed grant to Mr. Sperzel was made subject to
+stockholders’ approval of an increase in the shares reserved under the Prior Plan or of a new equity incentive plan under which the restricted shares could be issued. If the 2019 Plan is approved at the Annual Meeting, the restricted
+shares will be granted to Mr. Sperzel from the shares that will become available under the 2019 Plan, without further action by the compensation committee or the board of directors. 
+Key Features 
+The following features of the 2019 Plan will protect the interests of our stockholders: 
+• 
+Limitation on terms of stock options and stock appreciation rights .
+The maximum term of each stock option and stock appreciation right, or SAR, is ten years. 
+• 
+No repricing or grant of discounted stock options . The 2019 Plan does
+not permit the repricing of options or SARs either by amending an existing award or by substituting a new award at a lower price. The 2019 Plan prohibits the granting of stock options or SARs with an exercise price less than
+the fair market value of the common stock on the date of grant. 
+• 
+No liberal share recycling. Shares used to pay the exercise price or
+withholding taxes related to an outstanding award and unissued shares resulting from the net settlement of outstanding options and SARs do not become available for issuance as future awards under the plan. 
+• 
+Minimum vesting requirements. The 2019 Plan includes minimum vesting
+requirements. Equity-based awards generally cannot vest earlier than one year after grant. Certain limited exceptions are permitted. 
+14 
+Contents 
+• 
+No single-trigger acceleration . Under the 2019 Plan we do not
+automatically accelerate vesting of awards in connection with a change in control on the company. 
+• 
+Dividends . We do not pay dividends or dividend equivalents on stock
+options, SARs or other unearned awards, whether time- or performance-vesting. 
+Summary of the 2019 Plan 
+The principal features of the 2019 Plan are summarized below. The following summary of the
+2019 Plan does not purport to be a complete description of all of the provisions of the 2019 Plan. It is qualified in its entirety by reference to the complete text of the 2019 Plan, which is attached to this Proxy Statement as Annex A. 
+Eligibility 
+Awards may be granted under the 2019 Plan to officers, employees and consultants of our company and our
+subsidiaries and to our non-employee directors. Incentive stock options may be granted only to employees of our company or one of our subsidiaries. As of April 26, 2019, approximately 250 individuals were eligible to receive awards
+under the 2019 Plan, including 5 executive officers and 4 non-employee directors. 
+Administration 
+The 2019 Plan will be administered by the compensation committee of the board of directors. The compensation
+committee, in its discretion, selects the individuals to whom awards may be granted, the time or times at which such awards are granted, and the terms of such awards. The compensation committee may delegate its authority to the extent
+permitted by applicable law. 
+Number of Authorized Shares 
+A total of 2,400,000 shares of common stock are authorized for issuance under the 2019 Plan, which represents 13.4% of the
+fully diluted common shares outstanding as of April 26, 2019. In addition, as of the date of stockholder approval of the 2019 Plan, any awards then outstanding under the Prior Plan will remain subject to and be paid under the Prior Plan
+and any shares then subject to outstanding awards under the Prior Plan that subsequently expire, terminate, or are surrendered or forfeited for any reason without issuance of shares will automatically become available for issuance under
+the 2019 Plan. Up to 2,400,000 shares may be granted under the 2019 Plan as incentive stock options under Section 422 of the Code. The shares of common stock issuable under the 2019 Plan will consist of authorized and unissued shares,
+treasury shares, and shares purchased on the open market or otherwise. 
+If any award is canceled, terminates, expires or lapses for any reason prior to the issuance of shares or if
+shares are issued under the 2019 Plan and thereafter are forfeited to us, the shares subject to such awards and the forfeited shares will again be available for grant under the 2019 Plan. In addition, the following items will not count
+against the aggregate number of shares of common stock available for grant under the 2019 Plan: 
+• 
+the payment in cash of dividends or dividend equivalents under any outstanding award; 
+• 
+any award that is settled in cash rather than by issuance of shares of common stock; and 
+• 
+any awards granted in assumption of or in substitution for awards previously granted by an acquired company. 
+Shares tendered or withheld to pay the option exercise price or tax withholding for any award (including restricted stock and
+restricted stock units) will continue to count against the aggregate number of shares of common stock available for grant under the 2019 Plan. In addition, the total number of shares covering stock-settled SARs or net-settled options
+will be counted against the pool of available shares, not just the net shares issued upon exercise. Any shares of common stock repurchased by us with cash proceeds from the exercise of options will not be added back to the pool of
+shares available for grant under the 2019 Plan. 
+15 
+Contents 
+Adjustments 
+If certain changes in the common stock occur by reason of any recapitalization, reclassification, stock split,
+reverse split, combination of shares, exchange of shares, stock dividend or other distribution payable in stock, or other increase or decrease in the common stock without our receipt of consideration, or if there occurs any spin-off,
+split-up, extraordinary cash dividend or other distribution of assets by us, we will equitably adjust the number and kind of securities for which stock options and other stock-based awards may be made under the 2019 Plan. In addition,
+if there occurs any spin-off, split-up, extraordinary cash dividend or other distribution of assets by us, we will equitably adjust the number and kind of securities subject to any outstanding awards and the exercise price of any
+outstanding stock options or SARs. 
+Types of Awards 
+The 2019 Plan permits the granting of any or all of the following types of awards: 
+• 
+Stock Options . Stock options entitle the holder to
+purchase a specified number of shares of common stock at a specified price (the exercise price), subject to the terms and conditions of the stock option grant. The compensation committee may grant either incentive stock
+options, which must comply with Section 422 of the Code, or nonqualified stock options. The compensation committee sets exercise prices and terms, except that stock options must be granted with an exercise price not less
+than 100% of the fair market value of the common stock on the date of grant (excluding stock options granted in connection with assuming or substituting stock options in acquisition transactions). Unless the compensation
+committee determines otherwise, fair market value means, as of a given date, the closing price of the common stock. (The fair market value of a share of common stock as of April 26, 2019, the record date, was $7.43.) At the
+time of grant, the compensation committee determines the terms and conditions of stock options, including the quantity, exercise price, vesting periods, term (which cannot exceed ten years) and other conditions on exercise. 
+• 
+Stock Appreciation Rights . The compensation committee may grant SARs
+as a right in tandem with the number of shares underlying stock options granted under the 2019 Plan or as a freestanding award. Upon exercise, SARs entitle the holder to receive payment per share in stock or cash, or in a
+combination of stock and cash, equal to the excess of the share’s fair market value on the date of exercise over the grant price of the SAR. The grant price of a tandem SAR is equal to the exercise price of the related stock
+option and the grant price for a freestanding SAR is determined by the compensation committee in accordance with the procedures described above for stock options. Exercise of a SAR issued in tandem with a stock option will
+reduce the number of shares underlying the related stock option to the extent of the SAR exercised. The term of a freestanding SAR cannot exceed ten years, and the term of a tandem SAR cannot exceed the term of the related
+stock option. 
+• 
+Restricted Stock, Restricted Stock Units and Other Stock-Based Awards .
+The compensation committee may grant awards of restricted stock, which are shares of common stock subject to specified restrictions, and restricted stock units, which represent the right to receive shares of the common stock
+in the future. These awards may be made subject to repurchase, forfeiture or vesting restrictions at the compensation committee’s discretion. The restrictions may be based on continuous service with the company or the
+attainment of specified performance goals, as determined by the compensation committee. Stock units may be paid in stock or cash or a combination of stock and cash, as determined by the compensation committee. The
+compensation committee may also grant other types of equity or equity-based awards subject to the terms of the 2019 Plan and any other terms and conditions determined by the compensation committee. 
+• 
+Performance Awards . The compensation committee may condition the
+grant, exercise, vesting, or settlement of any award on such performance conditions as it may specify. We refer to these awards as “performance awards.” The compensation committee may select such business criteria or other
+performance measures as it may deem appropriate in establishing any performance conditions. 
+16 
+Contents 
+Minimum Vesting Requirements 
+Equity-based awards granted under the 2019 Plan will have a one-year minimum vesting requirement. This
+requirement does not apply to (1) substitute awards resulting from acquisitions, (2) shares delivered in lieu of fully vested cash awards, or (3) awards to non-employee directors that vest on the earlier of the one year anniversary of
+the date of grant or the next annual meeting of stockholders (but not sooner than 50 weeks after the grant date). Also, the compensation committee may grant equity-based awards without regard to the minimum vesting requirement with
+respect to a maximum of five percent of the available share reserve authorized for issuance under the 2019 Plan. In addition, the minimum vesting requirement does not apply to the compensation committee’s discretion to provide for
+accelerated exercisability or vesting of any award, including in cases of retirement, death, disability or a change in control, in the terms of the award or otherwise. 
+No Repricing 
+Without stockholder approval, the compensation committee is not authorized to: 
+• 
+lower the exercise or grant price of a stock option or SAR after it is granted, except in connection with certain adjustments to our corporate or
+capital structure permitted by the 2019 Plan, such as stock splits; 
+• 
+take any other action that is treated as a repricing under generally accepted accounting principles or 
+• 
+cancel a stock option or SAR at a time when its exercise or grant price exceeds the fair market value of the underlying stock, in exchange for cash,
+another stock option or SAR, restricted stock, restricted stock units or other equity award, unless the cancellation and exchange occur in connection with a change in capitalization or other similar change. 
+Clawback 
+All cash and equity awards granted under the 2019 Plan will be subject to clawback, cancellation, recoupment,
+rescission, payback, reduction, or other similar action in accordance with the terms of any company clawback or similar policy or any applicable law related to such actions, as may be in effect from time to time. 
+Transferability 
+Awards are not transferable other than by will or the laws of descent and distribution, except that in certain
+instances transfers may be made to or for the benefit of designated family members of the participant for no value. 
+Change in Control 
+In the event of a change in control of the Company, the compensation committee may accelerate the time period relating to the exercise of any
+award. In addition, the compensation committee may take other action, including (a) providing for the purchase of any award for an amount of cash or other property that could have been received upon the exercise of such award had the
+award been currently exercisable, (b) adjusting the terms of the award in a manner determined by the compensation committee to reflect the change in control, or (c) causing an award to be assumed, or new rights substituted therefor, by
+another entity with appropriate adjustments to be made regarding the number and kind of shares and exercise prices of the award. “Change in control” is defined under the 2019 Plan and requires consummation of the applicable transaction. 
+17 
+Contents 
+Term, Termination and Amendment of the 2019 Plan 
+Unless earlier terminated by the board of directors, the 2019 Plan will terminate, and no further awards may
+be granted, ten years after the date on which it is approved by stockholders. The board may amend, suspend or terminate the 2019 Plan at any time, except that, if required by applicable law, regulation or stock exchange rule,
+stockholder approval will be required for any amendment. The amendment, suspension or termination of the 2019 Plan or the amendment of an outstanding award generally may not, without a participant’s consent, materially impair the
+participant’s rights under an outstanding award. 
+New Plan Benefits 
+A new plan benefits table for the 2019 Plan and the benefits or amounts that would have been received by or
+allocated to participants under the 2019 Plan for the year ended December 31, 2018 if the 2019 Plan were then in effect, as described in the federal proxy rules, are not provided, because, except as noted below, all awards made under
+the 2019 Plan will be made at the compensation committee’s discretion, subject to the terms of the 2019 Plan. Therefore, the benefits and amounts that will be received or allocated under the 2019 Plan generally are not determinable at
+this time. The equity grant program for our non-employee directors is described under “Director Compensation” in this Proxy Statement. 
+On November 11, 2018, the compensation committee, based in part on advice from its independent compensation
+consultant, approved the grant to John Sperzel, our Chief Executive Officer and President, of a restricted stock award for 375,000 shares of common stock that would be subject to time vesting in full on November 11, 2022. Because fewer
+than 375,000 shares of common stock were then available under the Prior Plan at that time, this proposed grant is to be made under the 2019 Plan, without further action by the compensation committee or the board of director, if the 2019
+Plan is approved at the Annual Meeting. See “Proposal 2—Approval of 2019 Omnibus Incentive Plan—Background”. 
+Federal Income Tax Information 
+The following is a brief summary of the U.S. federal income tax consequences of the 2019
+Plan generally applicable to us and to participants in the 2019 Plan who are subject to U.S. federal taxes. The summary is based on the Code, applicable Treasury Regulations, and administrative and judicial interpretations thereof, each
+as in effect on the date of this Proxy Statement, and is, therefore, subject to future changes in the law, possibly with retroactive effect. The summary is general in nature and does not purport to be legal or tax advice. Furthermore,
+the summary does not address issues relating to any U.S. gift or estate tax consequences or the consequences of any state, local or foreign tax laws. 
+Nonqualified Stock Options . A
+participant generally will not recognize taxable income upon the grant or vesting of a nonqualified stock option with an exercise price at least equal to the fair market value of the common stock on the date of grant and no additional
+deferral feature. Upon the exercise of a nonqualified stock option, a participant generally will recognize compensation taxable as ordinary income in an amount equal to the difference between the fair market value of the shares
+underlying the stock option on the date of exercise and the exercise price of the stock option. When a participant sells the shares, the participant will have short-term or long-term capital gain or loss, as the case may be, equal to
+the difference between the amount the participant received from the sale and the tax basis of the shares sold. The tax basis of the shares generally will be equal to the greater of the fair market value of the shares on the exercise
+date or the exercise price of the stock option. 
+Incentive Stock Options. A participant generally will
+not recognize taxable income upon the grant of an incentive stock option. If a participant exercises an incentive stock option during employment or within three months after employment ends (one year in the case of permanent and total
+disability), the participant will not recognize taxable income at the time of exercise for regular U.S. federal income tax purposes (although the participant generally will have taxable income for alternative minimum tax purposes at
+that time as if the stock option were a nonqualified stock option). If a participant sells or otherwise disposes of the shares acquired upon exercise of an incentive stock option after the later of (a) one year from the date the
+participant exercised the option and (b) two years from the grant date of the stock option, the participant generally will recognize long-term capital gain or loss equal to the difference between the amount the participant received in
+the disposition and the exercise price of the stock option. If a participant sells or otherwise disposes of shares acquired upon exercise of an incentive stock option before these holding period requirements are satisfied, the
+disposition will constitute a “disqualifying disposition,” and the participant generally will recognize taxable ordinary income in the year of disposition equal to the excess of the fair market value of the shares on the date of
+exercise over the exercise price of the stock option (or, if less, the excess of the amount realized on the disposition of the shares over the exercise price of the stock option). The balance of the participant’s gain on a disqualifying
+disposition, if any, will be taxed as short-term or long-term capital gain, as the case may be. 
+18 
+Contents 
+With respect to both nonqualified stock options and incentive stock options, special rules apply if a
+participant uses shares of common stock already held by the participant to pay the exercise price or if the shares received upon exercise of the stock option are subject to a substantial risk of forfeiture by the participant. 
+Stock Appreciation Rights. A
+participant generally will not recognize taxable income upon the grant or vesting of a SAR with a grant price at least equal to the fair market value of common stock on the date of grant and no additional deferral feature. Upon the
+exercise of a SAR, a participant generally will recognize compensation taxable as ordinary income in an amount equal to the difference between the fair market value of the shares underlying the SAR on the date of exercise and the grant
+price of the SAR. 
+Restricted Stock Awards, Restricted
+Stock Units, and Performance Awards. A participant generally will not have taxable income upon the grant of restricted stock, restricted stock units or performance awards. Instead, the participant will recognize ordinary
+income at the time of vesting or payout equal to the fair market value (on the vesting or payout date) of the shares or cash received minus any amount paid. For restricted stock only, a participant may instead elect to be taxed at the
+time of grant. 
+Other Stock or Cash-Based Awards. The
+U.S. federal income tax consequences of other stock or cash-based awards will depend upon the specific terms of each award. 
+Tax Consequences to Us. In the
+foregoing cases, we generally will be entitled to a deduction at the same time, and in the same amount, as a participant recognizes ordinary income, subject to limitations imposed under the Code. 
+Section 409A. We intend that
+awards granted under the 2019 Plan comply with, or otherwise be exempt from, Section 409A of the Code, but make no representation or warranty to that effect. 
+Tax Withholding. We are authorized to deduct or
+withhold from any award granted or payment due under the 2019 Plan, or require a participant to remit to us, the amount of any withholding taxes due in respect of the award or payment and to take such other action as may be necessary to
+satisfy all obligations for the payment of applicable withholding taxes. We are not required to issue any shares of common stock or otherwise settle an award under the 2019 Plan until all tax withholding obligations are satisfied. 
+The board of directors recommends a vote 
+FOR 
+the approval of the 2019 Plan. 
+19 
+Contents 
+Proposal 
+— Ratification of Appointment of Independent Auditor for 2019 
+The audit committee annually evaluates the performance of our independent auditor, BDO USA, LLP, or BDO,
+including the senior audit engagement team, and determines whether to reengage the current independent auditor or consider other audit firms. Factors considered by the audit committee in deciding whether to retain include: 
+• 
+BDO’s global capabilities; 
+• 
+BDO’s technical expertise and knowledge of the Company’s global operations and industry; 
+• 
+BDO’s independence; 
+• 
+BDO’s objectivity and professional skepticism; 
+• 
+the appropriateness of BDO’s fees, BDO’s tenure as independent auditor, including the benefits of a longer tenure, and the controls and processes in
+place that help ensure BDO’s independence. 
+BDO has served as our independent auditor since 2011. The benefits of a longer tenure are: 
+• 
+Enhanced audit quality – BDO’s institutional knowledge of the Company’s global business, accounting policies and practices, and internal control
+over financial reporting enhance audit quality. 
+• 
+Competitive fees – Because of BDO’s familiarity with us, audit and other fees are competitive with peer companies. 
+• 
+Avoid costs associated with new auditor – Bringing on a new independent auditor would be costly and require a significant time commitment, which
+could lead to management distractions. 
+Based on the above evaluation, the audit committee has approved the retention of BDO as our independent
+auditor to examine and report on our consolidated financial statements and the effectiveness of our internal control over financial reporting for the fiscal year ending December 31, 2019. Even if the proposal is approved, the audit
+committee may, in its discretion, appoint a different independent registered public accounting firm to serve as independent auditor at any time during the year. 
+Representatives of BDO will be present at the Annual Meeting. The BDO representatives will have the
+opportunity to make a statement if they desire to do so, and we expect that they will be available to respond to appropriate questions. 
+The board of directors recommends a vote 
+FOR 
+the ratification of the appointment of BDO as our independent auditor for 2019. 
+20 
+Contents 
+Proposal 
+— Advisory Vote on 2018 Executive Compensation 
+Our stockholders have the opportunity at the Annual Meeting to vote to approve, on a non-binding, advisory
+basis, the compensation of our named executive officers in 2018 as disclosed in this Proxy Statement. 
+Our compensation program is intended to provide appropriate and balanced incentives toward achieving our
+annual and long-term strategic objectives and to create an alignment of interests between our executives and stockholders. This approach is intended to motivate our existing executives and to attract new executives with the skills and
+attributes that we need. Please refer to “Executive Compensation” for an overview of the compensation of our named executive officers. 
+We are asking for stockholder approval of the compensation of our named executive officers as disclosed in
+this Proxy Statement in accordance with SEC rules, which disclosures include the disclosures in the compensation tables and narrative disclosures included under “Executive Compensation.” This vote is not intended to address any specific
+item of compensation, but rather the overall compensation of our named executive officers and the policies and practices described in this Proxy Statement. 
+Accordingly, stockholders are being asked to vote on the following resolution: 
+Resolved: 
+That the stockholders approve the compensation paid to the “named executive officers” of Chembio Diagnostics, Inc. with respect to the fiscal year
+ended December 31, 2018, as disclosed, pursuant to Item 402 of Regulation S-K promulgated by the Securities and Exchange Commission, in the Proxy Statement for the 2019 Annual Meeting of Stockholders, including the
+compensation tables and narrative discussion set forth under “Executive Compensation” therein. 
+This vote is advisory and not binding on the board of directors or the compensation committee. The board and
+the compensation committee value the opinions of our stockholders, however, and to the extent there is any significant vote against the named executive officer compensation disclosed in this Proxy Statement, we will consider our
+stockholders concerns and the compensation committee will evaluate whether any actions are necessary or appropriate to address those concerns. 
+The board of directors recommends a vote 
+FOR 
+the approval of the compensation paid to our named executive
+officers with respect to 2018, 
+as disclosed in the compensation tables and narrative
+discussion set forth under 
+“Executive Compensation” and elsewhere in this Proxy
+Statement. 
+21 
+Contents 
+Proposal 
+— Advisory Vote on Frequency of Future Advisory Votes on Executive Compensation 
+In accordance with Section 14A of the Securities Exchange Act, we are requesting our stockholders vote, on a
+non-binding, advisory basis, on how frequently they would like to cast an advisory vote on the compensation of our named executive officers. By voting on this proposal, stockholders may indicate whether they would prefer an advisory
+vote on named executive officer compensation annually, every two years or every three years. 
+We currently present an advisory vote on executive compensation each year, and the board of directors believes
+that continuing to conduct an advisory “say on pay” vote annually is the most appropriate for us. This frequency will continue to enable stockholders to annually express their views on our executive compensation program in a timely
+manner, based on the most recent information presented in our proxy statements. An annual advisory vote on executive compensation helps ensure ongoing stockholder communication with the compensation committee and the board of directors
+on executive compensation and corporate governance matters. Further, the annual advisory vote on executive compensation is consistent with our practice of electing all directors annually and providing stockholders the opportunity to
+ratify the audit committee’s selection of independent auditors annually. 
+Accordingly, the stockholders are being asked to vote on the following resolution: 
+Resolved: 
+That the stockholders wish Chembio Diagnostics, Inc. to present an advisory vote on the compensation of named executive officers pursuant to Section
+14A of the Securities Exchange Act on an annual basis. 
+This vote is advisory and not binding on the board or the compensation committee. The board and the compensation
+committee value the opinions of our stockholders, however, and will carefully consider the outcome of the advisory vote when making future decisions regarding the frequency of advisory votes on executive compensation. 
+The board of directors recommends a vote for the approval of an 
+ANNUAL 
+advisory vote on the compensation of named executive officers 
+pursuant to Section 14A of the Securities Exchange Act. 
+22 
+Contents
\ No newline at end of file
diff --git a/raw/filings/0001092662/2019/0001140361-20-005780/filing.txt b/raw/filings/0001092662/2019/0001140361-20-005780/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..28ec1f2527a0c3f2ebcdbeea6591b2ae1e3e948b
--- /dev/null
+++ b/raw/filings/0001092662/2019/0001140361-20-005780/filing.txt
@@ -0,0 +1,3871 @@
+10-K
+1
+form10k.htm
+10-K
+UNITED STATES 
+Securities and Exchange Commission 
+Washington, D.C. 20549 
+FORM 10-K 
+☒ 
+ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the fiscal year ended December 31, 2019 
+or 
+☐ 
+TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the transition period from _______ to ______ . 
+Commission File No. 0-30379 
+CHEMBIO DIAGNOSTICS, INC. 
+(Exact name of registrant as specified in its charter) 
+Nevada 
+88-0425691 
+(State or other jurisdiction of incorporation or organization) 
+(I.R.S. Employer Identification No.) 
+555 Wireless Boulevard, Hauppauge, NY 
+11788 
+(Address of principal executive offices) 
+(Zip Code) 
+Registrant’s telephone number, including area code (631) 924-1135 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of each class 
+Trading Symbol 
+Name of each exchange on which registered 
+Common Stock, $0.01 par value 
+CEMI 
+The NASDAQ Stock Market LLC 
+Securities registered pursuant to Section 12(g) of the Act: 
+None 
+(Title of Class) 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒ 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒ 
+Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that
+the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ 
+Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12
+months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐ 
+Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in
+definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒ 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large
+accelerated filer”, “accelerated filer”, “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. 
+Large accelerated filer ☐ 
+Accelerated filer ☒ 
+Non-accelerated filer ☐ 
+Smaller reporting company ☒ 
+Emerging growth company ☐ 
+If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to
+Section 13(a) of the Exchange Act ☐ 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ 
+As of the last business day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of voting and non-voting common equity held by non-affiliates was $106,974,102. 
+As of March 4, 2020, the registrant had 17,733,617 shares of common stock outstanding. 
+Documents Incorporated By Reference 
+Portions of the registrant’s proxy statement for its 2020 annual meeting of stockholders are incorporated by reference in Part III of this report. 
+TABLE OF CONTENTS 
+Page 
+PART I 
+ITEM 1. 
+BUSINESS 
+5 
+ITEM 1A. 
+RISK FACTORS 
+16 
+ITEM 2. 
+PROPERTIES 
+40 
+ITEM 3. 
+LEGAL PROCEEDINGS 
+40 
+PART II 
+ITEM 5. 
+MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+41 
+ITEM 7. 
+MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+42 
+ITEM 8. 
+FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+51 
+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+51 
+PART III 
+ITEM 10. 
+DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
+53 
+ITEM 11. 
+EXECUTIVE COMPENSATION 
+53 
+ITEM 12. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+53 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+53 
+ITEM 14. 
+PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+53 
+PART IV 
+ITEM 15. 
+EXHIBITS, FINANCIAL STATEMENT SCHEDULES 
+54 
+SIGNATURES 
+55 
+Unless the context requires otherwise, the words “our,” “our company,” “us,” “we” and similar terms refer to Chembio Diagnostics, Inc. and its consolidated subsidiaries. 
+DPP, SAMPLETAINER, STAT-PAK, STAT-VIEW and SURE CHECK are our registered trademarks. For convenience, these trademarks appear in this prospectus supplement without ® symbols, but that practice does not mean
+that we will not assert, to the fullest extent under applicable law, our rights to the trademarks. This report also includes trademarks and service marks owned by other organizations. 
+FORWARD-LOOKING STATEMENTS AND STATISTICAL ESTIMATES 
+This report contains statements reflecting our views about our future performance that constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of
+1995. These forward-looking statements are generally identified through the inclusion of words such as “anticipate,” “believe,” “contemplate,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “objective,” “outlook,” “plan,” “potential,”
+“project,” “seek,” “should,” “strategy,” “target,” “will,” “would” or variations of such words or similar expressions. All statements addressing our future operating performance, and statements addressing events and developments that we expect or
+anticipate will occur in the future, are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are based upon currently available information, operating plans, and
+projections about future events and trends. 
+This report contains estimates, projections and other data concerning our industry, our business, and the markets for our products. Where expressly stated, we obtained this industry, business,
+market and other data from reports, research surveys, studies and similar data prepared by World Health Organization, or WHO. We also include data that we have compiled, obtained, identified or otherwise derived from reports, research surveys,
+studies and similar data prepared by market research firms and other third parties, industry, medical and general publications, government data and similar sources. Other than WHO, we do not expressly refer to the sources from which this data is
+derived. 
+Forward-looking statements and statistical estimates inherently involve risks and uncertainties that could cause actual results to differ materially from those predicted or expressed in this report.
+These risks and uncertainties include those described below in “Item 1A. Risk Factors.” Investors are cautioned not to place undue reliance on any forward-looking statements or statistical estimates, which speak only as of the date they are made. We
+undertake no obligation to update any forward-looking statement or statistical estimate, whether as a result of new information, future events or otherwise. 
+4 
+Table of Contents 
+PART I 
+ITEM 1. 
+BUSINESS 
+Overview 
+We are a leading provider of point-of-care diagnostic products for the detection and diagnosis of infectious diseases. We have been expanding our product portfolio based upon our proprietary Dual Path Platform, which
+we refer to as DPP, which uses a small drop of blood from the fingertip to provide high-quality, cost-effective diagnostic results in approximately 15 minutes. We seek to build additional revenue streams by entering into technology collaborations
+with leading global healthcare companies to leverage the DPP technology platform. 
+Compared with traditional lateral flow technology, the DPP technology platform provides enhanced sensitivity and specificity, advanced multiplexing capabilities, and, when used with the DPP Micro Reader, quantitative
+results. Our DPP test for human immunodeficiency virus, or HIV, provides sensitivity of 99.8% and specificity of 100%, and has been approved by the U.S. Food and Drug Administration, or FDA, and cleared as a waived test under the Clinical Laboratory
+Improvement Amendments of 1988, or CLIA. 
+On November 6, 2018, we completed our acquisition of opTricon GmbH, a Berlin-based developer and manufacturer of handheld analyzers for rapid diagnostic tests, which we believe will enable us to promote DPP tests and
+DPP Micro Readers more actively across global markets. On November 25, 2019, we completed our acquisition of Orangelife Comercio e Industria Ltda., a Brazilian manufacturer of lateral flow tests for infectious diseases to diversify our market channel
+penetration in Brazil and support Bio-Manguinos, a major customer. 
+We are pursuing three corporate priorities, the key building blocks to drive growth and operating efficiency: (1) expand our commercialization; (2) advance our research and development pipeline; and (3) prepare for
+future growth. 
+Industry 
+The DPP technology platform addresses the lateral flow test market, which includes infectious diseases, cardiac markers, cholesterol and lipids, pregnancy and fertility, and drugs of abuse. Based on our review of
+third-party reports and other information, we estimate that the market for lateral flow tests will increase from $5.5 billion in 2017 to $8.2 billion in 2022, representing a compound annual growth rate of 8.2%. 
+Infectious disease tests constitute the largest and fastest growing, segment of the lateral flow test market. We currently are targeting lateral flow test solutions for infectious diseases: sexually transmitted disease
+and mosquito-borne disease. The market for lateral flow infectious disease tests is being driven by the high prevalence of infectious diseases globally, an increase in the geriatric population, growing demand for rapid test results, and advancements
+in multiplexing. Based on our review of third-party reports and other information, we estimate that the market for lateral flow infectious disease tests will increase from $1.4 billion in 2017 to $2.3 billion in 2022, representing a compound annual
+growth rate of 10.7%. 
+5 
+Table of Contents 
+Products 
+Our point-of-care infectious disease portfolio is comprised of multiple commercial products, each serving unique customer requirements. The key advantages of our products, which are performed with a tiny drop of blood
+from the fingertip and provide results in approximately 15 minutes, include: 
+• 
+enhanced sensitivity and specificity; 
+• 
+advanced multiplexing; and 
+• 
+quantitative results, when used with DPP Micro Reader. 
+We have obtained FDA approvals and, directly or through our partners, international regulatory approvals for infectious disease tests as follows: 
+Product (Assay) 
+U.S. 
+International 
+DPP HIV 1/2 
+✓ 
+✓ 
+DPP HIV-Syphilis 
+✓ 
+DPP Syphilis Screen & Confirm 
+✓ 
+DPP Zika 
+✓ 
+✓ 
+DPP Leishmaniasis 
+✓ 
+STAT-PAK HIV 1/2 
+✓ 
+✓ 
+STAT-PAK Chagas 
+✓ 
+SURE CHECK HIV 1/2 
+✓ 
+✓ 
+SURE CHECK HIV 1/2 Self Test 
+✓ 
+Organic growth in our core infectious disease business is being driven by: 
+• 
+growth in the overall market for lateral flow infectious disease tests, which we estimate will increase at a compound annual growth rate of 10.7% through 2022 (see “–Industry”
+above); 
+• 
+our increased market penetration in existing markets and channels, including in the United States, Latin America, Africa and Europe; 
+• 
+our registration of existing and new products in unchartered countries and regions, such as selected countries in Latin America and Southeast Asia; 
+• 
+our entry into new market segments, such as international HIV Self-Testing; and 
+• 
+advances in our product pipeline in infectious disease with key products including a multiplex test for HIV and syphilis in the U.S. market and tests for dengue, zika and
+chikungunya. 
+6 
+Table of Contents 
+We market and sell both stand-alone and multiplex tests for sexually transmitted infectious diseases, such as HIV and syphilis. HIV and syphilis continue to be major global public health issues. According to WHO
+estimates: 
+• 
+HIV has claimed more than 35 million lives, including 770,000 in 2018. Approximately 37.9 million people were living with HIV at the end of 2018, and 1.7 million were newly
+infected during 2018. 
+• 
+There were 18.0 million prevalent cases of syphilis as of 2012, and 5.6 million new infections were estimated to occur annually. 
+• 
+Elimination of mother-to-child transmission, or MTCT, of both HIV and syphilis is a global health priority. In 2013, 1.9 million pregnant women were infected with syphilis
+worldwide. Congenital syphilis contributes significantly to infant mortality, accounting for 305,000 annual perinatal deaths worldwide in 2013. Globally, more than 1.4 million pregnant women were infected with HIV as of 2015, and MTCT of
+HIV is estimated to have resulted in over 150,000 infant cases in 2015. 
+We are seeking to address the global concerns related to HIV and syphilis co-infection through the development of a novel, multiplex test for both HIV and syphilis. We have developed a DPP HIV-Syphilis multiplex test
+and received regulatory approvals covering a number of international markets, including Brazil, Europe, Malaysia and Mexico. In the United States we completed a DPP HIV-Syphilis clinical trial but in February 2020 received a “not approvable” letter
+from the FDA with respect to our Premarket Approval, or PMA, application on our DPP HIV-Syphilis multiplex test for commercial use in the United States. The FDA has confirmed that, of the items that had been open for review in the PMA application,
+the syphilis arm of the study was acceptable, as were the results as they relate to the inclusion of pregnant women. The only remaining item requested of us was to repeat the reproducibility study, as one of the sites in the trial reported greater
+variability compared to the other sites. We have initiated the reproducibility study required by the FDA and, in parallel, accelerated the studies for a CLIA waiver, which can be submitted upon FDA approval of the PMA application. We believe we
+continue to be well-positioned to be the first company to introduce a multiplex rapid test for HIV and syphilis in the United States.
+We also market and sell tests for selected fever and tropical diseases such as Chagas, ebola, leishmaniasis and Zika. The market for lateral flow mosquito-borne diseases includes established markets for disease such as
+dengue and malaria, which WHO estimates together account for more than 600 million annual infections worldwide. There are also a number of emerging markets for lateral flow tests for infectious diseases such as burkholderia, chikungunya, lassa,
+leptospirosis, Marburg, rickettsia and Zika. We are developing tests, using the DPP platform, to detect all of the aforementioned fever and tropical diseases, as stand-alone or multiplex tests. 
+Since 2015 we have received over $12.2 million of funding from some of the world’s leading health organizations, which has helped us accelerate the expansion of our pipeline of infectious disease tests. Our
+collaborators have included Bill & Melinda Gates Foundation, The Paul G. Allen Family Foundation, The Oswaldo Cruz Foundation or FIOCRUZ, and the Foundation for Innovative New Diagnostics, or FIND, as well as U.S. government agencies such as
+Centers for Disease Control and Prevention, or CDC, the Biomedical Advanced Research and Development Authority of the U.S. Department of Health and Human Services, or BARDA, and the U.S. Department of Agriculture, or USDA. 
+Several tests in our infectious disease pipeline are approaching commercialization, and several have received initial regulatory approvals: 
+Product 
+Collaborator 
+Phase I 
+Feasibility 
+Phase II 
+Development 
+Phase III 
+Verification &Validation 
+Phase IV 
+Clinical & 
+Regulatory 
+Phase V 
+Commercial 
+Launch 
+DPP HIV-Syphilis (US) 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+PMA/510K pending 
+DPP Dengue IgM/IgG (International) 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 1 
+DPP Dengue NS1 Antigen (International) 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA pending 
+DPP Zika IgM/IgG (International) 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP Chikungunya IgM/IgG (International) 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP ZCD IgM/IgG(International) 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP Zika IgM (US) 
+BARDA 
+✓ 
+✓ 
+✓ 
+✓ 
+FDA-EUA 2 FDA 
+DPP Ebola 
+CDC 
+✓ 
+✓ 
+✓ 
+✓ 
+FDA-EUA 
+DPP Fever Assay Asia 
+FIND 
+✓ 
+✓ 
+✓ 
+✓ 
+Field studies ongoing 
+DPP Fever Assay Africa 
+Paul Allen Foundation 
+✓ 
+✓ 
+✓ 
+1 
+Agência Nacional de Vigilância Sanitária (Brazil) 
+2 
+Emergency Use Authorization 
+7 
+Table of Contents 
+Collaborations 
+We are building additional revenue streams by leveraging our patented DPP technology and scientific expertise through collaborations. Leading global healthcare organizations have chosen to collaborate with us based on
+our deep scientific expertise with our proven DPP technology platform and capabilities, our successful record of developing DPP tests with a diverse set of collaborators including global commercial companies, governments and non-governmental
+organizations, and our extensive experience in obtaining regulatory approvals in the United States (FDA), Brazil (ANVISA), the European Union (CE mark) and Mexico (Comisión Federal para la Protección contra Riesgos Sanitarios, or COFEPRIS) as well as
+from WHO (Prequalification, or PQ). 
+Product 
+Collaborator 
+Phase I 
+Feasibility 
+Phase II 
+Development 
+Phase III 
+Verification 
+&Validation 
+Phase IV 
+Clinical/ 
+Regulatory 
+Phase V 
+Commercial 
+Launch 
+DPP Rare Disease (undisclosed biomarker) 
+Takeda 
+✓ 
+✓ 
+Infectious Disease Portfolio 
+Lumira DX 
+✓ 
+✓ 
+DPP Biomarker Development Project (undisclosed biomarker) 
+AstraZeneca 
+✓ 
+✓ 
+✓ 
+CE Mark 3 
+DPP TBI 
+Perseus 
+✓ 
+✓ 
+3 
+For use in pharmaceutical research 
+By leveraging our DPP technology platform, we are creating opportunities to expand into new markets such as cancer diagnostics, concussion and traumatic brain injury, and veterinary and we are broadening the
+application of our technology from point-of-care diagnostics to include companion diagnostics. Research and development costs related to the collaborations are fully funded by our collaborators. 
+Sales Channels 
+Our products are sold globally, both directly and through distributors, to hospitals and clinics, physician offices, clinical laboratories, public health organizations, government agencies and consumers. Historically
+we marketed and sold our products only into a handful of countries and regions. In recent years we have hired sales executives to begin building our own channels in key markets such as the United States, Europe, Latin America, Africa and Southeast
+Asia. With sales growth as an underlying objective, we are focused on increasing sales in existing geographies, expanding sales into new geographies, and broadening sales coverage in key markets. 
+8 
+Table of Contents 
+Automation of U.S. Manufacturing 
+We are automating our U.S. manufacturing processes and expanding our manufacturing capacity. During 2018, we took delivery of our first automated manufacturing line. This automated manufacturing line provided DPP test
+production for Brazil and will allow assembly of various configurations of DPP tests. The automated line has an annual capacity of between five and ten million tests, depending on the test configuration, and uses vision-guided, robotic operation to
+improve inspection and quality control. During 2019, we took delivery of our second and third manufacturing lines that together, following commissioning and regulatory approvals, will support our other product platforms. As we transition from manual
+to automated assembly, we believe the reduced variable costs will improve product gross margins. 
+DPP Technology & Development 
+Our commercially available products employ either our patented DPP technology or traditional lateral flow technology. We believe products developed using our DPP technology can provide superior diagnostic performance
+compared with products that utilize traditional lateral flow technology. 
+We are executing our strategy to leverage DPP intellectual property, as well as our scientific and operational expertise, to create new collaborations where we will serve as an exclusive development and manufacturing
+partner. Examples of such collaborations include the following: 
+• 
+In January 2015, we entered into an agreement with the Concussion Science Group (CSG) Division of Perseus Science Group LLC to develop a point-of-care diagnostic test for
+traumatic brain injury, including sports-related concussions, utilizing both our DPP and optical analyzer technologies. 
+• 
+In October 2017, we signed a biomarker development project agreement with AstraZeneca, utilizing both our DPP and optical analyzer
+technologies. 
+• 
+In April 2018, we entered into a collaboration agreement with LumiraDx to develop new point-of-care diagnostic tests for infectious diseases. Under terms of the agreement,
+we receive funding from LumiraDx, subject to satisfying certain milestones, to develop certain new point-of-care infectious disease tests. Following the regulatory approval and commercialization of tests in accordance with this agreement,
+Chembio will both sell reagents to, and receive royalty payments from, LumiraDx on sales of all products developed through this collaboration. 
+• 
+In November 2018, we acquired opTricon (Berlin, Germany), a leading developer of handheld optical analyzers rapid diagnostic tests. 
+• 
+In July 2019, we entered into a collaboration agreement with Shire Human Genetic Therapies, Inc., a wholly owned subsidiary of Takeda Pharmaceutical Company Limited, to develop a novel point-of-care
+diagnostic test to detect an undisclosed biomarker. 
+• 
+In November 2019, we acquired Orangelife Comercio e Industria Ltda. (Rio de Janeiro, Brazil), a privately held manufacturer of lateral flow test for infectious diseases, to expand our market penetration and
+support Bio-Manguinhos, a major customer. 
+9 
+Table of Contents 
+Competition 
+Many of our competitors are significantly larger and have greater financial, research, manufacturing, and marketing resources. Important competitive factors include product quality, analytical performance, ease of use,
+price, customer service and reputation. Industry competition is based on these and the following additional factors: 
+• 
+patent protection; 
+• 
+scientific expertise; 
+• 
+ability to develop and market products and processes; 
+• 
+ability to obtain required regulatory approvals; 
+• 
+ability to manufacture cost-effective products that meet applicable regulatory requirements; 
+• 
+access to adequate capital; and, 
+• 
+ability to attract and retain qualified personnel. 
+We believe our scientific capabilities and proprietary know-how relating to our patented DPP technology and lateral flow technology are very strong, particularly for the development and manufacture of tests for the
+detection of antibodies to infectious diseases, and other diseases. 
+Our ability to develop and market other products is in large measure dependent on our having additional resources and/or collaborative relationships. Some of our product development efforts have been funded on a
+project or milestone basis. We believe that our proprietary know-how relating to our patented DPP technology has been instrumental in our obtaining the collaborations we have and that we continue to pursue. We believe that our patent protection
+enhances our ability to both develop more profitable, collaborative relationships and expand licensing revenue. However, there are a number of competitive technologies used and/or seeking to be used by others in point-of-care settings. 
+Although we have no specific knowledge of any other competitors’ products that could render our products obsolete, if we fail to maintain and enhance our competitive position or fail to introduce new products and
+product features, our customers may decide to use the products developed by our competitors, which could result in a loss of revenues and cash flow. 
+Employees 
+As of December 31, 2019, we had 324 full-time equivalent employees, of whom 35 were in administration, 230 were in manufacturing, 42 were in research and development, and 17 were in sales and marketing and customer
+service. Of these employees, approximately 256 were located in the United States, 30 were located in Malaysia, 19 were located in Germany and 19 were located in Brazil. 
+We have never had a work stoppage, and none of our employees are represented by a labor organization or subject to any collective bargaining arrangements. We consider our employee relations to be good. 
+Governmental Regulation 
+Certain of our activities are subject to regulatory oversight by the FDA under provisions of the Federal Food, Drug, and Cosmetic Act and regulations thereunder, including regulations governing the development,
+marketing, labeling, promotion, manufacturing, and export of diagnostic products. Our clinical laboratory customers are subject to oversight by Centers for Medicare and Medicaid Services, or CMS, pursuant to CLIA, as well as agencies in various
+states. Failure to comply with applicable requirements can lead to sanctions, including withdrawal of products from the market, recalls, refusal to authorize government contracts, product seizures, civil money penalties, injunctions, and criminal
+prosecution. 
+FDA Approval/Clearance Requirements 
+Unless an exemption applies, each medical device that we market or wish to market in the United States must receive 510(k) clearance or Premarket Approval, or PMA. Medical devices that receive 510(k) clearance are
+“cleared” by the FDA to market, distribute, and sell in the United States. Medical devices that obtain a PMA by the FDA are “approved” to market, distribute and sell in the United States. We cannot be certain that 510(k) clearance or PMA approval
+will ever be obtained for any products that have not already obtained 510(k) clearance or PMA approval. Descriptions of the PMA and 510(k) clearance processes are provided below. 
+10 
+Table of Contents 
+The FDA decides whether a device line must undergo either the 510(k) clearance or PMA based on statutory criteria that utilize a risk-based classification system. PMA is the FDA process of scientific and regulatory
+review to evaluate the safety and effectiveness of Class III medical devices and, in many cases, Class II medical devices. Class III devices are those that support or sustain human life, are of substantial importance in preventing impairment of human
+health, or which present a potential, unreasonable risk of illness or injury. The FDA uses these criteria to decide whether a PMA or a 510(k) is appropriate, including the level of risk that the agency perceives is associated with the device and a
+determination by the agency of whether the product is a type of device that is similar to devices that are already legally marketed. Devices deemed to pose relatively less risk are placed in either Class I or II. In many cases, the FDA requires the
+manufacturer to submit a 510(k) requesting clearance (also referred to as a premarket notification), unless an exemption applies. The 510(k) must demonstrate that the manufacturer’s proposed device is “substantially equivalent” in intended use and in
+safety and effectiveness to a legally marketed predicate device. A “predicate device” is a pre-existing medical device to which equivalence can be drawn, that is either in Class I or Class II or is a Class III device that was in commercial
+distribution before May 28, 1976, for which the FDA has not yet called for submission of a PMA application. 
+Device classification depends on the device’s intended use and its indications for use. In addition, classification is risk-based, that is, the risk the device poses to the patient and/or the user is a major factor in
+determining the class to which it is assigned. Class I includes devices with the lowest risk and Class III includes those with the greatest risk. 
+Class I devices are those for which safety and effectiveness can be assured by adherence to the FDA’s general regulatory controls for medical devices, or the General Controls,
+which include compliance with the applicable portions of the FDA’s quality system regulations, facility registration and product listing, reporting of adverse medical events, and appropriate, truthful and non-misleading labeling, advertising, and
+promotional materials. Some Class I devices also require premarket clearance by the FDA through the 510(k) process described below. 
+Class II devices are subject to the FDA’s General Controls, and any other special controls as deemed necessary by the FDA to ensure the safety and effectiveness of the device.
+Premarket review and clearance by the FDA for Class II devices is accomplished through the 510(k) process. Pursuant to the Medical Device User Fee and Modernization Act of 2002, unless a specific exemption applies, 510(k) submissions are subject to
+user fees. Certain Class II devices are exempt from this premarket review process. 
+Class III includes devices with the greatest risk. Devices in this class must meet all of the requirements in Classes I and II. In addition, Class III devices cannot be marketed
+until they receive Premarket Approval. 
+The safety and effectiveness of Class III devices cannot be assured solely by the General Controls and the other requirements described above. These devices require formal clinical studies to demonstrate safety and
+effectiveness. Under Medical Device User Fee and Modernization Act of 2002, PMA applications (and supplemental premarket approval applications) are subject to significantly higher user fees than 510(k) applications, and they also require considerably
+more time and resources. 
+Rapid HIV tests intended for diagnostic use are regulated as Class III devices. Responsibility for assuring the safety and effectiveness of these tests lies within the Center for Biologics Evaluation and Research’s
+Office of Blood Research and Review, with oversight by the Blood Products Advisory Committee. Approved rapid HIV tests must meet the regulations in the 21 CFR 800 series subparts, under the investigational device exemption, or IDE and PMA pathways. 
+11 
+Table of Contents 
+Premarket Approval Pathway 
+We manufacture, market and distribute three rapid HIV tests in the United States. Our HIV 1/2 STAT-PAK Assay, SURE CHECK HIV 1/2 Assay, and DPP HIV 1/2 Assay all have received FDA PMA approval. A PMA application must
+be supported by extensive data including, but not limited to, analytical, preclinical, clinical trials, manufacturing, statutory preapproval inspections, and labeling to demonstrate to the FDA’s satisfaction the safety and effectiveness of the device
+for its intended use. Before a PMA is submitted, a manufacturer must apply for an IDE. If the device presents a “significant risk,” as defined by the FDA, to human health, the FDA requires the device sponsor to file an IDE application with the FDA
+and obtain IDE approval prior to initiation of enrollment of human subjects for clinical trials. The IDE provides the manufacturer with a legal pathway to perform clinical trials on human subjects where without the IDE, only approved medical devices
+may be used on human subjects. 
+The IDE application must be supported by appropriate data, such as analytical, animal and laboratory testing results, manufacturing information, and an Investigational Review Board, or IRB, approved protocol showing
+that it is safe to test the device in humans and that the testing protocol is scientifically sound. If the clinical trial design is deemed to have “non-significant risk,” the clinical trial may be eligible for “abbreviated” IDE requirements. In some
+instances, clinical trials for in vitro diagnostic medical devices may be exempt from the more burdensome IDE requirements if certain labeling requirements are met. 
+A clinical trial may be suspended by either the FDA or the Investigational Review Board at any time for various reasons, including a belief that the risks to the study participants outweigh the benefits of
+participation in the study. Even if a study is completed, clinical testing results may not demonstrate the safety and efficacy of the device, or they may be equivocal or otherwise insufficient to obtain approval of the product being tested. After the
+clinical trials have been completed, if at all, and the clinical trial data and results are collected and organized, a manufacturer may complete a PMA application. 
+After a PMA application is sufficiently complete, the FDA will accept the application and begin an in-depth review of the submitted information. By statute, the FDA has 180 days to review the “accepted application,”
+although, generally, review of the application can take between one and three years, but it may take significantly longer. During this review period, the FDA may request additional information or clarification of information already provided. Also,
+during the review period, an advisory panel of experts from outside the FDA may be convened to review and evaluate the application and provide recommendations to the FDA as to the approvability of the device. The preapproval inspections conducted by
+the FDA include an evaluation of the manufacturing facility to ensure compliance with the FDA’s quality systems regulations or QSR, as well as inspections of the clinical trial sites by the Bioresearch Monitoring group to evaluate compliance with
+good clinical practice and human subject protections. New PMA applications or PMA supplements are required for modifications that affect the safety or effectiveness of the device, including, for example, certain types of modifications to the device’s
+indication for use, manufacturing process, labeling and design. Significant changes to an approved PMA require a 180-day supplement, whereas less substantive changes may utilize a 30-day notice, or a 135-day supplement. Premarket approval supplements
+often require submission of the same type of information as a premarket approval application, except that the supplement is limited to information needed to support any changes from the device covered by the original premarket approval application,
+and it may not require as extensive clinical data or the convening of an advisory panel. 
+Our HIV 1/2 STAT-PAK Assay PMA application number BP050009/0 and our SURE CHECK 1/2 HIV Assay PMA application number BP050010/0 were approved by the FDA in May 2006. Our DPP HIV 1/2 Assay PMA application number
+BP120032/0 was approved by the FDA in December 2012. 
+510(k) Clearance Pathway 
+We are currently developing products that either will or are likely to require an FDA 510(k) clearance. We anticipate submitting a 510(k) for each such product to demonstrate that such proposed device is substantially equivalent to a previously
+cleared 510(k) device or a device that was in commercial distribution before May 28, 1976, for which the FDA has not yet called for the submission of a 510(k). The FDA's 510(k) clearance pathway usually takes from three to twelve months but could
+take longer. In some cases the FDA may require additional information, including clinical data, to make a determination regarding substantial equivalence. 
+If a device receives 510(k) clearance, any modification that could significantly affect its safety or effectiveness, or that would constitute a new or major change in its intended use, will require a new 510(k) clearance or, depending on the
+modification, a PMA. The FDA requires each device manufacturer to determine whether the proposed change requires submission of a new 510(k) or a PMA, but the FDA can review any such decision and, if it disagrees with the manufacturer's
+determination, can require the manufacturer to cease marketing and/or recall the modified device until 510(k) clearance or PMA of the modified device is obtained. 
+12 
+Table of Contents 
+Clinical Laboratory Improvement Amendments of 1988 
+A manufacturer of a test categorized as moderately complex may request that categorization of the test be waived through a CLIA Waiver by Application, or CW, submission to the FDA. When a test is categorized as waived,
+it may be performed by laboratories with a Certificate of Waiver, such as a physician’s office outreach setting. In a CW submission, the manufacturer provides evidence to the FDA that a test meets the CLIA statutory criteria for waiver CLIA, a
+walk-in clinic or an emergency room provides CMS authority over all laboratory testing, except research that is performed on humans in the United States. The Division of Laboratory Services, within the Survey and Certification Group under the CMS,
+has the responsibility for implementing the CLIA program. 
+The CLIA program is designed to establish quality laboratory testing by ensuring the accuracy, reliability and timeliness of patient test results. Under CLIA, a laboratory is a facility that does laboratory testing on
+specimens derived from humans and used to provide information for the diagnosis, prevention or treatment of disease, or impairment of, or assessment of health. Under the CLIA program, unless waived, laboratories must be certified by the government,
+satisfy governmental quality and personnel standards, undergo proficiency testing, be subject to inspections and pay fees. We have received a CLIA waiver for all of our lateral flow rapid HIV tests that we market in the United States. Specifically,
+the CLIA waiver was granted by the FDA for HIV 1/2 STAT-PAK in November 2006,for SURE CHECK HIV 1/2 in October 2007, and for DPP HIV 1/2 in October 2014. 
+Pervasive and Continuing FDA Regulation 
+A host of regulatory requirements apply to our approved devices, including: the quality system regulation, which requires manufacturers to follow elaborate design, testing, control, documentation and other quality
+assurance procedures; the Medical Reporting Regulations, which require manufacturers to report to the FDA specified types of adverse events involving their products; labeling regulations; and the FDA’s general prohibition against promoting products
+for unapproved or “off-label” uses. Some Class II devices are subject to special controls-such as performance standards, post-market surveillance, patient registries, and FDA guidelines-that do not apply to Class I devices. 
+The regulatory requirements that apply to our approved products classified as medical devices include: 
+• 
+product listing and establishment registration, which helps facilitate FDA inspections and other regulatory action; 
+• 
+QSR, which require manufacturers, including third-party manufacturers, to follow stringent design, testing, control, documentation and other quality assurance procedures during all
+aspects of the development and manufacturing process; 
+13 
+Table of Contents 
+• 
+labeling regulations and FDA prohibitions against the promotion of products for uncleared, unapproved or off-label use or indication; 
+• 
+clearance of product modifications that could significantly affect safety or efficacy or that would constitute a major change in intended use of one of our cleared devices; 
+• 
+approval of product modifications that affect the safety or effectiveness of one of our cleared devices; 
+• 
+medical device reporting regulations, which require that manufacturers comply with FDA requirements to report if their device may have caused or contributed to a death or serious
+injury, or has malfunctioned in a way that would likely cause or contribute to a death or serious injury if the malfunction of the device or a similar device were to recur; 
+• 
+post-approval restrictions or conditions, including post-approval study commitments; 
+• 
+post-market surveillance regulations, which apply when necessary to protect the public health or to provide additional safety and effectiveness data for the device; 
+• 
+the FDA’s recall authority, whereby it can ask, or under certain conditions order, device manufacturers to recall from the market a product that is in violation of governing laws and
+regulations; 
+• 
+regulations pertaining to voluntary recalls; and, 
+• 
+notices of corrections or removals. 
+Our Medford, New York facility is currently registered as an establishment with the FDA. We and any third-party manufacturers are subject to announced and unannounced inspections by the FDA to determine our compliance
+with QSR and other regulations. 
+21st Century Cures Act 
+The 21st Century Cures Act, enacted in December 2016, contains several sections specific to medical device innovations. We believe that implementation of the 21st Century Cures Act may have a positive impact on its
+businesses by facilitating innovation and/or reducing the regulatory burden imposed on medical device manufacturers. 
+Government Regulation of Medical Devices for Animal Subjects 
+We currently offer two veterinary devices in the United States: DPP VetTB Assay for Cervids and DPP VetTB Assay for Elephants. Diagnostic tests for animal health infectious diseases, including our veterinary devices
+for the prevention and/or treatment of animal disease, are regulated in the U.S. by the Center for Veterinary Biologics within the U.S. Department of Agriculture Animal and Plant Health Inspection Service, or APHIS, under the Virus, Serum, and Toxin
+Act of 1913. As a requirement, our veterinary devices were approved by APHIS before they could be sold in the U.S. 
+The APHIS regulatory approval process involves the submission of product performance data and manufacturing documentation. Following regulatory approval to market a product, APHIS requires that each lot of product be
+submitted for review before release to customers. In addition, APHIS requires special approval to market products where test results are used in part for government-mandated disease management programs. 
+Environmental Laws 
+We believe that we are in compliance in all material respects with all foreign, federal, state, and local environmental regulations applicable to our manufacturing facilities. The cost of ongoing compliance with such
+regulations does not have a material effect on our operations. 
+14 
+Table of Contents 
+Intellectual Property 
+Intellectual Property Strategy 
+Our intellectual property strategy is to: (1) build our own intellectual property portfolio around our DPP technology and optical analyzers; (2) pursue licenses, trade secrets and know-how within the area of rapid
+point-of-care testing; and, (3) develop and acquire proprietary positions to certain reagents. 
+DPP Intellectual Property 
+We have obtained patent coverage on our DPP technology, including numerous patents in the United States, China, Malaysia, Eurasia, Mexico, Singapore, Japan, Australia, Indonesia, Korea and the U.K. Additional patent
+applications on our DPP technology are pending in the United States, as well as in foreign countries such as Brazil, Canada, the European Union, India, Israel, and South Africa. 
+DPP technology provides us with freedom to operate, which enables us to develop tests with better performance and capabilities compared with tests built on traditional lateral flow platforms. These advantages have
+allowed us to enter into multiple technology collaborations based upon DPP technology, which we believe will provide new manufacturing and marketing opportunities. We have filed additional patent applications that we believe will strengthen the DPP
+intellectual property and have also filed for patent protection for certain other point-of-care technologies or applications thereof. 
+We have also obtained patent coverage on our optical-based analyzer technology in the United States, with patents pending in several foreign countries. 
+Trademarks 
+We have filed and obtained trademarks for our products, including DPP, SURE CHECK, STAT-VIEW, and STAT-PAK, and NEXT GENERATION DPP, as well as for the SampleTainer and DPP Micro Reader, which are used with certain DPP
+products. Our trademarks have been obtained in the United States and certain other countries around the world. 
+Trade Secrets and Know-How 
+We have developed a substantial body of trade secrets and know-how relating to the development and manufacture of lateral flow and DPP-based diagnostic tests, including the sourcing and optimization of materials for
+such tests, and methods to maximize sensitivity, speed-to-result, specificity, stability and reproducibility of our tests. We possess proprietary know-how to develop tests for multiple conditions using colored particles. Our formulations enable
+long shelf lives of our rapid HIV and other tests, providing us with an important competitive advantage. 
+Lateral Flow Technology and Reagent Licenses 
+We seek licenses and/or redesigns of products that we believe to be in our best interests. Because of the costs and other negative consequences of time-consuming patent litigation, we often attempt to obtain a license
+on reasonable terms. 
+The peptides used in our rapid HIV tests were licensed to us by one or more third parties. We also have licensed the antigens used in other tests including our Syphilis, Tuberculosis, Leptospirosis, Leishmaniasis and
+Chagas tests, and we may enter into other license agreements. In prior years, we concluded license agreements related to intellectual property rights owned by the United States associated with HIV-1 and a sub-license agreement for HIV-2 with Bio-Rad
+Laboratories N.A., the exclusive licensee of the Pasteur Institute’s HIV-2 intellectual property estate. 
+15 
+Table of Contents 
+Available Information 
+We are required to file annual, quarterly and current reports, proxy statements and other information with the U.S. Securities and Exchange Commission. The SEC maintains a website at www.sec.gov that contains reports,
+proxy and information statements, and other information regarding issuers that file electronically with the SEC. 
+Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, proxy statements and amendments to those documents filed or furnished pursuant to Section 13(a) or 15(d) of the Securities
+Exchange Act of 1934, are also available free of charge on our website at www.chembio.com as soon as reasonably practicable after such reports are electronically filed with or furnished to the SEC. 
+Investors should note that we currently announce material information to our investors and others using filings with the SEC, press releases, public conference calls, webcasts or our website (www.chembio.com),
+including news and announcements regarding our financial performance, key personnel, our brands and our business strategy. Information that we post on our corporate website could be deemed material to investors. We encourage investors to review the
+information we post on these channels. We may from time to time update the list of channels we will use to communicate information that could be deemed material and will post information about any such change on www.chembio.com. The information on
+our website is not, and shall not be deemed to be, a part hereof or incorporated into this or any of our other filings with the SEC. 
+Corporate Information 
+Our principal executive offices are located at 555 Wireless Boulevard, Hauppauge, New York 11788. Our telephone number is (631) 924-1135. Our website address is www.chembio.com. The information contained in, or
+accessible through, our corporate website does not constitute part of this report. 
+ITEM 1A. 
+RISK FACTORS 
+You should carefully consider each of the following risk factors and all of the other information provided in this Form 10-K in considering whether to make or continue to hold an investment in our
+Common Stock. The risks described below are those we currently believe may materially affect us. An investment in our Company involves a high degree of risk, and should be considered only by persons who can afford the loss of their entire
+investment. Although we believe that these risks are the most important for you to consider, you should read this section in conjunction with our financial statements, the notes to those financial statements and our management’s discussion and
+analysis of financial condition and results of operations included in our periodic reports and incorporated into this Form 10-K by reference. 
+Risks Related to Our Business 
+Important competitive factors for our products include price, quality, performance, ease of use, and customer service. A few large corporations produce a wide variety of diagnostic tests and other medical devices and
+equipment. A larger number of mid-size companies generally compete only in the diagnostic industry and a significant number of small companies produce only a few diagnostic products. As a result, the diagnostic test industry is highly fragmented and
+segmented. 
+16 
+Table of Contents 
+More generally, the point-of-care diagnostics industry is undergoing rapid technological changes, with frequent introductions of new technology-driven products and services. As new technologies become introduced into
+the point-of-care diagnostic testing market, we may be required to commit considerable additional efforts, time and resources to enhance our current product portfolio or develop new products. We may not have the available time and resources to
+accomplish this, and many of our competitors have substantially greater financial and other resources to invest in technological improvements. We may not be able to effectively implement new technology-driven products and services or be successful
+in marketing these products and services to our customers, which would materially harm our operating results. 
+Although we own DPP patents, lateral flow technology is still a competitive platform to DPP, and lateral flow technology has a lower cost of manufacture than DPP products. Although the DPP platform has shown improved
+sensitivity as compared with conventional lateral flow platforms in a number of studies, several factors go into the development and performance attributes of products. Therefore the ability of our products to successfully compete will depend on
+several other factors, including our having a patented rapid test platform technology that differentiates DPP from lateral flow as well as from other diagnostic platform technologies. 
+There can be no assurance that our DPP patents or our products incorporating those patents will not be challenged at some time in the future. 
+Our Competitors may Develop and Commercialize More Effective or Successful Products, and Our Research, Development and Commercialization Efforts may not Succeed. 
+We regularly commit substantial resources to research and development and the commercialization of our new or enhanced products. The research and development process usually takes a long time from inception to
+commercial launch. During each stage of this process there is a substantial risk that we will not achieve our goals in a timely fashion, or at all, and we may have to abandon a new or enhanced product in which we have invested substantial time and
+money. We expect to continue to incur significant costs related to our research and development activities. 
+Our products require significant development and investment prior to commercialization, including testing to demonstrate the products’ performance capabilities, cost-effectiveness or other benefits. We must obtain
+regulatory approval before most products may be sold and additional development efforts on these products may be required before the products will be reviewed. However, regulatory authorities may not approve these products for commercial sale or may
+substantially delay or condition such approval. There may be little or no market for the product and entry into or development of new markets for our products may require an investment of substantial resources even if all applicable regulatory
+approvals are obtained. Furthermore, we may spend a significant amount of money on advertising or other activities and still fail to develop a market for the product. The success of our efforts may be affected by our ability to manufacture products
+in a cost-effective manner, whether we can obtain necessary intellectual property rights and protection and our ability to obtain reimbursement authorizations in the markets where the product will be sold. Therefore, if we fail to develop and gain
+commercial acceptance for our products, or if competitors develop more effective products or a greater number of successful new products, customers may decide not to purchase our products. 
+Our Products may not be Able to Compete with New Diagnostic Products or Existing Products Developed by Well-Established Competitors, which would Negatively Affect Our Business. 
+The diagnostic industry is focused on the testing of biological specimens in a laboratory or at the point-of-care and is highly competitive and rapidly changing. Important competitive factors for our products include
+price, quality, performance, ease of use, and customer service. 
+A few large corporations produce a wide variety of diagnostic tests and other medical devices and equipment. A larger number of mid-size companies generally compete only in the diagnostic industry and a significant
+number of small companies produce only a few diagnostic products. As a result, the diagnostic test industry is highly fragmented and segmented. 
+17 
+Table of Contents 
+Some of our principal competitors may have considerably greater financial, technical and marketing resources than we do. Several companies produce diagnostic tests that compete directly with our testing product line,
+including Abbott (Alere), OraSure Technologies and Trinity Biotech. Some competitors offer broader product lines and may have greater name recognition than we have. These and other companies have or may have products incorporating molecular or other
+advanced technologies that over time could directly compete with our testing product line. We also face competition from certain of our distributors or former customers that have created or may decide to create, their own products to compete with
+ours. 
+As new products incorporating new technologies enter the market, our products may become obsolete or a competitor’s products may be more effective or more effectively marketed and sold. If our competitors’ products
+take market share from our products through more effective marketing or competitive pricing, our revenues, margins and operating results could be adversely affected. In addition, our revenues and operating results could be negatively impacted if some
+of our customers internally develop or acquire their own sample collection devices and use those devices in place of our products in order to reduce costs. 
+Our Future Revenues and Operating Results may be Negatively Affected by Ongoing Consolidation in the Healthcare Industry. 
+There has been a significant amount of consolidation in the healthcare industry. This consolidation has increased the competition to provide goods and services to customers. In addition, group purchasing organizations
+and integrated health delivery networks have served to concentrate purchasing decisions for some customers, which has also placed pricing pressure on medical device suppliers. Due to ongoing consolidation, there could be additional pressure on the
+prices of our products. 
+The Company may not successfully manage the transition associated with the appointment of a new chief executive officer, which could have an adverse impact on the Company. 
+On January 9, 2020, we announced that John J. Sperzel III had notified the board of directors of his resignation as our Chief Executive Officer and President and one of our directors. On the same day,
+we announced that we had appointed Gail S. Page, one of our directors, to serve as our Interim Chief Executive Officer. On March 12, 2020, we announced that we had appointed Richard Eberly as our Chief Executive Officer, effective as of March 16,
+2020. 
+The effectiveness of our new Chief Executive Officer, and our senior leadership team generally, following these transitions and any further transition as a result of these changes, could have a significant impact on
+our results of operations. Management transition is often difficult and inherently causes some loss of institutional knowledge, which could negatively affect our results of operations and financial condition. Our ability to execute our business
+strategies may be adversely affected by the uncertainty associated with these transitions. 
+Our Continued Growth Depends on Retaining Our Current Key Employees and Attracting Additional Qualified Personnel, and We may not be Able to do so. 
+Our success depends to a large extent upon the skills and experience of our executive officers, sales, marketing, operations and scientific staff. We may not be able to attract or retain qualified employees due to the
+intense competition for qualified personnel among medical products businesses and academic and other research institutions, as well as to geographic considerations, our ability to offer competitive compensation and benefits, and other reasons. 
+If we are not able to attract and retain the necessary qualified personnel to accomplish our business objectives, we may experience constraints that will adversely affect our ability to effectively manufacture, sell
+and market our products to meet the demands of our customers and strategic partners in a timely fashion, or to support internal research and development programs. 
+18 
+Table of Contents 
+We have entered into employment contracts with our Interim Chief Executive Officer, Gail S. Page; our incoming Chief Executive Officer, Richard Eberly, our Chief Science & Technology Officer, Javan Esfandiari, and
+our Chief Financial Officer, Neil Goldman. Due to the specific knowledge and experience of these executives regarding the industry, technology and market generally and to our company specifically, the loss of the services of any one of these
+executives could have a material adverse effect on us. We have not obtained a key man insurance policy on any officer other than Mr. Esfandiari. 
+We may not generate the expected benefits of our acquisitions of opTricon GmbH or Orangelife Comercio e Industria Ltda. and the integration of the acquisitions could disrupt our ongoing business,
+distract our management and increase our expenses. 
+We acquired opTricon GmbH, or opTricon, and Orangelife Comercio e Industria Ltda., or Orangelife, in November 2018 and November 2019, respectively, with the expectation that the acquisition will result in various
+benefits, including securing global commercial rights and reducing cost of goods. Achieving the anticipated benefits of either acquisition is subject to a number of uncertainties, including whether our business and the businesses of opTricon or
+Orangelife can be integrated in an efficient and effective manner. We cannot assure you that we will be able to accurately forecast the performance or ultimate impact of either the opTricon acquisition or the Orangelife acquisition. 
+The integration processes may take longer than anticipated and result in the loss of valuable employees, the incurrence of additional and unforeseen expenses, the disruption of our ongoing business, processes and
+systems, or inconsistencies in standards, controls, procedures, practices, policies and compensation arrangements, any of which could adversely affect our ability to achieve the anticipated benefits of the acquisitions. There may be increased risk
+due to integrating financial reporting and internal control systems. The integration processes are subject to a number of uncertainties, and no assurance can be given that the anticipated benefits, expense savings and synergies will be realized or,
+if realized, the timing of their realization. Failure to achieve these anticipated benefits could result in increased costs or decreases in the amount of expected revenues and could adversely affect our future business, financial condition, operating
+results and prospects. 
+We have incurred and will continue to incur non-recurring expenses in connection with the opTricon acquisition and the Orangelife acquisition, including legal, accounting and other expenses. Additional unanticipated
+costs may be incurred following consummation of the opTricon acquisition or the Orangelife acquisition in the course of the integration of the respective businesses into our business. We cannot be certain that the realization of efficiencies related
+to the integration of the two businesses will offset the transaction and integration costs in the near term, or at all, or any losses from undiscovered liabilities not covered by an indemnification from the sellers of opTricon or Orangelife. 
+We may not Generate the Expected Benefits of Future Acquisitions or Investments, and they could Disrupt Our Ongoing Business, Distract Our Management, Increase Our Expenses and Negatively Affect Our
+Business. 
+As a way for us to grow our business, we may pursue strategic acquisitions or investments. These activities, and their impact on our business, are subject to many risks, including the following: (i) the benefits
+expected to be derived from an acquisition or investment may not materialize and could be affected by numerous factors, such as regulatory developments, insurance reimbursement, our inexperience with new businesses or markets, general economic
+conditions and increased competition; (ii) we may be unable to successfully integrate an acquired company’s personnel, assets, management, information technology systems, accounting policies and practices, products and/or technology into our
+business; (iii) we may not be able to accurately forecast the performance or ultimate impact of an acquired business; and (iv) an acquisition may result in the incurrence of unexpected expenses, stockholder lawsuits, the dilution of our earnings or
+our existing stockholders’ percentage ownership, or potential losses from undiscovered liabilities not covered by an indemnification from the seller(s) of the acquired business. 
+19 
+Table of Contents 
+If these factors occur, we may be unable to achieve all or a significant part of the benefits expected from an acquisition or investment. This may adversely affect our financial condition, results of operations and
+ability to grow our business or otherwise achieve our financial and strategic objectives. 
+Third-Party Reimbursement Policies and Potential Cost Constraints could Negatively Affect Our Business. 
+The list of our product end-users includes hospitals, physicians and other healthcare providers. If these end-users do not receive adequate reimbursement for the cost of our products from their patients’ healthcare
+insurers or payors, the use of our products could be negatively impacted. Furthermore, the net sales of our products could also be adversely affected by changes in reimbursement policies of government or private healthcare payors. 
+Hospitals, physicians and other healthcare providers who purchase diagnostic products in the United States generally rely on third-party payors, such as private health insurance plans, Medicare and Medicaid, to
+reimburse all or part of the cost of the product. Due to the overall escalating cost of medical products and services, there is increased pressures on the healthcare industry, both foreign and domestic, to reduce the cost of products and services.
+Given the efforts to control and reduce healthcare costs in the United States, available levels of reimbursement may change for our existing products or products under development. Third-party reimbursement and coverage may not be available or
+adequate in either the United States or international markets, current reimbursement amounts may be decreased in the future and future legislation, and regulation or reimbursement policies of third-party payors, may reduce the demand for our products
+or our ability to sell our products on a profitable basis. 
+To the Extent that We are Unable to Collect Our Outstanding Accounts Receivable, Our Operating Results could be Materially Harmed. 
+There may be circumstances and timing that require us to accept payment terms, including delayed payment terms, from distributors or customers, which, if not satisfied, could cause financial losses. 
+We generally accept payment terms which require us to ship product before the contract price has been paid fully, and there also are circumstances pursuant to which we may accept further delayed payment terms pursuant
+to which we may continue to deliver product. To the extent that these circumstances result in significant accounts receivables and those accounts receivables are not paid on a timely basis, or are not paid at all, especially if concentrated in one
+or two customers, we could suffer financial losses. 
+Ongoing Changes in Healthcare Regulation could Negatively Affect Our Revenues, Business and Financial Condition. 
+There have been several proposed changes in the United States at the federal and state level for comprehensive reforms regarding the payment for, the availability of and reimbursement for healthcare services. These
+proposals have ranged from fundamentally changing federal and state healthcare reimbursement programs, including providing comprehensive healthcare coverage to the public under government-funded programs, to minor modifications to existing programs.
+One example is the Patient Protection and Affordable Care or the Affordable Care Act, the Federal healthcare reform law enacted in 2010. 
+Healthcare reform initiatives will continue to be proposed, and may reduce healthcare related funding in an effort. It is impossible to predict the ultimate content and timing of any healthcare reform legislation and
+its resulting impact on us. If significant reforms are made to the healthcare system in the United States, or in other jurisdictions, those reforms may increase our costs or otherwise negatively effect on our financial condition and results of
+operations. 
+20 
+Table of Contents 
+In April 2017, the European Parliament passed the Medical Devices Regulation (Regulation 2017/745), which repeals and replaces the European Union Medical Devices Directive and the Active Implantable Medical Devices
+Directive. Unlike directives, which must be implemented into the national laws of the European Economic Area, which we refer to as the EEA, member States, the regulations would be directly applicable, i.e., without the need for adoption of EEA member
+State laws implementing them, in all EEA member States and are intended to eliminate current differences in the regulation of medical devices among EEA member States. The Medical Devices Regulation, among other things, is intended to establish a
+uniform, transparent, predictable and sustainable regulatory framework across the EEA for medical devices and ensure a high level of safety and health while supporting innovation. The Medical Devices Regulation will, however, only become fully
+applicable three years after publication (in May 2020). Once applicable, the Medical Devices Regulation will, among other things: 
+• 
+strengthen the rules on placing devices on the market and reinforce surveillance once they are available; 
+• 
+establish explicit provisions on manufacturers’ responsibilities for the follow-up of the quality, performance and safety of devices placed on the market; 
+• 
+improve the traceability of medical devices throughout the supply chain to the end-user or patient through a unique identification number; 
+• 
+set up a central database to provide patients, healthcare professionals and the public with comprehensive information on products available in the EU; and 
+• 
+strengthen rules for the assessment of certain high-risk devices, such as implants, which may have to undergo an additional check by experts before they are placed on the market. 
+Once applicable, the Medical Devices Regulation may impose increased compliance obligations for us to access the EU market. 
+We Believe Our Success Depends in Part on the Continued Funding of, and Our Ability to Participate in, Large Testing Programs in the U.S. and Worldwide, the Funding of which may be Reduced or
+Discontinued or Otherwise be Unavailable to Us. 
+We believe it to be in our best interests to meaningfully participate in large testing programs. Moreover many of these programs are funded by governments and other donors, and there can be no assurance that funding
+will not be reduced or completely discontinued. Participation in these programs also requires alignment and engagement with the many other participants in these programs, including WHO, CDC, the U.S. Agency for International Development, foreign
+governments and their agencies, non-governmental organizations, and HIV service organizations. If we are unsuccessful in our efforts to participate in these programs, our operating results could be materially harmed. 
+In December 2013 President Obama signed into law the PEPFAR Stewardship and Oversight Act, which is the most recent reauthorization of PEPFAR. However, unlike the 2008 PEPFAR authorization, which authorized
+approximately $45 billion in funding, the new law did not authorize a specific dollar amount for funding. 
+Developing Testing Guidelines could Negatively Affect Sales of Our Products. 
+Government agencies may issue diagnostic testing guidelines or recommendations, which can alter the usage of our HIV testing products. New laws or guidelines, or changes to existing laws or guidelines, and the manner
+in which these new or changed laws and guidelines are interpreted and applied, could impact the degree to which our testing products are used. These developments could affect the frequency of testing, the number of people tested and whether the
+testing products are used broadly for screening large populations or in a more limited capacity. These factors could in turn affect the level of sales of our products and our results of operations. 
+21 
+Table of Contents 
+Legislative and Other Regulatory Changes could have an Effect on Our Business. 
+The current U.S. Presidential Administration has promised to repeal and replace the Affordable Care Act, expressed concerns with respect to existing trade agreements, and has indicated a desire to make other regulatory
+changes during his administration. Changes in regulatory or economic conditions or in the laws and policies governing foreign trade, taxes, manufacturing, and development in the United States could impact our business. Economic and regulatory changes
+could also affect foreign currency exchange rates which, in turn, could affect our reported financial results and our competitiveness on a worldwide basis. 
+Developments Related to the U.K.’s Referendum On Membership in the E.U. Could Adversely Affect Us. 
+On June 23, 2016, the United Kingdom voted in favor of leaving the European Union, or E.U.. On January 24, 2020, the U.K. and the E.U. entered into a withdrawal agreement pursuant to which the U.K. formally left the E.U. on January 31, 2020, but
+will, for a transition period ending on December 31, 2020, maintain access to the E.U. single market and to the global trade deals negotiated by the E.U. on behalf of its members and remain subject to E.U. law. The ultimate impact of the “leave” vote
+will depend on the terms that are negotiated in relation to the U.K.’s future relationship with the E.U. “Brexit” could impair our ability to transact business in the U.K. and E.U. countries. Brexit has already and could continue to contribute to
+instability in the global financial markets. The long-term effects of Brexit will depend in part on any new trade agreements the U.K. makes to retain access to E.U. markets following the U.K.’s withdrawal transition period from the E.U. Negotiations
+of a trade agreement may be unsuccessful, and the U.K. may not reach agreement with the E.U. on the future terms of the U.K.’s relationship with the E.U. 
+Without an agreement, there will be a period of considerable uncertainty particularly in relation to the financial and banking markets and the regulation of our industry, including the regulatory approval process. 
+We expect that Brexit could lead to legal uncertainty and potentially divergent national laws and regulations as the U.K. determines which E.U. laws to replicate or replace. If the U.K. were to significantly alter its regulations affecting the
+pharmaceutical industry, we could face significant new costs relating to the development, manufacture, and marketing of our current and future products. It may also be time-consuming and expensive for us to alter our internal operations in order to
+comply with any new regulations. 
+Among other outcomes, Brexit could disrupt the free movement of goods, services and people between the U.K. and the E.U., and result in increased legal and regulatory complexities, as well as potential higher costs of conducting business in the
+U.K. and the E.U. In addition, changes to U.K. immigration policy as a result of Brexit could adversely affect our ability to retain talent for our European operations. Given the lack of comparable precedent, it is unclear what financial, trade,
+regulatory, and legal implications the final withdrawal of the U.K. from the E.U. would have and how such withdrawal would affect us. Any of these effects, and others we cannot anticipate, could negatively affect our business and financial condition. 
+We could be Exposed to Liability if We Experience Security Breaches or Other Disruptions, which could Harm Our Reputation and Business . 
+We may be subject to cyber-attacks whereby computer hackers may attempt to access our computer systems or our third party IT service provider’s systems and, if successful, misappropriate personal or confidential
+information. In addition, a contractor or other third party with whom we do business may attempt to circumvent our security measures or obtain such information, and may purposefully or inadvertently cause a breach involving sensitive information. We
+will continue to evaluate and implement additional protective measures to reduce the risk and detect cyber incidents, but cyber-attacks are becoming more sophisticated and frequent and the techniques used in such attacks change rapidly. Even though
+we take cyber-security measures that are continuously reviewed and updated, our information technology networks and infrastructure may still be vulnerable due to sophisticated attacks by hackers or breaches. 
+22 
+Table of Contents 
+Even the most well protected IT networks, systems, and facilities remain potentially vulnerable because the techniques used in security breaches are continually evolving and generally are not recognized until launched
+against a target and, in fact, may not be detected. Any such compromise of our or our third party’s IT service providers’ data security and access, public disclosure, or loss of personal or confidential business information, could result in legal
+claims proceedings, liability under laws to protect, privacy of personal information, and regulatory penalties, disrupt our operations, require significant management attention and resources to remedy any damages that result, damage our reputation
+and customers willingness to transact business with us, any of which could adversely affect our business. 
+Our Ability to Efficiently Operate Our Business is Reliant on Information Technology, and Any Material Failure, Inadequacy, Interruption or Security Breach of that Technology could Harm Our Business. 
+We rely heavily on complex information technology systems across our operations and on the internet, including for management of inventory, invoices, purchase orders, shipping, interactions with our third-party
+logistics provider, revenue and expense accounting, consumer call support, online business, and various other processes and transactions. Our ability to effectively manage our business, coordinate the production, distribution and sale of our
+products, respond to customer inquiries, and ensure the timely and accurate recording and disclosure of financial information depends significantly on the reliability and capacity of these systems and the internet. 
+If any of the foregoing systems fails to operate effectively, problems with transitioning to upgraded or replacement systems, or disruptions in the operation of the internet, could cause delays in product sales and
+reduced efficiency of our operations. Significant expenditures could be required to fix any such problem. 
+If there is an Increase in Demand for Our Products, it could Require Us to Expend Considerable Resources or Harm Our Customer Relationships if We are Unable to Meet that Demand. 
+If there are significant or unexpected increases in the demand for our products, we may not be able to meet that demand without expending additional capital resources. This would increase our capital costs, which could
+negatively affect our earnings in the short term. In addition, new manufacturing equipment or facilities may require FDA, WHO, and other regulatory approvals before they can be used to manufacture our products. To the extent we are unable to obtain
+or are delayed in obtaining such approvals, our ability to meet the demand for our products could be adversely affected. Furthermore, our suppliers may be unable or unwilling to expend the necessary capital resources or otherwise expand their
+capacity, which could negatively affect our business. 
+Our business could be negatively affected if we or our suppliers are unable to develop necessary manufacturing capabilities in a timely manner. If we fail to increase production volumes in a cost effective manner or if
+we experience lower than anticipated yields or production problems as a result of changes that we or our suppliers make in our manufacturing processes to meet increased demand, we could experience shipment delays or interruptions and increased
+manufacturing costs, which could also have a material adverse effect on our revenues and profitability. 
+If there are unexpected increases in demand for our products, we may be required to obtain additional raw materials in order to manufacture products to meet the increase in demand. However, some raw materials require
+significant ordering lead time and some are currently obtained from a sole supplier or a limited group of suppliers. It is also possible that one or more of our suppliers may become unwilling or unable to deliver materials to us. Any shortfall in our
+supply of raw materials and components, or our inability to quickly and cost-effectively obtain alternative sources for this supply, could have a material adverse effect on our ability to meet increased demand for our products. This could negatively
+affect our total revenues or cost of sales and related profits. 
+23 
+Table of Contents 
+If we are unable to meet customer demand for our products, it could also harm our relationships with our customers and impair our reputation within the industry. This, in turn, could have a material adverse effect on
+our business. 
+Risks Related to Our Products 
+For Our Business to Succeed in the Future, Our Current and Future Products Must Receive Market Acceptance. 
+Market acceptance and the timing of such acceptance, of our new products or technologies is necessary for our future success. To achieve market acceptance, we and our distributors will likely be required to undertake
+substantial efforts and spend significant funds to inform every one of the existence and perceived benefits of our products. We also may require government funding for the purchase of our products to help create market acceptance and expand the use
+of our products. 
+It may be difficult evaluate the market reaction to our products and our marketing efforts for new products may not be successful. The government funding we receive may be limited for new products. As such, there can
+be no assurance that any products will obtain significant market acceptance and fill the market need that is perceived to exist on a timely basis, or at all. 
+We may not have Sufficient Resources to Effectively Introduce and Market Our Products, which could Materially Harm Our Operating Results. 
+Introducing and achieving market acceptance for our new products will require substantial marketing efforts and will require us and/or our contract partners, sales agents, and/or distributors to make significant
+expenditures of time and money. In some instances we will be significantly or totally reliant on the marketing efforts and expenditures of our contract partners, sales agents, and distributors. If they do not have or commit the expertise and
+resources to effectively market the products that we manufacture, our operating results will be materially harmed. 
+New Developments in Health Treatments and Non-Diagnostic Products may Reduce or Eliminate the Demand for Our Products. 
+The development and commercialization of products outside of the diagnostics industry could adversely affect sales of our products. For example, the development of a safe and effective vaccine to HIV or treatments
+for other diseases or conditions that our products are designed to detect, could reduce or eventually eliminate the demand for our HIV or other diagnostic products and result in a loss of revenues. 
+Sales Cycles for Our Products can be Lengthy, which can Cause Variability and Unpredictability in Our Business. 
+Some of our products may require lengthy and unpredictable sales cycles, which makes it more difficult to accurately forecast revenues in a given period and may cause revenues and operating results to vary from
+period to period. Our products may involve sales to large public and private institutions which may require many levels of approval and may be dependent on economic or political conditions and the availability of grants or funding from government
+or public health agencies which can vary from period to period. There can be no assurance that purchases or funding from these agencies will occur or continue, especially if current negative economic conditions continue or intensify. As a result,
+we may expend considerable resources on unsuccessful sales efforts or we may not be able to complete transactions at all or on a schedule and in an amount consistent with our objectives. 
+24 
+Table of Contents 
+We May Face Product Liability Claims for Injuries. 
+The testing, manufacturing and marketing of medical diagnostic products involves an inherent risk of product liability claims. If we cannot successfully defend ourselves against product liability claims, we may incur
+substantial liabilities or be required to limit or cease sales of our products. We cannot be sure that we will not incur liabilities in excess of the policy limits of our existing product liability insurance coverage or that we will be able to
+continue to obtain adequate product liability insurance coverage in the future at an acceptable cost, or at all. In addition, a defect in the design or manufacture of our products could have a material adverse effect on our reputation in the
+industry and subject us to claims of liability for injury and otherwise. Any substantial underinsured loss resulting from such a claim could have a material adverse effect on our profitability, and the damage to our reputation in the industry could
+have a material adverse effect on our business. 
+Our Customers may not Adopt Rapid Point-of-Care Diagnostic Testing. 
+Rapid point-of-care tests are beneficial because, among other things, they can be administered by healthcare providers in their own facilities or used by consumers at home without sending samples to central
+laboratories. But currently the majority of diagnostic tests used by physicians and other healthcare providers in the U.S. are provided by clinical reference laboratories and hospital-based laboratories. In some international markets, such as
+Europe, diagnostic testing is performed primarily by centralized laboratories. Future sales of our products will depend, in part, on our ability to expand market acceptance of rapid point-of-care testing and successfully compete against laboratory
+testing methods and products. However, we expect that clinical reference and other hospital-based laboratories will continue to compete vigorously against our rapid point-of-care products. Even if we can demonstrate that our products are more cost
+effective, save time, or have better performance or other benefits, physicians, other healthcare providers and consumers may resist changing to rapid point-of-care tests and instead may choose to obtain diagnostic results through laboratory tests.
+If we fail to achieve and expand market acceptance of our rapid point-of-care diagnostic tests with customers, it would have a negative effect on our future sales growth. 
+Customer Concentration Creates Risks for Our Business. 
+A significant portion of our revenues each year comes from a few large customers. To the extent that such a large customer fails to meet its purchase commitments, changes its ordering patterns or business strategy,
+or otherwise reduces its purchases or stops purchasing our products, or if we experience difficulty in meeting the demand by these customers for our products, our revenues and results of operations could be adversely affected. 
+If Our Products do not Perform Properly, It may Affect Our Revenues, Stock Price and Reputation. 
+Our products may not perform as expected. For example, a defect in one of our diagnostic products or a failure by a customer to follow proper testing procedures may cause the product to report inaccurate information.
+Identifying the root cause of a product performance or quality issue can be difficult and time consuming. 
+If our products do not to perform in accordance with the applicable label claims or otherwise in accordance with the expectations or needs of our customers, customers may switch to a competing product or otherwise
+stop using our products, and our revenues could be negatively affected. If this occurs, we may be required to implement holds or product recalls and incur warranty obligations. Furthermore, the poor performance by one or more of our products could
+have an adverse effect on our reputation, our continuing ability to sell products and the price of our Common Stock. 
+25 
+Table of Contents 
+If We Expand Our International Presence, It may Increase Our Risks and Expose Our Business to Regulatory, Cultural or Other Challenges. 
+We will continue to try to increase revenue derived from international sales of our products. There are several of factors that could adversely affect the performance of our business and/or cause us to incur
+substantially increased costs because of our international presence and sales, including: (i) uncertainty in the application of foreign laws and the interpretation of contracts with foreign parties; (ii) cultural and political differences that
+favor local competitors or make it difficult to effectively market, sell and gain acceptance of our products; (iii) exchange rates, currency fluctuations, tariffs and other barriers, extended payment terms and dependence on international
+distributors or representatives; (iv) trade protection measures, trade sanctions and import/export licensing requirements; (v) our inability to obtain or maintain regulatory approvals or registrations for our products; (vi) Economic conditions,
+political instability, the absence of available funding sources, terrorism, civil unrest, war and natural disasters in foreign countries; (vii) Reduced protection for, or enforcement of, our patents and other intellectual property rights in foreign
+countries; (viii) our inability to identify international distributors and negotiate acceptable terms for distribution agreements; and (ix) restrictions on our ability to repatriate investments and earnings from foreign operations. 
+Economic, cultural and political conditions and foreign regulatory requirements may slow or prevent the manufacture of our products in countries other than the United States. Interruption of the supply of our
+products could reduce revenues or cause us to incur significant additional expenses in finding an alternative source of supply. Foreign currency fluctuations and economic conditions in foreign countries could also increase the costs of
+manufacturing our products in foreign countries. 
+Financial, Economic and Financing Risks 
+We have incurred losses in recent years and we are uncertain about our future profitability. 
+We incurred an operating loss every year from 2014 through 2019. Under our operating plans, we have made, and plan to continue to make, significant investments in our production capacity, including in expanding
+facilities and automating manufacturing, and in our sales and marketing, regulatory approval, and research and development activities. Our ability to achieve profitability and generate cash flow in the future will depend on our ability to increase
+sales of our existing products and to successfully introduce new and enhanced products into the marketplace, all while controlling and managing our expenses consistent with our operating plan. 
+If we are unable to increase our revenues and manage our expenses in accordance with our operating plan, our operating results would be harmed and we may not be able to generate the cash flow needed to fund the
+investments in our production capacity and other activities, we will be required to implement one or both of the following: 
+• 
+We could reduce the level, or otherwise delay the timing, of the anticipated investments in our production capacity and other activities, which would likely curtail or delay the
+growth in our business contemplated by our operating plan and could impair or defer our ability to achieve profitability and generate cash flow. 
+• 
+We could raise additional funds through public or private financings, strategic relationships, or other arrangements, to the extent funding would be available to us on acceptable
+terms or at all. If we succeed in raising additional funds through the issuance of equity or convertible securities, then the issuance could result in substantial dilution to existing stockholders. Furthermore, the holders of these new
+securities or debt may have rights, preferences and privileges senior to those of the holders of our Common Stock. 
+In such circumstances, we also would need to forego acquisition opportunities, which could impede our ability to grow our business. 
+26 
+Table of Contents 
+Our Financial Results may Fluctuate. 
+From quarter to quarter and year to year, our operating results can fluctuate, which could cause our growth or financial performance to fail to meet the expectations of investors and securities analysts. Sales to our
+distributors and other customers may not meet expectations because of lower than expected customer demand or other factors, including continued economic volatility and disruption, reduced governmental funding, and other circumstances described
+elsewhere in this report. A variety of factors could also contribute to the variability of our financial results, including infrequent, unusual or unexpected changes in revenues or costs. 
+Different products provide dissimilar contributions to our gross product margin. Accordingly, our operating results could also fluctuate and be negatively affected by the mix of products sold and the relative prices
+and gross product margin contribution of those products. Failure to achieve operating results consistent with the expectations of investors and securities analysts could adversely affect our reputation and the price of our Common Stock. 
+The failure to comply with the terms of our Credit Agreement and Guaranty could result in a default under its terms and, if uncured, could result in action against our pledged assets and dilution
+of our stockholders. 
+On September 3, 2019, we entered into a Credit Agreement and Guaranty, or Credit Agreement, with Perceptive Credit Holdings II, LP, or Perceptive. Under the Credit Agreement, we received a $20,000,000 senior secured
+term loan credit facility, which was drawn in full on September 4, 2019. In connection with the Credit Agreement, we issued a warrant to purchase up to 550,000 shares of our common stock. The credit agreement is secured by a first priority,
+perfected lien on substantially all of our property and assets, including our equity interests in our subsidiaries. 
+The Credit Agreement also contains covenants that restrict our ability to finance future operations or capital needs or to engage in other business activities. The Credit Agreement restricts our
+ability and the ability of our restricted subsidiaries to: 
+• 
+incur, assume or guarantee additional Indebtedness (as defined in the Credit Agreement); 
+• 
+repurchase capital stock; 
+• 
+make other restricted payments including, without limitation, paying dividends and making investments; 
+• 
+create liens; 
+• 
+sell or otherwise dispose of assets, including capital stock of subsidiaries; 
+• 
+enter into agreements that restrict dividends from subsidiaries; 
+• 
+enter into mergers or consolidations; and 
+• 
+enter into transactions with affiliates 
+In addition, the Credit Agreement also contain covenants requiring us and our subsidiaries to maintain cash and cash equivalents held in one or more accounts subject to the first priority perfected
+security interests of the lenders under the Credit Agreement of not less than $3,000,000. The Credit Agreement also provides for specified quarterly minimum consolidated net revenue covenants of us and our subsidiaries for the trailing twelve-month
+period ended on each such calculation date during the term of the Credit Agreement. A breach of any of these covenants would result in a default under the Credit Agreement. If an event of default under our Credit Agreements occurs, Perceptive could
+elect to declare all amounts outstanding thereunder, together with accrued interest, to be immediately due and payable. If we were unable to pay such amounts, Perceptive could proceed against the collateral pledged to them. We have pledged our
+inventory, accounts receivable, cash, securities, other general intangibles and the capital stock of certain subsidiaries to the lenders. In such an event, we cannot assure you that we would have sufficient assets to pay amounts due under the
+Credit Agreement. 
+27 
+Table of Contents 
+Servicing our debt will require a significant amount of cash. Our ability to generate sufficient cash to service our debt depends on many factors beyond our control. 
+Our ability to make payments on and to refinance our debt, to fund planned capital expenditures, and to maintain sufficient working capital depends on our ability to generate cash in the future. This,
+to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. We cannot assure you that our business will generate sufficient cash flow from operations or from
+other sources in an amount sufficient to enable us to service our debt or to fund our other liquidity needs. In the year ended December 31, 2019, our operations used $9.1 million in cash. If our cash flow and capital resources are insufficient to
+allow us to make scheduled payments on our debt, we may need seek additional capital or restructure or refinance all or a portion of our debt on or before the maturity thereof, any of which could have a material adverse effect on our business,
+financial condition or results of operations. We cannot assure you that, if needed, we would be able to refinance any of our debt on commercially reasonable terms or at all, or that the terms of that debt will allow any of the above alternative
+measures or that these measures would satisfy our scheduled debt service obligations. If we are unable to generate sufficient cash flow to repay or refinance our debt on favorable terms, it could significantly adversely affect our financial
+condition. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition. Any refinancing of our debt could be at higher interest rates and may require us to comply with more
+onerous covenants, which could further restrict our business operations. There can be no assurance that we will be able to obtain any financing when needed. 
+Our Operating Results may be Negatively Affected by Changes in Foreign Currency Exchange Rates. 
+In the past our exposure to foreign currency exchange rate risk has not been material. Nevertheless, sales of our products are subject to currency risks, since changes in the values of foreign currencies relative to
+the value of the U.S. dollar can render our products comparatively more expensive. The fluctuations in the exchange rate could negatively impact international sales of our products, as could changes in the general economic conditions. 
+The revenues and expenses of Chembio Diagnostics Malaysia, opTricon and Orangelife, one of our subsidiaries, are recorded in Malaysian Ringgit, in Euros and Brazilian Real, respectively. Revenues and expenses
+denominated in foreign currencies are translated into U.S. dollars for purposes of reporting our consolidated financial results. Our expectation is that the Chembio Diagnostics Malaysia, opTricon and Orangelife businesses will continue to grow and,
+consequently, our exposure to foreign currency exchange rates may grow as well. 
+Our foreign subsidiaries’ revenues and expenses and the translation of their financial results into U.S. dollars may be negatively affected by fluctuations in the exchange rate. Favorable movement in exchange rates
+have benefited us in prior periods. However, where there are unfavorable currency exchange rate fluctuations, our consolidated financial statements could be negatively affected. Furthermore, fluctuations in exchange rates could affect year-to-year
+comparability of operating results. In the past, we have not generally entered into hedging instruments to manage our currency exchange rate risk, but we may need to do so in the future. However, our attempts to hedge against these risks may not be
+successful. If we are unable to successfully hedge against unfavorable foreign currency exchange rate movements, our consolidated financial results may be adversely impacted. 
+We Operate in Countries where there is or may be Widespread Corruption. 
+We have a policy in place prohibiting our employees, distributors and agents from engaging in corrupt business practices, including activities prohibited by the U.S. Foreign Corrupt Practices Act. Nevertheless,
+because we work through independent sales agents and distributors outside the United States, we do not have control over the day-to-day activities of such independent agents and distributors. In addition, in the donor-funded markets in Africa where
+we sell our products, there is significant oversight from PEPFAR, the Global Fund, and advisory committees comprised of technical experts concerning the development and establishment of national testing protocols. This is a process that includes
+an overall assessment of a product which includes extensive product performance evaluations including five active collaborations and manufacturer’s quality systems, as well as price and delivery. In Brazil, where we operate our subsidiary
+Orangelife and have had numerous product collaborations with FIOCRUZ, the programs through which our products may be deployed are all funded by the Brazilian Ministry of Health. Although FIOCRUZ is affiliated with the Brazilian Ministry of Health,
+and is its sole customer, FIOCRUZ is not the exclusive supplier for the Ministry of Health. However, because each of our previous collaborations with FIOCRUZ incorporates a technology transfer aspect, we believe we have a competitive advantage
+versus other suppliers to the Brazilian Ministry of Health, assuming other aspects of our product offering through FIOCRUZ are otherwise competitive in comparison. We have no knowledge or reason to know of any activities by our employees,
+distributors or sales agents of any actions which could be in violation of the FCPA, although there can be no assurance of this. 
+28 
+Table of Contents 
+Our subsidiary Chembio Diagnostics Malaysia Sdn. Bhd. is located in Malaysia. There have been numerous high-profile corruption cases, and corruption is one of the most problematic factors for doing business in
+Malaysia. While the Malaysian government has acknowledged the problem, it appears that endemic corruption is continuing and that market-based principles are not applied in cases involving individuals with high-level political access. To the extent
+bribery and similar practices continue to exist in Malaysia, U.S. companies such as ours, which are subject to U.S. laws making it illegal to pay bribes to foreign officials, may make us less competitive in winning business in Malaysia when
+competing with non-U.S. companies. 
+Changes in Interpretation or Application of U.S. Generally Accepted Accounting Principles may Adversely Affect Our Operating Results. 
+We prepare our financial statements to conform to U.S. generally accepted accounting principles. These principles are subject to interpretation by the Financial Accounting Standards Board, the American Institute of
+Certified Public Accountants, the Public Company Accounting Oversight Board, the Securities and Exchange Commission and various other regulatory or accounting bodies. A change in interpretations of, or our application of, these principles can have
+a significant effect on our reported results and may even affect our reporting of transactions completed before a change is announced. Additionally, as we are required to adopt new accounting standards, our methods of accounting for certain items
+may change, which could cause our results of operations to fluctuate from period to period. For example, upon adoption of Accounting Standards Codification (“ASC”) 606 Revenue from Contracts with Customers of the Financial Accounting Standards
+Board (“FASB”), we now recognize revenue upon transfer of control, which is generally at time of delivery. Under the previous accounting guidance, we recognized revenue upon acceptance when and if we had production responsibilities. If
+circumstances change over time or interpretation of the revenue recognition rules change, we could be required to adjust the timing of recognizing revenue and our financial results could suffer. 
+We Base Our Estimates or Judgments Relating to Critical Accounting Policies on Assumptions that can Change or Prove to be Incorrect. 
+Our financial statements have been prepared in accordance with accounting principles generally accepted in the United States and our discussion and analysis of financial condition and results of operations is based
+on such statements. The preparation of financial statements requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. We continuously evaluate significant estimates
+used in preparing our financial statements, including those related to (i) revenue recognition; (ii) stock-based compensation; (iii) allowance for uncollectible accounts receivable; (iv) inventory reserves and obsolescence; (v) customer sales
+returns and allowances; (vi) contingencies; and (vii) income taxes, (viii) goodwill and intangibles, (ix) business acquisition, and (x) research and development costs. 
+Our estimates are based on historical experience and various other assumptions that we believe to be reasonable, as set forth in our discussion and analysis of financial condition and results of operations, the
+results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these and other estimates if our assumptions change or if
+actual circumstances differ from those in our assumptions. If our operating results fall below the expectations of securities analysts and investors, the price of our Common Stock may decline. 
+Our Global Operations may be Adversely Effected by the Coronavirus Outbreak and Face Risks that could Impact our Business. 
+A novel strain of coronavirus, COVID-19, originated in Wuhan, China, in December 2019. As of March 2020, the virus has spread globally, including to the United States, Malaysia, Germany and Brazil. Our business operations in those locations
+are subject to potential business interruptions arising from protective measures that may be taken by the respective governments, agencies or other governing bodies in each country. Business disruptions in other countries also could negatively
+affect the sources and availability of components and materials that are essential to the operation of our business. Extended periods of interruption to our U.S. or international operations due to the coronavirus outbreak could adversely impact
+the growth of our business, could cause us to cease or delay operations, and could prevent our customers from receiving shipments or processing payments. 
+The extent to which the coronavirus impacts our global business, sales and results of operations will depend on future developments, which are highly uncertain and cannot be predicted. This includes new information that may emerge concerning
+the severity of the coronavirus, the spread and proliferation of the coronavirus around the world, and the actions taken to contain the coronavirus or treat its impact, among others. 
+29 
+Table of Contents 
+Our Business may be Negatively Affected by Terrorist Attacks or Natural Disasters. 
+Terrorist attacks or natural disasters could cause economic instability. These events could negatively affect economic conditions both within and outside the United States and harm demand for our products. The
+operations of our customers and suppliers could be negatively impacted and eliminate, reduce or delay our customers’ ability to purchase and use our products and our suppliers’ ability to provide raw materials and finished products. 
+Our facilities, including some pieces of manufacturing equipment and our computer systems, may be difficult to replace. Various types of disasters, including fires, earthquakes, floods and acts of terrorism, may
+affect our facilities and computer systems. In the event our existing facilities or computer systems are affected by man-made or natural disasters, we may have difficulty operating our business and may be unable to manufacture products for sale or
+meet customer demands or sales projections. If our manufacturing operations were curtailed or shut down entirely, it would seriously harm our business. 
+Risks Related to Intellectual Property 
+Our Success Depends on Our Ability to Protect Our Proprietary Technology. We Rely on Trade Secret Laws and Agreements with Our Key Employees and Other Third Parties to Protect Our Proprietary
+Rights, and We cannot be sure that these Laws or Agreements will Adequately Protect Our Rights. 
+Our industry places considerable importance on obtaining patent, trademark and trade secret protection, as well as other intellectual property rights, for new technologies, products and processes. Our success
+depends, in part, on our ability to develop and maintain a strong intellectual property portfolio or obtain licenses to patents and technologies, both in the United States and in other countries. If we cannot continue to develop, obtain and protect
+intellectual property rights, our revenues and gross profits could be adversely affected. Moreover, our current and future licenses or other rights to patents and other technologies may not be adequate for the operation of our business. 
+As appropriate, we intend to file patent applications and obtain patent protection for our proprietary technology. These patent applications and patents will cover, as applicable, compositions of matter for our
+products, methods of making those products, methods of using those products and apparatuses relating to the use or manufacture of those products. However, there have been changes to the patent laws and proposed changes to the rules of the U.S.
+Patent and Trademark Office, which may impact our ability to protect our technology and enforce our intellectual property rights. For example, in 2011, the U.S. enacted sweeping changes to the U.S. patent system under the Leahy-Smith America
+Invents Act, including changes that would transition the U.S. from a “first-to-invent” system to a “first-to-file” system and alter the processes for challenging issued patents. These changes could increase the uncertainties and costs surrounding
+the prosecution of our patent applications and the enforcement or defense of our issued patents. 
+We believe that factors such as the technological and creative skills of our personnel, strategic relationships, new product developments, frequent product enhancements and name recognition are essential to our
+success. All our management personnel are bound by non-disclosure agreements. If personnel leave our employment, in some cases we would be required to protect our intellectual property rights pursuant to common law theories which may be less
+protective than provisions of employment, non-competition or non-disclosure agreements. 
+We seek to protect our proprietary products under trade secret and copyright laws, enter into license agreements for various materials and methods employed in our products, and enter into strategic relationships for
+distribution of the products. These strategies afford only limited protection. We currently have some foreign patents issued, and we are seeking additional patent protection in several other foreign jurisdictions for our DPP and optical
+technology. We have licenses to reagents (antigens and peptides) used in several of our products and products under development. Despite our efforts to protect our proprietary assets, and respect the intellectual property rights of others, we
+participate in several markets where intellectual property rights protections are of little or no value. This can place our products and our company at a competitive disadvantage. 
+30 
+Table of Contents 
+Moreover, issued patents remain in effect for a fixed period and after expiration will not provide protection of the inventions they cover. Once our patents expire, we may be faced with increased competition, which
+could reduce our revenues. We may also not be able to successfully protect our rights to unpatented trade secrets and know-how. 
+To facilitate development and commercialization of a proprietary technology base, we may need to obtain additional licenses to patents or other proprietary rights from other parties. Obtaining and maintaining these
+licenses, which may not be available, may require the payment of up-front fees and royalties. In addition, if we are unable to obtain these types of licenses, our product development and commercialization efforts may be delayed or precluded. 
+Any Future Intellectual Property Disputes could Require Significant Resource and Limit or Eliminate Our Ability to Sell Products or Use Certain Technologies. 
+We may be required to expend substantial resources in asserting or protecting our intellectual property rights, or in defending suits related to intellectual property rights. We may seek to enforce our patents or
+other intellectual property rights through litigation. Such litigation is prevalent and is expected to continue. In our business, there are a large number of patents and patent applications similar to our products, and additional patents may be
+issued to third parties relating to our product areas. We, our customers or our suppliers may be sued for infringement of patents or misappropriation of other intellectual property rights with respect to one or more of our products. We may also
+have disputes with parties that license patents to us if we believe the license is no longer needed for our products or the licensed patents are no longer valid or enforceable. 
+There are a large number of patents in our industry, and the claims of these patents appear to overlap in many cases. Therefore there is a significant amount of uncertainty regarding the extent of patent protection
+and infringement. Companies may have pending patent applications, which are typically confidential for the first eighteen months following filing that cover technologies we incorporate in our products. Accordingly, we may be subjected to
+substantial damages for past infringement or be required to modify our products or stop selling them if it is ultimately determined that our products infringe a third party’s proprietary rights. In addition, governmental agencies could commence
+investigations or criminal proceedings against our employees or us relating to claims of misuse or misappropriation of another party’s proprietary rights. 
+If we are involved in litigation or other legal proceedings with respect to patents or other intellectual property and proprietary technology, it could adversely affect our revenues, results of operations, market
+share and business because (1) it could consume a substantial portion of managerial and financial resources; (2) its outcome would be uncertain and a court may find that our patents are invalid or unenforceable in response to claims by another
+party or that the third-party patent claims are valid and infringed by our products; (3) the pendency of any litigation may in and of itself cause our distributors and customers to reduce or terminate purchases of our products; (4) a court could
+award a preliminary and/or permanent injunction, which would prevent us from selling our current or future products; and (5) an adverse outcome could subject us to the loss of the protection of our patents or to liability in the form of past
+royalty payments, penalties, reimbursement of litigation costs and legal fees, special and punitive damages, or future royalty payments, any of which could significantly affect our future earnings. 
+Under certain contracts with third parties, we may indemnify the other party if our products or activities have actually or allegedly infringed upon, misappropriated or misused another party’s proprietary rights.
+Furthermore, our products may contain technology provided to us by third parties, and we may be unable to determine in advance whether such technology infringes the intellectual property rights of a third party. These other parties may also not be
+required or financially able to indemnify us in the event that an infringement or misappropriation claim is asserted against us. 
+There may also be other types of disputes that we become involved in regarding intellectual property rights, including state, federal or foreign court litigation, and patent interference, patent reissue, patent
+reexamination, or trademark opposition proceedings in the United States Patent and Trademark Office. Opposition or revocation proceedings could be instituted in a foreign patent office as well. These proceedings permit certain persons to challenge
+the validity of a patent on the grounds that it was known from the prior art. The filing of such proceedings, or the issuance of an adverse decision in such proceedings, could result in the loss of valuable patent rights that could have a material
+adverse effect on our business, financial condition, results of operations and growth prospects. 
+31 
+Table of Contents 
+Risks Related to Our Third Party Collaborators 
+Our Use of Third-Party Suppliers, some of which may Constitute Our Sole Supply Source, for Certain Important Product Components and Materials Presents Risks that Could Have Negative Consequences
+for Our Business. 
+We purchase certain HIV antigens, a syphilis antigen, the nitrocellulose, and certain other critical components used in our STAT-PAK, STAT-VIEW, SURE CHECK and DPP product lines from a sole or limited number of
+sources. If for any reason these suppliers become unwilling or unable to supply our antigen, nitrocellulose, or other critical component needs, we believe that alternative supplies could be obtained at a competitive cost. However, a change in any
+of the antigens, nitrocellulose or other critical components used in our products would require additional development work and approval by the FDA and other regulatory agencies. In addition, it may be difficult to find such an alternate supply
+source in a reasonable time period or on commercially reasonable terms, if at all. As a result, the termination or limitation of our relationship with one or more of these suppliers could require significant time to complete, increase our costs,
+and disrupt or discontinue our ability to manufacture and sell the affected products. 
+With some of these suppliers, we do not have long-term agreements and instead purchase components and materials through a purchase order process. As a result, these suppliers may stop supplying us components and
+materials, limit the allocation of supply and equipment to us due to increased industry demand, or significantly increase their prices at any time with little or no advance notice. Our reliance on a limited number of suppliers could also result in
+delivery problems, reduced control over product pricing and quality, and our inability to identify and qualify another supplier in a timely manner. 
+Moreover, some of these suppliers may experience financial difficulties that could prevent them from supplying us with components or subassemblies used in the design and manufacture of our products. In addition,
+these suppliers may experience manufacturing delays or shut downs due to circumstances beyond their control, such as labor issues, political unrest or natural disasters. 
+Any supply deficiencies could materially and adversely affect our ability to fulfill customer orders and our results of operations. The availability of critical components and materials from sole- or limited source
+suppliers could reduce our control over pricing, quality and timely delivery, increase our costs, could disrupt our ability to manufacture and sell, and preclude us from manufacturing and selling, certain of our products into one or more markets.
+Any such event could have a material adverse effect on our results of operations, cash flow and business. 
+We May Work with Strategic Collaborators to Assist in Developing and Commercializing Our Products, which could Limit Rights We Receive from the Collaborations and Exposes Us to Other Risks Outside
+Our Control. 
+Some business opportunities that require a technology controlled by a third party, a significant level of investment for development and commercialization or a distribution network beyond our existing sales force may
+necessitate involving one or more strategic collaborators. As part of our strategy for development and commercialization of our products, we may enter into arrangements with distributors or other third-parties. Relying on such collaborative
+relationships could be risky to our business for a number of reasons, including: (i) we may be required to transfer material rights to such strategic collaborators, licensees and others; (ii) our collaborators may not obtain regulatory approvals
+necessary to continue the collaborations in a timely manner; (iii) our collaborators may decide to terminate our collaborative arrangement or become insolvent; (iv) our collaborators may develop technologies or components competitive with our
+products; (v) disagreements with collaborators could result in the termination of the relationship or litigation; and (vi) we may not be able to agree to future collaborative arrangements, or renewals of existing collaborative agreements, on
+acceptable terms or at all. 
+32 
+Table of Contents 
+We expect our collaborators will have an economic motivation to succeed in performing their contractual responsibilities under our agreements, there is no assurance that they will do so. Due to our reliance on
+strategic agreements, it can make it difficult to accurately forecast our future revenues and operating results. 
+Our Ability to Grow Our Business will be Limited if We Fail to Maintain Existing Distribution Channels or Develop New Distribution Channels. 
+We collaborate with laboratories, diagnostic companies and distributors in order to sell our products. The sale of our products depends in large part on our ability to sell products to these customers and on the
+marketing and distribution abilities of the companies with which we collaborate and work with. 
+By relying on distributors or third-parties to market and sell our products could negatively impact our business for various reasons, including: (i) we may not be able to find suitable distributors for our products
+on satisfactory terms, or at all; (ii) agreements with distributors may prematurely terminate or may result in litigation between the parties; (iii) our distributors or other customers may not fulfill their contractual obligations and distribute
+our products in the manner or at the levels we expect; (iv) our distributors may prioritize their own private label products that compete with our products; (v) Our existing distributor relationships or contracts may preclude or limit us from
+entering into arrangements with other distributors; and (vi) we may not be able to negotiate new or renew existing distribution agreements on acceptable terms, or at all. 
+We will try to maintain and expand our business with distributors and customers and make every effort to require that they fulfill their contractual obligations, but there can be no assurance that such companies will
+do so or that new distribution channels will be available on satisfactory terms. If we are unable to do so, our business will be negatively impacted. 
+Our U.S. Government Contracts Require Compliance with Numerous Laws and Increases Our Risk and Liability. 
+We are currently receiving funding from the U.S. government related to DPP Zika, and our growth strategy targets sales to U.S. government entities. As a result of our U.S. government funding and potential product
+sales to the U.S. government, we must comply with laws and regulations relating to the award, administration and performance of U.S. government contracts. U.S. government contracts typically contain a number of extraordinary provisions that would
+not typically be found in commercial contracts and which may create a disadvantage and additional risks to us as compared to competitors that do not rely on government contracts. As a U.S. government contractor, we are subject to increased risks of
+investigation, criminal prosecution and other legal actions and liabilities to which purely private sector companies are not. The results of any such actions could adversely impact our business and have an adverse effect on our consolidated
+financial performance. 
+A violation of specific laws and regulations could result in the imposition of fines and penalties or the termination of our contracts, as well as suspension or debarment. The suspension or debarment in any
+particular case may be limited to the facility, contract or subsidiary involved in the violation or could be applied to our entire enterprise in certain severe circumstances. Even a narrow scope suspension or debarment could result in negative
+publicity that could adversely affect our ability to renew contracts and to secure new contracts, both with the U.S. government and private customers, which could materially and adversely affect our business and results of operations. Fines and
+penalties could be imposed for failing to follow procurement integrity and bidding rules, employing improper billing practices or otherwise failing to follow rules relating to billing on cost-plus contracts, receiving or paying kickbacks, or filing
+false claims, among other potential violations. In addition, we could suffer serious reputational harm and the value of our Common Stock could be negatively affected if allegations of impropriety related to such contracts are made against us. 
+33 
+Table of Contents 
+Our U.S. Government Contracts are Subject to Future Funding and the Government’s Choice to Exercise Options, and may be Terminated at the Government’s Convenience. 
+Our contracts with the U.S. government are subject to future funding and are subject to the right of the government to terminate the contracts in whole or in part for its convenience. There is pressure for the U.S.
+government to reduce spending. The non-appropriation of funds or the termination for the government’s convenience of our contracts could negatively affect our financial results. If levels of U.S. government expenditures and authorizations for
+emerging diseases decrease or shift to programs in areas where we do not offer products or are not developing product candidates, or if the U.S. government otherwise declines to exercise its options under its contracts with us, our business,
+revenues and other operating results would suffer. 
+Risks Related to Regulations 
+Because We may not be Able to Obtain or Maintain the Necessary Regulatory Approvals for Some of Our Products, We may not Generate Revenues in the Amounts We Expect, or in the Amounts Necessary to
+Continue Our Business. Our Existing Products as well as Our Manufacturing Facility Must Meet Quality Standards and are Subject to Inspection by a Number of Domestic Regulatory and Other Governmental and Non-Governmental Agencies. 
+All of our proposed and existing products are subject to regulation in the U.S. by the U.S. Food and Drug Administration, the U.S. Department of Agriculture and/or other domestic and international governmental,
+public health agencies, regulatory bodies or non-governmental organizations. In particular, we are subject to strict governmental controls on the development, manufacture, labeling, distribution and marketing of our products. The process of
+obtaining required approvals or clearances varies according to the nature of, and uses for, a specific product. These processes can involve lengthy and detailed laboratory testing, human or animal clinical trials, sampling activities, and other
+costly, time-consuming procedures. The submission of an application to a regulatory authority does not guarantee that the authority will grant an approval or clearance for that product. Each authority may impose its own requirements and can delay
+or refuse to grant approval or clearance, even though a product has been approved in another country. 
+The time taken to obtain approval or clearance varies depending on the nature of the application and may result in the passage of a significant period of time from the date of submission of the application. Delays
+in the approval or clearance processes increase the risk that we will not succeed in introducing or selling the subject products, and we may determine to devote our resources to different products. 
+Changes in government regulations could increase our costs and could require us to undergo additional trials or procedures, or could make it impractical or impossible for us to market our products for certain uses,
+in certain markets, or at all. 
+Changes in government regulations may adversely affect our financial condition and results of operations because we may have to incur additional expenses if we are required to change or implement new testing,
+manufacturing and control procedures. If we are required to devote resources to develop such new procedures, we may not have sufficient resources to devote to research and development, marketing, or other activities that are critical to our
+business. 
+We can manufacture and sell our products only if we comply with regulations and quality standards established by government agencies such as the FDA and the U.S. Department of Agriculture as well as by
+non-governmental organizations such as the ISO and WHO. We have implemented a quality control system that is intended to comply with applicable regulations. Although FDA approval is not required for the export of our products, there are export
+regulations promulgated by the FDA that specifically relate to the export of our products that require compliance with FDA QSRs and that also require meeting certain documentary requirements regarding the approval of the product in export markets. 
+34 
+Table of Contents 
+If We do not Comply with FDA or Other Regulatory Requirements, We may be Required to Suspend Production or Sale of Our Products or Institute a Recall, which could Result in Higher Costs and a Loss
+of Revenues. 
+Regulations of the FDA and other federal, state and foreign regulatory agencies have significant effects on many aspects of our operations, and the operations of our suppliers and distributors, including packaging,
+labeling, manufacturing, adverse event reporting, recalls, distribution, storage, advertising, promotion and record keeping. We are subject to routine inspection by the FDA and other agencies to determine compliance with QSRs and FDA regulatory
+requirements in the United States and other applicable regulations worldwide, including but not limited to ISO standards. We believe that our facilities and procedures are in material compliance with the FDA requirements and ISO standards, but the
+regulations may be unclear and are subject to change, and we cannot be sure that the FDA or other regulators will agree with our compliance with these requirements. The FDA and foreign regulatory agencies may require post-marketing testing and
+surveillance to monitor the performance of approved or cleared products or impose conditions on any product clearances or approvals that could restrict the distribution or commercial applications of those products. Regulatory agencies may impose
+restrictions on our or our distributors’ advertising and promotional activities or preclude these activities altogether if a noncompliance is believed to exist. In addition, the subsequent discovery of previously unknown problems with a product may
+result in restrictions on the product or additional regulatory actions, including withdrawal of the product from the market. 
+Our inability to comply with the applicable requirements of the FDA can result in, among other things, 483 notices, warning letters, administrative or judicially imposed sanctions such as injunctions, recall or
+seizure of products, civil penalties, withdrawal of product registrations, total or partial suspension of production, refusal to grant premarket clearance for devices, a determination that a device is not approvable, marketing clearances or
+approvals, or criminal prosecution. For example, in February 2020, we received a “not approvable” letter from the U.S. Food and Drug Administration with respect to our premarket approval submission on our DPP HIV-Syphilis multiplex test for
+commercial use in the United States. The ability of our suppliers to supply critical components or materials and of our distributors to sell our products could also be adversely affected if their operations are determined to be out of compliance.
+Such actions by the FDA and other regulatory bodies could adversely affect our revenues, costs and results of operations. 
+We must frequently make judgment decisions with respect to compliance with applicable laws and regulations. If regulators subsequently disagree with how we have sought to comply with these regulations, we could be
+subjected to substantial civil and criminal penalties, as well as product recall, seizure or injunction with respect to the sale of our products. Our reputation could be substantially impaired if we are assessed any civil and criminal penalties and
+limit our ability to manufacture and market our products which could have a material adverse effect on our business. 
+Our Inability to Respond to Changes in Regulatory Requirements could Adversely Affect Our Business. 
+We believe that our products and procedures are in material compliance with all applicable FDA regulations, ISO requirements, and other applicable regulatory requirements, but the regulations regarding the
+manufacture and sale of our products, the QSR and ISO requirements, and other requirements may be unclear and are subject to change. Newly promulgated regulations could require changes to our products, necessitate additional clinical trials or
+procedures, or make it impractical or impossible for us to market our products for certain uses, in certain markets, or at all. The FDA and other regulatory authorities also have the ability to change the requirements for obtaining product approval
+and/or impose new or additional requirements as part of the approval process. These changes or new or additional requirements may occur after the completion of substantial clinical work and other costly development activities. The implementation of
+such changes or new or additional requirements may result in additional clinical trials and substantial additional costs and could delay or make it more difficult or complicated to obtain approvals and sell our products. In addition, the FDA may
+revoke an Emergency Use Authorization under which our products are sold, where it is determined that the underlying health emergency no longer exists or warrants such authorization. Such revocation would preclude the sale of our affected products
+unless and until a further regulatory approval or authorization is obtained. We cannot predict the effect, if any, that these changes might have on our business, financial condition or results of operations. 
+35 
+Table of Contents 
+Demand for Our Products may be Affected by FDA Regulation of Laboratory-Developed Tests and Genetic Testing. 
+Regulatory responsibility over instruments, test kits, reagents and other devices used to perform diagnostic testing by clinical laboratories is covered by the FDA. The FDA has previously taken the position that it
+has regulatory authority over laboratory-developed tests, or LDTs, but has exercised enforcement discretion by not regulating most LDTs performed by high complexity CLIA-certified laboratories. LDTs are tests designed, developed, and performed
+in-house by a laboratory. These laboratories are subject to CLIA regulation but such laboratories have previously not been subject to regulation by FDA under the agency’s medical device requirements. 
+However, the FDA has announced that it would begin regulating LDTs, and in October 2014 the FDA issued proposed guidance on the regulation of LDTs for public comment. But, on November 18, 2016, the FDA announced that
+it would not finalize the proposed guidance prior to the end of the Obama administration. On January 13, 2017, the FDA released a discussion paper synthesizing public comments on the 2014 draft guidance documents and outlining a possible approach
+to regulation of LDTs. The discussion paper has no legal status and does not represent a final version of the LDT draft guidance documents. We cannot predict what policies the Trump administration will adopt with respect to LDTs. If the FDA
+increases regulation of LDTs, it could make it more difficult for laboratories and other customers to continue offering LDTs that involve genetic or molecular testing. This, in turn, could reduce demand for our products and adversely impact our
+revenues. 
+In Addition to FDA Requirements, We Are Subject to Several Government Regulations, Compliance with which could Increase Our Costs and Affect Our Operations. 
+In addition to the FDA regulations previously described, laws and regulations in some states may restrict our ability to sell products in those states. 
+We must comply with numerous laws related to safe working conditions, environmental protection, disposal of hazardous substances, fire hazard control, manufacturing practices and labor or employment practices.
+Compliance with these laws or any new or changed laws regulating our business could result in substantial costs. Due to the number of laws and regulations governing our industry, and the actions of a number of government agencies that could affect
+our operations, it is impossible to reliably predict the full nature and impact of these laws and regulations. To the extent the costs and procedures associated with complying with these laws and requirements are substantial or it is determined
+that we do not comply, our business and results of operations could be adversely affected. 
+We may Incur Additional Costs if We do not Comply with Privacy, Security and Breach Notification Regulations. 
+We believe that we are not a covered entity nor a business associate of a covered entity and are not responsible for complying with the Health Insurance Portability and Accountability Act of 1996, or HIPAA. Even
+though we likely are not a covered entity under HIPAA, we do have in place administrative, technical and physical safeguards to protect the privacy and security of consumers’ personal information.] We are required to comply with varying state
+privacy, security and breach reporting laws. If we fail to comply with existing or new laws and regulations related to properly transferring data containing consumers’ personal information, we could be subject to monetary fines, civil penalties or
+criminal sanctions. Also, there are other federal and state laws that protect the privacy and security of consumers’ personal information, and we may be subject to enforcement by various governmental authorities and courts resulting in complex
+compliance issues. We could incur damages under state laws pursuant to an action brought by a private party for the wrongful use or disclosure of consumers’ personal information. 
+36 
+Table of Contents 
+Failure to Comply With Recent European Data Protection Requirements could Increase Our Costs. 
+The EU has adopted a comprehensive overhaul of its data protection regime from the prior national legislative approach to a single European Economic Area Privacy Regulation called the General Data Protection
+Regulation, or GDPR, which came into effect on May 25, 2018. The new EU data protection regime extends the scope of the EU data protection law to all foreign companies processing data of EU residents. It imposes a strict data protection compliance
+regime with severe penalties of up to the greater of 4% of worldwide turnover and €20 million and includes new rights such as the “portability” of personal data. Although the GDPR will apply across the EU without a need for local implementing
+legislation, as had been the case under the prior data protection regime, local data protection authorities will still have the ability to interpret the GDPR, which has the potential to create inconsistencies on a country-by-country basis. We are
+evaluating these new requirements and implementing a plan to ensure compliance. Complying with the enhanced obligations imposed by the GDPR may result in significant costs to our business and require us to amend certain of our business practices.
+Further, we have no assurances that violations will not occur, particularly given the complexity of the GDPR, as well as the uncertainties that accompany new, comprehensive legislation. 
+If We are not Able to Manufacture Products in Accordance with Applicable Requirements, It could Adversely Affect Our Business. 
+Our products must meet detailed specifications, performance standards and quality requirements. As a result, our products and the materials used in their manufacture or assembly undergo regular inspections and
+quality testing. Factors such as defective materials or processes, mechanical failures, human errors, environmental conditions, changes in materials or production methods, and other events or conditions could cause our products or the materials
+used to produce or assemble our products to fail inspections and quality testing or otherwise not perform in accordance with our label claims or the expectations of our customers. 
+If we are not able to meet the applicable specifications, performance standards, quality requirements or customer expectations could adversely affect our ability to manufacture and sell our products or comply with
+regulatory requirements. These events could, in turn, adversely affect our revenues and results of operations. 
+Healthcare Fraud and Abuse Laws Could Adversely Affect Our Business and Results of Operations. 
+There are various federal and state laws targeting fraud and abuse in the healthcare industry to which we are subject, including anti-kickback laws, laws constraining the sales, false claims laws, marketing and
+promotion of medical devices by limiting the kinds of financial arrangements that manufacturers of these products may enter into with physicians, hospitals, laboratories and other potential purchasers of medical devices. There are other laws we are
+subject to that require us to report certain transactions between it and healthcare professionals. Violations of these laws are punishable by criminal or civil sanctions, including substantial fines, imprisonment and exclusion from participation in
+government healthcare programs. Many of the existing requirements are new and have not been definitively interpreted by state authorities or courts, and available guidance is limited. We could face enforcement action and fines and other penalties,
+and could receive adverse publicity, unless and until we are in full compliance with these laws, all of which could materially harm us. Furthermore, changes in or evolving interpretations of these laws, regulations, or administrative or judicial
+interpretations, may require us to change our business practices or subject our business practices to legal challenges, which could have a material adverse effect on our business, financial condition and results of operations. 
+37 
+Table of Contents 
+Our Compliance with Regulations Governing Public Companies is Complex and Expensive. 
+Public companies are subject to various laws and regulations, which have increased the scope, complexity and cost of corporate governance, reporting and disclosure practices. For example, we are subject to the
+Sarbanes-Oxley Act of 2002, The Dodd-Frank Wall Street Reform and Consumer Protection Act and the requirements of The NASDAQ Global Market. The implementation of certain aspects of these laws and regulations has required and will continue to
+require substantial management time and oversight and may require us to incur significant additional accounting and legal costs. We continually review changes with respect to new and proposed rules and cannot predict or estimate the amount of
+additional costs, and the timing of such costs, we may incur. There are several interpretations of these laws and regulations, in many cases due to their lack of specificity, and as a result, their application in practice may change as new guidance
+is provided by regulatory and governing bodies. This may result in continuing uncertainty regarding compliance matters and higher costs. We are committed to maintaining high standards of corporate governance and public disclosure, but if we fail to
+comply with any of these requirements, legal proceedings may be initiated against us, which may adversely affect our business. 
+Risks Related to Our Common Stock 
+Our Common Stock has Limited Liquidity, and Investors may not be Able to Sell as Much Stock as They Want at Prevailing Market Prices or at all. 
+The liquidity of our Common Stock depends on several factors, including but not limited to our financial results and overall market conditions, so it is not possible to predict whether this level of liquidity will
+continue, be sustained, or decrease. Decreased trading volume in our stock would make it more difficult for investors to sell their shares in the public market at any given time at prevailing prices. Our management and larger stockholders exercise
+significant control over our company. 
+The Price of Our Common Stock could Continue to be Volatile. 
+The price of our Common Stock has been volatile and may be volatile in the future. The following factors, among others, could have a significant impact on the market for our Common Stock: (1) the performance of our
+business; (2) clinical results with respect to our products or those of our competitors; (3) the gain or loss of significant contracts and availability of funding for the purchase of our products; (4) actions undertaken by the Congress or the
+Presidential Administration; (5) changes in our relations with our key customers, distributors or suppliers; (6) developments in patent or other proprietary rights; (7) litigation or threatened litigation; (8) general market and economic
+conditions; (9) the relatively low trading volume for our Common Stock; (10) changes in competition; (11) Complaints or concerns about the performance or safety of our products and publicity about those issues, including publicity expressed through
+social media or otherwise over the internet; (12) failure to achieve, or changes in, financial estimates by securities analysts and comments or opinions about us by securities analysts or major stockholders; (13) announcement of regulatory or
+enforcement actions by the FDA or other agencies against us, our products or our customers; (14) changes in our operating results; and (15) terrorist attacks, civil unrest, war and national disasters. 
+Overall, the stock market has experienced price and volume fluctuations that have affected the market price of our Common Stock, as well as the stock of many other similar companies. Such price fluctuations are
+generally unrelated to the operating performance of the specific companies whose stock is affected. 
+After the volatility in the market price of a company’s stock, class action litigation has occurred against the issuing company. If we were subject to this type of litigation in the future, we could incur substantial
+costs and the attention and resources of our management could be diverted, each of which could have a material adverse effect on our revenue and earnings. Any adverse determination in this type of litigation could also subject us to significant
+liabilities. 
+Any Future Issuances of Shares of Our Common Stock by Us Could Harm the Price of Our Common Stock and Our Ability to Raise Funds in New Equity Offerings. 
+Any future sales of a substantial number of our shares of Common Stock or other equity-related securities, or the perception that such sales may occur, could adversely affect the price of our Common Stock, and could
+impair our ability to raise capital through future offerings of equity or equity-related securities. 
+38 
+Table of Contents 
+Our Management and Larger Stockholders Exercise Significant Control Over Us. 
+As of December 31, 2019, 25.5% of our outstanding common stock was beneficially owned by our executive officers, directors and 5% stockholders including three large investors that beneficially own 21%, of our
+outstanding common stock. For the foreseeable future, and assuming these ownership percentages continue to apply, to the extent that these parties vote similarly, they may be able to exercise significant control over many matters requiring approval
+by the board of directors or our stockholders. As a result, they may be able to: 
+• 
+control the composition of our board of directors; 
+• 
+control our management and policies; 
+• 
+determine the outcome of significant corporate transactions, including changes in control that may be beneficial to stockholders; and, 
+• 
+act in each of their own interests, which may conflict with or differ from the interests of each other or the interests of the other stockholders. 
+Sales of Our Common Stock by Existing Stockholders, Executive Officers or Directors could Depress the Market Price of Our Common Stock. 
+If our existing stockholders, officers or directors sell our Common Stock in the public market, or the perception that such sales may occur, it could negatively affect the price of our Common Stock. We are unable to
+estimate the number of shares of our Common Stock that may actually be resold in the public market since this will depend on the market price for our Common Stock, the individual circumstances of the sellers and other factors. 
+Institutional stockholders own significant amounts of our Common Stock. If one or more of these stockholders sell large portions of their holdings in a relatively short time, the prevailing price of our Common Stock
+could be negatively affected. In addition, it is possible that one or more of our executive officers or non-employee members of our Board of Directors could sell shares of our Common Stock during an open trading window. These transactions and the
+perceived reasons for these transactions could have a negative effect on the prevailing market price of our Common Stock. 
+We do not Intend to Pay Cash Dividends on Our Common Stock. 
+We do not expect to pay any cash dividends on our Common Stock and currently intend to retain our earnings, if any, to finance the expansion of our business. Therefore, the success of an investment in our Common
+Stock will depend entirely upon any future increase in value of our Common Stock. There is no guarantee that our Common Stock will gain value or even maintain the price at which investors purchased their shares. 
+39 
+Table of Contents 
+ITEM 2. 
+PROPERTIES 
+Our U.S. manufacturing, administrative offices, and research facilities are located in leased space in Medford, New York, pursuant to a lease covering approximately 39,650 square feet and expiring on June 30, 2021. 
+On February 5, 2019, we entered into a commercial real estate lease for new corporate headquarters comprised of 70,000 square feet of office, research and development, and warehouse space located in Hauppauge, New
+York. The lease has an initial term of eleven years that can be extended, at our option, for two additional terms of five years each. Rent under the lease, which is payable in monthly installments, totals approximately $900,000 for the initial year
+and then increases by approximately three percent each succeeding year. 
+On February 5, 2019, we also entered into an agreement to sublet the space at Holbrook, New York. The sublease has a term that (a) commenced on the date we vacate the premises and (b) terminate on April 29, 2020. The
+sublessee has paid us 50% of our rent and additional rent payments, which will total approximately $100,000 per year during the term of the sublease. 
+Our European headquarters and Center of Excellence for Optical Technology is located in leased office and manufacturing space in Berlin, Germany. Our Southeast Asia manufacturing, warehouse, and commercial facilities
+are located in leased space in Kuala Lumpur, Malaysia. Our Latin America manufacturing, warehouse, and commercial facilities are located in Rio de Janeiro, Brazil. We regularly review our real estate portfolio and develop footprint strategies to
+support our customers’ global plans, while at the same time supporting our technical needs and controlling operating expenses. 
+ITEM 3. 
+LEGAL PROCEEDINGS 
+From time to time we may become involved in legal proceedings or may be subject to claims arising in the ordinary course of our business. Although the results of litigation and claims cannot be predicted with
+certainty, we currently believe that the final outcome of these ordinary course matters will not have a material adverse effect on our business, operating results, financial condition or cash flows. Regardless of the outcome, litigation can have
+an adverse impact on us because of defense and settlement costs, diversion of management resources and other factors. 
+40 
+Table of Contents 
+PART II 
+ITEM 5. 
+MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+Listing Information 
+Our stock is listed on the NASDAQ Global Select Market of the NASDAQ Stock Market LLC under the symbol “CEMI.” 
+Holders 
+As of March 1, 2020 , there were 132 record owners of our Common Stock (including nominee holders such as banks and brokerage
+firms who hold shares for beneficial owners). 
+Recent Sales of Unregistered Securities 
+During the year ended December 31, 2019, we issued unregistered securities in connection with the acquisition of Orangelife. See Note 2 - Acquisitions, for further discussion. 
+Issuer Purchases of Equity Securities 
+We did not repurchase any of our equity securities during the year ended December 31, 2019. 
+41 
+Table of Contents 
+ITEM 7. 
+MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+The following discussion and analysis should be read in conjunction with the audited consolidated financial statements and related notes included in this report. In addition to historical
+information, the following discussion contains forward-looking statements that involves risks, uncertainties and assumptions. See “Special Note Regarding Forward-Looking Statements” at page 4 of this report. Please read “Item1A. Risk Factors” for a
+discussion of factors that could cause our actual results to differ materially from our expectations. 
+The following discussion is presented in six sections: 
+• 
+Executive Overview 
+• 
+Consolidated Results of Operations 
+• 
+Liquidity and Capital Resources 
+• 
+Significant Accounting Policies and Critical Accounting Estimates 
+• 
+Recently Issued Accounting Pronouncements 
+Executive Overview 
+Through our wholly owned subsidiaries, Chembio Diagnostic Systems Inc., Chembio Diagnostics Malaysia Sdn Bhd, Chembio Diagnostics Germany, and Chembio Diagnostics Brazil we develop, manufacture and commercialize
+point-of-care diagnostic tests that are used to detect or diagnose diseases. All products that are currently being developed are based on our patented DPP technology, a novel point-of-care diagnostic platform that offers certain customer advantages
+as compared to traditional lateral flow technology. Chembio was formed in 1985. 
+Recent operational accomplishments and highlights include: 
+• 
+Achieved product sales of $28.8 million for full year 2019, an increase of 3.3% over prior year 
+• 
+Achieved total revenue of $34.5 million for full year 2019, a decrease of 0.3% over prior year 
+• 
+Acquired Orangelife Comercio e Industria Ltda., a privately-held Brazilian manufacturer of lateral flow tests for infectious diseases to diversify and expand our market penetration in
+Brazil and support Bio-Manguinhos, a major customer. 
+• 
+Received WHO Prequalification approval for the HIV Self-Test and our Malaysian production facility 
+• 
+Successfully completed the technical feasibility phase for a rare disease with Takeda Pharmaceutical. 
+• 
+Initiated production on our fully-automated DPP test manufacturing line and took delivery of our second and third automated lines for our other product platforms. 
+We strengthened our balance sheet by entering a credit agreement with Perceptive Credit Holdings II, LP. for a $20 million term loan. See “—Liquidity and Capital Resources.” 
+The Company’s product commercialization and product development efforts are focused on infectious disease testing and technology collaborations. In infectious disease, the
+Company is commercializing tests for HIV and Syphilis, Zika virus, and developing tests for malaria, dengue virus, chikungunya virus, ebola, lassa , Marburg, leptospirosis, Rickettsia typhi , Burkholderia pseudomallei , and Orientia tsutsugamushi , individually or as part of fever panel tests. Through technology collaborations, the Company is developing tests
+for concussion, bovine tuberculosis, a rare disease in collaboration with Takeda Pharmaceutical, and a biomarker development project in collaboration with AstraZeneca. 
+Large and growing markets have been established for these kinds of tests, initially in high prevalence regions where they are indispensable for large scale prevention and treatment programs. Our product development
+is focused on areas where the availability of rapid point-of-care screening, diagnostic, or confirmatory results can improve health outcomes. More generally, we believe there is and will continue to be a growing demand for diagnostic products that
+can provide accurate, actionable diagnostic information in a rapid, cost-effective manner at the point of care. 
+Our products are sold to medical laboratories and hospitals, governmental and public health entities, non-governmental organizations, medical professionals and retail establishments, both domestically and
+internationally, under our STAT-PAK, SURE CHECK, STAT-VIEW or DPP registered trademarks, or under the private labels of our marketing partners. 
+42 
+Table of Contents 
+Consolidated Results of Operations 
+The results of operations for the years ended December 31, 2019 and 2018 were as follows: 
+Year Ended December 31, 
+2019 
+2018 
+TOTAL REVENUES 
+$ 
+34,464,032 
+100 
+% 
+$ 
+34,581,440 
+100 
+% 
+COSTS AND EXPENSES: 
+Cost of product sales 
+22,394,317 
+65 
+% 
+22,599,432 
+65 
+% 
+Research and development expenses 
+8,538,416 
+25 
+% 
+8,526,256 
+26 
+% 
+Selling, general and administrative expenses 
+16,138,424 
+47 
+% 
+11,100,775 
+33 
+% 
+Acquisition costs 
+721,465 
+2 
+% 
+337,645 
+1 
+% 
+47,792,622 
+139 
+% 
+42,564,108 
+25 
+% 
+LOSS FROM OPERATIONS 
+(13,328,590 
+) 
+(39 
+)% 
+(7,982,668 
+) 
+(23 
+)% 
+OTHER (LOSS)/INCOME 
+(846,831 
+) 
+(2 
+)% 
+49,498 
+0 
+% 
+LOSS BEFORE INCOME TAXES 
+(14,175,421 
+) 
+(41 
+)% 
+(7,933,170 
+) 
+(23 
+)% 
+Income tax benefit 
+(500,292 
+) 
+(2 
+)% 
+(67,521 
+) 
+0 
+% 
+NET LOSS 
+$ 
+(13,675,129 
+) 
+(39 
+)% 
+$ 
+(7,865,649 
+) 
+(23 
+)% 
+Percentages in the table reflect the percent of total revenues. 
+Total Revenues 
+Total revenues during the year ended December 31, 2019 were $34.5 million, a decrease of $0.1 million, or 0.3% compared to 2018. The decrease in total revenues was comprised of the following: 
+• 
+$0.9 million, or 3.3% increase in net product sales, reflecting gains in U.S., Europe, and Latin America, offset in part by lower sales in Africa and Asia. U.S. sales benefited from
+our winning back a large public health program and Latin America benefited from initial sales of Zika, Chikungunya, and Dengue Fever tests, both standalone and in the multiplex version. Europe includes contribution from our acquisition
+of Chembio Diagnostics GmbH in November 2018. Asia and Africa declines were affected by the timing of national tenders. 
+• 
+$1.0 million, or 15.7% decrease in R&D and grant, and license and royalty revenues compared to 2018, relating to the timing and cadence of customer program schedules and their
+related performance obligations. 
+Gross Product Margin 
+Cost of product sales is primarily comprised of material, labor, manufacturing overhead, depreciation and amortization, and other operating expenses. Gross product margin is net product sales less cost of product
+sales, and gross product margin percentage is gross product margin as a percentage of net product sales. 
+Gross product margin increased by $1.1 million, or 21.4% compared to 2018. The following schedule calculates gross product margin: 
+For the years ended December 31 
+Favorable/ 
+(unfavorable) 
+% Change 
+2019 
+2018 
+(in thousands) 
+Net product sales 
+$ 
+28,845 
+$ 
+27,913 
+$ 
+932 
+3.3 
+% 
+Less: Cost of product sales 
+(22,394 
+) 
+(22,599 
+) 
+205 
+(0.9 
+%) 
+Gross product margin 
+$ 
+6,451 
+$ 
+5,314 
+$ 
+1,137 
+21.4 
+% 
+Gross product margin % 
+22.4 
+% 
+19.0 
+% 
+The $1.1 million increase in gross product margin was comprised of the following: 
+• 
+$0.2 million from favorable product sales volume as described above, and 
+• 
+$0.9 million from favorable product margins, related to the impact of geographic mix on average selling price, initial benefits from our first automated assembly line, and reduced
+contract labor costs. 
+43 
+Table of Contents 
+Research and Development 
+This category includes costs incurred for clinical and regulatory affairs and other research and development, as follows: 
+For the years ended December 31 
+Favorable/ 
+(unfavorable) 
+% Change 
+2019 
+2018 
+(in thousands) 
+Clinical and regulatory affairs 
+$ 
+1,516 
+$ 
+1,307 
+$ 
+(209 
+) 
+(16.0 
+)% 
+Other research and development 
+7,022 
+7,219 
+197 
+2.7 
+% 
+Total research and development 
+$ 
+8,538 
+$ 
+8,526 
+$ 
+(12 
+) 
+(0.1 
+)% 
+The increase in clinical & regulatory affairs costs for 2019 as compared to 2018 is primarily associated
+with new product negotiations in new countries and around the world and clinical trial costs. The decrease in other research and development costs is correlates to the reduction in R&D revenue noted above. 
+Selling, General and Administrative Expense 
+Selling, general and administrative expense includes administrative expenses, sales and marketing costs including commissions, and other corporate items. The $5.0 million, or 45.4%
+increase in selling, general and administrative expenses for the year ended December 31, 2019 as compared to 2018 includes $0.9 million costs from Chembio Diagnostics
+Germany, $1.1 million higher non-cash equity compensation costs, and $0.7 million of rent and other costs related to leasing our new facility in Hauppauge, NY, which were partially non-cash in 2019 due to the lease terms. 
+Acqu isition Costs 
+Acquisition costs include legal, due diligence, audit, and related costs associated with acquisitions. The $0.4 million increase in acquisition costs for the year ended December 31, 2019
+as compared to 2018 is associated with spending related to acquisitions. During 2019, these included an audit required for Chembio Diagnostics Germany, as well as diligence and
+legal costs related to the acquisition of Chembio Dignostics Brazil in November 2019. 
+Other Income and Expense 
+Other income and expenses are principally interest income earned on our deposits, net of interest expense, which increased by approximately $0.9 million for 2019 as compared to 2018 due to the interest paid on the
+term loan debt the company entered into in September 2019. 
+Income Tax Provision 
+For 2019 we recognized a tax benefit of $0.6 primarily attributable to the loss generated by Chembio Diagnostics Malaysia. As of December 31, 2019 and 2018, the Company recorded a full valuation allowance against its
+net deferred tax assets. 
+Liquidity and Capital Resources 
+During 2019, we funded our business operations, including capital expenditures and working capital requirements, principally from cash and cash equivalents. Our operations used $9.1 million of cash. As of December
+31, 2019, we had outstanding debt (excluding leases) in the amount of $20.2 million (carrying amount of $17.7 million), consisting of loans of $20.0 million under a credit agreement entered into on September 3, 2019 (see “—Sources of Funds—Credit
+Agreement” below) and $0.2 million under a seller-financed note payable incurred in connection with our purchase of automated manufacturing equipment. 
+44 
+Table of Contents 
+We continually evaluate our liquidity requirements, capital needs and availability of capital resources based on our operating needs and our planned growth initiatives. We believe our existing cash and cash
+equivalents will be sufficient to meet our anticipated cash needs for at least the next twelve months. 
+Our future working capital needs will depend on many factors, including the rate of our business and revenue growth, the timing of our continuing automation of U.S. manufacturing, and the timing of investment in our
+research and development as well as sales and marketing. If, however, those sources of liquidity become insufficient to fund the growth of our business, we may need to reduce the level or slow the timing of its growth plans, which would likely
+curtail or delay the growth in our business contemplated by our operating plan and could impair or defer our ability to achieve profitability and generate cash flow, or to seek to raise additional funds through debt or equity financings, strategic
+relationships, or other arrangements, to the extent funding would be available to us on acceptable terms or at all. If we were to raise additional funds through the issuance of equity or convertible securities, the issuance could result in
+substantial dilution to existing stockholders, and the holders of these new securities or debt may have rights, preferences and privileges senior to those of the holders of common stock. 
+Sources of Funds 
+Credit Agreement. On September 3, 2019, we, as borrower, and certain of our subsidiaries, as guarantors, entered into a Credit Agreement and Guaranty, or the Credit Agreement, with Perceptive Credit Holdings II, LP,
+or the Lender. 
+• Principal Amount. The Credit Agreement provides for a $20,000,000 senior secured term loan credit facility, which was drawn in full on September 4, 2019. Under the terms of the Credit Agreement,
+we may use the proceeds (i) for general working capital purposes and other permitted corporate purposes, (ii) to refinance certain of our existing indebtedness and (iii) to pay fees, costs and expenses incurred in connection with the Credit
+Agreement, including the Lender’s closing cost amount of $550,000, which was netted from the proceeds, and a financing fee of $600,000 (3.0% of gross proceeds) payable to Craig-Hallum Capital Group LLC, our financial advisor for the financing. 
+• Interest Rate. Principal outstanding under the Credit Agreement bears interest at a rate per annum equal to the sum of (a) the greater of the one-month London Interbank Offered Rate and 2.5% plus
+(b) 8.75%. At any time at which an event of default (as described under “—Default Provisions” below) has occurred and is continuing, the interest rate will increase by 4.0%. Accrued interest is payable on a monthly basis. 
+• Scheduled Repayment. No principal repayments are due prior to September 30, 2022, unless we elect to prepay principal as described under “—Optional Prepayment” below or principal is accelerated
+pursuant to an event of default as described under “—Default Provisions” below. Principal installments in the amount of $300,000 are payable on the last day of each of the eleven months from September 2022 through July 2023, and all remaining
+principal is payable at maturity on September 3, 2023. 
+• Optional Prepayment. We may prepay outstanding principal from time to time, subject to payment of a premium on the prepaid principal amount equal to 10% through September 3, 2020, 8% from
+September 4, 2020 through September 3, 2021, and 4% from September 4, 2021 through September 3, 2022. 
+No premium will be due with respect to any prepayment made on or after September 4, 2022. 
+45 
+Table of Contents 
+• Guaranties. Our subsidiaries Chembio Diagnostic Systems Inc. and Chembio Diagnostics Malaysia Sdn Bhd. have guaranteed, and the Lender from time to time may require our other subsidiaries to
+guarantee, our obligations under the Credit Agreement. 
+• Security. Our obligations under the Credit Agreement are secured by a first priority, perfected lien on substantially all of our property and assets, including our equity interests in our
+subsidiaries. Our subsidiary Chembio Diagnostic Systems Inc. has secured its guarantee of our Credit Agreement obligations with a lien on substantially all of its assets, and the Lender from time to time may require Chembio Diagnostics Malaysia Sdn
+Bhd. and any of our other subsidiaries that has guaranteed our Credit Agreement obligations to do the same. 
+• Representations and Warranties; Financial and Other Covenants. In the Credit Agreement we made customary representations and warranties as well as customary affirmative and negative covenants,
+including covenants limiting additional indebtedness, liens, guaranties, mergers and acquisitions, substantial asset sales, investments and loans, sale and leasebacks, transactions with affiliates, and fundamental changes. The Credit Agreement also
+contains financial covenants requiring that (i) we maintain aggregate unrestricted cash of not less than $3,000,000 at all times and (ii) we achieve specified minimum rolling four-quarter (“last twelve month”) total revenue amounts as of September
+30, 2019 and the last day of each calendar quarter thereafter. The minimum total revenue amounts, which range from $32.0 million to $50.1 million, were developed for purposes of the Credit Agreement and do not reflect the internal estimates and
+plans used by our management and board of directors to understand and evaluate our operating performance, to establish budgets, and to establish operational goals for managing our business. We therefore do not believe that the covenant requirements
+provide useful information to investors or others in enhancing an understanding of our future prospects. 
+• Default Provisions. The Credit Agreement provides for customary events of default, including events of default based on non-payment of amounts due under the Credit Agreement, defaults on other
+debt, misrepresentations, covenant breaches, changes of control, insolvency, bankruptcy and the occurrence of a material adverse effect on the Company. Upon an event of default resulting from a voluntary or involuntary proceeding for bankruptcy,
+insolvency or receivership, the amounts outstanding under the Credit Agreement will become immediately due and payable and the Lender’s commitments will be automatically terminated. Upon the occurrence and continuation of any other event of
+default, the Lender may accelerate payment of all obligations and terminate the Lender’s commitments under the Credit Agreement. Upon an acceleration of payment following an event of default occurring prior to September 4, 2021, the amounts due and
+payable by us will include a prepayment premium on accelerated principal in the amount described under “—Optional Prepayment” above. 
+In connection with entering into the Credit Agreement, on September 3, 2019, we issued to the Lender a seven-year warrant, or the Warrant, to purchase up to 550,000 shares of our common stock at a
+per-share exercise price of $5.22. The Warrant is exercisable for cash or on a net, or “cashless,” basis, and the exercise price of the Warrant is subject to price-based, weighted-average antidilution adjustments for one year after issuance. 
+Equity and Equity-Related Securities. We did not raise additional capital from a public offering of Common Stock in 2019. 
+Research and Development Awards. We frequently seek research and development programs that may be awarded by government, non-governmental organizations, and non-profit
+entities, including private foundations. 
+46 
+Table of Contents 
+Since 2015 we have earned over $12.2 million of funding from some of the world’s leading health organizations, which has helped us accelerate the expansion of our pipeline of infectious disease tests. Our
+collaborators have included Bill & Melinda Gates Foundation, The Paul G. Allen Family Foundation, FIOCRUZ and FIND, as well as U.S. government agencies such as CDC, BARDA and the U.S. Department of Agriculture. See “Item 1. Business—Products”
+above. During the year ended December 31, 2019, we recognized grant revenue totaling $1.4 million from government, non-governmental organizations, and non-profit entities. 
+Working Capital . The following table sets forth selected working capital information: 
+December 31, 2019 
+(in thousands) 
+Cash and cash equivalents 
+$ 
+18,271 
+Accounts receivable, net 
+3,661 
+Inventories, net 
+9,598 
+Prepaid expenses and other current assets 
+693 
+Total current assets 
+32,223 
+Less: Total current liabilities 
+(6,442 
+) 
+Working capital 
+$ 
+25,781 
+Our cash and cash equivalents at December 31, 2019 were unrestricted and held for working capital purposes. We currently intend to retain all available funds and any future earnings for use in the operation of our
+business and do not anticipate paying any cash dividends. We have not entered into, and do not expect to enter into, investments for trading or speculative purposes. Our accounts receivable and inventory balances fluctuate from period to period,
+which affects our cash flow from operating activities. Fluctuations vary depending on cash collections, client mix, and the timing of shipment of our products and the invoicing of our research and development activities. 
+Uses of Funds 
+Cash Flow Used in Operating Activities . Our operations used $9.1 million of cash during the year ended December 31, 2019, primarily
+due to the net loss adjusted for non-cash items of $10.6 million, a $3.8 million decrease in accounts receivable related to favorable collections timing, and a $1.5 million increase in inventory related to supply chain timelines. 
+Acquisition. In November 2019, we acquired all of the equity interests of Orangelife for a purchase price net of cash acquired of $100,000 in cash, and 153,707 common shares,
+with an additional 316,456 common shares that would be deliverable as an earnout, based on the achievement of certain milestones between 2020 and 2022. 
+Capital Expenditures . During the year ended December 31, 2019, we advanced our plan to invest in automated manufacturing equipment,
+facilities, and other fixed assets. Our capital expenditures totaled $3.5 million in 2019. 
+Effects of Inflation 
+Inflation and changing prices have not had a material effect on our business, and we do not expect that they will materially affect our business in the foreseeable future. Any impact of inflation on cost of revenue
+and operating expenses, especially employee compensation costs, may not be readily recoverable in the price of our product offerings. 
+47 
+Table of Contents 
+Off-Balance Sheet Arrangements 
+We do not have any off-balance sheet arrangements, as defined in Item 303(a)(4)(ii) of Regulation S-K under the Securities Exchange Act of 1934. 
+Significant Accounting Policies and Critical Accounting Estimates 
+Our significant accounting policies are described in Note 3 – Significant Accounting Policies to the audited consolidated financial statements included herein. Certain of our accounting policies require the
+application of significant judgment by management in selecting the appropriate assumptions for calculating financial estimates. By their nature, these judgments are subject to an inherent degree of uncertainty. These judgments are based on our
+historical experience, terms of existing contracts, our evaluation of trends in the industry, information provided by our customers and information available from other outside sources, as appropriate. We consider an accounting estimate to be
+critical if: 
+• 
+It requires us to make assumptions about matters that were uncertain at the time we were making the estimate, and 
+• 
+Changes in the estimate or different estimates that we could have selected would have had a material impact on our financial condition or results of operations. 
+The following listing is not intended to be a comprehensive list of all of our accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by accounting
+principles generally accepted in the United States, with no need for management’s judgment in their application. There are also areas in which management’s judgment in selecting any viable alternative would not produce a materially different
+result. 
+Revenue Recognition 
+We recognize revenue for product sales in accordance with FASB ASC 606, Revenue from Contracts with Customers . Revenues from product sales are recognized when the customer
+obtains control of our product, which occurs at a point in time, typically upon tendering to the customer. We expense incremental costs of obtaining a contract as and when incurred because the expected amortization period of the asset that it would
+have recognized is one year or less or the amount is immaterial. Freight and distribution activities on products are performed after the customer obtains control of the goods. We have made an accounting policy election to account for shipping and
+handling activities that occur either when or after goods are tendered to the customer as a fulfillment activity, and therefore recognizes freight and distribution expenses in Cost of Product Sales. The Company excludes certain taxes from the
+transaction price (e.g., sales, value added and some excise taxes). 
+For certain contracts, we recognize revenue from research and development, milestone and grant revenues when earned. Grants are invoiced after expenses are incurred. Revenues from projects or grants funded in
+advance are deferred until earned. For certain collaborative research projects, we recognize revenue by defining milestones at the inception of the agreement and applying judgement and estimates in recognizing revenue for relevant contracts. 
+Stock-Based Compensation 
+We recognize the fair value of equity-based awards as compensation expense in our consolidated statement of operations. The fair value of restricted stock and restricted stock unit awards are their fair value on the
+date of grant. The fair value of our stock option awards was estimated using a Black-Scholes option valuation model. This valuation model’s computations incorporate highly subjective assumptions, such as the expected stock price volatility and the
+estimated life of each award. The fair value of equity-based awards, after considering the effect of expected forfeitures, is then amortized, generally on a straight-line basis, over the related vesting period of the option. 
+48 
+Table of Contents 
+Research and Development Costs 
+Research and development activities consist primarily of new product development, continuing engineering for existing products, and regulatory and clinical trial costs. Costs related to research and development
+efforts on existing or potential products are expensed/accrued as incurred. 
+Inventories 
+Inventories are stated at the lower of cost and net realizable value, using the first-in, first-out method, or FIFO, to determine cost. Our policy is to periodically evaluate the market value of the inventory and
+the stage of product life cycle, and record a reserve for any inventory considered slow moving or obsolete. For example, each additional 1% of obsolete inventory would reduce such inventory by approximately $95,980. 
+Accounts Receivable 
+Our policy is to review our accounts receivable on a periodic basis, no less frequently than monthly. On a quarterly basis an analysis is made of the adequacy of our allowance for doubtful accounts and adjustments
+are made accordingly. The current allowance is approximately 0.6% of accounts receivable. For example, each additional 1% of accounts receivable that becomes uncollectible would reduce such balance of accounts receivable by approximately $36,613. 
+Acquisitions 
+In accordance with accounting guidance for the provisions in FASB ASC 805, Business Combinations , we allocate the purchase price of an acquired business to its identifiable
+assets and liabilities based on estimated fair values. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. In addition, an acquisition may include a contingent consideration
+component. The fair value of the contingent consideration is estimated as of the date of the acquisition and is recorded as part of the purchase price. This estimate is updated in future periods and any changes in the estimate, which are not
+considered an adjustment to the purchase price, are recorded in our consolidated statements of operations. 
+We use all available information to estimate fair values. We typically engage outside appraisal firms to assist in the fair value determination of identifiable intangible assets and any other significant assets or
+liabilities. We may adjust the preliminary purchase price allocation, if necessary, up to one year after the acquisition closing date if we obtain more information regarding asset valuations and liabilities assumed that materially differs from the
+information available during the time of close. 
+Our purchase price allocation methodology contains uncertainties because it requires management to make assumptions and to apply judgment to estimate the fair value of acquired assets and liabilities. Management
+estimates the fair value of assets and liabilities based upon quoted market prices, the carrying value of the acquired assets and widely accepted valuation techniques, including discounted cash flows and market multiple analyses. Unanticipated
+events or circumstances may occur which could affect the accuracy of our fair value estimates, including assumptions regarding industry economic factors and business strategies. 
+Other estimates used in determining fair value include, but are not limited to, future cash flows or income related to intangibles, market rate assumptions, actuarial assumptions for benefit plans and appropriate
+discount rates. Our estimates of fair value are based upon assumptions believed to be reasonable, but that are inherently uncertain, and therefore, may not be realized. Accordingly, there can be no assurance that the estimates, assumptions, and
+values reflected in the valuations will be realized, and actual results could vary materially. 
+49 
+Table of Contents 
+Goodwill and Intangible Assets 
+We periodically review goodwill for impairment indicators. We review goodwill for impairment annually in the fourth quarter or more frequently if events or changes in circumstances indicate that goodwill might be
+impaired. We perform the goodwill impairment review at the reporting unit level. We perform a qualitative assessment of whether it is more likely than not that a reporting unit’s fair value is less than its carrying amount. If not, no further
+goodwill impairment testing is performed. If so, we perform the step discussed hereafter. Our qualitative assessment involves significant estimates, assumptions, and judgments, including, macroeconomic conditions, industry and market conditions,
+our financial performance, reporting unit specific events and changes in our share price. 
+If the fair value of the reporting unit is greater than its carrying amount, goodwill is not considered to be impaired. We would recognize an impairment charge for the
+amount by which the carrying amount exceeds the reporting unit’s fair value, provided the impairment charge does not exceed the total amount of goodwill allocated to the reporting unit. 
+Income Taxes 
+Income taxes are accounted for under FASB ASC 740, Income Taxes , authoritative guidance, which we refer to as the Guidance and which requires the asset and liability method
+of accounting for deferred income taxes. Deferred tax assets and liabilities are determined based on the difference between the financial statement and tax bases of assets and liabilities. Deferred tax assets or liabilities at the end of each
+period are determined using the tax rate expected to be in effect when taxes are actually paid or recovered. 
+The Guidance also requires that a valuation allowance be established when it is more likely than not that all or a portion of a deferred tax asset will not be realized. A review of all available positive and
+negative evidence needs to be considered, including a company’s current and past performance, the market environment in which the company operates, length of carryback and carryforward periods and existing contracts that will result in future
+profits. 
+The Guidance also prescribes a comprehensive model for recognizing, measuring, presenting and disclosing in the consolidated financial statements tax positions taken or expected to be taken on a tax return, including
+a decision whether to file or not to file in a particular jurisdiction. 
+Recently Issued Accounting Pronouncements 
+Refer to Note 3 – Significant Accounting Policies to the audited consolidated financial statements included herein for a complete description of recent accounting standards which we have not yet been required to
+implement which may be applicable to our operations. Additionally, the significant accounting standards that have been adopted during the year ended December 31, 2019 are described. 
+50 
+Table of Contents 
+ITEM 8. 
+FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+The Consolidated Financial Statements and schedules that constitute Item 8 are attached at the end of this report. An index to the Consolidated Financial Statements and schedules is also included on page F-1 of this
+report. 
+ITEM 9A. 
+Controls and Procedures 
+Evaluation of Disclosure Controls and Procedures 
+Our management, with the participation of our Interim Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures, as defined by
+Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of December 31, 2019. Based on the evaluation of our disclosure controls and procedures, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and
+procedures were effective as of December 31, 2019 at the reasonable assurance level. 
+Management’s Report on Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rules 13a-15(f) and
+15d-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer and effected by the board of directors, management and other personnel
+to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and
+procedures that: 
+• 
+pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; 
+• 
+provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and
+that receipts and expenditures of the company are being made in accordance with authorizations of management and directors of the company; and 
+• 
+provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the
+financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. As a result, even those systems determined to be effective can provide only
+reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions
+or that the degree of compliance with the policies or procedures may deteriorate. 
+Under the supervision and with the participation of our Interim Chief Executive Officer and Chief Financial Officer, our management evaluated the effectiveness of our internal control over
+financial reporting as of December 31, 2019. In making their assessment of internal control over financial reporting, our management used the criteria described in the 2013 Internal Control—Integrated Framework issued by the Committee of
+Sponsoring Organizations of the Treadway Commission. Our evaluation included documenting, evaluating and testing of the design and operating effectiveness of our internal control over financial reporting. Based on this evaluation, we concluded
+that our controls over financial reporting were effective as of December 31, 2019. 
+Previously Identified Material Weaknesses in Internal Control Over Financial Reporting 
+None. 
+Changes in Internal Control over Financial Reporting 
+There were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Securities Exchange Act of 1934 during
+the period covered by this Annual Report on Form 10-K that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+51 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+Shareholders and Board of Directors 
+Chembio Diagnostics, Inc. 
+Hauppauge, New York 
+Opinion on Internal Control over Financial Reporting 
+We have audited Chembio Diagnostics, Inc.’s (the “Company’s”) internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control –
+Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). In our opinion, the Company maintained, in all material respects, effective internal control over financial
+reporting as of December 31, 2019, based on the COSO criteria. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company and subsidiaries as of December 31,
+2019 and 2018, the related consolidated statements of operations, comprehensive loss, changes in stockholders’ equity, and cash flows for each of the two years in the period ended December 31, 2019, and the related notes and our report dated March
+13, 2020 expressed an unqualified opinion thereon. 
+Basis for Opinion 
+The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the
+accompanying “Item 9A, Management’s Report on Internal Control over Financial Reporting”. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm
+registered with the PCAOB and are required to be independent with respect to the Company in accordance with U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audit of internal control over financial reporting in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about
+whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and
+testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit
+provides a reasonable basis for our opinion. 
+Definition and Limitations of Internal Control over Financial Reporting 
+A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
+purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately
+and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted
+accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection
+of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk
+that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+/s/ BDO USA, LLP 
+Melville, NY 
+March 13, 2020 
+52 
+Table of Contents 
+PART III 
+ITEM 10. 
+DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
+The information required in response to this Item 10 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120
+days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+ITEM 11. 
+EXECUTIVE COMPENSATION 
+The information required in response to this Item 11 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120
+days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+ITEM 12. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+The information required in response to this Item 12 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120
+days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE. 
+The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120
+days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+ITEM 14. 
+PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+The information required in response to this Item 14 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120
+days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+53 
+Table of Contents 
+ITEM 15. 
+EXHIBITS, FINANCIAL STATEMENT SCHEDULES 
+(a) See “Item 8. Financial Statements and Supplementary Data – Index to Consolidated Financial Statements” above. 
+(b) Exhibits 
+Exhibit No. 
+Description 
+3.1 
+Articles of Incorporation, as amended, of Chembio Diagnostics, Inc. 
+3.2 
+Amended and Restated Bylaws, of Chembio Diagnostics, Inc. 
+4.1 
+Warrant to Purchase Common Stock dated as of September 3, 2019, issued by Chembio Diagnostics, Inc. to
+Perceptive Credit Holdings II, LP 
+10.1(a)* 
+2008 Stock Incentive Plan, as amended 
+10.1(b)* 
+Form of Option for 2008 Stock Incentive Plan 
+10.2(a)* 
+2014 Stock Incentive Plan 
+10.2(b)* 
+Form of Option for 2014 Stock Incentive Plan 
+10.3* 
+2019 Omnibus Incentive Plan 
+10.4* 
+Restated Annual Incentive Bonus Plan of Chembio Diagnostics, Inc., adopted as of March 15, 2019 
+10.5* 
+Letter agreement dated January 17, 2020, between Chembio Diagnostics, Inc. and Gail S. Page 
+10.6(a)* 
+Employment Agreement dated March 5, 2016 between Chembio Diagnostics, Inc. and Javan Esfandiari 
+10.6(b)* 
+Amendment No. 1 dated March 20, 2019 between Chembio Diagnostics, Inc. and Javan Esfandiari, amending
+the Employment Agreement dated March 5, 2016 
+10.7* 
+Employment Agreement dated September 14, 2017 between Chembio Diagnostics, Inc. and Sharon Klugewicz 
+10.8(a)* 
+Employment Agreement dated December 18, 2017 between Chembio Diagnostics, Inc. and Neil A. Goldman 
+10.8(b)* 
+Amendment No. 1 dated January 21, 2019 between Chembio Diagnostics, Inc. and Neil A. Goldman, amending
+Employment Agreement dated December 18, 2017 
+10.9* 
+Offer Letter dated October 19, 2016 between Worldwide Workplace Ireland and Robert Passas, with respect to
+employment by Chembio Diagnostics Systems, Inc . 
+10.10 
+Separation and Release Agreement, dated January 7, 2020, between Chembio Diagnostics, Inc. and John J.
+Sperzel III 
+10.11(a) 
+Lease Agreement, dated February 15, 2017, between Horseblock Associates and Chembio
+Diagnostics, Inc. with respect to 3661 Horseblock Road, Medford, New York, as amended 
+10.11(b) 
+Agreement of Sublease dated February 5, 2019 between Chembio Diagnostic Systems Inc., as sublessor, and
+Reliance Communications of New Jersey, LLC, as sublessee, with respect to 3661 Horseblock Road, Medford, New York, as amended 
+10.12 
+Lease Agreement, dated February 4, 2013, between Sherwood Corporate Center LLC and Chembio
+Diagnostics, Inc. with respect to 91-1A Colin Drive, Holbrook, New York, as amended on September 19, 2017 
+10.13 
+Lease Agreement dated February 5, 2019 between Myra Properties, LLC, as lessor, and Chembio Diagnostic
+Systems Inc., as lessee, with respect to 555 Wireless Boulevard, Hauppauge, New York. 
+10.14† 
+Credit Agreement and Guaranty dated as of September 3, 2019, among Chembio Diagnostics, Inc., as the
+Borrower, the Guarantors from time to time party thereto, and Perceptive Credit Holdings II, LP and its successors and assigns party 
+thereto, as Administrative Agent and as a Lender 
+14.1 
+Ethics Policy 
+21.1 
+List of Subsidiaries of Chembio Diagnostics, Inc. 
+23.1 
+Consent of BDO USA, LLP, Independent Registered Public
+Accounting Firm 
+31.1 
+Certification of the Chief Executive Officer pursuant to
+Section 302 of the Sarbanes-Oxley Act of 2002. 
+31.2 
+Certification of the Chief Financial Officer pursuant to
+Section 302 of the Sarbanes-Oxley Act of 2002. 
+32.1 
+Certification of Chief Executive Officer and Chief Financial
+Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 
+101.INS 
+XBRL Instance Document 
+101.SCH 
+XBRL Taxonomy Extension Schema Document 
+101.CAL 
+XBRL Taxonomy Extension Calculation Linkbase Document 
+101.DEF 
+XBRL Taxonomy Definition Linkbase Document 
+101.LAB 
+XBRL Taxonomy Label Linkbase Document 
+101.PRE 
+XBRL Taxonomy Presentation Linkbase Document 
+* 
+Indicates management contract or compensatory plan. 
+† 
+Certain exhibits and schedules have been omitted pursuant to Item 601(a)(5) of Regulation S-K. We hereby undertake to furnish copies of the omitted exhibits and schedules upon request
+by the Securities and Exchange Commission, provided that we may request confidential treatment pursuant to Rule 24b-2 of the Securities Exchange Act of 1934 for the exhibits and schedules so furnished. 
+54 
+Table of Contents 
+SIGNATURES 
+In accordance with Section 13 or 15(d) of the Exchange Act, the registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+CHEMBIO DIAGNOSTICS, INC. 
+March 13, 2020 
+By 
+/s/ Gail S. Page 
+Gail S. Page 
+Interim Chief Executive Officer 
+In accordance with the requirements of the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+Signatures 
+Title 
+Date 
+/s/ Gail S. Page 
+Interim Chief Executive Officer and Director 
+March 13, 2020 
+Gail S. Page 
+(Principal Executive Officer) 
+/s/ Neil A. Goldman 
+Executive Vice President and Chief Financial Officer 
+March 13, 2020 
+Neil A. Goldman 
+(Principal Financial & Accounting Officer) 
+/s/ Katherine L. Davis 
+Chair of the Board 
+March 13, 2020 
+Katherine L. Davis 
+/s/ Mary Lake Polan 
+Director 
+March 13, 2020 
+Mary Lake Polan 
+/s/ John G. Potthoff 
+Director 
+March 13, 2020 
+John G. Potthoff 
+55 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+Index to Consolidated Financial Statements 
+—INDEX— 
+Page(s) 
+Report of Independent Registered Public Accounting Firm 
+F-1 
+Consolidated Financial Statements: 
+Balance Sheets as of December 31, 2019 and 2018 
+F-2 
+Statements of Operations for the years ended December 31, 2019 and 2018 
+F-3 
+Statements of Comprehensive Loss for the years ended December 31, 2019 and 2018 
+F-4 
+Statements of Changes in Stockholders’ Equity for the years ended December 31, 2019 and 2018 
+F-5 
+Statements of Cash Flows for the years ended December 31, 2019 and 2018 
+F-6 
+Notes to Consolidated Financial Statements 
+F-7 - F-30 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+Shareholders and Board of Directors 
+Chembio Diagnostics, Inc. 
+Hauppauge, New York 
+Opinion on the Consolidated Financial Statements 
+We have audited the accompanying consolidated balance sheets of Chembio Diagnostics, Inc. (the “Company”) and subsidiaries as of December 31, 2019 and 2018, the related consolidated statements of operations,
+comprehensive loss, changes in stockholders’ equity, and cash flows the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present
+fairly, in all material respects, the financial position of the Company and subsidiaries at December 31, 2019 and 2018 , and the results of their operations and their cash flows for each of the two years in the
+period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2019,
+based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) and our report dated March 13, 2020
+expressed an unqualified opinion thereon. 
+Change in Accounting Principle 
+On January 1, 2019, the Company changed its method of accounting for leases due to the adoption of Accounting Standards Codification Topic 842, Leases. The effects of the adoption are described in Note 3 to the
+consolidated financial statements. 
+Basis for Opinion 
+These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a
+public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable
+rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are
+free of material misstatement, whether due to error or fraud. 
+Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks.
+Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by
+management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. 
+/s/ BDO USA, LLP 
+We have served as the Company’s auditor since 2011. 
+Melville, NY 
+March 13, 2020 
+F-1 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED BALANCE SHEETS 
+AS OF 
+December 31, 2019 
+December 31, 2018 
+- ASSETS - 
+CURRENT ASSETS: 
+Cash and cash equivalents 
+$ 
+18,271,352 
+$ 
+12,524,551 
+Accounts receivable, net of allowance for doubtful accounts of $62,000 and $42,000 at December 31, 2019 and 2018, respectively 
+3,661,325 
+7,373,971 
+Inventories, net 
+9,598,030 
+7,851,222 
+Prepaid expenses and other current assets 
+693,013 
+702,010 
+TOTAL CURRENT ASSETS 
+32,223,720 
+28,451,754 
+FIXED ASSETS: 
+Property, plant and equipment, net 
+5,933,569 
+2,873,920 
+Finance lease right-of-use assets, net 
+210,350 
+– 
+OTHER ASSETS: 
+Operating right-of-use assets, net 
+7,030,744 
+– 
+Intangible assets, net 
+3,914,352 
+3,884,831 
+Goodwill 
+5,872,690 
+4,983,127 
+Deposits and other assets 
+543,539 
+717,551 
+TOTAL ASSETS 
+$ 
+55,728,964 
+$ 
+40,911,183 
+- LIABILITIES AND STOCKHOLDERS’ EQUITY - 
+CURRENT LIABILITIES: 
+Accounts payable and accrued liabilities 
+$ 
+5,526,243 
+$ 
+5,888,681 
+Deferred revenue 
+125,000 
+422,905 
+Note payable 
+180,249 
+207,694 
+Finance lease liabilities 
+41,894 
+– 
+Operating lease liabilities 
+568,294 
+– 
+TOTAL CURRENT LIABILITIES 
+6,441,680 
+6,519,280 
+OTHER LIABILITIES: 
+Long-term operating lease liabilities 
+6,969,603 
+– 
+Long-term finance lease liabilities 
+171,953 
+– 
+Note payable 
+– 
+171,821 
+Long-term debt net of debt discount and issuance costs 
+17,644,149 
+– 
+Deferred tax liability 
+466,326 
+892,308 
+TOTAL LIABILITIES 
+31,693,711 
+7,583,409 
+COMMITMENTS AND CONTINGENCIES (Note 12) 
+STOCKHOLDERS’ EQUITY: 
+Preferred stock – 10,000,000 shares authorized, none outstanding 
+– 
+– 
+Common stock - $.01 par value; 100,000,000 shares authorized, 17,733,617 and 17,166,459 shares issued and outstanding at December 31, 2019 and 2018, respectively 
+177,335 
+171,664 
+Additional paid-in capital 
+95,433,077 
+90,953,788 
+Accumulated deficit 
+(71,585,003 
+) 
+(57,909,874 
+) 
+Accumulated other comprehensive income 
+9,844 
+112,196 
+TOTAL STOCKHOLDERS’ EQUITY 
+24,035,253 
+33,327,774 
+TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY 
+$ 
+55,728,964 
+$ 
+40,911,183 
+See accompanying notes to consolidated financial statements 
+F-2 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF OPERATIONS 
+For the years ended 
+December 31, 2019 
+December 31, 2018 
+REVENUES: 
+Net product sales 
+$ 
+28,844,997 
+$ 
+27,913,209 
+R&D and grant revenue 
+4,680,282 
+5,719,458 
+License and royalty revenue 
+938,753 
+948,773 
+TOTAL REVENUES 
+34,464,032 
+34,581,440 
+COSTS AND EXPENSES: 
+Cost of product sales 
+22,394,317 
+22,599,432 
+Research and development expenses 
+8,538,416 
+8,526,256 
+Selling, general and administrative expenses 
+16,138,424 
+11,100,775 
+Acquisition costs 
+721,465 
+337,645 
+47,792,622 
+42,564,108 
+LOSS FROM OPERATIONS 
+(13,328,590 
+) 
+(7,982,668 
+) 
+OTHER (EXPENSE) INCOME: 
+Interest (expense) income, net 
+(846,831 
+) 
+49,498 
+LOSS BEFORE INCOME TAX BENEFIT 
+(14,175,421 
+) 
+(7,933,170 
+) 
+Income tax benefit 
+(500,292 
+) 
+(67,521 
+) 
+NET LOSS 
+$ 
+(13,675,129 
+) 
+$ 
+(7,865,649 
+) 
+Basic loss per share 
+$ 
+(0.81 
+) 
+$ 
+(0.54 
+) 
+Diluted loss per share 
+$ 
+(0.81 
+) 
+$ 
+(0.54 
+) 
+Weighted average number of shares outstanding, basic 
+16,954,142 
+14,432,505 
+Weighted average number of shares outstanding, diluted 
+16,954,142 
+14,432,505 
+See accompanying notes to consolidated financial statements 
+F-3 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS 
+For the years ended 
+December 31, 2019 
+December 31, 2018 
+Net loss 
+$ 
+(13,675,129 
+) 
+$ 
+(7,865,649 
+) 
+Other comprehensive loss: 
+Foreign currency translation adjustments 
+(102,352 
+) 
+(66,752 
+) 
+COMPREHENSIVE LOSS 
+$ 
+(13,777,481 
+) 
+$ 
+(7,932,401 
+) 
+See accompanying notes to consolidated financial statements 
+F-4 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY 
+FOR THE YEARS ENDED DECEMBER 31, 2019, AND 2018 
+Common Stock 
+Additional 
+Paid-in-Capital 
+Amount 
+Accumulated 
+Deficit 
+Amount 
+AOCI 
+Amount 
+Total 
+Amount 
+Shares 
+Amount 
+Balance at December 31, 2017 
+12,318,570 
+$ 
+123,185 
+$ 
+62,821,288 
+$ 
+(50,044,225 
+) 
+$ 
+178,948 
+$ 
+13,079,196 
+Common Stock: 
+New stock from offerings 
+4,509,760 
+45,098 
+27,431,162 
+– 
+– 
+27,476,260 
+Restricted stock issued 
+266,839 
+2,668 
+(2,668 
+) 
+– 
+– 
+– 
+Restricted stock compensation 
+– 
+– 
+281,249 
+– 
+– 
+281,249 
+Options: 
+Exercised 
+71,290 
+713 
+71,201 
+– 
+– 
+71,914 
+Stock option compensation 
+– 
+– 
+351,556 
+– 
+– 
+351,556 
+Comprehensive loss 
+– 
+– 
+– 
+– 
+(66,752 
+) 
+(66,752 
+) 
+Net loss 
+– 
+– 
+– 
+(7,865,649 
+) 
+– 
+(7,865,649 
+) 
+Balance at December 31, 2018 
+17,166,459 
+$ 
+171,664 
+$ 
+90,953,788 
+$ 
+(57,909,874 
+) 
+$ 
+112,196 
+$ 
+33,327,774 
+Common Stock: 
+Restricted stock issued 
+381,908 
+3,819 
+(128,081 
+) 
+– 
+– 
+(124,262 
+) 
+Restricted stock compensation 
+– 
+– 
+1,394,812 
+– 
+– 
+1,394,812 
+Issuance of common stock for business acquired 
+153,707 
+1,537 
+441,754 
+– 
+– 
+443,291 
+Options: 
+Exercised 
+31,543 
+315 
+32,171 
+– 
+– 
+32,486 
+Stock option compensation 
+– 
+– 
+261,088 
+– 
+– 
+261,088 
+Warrants and Other: 
+Warrant on Term Debt 
+– 
+– 
+1,196,093 
+– 
+– 
+1,196,093 
+Contingent Earnout for business acquired 
+– 
+– 
+1,281,452 
+– 
+– 
+1,281,452 
+Comprehensive loss 
+– 
+– 
+– 
+– 
+(102,352 
+) 
+(102,352 
+) 
+Net loss 
+– 
+– 
+– 
+(13,675,129 
+) 
+– 
+(13,675,129 
+) 
+Balance at December 31, 2019 
+17,733,617 
+$ 
+177,335 
+$ 
+95,433,077 
+$ 
+(71,585,003 
+) 
+$ 
+9,844 
+$ 
+24,035,253 
+See accompanying notes to consolidated financial statements 
+F-5 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+FOR THE YEARS ENDED 
+December 31, 2019 
+December 31, 2018 
+CASH FLOWS FROM OPERATING ACTIVITIES: 
+Cash received from customers and grants 
+$ 
+37,930,172 
+$ 
+29,804,273 
+Cash paid to suppliers and employees 
+(45,655,562 
+) 
+(41,624,299 
+) 
+Cash paid for operating and finance leases 
+(640,844 
+) 
+– 
+Interest and taxes, net 
+(689,272 
+) 
+38,585 
+Net cash used in operating activities 
+(9,055,506 
+) 
+(11,781,441 
+) 
+CASH FLOWS FROM INVESTING ACTIVITIES: 
+Purchase of businesses, net of cash acquired 
+(100,000 
+) 
+(5,491,204 
+) 
+Acquisition of and deposits on fixed assets 
+(3,502,540 
+) 
+(1,467,192 
+) 
+Patent Application Costs 
+(297,006 
+) 
+– 
+Working capital adjustments related to business combination 
+145,760 
+– 
+Net cash used in investing activities 
+(3,753,786 
+) 
+(6,958,396 
+) 
+CASH FLOWS FROM FINANCING ACTIVITIES: 
+Proceeds from option exercises 
+32,486 
+71,914 
+Principal payments for finance leases 
+(19,875 
+) 
+– 
+Payments on debt issuance costs 
+(186,313 
+) 
+– 
+Payments on note payable 
+(181,822 
+) 
+(64,481 
+) 
+Proceeds from issuance of long-term debt, net 
+18,850,000 
+– 
+Proceeds from sale of common stock, net 
+– 
+27,476,260 
+Net cash provided by financing activities 
+18,494,476 
+27,483,693 
+Effect of exchange rate changes on cash 
+61,617 
+(9,607 
+) 
+INCREASE IN CASH AND CASH EQUIVALENTS 
+5,746,801 
+8,734,249 
+Cash and cash equivalents - beginning of the period 
+12,524,551 
+3,790,302 
+Cash and cash equivalents - end of the period 
+$ 
+18,271,352 
+$ 
+12,524,551 
+RECONCILIATION OF NET LOSS TO NET CASH USED IN OPERATING ACTIVITIES: 
+Net Loss 
+$ 
+(13,675,129 
+) 
+$ 
+(7,865,649 
+) 
+Adjustments: 
+Depreciation and amortization 
+1,916,194 
+902,505 
+Share based compensation 
+1,655,900 
+632,805 
+Benefit from deferred tax liability 
+(513,715 
+) 
+(78,432 
+) 
+Provision for doubtful accounts 
+20,000 
+– 
+Changes in assets and liabilities, net of effects from acquisitions: 
+Accounts receivable 
+3,764,045 
+(5,150,072 
+) 
+Inventories 
+(1,457,612 
+) 
+(3,077,104 
+) 
+Prepaid expenses and other current assets 
+64,355 
+(118,293 
+) 
+Deposits and other assets 
+(90,624 
+) 
+– 
+Accounts payable and accrued liabilities 
+(441,015 
+) 
+2,599,894 
+Deferred revenue 
+(297,905 
+) 
+372,905 
+Net cash used in operating activities 
+$ 
+(9,055,506 
+) 
+$ 
+(11,781,441 
+) 
+Supplemental disclosures for non-cash investing and financing activities: 
+Deposits on manufacturing equipment transferred to fixed assets 
+$ 
+430,000 
+$ 
+257,455 
+Deposits and other assets transferred to intangible assets 
+– 
+118,899 
+Seller-financed equipment purchases 
+– 
+326,110 
+Issuance of common stock for net assets of business acquired 
+443,291 
+– 
+Contingent liability earnout 
+1,225,000 
+– 
+See accompanying notes to consolidated financial statements 
+F-6 
+Table of Contents 
+NOTE 1 — DESCRIPTION OF BUSINESS: 
+Chembio Diagnostics, Inc. and its subsidiaries (collectively, the “Company” or “Chembio”), develop, manufacture, and commercialize point-of-care diagnostic tests that are used to detect and diagnose diseases. The
+Company is pursuing three corporate priorities: (1) expand its commercialization, (2) advance its research and development pipeline, and (3) prepare for future growth. 
+All products that are currently being developed are based on the Company’s patented DPP ® technology, a novel point-of-care diagnostic platform that offers certain customer advantages as compared to
+traditional lateral flow technology. 
+The Company’s product commercialization and product development efforts are focused on infectious disease testing and technology collaborations. In infectious disease, the
+Company is commercializing tests for HIV and Syphilis, Zika virus, and developing tests for malaria, dengue virus, chikungunya virus, ebola, lassa , Marburg, leptospirosis, Rickettsia typhi , Burkholderia pseudomallei , and Orientia tsutsugamushi , individually or as part of fever panel tests. Through technology collaborations, the Company is developing tests
+for concussion, bovine tuberculosis, a rare disease in collaboration with Takeda Pharmaceutical, and a biomarker development project in collaboration with AstraZeneca. 
+Large and growing markets have been established for these kinds of tests, initially in high prevalence regions where they are indispensable for large scale prevention and treatment programs. More generally, the
+Company believes there is and will continue to be a growing demand for diagnostic products that can provide accurate, actionable diagnostic information in a rapid, cost-effective manner at the point of care. 
+The Company’s products are sold to medical laboratories and hospitals, governmental and public health entities, non-governmental organizations, medical professionals and retail establishments, both domestically and
+internationally, under the Company’s STAT PAK ®, SURE CHECK ® , STAT-VIEW ® or DPP ® registered trademarks, or under the private labels of the Company’s marketing partners. 
+The Company routinely enters into arrangements with governmental and non-governmental organizations for the funding of certain research and development efforts. 
+NOTE 2 — ACQUISITIONS: 
+Orangelife 
+On November 25, 2019, pursuant to a quote purchase agreement, the Company acquired all of the outstanding shares of Orangelife Comercio e Industria Ltda., or Orangelife, a privately-held Brazilian company, which is
+an original equipment manufacturer of point-of-care tests approved by the Brazilian Health Surveillance Agency (Agência Nacional de Vigilância Sanitária, or ANVISA) for infectious diseases that include HIV, Hepatitis C, Zika, Chikungunya, and
+Dengue Fever. Orangelife tests are manufactured in its Rio de Janeiro facility, which is ISO-certified and approved by ANVISA to produce Class II/III/IV medical devices. The purchase price includes the following consideration: 
+· 
+$150,000 in cash and 153,707 shares of our common stock. 
+· 
+Issuance of 316,456 shares of our common stock to Dr. Manco Collovati, the founder and former CEO of Orangelife, based on the transfer and approval of certain of our product
+registration in Brazil prior to November 25, 2022. All of the shares may be deliverable in the event of change in control of our company. The number of shares issued is subjected to adjustments based upon Orangelife’s working capital at
+closing. The fair value of the shares on the date of the acquisition are recorded in equity. 
+The purchase consideration is subject to routine post-closing adjustments. The acquisition of Orangelife will allow us to expand our commercial presence by offering our products to the state, private, and pharmacy
+markets in Brazil, in addition to providing local support to our long time customer Bio-Manguinhos, the subsidiary of the Oswaldo Cruz Foundation (Fiocruz) that oversees development and production of vaccines, diagnostics, and biopharmaceuticals,
+primarily to meet the demands of Brazil’s national public health system. The results of Orangelife’s operations have been reflected in the consolidated financial statements since November 25, 2019. 
+F-7 
+Table of Contents 
+The acquisition was accounted for using the purchase method of accounting. The following table summarizes the allocation of the purchase price to the estimated fair values of
+the assets acquired and liabilities assumed on the closing date of November 25, 2019: 
+Amount 
+Net current assets 
+$ 
+320,293 
+Property, plant and equipment and other assets 
+226,035 
+Inventory 
+289,205 
+Goodwill 
+986,058 
+Deferred tax liability 
+(50,000 
+) 
+Other intangible assets (estimated useful life): 
+Trade name (0.5 years) 
+5,000 
+Customer contracts / relationships (5 years) 
+195,000 
+Total consideration 
+$ 
+1,971,591 
+The Company calculated the fair value of the fixed assets based on the net book value of Orangelife as that approximates fair value. The trade name, customer
+contracts/relationships and contingent earnouts were based on discounted cash flows using management estimates. 
+As a result of the consideration paid exceeding the fair value of the net assets acquired, goodwill in the amount of $986,058 was recorded in connection with this acquisition, none of which will be deductible for tax
+purposes. In addition, the Company recorded $200,000 in intangible assets associated with the addition of Orangelife’s trade name and customer base. The Consolidated Statements of Operations for the year ended December 31, 2019 include $325,853 of
+transaction costs related to the Orangelife acquisition. 
+The following represents pro forma operating results for the year ended December 31, 2019 as if the operations of Orangelife had been included in the Company’s Consolidated Statements of Operations as of January 1,
+2019. This pro forma financial information is unaudited and presented for illustrative purposes only and is not necessarily indicative of the operating results that would have occurred if the acquisition of Orangelife and the other transactions
+contemplated by this acquisition had been completed as of January 1, 2019, nor is it necessarily indicative of the future operating results of Chembio Diagnostics and Orangelife on a combined and consolidated basis. 
+Unaudited Proforma 
+December 31, 2019 
+Total revenues 
+$ 
+35,157,248 
+Net loss 
+$ 
+(13,654,001 
+) 
+Net loss per common share 
+$ 
+(0.80 
+) 
+Diluted net loss per common share 
+$ 
+(0.80 
+) 
+F-8 
+Table of Contents 
+opTricon 
+On November 6, 2018, pursuant to a share purchase agreement, the Company acquired all of the outstanding shares of opTricon GmbH (“opTricon”), a privately-held Germany based developer and manufacturer of handheld
+analyzers for rapid diagnostic tests, for $5.5 million in cash, subject to routine post-closing adjustments. Since 2015, the Company and opTricon have been parties to an agreement under which the Company has collaborated in developing its DPP Micro
+Reader, a handheld, battery-operated analyzer that uses an innovative image sensor to provide, when combined with the Company’s DPP tests, a quantitative interpretation of diagnostic results. The Company purchased opTricon because it believes it
+will enable it to promote DPP tests and DPP Micro Readers more actively across global markets. The results of opTricon operations have been reflected in the consolidated financial statements since November 6, 2018. 
+As a result of the consideration paid exceeding the fair value of the net assets acquired, goodwill in the amount of $3,290,888 was recorded in connection with this acquisition, none of which will be deductible for
+tax purposes. In addition, the Company recorded $2,260,000 in intangible assets associated with the addition of opTricon’s developed technology and customer base. The Consolidated Statements of Operations for the year ended December 31, 2019 and
+2018 includes $395,612 and $337,645 of transaction costs related to the opTricon acquisition, respectively. 
+The acquisition was accounted for using the purchase method of accounting. The following table summarizes the allocation of the purchase price to the estimated fair values of
+the assets acquired and liabilities assumed on the closing date of November 6, 2018: 
+Amount 
+Net current assets 
+$ 
+404,204 
+Property, plant and equipment 
+125,000 
+Goodwill 
+3,383,112 
+Deferred tax liability 
+(681,112 
+) 
+Other intangible assets (estimated useful life): 
+Developed technology (7 years) 
+1,900,000 
+Customer contracts / relationships (10 years) 
+360,000 
+Total consideration 
+$ 
+5,491,204 
+The Company calculated the fair value of the fixed assets based on the net book value of opTricon as that approximates fair value. The developed technology and customer
+contracts/relationships were based on discounted cash flows using management estimates. 
+The following represents unaudited pro forma operating results for the year ended December 31, 2018 as if the operations of opTricon had been included in the Company’s
+Consolidated Statements of Operations as of January 1, 2018: 
+Proforma 
+December 31, 2018 
+Total revenues 
+$ 
+36,614,995 
+Net loss 
+$ 
+(8,394,074 
+) 
+Net loss per common share 
+$ 
+(0.58 
+) 
+Diluted net loss per common share 
+$ 
+(0.58 
+) 
+The pro forma financial information includes business combination accounting effects from the acquisition including amortization charges from acquired intangible assets of opTricon approximately $ 351,000 for the year ended December 31, 2018. The unaudited pro forma information as presented above is for informational purposes only and is not indicative of the results of operations that would have
+been achieved if the acquisition had taken place at the beginning of fiscal 2018. Included in the proforma table above are opTricon’s net revenues and pre-tax loss for the year ended December 31, 2018 which were approximately $2,214,000 and
+$213,000, respectively. opTricon’s results of operations from the date of acquisition through December 31, 2018 are immaterial to the Company’s Consolidated Statements of Operations. 
+F-9 
+Table of Contents 
+NOTE 3 — SIGNIFICANT ACCOUNTING POLICIES: 
+(a) 
+Principles of Consolidation: 
+The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany transactions and balances are eliminated in consolidation. 
+(b) 
+Use of Estimates: 
+The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make assumptions and estimates that affect the amounts
+reported in the consolidated financial statements and accompanying notes. Judgments and estimates of uncertainties are required in applying the Company’s accounting policies in certain areas. Generally, matters subject to estimation and judgment
+include accounts receivable realization, inventory obsolescence, asset impairments, recognition of revenue pursuant to milestones, useful lives of intangible and fixed assets, stock-based compensation, and deferred tax asset valuation allowances.
+Due to the inherent uncertainty involved in making estimates, actual results reported in future periods may be based upon amounts that differ from those estimates. 
+(c) 
+Fair Value of Financial Instruments: 
+The carrying value for cash and cash equivalents, accounts receivable, and accounts payable, approximate fair value due to the immediate or short-term maturity of these financial instruments. Included in cash and
+cash equivalents is $16.0 million and $4.7 million as of December 31, 2019 and 2018, respectively, of money market funds that are Level 1 fair value measurements under the hierarchy. The fair value of the Company’s notes payable approximates the
+recorded value as the rate is based upon the current rates offered to the Company for similar financial instruments. 
+Fair value measurements of all financial assets and liabilities that are being measured and reported on a fair value basis are required to be classified and disclosed in one of the following three categories: 
+Level 1: 
+Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities; 
+Level 2: 
+Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability; and 
+Level 3: 
+Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). 
+(d) 
+Cash and Cash Equivalents: 
+Cash and cash equivalents are defined as short-term, highly liquid investments with original maturities of three months or less. 
+F-10 
+Table of Contents 
+(e) 
+Concentrations of Credit Risk: 
+Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of temporary cash investments and trade receivables. The Company places its temporary cash instruments
+with well-known financial institutions and, at times, may maintain balances in excess of the FDIC insurance limit. The Company monitors the credit ratings of the financial institutions to mitigate this risk. Concentration of credit risk with
+respect to trade receivables is principally mitigated by the Company’s ability to obtain letters of credit from certain foreign customers and its diverse customer base, both in number of customers and geographic locations. 
+(f) 
+Inventories: 
+Inventories, consisting of material, labor and manufacturing overhead, are stated at the lower of cost and net realizable value. Cost is determined on the first-in, first-out method. The Company’s policy is to
+periodically evaluate the market value of the inventory and the stage of product life cycle, and record a write-down for any inventory considered slow moving or obsolete. 
+(g) 
+Fixed Assets: 
+Fixed assets are stated at cost, less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the respective assets, which range from three to seven
+years. Leasehold improvements are amortized over the useful life of the asset or the lease term, whichever is shorter. Deposits paid for fixed assets are capitalized and not depreciated until the related asset is placed in service. 
+(h) 
+License Agreements: 
+The Company records up-front payments related to license agreements as prepaids and amortizes them over their respective economic life. As of December 31, 2019 and 2018, total prepaids were $100,000 and $100,000,
+respectively. 
+Amortization expenses for the licenses above for the years ended December 31, 2019, and 2018 were $0, and $0, respectively. 
+(i) 
+Valuation of Long-Lived Assets and Intangible Assets: 
+Long-lived assets to be held and used are analyzed for impairment whenever events or changes in circumstances indicate that the related carrying amounts may not be recoverable. The Company evaluates at each balance
+sheet date whether events and circumstances have occurred that indicate possible impairment. If there are indications of impairment, the Company uses future undiscounted cash flows of the related asset or asset grouping over the remaining life in
+measuring whether the assets are recoverable. In the event such cash flows are not expected to be sufficient to recover the recorded asset values, the assets are written down to their estimated fair value. No impairment of long-lived tangible and
+intangible assets was recorded for the years ended December 31, 2019 and 2018. 
+(j) 
+Revenue Recognition: 
+In May 2014, the Financial Accounting Standards Board (“FASB”) issued converged guidance on recognizing revenue in contracts with customers, Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers . The intent of the new standard is to improve financial reporting and comparability of revenue globally. The core principle of the standard is for a company to recognize revenue in a manner
+that depicts the transfer of goods or services to customers in an amount that reflects the consideration which the company expects to receive in exchange for those goods or services. The guidance provides a five-step analysis of transactions to
+determine when and how revenue is recognized. Other major provisions include capitalization of certain contract costs, consideration of the time value of money in the transaction price, and in certain circumstances, allowing estimates of variable
+consideration to be recognized before contingencies are resolved. The guidance also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from an entity’s contracts with customers. 
+F-11 
+Table of Contents 
+The new revenue standards became effective for the Company on January 1, 2018 and were adopted using the modified retrospective method. The adoption of the new revenue standards as of January 1, 2018 did not change
+the Company’s revenue recognition as its revenues continue to be recognized when the customer takes control of its product. As the Company did not identify any material accounting changes that impacted the amount of reported revenues with respect
+to its product revenue, license and royalty revenue, and R&D, milestone and grant revenues, no adjustment to retained earnings was required upon adoption. 
+The Company adopted the standards to contracts that were not completed at the date of initial application (January 1, 2018). 
+Under the new revenue standards, the Company recognizes revenues when its customer obtains control of promised goods or services, in an amount that reflects the consideration which the Company expects to receive in
+exchange for those goods or services. The Company recognizes revenues following the five-step model prescribed under ASU No. 2014-09: (i) identify contract(s) with a customer; (ii) identify the performance obligations in the contract; (iii)
+determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and (v) recognize revenues when (or as) the Company satisfies the performance obligation. 
+Product Revenues 
+Revenues from product sales are recognized and commissions are accrued when the customer obtains control of the Company’s product, which occurs at a point in time, typically upon tendering to the customer. The
+Company expenses incremental costs of obtaining a contract as and when incurred because the expected amortization period of the asset that it would have recognized is one year or less or the amount is immaterial. Freight and distribution activities
+on products are performed after the customer obtains control of the goods. The Company has made an accounting policy election to account for shipping and handling activities that occur either when or after goods are tendered to the customer as a
+fulfillment activity, and therefore recognizes freight and distribution expenses in Cost of Product Sales. The Company excludes certain taxes from the transaction price (e.g., sales, value added and some excise taxes). 
+Our contracts with customers often include promises to transfer products or services to a customer. Determining whether products and services are considered distinct performance
+obligations that should be accounted for separately versus together may require judgment. Typical products sold are diagnostic tests and typical services performed are R&D feasibility studies. Revenues from sale of products are recognized
+point-in-time and revenues from R&D feasibility studies are recognized ratably, over the period of the agreement. 
+Judgement is required to determine the stand-alone selling price (“SSP”) for each distinct performance obligation. SSP is directly observable and we can use a range of amounts to
+estimate SSP, as we sell products and services separately, and can determine whether there is a discount to be allocated based on the relative SSP of the various products and services, for the various geographies. The Company currently does not
+have agreements in which multiple performance obligations are sold combined. 
+The Company’s payment terms vary by the type and location of the Company’s customer and products or services offered. Payment terms differ by jurisdiction and customer but payment is generally required in a term
+ranging from 30 to 60 days from date of shipment or satisfaction of the performance obligation. 
+F-12 
+Table of Contents 
+Reserves for Discounts and Allowances 
+Revenues from product sales are recorded net of reserves established for applicable discounts and allowances that are offered within contracts with the Company’s customers. The Company’s process for estimating
+reserves established for these variable consideration components does not differ materially from its historical practices. 
+Product revenue reserves, which are classified as a reduction in product revenues, are generally related to discounts. Estimates of variable consideration and the determination of whether to include estimated amounts
+in the transaction price are based on all information (historical, current and forecasted) that is reasonably available to the Company, taking into consideration the type of customer, the type of transaction and the specific facts and circumstances
+of each arrangement. The transaction price, which includes variable consideration reflecting the impact of discounts and allowances, may be subject to constraint and is included in the net sales price only to the extent that it is probable that a
+significant reversal of the amount of the cumulative revenues recognized will not occur in a future period. Actual amounts may ultimately differ from the Company’s estimates. If actual results vary, the Company adjusts these estimates, which could
+have an effect on earnings in the period of adjustment. 
+Royalty Revenues 
+The Company receives royalty revenues on sales by its licensee of products covered under patents that it owns. The Company does not have future performance obligations under this license arrangement. The Company
+records these revenues based on estimates of the sales that occurred during the relevant period as a component of license and royalty revenues. The relevant period estimates of sales are based on interim data provided by the licensee and analysis
+of historical royalties that have been paid to the Company, adjusted for any changes in facts and circumstances, as appropriate. Differences between actual and estimated royalty revenues are adjusted for in the period in which they become known,
+typically the following quarter. Historically, adjustments have not been material when compared to actual amounts paid by licensee. 
+R&D and grant revenue 
+All such contracts are evaluated under the five-step model described above. For certain contracts that represent grants where the funder does not meet the definition of a customer, the Company recognizes revenue when
+earned in accordance with ASC 958. Such contracts are further described under Disaggregation of Revenue , below. Grants are invoiced and revenue is recognized ratably as that is the depiction of the timing
+of the transfer of services. Performance obligation is the feasibility study which encompasses various phases of product development processes: design feasibility & planning, product development & design optimization, design verification,
+design validation & process validation, and pivotal studies. 
+In June 2018, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2018-08, Not-for-Profit Entities (Topic 958): Clarifying the Scope and the Accounting Guidance for Contributions
+Received and Contributions Made. This ASU clarifies the guidance presented in Topic 958, “Not-for-Profit Entities,” of the FASB’s Accounting Standards Codification (ASC) for evaluating whether a transaction is reciprocal (i.e., an exchange
+transaction) or nonreciprocal (i.e., a contribution) and for distinguishing between conditional and unconditional contributions. The ASU also clarifies the guidance used by entities other than not-for-profits to identify and account for
+contributions made. 
+F-13 
+Table of Contents 
+Disaggregation of Revenue 
+The following tables disaggregate Total Revenues for the year ended December 31, 2019, by type of transaction and by geography: 
+Exchange 
+Transactions 
+Non-Exchange 
+Transactions 
+Total 
+Net product sales 
+$ 
+28,844,997 
+$ 
+– 
+$ 
+28,844,997 
+R&D, milestone and grant revenue 
+3,321,031 
+1,359,251 
+4,680,282 
+License and royalty revenue 
+938,753 
+– 
+938,753 
+$ 
+33,104,781 
+$ 
+1,359,251 
+$ 
+34,464,032 
+Exchange transactions are recognized in accordance with ASC 606, while non-exchange transactions are recognized in accordance with ASU No. 2018-08. 
+Total 
+Africa 
+$ 
+7,564,360 
+Asia 
+888,800 
+Europe & Middle East 
+6,498,995 
+Latin America 
+11,808,768 
+United States 
+7,703,109 
+$ 
+34,464,032 
+The following tables disaggregate Total Revenues for the year ended December 31, 2018, by type of transaction and by geography: 
+Exchange 
+Transactions 
+Non-Exchange 
+Transactions 
+Total 
+Net product sales 
+$ 
+27,913,209 
+$ 
+– 
+$ 
+27,913,209 
+R&D, milestone and grant revenue 
+2,687,210 
+3,032,248 
+5,719,458 
+License and royalty revenue 
+948,773 
+– 
+948,773 
+$ 
+34,581,440 
+$ 
+3,032,248 
+$ 
+34,581,440 
+Exchange transactions are recognized in accordance with ASC 606, while non-exchange transactions are recognized in accordance with ASU No. 2018-08. 
+Total 
+Africa 
+$ 
+8,838,632 
+Asia 
+1,404,982 
+Europe & Middle East 
+4,895,273 
+Latin America 
+12,546,083 
+United States 
+6,896,470 
+$ 
+34,581,440 
+Contract Liabilities 
+Deferred revenue relates to payments received in advance of performance under the contract. Deferred revenue is recognized as revenue as (or when) the Company performs under the contract. At December 31, 2018, the
+Company reported $422,905 in deferred revenue of which $422,905 was earned and recognized as R&D, milestone and grant revenue during the year ended December 31, 2019. At December 31, 2019, the Company reported $125,000 in deferred revenue which
+is expected to be recognized during the first quarter of 2020. 
+In April 2017, the Company entered into a $1.1 million agreement with FIND to develop a simple, point-of-care fever panel assay that can identify multiple life-threatening acute febrile illnesses common in the Asia
+Pacific region. The Company earned $0.2 million and $1.1 million for the year ended December 31, 2019, and from inception through December 31, 2019, respectively as R&D, milestone and grant revenue in the Company’s Consolidated Statements of
+Operations. 
+F-14 
+Table of Contents 
+In August 2016, the Company was awarded a grant of $5.9 million from BARDA, which is part of the U.S. Department of Health And Human Resources to develop a rapid Zika virus assay. The Company earned $0.6 million and
+$5.9 million for the year ended December 31, 2019 and from inception through December 31, 2019, respectively, as R&D, milestone and grant revenue in the Company’s Consolidated Statements of Operations. 
+(k) 
+Research and Development: 
+Research and development (R&D) costs are expensed as incurred. Advance payments for goods and services that will be used in future research and development activities are expensed when the activity has been
+performed or when the goods have been received rather than when the payment is made. 
+(l) 
+Stock-Based Compensation: 
+The fair value of restricted stock and restricted stock unit awards are their fair value on the date of grant. Stock-based compensation expense for stock options is calculated using the Black-Scholes valuation model
+based on awards ultimately expected to vest together with the fair value of restricted stock and restricted stock unit awards, are, reduced for actual forfeitures, and, expensed on a straight-line basis over the requisite service period of the
+grant. During 2018, the Company adopted ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting”. 
+(m) 
+I ncome Taxes: 
+The Company accounts for income taxes under an asset and liability approach that recognizes deferred tax assets and liabilities based on the difference between the financial statement carrying amounts and the tax
+bases of assets and liabilities using enacted tax rates in effect in the years in which the differences are expected to reverse. 
+The Company follows a more-likely-than-not threshold for financial statement recognition and measurement of a tax position taken, or expected to be taken, in a tax return. The guidance relates to, among other things,
+classification, accounting for interest and penalties associated with tax positions, and disclosure requirements. Any interest and penalties accrued related to uncertain tax positions are recorded in tax expense. 
+The Company assesses the realizability of its net deferred tax assets on an annual basis. If, after considering all relevant positive and negative evidence, it is more likely than not that some portion or all of the
+net deferred tax assets will not be realized, the Company will reduce the net deferred tax assets by a valuation allowance. The realization of net deferred tax assets is dependent on several factors, including the generation of sufficient taxable
+income prior to the expiration of net operating loss carryforwards. 
+(n) 
+Loss Per Share: 
+Basic loss per share is computed by dividing net loss attributable to common stockholders by the weighted-average number of common shares outstanding for the period including outstanding restricted stock that by its
+terms is includible in the calculation. Diluted loss per share for the years ended December 31, 2019, and 2018 reflects the potential dilution from the exercise or conversion of other securities into common stock, if dilutive. 
+There were 666,197, and 732,906 options outstanding as of December 31, 2019 and 2018, respectively, which were not included in the calculation of diluted income per share for the years ended because their effect
+would have been anti-dilutive. 
+F-15 
+Table of Contents 
+(o) 
+Goodwill and Intangible Assets: 
+Goodwill represents the excess of the purchase price the Company paid over the fair value of the net tangible and identifiable intangible assets acquired in the Company’s acquisition of opTricon in November 2018,
+Chembio Diagnostics Malaysia in January 2017 and Orangelife in November 2019. Goodwill is not amortized but rather is tested annually as of the first day of the fiscal fourth quarter, or sooner if the Company believes that indicators of impairment
+exist. The Company makes a qualitative evaluation about the likelihood of goodwill impairment, which is based on a number of applicable factors. If the Company concludes that it is more likely than not that the carrying value of the applicable
+reporting unit is greater than its fair value, then it would recognize an impairment charge for the amount by which the carrying value exceeds the reporting unit’s fair value, provided the impairment charge does not exceed the total amount of
+goodwill allocated to the reporting unit. 
+For the year ended December 31, 2019 and 2018, there was no impairment of goodwill and other intangible assets. 
+Following is a table that reflects changes in Goodwill: 
+Beginning balance January 1, 2019 
+$ 
+4,983,127 
+Acquisition of Orangelife 
+986,058 
+Chembio Diagnostics GmbH measurement period adjustment 
+(99,648 
+) 
+Changes in foreign currency exchange rate 
+3,153 
+Balance at December 31, 2019 
+$ 
+5,872,690 
+Intangible assets consist of the following at: 
+Weighted Average 
+Remaining Life 
+December 31, 2019 
+December 31, 2018 
+Cost 
+Accumulated 
+Amortization 
+Net 
+Book Value 
+Cost 
+Accumulated 
+Amortization 
+Net 
+Book Value 
+Intellectual property 
+6 
+$ 
+1,418,681 
+$ 
+299,232 
+$ 
+1,119,449 
+$ 
+1,089,688 
+$ 
+173,633 
+$ 
+916,055 
+Developed technology 
+6 
+1,922,682 
+266,550 
+1,656,132 
+1,910,315 
+– 
+1,910,315 
+Customer contracts/relationships 
+7 
+1,325,521 
+270,902 
+1,054,619 
+1,121,600 
+151,929 
+969,671 
+Trade names 
+8 
+114,946 
+30,794 
+84,152 
+108,521 
+19,731 
+88,790 
+$ 
+4,781,830 
+$ 
+867,478 
+$ 
+3,914,352 
+$ 
+4,230,124 
+$ 
+345,293 
+$ 
+3,884,831 
+Amortization expense for the year ended December 31, 2019 and 2018 was $515,263 and $233,734, respectively, and is recorded within COGS, R&D and Selling, General and Administrative expenses. Amortization expense,
+subject to changes in currency exchange rates, is expected to be approximately $590,000 per year from 2020 through 2024, and total $1 million for all of the years thereafter. 
+F-16 
+Table of Contents 
+(p) 
+Allowance for Doubtful Accounts: 
+The Company records allowances for doubtful accounts for the estimated probable losses on uncollectible accounts receivable. The allowance is based upon the credit worthiness of the Company’s customers, the Company’s
+historical experience, the age of the receivable and current market and economic conditions. Receivables are written off against these allowances in the period they are determined to be uncollectible. 
+(q) 
+Acquisition Costs: 
+Acquisition costs include period expenses, primarily professional services, related to acquisition activities. 
+(r) 
+Foreign Currency Translation: 
+The functional currency of a foreign subsidiary is the local currency. Assets and liabilities of foreign subsidiaries that use a currency other than U.S. dollars as their functional currency are translated to U.S.
+dollars at end of period currency exchange rates. The consolidated statements of operations of foreign subsidiaries are translated to U.S. dollars at average period currency exchange rates. The effect of translation for foreign subsidiaries is
+generally reported in other comprehensive income. Foreign transaction gains/losses are immaterial. 
+(s) 
+Recent Accounting Pronouncements Affecting the Company: 
+In February 2016, the FASB issued ASU No. 2016-02, Leases (“ASU 2016-02”). ASU 2016-02 requires the entity to recognize the assets and liabilities for the rights and
+obligations created by leased assets. Leases will be classified as either finance or operating, with classification affecting expense recognition in the income statement. In July 2018 the FASB issued ASU 2018-10, Codification
+Improvements to Topic 842, Leases , and ASU 2018-11, Leases (Topic 842) Targeted Improvements , which provide supplemental adoption guidance and clarification to ASU 2016-02, and must be adopted
+concurrently with the adoption of ASU 2016-02, cumulatively referred to as “Topic 842”. Topic 842 was effective for the Company in the first quarter of 2019, with early adoption permitted, and was applied using either a modified retrospective
+approach, or an optional transition method which allows an entity to apply the new standard at the adoption date with a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. 
+As further discussed on Note 12(c) – Leases, the Company adopted Topic 842 on January 1, 2019 under the optional transition method and elected the short-term lease exception and available practical expedients. Under
+the transition method, the Company did not adjust its comparative period financial information or make the new required lease disclosures for periods before the effective date. The impact of adoption of right-of-use assets and liabilities on
+January 1, 2019 was $0.8 million, and $0.8 million, respectively. 
+In March 2016, the FASB issued authoritative guidance under ASU 2016-09, Compensation-Stock Compensation (Topic 718) Improvements to Employee Share-Based Payment Accounting .
+ASU 2016-09 provides for simplification of several aspects of the accounting for share-based payment transactions, including income tax consequences, classification of awards as either equity or liabilities and classification on the statement of
+cash flows. The Company adopted ASU 2016-09 on January 1, 2017. As the Company has a full valuation allowance against its U.S. net deferred tax assets, the adoption of this standard for recognition of the tax effect of deductions for employee share
+awards in excess of compensation costs (“windfall”) did not have a material impact on its consolidated financial statements and related disclosures. See Note 8 – Income Taxes, for additional information. Should the full valuation allowance be
+reversed in future periods, the adoption of this new guidance could introduce more volatility in the calculation of the Company’s effective tax rate, depending on the Company’s share price at exercise or vesting of share-based awards as compared to
+grant date. The other provisions of ASU 2016-09 did not have a material impact on the Company’s consolidated financial statements and related disclosures. 
+In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments , which provides guidance related
+to cash flows presentation. The Company adopted ASU 2016-15 in the first quarter of 2018. The guidance in ASU 2016-15 is generally consistent with the Company’s current cash flow classifications,
+and did not have a material impact on the Company’s consolidated financial statements. 
+F-17 
+Table of Contents 
+In January 2017, the FASB issued ASU 2017-04, Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment , which requires an entity to no
+longer perform a hypothetical purchase price allocation to measure goodwill impairment. Instead, impairment will be measured using the difference between the carrying amount and the fair value of the reporting unit. This update will be effective
+for annual and interim periods in fiscal years beginning after December 15, 2019. Early adoption is permitted. The Company adopted ASU 2017-04 in the fourth quarter of 2017. The adoption of this standard did not have a material impact on the
+Company’s consolidated financial statements and related disclosures. 
+In May 2017, the FASB issued ASU No. 2017-09, Compensation-Stock Compensation (Topic 718): Scope of Modification Accounting , to provide clarity to which changes to the
+terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. The Company adopted ASU 2017-09 in the first quarter of 2018. Adoption did not
+have a material effect on the Company’s consolidated financial statements. 
+In July 2017, the FASB issued ASU 2017-11, Accounting for Certain Financial Instruments with Down Round Features and Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and
+Certain Mandatorily Redeemable Noncontrolling Interests with a Scope Exception. Part I of this ASU addresses the complexity of accounting for certain financial instruments with down round features. Per the ASU, a freestanding equity-linked
+financial instrument (or embedded conversion option) no longer would be accounted for as a derivative liability at fair value as a result of the existence of a down round feature. The ASU is effective for public entities for fiscal years beginning
+after December 15, 2018 and the Company adopted it effective January 1, 2019. This ASU is applicable to the stock warrants issued as part of the Credit Agreement, as further discussed in Note 14 – Warrants. 
+In July 2018, the FASB issued ASU 2018-08 N ot-for-Profit
+Entities (Topic 958): Clarifying the Scope and the Accounting Guidance for Contributions Received and Contributions Made to clarify the accounting guidance related to contributions made or
+received. This guidance primarily affects not-for-profit entities, although it also applies to businesses to the extent that they make or receive contributions, including grants. ASU 2018-08 clarifies and improves the scope and accounting
+guidance for both contributions received and made in order to assist entities in evaluating if those transactions should be accounted for as contributions under the scope of Topic 958, or as an exchange transaction subject to other guidance. Public entities are required to apply the amendments on contributions received and contributions made to annual periods beginning after June 15, 2018, and December 15, 2018, respectively, each including
+interim periods within those annual periods. Early adoption is permitted, and the Company adopted ASU 2018-08 effective as of January 1, 2018. The impact of adoption was immaterial. 
+In December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. This standard simplifies the accounting for
+income taxes by eliminating certain exceptions to the guidance in Topic 740 related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities
+for outside basis differences. The new guidance also simplifies aspects of the accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of
+goodwill and allocating consolidated income taxes to separate financial statements of entities not subject to income tax. ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, with early adoption permitted. Upon adoption,
+the Company must apply certain aspects of this standard retrospectively for all periods presented while other aspects are applied on a modified retrospective basis through a cumulative-effect adjustment to retained earnings as of the beginning of
+the fiscal year of adoption. The Company is currently evaluating the impact of this new standard on its consolidated financial statements. 
+In June 2016, the FASB issued a new standard to replace the incurred loss impairment methodology under current GAAP with a methodology that reflects expected credit losses and requires consideration of a broader
+range of reasonable and supportable information to inform credit loss estimates. We will be required to use a forward-looking expected credit loss model for accounts receivables, loans, and other financial instruments. Credit losses relating to
+available-for-sale debt securities will also be recorded through an allowance for credit losses rather than as a reduction in the amortized cost basis of the securities. The standard will be effective for us beginning July 1, 2020, with early
+adoption permitted beginning July 1, 2019. Adoption of the standard will be applied using a modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the effective date to align our credit loss methodology
+with the new standard. We are currently evaluating the impact of this standard in our consolidated financial statements, including accounting policies, processes, and systems. 
+F-18 
+Table of Contents 
+NOTE 4 — INVENTORIES: 
+Inventories consist of the following at December 31, 2019: 
+December 31 
+2019 
+2018 
+Raw Materials 
+$ 
+2,901,319 
+$ 
+2,803,677 
+Work in Process 
+793,343 
+263,043 
+Finished Goods 
+5,903,368 
+4,784,502 
+$ 
+9,598,030 
+$ 
+7,851,222 
+NOTE 5 — FIXED ASSETS: 
+Fixed assets consist of the following at December 31, 2019: 
+December 31 
+2019 
+2018 
+Machinery and Equipment 
+$ 
+7,955,511 
+$ 
+6,070,137 
+Furniture and Fixtures 
+21,477 
+35,287 
+Computer Equipment 
+416,359 
+435,348 
+Leasehold Improvements 
+3,038,469 
+2,334,512 
+Enterprise Business Systems 
+1,830,925 
+462,420 
+Less: Accumulated Depreciation and Amortization 
+(7,329,173 
+) 
+(6,463,784 
+) 
+$ 
+5,933,569 
+$ 
+2,873,920 
+Depreciation expense for the 2019 and 2018 years totaled $933,558 and $634,261, respectively. 
+As of December 31, 2019 and 2018, the Company has purchased manufacturing equipment that is not yet in use and therefore has not been depreciated, aggregating $1,400,181 and $428,859, respectively. 
+NOTE 6 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES: 
+Accounts payable and accrued liabilities consist of the following at December 31, 2019: 
+December 31 
+2019 
+2018 
+Accounts Payable - suppliers 
+$ 
+3,144,098 
+$ 
+3,622,765 
+Accrued Commissions & Royalties 
+931,760 
+867,344 
+Accrued Payroll 
+231,753 
+48,867 
+Accrued Vacation 
+410,199 
+264,789 
+Accrued Bonuses 
+215,000 
+494,318 
+Accrued Expenses - Other 
+593,433 
+590,598 
+$ 
+5,526,243 
+$ 
+5,888,681 
+F-19 
+Table of Contents 
+NOTE 7 — DEFERRED RESEARCH AND DEVELOPMENT REVENUE: 
+The Company recognizes income from R&D milestones when those milestones are reached and non-milestone contracts and grants when earned. These projects are invoiced after expenses are incurred. Any projects or
+grants funded in advance are deferred until earned. As of December 31, 2019 and 2018, there were $125,000 and $422,905 unearned advanced revenues, respectively. 
+NOTE 8 — INCOME TAXES: 
+The components of (loss) before income taxes consisted of the following: 
+Year Ending December 31, 
+2019 
+2018 
+United States operations 
+$ 
+(12,504,780 
+) 
+$ 
+(7,137,428 
+) 
+International operations 
+(1,670,641 
+) 
+(795,742 
+) 
+(Loss) before taxes 
+$ 
+(14,175,421 
+) 
+$ 
+(7,933,170 
+) 
+T he (benefit from) provision for income taxes for the years ended December 31, 2019 and 2018 is comprised of the following: 
+Year Ending December 31, 
+2019 
+2018 
+Current 
+Federal 
+$ 
+– 
+$ 
+– 
+State 
+9,790 
+10,911 
+Foreign 
+3,633 
+– 
+Total current (benefit) provision 
+13,423 
+10,911 
+Deferred 
+Federal 
+– 
+– 
+State 
+– 
+– 
+Foreign 
+(513,715 
+) 
+(78,435 
+) 
+Total deferred (benefit) provision 
+(513,715 
+) 
+(78,435 
+) 
+Total (benefit) provision 
+$ 
+(500,292 
+) 
+$ 
+(67,521 
+) 
+A reconciliation of the Federal statutory rate to the effective rate applicable to loss before income taxes is as follows: 
+Year Ending December 31, 
+2019 
+2018 
+Federal income tax at statutory rates 
+21.00 
+% 
+21.00 
+% 
+State income taxes, net of federal benefit 
+(0.05 
+)% 
+(0.10 
+)% 
+Nondeductible expenses 
+(1.00 
+)% 
+(1.58 
+)% 
+Foreign rate differential 
+0.45 
+% 
+0.36 
+% 
+Change in valuation allowance 
+(17.51 
+)% 
+(18.44 
+)% 
+Other 
+0.64 
+% 
+(0.39 
+)% 
+Income tax benefit 
+3.53 
+% 
+0.85 
+% 
+In January 2018, the FASB released guidance on the accounting for tax on the global intangible low-taxed income (“GILTI”) provisions of the Tax Act. The GILTI provisions impose a tax on foreign income
+in excess of a deemed return on tangible assets of foreign corporations. The guidance allows companies to make an accounting policy election to either (1) account for GILTI as a component of tax expense in the period in which they are subject to
+the rules (the period cost method), or (ii) account for GILTI in the Company’s measurement of deferred taxes (the deferred method). After completing the analysis of the GILTI provisions, the Company elected to account for GILTI using the period
+cost method. 
+F-20 
+Table of Contents 
+The Company had an ownership change as described in Internal Revenue Code Sec. 382 during 2004 (“2004 change”). As a result, the Company’s net operating losses prior to the 2004 change of $5,832,516
+were subject to an annual limitation of $150,608 and for the first five (5) years are entitled to a BIG (Built-In-Gains) of $488,207 per year. These net operating losses expire in 2020 through 2024. 
+The Company had a second ownership change during 2006 (“2006 change”). The net operating losses incurred between the 2004 change and the 2006 change of $8,586,861 were subject to an annual limitation
+of $1,111,831 and for the first five (5) years are entitled to a BIG of $1,756,842 per year. These net operating losses expire in 2024 through 2026. 
+After applying the above limitations, at December 31, 2019, the Company has post-change net operating loss carry-forwards of approximately $ 27,235,494 
+which expire between 2020 and 2037 and $ 16,242,683 which do not expire. In addition the Company has research and development tax credit carryforwards of approximately $ 1,679,495 for the year ended December 31, 2019 , which expire between 2020 and 2036. 
+The Company has state net operating loss carryforwards of approximately $ 1,912,798 which generally expire between 2035 and 2039. The Company has
+foreign net operating loss carryforwards of approximately $3,355,645 which generally expire between 2025 and 2026. 
+2019 
+2018 
+Inventory reserves 
+$ 
+196,193 
+$ 
+204,206 
+Accrued expenses 
+105,323 
+175,168 
+Net operating loss carry-forwards 
+10,079,317 
+7,122,576 
+Research and development credit 
+1,679,495 
+1,696,870 
+Stock-based compensation 
+581,053 
+215,797 
+Lease obligations 
+1,646,584 
+– 
+Depreciation 
+44,993 
+139,362 
+Total deferred tax assets 
+14,332,958 
+9,553,979 
+Right-of-use assets 
+(1,538,129 
+) 
+– 
+Intangibles 
+(921,807 
+) 
+(968,849 
+) 
+Total deferred tax liabilities 
+(2,459,936 
+) 
+(968,849 
+) 
+Net deferred tax assets before valuation allowance 
+11,873,022 
+8,585,130 
+Less valuation allowances 
+(12,339,348 
+) 
+(9,477,438 
+) 
+Net noncurrent deferred tax liabilities 
+$ 
+(466,326 
+) 
+$ 
+(892,308 
+) 
+The Company does not provide for U.S. income taxes on unremitted earnings of foreign subsidiaries as its present intention is to reinvest the unremitted earnings in the Company’s foreign operations.
+At December 31, 2019 there were no unremitted earnings of foreign subsidiaries. 
+Interest and penalties, if any, related to income tax liabilities are included in income tax expense. As of December 31, 2019, the Company does not have a liability for uncertain tax positions. 
+F-21 
+Table of Contents 
+The Company files Federal and state income tax returns, Chembio Germany files in Germany, Chembio Brazil files in Brazil and Chembio Malaysia files in Malaysia and has been on tax
+holiday which expired on December 31, 2018. With few exceptions, tax years for fiscal 2016 through 2019 are open and potentially subject to examination by federal,
+state and foreign taxing authorities. 
+NOTE 9 — STOCKHOLDERS’ EQUITY: 
+(a) 
+Common Stock 
+During 2019, options to purchase 54,343 shares of the Company’s common stock were exercised for 31,543 shares of common stock at exercise prices ranging from $3.48 to $4.35. During 2018, options to purchase 144,947
+shares of the Company’s common stock were exercised for 71,290 shares of common stock at exercise prices ranging from $3.48 to $5.64 by surrendering options and shares of common stock already owned. 
+In November 2018, the Company closed on an underwritten public offering of 2,726,000 shares of its common stock, including the underwriter’s exercise of its overallotment of 355,565 shares, at $6.75 per share. The
+net proceeds of the offering, after deducting the underwriter’s discounts and other offering expenses payable by the Company, was approximately $16.5 million. 
+In February 2018, the Company closed on an underwritten registered public offering of 1,783,760 shares of its common stock at $6.75 per share. The net proceeds of the offering, after deducting the underwriter’s
+discounts and other offering expenses payable by the Company, was approximately $10.9 million. 
+(b) 
+Preferred Stock 
+The Company has 10,000,000 shares of preferred stock authorized and none outstanding. These shares can become issuable upon an approved resolution by the board of directors and the filing of a Certificate of
+Designation with the state of Nevada. 
+(c) 
+Options, Restricted Stock, and Restricted Stock Units 
+The Board of Directors or its Compensation Committee may issue options, restricted stock, and restricted stock units pursuant to employee stock incentive plans that have been approved by the Company’s stockholders. 
+(d) 
+Warrants 
+As of December 31, 2019, the Company has 550,000 warrants outstanding to purchase shares of common stock as further discussed in Note 14 – Warrants. 
+NOTE 10 — EQUITY INCENTIVE PLANS: 
+Effective June 3, 2008, the Company’s stockholders voted to approve the 2008 Stock Incentive Plan (“SIP”), with 625,000 shares of common stock available to be issued. At the Annual Stockholder Meeting on September
+22, 2011 the Company’s stockholders voted to approve an increase to the shares of common stock issuable under the SIP by 125,000 to 750,000. Under the terms of the SIP, which expired during 2018, the Board of Directors or its Compensation
+Committee had the discretion to select the persons to whom awards were to be granted. Awards could be stock options, restricted stock and/or restricted stock units (“Equity Award Units”). The awards became vested at such times and under such
+conditions as determined by the Board or its Compensation Committee. Cumulatively through December 31, 2019, there were 0 options exercised, and at December 31, 2019, 0 options were outstanding and no Equity Award Units were available to be issued
+under the SIP. 
+F-22 
+Table of Contents 
+Effective June 19, 2014, the Company’s stockholders voted to approve the 2014 Stock Incentive Plan (“SIP14”), with 800,000 shares of common stock available to be issued. Under the terms of the SIP14, the Board or
+its Compensation Committee has the discretion to select the persons to whom awards are to be granted. Awards can be in the form of Equity Award Units. The awards become vested at such times and under such conditions as determined by the Board or
+its Compensation Committee. Cumulatively through December 31, 2019, there were 54,343 options exercised, and at December 31, 2019, 642,625 options were outstanding and 148,667 Equity Award Units were still available to be issued under the SIP14. 
+Effective June 18, 2019, the Company’s stockholders voted to approve the 2019 Omnibus Incentive Plan (“2019 Plan”), with 2,400,000 shares of common stock available to be issued. In addition, shares of Common Stock
+underlying any outstanding award granted under the 2019 Plan that, following the effective date of the 2019 Plan, expires, or is terminated, surrendered or forfeited for any reason without issuance of such shares shall be available for the grant of
+new awards under the 2019 Plan. Under the terms of the 2019 Plan, the Board or its Compensation Committee has the discretion to select the persons to whom awards are to be granted. Awards can be in the form of options, stock appreciation rights,
+restricted stock, restricted stock unit, or other stock-based award under the 2019 Plan (collectively, 2019 Equity Units). The awards become vested at such times and under such conditions as determined by the Board or its Compensation Committee.
+Cumulatively through December 31, 2019, there were 375,000 2019 Equity Units awarded under the 2019 Plan, and 2,025,000 2019 Equity Units available to be awarded. 
+The Company’s results for the years ended December 31, 2019 and 2018 include stock-based compensation expense totaling $1,655,900 and $632,805, respectively. Such amounts have been included in the Consolidated
+Statements of Operations within cost of product sales ($10,806 and $25,615, respectively), research and development ($228,597 and $78,831, respectively) and selling, general and administrative expenses ($1,416,497 and $528,360, respectively). 
+Stock option compensation expense in the years ended December 31, 2019 and 2018 represents the estimated fair value of options outstanding, which is being amortized on a straight-line basis over the requisite vesting
+period of the entire award. The stock compensation expense were $261,088 and $351,556 in December 31, 2019 and 2018, respectively. 
+No stock options were issued during 2019. The weighted average estimated fair value of stock options granted in the year ended December 31, 2018 was $3.76 per share. The fair value of options at the date of grant was
+estimated using the Black-Scholes option pricing model. The expected volatility is based upon historical volatility of the Company’s stock and other contributing factors. The expected term is based on the Company’s historical experience with
+similar type options. 
+The weighted-average assumptions made in calculating the fair values of options are as follows for the respective years ended December 31: 
+2019 
+2018 
+Expected term (in years) 
+n/a 
+4.96 
+Expected volatility 
+n/a 
+39.91 
+% 
+Expected dividend yield 
+n/a 
+n/a 
+Risk-free interest rate 
+n/a 
+2.70 
+% 
+F-23 
+Table of Contents 
+The following table provides stock option activity for the years ended December 31, 2019 and 2018: 
+Number 
+of Shares 
+Weighted 
+Average 
+Exercise Price 
+per Share 
+Weighted 
+Average 
+Remaining 
+Contractual Term 
+Aggregate 
+Intrinsic 
+Value 
+Outstanding at December 31, 2017 
+810,670 
+$ 
+5.18 
+3.69 years 
+$ 
+2,477,853 
+Granted 
+93,750 
+9.80 
+Exercised 
+144,947 
+4.83 
+523,327 
+Forfeited/expired/cancelled 
+47,505 
+8.82 
+Outstanding at December 31, 2018 
+711,968 
+$ 
+5.62 
+3.33 years 
+$ 
+687,364 
+Exercisable at December 31, 2018 
+396,799 
+$ 
+4.70 
+2.66 years 
+$ 
+568,956 
+Outstanding at December 31, 2018 
+711,968 
+$ 
+5.62 
+3.33 years 
+$ 
+687,364 
+Granted 
+– 
+$ 
+0.00 
+– 
+Exercised 
+54,343 
+$ 
+3.60 
+172,242 
+Forfeited/expired/cancelled 
+15,000 
+$ 
+5.68 
+– 
+Outstanding at December 31, 2019 
+642,625 
+$ 
+5.79 
+2.57 years 
+$ 
+285,925 
+Exercisable at December 31, 2019 
+493,958 
+$ 
+5.22 
+2.20 years 
+$ 
+285,925 
+The following table summarizes information about stock options outstanding at December 31, 2019: 
+Stock Options Outstanding 
+Stock Options Exercisable 
+Range of 
+Exercise Prices 
+Shares 
+Outstanding 
+Average 
+Remaining 
+Contract Life 
+(Year) 
+Weighted 
+Average 
+Exercise 
+Price 
+Aggregate 
+Intrinsic 
+Value 
+Shares 
+Exercisable 
+Weighted 
+Average 
+Exercise 
+Price 
+Aggregate 
+Intrinsic 
+Value 
+1 to 2.79999 
+– 
+– 
+$ 
+– 
+$ 
+– 
+– 
+$ 
+– 
+$ 
+– 
+2.8 to 4.59999 
+250,000 
+1.20 
+3.42 
+285,925 
+250,000 
+3.42 
+285,925 
+4.6 to 6.39999 
+137,875 
+2.44 
+5.87 
+– 
+87,125 
+5.89 
+– 
+6.4 to 8.19999 
+207,875 
+4.05 
+7.31 
+– 
+138,083 
+7.22 
+– 
+8.2 to 12 
+46,875 
+3.60 
+11.45 
+– 
+18,750 
+11.45 
+– 
+Total 
+642,625 
+2.57 
+$ 
+5.79 
+$ 
+285,925 
+493,958 
+$ 
+5.22 
+$ 
+285,925 
+The average remaining contract life for the shares exercisable is 2.2 years, as of December 31, 2019. 
+As of December 31, 2019, there was $432,746 of net unrecognized compensation cost related to stock options that are not vested, which is expected to be recognized over a weighted average period of approximately 2.00
+years. The total fair value of shares vested during the year ended December 31, 2019, was $469,032. 
+F-24 
+Table of Contents 
+The following table summarizes information about restricted stock and restricted stock units outstanding as of December 31, 2019: 
+Number of 
+Shares & Units 
+Weighted 
+Average 
+Grant Date 
+Fair Value 
+Unvested at December 31, 2018 
+287,564 
+$ 
+9.65 
+Granted 
+375,000 
+5.80 
+Vested 
+(116,578 
+) 
+9.65 
+Forfeited/expired/cancelled 
+– 
+– 
+Unvested at December 31, 2019 
+545,986 
+7.47 
+As of December 31, 2019, there was $3,273,929 of net unrecognized compensation cost related to restricted stock and restricted stock units that are not vested, which is expected to be recognized over a weighted
+average period of approximately 1.4 years. Stock based compensation cost related to restricted stock and restricted stock units recognized during the years ended December 31, 2019 and 2018 was $1,394,814 and $281,249, respectively. 
+NOTE 11 — GEOGRAPHIC INFORMATION AND ECONOMIC DEPENDENCY: 
+The Company produces only one group of similar products known collectively as “rapid medical tests,” and it operates in a single business segment. Net product sales by geographic area are as follows: 
+Year Ending December 31, 
+2019 
+2018 
+Africa 
+$ 
+7,564,360 
+$ 
+8,838,632 
+Asia 
+888,800 
+1,404,982 
+Europe & Middle East 
+3,781,761 
+2,208,063 
+Latin America 
+11,808,767 
+12,546,083 
+United States 
+4,801,309 
+2,915,449 
+$ 
+28,844,997 
+$ 
+27,913,209 
+Long-lived assets by geographic area are as follows: 
+2019 
+2018 
+Asia 
+$ 
+393,299 
+$ 
+466,185 
+Europe & Middle East 
+165,029 
+123,752 
+Latin America 
+60,527 
+– 
+United States 
+5,314,715 
+2,283,983 
+$ 
+5,933,569 
+$ 
+2,873,920 
+NOTE 12 — COMMITMENTS, CONTINGENCIES AND CONCENTRATIONS: 
+a) 
+Employment Contracts: 
+The Company has multi-year contracts with two key employees. The contracts call for salaries presently aggregating $730,000 per year, and they expire in March 2020 and December 2021. The following table is a
+schedule of future minimum salary commitments: 
+2020 
+$ 
+365,000 
+2021 
+365,000 
+Chembio’s President & CEO, the key employee whose agreement was set to expire in March 2020, resigned effective as of January 3, 2020. 
+F-25 
+Table of Contents 
+b) 
+Pension Plan: 
+The Company has a 401(k) plan established for its employees whereby it matches 40% of the first 5% (or 2% of salary) that an employee contributes to the plan. Matching contribution expenses totaled $93,892 and
+$94,544 for the years ended December 31, 2019 and 2018, respectively. 
+c) 
+Leases: 
+Chembio’s leases have historically been limited to its facilities in New York, Germany, Malaysia & Brazil. As of December 31, 2019, the Company was a party to eight leases. One of the leases is subject to a
+sublease for the remainder of its term, as further described below. 
+The Company’s leases generally include optional renewal periods. Upon entering into a new lease, the Company evaluates the leasehold improvements and regulatory requirements related to its operations in that
+location. To the extent that the initial lease term of the related lease is less than the useful life of the leasehold improvements and potential regulatory costs associated with moving the facility, the Company concludes that it is reasonably
+certain that a renewal option will be exercised, and thus that renewal period is included in the lease term and the related payments are reflected in the right-of-use (“ROU”) asset and lease liability. In January 2019 the Company recognized $0.8
+million and $0.8 million of right-of-use assets and liabilities, respectively. During 2019, the Company entered into a new lease agreement for its new headquarter location in Hauppauge, NY. The right-of-use asset acquired in exchange for
+right-of-use liabilities was approximately $6.5 million. 
+The Company’s leases generally include fixed rental payments with defined annual increases. While certain of the Company’s leases are gross leases, the majority of the Company’s leases are net leases in which the
+Company makes separate payments to the lessor based on the lessor’s property and casualty insurance costs, the property taxes assessed on the property, and a portion of the common area maintenance where applicable. The Company has elected the
+practical expedient not to separate lease and nonlease components for all of the Company’s facility leases. The Company has also elected the practical expedient for short-term lease exception for all of its facility leases. 
+The components of lease expense were as follows: 
+Year Ended 
+December 31, 2019 
+Operating lease expense 
+$ 
+1,655,573 
+Finance lease cost 
+Amortization of right-of-use assets 
+$ 
+23,372 
+Interest on lease liabilities 
+7,892 
+Total finance lease expense 
+$ 
+31,265 
+Rent expense was $653,155 for the year ended December 31, 2018. 
+Supplemental cash flow and other information related to leases were as follows: 
+Year Ended 
+December 31, 2019 
+Cash paid for amounts included in the measurement of lease liabilities: 
+Operating cash flows for operating leases 
+$ 
+632,952 
+Operating cash flows for finance leases 
+7,892 
+Financing cash flows for finance leases 
+19,875 
+Right-of-use assets obtained in exchange for lease obligations: 
+Operating leases 
+$ 
+7,030,744 
+Finance leases 
+210,350 
+F-26 
+Table of Contents 
+Supplemental balance sheet information related to leases was as follows: 
+December 31, 2019 
+Operating Leases 
+Operating lease right-of-use assets 
+$ 
+7,030,744 
+– 
+Current portion of operating lease liability 
+568,294 
+Operating lease liabilities 
+6,969,603 
+Total operating lease liabilities 
+$ 
+7,537,897 
+Finance Leases 
+Finance lease right of use asset 
+$ 
+233,722 
+Accumulated depreciation 
+(23,372 
+) 
+Finance lease right of use asset, net 
+$ 
+210,350 
+Current portion of finance lease liability 
+41,894 
+Finance lease liability 
+171,953 
+Total finance lease liabilities 
+$ 
+213,847 
+Weighted Average Remaining Lease Term 
+Operating leases 
+9.3 years 
+Finance leases 
+4.8 years 
+Weighted Average Discount Rate 
+Operating leases 
+8.67 
+% 
+Finance leases 
+7.00 
+% 
+During 2019, the Company executed an operating sublease related to its former Holbrook, New York facility. The sublease runs conterminously with the base lease in Holbrook, for which the Company remains primarily
+responsible. In addition, the Company entered into a finance lease agreement relating to office furniture in June 2019. The Company recognized the corresponding lease asset and liability effective June 30, 2019 and recorded related depreciation
+starting on July 1, 2019. Monthly payments towards this lease commenced in July 2019. 
+At the time of the initial assessment, the Company did not have an established incremental borrowing rate and the interest rates implicit in each of the leases were not readily determinable, therefore the Company
+used an interest rate based on the market place for public debt. In September 2019, the Company entered into a credit agreement for a $20 million term loan as described on Note 13 - Long Term Debt. 
+Maturities of lease liabilities as of December 31, 2019 were as follows. 
+Operating 
+Leases 
+Finance 
+Leases 
+2020 
+$ 
+1,205,161 
+$ 
+55,536 
+2021 
+1,209,787 
+55,536 
+2022 
+1,057,757 
+55,536 
+2023 
+1,026,272 
+55,536 
+2024 
+1,018,875 
+27,767 
+Thereafter 
+5,773,887 
+– 
+Total lease payments 
+$ 
+11,291,739 
+$ 
+249,911 
+Less: imputed interest 
+(3,753,842 
+) 
+(36,064 
+) 
+Total 
+$ 
+7,537,897 
+$ 
+213,847 
+F-27 
+Table of Contents 
+As previously disclosed in the Company’s 2018 Annual Report on Form 10-K, and under the previous lease accounting standard, future minimum lease payments for operating leases having initial or remaining
+non-cancellable lease terms in excess of one year would have been as follows for the years ending December 31: 
+2019 
+$ 
+384,308 
+2020 
+88,576 
+2021 
+– 
+$ 
+472,884 
+d) 
+Economic Dependency: 
+Customers are considered major customers when net sales exceed 10% of the Company’s total net sales for period or outstanding trade receivables exceed 10% of accounts receivable. The Company had the following major
+customers for the respective periods: 
+For the years ended 
+Accounts Receivable 
+December 31, 2019 
+December 31, 2018 
+December 31, 
+2019 
+December 31, 
+2018 
+Net Sales 
+% of Net 
+Sales 
+Net Sales 
+% of Net 
+Sales 
+Customer 1 
+$ 
+11,263,573 
+39 
+% 
+$ 
+11,333,767 
+33 
+% 
+$ 
+941,962 
+$ 
+3,499,340 
+Customer 2 
+5,782,543 
+20 
+% 
+4,346,640 
+13 
+% 
+16,033 
+1,033,824 
+The following table delineates purchases the Company had with vendors in excess of 10% of total purchases for the periods indicated: 
+For the years ended 
+Accounts Payable 
+December 31, 2019 
+December 31, 2018 
+December 
+31, 2019 
+December 
+31, 2018 
+Purchases 
+% of Purc. 
+Purchases 
+% of 
+Purc. 
+Vendor 1 
+* 
+* 
+1,646,614 
+16 
+% 
+* 
+164,312 
+In the tables above, an asterisk (*) indicates that purchases from the vendor did not exceed 10% for the period indicated. 
+The Company purchases materials pursuant to intellectual property rights agreements that are important components in its products. Management believes that other suppliers could provide similar materials on
+comparable terms. A change in suppliers, however, could cause a delay in manufacturing and a possible loss of sales, which could adversely affect operating results. 
+F-28 
+Table of Contents 
+e) 
+Litigation: 
+From time to time, the Company is involved in certain legal actions arising in the ordinary course of business. The outcomes of such actions, either individually or in the aggregate, are not expected to have a
+material adverse effect on the Company’s future financial position or results of operations. 
+f) 
+Governmental Regulation: 
+All of the Company’s existing and proposed diagnostic products are regulated by the U.S. Food and Drug Administration, U.S. Department of Agriculture, certain U.S., state and local agencies, and/or comparable
+regulatory bodies in other countries. Most aspects of development, production, and marketing, including product testing, authorizations to market, labeling, promotion, manufacturing, and record keeping, are subject to regulatory review. After
+marketing approval has been granted, Chembio must continue to comply with governmental regulations. Failure to comply with applicable requirements can lead to sanctions, including withdrawal of products from the market, recalls, refusal to
+authorize government contracts, product seizures, civil money penalties, injunctions, and criminal prosecution. 
+NOTE 13 — LONG-TERM DEBT: 
+In September 2017, the Company entered into an agreement with an equipment vendor to purchase automated assembly equipment for approximately $660,000. The terms call for payments of 30% down, 60% at time of factory
+acceptance testing and 10% after delivery. The vendor agreed to lend the Company 15%, 40%, and 10%, of each originally scheduled payment, respectively. The Company paid interest at an annual rate of 12% until delivery. Beginning in September
+2018, the Company began making monthly payments of principal and interest of approximately $20,150, at an annual rate of 12% over a twenty-four month period. The remaining balance was entirely short-term as of December 31, 2019. 
+On September 3, 2019, the Company entered into a Credit Agreement and Guaranty (the “Credit Agreement”) with Perceptive Credit Holdings II, LP (the “Lender”). The Credit Agreement provides for a $20,000,000 senior
+secured term loan credit facility, which was drawn in full on September 4, 2019. Under the terms of the Credit Agreement, the Company may use the proceeds (i) for general working capital purposes and other permitted corporate purposes, (ii) to
+refinance certain of the Company’s existing indebtedness and (iii) to pay fees, costs and expenses incurred in connection with the Credit Agreement, including the Lender’s closing cost amount of $550,000, which was netted from the proceeds, and a
+financing fee of $600,000 (3.0% of gross proceeds) payable to Craig-Hallum Capital Group LLC, the Company’s financial advisor for the financing. 
+Principal outstanding under the Credit Agreement bears interest at a rate per annum equal to the sum of (a) the greater of the one-month London Interbank Offered Rate and 2.5% plus (b) 8.75%. At any time at which an
+event of default has occurred and is continuing, the interest rate will increase by 4.0%. Accrued interest is payable on a monthly basis. On December 31, 2019 the interest rate was 11.25%. 
+No principal repayments are due under the Credit Agreement prior to September 30, 2022, unless the Company elects to prepay principal or principal is accelerated pursuant to an event of default identified in the
+Credit Agreement. Principal installments in the amount of $300,000 are payable on the last day of each of the eleven months from September 2022 through July 2023, and all remaining principal is payable at maturity on September 3, 2023. The Company
+may prepay outstanding principal from time to time, subject to payment of a premium on the prepaid principal amount equal to 10% through September 3, 2020, 8% from September 4, 2020 through September 3, 2021, and 4% from September 4, 2021 through
+September 3, 2022. No premium will be due with respect to any prepayment made on or after September 4, 2022. 
+As of December 31, 2019, the loan balance, net of unamortized discounts and debt issuance costs, was $17.6 million, and the company was in compliance with its loan covenants. Our obligations under the Credit Agreement are secured by a first
+priority, perfected lien on substantially all of our property and assets, including our equity interests in our subsidiaries. 
+F-29 
+Table of Contents 
+NOTE 14 — WARRANTS: 
+In connection with entering into the Credit Agreement, on September 3, 2019, the Company issued to the Lender a seven-year warrant (the “Warrant”) to purchase up to 550,000 shares of the Company’s common stock at a
+per-share exercise price of $5.22. The Warrant is exercisable for cash or on a net, or “cashless,” basis, and the exercise price of the Warrant is subject to price-based, weighted-average antidilution adjustments for one year after issuance. 
+The Warrant was evaluated by the Company and classified to stockholder’s equity. Its fair value was estimated using a Black-Scholes
+option-pricing model using the assumptions below. 
+Stock price on issuance date 
+$ 
+5.40 
+Strike Price 
+$ 
+5.22 
+Risk-free interest rate 
+1.45 
+% 
+Volatility 
+43.65 
+% 
+Expected life 
+7 years 
+The fair value of the Warrant was determined to be approximately $1.4 million at $2.49 per share. 
+As of December 31, 2019, the balance recorded in the Company’s Stockholders’ Equity for the Warrants, net of allocated issuance costs, was $1.2 million. 
+As of December 31, 2019, no warrants were exercised and no warrants have expired. 
+F-30
\ No newline at end of file
diff --git a/raw/filings/0001092662/2019/0001140361-20-005780/filing_metadata.csv b/raw/filings/0001092662/2019/0001140361-20-005780/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..fa8994e9356373c756e674236edce32bade0da10
--- /dev/null
+++ b/raw/filings/0001092662/2019/0001140361-20-005780/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0001092662,CEMI,"CHEMBIO DIAGNOSTICS, INC.",10-K,2020-03-13,2019-12-31,2020-03-13T21:10:04.000Z,0001140361-20-005780,form10k.htm,10-K,8079855,1,0,https://www.sec.gov/Archives/edgar/data/1092662/000114036120005780/form10k.htm,https://www.sec.gov/Archives/edgar/data/1092662/000114036120005780/,2019,2019,1
diff --git a/raw/filings/0001092662/2019/0001140361-20-005780/item1.txt b/raw/filings/0001092662/2019/0001140361-20-005780/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..d628be5a62307c47d66761754c0a1cfb4b60c7ac
--- /dev/null
+++ b/raw/filings/0001092662/2019/0001140361-20-005780/item1.txt
@@ -0,0 +1,452 @@
+ITEM 1. 
+BUSINESS 
+Overview 
+We are a leading provider of point-of-care diagnostic products for the detection and diagnosis of infectious diseases. We have been expanding our product portfolio based upon our proprietary Dual Path Platform, which
+we refer to as DPP, which uses a small drop of blood from the fingertip to provide high-quality, cost-effective diagnostic results in approximately 15 minutes. We seek to build additional revenue streams by entering into technology collaborations
+with leading global healthcare companies to leverage the DPP technology platform. 
+Compared with traditional lateral flow technology, the DPP technology platform provides enhanced sensitivity and specificity, advanced multiplexing capabilities, and, when used with the DPP Micro Reader, quantitative
+results. Our DPP test for human immunodeficiency virus, or HIV, provides sensitivity of 99.8% and specificity of 100%, and has been approved by the U.S. Food and Drug Administration, or FDA, and cleared as a waived test under the Clinical Laboratory
+Improvement Amendments of 1988, or CLIA. 
+On November 6, 2018, we completed our acquisition of opTricon GmbH, a Berlin-based developer and manufacturer of handheld analyzers for rapid diagnostic tests, which we believe will enable us to promote DPP tests and
+DPP Micro Readers more actively across global markets. On November 25, 2019, we completed our acquisition of Orangelife Comercio e Industria Ltda., a Brazilian manufacturer of lateral flow tests for infectious diseases to diversify our market channel
+penetration in Brazil and support Bio-Manguinos, a major customer. 
+We are pursuing three corporate priorities, the key building blocks to drive growth and operating efficiency: (1) expand our commercialization; (2) advance our research and development pipeline; and (3) prepare for
+future growth. 
+Industry 
+The DPP technology platform addresses the lateral flow test market, which includes infectious diseases, cardiac markers, cholesterol and lipids, pregnancy and fertility, and drugs of abuse. Based on our review of
+third-party reports and other information, we estimate that the market for lateral flow tests will increase from $5.5 billion in 2017 to $8.2 billion in 2022, representing a compound annual growth rate of 8.2%. 
+Infectious disease tests constitute the largest and fastest growing, segment of the lateral flow test market. We currently are targeting lateral flow test solutions for infectious diseases: sexually transmitted disease
+and mosquito-borne disease. The market for lateral flow infectious disease tests is being driven by the high prevalence of infectious diseases globally, an increase in the geriatric population, growing demand for rapid test results, and advancements
+in multiplexing. Based on our review of third-party reports and other information, we estimate that the market for lateral flow infectious disease tests will increase from $1.4 billion in 2017 to $2.3 billion in 2022, representing a compound annual
+growth rate of 10.7%. 
+5 
+Table of Contents 
+Products 
+Our point-of-care infectious disease portfolio is comprised of multiple commercial products, each serving unique customer requirements. The key advantages of our products, which are performed with a tiny drop of blood
+from the fingertip and provide results in approximately 15 minutes, include: 
+• 
+enhanced sensitivity and specificity; 
+• 
+advanced multiplexing; and 
+• 
+quantitative results, when used with DPP Micro Reader. 
+We have obtained FDA approvals and, directly or through our partners, international regulatory approvals for infectious disease tests as follows: 
+Product (Assay) 
+U.S. 
+International 
+DPP HIV 1/2 
+✓ 
+✓ 
+DPP HIV-Syphilis 
+✓ 
+DPP Syphilis Screen & Confirm 
+✓ 
+DPP Zika 
+✓ 
+✓ 
+DPP Leishmaniasis 
+✓ 
+STAT-PAK HIV 1/2 
+✓ 
+✓ 
+STAT-PAK Chagas 
+✓ 
+SURE CHECK HIV 1/2 
+✓ 
+✓ 
+SURE CHECK HIV 1/2 Self Test 
+✓ 
+Organic growth in our core infectious disease business is being driven by: 
+• 
+growth in the overall market for lateral flow infectious disease tests, which we estimate will increase at a compound annual growth rate of 10.7% through 2022 (see “–Industry”
+above); 
+• 
+our increased market penetration in existing markets and channels, including in the United States, Latin America, Africa and Europe; 
+• 
+our registration of existing and new products in unchartered countries and regions, such as selected countries in Latin America and Southeast Asia; 
+• 
+our entry into new market segments, such as international HIV Self-Testing; and 
+• 
+advances in our product pipeline in infectious disease with key products including a multiplex test for HIV and syphilis in the U.S. market and tests for dengue, zika and
+chikungunya. 
+6 
+Table of Contents 
+We market and sell both stand-alone and multiplex tests for sexually transmitted infectious diseases, such as HIV and syphilis. HIV and syphilis continue to be major global public health issues. According to WHO
+estimates: 
+• 
+HIV has claimed more than 35 million lives, including 770,000 in 2018. Approximately 37.9 million people were living with HIV at the end of 2018, and 1.7 million were newly
+infected during 2018. 
+• 
+There were 18.0 million prevalent cases of syphilis as of 2012, and 5.6 million new infections were estimated to occur annually. 
+• 
+Elimination of mother-to-child transmission, or MTCT, of both HIV and syphilis is a global health priority. In 2013, 1.9 million pregnant women were infected with syphilis
+worldwide. Congenital syphilis contributes significantly to infant mortality, accounting for 305,000 annual perinatal deaths worldwide in 2013. Globally, more than 1.4 million pregnant women were infected with HIV as of 2015, and MTCT of
+HIV is estimated to have resulted in over 150,000 infant cases in 2015. 
+We are seeking to address the global concerns related to HIV and syphilis co-infection through the development of a novel, multiplex test for both HIV and syphilis. We have developed a DPP HIV-Syphilis multiplex test
+and received regulatory approvals covering a number of international markets, including Brazil, Europe, Malaysia and Mexico. In the United States we completed a DPP HIV-Syphilis clinical trial but in February 2020 received a “not approvable” letter
+from the FDA with respect to our Premarket Approval, or PMA, application on our DPP HIV-Syphilis multiplex test for commercial use in the United States. The FDA has confirmed that, of the items that had been open for review in the PMA application,
+the syphilis arm of the study was acceptable, as were the results as they relate to the inclusion of pregnant women. The only remaining item requested of us was to repeat the reproducibility study, as one of the sites in the trial reported greater
+variability compared to the other sites. We have initiated the reproducibility study required by the FDA and, in parallel, accelerated the studies for a CLIA waiver, which can be submitted upon FDA approval of the PMA application. We believe we
+continue to be well-positioned to be the first company to introduce a multiplex rapid test for HIV and syphilis in the United States.
+We also market and sell tests for selected fever and tropical diseases such as Chagas, ebola, leishmaniasis and Zika. The market for lateral flow mosquito-borne diseases includes established markets for disease such as
+dengue and malaria, which WHO estimates together account for more than 600 million annual infections worldwide. There are also a number of emerging markets for lateral flow tests for infectious diseases such as burkholderia, chikungunya, lassa,
+leptospirosis, Marburg, rickettsia and Zika. We are developing tests, using the DPP platform, to detect all of the aforementioned fever and tropical diseases, as stand-alone or multiplex tests. 
+Since 2015 we have received over $12.2 million of funding from some of the world’s leading health organizations, which has helped us accelerate the expansion of our pipeline of infectious disease tests. Our
+collaborators have included Bill & Melinda Gates Foundation, The Paul G. Allen Family Foundation, The Oswaldo Cruz Foundation or FIOCRUZ, and the Foundation for Innovative New Diagnostics, or FIND, as well as U.S. government agencies such as
+Centers for Disease Control and Prevention, or CDC, the Biomedical Advanced Research and Development Authority of the U.S. Department of Health and Human Services, or BARDA, and the U.S. Department of Agriculture, or USDA. 
+Several tests in our infectious disease pipeline are approaching commercialization, and several have received initial regulatory approvals: 
+Product 
+Collaborator 
+Phase I 
+Feasibility 
+Phase II 
+Development 
+Phase III 
+Verification &Validation 
+Phase IV 
+Clinical & 
+Regulatory 
+Phase V 
+Commercial 
+Launch 
+DPP HIV-Syphilis (US) 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+PMA/510K pending 
+DPP Dengue IgM/IgG (International) 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 1 
+DPP Dengue NS1 Antigen (International) 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA pending 
+DPP Zika IgM/IgG (International) 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP Chikungunya IgM/IgG (International) 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP ZCD IgM/IgG(International) 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP Zika IgM (US) 
+BARDA 
+✓ 
+✓ 
+✓ 
+✓ 
+FDA-EUA 2 FDA 
+DPP Ebola 
+CDC 
+✓ 
+✓ 
+✓ 
+✓ 
+FDA-EUA 
+DPP Fever Assay Asia 
+FIND 
+✓ 
+✓ 
+✓ 
+✓ 
+Field studies ongoing 
+DPP Fever Assay Africa 
+Paul Allen Foundation 
+✓ 
+✓ 
+✓ 
+1 
+Agência Nacional de Vigilância Sanitária (Brazil) 
+2 
+Emergency Use Authorization 
+7 
+Table of Contents 
+Collaborations 
+We are building additional revenue streams by leveraging our patented DPP technology and scientific expertise through collaborations. Leading global healthcare organizations have chosen to collaborate with us based on
+our deep scientific expertise with our proven DPP technology platform and capabilities, our successful record of developing DPP tests with a diverse set of collaborators including global commercial companies, governments and non-governmental
+organizations, and our extensive experience in obtaining regulatory approvals in the United States (FDA), Brazil (ANVISA), the European Union (CE mark) and Mexico (Comisión Federal para la Protección contra Riesgos Sanitarios, or COFEPRIS) as well as
+from WHO (Prequalification, or PQ). 
+Product 
+Collaborator 
+Phase I 
+Feasibility 
+Phase II 
+Development 
+Phase III 
+Verification 
+&Validation 
+Phase IV 
+Clinical/ 
+Regulatory 
+Phase V 
+Commercial 
+Launch 
+DPP Rare Disease (undisclosed biomarker) 
+Takeda 
+✓ 
+✓ 
+Infectious Disease Portfolio 
+Lumira DX 
+✓ 
+✓ 
+DPP Biomarker Development Project (undisclosed biomarker) 
+AstraZeneca 
+✓ 
+✓ 
+✓ 
+CE Mark 3 
+DPP TBI 
+Perseus 
+✓ 
+✓ 
+3 
+For use in pharmaceutical research 
+By leveraging our DPP technology platform, we are creating opportunities to expand into new markets such as cancer diagnostics, concussion and traumatic brain injury, and veterinary and we are broadening the
+application of our technology from point-of-care diagnostics to include companion diagnostics. Research and development costs related to the collaborations are fully funded by our collaborators. 
+Sales Channels 
+Our products are sold globally, both directly and through distributors, to hospitals and clinics, physician offices, clinical laboratories, public health organizations, government agencies and consumers. Historically
+we marketed and sold our products only into a handful of countries and regions. In recent years we have hired sales executives to begin building our own channels in key markets such as the United States, Europe, Latin America, Africa and Southeast
+Asia. With sales growth as an underlying objective, we are focused on increasing sales in existing geographies, expanding sales into new geographies, and broadening sales coverage in key markets. 
+8 
+Table of Contents 
+Automation of U.S. Manufacturing 
+We are automating our U.S. manufacturing processes and expanding our manufacturing capacity. During 2018, we took delivery of our first automated manufacturing line. This automated manufacturing line provided DPP test
+production for Brazil and will allow assembly of various configurations of DPP tests. The automated line has an annual capacity of between five and ten million tests, depending on the test configuration, and uses vision-guided, robotic operation to
+improve inspection and quality control. During 2019, we took delivery of our second and third manufacturing lines that together, following commissioning and regulatory approvals, will support our other product platforms. As we transition from manual
+to automated assembly, we believe the reduced variable costs will improve product gross margins. 
+DPP Technology & Development 
+Our commercially available products employ either our patented DPP technology or traditional lateral flow technology. We believe products developed using our DPP technology can provide superior diagnostic performance
+compared with products that utilize traditional lateral flow technology. 
+We are executing our strategy to leverage DPP intellectual property, as well as our scientific and operational expertise, to create new collaborations where we will serve as an exclusive development and manufacturing
+partner. Examples of such collaborations include the following: 
+• 
+In January 2015, we entered into an agreement with the Concussion Science Group (CSG) Division of Perseus Science Group LLC to develop a point-of-care diagnostic test for
+traumatic brain injury, including sports-related concussions, utilizing both our DPP and optical analyzer technologies. 
+• 
+In October 2017, we signed a biomarker development project agreement with AstraZeneca, utilizing both our DPP and optical analyzer
+technologies. 
+• 
+In April 2018, we entered into a collaboration agreement with LumiraDx to develop new point-of-care diagnostic tests for infectious diseases. Under terms of the agreement,
+we receive funding from LumiraDx, subject to satisfying certain milestones, to develop certain new point-of-care infectious disease tests. Following the regulatory approval and commercialization of tests in accordance with this agreement,
+Chembio will both sell reagents to, and receive royalty payments from, LumiraDx on sales of all products developed through this collaboration. 
+• 
+In November 2018, we acquired opTricon (Berlin, Germany), a leading developer of handheld optical analyzers rapid diagnostic tests. 
+• 
+In July 2019, we entered into a collaboration agreement with Shire Human Genetic Therapies, Inc., a wholly owned subsidiary of Takeda Pharmaceutical Company Limited, to develop a novel point-of-care
+diagnostic test to detect an undisclosed biomarker. 
+• 
+In November 2019, we acquired Orangelife Comercio e Industria Ltda. (Rio de Janeiro, Brazil), a privately held manufacturer of lateral flow test for infectious diseases, to expand our market penetration and
+support Bio-Manguinhos, a major customer. 
+9 
+Table of Contents 
+Competition 
+Many of our competitors are significantly larger and have greater financial, research, manufacturing, and marketing resources. Important competitive factors include product quality, analytical performance, ease of use,
+price, customer service and reputation. Industry competition is based on these and the following additional factors: 
+• 
+patent protection; 
+• 
+scientific expertise; 
+• 
+ability to develop and market products and processes; 
+• 
+ability to obtain required regulatory approvals; 
+• 
+ability to manufacture cost-effective products that meet applicable regulatory requirements; 
+• 
+access to adequate capital; and, 
+• 
+ability to attract and retain qualified personnel. 
+We believe our scientific capabilities and proprietary know-how relating to our patented DPP technology and lateral flow technology are very strong, particularly for the development and manufacture of tests for the
+detection of antibodies to infectious diseases, and other diseases. 
+Our ability to develop and market other products is in large measure dependent on our having additional resources and/or collaborative relationships. Some of our product development efforts have been funded on a
+project or milestone basis. We believe that our proprietary know-how relating to our patented DPP technology has been instrumental in our obtaining the collaborations we have and that we continue to pursue. We believe that our patent protection
+enhances our ability to both develop more profitable, collaborative relationships and expand licensing revenue. However, there are a number of competitive technologies used and/or seeking to be used by others in point-of-care settings. 
+Although we have no specific knowledge of any other competitors’ products that could render our products obsolete, if we fail to maintain and enhance our competitive position or fail to introduce new products and
+product features, our customers may decide to use the products developed by our competitors, which could result in a loss of revenues and cash flow. 
+Employees 
+As of December 31, 2019, we had 324 full-time equivalent employees, of whom 35 were in administration, 230 were in manufacturing, 42 were in research and development, and 17 were in sales and marketing and customer
+service. Of these employees, approximately 256 were located in the United States, 30 were located in Malaysia, 19 were located in Germany and 19 were located in Brazil. 
+We have never had a work stoppage, and none of our employees are represented by a labor organization or subject to any collective bargaining arrangements. We consider our employee relations to be good. 
+Governmental Regulation 
+Certain of our activities are subject to regulatory oversight by the FDA under provisions of the Federal Food, Drug, and Cosmetic Act and regulations thereunder, including regulations governing the development,
+marketing, labeling, promotion, manufacturing, and export of diagnostic products. Our clinical laboratory customers are subject to oversight by Centers for Medicare and Medicaid Services, or CMS, pursuant to CLIA, as well as agencies in various
+states. Failure to comply with applicable requirements can lead to sanctions, including withdrawal of products from the market, recalls, refusal to authorize government contracts, product seizures, civil money penalties, injunctions, and criminal
+prosecution. 
+FDA Approval/Clearance Requirements 
+Unless an exemption applies, each medical device that we market or wish to market in the United States must receive 510(k) clearance or Premarket Approval, or PMA. Medical devices that receive 510(k) clearance are
+“cleared” by the FDA to market, distribute, and sell in the United States. Medical devices that obtain a PMA by the FDA are “approved” to market, distribute and sell in the United States. We cannot be certain that 510(k) clearance or PMA approval
+will ever be obtained for any products that have not already obtained 510(k) clearance or PMA approval. Descriptions of the PMA and 510(k) clearance processes are provided below. 
+10 
+Table of Contents 
+The FDA decides whether a device line must undergo either the 510(k) clearance or PMA based on statutory criteria that utilize a risk-based classification system. PMA is the FDA process of scientific and regulatory
+review to evaluate the safety and effectiveness of Class III medical devices and, in many cases, Class II medical devices. Class III devices are those that support or sustain human life, are of substantial importance in preventing impairment of human
+health, or which present a potential, unreasonable risk of illness or injury. The FDA uses these criteria to decide whether a PMA or a 510(k) is appropriate, including the level of risk that the agency perceives is associated with the device and a
+determination by the agency of whether the product is a type of device that is similar to devices that are already legally marketed. Devices deemed to pose relatively less risk are placed in either Class I or II. In many cases, the FDA requires the
+manufacturer to submit a 510(k) requesting clearance (also referred to as a premarket notification), unless an exemption applies. The 510(k) must demonstrate that the manufacturer’s proposed device is “substantially equivalent” in intended use and in
+safety and effectiveness to a legally marketed predicate device. A “predicate device” is a pre-existing medical device to which equivalence can be drawn, that is either in Class I or Class II or is a Class III device that was in commercial
+distribution before May 28, 1976, for which the FDA has not yet called for submission of a PMA application. 
+Device classification depends on the device’s intended use and its indications for use. In addition, classification is risk-based, that is, the risk the device poses to the patient and/or the user is a major factor in
+determining the class to which it is assigned. Class I includes devices with the lowest risk and Class III includes those with the greatest risk. 
+Class I devices are those for which safety and effectiveness can be assured by adherence to the FDA’s general regulatory controls for medical devices, or the General Controls,
+which include compliance with the applicable portions of the FDA’s quality system regulations, facility registration and product listing, reporting of adverse medical events, and appropriate, truthful and non-misleading labeling, advertising, and
+promotional materials. Some Class I devices also require premarket clearance by the FDA through the 510(k) process described below. 
+Class II devices are subject to the FDA’s General Controls, and any other special controls as deemed necessary by the FDA to ensure the safety and effectiveness of the device.
+Premarket review and clearance by the FDA for Class II devices is accomplished through the 510(k) process. Pursuant to the Medical Device User Fee and Modernization Act of 2002, unless a specific exemption applies, 510(k) submissions are subject to
+user fees. Certain Class II devices are exempt from this premarket review process. 
+Class III includes devices with the greatest risk. Devices in this class must meet all of the requirements in Classes I and II. In addition, Class III devices cannot be marketed
+until they receive Premarket Approval. 
+The safety and effectiveness of Class III devices cannot be assured solely by the General Controls and the other requirements described above. These devices require formal clinical studies to demonstrate safety and
+effectiveness. Under Medical Device User Fee and Modernization Act of 2002, PMA applications (and supplemental premarket approval applications) are subject to significantly higher user fees than 510(k) applications, and they also require considerably
+more time and resources. 
+Rapid HIV tests intended for diagnostic use are regulated as Class III devices. Responsibility for assuring the safety and effectiveness of these tests lies within the Center for Biologics Evaluation and Research’s
+Office of Blood Research and Review, with oversight by the Blood Products Advisory Committee. Approved rapid HIV tests must meet the regulations in the 21 CFR 800 series subparts, under the investigational device exemption, or IDE and PMA pathways. 
+11 
+Table of Contents 
+Premarket Approval Pathway 
+We manufacture, market and distribute three rapid HIV tests in the United States. Our HIV 1/2 STAT-PAK Assay, SURE CHECK HIV 1/2 Assay, and DPP HIV 1/2 Assay all have received FDA PMA approval. A PMA application must
+be supported by extensive data including, but not limited to, analytical, preclinical, clinical trials, manufacturing, statutory preapproval inspections, and labeling to demonstrate to the FDA’s satisfaction the safety and effectiveness of the device
+for its intended use. Before a PMA is submitted, a manufacturer must apply for an IDE. If the device presents a “significant risk,” as defined by the FDA, to human health, the FDA requires the device sponsor to file an IDE application with the FDA
+and obtain IDE approval prior to initiation of enrollment of human subjects for clinical trials. The IDE provides the manufacturer with a legal pathway to perform clinical trials on human subjects where without the IDE, only approved medical devices
+may be used on human subjects. 
+The IDE application must be supported by appropriate data, such as analytical, animal and laboratory testing results, manufacturing information, and an Investigational Review Board, or IRB, approved protocol showing
+that it is safe to test the device in humans and that the testing protocol is scientifically sound. If the clinical trial design is deemed to have “non-significant risk,” the clinical trial may be eligible for “abbreviated” IDE requirements. In some
+instances, clinical trials for in vitro diagnostic medical devices may be exempt from the more burdensome IDE requirements if certain labeling requirements are met. 
+A clinical trial may be suspended by either the FDA or the Investigational Review Board at any time for various reasons, including a belief that the risks to the study participants outweigh the benefits of
+participation in the study. Even if a study is completed, clinical testing results may not demonstrate the safety and efficacy of the device, or they may be equivocal or otherwise insufficient to obtain approval of the product being tested. After the
+clinical trials have been completed, if at all, and the clinical trial data and results are collected and organized, a manufacturer may complete a PMA application. 
+After a PMA application is sufficiently complete, the FDA will accept the application and begin an in-depth review of the submitted information. By statute, the FDA has 180 days to review the “accepted application,”
+although, generally, review of the application can take between one and three years, but it may take significantly longer. During this review period, the FDA may request additional information or clarification of information already provided. Also,
+during the review period, an advisory panel of experts from outside the FDA may be convened to review and evaluate the application and provide recommendations to the FDA as to the approvability of the device. The preapproval inspections conducted by
+the FDA include an evaluation of the manufacturing facility to ensure compliance with the FDA’s quality systems regulations or QSR, as well as inspections of the clinical trial sites by the Bioresearch Monitoring group to evaluate compliance with
+good clinical practice and human subject protections. New PMA applications or PMA supplements are required for modifications that affect the safety or effectiveness of the device, including, for example, certain types of modifications to the device’s
+indication for use, manufacturing process, labeling and design. Significant changes to an approved PMA require a 180-day supplement, whereas less substantive changes may utilize a 30-day notice, or a 135-day supplement. Premarket approval supplements
+often require submission of the same type of information as a premarket approval application, except that the supplement is limited to information needed to support any changes from the device covered by the original premarket approval application,
+and it may not require as extensive clinical data or the convening of an advisory panel. 
+Our HIV 1/2 STAT-PAK Assay PMA application number BP050009/0 and our SURE CHECK 1/2 HIV Assay PMA application number BP050010/0 were approved by the FDA in May 2006. Our DPP HIV 1/2 Assay PMA application number
+BP120032/0 was approved by the FDA in December 2012. 
+510(k) Clearance Pathway 
+We are currently developing products that either will or are likely to require an FDA 510(k) clearance. We anticipate submitting a 510(k) for each such product to demonstrate that such proposed device is substantially equivalent to a previously
+cleared 510(k) device or a device that was in commercial distribution before May 28, 1976, for which the FDA has not yet called for the submission of a 510(k). The FDA's 510(k) clearance pathway usually takes from three to twelve months but could
+take longer. In some cases the FDA may require additional information, including clinical data, to make a determination regarding substantial equivalence. 
+If a device receives 510(k) clearance, any modification that could significantly affect its safety or effectiveness, or that would constitute a new or major change in its intended use, will require a new 510(k) clearance or, depending on the
+modification, a PMA. The FDA requires each device manufacturer to determine whether the proposed change requires submission of a new 510(k) or a PMA, but the FDA can review any such decision and, if it disagrees with the manufacturer's
+determination, can require the manufacturer to cease marketing and/or recall the modified device until 510(k) clearance or PMA of the modified device is obtained. 
+12 
+Table of Contents 
+Clinical Laboratory Improvement Amendments of 1988 
+A manufacturer of a test categorized as moderately complex may request that categorization of the test be waived through a CLIA Waiver by Application, or CW, submission to the FDA. When a test is categorized as waived,
+it may be performed by laboratories with a Certificate of Waiver, such as a physician’s office outreach setting. In a CW submission, the manufacturer provides evidence to the FDA that a test meets the CLIA statutory criteria for waiver CLIA, a
+walk-in clinic or an emergency room provides CMS authority over all laboratory testing, except research that is performed on humans in the United States. The Division of Laboratory Services, within the Survey and Certification Group under the CMS,
+has the responsibility for implementing the CLIA program. 
+The CLIA program is designed to establish quality laboratory testing by ensuring the accuracy, reliability and timeliness of patient test results. Under CLIA, a laboratory is a facility that does laboratory testing on
+specimens derived from humans and used to provide information for the diagnosis, prevention or treatment of disease, or impairment of, or assessment of health. Under the CLIA program, unless waived, laboratories must be certified by the government,
+satisfy governmental quality and personnel standards, undergo proficiency testing, be subject to inspections and pay fees. We have received a CLIA waiver for all of our lateral flow rapid HIV tests that we market in the United States. Specifically,
+the CLIA waiver was granted by the FDA for HIV 1/2 STAT-PAK in November 2006,for SURE CHECK HIV 1/2 in October 2007, and for DPP HIV 1/2 in October 2014. 
+Pervasive and Continuing FDA Regulation 
+A host of regulatory requirements apply to our approved devices, including: the quality system regulation, which requires manufacturers to follow elaborate design, testing, control, documentation and other quality
+assurance procedures; the Medical Reporting Regulations, which require manufacturers to report to the FDA specified types of adverse events involving their products; labeling regulations; and the FDA’s general prohibition against promoting products
+for unapproved or “off-label” uses. Some Class II devices are subject to special controls-such as performance standards, post-market surveillance, patient registries, and FDA guidelines-that do not apply to Class I devices. 
+The regulatory requirements that apply to our approved products classified as medical devices include: 
+• 
+product listing and establishment registration, which helps facilitate FDA inspections and other regulatory action; 
+• 
+QSR, which require manufacturers, including third-party manufacturers, to follow stringent design, testing, control, documentation and other quality assurance procedures during all
+aspects of the development and manufacturing process; 
+13 
+Table of Contents 
+• 
+labeling regulations and FDA prohibitions against the promotion of products for uncleared, unapproved or off-label use or indication; 
+• 
+clearance of product modifications that could significantly affect safety or efficacy or that would constitute a major change in intended use of one of our cleared devices; 
+• 
+approval of product modifications that affect the safety or effectiveness of one of our cleared devices; 
+• 
+medical device reporting regulations, which require that manufacturers comply with FDA requirements to report if their device may have caused or contributed to a death or serious
+injury, or has malfunctioned in a way that would likely cause or contribute to a death or serious injury if the malfunction of the device or a similar device were to recur; 
+• 
+post-approval restrictions or conditions, including post-approval study commitments; 
+• 
+post-market surveillance regulations, which apply when necessary to protect the public health or to provide additional safety and effectiveness data for the device; 
+• 
+the FDA’s recall authority, whereby it can ask, or under certain conditions order, device manufacturers to recall from the market a product that is in violation of governing laws and
+regulations; 
+• 
+regulations pertaining to voluntary recalls; and, 
+• 
+notices of corrections or removals. 
+Our Medford, New York facility is currently registered as an establishment with the FDA. We and any third-party manufacturers are subject to announced and unannounced inspections by the FDA to determine our compliance
+with QSR and other regulations. 
+21st Century Cures Act 
+The 21st Century Cures Act, enacted in December 2016, contains several sections specific to medical device innovations. We believe that implementation of the 21st Century Cures Act may have a positive impact on its
+businesses by facilitating innovation and/or reducing the regulatory burden imposed on medical device manufacturers. 
+Government Regulation of Medical Devices for Animal Subjects 
+We currently offer two veterinary devices in the United States: DPP VetTB Assay for Cervids and DPP VetTB Assay for Elephants. Diagnostic tests for animal health infectious diseases, including our veterinary devices
+for the prevention and/or treatment of animal disease, are regulated in the U.S. by the Center for Veterinary Biologics within the U.S. Department of Agriculture Animal and Plant Health Inspection Service, or APHIS, under the Virus, Serum, and Toxin
+Act of 1913. As a requirement, our veterinary devices were approved by APHIS before they could be sold in the U.S. 
+The APHIS regulatory approval process involves the submission of product performance data and manufacturing documentation. Following regulatory approval to market a product, APHIS requires that each lot of product be
+submitted for review before release to customers. In addition, APHIS requires special approval to market products where test results are used in part for government-mandated disease management programs. 
+Environmental Laws 
+We believe that we are in compliance in all material respects with all foreign, federal, state, and local environmental regulations applicable to our manufacturing facilities. The cost of ongoing compliance with such
+regulations does not have a material effect on our operations. 
+14 
+Table of Contents 
+Intellectual Property 
+Intellectual Property Strategy 
+Our intellectual property strategy is to: (1) build our own intellectual property portfolio around our DPP technology and optical analyzers; (2) pursue licenses, trade secrets and know-how within the area of rapid
+point-of-care testing; and, (3) develop and acquire proprietary positions to certain reagents. 
+DPP Intellectual Property 
+We have obtained patent coverage on our DPP technology, including numerous patents in the United States, China, Malaysia, Eurasia, Mexico, Singapore, Japan, Australia, Indonesia, Korea and the U.K. Additional patent
+applications on our DPP technology are pending in the United States, as well as in foreign countries such as Brazil, Canada, the European Union, India, Israel, and South Africa. 
+DPP technology provides us with freedom to operate, which enables us to develop tests with better performance and capabilities compared with tests built on traditional lateral flow platforms. These advantages have
+allowed us to enter into multiple technology collaborations based upon DPP technology, which we believe will provide new manufacturing and marketing opportunities. We have filed additional patent applications that we believe will strengthen the DPP
+intellectual property and have also filed for patent protection for certain other point-of-care technologies or applications thereof. 
+We have also obtained patent coverage on our optical-based analyzer technology in the United States, with patents pending in several foreign countries. 
+Trademarks 
+We have filed and obtained trademarks for our products, including DPP, SURE CHECK, STAT-VIEW, and STAT-PAK, and NEXT GENERATION DPP, as well as for the SampleTainer and DPP Micro Reader, which are used with certain DPP
+products. Our trademarks have been obtained in the United States and certain other countries around the world. 
+Trade Secrets and Know-How 
+We have developed a substantial body of trade secrets and know-how relating to the development and manufacture of lateral flow and DPP-based diagnostic tests, including the sourcing and optimization of materials for
+such tests, and methods to maximize sensitivity, speed-to-result, specificity, stability and reproducibility of our tests. We possess proprietary know-how to develop tests for multiple conditions using colored particles. Our formulations enable
+long shelf lives of our rapid HIV and other tests, providing us with an important competitive advantage. 
+Lateral Flow Technology and Reagent Licenses 
+We seek licenses and/or redesigns of products that we believe to be in our best interests. Because of the costs and other negative consequences of time-consuming patent litigation, we often attempt to obtain a license
+on reasonable terms. 
+The peptides used in our rapid HIV tests were licensed to us by one or more third parties. We also have licensed the antigens used in other tests including our Syphilis, Tuberculosis, Leptospirosis, Leishmaniasis and
+Chagas tests, and we may enter into other license agreements. In prior years, we concluded license agreements related to intellectual property rights owned by the United States associated with HIV-1 and a sub-license agreement for HIV-2 with Bio-Rad
+Laboratories N.A., the exclusive licensee of the Pasteur Institute’s HIV-2 intellectual property estate. 
+15 
+Table of Contents 
+Available Information 
+We are required to file annual, quarterly and current reports, proxy statements and other information with the U.S. Securities and Exchange Commission. The SEC maintains a website at www.sec.gov that contains reports,
+proxy and information statements, and other information regarding issuers that file electronically with the SEC. 
+Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, proxy statements and amendments to those documents filed or furnished pursuant to Section 13(a) or 15(d) of the Securities
+Exchange Act of 1934, are also available free of charge on our website at www.chembio.com as soon as reasonably practicable after such reports are electronically filed with or furnished to the SEC. 
+Investors should note that we currently announce material information to our investors and others using filings with the SEC, press releases, public conference calls, webcasts or our website (www.chembio.com),
+including news and announcements regarding our financial performance, key personnel, our brands and our business strategy. Information that we post on our corporate website could be deemed material to investors. We encourage investors to review the
+information we post on these channels. We may from time to time update the list of channels we will use to communicate information that could be deemed material and will post information about any such change on www.chembio.com. The information on
+our website is not, and shall not be deemed to be, a part hereof or incorporated into this or any of our other filings with the SEC. 
+Corporate Information 
+Our principal executive offices are located at 555 Wireless Boulevard, Hauppauge, New York 11788. Our telephone number is (631) 924-1135. Our website address is www.chembio.com. The information contained in, or
+accessible through, our corporate website does not constitute part of this report.
\ No newline at end of file
diff --git a/raw/filings/0001092662/2019/0001140361-20-005780/item13.txt b/raw/filings/0001092662/2019/0001140361-20-005780/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..8f8695c5f8353e212a7cc9c7b7fa7919f3ed05c0
--- /dev/null
+++ b/raw/filings/0001092662/2019/0001140361-20-005780/item13.txt
@@ -0,0 +1,4 @@
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE. 
+The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120
+days after the end of the fiscal year covered by this Annual Report on Form 10-K.
\ No newline at end of file
diff --git a/raw/filings/0001092662/2019/0001140361-20-005780/item9a.txt b/raw/filings/0001092662/2019/0001140361-20-005780/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..d81bf8d33294058888af78480cf182c660db4943
--- /dev/null
+++ b/raw/filings/0001092662/2019/0001140361-20-005780/item9a.txt
@@ -0,0 +1,66 @@
+ITEM 9A. 
+Controls and Procedures 
+Evaluation of Disclosure Controls and Procedures 
+Our management, with the participation of our Interim Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures, as defined by
+Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of December 31, 2019. Based on the evaluation of our disclosure controls and procedures, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and
+procedures were effective as of December 31, 2019 at the reasonable assurance level. 
+Management’s Report on Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rules 13a-15(f) and
+15d-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer and effected by the board of directors, management and other personnel
+to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and
+procedures that: 
+• 
+pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; 
+• 
+provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and
+that receipts and expenditures of the company are being made in accordance with authorizations of management and directors of the company; and 
+• 
+provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the
+financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. As a result, even those systems determined to be effective can provide only
+reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions
+or that the degree of compliance with the policies or procedures may deteriorate. 
+Under the supervision and with the participation of our Interim Chief Executive Officer and Chief Financial Officer, our management evaluated the effectiveness of our internal control over
+financial reporting as of December 31, 2019. In making their assessment of internal control over financial reporting, our management used the criteria described in the 2013 Internal Control—Integrated Framework issued by the Committee of
+Sponsoring Organizations of the Treadway Commission. Our evaluation included documenting, evaluating and testing of the design and operating effectiveness of our internal control over financial reporting. Based on this evaluation, we concluded
+that our controls over financial reporting were effective as of December 31, 2019. 
+Previously Identified Material Weaknesses in Internal Control Over Financial Reporting 
+None. 
+Changes in Internal Control over Financial Reporting 
+There were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Securities Exchange Act of 1934 during
+the period covered by this Annual Report on Form 10-K that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+51 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+Shareholders and Board of Directors 
+Chembio Diagnostics, Inc. 
+Hauppauge, New York 
+Opinion on Internal Control over Financial Reporting 
+We have audited Chembio Diagnostics, Inc.’s (the “Company’s”) internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control –
+Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). In our opinion, the Company maintained, in all material respects, effective internal control over financial
+reporting as of December 31, 2019, based on the COSO criteria. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company and subsidiaries as of December 31,
+2019 and 2018, the related consolidated statements of operations, comprehensive loss, changes in stockholders’ equity, and cash flows for each of the two years in the period ended December 31, 2019, and the related notes and our report dated March
+13, 2020 expressed an unqualified opinion thereon. 
+Basis for Opinion 
+The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the
+accompanying “Item 9A, Management’s Report on Internal Control over Financial Reporting”. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm
+registered with the PCAOB and are required to be independent with respect to the Company in accordance with U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audit of internal control over financial reporting in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about
+whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and
+testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit
+provides a reasonable basis for our opinion. 
+Definition and Limitations of Internal Control over Financial Reporting 
+A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
+purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately
+and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted
+accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection
+of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk
+that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+/s/ BDO USA, LLP 
+Melville, NY 
+March 13, 2020 
+52 
+Table of Contents 
+PART III
\ No newline at end of file
diff --git a/raw/filings/0001092662/2019/0001140361-20-005780/rp_note.txt b/raw/filings/0001092662/2019/0001140361-20-005780/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0001092662/2019/0001140361-20-005780/rpt_disclosure.txt b/raw/filings/0001092662/2019/0001140361-20-005780/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..3085e256dc110c8c29b7b50640dbeff6a694bf14
--- /dev/null
+++ b/raw/filings/0001092662/2019/0001140361-20-005780/rpt_disclosure.txt
@@ -0,0 +1,167 @@
+related-party transactions by stockholders. 
+27 
+Contents 
+Provision 
+Nevada 
+Delaware 
+Quorum for 
+Stockholder 
+Meeting 
+Unless the articles of incorporation or bylaws provide otherwise, a majority of the voting power, present in person or by proxy at a
+meeting of stockholders (regardless of whether the proxy has authority to vote on all matters), constitutes a quorum for the transaction of business. NRS 78.320. 
+The Nevada Bylaws are consistent with the NRS. 
+The certificate of incorporation or bylaws may specify the number of shares (and the amount of other securities having voting power) the
+holders of which shall be present or represented by proxy at any meeting in order to constitute a quorum for, and the votes that shall be necessary for, the transaction of any business, but a quorum may not consist of less than
+one-third of the shares entitled to vote at the meeting, except that, where a separate vote by one or more classes or series is required, a quorum may not consist of less than one-third of the shares of each such class or series. In
+the absence of such a specification: (a) a majority of the shares entitled to vote, present in person or represented by proxy, shall constitute a quorum at a stockholder meeting; (b) in all matters other than the election of
+directors, the affirmative vote of the majority of shares present in person or represented by proxy at the meeting and entitled to vote on the subject matter shall be the act of the stockholders; (c) directors shall be elected by a
+plurality of the votes of the shares present in person or represented by proxy at the meeting and entitled to vote on the election of directors; and (d) where a separate vote by one or more classes or series is required, a majority
+of the outstanding shares of each such class or series, present in person or represented by proxy, shall constitute a quorum entitled to take action with respect to that vote on that matter and, in all matters other than the
+election of directors, the affirmative vote of the majority of shares of each such class or series present in person or represented by proxy at the meeting shall be the act of each such class or series. A bylaw amendment adopted by
+stockholders specifying the votes necessary for election of directors may not be further amended or repealed by the board of directors. DGCL §216. 
+Consistent with the DGCL, the Delaware Bylaws state that the holders of a majority in voting power of the capital stock issued and outstanding and entitled to
+vote, present in person or represented by proxy, shall constitute a quorum for the transaction of business. The Delaware Bylaws and Nevada Bylaws are substantially similar with respect to quorum requirements. 
+28 
+Contents 
+Provision 
+Nevada 
+Delaware 
+Cumulative 
+Voting for 
+Directors 
+The NRS permits cumulative voting in the election of directors only if the articles of incorporation provide for cumulative voting and
+certain procedures for the exercise of cumulative voting are followed. NRS 78.360. 
+The Nevada Charter does not provide for cumulative voting. 
+Under the DGCL, a corporation may provide for cumulative voting in its certificate of incorporation. DGCL
+Section 214. 
+The Delaware Charter does not provide for cumulative voting. 
+Duration of 
+Proxies 
+A proxy is effective only for a period of six months from the date of its creation, unless it is coupled with an interest or unless
+otherwise provided by the stockholder in the proxy, which duration may not exceed seven years. A proxy shall be deemed irrevocable if the written authorization states that the proxy is irrevocable, but is irrevocable only for as
+long as it is coupled with an interest sufficient in law to support an irrevocable power. NRS 78.355. 
+The Nevada Bylaws do not change this statutory rule. 
+A proxy executed by a stockholder will remain valid for a period of three years, unless the proxy provides for a longer period. A duly
+executed proxy shall be irrevocable if it states that it is irrevocable and if, and only as long as, it is coupled with an interest sufficient in law to support an irrevocable power. A proxy may be made irrevocable regardless of
+whether the interest with which it is coupled is an interest in the stock itself or an interest in the corporation generally. DGCL §212 
+The Delaware Bylaws do not change this statutory rule. The DGCL statutory default provides for proxies to remain valid for a longer
+duration than the NRS statutory default. 
+Advance Notice 
+Provisions 
+The Nevada Bylaws do not contain advance notice requirements for business to be brought by a stockholder before an annual or special
+meeting of stockholders. 
+The Delaware Bylaws contain advance notice requirements for business to be brought before an annual or special meeting of stockholders,
+including nominations of persons for election as directors. As a result, stockholders must satisfy specific timing and information requirements in order to have a proposal considered at or in order to nominate a person for election
+as a director at an annual or special meeting. Any proposal or nomination that fails to comply with these timing and information requirements may be disqualified. 
+The Delaware Bylaws and the Nevada Bylaws are materially different in this respect. 
+29 
+Contents 
+Provision 
+Nevada 
+Delaware 
+Stockholder 
+Votes for 
+Mergers and 
+Similar 
+Transactions 
+Under the NRS, the approval of a majority of outstanding shares entitled to vote, as well as the board of directors, is required for a
+merger or a sale of substantially all of the assets of the corporation. Generally, the NRS does not require a stockholder vote of the surviving corporation in a merger if: (a) the plan of merger does not amend the existing articles
+of incorporation; (b) each share of stock of the surviving corporation outstanding immediately before the effective date of the merger is an identical outstanding share after the merger; (c) the number of voting shares outstanding
+immediately after the merger, plus the number of voting shares issued as a result of the merger, either by the conversion of securities issued pursuant to the merger or the exercise of rights and warrants issued pursuant to the
+merger, will not exceed by more than 20% the total number of voting shares of the surviving domestic corporation outstanding immediately before the merger; and (d) the number of participating shares outstanding immediately after the
+merger, plus the number of participating shares issuable as a result of the merger, either by the conversion of securities issued pursuant to the merger or the exercise of rights and warrants issued pursuant to the merger, will not
+exceed by more than 20% the total number of participating shares outstanding immediately before the merger. NRS 92A.130. 
+The Nevada Charter and Nevada Bylaws do not change the statutory rule. 
+Under the DGCL, the approval of a majority of outstanding shares entitled to vote, as well as the board of directors, is required for a
+merger or a sale of substantially all of the assets of the corporation. Generally, the DGCL does not require a stockholder vote of the surviving corporation in a merger (unless the corporation provides otherwise in its certificate
+of incorporation) if: (a) the plan of merger does not amend the existing certificate of incorporation; (b) each share of stock of the surviving corporation outstanding immediately before the effective date of the merger is an
+identical outstanding share after the effective date of the merger; and (c) either no shares of common stock of the surviving corporation and no shares, securities or obligations convertible into such stock are to be issued or
+delivered under the plan of merger, or the authorized unissued shares or shares of common stock of the surviving corporation to be issued or delivered under the plan of merger plus those initially issuable upon conversion of any
+other shares, securities or obligations to be issued or delivered under such plan do not exceed 20% of the shares of common stock of such constituent corporation outstanding immediately prior to the effective date of the merger. DGCL §251. 
+The Delaware Charter and Delaware Bylaws do not change the statutory rule. The NRS and the DGCL are substantially similar in regard to
+stockholder approval of mergers and other corporate transactions. 
+Consideration 
+of Non- 
+Stockholder 
+Interests 
+The NRS authorizes directors, when taking action on behalf of the corporation, to consider the interests of constituencies other than
+stockholders, including employees, suppliers, creditors, customers and the community and society as a whole. NRS 78.138(4). 
+Delaware case law limits the ability of the board of directors to consider the interests of non-stockholders when taking action on behalf
+of the corporation in some circumstances. 
+This aspect of Delaware law could, in some circumstances, limit the discretion of the board in responding to unsolicited takeover proposals or similar events. 
+30 
+Contents 
+Provision 
+Nevada 
+Delaware 
+Special 
+Meetings of 
+Stockholders 
+The NRS states that, unless otherwise provided in the articles of incorporation or bylaws, the entire board of directors, any two
+directors or the president may call annual and special meetings of the stockholders and directors. NRS 78.310. 
+The Nevada Bylaws are consistent with the NRS, but also provide that a special meeting of stockholders may be called by the Chief
+Executive Officer or at the request in writing of stockholders owning a majority in amount of the entire capital stock issued and outstanding and entitled to vote. 
+The DGCL provides that special meetings of the stockholders may be called by the board of directors or by such persons as may be
+authorized by the certificate of incorporation or bylaws. DGCL §211. 
+The Delaware Charter and Delaware Bylaws state that special meetings of the stockholders may be called at any time by the board, the Chair of the Board, the Chief Executive Officer or the President (in
+the absence of the Chief Executive Officer), but may not be called by any other person. The Delaware Charter and Delaware Bylaws thus differ from the Nevada Bylaws in that stockholders cannot request that a special meeting of the
+stockholders be called. 
+Stockholder 
+Action by 
+Written 
+Consent 
+The NRS states that, unless the articles of incorporation or bylaws provide otherwise, any action required or permitted to be taken at a
+stockholder meeting may be taken without a meeting if the holders of outstanding stock having at least the minimum number of votes that would be necessary to authorize or take such action at a meeting consent to the action in
+writing. NRS 78.320. 
+The Nevada Bylaws state that any action which may be taken by the vote of the stockholders at a meeting may be taken without a meeting if authorized by the written
+consent of stockholders holding at least a majority of the outstanding voting power entitled to vote thereon. 
+The DGCL states that, unless the certificate of incorporation provides otherwise, any action required or permitted to be taken at a
+meeting of the stockholders may be taken without a meeting if the holders of outstanding stock having at least the minimum number of votes that would be necessary to authorize or take such action at a meeting consents to the action
+in writing. In addition, The DGCL requires the corporation to give prompt notice of the taking of corporate action without a meeting by less than unanimous written consent to those stockholders who did not consent in writing. DGCL §228. 
+The Delaware Charter and Delaware Bylaws do not allow stockholders to act by written consent, and therefore differ from the Nevada Bylaws. 
+31 
+Contents 
+Provision 
+Nevada 
+Delaware 
+Failure to Hold 
+Annual 
+Stockholder 
+Meeting 
+Under the NRS, if a corporation fails to hold an annual stockholder meeting to elect directors within 18 months after the last election of
+directors, a Nevada district court may order an election upon the petition of one or more stockholders holding at least 15% of the corporation’s voting power. NRS 78.345. 
+The Nevada Bylaws do not change this statutory rule. 
+Under the DGCL, if an annual meeting for election of directors is not held on the date designated or an action by written consent to elect
+directors in lieu of an annual meeting has not been taken within 30 days after the date designated for the annual meeting, or if no date has been designated, for a period of 13 months after the last annual meeting or the last action
+by written consent to elect directors in lieu of an annual meeting, the Delaware Court of Chancery may summarily order a meeting to be held upon the application of any stockholder or director. DGCL §211. 
+The Delaware Bylaws do not change this statutory rule. The DGCL provides for a shorter interval between meetings than the NRS (13 months
+versus 18 months) before a stockholder can apply to a court to order a meeting for the election of directors. The NRS requires that application be made by a stockholder holding at least 15% of the voting power, while the DGCL
+permits any stockholder or director to make the application. 
+Adjournment of 
+Stockholder 
+Meetings 
+Unless the articles of incorporation or bylaws provide otherwise, if a stockholder meeting is adjourned to another date, time or place,
+notice need not be delivered of the date, time or place of the adjourned meeting if they are announced at the meeting at which the adjournment is taken. If a new record date is fixed for the adjourned meeting, notice of the
+adjourned meeting must be delivered to each stockholder of record as of the new record date. NRS 78.370. 
+The Nevada Bylaws do not change this statutory rule. 
+If a meeting of stockholders is adjourned due to lack of a quorum and the adjournment is for more than 30 days, or if after the
+adjournment a new record date is fixed for the adjourned meeting, notice of the adjourned meeting must be given to each stockholder of record entitled to vote at the meeting. At the adjourned meeting, the corporation may transact
+any business that might have been transacted at the original meeting. DGCL §222. 
+The Delaware Bylaws do not change this statutory rule. 
+32 
+Contents 
+Provision 
+Nevada 
+Delaware 
+Director 
+Standard of 
+Conduct 
+Under the NRS, directors and officers must exercise their powers in good faith and with a view to the interests of the corporation. 
+Under the DGCL, the standards of conduct for directors have developed through written opinions of the Delaware courts. Generally,
+directors are subject to fiduciary duties of care, loyalty and good faith. 
+Limitation on 
+Director 
+Liability 
+Under the NRS, unless the articles of incorporation provide for greater individual liability, a director or officer is not individually
+liable to the corporation or its stockholders or creditors for any damages as a result of any act or failure to act in his or her capacity as a director or officer unless it is proven that (a) the director’s or officer’s act or
+failure to act constituted a breach of his or her fiduciary duties as a director or officer and (b) the breach of those duties involved intentional misconduct, fraud, or a knowing violation of law.
\ No newline at end of file
diff --git a/raw/filings/0001092662/2020/0001140361-21-008210/filing.txt b/raw/filings/0001092662/2020/0001140361-21-008210/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..fe1ec25f38d7c656127e5ebd09de4aec22a0270f
--- /dev/null
+++ b/raw/filings/0001092662/2020/0001140361-21-008210/filing.txt
@@ -0,0 +1,3359 @@
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cemi:KeyEmployee cemi:Lawsuit cemi:Applicants 
+UNITED STATES 
+Securities and Exchange Commission 
+Washington, D.C. 20549 
+FORM 10-K 
+☒ 
+ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the fiscal year ended December 31, 2020 
+or 
+☐ 
+TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the transition period from _______ to ______ . 
+Commission File No. 0-30379 
+CHEMBIO DIAGNOSTICS, INC. 
+(Exact name of registrant as specified in its charter) 
+Nevada 
+88-0425691 
+(State or other jurisdiction of incorporation or organization) 
+(I.R.S. Employer Identification No.) 
+555 Wireless, Boulevard, Hauppauge , NY 
+11788 
+(Address of principal executive offices) 
+(Zip Code) 
+Registrant’s telephone number, including area code ( 631 ) 924-1135 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of each class 
+Trading Symbol 
+Name of each exchange on which registered 
+Common Stock, $0.01 par value 
+CEMI 
+The NASDAQ Stock Market LLC 
+Securities registered pursuant to Section 12(g) of the Act: 
+None 
+(Title of Class) 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒ 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒ 
+Indicate by checkmark whether the registrant has filed a report on and attestation to it’s management’s assessment of the effectiveness of internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. Yes ☒ No ☐ 
+Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ 
+Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐ 
+Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒ 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. 
+Large accelerated filer ☐ 
+Accelerated filer ☒ 
+Non-accelerated filer ☐ 
+Smaller reporting company ☒ 
+Emerging growth company ☐ 
+If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act ☐ 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ 
+As of the last business day of the registrant’s most recently completed fiscal quarter, the aggregate market value of voting and non-voting common equity held by non-affiliates was $ 0 . 
+As of March 11, 2021, the registrant had 20,182,357 shares of common stock outstanding. 
+Documents Incorporated By Reference 
+Portions of the registrant’s proxy statement for its 2020 annual meeting of stockholders are incorporated by reference in Part III of this report. 
+Table of Contents 
+TABLE OF CONTENTS 
+Page 
+PART I 
+ITEM 1. 
+BUSINESS 
+4 
+ITEM 1A. 
+RISK FACTORS 
+14 
+ITEM 2. 
+PROPERTIES 
+38 
+ITEM 3. 
+LEGAL PROCEEDINGS 
+38 
+PART II 
+ITEM 5. 
+MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+39 
+ITEM 7. 
+MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+40 
+ITEM 8. 
+FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+47 
+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+47 
+PART III 
+ITEM 10. 
+DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
+48 
+ITEM 11. 
+EXECUTIVE COMPENSATION 
+48 
+ITEM 12. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+48 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+48 
+ITEM 14. 
+PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+48 
+PART IV 
+ITEM 15. 
+EXHIBITS, FINANCIAL STATEMENT SCHEDULES 
+49 
+SIGNATURES 
+50 
+Unless the context requires otherwise, the words ‘‘we,’’ ‘‘us,’’ ‘‘our,’’ ‘‘our company,’’ ‘‘Chembio’’ and similar terms refer to Chembio Diagnostics, Inc. and its consolidated subsidiaries. 
+DPP, STAT-PAK, STAT-VIEW and SURE CHECK are our registered trademarks, and CHEMBIO and MICRO READER are our trademarks. For convenience, these trademarks appear inthis report without ® and ™ symbols, and that practice does not mean that we will not assert, to the fullest extent under applicable law, our rights to the trademarks. 
+Table of Contents 
+FORWARD-LOOKING STATEMENTS AND STATISTICAL ESTIMATES 
+This report contains statements reflecting our views about our future performance that constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are generally identified through the inclusion of words such as “anticipate,” “believe,” “contemplate,” “could,”,“estimate,” “expect,” “forecast,” “intend,” “may,” “objective,” “outlook,” “plan,” “potential,” “project,” “seek,” “should,” “strategy,” “target,” “will,” “would” or variations of such words or similar expressions. All statements addressing our future operating performance, and statements addressing events and developments that we expect or anticipate will occur in the future, are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are based upon currently available information, operating plans, and projections about future events and trends. 
+This report contains estimates, projections and other data concerning our industry, our business and the markets for our products. Where expressly stated, we obtained this industry, business, market and other data from reports, research surveys, studies and similar data prepared by the World Health Organization, or WHO. We also include data that we have compiled, obtained, identified or otherwise derived from reports, research surveys, studies and similar data prepared by market research firms and other third parties, industry, medical and general publications, government data and similar sources. Other than WHO, we do not expressly refer to the sources from which this data is derived. 
+Forward-looking statements and statistical estimates inherently involve risks and uncertainties that could cause actual results to differ materially from those predicted or expressed in this report. These risks and uncertainties include those described in Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2020, as filed with the Securities and Exchange Commission on March X, 2020, in Part II, Item 1A. “Risk Factors” in our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2020, as filed with the Securities and Exchange Commission on May 4, 2020, in Part II, Item 1A. “Risk Factors” in our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2020, as filed with the Securities and Exchange Commission on August 7, 2020, and in Part II, Item 1A, . “Risk Factors” in our Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2020, as filed with the Securities and Exchange Commission on November 5, 2020, and in Part II, Item 1A, “Risk Factors,” of this report. You should interpret many of the risks identified in these reports as being heightened as a result of the ongoing and numerous adverse impacts of the COVID-19 pandemic. Investors are cautioned not to place undue reliance on any forward-looking statements or statistical estimates, which speak only as of the date they are made. We undertake no obligation to update any forward-looking statement or statistical estimate, whether as a result of new information, future events or otherwise. 
+3 
+Table of Contents 
+PART I 
+ITEM 1. 
+BUSINESS 
+Overview 
+We develop, manufacture and commercialize point-of-care tests for the detection and diagnosis of infectious diseases, including COVID‑19, sexually transmitted disease, and fever and tropical disease. 
+Our product portfolio is based upon our proprietary DPP technology, a diagnostic platform that provides high-quality, cost-effective results in 15 to 20 minutes using fingertip blood, nasal swabs and other sample types. The DPP technology platform addresses the rapid diagnostic test market, which includes infectious diseases, cardiac markers, cholesterol and lipids, pregnancy and fertility, and drugs of abuse. Compared with traditional lateral flow technology, the DPP technology platform can provide: 
+● 
+Enhanced sensitivity and specificity: This is achieved via our patented approach to separating the sample path from the buffer path, together with other patented and proprietary strategies, than traditional lateral flow tests. It also delivers lower levels of detection. 
+● 
+Advanced multiplexing capabilities : Through advanced multiplexing, the DPP platform can detect and differentiate up to eight distinct test results from a single patient sample, which can deliver greater clinical value than other rapid tests. 
+● 
+Quantitative results: For some diagnostic applications, our easy-to-use, highly portable, battery-operated DPP Micro Reader optical analyzers can report accurate results in approximately 15 seconds, making it well-suited for decentralized testing where real-time results enable patients to be clinically assessed while they are still onsite. Objective results produced by the DPP Micro Reader can reduce the possibility of the types of human error that can be experienced in the visual interpretations required by many rapid tests. 
+We target the market for rapid diagnostic test solutions for infectious diseases, which is driven by the high prevalence of infectious diseases globally, an increase in the geriatric population, growing demand for rapid test results, and advancements in multiplexing. We have a broad portfolio of infectious disease products, which prior to 2020 were focused principally on sexually transmitted disease and fever and tropical disease. For example, in June 2020 we received FDA clearance of our 510(k) submission for the DPP Zika IgM System, which consists of an antibody test for Zika IgM and a DPP Micro Reader and which had previously received an FDA Emergency Use Authorization or EUA. In October 2020 the DPP HIV-Syphilis System, an antibody test system for the human immunodeficiency virus or HIV and Treponema pallidum bacteria (the causative agent of syphilis), received FDA approval for a Premarket Approval, or PMA, application. 
+In February 2020 we began the process of shifting substantially all of our resources to leverage the DPP technology platform to address the acute and escalating need for diagnostic testing for COVID-19. 
+● 
+COVID-19 antibody test system: We initially refocused our business strategy on the development and commercialization of the DPP COVID-19 IgM/IgG System, which consisted of a new serological test for COVID-19 and a DPP Micro Reader that could provide separate numerical readings for both IgM and IgG levels of antibodies to the virus. We acquired three regulatory approvals of the DPP COVID-19 IgM/IgG system in our targeted global testing market: an EUA, granted by the FDA in April 2020; an approval for emergency use issued by Brazil’s Agência Nacional de Vigilância Sanitária, or ANVISA, in April 2020, and a CE Marking for the European Union obtained in early May 2020. In June 2020 the FDA revoked the EUA for the DPP COVID-19 IgM/IgG system. In September 2020 we submitted to the FDA an EUA application for the DPP SARS-CoV-2 IgM/IgG System, a new rapid antibody test system that detected COVID-19 antibodies using a different methodology that was consistent with updated FDA guidance, but in December 2020 the FDA notified us that it was declining to review the new system based on the FDA’s then-effective prioritization guidance, under which review of the system was not a priority because, for example, the FDA determined that authorization of the tests would have relatively limited impact on testing accessibility or testing capacity. 
+● 
+COVID-19 antigen test system: In July 2020 we received a $628,071 grant, the First BARDA Grant, from the Department of Health and Human Services; Office of the Assistant Secretary for Preparedness and Response; Biomedical Advanced Research and Development Authority, Division of Research Innovation and Ventures, or BARDA, to assist us in developing, submitting and obtaining an EUA application for a COVID-19 point-of-care antigen system using DPP technology. In October 2020, with BARDA’s support in accordance with its grant, we submitted to the FDA an EUA application for the DPP SARS‑CoV‑2 Antigen System, a test system that consists of a DPP SARS-CoV-2 Antigen test cartridge, a DPP Micro Reader optical analyzer and a minimally invasive nasal swab. In December 2020 we received a $12.7 million grant from BARDA, in part to support preparation, submission, and approval of FDA 510(k) clearance for the DPP SARS-CoV-2 Antigen System. In January 2021 the FDA notified us that it was declining to review the DPP SARS-CoV-2 Antigen System based on its updated prioritization guidance, under which review of the system was not a priority. The FDA has supplementally advised us of the type and nature of information it would need to receive in a subsequent EUA application in order for the DPP SARS-CoV-2 Antigen System to be prioritized for review, and we are engaged in testing and development in order to submit a new EUA application for a COVID-19 antigen test system. 
+4 
+Table of Contents 
+● 
+COVID-19 and Influenza respiratory antigen panel test system: BARDA’s $12.7 million grant in December 2020 also supported our development, submission and receipt of an EUA for a rapid, multiplex respiratory antigen panel point-of-care test system using DPP technology. We are currently seeking to develop and conduct clinical trials of the DPP Respiratory Antigen Panel, a test system being designed to provide simultaneous, discrete and differential detection of Influenza A, Influenza B and SARS-CoV-2 antigens from a single patient respiratory specimen, such as a nasal swab, in approximately 20 minutes. The system is intended to enable appropriate clinical management of patients with suspected respiratory infections and to assist in the containment of COVID-19 cases during the flu season. This test system is expected to provide results in approximately 20 minutes and to be run on the DPP Micro Reader. 
+For additional information about our existing and proposed product offerings, please see “—Products” below. 
+Our products are sold globally, directly and through distributors, to medical laboratories and hospitals, governmental and public health entities, non-governmental organizations, medical professionals, and retail establishments. We continue to seek to expand our commercial distribution channels. 
+The extensive economic disruption caused by the COVID-19 pandemic, exacerbated by the market and regulatory complications we faced in seeking to develop and commercialize a portfolio of COVID-19 test systems, was reflected in our operating results for 2020, as total revenues were $32.5 million, a decrease of 5.8% from 2019, and net product sales were $24.8 million, a decrease of 14.1% from 2019. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Consolidated Results of Operations.” 
+In 2020 we continued to invest in automating our test manufacturing processes, all of which are now based in the United States. Among other actions, we expanded our manufacturing capabilities by validating and implementing automated lines. Our transition from manual to automated assembly is intended to add capacity, reduce variable costs and improve product margins. In order to address challenging economic conditions and implement our business strategy, we continued to execute a program to reduce operating expenses and better align our costs with revenues, including by eliminating positions that were no longer aligned with our strategy. Our cash and cash equivalents totaled $23.1 million at December 31, 2020, compared to $18.3 million at December 31, 2019. 
+Industry 
+The DPP technology platform targets diagnostic disease states; (1) where rapid diagnosis impacts patient treatment and outcomes; (2) that are underserved by current diagnostic products due to performance or availability; and (3) that present opportunities regionally, demographically or clinically. We are focused on test solutions associated with infectious diseases: respiratory viruses, sexually transmitted diseases, gastroenterology and insect-vector diseases. 
+Our product portfolio is marketed globally to NGO’s, Ministries of Health, acute care hospitals, reference labs, outpatient clinics including urgent cares and physician offices. Our branded products have secured meaningful market share globally and include, SURE CHECK, STAT-PAK and DPP. We will focus on internally developed products and pursue external opportunities to license novel technologies and products with the intent of leveraging our growing commercial infrastructure. 
+We currently are targeting rapid diagnostic test solutions for infectious diseases: respiratory diseases, sexually transmitted diseases, gastroenterology and insect-vector diseases. The market for rapid diagnostic infectious disease tests is being driven by the high prevalence of infectious diseases globally, an increase in the geriatric population, growing demand for rapid test results, and advancements in multiplexing. 
+Products 
+We develop, manufacture and commercialize point-of-care tests for the detection and diagnosis of infectious diseases, including COVID‑19, sexually transmitted disease, and insect-vector diseases. We target the market for rapid diagnostic test solutions for infectious diseases, which is driven by the high prevalence of infectious diseases globally, an increase in the geriatric population, growing demand for rapid test results, and advancements in multiplexing. 
+Much of our product portfolio is based upon our proprietary DPP technology, a diagnostic platform that provides high-quality, cost-effective results in 15 to 20 minutes using fingertip blood, nasal swabs and other sample types. The DPP technology platform addresses the rapid diagnostic test market, which includes infectious diseases, cardiac markers, cholesterol and lipids, pregnancy and fertility, and drugs of abuse. Compared with traditional lateral flow technology, the DPP technology platform can provide: 
+● 
+Enhanced sensitivity and specificity: This is achieved via our patented approach to separating the sample path from the buffer path, together with other patented and proprietary strategies, than traditional lateral flow tests. It also delivers lower levels of detection. 
+5 
+Table of Contents 
+● 
+Advanced multiplexing capabilities : Through advanced multiplexing, the DPP platform can detect and differentiate up to eight distinct test results from a single patient sample, which can deliver greater clinical value than other rapid tests. 
+● 
+Quantitative results: For some diagnostic applications, our easy-to-use, highly portable, battery-operated DPP Micro Reader optical analyzers can report accurate results in approximately 15 seconds, making it well-suited for decentralized testing where real-time results enable patients to be clinically assessed while they are still onsite. Objective results produced by the DPP Micro Reader can reduce the possibility of the types of human error that can be experienced in the visual interpretations required by many rapid tests. 
+COVID-19 Diagnostic Test Systems 
+Prior to 2020, our broad portfolio of infectious disease products was focused principally on sexually transmitted disease and fever and tropical disease. In 2020 we shifted substantially all of our resources to leverage the DPP technology platform to address the acute and escalating need for diagnostic testing for COVID-19. 
+COVID-19 Antibody Test System 
+Beginning in February 2020 we refocused our business strategy on the development and commercialization of a COVID-19 antibody test system based on DPP technology. We initially developed the DPP COVID-19 IgM/IgG System, which consisted of a new serological test for COVID-19 and a DPP Micro Reader that could provide separate numerical readings for both IgM and IgG levels of antibodies to the CORONA-19 virus. We acquired three regulatory approvals of the DPP COVID-19 IgM/IgG System in our targeted global testing market: an EUA, granted by the FDA in April 2020; an approval for emergency use issued by Brazil’s Agência Nacional de Vigilância Sanitária, or ANVISA, in April 2020, and a CE Marking for the European Union obtained in early May 2020. In June 2020, however, the FDA revoked the EUA for the DPP COVID-19 IgM/IgG System. 
+In the second quarter of 2020 we began shipping the DPP COVID-19 IgM/IgG System to fulfill a $4 million purchase order from Bio-Manguinhos, a long-standing customer that is a subsidiary of the foundation responsible for the development and production of vaccines, diagnostics and biopharmaceuticals for Brazil’s national public health system. 
+In September 2020 we submitted to the FDA an EUA application for the DPP SARS-CoV-2 IgM/IgG System, a new rapid antibody test system that detected COVID-19 antibodies using a different methodology that was consistent with updated FDA guidance. In December 2020 the FDA notified us that it was declining to review the DPP SARS-CoV- 2 IgM/IgG System based on the FDA’s then-effective prioritization guidance. Under this guidance, review of the system was not a priority for the FDA because, for example, the FDA determined that authorization of the tests would have relatively limited impact on testing accessibility or testing capacity. The FDA has supplementally advised us of the type and nature of information it would need to receive in a subsequent EUA application in order for the DPP SARS-CoV-2 IgM/IgG System to be prioritized for review. We are continuing to evaluate whether to commit further resources to the testing and development that would be required in order to seek to submit a new EUA application for a COVID-19 antibody test system. 
+In January 2021 we announced the CE mark for the DPP SARS-CoV-2 IgM/IgG test system, providing regulatory approval to register and market the test systems in the European Union and other geographies that accept the CE mark. 
+COVID-19 Antigen Test System 
+In mid-2020 we began to focus on the development of a COVID-19 antigen test system based on DPP technology. In July 2020 we received a $628,071 grant from BARDA to assist us in developing, submitting and obtaining an EUA application for, a COVID-19 point-of-care antigen system. In October 2020, with BARDA’s support in accordance with its grant, we submitted to the FDA an EUA application for the DPP SARS‑CoV‑2 Antigen System, a test system that consists of a DPP SARS-CoV-2 Antigen test cartridge, a DPP Micro Reader optical analyzer and a minimally invasive nasal swab. 
+In November 2020 ANVISA approved the DPP SARS-CoV-2 Antigen test system for use in Brazil. 
+In December 2020 we received a $12.7 million grant from BARDA, in part to support preparation of a submission in pursuit of FDA 510(k) clearance for the DPP SARS-CoV-2 Antigen System. 
+In January 2021 the FDA notified us that it was declining to review the DPP SARS-CoV-2 Antigen System based on its updated prioritization guidance, under which review of the system was not a priority. The FDA has supplementally advised us of the type and nature of information it would need to receive in a subsequent EUA application in order for the DPP SARS-CoV-2 Antigen System to be prioritized for review, and we are engaged in testing and development in order to submit a new EUA application for a COVID-19 antigen test system. 
+In January 2021 we announced the CE mark for the DPP SARS-CoV-2 Antigen test system, providing regulatory approval to register and market the test systems in the European Union and other geographies that accept the CE mark. 
+6 
+Table of Contents 
+COVID-19 and Influenza Respiratory Antigen Panel Test System 
+In the fourth quarter of 2020 we began developing a rapid, multiplex respiratory antigen panel point-of-care test system using DPP technology. BARDA designated a portion of its $12.7 million grant in December 2020 for use to support our development, submission and receipt of an EUA for this system. 
+We are currently seeking to develop and conduct clinical trials of the DPP Respiratory Antigen Panel, a test system being designed to provide simultaneous, discrete and differential detection of Influenza A, Influenza B and SARS-CoV-2 antigens from a single patient respiratory specimen, such as a nasal swab, in approximately 20 minutes. The system is intended to enable appropriate clinical management of patients with suspected respiratory infections and to assist in the containment of COVID-19 cases during the flu season. This test system is expected to provide results in approximately 20 minutes and to be run on the DPP Micro Reader. 
+To enhance our offered product line quickly, we signed an in-licensing agreement to distribute a visual-read, point- of-care, EUA-approved respiratory panel for the detection of SARS-CoV-2 antigens, Influenza A and Influenza B. This offering is scheduled to launch in March 2021. 
+Legacy Products 
+We have obtained FDA approvals and, directly or through our partners, international regulatory approvals for infectious disease tests as follows: 
+Product 
+U.S. 
+International 
+DPP COVID-19 IgM/IgG System 
+✓ 
+DPP HIV 1/2 Assay 
+✓ 
+✓ 
+DPP HIV-Syphilis System 
+✓ 
+✓ 
+DPP Syphilis Screen & Confirm Assay 
+✓ 
+DPP ZCD IgM/IgG System 
+✓ 
+DPP Dengue NS1 Antigen System 
+✓ 
+DPP Dengue IgM/IgG System 
+✓ 
+DPP Zika IgM System 
+✓ 
+✓ 
+DPP Zika IgM/IgG System 
+✓ 
+DPP Chikungunya System 
+✓ 
+DPP Ebola Antigen System 
+✓ EUA 
+DPP Leishmaniasis Assay 
+✓ 
+HIV 1/2 STAT-PAK Assay 
+✓ 
+✓ 
+Chagas STAT-PAK Assay 
+✓ 
+SURE CHECK HIV 1/2 Assay 
+✓ 
+✓ 
+SURE CHECK HIV Self-Test 
+✓ 
+Organic growth in our core infectious disease business is being driven by: 
+● 
+growth in the overall market for rapid diagnostic infectious disease tests; 
+● 
+our increased market penetration in existing markets and channels, including in the United States, Latin America, and Europe; 
+● 
+our registration of existing and new products in unchartered countries and regions, such as selected countries in Latin America and Southeast Asia; 
+● 
+our entry into new market segments, such as respiratory tests and international HIV Self-Testing; and 
+● 
+advances in our product pipeline in infectious disease with key products including a tests for COVID-19, a multiplex test for HIV and syphilis in the U.S. market and tests for dengue, zika and chikungunya. 
+We market and sell both stand-alone and multiplex tests for sexually transmitted infectious diseases, such as HIV and syphilis. HIV and syphilis continue to be major global public health issues. According to WHO estimates: 
+● 
+HIV has claimed more than 35 million lives, including 770,000 in 2018. Approximately 37.9 million people were living with HIV at the end of 2018, and 1.7 million were newly infected during 2018. 
+● 
+There were 18.0 million prevalent cases of syphilis as of 2012, and 5.6 million new infections were estimated to occur annually. 
+● 
+Elimination of mother-to-child transmission, or MTCT, of both HIV and syphilis is a global health priority. In 2013, 1.9 million pregnant women were infected with syphilis worldwide. Congenital syphilis contributes significantly to infant mortality, accounting for 305,000 annual perinatal deaths worldwide in 2013. Globally, more than 1.4 million pregnant women were infected with HIV as of 2015, and MTCT of HIV is estimated to have resulted in over 150,000 infant cases in 2015. 
+7 
+Table of Contents 
+We are seeking to address the global concerns related to HIV and syphilis co-infection through the development of a novel, multiplex test for both HIV and syphilis. We have developed a DPP HIV-Syphilis multiplex test and received regulatory approvals in the United States and a number of international markets, including Brazil, Europe, Malaysia and Mexico. We are pursuing a CLIA waiver for the DPP HIV-Syphilis tests in the United States. 
+We also market and sell tests for selected fever and tropical diseases such as Chagas, ebola, leishmaniasis and Zika. The market for rapid diagnostic insect-vector diseases includes established markets for disease such as dengue and malaria, which WHO estimates together account for more than 600 million annual infections worldwide. There are also a number of emerging markets for rapid diagnostic tests for infectious diseases such as burkholderia, chikungunya, lassa, leptospirosis, Marburg, rickettsia and Zika. 
+Since 2015 we have received over $14.2 million of funding from some of the world’s leading health organizations, which has helped us accelerate the expansion of our pipeline of infectious disease tests. Our collaborators have included Bill & Melinda Gates Foundation, The Paul G. Allen Family Foundation, The Oswaldo Cruz Foundation or FIOCRUZ, and the Foundation for Innovative New Diagnostics, or FIND, as well as U.S. government agencies such as Centers for Disease Control and Prevention, or CDC, the Biomedical Advanced Research and Development Authority of the U.S. Department of Health and Human Services, or BARDA, and the U.S. Department of Agriculture, or USDA. 
+Several tests in our infectious disease pipeline are approaching commercialization, and several have received initial regulatory approvals: 
+Product 
+Collaborator 
+Phase I 
+Feasibility 
+Phase II 
+Development 
+Phase III 
+Verification & 
+Validation 
+Phase IV 
+Clinical & 
+Regulatory 
+Phase V 
+Commercial 
+Launch 
+DPP HIV-Syphilis System (US) 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+PMA approved 
+DPP Dengue IgM/IgG System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP Dengue NS1 Antigen System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA pending 
+DPP Chikungunya IgM/IgG System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP Zika Chikungunya Dengue IgM/IgG System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP Ebola Antigen System 
+CDC 
+✓ 
+✓ 
+✓ 
+✓ 
+FDA-EUA 
+DPP Fever Assay Asia 
+FIND 
+✓ 
+✓ 
+✓ 
+✓ 
+DPP Fever Assay Africa 
+Paul Allen Foundation 
+✓ 
+✓ 
+✓ 
+DPP Fever Assay Malaysia 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+Sales Channels 
+Our products are sold globally, both directly and through distributors, to hospitals and clinics, physician offices, clinical laboratories, public health organizations, government agencies and consumers. Historically we marketed and sold our products only into a handful of countries and regions. During 2020, we expanded our U.S.-based sales, customer service, and marketing team to focus on the COVID-19, HIV-Syphilis, and future DPP platform product opportunities. With sales growth as an underlying objective, we are focused on increasing sales in geographies that support higher average selling prices. From lead generation through technical inquiries, Chembio has the internal resources to support customers through the commercial process including marketing, sales, sales support, order entry and product support. Our goal is to delight our global customers through all facets of our commercial interactions. 
+Automation of U.S. Manufacturing 
+We are automating our U.S. manufacturing processes and expanding our manufacturing capacity. Over the past two years, we have taken delivery of and completed validation of most of our automated manufacturing lines. These use vision-guided, robotic operation to improve inspection and quality control. As we transition from manual to automated assembly, we believe the reduced variable costs will improve product gross margins. 
+DPP Technology & Development 
+Our commercially available products employ either our patented DPP technology or traditional lateral flow technology. We believe products developed using our DPP technology can provide superior diagnostic performance compared with products that utilize traditional lateral flow technology. 
+Chembio’s history of collaborations has proven the strength and capabilities of the DPP platform to address a diverse range of biomarkers. We are now focusing our R&D resources on delivering products to build a portfolio of COVID-19 tests, Chembio’s new and expanded product portfolio will emphasize high value added tests with strong margins, selling in developed markets, established sales channels, and clinically accepted use cases, where the differentiated capabilities of DPP provide a competitive advantage. 
+8 
+Table of Contents 
+Competition 
+Many of our competitors are significantly larger and have greater financial, research, manufacturing, and marketing resources. Important competitive factors include product quality, analytical performance, ease of use, price, customer service and reputation. Industry competition is based on these and the following additional factors: 
+● 
+patent protection; 
+● 
+scientific expertise; 
+● 
+ability to develop and market products and processes; 
+● 
+ability to obtain required regulatory approvals; 
+● 
+ability to manufacture cost-effective products that meet applicable regulatory requirements; 
+● 
+access to adequate capital; and, 
+● 
+ability to attract and retain qualified personnel. 
+We believe our scientific capabilities and proprietary know-how relating to our patented DPP technology and rapid diagnostic technology are very strong, particularly for the development and manufacture of tests for the detection of infectious and other diseases. 
+Although we have no specific knowledge of any other competitors’ products that could render our products obsolete, if we fail to maintain and enhance our competitive position or fail to introduce new products and product features, our customers may decide to use the products developed by our competitors, which could result in a loss of revenues and cash flow. 
+Employees 
+As of December 31, 2020, we had 355 full-time equivalent employees, of whom 39 were in administration, 262 were in manufacturing, 32 were in research and development, and 22 were in sales and marketing and customer service. Of these employees, approximately 320 were located in the United States, 0 were located in Malaysia, 19 were located in Germany and 16 were located in Brazil. 
+We have never had a work stoppage, and none of our employees are represented by a labor organization or subject to any collective bargaining arrangements. We consider our employee relations to be good. 
+In January 2021, Chembio announced a restructuting plan in the US and reduced its workforce by approximately 9%, as further discussed on Note 16 - Subsequent Events. 
+Governmental Regulation 
+Certain of our activities are subject to regulatory oversight by the FDA under provisions of the Federal Food, Drug, and Cosmetic Act and regulations thereunder, including regulations governing the development, marketing, labeling, promotion, manufacturing, and export of diagnostic products. Our clinical laboratory customers are subject to oversight by Centers for Medicare and Medicaid Services, or CMS, pursuant to CLIA, as well as agencies in various states. Failure to comply with applicable requirements can lead to sanctions, including withdrawal of products from the market, recalls, refusal to authorize government contracts, product seizures, civil money penalties, injunctions, and criminal prosecution. 
+FDA Approval/Clearance Requirements 
+Unless an exemption applies, each medical device that we market or wish to market in the United States must receive 510(k) clearance or Premarket Approval, or PMA. Medical devices that receive 510(k) clearance are “cleared” by the FDA to market, distribute, and sell in the United States. Medical devices that obtain a PMA by the FDA are “approved” to market, distribute and sell in the United States. We cannot be certain that 510(k) clearance or PMA approval will ever be obtained for any products that have not already obtained 510(k) clearance or PMA approval. Descriptions of the PMA and 510(k) clearance processes are provided below. 
+The FDA decides whether a device line must undergo either the 510(k) clearance or PMA based on statutory criteria that utilize a risk-based classification system. PMA is the FDA process of scientific and regulatory review to evaluate the safety and effectiveness of Class III medical devices and, in many cases, Class II medical devices. Class III devices are those that support or sustain human life, are of substantial importance in preventing impairment of human health, or which present a potential, unreasonable risk of illness or injury. The FDA uses these criteria to decide whether a PMA or a 510(k) is appropriate, including the level of risk that the agency perceives is associated with the device and a determination by the agency of whether the product is a type of device that is similar to devices that are already legally marketed. Devices deemed to pose relatively less risk are placed in either Class I or II. In many cases, the FDA requires the manufacturer to submit a 510(k) requesting clearance (also referred to as a premarket notification), unless an exemption applies. The 510(k) must demonstrate that the manufacturer’s proposed device is “substantially equivalent” in intended use and in safety and effectiveness to a legally marketed predicate device. A “predicate device” is a pre-existing medical device to which equivalence can be drawn, that is either in Class I or Class II or is a Class III device that was in commercial distribution before May 28, 1976, for which the FDA has not yet called for submission of a PMA application. 
+9 
+Table of Contents 
+Device classification depends on the device’s intended use and its indications for use. In addition, classification is risk-based, that is, the risk the device poses to the patient and/or the user is a major factor in determining the class to which it is assigned. Class I includes devices with the lowest risk and Class III includes those with the greatest risk. 
+Class I devices are those for which safety and effectiveness can be assured by adherence to the FDA’s general regulatory controls for medical devices, or the General Controls, which include compliance with the applicable portions of the FDA’s quality system regulations, facility registration and product listing, reporting of adverse medical events, and appropriate, truthful and non-misleading labeling, advertising, and promotional materials. Some Class I devices also require premarket clearance by the FDA through the 510(k) process described below. 
+Class II devices are subject to the FDA’s General Controls, and any other special controls as deemed necessary by the FDA to ensure the safety and effectiveness of the device. Premarket review and clearance by the FDA for Class II devices is accomplished through the 510(k) process. Pursuant to the Medical Device User Fee and Modernization Act of 2002, unless a specific exemption applies, 510(k) submissions are subject to user fees. Certain Class II devices are exempt from this premarket review process. 
+Class III includes devices with the greatest risk. Devices in this class must meet all of the requirements in Classes I and II. In addition, Class III devices cannot be marketed until they receive Premarket Approval. 
+The safety and effectiveness of Class III devices cannot be assured solely by the General Controls and the other requirements described above. These devices require formal clinical studies to demonstrate safety and effectiveness. Under Medical Device User Fee and Modernization Act of 2002, PMA applications (and supplemental premarket approval applications) are subject to significantly higher user fees than 510(k) applications, and they also require considerably more time and resources. 
+Rapid HIV tests intended for diagnostic use are regulated as Class III devices. Responsibility for assuring the safety and effectiveness of these tests lies within the Center for Biologics Evaluation and Research’s Office of Blood Research and Review, with oversight by the Blood Products Advisory Committee. Approved rapid HIV tests must meet the regulations in the 21 CFR 800 series subparts, under the investigational device exemption, or IDE and PMA pathways. 
+Premarket Approval Pathway 
+We manufacture, market and distribute three rapid HIV tests in the United States. Our HIV 1/2 STAT-PAK Assay, SURE CHECK HIV 1/2 Assay, and DPP HIV 1/2 Assay all have received FDA PMA approval. A PMA application must be supported by extensive data including, but not limited to, analytical, preclinical, clinical trials, manufacturing, statutory preapproval inspections, and labeling to demonstrate to the FDA’s satisfaction the safety and effectiveness of the device for its intended use. Before a PMA is submitted, a manufacturer must apply for an IDE. If the device presents a “significant risk,” as defined by the FDA, to human health, the FDA requires the device sponsor to file an IDE application with the FDA and obtain IDE approval prior to initiation of enrollment of human subjects for clinical trials. The IDE provides the manufacturer with a legal pathway to perform clinical trials on human subjects where without the IDE, only approved medical devices may be used on human subjects. 
+The IDE application must be supported by appropriate data, such as analytical, animal and laboratory testing results, manufacturing information, and an Investigational Review Board, or IRB approved protocol showing that it is safe to test the device in humans and that the testing protocol is scientifically sound. If the clinical trial design is deemed to have “non-significant risk,” the clinical trial may be eligible for “abbreviated” IDE requirements. In some instances, clinical trials for in vitro diagnostic medical devices may be exempt from the more burdensome IDE requirements if certain labeling requirements are met. 
+A clinical trial may be suspended by either the FDA or the Investigational Review Board at any time for various reasons, including a belief that the risks to the study participants outweigh the benefits of participation in the study. Even if a study is completed, clinical testing results may not demonstrate the safety and efficacy of the device, or they may be equivocal or otherwise insufficient to obtain approval of the product being tested. After the clinical trials have been completed, if at all, and the clinical trial data and results are collected and organized, a manufacturer may complete a PMA application. 
+After a PMA application is sufficiently complete, the FDA will accept the application and begin an in-depth review of the submitted information. By statute, the FDA has 180 days to review the “accepted application,” although, generally, review of the application can take between one and three years, but it may take significantly longer. During this review period, the FDA may request additional information or clarification of information already provided. Also, during the review period, an advisory panel of experts from outside the FDA may be convened to review and evaluate the application and provide recommendations to the FDA as to the approvability of the device. The preapproval inspections conducted by the FDA include an evaluation of the manufacturing facility to ensure compliance with the FDA’s quality systems regulations or QSR, as well as inspections of the clinical trial sites by the Bioresearch Monitoring group to evaluate compliance with good clinical practice and human subject protections. New PMA applications or PMA supplements are required for modifications that affect the safety or effectiveness of the device, including, for example, certain types of modifications to the device’s indication for use, manufacturing process, labeling and design. Significant changes to an approved PMA require a 180-day supplement, whereas less substantive changes may utilize a 30-day notice, or a 135-day supplement. Premarket approval supplements often require submission of the same type of information as a premarket approval application, except that the supplement is limited to information needed to support any changes from the device covered by the original premarket approval application, and it may not require as extensive clinical data or the convening of an advisory panel. 
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+Our HIV 1/2 STAT-PAK Assay PMA application number BP050009/0 and our SURE CHECK 1/2 HIV Assay PMA application number BP050010/0 were approved by the FDA in May 2006. Our DPP HIV 1/2 Assay PMA application number BP120032/0 was approved by the FDA in December 2012. Our DPP HIV Syphilis Assay PMA application number BP180191/0 was approved by the FDA in October 2020. 
+510(k) Clearance Pathway 
+We are currently developing products that either will or are likely to require an FDA 510(k) clearance. We anticipate submitting a 510(k) for each such product to demonstrate that such proposed device is substantially equivalent to a previously cleared 510(k) device or a device that was in commercial distribution before May 28, 1976, for which the FDA has not yet called for the submission of a 510(k). The FDA’s 510(k) clearance pathway usually takes from three to twelve months but could take longer. In some cases the FDA may require additional information, including clinical data, to make a determination regarding substantial equivalence. 
+If a device receives 510(k) clearance, any modification that could significantly affect its safety or effectiveness, or that would constitute a new or major change in its intended use, will require a new 510(k) clearance or, depending on the modification, a PMA. The FDA requires each device manufacturer to determine whether the proposed change requires submission of a new 510(k) or a PMA, but the FDA can review any such decision and, if it disagrees with the manufacturer’s determination, can require the manufacturer to cease marketing and/or recall the modified device until 510(k) clearance or PMA of the modified device is obtained. 
+Clinical Laboratory Improvement Amendments of 1988 
+A manufacturer of a test categorized as moderately complex may request that categorization of the test be waived through a CLIA Waiver by Application, or CW, submission to the FDA. When a test is categorized as waived, it may be performed by laboratories with a Certificate of Waiver, such as a physician’s office outreach setting. In a CW submission, the manufacturer provides evidence to the FDA that a test meets the CLIA statutory criteria for waiver CLIA, a walk-in clinic or an emergency room provides CMS authority over all laboratory testing, except research that is performed on humans in the United States. The Division of Laboratory Services, within the Survey and Certification Group under the CMS, has the responsibility for implementing the CLIA program. 
+The CLIA program is designed to establish quality laboratory testing by ensuring the accuracy, reliability and timeliness of patient test results. Under CLIA, a laboratory is a facility that does laboratory testing on specimens derived from humans and used to provide information for the diagnosis, prevention or treatment of disease, or impairment of, or assessment of health. Under the CLIA program, unless waived, laboratories must be certified by the government, satisfy governmental quality and personnel standards, undergo proficiency testing, be subject to inspections and pay fees. We have received a CLIA waiver for all of our rapid diagnostic rapid HIV tests that we market in the United States. Specifically, the CLIA waiver was granted by the FDA for HIV 1/2 STAT-PAK in November 2006,for SURE CHECK HIV 1/2 in October 2007, and for DPP HIV 1/2 in October 2014. 
+Emergency Use Authorizations (EUA) 
+A formal request to issue an EUA generally should not be submitted until the Secretary of HHS has issued an EUA declaration under section 564(b)(1). In particular, although section 564 allows FDA to issue an EUA for preparedness purposes, in such cases the HHS Secretary must first declare that circumstances exist justifying such an authorization in advance of an actual emergency based on a formal determination of a significant potential for emergency or a material threat determination. During the effective period of the HHS Secretary’s EUA declaration, FDA may authorize the introduction of a medical product into interstate commerce when the product is intended for use during an actual or potential emergency. EUA candidate products include medical products and uses that are not approved, cleared, or licensed under sections 505, 510(k), and 515 of the FD&C Act or section 351 of the PHS Act. 
+After the requisite determination and declaration have been issued, and after feasible and appropriate consultations, FDA may issue an EUA only if FDA concludes that the following four statutory criteria for issuance have been met for 1) Serious or Life-Threatening Disease or conditions, 2) evidence of effectiveness, 2) Risk –Benefit Analysis, 4) No Alternatives. A sponsor seeking an EUA can submit its formal request in the form of an EUA submission, which includes data for clinical studies, non-clinical laboratory studies to assess the safety and effectiveness of the product as well as the discussion of Risks and Benefits of the product. 
+FDA will specify the effective date of an EUA issued under section 564. In general, an EUA will remain in effect for the duration of the EUA declaration under which it was issued which describes termination of an EUA declaration and its impact on existing EUAs. 
+Pervasive and Continuing FDA Regulation 
+A host of regulatory requirements apply to our approved devices, including: the quality system regulation, which requires manufacturers to follow elaborate design, testing, control, documentation and other quality assurance procedures; the Medical Reporting Regulations, which require manufacturers to report to the FDA specified types of adverse events involving their products; labeling regulations; and the FDA’s general prohibition against promoting products for unapproved or “off-label” uses. Some Class II devices are subject to special controls-such as performance standards, post-market surveillance, patient registries, and FDA guidelines-that do not apply to Class I devices. 
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+The regulatory requirements that apply to our approved products classified as medical devices include: 
+● 
+product listing and establishment registration, which helps facilitate FDA inspections and other regulatory action; 
+● 
+QSR, which require manufacturers, including third-party manufacturers, to follow stringent design, testing, control, documentation and other quality assurance procedures during all aspects of the development and manufacturing process; 
+● 
+labeling regulations and FDA prohibitions against the promotion of products for uncleared, unapproved or off-label use or indication; 
+● 
+clearance of product modifications that could significantly affect safety or efficacy or that would constitute a major change in intended use of one of our cleared devices; 
+● 
+approval of product modifications that affect the safety or effectiveness of one of our cleared devices; 
+● 
+medical device reporting regulations, which require that manufacturers comply with FDA requirements to report if their device may have caused or contributed to a death or serious injury, or has malfunctioned in a way that would likely cause or contribute to a death or serious injury if the malfunction of the device or a similar device were to recur; 
+● 
+post-approval restrictions or conditions, including post-approval study commitments; 
+● 
+post-market surveillance regulations, which apply when necessary to protect the public health or to provide additional safety and effectiveness data for the device; 
+● 
+the FDA’s recall authority, whereby it can ask, or under certain conditions order, device manufacturers to recall from the market a product that is in violation of governing laws and regulations; 
+● 
+regulations pertaining to voluntary recalls; and, 
+● 
+notices of corrections or removals. 
+Our Medford, New York facility is currently registered as an establishment with the FDA. We and any third-party manufacturers are subject to announced and unannounced inspections by the FDA to determine our compliance with QSR and other regulations. 
+21st Century Cures Act 
+The 21st Century Cures Act, enacted in December 2016, contains several sections specific to medical device innovations. We believe that implementation of the 21st Century Cures Act may have a positive impact on its businesses by facilitating innovation and/or reducing the regulatory burden imposed on medical device manufacturers. 
+Government Regulation of Medical Devices for Animal Subjects 
+We currently offer two veterinary devices in the United States: DPP VetTB Assay for Cervids and DPP VetTB Assay for Elephants. Diagnostic tests for animal health infectious diseases, including our veterinary devices for the prevention and/or treatment of animal disease, are regulated in the U.S. by the Center for Veterinary Biologics within the U.S. Department of Agriculture Animal and Plant Health Inspection Service, or APHIS, under the Virus, Serum, and Toxin Act of 1913. As a requirement, our veterinary devices were approved by APHIS before they could be sold in the U.S. 
+The APHIS regulatory approval process involves the submission of product performance data and manufacturing documentation. Following regulatory approval to market a product, APHIS requires that each lot of product be submitted for review before release to customers. In addition, APHIS requires special approval to market products where test results are used in part for government-mandated disease management programs. 
+Environmental Laws 
+We believe that we are in compliance in all material respects with all foreign, federal, state, and local environmental regulations applicable to our manufacturing facilities. The cost of ongoing compliance with such regulations does not have a material effect on our operations. 
+Intellectual Property 
+Intellectual Property Strategy 
+Our intellectual property strategy is to: (1) build our own intellectual property portfolio around our DPP technology and optical analyzers; (2) pursue licenses, trade secrets and know-how within the area of rapid point-of-care testing; and, (3) develop and acquire proprietary positions to certain reagents. 
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+DPP Intellectual Property 
+We have obtained patent coverage on our DPP technology, including numerous patents in the United States, and one or more patents in Australia, Brazil, Canada, China, Columbia, Eurasia (Russia), European Union (fourteen European countries),Hong Kong, Israel, India, Indonesia, Japan, Korea, Malaysia, Mexico, Poland, Singapore, South Africa, Thailand, and the United Kingdom . Additional patent applications on our DPP technology are pending in the United States, as well as in foreign countries such as Australia, Brazil, Canada, China, the European Union, India, Indonesia, Malaysia, Mexico, Peru, Singapore and Thailand. 
+DPP technology provides us with freedom to operate and enables us to develop tests with better performance and capabilities compared with tests built on traditional lateral flow platforms. These advantages have allowed us to enter into multiple technology collaborations based upon DPP technology, which we believe will provide new manufacturing and marketing opportunities. We have filed additional patent applications that we believe will strengthen the DPP intellectual property and have also filed for patent protection for certain other point-of-care technologies or applications thereof. 
+We have also obtained patent coverage on our optical-based analyzer technology in the United States as well as in several EU countries. 
+Trademarks 
+We have filed and obtained trademarks for our company name CHEMBIO and CHEMBIO DIAGNOSTIC SYSTEMS, INC. as well as for many of our products, including DPP, SURE CHECK, STAT-VIEW, STAT-PAK, and NEXT GENERATION DPP, as well as for the SampleTainer and DPP Micro Reader, which are used with certain DPP products. Our trademarks have been registered in the United States and certain other countries around the world. 
+Trade Secrets and Know-How 
+We have developed a substantial body of trade secrets and know-how relating to the development and manufacture of lateral flow and DPP-based diagnostic tests, including the sourcing and optimization of materials for such tests, and methods to maximize sensitivity, speed-to-result, specificity, stability and reproducibility of our tests. We possess proprietary know-how to develop tests for multiple conditions using colored particles. Our formulations enable long shelf lives of our rapid HIV and other tests, providing us with an important competitive advantage. 
+Rapid Diagnostic Technology and Reagent Licenses 
+We seek licenses and/or redesigns of products that we believe to be in our best interests. Because of the costs and other negative consequences of time-consuming patent litigation, we often attempt to obtain a license on reasonable terms. 
+The peptides used in our rapid HIV tests were licensed to us by one or more third parties. We also have licensed the antigens used in other tests including our Syphilis, Tuberculosis, Leptospirosis, Leishmaniasis and Chagas tests, and we may enter into other license agreements. In prior years, we concluded license agreements related to intellectual property rights owned by the United States associated with HIV-1 and a sub-license agreement for HIV-2 with Bio-Rad Laboratories N.A., the exclusive licensee of the Pasteur Institute’s HIV-2 intellectual property estate. 
+Available Information 
+We are required to file annual, quarterly and current reports, proxy statements and other information with the U.S. Securities and Exchange Commission. The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. 
+Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, proxy statements and amendments to those documents filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, are also available free of charge on our website at www.chembio.com as soon as reasonably practicable after such reports are electronically filed with or furnished to the SEC. 
+Investors should note that we currently announce material information to our investors and others using filings with the SEC, press releases, public conference calls, webcasts or our website (www.chembio.com), including news and announcements regarding our financial performance, key personnel, our brands and our business strategy. Information that we post on our corporate website could be deemed material to investors. We encourage investors to review the information we post on these channels. We may from time to time update the list of channels we will use to communicate information that could be deemed material and will post information about any such change on www.chembio.com. The information on our website is not, and shall not be deemed to be, a part hereof or incorporated into this or any of our other filings with the SEC. 
+Corporate Information 
+Our principal executive offices are located at 555 Wireless Boulevard, Hauppauge, New York 11788. Our telephone number is (631) 924-1135. Our website address is www.chembio.com. The information contained in, or accessible through, our corporate website does not constitute part of this report. 
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+ITEM 1A. 
+RISK FACTORS 
+You should carefully consider each of the following risk factors and all of the other information provided in this Form 10 K in considering whether to make or continue to hold an investment in our Common Stock. The risks described below are those we currently believe may materially affect us. An investment in our Company involves a high degree of risk, and should be considered only by persons who can afford the loss of their entire investment. Although we believe that these risks are the most important for you to consider, you should read this section in conjunction with our financial statements, the notes to those financial statements and our management’s discussion and analysis of financial condition and results of operations included in our periodic reports and incorporated into this Form 10 K by reference. 
+RISK FACTORS SUMMARY 
+Our business is subject to a number of risks, including risks that may prevent us from achieving our business objectives or may adversely affect our business, financial condition, results of operations, cash flows and prospects. The risks are discussed more fully below and include, but are not limited to, the risks summarized below. 
+Risks Related to Our Business and Our Industry 
+● 
+the refocus of our business strategy to respond to COVID‑19, including the successful development and market acceptance of the DPP SARS-CoV-2 IgM/IgG System, the DPP SARS CoV 2 Antigen System and the DPP Respiratory Antigen Panel, which we refer to as the COVID-19 Diagnostic Test Systems; 
+● 
+our allocation of substantially all of our resources to the development and production of COVID-19 Diagnostic Test Systems; 
+● 
+the effects of existing or future shareholder litigation; 
+● 
+our competitors developing more effective or successful products; 
+● 
+the ability of our products to compete with the new or existing products of our competitors; 
+● 
+the negative impact of healthcare industry consolidation on our future revenues and operating results; 
+● 
+our ability to retain key employees and attract additional qualified personnel; 
+● 
+third‑party reimbursement policies; and 
+● 
+the vulnerability of our business to cyber‑attacks. 
+Risks Related to Our Products 
+● 
+the COVID-19 Diagnostic Test Systems not gaining wide industry acceptance; 
+● 
+the impact of COVID‑19 mutations on the ability of the COVID-19 Diagnostic Test Systems adequately detecting COVID‑19 or SARS‑CoV‑2 antigens; 
+● 
+our ability to successfully introduce and market our products, particularly the COVID-19 Diagnostic Test Systems; 
+● 
+timely receipt and implementation of additional customized manufacturing automation equipment; 
+● 
+variability and unpredictability due to lengthy sales cycles for our products; 
+● 
+our customers not adopting rapid point‑of‑care diagnostic testing; 
+● 
+the concentration of our customers; and 
+● 
+our products not performing properly. 
+Financial, Economic and Financing Risks 
+● 
+our incurrence of losses in recent years and uncertainty about our future profitability; 
+● 
+the fluctuation of our financial results; 
+● 
+our compliance with the terms of our Credit Agreement and Guaranty; 
+● 
+our ability to generate sufficient cash to service our debt; 
+● 
+increased interest expenses due to changes in LIBOR; 
+● 
+the negative impact of changes in foreign currency exchange rates on our operating results; and 
+● 
+basing our estimates or judgments relate to critical accounting policies on assumptions that can change or prove to be incorrect. 
+Risks Related to Intellectual Property 
+● 
+our ability to protect our proprietary technology; and 
+● 
+the effect of future intellectual property disputes on our ability to sell products or use certain technologies. 
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+Table of Contents 
+Risks Related to Our Third Party Collaborators 
+● 
+our dependence on a limited number of third‑party suppliers, including single source suppliers, for critical components and materials; 
+● 
+the limitation on rights we receive from collaborations with strategic collaborators, and the exposure to risks outside of our control due to such collaborations; 
+● 
+our ability to maintain existing distribution channels or develop new distribution channels; and 
+● 
+our compliance with U.S. government contracts. 
+Risks Related to Regulations 
+● 
+the impact of changes in CLIA, FDA, ANVISA, and other regulatory changes, on COVID‑19 diagnostic tests; 
+● 
+our ability to receive and maintain necessary regulatory approvals for our products, particularly the COVID-19 Diagnostic Test Systems; 
+● 
+the impact of governmental export controls on our ability to compete in international markets; 
+● 
+our ability to comply with FDA and other regulatory requirements, particularly with respect to the COVID-19 Diagnostic Test Systems; 
+● 
+our ability to respond to changes in regulatory requirements; 
+● 
+the effect of FDA regulation of laboratory‑developed tests and genetic testing on demand for our products; 
+● 
+disruptions at the FDA and other government agencies affecting the ability of the FDA to hire, retain or deploy key leadership or personal or otherwise could prevent new and modified products from being developed, cleared, approved, authorized or commercialized; 
+● 
+ongoing changes in healthcare regulation; 
+● 
+a reduction or elimination in the types of government awards that partially support some of our programs; 
+● 
+compliance with privacy, security and breach notification regulations; 
+● 
+our ability to manufacture products in accordance with applicable requirements; 
+● 
+the effect of healthcare fraud and abuse laws on our business; and 
+● 
+increased exposure to regulatory, cultural and other challenges due to international expansion. 
+Risks Related to Ownership of Common Stock 
+● 
+the limited liquidity of our Common Stock; 
+● 
+the volatility of the price of our Common Stock; 
+● 
+the effect of future issuances of Common Stock on the price of our Common Stock and our ability to raise funds in new equity offerings; 
+● 
+the control management and larger stockholders exercise over us; and 
+● 
+the depression of the market price of our common stock due to sale by existing stockholders, executive officers or directors. 
+General Risk Factors 
+● 
+our ability to successfully generate the expected benefits of our acquisitions; and 
+● 
+developments related to the U.K.’s referendum on membership in the E.U.; and 
+● 
+legislative and regulatory changes. 
+RISK FACTORS 
+Risks Related to Our Business and Our Industry 
+We have refocused our business strategy to respond to COVID‑19, which is a new and rapidly developing market, making it difficult to evaluate our business and future prospects. 
+The market for COVID‑19 diagnostic testing is new and rapidly developing, which makes it difficult to evaluate our business and future prospects. We have encountered, and will continue to encounter, risks and difficulties frequently experienced in rapidly changing industries, including those related to: 
+● 
+our ability to compete with companies that are currently in, or may in the future enter, the market for our products; 
+● 
+our ability to control costs, including our operating expenses; 
+● 
+our ability to successfully expand our business; 
+● 
+our ability to meet customer demand; 
+● 
+the amount and timing of operating expenses, particularly sales and manufacturing expenses, related to the maintenance and expansion of our business, operations and infrastructure; and 
+● 
+general economic and political conditions in our markets. 
+Given the unpredictable nature of the COVID‑19 pandemic, the potential size of this market and the timing of its development remains highly uncertain. Our future success is dependent on the manner in which the market for COVID‑19 diagnostics develops. If the market develops in a manner that does not facilitate the inclusion of our products, or fails to grow in the manner in which we expect, our business may not continue to grow. 
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+We are allocating substantially all of our resources to the development and production of COVID‑19 Test Systems for the foreseeable future, and our long‑term business success could be negatively impacted by our diversion of resources from our legacy business of diagnostic testing for other infectious diseases. 
+We are committing substantially all of our financial and personnel resources to the development, manufacturing and commercialization of COVID-19 Diagnostic Test Systems . This resource allocation may negatively impact our legacy product portfolio, as we expect to spend limited funds and time on updating pre‑existing products and regulatory approvals or on completing products that were in development prior to our strategic decision to focus on COVID-19 Diagnostic Test Systems . Our business could be negatively impacted by our allocation of significant resources to a global health threat that is unpredictable and could dissipate; there is no guarantee that current or anticipated demand will continue, or if demand does continue, that we will be able to produce in quantities to meet the demand. We intend to reestablish our legacy business in the future, but there can be no assurance that we will be able to successfully recommence the development and commercialization of our legacy products and products under development. 
+Our near‑term success is highly dependent on the success of the COVID-19 Diagnostic Test Systems , and we cannot be certain that we will succeed in developing one or more of those systems or that, if we do, they will attain market acceptance or be successfully commercialized in the United States or elsewhere. 
+We do not currently have an Emergency Use Authorization, or EUA, from the U.S. Food and Drug Administration, or FDA, for any of the COVID-19 Diagnostic Test Systems, and we do not currently have an application pending for any such EUA. Moreover, market and regulatory requirements continue to change at a rapid pace. The FDA has declined to review certain of our COVID-19 Diagnostic Test Systems based on then-effective prioritization guidance, which is subject to change. There can be no assurance that, if we are to make a submission of any future EUA application, we will meet the requirements of the prioritization guidance in effect at the time of the submission or otherwise be successful in obtaining an EUA that would permit us to offer and sell any COVID-19 Diagnostic Test System in the United States. 
+Even if we are able to obtain an EUA for any of the COVID-19 Diagnostic Test Systems, including our revised DPP SARS-CoV-2 IgM/IgG System and DPP SARS-CoV-2 Antigen System that product may not gain broad market acceptance among physicians, healthcare payers, patients, and the medical community. We have conducted our own research into the markets for our product candidates, including the COVID-19 Diagnostic Test Systems; however, we cannot guarantee market acceptance of our product, and have somewhat limited information on which to estimate our anticipated level of sales. Our products will require healthcare providers and doctors to accept and adopt our technology. Our industry is susceptible to rapid technological developments and there can be no assurance that we will be able to match any new technological advances. If we are unable to match the technological changes in the needs of our customers the demand for our products will be reduced. Acceptance and use of any products we market will depend upon a number of factors including: 
+● 
+perceptions by members of the health care community, including physicians, about the safety and effectiveness of our products; 
+● 
+limitation on use or warnings required by FDA in our product labeling; 
+● 
+cost‑effectiveness of our products relative to competing products; 
+● 
+convenience and ease of administration; 
+● 
+potential advantages of alternative treatment methods; 
+● 
+availability of reimbursement for our products from government or other healthcare payers; and 
+● 
+effectiveness of marketing and distribution efforts by us and our licensees and distributors, if any. 
+Because we expect virtually all of our product revenues for the foreseeable future to be generated from sales of our current products and COVID-19 Diagnostic Test Systems in particular, the failure of these products to find market acceptance would substantially harm our business and would adversely affect our revenue. If the COVID-19 Diagnostic Test Systems are not as successfully commercialized as expected, we may not be able to generate sufficient revenue to become profitable. Any failure of either of the COVID‑19 Diagnostic Test Systems to be successfully commercialized in the United States may have a material adverse effect on our business, operating result financial condition and cash flows, and could result in a substantial decline in the price of our common stock. 
+The diagnostic testing market, particularly with respect to COVID‑19, is highly competitive, and many of our competitors are larger, better established and have greater technical and marketing capabilities and financial and other resources than we have. 
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+The diagnostics market, particularly with respect to COVID‑19 diagnostic tests, is highly competitive and we face substantial competition based on factors such as product quality, analytical performance, ease of use, price, customer service and reputation. Industry competition is also based the following additional factors: 
+● 
+patent protection; 
+● 
+scientific expertise; 
+● 
+ability to develop and market products and processes; 
+● 
+ability to obtain required regulatory approvals; 
+● 
+ability to manufacture cost‑effective products that meet applicable regulatory requirements; 
+● 
+access to adequate capital; and 
+● 
+ability to attract and retain qualified personnel. 
+Numerous companies in the United States and internationally have announced their intention to offer new products, services and technologies that could be used in substitution for the COVID-19 Diagnostic Test Systems. Many of those competitors are significantly larger, and have substantially greater financial, engineering and other resources, than us. In addition, our competitors may have or may develop products or technologies that currently or in the future will enable them to produce competitive products with greater capabilities or at lower costs than ours. If we are unable to compete effectively, we may fail to meet our strategic objectives, and our business, financial condition and operating results could be harmed. In addition, the production of an efficacious vaccine or other treatment for COVID‑19 may reduce the demand for diagnostic products. The success or failure, or perceived success or failure, of other companies may adversely impact our ability to obtain any future funding, or to ultimately commercialize the COVID-19 Diagnostic Test Systems . 
+Shareholder litigation could negatively impact our business, operating results and financial condition. 
+We may incur additional costs in connection with the defense or settlement of existing and any future shareholder litigation, including four shareholder lawsuits to date that have been brought against us. See Part I, Item 3. “Legal Proceedings” below for additional information regarding these lawsuits. These lawsuits or other future litigation may adversely affect the ability of our technical and management personnel, and our directors, to perform their normal responsibilities. We could incur significant costs in connection with any such litigation lawsuits, including costs associated with the indemnification of obligations to our directors. 
+We expect competition to with respect to testing solutions for COVID‑19 to continue to increase and our success will depend on widespread market acceptance of our products. 
+We expect competition to continue to increase as other established and emerging companies enter the market, as customer requirements evolve, and as new products, services and technologies are introduced. The entrance of new competitors is being encouraged by governmental authorities, which are offering funding to support development of testing solutions for COVID‑19. Some of our existing or new competitors may have strong relationships with current and potential customers, including governmental authorities, and, as a result, may be able to respond more quickly to new or changing regulatory requirements, new or emerging technologies, and changes in customer requirements. Our products may not compete favorably, and we may not be successful in the face of increasing competition from new products and technologies introduced by our existing competitors or new companies entering our markets. Any failure to compete effectively could materially and adversely affect our business, financial condition and operating results. 
+The COVID‑19 pandemic could affect our suppliers and employees, and cause disruptions in current and future plans for operations and expansion. 
+The COVID‑19 pandemic may directly and indirectly adversely impact our business, financial condition and operating results. The extent to which this will continue will depend on numerous evolving factors that are highly uncertain, rapidly changing and cannot be predicted with precision or certainty at this time. 
+Our business may be disrupted due to the costs incurred as a result of additional necessary actions and preparedness plans to help ensure the health and safety of our employees and continued operations, including enhanced cleaning processes, protocols designed to implement appropriate social distancing practices, and/or adoption of additional wage and benefit programs to assist employees. We may also have difficulty meeting demand for our products if our employees are affected by COVID‑19, or if we do not have adequate space to produce our product with social distancing practices implemented. We also cannot predict the effect of COVID‑19 pandemic on our supply chain’s reliability and costs, 
+In addition, our business and operations, and the operations of our suppliers, may be adversely affected by the COVID‑19 pandemic. The pandemic, including the related response, could cause disruptions due to potential suspension or slowdown of activities at our third‑party suppliers, or increased prices implemented by our suppliers. The adverse effect on our employees or suppliers could have an adverse impact on our business, results of operations and financial condition. 
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+We operate in a fragmented, segmented, and rapidly changing industry, which is highly competitive with respect to numerous factors, and our success depends on our ability compete effectively with larger companies, develop new or enhance existing products, as well as acceptance of DPP over more traditional diagnostic platform technologies. 
+Important competitive factors for our products include price, quality, performance, ease of use, and customer service. A few large corporations produce a wide variety of diagnostic tests and other medical devices and equipment. A larger number of mid‑size companies generally compete only in the diagnostic industry and a significant number of small companies produce only a few diagnostic products. As a result, the diagnostic test industry is highly fragmented and segmented. 
+More generally, the point‑of‑care diagnostics industry is undergoing rapid technological changes, with frequent introductions of new technology‑driven products and services. As new technologies become introduced into the point‑of‑care diagnostic testing market, we may be required to commit considerable additional efforts, time and resources to enhance our current product portfolio or develop new products. We may not have the available time and resources to accomplish this, and many of our competitors have substantially greater financial and other resources to invest in technological improvements. We may not be able to effectively implement new technology‑driven products and services or be successful in marketing these products and services to our customers, which would materially harm our operating results. 
+Although we own DPP patents, lateral flow technology is still a competitive platform to DPP, and lateral flow technology has a lower cost of manufacture than DPP products. Although the DPP platform has shown improved sensitivity as compared with conventional lateral flow platforms in a number of studies, several factors go into the development and performance attributes of products. Therefore the ability of our products to successfully compete will depend on several other factors, including our having a patented rapid test platform technology that differentiates DPP from lateral flow as well as from other diagnostic platform technologies. 
+There can be no assurance that our DPP patents or our products incorporating those patents will not be challenged at some time in the future. 
+Our competitors may develop and commercialize more effective or successful products, and our research, development and commercialization efforts may not succeed. 
+We regularly commit substantial resources to research and development and the commercialization of our new or enhanced products. The research and development process usually takes a long time from inception to commercial launch. During each stage of this process there is a substantial risk that we will not achieve our goals in a timely fashion, or at all, and we may have to abandon a new or enhanced product in which we have invested substantial time and money. We expect to continue to incur significant costs related to our research and development activities. 
+Our products require significant development and investment prior to commercialization, including testing to demonstrate the products’ performance capabilities, cost‑effectiveness or other benefits. We must obtain regulatory approval before most products may be sold and additional development efforts on these products may be required before the products will be reviewed. However, regulatory authorities may not approve these products for commercial sale or may substantially delay or condition such approval. There may be little or no market for the product and entry into or development of new markets for our products may require an investment of substantial resources even if all applicable regulatory approvals are obtained. Furthermore, we may spend a significant amount of money on advertising or other activities and still fail to develop a market for the product. The success of our efforts may be affected by our ability to manufacture products in a cost‑effective manner, whether we can obtain necessary intellectual property rights and protection and our ability to obtain reimbursement authorizations in the markets where the product will be sold. Therefore, if we fail to develop and gain commercial acceptance for our products, or if competitors develop more effective products or a greater number of successful new products, customers may decide not to purchase our products. 
+Our products may not be able to compete with new diagnostic products or existing products developed by well‑established competitors, which would negatively affect our business. 
+The diagnostic industry is focused on the testing of biological specimens in a laboratory or at the point‑of‑care and is highly competitive and rapidly changing. Important competitive factors for our products include price, quality, performance, ease of use, and customer service. 
+A few large corporations produce a wide variety of diagnostic tests and other medical devices and equipment. A larger number of mid‑size companies generally compete only in the diagnostic industry and a significant number of small companies produce only a few diagnostic products. As a result, the diagnostic test industry is highly fragmented and segmented. 
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+Some of our principal competitors may have considerably greater financial, technical and marketing resources than we do. Several companies produce diagnostic tests that compete directly with our testing product line, including Abbott (Alere), OraSure Technologies and Trinity Biotech. Some competitors offer broader product lines and may have greater name recognition than we have. These and other companies have or may have products incorporating molecular or other advanced technologies that over time could directly compete with our testing product line. We also face competition from certain of our distributors or former customers that have created or may decide to create, their own products to compete with ours. 
+As new products incorporating new technologies enter the market, our products may become obsolete or a competitor’s products may be more effective or more effectively marketed and sold. If our competitors’ products take market share from our products through more effective marketing or competitive pricing, our revenues, margins and operating results could be adversely affected. In addition, our revenues and operating results could be negatively impacted if some of our customers internally develop or acquire their own sample collection devices and use those devices in place of our products in order to reduce costs. 
+Our future revenues and operating results may be negatively affected by ongoing consolidation in the healthcare industry. 
+There has been a significant amount of consolidation in the healthcare industry. This consolidation has increased the competition to provide goods and services to customers. In addition, group purchasing organizations and integrated health delivery networks have served to concentrate purchasing decisions for some customers, which has also placed pricing pressure on medical device suppliers. Due to ongoing consolidation, there could be additional pressure on the prices of our products. 
+Our continued growth depends on retaining our current key employees and attracting additional qualified personnel, and we may not be able to do so. 
+Our success depends to a large extent upon the skills and experience of our executive officers, sales, marketing, operations and scientific staff. We may not be able to attract or retain qualified employees due to the intense competition for qualified personnel among medical products businesses and academic and other research institutions, as well as to geographic considerations, our ability to offer competitive compensation and benefits, and other reasons. 
+If we are not able to attract and retain the necessary qualified personnel to accomplish our business objectives, we may experience constraints that will adversely affect our ability to effectively manufacture, sell and market our products to meet the demands of our customers and strategic partners in a timely fashion, or to support internal research and development programs. 
+We have entered into employment contracts with our Chief Executive Officer, Richard Eberly, our Chief Science & Technology Officer, Javan Esfandiari, and our Chief Financial Officer, Neil Goldman. Due to the specific knowledge and experience of these executives regarding the industry, technology and market generally and to our company specifically, the loss of the services of any one of these executives could have a material adverse effect on us. We have not obtained a key man insurance policy on any officer other than Mr. Esfandiari. 
+We may not generate the expected benefits of our acquisitions of opTricon GmbH or Orangelife Comercio e Industria Ltda. and the ongoing integration of the acquisitions could disrupt our ongoing business, distract our management and increase our expenses. 
+We acquired opTricon GmbH, or opTricon, and Orangelife Comercio e Industria Ltda., or Orangelife, in November 2018 and November 2019, respectively, with the expectation that the acquisition will result in various benefits, including securing global commercial rights and reducing cost of goods. Achieving the anticipated benefits of either acquisition is subject to a number of uncertainties, including whether our business and the businesses of opTricon or Orangelife can be integrated in an efficient and effective manner. We cannot assure you that we will be able to accurately forecast the performance or ultimate impact of either the opTricon acquisition or the Orangelife acquisition. 
+The integration processes may take longer than anticipated and result in the loss of valuable employees, the incurrence of additional and unforeseen expenses, the disruption of our ongoing business, processes and systems, or inconsistencies in standards, controls, procedures, practices, policies and compensation arrangements, any of which could adversely affect our ability to achieve the anticipated benefits of the acquisitions. There may be increased risk due to integrating financial reporting and internal control systems. The integration processes are subject to a number of uncertainties, and no assurance can be given that the anticipated benefits, expense savings and synergies will be realized or, if realized, the timing of their realization. Failure to achieve these anticipated benefits could result in increased costs or decreases in the amount of expected revenues and could adversely affect our future business, financial condition, operating results and prospects. 
+We have incurred and will continue to incur non‑recurring expenses in connection with the opTricon acquisition and the Orangelife acquisition, including legal, accounting and other expenses. Additional unanticipated costs may be incurred following consummation of the opTricon acquisition or the Orangelife acquisition in the course of the integration of the respective businesses into our business. We cannot be certain that the realization of efficiencies related to the integration of the two businesses will offset the transaction and integration costs in the near term, or at all, or any losses from undiscovered liabilities not covered by an indemnification from the sellers of opTricon or Orangelife. 
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+Third‑party reimbursement policies and potential cost constraints could negatively affect our business. 
+The potential end‑users of our products include hospitals, physicians and other healthcare providers. If these end‑users do not receive adequate reimbursement for the cost of our products from their patients’ healthcare insurers or payors, the use of our products could be negatively impacted. Furthermore, the net sales of our products could also be adversely affected by changes in reimbursement policies of government or private healthcare payors. 
+Hospitals, physicians and other healthcare providers who purchase diagnostic products in the United States generally rely on third‑party payors, such as private health insurance plans, Medicare and Medicaid, to reimburse all or part of the cost of the product. Due to the overall escalating cost of medical products and services, especially in light of the COVID‑19 outbreak and its straining of healthcare systems across the globe, there is increased pressure on the healthcare industry, both foreign and domestic, to reduce the cost of products and services. Given the efforts to control and reduce healthcare costs in the United States, available levels of reimbursement may change for our existing products or products under development. Third‑party reimbursement and coverage may not be available or adequate in either the United States or international markets, current reimbursement amounts may be decreased in the future and future legislation, and regulation or reimbursement policies of third‑party payors, may reduce the demand for our products or our ability to sell our products on a profitable basis. 
+To the extent that we are unable to collect our outstanding accounts receivable, our operating results could be materially harmed. 
+There may be circumstances and timing that require us to accept payment terms, including delayed payment terms, from distributors or customers, which, if not satisfied, could cause financial losses. 
+We generally accept payment terms which require us to ship product before the contract price has been paid fully, and there also are circumstances pursuant to which we may accept further delayed payment terms pursuant to which we may continue to deliver product. To the extent that these circumstances result in significant accounts receivables and those accounts receivables are not paid on a timely basis, or are not paid at all, especially if concentrated in one or two customers, we could suffer financial losses. 
+We believe our success depends in part on the continued funding of, and our ability to participate in, large testing programs in the U.S. And worldwide, the funding of which may be reduced or discontinued or otherwise be unavailable to us. 
+We believe it to be in our best interests to meaningfully participate in large testing programs. Moreover many of these programs are funded by governments and other donors, and there can be no assurance that funding will not be reduced or completely discontinued. Participation in these programs also requires alignment and engagement with the many other participants in these programs, including WHO, CDC, the U.S. Agency for International Development, foreign governments and their agencies, non‑governmental organizations, and HIV service organizations. If we are unsuccessful in our efforts to participate in these programs, our operating results could be materially harmed. 
+In December 2013 President Obama signed into law the PEPFAR Stewardship and Oversight Act, which is the most recent reauthorization of PEPFAR. However, unlike the 2008 PEPFAR authorization, which authorized approximately $45 billion in funding, the new law did not authorize a specific dollar amount for funding. 
+Developing testing guidelines could negatively affect sales of our products. 
+Government agencies may issue diagnostic testing guidelines or recommendations, which can alter the usage of our HIV testing products. New laws or guidelines, or changes to existing laws or guidelines, and the manner in which these new or changed laws and guidelines are interpreted and applied, could impact the degree to which our testing products are used. These developments could affect the frequency of testing, the number of people tested and whether the testing products are used broadly for screening large populations or in a more limited capacity. These factors could in turn affect the level of sales of our products and our results of operations. 
+Some of our programs are partially supported by government grant awards, which may not be available to us in the future. 
+We have received funding under grant award programs funded by governmental agencies such as NIDA and BARDA. To fund a portion of our future research and development programs, we may apply for additional grant funding from these or similar governmental agencies. However, funding by these governmental agencies may be significantly reduced or eliminated in the future for a number of reasons. For example, some programs are subject to a yearly appropriations process in Congress. In addition, we may not receive full funding under current or future grants because of budgeting constraints of the agency administering the program or unsatisfactory progress on the study being funded. Therefore, we cannot assure you that we will receive any future grant funding from any government agencies, or, that if received, we will receive the full amount of the particular grant award. Any such reductions could delay the development of our product candidates and the introduction of new products. 
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+We could be exposed to liability if we experience security breaches or other disruptions, which could harm our reputation and business . 
+We may be subject to cyber‑attacks whereby computer hackers may attempt to access our computer systems or our third party IT service provider’s systems and, if successful, misappropriate personal or confidential information, particularly if we gain recognition in our industry. In addition, a contractor or other third party with whom we do business may attempt to circumvent our security measures or obtain such information, and may purposefully or inadvertently cause a breach involving sensitive information. We will continue to evaluate and implement additional protective measures to reduce the risk and detect cyber incidents, but cyber‑attacks are becoming more sophisticated and frequent and the techniques used in such attacks change rapidly. Even though we take cyber‑security measures that are continuously reviewed and updated, our information technology networks and infrastructure may still be vulnerable due to sophisticated attacks by hackers or breaches. 
+Even the most well protected IT networks, systems, and facilities remain potentially vulnerable because the techniques used in security breaches are continually evolving and generally are not recognized until launched against a target and, in fact, may not be detected. Any such compromise of our or our third party’s IT service providers’ data security and access, public disclosure, or loss of personal or confidential business information, could result in legal claims proceedings, liability under laws to protect, privacy of personal information, and regulatory penalties, disrupt our operations, require significant management attention and resources to remedy any damages that result, damage our reputation and customers willingness to transact business with us, any of which could adversely affect our business. 
+Our ability to efficiently operate our business is reliant on information technology, and any material failure, inadequacy, interruption or security breach of that technology could harm our business. 
+We rely heavily on complex information technology systems across our operations and on the internet, including for management of inventory, invoices, purchase orders, shipping, interactions with our third‑party logistics provider, revenue and expense accounting, consumer call support, online business, and various other processes and transactions. Our ability to effectively manage our business, coordinate the production, distribution and sale of our products, respond to customer inquiries, and ensure the timely and accurate recording and disclosure of financial information depends significantly on the reliability and capacity of these systems and the internet. 
+If any of the foregoing systems fails to operate effectively, problems with transitioning to upgraded or replacement systems, or disruptions in the operation of the internet, could cause delays in product sales and reduced efficiency of our operations. Significant expenditures could be required to fix any such problem. 
+If there is an increase in demand for our products, it could require us to expend considerable resources or harm our customer relationships if we are unable to meet that demand. 
+If there are significant or unexpected increases in the demand for our products, we may not be able to meet that demand without expending additional capital resources. This would increase our capital costs, which could negatively affect our earnings in the short term. In addition, new manufacturing equipment or facilities may require FDA, WHO, and other regulatory approvals before they can be used to manufacture our products. To the extent we are unable to obtain or are delayed in obtaining such approvals, our ability to meet the demand for our products could be adversely affected. Furthermore, our suppliers may be unable or unwilling to expend the necessary capital resources or otherwise expand their capacity, which could negatively affect our business. 
+Our business could be negatively affected if we or our suppliers are unable to develop necessary manufacturing capabilities in a timely manner. If we fail to increase production volumes in a cost effective manner or if we experience lower than anticipated yields or production problems as a result of changes that we or our suppliers make in our manufacturing processes to meet increased demand, we could experience shipment delays or interruptions and increased manufacturing costs, which could also have a material adverse effect on our revenues and profitability. 
+If there are unexpected increases in demand for our products, we may be required to obtain additional raw materials in order to manufacture products to meet the increase in demand. However, some raw materials require significant ordering lead time and some are currently obtained from a sole supplier or a limited group of suppliers. It is also possible that one or more of our suppliers may become unwilling or unable to deliver materials to us. Any shortfall in our supply of raw materials and components, or our inability to quickly and cost‑effectively obtain alternative sources for this supply, could have a material adverse effect on our ability to meet increased demand for our products. This could negatively affect our total revenues or cost of sales and related profits. 
+If we are unable to meet customer demand for our products, it could also harm our relationships with our customers and impair our reputation within the industry. This, in turn, could have a material adverse effect on our business. 
+Our management and larger stockholders exercise significant control over us. 
+As of December 31, 2020, 2% of our outstanding common stock was beneficially owned by our executive officers, directors and 5% stockholders including three large investors that beneficially own 18%, of our outstanding common stock. For the foreseeable future, and assuming these ownership percentages continue to apply, to the extent that these parties vote similarly, they may be able to exercise significant control over many matters requiring approval by the board of directors or our stockholders. As a result, they may be able to: 
+● 
+control the composition of our board of directors; 
+● 
+control our management and policies; 
+● 
+determine the outcome of significant corporate transactions, including changes in control that may be beneficial to stockholders; and, 
+● 
+act in each of their own interests, which may conflict with or differ from the interests of each other or the interests of the other stockholders. 
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+Risks Related to Our Products 
+Our COVID-19 Diagnostic Test Systems may not gain wide industry acceptance, and industry adoption of alternative technology could negatively impact our ability to compete successfully. 
+Of the 171 manufacturers and commercial laboratories to receive an EUA for COVID‑19 diagnostics as of July 31, 2020, 35 were for serology tests, 134 were for molecular tests, and 2 were for antigen tests. Customers or the industry as a whole could adopt alternative technologies for testing, including molecular point‑of‑care testing, which could result in lower demand for our antigen test. Various advances in the treatment and monitoring of patients could cause lower demand for the COVID-19 Diagnostic Test Systems, including our revised DPP SARS‑CoV‑2 Antigen System or for antigen testing for COVID‑19 as a whole. 
+COVID‑19 is prone to genetic mutations which may impact the ability of the COVID-19 Diagnostic Test Systems to adequately detect COVID‑19 or SARS-CoV-2 antigens and could adversely affect demand for the COVID-19 Diagnostic Test Systems and harm our competitive position. 
+False test results are a risk with all laboratory tests, including COVID‑19 diagnostic tests. False results can occur in the presence or absence of a mutation in the COVID‑19 virus. In the presence of a mutation in the virus, false results can occur if a mutation occurs in the region of the virus that the test is designed to assess. False results may occur with the COVID-19 Diagnostic Test Systems in the presence or absence of one or more COVID‑19 mutations. If false negatives occur with the COVID-19 Diagnostic Test Systems , it will may reduce customer confidence in the accuracy of the COVID-19 Diagnostic Test Systems and harm our competitive position. 
+For our business to succeed in the future, our current and future products must receive market acceptance. 
+Market acceptance and the timing of such acceptance, of our new products or technologies is necessary for our future success. To achieve market acceptance, we and our distributors will likely be required to undertake substantial efforts and spend significant funds to inform every one of the existence and perceived benefits of our products. We also may require government funding for the purchase of our products to help create market acceptance and expand the use of our products. 
+It may be difficult evaluate the market reaction to our products and our marketing efforts for new products may not be successful. The government funding we receive may be limited for new products. As such, there can be no assurance that any products will obtain significant market acceptance and fill the market need that is perceived to exist on a timely basis, or at all. 
+We may not have sufficient resources to effectively introduce and market our products, which could materially harm our operating results. 
+Introducing and achieving market acceptance for our new products will require substantial marketing efforts and will require us and/or our contract partners, sales agents, and/or distributors to make significant expenditures of time and money. In some instances we will be significantly or totally reliant on the marketing efforts and expenditures of our contract partners, sales agents, and distributors. If they do not have or commit the expertise and resources to effectively market the products that we manufacture, our operating results will be materially harmed. 
+New developments in health treatments and non‑diagnostic products may reduce or eliminate the demand for our products. 
+The development and commercialization of products outside of the diagnostics industry could adversely affect sales of our products. For example, the development of a safe and effective vaccine to HIV or treatments for other diseases or conditions that our products are designed to detect, could reduce or eventually eliminate the demand for our HIV or other diagnostic products and result in a loss of revenues. 
+Our future success will depend on our ability to increase manufacturing production capacity through the implementation of additional customized manufacturing automation equipment. 
+One of our key challenges will be to increase our production capacity to meet sales demand while maintaining product quality and reducing production costs. Our primary strategy to accomplish this consists of the implementation of additional customized automation equipment. The equipment we order may not be delivered in a timely manner, and, once delivered, the equipment may require significant time and effort in order to operate in the manner required to produce high quality products. We experienced significant unexpected delays before our current automation equipment operated in the manner for which it was designed. The investments we make in this equipment may not yield the anticipated labor and material efficiencies. Our business, financial condition and results of operations could be harmed if we are unable to timely obtain automation equipment that meets our requirements or if there are significant increases in the costs of equipment. 
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+Sales cycles for our products can be lengthy, which can cause variability and unpredictability in our business. 
+Some of our products may require lengthy and unpredictable sales cycles, which makes it more difficult to accurately forecast revenues in a given period and may cause revenues and operating results to vary from period to period. Our products may involve sales to large public and private institutions which may require many levels of approval and may be dependent on economic or political conditions and the availability of grants or funding from government or public health agencies which can vary from period to period. There can be no assurance that purchases or funding from these agencies will occur or continue, especially if current negative economic conditions continue or intensify. As a result, we may expend considerable resources on unsuccessful sales efforts or we may not be able to complete transactions at all or on a schedule and in an amount consistent with our objectives. 
+We may face product liability claims for injuries. 
+The testing, manufacturing and marketing of medical diagnostic products involves an inherent risk of product liability claims. If we cannot successfully defend ourselves against product liability claims, we may incur substantial liabilities or be required to limit or cease sales of our products. We cannot be sure that we will not incur liabilities in excess of the policy limits of our existing product liability insurance coverage or that we will be able to continue to obtain adequate product liability insurance coverage in the future at an acceptable cost, or at all. In addition, a defect in the design or manufacture of our products could have a material adverse effect on our reputation in the industry and subject us to claims of liability for injury and otherwise. Any substantial underinsured loss resulting from such a claim could have a material adverse effect on our profitability, and the damage to our reputation in the industry could have a material adverse effect on our business. 
+Our customers may not adopt rapid point‑of‑care diagnostic testing. 
+Rapid point‑of‑care tests are beneficial because, among other things, they can be administered by healthcare providers in their own facilities or used by consumers at home without sending samples to central laboratories. But currently the majority of diagnostic tests used by physicians and other healthcare providers in the U.S. are provided by clinical reference laboratories and hospital‑based laboratories. In some international markets, such as Europe, diagnostic testing is performed primarily by centralized laboratories. Future sales of our products will depend, in part, on our ability to expand market acceptance of rapid point‑of‑care testing and successfully compete against laboratory testing methods and products. However, we expect that clinical reference and other hospital‑based laboratories will continue to compete vigorously against our rapid point‑of‑care products. Even if we can demonstrate that our products are more cost effective, save time, or have better performance or other benefits, physicians, other healthcare providers and consumers may resist changing to rapid point‑of‑care tests and instead may choose to obtain diagnostic results through laboratory tests. If we fail to achieve and expand market acceptance of our rapid point‑of‑care diagnostic tests with customers, it would have a negative effect on our future sales growth. 
+Customer concentration creates risks for our business. 
+A significant portion of our revenues each year comes from a few large customers. To the extent that such a large customer fails to meet its purchase commitments, changes its ordering patterns or business strategy, or otherwise reduces its purchases or stops purchasing our products, or if we experience difficulty in meeting the demand by these customers for our products, our revenues and results of operations could be adversely affected. 
+If our products do not perform properly, it may affect our revenues, stock price and reputation. 
+Our products may not perform as expected. For example, a defect in one of our diagnostic products or a failure by a customer to follow proper testing procedures may cause the product to report inaccurate information. Identifying the root cause of a product performance or quality issue can be difficult and time consuming. 
+If our products do not to perform in accordance with the applicable label claims or otherwise in accordance with the expectations or needs of our customers, customers may switch to a competing product or otherwise stop using our products, and our revenues could be negatively affected. If this occurs, we may be required to implement holds or product recalls and incur warranty obligations. Furthermore, the poor performance by one or more of our products could have an adverse effect on our reputation, our continuing ability to sell products and the price of our Common Stock. 
+Financial, Economic and Financing Risks 
+We have incurred losses in recent years and we are uncertain about our future profitability. 
+We incurred an operating loss every year from 2014 through 2020. Under our operating plans, we have made, and plan to continue to make, significant investments in our production capacity, including in expanding facilities and automating manufacturing, and in our sales and marketing, regulatory approval, and research and development activities. Our ability to achieve profitability and generate cash flow in the future will depend on our ability to increase sales of our existing products and to successfully introduce new and enhanced products into the marketplace, all while controlling and managing our expenses consistent with our operating plan. 
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+If we are unable to increase our revenues and manage our expenses in accordance with our operating plan, our operating results would be harmed and we may not be able to generate the cash flow needed to fund the investments in our production capacity and other activities, we will be required to implement one or both of the following: 
+● 
+We could reduce the level, or otherwise delay the timing, of the anticipated investments in our production capacity and other activities, which would likely curtail or delay the growth in our business contemplated by our operating plan and could impair or defer our ability to achieve profitability and generate cash flow. 
+● 
+We could raise additional funds through public or private financings, strategic relationships, or other arrangements, to the extent funding would be available to us on acceptable terms or at all. If we succeed in raising additional funds through the issuance of equity or convertible securities, then the issuance could result in substantial dilution to existing stockholders. Furthermore, the holders of these new securities or debt may have rights, preferences and privileges senior to those of the holders of our Common Stock. 
+In such circumstances, we also would need to forego acquisition opportunities, which could impede our ability to grow our business. 
+Our financial results may fluctuate. 
+From quarter to quarter and year to year, our operating results can fluctuate, which could cause our growth or financial performance to fail to meet the expectations of investors and securities analysts. Sales to our distributors and other customers may not meet expectations because of lower than expected customer demand or other factors, including continued economic volatility and disruption, reduced governmental funding, and other circumstances described elsewhere in this report. A variety of factors could also contribute to the variability of our financial results, including infrequent, unusual or unexpected changes in revenues or costs. 
+Different products provide dissimilar contributions to our gross product margin. Accordingly, our operating results could also fluctuate and be negatively affected by the mix of products sold and the relative prices and gross product margin contribution of those products. Failure to achieve operating results consistent with the expectations of investors and securities analysts could adversely affect our reputation and the price of our Common Stock. 
+The failure to comply with the terms of our Credit Agreement and Guaranty could result in a default under its terms and, if uncured, could result in action against our pledged assets and dilution of our stockholders. 
+On September 3, 2019, we entered into a Credit Agreement and Guaranty, or Credit Agreement, with Perceptive Credit Holdings II, LP, or Perceptive. Under the Credit Agreement, we received a $20,000,000 senior secured term loan credit facility, which was drawn in full on September 4, 2019. The credit agreement is secured by a first priority, perfected lien on substantially all of our property and assets, including our equity interests in our subsidiaries. 
+The Credit Agreement contains covenants that restrict our ability to finance future operations or capital needs or to engage in other business activities. The Credit Agreement restricts our ability and the ability of our restricted subsidiaries to: 
+● 
+incur, assume or guarantee additional Indebtedness (as defined in the Credit Agreement); 
+● 
+repurchase capital stock; 
+● 
+make other restricted payments including, without limitation, paying dividends and making investments; 
+● 
+create liens; 
+● 
+sell or otherwise dispose of assets, including capital stock of subsidiaries; 
+● 
+enter into agreements that restrict dividends from subsidiaries; 
+● 
+enter into mergers or consolidations; and 
+● 
+enter into transactions with affiliates 
+In addition, the Credit Agreement also contain covenants requiring us and our subsidiaries to maintain cash and cash equivalents held in one or more accounts subject to the first priority perfected security interests of the lenders under the Credit Agreement of not less than $3,000,000. The Credit Agreement also provides for specified quarterly minimum consolidated net revenue covenants of us and our subsidiaries for the trailing twelve‑month period ended on each such calculation date during the term of the Credit Agreement. A breach of any of these covenants would result in a default under the Credit Agreement. If an event of default under our Credit Agreements occurs, Perceptive could elect to declare all amounts outstanding thereunder, together with accrued interest, to be immediately due and payable. If we were unable to pay such amounts, Perceptive could proceed against the collateral pledged to them. We have pledged our inventory, accounts receivable, cash, securities, other general intangibles and the capital stock of certain subsidiaries to the lenders. In such an event, we cannot assure you that we would have sufficient assets to pay amounts due under the Credit Agreement. 
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+Servicing our debt will require a significant amount of cash. Our ability to generate sufficient cash to service our debt depends on many factors beyond our control. 
+Our ability to make payments on and to refinance our debt, to fund planned capital expenditures, and to maintain sufficient working capital depends on our ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. We cannot assure you that our business will generate sufficient cash flow from operations or from other sources in an amount sufficient to enable us to service our debt or to fund our other liquidity needs. In the year ended December 31, 2020, our operations used $18.9 million in cash. If our cash flow and capital resources are insufficient to allow us to make scheduled payments on our debt, we may need seek additional capital or restructure or refinance all or a portion of our debt on or before the maturity thereof, any of which could have a material adverse effect on our business, financial condition or results of operations. We cannot assure you that, if needed, we would be able to refinance any of our debt on commercially reasonable terms or at all, or that the terms of that debt will allow any of the above alternative measures or that these measures would satisfy our scheduled debt service obligations. If we are unable to generate sufficient cash flow to repay or refinance our debt on favorable terms, it could significantly adversely affect our financial condition. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. There can be no assurance that we will be able to obtain any financing when needed. 
+The LIBOR calculation method may change, and LIBOR is expected to be phased out after 2021, which may adversely affect our interest expenses under the Credit Agreement and Guaranty. 
+Loans under the Credit Agreement and Guaranty bear interest at a rate per annum equal to the sum of (a) the greater of the one‑month London Interbank Offered Rate, or LIBOR, and 2.5% plus (b) 8.75%. At any time at which an event of default has occurred and is continuing, the interest rate will increase by 4.0%. Accrued interest is payable on a monthly basis. On July 27, 2017, the U.K. Financial Conduct Authority announced that it will no longer require banks to submit rates for the calculation of LIBOR after 2021. On November 30, 2020, ICE Benchmark Administration, or IBA, the administrator of LIBOR, with the support of the United States Federal Reserve and the United Kingdom’s Financial Conduct Authority, announced plans to consult on ceasing publication of USD LIBOR on December 31, 2021 for only the one week and two month USD LIBOR tenors, and on June 30, 2023 for all other USD LIBOR tenors. While this announcement extends the transition period to June 2023, the United States Federal Reserve concurrently issued a statement advising banks to stop new USD LIBOR issuances by the end of 2021. In light of these recent announcements, the future of LIBOR at this time is uncertain and any changes in the methods by which LIBOR is determined or regulatory activity related to LIBOR’s phaseout could cause LIBOR to perform differently than in the past or cease to exist. 
+At this time, no consensus exists as to what rate or rates will become accepted alternatives to LIBOR, although The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, is considering replacing U.S. dollar LIBOR with the Secured Overnight Financing Rate, or SOFR, a newly created index, calculated with a broad set of short‑term repurchase agreements backed by treasury securities. It is not possible to predict the effect of these changes, other reforms or the establishment of alternative reference rates in the United States or elsewhere. 
+Pursuant to the Credit Agreement and Guaranty, if LIBOR becomes unavailable in the future, the Administrative Agent and Borrower (as such terms are defined in the Credit Agreement and Guaranty) may select an alternative benchmark rate, which may include SOFR. To the extent our interest rates increase as a result, our interest expense will increase, in which event we may have difficulties making interest payments and funding our other fixed costs, and our available cash flow for general corporate requirements may be adversely affected. 
+Our operating results may be negatively affected by changes in foreign currency exchange rates. 
+In the past our exposure to foreign currency exchange rate risk has not been material. Nevertheless, sales of our products are subject to currency risks, since changes in the values of foreign currencies relative to the value of the U.S. dollar can render our products comparatively more expensive. The fluctuations in the exchange rate could negatively impact international sales of our products, as could changes in the general economic conditions. 
+The revenues and expenses of Chembio Diagnostics Malaysia, opTricon and Orangelife, one of our subsidiaries, are recorded in Malaysian Ringgit, in Euros and Brazilian Real, respectively. Revenues and expenses denominated in foreign currencies are translated into U.S. dollars for purposes of reporting our consolidated financial results. Our expectation is that the Chembio Diagnostics Malaysia, opTricon and Orangelife businesses will continue to grow and, consequently, our exposure to foreign currency exchange rates may grow as well. 
+Our foreign subsidiaries’ revenues and expenses and the translation of their financial results into U.S. dollars may be negatively affected by fluctuations in the exchange rate. Favorable movement in exchange rates have benefited us in prior periods. However, where there are unfavorable currency exchange rate fluctuations, our consolidated financial statements could be negatively affected. Furthermore, fluctuations in exchange rates could affect year‑to‑year comparability of operating results. In the past, we have not generally entered into hedging instruments to manage our currency exchange rate risk, but we may need to do so in the future. However, our attempts to hedge against these risks may not be successful. If we are unable to successfully hedge against unfavorable foreign currency exchange rate movements, our consolidated financial results may be adversely impacted. 
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+We operate in countries where there is or may be widespread corruption. 
+We have a policy in place prohibiting our employees, distributors and agents from engaging in corrupt business practices, including activities prohibited by the U.S. Foreign Corrupt Practices Act. Nevertheless, because we work through independent sales agents and distributors outside the United States, we do not have control over the day‑to‑day activities of such independent agents and distributors. In addition, in the donor‑funded markets in Africa where we sell our products, there is significant oversight from PEPFAR, the Global Fund, and advisory committees comprised of technical experts concerning the development and establishment of national testing protocols. This is a process that includes an overall assessment of a product which includes extensive product performance evaluations including five active collaborations and manufacturer’s quality systems, as well as price and delivery. In Brazil, where we operate our subsidiary Orangelife and have had numerous product collaborations with FIOCRUZ, the programs through which our products may be deployed are all funded by the Brazilian Ministry of Health. Although FIOCRUZ is affiliated with the Brazilian Ministry of Health, and is its sole customer, FIOCRUZ is not the exclusive supplier for the Ministry of Health. However, because each of our previous collaborations with FIOCRUZ incorporates a technology transfer aspect, we believe we have a competitive advantage versus other suppliers to the Brazilian Ministry of Health, assuming other aspects of our product offering through FIOCRUZ are otherwise competitive in comparison. We have no knowledge or reason to know of any activities by our employees, distributors or sales agents of any actions which could be in violation of the FCPA, although there can be no assurance of this. 
+Our subsidiary Chembio Diagnostics Malaysia Sdn. Bhd. is located in Malaysia. There have been numerous high‑profile corruption cases, and corruption is one of the most problematic factors for doing business in Malaysia. While the Malaysian government has acknowledged the problem, it appears that endemic corruption is continuing and that market‑based principles are not applied in cases involving individuals with high‑level political access. To the extent bribery and similar practices continue to exist in Malaysia, U.S. companies such as ours, which are subject to U.S. laws making it illegal to pay bribes to foreign officials, may make us less competitive in winning business in Malaysia when competing with non‑U.S. companies. 
+Changes in interpretation or application of U.S. Generally Accepted Accounting Principles may adversely affect our operating results. 
+We prepare our financial statements to conform to U.S. generally accepted accounting principles. These principles are subject to interpretation by the Financial Accounting Standards Board, the American Institute of Certified Public Accountants, the Public Company Accounting Oversight Board, the Securities and Exchange Commission and various other regulatory or accounting bodies. A change in interpretations of, or our application of, these principles can have a significant effect on our reported results and may even affect our reporting of transactions completed before a change is announced. Additionally, as we are required to adopt new accounting standards, our methods of accounting for certain items may change, which could cause our results of operations to fluctuate from period to period. For example, upon adoption of Accounting Standards Codification (“ASC”) 606 Revenue from Contracts with Customers of the Financial Accounting Standards Board (“FASB”), we now recognize revenue upon transfer of control, which is generally at time of delivery. Under the previous accounting guidance, we recognized revenue upon acceptance when and if we had production responsibilities. If circumstances change over time or interpretation of the revenue recognition rules change, we could be required to adjust the timing of recognizing revenue and our financial results could suffer. 
+We base our estimates or judgments relating to critical accounting policies on assumptions that can change or prove to be incorrect. 
+Our financial statements have been prepared in accordance with accounting principles generally accepted in the United States and our discussion and analysis of financial condition and results of operations is based on such statements. The preparation of financial statements requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. We continuously evaluate significant estimates used in preparing our financial statements, including those related to (i) revenue recognition, including uncertainties related to variable consideration and milestones; (ii) stock‑based compensation; (iii) allowance for uncollectible accounts receivable; (iv) inventory reserves and obsolescence; (v) customer sales returns and allowances; (vi) contingencies; and (vii) income taxes, (viii) goodwill and intangibles, (ix) business acquisition, and (x) research and development costs. 
+For example, for the quarter ended June 30, 2020, our cost of product sales included the cost of COVID‑19 systems that were produced and shipped outside the U.S., but for which revenue was not recognized in the quarter. We decided we were unable to recognize the revenue from those shipments in the second quarter due to the GAAP requirement that we have a high degree of confidence that it is probable that a significant reversal in revenue will not occur in the future. Many factors can affect such a decision, including, for example, actions of third parties and other considerations that are outside our influence or control. As a result, we recognized negative gross margin in the quarter. 
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+Our estimates are based on historical experience and various other assumptions that we believe to be reasonable, as set forth in our discussion and analysis of financial condition and results of operations, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these and other estimates if our assumptions change or if actual circumstances differ from those in our assumptions. If our operating results fall below the expectations of securities analysts and investors, the price of our Common Stock may decline. 
+Risks Related to Intellectual Property 
+Our success depends on our ability to protect our proprietary technology. We rely on trade secret laws and agreements with our key employees and other third parties to protect our proprietary rights, and we cannot be sure that these laws or agreements will adequately protect our rights. 
+Our industry places considerable importance on obtaining patent, trademark and trade secret protection, as well as other intellectual property rights, for new technologies, products and processes. Our success depends, in part, on our ability to develop and maintain a strong intellectual property portfolio or obtain licenses to patents and technologies, both in the United States and in other countries. If we cannot continue to develop, obtain and protect intellectual property rights, our revenues and gross profits could be adversely affected. Moreover, our current and future licenses or other rights to patents and other technologies may not be adequate for the operation of our business. 
+As appropriate, we intend to file patent applications and obtain patent protection for our proprietary technology. These patent applications and patents will cover, as applicable, compositions of matter for our products, methods of making those products, methods of using those products and apparatuses relating to the use or manufacture of those products. However, there have been changes to the patent laws and proposed changes to the rules of the U.S. Patent and Trademark Office, which may impact our ability to protect our technology and enforce our intellectual property rights. For example, in 2011, the U.S. enacted sweeping changes to the U.S. patent system under the Leahy‑Smith America Invents Act, including changes that would transition the U.S. from a “first‑to‑invent” system to a “first‑to‑file” system and alter the processes for challenging issued patents. These changes could increase the uncertainties and costs surrounding the prosecution of our patent applications and the enforcement or defense of our issued patents. 
+We believe that factors such as the technological and creative skills of our personnel, strategic relationships, new product developments, frequent product enhancements and name recognition are essential to our success. All our management personnel are bound by non‑disclosure agreements. If personnel leave our employment, in some cases we would be required to protect our intellectual property rights pursuant to common law theories which may be less protective than provisions of employment, non‑competition or non‑disclosure agreements. 
+We seek to protect our proprietary products under trade secret and copyright laws, enter into license agreements for various materials and methods employed in our products, and enter into strategic relationships for distribution of the products. These strategies afford only limited protection. We currently have some foreign patents issued, and we are seeking additional patent protection in several other foreign jurisdictions for our DPP and optical technology. We have licenses to reagents (antigens and peptides) used in several of our products and products under development. Despite our efforts to protect our proprietary assets, and respect the intellectual property rights of others, we participate in several markets where intellectual property rights protections are of little or no value. This can place our products and our company at a competitive disadvantage. 
+Moreover, issued patents remain in effect for a fixed period and after expiration will not provide protection of the inventions they cover. Once our patents expire, we may be faced with increased competition, which could reduce our revenues. We may also not be able to successfully protect our rights to unpatented trade secrets and know‑how. 
+To facilitate development and commercialization of a proprietary technology base, we may need to obtain additional licenses to patents or other proprietary rights from other parties. Obtaining and maintaining these licenses, which may not be available, may require the payment of up‑front fees and royalties. In addition, if we are unable to obtain these types of licenses, our product development and commercialization efforts may be delayed or precluded. 
+Any future intellectual property disputes could require significant resource and limit or eliminate our ability to sell products or use certain technologies. 
+We may be required to expend substantial resources in asserting or protecting our intellectual property rights, or in defending suits related to intellectual property rights. We may seek to enforce our patents or other intellectual property rights through litigation. Such litigation is prevalent and is expected to continue. In our business, there are a large number of patents and patent applications similar to our products, and additional patents may be issued to third parties relating to our product areas. We, our customers or our suppliers may be sued for infringement of patents or misappropriation of other intellectual property rights with respect to one or more of our products. We may also have disputes with parties that license patents to us if we believe the license is no longer needed for our products or the licensed patents are no longer valid or enforceable. 
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+There are a large number of patents in our industry, and the claims of these patents appear to overlap in many cases. Therefore there is a significant amount of uncertainty regarding the extent of patent protection and infringement. Companies may have pending patent applications, which are typically confidential for the first eighteen months following filing that cover technologies we incorporate in our products. Accordingly, we may be subjected to substantial damages for past infringement or be required to modify our products or stop selling them if it is ultimately determined that our products infringe a third party’s proprietary rights. In addition, governmental agencies could commence investigations or criminal proceedings against our employees or us relating to claims of misuse or misappropriation of another party’s proprietary rights. 
+If we are involved in litigation or other legal proceedings with respect to patents or other intellectual property and proprietary technology, it could adversely affect our revenues, results of operations, market share and business because (1) it could consume a substantial portion of managerial and financial resources; (2) its outcome would be uncertain and a court may find that our patents are invalid or unenforceable in response to claims by another party or that the third‑party patent claims are valid and infringed by our products; (3) the pendency of any litigation may in and of itself cause our distributors and customers to reduce or terminate purchases of our products; (4) a court could award a preliminary and/or permanent injunction, which would prevent us from selling our current or future products; and (5) an adverse outcome could subject us to the loss of the protection of our patents or to liability in the form of past royalty payments, penalties, reimbursement of litigation costs and legal fees, special and punitive damages, or future royalty payments, any of which could significantly affect our future earnings. 
+Under certain contracts with third parties, we may indemnify the other party if our products or activities have actually or allegedly infringed upon, misappropriated or misused another party’s proprietary rights. Furthermore, our products may contain technology provided to us by third parties, and we may be unable to determine in advance whether such technology infringes the intellectual property rights of a third party. These other parties may also not be required or financially able to indemnify us in the event that an infringement or misappropriation claim is asserted against us. 
+There may also be other types of disputes that we become involved in regarding intellectual property rights, including state, federal or foreign court litigation, and patent interference, patent reissue, patent reexamination, or trademark opposition proceedings in the United States Patent and Trademark Office. Opposition or revocation proceedings could be instituted in a foreign patent office as well. These proceedings permit certain persons to challenge the validity of a patent on the grounds that it was known from the prior art. The filing of such proceedings, or the issuance of an adverse decision in such proceedings, could result in the loss of valuable patent rights that could have a material adverse effect on our business, financial condition, results of operations and growth prospects. 
+Risks Related to Our Third Party Collaborators 
+Our use of third‑party suppliers, some of which may constitute our sole supply source, for certain important product components and materials presents risks that could have negative consequences for our business. 
+We purchase certain HIV antigens, a syphilis antigen, COVID‑19 antigens, the nitrocellulose, and certain other critical components used in our STAT‑PAK, STAT‑VIEW, SURE CHECK and DPP product lines from a sole or limited number of sources. If for any reason these suppliers become unwilling or unable to supply our antigen, nitrocellulose, or other critical component needs, we believe that alternative supplies could be obtained at a competitive cost. However, a change in any of the antigens, nitrocellulose or other critical components used in our products would require additional development work and approval by the FDA and other regulatory agencies. In addition, it may be difficult to find such an alternate supply source in a reasonable time period or on commercially reasonable terms, if at all. As a result, the termination or limitation of our relationship with one or more of these suppliers could require significant time to complete, increase our costs, and disrupt or discontinue our ability to manufacture and sell the affected products. In addition, governmental purchasers or funding programs in a particular country may require that we purchase key components from suppliers in that country, which could significantly limit our ability to obtain the components with the quality, and at the price, we seek. 
+With some of these suppliers, we do not have long‑term agreements and instead purchase components and materials through a purchase order process. As a result, these suppliers may stop supplying us components and materials, limit the allocation of supply and equipment to us due to increased industry demand, or significantly increase their prices at any time with little or no advance notice. Our reliance on a limited number of suppliers could also result in delivery problems, reduced control over product pricing and quality, and our inability to identify and qualify another supplier in a timely manner. 
+Moreover, some of these suppliers may experience financial difficulties that could prevent them from supplying us with components or subassemblies used in the design and manufacture of our products. In addition, these suppliers may experience manufacturing delays or shut downs due to circumstances beyond their control, such as complications related to COVID‑19, labor issues, political unrest or natural disasters. 
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+Any supply chain deficiencies could materially and adversely affect our ability to fulfill customer orders and our results of operations. The availability of critical components and materials from sole‑ or limited source suppliers could reduce our control over pricing, quality and timely delivery, increase our costs, could disrupt our ability to manufacture and sell, and preclude us from manufacturing and selling, certain of our products into one or more markets. Any such event could have a material adverse effect on our results of operations, cash flow and business. 
+We may work with strategic collaborators to assist in developing and commercializing our products, which could limit rights we receive from the collaborations and exposes us to other risks outside our control. 
+Some business opportunities that require a technology controlled by a third party, a significant level of investment for development and commercialization or a distribution network beyond our existing sales force may necessitate involving one or more strategic collaborators. As part of our strategy for development and commercialization of our products, we may enter into arrangements with distributors or other third‑parties. Relying on such collaborative relationships could be risky to our business for a number of reasons, including: (i) we may be required to transfer material rights to such strategic collaborators, licensees and others; (ii) our collaborators may not obtain regulatory approvals necessary to continue the collaborations in a timely manner; (iii) our collaborators may decide to terminate our collaborative arrangement or become insolvent; (iv) our collaborators may develop technologies or components competitive with our products; (v) disagreements with collaborators could result in the termination of the relationship or litigation; and (vi) we may not be able to agree to future collaborative arrangements, or renewals of existing collaborative agreements, on acceptable terms or at all. 
+We expect our collaborators will have an economic motivation to succeed in performing their contractual responsibilities under our agreements, there is no assurance that they will do so. Due to our reliance on strategic agreements, it can make it difficult to accurately forecast our future revenues and operating results. 
+Our ability to grow our business will be limited if we fail to maintain existing distribution channels or develop new distribution channels. 
+We collaborate with laboratories, diagnostic companies and distributors in order to sell our products. The sale of our products depends in large part on our ability to sell products to these customers and on the marketing and distribution abilities of the companies with which we collaborate and work with. 
+By relying on distributors or third‑parties to market and sell our products could negatively impact our business for various reasons, including: (i) we may not be able to find suitable distributors for our products on satisfactory terms, or at all; (ii) agreements with distributors may prematurely terminate or may result in litigation between the parties; (iii) our distributors or other customers may not fulfill their contractual obligations and distribute our products in the manner or at the levels we expect; (iv) our distributors may prioritize their own private label products that compete with our products; (v) Our existing distributor relationships or contracts may preclude or limit us from entering into arrangements with other distributors; and (vi) we may not be able to negotiate new or renew existing distribution agreements on acceptable terms, or at all. 
+We will try to maintain and expand our business with distributors and customers and make every effort to require that they fulfill their contractual obligations, but there can be no assurance that such companies will do so or that new distribution channels will be available on satisfactory terms. If we are unable to do so, our business will be negatively impacted. 
+Our U.S. Government contracts require compliance with numerous laws and increases our risk and liability. 
+We are currently receiving funding from the U.S. government related to DPP Zika, and our growth strategy targets sales to U.S. government entities. As a result of our U.S. government funding and potential product sales to the U.S. government, we must comply with laws and regulations relating to the award, administration and performance of U.S. government contracts. U.S. government contracts typically contain a number of extraordinary provisions that would not typically be found in commercial contracts and which may create a disadvantage and additional risks to us as compared to competitors that do not rely on government contracts. As a U.S. government contractor, we are subject to increased risks of investigation, criminal prosecution and other legal actions and liabilities to which purely private sector companies are not. The results of any such actions could adversely impact our business and have an adverse effect on our consolidated financial performance. 
+A violation of specific laws and regulations could result in the imposition of fines and penalties or the termination of our contracts, as well as suspension or debarment. The suspension or debarment in any particular case may be limited to the facility, contract or subsidiary involved in the violation or could be applied to our entire enterprise in certain severe circumstances. Even a narrow scope suspension or debarment could result in negative publicity that could adversely affect our ability to renew contracts and to secure new contracts, both with the U.S. government and private customers, which could materially and adversely affect our business and results of operations. Fines and penalties could be imposed for failing to follow procurement integrity and bidding rules, employing improper billing practices or otherwise failing to follow rules relating to billing on cost‑plus contracts, receiving or paying kickbacks, or filing false claims, among other potential violations. In addition, we could suffer serious reputational harm and the value of our Common Stock could be negatively affected if allegations of impropriety related to such contracts are made against us. 
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+Our U.S. government contracts are subject to future funding and the government’s choice to exercise options, and may be terminated at the government’s convenience. 
+Our contracts with the U.S. government are subject to future funding and are subject to the right of the government to terminate the contracts in whole or in part for its convenience. There is pressure for the U.S. government to reduce spending. The non‑appropriation of funds or the termination for the government’s convenience of our contracts could negatively affect our financial results. If levels of U.S. government expenditures and authorizations for emerging diseases decrease or shift to programs in areas where we do not offer products or are not developing product candidates, or if the U.S. government otherwise declines to exercise its options under its contracts with us, our business, revenues and other operating results would suffer. 
+Risks Related to Regulations 
+COVID‑19 diagnostic tests, including the COVID-19 Diagnostic Test Systems , are subject to changes in CLIA, FDA, ANVISA and other regulatory requirements. 
+Our COVID-19 Diagnostic Test Systems are subject to regulations of the FDA, International Organization for Standards and other regulatory requirements, including ANVISA, Brazil’s health regulatory agency. The regulations regarding the manufacture and sale of COVID-19 Diagnostic Test Systems may be unclear and are subject to change. Newly promulgated regulations could require changes to COVID-19 Diagnostic Test Systems, necessitate additional procedures, or make it impractical or impossible for us to market COVID-19 Diagnostic Test Systems for certain uses, in certain markets, or at all. The FDA and other regulatory authorities also have the ability to impose new or additional requirements relating to the COVID-19 Diagnostic Test Systems. The implementation of such changes or new or additional requirements may result in a substantial additional costs and could delay or make it more difficult or complicated to sell our products. 
+On February 4, 2020, the U.S. Department of Health and Human Services issued a declaration that the threat to public health posed by COVID-19 justify the emergency use of unapproved in vitro diagnostics for the detection or diagnosis of SARS-CoV-2. Under Section 564 of the Food, Drug, and Cosmetic Act, because the U.S. Department of Health and Human Services has issued this declaration, the Commissioner of the U.S. Food and Drug Administration, or FDA, is authorized to issue EUAs to permit certain developers of SARS-CoV-2 diagnostics to begin offering the tests for detection and diagnosis of COVID-19 without having completed the normally applicable FDA review and clearance or approval process for marketing authorization. We received an EUA for the DPP COVID-19 IgM/IgG System on April 14, 2020, which was subsequent revoked by the FDA on June 16, 2020. Such revocation precludes the sale of DPP COVID‑19 IgM/IgG Systems in the United States unless and until a further regulatory approval or authorization is obtained. We have not received a subsequent EUA for any of the COVID-19 Diagnostic Test Systems, and we do not currently have an application pending for any such EUA. Moreover, market and regulatory requirements continue to change at a rapid pace. The FDA has announced, for example, that it intends to update its EUA templates with additional considerations related to the impact of genetic variants on test performance as the FDA learns more about the COVID-19 disease and its knowledge in this area progresses. The time required to obtain marketing authorizations and other approvals from regulatory authorities is unpredictable. The standards that the FDA and its foreign counterparts use when evaluating clinical trial data can change, and does often change, during development, which makes it difficult to predict with any certainty how they will be applied. If we make future submissions to the FDA, we may also encounter unexpected delays or increased costs due to new government regulations, including future legislation or administrative action, or changes in FDA policy during the period of FDA regulatory review. There can be no assurance that, if we are to make a submission of any future EUA application, we will be successful in obtaining an EUA that would permit us to offer and sell any COVID-19 Diagnostic Test System in the United States. 
+We are subject to governmental export controls that could impair our ability to compete in international markets. 
+The United States and various foreign governments have imposed controls, export license requirements and restrictions on the export of certain products and technologies. We must export our products in compliance with export controls in the United States, including the Commerce Department’s Export Administration Regulations and various economic and trade sanctions established by the Treasury Department’s Office of Foreign Assets Controls. We may not always be successful in obtaining necessary export licenses, and our failure to obtain required import or export approval for our products or limitations on our ability to export or sell our products imposed by these laws may harm our international and domestic sales and adversely affect our revenue. Noncompliance with these laws could have negative consequences, including government investigations, penalties and reputational harm. 
+If the United States government imposes restrictions on the export of COVID-19 Diagnostic Test Systems, or any of our other products, such restrictions could have a material impact on our ability to sell our products to existing or potential customers outside of the United States and harm our ability to compete internationally. Any change in export regulations or legislation, or change in the countries, persons or technologies targeted by export regulations, could decrease our ability to export or sell our products outside the United States or to existing or potential customers with international operations. Changes in our ability to sell our products outside the United States could negatively impact our business prospects and adversely affect our business and results of operations. 
+Because we may not be able to obtain or maintain the necessary regulatory approvals for some of our products, we may not generate revenues in the amounts we expect, or in the amounts necessary to continue our business. Our existing products as well as our manufacturing facility must meet quality standards and are subject to inspection by a number of domestic regulatory and other governmental and non‑governmental agencies. 
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+All of our proposed and existing products are subject to regulation in the U.S. by the U.S. Food and Drug Administration or FDA, the U.S. Department of Agriculture, and/or other domestic and international governmental, public health agencies, regulatory bodies or non‑governmental organizations. In particular, we are subject to strict governmental controls on the development, manufacture, labeling, distribution and marketing of our products. The process of obtaining required approvals or clearances varies according to the nature of, and uses for, a specific product. These processes can involve lengthy and detailed laboratory testing, human or animal clinical trials, sampling activities, and other costly, time‑consuming procedures. The submission of an application to a regulatory authority does not guarantee that the authority will grant an approval or clearance for that product. Each authority may impose its own requirements and can delay or refuse to grant approval or clearance, even though a product has been approved in another country. 
+The time taken to obtain approval or clearance varies depending on the nature of the application and may result in the passage of a significant period of time from the date of submission of the application. As an example, the time required to obtain an EUA from the FDA for COVID‑19 tests has lengthened markedly over the past months due to, among other things, application volume. Delays in the approval or clearance processes increase the risk that we will not succeed in introducing or selling the subject products, and we may determine to devote our resources to different products. 
+Changes or developments in government regulations, policies or interpretations could increase our costs and could require us to undergo additional trials or procedures, or could make it impractical or impossible for us to market our products for certain uses, in certain markets, or at all. For example, on June 16, 2020, the FDA revoked the EUA it had granted for the DPP COVID‑19 IgM/IgG System based in part on performance criteria identified after the EUA was granted on April 14, 2020. We do not currently have an EUA from the FDA for any of the COVID-19 Diagnostic Test Systems, and we do not currently have an application pending for any such EUA Moreover, FDA regulations, policies and procedures with respect to COVID‑19 tests may be significantly impacted by the continued development of vaccines for COVID‑19 and changes in the FDA’s prioritization guidance. 
+Changes in government regulations may adversely affect our financial condition and results of operations because we may have to incur additional expenses if we are required to change or implement new testing, manufacturing and control procedures. If we are required to devote resources to develop such new procedures, we may not have sufficient resources to devote to research and development, marketing, or other activities that are critical to our business. We are, for example, expending resources to modify the design of the COVID-19 Diagnostic Test System to achieve performance targets consistent with the FDA’s performance criteria issued subsequent to the granting of our original EUA. 
+We can manufacture and sell our products only if we comply with regulations and quality standards established by government agencies such as the FDA and the U.S. Department of Agriculture as well as by non‑governmental organizations such as the ISO and WHO. We have implemented a quality control system that is intended to comply with applicable regulations. Although FDA approval is not required for the export of our products, there are export regulations promulgated by the FDA that specifically relate to the export of our products that require compliance with FDA QSRs and that also require meeting certain documentary requirements regarding the approval of the product in export markets. We also may be subject to import regulations in connection with international sourcing of components and materials incorporated in the manufacturing of our products. 
+If we do not comply with FDA or other regulatory requirements, we may be required to suspend production or sale of our products or institute a recall, which could result in higher costs and a loss of revenues. 
+Regulations of the FDA and other federal, state and foreign regulatory agencies have significant effects on many aspects of our operations, and the operations of our suppliers and distributors, including packaging, labeling, manufacturing, adverse event reporting, recalls, distribution, storage, advertising, promotion and record keeping. We are subject to routine inspection by the FDA and other agencies to determine compliance with QSRs and FDA regulatory requirements in the United States and other applicable regulations worldwide, including but not limited to ISO standards. We believe that our facilities and procedures are in material compliance with the FDA requirements and ISO standards, but the regulations may be unclear and are subject to change, and we cannot be sure that the FDA or other regulators will agree with our compliance with these requirements. The FDA and foreign regulatory agencies may require post‑marketing testing and surveillance to monitor the performance of approved or cleared products or impose conditions on any product clearances or approvals that could restrict the distribution or commercial applications of those products. Regulatory agencies may impose restrictions on our or our distributors’ advertising and promotional activities or preclude these activities altogether if a noncompliance is believed to exist. In addition, the subsequent discovery of previously unknown problems with a product may result in restrictions on the product or additional regulatory actions, including withdrawal of the product from the market. 
+Our inability to comply with the applicable requirements of the FDA can result in, among other things, 483 notices, warning letters, administrative or judicially imposed sanctions such as injunctions, recall or seizure of products, civil penalties, withdrawal of product registrations, total or partial suspension of production, refusal to grant premarket clearance for devices, a determination that a device is not approvable, marketing clearances or approvals, or criminal prosecution. For example, in February 2020, we received a “not approvable” letter from the FDA with respect to our premarket approval submission on our DPP HIV‑Syphilis multiplex test for commercial use in the United States and in June 2020 we received notice from the FDA that the EUA for the DPP COVID‑19 IgM/IgG System had been revoked. The ability of our suppliers to supply critical components or materials and of our distributors to sell our products could also be adversely affected if their operations are determined to be out of compliance. Such actions by the FDA and other regulatory bodies could adversely affect our revenues, costs and results of operations. 
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+We must frequently make judgment decisions with respect to compliance with applicable laws and regulations. If regulators subsequently disagree with how we have sought to comply with these regulations, we could be subjected to substantial civil and criminal penalties, as well as product recall, seizure or injunction with respect to the sale of our products. Our reputation could be substantially impaired if we are assessed any civil and criminal penalties and limit our ability to manufacture and market our products which could have a material adverse effect on our business. 
+Our inability to respond to changes in regulatory requirements could adversely affect our business. 
+We believe that our existing products and procedures are in material compliance with all applicable FDA regulations, ISO requirements, and other applicable regulatory requirements, but the regulations regarding the manufacture and sale of our products, the QSR and ISO requirements, and other requirements may be unclear and are subject to change. Newly promulgated regulations could require changes to our products, necessitate additional clinical trials or procedures, or make it impractical or impossible for us to market our products for certain uses, in certain markets, or at all. The FDA and other regulatory authorities also have the ability to change the requirements for obtaining product approval and/or impose new or additional requirements as part of the approval process. These changes or new or additional requirements may occur after the completion of substantial clinical work and other costly development activities. The implementation of such changes or new or additional requirements may result in additional clinical trials and substantial additional costs and could delay or make it more difficult or complicated to obtain approvals and sell our products. In addition, the FDA may revoke an Emergency Use Authorization under which our products are sold, where it is determined that the underlying health emergency no longer exists or warrants such authorization. Such revocation would preclude the sale of our affected products unless and until a further regulatory approval or authorization is obtained. For example, For example, on June 16, 2020, the FDA revoked the EUA it had granted for the DPP COVID‑19 IgM/IgG System based in part on performance criteria identified after the Emergency Use Authorization was granted on April 14, 2020, and since that time we expended resources to design the new COVID-19 Diagnostic Test Systems, including the DPP Respiratory Antigen Panel. We do not currently have an EUA from the FDA for any of the COVID-19 Diagnostic Test Systems, and we do not currently have an application pending for any such EUA We cannot anticipate or predict the effect, if any, that these types of changes might have on our business, financial condition or results of operations. 
+Demand for our products may be affected by FDA regulation of laboratory‑developed tests and genetic testing. 
+Regulatory responsibility over instruments, test kits, reagents and other devices used to perform diagnostic testing by clinical laboratories is covered by the FDA, including our Micro Reader analyzer. The FDA has previously taken the position that it has regulatory authority over laboratory‑developed tests, or LDTs, but has exercised enforcement discretion by not regulating most LDTs performed by high complexity CLIA‑certified laboratories. LDTs are tests designed, developed, and performed in‑house by a laboratory. These laboratories are subject to CLIA regulation but such laboratories have previously not been subject to regulation by the FDA under the agency’s medical device requirements. 
+However, the FDA has announced that it would begin regulating LDTs, and in October 2014 the FDA issued proposed guidance on the regulation of LDTs for public comment. But, on November 18, 2016, the FDA announced that it would not finalize the proposed guidance prior to the end of the Obama administration. On January 13, 2017, the FDA released a discussion paper synthesizing public comments on the 2014 draft guidance documents and outlining a possible approach to regulation of LDTs. The discussion paper has no legal status and does not represent a final version of the LDT draft guidance documents. We cannot predict what policies the Trump administration will adopt with respect to LDTs. If the FDA increases regulation of LDTs, it could make it more difficult for laboratories and other customers to continue offering LDTs that involve genetic or molecular testing. This, in turn, could reduce demand for our products and adversely impact our revenues. 
+Disruptions at the FDA and other government agencies caused by funding shortages or global health concerns could hinder their ability to hire, retain or deploy key leadership and other personnel, or otherwise prevent new or modified products from being developed, cleared, approved, authorized, or commercialized in a timely manner or at all, which could negatively impact our business. 
+The ability of the FDA to review and clear, approve, or authorize new products can be affected by a variety of factors, including government budget and funding levels, statutory, regulatory, and policy changes, the FDA’s ability to hire and retain key personnel and accept the payment of user fees, and other events that may otherwise affect the FDA’s ability to perform routine functions. Average review times at the agency have fluctuated in recent years as a result. In addition, government funding of other government agencies that fund research and development activities is subject to the political process, which is inherently fluid and unpredictable. Disruptions at the FDA and other agencies may also slow the time necessary for medical devices or modifications to be cleared or approved, medical devices to be reviewed and/or approved by necessary government agencies, which would adversely affect our business. For example, over the last several years, including for 35 days beginning on December 22, 2018, the U.S. government has shut down several times and certain regulatory agencies, such as the FDA, have had to furlough critical FDA employees and stop critical activities. 
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+Separately, in response to the global COVID‑19 pandemic, on March 10, 2020 the FDA announced its intention to postpone most foreign inspections of manufacturing facilities and products, and subsequently, on March 18, 2020, the FDA announced its intention to temporarily postpone routine surveillance inspections of domestic manufacturing facilities. Regulatory authorities outside the United States may adopt similar restrictions or other policy measures in response to the COVID‑19 pandemic. If a prolonged government shutdown occurs, or if global health concerns continue to prevent the FDA or other regulatory authorities from conducting their regular inspections, reviews, or other regulatory activities, it could significantly impact the ability of the FDA or other regulatory authorities to timely review and process our regulatory submissions, which could have a material adverse effect on our business. 
+In addition to FDA requirements, we are subject to several government regulations, compliance with which could increase our costs and affect our operations. 
+In addition to the FDA regulations previously described, laws and regulations in some states may restrict our ability to sell products in those states. 
+We must comply with numerous laws related to safe working conditions, environmental protection, disposal of hazardous substances, fire hazard control, manufacturing practices and labor or employment practices. Compliance with these laws or any new or changed laws regulating our business could result in substantial costs. Due to the number of laws and regulations governing our industry, and the actions of a number of government agencies that could affect our operations, it is impossible to reliably predict the full nature and impact of these laws and regulations. To the extent the costs and procedures associated with complying with these laws and requirements are substantial or it is determined that we do not comply, our business and results of operations could be adversely affected. 
+Ongoing changes in healthcare regulation could negatively affect our revenues, business and financial condition. 
+There have been several proposed changes in the United States at the federal and state level for comprehensive reforms regarding the payment for, the availability of and reimbursement for healthcare services. These proposals have ranged from fundamentally changing federal and state healthcare reimbursement programs, including providing comprehensive healthcare coverage to the public under government‑funded programs, to minor modifications to existing programs. One example is the Patient Protection and Affordable Care or the Affordable Care Act, the Federal healthcare reform law enacted in 2010. 
+Healthcare reform initiatives will continue to be proposed, and may reduce healthcare related funding in an effort. It is impossible to predict the ultimate content and timing of any healthcare reform legislation and its resulting impact on us. If significant reforms are made to the healthcare system in the United States, or in other jurisdictions, those reforms may increase our costs or otherwise negatively effect on our financial condition and results of operations. 
+In April 2017, the European Parliament passed the Medical Devices Regulation (Regulation 2017/745), which repeals and replaces the European Union Medical Devices Directive and the Active Implantable Medical Devices Directive. Unlike directives, which must be implemented into the national laws of the European Economic Area, which we refer to as the EEA, member States, the regulations would be directly applicable, i.e., without the need for adoption of EEA member State laws implementing them, in all EEA member States and are intended to eliminate current differences in the regulation of medical devices among EEA member States. The Medical Devices Regulation, among other things, is intended to establish a uniform, transparent, predictable and sustainable regulatory framework across the EEA for medical devices and ensure a high level of safety and health while supporting innovation. The Medical Devices Regulation will, however, only become fully applicable three years after publication (in May 2020). Once applicable, the Medical Devices Regulation will, among other things: 
+● 
+strengthen the rules on placing devices on the market and reinforce surveillance once they are available; 
+● 
+establish explicit provisions on manufacturers’ responsibilities for the follow‑up of the quality, performance and safety of devices placed on the market; 
+● 
+improve the traceability of medical devices throughout the supply chain to the end‑user or patient through a unique identification number; 
+● 
+set up a central database to provide patients, healthcare professionals and the public with comprehensive information on products available in the EU; and 
+● 
+strengthen rules for the assessment of certain high‑risk devices, such as implants, which may have to undergo an additional check by experts before they are placed on the market. 
+Once applicable, the Medical Devices Regulation may impose increased compliance obligations for us to access the EU market. 
+We may incur additional costs if we do not comply with privacy, security and breach notification regulations. 
+We believe that we are not a covered entity nor a business associate of a covered entity and are not responsible for complying with the Health Insurance Portability and Accountability Act of 1996, or HIPAA. Even though we likely are not a covered entity under HIPAA, we do have in place administrative, technical and physical safeguards to protect the privacy and security of consumers’ personal information. We are required to comply with varying state privacy, security and breach reporting laws. If we fail to comply with existing or new laws and regulations related to properly transferring data containing consumers’ personal information, we could be subject to monetary fines, civil penalties or criminal sanctions. Also, there are other federal and state laws that protect the privacy and security of consumers’ personal information, and we may be subject to enforcement by various governmental authorities and courts resulting in complex compliance issues. We could incur damages under state laws pursuant to an action brought by a private party for the wrongful use or disclosure of consumers’ personal information. 
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+Table of Contents 
+Failure to comply with recent European data protection requirements could increase our costs. 
+The EU has adopted a comprehensive overhaul of its data protection regime from the prior national legislative approach to a single European Economic Area Privacy Regulation called the General Data Protection Regulation, or GDPR, which came into effect on May 25, 2018. The new EU data protection regime extends the scope of the EU data protection law to all foreign companies processing data of EU residents. It imposes a strict data protection compliance regime with severe penalties of up to the greater of 4% of worldwide turnover and €20 million and includes new rights such as the “portability” of personal data. Although the GDPR will apply across the EU without a need for local implementing legislation, as had been the case under the prior data protection regime, local data protection authorities will still have the ability to interpret the GDPR, which has the potential to create inconsistencies on a country‑by‑country basis. We are evaluating these new requirements and implementing a plan to ensure compliance. Complying with the enhanced obligations imposed by the GDPR may result in significant costs to our business and require us to amend certain of our business practices. Further, we have no assurances that violations will not occur, particularly given the complexity of the GDPR, as well as the uncertainties that accompany new, comprehensive legislation. 
+If we are not able to manufacture products in accordance with applicable requirements, it could adversely affect our business. 
+Our products must meet detailed specifications, performance standards and quality requirements. As a result, our products and the materials used in their manufacture or assembly undergo regular inspections and quality testing. Factors such as defective materials or processes, mechanical failures, human errors, environmental conditions, changes in materials or production methods, and other events or conditions could cause our products or the materials used to produce or assemble our products to fail inspections and quality testing or otherwise not perform in accordance with our label claims or the expectations of our customers. 
+If we are not able to meet the applicable specifications, performance standards, quality requirements or customer expectations could adversely affect our ability to manufacture and sell our products or comply with regulatory requirements. These events could, in turn, adversely affect our revenues and results of operations. 
+Healthcare fraud and abuse laws could adversely affect our business and results of operations. 
+There are various federal and state laws targeting fraud and abuse in the healthcare industry to which we are subject, including anti‑kickback laws, laws constraining the sales, false claims laws, marketing and promotion of medical devices by limiting the kinds of financial arrangements that manufacturers of these products may enter into with physicians, hospitals, laboratories and other potential purchasers of medical devices. There are other laws we are subject to that require us to report certain transactions between it and healthcare professionals. Violations of these laws are punishable by criminal or civil sanctions, including substantial fines, imprisonment and exclusion from participation in government healthcare programs. Many of the existing requirements are new and have not been definitively interpreted by state authorities or courts, and available guidance is limited. We could face enforcement action and fines and other penalties, and could receive adverse publicity, unless and until we are in full compliance with these laws, all of which could materially harm us. Furthermore, changes in or evolving interpretations of these laws, regulations, or administrative or judicial interpretations, may require us to change our business practices or subject our business practices to legal challenges, which could have a material adverse effect on our business, financial condition and results of operations. 
+Our compliance with regulations governing public companies is complex and expensive. 
+Public companies are subject to various laws and regulations, which have increased the scope, complexity and cost of corporate governance, reporting and disclosure practices. For example, we are subject to the Sarbanes‑Oxley Act of 2002, The Dodd‑Frank Wall Street Reform and Consumer Protection Act and the requirements of The NASDAQ Global Market. The implementation of certain aspects of these laws and regulations has required and will continue to require substantial management time and oversight and may require us to incur significant additional accounting and legal costs. We continually review changes with respect to new and proposed rules and cannot predict or estimate the amount of additional costs, and the timing of such costs, we may incur. There are several interpretations of these laws and regulations, in many cases due to their lack of specificity, and as a result, their application in practice may change as new guidance is provided by regulatory and governing bodies. This may result in continuing uncertainty regarding compliance matters and higher costs. We are committed to maintaining high standards of corporate governance and public disclosure, but if we fail to comply with any of these requirements, legal proceedings may be initiated against us, which may adversely affect our business. 
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+Table of Contents 
+If we expand our international presence, it may increase our risks and expose our business to regulatory, cultural or other challenges. 
+We will continue to try to increase revenue derived from international sales of our products. There are several of factors that could adversely affect the performance of our business and/or cause us to incur substantially increased costs because of our international presence and sales, including: (i) uncertainty in the application of foreign laws and the interpretation of contracts with foreign parties; (ii) cultural and political differences that favor local competitors or make it difficult to effectively market, sell and gain acceptance of our products; (iii) exchange rates, currency fluctuations, tariffs and other barriers, extended payment terms and dependence on international distributors or representatives; (iv) trade protection measures, trade sanctions and import/export licensing requirements; (v) our inability to obtain or maintain regulatory approvals or registrations for our products; (vi) Economic conditions, political instability, the absence of available funding sources, terrorism, civil unrest, war and natural disasters in foreign countries; (vii) Reduced protection for, or enforcement of, our patents and other intellectual property rights in foreign countries; (viii) our inability to identify international distributors and negotiate acceptable terms for distribution agreements; and (ix) restrictions on our ability to repatriate investments and earnings from foreign operations. 
+Economic, cultural and political conditions and foreign regulatory requirements may slow or prevent the manufacture of our products in countries other than the United States. Interruption of the supply of our products could reduce revenues or cause us to incur significant additional expenses in finding an alternative source of supply. Foreign currency fluctuations and economic conditions in foreign countries could also increase the costs of manufacturing our products in foreign countries. 
+Risks Related to Ownership of Common Stock 
+Our Common Stock has limited liquidity, and investors may not be able to sell as much stock as they want at prevailing market prices or at all. 
+The liquidity of our Common Stock depends on several factors, including but not limited to our financial results and overall market conditions, so it is not possible to predict whether this level of liquidity will continue, be sustained, or decrease. Decreased trading volume in our stock would make it more difficult for investors to sell their shares in the public market at any given time at prevailing prices. Our management and larger stockholders exercise significant control over our company. 
+The price of our Common Stock could continue to be volatile. 
+The price of our Common Stock has been volatile, subject to rapid and substantial decreases in stock price, and may be volatile in the future. By way of example, on February 10, 2021, the price of our Common Stock closed at $7.92 per share while on February 17, 2021, our stock price closed at $6.94 per share with no discernable announcements or developments by us or third parties. On February 12, 2021, the intra‑day sales price of our Common Stock fluctuated between a reported low sale price of $6.96 and a reported high sales price of $7.45. The following factors, among others, could have a significant impact on the market for our Common Stock: (1) the performance of our business; (2) clinical results with respect to our products or those of our competitors; (3) the gain or loss of significant contracts and availability of funding for the purchase of our products; (4) actions undertaken by the Congress or the Presidential Administration; (5) changes in our relations with our key customers, distributors or suppliers; (6) developments in patent or other proprietary rights; (7) litigation or threatened litigation; (8) general market and economic conditions; (9) the relatively low trading volume for our Common Stock; (10) changes in competition; (11) complaints or concerns about the performance or safety of our products and publicity about those issues, including publicity expressed through social media or otherwise over the internet; (12) failure to achieve, or changes in, financial estimates by securities analysts and comments or opinions about us by securities analysts or major stockholders; (13) announcement of regulatory or enforcement actions by the FDA or other agencies against us, our products or our customers; (14) changes in our operating results; (15) terrorist attacks, civil unrest, war and national disasters; and (16) other factors unrelated to our operating performance or prospects. 
+Overall, the stock market has experienced price and volume fluctuations that have affected the market price of our Common Stock, as well as the stock of many other similar companies. Such price fluctuations are generally unrelated to the operating performance of the specific companies whose stock is affected. 
+After the volatility in the market price of a company’s stock, class action litigation has occurred against the issuing company. If we were subject to this type of litigation in the future, we could incur substantial costs and the attention and resources of our management could be diverted, each of which could have a material adverse effect on our revenue and earnings. Any adverse determination in this type of litigation could also subject us to significant liabilities. 
+Our Common Stock may become the target of a “short squeeze.” 
+In the past several weeks prior to the filing of this Annual Report on Form 10‑K, securities of certain companies have increasingly experienced significant and extreme volatility in stock price due to short sellers of shares of common stock, known as a “short squeeze.” Short squeezes have caused extreme volatility in those companies and in the market and have led to the price per share of those companies to trade at a significantly inflated rate that is disconnected from the underlying value of the company. Sharp rises in a company’s stock price may force traders in a short position to buy the stock to avoid even greater losses. Many investors who have purchased shares in those companies at an inflated rate face the risk of losing a significant portion of their original investment as the price per share has declined steadily as interest in those stocks have abated. There can be no assurance that we will not, in the future be, a target of a short squeeze, and you may lose a significant portion or all of your investment if you purchase our shares at a rate that is significantly disconnected from our underlying value. 
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+Table of Contents 
+Any future issuances of shares of our Common Stock by us could harm the price of our Common Stock and our ability to raise funds in new equity offerings. 
+Any future sales of a substantial number of our shares of Common Stock or other equity‑related securities, or the perception that such sales may occur, could adversely affect the price of our Common Stock, and could impair our ability to raise capital through future offerings of equity or equity‑related securities. 
+Sales of our Common Stock by existing stockholders, executive officers or directors could depress the market price of our Common Stock. 
+If our existing stockholders, officers or directors sell our Common Stock in the public market, or the perception that such sales may occur, it could negatively affect the price of our Common Stock. We are unable to estimate the number of shares of our Common Stock that may actually be resold in the public market since this will depend on the market price for our Common Stock, the individual circumstances of the sellers and other factors. 
+Institutional stockholders own significant amounts of our Common Stock. If one or more of these stockholders sell large portions of their holdings in a relatively short time, the prevailing price of our Common Stock could be negatively affected. In addition, it is possible that one or more of our executive officers or non‑employee members of our Board of Directors could sell shares of our Common Stock during an open trading window. These transactions and the perceived reasons for these transactions could have a negative effect on the prevailing market price of our Common Stock. 
+We do not intend to pay cash dividends on our Common Stock. 
+We do not expect to pay any cash dividends on our Common Stock and currently intend to retain our earnings, if any, to finance the expansion of our business. Therefore, the success of an investment in our Common Stock will depend entirely upon any future increase in value of our Common Stock. There is no guarantee that our Common Stock will gain value or even maintain the price at which investors purchased their shares. 
+General Risk Factors 
+We may not generate the expected benefits of future acquisitions or investments, and they could disrupt our ongoing business, distract our management, increase our expenses and negatively affect our business. 
+As a way for us to grow our business, we may pursue strategic acquisitions or investments. These activities, and their impact on our business, are subject to many risks, including the following: (i) the benefits expected to be derived from an acquisition or investment may not materialize and could be affected by numerous factors, such as regulatory developments, insurance reimbursement, our inexperience with new businesses or markets, general economic conditions and increased competition; (ii) we may be unable to successfully integrate an acquired company’s personnel, assets, management, information technology systems, accounting policies and practices, products and/or technology into our business; (iii) we may not be able to accurately forecast the performance or ultimate impact of an acquired business; and (iv) an acquisition may result in the incurrence of unexpected expenses, stockholder lawsuits, the dilution of our earnings or our existing stockholders’ percentage ownership, or potential losses from undiscovered liabilities not covered by an indemnification from the seller(s) of the acquired business. 
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+Table of Contents 
+If these factors occur, we may be unable to achieve all or a significant part of the benefits expected from an acquisition or investment. This may adversely affect our financial condition, results of operations and ability to grow our business or otherwise achieve our financial and strategic objectives. 
+Developments related to the U.K.’s referendum on membership in the E.U. could adversely affect us. 
+On June 23, 2016, the United Kingdom voted in favor of leaving the European Union, or E.U. On January 24, 2020, the U.K. and the E.U. entered into a withdrawal agreement pursuant to which the U.K. formally left the E.U. on January 31, 2020,In December 2020, the U.K. and E.U. agreed on a trade and cooperation that will provisionally apply after the end of the transition period until it is ratified by the parties to the agreement. On December 31, 2020, the U.K. passed legislation giving effect to the trade and cooperation agreement. The E.U. is expected to formally adopt the agreement in early 2021. The trade and cooperation agreement covers the general objectives and framework of the relationship between the U.K. and the E.U. , including as it relates to trade, transport, visas, judicial, law enforcement and security matters. Notably, under the trade and cooperation agreement, U.K. goods no longer benefit from the free movement of goods, and there is no longer the free movement of people between the U.K. and the E.U. 
+Such a withdrawal from the E.U. is unprecedented, and it is unclear how the changes to U.K.’s access to the European single market for goods, capital, services and labor within the E.U., or the European single market, and the wider commercial, legal and regulatory environment, will impact our U.K. operations. We may also face new regulatory costs and challenges that could have an adverse effect on our operations and development programs. For example, because the regulatory framework for pharmaceutical products in the U.K. covering quality, safety and efficacy of pharmaceutical products, clinical studies, marketing authorization, commercial sales and distribution of pharmaceutical products is derived from E.U. directives and regulations, Brexit could materially impact the future regulatory regime that applies to products and the approval of product candidates in the U.K. Any delay in obtaining, or an inability to obtain, any marketing approvals, as a result of Brexit or otherwise, may force us to restrict or delay efforts to seek regulatory approval in the U.K. and/or E.U. for our product or gene therapy product candidate, which could significantly harm our business. 
+Given the lack of comparable precedent, it is unclear what financial, trade and legal implications the withdrawal of the United Kingdom from the E.U. will have and how such withdrawal may affect us. 
+Legislative and other regulatory changes could have an effect on our business. 
+Changes in regulatory or economic conditions or in the laws and policies governing foreign trade, taxes, manufacturing, and development in the United States could impact our business. Economic and regulatory changes could also affect foreign currency exchange rates which, in turn, could affect our reported financial results and our competitiveness on a worldwide basis. 
+Our business may be negatively affected by terrorist attacks or natural disasters. 
+Terrorist attacks or natural disasters could cause economic instability. These events could negatively affect economic conditions both within and outside the United States and harm demand for our products. The operations of our customers and suppliers could be negatively impacted and eliminate, reduce or delay our customers’ ability to purchase and use our products and our suppliers’ ability to provide raw materials and finished products. 
+Our facilities, including some pieces of manufacturing equipment and our computer systems, may be difficult to replace. Various types of disasters, including fires, earthquakes, floods and acts of terrorism, may affect our facilities and computer systems. In the event our existing facilities or computer systems are affected by man‑made or natural disasters, we may have difficulty operating our business and may be unable to manufacture products for sale or meet customer demands or sales projections. If our manufacturing operations were curtailed or shut down entirely, it would seriously harm our business. 
+37 
+Table of Contents 
+ITEM 2. 
+PROPERTIES 
+Our U.S. manufacturing, administrative offices, and research facilities are located in leased space in Medford, New York, pursuant to a lease covering approximately 39,650 square feet and expiring on June 30, 2021. 
+On February 5, 2019, we entered into a commercial real estate lease for new corporate headquarters comprised of 70,000 square feet of office, research and development, and warehouse space located in Hauppauge, New York. The lease has an initial term of eleven years that can be extended, at our option, for two additional terms of five years each. Rent under the lease, which is payable in monthly installments, totals approximately $900,000 for the initial year and then increases by approximately three percent each succeeding year. 
+On February 5, 2019, we also entered into an agreement to sublet the space at Holbrook, New York. The sublease has a term that (a) commenced on the date we vacate the premises and (b) terminate on April 29, 2020. The sublessee has paid us 50% of our rent and additional rent payments, which will total approximately $100,000 per year during the term of the sublease. The sublease ran conterminously with the base lease in Holbrook, for which the Company was primarily responsible until the end of the lease term in April 2020. 
+Our European headquarters and Center of Excellence for Optical Technology is located in leased office and manufacturing space in Berlin, Germany. Our Southeast Asia manufacturing, warehouse, and commercial facilities are located in leased space in Kuala Lumpur, Malaysia. Our Latin America manufacturing, warehouse, and commercial facilities are located in Rio de Janeiro, Brazil. We regularly review our real estate portfolio and develop footprint strategies to support our customers’ global plans, while at the same time supporting our technical needs and controlling operating expenses. 
+ITEM 3. 
+LEGAL PROCEEDINGS 
+This information is set forth under “Note 12 – Commitments, Contingencies And Concentrations – Litigation” to the Consolidated Financial Statements of this Annual Report on Form 10-K is incorporated herein by reference. 
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+Table of Contents 
+PART II 
+ITEM 5. 
+MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+Listing Information 
+Our stock is listed on the NASDAQ Global Select Market of the NASDAQ Stock Market LLC under the symbol “CEMI.” 
+Holders 
+As of March 1, 2021 , there were 115 record owners of our Common Stock (including nominee holders such as banks and brokerage firms who hold shares for beneficial owners). 
+Recent Sales of Unregistered Securities 
+During the year ended December 31, 2020 , we issued unregistered securities in connection with the acquisition of Orangelife. See Note 3 - Acquisitions, for further discussion. 
+Issuer Purchases of Equity Securities 
+We did not repurchase any of our equity securities during the year ended December 31, 2020. 
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+Table of Contents 
+ITEM 7. 
+MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+We develop, manufacture and commercialize point-of-care tests for the detection and diagnosis of infectious diseases, including COVID 19, sexually transmitted disease, and fever and tropical disease. 
+Our product portfolio is based upon our proprietary DPP technology, a diagnostic platform that provides high-quality, cost-effective results in 15 to 20 minutes using fingertip blood, nasal swabs and other sample types. The DPP technology platform addresses the rapid diagnostic test market, which includes infectious diseases, cardiac markers, cholesterol and lipids, pregnancy and fertility, and drugs of abuse. Compared with traditional lateral flow technology, the DPP technology platform can provide enhanced sensitivity and specificity, advanced multiplexing capabilities and, with the DPP Micro Reader, quantitative results. 
+We target the market for rapid diagnostic test solutions for infectious diseases, which is driven by the high prevalence of infectious diseases globally, an increase in the geriatric population, growing demand for rapid test results, and advancements in multiplexing. We have a broad portfolio of infectious disease products, which prior to 2020 were focused principally on sexually transmitted disease and fever and tropical disease. In February 2020 we began the process of shifting substantially all of our resources to leverage the DPP technology platform to address the acute and escalating need for diagnostic testing for COVID-19. 
+Our products are sold globally, directly and through distributors, to medical laboratories and hospitals, governmental and public health entities, non-governmental organizations, medical professionals, and retail establishments. We continue to seek to expand our commercial distribution channels. 
+In 2020 we continued to invest in automating our test manufacturing processes, all of which are now based in the United States. Among other actions, we expanded our manufacturing capabilities by validating and implementing automated lines. Our transition from manual to automated assembly is intended to add capacity, reduce variable costs and improve product margins. In order to address challenging economic conditions and implement our business strategy, we continued to execute a program to reduce operating expenses and better align our costs with revenues, including by eliminating positions that were no longer aligned with our strategy. 
+Consolidated Results of Operations 
+The results of operations for the years ended December 31, 2020 and 2019 were as follows: 
+Year Ended December 31, 
+(in thousands) 
+2020 
+2019 
+TOTAL REVENUES 
+$ 
+32,470 
+100 
+% 
+$ 
+34,464 
+100 
+% 
+COSTS AND EXPENSES: 
+Cost of product sales 
+23,874 
+74 
+% 
+22,394 
+65 
+% 
+Research and development expenses 
+9,509 
+29 
+% 
+8,538 
+25 
+% 
+Selling, general and administrative expenses 
+21,038 
+65 
+% 
+16,139 
+47 
+% 
+Severance and related costs 
+1,122 
+3 
+% 
+— 
+0 
+% 
+Acquisition costs 
+63 
+0 
+% 
+721 
+2 
+% 
+55,606 
+171 
+% 
+47,792 
+139 
+% 
+LOSS FROM OPERATIONS 
+(23,136 
+) 
+(71 
+)% 
+(13,328 
+) 
+(39 
+)% 
+OTHER (EXPENSE) / INCOME 
+(2,842 
+) 
+(9 
+)% 
+(847 
+) 
+(2 
+)% 
+LOSS BEFORE INCOME TAX BENEFIT 
+(25,978 
+) 
+(80 
+)% 
+(14,175 
+) 
+(41 
+)% 
+Income tax benefit 
+457 
+1 
+% 
+500 
+1 
+% 
+NET LOSS 
+$ 
+(25,521 
+) 
+(79 
+)% 
+$ 
+(13,675 
+) 
+(40 
+)% 
+Percentages in the table reflect the percent of total revenues. 
+Total Revenues 
+Total revenues during 2020 were $32.5 million, a decrease of $2.0 million, or 5.8%, compared to 2019. The decrease in total revenues reflected a $4.1 million, or 14%, decrease in net product sales, which was principally comprised of (a) lower sales in Africa, Latin America, and the United States associated with diminished funding and the closure of clinics for HIV testing due to the COVID-19 pandemic, offset in part by (b) The Company’s success in achieving regulatory approvals for and selling the COVID-19 IgM/IgG Systems in Latin America and gains in Europe associated with our long term agreement with UNICEF for our DPP Zika IgM/IgG and DPP ZCD IgM/IgG multiplex tests and Micro Readers. The decrease in net product sales was offset in part by a $2.2 million, or 31.9%, increase in research and development and grant revenues relating to new government grants for the development, and submission for U.S. regulatory approval, of DPP SARS-CoV-2 Antigen and DPP Respiratory Panel test systems. 
+Gross Product Margin 
+Cost of product sales is primarily comprised of material, labor, manufacturing overhead, depreciation and amortization, and freight and distribution costs. Gross product margin is net product sales less cost of product sales, and gross product margin percentage is gross product margin as a percentage of net product sales. 
+Gross product margin decreased by $5.6 million, or 86.2% compared to 2019. The following schedule calculates gross product margin: 
+For the years ended December 31 
+Favorable/ 
+2020 
+2019 
+(unfavorable) 
+% Change 
+(in thousands) 
+Net product sales 
+$ 
+24,767 
+$ 
+28,845 
+$ 
+(4,078 
+) 
+(14.1 
+)% 
+Less: Cost of product sales 
+(23,874 
+) 
+(22,394 
+) 
+(1,480 
+) 
+6.6 
+% 
+Gross product margin 
+$ 
+893 
+$ 
+6,451 
+$ 
+(5,558 
+) 
+(86.2 
+)% 
+Gross product margin % 
+3.6 
+% 
+22.4 
+% 
+40 
+Table of Contents 
+In 2020 we invested in developing and offering products to address the COVID-19 pandemic, which we expect will have average selling prices greater than those of our legacy products. We also continued to invest in automation in order to reduce our reliance on manual labor and improve our product margins (see Q1’21 Restructuring Charge). The $5.6 million decrease in gross product margin was comprised of (a) $4.7 million from unfavorable product margins and (b) $0.9 million from unfavorable product sales volume as described under “—Total Revenues” above. The $4.6 million decrease from unfavorable product margins principally reflected the following: 
+● 
+We incurred the cost of product sales for COVID-19 IgM/IgG Systems that were returned by customers following the Revocation. 
+● 
+The Revocation precluded planned sales of COVID-19 IgM/IgG Systems to customers in the United States in the last three quarters of 2020 and resulted in the deferral ,of certain customer opportunities for sales of COVID-19 IgM/IgG Systems outside the United States, which negatively impacted our sales mix as we experienced (a) significantly lower sales in the United States, where we have our highest average selling prices, and (b) outside the United States, a higher mix of sales in geographic regions with lower average selling prices. 
+● 
+We experienced operational inefficiencies, including those triggered by the Revocation and activities related to qualifying automated lines for production of certain products, which resulted in increased cost of product sales as we substantially shifted our production from COVID-19 products back to legacy products. 
+41 
+Table of Contents 
+Research and Development 
+This category includes costs incurred for clinical and regulatory affairs and other research and development, as follows: 
+For the years ended December 31 
+Favorable/ 
+2020 
+2019 
+(unfavorable) 
+% Change 
+(in thousands) 
+Clinical and regulatory affairs 
+$ 
+1,061 
+$ 
+1,516 
+$ 
+455 
+30.0 
+% 
+Other research and development 
+8,448 
+7,022 
+(1,426 
+) 
+(20.3 
+)% 
+Total research and development 
+$ 
+9,509 
+$ 
+8,538 
+$ 
+(971 
+) 
+(11.4 
+)% 
+The decrease in clinical and regulatory affairs costs for 2020 as compared to 2019 was primarily associated with reduced clinical trial costs following the FDA’s granting of premarket approval for the DPP HIV-Syphilis test during 2020, offset in part by expenditures related to the DPP SARS-CoV-2 Systems. The increase in other research and development costs was primarily related to costs associated with the development of the DPP SARS-CoV-2 Systems. 
+Selling, General and Administrative Expense 
+Selling, general and administrative expenses include administrative expenses, sales and marketing costs (including commissions), and other corporate items. The $4.9 million, or 30%, increase in selling, general and administrative expenses for 2020 as compared to 2019 primarily reflected legal costs arising subsequent to the Revocation, costs from expanding our U.S. commercial organization, a full year of our Brazilian facility (which was acquired during the fourth quarter of 2019), and facility costs related to the COVID-19 pandemic, offset in part by cost savings from retrenching our Malaysia facility and other restructuring actions taken during the first quarter of 2020. 
+Severance, Restructuring and other related c osts 
+During the year ended December 31, 2020, the Company recognized $0.7 million in net severance expenses related to the departure of Chembio’s former chief executive officer and the elimination of certain positions as part of its multi-faceted expense reduction program to reduce operating expenses. The Company undertook actions to adjust the size and composition of the organization, including by removing positions that were non-essential in light of its new business strategy, and to remove other expenses, all of which the Company expects will provide savings throughout, and after, 2020. 
+In light of market dynamics, the Company retrenched its Malaysian operations, including the termination of employment of its Malaysian workforce. The Company will maintain its Malaysian subsidiary and sustain the product registrations that were obtained throughout southeast Asia, with the benefit of having that entity and the WHO prequalification certified facility. 
+Based on these activities, the Company took restructuring actions totaling $0.4 million to realign and resize its production capacity and cost structure. All expenses have been paid as of December 31, 2020. 
+Acqu isition Costs 
+Acquisition costs include legal, due diligence, audit, and related costs associated with acquisitions. The $0.7 million decrease in acquisition costs for 2020 as compared to 2019 reflected the fact that we completed acquisitions in 2019 but not 2020. 
+Other (Expense) / Income 
+Other (expense) / income was principally comprised of interest expense net of interest income. Interest expense increased by $2.0 million for 2020 as compared to 2019, due to the interest paid on the term loan debt we incurred in September 2019. 
+Income Tax Benefit 
+For 2020 we recognized a tax benefit of $0.4 million primarily attributable to the loss generated by Chembio Diagnostics Germany. As of December 31, 2020 and 2019, the Company recorded a full valuation allowance against its net deferred tax assets. 
+Liquidity and Capital Resources 
+During the year ended December 31, 2020, we funded our business operations, including capital expenditures and working capital requirements, principally from a public offering of common stock, which generated proceeds of $28.4 million (net of expenses), and from cash and cash equivalents. Our operations used $18.9 million of cash. As of December 31, 2020, we had outstanding indebtedness of $20 million (carrying amount of $18.2 million) pursuant to the Credit Agreement described under “—Sources of Funds—Credit Agreement” below. 
+42 
+Table of Contents 
+We continually evaluate our liquidity requirements, capital needs and availability of capital resources based on our operating needs and our planned growth initiatives, particularly in the light of our shift in business focus to the DPP SARS-CoV-2 Systems. We believe our existing cash and cash equivalents will be sufficient to meet our anticipated cash needs for at least the next twelve months. Our future working capital needs will depend on many factors, including: the fact and timing of our receipt from the FDA of an EUA award for the DPP SARS-CoV-2 Antigen System and/or the DPP Respiratory Panel System; the fact and timing of our receipt from the FDA of a CLIA waiver for the DPP HIV-Syphilis System; the rate of our business and revenue growth, including our ability to successfully build distribution channels and commercialize the COVID-19 Diagnostic Test Systems in geographies (principally Europe) covered by our CE-Marks for those products, particularly if we are able to resume commercialization of the COVID-19 Diagnostic Test Systems in the United States; the occurrence and timing of regulatory approvals for other new products; the timing of our continuing automation of U.S. manufacturing; and the timing of our investment in research and development as well as sales and marketing. If our sources of liquidity become insufficient to fund the growth of our business, we may need to reduce the level or slow the timing of our growth plans, which would likely curtail or delay the growth in our business contemplated by our operating plan and could impair or defer our ability to achieve profitability and generate cash flow, or to seek to raise additional funds through debt or equity financings, strategic relationships, or other arrangements, to the extent funding would be available to us on acceptable terms or at all. If we were to raise additional funds through the issuance of equity or convertible securities, the issuance could result in substantial dilution to existing stockholders, and the holders of those new securities may have rights, preferences and privileges senior to those of the holders of common stock. 
+Sources of Funds 
+Credit Agreement. On September 3, 2019, we, as borrower, and certain of our subsidiaries, as guarantors, entered into a Credit Agreement and Guaranty, or the Credit Agreement, with Perceptive Credit Holdings II, LP, or the Lender. 
+● 
+Principal Amount . The Credit Agreement provides for a $20,000,000 senior secured term loan credit facility, which was drawn in full on September 4, 2019. Under the terms of the Credit Agreement, we may use the proceeds for general working capital purposes and other permitted corporate purposes, to refinance certain of our existing indebtedness and to pay fees, costs and expenses incurred in connection with the Credit Agreement. 
+● 
+Interest Rate . Principal outstanding under the Credit Agreement bears interest at a rate per annum equal to the sum of (a) the greater of the one-month London Interbank Offered Rate and 2.5% plus (b) 8.75%. At any time at which an event of default (as described under “—Default Provisions” below) has occurred and is continuing, the interest rate will increase by 4.0%. Accrued interest is payable on a monthly basis. 
+● 
+Scheduled Repayment . No principal repayments are due prior to September 30, 2022, unless we elect to prepay principal as described under “—Optional Prepayment” below or principal is accelerated pursuant to an event of default as described under “—Default Provisions” below. Principal installments in the amount of $300,000 are payable on the last day of each of the eleven months from September 2022 through July 2023, and all remaining principal is payable at maturity on September 3, 2023. 
+● 
+Optional Prepayment . We may prepay outstanding principal from time to time, subject to payment of a premium on the prepaid principal amount equal to 10% through September 3, 2020, 8% from September 4, 2020 through September 3, 2021, and 4% from September 4, 2021 through September 3, 2022. No premium will be due with respect to any prepayment made on or after September 4, 2022. 
+● 
+Guaranties . Our subsidiaries Chembio Diagnostic Systems Inc. and Chembio Diagnostics Malaysia Sdn Bhd. have guaranteed, and the Lender from time to time may require our other subsidiaries to guarantee, our obligations under the Credit Agreement. 
+● 
+Security . Our obligations under the Credit Agreement are secured by a first priority, perfected lien on substantially all of our property and assets, including our equity interests in our subsidiaries. Our subsidiary Chembio Diagnostic Systems Inc. has secured its guarantee of our Credit Agreement obligations with a lien on substantially all of its assets, and the Lender from time to time may require Chembio Diagnostics Malaysia Sdn Bhd. and any of our other subsidiaries that has guaranteed our Credit Agreement obligations to do the same. 
+● 
+Representations and Warranties; Financial and Other Covenants . In the Credit Agreement we made customary representations and warranties as well as customary affirmative and negative covenants, including covenants limiting additional indebtedness, liens, guaranties, mergers and acquisitions, substantial asset sales, investments and loans, sale and leasebacks, transactions with affiliates, and fundamental changes. The Credit Agreement also contains financial covenants requiring that we maintain aggregate unrestricted cash of not less than $3,000,000 at all times and we achieve specified minimum rolling four-quarter (“last twelve month”) total revenue amounts as of September 30, 2019 and the last day of each calendar quarter thereafter. The minimum total revenue amounts, which range from $32.0 million to $50.1 million, were developed for purposes of the Credit Agreement and do not reflect the internal estimates and plans used by our management and board of directors to understand and evaluate our operating performance, to establish budgets, and to establish operational goals for managing our business. We therefore do not believe that the covenant requirements provide useful information to investors or others in enhancing an understanding of our future prospects. 
+43 
+Table of Contents 
+● 
+Default Provisions . The Credit Agreement provides for customary events of default, including events of default based on non-payment of amounts due under the Credit Agreement, defaults on other debt, misrepresentations, covenant breaches, changes of control, insolvency, bankruptcy and the occurrence of a material adverse effect on the Company. Upon an event of default resulting from a voluntary or involuntary proceeding for bankruptcy, insolvency or receivership, the amounts outstanding under the Credit Agreement will become immediately due and payable and the Lender’s commitments will be automatically terminated. Upon the occurrence and continuation of any other event of default, the Lender may accelerate payment of all obligations and terminate the Lender’s commitments under the Credit Agreement. Upon an acceleration of payment following an event of default occurring prior to September 4, 2021, the amounts due and payable by us will include a prepayment premium on accelerated principal in the amount described under “—Optional Prepayment” above. 
+We were in compliance with the cash balance and revenue financial covenants as of December 31, 2020. 
+Equity and Equity-Related Securities. We raised additional capital from an underwritten public offering of common stock in 2020 in the amount of $28.4 million (net of expenses). 
+Research and Development Awards. We routinely seek research and development programs that may be awarded by government, non-governmental organizations, and non-profit entities, including private foundations. Since 2015 we have received over $14.2 million of funding from some of the world’s leading health organizations, which has helped us accelerate the expansion of our pipeline of infectious disease tests. Our collaborators have included Bill & Melinda Gates Foundation, The Paul G. Allen Family Foundation, FIOCRUZ and FIND, as well as U.S. government agencies such as Centers for Disease Control and Prevention, Biomedical Advanced Research and Development Authority or BARDA, and the U.S. Department of Agriculture. See “Item 1. Business—Products” above. During the year ended December 31, 2020, we recognized grant revenue totaling $2 million from government, non-governmental organizations, and non-profit entities. 
+Working Capital . The following table sets forth selected working capital information: 
+December 31, 2020 
+(in thousands) 
+Cash and cash equivalents 
+$ 
+23,066 
+Accounts receivable, net 
+3,377 
+Inventories, net 
+12,516 
+Prepaid expenses and other current assets 
+779 
+Total current assets 
+39,738 
+Less: Total current liabilities 
+12,351 
+Working capital 
+$ 
+27,387 
+On December 2, 2020, we were awarded a contract of $12.7 million from BARDA to assist us in (a) developing, and requesting an EUA from the FDA for, the DPP Respiratory Panel and (b) performing the clinical trials for and submitting the DPP SARS-CoV-2 Antigen system to the FDA for a 510(k). 
+Our cash and cash equivalents at December 31, 2020, which included a restricted amount of $1.0 million, were held for working capital purposes. We currently intend to retain all available funds and any future earnings for use in the operation of our business and do not anticipate paying any cash dividends. We have not entered into, and do not expect to enter into, investments for trading or speculative purposes. Our accounts receivable and inventory balances fluctuate from period to period, which affects our cash flow from operating activities. Fluctuations vary depending on cash collections, client mix, raw material lead times, the mix of vendor terms, and the timing of shipment of our products and the invoicing of our research and development activities. 
+Uses of Funds 
+Cash Flow Used in Operating Activities . Our operations used $18.9 million of cash during the year ended December 31, 2020, primarily due to the net loss adjusted for non-cash items of $7.3 million and a $6.5 million increase in inventory related to supply chain timelines, including materials for COVID-19 systems that were ordered but could not be cancelled following the Revocation. Those uses of cash were offset in part by a $3.9 million increase in accounts payable and other accrued liabilities, a $1.5 million increase in deferred revenue, and a $0.3 million reduction in accounts receivable. 
+Capital Expenditures . Our capital expenditures totaled $4.2 million in 2020, of which $4.0 million related to investments in automated manufacturing equipment, facilities, and other fixed assets. 
+44 
+Table of Contents 
+We have capital purchase obligations of $1.3 million related to additional automated manufacturing equipment with payments expected to come due during 2021 based on vendor performance milestones. 
+Effects of Inflation 
+Other than the impact of increases in minimum wage levels in New York, inflation and changing prices have not had a material effect on our business, and we do not expect that they will materially affect our business in the foreseeable future. Any impact of inflation on cost of revenue and operating expenses, especially employee compensation costs (including any effects of future increases in minimum wages levels in New York), may not be readily recoverable in the price of our product offerings. 
+Q1’21 Restructuring Charge 
+On January 14, 2021, the Company’s Board of Directors (the “Board”) approved a restructuring plan (“2021 Plan”) to better align its business priorities. The Plan comprises the termination of employees primarily in the manufacturing department. These actions were intended to better align the Company’s cost structure with the skills and resources required to more effectively pursue opportunities in the marketplace and execute the Company’s long-term growth strategy. 
+Costs associated with the 2021 Plan are primarily related to Severance and Legal costs. Severance payouts are expected to be substantially completed by the end of the six months ending June 30, 2021. Under the 2021 Plan, the Company expects to incur pre-tax charges between approximately $0.1 million and $0.2 million. 
+Off-Balance Sheet Arrangements 
+We do not have any off-balance sheet arrangements, as defined in Item 303(a)(4)(ii) of Regulation S-K under the Securities Exchange Act of 1934. 
+Significant Accounting Policies and Critical Accounting Estimates 
+Our significant accounting policies are described in Note 2 – Significant Accounting Policies to the audited consolidated financial statements included herein. Certain of our accounting policies require the application of significant judgment by management in selecting the appropriate assumptions for calculating financial estimates. By their nature, these judgments are subject to an inherent degree of uncertainty. These judgments are based on our historical experience, terms of existing contracts, our evaluation of trends in the industry, information provided by our customers and information available from other outside sources, as appropriate. We consider an accounting estimate to be critical if (a) it requires us to make assumptions about matters that were uncertain at the time we were making the estimate and (b) changes in the estimate or different estimates that we could have selected would have had a material impact on our financial condition or results of operations. 
+The following listing is not intended to be a comprehensive list of all of our accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by accounting principles generally accepted in the United States, with no need for management’s judgment in their application. There are also areas in which management’s judgment in selecting any viable alternative would not produce a materially different result. 
+Revenue Recognition 
+We recognize revenue for product sales in accordance with Financial Accounting Standards Board Accounting Standards Codification, or ASC, 606, Revenue from Contracts with Customers . Revenues from product sales are recognized when the customer obtains control of our product, which occurs at a point in time, typically upon tendering to the customer. We expense incremental costs of obtaining a contract as and when incurred because the expected amortization period of the asset that it would have recognized is one year or less or the amount is immaterial. Freight and distribution activities on products are performed after the customer obtains control of the goods. We have made an accounting policy election to account for shipping and handling activities that occur either when or after goods are tendered to the customer as a fulfillment activity, and therefore recognizes freight and distribution expenses in cost of product sales. We exclude certain taxes from the transaction price ( e.g. , sales, value added and some excise taxes). 
+Product revenue reserves, which are classified as a reduction in product revenue, are generally related to discounts and returns. Estimates of variable consideration and the determination of whether to include estimated amounts in the transaction price are based on all information (historical, current, and forecasted) that is reasonably available to the Company, taking into consideration the type of customer, the type of transaction, market events and trends, and the specific facts and circumstances of each arrangement. The transaction price, which includes variable consideration reflecting the impact of discounts, allowances and returns may be subject to constraint and is included in the net sales price only to the extent that it is probable that a significant reversal of the amount of the cumulative revenue recognized will not occur in a future period. Actual amounts may ultimately differ from the Company’s estimates. If actual results vary, the Company adjusts these estimates, which could have an effect on revenue and earnings in the period of adjustment. 
+For applicable contracts, we recognize revenue from research and development, milestone and grant revenues when earned. Grants are invoiced after expenses are incurred. Revenues from projects or grants funded in advance are deferred until earned. For certain collaborative research projects, we recognize revenue by defining milestones at the inception of the agreement and applying judgement and estimates in recognizing revenue for relevant contracts. 
+Stock-Based Compensation 
+We recognize the fair value of equity-based awards as compensation expense in our consolidated statement of operations. The fair value of restricted stock and restricted stock unit awards are their fair value on the date of grant. The fair value of our stock option awards was estimated using a Black-Scholes option valuation model. This valuation model’s computations incorporate subjective assumptions, such as the expected stock price volatility and the estimated life of each award. The fair value of equity-based awards, after considering the effect of expected forfeitures, is then amortized, generally on a straight-line basis, over the related vesting period of the option. 
+45 
+Table of Contents 
+Research and Development Costs 
+Research and development activities consist primarily of new product development, continuing engineering for existing products, and regulatory and clinical trial costs. Costs related to research and development efforts on existing or potential products are expensed/accrued as incurred. 
+Inventories 
+Inventories are stated at the lower of cost or net realizable value with cost being determined using a standard cost method, which approximates average cost. Average cost consists primarily of material, labor and manufacturing overhead expenses (including fixed production-overhead costs). The Company analyzes its inventory levels quarterly and writes down, in the applicable period, inventory that has become obsolete, inventory that has a cost basis in excess of its expected net realizable value and inventory in excess of expected customer demand. The Company also writes off, in the applicable period, the costs related to expired inventory. Costs of purchased inventories are recorded using weighted-average costing. 
+Accounts Receivable 
+Our policy is to review our accounts receivable on a periodic basis, no less frequently than monthly. On a quarterly basis an analysis is made of the adequacy of our allowance for doubtful accounts and adjustments are made accordingly. The allowance was approximately 0.6% of accounts receivable as of December 31, 2020. 
+Goodwill and Indefinite-lived Intangible Assets 
+We periodically review goodwill for impairment indicators. We review goodwill for impairment annually in the fourth quarter or more frequently if events or changes in circumstances indicate that goodwill might be impaired. We perform the goodwill impairment review at the reporting unit level. We perform a qualitative assessment of whether it is more likely than not that a reporting unit’s fair value is less than its carrying amount. If not, no further goodwill impairment testing is performed. If so, we perform the step discussed hereafter. Our qualitative assessment involves significant estimates, assumptions, and judgments, including, macroeconomic conditions, industry and market conditions, our financial performance, reporting unit specific events and changes in our share price. 
+If the fair value of the reporting unit is greater than its carrying amount, goodwill is not considered to be impaired. We would recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value, provided the impairment charge does not exceed the total amount of goodwill allocated to the reporting unit. 
+Indefinite-lived intangible assets are tested for impairment annually during the first fiscal quarter of the year, and when events or changes in circumstances indicate the assets might be impaired. Impairment is indicated when the carrying value of the intangible asset exceeds its fair value. 
+Recently Issued Accounting Pronouncements 
+Refer to Note 2 – Significant Accounting Policies to the audited consolidated financial statements included herein for a complete description of recent accounting standards that we have not yet been required to implement which may be applicable to our operations. Additionally, the significant accounting standards that have been adopted during the year ended December 31, 2020 are described. 
+46 
+Table of Contents 
+ITEM 8. 
+FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+The Consolidated Financial Statements and schedules that constitute Item 8 are attached at the end of this report. An index to the Consolidated Financial Statements and supplemental schedules are also included on page F-1 of this report. 
+ITEM 9A. 
+Controls and Procedures 
+Evaluation of Disclosure Controls and Procedures 
+Our management, with the participation of our Interim Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures, as defined by Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of December 31, 2020. Based on the evaluation of our disclosure controls and procedures, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2020 at the reasonable assurance level. 
+Management’s Report on Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer and effected by the board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that: 
+● 
+pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; 
+● 
+provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made in accordance with authorizations of management and directors of the company; and 
+● 
+provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. As a result, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate. 
+Under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, our management evaluated the effectiveness of our internal control over financial reporting as of December 31, 2020. In making their assessment of internal control over financial reporting, our management used the criteria described in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Our evaluation included documenting, evaluating and testing of the design and operating effectiveness of our internal control over financial reporting. Based on this evaluation, we concluded that our controls over financial reporting were effective as of December 31, 2020. 
+Previously Identified Material Weaknesses in Internal Control Over Financial Reporting 
+None. 
+Changes in Internal Control over Financial Reporting 
+There were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Securities Exchange Act of 1934 during the period covered by this Annual Report on Form 10-K that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+Inherent Limitations of Internal Control 
+Management, including the Comapny’s Chief Excutive Officer and Chief Financial Officer, does not expect that the Company’s internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints and the benefits of controls must be considered relative to their costs. Because of the inherent liminations in all control systems, no evaluation of internal control can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. Also, any evaluation of the effectiveness of internal controls in future periods are subject to the risk that those internal controls may become inadequate because of changes in business conditions, or that the degree of compliance with the policies and procedures may deteriorate. 
+ITEM 9B. 
+Other Information 
+None. 
+47 
+Table of Contents 
+PART III 
+ITEM 10. 
+DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
+The information required in response to this Item 10 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+ITEM 11. 
+EXECUTIVE COMPENSATION 
+The information required in response to this Item 11 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+ITEM 12. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+The information required in response to this Item 12 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE. 
+The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+ITEM 14. 
+PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+The information required in response to this Item 14 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+48 
+Table of Contents 
+ITEM 15. 
+EXHIBITS, FINANCIAL STATEMENT SCHEDULES 
+(a) See “Item 8. Financial Statements and Supplementary Data – Index to Consolidated Financial Statements” above. 
+(b) Exhibits 
+Exhibit 
+No. 
+Description 
+3.1 
+Articles of Incorporation, as amended, of Chembio Diagnostics, Inc. 
+3.2 
+Amended and Restated Bylaws, of Chembio Diagnostics, Inc. 
+4.1 
+Warrant to Purchase Common Stock dated as of September 3, 2019, issued by Chembio Diagnostics, Inc. to Perceptive Credit Holdings II, LP 
+4.2 
+Description of Securities 
+10.1(a)* 
+2008 Stock Incentive Plan, as amended 
+10.1(b)* 
+Form of Option for 2008 Stock Incentive Plan 
+10.2(a)* 
+2014 Stock Incentive Plan 
+10.2(b)* 
+Form of Option for 2014 Stock Incentive Plan 
+10.3 
+2019 Omnibus Incentive Plan 
+10.4* 
+Restated Annual Incentive Bonus Plan of Chembio Diagnostics, Inc., adopted as of March 15, 2019 
+10.5* 
+Outside Director Compensation Policy of Chembio Diagnostics, Inc. 
+10.6*‡ 
+Employment Agreement, dated as of March 4, 2020 and effective as of March 16, 2020, between Chembio Diagnostics, Inc. and Richard L. Eberly 
+10.7(a)* 
+Employment Agreement dated March 5, 2016 between Chembio Diagnostics, Inc. and Javan Esfandiari 
+10.7(b)* 
+Amendment No. 1 dated March 20, 2019 between Chembio Diagnostics, Inc. and Javan Esfandiari, amending the Employment Agreement dated March 5, 2016 
+10.8(a)* 
+Employment Agreement dated December 18, 2017 between Chembio Diagnostics, Inc. and Neil A. Goldman 
+10.8(b)* 
+Amendment No. 1 dated January 21, 2019 between Chembio Diagnostics, Inc. and Neil A. Goldman, amending Employment Agreement dated December 18, 2017 
+10.9* 
+Offer Letter dated October 19, 2016 between Worldwide Workplace Ireland and Robert Passas, with respect to employment by Chembio Diagnostics Systems, Inc. 
+10.10(a) 
+Lease Agreement, dated February 15, 2017, between Horseblock Associates and Chembio Diagnostics, Inc. with respect to 3661 Horseblock Road, Medford, New York, as amended 
+10.10(b) 
+Agreement of Sublease dated February 5, 2019 between Chembio Diagnostic Systems Inc., as sublessor, and Reliance Communications of New Jersey, LLC, as sublessee, with respect to 3661 Horseblock Road, Medford, New York, as amended 
+10.11 
+Lease Agreement, dated February 4, 2013, between Sherwood Corporate Center LLC and Chembio Diagnostics, Inc. with respect to 91-1A Colin Drive, Holbrook, New York, as amended on September 19, 2017 
+10.12 
+Lease Agreement dated February 5, 2019 between Myra Properties, LLC, as lessor, and Chembio Diagnostic Systems Inc., as lessee, with respect to 555 Wireless Boulevard, Hauppauge, New York. 
+10.13† 
+Credit Agreement and Guaranty dated as of September 3, 2019, among Chembio Diagnostics, Inc., as the Borrower, the Guarantors from time to time party thereto, and Perceptive Credit Holdings II, LP and its successors and assigns party thereto, as Administrative Agent and as a Lender 
+10.14*‡ 
+Letter agreement dated June 15, 2020 between Chembio Diagnostics, Inc. and Gail S. Page 
+10.15* 
+Amendment No. 1, dated June 30, 2020, to the letter agreement dated June 15, 2020 between Chembio Diagnostics, Inc. and Gail S. Page 
+14.1 
+Ethics Policy 
+21.1 
+List of Subsidiaries of Chembio Diagnostics, Inc. 
+22.1 
+Consent of EY, Independent Registered Public Accounting Firm 
+23.1 
+Consent of BDO USA, LLP, Independent Registered Public Accounting Firm 
+31.1 
+Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+31.2 
+Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+32.1** 
+Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 
+101.INS 
+XBRL Instance Document 
+101.SCH 
+XBRL Taxonomy Extension Schema Document 
+101.CAL 
+XBRL Taxonomy Extension Calculation Linkbase Document 
+101.DEF 
+XBRL Taxonomy Definition Linkbase Document 
+101.LAB 
+XBRL Taxonomy Label Linkbase Document 
+101.PRE 
+XBRL Taxonomy Presentation Linkbase Document 
+104 
+Cover Page Interactive Data File (embedded within the Inline XBRL document) 
+* 
+Indicates management contract or compensatory plan. 
+† 
+Certain exhibits and schedules have been omitted pursuant to Item 601(a)(5) of Regulation S-K. We hereby undertake to furnish copies of the omitted exhibits and schedules upon request by the Securities and Exchange Commission, provided that we may request confidential treatment pursuant to Rule 24b-2 of the Securities Exchange Act of 1934 for the exhibits and schedules so furnished. 
+‡ 
+Certain sensitive personally identifiable information in this exhibit was omitted by means of redacting a portion of the text and replacing it with [***]. 
+** 
+The certifications attached as Exhibit 32.1 accompany the Annual Report on Form 10-K pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended. 
+49 
+Table of Contents 
+SIGNATURES 
+In accordance with Section 13 or 15(d) of the Exchange Act, the registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+CHEMBIO DIAGNOSTICS, INC. 
+March 11, 2021 
+By 
+/s/ Richard L. Eberly 
+Richard L. Eberly 
+Chief Executive Officer and President 
+In accordance with the requirements of the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+Signatures 
+Title 
+Date 
+/s/ Richard L. Eberly 
+Chief Executive Officer and President 
+March 11, 2021 
+Richard L. Eberly 
+(Principal Executive Officer) 
+/s/ Neil A. Goldman 
+Executive Vice President and Chief Financial Officer 
+March 11, 2021 
+Neil A. Goldman 
+(Principal Financial & Accounting Officer) 
+/s/ Katherine L. Davis 
+Chair of the Board 
+March 11, 2021 
+Katherine L. Davis 
+/s/ David W. K. Acheson 
+Director 
+March 11, 2021 
+David W. K. Acheson 
+/s/ David W. Bespalko 
+Director 
+March 11, 2021 
+David W. Bespalko 
+/s/ Mary Lake Polan 
+Director 
+March 11, 2021 
+Mary Lake Polan 
+/s/ John G. Potthoff 
+Director 
+March 11, 2021 
+John G. Potthoff 
+50 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+Index to Consolidated Financial Statements 
+—INDEX— 
+Pages 
+Reports of Independent Registered Public Accounting Firm 
+F-1 and F-2 
+Consolidated Financial Statements: 
+Balance Sheets as of December 31, 2020 and 2019 
+F-3 
+Statements of Operations for the years ended December 31, 2020 and 2019 
+F-4 
+Statements of Comprehensive Loss for the years ended December 31, 2020 and 2019 
+F-5 
+Statements of Changes in Stockholders’ Equity for the years ended December 31, 2020 and 2019 
+F-6 
+Statements of Cash Flows for the years ended December 31, 2020 and 2019 
+F-7 
+Notes to Consolidated Financial Statements 
+F-8 - F-28 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+To the Stockholders and the Board of Directors of Chembio Diagnostics, Inc. 
+Opinion on the Financial Statements 
+We have audited the accompanying consolidated balance sheet of Chembio Diagnostics, Inc. (and subsidiaries) (the Company) as of December 31, 2020, the related consolidated statements of operations, comprehensive loss, stockholders’ equity and cash flows for the year ended December 31, 2020, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2020, and the results of its operations and its cash flows for the year ended December 31, 2020, in conformity with U.S. generally accepted accounting principles. 
+Basis for Opinion 
+These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audit we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. 
+Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion. 
+Critical Audit Matter 
+The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the account or disclosure to which it relates. 
+Description of the 
+Matter 
+Revenue Recognition – Variable Consideration 
+For the year ended December 31, 2020, the Company recognized $24.8 million of net product revenue. As discussed in Note 2 to the consolidated financial statements, variable consideration, which includes the effect of estimated future returns, is included in the transaction price only to the extent that it is probable that a significant reversal in the amount of the cumulative revenues recognized will not occur when the uncertainty associated with the variable consideration is subsequently resolved. 
+Auditing the Company’s measurement of variable consideration related to future returns was especially complex and involved a higher degree of subjectivity due to the significant estimation uncertainty. The estimation of variable consideration was dependent upon significant assumptions such as the probability of future returns and the likelihood of changes in approval by regulatory agencies. Changes in management’s significant assumptions can have a material effect on the amount and timing of revenue recognized. 
+How We Addressed 
+the Matter in Our 
+Audit 
+To test the estimation of variable consideration, our audit procedures included, among others, the evaluation of the completeness of the underlying data used in management’s calculation and testing the significant assumptions described above. For example, these procedures included evaluating the likelihood of changes in regulatory approval, inspection of Company’s correspondences with the third parties and regulatory agencies, and corroborating inquiries of the Company’s operational personnel in order to support management’s assumptions. We also tested subsequent cash collection for products shipped to third party customers and performed a lookback analysis comparing actual product returns to the reserve established by management. 
+/s/ Ernst & Young LLP 
+We have served as the Company’s auditor since 2020. 
+Jericho, New York 
+March 11, 2021 
+F- 1 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+Shareholders and Board of Directors 
+Chembio Diagnostics, Inc. 
+Hauppauge, New York 
+Opinion on the Consolidated Financial Statements 
+We have audited the accompanying consolidated balance sheet of Chembio Diagnostics, Inc. (the “Company”) and subsidiaries as of December 31, 2019, the related consolidated statements of operations, comprehensive loss, changes in stockholders’ equity, and cash flows the year then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company and subsidiaries at December 31, 2019, and the results of their operations and their cash flows for the year ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America. 
+Change in Accounting Principle 
+On January 1, 2019, the Company changed its method of accounting for leases due to the adoption of Accounting Standards Codification Topic 842, Leases. The effects of the adoption are described in Note 3 to the consolidated financial statements. 
+Basis for Opinion 
+These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. 
+Our audit included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audit provides a reasonable basis for our opinion. 
+/s/ BDO USA, LLP 
+We served as the Company's auditor from 2011 to 2019. 
+Melville, NY 
+March 13, 2020 
+F- 2 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED BALANCE SHEETS 
+AS OF 
+December 31, 
+2020 
+2019 
+- ASSETS - 
+CURRENT ASSETS: 
+Cash and cash equivalents 
+$ 
+23,066,301 
+$ 
+18,271,352 
+Accounts receivable, net of allowance for doubtful accounts of $ 296,793 and $ 62,000 at December 31, 2020 and 2019, respectively 
+3,377,387 
+3,661,325 
+Inventories, net 
+12,516,402 
+9,598,030 
+Prepaid expenses and other current assets 
+778,683 
+693,013 
+TOTAL CURRENT ASSETS 
+39,738,773 
+32,223,720 
+FIXED ASSETS: 
+Property, plant and equipment, net 
+8,688,403 
+5,933,569 
+Finance lease right-of-use assets, net 
+233,134 
+210,350 
+OTHER ASSETS: 
+Operating right-of-use assets, net 
+6,112,632 
+7,030,744 
+Intangible assets, net 
+3,645,986 
+3,914,352 
+Goodwill 
+5,963,744 
+5,872,690 
+Deposits and other assets 
+509,342 
+543,539 
+TOTAL ASSETS 
+$ 
+64,892,014 
+$ 
+55,728,964 
+- LIABILITIES AND STOCKHOLDERS’ EQUITY - 
+CURRENT LIABILITIES: 
+Accounts payable and accrued liabilities 
+$ 
+10,042,790 
+$ 
+5,526,243 
+Deferred revenue 
+1,606,997 
+125,000 
+Notes Payable 
+- 
+180,249 
+Operating lease liabilities 
+642,460 
+568,294 
+Finance lease liabilities 
+58,877 
+41,894 
+TOTAL CURRENT LIABILITIES 
+12,351,124 
+6,441,680 
+OTHER LIABILITIES: 
+Long-term operating lease liabilities 
+6,327,143 
+6,969,603 
+Long-term finance lease liabilities 
+185,239 
+171,953 
+Long-term debt, less current portion, net 
+18,182,158 
+17,644,149 
+Deferred tax liability 
+69,941 
+466,326 
+TOTAL LIABILITIES 
+37,115,605 
+31,693,711 
+COMMITMENTS AND CONTINGENCIES (Note 12) 
+STOCKHOLDERS’ EQUITY: 
+Preferred stock – 10,000,000 shares authorized, none outstanding 
+- 
+- 
+Common stock - $ 0.01 par value; 100,000,000 shares authorized, 20,223,498 and 17,733,617 shares issued and outstanding at December 31, 2020 and 2019, respectively 
+202,235 
+177,335 
+Additional paid-in capital 
+124,961,514 
+95,433,077 
+Accumulated deficit 
+( 97,106,331 
+) 
+( 71,585,003 
+) 
+Treasury stock – 41,141 and 0 shares at cost, at December 31, 2020 and 2019, respectively 
+( 190,093 
+) 
+- 
+Accumulated other comprehensive income 
+( 90,916 
+) 
+9,844 
+TOTAL STOCKHOLDERS’ EQUITY 
+27,776,409 
+24,035,253 
+TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY 
+$ 
+64,892,014 
+$ 
+55,728,964 
+See accompanying notes to consolidated financial statements 
+F- 3 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF OPERATIONS 
+FOR THE YEARS ENDED 
+December 31, 
+2020 
+2019 
+REVENUES: 
+Product revenue 
+$ 
+24,767,149 
+$ 
+28,844,997 
+R&D revenue 
+4,851,562 
+4,025,538 
+Government grant income 
+2,018,924 
+654,744 
+License and royalty revenue 
+832,562 
+938,753 
+TOTAL REVENUES 
+32,470,197 
+34,464,032 
+COSTS AND EXPENSES: 
+Cost of product sales 
+23,874,487 
+22,394,317 
+Research and development expenses 
+9,508,494 
+8,538,416 
+Selling, general and administrative expenses 
+21,037,701 
+16,138,424 
+Severance and related costs 
+1,122,310 
+- 
+Acquisition costs 
+63,497 
+721,465 
+55,606,489 
+47,792,622 
+LOSS FROM OPERATIONS 
+( 23,136,292 
+) 
+( 13,328,590 
+) 
+OTHER (EXPENSE) INCOME: 
+Interest expense, net 
+( 2,841,830 
+) 
+( 846,831 
+) 
+LOSS BEFORE INCOME TAX BENEFIT 
+( 25,978,122 
+) 
+( 14,175,421 
+) 
+Income tax benefit 
+456,794 
+500,292 
+NET LOSS 
+$ 
+( 25,521,328 
+) 
+$ 
+( 13,675,129 
+) 
+Basic and diluted loss per share 
+$ 
+( 1.34 
+) 
+$ 
+( 0.81 
+) 
+Weighted average number of shares outstanding, basic and diluted 
+19,085,691 
+16,954,142 
+See accompanying notes to consolidated financial statements 
+F- 4 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS 
+FOR THE YEARS ENDED 
+December 31, 
+2020 
+2019 
+Net loss 
+$ 
+( 25,521,328 
+) 
+$ 
+( 13,675,129 
+) 
+Other comprehensive loss: 
+Foreign currency translation adjustments 
+( 100,760 
+) 
+( 102,352 
+) 
+COMPREHENSIVE LOSS 
+$ 
+( 25,622,088 
+) 
+$ 
+( 13,777,481 
+) 
+See accompanying notes to consolidated financial statements 
+F- 5 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY 
+FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019 
+Common Stock 
+Additional 
+Paid-in-Capital 
+Amount 
+Treasury Stock 
+Accumulated 
+Deficit 
+Amount 
+AOCI 
+Amount 
+Total 
+Amount 
+Shares 
+Amount 
+Shares 
+Amount 
+Balance at December 31, 2018 
+17,166,459 
+$ 
+171,664 
+$ 
+90,953,788 
+- 
+$ 
+- 
+$ 
+( 57,909,874 
+) 
+$ 
+112,196 
+$ 
+33,327,774 
+Common Stock: 
+Restricted stock issued 
+381,908 
+3,819 
+( 128,081 
+) 
+- 
+- 
+- 
+- 
+( 124,262 
+) 
+Restricted stock compensation 
+- 
+- 
+1,394,812 
+- 
+- 
+- 
+- 
+1,394,812 
+Issuance of common stock for business acquired 
+153,707 
+1,537 
+441,754 
+- 
+- 
+- 
+- 
+443,291 
+Options: 
+Exercised 
+31,543 
+315 
+32,171 
+- 
+- 
+- 
+- 
+32,486 
+Stock option compensation 
+- 
+- 
+261,088 
+- 
+- 
+- 
+- 
+261,088 
+Warrants and Other: 
+Warrant on Term Debt 
+- 
+- 
+1,196,093 
+- 
+- 
+- 
+- 
+1,196,093 
+Contingent Earnout for business acquired 
+- 
+- 
+1,281,452 
+- 
+- 
+- 
+- 
+1,281,452 
+Comprehensive loss 
+- 
+- 
+- 
+- 
+- 
+- 
+( 102,352 
+) 
+( 102,352 
+) 
+Net loss 
+- 
+- 
+- 
+- 
+- 
+( 13,675,129 
+) 
+- 
+( 13,675,129 
+) 
+Balance at December 31, 2019 
+17,733,617 
+$ 
+177,335 
+$ 
+95,433,077 
+- 
+$ 
+- 
+$ 
+( 71,585,003 
+) 
+$ 
+9,844 
+$ 
+24,035,253 
+Common Stock: 
+Issuance of stock, net 
+2,619,593 
+26,196 
+28,410,544 
+- 
+- 
+- 
+- 
+28,436,740 
+Restricted stock issued 
+81,773 
+819 
+128,356 
+- 
+- 
+- 
+- 
+129,175 
+Restricted stock compensation, net 
+( 470,174 
+) 
+( 4,702 
+) 
+617,919 
+- 
+- 
+- 
+- 
+613,217 
+Shares tendered for withholding taxes 
+- 
+- 
+( 296,667 
+) 
+- 
+- 
+- 
+- 
+( 296,667 
+) 
+Options: 
+Exercised 
+5,528 
+55 
+( 55 
+) 
+- 
+Stock option compensation 
+- 
+- 
+480,779 
+- 
+- 
+- 
+- 
+480,779 
+Warrants exercised 
+253,161 
+2,532 
+( 2,532 
+) 
+- 
+- 
+- 
+- 
+- 
+Treasury stock 
+- 
+- 
+190,093 
+( 41,141 
+) 
+( 190,093 
+) 
+- 
+- 
+- 
+Comprehensive loss 
+- 
+- 
+- 
+- 
+- 
+- 
+( 100,760 
+) 
+( 100,760 
+) 
+Net loss 
+- 
+- 
+- 
+- 
+- 
+( 25,521,328 
+) 
+- 
+( 25,521,328 
+) 
+Balance at December 31, 2020 
+20,223,498 
+$ 
+202,235 
+$ 
+124,961,514 
+( 41,141 
+) 
+$ 
+( 190,093 
+) 
+$ 
+( 97,106,331 
+) 
+$ 
+( 90,916 
+) 
+$ 
+27,776,409 
+See accompanying notes to consolidated financial statements 
+F- 6 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+FOR THE YEARS ENDED 
+December 31, 
+2020 
+2019 
+CASH FLOWS FROM OPERATING ACTIVITIES: 
+Cash received from customers and grants 
+$ 
+34,736,133 
+$ 
+37,930,172 
+Cash paid to suppliers and employees 
+( 50,238,409 
+) 
+( 45,655,562 
+) 
+Cash paid for operating leases 
+( 1,139,944 
+) 
+( 632,952 
+) 
+Cash paid for finance leases 
+( 19,987 
+) 
+( 7,892 
+) 
+Interest and taxes, net 
+( 2,225,031 
+) 
+( 689,272 
+) 
+Net cash used in operating activities 
+( 18,887,238 
+) 
+( 9,055,506 
+) 
+CASH FLOWS FROM INVESTING ACTIVITIES: 
+Purchase of businesses, net of cash acquired 
+- 
+( 100,000 
+) 
+Acquisition of and deposits on fixed assets 
+( 3,961,369 
+) 
+( 3,502,540 
+) 
+Patent Application Costs 
+( 205,493 
+) 
+( 297,006 
+) 
+Working capital adjustment related to business combination 
+- 
+145,760 
+Net cash used in investing activities 
+( 4,166,862 
+) 
+( 3,753,786 
+) 
+CASH FLOWS FROM FINANCING ACTIVITIES: 
+Proceeds from sale of common stock, net 
+28,436,740 
+- 
+Proceeds from option exercises 
+- 
+32,486 
+Principal payments for finance leases 
+( 51,166 
+) 
+( 19,875 
+) 
+Payments on debt issuance costs 
+- 
+( 186,313 
+) 
+Payments on note payable 
+( 180,249 
+) 
+( 181,822 
+) 
+Proceeds from issuance of long-term debt, net 
+- 
+18,850,000 
+Stimulus package loan 
+2,978,315 
+- 
+Payment of stimulus package loan 
+( 2,978,315 
+) 
+- 
+Payments of tax withholdings on stock award 
+( 441,723 
+) 
+- 
+Net cash provided by financing activities 
+27,763,602 
+18,494,476 
+Effect of exchange rate changes on cash 
+85,447 
+61,617 
+INCREASE IN CASH AND CASH EQUIVALENTS 
+4,794,949 
+5,746,801 
+Cash and cash equivalents - beginning of the period 
+18,271,352 
+12,524,551 
+Cash and cash equivalents - end of the period 
+$ 
+23,066,301 
+$ 
+18,271,352 
+RECONCILIATION OF NET LOSS TO NET CASH USED IN OPERATING ACTIVITIES: 
+Net Loss 
+$ 
+( 25,521,328 
+) 
+$ 
+( 13,675,129 
+) 
+Adjustments: 
+Depreciation and amortization 
+2,697,126 
+1,916,194 
+Share based compensation 
+1,223,171 
+1,655,900 
+Benefit from deferred tax liability 
+( 396,385 
+) 
+( 513,715 
+) 
+Provision for doubtful accounts 
+270,193 
+20,000 
+Non-cash inventory changes 
+3,543,515 
+- 
+Changes in assets and liabilities, net of effects from acquisitions: 
+Accounts receivable 
+283,939 
+3,764,045 
+Inventories 
+( 6,461,887 
+) 
+( 1,457,612 
+) 
+Prepaid expenses and other current assets 
+( 85,670 
+) 
+64,355 
+Deposits and other assets 
+34,195 
+( 90,624 
+) 
+Accounts payable and accrued liabilities 
+4,043,896 
+( 441,015 
+) 
+Deferred revenue 
+1,481,997 
+( 297,905 
+) 
+Net cash used in operating activities 
+$ 
+( 18,887,238 
+) 
+$ 
+( 9,055,506 
+) 
+Supplemental disclosures for non-cash investing and financing activities: 
+Deposits on manufacturing equipment transferred to fixed assets 
+$ 
+472,651 
+$ 
+430,000 
+Issuance of common stock for net assets of business acquired 
+– 
+443,291 
+Contingent liability earnout 
+1,011,261 
+1,225,000 
+See accompanying notes to consolidated financial statements 
+F- 7 
+Table of Contents 
+NOTE 1 — DESCRIPTION OF BUSINESS: 
+Chembio Diagnostics, Inc. (“Chembio”) and its subsidiaries (collectively with Chembio, the “Company”) develop and commercialize point-of-care rapid tests used for the detection and diagnosis of infectious diseases, including COVID-19, sexually transmitted disease, and fever and tropical disease. Coupled with the Company’s extensive scientific expertise, its novel DPP technology offers broad market applications beyond infectious disease. Chembio’s products are sold globally, directly and through distributors, to hospitals and clinics, physician offices, clinical laboratories, public health organizations, government agencies, and consumers under the Company’s DPP, STAT PAK, SURE CHECK and STAT-VIEW registered trademarks or under the private labels of the Company’s marketing partners. 
+The Company has been expanding its product portfolio based upon its proprietary DPP technology platform that provides high-quality, rapid diagnostic results in 15 to 20 minutes using a small drop of blood from the fingertip or alternative samples. Through advanced multiplexing, the DPP platform can detect up to eight, distinct test results from a single patient sample, which can deliver greater clinical value than other rapid tests. For certain applications, Chembio’s easy-to-use, highly portable, battery-operated DPP Micro Reader optical analyzer then reports accurate results in approximately 15 seconds, making it well-suited for decentralized testing where real-time results enable patients to be clinically assessed while they are still onsite. Objective results produced by the DPP Micro Reader can reduce the possibility of the types of human error that can be experienced in the visual interpretations required by many rapid tests. 
+All DPP tests are developed and manufactured in the United States and are the subject of a range of domestic and global patents and patents pending. 
+During 2020, the Company refocused its business strategy on the development and commercialization of the DPP COVID-19 IgM/IgG System, which consists of a new serological test for COVID-19 and a Micro Reader analyzer. In the twelve months ended December 31, 2020, the Company developed, received regulatory approval in the US, Brazil and Europe, and commercialized the DPP COVID-19 IgM/IgG System, which provided numerical readings for both IgM and IgG levels of antibodies to the virus, and began developing its strategy for a portfolio of products both related to and expanding beyond COVID-19. On June 16, 2020, the U.S. FDA Food and Drug Administration (the “FDA”) revoked the Company’s Emergency Use Authorization (“EUA”) for the DPP COVID-19 System in the U.S., and the Company immediately began developing a revised version. The Company submitted an application for EUA to the FDA for its new rapid antibody test system, DPP SARS-CoV-2 IgM/IgG on September 8, 2020 (the “IgM/IgG EUA”). 
+On December 3, 2020, the Company received from the FDA a letter responding to the IgM/IgG EUA. The response letter stated that, given the volume of EUA requests it has received, the FDA was prioritizing review of EUA requests for tests, taking into account a variety of factors such as the public health need for the product and the availability of the product. The response letter further stated that the FDA determined that review of the IgM/IgG EUA request was not a priority because, for example, authorization of the test would have relatively limited impact on testing accessibility or testing capacity, and therefore the FDA declined to review the IgM/IgG EUA request at that time. 
+On July 6, 2020, the Company received a $ 628,071 grant from the Department of Health and Human Services; Office of the Assistant Secretary for Preparedness and Response; Biomedical Advanced Research and Development Authority, Division of Research Innovation and Ventures (“BARDA”) to assist the Company in developing a COVID-19 point-of-care antigen system using Chembio’s proprietary DPP technology and submitting an application for EUA to the FDA for the system. On October 15, 2020, Chembio submitted the EUA application for the DPP SARS-CoV-2 Antigen test system, which was designed to detect SARS-CoV-2 antigens in only 20 minutes. The DPP SARS-CoV-2 Antigen test system consists of a DPP SARS-CoV-2 Antigen test cartridge, a DPP Micro Reader optical analyzer and a minimally-invasive nasal swab. 
+On December 2, 2020, the Company received a $ 12,691,726 grant from BARDA to support the development and pursuit of FDA EUA for a rapid, multiplex DPP Respiratory Antigen Panel point-of-care test system. The contract also supports preparation of a submission in pursuit of FDA 510(k) clearance for the Company’s rapid DPP SARS-CoV-2 Antigen test system. 
+The DPP Respiratory Antigen Panel test system is intended to provide simultaneous, discrete, and differential detection of Influenza A, Influenza B, and SARS-CoV-2 antigens from a single patient respiratory specimen, such as a nasal or nasopharyngeal swab. It is expected to provide results in approximately 20 minutes and be run on Chembio’s DPP Micro Reader analyzer. The system is intended to enable appropriate clinical management of patients with suspected respiratory infections and assist in the containment of COVID-19 cases during the flu season. 
+In addition to its DPP COVID-19 rapid test products, the Company has a broad portfolio of infectious disease products, which it expects to generate a diminished amount of revenue for the foreseeable future both due to the impact of the global COVID-19 pandemic and while it focuses on the development, manufacture, and commercialization of DPP COVID-19 products. Through Research & Development (“R&D”) Services, the Company is developing tests in collaboration with Takeda Pharmaceutical Company Limited. 
+F- 8 
+Table of Contents 
+NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES: 
+(a) Basis of Presentation: 
+The accompanying consolidated financial statements include the accounts of Chembio and its subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. 
+The Company’s future working capital needs will depend on many factors, including the rate of its business and revenue growth, the timing of its continuing automation of U.S. manufacturing, and the timing of its investment in research and development as well as sales and marketing. If the Company is unable to increase its revenues and manage its expenses in accordance with its operating plan, it may need to reduce the level or slow the timing of the growth plans contemplated by its operating plan, which would likely curtail or delay the growth in its business contemplated by its operating plan and could impair or defer its ability to achieve profitability and generate cash flow, or to seek to raise additional funds through debt or equity financing, strategic relationships, or other arrangements. 
+Certain amounts related to other government income in the prior period financial statements have been reclassified to conform to the presentation of the current period financial statements. 
+(b) Use of Estimates: 
+The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make assumptions and estimates that affect the amounts reported in the consolidated financial statements and accompanying notes. Judgments and estimates of uncertainties are required in applying the Company’s accounting policies in certain areas. Generally, matters subject to estimation and judgment include accounts receivable realization, inventory obsolescence, asset impairments, recognition of revenue, useful lives of intangible and fixed assets, stock-based compensation, and deferred tax asset valuation allowances. Due to the inherent uncertainty involved in making estimates, actual results reported in future periods may be based upon amounts that differ from those estimates. 
+(c) Fair Value of Financial Instruments: 
+The carrying value for cash and cash equivalents, accounts receivable, accounts payable, accrued expenses and other current liabilities approximate fair value due to the immediate or short-term maturity of these financial instruments. Included in cash and cash equivalents is $ 14.8 million and $ 16.0 million as of December 31, 2020 and 2019, respectively, of money market funds that are Level 1 fair value measurements under the hierarchy. The fair value of the Company’s total debt of $ 20 million (carrying value of $ 18.2 million) and $ 20 million (carrying value of $ 17.6 million) as of December 31, 2020 and 2019, respectively, is a Level 2 fair value measurement under the hierarchy, and the carrying value approximates fair value. 
+Fair value measurements of all financial assets and liabilities that are being measured and reported on a fair value basis are required to be classified and disclosed in one of the following three categories: 
+Level 1: 
+Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities; 
+Level 2: 
+Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability; and 
+Level 3: 
+Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). 
+(d) Cash and Cash Equivalents: 
+Cash and cash equivalents are defined as short-term, highly liquid investments with original maturities of three months or less at date of purchase, and include restricted cash of $ 1 million and $ 0 as of December 31, 2020 and 2019, respectively. 
+The Company is contractually obligated to maintain the restricted cash balance on deposit with a bank as security for the bank’s issuance of a guarantee on behalf of the Company for its performance under purchase orders from which the Company received advance payments by a customer. The Company expects that the restriction will be released within the next twelve months.. 
+(e) Concentrations of Credit Risk: 
+Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of cash and trade receivables. The Company places its cash with well-known financial institutions and, at times, may maintain balances in excess of the FDIC insurance limit. The Company monitors the credit ratings of the financial institutions to mitigate this risk. Concentration of credit risk with respect to trade receivables is principally mitigated by the Company’s ability to obtain letters of credit from certain foreign customers and its diverse customer base, both in number of customers and geographic locations. 
+F- 9 
+Table of Contents 
+(f) Inventory: 
+Inventories are stated at the lower of cost or net realizable value with cost being determined using a standard cost method, which approximates average cost. Average cost consists primarily of material, labor and manufacturing overhead expenses (including fixed production-overhead costs). The Company analyzes its inventory levels quarterly and writes down, in the applicable period, inventory that has become obsolete, inventory that has a cost basis in excess of its expected net realizable value and inventory in excess of expected customer demand. The Company also writes off, in the applicable period, the costs related to expired inventory. Costs of purchased inventories are recorded using weighted-average costing. 
+(g) Fixed Assets: 
+Fixed assets are stated at cost, less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the respective assets, which range from three to seven years . Leasehold improvements are amortized over the useful life of the asset or the lease term, whichever is shorter. Deposits paid for fixed assets are capitalized and not depreciated until the related asset is placed in service. 
+( h ) Valuation of Long-Lived Assets and Intangible Assets: 
+Long-lived assets to be held and used are analyzed for impairment whenever events or changes in circumstances indicate that the related carrying amounts may not be recoverable. The Company evaluates at each balance sheet date whether events and circumstances have occurred that indicate possible impairment. If there are indications of impairment, the Company uses future undiscounted cash flows of the related asset or asset grouping over the remaining life in measuring whether the assets are recoverable. In the event such cash flows are not expected to be sufficient to recover the recorded asset values, the assets are written down to their estimated fair value. No impairment of long-lived tangible and intangible assets was recorded for the years ended December 31, 2020 and 2019. 
+( i ) Revenue Recognition: 
+The Company recognizes revenue when the customer obtains control of promised goods or services, in an amount that reflects the consideration the Company expects to receive in exchange for those goods or services. The Company recognizes revenue following the five-step model prescribed under Accounting Standards Update (“ASU”) 2014-09: (i) identify contract(s) with a customer; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and (v) recognize revenue when (or as) the Company satisfies the performance obligation. 
+Product Revenue 
+Revenue from product sales are recognized and commissions are accrued when the customer obtains control of the Company’s product, which occurs at a point in time, typically upon tendering the product to the customer. The Company expenses incremental costs of obtaining a contract as and when incurred because the expected amortization period of the asset that it would have recognized is one year or less or the amount is immaterial. Freight and distribution activities on products are performed when the customer obtains control of the goods. The Company has made an accounting policy election to account for shipping and handling activities that occur either when or after goods are tendered to the customer as a fulfillment activity, and therefore recognizes freight and distribution expenses in cost of product sales. The Company excludes certain taxes from the transaction price (e.g., sales, value added and some excise taxes). 
+The Company’s contracts with customers often include promises to transfer products or services to a customer. Determining whether products and services are considered distinct performance obligations that should be accounted for separately versus together may require judgment. Typical products sold are diagnostic tests and typical services performed are R&D studies. Revenues from product sales are recognized at a point-in-time and revenues from R&D studies are recognized ratably, over the period of the agreement, unless the related performance obligations indicate otherwise. 
+Judgment is required to determine the stand-alone selling price (“SSP”) for each distinct performance obligation. SSP is directly observable and the Company can use a range of amounts to estimate SSP, as it sells products and services separately, and can determine whether there is a discount to be allocated based on the relative SSP of the various products and services, for the various geographies. 
+F- 10 
+Table of Contents 
+The Company’s payment terms vary by the type and location of the Company’s customer and products or services offered. Payment terms differ by jurisdiction and customer but payment is generally required in a term ranging from 30 to 60 days from date of shipment or satisfaction of the performance obligation. 
+Reserves for Discounts and Allowances 
+Revenue from product sales are recorded net of reserves established for applicable discounts and allowances that are offered within contracts with the Company’s customers. The Company’s process for estimating reserves established for these variable consideration components does not differ materially from its historical practices. 
+Product revenue reserves, which are classified as a reduction in product revenue, are generally related to discounts and returns. Estimates of variable consideration and the determination of whether to include estimated amounts in the transaction price are based on all information (historical, current and forecasted) that is reasonably available to the Company, taking into consideration the type of customer, the type of transaction, market events and trends, and the specific facts and circumstances of each arrangement. The transaction price, which includes variable consideration reflecting the impact of discounts, allowances and returns may be subject to constraint and is included in the net sales price only to the extent that it is probable that a significant reversal of the amount of the cumulative revenue recognized will not occur in a future period. Actual amounts may ultimately differ from the Company’s estimates. If actual results vary, the Company adjusts these estimates, which could have an effect on revenue and earnings in the period of adjustment. 
+License and Royalty Revenues 
+The Company receives royalty revenue on sales by its licensee of products covered under patents that the Company owns. The Company does not have future performance obligations under this license arrangement. The Company records revenue based on estimates of the sales that occurred during the relevant period as a component of license and royalty revenue. The relevant period estimates of sales are based on interim data provided by the licensee and analysis of historical royalties that have been paid to the Company, adjusted for any changes in facts and circumstances, as appropriate. Differences between actual and estimated royalty revenue are adjusted for in the period in which they become known, typically the following quarter. Historically, adjustments have not been material when compared to actual amounts paid by licensees. 
+R&D Revenue 
+All contracts with customers are evaluated under the five-step model described above. Such contracts are further described in Note 7 - Revenue. Grants are invoiced and revenue is recognized ratably as that is the depiction of the timing of the transfer of services. The R&D study, which encompasses various phases of product development processes: design feasibility & planning, product development and design optimization, design verification, design validation and process validation, and pivotal studies, is also recognized ratably. 
+For certain contracts that represent non-governmental grants where the funder does not meet the definition of a customer, the Company recognizes revenue when earned in accordance with Accounting Standards Codification (“ASC”) Topic 958. 
+Government Grant Income 
+Chembio often receives government grants in support of R&D activities that are not associated with a customer-vendor relationship and therefore falls outside the scope of ASC 606. Because there is no authoritative guidance under U.S. GAAP on accounting for government grants received, Chembio applies Topic 958 - Not-for-profit entities guidance by analogy. In June 2018, the Financial Accounting Standards Board (the “FASB”) issued ASU 2018-08, Not-for-Profit Entities (Topic 958): Clarifying the Scope and the Accounting Guidance for Contributions Received and Contributions Made. This ASU clarifies the guidance presented in ASC Topic 958, “Not-for-Profit Entities,” for evaluating whether a transaction is reciprocal (i.e., an exchange transaction) or non reciprocal (i.e., a contribution) and for distinguishing between conditional and unconditional contributions. The ASU also clarified the guidance used by entities other than not-for-profits to identify and account for contributions made. Government grants are invoiced and revenue is recognized as milestones are achieved, conditions are removed and approval from grantor is obtained. 
+Contract Liabilities 
+Deferred revenue relates to payments received in advance of performance under the contract. Deferred revenue is recognized as revenue as (or when) the Company performs under the contract. At December 31, 2019, the Company reported $ 0.1 million in deferred revenue of which $ 0.1 million was earned and recognized as R&D, milestone and grant revenue during the year ended December 31, 2020. At December 31, 2020, the Company reported $ 1.6 in deferred revenue, in which $ 0.8 million is expected to be recognized during the three months ending March 31, 2021 and the remainder in the next twelve months . 
+F- 11 
+Table of Contents 
+In July 2020, the Company was awarded a grant of $ 0.6 million from BARDA to develop a SARS-CoV-2 Ag System. The Company earned $ 0.4 million for the year ended December 31,2020 and was recorded as government grant income. 
+In December 2020, the Company was awarded a grant of $ 12.7 million from BARDA to support the development and pursuit of FDA EUA for a rapid, multiplex DPP Respiratory Antigen Panel point-of-care test system. The Company earned $ 1.6 million for the year ended December 31,2020 and was recorded as government grant income.. 
+( j ) Loss Per Share: 
+Basic loss per share is computed by dividing net loss by the weighted average number of shares of the Company assumed to be outstanding during the period of computation. Diluted loss per share is computed using the treasury stock method if the additional shares are dilutive. For all periods presented, basic and diluted loss per share are the same as any additional shares would be anti-dilutive. 
+There were 603,531 and 545,986 restricted shares awards outstanding as of December 31, 2020 and 2019, respectively, that were not included in the calculation of diluted loss per share for the year ended December 31, 2020 and 2019, because their effect would have been anti-dilutive. There were 974,778 and 642,625 options outstanding as of December 31, 2020 and 2019 respectively, that were not included in the calculation of diluted loss per share for the twelve months ended December 31, 2020 and 2019, respectively, because their effect would have been anti-dilutive. 
+(k) Research and Development: 
+Research and Development (R&D) include product development, program management, clinical trials and regulatory costs and are expensed when incurred. Advance payments for goods and services that will be used in future research and development activities are expensed when the activity has been performed or when the goods have been received rather than when the payment is made. 
+(l) Stock-Based Compensation: 
+The Company grants share options to employees, non-employee members of the Company’s board of directors and non-employee consultants as compensation for services performed. Employee and non-employee members of the board of directors’ awards of share-based compensation are accounted for in accordance with ASC 718, Compensation - Stock Compensation, or ASC 718. ASC 718 requires all share-based payments to employees and non-employee directors, including grants of share options, to be recognized in the consolidated statement of operations and comprehensive loss based on their grant date fair values. 
+Using this model, fair value is calculated based on assumptions with respect to (i) the fair value of the Company’s common stock on the grant date; (ii) expected volatility of the Company’s common stock price, (iii) the periods of time over which the optionees are expected to hold their options prior to exercise (expected term), (iv) expected dividend yield on the Company’s common stock, and (v) risk-free interest rates. 
+The grant date fair value of share options is estimated using the Black-Scholes option valuation model. The fair value of restricted stock and performance/restricted stock unit awards are determined on the date of grant or the date of issuance, as applicable. 
+The expected volatility is calculated based on historical data of the Company’s common stock. The expected dividend yield is zero as the Company has never paid dividends and does not currently anticipate paying any in the foreseeable future. Risk-free interest rates are based on quoted U.S. Treasury rates for securities with maturities approximating the option’s expected term. The expected term of share options granted to the optionees is determined using the expected life of the option. 
+Stock based compensation is reduced for actual forfeitures in the period in which the forfeiture occurs and generally recognized on a straight-line basis over the service period of the grant. 
+(m) Income Taxes: 
+The Company accounts for income taxes under an asset and liability approach that recognizes deferred tax assets and liabilities based on the difference between the financial statement carrying amounts and the tax bases of assets and liabilities using enacted tax rates in effect in the years in which the differences are expected to reverse. 
+The Company follows a more-likely-than-not threshold for financial statement recognition and measurement of a tax position taken, or expected to be taken, in a tax return. The guidance relates to, among other things, classification, accounting for interest and penalties associated with tax positions, and disclosure requirements. Any interest and penalties accrued related to uncertain tax positions are recorded in tax expense. 
+F- 12 
+Table of Contents 
+The Company assesses the realizability of its net deferred tax assets on an annual basis. If, after considering all relevant positive and negative evidence, it is more likely than not that some portion or all of the net deferred tax assets will not be realized, the Company will reduce the net deferred tax assets by a valuation allowance. The realization of net deferred tax assets is dependent on several factors, including the generation of sufficient taxable income prior to the expiration of net operating loss carryforwards. 
+( n ) Goodwill and Indefinite-lived Intangible Assets: 
+Goodwill represents the excess of the purchase price the Company paid over the fair value of the net tangible and identifiable intangible assets acquired in the Company’s acquisition. Goodwill is not amortized but rather is tested annually as of the first day of the fiscal fourth quarter, or sooner if the Company believes that indicators of impairment exist. The Company makes a qualitative evaluation about the likelihood of goodwill impairment, which is based on a number of applicable factors. If the Company concludes that it is more likely than not that the carrying value of the applicable reporting unit is greater than its fair value, then it would recognize an impairment charge for the amount by which the carrying value exceeds the reporting unit’s fair value, provided the impairment charge does not exceed the total amount of goodwill allocated to the reporting unit. 
+Indefinite-lived intangible assets are tested for impairment annually during the first day of the fiscal fourth quarter of the year, and when events or changes in circumstances indicate the assets might be impaired. Impairment is indicated when the carrying value of the intangible asset exceeds its fair value. 
+( o ) Allowance for Doubtful Accounts: 
+The Company records allowances for doubtful accounts for the estimated probable losses on uncollectible accounts receivable. The allowance is based upon the credit worthiness of the Company’s customers, the Company’s historical experience, the age of the receivable and current market and economic conditions. Receivables are written off against these allowances in the period they are determined to be uncollectible. 
+( p ) Acquisition Costs: 
+Acquisition costs are expensed when incurred and include primarily professional services, related to acquisition activities. 
+( q ) Foreign Currency Translation: 
+The functional currency of a foreign subsidiary is the local currency. Assets and liabilities of foreign subsidiaries that use a currency other than U.S. dollars as their functional currency are translated to U.S. dollars at end of period currency exchange rates. The consolidated statements of operations of foreign subsidiaries are translated to U.S. dollars at average period currency exchange rates. The effect of translation for foreign subsidiaries is generally reported in other comprehensive income. Foreign transaction gains/losses are immaterial. 
+(r ) Leases: 
+The Company accounts for leases in accordance with ASC 842. The Company determines if an arrangement is a lease at contract inception. A lease exists when a contract conveys the right to control the use of identified property, plant, or equipment for a period of time in exchange for consideration. The definition of a lease embodies two conditions: (1) there is an identified asset in the contract that is land or a depreciable asset (i.e., property, plant, and equipment), and (2) the Company has the right to control the use of the identified asset. The Company accounts for the lease and non-lease components as a single lease component. 
+From time to time the Company enters into direct financing lease arrangements that include a lessee obligation to purchase the leased asset at the end of the lease term, a bargain purchase option, or provides for minimum lease payments with a present value of 90 % or more of the fair value of the leased asset at the date of lease inception. 
+Operating leases where the Company is the lessee are included in right-of-use (“ROU”) assets and lease obligations are included on the Company’s consolidated balance sheets. The lease obligations are initially and subsequently measured at the present value of the unpaid lease payments at the lease commencement date and subsequent reporting periods. 
+F- 13 
+Table of Contents 
+Finance leases where the Company is the lessee are included in ROU assets and lease obligations on the Company’s consolidated balance sheets. The lease obligations are initially measured in the same manner as for operating leases and are subsequently measured at amortized cost using the effective interest method. 
+Key estimates and judgments include how the Company determined (1) the discount rate used to discount the unpaid lease payments to present value, (2) lease term and (3) lease payments. ASC 842 requires a lessee to discount its unpaid lease payments using the interest rate implicit in the lease or, if that rate cannot be readily determined, its incremental borrowing rate. As most of the Company’s leases where it is the lessee do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company’s incremental borrowing rate for a lease is the rate of interest it would have to pay on a collateralized basis to borrow an amount equal to the lease payments under similar terms. The Company uses the implicit rate when readily determinable. 
+The lease term for all of the Company’s leases includes the non-cancellable period of the lease plus any additional periods covered by either a lessee option to extend (or not to terminate) the lease that is reasonably certain to be exercised, or an option to extend (or not to terminate) the lease controlled by the lessor. 
+The ROU asset is initially measured at cost, which comprises the initial amount of the lease liability adjusted for lease payments made at or before the lease commencement date less any lease incentives received. For operating leases, the ROU asset is subsequently measured throughout the lease term at the carrying amount of the lease liability, minus any accrued lease payments, less the unamortized balance of lease incentives received. Lease expense for lease payments is recognized on a straight-line basis over the lease term. 
+For finance leases, the ROU asset is subsequently amortized using the straight-line method from the lease commencement date to the earlier of the end of its useful life or the end of the lease term unless the lease transfers ownership of the underlying asset, or the Company is reasonably certain to exercise an option to purchase the underlying asset. In those cases, the ROU asset is amortized over the useful life of the underlying asset. Amortization of the ROU asset is recognized and presented separately from interest expense on the lease liability. 
+The Company has elected not to recognize ROU assets and lease liabilities for all short-term leases that have a lease term of 12 months or less at lease commencement. Lease payments associated with short-term leases are recognized as an expense on a straight-line basis over the lease term. 
+(s) Recent Accounting Pronouncements Affecting the Company: 
+Recently Adopted 
+ASU 2020-10, Codification Improvements 
+In November 2020, the FASB issued ASU 2020-10, which clarifies various topics in the ASC, including the addition of existing disclosure requirements to the relevant disclosure sections. This update improves consistency by amending the ASC to include all disclosure guidance in the appropriate disclosure sections and clarifies application of various provisions in the ASC by amending and adding new headings, cross referencing to other guidance, and refining or correcting terminology. The Company has evaluated the effects of this standard and determined that the adoption did not have a material impact on the Company’s consolidated financial statements. 
+ASU 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”) 
+In June 2016, the FASB issued ASU 2016-13. ASU 2016-13 provides guidance on measurement of credit losses on financial instruments that changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, held-to-maturity debt securities and loans, and that requires entities to use a new, forward-looking “expected loss” model that is expected to generally result in the earlier recognition of allowances for losses. The Company adopted the standard effective January 1, 2020 and has evaluated the effects of this standard and determined that the adoption did not have a material impact on the Company’s consolidated financial statements. 
+ASU 2018-13, Fair Value Measurement - Disclosure Framework (Topic 820) (“ASU 2018-13”) 
+In August 2018, the FASB issued ASU 2018-13. ASU 2018-13 improves the disclosure requirements on fair value measurements. The updated guidance became effective for fiscal years beginning after December 15, 2019 including interim periods within those years. The Company adopted the standard effective January 1, 2020 and has evaluated the effects of this standard and determined that the adoption did not have a material impact on the Company’s consolidated financial statements. 
+F- 14 
+Table of Contents 
+ASU 2017-4, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (“ASU 2017-4”) 
+In January 2017, the FASB issued ASU 2017-4. ASU 2017-4 simplifies the subsequent measurement of goodwill and eliminates Step 2 from the goodwill impairment test. ASU 2017-4 is effective for annual and interim goodwill tests beginning after December 15, 2019. The Company adopted the standard effective January 1, 2020 and has evaluated the effects of this standard and determined that the adoption did not have a material impact on the Company’s consolidated financial statements. 
+Not Yet Adopted 
+ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes 
+In December 2019, the FASB issued ASU 2019-12. This standard simplifies the accounting for income taxes by eliminating certain exceptions to the guidance in Topic 740 related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences. The new guidance also simplifies aspects of the accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of goodwill and allocating consolidated income taxes to separate financial statements of entities not subject to income tax. ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, with early adoption permitted. Upon adoption, the Company must apply certain aspects of this standard retrospectively for all periods presented while other aspects are applied on a modified retrospective basis through a cumulative-effect adjustment to retained earnings as of the beginning of the fiscal year of adoption. The Company will adopt the standard effective January 1, 2021 and has determined that the adoption will not have a material impact on the Company’s consolidated financial statements. 
+ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting 
+In March 2020, the FASB issued ASC Topic 848. ASC Topic 848 provides relief for impacted areas as it relates to impending reference rate reform. ASC Topic 848 contains optional expedients and exceptions for applying GAAP to debt arrangements, contracts, hedging relationships, and other areas or transactions that are impacted by reference rate reform. This guidance is effective upon issuance for all entities and elections of certain optional expedients are required to apply the provisions of the guidance. The Company will adopt the standard effective January 1, 2021 and has determined that the adoption will not have a material impact on the Company’s consolidated financial statements. 
+ASU 2020-06 - Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging—Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity 
+20 
+On August 5, 2020, the FASB issued ASU 2020-06, which simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity. The ASU is part of the FASB’s simplification initiative, which aims to reduce unnecessary complexity in U.S. GAAP. ASU 2020-06 simplifies the guidance in U.S. GAAP on the issuer’s accounting for convertible debt instruments, requires entities to provide expanded disclosures about “the terms and features of convertible instruments” and how the instruments have been reported in the entity’s financial statements. It also removes from ASC 815-40-25-10 certain conditions for equity classification and amends certain guidance in ASC 260 on the computation of EPS for convertible instruments and contracts on an entity’s own equity. An entity can use either a full or modified retrospective approach to adopt the ASU’s guidance. The ASU’s amendments are effective for smaller public business entities fiscal years beginning after December 15, 2023. The Company continues to assess all potential impact of the standard and will disclose the nature and reason for any elections that the Company makes. 
+NOTE 3 — ACQUISITIONS: 
+Orangelife 
+On November 25, 2019, pursuant to a quota purchase agreement, the Company acquired all of the outstanding shares of Orangelife Comercio e Industria Ltda., or Orangelife, a privately-held Brazilian company, which is an original equipment manufacturer of point-of-care tests approved by the Brazilian Health Surveillance Agency (Agência Nacional de Vigilância Sanitária, or ANVISA) for infectious diseases that include HIV, Hepatitis C, Zika, Chikungunya, and Dengue Fever. Orangelife tests are manufactured in its Rio de Janeiro facility, which is ISO-certified and approved by ANVISA to produce Class II/III/IV medical devices. The purchase price includes the following consideration: 
+● 
+$ 150,000 in cash and 153,707 shares of common stock. 
+● 
+Issuance of 316,456 shares of common stock to the founder and former chief executive officer of Orangelife, based on the transfer and approval of registration of certain of the Company’s products in Brazil prior to November 25, 2022. All of the shares may be deliverable in the event of change in control of Chembio. The number of shares issued was subject to adjustments based upon Orangelife’s working capital at closing. The fair value of the shares on the date of the acquisition was recorded in equity and was valued at $ 1.2 million. 
+F- 15 
+Table of Contents 
+The purchase consideration is subject to routine post-closing adjustments and has been finalized as of December 31, 2020. The acquisition of Orangelife will allow us to expand our commercial presence by offering our products to the state, private, and pharmacy markets in Brazil, in addition to providing local support to our long time customer Bio-Manguinhos, the subsidiary of the Oswaldo Cruz Foundation (Fiocruz) that oversees development and production of vaccines, diagnostics, and biopharmaceuticals, primarily to meet the demands of Brazil’s national public health system. The results of Orangelife’s operations have been reflected in the consolidated financial statements since November 25, 2019. 
+The acquisition was accounted for using the purchase method of accounting. The following table summarizes the allocation of the purchase price to the estimated fair values of the assets acquired and liabilities assumed on the closing date of November 25, 2019: 
+Amount 
+Net current assets 
+$ 
+320,293 
+Property, plant and equipment and other assets 
+226,035 
+Inventory 
+289,205 
+Goodwill 
+986,058 
+Deferred tax liability 
+( 50,000 
+) 
+Other intangible assets (estimated useful life): 
+Trade name ( 0.5 years ) 
+5,000 
+Customer contracts / relationships ( 5 years ) 
+195,000 
+Total consideration 
+$ 
+1,971,591 
+The Company calculated the fair value of the property, plant and equipment based on the net book value of Orangelife as that approximates fair value. The estimated fair value of the trade name, customer contracts/relationships and contingent earnouts were based on discounted cash flows using management estimates. 
+As a result of the consideration paid exceeding the fair value of the net assets acquired, goodwill in the amount of $ 986,058 was recorded in connection with this acquisition, none of which will be deductible for tax purposes. In addition, the Company recorded $ 200,000 in intangible assets associated with the addition of Orangelife’s trade name and customer base. 
+The following represents unaudited pro forma operating results for the year ended December 31, 2019 as if the operations of Orangelife had been included in the Company’s Consolidated Statements of Operations as of January 1, 2019. This pro forma financial information is unaudited and presented for illustrative purposes only and is not necessarily indicative of the operating results that would have occurred if the acquisition of Orangelife and the other transactions contemplated by this acquisition had been completed as of January 1, 2019, nor is it necessarily indicative of the future operating results of Chembio Diagnostics and Orangelife on a combined and consolidated basis. 
+Unaudited Proforma 
+December 31, 2019 
+Total revenues 
+$ 
+35,157,248 
+Net loss 
+$ 
+( 13,654,001 
+) 
+Net loss per common share (basic and diluted) 
+$ 
+( 0.80 
+) 
+NOTE 4 — INVENTORIES: 
+Net inventories consist of the following at December 31: 
+December 31 
+2020 
+2019 
+Raw Materials 
+$ 
+5,955,215 
+$ 
+2,901,319 
+Work in Process 
+2,549,516 
+793,343 
+Finished Goods 
+4,011,671 
+5,903,368 
+$ 
+12,516,402 
+$ 
+9,598,030 
+F- 16 
+Table of Contents 
+NOTE 5 — FIXED ASSETS: 
+Fixed assets consist of the following at December 31: 
+December 31 
+2020 
+2019 
+Machinery and Equipment 
+$ 
+10,996,869 
+$ 
+7,955,511 
+Furniture and Fixtures 
+25,418 
+21,477 
+Computer Equipment 
+446,300 
+416,359 
+Leasehold Improvements 
+3,158,074 
+3,038,469 
+Enterprise Business Systems 
+2,741,806 
+1,830,925 
+Subtotal: 
+17,368,467 
+13,262,741 
+Less: Accumulated Depreciation and Amortization 
+( 8,680,064 
+) 
+( 7,329,172 
+) 
+$ 
+8,688,403 
+$ 
+5,933,569 
+Depreciation expense for the 2020 and 2019 years totaled $ 1,227,860 and $ 933,558 , respectively. 
+As of December 31, 2020 and 2019, the Company has purchased manufacturing equipment that is not yet in use and therefore has not been depreciated, aggregating $ 3,011,273 and $ 1,400,181 , respectively. 
+NOTE 6 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES: 
+Accounts payable and accrued liabilities consist of the following at December 31: 
+December 31 
+2020 
+2019 
+Accounts Payable - suppliers 
+$ 
+5,727,781 
+$ 
+3,144,098 
+Accrued Commissions & Royalties 
+807,708 
+931,760 
+Accrued Payroll 
+277,908 
+231,753 
+Accrued Vacation 
+417,238 
+410,199 
+Accrued Bonuses 
+1,193,985 
+215,000 
+Accrued Professional Fees 
+511,681 
+- 
+Accrued Expenses - Other 
+1,106,489 
+593,433 
+$ 
+10,042,790 
+$ 
+5,526,243 
+NOTE 7 — REVENUE: 
+Deferred Revenue 
+The Company recognizes income from R&D milestones when those milestones are reached and non-milestone contracts and grants when earned. These projects are invoiced after expenses are incurred. Any projects or grants funded in advance are deferred until earned. 
+From time to time the Company may receive prepayment from customers for products to be manufactured and shipped at future dates. Customer payments in advance of the applicable performance obligation are deferred and recognized in accordance with ASC 606. 
+As of December 31, 2020 and 2019, there were $ 1,606,997 and $ 125,000 unearned advanced revenues, respectively. 
+Disaggregation of Revenue 
+The following tables disaggregates total revenues for the period ending December 31, 2020: 
+Exchange 
+Transactions 
+Non-Exchange 
+Transactions 
+Total 
+Net product sales 
+$ 
+24,767,149 
+$ 
+- 
+$ 
+24,767,149 
+R&D revenue 
+4,851,562 
+- 
+4,851,562 
+Government grant income 
+- 
+2,018,924 
+2,018,924 
+License and royalty revenue 
+832,562 
+- 
+832,562 
+$ 
+30,451,273 
+$ 
+2,018,924 
+$ 
+32,470,197 
+Exchange transactions are recognized in accordance with ASC 606, while non-exchange transactions are recognized in accordance with ASU 2018-08. 
+F- 17 
+Table of Contents 
+The following tables disaggregates total revenues for the period ending December 31, 2020 by region: 
+Total 
+Africa 
+$ 
+4,890,370 
+Asia 
+824,488 
+Europe & Middle East 
+9,905,437 
+Latin America 
+9,841,773 
+United States 
+7,008,129 
+$ 
+32,470,197 
+The following tables disaggregates total revenues for the period ending December 31, 2019: 
+Exchange 
+Transactions 
+Non-Exchange 
+Transactions 
+Total 
+Net product sales 
+$ 
+28,844,997 
+$ 
+- 
+$ 
+28,844,997 
+R&D revenue 
+3,321,031 
+704,507 
+4,025,538 
+Government grant income 
+- 
+654,744 
+654,744 
+License and royalty revenue 
+938,753 
+- 
+938,753 
+$ 
+33,104,781 
+$ 
+1,359,251 
+$ 
+34,464,032 
+Exchange transactions are recognized in accordance with ASC 606, while non-exchange transactions are recognized in accordance with ASU 2018-08. 
+The following tables disaggregates total revenues for the period ending December 31, 2019 by region: 
+Total 
+Africa 
+$ 
+7,564,360 
+Asia 
+888,800 
+Europe & Middle East 
+6,498,995 
+Latin America 
+11,808,768 
+United States 
+7,703,109 
+$ 
+34,464,032 
+NOTE 8 — INCOME TAXES: 
+The components of (loss) before income taxes consisted of the following: 
+Year Ending December 31, 
+2020 
+2019 
+United States operations 
+$ 
+( 23,384,133 
+) 
+$ 
+( 12,504,780 
+) 
+International operations 
+( 2,593,989 
+) 
+( 1,670,641 
+) 
+(Loss) before taxes 
+$ 
+( 25,978,122 
+) 
+$ 
+( 14,175,421 
+) 
+T he (benefit from) provision for income taxes for the years ended December 31, 2020 and 2019 is comprised of the following: 
+Year Ending December 31, 
+2020 
+2019 
+Current 
+Federal 
+$ 
+( 66,906 
+) 
+$ 
+- 
+State 
+6,497 
+9,790 
+Foreign 
+- 
+3,633 
+Total current (benefit) provision 
+( 60,409 
+) 
+13,423 
+Deferred 
+Federal 
+- 
+- 
+State 
+- 
+- 
+Foreign 
+( 396,385 
+) 
+( 513,715 
+) 
+Total deferred (benefit) provision 
+( 396,385 
+) 
+( 513,715 
+) 
+Total (benefit) provision 
+$ 
+( 456,794 
+) 
+$ 
+( 500,292 
+) 
+F- 18 
+Table of Contents 
+A reconciliation of the Federal statutory rate to the effective rate applicable to loss before income taxes is as follows: 
+Year Ending December 31, 
+2020 
+2019 
+Federal income tax at statutory rates 
+21.00 
+% 
+21.00 
+% 
+State income taxes, net of federal benefit 
+( 0.02 
+)% 
+( 0.05 
+)% 
+Nondeductible expenses 
+( 0.19 
+)% 
+( 1.00 
+)% 
+Foreign rate differential 
+0.47 
+% 
+0.45 
+% 
+Change in valuation allowance 
+( 19.37 
+)% 
+( 17.51 
+)% 
+Other 
+( 0.13 
+)% 
+0.64 
+% 
+Income tax benefit 
+1.76 
+% 
+3.53 
+% 
+In January 2018, the FASB released guidance on the accounting for tax on the global intangible low-taxed income (“GILTI”) provisions of the Tax Act. The GILTI provisions impose a tax on foreign income in excess of a deemed return on tangible assets of foreign corporations. The guidance allows companies to make an accounting policy election to either (1) account for GILTI as a component of tax expense in the period in which they are subject to the rules (the period cost method), or (ii) account for GILTI in the Company’s measurement of deferred taxes (the deferred method). After completing the analysis of the GILTI provisions, the Company elected to account for GILTI using the period cost method. 
+The Company had an ownership change as described in Internal Revenue Code Sec. 382 during 2004 (“2004 change”). As a result, the Company’s net operating losses prior to the 2004 change of $ 5,832,516 were subject to an annual limitation of $ 150,608 and for the first five (5) years are entitled to a BIG (Built-In-Gains) of $ 488,207 per year. These net operating losses expire in 2020 through 2024. 
+The Company had a second ownership change during 2006 (“2006 change”). The net operating losses incurred between the 2004 change and the 2006 change of $ 8,586,861 were subject to an annual limitation of $ 1,111,831 and for the first five (5) years are entitled to a BIG of $ 1,756,842 per year. These net operating losses expire in 2024 through 2026. 
+After applying the above limitations, at December 31, 2020, the Company has post-change net operating loss carry-forwards of approximately $ 27,001,828 which expire between 2021 and 2037 and $ 35,840,768 which do not expire. In addition, the Company has research and development tax credit carryforwards of approximately $ 1,696,870 for the year ended December 31, 2020 , which expire between 2021 and 2036. 
+The Company has state net operating loss carryforwards of approximately $ 3,511,090 which generally expire between 2035 and 2039. The Company has foreign net operating loss carryforwards of approximately $ 5,598,852 which generally expire between 2025 and 2026. 
+2020 
+2019 
+Inventory reserves 
+$ 
+461,709 
+$ 
+196,193 
+Accrued expenses 
+130,291 
+105,323 
+Net operating loss carry-forwards 
+14,844,798 
+10,079,317 
+Research and development credit 
+1,696,870 
+1,679,495 
+Stock-based compensation 
+398,900 
+581,053 
+602,187 
+- 
+Lease obligations 
+1,583,814 
+1,646,584 
+Depreciation 
+- 
+44,993 
+Total deferred tax assets 
+19,718,569 
+14,332,958 
+Right-of-use assets 
+( 1,340,914 
+) 
+( 1,538,129 
+) 
+Depreciation 
+( 254,366 
+) 
+- 
+Intangibles 
+( 821,363 
+) 
+( 921,807 
+) 
+Total deferred tax liabilities 
+( 2,416,643 
+) 
+( 2,459,936 
+) 
+Net deferred tax assets before valuation allowance 
+17,301,926 
+11,873,022 
+Less valuation allowances 
+( 17,371,867 
+) 
+( 12,339,348 
+) 
+Net noncurrent deferred tax liabilities 
+$ 
+( 69,941 
+) 
+$ 
+( 466,326 
+) 
+The Company does not provide for U.S. income taxes on unremitted earnings of foreign subsidiaries as its present intention is to reinvest the unremitted earnings in the Company’s foreign operations. At December 31, 2020 there were no unremitted earnings of foreign subsidiaries. 
+Interest and penalties, if any, related to income tax liabilities are included in income tax expense. As of December 31, 2020, the Company does not have a liability for uncertain tax positions. 
+F- 19 
+Table of Contents 
+The Company files Federal and state income tax returns, Chembio Germany files in Germany, Chembio Brazil files in Brazil and Chembio Malaysia files in Malaysia and has been on tax holiday which expired on December 31, 2018. With few exceptions, tax years for fiscal 2017 through 2020 are open and potentially subject to examination by federal, state and foreign taxing authorities. 
+On March 27, 2020, the Coronavirus Aid, Relief, and Economic Security Act, (“CARES Act”), was enacted in response to the COVID-19 pandemic. The CARES Act, among other things, permits NOL carryovers and carrybacks to offset 100% of taxable income for taxable years beginning before 2021. In addition, the CARES Act allows NOLs incurred in tax years 2018, 2019, and 2020 to be carried back to each of the five preceding taxable years. In addition to the NOL changes, the CARES Act contains modifications on the limitation of business interest for tax years beginning in 2019 and 2020. The modifications to Section 163(j) increase the allowable business interest deduction from 30% of adjusted taxable income to 50% of adjusted taxable income. This modification did not effect the Company’s interest expense limitation. Overall the CARES ACT did not have a significant impact on the Company since it maintains a full valuation allowance. 
+NOTE 9 — STOCKHOLDERS’ EQUITY: 
+(a) 
+Common Stock 
+During 2020, options to purchase 36,000 shares of the Company’s common stock were exercised for 5,528 shares of common stock , net of tax withholdings, at an exercise prices of $ 6.30 . During 2019, options to purchas e 54,343 shares of the Company’s common stock were exercised for 31,543 shares of common stock at an exercise prices ranging from $ 3.48 to $ 4.35 in each case by surrendering options or shares of common stock already owne d. 
+In April 2020, the Company closed on an underwritten public offering of 619,593 shares of its common stock, including the underwriter’s exercise of its overallotment of 281,125 shares, at $ 11.75 per share. The net proceeds of the offering, after deducting the underwriter’s discounts and other offering expenses payable by the Company, was approximately $ 28.4 million. 
+(b) 
+Preferred Stock 
+The Company has 10,000,000 shares of preferred stock authorized and none outstanding. These shares can become issuable upon an approved resolution by the board of directors and the filing of a Certificate of Designation with the state of Nevada. 
+(c) 
+Options, Restricted Stock, and Restricted Stock Units 
+T he Board of Directors or its Compensation Committee may authorize the Company’s issuance of options, restricted stock, restricted stock units and other equity awards to officers, employees, directors, consultants and other service providers pursuant to the Company’s 2019 Omnibus Incentive Plan or otherwise . 
+(d) 
+Warrants 
+As of December 31, 2020, th e Company has no warrants outstanding to purchase shares of common stock as further discussed in Note 14 – Warrants. 
+F- 20 
+Table of Contents 
+NOTE 10 — EQUITY INCENTIVE PLANS: 
+Effective June 3, 2008, the Company’s stockholders voted to approve the 2008 Stock Incentive Plan (“SIP”), with 625,000 shares of common stock available to be issued. At the Annual Stockholder Meeting on September 22, 2011 the Company’s stockholders voted to approve an increase to the shares of common stock issuable under the SIP by 125,000 to 750,000 . Under the terms of the SIP, which expired during 2018, the Board of Directors or its Compensation Committee had the discretion to select the persons to whom awards were to be granted. Awards could be stock options, restricted stock and/or restricted stock units (“Equity Award Units”). The awards became vested at such times and under such conditions as determined by the Board or its Compensation Committee. Cumulatively through December 31, 2020, there were 694,000 options expired, forfeited or exercised, and at December 3 1, 2020, 56,000 options were outstanding. No Equity Award Units were available to be issued under the SIP. 
+Effective June 19, 2014, the Company’s stockholders voted to approve the 2014 Stock Incentive Plan (“SIP14”), with 800,000 shares of common stock available to be issued. Under the terms of the SIP14, the Board or its Compensation Committee has the discretion to select the persons to whom awards are to be granted. Awards can be in the form of Equity Award Units. The awards become vested at such times and under such conditions as determined by the Board or its Compensation Committee. Cumulatively through December 31, 2020, there were there were 514,782 options expired, forfeited or exercised. At December 31, 2020, 264,157 options were outstanding and 0 Equity Award Units are available to be issued under the SIP14. Following the approval of the 2019 Plan (defined below), any Equity Award Units outstanding under the SIP14 remain subject to and be paid under the SIP14, and any shares subject to outstanding awards under the SIP14 that expire, terminate, or are surrendered or forfeited for any reason without issuance of shares automatically become available for issuance under the 2019 Plan . 
+Effective June 18, 2019, the Company’s stockholders voted to approve the 2019 Omnibus Incentive Plan (“2019 Plan”), with 2,400,000 shares of common stock available to be issued. In addition, shares of Common Stock underlying any outstanding award granted under the 2019 Plan that, following the effective date of the 2019 Plan, expires, or is terminated, surrendered or forfeited for any reason without issuance of such shares shall be available for the grant of new awards under the 2019 Plan. Under the terms of the 2019 Plan, the Board or its Compensation Committee has the discretion to select the persons to whom awards are to be granted. Awards can be in the form of options, stock appreciation rights, restricted stock, restricted stock units, or other stock-based awar d’s under the 2019 Plan (collectively, “2019 Equity Units”). The awards become vested at such times and under such conditions as determined by the Board or its Compensation Committee. Cumulatively through December 31, 2020, 489,294 2019 Equity Units have been exercised or forfeited. At December 31, 2020, 1,024,563 2019 Equity Units were outstanding, and 1,506,226 2 019 Equity Units were available to be awarded under the 2019 Plan . 
+The Company’s results for the years ended December 31, 2020 and 2019 include stock-based compensation expense totaling $ 1,098,698 and $ 1,655,900 , respectively. Such amounts have been included in the Consolidated Statements of Operations within cost of product sales ($ 6,300 and $ 10,806 , respectively), research and development ($ 386,016 and $ 228,597 , respectively) and selling, general and administrative expenses ($ 706,382 and $ 1,416,497 , respectively). 
+Stock option compensation expense in the years ended December 31, 2020 and 2019 represents the estimated fair value of options outstanding, which is being amortized on a straight-line basis over the requisite vesting period of the entire award. The stock compensation expense were $ 480,779 and $ 351,556 in December 31, 2020 and 2019, respectively. 
+The fair value of restricted stock and performance/restricted stock unit awards are determined on the date of grant or the date of issuance, as applicable. Stock-based compensation expense for stock options is calculated using the Black-Scholes valuation model. Stock based compensation is reduced for actual forfeitures in the period in which the forfeiture occurs and generally recognized on a straight-line basis over the service period of the grant. During the year ended December 31, 2020 and 2019, 486,488 and 0 shares of restricted stock were forfeited, respectively. During the year ended December 31, 2020 and 2019, 123,127 and 0 options were forfeited, respectively . 
+The weighted-average assumptions made in calculating the fair values of options are as follows for the respective years ended December 31: 
+2020 
+2019 
+Expected term (in years) 
+6.29 
+n/a 
+Expected volatility 
+46.21 
+% 
+n/a 
+Expected dividend yield 
+0 
+n/a 
+Risk-free interest rate 
+1.30 
+% 
+n/a 
+F- 21 
+Table of Contents 
+The following table provides stock option activity for the years ended December 31, 2020 and 2019: 
+Number 
+of Shares 
+Weighted 
+Average 
+Exercise Price 
+per Share 
+Weighted 
+Average 
+Remaining 
+Contractual Term 
+Aggregate 
+Intrinsic 
+Value 
+Outstanding at December 31, 2019 
+642,625 
+$ 
+5.79 
+2.57 years 
+$ 
+285,925 
+Granted 
+726,280 
+$ 
+2.59 
+- 
+Exercised 
+36,000 
+$ 
+6.30 
+95,976 
+Forfeited/expired/cancelled 
+358,127 
+$ 
+2.44 
+- 
+Outstanding at December 31, 2020 
+974,778 
+$ 
+4.12 
+5.19 years 
+$ 
+1,520,910 
+Exercisable at December 31, 2020 
+257,211 
+$ 
+7.42 
+2.87 years 
+$ 
+- 
+The following table summarizes information about stock options outstanding at December 31, 2020: 
+Stock Options Outstanding 
+Stock Options Exercisable 
+Range of 
+Exercise Prices 
+Shares 
+Outstanding 
+Average 
+Remaining 
+Contract Life 
+(Year) 
+Weighted 
+Average 
+Exercise 
+Price 
+Aggregate 
+Intrinsic 
+Value 
+Shares 
+Exercisable 
+Weighted 
+Average 
+Exercise 
+Price 
+Aggregate 
+Intrinsic 
+Value 
+1 to 2.79999 
+636,364 
+6.21 
+$ 
+2.36 
+$ 
+1,520,910 
+- 
+$ 
+- 
+$ 
+- 
+2.8 to 4.59999 
+- 
+- 
+- 
+- 
+- 
+- 
+- 
+4.6 to 6.39999 
+83,664 
+4.25 
+5.53 
+- 
+39,961 
+5.53 
+- 
+6.4 to 8.19999 
+207,875 
+3.05 
+7.31 
+- 
+189,125 
+7.22 
+- 
+8.2 to 12 
+46,875 
+2.60 
+11.45 
+- 
+28,125 
+11.45 
+- 
+Total 
+974,778 
+5.19 
+$ 
+4.12 
+$ 
+1,520,910 
+257,211 
+$ 
+7.42 
+$ 
+- 
+As of December 31, 2020, there was $ 736,339 of net unrecognized compensation cost related to stock options that are not vested, which is expected to be recognized over a weighted average period of approximately 2.11 years. The total fair value of shares vested during the year ended December 31, 2020, was $ 326,630 . 
+The following table summarizes information about restricted stock and restricted stock units outstanding as of December 31, 2020: 
+Number of 
+Shares & Units 
+Weighted 
+Average 
+Grant Date 
+Fair Value 
+Unvested at December 31, 2019 
+545,986 
+$ 
+7.47 
+Granted 
+656,759 
+2.75 
+Vested 
+112,726 
+5.63 
+Forfeited/expired/cancelled 
+486,488 
+6.43 
+Unvested at December 31, 2020 
+603,531 
+3.08 
+As of December 31, 2020, there was $ 1,215,441 of net unrecognized compensation cost related to restricted stock and restricted stock units that are not vested, which is expected to be recognized over a weighted average period of approximately 1.8 years. Stock based compensation cost related to restricted stock and restricted stock units recognized during the years ended December 31, 2020 and 2019 was $ 617,919 and $ 1,394,814 , respectively. 
+NOTE 11 — GEOGRAPHIC INFORMATION AND ECONOMIC DEPENDENCY: 
+The Company produces only one group of similar products known collectively as “rapid medical tests,” and i t operates in a single operating segment. Product revenue by geographic area are as follow s: 
+Year Ending December 31, 
+2020 
+2019 
+Africa 
+$ 
+4,890,370 
+$ 
+7,564,360 
+Asia 
+824,488 
+888,800 
+Europe & Middle East 
+5,274,927 
+3,781,761 
+Latin America 
+9,841,772 
+11,808,767 
+United States 
+3,935,592 
+4,801,309 
+$ 
+24,767,149 
+$ 
+28,844,997 
+F- 22 
+Table of Contents 
+Long-lived assets by geographic area are as follows: 
+2020 
+2019 
+Asia 
+$ 
+326,267 
+$ 
+393,299 
+Europe & Middle East 
+147,692 
+165,029 
+Latin America 
+14,719 
+60,527 
+United States 
+8,199,725 
+5,314,715 
+$ 
+8,688,403 
+$ 
+5,933,569 
+NOTE 12 — COMMITMENTS, CONTINGENCIES AND CONCENTRATIONS: 
+a) 
+Employment Contracts: 
+The Company has multi-year contracts with two key employees. The contracts call for salaries presently aggregating $ 843,292 per year, and they expire in December 2021 and December 2022 . The following table is a schedule of future minimum salary commitments: 
+2021 
+$ 
+843,292 
+2022 
+460,000 
+2023 
+- 
+b) 
+Benefit Plan: 
+The Company has a 401(k) plan established for its employees whereby it matches 40 % of the first 5 % (or 2 % of salary) that an employee contributes to the plan. Matching contribution expenses totaled $ 87,377 and $ 93,892 for the years ended December 31, 2020 and 2019, respectively. 
+c) 
+Leases: 
+The Company leases facilities in New York, Germany, Malaysia, and Brazil, and certain equipment. 
+The Company’s facility leases generally include optional renewal periods. Upon entering into a new facility lease, the Company evaluates the leasehold improvements and regulatory requirements related to its operations in that location. To the extent that the initial lease term of the related facility lease is less than the useful life of the leasehold improvements and potential regulatory costs associated with moving the facility, the Company concludes that it is reasonably certain that a renewal option will be exercised, and thus that renewal period is included in the lease term and the related payments are reflected in the right-of-use asset and lease liability. 
+The Company’s leases generally include fixed rental payments with defined annual increases. While certain of the Company’s leases are gross leases, the majority of the Company’s leases are net leases in which the Company makes separate payments to the lessor based on the lessor’s property and casualty insurance costs, the property taxes assessed on the property, and a portion of the common area maintenance where applicable. The Company has elected the practical expedient not to separate lease and nonlease components for all of the Company’s facility leases. 
+The components of lease expense were as follows: 
+Year Ended 
+December 31, 2020 
+Year Ended 
+December 31, 2019 
+Operating lease expense 
+$ 
+1,669,105 
+$ 
+1,655,573 
+Finance lease cost 
+Amortization of right-of-use assets 
+$ 
+58,414 
+$ 
+23,372 
+Interest on lease liabilities 
+19,986 
+7,892 
+Total finance lease expense 
+$ 
+78,400 
+$ 
+31,264 
+Supplemental cash flow and other information related to leases were as follows: 
+Year Ended 
+December 31, 2020 
+Year Ended 
+December 31, 2019 
+Cash paid for amounts included in the measurement of lease liabilities: 
+Operating cash flows for operating leases 
+$ 
+1,139,944 
+$ 
+632,952 
+Operating cash flows for finance leases 
+19,987 
+7,892 
+Financing cash flows for finance leases 
+51,166 
+19,875 
+Right-of-use assets obtained in exchange for lease obligations: 
+7,892 
+Operating leases 
+$ 
+- 
+$ 
+7,030,744 
+Finance leases 
+69,528 
+210,350 
+F- 23 
+Table of Contents 
+Supplemental balance sheet information related to leases was as follows: 
+December 31, 2020 
+December 31, 2019 
+Finance Leases 
+Finance lease right of use asset 
+$ 
+315,154 
+$ 
+233,722 
+Accumulated depreciation 
+( 82,020 
+) 
+( 23,372 
+) 
+Finance lease right of use asset, net 
+$ 
+233,134 
+$ 
+210,350 
+Current portion of finance lease liability 
+58,877 
+41,894 
+Finance lease liability 
+185,239 
+171,953 
+Total finance lease liabilities 
+$ 
+244,116 
+$ 
+213,847 
+Weighted Average Remaining Lease Term 
+Operating leases 
+9.0 years 
+9.3 years 
+Finance leases 
+3.7 years 
+4.8 years 
+Weighted Average Discount Rate 
+Operating leases 
+8.58 
+% 
+8.67 
+% 
+Finance leases 
+8.18 
+% 
+7.00 
+% 
+During 2019, the Company executed an operating sublease related to its former Holbrook, New York facility. The sublease ran conterminously with the base lease in Holbrook, for which the Company was primarily responsible until the end of the lease term in April 2020. 
+Maturities of lease liabilities as of December 31, were as follows. 
+December 31, 2020 
+December 31, 2019 
+Operating 
+Leases 
+Finance 
+Leases 
+Operating 
+Leases 
+Finance 
+Leases 
+2021 
+$ 
+1,209,787 
+$ 
+76,904 
+$ 
+1,205,161 
+$ 
+55,536 
+2022 
+1,057,757 
+76,904 
+1,209,787 
+55,536 
+2023 
+1,026,272 
+76,904 
+1,057,757 
+55,536 
+2024 
+1,018,875 
+49,136 
+1,026,272 
+55,536 
+2025 
+1,049,442 
+5,755 
+1,018,875 
+27,767 
+Thereafter 
+4,724,445 
+- 
+5,773,887 
+- 
+Total lease payments 
+$ 
+10,086,578 
+$ 
+285,603 
+$ 
+11,291,739 
+$ 
+249,911 
+Less: imputed interest 
+( 3,116,975 
+) 
+( 41,487 
+) 
+( 3,753,842 
+) 
+( 36,064 
+) 
+Total 
+$ 
+6,969,603 
+$ 
+244,116 
+$ 
+7,537,897 
+$ 
+213,847 
+d) 
+Economic Dependency: 
+The following table discloses product sales the Company had to customers that purchased in excess of 10% of the Company’s net product sales for the periods indicated: 
+For The Years Ended 
+Accounts Receivable 
+December 31, 2020 
+December 31, 2019 
+December 31, 
+2020 
+December 31, 
+2019 
+Net Sales 
+% of Net Sales 
+Net Sales 
+% of Net Sales 
+Customer 1 
+$ 
+6,224,737 
+25.1 
+% 
+$ 
+11,263,573 
+39 
+% 
+$ 
+522,218 
+$ 
+941,962 
+Customer 2 
+2,955,312 
+11.9 
+% 
+5,782,543 
+20 
+% 
+1,987 
+16,033 
+Customer 3 
+2,956,945 
+11.9 
+% 
+* 
+* 
+* 
+* 
+Revenue includes product sales only, while accounts receivable reflects the total due from the customer, including freight. 
+F- 24 
+Table of Contents 
+The following table discloses purchases the Company made form vendors in excess of 10% of the Company’s net purchases for the periods indicated: 
+For The Years Ended 
+Accounts Payable 
+December 31, 2020 
+December 31, 2019 
+December 
+31, 2020 
+December 
+31, 2019 
+Purchases 
+% of Purc. 
+Purchases 
+% of Purc. 
+Vendor 1 
+$ 
+2,222,182 
+13.0 
+% 
+* 
+* 
+$ 
+222,588 
+* 
+In the tables above, an asterisk (*) indicates that indicates that sales, accounts receivable, purchases or accounts payable, as applicable to the tabular column, did not exceed 10% for the period indicated. 
+The Company purchases materials pursuant to intellectual property rights agreements that are important components in its products. Management believes that other suppliers could provide similar materials on comparable terms. A change in suppliers, however, could cause a delay in manufacturing and a possible loss of sales, which could adversely affect operating results. 
+e) 
+Litigation: 
+Employee Litigation 
+John J. Sperzel III, our former chief executive officer, filed suit in the United States District Court in Maine asserting a right to exercise certain options to purchase, for an aggregate exercise price of $ 943,126 , a total of 266,666 shares of common stock that were vested when he resigned on January 3, 2020. Under their terms, those options were exercisable for a period of thirty days after his service to our company ended. The compensation committee of the board, acting in its discretion in accordance with the terms of the underlying equity incentive plans, has determined that Sperzel’s attempt to exercise the options following the thirty day period was not valid. The Court has dismissed Sperzel’s lawsuit for lack of personal jurisdiction in Maine. If Sperzel refiles the lawsuit in another jurisdiction, Chembio intends to vigorously defend against any claim by Mr. Sperzel that he continues to have a right to exercise any options. 
+Stockholder Litigation 
+Putative Stockholder Securities Class Action Litigation 
+As we reported previously, four purported securities class action lawsuits were filed by alleged stockholders of our Company in the United States District Court for the Eastern District of New York: 
+● 
+Sergey Chernysh v. Chembio Diagnostics, Inc., Richard L. Eberly, and Gail S. Page, filed on June 18, 2020, which we refer to as the Chernysh case; 
+● 
+James Gowen v. Chembio Diagnostics, Inc., Richard L. Eberly, and Gail S. Page, filed on June 22, 2020, which we refer to as the Gowen case; 
+● 
+Anthony Bailey v. Chembio Diagnostics, Inc. Richard J. Eberly, Gail S. Page, and Neil A. Goldman, filed on July 3, 2020, which we refer to as the Bailey case; and 
+● 
+Special Situations Fund III QP, L.P., Special Situations Cayman Fund, L.P., and Special Situations Private Equity Fund, L.P. v. Chembio Diagnostics, Inc., Richard Eberly, Gail S. Page, Robert W. Baird & Co. Inc. and Dougherty & Company LLC, filed August 17, 2020, which we refer to as the Special Situations Funds case. 
+The plaintiffs in each of the cases alleged claims under Section 10(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), Rule 10b-5 thereunder, and Section 20(a) of the Exchange Act. Special Situations Fund III QP, L.P., Special Situations Cayman Fund, L.P., and Special Situations Private Equity Fund, L.P. (together, the “Special Situations Funds”) also asserted claims under Sections 11, 12(a)(2) and 15 of the Securities Act of 1933 (the “Securities Act”) relating to Chembio’s May 2020 public offering. 
+We and the plaintiffs entered into court-approved stipulations relieving the defendants of the obligation to respond to the complaints in these cases pending the designation of a lead plaintiff pursuant to the Private Securities Litigation Reform Act of 1995. Eight motions for appointment as lead plaintiff were filed by various prospective lead plaintiffs. However, all but two of these motions were withdrawn or otherwise abandoned, leaving before the Court two motions for appointment as lead plaintiff -- one filed by the Special Situations Funds, and one by Municipal Employees’ Retirement System of Michigan (“MERS”). By Order entered December 29, 2020, Magistrate Judge Lindsay consolidated the cases and appointed the Special Situations Funds and MERS as co-lead plaintiffs, and their respective counsel as co-lead counsel. The consolidated cases are now pending under the caption “In re Chembio Diagnostics, Inc. Securities Litigation.” 
+F- 25 
+Table of Contents 
+The Special Situations Funds and MERS (together “Lead Plaintiffs”) filed their Consolidated Amended Complaint (“CAC”) on February 12, 2021. In summary, the CAC purports to allege claims based on assertedly false and misleading statements and omissions concerning the performance of the DPP COVID-19 IgM/IgG System, as well as an asserted failure to timely disclose that the Emergency Use Authorization that had been granted by the Food and Drug Administration with respect to the System “was -- or was at an increased risk of -- being revoked.” The CAC names as defendants the Company, Richard L. Eberly, Gail S. Page, Neil A. Goldman, Javan Esfandiari, Katherine L. Davis, Dr. Mary Lake Polan, Dr. John Potthoff, and the underwriters for the Company’s May 2020 public offering, Robert W. Baird & Co., Inc. and Dougherty & Company LLC. 
+The CAC purports to assert five counts under the Securities Act and the Exchange Act of 1934. Counts I through III are brought under the Securities Act, allegedly on behalf of a purported class consisting of all persons who purchased Chembio common stock directly in or traceable to the Company’s May 2020 offering pursuant to the Company’s Form S-3 Registration Statement and its Prospectus and Prospectus Supplement dated May 7, 2020 (the “Securities Act Class”). Count I purports to allege a claim for violation of Section 11 of the Securities Act against all defendants other than Messrs. Eberly and Esfandiari. Count II purports to allege a claim for violation of Section 12 of the Securities Act against all defendants other than Messrs. Eberly and Esfandiari. Count III purports to allege a claim under Section 15 of the Securities Act against Ms. Davis, Dr. Polan, Dr. Potthoff, Ms. Page, and Mr. Goldman. 
+Counts IV and V are alleged claims under the Exchange Act on behalf of a purported class consisting of all persons who purchased Chembio securities on the open market between March 12, 2020 and June 16, 2020, inclusive (the “Exchange Act Class”). Count IV purports to allege a claim for violation of Section 10(b) of the Exchange Act and Rule 10b-5 thereunder against the Company, Mr. Eberly, Ms. Page, Mr. Goldman, and Mr. Esfandiari. Count V purports to allege a claim under Section 20(a) of the Exchange Act against Mr. Eberly, Ms. Page, Mr. Goldman, and Mr. Esfandiari. 
+Lead Plaintiffs seek, on behalf of the Securities Act Class and the Exchange Act Class, among other things, an award of damages in an amount to be proven at trial, as well as an award of reasonable costs, including attorneys’ fees and expenses, expert fees, pre-judgment and post-judgment interest, and such other relief as the court deems just and proper. The Lead Plaintiffs also seeks rescission “or a rescissory measure of damages” on behalf of the Securities Act Class as to Count II. 
+Pursuant to an Order entered by the Court on January 29, 2021, any defendant wishing to move against the amended complaint was required to file, by February 18, 2021, a letter requesting a pre-motion conference. On that date, the defendants submitted letters to the Court requesting a pre-motion conference regarding anticipated motions to dismiss the CAC, and Lead Plaintiffs responded on February 24, 2021. In its January 29, 2021 Order, the Court indicated that it would consider a briefing schedule on motions to dismiss after it had received and reviewed the parties’ correspondence. 
+On March 5, 2021, the Court entered an Order in which the Court advised the parties that it had determined that a pre-motion conference was not necessary and established a briefing schedule on the defendants’ anticipated motions to dismiss. Pursuant to that schedule, defendants’ motions and supporting papers are due to be filed no later than March 19, 2021, the Lead Plaintiffs’ opposition papers are due to be filed no later than April 2, 2021, and the defendants’ reply papers are due to be filed no later than April 9, 2021. We have agreed with Plaintiffs’ counsel to a modification of the schedule such that defendants’ motions and supporting papers would be due to be filed no later than March 26, 2021, the Lead Plaintiffs’ opposition papers would be due to be filed no later than April 16, 2021, and the defendants’ reply papers would be due to be filed no later than April 30, 2021. This schedule modification is subject to the Court’s approval. 
+Putative Stockholder Derivative Litigation 
+On September 11, 2020, a putative stockholder derivative action was filed purportedly on our Company’s behalf in the United States District Court for the Eastern District of New York captioned Karen Wong, derivatively on behalf of Chembio Diagnostics, Inc., Plaintiff v. Richard L. Eberly, Gail S. Page, Neil A. Goldman, Javan Esfandiari, Katherine L. Davis, Mary Lake Polan, and John G. Potthoff, Defendants, and Chembio Diagnostics, Inc., Nominal Defendant, which we refer to as the Wong complaint. The Wong complaint purports to assert a claim for violation of Section 14(a) of the Exchange Act and Rule 14a-9 thereunder based on ostensibly false and misleading statements and omissions concerning our rapid COVID-19 antibody test in the proxy statement disseminated in advance of our Annual Meeting of Stockholders held on July 28, 2020. The Wong complaint also asserts claims against the individual defendants for purported breaches of fiduciary duties owed to our Company, as well as unjust enrichment. 
+The Wong complaint requests a declaration that the individual defendants have breached or aided and abetted the breach of their fiduciary duties to our Company, an award of damages to our Company, restitution, and an award of the plaintiff’s costs and disbursements in the action, including reasonable attorneys’ and experts’ fees, costs and expenses, and improvements to our Company’s corporate governance and internal procedures regarding compliance with laws. Pursuant to a stipulation by which the individual defendants in the Wong action agreed to waive service of process, the Court ordered that the time for defendants to answer or otherwise respond to the complaint be extended to November 19, 2020. The parties subsequently entered into a stipulation for a stay of proceedings in the Wong action pending final disposition of motions to dismiss the pending putative class action litigation, subject to certain conditions. The Court entered an order granting the requested stay on November 3, 2020. 
+Commercial Litigation 
+Chembio Diagnostic Systems Inc. (“Chembio”) and BioSure (UK) Ltd (“BioSure”) entered into the BioSure Sure Check® HIV 1 / 2 Assay OTC Agreement dated April 2, 2014, and as subsequently amended (the “Distribution Agreement”). Pursuant to the Distribution Agreement, BioSure acquired the right to sell bundled products in the UK containing Chembio’s Sure Check® HIV 1 / 2 pouched tests. The Distribution Agreement terminated on April 1, 2019. On September 16, 2019, Chembio initiated arbitration in New York, USA. Chembio alleges that BioSure (1) breached various provisions of the Distribution Agreement, (2) misappropriated Chembio’s trade secrets, (3) engaged in deceptive business acts and practices, and (4) breached the implied covenant of good faith and fair dealing. On November 23, 2020, BioSure requested leave to file a counterclaim seeking recession of the Distribution Agreement based on alleged fraudulent concealment by Chembio. Chembio opposed BioSure’s request for leave to file the counterclaim on procedural and substantive grounds, and on December 11, 2020 the Tribunal denied the request for leave to file the counterclaim. The Tribunal’s denial was without prejudice to BioSure’s ability to assert its claim in a separate proceeding. BioSure continues to deny the relief sought and alleges certain statements Chembio made to third parties about the Distribution Agreement were in bad faith and are a defense to Chembio’s claims. BioSure also asserts that certain alleged misrepresentations entitle BioSure to “set off” any award Chembio might receive from the Tribunal. The parties have completed discovery, and submitted their first pre-hearing submissions. Chembio intends to vigorously pursue its claims in the arbitration. The final merits hearing is scheduled for April 2021. At this stage in the litigation, we are not able to predict the probability of a favorable or unfavorable outcome. 
+f) 
+Governmental Regulation: 
+All of the Company’s existing and proposed diagnostic products are regulated by the U.S. Food and Drug Administration, U.S. Department of Agriculture, certain U.S., state and local agencies, and/or comparable regulatory bodies in other countries. Most aspects of development, production, and marketing, including product testing, authorizations to market, labeling, promotion, manufacturing, and record keeping, are subject to regulatory review. After marketing approval has been granted, Chembio must continue to comply with governmental regulations. Failure to comply with applicable requirements can lead to sanctions, including withdrawal of products from the market, recalls, refusal to authorize government contracts, product seizures, civil money penalties, injunctions, and criminal prosecution. 
+F- 26 
+Table of Contents 
+NOTE 13 — LONG-TERM DEBT: 
+In September 2017, the Company entered into an agreement with an equipment vendor to purchase automated assembly equipment for approximately $ 660,000 . The terms call for payments of 30 % down, 60 % at time of factory acceptance testing and 10 % after delivery. The vendor agreed to lend the Company 15 %, 40 %, and 10 %, of each originally scheduled payment, respectively. The Company paid interest at an annual rate of 12 % until delivery. Beginning in September 2018, the Company began making monthly payments of principal and interest of approximately $ 20,150 , at an annual rate of 12% over a twenty-four month period. The remaining balance was entirely short-term as of December 31, 2019. This balance was fully paid during 2020. 
+On September 3, 2019, the Company entered into a Credit Agreement and Guaranty (the “Credit Agreement”) with Perceptive Credit Holdings II, LP (the “Lender”). The Credit Agreement provides for a $ 20,000,000 senior secured term loan credit facility, which was drawn in full on September 4, 2019. Under the terms of the Credit Agreement, the Company may use the proceeds (i) for general working capital purposes and other permitted corporate purposes, (ii) to refinance certain of the Company’s existing indebtedness and (iii) to pay fees, costs and expenses incurred in connection with the Credit Agreement, including the Lender’s closing cost amount of $ 550,000 , which was netted from the proceeds, and a financing fee of $ 600,000 ( 3.0 % of gross proceeds) payable to Craig-Hallum Capital Group LLC, the Company’s financial advisor for the financing. 
+Principal outstanding under the Credit Agreement bears interest at a rate per annum equal to the sum of (a) the greater of the one-month London Interbank Offered Rate and 2.5 % plus (b) 8.75 %. At any time at which an event of default has occurred and is continuing, the interest rate will increase by 4.0 %. Accrued interest is payable on a monthly basis. On December 31, 2020 the interest rate was 11.25 %. 
+No principal repayments are due under the Credit Agreement prior to September 30, 2022, unless the Company elects to prepay principal or principal is accelerated pursuant to an event of default identified in the Credit Agreement. Principal installments in the amount of $ 300,000 are payable on the last day of each of the eleven months from September 2022 through July 2023, and all remaining principal is payable at maturity on September 3, 2023 . The Company may prepay outstanding principal from time to time, subject to payment of a premium on the prepaid principal amount equal to 10 % through September 3, 2020, 8 % from September 4, 2020 through September 3, 2021, and 4 % from September 4, 2021 through September 3, 2022. No premium will be due with respect to any prepayment made on or after September 4, 2022. 
+Chembio’s obligations under the Credit Agreement are secured by a first priority, perfected lien on substantially all of its property and assets, including its equity interests in subsidiaries. 
+As of December 31, 2020, the loan balance, net of unamortized discounts and debt issuance costs, was $ 18.2 million, and Chembio was in compliance with its loan covenants. 
+NOTE 14 — WARRANTS: 
+In connection with entering into the Credit Agreement, on September 3, 2019, the Company issued to the Lender a seven-year warrant (the “Warrant”) to purchase up to 550,000 shares of the Company’s common stock at a per-share exercise price of $ 5.22 . The Warrant was exercisable for cash or on a net, or “cashless,” basis, and the exercise price of the Warrant was subject to price-based, weighted-average antidilution adjustments for one year after issuance. 
+The Warrant was evaluated by the Company and classified within stockholder’s equity. Its fair value was estimated using a Black-Scholes option-pricing model using the assumptions below. 
+Stock price on issuance date 
+$ 
+5.40 
+Strike Price 
+$ 
+5.22 
+Risk-free interest rate 
+1.45 
+% 
+Volatility 
+43.65 
+% 
+Expected life 
+7 years 
+The fair value of the Warrant was determined to be approximately $ 1.4 million at $ 2.49 per share. 
+As of December 31, 2020, the Warrant was fully exercised. 
+F- 27 
+Table of Contents 
+NOTE 15 - GOODWILL AND INTANGIBLE ASSETS: 
+For the years ended December 31, 2020 and 2019, there was no impairment of goodwill and other intangible assets. 
+Following is a table that reflects changes in Goodwill: 
+Beginning balance January 1, 2020 
+$ 
+5,872,690 
+Changes in foreign currency exchange rate 
+91,054 
+Balance at December 31, 2020 
+$ 
+5,963,744 
+Intangible assets consist of the following at: 
+December 31, 2020 
+December 31, 2019 
+Weighted Average 
+Remaining Life 
+Cost 
+Accumulated 
+Amortization 
+Net 
+Book Value 
+Cost 
+Accumulated 
+Amortization 
+Net 
+Book Value 
+Intellectual property 
+5 
+$ 1,638,699 
+$ 472,190 
+$ 1,166,509 
+$ 1,418,681 
+$ 299,232 
+$ 1,119,449 
+Developed technology 
+5 
+2,102,526 
+594,186 
+1,508,340 
+1,922,682 
+266,550 
+1,656,132 
+Customer contracts/relationships 
+6 
+1,323,424 
+423,093 
+900,331 
+1,325,521 
+270,902 
+1,054,619 
+Trade names 
+7 
+115,318 
+44,512 
+70,806 
+114,946 
+30,794 
+84,152 
+$ 5,179,967 
+$ 1,533,981 
+$ 3,645,986 
+$ 4,781,830 
+$ 867,478 
+$ 3,914,352 
+Amortization expense for the year ended December 31, 2020 and 2019 was $ 588,962 and $ 515,263 , respectively, and is recorded within COGS, R&D and Selling, General and Administrative expenses. Amortization expense, subject to changes in currency exchange rates, is expected to be approximately $ 617,000 per year from 2021 through 2025, and total $ 561,000 million for all of the years thereafter. 
+NOTE 16 — SUBSEQUENT EVENTS: 
+Restructuring 
+On January 14, 2021, the Company’s Board of Directors (the “Board”) approved a restructuring plan (“2021 Plan”) to better align its business priorities. The Plan comprises the termination of employees primarily in the manufacturing department. These actions were intended to better align the Company’s cost structure with the skills and resources required to more effectively pursue opportunities in the marketplace and execute the Company’s long-term growth strategy. 
+Costs associated with the 2021 Plan are primarily related to Severance and Legal costs. Severance payouts are expected to be substantially completed by the end of the six months ending June 30, 2021. Under the 2021 Plan, the Company expects to incur pre-tax charges between approximately $ 0.1 million and $ 0.2 million. 
+F-28
\ No newline at end of file
diff --git a/raw/filings/0001092662/2020/0001140361-21-008210/filing_metadata.csv b/raw/filings/0001092662/2020/0001140361-21-008210/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..4d29429095b3fe2d5406ae5aa4534e2635e6def6
--- /dev/null
+++ b/raw/filings/0001092662/2020/0001140361-21-008210/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0001092662,CEMI,"CHEMBIO DIAGNOSTICS, INC.",10-K,2021-03-11,2020-12-31,2021-03-11T22:22:22.000Z,0001140361-21-008210,brhc10021388_10k.htm,10-K,9927629,1,1,https://www.sec.gov/Archives/edgar/data/1092662/000114036121008210/brhc10021388_10k.htm,https://www.sec.gov/Archives/edgar/data/1092662/000114036121008210/,2020,2020,1
diff --git a/raw/filings/0001092662/2020/0001140361-21-008210/item1.txt b/raw/filings/0001092662/2020/0001140361-21-008210/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..3d292df93b1db3f1b9011c907f1fbcecd0153b89
--- /dev/null
+++ b/raw/filings/0001092662/2020/0001140361-21-008210/item1.txt
@@ -0,0 +1,320 @@
+ITEM 1. 
+BUSINESS 
+Overview 
+We develop, manufacture and commercialize point-of-care tests for the detection and diagnosis of infectious diseases, including COVID‑19, sexually transmitted disease, and fever and tropical disease. 
+Our product portfolio is based upon our proprietary DPP technology, a diagnostic platform that provides high-quality, cost-effective results in 15 to 20 minutes using fingertip blood, nasal swabs and other sample types. The DPP technology platform addresses the rapid diagnostic test market, which includes infectious diseases, cardiac markers, cholesterol and lipids, pregnancy and fertility, and drugs of abuse. Compared with traditional lateral flow technology, the DPP technology platform can provide: 
+● 
+Enhanced sensitivity and specificity: This is achieved via our patented approach to separating the sample path from the buffer path, together with other patented and proprietary strategies, than traditional lateral flow tests. It also delivers lower levels of detection. 
+● 
+Advanced multiplexing capabilities : Through advanced multiplexing, the DPP platform can detect and differentiate up to eight distinct test results from a single patient sample, which can deliver greater clinical value than other rapid tests. 
+● 
+Quantitative results: For some diagnostic applications, our easy-to-use, highly portable, battery-operated DPP Micro Reader optical analyzers can report accurate results in approximately 15 seconds, making it well-suited for decentralized testing where real-time results enable patients to be clinically assessed while they are still onsite. Objective results produced by the DPP Micro Reader can reduce the possibility of the types of human error that can be experienced in the visual interpretations required by many rapid tests. 
+We target the market for rapid diagnostic test solutions for infectious diseases, which is driven by the high prevalence of infectious diseases globally, an increase in the geriatric population, growing demand for rapid test results, and advancements in multiplexing. We have a broad portfolio of infectious disease products, which prior to 2020 were focused principally on sexually transmitted disease and fever and tropical disease. For example, in June 2020 we received FDA clearance of our 510(k) submission for the DPP Zika IgM System, which consists of an antibody test for Zika IgM and a DPP Micro Reader and which had previously received an FDA Emergency Use Authorization or EUA. In October 2020 the DPP HIV-Syphilis System, an antibody test system for the human immunodeficiency virus or HIV and Treponema pallidum bacteria (the causative agent of syphilis), received FDA approval for a Premarket Approval, or PMA, application. 
+In February 2020 we began the process of shifting substantially all of our resources to leverage the DPP technology platform to address the acute and escalating need for diagnostic testing for COVID-19. 
+● 
+COVID-19 antibody test system: We initially refocused our business strategy on the development and commercialization of the DPP COVID-19 IgM/IgG System, which consisted of a new serological test for COVID-19 and a DPP Micro Reader that could provide separate numerical readings for both IgM and IgG levels of antibodies to the virus. We acquired three regulatory approvals of the DPP COVID-19 IgM/IgG system in our targeted global testing market: an EUA, granted by the FDA in April 2020; an approval for emergency use issued by Brazil’s Agência Nacional de Vigilância Sanitária, or ANVISA, in April 2020, and a CE Marking for the European Union obtained in early May 2020. In June 2020 the FDA revoked the EUA for the DPP COVID-19 IgM/IgG system. In September 2020 we submitted to the FDA an EUA application for the DPP SARS-CoV-2 IgM/IgG System, a new rapid antibody test system that detected COVID-19 antibodies using a different methodology that was consistent with updated FDA guidance, but in December 2020 the FDA notified us that it was declining to review the new system based on the FDA’s then-effective prioritization guidance, under which review of the system was not a priority because, for example, the FDA determined that authorization of the tests would have relatively limited impact on testing accessibility or testing capacity. 
+● 
+COVID-19 antigen test system: In July 2020 we received a $628,071 grant, the First BARDA Grant, from the Department of Health and Human Services; Office of the Assistant Secretary for Preparedness and Response; Biomedical Advanced Research and Development Authority, Division of Research Innovation and Ventures, or BARDA, to assist us in developing, submitting and obtaining an EUA application for a COVID-19 point-of-care antigen system using DPP technology. In October 2020, with BARDA’s support in accordance with its grant, we submitted to the FDA an EUA application for the DPP SARS‑CoV‑2 Antigen System, a test system that consists of a DPP SARS-CoV-2 Antigen test cartridge, a DPP Micro Reader optical analyzer and a minimally invasive nasal swab. In December 2020 we received a $12.7 million grant from BARDA, in part to support preparation, submission, and approval of FDA 510(k) clearance for the DPP SARS-CoV-2 Antigen System. In January 2021 the FDA notified us that it was declining to review the DPP SARS-CoV-2 Antigen System based on its updated prioritization guidance, under which review of the system was not a priority. The FDA has supplementally advised us of the type and nature of information it would need to receive in a subsequent EUA application in order for the DPP SARS-CoV-2 Antigen System to be prioritized for review, and we are engaged in testing and development in order to submit a new EUA application for a COVID-19 antigen test system. 
+4 
+Table of Contents 
+● 
+COVID-19 and Influenza respiratory antigen panel test system: BARDA’s $12.7 million grant in December 2020 also supported our development, submission and receipt of an EUA for a rapid, multiplex respiratory antigen panel point-of-care test system using DPP technology. We are currently seeking to develop and conduct clinical trials of the DPP Respiratory Antigen Panel, a test system being designed to provide simultaneous, discrete and differential detection of Influenza A, Influenza B and SARS-CoV-2 antigens from a single patient respiratory specimen, such as a nasal swab, in approximately 20 minutes. The system is intended to enable appropriate clinical management of patients with suspected respiratory infections and to assist in the containment of COVID-19 cases during the flu season. This test system is expected to provide results in approximately 20 minutes and to be run on the DPP Micro Reader. 
+For additional information about our existing and proposed product offerings, please see “—Products” below. 
+Our products are sold globally, directly and through distributors, to medical laboratories and hospitals, governmental and public health entities, non-governmental organizations, medical professionals, and retail establishments. We continue to seek to expand our commercial distribution channels. 
+The extensive economic disruption caused by the COVID-19 pandemic, exacerbated by the market and regulatory complications we faced in seeking to develop and commercialize a portfolio of COVID-19 test systems, was reflected in our operating results for 2020, as total revenues were $32.5 million, a decrease of 5.8% from 2019, and net product sales were $24.8 million, a decrease of 14.1% from 2019. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Consolidated Results of Operations.” 
+In 2020 we continued to invest in automating our test manufacturing processes, all of which are now based in the United States. Among other actions, we expanded our manufacturing capabilities by validating and implementing automated lines. Our transition from manual to automated assembly is intended to add capacity, reduce variable costs and improve product margins. In order to address challenging economic conditions and implement our business strategy, we continued to execute a program to reduce operating expenses and better align our costs with revenues, including by eliminating positions that were no longer aligned with our strategy. Our cash and cash equivalents totaled $23.1 million at December 31, 2020, compared to $18.3 million at December 31, 2019. 
+Industry 
+The DPP technology platform targets diagnostic disease states; (1) where rapid diagnosis impacts patient treatment and outcomes; (2) that are underserved by current diagnostic products due to performance or availability; and (3) that present opportunities regionally, demographically or clinically. We are focused on test solutions associated with infectious diseases: respiratory viruses, sexually transmitted diseases, gastroenterology and insect-vector diseases. 
+Our product portfolio is marketed globally to NGO’s, Ministries of Health, acute care hospitals, reference labs, outpatient clinics including urgent cares and physician offices. Our branded products have secured meaningful market share globally and include, SURE CHECK, STAT-PAK and DPP. We will focus on internally developed products and pursue external opportunities to license novel technologies and products with the intent of leveraging our growing commercial infrastructure. 
+We currently are targeting rapid diagnostic test solutions for infectious diseases: respiratory diseases, sexually transmitted diseases, gastroenterology and insect-vector diseases. The market for rapid diagnostic infectious disease tests is being driven by the high prevalence of infectious diseases globally, an increase in the geriatric population, growing demand for rapid test results, and advancements in multiplexing. 
+Products 
+We develop, manufacture and commercialize point-of-care tests for the detection and diagnosis of infectious diseases, including COVID‑19, sexually transmitted disease, and insect-vector diseases. We target the market for rapid diagnostic test solutions for infectious diseases, which is driven by the high prevalence of infectious diseases globally, an increase in the geriatric population, growing demand for rapid test results, and advancements in multiplexing. 
+Much of our product portfolio is based upon our proprietary DPP technology, a diagnostic platform that provides high-quality, cost-effective results in 15 to 20 minutes using fingertip blood, nasal swabs and other sample types. The DPP technology platform addresses the rapid diagnostic test market, which includes infectious diseases, cardiac markers, cholesterol and lipids, pregnancy and fertility, and drugs of abuse. Compared with traditional lateral flow technology, the DPP technology platform can provide: 
+● 
+Enhanced sensitivity and specificity: This is achieved via our patented approach to separating the sample path from the buffer path, together with other patented and proprietary strategies, than traditional lateral flow tests. It also delivers lower levels of detection. 
+5 
+Table of Contents 
+● 
+Advanced multiplexing capabilities : Through advanced multiplexing, the DPP platform can detect and differentiate up to eight distinct test results from a single patient sample, which can deliver greater clinical value than other rapid tests. 
+● 
+Quantitative results: For some diagnostic applications, our easy-to-use, highly portable, battery-operated DPP Micro Reader optical analyzers can report accurate results in approximately 15 seconds, making it well-suited for decentralized testing where real-time results enable patients to be clinically assessed while they are still onsite. Objective results produced by the DPP Micro Reader can reduce the possibility of the types of human error that can be experienced in the visual interpretations required by many rapid tests. 
+COVID-19 Diagnostic Test Systems 
+Prior to 2020, our broad portfolio of infectious disease products was focused principally on sexually transmitted disease and fever and tropical disease. In 2020 we shifted substantially all of our resources to leverage the DPP technology platform to address the acute and escalating need for diagnostic testing for COVID-19. 
+COVID-19 Antibody Test System 
+Beginning in February 2020 we refocused our business strategy on the development and commercialization of a COVID-19 antibody test system based on DPP technology. We initially developed the DPP COVID-19 IgM/IgG System, which consisted of a new serological test for COVID-19 and a DPP Micro Reader that could provide separate numerical readings for both IgM and IgG levels of antibodies to the CORONA-19 virus. We acquired three regulatory approvals of the DPP COVID-19 IgM/IgG System in our targeted global testing market: an EUA, granted by the FDA in April 2020; an approval for emergency use issued by Brazil’s Agência Nacional de Vigilância Sanitária, or ANVISA, in April 2020, and a CE Marking for the European Union obtained in early May 2020. In June 2020, however, the FDA revoked the EUA for the DPP COVID-19 IgM/IgG System. 
+In the second quarter of 2020 we began shipping the DPP COVID-19 IgM/IgG System to fulfill a $4 million purchase order from Bio-Manguinhos, a long-standing customer that is a subsidiary of the foundation responsible for the development and production of vaccines, diagnostics and biopharmaceuticals for Brazil’s national public health system. 
+In September 2020 we submitted to the FDA an EUA application for the DPP SARS-CoV-2 IgM/IgG System, a new rapid antibody test system that detected COVID-19 antibodies using a different methodology that was consistent with updated FDA guidance. In December 2020 the FDA notified us that it was declining to review the DPP SARS-CoV- 2 IgM/IgG System based on the FDA’s then-effective prioritization guidance. Under this guidance, review of the system was not a priority for the FDA because, for example, the FDA determined that authorization of the tests would have relatively limited impact on testing accessibility or testing capacity. The FDA has supplementally advised us of the type and nature of information it would need to receive in a subsequent EUA application in order for the DPP SARS-CoV-2 IgM/IgG System to be prioritized for review. We are continuing to evaluate whether to commit further resources to the testing and development that would be required in order to seek to submit a new EUA application for a COVID-19 antibody test system. 
+In January 2021 we announced the CE mark for the DPP SARS-CoV-2 IgM/IgG test system, providing regulatory approval to register and market the test systems in the European Union and other geographies that accept the CE mark. 
+COVID-19 Antigen Test System 
+In mid-2020 we began to focus on the development of a COVID-19 antigen test system based on DPP technology. In July 2020 we received a $628,071 grant from BARDA to assist us in developing, submitting and obtaining an EUA application for, a COVID-19 point-of-care antigen system. In October 2020, with BARDA’s support in accordance with its grant, we submitted to the FDA an EUA application for the DPP SARS‑CoV‑2 Antigen System, a test system that consists of a DPP SARS-CoV-2 Antigen test cartridge, a DPP Micro Reader optical analyzer and a minimally invasive nasal swab. 
+In November 2020 ANVISA approved the DPP SARS-CoV-2 Antigen test system for use in Brazil. 
+In December 2020 we received a $12.7 million grant from BARDA, in part to support preparation of a submission in pursuit of FDA 510(k) clearance for the DPP SARS-CoV-2 Antigen System. 
+In January 2021 the FDA notified us that it was declining to review the DPP SARS-CoV-2 Antigen System based on its updated prioritization guidance, under which review of the system was not a priority. The FDA has supplementally advised us of the type and nature of information it would need to receive in a subsequent EUA application in order for the DPP SARS-CoV-2 Antigen System to be prioritized for review, and we are engaged in testing and development in order to submit a new EUA application for a COVID-19 antigen test system. 
+In January 2021 we announced the CE mark for the DPP SARS-CoV-2 Antigen test system, providing regulatory approval to register and market the test systems in the European Union and other geographies that accept the CE mark. 
+6 
+Table of Contents 
+COVID-19 and Influenza Respiratory Antigen Panel Test System 
+In the fourth quarter of 2020 we began developing a rapid, multiplex respiratory antigen panel point-of-care test system using DPP technology. BARDA designated a portion of its $12.7 million grant in December 2020 for use to support our development, submission and receipt of an EUA for this system. 
+We are currently seeking to develop and conduct clinical trials of the DPP Respiratory Antigen Panel, a test system being designed to provide simultaneous, discrete and differential detection of Influenza A, Influenza B and SARS-CoV-2 antigens from a single patient respiratory specimen, such as a nasal swab, in approximately 20 minutes. The system is intended to enable appropriate clinical management of patients with suspected respiratory infections and to assist in the containment of COVID-19 cases during the flu season. This test system is expected to provide results in approximately 20 minutes and to be run on the DPP Micro Reader. 
+To enhance our offered product line quickly, we signed an in-licensing agreement to distribute a visual-read, point- of-care, EUA-approved respiratory panel for the detection of SARS-CoV-2 antigens, Influenza A and Influenza B. This offering is scheduled to launch in March 2021. 
+Legacy Products 
+We have obtained FDA approvals and, directly or through our partners, international regulatory approvals for infectious disease tests as follows: 
+Product 
+U.S. 
+International 
+DPP COVID-19 IgM/IgG System 
+✓ 
+DPP HIV 1/2 Assay 
+✓ 
+✓ 
+DPP HIV-Syphilis System 
+✓ 
+✓ 
+DPP Syphilis Screen & Confirm Assay 
+✓ 
+DPP ZCD IgM/IgG System 
+✓ 
+DPP Dengue NS1 Antigen System 
+✓ 
+DPP Dengue IgM/IgG System 
+✓ 
+DPP Zika IgM System 
+✓ 
+✓ 
+DPP Zika IgM/IgG System 
+✓ 
+DPP Chikungunya System 
+✓ 
+DPP Ebola Antigen System 
+✓ EUA 
+DPP Leishmaniasis Assay 
+✓ 
+HIV 1/2 STAT-PAK Assay 
+✓ 
+✓ 
+Chagas STAT-PAK Assay 
+✓ 
+SURE CHECK HIV 1/2 Assay 
+✓ 
+✓ 
+SURE CHECK HIV Self-Test 
+✓ 
+Organic growth in our core infectious disease business is being driven by: 
+● 
+growth in the overall market for rapid diagnostic infectious disease tests; 
+● 
+our increased market penetration in existing markets and channels, including in the United States, Latin America, and Europe; 
+● 
+our registration of existing and new products in unchartered countries and regions, such as selected countries in Latin America and Southeast Asia; 
+● 
+our entry into new market segments, such as respiratory tests and international HIV Self-Testing; and 
+● 
+advances in our product pipeline in infectious disease with key products including a tests for COVID-19, a multiplex test for HIV and syphilis in the U.S. market and tests for dengue, zika and chikungunya. 
+We market and sell both stand-alone and multiplex tests for sexually transmitted infectious diseases, such as HIV and syphilis. HIV and syphilis continue to be major global public health issues. According to WHO estimates: 
+● 
+HIV has claimed more than 35 million lives, including 770,000 in 2018. Approximately 37.9 million people were living with HIV at the end of 2018, and 1.7 million were newly infected during 2018. 
+● 
+There were 18.0 million prevalent cases of syphilis as of 2012, and 5.6 million new infections were estimated to occur annually. 
+● 
+Elimination of mother-to-child transmission, or MTCT, of both HIV and syphilis is a global health priority. In 2013, 1.9 million pregnant women were infected with syphilis worldwide. Congenital syphilis contributes significantly to infant mortality, accounting for 305,000 annual perinatal deaths worldwide in 2013. Globally, more than 1.4 million pregnant women were infected with HIV as of 2015, and MTCT of HIV is estimated to have resulted in over 150,000 infant cases in 2015. 
+7 
+Table of Contents 
+We are seeking to address the global concerns related to HIV and syphilis co-infection through the development of a novel, multiplex test for both HIV and syphilis. We have developed a DPP HIV-Syphilis multiplex test and received regulatory approvals in the United States and a number of international markets, including Brazil, Europe, Malaysia and Mexico. We are pursuing a CLIA waiver for the DPP HIV-Syphilis tests in the United States. 
+We also market and sell tests for selected fever and tropical diseases such as Chagas, ebola, leishmaniasis and Zika. The market for rapid diagnostic insect-vector diseases includes established markets for disease such as dengue and malaria, which WHO estimates together account for more than 600 million annual infections worldwide. There are also a number of emerging markets for rapid diagnostic tests for infectious diseases such as burkholderia, chikungunya, lassa, leptospirosis, Marburg, rickettsia and Zika. 
+Since 2015 we have received over $14.2 million of funding from some of the world’s leading health organizations, which has helped us accelerate the expansion of our pipeline of infectious disease tests. Our collaborators have included Bill & Melinda Gates Foundation, The Paul G. Allen Family Foundation, The Oswaldo Cruz Foundation or FIOCRUZ, and the Foundation for Innovative New Diagnostics, or FIND, as well as U.S. government agencies such as Centers for Disease Control and Prevention, or CDC, the Biomedical Advanced Research and Development Authority of the U.S. Department of Health and Human Services, or BARDA, and the U.S. Department of Agriculture, or USDA. 
+Several tests in our infectious disease pipeline are approaching commercialization, and several have received initial regulatory approvals: 
+Product 
+Collaborator 
+Phase I 
+Feasibility 
+Phase II 
+Development 
+Phase III 
+Verification & 
+Validation 
+Phase IV 
+Clinical & 
+Regulatory 
+Phase V 
+Commercial 
+Launch 
+DPP HIV-Syphilis System (US) 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+PMA approved 
+DPP Dengue IgM/IgG System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP Dengue NS1 Antigen System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA pending 
+DPP Chikungunya IgM/IgG System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP Zika Chikungunya Dengue IgM/IgG System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP Ebola Antigen System 
+CDC 
+✓ 
+✓ 
+✓ 
+✓ 
+FDA-EUA 
+DPP Fever Assay Asia 
+FIND 
+✓ 
+✓ 
+✓ 
+✓ 
+DPP Fever Assay Africa 
+Paul Allen Foundation 
+✓ 
+✓ 
+✓ 
+DPP Fever Assay Malaysia 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+Sales Channels 
+Our products are sold globally, both directly and through distributors, to hospitals and clinics, physician offices, clinical laboratories, public health organizations, government agencies and consumers. Historically we marketed and sold our products only into a handful of countries and regions. During 2020, we expanded our U.S.-based sales, customer service, and marketing team to focus on the COVID-19, HIV-Syphilis, and future DPP platform product opportunities. With sales growth as an underlying objective, we are focused on increasing sales in geographies that support higher average selling prices. From lead generation through technical inquiries, Chembio has the internal resources to support customers through the commercial process including marketing, sales, sales support, order entry and product support. Our goal is to delight our global customers through all facets of our commercial interactions. 
+Automation of U.S. Manufacturing 
+We are automating our U.S. manufacturing processes and expanding our manufacturing capacity. Over the past two years, we have taken delivery of and completed validation of most of our automated manufacturing lines. These use vision-guided, robotic operation to improve inspection and quality control. As we transition from manual to automated assembly, we believe the reduced variable costs will improve product gross margins. 
+DPP Technology & Development 
+Our commercially available products employ either our patented DPP technology or traditional lateral flow technology. We believe products developed using our DPP technology can provide superior diagnostic performance compared with products that utilize traditional lateral flow technology. 
+Chembio’s history of collaborations has proven the strength and capabilities of the DPP platform to address a diverse range of biomarkers. We are now focusing our R&D resources on delivering products to build a portfolio of COVID-19 tests, Chembio’s new and expanded product portfolio will emphasize high value added tests with strong margins, selling in developed markets, established sales channels, and clinically accepted use cases, where the differentiated capabilities of DPP provide a competitive advantage. 
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+Table of Contents 
+Competition 
+Many of our competitors are significantly larger and have greater financial, research, manufacturing, and marketing resources. Important competitive factors include product quality, analytical performance, ease of use, price, customer service and reputation. Industry competition is based on these and the following additional factors: 
+● 
+patent protection; 
+● 
+scientific expertise; 
+● 
+ability to develop and market products and processes; 
+● 
+ability to obtain required regulatory approvals; 
+● 
+ability to manufacture cost-effective products that meet applicable regulatory requirements; 
+● 
+access to adequate capital; and, 
+● 
+ability to attract and retain qualified personnel. 
+We believe our scientific capabilities and proprietary know-how relating to our patented DPP technology and rapid diagnostic technology are very strong, particularly for the development and manufacture of tests for the detection of infectious and other diseases. 
+Although we have no specific knowledge of any other competitors’ products that could render our products obsolete, if we fail to maintain and enhance our competitive position or fail to introduce new products and product features, our customers may decide to use the products developed by our competitors, which could result in a loss of revenues and cash flow. 
+Employees 
+As of December 31, 2020, we had 355 full-time equivalent employees, of whom 39 were in administration, 262 were in manufacturing, 32 were in research and development, and 22 were in sales and marketing and customer service. Of these employees, approximately 320 were located in the United States, 0 were located in Malaysia, 19 were located in Germany and 16 were located in Brazil. 
+We have never had a work stoppage, and none of our employees are represented by a labor organization or subject to any collective bargaining arrangements. We consider our employee relations to be good. 
+In January 2021, Chembio announced a restructuting plan in the US and reduced its workforce by approximately 9%, as further discussed on Note 16 - Subsequent Events. 
+Governmental Regulation 
+Certain of our activities are subject to regulatory oversight by the FDA under provisions of the Federal Food, Drug, and Cosmetic Act and regulations thereunder, including regulations governing the development, marketing, labeling, promotion, manufacturing, and export of diagnostic products. Our clinical laboratory customers are subject to oversight by Centers for Medicare and Medicaid Services, or CMS, pursuant to CLIA, as well as agencies in various states. Failure to comply with applicable requirements can lead to sanctions, including withdrawal of products from the market, recalls, refusal to authorize government contracts, product seizures, civil money penalties, injunctions, and criminal prosecution. 
+FDA Approval/Clearance Requirements 
+Unless an exemption applies, each medical device that we market or wish to market in the United States must receive 510(k) clearance or Premarket Approval, or PMA. Medical devices that receive 510(k) clearance are “cleared” by the FDA to market, distribute, and sell in the United States. Medical devices that obtain a PMA by the FDA are “approved” to market, distribute and sell in the United States. We cannot be certain that 510(k) clearance or PMA approval will ever be obtained for any products that have not already obtained 510(k) clearance or PMA approval. Descriptions of the PMA and 510(k) clearance processes are provided below. 
+The FDA decides whether a device line must undergo either the 510(k) clearance or PMA based on statutory criteria that utilize a risk-based classification system. PMA is the FDA process of scientific and regulatory review to evaluate the safety and effectiveness of Class III medical devices and, in many cases, Class II medical devices. Class III devices are those that support or sustain human life, are of substantial importance in preventing impairment of human health, or which present a potential, unreasonable risk of illness or injury. The FDA uses these criteria to decide whether a PMA or a 510(k) is appropriate, including the level of risk that the agency perceives is associated with the device and a determination by the agency of whether the product is a type of device that is similar to devices that are already legally marketed. Devices deemed to pose relatively less risk are placed in either Class I or II. In many cases, the FDA requires the manufacturer to submit a 510(k) requesting clearance (also referred to as a premarket notification), unless an exemption applies. The 510(k) must demonstrate that the manufacturer’s proposed device is “substantially equivalent” in intended use and in safety and effectiveness to a legally marketed predicate device. A “predicate device” is a pre-existing medical device to which equivalence can be drawn, that is either in Class I or Class II or is a Class III device that was in commercial distribution before May 28, 1976, for which the FDA has not yet called for submission of a PMA application. 
+9 
+Table of Contents 
+Device classification depends on the device’s intended use and its indications for use. In addition, classification is risk-based, that is, the risk the device poses to the patient and/or the user is a major factor in determining the class to which it is assigned. Class I includes devices with the lowest risk and Class III includes those with the greatest risk. 
+Class I devices are those for which safety and effectiveness can be assured by adherence to the FDA’s general regulatory controls for medical devices, or the General Controls, which include compliance with the applicable portions of the FDA’s quality system regulations, facility registration and product listing, reporting of adverse medical events, and appropriate, truthful and non-misleading labeling, advertising, and promotional materials. Some Class I devices also require premarket clearance by the FDA through the 510(k) process described below. 
+Class II devices are subject to the FDA’s General Controls, and any other special controls as deemed necessary by the FDA to ensure the safety and effectiveness of the device. Premarket review and clearance by the FDA for Class II devices is accomplished through the 510(k) process. Pursuant to the Medical Device User Fee and Modernization Act of 2002, unless a specific exemption applies, 510(k) submissions are subject to user fees. Certain Class II devices are exempt from this premarket review process. 
+Class III includes devices with the greatest risk. Devices in this class must meet all of the requirements in Classes I and II. In addition, Class III devices cannot be marketed until they receive Premarket Approval. 
+The safety and effectiveness of Class III devices cannot be assured solely by the General Controls and the other requirements described above. These devices require formal clinical studies to demonstrate safety and effectiveness. Under Medical Device User Fee and Modernization Act of 2002, PMA applications (and supplemental premarket approval applications) are subject to significantly higher user fees than 510(k) applications, and they also require considerably more time and resources. 
+Rapid HIV tests intended for diagnostic use are regulated as Class III devices. Responsibility for assuring the safety and effectiveness of these tests lies within the Center for Biologics Evaluation and Research’s Office of Blood Research and Review, with oversight by the Blood Products Advisory Committee. Approved rapid HIV tests must meet the regulations in the 21 CFR 800 series subparts, under the investigational device exemption, or IDE and PMA pathways. 
+Premarket Approval Pathway 
+We manufacture, market and distribute three rapid HIV tests in the United States. Our HIV 1/2 STAT-PAK Assay, SURE CHECK HIV 1/2 Assay, and DPP HIV 1/2 Assay all have received FDA PMA approval. A PMA application must be supported by extensive data including, but not limited to, analytical, preclinical, clinical trials, manufacturing, statutory preapproval inspections, and labeling to demonstrate to the FDA’s satisfaction the safety and effectiveness of the device for its intended use. Before a PMA is submitted, a manufacturer must apply for an IDE. If the device presents a “significant risk,” as defined by the FDA, to human health, the FDA requires the device sponsor to file an IDE application with the FDA and obtain IDE approval prior to initiation of enrollment of human subjects for clinical trials. The IDE provides the manufacturer with a legal pathway to perform clinical trials on human subjects where without the IDE, only approved medical devices may be used on human subjects. 
+The IDE application must be supported by appropriate data, such as analytical, animal and laboratory testing results, manufacturing information, and an Investigational Review Board, or IRB approved protocol showing that it is safe to test the device in humans and that the testing protocol is scientifically sound. If the clinical trial design is deemed to have “non-significant risk,” the clinical trial may be eligible for “abbreviated” IDE requirements. In some instances, clinical trials for in vitro diagnostic medical devices may be exempt from the more burdensome IDE requirements if certain labeling requirements are met. 
+A clinical trial may be suspended by either the FDA or the Investigational Review Board at any time for various reasons, including a belief that the risks to the study participants outweigh the benefits of participation in the study. Even if a study is completed, clinical testing results may not demonstrate the safety and efficacy of the device, or they may be equivocal or otherwise insufficient to obtain approval of the product being tested. After the clinical trials have been completed, if at all, and the clinical trial data and results are collected and organized, a manufacturer may complete a PMA application. 
+After a PMA application is sufficiently complete, the FDA will accept the application and begin an in-depth review of the submitted information. By statute, the FDA has 180 days to review the “accepted application,” although, generally, review of the application can take between one and three years, but it may take significantly longer. During this review period, the FDA may request additional information or clarification of information already provided. Also, during the review period, an advisory panel of experts from outside the FDA may be convened to review and evaluate the application and provide recommendations to the FDA as to the approvability of the device. The preapproval inspections conducted by the FDA include an evaluation of the manufacturing facility to ensure compliance with the FDA’s quality systems regulations or QSR, as well as inspections of the clinical trial sites by the Bioresearch Monitoring group to evaluate compliance with good clinical practice and human subject protections. New PMA applications or PMA supplements are required for modifications that affect the safety or effectiveness of the device, including, for example, certain types of modifications to the device’s indication for use, manufacturing process, labeling and design. Significant changes to an approved PMA require a 180-day supplement, whereas less substantive changes may utilize a 30-day notice, or a 135-day supplement. Premarket approval supplements often require submission of the same type of information as a premarket approval application, except that the supplement is limited to information needed to support any changes from the device covered by the original premarket approval application, and it may not require as extensive clinical data or the convening of an advisory panel. 
+10 
+Table of Contents 
+Our HIV 1/2 STAT-PAK Assay PMA application number BP050009/0 and our SURE CHECK 1/2 HIV Assay PMA application number BP050010/0 were approved by the FDA in May 2006. Our DPP HIV 1/2 Assay PMA application number BP120032/0 was approved by the FDA in December 2012. Our DPP HIV Syphilis Assay PMA application number BP180191/0 was approved by the FDA in October 2020. 
+510(k) Clearance Pathway 
+We are currently developing products that either will or are likely to require an FDA 510(k) clearance. We anticipate submitting a 510(k) for each such product to demonstrate that such proposed device is substantially equivalent to a previously cleared 510(k) device or a device that was in commercial distribution before May 28, 1976, for which the FDA has not yet called for the submission of a 510(k). The FDA’s 510(k) clearance pathway usually takes from three to twelve months but could take longer. In some cases the FDA may require additional information, including clinical data, to make a determination regarding substantial equivalence. 
+If a device receives 510(k) clearance, any modification that could significantly affect its safety or effectiveness, or that would constitute a new or major change in its intended use, will require a new 510(k) clearance or, depending on the modification, a PMA. The FDA requires each device manufacturer to determine whether the proposed change requires submission of a new 510(k) or a PMA, but the FDA can review any such decision and, if it disagrees with the manufacturer’s determination, can require the manufacturer to cease marketing and/or recall the modified device until 510(k) clearance or PMA of the modified device is obtained. 
+Clinical Laboratory Improvement Amendments of 1988 
+A manufacturer of a test categorized as moderately complex may request that categorization of the test be waived through a CLIA Waiver by Application, or CW, submission to the FDA. When a test is categorized as waived, it may be performed by laboratories with a Certificate of Waiver, such as a physician’s office outreach setting. In a CW submission, the manufacturer provides evidence to the FDA that a test meets the CLIA statutory criteria for waiver CLIA, a walk-in clinic or an emergency room provides CMS authority over all laboratory testing, except research that is performed on humans in the United States. The Division of Laboratory Services, within the Survey and Certification Group under the CMS, has the responsibility for implementing the CLIA program. 
+The CLIA program is designed to establish quality laboratory testing by ensuring the accuracy, reliability and timeliness of patient test results. Under CLIA, a laboratory is a facility that does laboratory testing on specimens derived from humans and used to provide information for the diagnosis, prevention or treatment of disease, or impairment of, or assessment of health. Under the CLIA program, unless waived, laboratories must be certified by the government, satisfy governmental quality and personnel standards, undergo proficiency testing, be subject to inspections and pay fees. We have received a CLIA waiver for all of our rapid diagnostic rapid HIV tests that we market in the United States. Specifically, the CLIA waiver was granted by the FDA for HIV 1/2 STAT-PAK in November 2006,for SURE CHECK HIV 1/2 in October 2007, and for DPP HIV 1/2 in October 2014. 
+Emergency Use Authorizations (EUA) 
+A formal request to issue an EUA generally should not be submitted until the Secretary of HHS has issued an EUA declaration under section 564(b)(1). In particular, although section 564 allows FDA to issue an EUA for preparedness purposes, in such cases the HHS Secretary must first declare that circumstances exist justifying such an authorization in advance of an actual emergency based on a formal determination of a significant potential for emergency or a material threat determination. During the effective period of the HHS Secretary’s EUA declaration, FDA may authorize the introduction of a medical product into interstate commerce when the product is intended for use during an actual or potential emergency. EUA candidate products include medical products and uses that are not approved, cleared, or licensed under sections 505, 510(k), and 515 of the FD&C Act or section 351 of the PHS Act. 
+After the requisite determination and declaration have been issued, and after feasible and appropriate consultations, FDA may issue an EUA only if FDA concludes that the following four statutory criteria for issuance have been met for 1) Serious or Life-Threatening Disease or conditions, 2) evidence of effectiveness, 2) Risk –Benefit Analysis, 4) No Alternatives. A sponsor seeking an EUA can submit its formal request in the form of an EUA submission, which includes data for clinical studies, non-clinical laboratory studies to assess the safety and effectiveness of the product as well as the discussion of Risks and Benefits of the product. 
+FDA will specify the effective date of an EUA issued under section 564. In general, an EUA will remain in effect for the duration of the EUA declaration under which it was issued which describes termination of an EUA declaration and its impact on existing EUAs. 
+Pervasive and Continuing FDA Regulation 
+A host of regulatory requirements apply to our approved devices, including: the quality system regulation, which requires manufacturers to follow elaborate design, testing, control, documentation and other quality assurance procedures; the Medical Reporting Regulations, which require manufacturers to report to the FDA specified types of adverse events involving their products; labeling regulations; and the FDA’s general prohibition against promoting products for unapproved or “off-label” uses. Some Class II devices are subject to special controls-such as performance standards, post-market surveillance, patient registries, and FDA guidelines-that do not apply to Class I devices. 
+11 
+Table of Contents 
+The regulatory requirements that apply to our approved products classified as medical devices include: 
+● 
+product listing and establishment registration, which helps facilitate FDA inspections and other regulatory action; 
+● 
+QSR, which require manufacturers, including third-party manufacturers, to follow stringent design, testing, control, documentation and other quality assurance procedures during all aspects of the development and manufacturing process; 
+● 
+labeling regulations and FDA prohibitions against the promotion of products for uncleared, unapproved or off-label use or indication; 
+● 
+clearance of product modifications that could significantly affect safety or efficacy or that would constitute a major change in intended use of one of our cleared devices; 
+● 
+approval of product modifications that affect the safety or effectiveness of one of our cleared devices; 
+● 
+medical device reporting regulations, which require that manufacturers comply with FDA requirements to report if their device may have caused or contributed to a death or serious injury, or has malfunctioned in a way that would likely cause or contribute to a death or serious injury if the malfunction of the device or a similar device were to recur; 
+● 
+post-approval restrictions or conditions, including post-approval study commitments; 
+● 
+post-market surveillance regulations, which apply when necessary to protect the public health or to provide additional safety and effectiveness data for the device; 
+● 
+the FDA’s recall authority, whereby it can ask, or under certain conditions order, device manufacturers to recall from the market a product that is in violation of governing laws and regulations; 
+● 
+regulations pertaining to voluntary recalls; and, 
+● 
+notices of corrections or removals. 
+Our Medford, New York facility is currently registered as an establishment with the FDA. We and any third-party manufacturers are subject to announced and unannounced inspections by the FDA to determine our compliance with QSR and other regulations. 
+21st Century Cures Act 
+The 21st Century Cures Act, enacted in December 2016, contains several sections specific to medical device innovations. We believe that implementation of the 21st Century Cures Act may have a positive impact on its businesses by facilitating innovation and/or reducing the regulatory burden imposed on medical device manufacturers. 
+Government Regulation of Medical Devices for Animal Subjects 
+We currently offer two veterinary devices in the United States: DPP VetTB Assay for Cervids and DPP VetTB Assay for Elephants. Diagnostic tests for animal health infectious diseases, including our veterinary devices for the prevention and/or treatment of animal disease, are regulated in the U.S. by the Center for Veterinary Biologics within the U.S. Department of Agriculture Animal and Plant Health Inspection Service, or APHIS, under the Virus, Serum, and Toxin Act of 1913. As a requirement, our veterinary devices were approved by APHIS before they could be sold in the U.S. 
+The APHIS regulatory approval process involves the submission of product performance data and manufacturing documentation. Following regulatory approval to market a product, APHIS requires that each lot of product be submitted for review before release to customers. In addition, APHIS requires special approval to market products where test results are used in part for government-mandated disease management programs. 
+Environmental Laws 
+We believe that we are in compliance in all material respects with all foreign, federal, state, and local environmental regulations applicable to our manufacturing facilities. The cost of ongoing compliance with such regulations does not have a material effect on our operations. 
+Intellectual Property 
+Intellectual Property Strategy 
+Our intellectual property strategy is to: (1) build our own intellectual property portfolio around our DPP technology and optical analyzers; (2) pursue licenses, trade secrets and know-how within the area of rapid point-of-care testing; and, (3) develop and acquire proprietary positions to certain reagents. 
+12 
+Table of Contents 
+DPP Intellectual Property 
+We have obtained patent coverage on our DPP technology, including numerous patents in the United States, and one or more patents in Australia, Brazil, Canada, China, Columbia, Eurasia (Russia), European Union (fourteen European countries),Hong Kong, Israel, India, Indonesia, Japan, Korea, Malaysia, Mexico, Poland, Singapore, South Africa, Thailand, and the United Kingdom . Additional patent applications on our DPP technology are pending in the United States, as well as in foreign countries such as Australia, Brazil, Canada, China, the European Union, India, Indonesia, Malaysia, Mexico, Peru, Singapore and Thailand. 
+DPP technology provides us with freedom to operate and enables us to develop tests with better performance and capabilities compared with tests built on traditional lateral flow platforms. These advantages have allowed us to enter into multiple technology collaborations based upon DPP technology, which we believe will provide new manufacturing and marketing opportunities. We have filed additional patent applications that we believe will strengthen the DPP intellectual property and have also filed for patent protection for certain other point-of-care technologies or applications thereof. 
+We have also obtained patent coverage on our optical-based analyzer technology in the United States as well as in several EU countries. 
+Trademarks 
+We have filed and obtained trademarks for our company name CHEMBIO and CHEMBIO DIAGNOSTIC SYSTEMS, INC. as well as for many of our products, including DPP, SURE CHECK, STAT-VIEW, STAT-PAK, and NEXT GENERATION DPP, as well as for the SampleTainer and DPP Micro Reader, which are used with certain DPP products. Our trademarks have been registered in the United States and certain other countries around the world. 
+Trade Secrets and Know-How 
+We have developed a substantial body of trade secrets and know-how relating to the development and manufacture of lateral flow and DPP-based diagnostic tests, including the sourcing and optimization of materials for such tests, and methods to maximize sensitivity, speed-to-result, specificity, stability and reproducibility of our tests. We possess proprietary know-how to develop tests for multiple conditions using colored particles. Our formulations enable long shelf lives of our rapid HIV and other tests, providing us with an important competitive advantage. 
+Rapid Diagnostic Technology and Reagent Licenses 
+We seek licenses and/or redesigns of products that we believe to be in our best interests. Because of the costs and other negative consequences of time-consuming patent litigation, we often attempt to obtain a license on reasonable terms. 
+The peptides used in our rapid HIV tests were licensed to us by one or more third parties. We also have licensed the antigens used in other tests including our Syphilis, Tuberculosis, Leptospirosis, Leishmaniasis and Chagas tests, and we may enter into other license agreements. In prior years, we concluded license agreements related to intellectual property rights owned by the United States associated with HIV-1 and a sub-license agreement for HIV-2 with Bio-Rad Laboratories N.A., the exclusive licensee of the Pasteur Institute’s HIV-2 intellectual property estate. 
+Available Information 
+We are required to file annual, quarterly and current reports, proxy statements and other information with the U.S. Securities and Exchange Commission. The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. 
+Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, proxy statements and amendments to those documents filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, are also available free of charge on our website at www.chembio.com as soon as reasonably practicable after such reports are electronically filed with or furnished to the SEC. 
+Investors should note that we currently announce material information to our investors and others using filings with the SEC, press releases, public conference calls, webcasts or our website (www.chembio.com), including news and announcements regarding our financial performance, key personnel, our brands and our business strategy. Information that we post on our corporate website could be deemed material to investors. We encourage investors to review the information we post on these channels. We may from time to time update the list of channels we will use to communicate information that could be deemed material and will post information about any such change on www.chembio.com. The information on our website is not, and shall not be deemed to be, a part hereof or incorporated into this or any of our other filings with the SEC. 
+Corporate Information 
+Our principal executive offices are located at 555 Wireless Boulevard, Hauppauge, New York 11788. Our telephone number is (631) 924-1135. Our website address is www.chembio.com. The information contained in, or accessible through, our corporate website does not constitute part of this report. 
+13 
+Table of Contents
\ No newline at end of file
diff --git a/raw/filings/0001092662/2020/0001140361-21-008210/item13.txt b/raw/filings/0001092662/2020/0001140361-21-008210/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..fe91ac2f674135ad3af95e0173fb91bdaeaadfe2
--- /dev/null
+++ b/raw/filings/0001092662/2020/0001140361-21-008210/item13.txt
@@ -0,0 +1,3 @@
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE. 
+The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.
\ No newline at end of file
diff --git a/raw/filings/0001092662/2020/0001140361-21-008210/item9a.txt b/raw/filings/0001092662/2020/0001140361-21-008210/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..479b10ab94ec297cd67fe001d7c3e2e793501e39
--- /dev/null
+++ b/raw/filings/0001092662/2020/0001140361-21-008210/item9a.txt
@@ -0,0 +1,20 @@
+ITEM 9A. 
+Controls and Procedures 
+Evaluation of Disclosure Controls and Procedures 
+Our management, with the participation of our Interim Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures, as defined by Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of December 31, 2020. Based on the evaluation of our disclosure controls and procedures, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2020 at the reasonable assurance level. 
+Management’s Report on Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer and effected by the board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that: 
+● 
+pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; 
+● 
+provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made in accordance with authorizations of management and directors of the company; and 
+● 
+provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. As a result, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate. 
+Under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, our management evaluated the effectiveness of our internal control over financial reporting as of December 31, 2020. In making their assessment of internal control over financial reporting, our management used the criteria described in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Our evaluation included documenting, evaluating and testing of the design and operating effectiveness of our internal control over financial reporting. Based on this evaluation, we concluded that our controls over financial reporting were effective as of December 31, 2020. 
+Previously Identified Material Weaknesses in Internal Control Over Financial Reporting 
+None. 
+Changes in Internal Control over Financial Reporting 
+There were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Securities Exchange Act of 1934 during the period covered by this Annual Report on Form 10-K that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+Inherent Limitations of Internal Control 
+Management, including the Comapny’s Chief Excutive Officer and Chief Financial Officer, does not expect that the Company’s internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints and the benefits of controls must be considered relative to their costs. Because of the inherent liminations in all control systems, no evaluation of internal control can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. Also, any evaluation of the effectiveness of internal controls in future periods are subject to the risk that those internal controls may become inadequate because of changes in business conditions, or that the degree of compliance with the policies and procedures may deteriorate.
\ No newline at end of file
diff --git a/raw/filings/0001092662/2020/0001140361-21-008210/rp_note.txt b/raw/filings/0001092662/2020/0001140361-21-008210/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0001092662/2020/0001140361-21-008210/rpt_disclosure.txt b/raw/filings/0001092662/2020/0001140361-21-008210/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..3911a022ed701e1870e2550f650ac2159db8372b
--- /dev/null
+++ b/raw/filings/0001092662/2020/0001140361-21-008210/rpt_disclosure.txt
@@ -0,0 +1,105 @@
+Certain Relationships and Related-Person Transactions 
+Procedures for Approval of Related Person Transactions 
+The board of directors reviews all transactions involving us in which any of our
+directors, director nominees, significant stockholders and executive officers and their immediate family members are participants, in order to determine whether any such party has a direct or indirect material interest in the transaction. All
+directors, director nominees and executive officers must notify us of any proposed transaction involving us in which such person has a direct or indirect material interest. The proposed transaction is then reviewed by either the board as a whole or
+the audit committee, which determines whether to approve the transaction. After such review, the reviewing body approves the transaction only if it determines that the transaction is in, or not inconsistent with, the best interests of our company and
+stockholders. 
+Conflict of Interest Policy 
+The board of directors has adopted a Conflict of Interest Policy applicable to all
+directors, officers, and employees of our company and our subsidiaries. 
+The Conflict of Interest Policy requires each director and executive officer,
+including their immediate family members, to provide written notice of any potential related-party transaction, defined by the policy to mirror the definition of Item 404 of Regulation S-K of the SEC (with the exception that the policy includes a
+monetary threshold of $100,000 as opposed to the threshold of $120,000 set by Item 404) to the Chair of the Board (or to the Chief Executive Officer if such transaction involves the Chair of the Board, or to the Chief Financial Officer if such
+transaction involves the Chief Executive Officer), including all information that the Chair of the Board, the Chief Executive Officer or the Chief Financial Officer may request. Upon receiving all relevant information, the board may approve the
+transaction if it determines that the transaction is in our best interests and fair to us, may require modifications to the transaction to make it acceptable for approval, or may reject it. The board may also establish guidelines for ongoing
+management of a specific related-party transaction. The policy requires that continuing related-party transactions are reviewed on at least an annual basis. Additionally, the policy requires that all directors and executive officers complete a
+director and officer questionnaire in connection with each of our annual proxy statements, in which they are asked to disclose family relationships and other related-party transactions. 
+Since January 1, 2021, we have not engaged in any related-party transactions in
+which the amount involved exceeded $100,000 and in which any of our directors or executive officers or any holder of more than 5% of our common stock, or any member of the immediate family of any of these persons or entities controlled by any of
+them, had or will have a direct or indirect material interest, other than the compensation arrangements described in “Director Compensation” and “Executive Compensation.” It is our intention to ensure that any future transactions between us and our
+officers, directors and significant stockholders and their affiliates are approved by the audit committee and a majority of the members of the board, including a majority of the independent and disinterested members of the board, and are on terms no
+less favorable to us than those that we could obtain from unaffiliated third parties. 
+27 
+Beneficial Ownership
+of Common Stock 
+The following table sets forth the number of outstanding
+shares of common stock beneficially owned, and the percentage of the class beneficially owned, as of March 28, 2022, by: 
+● 
+each named executive officer included in “Executive Compensation—Summary Compensation Table”; 
+● 
+each current director and the additional nominee for election as a director; and 
+● 
+all of our current executive officers and directors and the additional nominee for election as a director, as a group. 
+The number of shares of common stock beneficially owned
+by each person is determined under the rules of the SEC. Under these rules, beneficial ownership includes any shares as to which the individual has sole or shared voting power or investment power and also any shares that the individual has the right
+to acquire by May 27, 2022 (60 days after March 28, 2022) through the exercise or conversion of a security or other right. Unless otherwise indicated, each person has sole investment and voting power, or shares such power with a family member, with
+respect to the shares set forth in the following table. The inclusion in this table of any shares deemed beneficially owned does not constitute an admission of beneficial ownership of those shares for any other purpose. As of March 28, 2022, there
+were 30,216,016 shares of common stock outstanding. Shares not outstanding, but deemed beneficially owned by virtue of the right of a person to acquire those shares, are treated as outstanding only for purposes of determining the number and percent
+of shares of common stock owned by such person or group. There are no persons known to us to be the beneficial owners of more than five percent of the shares of common stock outstanding as of March 28, 2022. Unless otherwise noted below, the address
+of each person listed in the table is in care of Chembio Diagnostics, Inc., 555 Wireless Boulevard, Hauppauge, New York 11788. 
+Common Stock 
+Named Executive Officers, Directors and Director Nominees 
+Shares 
+% 
+Richard L. Eberly(1) 
+248,342 
+* 
+% 
+Neil A. Goldman(2) 
+45,903 
+* 
+Javan Esfandiari(3) 
+263,412 
+* 
+Lawrence J. Steenvoorden 
+— 
+— 
+Katherine L. Davis(4) 
+142,709 
+* 
+John G. Potthoff(5) 
+137,213 
+* 
+David W.K. Acheson(6) 
+28,674 
+* 
+David W. Bespalko(7) 
+37,480 
+* 
+Leslie Teso-Lichtman 
+— 
+— 
+All current executive officers and directors as a group (10 persons)(8) 
+997,450 
+3.3 
+* 
+Less than 1%. 
+(1) 
+Includes (a) 116,572 shares issuable under restricted stock units and 80,357 shares issuable under options exercisable by May 27, 2022 and (b) 51,413 shares held by Mr.
+Eberly’s spouse. 
+(2) 
+Mr. Goldman resigned as our Executive Vice President and Chief Financial Officer effective as of November 5, 2021. 
+(3) 
+Includes 152,161 shares issuable under options exercisable by May 27, 2022. 
+(4) 
+Includes 36,252 shares issuable under options exercisable by May 27, 2022. 
+(5) 
+Includes 83,127 shares issuable under options exercisable by May 27, 2022. 
+(6) 
+Includes 23,781 shares issuable under options exercisable by May 27, 2022. 
+(7) 
+Includes 31,746 shares issuable under options exercisable by May 27, 2022. 
+(8) 
+Includes 52,660 shares issuable under options exercisable, by May 27, 2022. 
+28 
+Director
+Compensation 
+Our director compensation program is intended to enhance
+our ability to attract, retain and motivate non-employee directors of exceptional ability and to promote the common interest of directors and stockholders in enhancing the value of the common stock. The board of directors reviews director
+compensation annually based on recommendations by the nominating and corporate governance committee. The nominating and corporate governance committee has the sole authority to engage a consulting firm to evaluate director compensation. 
+Under our non-employee director compensation program,
+each non-employee director is eligible to receive compensation for board and committee service consisting of annual cash retainers and equity awards. Directors also may be paid for serving on ad hoc committees of the board. Richard Eberly, our
+President and Chief Executive Officer, does not receive any additional compensation for his service as a director. 
+Under our non-employee director compensation program, in
+2021 our non-employee directors were eligible to receive the following annual cash compensation for their service on the board and the board’s standing committees:
\ No newline at end of file
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new file mode 100644
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+UNITED STATES 
+Securities and Exchange Commission 
+Washington, D.C. 20549 
+FORM 10-K 
+☒ 
+ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the fiscal year ended December 31, 2021 
+or 
+☐ 
+TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the transition period from _______ to ______ . 
+Commission File No. 0-30379 
+CHEMBIO DIAGNOSTICS, INC. 
+(Exact name of registrant as specified in its charter) 
+Nevada 
+88-0425691 
+(State or other jurisdiction of incorporation or organization) 
+(I.R.S. Employer Identification No.) 
+555 Wireless Boulevard, Hauppauge , NY 
+11788 
+(Address of principal executive offices) 
+(Zip Code) 
+Registrant’s telephone number, including area code ( 631 ) 924-1135 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of each class 
+Trading Symbol 
+Name of each exchange on which registered 
+Common Stock, $0.01 par value 
+CEMI 
+The NASDAQ Stock Market LLC 
+Securities registered pursuant to Section 12(g) of the Act: 
+None 
+(Title of Class) 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒ 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒ 
+Indicate by checkmark whether the registrant has filed a report on and attestation to it’s management’s assessment of the effectiveness of internal control over
+financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. Yes ☒ No ☐ 
+Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
+preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ 
+Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§
+232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐ 
+Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be
+contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒ 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging
+growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. 
+Large accelerated filer ☐ 
+Accelerated filer ☒ 
+Non-accelerated filer ☐ 
+Smaller reporting company ☒ 
+Emerging growth company ☐ 
+If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised
+financial accounting standards provided pursuant to Section 13(a) of the Exchange Act ☐ 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ 
+As of the last business day of the registrant’s most recently completed fiscal quarter, the aggregate market value of voting and non-voting common equity held by
+non-affiliates was $ 0 . 
+As of March 3, 2022, the registrant had 30,056,929 
+shares of common stock outstanding. 
+Documents Incorporated By Reference 
+Portions of the registrant’s proxy statement for its 2021 annual meeting of stockholders are incorporated by reference in Part III of this report. 
+TABLE OF CONTENTS 
+Page 
+PART I 
+ITEM 1. 
+BUSINESS 
+4 
+ITEM 1A. 
+RISK FACTORS 
+19 
+ITEM 2. 
+PROPERTIES 
+52 
+ITEM 3. 
+LEGAL PROCEEDINGS 
+52 
+PART II 
+ITEM 5. 
+MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+53 
+ITEM 7. 
+MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+54 
+ITEM 8. 
+FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+67 
+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+67 
+PART III 
+ITEM 10. 
+DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
+69 
+ITEM 11. 
+EXECUTIVE COMPENSATION 
+69 
+ITEM 12. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+69 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+69 
+ITEM 14. 
+PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+69 
+PART IV 
+ITEM 15. 
+EXHIBITS, FINANCIAL STATEMENT SCHEDULES 
+70 
+SIGNATURES 
+72 
+Unless the context requires otherwise, the words ‘‘we,’’ ‘‘us,’’ ‘‘our,’’ ‘‘our company,’’ ‘‘Chembio’’ and similar terms refer to Chembio Diagnostics, Inc. and its consolidated subsidiaries. 
+DPP, STAT-PAK, STAT-VIEW and SURE CHECK are our registered trademarks, and CHEMBIO and MICRO READER are our trademarks. For convenience, these trademarks appear in this report without ® and ™ symbols, and that
+practice does not mean that we will not assert, to the fullest extent under applicable law, our rights to the trademarks. 
+Table of Contents 
+FORWARD-LOOKING STATEMENTS AND STATISTICAL ESTIMATES 
+This report contains statements reflecting our views about our future performance that constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These
+forward-looking statements are generally identified through the inclusion of words such as “anticipate,” “believe,” “contemplate,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “objective,” “outlook,” “plan,” “potential,” “project,”
+“seek,” “should,” “strategy,” “target,” “will,” “would” or variations of such words or similar expressions. All statements addressing our future operating performance, and statements addressing events and developments that we expect or anticipate
+will occur in the future, are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are based upon currently available information, operating plans, and projections about
+future events and trends. 
+This report contains estimates, projections and other data concerning our industry, our business and the markets for our products. Where expressly stated, we obtained this industry, business, market and other data
+from reports, research surveys, studies and similar data prepared by the World Health Organization, or WHO. We also include data that we have compiled, obtained, identified or otherwise derived from reports, research surveys, studies and similar
+data prepared by market research firms and other third parties, industry, medical and general publications, government data and similar sources. Other than WHO, we do not expressly refer to the sources from which this data is derived. 
+Forward-looking statements and statistical estimates inherently involve risks and uncertainties that could cause actual results to differ materially from those predicted or expressed in this
+report. These risks and uncertainties include those described in “Item 1A. Risk Factors” of Part I of this report. You should interpret many of the identified risks and uncertainties as being heightened as a result of the ongoing and numerous
+adverse impacts of the COVID-19 pandemic. Investors are cautioned not to place undue reliance on any forward-looking statements or statistical estimates, which speak only as of the date they are made. We undertake no obligation to update any
+forward-looking statement or statistical estimate, whether as a result of new information, future events or otherwise. 
+3 
+Table of Contents 
+PART I 
+ITEM 1. 
+BUSINESS 
+Overview 
+We develop and commercialize point-of-care diagnostic tests used for the rapid detection and diagnosis of infectious diseases, including sexually transmitted disease, insect vector and tropical disease, COVID-19 and
+other viral and bacterial infections, enabling expedited treatment. 
+Our product portfolio is based upon our proprietary DPP technology, a diagnostic platform that provides high-quality, cost-effective results in 15 to 20 minutes using fingertip blood, nasal swabs and other sample
+types. The DPP technology platform addresses the rapid diagnostic test market, which includes infectious diseases such as STI’s and HIV, Gastroenterology and Women’s Health. Compared with traditional lateral flow technology, the DPP technology
+platform can provide: 
+• 
+Enhanced sensitivity and specificity: This is achieved via our patented approach to separating the sample path from the buffer path, together with other patented and
+proprietary strategies, that differ significantly from traditional lateral flow test. 
+• 
+Advanced multiplexing capabilities: Through advanced multiplexing, the DPP platform can detect and differentiate up to eight distinct test results from a single
+patient sample, which can deliver greater clinical value than other rapid tests currently on the market. 
+• 
+Objective results: For some diagnostic applications, our easy-to-use, highly portable, battery-operated DPP Micro Reader optical analyzers can report accurate
+results in approximately 15 seconds, making it well-suited for decentralized testing where real-time results enable patients to be clinically assessed while they are still onsite. Objective results produced by the DPP Micro Reader can
+reduce the possibility of the types of human error that can be experienced in the visual interpretations required by many rapid tests. 
+We target the market for rapid diagnostic test solutions for infectious diseases, which is driven by the high prevalence of infectious diseases globally, an increase in the elderly population, growing demand for
+rapid test results, and advancements in multiplexing. We have a broad portfolio of infectious disease products, which prior to 2020 were focused principally on sexually transmitted disease and fever and tropical disease. In February 2020 we began
+the process of shifting substantially all of our resources to seek to leverage the DPP technology platform to address the acute and escalating need for diagnostic testing for COVID-19. We are continuing to pursue: 
+• 
+an emergency use authorization, or EUA, from the U.S. Food and Drug Administration, or FDA, as well as 510(k) clearance from the FDA, for the DPP SARS-CoV-2 Antigen test system; 
+• 
+an EUA from the FDA for the DPP Respiratory Antigen Panel; and 
+• 
+a Clinical Laboratory Improvement Amendment, or CLIA, waiver from the FDA for the DPP HIV-Syphilis test system. 
+For additional information about our existing and proposed product offerings, please see “—Products” below. Our products are sold globally, directly and through distributors, to medical laboratories and hospitals,
+governmental and public health entities, nongovernmental organizations, medical professionals, and retail establishments. We continue to seek to expand our commercial distribution channels. 
+4 
+Table of Contents 
+The extensive economic disruption caused by the COVID-19 pandemic, exacerbated by the market and regulatory complications we faced in seeking to develop and commercialize a portfolio of COVID-19 test systems, was
+reflected in our operating results for 2021, as total revenues were $47.8 million, an increase of 47.3% from 2020, and net product sales were $34.8 million, an increase of 40.3% from 2020. See “Item 7. Management’s Discussion and Analysis of
+Financial Condition and Results of Operations—Consolidated Results of Operations.” 
+In 2021 we continued to invest in automating our test manufacturing processes, all of which are now based in the United States. Among other actions, we expanded our manufacturing capabilities by validating and implementing automated lines. Our
+transition from manual to automated assembly is intended to add capacity, reduce variable costs and improve product margins. In order to address challenging economic conditions and implement our business strategy, we continued to execute a program
+to reduce operating expenses and better align our costs with revenues by eliminating positions that were no longer aligned with our strategy. Our cash and cash equivalents totaled $28.8 million at December 31, 2021, compared to $23.1 million at
+December 31, 2020. 
+The Company’s future working capital needs will depend on many factors, including the rate of its business and revenue growth, the availability and cost of human, material and other resources required to build and
+deliver products in accordance with its existing or future product orders, the timing of its continuing automation of manufacturing, and the timing of its investment in research and development as well as sales and marketing. If the Company is
+unable to increase its revenues and manage its expenses in accordance with its operating plan, it may need to reduce the level or slow the timing of the growth plans contemplated by its operating plan, which would likely curtail or delay the growth
+in its business contemplated by its operating plan and could impair or defer its ability to achieve profitability and generate cash flow, or to seek to raise additional funds through debt or equity financings, strategic relationships, or other
+arrangements. All DPP tests are developed and manufactured in the United States and are the subject of a range of domestic and global patents and patents pending. 
+Going Concern Considerations 
+Revenues during the twelve months ended December 31, 2021 did not meet the Company’s expectations. The Company’s increase in cash and cash equivalents over the year reflected its issuance of common stock in
+at-the-market offerings for net proceeds of $38.8 million (see Note 9 - Stockholder’s Equity). The Company continued to experience market, clinical trial and regulatory complications in seeking to develop and commercialize a portfolio of COVID-19
+test systems during the continuing, but evolving, uncertainty of the COVID‑19 pandemic. In the year ending on December 31, 2021, the Company continued to incur significant expenses in connection with pending legal matters (see Note 12 –
+Commitments, Contingencies, and Concentrations: Litigation), delayed achievement of milestones associated with government grant income, investments in inventory, and the continuing automation of manufacturing. 
+The Company performed an assessment to determine whether there were conditions or events that, considered in the aggregate, raised substantial doubt about the Company’s ability to continue as a going concern within
+one year after the date the accompanying consolidated financial statements are being issued. Initially, this assessment did not consider the potential mitigating effect of management’s plans that had not been fully implemented. Because, as
+described below, substantial doubt was determined to exist as the result of this initial assessment, management then assessed the mitigating effect of its plans to determine if it is probable that the plans (1) would be effectively implemented
+within one year after the date the accompanying consolidated financial statements are issued and (2) when implemented, would mitigate the relevant conditions or events that raise substantial doubt about the entity’s ability to continue as a going
+concern. 
+During the twelve months ended December 31, 2021, the Company undertook measures to increase its total revenues and improve its liquidity position. In particular, the Company received significant purchase orders from
+two customers (the “July Purchase Orders”). The Company had pursued the July Purchase Orders for an extended period of time. The July Purchase Orders consist of the following: 
+• 
+On July 20, 2021, the Company received a $28.3 million purchase order from Bio-Manguinhos for the purchase of DPP SARS-CoV-2
+Antigen tests for delivery during 2021 to support the urgent needs of Brazil’s Ministry of Health in addressing the COVID-19 pandemic. Bio-Manguinhos, is responsible for the development and production of vaccines, diagnostics and
+biopharmaceuticals, primarily to meet the demand of Brazil’s national public health system. As of December 31, 2021 $16.8 million was recognized in connection with this order. 
+5 
+Table of Contents 
+• 
+On July 22, 2021, the Company received a $4 million purchase order from the Partnership for Supply Chain Management, supported by The Global Fund, for the purchase of HIV 1/2 STAT-PAK Assays for shipment to
+Ethiopia into early 2022. As of December 31, 2021 $1.2 million was recognized in connection with this order. 
+These measures and other plans and initiatives have been designed to provide the Company with adequate liquidity to meet its obligations for at least the twelve-month period following the date the accompanying
+consolidated financial statements are being issued. The Company’s execution of those measures and its other plans and initiatives continue to depend, however, on factors and uncertainties that are beyond the Company’s control, or that may not be
+addressable on terms acceptable to the Company or at all. The Company considered in particular how: 
+• 
+The ongoing healthcare and economic impacts of the COVID-19 pandemic on the global customer base for the Company’s non‑COVID-19 products continue to negatively affect the timing and rate of recovery of the
+Company’s revenues from those products by, for example, decreasing the allocation of funding for HIV testing, thereby continuing to adversely affect the Company’s liquidity. 
+• 
+Although the Company has entered into agreements to distribute third-party COVID-19 products in the United States, its ability to sell those products could be constrained because of staffing and supply chain
+limitations affecting the suppliers of those products. 
+The Company further considered how these factors and uncertainties could impact its ability over the next year to meet the obligations
+specified in the Credit Agreement with the Lender (each as defined in Note 13 – Long-Term Debt). Those obligations include covenants requiring: 1) minimum cash balance of $3.0 million and ii) minimum total revenue amounts for the twelve months
+preceding each quarter end. For the next year, the minimum total revenue requirements range from $42.0 million for the twelve months ending March 31, 2022 to $47.4 million for the twelve months ending December 31, 2022. Upon an event of default
+under the Credit Agreement, the Lender could elect to declare all amounts outstanding thereunder, together with accrued interest, to be immediately due and payable. In such an event, there can be no assurance that the Company would have
+sufficient liquidity to fund payment of the amounts that would be due under the Credit Agreement or that, if such liquidity were not available, the Company would be successful in raising additional capital on acceptable terms, or at all, or in
+completing any other endeavor to continue to be financially viable and continue as a going concern. The Company’s inability to raise additional capital on acceptable terms in the near future, whether for purposes of funding payments required
+under the Credit Agreement or providing additional liquidity needed for its operations, could have a material adverse effect on its business, prospects, results of operations, liquidity and financial condition. 
+Accordingly, management determined the Company could not be certain that the Company’s plans and initiatives would be effectively implemented within one year after the date on which the accompanying consolidated
+financial statements are being issued. Without giving effect to the prospect of raising additional capital pursuant to the ATM Agreement (as defined in Note 9 – Stockholders’ Equity: Common Stock), increasing product revenue in the near future or
+executing other mitigating plans, many of which are beyond the Company’s control, it is unlikely that the Company will be able to generate sufficient cash flows to meet its required financial obligations, including its debt service and other
+obligations due to third parties. The existence of these conditions raises substantial doubt about the Company’s ability to continue as a going concern for the twelve-month period following the date on which the accompanying audited consolidated
+financial statements are being issued. 
+6 
+Table of Contents 
+The accompanying audited consolidated financial statements have been prepared assuming the Company will continue as a going concern, which contemplates continuity of operations, realization of assets and the
+satisfaction of liabilities in the normal course of business for the twelve-month period following the date the accompanying consolidated financial statements are issued. As such, the accompanying audited consolidated financial statements do not
+include any adjustments relating to the recoverability and classification of assets and their carrying amounts, or the amount and classification of liabilities that may result should the Company be unable to continue as a going concern. 
+Industry 
+The DPP technology platform targets diagnostic disease states; (1) where rapid diagnosis impacts patient treatment and outcomes; (2) that are underserved by current diagnostic products due to performance or
+availability; (3) that present opportunities regionally, demographically or clinically. The Company is focused on test solutions associated with infectious diseases: respiratory viruses, sexually transmitted diseases, gastroenterology and
+insect-vector diseases. 
+Our product portfolio is marketed globally to NGO’s, Ministries of Health, acute care hospitals, reference labs, outpatient clinics including urgent cares and physician offices. Our branded products have secured
+meaningful market share globally and include, SureCheck, Stat Pak and DPP. The Company will focus on internally developed products and pursue external opportunities to license novel technologies and products with the intent of leveraging Chembio’s
+growing commercial infrastructure. 
+We currently are targeting lateral flow test solutions for infectious diseases: respiratory diseases, sexually transmitted diseases and mosquito-borne diseases. The market for lateral flow infectious disease tests is
+being driven by the high prevalence of infectious diseases globally, an increase in the elderly population, growing demand for rapid test results, and advancements in multiplexing. 
+Products 
+COVID-19 Diagnostic Test Systems 
+Prior to 2020, our broad portfolio of infectious disease products was focused principally on sexually transmitted disease and fever and tropical disease. In 2020 we shifted substantially all of our resources to
+leverage the DPP technology platform to address the acute and escalating need for diagnostic testing for COVID-19. 
+COVID-19 Antibody Test System 
+In January 2021 we announced the CE mark for both the DPP SARS-CoV-2 Antigen test system and the DPP SARS-CoV-2 IgM/IgG test system, providing regulatory approval to register and market the test systems in the
+European Union and other geographies that accept the CE mark. 
+COVID-19 Antigen Test System 
+In mid-2020 we began to focus on the development of a COVID-19 antigen test system based on DPP technology. In July 2020 we received a $628,071 grant from BARDA to assist us in developing, submitting and obtaining an
+EUA application for a COVID-19 point-of-care antigen system. In October 2020, with BARDA’s support in accordance with its grant, we submitted to the FDA an EUA application for the DPP SARS‑CoV‑2 Antigen System, a test system that consists of a DPP
+SARS-CoV-2 Antigen test cartridge, a DPP Micro Reader optical analyzer and a minimally invasive nasal swab. 
+7 
+Table of Contents 
+In November 2020 ANVISA approved the DPP SARS-CoV-2 Antigen test system for use in Brazil. In January 2021 we announced the CE mark for the DPP SARS-CoV-2 Antigen test system, providing regulatory approval to
+register and market the test systems in the European Union and other geographies that accept the CE mark. 
+In December 2020 we received a $12.7 million grant from BARDA, in part to support preparation of a submission in pursuit of FDA 510(k) clearance for the DPP SARS-CoV-2 Antigen System. 
+In January 2021 the FDA notified us that it was declining to review the DPP SARS-CoV-2 Antigen System based on its updated prioritization guidance, under which review of the system was not a priority. The FDA has
+supplementally advised us of the type and nature of information it would need to receive in a subsequent EUA application in order for the DPP SARS-CoV-2 Antigen System to be prioritized for review, and we are engaged in testing and development in
+order to submit a new EUA application for a COVID-19 antigen test system. 
+During the year ending December 31, 2021 we performed the clinical trials and on December 2, 2021 we submitted the DPP SARS‑CoV‑2 Antigen test system to the FDA, as a de Novo submission. 
+COVID-19 and Influenza Respiratory Antigen Panel Test System 
+In the fourth quarter of 2020 we began developing a rapid, multiplex respiratory antigen panel point-of-care test system using DPP technology. BARDA designated a portion of its $12.7 million grant in December 2020
+for use to support our development, submission and receipt of an EUA for this system. 
+During 2021, we developed and conducted clinical trials of the DPP Respiratory Antigen Panel, a test system being designed to provide simultaneous, discrete and differential detection of Influenza A, Influenza B and
+SARS-CoV-2 antigens from a single patient respiratory specimen, such as a nasal swab. The system is intended to enable appropriate clinical management of patients with suspected respiratory infections and to assist in the containment of COVID-19
+cases during the flu season. This test system provides results in approximately 20 minutes and is run on the DPP Micro Reader. As of December 31, 2021, we have submitted a request for the EUA approval by the FDA which is currently under review. In
+addition, as of December 31, 2021, we submitted a request for approval to ANVISA in Brazil and CE in Europe, which has been approved as of the date of this filing. 
+As a result, we earned $12.5 million of the $12.7 million available under the BARDA Agreement, dated December 2, 2020 with the Biomedical Advanced Research and Development Authority, or BARDA (part of the U.S.
+Department of Health and Human Services’ Office of the Assistant Secretary for Preparedness and Response) with the remaining $0.2 million having not been earned because it was contingent on our receiving an emergency use authorization for the DPP
+SARS-CoV-2 Antigen by December 2, 2021. 
+HIV-Syphilis Diagnostic Test Systems 
+On December 1, 2021, we received notice from the FDA that it would require additional data related to our Clinical Laboratory Improvement Amendment, or CLIA, waiver submission for the DPP HIV-Syphilis test system. We
+are in active discussions with the FDA in connection with the FDA’s review of our submission and we intend to comply with the FDA’s request for additional data. The process of seeking additional data will extend, for a currently undeterminable
+period, our process for seeking a CLIA waiver for the DPP HIV-Syphilis test system. 
+8 
+Table of Contents 
+Core Products 
+We have obtained FDA approvals and, directly or through our partners, international regulatory approvals for infectious disease tests as follows: 
+Product 
+U.S. 
+International 
+DPP COVID-19 IgM/IgG System 
+✓ 
+DPP SARS-CoV-2 IgM/IgG System 
+✓ 
+DPP SARS-CoV-2 Antigen 
+✓ 
+DPP HIV 1/2 Assay 
+✓ 
+✓ 
+DPP HIV-Syphilis System 
+✓ 
+✓ 
+DPP Syphilis Screen & Confirm Assay 
+✓ 
+DPP ZCD IgM/IgG System 
+✓ 
+DPP Dengue NS1 Antigen System 
+✓ 
+DPP Dengue IgM/IgG System 
+✓ 
+DPP Zika IgM System 
+✓ 
+✓ 
+DPP Zika IgM/IgG System 
+✓ 
+DPP Chikungunya System 
+✓ 
+DPP Ebola Antigen System 
+✓ EUA 
+DPP Leishmaniasis Assay 
+✓ 
+DPP Respiratory Antigen Panel 
+✓ 
+DPP VetTB Assay 
+✓ 
+HIV 1/2 STAT-PAK Assay 
+✓ 
+✓ 
+Chagas STAT-PAK Assay 
+✓ 
+SURE CHECK HIV 1/2 Assay 
+✓ 
+✓ 
+SURE CHECK HIV Self-Test 
+✓ 
+Organic growth in our core infectious disease business is being driven by: 
+• 
+growth in the overall market for point of care infectious disease tests; 
+• 
+our increased market penetration in existing markets and channels, including in the United States, Latin America, Africa and Europe; 
+• 
+our registration of existing and new products in unchartered countries and regions, such as selected countries in Latin America and Southeast Asia; 
+• 
+our entry into new market segments, such as respiratory tests and international HIV Self-Testing; and 
+• 
+advances in our product pipeline in infectious disease with key products including tests for COVID-19, a multiplex test for HIV and syphilis in the U.S. market and tests for dengue, zika and chikungunya. 
+We market and sell both stand-alone and multiplex tests for sexually transmitted infectious diseases, such as HIV and syphilis which continue to be major global public health issues. According to WHO estimates: 
+• 
+HIV has claimed more than 36 million lives, including 680,000 in 2020. Approximately 37.7 million people were living with HIV at the end of 2020, and 1.5 million were newly infected during 2020. 
+• 
+There were 18.0 million prevalent cases of syphilis as of 2012, and 5.6 million new infections were estimated to occur annually. 
+• 
+Elimination of mother-to-child transmission, or MTCT, of both HIV and syphilis is a global health priority. In 2013, 1.9 million pregnant women were infected with syphilis worldwide. Congenital syphilis
+contributes significantly to infant mortality, accounting for 305,000 annual perinatal deaths worldwide in 2013. Globally, more than 1.4 million pregnant women were infected with HIV as of 2015, and MTCT of HIV is estimated to have
+resulted in over 150,000 infant cases in 2015. 
+9 
+Table of Contents 
+We are seeking to address the global concerns related to HIV and syphilis co-infection through the development of a novel, multiplex test for both HIV and syphilis. We have developed a DPP HIV-Syphilis multiplex test
+and received regulatory approvals in the United States and a number of international markets, including Brazil, Europe, Africa, Malaysia and Mexico. We are pursuing a CLIA waiver for the DPP HIV-Syphilis test in the United States. 
+We also market and sell tests for selected fever and tropical diseases such as Chagas, ebola, leishmaniasis and Zika. The market for lateral flow mosquito-borne diseases includes established markets for disease such
+as dengue and malaria, which WHO estimates together account for more than 600 million annual infections worldwide. There are also a number of emerging markets for rapid point of care tests for infectious diseases such as burkholderia, chikungunya,
+lassa, leptospirosis, Marburg, rickettsia and Zika. 
+Since 2015 we have received over $25.1 million of funding from some of the world’s leading health organizations, which has helped us accelerate the expansion of our pipeline of infectious disease tests. Our
+collaborators have included Bill & Melinda Gates Foundation, The Paul G. Allen Family Foundation, The Oswaldo Cruz Foundation or FIOCRUZ, and the Foundation for Innovative New Diagnostics, or FIND, as well as U.S. government agencies such as
+Centers for Disease Control and Prevention, or CDC, the Biomedical Advanced Research and Development Authority of the U.S. Department of Health and Human Services, or BARDA, and the U.S. Department of Agriculture, or USDA. 
+Several tests in our infectious disease pipeline are approaching commercialization, and several have received initial regulatory approvals: 
+Product 
+Collaborator 
+Phase I 
+Feasibility 
+Phase II 
+Development 
+Phase III 
+Verification & 
+Validation 
+Phase IV 
+Clinical & 
+Regulatory 
+Phase V 
+Commercial 
+Launch 
+DPP HIV-Syphilis System (US) 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+PMA approved 
+DPP Dengue IgM/IgG System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP Dengue NS1 Antigen System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA pending 
+DPP Chikungunya IgM/IgG System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP Zika Chikungunya Dengue IgM/IgG System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP Ebola Antigen System 
+CDC 
+✓ 
+✓ 
+✓ 
+✓ 
+FDA-EUA 
+DPP Fever Assay Asia 
+FIND 
+✓ 
+✓ 
+✓ 
+✓ 
+DPP Fever Assay Africa 
+Paul Allen Foundation 
+✓ 
+✓ 
+✓ 
+DPP Fever Assay Malaysia 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+DPP SARS CoV-2 Antigen 
+BARDA 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP Respiratory Antigen Panel 
+BARDA 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP COVID-19 IgM/IgG System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP SARS CoV-2 IgM/IgG System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE 
+10 
+Table of Contents 
+Sales Channels 
+Our products are sold globally, both directly and through distributors, to hospitals and clinics, physician offices, clinical laboratories, public health organizations, government agencies and consumers. Historically
+we marketed and sold our products only into a handful of countries and regions. During 2021, we expanded our U.S.-based sales, customer service, and marketing team to focus on the COVID-19, HIV-Syphilis, and future DPP platform product
+opportunities. With sales growth as an underlying objective, we are focused on increasing sales in geographies that support higher average selling prices. From lead generation through technical inquiries, Chembio has the internal resources to
+support customers through the commercial process including marketing, sales, sales support, order entry and product support. 
+Automation of U.S. Manufacturing 
+We are automating our U.S. manufacturing processes and expanding our manufacturing capacity. Over the past three years, we have taken delivery of and completed validation of most of our automated manufacturing lines.
+These use vision-guided, robotic operation to improve inspection and quality control. As we transition from manual to automated assembly, we believe the reduced variable costs will improve product gross margins. 
+DPP Technology & Development 
+Our commercially available products employ either our patented DPP technology or traditional lateral flow technology. We believe products developed using our DPP technology can provide superior diagnostic performance
+compared with products that utilize traditional lateral flow technology. 
+Chembio’s history of collaborations have proven the strength and capabilities of the DPP platform to address a diverse range of biomarkers. We are now focusing our R&D resources on delivering products to build a
+portfolio of COVID-19 tests and developing Chembio’s new and expanded product portfolio focused on high average selling price, developed markets, established sales channels, and clinically accepted use cases, where the differentiated capabilities
+of DPP provide a competitive advantage. 
+Competition 
+Many of our competitors are significantly larger and have greater financial, research, manufacturing, and marketing resources. Important competitive factors include product quality, analytical performance, ease of
+use, price, customer service and reputation. Industry competition is based on these and the following additional factors: 
+• 
+patent protection; 
+• 
+scientific expertise; 
+• 
+ability to develop and market products and processes; 
+• 
+ability to obtain required regulatory approvals; 
+• 
+ability to manufacture cost-effective products that meet applicable regulatory requirements; 
+• 
+access to adequate capital; and, 
+• 
+ability to attract and retain qualified personnel. 
+We believe our scientific capabilities and proprietary know-how relating to our patented DPP technology and lateral flow technology are very strong, particularly for the development and manufacture of tests for the
+detection of infectious and other diseases. 
+11 
+Table of Contents 
+Although we have no specific knowledge of any other competitors’ products that could render our products obsolete, if we fail to maintain and enhance our competitive position or fail to introduce new products and
+product features, our customers may decide to use the products developed by our competitors, which could result in a loss of revenues and cash flow. 
+Human Capital 
+As of December 31, 2021, we had 337 full-time equivalent employees, of whom 46 were in administration, 241 were in manufacturing, 28 were in research and development, and 22 were in sales and marketing and customer
+service. Of these employees, approximately 297 were located in the United States, 22 were located in Germany and 18 were located in Brazil. We have never had a work stoppage, and none of our employees are represented by a labor organization or
+subject to any collective bargaining arrangements. We consider our employee relations to be good. 
+Our employees are one of our most important assets and set the foundation for our ability to achieve our strategic objectives, drive operational execution, deliver strong financial performance, advance innovation and
+maintain our quality and compliance programs. The success and growth of our business depends in large part on our ability to attract, retain and develop a diverse population of talented and high-performing employees at all levels of our
+organization. 
+Health, Wellness and Safety 
+The health, wellness and safety of our employees is a priority embedded at every level of our business. We provide our employees upfront and ongoing safety training to ensure that safety policies and procedures are
+effectively communicated and implemented. Personal protective equipment is provided to those employees where needed for the employee to safely perform their job function. 
+Since 2020, in response to the COVID-19 pandemic, we implemented safety protocols and new procedures to protect our employees, including more frequent deep cleaning of the facilities, social distancing and onsite
+COVID-19 testing. 
+Workforce Stability 
+Retaining and developing our employees is an important factor in our continued success and growth. We regularly evaluate our employee retention and turnover rates. With the contraction of the labor force as a result
+of the global pandemic, we have also experienced the effects of the labor shortage in our staffing. We expect the labor shortage to continue in 2022 and will continue to monitor and analyze retention closely to identify any areas of concern. 
+Compensation and Benefits 
+To succeed in a competitive labor market, we have recruitment and retention strategies that we focus on as part of the overall management of our business, including designing our compensation and benefits programs to
+be competitive and align with our strategic and stockholders’ interests. Some of our key employee benefits include eligibility for health insurance, vacation time, a retirement plan, an employee assistance program, life and disability coverage. We
+also have procedures and processes focused on providing employees equitable compensation, regardless of race or gender or other personal characteristics. 
+Impact of the COVID-19 Pandemic 
+The COVID-19 pandemic has disrupted nearly every aspect of the global supply chain, including the manufacturing of some of the key supplies used in our tests. Many suppliers are experiencing shortages of required
+personnel as the result of the tight labor market and underlying raw material commodities. To fulfil our obligations, we have had to identify sources of supplies on a short timeframe and in a markedly increased quantity and have been required to
+seek to identify new sources of materials to replace or augment our past sources. Moreover, scarcity has caused increases in the cost of some supplies. 
+12 
+Table of Contents 
+Governmental Regulation 
+Certain of our activities are subject to regulatory oversight by the FDA under provisions of the Federal Food, Drug, and Cosmetic Act and regulations thereunder, including regulations governing the development,
+marketing, labeling, promotion, manufacturing, and export of diagnostic products. Our clinical laboratory customers are subject to oversight by Centers for Medicare and Medicaid Services, or CMS, pursuant to CLIA, as well as agencies in various
+states. Failure to comply with applicable requirements can lead to sanctions, including withdrawal of products from the market, recalls, refusal to authorize government contracts, product seizures, civil money penalties, injunctions, and criminal
+prosecution. 
+FDA Approval/Clearance Requirements 
+Unless an exemption applies, each medical device that we market or wish to market in the United States must receive 510(k) clearance or Premarket Approval, or PMA. Medical devices that receive 510(k) clearance are
+“cleared” by the FDA to market, distribute, and sell in the United States. Medical devices that obtain a PMA by the FDA are “approved” to market, distribute and sell in the United States. We cannot be certain that 510(k) clearance or PMA approval
+will ever be obtained for any products that have not already obtained 510(k) clearance or PMA approval. Descriptions of the PMA and 510(k) clearance processes are provided below. 
+The FDA decides whether a device line must undergo either the 510(k) clearance or PMA based on statutory criteria that utilize a risk-based classification system. PMA is the FDA process of scientific and regulatory
+review to evaluate the safety and effectiveness of Class III medical devices and, in many cases, Class II medical devices. Class III devices are those that support or sustain human life, are of substantial importance in preventing impairment of
+human health, or which present a potential, unreasonable risk of illness or injury. The FDA uses these criteria to decide whether a PMA or a 510(k) is appropriate, including the level of risk that the agency perceives is associated with the device
+and a determination by the agency of whether the product is a type of device that is similar to devices that are already legally marketed. Devices deemed to pose relatively less risk are placed in either Class I or II. In many cases, the FDA
+requires the manufacturer to submit a 510(k) requesting clearance (also referred to as a premarket notification), unless an exemption applies. The 510(k) must demonstrate that the manufacturer’s proposed device is “substantially equivalent” in
+intended use and in safety and effectiveness to a legally marketed predicate device. A “predicate device” is a pre-existing medical device to which equivalence can be drawn, that is either in Class I or Class II or is a Class III device that was in
+commercial distribution before May 28, 1976, for which the FDA has not yet called for submission of a PMA application. 
+Device classification depends on the device’s intended use and its indications for use. In addition, classification is risk-based, that is, the risk the device poses to the patient and/or the user is a major factor
+in determining the class to which it is assigned. Class I includes devices with the lowest risk and Class III includes those with the greatest risk. 
+Class I devices are those for which safety and effectiveness can be assured by adherence to the FDA’s general regulatory controls for medical devices, or the General Controls,
+which include compliance with the applicable portions of the FDA’s quality system regulations, facility registration and product listing, reporting of adverse medical events, and appropriate, truthful and non-misleading labeling, advertising, and
+promotional materials. Some Class I devices also require premarket clearance by the FDA through the 510(k) process described below. 
+Class II devices are subject to the FDA’s General Controls, and any other special controls as deemed necessary by the FDA to ensure the safety and effectiveness of the device.
+Premarket review and clearance by the FDA for Class II devices is accomplished through the 510(k) process. Pursuant to the Medical Device User Fee and Modernization Act of 2002, unless a specific exemption applies, 510(k) submissions are subject to
+user fees. Certain Class II devices are exempt from this premarket review process. 
+Class III includes devices with the greatest risk. Devices in this class must meet all of the requirements in Classes I and II. In addition, Class III devices cannot be
+marketed until they receive Premarket Approval. 
+The safety and effectiveness of Class III devices cannot be assured solely by the General Controls and the other requirements described above. These devices require formal clinical studies to demonstrate safety and
+effectiveness. Under the Medical Device User Fee and Modernization Act of 2002, PMA applications (and supplemental premarket approval applications) are subject to significantly higher user fees than 510(k) applications, and they also require
+considerably more time and resources. 
+13 
+Table of Contents 
+Rapid HIV tests intended for diagnostic use are regulated as Class III devices. Responsibility for assuring the safety and effectiveness of these tests lies within the Center for Biologics Evaluation and Research’s
+Office of Blood Research and Review, with oversight by the Blood Products Advisory Committee. Approved rapid HIV tests must meet the regulations in the 21 CFR 800 series subparts, under the investigational device exemption, or IDE and PMA pathways. 
+Premarket Approval Pathway 
+We manufacture, market and distribute three rapid HIV tests in the United States. Our HIV 1/2 STAT-PAK Assay, SURE CHECK HIV 1/2 Assay, and DPP HIV 1/2 Assay all have received FDA PMA approval. A PMA application must
+be supported by extensive data including, but not limited to, analytical, preclinical, clinical trials, manufacturing, statutory preapproval inspections, and labeling to demonstrate to the FDA’s satisfaction the safety and effectiveness of the
+device for its intended use. Before a PMA is submitted, a manufacturer must apply for an Investigational Device Exemption (“IDE”). If the device presents a “significant risk,” as defined by the FDA, to human health, the FDA requires the device
+sponsor to file an IDE application with the FDA and obtain IDE approval prior to initiation of enrollment of human subjects for clinical trials. The IDE provides the manufacturer with a legal pathway to perform clinical trials on human subjects
+where without the IDE, only approved medical devices may be used on human subjects. 
+The IDE application must be supported by appropriate data, such as analytical, animal and laboratory testing results, manufacturing information, and an Investigational Review Board, or IRB approved protocol showing
+that it is safe to test the device in humans and that the testing protocol is scientifically sound. If the clinical trial design is deemed to have “non-significant risk,” the clinical trial may be eligible for “abbreviated” IDE requirements. In
+some instances, clinical trials for in vitro diagnostic medical devices may be exempt from the more burdensome IDE requirements if certain labeling requirements are met. 
+A clinical trial may be suspended by either the FDA or the Investigational Review Board at any time for various reasons, including a belief that the risks to the study participants outweigh the benefits of
+participation in the study. Even if a study is completed, clinical testing results may not demonstrate the safety and efficacy of the device, or they may be equivocal or otherwise insufficient to obtain approval of the product being tested. After
+the clinical trials have been completed, if at all, and the clinical trial data and results are collected and organized, a manufacturer may complete a PMA application. 
+After a PMA application is sufficiently complete, the FDA will accept the application and begin an in-depth review of the submitted information. By statute, the FDA has 180 days to review the “accepted application,”
+although, generally, review of the application can take between one and three years, but it may take significantly longer. During this review period, the FDA may request additional information or clarification of information already provided. Also,
+during the review period, an advisory panel of experts from outside the FDA may be convened to review and evaluate the application and provide recommendations to the FDA as to the approvability of the device. The preapproval inspections conducted
+by the FDA include an evaluation of the manufacturing facility to ensure compliance with the FDA’s quality systems regulations or QSR, as well as inspections of the clinical trial sites by the Bioresearch Monitoring group to evaluate compliance
+with good clinical practice and human subject protections. New PMA applications or PMA supplements are required for modifications that affect the safety or effectiveness of the device, including, for example, certain types of modifications to the
+device’s indication for use, manufacturing process, labeling and design. Significant changes to an approved PMA require a 180-day supplement, whereas less substantive changes may utilize a 30-day notice, or a 135-day supplement. Premarket approval
+supplements often require submission of the same type of information as a premarket approval application, except that the supplement is limited to information needed to support any changes from the device covered by the original premarket approval
+application, and it may not require as extensive clinical data or the convening of an advisory panel. 
+Our HIV 1/2 STAT-PAK Assay PMA application number BP050009/0 and our SURE CHECK 1/2 HIV Assay PMA application number BP050010/0 were approved by the FDA in May 2006. Our DPP HIV 1/2 Assay PMA application number
+BP120032/0 was approved by the FDA in December 2012. Our DPP HIV Syphilis Assay PMA application number BP180191/0 was approved by the FDA in October 2020. 
+14 
+Table of Contents 
+510(k) Clearance Pathway 
+We are currently developing products that either will or are likely to require an FDA 510(k) clearance. We anticipate submitting a 510(k) for each such product to demonstrate that such proposed device is
+substantially equivalent to a previously cleared 510(k) device or a device that was in commercial distribution before May 28, 1976, for which the FDA has not yet called for the submission of a 510(k). The FDA’s 510(k) clearance pathway usually
+takes from three to twelve months but could take longer. In some cases the FDA may require additional information, including clinical data, to make a determination regarding substantial equivalence. 
+If a device receives 510(k) clearance, any modification that could significantly affect its safety or effectiveness, or that would constitute a new or major change in its intended use, will require a new 510(k) clearance or, depending on the
+modification, a PMA. The FDA requires each device manufacturer to determine whether the proposed change requires submission of a new 510(k) or a PMA, but the FDA can review any such decision and, if it disagrees with the manufacturer’s
+determination, can require the manufacturer to cease marketing and/or recall the modified device until 510(k) clearance or PMA of the modified device is obtained. 
+Clinical Laboratory Improvement Amendments of 1988 
+A manufacturer of a test categorized as moderately complex may request that categorization of the test be waived through a CLIA Waiver by Application, or CW, submission to the FDA. When a test is categorized as
+waived, it may be performed by laboratories with a Certificate of Waiver, such as a physician’s office outreach setting. In a CW submission, the manufacturer provides evidence to the FDA that a test meets the CLIA statutory criteria for waiver
+CLIA, a walk-in clinic or an emergency room provides CMS authority over all laboratory testing, except research that is performed on humans in the United States. The Division of Laboratory Services, within the Survey and Certification Group under
+the CMS, has the responsibility for implementing the CLIA program. 
+The CLIA program is designed to establish quality laboratory testing by ensuring the accuracy, reliability and timeliness of patient test results. Under CLIA, a laboratory is a facility that does laboratory testing
+on specimens derived from humans and used to provide information for the diagnosis, prevention or treatment of disease, or impairment of, or assessment of health. Under the CLIA program, unless waived, laboratories must be certified by the
+government, satisfy governmental quality and personnel standards, undergo proficiency testing, be subject to inspections and pay fees. We have received a CLIA waiver for all of our lateral flow rapid HIV tests that we market in the United States.
+Specifically, the CLIA waiver was granted by the FDA for HIV 1/2 STAT-PAK in November 2006, for SURE CHECK HIV 1/2 in October 2007, and for DPP HIV 1/2 in October 2014. 
+Emergency Use Authorizations (EUA) 
+A formal request to issue an EUA generally should not be submitted until the Secretary of HHS has issued an EUA declaration under section 564(b)(1). In particular, although section 564 allows FDA to issue an EUA for
+preparedness purposes, in such cases the HHS Secretary must first declare that circumstances exist justifying such an authorization in advance of an actual emergency based on a formal determination of a significant potential for emergency or a
+material threat determination. During the effective period of the HHS Secretary’s EUA declaration, FDA may authorize the introduction of a medical product into interstate commerce when the product is intended for use during an actual or potential
+emergency. EUA candidate products include medical products and uses that are not approved, cleared, or licensed under sections 505, 510(k), and 515 of the FD&C Act or section 351 of the PHS Act. 
+After the requisite determination and declaration have been issued, and after feasible and appropriate consultations, FDA may issue an EUA only if FDA concludes that the following four statutory criteria for issuance
+have been met for 1) Serious or Life-Threatening Disease or conditions, 2) evidence of effectiveness, 2) Risk –Benefit Analysis, 4) No Alternatives. A sponsor seeking an EUA can submit its formal request in the form of an EUA submission, which
+includes data for clinical studies, non-clinical laboratory studies to assess the safety and effectiveness of the product as well as the discussion of Risks and Benefits of the product. 
+FDA will specify the effective date of an EUA issued under section 564. In general, an EUA will remain in effect for the duration of the EUA declaration under which it was issued which describes termination of an EUA
+declaration and its impact on existing EUAs. 
+15 
+Table of Contents 
+Pervasive and Continuing FDA Regulation 
+A host of regulatory requirements apply to our approved devices, including: the quality system regulation, which requires manufacturers to follow elaborate design, testing, control, documentation and other quality
+assurance procedures; the Medical Reporting Regulations, which require manufacturers to report to the FDA specified types of adverse events involving their products; labeling regulations; and the FDA’s general prohibition against promoting products
+for unapproved or “off-label” uses. Some Class II devices are subject to special controls-such as performance standards, post-market surveillance, patient registries, and FDA guidelines-that do not apply to Class I devices. 
+The regulatory requirements that apply to our approved products classified as medical devices include: 
+• 
+product listing and establishment registration, which helps facilitate FDA inspections and other regulatory action; 
+• 
+QSR, which require manufacturers, including third-party manufacturers, to follow stringent design, testing, control, documentation and other quality assurance procedures during all aspects of the development
+and manufacturing process; 
+• 
+labeling regulations and FDA prohibitions against the promotion of products for uncleared, unapproved or off-label use or indication; 
+• 
+clearance of product modifications that could significantly affect safety or efficacy or that would constitute a major change in intended use of one of our cleared devices; 
+• 
+approval of product modifications that affect the safety or effectiveness of one of our cleared devices; 
+• 
+medical device reporting regulations, which require that manufacturers comply with FDA requirements to report if their device may have caused or contributed to a death or serious injury, or has malfunctioned
+in a way that would likely cause or contribute to a death or serious injury if the malfunction of the device or a similar device were to recur; 
+• 
+post-approval restrictions or conditions, including post-approval study commitments; 
+• 
+post-market surveillance regulations, which apply when necessary to protect the public health or to provide additional safety and effectiveness data for the device; 
+• 
+the FDA’s recall authority, whereby it can ask, or under certain conditions order, device manufacturers to recall from the market a product that is in violation of governing laws and regulations; 
+• 
+regulations pertaining to voluntary recalls; and, 
+• 
+notices of corrections or removals. 
+Our Medford, New York facility is currently registered as an establishment with the FDA. We and any third-party manufacturers are subject to announced and unannounced inspections by the FDA to determine our
+compliance with QSR and other regulations. 
+Government Regulation of Medical Devices for Animal Subjects 
+We currently offer two veterinary devices in the United States: DPP VetTB Assay for Cervids and DPP VetTB Assay for Elephants. Diagnostic tests for animal health infectious diseases, including our veterinary devices
+for the prevention and/or treatment of animal disease, are regulated in the U.S. by the Center for Veterinary Biologics within the U.S. Department of Agriculture Animal and Plant Health Inspection Service, or APHIS, under the Virus, Serum, and
+Toxin Act of 1913. As a requirement, our veterinary devices were approved by APHIS before they could be sold in the U.S. 
+16 
+Table of Contents 
+The APHIS regulatory approval process involves the submission of product performance data and manufacturing documentation. Following regulatory approval to market a product, APHIS requires that each lot of product be
+submitted for review before release to customers. In addition, APHIS requires special approval to market products where test results are used in part for government-mandated disease management programs. 
+Climate Change and Environmental Laws 
+The medical device industry is increasingly becoming subject of scrutiny, stringent regulation and the demand for green, sustainable products. We are focused on monitoring these increasing requirements for efficient
+and accurate processes for hazardous substance handling, supplier disclosures, and regulatory reporting in order to comply with numerous global health and environmental regulatory requirements and restrictions. 
+We believe that we are in compliance in all material respects with all foreign, federal, state, and local environmental regulations applicable to our manufacturing facilities. The cost of ongoing compliance with such
+regulations does not have a material effect on our operations. 
+Intellectual Property 
+Intellectual Property Strategy 
+Our intellectual property strategy is to: (1) build our own intellectual property portfolio around our DPP technology and optical analyzers; (2) pursue licenses, trade secrets and know-how within the area of rapid
+point-of-care testing; and, (3) develop and acquire proprietary positions to certain reagents. 
+DPP Intellectual Property 
+We have obtained patent coverage on our DPP technology, including numerous patents in the United States, and one or more patents in Australia, Brazil, Canada, China, Columbia, Eurasia (Russia), European Union
+(fourteen European countries), Hong Kong, Israel, India, Indonesia, Japan, Korea, Malaysia, Mexico, Poland, Singapore, South Africa, Thailand, and the United Kingdom. Additional patent applications on our DPP technology are pending in the United
+States, as well as in foreign countries such as Australia, Brazil, Canada, China, the European Union, India, Indonesia, Malaysia, Mexico, Peru, Singapore and Thailand. 
+DPP technology provides us with freedom to operate and enables us to develop tests with better performance and capabilities compared with tests built on traditional lateral flow platforms. These advantages have
+allowed us to enter into multiple technology collaborations based upon DPP technology, which we believe will provide new manufacturing and marketing opportunities. We have filed additional patent applications that we believe will strengthen the DPP
+intellectual property and have also filed for patent protection for certain other point-of-care technologies or applications thereof. 
+We have also obtained patent coverage on our optical-based analyzer technology in the United States as well as in several EU countries. 
+Trademarks 
+We have filed and obtained trademarks for our company name CHEMBIO and CHEMBIO DIAGNOSTIC SYSTEMS, INC. as well as for many of our products, including DPP, SURE CHECK, STAT-VIEW, STAT-PAK, and NEXT GENERATION DPP, as
+well as for the SampleTainer and DPP Micro Reader, which are used with certain DPP products. Our trademarks have been registered in the United States and certain other countries around the world. 
+Trade Secrets and Know-How 
+We have developed a substantial body of trade secrets and know-how relating to the development and manufacture of lateral flow and DPP-based diagnostic tests, including the sourcing and optimization of materials for
+such tests, and methods to maximize sensitivity, speed-to-result, specificity, stability and reproducibility of our tests. We possess proprietary know-how to develop tests for multiple conditions using colored particles. Our formulations enable
+long shelf lives of our rapid HIV and other tests, providing us with an important competitive advantage. 
+17 
+Table of Contents 
+Rapid Diagnostic Technology and Reagent Licenses 
+We seek licenses and/or redesigns of products that we believe to be in our best interests. Because of the costs and other negative consequences of time consuming patent litigation, we often attempt to obtain a
+license on reasonable terms. The peptides used in our rapid HIV tests were licensed to us by one or more third parties. We also have licensed the antigens used in other tests including our Syphilis, Tuberculosis, Leptospirosis, Leishmaniasis and
+Chagas tests, and we may enter into other license agreements. In prior years, we concluded license agreements related to intellectual property rights owned by the United States associated with HIV-1 and a sub-license agreement for HIV-2 with
+Bio-Rad Laboratories N.A., the exclusive licensee of the Pasteur Institute’s HIV-2 intellectual property estate. 
+Available Information 
+We are required to file annual, quarterly and current reports, proxy statements and other information with the U.S. Securities and Exchange Commission. The SEC maintains a website at www.sec.gov that contains
+reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. 
+Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, proxy statements and amendments to those documents filed or furnished pursuant to Section 13(a) or 15(d) of the Securities
+Exchange Act of 1934, are also available free of charge on our website at www.chembio.com as soon as reasonably practicable after such reports are electronically filed with or furnished to the SEC. 
+Investors should note that we currently announce material information to our investors and others using filings with the SEC, press releases, public conference calls, webcasts or our website (www.chembio.com),
+including news and announcements regarding our financial performance, key personnel, our brands and our business strategy. Information that we post on our corporate website could be deemed material to investors. We encourage investors to review the
+information we post on these channels. We may from time to time update the list of channels we will use to communicate information that could be deemed material and will post information about any such change on www.chembio.com. The information on
+our website is not, and shall not be deemed to be, a part hereof or incorporated into this or any of our other filings with the SEC. 
+Corporate Information 
+Our principal executive offices are located at 555 Wireless Boulevard, Hauppauge, New York 11788. Our telephone number is (631) 924-1135. Our website address is www.chembio.com. The information contained in, or
+accessible through, our corporate website does not constitute part of this report. 
+18 
+Table of Contents 
+ITEM 1A. 
+RISK FACTORS 
+You should carefully consider each of the following risk factors and all of the other information provided in this Form 10-K in considering whether to make or continue to hold an investment in our
+Common Stock. The risks described below are those we currently believe may materially affect us. An investment in our Company involves a high degree of risk, and should be considered only by persons who can afford the loss of their entire
+investment. Although we believe that these risks are the most important for you to consider, you should read this section in conjunction with our financial statements, the notes to those financial statements and our management’s discussion and
+analysis of financial condition and results of operations included in our periodic reports and incorporated into this Form 10-K by reference. 
+RISK FACTORS SUMMARY 
+Our business is subject to a number of risks, including risks that may prevent us from achieving our business objectives or may adversely affect our business, financial condition, results of
+operations, cash flows and prospects. The risks are discussed more fully below and include, but are not limited to, the risks summarized below. 
+Risks Related to Our Business and Our Industry 
+● 
+our ability to initiate and complete clinical trials necessary to support EUA, 510(k), PMA or de novo submissions; 
+● 
+our allocation of a substantial portion of our resources to the development and production of our DPP SARS-CoV-2 Antigen
+system; 
+● 
+uncertainty and competition in the diagnostic testing market, particularly with
+respect to COVID-19; 
+● 
+the effects of the ongoing or future SEC investigation; 
+● 
+the effects of existing or future stockholder litigation; 
+● 
+impacts on our suppliers and employees due to the COVID‑19 pandemic; 
+● 
+the ability of our products to compete with the new or existing products of our
+competitors; 
+● 
+the negative impact of healthcare industry consolidation on our future revenues and operating results; 
+● 
+our ability to successfully manage the transition associated with the appointment of a new chief financial officer; 
+● 
+our ability to retain key employees and attract additional qualified personnel; 
+● 
+third‑party reimbursement policies; 
+● 
+our ability to collect our outstanding accounts receivable; 
+● 
+the continued funding of, and ability to participate in, large
+testing program in the U.S.; 
+● 
+developments in diagnostic testing guidelines or recommendations; 
+● 
+our ability to obtain government grant awards; and 
+● 
+the vulnerability of our business to cyber‑attacks. 
+Risks Related to Our Products 
+● 
+the COVID-19 Diagnostic Test Systems not gaining wide industry acceptance; 
+● 
+the impact of COVID‑19 mutations on the ability of the COVID-19 Diagnostic Test Systems adequately detecting COVID‑19 or SARS‑CoV‑2 antigens; 
+● 
+our ability to successfully introduce and market our products; 
+● 
+timely receipt and implementation of additional customized manufacturing automation equipment; 
+● 
+variability and unpredictability due to lengthy sales cycles for our products; 
+● 
+our customers not adopting rapid point‑of‑care diagnostic testing; 
+● 
+the concentration of our customers; and 
+● 
+our products not performing properly. 
+19 
+Table of Contents 
+Financial, Economic and Financing Risks 
+● 
+our liquidity limitations, including that we have concluded there is a substantial doubt about our ability to continue as a
+going concern; 
+● 
+the impact of our liquidity and operational limitations on our ability to fulfill
+purchased orders; 
+● 
+the our incurrence of losses in recent years and uncertainty about our future
+profitability; 
+● 
+the fluctuation of our financial results; 
+● 
+our compliance with the terms of the Credit Agreement; 
+● 
+our ability to generate sufficient cash to service our debt; 
+● 
+increased interest expenses due to changes in LIBOR; 
+● 
+the negative impact of changes in foreign currency exchange rates on our operating results; and 
+● 
+basing our estimates or judgments relate to critical accounting policies on assumptions that can change or prove to be incorrect. 
+Risks Related to Intellectual Property 
+● 
+our ability to protect our proprietary technology; and 
+● 
+the effect of future intellectual property disputes on our ability to sell products or use certain technologies. 
+Risks Related to Our Reliance on Third Parties 
+● 
+our dependence on a limited number of third‑party suppliers, including single source suppliers, for critical components and materials; 
+● 
+the limitation on rights we receive from collaborations with strategic collaborators, and the exposure to risks outside of our control due to such collaborations; 
+● 
+our ability to maintain existing distribution channels or develop new distribution channels; and 
+● 
+our compliance with U.S. government contracts. 
+Risks Related to Regulations 
+● 
+the impact of changes in CLIA, FDA, ANVISA, and other regulatory changes, on COVID‑19 diagnostic tests; 
+● 
+our ability to receive and maintain necessary regulatory approvals for our products; 
+● 
+the impact of governmental export controls on our ability to compete in international markets; 
+● 
+our ability to comply with FDA and other regulatory requirements; 
+● 
+our ability to respond to changes in regulatory requirements; 
+● 
+the effect of FDA regulation of laboratory‑developed tests and genetic testing on demand for our products; 
+● 
+disruptions at the FDA and other government agencies affecting the ability of the FDA to hire, retain or deploy key leadership or personal or otherwise could prevent new and modified products from being
+developed, cleared, approved, authorized or commercialized; 
+● 
+ongoing changes in healthcare regulation; 
+● 
+a reduction or elimination in the types of government awards that partially support some of our programs; 
+● 
+compliance with privacy, security and breach notification regulations; 
+● 
+our ability to manufacture products in accordance with applicable requirements; 
+● 
+the effect of healthcare fraud and abuse laws on our business; and 
+● 
+increased exposure to regulatory, cultural and other challenges due to international expansion. 
+20 
+Table of Contents 
+Risks Related to Ownership of Common Stock 
+● 
+the limited liquidity of our common stock; 
+● 
+the volatility of the price of our common stock; 
+● 
+the ability of our stock price to meet the minimum bid price for continued listing on the Nasdaq capital market; 
+● 
+the effect of future issuances of common stock on the price of our common stock and our ability to raise funds in new equity offerings; 
+● 
+management’s broad discretion as to the use of proceeds of the offering made pursuant
+to the ATM Agreement; and 
+● 
+the depression of the market price of our common stock due to sale by existing stockholders, executive officers or directors. 
+General Risk Factors 
+● 
+our ability to successfully generate the expected benefits of strategic transactions; 
+● 
+costs associated with compliance with public company regulations; and 
+● 
+terrorist attacks or natural disasters. 
+RISK FACTORS 
+Risks Related to Our Business and Our Industry 
+Our near term success is highly dependent on the success of the our DPP platform, and we cannot be certain that we will succeed in developing one or more of those systems or
+that, if we do, they will attain market acceptance or be successfully commercialized in the United States or elsewhere. 
+We do not currently have an Emergency Use Authorization, or EUA, from the U.S. Food and Drug Administration, or FDA, for any of the COVID-19 Diagnostic Test Systems or for our DPP Respiratory Panel, and we do not
+currently have an application pending for any such EUA. We also do not have a CLIA waiver from the FDA for our DPP HIV-Syphilis test system. Market and regulatory requirements continue to change at a rapid pace. The FDA has declined to review our
+most recent EUAs submitted for our DPP SARS-CoV-2 Antigen System based on then-effective prioritization guidance, which is subject to change. There can be no assurance that, if we make a submission of any future EUA or CLIA waiver application, we
+will meet the requirements of the prioritization guidance in effect at the time of the submission or otherwise be successful in obtaining either (1) an EUA that would permit us to offer and sell the DPP SARS-CoV-2 Antigen test system or DPP
+Respiratory Panel in the United States or (2) a CLIA waiver for our DPP HIV-Syphilis test. 
+21 
+Table of Contents 
+Even if we are able to obtain any such EUA or CLIA waiver, our product may not gain broad market acceptance among physicians, healthcare payers, patients, and the medical community. We cannot guarantee market
+acceptance of our product, and have somewhat limited information on which to estimate our anticipated level of sales. Our products will require healthcare providers and doctors to accept and adopt our technology. Our industry is susceptible to
+rapid technological developments and there can be no assurance that we will be able to match any new technological advances. Acceptance and use of any products we market will depend upon a number of factors including: 
+• 
+perceptions by members of the health care community, including physicians, about the safety and effectiveness of our products; 
+• 
+limitation on use or warnings required by the FDA or other global regulators in our product labeling; 
+• 
+the cost of our products relative to competing products; 
+• 
+convenience and ease of administration; 
+• 
+potential advantages of alternative diagnostic and treatment methods; 
+• 
+availability of reimbursement for our products from government or other healthcare payers; 
+• 
+effectiveness of marketing and distribution efforts by us and our licensees and distributors, if any; and 
+• 
+the ability of our diagnostic solutions to address different variants. 
+In addition, with respect to any EUA we obtain, the FDA may revoke an EUA where it is determined that the underlying health emergency no longer exists or warrants such authorization, even if we obtain an EUA, we
+cannot predict how long such EUA would remain in place. Such revocation could materially adversely impact our business in a variety of ways, including if the relevant product is not yet approved by the FDA under a traditional approval pathway and
+if we have invested in the supply chain to provide any of our products under an EUA, and would require us to obtain a 510(k) or other marketing authorization from the FDA. If the FDA revokes a previously issued EUA prior to us having received
+regulatory approval to commercialize our DPP SARS-CoV-2 Antigen test system or DPP Respiratory Panel through a traditional approval pathway, we would be required to cease our commercialization efforts, which would substantially and negatively
+impact our business. 
+The failure of these products to find market acceptance would substantially harm our business and would adversely affect our revenue. If the DPP SARS-CoV-2 Antigen test system, DPP Respiratory Panel or DPP
+HIV-Syphilis test are not as successfully commercialized as expected, we may not be able to generate sufficient revenue to become profitable. Any failure of one of these products to be successfully commercialized in the United States may have a
+material adverse effect on our business, operating result financial condition and cash flows, and could result in a substantial decline in the price of our common stock. In addition, the production and widely administered use of efficacious
+vaccines for COVID-19 may reduce the demand for diagnostic tests and, as a result, the COVID-19 diagnostic testing market may not develop or substantially grow. Our future success is substantially dependent on the manner in which the market for
+diagnostic testing develops and grows. If the market develops in a manner that does not facilitate demand for our products, or fails to develop or grow in the manner in which we expect or at all, our business, financial condition, results of
+operations and cash flows may be negatively affected. 
+Clinical trials necessary to support a future test kit submission will be expensive and may require the enrollment of large numbers of subjects, and suitable subjects may be difficult to identify and recruit. Delays
+or failures in our clinical trials will prevent us from commercializing any modified or new test kits and will adversely affect our business, operating results and prospects. 
+22 
+Table of Contents 
+Initiating and completing clinical trials necessary to support a future EUA, 510(k), PMA, or de novo submission, will be time consuming, expensive, and have an uncertain outcome. Moreover, the
+results of early clinical trials are not necessarily predictive of future results, and any test kit we advance into clinical trials may not have favorable results in later clinical trials. 
+Conducting successful clinical trials will require the enrollment of large numbers of subjects, and suitable subjects may be difficult to identify and recruit. Subject enrollment in clinical trials and completion of subject participation
+depends on many factors, including the nature of the trial protocol, the attractiveness of, or the discomforts and risks associated with, the indication of the underlying test kit, the availability of appropriate clinical trial investigators,
+support staff, and proximity of subjects to clinical sites and able to comply with the eligibility and exclusion criteria for participation in the clinical trial and subject compliance. In addition, subjects may not participate in our clinical
+trials if they choose to participate in contemporaneous clinical trials of competitive products. 
+In addition, our clinical trials may in the future be affected by the COVID-19 pandemic. For example, subjects may choose not to enroll or continue participating in the clinical trial as a result of the pandemic. As
+a result, potential subjects in our clinical trials may choose to not enroll, not participate in follow-up clinical visits, or drop out of the trial as a precaution against contracting COVID-19. Further, some subjects may not be able or willing to
+comply with clinical trial protocols if quarantines impede subject movement or interrupt healthcare services. We are unable to predict with confidence the duration of any such potential subject enrollment delays and difficulties, whether related to
+COVID-19 or otherwise. Delays in subject enrollment or failure of subjects to continue to participate in a clinical trial may cause an increase in costs and delays in the approval and attempted commercialization of our test kits or result in the
+failure of the clinical trial. 
+Development of sufficient and appropriate clinical protocols to demonstrate safety and efficacy are required and we may not adequately develop such protocols to support clearance and approval. Further, the FDA may
+require us to submit data on a greater number of subjects than we originally anticipated and/or for a longer follow-up period or change the data collection requirements or data analysis applicable to our clinical trials. In addition, despite
+considerable time and expense invested in our clinical trials, the FDA may not consider our data adequate for approval. Such increased costs and delays or failures could adversely affect our business, operating results and prospects. 
+We have been allocating a substantial portion of our resources to the development and commercialization of DPP SARS-CoV-2 Antigen test system, and our long term business success
+could be negatively impacted by our diversion of resources from our legacy business of diagnostic testing for other infectious diseases. 
+In the first quarter of 2020 we began committing substantially all of our financial and personnel resources to the development, manufacturing and commercialization of the DPP SARS-CoV-2 Antigen test system. Because
+we do not currently have an EUA from the FDA for the DPP SARS-CoV-2 Antigen test system, starting in the first quarter of 2021 we began allocating an increased portion of our resources to our legacy products. Our earlier and continuing resource
+allocation to the DPP SARS-CoV-2 Antigen test system may have negatively impacted, and may continue to negatively impact, our legacy product portfolio, as we have spent limited funds and time on updating pre-existing products and regulatory
+approvals and on completing products that were in development prior to our strategic decision to focus on the DPP SARS-CoV-2 Antigen test system. Our business could be negatively impacted by our allocation of significant resources to a global
+health threat that is unpredictable and could dissipate; there is no guarantee that current or anticipated demand will continue, or if demand does continue, that we will be able to produce in quantities to meet the demand. We intend to continue to
+reestablish our legacy business, but there can be no assurance that we will be able to successfully recommence the development and commercialization of our legacy products and products under development. 
+The diagnostic testing market, particularly with respect to COVID‑19, is highly competitive, and many of our competitors are larger, better established and have greater
+technical and marketing capabilities and financial and other resources than we have. 
+The diagnostics market, particularly with respect to COVID‑19 diagnostic tests, is highly competitive and we face substantial competition based on factors such as product quality, analytical performance, ease of use,
+price, manufacturing costs, customer service and reputation. Industry competition is also based the following additional factors: 
+● 
+patent protection; 
+● 
+scientific expertise; 
+● 
+ability to develop and market products and processes; 
+● 
+ability to obtain required regulatory approvals; 
+● 
+ability to manufacture cost‑effective products that meet applicable regulatory requirements; 
+● 
+access to adequate capital; and 
+● 
+ability to attract and retain qualified personnel. 
+23 
+Table of Contents 
+Numerous companies in the United States and internationally have introduced or announced their intention to introduce new products, services and technologies that could be used in substitution for the DPP SARS-CoV-2 Antigen test system. Many
+of those competitors are significantly larger, and have substantially greater financial, engineering and other resources, than us. In addition, our competitors may have or may develop products or technologies that currently or in the future
+will enable them to produce competitive products with greater capabilities or at lower costs than ours. If we are unable to compete effectively, we may fail to meet our strategic objectives, and our business, financial condition and operating
+results could be harmed. In addition, the production of an efficacious vaccine or other treatment for a disease underlying one of our products may reduce the demand for relevant diagnostic products. The success or failure, or perceived success
+or failure, of other companies may adversely impact our ability to obtain any future funding, or to ultimately commercialize the DPP SARS-CoV-2 Antigen test system. 
+We face risks related to an ongoing SEC investigation. 
+The SEC is conducting a non-public, fact-finding investigation relating to the May 2020 Offering and to the FDA’s revocation in June 2020 of an EUA for the DPP COVID-19 IgM/IgG system that was issued in April 2020. We received subpoenas from
+the SEC in July 2020 and April 2021 seeking the production of documents in connection with this investigation. In addition, the SEC delivered subpoenas in April 2021 to five of our employees (including our three executive officers, who consist
+of our Chief Executive Officer and President, our Executive Vice President and Chief Financial Officer, and our Executive Vice President and Chief Scientific and Technology Officer). An additional subpoena was issued in June 2021 to our former
+Interim Chief Executive Officer and Executive Chair. Each subpoena requested the production of documents relating to the same matters as are the subject of the subpoenas we received. 
+We are unable to predict what the timing or outcome of the SEC investigation will be or what, if any, consequences the SEC investigation may have with respect to our company or the six individuals mentioned above. The SEC investigation could
+result in considerable legal expenses, divert management’s attention from other business concerns and harm our business. If the SEC were to determine that legal violations occurred, we could be required to pay significant civil penalties or
+other amounts, and remedies or conditions could be imposed as part of any resolution. We can provide no assurances as to the outcome of the SEC investigation. 
+Stockholder litigation could negatively impact our business, operating results and financial condition. 
+We may incur additional costs in connection with the defense or settlement of existing and any future stockholder litigation, including four stockholder lawsuits to date that have been brought against us. See “Part I, Item 3. Legal
+Proceedings” below for additional information regarding existing lawsuits. These lawsuits or other future litigation may adversely affect the ability of our technical and management personnel, and our directors, to perform their normal
+responsibilities. We could incur significant costs in connection with any such litigation lawsuits, including costs associated with the indemnification of obligations to our directors, officers and other employees, as well as to third parties
+such as underwriters of our public offerings. 
+We expect competition with respect to testing solutions for COVID-19 to continue to increase and our success will depend on market acceptance of our products. 
+We expect competition to continue to increase as other established and emerging companies enter the market, as customer requirements evolve, and as new products, services and technologies are introduced. The entrance of new competitors is
+being encouraged by governmental authorities, which are offering funding to support development of testing solutions for COVID-19. Some of our existing or new competitors may have strong relationships with current and potential customers,
+including governmental authorities that may help fund those competing entities through grant awards or other funding. As a result, those competitors may be able to respond more quickly to new or changing regulatory requirements, new or emerging
+technologies, and changes in customer requirements. We do not currently have, or have an application pending for, an EUA from the FDA for any of the COVID-19 Diagnostic Test Systems. Even if we succeed in obtaining approvals for
+commercialization for one or more of the COVID-19 Diagnostic Test Systems, those products may not compete favorably, and we may not be successful in the face of existing and new products and technologies offered by our existing competitors or
+new companies entering our markets. Any failure to compete effectively could materially and adversely affect our business, financial condition and operating results. 
+24 
+Table of Contents 
+The COVID‑19 pandemic could continue to affect our suppliers and employees, and cause
+disruptions in current and future plans for operations and expansion. 
+The COVID‑19 pandemic may continue to directly and indirectly adversely impact our business, financial condition and operating results. The extent to which this will continue will depend on numerous evolving factors that are highly
+uncertain, rapidly changing and cannot be predicted with precision or certainty at this time. 
+Our business may continue to be disrupted due to the costs incurred as a result of additional necessary actions and preparedness
+plans to help ensure the health and safety of our employees and continued operations, including enhanced cleaning processes, protocols designed to implement appropriate social distancing practices, and/or adoption of additional wage and
+benefit programs to assist employees. We may also have difficulty meeting demand for our products if our employees are affected by COVID‑19, or if we do not have adequate space to produce our product with social distancing practices
+implemented. We also cannot predict the effect of COVID‑19 pandemic on our supply chain’s reliability and costs. 
+In addition, our business and operations, and the operations of our suppliers, may continue to be adversely affected by the
+COVID‑19 pandemic. The pandemic, including the related response, could cause disruptions due to potential suspension or slowdown of activities at our third‑party suppliers, manufacturing delays, or increased prices implemented by our
+suppliers. The COVID-19 pandemic has disrupted nearly every aspect of the global supply chain, including the manufacturing or delivery of some of the key supplies used in our tests. Many suppliers are experiencing shortages of required
+personnel as the result of the tight labor market and underlying raw material commodities. Some suppliers have been unable to deliver supplies in the quantity we need or at all. As a result, these suppliers may stop supplying us components
+and materials, limit the allocation of supply and equipment to us due to increased industry demand, or significantly increase their prices at any time with little or no advance notice. The adverse effect on our employees or suppliers could
+have an adverse impact on our business, results of operations and financial condition. 
+We operate in a fragmented, segmented, and rapidly changing industry, which is highly competitive with respect to numerous factors, and our success depends on our ability compete effectively
+with larger companies, develop new or enhance existing products, as well as acceptance of DPP over other diagnostic platform technologies. 
+Important competitive factors for our products include price, quality, performance, ease of use, and customer service. A few large corporations produce a wide variety of diagnostic tests and other medical devices and equipment. A larger
+number of mid‑size companies generally compete only in the diagnostic industry and a significant number of small companies produce only a few diagnostic products. As a result, the diagnostic test industry is highly fragmented and segmented. 
+More generally, the point‑of‑care diagnostics industry is undergoing rapid technological changes, with frequent introductions of new technology‑driven products and services. As new technologies become introduced into the point‑of‑care
+diagnostic testing market, we may be required to commit considerable additional efforts, time and resources to enhance our current product portfolio or develop new products. We may not have the available time and resources to accomplish this,
+and many of our competitors have substantially greater financial and other resources to invest in technological improvements. We may not be able to effectively implement new technology‑driven products and services or be successful in marketing
+these products and services to our customers, which would materially harm our operating results. 
+Although we own DPP patents, lateral flow technology is still a competitive platform to DPP, and lateral flow technology has a lower cost of manufacture than DPP products. Although the DPP platform has shown improved sensitivity as compared
+with conventional lateral flow platforms in a number of studies, several factors go into the development and performance attributes of products. Therefore the ability of our products to successfully compete will depend on several other factors,
+including our having a patented rapid test platform technology that differentiates DPP from lateral flow as well as from other diagnostic platform technologies. 
+There can be no assurance that our DPP patents or our products incorporating those patents will not be challenged at some time in the future. 
+25 
+Table of Contents 
+Our competitors may develop and commercialize more effective or successful products, and our research, development and commercialization efforts may not succeed. 
+We regularly commit substantial resources to research and development and the commercialization of our new or enhanced products. The research and development process usually takes a long time from inception to commercial launch. During each
+stage of this process there is a substantial risk that we will not achieve our goals in a timely fashion, or at all, and we may have to abandon a new or enhanced product in which we have invested substantial time and money. We expect to
+continue to incur significant costs related to our research and development activities. 
+Our products require significant development and investment prior to commercialization, including testing to demonstrate the products’ performance capabilities, cost‑effectiveness or other benefits. We must obtain regulatory approval before
+most products may be sold and additional development efforts on these products may be required before the products will be reviewed. However, regulatory authorities may not approve these products for commercial sale or may substantially delay
+or condition such approval. There may be little or no market for the product and entry into or development of new markets for our products may require an investment of substantial resources even if all applicable regulatory approvals are
+obtained. Furthermore, we may spend a significant amount of money on advertising or other activities and still fail to develop a market for the product. The success of our efforts may be affected by our ability to manufacture products in a
+cost‑effective manner, whether we can obtain necessary intellectual property rights and protection and our ability to obtain reimbursement authorizations in the markets where the product will be sold. Therefore, if we fail to develop and gain
+commercial acceptance for our products, or if competitors develop more effective products or a greater number of successful new products, customers may decide not to purchase our products. 
+Our products may not be able to compete with new diagnostic products or existing products developed by well‑established competitors, which would negatively affect our business. 
+The diagnostic industry is focused on the testing of biological specimens in a laboratory or at the point‑of‑care and is highly competitive and rapidly changing. Important competitive factors for our products include price, quality,
+performance, ease of use, and customer service. 
+A few large corporations produce a wide variety of diagnostic tests and other medical devices and equipment. A larger number of mid‑size companies generally compete only in the diagnostic industry and a significant number of small companies
+produce only a few diagnostic products. As a result, the diagnostic test industry is highly fragmented and segmented. 
+Some of our principal competitors may have considerably greater financial, technical and marketing resources than we do. Several companies produce diagnostic tests that compete directly with our testing product line, including Abbott
+(Alere), OraSure Technologies and Trinity Biotech. Some competitors offer broader product lines and may have greater name recognition than we have. These and other companies have or may have products incorporating molecular or other advanced
+technologies that over time could directly compete with our testing product line. We also face competition from certain of our distributors or former customers that have created or may decide to create, their own products to compete with ours. 
+As new products incorporating new technologies enter the market, our products may become obsolete or a competitor’s products may be more effective or more effectively marketed and sold. If our competitors’ products take market share from our
+products through more effective marketing or competitive pricing, our revenues, margins and operating results could be adversely affected. In addition, our revenues and operating results could be negatively impacted if some of our customers
+internally develop or acquire their own sample collection devices and use those devices in place of our products in order to reduce costs. 
+Our future revenues and operating results may be negatively affected by ongoing consolidation in the healthcare industry. 
+There has been a significant amount of consolidation in the healthcare industry. This consolidation has increased the competition to provide goods and services to customers. In addition, group purchasing organizations and integrated health
+delivery networks have served to concentrate purchasing decisions for some customers, which has also placed pricing pressure on medical device suppliers. Due to ongoing consolidation, there could be additional pressure on the prices of our
+products. 
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+We may not successfully manage the transition associated with the appointment of a new chief financial officer, which could have an adverse impact on us. 
+On October 18, 2021, we announced that Neil A. Goldman had notified the board of directors of his resignation as our Executive Vice President and Chief Financial Officer. On January 6, 2022, we announced that we had appointed Lawrence J.
+Steenvoorden as our Chief Financial Officer, effective as of January 5, 2022. 
+The effectiveness of our new Chief Financial Officer, and our senior leadership team generally, and any further transition as a result of these changes, could have a significant impact on our results of operations. Management transition is
+often difficult and inherently causes some loss of institutional knowledge, which could negatively affect our results of operations and financial condition. Our ability to execute our business strategies may be adversely affected by the
+uncertainty associated with these transitions. 
+Our continued growth depends on retaining our current key employees and attracting additional qualified personnel, and we may not be able to do so. 
+Our success depends to a large extent upon the skills and experience of our executive officers, sales, marketing, operations and scientific staff. We may not be able to attract or retain qualified employees due to the intense competition for
+qualified personnel among medical products businesses and academic and other research institutions, as well as to geographic considerations, our ability to offer competitive compensation and benefits, and other reasons. 
+If we are not able to attract and retain the necessary qualified personnel to accomplish our business objectives, we may experience constraints that will adversely affect our ability to effectively manufacture, sell and market our products
+to meet the demands of our customers and strategic partners in a timely fashion, or to support internal research and development programs. 
+We have entered into employment contracts with our Chief Executive Officer, Richard Eberly, our Chief Science & Technology Officer, Javan Esfandiari, and our Chief Financial Officer, Lawrence J. Steenvoorden. Due to the specific
+knowledge and experience of these executives regarding the industry, technology and market generally and to our company specifically, the loss of the services of any one of these executives could have a material adverse effect on us. We have
+not obtained a key man insurance policy on any officers other than Messrs. Eberly and Esfandiari. 
+Third‑party reimbursement policies and potential cost constraints could negatively affect our business. 
+The potential end‑users of our products include hospitals, physicians and other healthcare providers. If these end‑users do not receive adequate reimbursement for the cost of our products from their patients’ healthcare insurers or payors,
+the use of our products could be negatively impacted. Furthermore, the net sales of our products could also be adversely affected by changes in reimbursement policies of government or private healthcare payors. 
+Hospitals, physicians and other healthcare providers who purchase diagnostic products in the United States generally rely on third‑party payors, such as private health insurance plans, Medicare and Medicaid, to reimburse all or part of the
+cost of the product. Due to the overall escalating cost of medical products and services, especially in light of the COVID‑19 outbreak and its straining of healthcare systems across the globe, there is increased pressure on the healthcare
+industry, both foreign and domestic, to reduce the cost of products and services. Given the efforts to control and reduce healthcare costs in the United States, available levels of reimbursement may change for our existing products or products
+under development. Third‑party reimbursement and coverage may not be available or adequate in either the United States or international markets, current reimbursement amounts may be decreased in the future and future legislation, and regulation
+or reimbursement policies of third‑party payors, may reduce the demand for our products or our ability to sell our products on a profitable basis. 
+To the extent that we are unable to collect our outstanding accounts receivable, our operating results could be materially harmed. 
+There may be circumstances and timing that require us to accept payment terms, including delayed payment terms, from distributors or customers, which, if not satisfied, could cause financial losses. 
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+Table of Contents 
+We generally accept payment terms which require us to ship product before the contract price has been paid fully, and there also are circumstances pursuant to which we may accept further delayed payment terms pursuant to which we may
+continue to deliver product. To the extent that these circumstances result in significant accounts receivables and those accounts receivables are not paid on a timely basis, or are not paid at all, especially if concentrated in one or two
+customers, we could suffer financial losses. 
+We believe our success depends in part on the continued funding of, and our ability to
+participate in, large testing programs in the U.S. and worldwide, the funding of which may be reduced or discontinued or otherwise be unavailable to us. 
+We believe it to be in our best interests to meaningfully participate in large testing programs. Moreover many of these programs are funded by governments and other donors, and there can be no assurance that funding will not be reduced or
+completely discontinued. Participation in these programs also requires alignment and engagement with the many other participants in these programs, including the World Health Organization, or WHO, the U.S. Centers for Disease Control and
+Prevention, the U.S. Agency for International Development, foreign governments and their agencies, non‑governmental organizations, and HIV service organizations. If we are unsuccessful in our efforts to participate in these programs, our
+operating results could be materially harmed. 
+Developing testing guidelines could negatively affect sales of our products. 
+Government agencies may issue diagnostic testing guidelines or recommendations, which can alter the usage of our HIV testing products. New laws or guidelines, or changes to existing laws or guidelines, and the manner in which these new or
+changed laws and guidelines are interpreted and applied, could impact the degree to which our testing products are used. These developments could affect the frequency of testing, the number of people tested and whether the testing products are
+used broadly for screening large populations or in a more limited capacity. These factors could in turn affect the level of sales of our products and our results of operations. 
+Some of our programs are supported by government grant awards, and our inability to obtain additional grant awards in the future or to derive all of the funding potentially available under those
+awards could delay our development and introduction of products. 
+We have received funding under grant award programs funded by governmental agencies such as BARDA. To fund a portion of our future research and development programs, we may apply for additional grant funding from these or similar
+governmental agencies. Funding by these governmental agencies may, however, be significantly reduced or eliminated in the future for a number of reasons. For example, some programs are subject to a yearly appropriations process in Congress. We
+may not receive full funding under current or future grants because of budgeting constraints of the agency administering the program or unsatisfactory progress on the study being funded. 
+In addition, some or all of the funding available under grant awards may be conditioned upon our successfully meeting specified
+milestones or other conditions, and there can be no assurance that those milestones or conditions will be met. For example, in December 2020 we were awarded the Second Grant pursuant to a contract from BARDA that included funding milestones
+related to our development and pursuit of an EUA for a DPP Respiratory Antigen Panel and our submission for 510(k) clearance from the FDA for the DPP SARS CoV 2 Antigen System. 
+There can be no assurance that we will receive any future grant awards from any government agencies or that, if a grant award is obtained, we will receive the full amount potentially available under the grant award. Our inability to obtain
+future grant awards, or to earn the full amount available under those awards, could delay the development of our product candidates and the introduction of new products. 
+28 
+Table of Contents 
+We could be exposed to liability if we experience security breaches or other disruptions, which could harm our reputation and business . 
+We may be subject to cyber‑attacks whereby computer hackers may attempt to access our computer systems or our third-party IT service providers’ systems and, if successful, misappropriate personal or confidential information. In addition, a
+contractor or other third party with whom we do business may attempt to circumvent our security measures or obtain such information, and may purposefully or inadvertently cause a breach involving sensitive information. We will continue to
+evaluate and implement additional protective measures to reduce the risk and detect cyber incidents, but cyber‑attacks are becoming more sophisticated and frequent and the techniques used in such attacks change rapidly. Even though we take
+cyber‑security measures that are continuously reviewed and updated, our information technology networks and infrastructure may still be vulnerable due to sophisticated attacks by hackers or breaches. 
+Even the most well protected IT networks, systems, and facilities remain potentially vulnerable because the techniques used in security breaches are continually evolving and generally are not recognized until launched against a target and,
+in fact, may not be detected. Any such compromise of our or our third party’s IT service providers’ data security and access, public disclosure, or loss of personal or confidential business information, could result in legal claims proceedings,
+liability under laws to protect, privacy of personal information, and regulatory penalties, disrupt our operations, require significant management attention and resources to remedy any damages that result, damage our reputation and customers
+willingness to transact business with us, any of which could adversely affect our business. 
+Our ability to efficiently operate our business is reliant on information technology, and any material failure, inadequacy, interruption or security breach of that technology could harm our
+business. 
+We rely heavily on complex information technology systems across our operations and on the internet, including for management of inventory, invoices, purchase orders, shipping, interactions with our third‑party logistics providers, revenue
+and expense accounting, consumer call support, and various other processes and transactions. Our ability to effectively manage our business, coordinate the production, distribution and sale of our products, respond to customer inquiries, and
+ensure the timely and accurate recording and disclosure of financial information depends significantly on the reliability and capacity of these systems and the internet. 
+If any of the foregoing systems fails to operate effectively, problems with transitioning to upgraded or replacement systems, or disruptions in the operation of the internet, could cause delays in product sales and reduced efficiency of our
+operations. Significant expenditures could be required to fix any such problem. 
+If there is an increase in demand for our products, it could require us to expend considerable resources or harm our customer relationships if we are unable to meet that demand. 
+If there are significant or unexpected increases in the demand for our products, we may not be able to meet that demand without expending additional capital resources. This would increase our capital costs, which could negatively affect our
+earnings and liquidity in the short term. In addition, new manufacturing equipment or facilities may require FDA, WHO, and other regulatory approvals before they can be used to manufacture our products. To the extent we are unable to obtain or
+are delayed in obtaining such approvals, our ability to meet the demand for our products could be adversely affected. Furthermore, our suppliers may be unable or unwilling to expend the necessary capital resources or otherwise expand their
+capacity, which could negatively affect our business. 
+Our business could be negatively affected if we or our suppliers are unable to develop necessary manufacturing capabilities in a timely manner. If we fail to increase production volumes in a cost effective manner or if we experience lower
+than anticipated yields or production problems as a result of changes that we or our suppliers make in our manufacturing processes to meet increased demand, we could experience shipment delays or interruptions and increased manufacturing costs,
+which could also have a material adverse effect on our revenues and profitability. 
+If there are unexpected increases in demand for our products, we may be required to obtain additional raw materials in order to manufacture products to meet the increase in demand. However, some raw materials require significant ordering
+lead time and some are currently obtained from a sole supplier or a limited group of suppliers. It is also possible that one or more of our suppliers may become unwilling or unable to deliver materials to us. Any shortfall in our supply of raw
+materials and components, or our inability to quickly and cost‑effectively obtain alternative sources for this supply, could have a material adverse effect on our ability to meet increased demand for our products. This could negatively affect
+our total revenues or cost of sales and related profits. 
+29 
+Table of Contents 
+If we are unable to meet customer demand for our products, it could also harm our relationships with our customers and impair our reputation within the industry. This, in turn, could have a material adverse effect on our business. 
+Risks Related to Our Products 
+Industry adoption of alternative technology to our COVID-19 Diagnostic Test Systems could negatively impact our ability to compete successfully. 
+Of the 263 manufacturers and commercial laboratories to receive an EUA for COVID-19 diagnostics as of December 31, 2021, 66 were for serology tests, 200 were for molecular tests, and 14 were for antigen tests. Customers or the industry as a
+whole could adopt alternative technologies for testing, including molecular point of care testing, which could result in lower demand for our antigen test. Various advances in the treatment and monitoring of patients could cause lower demand
+for the COVID-19 Diagnostic Test Systems, including our revised DPP SARS CoV 2 Antigen System or for antigen testing for COVID-19 as a whole. 
+COVID-19 is prone to genetic mutations that may impact the ability of the COVID-19 Diagnostic Test Systems to adequately detect COVID-19, SARS-CoV-2 antigens and antibodies, and could adversely
+affect demand for the COVID-19 Diagnostic Test Systems and harm our competitive position. 
+False test results are a risk with all laboratory tests, including COVID-19 diagnostic tests. False results can occur in the presence or absence of a mutation in the COVID-19 virus. Multiple variations of the virus that causes COVID-19 are
+circulating globally and within the United States, including variants of concern initially identified in California, Brazil, South Africa and the United Kingdom. In the presence of a mutation in the virus, false results can occur if a mutation
+occurs in the region of the virus that the test is designed to assess. False results may occur with the COVID-19 Diagnostic Test Systems in the presence or absence of one or more COVID-19 mutations. If false negatives occur with the COVID-19
+Diagnostic Test Systems, it will may reduce customer confidence in the accuracy of the COVID-19 Diagnostic Test Systems and harm our competitive position. 
+For our business to succeed in the future, our current and future products must receive market acceptance. 
+Market acceptance and the timing of such acceptance, of our new products or technologies is necessary for our future success. To achieve market acceptance, we and our distributors will likely be required to undertake substantial efforts and
+spend significant funds to inform every one of the existence and perceived benefits of our products. We also may require government funding for the purchase of our products to help create market acceptance and expand the use of our products. 
+It may be difficult evaluate the market reaction to our products and our marketing efforts for new products may not be successful. The government funding we receive may be limited for new products. As such, there can be no assurance that any
+products will obtain significant market acceptance and fill the market need that is perceived to exist on a timely basis, or at all. 
+We may not have sufficient resources to effectively introduce and market our products, which could materially harm our operating results. 
+Introducing and achieving market acceptance for our new products will require substantial marketing efforts and will require us and/or our contract partners, sales agents, and/or distributors to make significant expenditures of time and
+money. In some instances we will be significantly or totally reliant on the marketing efforts and expenditures of our contract partners, sales agents, and distributors. If they do not have or commit the expertise and resources to effectively
+market the products that we manufacture, our operating results will be materially harmed. 
+New developments in health treatments and non‑diagnostic products may reduce or eliminate the demand for our products. 
+The development and commercialization of products outside of the diagnostics industry could adversely affect sales of our products. For example, the development of a safe and effective vaccine to COVID-19 or HIV or treatments for other
+diseases or conditions that our products are designed to detect, could reduce or eventually eliminate the demand for our HIV or other diagnostic products and result in a loss of revenues. 
+30 
+Table of Contents 
+Our future success will depend on our ability to cost-effectively increase manufacturing production capacity through the implementation of additional customized manufacturing automation
+equipment. 
+If we successfully commercialize the COVID-19 Diagnostic Test Systems or other new products, one of our key challenges will be to increase our production capacity to meet sales demand while maintaining product quality and reducing production
+costs. Our primary strategy to cost-effectively increase product capacity has been to implement customized automation equipment, and we have entered into agreements to acquire additional customized automation equipment. The equipment we order
+may not be delivered in a timely manner, and, once delivered, the equipment may require significant time and effort in order to operate in the manner required to produce high quality products. We experienced significant unexpected delays before
+our current automation equipment operated in the manner for which it was designed. The investments we make in this equipment may not yield the anticipated labor and material efficiencies. If we are not successful in introducing COVID-19
+Diagnostic Test Systems or other new products in accordance with our operating plans, we do not have the right to terminate the existing purchase orders for additional automation equipment and we may have excess capacity for a period of time.
+Our business, financial condition and results of operations could be harmed if we are unable to timely obtain automation equipment that meets our requirements or if there are significant increases in the costs of equipment. 
+Customer concentration creates risks for our business. 
+A significant portion of our revenues each year comes from a few large customers. Bio-Manguinhos constituted 51% of our total revenues in 2021 and 25% of our total revenues in 2020. We had another customer that accounted for 10% of our total
+revenues in 2021, and a third customer that accounted for 12% of our revenue in 2020. To the extent that Bio-Manguinhos or any other large customer fails to meet its purchase commitments, changes its ordering patterns or business strategy, or
+otherwise reduces its purchases or stops purchasing our products, or if we experience difficulty in meeting the demand by these customers for our products, our revenues and results of operations could be adversely affected. 
+Sales cycles for our products can be lengthy, which can cause variability and unpredictability in our business. 
+Some of our products may require lengthy and unpredictable sales cycles, which makes it more difficult to accurately forecast revenues in a given period and may cause revenues and operating results to vary from period to period. Our products
+may involve sales to large public and private institutions which may require many levels of approval and may be dependent on economic or political conditions and the availability of grant awards or other funding from government or public health
+agencies which can vary from period to period. There can be no assurance that purchases or funding from these agencies will occur or continue, especially if current negative economic conditions continue or intensify. As a result, we may expend
+considerable resources on unsuccessful sales efforts or we may not be able to complete transactions at all or on a schedule and in an amount consistent with our objectives. 
+We may face product liability claims for injuries. 
+The testing, manufacturing and marketing of medical diagnostic products involves an inherent risk of product liability claims. If we cannot successfully defend ourselves against product liability claims, we may incur substantial liabilities
+or be required to limit or cease sales of our products. We cannot be sure that we will not incur liabilities in excess of the policy limits of our existing product liability insurance coverage or that we will be able to continue to obtain
+adequate product liability insurance coverage in the future at an acceptable cost, or at all. In addition, a defect in the design or manufacture of our products could have a material adverse effect on our reputation in the industry and subject
+us to claims of liability for injury and otherwise. Any substantial underinsured loss resulting from such a claim could have a material adverse effect on our profitability, and the damage to our reputation in the industry could have a material
+adverse effect on our business. 
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+Our customers may not adopt rapid point‑of‑care diagnostic testing. 
+Rapid point‑of‑care tests are beneficial because, among other things, they can be administered by healthcare providers in their own facilities or used by consumers at home without sending samples to central laboratories. But currently the
+majority of diagnostic tests used by physicians and other healthcare providers in the U.S. are provided by clinical reference laboratories and hospital‑based laboratories. In some international markets, such as Europe, diagnostic testing is
+performed primarily by centralized laboratories. Future sales of our products will depend, in part, on our ability to expand market acceptance of rapid point‑of‑care testing and successfully compete against laboratory testing methods and
+products. However, we expect that clinical reference and other hospital‑based laboratories will continue to compete vigorously against our rapid point‑of‑care products. Even if we can demonstrate that our products are more cost effective, save
+time, or have better performance or other benefits, physicians, other healthcare providers and consumers may resist changing to rapid point‑of‑care tests and instead may choose to obtain diagnostic results through laboratory tests. If we fail
+to achieve and expand market acceptance of our rapid point‑of‑care diagnostic tests with customers, it would have a negative effect on our future sales growth. 
+If our products do not perform properly, it may affect our revenues, stock price and reputation. 
+Our products may not perform as expected. For example, a defect in one of our diagnostic products or a failure by a customer to follow proper testing procedures may cause the product to report inaccurate information. Identifying the root
+cause of a product performance or quality issue can be difficult and time consuming. 
+If our products do not to perform in accordance with the applicable label claims or otherwise in accordance with the expectations or needs of our customers, customers may switch to a competing product or otherwise stop using our products,
+and our revenues could be negatively affected. If this occurs, we may be required to implement holds or product recalls and incur warranty obligations. Furthermore, the poor performance by one or more of our products could have an adverse
+effect on our reputation, our continuing ability to sell products and the price of our common stock. 
+Financial, Economic and Financing Risks 
+Because of our liquidity limitations, we have concluded there is a substantial doubt about our ability to continue as a going concern and we may require additional capital to fund our
+operations, which capital may not be available to us on acceptable terms or at all. 
+As described under “Part I, Item 1. Business─Overview”, “Part II, Item 7. Management’s Discussion and Analysis of Financial
+Condition and Results of Operations-Substantial Doubt as to Going Concern Status” and “─Liquidity and Capital Resources”, management has determined we could not be certain that our plans and initiatives to increase our total revenues and
+improve our liquidity position would be effectively implemented within one year after the filing date of this report, when the consolidated financial statements accompanying this report, or the Accompanying Financial Statements, are being
+issued. Without giving effect to the prospect of raising additional capital pursuant to our at-the-market offerings under the ATM Agreement, increasing product revenue in the near future or executing other mitigating plans, many of which are
+beyond our control, it is unlikely that we will be able to generate sufficient cash flows to meet our required financial obligations, including our debt service and other obligations due to third parties. The existence of these conditions
+raises substantial doubt about our ability to continue as a going concern for the twelve-month period following the filing date of this report, when the Accompanying Financial Statements are being issued. 
+Our diagnostic test products require ongoing funding to continue our current development and operational plans, and we have a history of net losses. We intend to continue to expend substantial resources in the short term in connection with
+the July Purchase Orders (see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition”), but we may encounter challenges in fulfilling our obligations, and therefore receiving revenue, under those purchase orders. See
+“─Because of our liquidity and operational limitations, including the availability of staffing and supply chain resources that are necessary but outside of our control, we will not be able to timely fulfill all of the requirements of the July
+Purchase Order from Bio‑Manguinhos and it is difficult to reliably estimate the extent to which we will be able to timely meet those requirements” below. We will also incur costs associated with research and development activity, corporate
+administration, business development, debt service, marketing and selling of our products, and litigation. In addition, other unanticipated costs may arise. 
+As of December 31, 2021, we had outstanding indebtedness of $20.0 million under the Credit Agreement. We may face further liquidity challenges if we are unable to meet obligations set forth in the Credit Agreement, including a financial
+covenant requiring that we achieve specified minimum total revenue amounts measured as of the end of each quarter. A breach of the minimum total revenue covenant or any other covenant in the Credit Agreement would result in a default under the
+Credit Agreement, which could enable the Lender to declare all amounts outstanding thereunder, together with accrued interest, to be immediately due and payable. We cannot assure you that, in such an event, we would have sufficient assets to
+pay amounts due under the Credit Agreement. See “─The failure to comply with the terms of the Credit Agreement could result in a default under its terms and, if uncured, could result in action against our pledged assets and dilution of our
+stockholders” below. 
+32 
+Table of Contents 
+As a result, we may need to raise capital in one or more debt or equity offerings to fund our operations and obligations. There can be no assurance, however, that we will be successful in raising the necessary capital or that any such
+offering will be available to us on terms acceptable to us, or at all. If we are unable to raise additional capital that may be needed on terms in sufficient amounts or on terms acceptable to us, it could have a material adverse effect on our
+company. If we are unable to raise additional capital in sufficient amounts or on terms acceptable to us, we may have to significantly delay, scale back or discontinue our deliveries under our outstanding customer purchase orders or the
+development or commercialization of one or more of our products or one or more of our other research and development initiatives. The outbreak of the COVID-19 pandemic has significantly disrupted world financial markets, negatively impacted
+U.S. market conditions and may reduce opportunities for us to seek out additional funding. A decline in the market price of our common stock, whether or not coupled with the suspension of trading of our common stock on the Nasdaq Capital
+Market, could make it more difficult for us to sell equity or equity-related securities in the future at a time and price that we deem appropriate, or at all. 
+Continuing doubt about our ability to continue as a going concern may materially and adversely affect the price of our common stock, and it may be more difficult for us to obtain financing. Any uncertainty about our ability to continue as a
+going concern may also adversely affect our relationships with current and future employees, suppliers, vendors, customers, grantors, creditors, regulators and investors, who may become concerned about our ability to meet our ongoing financial
+obligations. There is risk that, among other things: 
+• 
+third parties lose confidence in our ability to continue to operate in the ordinary course, which could impact our ability to execute on our business strategy; 
+• 
+it may become more difficult for us to attract, retain or replace employees; 
+• 
+employees could be distracted from performance of their duties; 
+• 
+we could lose some or a significant portion of our liquidity, either due to stricter credit terms from vendors, or, in the event we undertake a Chapter 11 proceeding and conclude that we need to procure
+debtor-in-possession financing, an inability to obtain any needed debtor-in-possession financing or to provide adequate protection to certain secured lenders to permit us to access some or all of our cash; and 
+• 
+our vendors and service providers could seek to renegotiate the terms of our arrangements, terminate their relationships with us or require financial assurances from us. 
+The Accompanying Financial Statements have been prepared assuming we will continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business
+for the twelve-month period following the date of this report. As such, the Accompanying Financial Statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amounts, or the amount
+and classification of liabilities that may result should we be unable to continue as a going concern. 
+Because of our liquidity and operational limitations, including the availability of staffing
+and supply chain resources that are necessary but outside of our control, we may not be able to timely fulfill all of the requirements of the July Purchase Order from Bio-Manguinhos and it is difficult to reliably estimate the extent to which
+we will be able to timely meet those requirements. 
+In July 2021 we received the July Purchase Orders, which we had been pursuing for an extended period of time. See “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition below. Our delivery of the full number of tests
+covered by each of the July Purchase Orders may be affected by limitations of our supply chain, staffing and liquidity, including matters that are outside our control. We have established internal plans designed to maximize the number of tests
+we can deliver timely, or at all, pursuant to the July Purchase Orders, and we expect to continue to revise those plans as we obtain new information. The number of uncertainties related to third parties - including the availability of required
+personnel, raw materials and other resources - currently preclude us, however, from reliably estimating the extent to which we will be able to fulfill the July Purchase Orders on time and at an acceptable cost, or at all. Our ability to
+generate revenue from the July Purchase Orders, and the margins we can realize from that revenue, will depend on the availability and cost of human, material and other resources required to build and deliver tests in accordance with the July
+Purchase Orders. 
+33 
+Table of Contents 
+In anticipation of receipt of significant purchase orders in 2021, during the first half of 2021 we continued to invest in automating our test manufacturing processes, all of which are now based in the United States, by, among other actions,
+validating and implementing automated lines to expand our manufacturing capabilities. We did not know, however, the number or mix of tests for which purchase orders might be received, and we now need to configure our automated manufacturing
+lines for the most efficient use feasible, subject to numerous staffing and other constraints, in producing DPP SARS-CoV-2 Antigen tests and HIV 1/2 STAT-PAK Assays contemplated by the July Purchase Orders. The number of tests to be delivered
+pursuant to the July Purchase Orders significantly exceeds the capacity of our automated manufacturing lines. We have neither the time nor the resources to increase our automated manufacturing capacity meaningfully during the delivery periods
+contemplated by the July Purchase Orders. 
+We therefore are relying upon manual assembly processes to produce a significant portion of the tests deliverable under the July Purchase Orders and other customer orders, which require that we successfully recruit, hire and train a
+significant number of personnel for employment at our Long Island, New York facilities. Identifying, hiring and retaining assembly line, formulations, production, warehouse, quality control and other personnel for our Long Island facilities at
+acceptable compensation levels has been challenging in the past, and those circumstances have been exacerbated by the continuing effects of the COVID-19 pandemic, which may discourage potential employees from returning to a physical worksite at
+compensation levels that are acceptable to us, or at all. Upon receiving the July Purchase Orders, we launched a broad campaign to recruit and retain manufacturing and other personnel and, more recently, we temporarily increased pay for
+manufacturing personnel. Our recruiting efforts have not, however, proven sufficient to overcome the tight labor market that has been impacting many U.S. companies, including employers on Long Island, and we have not been able to hire the
+number of manufacturing personnel required to meet our internal plans for delivery of all of the tests contemplated by the July Purchase Orders. Our continued inability to identify and hire sufficient numbers of manufacturing personnel, and to
+manage turnover of currently existing and newly hired personnel, would continue to materially limit our ability to deliver tests under the July Purchase Orders. 
+Our delivery of tests covered by the July Purchase Orders has also been negatively affected by limitations on raw materials, components and other supplies. We must obtain additional supplies in order to manufacture tests to meet the
+requirements of the July Purchase Orders. Some supplies require significant ordering lead time, and some are currently obtained from a sole supplier or a limited group of suppliers. With some of these suppliers, we do not have long term
+agreements and instead purchase materials, components and other supplies through a purchase order process. The COVID-19 pandemic has disrupted nearly every aspect of the global supply chain, including the manufacturing or delivery of some of
+the key supplies used in our tests. Many suppliers are experiencing shortages of required personnel as the result of the tight labor market and underlying raw material commodities. Some suppliers have been unable to deliver supplies in the
+quantity we need or at all. As a result, these suppliers may stop supplying us components and materials, limit the allocation of supply and equipment to us due to increased industry demand, or significantly increase their prices at any time
+with little or no advance notice. Because of the foregoing limitations, as exacerbated by the quantities and timing of supplies required to timely fulfill the July Purchase Orders, we have been required to seek to identify new sources of
+supplies to replace or augment our past sources, which has proven difficult to do in a reasonable time period and on commercially reasonable terms, if at all. Moreover, scarcity has caused increases in the cost of some supplies. Our inability
+to timely obtain required supplies has had an adverse effect on our ability to timely fulfill the July Purchase Orders as well as on our total revenues, cost of sales, related margin and cash flow. 
+We have incurred losses in recent years and we are uncertain about our future profitability and cash flow. 
+We incurred an operating loss every year from 2014 through 2021. Under our operating plans, we have made, and plan to continue to make, significant investments in our production capacity, including in expanding facilities and automating
+manufacturing, and in our sales and marketing, regulatory approval, and research and development activities. Our ability to achieve profitability and generate cash flow in the future will depend on our ability to increase sales of our existing
+products and to successfully introduce new and enhanced products into the marketplace, all while controlling and managing our expenses consistent with our operating plan. 
+34 
+Table of Contents 
+Because we do not currently have an EUA from the FDA for any of the COVID-19 Diagnostic Test Systems, we have been unable to
+increase our revenues in accordance with our operating plan. As a result, our operating results have not met our expectations. If we experience a continuing delay in obtaining, or are unable to obtain, an EUA for one or more of our COVID-19
+Diagnostic Test Systems, our operating results will be further harmed and we may not be able to generate the cash flow needed to fund the investments in our production capacity and other activities. In such an event, we will be required to
+implement one or both of the following: 
+• 
+We could reduce the level, or otherwise delay the timing, of the anticipated investments in our production capacity and other activities, which would likely curtail or delay the growth in our
+business contemplated by our operating plan and could impair or defer our ability to achieve profitability and generate cash flow. Moreover, if we were to further reduce the number of our personnel, there can be no assurance that
+we would be able, when desirable, to successfully rehire or rebuild our workforce. 
+• 
+We could raise additional funds through public or private financings, strategic relationships, or other arrangements, to the extent funding would be available to us on acceptable terms or at all. If
+we succeed in raising additional funds through the issuance of equity or convertible securities, then the issuance could result in substantial dilution to existing stockholders. Furthermore, the holders of these new securities or
+debt may have rights, preferences and privileges senior to those of the holders of our common stock. 
+In such circumstances, we also would need to forego acquisition opportunities, which could impede our ability to grow our business. 
+Our financial results may fluctuate. 
+From quarter to quarter and year to year, our operating results can fluctuate, which could cause our growth or financial performance to fail to meet the expectations of investors and securities analysts. Sales to our distributors and other
+customers may not meet expectations because of lower than expected customer demand or other factors, including continued economic volatility and disruption, reduced governmental funding, and other circumstances described elsewhere in this
+report. A variety of factors could also contribute to the variability of our financial results, including infrequent, unusual or unexpected changes in revenues or costs. 
+Different products provide dissimilar contributions to our gross product margin. Accordingly, our operating results could also fluctuate and be negatively affected by the mix of products sold and the relative prices and gross product margin
+contribution of those products. Failure to achieve operating results consistent with the expectations of investors and securities analysts could adversely affect our reputation and the price of our common stock. 
+The failure to comply with the terms of the Credit Agreement could result in a default under its terms and, if uncured, could result in action against our pledged assets and dilution of our
+stockholders. 
+On September 3, 2019, we and certain of our subsidiaries, as guarantors, entered into the Credit Agreement, under which we received a $20,000,000 senior secured term loan credit facility that was drawn in full on September 4, 2019. The
+Credit Agreement is secured by a first priority, perfected lien on substantially all of our property and assets, including our equity interests in our subsidiaries. See “Part II, Item 7. Management’s Discussion and Analysis of Financial
+Condition and Results of Operations─Liquidity and Capital Resources─Sources of Funds─Credit Agreement.” 
+The Credit Agreement also contains financial covenants requiring that we (a) maintain aggregate unrestricted cash of not less than
+$3,000,000 at all times, which must be held in one or more accounts subject to the first priority perfected security interests of the Lender under the Credit Agreement, and (b) achieve specified minimum total revenue requirements for the
+twelve months preceding each quarter end. The minimum total revenue amounts over the next year increase from $42.0 million for the twelve months ending March 31, 2022 to $47.4 million for the twelve months ending December 31, 2022 (see note
+13 to the Accompanying Financial Statements). These minimum revenue requirements were developed for purposes of the Credit Agreement and do not reflect the internal estimates and plans used by our management and board of directors to
+establish operational goals for managing our business. The minimum revenue requirements for the twelve months ending December 31, 2022 do not, for example, take into account the challenges we are facing in ramping up production, including
+hiring personnel and obtaining commitments from our supply chain as described above in “─Because of our liquidity and operational limitations, including the availability of staffing and supply chain resources that are necessary but outside of
+our control, we will not be able to timely fulfill all of the requirements of the July Purchase Orders and it is difficult to reliably estimate the extent to which we will be able to timely meet those requirements.” 
+35 
+Table of Contents 
+In addition, the Credit Agreement contains covenants that restrict our ability to finance future operations or capital needs or to engage in other business activities. The Credit Agreement restricts the ability of our company and the
+restricted subsidiaries to: 
+• 
+incur, assume or guarantee additional Indebtedness (as defined in the Credit Agreement); 
+• 
+repurchase capital stock; 
+• 
+make other restricted payments, including paying dividends and making investments; 
+• 
+create liens; 
+• 
+sell or otherwise dispose of assets, including capital stock of subsidiaries; 
+• 
+enter into agreements that restrict dividends from subsidiaries; 
+• 
+enter into mergers or consolidations; and 
+• 
+enter into transactions with affiliates. 
+A breach of the minimum total revenue covenant or any other covenant in the Credit Agreement would result in a default under the Credit Agreement. Upon an event of default under the Credit Agreement, the Lender could elect to declare all
+amounts outstanding thereunder, together with accrued interest, to be immediately due and payable. In such an event, there can be no assurance that we would have sufficient liquidity to fund payment of the amounts that would be due under the
+Credit Agreement or that, if such liquidity were not available, we would be successful in raising additional capital on acceptable terms, or at all, or in completing any other endeavor to continue to be financially viable and continue as a
+going concern. Our inability to raise additional capital on acceptable terms in the near future, whether for purposes of funding payments required under the Credit Agreement or providing additional liquidity needed for our operations, could
+have a material adverse effect on our business, prospects, results of operations, liquidity and financial condition. 
+Servicing our debt will require a significant amount of cash. Our ability to generate sufficient cash to service our debt depends on many factors beyond our control. 
+Our ability to make payments on and to refinance our debt, to fund planned capital expenditures, and to maintain sufficient working
+capital depends on our ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. We cannot assure you that
+our business will generate sufficient cash flow from operations or from other sources in an amount sufficient to enable us to service our debt or to fund our other liquidity needs. Our operations used $30.9 million in cash in 2021 and $18.9
+million in 2020. If our cash flow and capital resources are insufficient to allow us to make scheduled payments on our debt, we may need to seek additional capital or restructure or refinance all or a portion of our debt on or before the
+maturity thereof, any of which could have a material adverse effect on our business, financial condition or results of operations. We cannot assure you that, if needed, we would be able to refinance any of our debt on commercially reasonable
+terms or at all, or that the terms of that debt will allow any of the above alternative measures or that these measures would satisfy our scheduled debt service obligations. If we are unable to generate sufficient cash flow to repay or
+refinance our debt on favorable terms, it could significantly adversely affect our financial condition. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition. Any
+refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. There can be no assurance that we will be able to obtain any financing
+when needed. 
+36 
+Table of Contents 
+Our ability to utilize our net operating loss carryforwards and certain other tax attributes may be limited. 
+Our ability to utilize our federal net operating loss and tax credit carryforwards may be limited under Sections 382 and 383 of the U.S. Internal Revenue Code of 1986, or the Code. The limitations apply if we experience an “ownership change”
+(generally defined as a greater than 50 percentage point change (by value) in the ownership of our equity by certain stockholders over a rolling three-year period). Similar provisions of state tax law may also apply to limit the use of our
+state net operating loss carryforwards. 
+We experienced an ownership change in 2004 and 2006, and we estimate a portion of our existing federal net operating loss carryforwards are subject to an annual limitation under Section 382 of the Code. Since our ownership change in 2006, we
+have not assessed whether an ownership change has subsequently occurred. If we have experienced an ownership change at any time since our ownership change in 2006, we may already be subject to limitations on our ability to utilize our net
+operating losses and other tax attributes generated before such additional ownership change to offset post-change taxable income. In addition, future changes in our stock ownership, which may be outside of our control, may trigger an ownership
+change and, consequently, the limitations under Sections 382 and 383 of the Code. As a result, if or when we earn net taxable income, our ability to use our pre-change net operating loss carryforwards and other tax attributes to offset such
+taxable income may be subject to limitations, which could adversely affect our future cash flows. 
+The LIBOR calculation method may change, and LIBOR is expected to be phased out after 2021, which may adversely affect our interest expenses under the Credit Agreement. 
+Loans under the Credit Agreement bear interest at a rate per annum equal to the sum of (a) the greater of the one‑month London Interbank Offered Rate, or LIBOR, and 2.5% plus (b) 8.75%. At any time at which an event of default has occurred
+and is continuing, the interest rate will increase by 4.0%. Accrued interest is payable on a monthly basis. On July 27, 2017, the U.K. Financial Conduct Authority announced that it will no longer require banks to submit rates for the
+calculation of LIBOR after 2021. On November 30, 2020, ICE Benchmark Administration, or IBA, the administrator of LIBOR, with the support of the United States Federal Reserve and the United Kingdom’s Financial Conduct Authority, announced plans
+to consult on ceasing publication of USD LIBOR on December 31, 2021 for only the one week and two month USD LIBOR tenors, and on June 30, 2023 for all other USD LIBOR tenors. While this announcement extended the transition period to June 2023,
+the United States Federal Reserve concurrently issued a statement advising banks to stop new USD LIBOR issuances by the end of 2021. In light of these recent announcements, the future of LIBOR at this time is uncertain and any changes in the
+methods by which LIBOR is determined or regulatory activity related to LIBOR’s phaseout could cause LIBOR to perform differently than in the past or cease to exist. 
+In response to concerns regarding the future of LIBOR, the Board of Governors of the Federal Reserve System and the Federal Reserve Bank of New York convened the Alternative Reference Rates Committee, or ARRC, to identify alternatives to
+LIBOR. The ARRC has recommended benchmark replacement procedures to assist issuers in continued capital market entry while safeguarding against LIBOR’s discontinuation. The initial steps in the ARRC’s recommended provision reference variations
+of the Secured Overnight Financing Rate, or SOFR. It is not possible to predict the effect of these changes, other reforms or the establishment of alternative reference rates in the United States or elsewhere. 
+Pursuant to the Credit Agreement, if LIBOR becomes unavailable in the future an alternative benchmark rate will apply. To the extent our interest rates increase as a result, our interest expense will increase, in which event we may have
+difficulties making interest payments and funding our other fixed costs, and our available cash flow for general corporate requirements may be adversely affected. 
+Our operating results may be negatively affected by changes in foreign currency exchange rates. 
+In the past our exposure to foreign currency exchange rate risk has not been material. Nevertheless, sales of our products are subject to currency risks, since changes in the values of foreign currencies relative to the value of the U.S.
+dollar can render our products comparatively more expensive. The fluctuations in the exchange rate could negatively impact international sales of our products, as could changes in the general economic conditions. 
+37 
+Table of Contents 
+The revenues and expenses of our Malaysian, German and Brazilian subsidiaries are recorded in Malaysian Ringgit, in Euros and Brazilian Real, respectively. Revenues and expenses denominated in foreign currencies are translated into U.S.
+dollars for purposes of reporting our consolidated financial results, and, consequently, our operating results reflect exposure to foreign currency exchange rates, which could increase in the future. 
+Our foreign subsidiaries’ revenues and expenses and the translation of their financial results into U.S. dollars may be negatively affected by fluctuations in the exchange rate. Favorable movement in exchange rates have benefited us in prior
+periods. However, where there are unfavorable currency exchange rate fluctuations, our consolidated financial statements could be negatively affected. Furthermore, fluctuations in exchange rates could affect year‑to‑year comparability of
+operating results. In the past, we have not generally entered into hedging instruments to manage our currency exchange rate risk, but we may need to do so in the future. However, our attempts to hedge against these risks may not be successful.
+If we are unable to successfully hedge against unfavorable foreign currency exchange rate movements, our consolidated financial results may be adversely impacted. 
+We operate in countries where there is or may be widespread corruption. 
+We have a policy in place prohibiting our employees, distributors and agents from engaging in corrupt business practices, including activities prohibited by the U.S. Foreign Corrupt Practices Act. Nevertheless, because we work through
+independent sales agents and distributors outside the United States, we do not have control over the day to day activities of such independent agents and distributors. In addition, in the donor funded markets in Africa where we sell our
+products, there is significant oversight from PEPFAR, the Global Fund, and advisory committees comprised of technical experts concerning the development and establishment of national testing protocols. This is a process that includes an overall
+assessment of a product that includes extensive evaluations of product performance, as well as price and delivery. In Brazil, where we have had numerous product collaborations with FIOCRUZ, the programs through which our products may be
+deployed are all funded by the Brazilian Ministry of Health. Although FIOCRUZ is affiliated with the Brazilian Ministry of Health, which is FIOCRUZ’s sole customer, FIOCRUZ is not the exclusive supplier for the Ministry of Health. However,
+because each of our previous collaborations with FIOCRUZ incorporates a technology transfer aspect, we believe we have a competitive advantage versus other suppliers to the Brazilian Ministry of Health, assuming other aspects of our product
+offering through FIOCRUZ are otherwise competitive in comparison. We have no knowledge or reason to know of any activities by our employees, distributors or sales agents of any actions which could be in violation of the FCPA, although there can
+be no assurance of this. In addition, corruption is a problematic factor in doing business in Brazil, and, to the extent bribery and similar practices continue to exist in Brazil, we may be at a competitive disadvantage in gaining business in
+Brazil, particularly when competing with non U.S. companies. 
+Our subsidiary Chembio Diagnostics Malaysia Sdn. Bhd. is located in Malaysia. There have been numerous high‑profile corruption cases, and corruption is one of the most problematic factors for doing business in Malaysia. While the Malaysian
+government has acknowledged the problem, it appears that endemic corruption is continuing and that market‑based principles are not applied in cases involving individuals with high‑level political access. To the extent bribery and similar
+practices continue to exist in Malaysia, U.S. companies such as ours, which are subject to U.S. laws making it illegal to pay bribes to foreign officials, may make us less competitive in winning business in Malaysia when competing with non‑U.S.
+companies. 
+We base our estimates or judgments relating to critical accounting policies on assumptions that can change or prove to be incorrect. 
+Our financial statements have been prepared in accordance with accounting principles generally accepted in the United States and
+our discussion and analysis of financial condition and results of operations is based on such statements. The preparation of financial statements requires management to make estimates and assumptions that affect the amounts reported in the
+financial statements and accompanying notes. We continuously evaluate significant estimates used in preparing our financial statements, including those related: to (1) revenue recognition, including uncertainties related to variable
+consideration, milestones and bill and hold arrangements; (2) stock based compensation; (3) allowance for uncollectible accounts receivable; (4) inventory reserves and obsolescence; (5) customer sales returns and allowances; (6)
+contingencies; (7) income taxes; (8) goodwill and intangibles; (8) business acquisition; and (10) research and development costs. 
+38 
+Table of Contents 
+Our estimates are based on historical experience and various other assumptions that we believe to be reasonable, as set forth in our discussion and analysis of financial condition and results of operations, the
+results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these and other estimates if our assumptions change or
+if actual circumstances differ from those in our assumptions. If our operating results fall below the expectations of securities analysts and investors, the price of our common Stock may decline. 
+Risks Related to Intellectual Property 
+Our success depends on our ability to protect our proprietary technology. We rely on trade secret laws and agreements with our key employees and other third parties to protect our proprietary
+rights, and we cannot be sure that these laws or agreements will adequately protect our rights. 
+Our industry places considerable importance on obtaining patent, trademark and trade secret protection, as well as other intellectual property rights, for new technologies, products and processes. Our success depends, in part, on our ability
+to develop and maintain a strong intellectual property portfolio or obtain licenses to patents and technologies, both in the United States and in other countries. If we cannot continue to develop, obtain and protect intellectual property
+rights, our revenues and gross profits could be adversely affected. Moreover, our current and future licenses or other rights to patents and other technologies may not be adequate for the operation of our business. 
+As appropriate, we intend to file patent applications and obtain patent protection for our proprietary technology. These patent applications and patents will cover, as applicable, compositions of matter for our products, methods of making
+those products, methods of using those products and apparatuses relating to the use or manufacture of those products. However, there have been changes to the patent laws and proposed changes to the rules of the U.S. Patent and Trademark Office,
+which may impact our ability to protect our technology and enforce our intellectual property rights. For example, in 2011, the U.S. enacted sweeping changes to the U.S. patent system under the Leahy‑Smith America Invents Act, including changes
+that would transition the U.S. from a “first‑to‑invent” system to a “first‑to‑file” system and alter the processes for challenging issued patents. These changes could increase the uncertainties and costs surrounding the prosecution of our
+patent applications and the enforcement or defense of our issued patents. 
+We believe that factors such as the technological and creative skills of our personnel, strategic relationships, new product developments, frequent product enhancements and name recognition are essential to our success. All our management
+personnel are bound by non‑disclosure agreements. If personnel leave our employment, in some cases we would be required to protect our intellectual property rights pursuant to common law theories which may be less protective than provisions of
+employment, non‑competition or non‑disclosure agreements. 
+We seek to protect our proprietary products under trade secret and copyright laws, enter into license agreements for various materials and methods employed in our products, and enter into strategic relationships for distribution of the
+products. These strategies afford only limited protection. We currently have some foreign patents issued, and we are seeking additional patent protection in several other foreign jurisdictions for our DPP and optical technology. We have
+licenses to reagents (antigens and peptides) used in several of our products and products under development. Despite our efforts to protect our proprietary assets, and respect the intellectual property rights of others, we participate in
+several markets where intellectual property rights protections are of little or no value. This can place our products and our company at a competitive disadvantage. 
+Moreover, issued patents remain in effect for a fixed period and after expiration will not provide protection of the inventions they cover. Once our patents expire, we may be faced with increased competition, which could reduce our revenues.
+We may also not be able to successfully protect our rights to unpatented trade secrets and know‑how. 
+To facilitate development and commercialization of a proprietary technology base, we may need to obtain additional licenses to patents or other proprietary rights from other parties. Obtaining and maintaining these licenses, which may not be
+available, may require the payment of up‑front fees and royalties. In addition, if we are unable to obtain these types of licenses, our product development and commercialization efforts may be delayed or precluded. 
+39 
+Table of Contents 
+Any future intellectual property disputes could require significant resource and limit or eliminate our ability to sell products or use certain technologies. 
+We may be required to expend substantial resources in asserting or protecting our intellectual property rights, or in defending suits related to intellectual property rights. We may seek to enforce our patents or other intellectual
+property rights through litigation. Such litigation is prevalent and is expected to continue. In our business, there are a large number of patents and patent applications similar to our products, and additional patents may be issued to third
+parties relating to our product areas. We, our customers or our suppliers may be sued for infringement of patents or misappropriation of other intellectual property rights with respect to one or more of our products. We may also have disputes
+with parties that license patents to us if we believe the license is no longer needed for our products or the licensed patents are no longer valid or enforceable. 
+There are a large number of patents in our industry, and the claims of these patents appear to overlap in many cases. Therefore there is a significant amount of uncertainty regarding the extent of patent protection and infringement.
+Companies may have pending patent applications, which are typically confidential for the first eighteen months following filing that cover technologies we incorporate in our products. Accordingly, we may be subjected to substantial damages for
+past infringement or be required to modify our products or stop selling them if it is ultimately determined that our products infringe a third party’s proprietary rights. In addition, governmental agencies could commence investigations or
+criminal proceedings against our employees or us relating to claims of misuse or misappropriation of another party’s proprietary rights. 
+If we are involved in litigation or other legal proceedings with respect to patents or other intellectual property and proprietary technology, it could adversely affect our revenues, results of operations, market share and business because
+(1) it could consume a substantial portion of managerial and financial resources; (2) its outcome would be uncertain and a court may find that our patents are invalid or unenforceable in response to claims by another party or that the
+third‑party patent claims are valid and infringed by our products; (3) the pendency of any litigation may in and of itself cause our distributors and customers to reduce or terminate purchases of our products; (4) a court could award a
+preliminary and/or permanent injunction, which would prevent us from selling our current or future products; and (5) an adverse outcome could subject us to the loss of the protection of our patents or to liability in the form of past royalty
+payments, penalties, reimbursement of litigation costs and legal fees, special and punitive damages, or future royalty payments, any of which could significantly affect our future earnings. 
+Under certain contracts with third parties, we may indemnify the other party if our products or activities have actually or allegedly infringed upon, misappropriated or misused another party’s proprietary rights. Furthermore, our products
+may contain technology provided to us by third parties, and we may be unable to determine in advance whether such technology infringes the intellectual property rights of a third party. These other parties may also not be required or
+financially able to indemnify us in the event that an infringement or misappropriation claim is asserted against us. 
+There may also be other types of disputes that we become involved in regarding intellectual property rights, including state, federal or foreign court litigation, and patent interference, patent reissue, patent reexamination, or trademark
+opposition proceedings in the United States Patent and Trademark Office. Opposition or revocation proceedings could be instituted in a foreign patent office as well. These proceedings permit certain persons to challenge the validity of a patent
+on the grounds that it was known from the prior art. The filing of such proceedings, or the issuance of an adverse decision in such proceedings, could result in the loss of valuable patent rights that could have a material adverse effect on our
+business, financial condition, results of operations and growth prospects. 
+Risks Related to Our Reliance on Third Parties 
+Our use of third‑party suppliers, some of which may constitute our sole supply source, for certain important product components and materials presents risks that could have negative consequences
+for our business. 
+We purchase certain HIV antigens, a syphilis antigen, COVID-19 antibodies and antigens, the nitrocellulose, and certain other critical components used in our STAT PAK, STAT VIEW, SURE CHECK and DPP product lines from a sole or limited number
+of sources. If for any reason these suppliers become unwilling or unable to supply our antigen, nitrocellulose, or other critical component needs, we believe that alternative supplies could be obtained at a competitive cost. However, a change
+in any of the antibodies, antigens, nitrocellulose or other critical components used in our products would require additional development work and clinical trials, as well as approval by the FDA and other regulatory agencies. In addition, it
+may be difficult to find such an alternate supply source in a reasonable time period or on commercially reasonable terms, if at all. As a result, the termination or limitation of our relationship with one or more of these suppliers could
+require significant time to complete, increase our costs, and disrupt or discontinue our ability to manufacture and sell the affected products. In addition, governmental purchasers or funding programs in a particular country may require that we
+purchase key components from suppliers in that country, which could significantly limit our ability to obtain the components with the quality, and at the price, we seek. 
+40 
+Table of Contents 
+With some of these suppliers, we do not have long‑term agreements and instead purchase components and materials through a purchase order process. As a result, these suppliers may stop supplying us components and materials, limit the
+allocation of supply and equipment to us due to increased industry demand, or significantly increase their prices at any time with little or no advance notice. Our reliance on a limited number of suppliers could also result in delivery
+problems, reduced control over product pricing and quality, and our inability to identify and qualify another supplier in a timely manner. 
+Moreover, some of these suppliers may experience financial difficulties that could prevent them from supplying us with components or subassemblies used in the design and manufacture of our products. In addition, these suppliers may
+experience manufacturing delays or shut downs due to circumstances beyond their control, such as complications related to COVID‑19, labor issues, political unrest or natural disasters. 
+Any supply chain deficiencies could materially and adversely affect our ability to fulfill customer orders and our results of operations. The availability of critical components and materials from sole‑ or limited source suppliers could
+reduce our control over pricing, quality and timely delivery, increase our costs, could disrupt our ability to manufacture and sell, and preclude us from manufacturing and selling, certain of our products into one or more markets. Any such
+event could have a material adverse effect on our results of operations, cash flow and business. 
+Our ability to grow our business will be limited if we fail to maintain existing distribution channels or develop new distribution channels. 
+We collaborate with laboratories, diagnostic companies and distributors in order to sell our products. The sale of our products depends in large part on our ability to sell products to these customers and on the marketing and distribution
+abilities of the companies with which we collaborate and work with. 
+Relying on distributors or third parties to market and sell our products could negatively impact our business for various reasons, including: (1) we may not be able to find suitable distributors for our products on satisfactory terms, or at
+all; (2) agreements with distributors may prematurely terminate or may result in litigation between the parties; (3) our distributors or other customers may not fulfill their contractual obligations and distribute our products in the manner or
+at the levels we expect; (4) our distributors may prioritize their own private label products that compete with our products; (5) our existing distributor relationships or contracts may preclude or limit us from entering into arrangements with
+other distributors; and (6) we may not be able to negotiate new or renew existing distribution agreements on acceptable terms, or at all. 
+We will try to maintain and expand our business with distributors and customers and make every effort to require that they fulfill their contractual obligations, but there can be no assurance that such companies will do so or that new
+distribution channels will be available on satisfactory terms. If we are unable to do so, our business will be negatively impacted. 
+Our U.S. government contracts require compliance with numerous laws and increase our risk and liability. 
+We are currently receiving funding from the U.S. government related to the DPP SARS-CoV-2 Antigen System, the DPP Respiratory Antigen Panel and DPP Zika, and our growth strategy may target sales to U.S. government entities. As a result of
+our U.S. government funding and potential product sales to the U.S. government, we must comply with laws and regulations relating to the award, administration and performance of U.S. government contracts. U.S. government contracts typically
+contain a number of extraordinary provisions that would not typically be found in commercial contracts and which may create a disadvantage and additional risks to us as compared to competitors that do not rely on government contracts. As a U.S.
+government contractor, we are subject to increased risks of investigation, criminal prosecution and other legal actions and liabilities to which purely private sector companies are not. The results of any such actions could adversely impact our
+business and have an adverse effect on our consolidated financial performance. 
+A violation of specific laws and regulations could result in the imposition of fines and penalties or the termination of our contracts, as well as suspension or debarment. The suspension or debarment in any particular case may be limited to
+the facility, contract or subsidiary involved in the violation or could be applied to our entire enterprise in certain severe circumstances. Even a narrow scope suspension or debarment could result in negative publicity that could adversely
+affect our ability to renew contracts and to secure new contracts, both with the U.S. government and private customers, which could materially and adversely affect our business and results of operations. Fines and penalties could be imposed for
+failing to follow procurement integrity and bidding rules, employing improper billing practices or otherwise failing to follow rules relating to billing on cost‑plus contracts, receiving or paying kickbacks, or filing false claims, among other
+potential violations. In addition, we could suffer serious reputational harm and the value of our common stock could be negatively affected if allegations of impropriety related to such contracts are made against us. 
+41 
+Table of Contents 
+Our U.S. government contracts are subject to future funding and the government’s choice to exercise options, and may be terminated at the government’s convenience. 
+Our contracts with the U.S. government are subject to future funding and are subject to the right of the government to terminate the contracts in whole or in part for its convenience. There is pressure for the U.S. government to reduce
+spending. The non‑appropriation of funds or the termination for the government’s convenience of our contracts could negatively affect our financial results. If levels of U.S. government expenditures and authorizations for emerging diseases
+decrease or shift to programs in areas where we do not offer products or are not developing product candidates, or if the U.S. government otherwise declines to exercise its options under its contracts with us, our business, revenues and other
+operating results would suffer. 
+Risks Related to Regulations 
+COVID‑19 diagnostic tests, including the COVID-19 Diagnostic Test Systems, are subject to changes in CLIA, FDA, ANVISA and other regulatory requirements. 
+Our COVID-19 Diagnostic Test Systems are subject to regulations of the FDA and other regulatory requirements, including ANVISA, Brazil’s health regulatory agency. The regulations regarding the manufacture and sale of COVID-19 Diagnostic Test
+Systems may be unclear and are subject to recurring change. Newly promulgated regulations could require changes to COVID-19 Diagnostic Test Systems, necessitate additional procedures, or make it impractical or impossible for us to market
+COVID-19 Diagnostic Test Systems for certain uses, in certain markets, or at all. The FDA and other regulatory authorities also have the ability to impose new or additional requirements relating to the COVID-19 Diagnostic Test Systems. The
+implementation of such changes or new or additional requirements may result in a substantial additional costs and could delay or make it more difficult or complicated to sell our products. 
+On February 4, 2020, the U.S. Department of Health and Human Services issued a declaration that the threat to public health posed by COVID-19 justify the emergency use of unapproved in vitro diagnostics for the detection or diagnosis of
+SARS-CoV-2. Under Section 564 of the Food, Drug, and Cosmetic Act, because the U.S. Department of Health and Human Services has issued this declaration, the Commissioner of the FDA is authorized to issue EUAs to permit certain developers of
+SARS-CoV-2 diagnostics to begin offering the tests for detection and diagnosis of COVID-19 without having completed the normally applicable FDA review and clearance or approval process for marketing authorization. We received an EUA for the DPP
+COVID-19 IgM/IgG System on April 14, 2020, which was subsequent revoked by the FDA on June 16, 2020. Such revocation precludes the sale of DPP COVID-19 IgM/IgG Systems in the United States unless and until a further regulatory approval or
+authorization is obtained. We have not received a subsequent EUA for any of the COVID-19 Diagnostic Test Systems, and we do not currently have an application pending for any such EUA. Moreover, market and regulatory requirements continue to
+change at a rapid pace. The FDA has announced, for example, that it intends to update its EUA templates with additional considerations related to the impact of genetic variants on test performance as the FDA learns more about the COVID-19
+disease and its knowledge in this area progresses. The time required to obtain marketing authorizations and other approvals from regulatory authorities is unpredictable. The standards that the FDA and its foreign counterparts use when
+evaluating clinical trial data can change, and do often change, during development, which makes it difficult to predict with any certainty how they will be applied. If we make future submissions to the FDA, we may also encounter unexpected
+delays or increased costs due to new government regulations, including future legislation or administrative action, or changes in FDA policy during the period of FDA regulatory review. There can be no assurance that if we are to make a
+submission of any future EUA application, we will be successful in obtaining an EUA that would permit us to offer and sell any COVID-19 Diagnostic Test System in the United States. 
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+We are subject to governmental export controls that could impair our ability to compete in international markets. 
+The U.S. and various foreign governments have imposed controls, export license requirements and restrictions on the export of certain products and technologies. We must export our products in compliance with export controls in the United
+States, including the Commerce Department’s Export Administration Regulations and various economic and trade sanctions established by the Treasury Department’s Office of Foreign Assets Controls. We may not always be successful in obtaining
+necessary export licenses, and our failure to obtain required import or export approval for our products or limitations on our ability to export or sell our products imposed by these laws may harm our international and domestic sales and
+adversely affect our revenue. Noncompliance with these laws could have negative consequences, including government investigations, penalties and reputational harm. 
+If the U.S. government imposes restrictions on the export of COVID-19 Diagnostic Test Systems, or any of our other products, such restrictions could have a material impact on our ability to sell our products to existing or potential
+customers outside of the United States and harm our ability to compete internationally. Any change in export regulations or legislation, or change in the countries, persons or technologies targeted by export regulations, could decrease our
+ability to export or sell our products outside the United States or to existing or potential customers with international operations. Changes in our ability to sell our products outside the United States could negatively impact our business
+prospects and adversely affect our business and results of operations. 
+Because we may not be able to obtain or maintain the necessary regulatory approvals for some of our products, we may not generate revenues in the amounts we expect, or in the amounts necessary
+to continue our business. Our existing products as well as our manufacturing facility must meet quality standards and are subject to inspection by a number of domestic regulatory and other governmental and non‑governmental agencies. 
+All of our proposed and existing products are subject to regulation in the United States by the FDA, the U.S. Department of Agriculture, and/or other domestic and international governmental, public health agencies, regulatory bodies or
+non-governmental organizations. In particular, we are subject to strict governmental controls on the development, manufacture, labeling, distribution and marketing of our products. The process of obtaining required approvals or clearances
+varies according to the nature of, and uses for, a specific product. These processes can involve lengthy and detailed laboratory testing, human or animal clinical trials, sampling activities, and other costly, time consuming procedures. The
+submission of an application to a regulatory authority does not guarantee that the authority will grant an approval or clearance for that product. Each authority may impose its own requirements and can delay or refuse to grant approval or
+clearance, even though a product has been approved in another country. 
+The time taken to obtain approval or clearance varies depending on the nature of the application and may result in the passage of a significant period of time from the date of submission of the application. As an example, the time required
+to obtain an EUA from the FDA for COVID‑19 tests has lengthened markedly over the past months due to, among other things, application volume. Delays in the approval or clearance processes increase the risk that we will not succeed in
+introducing or selling the subject products, and we may determine to devote our resources to different products. 
+Changes or developments in government regulations, policies or interpretations could increase our costs and could require us to undergo additional trials or procedures, or could make it impractical or impossible for us to market our products
+for certain uses, in certain markets, or at all. For example, on June 16, 2020, the FDA revoked the EUA it had granted for the DPP COVID-19 IgM/IgG System based in part on performance criteria identified after the EUA was granted on April 14,
+2020. We do not currently have an EUA from the FDA for any of the COVID-19 Diagnostic Test Systems, and we do not currently have an application pending for any such EUA. Moreover, FDA regulations, policies and procedures with respect to
+COVID-19 tests may be significantly impacted by the availability of vaccines for COVID-19 and changes in the FDA’s prioritization guidance. Similarly, the regulatory pathway to 510(k) clearance by the FDA for COVID-19 tests is unclear in light
+of limited FDA feedback resulting in part from the FDA’s constrained resources. 
+Changes in government regulations may adversely affect our financial condition and results of operations because we may have to incur additional expenses if we are required to change or implement new testing, manufacturing and control
+procedures. If we are required to devote resources to develop such new procedures, we may not have sufficient resources to devote to research and development, marketing, or other activities that are critical to our business. We are, for
+example, expending resources to modify the design of the COVID-19 Diagnostic Test System to achieve performance targets consistent with the FDA’s performance criteria issued subsequent to the granting of our original EUA. 
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+We can manufacture and sell our products only if we comply with regulations and quality standards established by government agencies such as the FDA and the U.S. Department of Agriculture as well as by non-governmental organizations such as
+the International Organization for Standardization, or ISO, and WHO. We have implemented a quality control system that is intended to comply with applicable regulations. Although FDA approval is not required for the export of our products,
+there are export regulations promulgated by the FDA that specifically relate to the export of our products that require compliance with the FDA’s quality system requirements, or QSRs, and that also require meeting certain documentary
+requirements regarding the approval of the product in export markets. We also may be subject to import regulations in connection with international sourcing of components and materials incorporated in the manufacturing of our products. 
+If we do not comply with FDA or other regulatory requirements, we may be required to suspend production or sale of our products or institute a recall, which could result in higher costs and a
+loss of revenues. 
+Regulations of the FDA and other federal, state and foreign regulatory agencies have significant effects on many aspects of our operations and the operations of our suppliers and distributors, including packaging, labeling, manufacturing,
+adverse event reporting, recalls, distribution, storage, advertising, promotion and record keeping. We are subject to routine inspection by the FDA and other agencies to determine compliance with FDA regulatory requirements, including QSRs, in
+the United States and other applicable regulations worldwide, including ISO standards. We believe that our facilities and procedures are in material compliance with the FDA requirements and ISO standards, but the regulations may be unclear and
+are subject to change, and we cannot be sure that the FDA or other regulators will agree with our compliance with these requirements. The FDA and foreign regulatory agencies may require post marketing testing and surveillance to monitor the
+performance of approved or cleared products or impose conditions on any product clearances or approvals that could restrict the distribution or commercial applications of those products. Regulatory agencies may impose restrictions on our or our
+distributors’ advertising and promotional activities or preclude these activities altogether if a noncompliance is believed to exist. In addition, the subsequent discovery of previously unknown problems with a product may result in restrictions
+on the product or additional regulatory actions, including withdrawal of the product from the market. 
+Our inability to comply with the applicable requirements of the FDA can result in, among other things, 483 notices, warning letters, administrative or judicially imposed sanctions such as injunctions, recall or seizure of products, civil
+penalties, withdrawal of product registrations, total or partial suspension of production, refusal to grant premarket clearance for devices, a determination that a device is not approvable, marketing clearances or approvals, or criminal
+prosecution. For example, in February 2020, we received a “not approvable” letter from the FDA with respect to our premarket approval submission on our DPP HIV Syphilis multiplex test for commercial use in the United States, in June 2020 we
+received notice from the FDA that the EUA for the DPP COVID-19 IgM/IgG System had been revoked, and in January 2021 we received notice from the FDA that it was declining to review the DPP SARS CoV 2 Antigen System based on its updated
+prioritization guidance, under which review of the system was not a priority. The ability of our suppliers to supply critical components or materials and of our distributors to sell our products could also be adversely affected if their
+operations are determined to be out of compliance. Such actions by the FDA and other regulatory bodies could adversely affect our revenues, costs and results of operations. 
+We must frequently make judgment decisions with respect to compliance with applicable laws and regulations. If regulators subsequently disagree with how we have sought to comply with these regulations, we could be subjected to substantial
+civil and criminal penalties, as well as product recall, seizure or injunction with respect to the sale of our products. Our reputation could be substantially impaired if we are assessed any civil and criminal penalties and limit our ability to
+manufacture and market our products which could have a material adverse effect on our business. 
+Our inability to respond to changes in regulatory requirements could adversely affect our business. 
+We believe that our existing products and procedures are in material compliance with all applicable FDA regulations, ISO requirements, and other applicable regulatory requirements, but the regulations regarding the manufacture and sale of
+our products and QSR, ISO and other requirements may be unclear and are subject to change. Newly promulgated regulations could require changes to our products, necessitate additional clinical trials or procedures, or make it impractical or
+impossible for us to market our products for certain uses, in certain markets, or at all. The FDA and other regulatory authorities also have the ability to change the requirements for obtaining product approval and/or impose new or additional
+requirements as part of the approval process. These changes or new or additional requirements may occur after the completion of substantial clinical work and other costly development activities. The implementation of such changes or new or
+additional requirements may result in additional clinical trials and substantial additional costs and could delay or make it more difficult or complicated to obtain approvals and sell our products. In addition, the FDA may revoke an Emergency
+Use Authorization under which our products are sold, where it is determined that the underlying health emergency no longer exists or warrants such authorization. Such revocation would preclude the sale of our affected products unless and until
+a further regulatory approval or authorization is obtained. For example, For example, on June 16, 2020, the FDA revoked the EUA it had granted for the DPP COVID‑19 IgM/IgG System based in part on performance criteria identified after the
+Emergency Use Authorization was granted on April 14, 2020, and since that time we expended resources to design the new COVID-19 Diagnostic Test Systems, including the DPP Respiratory Antigen Panel. We do not currently have an EUA from the FDA
+for any of the COVID-19 Diagnostic Test Systems, and we do not currently have an application pending for any such EUA We cannot anticipate or predict the effect, if any, that these types of changes might have on our business, financial
+condition or results of operations. 
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+Demand for our products may be affected by FDA regulation of laboratory developed tests. 
+Regulatory responsibility over instruments, test kits, reagents and other devices used to perform diagnostic testing by clinical laboratories is covered by the FDA, including our Micro Reader analyzer. The FDA has previously taken the
+position that it has regulatory authority over laboratory developed tests, or LDTs, but has exercised enforcement discretion by not regulating most LDTs performed by high complexity CLIA certified laboratories. LDTs are tests designed,
+developed, and performed in house by a laboratory. These laboratories are subject to CLIA regulation but such laboratories have previously not been subject to regulation by the FDA under the agency’s medical device requirements. 
+The FDA announced that it would begin regulating LDTs, and in October 2014 the FDA issued proposed guidance on the regulation of LDTs for public comment. In November 2016, however, the FDA announced it would not finalize the proposed
+guidance prior to the end of the Obama administration. In January 2017 the FDA released a discussion paper synthesizing public comments on the 2014 draft guidance documents and outlining a possible approach to regulation of LDTs. The discussion
+paper has no legal status and does not represent a final version of the LDT draft guidance documents. We cannot predict what policies the Biden administration will adopt with respect to LDTs. If the FDA increases regulation of LDTs, it could
+make it more difficult for laboratories and other customers to continue offering LDTs that involve molecular testing. This, in turn, could reduce demand for our products and adversely impact our revenues. 
+Disruptions at the FDA and other government agencies caused by funding shortages or global health concerns could hinder their ability to hire, retain or deploy key leadership and other
+personnel, or otherwise prevent new or modified products from being developed, cleared, approved, authorized, or commercialized in a timely manner or at all, which could negatively impact our business. 
+The ability of the FDA and other government agencies to review and clear, approve, or authorize new products can be affected by a variety of factors, including government budget and funding levels, statutory, regulatory, and policy changes,
+the agencies’ ability to hire and retain key personnel and accept the payment of user fees, and other events that may otherwise affect the agencies’ ability to perform routine functions. Average review times at these agencies have fluctuated in
+recent years as a result. In addition, government funding of other government agencies that fund research and development activities is subject to the political process, which is inherently fluid and unpredictable. Disruptions at the FDA and
+other agencies may also slow the time necessary for medical devices or modifications to be cleared or approved, medical devices to be reviewed and/or approved by necessary government agencies, which would adversely affect our business. For
+example, over the last several years, including for 35 days beginning on December 22, 2018, the U.S. government has shut down several times and certain regulatory agencies, such as the FDA, have had to furlough critical FDA employees and stop
+critical activities. 
+Separately, in response to the global COVID-19 pandemic, on January 29, 2021, the FDA announced its intention to resume inspections of manufacturing facilities and products, that would be deemed “mission-critical.” The FDA’s assessment of
+whether an inspection is mission-critical considers many factors related to the public health benefit of U.S. patients having access to the product subject to inspection. These factors include, but are not limited to, whether the products have
+received breakthrough therapy designation or regenerative medicine advanced therapy designation, or are products used to diagnose, treat, or prevent a serious disease or medical condition for which there is no other appropriate substitute. Both
+for-cause and pre-approval inspections can be deemed mission-critical. When determining whether to conduct a mission-critical inspection, FDA takes into account concerns about the safety of its investigators, employees at a site or facility,
+and where applicable, clinical trial participants and other patients at investigator sites. Regulatory authorities outside the United States may adopt similar restrictions or other policy measures in response to the COVID-19 pandemic. If a
+prolonged government shutdown occurs, or if global health concerns continue to prevent the FDA or other regulatory authorities from conducting their regular inspections, reviews or other regulatory activities, it could significantly impact the
+ability of the FDA or other regulatory authorities to timely review and process our regulatory submissions, which could have a material adverse effect on our business. 
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+In addition to FDA requirements, we are subject to numerous other federal, state and foreign government regulations, compliance with which could increase our costs and affect our operations. 
+In addition to the FDA regulations previously described, other federal, state and foreign laws and regulations may restrict our ability to sell products in those jurisdictions. 
+We must comply with numerous laws related to safe working conditions, environmental protection, disposal of hazardous substances, fire hazard control, manufacturing practices and labor or employment practices. Compliance with these laws or
+any new or changed laws regulating our business could result in substantial costs. Due to the number of laws and regulations governing our industry, and the actions of a number of government agencies that could affect our operations, it is
+impossible to reliably predict the full nature and impact of these laws and regulations. To the extent the costs and procedures associated with complying with these laws and requirements are substantial or it is determined that we do not
+comply, our business and results of operations could be adversely affected. 
+Ongoing changes in healthcare regulation could negatively affect our revenues, business and financial condition. 
+There have been several proposed changes in the United States at the federal and state level for comprehensive reforms regarding the payment for, the availability of and reimbursement for healthcare services. These proposals have ranged from
+fundamentally changing federal and state healthcare reimbursement programs, including providing comprehensive healthcare coverage to the public under government‑funded programs, to minor modifications to existing programs. One example is the
+Patient Protection and Affordable Care or the Affordable Care Act, the Federal healthcare reform law enacted in 2010. 
+Healthcare reform initiatives will continue to be proposed, and may reduce healthcare related funding in an effort. It is impossible to predict the ultimate content and timing of any healthcare reform legislation and its resulting impact on
+us. If significant reforms are made to the healthcare system in the United States, or in other jurisdictions, those reforms may increase our costs or otherwise negatively effect on our financial condition and results of operations. 
+The EU landscape concerning medical devices recently evolved. On May 25, 2017, the E.U. Medical Devices Regulation entered into force, which repeals and replaces the Council Directive 93/42/EEC, or E.U. Medical Devices Directive, and
+Directive 90/385/EEC, or AIMDD. Unlike directives, which must be implemented into the national laws of the EU member states, regulations are directly applicable (i.e., without the need for adoption of E.U. member state laws implementing them)
+in all E.U. member states and are intended to eliminate current differences in the regulation of medical devices among E.U. member states. Devices lawfully placed on the market pursuant to the E.U. Medical Devices Directive or the AIMDD prior
+to May 26, 2021 may generally continue to be made available on the market or put into service until May 26, 2025, provided that the requirements of the transitional provisions are fulfilled. In particular, the certificate in question must still
+be valid. However, even in this case, manufacturers must comply with a number of new or reinforced requirements set forth in the E.U. Medical Devices Regulation with regard to registration of economic operators and of devices, post-market
+surveillance, market surveillance and vigilance requirements. 
+Subject to the transitional provisions, in order to sell our products in E.U. member states, our products must comply with the general safety and performance requirements of the E.U. Medical Devices Regulation, which repeals and replaces EU
+Medical Devices Directive and the AIMDD. Compliance with these requirements is a prerequisite to be able to affix the CE mark to our products, without which they cannot be sold or marketed in the EU. To demonstrate compliance with the general
+safety and performance requirements, we must undergo a conformity assessment procedure, which varies according to the type of medical device and its (risk) classification. Except for low risk medical devices (Class I), where the manufacturer
+can self-assess the conformity of its products with the general safety and performance requirements (except for any parts which relate to sterility, metrology or reuse aspects), a conformity assessment procedure requires the intervention of a
+notified body. The notified body would typically audit and examine the technical file and the quality system for the manufacture, design and final inspection of our devices. If satisfied that the relevant product conforms to the relevant
+general safety and performance requirements, the notified body issues a certificate of conformity, which the manufacturer uses as a basis for its own declaration of conformity. The manufacturer may then apply the CE mark to the device, which
+allows the device to be placed on the market throughout the E.U. If we fail to comply with applicable laws and regulations, we would be unable to affix the CE mark to our products, which would prevent us from selling them within the E.U. 
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+We must inform the notified body that carried out the conformity assessment of the medical devices that we market or sell in the E.U. and the EEA of any planned substantial changes to our quality system or substantial changes to our medical
+devices that could affect compliance with the general safety and performance requirements laid down in Annex I to the E.U. Medical Devices Regulation or cause a substantial change to the intended use for which the device has been CE marked. The
+notified body will then assess the planned changes and verify whether they affect the products’ ongoing conformity with the E.U. Medical Devices Regulation. If the assessment is favorable, the notified body will issue a new certificate of
+conformity or an addendum to the existing certificate attesting compliance with the general safety and performance requirements and quality system requirements laid down in the Annexes to the E.U. Medical Devices Regulation. 
+We may incur additional costs if we do not comply with privacy, security and breach notification regulations. 
+We believe that we are not a covered entity nor a business associate of a covered entity and are not responsible for complying with the Health Insurance Portability and Accountability Act of 1996, or HIPAA. Even though we likely are not a
+covered entity under HIPAA, we do have in place administrative, technical and physical safeguards to protect the privacy and security of consumers’ personal information. We are required to comply with varying state privacy, security and breach
+reporting laws. If we fail to comply with existing or new laws and regulations related to properly transferring data containing consumers’ personal information, we could be subject to monetary fines, civil penalties or criminal sanctions. Also,
+there are other federal and state laws that protect the privacy and security of consumers’ personal information, and we may be subject to enforcement by various governmental authorities and courts resulting in complex compliance issues. We
+could incur damages under state laws pursuant to an action brought by a private party for the wrongful use or disclosure of consumers’ personal information. 
+Failure to comply with European and U.K. data protection requirements could increase our costs. 
+The E.U. adopted a comprehensive overhaul of its data protection regime from the prior national legislative approach to a single European Economic Area Privacy Regulation called the General Data Protection Regulation, or GDPR, which came
+into effect on May 25, 2018. The E.U. data protection regime extends the scope of the E.U. data protection law to all foreign companies processing data of E.U. residents. It imposes a strict data protection compliance regime with severe
+penalties of up to the greater of 4% of worldwide turnover and €20 million and includes new rights such as the “portability” of personal data. Although the GDPR applies across the E.U. without a need for local implementing legislation, as had
+been the case under the prior data protection regime, local data protection authorities have the ability to interpret the GDPR, which has the potential to create inconsistencies on a country‑by‑country basis. We have evaluated these new
+requirements and have implemented a plan to ensure compliance. Complying with the enhanced obligations imposed by the GDPR may result in significant costs to our
+business and require us to amend certain of our business practices. Further, we have no assurances that violations will not occur, particularly given the complexity of the GDPR, as well as the uncertainties that accompany new, comprehensive
+legislation. Further, from January 1, 2021, we have to comply with both the GDPR and the GDPR as incorporated into United Kingdom national law, the latter regime having the ability to separately fine up to the greater of £17.5 million or 4% of
+global turnover. The relationship between the United Kingdom and the EU in relation to certain aspects of data protection law remains unclear, for example around how data can lawfully be transferred between each jurisdiction, which may expose
+us to further compliance risk. The European Commission has adopted an adequacy decision in favor of the UK, enabling data transfers from EU member states to the UK without additional safeguards. However, the UK adequacy decision will
+automatically expire in June 2025 unless the European Commission re-assesses and renews/ extends that decision. 
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+If we are not able to manufacture products in accordance with applicable requirements, it could adversely affect our business. 
+Our products must meet detailed specifications, performance standards and quality requirements. As a result, our products and the materials used in their manufacture or assembly undergo regular inspections and quality testing. Factors such
+as defective materials or processes, mechanical failures, human errors, environmental conditions, changes in materials or production methods, and other events or conditions could cause our products or the materials used to produce or assemble
+our products to fail inspections and quality testing or otherwise not perform in accordance with our label claims or the expectations of our customers. 
+If we are not able to meet the applicable specifications, performance standards, quality requirements or customer expectations could adversely affect our ability to manufacture and sell our products or comply with regulatory requirements.
+These events could, in turn, adversely affect our revenues and results of operations. 
+Healthcare fraud and abuse laws could adversely affect our business and results of operations. 
+There are various federal and state laws targeting fraud and abuse in the healthcare industry to which we are subject, including anti‑kickback laws, laws constraining the sales, false claims laws, marketing and promotion of medical devices
+by limiting the kinds of financial arrangements that manufacturers of these products may enter into with physicians, hospitals, laboratories and other potential purchasers of medical devices. There are other laws we are subject to that require
+us to report certain transactions between it and healthcare professionals. Violations of these laws are punishable by criminal or civil sanctions, including substantial fines, imprisonment and exclusion from participation in government
+healthcare programs. Many of the existing requirements are new and have not been definitively interpreted by state authorities or courts, and available guidance is limited. We could face enforcement action and fines and other penalties, and
+could receive adverse publicity, unless and until we are in full compliance with these laws, all of which could materially harm us. Furthermore, changes in or evolving interpretations of these laws, regulations, or administrative or judicial
+interpretations, may require us to change our business practices or subject our business practices to legal challenges, which could have a material adverse effect on our business, financial condition and results of operations. 
+If we expand our international presence, it may increase our risks and expose our business to regulatory, cultural or other challenges. 
+There are several of factors that could adversely affect the performance of our business and/or cause us to incur substantially increased costs because of our international presence and sales, including: (1) uncertainty in the application of
+foreign laws and the interpretation of contracts with foreign parties; (2) cultural and political differences that favor local competitors or make it difficult to effectively market, sell and gain acceptance of our products; (3) exchange rates,
+currency fluctuations, tariffs and other barriers, extended payment terms and dependence on international distributors or representatives; (4) trade protection measures, trade sanctions and import/export licensing requirements; (5) our
+inability to obtain or maintain regulatory approvals or registrations for our products; (6) economic conditions, political instability, the absence of available funding sources, terrorism, civil unrest, war and natural disasters in foreign
+countries; (7) reduced protection for, or enforcement of, our patents and other intellectual property rights in foreign countries; (8) our inability to identify international distributors and negotiate acceptable terms for distribution
+agreements; and (9) restrictions on our ability to repatriate investments and earnings from foreign operations. 
+Economic, cultural and political conditions and foreign regulatory requirements may slow or prevent the manufacture of our products in countries other than the United States. Interruption of the supply of our products could reduce revenues
+or cause us to incur significant additional expenses in finding an alternative source of supply. Foreign currency fluctuations and economic conditions in foreign countries could also increase the costs of manufacturing our products in foreign
+countries. 
+Risks Related to Ownership of Common Stock 
+Our common stock may have limited liquidity, and investors may not be able to sell as much common stock as they want at prevailing market prices or at all. 
+The liquidity of our common stock depends on several factors, including our financial results and overall market conditions, so it is not possible to predict whether this level of liquidity will continue, be sustained, or decrease. Decreased
+trading volume in our stock would make it more difficult for investors to sell their shares in the public market at any given time at prevailing prices. Our management and larger stockholders exercise significant control over our company. 
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+Table of Contents 
+Decreased trading volume in our stock would make it more difficult for investors to sell their shares in the public market at any given time at prevailing prices. Although there is no affiliation between our management and our larger
+stockholders, they could exercise significant control over our company if they voted their shares in a similar manner. 
+The price of our common stock could continue to be volatile, and existing stockholders’ investments in our common stock could lose value. 
+The price of our common stock has been volatile, subject to rapid and substantial decreases in stock price, and may be volatile in the future. By way of example, during the year ended December 31, 2021, our common stock has traded at a low
+of $1.09 and a high of $7.97. As a result of this volatility, investors could experience losses on their investment in our common stock. 
+The stock market is subject to significant price and volume fluctuations, and the price of our common stock could fluctuate widely in response to several factors, including, but not limited to: our cash flows and cash position; the duration
+and severity of the COVID-19 pandemic; our quarterly or annual operating results; investment recommendations by securities analysts following our business or our industry; additions or departures of key personnel; changes in our business,
+earnings estimates or market perceptions of our competitors; our failure to achieve operating results consistent with securities analysts’ projections; changes in industry, general market or economic conditions; and announcements of legislative
+or regulatory change. 
+Overall, the stock market has experienced price and volume fluctuations that have affected the market price of our common stock, as well as the stock of many other similar companies. Such price fluctuations are generally unrelated to the
+operating performance of the specific companies whose stock is affected. 
+Since the stock price of our common stock has fluctuated in the past, has been recently volatile and may be volatile in the future, investors in our common stock could incur substantial losses. In the past, following periods of volatility in
+the market, securities class-action litigation has often been instituted against companies. Such litigation, if instituted against us, could result in substantial costs and diversion of management’s attention and resources, which could
+materially and adversely affect our business, financial condition, results of operations and growth prospects. We are currently subject to securities class-action litigation as described in “—Legal Matters—Legal Proceedings” above. There can be
+no guarantee that our stock price will remain at current levels. 
+Securities of certain companies have recently experienced significant and extreme volatility in stock price due to short sellers of shares of common stock, known as a “short squeeze.” Short squeezes have caused extreme volatility in those
+companies and in the market and have led to the price per share of those companies to trade at a significantly inflated rate that is disconnected from the underlying value of the company. Sharp rises in a company’s stock price may force traders
+in a short position to buy the stock to avoid even greater losses. Many investors who have purchased shares in those companies at an inflated rate face the risk of losing a significant portion of their original investment as the price per share
+has declined steadily as interest in those stocks have abated. There can be no assurance that we will not, in the future be, a target of a short squeeze, and stockholders may lose a significant portion or all of their investments if they
+purchase our shares at a rate that is significantly disconnected from our underlying value. 
+Our stock price may in the future not meet the minimum bid price for continued listing on the Nasdaq Capital Market. Our ability to publicly or privately sell equity securities and the liquidity
+of our common stock could be adversely affected if we are delisted from The Nasdaq Capital Market. 
+Nasdaq Listing Rule 5450(a)(1), which we refer to as the Minimum Bid Price Rule, provides that the closing bid price for our common stock may not be below $1.00 per share for any period of 30 consecutive trading days to maintain our
+continued listing on The Nasdaq Capital Market. As of March 1, 2022, the closing bid price for our common stock was $0.97. Although we are currently in compliance with the Minimum Bid Price Rule, there can be no assurance that our common stock
+will continue to satisfy this rule. If we were to fail to comply with the Minimum Bid Price Rule in the future and became subject to delisting, such delisting from Nasdaq would adversely affect our ability to raise additional financing through
+the public or private sale of equity securities, would significantly affect the ability of investors to trade our securities and would negatively affect the value and liquidity of our common stock. Delisting also could have other negative
+results, including the potential loss of confidence by employees, the loss of institutional investor interest and fewer business development opportunities. 
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+Table of Contents 
+Our common stock may become the target of a “short squeeze.” 
+Securities of certain companies have increasingly experienced significant and extreme volatility in stock price due to short sellers of shares of common stock, known as a “short squeeze.” Short squeezes have caused extreme volatility in
+those companies and in the market and have led to the price per share of those companies to trade at a significantly inflated rate that is disconnected from the underlying value of the company. Sharp rises in a company’s stock price may force
+traders in a short position to buy the stock to avoid even greater losses. Many investors who have purchased shares in those companies at an inflated rate face the risk of losing a significant portion of their original investment as the price
+per share has declined steadily as interest in those stocks have abated. There can be no assurance that we will not, in the future be, a target of a short squeeze, and you may lose a significant portion or all of your investment if you purchase
+our shares at a rate that is significantly disconnected from our underlying value. 
+You may experience future dilution as a result of future equity offerings, exercises of outstanding options and vesting of options and restricted and performance stock units. 
+On July 19, 2021, we entered into the ATM Agreement, pursuant to which we may sell from time to time, at our option, up to an aggregate of $60,000,000 of shares of common stock through Craig-Hallum, as sales agent. As of the filing date of
+this report, we have issued and sold pursuant to the ATM Agreement a total of 9,709,328 shares of common stock at a volume-weighted average price of $4.2011 per share for gross proceeds of $40.8 million and net proceeds, after giving effect to
+placement fees and other transaction costs, of $38.8 million. For additional information about the at-the-market offerings pursuant to the ATM Agreement, see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and
+Results of Operations”. 
+In order to raise additional capital, we may seek to offer pursuant to the ATM Agreement additional shares of common stock for up to $19.2 million in gross proceeds and we may in the future offer additional shares of our common stock or
+other securities convertible into or exchangeable for our common stock. There can be no assurance that we will be able to sell additional shares in at-the-market offerings made pursuant to the ATM Agreement, or in any other offering, at a price
+per share that is equal to or greater than the price per share paid by existing stockholders. Investors purchasing securities in other offerings in the future could have rights superior to existing stockholders. 
+As of the close of business on March 1, 2022, our market capitalization was approximately $29.2 million. Existing stockholders may
+experience significant dilution in connection with our issuance and sale of up to $21.2 million of additional shares of common stock pursuant to the ATM Agreement. In addition, as of December 31, 2021, 3,386,393 shares of common stock were
+reserved for future issuance under our 2019 Omnibus Incentive Plan, 1,600,372 shares were subject to outstanding options, and 705,325 shares were subject to outstanding restricted and performance stock units. Stockholders will incur dilution
+upon vesting of restricted and performance stock units, and they may incur dilution upon exercises of stock options. 
+Management will have broad discretion as to the use of any net proceeds of the offering made pursuant to the ATM Agreement, and we may not use those net proceeds effectively. 
+Our management will have broad discretion in the application of the net proceeds of this offering made pursuant to the ATM Agreement and could spend the proceeds in ways that do not improve our results of operations or enhance the value of
+our common stock. Our failure to apply these funds effectively could have a material adverse effect on our business and could cause the price of our common stock to decline. 
+Any future issuances of shares of our common stock by us could harm the price of our common stock and our ability to raise funds in new equity offerings. 
+Any future sales of a substantial number of our shares of common stock or other equity‑related securities, or the perception that such sales may occur, could adversely affect the price of our common stock, and could impair our ability to
+raise capital through future offerings of equity or equity‑related securities. 
+50 
+Table of Contents 
+Sales of our common stock by existing stockholders, executive officers or directors could depress the market price of our common stock. 
+If our existing stockholders, officers or directors sell our common stock in the public market, or the perception that such sales may occur, it could negatively affect the price of our common stock. We are unable to estimate the number of
+shares of our common stock that may actually be resold in the public market since this will depend on the market price for our common stock, the individual circumstances of the sellers and other factors. 
+Institutional stockholders own significant amounts of our common stock. If one or more of these stockholders sell large portions of their holdings in a relatively short time, the prevailing price of our common stock could be negatively
+affected. In addition, it is possible that one or more of our executive officers or non‑employee members of our Board of Directors could sell shares of our common stock during an open trading window. These transactions and the perceived reasons
+for these transactions could have a negative effect on the prevailing market price of our common stock. 
+We do not intend to pay cash dividends on our common stock. 
+We do not expect to pay any cash dividends on our common stock and currently intend to retain our earnings, if any, to finance the expansion of our business. Therefore, the success of an investment in our common stock will depend entirely
+upon any future increase in value of our common stock. There is no guarantee that our common stock will gain value or even maintain the price at which investors purchased their shares. 
+General Risk Factors 
+We may not generate the expected benefits of future strategic transactions or investments, and they could disrupt our ongoing business, distract our management, increase our expenses and
+negatively affect our business. 
+As a way for us to grow our business, we may pursue strategic transactions or investments. These activities, and their impact on our business, are subject to many risks, including the following: (1) the benefits expected to be derived from a
+transaction or investment may not materialize and could be affected by numerous factors, such as regulatory developments, insurance reimbursement, our inexperience with new businesses or markets, general economic conditions and increased
+competition; (2) we may be unable to successfully integrate with a partner company’s personnel, assets, management, information technology systems, accounting policies and practices, products and/or technology into our business; (3) we may not
+be able to accurately forecast the performance or ultimate impact of a partner business; and (4) a strategic transaction may result in the incurrence of unexpected expenses, stockholder lawsuits, the dilution of our earnings or our existing
+stockholders’ percentage ownership, or potential losses from undiscovered liabilities not covered by an indemnification from the seller(s) of the partner business. 
+If these factors occur, we may be unable to achieve all or a significant part of the benefits expected from a strategic transaction or investment. This may adversely affect our financial condition, results of operations and ability to grow
+our business or otherwise achieve our financial and strategic objectives. 
+Our compliance with regulations governing public companies is complex and expensive. 
+Public companies are subject to various laws and regulations, which have increased the scope, complexity and cost of corporate governance, reporting and disclosure practices. For example, we are subject to the Sarbanes‑Oxley Act of 2002, The
+Dodd‑Frank Wall Street Reform and Consumer Protection Act and the requirements of the Nasdaq Capital Market. The implementation of certain aspects of these laws and regulations has required and will continue to require substantial management
+time and oversight and may require us to incur significant additional accounting and legal costs. We continually review changes with respect to new and proposed rules and cannot predict or estimate the amount of additional costs, and the timing
+of such costs, we may incur. There are several interpretations of these laws and regulations, in many cases due to their lack of specificity, and as a result, their application in practice may change as new guidance is provided by regulatory
+and governing bodies. This may result in continuing uncertainty regarding compliance matters and higher costs. We are committed to maintaining high standards of corporate governance and public disclosure, but if we fail to comply with any of
+these requirements, legal proceedings may be initiated against us, which may adversely affect our business. 
+Our business may be negatively affected by terrorist attacks or natural disasters. 
+Terrorist attacks or natural disasters could cause economic instability. These events could negatively affect economic conditions both within and outside the United States and harm demand for our products. The operations of our customers and
+suppliers could be negatively impacted and eliminate, reduce or delay our customers’ ability to purchase and use our products and our suppliers’ ability to provide raw materials and finished products. 
+Our facilities, including some pieces of manufacturing equipment and our computer systems, may be difficult to replace. Various types of disasters, including fires, earthquakes, floods and acts of terrorism, may affect our facilities and
+computer systems. In the event our existing facilities or computer systems are affected by man‑made or natural disasters, we may have difficulty operating our business and may be unable to manufacture products for sale or meet customer demands
+or sales projections. If our manufacturing operations were curtailed or shut down entirely, it would seriously harm our business 
+51 
+Table of Contents 
+ITEM 2. 
+PROPERTIES 
+Our U.S. manufacturing, administrative offices, and research facilities are located in leased space in Medford, New York, pursuant to a lease covering approximately 39,650 square feet and expiring on June 30, 2022, with an option to renew
+each year. 
+On February 5, 2019, we entered into a commercial real estate lease for new corporate headquarters comprised of 70,000 square feet of office, research and development, and warehouse space located in Hauppauge, New York. The lease has an
+initial term of eleven years that can be extended, at our option, for two additional terms of five years each. Rent under the lease, which is payable in monthly installments, totals approximately $900,000 for the initial year and then increases
+by approximately three percent each succeeding year. 
+Our European headquarters and Center of Excellence for Optical Technology is located in leased office and manufacturing space in Berlin, Germany. Our Southeast Asia manufacturing, warehouse, and commercial facilities are located in leased
+space in Kuala Lumpur, Malaysia and is currently inactive. Our Latin America manufacturing, warehouse, and commercial facilities are located in Rio de Janeiro, Brazil. We regularly review our real estate portfolio and develop footprint
+strategies to support our customers’ global plans, while at the same time supporting our technical needs and controlling operating expenses. 
+ITEM 3. 
+LEGAL PROCEEDINGS 
+This information is set forth under “Note 12 – Commitments, Contingencies And Concentrations – Litigation” to the Consolidated Financial Statements of this Annual Report on Form 10-K is incorporated herein by reference. 
+52 
+Table of Contents 
+PART II 
+ITEM 5. 
+MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+Listing Information 
+Our stock is listed on the NASDAQ Global Select Market of the NASDAQ Stock Market LLC under the symbol “CEMI.” 
+Holders 
+As of February 23, 2022, there were 71 record owners of our Common Stock (including nominee holders such as banks and brokerage firms who hold shares for beneficial owners). 
+Recent Sales of Unregistered Securities 
+During the year ended December 31, 2021, we issued unregistered securities in connection with the 2020 Amended and Restated Agency & Commission Agreement from November 2020. 
+Issuer Purchases of Equity Securities 
+We did not repurchase any of our equity securities during the year ended December 31, 2021. 
+53 
+Table of Contents 
+ITEM 7. 
+MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+We develop and commercialize point-of-care diagnostic tests used for the rapid detection and diagnosis of infectious diseases, including sexually transmitted disease, insect vector and tropical
+disease, COVID-19 and other viral and bacterial infections, enabling expedited treatment. 
+Our product portfolio is based upon our proprietary DPP technology, a diagnostic platform that provides high-quality, cost-effective results in 15 to 20 minutes using fingertip blood, nasal
+swabs and other sample types. The DPP technology platform addresses the rapid diagnostic test market, which includes infectious diseases, cardiac markers, cholesterol and lipids, pregnancy and fertility, and drugs of abuse. Compared with
+traditional lateral flow technology, the DPP technology platform can provide enhanced sensitivity and specificity, advanced multiplexing capabilities and, with the DPP Micro Reader, quantitative results. 
+We target the market for rapid diagnostic test solutions for infectious diseases, which is driven by the high prevalence of infectious diseases globally, an increase in the geriatric population, growing demand for rapid test results, and
+advancements in multiplexing. We have a broad portfolio of infectious disease products, which prior to 2020 were focused principally on sexually transmitted disease and fever and tropical disease. In February 2020 we began the process of
+shifting substantially all of our resources to seek to leverage the DPP technology platform to address the acute and escalating need for diagnostic testing for COVID-19. We are continuing to pursue: 
+• 
+an emergency use authorization, or EUA, from the U.S. Food and Drug Administration, or FDA, as well as 510(k) clearance from the FDA, for the DPP SARS-CoV-2 Antigen
+test system; 
+• 
+an EUA from the FDA for the DPP Respiratory Panel; and 
+• 
+a Clinical Laboratory Improvement Amendment, or CLIA, waiver from the FDA for the DPP HIV-Syphilis test system. 
+Our products are sold globally, directly and through distributors, to medical laboratories and hospitals, governmental and public health entities, nongovernmental organizations, medical
+professionals, and retail establishments. We continue to seek to expand our commercial distribution channels. 
+Global Competitiveness Program 
+We have achieved significant revenue growth in recent years while profitability has not been at levels as expected. We have taken steps including investments in automation to mitigate headwinds including labor availability, volatile capacity
+planning and implementation of operational efficiency targets to proactively monitor production with the overarching goal for profitable growth. To further accelerate and aggressively execute towards this goal to improve profitability, in the
+first quarter of 2022 we have initiated a Global Competitiveness Program. Our Global Competitiveness Program has been developed with the support of the Company’s executive leadership team to ensure cross-functional alignment, commitment and
+accountability throughout the organization. The main pillars of the Global Competitiveness Program include the following: 
+• 
+Focus on higher margin business in growth markets : Our pursuit of growth in markets with higher selling prices remains unchanged. We have recently completed
+an in-depth analysis of our product portfolio and profitability on both a product and regional basis. With this increased transparency at a product-level, we now have visibility to support customer pricing, marketing strategies
+and evaluate opportunities to increase prices. Furthermore, focus will be on recurring revenue streams of our core business by leveraging more recently established distributor and direct customer channels in the US and other key
+markets. 
+54 
+Table of Contents 
+• 
+Lower manufacturing costs: Automation and labor management is essential to scale unit volumes while also seeking additional ways to drive our manufacturing
+costs down. With improved visibility on our labor and material costs at a product-level, we will primarily target optimization of our lower margin business. 
+• 
+Reduce infrastructure costs: This includes an in-depth evaluation of all support functions and external spend to reduce costs. Research & Development
+will be further aligned with our future innovation centered on core strategy, including DPP and expansion of product pipeline with a more disciplined approach to cost-benefit analysis, target markets, and competitor landscape. 
+• 
+Strategic review of non-core businesses and assets: Our prior acquisitions have not achieved the business plans as originally planned. More specifically,
+emphasis will be on both our German and Brazilian subsidiaries with a reorientation for those businesses to achieve an independent path to profitability and alignment with the long-term strategic roadmap. 
+While these pillars establish a framework to improve our profitability, successful execution is dependent on many factors including future regulatory approvals, key relationships with long term customers and expansion in large markets
+including the US. We plan to aggressively implement these actions that underpin fundamentals for long-term profitable growth and sustainable shareholder value. 
+Substantial Doubt as to Going Concern Status 
+Factors and considerations with respect to our liquidity raised substantial doubt as to our ability to continue as a going concern
+through one year after the date that our financial statements are being issued. 
+Revenues during the twelve months ended December 31, 2021 did not meet our expectations. Our increase in cash and cash equivalents over the year reflected our issuance of common stock in at-the-market offerings for net proceeds of $38.8
+million (see “Note 9 - Stockholder’s Equity” to the Consolidated Financial Statements of this Annual Report on Form 10-K is incorporated herein by reference). 
+We continued to experience market, clinical trial and regulatory complications in seeking to develop and commercialize a portfolio of COVID-19 test systems during the continuing, but evolving, uncertainty of the COVID‑19 pandemic. In the
+year ending on December 31, 2021, we continued to incur significant expenses in connection with pending legal matters (see “Note 12 – Commitments, Contingencies, and Concentrations: Litigation” to the Consolidated Financial Statements of this
+Annual Report on Form 10-K is incorporated herein by reference), delayed achievement of milestones associated with government grant income, investments in inventory, and the continuing automation of manufacturing. 
+During the twelve months ended December 31, 2021, we undertook measures to increase our total revenues and improve our liquidity position. These measures included: 
+• 
+On July 19, 2021, we entered into an At the Market Offering Agreement, or the ATM Agreement, with Craig‑Hallum Capital Group LLC, or Craig‑Hallum, pursuant to which we may sell from time to time, at our
+option, up to an aggregate of $60,000,000 of shares of common stock through Craig‑Hallum, as sales agent. As of the filing date of this report, we have issued and sold pursuant to the ATM Agreement a total of 9,709,328 shares of
+common stock at a volume-weighted average price of $4.20 per share for gross proceeds of $40.8 million and net proceeds, after giving effect to placement fees and other transaction costs, of $38.8 million. 
+• 
+We also received significant purchase orders from two customers, which we refer to as the July Purchase Orders. We had pursued the July Purchase Orders for an extended period of time. The July Purchase
+Orders consist of the following: 
+55 
+Table of Contents 
+o 
+On July 20, 2021, we received a $28.3 million purchase order from Bio-Manguinhos for the purchase of DPP SARS-CoV-2 Antigen tests for delivery during 2021 to support the needs of Brazil’s Ministry of
+Health in addressing the COVID-19 pandemic. Bio-Manguinhos is responsible for the development and production of vaccines, diagnostics, and biopharmaceuticals, primarily to meet demands of Brazil’s national public health system. As of
+December 31, 2021 $16.8 million was recognized in connection with this order. 
+o 
+On July 22, 2021, we received a $4.0 million purchase order from the Partnership for Supply Chain Management, supported by The Global Fund, for the purchase of HIV 1/2 STAT-PAK Assays for shipment to
+Ethiopia into early 2022. As of December 31, 2021 $1.2 million was recognized in connection with this order. 
+These measures and other plans and initiatives have been designed to provide us with adequate liquidity to meet our obligations for at least the twelve-month period following the filing date of this report, when the Accompanying Financial
+Statements are being issued. Our execution of those measures and our other plans and initiatives continue to depend, however, on factors that are beyond our control, or that may not be addressable on terms acceptable to us or at all. We have
+considered in particular how: 
+• 
+The ongoing healthcare and economic impacts of the COVID-19 pandemic on the global customer base for our non‑COVID-19 products continue to negatively affect the timing and rate of recovery of our revenues
+from those products by, for example, decreasing the allocation of funding for HIV testing, thereby continuing to adversely affect our liquidity. 
+• 
+Although we have entered into agreements to distribute third-party COVID-19 products in the United States, our ability to sell those products could be constrained because of staffing and supply chain
+limitations affecting the suppliers of those products. 
+We further considered how these factors and uncertainties could impact our ability over the next year to meet the obligations
+specified in the Credit Agreement and Guaranty, or the Credit Agreement, that we and certain of our subsidiaries, as guarantors, entered into with Perceptive Credit Holdings II, LP, or the Lender. Those obligations include (a) covenants
+requiring: i) minimum cash balance of $3 million and ii) minimum total revenue amounts for the twelve months preceding each quarter end. For the next year, the minimum total revenue requirements range from $42.0 million for the twelve months
+ending March 31, 2022 to $47.4 million for the twelve months ending December 31, 2022 and (b) an obligation requiring the payment of principal installments, commencing with the payment of $300,000 on September 30, 2022. Upon an event of
+default under the Credit Agreement, the Lender could elect to declare all amounts outstanding thereunder, together with accrued interest, to be immediately due and payable. In such an event, there can be no assurance that we would have
+sufficient liquidity to fund payment of the amounts that would be due under the Credit Agreement or that, if such liquidity were not available, we would be successful in raising additional capital on acceptable terms, or at all, or in
+completing any other endeavor to continue to be financially viable and continue as a going concern. Our inability to raise additional capital on acceptable terms in the near future, whether for purposes of funding payments required under the
+Credit Agreement or providing additional liquidity needed for our operations, could have a material adverse effect on our business, prospects, results of operations, liquidity and financial condition. 
+56 
+Table of Contents 
+Accordingly, management determined we could not be certain that our plans and initiatives would be effectively implemented within one year after the filing date of this report, when the Accompanying Financial Statements are being issued.
+Without giving effect to the prospect of raising additional capital pursuant to our at-the-market offerings, increasing product revenue in the near future or executing other mitigating plans, many of which are beyond our control, it is unlikely
+that we will be able to generate sufficient cash flows to meet our required financial obligations, including our debt service and other obligations due to third parties. The existence of these conditions raises substantial doubt about our
+ability to continue as a going concern for the twelve-month period following the filing date of this report. 
+The Accompanying Financial Statements have been prepared assuming we will continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business
+for the twelve-month period following the date the accompanying consolidated financial statements are issued. As such, the Accompanying Financial Statements do not include any adjustments relating to the recoverability and classification of
+assets and their carrying amounts, or the amount and classification of liabilities that may result should we be unable to continue as a going concern. 
+Consolidated Results of Operations 
+The results of operations for the years ended December 31, 2021 and 2020 were as follows: 
+Year Ended December 31, 
+(in thousands) 
+2021 
+2020 
+TOTAL REVENUES 
+$ 
+47,818 
+100 
+% 
+$ 
+32,470 
+100 
+% 
+COSTS AND EXPENSES: 
+Cost of product sales 
+34,496 
+72 
+% 
+23,874 
+74 
+% 
+Research and development expenses 
+12,487 
+26 
+% 
+9,509 
+29 
+% 
+Selling, general and administrative expenses 
+24,841 
+52 
+% 
+21,038 
+65 
+% 
+Impairment, restructuring, severance and related costs 
+7,048 
+15 
+% 
+1,122 
+3 
+% 
+Acquisition costs 
+- 
+0 
+% 
+63 
+0 
+% 
+78,872 
+55,606 
+LOSS FROM OPERATIONS 
+(31,054 
+) 
+(23,136 
+) 
+OTHER (EXPENSE) / INCOME 
+(2,912 
+) 
+(2,842 
+) 
+LOSS BEFORE INCOME TAX BENEFIT 
+(33,966 
+) 
+(25,978 
+) 
+Income tax benefit 
+62 
+457 
+NET LOSS 
+$ 
+(33,904 
+) 
+(71 
+%) 
+$ 
+(25,521 
+) 
+(79 
+%) 
+Percentages in the table reflect the percent of total revenues. 
+Total Revenues 
+Total revenues during 2021 were $47.8 million, an increase of $15.3 million, or 47.3%, compared to 2020. The increase in total revenues reflected a $10 million, or 40.3%, increase in net product sales, which was principally comprised of
+(a) higher sales in Latin America, US and Africa, offset by lower sales in Europe and Asia; (b) decrease in R&D revenue of $3.7 million due to the completion of agreements in the early part of 2021; and (c) increase in grant income related
+to the BARDA $12.7 million agreement in the amount of $8.9 million. 
+57 
+Table of Contents 
+Gross Product Margin 
+Cost of product sales is primarily comprised of material, labor, manufacturing overhead, depreciation and amortization, and freight and distribution costs. Gross product margin is net product sales less cost of product sales, and gross
+product margin percentage is gross product margin as a percentage of net product sales. 
+Gross product margin decreased by $0.7 million, or 73% compared to 2020. The following schedule calculates gross product margin: 
+For the years ended December 31 
+Favorable/ 
+2021 
+2020 
+(unfavorable) 
+% Change 
+(in thousands) 
+Net product sales 
+$ 
+34,737 
+$ 
+24,767 
+$ 
+9,970 
+40.3 
+% 
+Less: Cost of product sales 
+(34,496 
+) 
+(23,874 
+) 
+(10,622 
+) 
+44.5 
+% 
+Gross product margin 
+$ 
+241 
+$ 
+893 
+$ 
+(652 
+) 
+(73.0 
+)% 
+Gross product margin % 
+0.7 
+% 
+3.6 
+% 
+In 2021, we invested in developing and offering products to address the COVID-19 pandemic, which we expected to have average
+selling prices greater than those of our legacy products. We also continued to invest in automation in order to reduce our reliance on manual labor and improve our product margins. The $0.7 million decrease in gross product margin was
+comprised of (a) $1.0 million from unfavorable product margins offset by (b) $0.3 million favorable product sales volume as described under “—Total Revenues” above. The $1.0 million decrease from unfavorable product margins principally
+reflected the increased labor and overhead costs and unfavorable mix of average selling prices. 
+58 
+Table of Contents 
+Research and Development 
+This category includes costs incurred for clinical and regulatory affairs and other research and development, as follows: 
+For the years ended December 31 
+Favorable/ 
+2021 
+2020 
+(unfavorable) 
+% Change 
+(in thousands) 
+Clinical and regulatory affairs 
+$ 
+5,109 
+$ 
+1,061 
+$ 
+(4,048 
+) 
+(381.5 
+)% 
+Other research and development 
+7,378 
+8,448 
+1,070 
+12.7 
+% 
+Total research and development 
+$ 
+12,487 
+$ 
+9,509 
+$ 
+(2,978 
+) 
+(31.3 
+)% 
+The increase in clinical and regulatory affairs costs for 2021 as compared to 2020 was primarily associated with increased clinical trial costs related to the BARDA $12.7 million agreement which was completed on December 2, 2021. The
+decrease in other research and development costs was primarily related to the completion of R&D agreements in the early part of 2021. 
+Selling, General and Administrative Expense 
+Selling, general and administrative expenses include administrative expenses, sales and marketing costs (including commissions), and other corporate items. The $3.8 million, or 18.1%, increase in selling, general and administrative expenses
+for 2021 as compared to 2020 primarily reflected increased legal costs associated with the ongoing litigations, recruiting fees due to the ramp up in production that took place in the later part of 2021 and higher insurance costs. 
+Impairment, restructuring. severance and related costs 
+The Company recorded an impairment loss of $1.3 million during the second quarter of 2021, as the result of its write-off of the intangible assets, net, leasehold improvements, net and right-of-use assets for leases, net associated with its
+Malaysian operations that underwent a retrenchment during the second quarter of 2020. 
+In addition, the Company recorded an impairment loss of $4.6 million during the fourth quarter of 2021, as the result of a write down of finite-lived intangible assets ($2.0 million) and goodwill ($2.6 million) due to the substantial
+decrease in share price as of December 31, 2021. The low price per share value on December 31, 2021 caused the book value of the Company to exceed its market cap. 
+In light of the uncertainty of the timing and any receipt of those regulatory approvals, the timing of progress on and results of clinical trial programs, and the timing and any receipt of product orders from the commercialization of the
+COVID-19 Diagnostic Test Systems and other diagnostic test systems both within and outside the United States, during the second quarter of 2021, the Company engaged the services of an independent financial advisory firm (the “Financial
+Advisor”). The Financial Advisor worked with management to develop a forecast model to assess the amount and timing of the Company’s liquidity needs, assuming various business cases, and together with legal counsel advised the Company regarding
+alternative approaches to enhancing its liquidity position, participating in discussions with the Lender, and related matters. During the year ended December 31, 2021 and 2020, the Company incurred $1.1 and $0.4 million, respectively, related
+to these restructuring matters. 
+In order to address challenging economic conditions and implement its business strategy, in the first quarter of 2021 the Company continued to execute a program to reduce operating expenses and better align its costs with revenues, including
+by eliminating positions that were no longer aligned with its strategy, and recognized severance charges of $0.1 million. 
+59 
+Table of Contents 
+Acquisition Costs 
+Acquisition costs include legal, due diligence, audit, and related costs associated with acquisitions. The $0.1 million decrease in acquisition costs for 2021 as compared to 2020 reflected the fact that we completed acquisitions in 2020. 
+Other (Expense) / Income 
+Other (expense) / income was principally comprised of interest expense net of interest income. Interest expense increased by $0.1 million for 2021 as compared to 2020, due to the interest paid on the term loan debt we incurred in September
+2019. 
+Income Tax Benefit 
+For 2021 we recognized a tax benefit of $0.1 primarily attributable to the loss generated by Chembio Diagnostics Germany. As of December 31, 2021 and 2020, the Company recorded a full valuation allowance against its net deferred tax assets. 
+Liquidity and Capital Resources 
+Our cash and cash equivalents totaled $28.8 million at December 31, 2021, an increase of $5.7 million from $23.1 million at December 31, 2020. We are obligated to maintain aggregate unrestricted
+cash of not less than $3,000,000 at all times under a covenant in the Credit Agreement. 
+During the year ended December 31, 2021, we funded our business operations, including capital expenditures and working capital requirements, principally from cash and cash equivalents and issuance of common stock in at-the-market offerings.
+Our operations used $30.9 million of cash during the twelve months ended December 31, 2021. In the first half of 2021, revenues did not meet our expectations, and the shortfall in revenues from the first two quarters was one of the principal
+reasons we issued common stock in the at-the-market offerings during the year ended December 31, 2021, which provided us with net proceeds of $38.8 million. This increase in cash and cash equivalents was offset in part as the result of
+(a) market, clinical trial and regulatory complications we faced in seeking to develop and commercialize a portfolio of COVID‑19 test systems during the continuing, but evolving, uncertainty of the COVID‑19 pandemic and (b) significant
+continuing expenses incurred in connection with pending legal matters (see “Note 12(e) – Commitments, Contingencies, and Concentrations – Litigation” in the Accompanying Financial Statements), delayed achievement of milestones associated with
+government grant income, investments in inventory, and, the continuing automation of U.S. manufacturing. 
+In light of the uncertainty of the timing and any receipt of regulatory approvals, the timing of progress on and results of clinical trial programs, and the timing and any receipt of product orders from the commercialization of our COVID‑19
+and other diagnostic test systems both within and outside the United States, during the year we engaged the services of an independent financial advisory firm. The financial advisory firm worked with management to develop a forecast model to
+assess the amount and timing of our liquidity needs, assuming various business cases and, together with legal counsel, advised us regarding alternative approaches to enhancing our liquidity position, participating in discussions with the Lender
+under our credit facility and related matters. We incurred fees related to these restructuring matters totaling $1.1 million in during the year. 
+Factors and considerations with respect to our liquidity raised substantial doubt as to our ability to continue as a going concern
+through one year after the date that the Accompanying Financial Statements are being issued. See “—Substantial Doubt as to Going Concern Status” above. 
+60 
+Table of Contents 
+We have undertaken plans and initiatives, including fulfillment of the July Purchase Orders (see “— Substantial Doubt as to Going Concern Status” above) and fundraising through “at-the-market” offerings (see “—Substantial Doubt as to Going
+Concern Status” above), designed to provide us with adequate liquidity to meet our obligations for at least the twelve-month period following the filing date of this report, when the Accompanying Financial Statements are being issued. Our
+execution of those plans and initiatives is dependent, however, on a number of operational performance factors, such as the effectiveness of our automated manufacturing operations, as well as numerous other factors that are beyond our control
+or that may not be addressable on terms acceptable to us, or at all. We have considered how the uncertainties around the delivery of the full number of tests covered by customer orders may be affected by limitations of our staffing, supply
+chain and liquidity, uncertainties regarding the achievement of milestones and related recognition of revenue under government grants from BARDA, and other matters outside our control. We further considered how those uncertainties could impact
+our ability to meet the obligations specified in the Credit Agreement over the next twelve months, which include (a) a covenant requiring minimum total revenues for the twelve months preceding each quarter end, which requirements range from
+$40.3 million for the twelve months ending December 31, 2021 to $47.4 million for the twelve months ending December 31, 2022 and (b) an obligation requiring the payment of principal installments, commencing with the payment of $300,000 on
+September 30, 2022. Upon an event of default under the Credit Agreement, the Lender could elect to declare all amounts outstanding thereunder, together with accrued interest, to be immediately due and payable. In such an event, there can be no
+assurance that we would have sufficient liquidity to fund payment of the amounts that would be due under the Credit Agreement or that, if such liquidity were not available, we would be successful in raising additional capital on acceptable
+terms, or at all, or in completing any other endeavor to continue to be financially viable and continue as a going concern. Our inability to raise additional capital on acceptable terms or to otherwise generate cash in the near future, whether
+for purposes of funding payments required under the Credit Agreement or providing additional liquidity needed for our operations, could have a material adverse effect on our business, prospects, results of operations, liquidity and financial
+condition. 
+We cannot be certain that our plans and initiatives would be effectively implemented within one year after the filing date of this report, when the Accompanying Financial Statements are being issued. Without giving effect to the prospect of
+raising additional capital pursuant to our at-the-market offerings, increasing product revenue in the near future or executing other mitigating plans, many of which are beyond our control, it is unlikely that we will be able to generate
+sufficient cash flows to meet our required financial obligations, including our debt service and other obligations due to third parties. The existence of these conditions raises substantial doubt about our ability to continue as a going concern
+for the twelve-month period following the date of this report. 
+Please see note 2 to the Accompanying Financial Statements for additional information regarding our going concern assessment in connection with the Accompanying Financial Statements. You are urged to read carefully the information provided
+in “Because of our liquidity limitations, we have concluded there is a substantial doubt about our ability to continue as a going concern and we may require additional capital to fund our operations, which capital may not be available to us on
+acceptable terms or at all,” “Because of our liquidity and operational limitations, including the availability of staffing and supply chain resources that are necessary but outside of our control, we may not be able to timely fulfill some of
+the requirements of the July Purchase Orders without additional capital to fund our operations, which capital may not be available to us on acceptable terms, or at all,” and “The failure to comply with the terms of the Credit Agreement could
+result in a default under its terms and, if uncured, could result in action against our pledged assets and dilution of our stockholders” under “Item 1A. Risk Factors” of Part I of this report. 
+We currently intend to retain all available funds and any future earnings for use in the operation of our business and do not anticipate paying any cash dividends. We have not entered into, and do not expect to enter into, investments for
+trading or speculative purposes. Our accounts receivable, accounts payable and inventory balances fluctuate from period to period, which affects our cash flow from operating activities. The amounts of these fluctuations vary depending on cash
+collections, client mix, raw material lead times, the mix of vendor terms, the timing of shipment of our products and the invoicing of our research and development activities. As of December 31, 2021, we did not have any off-balance sheet
+arrangements, as defined in Item 303(a)(4)(ii) of Regulation S-K under the Securities Exchange Act of 1934. 
+61 
+Table of Contents 
+We continually evaluate our liquidity requirements, capital needs and availability of capital resources based on our operating needs and our planned growth initiatives. Our future working capital needs will depend on many factors, including
+the rate of our business and revenue growth, the availability and cost of human, material and other resources required to build and deliver products in accordance with our existing or future product orders, the timing of our continuing
+automation of U.S. manufacturing, and the timing of our investment in research and development as well as sales and marketing. If we are unable to increase our revenues and manage our expenses in accordance with our operating plan, we may need
+to reduce the level or slow the timing of the growth plans contemplated by our operating plan, which would likely curtail or delay the growth in our business contemplated by our operating plan and could impair or defer our ability to achieve
+profitability and generate cash flow, or to seek to raise additional funds through debt or equity financings, strategic relationships, or other arrangements. There can be no assurance that we would be able to complete any proposed financing on
+terms acceptable to us, or at all, or that we otherwise will be successful in any of our other endeavors to continue to be financially viable and continue as a going concern. Our inability to raise additional capital on acceptable terms could
+have a material adverse effect on our business, prospects, results of operations, liquidity and financial condition. If we were to raise additional funds through the issuance of equity or convertible securities, the issuance could result in
+substantial dilution to existing stockholders, and the holders of those new securities may have rights, preferences and privileges senior to those of the holders of common stock. Furthermore, any decline in the market price of our common stock
+could make it more difficult for us to sell equity or equity-related securities in the future at a time and price that we deem appropriate. 
+Sources of Funds 
+Equity and Equity-Related Securities . On July 19, 2021, we entered into the ATM Agreement with Craig‑Hallum, pursuant to which we may sell from time to time, at our option, up to an aggregate of
+$60,000,000 of shares of common stock through Craig‑Hallum, as sales agent. Any sales of shares made pursuant to the ATM Agreement will be made pursuant to our shelf registration statement on Form S‑3 (File No. 333‑254261) and the related
+prospectus previously declared effective by the SEC on May 5, 2021, as supplemented by a prospectus supplement dated July 19, 2021 that we filed with the SEC, pursuant to Rule 424(b)(5) under the Securities Act, on July 19, 2021, as such
+prospectus supplement may be amended or supplemented from time to time. 
+Prior to any sale of shares of common stock under the ATM Agreement, we may deliver a sales notice to Craig-Hallum that will set the parameters for such sale, including the number of shares to be issued and sold, the time period during which
+such sale is requested to be made, any limitation on the number of shares that may be sold in any one trading day and any minimum price below which sales may not be made. Under the ATM Agreement, Craig-Hallum is required to use commercially
+reasonable efforts consistent with its normal trading and sales practices to sell shares in accordance with the terms of the ATM Agreement and any applicable sales notice. 
+Subject to the terms and conditions of the ATM Agreement, Craig-Hallum may sell any shares of common stock only by methods deemed to be an “at the market” offering as defined in Rule 415 under the Securities Act, including sales made
+directly through the Nasdaq Capital Market, by means of ordinary brokers’ transactions, in negotiated transactions, to or through a market maker other than on an exchange or otherwise, at market prices prevailing at the time of sale, at prices
+related to such prevailing market prices, or at negotiated prices and/or any other method permitted by law. If any sale of shares pursuant to the ATM Agreement is not made directly on the Nasdaq Capital Market or any other existing trading
+market for common stock at market prices at the time of sale, including a sale to Craig-Hallum acting as principal or a sale in a privately negotiated transaction, we must file a prospectus supplement describing the terms of such sale, the
+number of shares sold, the price of the shares, the applicable compensation, and such other information as may be required pursuant to Rules 424 and 430B under the Securities Act, as applicable, within the time required by Rule 424 under the
+Securities Act. 
+Under the terms of the ATM Agreement, we are to pay Craig-Hallum a placement fee of 3.5% of the gross sales price of shares of common stock sold, unless Craig-Hallum acts as principal, in which case we may sell the shares to Craig-Hallum as
+principal at a price we agree upon with Craig-Hallum. We are obligated to reimburse Craig-Hallum for certain expenses incurred in connection with the ATM Agreement, and we have provided Craig-Hallum with customary indemnification and
+contribution rights with respect to certain liabilities, including liabilities under the Securities Act and the Securities Exchange Act of 1934. 
+The offering of shares of common stock pursuant to the ATM Agreement will terminate upon the earliest of (a) the sale of all of the shares registered for purposes of the offering pursuant to the ATM Agreement, (b) our mutual written
+agreement with Craig-Hallum, (c) written notice from Craig-Hallum, in its sole discretion, to us, and (d) five business days’ prior written notice from us, in our sole discretion, to Craig-Hallum. 
+As of the filing date of this report, we have issued and sold pursuant to the ATM Agreement a total of 9,709,328 shares of common stock at a volume-weighted average price of $4.20 per share for gross proceeds of $40.8 million and net
+proceeds, after giving effect to placement fees and other transaction costs, of $38.8 million. Additional shares of common stock may be issued and sold pursuant to the ATM Agreement for gross proceeds of up to $19.2 million, but we cannot
+provide any assurance that will be able to issue any additional shares under the ATM Agreement at an acceptable price or at all. 
+62 
+Table of Contents 
+Credit Agreement . The following description summarizes certain key provisions of the Credit Agreement: 
+• 
+Principal Amount . The Credit Agreement provides for a $20,000,000 senior secured term loan credit facility, which was drawn in full on September 4, 2019. Under
+the terms of the Credit Agreement, we may use the proceeds (a) for general working capital purposes and other permitted corporate purposes, (b) to refinance certain of our existing indebtedness and (c) to pay fees, costs and expenses
+incurred in connection with the Credit Agreement, including the Lender’s closing cost amount of $550,000, which was netted from the proceeds, and a financing fee of $600,000 (3.0% of gross proceeds) payable to Craig-Hallum, our
+financial advisor for the financing. 
+• 
+Interest Rate . Principal outstanding under the Credit Agreement bears interest at a rate per annum equal to the sum of (a) the greater of the one month London
+Interbank Offered Rate and 2.5% plus (b) 8.75%. At any time at which an event of default (as described under “—Default Provisions” below) has occurred and is continuing, the interest rate will increase by 4.0%. Accrued interest is
+payable on a monthly basis. On December 31, 2021 the interest rate was 11.25%. 
+• 
+Scheduled Repayment . No principal repayments are due prior to September 30, 2022, unless we elect to prepay principal as described under “— Optional Prepayment”
+below or principal is accelerated pursuant to an event of default as described under “—Default Provisions” below. Principal installments in the amount of $300,000 are payable on the last day of each of the eleven months from September
+2022 through July 2023, and all remaining principal is payable at maturity on September 3, 2023. 
+• 
+Optional Prepayment . We may prepay outstanding principal from time to time, subject to payment of a premium on the prepaid principal amount equal to 4% through
+September 3, 2022. No premium will be due with respect to any prepayment made on or after September 4, 2022. 
+• 
+Guarantees . Our subsidiaries Chembio Diagnostic Systems Inc. and Chembio Diagnostics Malaysia Sdn Bhd. have guaranteed, and the Lender from time to time may
+require our other subsidiaries to guarantee, our obligations under the Credit Agreement. 
+• 
+Security . Our obligations under the Credit Agreement are secured by a first priority, perfected lien on substantially all of our property and assets, including
+our equity interests in our subsidiaries. Our subsidiary Chembio Diagnostic Systems Inc. has secured its guarantee of our Credit Agreement obligations with a lien on substantially all of its assets, and the Lender from time to time
+may require Chembio Diagnostics Malaysia Sdn Bhd. and any of our other subsidiaries that has guaranteed our Credit Agreement obligations to do the same. 
+• 
+Representations and
+Warranties . Financial and Other Covenants. In the Credit Agreement we made customary representations and warranties as well as customary affirmative and negative covenants, including covenants limiting additional
+indebtedness, liens, guarantees, mergers and acquisitions, substantial asset sales, investments and loans, sale and leasebacks, transactions with affiliates, and fundamental changes. The Credit Agreement also contains financial
+covenants requiring that (a) we maintain aggregate unrestricted cash of not less than $3,000,000 at all times and (b) we achieve specified minimum total revenue requirements for the twelve months preceding each quarter end. The
+minimum total revenue amounts range from $32.0 million to $50.1 million and, for the next year, range from $42.0 million for the twelve months ending March 31, 2022 to $47.4 million for the twelve months ending December 31, 2022.
+The minimum total revenue requirements were developed for purposes of the Credit Agreement and do not reflect the internal estimates and plans used by our management and board of directors to understand and evaluate our operating
+performance, to establish budgets, and to establish operational goals for managing our business. We therefore do not believe that the covenant requirements provide useful information to investors or others in enhancing an
+understanding of our future prospects. 
+63 
+Table of Contents 
+• 
+Default Provisions . The Credit Agreement provides for customary events of default, including events of default based on non-payment of amounts due under the
+Credit Agreement, defaults on other debt, misrepresentations, covenant breaches, changes of control, insolvency, bankruptcy and the occurrence of a material adverse effect on our company. Upon an event of default resulting from a
+voluntary or involuntary proceeding for bankruptcy, insolvency or receivership, the amounts outstanding under the Credit Agreement will become immediately due and payable and the Lender’s commitments will be automatically terminated.
+Upon the occurrence and continuation of any other event of default, the Lender may accelerate payment of all obligations and terminate its commitments under the Credit Agreement. 
+Research and Development Awards. Under a contract we entered into with BARDA on December 2, 2020, a total of up to $12.7 million of awards were available from BARDA to assist us in (a) developing, and
+pursuing an EUA from the FDA for, the DPP Respiratory Antigen Panel and (b) performing the clinical trials for and submitting the DPP SARS-CoV-2 Antigen test system to the FDA for 510(k) clearance. Of the total awards available under this
+contract, we recognized government grant income totaling $10.9 million during the year ended December 31, 2021. The completion of milestones to earn the remaining awards are outside our control, and contingent to the EUA approval by the FDA. 
+Working Capital . The following table sets forth selected working capital information: 
+December 31, 
+2021 
+(in thousands) 
+Cash and cash equivalents 
+$ 
+28,773 
+Accounts receivable, net 
+11,441 
+Inventories, net 
+12,920 
+Prepaid expenses and other current assets 
+1,710 
+Total current assets 
+54,844 
+Less: Total current liabilities 
+(15,282 
+) 
+Working capital 
+$ 
+39,562 
+Our cash and cash equivalents at December 31, 2021, were held for working capital purposes. We currently intend to retain all available funds and any future earnings for use in the operation of our business and do not anticipate paying any
+cash dividends. We have not entered into, and do not expect to enter into, investments for trading or speculative purposes. Our accounts receivable and inventory balances fluctuate from period to period, which affects our cash flow from
+operating activities. Fluctuations vary depending on cash collections, client mix, raw material lead times, the mix of vendor terms, and the timing of shipment of our products and the invoicing of our research and development activities. 
+Uses of Funds 
+Cash Flow Used in Operating Activities . Our operations used $30.9 million of cash during the year ended December 31, 2021, primarily due to the net loss
+adjusted for non-cash items of $18.8 million. Those uses of cash were the result of $8.0 million increase in accounts receivable, a $4.5 million increase in inventory, $1.6 million decrease in deferred revenue and $0.9 million decrease in
+Prepaid and other current assets, offset in part by a $3.1 million increase in accounts payable and other accrued liabilities. 
+64 
+Table of Contents 
+Credit Agreement. Principal installments in the amount of $300,000 are payable under the Credit Agreement on the last day of each of the eleven months from September 2022 through July 2023, and all
+remaining principal is payable at maturity on September 3, 2023. Upon an event of default under the Credit Agreement, the Lender could elect to declare all amounts outstanding thereunder, together with accrued interest, to be immediately due
+and payable, as further described “—Sources of Funds—Credit Agreement—Default Provisions” above. In addition, we could determine to prepay from time to time outstanding principal under the Credit Agreement (see “—Sources of Funds—Credit
+Agreement—Optional Prepayment” above) or to make other payments under the Credit Agreement that may not be then due or otherwise required under the Credit Agreement, although, as of the date of the filing of this report, we do not intend to
+make any such prepayments or other payments. 
+Capital Expenditures. Our capital expenditures totaled $1.9 million in the year ended December 31, 2021, all of which related to investments in automated manufacturing equipment, facilities, and other
+fixed assets. As of December 31, 2021, we had capital purchase obligations of $1.5 million related to additional automated manufacturing equipment, with payments expected to come due during 2022 based on vendor performance milestones. 
+Significant Accounting Policies and Critical Accounting Estimates 
+Our significant accounting policies are described in Note 2 – Significant Accounting Policies to the audited consolidated financial statements included herein. Certain of our accounting policies require the application of significant
+judgment by management in selecting the appropriate assumptions for calculating financial estimates. By their nature, these judgments are subject to an inherent degree of uncertainty. These judgments are based on our historical experience,
+terms of existing contracts, our evaluation of trends in the industry, information provided by our customers and information available from other outside sources, as appropriate. We consider an accounting estimate to be critical if (a) it
+requires us to make assumptions about matters that were uncertain at the time we were making the estimate and (b) changes in the estimate or different estimates that we could have selected would have had a material impact on our financial
+condition or results of operations. 
+The following listing is not intended to be a comprehensive list of all of our accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by accounting principles generally accepted in
+the United States, with no need for management’s judgment in their application. There are also areas in which management’s judgment in selecting any viable alternative would not produce a materially different result. 
+Revenue Recognition 
+We recognize revenue for product sales in accordance with Financial Accounting Standards Board Accounting Standards Codification, or ASC, 606, Revenue from Contracts with Customers . Revenues from
+product sales are recognized when the customer obtains control of our product, which occurs at a point in time, typically upon tendering to the customer. We expense incremental costs of obtaining a contract as and when incurred because the
+expected amortization period of the asset that it would have recognized is one year or less or the amount is immaterial. Freight and distribution activities on products are performed after the customer obtains control of the goods. We have made
+an accounting policy election to account for shipping and handling activities that occur either when or after goods are tendered to the customer as a fulfillment activity, and therefore recognizes freight and distribution expenses in cost of
+product sales. We exclude certain taxes from the transaction price ( e.g. , sales, value added and some excise taxes). 
+Estimates of variable consideration and the determination of whether to include estimated amounts in the transaction price are based on all information (historical, current, and forecasted) that is reasonably available to us, taking into
+consideration the type of customer, the type of transaction, market events and trends, and the specific facts and circumstances of each arrangement. 
+For applicable contracts, we recognize revenue from research and development, milestone and grant revenues when earned. Grants are invoiced after expenses are incurred. Revenues from projects or grants funded in advance are deferred until
+earned. For certain collaborative research projects, we recognize revenue by defining milestones at the inception of the agreement and applying judgment and estimates in recognizing revenue for relevant contracts. 
+65 
+Table of Contents 
+From time to time the Company engages in bill-and-hold arrangements, whereby the Company manufactures and sells its product and at the customer’s
+request stores the product at the Company’s warehouse. Even though the product remains in the Company’s possession, a sale is recognized at the point in time when
+the customer obtains control of the product. Control is transferred to the customer in bill and hold transactions when: customer acceptance specifications have been met, legal title has transferred, the customer has a present obligation to
+pay for the product and the risk and rewards of ownership have transferred to the customer. Additionally, all the following bill and hold criteria would have to be met in order for control to be transferred to the customer: 
+(a) 
+The reason for the bill-and-hold arrangement must be substantive (for example, the customer has requested the arrangement). 
+(b) 
+The product must be identified separately as belonging to the customer. 
+(c) 
+The product currently must be ready for physical transfer to the customer. 
+(d) 
+The entity cannot have the ability to use the product or to direct it to another customer. 
+Goodwill 
+We periodically review goodwill for impairment indicators. We review goodwill for impairment annually in the fourth quarter or more frequently if events or changes in circumstances indicate that goodwill might be impaired. We perform the
+goodwill impairment review at the reporting unit level. We perform a qualitative assessment of whether it is more likely than not that a reporting unit’s fair value is less than its carrying amount. If not, no further goodwill impairment
+testing is performed. If so, we perform the step discussed hereafter. Our qualitative assessment involves significant estimates, assumptions, and judgments, including, macroeconomic conditions, industry and market conditions, our financial
+performance, reporting unit specific events and changes in our share price. 
+If the fair value of the reporting unit is greater than its carrying amount, goodwill is not considered to be impaired. We would recognize an impairment charge for the amount by which the carrying
+amount exceeds the reporting unit’s fair value, provided the impairment charge does not exceed the total amount of goodwill allocated to the reporting unit. 
+The company operates as a single operating segment and has one reporting unit. During the year ended December 31, 2021, the Company performed a quantitative analysis and determined that the carrying value exceeded its fair value by $2.6
+million, on December 31, 2021. 
+Recently Issued Accounting Pronouncements 
+Refer to Note 2 – Significant Accounting Policies to the audited consolidated financial statements included herein for a complete description of recent accounting standards that we have not yet been required to implement which may be
+applicable to our operations. Additionally, the significant accounting standards that have been adopted during the year ended December 31, 2021 are described. 
+66 
+Table of Contents 
+ITEM 8. 
+FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+The Consolidated Financial Statements and schedules that constitute Item 8 are attached at the end of this report. An index to the Consolidated Financial Statements and supplemental schedules are also included on page F-1 of this report. 
+ITEM 9A. 
+Controls and Procedures 
+Evaluation of Disclosure Controls and Procedures 
+Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures, as defined by Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as
+of December 31, 2021. Based on the evaluation of our disclosure controls and procedures, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2021 at the
+reasonable assurance level. 
+Management’s Report on Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Securities
+Exchange Act of 1934 as a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer and effected by the board of directors, management and other personnel to provide reasonable assurance regarding
+the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that: 
+• 
+pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; 
+• 
+provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
+expenditures of the company are being made in accordance with authorizations of management and directors of the company; and 
+• 
+provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. As a result, even those systems determined to be effective can provide only reasonable assurance with respect to
+financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance
+with the policies or procedures may deteriorate. 
+Under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, our management evaluated the effectiveness of our internal control over financial reporting as of December 31, 2021. In making their
+assessment of internal control over financial reporting, our management used the criteria described in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Our evaluation
+included documenting, evaluating and testing of the design and operating effectiveness of our internal control over financial reporting. Based on this evaluation, we concluded that our controls over financial reporting were effective as of
+December 31, 2021. 
+67 
+Table of Contents 
+Previously Identified Material Weaknesses in Internal Control Over Financial Reporting 
+None. 
+Changes in Internal Control over Financial Reporting 
+There were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Securities Exchange Act of 1934 during the period covered by this Annual Report on
+Form 10-K that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+Inherent Limitations of Internal Control 
+Management, including the Company’s Chief Executive Officer and Chief Financial Officer, does not expect that the Company’s internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and
+operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints and the benefits of controls
+must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of internal control can provide absolute assurance that all control issues and instances of fraud, if any, have been detected.
+Also, any evaluation of the effectiveness of internal controls in future periods are subject to the risk that those internal controls may become inadequate because of changes in business conditions, or that the degree of compliance with the
+policies and procedures may deteriorate. 
+ITEM 9B. 
+Other Information 
+None. 
+68 
+Table of Contents 
+PART III 
+ITEM 10. 
+DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
+The information required in response to this Item 10 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the
+fiscal year covered by this Annual Report on Form 10-K. 
+ITEM 11. 
+EXECUTIVE COMPENSATION 
+The information required in response to this Item 11 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the
+fiscal year covered by this Annual Report on Form 10-K. 
+ITEM 12. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+The information required in response to this Item 12 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the
+fiscal year covered by this Annual Report on Form 10-K. 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE. 
+The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the
+fiscal year covered by this Annual Report on Form 10-K. 
+ITEM 14. 
+PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+The information required in response to this Item 14 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the
+fiscal year covered by this Annual Report on Form 10-K. 
+69 
+Table of Contents 
+ITEM 15. 
+EXHIBITS, FINANCIAL STATEMENT SCHEDULES 
+(a) See “Item 8. Financial Statements and Supplementary Data – Index to Consolidated Financial Statements” above. 
+(b) Exhibits 
+Exhibit No. 
+Description 
+3.1 
+Articles of Incorporation, as amended, of Chembio Diagnostics, Inc. (incorporated herein by reference to Exhibit 3.1 to the
+Quarterly Report on Form 10-Q filed on July 29, 2010) 
+3.2 
+Amended and Restated Bylaws, of Chembio Diagnostics, Inc. (incorporated herein by reference to Exhibit 3.2 to the Current
+Report on Form 8-K filed on September 17, 2018) 
+4.1 
+Warrant to Purchase Common Stock dated as of September 3, 2019, issued by Chembio Diagnostics, Inc. to Perceptive Credit
+Holdings II, LP (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on September 5, 2019) 
+4.2 
+Description of Securities (incorporated herein by reference to Exhibit 4.2 to the Annual Report on Form 10-K filed on March 11,
+2021) 
+10.1(a)* 
+2008 Stock Incentive Plan, as amended (incorporated herein by reference to Attachment B to the Proxy Statement on Form DEF 14A
+filed on 2012) 
+10.1(b)* 
+Form of Option for 2008 Stock Incentive Plan (incorporated herein by reference to Exhibit 4.4 to the Quarterly Report on Form
+10-Q filed on May 8, 2014) 
+10.2(a)* 
+2014 Stock Incentive Plan (incorporated herein by reference to Attachment A to the Proxy Statement on Form DEF 14A filed on
+April 29, 2014) 
+10.2(b)* 
+Form of Option for 2014 Stock Incentive Plan (incorporated herein by reference to Exhibit 4.7 to the Quarterly Report on Form
+10-Q filed on August 7, 2014) 
+10.3* 
+2019 Omnibus Incentive Plan (incorporated herein by reference to Exhibit 10.3 to the Annual Report on Form 10-K filed on March
+13, 2020) 
+10.4* 
+Restated Annual Incentive Bonus Plan of Chembio Diagnostics, Inc., adopted as of March 15, 2019 (incorporated herein by
+reference to Exhibit 10.3 to the Annual Report on Form 10-K filed on March 18, 2019) 
+10.5* 
+Outside Director Compensation Policy of Chembio Diagnostics, adopted as of December 15, 2020 (incorporated herein by reference
+to Exhibit 10.1 to the Current Report on Form 8-K filed on December 17, 2020) 
+10.6(a)* 
+Employment Agreement, dated as of March 4, 2020 and effective as of March 16, 2020 between Chembio Diagnostics, Inc. and
+Richard L. Eberly (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on March 20, 2020) 
+10.6(b)* 
+Amendment No. 1 dated February 9, 2022 between Chembio Diagnostics, Inc. and Richard L. Eberly, amending the Employment
+Agreement dated March 4, 2020 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on February 14, 2022) 
+10.7(a)* 
+Employment Agreement dated March 5, 2016 between Chembio Diagnostics, Inc. and Javan Esfandiari (incorporated herein by
+reference to Exhibit 10.2 to the Current Report on Form 8-K filed on March 14, 2016) 
+10.7(b)* 
+Amendment No. 1 dated March 20, 2019 between Chembio Diagnostics, Inc. and Javan Esfandiari, amending the Employment Agreement
+dated March 5, 2016 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on March 25, 2019) 
+10.7(c)* 
+Amendment No. 2 dated November 30, 2021 between Chembio Diagnostics, Inc. and Javan Esfandiari, amending the Employment
+Agreement dated March 5, 2016 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on December 6, 2021) 
+10.8(a)* 
+Employment Agreement dated December 18, 2017 between Chembio Diagnostics, Inc. and Neil A. Goldman (incorporated herein by
+reference to Exhibit 10.4 to the Annual Report on Form 10-K filed on March 8, 2018). 
+10.8(b)* 
+Amendment No. 1 dated January 21, 2019 between Chembio Diagnostics, Inc. and Neil A. Goldman, amending Employment Agreement
+dated December 18, 2017 (incorporated herein by reference to Exhibit 10.01 to the Current Report on Form 8-K filed on January 25, 2019) 
+10.9* 
+Employment Agreement, dated as of December 30, 2021 and effective as of January 5, 2022, between Chembio Diagnostics, Inc. and
+Lawrence J. Steenvoorden (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on January 6, 2022) 
+10.10* 
+Offer Letter dated October 19, 2016 between Worldwide Workplace Ireland and Robert Passas, with respect to employment by
+Chembio Diagnostics Systems, Inc. (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K filed on October 22, 2018) 
+10.11 
+Separation and Release Agreement, dated January 7, 2020, between Chembio Diagnostics, Inc. and John J. Sperzel III
+(incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on January 9, 2020) 
+10.12(a) 
+Lease Agreement, dated February 15, 2017, between Horseblock Associates and Chembio Diagnostics, Inc. with respect to 3661
+Horseblock Road, Medford, New York, as amended (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 22, 2018) 
+10.12(b) 
+Agreement of Sublease dated February 5, 2019 between Chembio Diagnostic Systems Inc., as sublessor, and Reliance
+Communications of New Jersey, LLC, as sublessee, with respect to 3661 Horseblock Road, Medford, New York, as amended (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on February 11, 2019) 
+10.13 
+Lease Agreement, dated February 4, 2013, between Sherwood Corporate Center LLC and Chembio
+Diagnostics, Inc. with respect to 91-1A Colin Drive, Holbrook, New York, as amended on September 19, 2017 (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on October 22, 2018) 
+10.14 
+Lease Agreement dated February 5, 2019 between Myra Properties, LLC, as lessor, and Chembio Diagnostic Systems Inc., as
+lessee, with respect to 555 Wireless Boulevard, Hauppauge, New York (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on February 11, 2019) 
+10.15† 
+Credit Agreement and Guaranty dated as of September 3, 2019, among Chembio Diagnostics, Inc., as the Borrower, the Guarantors
+from time to time party thereto, and Perceptive Credit Holdings II, LP and its successors and assigns party thereto, as Administrative Agent and as a Lender (incorporated herein by reference to Exhibit 10.1 to the Current Report on
+Form 8-K filed on September 5, 2019) 
+10.16 
+At the Market Offering Agreement, dated July 19, 2021, between Chembio Diagnostics, Inc. and Craig-Hallum Capital Group LLC
+(incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on July 19, 2021) 
+14.1 
+Ethics Policy (incorporated herein by reference to Exhibit 14.1 to the Annual Report on Form 10-KSB filed on March 30, 2006) 
+21.1 
+List of Subsidiaries of Chembio Diagnostics, Inc. 
+70 
+Table of Contents 
+23.1 
+Consent of EY, Independent Registered Public Accounting Firm 
+31.1 
+Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+31.2 
+Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+32.1** 
+Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to
+Section 906 of the Sarbanes-Oxley Act of 2002 
+101.INS 
+XBRL Instance Document 
+101.SCH 
+XBRL Taxonomy Extension Schema Document 
+101.CAL 
+XBRL Taxonomy Extension Calculation Linkbase Document 
+101.DEF 
+XBRL Taxonomy Definition Linkbase Document 
+101.LAB 
+XBRL Taxonomy Label Linkbase Document 
+101.PRE 
+XBRL Taxonomy Presentation Linkbase Document 
+* 
+Indicates management contract or compensatory plan. 
+† 
+Certain exhibits and schedules have been omitted pursuant to Item 601(a)(5) of Regulation S-K. We hereby undertake to furnish copies of the omitted exhibits and schedules upon request by the Securities and
+Exchange Commission, provided that we may request confidential treatment pursuant to Rule 24b-2 of the Securities Exchange Act of 1934 for the exhibits and schedules so furnished. 
+** 
+The certifications attached as Exhibit
+32.1 accompany the Annual Report on Form 10-K pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the registrant for purposes of Section 18 of
+the Securities Exchange Act of 1934, as amended. 
+71 
+Table of Contents 
+SIGNATURES 
+In accordance with Section 13 or 15(d) of the Exchange Act, the registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+CHEMBIO DIAGNOSTICS, INC. 
+March 3, 2022 
+By 
+/s/ Richard L. Eberly 
+Richard L. Eberly 
+Chief Executive Officer and President 
+In accordance with the requirements of the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+Signatures 
+Title 
+Date 
+/s/ Richard L. Eberly 
+Chief Executive Officer and President 
+March 3, 2022 
+Richard L. Eberly 
+(Principal Executive Officer) 
+/s/ Lawrence J. Steenvoorden 
+Chief Financial Officer 
+March 3, 2022 
+Lawrence J. Steenvoorden 
+(Principal Financial & Accounting Officer) 
+Chair of the Board 
+Katherine L. Davis 
+/s/ David W. K. Acheson 
+Director 
+March 3, 2022 
+David W. K. Acheson 
+/s/ David W. Bespalko 
+Director 
+March 3, 2022 
+David W. Bespalko 
+/s/ John G. Potthoff 
+Director 
+March 3, 2022 
+John G. Potthoff 
+72 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+Index to Consolidated Financial Statements 
+—INDEX— 
+Pages 
+Reports of Independent Registered Public Accounting Firm (PCAOB ID 42 ) 
+F-1 
+Consolidated Financial Statements: 
+Balance Sheets as of December 31, 2021 and 2020 
+F-2 
+Statements of Operations for the years ended December 31, 2021 and 2020 
+F-3 
+Statements of Comprehensive Loss for the years ended December 31, 2021 and 2020 
+F-4 
+Statements of Changes in Stockholders’ Equity for the years ended December 31, 2021 and 2020 
+F-5 
+Statements of Cash Flows for the years ended December 31, 2021 and 2020 
+F-6 
+Notes to Consolidated Financial Statements 
+F-7 - F-33 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+To the Stockholders and the Board of Directors of Chembio Diagnostics, Inc. 
+Opinion on the Financial Statements 
+We have audited the accompanying consolidated balance sheet of Chembio Diagnostics, Inc. (and subsidiaries) (the Company) as of December 31, 2021 and
+2020, the related consolidated statements of operations, comprehensive loss , stockholders' equity and cash flows for the years ended December
+31, 2021 and 2020, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company
+at December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles. 
+The Company’s Ability to Continue as a Going Concern 
+The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note
+2 to the consolidated financial statements, the Company has suffered recurring losses from operations and has stated that substantial doubt exists about the Company’s ability to continue as a going concern. Management's evaluation of the events
+and conditions and management’s plans regarding these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty. As explained below, auditing
+the Company’s evaluation of its ability to continue as a going concern was a critical audit matter. 
+Basis for Opinion 
+These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial
+statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S.
+federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable
+assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As
+part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.
+Accordingly, we express no such opinion. 
+Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and
+performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used
+and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. 
+Critical Audit Matters 
+The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or
+required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of
+the critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing a separate opinion on the critical audit
+matters or on the accounts or disclosures to which they relate. 
+Revenue Recognition – Transfer of Control 
+Description of the Matter 
+For the year ended December 31, 2021, the Company recognized $34.7 million of net product revenue. As discussed in Note 2 to
+the consolidated financial statements, product revenue is recognized when the customer obtains control of the Company’s product in an amount that reflects the consideration which the Company expects to receive in exchange for those
+goods or services. 
+Auditing the determination of transfer of control to recognize revenue was especially complex due to the
+variability in the terms and conditions within certain customer contracts. Customer contracts must be carefully evaluated for terms that may affect the timing or measurement of revenue recognition, including any bill-and-hold
+arrangements. 
+How We Addressed the Matter in Our Audit 
+To test the transfer of control, our audit procedures included, among others, testing that the Company
+recorded revenue in accordance with the terms and conditions of the contract by testing a sample of customer contracts. As part of this testing, we inspected the executed customer contract to identify the performance obligation and when
+the transfer of control occurred. We evaluated the Company’s assessment as to when the performance obligation was fulfilled, and that revenue was properly recognized within the correct period. Our procedures also included inspecting
+third-party evidence of transfer of control to the customer, and where appropriate, we also confirmed with customers contract terms and conditions. We also performed cut-off testing around period end in order to test that revenue was
+properly recognized in the correct period. 
+Going Concern 
+Description of the Matter 
+As discussed in Note 2, the determination as to whether the Company can continue as a going concern includes consideration of
+management’s operating plan and anticipated timing of future cash flows. The Company’s Credit Agreement contains covenants that, among other items, require the Company to maintain a minimum cash balance and meet certain minimum revenue
+requirements. This matter is also described in the "Going Concern Uncertainty" section of our report. Management is required to make subjective judgments and assumptions in concluding on going concern uncertainty. 
+Auditing the Company’s going concern assessment is complex because it involves a high degree of auditor judgment to assess
+the reasonableness of the cash flow forecasts used in the Company’s going concern analysis. In particular, the cash flows are sensitive to changes related to significant assumptions, such as the estimation of the future cash to be used
+in operations, projected net revenue, projected earnings before interest, taxes, depreciation and amortization, and compliance with debt covenants. The Company’s ability to achieve forecasted results is judgmental given the
+unpredictability of its customers spending habits as a result of the COVID-19 pandemic. 
+How We Addressed the Matter in Our Audit 
+To test the future cash flow forecasts, we performed audit procedures that included, among others,
+evaluating and testing the significant assumptions discussed above and the underlying data used by the Company in its analysis. This testing included inquiries with management, comparison of prior period forecasts to actual results,
+consideration of contrary evidence impacting management’s forecasts, and the Company’s financing arrangements in place as of the report date. 
+Goodwill and Long-Lived Assets Impairment 
+Description of the Matter 
+As discussed in Notes 2 and 14 to the consolidated financial statements, the Company identified indicators of impairment,
+which resulted in the Company assessing the value of goodwill and its long-lived asset group for recoverability. The Company's analysis resulted in goodwill and long-lived asset impairment charges of $2.6 million and $2.0 million,
+respectively. 
+Auditing the Company's measurement of impairment involved a high degree of subjectivity as estimates
+underlying the determination of fair values were based on assumptions about future economic conditions. Significant assumptions used in the Company's fair value estimates included projected net revenue and projected earnings before
+interest, taxes, depreciation and amortization. 
+How We Addressed the Matter in Our Audit 
+To test the future economic conditions, as part of our audit, we assessed the methodologies and
+significant assumptions used in the impairment tests, among other procedures. We tested the significant assumptions discussed above, as well as the completeness and accuracy of the underlying data used in the valuations. In order to
+reflect the uncertainty inherent in the projections, we performed our own sensitivity analyses by increasing or decreasing the significant assumptions and evaluated the potential impact on the fair value. In addition, we tested the
+reconciliation of the fair value of the reporting unit developed by management to the market capitalization of the Company as of the valuation date and evaluated the implied control premium for reasonableness. 
+/s/ Ernst & Young LLP 
+We have served as the Company’s auditor since 2020. 
+Jericho, New York 
+March 3, 2022 
+F-1 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED BALANCE SHEETS 
+AS OF 
+December 31, 
+2021 
+2020 
+- ASSETS - 
+CURRENT ASSETS: 
+Cash and cash equivalents 
+$ 
+28,772,892 
+$ 
+23,066,301 
+Accounts receivable, net of allowance for doubtful accounts of $ 243,042 and $ 296,793 at December 31, 2021 and 2020,
+respectively 
+11,441,107 
+3,377,387 
+Inventories, net 
+12,920,451 
+12,516,402 
+Prepaid expenses and other current assets 
+1,710,194 
+778,683 
+TOTAL CURRENT ASSETS 
+54,844,644 
+39,738,773 
+FIXED ASSETS: 
+Property, plant and equipment, net 
+8,556,773 
+8,688,403 
+Finance lease right-of-use assets, net 
+191,870 
+233,134 
+OTHER ASSETS: 
+Operating right-of-use assets, net 
+5,891,906 
+6,112,632 
+Intangible assets, net 
+- 
+3,645,986 
+Goodwill 
+3,022,787 
+5,963,744 
+Deposits and other assets 
+744,215 
+509,342 
+TOTAL ASSETS 
+$ 
+73,252,195 
+$ 
+64,892,014 
+- LIABILITIES AND STOCKHOLDERS’ EQUITY - 
+CURRENT LIABILITIES: 
+Accounts payable and accrued liabilities 
+$ 
+13,127,993 
+$ 
+10,042,790 
+Deferred revenue 
+- 
+1,606,997 
+Current portion of long term debt 
+1,200,000 
+- 
+Operating lease liabilities 
+886,294 
+642,460 
+Finance lease liabilities 
+68,176 
+58,877 
+TOTAL CURRENT LIABILITIES 
+15,282,463 
+12,351,124 
+OTHER LIABILITIES: 
+Long-term operating lease liabilities 
+5,976,151 
+6,327,143 
+Long-term finance lease liabilities 
+139,678 
+185,239 
+Long-term debt, less current portion, net 
+17,589,003 
+18,182,158 
+Deferred tax liability 
+- 
+69,941 
+TOTAL LIABILITIES 
+38,987,295 
+37,115,605 
+COMMITMENTS AND CONTINGENCIES (Note 12) 
+STOCKHOLDERS’ EQUITY: 
+Preferred stock – 10,000,000 
+shares authorized, none outstanding 
+- 
+- 
+Common stock - $ 0.01 
+par value; 100,000,000 shares authorized, 30,104,986 and 20,223,498 shares issued and outstanding at December 31, 2021 and 2020,
+respectively 
+301,050 
+202,235 
+Additional paid-in capital 
+165,772,636 
+124,961,514 
+Accumulated deficit 
+( 131,009,860 
+) 
+( 97,106,331 
+) 
+Treasury stock – 48,057 
+and 41,141 shares at cost, at December 31, 2021 and 2020, respectively 
+( 206,554 
+) 
+( 190,093 
+) 
+Accumulated other comprehensive loss 
+( 592,372 
+) 
+( 90,916 
+) 
+TOTAL STOCKHOLDERS’ EQUITY 
+34,264,900 
+27,776,409 
+TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY 
+$ 
+73,252,195 
+$ 
+64,892,014 
+See accompanying notes to consolidated financial statements 
+F-2 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF OPERATIONS 
+December 31, 
+2021 
+2020 
+REVENUES: 
+Product revenue 
+$ 
+34,737,444 
+$ 
+24,767,149 
+R&D revenue 
+1,159,381 
+4,851,562 
+Government grant income 
+10,891,726 
+2,018,924 
+License and royalty revenue 
+1,029,901 
+832,562 
+TOTAL REVENUES 
+47,818,452 
+32,470,197 
+COSTS AND EXPENSES: 
+Cost of product sales 
+34,495,802 
+23,874,487 
+Research and development expenses 
+12,487,424 
+9,508,494 
+Selling, general and administrative expenses 
+24,840,611 
+21,037,701 
+I mpairment, restructuring, severance and related costs 
+7,047,779 
+1,122,310 
+Acquisition costs 
+- 
+63,497 
+78,871,616 
+55,606,489 
+LOSS FROM OPERATIONS 
+( 31,053,164 
+) 
+( 23,136,292 
+) 
+OTHER (EXPENSE) INCOME: 
+Interest expense, net 
+( 2,912,415 
+) 
+( 2,841,830 
+) 
+LOSS BEFORE INCOME TAX BENEFIT 
+( 33,965,579 
+) 
+( 25,978,122 
+) 
+Income tax benefit 
+62,050 
+456,794 
+NET LOSS 
+$ 
+( 33,903,529 
+) 
+$ 
+( 25,521,328 
+) 
+Basic and diluted loss per share 
+$ 
+( 1.40 
+) 
+$ 
+( 1.34 
+) 
+Weighted average number of shares outstanding, basic and diluted 
+24,299,465 
+19,085,691 
+See accompanying notes to consolidated financial statements 
+F-3 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS 
+December 31, 
+2021 
+2020 
+Net loss 
+$ 
+( 33,903,529 
+) 
+$ 
+( 25,521,328 
+) 
+Other comprehensive loss: 
+Foreign currency translation adjustments 
+( 501,456 
+) 
+( 100,760 
+) 
+COMPREHENSIVE LOSS 
+$ 
+( 34,404,985 
+) 
+$ 
+( 25,622,088 
+) 
+See accompanying notes to consolidated financial statements 
+F-4 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY 
+FOR THE YEARS ENDED DECEMBER 31, 2021,
+AND 2020 
+Common Stock 
+Additional 
+Paid-in-Capital 
+Treasury Stock 
+Accumulated 
+Deficit 
+AOCL 
+Total 
+Shares 
+Amount 
+Amount 
+Shares 
+Amount 
+Amount 
+Amount 
+Amount 
+Balance at December 31, 2019 
+17,733,617 
+$ 
+177,335 
+$ 
+95,433,077 
+- 
+$ 
+- 
+$ 
+( 71,585,003 
+) 
+$ 
+9,844 
+$ 
+24,035,253 
+Common Stock: 
+Issuance of stock, net 
+2,619,593 
+26,196 
+28,410,544 
+- 
+- 
+- 
+- 
+28,436,740 
+Restricted stock issued 
+81,773 
+819 
+128,356 
+- 
+- 
+- 
+- 
+129,175 
+Restricted stock compensation, net 
+( 470,174 
+) 
+( 4,702 
+) 
+617,919 
+- 
+- 
+- 
+- 
+613,217 
+Shares tendered for withholding taxes 
+- 
+- 
+( 296,667 
+) 
+- 
+- 
+- 
+- 
+( 296,667 
+) 
+Options: 
+Exercised 
+5,528 
+55 
+( 55 
+) 
+- 
+- 
+- 
+- 
+- 
+Stock option compensation 
+- 
+- 
+480,779 
+- 
+- 
+- 
+- 
+480,779 
+Treasury Stock 
+- 
+- 
+190,093 
+( 41,141 
+) 
+( 190,093 
+) 
+- 
+- 
+- 
+Warrant exercised 
+253,161 
+2,532 
+( 2,532 
+) 
+- 
+- 
+- 
+- 
+- 
+Comprehensive loss 
+- 
+- 
+- 
+- 
+- 
+- 
+( 100,760 
+) 
+( 100,760 
+) 
+Net loss 
+- 
+- 
+- 
+- 
+- 
+( 25,521,328 
+) 
+- 
+( 25,521,328 
+) 
+Balance at December 31, 2020 
+20,223,498 
+$ 
+202,235 
+$ 
+124,961,514 
+( 41,141 
+) 
+$ 
+( 190,093 
+) 
+$ 
+( 97,106,331 
+) 
+$ 
+( 90,916 
+) 
+$ 
+27,776,409 
+Common Stock: 
+Issuance of stock, net 
+9,709,328 
+97,093 
+38,714,865 
+- 
+- 
+- 
+- 
+38,811,958 
+Restricted stock issued 
+135,908 
+1,359 
+105,582 
+- 
+- 
+- 
+- 
+106,941 
+Restricted stock compensation, net 
+- 
+- 
+1,160,953 
+- 
+- 
+- 
+- 
+1,160,953 
+Shares tendered for withholding taxes 
+- 
+- 
+( 145,225 
+) 
+- 
+- 
+- 
+- 
+( 145,225 
+) 
+Options: 
+Exercised 
+36,252 
+363 
+85,192 
+- 
+- 
+- 
+- 
+85,555 
+Stock option compensation 
+- 
+- 
+873,294 
+- 
+- 
+- 
+- 
+873,294 
+Treasury stock 
+- 
+- 
+16,461 
+( 6,916 
+) 
+( 16,461 
+) 
+- 
+- 
+- 
+Comprehensive loss 
+- 
+- 
+- 
+- 
+- 
+- 
+( 501,456 
+) 
+( 501,456 
+) 
+Net loss 
+- 
+- 
+- 
+- 
+- 
+( 33,903,529 
+) 
+- 
+( 33,903,529 
+) 
+Balance at December 31, 2021 
+30,104,986 
+$ 
+301,050 
+$ 
+165,772,636 
+( 48,057 
+) 
+$ 
+( 206,554 
+) 
+$ 
+( 131,009,860 
+) 
+$ 
+( 592,372 
+) 
+$ 
+34,264,900 
+See accompanying notes to consolidated financial statements 
+F-5 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+FOR THE YEARS ENDED 
+December 31, 
+2021 
+2020 
+CASH FLOWS FROM OPERATING ACTIVITIES: 
+Cash received from customers and grants 
+$ 
+38,093,984 
+$ 
+34,736,133 
+Cash paid to suppliers and employees 
+( 65,273,967 
+) 
+( 50,238,409 
+) 
+Cash paid for operating leases 
+( 1,404,532 
+) 
+( 1,139,944 
+) 
+Cash paid for finance leases 
+( 20,077 
+) 
+( 19,987 
+) 
+Interest and taxes, net 
+( 2,281,124 
+) 
+( 2,225,031 
+) 
+Net cash used in operating activities 
+( 30,885,716 
+) 
+( 18,887,238 
+) 
+CASH FLOWS FROM INVESTING ACTIVITIES: 
+Acquisition of and deposits on fixed assets 
+( 1,824,285 
+) 
+( 3,961,369 
+) 
+Patent application costs 
+( 33,398 
+) 
+( 205,493 
+) 
+Net cash used in investing activities 
+( 1,857,683 
+) 
+( 4,166,862 
+) 
+CASH FLOWS FROM FINANCING ACTIVITIES: 
+Proceeds from sale of common stock, net 
+38,811,958 
+28,436,740 
+Proceeds from option exercises 
+85,555 
+- 
+Principal payments for finance leases 
+( 61,867 
+) 
+( 51,166 
+) 
+Payments on note payable 
+- 
+( 180,249 
+) 
+Stimulus package loan 
+- 
+2,978,315 
+Payment of stimulus package loan 
+- 
+( 2,978,315 
+) 
+Payments of tax withholdings on stock award 
+( 145,225 
+) 
+( 441,723 
+) 
+Net cash provided by financing activities 
+38,690,421 
+27,763,602 
+Effect of exchange rate changes on cash 
+( 240,431 
+) 
+85,447 
+INCREASE IN CASH AND CASH EQUIVALENTS 
+5,706,591 
+4,794,949 
+Cash and cash equivalents - beginning of the period 
+23,066,301 
+18,271,352 
+Cash and cash equivalents - end of the period 
+$ 
+28,772,892 
+$ 
+23,066,301 
+RECONCILIATION OF NET LOSS TO NET CASH USED IN OPERATING ACTIVITIES: 
+Net Loss 
+$ 
+( 33,903,529 
+) 
+$ 
+( 25,521,328 
+) 
+Adjustments: 
+Depreciation and amortization 
+2,930,976 
+2,697,126 
+Share based compensation 
+2,431,982 
+1,223,171 
+Benefit from deferred tax liability 
+( 69,941 
+) 
+( 396,385 
+) 
+Provision for (recovery of) doubtful accounts 
+( 53,751 
+) 
+270,193 
+Non-cash inventory changes 
+4,054,701 
+3,543,515 
+Impairment charges 
+5,880,741 
+- 
+Changes in assets and liabilities: 
+Accounts receivable 
+( 8,009,969 
+) 
+283,939 
+Inventories 
+( 4,458,750 
+) 
+( 6,461,887 
+) 
+Prepaid expenses and other current assets 
+( 931,510 
+) 
+( 85,670 
+) 
+Deposits and other assets 
+( 234,874 
+) 
+34,195 
+Accounts payable and accrued liabilities 
+3,085,205 
+4,043,896 
+Deferred revenue 
+( 1,606,997 
+) 
+1,481,997 
+Net cash used in operating activities 
+$ 
+( 30,885,716 
+) 
+$ 
+( 18,887,238 
+) 
+Supplemental disclosures for non-cash investing and financing activities: 
+Deposits on manufacturing equipment transferred to fixed assets 
+$ 
+- 
+$ 
+472,651 
+Contingent liability earnout 
+$ 
+- 
+$ 
+1,011,261 
+See accompanying notes to consolidated financial statements 
+F-6 
+Table of Contents 
+NOTE 1 — DESCRIPTION OF BUSINESS: 
+We develop and commercialize point-of-care diagnostic tests used for the rapid detection and diagnosis of infectious diseases, including sexually
+transmitted disease, insect vector and tropical disease, COVID-19 and other viral and bacterial infections, enabling expedited treatment. 
+Our product portfolio is based upon our proprietary DPP technology, a diagnostic platform that provides high-quality, cost-effective results in 15
+to 20 minutes using fingertip blood, nasal swabs and other sample types. The DPP technology platform addresses the rapid diagnostic test market, which includes infectious diseases such as STI's and HIV, Gastroenterology and Women's Health. Compared
+with traditional lateral flow technology, the DPP technology platform can provide: 
+• 
+Enhanced sensitivity and specificity: This is achieved via our
+patented approach to separating the sample path from the buffer path, together with other patented and proprietary strategies, that differ significantly from traditional lateral flow test. 
+• 
+Advanced multiplexing capabilities: Through advanced multiplexing,
+the DPP platform can detect and differentiate up to eight distinct test results from a single patient sample, which can deliver greater clinical value than other rapid tests currently on the market. 
+• 
+Objective results: For some diagnostic applications, our
+easy-to-use, highly portable, battery-operated DPP Micro Reader optical analyzers can report accurate results in approximately 15 seconds, making it well-suited for decentralized testing where real-time results enable patients to be
+clinically assessed while they are still onsite. Objective results produced by the DPP Micro Reader can reduce the possibility of the types of human error that can be experienced in the visual interpretations required by many rapid tests. 
+We target the market for rapid diagnostic test solutions for infectious diseases, which is driven by the high prevalence of infectious diseases
+globally, an increase in the geriatric population, growing demand for rapid test results, and advancements in multiplexing. We have a broad portfolio of infectious disease products, which prior to 2020 were focused principally on sexually
+transmitted disease and fever and tropical disease. In February 2020 we began the process of shifting substantially all of our resources to seek to leverage the DPP technology platform to address the acute and escalating need for diagnostic testing
+for COVID-19. We are continuing to pursue: 
+• 
+an emergency use authorization, or EUA, from the U.S. Food and Drug Administration, or FDA, as well as 510(k) clearance from the FDA, for
+the DPP SARS-CoV-2 Antigen test system; 
+• 
+an EUA from the FDA for the DPP Respiratory Antigen Panel; and 
+• 
+a Clinical Laboratory Improvement Amendment, or CLIA, waiver from the FDA for the DPP HIV-Syphilis test system. 
+F-7 
+Table of Contents 
+NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES: 
+(a) Basis
+of Presentation: 
+The accompanying consolidated financial statements include the accounts of Chembio and its subsidiaries. All significant intercompany accounts and transactions have been
+eliminated in consolidation. 
+Going Concern Considerations 
+Revenues during the twelve months ended December 31, 2021 did not meet the Company’s expectations. The Company’s increase in cash and cash equivalents over the year
+reflected its issuance of common stock in at-the-market offerings for net proceeds of $ 38.8 million (see Note 9 - Stockholder's Equity).
+The Company continued to experience market, clinical trial and regulatory complications in seeking to develop and commercialize a portfolio of COVID-19 test systems during the continuing, but evolving, uncertainty of the COVID‑19 pandemic. For the
+year ending December 31, 2021, the Company continued to incur significant expenses in connection with pending legal matters (see Note 12 – Commitments, Contingencies, and Concentrations: Litigation), delayed achievement of milestones associated
+with government grant income, investments in inventory, and the continuing automation of manufacturing. 
+The Company performed an assessment to determine whether there were conditions or events that, considered in the aggregate, raised substantial doubt about the
+Company’s ability to continue as a going concern within one year after the date the accompanying consolidated financial statements are being issued. Initially, this assessment did not consider the potential mitigating effect of management’s plans
+that had not been fully implemented. Because, as described below, substantial doubt was determined to exist as the result of this initial assessment, management then assessed the mitigating effect of its plans to determine if it is probable that
+the plans (1) would be effectively implemented within one year after the date the accompanying consolidated financial statements are issued and (2) when implemented, would mitigate the relevant conditions or events that raise substantial doubt
+about the entity’s ability to continue as a going concern. 
+During the twelve months ended December 31, 2021, the Company undertook measures to increase its total revenues and improve its liquidity position. In particular, the
+Company received significant purchase orders from two customers (the “July Purchase Orders”). The Company had pursued the July Purchase
+Orders for an extended period of time. The July Purchase Orders consist of the following: 
+• 
+On July 20, 2021, the Company received a $ 28.3 million purchase order
+from Bio-Manguinhos for the purchase of DPP SARS-CoV-2 Antigen tests for delivery during 2021 to support the urgent needs of Brazil’s Ministry of Health in addressing the COVID-19 pandemic. Bio-Manguinhos is responsible for the development
+and production of vaccines, diagnostics and biopharmaceuticals, primarily to meet the demand of Brazil’s national public health system. As of December 31, 2021 $ 16.8 million was recognized in connection with this order. 
+• 
+On July 22, 2021, the Company received a $ 4 million purchase order
+from the Partnership for Supply Chain Management, supported by The Global Fund, for the purchase of HIV 1/2 STAT-PAK Assays for shipment to Ethiopia into early 2022. As of December 31, 2021 $ 1.2 million was recognized in connection with this order. 
+These measures and other plans and initiatives have been designed to provide the Company with adequate liquidity to meet its
+obligations for at least the twelve-month period following the date the accompanying audited consolidated financial statements are being issued. The Company’s execution of those measures and its other plans and initiative continue to depend,
+however, on factors and uncertainties that are beyond the Company’s control, or that may not be addressable on terms acceptable to the Company or at all. The Company considered in particular how: 
+F-8 
+Table of Contents 
+• 
+The ongoing healthcare and economic impacts of the COVID-19 pandemic on the global customer base for the Company’s non‑COVID-19 products continue to negatively affect the timing
+and rate of recovery of the Company’s revenues from those products by, for example, decreasing the allocation of funding for HIV testing, thereby continuing to adversely affect the Company’s liquidity. 
+• 
+Although the Company has entered into agreements to distribute third-party COVID-19 products in the United States, its ability to sell those products could be constrained because
+of staffing and supply chain limitations affecting the suppliers of those products. 
+The Company further considered how these factors and uncertainties could impact its ability over the next year to meet the obligations specified in the Credit
+Agreement with the Lender (each as defined in Note 13 – Long-Term Debt). Those obligations include covenants requiring: i) minimum cash balance of $3.0 million and ii) minimum total revenue amounts for the twelve months preceding each quarter end.
+For the next year, the minimum total revenue requirements range from $ 42.0 million for the twelve months ending March 31, 2022 to $ 47.4 million for the twelve months ending December 31, 2022. Upon an event of default under the Credit Agreement, the Lender could elect to declare all
+amounts outstanding thereunder, together with accrued interest, to be immediately due and payable. In such an event, there can be no assurance that the Company would have sufficient liquidity to fund payment of the amounts that would be due under
+the Credit Agreement or that, if such liquidity were not available, the Company would be successful in raising additional capital on acceptable terms, or at all, or in completing any other endeavor to continue to be financially viable and continue
+as a going concern. The Company’s inability to raise additional capital on acceptable terms in the near future, whether for purposes of funding payments required under the Credit Agreement or providing additional liquidity needed for its
+operations, could have a material adverse effect on its business, prospects, results of operations, liquidity and financial condition. 
+Accordingly, management determined the Company could not be certain that the Company’s plans and initiatives would be effectively implemented within one year after the
+date on which the accompanying consolidated financial statements are being issued. Without giving effect to the prospect of raising additional capital pursuant to the ATM Agreement (as defined in Note 9 – Stockholders’ Equity: Common Stock),
+increasing product revenue in the near future or executing other mitigating plans, many of which are beyond the Company’s control, it is unlikely that the Company will be able to generate sufficient cash flows to meet its required financial
+obligations, including its debt service and other obligations due to third parties. The existence of these conditions raises substantial doubt about the Company’s ability to continue as a going concern for the twelve-month period following the date
+on which the accompanying audited consolidated financial statements are being issued. 
+The accompanying audited consolidated financial statements have been prepared assuming the Company will continue as a going concern, which contemplates continuity of
+operations, realization of assets and the satisfaction of liabilities in the normal course of business for the twelve-month period following the date the accompanying consolidated financial statements are issued. As such, the accompanying audited
+consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amounts, or the amount and classification of liabilities that may result should the Company be unable to
+continue as a going concern. 
+(b) Use
+of Estimates: 
+The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make
+assumptions and estimates that affect the amounts reported in the consolidated financial statements and accompanying notes. Judgments and estimates of uncertainties are required in applying the Company’s accounting policies in certain areas.
+Generally, matters subject to estimation and judgment include accounts receivable realization, inventory obsolescence, asset impairments, recognition of revenue, useful lives of intangible and fixed assets, stock-based compensation, and deferred tax
+asset valuation allowances. Due to the inherent uncertainty involved in making estimates, actual results reported in future periods may be based upon amounts that differ from those estimates. 
+F-9 
+Table of Contents 
+(c) Fair
+Value of Financial Instruments: 
+The carrying value for cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate fair value due to the immediate or short-term
+maturity of these financial instruments. Included in cash and cash equivalents is $ 25.0 million and $ 16.0 million as of December 31, 2021 and 2020, respectively, of money market funds that are Level 1 fair value measurements under the hierarchy. The fair
+value of the Company’s total debt of $ 20 million (carrying value of $ 18.8 million) and $ 20 million (carrying value of $ 18.2 million) as of December 31, 2021 and 2020, respectively, is a Level 2 fair value measurement under the hierarchy, and the carrying value approximates
+fair value. 
+Fair value measurements of all financial assets and liabilities that are being measured and reported on a fair value basis are required to be classified and disclosed in
+one of the following three categories: 
+Level 1: 
+Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities; 
+Level 2: 
+Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or
+liability; and 
+Level 3: 
+Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no
+market activity). 
+(d) Cash
+and Cash Equivalents: 
+Cash and cash equivalents are defined as short-term, highly liquid investments with original maturities of three months or less at date of purchase. 
+As of December 31, 2020, the Company was contractually obligated to maintain a restricted cash balance of $ 1 million on deposit with a bank as security for the bank’s issuance of a guarantee on behalf of the Company for its performance under purchase orders from which the Company received advance
+payments by a customer. The Company has fully performed under the purchase order as of December 31, 2021. 
+(e) Concentrations
+of Credit Risk: 
+Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of cash and trade receivables. The Company places its
+cash with well-known financial institutions and, at times, may maintain balances in excess of the FDIC insurance limit. 
+(f) Inventory: 
+Inventories are stated at the lower of cost or net realizable value with cost being determined using a standard cost method, which approximates average cost. Average
+cost consists primarily of material, labor and manufacturing overhead expenses (including fixed production-overhead costs). The Company analyzes its inventory levels quarterly and writes down, in the applicable period, inventory that has become
+obsolete, inventory that has a cost basis in excess of its expected net realizable value and inventory in excess of expected customer demand. 
+F-10 
+Table of Contents 
+(g) Fixed
+Assets: 
+Fixed assets are stated at cost, less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the
+respective assets, which range from three to seven years . Leasehold improvements are amortized over the useful life of the asset or the lease term, whichever is shorter. Deposits paid for fixed assets are capitalized and not depreciated until the related asset is placed in
+service. 
+( h ) Valuation of Long-Lived Assets and Intangible Assets: 
+Long-lived assets to be held and used are analyzed for impairment whenever events or changes in circumstances indicate that the related carrying amounts may not be
+recoverable. The Company evaluates at each balance sheet date whether events and circumstances have occurred that indicate possible impairment. If there are indications of impairment, the Company uses future undiscounted cash flows of the related
+asset or asset grouping over the remaining life in measuring whether the assets are recoverable. In the event such cash flows are not expected to be sufficient to recover the recorded asset values, the assets are written down to their estimated fair
+value. A $ 3.3 and $ 0 million
+impairment of long-lived intangible assets was recorded for the years ended December 31, 2021 and 2020 (see Note 14 - Asset Impairment, Restructuring, Severance and related costs). 
+( i ) Revenue Recognition: 
+The Company recognizes revenue when the customer obtains control of promised goods or services, in an amount that reflects the consideration the Company expects to
+receive in exchange for those goods or services. The Company recognizes revenue following the five-step model prescribed under Accounting Standards Update (“ASU”) 2014-09: (i) identify contract(s) with a customer; (ii) identify the performance
+obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and (v) recognize revenue when (or as) the Company satisfies the performance obligation. 
+Product Revenue 
+Revenue from product sales are recognized and commissions are accrued when the customer obtains control of the Company’s product, which occurs at a point in time,
+typically upon tendering the product to the customer. The Company expenses incremental costs of obtaining a contract as and when incurred because the expected amortization period of the asset that it would have recognized is one year or less or the amount is immaterial. Freight and distribution activities on products are performed when the customer obtains control of the
+goods. The Company has made an accounting policy election to account for shipping and handling activities that occur either when or after goods are tendered to the customer as a fulfillment activity, and therefore recognizes freight and distribution
+expenses in cost of product sales. The Company excludes certain taxes from the transaction price (e.g., sales, value added and some excise taxes). 
+The Company’s contracts with customers often include promises to transfer products or services to a customer. Determining whether products and services are considered
+distinct performance obligations that should be accounted for separately versus together may require judgment. Typical products sold are diagnostic tests and typical services performed are R&D studies. Revenues from product sales are recognized
+at a point-in-time and revenues from R&D studies are recognized ratably over the period of the agreement, unless the related performance obligations indicate otherwise. 
+Judgment is required to determine the stand-alone selling price (“SSP”) for each distinct performance obligation. SSP is directly observable and the Company can use a
+range of amounts to estimate SSP, as it sells products and services separately, and can determine whether there is a discount to be allocated based on the relative SSP of the various products and services, for the various geographies. 
+F-11 
+Table of Contents 
+From time to time the Company engages in bill-and-hold arrangements, whereby the Company manufactures and sells its product and at the customer’s request stores the product at the Company’s
+warehouse. Even though the product remains in the Company’s possession, a sale is recognized at the point in time when the customer obtains control of the product. Control is transferred to the customer in bill and hold transactions when:
+customer acceptance specifications have been met, legal title has transferred, the customer has a present obligation to pay for the product and the risk and rewards of ownership have transferred to the customer. Additionally, all the following
+bill and hold criteria would have to be met in order for control to be transferred to the customer: 
+(a) 
+The reason for the bill-and-hold arrangement must be substantive (for example, the customer has requested the arrangement). 
+(b) 
+The product must be identified separately as belonging to the customer. 
+(c) 
+The product currently must be ready for physical transfer to the customer. 
+(d) 
+The entity cannot have the ability to use the product or to direct it to another customer. 
+The Company’s payment terms vary by the type and location of the Company’s customer and products or services offered. Payment terms differ by jurisdiction and customer,
+but payment is generally required in a term ranging from 30 to 60 days from date of shipment or satisfaction of the performance obligation. 
+Reserves for Discounts and Allowances 
+Revenue from product sales are recorded net of reserves established for applicable discounts and allowances that are offered within contracts with the Company’s
+customers. 
+Product revenue reserves, which are classified as a reduction in product revenue, are generally related to discounts and returns. Estimates of variable consideration and
+the determination of whether to include estimated amounts in the transaction price are based on all information (historical, current, and forecasted) that is reasonably available to the Company, taking into consideration the type of customer, the
+type of transaction, market events and trends, and the specific facts and circumstances of each arrangement. The transaction price, which includes variable consideration reflecting the impact of discounts, allowances and returns may be subject to
+constraint and is included in the net sales price only to the extent that it is probable that a significant reversal of the amount of the revenue recognized will not occur in a future period. Actual amounts may ultimately differ from the Company’s
+estimates. If actual results vary, the Company adjusts these estimates, which could have an effect on revenue and earnings in the period of adjustment. 
+License and Royalty Revenues 
+The Company receives royalty revenue on sales by its licensee of products covered under patents that the Company owns. The Company does not have future performance
+obligations under this license arrangement. The Company records revenue based on estimates of the sales that occurred during the relevant period as a component of license and royalty revenue. The relevant period estimates of sales are based on
+interim data provided by the licensee and analysis of historical royalties that have been paid to the Company, adjusted for any changes in facts and circumstances, as appropriate. Differences between actual and estimated royalty revenue are adjusted
+for in the period in which they become known, typically the following quarter. Historically, adjustments have not been material when compared to actual amounts paid by licensees. 
+R&D Revenue 
+All contracts with customers are evaluated under the five-step model described above. Such contracts are further described in Note 7 - Revenue. Grants are invoiced and
+revenue is recognized ratably as that is the depiction of the timing of the transfer of services. The R&D study, which encompasses various phases of product development processes: design feasibility & planning, product development and design
+optimization, design verification, design validation and process validation, and pivotal studies, is also recognized ratably. 
+For certain contracts that represent non-governmental grants where the funder does not meet the definition of a customer, the Company recognizes revenue when earned in
+accordance with Accounting Standards Codification (“ASC”) Topic 958. 
+F-12 
+Table of Contents 
+Government Grant Income 
+Chembio receives government grants in support of R&D activities that are not associated with a customer-vendor relationship and therefore falls outside the scope of
+ASC 606. Because there is no authoritative guidance under U.S. GAAP on accounting for government grants received, Chembio applies Topic 958 - Not-for-profit entities guidance by analogy. In June 2018, the Financial Accounting Standards Board (the
+“FASB”) issued ASU 2018-08, Not-for-Profit Entities (Topic 958): Clarifying the Scope and the Accounting Guidance for Contributions Received and Contributions Made. This ASU clarifies the guidance presented in ASC Topic 958, “Not-for-Profit
+Entities,” for evaluating whether a transaction is reciprocal (i.e., an exchange transaction) or non reciprocal (i.e., a contribution) and for distinguishing between conditional and unconditional contributions. The ASU also clarified the guidance
+used by entities other than not-for-profits to identify and account for contributions made. Government grants are invoiced and revenue is recognized as milestones are achieved, conditions are removed and approval from grantor is obtained. 
+In July 2020, the Company
+was awarded a grant of $ 0.6 million from BARDA to develop a SARS-CoV-2 Ag System. The Company earned $ 0.2 and $ 0.4 million for the years ended
+December 31, 2021 and 2020, respectively, and was recorded as government grant income. 
+In December 2020, the Company was awarded a grant of $ 12.7 
+million from BARDA to support the development and pursuit of FDA EUA for a rapid, multiplex DPP Respiratory Antigen Panel point-of-care test system. The Company earned $ 10.9 and $ 1.6 million for the years ended December 31, 2021 and 2020,
+respectively, and was recorded as government grant income. Culmulative through December 31, 2021, the Company recognized $ 12.5 million
+under this agreement, and the remainder $ 0.2 million is subject to obtaining the EUA for the DPP SARs-COV-2 Antigen test.
+Contract Liabilities 
+Deferred revenue relates to payments received in advance of performance under the contract. Deferred revenue is recognized as revenue as (or when) the Company performs under the contract. At December 31, 2020, the Company reported $ 1.6 million in deferred revenue of which $ 1.6 
+million was earned and recognized as product sales during the year ended December 31, 2021. At December 31, 2021, the Company reported $ 0 
+in deferred revenue. 
+( j ) Loss Per Share: 
+Basic loss per share is computed by dividing net loss by the weighted average number of common stock shares outstanding during the period. Diluted net loss per share is
+computed using the treasury stock method if the additional shares are dilutive. For all periods presented, basic and diluted net loss per share are the same as any additional shares would be anti-dilutive. 
+There were 705,325 and 603,531 restricted shares awards outstanding as of December 31, 2021 and 2020, respectively, that were not included in the calculation of diluted income
+per share for the year ended December 31, 2021 and 2020, because their effect would have been anti-dilutive. There were 1,600,372 and 974,778 options outstanding as of December 31, 2021 and 2020 respectively, that were not included in the calculation of diluted income per share for the
+twelve months ended December 31, 2021 and 2020, respectively, because their effect would have been anti-dilutive. 
+(k) Research
+and Development: 
+Research and Development (R&D) include product development, program management, clinical trials and regulatory costs and are expensed when incurred. Advance payments
+for goods and services that will be used in future research and development activities are expensed when the activity has been performed or when the goods have been received rather than when the payment is made. 
+(l) Stock-Based
+Compensation: 
+The Company grants share options to employees and non-employee members of the Company’s board of directors as compensation for services performed. Employee and
+non-employee members of the board of directors’ awards of share-based compensation are accounted for in accordance with ASC 718, Compensation - Stock Compensation, or ASC 718. ASC 718 requires all share-based payments to employees and non-employee
+directors, including grants of share options, to be recognized in the consolidated statement of operations and comprehensive loss based on their grant date fair values. 
+F-13 
+Table of Contents 
+The grant date fair value of share options is estimated using the Black-Scholes option valuation model. The fair value of restricted stock and performance/restricted
+stock unit awards are determined on the date of grant or the date of issuance, as applicable. 
+The grant date fair value is calculated based on assumptions with respect to (i) the fair value of the Company’s common stock on the grant date; (ii) expected volatility
+of the Company’s common stock price, (iii) the periods of time over which the optionees are expected to hold their options prior to exercise (expected term), (iv) expected dividend yield on the Company’s common stock, and (v) risk-free interest
+rates. 
+The expected volatility is calculated based on historical data of the Company's common stock. The expected dividend yield is zero as the Company has never paid dividends
+and does not currently anticipate paying any in the foreseeable future. Risk-free interest rates are based on quoted U.S. Treasury rates for securities with maturities approximating the option’s expected term. The expected term of share options
+granted to the optionees is determined using the average of the vesting period and contractual life of the option. 
+Stock based compensation is generally recognized on a straight-line basis over the service period of the grant and is reduced for actual forfeitures in the period in
+which the forfeiture occurs. 
+(m) Income
+Taxes: 
+The Company accounts for income taxes under an asset and liability approach that recognizes deferred tax assets and liabilities based on the difference between the
+financial statement carrying amounts and the tax bases of assets and liabilities using enacted tax rates in effect in the years in which the differences are expected to reverse. 
+The Company follows a more-likely-than-not threshold for financial statement recognition and measurement of a tax position taken, or expected to be taken, in a tax
+return. The guidance relates to, among other things, classification, accounting for interest and penalties associated with tax positions, and disclosure requirements. Any interest and penalties accrued related to uncertain tax positions are recorded
+in tax expense. 
+The Company assesses the realizability of its net deferred tax assets on an annual basis. If, after considering all relevant positive and negative evidence, it is more
+likely than not that some portion or all of the net deferred tax assets will not be realized, the Company will reduce the net deferred tax assets by a valuation allowance. The realization of net deferred tax assets is dependent on several factors,
+including the generation of sufficient taxable income prior to the expiration of net operating loss carryforwards. 
+( n ) Goodwill 
+Goodwill represents the excess of the purchase price the Company paid over the fair value of the net tangible and identifiable intangible assets acquired in the
+Company’s acquisition. Goodwill is not amortized but rather is tested annually as of the first day of the fiscal fourth quarter, or sooner if the Company believes that indicators of impairment exist. The Company makes a qualitative evaluation about
+the likelihood of goodwill impairment, which is based on a number of applicable factors. If the Company concludes that it is more likely than not that the carrying value of the applicable reporting unit is greater than its fair value, then it would
+recognize an impairment charge for the amount by which the carrying value exceeds the reporting unit’s fair value, provided the impairment charge does not exceed the total amount of goodwill allocated to the reporting unit. 
+The quantitative goodwill impairment test is performed using a one-step process. The process is to compare the fair value of a reporting unit with its carrying amount.
+If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not impaired. If the carrying amount of a reporting unit exceeds its fair value, goodwill of the reporting unit is impaired and an impairment loss is
+recognized in an amount equal to that excess. 
+The company operates as a single operating segment and
+has one reporting unit. During the year ended December 31, 2021, the Company performed a quantitative analysis and determined that the
+carrying value exceeded its fair value by $ 2.6 million, on December 31, 2021 and recorded an impairment charge. 
+F-14 
+Table of Contents 
+( o ) Allowance for Doubtful Accounts: 
+The Company records allowances for doubtful accounts for the estimated probable losses on uncollectible accounts receivable. The allowance is based upon the credit
+worthiness of the Company’s customers, the Company’s historical experience, the age of the receivable and current market and economic conditions. Receivables are written off against these allowances in the period they are determined to be
+uncollectible. 
+( p ) Acquisition Costs: 
+Acquisition costs are expensed when incurred and include primarily professional services, related to acquisition activities. 
+( q ) Foreign Currency Translation: 
+The functional currency of a foreign subsidiary is the local currency. Assets and liabilities of foreign subsidiaries that use a currency other than U.S. dollars as
+their functional currency are translated to U.S. dollars at end of period currency exchange rates. The consolidated statements of operations of foreign subsidiaries are translated to U.S. dollars at average period currency exchange rates. The effect
+of translation for foreign subsidiaries is generally reported in other comprehensive income. 
+(r ) Leases: 
+The Company accounts for leases in accordance with ASC 842. The Company determines if an arrangement is a lease at contract inception. A lease exists when a contract
+conveys the right to control the use of identified property, plant, or equipment for a period of time in exchange for consideration. The definition of a lease embodies two conditions: (1) there is an identified asset in the contract that is land or a
+depreciable asset (i.e., property, plant, and equipment), and (2) the Company has the right to control the use of the identified asset. The Company accounts for the lease and non-lease components as a single lease component. 
+From time to time the Company enters into direct financing lease arrangements that include a lessee obligation to purchase the leased asset at the end of the lease term,
+a bargain purchase option, or provides for minimum lease payments with a present value of 90 % or more of the fair value of the leased
+asset at the date of lease inception. 
+Operating leases where the Company is the lessee are included in right-of-use (“ROU”) assets and lease obligations are included on the Company’s consolidated balance
+sheets. The lease obligations are initially and subsequently measured at the present value of the unpaid lease payments at the lease commencement date and subsequent reporting periods. 
+Finance leases where the Company is the lessee are included in ROU assets and lease obligations on the Company’s consolidated balance sheets. The lease obligations are
+initially measured in the same manner as for operating leases and are subsequently measured at amortized cost using the effective interest method. 
+Key estimates and judgments include how the Company determined (1) the discount rate used to discount the unpaid lease payments to present value, (2) lease term and (3)
+lease payments. ASC 842 requires a lessee to discount its unpaid lease payments using the interest rate implicit in the lease or, if that rate cannot be readily determined, its incremental borrowing rate. As most of the Company’s leases where it is
+the lessee do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company’s incremental borrowing rate for a
+lease is the rate of interest it would have to pay on a collateralized basis to borrow an amount equal to the lease payments under similar terms. The Company uses the implicit rate when readily determinable. 
+F-15 
+Table of Contents 
+The lease term for all of the Company’s leases includes the noncancelable period of the lease plus any additional periods covered by either a lessee option to extend (or
+not to terminate) the lease that is reasonably certain to be exercised, or an option to extend (or not to terminate) the lease controlled by the lessor. 
+The ROU asset is initially measured at cost, which comprises the initial amount of the lease liability adjusted for lease payments made at or before the lease
+commencement date less any lease incentives received. For operating leases, the ROU asset is subsequently measured throughout the lease term at the carrying amount of the lease liability, minus any accrued lease payments, less the unamortized balance
+of lease incentives received. Lease expense for lease payments is recognized on a straight-line basis over the lease term. 
+For finance leases, the ROU asset is subsequently amortized using the straight-line method from the lease commencement date to the earlier of the end of its useful life
+or the end of the lease term unless the lease transfers ownership of the underlying asset, or the Company is reasonably certain to exercise an option to purchase the underlying asset. In those cases, the ROU asset is amortized over the useful life of
+the underlying asset. Amortization of the ROU asset is recognized and presented separately from interest expense on the lease liability. 
+The Company has elected not to recognize ROU assets and lease liabilities for all short-term leases that have a lease term of 12 months or less at lease commencement. Lease payments associated with short-term leases are recognized as an expense on a straight-line basis over the lease term. 
+Impairment charges for the Malaysian facility right-of-use asset recorded during the years ended December 31, 2021 was $ 0.1 and $ 0 million, respectively (see Note 14 - Asset Impairment,
+Restructuring, Severance and related costs). 
+(s) Recent
+Accounting Pronouncements Affecting the Company: 
+Recently Adopted 
+ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes 
+In December 2019, the FASB issued ASU 2019-12. This standard simplifies the accounting for income
+taxes by eliminating certain exceptions to the guidance in Topic 740 related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside
+basis differences. The new guidance also simplifies aspects of the accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of goodwill and
+allocating consolidated income taxes to separate financial statements of entities not subject to income tax. ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, with early adoption permitted. Upon adoption, the Company must
+apply certain aspects of this standard retrospectively for all periods presented while other aspects are applied on a modified retrospective basis through a cumulative-effect adjustment to retained earnings as of the beginning of the fiscal year of
+adoption. The Company adopted the standard effective January 1, 2021 and has determined that the adoption did not have a material impact on the Company’s consolidated financial statements. 
+ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting 
+In March 2020, the FASB issued ASC Topic 848. ASC Topic 848 provides relief for impacted areas as it relates to impending reference rate reform. ASC Topic 848 contains
+optional expedients and exceptions for applying GAAP to debt arrangements, contracts, hedging relationships, and other areas or transactions that are impacted by reference rate reform. This guidance is effective upon issuance for all entities and
+elections of certain optional expedients are required to apply the provisions of the guidance. The Company adopted the standard effective January 1, 2021 and has determined that the adoption did not have a material impact on the Company’s
+consolidated financial statements. 
+F-16 
+Table of Contents 
+Not Yet Adopted 
+ASU 2021-10 - Government Assistance (Topic 832): Disclosures by Business Entities about Government Assistance 
+In November 2021, the FASB issued ASU 2021-10, Government Assistance (Topic 832): Disclosures by Business Entities about Government Assistance, which aims to provide
+increased transparency by requiring business entities to disclose information about certain types of government assistance they receive in the notes to the financial statements. The disclosure requirements in ASC 832 only apply to transactions with a
+government that are accounted for by analogizing to either a grant model (for example, in International Accounting Standard (IAS) 20, Accounting for Government Grants and Disclosure of Government Assistance), or a contribution model (for example, in
+ASC 958-605, Not-for-Profit Entities – Revenue Recognition). The FASB broadly defined “government assistance” in ASC 832 to ensure that assistance received from most types of governmental entities or other related organizations would be disclosed. 
+Entities are required to provide the new disclosures prospectively for all transactions with a government entity that are accounted for under either a grant or a contribution accounting model and are reflected in the financial statements at the date
+of initially applying the new amendments, and to new transactions entered into after that date. Retrospective application of the guidance is permitted. The guidance in ASU 2021-10 is effective for financial statements of all entities, for annual
+periods beginning after December 15, 2021, with early application permitted. The Company continues to assess all potential impact of the standard and will disclose the nature and reason for any elections that the Company makes. 
+ASU 2020-06 - Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging—Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting
+for Convertible Instruments and Contracts in an Entity’s Own Equity 
+20 
+On August 5, 2020, the FASB issued ASU 2020-06, which simplifies the accounting for certain financial instruments with characteristics of liabilities and equity,
+including convertible instruments and contracts on an entity’s own equity. The ASU is part of the FASB’s simplification initiative, which aims to reduce unnecessary complexity in U.S. GAAP. ASU 2020-06 simplifies the guidance in U.S. GAAP on the
+issuer’s accounting for convertible debt instruments, requires entities to provide expanded disclosures about “the terms and features of convertible instruments” and how the instruments have been reported in the entity’s financial statements. It also
+removes from ASC 815-40-25-10 certain conditions for equity classification and amends certain guidance in ASC 260 on the computation of EPS for convertible instruments and contracts on an entity’s own equity. An entity can use either a full or
+modified retrospective approach to adopt the ASU’s guidance. The ASU’s amendments are effective for smaller public business entities fiscal years beginning after December 15, 2023. The Company continues to assess the potential impact of the standard
+and will disclose the nature and reason for any elections that the Company makes. 
+ASU 2021-08—Business Combinations (Topic 805): Accounting for Contract Assets and Contract Liabilities from Contracts with Customers 
+On October 28, 2021, the FASB issued ASU 2021-08,1 which amends ASC 805 to “require acquiring entities to apply Topic 606 to recognize and measure contract assets and
+contract liabilities in a business combination.” Under current GAAP, an acquirer generally recognizes such items at fair value on the acquisition date. ASU 2021-08 amends ASC 805 to add contract assets and contract liabilities to the list of
+exceptions to the recognition and measurement principles that apply to business combinations and to “require that an entity (acquirer) recognize and measure contract assets and contract liabilities acquired in a business combination in accordance
+with Topic 606.” While primarily related to contract assets and contract liabilities that were accounted for by the acquiree in accordance with ASC 606, “the amendments also apply to contract assets and contract liabilities from other contracts to
+which the provisions of Topic 606 apply, such as contract liabilities from the sale of nonfinancial assets within the scope of Subtopic 610-20.” The ASU’s amendments are effective for public business entities for the fiscal years beginning after
+December 15, 2022, including interim periods within those fiscal years. The amendments should be applied prospectively to business combinations occurring on or after the effective date of the amendments. The Company continues to assess the potential
+impact of the standard and will disclose the nature and reason for any elections that the Company makes. 
+NOTE 3 — INVENTORIES: 
+Net inventories consist of the following at December 31: 
+December 31 
+2021 
+2020 
+Raw Materials 
+$ 
+7,306,095 
+$ 
+5,955,215 
+Work in Process 
+3,556,878 
+2,549,516 
+Finished Goods 
+2,057,478 
+4,011,671 
+$ 
+12,920,451 
+$ 
+12,516,402 
+During the year ended December 31, 2021, the Company recognized inventory adjustments related to expired and obsolete items totaling $ 4.1 million. 
+F-17 
+Table of Contents 
+NOTE 4 — FIXED ASSETS: 
+Fixed assets consist of the following at December 31: 
+December 31 
+2021 
+2020 
+Machinery and Equipment 
+$ 
+12,500,235 
+$ 
+10,996,869 
+Furniture and Fixtures 
+6,631 
+25,418 
+Computer Equipment 
+465,576 
+446,300 
+Leasehold Improvements 
+2,933,159 
+3,158,074 
+Enterprise Business Systems 
+2,953,221 
+2,741,806 
+Subtotal: 
+18,858,822 
+17,368,467 
+Less: Accumulated Depreciation and Amortization 
+( 10,302,049 
+) 
+( 8,680,064 
+) 
+$ 
+8,556,773 
+$ 
+8,688,403 
+Depreciation expense for the 2021 and 2020 years totaled $ 1,801,481 
+and $ 1,227,860 , respectively. 
+Effective May 2021, the Company discontinued its operations in Malaysia. Impairment charges recorded for the Malaysian fixed assets, net for the year ended December 31,
+2021 and 2020 were $ 0.1 and $ 0 
+millions, respectively. 
+As of December 31, 2021 and 2020, the Company has purchased manufacturing equipment that is not yet in use and therefore has not been depreciated, aggregating $ 1,970,652 and $ 3,011,273 , respectively.
+These balances are reflected under the Machinery and Equipment line on the table above. 
+NOTE 5 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES: 
+Accounts payable and accrued liabilities consist of the following at December 31: 
+December 31 
+2021 
+2020 
+Accounts Payable - suppliers 
+$ 
+7,745,592 
+$ 
+5,727,781 
+Accrued Commissions & Royalties 
+1,359,691 
+807,708 
+Accrued Payroll 
+494,258 
+277,908 
+Accrued Vacation 
+421,416 
+417,238 
+Accrued Bonuses 
+1,378,706 
+1,193,985 
+Accrued Professional Fees 
+522,935 
+511,681 
+Accrued Expenses - Other 
+1,205,395 
+1,106,489 
+$ 
+13,127,993 
+$ 
+10,042,790 
+F-18 
+Table of Contents 
+NOTE 6 — REVENUE: 
+Disaggregation of Revenue 
+Exchange transactions are recognized in accordance with ASC Topic 606, Revenue from Contracts with Customers, while non-exchange transactions are recognized in
+accordance with ASU 2018-08, Not-For-Profit Entities (Topic 958): Clarifying the Scope and Accounting Guidance for Contributions Received and Contributions Made. 
+The following tables disaggregates total revenues for the period ending December 31, 2021: 
+Exchange 
+Transactions 
+Non-Exchange 
+Transactions 
+Total 
+Net product revenue 
+$ 
+34,737,444 
+$ 
+- 
+$ 
+34,737,444 
+R&D revenue 
+1,159,381 
+- 
+1,159,381 
+Government grant income 
+- 
+10,891,726 
+10,891,726 
+License and royalty revenue 
+1,029,901 
+- 
+1,029,901 
+$ 
+36,926,726 
+$ 
+10,891,726 
+$ 
+47,818,452 
+The following tables disaggregates total revenues for the period ending December 31, 2021 by region: 
+Total 
+Africa 
+$ 
+5,562,788 
+Asia 
+664,579 
+Europe & Middle East 
+5,179,267 
+Latin America 
+18,418,983 
+United States 
+17,992,835 
+$ 
+47,818,452 
+The following tables disaggregates total revenues for the period ending December 31, 2020: 
+Exchange 
+Transactions 
+Non-Exchange 
+Transactions 
+Total 
+Net product revenue 
+$ 
+24,767,149 
+$ 
+- 
+$ 
+24,767,149 
+R&D revenue 
+4,851,562 
+- 
+4,851,562 
+Government grant income 
+- 
+2,018,924 
+2,018,924 
+License and royalty revenue 
+832,562 
+- 
+832,562 
+$ 
+30,451,273 
+$ 
+2,018,924 
+$ 
+32,470,197 
+The following tables disaggregates total revenues for the period ending December 31, 2020 by region: 
+Total 
+Africa 
+$ 
+4,890,370 
+Asia 
+824,488 
+Europe & Middle East 
+9,905,437 
+Latin America 
+9,841,773 
+United States 
+7,008,129 
+$ 
+32,470,197 
+Deferred Revenue 
+From time to time the Company may receive prepayment from customers for products to be manufactured and shipped at future dates. Customer payments in advance of the
+applicable performance obligation are deferred and recognized in accordance with ASC 606. 
+As of December 31, 2021 and 2020, there were $ 0 and $ 1,606,997 unearned advanced revenues, respectively. 
+F-19 
+Table of Contents 
+NOTE 7 — INCOME TAXES: 
+The components of loss before income taxes consisted of the following: 
+Year Ending December 31, 
+2021 
+2020 
+United States operations 
+$ 
+( 26,858,325 
+) 
+$ 
+( 23,384,133 
+) 
+International operations 
+( 7,107,254 
+) 
+( 2,593,989 
+) 
+(Loss) before taxes 
+$ 
+( 33,965,579 
+) 
+$ 
+( 25,978,122 
+) 
+The (benefit from) provision for income taxes for the years ended December 31, 2021 and 2020 is comprised
+of the following: 
+Year Ending December 31, 
+2021 
+2020 
+Current 
+Federal 
+$ 
+- 
+$ 
+( 66,906 
+) 
+State 
+7,891 
+6,497 
+Foreign 
+- 
+- 
+Total current (benefit) provision 
+7,891 
+( 60,409 
+) 
+Deferred 
+Federal 
+- 
+- 
+State 
+- 
+- 
+Foreign 
+( 69,941 
+) 
+( 396,385 
+) 
+Total deferred (benefit) provision 
+( 69,941 
+) 
+( 396,385 
+) 
+Total (benefit) provision 
+$ 
+( 62,050 
+) 
+$ 
+( 456,794 
+) 
+A reconciliation of the Federal statutory rate to the effective rate applicable to loss before income taxes is as follows: 
+Year Ending December 31, 
+2021 
+2020 
+Federal income tax at statutory rates 
+21.00 
+% 
+21.00 
+% 
+State income taxes, net of federal benefit 
+0.18 
+% 
+( 0.02 
+)% 
+Nondeductible expenses 
+( 2.04 
+)% 
+( 0.19 
+)% 
+Foreign rate differential 
+0.32 
+% 
+0.47 
+% 
+Change in valuation allowance 
+( 19.60 
+)% 
+( 19.37 
+)% 
+Other 
+0.32 
+% 
+( 0.13 
+)% 
+Income tax benefit 
+0.18 
+% 
+1.76 
+% 
+The Company had an ownership change as described in Internal Revenue Code Sec. 382 during 2004 (“2004 change”). As a result, the Company’s net operating losses prior to
+the 2004 change of $ 5,832,516 were subject to an annual limitation of $ 150,608 and for the first five (5) years are entitled to a BIG (Built-In-Gains) of $ 488,207 
+per year. These net operating losses expire in 2022 through 2024. 
+The Company had a second ownership change during 2006 (“2006 change”). The net operating losses incurred between the 2004 change and the 2006 change of $ 8,586,861 were subject to an annual limitation of $ 1,111,831 
+and for the first five (5) years are entitled to a BIG of $ 1,756,842 per year. These net operating losses expire in 2024 through 2026. 
+F-20 
+Table of Contents 
+After applying the above limitations, at December 31, 2019, the Company has post-change net operating loss
+carry-forwards of approximately $ 26,362,574 which expire between
+2022 and 2037 and $ 59,787,076 which do not expire. In addition the
+Company has research and development tax credit carryforwards of approximately $ 1,651,529 for the year ended December 31, 2021 , which expire between 2022 and 2036. 
+The Company has state net operating loss carryforwards of approximately $ 4,458,041 
+which generally expire between 2035 and 2040. The Company has foreign net operating loss carryforwards of approximately $ 7,666,504 which
+generally expire between 2025 and 2029. 
+Deferred tax assets and liabilities as of December 31 are as follows: 
+Year Ending December 31, 
+2021 
+2020 
+Inventory reserves 
+$ 
+333,551 
+$ 
+461,709 
+Accrued expenses 
+374,673 
+130,291 
+Net operating loss carry-forwards 
+20,401,828 
+14,844,798 
+Research and development credit 
+1,651,529 
+1,696,870 
+Stock-based compensation 
+259,106 
+398,900 
+Interest Expense 
+1,221,171 
+602,187 
+Lease obligations 
+1,504,433 
+1,583,814 
+Intangibles 
+137,142 
+- 
+Total deferred tax assets 
+25,883,433 
+19,718,569 
+Right-of-use assets 
+( 1,294,519 
+) 
+( 1,340,914 
+) 
+Depreciation 
+( 560,754 
+) 
+( 254,366 
+) 
+Intangibles 
+- 
+( 821,363 
+) 
+Total deferred tax liabilities 
+( 1,855,273 
+) 
+( 2,416,643 
+) 
+Net deferred tax assets before valuation allowance 
+24,028,160 
+17,301,926 
+Less valuation allowances 
+( 24,028,160 
+) 
+( 17,371,867 
+) 
+Net noncurrent deferred tax liabilities 
+$ 
+- 
+$ 
+( 69,941 
+) 
+The Company does not provide for U.S. income taxes on unremitted earnings of foreign subsidiaries as its present intention is to reinvest the unremitted earnings in the
+Company’s foreign operations. At December 31, 2021 there were no unremitted earnings of foreign subsidiaries. 
+Interest and penalties, if any, related to income tax liabilities are included in income tax expense. As of December 31, 2021, the
+Company does not have any uncertain tax positions. 
+On March 27, 2020, the Coronavirus Aid, Relief, and Economic Security Act, (“CARES Act”), was enacted in response to the COVID-19 pandemic. The CARES Act, among other
+things, permits NOL carryovers and carrybacks to offset 100% of taxable income for taxable years beginning before 2021. In addition, the CARES Act allows NOLs incurred in tax years 2018, 2019, and 2020 to be carried back to each of the five preceding
+taxable years. In addition to the NOL changes, the CARES Act contains modifications on the limitation of business interest for tax years beginning in 2019 and 2020. The modifications to Section 163(j) increase the allowable business interest
+deduction from 30% of adjusted taxable income to 50% of adjusted taxable income. This modification did not effect the Company’s interest expense limitation. Overall the CARES ACT did not have a significant impact on the Company since it maintains a
+full valuation allowance. 
+F-21 
+Table of Contents 
+NOTE 8 — GOODWILL AND INTANGIBLE ASSETS: 
+Following is a table that reflects changes in Goodwill: 
+Beginning balance January 1, 2021 
+$ 
+5,963,744 
+Changes in foreign currency exchange rate 
+( 373,204 
+) 
+Impairment 
+( 2,567,753 
+) 
+Balance at December 31, 2021 
+$ 
+3,022,787 
+Intangible assets consist of the following at: 
+December 31,2021 
+December 31, 2020 
+Weighted Average 
+Remaining Life 
+Cost 
+Accumulated 
+Amortization 
+Impairment 
+Net Book Value 
+Cost 
+Accumulated 
+Amortization 
+Net 
+Book Value 
+Intellectual property 
+- 
+$ 
+1,636,724 
+$ 
+546,252 
+$ 
+1,090,472 
+$ 
+- 
+$ 
+1,638,699 
+$ 
+472,190 
+$ 
+1,166,509 
+Developed technology 
+- 
+1,944,500 
+828,681 
+1,115,819 
+- 
+2,102,526 
+594,186 
+1,508,340 
+Customer contracts/relationships 
+- 
+1,254,344 
+477,661 
+776,683 
+- 
+1,323,424 
+423,093 
+900,331 
+Trade names 
+- 
+110,853 
+43,696 
+67,157 
+- 
+115,318 
+44,512 
+70,806 
+$ 
+4,946,421 
+$ 
+1,896,290 
+$ 
+3,050,131 
+$ 
+- 
+$ 
+5,179,967 
+$ 
+1,533,981 
+$ 
+3,645,986 
+Intellectual property, developed technology, customer contracts/relationships and trade names were being amortized over 10 , 7 , 10 and 11 years, respectively. Amortization expense for the year ended December
+31, 2021 and 2020 was $ 479,988 and $ 588,962 ,
+respectively. 
+As of December 31, 2021, the Company determined indicators of impairment existed. As a result, the Company recognized an impairment loss of its finite-lived intangible
+assets totaling $ 3.1 million (Intellectual Property $ 1.1 million, Developed Technology $ 1.1 million, Customer Contracts $ 0.8 
+million and Trademark $ 0.1 million ). 
+NOTE 9 — STOCKHOLDERS’ EQUITY: 
+(a) 
+Common Stock 
+In April 2020, the Company closed on an underwritten public offering of 2,619,593 
+shares of its common stock, including the underwriter’s exercise of its overallotment of 281,125 shares, at $ 11.75 per share. The net proceeds of the offering, after deducting the underwriter’s discounts and other offering expenses payable by the Company, was
+approximately $ 28.4 million. 
+On July 19, 2021, Chembio entered into an At the Market Offering Agreement (the “ATM Agreement”) with Craig‑Hallum Capital Group LLC (“Craig‑Hallum”), pursuant to which
+Chembio may sell from time to time, at its option, up to an aggregate of $ 60,000,000 of shares of common stock through Craig‑Hallum, as
+sales agent. During the year ended December 31, 2021, Chembio issued and sold pursuant to the ATM Agreement a total of 9,709,328 shares of
+common stock at a volume-weighted average price of $ 4.20 per share for gross proceeds of $ 40.8 million and net proceeds, after giving effect to placement fees and other transaction costs, of $ 38.8 million. Additional shares of common stock may be issued and sold pursuant to the ATM Agreement for gross proceeds of up to $ 19.2 million. 
+(b) 
+Preferred Stock 
+The Company has 10,000,000 shares of preferred stock
+authorized and none outstanding. These shares can become issuable upon an approved resolution by the board of directors and the filing of
+a Certificate of Designation with the state of Nevada. 
+(c) 
+Options, Restricted Stock, and Restricted Stock Units 
+T he Board of Directors or its Compensation Committee may authorize the Company’s issuance of options,
+restricted stock, restricted stock units and other equity awards to officers, employees, directors, consultants and other service providers pursuant to the Company’s 2019 Omnibus Incentive Plan or otherwise . 
+F-22 
+Table of Contents 
+NOTE 10 — EQUITY INCENTIVE PLANS: 
+Effective June 3, 2008, Chembio’s stockholders voted to approve the 2008 Stock Incentive Plan (the “2008 Plan”), with 625,000 shares of common stock available to be issued. At the Annual Stockholder Meeting on September 22, 2011 Chembio’s stockholders voted to approve an increase to the shares
+of common stock issuable under the 2008 Plan by 125,000 to 750,000 . Under the terms of the 2008 Plan, which expired during 2018, the Board or its Compensation Committee had the discretion to select the persons to whom awards were to be granted. Awards
+could be stock options, restricted stock and/or restricted stock units (collectively, “Equity Award Units”). The awards became vested at such times and under such conditions as determined by the Board or its Compensation Committee. Cumulatively
+through December 31, 2021, there were 750,000 options expired, forfeited or exercised, and at December 31, 2021, 0 options were outstanding and no Equity
+Award Units were available to be issued under the 2008 Plan. 
+Effective June 19, 2014, Chembio’s stockholders voted to approve the 2014 Stock Incentive Plan (the “2014 Plan”), with 800,000 shares of common stock available to be issued. Under the terms of the 2014 Plan, the Board or its Compensation Committee has the discretion to select the persons to whom
+awards are to be granted. Awards can be in the form of Equity Award Units. The awards vest at such times and under such conditions as determined by the Board or its Compensation Committee. Cumulatively through December 31, 2021, there were 602,064 Equity Award Units expired, forfeited or exercised. At December 31, 2021, 176,875 Equity Award Units were outstanding and, 21,061 shares were not issued.
+All shares that expired, forfeited or were not issued rolled over into the 2019 Plan. No Equity Award Units remain available to be issued
+under the 2014 Plan. 
+Effective June 18, 2019, Chembio’s stockholders voted to approve the 2019 Omnibus Incentive Plan (the “2019 Plan”), with 2,400,000 shares of common stock available to be issued. At the Annual Stockholder Meeting on June 25, 2021, Chembio’s stockholders voted to approve an increase to the shares of
+common stock issuable under the SIP by 2,400,000 to 4,800,000 . In addition, shares of common stock underlying any outstanding award granted under the 2019 Plan that, following the effective date of the 2019 Plan, expire, or are terminated,
+surrendered or forfeited for any reason without issuance of such shares, shall be available for the grant of new awards under the 2019 Plan. Under the terms of the 2019 Plan, the Board or its Compensation Committee has the discretion to select the
+persons to whom awards are to be granted. Awards can be in the form of options, stock appreciation rights, restricted stock, restricted stock units, performance stock units or other stock-based awards under the 2019 Plan (collectively, “2019 Equity
+Units”). The 2019 Equity Units become vested at such times and under such conditions as determined by the Board or its Compensation Committee. Cumulatively through December 31, 2021, 790,538 2019 Equity Units have been cancelled or forfeited. At December 31, 2021, 1,973,096 
+2019 Equity Units were outstanding, and 3,386,393 2019 Equity Units were available to be awarded. 
+The Company’s results for the years ended December 31, 2021 and 2020 include stock-based compensation expense totaling $ 2,034,247 and $ 1,098,698 , respectively. Such amounts have been
+included in the Consolidated Statements of Operations within cost of product sales ($ 174,537 and $ 6,300 , respectively), research and development ($ 494,235 and $ 386,016 , respectively) and selling, general and administrative expenses ($ 1,365,475 and $ 706,382 , respectively). 
+The weighted-average assumptions made in calculating the fair values of options are as follows for the respective years ended December 31: 
+2021 
+2020 
+Expected term (in years) 
+5.10 
+6.29 
+Expected volatility 
+78.95 
+% 
+46.21 
+% 
+Expected dividend yield 
+0 
+0 
+Risk-free interest rate 
+0.85 
+% 
+1.30 
+% 
+F-23 
+Table of Contents 
+The following table provides stock option activity for the years ended December 31, 2021: 
+Number 
+of Shares 
+Weighted 
+Average 
+Exercise Price 
+per Share 
+Weighted 
+Average 
+Remaining 
+Contractual Term 
+Aggregate 
+Intrinsic 
+Value 
+Outstanding at December 31, 2020 
+974,778 
+$ 
+4.12 
+5.19 years 
+$ 
+1,520,910 
+Granted 
+1,006,541 
+$ 
+4.54 
+7.85 years 
+- 
+Exercised 
+36,252 
+$ 
+2.36 
+101,139 
+Forfeited 
+260,570 
+$ 
+4.32 
+- 
+Expired/cancelled 
+84,125 
+8.23 
+Outstanding at December 31, 2021 
+1,600,372 
+$ 
+4.18 
+6.59 years 
+$ 
+- 
+Exercisable at December 31, 2021 
+435,794 
+$ 
+4.38 
+2.71 years 
+$ 
+- 
+The following table summarizes information about stock options outstanding at December 31, 2021: 
+Stock Options Outstanding 
+Stock Options Exercisable 
+Range of 
+Exercise Prices 
+Shares 
+Outstanding 
+Average 
+Remaining 
+Contract Life 
+(Year) 
+Weighted 
+Average 
+Exercise 
+Price 
+Aggregate 
+Intrinsic 
+Value 
+Shares 
+Exercisable 
+Weighted 
+Average 
+Exercise 
+Price 
+Aggregate 
+Intrinsic 
+Value 
+1 to 2.79999 
+571,209 
+5.35 
+$ 
+2.36 
+$ 
+- 
+248,372 
+$ 
+2.36 
+$ 
+- 
+2.8 to 4.59999 
+29,410 
+9.43 
+3.05 
+- 
+- 
+- 
+- 
+4.6 to 6.39999 
+827,217 
+8.62 
+4.82 
+- 
+24,922 
+5.54 
+- 
+6.4 to 8.19999 
+172,536 
+0.47 
+7.34 
+- 
+162,500 
+7.29 
+- 
+Total 
+1,600,372 
+6.59 
+$ 
+4.18 
+$ 
+- 
+435,794 
+$ 
+4.38 
+$ 
+- 
+As of December 31, 2021, there was $ 2,129,141 of net
+unrecognized compensation cost related to stock options that are not vested, which is expected to be recognized over a weighted average period of approximately 2.55 years. The total fair value of shares vested during the year ended December 31, 2021, was $ 348,727 . 
+The following table summarizes information about restricted stock and restricted stock units outstanding as of December 31, 2021: 
+Number of 
+Shares & Units 
+Weighted 
+Average 
+Grant Date 
+Fair Value 
+Unvested at December 31, 2020 
+603,531 
+$ 
+3.08 
+Granted 
+404,852 
+4.25 
+Vested 
+176,906 
+4.12 
+Forfeited/expired/cancelled 
+126,152 
+3.01 
+Unvested at December 31, 2021 
+705,325 
+3.34 
+As of December 31, 2021, there was $ 1,474,042 of net
+unrecognized compensation cost related to restricted stock and restricted stock units that are not vested, which is expected to be recognized over a weighted average period of approximately 1.9 years. Stock based compensation cost related to restricted stock and restricted stock units recognized during the years ended December 31, 2021 and 2020 was $ 1,160,953 and $ 617,919 , respectively. 
+F-24 
+Table of Contents 
+NOTE 11 — GEOGRAPHIC INFORMATION AND ECONOMIC DEPENDENCY: 
+The Company produces only one 
+group of similar products known collectively as “rapid medical tests” and operates under one segment, as a single reporting unit.
+Product revenue by geographic area are as follows: 
+Year Ending December 31, 
+2021 
+2020 
+Africa 
+$ 
+5,562,787 
+$ 
+4,890,370 
+Asia 
+664,579 
+824,488 
+Europe & Middle East 
+4,067,682 
+5,274,927 
+Latin America 
+18,418,983 
+9,841,772 
+United States 
+6,023,413 
+3,935,592 
+$ 
+34,737,444 
+$ 
+24,767,149 
+Property, plant and equipment, net by geographic area are as follows: 
+2021 
+2020 
+Asia 
+$ 
+86,041 
+$ 
+326,267 
+Europe & Middle East 
+113,883 
+147,692 
+Latin America 
+36,224 
+14,719 
+United States 
+8,320,625 
+8,199,725 
+$ 
+8,556,773 
+$ 
+8,688,403 
+Effective
+May 2021, the Company discontinued its operations in Malaysia. Impairment charges recorded for the Malaysian property, plant and equipment for the year ended December 31, 2021 and 2020 were $ 0.1 and $ 0 millions, respectively. 
+F-25 
+Table of Contents 
+NOTE 12 — COMMITMENTS, CONTINGENCIES AND CONCENTRATIONS: 
+a) 
+Employment Contracts: 
+The Company has multi-year contracts with two 
+key employees. The contracts call for salaries presently aggregating $ 843,000 per year, and they expire in December 2022 and December 2025 . The
+following table is a schedule of future minimum salary commitments: 
+2022 
+$ 
+843,000 
+2023 
+383,000 
+2024 
+383,000 
+2025 
+383,000 
+b) 
+Benefit Plan: 
+The Company has a 401(k) plan established for its employees whereby it matches 40 % of the first 5 % (or 2 % of salary) that an employee contributes to the plan. Matching contribution expenses totaled $ 138,513 
+and $ 87,377 for the years ended December 31, 2021 and 2020, respectively. 
+c) 
+Leases: 
+The Company leases facilities in New York, Germany, Malaysia, and Brazil, and certain equipment. 
+The Company’s facility leases generally include optional renewal periods. Upon entering into a new facility lease, the Company evaluates the leasehold improvements and
+regulatory requirements related to its operations in that location. To the extent that the initial lease term of the related facility lease is less than the useful life of the leasehold improvements and potential regulatory costs associated with
+moving the facility, the Company concludes that it is reasonably certain that a renewal option will be exercised, and thus that renewal period is included in the lease term and the related payments are reflected in the right-of-use asset and lease
+liability. 
+The Company’s leases generally include fixed rental payments with defined annual increases. While certain of the Company’s leases are gross leases, the majority of the
+Company’s leases are net leases in which the Company makes separate payments to the lessor based on the lessor’s property and casualty insurance costs, the property taxes assessed on the property, and a portion of the common area maintenance where
+applicable. The Company has elected the practical expedient not to separate lease and nonlease components for all of the Company’s facility leases. 
+The components of lease expense were as follows: 
+Year Ended 
+December 31, 2021 
+Year Ended 
+December 31, 2020 
+Operating lease expense 
+$ 
+1,625,280 
+$ 
+1,669,105 
+Finance lease cost 
+Amortization of right-of-use assets 
+$ 
+66,872 
+$ 
+58,414 
+Interest on lease liabilities 
+20,077 
+19,986 
+Total finance lease expense 
+$ 
+86,949 
+$ 
+78,400 
+F-26 
+Table of Contents 
+Supplemental cash flow and other information related to leases were as follows: 
+Year Ended 
+December 31, 2021 
+Year Ended 
+December 31, 2020 
+Cash paid for amounts included in the measurement of lease liabilities: 
+Operating cash flows for operating leases 
+$ 
+1,404,532 
+$ 
+1,139,944 
+Operating cash flows for finance leases 
+20,077 
+19,987 
+Financing cash flows for finance leases 
+61,867 
+51,166 
+Right-of-use assets obtained in exchange for lease obligations: 
+Operating leases 
+$ 
+- 
+$ 
+- 
+Finance leases 
+25,609 
+69,528 
+Supplemental balance sheet information related to leases was as follows: 
+December 31, 2021 
+December 31, 2020 
+Finance Leases 
+Finance lease right of use asset 
+$ 
+340,762 
+$ 
+315,154 
+Accumulated depreciation 
+( 148,892 
+) 
+( 82,020 
+) 
+Finance lease right of use asset, net 
+$ 
+191,870 
+$ 
+233,134 
+Current portion of finance lease liability 
+68,176 
+58,877 
+Finance lease liability 
+139,678 
+185,239 
+Total finance lease liabilities 
+$ 
+207,854 
+$ 
+244,116 
+Weighted Average Remaining Lease Term 
+Operating leases 
+7.5 years 
+9.0 years 
+Finance leases 
+2.9 years 
+3.7 years 
+Weighted Average Discount Rate 
+Operating leases 
+8.08 
+% 
+8.58 
+% 
+Finance leases 
+8.76 
+% 
+8.18 
+% 
+Maturities of lease liabilities as of December 31 were as follows: 
+December 31, 2021 
+December 31, 2020 
+Operating 
+Leases 
+Finance 
+Leases 
+Operating 
+Leases 
+Finance 
+Leases 
+2022 
+$ 
+1,447,249 
+$ 
+83,624 
+$ 
+1,209,787 
+$ 
+76,904 
+2023 
+1,221,017 
+83,624 
+1,057,757 
+76,904 
+2024 
+1,018,875 
+55,856 
+1,026,272 
+76,904 
+2025 
+1,049,442 
+12,471 
+1,018,875 
+49,136 
+2026 
+1,080,925 
+1,680 
+1,049,442 
+5,755 
+Thereafter 
+3,643,520 
+- 
+4,724,445 
+- 
+Total lease payments 
+$ 
+9,461,028 
+$ 
+237,255 
+$ 
+10,086,578 
+$ 
+285,603 
+Less: imputed interest 
+( 2,598,583 
+) 
+( 29,401 
+) 
+( 3,116,975 
+) 
+( 41,487 
+) 
+Total 
+$ 
+6,862,445 
+$ 
+207,854 
+$ 
+6,969,603 
+$ 
+244,116 
+d) 
+Economic Dependency: 
+The following table discloses product sales the Company had to customers that purchased in excess of 10% of the Company’s net product sales for the periods indicated: 
+For The Years Ended 
+Accounts Receivable 
+December 31, 2021 
+December 31, 2020 
+December 31, 
+2021 
+December 31, 
+2020 
+Net Product Sales 
+% of Net Product Sales 
+Net Product Sales 
+% of Net Product Sales 
+Customer 1 
+$ 
+17,576,641 
+51 
+% 
+$ 
+6,224,737 
+25 
+% 
+$ 
+7,672,845 
+$ 
+522,218 
+Customer 2 
+* 
+* 
+2,955,312 
+12 
+% 
+* 
+1,987 
+Customer 3 
+3,606,552 
+10 
+% 
+* 
+* 
+1,433,305 
+* 
+F-27 
+Table of Contents 
+Revenue includes product sales only, while accounts receivable reflects the total due from the customer, including freight. 
+The following table discloses purchases the Company made form vendors in excess of 10% of the Company’s net purchases for the periods indicated: 
+For The Years Ended 
+Accounts Payable 
+December 31, 2021 
+December 31, 2020 
+December 31, 
+2021 
+December 31, 
+2020 
+Purchases 
+% of Purc. 
+Purchases 
+% of Purc. 
+Vendor 1 
+$ 
+3,163,285 
+16 
+% 
+$ 
+2,222,182 
+13 
+% 
+$ 
+1,361,383 
+$ 
+222,588 
+Vendor 2 
+$ 
+2,031,795 
+10 
+% 
+$ 
+* 
+* 
+$ 
+353,097 
+$ 
+* 
+In the tables above, an asterisk (*)
+indicates that indicates that sales, accounts receivable, purchases or accounts payable, as applicable to the tabular column, did not exceed 10% for the period indicated. 
+The Company purchases materials pursuant to intellectual property rights agreements that are important components in its products. Management believes that other
+suppliers could provide similar materials on comparable terms. A change in suppliers, however, could cause a delay in manufacturing and a possible loss of sales, which could adversely affect operating results. 
+e) 
+Litigation: 
+SEC Investigation 
+The SEC is conducting a non-public, fact-finding investigation relating to the public offering of
+common stock that Chembio completed in May 2020 (the “May 2020 Offering”) and to the FDA’s revocation in June 2020 of an emergency use authorization for the DPP COVID-19 IgM/IgG system that was issued by the FDA in April 2020. Chembio received
+subpoenas from the SEC in July 2020 and April 2021 seeking the production of documents in connection with this investigation. In addition, the SEC delivered subpoenas in April 2021 to five of Chembio’s employees (including its three executive
+officers, who consist of its Chief Executive Officer and President, its former Executive Vice President and Chief Financial Officer, and its Executive Vice President and Chief Scientific and Technology Officer). An additional subpoena was issued in
+June 2021 to Chembio’s former Interim Chief Executive Officer and Executive Chair. Each subpoena requested the production of documents relating to the same matters as are the subject of the subpoenas Chembio received. Chembio and the six
+individuals are cooperating fully in the SEC’s investigation and expect to continue to do so. 
+The SEC’s letters transmitting the subpoenas expressly provide that the inquiry does not mean that
+the SEC or its staff have concluded that anyone has violated the federal securities laws or have a negative opinion of any person, entity or security. The Company cannot predict the scope, duration or outcome of the investigation or the impact, if
+any, of the investigation on its results of operations. 
+Legal Proceedings 
+Stockholder Litigation 
+Putative Stockholder Securities Class-Action Litigation 
+In 2020 four purported securities class-action lawsuits
+were filed in the United States District Court for the Eastern District of New York by alleged stockholders of Chembio: 
+● 
+Sergey Chernysh v. Chembio Diagnostics, Inc., Richard L. Eberly, and Gail S. Page, filed on June 18, 2020; 
+● 
+James Gowen v. Chembio Diagnostics, Inc., Richard L. Eberly, and Gail S. Page, filed on June 22, 2020; 
+● 
+Anthony Bailey v. Chembio Diagnostics, Inc. Richard J. Eberly, Gail S. Page, and Neil A. Goldman, filed on July 3, 2020; and 
+● 
+Special Situations Fund III QP, L.P., Special Situations Cayman Fund, L.P., and Special Situations Private Equity Fund, L.P. v. Chembio Diagnostics, Inc., Richard Eberly, Gail S.
+Page, Robert W. Baird & Co. Inc. and Dougherty & Company LLC, filed August 17, 2020. 
+F-28 
+Table of Contents 
+The plaintiffs in each of the above cases alleged claims under Section 10(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), Rule 10b-5 thereunder and
+Section 20(a) of the Exchange Act. Special Situations Fund III QP, L.P., Special Situations Cayman Fund, L.P. and Special Situations Private Equity Fund, L.P. (collectively, the “Special Situations Funds”) also asserted claims under Sections 11,
+12(a)(2) and 15 of the Securities Act of 1933 (the “Securities Act”) relating to the May 2020 Offering. 
+Chembio and the plaintiffs entered into Court-approved stipulations relieving Chembio and the other defendants of the obligation to respond to the complaints in these
+cases pending the designation of a lead plaintiff pursuant to the Private Securities Litigation Reform Act of 1995. Eight motions for
+appointment as lead plaintiff were filed by various prospective lead plaintiffs. However, all but two of these motions were withdrawn or
+otherwise abandoned, leaving before the Court two motions for appointment as lead plaintiff - one filed by the Special Situations Funds and one by Municipal
+Employees’ Retirement System of Michigan. By order entered December 29, 2020, Magistrate Judge Lindsay consolidated the cases and appointed the Special Situations Funds and Municipal Employees’ Retirement System of Michigan (together, the “Lead Plaintiffs”) , as co-lead plaintiffs and their respective
+counsel as co-lead counsel. The consolidated cases are now pending under the caption “In re Chembio Diagnostics, Inc. Securities Litigation.” 
+The Lead Plaintiffs filed their Consolidated Amended Complaint (the “CAC”) on February 12, 2021. In summary, the CAC purported to allege claims based on assertedly false and misleading statements and
+omissions concerning the performance of the DPP COVID-19 IgM/IgG System, as well as an asserted failure to timely disclose that the emergency use authorization that had been granted by the FDA with respect to the DPP COVID-19 IgM/IgG System “was -
+or was at an increased risk of - being revoked.” The CAC named as defendants Chembio, Richard L. Eberly, Gail S. Page, Neil A. Goldman, Javan Esfandiari, Katherine L. Davis, Mary Lake Polan, John Potthoff and the underwriters for the May 2020
+Offering, Robert W. Baird & Co., Inc. and Dougherty & Company LLC (the “Underwriter Defendants”). 
+The CAC purported to assert five counts under the Securities Act and the Exchange Act. Counts I
+through III were brought under the Securities Act, allegedly on behalf of a purported class consisting of all persons who purchased Chembio common stock directly in or traceable to the May 2020 Offering pursuant to Chembio’s shelf registration
+statement on Form S 3 (File No. 333-227398) and the related prospectus, as supplemented by a prospectus supplement dated May 7, 2020 (the “Securities Act Class”). Count I purported to allege a claim for violation of Section 11 of the Securities Act
+against all defendants other than Messrs. Eberly and Esfandiari. Count II purported to allege a claim for violation of Section 12 of the Securities Act against all defendants other than Messrs. Eberly and Esfandiari. Count III purported to allege a
+claim under Section 15 of the Securities Act against Ms. Davis, Dr. Polan, Dr. Potthoff, Ms. Page and Mr. Goldman. 
+Counts IV and V alleged claims under the Exchange Act on behalf of a purported class consisting of
+all persons who purchased Chembio common stock on the open market from March 12, 2020 through June 16, 2020 (the “Exchange Act Class”). Count IV purported to allege a claim for violation of Section 10(b) of the Exchange Act and Rule 10b-5
+thereunder against Chembio, Mr. Eberly, Ms. Page, Mr. Goldman and Mr. Esfandiari. Count V purported to allege a claim under Section 20(a) of the Exchange Act against Mr. Eberly, Ms. Page, Mr. Goldman and Mr. Esfandiari. 
+In their CAC, the Lead Plaintiffs sought, on behalf of the Securities Act Class and the Exchange Act
+Class, among other things, an award of damages in an amount to be proven at trial, as well as an award of reasonable costs, including attorneys’ fees and expenses, expert fees, pre-judgment and post-judgment interest, and such other relief as the
+Court deems just and proper. The Lead Plaintiffs also sought rescission “or a rescissory measure of damages” on behalf of the Securities Act Class as to Count II. 
+F-29 
+Table of Contents 
+Pursuant to an order entered by the Court on January 29, 2021, any defendant wishing to move against
+the amended complaint was required to file, by February 18, 2021, a letter requesting a pre-motion conference. On that date, the defendants submitted letters to the Court requesting a pre-motion conference regarding anticipated motions to dismiss
+the CAC, and the Lead Plaintiffs responded on February 24, 2021. In its January 29, 2021 order, the Court indicated that it would consider a briefing schedule on motions to dismiss after it had received and reviewed the parties’ correspondence. 
+On March 5, 2021, the Court entered an order in which it advised the parties that it had determined a
+pre motion conference was not necessary and established a briefing schedule on the defendants’ anticipated motions to dismiss. However, the defendants subsequently agreed with the Lead Plaintiffs’ counsel to a modification of the schedule, which
+was then approved by the Court. Pursuant to that schedule, defendants’ motions and supporting papers were filed on March 26, 2021, the Lead Plaintiffs’ opposition papers were filed on April 16, 2021, and the defendants’ reply papers were filed on
+April 30, 2021. 
+The Court issued its Opinion and Order (the “Order”) on the defendants’ motions to dismiss on
+February 23, 2022. In its Order, the Court: (i) dismissed Counts I and II without prejudice as to all defendants named in those Counts except the Underwriter Defendants as to which Counts I and II were not dismissed; (ii) dismissed Count III
+without prejudice as to all defendants named in that Count; and (iii) dismissed Counts IV and V with prejudice as to all defendants named in those Counts. The Court gave Lead Plaintiffs fourteen days within which to attempt to replead their claims under the Securities Act against Chembio, Ms. Page, Mr. Goldman, Ms. Davis, Ms. Polan and Mr. Potthoff. 
+Putative Stockholder Derivative Litigation 
+On September 11, 2020, a putative stockholder derivative action captioned Karen Wong, derivatively on behalf of Chembio Diagnostics, Inc., Plaintiff v. Richard L. Eberly, Gail S. Page, Neil A. Goldman,
+Javan Esfandiari, Katherine L. Davis, Mary Lake Polan and John G. Potthoff, Defendants, and Chembio Diagnostics, Inc., Nominal Defendant (the “Wong complaint”) was filed purportedly on Chembio’s behalf in the United States District Court for the
+Eastern District of New York. The Wong complaint purports to assert a claim for violation of Section 14(a) of the Exchange Act and Rule 14a-9 thereunder based on ostensibly false and misleading statements and omissions concerning the Company’s
+rapid COVID-19 antibody test in the proxy statement disseminated in advance of Chembio’s Annual Meeting of Stockholders held on July 28, 2020. The Wong complaint also asserts claims against the individual defendants for purported breaches of
+fiduciary duties owed to Chembio, as well as unjust enrichment. 
+The Wong complaint requests a declaration that the individual defendants have breached or aided and
+abetted the breach of their fiduciary duties to Chembio, an award of damages to us, restitution, and an award of the plaintiff’s costs and disbursements in the action, including reasonable attorneys’ and experts’ fees, costs and expenses, and
+improvements to Chembio’s corporate governance and internal procedures regarding compliance with laws. Pursuant to a stipulation by which the individual defendants named in the Wong complaint agreed to waive service of process, the Court ordered
+that the time for defendants to answer or otherwise respond to the complaint be extended to November 19, 2020. The parties subsequently entered into a stipulation for a stay of proceedings in the action relating to the Wong complaint pending final
+disposition of motions to dismiss the pending putative class-action litigation, subject to certain conditions. The Court entered an order granting the requested stay on November 3, 2020. At this stage of the litigation, the Company is not able to
+predict the probability of a favorable or unfavorable outcome. 
+Employee Litigation 
+On March
+19, 2021, John J. Sperzel III, Chembio’s former chief executive officer, filed a fifteen -count complaint in the United States District
+Court for the Eastern District of New York. The complaint was filed following the dismissal of an action previously filed by Mr. Sperzel in the United States District Court in Maine, which was dismissed for lack of personal jurisdiction over
+Chembio. In summary, the complaint filed in the Eastern District of New York alleges that Chembio wrongfully refused to allow Mr. Sperzel to exercise certain options to purchase, for an aggregate exercise price of $ 943,126 , a total of 266,666 shares of
+common stock that were allegedly vested as of the date of his separation from Chembio, on January 3, 2020. The complaint alleges that under the terms of the applicable stock incentive plans, Mr. Sperzel had thirty days after the date on which he ceased to qualify as an “Eligible Person” under the plans within which to exercise the options, and asserts that by reason of his alleged
+continued service to us, he remained an “Eligible Person” and ostensibly retained the right to exercise the options. The Compensation Committee of the Board determined that the options expired on February 3, 2020, thirty days after Mr. Sperzel’s separation from Chembio, and that a purported attempt by Mr. Sperzel to exercise the options after that date was not
+valid. 
+F-30 
+Table of Contents 
+Count I of the complaint purports to allege that Chembio breached Mr. Sperzel’s separation agreement
+by refusing to allow him to exercise the stock options. Counts II through XI of the complaint purport to allege claims for breach of each of ten 
+separate stock option agreements, collectively asserting damages of “at least” $ 3,190,198 . Count XII of the complaint alleges a breach of
+Mr. Sperzel’s separation agreement based on Chembio’s purported failure to pay Mr. Sperzel consulting fees to which he claims to be entitled for consulting services allegedly performed following his separation. Count XIII of the complaint alleges a
+claim for breach of an implied covenant of good faith and fair dealing under Nevada common law based on the allegation that Chembio prevented Mr. Sperzel from obtaining the benefits of the stock option agreements and separation agreement. Mr.
+Sperzel alleges that he suffered damages in excess of $ 3 million as a result of the purported breach of the covenant of good faith and
+fair dealing. Count XIV of the complaint purports to assert a claim for quantum meruit, alleging that “it is reasonable for Sperzel to expect payment in exchange for ... services” he assertedly provided to us and, based on allegations that upon his
+separation Mr. Sperzel was not informed as to the pending expiration of the stock options he later sought to exercise, that Chembio has been unjustly enriched. Finally, Count XV of the complaint seeks a declaratory judgment that Mr. Sperzel is
+relieved from performance under his separation agreement due to asserted material breaches of the agreement based on the allegations summarized above. The complaint seeks compensatory damages in an unspecified amount, a declaration, as described
+above, and an award of Mr. Sperzel’s costs and expenses in the litigation, including reasonable attorneys’ fees, expert costs and disbursements. The complaint requests a trial by jury. In recently served initial disclosures, Mr. Sperzel claims
+entitlement to recover damages in a total amount not less than $ 10 million, together with prejudgment interest at the rate of 9 % per annum. 
+On May 20, 2021, Chembio filed its
+answer and affirmative defenses denying the material allegations of Mr. Sperzel’s complaint. Chembio and Mr. Sperzel are presently engaged in discovery. Under the present case schedule, all discovery is expected to be completed by April 28, 2022.
+At this stage of the litigation, the Company is not able to predict the probability of a favorable or unfavorable outcome . 
+Other 
+From time to time the Company may become involved in legal proceedings or may be subject to claims arising in the ordinary
+course of its business. Although the results of litigation and claims cannot be predicted with certainty, the Company currently believes that the final outcome of these ordinary course matters will not have a material adverse effect on its
+business, operating results, financial condition or cash flows. Regardless of the outcome, litigation can have an adverse impact on the Company because of defense and settlement costs, diversion of management resources, and other factors. 
+F-31 
+Table of Contents 
+NOTE 13 — LONG-TERM DEBT: 
+On September 3, 2019, the Company entered into a Credit Agreement and Guaranty (the “Credit Agreement”) with Perceptive Credit Holdings II, LP (the “Lender”). The Credit
+Agreement provides for a $ 20,000,000 senior secured term loan credit facility, which was drawn in full on September 4, 2019. Under the
+terms of the Credit Agreement, the Company may use the proceeds (i) for general working capital purposes and other permitted corporate purposes, (ii) to refinance certain of the Company’s existing indebtedness and (iii) to pay fees, costs and
+expenses incurred in connection with the Credit Agreement, including the Lender’s closing cost amount of $ 550,000 , which was netted from
+the proceeds, and a financing fee of $ 600,000 ( 3.0 %
+of gross proceeds) payable to Craig-Hallum Capital Group LLC, the Company’s financial advisor for the financing. 
+Principal outstanding under the Credit Agreement bears interest at a rate per annum equal to the sum of (a) the greater of the one-month London Interbank Offered Rate and 2.5 % plus (b) 8.75 %. At any time at which an event of default has occurred and is continuing, the interest rate will increase by 4.0 %. Accrued interest is payable on a monthly basis. On December 31, 2021 the interest rate was 11.25 %. 
+No principal repayments are due under the Credit Agreement prior to September 30, 2022, unless the Company elects to prepay principal or principal is accelerated
+pursuant to an event of default identified in the Credit Agreement. Principal installments in the amount of $ 300,000 are payable on the
+last day of each of the eleven months from September 2022 through July 2023, and all remaining principal is payable at maturity on September 3, 2023 .
+The Company may prepay outstanding principal from time to time, subject to payment of a premium on the prepaid principal amount equal to 10 %
+through September 3, 2020, 8 % from September 4, 2020 through September 3, 2021, and 4 % from September 4, 2021 through September 3, 2022. No premium will be due with respect to any prepayment made on or after September 4, 2022. 
+Chembio’s obligations under the Credit Agreement are secured by a first priority, perfected lien on substantially all of its property and assets, including its equity
+interests in subsidiaries. 
+As of December 31, 2021, the loan balance, net of unamortized discounts and debt issuance costs, was $ 18.8 million, and Chembio was in compliance with its loan covenants. 
+NOTE 14 — IMPAIRMENT, RESTRUCTURING, SEVERANCE AND RELATED COSTS: 
+The Company recorded an impairment loss of $ 1.3 million
+during the second quarter of 2021, as the result of its write-off of the intangible assets, net, leasehold improvements, net and right-of-use assets for leases, net associated with its Malaysian operations that underwent a retrenchment during the
+second quarter of 2020. During the second quarter of 2021, the Company was informed that the World Health Organization had prioritized its review of prequalification of the manufacture of the Company’s HIV 1/2 STAT-PAK Assay on its U.S. automated
+manufacturing processes, which would reduce the Company’s reliance on manual labor that otherwise could have been performed at the Malaysian facilities had the Company re-started operations there. During July 2021, the World Health Organization
+approved the change notification. The products produced on the Company’s automated and manual production lines at any time depend on, among other things, the timing of customer orders and the mix of products being produced. 
+In light of the uncertainty of the timing and any receipt of those regulatory approvals, the timing of progress on and results of clinical trial programs, and the
+timing and any receipt of product orders from the commercialization of the COVID-19 Diagnostic Test Systems and other diagnostic test systems both within and outside the United States, during the second quarter of 2021, the Company engaged the
+services of an independent financial advisory firm (the “Financial Advisor”). The Financial Advisor worked with management to develop a forecast model to assess the amount and timing of the Company’s liquidity needs, assuming various business
+cases, and together with legal counsel advised the Company regarding alternative approaches to enhancing its liquidity position, participating in discussions with the Lender, and related matters. During the year ended December 31, 2021 and 2020,
+the Company incurred $ 1.1 and $ 0.4 
+million, respectively, related to these restructuring matters. 
+F-32 
+Table of Contents 
+In order to address challenging economic conditions and implement its business strategy, in the first quarter of 2021 the Company continued to execute a program to
+reduce operating expenses and better align its costs with revenues, including by eliminating positions that were no longer aligned with its strategy, and recognized severance charges of $ 0.1 million. 
+The table below represents the total costs by category: 
+For the year ended 
+December 31, 2021 
+For the year ended 
+December 31, 2020 
+Severance 
+$ 
+83,087 
+$ 
+723,118 
+Restructuring costs 
+1,083,951 
+399,192 
+Impairment 
+5,880,741 
+- 
+$ 
+7,047,779 
+$ 
+1,122,310 
+Impairment details are as follows: 
+For the year ended 
+December 31, 2021 
+Goodwill 
+$ 
+2,567,753 
+Intellectual Property 
+1,090,472 
+Developed Technology 
+1,115,819 
+Customer Contracts 
+776,683 
+Trademarks 
+67,157 
+Fixed Asset 
+152,109 
+ROU Lease Asset 
+110,748 
+Total 
+$ 
+5,880,741 
+NOTE 15 — SUBSEQUENT EVENTS: 
+On February 17, 2022, Chembio Diagnostics GmbH, our German subsidiary formed under the laws of the Federal Republic of Germany, has filed a petition for insolvency in
+the Charlottenburg District Court (“Amtsgericht Charlottenburg“) in Berlin, Germany in compliance with German insolvency law. A provisional insolvency administrator (“Administrator”) has been appointed to manage cash disbursements and general
+affairs of the business. We expect to provide certain support and liquidity for the subsidiary to continue operations until such time a viable business strategy has been determined and agreed to with the Administrator. 
+F-33
\ No newline at end of file
diff --git a/raw/filings/0001092662/2021/0001140361-22-007735/filing_metadata.csv b/raw/filings/0001092662/2021/0001140361-22-007735/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..a77a8c72eccac376dada810ccf9b1a854ef6ca16
--- /dev/null
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@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0001092662,CEMI,"CHEMBIO DIAGNOSTICS, INC.",10-K,2022-03-03,2021-12-31,2022-03-03T22:15:35.000Z,0001140361-22-007735,brhc10034606_10k.htm,10-K,10296655,1,1,https://www.sec.gov/Archives/edgar/data/1092662/000114036122007735/brhc10034606_10k.htm,https://www.sec.gov/Archives/edgar/data/1092662/000114036122007735/,2021,2021,1
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@@ -0,0 +1,551 @@
+ITEM 1. 
+BUSINESS 
+Overview 
+We develop and commercialize point-of-care diagnostic tests used for the rapid detection and diagnosis of infectious diseases, including sexually transmitted disease, insect vector and tropical disease, COVID-19 and
+other viral and bacterial infections, enabling expedited treatment. 
+Our product portfolio is based upon our proprietary DPP technology, a diagnostic platform that provides high-quality, cost-effective results in 15 to 20 minutes using fingertip blood, nasal swabs and other sample
+types. The DPP technology platform addresses the rapid diagnostic test market, which includes infectious diseases such as STI’s and HIV, Gastroenterology and Women’s Health. Compared with traditional lateral flow technology, the DPP technology
+platform can provide: 
+• 
+Enhanced sensitivity and specificity: This is achieved via our patented approach to separating the sample path from the buffer path, together with other patented and
+proprietary strategies, that differ significantly from traditional lateral flow test. 
+• 
+Advanced multiplexing capabilities: Through advanced multiplexing, the DPP platform can detect and differentiate up to eight distinct test results from a single
+patient sample, which can deliver greater clinical value than other rapid tests currently on the market. 
+• 
+Objective results: For some diagnostic applications, our easy-to-use, highly portable, battery-operated DPP Micro Reader optical analyzers can report accurate
+results in approximately 15 seconds, making it well-suited for decentralized testing where real-time results enable patients to be clinically assessed while they are still onsite. Objective results produced by the DPP Micro Reader can
+reduce the possibility of the types of human error that can be experienced in the visual interpretations required by many rapid tests. 
+We target the market for rapid diagnostic test solutions for infectious diseases, which is driven by the high prevalence of infectious diseases globally, an increase in the elderly population, growing demand for
+rapid test results, and advancements in multiplexing. We have a broad portfolio of infectious disease products, which prior to 2020 were focused principally on sexually transmitted disease and fever and tropical disease. In February 2020 we began
+the process of shifting substantially all of our resources to seek to leverage the DPP technology platform to address the acute and escalating need for diagnostic testing for COVID-19. We are continuing to pursue: 
+• 
+an emergency use authorization, or EUA, from the U.S. Food and Drug Administration, or FDA, as well as 510(k) clearance from the FDA, for the DPP SARS-CoV-2 Antigen test system; 
+• 
+an EUA from the FDA for the DPP Respiratory Antigen Panel; and 
+• 
+a Clinical Laboratory Improvement Amendment, or CLIA, waiver from the FDA for the DPP HIV-Syphilis test system. 
+For additional information about our existing and proposed product offerings, please see “—Products” below. Our products are sold globally, directly and through distributors, to medical laboratories and hospitals,
+governmental and public health entities, nongovernmental organizations, medical professionals, and retail establishments. We continue to seek to expand our commercial distribution channels. 
+4 
+Table of Contents 
+The extensive economic disruption caused by the COVID-19 pandemic, exacerbated by the market and regulatory complications we faced in seeking to develop and commercialize a portfolio of COVID-19 test systems, was
+reflected in our operating results for 2021, as total revenues were $47.8 million, an increase of 47.3% from 2020, and net product sales were $34.8 million, an increase of 40.3% from 2020. See “Item 7. Management’s Discussion and Analysis of
+Financial Condition and Results of Operations—Consolidated Results of Operations.” 
+In 2021 we continued to invest in automating our test manufacturing processes, all of which are now based in the United States. Among other actions, we expanded our manufacturing capabilities by validating and implementing automated lines. Our
+transition from manual to automated assembly is intended to add capacity, reduce variable costs and improve product margins. In order to address challenging economic conditions and implement our business strategy, we continued to execute a program
+to reduce operating expenses and better align our costs with revenues by eliminating positions that were no longer aligned with our strategy. Our cash and cash equivalents totaled $28.8 million at December 31, 2021, compared to $23.1 million at
+December 31, 2020. 
+The Company’s future working capital needs will depend on many factors, including the rate of its business and revenue growth, the availability and cost of human, material and other resources required to build and
+deliver products in accordance with its existing or future product orders, the timing of its continuing automation of manufacturing, and the timing of its investment in research and development as well as sales and marketing. If the Company is
+unable to increase its revenues and manage its expenses in accordance with its operating plan, it may need to reduce the level or slow the timing of the growth plans contemplated by its operating plan, which would likely curtail or delay the growth
+in its business contemplated by its operating plan and could impair or defer its ability to achieve profitability and generate cash flow, or to seek to raise additional funds through debt or equity financings, strategic relationships, or other
+arrangements. All DPP tests are developed and manufactured in the United States and are the subject of a range of domestic and global patents and patents pending. 
+Going Concern Considerations 
+Revenues during the twelve months ended December 31, 2021 did not meet the Company’s expectations. The Company’s increase in cash and cash equivalents over the year reflected its issuance of common stock in
+at-the-market offerings for net proceeds of $38.8 million (see Note 9 - Stockholder’s Equity). The Company continued to experience market, clinical trial and regulatory complications in seeking to develop and commercialize a portfolio of COVID-19
+test systems during the continuing, but evolving, uncertainty of the COVID‑19 pandemic. In the year ending on December 31, 2021, the Company continued to incur significant expenses in connection with pending legal matters (see Note 12 –
+Commitments, Contingencies, and Concentrations: Litigation), delayed achievement of milestones associated with government grant income, investments in inventory, and the continuing automation of manufacturing. 
+The Company performed an assessment to determine whether there were conditions or events that, considered in the aggregate, raised substantial doubt about the Company’s ability to continue as a going concern within
+one year after the date the accompanying consolidated financial statements are being issued. Initially, this assessment did not consider the potential mitigating effect of management’s plans that had not been fully implemented. Because, as
+described below, substantial doubt was determined to exist as the result of this initial assessment, management then assessed the mitigating effect of its plans to determine if it is probable that the plans (1) would be effectively implemented
+within one year after the date the accompanying consolidated financial statements are issued and (2) when implemented, would mitigate the relevant conditions or events that raise substantial doubt about the entity’s ability to continue as a going
+concern. 
+During the twelve months ended December 31, 2021, the Company undertook measures to increase its total revenues and improve its liquidity position. In particular, the Company received significant purchase orders from
+two customers (the “July Purchase Orders”). The Company had pursued the July Purchase Orders for an extended period of time. The July Purchase Orders consist of the following: 
+• 
+On July 20, 2021, the Company received a $28.3 million purchase order from Bio-Manguinhos for the purchase of DPP SARS-CoV-2
+Antigen tests for delivery during 2021 to support the urgent needs of Brazil’s Ministry of Health in addressing the COVID-19 pandemic. Bio-Manguinhos, is responsible for the development and production of vaccines, diagnostics and
+biopharmaceuticals, primarily to meet the demand of Brazil’s national public health system. As of December 31, 2021 $16.8 million was recognized in connection with this order. 
+5 
+Table of Contents 
+• 
+On July 22, 2021, the Company received a $4 million purchase order from the Partnership for Supply Chain Management, supported by The Global Fund, for the purchase of HIV 1/2 STAT-PAK Assays for shipment to
+Ethiopia into early 2022. As of December 31, 2021 $1.2 million was recognized in connection with this order. 
+These measures and other plans and initiatives have been designed to provide the Company with adequate liquidity to meet its obligations for at least the twelve-month period following the date the accompanying
+consolidated financial statements are being issued. The Company’s execution of those measures and its other plans and initiatives continue to depend, however, on factors and uncertainties that are beyond the Company’s control, or that may not be
+addressable on terms acceptable to the Company or at all. The Company considered in particular how: 
+• 
+The ongoing healthcare and economic impacts of the COVID-19 pandemic on the global customer base for the Company’s non‑COVID-19 products continue to negatively affect the timing and rate of recovery of the
+Company’s revenues from those products by, for example, decreasing the allocation of funding for HIV testing, thereby continuing to adversely affect the Company’s liquidity. 
+• 
+Although the Company has entered into agreements to distribute third-party COVID-19 products in the United States, its ability to sell those products could be constrained because of staffing and supply chain
+limitations affecting the suppliers of those products. 
+The Company further considered how these factors and uncertainties could impact its ability over the next year to meet the obligations
+specified in the Credit Agreement with the Lender (each as defined in Note 13 – Long-Term Debt). Those obligations include covenants requiring: 1) minimum cash balance of $3.0 million and ii) minimum total revenue amounts for the twelve months
+preceding each quarter end. For the next year, the minimum total revenue requirements range from $42.0 million for the twelve months ending March 31, 2022 to $47.4 million for the twelve months ending December 31, 2022. Upon an event of default
+under the Credit Agreement, the Lender could elect to declare all amounts outstanding thereunder, together with accrued interest, to be immediately due and payable. In such an event, there can be no assurance that the Company would have
+sufficient liquidity to fund payment of the amounts that would be due under the Credit Agreement or that, if such liquidity were not available, the Company would be successful in raising additional capital on acceptable terms, or at all, or in
+completing any other endeavor to continue to be financially viable and continue as a going concern. The Company’s inability to raise additional capital on acceptable terms in the near future, whether for purposes of funding payments required
+under the Credit Agreement or providing additional liquidity needed for its operations, could have a material adverse effect on its business, prospects, results of operations, liquidity and financial condition. 
+Accordingly, management determined the Company could not be certain that the Company’s plans and initiatives would be effectively implemented within one year after the date on which the accompanying consolidated
+financial statements are being issued. Without giving effect to the prospect of raising additional capital pursuant to the ATM Agreement (as defined in Note 9 – Stockholders’ Equity: Common Stock), increasing product revenue in the near future or
+executing other mitigating plans, many of which are beyond the Company’s control, it is unlikely that the Company will be able to generate sufficient cash flows to meet its required financial obligations, including its debt service and other
+obligations due to third parties. The existence of these conditions raises substantial doubt about the Company’s ability to continue as a going concern for the twelve-month period following the date on which the accompanying audited consolidated
+financial statements are being issued. 
+6 
+Table of Contents 
+The accompanying audited consolidated financial statements have been prepared assuming the Company will continue as a going concern, which contemplates continuity of operations, realization of assets and the
+satisfaction of liabilities in the normal course of business for the twelve-month period following the date the accompanying consolidated financial statements are issued. As such, the accompanying audited consolidated financial statements do not
+include any adjustments relating to the recoverability and classification of assets and their carrying amounts, or the amount and classification of liabilities that may result should the Company be unable to continue as a going concern. 
+Industry 
+The DPP technology platform targets diagnostic disease states; (1) where rapid diagnosis impacts patient treatment and outcomes; (2) that are underserved by current diagnostic products due to performance or
+availability; (3) that present opportunities regionally, demographically or clinically. The Company is focused on test solutions associated with infectious diseases: respiratory viruses, sexually transmitted diseases, gastroenterology and
+insect-vector diseases. 
+Our product portfolio is marketed globally to NGO’s, Ministries of Health, acute care hospitals, reference labs, outpatient clinics including urgent cares and physician offices. Our branded products have secured
+meaningful market share globally and include, SureCheck, Stat Pak and DPP. The Company will focus on internally developed products and pursue external opportunities to license novel technologies and products with the intent of leveraging Chembio’s
+growing commercial infrastructure. 
+We currently are targeting lateral flow test solutions for infectious diseases: respiratory diseases, sexually transmitted diseases and mosquito-borne diseases. The market for lateral flow infectious disease tests is
+being driven by the high prevalence of infectious diseases globally, an increase in the elderly population, growing demand for rapid test results, and advancements in multiplexing. 
+Products 
+COVID-19 Diagnostic Test Systems 
+Prior to 2020, our broad portfolio of infectious disease products was focused principally on sexually transmitted disease and fever and tropical disease. In 2020 we shifted substantially all of our resources to
+leverage the DPP technology platform to address the acute and escalating need for diagnostic testing for COVID-19. 
+COVID-19 Antibody Test System 
+In January 2021 we announced the CE mark for both the DPP SARS-CoV-2 Antigen test system and the DPP SARS-CoV-2 IgM/IgG test system, providing regulatory approval to register and market the test systems in the
+European Union and other geographies that accept the CE mark. 
+COVID-19 Antigen Test System 
+In mid-2020 we began to focus on the development of a COVID-19 antigen test system based on DPP technology. In July 2020 we received a $628,071 grant from BARDA to assist us in developing, submitting and obtaining an
+EUA application for a COVID-19 point-of-care antigen system. In October 2020, with BARDA’s support in accordance with its grant, we submitted to the FDA an EUA application for the DPP SARS‑CoV‑2 Antigen System, a test system that consists of a DPP
+SARS-CoV-2 Antigen test cartridge, a DPP Micro Reader optical analyzer and a minimally invasive nasal swab. 
+7 
+Table of Contents 
+In November 2020 ANVISA approved the DPP SARS-CoV-2 Antigen test system for use in Brazil. In January 2021 we announced the CE mark for the DPP SARS-CoV-2 Antigen test system, providing regulatory approval to
+register and market the test systems in the European Union and other geographies that accept the CE mark. 
+In December 2020 we received a $12.7 million grant from BARDA, in part to support preparation of a submission in pursuit of FDA 510(k) clearance for the DPP SARS-CoV-2 Antigen System. 
+In January 2021 the FDA notified us that it was declining to review the DPP SARS-CoV-2 Antigen System based on its updated prioritization guidance, under which review of the system was not a priority. The FDA has
+supplementally advised us of the type and nature of information it would need to receive in a subsequent EUA application in order for the DPP SARS-CoV-2 Antigen System to be prioritized for review, and we are engaged in testing and development in
+order to submit a new EUA application for a COVID-19 antigen test system. 
+During the year ending December 31, 2021 we performed the clinical trials and on December 2, 2021 we submitted the DPP SARS‑CoV‑2 Antigen test system to the FDA, as a de Novo submission. 
+COVID-19 and Influenza Respiratory Antigen Panel Test System 
+In the fourth quarter of 2020 we began developing a rapid, multiplex respiratory antigen panel point-of-care test system using DPP technology. BARDA designated a portion of its $12.7 million grant in December 2020
+for use to support our development, submission and receipt of an EUA for this system. 
+During 2021, we developed and conducted clinical trials of the DPP Respiratory Antigen Panel, a test system being designed to provide simultaneous, discrete and differential detection of Influenza A, Influenza B and
+SARS-CoV-2 antigens from a single patient respiratory specimen, such as a nasal swab. The system is intended to enable appropriate clinical management of patients with suspected respiratory infections and to assist in the containment of COVID-19
+cases during the flu season. This test system provides results in approximately 20 minutes and is run on the DPP Micro Reader. As of December 31, 2021, we have submitted a request for the EUA approval by the FDA which is currently under review. In
+addition, as of December 31, 2021, we submitted a request for approval to ANVISA in Brazil and CE in Europe, which has been approved as of the date of this filing. 
+As a result, we earned $12.5 million of the $12.7 million available under the BARDA Agreement, dated December 2, 2020 with the Biomedical Advanced Research and Development Authority, or BARDA (part of the U.S.
+Department of Health and Human Services’ Office of the Assistant Secretary for Preparedness and Response) with the remaining $0.2 million having not been earned because it was contingent on our receiving an emergency use authorization for the DPP
+SARS-CoV-2 Antigen by December 2, 2021. 
+HIV-Syphilis Diagnostic Test Systems 
+On December 1, 2021, we received notice from the FDA that it would require additional data related to our Clinical Laboratory Improvement Amendment, or CLIA, waiver submission for the DPP HIV-Syphilis test system. We
+are in active discussions with the FDA in connection with the FDA’s review of our submission and we intend to comply with the FDA’s request for additional data. The process of seeking additional data will extend, for a currently undeterminable
+period, our process for seeking a CLIA waiver for the DPP HIV-Syphilis test system. 
+8 
+Table of Contents 
+Core Products 
+We have obtained FDA approvals and, directly or through our partners, international regulatory approvals for infectious disease tests as follows: 
+Product 
+U.S. 
+International 
+DPP COVID-19 IgM/IgG System 
+✓ 
+DPP SARS-CoV-2 IgM/IgG System 
+✓ 
+DPP SARS-CoV-2 Antigen 
+✓ 
+DPP HIV 1/2 Assay 
+✓ 
+✓ 
+DPP HIV-Syphilis System 
+✓ 
+✓ 
+DPP Syphilis Screen & Confirm Assay 
+✓ 
+DPP ZCD IgM/IgG System 
+✓ 
+DPP Dengue NS1 Antigen System 
+✓ 
+DPP Dengue IgM/IgG System 
+✓ 
+DPP Zika IgM System 
+✓ 
+✓ 
+DPP Zika IgM/IgG System 
+✓ 
+DPP Chikungunya System 
+✓ 
+DPP Ebola Antigen System 
+✓ EUA 
+DPP Leishmaniasis Assay 
+✓ 
+DPP Respiratory Antigen Panel 
+✓ 
+DPP VetTB Assay 
+✓ 
+HIV 1/2 STAT-PAK Assay 
+✓ 
+✓ 
+Chagas STAT-PAK Assay 
+✓ 
+SURE CHECK HIV 1/2 Assay 
+✓ 
+✓ 
+SURE CHECK HIV Self-Test 
+✓ 
+Organic growth in our core infectious disease business is being driven by: 
+• 
+growth in the overall market for point of care infectious disease tests; 
+• 
+our increased market penetration in existing markets and channels, including in the United States, Latin America, Africa and Europe; 
+• 
+our registration of existing and new products in unchartered countries and regions, such as selected countries in Latin America and Southeast Asia; 
+• 
+our entry into new market segments, such as respiratory tests and international HIV Self-Testing; and 
+• 
+advances in our product pipeline in infectious disease with key products including tests for COVID-19, a multiplex test for HIV and syphilis in the U.S. market and tests for dengue, zika and chikungunya. 
+We market and sell both stand-alone and multiplex tests for sexually transmitted infectious diseases, such as HIV and syphilis which continue to be major global public health issues. According to WHO estimates: 
+• 
+HIV has claimed more than 36 million lives, including 680,000 in 2020. Approximately 37.7 million people were living with HIV at the end of 2020, and 1.5 million were newly infected during 2020. 
+• 
+There were 18.0 million prevalent cases of syphilis as of 2012, and 5.6 million new infections were estimated to occur annually. 
+• 
+Elimination of mother-to-child transmission, or MTCT, of both HIV and syphilis is a global health priority. In 2013, 1.9 million pregnant women were infected with syphilis worldwide. Congenital syphilis
+contributes significantly to infant mortality, accounting for 305,000 annual perinatal deaths worldwide in 2013. Globally, more than 1.4 million pregnant women were infected with HIV as of 2015, and MTCT of HIV is estimated to have
+resulted in over 150,000 infant cases in 2015. 
+9 
+Table of Contents 
+We are seeking to address the global concerns related to HIV and syphilis co-infection through the development of a novel, multiplex test for both HIV and syphilis. We have developed a DPP HIV-Syphilis multiplex test
+and received regulatory approvals in the United States and a number of international markets, including Brazil, Europe, Africa, Malaysia and Mexico. We are pursuing a CLIA waiver for the DPP HIV-Syphilis test in the United States. 
+We also market and sell tests for selected fever and tropical diseases such as Chagas, ebola, leishmaniasis and Zika. The market for lateral flow mosquito-borne diseases includes established markets for disease such
+as dengue and malaria, which WHO estimates together account for more than 600 million annual infections worldwide. There are also a number of emerging markets for rapid point of care tests for infectious diseases such as burkholderia, chikungunya,
+lassa, leptospirosis, Marburg, rickettsia and Zika. 
+Since 2015 we have received over $25.1 million of funding from some of the world’s leading health organizations, which has helped us accelerate the expansion of our pipeline of infectious disease tests. Our
+collaborators have included Bill & Melinda Gates Foundation, The Paul G. Allen Family Foundation, The Oswaldo Cruz Foundation or FIOCRUZ, and the Foundation for Innovative New Diagnostics, or FIND, as well as U.S. government agencies such as
+Centers for Disease Control and Prevention, or CDC, the Biomedical Advanced Research and Development Authority of the U.S. Department of Health and Human Services, or BARDA, and the U.S. Department of Agriculture, or USDA. 
+Several tests in our infectious disease pipeline are approaching commercialization, and several have received initial regulatory approvals: 
+Product 
+Collaborator 
+Phase I 
+Feasibility 
+Phase II 
+Development 
+Phase III 
+Verification & 
+Validation 
+Phase IV 
+Clinical & 
+Regulatory 
+Phase V 
+Commercial 
+Launch 
+DPP HIV-Syphilis System (US) 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+PMA approved 
+DPP Dengue IgM/IgG System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP Dengue NS1 Antigen System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA pending 
+DPP Chikungunya IgM/IgG System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP Zika Chikungunya Dengue IgM/IgG System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP Ebola Antigen System 
+CDC 
+✓ 
+✓ 
+✓ 
+✓ 
+FDA-EUA 
+DPP Fever Assay Asia 
+FIND 
+✓ 
+✓ 
+✓ 
+✓ 
+DPP Fever Assay Africa 
+Paul Allen Foundation 
+✓ 
+✓ 
+✓ 
+DPP Fever Assay Malaysia 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+DPP SARS CoV-2 Antigen 
+BARDA 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP Respiratory Antigen Panel 
+BARDA 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP COVID-19 IgM/IgG System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP SARS CoV-2 IgM/IgG System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE 
+10 
+Table of Contents 
+Sales Channels 
+Our products are sold globally, both directly and through distributors, to hospitals and clinics, physician offices, clinical laboratories, public health organizations, government agencies and consumers. Historically
+we marketed and sold our products only into a handful of countries and regions. During 2021, we expanded our U.S.-based sales, customer service, and marketing team to focus on the COVID-19, HIV-Syphilis, and future DPP platform product
+opportunities. With sales growth as an underlying objective, we are focused on increasing sales in geographies that support higher average selling prices. From lead generation through technical inquiries, Chembio has the internal resources to
+support customers through the commercial process including marketing, sales, sales support, order entry and product support. 
+Automation of U.S. Manufacturing 
+We are automating our U.S. manufacturing processes and expanding our manufacturing capacity. Over the past three years, we have taken delivery of and completed validation of most of our automated manufacturing lines.
+These use vision-guided, robotic operation to improve inspection and quality control. As we transition from manual to automated assembly, we believe the reduced variable costs will improve product gross margins. 
+DPP Technology & Development 
+Our commercially available products employ either our patented DPP technology or traditional lateral flow technology. We believe products developed using our DPP technology can provide superior diagnostic performance
+compared with products that utilize traditional lateral flow technology. 
+Chembio’s history of collaborations have proven the strength and capabilities of the DPP platform to address a diverse range of biomarkers. We are now focusing our R&D resources on delivering products to build a
+portfolio of COVID-19 tests and developing Chembio’s new and expanded product portfolio focused on high average selling price, developed markets, established sales channels, and clinically accepted use cases, where the differentiated capabilities
+of DPP provide a competitive advantage. 
+Competition 
+Many of our competitors are significantly larger and have greater financial, research, manufacturing, and marketing resources. Important competitive factors include product quality, analytical performance, ease of
+use, price, customer service and reputation. Industry competition is based on these and the following additional factors: 
+• 
+patent protection; 
+• 
+scientific expertise; 
+• 
+ability to develop and market products and processes; 
+• 
+ability to obtain required regulatory approvals; 
+• 
+ability to manufacture cost-effective products that meet applicable regulatory requirements; 
+• 
+access to adequate capital; and, 
+• 
+ability to attract and retain qualified personnel. 
+We believe our scientific capabilities and proprietary know-how relating to our patented DPP technology and lateral flow technology are very strong, particularly for the development and manufacture of tests for the
+detection of infectious and other diseases. 
+11 
+Table of Contents 
+Although we have no specific knowledge of any other competitors’ products that could render our products obsolete, if we fail to maintain and enhance our competitive position or fail to introduce new products and
+product features, our customers may decide to use the products developed by our competitors, which could result in a loss of revenues and cash flow. 
+Human Capital 
+As of December 31, 2021, we had 337 full-time equivalent employees, of whom 46 were in administration, 241 were in manufacturing, 28 were in research and development, and 22 were in sales and marketing and customer
+service. Of these employees, approximately 297 were located in the United States, 22 were located in Germany and 18 were located in Brazil. We have never had a work stoppage, and none of our employees are represented by a labor organization or
+subject to any collective bargaining arrangements. We consider our employee relations to be good. 
+Our employees are one of our most important assets and set the foundation for our ability to achieve our strategic objectives, drive operational execution, deliver strong financial performance, advance innovation and
+maintain our quality and compliance programs. The success and growth of our business depends in large part on our ability to attract, retain and develop a diverse population of talented and high-performing employees at all levels of our
+organization. 
+Health, Wellness and Safety 
+The health, wellness and safety of our employees is a priority embedded at every level of our business. We provide our employees upfront and ongoing safety training to ensure that safety policies and procedures are
+effectively communicated and implemented. Personal protective equipment is provided to those employees where needed for the employee to safely perform their job function. 
+Since 2020, in response to the COVID-19 pandemic, we implemented safety protocols and new procedures to protect our employees, including more frequent deep cleaning of the facilities, social distancing and onsite
+COVID-19 testing. 
+Workforce Stability 
+Retaining and developing our employees is an important factor in our continued success and growth. We regularly evaluate our employee retention and turnover rates. With the contraction of the labor force as a result
+of the global pandemic, we have also experienced the effects of the labor shortage in our staffing. We expect the labor shortage to continue in 2022 and will continue to monitor and analyze retention closely to identify any areas of concern. 
+Compensation and Benefits 
+To succeed in a competitive labor market, we have recruitment and retention strategies that we focus on as part of the overall management of our business, including designing our compensation and benefits programs to
+be competitive and align with our strategic and stockholders’ interests. Some of our key employee benefits include eligibility for health insurance, vacation time, a retirement plan, an employee assistance program, life and disability coverage. We
+also have procedures and processes focused on providing employees equitable compensation, regardless of race or gender or other personal characteristics. 
+Impact of the COVID-19 Pandemic 
+The COVID-19 pandemic has disrupted nearly every aspect of the global supply chain, including the manufacturing of some of the key supplies used in our tests. Many suppliers are experiencing shortages of required
+personnel as the result of the tight labor market and underlying raw material commodities. To fulfil our obligations, we have had to identify sources of supplies on a short timeframe and in a markedly increased quantity and have been required to
+seek to identify new sources of materials to replace or augment our past sources. Moreover, scarcity has caused increases in the cost of some supplies. 
+12 
+Table of Contents 
+Governmental Regulation 
+Certain of our activities are subject to regulatory oversight by the FDA under provisions of the Federal Food, Drug, and Cosmetic Act and regulations thereunder, including regulations governing the development,
+marketing, labeling, promotion, manufacturing, and export of diagnostic products. Our clinical laboratory customers are subject to oversight by Centers for Medicare and Medicaid Services, or CMS, pursuant to CLIA, as well as agencies in various
+states. Failure to comply with applicable requirements can lead to sanctions, including withdrawal of products from the market, recalls, refusal to authorize government contracts, product seizures, civil money penalties, injunctions, and criminal
+prosecution. 
+FDA Approval/Clearance Requirements 
+Unless an exemption applies, each medical device that we market or wish to market in the United States must receive 510(k) clearance or Premarket Approval, or PMA. Medical devices that receive 510(k) clearance are
+“cleared” by the FDA to market, distribute, and sell in the United States. Medical devices that obtain a PMA by the FDA are “approved” to market, distribute and sell in the United States. We cannot be certain that 510(k) clearance or PMA approval
+will ever be obtained for any products that have not already obtained 510(k) clearance or PMA approval. Descriptions of the PMA and 510(k) clearance processes are provided below. 
+The FDA decides whether a device line must undergo either the 510(k) clearance or PMA based on statutory criteria that utilize a risk-based classification system. PMA is the FDA process of scientific and regulatory
+review to evaluate the safety and effectiveness of Class III medical devices and, in many cases, Class II medical devices. Class III devices are those that support or sustain human life, are of substantial importance in preventing impairment of
+human health, or which present a potential, unreasonable risk of illness or injury. The FDA uses these criteria to decide whether a PMA or a 510(k) is appropriate, including the level of risk that the agency perceives is associated with the device
+and a determination by the agency of whether the product is a type of device that is similar to devices that are already legally marketed. Devices deemed to pose relatively less risk are placed in either Class I or II. In many cases, the FDA
+requires the manufacturer to submit a 510(k) requesting clearance (also referred to as a premarket notification), unless an exemption applies. The 510(k) must demonstrate that the manufacturer’s proposed device is “substantially equivalent” in
+intended use and in safety and effectiveness to a legally marketed predicate device. A “predicate device” is a pre-existing medical device to which equivalence can be drawn, that is either in Class I or Class II or is a Class III device that was in
+commercial distribution before May 28, 1976, for which the FDA has not yet called for submission of a PMA application. 
+Device classification depends on the device’s intended use and its indications for use. In addition, classification is risk-based, that is, the risk the device poses to the patient and/or the user is a major factor
+in determining the class to which it is assigned. Class I includes devices with the lowest risk and Class III includes those with the greatest risk. 
+Class I devices are those for which safety and effectiveness can be assured by adherence to the FDA’s general regulatory controls for medical devices, or the General Controls,
+which include compliance with the applicable portions of the FDA’s quality system regulations, facility registration and product listing, reporting of adverse medical events, and appropriate, truthful and non-misleading labeling, advertising, and
+promotional materials. Some Class I devices also require premarket clearance by the FDA through the 510(k) process described below. 
+Class II devices are subject to the FDA’s General Controls, and any other special controls as deemed necessary by the FDA to ensure the safety and effectiveness of the device.
+Premarket review and clearance by the FDA for Class II devices is accomplished through the 510(k) process. Pursuant to the Medical Device User Fee and Modernization Act of 2002, unless a specific exemption applies, 510(k) submissions are subject to
+user fees. Certain Class II devices are exempt from this premarket review process. 
+Class III includes devices with the greatest risk. Devices in this class must meet all of the requirements in Classes I and II. In addition, Class III devices cannot be
+marketed until they receive Premarket Approval. 
+The safety and effectiveness of Class III devices cannot be assured solely by the General Controls and the other requirements described above. These devices require formal clinical studies to demonstrate safety and
+effectiveness. Under the Medical Device User Fee and Modernization Act of 2002, PMA applications (and supplemental premarket approval applications) are subject to significantly higher user fees than 510(k) applications, and they also require
+considerably more time and resources. 
+13 
+Table of Contents 
+Rapid HIV tests intended for diagnostic use are regulated as Class III devices. Responsibility for assuring the safety and effectiveness of these tests lies within the Center for Biologics Evaluation and Research’s
+Office of Blood Research and Review, with oversight by the Blood Products Advisory Committee. Approved rapid HIV tests must meet the regulations in the 21 CFR 800 series subparts, under the investigational device exemption, or IDE and PMA pathways. 
+Premarket Approval Pathway 
+We manufacture, market and distribute three rapid HIV tests in the United States. Our HIV 1/2 STAT-PAK Assay, SURE CHECK HIV 1/2 Assay, and DPP HIV 1/2 Assay all have received FDA PMA approval. A PMA application must
+be supported by extensive data including, but not limited to, analytical, preclinical, clinical trials, manufacturing, statutory preapproval inspections, and labeling to demonstrate to the FDA’s satisfaction the safety and effectiveness of the
+device for its intended use. Before a PMA is submitted, a manufacturer must apply for an Investigational Device Exemption (“IDE”). If the device presents a “significant risk,” as defined by the FDA, to human health, the FDA requires the device
+sponsor to file an IDE application with the FDA and obtain IDE approval prior to initiation of enrollment of human subjects for clinical trials. The IDE provides the manufacturer with a legal pathway to perform clinical trials on human subjects
+where without the IDE, only approved medical devices may be used on human subjects. 
+The IDE application must be supported by appropriate data, such as analytical, animal and laboratory testing results, manufacturing information, and an Investigational Review Board, or IRB approved protocol showing
+that it is safe to test the device in humans and that the testing protocol is scientifically sound. If the clinical trial design is deemed to have “non-significant risk,” the clinical trial may be eligible for “abbreviated” IDE requirements. In
+some instances, clinical trials for in vitro diagnostic medical devices may be exempt from the more burdensome IDE requirements if certain labeling requirements are met. 
+A clinical trial may be suspended by either the FDA or the Investigational Review Board at any time for various reasons, including a belief that the risks to the study participants outweigh the benefits of
+participation in the study. Even if a study is completed, clinical testing results may not demonstrate the safety and efficacy of the device, or they may be equivocal or otherwise insufficient to obtain approval of the product being tested. After
+the clinical trials have been completed, if at all, and the clinical trial data and results are collected and organized, a manufacturer may complete a PMA application. 
+After a PMA application is sufficiently complete, the FDA will accept the application and begin an in-depth review of the submitted information. By statute, the FDA has 180 days to review the “accepted application,”
+although, generally, review of the application can take between one and three years, but it may take significantly longer. During this review period, the FDA may request additional information or clarification of information already provided. Also,
+during the review period, an advisory panel of experts from outside the FDA may be convened to review and evaluate the application and provide recommendations to the FDA as to the approvability of the device. The preapproval inspections conducted
+by the FDA include an evaluation of the manufacturing facility to ensure compliance with the FDA’s quality systems regulations or QSR, as well as inspections of the clinical trial sites by the Bioresearch Monitoring group to evaluate compliance
+with good clinical practice and human subject protections. New PMA applications or PMA supplements are required for modifications that affect the safety or effectiveness of the device, including, for example, certain types of modifications to the
+device’s indication for use, manufacturing process, labeling and design. Significant changes to an approved PMA require a 180-day supplement, whereas less substantive changes may utilize a 30-day notice, or a 135-day supplement. Premarket approval
+supplements often require submission of the same type of information as a premarket approval application, except that the supplement is limited to information needed to support any changes from the device covered by the original premarket approval
+application, and it may not require as extensive clinical data or the convening of an advisory panel. 
+Our HIV 1/2 STAT-PAK Assay PMA application number BP050009/0 and our SURE CHECK 1/2 HIV Assay PMA application number BP050010/0 were approved by the FDA in May 2006. Our DPP HIV 1/2 Assay PMA application number
+BP120032/0 was approved by the FDA in December 2012. Our DPP HIV Syphilis Assay PMA application number BP180191/0 was approved by the FDA in October 2020. 
+14 
+Table of Contents 
+510(k) Clearance Pathway 
+We are currently developing products that either will or are likely to require an FDA 510(k) clearance. We anticipate submitting a 510(k) for each such product to demonstrate that such proposed device is
+substantially equivalent to a previously cleared 510(k) device or a device that was in commercial distribution before May 28, 1976, for which the FDA has not yet called for the submission of a 510(k). The FDA’s 510(k) clearance pathway usually
+takes from three to twelve months but could take longer. In some cases the FDA may require additional information, including clinical data, to make a determination regarding substantial equivalence. 
+If a device receives 510(k) clearance, any modification that could significantly affect its safety or effectiveness, or that would constitute a new or major change in its intended use, will require a new 510(k) clearance or, depending on the
+modification, a PMA. The FDA requires each device manufacturer to determine whether the proposed change requires submission of a new 510(k) or a PMA, but the FDA can review any such decision and, if it disagrees with the manufacturer’s
+determination, can require the manufacturer to cease marketing and/or recall the modified device until 510(k) clearance or PMA of the modified device is obtained. 
+Clinical Laboratory Improvement Amendments of 1988 
+A manufacturer of a test categorized as moderately complex may request that categorization of the test be waived through a CLIA Waiver by Application, or CW, submission to the FDA. When a test is categorized as
+waived, it may be performed by laboratories with a Certificate of Waiver, such as a physician’s office outreach setting. In a CW submission, the manufacturer provides evidence to the FDA that a test meets the CLIA statutory criteria for waiver
+CLIA, a walk-in clinic or an emergency room provides CMS authority over all laboratory testing, except research that is performed on humans in the United States. The Division of Laboratory Services, within the Survey and Certification Group under
+the CMS, has the responsibility for implementing the CLIA program. 
+The CLIA program is designed to establish quality laboratory testing by ensuring the accuracy, reliability and timeliness of patient test results. Under CLIA, a laboratory is a facility that does laboratory testing
+on specimens derived from humans and used to provide information for the diagnosis, prevention or treatment of disease, or impairment of, or assessment of health. Under the CLIA program, unless waived, laboratories must be certified by the
+government, satisfy governmental quality and personnel standards, undergo proficiency testing, be subject to inspections and pay fees. We have received a CLIA waiver for all of our lateral flow rapid HIV tests that we market in the United States.
+Specifically, the CLIA waiver was granted by the FDA for HIV 1/2 STAT-PAK in November 2006, for SURE CHECK HIV 1/2 in October 2007, and for DPP HIV 1/2 in October 2014. 
+Emergency Use Authorizations (EUA) 
+A formal request to issue an EUA generally should not be submitted until the Secretary of HHS has issued an EUA declaration under section 564(b)(1). In particular, although section 564 allows FDA to issue an EUA for
+preparedness purposes, in such cases the HHS Secretary must first declare that circumstances exist justifying such an authorization in advance of an actual emergency based on a formal determination of a significant potential for emergency or a
+material threat determination. During the effective period of the HHS Secretary’s EUA declaration, FDA may authorize the introduction of a medical product into interstate commerce when the product is intended for use during an actual or potential
+emergency. EUA candidate products include medical products and uses that are not approved, cleared, or licensed under sections 505, 510(k), and 515 of the FD&C Act or section 351 of the PHS Act. 
+After the requisite determination and declaration have been issued, and after feasible and appropriate consultations, FDA may issue an EUA only if FDA concludes that the following four statutory criteria for issuance
+have been met for 1) Serious or Life-Threatening Disease or conditions, 2) evidence of effectiveness, 2) Risk –Benefit Analysis, 4) No Alternatives. A sponsor seeking an EUA can submit its formal request in the form of an EUA submission, which
+includes data for clinical studies, non-clinical laboratory studies to assess the safety and effectiveness of the product as well as the discussion of Risks and Benefits of the product. 
+FDA will specify the effective date of an EUA issued under section 564. In general, an EUA will remain in effect for the duration of the EUA declaration under which it was issued which describes termination of an EUA
+declaration and its impact on existing EUAs. 
+15 
+Table of Contents 
+Pervasive and Continuing FDA Regulation 
+A host of regulatory requirements apply to our approved devices, including: the quality system regulation, which requires manufacturers to follow elaborate design, testing, control, documentation and other quality
+assurance procedures; the Medical Reporting Regulations, which require manufacturers to report to the FDA specified types of adverse events involving their products; labeling regulations; and the FDA’s general prohibition against promoting products
+for unapproved or “off-label” uses. Some Class II devices are subject to special controls-such as performance standards, post-market surveillance, patient registries, and FDA guidelines-that do not apply to Class I devices. 
+The regulatory requirements that apply to our approved products classified as medical devices include: 
+• 
+product listing and establishment registration, which helps facilitate FDA inspections and other regulatory action; 
+• 
+QSR, which require manufacturers, including third-party manufacturers, to follow stringent design, testing, control, documentation and other quality assurance procedures during all aspects of the development
+and manufacturing process; 
+• 
+labeling regulations and FDA prohibitions against the promotion of products for uncleared, unapproved or off-label use or indication; 
+• 
+clearance of product modifications that could significantly affect safety or efficacy or that would constitute a major change in intended use of one of our cleared devices; 
+• 
+approval of product modifications that affect the safety or effectiveness of one of our cleared devices; 
+• 
+medical device reporting regulations, which require that manufacturers comply with FDA requirements to report if their device may have caused or contributed to a death or serious injury, or has malfunctioned
+in a way that would likely cause or contribute to a death or serious injury if the malfunction of the device or a similar device were to recur; 
+• 
+post-approval restrictions or conditions, including post-approval study commitments; 
+• 
+post-market surveillance regulations, which apply when necessary to protect the public health or to provide additional safety and effectiveness data for the device; 
+• 
+the FDA’s recall authority, whereby it can ask, or under certain conditions order, device manufacturers to recall from the market a product that is in violation of governing laws and regulations; 
+• 
+regulations pertaining to voluntary recalls; and, 
+• 
+notices of corrections or removals. 
+Our Medford, New York facility is currently registered as an establishment with the FDA. We and any third-party manufacturers are subject to announced and unannounced inspections by the FDA to determine our
+compliance with QSR and other regulations. 
+Government Regulation of Medical Devices for Animal Subjects 
+We currently offer two veterinary devices in the United States: DPP VetTB Assay for Cervids and DPP VetTB Assay for Elephants. Diagnostic tests for animal health infectious diseases, including our veterinary devices
+for the prevention and/or treatment of animal disease, are regulated in the U.S. by the Center for Veterinary Biologics within the U.S. Department of Agriculture Animal and Plant Health Inspection Service, or APHIS, under the Virus, Serum, and
+Toxin Act of 1913. As a requirement, our veterinary devices were approved by APHIS before they could be sold in the U.S. 
+16 
+Table of Contents 
+The APHIS regulatory approval process involves the submission of product performance data and manufacturing documentation. Following regulatory approval to market a product, APHIS requires that each lot of product be
+submitted for review before release to customers. In addition, APHIS requires special approval to market products where test results are used in part for government-mandated disease management programs. 
+Climate Change and Environmental Laws 
+The medical device industry is increasingly becoming subject of scrutiny, stringent regulation and the demand for green, sustainable products. We are focused on monitoring these increasing requirements for efficient
+and accurate processes for hazardous substance handling, supplier disclosures, and regulatory reporting in order to comply with numerous global health and environmental regulatory requirements and restrictions. 
+We believe that we are in compliance in all material respects with all foreign, federal, state, and local environmental regulations applicable to our manufacturing facilities. The cost of ongoing compliance with such
+regulations does not have a material effect on our operations. 
+Intellectual Property 
+Intellectual Property Strategy 
+Our intellectual property strategy is to: (1) build our own intellectual property portfolio around our DPP technology and optical analyzers; (2) pursue licenses, trade secrets and know-how within the area of rapid
+point-of-care testing; and, (3) develop and acquire proprietary positions to certain reagents. 
+DPP Intellectual Property 
+We have obtained patent coverage on our DPP technology, including numerous patents in the United States, and one or more patents in Australia, Brazil, Canada, China, Columbia, Eurasia (Russia), European Union
+(fourteen European countries), Hong Kong, Israel, India, Indonesia, Japan, Korea, Malaysia, Mexico, Poland, Singapore, South Africa, Thailand, and the United Kingdom. Additional patent applications on our DPP technology are pending in the United
+States, as well as in foreign countries such as Australia, Brazil, Canada, China, the European Union, India, Indonesia, Malaysia, Mexico, Peru, Singapore and Thailand. 
+DPP technology provides us with freedom to operate and enables us to develop tests with better performance and capabilities compared with tests built on traditional lateral flow platforms. These advantages have
+allowed us to enter into multiple technology collaborations based upon DPP technology, which we believe will provide new manufacturing and marketing opportunities. We have filed additional patent applications that we believe will strengthen the DPP
+intellectual property and have also filed for patent protection for certain other point-of-care technologies or applications thereof. 
+We have also obtained patent coverage on our optical-based analyzer technology in the United States as well as in several EU countries. 
+Trademarks 
+We have filed and obtained trademarks for our company name CHEMBIO and CHEMBIO DIAGNOSTIC SYSTEMS, INC. as well as for many of our products, including DPP, SURE CHECK, STAT-VIEW, STAT-PAK, and NEXT GENERATION DPP, as
+well as for the SampleTainer and DPP Micro Reader, which are used with certain DPP products. Our trademarks have been registered in the United States and certain other countries around the world. 
+Trade Secrets and Know-How 
+We have developed a substantial body of trade secrets and know-how relating to the development and manufacture of lateral flow and DPP-based diagnostic tests, including the sourcing and optimization of materials for
+such tests, and methods to maximize sensitivity, speed-to-result, specificity, stability and reproducibility of our tests. We possess proprietary know-how to develop tests for multiple conditions using colored particles. Our formulations enable
+long shelf lives of our rapid HIV and other tests, providing us with an important competitive advantage. 
+17 
+Table of Contents 
+Rapid Diagnostic Technology and Reagent Licenses 
+We seek licenses and/or redesigns of products that we believe to be in our best interests. Because of the costs and other negative consequences of time consuming patent litigation, we often attempt to obtain a
+license on reasonable terms. The peptides used in our rapid HIV tests were licensed to us by one or more third parties. We also have licensed the antigens used in other tests including our Syphilis, Tuberculosis, Leptospirosis, Leishmaniasis and
+Chagas tests, and we may enter into other license agreements. In prior years, we concluded license agreements related to intellectual property rights owned by the United States associated with HIV-1 and a sub-license agreement for HIV-2 with
+Bio-Rad Laboratories N.A., the exclusive licensee of the Pasteur Institute’s HIV-2 intellectual property estate. 
+Available Information 
+We are required to file annual, quarterly and current reports, proxy statements and other information with the U.S. Securities and Exchange Commission. The SEC maintains a website at www.sec.gov that contains
+reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. 
+Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, proxy statements and amendments to those documents filed or furnished pursuant to Section 13(a) or 15(d) of the Securities
+Exchange Act of 1934, are also available free of charge on our website at www.chembio.com as soon as reasonably practicable after such reports are electronically filed with or furnished to the SEC. 
+Investors should note that we currently announce material information to our investors and others using filings with the SEC, press releases, public conference calls, webcasts or our website (www.chembio.com),
+including news and announcements regarding our financial performance, key personnel, our brands and our business strategy. Information that we post on our corporate website could be deemed material to investors. We encourage investors to review the
+information we post on these channels. We may from time to time update the list of channels we will use to communicate information that could be deemed material and will post information about any such change on www.chembio.com. The information on
+our website is not, and shall not be deemed to be, a part hereof or incorporated into this or any of our other filings with the SEC. 
+Corporate Information 
+Our principal executive offices are located at 555 Wireless Boulevard, Hauppauge, New York 11788. Our telephone number is (631) 924-1135. Our website address is www.chembio.com. The information contained in, or
+accessible through, our corporate website does not constitute part of this report. 
+18 
+Table of Contents
\ No newline at end of file
diff --git a/raw/filings/0001092662/2021/0001140361-22-007735/item13.txt b/raw/filings/0001092662/2021/0001140361-22-007735/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..8919b934ab1d4a68b34b470fc0327342431a05b2
--- /dev/null
+++ b/raw/filings/0001092662/2021/0001140361-22-007735/item13.txt
@@ -0,0 +1,4 @@
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE. 
+The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act not later than 120 days after the end of the
+fiscal year covered by this Annual Report on Form 10-K.
\ No newline at end of file
diff --git a/raw/filings/0001092662/2021/0001140361-22-007735/item9a.txt b/raw/filings/0001092662/2021/0001140361-22-007735/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e86ea9c42ad1a6cc72032d4a75373121261a8f1c
--- /dev/null
+++ b/raw/filings/0001092662/2021/0001140361-22-007735/item9a.txt
@@ -0,0 +1,37 @@
+ITEM 9A. 
+Controls and Procedures 
+Evaluation of Disclosure Controls and Procedures 
+Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures, as defined by Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as
+of December 31, 2021. Based on the evaluation of our disclosure controls and procedures, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2021 at the
+reasonable assurance level. 
+Management’s Report on Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Securities
+Exchange Act of 1934 as a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer and effected by the board of directors, management and other personnel to provide reasonable assurance regarding
+the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that: 
+• 
+pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; 
+• 
+provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
+expenditures of the company are being made in accordance with authorizations of management and directors of the company; and 
+• 
+provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. As a result, even those systems determined to be effective can provide only reasonable assurance with respect to
+financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance
+with the policies or procedures may deteriorate. 
+Under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, our management evaluated the effectiveness of our internal control over financial reporting as of December 31, 2021. In making their
+assessment of internal control over financial reporting, our management used the criteria described in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Our evaluation
+included documenting, evaluating and testing of the design and operating effectiveness of our internal control over financial reporting. Based on this evaluation, we concluded that our controls over financial reporting were effective as of
+December 31, 2021. 
+67 
+Table of Contents 
+Previously Identified Material Weaknesses in Internal Control Over Financial Reporting 
+None. 
+Changes in Internal Control over Financial Reporting 
+There were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Securities Exchange Act of 1934 during the period covered by this Annual Report on
+Form 10-K that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+Inherent Limitations of Internal Control 
+Management, including the Company’s Chief Executive Officer and Chief Financial Officer, does not expect that the Company’s internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and
+operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints and the benefits of controls
+must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of internal control can provide absolute assurance that all control issues and instances of fraud, if any, have been detected.
+Also, any evaluation of the effectiveness of internal controls in future periods are subject to the risk that those internal controls may become inadequate because of changes in business conditions, or that the degree of compliance with the
+policies and procedures may deteriorate.
\ No newline at end of file
diff --git a/raw/filings/0001092662/2021/0001140361-22-007735/rp_note.txt b/raw/filings/0001092662/2021/0001140361-22-007735/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0001092662/2021/0001140361-22-007735/rpt_disclosure.txt b/raw/filings/0001092662/2021/0001140361-22-007735/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..3911a022ed701e1870e2550f650ac2159db8372b
--- /dev/null
+++ b/raw/filings/0001092662/2021/0001140361-22-007735/rpt_disclosure.txt
@@ -0,0 +1,105 @@
+Certain Relationships and Related-Person Transactions 
+Procedures for Approval of Related Person Transactions 
+The board of directors reviews all transactions involving us in which any of our
+directors, director nominees, significant stockholders and executive officers and their immediate family members are participants, in order to determine whether any such party has a direct or indirect material interest in the transaction. All
+directors, director nominees and executive officers must notify us of any proposed transaction involving us in which such person has a direct or indirect material interest. The proposed transaction is then reviewed by either the board as a whole or
+the audit committee, which determines whether to approve the transaction. After such review, the reviewing body approves the transaction only if it determines that the transaction is in, or not inconsistent with, the best interests of our company and
+stockholders. 
+Conflict of Interest Policy 
+The board of directors has adopted a Conflict of Interest Policy applicable to all
+directors, officers, and employees of our company and our subsidiaries. 
+The Conflict of Interest Policy requires each director and executive officer,
+including their immediate family members, to provide written notice of any potential related-party transaction, defined by the policy to mirror the definition of Item 404 of Regulation S-K of the SEC (with the exception that the policy includes a
+monetary threshold of $100,000 as opposed to the threshold of $120,000 set by Item 404) to the Chair of the Board (or to the Chief Executive Officer if such transaction involves the Chair of the Board, or to the Chief Financial Officer if such
+transaction involves the Chief Executive Officer), including all information that the Chair of the Board, the Chief Executive Officer or the Chief Financial Officer may request. Upon receiving all relevant information, the board may approve the
+transaction if it determines that the transaction is in our best interests and fair to us, may require modifications to the transaction to make it acceptable for approval, or may reject it. The board may also establish guidelines for ongoing
+management of a specific related-party transaction. The policy requires that continuing related-party transactions are reviewed on at least an annual basis. Additionally, the policy requires that all directors and executive officers complete a
+director and officer questionnaire in connection with each of our annual proxy statements, in which they are asked to disclose family relationships and other related-party transactions. 
+Since January 1, 2021, we have not engaged in any related-party transactions in
+which the amount involved exceeded $100,000 and in which any of our directors or executive officers or any holder of more than 5% of our common stock, or any member of the immediate family of any of these persons or entities controlled by any of
+them, had or will have a direct or indirect material interest, other than the compensation arrangements described in “Director Compensation” and “Executive Compensation.” It is our intention to ensure that any future transactions between us and our
+officers, directors and significant stockholders and their affiliates are approved by the audit committee and a majority of the members of the board, including a majority of the independent and disinterested members of the board, and are on terms no
+less favorable to us than those that we could obtain from unaffiliated third parties. 
+27 
+Beneficial Ownership
+of Common Stock 
+The following table sets forth the number of outstanding
+shares of common stock beneficially owned, and the percentage of the class beneficially owned, as of March 28, 2022, by: 
+● 
+each named executive officer included in “Executive Compensation—Summary Compensation Table”; 
+● 
+each current director and the additional nominee for election as a director; and 
+● 
+all of our current executive officers and directors and the additional nominee for election as a director, as a group. 
+The number of shares of common stock beneficially owned
+by each person is determined under the rules of the SEC. Under these rules, beneficial ownership includes any shares as to which the individual has sole or shared voting power or investment power and also any shares that the individual has the right
+to acquire by May 27, 2022 (60 days after March 28, 2022) through the exercise or conversion of a security or other right. Unless otherwise indicated, each person has sole investment and voting power, or shares such power with a family member, with
+respect to the shares set forth in the following table. The inclusion in this table of any shares deemed beneficially owned does not constitute an admission of beneficial ownership of those shares for any other purpose. As of March 28, 2022, there
+were 30,216,016 shares of common stock outstanding. Shares not outstanding, but deemed beneficially owned by virtue of the right of a person to acquire those shares, are treated as outstanding only for purposes of determining the number and percent
+of shares of common stock owned by such person or group. There are no persons known to us to be the beneficial owners of more than five percent of the shares of common stock outstanding as of March 28, 2022. Unless otherwise noted below, the address
+of each person listed in the table is in care of Chembio Diagnostics, Inc., 555 Wireless Boulevard, Hauppauge, New York 11788. 
+Common Stock 
+Named Executive Officers, Directors and Director Nominees 
+Shares 
+% 
+Richard L. Eberly(1) 
+248,342 
+* 
+% 
+Neil A. Goldman(2) 
+45,903 
+* 
+Javan Esfandiari(3) 
+263,412 
+* 
+Lawrence J. Steenvoorden 
+— 
+— 
+Katherine L. Davis(4) 
+142,709 
+* 
+John G. Potthoff(5) 
+137,213 
+* 
+David W.K. Acheson(6) 
+28,674 
+* 
+David W. Bespalko(7) 
+37,480 
+* 
+Leslie Teso-Lichtman 
+— 
+— 
+All current executive officers and directors as a group (10 persons)(8) 
+997,450 
+3.3 
+* 
+Less than 1%. 
+(1) 
+Includes (a) 116,572 shares issuable under restricted stock units and 80,357 shares issuable under options exercisable by May 27, 2022 and (b) 51,413 shares held by Mr.
+Eberly’s spouse. 
+(2) 
+Mr. Goldman resigned as our Executive Vice President and Chief Financial Officer effective as of November 5, 2021. 
+(3) 
+Includes 152,161 shares issuable under options exercisable by May 27, 2022. 
+(4) 
+Includes 36,252 shares issuable under options exercisable by May 27, 2022. 
+(5) 
+Includes 83,127 shares issuable under options exercisable by May 27, 2022. 
+(6) 
+Includes 23,781 shares issuable under options exercisable by May 27, 2022. 
+(7) 
+Includes 31,746 shares issuable under options exercisable by May 27, 2022. 
+(8) 
+Includes 52,660 shares issuable under options exercisable, by May 27, 2022. 
+28 
+Director
+Compensation 
+Our director compensation program is intended to enhance
+our ability to attract, retain and motivate non-employee directors of exceptional ability and to promote the common interest of directors and stockholders in enhancing the value of the common stock. The board of directors reviews director
+compensation annually based on recommendations by the nominating and corporate governance committee. The nominating and corporate governance committee has the sole authority to engage a consulting firm to evaluate director compensation. 
+Under our non-employee director compensation program,
+each non-employee director is eligible to receive compensation for board and committee service consisting of annual cash retainers and equity awards. Directors also may be paid for serving on ad hoc committees of the board. Richard Eberly, our
+President and Chief Executive Officer, does not receive any additional compensation for his service as a director. 
+Under our non-employee director compensation program, in
+2021 our non-employee directors were eligible to receive the following annual cash compensation for their service on the board and the board’s standing committees:
\ No newline at end of file
diff --git a/raw/filings/0001092662/2022/0001140361-23-014526/filing.txt b/raw/filings/0001092662/2022/0001140361-23-014526/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..3a58ee235afeb19b0fc288d9623973e8675cb9f6
--- /dev/null
+++ b/raw/filings/0001092662/2022/0001140361-23-014526/filing.txt
@@ -0,0 +1,6058 @@
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cemi:Claim 
+UNITED STATES 
+Securities and Exchange Commission 
+Washington, D.C. 20549 
+FORM 10-K 
+☒ 
+ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the fiscal year ended December 31, 2022 
+or 
+☐ 
+TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the transition period from _______ to ______ . 
+Commission File No. 001-35569 
+CHEMBIO DIAGNOSTICS, INC. 
+(Exact name of registrant as specified in its charter) 
+Nevada 
+88-0425691 
+(State or other jurisdiction of incorporation or organization) 
+(I.R.S. Employer Identification No.) 
+3661 Horseblock Rd , Medford NY 
+11763 
+(Address of principal executive offices) 
+(Zip Code) 
+Registrant’s telephone number, including area code ( 631 ) 924-1135 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of each class 
+Trading Symbol 
+Name of each exchange on which registered 
+Common Stock, $0.01 par value 
+CEMI 
+The Nasdaq Stock Market LLC 
+Securities registered pursuant to Section 12(g) of the Act: 
+None 
+(Title of Class) 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒ 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒ 
+Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
+preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ 
+Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§
+232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐ 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging
+growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. 
+Large accelerated filer ☐ 
+Accelerated filer ☐ 
+Non-accelerated filer ☒ 
+Smaller reporting company ☒ 
+Emerging growth company ☐ 
+If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised
+financial accounting standards provided pursuant to Section 13(a) of the Exchange Act ☐ 
+Indicate by checkmark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of internal control over financial
+reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ 
+If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing
+reflect the correction of an error to previously issued financial statements. ☐ 
+Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the
+registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐ 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ 
+As of the last business day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of voting and non-voting common equity held by
+non-affiliates was $ 18,739,117 . 
+As of March 24, 2023, the registrant had 36,725,858 
+shares of common stock outstanding. 
+Documents Incorporated By Reference 
+None. 
+TABLE OF CONTENTS 
+Page 
+PART I 
+ITEM 1. 
+BUSINESS 
+3 
+ITEM 1A. 
+RISK FACTORS 
+16 
+ITEM 1B. 
+UNRESOLVED STAFF COMMENTS 
+50 
+ITEM 2. 
+PROPERTIES 
+50 
+ITEM 3. 
+LEGAL PROCEEDINGS 
+50 
+ITEM 4. 
+MINE SAFETY DISCLOSURES 
+50 
+PART II 
+ITEM 5. 
+MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+50 
+ITEM 6. 
+[RESERVED] 
+51 
+ITEM 7. 
+MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+51 
+ITEM 8. 
+FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+61 
+ITEM 9. 
+CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 
+62 
+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+62 
+ITEM 9B. 
+OTHER INFORMATION 
+63 
+ITEM 9C. 
+DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS 
+64 
+PART III 
+ITEM 10. 
+DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
+64 
+ITEM 11. 
+EXECUTIVE COMPENSATION 
+70 
+ITEM 12. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+76 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+77 
+ITEM 14. 
+PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+79 
+PART IV 
+ITEM 15. 
+EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 
+79 
+ITEM 16. 
+FORM 10-K SUMMARY 
+82 
+SIGNATURES 
+83 
+Unless the context requires otherwise, the words ‘‘we,’’ ‘‘us,’’ ‘‘our,’’ ‘‘our company,’’ ‘‘Chembio’’ and similar terms refer to Chembio Diagnostics, Inc. and its consolidated subsidiaries. 
+DPP, STAT-PAK, STAT-VIEW and SURE CHECK are our registered trademarks, and CHEMBIO and MICRO READER are our trademarks. For convenience, these trademarks appear in this report without ® and ™ symbols, and that
+practice does not mean that we will not assert, to the fullest extent under applicable law, our rights to the trademarks. 
+Table of Contents 
+FORWARD-LOOKING STATEMENTS AND STATISTICAL ESTIMATES 
+This report contains statements reflecting our views about our future performance that constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These
+forward-looking statements are generally identified through the inclusion of words such as “anticipate,” “believe,” “contemplate,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “objective,” “outlook,” “plan,” “potential,” “project,”
+“seek,” “should,” “strategy,” “target,” “will,” “would” or variations of such words or similar expressions. All statements addressing our future operating performance, and statements addressing events and developments that we expect or anticipate
+will occur in the future, including our proposed merger with Biosynex SA, are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are based upon currently available
+information, operating plans, and projections about future events and trends. 
+This report contains estimates, projections and other data concerning our industry, our business and the markets for our products. Where expressly stated, we obtained this industry, business, market and other data
+from reports, research surveys, studies and similar data prepared by the World Health Organization, or WHO. We also include data that we have compiled, obtained, identified or otherwise derived from reports, research surveys, studies and similar
+data prepared by market research firms and other third parties, industry, medical and general publications, government data and similar sources. Other than WHO, we do not expressly refer to the sources from which this data is derived. 
+Forward-looking statements and statistical estimates inherently involve risks and uncertainties that could cause actual results to differ materially from those predicted or expressed in this
+report. These risks and uncertainties include those described in “Item 1A. Risk Factors” of Part I of this report. Investors are cautioned not to place undue reliance on any forward-looking statements or statistical estimates, which speak only as
+of the date they are made. We undertake no obligation to update any forward-looking statement or statistical estimate, whether as a result of new information, future events or otherwise. 
+PART I 
+ITEM 1. 
+BUSINESS 
+Overview 
+Chembio Diagnostics, Inc. (“Chembio”) and its subsidiaries (collectively with Chembio, the “Company”) develop and commercialize point-of-care tests used to detect and diagnose infectious diseases, including
+sexually transmitted disease, insect vector and tropical disease, COVID-19 and other viral and bacterial infections, enabling expedited treatment. 
+The Company’s product portfolio is based upon our proprietary DPP technology, a diagnostic platform that provides high-quality, cost-effective results in 15 to 20 minutes using fingertip blood, nasal swabs and
+other sample types. The DPP technology platform addresses the rapid diagnostic test market, which includes infectious diseases such as sexually transmitted infections and HIV, and Women’s Health. Compared with traditional lateral flow technology,
+the DPP technology platform can provide: 
+• 
+Enhanced sensitivity and specificity: This is achieved via the Company’s proprietary approach to separating the sample path from the buffer path, together with patent and other proprietary strategies, which differ significantly
+from traditional lateral flow test. 
+• 
+Advanced multiplexing capabilities: Through advanced multiplexing, the DPP platform can detect and differentiate up to eight distinct test results from a single patient sample, which can deliver greater clinical value than other rapid
+tests currently on the market. 
+• 
+Objective results: For some diagnostic applications, the Company’s easy-to-use, highly portable, battery-operated DPP Micro Reader optical analyzers can report accurate results in approximately 15 seconds, making it well-suited for
+decentralized testing where real-time results enable patients to be clinically assessed while they are still on site. Objective results produced by the DPP Micro Reader can reduce the possibility of the types of human error that can be
+experienced in the visual interpretations required by many rapid tests. 
+3 
+Table of Contents 
+The Company targets the market for rapid diagnostic test solutions for infectious diseases, which is driven by the high prevalence of infectious diseases globally, an increase in the geriatric population, growing
+demand for rapid test results, and advancements in multiplexing. The Company has a broad portfolio of infectious disease products, which prior to 2020 were focused principally on sexually transmitted disease and fever and tropical disease. In
+February 2020 the Company began the process to leverage the DPP technology platform to address the acute and escalating need for diagnostic testing. The Company is continuing to pursue or has pursued: 
+• 
+a 510(k) clearance from the U.S. Food and Drug Administration, (the "FDA") for the DPP SARS-CoV-2 Antigen test system; 
+• 
+an Emergency Use Authorization (“EUA”) from the FDA for the DPP Respiratory Antigen Panel; and 
+• 
+a Clinical Laboratory Improvement Amendment (“CLIA”), waiver from the FDA for the DPP HIV-Syphilis test system, which was received in February 2023. 
+For additional information about our existing and proposed product offerings, please see “—Products” below. Our products are sold globally, directly and through distributors, to medical laboratories and hospitals,
+governmental and public health entities, nongovernmental organizations, medical professionals, and retail establishments. We continue to seek to expand our commercial distribution channels. 
+Pending Merger with Biosynex SA 
+The Company entered into an Agreement and Plan of Merger (the “Merger Agreement”), dated as of January 31, 2023, with Biosynex SA, a French société anonyme (“Biosynex”), and Project Merci Merger Sub, Inc., a Nevada
+corporation and wholly-owned indirect subsidiary of Biosynex (the “Purchaser”). Pursuant to the Merger Agreement, on February 14, 2023, the Purchaser commenced a tender offer (the “Offer”) to purchase all of the issued and outstanding shares of
+the Company’s common stock, par value $0.01 per share (the “Shares”), for a purchase price of $0.45 per share, net to the seller in cash, without interest and subject to any required tax withholding. On March 15, 2023, Biosynex announced an
+extension of the Offer until 6:00 p.m., New York City time, on March 28, 2023. Subsequently, on March 29, 2023, Biosynex announced an extension of the Offer until 6:00 p.m., New York City time, on April 12, 2023. 
+If the conditions to the Offer are satisfied and the Offer closes, Purchaser would acquire all remaining Chembio shares by a merger of Purchaser with and into
+Chembio (the “Merger”), with Chembio surviving the Merger as a wholly-owned indirect subsidiary of Biosynex. At the effective time of the Merger (the “Effective Time”), each Share issued and outstanding immediately prior to the Effective Time
+(including shares paid to holders of vested Chembio restricted stock units) will be converted into the right to receive $0.45 per share. Stock options that are outstanding immediately prior to the Effective Time will automatically terminate for
+no consideration. 
+The Merger Agreement and the transactions contemplated thereby, including the Merger, were unanimously approved by the Company’s Board of Directors. Completion of the Merger is subject to certain customary
+conditions as set forth in the Merger Agreement and the successful completion of the Offer. There can be no assurance that the Merger will be consummated on the terms described above or at all. 
+The foregoing description of the Merger Agreement and the transactions contemplated thereby, including the Offer, does not purport to be complete and is subject to, and qualified in its entirety by reference to,
+the full text of the Merger Agreement, which has been filed as Exhibit 2.1 to our Current Report on Form 8-K filed with the SEC on January 31, 2023. 
+Likely Default Under Credit Agreement 
+On September 3, 2019, we and certain of our subsidiaries, as guarantors, entered into the Credit Agreement and Guaranty (the “Credit Agreement”) with Perceptive
+Credit Holdings II, LP (the “Lender”), under which we received a $20.0 million senior secured term loan that was drawn in full on September 4, 2019. The Credit Agreement is secured by a first priority lien on substantially all of our property
+and assets. The Credit Agreement contains financial covenants requiring that we (a) maintain aggregate unrestricted cash of not less than $3.0 million at all times, and (b) achieve specified minimum total revenue requirements for the twelve
+months preceding each quarter end. 
+The Credit Agreement has a September 3, 2023 maturity date, and we do not currently believe that replacement debt or equity financing arrangements are
+or will be available to us or, if available to us, will be on acceptable terms. We do not believe that we will be in compliance with the minimum revenue covenant in the Credit Agreement for the four fiscal quarters ended March 31, 2023. Our
+Lender has previously informed us that it will not agree to any restructuring of the Credit Agreement, and as a result we may be forced to pursue a bankruptcy or restructuring proceeding when the debt matures (or earlier if the lender
+accelerates following a breach of the minimum total revenue covenant) or pursue a transaction or financing arrangement that could be dilutive to stockholders. 
+Operating Results and Working Capital 
+Total revenues were $49.5 million, an increase of 3.6% from 2021, and net product sales were $47.1 million, an increase of 35.6% from 2021. Our loss from operations was $23.6 million in 2022 compared to $31.1
+million in 2021. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Consolidated Results of Operations.” 
+4 
+Table of Contents 
+In 2022 we continued to invest in automating our test manufacturing processes, most of which are now based in the United States. Among other actions, we expanded our manufacturing capabilities by validating and
+implementing automated lines. Our transition from manual to automated assembly is intended to add capacity, reduce variable costs and improve product margins. In order to address challenging economic conditions and implement our business
+strategy, we continued to execute a program to reduce operating expenses and better align our costs with revenues by eliminating positions that were no longer aligned with our strategy. Our cash and cash equivalents totaled $18.2 million at
+December 31, 2022, compared to $28.8 million at December 31, 2021. 
+The Company’s future working capital needs will depend on many factors, including the rate of its business and revenue growth, its ability to achieve operating profitability, the availability and cost of human,
+material and other resources required to build and deliver products in accordance with its existing or future product orders, the timing of its continuing automation of manufacturing, and the timing of its investment in research and development
+as well as sales and marketing. If the Company is unable to increase its revenues and manage its expenses in accordance with its operating plan, it may need to reduce the level or slow the timing of the growth plans contemplated by its operating
+plan, which would likely curtail or delay the growth in its business contemplated by its operating plan and could impair or defer its ability to achieve profitability and generate cash flow, or to seek to raise additional funds through debt or
+equity financing, strategic relationships, or other arrangements. All DPP tests are developed and manufactured in the United States and are the subject of a range of domestic and global patents and patents pending. 
+Going Concern Considerations 
+The Company continued to experience market, clinical trial and regulatory complications in seeking to develop and commercialize a portfolio of
+COVID-19 test systems during the continuing, but evolving, uncertainty resulting from COVID‑19. For the year ended December 31, 2022, the Company also continued to incur significant operating
+losses and significant expenses in connection with pending legal matters (see Note 12 – Commitments, Contingencies, and Concentrations: Litigation). 
+The Company performed an assessment to determine whether there were conditions or events that, considered in the aggregate, raised substantial doubt
+about the Company’s ability to continue as a going concern within one year after the filing date of this report, when the accompanying financial statements are being issued. Initially, this assessment did not consider the potential mitigating
+effect of management’s plans that had not been fully implemented. Because, as described below, substantial doubt was determined to exist as the result of this initial assessment, management then assessed the mitigating effect of its plans to
+determine if it is probable that the plans (1) would be effectively implemented within one year after the filing date of this report, when the accompanying financial statements are being issued and (2) when implemented, would mitigate the
+relevant conditions or events that raise substantial doubt about the Company’s ability to continue as a going concern. 
+The Company achieved revenue growth in recent years while profitability has not been at levels as expected. It has taken steps including investments
+in automation to mitigate headwinds such as labor availability, volatile capacity planning and implementation of operational efficiency targets to proactively monitor production with the overarching goal of profitable growth. The Company
+undertook measures to increase its total revenues and improve its liquidity position by continuing to develop the Global Competitiveness Program. The main pillars of the Global Competitiveness Program include the following: 
+• 
+Focus on higher margin business in growth markets 
+• 
+Lower manufacturing costs 
+• 
+Reduce infrastructure costs 
+• 
+Strategic review of non-core businesses and assets 
+The Company’s execution of its plans continue to depend, however, on factors and uncertainties that are beyond the Company’s control, or that
+may not be addressable on terms acceptable to the Company or at all. The Company considered in particular how: 
+5 
+Table of Contents 
+• 
+The ongoing healthcare and economic impacts of COVID-19 on the global customer base for the Company’s non‑COVID-19 products continue to negatively affect the
+timing and rate of recovery of the Company’s revenues from those products. 
+The Company further considered how these factors and uncertainties could impact its ability over the next year to meet the obligations specified in
+the Credit Agreement with the Lender. Those obligations include covenants requiring: i) minimum cash balance of $3.0 million and ii) minimum total revenue amounts for the twelve months preceding each quarter end. The minimum total revenue
+requirements are $48.8 million for the twelve months ending March 31, 2023 and $50.1 million for the twelve months ending June 30, 2023. We do not believe that we will comply with the minimum total revenue covenant for the twelve months ended
+March 31, 2023. Upon an event of default under the Credit Agreement, the Lender could elect to declare all amounts outstanding thereunder, together with accrued interest, to be immediately due and payable. Furthermore, all remaining principal and
+interest is due on or before September 3, 2023. There can be no assurance that the Company would have sufficient liquidity to fund payment of the amounts that would be due under the Credit Agreement or that, if such liquidity were not available,
+the Company would be successful in raising additional capital on acceptable terms, or at all, or in completing any other endeavor to continue to be financially viable and continue as a going concern. The Company’s inability to raise additional
+capital on acceptable terms in the near future, whether for purposes of funding payments required under the Credit Agreement or providing additional liquidity needed for its operations, could have a material adverse effect on its business,
+prospects, results of operations, liquidity and financial condition and would likely result in the Company being forced to seek protection under a bankruptcy proceeding. 
+Accordingly, management determined the Company could not be certain that the Company’s plans and initiatives would be effectively implemented within
+one year after the filing date of this report, when the accompanying financial statements are being issued. Without giving effect to increasing product revenue in the near future, the proposed merger with Biosynex or executing other mitigating
+plans, many of which are beyond the Company’s control, it is unlikely that the Company will be able to generate sufficient cash flows to meet its required financial obligations, including its debt service and other obligations due to third
+parties. The existence of these conditions raises substantial doubt about the Company’s ability to continue as a going concern for the twelve-month period following the date on which the accompanying consolidated financial statements are being
+issued. 
+The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern, which contemplates
+continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business for the twelve-month period following the date the accompanying consolidated financial statements are issued. As such, the
+accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amounts, or the amount and classification of liabilities that may result should the
+Company be unable to continue as a going concern. 
+Industry 
+The DPP technology platform targets diagnostic disease states; (1) where rapid diagnosis impacts patient treatment and outcomes; (2) that are underserved by current diagnostic products due to performance or
+availability; (3) that present opportunities regionally, demographically or clinically. The Company is focused on test solutions associated with infectious diseases: respiratory viruses, sexually transmitted diseases, and insect-vector diseases. 
+Our product portfolio is marketed globally to NGO’s, Ministries of Health, acute care hospitals, reference labs, outpatient clinics including urgent cares and physician offices. Our branded products have achieved
+meaningful market share globally and include, SureCheck, Stat Pak and DPP. The Company will focus on internally developed products and pursue external opportunities to license novel technologies and products with the intent of leveraging
+Chembio’s growing commercial infrastructure. 
+6 
+Table of Contents 
+We currently are targeting lateral flow test solutions for infectious diseases: respiratory diseases, sexually transmitted diseases and mosquito-borne diseases. The market for lateral flow infectious disease tests
+is being driven by the high prevalence of infectious diseases globally, an increase in the elderly population, growing demand for rapid test results, and advancements in multiplexing. 
+Products 
+COVID-19 Diagnostic Test Systems 
+Prior to 2020, our broad portfolio of infectious disease products was focused principally on sexually transmitted disease and fever and tropical disease. In 2020 we shifted substantially all of our resources to
+leverage the DPP technology platform to address the acute and escalating need for diagnostic testing for COVID-19. 
+COVID-19 Antibody Test System 
+In January 2021 we announced the CE mark for both the DPP SARS-CoV-2 Antigen test system and the DPP SARS-CoV-2 IgM/IgG test system, providing regulatory approval to register and market the test systems in the
+European Union and other geographies that accept the CE mark. 
+COVID-19 Antigen Test System 
+In mid-2020 we began to focus on the development of a COVID-19 antigen test system based on DPP technology. In January 2021 we announced the CE mark for the DPP SARS-CoV-2 Antigen test system, providing regulatory
+approval to register and market the test systems in the European Union and other geographies that accept the CE mark. 
+In December 2020 we received a $12.7 million grant from the Biomedical Advanced Research and Development Authority, part of the U.S. Department of Health and Human
+Services’ Office of the Assistant Secretary for Preparedness and Response, (“BARDA”), in part to support preparation of a submission in pursuit of FDA 510(k) clearance for the DPP SARS-CoV-2 Antigen System. 
+In January 2021 the FDA notified us that it was declining to review the DPP SARS-CoV-2 Antigen System based on its updated prioritization guidance, under which review of the system was not a priority. 
+During the year ended December 31, 2021 we performed the clinical trials and on December 2, 2021 we submitted the DPP SARS‑CoV‑2 Antigen test system to the FDA, as a de Novo submission. We are in interactive review
+process with the FDA. 
+COVID-19 and Influenza Respiratory Antigen Panel Test System 
+In the fourth quarter of 2020 we began developing a rapid, multiplex respiratory antigen panel point-of-care test system using DPP technology. BARDA designated a portion of its $12.7 million grant in December 2020
+for use to support our development, submission and receipt of an EUA for this system. 
+During 2021, we developed and conducted clinical trials of the DPP Respiratory Antigen Panel, a test system being designed to provide simultaneous, discrete and differential detection of Influenza A, Influenza B
+and SARS-CoV-2 antigens from a single patient respiratory specimen, such as a nasal swab. As of December 31, 2021, we have submitted a request for the EUA approval by the FDA which in 2022, we were notified by the FDA that our request for EUA was
+no longer under review. In addition, in 2021 we submitted a request for approval to ANVISA in Brazil and CE in Europe, which was approved in 2022. 
+As a result, we earned $12.5 million of the $12.7 million available under the BARDA Agreement, dated December 2, 2020, with the remaining $0.2 million having not been earned because it was contingent on our
+receiving an emergency use authorization for the DPP SARS-CoV-2 Antigen by December 2, 2021. 
+HIV-Syphilis Diagnostic Test Systems 
+On February 23, 2023 we received notice from the FDA that we were granted Clinical Laboratory Improvement Amendment, or "CLIA", waiver for the DPP HIV-Syphilis test system. 
+7 
+Table of Contents 
+Core Products 
+We have obtained FDA approvals and, directly or through our partners, international regulatory approvals for infectious disease tests as follows: 
+Product 
+U.S. 
+International 
+DPP COVID-19 IgM/IgG System 
+✓ 
+DPP SARS-CoV-2 IgM/IgG System 
+✓ 
+DPP SARS-CoV-2 Antigen 
+✓ 
+DPP HIV 1/2 Assay 
+✓ 
+✓ 
+DPP HIV-Syphilis System 
+✓ 
+✓ 
+DPP Syphilis Screen & Confirm Assay 
+✓ 
+DPP ZCD IgM/IgG System 
+✓ 
+DPP Dengue NS1 Antigen System 
+✓ 
+DPP Dengue IgM/IgG System 
+✓ 
+DPP Zika IgM System 
+✓ 
+✓ 
+DPP Zika IgM/IgG System 
+✓ 
+DPP Chikungunya System 
+✓ 
+DPP Ebola Antigen System 
+✓ EUA 
+DPP Leishmaniasis Assay 
+✓ 
+DPP Respiratory Antigen Panel 
+✓ 
+DPP VetTB Assay 
+✓ 
+HIV 1/2 STAT-PAK Assay 
+✓ 
+✓ 
+Chagas STAT-PAK Assay 
+✓ 
+SURE CHECK HIV 1/2 Assay 
+✓ 
+✓ 
+SURE CHECK HIV Self-Test 
+✓ 
+Organic growth in our core infectious disease business is being driven by: 
+• 
+growth in the overall market for point of care infectious disease tests; 
+• 
+our increased market penetration in existing markets and channels, including in the United States, Latin America, Africa and Europe; 
+• 
+our registration of existing and new products in unchartered countries and regions, such as selected countries in Latin America and Southeast Asia; 
+• 
+our entry into new market segments, such as respiratory tests and international HIV Self-Testing; and 
+• 
+advances in our product pipeline in infectious disease with key products including tests for COVID-19, a multiplex test for HIV and syphilis in the U.S. market and tests for dengue, zika and chikungunya. 
+We market and sell both stand-alone and multiplex tests for sexually transmitted infectious diseases, such as HIV and syphilis, which continue to be major global public health issues. According to WHO estimates: 
+• 
+HIV has claimed more than 40 million lives, including 650,000 in 2021. Approximately 38.4 million people were living with HIV at the end of 2021, and 1.5 million were newly infected during 2021. 
+We are seeking to address the global concerns related to HIV and syphilis co-infection through the development of a novel, multiplex test for both HIV and syphilis. We have developed a DPP HIV-Syphilis multiplex
+test and received regulatory approvals in the United States and a number of international markets, including Brazil, Europe, Africa, Malaysia and Mexico. Approval of a CLIA waiver for the DPP HIV-Syphilis test in the United States was received in
+February 2023. 
+We also market and sell tests for selected fever and tropical diseases such as Chagas, Ebola, leishmaniasis and Zika. The market for lateral flow mosquito-borne diseases includes established markets for disease
+such as dengue and malaria, which WHO estimates together account for more than 600 million annual infections worldwide. There are also a number of emerging markets for rapid point of care tests for infectious diseases such as burkholderia,
+chikungunya, lassa, leptospirosis, Marburg, rickettsia and Zika. 
+We have received funding from some of the world’s leading health organizations, which has helped us accelerate the expansion of our pipeline of infectious disease tests. Our collaborators have included Bill &
+Melinda Gates Foundation, The Paul G. Allen Family Foundation, The Oswaldo Cruz Foundation or FIOCRUZ, and the Foundation for Innovative New Diagnostics, or FIND, as well as U.S. government agencies such as Centers for Disease Control and
+Prevention, or ("CDC"), BARDA, and the U.S. Department of Agriculture, or USDA. 
+8 
+Table of Contents 
+Several tests in our infectious disease pipeline are approaching commercialization, and several have received initial regulatory approvals: 
+Product 
+Collaborator 
+Phase I 
+Feasibility 
+Phase II 
+Development 
+Phase III 
+Verification & 
+Validation 
+Phase IV 
+Clinical & 
+Regulatory 
+Phase V 
+Commercial 
+Launch 
+DPP HIV-Syphilis System (US) 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CLIA Waived 
+DPP Dengue IgM/IgG System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP Dengue NS1 Antigen System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA pending 
+DPP Chikungunya IgM/IgG System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP Zika Chikungunya Dengue IgM/IgG System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP Ebola Antigen System 
+CDC 
+✓ 
+✓ 
+✓ 
+✓ 
+FDA-EUA 
+DPP Fever Assay Asia 
+FIND 
+✓ 
+✓ 
+✓ 
+✓ 
+DPP Fever Assay Africa 
+Paul Allen Foundation 
+✓ 
+✓ 
+✓ 
+DPP Fever Assay Malaysia 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+DPP SARS CoV-2 Antigen 
+BARDA 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP Respiratory Antigen Panel 
+BARDA 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP COVID-19 IgM/IgG System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP SARS CoV-2 IgM/IgG System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE 
+Sales Channels 
+Our products are sold globally, both directly and through distributors, to hospitals and clinics, physician offices, clinical laboratories, public health organizations, government agencies and consumers.
+Historically we marketed and sold our products only into a handful of countries and regions. During 2022, we expanded our U.S.-based sales, customer service, and marketing team to focus on the COVID-19, HIV-Syphilis, and future DPP platform
+product opportunities. With sales growth as an underlying objective, we are focused on increasing sales in geographies that support higher average selling prices. From lead generation through technical inquiries, Chembio has the internal
+resources to support customers through the commercial process including marketing, sales, sales support, order entry and product support. 
+Automation of U.S. Manufacturing 
+We are automating our U.S. manufacturing processes and expanding our manufacturing capacity. Over the past four years, we have taken delivery of and completed validation of most of our automated manufacturing
+lines. These use vision-guided, robotic operation to improve inspection and quality control. As we transition from manual to automated assembly, we believe the reduced variable costs will improve product gross margins. 
+9 
+Table of Contents 
+DPP Technology & Development 
+Our commercially available products employ either our patented DPP technology or traditional lateral flow technology. We believe products developed using our DPP technology can provide superior diagnostic
+performance compared with products that utilize traditional lateral flow technology. 
+Chembio’s history of collaborations have proven the strength and capabilities of the DPP platform to address a diverse range of biomarkers. We are now focusing our R&D resources on developing Chembio’s new and
+expanded product portfolio focused on high average selling price, developed markets, established sales channels, and clinically accepted use cases, where the differentiated capabilities of DPP provide a competitive advantage. 
+Competition 
+Many of our competitors are significantly larger and have greater financial, research, manufacturing, and marketing resources. Important competitive factors include product quality, analytical performance, ease of
+use, price, customer service and reputation. Industry competition is based on these and the following additional factors: 
+• 
+patent protection; 
+• 
+scientific expertise; 
+• 
+ability to develop and market products and processes; 
+• 
+ability to obtain required regulatory approvals; 
+• 
+ability to manufacture cost-effective products that meet applicable regulatory requirements; 
+• 
+access to adequate capital; and 
+• 
+ability to attract and retain qualified personnel. 
+We believe our scientific capabilities and proprietary know-how relating to our patented DPP technology and lateral flow technology are very strong, particularly for the development and manufacture of tests for the
+detection of infectious and other diseases. 
+Although we have no specific knowledge of any other competitors’ products that could render our products obsolete, if we fail to maintain and enhance our competitive position or fail to introduce new products and
+product features, our customers may decide to use the products developed by our competitors, which could result in a loss of revenues and cash flow. 
+Human Capital 
+As of December 31, 2022, we had 188 full-time equivalent employees, of whom 20 were in administration, 127 were in manufacturing, 23 were in research and development, and 18 were in sales and marketing and customer
+service. Of these employees, approximately 151 were located in the United States, 17 were located in Germany and 20 were located in Brazil. We have never had a work stoppage, and none of our employees are represented by a labor organization or
+subject to any collective bargaining arrangements. We consider our employee relations to be good. 
+Our employees are one of our most important assets and set the foundation for our ability to achieve our strategic objectives, drive operational execution, deliver strong financial performance, advance innovation
+and maintain our quality and compliance programs. The success and growth of our business depends in large part on our ability to attract, retain and develop a diverse population of talented and high-performing employees at all levels of our
+organization. 
+Health, Wellness and Safety 
+The health, wellness and safety of our employees is a priority embedded at every level of our business. We provide our employees upfront and ongoing safety training to ensure that safety policies and procedures
+are effectively communicated and implemented. Personal protective equipment is provided to those employees where needed for the employee to safely perform their job function. 
+Since 2020, in response to the COVID-19 pandemic, we implemented safety protocols and new procedures to protect our employees, including more frequent deep cleaning of the facilities, social distancing and onsite
+COVID-19 testing. 
+10 
+Table of Contents 
+Workforce Stability 
+Retaining and developing our employees is an important factor in our continued success and growth. We regularly evaluate our employee retention and turnover rates. 
+Compensation and Benefits 
+To succeed in a competitive labor market, we have recruitment and retention strategies that we focus on as part of the overall management of our business, including designing our compensation and benefits programs
+to be competitive and align with our strategic and stockholders’ interests. Some of our key employee benefits include eligibility for health insurance, vacation time, a retirement plan, an employee assistance program, life and disability
+coverage. We also have procedures and processes focused on providing employees equitable compensation, regardless of race or gender or other personal characteristics. 
+Governmental Regulation 
+Certain of our activities are subject to regulatory oversight by the FDA under provisions of the Federal Food, Drug, and Cosmetic Act and regulations thereunder, including regulations governing the development,
+marketing, labeling, promotion, manufacturing, and export of diagnostic products. Our clinical laboratory customers are subject to oversight by Centers for Medicare and Medicaid Services, or CMS, pursuant to CLIA, as well as agencies in various
+states. Failure to comply with applicable requirements can lead to sanctions, including withdrawal of products from the market, recalls, refusal to authorize government contracts, product seizures, civil money penalties, injunctions, and criminal
+prosecution. 
+FDA Approval/Clearance Requirements 
+Unless an exemption applies, each medical device that we market or wish to market in the United States must receive 510(k) clearance or Premarket Approval, or PMA. Medical devices that receive 510(k) clearance are
+“cleared” by the FDA to market, distribute, and sell in the United States. Medical devices that obtain a PMA by the FDA are “approved” to market, distribute and sell in the United States. We cannot be certain that 510(k) clearance or PMA approval
+will ever be obtained for any products that have not already obtained 510(k) clearance or PMA approval. Descriptions of the PMA and 510(k) clearance processes are provided below. 
+The FDA decides whether a device line must undergo either the 510(k) clearance or PMA based on statutory criteria that utilize a risk-based classification system. PMA is the FDA process of scientific and regulatory
+review to evaluate the safety and effectiveness of Class III medical devices and, in many cases, Class II medical devices. Class III devices are those that support or sustain human life, are of substantial importance in preventing impairment of
+human health, or which present a potential, unreasonable risk of illness or injury. The FDA uses these criteria to decide whether a PMA or a 510(k) is appropriate, including the level of risk that the agency perceives is associated with the
+device and a determination by the agency of whether the product is a type of device that is similar to devices that are already legally marketed. Devices deemed to pose relatively less risk are placed in either Class I or II. In many cases, the
+FDA requires the manufacturer to submit a 510(k) requesting clearance (also referred to as a premarket notification), unless an exemption applies. The 510(k) must demonstrate that the manufacturer’s proposed device is “substantially equivalent”
+in intended use and in safety and effectiveness to a legally marketed predicate device. A “predicate device” is a pre-existing medical device to which equivalence can be drawn, that is either in Class I or Class II or is a Class III device that
+was in commercial distribution before May 28, 1976, for which the FDA has not yet called for submission of a PMA application. 
+Device classification depends on the device’s intended use and its indications for use. In addition, classification is risk-based, that is, the risk the device poses to the patient and/or the user is a major factor
+in determining the class to which it is assigned. Class I includes devices with the lowest risk and Class III includes those with the greatest risk. 
+11 
+Table of Contents 
+Class I devices are those for which safety and effectiveness can be assured by adherence to the FDA’s general regulatory controls for medical devices, or the General
+Controls, which include compliance with the applicable portions of the FDA’s quality system regulations, facility registration and product listing, reporting of adverse medical events, and appropriate, truthful and non-misleading labeling,
+advertising, and promotional materials. Some Class I devices also require premarket clearance by the FDA through the 510(k) process described below. 
+Class II devices are subject to the FDA’s General Controls, and any other special controls as deemed necessary by the FDA to ensure the safety and effectiveness of the
+device. Premarket review and clearance by the FDA for Class II devices is accomplished through the 510(k) process. Pursuant to the Medical Device User Fee and Modernization Act of 2002, unless a specific exemption applies, 510(k) submissions are
+subject to user fees. Certain Class II devices are exempt from this premarket review process. 
+Class III includes devices with the greatest risk. Devices in this class must meet all of the requirements in Classes I and II. In addition, Class III devices cannot be
+marketed until they receive Premarket Approval. 
+The safety and effectiveness of Class III devices cannot be assured solely by the General Controls and the other requirements described above. These devices require formal clinical studies to demonstrate safety and
+effectiveness. Under the Medical Device User Fee and Modernization Act of 2002, PMA applications (and supplemental premarket approval applications) are subject to significantly higher user fees than 510(k) applications, and they also require
+considerably more time and resources. 
+Premarket Approval Pathway 
+We manufacture, market and distribute three rapid HIV tests in the United States. Our HIV 1/2 STAT-PAK Assay, SURE CHECK HIV 1/2 Assay, and DPP HIV 1/2 Assay all have received FDA PMA approval. A PMA application
+must be supported by extensive data including, but not limited to, analytical, preclinical, clinical trials, manufacturing, statutory preapproval inspections, and labeling to demonstrate to the FDA’s satisfaction the safety and effectiveness of
+the device for its intended use. Before a PMA is submitted, a manufacturer must apply for an Investigational Device Exemption (“IDE”). If the device presents a “significant risk,” as defined by the FDA, to human health, the FDA requires the
+device sponsor to file an IDE application with the FDA and obtain IDE approval prior to initiation of enrollment of human subjects for clinical trials. The IDE provides the manufacturer with a legal pathway to perform clinical trials on human
+subjects where without the IDE, only approved medical devices may be used on human subjects. 
+The IDE application must be supported by appropriate data, such as analytical, animal and laboratory testing results, manufacturing information, and an Investigational Review Board, or IRB approved protocol showing
+that it is safe to test the device in humans and that the testing protocol is scientifically sound. If the clinical trial design is deemed to have “non-significant risk,” the clinical trial may be eligible for “abbreviated” IDE requirements. In
+some instances, clinical trials for in vitro diagnostic medical devices may be exempt from the more burdensome IDE requirements if certain labeling requirements are met. 
+A clinical trial may be suspended by either the FDA or the Investigational Review Board at any time for various reasons, including a belief that the risks to the study participants outweigh the benefits of
+participation in the study. Even if a study is completed, clinical testing results may not demonstrate the safety and efficacy of the device, or they may be equivocal or otherwise insufficient to obtain approval of the product being tested. After
+the clinical trials have been completed, if at all, and the clinical trial data and results are collected and organized, a manufacturer may complete a PMA application. 
+12 
+Table of Contents 
+After a PMA application is sufficiently complete, the FDA will accept the application and begin an in-depth review of the submitted information. By statute, the FDA has 180 days to review the “accepted
+application,” although, generally, review of the application can take between one and three years, but it may take significantly longer. During this review period, the FDA may request additional information or clarification of information already
+provided. Also, during the review period, an advisory panel of experts from outside the FDA may be convened to review and evaluate the application and provide recommendations to the FDA as to the approvability of the device. The preapproval
+inspections conducted by the FDA include an evaluation of the manufacturing facility to ensure compliance with the FDA’s quality systems regulations or QSR, as well as inspections of the clinical trial sites by the Bioresearch Monitoring group to
+evaluate compliance with good clinical practice and human subject protections. New PMA applications or PMA supplements are required for modifications that affect the safety or effectiveness of the device, including, for example, certain types of
+modifications to the device’s indication for use, manufacturing process, labeling and design. Significant changes to an approved PMA require a 180-day supplement, whereas less substantive changes may utilize a 30-day notice, or a 135-day
+supplement. Premarket approval supplements often require submission of the same type of information as a premarket approval application, except that the supplement is limited to information needed to support any changes from the device covered by
+the original premarket approval application, and it may not require as extensive clinical data or the convening of an advisory panel. 
+Our HIV 1/2 STAT-PAK Assay PMA application number BP050009/0 and our SURE CHECK 1/2 HIV Assay PMA application number BP050010/0 were approved by the FDA in May 2006. Our DPP HIV 1/2 Assay PMA application number
+BP120032/0 was approved by the FDA in December 2012. Our DPP HIV Syphilis Assay PMA application number BP180191/0 was approved by the FDA in October 2020. 
+510(k) Clearance Pathway 
+We are currently developing products that either will or are likely to require an FDA 510(k) clearance. We anticipate submitting a 510(k) for each such product to demonstrate that such proposed device is
+substantially equivalent to a previously cleared 510(k) device or a device that was in commercial distribution before May 28, 1976, for which the FDA has not yet called for the submission of a 510(k). The FDA’s 510(k) clearance pathway usually
+takes from three to twelve months but could take longer. In some cases the FDA may require additional information, including clinical data, to make a determination regarding substantial equivalence. 
+If a device receives 510(k) clearance, any modification that could significantly affect its safety or effectiveness, or that would constitute a new or major change in its intended use, will require a new 510(k)
+clearance or, depending on the modification, a PMA. The FDA requires each device manufacturer to determine whether the proposed change requires submission of a new 510(k) or a PMA, but the FDA can review any such decision and, if it disagrees
+with the manufacturer’s determination, can require the manufacturer to cease marketing and/or recall the modified device until 510(k) clearance or PMA of the modified device is obtained. 
+Clinical Laboratory Improvement Amendments of 1988 
+A manufacturer of a test categorized as moderately complex may request that categorization of the test be waived through a CLIA Waiver by Application, or CW, submission to the FDA. When a test is categorized as
+waived, it may be performed by laboratories with a Certificate of Waiver, such as a physician’s office outreach setting. In a CW submission, the manufacturer provides evidence to the FDA that a test meets the CLIA statutory criteria for waiver
+CLIA, a walk-in clinic or an emergency room provides CMS authority over all laboratory testing, except research that is performed on humans in the United States. The Division of Laboratory Services, within the Survey and Certification Group under
+the CMS, has the responsibility for implementing the CLIA program. 
+The CLIA program is designed to establish quality laboratory testing by ensuring the accuracy, reliability and timeliness of patient test results. Under CLIA, a laboratory is a facility that does laboratory testing
+on specimens derived from humans and used to provide information for the diagnosis, prevention or treatment of disease, or impairment of, or assessment of health. Under the CLIA program, unless waived, laboratories must be certified by the
+government, satisfy governmental quality and personnel standards, undergo proficiency testing, be subject to inspections and pay fees. We have received a CLIA waiver for all of our lateral flow rapid HIV tests that we market in the United States.
+Specifically, the CLIA waiver was granted by the FDA for HIV 1/2 STAT-PAK in November 2006, for SURE CHECK HIV 1/2 in October 2007, DPP HIV 1/2 in October 2014 and DPP HIV-Syphilis in February 2023. 
+13 
+Table of Contents 
+Emergency Use Authorizations (EUA) 
+A formal request to issue an EUA generally should not be submitted until the Secretary of HHS has issued an EUA declaration under section 564(b)(1). In particular, although section 564 allows FDA to issue an EUA
+for preparedness purposes, in such cases the HHS Secretary must first declare that circumstances exist justifying such an authorization in advance of an actual emergency based on a formal determination of a significant potential for emergency or
+a material threat determination. During the effective period of the HHS Secretary’s EUA declaration, FDA may authorize the introduction of a medical product into interstate commerce when the product is intended for use during an actual or
+potential emergency. EUA candidate products include medical products and uses that are not approved, cleared, or licensed under sections 505, 510(k), and 515 of the FD&C Act or section 351 of the PHS Act. 
+After the requisite determination and declaration have been issued, and after feasible and appropriate consultations, FDA may issue an EUA only if FDA concludes that the following four statutory criteria for
+issuance have been met for 1) Serious or Life-Threatening Disease or conditions, 2) evidence of effectiveness, 3) Risk –Benefit Analysis, 4) No Alternatives. A sponsor seeking an EUA can submit its formal request in the form of an EUA
+submission, which includes data for clinical studies, non-clinical laboratory studies to assess the safety and effectiveness of the product as well as the discussion of Risks and Benefits of the product. 
+FDA will specify the effective date of an EUA issued under section 564. In general, an EUA will remain in effect for the duration of the EUA declaration under which it was issued which describes termination of an
+EUA declaration and its impact on existing EUAs. 
+Pervasive and Continuing FDA Regulation 
+A host of regulatory requirements apply to our approved devices, including: the quality system regulation, which requires manufacturers to follow elaborate design, testing, control, documentation and other quality
+assurance procedures; the Medical Reporting Regulations, which require manufacturers to report to the FDA specified types of adverse events involving their products; labeling regulations; and the FDA’s general prohibition against promoting
+products for unapproved or “off-label” uses. Some Class II devices are subject to special controls-such as performance standards, post-market surveillance, patient registries, and FDA guidelines-that do not apply to Class I devices. 
+The regulatory requirements that apply to our approved products classified as medical devices include: 
+• 
+product listing and establishment registration, which helps facilitate FDA inspections and other regulatory action; 
+• 
+QSR, which require manufacturers, including third-party manufacturers, to follow stringent design, testing, control, documentation and other quality assurance procedures during all aspects of the development and manufacturing process; 
+• 
+labeling regulations and FDA prohibitions against the promotion of products for uncleared, unapproved or off-label use or indication; 
+• 
+clearance of product modifications that could significantly affect safety or efficacy or that would constitute a major change in intended use of one of our cleared devices; 
+• 
+approval of product modifications that affect the safety or effectiveness of one of our cleared devices; 
+• 
+medical device reporting regulations, which require that manufacturers comply with FDA requirements to report if their device may have caused or contributed to a death or serious injury, or has malfunctioned in a way that would likely
+cause or contribute to a death or serious injury if the malfunction of the device or a similar device were to recur; 
+• 
+post-approval restrictions or conditions, including post-approval study commitments; 
+• 
+post-market surveillance regulations, which apply when necessary to protect the public health or to provide additional safety and effectiveness data for the device; 
+• 
+the FDA’s recall authority, whereby it can ask, or under certain conditions order, device manufacturers to recall from the market a product that is in violation of governing laws and regulations; 
+• 
+regulations pertaining to voluntary recalls; and 
+• 
+notices of corrections or removals. 
+Our Medford, New York facility is currently registered as an establishment with the FDA. We and any third-party manufacturers are subject to announced and unannounced inspections by the FDA to determine our
+compliance with QSR and other regulations. 
+14 
+Table of Contents 
+Government Regulation of Medical Devices for Animal Subjects 
+We currently offer two veterinary devices in the United States: DPP VetTB Assay for Cervids and DPP VetTB Assay for Elephants. Diagnostic tests for animal health infectious diseases, including our veterinary
+devices for the prevention and/or treatment of animal disease, are regulated in the U.S. by the Center for Veterinary Biologics within the U.S. Department of Agriculture Animal and Plant Health Inspection Service, or APHIS, under the Virus,
+Serum, and Toxin Act of 1913. As a requirement, our veterinary devices were approved by APHIS before they could be sold in the United States. 
+The APHIS regulatory approval process involves the submission of product performance data and manufacturing documentation. Following regulatory approval to market a product, APHIS requires that each lot of product
+be submitted for review before release to customers. In addition, APHIS requires special approval to market products where test results are used in part for government-mandated disease management programs. 
+Climate Change and Environmental Laws 
+The medical device industry is increasingly becoming subject of scrutiny, stringent regulation and the demand for green, sustainable products. We are focused on monitoring these increasing requirements for
+efficient and accurate processes for hazardous substance handling, supplier disclosures, and regulatory reporting in order to comply with numerous global health and environmental regulatory requirements and restrictions. 
+We believe that we are in compliance in all material respects with all foreign, federal, state, and local environmental regulations applicable to our manufacturing facilities. The cost of ongoing compliance with
+such regulations does not have a material effect on our operations. 
+Intellectual Property 
+Intellectual Property Strategy 
+Our intellectual property strategy is to: (1) build our own intellectual property portfolio around our DPP technology and optical analyzers; (2) pursue licenses, trade secrets and know-how within the area of rapid
+point-of-care testing; and, (3) develop and acquire proprietary positions to certain reagents. 
+DPP Intellectual Property 
+We have obtained patent coverage on our DPP technology, including numerous patents in the United States, and one or more patents in Australia, Brazil, Canada, China, Columbia, Eurasia (Russia), European Union
+(fourteen European countries),Hong Kong, Israel, India, Indonesia, Japan, Korea, Malaysia, Mexico, Poland, Singapore, South Africa, Thailand, and the United Kingdom. Additional patent applications on our DPP technology are pending in the United
+States, as well as in foreign countries such as Australia, Brazil, Canada, China, the European Union, India, Indonesia, Malaysia, Mexico, Peru, Singapore and Thailand. 
+DPP technology provides us with freedom to operate and enables us to develop tests with better performance and capabilities compared with tests built on traditional lateral flow platforms. These advantages have
+allowed us to enter into multiple technology collaborations based upon DPP technology, which we believe will provide new manufacturing and marketing opportunities. We have filed additional patent applications that we believe will strengthen the
+DPP intellectual property and have also filed for patent protection for certain other point-of-care technologies or applications thereof. 
+We have also obtained patent coverage on our optical-based analyzer technology in the United States as well as in several EU countries. 
+Trademarks 
+We have filed and obtained trademarks for our company name CHEMBIO and CHEMBIO DIAGNOSTIC SYSTEMS, INC. as well as for many of our products, including DPP, SURE CHECK, STAT-VIEW, STAT-PAK, and NEXT GENERATION DPP,
+as well as for the SampleTainer and DPP Micro Reader, which are used with certain DPP products. Our trademarks have been registered in the United States and certain other countries around the world. 
+15 
+Table of Contents 
+Trade Secrets and Know-How 
+We have developed a substantial body of trade secrets and know-how relating to the development and manufacture of lateral flow and DPP-based diagnostic tests, including the sourcing and optimization of materials
+for such tests, and methods to maximize sensitivity, speed-to-result, specificity, stability and reproducibility of our tests. We possess proprietary know-how to develop tests for multiple conditions using colored particles. Our formulations
+enable long shelf lives of our rapid HIV and other tests, providing us with an important competitive advantage. 
+Rapid Diagnostic Technology and Reagent Licenses 
+We seek licenses and/or redesigns of products that we believe to be in our best interests. Because of the costs and other negative consequences of time consuming patent litigation, we often attempt to obtain a
+license on reasonable terms. The peptides used in our rapid HIV tests were licensed to us by one or more third parties. We also have licensed the antigens used in other tests including our Syphilis, Tuberculosis, Leptospirosis, Leishmaniasis and
+Chagas tests, and we may enter into other license agreements. In prior years, we concluded license agreements related to intellectual property rights owned by the United States associated with HIV-1 and a sub-license agreement for HIV-2 with
+Bio-Rad Laboratories N.A., the exclusive licensee of the Pasteur Institute’s HIV-2 intellectual property estate. 
+Available Information 
+We are required to file annual, quarterly and current reports, proxy statements and other information with the U.S. Securities and Exchange Commission. The SEC maintains a website at www.sec.gov that contains
+reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. 
+Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, proxy statements and amendments to those documents filed or furnished pursuant to Section 13(a) or 15(d) of the
+Securities Exchange Act of 1934, are also available free of charge on our website at www.chembio.com as soon as reasonably practicable after such reports are electronically filed with or furnished to the SEC. 
+Investors should note that we currently announce material information to our investors and others using filings with the SEC, press releases, public conference calls, webcasts or our website (www.chembio.com),
+including news and announcements regarding our financial performance, key personnel, our brands and our business strategy. Information that we post on our corporate website could be deemed material to investors. We encourage investors to review
+the information we post on these channels. We may from time to time update the list of channels we will use to communicate information that could be deemed material and will post information about any such change on www.chembio.com. The
+information on our website is not, and shall not be deemed to be, a part hereof or incorporated into this or any of our other filings with the SEC. 
+Corporate Information 
+Our principal executive offices are located at 3661 Horseblock Rd, Medford, New York 11763. Our telephone number is (631) 924-1135. Our website address is www.chembio.com. The information contained in, or
+accessible through, our corporate website does not constitute part of this report. 
+ITEM 1A. 
+RISK FACTORS 
+You should carefully consider each of the following risk factors and all of the other information provided in this Form 10-K in considering whether to make or continue to hold an investment in
+our Common Stock. The risks described below are those we currently believe may materially affect us. An investment in our Company involves a high degree of risk, and should be considered only by persons who can afford the loss of their entire
+investment. Although we believe that these risks are the most important for you to consider, you should read this section in conjunction with our financial statements, the notes to those financial statements and our management’s discussion and
+analysis of financial condition and results of operations included in our periodic reports and incorporated into this Form 10-K by reference. 
+16 
+Table of Contents 
+RISK FACTORS SUMMARY 
+Our business is subject to a number of risks, including risks that may prevent us from achieving our business objectives or may adversely affect our business,
+financial condition, results of operations, cash flows and prospects. The risks are discussed more fully below and include, but are not limited to, the risks summarized below. 
+Risks Related to the Pending Merger with Biosynex SA and Project Merci Merger Sub, Inc. 
+• 
+our ability to complete the pending Merger within the time frame we anticipate or at all; 
+• 
+our ability to complete the Merger is subject to certain closing conditions; 
+• 
+the pendency of the Merger could adversely affect our business, financial results and operations; 
+• 
+stockholder litigation could prevent or delay the consummation of the Offer and the Merger; 
+• 
+our stockholders will not be able to participate in any financial upside to our business after the Merger; 
+• 
+costs we have incurred, and will continue to incur as a result of the pending Merger; 
+• 
+restrictions on our business activities as a result of the Merger Agreement; and 
+• 
+limitations our ability to pursue alternative transactions. 
+Risks Related to Our Business and Our Industry 
+• 
+our dependence on the success of our DPP platform for our near term success; 
+• 
+our ability to implement the transitions contemplated by our Strategic Planning Process; 
+• 
+uncertainty and competition in the diagnostic testing market, particularly with respect to COVID-19; 
+• 
+our ability to initiate and complete clinical trials necessary to support EUA, 510(k), PMA or de novo submissions; 
+• 
+the effects of existing or future stockholder litigation; 
+• 
+our allocation of a substantial portion of our resources to the development and production of our DPP SARS-CoV-2 Antigen system; 
+• 
+impacts on our suppliers and employees due to the COVID-19 pandemic; 
+• 
+the ability of our products to compete with the new or existing products of our competitors; 
+• 
+the acceptance of our DPP platform in the market; 
+• 
+the negative impact of healthcare industry consolidation on our future revenues and operating results; 
+• 
+our ability to retain key employees and attract additional qualified personnel; 
+• 
+third-party reimbursement policies; 
+• 
+our ability to collect our outstanding accounts receivable; 
+• 
+the continued funding of, and ability to participate in, large testing program in the United States; 
+• 
+developments in diagnostic testing guidelines or recommendations; 
+• 
+the effect of an increase in demand for our products on our available resources or customer relationships if we are unable to meet such demand; 
+• 
+our ability to obtain government grant awards; and 
+• 
+the vulnerability of our business to cyber-attacks. 
+Risks Related to Our Products 
+• 
+the COVID-19 Diagnostic Test Systems not gaining wide industry acceptance; 
+• 
+the impact of COVID-19 mutations on the detection ability of our COVID-19 Diagnostic Test Systems; 
+• 
+our ability to successfully introduce and market our products; 
+• 
+timely receipt and implementation of additional customized manufacturing automation equipment; 
+• 
+variability and unpredictability due to lengthy sales cycles for our products; 
+• 
+our customers not adopting rapid point-of-care diagnostic testing; 
+• 
+the concentration of our customers; 
+• 
+our ability to successfully defend ourselves against product liability claims; and 
+• 
+our products not performing properly. 
+Financial, Economic and Financing Risks 
+• 
+our liquidity limitations, including that we have concluded there is a substantial doubt about our ability to continue as a going concern; 
+• 
+failure to meet the minimum bid price for continued listing on The Nasdaq Capital Market and the effect on our ability to sell equity securities and the liquidity of our common
+stock; 
+• 
+failure to maintain effective internal controls and our ability to accurately report our financial results or prevent fraud; 
+17 
+Table of Contents 
+• 
+future dilution as a result of future equity offerings, exercises of outstanding options and vesting of options and restricted and performance stock units; 
+• 
+our incurrence of losses in recent years and uncertainty about our future profitability; 
+• 
+the fluctuation of our financial results; 
+• 
+our compliance with the terms of the Credit Agreement; 
+• 
+our ability to generate sufficient cash to service our debt; 
+• 
+our ability to utilize our net operating loss carryforwards and certain other tax attributes; 
+• 
+increased interest expenses due to changes in LIBOR; 
+• 
+the negative impact of changes in foreign currency exchange rates on our operating results; and 
+• 
+basing our estimates or judgments related to critical accounting policies on assumptions that can change or prove to be incorrect. 
+Risks Related to Intellectual Property 
+• 
+our ability to protect our proprietary technology; and 
+• 
+the effect of future intellectual property disputes on our ability to sell products or use certain technologies. 
+Risks Related to Our Reliance on Third Parties 
+• 
+our dependence on a limited number of third-party suppliers, including single source suppliers, for critical components and materials; 
+• 
+the limitation on rights we receive from collaborations with strategic collaborators, and the exposure to risks outside of our control due to such collaborations; 
+• 
+our ability to maintain existing distribution channels or develop new distribution channels; and 
+• 
+our compliance with U.S. government contracts. 
+Risks Related to Regulations 
+• 
+the impact of changes in CLIA, FDA, ANVISA, and other regulators, on our products; 
+• 
+our ability to receive and maintain necessary regulatory approvals for our products; 
+• 
+the impact of governmental export controls on our ability to compete in international markets; 
+• 
+our ability to comply with FDA and other regulatory requirements; 
+• 
+our ability to respond to changes in regulatory requirements; 
+• 
+the effect of FDA regulation of laboratory-developed tests and genetic testing on demand for our products; 
+• 
+disruptions at the FDA and other government agencies could prevent new and modified products from being developed, cleared, approved, authorized or commercialized; 
+• 
+ongoing changes in healthcare regulation; 
+• 
+a reduction or elimination in the types of government awards that partially support some of our programs; 
+• 
+compliance with privacy, security and breach notification regulations; 
+• 
+our ability to manufacture products in accordance with applicable requirements; 
+• 
+the effect of healthcare fraud and abuse laws on our business; and 
+• 
+increased exposure to regulatory, cultural and other challenges due to international expansion. 
+Risks Related to Ownership of Common Stock 
+• 
+the limited liquidity of our common stock and the volatility of the price of our common stock; 
+• 
+the effect of future issuances of common stock on the price of our common stock and our ability to raise funds in new equity offerings; 
+• 
+the dilution of our current stockholders due to future equity offerings; 
+• 
+management’s broad discretion as to the use of proceeds of the offering; and 
+• 
+the depression of the market price of our common stock due to sale by existing stockholders, executive officers or directors. 
+General Risk Factors 
+• 
+our ability to successfully generate the expected benefits of strategic transactions, if any; 
+• 
+costs associated with compliance with public company regulations; and 
+• 
+terrorist attacks or natural disasters. 
+18 
+Table of Contents 
+Risks Related to the Pending Merger with Biosynex SA and Project Merci Merger Sub, Inc. 
+We may not complete the pending Merger with Biosynex SA and Project Merci Merger Sub, Inc. within the time frame we anticipate
+or at all, which could have an adverse effect on our business, financial results and operations. 
+On January 31, 2023, we entered into a Merger Agreement with Biosynex and the Purchaser. The Merger Agreement provides for, among other things and on the terms and
+subject to the conditions set forth therein, a two-step transaction in which the first step is an Offer by the Purchaser to purchase all of the Company’s issued and outstanding Shares for a purchase price $0.45 per share, net to the seller in
+cash, without interest and subject to any required tax withholding. The Merger Agreement provides that, among other things, as soon as practicable after the consummation of the Offer, and subject to the satisfaction or waiver of the conditions
+in the Merger Agreement, the Purchaser will be merged with and into the Company with the Company continuing as the surviving corporation and a wholly owned subsidiary of Biosynex. 
+If the Merger is not completed within the expected time frame or at all, we may be subject to a number of material risks in addition to the risks of continuing to
+operate our business. The price of our common stock may decline to the extent that current market prices of our common stock reflect a market assumption that the Merger will be completed on a timely basis. We could be required to pay Biosynex a
+termination fee of $850,000 if the Merger Agreement is terminated under specific circumstances as described in the Merger Agreement. The failure to complete the transaction also may result in negative publicity and negatively affect our
+relationship with our stockholders, employees, strategic partners, suppliers and lender. We may also be required to devote significant time and resources to litigation related to any failure to complete the Merger or related to any enforcement
+proceeding commenced against us to perform our obligations under the Merger Agreement. 
+Our ability to complete the Merger is subject to certain closing conditions that could adversely affect us or cause the
+Merger to be abandoned. 
+The Purchaser’s obligation to accept the Shares tendered in the Offer is subject to certain closing conditions, including: (a) that the number of Shares validly
+tendered and not validly withdrawn equals a majority of the outstanding Shares; (b) the absence of any injunction or legal restraint that has the effect of prohibiting the consummation of the Offer or the Merger or making the Offer or the
+Merger illegal or prohibiting or making illegal the acquisition of or payment for Shares pursuant to the Offer or the consummation of the Merger; (c) that, since the date of the Merger Agreement, there shall not have occurred any event that
+would be reasonably likely to have a Company material adverse effect; (d) compliance by the Company with its obligations, covenants and agreements under the Merger Agreement; (e) the accuracy of representations and warranties made by us in the
+Merger Agreement; (f) the absence of any pending legal proceeding in which a governmental body is a party challenging the Offer or the Merger; and (g) other customary conditions. We cannot provide any assurance that the conditions to the
+consummation of the Merger will be satisfied or waived, or will not result in the abandonment or delay of the Merger. 
+The pendency of the Merger with Biosynex and the Purchaser could adversely affect our business, financial results and
+operations. 
+Our efforts to complete the transaction with Biosynex and the Purchaser could cause substantial disruptions in, and create uncertainty surrounding, our business,
+which may materially adversely affect our results of operation and our business. Uncertainty as to whether the Merger will be completed may affect our ability to retain and motivate employees. Employee retention may be particularly challenging
+while the Merger is pending because employees may experience uncertainty about their roles following consummation of the Merger. A substantial amount of our management’s and employees’ attention is being directed toward the completion of the
+Merger and thus is being diverted from our day-to-day operations. Uncertainty as to our future could adversely affect our business and our relationship with strategic partners, suppliers and our lender. Changes to or termination of existing
+business relationships could adversely affect our results of business, financial results and operations, as well as the market price of our common stock. The adverse effects of the pendency of the Merger could be exacerbated by any delays in
+completion of the Merger or termination of the Merger Agreement. 
+19 
+Table of Contents 
+Stockholder litigation could prevent or delay the consummation of the Offer and the Merger or otherwise negatively impact our
+business, financial results and operations. 
+We may incur costs in connection with the defense or settlement of existing and future stockholder litigation and demands in connection with the Offer and the
+Merger. In connection with the Offer and Merger, as of March 24, 2023, two complaints had been filed by certain purported stockholders alleging that the Schedule 14D-9, which we filed with the SEC on February 14, 2023 in connection with the
+Offer (as amended and supplemented, the “Schedule 14D-9”), contains omissions and misrepresentations that render it materially deficient and misleading. Additionally, as of March 24, 2023, we had received thirteen stockholder demand letters,
+which similarly allege that the Schedule 14D-9 contains omissions and misrepresentations that render it materially deficient and misleading. Such litigation could adversely effect our ability to complete the Offer and the Merger and result in
+the Merger being delayed or enjoined by a court of competent jurisdiction, which could prevent the consummation of the Merger. We could also incur significant costs in connection with any such litigation and demands, including costs associated
+with the indemnification of our directors and officers and settlement payments. 
+If the Merger occurs, our stockholders will not be able to participate in any financial upside to our business after the
+Merger. 
+The nature of the Merger means that the stockholders will not participate in future earnings or growth of the Company upon completion of the Merger and will not
+benefit from any appreciation in value of the surviving corporation. 
+We have incurred, and will continue to incur, direct and indirect costs as a result of the pending Merger. 
+We have incurred, and will continue to incur, significant costs and expenses, including fees for professional services and other transaction costs, in connection
+with the pending Merger. We must pay substantially all of these costs and expenses whether or not the Merger is completed. There are a number of factors beyond our control that could affect the total amount or the timing of these costs and
+expenses. 
+While the Merger Agreement is in effect, we are subject to restrictions on our business activities. 
+The Merger Agreement includes restrictions on the conduct of our business prior to the completion of the Merger, generally requiring us to conduct our business and
+operations in the ordinary course and in accordance, in all material respects, with past practice and all applicable legal requirements, and otherwise in accordance with the Merger Agreement. Without limiting the generality of the foregoing, we
+are subject to a variety of specified restrictions. Unless we obtain Biosynex’s prior written consent and except (i) as expressly permitted by the Merger Agreement, (ii) as required by applicable law, or (iii) as set forth in the disclosure
+schedule delivered by us to Biosynex, we may not, among other things and subject to certain exceptions, (a) pay dividends, (b) complete any stock splits or combinations, (c) issue additional shares of our common stock, except pursuant to the
+terms of our outstanding equity awards, (d) hire or terminate any employees, (e) amend our certificate of incorporation or bylaws, (f) form any subsidiaries, (g) enter into certain material contracts or amend or modify our current material
+contracts, (h) acquire or dispose of any rights or assets other than in the ordinary course of business or that are immaterial to our business, (i) make any pledge or mortgage of any material assets, (j) settle or release certain legal actions
+or proceedings, or (k) make or authorize any capital expenditure, except for such expenditures that fall under certain dollar thresholds. We may find that these and other contractual restrictions in the Merger Agreement delay or prevent us from
+responding, or limit our ability to respond, effectively to competitive pressures, industry developments and future business opportunities that may arise during such period, even if our management believes they may be advisable. If any of these
+effects were to occur, it could materially and adversely impact our operating results, financial position, cash flows and/or the price of our common stock. 
+20 
+Table of Contents 
+The Merger Agreement limits our ability to pursue alternative transactions, which could deter a third party from proposing an
+alternative transaction. 
+The Merger Agreement contains provisions that, subject to certain exceptions, preclude us from soliciting alternative acquisition proposals. It is possible that
+these or other provisions in the Merger Agreement might discourage a potential competing acquirer that might have an interest in acquiring all or a significant part of the outstanding shares of our common stock from considering or proposing
+an acquisition or might result in a potential competing acquirer proposing to pay a lower per share price to acquire our common stock than it might otherwise have proposed to pay. 
+Risks Related to Our Business and Our Industry 
+Our near term success is highly dependent on the success of the our DPP platform, and we cannot be certain that we will succeed
+in developing one or more of those systems or that, if we do, they will attain market acceptance or be successfully commercialized in the United States or elsewhere. 
+We do not currently have an EUA from the FDA for any of the COVID-19 Diagnostic Test Systems or for our DPP Respiratory Panel. Market and regulatory requirements
+continue to change at a rapid pace. There can be no assurance that, if we make a submission of any future EUA, we will meet the requirements of the prioritization guidance in effect at the time of the submission or otherwise be successful in
+obtaining an EUA that would permit us to offer and sell the DPP SARS-CoV-2 Antigen test system or DPP Respiratory Panel in the United States. 
+Even if we are able to obtain any such EUA, our product may not gain broad market acceptance among physicians, healthcare payors, patients, and the medical
+community. We cannot guarantee market acceptance of our product, and we only have limited information on which to estimate our anticipated level of sales. Our products will require healthcare providers and doctors to accept and adopt our
+technology. Our industry is susceptible to rapid technological developments and there can be no assurance that we will be able to match any new technological advances. Acceptance and use of any products we market will depend upon a number of
+factors including: 
+• 
+perceptions by members of the health care community, including physicians, about the safety and effectiveness of our products; 
+• 
+limitation on use or warnings required by the FDA or other global regulators in our product labeling; 
+• 
+the cost of our products relative to competing products; 
+• 
+convenience and ease of administration; 
+• 
+potential advantages of alternative diagnostic and treatment methods; 
+• 
+availability of reimbursement for our products from government or other healthcare payors; 
+• 
+effectiveness of marketing and distribution efforts by us and our licensees and distributors, if any; and 
+• 
+the ability of our diagnostic solutions to address different variants. 
+In addition, with respect to any EUA we obtain, the FDA may revoke an EUA where it is determined that the underlying health emergency no longer exists or warrants
+such authorization, and even if we obtain an EUA, we cannot predict how long such EUA would remain in place. Such revocation could materially adversely impact our business in a variety of ways, including if the relevant product is not yet
+approved by the FDA under a traditional approval pathway and if we have invested in the supply chain to provide any of our products under an EUA, and would require us to obtain a 510(k) or other marketing authorization from the FDA. If the FDA
+revokes a previously issued EUA prior to us having received regulatory approval to commercialize our DPP SARS-CoV-2 Antigen test system or DPP Respiratory Panel through a traditional approval pathway, we would be required to cease our
+commercialization efforts in the United States, which would substantially and negatively impact our business. 
+The failure of these products to find market acceptance would substantially harm our business and would adversely affect our revenue. If the DPP SARS-CoV-2 Antigen
+test system or DPP Respiratory Panel, we may not be able to generate sufficient revenue to become profitable. Any failure of one of these products to be successfully commercialized in the United States may have a material adverse effect on our
+business, operating result financial condition and cash flows, and could result in a substantial decline in the price of our common stock. In addition, the production and widely administered use of efficacious vaccines for COVID-19 may reduce
+the demand for diagnostic tests and, as a result, the COVID-19 diagnostic testing market may not develop or substantially grow. Our future success is substantially dependent on the manner in which the market for diagnostic testing develops and
+grows. If the market develops in a manner that does not facilitate demand for our products, or fails to develop or grow in the manner in which we expect or at all, our business, financial condition, results of operations and cash flows may be
+negatively affected. 
+21 
+Table of Contents 
+Clinical trials necessary to support a future test kit submission will be expensive and may require the
+enrollment of large numbers of subjects, and suitable subjects may be difficult to identify and recruit. Delays or failures in our clinical trials will prevent us from commercializing any modified or new test kits and will adversely affect
+our business, operating results and prospects. 
+The transitions contemplated by our Strategic Planning Process may not be successful. 
+Our going forward business strategy is based on our Strategic Planning Process and the transitions contemplated thereby (including our Global
+Competitiveness Program). The transitions may be disruptive to, or cause uncertainty in, our business and strategic direction. If we are unable to achieve the milestones set forth in the strategy, or the strategies implemented by our
+management team are not successful, our business could be materially harmed. 
+We expect competition with respect to testing solutions for COVID-19 to continue to increase and our success will depend on
+market acceptance of our products. 
+We expect competition to continue to increase as other established and emerging companies enter our markets, as customer requirements evolve, and as new products,
+services and technologies are introduced. The entrance of new competitors is being encouraged by governmental authorities, which are offering funding to support development of testing solutions for COVID-19. Some of our existing or new
+competitors may have strong relationships with current and potential customers, including governmental authorities that may help fund those competing entities through grant awards or other funding. As a result, those competitors may be able to
+respond more quickly to new or changing regulatory requirements, new or emerging technologies, and changes in customer requirements. We do not currently have an EUA from the FDA for any of the COVID-19 Diagnostic Test Systems. Even if we
+succeed in obtaining approvals for commercialization for one or more of the COVID-19 Diagnostic Test Systems, those products may not compete favorably, and we may not be successful in the face of existing and new products and technologies
+offered by our existing competitors or new companies entering our markets. Any failure to compete effectively could materially and adversely affect our business, financial condition and operating results. 
+Some of our programs are supported by government grant awards, and our inability to obtain additional grant awards in the
+future or to derive all of the funding potentially available under those awards could delay our development and introduction of products. 
+We have received funding under grant award programs funded by governmental agencies such as BARDA. To fund a portion of our future research and development
+programs, we may apply for additional grant funding from these or similar governmental agencies. Funding by these governmental agencies may, however, be significantly reduced or eliminated in the future for a number of reasons. For example,
+some programs are subject to a yearly appropriations process in Congress. We may not receive full funding under current or future grants because of budgeting constraints of the agency administering the program or unsatisfactory progress on the
+study being funded. 
+In addition, some or all of the funding available under grant awards may be conditioned upon our successfully meeting specified milestones or other conditions, and
+there can be no assurance that those milestones or conditions will be met. For example, in December 2020 we were awarded the Second Grant pursuant to a contract from BARDA that included funding milestones related to our development and pursuit
+of an EUA for a DPP Respiratory Antigen Panel and our submission for 510(k) clearance from the FDA for the DPP SARS CoV 2 Antigen System. 
+There can be no assurance that we will receive any future grant awards from any government agencies or that, if a grant award is obtained, we will receive the full
+amount potentially available under the grant award. Our inability to obtain future grant awards, or to earn the full amount available under those awards, could delay the development of our product candidates and the introduction of new
+products. 
+Initiating and completing clinical trials necessary to support a future EUA, 510(k), PMA, or de novo submission will be time
+consuming, expensive, and have an uncertain outcome. Moreover, the results of early clinical trials are not necessarily predictive of future results, and any test kit we advance into clinical trials may not have favorable results in later
+clinical trials. 
+Conducting successful clinical trials will require the enrollment of large numbers of subjects, and suitable subjects may be difficult to identify and recruit.
+Subject enrollment in clinical trials and completion of subject participation depends on many factors, including the nature of the trial protocol, the attractiveness of, or the discomforts and risks associated with, the indication of the
+underlying test kit, the availability of appropriate clinical trial investigators, support staff, and proximity of subjects to clinical sites and able to comply with the eligibility and exclusion criteria for participation in the clinical trial
+and subject compliance. In addition, subjects may not participate in our clinical trials if they choose to participate in contemporaneous clinical trials of competitive products. 
+22 
+Table of Contents 
+In addition, our clinical trials may in the future be affected by the COVID-19 pandemic. For example, subjects may choose not to enroll or continue participating
+in the clinical trial as a result of the pandemic. As a result, potential subjects in our clinical trials may choose to not enroll, not participate in follow-up clinical visits, or drop out of the trial as a precaution against contracting
+COVID-19. Further, some subjects may not be able or willing to comply with clinical trial protocols if quarantines impede subject movement or interrupt healthcare services. We are unable to predict with confidence the duration of any such
+potential subject enrollment delays and difficulties, whether related to COVID-19 or otherwise. Delays in subject enrollment or failure of subjects to continue to participate in a clinical trial may cause an increase in costs and delays in the
+approval and attempted commercialization of our test kits or result in the failure of the clinical trial. 
+Development of sufficient and appropriate clinical protocols to demonstrate safety and efficacy are required and we may not adequately develop such protocols to
+support clearance and approval. Further, the FDA may require us to submit data on a greater number of subjects than we originally anticipated and/or for a longer follow-up period or change the data collection requirements or data analysis
+applicable to our clinical trials. In addition, despite considerable time and expense invested in our clinical trials, the FDA may not consider our data adequate for approval. Such increased costs and delays or failures could adversely affect
+our business, operating results and prospects. 
+We have been allocating a substantial portion of our resources to the development and commercialization of DPP SARS-CoV-2
+Antigen test system, and our long term business success could be negatively impacted by our diversion of resources from our legacy business of diagnostic testing for other infectious diseases. 
+In the first quarter of 2020 we began committing substantially all of our financial and personnel resources to the development, manufacturing and commercialization
+of the DPP SARS-CoV-2 Antigen test system. Because we do not currently have an EUA from the FDA for the DPP SARS-CoV-2 Antigen test system, starting in the first quarter of 2021 we began allocating an increased portion of our resources to our
+legacy products. Our earlier and continuing resource allocation to the DPP SARS-CoV-2 Antigen test system may have negatively impacted, and may continue to negatively impact, our legacy product portfolio, as we have spent limited funds and time
+on updating pre-existing products and regulatory approvals and on completing products that were in development prior to our strategic decision to focus on the DPP SARS-CoV-2 Antigen test system. Our business could be negatively impacted by our
+allocation of significant resources to a global health threat that is unpredictable and could dissipate; there is no guarantee that current or anticipated demand will continue, or if demand does continue, that we will be able to produce in
+quantities to meet the demand. We intend to continue to reestablish our legacy business, but there can be no assurance that we will be able to successfully recommence the development and commercialization of our legacy products and products
+under development. 
+The diagnostic testing market, particularly with respect to COVID-19, is highly competitive, and many of our competitors are
+larger, better established and have greater technical and marketing capabilities and financial and other resources than we have. 
+The diagnostics market, particularly with respect to COVID-19 diagnostic tests, is highly competitive and we face substantial competition based on factors such as
+product quality, analytical performance, ease of use, price, manufacturing costs, customer service and reputation. Industry competition is also based the following additional factors: 
+• 
+patent protection; 
+• 
+scientific expertise; 
+• 
+ability to develop and market products and processes; 
+• 
+ability to obtain required regulatory approvals; 
+• 
+access to adequate capital; and 
+• 
+ability to attract and retain qualified personnel. 
+Numerous companies in the United States and internationally have introduced or announced their intention to introduce new products, services and technologies
+that could be used in substitution for the DPP SARS-CoV-2 Antigen test system. Many of those competitors are significantly larger, and have substantially greater financial, engineering and other resources, than we do. In addition, our
+competitors may have or may develop products or technologies that currently or in the future will enable them to produce competitive products with greater capabilities or at lower costs than ours. If we are unable to compete effectively, we
+may fail to meet our strategic objectives, and our business, financial condition and operating results could be harmed. In addition, the production of an efficacious vaccine or other treatment for a disease underlying one of our products may
+reduce the demand for relevant diagnostic products. The success or failure, or perceived success or failure, of other companies may adversely impact our ability to obtain any future funding, or to ultimately commercialize the DPP SARS-CoV-2
+Antigen test system. 
+23 
+Table of Contents 
+Stockholder litigation could negatively impact our business, operating results and financial condition. 
+We may incur costs in connection with the defense or settlement of existing and any future stockholder litigation, including the securities class-action and
+stockholder derivative lawsuits that have been brought against us. See “Part I, Item 3. Legal Proceedings” above and the information set forth under “Note 12 – Commitments, Contingencies And Concentrations – Litigation” to the consolidated
+financial statements included in this Annual Report on Form 10-K for additional information regarding certain existing lawsuits. These lawsuits or other future litigation may adversely affect the ability of our technical and management
+personnel, and our directors, to perform their normal responsibilities. We could incur significant costs in connection with any such litigation, including costs associated with the indemnification of obligations to our directors, officers and
+other employees, as well as to third parties. 
+We expect competition with respect to testing solutions for COVID-19 to continue to increase and our success will depend on
+market acceptance of our products. 
+We expect competition to continue to increase as other established and emerging companies enter the market, as customer requirements evolve, and as new products,
+services and technologies are introduced. The entrance of new competitors is being encouraged by governmental authorities, which are offering funding to support development of testing solutions for COVID-19. Some of our existing or new
+competitors may have strong relationships with current and potential customers, including governmental authorities that may help fund those competing entities through grant awards or other funding. As a result, those competitors may be able to
+respond more quickly to new or changing regulatory requirements, new or emerging technologies, and changes in customer requirements. We do not currently have, or have an application pending for, an EUA from the FDA for any of the COVID-19
+Diagnostic Test Systems. Even if we succeed in obtaining approvals for commercialization for one or more of the COVID-19 Diagnostic Test Systems, those products may not compete favorably, and we may not be successful in the face of existing and
+new products and technologies offered by our existing competitors or new companies entering our markets. Any failure to compete effectively could materially and adversely affect our business, financial condition and operating results. 
+The COVID-19 pandemic could continue to affect our suppliers and employees, and cause disruptions in current and future
+plans for operations and expansion. 
+The COVID-19 pandemic may continue to directly and indirectly adversely impact our business, financial condition and operating results. The extent to which this
+will continue will depend on numerous evolving factors that are highly uncertain, rapidly changing and cannot be predicted with precision or certainty at this time. 
+Our business may continue to be disrupted due to the costs incurred as a result of additional necessary actions and preparedness plans to help ensure the health
+and safety of our employees and continued operations, including enhanced cleaning processes, protocols designed to implement appropriate social distancing practices, and/or adoption of additional wage and benefit programs to assist employees.
+We may also have difficulty meeting demand for our products if our employees are affected by COVID-19, or if we do not have adequate space to produce our product with social distancing practices implemented. We also cannot predict the effect of
+COVID-19 pandemic on our supply chain’s reliability and costs. 
+In addition, our business and operations, and the operations of our suppliers, may continue to be adversely affected by the COVID-19 pandemic. The pandemic,
+including the related response, could cause disruptions due to potential suspension or slowdown of activities at our third-party suppliers, manufacturing delays, or increased prices implemented by our suppliers. The COVID-19 pandemic has
+disrupted nearly every aspect of the global supply chain, including the manufacturing or delivery of some of the key supplies used in our tests. Many suppliers are experiencing shortages of required personnel as the result of the tight labor
+market and underlying raw material commodities. Some suppliers have been unable to deliver supplies in the quantity we need or at all. As a result, these suppliers may stop supplying us components and materials, limit the allocation of supply
+and equipment to us due to increased industry demand, or significantly increase their prices at any time with little or no advance notice. The adverse effect on our employees or suppliers could have an adverse impact on our business, results of
+operations and financial condition. 
+24 
+Table of Contents 
+We operate in a fragmented, segmented, and rapidly changing industry, which is highly competitive with respect to numerous
+factors, and our success depends on our ability compete effectively with larger companies, develop new or enhance existing products, as well as acceptance of DPP over other diagnostic platform technologies. 
+Important competitive factors for our products include price, quality, performance, ease of use, and customer service. A few large corporations produce a wide
+variety of diagnostic tests and other medical devices and equipment. A larger number of mid-size companies generally compete only in the diagnostic industry and a significant number of small companies produce only a few diagnostic products. As
+a result, the diagnostic test industry is highly fragmented and segmented. 
+More generally, the point-of-care diagnostics industry is undergoing rapid technological changes, with frequent introductions of new technology-driven products and
+services. As new technologies become introduced into the point-of-care diagnostic testing market, we may be required to commit considerable additional efforts, time and resources to enhance our current product portfolio or develop new products.
+We may not have the available time and resources to accomplish this, and many of our competitors have substantially greater financial and other resources to invest in technological improvements. We may not be able to effectively implement new
+technology-driven products and services or be successful in marketing these products and services to our customers, which would materially harm our operating results. 
+Although we own DPP patents, lateral flow technology is still a competitive platform to DPP, and lateral flow technology has a lower cost of manufacture than DPP
+products. Although the DPP platform has shown improved sensitivity as compared with conventional lateral flow platforms in a number of studies, several factors go into the development and performance attributes of products. Therefore the
+ability of our products to successfully compete will depend on several other factors, including our having a patented rapid test platform technology that differentiates DPP from lateral flow as well as from other diagnostic platform
+technologies. There can be no assurance that our DPP patents or our products incorporating those patents will not be challenged at some time in the future. 
+Our competitors may develop and commercialize more effective or successful products, and our research, development and
+commercialization efforts may not succeed. 
+We regularly commit substantial resources to research and development and the commercialization of our new or enhanced products. The research and development
+process usually takes a long time from inception to commercial launch. During each stage of this process there is a substantial risk that we will not achieve our goals in a timely fashion, or at all, and we may have to abandon a new or enhanced
+product in which we have invested substantial time and money. We expect to continue to incur significant costs related to our research and development activities. 
+Our products require significant development and investment prior to commercialization, including testing to demonstrate the products’ performance capabilities,
+cost-effectiveness or other benefits. We must obtain regulatory approval before most products may be sold and additional development efforts on these products may be required before the products will be reviewed. However, regulatory authorities
+may not approve these products for commercial sale or may substantially delay or condition such approval. There may be little or no market for the product and entry into or development of new markets for our products may require an investment
+of substantial resources even if all applicable regulatory approvals are obtained. Furthermore, we may spend a significant amount of money on advertising or other activities and still fail to develop a market for the product. The success of our
+efforts may be affected by our ability to manufacture products in a cost-effective manner, whether we can obtain necessary intellectual property rights and protection and our ability to obtain reimbursement authorizations in the markets where
+the product will be sold. Therefore, if we fail to develop and gain commercial acceptance for our products, or if competitors develop more effective products or a greater number of successful new products, customers may decide not to purchase
+our products. 
+25 
+Table of Contents 
+Our products may not be able to compete with new diagnostic products or existing products developed by well-established
+competitors, which would negatively affect our business. 
+The diagnostic industry is focused on the testing of biological specimens in a laboratory or at the point-of-care and is highly competitive and rapidly changing.
+Important competitive factors for our products include price, quality, performance, ease of use, and customer service. 
+A few large corporations produce a wide variety of diagnostic tests and other medical devices and equipment. A larger number of mid-size companies generally
+compete only in the diagnostic industry and a significant number of small companies produce only a few diagnostic products. As a result, the diagnostic test industry is highly fragmented and segmented. 
+Some of our principal competitors may have considerably greater financial, technical and marketing resources than we do. Several companies produce diagnostic tests
+that compete directly with our testing product line, including Abbott (Alere), OraSure Technologies and Trinity Biotech. Some competitors offer broader product lines and may have greater name recognition than we have. These and other companies
+have or may have products incorporating molecular or other advanced technologies that over time could directly compete with our testing product line. We also face competition from certain of our distributors or former customers that have
+created or may decide to create, their own products to compete with ours. 
+As new products incorporating new technologies enter the market, our products may become obsolete or a competitor’s products may be more effective or more
+effectively marketed and sold. If our competitors’ products take market share from our products through more effective marketing or competitive pricing, our revenues, margins and operating results could be adversely affected. In addition, our
+revenues and operating results could be negatively impacted if some of our customers internally develop or acquire their own sample collection devices and use those devices in place of our products in order to reduce costs. 
+Our future revenues and operating results may be negatively affected by ongoing consolidation in the healthcare industry. 
+There has been a significant amount of consolidation in the healthcare industry. This consolidation has increased the competition to provide goods and services to
+customers. In addition, group purchasing organizations and integrated health delivery networks have served to concentrate purchasing decisions for some customers, which has also placed pricing pressure on medical device suppliers. Due to
+ongoing consolidation, there could be additional pressure on the prices of our products. 
+Our continued growth depends on retaining our current key employees and attracting additional qualified personnel, and we
+may not be able to do so. 
+Our success depends to a large extent upon the skills and experience of our executive officers, sales, marketing, operations and scientific staff. We may not be
+able to attract or retain qualified employees due to the intense competition for qualified personnel among medical products businesses and academic and other research institutions, as well as to geographic considerations, our ability to offer
+competitive compensation and benefits, and other reasons. 
+If we are not able to attract and retain the necessary qualified personnel to accomplish our business objectives, we may experience constraints that will adversely
+affect our ability to effectively manufacture, sell and market our products to meet the demands of our customers and strategic partners in a timely fashion, or to support internal research and development programs. 
+We have entered into employment contracts with our Chief Executive Officer, Richard Eberly, our Chief Science & Technology Officer, Javan Esfandiari, and our
+Chief Financial Officer, Lawrence J. Steenvoorden. Due to the specific knowledge and experience of these executives regarding the industry, technology and market generally and to our company specifically, the loss of the services of any one of
+these executives could have a material adverse effect on us. We have not obtained a key man insurance policy on any officers other than Messrs. Eberly, Esfandiari and Steenvoorden. 
+26 
+Table of Contents 
+Third-party reimbursement policies and potential cost constraints could negatively affect our business. 
+The potential end-users of our products include hospitals, physicians and other healthcare providers. If these end-users do not receive adequate reimbursement for
+the cost of our products from their patients’ healthcare insurers or payors, the use of our products could be negatively impacted. Furthermore, the net sales of our products could also be adversely affected by changes in reimbursement policies
+of government or private healthcare payors. 
+Hospitals, physicians and other healthcare providers who purchase diagnostic products in the United States generally rely on third-party payors, such as private
+health insurance plans, Medicare and Medicaid, to reimburse all or part of the cost of the product. Due to the overall escalating cost of medical products and services, especially in light of the COVID-19 outbreak and its straining of
+healthcare systems across the globe, there is increased pressure on the healthcare industry, both foreign and domestic, to reduce the cost of products and services. Given the efforts to control and reduce healthcare costs in the United States,
+available levels of reimbursement may change for our existing products or products under development. Third-party reimbursement and coverage may not be available or adequate in either the United States or international markets, current
+reimbursement amounts may be decreased in the future and future legislation, and regulation or reimbursement policies of third-party payors, may reduce the demand for our products or our ability to sell our products on a profitable basis. 
+To the extent that we are unable to collect our outstanding accounts receivable, our operating results could be materially
+harmed. 
+There may be circumstances and timing that require us to accept payment terms, including delayed payment terms, from distributors or customers, which, if not
+satisfied, could cause financial losses. We generally accept payment terms which require us to ship product before the contract price has been paid fully, and there also are circumstances pursuant to which we may accept further delayed payment
+terms pursuant to which we may continue to deliver product. To the extent that these circumstances result in significant accounts receivables and those accounts receivables are not paid on a timely basis, or are not paid at all, especially if
+concentrated in one or two customers, we could suffer financial losses. 
+We believe our success depends in part on the continued funding of, and our ability to participate in, large testing
+programs in the United States and worldwide, the funding of which may be reduced or discontinued or otherwise be unavailable to us. 
+We believe it to be in our best interests to meaningfully participate in large testing programs. Moreover many of these programs are funded by governments and
+other donors, and there can be no assurance that funding will not be reduced or completely discontinued. Participation in these programs also requires alignment and engagement with the many other participants in these programs, including the
+WHO, the U.S. Centers for Disease Control and Prevention, the U.S. Agency for International Development, foreign governments and their agencies, non-governmental organizations, and HIV service organizations. If we are unsuccessful in our
+efforts to participate in these programs, our operating results could be materially harmed. 
+Developing testing guidelines could negatively affect sales of our products. 
+Government agencies may issue diagnostic testing guidelines or recommendations, which can alter the usage of our HIV testing products. New laws or guidelines, or
+changes to existing laws or guidelines, and the manner in which these new or changed laws and guidelines are interpreted and applied, could impact the degree to which our testing products are used. These developments could affect the frequency
+of testing, the number of people tested and whether the testing products are used broadly for screening large populations or in a more limited capacity. These factors could in turn affect the level of sales of our products and our results of
+operations. 
+We could be exposed to liability if we experience security
+breaches or other disruptions, which could harm our reputation and business . 
+We may be subject to cyber-attacks whereby computer hackers may attempt to access our computer systems or our third-party IT service providers’ systems and, if
+successful, misappropriate personal or confidential information. In addition, a contractor or other third party with whom we do business may attempt to circumvent our security measures or obtain such information, and may purposefully or
+inadvertently cause a breach involving sensitive information. We will continue to evaluate and implement additional protective measures to reduce the risk and detect cyber incidents, but cyber-attacks are becoming more sophisticated and
+frequent and the techniques used in such attacks change rapidly. Even though we take cyber-security measures that are continuously reviewed and updated, our information technology networks and infrastructure may still be vulnerable due to
+sophisticated attacks by hackers or breaches. 
+27 
+Table of Contents 
+Even the most well protected IT networks, systems, and facilities remain potentially vulnerable because the techniques used in security breaches are continually
+evolving and generally are not recognized until launched against a target and, in fact, may not be detected. Any such compromise of our or our third party’s IT service providers’ data security and access, public disclosure, or loss of personal
+or confidential business information, could result in legal claims proceedings, liability under laws to protect, privacy of personal information, and regulatory penalties, disrupt our operations, require significant management attention and
+resources to remedy any damages that result, damage our reputation and customers willingness to transact business with us, any of which could adversely affect our business. 
+Our ability to efficiently operate our business is reliant on information technology, and any material failure, inadequacy,
+interruption or security breach of that technology could harm our business. 
+We rely heavily on complex information technology systems across our operations and on the internet, including for management of inventory, invoices, purchase
+orders, shipping, interactions with our third-party logistics providers, revenue and expense accounting, consumer call support, and various other processes and transactions. Our ability to effectively manage our business, coordinate the
+production, distribution and sale of our products, respond to customer inquiries, and ensure the timely and accurate recording and disclosure of financial information depends significantly on the reliability and capacity of these systems and
+the internet. 
+If any of the foregoing systems fails to operate effectively, problems with transitioning to upgraded or replacement systems, or disruptions in the operation of
+the internet, could cause delays in product sales and reduced efficiency of our operations. Significant expenditures could be required to fix any such problem. 
+If there is an increase in demand for our products, it could require us to expend considerable resources or harm our
+customer relationships if we are unable to meet that demand. 
+If there are significant or unexpected increases in the demand for our products, we may not be able
+to meet that demand without expending additional capital resources. This would increase our capital costs, which could negatively affect our earnings and liquidity in the short term. In addition, new manufacturing equipment or facilities may require FDA, WHO, and other regulatory approvals before they can be used
+to manufacture our products. To the extent we are unable to obtain or are delayed in obtaining such approvals, our ability to meet the demand for our products could be adversely affected. Furthermore, our suppliers may be unable or unwilling
+to expend the necessary capital resources or otherwise expand their capacity, which could negatively affect our business. 
+Our business could be negatively affected if we or our suppliers are unable to develop necessary manufacturing capabilities in a timely manner. If we fail to
+increase production volumes in a cost effective manner or if we experience lower than anticipated yields or production problems as a result of changes that we or our suppliers make in our manufacturing processes to meet increased demand, we
+could experience shipment delays or interruptions and increased manufacturing costs, which could also have a material adverse effect on our revenues and profitability. 
+If there are unexpected increases in demand for our products, we may be required to obtain additional raw materials in order to manufacture products to meet the
+increase in demand. However, some raw materials require significant ordering lead time and some are currently obtained from a sole supplier or a limited group of suppliers. It is also possible that one or more of our suppliers may become
+unwilling or unable to deliver materials to us. Any shortfall in our supply of raw materials and components, or our inability to quickly and cost-effectively obtain alternative sources for this supply, could have a material adverse effect on
+our ability to meet increased demand for our products. This could negatively affect our total revenues or cost of sales and related profits. 
+If we are unable to meet customer demand for our products, it could also harm our relationships with our customers and impair our reputation within the industry.
+This, in turn, could have a material adverse effect on our business. 
+28 
+Table of Contents 
+Risks Related to Our Products 
+Industry adoption of alternative technology to our COVID-19 Diagnostic Test Systems could negatively impact our ability to
+compete successfully. 
+Customers or the industry as a whole could adopt alternative technologies for testing, including molecular point of care testing, which could result in lower
+demand for our antigen test. Various advances in the treatment and monitoring of patients could cause lower demand for the COVID-19 Diagnostic Test Systems, including our revised DPP SARS-CoV-2 Antigen System or for antigen testing for COVID-19
+as a whole. 
+COVID-19 is prone to genetic mutations that may impact the ability of the COVID-19 Diagnostic Test Systems to adequately
+detect COVID-19, SARS-CoV-2 antigens and antibodies, and could adversely affect demand for the COVID-19 Diagnostic Test Systems and harm our competitive position. 
+False test results are a risk with all laboratory tests, including COVID-19 diagnostic tests. False results can occur in the presence or absence of a mutation in
+the COVID-19 virus. Multiple variations of the virus that causes COVID-19 are circulating globally and within the United States, including variants of concern initially identified in California, Brazil, South Africa and the United Kingdom. In
+the presence of a mutation in the virus, false results can occur if a mutation occurs in the region of the virus that the test is designed to assess. False results may occur with the COVID-19 Diagnostic Test Systems in the presence or absence
+of one or more COVID-19 mutations. If false negatives occur with the COVID-19 Diagnostic Test Systems, it will may reduce customer confidence in the accuracy of the COVID-19 Diagnostic Test Systems and harm our competitive position. 
+For our business to succeed in the future, our current and future products must receive market acceptance. 
+Market acceptance and the timing of such acceptance of our new products or technologies is necessary for our future success. To achieve market acceptance, we and
+our distributors will likely be required to undertake substantial efforts and spend significant funds to inform the public of the existence and perceived benefits of our products. We also may require government funding for the purchase of our
+products to help create market acceptance and expand the use of our products. 
+It may be difficult evaluate the market reaction to our products and our marketing efforts for new products may not be successful. The government funding we
+receive may be limited for new products. As such, there can be no assurance that any products will obtain significant market acceptance and fill the market need that is perceived to exist on a timely basis, or at all. 
+We may not have sufficient resources to effectively introduce and market our products, which could materially harm our
+operating results. 
+Introducing and achieving market acceptance for our new products will require substantial marketing efforts and will require us and/or our contract partners, sales
+agents, and/or distributors to make significant expenditures of time and money. In some instances we will be significantly or totally reliant on the marketing efforts and expenditures of our contract partners, sales agents, and distributors. If
+they do not have or commit the expertise and resources to effectively market the products that we manufacture, our operating results will be materially harmed. 
+New developments in health treatments and non-diagnostic products may reduce or eliminate the demand for our products. 
+The development and commercialization of products outside of the diagnostics industry could adversely affect sales of our products. For example, the development of
+a safe and effective vaccine to COVID-19 or HIV or treatments for other diseases or conditions that our products are designed to detect, could reduce or eventually eliminate the demand for our HIV or other diagnostic products and result in a
+loss of revenues. 
+Our future success will depend on our ability to cost-effectively increase manufacturing production capacity through the
+implementation of additional customized manufacturing automation equipment. 
+If we successfully commercialize the COVID-19 Diagnostic Test Systems or other new products, one of our key challenges will be to increase our production
+capacity to meet sales demand while maintaining product quality and reducing production costs. Our primary strategy to cost-effectively increase product capacity has been to implement customized automation equipment, and we have entered into
+agreements to acquire additional customized automation equipment. The equipment we order may not be delivered in a timely manner, and, once delivered, the equipment may require significant time and effort in order to operate in the manner
+required to produce high quality products. We experienced significant unexpected delays before our current automation equipment operated in the manner for which it was designed. The investments we make in this equipment may not yield the
+anticipated labor and material efficiencies. If we are not successful in introducing COVID-19 Diagnostic Test Systems or other new products in accordance with our operating plans, we do not have the right to terminate the existing purchase
+orders for additional automation equipment and we may have excess capacity for a period of time. Our business, financial condition and results of operations could be harmed if we are unable to timely obtain automation equipment that meets our
+requirements or if there are significant increases in the costs of equipment. 
+29 
+Table of Contents 
+Customer concentration creates risks for our business. 
+A significant portion of our revenues each year comes from a few large customers. Bio-Manguinhos constituted 38% of our total revenues in 2022 and 51% of our total
+revenues in 2021. We had another customer that accounted for 16% of our total revenues in 2022, and a third customer that accounted for 10% of our total revenue in 2021. To the extent that Bio-Manguinhos or any other large customer fails to
+meet its purchase commitments, changes its ordering patterns or business strategy, or otherwise reduces its purchases or stops purchasing our products, or if we experience difficulty in meeting the demand by these customers for our products,
+our revenues and results of operations could be adversely affected. 
+Sales cycles for our products can be lengthy, which can cause variability and unpredictability in our business. 
+Some of our products may require lengthy and unpredictable sales cycles, which makes it more difficult to accurately forecast revenues in a given period and may
+cause revenues and operating results to vary from period to period. Our products may involve sales to large public and private institutions which may require many levels of approval and may be dependent on economic or political conditions and
+the availability of grant awards or other funding from government or public health agencies which can vary from period to period. There can be no assurance that purchases or funding from these agencies will occur or continue, especially if
+current negative economic conditions continue or intensify. As a result, we may expend considerable resources on unsuccessful sales efforts or we may not be able to complete transactions at all or on a schedule and in an amount consistent with
+our objectives. 
+We may face product liability claims for injuries. 
+The testing, manufacturing and marketing of medical diagnostic products involves an inherent risk of product liability claims. If we cannot successfully defend
+ourselves against product liability claims, we may incur substantial liabilities or be required to limit or cease sales of our products. We cannot be sure that we will not incur liabilities in excess of the policy limits of our existing product
+liability insurance coverage or that we will be able to continue to obtain adequate product liability insurance coverage in the future at an acceptable cost, or at all. In addition, a defect in the design or manufacture of our products could
+have a material adverse effect on our reputation in the industry and subject us to claims of liability for injury and otherwise. Any substantial underinsured loss resulting from such a claim could have a material adverse effect on our
+profitability, and the damage to our reputation in the industry could have a material adverse effect on our business. 
+Our customers may not adopt rapid point-of-care diagnostic testing. 
+Rapid point-of-care tests are beneficial because, among other things, they can be administered by healthcare providers in their own facilities or used by consumers
+at home without sending samples to central laboratories. However, the majority of diagnostic tests used by physicians and other healthcare providers in the United States are currently provided by clinical reference laboratories and
+hospital-based laboratories. In some international markets, such as Europe, diagnostic testing is performed primarily by centralized laboratories. Future sales of our products will depend, in part, on our ability to expand market acceptance of
+rapid point-of-care testing and successfully compete against laboratory testing methods and products. However, we expect that clinical reference and other hospital-based laboratories will continue to compete vigorously against our rapid
+point-of-care products. Even if we can demonstrate that our products are more cost effective, save time, or have better performance or other benefits, physicians, other healthcare providers and consumers may resist changing to rapid
+point-of-care tests and instead may choose to obtain diagnostic results through laboratory tests. If we fail to achieve and expand market acceptance of our rapid point-of-care diagnostic tests with customers, it would have a negative effect on
+our future sales growth. 
+30 
+Table of Contents 
+If our products do not perform properly, it may affect our revenues, stock price and reputation. 
+Our products may not perform as expected. For example, a defect in one of our diagnostic products or a failure by a customer to follow proper testing procedures
+may cause the product to report inaccurate information. Identifying the root cause of a product performance or quality issue can be difficult and time consuming. 
+If our products do not to perform in accordance with the applicable label claims or otherwise in accordance with the expectations or needs of our customers,
+customers may switch to a competing product or otherwise stop using our products, and our revenues could be negatively affected. If this occurs, we may be required to implement holds or product recalls and incur warranty obligations.
+Furthermore, the poor performance by one or more of our products could have an adverse effect on our reputation, our continuing ability to sell products and the price of our common stock. 
+Financial, Economic and Financing Risks 
+Because of our liquidity limitations, we have concluded there is a substantial doubt about our ability to continue as a
+going concern and we may require additional capital to fund our operations, which capital may not be available to us on acceptable terms or at all. 
+As described under “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Likely Default Under Credit Agreement,”
+“—Going Concern Considerations” and “—Liquidity and Capital Resources,” management has determined we could not be certain that our plans and initiatives to increase our total revenues and improve our liquidity position would be effectively
+implemented within one year after the filing date of this report, when the accompanying financial statements are being issued. Without giving effect to the prospect of raising additional capital, increasing product revenue in the near future or
+executing other mitigating plans, many of which are beyond our control, it is unlikely that we will be able to generate sufficient cash flows to meet our required financial obligations, including our debt service and other obligations due to
+third parties. The existence of these conditions raises substantial doubt about our ability to continue as a going concern for the twelve-month period following the filing date of this report, when the accompanying financial statements are
+being issued. 
+Our diagnostic test products require ongoing funding to continue our current development and operational plans, and we have a history of net losses. We may
+encounter challenges in fulfilling our obligations, and therefore receiving revenue, under those purchase orders. We will also incur costs associated with research and development activity, corporate administration, business development, debt
+service, marketing and selling of our products, and litigation. In addition, other unanticipated costs may arise. 
+As of December 31, 2022, we had a loan balance, net of unamortized discounts and debt issuance costs, of $18.6 million under the Credit Agreement. We may face
+further liquidity challenges if we are unable to meet our obligations set forth in the Credit Agreement, including a financial covenant requiring that we achieve specified minimum total revenue amounts measured as of the end of each quarter. A
+breach of the minimum total revenue covenant or any other covenant in the Credit Agreement would result in a default under the Credit Agreement, which could enable the Lender to declare all amounts outstanding thereunder, together with accrued
+interest, to be immediately due and payable. We do not believe that we will comply with the minimum total revenue covenant for the twelve months ended March 31, 2023. We cannot assure you that, in such an event, we would have sufficient assets
+to pay amounts due under the Credit Agreement. If we are unable to pay any such amounts due under the Credit Agreement, we would likely be forced to pursue a reorganization proceeding under Chapter 11 of the U.S. Bankruptcy Code. 
+31 
+Table of Contents 
+As a result, we will need to raise capital in one or more debt or equity offerings to fund our operations and obligations. There can be no assurance, however, that
+we will be successful in raising the necessary capital or that any such offering will be available to us on terms acceptable to us, or at all. If we are unable to raise additional capital that may be needed on terms in sufficient amounts or on
+terms acceptable to us, it could have a material adverse effect on our company. If we are unable to raise additional capital in sufficient amounts or on terms acceptable to us, we may have to delay the implementation of our new strategic plan
+and otherwise significantly delay, scale back or discontinue our deliveries under our outstanding customer purchase orders or the development or commercialization of one or more of our products or one or more of our other research and
+development initiatives. The effects of COVID-19 have significantly disrupted world financial markets and negatively impacted U.S. market conditions, and they may reduce opportunities for us to seek out additional funding. A decline in the
+market price of our common stock, whether or not coupled with the suspension of trading of our common stock on The Nasdaq Capital Market, could make it more difficult for us to sell equity or equity-related securities in the future at a time
+and price that we deem appropriate, or at all. Moreover, on April 5, 2022, we received notification from the Listing Qualifications Department of Nasdaq stating that the Company did not comply with the Bid Price Requirement. In accordance with
+Nasdaq listing rules, the Company was afforded 180 calendar days (until October 3, 2022) to regain compliance with the Bid Price Requirement. On October 4, 2022, the Company received written notice from Nasdaq stating that, although the Company
+had not regained compliance with the Bid Price Requirement by October 3, 2022, in accordance with Nasdaq Listing Rule 5810(c)(3)(A), the Company is eligible for an additional 180 calendar day period, or until April 3, 2023, to regain compliance
+with the Bid Price Requirement. To regain compliance, the closing bid price of the Company’s common stock must meet or exceed $1.00 per share for a minimum of ten consecutive business days during this additional 180-day period, all as described
+in more detail in the Current Reports on Form 8-K we filed with the SEC on April 7, 2022 and October 4, 2022. We do not believe that we will regain compliance with the Bid Price Requirement by the April 3, 2023 deadline, and there can be no
+assurance that we will ever be able to do so. Given the current trading price of our common stock, it is likely that we will receive a delisting notification from Nasdaq. Our inability to regain compliance with the Bid Price Requirement would,
+and the existence of the pending deficiency letter could, materially impair our ability to raise capital. 
+Continuing doubt about our ability to continue as a going concern may materially and adversely affect the price of our common stock, and it may be more difficult
+for us to obtain financing. Any uncertainty about our ability to continue as a going concern may also adversely affect our relationships with current and future employees, suppliers, vendors, customers, grantors, creditors, regulators and
+investors, who may become concerned about our ability to meet our ongoing financial obligations. There is risk that, among other things: 
+• 
+third parties lose confidence in our ability to continue to operate in the ordinary course, which could impact our ability to execute on our business strategy; 
+• 
+it may become more difficult for us to attract, retain or replace employees; 
+• 
+employees could be distracted from performance of their duties; 
+• 
+we could lose some or a significant portion of our liquidity, either due to stricter credit terms from vendors, or, in the event we undertake a Chapter 11 proceeding and
+conclude that we need to procure debtor-in-possession financing, an inability to obtain any needed debtor-in-possession financing or to provide adequate protection to certain secured lenders to permit us to access some or all of our
+cash; and 
+• 
+our vendors and service providers could seek to renegotiate the terms of our arrangements, terminate their relationships with us or require financial assurances from us. 
+The accompanying financial statements have been prepared assuming we will continue as a going concern, which contemplates continuity of operations, realization of
+assets and the satisfaction of liabilities in the normal course of business for the twelve-month period following the date of this report. As such, the accompanying financial statements do not include any adjustments relating to the
+recoverability and classification of assets and their carrying amounts, or the amount and classification of liabilities that may result should we be unable to continue as a going concern. 
+Additionally, we are currently subject to the SEC’s baby shelf rule and the amount of funds we can raise through primary public offerings of securities in any
+12-month period using our registration statement on Form S-3 is limited to one-third of the aggregate market value of the voting and non-voting common equity held by non-affiliates. We will be limited by the baby shelf rule until such time, if
+any, as our public float exceeds $75 million. 
+32 
+Table of Contents 
+Our failure to meet the minimum bid price for continued listing on The Nasdaq Capital Market could adversely affect our
+ability to publicly or privately sell equity securities and the liquidity of our common stock. 
+On April 5, 2022, we received notification from the Listing Qualifications Department of The Nasdaq Stock Market, or Nasdaq, stating that the Company did not
+comply with the minimum $1.00 bid price requirement for continued listing set forth in Nasdaq Listing Rule 5550(a)(2) (the “Bid Price Requirement”). In accordance with Nasdaq listing rules, the Company was afforded 180 calendar days (until
+October 3, 2022) to regain compliance with the Bid Price Requirement. On October 4, 2022, the Company received written notice from Nasdaq stating that, although the Company had not regained compliance with the Bid Price Requirement by October
+3, 2022, in accordance with Nasdaq Listing Rule 5810(c)(3)(A), the Company is eligible for an additional 180 calendar day period, or until April 3, 2023, to regain compliance with the Bid Price Requirement. To regain compliance, the closing bid
+price of the Company’s common stock must meet or exceed $1.00 per share for a minimum of ten consecutive business days during this additional 180-day period, all as described in more detail in the Current Reports on Form 8-K filed with the SEC
+on April 7, 2022 and October 4, 2022. The closing price of our common stock was $0.39 on March 24, 2023. We do not believe that we will regain compliance with the Bid Price Requirement by the April 3, 2023 deadline, and there can be no
+assurance that we will ever be able to do so. Given the current trading price of our common stock, it is likely that we will receive a delisting notification from Nasdaq. Our inability to regain compliance with the Bid Price Requirement would,
+and the existence of the pending deficiency letter could, materially impair our ability to raise capital. Moreover, if we were unable to regain compliance with the Bid Price Requirement, our common stock would likely then trade only in the
+over-the-counter market and the market liquidity of our common stock could be adversely affected and its market price could decrease. If our common stock were to trade on the over-the-counter market, selling our common stock could be more
+difficult because smaller quantities of shares would likely be bought and sold, transactions could be delayed, and we could face significant material adverse consequences, including: a limited availability of market quotations for our
+securities; reduced liquidity with respect to our securities; a determination that our shares are a “penny stock,” which will require brokers trading in our securities to adhere to more stringent rules, possibly resulting in a reduced level of
+trading activity in the secondary trading market for our securities; a reduced amount of news and analyst coverage; and a decreased ability to issue additional securities or obtain additional financing in the future. These factors could result
+in lower prices and larger spreads in the bid and ask prices for our common stock and would substantially impair our ability to raise additional funds and could result in a loss of institutional investor interest and fewer development
+opportunities for us. 
+Failure to maintain effective internal controls could cause our investors to lose confidence in us and adversely affect the
+market price of our common stock. If our internal controls are not effective, we may not be able to accurately report our financial results or prevent fraud. 
+Effective internal control over financial reporting is necessary for us to provide reliable financial reports in a timely manner. In connection with the audit of
+our financial statements for the year ended December 31, 2022, our independent registered public accounting firm identified a material weakness. A material weakness is a significant deficiency, or a combination of significant deficiencies, in
+internal controls over financial reporting such that it is reasonably possible that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. The material weakness that has been
+identified by our independent registered public accounting firm relates to the inventory costing process. While we intend to take steps to remediate the material weakness in our internal control over financial reporting by formalizing certain
+accounting policies and internal control documentation, we may not be successful in remediating such weaknesses in a timely manner, if at all, which may undermine our ability to provide accurate, timely and reliable reports on our financial and
+operating results. Furthermore, if we remediate our current material weakness but identify new material weaknesses in our internal control over financial reporting in the future, investors may lose confidence in the accuracy and completeness of
+our financial reports and the market price of our common stock may be negatively affected. As a result of such failures, we could also become subject to investigations by Nasdaq, the SEC, or other regulatory authorities, and become subject to
+litigation from investors and stockholders, which could harm our reputation, financial condition or divert financial and management resources from our business. 
+You may experience future dilution as a result of future equity offerings, exercises of outstanding options and vesting of
+options and restricted and performance stock units. 
+On July 19, 2021, we entered into the ATM Agreement, pursuant to which we may sell from time to time, at our option, up to an aggregate of $60,000,000 of shares of
+common stock through Craig-Hallum, as sales agent. As of the filing date of this report, we have issued and sold pursuant to the ATM Agreement a total of 16,175,519 shares of common stock at a volume-weighted average price of $2.81 per share
+for gross proceeds of $45.4 million and net proceeds, after giving effect to placement fees and other transaction costs, of $43.1 million. For additional information about the at-the-market offerings pursuant to the ATM Agreement, see “Part II,
+Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”. 
+In order to raise additional capital, we may seek to offer pursuant to the ATM Agreement additional shares of common stock for up to $14.6 million in gross
+proceeds and we may in the future offer additional shares of our common stock or other securities convertible into or exchangeable for our common stock. There can be no assurance that we will be able to sell additional shares in at-the-market
+offerings made pursuant to the ATM Agreement, or in any other offering, at a price per share that is equal to or greater than the price per share paid by existing stockholders. Investors purchasing securities in other offerings in the future
+could have rights superior to existing stockholders. 
+Additionally, we are currently subject to the SEC’s baby shelf rule and the amount of funds we can raise pursuant to the ATM Agreement or through other primary
+public offerings of securities in any 12-month period using our registration statement on Form S-3 is limited to one-third of the aggregate market value of the voting and non-voting common equity held by non-affiliates. We will be limited by
+the baby shelf rule until such time, if any, as our public float exceeds $75 million. 
+33 
+Table of Contents 
+As of the close of business on December 31, 2022, our market capitalization was approximately $1.15 million. Existing stockholders may experience significant
+dilution in connection with our issuance and sale of up to $14.6 million of additional shares of common stock pursuant to the ATM Agreement. In addition, as of December 31, 2022, 226,702 shares of common stock were reserved for future issuance
+under our 2019 Omnibus Incentive Plan, 3,657,163 shares were subject to outstanding options, and 1,588,387 shares were subject to outstanding restricted and performance stock units. Stockholders will incur dilution upon vesting of restricted
+and performance stock units, and they may incur dilution upon exercises of stock options. 
+We have incurred losses in recent years and we are uncertain about our future profitability and cash flow. 
+We incurred an operating loss every year from 2014 through 2022. Under our operating plans, we have made, and plan to continue to make, significant investments in
+our production capacity, including in expanding facilities and automating manufacturing, and in our sales and marketing, regulatory approval, and research and development activities. Our ability to achieve profitability and generate cash flow
+in the future will depend on our ability to increase sales of our existing products and to successfully introduce new and enhanced products into the marketplace, all while controlling and managing our expenses consistent with our operating
+plan. 
+Because we do not currently have an EUA from the FDA for any of the COVID-19 Diagnostic Test Systems, we have been unable to increase our revenues in accordance
+with our operating plan. As a result, our operating results have not met our expectations. If we experience a continuing delay in obtaining, or are unable to obtain, an EUA for one or more of our COVID-19 Diagnostic Test Systems, our operating
+results will be further harmed and we may not be able to generate the cash flow needed to fund the investments in our production capacity and other activities. In such an event, we will be required to implement one or both of the following: 
+• 
+We could reduce the level, or otherwise delay the timing, of the anticipated investments in our production capacity and other activities, which would likely curtail or delay
+the growth in our business contemplated by our operating plan and could impair or defer our ability to achieve profitability and generate cash flow. Moreover, if we were to further reduce the number of our personnel, there can be no
+assurance that we would be able, when desirable, to successfully rehire or rebuild our workforce. 
+• 
+We could raise additional funds through public or private financings, strategic relationships, or other arrangements, to the extent funding would be available to us on
+acceptable terms or at all. If we succeed in raising additional funds through the issuance of equity or convertible securities, then the issuance could result in substantial dilution to existing stockholders. Furthermore, the holders of
+these new securities or debt may have rights, preferences and privileges senior to those of the holders of our common stock. 
+In such circumstances, we also would need to forego acquisition opportunities, which could impede our ability to grow our business. 
+Our financial results may fluctuate. 
+From quarter to quarter and year to year, our operating results can fluctuate, which could cause our growth or financial performance to fail to meet the
+expectations of investors and securities analysts. Sales to our distributors and other customers may not meet expectations because of lower than expected customer demand or other factors, including continued economic volatility and
+disruption, reduced governmental funding, and other circumstances described elsewhere in this report. A variety of factors could also contribute to the variability of our financial results, including infrequent, unusual or unexpected changes
+in revenues or costs. 
+Different products provide dissimilar contributions to our gross product margin. Accordingly, our operating results could also fluctuate and be negatively
+affected by the mix of products sold and the relative prices and gross product margin contribution of those products. Failure to achieve operating results consistent with the expectations of investors and securities analysts could adversely
+affect our reputation and the price of our common stock. 
+34 
+Table of Contents 
+The failure to comply with the terms of the Credit Agreement could result in a default under its terms and, if uncured,
+could result in action against our pledged assets and dilution of our stockholders. 
+On September 3, 2019, we and certain of our subsidiaries, as guarantors, entered into the Credit Agreement, under which we received a $20.0 million senior secured
+term loan credit facility that was drawn in full on September 4, 2019 and matures on September 3, 2023. The Credit Agreement is secured by a first priority, perfected lien on substantially all of our property and assets. See “Part II, Item 7.
+Management’s Discussion and Analysis of Financial Condition and Results of Operations—Likely Default Under Credit Agreement” and “—Liquidity and Capital Resources—Sources of Funds—Credit Agreement” below. 
+The Credit Agreement also contains financial covenants requiring that we (a) maintain aggregate unrestricted cash of not less than $3.0 million at all times, and
+(b) achieve specified minimum total revenue requirements for the twelve months preceding each quarter end. These minimum revenue requirements were developed for purposes of the Credit Agreement and do not reflect the internal estimates and
+plans used by our management and board of directors to establish operational goals for managing our business. Similarly, the minimum revenue requirements do not reflect our new strategic plan, and as we execute our new strategic plan it will
+likely be more difficult for us to comply with such minimum revenue requirements. 
+In addition, the Credit Agreement contains covenants that restrict our ability to finance future operations or capital needs or to engage in other business
+activities. The Credit Agreement restricts the ability of our company and the restricted subsidiaries to: 
+• 
+incur, assume or guarantee additional Indebtedness (as defined in the Credit Agreement); 
+• 
+repurchase capital stock; 
+• 
+make other restricted payments, including paying dividends and making investments; 
+• 
+create liens; 
+• 
+sell or otherwise dispose of assets, including capital stock of subsidiaries; 
+• 
+enter into agreements that restrict dividends from subsidiaries; 
+• 
+enter into mergers or consolidations; and 
+• 
+enter into transactions with affiliates. 
+A breach of the minimum total revenue covenant or any other covenant in the Credit Agreement would result in a default under the Credit Agreement. The minimum
+total revenue requirements are $48.8 million for the twelve months ending March 31, 2023 and $50.1 million for the twelve months ending June 30, 2023. We do not believe that we will comply with the minimum total revenue covenant for the twelve
+months ended March 31, 2023. Upon not meeting the minimum total revenue requirement for the four quarters ending March 31, 2023, the Lender could elect to declare all amounts outstanding thereunder, together with accrued interest, to be
+immediately due and payable. In such an event or upon all amounts owing under the Credit Agreement otherwise maturing on September 3, 2023, there can be no assurance that we would have sufficient liquidity to fund payment of the amounts that
+would be due under the Credit Agreement or that, if such liquidity were not available, we would be successful in raising additional capital on acceptable terms, or at all, or in completing any other endeavor to continue to be financially viable
+and continue as a going concern. Our inability to raise additional capital on acceptable terms in the near future, whether for purposes of funding payments required under the Credit Agreement or providing additional liquidity needed for our
+operations, could have a material adverse effect on our business, prospects, results of operations, liquidity and financial condition. If we are unable to repay amounts owed under the Credit Agreement or to raise such additional capital, we
+would likely be forced to pursue a reorganization proceeding under Chapter 11 of the U.S. Bankruptcy Code. 
+Servicing our debt will require a significant amount of cash. Our ability to generate sufficient cash to service our debt
+depends on many factors beyond our control. 
+Our ability to make payments on and to refinance our debt, to fund planned capital expenditures, and to maintain sufficient working capital depends on our
+ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. We cannot assure you that our business will
+generate sufficient cash flow from operations or from other sources in an amount sufficient to enable us to service our debt or to fund our other liquidity needs. Our operations used $12.7 million in cash in 2022. If our cash flow and capital
+resources are insufficient to allow us to make scheduled payments on our debt, we may need to seek additional capital or restructure or refinance all or a portion of our debt on or before the maturity thereof, any of which could have a
+material adverse effect on our business, financial condition or results of operations. We cannot assure you that, if needed, we would be able to refinance any of our debt on commercially reasonable terms or at all, or that the terms of that
+debt will allow any of the above alternative measures or that these measures would satisfy our scheduled debt service obligations. If we are unable to generate sufficient cash flow to repay or refinance our debt on favorable terms, it could
+significantly adversely affect our financial condition. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition. Any refinancing of our debt could be at higher interest
+rates and may require us to comply with more onerous covenants, which could further restrict our business operations. There can be no assurance that we will be able to obtain any financing when needed, and if we are unable to do so, we would
+likely be forced to pursue a reorganization proceeding under Chapter 11 of the U.S. Bankruptcy Code. 
+35 
+Table of Contents 
+Our ability to utilize our net operating loss carryforwards and certain other tax attributes may be limited. 
+Our ability to utilize our federal net operating loss and tax credit carryforwards may be limited under Sections 382 and 383 of the U.S. Internal Revenue Code of
+1986 (the “Code”). The limitations apply if we experience an “ownership change” (generally defined as a greater than 50 percentage point change (by value) in the ownership of our equity by certain stockholders over a rolling three-year period).
+Similar provisions of state tax law may also apply to limit the use of our state net operating loss carryforwards. 
+We experienced ownership changes in 2004 and 2006, and we estimate a portion of our existing federal net operating loss carryforwards are subject to an annual
+limitation under Section 382 of the Code. Since our ownership change in 2006, we have not assessed whether an ownership change has subsequently occurred. If we have experienced an ownership change at any time since our ownership change in 2006,
+we may already be subject to limitations on our ability to utilize our net operating losses and other tax attributes generated before such additional ownership change to offset post-change taxable income. In addition, future changes in our
+stock ownership, which may be outside of our control, may trigger an ownership change and, consequently, the limitations under Sections 382 and 383 of the Code. As a result, if or when we earn net taxable income, our ability to use our
+pre-change net operating loss carryforwards and other tax attributes to offset such taxable income may be subject to limitations, which could adversely affect our future cash flows. 
+The LIBOR calculation method may change, and LIBOR is expected to be phased out, which may adversely affect our interest
+expenses under the Credit Agreement. 
+Loans under the Credit Agreement bear interest at a rate per annum equal to the sum of (a) the greater of the one-month London Interbank Offered Rate (“LIBOR”) and
+2.5% plus (b) 8.75%. At any time at which an event of default has occurred and is continuing, the interest rate will increase by 4.0%. Accrued interest is payable on a monthly basis. On July 27, 2017, the U.K. Financial Conduct Authority
+announced that it will no longer require banks to submit rates for the calculation of LIBOR after 2021. On November 30, 2020, ICE Benchmark Administration (“IBA”), the administrator of LIBOR, with the support of the United States Federal
+Reserve and the United Kingdom’s Financial Conduct Authority, announced plans to consult on ceasing publication of USD LIBOR on December 31, 2021 for only the one week and two month USD LIBOR tenors, and on June 30, 2023 for all other USD LIBOR
+tenors. While this announcement extended the transition period to June 2023, the United States Federal Reserve concurrently issued a statement advising banks to stop new USD LIBOR issuances by the end of 2021. In light of these recent
+announcements, the future of LIBOR at this time is uncertain and any changes in the methods by which LIBOR is determined or regulatory activity related to LIBOR’s phaseout could cause LIBOR to perform differently than in the past or cease to
+exist. 
+In response to concerns regarding the future of LIBOR, the Board of Governors of the Federal Reserve System and the Federal Reserve Bank of New York convened the
+Alternative Reference Rates Committee (“ARRC”), to identify alternatives to LIBOR. The ARRC has recommended benchmark replacement procedures to assist issuers in continued capital market entry while safeguarding against LIBOR’s
+discontinuation. The initial steps in the ARRC’s recommended provision reference variations of the Secured Overnight Financing Rate (“SOFR”). It is not possible to predict the effect of these changes, other reforms or the establishment of
+alternative reference rates in the United States or elsewhere. 
+Pursuant to the Credit Agreement, if LIBOR becomes unavailable in the future an alternative benchmark rate will apply. To the extent our interest rates increase
+as a result, our interest expense will increase, in which event we may have difficulties making interest payments and funding our other fixed costs, and our available cash flow for general corporate requirements may be adversely affected. 
+36 
+Table of Contents 
+Our operating results may be negatively affected by changes in foreign currency exchange rates. 
+In the past our exposure to foreign currency exchange rate risk has not been material. Nevertheless, sales of our products are subject to currency risks, since
+changes in the values of foreign currencies relative to the value of the U.S. dollar can render our products comparatively more expensive. The fluctuations in the exchange rate could negatively impact international sales of our products, as
+could changes in the general economic conditions. 
+The revenues and expenses of our Malaysian, German and Brazilian subsidiaries are recorded in Malaysian Ringgit, in Euros and Brazilian Real, respectively.
+Revenues and expenses denominated in foreign currencies are translated into U.S. dollars for purposes of reporting our consolidated financial results, and, consequently, our operating results reflect exposure to foreign currency exchange rates,
+which could increase in the future. 
+Our foreign subsidiaries’ revenues and expenses and the translation of their financial results into U.S. dollars may be negatively affected by fluctuations in the
+exchange rate. Favorable movement in exchange rates have benefited us in prior periods. However, where there are unfavorable currency exchange rate fluctuations, our consolidated financial statements could be negatively affected. Furthermore,
+fluctuations in exchange rates could affect year-to-year comparability of operating results. In the past, we have not generally entered into hedging instruments to manage our currency exchange rate risk, but we may need to do so in the future.
+However, our attempts to hedge against these risks may not be successful. If we are unable to successfully hedge against unfavorable foreign currency exchange rate movements, our consolidated financial results may be adversely impacted. 
+We operate in countries where there is or may be widespread corruption. 
+We have a policy in place prohibiting our employees, distributors and agents from engaging in corrupt business practices, including activities prohibited by the
+U.S. Foreign Corrupt Practices Act. Nevertheless, because we work through independent sales agents and distributors outside the United States, we do not have control over the day to day activities of such independent agents and distributors. In
+addition, in the donor funded markets in Africa where we sell our products, there is significant oversight from PEPFAR, the Global Fund, and advisory committees comprised of technical experts concerning the development and establishment of
+national testing protocols. This is a process that includes an overall assessment of a product that includes extensive evaluations of product performance, as well as price and delivery. In Brazil, where we have had numerous product
+collaborations with FIOCRUZ, the programs through which our products may be deployed are all funded by the Brazilian Ministry of Health. Although FIOCRUZ is affiliated with the Brazilian Ministry of Health, which is FIOCRUZ’s sole customer,
+FIOCRUZ is not the exclusive supplier for the Ministry of Health. However, because each of our previous collaborations with FIOCRUZ incorporates a technology transfer aspect, we believe we have a competitive advantage versus other suppliers to
+the Brazilian Ministry of Health, assuming other aspects of our product offering through FIOCRUZ are otherwise competitive in comparison. We have no knowledge or reason to know of any activities by our employees, distributors or sales agents of
+any actions which could be in violation of the FCPA, although there can be no assurance of this. In addition, corruption is a problematic factor in doing business in Brazil, and, to the extent bribery and similar practices continue to exist in
+Brazil, we may be at a competitive disadvantage in gaining business in Brazil, particularly when competing with non U.S. companies. 
+Our subsidiary Chembio Diagnostics Malaysia Sdn. Bhd. is located in Malaysia. There have been numerous high-profile corruption cases, and corruption is one of the most problematic factors for doing business in Malaysia. While the Malaysian
+government has acknowledged the problem, it appears that endemic corruption is continuing and that market-based principles are not applied in cases involving individuals with high-level political access. To the extent bribery and similar
+practices continue to exist in Malaysia, U.S. companies such as ours, which are subject to U.S. laws making it illegal to pay bribes to foreign officials, may make us less competitive in winning business in Malaysia when competing with non-U.S.
+companies. 
+37 
+Table of Contents 
+We base our estimates or judgments relating to critical accounting policies on assumptions that can change or prove to be
+incorrect. 
+Our financial statements have been prepared in accordance with accounting principles generally accepted in the United States and our discussion and analysis of
+financial condition and results of operations is based on such statements. The preparation of financial statements requires management to make estimates and assumptions that affect the amounts reported in the financial statements and
+accompanying notes. We continuously evaluate significant estimates used in preparing our financial statements, including those related: to (1) revenue recognition, including uncertainties related to variable consideration, milestones and bill
+and hold arrangements; (2) stock based compensation; (3) allowance for uncollectible accounts receivable; (4) inventory reserves and obsolescence; (5) customer sales returns and allowances; (6) contingencies; (7) income taxes; (8) goodwill and
+intangibles; (9) business acquisition; (10) research and development costs; (11) insurance receivable; and (12) litigation reserve. 
+Our estimates are based on historical experience and various other assumptions that we believe to be reasonable, as set forth in our discussion and analysis of
+financial condition and results of operations, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these
+and other estimates if our assumptions change or if actual circumstances differ from those in our assumptions. If our operating results fall below the expectations of securities analysts and investors, the price of our common stock may decline. 
+Risks Related to Intellectual Property 
+Our success depends on our ability to protect our proprietary technology. We rely on trade secret laws and agreements with
+our key employees and other third parties to protect our proprietary rights, and we cannot be sure that these laws or agreements will adequately protect our rights. 
+Our industry places considerable importance on obtaining patent, trademark and trade secret protection, as well as other intellectual property rights, for new
+technologies, products and processes. Our success depends, in part, on our ability to develop and maintain a strong intellectual property portfolio or obtain licenses to patents and technologies, both in the United States and in other
+countries. If we cannot continue to develop, obtain and protect intellectual property rights, our revenues and gross profits could be adversely affected. Moreover, our current and future licenses or other rights to patents and other
+technologies may not be adequate for the operation of our business. 
+As appropriate, we intend to file patent applications and obtain patent protection for our proprietary technology. These patent applications and patents will
+cover, as applicable, compositions of matter for our products, methods of making those products, methods of using those products and apparatuses relating to the use or manufacture of those products. 
+We believe that factors such as the technological and creative skills of our personnel, strategic relationships, new product developments, frequent product
+enhancements and name recognition are essential to our success. All our management personnel are bound by non-disclosure agreements. If personnel leave our employment, in some cases we would be required to protect our intellectual property
+rights pursuant to common law theories which may be less protective than provisions of employment, non-competition or non-disclosure agreements. 
+We seek to protect our proprietary products under trade secret and copyright laws, enter into license agreements for various materials and methods employed in
+our products, and enter into strategic relationships for distribution of the products. These strategies afford only limited protection. We currently have some foreign patents issued, and we are seeking additional patent protection in several
+other foreign jurisdictions for our DPP and optical technology. We have licenses to reagents (antigens and peptides) used in several of our products and products under development. Despite our efforts to protect our proprietary assets, and
+respect the intellectual property rights of others, we participate in several markets where intellectual property rights protections are of little or no value. This can place our products and our company at a competitive disadvantage. 
+Moreover, issued patents remain in effect for a fixed period and after expiration will not provide protection of the inventions they cover. Once our patents
+expire, we may be faced with increased competition, which could reduce our revenues. We may also not be able to successfully protect our rights to unpatented trade secrets and know-how. 
+To facilitate development and commercialization of a proprietary technology base, we may need to obtain additional licenses to patents or other proprietary
+rights from other parties. Obtaining and maintaining these licenses, which may not be available, may require the payment of up-front fees and royalties. In addition, if we are unable to obtain these types of licenses, our product development
+and commercialization efforts may be delayed or precluded. 
+38 
+Table of Contents 
+Any future intellectual property disputes could require significant resource and limit or eliminate our ability to sell
+products or use certain technologies. 
+We may be required to expend substantial resources in asserting or protecting our intellectual property rights, or in defending suits related to intellectual
+property rights. We may seek to enforce our patents or other intellectual property rights through litigation. Such litigation is prevalent and is expected to continue. In our business, there are a large number of patents and patent applications
+similar to our products, and additional patents may be issued to third parties relating to our product areas. We, our customers or our suppliers may be sued for infringement of patents or misappropriation of other intellectual property rights
+with respect to one or more of our products. We may also have disputes with parties that license patents to us if we believe the license is no longer needed for our products or the licensed patents are no longer valid or enforceable. 
+There are a large number of patents in our industry, and the claims of these patents appear to overlap in many cases. Therefore there is a significant amount of
+uncertainty regarding the extent of patent protection and infringement. Companies may have pending patent applications, which are typically confidential for the first eighteen months following filing that cover technologies we incorporate in
+our products. Accordingly, we may be subjected to substantial damages for past infringement or be required to modify our products or stop selling them if it is ultimately determined that our products infringe a third party’s proprietary rights.
+In addition, governmental agencies could commence investigations or criminal proceedings against our employees or us relating to claims of misuse or misappropriation of another party’s proprietary rights. 
+If we are involved in litigation or other legal proceedings with respect to patents or other
+intellectual property and proprietary technology, it could adversely affect our revenues, results of operations, market share and business because (1) it could consume a substantial portion of managerial and financial resources; (2) its
+outcome would be uncertain and a court may find that our patents are invalid or unenforceable in response to claims by another party or that the third-party patent claims are valid and infringed by our products; (3) the pendency of any
+litigation may in and of itself cause our distributors and customers to reduce or terminate purchases of our products; (4) a court could award a preliminary and/or permanent injunction, which would prevent us from selling our current or
+future products; and (5) an adverse outcome could subject us to the loss of the
+protection of our patents or to liability in the form of past royalty payments, penalties, reimbursement of litigation costs and legal fees, special and punitive damages, or future royalty payments, any of which could significantly affect our
+future earnings. 
+Under certain contracts with third parties, we may indemnify the other party if our products or activities have actually or allegedly infringed upon,
+misappropriated or misused another party’s proprietary rights. Furthermore, our products may contain technology provided to us by third parties, and we may be unable to determine in advance whether such technology infringes the intellectual
+property rights of a third party. These other parties may also not be required or financially able to indemnify us in the event that an infringement or misappropriation claim is asserted against us. 
+There may also be other types of disputes that we become involved in regarding intellectual property rights, including state, federal or foreign court litigation,
+and patent interference, patent reissue, patent reexamination, or trademark opposition proceedings in the United States Patent and Trademark Office. Opposition or revocation proceedings could be instituted in a foreign patent office as well.
+These proceedings permit certain persons to challenge the validity of a patent on the grounds that it was known from the prior art. The filing of such proceedings, or the issuance of an adverse decision in such proceedings, could result in the
+loss of valuable patent rights that could have a material adverse effect on our business, financial condition, results of operations and growth prospects. 
+Risks Related to Our Reliance on Third Parties 
+Our use of third-party suppliers, some of which may constitute our sole supply source, for certain important product
+components and materials presents risks that could have negative consequences for our business. 
+We purchase certain HIV antigens, a syphilis antigen, COVID-19 antibodies and antigens, the nitrocellulose, and certain other critical components used in our
+STAT PAK, STAT VIEW, SURE CHECK and DPP product lines from a sole or limited number of sources. If for any reason these suppliers become unwilling or unable to supply our antigen, nitrocellulose, or other critical component needs, we believe
+that alternative supplies could be obtained at a competitive cost. However, a change in any of the antibodies, antigens, nitrocellulose or other critical components used in our products would require additional development work and clinical
+trials, as well as approval by the FDA and other regulatory agencies. In addition, it may be difficult to find such an alternate supply source in a reasonable time period or on commercially reasonable terms, if at all. As a result, the
+termination or limitation of our relationship with one or more of these suppliers could require significant time to complete, increase our costs, and disrupt or discontinue our ability to manufacture and sell the affected products. In
+addition, governmental purchasers or funding programs in a particular country may require that we purchase key components from suppliers in that country, which could significantly limit our ability to obtain the components with the quality,
+and at the price, we seek. 
+39 
+Table of Contents 
+With some of these suppliers, we do not have long-term agreements and instead purchase components and materials through a purchase order process. As a result,
+these suppliers may stop supplying us components and materials, limit the allocation of supply and equipment to us due to increased industry demand, or significantly increase their prices at any time with little or no advance notice. Our
+reliance on a limited number of suppliers could also result in delivery problems, reduced control over product pricing and quality, and our inability to identify and qualify another supplier in a timely manner. 
+Moreover, some of these suppliers may experience financial difficulties that could prevent them from supplying us with components or subassemblies used in the
+design and manufacture of our products. In addition, these suppliers may experience manufacturing delays or shut downs due to circumstances beyond their control, such as complications related to COVID-19, labor issues, political unrest or
+natural disasters. 
+Any supply chain deficiencies could materially and adversely affect our ability to fulfill customer orders and our results of operations. The availability of
+critical components and materials from sole- or limited source suppliers could reduce our control over pricing, quality and timely delivery, increase our costs, could disrupt our ability to manufacture and sell, and preclude us from
+manufacturing and selling, certain of our products into one or more markets. Any such event could have a material adverse effect on our results of operations, cash flow and business. 
+Our ability to grow our business will be limited if we fail to maintain existing distribution channels or develop new
+distribution channels. 
+We collaborate with laboratories, diagnostic companies and distributors in order to sell our products. The sale of our products depends in large part on our
+ability to sell products to these customers and on the marketing and distribution abilities of the companies with which we collaborate and work with. 
+Relying on distributors or third parties to market and sell our products could negatively impact our business for various reasons, including: (i) we may not be
+able to find suitable distributors for our products on satisfactory terms, or at all; (ii) agreements with distributors may prematurely terminate or may result in litigation between the parties; (iii) our distributors or other customers may not
+fulfill their contractual obligations and distribute our products in the manner or at the levels we expect; (iv) our distributors may prioritize their own private label products that compete with our products; (v) our existing distributor
+relationships or contracts may preclude or limit us from entering into arrangements with other distributors; and (vi) we may not be able to negotiate new or renew existing distribution agreements on acceptable terms, or at all. 
+We will try to maintain and expand our business with distributors and customers and make every effort to require that they fulfill their contractual obligations,
+but there can be no assurance that such companies will do so or that new distribution channels will be available on satisfactory terms. If we are unable to do so, our business will be negatively impacted. 
+Our U.S. government contracts require compliance with numerous laws and increase our risk and liability. 
+We are currently receiving funding from the U.S. government related to the DPP SARS-CoV-2 Antigen System, the DPP Respiratory Antigen Panel and DPP Zika, and our
+growth strategy may target sales to U.S. government entities. As a result of our U.S. government funding and potential product sales to the U.S. government, we must comply with laws and regulations relating to the award, administration and
+performance of U.S. government contracts. U.S. government contracts typically contain a number of extraordinary provisions that would not typically be found in commercial contracts and which may create a disadvantage and additional risks to
+us as compared to competitors that do not rely on government contracts. As a U.S. government contractor, we are subject to increased risks of investigation, criminal prosecution and other legal actions and liabilities to which purely private
+sector companies are not. The results of any such actions could adversely impact our business and have an adverse effect on our consolidated financial performance. 
+40 
+Table of Contents 
+A violation of specific laws and regulations could result in the imposition of fines and penalties or the termination of our contracts, as well as suspension or
+debarment. The suspension or debarment in any particular case may be limited to the facility, contract or subsidiary involved in the violation or could be applied to our entire enterprise in certain severe circumstances. Even a narrow scope
+suspension or debarment could result in negative publicity that could adversely affect our ability to renew contracts and to secure new contracts, both with the U.S. government and private customers, which could materially and adversely affect
+our business and results of operations. Fines and penalties could be imposed for failing to follow procurement integrity and bidding rules, employing improper billing practices or otherwise failing to follow rules relating to billing on
+cost-plus contracts, receiving or paying kickbacks, or filing false claims, among other potential violations. In addition, we could suffer serious reputational harm and the value of our common stock could be negatively affected if allegations
+of impropriety related to such contracts are made against us. 
+Our U.S. government contracts are subject to future funding and the government’s choice to exercise options, and may be
+terminated at the government’s convenience. 
+Our contracts with the U.S. government are subject to future funding and are subject to the right of the government to terminate the contracts in whole or in part
+for its convenience. There is pressure for the U.S. government to reduce spending. The non-appropriation of funds or the termination for the government’s convenience of our contracts could negatively affect our financial results. If levels of
+U.S. government expenditures and authorizations for emerging diseases decrease or shift to programs in areas where we do not offer products or are not developing product candidates, or if the U.S. government otherwise declines to exercise its
+options under its contracts with us, our business, revenues and other operating results would suffer. 
+Risks Related to Regulations 
+COVID-19 diagnostic tests, including the COVID-19 Diagnostic Test Systems, are subject to changes in CLIA, FDA, ANVISA and
+other regulatory requirements. 
+Our COVID-19 Diagnostic Test Systems are subject to regulations of the FDA and other regulatory requirements, including ANVISA, Brazil’s health regulatory agency.
+The regulations regarding the manufacture and sale of COVID-19 Diagnostic Test Systems may be unclear and are subject to recurring change. Newly promulgated regulations could require changes to COVID-19 Diagnostic Test Systems, necessitate
+additional procedures, or make it impractical or impossible for us to market COVID-19 Diagnostic Test Systems for certain uses, in certain markets, or at all. The FDA and other regulatory authorities also have the ability to impose new or
+additional requirements relating to the COVID-19 Diagnostic Test Systems. The implementation of such changes or new or additional requirements may result in a substantial additional costs and could delay or make it more difficult or complicated
+to sell our products. 
+On February 4, 2020, the U.S. Department of Health and Human Services issued a declaration that the threat to public health posed by COVID-19 justifies the emergency use of unapproved in vitro diagnostics for the
+detection or diagnosis of SARS-CoV-2. Under Section 564 of the Food, Drug, and Cosmetic Act, because the U.S. Department of Health and Human Services has issued this declaration, the Commissioner of the FDA is authorized to issue EUAs to permit
+certain developers of SARS-CoV-2 diagnostics to begin offering the tests for detection and diagnosis of COVID-19 without having completed the normally applicable FDA review and clearance or approval process for marketing authorization. We
+received an EUA for the DPP COVID-19 IgM/IgG System on April 14, 2020, which was subsequent revoked by the FDA on June 16, 2020. Such revocation precludes the sale of DPP COVID-19 IgM/IgG Systems in the United States unless and until a further
+regulatory approval or authorization is obtained. We have not received a subsequent EUA for any of the COVID-19 Diagnostic Test Systems. Moreover, market and regulatory requirements continue to change at a rapid pace. The FDA has announced, for
+example, that it intends to update its EUA templates with additional considerations related to the impact of genetic variants on test performance as the FDA learns more about the COVID-19 disease and its knowledge in this area progresses. The
+time required to obtain marketing authorizations and other approvals from regulatory authorities is unpredictable. The standards that the FDA and its foreign counterparts use when evaluating clinical trial data can change, and do often change,
+during development, which makes it difficult to predict with any certainty how they will be applied. If we make future submissions to the FDA, we may also encounter unexpected delays or increased costs due to new government regulations,
+including future legislation or administrative action, or changes in FDA policy during the period of FDA regulatory review. There can be no assurance that if we are to make a submission of any future EUA application, we will be successful in
+obtaining an EUA that would permit us to offer and sell any COVID-19 Diagnostic Test System in the United States. 
+41 
+Table of Contents 
+We are subject to governmental export controls that could impair our ability to compete in international markets. 
+The United States and various foreign governments have imposed controls, export license requirements and restrictions on the export of certain products and
+technologies. We must export our products in compliance with export controls in the United States, including the Commerce Department’s Export Administration Regulations and various economic and trade sanctions established by the Treasury
+Department’s Office of Foreign Assets Controls. We may not always be successful in obtaining necessary export licenses, and our failure to obtain required import or export approval for our products or limitations on our ability to export or
+sell our products imposed by these laws may harm our international and domestic sales and adversely affect our revenue. Noncompliance with these laws could have negative consequences, including government investigations, penalties and
+reputational harm. 
+If the U.S. government imposes restrictions on the export of COVID-19 Diagnostic Test Systems, or any of our other products, such restrictions could have a
+material impact on our ability to sell our products to existing or potential customers outside of the United States and harm our ability to compete internationally. Any change in export regulations or legislation, or change in the countries,
+persons or technologies targeted by export regulations, could decrease our ability to export or sell our products outside the United States or to existing or potential customers with international operations. Changes in our ability to sell our
+products outside the United States could negatively impact our business prospects and adversely affect our business and results of operations. 
+Because we may not be able to obtain or maintain the necessary regulatory approvals for some of our products, we may not
+generate revenues in the amounts we expect, or in the amounts necessary to continue our business. Our existing products as well as our manufacturing facility must meet quality standards and are subject to inspection by a number of domestic
+regulatory and other governmental and non-governmental agencies. 
+All of our proposed and existing products are subject to regulation in the United States by the FDA, the U.S. Department of Agriculture, and/or other domestic and
+international governmental, public health agencies, regulatory bodies or non-governmental organizations. In particular, we are subject to strict governmental controls on the development, manufacture, labeling, distribution and marketing of our
+products. The process of obtaining required approvals or clearances varies according to the nature of, and uses for, a specific product. These processes can involve lengthy and detailed laboratory testing, human or animal clinical trials,
+sampling activities, and other costly, time consuming procedures. The submission of an application to a regulatory authority does not guarantee that the authority will grant an approval or clearance for that product. Each authority may impose
+its own requirements and can delay or refuse to grant approval or clearance, even though a product has been approved in another country. 
+The time taken to obtain approval or clearance varies depending on the nature of the application and may result in the passage of a significant period of time
+from the date of submission of the application. As an example, the time required to obtain an EUA from the FDA for COVID-19 tests has lengthened markedly over the past months due to, among other things, application volume. Delays in the
+approval or clearance processes increase the risk that we will not succeed in introducing or selling the subject products, and we may determine to devote our resources to different products. 
+Changes or developments in government regulations, policies or interpretations could increase our costs and could require us to undergo additional trials or
+procedures, or could make it impractical or impossible for us to market our products for certain uses, in certain markets, or at all. For example, on June 16, 2020, the FDA revoked the EUA it had granted for the DPP COVID-19 IgM/IgG System
+based in part on performance criteria identified after the EUA was granted on April 14, 2020. We do not currently have an EUA from the FDA for any of the COVID-19 Diagnostic Test Systems. Moreover, FDA regulations, policies and procedures
+with respect to COVID-19 tests may be significantly impacted by the availability of vaccines for COVID-19 and changes in the FDA’s prioritization guidance. Similarly, the regulatory pathway to 510(k) clearance by the FDA for COVID-19 tests is
+unclear in light of limited FDA feedback resulting in part from the FDA’s constrained resources. 
+42 
+Table of Contents 
+Changes in government regulations may adversely affect our financial condition and results of operations because we may have to incur additional expenses if we are
+required to change or implement new testing, manufacturing and control procedures. If we are required to devote resources to develop such new procedures, we may not have sufficient resources to devote to research and development, marketing, or
+other activities that are critical to our business. We are, for example, expending resources to modify the design of the COVID-19 Diagnostic Test System to achieve performance targets consistent with the FDA’s performance criteria issued
+subsequent to the granting of our original EUA. 
+If we do not comply with FDA or other regulatory requirements, we may be required to suspend production or sale of our
+products or institute a recall, which could result in higher costs and a loss of revenues. 
+Regulations of the FDA and other federal, state and foreign regulatory agencies have significant effects on many aspects of our operations and the operations of
+our suppliers and distributors, including packaging, labeling, manufacturing, adverse event reporting, recalls, distribution, storage, advertising, promotion and record keeping. We are subject to routine inspection by the FDA and other agencies
+to determine compliance with FDA regulatory requirements, including Quality System Regulations (“QSRs”), in the United States and other applicable regulations worldwide, including International Organization for Standardization (“ISO”)
+standards. We believe that our facilities and procedures are in material compliance with the FDA requirements and ISO standards, but the regulations may be unclear and are subject to change, and we cannot be sure that the FDA or other
+regulators will agree with our compliance with these requirements. The FDA and foreign regulatory agencies may require post-marketing testing and surveillance to monitor the performance of approved or cleared products or impose conditions on
+any product clearances or approvals that could restrict the distribution or commercial applications of those products. Regulatory agencies may impose restrictions on our or our distributors’ advertising and promotional activities or preclude
+these activities altogether if a noncompliance is believed to exist. In addition, the subsequent discovery of previously unknown problems with a product may result in restrictions on the product or additional regulatory actions, including
+withdrawal of the product from the market. 
+Our inability to comply with the applicable requirements of the FDA can result in, among other things, 483 notices, warning letters, administrative or judicially
+imposed sanctions such as injunctions, recall or seizure of products, civil penalties, withdrawal of product registrations, total or partial suspension of production, refusal to grant premarket clearance for devices, a determination that a
+device is not approvable, marketing clearances or approvals, or criminal prosecution. For example, in February 2020, we initially received a “not approvable” letter from the FDA with respect to our premarket approval submission on our DPP HIV
+Syphilis multiplex test for commercial use in the United States, in June 2020 we received notice from the FDA that the EUA for the DPP COVID-19 IgM/IgG System had been revoked, and in January 2021 we received notice from the FDA that it was
+declining to review the DPP SARS CoV 2 Antigen System based on its updated prioritization guidance, under which review of the system was not a priority. The ability of our suppliers to supply critical components or materials and of our
+distributors to sell our products could also be adversely affected if their operations are determined to be out of compliance. Such actions by the FDA and other regulatory bodies could adversely affect our revenues, costs and results of
+operations. 
+We must frequently make judgment decisions with respect to compliance with applicable laws and regulations. If regulators subsequently disagree with how we have
+sought to comply with these regulations, we could be subjected to substantial civil and criminal penalties, as well as product recall, seizure or injunction with respect to the sale of our products. Our reputation could be substantially
+impaired if we are assessed any civil and criminal penalties and limit our ability to manufacture and market our products which could have a material adverse effect on our business. 
+Our inability to respond to changes in regulatory requirements could adversely affect our business. 
+We believe that our existing products and procedures are in material compliance with all applicable FDA regulations, ISO requirements, and other applicable
+regulatory requirements, but the regulations regarding the manufacture and sale of our products and QSR, ISO and other requirements may be unclear and are subject to change. Newly promulgated regulations could require changes to our products,
+necessitate additional clinical trials or procedures, or make it impractical or impossible for us to market our products for certain uses, in certain markets, or at all. The FDA and other regulatory authorities also have the ability to change
+the requirements for obtaining product approval and/or impose new or additional requirements as part of the approval process. These changes or new or additional requirements may occur after the completion of substantial clinical work and
+other costly development activities. The implementation of such changes or new or additional requirements may result in additional clinical trials and substantial additional costs and could delay or make it more difficult or complicated to
+obtain approvals and sell our products. In addition, the FDA may revoke an EUA under which our products are sold, where it is determined that the underlying health emergency no longer exists or warrants such authorization. Such revocation
+would preclude the sale of our affected products unless and until a further regulatory approval or authorization is obtained. For example, on June 16, 2020, the FDA revoked the EUA it had granted for the DPP COVID-19 IgM/IgG System based in
+part on performance criteria identified after the EUA was granted on April 14, 2020, and since that time we expended resources to design the new COVID-19 Diagnostic Test Systems, including the DPP Respiratory Antigen Panel. We do not
+currently have an EUA from the FDA for any of the COVID-19 Diagnostic Test Systems. We cannot anticipate or predict the effect, if any, that these types of changes might have on our business, financial condition or results of operations. 
+43 
+Table of Contents 
+Demand for our products may be affected by FDA regulation of laboratory developed tests. 
+Regulatory responsibility over instruments, test kits, reagents and other devices used to perform diagnostic testing by clinical laboratories is covered by the
+FDA, including our Micro Reader analyzer. The FDA has previously taken the position that it has regulatory authority over laboratory developed tests (“LDTs”), but has exercised enforcement discretion by not regulating most LDTs performed by
+high complexity CLIA certified laboratories. LDTs are tests designed, developed, and performed in house by a laboratory. These laboratories are subject to CLIA regulation but such laboratories have previously not been subject to regulation by
+the FDA under the agency’s medical device requirements. 
+The FDA announced that it would begin regulating LDTs, and in October 2014 the FDA issued proposed guidance on the regulation of LDTs for public comment. In
+November 2016, however, the FDA announced it would not finalize the proposed guidance prior to the end of the Obama administration. In January 2017 the FDA released a discussion paper synthesizing public comments on the 2014 draft guidance
+documents and outlining a possible approach to regulation of LDTs. The discussion paper has no legal status and does not represent a final version of the LDT draft guidance documents. We cannot predict what policies the Biden administration
+will adopt with respect to LDTs. If the FDA increases regulation of LDTs, it could make it more difficult for laboratories and other customers to continue offering LDTs that involve molecular testing. This, in turn, could reduce demand for our
+products and adversely impact our revenues. 
+Disruptions at the FDA and other government agencies caused by funding shortages or global health concerns could hinder
+their ability to hire, retain or deploy key leadership and other personnel, or otherwise prevent new or modified products from being developed, cleared, approved, authorized, or commercialized in a timely manner or at all, which could
+negatively impact our business. 
+The ability of the FDA and other government agencies to review and clear, approve, or authorize new products can be affected by a variety of factors, including
+government budget and funding levels, statutory, regulatory, and policy changes, the agencies’ ability to hire and retain key personnel and accept the payment of user fees, and other events that may otherwise affect the agencies’ ability to
+perform routine functions. Average review times at these agencies have fluctuated in recent years as a result. In addition, government funding of other government agencies that fund research and development activities is subject to the
+political process, which is inherently fluid and unpredictable. Disruptions at the FDA and other agencies may also slow the time necessary for medical devices or modifications to be cleared or approved, medical devices to be reviewed and/or
+approved by necessary government agencies, which would adversely affect our business. For example, over the last several years, the U.S. government has shut down several times and certain regulatory agencies, such as the FDA, have had to
+furlough critical FDA employees and stop critical activities. 
+Separately, in response to the global COVID-19 pandemic, on January 29, 2021, the FDA announced its intention to resume inspections of manufacturing facilities and
+products, which would be deemed “mission-critical.” The FDA’s assessment of whether an inspection is mission-critical considers many factors related to the public health benefit of U.S. patients having access to the product subject to
+inspection. These factors include, but are not limited to, whether the products have received breakthrough therapy designation or regenerative medicine advanced therapy designation, or are products used to diagnose, treat, or prevent a serious
+disease or medical condition for which there is no other appropriate substitute. Both for-cause and pre-approval inspections can be deemed mission-critical. When determining whether to conduct a mission-critical inspection, the FDA takes into
+account concerns about the safety of its investigators, employees at a site or facility, and where applicable, clinical trial participants and other patients at investigator sites. Regulatory authorities outside the United States may adopt
+similar restrictions or other policy measures in response to the COVID-19 pandemic. If a prolonged government shutdown occurs, or if global health concerns continue to prevent the FDA or other regulatory authorities from conducting their
+regular inspections, reviews or other regulatory activities, it could significantly impact the ability of the FDA or other regulatory authorities to timely review and process our regulatory submissions, which could have a material adverse
+effect on our business. 
+44 
+Table of Contents 
+In addition to FDA requirements, we are subject to numerous other federal, state and foreign government regulations,
+compliance with which could increase our costs and affect our operations. 
+In addition to the FDA regulations previously described, other federal, state and foreign laws and regulations may restrict our ability to sell products in those
+jurisdictions. 
+We must comply with numerous laws related to safe working conditions, environmental protection, disposal of hazardous substances, fire hazard control,
+manufacturing practices and labor or employment practices. Compliance with these laws or any new or changed laws regulating our business could result in substantial costs. Due to the number of laws and regulations governing our industry, and
+the actions of a number of government agencies that could affect our operations, it is impossible to reliably predict the full nature and impact of these laws and regulations. To the extent the costs and procedures associated with complying
+with these laws and requirements are substantial or it is determined that we do not comply, our business and results of operations could be adversely affected. 
+Ongoing changes in healthcare regulation could negatively affect our revenues, business and financial condition. 
+There have been several proposed changes in the United States at the federal and state level for comprehensive reforms regarding the payment for, the availability
+of and reimbursement for healthcare services. These proposals have ranged from fundamentally changing federal and state healthcare reimbursement programs, including providing comprehensive healthcare coverage to the public under
+government-funded programs, to minor modifications to existing programs. 
+Healthcare reform initiatives will continue to be proposed, and may reduce healthcare related funding in an effort. It is impossible to predict the ultimate
+content and timing of any healthcare reform legislation and its resulting impact on us. If significant reforms are made to the healthcare system in the United States, or in other jurisdictions, those reforms may increase our costs or otherwise
+negatively affect our financial condition and results of operations. 
+The E.U. In-Vitro Diagnostic Regulation entered into force, which repeals and replaces the Council Directive 98/79/EC, or E.U. In-Vitro Diagnostic Directive.
+Unlike directives, which must be implemented into the national laws of the EU member states, regulations are directly applicable (i.e., without the need for adoption of E.U. member state laws implementing them) in all E.U. member states and are
+intended to eliminate current differences in the regulation of medical devices among E.U. member states. Devices lawfully placed on the market pursuant to the E.U. In-Vitro Diagnostic Directive prior to May 26, 2022 may generally continue to be
+made available on the market or put into service until May 26, 2027, provided that the requirements of the transitional provisions are fulfilled. In particular, the certificate in question must still be valid. However, even in this case,
+manufacturers must comply with a number of new or reinforced requirements set forth in the E.U. In-Vitro Diagnostic Regulation with regard to registration of economic operators and of devices, post-market surveillance, market surveillance and
+vigilance requirements. 
+Subject to the transitional provisions, in order to sell our products in E.U. member states, our products must comply with the general safety and performance
+requirements of the E.U. In-Vitro Device Regulation, which repeals and replaces E.U. In-Vitro Diagnostic Directive. Compliance with these requirements is a prerequisite to be able to affix the CE mark to our products, without which they cannot
+be sold or marketed in the E.U. To demonstrate compliance with the general safety and performance requirements, we must undergo a conformity assessment procedure, which varies according to the type of medical device and its (risk)
+classification. Except for low risk medical devices (Class I), where the manufacturer can self-assess the conformity of its products with the general safety and performance requirements (except for any parts which relate to sterility, metrology
+or reuse aspects), a conformity assessment procedure requires the intervention of a notified body. The notified body would typically audit and examine the technical file and the quality system for the manufacture, design and final inspection of
+our devices. If satisfied that the relevant product conforms to the relevant general safety and performance requirements, the notified body issues a certificate of conformity, which the manufacturer uses as a basis for its own declaration of
+conformity. The manufacturer may then apply the CE mark to the device, which allows the device to be placed on the market throughout the E.U. If we fail to comply with applicable laws and regulations, we would be unable to affix the CE mark to
+our products, which would prevent us from selling them within the E.U. 
+45 
+Table of Contents 
+We must inform the notified body that carried out the conformity assessment of the medical devices that we market or sell in the E.U. and the EEA of any planned
+substantial changes to our quality system or substantial changes to our medical devices that could affect compliance with the general safety and performance requirements laid down in Annex I to the E.U. In-Vitro Diagnostic Regulation or cause a
+substantial change to the intended use for which the device has been CE marked. The notified body will then assess the planned changes and verify whether they affect the products’ ongoing conformity with the E.U. In-Vitro Diagnostic Regulation.
+If the assessment is favorable, the notified body will issue a new certificate of conformity or an addendum to the existing certificate attesting compliance with the general safety and performance requirements and quality system requirements
+laid down in the Annexes to the E.U. In-Vitro Diagnostic Regulation. 
+We may incur additional costs if we do not comply with privacy, security and breach notification regulations. 
+We believe that we are not a covered entity nor a business associate of a covered entity and are not responsible for complying with the Health Insurance
+Portability and Accountability Act of 1996 (“HIPAA”). Even though we likely are not a covered entity under HIPAA, we do have in place administrative, technical and physical safeguards to protect the privacy and security of consumers’ personal
+information. We are required to comply with varying state privacy, security and breach reporting laws. If we fail to comply with existing or new laws and regulations related to properly transferring data containing consumers’ personal
+information, we could be subject to monetary fines, civil penalties or criminal sanctions. Also, there are other federal and state laws that protect the privacy and security of consumers’ personal information, and we may be subject to
+enforcement by various governmental authorities and courts resulting in complex compliance issues. We could incur damages under state laws pursuant to an action brought by a private party for the wrongful use or disclosure of consumers’
+personal information. 
+Failure to comply with E.U. and U.K. data protection requirements could increase our costs. 
+The E.U. adopted a comprehensive overhaul of its data protection regime from the prior national legislative approach to a single European Economic Area Privacy
+Regulation called the General Data Protection Regulation (the “GDPR”), which came into effect on May 25, 2018. The E.U. data protection regime extends the scope of the E.U. data protection law to all foreign companies processing data of E.U.
+residents. It imposes a strict data protection compliance regime with severe penalties of up to the greater of 4% of worldwide turnover and €20 million and includes new rights such as the “portability” of personal data. Although the GDPR
+applies across the E.U. without a need for local implementing legislation, as had been the case under the prior data protection regime, local data protection authorities have the ability to interpret the GDPR, which has the potential to create
+inconsistencies on a country-by-country basis. We have evaluated these new requirements and have implemented a plan to ensure compliance. Complying with the enhanced obligations imposed by the GDPR may result in significant costs to our
+business and require us to amend certain of our business practices. Further, we have no assurances that violations will not occur, particularly given the complexity of the GDPR, as well as the uncertainties that accompany new, comprehensive
+legislation. Further, from January 1, 2021, we have to comply with both the GDPR and the GDPR as incorporated into United Kingdom national law, the latter regime having the ability to separately fine up to the greater of £17.5 million or 4% of
+global turnover. The relationship between the United Kingdom and the E.U. in relation to certain aspects of data protection law remains unclear, for example around how data can lawfully be transferred between each jurisdiction, which may expose
+us to further compliance risk. The European Commission has adopted an adequacy decision in favor of the U.K., enabling data transfers from E.U. member states to the U.K. without additional safeguards. However, the U.K. adequacy decision will
+automatically expire in June 2025 unless the European Commission re-assesses and renews/extends that decision. 
+46 
+Table of Contents 
+If we are not able to manufacture products in accordance with applicable requirements, it could adversely affect our
+business. 
+Our products must meet detailed specifications, performance standards and quality requirements. As a result, our products and the materials used in their
+manufacture or assembly undergo regular inspections and quality testing. Factors such as defective materials or processes, mechanical failures, human errors, environmental conditions, changes in materials or production methods, and other events
+or conditions could cause our products or the materials used to produce or assemble our products to fail inspections and quality testing or otherwise not perform in accordance with our label claims or the expectations of our customers. 
+If we are not able to meet the applicable specifications, performance standards, quality requirements or customer expectations could adversely affect our ability
+to manufacture and sell our products or comply with regulatory requirements. These events could, in turn, adversely affect our revenues and results of operations. 
+Healthcare fraud and abuse laws could adversely affect our business and results of operations. 
+There are various federal and state laws targeting fraud and abuse in the healthcare industry to which we are subject, including anti-kickback laws, laws
+constraining the sales, false claims laws, marketing and promotion of medical devices by limiting the kinds of financial arrangements that manufacturers of these products may enter into with physicians, hospitals, laboratories and other
+potential purchasers of medical devices. There are other laws we are subject to that require us to report certain transactions between it and healthcare professionals. Violations of these laws are punishable by criminal or civil sanctions,
+including substantial fines, imprisonment and exclusion from participation in government healthcare programs. Many of the existing requirements are new and have not been definitively interpreted by state authorities or courts, and available
+guidance is limited. We could face enforcement action and fines and other penalties, and could receive adverse publicity, unless and until we are in full compliance with these laws, all of which could materially harm us. Furthermore, changes in
+or evolving interpretations of these laws, regulations, or administrative or judicial interpretations, may require us to change our business practices or subject our business practices to legal challenges, which could have a material adverse
+effect on our business, financial condition and results of operations. 
+If we expand our international presence, it may increase our risks and expose our business to regulatory, cultural or other
+challenges. 
+There are several of factors that could adversely affect the performance of our business and/or cause us to incur substantially increased costs because of our
+international presence and sales, including: (i) uncertainty in the application of foreign laws and the interpretation of contracts with foreign parties; (ii) cultural and political differences that favor local competitors or make it difficult to effectively market, sell and gain acceptance of our products; (iii) exchange rates, currency fluctuations, tariffs and other barriers, extended
+payment terms and dependence on international distributors or representatives; (iv) trade protection measures, trade sanctions and import/export licensing requirements; (v) our inability to obtain or maintain regulatory approvals or
+registrations for our products; (vi) economic conditions, political instability, the absence of available funding sources, terrorism, civil unrest, war and natural disasters in foreign countries; (vii) reduced protection for, or enforcement of,
+our patents and other intellectual property rights in foreign countries; (viii) our inability to identify international distributors and negotiate acceptable terms for distribution agreements; and (ix) restrictions on our ability to repatriate
+investments and earnings from foreign operations. 
+Economic, cultural and political conditions and foreign regulatory requirements may slow or prevent the manufacture of our products in countries other than the
+United States. Interruption of the supply of our products could reduce revenues or cause us to incur significant additional expenses in finding an alternative source of supply. Foreign currency fluctuations and economic conditions in foreign
+countries could also increase the costs of manufacturing our products in foreign countries. 
+47 
+Table of Contents 
+Risks Related to Ownership of Common Stock 
+Our common stock may have limited liquidity, and investors may not be able to sell as much common stock as they want at
+prevailing market prices or at all. 
+The liquidity of our common stock depends on several factors, including our financial results and overall market conditions, so it is not possible to predict
+whether this level of liquidity will continue, be sustained, or decrease. Decreased trading volume in our stock would make it more difficult for investors to sell their shares in the public market at any given time at prevailing prices. Our
+management and larger stockholders exercise significant control over our company. 
+Decreased trading volume in our stock would make it more difficult for investors to sell their shares in the public market at any given time at prevailing prices.
+Although there is no affiliation between our management and our larger stockholders, they could exercise significant control over our company if they voted their shares in a similar manner. 
+Our common stock may become the target of a “short squeeze.” 
+Securities of certain companies have increasingly experienced significant and extreme volatility in stock price due to short sellers of shares of common stock,
+known as a “short squeeze.” Short squeezes have caused extreme volatility in those companies and in the market and have led to the price per share of those companies to trade at a significantly inflated rate that is disconnected from the
+underlying value of the company. Sharp rises in a company’s stock price may force traders in a short position to buy the stock to avoid even greater losses. Many investors who have purchased shares in those companies at an inflated rate face
+the risk of losing a significant portion of their original investment as the price per share has declined steadily as interest in those stocks have abated. There can be no assurance that we will not, in the future be, a target of a short
+squeeze, and you may lose a significant portion or all of your investment if you purchase our shares at a rate that is significantly disconnected from our underlying value. 
+You may experience future dilution as a result of future equity offerings, exercises of outstanding options and vesting of
+options and restricted and performance stock units. 
+We have sold 16,175,519 shares of common stock, for gross proceeds of $45.4 million and net proceeds, after giving effect to commissions and other transaction
+costs, of $43.1 million under the At the Market Offering Agreement, entered into July 19, 2021, pursuant to which we may sell from time to time, at our option, up to an aggregate of $60.0 million of shares of common stock through Craig-Hallum
+Capital Group LLC, as sales agent (the “ATM Agreement”). These sales include sales of common stock for gross proceeds of $4.6 million and net proceeds of $4.3 million since December 31, 2022. We are currently subject to General Instruction
+I.B.6 to Form S-3 (the “baby shelf rule”) and are generally limited to sales pursuant to our existing shelf registration statement during any twelve-month period of an amount equal to one-third of the aggregate market value of our common equity
+held by non-affiliates. For additional information about the at-the-market offerings pursuant to the ATM Agreement, see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” 
+In order to raise additional capital and subject to having available shares of common stock under our articles of incorporation, we may in the future seek to offer
+pursuant to the ATM Agreement additional shares of common stock for up to $14.6 million in gross proceeds and we may in the future offer additional shares of our common stock or other securities convertible into or exchangeable for our common
+stock. There can be no assurance that we will be able to sell additional shares in at-the-market offerings made pursuant to the ATM Agreement, or in any other offering, at a price per share that is equal to or greater than the price per share
+paid by existing stockholders. Investors purchasing securities in other offerings in the future could have rights superior to existing stockholders. 
+Management will have broad discretion as to the use of any net proceeds of the offering made pursuant to the ATM Agreement,
+and we may in the future not use those net proceeds effectively. 
+If we continue to make sales under the ATM Agreement, our management will have broad discretion in the application of the net proceeds of any such offering made
+pursuant to the ATM Agreement and could spend the proceeds in ways that do not improve our results of operations or enhance the value of our common stock. Our failure to apply these funds effectively could have a material adverse effect on our
+business and could cause the price of our common stock to decline. 
+48 
+Table of Contents 
+Sales of our common stock by existing stockholders, executive officers or directors could depress the market price of our
+common stock. 
+If our existing stockholders, officers or directors sell our common stock in the public market, or the perception that such sales may occur, it could negatively
+affect the price of our common stock. We are unable to estimate the number of shares of our common stock that may actually be resold in the public market since this will depend on the market price for our common stock, the individual
+circumstances of the sellers and other factors. 
+We do not intend to pay cash dividends on our common stock. 
+We do not expect to pay any cash dividends on our common stock and currently intend to retain our earnings, if any, to finance the expansion of our business. The
+payment of dividends is restricted by the Credit Agreement and will depend on our earnings, capital requirements, financial condition, prospects and other factors our board of directors may deem relevant. We are also limited under the terms of
+the Merger Agreement from paying cash dividends without the consent of Biosynex, Therefore, the success of an investment in our common stock will depend entirely upon any future increase in value of our common stock. There is no guarantee that
+our common stock will gain value or even maintain the price at which investors purchased their shares. 
+General Risk Factors 
+We may not generate the expected benefits of future strategic transactions or investments, and they could disrupt our
+ongoing business, distract our management, increase our expenses and negatively affect our business. 
+As a way for us to grow our business, we may pursue strategic transactions or investments. These activities, and their impact on our business, are subject to many
+risks, including the following: (i) the benefits expected to be derived from a transaction or investment may not materialize and could be affected by numerous factors, such as regulatory developments, insurance reimbursement, our inexperience
+with new businesses or markets, general economic conditions and increased competition; (ii) we may be unable to successfully integrate with a partner company’s personnel, assets, management, information technology systems, accounting policies
+and practices, products and/or technology into our business; (iii) we may not be able to accurately forecast the performance or ultimate impact of a partner business; and (iv) a strategic transaction may result in the incurrence of unexpected
+expenses, stockholder lawsuits, the dilution of our earnings or our existing stockholders’ percentage ownership, or potential losses from undiscovered liabilities not covered by an indemnification from the seller(s) of the partner business. 
+If these factors occur, we may be unable to achieve all or a significant part of the benefits expected from a strategic transaction or investment. This may
+adversely affect our financial condition, results of operations and ability to grow our business or otherwise achieve our financial and strategic objectives. 
+Our compliance with regulations governing public companies is complex and expensive. 
+Public companies are subject to various laws and regulations, which have increased the scope, complexity and cost of corporate governance, reporting and disclosure
+practices. For example, we are subject to the Sarbanes-Oxley Act of 2002, The Dodd-Frank Wall Street Reform and Consumer Protection Act and the requirements of The Nasdaq Capital Market. The implementation of certain aspects of these laws and
+regulations has required and will continue to require substantial management time and oversight and may require us to incur significant additional accounting and legal costs. We continually review changes with respect to new and proposed rules
+and cannot predict or estimate the amount of additional costs, and the timing of such costs, we may incur. There are several interpretations of these laws and regulations, in many cases due to their lack of specificity, and as a result, their
+application in practice may change as new guidance is provided by regulatory and governing bodies. This may result in continuing uncertainty regarding compliance matters and higher costs. We are committed to maintaining high standards of
+corporate governance and public disclosure, but if we fail to comply with any of these requirements, legal proceedings may be initiated against us, which may adversely affect our business. 
+Our business may be negatively affected by terrorist attacks or natural disasters. 
+Terrorist attacks or natural disasters could cause economic instability. These events could negatively affect economic conditions both within and outside the
+United States and harm demand for our products. The operations of our customers and suppliers could be negatively impacted and eliminate, reduce or delay our customers’ ability to purchase and use our products and our suppliers’ ability to
+provide raw materials and finished products. 
+Our facilities, including some pieces of manufacturing equipment and our computer systems, may be difficult to replace. Various types of disasters, including
+fires, earthquakes, floods and acts of terrorism, may affect our facilities and computer systems. In the event our existing facilities or computer systems are affected by man-made or natural disasters, we may have difficulty operating our
+business and may be unable to manufacture products for sale or meet customer demands or sales projections. If our manufacturing operations were curtailed or shut down entirely, it would seriously harm our business. 
+49 
+Table of Contents 
+ITEM 1B. 
+UNRESOLVED STAFF COMMENTS 
+None. 
+ITEM 2. 
+PROPERTIES 
+Our U.S. manufacturing, administrative offices, and research facilities are located in leased space in Medford, New York, pursuant to a lease covering approximately 39,650 square feet and expiring on June 30, 2023,
+with an option to renew each year. 
+On February 5, 2019, we entered into a commercial real estate lease for new corporate headquarters comprised of 70,000 square feet of office, research and development, and warehouse space located in Hauppauge, New
+York. The lease has an initial term of eleven years that can be extended, at our option, for two additional terms of five years each. Rent under the lease, which is payable in monthly installments, totals approximately $900,000 for the initial
+year and then increases by approximately three percent each succeeding year. 
+On January 25, 2023, the lease in Hauppauge, New York was terminated and a new lease was entered into for a 50,000 square foot space in Bayshore, New York. The lease has an initial term of seven years and one
+month. Rent under the lease, which is payable in monthly installments, has a minimum annual rent of approximately $996,240. 
+Our European headquarters and Center of Excellence for Optical Technology is located in leased office and manufacturing space in Berlin, Germany. Our Southeast Asia manufacturing, warehouse, and commercial
+facilities are located in leased space in Kuala Lumpur, Malaysia and is currently inactive. Our Latin America manufacturing, warehouse, and commercial facilities are located in Rio de Janeiro, Brazil. We regularly review our real estate portfolio
+and develop footprint strategies to support our customers’ global plans, while at the same time supporting our technical needs and controlling operating expenses. 
+ITEM 3. 
+LEGAL PROCEEDINGS 
+This information is set forth under “Note 12 – Commitments, Contingencies And Concentrations – Litigation” to the Consolidated Financial Statements of this Annual Report on Form 10-K is incorporated herein by
+reference. 
+ITEM 4. 
+MINE SAFETY DISCLOSURES 
+N/A 
+PART II 
+ITEM 5. 
+MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+Listing Information 
+Our stock is currently listed on the Nasdaq Capital Market of the Nasdaq Stock Market LLC under the symbol “CEMI.” 
+Holders 
+As of March 24, 2023, there were 114 record owners of our Common Stock (including nominee holders such as banks and brokerage firms who hold shares for beneficial owners). 
+50 
+Table of Contents 
+Recent Sales of Unregistered Securities 
+During the year ended December 31, 2022, we have issued, in the aggregate, 48,117 shares of common stock to Marco Collovati pursuant to a consulting agreement between us, our subsidiary Chembio Diagnostics Brazil
+LLC, and Mr. Collovati, upon the achievement of certain regulatory milestones in Brazil. The Company issued the foregoing securities in transactions not involving an underwriter and not requiring registration under Section 5 of the Securities Act
+in reliance on the exemption afforded by Section 4(a)(2) thereof. 
+Issuer Purchases of Equity Securities 
+We did not repurchase any of our equity securities during the year ended December 31, 2022. 
+Dividend Policy 
+We have never paid dividends and do not anticipate paying dividends in the foreseeable future. The payment of dividends is restricted by the Credit Agreement and
+will depend on our earnings, capital requirements, financial condition, prospects and other factors our board of directors may deem relevant. We are also limited under the terms of the Merger Agreement from paying cash dividends without the
+consent of Biosynex. We intend to retain any future earnings for reinvestment in our business. 
+ITEM 6. 
+[RESERVED] 
+ITEM 7. 
+MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+We develop and commercialize point-of-care diagnostic tests used for the rapid detection and diagnosis of infectious diseases, including sexually transmitted disease, insect vector and tropical disease, COVID-19
+and other viral and bacterial infections, enabling expedited treatment. 
+Our product portfolio is based upon our proprietary DPP technology, a diagnostic platform that provides high-quality, cost-effective results in 15 to 20 minutes using fingertip blood, nasal swabs and other sample
+types. The DPP technology platform addresses the rapid diagnostic test market, which includes infectious diseases, cardiac markers, cholesterol and lipids, pregnancy and fertility, and drugs of abuse. Compared with traditional lateral flow
+technology, the DPP technology platform can provide enhanced sensitivity and specificity, advanced multiplexing capabilities and, with the DPP Micro Reader, quantitative results. 
+We target the market for rapid diagnostic test solutions for infectious diseases, which is driven by the high prevalence of infectious diseases globally, an increase in the geriatric population, growing demand for
+rapid test results, and advancements in multiplexing. We have a broad portfolio of infectious disease products, which prior to 2020 were focused principally on sexually transmitted disease and fever and tropical disease. In February 2020 we began
+the process to leverage the DPP technology platform to address the acute and escalating need for diagnostic testing. We are continuing to pursue or have pursued: 
+• 
+an emergency use authorization, or EUA, from the U.S. Food and Drug Administration, or FDA, as well as 510(k) clearance from the FDA, for the DPP SARS-CoV-2 Antigen test system; 
+• 
+an EUA from the FDA for the DPP Respiratory Panel; and 
+• 
+a Clinical Laboratory Improvement Amendment (“CLIA”), waiver from the FDA for the DPP HIV-Syphilis test system, which was received in February 2023. 
+Our products are sold globally, directly and through distributors, to medical laboratories and hospitals, governmental and public health entities, nongovernmental organizations, medical professionals, and retail
+establishments. We continue to seek to expand our commercial distribution channels. 
+51 
+Table of Contents 
+Pending Merger with Biosynex SA 
+The Company has entered into a Merger Agreement with Biosynex and Purchaser. Pursuant to the Merger Agreement, on February 14, 2023, the Purchaser commenced the Offer to purchase all of the issued and outstanding
+Shares for a purchase price of $0.45 per share, net to the seller in cash, without interest and subject to any required tax withholding. On March 15, 2023, Biosynex announced an extension of the Offer until 6:00 p.m., New York City time, on March
+28, 2023. Subsequently, on March 29, 2023, Biosynex announced an extension of the Offer until 6:00 p.m., New York City time, on April 12, 2023. 
+If the conditions to the Offer are satisfied and the Offer closes, Purchaser would acquire all remaining Chembio shares by a merger of Purchaser with and into
+Chembio, with Chembio surviving the Merger as a wholly-owned indirect subsidiary of Biosynex. At the Effective Time, each Share issued and outstanding immediately prior to the Effective Time (including shares paid to holders of vested Chembio
+restricted stock units) will be converted into the right to receive $0.45 per share. Stock options that are outstanding immediately prior to the Effective Time will automatically terminate for no consideration. 
+The Merger Agreement and the transactions contemplated thereby, including the Merger, were unanimously approved by the Company’s Board of Directors. Completion of the Merger is subject to certain customary
+conditions as set forth in the Merger Agreement and the successful completion of the Offer. There can be no assurance that the Merger will be consummated on the terms described above or at all. 
+The foregoing description of the Merger Agreement and the transactions contemplated thereby, including the Offer, does not purport to be complete and is subject to, and qualified in its entirety by reference to,
+the full text of the Merger Agreement, which has been filed as Exhibit 2.1 to our Current Report on Form 8-K filed with the SEC on January 31, 2023. 
+Likely Default Under Credit Agreement 
+On September 3, 2019, we and certain of our subsidiaries, as guarantors, entered into the Credit Agreement and Guaranty (the “Credit Agreement”) with Perceptive Credit Holdings II, LP (the “Lender”), under
+which we received a $20.0 million senior secured term loan that was drawn in full on September 4, 2019. The Credit Agreement is secured by a first priority lien on substantially all of our property and assets. The Credit Agreement contains
+financial covenants requiring that we (a) maintain aggregate unrestricted cash of not less than $3.0 million at all times, and (b) achieve specified minimum total revenue requirements for the twelve months preceding each quarter end. 
+The Credit Agreement has a September 3, 2023 maturity date, and we do not currently believe that replacement debt or equity financing arrangements are or will be available to us or, if available to us, will be
+on acceptable terms. We do not believe that we will be in compliance with the minimum revenue covenant in the Credit Agreement for the four fiscal quarters ended March 31, 2023. Our Lender has previously informed us that it will not agree to
+any restructuring of the Credit Agreement, and as a result we may be forced to pursue a bankruptcy or restructuring proceeding when the debt matures (or earlier if the lender accelerates following a breach of the minimum total revenue
+covenant) or pursue a transaction or financing arrangement that could be dilutive to stockholders. 
+Going Concern Considerations 
+The Company continued to experience market, clinical trial and regulatory complications in seeking to develop and commercialize a portfolio of
+COVID-19 test systems during the continuing, but evolving, uncertainty resulting from COVID‑19. For the year ended December 31, 2022, the Company also continued to incur significant operating
+losses and significant expenses in connection with pending legal matters (see Note 12 – Commitments, Contingencies, and Concentrations: Litigation). 
+The Company performed an assessment to determine whether there were conditions or events that, considered in the aggregate, raised substantial doubt
+about the Company’s ability to continue as a going concern within one year after the filing date of this report, when the accompanying financial statements are being issued. Initially, this assessment did not consider the potential mitigating
+effect of management’s plans that had not been fully implemented. Because, as described below, substantial doubt was determined to exist as the result of this initial assessment, management then assessed the mitigating effect of its plans to
+determine if it is probable that the plans (1) would be effectively implemented within one year after the filing date of this report, when the accompanying financial statements are being issued and (2) when implemented, would mitigate the
+relevant conditions or events that raise substantial doubt about the Company’s ability to continue as a going concern. 
+The Company achieved revenue growth in recent years while profitability has not been at levels as expected. It has taken steps including investments
+in automation to mitigate headwinds such as labor availability, volatile capacity planning and implementation of operational efficiency targets to proactively monitor production with the overarching goal of profitable growth. The Company
+undertook measures to increase its total revenues and improve its liquidity position by continuing to develop the Global Competitiveness Program. The main pillars of the Global Competitiveness Program include the following: 
+• 
+Focus on higher margin business in growth markets 
+• 
+Lower manufacturing costs 
+• 
+Reduce infrastructure costs 
+52 
+Table of Contents 
+• 
+Strategic review of non-core businesses and assets 
+The Company’s execution of its plans continue to depend, however, on factors and uncertainties that are beyond the Company’s
+control, or that may not be addressable on terms acceptable to the Company or at all. The Company considered in particular how: 
+• 
+The ongoing healthcare and economic impacts of COVID-19 on the global customer base for the Company’s non‑COVID-19 products continue to negatively affect the
+timing and rate of recovery of the Company’s revenues from those products. 
+The Company further considered how these factors and uncertainties could impact its ability over the next year to meet the obligations specified
+in the Credit Agreement with the Lender. Those obligations include covenants requiring: i) minimum cash balance of $3.0 million and ii) minimum total revenue amounts for the twelve months preceding each quarter end. The minimum total revenue
+requirements are $48.8 million for the twelve months ending March 31, 2023 and $50.1 million for the twelve months ending June 30, 2023. We do not believe that we will comply with the minimum total revenue covenant for the twelve months
+ended March 31, 2023. Upon an event of default under the Credit Agreement, the Lender could elect to declare all amounts outstanding thereunder, together with accrued interest, to be immediately due and payable. Furthermore, all remaining
+principal and interest is due on or before September 3, 2023. There can be no assurance that the Company would have sufficient liquidity to fund payment of the amounts that would be due under the Credit Agreement or that, if such liquidity
+were not available, the Company would be successful in raising additional capital on acceptable terms, or at all, or in completing any other endeavor to continue to be financially viable and continue as a going concern. The Company’s
+inability to raise additional capital on acceptable terms in the near future, whether for purposes of funding payments required under the Credit Agreement or providing additional liquidity needed for its operations, could have a material
+adverse effect on its business, prospects, results of operations, liquidity and financial condition and would likely result in the Company being forced to seek protection under a bankruptcy proceeding. 
+Accordingly, management determined the Company could not be certain that the Company’s plans and initiatives would be effectively implemented
+within one year after the filing date of this report, when the accompanying financial statements are being issued. Without giving effect to increasing product revenue in the near future, the proposed merger with Biosynex or executing other
+mitigating plans, many of which are beyond the Company’s control, it is unlikely that the Company will be able to generate sufficient cash flows to meet its required financial obligations, including its debt service and other obligations due
+to third parties. The existence of these conditions raises substantial doubt about the Company’s ability to continue as a going concern for the twelve-month period following the date on which the accompanying consolidated financial statements
+are being issued. 
+The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern, which contemplates
+continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business for the twelve-month period following the date the accompanying consolidated financial statements are issued. As such, the
+accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amounts, or the amount and classification of liabilities that may result should the
+Company be unable to continue as a going concern. 
+53 
+Table of Contents 
+Consolidated Results of Operations 
+The results of operations for the years ended December 31, 2022 and 2021 were as follows: 
+Year Ended December 31, 
+(in thousands) 
+2022 
+2021 
+TOTAL REVENUES 
+$ 
+49,522 
+100 
+% 
+$ 
+47,818 
+100 
+% 
+COSTS AND EXPENSES: 
+Cost of product sales 
+38,578 
+78 
+% 
+34,496 
+72 
+% 
+Research and development expenses 
+7,068 
+14 
+% 
+12,487 
+26 
+% 
+Selling, general and administrative expenses 
+24,278 
+49 
+% 
+24,841 
+52 
+% 
+Impairment, restructuring, severance and related costs 
+3,236 
+7 
+% 
+7,048 
+15 
+% 
+TOTAL OPERATING COST AND EXPENSES 
+73,160 
+78,872 
+LOSS FROM OPERATIONS 
+(23,638 
+) 
+(31,054 
+) 
+INTEREST (EXPENSE) / INCOME AND OTHER INCOME 
+382 
+(2,912 
+) 
+LOSS BEFORE INCOME TAXES 
+(23,256 
+) 
+(33,966 
+) 
+Income tax (expense) / benefit 
+(34 
+) 
+62 
+NET LOSS 
+$ 
+(23,290 
+) 
+(47 
+%) 
+$ 
+(33,904 
+) 
+(71 
+%) 
+Percentages in the table reflect the percent of total revenues. 
+Total Revenues 
+Total revenues during 2022 were $49.5 million, an increase of $1.7 million, or 3.6%, compared to 2021. The increase in total revenues reflected a $12.4 million, or 36%, increase in net product sales, which was
+principally comprised of higher sales in the United States and Africa, offset by a decrease in government grant revenue of $9.7 million related to the completion of the BARDA $12.7 million agreement in 2021. 
+Gross Product Margin 
+Cost of product sales is primarily comprised of material, labor, manufacturing overhead, depreciation and amortization, and freight and distribution costs. Gross product margin is net product sales less cost of
+product sales, and gross product margin percentage is gross product margin as a percentage of net product sales. 
+Gross product margin increased by $8.3 million, or 3,433% compared to 2021. The following schedule calculates gross product margin: 
+For the years ended December 31 
+Favorable/ 
+(unfavorable) 
+% Change 
+2022 
+2021 
+(in thousands) 
+Net product sales 
+$ 
+47,092 
+$ 
+34,737 
+$ 
+12,355 
+36 
+% 
+Less: Cost of product sales 
+(38,578 
+) 
+(34,496 
+) 
+(4,082 
+) 
+12 
+% 
+Gross product margin 
+$ 
+8,514 
+$ 
+241 
+$ 
+8,273 
+3,433 
+% 
+Gross product margin % 
+18 
+% 
+1 
+% 
+In 2022, we continued to invest in automation in order to reduce our reliance on manual labor and improve our product margins. The $8.3 million increase in gross product margin resulted from favorable product
+margins related to the impact of geographic mix on average selling price. 
+54 
+Table of Contents 
+Research and Development 
+This category includes costs incurred for clinical and regulatory affairs and other research and development, as follows: 
+For the years ended December 31 
+Favorable/ 
+(unfavorable) 
+% Change 
+2022 
+2021 
+(in thousands) 
+Clinical and regulatory affairs 
+$ 
+1,637 
+$ 
+5,109 
+$ 
+3,472 
+68 
+% 
+Other research and development 
+5,431 
+7,378 
+1,947 
+26 
+% 
+Total research and development 
+$ 
+7,068 
+$ 
+12,487 
+$ 
+5,419 
+43 
+% 
+The overall decrease in total research and development costs for 2022 as compared to 2021 was primarily associated to decreased clinical trial costs and other R&D costs related to the BARDA $12.7 million
+agreement which was completed on December 2, 2021. Total research and development costs incurred for the year ended 2022 were primarily related to ongoing projects in our new product pipeline. 
+Selling, General and Administrative Expense 
+Selling, general and administrative expenses include administrative expenses, sales and marketing costs (including commissions), and other corporate items. The $0.6 million, or 2%, decrease in selling, general and
+administrative expenses for 2022 as compared to 2021 primarily reflected decrease in professional fees, commissions and recruiting fees. 
+Impairment, Restructuring, Severance and Related Costs 
+Impairment, restructuring, severance and related costs include an impairment loss of $3.0 million during the first quarter of 2022 as a result of an impairment of goodwill due to the substantial decrease in our
+share price at March 31, 2022. The low price per share value at March 31, 2022 caused our book value to exceed our fair value. During the year ended 2022, $0.2 million of severance cost was recorded. 
+During 2021, $7.0 million of impairment, restructuring, severance and related costs was incurred, of which $5.9 million was related to the write-off of intangible assets, net leasehold improvements, and net
+right-of-use assets for leases associated with our Malaysian operations, and a write down of finite-lived intangible assets and goodwill, $1.1 million was related to restructuring matters and $0.1 million was related to severance charges. 
+Interest (Expense) / Income and Other Income 
+Interest (expense) / income and other income was principally comprised of interest expense (net of interest income) offset by $3.2 million cash receipt for the Employee Retention Credit (ERC) that we qualified for
+in the second and third quarter of 2021. Interest expense decreased by $0.1 million for 2022 as compared to 2021, due to the interest paid on the term loan debt we incurred in September 2019 as a result of repayment of principal starting in
+September 2022. 
+Income Tax Benefit 
+For 2022 we recognized a tax expense of $0.04 million primarily attributable to state taxes, compared to a tax benefit of $.01 million recorded in 2021. As of December 31, 2022 and 2021, the Company recorded a full
+valuation allowance against its net deferred tax assets. 
+Liquidity and Capital Resources 
+Our cash and cash equivalents totaled $18.2 million at December 31, 2022, a decrease of $10.6 million from $28.8 million at December 31, 2021. We are obligated to maintain aggregate unrestricted cash of not less
+than $3,000,000 at all times under a covenant in the Credit Agreement. 
+During the year ended December 31, 2022, we funded our business operations, including capital expenditures and working capital requirements, principally from cash and cash equivalents, using $14 million of cash. We
+also issued and sold 6,466,191 shares of common stock for net proceeds of $4.3 million pursuant to the ATM agreement. 
+55 
+Table of Contents 
+Additionally, the Merger Agreement with Biosynex contains certain termination rights for Biosynex and us. Upon termination of the Merger Agreement under specified circumstances, we may be required to pay Biosynex
+a termination fee of $850,000. 
+Factors and considerations with respect to our liquidity raised substantial doubt as to our ability to continue as a going concern through one year after the filing
+date of this report, when the accompanying financial statements are being issued. See “Likely Default Under Credit Agreement” and “Going Concern Considerations” above. 
+We have considered how the uncertainties around the delivery of the full number of tests covered by customer orders may be affected by limitations of our staffing,
+supply chain and liquidity and other matters outside our control. We further considered how those uncertainties could impact our ability to meet the obligations specified in the Credit Agreement over the next twelve months, which include (a) a
+covenant requiring minimum total revenues for the twelve months preceding each quarter end and (b) an obligation requiring the payment of principal installments, commencing with the payment of $300,000 on September 30, 2022. The minimum total
+revenue requirements are $48.8 million for the twelve months ending March 31, 2023 and $50.1 million for the twelve months ending June 30, 2023. We do not believe that we will comply with the minimum total revenue covenant for the twelve months
+ended March 31, 2023. Upon an event of default under the Credit Agreement, the Lender could elect to declare all amounts outstanding thereunder, together with accrued interest, to be immediately due and payable. Furthermore, all remaining
+principal and interest is due on or before September 3, 2023. There can be no assurance that we would have sufficient liquidity to fund payment of the amounts that would be due under the Credit Agreement or that, if such liquidity were not
+available, we would be successful in raising additional capital on acceptable terms, or at all, or in completing any other endeavor to continue to be financially viable and continue as a going concern. Our inability to raise additional capital on
+acceptable terms or to otherwise generate cash in the near future, whether for purposes of funding payments required under the Credit Agreement or providing additional liquidity needed for our operations, could have a material adverse effect on
+our business, prospects, results of operations, liquidity and financial condition and would likely result in the Company being forced to seek protection under a bankruptcy proceeding. 
+We cannot be certain that our plans and initiatives would be effectively implemented within one year after the filing date of this report, when the accompanying
+financial statements are being issued. Without giving effect to the prospect of raising additional capital pursuant to our at-the-market offering or likewise, increasing product revenue in the near future, the proposed merger with Biosynex or
+executing other mitigating plans, many of which are beyond our control, it is unlikely that we will be able to generate sufficient cash flows to meet our required financial obligations, including our debt service and other obligations due to
+third parties. The existence of these conditions raises substantial doubt about our ability to continue as a going concern for the twelve-month period following the filing date of this report, when the accompanying financial statements are being
+issued. 
+Please see Note 2 to the accompanying financial statements for additional information regarding our going concern assessment in connection with the accompanying
+financial statements. You are urged to read carefully the information provided in “Because of our liquidity limitations, we have concluded there is a substantial doubt about our ability to continue as a going concern and we may require additional
+capital to fund our operations, which capital may not be available to us on acceptable terms or at all.” “The failure to comply with the terms of the Credit Agreement could result in a default under its terms and, if uncured, could result in
+action against our pledged assets and dilution of our stockholders” under Part I, Item 1A, “Risk Factors” of this report. 
+On April 5, 2022, we received notification from the Listing Qualifications Department of The Nasdaq Stock Market, or Nasdaq, stating that the Company did not comply
+with the minimum $1.00 bid price requirement for continued listing set forth in Nasdaq Listing Rule 5550(a)(2) (the “Bid Price Requirement”). In accordance with Nasdaq listing rules, the Company was afforded 180 calendar days (until October 3,
+2022) to regain compliance with the Bid Price Requirement. On October 4, 2022, the Company received written notice from Nasdaq stating that, although the Company had not regained compliance with the Bid Price Requirement by October 3, 2022, in
+accordance with Nasdaq Listing Rule 5810(c)(3)(A), the Company is eligible for an additional 180 calendar day period, or until April 3, 2023, to regain compliance with the Bid Price Requirement. To regain compliance, the closing bid price of the
+Company’s common stock must meet or exceed $1.00 per share for a minimum of ten consecutive business days during this additional 180-day period, all as described in more detail in the Current Reports on Form 8-K filed with the SEC on April 7,
+2022 and October 4, 2022. The closing price of our common stock was $0.39 on March 24, 2023. We do not believe that we will regain compliance with the Bid Price Requirement by the April 3, 2023 deadline, and there can be no assurance that we will
+ever be able to do so. Given the current trading price of our common stock, it is likely that we will receive a delisting notification from Nasdaq. The existence of the pending deficiency letter could, materially impair our ability to raise
+capital. Moreover, if we were unable to regain compliance with the Bid Price Requirement, our common stock would likely then trade only in the over-the-counter market and the market liquidity of our common stock could be adversely affected and
+its market price could decrease. If our common stock were to trade on the over-the-counter market, selling our common stock could be more difficult because smaller quantities of shares would likely be bought and sold, transactions could be
+delayed, and we could face significant material adverse consequences, including: a limited availability of market quotations for our securities; reduced liquidity with respect to our securities; a determination that our shares are a “penny
+stock,” which will require brokers trading in our securities to adhere to more stringent rules, possibly resulting in a reduced level of trading activity in the secondary trading market for our securities; a reduced amount of news and analyst
+coverage; and a decreased ability to issue additional securities or obtain additional financing in the future. These factors could result in lower prices and larger spreads in the bid and ask prices for our common stock and would substantially
+impair our ability to raise additional funds and could result in a loss of institutional investor interest and fewer development opportunities for us. 
+56 
+Table of Contents 
+We currently intend to retain all available funds and any future earnings for use in the operation of our business and do not anticipate paying any cash dividends. We have not entered into, and do not expect to
+enter into, investments for trading or speculative purposes. Our accounts receivable, accounts payable and inventory balances fluctuate from period to period, which affects our cash flow from operating activities. The amounts of these
+fluctuations vary depending on cash collections, client mix, raw material lead times, the mix of vendor terms, the timing of shipment of our products and the invoicing of our research and development activities. As of December 31, 2022, we did
+not have any off-balance sheet arrangements, as defined in Item 303(a)(4)(ii) of Regulation S-K under the Securities Exchange Act of 1934. 
+We continually evaluate our liquidity requirements, capital needs and availability of capital resources based on our operating needs and our planned growth initiatives. Our future working capital needs will depend
+on many factors, including the rate of our business and revenue growth, the availability and cost of human, material and other resources required to build and deliver products in accordance with our existing or future product orders, the timing
+of our continuing automation of U.S. manufacturing, and the timing of our investment in research and development as well as sales and marketing. If we are unable to increase our revenues and manage our expenses in accordance with our operating
+plan, we may need to reduce the level or slow the timing of the growth plans contemplated by our operating plan, which would likely curtail or delay the growth in our business contemplated by our operating plan and could impair or defer our
+ability to achieve profitability and generate cash flow, or to seek to raise additional funds through debt or equity financing, strategic relationships, or other arrangements. There can be no assurance that we would be able to complete any
+proposed financing on terms acceptable to us, or at all, or that we otherwise will be successful in any of our other endeavors to continue to be financially viable and continue as a going concern. Our inability to raise additional capital on
+acceptable terms could have a material adverse effect on our business, prospects, results of operations, liquidity and financial condition. If we were to raise additional funds through the issuance of equity or convertible securities, the
+issuance could result in substantial dilution to existing stockholders, and the holders of those new securities may have rights, preferences and privileges senior to those of the holders of common stock. Furthermore, any decline in the market
+price of our common stock could make it more difficult for us to sell equity or equity-related securities in the future at a time and price that we deem appropriate. 
+Sources of Funds 
+Equity and Equity-Related Securities . On July 19, 2021, we and Craig‑Hallum Capital Group LLC, or Craig-Hallum, entered into the ATM Agreement, pursuant to which we may sell
+from time to time, at our option, up to an aggregate of $60,000,000 of shares of common stock through Craig‑Hallum, as sales agent. Any sales of shares made pursuant to the ATM Agreement will be made pursuant to our shelf registration statement
+on Form S‑3 (File No. 333‑254261) and the related prospectus previously declared effective by the SEC on May 5, 2021, as supplemented by a prospectus supplement dated July 19, 2021 that we filed with the SEC, pursuant to Rule 424(b)(5) under the
+Securities Act, on July 19, 2021, as such prospectus supplement may be amended or supplemented from time to time. 
+Prior to any sale of shares of common stock under the ATM Agreement, we may deliver a sales notice to Craig-Hallum that will set the parameters for such sale, including the number of shares to be issued and sold,
+the time period during which such sale is requested to be made, any limitation on the number of shares that may be sold in any one trading day and any minimum price below which sales may not be made. Under the ATM Agreement, Craig-Hallum is
+required to use commercially reasonable efforts consistent with its normal trading and sales practices to sell shares in accordance with the terms of the ATM Agreement and any applicable sales notice. 
+57 
+Table of Contents 
+Subject to the terms and conditions of the ATM Agreement, Craig-Hallum may sell any shares of common stock only by methods deemed to be an “at the market” offering as defined in Rule 415 under the Securities Act,
+including sales made directly through the Nasdaq Capital Market, by means of ordinary brokers’ transactions, in negotiated transactions, to or through a market maker other than on an exchange or otherwise, at market prices prevailing at the time
+of sale, at prices related to such prevailing market prices, or at negotiated prices and/or any other method permitted by law. If any sale of shares pursuant to the ATM Agreement is not made directly on the Nasdaq Capital Market or any other
+existing trading market for common stock at market prices at the time of sale, including a sale to Craig-Hallum acting as principal or a sale in a privately negotiated transaction, we must file a prospectus supplement describing the terms of such
+sale, the number of shares sold, the price of the shares, the applicable compensation, and such other information as may be required pursuant to Rules 424 and 430B under the Securities Act, as applicable, within the time required by Rule 424
+under the Securities Act. 
+Under the terms of the ATM Agreement, we are to pay Craig-Hallum a placement fee of 3.5% of the gross sales price of shares of common stock sold, unless Craig-Hallum acts as principal, in which case we may sell the
+shares to Craig-Hallum as principal at a price we agree upon with Craig-Hallum. We are obligated to reimburse Craig-Hallum for certain expenses incurred in connection with the ATM Agreement, and we have provided Craig-Hallum with customary
+indemnification and contribution rights with respect to certain liabilities, including liabilities under the Securities Act and the Securities Exchange Act of 1934. 
+We are currently subject to General Instruction I.B.6 to Form S-3, or the baby shelf rule, and the amount of funds we can raise through primary public offerings of securities in any twelve-month period using our
+existing registration statement on Form S-3 is limited to one-third of the aggregate market value of the voting and non-voting common equity held by non-affiliates. 
+The offering of shares of common stock pursuant to the ATM Agreement will terminate upon the earliest of (a) the sale of all of the shares registered for purposes of the offering pursuant to the ATM Agreement, (b)
+our mutual written agreement with Craig-Hallum, (c) written notice from Craig-Hallum, in its sole discretion, to us, and (d) five business days’ prior written notice from us, in our sole discretion, to Craig-Hallum. 
+As of the filing date of this report, we have issued and sold pursuant to the ATM Agreement a total of 16,175,5195 shares of common stock at a volume-weighted average price of $2.81 per share for gross proceeds of
+$45.4 million and net proceeds, after giving effect to placement fees and other transaction costs, of $43.1 million. Additional shares of common stock may be issued and sold pursuant to the ATM Agreement, but we cannot provide any assurance that
+will be able to issue any additional shares under the ATM Agreement at an acceptable price or at all. Furthermore, any such sales shall be subject to the Baby Shelf Rule. 
+Credit Agreement . The following description summarizes certain key provisions of the Credit Agreement: 
+• 
+Principal Amount. The Credit Agreement provides for a $20,000,000 senior secured term loan credit facility, which was drawn in full on September 4, 2019. Under the terms of the Credit Agreement, we may use the proceeds (i) for general
+working capital purposes and other permitted corporate purposes, (ii) to refinance certain of our existing indebtedness and (iii) to pay fees, costs and expenses incurred in connection with the Credit Agreement, including the Lender’s
+closing cost amount of $550,000, which was netted from the proceeds, and a financing fee of $600,000 (3.0% of gross proceeds) payable to Craig-Hallum Capital Group LLC, our financial advisor for the financing. 
+• 
+Interest Rate. Principal outstanding under the Credit Agreement bears interest at a rate per annum equal to the sum of (a) the greater of the one-month London Interbank Offered Rate and 2.5% plus (b) 8.75%. At any time at which an
+event of default (as described under “—Default Provisions” below) has occurred and is continuing, the interest rate will increase by 4.0%. Accrued interest is payable on a monthly basis. On December 31, 2022, the interest rate was 12.88%. 
+• 
+Scheduled Repayment. No principal repayments were due prior to September 30, 2022. The Company did not elect to prepay principal as described under
+“—Optional Prepayment” below and an event of default as described under “—Default Provisions” below did not occur. Principal installments in the amount of $300,000 are payable on the last day of each of the eleven months from September
+2022 through July 2023, and all remaining principal is payable at maturity on September 3, 2023. We also have certain obligations under the Credit Agreement which include covenants requiring: i) the minimum cash balance of $3.0 million
+and ii) minimum total revenue amounts for the twelve months preceding each quarter end. The minimum total revenue requirements are $48,8 million for the twelve months ending March 31, 2023 and $50.1 million for the twelve months ending
+June 30, 2023. We do not believe that we will comply with the minimum total revenue covenant for the twelve months ended March 31, 2023. A breach of the minimum total revenue covenant or any other covenant in the Credit Agreement would
+result in a default under the Credit Agreement and the Lender could elect to declare all amounts outstanding thereunder, together with accrued interest, to be immediately due and payable. 
+58 
+Table of Contents 
+• 
+Optional Prepayment. We may prepay outstanding principal from time to time, subject to payment of a premium on the prepaid principal amount equal to 10% through September 3, 2020, 8% from September 4, 2020 through September 3, 2021,
+and 4% from September 4, 2021 through September 3, 2022. No premium will be due with respect to any prepayment made on or after September 4, 2022. 
+• 
+Guarantees. Our subsidiaries Chembio Diagnostic Systems Inc. and Chembio Diagnostics Malaysia Sdn Bhd. have guaranteed, and the Lender from time to time may require our other subsidiaries to guarantee, our obligations under the Credit
+Agreement. 
+• 
+Security. Our obligations under the Credit Agreement are secured by a first priority, perfected lien on substantially all of our property and assets, including our equity interests in our subsidiaries. Our subsidiary Chembio Diagnostic
+Systems Inc. has secured its guarantee of our Credit Agreement obligations with a lien on substantially all of its assets, and the Lender from time to time may require Chembio Diagnostics Malaysia Sdn Bhd. and any of our other
+subsidiaries that has guaranteed our Credit Agreement obligations to do the same. 
+• 
+Representations and Warranties; Financial and Other Covenants. In the Credit Agreement we made customary representations and warranties as well as
+customary affirmative and negative covenants, including covenants limiting additional indebtedness, liens, guarantees, mergers and acquisitions, substantial asset sales, investments and loans, sale and leasebacks, transactions with
+affiliates, and fundamental changes. The Credit Agreement also contains financial covenants requiring that (i) we maintain aggregate unrestricted cash of not less than $3,000,000 at all times and (ii) we achieve specified minimum
+rolling four-quarter (“last twelve month”) total revenue amounts as of September 30, 2019 and the last day of each calendar quarter thereafter. The minimum total revenue requirements are $48.8 million for the twelve months ending March
+31, 2023, and $50.1 million for the twelve months ending June 30, 2023. We do not believe that we will comply with the minimum total revenue covenant for the twelve months ended March 31, 2023. The minimum total revenue amounts were
+developed for purposes of the Credit Agreement and do not reflect the internal estimates and plans used by our management and board of directors to understand and evaluate our operating performance, to establish budgets, and to
+establish operational goals for managing our business. We therefore do not believe that the covenant requirements provide useful information to investors or others in enhancing an understanding of our future prospects. 
+• 
+Default Provisions. The Credit Agreement provides for customary events of default, including events of default based on non-payment of amounts due under the Credit Agreement, defaults on other debt, misrepresentations, covenant
+breaches, changes of control, insolvency, bankruptcy and the occurrence of a material adverse effect on our company. Upon an event of default resulting from a voluntary or involuntary proceeding for bankruptcy, insolvency or receivership,
+the amounts outstanding under the Credit Agreement will become immediately due and payable and the Lender’s commitments will be automatically terminated. Upon the occurrence and continuation of any other event of default, the Lender may
+accelerate payment of all obligations and terminate its commitments under the Credit Agreement. 
+Research and Development Awards. Under a contract we entered into with the CDC, effective September 1, 2022, a total of up to $3.2 million of awards are available to assist
+us in developing a rapid POC Syphilis Diagnostic Test using the Company's DPP Technology. Of the total awards available under this contract, we recognized government grant income totaling $0.6 million during the year ended December 31, 2022. 
+Working Capital . The following table sets forth selected working capital information: 
+December 31, 2022 
+Cash and cash equivalents 
+18,179 
+Accounts receivable, net 
+6,536 
+Inventories, net 
+7,715 
+Insurance receivable 
+12,186 
+Prepaid expenses and other current assets 
+3,835 
+Total current assets 
+48,451 
+Less: Total current liabilities 
+(39,300 
+) 
+Working capital 
+9,151 
+59 
+Table of Contents 
+Our cash and cash equivalents at December 31, 2022, were held for working capital purposes. We currently intend to retain all available funds in excess of required minimum cash balance related to the Credit
+Agreement and any future earnings for use in the operation of our business and do not anticipate paying any cash dividends. We have not entered into, and do not expect to enter into, investments for trading or speculative purposes. Our accounts
+receivable and inventory balances fluctuate from period to period, which affects our cash flow from operating activities. Fluctuations vary depending on cash collections, client mix, raw material lead times, the mix of vendor terms, and the
+timing of shipment of our products and the invoicing of our research and development activities. 
+Uses of Funds 
+Cash Flow Used in Operating Activities . Our operations used $12.7 million of cash during the year ended December 31, 2022, primarily
+due to the net loss adjusted for non-cash items of $14.7 million. Those uses of cash were the result of $4.8 million decrease in accounts receivable, a $4.6 million decrease in inventory, and $14.0 million increase in Prepaid and other current
+assets, offset in part by a $6.6 million increase in accounts payable and other accrued liabilities. 
+Credit Agreement. Principal installments in the amount of $300,000 are payable under the Credit Agreement on the last day of each of the eleven months from September 2022
+through July 2023, and all remaining principal is payable at maturity on September 3, 2023. Upon an event of default under the Credit Agreement, the Lender could elect to declare all amounts outstanding thereunder, together with accrued interest,
+to be immediately due and payable, as further described “—Sources of Funds—Credit Agreement—Default Provisions” above. In addition, we could determine to prepay from time to time outstanding principal under the Credit Agreement (see “—Sources of
+Funds—Credit Agreement—Optional Prepayment” above) or to make other payments under the Credit Agreement that may not be then due or otherwise required under the Credit Agreement, although, as of the date of the filing of this report, we do not
+intend to make any such prepayments or other payments. 
+Capital Expenditures. Our capital expenditures totaled $1.5 million in the year ended December 31, 2022, all of which related to investments in automated manufacturing
+equipment, facilities, and other fixed assets. As of December 31, 2022, we had capital purchase obligations of $0.01 million related to additional automated manufacturing equipment, with payments expected to come due during 2023 based on vendor
+performance milestones. 
+Significant Accounting Policies and Critical Accounting Estimates 
+Our significant accounting policies are described in Note 2 – Significant Accounting Policies to the audited consolidated financial statements included herein. Certain of our accounting policies require the
+application of significant judgment by management in selecting the appropriate assumptions for calculating financial estimates. By their nature, these judgments are subject to an inherent degree of uncertainty. These judgments are based on our
+historical experience, terms of existing contracts, our evaluation of trends in the industry, information provided by our customers and information available from other outside sources, as appropriate. We consider an accounting estimate to be
+critical if (a) it requires us to make assumptions about matters that were uncertain at the time we were making the estimate and (b) changes in the estimate or different estimates that we could have selected would have had a material impact on
+our financial condition or results of operations. 
+The following listing is not intended to be a comprehensive list of all of our accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by accounting
+principles generally accepted in the United States, with no need for management’s judgment in their application. There are also areas in which management’s judgment in selecting any viable alternative would not produce a materially different
+result. 
+60 
+Table of Contents 
+Revenue Recognition 
+We recognize revenue for product sales in accordance with Financial Accounting Standards Board Accounting Standards Codification, or ASC, 606, Revenue from Contracts with
+Customers . Revenues from product sales are recognized when the customer obtains control of our product, which occurs at a point in time, typically upon tendering to the customer. We expense incremental costs of obtaining a contract as
+and when incurred because the expected amortization period of the asset that it would have recognized is one year or less or the amount is immaterial. Freight and distribution activities on products are performed after the customer obtains
+control of the goods. We have made an accounting policy election to account for shipping and handling activities that occur either when or after goods are tendered to the customer as a fulfillment activity, and therefore recognizes freight and
+distribution expenses in cost of product sales. We exclude certain taxes from the transaction price ( e.g. , sales, value added and some excise taxes). 
+Estimates of variable consideration and the determination of whether to include estimated amounts in the transaction price are based on all information (historical, current, and forecasted) that is reasonably
+available to us, taking into consideration the type of customer, the type of transaction, market events and trends, and the specific facts and circumstances of each arrangement. 
+For applicable contracts, we recognize revenue from research and development, milestone and grant revenues when earned. Grants are invoiced after expenses are incurred. Revenues from projects or grants funded in
+advance are deferred until earned. For certain collaborative research projects, we recognize revenue by defining milestones at the inception of the agreement and applying judgment and estimates in recognizing revenue for relevant contracts. 
+From time to time the Company engages in bill-and-hold arrangements, whereby the Company manufactures and sells its product and at the customer’s request stores the product at the Company’s warehouse. Even though
+the product remains in the Company’s possession, a sale is recognized at the point in time when the customer obtains control of the product. Control is transferred to the customer in bill and hold transactions when: customer acceptance
+specifications have been met, legal title has transferred, the customer has a present obligation to pay for the product and the risk and rewards of ownership have transferred to the customer. Additionally, all the following bill and hold
+criteria would have to be met in order for control to be transferred to the customer: 
+(a) The reason for the bill-and-hold arrangement must be substantive (for example, the customer has requested the arrangement). 
+(b) The product must be identified separately as belonging to the customer. 
+(c) The product currently must be ready for physical transfer to the customer. 
+(d) The entity cannot have the ability to use the product or to direct it to another customer. 
+Goodwill 
+We periodically review goodwill for impairment indicators. We review goodwill for impairment annually in the fourth quarter or more frequently if events or changes in circumstances indicate that goodwill might be
+impaired. We perform the goodwill impairment review at the reporting unit level. We perform a qualitative assessment of whether it is more likely than not that a reporting unit’s fair value is less than its carrying amount. If not, no further
+goodwill impairment testing is performed. If so, we perform the step discussed hereafter. Our qualitative assessment involves significant estimates, assumptions, and judgments, including, macroeconomic conditions, industry and market conditions,
+our financial performance, reporting unit specific events and changes in our share price. 
+If the fair value of the reporting unit is greater than its carrying amount, goodwill is not considered to be impaired. We would recognize an impairment charge for the
+amount by which the carrying amount exceeds the reporting unit’s fair value, provided the impairment charge does not exceed the total amount of goodwill allocated to the reporting unit. 
+The company operates as a single operating segment and has one reporting unit. During the year ended December 31, 2022, the Company performed a quantitative analysis and determined that the carrying value exceeded
+its fair value and recorded a goodwill impairment charge of $3.0 million. 
+Recently Issued Accounting Pronouncements 
+Refer to Note 2 – Significant Accounting Policies to the audited consolidated financial statements included herein for a complete description of recent accounting standards that we have not yet been required to
+implement which may be applicable to our operations. Additionally, the significant accounting standards that have been adopted during the year ended December 31, 2022 are described. 
+ITEM 8. 
+FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+The Consolidated Financial Statements and schedules that constitute Item 8 are attached at the end of this report. An index to the Consolidated
+Financial Statements and supplemental schedules are also included on page F-1 of this report. 
+61 
+Table of Contents 
+ITEM 9. 
+CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 
+None. 
+ITEM 9A. 
+Controls and Procedures 
+Evaluation of Disclosure Controls and Procedures 
+Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures, as defined by Rules 13a-15(e) and 15d-15(e)
+under the Exchange Act, as of December 31, 2022. Based on the evaluation of our disclosure controls and procedures, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective
+as of December 31, 2022 due to a material weakness in internal control over financial reporting described below. 
+Management’s Report on Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rules 13a-15(f) and 15d-15(f) promulgated
+under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer and effected by the board of directors, management and other personnel to provide reasonable
+assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that: 
+• 
+pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; 
+• 
+provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are
+being made in accordance with authorizations of management and directors of the company; and 
+• 
+provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. As a result, even those systems determined to be effective can provide only reasonable
+assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the
+degree of compliance with the policies or procedures may deteriorate. 
+Under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, our management evaluated the effectiveness of our internal control over financial reporting as of
+December 31, 2022. In making their assessment of internal control over financial reporting, our management used the criteria described in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the
+Treadway Commission. Our evaluation included documenting, evaluating and testing of the design and operating effectiveness of our internal control over financial reporting. Based on this evaluation, we concluded that our controls over financial
+reporting were not effective as of December 31, 2022. 
+A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual
+or interim financial statements will not be prevented or detected on a timely basis. In connection with the assessment of our internal control over financial reporting described above, management identified the following deficiencies that
+constituted individually, or in the aggregate, material weakness in our internal control over financial reporting as of December 31, 2022: 
+62 
+Table of Contents 
+• 
+Inventory Costing Process – We did not appropriately include all direct labor in the products unit cost, freight in charges and adjustments for products not shipped when establishing the
+inventory balance as of December 31, 2022. These adjustments indicate ineffective or insufficient review of the inventory accounts. 
+The errors arising from the underlying deficiencies are not material to the financial statements reported in any interim or prior annual period and therefore did not result in a restatement to previously filed
+financial statements. These control deficiencies, however, could result in misstatements of the aforementioned accounts and disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that
+would not be prevented or detected in a timely manner. Accordingly, we have determined that these control deficiencies constitute a material weakness. 
+Remediation of the Material Weaknesses in Internal Control Over Financial Reporting 
+Management is committed to the planning and implementation of remediation efforts to address the material weakness. These remediation efforts, which have been implemented or are in process of implementation, are
+intended to both address the identified material weakness and to enhance our overall financial control environment. These efforts include revisiting the review controls and control owners involved in the inventory costing process. We identified
+and implemented additional internal controls to strengthen account analyses related to inventory costing and have personnel with additional cost accounting experience. In addition, we began the process to review all internal controls related to
+cost accounting and established procedures for cost data validation and reporting. As we continue to solidify our internal controls over the financial closing and reporting processes, we expect to fully remediate this material weakness. 
+Previously Identified Material Weaknesses in Internal Control Over Financial Reporting 
+None. 
+Changes in Internal Control over Financial Reporting 
+Other than the ongoing remediation efforts described above, there were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of
+the Securities Exchange Act of 1934 during the three months ended December 31, 2022 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+Inherent Limitations of Internal Control 
+Management, including the Company’s Chief Executive Officer and Chief Financial Officer, does not expect that the Company’s internal controls will prevent or detect all errors and all fraud. A control system, no
+matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints and
+the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of internal control can provide absolute assurance that all control issues and instances of fraud, if
+any, have been detected. Also, any evaluation of the effectiveness of internal controls in future periods are subject to the risk that those internal controls may become inadequate because of changes in business conditions, or that the degree of
+compliance with the policies and procedures may deteriorate. 
+ITEM 9B. 
+Other Information 
+None. 
+63 
+Table of Contents 
+ITEM 9C. 
+Disclosure Regarding Foreign Jurisdiction that Prevent Inspections 
+None. 
+PART III 
+ITEM 10. 
+DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
+Identification of Directors 
+Name 
+Age 
+Position with the Company 
+Director Since 
+David W.K. Acheson, M.D. 
+67 
+Director 
+2020 
+David W. Bespalko 
+67 
+Director 
+2021 
+Katherine L. Davis 
+66 
+Chair of the Board, Director 
+2007 
+Richard L. Eberly 
+62 
+Director, Chief Executive Officer and President 
+2020 
+John G. Potthoff 
+55 
+Director 
+2018 
+Leslie Teso-Lichtman 
+64 
+Director 
+2022 
+Dr. David W.K. Acheson, M.D. 
+Professional Experience 
+• 
+Director since December 2020 
+• 
+President and Chief Executive Officer of The Acheson Group, a global food safety consulting group, since 2013 
+• 
+Partner and Managing Director of Leavitt Partners, a health care consulting firm, where he founded and managed the firm’s food safety services business, from 2009 to 2013 
+• 
+From 2002 to 2009, served at the U.S. Food and Drug Administration in various positions, progressing from Chief Medical Officer of the Center for Food Safety and Applied
+Nutrition to Associate Commissioner for Foods, where he held an agency-wide leadership role for food issues 
+• 
+Prior to joining the U.S. Food and Drug Administration, he practiced in the areas of internal medicine and infectious diseases in the United Kingdom from 1980 to 1987 
+• 
+After his internal medicine practice, he served as an Associate Professor at Tufts University studying the molecular pathogenesis of foodborne pathogens 
+• 
+Fellow of the Royal College of Physicians (London) and the Infectious Disease Society of America 
+Education 
+• 
+Doctor in Medicine degree, Bachelor of Science degree, Bachelor of Medicine degree, and Bachelor of Surgery degree from the University of London 
+Relevant Skills 
+• 
+Leadership 
+• 
+Policy/Government 
+• 
+Industry 
+David W. Bespalko 
+Professional Experience 
+• 
+Director since March 2021 
+• 
+Founder and Chief Executive Officer of BMC Consulting, a management consulting firm for in vitro diagnostics companies, since September 2019 
+• 
+From 2017 to April 2019, Group Vice President, Global Commercial Operations Specialty Diagnostics Group of Thermo Fisher Scientific Inc., or Thermo Fisher, a provider of
+scientific instrumentation, reagents and consumables, and software and services to healthcare and other laboratories from December 2017 to April 2019 
+• 
+President of Anatomical Pathology and Healthcare Market Divisions of Thermo Fisher from 2015 to December 2017 
+• 
+President of Fisher Healthcare at Thermo Fisher from 2011 to 2015 
+64 
+Table of Contents 
+• 
+Prior to his appointment as President of Fisher Healthcare, he served as Corporate Vice President, North America Commercial Operations at Beckman Coulter, Inc. 
+• 
+Before joining Beckman Coulter, Inc., he served in commercial and general management roles at Baxter Healthcare Corporation and Dade Behring, Inc. 
+Education 
+• 
+Bachelor of Science degree from the University of Alberta 
+Relevant Skills 
+• 
+Leadership 
+• 
+Governance 
+• 
+Industry 
+Katherine L. Davis 
+Professional Experience 
+• 
+Director since 2007 and served as Chair of the Board from March 2014 to April 2020 and since July 2020 
+• 
+Owner of Davis Design Group LLC, a provider of analytical and visual tools for public policy design, since 2007 
+• 
+Chief Executive Officer of Global Access Point, a start-up company with products for data transport, data processing, and data storage network and hub facilities, from 2005 to
+2006 
+• 
+Lieutenant Governor of the State of Indiana from 2003 to 2005 
+• 
+Controller of the City of Indianapolis from 2000 to 2003 
+• 
+Financial Advisor to the Mayor of Indianapolis since 2016 
+Education 
+• 
+Master of Business Administration degree from Harvard Business School 
+• 
+Bachelor of Science degree in mechanical engineering from the Massachusetts Institute of Technology 
+Relevant Skills 
+• 
+Leadership 
+• 
+Governance 
+• 
+Policy / Government 
+Richard L. Eberly 
+Professional Experience 
+• 
+Chief Executive Office and President since March 2020 and a director since May 2020 
+• 
+Managing Director at Solid Rock Principled Capital of Solid Rock Principled Capital LLC, a private equity firm focused on biomedical companies, from March 2018 to March 2020 
+• 
+Executive Vice President and President, Chief Commercial Officer at Meridian Bioscience, Inc. from 2016 to February 2018 
+• 
+President of Meridian Life Science from 2012 to 2016 
+• 
+Chief Commercial Officer of Meridian Life Science from 2011 to February 2018 
+• 
+Executive Vice President from 2005 to 2011, Executive Vice President, General Manager from 2003 to 2005, Executive Vice President from 2000 to 2003 and Vice President of Sales
+and Marketing from 1997 to 2000, all at Meridian Life Science 
+• 
+Prior to his appointment to Vice President of Sales and Marketing, he served as Director of Sales for Meridian 
+• 
+Before joining Meridian, Mr. Eberly held sales and marketing positions at Abbott Diagnostics, Division of Abbott Laboratories 
+65 
+Table of Contents 
+Education 
+• 
+Master of Business Administration degree from Xavier University 
+• 
+Bachelor of Science degree in Biochemistry from Juniata College 
+Relevant Skills 
+• 
+Industry 
+• 
+Leadership 
+• 
+Innovation 
+Dr. John G. Potthoff, Ph.D. 
+Professional Experience 
+• 
+Director since May 2018 
+• 
+Chief Executive Officer, co-founder and director of Elligo Health Research, a clinical research company, since 2016 
+• 
+President and Chief Executive Officer of Theorem Clinical Research Inc., a global contract research organization providing comprehensive clinical services, from 2011 until its
+acquisition by Chiltern International in 2015 
+• 
+Chief Operating Officer of INC Research Holdings, Inc. from its acquisition of Tanistry, Inc. in 2001 until its acquisition by private equity investors in 2010 
+• 
+Chief Executive Officer and founder of Tanistry, Inc., a contract research organization focused on the central nervous system, from 2000 to 2001 
+Education 
+• 
+Doctor of Philosophy degree in Psychology from the University of Texas-Austin 
+• 
+Master of Arts degree in Psychology from the University of Texas-Austin 
+• 
+Bachelor of Arts degree in Psychology from the University of Texas-Austin 
+Relevant Skills 
+• 
+Finance 
+• 
+Industry 
+• 
+Leadership 
+Ms. Leslie Teso-Lichtman 
+Professional Experience 
+• 
+Director since May 2022 
+• 
+Senior Vice President and Chief Financial Officer of CereVasc, Inc., a medical device company developing treatments for neurological diseases, since 2014 
+• 
+Senior Vice President Finance and Treasurer of Roche Diagnostics Hematology, Inc. (formerly Constitution Medical Investors, Inc.), a developer of hematology testing systems,
+from 2011 to 2014 
+• 
+Vice President and Controller of Hologic, Inc. (formerly Cytyc Corporation), a manufacturer of diagnostic and surgical products for cancer and women’s health, from 1998 to 2006 
+Education 
+• 
+Master of Business Administration from Southern New Hampshire University (formerly New Hampshire College) 
+• 
+Bachelor of Science degree in Business Management from Daniel Webster College 
+• 
+Associate of Science degree in Accounting from Daniel Webster College 
+Relevant Skills 
+• 
+Leadership 
+• 
+Finance 
+• 
+Industry 
+66 
+Table of Contents 
+Identification of Executive Officers 
+Name 
+Age 
+Position with the Company 
+Date First Appointed 
+Paul Angelico 
+66 
+Executive Vice President and Chief Operations Officer 
+January 2022 
+Charles Caso 
+61 
+Senior Vice President, Global Commercial Operations 
+January 2022 
+Richard L. Eberly 
+62 
+Director, Chief Executive Officer and President 
+March 2020 
+Javan Esfandiari 
+56 
+Executive Vice President and Chief Scientific and Technology Officer 
+2004 
+Lawrence J. Steenvoorden 
+53 
+Executive Vice President and Chief Financial Officer 
+January 2022 
+Paul J. Angelico 
+Professional Experience 
+• 
+Executive Vice President and Chief Operations Officer since January 2022, Vice President of Global Operations from April 2020 to January 2022 and Vice President of
+Manufacturing Operations from October 2019 to April 2020 
+• 
+Executive Vice President of Global Operations of US Nonwovens LLC, a private label manufacturer of personal, fabric and home-care products for consumer products retailers, from
+December 2017 to October 2019 
+• 
+Principal and Owner of The Dover Group, a management consultancy servicing multiple industry sectors, from 2009 to December 2017 
+• 
+President, Chief Executive Officer and Director of Cyclica Inc., a life sciences technology provider of proprietary software solutions to drug discovery and development
+companies, from 2015 to 2016 
+Education 
+• 
+Bachelor of Science degree in Mechanical Engineering from Worcester Polytechnic Institute 
+Charles Caso 
+Professional Experience 
+• 
+Senior Vice President, Global Commercial Operations since January 2022, Vice President, North American Sales & Global Marketing from May 2020 to January 2022 
+• 
+Vice President, Global Sales and Customer Success of ArcherDX, Inc., (now Invitae Corporation) a life sciences tool company, from July 2019 to April 2020 
+• 
+Senior Vice President, Commercial Operations – Global Diagnostics from March 2018 to April 2019 and Vice President, Sales & Marketing – Global Diagnostics from August 2016
+to March 2018 at Meridian Bioscience, a global provider of molecular and immunological reagents and life science raw materials for diagnostic applications 
+• 
+Served in a series of positions at Beckman Coulter Genomics (operating company of Danaher Inc.) from 2011 to 2016, including as Director of Worldwide Commercial Operations
+from 2015-2016 
+Education 
+• 
+Bachelor of Science degree in Marketing from Indiana University of Pennsylvania 
+• 
+Master of Business Administration degree from University of Pittsburgh Katz Graduate School of Business 
+Richard L. Eberly is discussed above under “Identification of Directors.” 
+67 
+Table of Contents 
+Javan Esfandiari 
+Professional Experience 
+• 
+Executive Vice President and Chief Scientific and Technology Officer since 2004 and Director of Research and Development, from 2000 to 2004 
+• 
+Co-founder and Director of Research and Development of Sinovus Biotech AB, a developer of lateral flow technology, from 1997 to 2000 
+• 
+Director of Research and Development with On-Site Biotech/National Veterinary Institute, a government agency for veterinary medicine, from 1993 to 1997 
+Education 
+• 
+Master of Science degree in Molecular Biology from Lund University, Sweden 
+• 
+Bachelor of Science degree in Clinical Chemistry from Lund University, Sweden 
+Lawrence J. Steenvoorden 
+Professional Experience 
+• 
+Senior Director at Accordion Partners, a private equity-focused financial consulting and technology firm, from December 2018 to December 2021, Director from December 2017 to
+December 2018 
+• 
+Chief Accounting & Financial Officer of Onyx Renewable Partners, LP, a renewable energy development company managed by Blackstone Energy Partners, from March 2016 to
+November 2017 
+• 
+Various accounting roles of increasing responsibility at Siemens Healthcare Diagnostics Inc., Siemens Corporation and Siemens AG, including most recently Global Controller,
+Business Planning & Controlling of Siemens Healthcare Diagnostics Inc, from 2001 to February 2016. 
+• 
+Certified Public Accountant 
+Education 
+• 
+Bachelor of Science degree in Accounting from the University of Delaware 
+• 
+Master of Business Administration degree from Rider University 
+Family Relationships 
+There are no family relationships between our Directors or executive officers. 
+Delinquent Section 16(a) Reports 
+Section 16(a) of the Securities Exchange Act requires the Company’s directors and certain of its executive officers and persons who beneficially own more than 10%
+of the Company’s common shares to file reports of and changes in ownership with the SEC. Based solely on the Company’s review of copies of SEC filings it has received or filed, the Company believes that each of its directors, executive
+officers, and beneficial owners of more than 10% of the shares satisfied the Section 16(a) filing requirements during the fiscal year-ended December 31, 2022, except that a Form 3 for each of Paul Angelico and Charles Caso were filed on April
+27, 2022 after each became subject to reporting his beneficial ownership of our common stock on April 11, 2022. 
+Code of Business Conduct and Ethics 
+Our board of directors has adopted a Code of Business Conduct and Ethics applicable to all of our directors, officers and employees. We have posted the Code of
+Business Conduct and Ethics on our website at https://chembiodiagnosticsinc.gcs-web.com/static-files/bca4f259-b35e-4280-a17f-2509fb6ff007. We will post
+any amendments to the Code of Business Conduct and Ethics on our website. In accordance with the requirements of the SEC and Nasdaq, we will also post waivers applicable to any of our officers or directors from provisions of the Code of
+Business Conduct and Ethics on our website. We have not granted any such waivers to date. 
+We have implemented whistleblower procedures, which establish format protocols for receiving and handling complaints from employees. We have posted copies of our
+whistleblower procedures on our website at https://chembio.com/investors/corporate-governance/ . Any concerns regarding accounting or auditing matters
+reported under these procedures are to be communicated to the audit committee or our President and Chief Executive Officer. 
+68 
+Table of Contents 
+Audit Committee 
+The principal responsibilities of the audit committee are: 
+• 
+appointing, approving the compensation of, and assessing the independence of our independent auditor; 
+• 
+approving all audit and non-audit services of the independent auditor; 
+• 
+evaluating our independent auditor’s qualifications, performance and independence; 
+• 
+reviewing our financial statements and financial disclosure; 
+• 
+conducting periodic assessments of our accounting practices and policies; 
+• 
+furnishing the audit committee report required by SEC rules; 
+• 
+reviewing and approving of all related-party transactions; 
+• 
+setting hiring policies for the hiring of employees and former employees or our independent auditor and ensuring that those policies comply with all applicable regulations; 
+• 
+developing and monitoring compliance with a code of ethics for senior financial officers and a code of conduct for our employees, officers and directors; 
+• 
+establishing procedures for the receipt, retention and treatment of complaints regarding accounting, internal accounting controls or auditing matters; 
+• 
+establishing procedures for the confidential, anonymous submission by employees of concerns regarding questionable accounting or auditing matters; 
+• 
+overseeing the work of our independent auditor, including resolution of disagreements between management and our independent auditor; and 
+• 
+reviewing and discussing our annual and quarterly financial statements and related disclosures with management and our independent auditor. 
+Our independent auditor is ultimately accountable to the audit committee. The audit committee has the ultimate authority and responsibility to select, evaluate,
+approve terms of retention and compensation of, and, where appropriate, replace the independent auditor. 
+The current members of the audit committee are John Potthoff, who serves as chair, David Acheson, David Bespalko, and Leslie Teso-Lichtman. The board determined
+that each of the current audit committee members is (a) independent, as defined in the listing standards of Nasdaq, (b) a “non-employee director,” as defined in Rule 16b-3 under the Securities Exchange Act, (c) an “outside director,” as defined
+in Section 162(m) of the Internal Revenue Code of 1986, or the Code, and (d) financially literate. The board also determined that Dr. Potthoff is an audit committee financial expert in accordance with the standards of the SEC. 
+69 
+Table of Contents 
+ITEM 11. 
+EXECUTIVE COMPENSATION 
+Director Compensation 
+Our director compensation program is intended to enhance our ability to attract, retain and motivate non-employee directors of exceptional ability and to promote the common interest of directors and stockholders in
+enhancing the value of the common stock. The board of directors reviews director compensation annually based on recommendations by the nominating and corporate governance committee. The nominating and corporate governance committee has the sole
+authority to engage a consulting firm to evaluate director compensation. 
+Under our non-employee director compensation program, each non-employee director is eligible to receive compensation for board and committee service consisting of annual cash retainers and equity awards. Directors
+also may be paid for serving on ad hoc committees of the board. Richard Eberly, our President and Chief Executive Officer, does not receive any additional compensation for his service as a director. 
+Under our non-employee director compensation program, in 2022 our non-employee directors were eligible to receive the following annual cash compensation for their service on the board and the board’s standing
+committees: 
+NON-EMPLOYEE DIRECTOR ANNUAL RETAINERS 
+Position 
+Annual Cash 
+Retainer 
+Chair of the Board 
+$ 
+70,000 
+All Other Independent Directors 
+35,000 
+Audit Committee Chair 
+15,000 
+Other Audit Committee Members 
+7,500 
+Compensation Committee Chair 
+10,000 
+Other Compensation Committee Members 
+5,000 
+Nominating and Governance Committee Chair 
+7,500 
+Other Nominating and Governance Committee Members 
+3,750 
+The following table shows the total compensation for non-employee directors during 2022. 
+2022 NON-EMPLOYEE DIRECTOR COMPENSATION TABLE 
+Non Employee Director 
+Fees Earned or 
+Paid in Cash ($)(1) 
+Option 
+Awards($)(2)(3)(5) 
+Stock 
+Awards($)(2)(4) 
+Total($) 
+David W.K. Acheson 
+$ 
+50,000 
+$ 
+19,196 
+$ 
+22,365 
+$ 
+91,561 
+David W. Bespalko 
+52,500 
+19,196 
+22,365 
+94,061 
+Katherine L. Davis 
+82,325 
+19,196 
+22,365 
+123,886 
+John G. Potthoff 
+58,750 
+19,196 
+22,365 
+100,311 
+Leslie Teso-Lichtman 
+27,829 
+52,987 
+62,611 
+143,427 
+(1) 
+Consist of annual retainer fees, as described in the preceding table. 
+(2) 
+Reflects the aggregate grant date fair value of any restricted stock units and stock options granted determined in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718, Compensation—Stock
+Compensation. Assumptions used in the calculation of this amount are included in Note 10. Equity Incentive Plans to the Consolidated Financial Statements included in our Annual Report on Form 10-K for the fiscal year ended December 31,
+2022. This amount does not reflect the actual economic value that will ultimately be realized by each director. 
+70 
+Table of Contents 
+(3) 
+Upon appointment to the board, Ms. Teso-Lichtman was awarded nonqualified stock options to acquire 41,143 shares of common stock, each with an exercise price of $1.25 per share. The nonqualified stock options will vest in full
+immediately prior to the earlier of (i) the 2023 annual meeting of stockholders and (ii) a Change in Control (as defined in the 2019 Omnibus Incentive Plan). 
+(4) 
+Upon appointment to the board, Ms. Teso-Lichtman was awarded 32,000 restricted stock units, each to acquire one share of common stock. The restricted stock units vest in full immediately prior to the earlier of (i) the 2023 annual
+meeting of stockholders and (ii) a Change in Control (as defined in the 2019 Omnibus Incentive Plan). 
+(5) 
+As of December 31, 2022, there were 462,9007 shares of unexercised options of which, 288,001 were not yet vested. 
+As discussed under “Executive Compensation—Summary Compensation Table—Narrative Explanation of Summary Compensation Table,” on February 20, 2020, the board adopted the Grant Guidelines in the form recommended by
+the compensation committee. The Grant Guidelines provide for the grant of equity awards to non-employee directors once annually, on the date of our annual meeting of stockholders at which the non-employee directors are elected (or re-elected) to
+the board unless such annual stockholder meeting occurs either (a) earlier than the third trading day following the date on which we file our Quarterly Report on Form 10-Q for the quarter ended March 31 of such year, in which case the grant date
+generally shall be the first Monday that follows the date of such filing, or (b) on or after June 1 of such year, in which case the grant date generally shall be the first Monday that follows the date on which we next file an Annual Report on
+Form 10-K or Quarterly Report on Form 10-Q. 
+Outside Director Compensation Policy: In January 2022, the Compensation Committee approved the adoption of the Outside Director Compensation Policy, effective immediately. The purpose of the Outside Director
+Compensation Policy is to provide a total compensation package that enables us to attract and retain, on a long-term basis, high-caliber directors. The Outside Director Compensation Policy applies to each non-employee who serves on the board. The
+Compensation Committee approved the Outside Director Compensation Policy in after considering recommendations made by our compensation consultant based in part upon assessments of our director compensation relative to that of a peer group of
+comparable companies. 
+The Outside Director Compensation Policy sets forth (a) cash and equity compensation for directors serving during calendar year 2022 and (b) one-time equity compensation for new directors joining the board on or
+after January 1, 2022. The board reviews and approves director compensation annually and will amend or restate the Outside Director Compensation Policy accordingly. 
+Compensation for 2022 Services. Under the Outside Director Compensation Policy, the following terms applied during calendar year 2022: 
+• 
+Cash Compensation. Each non-employee director was entitled to a cash retainer of $35,000 for service on the board of directors for 2022, except that the Chair of the Board would receive a cash retainer of $70,000. In addition, a
+non-employee director serving on the board’s audit committee, compensation committee, or nominating and corporate governance committee in a non-Chair capacity was entitled to a cash retainer of $7,500, $5,000 or $3,750, respectively, for
+services on those committees for the year. The Chair of one of those committees was entitled to a cash retainer twice the amount payable to other members of that committee. Directors were not entitled to receive attendance fees for any
+meetings of the board or its committees. 
+• 
+Equity Awards. Under the Outside Director Compensation Policy, each of the non-employee directors elected (or re-elected) to the board at the 2022 annual meeting of stockholders would have received annual equity-based awards under our
+2019 Omnibus Incentive Plan having an aggregate value of $80,000, based upon the fair market value of common stock on the grant date and consisting of $40,000 in value of restricted stock units and $40,000 in value of nonqualified stock
+options. These awards would have been granted as of the date of the 2022 annual meeting and would have vested immediately prior to the Annual Meeting. 
+One-time Equity Award for New Directors. Each non-employee director who is initially elected to the board after January 1, 2022 will receive equity awards with an aggregate value of $160,000, which will consist of
+$80,000 in value of restricted stock units and $80,000 in value of nonqualified stock options unless otherwise determined by the compensation committee. These awards are to be granted upon commencement of board service. The restricted stock units
+will vest on the first, second and third anniversaries of the grant date, and the nonqualified stock options will vest in full immediately prior to second annual meeting of stockholders following the grant (unless the director is first elected at
+an annual meeting, in which case the nonqualified stock option will vest in full immediately prior to the next annual meeting). All of the restricted stock units and nonqualified stock options will be subject to accelerated vesting upon a defined
+change in control. 
+71 
+Table of Contents 
+Executive Compensation 
+Summary Compensation Table 
+We are eligible, and have chosen, to comply with the scaled executive and director compensation disclosure rules applicable to a “smaller reporting company,” as defined in applicable SEC rules. 
+The following table provides information concerning the compensation paid for 2022 and 2021 to our “named executive officers” as of December 31, 2022, who consisted of our President and Chief Executive Officer and
+our next two most highly compensated executive officers during 2022. 
+Name and Principal Position 
+Year 
+Salary 
+($) 
+Bonus 
+($) 
+Stock 
+Awards 
+($)(1)(2)(5) 
+Option 
+Awards 
+($)(1)(3)(6) 
+All Other 
+Compensation 
+($)(4)(7) 
+Total 
+($) 
+Richard L. Eberly 
+2022 
+$ 
+459,887 
+$ 
+453,100 
+$ 
+301,925 
+$ 
+393,371 
+$ 
+2,123 
+$ 
+1,610,406 
+President and Chief Executive Officer 
+2021 
+476,764 
+186,300 
+540,000 
+938,774 
+1,062 
+2,142,900 
+Lawrence J. Steenvoorden 
+2022 
+334,966 
+269,920 
+180,000 
+244,626 
+14,999 
+1,044,510 
+Executive Vice President and Chief Financial Officer 
+2021 
+- 
+- 
+- 
+- 
+- 
+- 
+Javan Esfandiari 
+2022 
+383,000 
+143,625 
+100,642 
+131,123 
+7,574 
+765,964 
+Executive Vice President and Chief Science 
+and Technology Officer 
+2021 
+397,453 
+108,389 
+180,002 
+312,993 
+2,380 
+1,001,217 
+(1) 
+Reflects the aggregate grant date fair value of any restricted stock units and stock options granted determined in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718, Compensation—Stock
+Compensation. Assumptions used in the calculation of this amount are included in Note 10. Equity Incentive Plans to the Consolidated Financial Statements. This amount does not reflect the actual economic value that will ultimately be
+realized by each NEO. 
+(2) 
+Consist of restricted stock units that vest over three years, one-third of which vested on March 11, 2023, and with one-third vesting on each of March 11, 2024 and 2025, subject to continued service through each vesting date. 
+(3) 
+Consist of option awards exercisable for common stock. The option awards are scheduled to vest and become exercisable over four years, one-fourth of each vested on March 11, 2022 and March 11, 2023, and with one-fourth vesting on each
+of March 11, 2024 and 2025, subject to continued service through each vesting date. 
+(4) 
+Consists of matching contributions to 401(k) plan, car allowance, and relocation. 
+(5) 
+Consist of restricted stock units that vest over three years, one-third of which vested on January 05, 2023, and with one-third vesting on each of January 05, 2024 and 2025, subject to continued service through each vesting date. 
+(6) 
+Consist of option awards exercisable for common stock. The option awards are scheduled to vest and become exercisable over four years, one-fourth of which vested on January 05, 2023, and with one-fourth vesting on each of January 05,
+2024, 2025, and 2026 subject to continued service through each vesting date. 
+(7) 
+Mr. Steenvoorden received $12,000 for relocation expenses and $2,999 for 401(k) match. 
+Narrative Explanation of the Summary Compensation Table 
+The compensation paid to executives for 2022 consisted of the following components: 
+• 
+base salary; 
+• 
+cash bonuses, consisting of annual performance-based bonuses and one-time incentive bonuses; 
+• 
+long-term incentive compensation in the form of stock options and restricted stock units, or RSUs; and 
+• 
+benefits consisting principally of health and welfare plan contributions. 
+Following a review of market benchmarks in December 2022, it was determined that 2022 total compensation, and in particular target cash compensation (base salary and target annual cash bonuses), for our executives
+approached the market medians, but continued to be below that of similarly sized companies. We continue to believe that a performance-based compensation program calibrated to market median balances stockholder interests with our ability to
+attract and engage our executives. 
+2022 Cash Bonuses 
+Annual Performance-Based Bonuses. At meetings held in March 2022, the compensation committee, with the assistance of our independent compensation consultant Pearl Meyer, approved a formulaic structure for bonus
+determinations for executives with respect to 2022. In accordance with this structure: 
+• 
+Annual cash bonus payments for executives for 2022 were determined based on achievement of weighted metrics with respect to three corporate goals: revenue, 55%; adjusted EBITDA, 15%; and specified organizational goals aligned with our
+strategic plan (including regulatory, product development, manufacturing automation, employee retention and inventory-related milestones), 30%. In the first quarter of 2023, the compensation committee confirmed that NEOs had achieved, on
+a weighted basis, 68% of the target bonus amounts, as the result of substantial achievement of the targeted revenue metric and overachievement of the pre-determined organizational goals but no achievement of the targeted adjusted EBITDA
+metric. 
+72 
+Table of Contents 
+As the result of the above computations, 2022 annual cash bonus payments were made to Richard Eberly in the amount of $386,400, Javan Esfandiari in the amount of $88,090, and Lawrence J. Steenvoorden in the amount
+of $184,920. 
+One-Time Incentive Bonuses. 
+In August 2021 the board of directors, upon the recommendation of the compensation committee, approved the adoption of a One-Time Incentive Plan, or the OTIP, under which up to $1.5 million, or the OTIP Pool, was
+made available for cash awards to a number of employees, including executives. The board intended that the OTIP would help us: retain the employment of employees in the light of our liquidity challenges and a highly competitive employment market
+stemming, in part, from the ongoing COVID-19 pandemic; optimize our potential to deliver tests in accordance with the two significant customer purchase orders received in July 2021; and position our company on a solid path for the future. The
+company made OTIP payments of $163K and $637K for year ending 2021 and 2022, respectively. 
+• 
+Sixty percent, or up to $900,000, of the OTIP Pool was made available upon compliance with three performance milestones based on our receipt of payment for tests delivered under the two significant customer purchase orders, as follows:
+20%, or up to $180,000, would be payable to OTIP participants following our receipt of payment for the initial delivery of tests under either order; 30%, or up to $270,000, would be payable to OTIP participants following our receipt of
+payments under the orders totaling approximately $16.2 million (one-half of the aggregate purchase prices of the two orders); and 50%, or up to $450,000, would be payable to OTIP participants upon our receipt of payment for the total
+purchase prices of the two orders. Compliance with the performance milestones was completed by March 31, 2022. 
+• 
+The remaining forty percent, or $600,000, of the OTIP Pool is designed for employee retention, and will be available to OTIP participants who were employees in good standing as of August 31, 2022. Approximately $1.3 million of the cash
+awards under the OTIP was available for awards to 37 identified “critical employees,” who included each of the NEOs. Eligible employees were assigned to two tiers, with the 19 members of Tier I having potential awards of up to 25% of
+their annual base salaries and the 18 members of Tier II having potential awards of up to 15% of their annual base salaries. Each of our NEOs was a member of Tier 1, and their maximum award amounts, payable during 2022, were: Richard
+Eberly, $66,700; Javan Esfandiari, $55,535. 
+2022 Equity Awards 
+Prior to 2020, we did not typically grant equity awards to executives on an annual basis. From time to time, however, we did grant stock options, when appropriate, as a long-term incentive component of our
+compensation program. With respect to our long-term incentive program for 2022, the compensation committee adopted Pearl Meyer’s recommendation to grant to executives equity awards approaching the market median at similarly sized companies in our
+sector and we delivered equity grants in March 2022 in a combination of stock options (60% of value) and time-vesting RSUs (40% of value). The compensation committee determined, based on information compiled by Pearl Meyer, this structure is
+consistent with that of comparable companies. The compensation committee further determined that use of 2022 grant values approaching the market median appropriately balanced a recognition of our performance in 2021 and a desire to align the
+compensation of the executive team with future value creation. 
+Our stock options allow our executives to purchase covered shares at a price equal to the fair market value on the date of grant. In some cases, we attach performance criteria to the vesting of the stock options. 
+See also “—Outstanding Equity Awards at December 31, 2022” below. 
+On February 20, 2020, the board of directors adopted Equity Award Grant Guidelines, or the Grant Guidelines, in the form recommended by the compensation committee. The Grant Guidelines are intended to establish
+procedures for granting of equity-based awards that minimize the opportunity – or the perception of an opportunity – for us to time an equity award grant in a manner that could take advantage of any material nonpublic information or could result
+in an assertion that the equity award has been are priced at a value less than the fair market value of common stock on the grant date. Under the Grant Guidelines, the compensation committee generally is to consider and, if approved, grant equity
+awards to our employees once annually during the first quarter of the fiscal year, on the first Monday that follows the date on which we file our Annual Report on Form 10-K. The Grant Guidelines contemplate that the compensation committee may,
+from time to time, determine that it is in our best interests to deviate from the foregoing terms with respect to the grant of an equity award, in which case such Equity Award must be reviewed and approved by the board. 
+73 
+Table of Contents 
+Outstanding Equity Awards at December 31, 2022 
+The following table sets forth information regarding each unexercised option or unvested RSU held by each of our named executive officers as of December 31, 2022: 
+Option Awards 
+Stock Awards 
+Name 
+Number of 
+Securities 
+Underlying 
+Unexercised 
+Options 
+(#)Exercisable 
+Number of 
+Securities 
+Underlying 
+Unexercised 
+Options 
+(#)Unexe rcisab le 
+Option 
+Exercise 
+Price($) 
+Option 
+Expiration Date 
+Number of 
+Shares 
+or Units of 
+Stock 
+that have not 
+Vested(#) 
+M arket Value of 
+Shares or Units of 
+Stock that have not 
+Vested 
+Richard L. Eberly 
+(1)(4 
+) 
+- 
+- 
+- 
+- 
+288,000 
+- 
+(2)(4 
+) 
+208,285 
+624,858 
+1.25 
+3/10/2032 
+- 
+- 
+(1)(6 
+) 
+- 
+- 
+- 
+- 
+38,710 
+- 
+(2)(7 
+) 
+160,714 
+160,715 
+4.65 
+3/14/2028 
+- 
+- 
+Lawrence J. Steenvoorden 
+(1)(9 
+) 
+- 
+- 
+- 
+- 
+107,143 
+- 
+(2)(10 
+) 
+75,000 
+225,000 
+1.12 
+1/5/2029 
+- 
+- 
+Javan Esfandiari 
+(1)(4 
+) 
+- 
+- 
+- 
+- 
+96,000 
+- 
+(2)(5 
+) 
+69,428 
+208,286 
+1.25 
+3/10/2032 
+- 
+- 
+(1)(6 
+) 
+- 
+- 
+- 
+- 
+12,904 
+- 
+(2)(7 
+) 
+53,571 
+53,572 
+4.65 
+3/14/2028 
+- 
+- 
+(3)(8 
+) 
+- 
+188,064 
+2.36 
+3/15/2027 
+- 
+- 
+(1) 
+RSUs subject to vesting, to acquire common stock. 
+(2) 
+Options exercisable, subject to vesting, to acquire common stock. 
+(3) 
+Restricted stock award, or RSA. 
+(4) 
+RSU was granted on March 11, 2022. RSU vests over three years, with one-third vesting on each of the first, second and third anniversary of
+the grant date, subject to continued service through each vesting date. 
+(5) 
+Option was granted on March 11, 2022. Option vests and becomes exercisable over four years, with one-fourth vesting on each of the first,
+second, third and fourth anniversary of the grant date, subject to continued service through each vesting date. 
+(6) 
+RSU was granted on March 15, 2021. RSU vests over three years, with one-third vesting on each of the first, second and third anniversary of
+the grant date, subject to continued service through each vesting date. 
+(7) 
+Option was granted on March 15, 2021. Option vests and becomes exercisable over four years, with one-fourth vesting on each of the first,
+second, third and fourth anniversary of the grant date, subject to continued service through each vesting date. 
+(8) 
+Option was granted on March 16, 2020. Option vests and becomes exercisable over three years, with one-third vesting on each of the first,
+second and third anniversary of the grant date, subject to continued service through each vesting date. 
+(9) 
+RSU was granted on January 05, 2022. RSU vests over three years, with one-third vesting on each of the first, second and third anniversary
+of the grant date, subject to continued service through each vesting date. 
+(10) 
+Option was granted on January 05, 2022. Option vests and becomes exercisable over four years, with one-fourth vesting on each of the first,
+second, third and fourth anniversary of the grant date, subject to continued service through each vesting date. 
+74 
+Table of Contents 
+For information regarding the vesting acceleration provisions applicable to the options held by our named executive officers, please see “—Employment Agreements” below. 
+Employment Agreements 
+Richard L. Eberly 
+Effective as of March 16, 2020 and as amended on February 9, 2022, we entered into an employment agreement with Richard Eberly to serve as our President and Chief Executive Officer. The employment agreement, as
+amended, provides for our at-will employment of Mr. Eberly as our President and Chief Executive Officer through December 31 of each calendar year, which term will extend automatically for additional calendar years as of each January 1 unless
+either party delivers, by no later than the immediately preceding October 1, a written notice to the other party that the term will not be extended. Under the terms of the employment agreement, we will pay Mr. Eberly an annual base salary of
+$400,000, which amount is subject to annual review by the compensation committee and may be increased, but not decreased. In accordance with the terms of the employment agreement, we granted to Mr. Eberly on March 16, 2020 an RSU, award covering
+233,589 shares of common stock. Subject to Mr. Eberly’s continued service with us, the RSU award vests in three equal instalments, two of which vested as of March 16 of each of 2021, 2022 and with the final instalment vesting on March 16, 2023,
+except that vesting with respect to each outstanding equity award agreement executed by us and Mr. Eberly will accelerate if Mr. Eberly’s employment is terminated or not renewed by us without Cause or by Mr. Eberly for Good Reason within 12
+months following a Change in Control (each such capitalized term as defined in the employment agreement), to the extent such vesting is based solely on Mr. Eberly’s continued service over a period of time (rather than any performance-related
+metric). If Mr. Eberly’s employment is terminated or not renewed by us without Cause or by Mr. Eberly for Good Reason within 12 months of a Change in Control, we will be required to pay Mr. Eberly an amount equal to twice his base salary with
+respect to the year in which the termination occurs, in addition to the pro rata bonus amount. 
+Javan Esfandiari 
+Effective as of March 5, 2016 and as amended on March 20, 2019 and November 30, 2021, we entered into an employment agreement with Javan Esfandiari to continue as our Executive Vice President and Chief Scientific
+and Technology Officer for an additional term through December 31, 2024. The term will extend automatically for additional calendar years as of each January 1 (commencing January 1, 2025), unless either party delivers, by no later than three
+months prior to the scheduled expiration (initially September 31, 2024), a written notice to the other party that the term will not be extended. In the event Mr. Esfandiari’s employment is terminated by reason of Disability or for Cause, (as
+defined in the employment agreement), or due to Mr. Esfandiari’s resignation or voluntary termination, all compensation, including his base salary, his right to receive a performance bonus, and benefits, and the vesting of any unvested equity
+awards, will cease as of his termination date, and Mr. Esfandiari will receive no severance benefits. If Mr. Esfandiari’s employment agreement is terminated by us without Cause, or if Mr. Esfandiari terminates his employment agreement for a
+Reasonable Basis(as defined in the employment agreement), including within 12 months of a Change in Control (as defined in the employment agreement), we will be required to pay his base salary. Mr. Esfandiari’s employment agreement also contains
+provisions prohibiting Mr. Esfandiari from (a) soliciting our employees for a period of 24 months following his termination, (b) soliciting our customers, agents, or other sources of distribution of our business for a period of twelve months
+following his termination, and (c) except where termination is involuntary upon a “Change in Control,” for a period of twelve months following his termination, competing with us. 
+Lawrence J. Steenvoorden 
+Effective January 5, 2022, we entered into an employment agreement with Lawrence J. Steenvoorden to serve as our Executive Vice President and Chief Financial Officer. The employment agreement provides for Mr.
+Steenvoorden’s at-will employment as our Executive Vice President and Chief Financial Officer for an initial term commencing January 5, 2022 and expiring December 31, 2022. The term will extend automatically for an additional calendar year as of
+each January 1 (commencing January 1, 2023), unless either party delivers, by no later than the immediately preceding October 1 (initially October 1, 2022), a written notice to the other party that the term will not be extended. Under the terms
+of the employment agreement, we will pay Mr. Steenvoorden an annual base salary of $335,000, which amount is subject to annual review by the compensation committee and may be increased, but not decreased. In addition, we agreed to pay Mr.
+Steenvoorden (a) a cash signing bonus totaling $85,000, of which $40,000 was paid in January 2022 and $45,000 is payable in July 2022, and (b) a non-accountable allowance totaling $12,000 for living expenses associated with his relocation to a
+new principal place of employment with us, paid in equal monthly installments in January, February and March 2022. In accordance with the terms of the employment agreement, we granted to Mr. Steenvoorden on January 5, 2022 (a) a nonqualified
+stock option to acquire 300,000 shares of common stock at a price of $1.12 per share, expiring on January 5, 2029, and (b) a restricted stock unit award to acquire, without payment of any purchase price, up to 160,714 shares of common stock.
+Subject to Mr. Steenvoorden’s continued service with us, the shares subject to the nonqualified stock option will vest in four equal annual installments and the shares subject to the restricted stock unit award will vest in three equal annual
+installments, except that, in each case, vesting will accelerate in full upon (a) our termination of Mr. Steenvoorden’s employment without Cause, Mr. Steenvoorden’s termination of his employment for Good Reason or the expiration of the Term upon
+notice of nonrenewal delivered by Chembio, in each case within 12 months following a Change in Control, or (b) Mr. Steenvoorden’s death or Permanent Disability (each such capitalized term as defined in the employment agreement). Pursuant to the
+employment agreement, if Mr. Steenvoorden’s employment is terminated or not renewed by us without Cause or by Mr. Steenvoorden for Good Reason, we will be required to pay to Mr. Steenvoorden (a) a lump sum amount equal to his annual base salary
+and a pro rata bonus amount, each with respect to the year in which the termination occurs, and (b) on a monthly basis, for a period of up to one year, an amount equal to the Consolidated Omnibus Budget Reconciliation Act of 1985 (COBRA) premium
+for the highest level of coverage available under our group health plans, but reduced by the monthly amount that Mr. Steenvoorden would pay for such coverage if he were an active employee. 
+75 
+Table of Contents 
+ITEM 12. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+Beneficial Ownership of Common Stock 
+The following table sets forth the number of outstanding shares of common stock beneficially owned, and the percentage of the class beneficially owned, as of March
+28, 2023, by: 
+• 
+each named executive officer included in “Executive Compensation—Summary Compensation Table”; 
+• 
+each current director and the additional nominee for election as a director; and 
+• 
+all of our current executive officers and directors and the additional nominee for election as a director, as a group 
+The number of shares of common stock beneficially owned by each person is determined under the rules of the SEC. Under these rules, beneficial ownership includes any
+shares as to which the individual has sole or shared voting power or investment power and also any shares that the individual has the right to acquire by May 27, 2023 (60 days after March 28, 2023) through the exercise or conversion of a security
+or other right. Unless otherwise indicated, each person has sole investment and voting power, or shares such power with a family member, with respect to the shares set forth in the following table. The inclusion in this table of any shares deemed
+beneficially owned does not constitute an admission of beneficial ownership of those shares for any other purpose. As of March 28, 2023, there were 36,725,858 shares of common stock outstanding. Shares not outstanding, but deemed beneficially
+owned by virtue of the right of a person to acquire those shares, are treated as outstanding only for purposes of determining the number and percent of shares of common stock owned by such person or group. There are no persons known to us to be
+the beneficial owners of more than five percent of the shares of common stock outstanding as of March 28, 2023. Unless otherwise noted below, the address of each person listed in the table is in care of Chembio Diagnostics, Inc., 3661 Horseblock
+Rd., Medford, New York 11763. 
+Common Stock 
+Named Executive Officers and Directors 
+Shares 
+% 
+Richard L. Eberly(1) 
+797,557 
+2.2 
+% 
+Javan Esfandiari(2) 
+522,957 
+1.4 
+Lawrence J. Steenvoorden(3) 
+128,571 
+* 
+Katherine L. Davis(4) 
+150,481 
+* 
+John G. Potthoff(5) 
+137,213 
+* 
+David W.K. Acheson(6) 
+38,459 
+* 
+David W. Bespalko(7) 
+43,215 
+* 
+Leslie Teso-Lichtman 
+— 
+* 
+All current executive officers and directors as a group (10 persons)(8) 
+2,128,856 
+5.8 
+* Less than 1%. 
+(1) 
+Includes (a) 368,999 shares issuable under options exercisable by May 27, 2023 and (b) 51,413 shares held by Mr.
+Eberly’s spouse. 
+76 
+Table of Contents 
+(2) 
+Includes 337,849 shares issuable under options exercisable by May 27, 2023. 
+(3) 
+Includes 75,000 shares issuable under options exercisable by May 27, 2023. 
+(4) 
+Includes 36,252 shares issuable under options exercisable by May 27, 2023. 
+(5) 
+Includes 83,127 shares issuable under options exercisable by May 27, 2023. 
+(6) 
+Includes 23,781 shares issuable under options exercisable by May 27, 2023. 
+(7) 
+Includes 31,746 shares issuable under options exercisable, by May 27, 2023. 
+(8) 
+Includes, in addition to the foregoing, 180,215 shares issuable under options exercisable, by May 27, 2023. 
+Equity Compensation Plan Information 
+The following table provides information as of December 31, 2022 with respect to shares of common stock that may be issued under equity plans and standalone option
+grants: 
+Plan Category 
+Number of Securities to be 
+Issued Upon Exercise of 
+Outstanding Options, Warrants 
+and Rights 
+Weighted Average Exercise 
+Price of Outstanding 
+Options, Warrants and 
+Rights 
+Number of Securities 
+Remaining Available for 
+Future Issuance Under Equity 
+Compensation Plans 
+Equity compensation plans approved by stockholders 
+4,706,973(1 
+) 
+$ 
+2.01 
+226,702(2 
+) 
+Equity compensation plans not approved by stockholders 
+538,577(3 
+) 
+$ 
+1.30 
+-- 
+Totals 
+5,245,550 
+$ 
+1.94 
+226,702 
+(1) 
+Consists of 21,061 shares to be issued under the 2014 Stock Incentive Plan and 205,641 shares to be issued under the 2019 Omnibus Incentive Plan. 
+(2) 
+Consists of shares available under the 2019 Omnibus Incentive Plan. 
+(3) 
+Consists of (i) 77,863 shares issued as an inducement grant under our employment agreement with Richard L. Eberly and (ii) 460,714 shares issued as an inducement grant under our
+employment agreement with Lawrence J. Steenvoorden. 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE. 
+Procedures for Approval of Related Person Transactions 
+The board of directors reviews all transactions involving us in which any of our directors, significant stockholders and executive officers and their immediate family members are participants, in order to determine
+whether any such party has a direct or indirect material interest in the transaction. All directors and executive officers must notify us of any proposed transaction involving us in which such person has a direct or indirect material interest.
+The proposed transaction is then reviewed by either the board of directors as a whole or the audit committee, which determines whether to approve the transaction. After such review, the reviewing body approves the transaction only if it
+determines that the transaction is in, or not inconsistent with, the best interests of our company and stockholders. 
+77 
+Table of Contents 
+Conflict of Interest Policy 
+The board of directors has adopted a Conflict of Interest Policy applicable to all directors, officers, and employees of our company and our subsidiaries. 
+The Conflict of Interest Policy requires each director and executive officer, including their immediate family members, to provide written notice of any potential related-party transaction, defined by the policy to
+mirror the definition of Item 404 of Regulation S-K of the SEC (with the exception that the policy includes a monetary threshold of $100,000) to the Chair of the Board of Directors (or to the Chief Executive Officer if such transaction involves
+the Chair of the Board of Directors, or to the Chief Financial Officer if such transaction involves the Chief Executive Officer), including all information that the Chair of the Board of Directors, the Chief Executive Officer or the Chief
+Financial Officer may request. Upon receiving all relevant information, the board of directors may approve the transaction if it determines that the transaction is in the Company’s best interests and fair to us, may require modifications to the
+transaction to make it acceptable for approval, or may reject it. The board of directors may also establish guidelines for ongoing management of a specific related-party transaction. The policy requires that continuing related-party transactions
+are reviewed on at least an annual basis. Additionally, the policy requires that all directors and executive officers complete a director and officer questionnaire in connection with each of our annual proxy statements, in which they are asked to
+disclose family relationships and other related-party transactions. 
+2022 Related Person Transactions 
+Since January 1, 2022, we have not engaged in any related-party transactions in which the amount involved exceeded $100,000 and in which any of our directors or executive officers or any holder of more than 5% of
+our common stock, or any member of the immediate family of any of these persons or entities controlled by any of them, had or will have a direct or indirect material interest, other than the compensation arrangements described in “Director
+Compensation” and “Executive Compensation” of Item 11 above. It is our intention to ensure that any future transactions between us and our officers, directors and significant stockholders and their affiliates are approved by the audit committee
+and a majority of the members of the board of directors, including a majority of the independent and disinterested members of the board of directors, and are on terms no less favorable to us than those that we could obtain from unaffiliated third
+parties. 
+Independence of Directors 
+The board of directors must consist of a majority of independent directors under both the Corporate Governance Guidelines and the applicable requirements of the Nasdaq. 
+Under Nasdaq rules, independent directors must comprise a majority of a listed company’s board of directors. In addition, Nasdaq rules require that, subject to specified exceptions, each member of a listed
+company’s audit, compensation, and nominating and corporate governance committees be independent. Under Nasdaq rules, an individual will qualify as an “independent director” only if, in the opinion of the company’s board of directors, he or she
+does not have a relationship that would interfere with the exercise of independent judgment in carrying out the responsibilities of a director. The Corporate Governance Guidelines effectively mandate compliance with these Nasdaq requirements. 
+• 
+Audit committee members must also satisfy additional independence criteria, including those set forth in Rule 10A-3 under the Securities Exchange Act of 1934 or the Securities Exchange Act. In order to be considered independent for
+purposes of Rule 10A-3, a member of an audit committee of a listed company may not accept, directly or indirectly, any consulting, advisory or other compensatory fee from the listed company or any of its subsidiaries, other than
+compensation for board or committee service, and may not be an affiliated person of the listed company or any of its subsidiaries; and 
+• 
+Compensation committee members must also satisfy additional independence criteria, including those set forth in Rule 10C-1 under the Securities Exchange Act. In determining independence requirements for members of compensation
+committees, Nasdaq and other national securities exchanges and national securities associations are to consider relevant factors that include (a) the source of compensation of a director, including any consulting, advisory or other
+compensatory fee paid by the listed company to the director, and (b) whether the director is affiliated with the listed company, a subsidiary of the listed company or an affiliate of a subsidiary of the listed company. 
+78 
+Table of Contents 
+The board annually reviews the independence of all non-employee directors. The board has determined that each of David Acheson, David Bespalko, Katherine Davis,
+John Potthoff and Leslie Teso-Lichtman qualifies as an independent director in accordance with the rules of Nasdaq and Rules 10C-1 and 10A-3 under the Securities Exchange Act. 
+ITEM 14. 
+PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+The following table sets forth the aggregate fees billed to us by E&Y, our current independent auditor, for professional services rendered for the fiscal year ended December 31, 2022 and 2021 and the aggregate
+fees billed to us by BDO USA, LLP, our former independent auditor, for professional services rendered for the fiscal year ended December 31, 2021. 
+2022 
+2021 
+E&Y 
+BDO 
+Total 
+E&Y 
+BDO 
+Total 
+Audit Fees(1) 
+$ 
+526,000 
+$ 
+- 
+$ 
+526,000 
+$ 
+615,000 
+$ 
+- 
+$ 
+615,000 
+Audit-related Fees(2) 
+$ 
+0 
+$ 
+50,000 
+$ 
+50,000 
+$ 
+0 
+$ 
+50,000 
+$ 
+50,000 
+Tax Fees(3) 
+$ 
+40,945 
+$ 
+- 
+$ 
+40,945 
+$ 
+25,750 
+$ 
+- 
+$ 
+25,750 
+All Other Fees 
+$ 
+- 
+$ 
+- 
+$ 
+- 
+$ 
+- 
+$ 
+- 
+$ 
+- 
+Total Fees 
+$ 
+566,945 
+$ 
+50,000 
+$ 
+616,945 
+$ 
+640,750 
+$ 
+50,000 
+$ 
+690,750 
+(1) 
+Includes services relating to the audit of annual consolidated financial statements, review of quarterly consolidated financial statements, statutory audits, comfort letters, and consents and review of documentation filed with
+SEC-registered and other securities offerings. 
+(2) 
+Includes services related to assistance with general accounting matters, work performed on acquisitions and divestitures, employee benefit plan audits and assistance with statutory audit matters. 
+(3) 
+Includes services for tax compliance, tax advice and tax planning. 
+Audit Committee Pre-Approval Policies and Procedures 
+The audit committee approves in advance all audit and non-audit services performed by the independent registered public accounting firm. There are no other specific policies or procedures relating to the
+pre-approval of services performed by the independent registered public accounting firm. 
+ITEM 15. 
+EXHIBITS, FINANCIAL STATEMENT SCHEDULES 
+(a) 
+See “Item 8. Financial Statements and Supplementary Data – Index to Consolidated Financial Statements” above. 
+(b) 
+Exhibits 
+79 
+Table of Contents 
+Exhibit No. 
+Description 
+3.1 
+Articles of Incorporation, as amended, of Chembio Diagnostics, Inc. (incorporated herein by reference to Exhibit 3.1 to the Quarterly Report on Form 10-Q filed on July 29, 2010) 
+3.2 
+Amended and Restated Bylaws, of Chembio Diagnostics, Inc. (incorporated herein by reference to Exhibit 3.2 to the Current Report on Form 8-K filed on September 17, 2018) 
+3.3 
+Amendment No. 1 to Amended and Restated Bylaws of Chembio Diagnostics, Inc. (incorporated herein by reference to Exhibit 3.1 to the Quarterly Report on Form
+10-Q filed on August 9, 2021) 
+4.1 
+Description of Securities (incorporated herein by reference to Exhibit 4.2 to the Annual Report on Form 10-K filed on March 11, 2021) 
+10.1(a)* 
+2008 Stock Incentive Plan, as amended (incorporated herein by reference to Attachment B to the Proxy Statement on Form DEF 14A filed on 2012) 
+10.1(b)* 
+Form of Option for 2008 Stock Incentive Plan (incorporated herein by reference to Exhibit 4.4 to the Quarterly Report on Form 10-Q filed on May 8, 2014) 
+10.2(a)* 
+2014 Stock Incentive Plan (incorporated herein by reference to Attachment A to the Proxy Statement on Form DEF 14A filed on April 29, 2014) 
+10.2(b)* 
+Form of Option for 2014 Stock Incentive Plan (incorporated herein by reference to Exhibit 4.7 to the Quarterly Report on Form 10-Q filed on August 7, 2014) 
+10.3* 
+2019 Omnibus Incentive Plan (incorporated herein by reference to Exhibit 10.3 to the Annual Report on Form 10-K filed on March 13, 2020) 
+10.4* 
+Restated Annual Incentive Bonus Plan of Chembio Diagnostics, Inc., adopted as of March 15, 2019 (incorporated herein by reference to Exhibit 10.3 to the Annual Report on Form 10-K filed on March 18, 2019) 
+10.5* 
+Outside Director Compensation Policy of Chembio Diagnostics, adopted as of December 15, 2020 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on December 17, 2020) 
+10.6(a)* 
+Employment Agreement, dated as of March 4, 2020 and effective as of March 16, 2020 between Chembio Diagnostics, Inc. and Richard L. Eberly (incorporated herein by reference to Exhibit 10.1 to the Current
+Report on Form 8-K filed on March 20, 2020) 
+10.6(b)* 
+Amendment No. 1 dated February 9, 2022 between Chembio Diagnostics, Inc. and Richard L. Eberly, amending the Employment Agreement dated March 4, 2020 (incorporated herein by reference to Exhibit 10.1 to
+the Current Report on Form 8-K filed on February 14, 2022) 
+10.6(c)* 
+Non-Disclosure, Intellectual Property, Non-Competition and Non-Solicitation Agreement, dated as of March 16, 2020, between Chembio Diagnostics, Inc. and Richard L. Eberly (incorporated herein by reference
+to Exhibit (e)(9) to the Schedule 14D-9 filed on February 14, 2023) 
+10.7(a)* 
+Employment Agreement dated March 5, 2016 between Chembio Diagnostics, Inc. and Javan Esfandiari (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on March 14, 2016) 
+10.7(b)* 
+Amendment No. 1 dated March 20, 2019 between Chembio Diagnostics, Inc. and Javan Esfandiari, amending the Employment Agreement dated March 5, 2016 (incorporated herein by reference to Exhibit 10.1 to the
+Current Report on Form 8-K filed on March 25, 2019) 
+10.7(c)* 
+Amendment No. 2 dated November 30, 2021 between Chembio Diagnostics, Inc. and Javan Esfandiari, amending the Employment Agreement dated March 5, 2016 (incorporated herein by reference to Exhibit 10.1 to
+the Current Report on Form 8-K filed on December 6, 2021) 
+10.8(a)* 
+Employment Agreement, dated as of December 30, 2021 and effective as of January 5, 2022, between Chembio Diagnostics, Inc. and Lawrence J. Steenvoorden (incorporated herein by reference to Exhibit 10.1 to
+the Current Report on Form 8-K filed on January 6, 2022) 
+10.8(b)* 
+Non-Disclosure, Intellectual Property, Non-Competition and Non-Solicitation Agreement, dated as of January 5, 2022, between Chembio Diagnostics, Inc. and Lawrence J. Steenvoorden (incorporated herein by
+reference to Exhibit (e)(14) to the Schedule 14D-9 filed on February 14, 2023) 
+10.9(a) 
+Lease Agreement, dated February 15, 2017, between Horseblock Associates and Chembio Diagnostics, Inc. with respect to 3661 Horseblock Road, Medford, New York, as amended (incorporated herein by reference
+to Exhibit 10.1 to the Current Report on Form 8-K filed on October 22, 2018) 
+10.9(b) 
+Agreement of Sublease dated February 5, 2019 between Chembio Diagnostic Systems Inc., as sublessor, and Reliance Communications of New Jersey, LLC, as sublessee, with respect to 3661 Horseblock Road,
+Medford, New York, as amended (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on February 11, 2019) 
+10.10 
+Lease Agreement, dated February 4, 2013, between Sherwood Corporate Center LLC and Chembio Diagnostics, Inc. with respect to 91-1A Colin Drive, Holbrook, New York, as amended on September 19, 2017
+(incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on October 22, 2018) 
+10.11 
+Lease Agreement dated February 5, 2019 between Myra Properties, LLC, as lessor, and Chembio Diagnostic Systems Inc., as lessee, with respect to 555 Wireless Boulevard, Hauppauge, New York (incorporated
+herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on February 11, 2019) 
+80 
+Table of Contents 
+10.12† 
+Credit Agreement and Guaranty dated as of September 3, 2019, among Chembio Diagnostics, Inc., as the Borrower, the Guarantors from time to time party thereto, and Perceptive Credit Holdings II, LP and its
+successors and assigns party thereto, as Administrative Agent and as a Lender (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on September 5, 2019) 
+10.13 
+At the Market Offering Agreement, dated July 19, 2021, between Chembio Diagnostics, Inc. and Craig-Hallum Capital Group LLC (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form
+8-K filed on July 19, 2021) 
+10.14* 
+Retention Agreement with Paul Angelico, dated as of February 9, 2022 (incorporated herein by reference to Exhibit (e)(15) to the Schedule 14D-9 filed on February 14, 2023) 
+10.15(a)* 
+Retention Agreement with Charles Caso, dated as of February 9, 2022 (incorporated herein by reference to Exhibit (e)(16) to the Schedule 14D-9 filed on February 14, 2023) 
+10.15(b)* 
+Non-Disclosure, Intellectual Property, Non-Competition and Non-Solicitation Agreement, dated as of February 9, 2022, between Chembio Diagnostics, Inc. and Charles Caso (incorporated herein by reference to
+Exhibit (e)(17) to the Schedule 14D-9 filed on February 14, 2023) 
+14.1 
+Ethics Policy (incorporated herein by reference to Exhibit 14.1 to the Annual Report on Form 10-KSB filed on March 30, 2006) 
+21.1 
+List of Subsidiaries of Chembio Diagnostics, Inc. (incorporated herein by reference to Exhibit 21.1 to the Annual Report on Form 10-K filed on March 3, 2022) 
+23.1 
+Consent of EY, Independent Registered Public Accounting Firm 
+31.1 
+Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+31.2 
+Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+32.1** 
+Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 
+101.INS 
+XBRL Instance Document 
+101.SCH 
+XBRL Taxonomy Extension Schema Document 
+101.CAL 
+XBRL Taxonomy Extension Calculation Linkbase Document 
+101.DEF 
+XBRL Taxonomy Definition Linkbase Document 
+101.LAB 
+XBRL Taxonomy Label Linkbase Document 
+101.PRE 
+XBRL Taxonomy Presentation Linkbase Document 
+104 
+Cover Page Interactive Data File (embedded within the Inline XBRL document) 
+* 
+Indicates management contract or compensatory plan. 
+† 
+Certain exhibits and schedules have been omitted pursuant to Item 601(a)(5) of Regulation S-K. We hereby undertake to furnish copies of the omitted exhibits and schedules upon request by the Securities and Exchange Commission, provided
+that we may request confidential treatment pursuant to Rule 24b-2 of the Securities Exchange Act of 1934 for the exhibits and schedules so furnished. 
+** 
+The certifications attached as Exhibit 32.1 accompany the Annual Report on Form 10-K pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the
+registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended. 
+81 
+Table of Contents 
+ITEM 16. 
+FORM 10-K SUMMARY 
+None. 
+82 
+Table of Contents 
+SIGNATURES 
+In accordance with Section 13 or 15(d) of the Exchange Act, the registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+CHEMBIO DIAGNOSTICS, INC. 
+March 29, 2023 
+By 
+/s/ Richard L. Eberly 
+Richard L. Eberly 
+Chief Executive Officer and President 
+In accordance with the requirements of the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+Signatures 
+Title 
+Date 
+/s/ Richard L. Eberly 
+Chief Executive Officer and President 
+March 29, 2023 
+Richard L. Eberly 
+(Principal Executive Officer) 
+/s/ Lawrence J. Steenvoorden 
+Chief Financial Officer 
+March 29, 2023 
+Lawrence J. Steenvoorden 
+(Principal Financial & Accounting Officer) 
+/s/ Katherine L. Davis 
+Chair of the Board 
+March 29, 2023 
+Katherine L. Davis 
+/s/ David W. K. Acheson 
+Director 
+March 29, 2023 
+David W. K. Acheson 
+/s/ David W. Bespalko 
+Director 
+March 29, 2023 
+David W. Bespalko 
+/s/ John G. Potthoff 
+Director 
+March 29, 2023 
+John G. Potthoff 
+/s/ Leslie Teso-Lichtman 
+Director 
+March 29, 2023 
+Leslie Teso-Lichtman 
+83 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+Index to Consolidated Financial Statements 
+—INDEX— 
+Pages 
+Reports of Independent Registered Public Accounting Firm (PCAOB ID 42 ) 
+F-1 
+Consolidated Financial Statements: 
+Balance Sheets as of December 31, 2022 and 2021 
+F-2 
+Statements of Operations for the years ended December 31, 2022 and 2021 
+F-3 
+Statements of Comprehensive Loss for the years ended December 31, 2022 and 2021 
+F-4 
+Statements of Changes in Stockholders’ Equity for the years ended December 31, 2022 and 2021 
+F-5 
+Statements of Cash Flows for the years ended December 31, 2022 and 2021 
+F-6 
+Notes to Consolidated Financial Statements 
+F-7 - F-34 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+To the Stockholders and the Board of Directors of Chembio Diagnostics, Inc. 
+Opinion on the Financial Statements 
+We have audited the accompanying consolidated balance sheet of Chembio Diagnostics, Inc. (and subsidiaries) (the Company) as of December 31, 2022 and 2021, the
+related consolidated statements of operations, comprehensive loss , stockholders' equity and cash flows for the years ended December 31, 2022 and 2021, and
+the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2022
+and 2021, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2022, in conformity with U.S. generally accepted accounting principles. 
+The Company’s Ability to Continue as a Going Concern 
+The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the
+consolidated financial statements, the Company has suffered recurring losses from operations and has stated that substantial doubt exists about the Company’s ability to continue as a going concern. Management's evaluation of the events and
+conditions and management’s plans regarding these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty. 
+Basis for Opinion 
+These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements
+based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal
+securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about
+whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our
+audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we
+express no such opinion. 
+Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing
+procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and
+significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. 
+Critical Audit Matters 
+The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be
+communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of the critical
+audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing a separate opinion on the critical audit matters or on
+the accounts or disclosures to which they relate. 
+Insurance Receivable 
+Description of the Matter 
+As discussed in the consolidated financial statements, the Company recorded a receivable for expected recoveries from insurance carriers
+related to legal costs and settlements. As of December 31, 2022, the Company recorded an estimated insurance receivable of $12.2 million. 
+Auditing management’s accounting for the insurance receivable was especially challenging due to the complexity of the underlying claims and
+determining the amount recoverable. Evaluating the likelihood and amount of recoveries from insurance carriers was highly subjective and required significant judgment. Specifically, there was significant judgment around management’s
+estimation of how much of the legal costs incurred and settlements to date are expected to be recovered from the insurance carriers. 
+How We Addressed the Matter in Our Audit 
+To test the expected recoveries from insurance carriers, we performed audit procedures that included, among others, reading and understanding
+the Company’s insurance policies, testing the legal costs and settlements submitted under the Company’s insurance policies on a case-by-case basis, and, when applicable, vouching cash receipts from the insurance carriers for previously
+submitted claims. 
+Goodwill and Long-Lived Assets Impairment 
+Description of the Matter 
+As discussed in the consolidated financial statements, the Company identified indicators of impairment, which resulted in the Company
+assessing the value of goodwill and its long-lived asset group for recoverability. The Company's analysis resulted in goodwill impairment charges of $3.0 million. No impairment charges were recorded relating to the Company’s long-lived
+assets. 
+Auditing the Company’s assessment and measurement of impairment involved a high degree of subjectivity as estimates underlying the
+determination of fair values of the consolidated business and the Company’s long-lived assets were based on assumptions about future economic conditions. Significant inputs used in the Company's fair value estimates included the market
+capitalization of the business as of its testing dates and the implied control premium. 
+How We Addressed the Matter in Our Audit 
+To test the future economic conditions, as part of our audit, we assessed the methodologies and significant inputs used in the impairment
+tests, among other procedures. We tested the significant inputs discussed above, as well as the completeness and accuracy of the underlying data used in the valuations. We tested the reconciliation of the fair value of the reporting unit
+developed by management to the market capitalization of the Company as of the valuation dates and evaluated the implied control premium for reasonableness. 
+/s/ Ernst & Young LLP 
+We have served as the Company’s auditor since 2020. 
+Jericho, New York 
+March 29, 2023 
+F-1 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED BALANCE SHEETS 
+AS OF 
+December 31, 
+2022 
+2021 
+- ASSETS - 
+CURRENT ASSETS: 
+Cash and cash equivalents 
+$ 
+18,178,985 
+$ 
+28,772,892 
+Accounts receivable, net of allowance for doubtful accounts of $ 346,896 and $ 243,042 at December 31, 2022 and 2021,
+respectively 
+6,536,415 
+11,441,107 
+Inventories, net 
+7,715,413 
+12,920,451 
+Prepaid expenses and other current assets 
+3,834,560 
+1,710,194 
+Insurance receivable, current 
+12,186,322 
+- 
+TOTAL CURRENT ASSETS 
+48,451,695 
+54,844,644 
+FIXED ASSETS: 
+Property, plant and equipment, net 
+8,154,651 
+8,556,773 
+Finance lease right-of-use assets, net 
+136,976 
+191,870 
+OTHER ASSETS: 
+Operating right-of-use assets, net 
+5,433,211 
+5,891,906 
+Goodwill 
+- 
+3,022,787 
+Deposits and other assets 
+434,872 
+358,010 
+Insurance receivable, long-term 
+- 
+386,205 
+TOTAL ASSETS 
+$ 
+62,611,405 
+$ 
+73,252,195 
+- LIABILITIES AND STOCKHOLDERS’ EQUITY - 
+CURRENT LIABILITIES: 
+Accounts payable and accrued liabilities 
+$ 
+19,730,697 
+$ 
+13,127,993 
+Current
+portion of long term debt 
+18,577,693 
+1,200,000 
+Operating lease liabilities 
+914,857 
+886,294 
+Finance lease liabilities 
+76,869 
+68,176 
+TOTAL CURRENT LIABILITIES 
+39,300,116 
+15,282,463 
+OTHER LIABILITIES: 
+Long-term operating lease liabilities 
+5,426,030 
+5,976,151 
+Long-term finance lease liabilities 
+76,705 
+139,678 
+Long-term debt, less current portion, net 
+10,197 
+17,589,003 
+TOTAL LIABILITIES 
+44,813,048 
+38,987,295 
+COMMITMENTS AND CONTINGENCIES (Note 12) 
+STOCKHOLDERS’ EQUITY: 
+Preferred stock – 10,000,000 
+shares authorized, none outstanding 
+- 
+- 
+Common stock – $ 0.01 
+par value; 100,000,000 shares authorized, 36,765,785 and 30,104,986 shares issued and outstanding at December 31, 2022 and 2021,
+respectively 
+367,658 
+301,050 
+Additional paid-in capital 
+172,275,057 
+165,772,636 
+Accumulated deficit 
+( 154,300,517 
+) 
+( 131,009,860 
+) 
+Treasury stock – 48,057 
+and 48,057 shares at cost, at December 31, 2022 and 2021, respectively 
+( 206,554 
+) 
+( 206,554 
+) 
+Accumulated other comprehensive loss 
+( 337,287 
+) 
+( 592,372 
+) 
+TOTAL STOCKHOLDERS’ EQUITY 
+17,798,357 
+34,264,900 
+TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY 
+$ 
+62,611,405 
+$ 
+73,252,195 
+See accompanying notes to consolidated financial statements 
+F-2 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF OPERATIONS 
+FOR THE YEARS ENDED 
+December 31, 
+2022 
+2021 
+REVENUES: 
+Net product sales 
+$ 
+47,091,673 
+$ 
+34,737,444 
+R&D revenue 
+112,986 
+1,159,381 
+Government grant income 
+1,182,023 
+10,891,726 
+License and royalty revenue 
+1,135,241 
+1,029,901 
+TOTAL REVENUES 
+49,521,923 
+47,818,452 
+COSTS AND EXPENSES: 
+Cost of product sales 
+38,578,098 
+34,495,802 
+Research and development expenses 
+7,067,852 
+12,487,424 
+Selling, general and administrative expenses 
+24,277,834 
+24,840,611 
+I mpairment, restructuring, severance and related costs 
+3,236,186 
+7,047,779 
+TOTAL COSTS AND EXPENSES 
+73,159,970 
+78,871,616 
+LOSS FROM OPERATIONS 
+( 23,638,047 
+) 
+( 31,053,164 
+) 
+OTHER INCOME (EXPENSE): 
+Interest (expense)/ income, net 
+( 2,812,772 
+) 
+( 2,912,415 
+) 
+Other income 
+3,194,567 
+- 
+LOSS BEFORE INCOME TAXES BENEFIT 
+( 23,256,252 
+) 
+( 33,965,579 
+) 
+Income tax (expense)/benefit 
+( 34,405 
+) 
+62,050 
+NET LOSS 
+$ 
+( 23,290,657 
+) 
+$ 
+( 33,903,529 
+) 
+Basic and diluted loss per share 
+$ 
+( 0.72 
+) 
+$ 
+( 1.40 
+) 
+Weighted average number of shares outstanding, basic and diluted 
+32,269,147 
+24,299,465 
+See accompanying notes to consolidated financial statements 
+F-3 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS 
+FOR THE YEARS ENDED 
+December 31, 
+2022 
+2021 
+Net loss 
+$ 
+( 23,290,657 
+) 
+$ 
+( 33,903,529 
+) 
+Other comprehensive loss: 
+Foreign currency translation adjustments 
+255,085 
+( 501,456 
+) 
+COMPREHENSIVE LOSS 
+$ 
+( 23,035,572 
+) 
+$ 
+( 34,404,985 
+) 
+See accompanying notes to consolidated financial statements 
+F-4 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY 
+FOR THE YEARS ENDED DECEMBER 31, 2022,
+AND 2021 
+Common Stock 
+Additional 
+Paid-in-Capital 
+Treasury Stock 
+Accumulated 
+Deficit 
+AOCL 
+Total 
+Shares 
+Amount 
+Amount 
+Shares 
+Amount 
+Amount 
+Amount 
+Amount 
+Balance at December 31, 2020 
+20,223,498 
+$ 
+202,235 
+$ 
+124,961,514 
+( 41,141 
+) 
+$ 
+( 190,093 
+) 
+$ 
+( 97,106,331 
+) 
+$ 
+( 90,916 
+) 
+$ 
+27,776,409 
+Common Stock: 
+Issuance of stock, net 
+9,709,328 
+97,093 
+38,714,865 
+- 
+- 
+- 
+- 
+38,811,958 
+Restricted stock issued 
+135,908 
+1,359 
+105,582 
+- 
+- 
+- 
+- 
+106,941 
+Restricted stock compensation, net 
+- 
+- 
+1,160,953 
+- 
+- 
+- 
+- 
+1,160,953 
+Shares tendered for withholding taxes 
+- 
+- 
+( 145,225 
+) 
+- 
+- 
+- 
+- 
+( 145,225 
+) 
+Options: 
+Exercised 
+36,252 
+363 
+85,192 
+- 
+- 
+- 
+- 
+85,555 
+Stock option compensation 
+- 
+- 
+873,294 
+- 
+- 
+- 
+- 
+873,294 
+Treasury Stock 
+- 
+- 
+16,461 
+( 6,916 
+) 
+( 16,461 
+) 
+- 
+- 
+- 
+Warrant exercised 
+- 
+- 
+- 
+- 
+- 
+- 
+- 
+- 
+Comprehensive loss 
+- 
+- 
+- 
+- 
+- 
+- 
+( 501,456 
+) 
+( 501,456 
+) 
+Net loss 
+- 
+- 
+- 
+- 
+- 
+( 33,903,529 
+) 
+- 
+( 33,903,529 
+) 
+Balance at December 31, 2021 
+30,104,986 
+$ 
+301,050 
+$ 
+165,772,636 
+( 48,057 
+) 
+$ 
+( 206,554 
+) 
+$ 
+( 131,009,860 
+) 
+$ 
+( 592,372 
+) 
+$ 
+34,264,900 
+Common Stock: 
+Issuance of stock, net 
+6,466,191 
+64,662 
+4,246,824 
+- 
+- 
+- 
+- 
+4,311,486 
+Restricted stock issued 
+194,608 
+1,946 
+264,141 
+- 
+- 
+- 
+- 
+266,087 
+Restricted stock compensation, net 
+- 
+- 
+967,262 
+- 
+- 
+- 
+- 
+967,262 
+Shares tendered for withholding taxes 
+- 
+- 
+( 41,537 
+) 
+- 
+- 
+- 
+- 
+( 41,537 
+) 
+Options: 
+Exercised 
+- 
+- 
+- 
+- 
+- 
+- 
+- 
+- 
+Stock option compensation 
+- 
+- 
+1,065,731 
+- 
+- 
+- 
+- 
+1,065,731 
+Treasury stock 
+- 
+- 
+- 
+- 
+- 
+- 
+- 
+- 
+Comprehensive loss 
+- 
+- 
+- 
+- 
+- 
+- 
+255,085 
+255,085 
+Net loss 
+- 
+- 
+- 
+- 
+- 
+( 23,290,657 
+) 
+- 
+( 23,290,657 
+) 
+Balance at December 31, 2022 
+36,765,785 
+$ 
+367,658 
+$ 
+172,275,057 
+( 48,057 
+) 
+$ 
+( 206,554 
+) 
+$ 
+( 154,300,517 
+) 
+$ 
+( 337,287 
+) 
+$ 
+17,798,357 
+See accompanying notes to consolidated financial statements 
+F-5 
+Table of Contents 
+CHEMBIO DIAGNOSTICS, INC. AND SUBSIDIARIES 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+FOR THE YEARS ENDED 
+December 31, 
+2022 
+2021 
+CASH FLOWS FROM OPERATING ACTIVITIES: 
+Cash received from customers and grants 
+$ 
+53,886,080 
+$ 
+37,232,082 
+Cash received from insurance receivable 
+644,389 
+861,902 
+Cash paid to suppliers and employees 
+( 63,624,525 
+) 
+( 65,273,967 
+) 
+Cash paid for operating leases 
+( 1,453,778 
+) 
+( 1,404,532 
+) 
+Cash paid for finance leases 
+( 17,015 
+) 
+( 20,077 
+) 
+Interest and taxes, net 
+( 2,129,104 
+) 
+( 2,281,124 
+) 
+Net cash used in operating activities 
+( 12,693,953 
+) 
+( 30,885,716 
+) 
+CASH FLOWS FROM INVESTING ACTIVITIES: 
+Acquisition of and deposits on fixed assets 
+( 1,451,233 
+) 
+( 1,824,285 
+) 
+Patent application costs 
+- 
+( 33,398 
+) 
+Net cash used in investing activities 
+( 1,451,233 
+) 
+( 1,857,683 
+) 
+CASH FLOWS FROM FINANCING ACTIVITIES: 
+Proceeds from sale of common stock, net 
+4,311,486 
+38,811,958 
+Proceeds from option exercises 
+- 
+85,555 
+Interest received on Employee Retention Credit 
+67,818 
+- 
+Principal payments for finance leases 
+( 70,514 
+) 
+( 61,867 
+) 
+Payments on note payable 
+( 900,000 
+) 
+- 
+Payments of tax withholdings on stock award 
+( 41,537 
+) 
+( 145,225 
+) 
+Net cash provided by financing activities 
+3,367,253 
+38,690,421 
+Effect of exchange rate changes on cash 
+184,026 
+( 240,431 
+) 
+INCREASE IN CASH AND CASH EQUIVALENTS 
+( 10,593,907 
+) 
+5,706,591 
+Cash and cash equivalents - beginning of the period 
+28,772,892 
+23,066,301 
+Cash and cash equivalents - end of the period 
+$ 
+18,178,985 
+$ 
+28,772,892 
+RECONCILIATION OF NET LOSS TO NET CASH USED IN OPERATING ACTIVITIES: 
+Net Loss 
+$ 
+( 23,290,657 
+) 
+$ 
+( 33,903,529 
+) 
+Adjustments: 
+Depreciation and amortization 
+2,552,969 
+2,930,976 
+Share based compensation 
+2,299,081 
+2,431,982 
+Benefit from deferred tax liability 
+— 
+( 69,941 
+) 
+Provision for (recovery of) doubtful accounts 
+103,854 
+( 53,751 
+) 
+Non-cash inventory changes 
+569,430 
+4,054,701 
+Impairment charges 
+3,033,565 
+5,880,741 
+Changes in assets and liabilities: 
+Accounts receivable 
+4,800,838 
+( 8,009,969 
+) 
+Inventories 
+4,635,608 
+( 4,458,750 
+) 
+Prepaid expenses and other current assets 
+( 2,124,366 
+) 
+( 545,305 
+) 
+Insurance receivable, current 
+( 12,186,322 
+) 
+— 
+Deposits and other assets 
+( 76,862 
+) 
+( 234,874 
+) 
+Insurance receivable, long-term 
+386,205 
+( 386,205 
+) 
+Accounts payable and accrued liabilities 
+6,602,704 
+3,085,205 
+Deferred revenue 
+— 
+( 1,606,997 
+) 
+Net cash used in operating activities 
+$ 
+( 12,693,953 
+) 
+$ 
+( 30,885,716 
+) 
+See accompanying notes to consolidated financial statements 
+F-6 
+Table of Contents 
+NOTE 1 — DESCRIPTION OF BUSINESS: 
+Chembio Diagnostics, Inc. (“Chembio”) and its subsidiaries (collectively with Chembio, the “Company”) develop and commercialize point-of-care
+tests used to detect and diagnose infectious diseases, including sexually transmitted disease, insect vector and tropical disease, COVID-19 and other viral and bacterial infections, enabling expedited treatment. 
+The Company’s product portfolio is based upon our proprietary DPP technology, a diagnostic platform that provides
+high-quality, cost-effective results in 15 to 20 minutes using fingertip blood, nasal swabs and other sample types. The DPP technology platform addresses the rapid diagnostic test market, which includes infectious diseases such as sexually
+transmitted infections and HIV, and Women ’ s Health. Compared with traditional lateral flow technology, the DPP technology platform can provide: 
+• 
+Enhanced
+sensitivity and specificity: This is achieved via the Company’s proprietary approach to separating the sample path from the buffer path, together with patent and other proprietary strategies, which differ significantly from traditional
+lateral flow test. 
+• 
+Advanced
+multiplexing capabilities: Through advanced multiplexing, the DPP platform can detect and differentiate up to eight distinct test results from a single patient sample, which can deliver greater clinical value than other rapid tests
+currently on the market. 
+• 
+Objective
+results: For some diagnostic applications, the Company’s easy-to-use, highly portable, battery-operated DPP Micro Reader optical analyzers can report accurate results in approximately 15 seconds, making it well-suited for decentralized
+testing where real-time results enable patients to be clinically assessed while they are still on site. Objective results produced by the DPP Micro Reader can reduce the possibility of the types of human error that can be experienced in
+the visual interpretations required by many rapid tests. 
+The Company targets the market for rapid diagnostic test solutions for infectious diseases, which is driven by the high prevalence of infectious
+diseases globally, an increase in the geriatric population, growing demand for rapid test results, and advancements in multiplexing. The Company has a broad portfolio of infectious disease products, which prior to 2020 were focused principally on
+sexually transmitted disease and fever and tropical disease. In February 2020 the Company began the process to leverage the DPP technology platform to address the acute and escalating need for diagnostic testing. The Company is continuing to pursue
+or has pursued: 
+• 
+a 510(k)
+clearance from the U. S. Food and Drug Administration (the “FDA”) for the DPP SARS-CoV-2 Antigen test system; 
+• 
+an Emergency
+Use Authorization from the FDA for the DPP Respiratory Antigen Panel; and 
+• 
+a Clinical Laboratory Improvement Amendment (“CLIA”), waiver from the FDA for the DPP HIV-Syphilis test system, which was approved in February 2023. 
+NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES: 
+(a) Basis
+of Presentation: 
+The accompanying consolidated financial statements include the accounts of Chembio and its subsidiaries. All significant intercompany accounts and transactions have been
+eliminated in consolidation. Certain reclassifications have been made to the consolidated balance sheet of the prior year to conform to the current year presentation. 
+Going Concern Considerations 
+The Company continued
+to experience market, clinical trial and regulatory complications in seeking to develop and commercialize a portfolio of COVID-19 test systems during the continuing, but evolving, uncertainty resulting from COVID‑19. For the year ended December 31,
+2022, the Company also continued to incur significant operating losses and significant expenses in connection with pending legal matters (see Note 12 – Commitments, Contingencies, and Concentrations: Litigation). 
+F-7 
+Table of Contents 
+The Company performed
+an assessment to determine whether there were conditions or events that, considered in the aggregate, raised substantial doubt about the Company’s ability to continue as a going concern within one year after the filing date of this report, when the
+accompanying financial statements are being issued. Initially, this assessment did not consider the potential mitigating effect of management’s plans that had not been fully implemented. Because, as described below, substantial doubt was determined
+to exist as the result of this initial assessment, management then assessed the mitigating effect of its plans to determine if it is probable that the plans (1) would be effectively implemented within one year after the filing date of this report,
+when the accompanying financial statements are being issued and (2) when implemented, would mitigate the relevant conditions or events that raise substantial doubt about the Company’s ability to continue as a going concern. 
+The Company achieved
+revenue growth in recent years while profitability has not been at expected levels. It has taken steps including investments in automation to mitigate headwinds such as labor availability, volatile capacity planning and implementation of
+operational efficiency targets to proactively monitor production with the overarching goal of profitable growth. The Company undertook measures to increase its total revenues and improve its liquidity position by continuing to develop the Global
+Competitiveness Program. The main pillars of the Global Competitiveness Program include the following: 
+• 
+Focus on higher margin business in
+growth markets 
+• 
+Lower manufacturing costs 
+• 
+Reduce infrastructure costs 
+• 
+Strategic review of non-core
+businesses and assets 
+The Company’s execution of its plan continues to depend on factors and uncertainties that are beyond the Company’s control, or that may not be addressable on terms acceptable to the Company or at all. The Company considered in particular how the
+ongoing healthcare and economic impacts of COVID-19 on the global customer base for the Company’s non‑COVID-19 products continue to negatively affect the timing and rate of recovery of the Company’s revenues from those products. 
+The Company further considered how these factors and uncertainties could impact its ability over the next year to meet the obligations specified in the Credit Agreement with the Lender. Those
+obligations include covenants requiring: i) minimum cash balance of $ 3.0 million and ii) minimum total revenue amounts for the twelve
+months preceding each quarter end. The minimum total revenue requirements are $ 48.8 million for the twelve months ending March 31, 2023
+and $ 50.1 million for the twelve months ending June 30, 2023. We do not believe that we will comply with the minimum total revenue
+covenant for the twelve months ended March 31, 2023. Upon an event of default under the Credit Agreement, the Lender could elect to declare all amounts outstanding thereunder, together with accrued interest, to be immediately due and payable.
+Furthermore, all remaining principal and interest is due on or before September 3, 2023. There can be no assurance that the Company would have sufficient liquidity to fund payment of the amounts that would be due under the Credit Agreement or
+that, if such liquidity were not available, the Company would be successful in raising additional capital on acceptable terms, or at all, or in completing any other endeavor to continue to be financially viable and continue as a going concern.
+The Company’s inability to raise additional capital on acceptable terms in the near future, whether for purposes of funding payments required under the Credit Agreement or providing additional liquidity needed for its operations, could have a
+material adverse effect on its business, prospects, results of operations, liquidity and financial condition and would likely result in the Company being forced to seek protection under a bankruptcy proceeding. 
+F-8 
+Table of Contents 
+Accordingly, management
+determined the Company could not be certain that the Company’s plans and initiatives would be effectively implemented within one year after the filing date of this report, when the accompanying financial statements are being issued. Without giving
+effect to increasing product revenue in the near future, the proposed merger with Biosynex or executing other mitigating plans, many of which are beyond the Company’s control, it is unlikely that the Company will be able to generate sufficient cash
+flows to meet its required financial obligations, including its debt service and other obligations due to third parties. The existence of these conditions raises substantial doubt about the Company’s ability to continue as a going concern for the
+twelve-month period following the date on which the accompanying consolidated financial statements are being issued. 
+The accompanying
+consolidated financial statements have been prepared assuming the Company will continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business for
+the twelve-month period following the date the accompanying consolidated financial statements are issued. As such, the accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification
+of assets and their carrying amounts, or the amount and classification of liabilities that may result should the Company be unable to continue as a going concern. 
+(b) Use
+of Estimates: 
+The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make
+assumptions and estimates that affect the amounts reported in the consolidated financial statements and accompanying notes. Judgments and estimates of uncertainties are required in applying the Company’s accounting policies in certain areas.
+Generally, matters subject to estimation and judgment include accounts receivable realization, inventory obsolescence, asset impairments, recognition of revenue, useful lives of fixed assets, stock-based compensation, insurance recoveries, and
+deferred tax asset valuation allowances. Due to the inherent uncertainty involved in making estimates, actual results reported in future periods may be based upon amounts that differ from those estimates. 
+(c) Fair
+Value of Financial Instruments: 
+The carrying value for cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate fair value due to the immediate or short-term
+maturity of these financial instruments. Included in cash and cash equivalents is $ 18.2 million and $ 28.8 million as of December 31, 2022 and 2021, respectively, of money market funds that are Level 1 fair value measurements under the hierarchy. The fair
+value of the Company’s total debt of $ 19.1 million (carrying value of $ 18.6 million) and $ 20 million (carrying value of $ 18.8 million) as of December 31, 2022 and 2021, respectively, is a Level 2 fair value measurement under the hierarchy, and the carrying value approximates
+fair value. 
+Fair value measurements of all financial assets and liabilities that are being measured and reported on a fair value basis are required to be classified and disclosed in
+one of the following three categories: 
+Level 1: 
+Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities; 
+Level 2: 
+Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or
+liability; and 
+Level 3: 
+Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no
+market activity). 
+F-9 
+Table of Contents 
+(d) Cash
+and Cash Equivalents: 
+Cash and cash equivalents are defined as short-term, highly liquid investments with original maturities of three months or less at date of purchase. 
+(e) Concentrations
+of Credit Risk: 
+Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of cash and trade receivables. The Company places its
+cash with well-known financial institutions and, at times, may maintain balances in excess of the FDIC insurance limit. 
+(f) Inventory: 
+Inventories are stated at the lower of cost or net realizable value with cost being determined using a standard cost method, which approximates average cost. Average
+cost consists primarily of material, labor and manufacturing overhead expenses (including fixed production-overhead costs). The Company analyzes its inventory levels quarterly and writes down, in the applicable period, inventory that has become
+obsolete, inventory that has a cost basis in excess of its expected net realizable value and inventory in excess of expected customer demand. 
+(g) Fixed
+Assets: 
+Fixed assets are stated at cost, less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the
+respective assets, which range from three to seven years . Leasehold improvements are amortized over the useful life of the asset or the lease term, whichever is shorter. Deposits paid for fixed assets are capitalized and not depreciated until the related asset is placed in
+service. 
+( h ) Valuation of Long-Lived Assets and Intangible Assets: 
+Long-lived assets to be held and used are analyzed for impairment whenever events or changes in circumstances indicate that the related carrying amounts may not be
+recoverable. The Company evaluates at each balance sheet date whether events and circumstances have occurred that indicate possible impairment. If there are indications of impairment, the Company uses future undiscounted cash flows of the related
+asset or asset grouping over the remaining life in measuring whether the assets are recoverable. In the event such cash flows are not expected to be sufficient to recover the recorded asset values, the assets are written down to their estimated fair
+value. A $ 0 and $ 3.3 million
+impairment of long-lived intangible assets was recorded for the years ended December 31, 2022 and 2021 (see Note 14 - Asset Impairment, Restructuring, Severance and related costs ). 
+( i ) Revenue Recognition: 
+The Company recognizes revenue when the customer obtains control of promised goods or services, in an amount that reflects the consideration the Company expects to
+receive in exchange for those goods or services. The Company recognizes revenue following the five-step model prescribed under Accounting Standards Update (“ASU”) 2014-09: (i) identify contract(s) with a customer; (ii) identify the performance
+obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and (v) recognize revenue when (or as) the Company satisfies the performance obligation. 
+Product Revenue 
+Revenue from product sales are recognized and commissions are accrued when the customer obtains control of the Company’s product, which occurs at a point in time,
+typically upon tendering the product to the customer. The Company expenses incremental costs of obtaining a contract as and when incurred because the expected amortization period of the asset that it would have recognized is one year or less or the amount is immaterial. Freight and distribution activities on products are performed when the customer obtains control of the
+goods. The Company has made an accounting policy election to account for shipping and handling activities that occur either when or after goods are tendered to the customer as a fulfillment activity, and therefore recognizes freight and distribution
+expenses in cost of product sales. The Company excludes certain taxes from the transaction price (e.g., sales, value added and some excise taxes). 
+F-10 
+Table of Contents 
+The Company’s contracts with customers often include promises to transfer products or services to a customer. Determining whether products and services are considered
+distinct performance obligations that should be accounted for separately versus together may require judgment. Typical products sold are diagnostic tests and typical services performed are R&D studies. Revenues from product sales are recognized
+at a point-in-time and revenues from R&D studies are recognized ratably over the period of the agreement, unless the related performance obligations indicate otherwise. 
+Judgment is required to determine the stand-alone selling price (“SSP”) for each distinct performance obligation. SSP is directly observable and the Company can use a
+range of amounts to estimate SSP, as it sells products and services separately, and can determine whether there is a discount to be allocated based on the relative SSP of the various products and services, for the various geographies. 
+From time to time the Company engages in bill-and-hold arrangements, whereby the Company manufactures and sells its product and at the customer’s request stores the product at the Company’s warehouse.
+Even though the product remains in the Company’s possession, a sale is recognized at the point in time when the customer obtains control of the product. Control is transferred to the customer in bill and hold transactions when: customer
+acceptance specifications have been met, legal title has transferred, the customer has a present obligation to pay for the product and the risk and rewards of ownership have transferred to the customer. Additionally, all the following bill and
+hold criteria would have to be met in order for control to be transferred to the customer: 
+(a) 
+The reason for the bill-and-hold arrangement must be substantive (for example, the customer has requested the arrangement). 
+(b) 
+The product must be identified separately as belonging to the customer. 
+(c) 
+The product currently must be ready for physical transfer to the customer. 
+(d) 
+The entity cannot have the ability to use the product or to direct it to another customer. 
+The Company’s payment terms vary by the type and location of the Company’s customer and products or services offered. Payment terms differ by jurisdiction and customer,
+but payment is generally required in a term ranging from 30 to 60 days from date of shipment or satisfaction of the performance obligation. 
+Reserves for Discounts and Allowances 
+Revenue from product sales are recorded net of reserves established for applicable discounts and allowances that are offered within contracts with the Company’s
+customers. 
+Product revenue reserves, which are classified as a reduction in product revenue, are generally related to discounts and returns. Estimates of variable consideration and
+the determination of whether to include estimated amounts in the transaction price are based on all information (historical, current, and forecasted) that is reasonably available to the Company, taking into consideration the type of customer, the
+type of transaction, market events and trends, and the specific facts and circumstances of each arrangement. The transaction price, which includes variable consideration reflecting the impact of discounts, allowances and returns may be subject to
+constraint and is included in the net sales price only to the extent that it is probable that a significant reversal of the amount of the revenue recognized will not occur in a future period. Actual amounts may ultimately differ from the Company’s
+estimates. If actual results vary, the Company adjusts these estimates, which could have an effect on revenue and earnings in the period of adjustment. 
+License and Royalty Revenues 
+The Company receives royalty revenue on sales by its licensee of products covered under patents that the Company owns. The Company does not have future performance
+obligations under this license arrangement. The Company records revenue based on estimates of the sales that occurred during the relevant period as a component of license and royalty revenue. The relevant period estimates of sales are based on
+interim data provided by the licensee and analysis of historical royalties that have been paid to the Company, adjusted for any changes in facts and circumstances, as appropriate. Differences between actual and estimated royalty revenue are adjusted
+for in the period in which they become known, typically the following quarter. Historically, adjustments have not been material when compared to actual amounts paid by licensees. 
+F-11 
+Table of Contents 
+R&D Revenue 
+All contracts with customers are evaluated under the five-step model described above. Such contracts are further described in Note 6 - Revenue. Grants are invoiced and
+revenue is recognized ratably as that is the depiction of the timing of the transfer of services. The R&D study, which encompasses various phases of product development processes: design feasibility & planning, product development and design
+optimization, design verification, design validation and process validation, and pivotal studies, is also recognized ratably. 
+For certain contracts that represent non-governmental grants where the funder does not meet the definition of a customer, the Company recognizes revenue when earned in
+accordance with Accounting Standards Codification (“ASC”) Topic 958. 
+Government Grant Income 
+Chembio receives government grants in support of R&D activities that are not associated with a customer-vendor relationship and therefore falls outside the scope of
+ASC 606. Because there is no authoritative guidance under U.S. GAAP on accounting for government grants received, Chembio applies Topic 958 - Not-for-profit entities guidance by analogy. In June 2018, the Financial Accounting Standards Board (the
+“FASB”) issued ASU 2018-08, Not-for-Profit Entities (Topic 958): Clarifying the Scope and the Accounting Guidance for Contributions Received and Contributions Made. This ASU clarifies the guidance presented in ASC Topic 958, “Not-for-Profit
+Entities,” for evaluating whether a transaction is reciprocal (i.e., an exchange transaction) or non reciprocal (i.e., a contribution) and for distinguishing between conditional and unconditional contributions. The ASU also clarified the guidance
+used by entities other than not-for-profits to identify and account for contributions made. Government grants are invoiced and revenue is recognized as milestones are achieved, conditions are removed and approval from grantor is obtained. 
+In July 2020, the Company was awarded a grant of $ 0.6 million from BARDA to develop a SARS-CoV-2 Ag System. The Company earned $ 0 
+and $ 0.2 million for the years ended December 31, 2022 and 2021, respectively, and was recorded as government grant income. 
+In
+December 2020, the Company was awarded a grant of $ 12.7 million from BARDA to support the development and pursuit of FDA EUA for a
+rapid, multiplex DPP Respiratory Antigen Panel point-of-care test system. The Company earned $ 0 and $ 10.9 million for the years ended December 31, 2022 and 2021, respectively, and was recorded as government grant income. Cumulative through December
+31, 2022, the Company recognized $ 12.5 million under this agreement, and the remainder $ 0.2 million is subject to obtaining the EUA for the DPP SARs-COV-2 Antigen test. 
+In September 2022, the
+Company was awarded a grant of $ 3.2 million from the Centers for Disease Control and Prevention (CDC) to develop a rapid POC Syphilis
+Diagnostic Test using Chembio DPP Technology. As of December 31, 2022, the company earned $ 0.6 million that was recorded as government
+grant income. 
+Contract Liabilities 
+Deferred revenue relates to payments received in advance of performance under the contract. Deferred revenue is recognized as revenue as (or when) the Company performs under the contract. At December 31, 2022 and 2021, the Company reported $ 0 in deferred revenue. 
+( j ) Loss Per Share: 
+Basic loss per share is computed by dividing net loss attributable to common stockholders by the weighted-average number of common shares outstanding for the period
+excluding unvested restricted stock. Diluted net loss per share is computed using the treasury stock method if the additional shares are dilutive. For all periods presented, basic and diluted net loss per share are the same as any additional shares
+would be anti-dilutive. 
+F-12 
+Table of Contents 
+There were 1,588,387 and 705,325 restricted shares awards outstanding as of December 31, 2022 and 2021, respectively, that were not included in the calculation of diluted income
+per share for the year ended December 31, 2022 and 2021, because their effect would have been anti-dilutive. There were 3,657,163 and 1,600,372 options outstanding as of December 31, 2022 and 2021 respectively, that were not included in the calculation of diluted income per share for the
+twelve months ended December 31, 2022 and 2021, respectively, because their effect would have been anti-dilutive. 
+(k) Research
+and Development: 
+Research and Development (R&D) include product development, program management, clinical trials and regulatory costs and are expensed when incurred. Advance payments
+for goods and services that will be used in future research and development activities are expensed when the activity has been performed or when the goods have been received rather than when the payment is made. 
+(l) Stock-Based
+Compensation: 
+The Company grants share options to employees and non-employee members of the Company’s board of directors as compensation for services performed. Employee and
+non-employee members of the board of directors’ awards of share-based compensation are accounted for in accordance with ASC 718, Compensation - Stock Compensation, or ASC 718. ASC 718 requires all share-based payments to employees and non-employee
+directors, including grants of share options, to be recognized in the consolidated statement of operations and comprehensive loss based on their grant date fair values. 
+The grant date fair value of share options is estimated using the Black-Scholes option valuation model. The fair value of restricted stock and performance/restricted
+stock unit awards are determined on the date of grant or the date of issuance, as applicable. 
+The grant date fair value is calculated based on assumptions with respect to (i) the fair value of the Company’s common stock on the grant date; (ii) expected volatility
+of the Company’s common stock price, (iii) the periods of time over which the optionees are expected to hold their options prior to exercise (expected term), (iv) expected dividend yield on the Company’s common stock, and (v) risk-free interest
+rates. 
+The expected volatility is calculated based on historical data of the Company’s common stock. The expected dividend yield is zero as the Company has never paid dividends
+and does not currently anticipate paying any in the foreseeable future. Risk-free interest rates are based on quoted U.S. Treasury rates for securities with maturities approximating the option’s expected term. The expected term of share options
+granted to the optionees is determined using the average of the vesting period and contractual life of the option. 
+Stock based compensation is generally recognized on a straight-line basis over the service period of the grant and is reduced for actual forfeitures in the period in
+which the forfeiture occurs. 
+(m) Income
+Taxes: 
+The Company accounts for income taxes under an asset and liability approach that recognizes deferred tax assets and liabilities based on the difference between the
+financial statement carrying amounts and the tax bases of assets and liabilities using enacted tax rates in effect in the years in which the differences are expected to reverse. 
+The Company follows a more-likely-than-not threshold for financial statement recognition and measurement of a tax position taken, or expected to be taken, in a tax
+return. The guidance relates to, among other things, classification, accounting for interest and penalties associated with tax positions, and disclosure requirements. Any interest and penalties accrued related to uncertain tax positions are recorded
+in tax expense. 
+The Company assesses the realizability of its net deferred tax assets on an annual basis. If, after considering all relevant positive and negative evidence, it is more
+likely than not that some portion or all of the net deferred tax assets will not be realized, the Company will reduce the net deferred tax assets by a valuation allowance. The realization of net deferred tax assets is dependent on several factors,
+including the generation of sufficient taxable income prior to the expiration of net operating loss carryforwards. 
+F-13 
+Table of Contents 
+( n ) Goodwill: 
+Goodwill represents the excess of the purchase price the Company paid over the fair value of the net tangible and identifiable intangible assets acquired in the
+Company’s acquisition. Goodwill is not amortized but rather is tested annually as of the first day of the fiscal fourth quarter, or sooner if the Company believes that indicators of impairment exist. The Company makes a qualitative evaluation about
+the likelihood of goodwill impairment, which is based on a number of applicable factors. If the Company concludes that it is more likely than not that the carrying value of the applicable reporting unit is greater than its fair value, then it would
+recognize an impairment charge for the amount by which the carrying value exceeds the reporting unit’s fair value, provided the impairment charge does not exceed the total amount of goodwill allocated to the reporting unit. 
+The quantitative goodwill impairment test is performed using a one-step process. The process is to compare the fair value of a reporting unit with its carrying amount.
+If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not impaired. If the carrying amount of a reporting unit exceeds its fair value, goodwill of the reporting unit is impaired, and an impairment loss
+is recognized in an amount equal to that excess. 
+The Company operates as a single operating segment and
+has one reporting unit. The Company recognized an impairment loss of its goodwill totaling $ 3.0 and $ 2.6 million for the year ended December 31, 2022 and 2021
+respectively. 
+( o ) Allowance for Doubtful Accounts: 
+The Company records allowances for doubtful accounts for the estimated probable losses on uncollectible accounts receivable. The allowance is based upon the credit
+worthiness of the Company’s customers, the Company’s historical experience, the age of the receivable and current market and economic conditions. Receivables are written off against these allowances in the period they are determined to be
+uncollectible. 
+(p) Foreign
+Currency Translation: 
+The functional currency of a foreign subsidiary is the local currency. Assets and liabilities of foreign subsidiaries that use a currency other than U.S. dollars as
+their functional currency are translated to U.S. dollars at end of period currency exchange rates. The consolidated statements of operations of foreign subsidiaries are translated to U.S. dollars at average period currency exchange rates. The effect
+of translation for foreign subsidiaries is reported in other comprehensive income. 
+(q ) Leases: 
+The Company accounts for leases in accordance with ASC 842. The Company determines if an arrangement is a lease at contract inception. A lease exists when a contract
+conveys the right to control the use of identified property, plant, or equipment for a period of time in exchange for consideration. The definition of a lease embodies two conditions: (1) there is an identified asset in the contract that is land or a
+depreciable asset (i.e., property, plant, and equipment), and (2) the Company has the right to control the use of the identified asset. The Company accounts for the lease and non-lease components as a single lease component. 
+From time to time the Company enters into direct financing lease arrangements that include a lessee obligation to purchase the leased asset at the end of the lease term,
+a bargain purchase option, or provides for minimum lease payments with a present value of 90 % or more of the fair value of the leased
+asset at the date of lease inception. 
+Operating leases where the Company is the lessee are included in right-of-use (“ROU”) assets and lease obligations are included on the Company’s consolidated balance
+sheets. The lease obligations are initially and subsequently measured at the present value of the unpaid lease payments at the lease commencement date and subsequent reporting periods. 
+F-14 
+Table of Contents 
+Finance leases where the Company is the lessee are included in ROU assets and lease obligations on the Company’s consolidated balance sheets. The lease obligations are
+initially measured in the same manner as for operating leases and are subsequently measured at amortized cost using the effective interest method. 
+Key estimates and judgments include how the Company determined (1) the discount rate used to discount the unpaid lease payments to present value, (2) lease term and (3)
+lease payments. ASC 842 requires a lessee to discount its unpaid lease payments using the interest rate implicit in the lease or, if that rate cannot be readily determined, its incremental borrowing rate. As most of the Company’s leases where it is
+the lessee do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company’s incremental borrowing rate for a
+lease is the rate of interest it would have to pay on a collateralized basis to borrow an amount equal to the lease payments under similar terms. The Company uses the implicit rate when readily determinable. 
+The lease term for all of the Company’s leases includes the noncancelable period of the lease plus any additional periods covered by either a lessee option to extend (or
+not to terminate) the lease that is reasonably certain to be exercised, or an option to extend (or not to terminate) the lease controlled by the lessor. 
+The ROU asset is initially measured at cost, which comprises the initial amount of the lease liability adjusted for lease payments made at or before the lease
+commencement date less any lease incentives received. For operating leases, the ROU asset is subsequently measured throughout the lease term at the carrying amount of the lease liability, minus any accrued lease payments, less the unamortized balance
+of lease incentives received. Lease expense for lease payments is recognized on a straight-line basis over the lease term. 
+For finance leases, the ROU asset is subsequently amortized using the straight-line method from the lease commencement date to the earlier of the end of its useful life
+or the end of the lease term unless the lease transfers ownership of the underlying asset, or the Company is reasonably certain to exercise an option to purchase the underlying asset. In those cases, the ROU asset is amortized over the useful life of
+the underlying asset. Amortization of the ROU asset is recognized and presented separately from interest expense on the lease liability. 
+The Company has elected not to recognize ROU assets and lease liabilities for all short-term leases that have a lease term of 12 months or less at lease commencement. Lease payments associated with short-term leases are recognized as an expense on a straight-line basis over the lease term. 
+Impairment charges for the Malaysian facility right-of-use asset recorded during the years ended December 31, 2022 and 2021 was $ 0 and $ 0.1 million, respectively (see
+Note 14 - Asset Impairment, Restructuring, Severance and related costs). 
+( r) Employee Retention Credit 
+Accounting
+Standards Codification 105, “Generally Accepted Accounting Principles,” describes the decision-making framework when no clear guidance exists in US GAAP for a particular transaction. Specifically, ASC 105-10-05-2 instructs companies to look for
+guidance for a similar transaction within US GAAP and apply that guidance by analogy. As such, forms of government assistance, such as the Employee Retention Credit, provided to business entities would not be within
+the scope of International Accounting Standards (IAS) 20 Accounting for Government Grants and Disclosure of Government Assistance, but it may be applied by analogy under ASC 105-10-05-2. We accounted for the Employee Retention Credit (“ERC”) as a
+government grant in accordance with IAS 20 by analogy under ASC 105-10-05-2 and a current receivable and other income was recorded for the year ended December 31, 2022. 
+(s) Insurance Receivable 
+Upon the
+recognition of a loss related to a pending, threatened or actual litigation for which the Company has insurance coverage, a related insurance receivable is recorded upon evaluation that an insurance contract is enforceable and the insurer has not
+disputed the claim. If the insurance is enforceable and not subject to dispute, the Company recognizes a receivable from the insurer when it is probable of recovery up to the loss recognized. 
+(t) Recent
+Accounting Pronouncements Affecting the Company: 
+Recently Adopted 
+ASU 2021-10 - Government Assistance (Topic 832): Disclosures by Business Entities about Government Assistance 
+In November 2021, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2021-10, Government Assistance (Topic 832): Disclosures by
+Business Entities about Government Assistance, which creates Accounting Standards Codification (“ASC”) 832 and aims to provide increased transparency by requiring business entities to disclose information about certain types of government assistance
+they receive in the notes to the financial statements. The disclosure requirements in ASC 832 only apply to transactions with a government that are accounted for by analogizing to either a grant model (for example, in International Accounting
+Standard 20, Accounting for Government Grants and Disclosure of Government Assistance), or a contribution model (for example, in ASC 958-605, Not-for-Profit Entities – Revenue Recognition). The FASB broadly defined “government assistance” in ASC 832
+to ensure that assistance received from most types of governmental entities or other related organizations would be disclosed. Entities are required to provide the new disclosures prospectively for all transactions with a government entity that are
+accounted for under either a grant or a contribution accounting model and are reflected in the financial statements at the date of initially applying the new amendments, and to new transactions entered into after that date. Retrospective application
+of the guidance is permitted. The Company adopted the standard effective January 1, 2022 and has determined that the adoption did not have an impact on the Company’s consolidated financial statements. 
+F-15 
+Table of Contents 
+Not Yet Adopted 
+ASU 2020-06 - Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging—Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting
+for Convertible Instruments and Contracts in an Entity’s Own Equity 
+On August 5, 2020, the FASB issued ASU 2020-06, which simplifies the accounting for certain financial instruments with characteristics of liabilities and equity,
+including convertible instruments and contracts on an entity’s own equity. The ASU is part of the FASB’s simplification initiative, which aims to reduce unnecessary complexity in GAAP. ASU 2020-06 simplifies the guidance in GAAP on the issuer’s
+accounting for convertible debt instruments, requires entities to provide expanded disclosures about “the terms and features of convertible instruments” and how the instruments have been reported in the entity’s financial statements. It also removes
+from ASC 815-40-25-10 certain conditions for equity classification and amends certain guidance in ASC 260 on the computation of EPS for convertible instruments and contracts on an entity’s own equity. An entity can use either a full or modified
+retrospective approach to adopt the ASU’s guidance. The ASU’s amendments are effective for smaller public business entities fiscal years beginning after December 15, 2023. The Company continues to assess the potential impact of the standard and will
+disclose the nature and reason for any elections that the Company makes. 
+NOTE 3 — INVENTORIES: 
+Net inventories consist of the following at December 31: 
+December 31 
+2022 
+2021 
+Raw Materials 
+$ 
+4,539,346 
+$ 
+7,306,095 
+Work in Process 
+1,106,962 
+3,556,878 
+Finished Goods 
+2,069,105 
+2,057,478 
+$ 
+7,715,413 
+$ 
+12,920,451 
+During the year ended December 31, 2022 and 2021, the Company recognized inventory adjustments related to expired and obsolete items totaling $ 0.6 million and $ 4.1 million respectively.
+F-16 
+Table of Contents 
+NOTE 4 — FIXED ASSETS: 
+Fixed assets consist of the following at December 31: 
+December 31 
+2022 
+2021 
+Machinery and Equipment 
+$ 
+13,848,792 
+$ 
+12,500,235 
+Furniture and Fixtures 
+11,996 
+6,631 
+Computer Equipment 
+468,185 
+465,576 
+Leasehold Improvements 
+3,027,861 
+2,933,159 
+Enterprise Business Systems 
+2,953,221 
+2,953,221 
+Subtotal: 
+20,310,055 
+18,858,822 
+Less: Accumulated Depreciation and Amortization 
+( 12,155,404 
+) 
+( 10,302,049 
+) 
+$ 
+8,154,651 
+$ 
+8,556,773 
+Depreciation expense for the 2022 and 2021 years totaled $ 1.9 
+million and $ 1.8 million, respectively. 
+Effective May 2021, the Company discontinued its operations in Malaysia. Impairment charges recorded for the Malaysian fixed assets, net for the year ended December 31,
+2022 and 2021 were $ 0 and $ 0.1 
+million, respectively. 
+As of December 31, 2022 and 2021, the Company has purchased manufacturing equipment that is not yet in use and therefore has not been depreciated, aggregating $ 3,192,824 and $ 1,970,652 , respectively.
+These balances are reflected under the Machinery and Equipment line on the table above. 
+NOTE 5 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES: 
+Accounts payable and accrued liabilities consist of the following at December 31: 
+December 31 
+2022 
+2021 
+Accounts Payable - suppliers 
+$ 
+3,342,926 
+$ 
+7,745,592 
+Accrued Commissions & Royalties 
+2,425,302 
+1,359,691 
+Accrued Payroll 
+330,784 
+494,258 
+Accrued Vacation 
+400,409 
+421,416 
+Accrued Bonuses 
+1,467,756 
+1,378,706 
+Accrued Professional Fees 
+114,000 
+122,935 
+Accrued Legal 
+11,182,997 
+400,000 
+Accrued Expenses - Other 
+466,523 
+1,205,395 
+$ 
+19,730,697 
+$ 
+13,127,993 
+As of December 31, 2022, the amounts in other accrued expenses
+include expenses in connection with pending legal matters (see Note 12 – Commitments, Contingencies, and Concentrations: Litigation). 
+F-17 
+Table of Contents 
+NOTE 6 — REVENUE: 
+Disaggregation
+of Revenue 
+Exchange transactions are recognized in accordance with ASC Topic 606, Revenue from Contracts with Customers, while non-exchange transactions are recognized in
+accordance with ASU 2018-08, Not-For-Profit Entities (Topic 958): Clarifying the Scope and Accounting Guidance for Contributions Received and Contributions Made. 
+The following tables disaggregates total revenues for the period ending December 31, 2022: 
+Exchange 
+Transactions 
+Non-Exchange 
+Transactions 
+Total 
+Net product sales 
+$ 
+47,091,673 
+$ 
+- 
+$ 
+47,091,673 
+R&D revenue 
+112,986 
+- 
+112,986 
+Government grant income 
+- 
+1,182,023 
+1,182,023 
+License and royalty revenue 
+1,135,241 
+- 
+1,135,241 
+$ 
+48,339,900 
+$ 
+1,182,023 
+$ 
+49,521,923 
+The following tables disaggregates total revenues for the period ending December 31, 2022 by region: 
+Total 
+Africa 
+$ 
+7,000,085 
+Asia 
+665,159 
+Europe & Middle East 
+4,518,475 
+Latin America 
+19,265,840 
+United States 
+18,072,364 
+$ 
+49,521,923 
+The following tables disaggregates total revenues for the period ending December 31, 2021: 
+Exchange 
+Transactions 
+Non-Exchange 
+Transactions 
+Total 
+Net product sales 
+$ 
+34,737,444 
+$ 
+- 
+$ 
+34,737,444 
+R&D revenue 
+1,159,381 
+- 
+1,159,381 
+Government grant income 
+- 
+10,891,726 
+10,891,726 
+License and royalty revenue 
+1,029,901 
+- 
+1,029,901 
+$ 
+36,926,726 
+$ 
+10,891,726 
+$ 
+47,818,452 
+The following tables disaggregates total revenues for the period ending December 31, 2021 by region: 
+Total 
+Africa 
+$ 
+5,562,788 
+Asia 
+664,579 
+Europe & Middle East 
+5,179,267 
+Latin America 
+18,418,983 
+United States 
+17,992,835 
+$ 
+47,818,452 
+F-18 
+Table of Contents 
+NOTE 7 — INCOME TAXES: 
+The components of loss before income taxes consisted of the following: 
+Year Ending December 31, 
+2022 
+2021 
+United States operations 
+$ 
+( 18,425,426 
+) 
+$ 
+( 26,858,325 
+) 
+International operations 
+( 4,830,826 
+) 
+( 7,107,254 
+) 
+Loss before taxes 
+$ 
+( 23,256,252 
+) 
+$ 
+( 33,965,579 
+) 
+The (benefit) provision for income taxes for the years ended December 31, 2022 and 2021 was comprised of
+the following: 
+Year Ending December 31, 
+2022 
+2021 
+Current 
+Federal 
+$ 
+- 
+$ 
+- 
+State 
+33,948 
+7,891 
+Foreign 
+457 
+- 
+Total current (benefit) provision 
+34,405 
+7,891 
+Deferred 
+Federal 
+- 
+- 
+State 
+- 
+- 
+Foreign 
+- 
+( 69,941 
+) 
+Total deferred (benefit) provision 
+- 
+( 69,941 
+) 
+Total (benefit) provision 
+$ 
+34,405 
+$ 
+( 62,050 
+) 
+A reconciliation of the Federal statutory rate to the effective rate applicable to loss before income taxes is as follows: 
+Year Ending December 31, 
+2022 
+2021 
+Federal income tax at statutory rates 
+21.00 
+% 
+21.00 
+% 
+State income taxes, net of federal benefit 
+0.01 
+% 
+0.18 
+% 
+Nondeductible expenses 
+( 3.69 
+)% 
+( 2.04 
+)% 
+Foreign rate differential 
+0.40 
+% 
+0.32 
+% 
+Change in valuation allowance 
+( 16.85 
+)% 
+( 19.60 
+)% 
+Other 
+( 1.02 
+)% 
+0.32 
+% 
+Income tax (expense) benefit 
+( 0.15 
+)% 
+0.18 
+% 
+The Company had an ownership change as described in Internal Revenue Code Sec. 382 during 2004 (“2004 change”). As a result, the Company’s net operating losses prior to
+the 2004 change of $ 5,832,516 were subject to an annual limitation of $ 150,608 and for the first five (5) years are entitled to a BIG (Built-In-Gains) of $ 488,207 
+per year. These net operating losses expire in 2023 through 2024. 
+The Company had a second ownership change during 2006 (“2006 change”). The net operating losses incurred between the 2004 change and the 2006 change of $ 8,586,861 were subject to an annual limitation of $ 1,111,831 
+and for the first five (5) years are entitled to a BIG of $ 1,756,842 per year. These net operating losses expire in 2023 through 2026. 
+After applying the above limitations, at December 31, 2022, the Company has post-change net operating loss
+carry-forwards of approximately $ 25,671,216 which expire between
+2023 and 2037 and $ 66,924,161 which do not expire. In addition the
+Company has research and development tax credit carryforwards of approximately $ 1,632,846 for the year ended December 31, 2022 , which expire between 2023 and 2036. 
+F-19 
+Table of Contents 
+The Company has state net operating loss carryforwards of approximately $ 4,746,769 
+which generally expire between 2035 and 2042. The Company has foreign net operating loss carryforwards of approximately $ 3,207,825 which
+generally expire between 2025 and 2029 and foreign net operating loss carryforwards of $ 5,803,963 which do not expire. 
+Deferred tax assets and liabilities as of December 31 are as follows: 
+Year Ending December 31, 
+2022 
+2021 
+Inventory reserves 
+$ 
+343,262 
+$ 
+333,551 
+Accrued expenses 
+822,145 
+374,673 
+Net operating loss carry-forwards 
+22,123,522 
+20,401,828 
+Research and development credit 
+1,632,846 
+1,651,529 
+Research and development expenses 
+628,711 
+- 
+Stock-based compensation 
+437,992 
+259,106 
+Interest Expense 
+1,825,347 
+1,221,171 
+Lease obligations 
+1,381,089 
+1,504,433 
+Intangibles 
+136,478 
+137,142 
+Total deferred tax assets 
+29,331,392 
+25,883,433 
+Right-of-use assets 
+( 1,155,407 
+) 
+( 1,294,519 
+) 
+Depreciation 
+( 252,097 
+) 
+( 560,754 
+) 
+Total deferred tax liabilities 
+( 1,407,504 
+) 
+( 1,855,273 
+) 
+Net deferred tax assets before valuation allowance 
+27,923,888 
+24,028,160 
+Less valuation allowances 
+( 27,923,888 
+) 
+( 24,028,160 
+) 
+Net noncurrent deferred tax liabilities 
+$ 
+- 
+$ 
+- 
+The Company does not provide for U.S. income taxes on unremitted earnings of foreign subsidiaries as its present intention is to reinvest the unremitted earnings in the
+Company’s foreign operations. At December 31, 2022 there were no unremitted earnings of foreign subsidiaries. 
+Interest and penalties, if any, related to incom e tax liabilities are included in income tax expense. As of December 31, 2022, the Company does not have any uncertain tax
+positions. 
+NOTE 8 — GOODWILL AND INTANGIBLE ASSETS: 
+Following is a table that reflects changes in Goodwill: 
+Beginning balance January 1, 2022 
+$ 
+3,022,787 
+Changes in foreign currency exchange rate 
+10,778 
+Impairment 
+( 3,033,565 
+) 
+Balance at December 31, 2022 
+$ 
+— 
+During the
+Company’s interim goodwill impairment testing conducted during the first quarter of 2022, it was concluded that goodwill was impaired and an impairment of $ 3.0 
+million was recognized during the period ended December 31, 2022. During the period ended December 31, 2021, $ 2.6 million was recognized as an impairment. 
+F-20 
+Table of Contents 
+Intangible assets consist of the following at: 
+December
+31, 2022 
+December 31, 2021 
+Weighted Average 
+Remaining Life 
+Cost 
+Accumulated 
+Amortization 
+Impairment 
+Net Book Value 
+Cost 
+Accumulated 
+Amortization 
+Impairment 
+Net 
+Book Value 
+Intellectual property 
+- 
+$ 
+- 
+$ 
+- 
+$ 
+- 
+$ 
+- 
+$ 
+1,636,724 
+$ 
+546,252 
+1,090,472 
+$ 
+- 
+Developed technology 
+- 
+- 
+- 
+- 
+- 
+1,944,500 
+828,681 
+1,115,819 
+- 
+Customer contracts/relationships 
+- 
+- 
+- 
+- 
+- 
+1,254,344 
+477,661 
+776,683 
+- 
+Trade names 
+- 
+- 
+- 
+- 
+- 
+110,853 
+43,696 
+67,157 
+- 
+$ 
+- 
+$ 
+- 
+$ 
+- 
+$ 
+- 
+$ 
+4,946,421 
+$ 
+1,896,290 
+3,050,131 
+$ 
+- 
+Intellectual property, developed technology, customer contracts/relationships and trade names were being amortized over 10 , 7 , 10 and 11 years, respectively. Amortization expense for the year ended December
+31, 2022 and 2021 was $ 0 and $ 479,988 ,
+respectively. 
+As of December 31, 2021, the Company recognized an impairment loss of all its finite-lived intangible assets totaling $ 3.1 
+million . As of December 31, 2022, no additional finite-lived intangible assets remained. 
+NOTE 9 — STOCKHOLDERS’ EQUITY: 
+(a) 
+Common Stock 
+On July 19, 2021, Chembio entered into an At the Market Offering Agreement (the “ATM Agreement”) with Craig‑Hallum Capital Group LLC (“Craig‑Hallum”), pursuant to which
+Chembio may sell from time to time, at its option, up to an aggregate of $ 60,000,000 of shares of common stock through Craig‑Hallum, as
+sales agent. During the year ended December 31, 2022, Chembio issued and sold pursuant to the ATM Agreement a total of 6,466,191 shares of
+common stock at a volume-weighted average price of $ 0.71 per share for gross proceeds of $ 4.6 million and net proceeds, after giving effect to placement fees and other transaction costs, of $ 4.3 million. Additional shares of common stock may be issued and sold pursuant to the ATM Agreement for gross proceeds of up to $ 6.3 million. 
+(b) 
+Preferred Stock 
+Chembio has 10,000,000 shares of preferred stock
+authorized and none outstanding. These shares can become issuable upon an approved resolution by the board of directors of Chembio (the “Board”) and the filing of a Certificate of
+Designation with the state of Nevada. 
+(c) 
+Treasury Stock 
+Chembio has 48,057 shares of treasury stock acquired upon the vesting of restricted stock awards related to the tax withholding requirements paid on behalf of the employees. 
+(d) 
+Options, Restricted Stock, and Restricted Stock Units 
+T he Board or its Compensation Committee may make grants of options, restricted stock, and restricted stock units pursuant to equity incentive plans that have
+been approved by Chembio’s stockholders. 
+NOTE 10 — EQUITY INCENTIVE PLANS: 
+Effective June 19, 2014, Chembio’s stockholders voted to approve the 2014 Stock Incentive Plan (the “2014 Plan”), with 800,000 shares of common stock available to be issued. Under the terms of the 2014 Plan, the Board or its Compensation Committee has the discretion to select the persons to whom
+awards are to be granted. Awards can be in the form of Equity Award Units. The awards vest at such times and under such conditions as determined by the Board or its Compensation Committee. Cumulatively through December 31, 2022, there were 732,064 Equity Award Units expired, forfeited or exercised. At December 31, 2022, 46,875 Equity Award Units were outstanding and 21,061 shares were
+not issued. All shares that expired, forfeited or were not issued rolled over into the 2019 Plan. No Equity Award Units remain available
+to be issued under the 2014 Plan. 
+F-21 
+Table of Contents 
+Effective June 18, 2019, Chembio’s stockholders voted to approve the 2019 Omnibus Incentive Plan (the “2019 Plan”), with 2,400,000 shares of common stock available to be issued. At the Annual Stockholder Meeting on June 25, 2021, Chembio’s stockholders voted to approve an increase to the shares of
+common stock issuable under the SIP by 2,400,000 to 4,800,000 . In addition, shares of common stock underlying any outstanding award granted under the 2019 Plan that, following the effective date of the 2019 Plan, expire, or are terminated, surrendered or forfeited for
+any reason without issuance of such shares, shall be available for the grant of new awards under the 2019 Plan. Under the terms of the 2019 Plan, the Board or its Compensation Committee has the discretion to select the persons to whom awards are to
+be granted. Awards can be in the form of options, stock appreciation rights, restricted stock, restricted stock units, performance stock units or other stock-based awards under the 2019 Plan (collectively, “2019 Equity Units”). The 2019 Equity Units
+become vested at such times and under such conditions as determined by the Board or its Compensation Committee. Cumulatively through December 31, 2022, 1,307,361 
+2019 Equity Units have been cancelled or forfeited. At December 31, 2022, 4,660,098 2019 Equity Units were outstanding, and 226,702 2019 Equity Units were available to be awarded. 
+The Company’s results for the years ended December 31, 2022 and 2021 include stock-based compensation expense totaling $ 2,299,081 and $ 2,034,247 , respectively. Such amounts have been
+included in the Consolidated Statements of Operations within cost of product sales ($ 209,792 and $ 174,537 , respectively), research and development ($ 446,769 and $ 494,235 , respectively) and selling, general and administrative expenses ($ 1,642,520 and $ 1,365,475 , respectively). 
+The weighted-average assumptions made in calculating the fair values of options are as follows for the respective years ended December 31: 
+2022 
+2021 
+Expected term (in years) 
+6.00 
+5.10 
+Expected volatility 
+91.62 
+% 
+78.95 
+% 
+Expected dividend yield 
+0 
+0 
+Risk-free interest rate 
+1.97 
+% 
+0.85 
+% 
+The following table provides stock option activity for the years ended December 31, 2022: 
+Number 
+of Shares 
+Weighted 
+Average 
+Exercise Price 
+per Share 
+Weighted 
+Average 
+Remaining 
+Contractual Term 
+Aggregate 
+Intrinsic 
+Value 
+Outstanding at December 31, 2021 
+1,600,372 
+$ 
+4.18 
+6.59 years 
+$ 
+- 
+Granted 
+2,481,968 
+$ 
+1.24 
+- 
+Exercised 
+— 
+$ 
+— 
+- 
+Forfeited 
+154,076 
+$ 
+2.70 
+- 
+Expired/cancelled 
+271,101 
+5.01 
+Outstanding at December 31, 2022 
+3,657,163 
+$ 
+2.20 
+8.05 years 
+$ 
+- 
+Exercisable at December 31, 2022 
+581,574 
+$ 
+3.98 
+5.42 years 
+$ 
+- 
+F-22 
+Table of Contents 
+The following table summarizes information about stock options outstanding at December 31, 2022: 
+Stock Options Outstanding 
+Stock Options Exercisable 
+Range of 
+Exercise Prices 
+Shares 
+Outstanding 
+Average 
+Remaining 
+Contract Life 
+(Year) 
+Weighted 
+Average 
+Exercise 
+Price 
+Aggregate 
+Intrinsic 
+Value 
+Shares 
+Exercisable 
+Weighted 
+Average 
+Exercise 
+Price 
+Aggregate 
+Intrinsic 
+Value 
+1 to 2.79999 
+2,824,519 
+8.26 
+$ 
+1.40 
+$ 
+- 
+266,431 
+$ 
+2.36 
+$ 
+- 
+2.8 to 4.59999 
+26,335 
+8.43 
+3.06 
+- 
+8,776 
+3.06 
+- 
+4.6 to 6.39999 
+759,434 
+7.69 
+4.80 
+- 
+259,492 
+4.93 
+- 
+6.4 to 8.19999 
+46,875 
+0.36 
+8.15 
+- 
+46,875 
+8.15 
+- 
+Total 
+3,657,163 
+8.04 
+$ 
+2.20 
+$ 
+- 
+581,574 
+$ 
+3.98 
+$ 
+- 
+As of December 31, 2022, there was $ 2,113,275 of net
+unrecognized compensation cost related to stock options that are not vested, which is expected to be recognized over a weighted average period of approximately 2.61 years. The total fair value of shares vested during the year ended December 31, 2022, was $ 962,801 . 
+The following table summarizes information about restricted stock and restricted stock units outstanding as of December 31, 2022: 
+Number of 
+Shares & Units 
+Weighted 
+Average 
+Grant Date 
+Fair Value 
+Unvested at December 31, 2021 
+705,325 
+$ 
+3.34 
+Granted 
+1,308,547 
+0.75 
+Vested 
+203,839 
+3.75 
+Forfeited/expired/cancelled 
+221,646 
+1.35 
+Unvested at December 31, 2022 
+1,588,387 
+1.34 
+As of December 31, 2022, there was $ 1,259,000 of net unrecognized compensation cost related
+to restricted stock and restricted stock units that are not vested, which is expected to be recognized over a weighted average period of approximately 1.79 
+years. Stock based compensation cost related to restricted stock and restricted stock units recognized during the years ended December 31, 2022 and 2021 was $ 967,262 and $ 1,160,953 , respectively. 
+One-Time Incentive
+Bonuses. 
+In August 2021 the
+board of directors approved the adoption of a One-Time Incentive Plan, or the OTIP, under which up to $ 1.5 million, was made available
+for cash awards to a number of employees, including executives. 
+The company made
+OTIP payments of $ 0.6 million and $ 0.1 
+million for years ending December 31, 2022 and 2021, respectively. 
+NOTE 11 — GEOGRAPHIC INFORMATION AND ECONOMIC DEPENDENCY: 
+The Company produces only one 
+group of similar products known collectively as “rapid medical tests” and operates under one segment, as a single reporting unit.
+Product revenue by geographic area are as follows: 
+Year Ending December 31, 
+2022 
+2021 
+Africa 
+$ 
+7,000,085 
+$ 
+5,562,787 
+Asia 
+626,210 
+664,579 
+Europe & Middle East 
+3,351,003 
+4,067,682 
+Latin America 
+19,253,504 
+18,418,983 
+United States 
+16,860,871 
+6,023,413 
+$ 
+47,091,673 
+$ 
+34,737,444 
+Property, plant and equipment, net by geographic area are as follows: 
+2022 
+2021 
+Asia 
+$ 
+81,536 
+$ 
+86,041 
+Europe & Middle East 
+74,815 
+113,883 
+Latin America 
+81,315 
+36,224 
+United States 
+7,916,985 
+8,320,625 
+$ 
+8,154,651 
+$ 
+8,556,773 
+F-23 
+Table of Contents 
+NOTE 12 — COMMITMENTS, CONTINGENCIES AND CONCENTRATIONS: 
+a) 
+Employment Contracts: 
+The Company has contracts with three 
+key employees. The following table is a schedule of future minimum salary commitments: 
+2023 
+$ 
+1,178,000 
+2024 
+383,000 
+b) 
+Benefit Plan: 
+The Company has a 401(k) plan established for its employees whereby it matches 40 % of the first 5 % (or 2 % of salary) that an employee contributes to the plan. Matching contribution expenses totaled $ 191,113 
+and $ 138,513 for the years ended December 31, 2022 and 2021, respectively. 
+c) 
+Leases: 
+The Company leases facilities in New York, Germany, Malaysia, and Brazil, and certain equipment. 
+The Company’s facility leases generally include optional renewal periods. Upon entering into a new facility lease, the Company evaluates the leasehold improvements and
+regulatory requirements related to its operations in that location. To the extent that the initial lease term of the related facility lease is less than the useful life of the leasehold improvements and potential regulatory costs associated with
+moving the facility, the Company concludes that it is reasonably certain that a renewal option will be exercised, and thus that renewal period is included in the lease term and the related payments are reflected in the right-of-use asset and lease
+liability. 
+The Company’s leases generally include fixed rental payments with defined annual increases. While certain of the Company’s leases are gross leases, the majority of the
+Company’s leases are net leases in which the Company makes separate payments to the lessor based on the lessor’s property and casualty insurance costs, the property taxes assessed on the property, and a portion of the common area maintenance where
+applicable. The Company has elected the practical expedient not to separate lease and nonlease components for all of the Company’s facility leases. 
+The components of lease expense were as follows: 
+Year Ended 
+December 31, 2022 
+Year Ended 
+December 31, 2021 
+Operating lease expense 
+$ 
+1,630,609 
+$ 
+1,625,280 
+Finance lease cost 
+Amortization of right-of-use assets 
+$ 
+71,129 
+$ 
+66,872 
+Interest on lease liabilities 
+17,015 
+20,077 
+Total finance lease expense 
+$ 
+88,144 
+$ 
+86,949 
+F-24 
+Table of Contents 
+Supplemental cash flow and other information related to leases were as follows: 
+Year Ended 
+December 31, 2022 
+Year Ended 
+December 31, 2021 
+Cash paid for amounts included in the measurement of lease liabilities: 
+Operating cash flows for operating leases 
+$ 
+1,453,778 
+$ 
+1,404,532 
+Operating cash flows for finance leases 
+17,015 
+20,077 
+Financing cash flows for finance leases 
+70,514 
+61,867 
+Right-of-use assets obtained in exchange for lease obligations: 
+Operating leases 
+$ 
+717,956 
+$ 
+- 
+Finance leases 
+16,234 
+25,609 
+Supplemental balance sheet information related to leases was as follows: 
+December 31, 2022 
+December 31, 2021 
+Finance Leases 
+Finance lease right of use asset 
+$ 
+356,997 
+$ 
+340,762 
+Accumulated depreciation 
+( 220,021 
+) 
+( 148,892 
+) 
+Finance lease right of use asset, net 
+$ 
+136,976 
+$ 
+191,870 
+Current portion of finance lease liability 
+76,869 
+68,176 
+Finance lease liability, net of current 
+76,705 
+139,678 
+Total finance lease liabilities 
+$ 
+153,574 
+$ 
+207,854 
+Weighted Average Remaining Lease Term 
+Operating leases 
+6.6 years 
+7.5 years 
+Finance leases 
+2.1 years 
+2.9 years 
+Weighted Average Discount Rate 
+Operating leases 
+8.70 
+% 
+8.08 
+% 
+Finance leases 
+9.18 
+% 
+8.76 
+% 
+Maturities of lease liabilities as of December 31 were as follows: 
+December 31, 2022 
+December 31, 2021 
+Operating 
+Leases 
+Finance 
+Leases 
+Operating 
+Leases 
+Finance 
+Leases 
+2023 
+$ 
+1,428,821 
+$ 
+87,884 
+$ 
+1,447,249 
+$ 
+83,624 
+2024 
+1,220,150 
+60,116 
+1,221,017 
+83,624 
+2025 
+1,049,442 
+16,731 
+1,018,875 
+55,856 
+2026 
+1,080,925 
+5,940 
+1,049,442 
+12,471 
+2027 
+1,113,353 
+355 
+1,080,925 
+1,680 
+Thereafter 
+2,530,168 
+- 
+3,643,520 
+- 
+Total lease payments 
+$ 
+8,422,859 
+$ 
+171,026 
+$ 
+9,461,028 
+$ 
+237,255 
+Less: imputed interest 
+( 2,081,972 
+) 
+( 17,452 
+) 
+( 2,598,583 
+) 
+( 29,401 
+) 
+Total 
+$ 
+6,340,887 
+$ 
+153,574 
+$ 
+6,862,445 
+$ 
+207,854 
+d) 
+Economic Dependency: 
+F-25 
+Table of Contents 
+The following table discloses product sales the Company had to customers that purchased in excess of 10% of the Company’s net product sales for the periods indicated: 
+For The Years Ended 
+Accounts Receivable 
+December 31, 2022 
+December 31, 2021 
+December 31, 
+2022 
+December 31, 
+2021 
+Net Product Sales 
+% of Net Product Sales 
+Net Product Sales 
+% of Net Product Sales 
+Customer 1 
+$ 
+18,050,287 
+38 
+% 
+$ 
+17,576,641 
+51 
+% 
+$ 
+1,630,007 
+$ 
+7,672,845 
+Customer 2 
+7,562,481 
+16 
+% 
+* 
+* 
+2,062,431 
+* 
+Customer 3 
+* 
+* 
+3,606,552 
+10 
+% 
+* 
+1,433,305.00 
+Revenue includes product sales only, while accounts receivable reflects the total due from the customer, including freight. 
+The following table discloses purchases the Company made from vendors in excess of 10% of the Company’s net purchases for the periods indicated: 
+For The Years Ended 
+Accounts Payable 
+December 31, 2022 
+December 31, 2021 
+December 31, 
+2022 
+December 31, 
+2021 
+Purchases 
+% of Purc. 
+Purchases 
+% of Purc. 
+Vendor 1 
+$ 
+5,359,388 
+34 
+% 
+$ 
+* 
+* 
+$ 
+381,923 
+$ 
+– 
+Vendor 2 
+$ 
+* 
+* 
+$ 
+3,163,285 
+16 
+% 
+$ 
+* 
+$ 
+1,361,383 
+Vendor 3 
+$ 
+2,231,580 
+14 
+% 
+$ 
+2,031,795 
+10 
+% 
+$ 
+179,482 
+$ 
+353,097 
+In the tables above, an asterisk (*)
+indicates that sales, accounts receivable, purchases or accounts payable, as applicable to the tabular column, did not exceed 10% for the period indicated. 
+The Company purchases materials pursuant to intellectual property rights agreements that are important components in its products. Management believes that other
+suppliers could provide similar materials on comparable terms. A change in suppliers, however, could cause a delay in manufacturing and a possible loss of sales, which could adversely affect operating results. 
+e) 
+Litigation: 
+SEC Investigation 
+The SEC recently concluded an investigation (the “SEC Investigation”) relating to the public offering of common stock that Chembio completed in May 2020
+(the “May 2020 Offering”) and to the FDA’s revocation in June 2020 of an emergency use authorization for the DPP COVID-19 IgM/IgG system that was issued by the FDA in April 2020. Chembio received subpoenas from the SEC in July 2020 and April 2021
+seeking the production of documents in connection with this investigation. In addition, the SEC delivered subpoenas in April 2021 to five of Chembio’s employees (including its three executive officers, who consist of its Chief Executive Officer and
+President, its former Executive Vice President and Chief Financial Officer, and its Executive Vice President and Chief Scientific and Technology Officer). An additional subpoena was issued in June 2021 to Chembio’s former Interim Chief Executive
+Officer and Executive Chair. Each subpoena requested the production of documents relating to the same matters as are the subject of the subpoenas Chembio received. One current employee, the Chief Executive Officer, also received a testimonial
+subpoena from the SEC. 
+On March 2, 2023, the Company and the SEC settled the SEC Investigation through an Administrative Order dated March 2, 2023, instituting
+cease-and-desist proceedings pursuant to Section 8A of the U.S. Securities Act of 1933, as amended. The Company agreed to cease and desist from committing or causing any violations or future violations of Sections 17(a)(2) and 17(a)(3) of the
+Securities Act and pay a one-time civil monetary penalty of $ 500,000 . Under the terms of the settlement, the Company neither admitted
+nor denied the SEC’s findings. 
+F-26 
+Table of Contents 
+Legal Proceedings 
+Stockholder Litigation 
+Putative Stockholder Securities Class-Action Litigation 
+In 2020 four purported securities class-action lawsuits
+were filed in the United States District Court for the Eastern District of New York by alleged stockholders of Chembio: 
+• 
+Sergey Chernysh v. Chembio Diagnostics, Inc., Richard L. Eberly, and Gail S. Page, filed on June 18, 2020; 
+• 
+James Gowen v. Chembio Diagnostics, Inc., Richard L. Eberly, and Gail S. Page, filed on June 22, 2020; 
+• 
+Anthony Bailey v. Chembio Diagnostics, Inc. Richard J. Eberly, Gail S. Page, and Neil A. Goldman, filed on July 3, 2020; and 
+• 
+Special Situations Fund III QP, L.P., Special Situations Cayman Fund, L.P., and Special Situations Private Equity Fund, L.P. v. Chembio Diagnostics, Inc., Richard Eberly, Gail S.
+Page, Robert W. Baird & Co. Inc. and Dougherty & Company LLC, filed August 17, 2020. 
+The plaintiffs in each of the above cases alleged claims under Section 10(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), Rule 10b-5 thereunder and
+Section 20(a) of the Exchange Act. Special Situations Fund III QP, L.P., Special Situations Cayman Fund, L.P. and Special Situations Private Equity Fund, L.P. (collectively, the “Special Situations Funds”) also asserted claims under Sections 11,
+12(a)(2) and 15 of the Securities Act of 1933 (the “Securities Act”) relating to the May 2020 Offering. 
+On
+December 29, 2020, the Court issued an Order consolidating the cases and appointing the Spe cial Situations Funds and Municipal Employees’ Retirement System of Michigan (together, the “Lead Plaintiffs”) , as co-lead plaintiffs and their respective counsel as co-lead counsel. The consolidated cases are now pending under the caption “In re
+Chembio Diagnostics, Inc. Securities Litigation.” 
+The Lead Plaintiffs filed their Consolidated Amended Complaint (the “CAC”) on February 12, 2021. In summary, the CAC purported to allege claims based on assertedly false and misleading statements and
+omissions concerning the performance of the DPP COVID-19 IgM/IgG System, as well as an asserted failure to timely disclose that the emergency use authorization that had been granted by the FDA with respect to the DPP COVID-19 IgM/IgG System “was -
+or was at an increased risk of - being revoked.” The CAC named as defendants Chembio, Richard L. Eberly, Gail S. Page, Neil A. Goldman, Javan Esfandiari, Katherine L. Davis, Mary Lake Polan, John Potthoff (together, the “Chembio Defendants”) and
+the underwriters for the May 2020 Offering, Robert W. Baird & Co., Inc. and Dougherty & Company LLC (the “Underwriter Defendants”). 
+The CAC purported to assert five counts under the Securities Act and the Exchange Act. Counts I
+through III were brought under the Securities Act, allegedly on behalf of a purported class consisting of all persons who purchased Chembio common stock directly in or traceable to the May 2020 Offering pursuant to Chembio’s shelf registration
+statement on Form S 3 (File No. 333-227398) and the related prospectus, as supplemented by a prospectus supplement dated May 7, 2020 (the “Securities Act Class”). Count I purported to allege a claim for violation of Section 11 of the Securities Act
+against all defendants other than Messrs. Eberly and Esfandiari. Count II purported to allege a claim for violation of Section 12 of the Securities Act against all defendants other than Messrs. Eberly and Esfandiari. Count III purported to allege a
+claim under Section 15 of the Securities Act against Ms. Davis, Dr. Polan, Dr. Potthoff, Ms. Page and Mr. Goldman. 
+Counts IV and V alleged claims under the Exchange Act on behalf of a purported class consisting of all persons who purchased Chembio common stock on the open market from March 12, 2020 through June 16, 2020 (the “Exchange Act
+Class”). Count IV purported to allege a claim for violation of Section 10(b) of the Exchange Act and Rule 10b-5 thereunder against Chembio, Mr. Eberly, Ms. Page, Mr. Goldman and Mr. Esfandiari. Count V purported to allege a claim under Section
+20(a) of the Exchange Act against Mr. Eberly, Ms. Page, Mr. Goldman and Mr. Esfandiari. 
+F-27 
+Table of Contents 
+Defendants filed a motion to dismiss the CAC on March 26, 2021. The Court issued its Opinion and Order (the “February 23 Order”) on the
+defendants’ motions to dismiss on February 23, 2022. In its February 23 Order, the Court: (i) dismissed Counts I and II without prejudice as to all defendants named in those Counts except the Underwriter Defendants as to which Counts I and II
+were not dismissed; (ii) dismissed Count III without prejudice as to all defendants named in that Count; and (iii) dismissed Counts IV and V with prejudice as to all defendants named in those Counts. 
+On March 9, 2022, Lead Plaintiffs filed a motion for partial reconsideration of the Court’s February
+23 Order, which the Court denied on July 21, 2022.On July 14, 2022 , all parties in the In re Chembio Diagnostics, Inc. Securities Litigation action participated in a mediation. The mediation was adjourned without an agreement to resolve the action, but
+the parties continued to discuss a potential negotiated resolution with the mediator’s assistance. 
+Lead Plaintiffs filed their Second Consolidated Amended Complaint (the “SCAC”) on July 26, 2022. The
+SCAC purports to allege three counts under the Securities Act on behalf of the Securities Act Class. Count I purports to allege a claim for violation of Section 11 of the Securities Act against Chembio, Ms. Page, Mr. Goldman, Ms. Davis, Dr.
+Polan, Dr. Potthoff and the Underwriter Defendants. Count II purports to allege a claim for violation of Section 12 of the Securities Act against Chembio, Ms. Page, and the Underwriter Defendants. Count III purports to allege a claim under
+Section 15 of the Securities Act against Ms. Page, Mr. Goldman, Ms. Davis, Dr. Polan and Dr. Potthoff. 
+On August 26, 2022, the Company and the other parties to the litigation reached an agreement in
+principle on the financial terms of a proposed settlement of all claims that were asserted, or could have been asserted, on an individual and class-wide basis against all defendants in the case, including under both the Securities Act and the
+Securities Exchange Act. 
+On December 28, 2022, plaintiffs filed a motion for
+preliminary approval of the class action settlement that included a stipulation of settlement. On February 3, 2023, the Court entered an opinion and order granting preliminary approval of the proposed settlement. The court set a hearing on
+June 5, 2023 to determine, inter alia , whether final approval should be given to the settlement. The principal terms of the settlement are: 
+• 
+A cash payment to a settlement escrow account in the amount of $ 8,100,000 of which approximately $ 209,000 is
+payable by the Company and the remainder is payable by certain of the Company’s insurers; 
+• 
+The net proceeds of the settlement escrow, after deduction of Court-approved
+administrative costs and Court-approved attorneys’ fees and costs, will be distributed to the class; and 
+• 
+A release of claims (including unknown claims) and dismissal of the action with prejudice. 
+By
+entering into the settlement, the settling parties have resolved the class claims to their mutual satisfaction. However, the final determination is subject to approval by the Court. 
+Putative Stockholder Derivative
+Litigation 
+On
+September 11, 2020, a putative stockholder derivative action captioned Karen Wong, derivatively on behalf of Chembio Diagnostics, Inc., Plaintiff v. Richard L. Eberly, Gail S. Page, Neil A. Goldman, Javan Esfandiari, Katherine L. Davis, Mary
+Lake Polan and John G. Potthoff, Defendants, and Chembio Diagnostics, Inc., Nominal Defendant (the “Wong complaint”) was filed purportedly on Chembio’s behalf in the United States District Court for the Eastern District of New York. The Wong
+complaint purports to assert a claim for violation of Section 14(a) of the Exchange Act and Rule 14a-9 thereunder based on ostensibly false and misleading statements and omissions concerning, inter alia ,
+the Company’s rapid COVID-19 antibody test in the proxy statement disseminated in advance of Chembio’s Annual Meeting of Stockholders held on July 28, 2020. The Wong complaint also asserts claims against the individual defendants for purported breaches of fiduciary duties owed to Chembio, as well as unjust enrichment. 
+The Wong complaint
+requests a declaration that the individual defendants have breached or aided and abetted the breach of their fiduciary duties to Chembio, an award of damages to Chembio, restitution, and an award of the plaintiff’s costs and disbursements in the
+action, including reasonable attorneys’ and experts’ fees, costs and expenses, and improvements to Chembio’s corporate governance and internal procedures regarding compliance with laws. 
+On
+March 31, 2022, a second putative stockholder derivative action captioned Michelle Chen, derivatively on behalf of Chembio Diagnostics, Inc., Plaintiff v. Richard L. Eberly, Gail S. Page, Neil A. Goldman, Javan Esfandiari, Katherine L. Davis,
+Mary Lake Polan and John G. Potthoff, Defendants, and Chembio Diagnostics, Inc., Nominal Defendant (the “Chen complaint”) was filed purportedly on behalf of Chembio in the Supreme Court for the State of New York, County of Suffolk. The Chen
+complaint purports to assert a claim for breach of fiduciary duty against the defendants based on ostensibly false and misleading statements and omissions, interalia, concerning the Company’s rapid COVID-19 antibody test. The Chen complaint
+goes on to allege that the misconduct asserted in the complaint gave rise to the filing of the consolidated securities litigation described above. 
+F-28 
+Table of Contents 
+The
+plaintiffs in the Wong and Chen actions took part in the July 14, 2022 mediation described above, and the parties subsequently reached an agreement in principle on the terms of a proposed settlement of both actions, subject to execution of settlement papers and
+court approval. The proposed settlement contemplated the adoption of certain corporate governance measures that did not have to be implemented in the event of a change of control and did not entail any
+monetary compensation or payment other than the derivative plaintiffs’ attorneys’ fees, which the parties agreed would not exceed $ 595,000 , and subject to Court approval. 
+On December 5, 2022, the parties to the Wong action advised
+the court that the parties had reached a settlement in principle of the claims in the Wong action as well as in the related Chen action and requested that the court stay the Wong action to allow the parties sufficient time to finish negotiating
+the settlement documentation and obtain settlement approval from the state court in the Chen action. The court granted the parties’ request that same day. 
+On
+January 31, 2023, the Company announced that it entered into a definitive merger agreement with Biosynex SA. 
+On February 3, 2023, the Company submitted a letter to the United States District Court for the Eastern District of New York before which the Wong complaint is pending, informing the court of the proposed merger with Biosynex.
+In its letter, the Company advised the court that because the corporate governance enhancements central to the parties’ settlement in principle will be mooted if the merger is consummated (in which case there will no longer be any Chembio
+public stockholders), the Company requested that the action should continue to be stayed until such time as it is known whether the merger with Biosynex is completed. 
+On February 6, 2023, counsel for the plaintiff in the Chen action sent a letter to K&L
+Gates, as counsel for the defendants, informing them of their intent to request the state court to lift the stay of the Chen action on an expedited basis for the purposes of allowing the plaintiff to engage in limited discovery, and
+suggesting that the parties speak to the mediator who had previously served the parties. 
+On February 7, 2023, K&L Gates sent counsel for the plaintiff in the Chen action a letter rejecting their request for discovery but agreeing to engage in a call with the mediator to further discuss the impact of
+the proposed Merger on the derivative litigation. 
+On February 13, 2023, the parties in the derivative
+litigation participated in a call with the mediator to discuss the impact of the proposed Merger on the settlement in principle and plaintiffs’ standing in the event the Merger is consummated, as well as the discovery sought in the Chen action.
+While no resolution was reached on these issues during the call, the parties agreed to discuss the substance of their call and the mediator’s suggestions with their clients, and counsel for Chen indicated that they would review the Schedule
+14D-9, which we filed with the Securities and Exchange Commission on February 14, 2023 in connection with the Offer (as amended and supplemented, the “Schedule 14D-9”) once filed to determine whether they would pursue the discovery for the Chen
+action set forth in their February 6 letter. 
+Pursuant to the court’s February 11, 2023 order, the
+parties to the Wong action filed a joint status letter on February 17, 2023. In that joint status letter, the defendants advised the court that in the parties’ February 13, 2023 call with the mediator, the parties discussed the impact of the
+Company’s proposed merger with Parent on the settlement in principle of the litigation and on the plaintiffs’ standing to pursue that litigation in the event the Merger is consummated, as well as the proposed discovery sought by counsel for
+plaintiff in the Chen action. The defendants also advised the court that no resolution of the issues was reached during the call with the mediator, but that counsel for the parties agreed to discuss the substance of the call and the mediator’s
+suggestions with their clients, and that plaintiff’s counsel in the Chen action had indicated that they would review the Schedule 14D-9 to determine whether they would pursue discovery in that litigation. Defendants also advised the court that
+defendants’ position continues to be that the putative derivative litigation should be stayed until at least such time as it is known whether the Merger will be consummated and, in the event plaintiff in the Wong action intends to seek to lift
+the stay in that action, requested that the court schedule a conference to discuss any such request and, if appropriate, to discuss a briefing schedule on any motion to dismiss the case. Defendants also pointed out that the Company had made
+public disclosure of its consideration of strategic alternatives in its Form 10-Q filed on August 5, 2022, prior to the parties’ entry into their memorandum of understanding dated August 15, 2022, and that the Schedule 14D-9 described in
+detail the timing of the Company’s discussions with Parent regarding the particular transaction that is the subject of the Merger Agreement. Plaintiff Wong’s counsel stated that Wong would like to pursue discovery from defendants to address
+plaintiff’s asserted concerns regarding whether defendants intended to proceed with finalizing the settlement agreement over the past months and whether defendants had been planning the Merger for a long while. Plaintiff further asserted that
+defendants had received the benefit of a stay of proceedings in order to document a settlement, but were now continuing to seek a stay to see whether the Merger closes, resulting in Plaintiff’s loss of standing to pursue the derivative claims.
+Plaintiff also contended that no stay was currently in place in the case, and requested that the court order defendants to respond to the complaint no later than March 10, 2023. Plaintiff further reserved her rights regarding any obligations
+that defendants may have pursuant to the memorandum of understanding executed on August 15, 2022. 
+F-29 
+Table of Contents 
+On February 19, 2023, the court in the Wong action entered
+an order setting a status conference on March 2, 2023, directing the parties to be prepared to discuss the issues set forth in the joint status letter and whether the stay of the action should be continued. During the March 2, 2023 status
+conference, the parties advised the court of the status of settlement in light of the proposed Merger and took opposing positions regarding the appropriateness of the stay. The court directed the parties to submit, on or before March 8, 2023,
+simultaneous letter briefings as to whether the stay should remain in place. 
+On February 20, 2023, counsel for the plaintiff in the Chen case sent a letter to K&L Gates
+indicating that they had reviewed the Schedule 14D-9 and remained of the view that the Company is obligated to execute a settlement agreement in the case. Counsel for Chen also indicated that they were willing to continue discussions with the
+mediator in an attempt to reach an amicable resolution. 
+On March 8, 2023, the parties to the Wong action filed
+letter briefs addressing whether the December 5, 2022 stay of the Wong action should remain in place. On March 13, 2023, the court entered an order lifting the stay in the Wong action, directing the parties to meet, confer and submit a
+proposed discovery schedule to the court on or before March 20, 2023, and requiring that the defendants answer, move or otherwise respond to the complaint in the Wong action on or before April 13, 2023. 
+On March 17, 2023, the defendants in the Wong action filed
+a letter with the court advising the court that they intend to move to dismiss the complaint and requesting that the court stay discovery pursuant to the Private Securities Litigation Reform Act (“PSLRA”) pending a ruling on their anticipated
+motion to dismiss. Defendants further argued that discovery requested by plaintiff regarding the Merger and the defendants’ intent during settlement discussions is not relevant to any claims at issue in the case, and requested that the court
+adjourn the deadline to submit a discovery plan until after the motion to dismiss is decided. In response, plaintiff submitted a letter to the court in which she argued that the statutory stay does not apply to the discovery being sought or was
+waived. Plaintiff also submitted a proposed discovery plan for the court’s consideration. On March 18, 2023, the court entered an order denying the defendants’ request to adjourn the deadline to submit a proposed discovery plan and entered its
+own order requiring fact depositions to be completed on or before August 15, 2023. The court further noted that it will consider whether the statutory stay under the PSLRA applies at the time defendants file their motion to dismiss. 
+Merger Litigation 
+On February 17, 2023, a complaint was filed in the United
+States District Court, Southern District of New York, against the Company and the individual members of the Company Board and management, captioned Sholom Keller v. Chembio Diagnostics, Inc., Katherine L. Davis, John G. Potthoff, David W.K.
+Acheson, David W. Bespalko, Richard L. Eberly, Leslie Teso-Lichtman, and Lawrence J. Steenvoorden, Case No. 1:23-cv-01388 (the “New York Complaint”). 
+F-30 
+Table of Contents 
+On March 8, 2023, a pro se complaint was filed in the
+United States District Court, District of Nevada, against the Company and the individual members of the Company Board and management, captioned David S. Gross v. Chembio Diagnostics, Inc., Katherine L. Davis, John G. Potthoff, David W.K.
+Acheson, David W. Bespalko, Richard L. Eberly, Leslie Teso-Lichtman, and Lawrence J. Steenvoorden, Case No. 3:23-cv-00093 (the “Nevada Complaint, and together with the New York Complaint, the “Complaints”). 
+The Complaints asserts that the defendants violated Sections 14(d), 14(e), and 20(a)
+of the Exchange Act and certain rules and regulations promulgated thereunder by allegedly making false and misleading statements, or failing to disclose allegedly material facts necessary to make the statements made not misleading, relating
+to the Merger in the Company’s Recommendation / Solicitation Statement on Schedule 14D-9 filed with the SEC on February 14, 2023 (as amended, the “Schedule 14D-9), including allegations relating to the background of the Merger,
+financial projections, and analyses of the Company’s financial adviser, Craig-Hallum. 
+In addition to the Complaints referenced above, thirteen demand letters have been received from purported stockholders of the Company as of the date of this Annual Report, each challenging certain of the disclosures in the
+Schedule 14D-9. Additional complaints may be filed and/or demand letters may be received in connection with the Merger and the Transactions. If additional similar complaints are filed and/or demand letters received, absent new or different
+allegations that are material, the Company will not necessarily announce such additional complaints or demand letters. 
+The Company believes that the disclosures set forth in the Schedule 14D-9 comply fully with applicable laws and
+denies the allegations in the matters described above. However, in order to moot certain of the disclosure claims and avoid the costs, risks and uncertainties inherent in litigation, and provide additional information to its stockholders, the
+Company determined to voluntarily provide certain additional disclosures reflected in Amendment No. 1 to the Schedule 14D-9. Nothing in these supplemental disclosures, which also include certain supplemental disclosures unrelated to the New
+York Complaint and/or the demand letters, should be regarded as an indication that the Company or the Company’s affiliates, management, directors or other representatives, or any recipient of this information, considered or now considers the
+information contained in the supplemental disclosures to be material; rather, the Company believes that the Schedule 14D-9 as filed on February 14, 2023 disclosed all necessary information and denies that any additional disclosures are or were
+required under any federal or state law. 
+Employee Litigation 
+On March
+19, 2021, John J. Sperzel III, Chembio’s former chief executive officer, filed a fifteen -count complaint in the United States District
+Court for the Eastern District of New York. The complaint was filed following the dismissal of an action previously filed by Mr. Sperzel in the United States District Court in Maine, which was dismissed for lack of personal jurisdiction over
+Chembio. In summary, the complaint filed in the Eastern District of New York alleges that Chembio wrongfully refused to allow Mr. Sperzel to exercise certain options to purchase, for an aggregate exercise price of $ 943,126 , a total of 266,666 shares of
+common stock that were allegedly vested as of the date of his separation from Chembio, on January 3, 2020. The complaint alleges that under the terms of the applicable stock incentive plans, Mr. Sperzel had thirty days after the date on which he ceased to qualify as an “Eligible Person” under the plans within which to exercise the options, and asserts that by reason of his alleged
+continued service to Chembio, he remained an “Eligible Person” and ostensibly retained the right to exercise the options. The Compensation Committee of the Board determined that the options expired on February 3, 2020, thirty days after Mr. Sperzel’s separation from Chembio, and that a purported attempt by Mr. Sperzel to exercise the options after that date was not
+valid. 
+F-31 
+Table of Contents 
+Count I of the complaint purports to allege that Chembio breached Mr. Sperzel’s separation agreement
+by refusing to allow him to exercise the stock options. Counts II through XI of the complaint purport to allege claims for breach of each of ten 
+separate stock option agreements, collectively asserting damages of “at least” $ 3,190,198 . Count XII of the complaint alleges a breach of
+Mr. Sperzel’s separation agreement based on Chembio’s purported failure to pay Mr. Sperzel consulting fees to which he claims to be entitled for consulting services allegedly performed following his separation. Count XIII of the complaint alleges a
+claim for breach of an implied covenant of good faith and fair dealing under Nevada common law based on the allegation that Chembio prevented Mr. Sperzel from obtaining the benefits of the stock option agreements and separation agreement. Mr.
+Sperzel alleges that he suffered damages in excess of $ 3 million as a result of the purported breach of the covenant of good faith and
+fair dealing. Count XIV of the complaint purports to assert a claim for quantum meruit, alleging that “it is reasonable for Sperzel to expect payment in exchange for ... services” he allegedly provided to Chembio and, based on allegations that upon
+his separation Mr. Sperzel was not informed as to the pending expiration of the stock options he later sought to exercise, that Chembio has been unjustly enriched. Finally, Count XV of the complaint seeks a declaratory judgment that Mr. Sperzel is
+relieved from performance under his separation agreement due to asserted material breaches of the agreement based on the allegations summarized above. The complaint seeks compensatory damages in an unspecified amount, a declaration, as described
+above, and an award of Mr. Sperzel’s costs and expenses in the litigation, including reasonable attorneys’ fees, expert costs and disbursements. The complaint requests a trial by jury. In his initial disclosures served in discovery, Mr. Sperzel
+claims entitlement to recover damages in a total amount not less than $ 10 million, together with prejudgment interest at the rate of 9 % per annum. 
+On May 20, 2021, Chembio filed
+its answer and affirmative defenses denying the material allegations of Mr. Sperzel’s complaint. All discovery in the case was completed in June 2022. On July 6, 2022, pursuant to local court rules, Chembio filed a formal notice with the District
+Court stating its intention to file a motion for summary judgment on all of Mr. Sperzel’s claims, along with a statement of facts in support thereof. Mr. Sperzel’s filed a responsive letter and factual statements on July 27, 2022, and Chembio filed
+a timely reply on August 10, 2022. On August 16, 2022, the Court held a pre-motion status conference, during which the Court directed the parties to confer regarding the renewal of settlement discussions. The parties subsequently engaged in a
+formal mediation conference before a neutral, private mediator on October 25, 2022, and have continued their settlement discussions into 2023. The Court has entered an Order providing for the filing of Chembio’s summary judgment motion, any
+opposition, and reply, by May 4, 2023. At this stage of the litigation, the Company is not able to predict the probability of a favorable or unfavorable outcome. 
+Other 
+From time to time the Company may become involved in legal proceedings or may be subject to claims arising in the ordinary
+course of its business. Although the results of litigation and claims cannot be predicted with certainty, the Company currently believes that the final outcome of these ordinary course matters will not have a material adverse effect on its
+business, operating results, financial condition or cash flows. Regardless of the outcome, litigation can have an adverse impact on the Company because of defense and settlement costs, diversion of management resources, and other factors. 
+Nasdaq Communications 
+On April 5, 2022, the Company received notification from the Listing Qualifications Department of The Nasdaq Stock Market, or Nasdaq, stating that the Company did not comply with the minimum $ 1.00 bid price requirement for continued listing set forth in Nasdaq Listing Rule 5550(a)(2) (the “Bid Price Requirement”). In accordance with Nasdaq listing rules, the Company
+was afforded 180 calendar days (until October 3, 2022) to regain compliance with the Bid Price Requirement. On October 4, 2022, the
+Company received written notice from Nasdaq stating that, although the Company had not regained compliance with the Bid Price Requirement by October 3, 2022, in accordance with Nasdaq Listing Rule 5810(c)(3)(A), the Company is eligible for an
+additional 180 calendar day period, or until April 3, 2023, to regain compliance with the Bid Price Requirement. To regain compliance,
+the closing bid price of the Company’s common stock must meet or exceed $ 1.00 per share for a minimum of ten consecutive business days during this additional 180 -day
+period, all as described in more detail in the Current Reports on Form 8-K filed with the SEC on April 7, 2022 and October 4, 2022. 
+There can be no assurance that Chembio will be able to regain compliance with the Bid Price Requirement. The Company’s
+inability to regain compliance with the Bid Price Requirement would, and the existence of the pending deficiency letter could, materially impair its ability to raise capital. Moreover, if Chembio were unable to regain compliance with the Bid Price
+Requirement, its common stock would likely then trade only in the over-the-counter market and the market liquidity of its common stock could be adversely affected and its market price could decrease. If Chembio’s common stock were to trade on the
+over-the-counter market, selling Chembio’s common stock could be more difficult because smaller quantities of shares would likely be bought and sold, transactions could be delayed, and Chembio could face significant material adverse consequences,
+including: a limited availability of market quotations for its securities; reduced liquidity with respect to its securities; a determination that its shares are a “penny stock,” which will require brokers trading in its securities to adhere to more
+stringent rules, possibly resulting in a reduced level of trading activity in the secondary trading market for its securities; a reduced amount of news and analyst coverage; and a decreased ability to issue additional securities or obtain
+additional financing in the future. These factors could result in lower prices and larger spreads in the bid and ask prices for its common stock and would substantially impair its ability to raise additional funds and could result in a loss of
+institutional investor interest and fewer development opportunities for Chembio. 
+F-32 
+Table of Contents 
+NOTE 13 — LONG-TERM DEBT: 
+On September 3, 2019, the Company entered into a Credit Agreement and Guaranty (the “Credit Agreement”) with Perceptive Credit Holdings II, LP (the “Lender”). The Credit
+Agreement provides for a $ 20,000,000 senior secured term loan credit facility, which was drawn in full on September 4, 2019. Under the
+terms of the Credit Agreement, the Company may use the proceeds (i) for general working capital purposes and other permitted corporate purposes, (ii) to refinance certain of the Company’s existing indebtedness and (iii) to pay fees, costs and
+expenses incurred in connection with the Credit Agreement, including the Lender’s closing cost amount of $ 550,000 , which was netted from
+the proceeds, and a financing fee of $ 600,000 ( 3.0 %
+of gross proceeds) payable to Craig-Hallum Capital Group LLC, the Company’s financial advisor for the financing. 
+Principal outstanding under the Credit Agreement bears interest at a rate per annum equal to the sum of (a) the greater of the one-month London Interbank Offered Rate and 2.5 % plus (b) 8.75 %. At any time at which an event of default has occurred and is continuing, the interest rate will increase by 4.0 %. Accrued interest is payable on a monthly basis. On December 31, 2022 the interest rate was 12.88 %. 
+No principal repayments were due under the Credit Agreement prior to September 30, 2022. Chembio did not elect to prepay principal and an event of default identified in
+the Credit Agreement did not occur that would have accelerated principal payments. Principal installments in the amount of $ 300,000 are
+payable on the last day of each of the eleven months from September 2022 through July 2023, and all remaining principal is payable at maturity on September 3, 2023 . 
+Chembio’s obligations under the Credit Agreement are secured by a first priority, perfected lien on substantially all of its property and assets, including its equity
+interests in subsidiaries. 
+As of December 31, 2022, the loan balance, net of unamortized discounts and debt issuance costs, was $ 18.6 million, and Chembio was in compliance with its loan covenants. 
+NOTE 14 — IMPAIRMENT, RESTRUCTURING, SEVERANCE AND RELATED COSTS: 
+Impairment, restructuring, severance and related costs include an impairment loss of $ 3.0 million during the first quarter of 2022 as a result of an impairment of goodwill due to the substantial decrease in our share price at March 31, 2022. The low price per share value at March 31, 2022 caused our
+book value to exceed our fair value. In addition, for the year ended December 31, 2022, $ 0.2 million was recorded which was related to
+severance charges. For the year ended 2021, the Company recorded an impairment loss of $ 7.0 million, of which $ 5.9 million was related to the write-off of intangible assets, net leasehold improvements, and net right-of-use assets for leases associated with our
+Malaysian operations, and $ 1.1 million was related to restructuring matters. 
+In order to address challenging economic conditions and implement its business strategy, in the first quarter of 2022 the Company continued to execute a program to
+reduce operating expenses and better align its costs with revenues, including by eliminating positions that were no longer aligned with its strategy, and recognized severance charges of $ 0.1 million. 
+F-33 
+Table of Contents 
+The table below represents the total costs by category: 
+For the year ended 
+December 31, 2022 
+For the year ended 
+December 31, 2021 
+Severance 
+$ 
+202,621 
+$ 
+83,087 
+Restructuring costs 
+- 
+1,083,951 
+Impairment 
+3,033,565 
+5,880,741 
+$ 
+3,236,186 
+$ 
+7,047,779 
+NOTE 15 — SUBSEQUENT EVENTS: 
+The Company entered into an Agreement and Plan of Merger (the “Merger Agreement”), dated as of January 31, 2023, with Biosynex SA, a French société anonyme (“Biosynex”), and Project Merci Merger Sub,
+Inc., a Nevada corporation and wholly-owned indirect subsidiary of Biosynex (the “Purchaser”). Pursuant to the Merger Agreement, on February 14, 2023, the Purchaser commenced a tender offer (the “Offer”) to purchase all of the issued and
+outstanding shares of the Company’s common stock, par value $ 0.01 per share (the “Shares”), for a purchase price of $ 0.45 per share, net to the seller in cash, without interest and subject to any required tax withholding. On March 15, 2023, Biosynex announced an
+extension of the Offer until 6:00 p.m., New York City time, on March 28, 2023. Subsequently, on March 29,2023, Biosynex announced an extension of the Offer until 6:00 p.m., New York City time, on April 12, 2023. If the conditions to the Offer are
+satisfied and the Offer closes, Purchaser would acquire all remaining Chembio shares by a merger of Purchaser with and into Chembio (the “Merger”), with Chembio surviving the Merger as a wholly-owned indirect subsidiary of Biosynex. At the
+effective time of the Merger (the “Effective Time”), each Share issued and outstanding immediately prior to the Effective Time (including shares paid to holders of vested Chembio restricted stock units) will be converted into the right to receive $ 0.45 per share. Stock options that are outstanding immediately prior to the Effective Time will automatically terminate for no consideration. 
+If the conditions to the Offer are
+satisfied and the Offer closes, Purchaser would acquire all remaining Chembio shares by a merger of Purchaser with and into Chembio (the “Merger”), with Chembio surviving the Merger as a wholly-owned indirect subsidiary of Biosynex. At the
+effective time of the Merger (the “Effective Time”), each Share issued and outstanding immediately prior to the Effective Time (including shares paid to holders of vested Chembio restricted stock units) will be converted into the right to receive
+$ 0.45 per share. Stock options that are outstanding immediately prior to the Effective Time will automatically terminate for no
+consideration. 
+The Merger Agreement and the
+transactions contemplated thereby, including the Merger, were unanimously approved by the Company’s Board of Directors. Completion of the Merger is subject to certain customary conditions as set forth in the Merger Agreement and the successful
+completion of the Offer. There can be no assurance that the Merger will be consummated on the terms described above or at all. 
+The foregoing description of the Merger
+Agreement and the transactions contemplated thereby, including the Offer, does not purport to be complete and is subject to, and qualified in its entirety by reference to, the full text of the Merger Agreement, which has been filed as Exhibit
+2.1 to our Current Report on Form 8-K filed with the SEC on January 31, 2023. 
+F-34
\ No newline at end of file
diff --git a/raw/filings/0001092662/2022/0001140361-23-014526/filing_metadata.csv b/raw/filings/0001092662/2022/0001140361-23-014526/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..b656563881ab92265c22a9ea92119990454a5704
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+0001092662,CEMI,"CHEMBIO DIAGNOSTICS, INC.",10-K,2023-03-29,2022-12-31,2023-03-29T20:06:24.000Z,0001140361-23-014526,brhc10050381_10k.htm,10-K,10872984,1,1,https://www.sec.gov/Archives/edgar/data/1092662/000114036123014526/brhc10050381_10k.htm,https://www.sec.gov/Archives/edgar/data/1092662/000114036123014526/,2022,2022,1
diff --git a/raw/filings/0001092662/2022/0001140361-23-014526/item1.txt b/raw/filings/0001092662/2022/0001140361-23-014526/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..2d4443e4b4d78969a16a4619ce673c62deb2d719
--- /dev/null
+++ b/raw/filings/0001092662/2022/0001140361-23-014526/item1.txt
@@ -0,0 +1,546 @@
+ITEM 1. 
+BUSINESS 
+Overview 
+Chembio Diagnostics, Inc. (“Chembio”) and its subsidiaries (collectively with Chembio, the “Company”) develop and commercialize point-of-care tests used to detect and diagnose infectious diseases, including
+sexually transmitted disease, insect vector and tropical disease, COVID-19 and other viral and bacterial infections, enabling expedited treatment. 
+The Company’s product portfolio is based upon our proprietary DPP technology, a diagnostic platform that provides high-quality, cost-effective results in 15 to 20 minutes using fingertip blood, nasal swabs and
+other sample types. The DPP technology platform addresses the rapid diagnostic test market, which includes infectious diseases such as sexually transmitted infections and HIV, and Women’s Health. Compared with traditional lateral flow technology,
+the DPP technology platform can provide: 
+• 
+Enhanced sensitivity and specificity: This is achieved via the Company’s proprietary approach to separating the sample path from the buffer path, together with patent and other proprietary strategies, which differ significantly
+from traditional lateral flow test. 
+• 
+Advanced multiplexing capabilities: Through advanced multiplexing, the DPP platform can detect and differentiate up to eight distinct test results from a single patient sample, which can deliver greater clinical value than other rapid
+tests currently on the market. 
+• 
+Objective results: For some diagnostic applications, the Company’s easy-to-use, highly portable, battery-operated DPP Micro Reader optical analyzers can report accurate results in approximately 15 seconds, making it well-suited for
+decentralized testing where real-time results enable patients to be clinically assessed while they are still on site. Objective results produced by the DPP Micro Reader can reduce the possibility of the types of human error that can be
+experienced in the visual interpretations required by many rapid tests. 
+3 
+Table of Contents 
+The Company targets the market for rapid diagnostic test solutions for infectious diseases, which is driven by the high prevalence of infectious diseases globally, an increase in the geriatric population, growing
+demand for rapid test results, and advancements in multiplexing. The Company has a broad portfolio of infectious disease products, which prior to 2020 were focused principally on sexually transmitted disease and fever and tropical disease. In
+February 2020 the Company began the process to leverage the DPP technology platform to address the acute and escalating need for diagnostic testing. The Company is continuing to pursue or has pursued: 
+• 
+a 510(k) clearance from the U.S. Food and Drug Administration, (the "FDA") for the DPP SARS-CoV-2 Antigen test system; 
+• 
+an Emergency Use Authorization (“EUA”) from the FDA for the DPP Respiratory Antigen Panel; and 
+• 
+a Clinical Laboratory Improvement Amendment (“CLIA”), waiver from the FDA for the DPP HIV-Syphilis test system, which was received in February 2023. 
+For additional information about our existing and proposed product offerings, please see “—Products” below. Our products are sold globally, directly and through distributors, to medical laboratories and hospitals,
+governmental and public health entities, nongovernmental organizations, medical professionals, and retail establishments. We continue to seek to expand our commercial distribution channels. 
+Pending Merger with Biosynex SA 
+The Company entered into an Agreement and Plan of Merger (the “Merger Agreement”), dated as of January 31, 2023, with Biosynex SA, a French société anonyme (“Biosynex”), and Project Merci Merger Sub, Inc., a Nevada
+corporation and wholly-owned indirect subsidiary of Biosynex (the “Purchaser”). Pursuant to the Merger Agreement, on February 14, 2023, the Purchaser commenced a tender offer (the “Offer”) to purchase all of the issued and outstanding shares of
+the Company’s common stock, par value $0.01 per share (the “Shares”), for a purchase price of $0.45 per share, net to the seller in cash, without interest and subject to any required tax withholding. On March 15, 2023, Biosynex announced an
+extension of the Offer until 6:00 p.m., New York City time, on March 28, 2023. Subsequently, on March 29, 2023, Biosynex announced an extension of the Offer until 6:00 p.m., New York City time, on April 12, 2023. 
+If the conditions to the Offer are satisfied and the Offer closes, Purchaser would acquire all remaining Chembio shares by a merger of Purchaser with and into
+Chembio (the “Merger”), with Chembio surviving the Merger as a wholly-owned indirect subsidiary of Biosynex. At the effective time of the Merger (the “Effective Time”), each Share issued and outstanding immediately prior to the Effective Time
+(including shares paid to holders of vested Chembio restricted stock units) will be converted into the right to receive $0.45 per share. Stock options that are outstanding immediately prior to the Effective Time will automatically terminate for
+no consideration. 
+The Merger Agreement and the transactions contemplated thereby, including the Merger, were unanimously approved by the Company’s Board of Directors. Completion of the Merger is subject to certain customary
+conditions as set forth in the Merger Agreement and the successful completion of the Offer. There can be no assurance that the Merger will be consummated on the terms described above or at all. 
+The foregoing description of the Merger Agreement and the transactions contemplated thereby, including the Offer, does not purport to be complete and is subject to, and qualified in its entirety by reference to,
+the full text of the Merger Agreement, which has been filed as Exhibit 2.1 to our Current Report on Form 8-K filed with the SEC on January 31, 2023. 
+Likely Default Under Credit Agreement 
+On September 3, 2019, we and certain of our subsidiaries, as guarantors, entered into the Credit Agreement and Guaranty (the “Credit Agreement”) with Perceptive
+Credit Holdings II, LP (the “Lender”), under which we received a $20.0 million senior secured term loan that was drawn in full on September 4, 2019. The Credit Agreement is secured by a first priority lien on substantially all of our property
+and assets. The Credit Agreement contains financial covenants requiring that we (a) maintain aggregate unrestricted cash of not less than $3.0 million at all times, and (b) achieve specified minimum total revenue requirements for the twelve
+months preceding each quarter end. 
+The Credit Agreement has a September 3, 2023 maturity date, and we do not currently believe that replacement debt or equity financing arrangements are
+or will be available to us or, if available to us, will be on acceptable terms. We do not believe that we will be in compliance with the minimum revenue covenant in the Credit Agreement for the four fiscal quarters ended March 31, 2023. Our
+Lender has previously informed us that it will not agree to any restructuring of the Credit Agreement, and as a result we may be forced to pursue a bankruptcy or restructuring proceeding when the debt matures (or earlier if the lender
+accelerates following a breach of the minimum total revenue covenant) or pursue a transaction or financing arrangement that could be dilutive to stockholders. 
+Operating Results and Working Capital 
+Total revenues were $49.5 million, an increase of 3.6% from 2021, and net product sales were $47.1 million, an increase of 35.6% from 2021. Our loss from operations was $23.6 million in 2022 compared to $31.1
+million in 2021. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Consolidated Results of Operations.” 
+4 
+Table of Contents 
+In 2022 we continued to invest in automating our test manufacturing processes, most of which are now based in the United States. Among other actions, we expanded our manufacturing capabilities by validating and
+implementing automated lines. Our transition from manual to automated assembly is intended to add capacity, reduce variable costs and improve product margins. In order to address challenging economic conditions and implement our business
+strategy, we continued to execute a program to reduce operating expenses and better align our costs with revenues by eliminating positions that were no longer aligned with our strategy. Our cash and cash equivalents totaled $18.2 million at
+December 31, 2022, compared to $28.8 million at December 31, 2021. 
+The Company’s future working capital needs will depend on many factors, including the rate of its business and revenue growth, its ability to achieve operating profitability, the availability and cost of human,
+material and other resources required to build and deliver products in accordance with its existing or future product orders, the timing of its continuing automation of manufacturing, and the timing of its investment in research and development
+as well as sales and marketing. If the Company is unable to increase its revenues and manage its expenses in accordance with its operating plan, it may need to reduce the level or slow the timing of the growth plans contemplated by its operating
+plan, which would likely curtail or delay the growth in its business contemplated by its operating plan and could impair or defer its ability to achieve profitability and generate cash flow, or to seek to raise additional funds through debt or
+equity financing, strategic relationships, or other arrangements. All DPP tests are developed and manufactured in the United States and are the subject of a range of domestic and global patents and patents pending. 
+Going Concern Considerations 
+The Company continued to experience market, clinical trial and regulatory complications in seeking to develop and commercialize a portfolio of
+COVID-19 test systems during the continuing, but evolving, uncertainty resulting from COVID‑19. For the year ended December 31, 2022, the Company also continued to incur significant operating
+losses and significant expenses in connection with pending legal matters (see Note 12 – Commitments, Contingencies, and Concentrations: Litigation). 
+The Company performed an assessment to determine whether there were conditions or events that, considered in the aggregate, raised substantial doubt
+about the Company’s ability to continue as a going concern within one year after the filing date of this report, when the accompanying financial statements are being issued. Initially, this assessment did not consider the potential mitigating
+effect of management’s plans that had not been fully implemented. Because, as described below, substantial doubt was determined to exist as the result of this initial assessment, management then assessed the mitigating effect of its plans to
+determine if it is probable that the plans (1) would be effectively implemented within one year after the filing date of this report, when the accompanying financial statements are being issued and (2) when implemented, would mitigate the
+relevant conditions or events that raise substantial doubt about the Company’s ability to continue as a going concern. 
+The Company achieved revenue growth in recent years while profitability has not been at levels as expected. It has taken steps including investments
+in automation to mitigate headwinds such as labor availability, volatile capacity planning and implementation of operational efficiency targets to proactively monitor production with the overarching goal of profitable growth. The Company
+undertook measures to increase its total revenues and improve its liquidity position by continuing to develop the Global Competitiveness Program. The main pillars of the Global Competitiveness Program include the following: 
+• 
+Focus on higher margin business in growth markets 
+• 
+Lower manufacturing costs 
+• 
+Reduce infrastructure costs 
+• 
+Strategic review of non-core businesses and assets 
+The Company’s execution of its plans continue to depend, however, on factors and uncertainties that are beyond the Company’s control, or that
+may not be addressable on terms acceptable to the Company or at all. The Company considered in particular how: 
+5 
+Table of Contents 
+• 
+The ongoing healthcare and economic impacts of COVID-19 on the global customer base for the Company’s non‑COVID-19 products continue to negatively affect the
+timing and rate of recovery of the Company’s revenues from those products. 
+The Company further considered how these factors and uncertainties could impact its ability over the next year to meet the obligations specified in
+the Credit Agreement with the Lender. Those obligations include covenants requiring: i) minimum cash balance of $3.0 million and ii) minimum total revenue amounts for the twelve months preceding each quarter end. The minimum total revenue
+requirements are $48.8 million for the twelve months ending March 31, 2023 and $50.1 million for the twelve months ending June 30, 2023. We do not believe that we will comply with the minimum total revenue covenant for the twelve months ended
+March 31, 2023. Upon an event of default under the Credit Agreement, the Lender could elect to declare all amounts outstanding thereunder, together with accrued interest, to be immediately due and payable. Furthermore, all remaining principal and
+interest is due on or before September 3, 2023. There can be no assurance that the Company would have sufficient liquidity to fund payment of the amounts that would be due under the Credit Agreement or that, if such liquidity were not available,
+the Company would be successful in raising additional capital on acceptable terms, or at all, or in completing any other endeavor to continue to be financially viable and continue as a going concern. The Company’s inability to raise additional
+capital on acceptable terms in the near future, whether for purposes of funding payments required under the Credit Agreement or providing additional liquidity needed for its operations, could have a material adverse effect on its business,
+prospects, results of operations, liquidity and financial condition and would likely result in the Company being forced to seek protection under a bankruptcy proceeding. 
+Accordingly, management determined the Company could not be certain that the Company’s plans and initiatives would be effectively implemented within
+one year after the filing date of this report, when the accompanying financial statements are being issued. Without giving effect to increasing product revenue in the near future, the proposed merger with Biosynex or executing other mitigating
+plans, many of which are beyond the Company’s control, it is unlikely that the Company will be able to generate sufficient cash flows to meet its required financial obligations, including its debt service and other obligations due to third
+parties. The existence of these conditions raises substantial doubt about the Company’s ability to continue as a going concern for the twelve-month period following the date on which the accompanying consolidated financial statements are being
+issued. 
+The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern, which contemplates
+continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business for the twelve-month period following the date the accompanying consolidated financial statements are issued. As such, the
+accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amounts, or the amount and classification of liabilities that may result should the
+Company be unable to continue as a going concern. 
+Industry 
+The DPP technology platform targets diagnostic disease states; (1) where rapid diagnosis impacts patient treatment and outcomes; (2) that are underserved by current diagnostic products due to performance or
+availability; (3) that present opportunities regionally, demographically or clinically. The Company is focused on test solutions associated with infectious diseases: respiratory viruses, sexually transmitted diseases, and insect-vector diseases. 
+Our product portfolio is marketed globally to NGO’s, Ministries of Health, acute care hospitals, reference labs, outpatient clinics including urgent cares and physician offices. Our branded products have achieved
+meaningful market share globally and include, SureCheck, Stat Pak and DPP. The Company will focus on internally developed products and pursue external opportunities to license novel technologies and products with the intent of leveraging
+Chembio’s growing commercial infrastructure. 
+6 
+Table of Contents 
+We currently are targeting lateral flow test solutions for infectious diseases: respiratory diseases, sexually transmitted diseases and mosquito-borne diseases. The market for lateral flow infectious disease tests
+is being driven by the high prevalence of infectious diseases globally, an increase in the elderly population, growing demand for rapid test results, and advancements in multiplexing. 
+Products 
+COVID-19 Diagnostic Test Systems 
+Prior to 2020, our broad portfolio of infectious disease products was focused principally on sexually transmitted disease and fever and tropical disease. In 2020 we shifted substantially all of our resources to
+leverage the DPP technology platform to address the acute and escalating need for diagnostic testing for COVID-19. 
+COVID-19 Antibody Test System 
+In January 2021 we announced the CE mark for both the DPP SARS-CoV-2 Antigen test system and the DPP SARS-CoV-2 IgM/IgG test system, providing regulatory approval to register and market the test systems in the
+European Union and other geographies that accept the CE mark. 
+COVID-19 Antigen Test System 
+In mid-2020 we began to focus on the development of a COVID-19 antigen test system based on DPP technology. In January 2021 we announced the CE mark for the DPP SARS-CoV-2 Antigen test system, providing regulatory
+approval to register and market the test systems in the European Union and other geographies that accept the CE mark. 
+In December 2020 we received a $12.7 million grant from the Biomedical Advanced Research and Development Authority, part of the U.S. Department of Health and Human
+Services’ Office of the Assistant Secretary for Preparedness and Response, (“BARDA”), in part to support preparation of a submission in pursuit of FDA 510(k) clearance for the DPP SARS-CoV-2 Antigen System. 
+In January 2021 the FDA notified us that it was declining to review the DPP SARS-CoV-2 Antigen System based on its updated prioritization guidance, under which review of the system was not a priority. 
+During the year ended December 31, 2021 we performed the clinical trials and on December 2, 2021 we submitted the DPP SARS‑CoV‑2 Antigen test system to the FDA, as a de Novo submission. We are in interactive review
+process with the FDA. 
+COVID-19 and Influenza Respiratory Antigen Panel Test System 
+In the fourth quarter of 2020 we began developing a rapid, multiplex respiratory antigen panel point-of-care test system using DPP technology. BARDA designated a portion of its $12.7 million grant in December 2020
+for use to support our development, submission and receipt of an EUA for this system. 
+During 2021, we developed and conducted clinical trials of the DPP Respiratory Antigen Panel, a test system being designed to provide simultaneous, discrete and differential detection of Influenza A, Influenza B
+and SARS-CoV-2 antigens from a single patient respiratory specimen, such as a nasal swab. As of December 31, 2021, we have submitted a request for the EUA approval by the FDA which in 2022, we were notified by the FDA that our request for EUA was
+no longer under review. In addition, in 2021 we submitted a request for approval to ANVISA in Brazil and CE in Europe, which was approved in 2022. 
+As a result, we earned $12.5 million of the $12.7 million available under the BARDA Agreement, dated December 2, 2020, with the remaining $0.2 million having not been earned because it was contingent on our
+receiving an emergency use authorization for the DPP SARS-CoV-2 Antigen by December 2, 2021. 
+HIV-Syphilis Diagnostic Test Systems 
+On February 23, 2023 we received notice from the FDA that we were granted Clinical Laboratory Improvement Amendment, or "CLIA", waiver for the DPP HIV-Syphilis test system. 
+7 
+Table of Contents 
+Core Products 
+We have obtained FDA approvals and, directly or through our partners, international regulatory approvals for infectious disease tests as follows: 
+Product 
+U.S. 
+International 
+DPP COVID-19 IgM/IgG System 
+✓ 
+DPP SARS-CoV-2 IgM/IgG System 
+✓ 
+DPP SARS-CoV-2 Antigen 
+✓ 
+DPP HIV 1/2 Assay 
+✓ 
+✓ 
+DPP HIV-Syphilis System 
+✓ 
+✓ 
+DPP Syphilis Screen & Confirm Assay 
+✓ 
+DPP ZCD IgM/IgG System 
+✓ 
+DPP Dengue NS1 Antigen System 
+✓ 
+DPP Dengue IgM/IgG System 
+✓ 
+DPP Zika IgM System 
+✓ 
+✓ 
+DPP Zika IgM/IgG System 
+✓ 
+DPP Chikungunya System 
+✓ 
+DPP Ebola Antigen System 
+✓ EUA 
+DPP Leishmaniasis Assay 
+✓ 
+DPP Respiratory Antigen Panel 
+✓ 
+DPP VetTB Assay 
+✓ 
+HIV 1/2 STAT-PAK Assay 
+✓ 
+✓ 
+Chagas STAT-PAK Assay 
+✓ 
+SURE CHECK HIV 1/2 Assay 
+✓ 
+✓ 
+SURE CHECK HIV Self-Test 
+✓ 
+Organic growth in our core infectious disease business is being driven by: 
+• 
+growth in the overall market for point of care infectious disease tests; 
+• 
+our increased market penetration in existing markets and channels, including in the United States, Latin America, Africa and Europe; 
+• 
+our registration of existing and new products in unchartered countries and regions, such as selected countries in Latin America and Southeast Asia; 
+• 
+our entry into new market segments, such as respiratory tests and international HIV Self-Testing; and 
+• 
+advances in our product pipeline in infectious disease with key products including tests for COVID-19, a multiplex test for HIV and syphilis in the U.S. market and tests for dengue, zika and chikungunya. 
+We market and sell both stand-alone and multiplex tests for sexually transmitted infectious diseases, such as HIV and syphilis, which continue to be major global public health issues. According to WHO estimates: 
+• 
+HIV has claimed more than 40 million lives, including 650,000 in 2021. Approximately 38.4 million people were living with HIV at the end of 2021, and 1.5 million were newly infected during 2021. 
+We are seeking to address the global concerns related to HIV and syphilis co-infection through the development of a novel, multiplex test for both HIV and syphilis. We have developed a DPP HIV-Syphilis multiplex
+test and received regulatory approvals in the United States and a number of international markets, including Brazil, Europe, Africa, Malaysia and Mexico. Approval of a CLIA waiver for the DPP HIV-Syphilis test in the United States was received in
+February 2023. 
+We also market and sell tests for selected fever and tropical diseases such as Chagas, Ebola, leishmaniasis and Zika. The market for lateral flow mosquito-borne diseases includes established markets for disease
+such as dengue and malaria, which WHO estimates together account for more than 600 million annual infections worldwide. There are also a number of emerging markets for rapid point of care tests for infectious diseases such as burkholderia,
+chikungunya, lassa, leptospirosis, Marburg, rickettsia and Zika. 
+We have received funding from some of the world’s leading health organizations, which has helped us accelerate the expansion of our pipeline of infectious disease tests. Our collaborators have included Bill &
+Melinda Gates Foundation, The Paul G. Allen Family Foundation, The Oswaldo Cruz Foundation or FIOCRUZ, and the Foundation for Innovative New Diagnostics, or FIND, as well as U.S. government agencies such as Centers for Disease Control and
+Prevention, or ("CDC"), BARDA, and the U.S. Department of Agriculture, or USDA. 
+8 
+Table of Contents 
+Several tests in our infectious disease pipeline are approaching commercialization, and several have received initial regulatory approvals: 
+Product 
+Collaborator 
+Phase I 
+Feasibility 
+Phase II 
+Development 
+Phase III 
+Verification & 
+Validation 
+Phase IV 
+Clinical & 
+Regulatory 
+Phase V 
+Commercial 
+Launch 
+DPP HIV-Syphilis System (US) 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CLIA Waived 
+DPP Dengue IgM/IgG System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP Dengue NS1 Antigen System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA pending 
+DPP Chikungunya IgM/IgG System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP Zika Chikungunya Dengue IgM/IgG System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP Ebola Antigen System 
+CDC 
+✓ 
+✓ 
+✓ 
+✓ 
+FDA-EUA 
+DPP Fever Assay Asia 
+FIND 
+✓ 
+✓ 
+✓ 
+✓ 
+DPP Fever Assay Africa 
+Paul Allen Foundation 
+✓ 
+✓ 
+✓ 
+DPP Fever Assay Malaysia 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+DPP SARS CoV-2 Antigen 
+BARDA 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP Respiratory Antigen Panel 
+BARDA 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP COVID-19 IgM/IgG System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE and ANVISA 
+DPP SARS CoV-2 IgM/IgG System 
+Self-funded 
+✓ 
+✓ 
+✓ 
+✓ 
+CE 
+Sales Channels 
+Our products are sold globally, both directly and through distributors, to hospitals and clinics, physician offices, clinical laboratories, public health organizations, government agencies and consumers.
+Historically we marketed and sold our products only into a handful of countries and regions. During 2022, we expanded our U.S.-based sales, customer service, and marketing team to focus on the COVID-19, HIV-Syphilis, and future DPP platform
+product opportunities. With sales growth as an underlying objective, we are focused on increasing sales in geographies that support higher average selling prices. From lead generation through technical inquiries, Chembio has the internal
+resources to support customers through the commercial process including marketing, sales, sales support, order entry and product support. 
+Automation of U.S. Manufacturing 
+We are automating our U.S. manufacturing processes and expanding our manufacturing capacity. Over the past four years, we have taken delivery of and completed validation of most of our automated manufacturing
+lines. These use vision-guided, robotic operation to improve inspection and quality control. As we transition from manual to automated assembly, we believe the reduced variable costs will improve product gross margins. 
+9 
+Table of Contents 
+DPP Technology & Development 
+Our commercially available products employ either our patented DPP technology or traditional lateral flow technology. We believe products developed using our DPP technology can provide superior diagnostic
+performance compared with products that utilize traditional lateral flow technology. 
+Chembio’s history of collaborations have proven the strength and capabilities of the DPP platform to address a diverse range of biomarkers. We are now focusing our R&D resources on developing Chembio’s new and
+expanded product portfolio focused on high average selling price, developed markets, established sales channels, and clinically accepted use cases, where the differentiated capabilities of DPP provide a competitive advantage. 
+Competition 
+Many of our competitors are significantly larger and have greater financial, research, manufacturing, and marketing resources. Important competitive factors include product quality, analytical performance, ease of
+use, price, customer service and reputation. Industry competition is based on these and the following additional factors: 
+• 
+patent protection; 
+• 
+scientific expertise; 
+• 
+ability to develop and market products and processes; 
+• 
+ability to obtain required regulatory approvals; 
+• 
+ability to manufacture cost-effective products that meet applicable regulatory requirements; 
+• 
+access to adequate capital; and 
+• 
+ability to attract and retain qualified personnel. 
+We believe our scientific capabilities and proprietary know-how relating to our patented DPP technology and lateral flow technology are very strong, particularly for the development and manufacture of tests for the
+detection of infectious and other diseases. 
+Although we have no specific knowledge of any other competitors’ products that could render our products obsolete, if we fail to maintain and enhance our competitive position or fail to introduce new products and
+product features, our customers may decide to use the products developed by our competitors, which could result in a loss of revenues and cash flow. 
+Human Capital 
+As of December 31, 2022, we had 188 full-time equivalent employees, of whom 20 were in administration, 127 were in manufacturing, 23 were in research and development, and 18 were in sales and marketing and customer
+service. Of these employees, approximately 151 were located in the United States, 17 were located in Germany and 20 were located in Brazil. We have never had a work stoppage, and none of our employees are represented by a labor organization or
+subject to any collective bargaining arrangements. We consider our employee relations to be good. 
+Our employees are one of our most important assets and set the foundation for our ability to achieve our strategic objectives, drive operational execution, deliver strong financial performance, advance innovation
+and maintain our quality and compliance programs. The success and growth of our business depends in large part on our ability to attract, retain and develop a diverse population of talented and high-performing employees at all levels of our
+organization. 
+Health, Wellness and Safety 
+The health, wellness and safety of our employees is a priority embedded at every level of our business. We provide our employees upfront and ongoing safety training to ensure that safety policies and procedures
+are effectively communicated and implemented. Personal protective equipment is provided to those employees where needed for the employee to safely perform their job function. 
+Since 2020, in response to the COVID-19 pandemic, we implemented safety protocols and new procedures to protect our employees, including more frequent deep cleaning of the facilities, social distancing and onsite
+COVID-19 testing. 
+10 
+Table of Contents 
+Workforce Stability 
+Retaining and developing our employees is an important factor in our continued success and growth. We regularly evaluate our employee retention and turnover rates. 
+Compensation and Benefits 
+To succeed in a competitive labor market, we have recruitment and retention strategies that we focus on as part of the overall management of our business, including designing our compensation and benefits programs
+to be competitive and align with our strategic and stockholders’ interests. Some of our key employee benefits include eligibility for health insurance, vacation time, a retirement plan, an employee assistance program, life and disability
+coverage. We also have procedures and processes focused on providing employees equitable compensation, regardless of race or gender or other personal characteristics. 
+Governmental Regulation 
+Certain of our activities are subject to regulatory oversight by the FDA under provisions of the Federal Food, Drug, and Cosmetic Act and regulations thereunder, including regulations governing the development,
+marketing, labeling, promotion, manufacturing, and export of diagnostic products. Our clinical laboratory customers are subject to oversight by Centers for Medicare and Medicaid Services, or CMS, pursuant to CLIA, as well as agencies in various
+states. Failure to comply with applicable requirements can lead to sanctions, including withdrawal of products from the market, recalls, refusal to authorize government contracts, product seizures, civil money penalties, injunctions, and criminal
+prosecution. 
+FDA Approval/Clearance Requirements 
+Unless an exemption applies, each medical device that we market or wish to market in the United States must receive 510(k) clearance or Premarket Approval, or PMA. Medical devices that receive 510(k) clearance are
+“cleared” by the FDA to market, distribute, and sell in the United States. Medical devices that obtain a PMA by the FDA are “approved” to market, distribute and sell in the United States. We cannot be certain that 510(k) clearance or PMA approval
+will ever be obtained for any products that have not already obtained 510(k) clearance or PMA approval. Descriptions of the PMA and 510(k) clearance processes are provided below. 
+The FDA decides whether a device line must undergo either the 510(k) clearance or PMA based on statutory criteria that utilize a risk-based classification system. PMA is the FDA process of scientific and regulatory
+review to evaluate the safety and effectiveness of Class III medical devices and, in many cases, Class II medical devices. Class III devices are those that support or sustain human life, are of substantial importance in preventing impairment of
+human health, or which present a potential, unreasonable risk of illness or injury. The FDA uses these criteria to decide whether a PMA or a 510(k) is appropriate, including the level of risk that the agency perceives is associated with the
+device and a determination by the agency of whether the product is a type of device that is similar to devices that are already legally marketed. Devices deemed to pose relatively less risk are placed in either Class I or II. In many cases, the
+FDA requires the manufacturer to submit a 510(k) requesting clearance (also referred to as a premarket notification), unless an exemption applies. The 510(k) must demonstrate that the manufacturer’s proposed device is “substantially equivalent”
+in intended use and in safety and effectiveness to a legally marketed predicate device. A “predicate device” is a pre-existing medical device to which equivalence can be drawn, that is either in Class I or Class II or is a Class III device that
+was in commercial distribution before May 28, 1976, for which the FDA has not yet called for submission of a PMA application. 
+Device classification depends on the device’s intended use and its indications for use. In addition, classification is risk-based, that is, the risk the device poses to the patient and/or the user is a major factor
+in determining the class to which it is assigned. Class I includes devices with the lowest risk and Class III includes those with the greatest risk. 
+11 
+Table of Contents 
+Class I devices are those for which safety and effectiveness can be assured by adherence to the FDA’s general regulatory controls for medical devices, or the General
+Controls, which include compliance with the applicable portions of the FDA’s quality system regulations, facility registration and product listing, reporting of adverse medical events, and appropriate, truthful and non-misleading labeling,
+advertising, and promotional materials. Some Class I devices also require premarket clearance by the FDA through the 510(k) process described below. 
+Class II devices are subject to the FDA’s General Controls, and any other special controls as deemed necessary by the FDA to ensure the safety and effectiveness of the
+device. Premarket review and clearance by the FDA for Class II devices is accomplished through the 510(k) process. Pursuant to the Medical Device User Fee and Modernization Act of 2002, unless a specific exemption applies, 510(k) submissions are
+subject to user fees. Certain Class II devices are exempt from this premarket review process. 
+Class III includes devices with the greatest risk. Devices in this class must meet all of the requirements in Classes I and II. In addition, Class III devices cannot be
+marketed until they receive Premarket Approval. 
+The safety and effectiveness of Class III devices cannot be assured solely by the General Controls and the other requirements described above. These devices require formal clinical studies to demonstrate safety and
+effectiveness. Under the Medical Device User Fee and Modernization Act of 2002, PMA applications (and supplemental premarket approval applications) are subject to significantly higher user fees than 510(k) applications, and they also require
+considerably more time and resources. 
+Premarket Approval Pathway 
+We manufacture, market and distribute three rapid HIV tests in the United States. Our HIV 1/2 STAT-PAK Assay, SURE CHECK HIV 1/2 Assay, and DPP HIV 1/2 Assay all have received FDA PMA approval. A PMA application
+must be supported by extensive data including, but not limited to, analytical, preclinical, clinical trials, manufacturing, statutory preapproval inspections, and labeling to demonstrate to the FDA’s satisfaction the safety and effectiveness of
+the device for its intended use. Before a PMA is submitted, a manufacturer must apply for an Investigational Device Exemption (“IDE”). If the device presents a “significant risk,” as defined by the FDA, to human health, the FDA requires the
+device sponsor to file an IDE application with the FDA and obtain IDE approval prior to initiation of enrollment of human subjects for clinical trials. The IDE provides the manufacturer with a legal pathway to perform clinical trials on human
+subjects where without the IDE, only approved medical devices may be used on human subjects. 
+The IDE application must be supported by appropriate data, such as analytical, animal and laboratory testing results, manufacturing information, and an Investigational Review Board, or IRB approved protocol showing
+that it is safe to test the device in humans and that the testing protocol is scientifically sound. If the clinical trial design is deemed to have “non-significant risk,” the clinical trial may be eligible for “abbreviated” IDE requirements. In
+some instances, clinical trials for in vitro diagnostic medical devices may be exempt from the more burdensome IDE requirements if certain labeling requirements are met. 
+A clinical trial may be suspended by either the FDA or the Investigational Review Board at any time for various reasons, including a belief that the risks to the study participants outweigh the benefits of
+participation in the study. Even if a study is completed, clinical testing results may not demonstrate the safety and efficacy of the device, or they may be equivocal or otherwise insufficient to obtain approval of the product being tested. After
+the clinical trials have been completed, if at all, and the clinical trial data and results are collected and organized, a manufacturer may complete a PMA application. 
+12 
+Table of Contents 
+After a PMA application is sufficiently complete, the FDA will accept the application and begin an in-depth review of the submitted information. By statute, the FDA has 180 days to review the “accepted
+application,” although, generally, review of the application can take between one and three years, but it may take significantly longer. During this review period, the FDA may request additional information or clarification of information already
+provided. Also, during the review period, an advisory panel of experts from outside the FDA may be convened to review and evaluate the application and provide recommendations to the FDA as to the approvability of the device. The preapproval
+inspections conducted by the FDA include an evaluation of the manufacturing facility to ensure compliance with the FDA’s quality systems regulations or QSR, as well as inspections of the clinical trial sites by the Bioresearch Monitoring group to
+evaluate compliance with good clinical practice and human subject protections. New PMA applications or PMA supplements are required for modifications that affect the safety or effectiveness of the device, including, for example, certain types of
+modifications to the device’s indication for use, manufacturing process, labeling and design. Significant changes to an approved PMA require a 180-day supplement, whereas less substantive changes may utilize a 30-day notice, or a 135-day
+supplement. Premarket approval supplements often require submission of the same type of information as a premarket approval application, except that the supplement is limited to information needed to support any changes from the device covered by
+the original premarket approval application, and it may not require as extensive clinical data or the convening of an advisory panel. 
+Our HIV 1/2 STAT-PAK Assay PMA application number BP050009/0 and our SURE CHECK 1/2 HIV Assay PMA application number BP050010/0 were approved by the FDA in May 2006. Our DPP HIV 1/2 Assay PMA application number
+BP120032/0 was approved by the FDA in December 2012. Our DPP HIV Syphilis Assay PMA application number BP180191/0 was approved by the FDA in October 2020. 
+510(k) Clearance Pathway 
+We are currently developing products that either will or are likely to require an FDA 510(k) clearance. We anticipate submitting a 510(k) for each such product to demonstrate that such proposed device is
+substantially equivalent to a previously cleared 510(k) device or a device that was in commercial distribution before May 28, 1976, for which the FDA has not yet called for the submission of a 510(k). The FDA’s 510(k) clearance pathway usually
+takes from three to twelve months but could take longer. In some cases the FDA may require additional information, including clinical data, to make a determination regarding substantial equivalence. 
+If a device receives 510(k) clearance, any modification that could significantly affect its safety or effectiveness, or that would constitute a new or major change in its intended use, will require a new 510(k)
+clearance or, depending on the modification, a PMA. The FDA requires each device manufacturer to determine whether the proposed change requires submission of a new 510(k) or a PMA, but the FDA can review any such decision and, if it disagrees
+with the manufacturer’s determination, can require the manufacturer to cease marketing and/or recall the modified device until 510(k) clearance or PMA of the modified device is obtained. 
+Clinical Laboratory Improvement Amendments of 1988 
+A manufacturer of a test categorized as moderately complex may request that categorization of the test be waived through a CLIA Waiver by Application, or CW, submission to the FDA. When a test is categorized as
+waived, it may be performed by laboratories with a Certificate of Waiver, such as a physician’s office outreach setting. In a CW submission, the manufacturer provides evidence to the FDA that a test meets the CLIA statutory criteria for waiver
+CLIA, a walk-in clinic or an emergency room provides CMS authority over all laboratory testing, except research that is performed on humans in the United States. The Division of Laboratory Services, within the Survey and Certification Group under
+the CMS, has the responsibility for implementing the CLIA program. 
+The CLIA program is designed to establish quality laboratory testing by ensuring the accuracy, reliability and timeliness of patient test results. Under CLIA, a laboratory is a facility that does laboratory testing
+on specimens derived from humans and used to provide information for the diagnosis, prevention or treatment of disease, or impairment of, or assessment of health. Under the CLIA program, unless waived, laboratories must be certified by the
+government, satisfy governmental quality and personnel standards, undergo proficiency testing, be subject to inspections and pay fees. We have received a CLIA waiver for all of our lateral flow rapid HIV tests that we market in the United States.
+Specifically, the CLIA waiver was granted by the FDA for HIV 1/2 STAT-PAK in November 2006, for SURE CHECK HIV 1/2 in October 2007, DPP HIV 1/2 in October 2014 and DPP HIV-Syphilis in February 2023. 
+13 
+Table of Contents 
+Emergency Use Authorizations (EUA) 
+A formal request to issue an EUA generally should not be submitted until the Secretary of HHS has issued an EUA declaration under section 564(b)(1). In particular, although section 564 allows FDA to issue an EUA
+for preparedness purposes, in such cases the HHS Secretary must first declare that circumstances exist justifying such an authorization in advance of an actual emergency based on a formal determination of a significant potential for emergency or
+a material threat determination. During the effective period of the HHS Secretary’s EUA declaration, FDA may authorize the introduction of a medical product into interstate commerce when the product is intended for use during an actual or
+potential emergency. EUA candidate products include medical products and uses that are not approved, cleared, or licensed under sections 505, 510(k), and 515 of the FD&C Act or section 351 of the PHS Act. 
+After the requisite determination and declaration have been issued, and after feasible and appropriate consultations, FDA may issue an EUA only if FDA concludes that the following four statutory criteria for
+issuance have been met for 1) Serious or Life-Threatening Disease or conditions, 2) evidence of effectiveness, 3) Risk –Benefit Analysis, 4) No Alternatives. A sponsor seeking an EUA can submit its formal request in the form of an EUA
+submission, which includes data for clinical studies, non-clinical laboratory studies to assess the safety and effectiveness of the product as well as the discussion of Risks and Benefits of the product. 
+FDA will specify the effective date of an EUA issued under section 564. In general, an EUA will remain in effect for the duration of the EUA declaration under which it was issued which describes termination of an
+EUA declaration and its impact on existing EUAs. 
+Pervasive and Continuing FDA Regulation 
+A host of regulatory requirements apply to our approved devices, including: the quality system regulation, which requires manufacturers to follow elaborate design, testing, control, documentation and other quality
+assurance procedures; the Medical Reporting Regulations, which require manufacturers to report to the FDA specified types of adverse events involving their products; labeling regulations; and the FDA’s general prohibition against promoting
+products for unapproved or “off-label” uses. Some Class II devices are subject to special controls-such as performance standards, post-market surveillance, patient registries, and FDA guidelines-that do not apply to Class I devices. 
+The regulatory requirements that apply to our approved products classified as medical devices include: 
+• 
+product listing and establishment registration, which helps facilitate FDA inspections and other regulatory action; 
+• 
+QSR, which require manufacturers, including third-party manufacturers, to follow stringent design, testing, control, documentation and other quality assurance procedures during all aspects of the development and manufacturing process; 
+• 
+labeling regulations and FDA prohibitions against the promotion of products for uncleared, unapproved or off-label use or indication; 
+• 
+clearance of product modifications that could significantly affect safety or efficacy or that would constitute a major change in intended use of one of our cleared devices; 
+• 
+approval of product modifications that affect the safety or effectiveness of one of our cleared devices; 
+• 
+medical device reporting regulations, which require that manufacturers comply with FDA requirements to report if their device may have caused or contributed to a death or serious injury, or has malfunctioned in a way that would likely
+cause or contribute to a death or serious injury if the malfunction of the device or a similar device were to recur; 
+• 
+post-approval restrictions or conditions, including post-approval study commitments; 
+• 
+post-market surveillance regulations, which apply when necessary to protect the public health or to provide additional safety and effectiveness data for the device; 
+• 
+the FDA’s recall authority, whereby it can ask, or under certain conditions order, device manufacturers to recall from the market a product that is in violation of governing laws and regulations; 
+• 
+regulations pertaining to voluntary recalls; and 
+• 
+notices of corrections or removals. 
+Our Medford, New York facility is currently registered as an establishment with the FDA. We and any third-party manufacturers are subject to announced and unannounced inspections by the FDA to determine our
+compliance with QSR and other regulations. 
+14 
+Table of Contents 
+Government Regulation of Medical Devices for Animal Subjects 
+We currently offer two veterinary devices in the United States: DPP VetTB Assay for Cervids and DPP VetTB Assay for Elephants. Diagnostic tests for animal health infectious diseases, including our veterinary
+devices for the prevention and/or treatment of animal disease, are regulated in the U.S. by the Center for Veterinary Biologics within the U.S. Department of Agriculture Animal and Plant Health Inspection Service, or APHIS, under the Virus,
+Serum, and Toxin Act of 1913. As a requirement, our veterinary devices were approved by APHIS before they could be sold in the United States. 
+The APHIS regulatory approval process involves the submission of product performance data and manufacturing documentation. Following regulatory approval to market a product, APHIS requires that each lot of product
+be submitted for review before release to customers. In addition, APHIS requires special approval to market products where test results are used in part for government-mandated disease management programs. 
+Climate Change and Environmental Laws 
+The medical device industry is increasingly becoming subject of scrutiny, stringent regulation and the demand for green, sustainable products. We are focused on monitoring these increasing requirements for
+efficient and accurate processes for hazardous substance handling, supplier disclosures, and regulatory reporting in order to comply with numerous global health and environmental regulatory requirements and restrictions. 
+We believe that we are in compliance in all material respects with all foreign, federal, state, and local environmental regulations applicable to our manufacturing facilities. The cost of ongoing compliance with
+such regulations does not have a material effect on our operations. 
+Intellectual Property 
+Intellectual Property Strategy 
+Our intellectual property strategy is to: (1) build our own intellectual property portfolio around our DPP technology and optical analyzers; (2) pursue licenses, trade secrets and know-how within the area of rapid
+point-of-care testing; and, (3) develop and acquire proprietary positions to certain reagents. 
+DPP Intellectual Property 
+We have obtained patent coverage on our DPP technology, including numerous patents in the United States, and one or more patents in Australia, Brazil, Canada, China, Columbia, Eurasia (Russia), European Union
+(fourteen European countries),Hong Kong, Israel, India, Indonesia, Japan, Korea, Malaysia, Mexico, Poland, Singapore, South Africa, Thailand, and the United Kingdom. Additional patent applications on our DPP technology are pending in the United
+States, as well as in foreign countries such as Australia, Brazil, Canada, China, the European Union, India, Indonesia, Malaysia, Mexico, Peru, Singapore and Thailand. 
+DPP technology provides us with freedom to operate and enables us to develop tests with better performance and capabilities compared with tests built on traditional lateral flow platforms. These advantages have
+allowed us to enter into multiple technology collaborations based upon DPP technology, which we believe will provide new manufacturing and marketing opportunities. We have filed additional patent applications that we believe will strengthen the
+DPP intellectual property and have also filed for patent protection for certain other point-of-care technologies or applications thereof. 
+We have also obtained patent coverage on our optical-based analyzer technology in the United States as well as in several EU countries. 
+Trademarks 
+We have filed and obtained trademarks for our company name CHEMBIO and CHEMBIO DIAGNOSTIC SYSTEMS, INC. as well as for many of our products, including DPP, SURE CHECK, STAT-VIEW, STAT-PAK, and NEXT GENERATION DPP,
+as well as for the SampleTainer and DPP Micro Reader, which are used with certain DPP products. Our trademarks have been registered in the United States and certain other countries around the world. 
+15 
+Table of Contents 
+Trade Secrets and Know-How 
+We have developed a substantial body of trade secrets and know-how relating to the development and manufacture of lateral flow and DPP-based diagnostic tests, including the sourcing and optimization of materials
+for such tests, and methods to maximize sensitivity, speed-to-result, specificity, stability and reproducibility of our tests. We possess proprietary know-how to develop tests for multiple conditions using colored particles. Our formulations
+enable long shelf lives of our rapid HIV and other tests, providing us with an important competitive advantage. 
+Rapid Diagnostic Technology and Reagent Licenses 
+We seek licenses and/or redesigns of products that we believe to be in our best interests. Because of the costs and other negative consequences of time consuming patent litigation, we often attempt to obtain a
+license on reasonable terms. The peptides used in our rapid HIV tests were licensed to us by one or more third parties. We also have licensed the antigens used in other tests including our Syphilis, Tuberculosis, Leptospirosis, Leishmaniasis and
+Chagas tests, and we may enter into other license agreements. In prior years, we concluded license agreements related to intellectual property rights owned by the United States associated with HIV-1 and a sub-license agreement for HIV-2 with
+Bio-Rad Laboratories N.A., the exclusive licensee of the Pasteur Institute’s HIV-2 intellectual property estate. 
+Available Information 
+We are required to file annual, quarterly and current reports, proxy statements and other information with the U.S. Securities and Exchange Commission. The SEC maintains a website at www.sec.gov that contains
+reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. 
+Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, proxy statements and amendments to those documents filed or furnished pursuant to Section 13(a) or 15(d) of the
+Securities Exchange Act of 1934, are also available free of charge on our website at www.chembio.com as soon as reasonably practicable after such reports are electronically filed with or furnished to the SEC. 
+Investors should note that we currently announce material information to our investors and others using filings with the SEC, press releases, public conference calls, webcasts or our website (www.chembio.com),
+including news and announcements regarding our financial performance, key personnel, our brands and our business strategy. Information that we post on our corporate website could be deemed material to investors. We encourage investors to review
+the information we post on these channels. We may from time to time update the list of channels we will use to communicate information that could be deemed material and will post information about any such change on www.chembio.com. The
+information on our website is not, and shall not be deemed to be, a part hereof or incorporated into this or any of our other filings with the SEC. 
+Corporate Information 
+Our principal executive offices are located at 3661 Horseblock Rd, Medford, New York 11763. Our telephone number is (631) 924-1135. Our website address is www.chembio.com. The information contained in, or
+accessible through, our corporate website does not constitute part of this report.
\ No newline at end of file
diff --git a/raw/filings/0001092662/2022/0001140361-23-014526/item13.txt b/raw/filings/0001092662/2022/0001140361-23-014526/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..f2c8d0750fd389bfd5706bf24e606263e28cfa53
--- /dev/null
+++ b/raw/filings/0001092662/2022/0001140361-23-014526/item13.txt
@@ -0,0 +1,41 @@
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE. 
+Procedures for Approval of Related Person Transactions 
+The board of directors reviews all transactions involving us in which any of our directors, significant stockholders and executive officers and their immediate family members are participants, in order to determine
+whether any such party has a direct or indirect material interest in the transaction. All directors and executive officers must notify us of any proposed transaction involving us in which such person has a direct or indirect material interest.
+The proposed transaction is then reviewed by either the board of directors as a whole or the audit committee, which determines whether to approve the transaction. After such review, the reviewing body approves the transaction only if it
+determines that the transaction is in, or not inconsistent with, the best interests of our company and stockholders. 
+77 
+Table of Contents 
+Conflict of Interest Policy 
+The board of directors has adopted a Conflict of Interest Policy applicable to all directors, officers, and employees of our company and our subsidiaries. 
+The Conflict of Interest Policy requires each director and executive officer, including their immediate family members, to provide written notice of any potential related-party transaction, defined by the policy to
+mirror the definition of Item 404 of Regulation S-K of the SEC (with the exception that the policy includes a monetary threshold of $100,000) to the Chair of the Board of Directors (or to the Chief Executive Officer if such transaction involves
+the Chair of the Board of Directors, or to the Chief Financial Officer if such transaction involves the Chief Executive Officer), including all information that the Chair of the Board of Directors, the Chief Executive Officer or the Chief
+Financial Officer may request. Upon receiving all relevant information, the board of directors may approve the transaction if it determines that the transaction is in the Company’s best interests and fair to us, may require modifications to the
+transaction to make it acceptable for approval, or may reject it. The board of directors may also establish guidelines for ongoing management of a specific related-party transaction. The policy requires that continuing related-party transactions
+are reviewed on at least an annual basis. Additionally, the policy requires that all directors and executive officers complete a director and officer questionnaire in connection with each of our annual proxy statements, in which they are asked to
+disclose family relationships and other related-party transactions. 
+2022 Related Person Transactions 
+Since January 1, 2022, we have not engaged in any related-party transactions in which the amount involved exceeded $100,000 and in which any of our directors or executive officers or any holder of more than 5% of
+our common stock, or any member of the immediate family of any of these persons or entities controlled by any of them, had or will have a direct or indirect material interest, other than the compensation arrangements described in “Director
+Compensation” and “Executive Compensation” of Item 11 above. It is our intention to ensure that any future transactions between us and our officers, directors and significant stockholders and their affiliates are approved by the audit committee
+and a majority of the members of the board of directors, including a majority of the independent and disinterested members of the board of directors, and are on terms no less favorable to us than those that we could obtain from unaffiliated third
+parties. 
+Independence of Directors 
+The board of directors must consist of a majority of independent directors under both the Corporate Governance Guidelines and the applicable requirements of the Nasdaq. 
+Under Nasdaq rules, independent directors must comprise a majority of a listed company’s board of directors. In addition, Nasdaq rules require that, subject to specified exceptions, each member of a listed
+company’s audit, compensation, and nominating and corporate governance committees be independent. Under Nasdaq rules, an individual will qualify as an “independent director” only if, in the opinion of the company’s board of directors, he or she
+does not have a relationship that would interfere with the exercise of independent judgment in carrying out the responsibilities of a director. The Corporate Governance Guidelines effectively mandate compliance with these Nasdaq requirements. 
+• 
+Audit committee members must also satisfy additional independence criteria, including those set forth in Rule 10A-3 under the Securities Exchange Act of 1934 or the Securities Exchange Act. In order to be considered independent for
+purposes of Rule 10A-3, a member of an audit committee of a listed company may not accept, directly or indirectly, any consulting, advisory or other compensatory fee from the listed company or any of its subsidiaries, other than
+compensation for board or committee service, and may not be an affiliated person of the listed company or any of its subsidiaries; and 
+• 
+Compensation committee members must also satisfy additional independence criteria, including those set forth in Rule 10C-1 under the Securities Exchange Act. In determining independence requirements for members of compensation
+committees, Nasdaq and other national securities exchanges and national securities associations are to consider relevant factors that include (a) the source of compensation of a director, including any consulting, advisory or other
+compensatory fee paid by the listed company to the director, and (b) whether the director is affiliated with the listed company, a subsidiary of the listed company or an affiliate of a subsidiary of the listed company. 
+78 
+Table of Contents 
+The board annually reviews the independence of all non-employee directors. The board has determined that each of David Acheson, David Bespalko, Katherine Davis,
+John Potthoff and Leslie Teso-Lichtman qualifies as an independent director in accordance with the rules of Nasdaq and Rules 10C-1 and 10A-3 under the Securities Exchange Act.
\ No newline at end of file
diff --git a/raw/filings/0001092662/2022/0001140361-23-014526/item9a.txt b/raw/filings/0001092662/2022/0001140361-23-014526/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..908b391b18e7040809f63effc2facb38e1884bc9
--- /dev/null
+++ b/raw/filings/0001092662/2022/0001140361-23-014526/item9a.txt
@@ -0,0 +1,51 @@
+ITEM 9A. 
+Controls and Procedures 
+Evaluation of Disclosure Controls and Procedures 
+Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures, as defined by Rules 13a-15(e) and 15d-15(e)
+under the Exchange Act, as of December 31, 2022. Based on the evaluation of our disclosure controls and procedures, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective
+as of December 31, 2022 due to a material weakness in internal control over financial reporting described below. 
+Management’s Report on Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rules 13a-15(f) and 15d-15(f) promulgated
+under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer and effected by the board of directors, management and other personnel to provide reasonable
+assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that: 
+• 
+pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; 
+• 
+provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are
+being made in accordance with authorizations of management and directors of the company; and 
+• 
+provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. As a result, even those systems determined to be effective can provide only reasonable
+assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the
+degree of compliance with the policies or procedures may deteriorate. 
+Under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, our management evaluated the effectiveness of our internal control over financial reporting as of
+December 31, 2022. In making their assessment of internal control over financial reporting, our management used the criteria described in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the
+Treadway Commission. Our evaluation included documenting, evaluating and testing of the design and operating effectiveness of our internal control over financial reporting. Based on this evaluation, we concluded that our controls over financial
+reporting were not effective as of December 31, 2022. 
+A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual
+or interim financial statements will not be prevented or detected on a timely basis. In connection with the assessment of our internal control over financial reporting described above, management identified the following deficiencies that
+constituted individually, or in the aggregate, material weakness in our internal control over financial reporting as of December 31, 2022: 
+62 
+Table of Contents 
+• 
+Inventory Costing Process – We did not appropriately include all direct labor in the products unit cost, freight in charges and adjustments for products not shipped when establishing the
+inventory balance as of December 31, 2022. These adjustments indicate ineffective or insufficient review of the inventory accounts. 
+The errors arising from the underlying deficiencies are not material to the financial statements reported in any interim or prior annual period and therefore did not result in a restatement to previously filed
+financial statements. These control deficiencies, however, could result in misstatements of the aforementioned accounts and disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that
+would not be prevented or detected in a timely manner. Accordingly, we have determined that these control deficiencies constitute a material weakness. 
+Remediation of the Material Weaknesses in Internal Control Over Financial Reporting 
+Management is committed to the planning and implementation of remediation efforts to address the material weakness. These remediation efforts, which have been implemented or are in process of implementation, are
+intended to both address the identified material weakness and to enhance our overall financial control environment. These efforts include revisiting the review controls and control owners involved in the inventory costing process. We identified
+and implemented additional internal controls to strengthen account analyses related to inventory costing and have personnel with additional cost accounting experience. In addition, we began the process to review all internal controls related to
+cost accounting and established procedures for cost data validation and reporting. As we continue to solidify our internal controls over the financial closing and reporting processes, we expect to fully remediate this material weakness. 
+Previously Identified Material Weaknesses in Internal Control Over Financial Reporting 
+None. 
+Changes in Internal Control over Financial Reporting 
+Other than the ongoing remediation efforts described above, there were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of
+the Securities Exchange Act of 1934 during the three months ended December 31, 2022 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+Inherent Limitations of Internal Control 
+Management, including the Company’s Chief Executive Officer and Chief Financial Officer, does not expect that the Company’s internal controls will prevent or detect all errors and all fraud. A control system, no
+matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints and
+the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of internal control can provide absolute assurance that all control issues and instances of fraud, if
+any, have been detected. Also, any evaluation of the effectiveness of internal controls in future periods are subject to the risk that those internal controls may become inadequate because of changes in business conditions, or that the degree of
+compliance with the policies and procedures may deteriorate.
\ No newline at end of file
diff --git a/raw/filings/0001092662/2022/0001140361-23-014526/rp_note.txt b/raw/filings/0001092662/2022/0001140361-23-014526/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0001092662/2022/0001140361-23-014526/rpt_disclosure.txt b/raw/filings/0001092662/2022/0001140361-23-014526/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..f2c8d0750fd389bfd5706bf24e606263e28cfa53
--- /dev/null
+++ b/raw/filings/0001092662/2022/0001140361-23-014526/rpt_disclosure.txt
@@ -0,0 +1,41 @@
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE. 
+Procedures for Approval of Related Person Transactions 
+The board of directors reviews all transactions involving us in which any of our directors, significant stockholders and executive officers and their immediate family members are participants, in order to determine
+whether any such party has a direct or indirect material interest in the transaction. All directors and executive officers must notify us of any proposed transaction involving us in which such person has a direct or indirect material interest.
+The proposed transaction is then reviewed by either the board of directors as a whole or the audit committee, which determines whether to approve the transaction. After such review, the reviewing body approves the transaction only if it
+determines that the transaction is in, or not inconsistent with, the best interests of our company and stockholders. 
+77 
+Table of Contents 
+Conflict of Interest Policy 
+The board of directors has adopted a Conflict of Interest Policy applicable to all directors, officers, and employees of our company and our subsidiaries. 
+The Conflict of Interest Policy requires each director and executive officer, including their immediate family members, to provide written notice of any potential related-party transaction, defined by the policy to
+mirror the definition of Item 404 of Regulation S-K of the SEC (with the exception that the policy includes a monetary threshold of $100,000) to the Chair of the Board of Directors (or to the Chief Executive Officer if such transaction involves
+the Chair of the Board of Directors, or to the Chief Financial Officer if such transaction involves the Chief Executive Officer), including all information that the Chair of the Board of Directors, the Chief Executive Officer or the Chief
+Financial Officer may request. Upon receiving all relevant information, the board of directors may approve the transaction if it determines that the transaction is in the Company’s best interests and fair to us, may require modifications to the
+transaction to make it acceptable for approval, or may reject it. The board of directors may also establish guidelines for ongoing management of a specific related-party transaction. The policy requires that continuing related-party transactions
+are reviewed on at least an annual basis. Additionally, the policy requires that all directors and executive officers complete a director and officer questionnaire in connection with each of our annual proxy statements, in which they are asked to
+disclose family relationships and other related-party transactions. 
+2022 Related Person Transactions 
+Since January 1, 2022, we have not engaged in any related-party transactions in which the amount involved exceeded $100,000 and in which any of our directors or executive officers or any holder of more than 5% of
+our common stock, or any member of the immediate family of any of these persons or entities controlled by any of them, had or will have a direct or indirect material interest, other than the compensation arrangements described in “Director
+Compensation” and “Executive Compensation” of Item 11 above. It is our intention to ensure that any future transactions between us and our officers, directors and significant stockholders and their affiliates are approved by the audit committee
+and a majority of the members of the board of directors, including a majority of the independent and disinterested members of the board of directors, and are on terms no less favorable to us than those that we could obtain from unaffiliated third
+parties. 
+Independence of Directors 
+The board of directors must consist of a majority of independent directors under both the Corporate Governance Guidelines and the applicable requirements of the Nasdaq. 
+Under Nasdaq rules, independent directors must comprise a majority of a listed company’s board of directors. In addition, Nasdaq rules require that, subject to specified exceptions, each member of a listed
+company’s audit, compensation, and nominating and corporate governance committees be independent. Under Nasdaq rules, an individual will qualify as an “independent director” only if, in the opinion of the company’s board of directors, he or she
+does not have a relationship that would interfere with the exercise of independent judgment in carrying out the responsibilities of a director. The Corporate Governance Guidelines effectively mandate compliance with these Nasdaq requirements. 
+• 
+Audit committee members must also satisfy additional independence criteria, including those set forth in Rule 10A-3 under the Securities Exchange Act of 1934 or the Securities Exchange Act. In order to be considered independent for
+purposes of Rule 10A-3, a member of an audit committee of a listed company may not accept, directly or indirectly, any consulting, advisory or other compensatory fee from the listed company or any of its subsidiaries, other than
+compensation for board or committee service, and may not be an affiliated person of the listed company or any of its subsidiaries; and 
+• 
+Compensation committee members must also satisfy additional independence criteria, including those set forth in Rule 10C-1 under the Securities Exchange Act. In determining independence requirements for members of compensation
+committees, Nasdaq and other national securities exchanges and national securities associations are to consider relevant factors that include (a) the source of compensation of a director, including any consulting, advisory or other
+compensatory fee paid by the listed company to the director, and (b) whether the director is affiliated with the listed company, a subsidiary of the listed company or an affiliate of a subsidiary of the listed company. 
+78 
+Table of Contents 
+The board annually reviews the independence of all non-employee directors. The board has determined that each of David Acheson, David Bespalko, Katherine Davis,
+John Potthoff and Leslie Teso-Lichtman qualifies as an independent director in accordance with the rules of Nasdaq and Rules 10C-1 and 10A-3 under the Securities Exchange Act.
\ No newline at end of file
diff --git a/raw/filings/0001532286/2019/0001532286-20-000005/filing.txt b/raw/filings/0001532286/2019/0001532286-20-000005/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..5e1ed3baf78e5ef582ed926c46f1c695cee39ca2
--- /dev/null
+++ b/raw/filings/0001532286/2019/0001532286-20-000005/filing.txt
@@ -0,0 +1,4714 @@
+10-K
+1
+nine-20191231x10k.htm
+10-K
+Document 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+WASHINGTON, D.C. 20549 
+______________________________________________________________________________________ 
+FORM 10-K 
+_____________________________________________________________________________________ 
+(Mark One) 
+x 
+ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+FOR THE FISCAL YEAR ENDED DECEMBER 31, 2019 
+OR 
+¨ 
+TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+FOR THE TRANSITION PERIOD FROM TO 
+Commission File Number: 001-38347 
+_____________________________________________________________________________________ 
+Nine Energy Service, Inc. 
+(Exact name of registrant as specified in its charter) 
+_____________________________________________________________________________________ 
+Delaware 
+80-0759121 
+(State or other jurisdiction of 
+incorporation or organization) 
+(I.R.S. Employer 
+Identification No.) 
+2001 Kirby Drive, Suite 200 
+Houston, TX 77019 
+(Address of principal executive offices) 
+(281) 730-5100 
+(Registrant’s telephone number, including area code) 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of each class 
+Trading Symbol(s) 
+Name of each exchange on which registered 
+Common Stock, par value $0.01 per share 
+NINE 
+New York Stock Exchange 
+Securities registered pursuant to Section 12(g) of the Act: None 
+_____________________________________________________________________________________ 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x 
+Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o 
+Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No o 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. 
+Large accelerated filer 
+o 
+Accelerated filer 
+x 
+Non-accelerated filer 
+o 
+Smaller reporting company 
+o 
+Emerging growth company 
+x 
+If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x 
+The aggregate market value of the registrant’s common stock held by non-affiliates of the registrant on the last business day of the registrant’s most recently completed second fiscal quarter (based on the closing sales price on the New York Stock Exchange on June 28, 2019) was $277,678,642 . 
+The number of shares of the registrant’s common stock outstanding at March 5, 2020 was 30,537,732 . 
+DOCUMENTS INCORPORATED BY REFERENCE 
+Information called for in Part III of this Annual Report on Form 10-K is incorporated by reference to the registrant ’ s Definitive Proxy Statement for its Annual Meeting of Stockholders to be held in May 2020. 
+TABLE OF CONTENTS 
+PART I 
+Item 1. 
+Business 
+1 
+Item 1A. 
+Risk Factors 
+10 
+Item 1B. 
+Unresolved Staff Comments 
+31 
+Item 2. 
+Properties 
+31 
+Item 3. 
+Legal Proceedings 
+31 
+Item 4. 
+Mine Safety Disclosures 
+31 
+PART II 
+Item 5. 
+Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities 
+32 
+Item 6. 
+Selected Financial Data 
+33 
+Item 7. 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+35 
+Item 7A. 
+Quantitative and Qualitative Disclosures About Market Risk 
+51 
+Item 8. 
+Financial Statements and Supplementary Data 
+52 
+Item 9. 
+Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+53 
+Item 9A. 
+Controls and Procedures 
+53 
+Item 9B. 
+Other Information 
+53 
+PART III 
+Item 10. 
+Directors, Executive Officers and Corporate Governance 
+54 
+Item 11. 
+Executive Compensation 
+54 
+Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+54 
+Item 13. 
+Certain Relationships and Related Transactions, and Director Independence 
+54 
+Item 14. 
+Principal Accounting Fees and Services 
+54 
+PART IV 
+Item 15. 
+Exhibits, Financial Statement Schedules 
+55 
+Item 16. 
+Form 10-K Summary 
+58 
+CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS 
+This Annual Report on Form 10-K (this “Annual Report”) contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans, and objectives of management are forward-looking statements. When used in this Annual Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. 
+All forward-looking statements speak only as of the date of this Annual Report; we disclaim any obligation to update these statements unless required by law, and we caution you not to place undue reliance on them. Although we believe that our plans, intentions, and expectations reflected in or suggested by the forward-looking statements we make in this Annual Report are reasonable, we can give no assurance that these plans, intentions, or expectations will be achieved. 
+We disclose important known factors that could cause our actual results to differ materially from our expectations under “Risk Factors” in Item 1A of Part I and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of Part II of this Annual Report. Additional risks or uncertainties that are not currently known to us, that we currently deem to be immaterial, or that could apply to any company could also materially adversely affect our business, financial condition, or future results. 
+These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. 
+PART I 
+Item 1. 
+Business 
+Overview 
+Nine Energy Service, Inc. (either individually or together with its subsidiaries, as the context requires, the “Company,” “Nine,” “we,” “us,” and “our”) is a Delaware corporation that was formed in February 2013 through a combination of three service companies owned by SCF Partners, L.P. or its affiliates. Nine is a leading completion services provider that targets unconventional oil and gas resource development across all North American basins and abroad. We partner with our exploration and production (“E&P”) customers to design and deploy downhole solutions and technology to prepare horizontal, multistage wells for production. We focus on providing our customers with cost-effective and comprehensive completion solutions designed to maximize their production levels and operating efficiencies. We believe our success is a product of our culture, which is driven by our intense focus on performance and wellsite execution as well as our commitment to forward-leaning technologies that aid us in the development of smarter, customized applications that drive efficiencies. 
+We provide our comprehensive completion solutions across a diverse set of well-types, including on the most complex, technically demanding unconventional wells. Modern, high-intensity completion techniques are a more effective way for our customers to maximize resource extraction from horizontal oil and gas wells. These completion techniques provide improved estimated ultimate recovery per lateral foot and a superior return on investment by decreasing cycle time, which make them attractive to operators despite their associated increased well cost. We compete for the most intricate and demanding projects, which are characterized by extended reach horizontal laterals, increased stage counts per well, multi-well pad development, and increased proppant loading per lateral foot. As stage counts per well and wells per pad increase, so do our operating leverage and returns, as we are able to complete more jobs and stages with the same number of units and crews. Service providers for these demanding projects are selected based on their technical expertise and ability to execute safely and efficiently, rather than only price. As our customers continue to improve operational efficiencies in completions design, increasing its complexity and difficulty, oilfield service selection becomes much more critical and selective. 
+We offer a variety of completion applications and technologies to match customer needs across the broadest addressable completions market. Our comprehensive well solutions range from cementing the well at the initial stages of the completion, preparing the well for stimulation, isolating all the stages of an extended reach lateral, and the drilling out of isolation tools. Our completion techniques are specifically tailored to the customer and geology of each well. At the initial stage of a well completion, our lab facilities produce customized cementing slurries used to secure the production casing to ensure well integrity throughout the life of the well. Once the casing is in place, we utilize our proprietary tools at the toe (end) of the well, often called stage one, to prepare for the well stimulation process. We provide customers with plug-and-perf or pinpoint frac sleeve system technology to complete the remaining stages of the well. Through our wireline units, we provide plug-and-perf services that, when combined with our fully-composite or dissolvable frac plugs, create perforations to isolate and divert the fracture to the correct stage. Our pinpoint frac sleeve system involves packers, either hydraulic or swellable, to isolate sections of the wellbore and frac sleeves to provide access to each stage for stimulation and production. Our equipment also includes large-diameter coiled tubing units that are capable of reaching the farthest depths for the removal of plugs and cleaning of the wellbore to prepare for production. 
+In October 2018, we acquired Magnum Oil Tools International, LTD, Magnum Oil Tools GP, LLC, and Magnum Oil Tools Canada Ltd. (collectively, “Magnum” and such acquisition, the “Magnum Acquisition”). Magnum is a leading oilfield completion tools company that is focused on the development of innovative tools for unconventional oil and gas resource development. Magnum has a broad offering of proprietary downhole completions consumables products, including a comprehensive line of dissolvable and composite frac plugs; disk subs, including intervention-less designs, for wellbore isolation and casing flotation device applications; and dissolvable frac balls. 
+Our website is located at https://nineenergyservice.com, and our investor relations website is located at https://investor.nineenergyservice.com. The information posted on our website is not incorporated into this Annual Report. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to reports filed or furnished pursuant to Sections 13(a) and 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are available free of charge on our investor relations website as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (the “SEC”). You may also access all of our public filings through the SEC’s website at www.sec.gov. Investors and other interested parties should note that we use our investor relations website to publish important information about us, including information that may be deemed material to investors. We encourage investors and other interested parties to review the information we may publish through our investor relations website, in addition to our SEC filings, press releases, conference calls, and webcasts. 
+1 
+Our Services 
+We derive revenue by providing services integral to the completion of unconventional wells through a full range of tools and methodologies. On August 30, 2019, we sold our Production Solutions segment. For additional information on this divestiture, see Note 3 – Divestitures, Acquisitions, and Combinations included in Item 8 of Part II of this Annual Report. 
+The following is a description of our primary service offerings and deployment methods: 
+Cementing Services: Our cementing services consist of blending high-grade cement and water with various solid and liquid additives to create a cement slurry that is pumped between the casing and the wellbore of the well. We currently operate three high-quality laboratory facilities capable of designing and testing all of the current industry cement designs. The laboratory facilities operate twenty-four hours a day and are fully staffed by qualified technicians with the latest equipment and modeling software. Additionally, our technicians and engineers ensure that all tests are performed to American Petroleum Institute specifications and results are delivered to customers promptly. Our cement slurries are designed to achieve the proper cement thickening time, compressive strength, and fluid loss control. Our slurries can be modified to address a wide range of downhole needs of our E&P customers, including varying well depths, downhole temperatures, pressures, and formation characteristics. 
+We deploy our slurries by using our customized design twin-pumping units, which are fully redundant, containing two pumps, two hydraulic systems, two mixing pumps, and two electrical systems. This customized design significantly decreases our risk of downtime due to mechanical failure and eliminates the necessity to have an additional cementing unit on standby. We have invested in the highest quality cementing equipment, and since 2012, we have deployed only new equipment for use in the fields. As of December 31, 2019 , we had a total of 37 pumping units. 
+From January 2014 through December 2019, we completed approximately 19,600 cementing jobs, with an on-time rate of approximately 91% . Punctuality of service has become one of the primary metrics that E&P operators use to evaluate the cementing services they receive. Key contributors to our 91% on-time rate include our lab capabilities, personnel, close proximity to our customers’ acreage, dual-sided bulk loading plants, and our service-driven culture. 
+Completion Tools: We provide downhole solutions and technology used for multistage completions. Our comprehensive completion service offerings are complemented by our unconventional open hole and cemented completion tool products, such as liner hangers and accessories, fracture isolation packers, frac sleeves, stage one prep tools, fully-composite and dissolvable frac plugs, casing flotation tools, specialty open hole float equipment, disk subs, composite cement retainers, and centralizers. Our completion tools provide pinpoint frac sleeve system technologies as well as a portfolio of completion technologies used for completing the toe stage of a horizontal well and fully-composite, dissolvable, and extended range frac plugs to isolate stages during plug and perf operations. 
+Our systems provide completion efficiencies at the wellsite by reducing our customers’ equipment needs and stimulation time and allowing for specific zonal treatment. From March 2011 through December 2019, we deployed approximately 193,300 isolation, stage one, and casing flotation tools and approximately 22,500 frac sleeves. 
+Wireline Services: Our wireline services involve the use of a wireline unit equipped with a spool of wireline that is unwound and lowered into oil and gas wells to convey specialized tools or equipment for well completion, well intervention, or pipe recovery. We operate a fleet of modern and “fit-for-purpose” cased hole wireline units designed for operating in unconventional completion operations. We currently operate 47 wireline pumpdown units in the U.S. Our operation is equipped with the latest technology utilized to service long lateral completions, including head tension tools, ballistic release tools, and addressable switches. We currently have wireline units equipped with Coated Line, which is a coated wireline that significantly reduces injector oil use. Offering a lower dynamic coefficient of friction, Coated Line Wireline requires less pump down fluid to operate and is more conducive for reaching further depths in longer laterals. 
+The majority of our wireline work consists of plug-and-perf completions, which is a multistage well completion technique for cased-hole wells that consists of deploying perforating guns to a specified depth. We deploy proprietary specialized tools like our fully-composite and dissolvable frac plugs through our wireline units. From January 2014 through December 2019, we completed approximately 153,100 wireline stages with a success rate of approximately 99% . 
+Coiled Tubing Services: Coiled tubing services perform wellbore intervention operations utilizing a continuous steel pipe that is transported to the wellsite wound on a large spool in lengths of up to 30,000 feet. Coiled tubing provides a cost-effective solution for well work due to the ability to deploy efficiently and safely into a live well using specialized well-control equipment. The live well work capability limits the customer’s risk of formation damage associated with “killing” a well (the temporary placement of heavy fluids in a wellbore to keep reservoir fluids in place), while allowing for safer operations due to 
+2 
+minimal equipment handling. Coiled tubing facilitates a variety of services in both new and old wells, such as milling, drilling, fishing, production logging, artificial lift, cementing, and stimulation. 
+We currently operate 14 coiled tubing units serving the Permian Basin, SCOOP/STACK region, and Haynesville markets. Our coiled tubing units carry data acquisition and dissemination technology, allowing our customers to monitor jobs via a web interface. Of the 14 coiled tubing units, we consider 12 to be “extended reach” units capable of reaching the toe of wells with total measured depths of 24,000 feet and beyond, including lateral lengths in excess of 12,500 feet, keeping pace with the industry’s most challenging downhole environments. While we specialize in larger-diameter (2 3/8” and 2 5/8”) coiled tubing units, we also offer 2” and 1 1/4” diameter solutions to our customers. From April 2014 through December 2019, we have performed approximately 9,100 jobs and deployed more than 198 million running feet of coiled tubing, with a success rate of over 99% . 
+Geographic Areas of Operation 
+We operate in all major onshore basins in both the U.S. and Canada, including the Permian Basin, Marcellus and Utica Shales, Eagle Ford Shale, DJ Basin, SCOOP/STACK Formation, Bakken Formation, Haynesville Formation, and Western Canada Sedimentary Basin. We provide our services through strategically placed operating facilities located in-basin throughout North America. This local presence allows us to quickly respond to customer demands and operate efficiently. Additionally, through our extensive footprint, we are able to track and implement best practices around completion trends and technology across all divisions and geography. 
+We believe that our strategic geographic diversity will benefit us as activity increases or decreases in select basins by helping to mitigate basin-risk. Our broad geographic footprint provides us with exposure to potential increases in drilling and completion activity and will allow us to opportunistically pursue new business in basins with the most active drilling environments. 
+Seasonality 
+Our operations are subject to seasonal factors, and our overall financial results reflect seasonal variations. Specifically, we typically have experienced a pause by our customers around the holiday season in the fourth quarter, which may be compounded as our customers exhaust their annual capital spending budgets towards year end. 
+Additionally, our operations are directly affected by weather conditions. During the winter months (portions of the first and fourth quarters) and periods of heavy snow, ice, or rain, particularly in the northeastern U.S., North Dakota, Rockies, and western Canada, our customers may delay operations or we may not be able to operate or move our equipment between locations. Also, during the spring thaw, which normally starts in late March and continues through June, some areas, primarily in western Canada, impose transportation restrictions to prevent damage caused by the spring thaw. Throughout the year, heavy rains adversely affect activity levels because well locations and dirt access roads can become impassible in wet conditions. Weather conditions may also negatively affect our customers activity levels. 
+Sales and Marketing 
+Our sales activities are conducted through a network of sales representatives and business development personnel, which provides us coverage at both the corporate and field level of our customers. We have a technical sales organization with expertise and focus within our specific service lines. Sales representatives work closely with local operations managers to target potential opportunities through strategic focus and planning. Customers are identified as targets based on their drilling and completion activity, geographic location, and economic viability. Our marketing activities are performed internally with input and guidance from a third-party marketing agency. Our strategy is based on building a strong brand though multiple media outlets including our website, select social media accounts, print and online advertisements, billboard advertisements, press releases and various industry-specific conferences, publications, and lectures. 
+Customers 
+Our customer base includes a broad range of integrated and independent E&P companies. For the year ended December 31, 2019 , our top five customers collectively accounted for approximately 34% of our revenues. For the year ended December 31, 2019 , no single customer accounted for 10% or more of our revenues. 
+Demand for our services and products is cyclical and substantially dependent upon activity levels in the oil and gas industry, particularly our customers’ willingness to spend capital on the exploration for and development of oil and natural gas. Our customers’ spending plans are generally based on their outlook for near-term and long-term commodity prices. As a result, the demand for our services and products is highly sensitive to current and expected commodity prices. 
+3 
+Competition 
+We provide our services and products across the United States, Canada, and abroad, and we compete against different companies in each service and product line we offer. Our competition includes many large and small oilfield service companies, including the largest integrated oilfield services companies. We believe that the principal competitive factors in the markets we serve are technology offerings, wellsite execution, service quality, technical expertise, equipment capacity, work force competency, efficiency, safety record, reputation, and experience. Additionally, projects are often awarded on a bid basis, which tends to create a highly competitive environment. We seek to differentiate our company from our competitors by delivering the highest-quality services, technology, and equipment possible, coupled with superior execution and operating efficiency in a safe working environment. By focusing on cultivating our existing customer relationships and maintaining our high standard of customer service, technology, safety, performance, and quality of crews, equipment, and services, we believe we are differentiated in a competitive market. 
+Our major competitors include Halliburton Company, Schlumberger Limited, Baker Hughes, NCS Multistage, NexTier Oilfield Solutions, KLX Energy Services Holdings, and a significant number of private and locally-oriented businesses. 
+Suppliers 
+We purchase a wide variety of raw materials, parts, and components that are manufactured and supplied for our operations from various suppliers. While we are not dependent on any single supplier for those materials, parts, or components, certain product lines acquired in the Magnum Acquisition depend on a limited number of third-party suppliers and vendors. During the year ended December 31, 2019 , no supplier of the materials used in our services provided over 10% of our materials or equipment as a percentage of overall costs. 
+To date, we have generally been able to obtain the equipment, parts, and supplies necessary to support our operations on a timely basis. While we believe that we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers, we may not always be able to make alternative arrangements. In addition, certain materials for which we do not currently have long-term supply agreements could experience shortages and significant price increases in the future. As a result, we may be unable to mitigate any future supply shortages and our results of operations, prospects, and financial condition could be adversely affected. 
+Research & Technology, Intellectual Property 
+Our sales and earnings are influenced by our ability to successfully introduce new or improved products and services to the market. We believe we have become a “go-to” provider for piloting new technologies because of our service quality and offering, execution at the wellsite, and geographic footprint. 
+Our engineering and technology efforts are focused on providing efficient and cost-effective solutions to maximize production for our customers across major North American onshore basins and abroad. We have dedicated resources focused on internally developing new technology and equipment and evolving our existing proprietary tools, as well as resources focused on sourcing and commercializing new technologies through mergers and acquisitions and strategic partnerships, to stay ahead of industry trends and achieve lower completion and production costs for our customers. With the acquisition of Magnum, our internal research and development capabilities have increased substantially. 
+We have developed a suite of proprietary downhole tools, products, and techniques through both internal resources, as well as mergers and acquisitions and strategic partnerships with manufacturers and engineering companies looking for a reliable and expansive channel to market. In these partnerships, we have exclusive rights to market and sell technology unavailable to any other service providers in the designated regions, and we sell the technology directly to the customer and order from the manufacturer on an as-needed basis, with no minimum volume requirements and without having to hold excess inventory. These strategic partnerships provide us and our customers with access to unique downhole technology from independent innovators while allowing us to minimize exposure to potential technology adoption risks and the significant costs associated with developing and implementing research and development internally. 
+Although in the aggregate our patents, licenses, and strategic partnerships are important to us, we do not regard any single patent, license, or strategic partnership as critical or essential to our business as a whole. In general, we depend on our technological capabilities, customer service-oriented culture, and application of our know-how to distinguish ourselves from our competitors, rather than our right to exclude others through patents or exclusive licenses. We also consider the quality and timely delivery of our products, the service we provide to our customers, and the technical knowledge and skill of our personnel to be more important than our registered intellectual property in our ability to compete. 
+4 
+Risk Management and Insurance 
+Our operations are subject to hazards inherent in the oil and natural gas industry, including, but not limited to, accidents, blowouts, explosions, craterings, fires, oil spills, and hazardous materials spills. These conditions can cause personal injury or loss of life; damage to, or destruction of, property, the environment, and wildlife; and the suspension of our or our customers’ operations. 
+In addition, claims for loss of oil and gas production and damage to formations can occur in the oilfield services industry. If a serious accident were to occur at a location where our equipment and services are being used, it could result in us being named as a defendant in lawsuits asserting large claims. 
+Because our business involves the transportation of heavy equipment and materials, we may also experience traffic accidents which may result in spills, property damage, and personal injury. 
+Despite our efforts to maintain high safety standards, from time to time, we have suffered accidents, and there is a risk that we will experience accidents in the future. In addition to the property and personal losses from these accidents, the frequency and severity of these incidents affect our operating costs, insurability, and relationships with customers, employees, and regulatory agencies. In particular, in recent years many of our large customers have placed an increased emphasis on the safety records of their service providers. Any significant increase in the frequency or severity of these incidents, or the general level of compensatory payments, could adversely affect the cost of, or our ability to obtain, workers’ compensation and other forms of insurance and could have other material adverse effects on our financial condition and results of operations. 
+We maintain insurance coverage of types and amounts that we believe to be customary in the industry including workers’ compensation, employer’s liability, claims based pollution, umbrella, comprehensive commercial general liability, business automobile, and property. Our insurance coverage may be inadequate to cover our liabilities. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable and commercially justifiable or on terms as favorable as our current arrangements. 
+We endeavor to allocate potential liabilities and risks between the parties in our Master Service Agreements (“MSAs”). We retain the risk for any liability not indemnified by our customers in excess of our insurance coverage. These MSAs delineate our and our customers’ respective warranty and indemnification obligations with respect to the services we provide. We endeavor to negotiate MSAs with our customers that provide, among other things, that we and our customers assume (without regard to fault) liability for damages to our respective personnel and property. For catastrophic losses, we endeavor to negotiate MSAs that include industry-standard carve-outs from the knock-for-knock indemnities. Additionally, our MSAs often provide carve-outs to the “without regard to fault” concept that would permit, for example, us to be held responsible for events of catastrophic loss only if they arise as a result of our gross negligence or willful misconduct. Our MSAs typically provide for industry-standard pollution indemnities, pursuant to which we assume liability for surface pollution associated with our equipment and originating above the surface (without regard to fault), and our customer assumes (without regard to fault) liability arising from all other pollution, including, without limitation, underground pollution and pollution emanating from the wellbore as a result of an explosion, fire, or blowout. This description of our MSAs is a summary of the material terms of the typical MSA that we have in place and does not reflect every MSA that we have entered into or may enter into in the future, some of which may contain indemnity structures and risk allocations between our customers and us that are different than those described here. 
+Employees 
+As of December 31, 2019 , we had 1,469 employees. We are not a party to any collective bargaining agreements. 
+Government Regulations and Environmental, Health, and Safety Matters 
+Our operations are subject to numerous stringent and complex laws and regulations at the U.S. federal, state, and local levels governing the discharge of materials into the environment, environmental protection, and health and safety aspects of our operations. In addition, due to our operations in Canada, we are subject to Canadian environmental statutes and regulations. Failure to comply with these laws and regulations or to obtain or comply with permits may result in the assessment of administrative, civil, and criminal penalties, imposition of remedial or corrective action requirements, and the imposition of injunctions or other orders to prohibit certain activities, restrict certain operations, or force future compliance with environmental requirements. 
+There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons, other hazardous substances, and wastes, as a result of air emissions and 
+5 
+wastewater discharges related to our operations, and because of historical operations and waste disposal practices. Spills or other releases of regulated substances, including such spills and releases that occur in the future, could expose us to material losses, expenditures, and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. 
+The following is a summary of some of the existing laws, rules, and regulations to which we are subject. 
+Hazardous Substances and Waste Handling 
+The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Under the guidance issued by the U.S. Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. We are required to manage the disposal of hazardous and non-hazardous wastes in compliance with RCRA and analogous state laws. RCRA currently exempts many E&P wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes intrinsically associated with the exploration, development, or production of crude oil and natural gas. However, these oil and gas E&P wastes may still be regulated under state solid waste laws and regulations, and it is possible that certain oil and natural gas E&P wastes now classified as non-hazardous could be classified as hazardous waste in the future. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain E&P related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree required the EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. On April 23, 2019, the EPA determined that a revision of the regulations was not necessary. Stricter regulation of wastes generated during our or our customers’ operations could result in increased costs for our operations or the operations of our customers, which could in turn reduce demand for our services and adversely affect our business. 
+Comprehensive Environmental Response, Compensation, and Liability Act 
+The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owner or operator of the site where the release occurred and anyone who transported or disposed or arranged for the transport or disposal of a hazardous substance released at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA and any state analogs may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources and for the costs of certain health studies. We currently own, lease, or operate numerous properties that have been used for manufacturing and other operations for many years. These properties and the substances disposed or released on them may be subject to CERCLA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. 
+Worker Health and Safety 
+We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”), establishing requirements to protect the health and safety of workers. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require maintenance of information about hazardous materials used or produced in operations and provision of this information to employees, state and local government authorities, and citizens. In June 2016, OSHA finalized a new regulation regarding crystalline silica exposures, which included requirements that hydraulic fracturing operations implement dust controls to limit exposures to the substance by June 23, 2021. Additionally, the Federal Motor Carrier Safety Administration (the “FMCSA”) regulates and provides safety oversight of commercial motor vehicles, the EPA establishes requirements to protect human health and the environment, the federal Bureau of Alcohol, Tobacco, Firearms and Explosives establishes requirements for the safe use and storage of explosives, and the federal Nuclear Regulatory Commission establishes requirements for the protection against ionizing radiation. Substantial fines and penalties can be imposed, and orders or injunctions limiting or prohibiting certain operations may be issued, in connection with any failure to comply with these laws and regulations. 
+6 
+Transportation Safety and Compliance 
+Due to operating a fleet in excess of 750 commercial motor vehicles, we are subject to a number of federal and state laws and regulations, including the Federal Motor Carrier Safety Regulations and Hazardous Material Regulations for interstate travel and comparable state regulations for intrastate travel. Substantial fines and penalties can be imposed and orders or injunctions limiting or prohibiting certain operations may be issued in connection with any failure to comply with laws and regulations relating to the safe operation of commercial motor vehicles. 
+Water Discharges 
+The Federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters, including jurisdictional wetlands, is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. In September 2015, a new EPA and U.S. Army Corps of Engineers (the “Corps”) rule defining the scope of federal jurisdiction over wetlands and other waters became effective; however, this rule was repealed on October 22, 2019. On January 23, 2020, the EPA and the Corps issued a final rule re-defining the term “waters of the United States” as applied under the Clean Water Act and narrowing the scope of waters subject to federal regulation. This 2020 rule is subject to various pending legal challenges. Future implementation of this final rule is uncertain at this time. To the extent a future rule expands the range of properties subject to the Clean Water Act’s jurisdiction, certain energy companies could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas, which in turn could reduce demand for our services. The process for obtaining permits has the potential to delay our operations and those of our customers. Spill prevention, control, and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture, or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of wastewater and storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. The Clean Water Act and analogous state laws provide for administrative, civil, and criminal penalties for unauthorized discharges and, together with the Oil Pollution Act of 1990, impose rigorous requirements for spill prevention and response planning, as well as substantial potential liability for the costs of removal, remediation, and damages in connection with any unauthorized discharges. 
+Air Emissions 
+The federal Clean Air Act (the “CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. These regulations change frequently. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements, or utilize specific equipment or technologies to control emissions of certain pollutants. For example, in May 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements. In addition, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. In November 2017, the EPA published a list of areas that are in compliance with the new ozone standard and, separately in December 2017, issued responses to state recommendations for designating non-attainment areas. The EPA completed all initial area designations in July 2018. State implementation of the revised NAAQS could result in stricter permitting requirements, which in turn could delay or impair our or our customers’ ability to obtain air emission permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties, as well as injunctive relief, for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. 
+Climate Change 
+The EPA has determined that emissions of greenhouse gases, including carbon dioxide and methane, present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. The EPA has established greenhouse gas emission reporting requirements for sources in the oil and gas sector and has also promulgated rules requiring certain large stationary sources of greenhouse gases to obtain preconstruction permits under the CAA and follow “best available control technology” requirements. Although we are not likely to become subject to greenhouse gas emissions permitting and best available control technology requirements 
+7 
+because none of our facilities are presently major sources of greenhouse gas emissions, such requirements could become applicable to our customers and could have an adverse effect on their costs of operations or financial performance, thereby adversely affecting our business, financial condition, and results of operations. 
+In December 2015, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change resulted in 195 countries, including the United States, coming together to develop the Paris Agreement, which calls for the parties to undertake “ambitious efforts” to limit the average global temperature. The Paris Agreement went into effect on November 4, 2016 and establishes a framework for the parties to cooperate and report actions to reduce greenhouse gas emissions. The United States formally announced its intent to withdraw from the Paris Agreement on November 4, 2019, with withdrawal becoming effective on November 4, 2020. 
+Also, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, and many states have already established regional greenhouse gas “cap-and-trade” programs. The adoption of any legislation or regulation that restricts emissions of greenhouse gases from the equipment and operations of our customers or with respect to the oil and natural gas they produce could adversely affect demand for our products and services. Finally, most scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that could have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if such effects were to occur, they could have an adverse impact on our operations. 
+Hydraulic Fracturing 
+Our businesses are dependent on hydraulic fracturing and horizontal drilling activities. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. 
+There is considerable uncertainty surrounding regulation of the emissions of methane, which may be released during hydraulic fracturing. In 2016, the EPA issued final regulations under the CAA establishing performance standards, including standards for the capture of methane emissions released during hydraulic fracturing. However, the EPA has taken several steps to delay implementation of its methane standards, including most recently in September 2018, when the EPA announced a proposed rule that rolls back parts of the 2016 performance standards. Various industry and environmental groups have separately challenged both the original standards and the EPA’s attempts to delay implementation of the rule. Separately, in August 2019, the EPA issued proposed amendments that would rescind requirements related to the regulations of methane emissions from the oil and natural gas industry. Neither rulemaking has been finalized to date and, therefore, the scope of future obligations continues to remain uncertain. In addition, in April 2018, a coalition of states filed a lawsuit in the U.S. District Court for the District of Columbia aiming to force the EPA to establish guidelines for limiting methane emissions from existing sources in the oil and natural gas sector; that lawsuit is pending. On March 20, 2015, the U.S. Bureau of Land Management (the “BLM”) finalized a rule regulating hydraulic fracturing activities on federal lands, including requirements for the disclosure, wellbore integrity, and handling of flowback water; however, on December 29, 2017, the BLM issued a rescission of the hydraulic fracturing rule. This rescission and the rule as promulgated are subject to ongoing litigation. The BLM also previously finalized in 2016 similar limitations on methane emissions from venting and flaring and leaking equipment from oil and natural gas activities on public lands, but in September 2018 issued a final rule repealing certain provisions of the 2016 rule and reinstating the pre-2016 regulations. This repeal is the subject of legal challenges. As a result, future implementation of both the EPA and BLM methane rules is uncertain at this time. However, given the long-term trend towards increasing regulation, future federal regulation of methane and other greenhouse gas emissions from the oil and gas industry remain a possibility. 
+The EPA has also issued effluent limitation guidelines that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. These rules were finalized in June 2016. The EPA conducted a study on effluent guidelines for the oil and gas industry, and a draft of this study was published in May 2019. It is unclear how any additional federal regulation of hydraulic fracturing activities may affect our operations, but additional regulatory burdens on our customers could ultimately result in decreased demand for our services. 
+Various studies analyzing the potential environmental impacts of hydraulic fracturing have also been performed. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking 
+8 
+water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. As described elsewhere in this Annual Report, these risks are regulated under various state, federal, and local laws. 
+Some states, counties, and municipalities have enacted or are considering moratoria on hydraulic fracturing. For example, New York, Vermont, Maryland, and Washington have banned, or are in the process of banning, the use of high-volume hydraulic fracturing. Alternatively, some municipalities are, or have considered, zoning and other ordinances, the conditions of which could impose a de facto ban on drilling and/or hydraulic fracturing operations. Further, some states, counties, and municipalities are closely examining water use issues, such as permit and disposal options for processed water, which could have a material adverse impact on our financial condition, prospects, and results of operations if such additional permitting requirements are imposed upon our industry. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could reduce demand for our business by making it more difficult or costly for certain customers to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, the business and operations of our customers could be subject to additional permitting requirements, attendant permitting delays, increased operating and compliance costs and process prohibitions, which could have an adverse effect on our business, financial condition, and results of operations. 
+In light of concerns about seismic activity being triggered by the injection of produced waters into underground wells, certain regulators are also considering additional requirements related to seismic safety for hydraulic fracturing activities. A 2015 U.S. Geological Survey report identified eight states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. Any regulation that restricts the ability of our customers to dispose of produced waters or increases their cost of doing business could cause them to curtail operations, which in turn could decrease demand for our services and have a material adverse effect on our business. 
+National Environmental Policy Act 
+Businesses and operations of our customers that are carried out on federal lands may be subject to the National Environmental Policy Act (“NEPA”), which requires federal agencies, including the Department of the Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect, and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. On January 10, 2020, the Council on Environmental Quality issued a proposed rule designed to streamline approvals for projects under NEPA. Among other revisions, the proposed rule would redefine environmental “effects” or “impacts” as the effects “that are reasonably foreseeable and have a reasonably close causal relationship to the proposed action or alternatives.” The proposed rule would also eliminate the current “direct,” “indirect,” or “cumulative” categories of effects. This rulemaking process is ongoing. To the extent that our customers’ current activities, as well as proposed plans, on federal lands require governmental permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects. 
+Endangered Species Act 
+The Endangered Species Act was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or its habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. If our customers were to have areas within their business and operations designated as critical or suitable habitat or a protected species, it could decrease demand for our services and have a material adverse effect on our business. 
+9 
+Item 1A. 
+Risk Factors 
+We face many challenges and risks in the industry in which we operate. You should carefully consider each of the following risk factors and all of the other information set forth in this Annual Report, including under the section titled “Cautionary Note Regarding Forward-Looking Statements.” The risks and uncertainties described are not the only ones we face. Additional risk factors not presently known to us or which we currently consider immaterial may also adversely affect our business, financial condition, or future results. If any of these risks were actually to occur, our business, financial condition, or results of operations could be materially adversely affected. In that case, the trading price of our common stock could decline, and a stockholder could lose all or part of its investment. 
+Risks Related to Our Business and Our Industry 
+Our business is cyclical and depends on capital spending and well completions by the onshore oil and natural gas industry, and the level of such activity is volatile. Our business has been, and may continue to be, adversely affected by industry and financial market conditions that are beyond our control. 
+Our business is cyclical, and we depend on our customers’ willingness to make operating and capital expenditures to explore for, develop, and produce oil and natural gas, which, in turn, largely depends on prevailing industry and financial market conditions that are influenced by numerous factors beyond our control, including: 
+• 
+the level of prices, and expectations about future prices, for oil and natural gas; 
+• 
+the domestic and foreign supply of, and demand for, oil and natural gas and related products; 
+• 
+the level of global and domestic oil and natural gas production; 
+• 
+the supply of, and demand for, hydraulic fracturing and other oilfield services and equipment; 
+• 
+governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves; 
+• 
+the cost of exploring for, developing, producing, and delivering oil and natural gas; 
+• 
+available pipeline, storage, and other transportation capacity; 
+• 
+worldwide political, military, and economic conditions; 
+• 
+global or national health epidemics or concerns, such as the recent coronavirus outbreaks, which may reduce demand for oil, natural gas, and related products because of reduced global or national economic activity; 
+• 
+lead times associated with acquiring equipment and products and availability of qualified personnel; 
+• 
+the discovery rates of new oil and natural gas reserves; 
+• 
+federal, state, and local regulation of hydraulic fracturing and other oilfield service activities, as well as E&P activities, including public pressure on governmental bodies and regulatory agencies to regulate our industry; 
+• 
+economic and political conditions in oil and natural gas producing countries; 
+• 
+actions of the Organization of the Petroleum Exporting Countries (“OPEC”), its members, and other state-controlled oil companies relating to oil price and production levels, including announcements of potential changes to such levels; 
+• 
+advances in exploration, development, and production technologies or in technologies affecting energy consumption; 
+• 
+activities by non-governmental organizations to restrict the exploration, development, and production of oil and natural gas so as to minimize emissions of carbon dioxide, a greenhouse gas; 
+• 
+the price and availability of alternative fuels and energy sources; 
+• 
+global weather conditions and natural disasters; and 
+10 
+• 
+uncertainty in capital and commodities markets and the ability of oil and natural gas producers to access capital. 
+A decline in oil and natural gas commodity prices may adversely affect the demand for our products and services and the rates we are able to charge. 
+Our business depends, to a significant extent, on the level of unconventional resource development activity and corresponding capital spending of oil and natural gas companies, which are strongly influenced by current and expected oil and natural gas prices. Volatility or weakness in oil and natural gas commodity prices (or the perception that oil and natural gas commodity prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells or lower production spending on existing wells. Historically, oil and natural gas commodity prices have been extremely volatile. During the past five years ending December 31, 2019 , the posted price for West Texas Intermediate oil has ranged from a low of $26.19 per barrel in February 2016 to a high of $77.41 per barrel in June 2018, and the Henry Hub spot market price of gas has ranged from a low of $1.49 per MMBtu in January 2016 to a high of $6.24 per MMBtu in January 2018. On March 9, 2020, as a result of multiple significant factors impacting supply and demand in the global oil and natural gas markets, including the announced price reductions and possible production increases by members of OPEC and other oil exporting nations, the posted price for West Texas Intermediate oil declined sharply and may continue to decline. Oil and natural gas commodity prices are expected to continue to be volatile. If the prices of oil and natural gas continue to decline or remain depressed for a lengthy period, our business, financial condition, results of operations, cash flows, and prospects may be materially and adversely affected. 
+Significant factors that are likely to affect near-term commodity prices include the extent to which members of OPEC and other oil exporting nations continue to reduce oil export prices and increase production; the effect of U.S. energy, monetary, and trade policies; the pace of economic growth in the U.S. and throughout the world, including the potential for macro weakness; geopolitical and economic developments in the U.S. and globally; the outcome of the United States presidential election and subsequent energy and EPA policies; and overall North American natural gas supply and demand fundamentals, including the pace at which export capacity grows. For additional information, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – Industry Trends and Outlook” in Item 7 of Part II of this Annual Report. 
+On average, we expect customer budgets for 2020 to likely decrease as compared to 2019, which could adversely affect our business. Even if oil and natural gas prices improve, E&P operator activity may not materially increase, as they remain focused on operating within their capital plans. 
+The products and services we provide are, to a substantial extent, deferrable in the event oil and natural gas companies reduce capital expenditures. As a result, we may experience lower utilization of, and may be unable to increase rates or be forced to lower our rates for, our equipment and services in weak oil and natural gas commodity price environments. As an example, we believe that the drop in the price of oil at the end of 2018 had a negative impact on certain of our customers’ expectations about prices during 2019 and, as a result, the amount of their capital spending budgets for 2019. Any substantial and unexpected drop in commodity prices in the future, even if the drop is relatively short-lived, could similarly affect our customers’ expectations and capital spending, which could result in a material adverse effect on our business, financial condition, results of operations, cash flows, and prospects. 
+Reduced discovery rates of new oil and natural gas reserves in our market areas as a result of decreased capital spending may also have a negative long-term impact on our business, even in an environment of stronger oil and natural gas prices, to the extent the reduced number of wells for us to service more than offsets increasing completion activity and intensity. 
+Our business could be adversely affected by a decline in general economic conditions or a weakening of the broader energy industry. 
+A prolonged economic slowdown or recession, adverse events relating to the energy industry, or regional, national, or global economic conditions and factors, particularly a slowdown in the E&P industry, could negatively impact our operations and therefore adversely affect our results. The risks associated with our business are more acute during periods of economic slowdown or recession because such periods may be accompanied by decreased exploration and development spending by our customers, decreased demand for oil and natural gas, and decreased prices for oil and natural gas. 
+Our substantial debt obligations could have significant adverse consequences on our business and future prospects. 
+As of December 31, 2019 , we had $400.0 million of 8.750% Senior Notes due 2023 (the “Senior Notes”) outstanding, and we had $99.2 million of availability under the 2018 ABL Credit Facility (as defined and described in “Management’s 
+11 
+Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” in Item 7 of Part II of this Annual Report), net of an outstanding letter of credit of $0.2 million . Subject to the restrictions in the 2018 ABL Credit Facility and the indenture governing the Senior Notes, we may incur substantial additional indebtedness (including secured indebtedness) in the future. Our current or future level of indebtedness could have significant adverse consequences on our business and future prospects, including in the following ways: 
+• 
+requiring us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities; 
+• 
+limiting management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; 
+• 
+increasing our vulnerability to downturns and adverse developments in our business and the economy generally; 
+• 
+limiting our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures, or acquisitions or to refinance existing indebtedness; 
+• 
+making us vulnerable to increases in interest rates as our indebtedness under the 2018 ABL Credit Facility may vary with prevailing interest rates; 
+• 
+placing us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness; and 
+• 
+making it more difficult for us to satisfy our obligations under our debt instruments and increase the risk that we may default on our debt obligations. 
+We may not be able to generate sufficient cash to service all of our indebtedness. 
+Our ability to make scheduled payments with respect to our indebtedness depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business, and other factors beyond our control. If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to sell assets, seek additional capital, or restructure or refinance indebtedness. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations. For example, we may not be able to consummate dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. Also, our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. 
+If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest on our indebtedness, we could be in default under the terms of the agreements governing such indebtedness. An event of default, if not waived, could result in acceleration of the indebtedness outstanding under the applicable agreement and an event of default with respect to, and an acceleration of, the indebtedness outstanding under any other debt agreements to which we are a party. Any such accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments. In addition, any failure to make payments on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. 
+We may be unable to maintain existing prices or implement price increases on our products and services. 
+We periodically seek to increase the prices on our products and services to offset rising costs and to generate higher returns for our stockholders. However, we operate in a very competitive industry and as a result, we are not always successful in raising or maintaining our existing prices. Volatility in oil and natural gas prices can impact our customers’ activity levels, and current energy prices are important contributors to cash flow for our customers and their actual or perceived ability to fund exploration and development activities, which may limit our ability to increase or maintain prices. Additionally, during periods of increased market demand, a significant amount of new service capacity, including new well service rigs, wireline units, and coiled tubing units, may enter the market, which also puts pressure on the pricing of our services and limits our ability to increase prices. 
+Even when we are able to increase our prices, we may not be able to do so at a rate that is sufficient to offset rising 
+12 
+costs. In periods of high demand for oilfield services, a tighter labor market may result in higher labor costs. During such periods, our labor costs could increase at a greater rate than our ability to raise prices for our services. Also, we may not be able to successfully increase prices without adversely affecting our activity levels. The inability to maintain our pricing and to increase our pricing as costs increase could have a material adverse effect on our business, financial position, results of operations, and cash flows. 
+Intense competition in the markets for our dissolvable plug products may lead to pricing pressures, reduced sales, or reduced market share. 
+The oil and natural gas industry is intensely competitive and has been characterized by price erosion for new technologies as additional competing products enter the market. In recent months, we have experienced a decline in the pricing and profitability of our dissolvable plug products, including the products acquired in the Magnum Acquisition. Any further declines in the future may harm our business. 
+We compete with major domestic and international oilfield services companies, many of which have greater market recognition and substantially greater financial, technical, marketing, distribution, and other resources than we do. We have experienced pricing declines in certain of our more mature proprietary product lines, primarily due to competitive conditions. Likewise, our customers may seek pricing declines more precipitously than our ability to reduce costs, leaving us unable to achieve or maintain pricing to our customers at a level sufficient to cover our costs. 
+We have been able to moderate average selling price declines in many of our proprietary product lines by continuing to introduce new and differentiated products with more valuable features and higher prices. However, there can be no assurance that we will be able to do so in the future. If the amounts we are able to charge customers for our dissolvable plug products decline further or are insufficient to cover our costs, that could have a material adverse effect on our financial condition, results of operations, and cash flows. 
+If we are unable to accurately predict customer demand or if customers cancel their orders on short notice, we may hold excess or obsolete inventory, which would reduce gross margins. Conversely, insufficient inventory would result in lost revenue opportunities and potentially in loss of market share and damaged customer relationships. 
+We often place orders with our suppliers based on forecasts of customer demand. Anticipating customer demand is difficult because our customers face unpredictable demand for their own products and are increasingly focused on cash preservation and tighter inventory management. Our forecasts of customer demand are based on multiple assumptions, each of which may introduce errors into the forecasts. If we overestimate customer demand, we may allocate resources to the purchase of material or manufactured products that we may not be able to sell when we expect to, if at all. As a result, we would hold excess or obsolete inventory, which would reduce gross margin and adversely affect financial results. Conversely, if we underestimate customer demand or if insufficient manufacturing capacity is available, we would miss revenue opportunities and potentially lose market share and damage our customer relationships. In addition, any future significant cancellations or deferrals of orders or the return of previously sold products could materially and adversely affect profit margins, increase inventory obsolescence, and restrict our ability to fund our operations. 
+We may be unable to employ, or maintain the employment of, a sufficient number of key employees, technical personnel, and other skilled and qualified workers. 
+The delivery of our services and products requires personnel with specialized skills and experience, including personnel who can perform physically demanding work. Our ability to be profitable and productive will depend upon our ability to employ and retain skilled workers. Workers may choose to pursue employment with our competitors or in fields that offer a more desirable work environment as a result of the volatility in the oilfield service industry and the demanding nature of our work. In addition, the shortage of fixed housing and the lack of employee housing in certain areas where we operate could make it difficult for us to attract and retain quality, long-term personnel. The right-sizing of our and our competitors’ labor force over the sustained period of commodity price declines that began in late 2014, as well as a significant decrease in the wages paid by us or our competitors as a result of reduced industry demand, has resulted in a reduction of the available skilled labor force to service the energy industry, and there is no assurance that the availability of skilled labor will improve following a subsequent increase in demand for our products or services or an increase in wage rates. If we are unable to employ and retain skilled workers, our capacity and profitability could be diminished, and our growth potential could be impaired. 
+13 
+Our operations are subject to conditions inherent in the oilfield services industry. 
+Conditions inherent in the oil and natural gas industry can cause personal injury or loss of life, disruption or suspension in operations, damage to geological formations, damage to facilities, substantial revenue loss, business interruption, and damage to, or destruction of, property, equipment, and the environment. Such risks may include, but are not limited to: 
+• 
+equipment defects; 
+• 
+liabilities arising from accidents or damage involving our fleet of trucks and other equipment; 
+• 
+explosions and uncontrollable flows of gas or well fluids; 
+• 
+unusual or unexpected geological formations or pressures and industrial accidents; 
+• 
+blowouts; 
+• 
+fires; 
+• 
+cratering; 
+• 
+loss of well control; 
+• 
+collapse of the borehole; and 
+• 
+damaged or lost equipment. 
+Defects or other performance problems in the products that we sell or services that we offer could result in our customers seeking damages from us for losses associated with these defects or other performance problems. In addition, our services could become a source of spills or release of fluids, including chemicals used during hydraulic fracturing activities, at the site where such services are performed, or could result in the discharge of such fluids into underground formations that were not targeted for fracturing or well completion activities, such as potable aquifers, or at third-party properties. These risks could expose us to substantial liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution, and other environmental damages and could result in a variety of claims, losses, and remedial obligations that could have an adverse effect on our business and results of operations. The existence, frequency, and severity of such incidents could affect operating costs, insurability, and relationships with customers, employees, and regulators. In particular, our customers may elect not to purchase our services if they view our safety record as unacceptable or otherwise experience material defects in our products or performance problems, which could cause us to lose customers and substantial revenue, and any litigation or claims, even if fully indemnified or insured, could negatively affect our reputation with our customers and the public and make it more difficult for us to compete effectively or obtain adequate insurance in the future. 
+Our success may be affected by the use and protection of our proprietary technology as well as our ability to enter into license agreements. There are limitations to our intellectual property rights and, thus, our right to exclude others from the use of such proprietary technology. 
+Our success may be affected by our development and implementation of new product designs and improvements and by our ability to protect, obtain, and maintain intellectual property assets related to these developments. We rely on a combination of patents and trade secret laws to establish and protect this proprietary technology. We have received patents and have filed patent applications with respect to certain aspects of our technology, and we generally rely on patent protection with respect to our proprietary technology, as well as a combination of trade secrets and copyright law, employee and third-party non-disclosure agreements, and other protective measures to protect intellectual property rights pertaining to our products and technologies. In addition, we are a party to and rely on several arrangements with third parties, which give us exclusive distribution rights to certain product offerings with desirable intellectual property assets, and we may enter into similar arrangements in the future. Such measures may not provide meaningful protection of our trade secrets, know-how, or other intellectual property in the event of any unauthorized use, misappropriation, or disclosure. We cannot assure you that competitors will not infringe upon, misappropriate, violate, or challenge our intellectual property rights in the future. Additionally, we cannot assure you that our intellectual property rights will deter or prevent competitors from creating similar purpose products for our customers. If we are not able to adequately protect or enforce our intellectual property rights, such intellectual property rights may not provide significant value to our business, results of operations, or financial condition. 
+Moreover, our rights in our confidential information, trade secrets, and confidential know-how will not prevent third parties from independently developing similar technologies or duplicating such technologies. Publicly available information 
+14 
+(e.g., information in issued patents, published patent applications, and scientific literature) can be used by third parties to independently develop technology, and we cannot provide assurance that this independently-developed technology will not be equivalent or superior to our proprietary technology. In addition, while we have patented some of our key technologies, we do not patent all of our proprietary technology, even when regarded as patentable. The process of seeking patent protection can be long and expensive. There can be no assurance that patents will be issued from currently pending or future applications or that, if patents are issued, they will be of sufficient scope or strength to provide meaningful protection or any commercial advantage to us. Further, with respect to exclusive third-party arrangements, these arrangements could be terminated, which would result in our inability to provide the services and/or products covered by such arrangements. 
+We may be adversely affected by disputes regarding intellectual property rights, and the value of our intellectual property rights is uncertain. 
+We may become involved in dispute resolution proceedings from time to time to protect and enforce our intellectual property rights. In these dispute resolution proceedings, a defendant may assert that our intellectual property rights are invalid or unenforceable. Third parties from time to time may also initiate dispute resolution proceedings against us by asserting that our businesses infringe, impair, misappropriate, dilute, or otherwise violate another party’s intellectual property rights. We may not prevail in any such dispute resolution proceedings, and our intellectual property rights may be found invalid or unenforceable or our products and services may be found to infringe, impair, misappropriate, dilute, or otherwise violate the intellectual property rights of others. The results or costs of any such dispute resolution proceedings may have an adverse effect on our business, operating results, and financial condition. Any dispute resolution proceeding concerning intellectual property could be protracted and costly, is inherently unpredictable, and could have an adverse effect on our business, regardless of its outcome. 
+We are exposed to the credit risk of our customers, and the deterioration of the financial condition of our customers could adversely affect our financial results. 
+We are subject to the risk of loss resulting from nonpayment or nonperformance by our customers, many of whose operations are concentrated solely in the domestic and Canadian E&P industry, which, as described above, is subject to volatility and, therefore, credit risk. Our credit procedures and policies may not be adequate to fully reduce customer credit risk. If we are unable to adequately assess the creditworthiness of existing or future customers or unanticipated deterioration in their creditworthiness, any resulting increase in nonpayment or nonperformance by them and our inability to re-market or otherwise use our equipment could have a material adverse effect on our business, financial condition, prospects, and/or results of operations. In the course of our business, we hold accounts receivable from our customers. In the event of the financial distress or bankruptcy of a customer, we could lose all or a portion of such outstanding accounts receivable associated with that customer. Further, if a customer was to enter into bankruptcy, it could also result in the cancellation of all or a portion of our service contracts with such customer at significant expense or loss of expected revenues to us. 
+In addition, during times when the oil or natural gas markets weaken, our customers are more likely to experience financial difficulties, including being unable to access debt or equity financing, which could result in a reduction in our customers’ spending for our products and services. 
+We have operated at a loss in the past, and there is no assurance of our profitability in the future. 
+Historically, we have experienced periods of low demand for our products and services and have incurred operating losses. In the future, we may not be able to reduce our costs, increase our revenues, or reduce our debt service obligations sufficiently to achieve or maintain profitability and generate positive operating income. Under such circumstances, we may incur further operating losses and experience negative operating cash flow. 
+Restrictions in our debt agreements could limit our growth and our ability to engage in certain activities. 
+The 2018 ABL Credit Facility (as defined and described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” in Item 7 of Part II of this Annual Report) and the indenture governing our Senior Notes have, and future financing agreements could have, restrictive covenants that could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities. For example, our debt agreements contain restrictive covenants that limit our ability to, among other things: 
+• 
+incur additional indebtedness and guarantee indebtedness; 
+• 
+pay dividends or make other distributions or repurchase or redeem our capital stock; 
+• 
+transfer or sell assets; 
+15 
+• 
+make loans and investments; 
+• 
+incur liens; 
+• 
+enter into agreements that restrict dividends or other payments from any non-guarantor restricted subsidiaries to us; 
+• 
+consolidate, merge, or sell all or substantially all of our assets; 
+• 
+prepay, redeem, or repurchase certain debt; 
+• 
+issue certain preferred stock or similar equity securities; 
+• 
+make certain acquisitions and investments; 
+• 
+engage in transactions with affiliates; and 
+• 
+create unrestricted subsidiaries. 
+The restrictions in our debt agreements could also impact our ability to obtain capital to withstand a downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our debt arrangements may impose on us. 
+A breach of any covenant in our debt agreements will result in a default under the applicable agreement and an event of default under such agreement if there is no grace period or if such default is not cured during any applicable grace period. An event of default, if not waived, could result in acceleration of the indebtedness outstanding under the applicable agreement and an event of default with respect to, and an acceleration of, the indebtedness outstanding under any other debt agreements to which we are a party. Any such accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us. 
+Our current and potential competitors may have longer operating histories, significantly greater financial or technical resources, and greater name recognition than we do. 
+The oilfield services industry is highly competitive and fragmented and includes several large companies that compete in many of the markets we serve, as well as numerous small companies that compete with us on a local basis. The oilfield services industry competes primarily on a regional basis, and the intensity of competition may vary significantly from region to region at any particular time. We believe the principal competitive factors in the market areas we serve include price, equipment quality, supply chains, balance sheet strength and financial condition, product and service quality, safety record, availability of crews and equipment, and technical proficiency. 
+Many of our existing and potential competitors have substantially greater financial, technical, manufacturing, and other resources than we do. The greater size of many of our competitors provides them with cost advantages as a result of their economies of scale and their ability to obtain volume discounts and purchase raw materials at lower prices. As a result, such competitors may have stronger bargaining power with their suppliers and have an advantage over us in pricing as well as securing a sufficient supply of raw materials during times of shortage. Many of our competitors also have better brand name recognition, stronger presence in more geographic markets, more established distribution networks, larger customer bases, more in-depth knowledge of the target markets, and the ability to provide a much broader array of products and services. Some of our competitors may also be able to devote greater resources to the research and development, promotion, and sale of their products and better withstand the evolving industry standards and changes in market conditions as compared to us. Our operations may be adversely affected if our competitors introduce new products or services with better features, performance, prices, or other characteristics than our products and services or expand into service areas where we operate. Our operations may also be adversely affected if our competitors are able to respond more quickly to new or emerging technologies and services and changes in customer requirements. 
+Competitive pressures could reduce our market share or require us to reduce the price of our services and products, particularly during industry downturns, either of which would harm our business and operating results. Significant increases in overall market capacity have also caused active price competition and led to lower pricing and utilization levels for our services and products. The competitive environment has intensified since the industry downturn that began in late 2014, which caused an oversupply of, and reduced demand for, oilfield services, and we have seen substantial reductions in the prices we can 
+16 
+charge for our services and products. Any significant future increase in overall market capacity for completion services may adversely affect our business, financial condition, and results of operations. 
+Fuel conservation measures may reduce oil and natural gas demand. 
+Fuel conservation measures, alternative fuel requirements, and increasing consumer demand for alternatives to oil and natural gas, as well as the increased competitiveness of alternative energy sources (such as wind, solar geothermal, tidal, fuel cells, and biofuels), could reduce demand for oil and natural gas and therefore our products and services, which would lead to a reduction in our revenues and have a material adverse effect on our business, financial condition, results of operations, cash flows, and prospects. 
+Our success may be affected by our ability to implement new technologies and services. Additionally, we rely on a limited number of manufacturers to produce the proprietary products used in the provision of our services, which exposes us to risks. 
+Our success may be affected by the ongoing development and implementation of new product designs, methods, and improvements, and our ability to protect, obtain, and maintain intellectual property assets related to these developments. If we are not able to obtain patent or other protection of our technology, it may not be economical for us to continue to develop systems, services, and technologies to meet evolving industry requirements at prices acceptable to our customers. Further, we may face competitive pressure to develop, implement, or acquire certain new technologies at a substantial cost. Although we take measures to ensure that we use advanced technologies, changes in technology or improvements in our competitors’ equipment could make our equipment less competitive or require significant capital investments to keep our equipment competitive. 
+We currently rely on a limited number of manufacturers for production of the proprietary products used in the provision of our products and services. Termination of the manufacturing relationship with any of these manufacturers could affect our ability to provide such products and services to our customers. Although we believe other alternate sources of supply for our proprietary products exist, we would need to establish relationships with new manufacturers, which could potentially involve significant expense, delay, and potential changes to certain product components. Any protracted curtailment or interruptions of the supply of any of our key products, whether or not as a result or termination of our manufacturing relationships or patent infringement claims, could have a material adverse effect on our financial condition, business, and results of operations. 
+Some of our competitors are large national and multinational companies that may be able to devote greater financial, technical, manufacturing, and marketing resources to research and development of new systems, services, and technologies and may have a larger number of manufacturers for their products or ability to manufacture their own products. As competitors and others use or develop new or comparable technologies in the future, we may lose market share or be placed at a competitive disadvantage if we are not able to develop and implement new technologies or products on a timely basis or at an acceptable cost. If we are unable to compete effectively given these risks, our business and results of operations could be affected. 
+Uncertainty relating to the LIBOR calculation process and potential phasing out of LIBOR after 2021 may adversely affect the market value of our current or future debt obligations. 
+Loans to us and our domestic related subsidiaries under the 2018 ABL Credit Facility (as defined and described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” in Item 7 of Part II of this Annual Report) may be base rate loans or London Interbank Offered Rate (“LIBOR”) loans. LIBOR is calculated by reference to a market for interbank lending, and it is based on increasingly fewer actual transactions. This reduction increases the subjectivity of the LIBOR calculation process and increases the risk of manipulation. Actions by the regulators or law enforcement agencies, as well as ICE Benchmark Administration (the current administrator of LIBOR), may result in changes to the manner that LIBOR is determined or the establishment of alternative reference rates. For example, on July 27, 2017, the U.K. Financial Conduct Authority announced that it intends to stop persuading or compelling banks to submit LIBOR rates after 2021. U.S. Dollar LIBOR will likely be replaced by the Secured Overnight Financing Rate (“SOFR”) published by the Federal Reserve Bank of New York; however, the timing of this shift is currently unknown. SOFR is an overnight rate instead of a term rate, making SOFR an inexact replacement for LIBOR, and there is not an established process to create robust, forward-looking, SOFR term rates. Changing the benchmark rate for LIBOR loans from LIBOR to SOFR requires calculations of a spread. Industry organizations are attempting to structure the spread calculation in a manner that minimizes the possibility of value transfer between counterparties, borrowers, and lenders by the transition, but there is no assurance that the calculated spread will be fair and accurate. At this time, it is not possible to predict the effect of any such changes, any establishment of alternative reference rates or any other reforms to LIBOR that may be implemented. If LIBOR ceases to exist, we may need to renegotiate the 2018 ABL Credit Facility to determine the interest rate to replace LIBOR with 
+17 
+the new standard that is established. As such, the potential effect of any such event on our interest expense cannot yet be determined. 
+A negative shift in investor sentiment of the oil and gas industry could adversely affect our ability to raise debt and equity capital. 
+Certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition, some investors, including investment advisors and certain sovereign wealth funds, pension funds, university endowments, and family foundations, have stated policies to disinvest in the oil and gas sector based on their social and environmental considerations. Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas production and related infrastructure projects. Such developments, including environmental activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, including ours. These developments may also potentially result in a reduction of available capital funding for potential development projects, impacting our future financial results. 
+Certain of our product lines are subject to the risk of supplier concentration. 
+Certain of the product lines acquired in the Magnum Acquisition depend on a limited number of third-party suppliers and vendors. As a result of this concentration in some supply chains, our business and operations could be negatively affected if certain key suppliers were to experience significant disruptions affecting the price, quality, availability, or timely delivery of their products. The partial or complete loss of any one of those key suppliers, or a significant adverse change in the relationship with any such suppliers, through consolidation or otherwise, may limit our ability to manufacture and sell certain of our product lines. 
+Our assets require capital for maintenance, upgrades, and refurbishment, and we may require capital expenditures for new equipment. 
+Our equipment requires capital investment in maintenance, upgrades, and refurbishment to maintain their competitiveness. For the years ended December 31, 2019 and 2018 , we spent approximately $13.6 million and $11.6 million , respectively, on capital expenditures related to maintenance. Our equipment typically does not generate revenue while it is undergoing maintenance, refurbishment, or upgrades. Any maintenance, upgrade, or refurbishment project for our assets could increase our indebtedness or reduce cash available for other opportunities. Further, such projects may require proportionally greater capital investments as a percentage of total asset value, which may make such projects difficult to finance on acceptable terms. To the extent we are unable to fund such projects, we may have less equipment available for service or our equipment may not be attractive to potential or current customers. Additionally, competition or advances in technology within our industry may require us to update our products and services. Such demands on our capital or reductions in demand and the increase in cost to maintain labor necessary for such maintenance and improvement, in each case, could have a material adverse effect on our business, liquidity position, financial condition, prospects, and results of operations and may increase costs. 
+Our future financial condition and results of operations could be adversely impacted by long-lived assets, goodwill, or other asset impairment charges. 
+Determining whether an impairment exists and the amount of the potential impairment involves quantitative data and qualitative criteria that are based on estimates and assumptions requiring significant management judgment, such as those relating to revenue growth rates, future cash flows, and future market conditions. Future events or new information, including regarding the general economic environment, E&P activity levels, our financial performance and trends, and our strategies and business plans, may change management’s valuation of long-lived assets, goodwill, other intangible assets, or other assets in a short amount of time. In particular, prolonged periods of decreased demand, low utilization, changes in technology or market conditions, or sales and other dispositions of assets for amounts less than their carrying value may cause us to recognize impairment charges relating to our long-lived assets, goodwill, other intangible assets, or other assets that reduce our net income. 
+In 2019, we recorded a goodwill impairment charge of $20.3 million and an intangible asset impairment charge of $12.7 million associated with indefinite-lived trade names in our coiled tubing reporting unit within our Completion Solutions segment; and an intangible asset impairment charge of $7.1 million associated with definite-lived customer relationship intangible assets and a property and equipment impairment charge of $66.2 million in our coiled tubing asset group within our Completion Solutions segment. These impairment charges were due to a reduction of the need for coiled tubing during the drill-out phase of the overall completions process due to a recent decline in exploration and production capital budgets and activity, an over-supply of new coiled tubing units and the introduction of dissolvable plug technology. Additionally, in 2019, we 
+18 
+recorded an intangible asset impairment charge of $95.0 million associated with indefinite-lived trade names in our completion tools reporting unit within our Completion Solutions segment and due to the transitioning of certain Magnum trade names to our trade names in order to better funnel and allocate resources, create a stronger identity, facilitate cross-selling, and streamline and simplify communication with existing customers. 
+In 2018, we recorded a goodwill impairment charge of $13.0 million , which represents a full write-off of goodwill attributed to our Production Solutions segment, an intangible asset impairment charge of $9.3 million associated with indefinite-lived trade names, an intangible asset impairment charge of $9.8 million associated with definite-lived customer relationship intangible assets, and a property and equipment impairment charge of $45.7 million , in each case associated with our Production Solutions segment and due to depressed commodity prices towards the end of the fourth quarter of 2018, coupled with customers focusing more on the completions business where there is more technological differentiation and value. 
+In 2017, we recorded a goodwill impairment charge of $31.5 million and an intangible asset impairment charge of $3.8 million associated with definite-lived customer relationship intangible assets, in each case associated with a unit in our Completion Solutions segment and due to declining profitability and deteriorating market conditions, which included a shift from open hole completions to significantly less profitable cemented liners. 
+While we believe our estimates and assumptions used in impairment tests are reasonable, we cannot provide assurance that additional impairment charges in the future will not be required, especially if an economic downturn occurs and continues for a lengthy period or becomes severe or if our acquisitions and investments fail to achieve expected returns. Significant impairment charges as a result of a decline in market conditions or otherwise could have a material adverse effect on our financial condition or results of operations in future periods. 
+Seasonal and adverse weather conditions adversely affect demand for our products and services. 
+Weather can have a significant impact on demand for our services and products as consumption of energy is seasonal, and any variation from normal weather patterns or cooler or warmer summers and winters can have a significant impact on demand. In addition, adverse weather conditions, such as hurricanes, tropical storms, and severe cold weather, may interrupt or curtail our operations or our customers’ operations, cause supply disruptions, and damage our equipment and facilities, which may or may not be insured. During the winter months (portions of the first and fourth quarters) and periods of heavy snow, ice, or rain, particularly in the northeastern U.S., Michigan, North Dakota, Wyoming, and western Canada, our customers may delay operations, or we may not be able to operate or move our equipment between locations. Also, during the spring thaw, which normally starts in late March and continues through June, some areas, primarily in western Canada, impose transportation restrictions to prevent damage caused by the spring thaw. For the years ended December 31, 2019 and 2018 , we generated approximately 2.2% and 3.7% , respectively, of our revenue from our operations in western Canada. Lastly, throughout the year heavy rains adversely affect activity levels because well locations and dirt access roads can become impassible in wet conditions. 
+In addition, we typically have experienced a pause by our customers around the holiday season in the fourth quarter, which may be compounded as our customers exhaust their annual capital spending budgets towards year end. 
+Oilfield anti-indemnity provisions enacted by many states may restrict or prohibit a party’s indemnification of us. 
+We typically enter into agreements with our customers governing the provision of our services, which usually include certain indemnification provisions for losses resulting from operations. Such agreements may require each party to indemnify the other against certain claims regardless of the negligence or other fault of the indemnified party; however, many states place limitations on contractual indemnity agreements, particularly agreements that indemnify a party against the consequences of its own negligence. Furthermore, certain states, including Louisiana, New Mexico, Texas, and Wyoming, have enacted statutes generally referred to as “oilfield anti-indemnity acts” expressly prohibiting certain indemnity agreements contained in or related to oilfield services agreements. Such oilfield anti-indemnity acts may restrict or void a party’s indemnification of us, which could have a material adverse effect on our business, financial condition, prospects, and results of operations. 
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+The growth of our business through acquisitions may expose us to various risks, including those relating to difficulties in identifying suitable, accretive acquisition opportunities and integrating businesses, assets, systems, and personnel, as well as difficulties in obtaining financing for targeted acquisitions and the potential for increased leverage or debt service requirements. 
+As a component of our business strategy, we have pursued and may continue to pursue selected, accretive acquisitions of complementary assets, businesses, and technologies, such as the Magnum Acquisition. Acquisitions involve numerous risks, including: 
+• 
+unanticipated costs and assumption of liabilities and exposure to unforeseen liabilities of acquired businesses, including, but not limited to, environmental liabilities; 
+• 
+difficulties in integrating the businesses, assets and financial accounting, operating, information and other systems of the acquired business, and the acquired personnel; 
+• 
+limitations on our ability to properly assess and maintain an effective internal control environment over an acquired business in order to comply with public reporting requirements; 
+• 
+potential losses of key employees and customers of the acquired businesses; 
+• 
+inability to commercially develop acquired technologies; 
+• 
+risks of entering markets in which we have limited prior experience; and 
+• 
+increases in our expenses and working capital requirements. 
+The process of integrating an acquired business may involve unforeseen costs and delays or other operational, technical, and financial difficulties and may require a disproportionate amount of management attention and financial and other resources. In addition, even following successful integration, the anticipated benefits of an acquisition may not be realized fully or at all or may take longer to realize than expected. Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully, or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations. 
+With respect to the Magnum Acquisition in particular, we are devoting significant management attention and resources to integrating Magnum’s business practices, cultures, and operations. Also, we have assumed certain potential liabilities and could be exposed to additional unknown and contingent liabilities associated with Magnum, including post-closing tax obligations and other liabilities for activities of Magnum before the consummation of the Magnum Acquisition, including violations of laws, rules and regulations, commercial disputes, tax liabilities, and other known and unknown liabilities. We have performed a certain level of due diligence in connection with the Magnum Acquisition and have attempted to verify the representations made by Magnum, but there may be liabilities related to Magnum of which we are unaware. There is a risk that we could ultimately be liable for obligations such as post-closing tax obligations relating to Magnum for which indemnification is either not available or not sufficient, which could materially adversely affect our business, results of operations, and cash flow. 
+There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Furthermore, we may not have sufficient capital resources to complete additional acquisitions. Historically, we have financed acquisitions primarily with funding from our equity investors, cash generated by operations, and borrowings. We may incur substantial indebtedness to finance future acquisitions and also may issue equity, debt, or convertible securities in connection with such acquisitions. Any additional debt service requirements could represent a significant burden on our results of operations and financial condition, and the issuance of additional equity or convertible securities could be dilutive to our existing stockholders. Furthermore, we may not be able to obtain additional financing on satisfactory terms. Even if we have access to the necessary capital, we may be unable to continue to identify additional suitable acquisition opportunities, negotiate acceptable terms, or successfully acquire identified targets. 
+Our ability to grow through acquisitions and manage growth will require us to continue to invest in operational, financial, and management information systems and to attract, retain, motivate, and effectively manage our employees. The inability to effectively manage the integration of acquisitions could reduce our focus on current operations and subsequent acquisitions, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods. 
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+We are subject to federal, state, and local laws and regulations regarding issues of health, safety, and protection of the environment. Under these laws and regulations, we may become liable for penalties, damages, or costs of remediation or other corrective measures. Any changes in laws or government regulations could increase our costs of doing business. 
+Our operations are subject to stringent federal, state, local, and tribal laws and regulations relating to, among other things, protection of natural resources, clean air and drinking water, wetlands, endangered species, greenhouse gases, nonattainment areas, the environment, occupational health and safety, chemical use and storage, waste management, waste disposal, and transportation of waste and other hazardous and nonhazardous materials. Our operations involve risks of environmental liability, including leakage from an operator’s casing during our operations or accidental spills of hazardous materials onto or into surface or subsurface soils, surface water, or groundwater. Some environmental laws and regulations may impose strict liability, joint and several liability, or both. In some situations, we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, third parties without regard to whether we caused or contributed to the conditions. Additionally, environmental concerns, including clean air, drinking water contamination, and seismic activity, have prompted investigations that could lead to the enactment of regulations, limitations, restrictions, or moratoria that could potentially have a material adverse impact on our business. Actions arising under these laws and regulations could result in the shutdown of our operations, fines and penalties (administrative, civil, or criminal), revocations of permits to conduct business, expenditures for remediation or other corrective measures, and/or claims for liability for property damage, exposure to hazardous materials, exposure to hazardous waste, nuisance, or personal injuries. Sanctions for noncompliance with applicable environmental laws and regulations may also include the assessment of administrative, civil, or criminal penalties, revocation of permits and temporary or permanent cessation of operations in a particular location, and issuance of corrective action orders. Such claims or sanctions and related costs could cause us to incur substantial costs or losses and could have a material adverse effect on our business, financial condition, prospects, and results of operations. Additionally, an increase in regulatory requirements or limitations, restrictions, or moratoria on oil and natural gas exploration and completion activities at a federal, state, or local level could significantly delay or interrupt our operations, limit the amount of work we can perform, increase our costs of compliance, or increase the cost of our services, thereby possibly having a material adverse impact on our financial condition. 
+If we do not perform our operations in accordance with government, industry, customer, or our own stringent occupational safety, health, and environmental standards, we could lose business from our customers, many of whom have an increased focus on environmental and safety issues. 
+We are subject to the oversight of the EPA, the U.S. Department of Transportation (the “DOT”), U.S. Nuclear Regulation Commission, Bureau of Alcohol, Tobacco, Firearms and Explosives, OSHA, and state regulatory agencies that regulate operations to prevent air, soil, and water pollution. The energy extraction sector is one of the sectors designated for increased enforcement by the EPA, which will continue to regulate our industry in the years to come, potentially resulting in additional regulations that could have a material adverse impact on our business, prospects, or financial condition. 
+The EPA regulates air emissions from all engines, including off-road diesel engines that are used by us to power equipment in the field under the CAA Tier 4 emission standards. The Tier 4 standards (the “Tier 4” standards) require substantial reductions in emissions of particulate matter and nitrous oxide from off-road diesel engines. Such emission reductions can be achieved through the use of appropriate control technologies. Under these U.S. emission control regulations, we could be limited in the number of certain off-road diesel engines we can purchase if we are unable to find a sufficient number of Tier 4-compliant engines from manufacturers. Further, these emission control regulations could result in increased capital and operating costs. 
+Changes in environmental laws and regulations could lead to material increases in our costs, and liability exposure, for future environmental compliance and remediation. Additionally, if we expand the size or scope of our operations, we could be subject to regulatory requirements that are more stringent than the requirements under which we are currently allowed to operate or require additional authorizations to continue operations. Compliance with this additional regulatory burden could increase our operating or other costs. 
+We face various risks associated with increased activism against oil and natural gas exploration and development activities. 
+Opposition toward oil and natural gas drilling and development activity has been growing globally and is particularly pronounced in the United States. Companies in the oil and natural gas industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, human rights, environmental matters, sustainability, and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain operations such as drilling and development. If activism against oil and natural gas exploration and development persists or increases, there could be a material adverse effect on our business, financial condition, and results of operations. 
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+Federal, state, and local legislative and regulatory initiatives relating to hydraulic fracturing could prohibit, restrict, or limit hydraulic fracturing operations, or increase our operating costs. 
+Our businesses are dependent on hydraulic fracturing and horizontal drilling activities. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. 
+There is considerable uncertainty surrounding regulation of methane emissions. In 2016, the EPA issued final regulations under the CAA establishing performance standards, including standards for the capture of methane emissions released during hydraulic fracturing. However, the EPA has taken several steps to delay implementation of its methane standards, including most recently in September 2018, when the EPA announced a proposed rule that rolls back parts of the 2016 performance standards. Various industry and environmental groups have separately challenged both the original standards and the EPA’s attempts to delay implementation of the rule. Separately, in August 2019, the EPA issued proposed amendments that would rescind requirements related to the regulation of methane emissions from the oil and natural gas industry. Neither rulemaking has been finalized and, therefore, future obligations continue to remain uncertain. In addition, in April 2018, a coalition of states filed a lawsuit in the U.S. District Court for the District of Columbia aiming to force the EPA to establish guidelines for limiting methane emissions from existing sources in the oil and natural gas sector; that lawsuit is pending. On March 20, 2015, the BLM finalized a rule regulating hydraulic fracturing activities on federal lands, including requirements for disclosure, wellbore integrity, and handling of flowback water; however, on December 29, 2017, the BLM issued a rescission of the hydraulic fracturing rule. This rescission and the rule as promulgated are subject to ongoing litigation. The BLM also previously finalized in 2016 similar limitations on methane emissions from venting and flaring and leaking equipment from oil and natural gas activities on public lands, but in September 2018 issued a final rule repealing certain provisions of the 2016 rule and reinstating the pre-2016 regulations. This repeal is the subject of legal challenges. As a result, future implementation of both the EPA and BLM methane rules is uncertain at this time. However, given the long-term trend towards increasing regulation, future federal regulation of methane and other greenhouse gas emissions from the oil and gas industry remains a possibility. 
+The EPA has also issued effluent limitation guidelines that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. These rules were finalized in June 2016. The EPA is currently conducting a study on effluent guidelines for the oil and gas extraction industry, and a draft of this study was published in May 2019. It is unclear how any additional federal regulation of hydraulic fracturing activities may affect our operations, but additional regulatory burdens on our customers could ultimately result in decreased demand for our products and services. 
+Various studies analyzing the potential environmental impacts of hydraulic fracturing have also been performed. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals, or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. As described elsewhere in this Annual Report, these risks are regulated under various state, federal, and local laws. 
+Some states, counties, and municipalities have enacted or are considering moratoria on hydraulic fracturing. For example, New York, Vermont, Maryland, and Washington have banned, or are in the process of banning, the use of high-volume hydraulic fracturing. Alternatively, some municipalities are, or have considered, zoning and other ordinances, the conditions of which could impose a de facto ban on drilling and/or hydraulic fracturing operations. Further, some states, counties, and municipalities are closely examining water use issues, such as permit and disposal options for processed water, which could have a material adverse impact on our financial condition, prospects, and results of operations if such additional permitting requirements are imposed upon our industry. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could reduce demand for our business by making it more difficult or costly for certain customers to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the 
+22 
+federal level as a result of federal legislation or regulatory initiatives by the EPA, the business and operations of our customers could be subject to additional permitting requirements, and also to attendant permitting delays, increased operating and compliance costs, and process prohibitions, which could have an adverse effect on our business, financial condition, and results of operations. 
+Existing or future laws and regulations related to greenhouse gases and climate change could have a negative impact on our business and may result in additional compliance obligations with respect to the release, capture, and use of greenhouse gases that could have a material adverse effect on our business, results of operations, prospects, and financial condition. 
+Changes in environmental requirements related to greenhouse gas emissions and climate change may negatively impact demand for our products and services. For example, oil and natural gas E&P may decline as a result of environmental requirements, including land use policies responsive to environmental concerns (e.g., certain cities have banned the use of natural gas in new construction starting in 2020 (e.g., Berkeley and San Jose, CA) or the installation of new natural gas hookups (e.g., Brookline, MA), and other cities (e.g., Seattle, WA) are considering similar initiatives). Federal, state, and local agencies have been evaluating climate-related legislation and other regulatory initiatives that would restrict emissions of greenhouse gases in areas in which we conduct business. Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws and regulations related to greenhouse gases and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our business if such laws or regulations reduce demand for oil and natural gas. Likewise, such restrictions may result in additional compliance obligations with respect to the release, capture, sequestration, and use of greenhouse gases that could have a material adverse effect on our business, results of operations, prospects, and financial condition. Finally, most scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that could have significant physical effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events; if such effects were to occur, they could have an adverse impact on our operations. 
+Studies by either state or federal agencies demonstrating a correlation between earthquakes and oil and natural gas activities could result in increased regulatory and operational burdens. 
+In light of concerns about seismic activity being triggered by the injection of produced waters into underground wells, certain regulators are also considering additional requirements related to seismic safety for hydraulic fracturing activities. A 2015 U.S. Geological Survey report identified eight states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. Any regulation that restricts the ability of our customers to dispose of produced waters or increases their cost of doing business could cause them to curtail operation, which in turn could decrease demand for our products and services and have a material adverse effect on our business. 
+A portion of our revenue is derived from sales to customers outside of the United States, which exposes us to risks inherent in doing business internationally. 
+In 2019 , we derived 5.1% of our revenue from sales to customers outside of the United States. Sales to customers in countries other than the United States are subject to various risks, including: 
+• 
+volatility in political, social, and economic conditions; 
+• 
+social unrest, acts of terrorism, war, or other armed conflicts; 
+• 
+confiscatory taxation or other adverse tax policies; 
+• 
+deprivation of contract rights; 
+• 
+trade and economic sanctions or other restrictions imposed by the European Union, the United States, or other countries; 
+• 
+exposure under the U.S. Foreign Corrupt Practices Act (the “FCPA”) or similar legislation, as discussed in the below risk factor; and 
+• 
+currency exchange controls. 
+We are subject to complex U.S. and foreign laws and regulations governing anti-corruption and export controls and economic sanctions . 
+The FCPA, the U.K. Bribery Act (“UKBA”), Canada’s Corruption of Foreign Public Officials Act (the “CFPOA”), and 
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+similar anti-bribery and anticorruption laws generally prohibit companies and their intermediaries from making improper payments or improperly providing anything of value for the purpose of obtaining or retaining business. Following the Magnum Acquisition, we now operate and make sales in parts of the world that may be viewed as higher risk for corruption or may have experienced some corruption in the past, and in some instances, strict compliance with the FCPA, UKBA, CFPOA, and similar anti-bribery laws may conflict with local practices. We are also subject to export control and economic sanctions laws and regulations, including those implemented by the U.S. Office of Foreign Assets Control, the U.S. Department of State, the U.S. Department of Commerce, the European Union and its member states, Her Majesty’s Treasury of the United Kingdom, and other relevant sanctions authorities. These measures can prohibit or restrict transactions and dealings with certain designated persons and in certain countries in which we conduct business. Despite efforts to ensure compliance, there can be no assurance that our directors, officers, employees, agents, and third-party intermediaries will comply with such laws and regulations. We can be held liable for violations under such laws and regulations either due to our acts or omissions or due to the acts or omissions of others, including intermediaries working on our behalf. 
+If we fail to comply with applicable laws and regulations, including those referred to above, we may be subject to criminal and civil penalties or other sanctions, which could harm our reputation and have a material adverse impact on our business, financial condition, results of operations, and prospects. Any investigation of any actual or alleged violations of such laws could also harm our reputation or have an adverse impact on our business, financial condition, results of operations, and prospects. Additionally, we could face other third-party claims by agents, stockholders, debt holders, or other interest holders or constituents of our company. Our customers in relevant jurisdictions could seek to impose penalties or take other actions adverse to our interests, and we may be required to dedicate significant time and resources to investigate and resolve allegations of misconduct, regardless of the merit of such allegations. Furthermore, compliance with this additional regulatory burden could increase our operating or other costs. 
+We may be subject to claims for personal injury and property damage or other litigation, which could materially adversely affect our financial condition, prospects, and results of operations. 
+Our services are subject to inherent risks that can cause personal injury or loss of life, damage to or destruction of property, equipment, or the environment, or the suspension of our operations. As the wells we service continue to become more complex, our exposure to such inherent risks becomes greater as downhole risks increase exponentially with an increase in complexity and lateral length. Our operations are also exposed to risks of labor organizing and risks of claims for alleged employment-related liabilities, including risks of claims related to alleged wrongful termination or discrimination, wage payment practices, retaliation claims, and other human resource related matters. Litigation arising from operations where our facilities are located, or our services are provided, may cause us to be named as a defendant in lawsuits asserting potentially large claims, including claims for exemplary damages. For example, transportation of heavy equipment creates the potential for our trucks to become involved in roadway accidents, which in turn could result in personal injury or property damages lawsuits being filed against us. 
+We maintain what we believe is customary and reasonable insurance to protect our business against most potential losses, but such insurance may not be adequate to cover our liabilities, especially as the inherent risks in our operations increase with increasing well complexity, and we are not fully insured against all risks, including alleged employment-related liabilities. Further, our insurance has deductibles or self-insured retentions and contains certain coverage exclusions. The current trend in the insurance industry is towards larger deductibles and self-insured retentions. In addition, insurance may not be available in the future at rates that we consider reasonable and commercially justifiable, compelling us to have larger deductibles or self-insured retentions to effectively manage expenses. As a result, we could become subject to material uninsured liabilities or situations where we have high deductibles or self-insured retentions that expose us to liabilities that could have a material adverse effect on our business, financial condition, prospects, or results of operations. 
+In recent years, oilfield services companies have been the subject of a significant volume of wage and hour-related litigation, including claims brought under the Fair Labor Standards Act (“FLSA”), in which employee pay practices have been challenged. We have been named as defendants in these lawsuits, and we do not maintain insurance for alleged wage and hour-related litigation. Some of these cases remain outstanding and are in various states of negotiation and/or litigation. The frequency and significance of wage- or other employment-related claims may affect expenses, costs, and relationships with employees and regulators. Additionally, we could become subject to material uninsured liabilities that could have a material adverse effect on our business, financial condition, prospects, or results of operations. 
+Our operations are subject to cyber security risks that could have a material adverse effect on our results of operations and financial condition. 
+The efficient operation of our business is dependent on our information technology (“IT”) systems. Accordingly, we rely upon the capacity, reliability, and security of our IT hardware and software infrastructure and our ability to expand and 
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+update this infrastructure in response to our changing needs. Our IT systems are subject to possible breaches and other threats that could cause us harm. If our systems for protecting against cyber security risks prove not to be sufficient, we could be adversely affected by, among other things, loss or damage of intellectual property, proprietary information, customer or business data; interruption of business operations; or additional costs to prevent, respond to, or mitigate cyber security attacks. These risks could have a material adverse effect on our business, financial condition, and result of operations and could lead to litigation or regulatory action against us. 
+Changes in transportation regulations may increase our costs and negatively impact our results of operations. 
+We are subject to various transportation regulations including as a motor carrier by the DOT and by various federal, state, and tribal agencies, whose regulations include certain permit requirements of highway and safety authorities. These regulatory authorities exercise broad powers over our trucking operations, generally governing such matters as the authorization to engage in motor carrier operations, safety, equipment testing, driver requirements and specifications, and insurance requirements. Certain motor vehicle operators are required to register with the DOT. This registration requires an acceptable operating record. The DOT periodically conducts compliance reviews and may revoke registration privileges based on certain safety performance criteria, and a revocation could result in a suspension of operations. Since 2010, the DOT has pursued its Compliance, Safety, Accountability (“CSA”) program in an effort to improve commercial truck and bus safety. A component of CSA is the Safety Measurement System (“SMS”), which analyzes all safety violations recorded by federal and state law enforcement personnel to determine a carrier’s safety performance. The SMS is intended to allow the DOT to identify carriers with safety issues and intervene to address those problems. 
+The trucking industry is subject to possible regulatory and legislative changes that may impact our operations, such as changes in fuel emissions limits, hours of service regulations that govern the amount of time a driver may drive or work in any specific period, and limits on vehicle weight and size. For example, in December 2016, the DOT finalized minimum training standards for new drivers seeking a commercial driver’s license, and effective December 2017, the FMCSA has mandated electronic logging devices in all interstate commercial trucks. As the federal government continues to develop and propose regulations relating to fuel quality, engine efficiency, and greenhouse gas emissions, we may experience an increase in costs related to truck purchases and maintenance, impairment of equipment productivity, a decrease in the residual value of vehicles, unpredictable fluctuations in fuel prices, and an increase in operating expenses. Increased truck traffic may contribute to deteriorating road conditions in some areas where our operations are performed. Our operations, including routing and weight restrictions, could be affected by road construction, road repairs, detours, and state and local regulations and ordinances restricting access to certain roads. Proposals to increase federal, state, or local taxes, including taxes on motor fuels, are also made from time to time, and any such increase would increase our operating costs. Also, state and local regulation of permitted routes and times on specific roadways could adversely affect our operations. We cannot predict whether, or in what form, any legislative or regulatory changes or municipal ordinances applicable to our logistics operations will be enacted and to what extent any such legislation or regulations could increase our costs or otherwise adversely affect our business or operations. 
+We are dependent on customers in a single industry. The loss of one or more significant customers could adversely affect our financial condition, prospects, and results of operations. 
+Our customers are engaged in the oil and natural gas E&P business, which has been historically volatile. For the year ended December 31, 2019 , our five largest customers collectively accounted for approximately 34% of total revenues. If we were to lose several key alliances over a relatively short period of time or if one of our largest customers fails to pay or delays in paying a significant amount of our outstanding receivables, we could experience an adverse impact on our business, financial condition, results of operations, cash flows, and prospects. Additionally, the E&P industry is characterized by frequent consolidation activity. Changes in ownership of our customers may result in the loss of, or reduction in, business from those customers, which could materially and adversely affect our business, financial condition, results of operations, and prospects. 
+Our executive officers and certain key personnel are critical to our business, and these officers and key personnel may not remain with us in the future. 
+Our future success depends in substantial part on our ability to hire and retain our executive officers and other key personnel. In particular, we are highly dependent on certain of our executive officers, particularly our President and Chief Executive Officer, Ann G. Fox, and the Chief Operating Officer, David Crombie. These individuals possess extensive expertise, talent, and leadership, and they are critical to our success. The diminution or loss of the services of these individuals, or other integral key personnel affiliated with entities that we acquire in the future, could have a material adverse effect on our business. Furthermore, we may not be able to enforce all of the provisions in any employment agreement we have entered into with certain of our executive officers, and such employment agreements may not otherwise be effective in retaining such individuals. In addition, we may not be able to retain key employees of entities that we acquire in the future, which may impact our ability to successfully integrate or operate the assets we acquire. 
+25 
+A terrorist attack or armed conflict could harm our business. 
+The occurrence or threat of terrorist attacks in the United States or other countries, anti-terrorist efforts, and other armed conflicts involving the United States or other countries, including continued hostilities in the Middle East, may adversely affect the United States and global economies and could prevent us from meeting financial and other obligations. We could experience loss of business, delays or defaults in payments from payors, or disruptions of fuel supplies and markets if wells, operations sites, or other related facilities are direct targets or indirect casualties of an act of terror or war. Such activities could reduce the overall demand for oil and natural gas, which, in turn, could also reduce the demand for our products and services. Oil and natural gas-related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all. Terrorist activities and the threat of potential terrorist activities and any resulting economic downturn could adversely affect our results of operations, impair our ability to raise capital, or otherwise adversely impact our ability to realize certain business strategies. 
+Delays or restrictions in obtaining, or inability to obtain or renew, permits or authorizations by our customers for their operations or by us for our operations could impair our business. 
+In most states, our operations and the operations of our customers require permits or authorizations from one or more governmental agencies or other third parties to perform drilling and completion and production activities, including hydraulic fracturing. Such permits or approvals are typically required by state agencies, but federal and local governmental permits may also be required. We are also required to obtain federal, state, local, and/or third-party permits and authorizations in some jurisdictions in connection with our wireline services and trucking operations. The requirements for permits or authorizations vary depending on the location where the associated activities will be conducted. As with most permitting and authorization processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit or approval to be issued, and the conditions which may be imposed in connection with the granting of the permit. In Texas, rural water districts have begun to impose restrictions on water use and may require permits for water used in drilling and completion activities. In addition, some of our customers’ drilling and completion activities may take place on federal land or Native American lands, requiring leases and other approvals from the federal government or Native American tribes to conduct such drilling and completion activities. Permitting, authorization, or renewal delays, the inability to obtain new permits, or the revocation of current permits could cause a loss of revenue and potentially have a materially adverse effect on our business, financial condition, prospects, or results of operations. 
+Our Canadian operations subject us to currency translation risk, which could cause our results to fluctuate significantly from period to period. 
+A portion of our revenues is derived from our Canadian activities and operations. As a result, we translate the results of our operations and financial condition of our Canadian operations into U.S. dollars. Therefore, our reported results of operations and financial condition are subject to changes in the exchange rate between the two currencies. Fluctuations in foreign currency exchange rates could affect our revenue, expenses, and operating margins. Currently, we do not hedge our exposure to changes in foreign exchange rates. 
+Risks Related to Our Common Stock 
+Significant ownership of our common stock by certain stockholders could adversely affect our other stockholders. 
+SCF VII, L.P. and SCF-VII(A), L.P. (collectively, “SCF”) owned approximately 30% of our outstanding common stock as of December 31, 2019 . In addition, certain of our directors are currently employed by SCF. Consequently, SCF is able to strongly influence all matters that require approval by our stockholders, including the election and removal of directors, changes to our organizational documents, and approval of acquisition offers and other significant corporate transactions. In addition, one of the Magnum sellers owned approximately 16% of our outstanding common stock as of December 31, 2019 . This concentration of ownership by a small group of stockholders will limit other stockholders’ ability to influence corporate matters, and as a result, actions may be taken that other stockholders may not view as beneficial. For example, this concentration of ownership could have the effect of delaying or preventing a change in control or otherwise discouraging a potential acquirer from attempting to obtain control of us, which in turn could cause the market price of our common stock to decline or prevent our stockholders from realizing a premium over the market price for their shares of our common stock. This concentration of stock ownership may also adversely affect the trading price of our common stock to the extent investors perceive a disadvantage in owning stock of a company with significant stockholders. 
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+A significant reduction by SCF of its ownership interests in us could adversely affect us. 
+We believe that SCF’s substantial ownership interest in us provides them with an economic incentive to assist us to be successful. SCF is not subject to any obligation to maintain its ownership interest in us and may elect at any time to sell all or a substantial portion of or otherwise reduce its ownership interest in us. If SCF sells all or a substantial portion of its ownership interest in us, it may have less incentive to assist in our success and its affiliates that serve as members of our board of directors may resign. Such actions could adversely affect our ability to successfully implement our business strategies, which could adversely affect our cash flows or results of operations. 
+Certain of our directors may have conflicts of interest because they are also directors or officers of SCF. The resolution of these conflicts of interest may not be in our or other stockholders’ best interests. 
+Certain of our directors, namely David C. Baldwin and Andrew L. Waite, are currently officers of SCF’s ultimate general partner. In addition, Mr. Baldwin and Mr. Waite are both directors of Forum Energy Technologies, a corporation in which SCF and its affiliates own an approximate 18% equity interest as of December 31, 2019 . These positions may conflict with such individuals’ duties as one of our directors regarding business dealings and other matters between SCF and us. The resolution of these conflicts may not always be in the best interest of the Company or its stockholders. 
+SCF and its affiliates are not limited in their ability to compete with us, and the corporate opportunity provisions in our charter could enable SCF to benefit from corporate opportunities that may otherwise be available to us. 
+SCF and its affiliates have investments in other oilfield service companies that may compete with us, and SCF and its affiliates may invest in such other companies in the future. SCF, its other affiliates, and its other portfolio companies are referred to herein as the “SCF Group.” Conflicts of interest could arise in the future between us, on the one hand, and the SCF Group, on the other hand, concerning among other things, potential competitive business activities or business opportunities. 
+Our charter provides that, to the fullest extent permitted by applicable law, we renounce any interest or expectancy in any business opportunity that involves any aspect of the energy equipment or services business or industry and that may be from time to time presented to SCF or any of our directors or officers who is also an employee, partner, member, manager, officer, or director of any SCF Group entity, even if the opportunity is one that we might reasonably have pursued or had the ability or desire to pursue if granted the opportunity to do so. Our charter further provides that no such person or party shall be liable to us by reason of the fact that such person pursues any such business opportunity or fails to offer any such business opportunity to us. As a result, any of our directors or officers who is also an employee, partner, member, manager, officer, or director of any SCF Group entity may become aware, from time to time, of certain business opportunities, such as acquisition opportunities, and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities. As a result, by renouncing our interest and expectancy in any business opportunity that may be from time to time presented to any member of an SCF Group entity or any of our directors or officers who is also an employee, partner, member, manager, officer, or director of any SCF Group entity, our business or prospects could be adversely affected if attractive business opportunities are procured by such parties for their own benefit rather than for ours. Our charter provides that any amendment to or adoption of any provision inconsistent with our charter’s provisions governing the renouncement of business opportunities must be approved by the holders of at least 80% of the voting power of the outstanding stock of the corporation entitled to vote thereon. Any actual or perceived conflicts of interest with respect to the foregoing could have an adverse impact on the trading price of our common stock. 
+Taking advantage of the reduced disclosure requirements applicable to “emerging growth companies” may make our common stock less attractive to investors. 
+We are an “emerging growth company,” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”), and we will remain an emerging growth company until the earliest to occur of (i) the last day of the fiscal year in which we have more than $1.07 billion in annual revenue; (ii) the date on which we become a “large accelerated filer” (the fiscal year-end on which at least $700 million of equity securities are held by non-affiliates as of the last day of our then most recently completed second fiscal quarter); (iii) the date on which we have issued, in any three-year period, more than $1.0 billion in non-convertible debt securities; and (iv) December 31, 2023, which is the last day of the fiscal year ending after the fifth anniversary of the completion of our initial public offering (the “IPO”). An emerging growth company may take advantage of certain reduced reporting and other requirements that are otherwise applicable generally to public companies. Pursuant to these reduced disclosure requirements, emerging growth companies are not required to, among other things, comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”), provide certain disclosures regarding executive compensation, hold stockholder advisory votes on executive compensation, or obtain stockholder approval of any golden parachute payments not previously approved. In addition, emerging growth companies have 
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+longer phase-in periods for the adoption of new or revised financial accounting standards. Under the JOBS Act, emerging growth companies can delay adopting new or revised accounting standards until such time as those standards apply to private companies. 
+We intend to take advantage of all of the reduced reporting requirements and exemptions, including the longer phase-in periods for the adoption of new or revised financial accounting standards under Section 107 of the JOBS Act, until we are no longer an emerging growth company. If we were to subsequently elect instead to comply with these public company effective dates, such election would be irrevocable pursuant to Section 107 of the JOBS Act. 
+Our election to use the phase-in periods permitted by this election may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the longer phase-in periods under Section 107 of the JOBS Act and who will comply with new or revised financial accounting standards. We cannot predict if investors will find our common stock less attractive because we will rely on these exemptions. If some investors find our common stock less attractive as a result, there may be a less active trading market for our common stock and our common stock price may be more volatile. 
+On the other hand, once we are no longer an emerging growth company, compliance with rules and regulations that do not currently apply to us as an emerging growth company will increase our legal and financial compliance costs, may make some activities more difficult, time-consuming, or costly, and will increase demand on our systems and resources. 
+We have identified material weaknesses in our internal control over financial reporting, with regard to segregation of certain accounting duties. We may identify additional material weaknesses in the future or otherwise fail to maintain an effective system of internal controls, which may result in material misstatements of our financial statements or cause us to fail to meet our reporting obligations. 
+A material weakness is defined as a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. In connection with the preparation of our financial statements for the nine months ended September 30, 2017, we identified a material weakness in our internal control over financial reporting, specifically as it related to segregation of certain accounting duties stemming from our decentralized accounting structure and limited number of accounting personnel. We did not design and maintain adequate controls to address segregation of certain accounting duties related to journal entries, account reconciliations, and other accounting functions. Certain accounting personnel had the ability to prepare and post journal entries, as well as reconcile accounts, without an independent review by someone other than the preparer. Specifically, our internal controls were not designed or operating effectively to evidence that journal entries were appropriately recorded or were properly reviewed for validity, accuracy, and completeness. Immaterial misstatements were identified related to the inadequate segregation of accounting duties. This material weakness could result in a misstatement of the aforementioned account balances or disclosures that would result in a material misstatement of the annual or interim consolidated financial statements that would not be prevented or detected. In response to this material weakness, our management has performed or is in the process of performing the remediation steps listed in our Annual Report on Form 10-K for the year ended December 31, 2019. 
+The material weakness described above or any newly identified material weakness could limit our ability to prevent or detect a misstatement of our accounts or disclosures that could result in a material misstatement of our annual or interim financial statements. We cannot assure you that the measures we have taken to date, or any measures we may take in the future, will be sufficient to remediate the control deficiencies that led to the material weaknesses in our internal control over financial reporting described above or to avoid potential future material weaknesses. In addition, an independent registered public accounting firm has never performed an evaluation of our internal control over financial reporting in accordance with the provisions of the Sarbanes-Oxley Act because no such evaluation has been required. Had our independent registered public accounting firm performed an evaluation of our internal control over financial reporting in accordance with the provisions of the Sarbanes-Oxley Act, additional material weaknesses may have been identified. 
+Effective internal controls are necessary for us to provide reliable financial reports and prevent fraud. If we are unable to successfully remediate our existing or any future material weakness in our internal control over financial reporting, or identify any additional material weaknesses that may exist, the accuracy and timing of our financial reporting may be adversely affected, we may be unable to maintain compliance with securities law requirements regarding timely filing of periodic reports in addition to applicable stock exchange listing requirements, we may be unable to prevent fraud, investors may lose confidence in our financial reporting, and our stock price may decline as a result. Additionally, our reporting obligations as a public company could place a significant strain on our management, operational and financial resources, and systems for the foreseeable future and may cause us to fail to timely achieve and maintain the adequacy of our internal control over financial reporting. 
+28 
+If securities or industry analysts do not publish research reports or publish unfavorable research about our business, the price and trading volume of our common stock could decline. 
+The trading market for our common stock depends in part on the research reports that securities or industry analysts publish about us or our business. If one or more of the analysts who covers us downgrades our securities, the price of our securities would likely decline. If one or more of these analysts ceases to cover us or fails to publish regular reports on us, interest in the purchase of our securities could decrease, which could cause the price of our common stock and other securities and their trading volume to decline. 
+Our charter and bylaws contain provisions that could delay, discourage, or prevent a takeover attempt even if a takeover might be beneficial to our stockholders, and such provisions may adversely affect the market price of our common stock. 
+Provisions contained in our charter and bylaws could make it more difficult for a third party to acquire us. Our charter and bylaws also impose various procedural and other requirements, which could make it more difficult for stockholders to effect certain corporate actions. For example, our charter authorizes our board of directors to determine the rights, preferences, privileges, and restrictions of unissued series of preferred stock without any vote or action by our stockholders. Thus, our board of directors can authorize and issue shares of preferred stock with voting or conversion rights that could adversely affect the voting or other rights of holders of our capital stock. These rights may have the effect of delaying or deterring a change of control of our company. Additionally, for example, our bylaws (i) establish limitations on the removal of directors and on the ability of our stockholders to call special meetings, (ii) include advance notice requirements for nominations for election to our board of directors and for proposing matters that can be acted upon at stockholder meetings, (iii) provide that our board of directors is expressly authorized to adopt, or to alter or repeal, our bylaws, and (iv) provide for a classified board of directors, consisting of three classes of approximately equal size, each class serving staggered three-year terms, so that only approximately one-third of our directors will be elected each year. These provisions could limit the price that certain investors might be willing to pay in the future for shares of our common stock. 
+Our charter and bylaws designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees, or agents. 
+Our charter and bylaws provide that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees, or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (the “DGCL”), our charter or our bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. These exclusive forum provisions are not intended to apply to actions arising under the Exchange Act or the Securities Act of 1933, as amended. The Court of Chancery of the State of Delaware has recently held that a Delaware corporation can only use its constitutive documents to bind a plaintiff to a particular forum where the claim involves rights or relationships that were established by or under the DGCL. 
+Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the forum selection provisions of our charter and bylaws. These choice of forum provisions may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees, or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our charter or bylaws inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition, or results of operations. 
+We do not intend to pay dividends on our common stock, and our debt agreements place certain restrictions on our ability to do so. Consequently, a stockholder’s only opportunity to achieve a return on his investment is if the price of our common stock appreciates. 
+We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally, our debt agreements place certain restrictions on our ability to pay cash dividends. Consequently, unless we revise our dividend policy, a stockholder’s only opportunity to achieve a return on his investment in us will be by selling his common stock at a price greater than the stockholder paid for it. There is no guarantee that the price of our common stock that will prevail in the market will ever exceed the price at which a stockholder purchased his shares of our common stock. 
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+Future sales of our common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute a stockholder’s ownership in us. 
+Sales of a substantial number of shares of our common stock in the public market, or the perception that such sales could occur, could adversely affect the market price of our common stock. We are unable to predict the effect that such sales may have on the prevailing market price of our common stock. SCF and certain of our other stockholders are parties to the Second Amended and Restated Stockholders Agreement, as amended, and the sellers of Magnum are parties to a Registration Rights Agreement, both of which require us to effect the registration of their shares in certain circumstances. In addition, in connection with our IPO, we filed a registration statement on Form S-8 with the SEC providing for the registration of shares of our common stock issued or reserved for issuance under our equity incentive plan. Subject to the satisfaction of vesting conditions and the requirements of Rule 144, shares registered under the registration statement on Form S-8 will be available for resale immediately in the public market without restriction. 
+We may issue additional capital stock in the future that will result in dilution to all other stockholders. We may also raise capital through equity financings in the future. As part of our business strategy, we may acquire or make investments in complementary companies, products, or technologies and issue equity securities to pay for any such acquisition or investment. Any such issuances of additional capital stock may cause stockholders to experience significant dilution of their ownership interests and the per share value of our common stock to decline. 
+We may not be able to utilize a portion of our net operating loss carryforwards (“NOLs”) to offset future taxable income for U.S. federal or state tax purposes, which could adversely affect our net income and cash flows. 
+As of December 31, 2019 , we had federal and state income tax NOLs of approximately $202.6 million , which will begin to expire between 2023 and 2034. Utilization of these NOLs depends on many factors, including our future taxable income, which cannot be assured. In addition, Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”), generally imposes an annual limitation on the amount of an NOL that may be used to offset taxable income when a corporation has undergone an “ownership change” (as determined under Section 382). 
+Determining the limitations under Section 382 is technical and highly complex. An ownership change generally occurs if one or more stockholders (or groups of stockholders) who are each deemed to own at least 5% of the corporation’s stock increase their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period. In the event that an ownership change has occurred, or were to occur, with respect to a corporation following its recognition of an NOL, utilization of such NOL would be subject to an annual limitation under Section 382, generally determined by multiplying the value of the corporation’s stock at the time of the ownership change by the applicable long-term tax-exempt rate (as defined in Section 382). However, this annual limitation would be increased under certain circumstances by recognized built-in gains of the corporation existing at the time of the ownership change. In the case of an NOL that arose in a taxable year beginning before January 1, 2018, any unused annual limitation with respect to an NOL generally may be carried over to later years, subject to the expiration of such NOL 20 years after it arose. 
+The issuance of additional stock in the IPO, combined with ownership shifts over the rolling three-year period, resulted in an ownership change under Section 382, and we may be prevented from fully utilizing our NOLs prior to their expiration. Future changes in our stock ownership or future regulatory changes could also limit our ability to utilize our NOLs. To the extent we are not able to offset future taxable income with our NOLs, our net income and cash flows may be adversely affected. 
+30 
+Item 1B. 
+Unresolved Staff Comments 
+None. 
+Item 2. 
+Properties 
+The following table describes the material facilities owned or leased by us as of December 31, 2019 . 
+Segment 
+Location 
+Basin/ Region 
+Leased or Owned 
+Principal/Most 
+Significant Use 
+Headquarters 
+Houston, TX 
+— 
+Leased 
+Corporate Headquarters/Administrative 
+Completion 
+Athens, TX 
+— 
+Leased 
+Operations 
+Completion 
+Baker, MT 
+Bakken 
+Owned 
+Operations/Administrative 
+Completion 
+Canadian County, OK 
+SCOOP/STACK 
+Leased 
+Operations 
+Completion 
+Calgary, AB, Canada 
+— 
+Leased 
+Administrative 
+Completion 
+Charleroi, PA 
+Marcellus/Utica 
+Leased 
+Operations 
+Completion 
+Corpus Christi, TX 
+— 
+Leased 
+Operations/Administrative 
+Completion 
+Dickinson, ND 
+Bakken 
+Leased 
+Operations/Administrative 
+Completion 
+Enid, OK 
+SCOOP/STACK 
+Leased 
+Operations/Administrative 
+Completion 
+Fort Worth, TX 
+— 
+Leased 
+Administrative 
+Completion 
+Hobbs, NM 
+Permian 
+Leased 
+Operations 
+Completion 
+Jacksboro, TX 
+Barnett 
+Leased 
+Operations 
+Completion 
+Marietta, OH 
+Marcellus/Utica 
+Leased 
+Operations/Administrative 
+Completion 
+Mead, CO 
+Rockies 
+Leased 
+Operations 
+Completion 
+Midland, TX 
+Permian 
+Leased 
+Operations 
+Completion 
+Midland, TX 
+Permian 
+Owned 
+Operations/Administrative 
+Completion 
+Midland, TX 
+Permian 
+Leased 
+Operations/Administrative 
+Completion 
+Midland, TX 
+Permian 
+Leased 
+Operations 
+Completion 
+Monahans, TX 
+Permian 
+Leased 
+Operations/Administrative 
+Completion 
+Oklahoma City, OK 
+SCOOP/STACK 
+Leased 
+Operations 
+Completion 
+Pleasanton, TX 
+Eagle Ford 
+Leased 
+Operations 
+Completion 
+Poolville, TX 
+— 
+Owned 
+Operations 
+Completion 
+Red Deer, AB, Canada 
+WCSB 
+Leased 
+Operations 
+Completion 
+San Antonio, TX 
+Eagle Ford 
+Leased 
+Operations/Administrative 
+Completion 
+Shawnee, OK 
+SCOOP/STACK 
+Leased 
+Operations 
+Completion 
+Sweetwater, TX 
+Permian 
+Leased 
+Operations 
+Completion 
+Ulster, PA 
+Marcellus/Utica 
+Leased 
+Operations 
+Completion 
+Tyler, TX 
+Haynesville 
+Leased 
+Operations 
+Completion 
+Williston, ND 
+Bakken 
+Owned 
+Operations 
+Completion 
+Williston, ND 
+Bakken 
+Owned 
+Operations/Administrative 
+Item 3. 
+Legal Proceeding 
+From time to time, we have various claims, lawsuits, and administrative proceedings that are pending or threatened with respect to personal injury, workers’ compensation, contractual matters, and other matters. Although no assurance can be given with respect to the outcome of these claims, lawsuits, or proceedings or the effect such outcomes may have, we believe any ultimate liability resulting from the outcome of such claims, lawsuits, or administrative proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on our business, operating results, or financial condition. 
+Item 4. 
+Mine Safety Disclosures 
+Not applicable. 
+31 
+PART II 
+Item 5. 
+Market for Registrant’s Common Equity and Related Shareholder Matters and Issuer Purchases of Equity Securities 
+Market Information 
+Nine Energy Service, Inc.’s common stock is traded on the New York Stock Exchange under the symbol “NINE.” 
+Holders 
+As of March 5, 2020, we had 52 stockholders of record. The number of record holders does not include persons who held shares of our common stock in nominee or “street name” accounts through brokers. 
+Dividend Policy 
+We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to fund our operations and to develop and grow our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors our board of directors deems relevant, including our results of operations, financial condition, capital requirements, and investment opportunities, as well as any restrictions on our ability to pay cash dividends. 
+Recent Sales of Unregistered Securities 
+None. 
+Purchases of Equity Securities by the Issuer and Affiliated Purchasers 
+None. 
+32 
+Item 6. 
+Selected Financial Data 
+This section presents our selected consolidated financial data for the periods and as of the dates indicated. The financial data set forth below, as well as our audited financial statements and related notes, give effect to the Company’s merger with Beckman Production Services, Inc. (“Beckman”) which was completed on February 28, 2017 and the divestiture of our Production Solutions segment on August 30, 2019 as well as the Magnum Acquisition on October 25, 2018 and represent the consolidated results of Nine, Beckman, and their respective subsidiaries. The selected historical consolidated financial data presented below is not intended to replace our historical consolidated financial statements. The following selected consolidated financial data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of Part II and “Financial Statements and Supplementary Data” in Item 8 of Part II of this Annual Report in order to fully understand those factors which may affect the comparability of the information presented below. 
+33 
+Year Ended December 31, 
+2019 
+2018 
+2017 
+2016 
+2015 
+(in thousands, except share and per share amounts) 
+Statement of operations data: 
+Revenues 
+$ 
+832,937 
+$ 
+827,174 
+$ 
+543,660 
+$ 
+282,354 
+$ 
+478,522 
+Cost and expenses 
+Cost of revenues (exclusive of depreciation and amortization shown separately below) 
+669,979 
+639,298 
+448,467 
+246,109 
+373,191 
+General and administrative expenses 
+81,327 
+73,078 
+49,505 
+37,652 
+43,155 
+Depreciation 
+50,544 
+54,257 
+53,422 
+55,260 
+58,894 
+Amortization of intangibles 
+18,367 
+9,558 
+8,799 
+9,083 
+8,650 
+Impairment of property and equipment 
+66,200 
+45,694 
+— 
+— 
+— 
+Impairment of goodwill 
+20,273 
+12,986 
+31,530 
+12,207 
+35,540 
+Impairment of intangibles 
+114,804 
+19,065 
+3,800 
+— 
+— 
+(Gain) loss on revaluation of contingent liabilities 
+(21,187 
+) 
+3,262 
+415 
+1,735 
+(293 
+) 
+Loss on sale of subsidiaries 
+15,896 
+— 
+— 
+— 
+— 
+(Gain) loss on sale of property and equipment 
+(538 
+) 
+(1,731 
+) 
+4,688 
+3,320 
+2,004 
+Loss from operations 
+(182,728 
+) 
+(28,293 
+) 
+(56,966 
+) 
+(83,012 
+) 
+(42,619 
+) 
+Interest expense 
+39,770 
+22,939 
+16,252 
+14,720 
+10,247 
+Interest income 
+(860 
+) 
+(624 
+) 
+(549 
+) 
+(535 
+) 
+(361 
+) 
+Loss from continuing operations before income taxes 
+(221,638 
+) 
+(50,608 
+) 
+(72,669 
+) 
+(97,197 
+) 
+(52,505 
+) 
+Provision (benefit) for income taxes 
+(3,887 
+) 
+2,375 
+(4,987 
+) 
+(26,286 
+) 
+(14,323 
+) 
+Loss from continuing operations, net of tax 
+(217,751 
+) 
+(52,983 
+) 
+(67,682 
+) 
+(70,911 
+) 
+(38,182 
+) 
+Loss from discontinued operations, net of tax of $0, $0, $0, $0, and $513 
+— 
+— 
+— 
+— 
+(935 
+) 
+Net loss 
+(217,751 
+) 
+(52,983 
+) 
+(67,682 
+) 
+(70,911 
+) 
+(39,117 
+) 
+Other comprehensive income (loss), net of tax 
+Foreign currency translation adjustments, net of $0 tax in each period 
+376 
+(1,159 
+) 
+(198 
+) 
+210 
+(4,067 
+) 
+Total other comprehensive income (loss), net of tax 
+376 
+(1,159 
+) 
+(198 
+) 
+210 
+(4,067 
+) 
+Total comprehensive loss 
+$ 
+(217,375 
+) 
+$ 
+(54,142 
+) 
+$ 
+(67,880 
+) 
+$ 
+(70,701 
+) 
+$ 
+(43,184 
+) 
+Historical earnings per share data: 
+Weighted average shares outstanding – basic 
+29,308,107 
+24,411,213 
+14,887,006 
+13,268,540 
+13,193,380 
+Loss from continuing operations per share – basic 
+$ 
+(7.43 
+) 
+$ 
+(2.17 
+) 
+$ 
+(4.55 
+) 
+$ 
+(5.34 
+) 
+$ 
+(2.89 
+) 
+Loss from discontinued operations per share – basic 
+— 
+— 
+— 
+— 
+(0.07 
+) 
+Loss per share – basic 
+$ 
+(7.43 
+) 
+$ 
+(2.17 
+) 
+$ 
+(4.55 
+) 
+$ 
+(5.34 
+) 
+$ 
+(2.96 
+) 
+Weighted average shares outstanding – fully diluted 
+29,308,107 
+24,411,213 
+14,887,006 
+13,268,540 
+13,193,380 
+Loss from continuing operations – fully diluted 
+$ 
+(7.43 
+) 
+$ 
+(2.17 
+) 
+$ 
+(4.55 
+) 
+$ 
+(5.34 
+) 
+$ 
+(2.89 
+) 
+Loss from discontinued operations per share – fully diluted 
+— 
+— 
+— 
+— 
+(0.07 
+) 
+Loss per share – fully diluted 
+$ 
+(7.43 
+) 
+$ 
+(2.17 
+) 
+$ 
+(4.55 
+) 
+$ 
+(5.34 
+) 
+$ 
+(2.96 
+) 
+Balance sheet data at period end: 
+Cash and cash equivalents 
+$ 
+92,989 
+$ 
+63,615 
+$ 
+17,513 
+$ 
+4,074 
+$ 
+18,877 
+Property and equipment, net 
+128,604 
+211,644 
+259,039 
+273,210 
+325,894 
+Total assets 
+850,895 
+1,141,172 
+578,859 
+576,094 
+658,434 
+Long-term debt 
+392,059 
+424,978 
+— 
+244,262 
+249,641 
+Total stockholders’ equity 
+$ 
+389,877 
+$ 
+594,823 
+$ 
+287,358 
+$ 
+288,186 
+$ 
+352,676 
+Statement of cash flows data: 
+Net cash provided by (used in) operating activities 
+$ 
+101,305 
+$ 
+89,577 
+$ 
+5,671 
+$ 
+(3,290 
+) 
+$ 
+140,367 
+Net cash used in investing activities 
+(34,121 
+) 
+(389,765 
+) 
+(44,464 
+) 
+(4,176 
+) 
+(19,251 
+) 
+Net cash provided by (used in) financing activities 
+$ 
+(37,905 
+) 
+346,691 
+$ 
+52,342 
+$ 
+(7,315 
+) 
+$ 
+(126,878 
+) 
+All shares and per share data reflect the 8.0256 for 1 stock split that took place in January 2018. 
+34 
+Item 7. 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Selected Financial Data” in Item 6 of Part II and “Financial Statements and Supplementary Data” in Item 8 of Part II of this Annual Report. A discussion and analysis of our financial condition and results of operations for the year ended December 31, 2017 can be found in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2018, which was filed with the SEC on March 7, 2019 and is incorporated herein by reference. 
+This discussion contains forward-looking statements based on our current expectations, estimates, and projections about our operations and the industry in which we operate. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a variety of risks and uncertainties, including those described under “Risk Factors” in Item 1A of Part I of this Annual Report. We assume no obligation to update any of these forward-looking statements. 
+Overview 
+Company Description 
+We are a leading North American onshore completion services provider that targets unconventional oil and gas resource development. We partner with our E&P customers across all major onshore basins in both the U.S. and Canada as well as abroad to design and deploy downhole solutions and technology to prepare horizontal, multistage wells for production. We focus on providing our customers with cost-effective and comprehensive completion solutions designed to maximize their production levels and operating efficiencies. We believe our success is a product of our culture, which is driven by our intense focus on performance and wellsite execution as well as our commitment to forward-leaning technologies that aid us in the development of smarter, customized applications that drive efficiencies. We provide (i) cementing services, which consist of blending high-grade cement and water with various solid and liquid additives to create a cement slurry that is pumped between the casing and the wellbore of the well, (ii) an innovative portfolio of completion tools, including those that provide pinpoint frac sleeve system technologies as well as a portfolio of completion technologies used for completing the toe stage of a horizontal well and fully-composite, dissolvable, and extended range frac plugs to isolate stages during plug and perf operations, (iii) wireline services, the majority of which consist of plug-and-perf completions, which is a multistage well completion technique for cased-hole wells that consists of deploying perforating guns and isolation tools to a specified depth, and (iv) coiled tubing services, which perform wellbore intervention operations utilizing a continuous steel pipe that is transported to the wellsite wound on a large spool in lengths of up to 30,000 feet and which provides a cost-effective solution for well work due to the ability to deploy efficiently and safely into a live well. 
+Recent Significant Events 
+Production Solutions Divestiture 
+On August 30, 2019, we sold our Production Solutions segment for approximately $17.1 million in cash. In connection with this divestiture, we recorded a loss of $15.9 million during the year ended December 31, 2019. For additional information on this divestiture, see Note 3 – Divestitures, Acquisitions, and Combinations included in Item 8 of Part II of this Annual Report. 
+Magnum Acquisition 
+On October 25, 2018 (the “Magnum Closing Date”), pursuant to the terms of a Securities Purchase Agreement dated October 15, 2018 (as amended on June 7, 2019, the “Magnum Purchase Agreement”), we acquired all of the equity interests of Magnum for approximately $334.5 million in upfront cash consideration, subject to customary adjustments, and 5.0 million shares of our common stock, which were issued to the sellers of Magnum in a private placement. For additional information on the Magnum Acquisition, see Note 3 – Divestitures, Acquisitions, and Combinations included in Item 8 of Part II of this Annual Report. 
+The Magnum Purchase Agreement also includes the potential for additional future payments in cash of (i) up to 60% of net income (before interest, taxes, and certain gains or losses) for the “E-Set” tools business in 2019 through 2026 and (ii) up to $25.0 million based on sales of certain dissolvable plug products in 2019. In 2019, we did not meet the sales requirement of certain dissolvable plug products during the year. For additional information, see Note 12 – Commitments and Contingencies included in Item 8 of Part II of this Annual Report. 
+35 
+How We Generate Revenue and the Costs of Conducting Our Business 
+We generate our revenues by providing completion services to E&P customers across all major onshore basins in both the U.S. and Canada as well as abroad. We primarily earn our revenues pursuant to work orders entered into with our customers on a job-by-job basis. We typically will enter into an MSA with each customer that provides a framework of general terms and conditions of our services that will govern any future transactions or jobs awarded to us. Each specific job is obtained through competitive bidding or as a result of negotiations with customers. The rate we charge is determined by location, complexity of the job, operating conditions, duration of the contract, and market conditions. In addition to MSAs, we have entered into a select number of longer-term contracts with certain customers relating to our wireline and cementing services, and we may enter into similar contracts from time to time to the extent beneficial to the operation of our business. These longer-term contracts address pricing and other details concerning our services, but each job is performed on a standalone basis. 
+The principal expenses involved in conducting our business include labor costs, materials and freight, the costs of maintaining our equipment, and fuel costs. Our direct labor costs vary with the amount of equipment deployed and the utilization of that equipment. Another key component of labor costs relates to the ongoing training of our field service employees, which improves safety rates and reduces employee attrition. 
+How We Evaluate Our Operations 
+We evaluate our performance based on a number of financial and non-financial measures, including the following: 
+• 
+Revenue : We compare actual revenue achieved each month to the most recent projection for that month and to the annual plan for the month established at the beginning of the year. We monitor our revenue to analyze trends in the performance of our operations compared to historical revenue drivers or market metrics. We are particularly interested in identifying positive or negative trends and investigating to understand the root causes. 
+• 
+Adjusted Gross Profit (Excluding Depreciation and Amortization) : Adjusted gross profit (excluding depreciation and amortization) is a key metric that we use to evaluate operating performance. We define adjusted gross profit (excluding depreciation and amortization) as revenues less direct and indirect costs of revenues (excluding depreciation and amortization). Costs of revenues include direct and indirect labor costs, costs of materials, maintenance of equipment, fuel and transportation freight costs, contract services, crew cost, and other miscellaneous expenses. For additional information, see “ Non-GAAP Financial Measures ” below. 
+• 
+Adjusted EBITDA : We define Adjusted EBITDA as net income (loss) before interest, taxes, and depreciation and amortization, further adjusted for (i) property and equipment, goodwill, and/or intangible asset impairment charges, (ii) transaction and integration costs related to acquisitions and our IPO, (iii) loss or gain on equity method investment, (iv) loss or gain on revaluation of contingent liabilities, (v) loss or gain on the sale of subsidiaries, (vi) restructuring charges, (vii) stock-based compensation expense, (viii) loss or gain on sale of property and equipment, (ix) other expenses or charges to exclude certain items which we believe are not reflective of ongoing performance of our business, such as legal expenses and settlement costs related to litigation outside the ordinary course of business. For additional information, see “ Non-GAAP Financial Measures ” below. 
+• 
+Return on Invested Capital (“ROIC”): We define ROIC as after-tax net operating profit (loss), divided by average total capital. We define after-tax net operating profit (loss) as net income (loss) plus (i) property and equipment, goodwill, and/or intangible asset impairment charges, (ii) transaction and integration costs related to acquisitions and our IPO, (iii) interest expense (income), (iv) restructuring charges, (v) loss or gain on the sale of subsidiaries, and (vi) the provision or benefit for deferred income taxes. We define total capital as book value of equity plus the book value of debt less balance sheet cash and cash equivalents. We compute the average of the current and prior year-end total capital for use in this analysis. For additional information, see “ Non-GAAP Financial Measures ” below. 
+• 
+Safety : We measure safety by tracking the total recordable incident rate (“TRIR”), which is reviewed on a monthly basis. TRIR is a measure of the rate of recordable workplace injuries, defined below, normalized and stated on the basis of 100 workers for an annual period. The factor is derived by multiplying the number of recordable injuries in a calendar year by 200,000 (i.e., the total hours for 100 employees working 2,000 hours per year) and dividing this value by the total hours actually worked in the year. A recordable injury includes occupational death, nonfatal occupational illness, and other occupational injuries that involve loss of 
+36 
+consciousness, restriction of work or motion, transfer to another job, or medical treatment other than first aid. 
+Factors Affecting the Comparability of Our Results of Operations 
+Our future results of operations may not be comparable to our historical results of operations for the periods presented, and our historical results of operations among the periods presented may not be comparable to each other, primarily due to the Magnum Acquisition and our divestiture of the Production Solutions segment. 
+The historical results of operations for the year ended December 31, 2019 include activity related to the Magnum Acquisition whereas the historical results of operations for the year ended December 31, 2018 include activity related to the Magnum Acquisition only after the Magnum Closing Date (October 25, 2018). As a result, the historical results of operations for the year ended December 31, 2018 may not give an accurate indication of what our actual results would have been if the Magnum Acquisition had been completed at the beginning of the period presented, or of what our future results of operations are likely to be for the following reasons: 
+• 
+As a result of the Magnum Acquisition and the application of purchase accounting, these identifiable net assets have been adjusted to their estimated fair value as of October 25, 2018, the Magnum Closing Date. These adjusted valuations increase our operating expenses in periods after the Magnum Closing Date, primarily due to an increase in the amortization of intangible assets with definite lives. 
+• 
+Transaction and integration costs associated with the Magnum Acquisition increase operating expenses in periods after the Magnum Closing Date. 
+• 
+Our completion tools line constitutes a larger portion of our business, due in large part to the Magnum Acquisition. 
+• 
+We incurred significant indebtedness in connection with the consummation of the Magnum Acquisition, and our related interest expense is expected to be significantly higher than in prior periods 
+For additional information on the Magnum Acquisition, see Note 3 – Divestitures, Acquisitions, and Combinations included in Item 8 of Part II of this Annual Report on Form 10-K. 
+Our historical results of operations included in this Annual Report include the impact of the divestiture of the Production Solutions segment on August 30, 2019. Future results of operations will not include activity related to the Production Solutions segment. For additional information on the divestiture of the Production Solutions segment, see Note 3 – Divestitures, Acquisitions, and Combinations included in Item 8 of Part II of this Annual Report on Form 10-K. 
+Industry Trends and Outlook 
+Our business depends, to a significant extent, on the level of unconventional resource development activity and corresponding capital spending of oil and natural gas companies. These activity and spending levels are strongly influenced by the current and expected oil and natural gas prices. During 2019, oil prices mostly ranged from $50 to $60. At the beginning of 2019, OPEC members and some nonmembers, including Russia, renewed pledges to reduce planned production in an effort to draw down a global oversupply and to rebalance supply and demand. These and other events provided support for an increase in oil prices during the first several months of 2019. As a result of a decrease in global demand for oil and natural gas due to the recent coronavirus outbreaks, in March 2020, members of OPEC and Russia considered extending their agreed oil production cuts and making additional oil production cuts. However, negotiations were unsuccessful; Saudi Arabia has announced a significant reduction in its export prices effective immediately and Russia has announced that all agreed oil production cuts between members of OPEC and Russia will expire on April 1, 2020. Following these announcements, global oil and natural gas prices declined sharply and may continue to decline. 
+We expect ongoing oil price volatility as output increases over the short term as a result of the events described above, the coronavirus outbreaks continue to develop, and changes in oil inventories, GDP growth, and actual demand growth are reported. Similarly, natural gas prices have decreased significantly throughout 2019 and are expected to continue to be volatile in 2020, causing many operators in the more gas-exposed regions to curtail activity in 2020. Significant factors that are likely to affect 2020 commodity prices include the extent to which members of OPEC and other oil exporting nations continue to reduce oil export prices and increase production; the effect of U.S. energy, monetary, and trade policies; the pace of economic growth in the U.S. and throughout the world, including the potential for macro weakness; geopolitical and economic developments in the U.S. and globally; the outcome of the United States presidential election and subsequent energy and EPA policies; and overall North American natural gas supply and demand fundamentals, including the pace at which export capacity grows. 
+37 
+On average, customer budgets for 2020 are likely to decrease as compared to 2019, which could adversely affect our business. With this overall reduction, there has been a strong commitment from E&P operators to stay within capital budgets, prompting many of them to scale back activity. Even with price improvements in oil and natural gas, operator activity may not materially increase, as operators remain focused on operating within their capital plans. Additionally, if natural gas prices remain depressed in 2020, it could negatively affect activity and pricing in our gas-leveraged regions, specifically in the Marcellus and Utica. 
+Operators have continued to improve operational efficiencies in completions design, increasing the complexity and difficulty, making oilfield service selection more important. This increase in high-intensity, high-efficiency completions of oil and gas wells further enhances the demand for our services. We compete for the most complex and technically demanding wells in which we specialize, which are characterized by extended laterals, increased stage spacing, multi-well pads, cluster spacing, and high proppant loads. These well characteristics lead to increased operating leverage and returns for us, as we are able to complete more jobs and stages with the same number of units and crews. Service providers for these projects are selected based on their technical expertise and ability to execute safely and efficiently, rather than only price. 
+Results of Operations 
+Year Ended December 31, 
+2019 
+2018 
+Change 
+(in thousands) 
+Revenues 
+Completion Solutions 
+$ 
+774,665 
+$ 
+745,316 
+$ 
+29,349 
+Production Solutions 
+58,272 
+81,858 
+(23,586 
+) 
+832,937 
+$ 
+827,174 
+$ 
+5,763 
+Cost of revenues (exclusive of depreciation and amortization shown separately below) 
+Completion Solutions 
+620,125 
+568,497 
+51,628 
+Production Solutions 
+49,854 
+70,801 
+(20,947 
+) 
+669,979 
+639,298 
+30,681 
+Adjusted gross profit 
+Completion Solutions 
+154,540 
+176,819 
+(22,279 
+) 
+Production Solutions 
+8,418 
+11,057 
+(2,639 
+) 
+162,958 
+187,876 
+(24,918 
+) 
+General and administrative expenses 
+81,327 
+73,078 
+8,249 
+Depreciation 
+50,544 
+54,257 
+(3,713 
+) 
+Amortization of intangibles 
+18,367 
+9,558 
+8,809 
+Impairment of property and equipment 
+66,200 
+45,694 
+20,506 
+Impairment of goodwill 
+20,273 
+12,986 
+7,287 
+Impairment of intangibles 
+114,804 
+19,065 
+95,739 
+(Gain) loss on revaluation of contingent liabilities 
+(21,187 
+) 
+3,262 
+(24,449 
+) 
+Loss on sale of subsidiaries 
+15,896 
+— 
+15,896 
+(Gain) loss on sale of property and equipment 
+(538 
+) 
+(1,731 
+) 
+1,193 
+Loss from operations 
+(182,728 
+) 
+(28,293 
+) 
+(154,435 
+) 
+Non-operating expenses 
+38,910 
+22,315 
+16,595 
+Loss before income taxes 
+(221,638 
+) 
+(50,608 
+) 
+(171,030 
+) 
+Provision (benefit) for income taxes 
+(3,887 
+) 
+2,375 
+(6,262 
+) 
+Net loss 
+$ 
+(217,751 
+) 
+$ 
+(52,983 
+) 
+$ 
+(164,768 
+) 
+Revenues 
+Revenue increased $5.8 million , or 1% , to $832.9 million in 2019. The increase is primarily related to an increase in completion tools revenue, due in large part to a full year of revenue attributed to the Magnum Acquisition in 2019, compared to approximately two months of revenue in 2018. The overall increase in revenue is partially offset with pricing pressure across 
+38 
+other service offerings within the company. The Completion Solutions segment depends, to a significant extent, on the level of unconventional resource development activity and corresponding capital spending of oil and natural gas companies onshore in North America. In turn, activity and capital spending are strongly influenced by current and expected oil and natural gas prices. During 2019, the average closing price of oil was $56.98 per barrel, and the average closing price of natural gas was $2.56 per MMBtu. During 2018, the average closing price per barrel of oil was $65.23 , and the average closing price of natural gas was $3.15 per MMBtu . 
+The overall increase in revenue is also partially offset with a reduction in revenue attributed to the sale of the historical Production Solutions segment on August 30, 2019. 
+Additional information with respect to revenue by historical reportable segment is discussed below. 
+Completion Solutions : Revenue increased $29.3 million , or 4% , to $774.7 million in 2019 . The increase in 2019 was primarily related to an increase in completion tools revenue of $67.6 million , or 57% , as completion tool stages increased 37% and completion tools revenue by stage increased 18% , due in large part to a full year of revenue attributed to the Magnum Acquisition in 2019, compared to approximately two months of revenue in 2018. In addition, cementing revenue (including pump downs) increased $17.9 million , or 9% , as total cement jobs increased 9% year-over-year. The overall increase in revenue is partially offset by a decrease in coiled tubing revenue of $48.4 million , or 27% , in 2019 as total days worked decreased by 34% in comparison to 2018. In addition, wireline revenue decreased $8.1 million , or 3% , in 2019 primarily due to the pricing pressure from its customer base, as discussed above. Total completed wireline stages increased 11% year-over-year. 
+Production Solutions: Revenue decreased $23.6 million , or 29% , to $58.3 million in 2019 . The overall decrease in revenue was related to the fact that, given the segment was sold on August 30, 2019, only eight months of revenue was recorded in 2019 compared to a full year of revenue in 2018. 
+Cost of Revenues (Exclusive of Depreciation and Amortization) 
+Cost of revenue increased $30.7 million , or 5% , to $670.0 million in 2019 . The increase was primarily related to additional costs of $42.9 million for materials installed and consumed while performing services. The increase in these costs was due in large part to a full year of activity attributed to the Magnum Acquisition in 2019, compared to approximately two months of activity in 2018. The overall increase in cost of revenue was partially offset by a decrease of $11.0 million in employee-related costs, driven in part by the sale of the historical Production Solutions segment on August 30, 2019, which reduced headcount year-over-year. 
+Additional information with respect to cost of revenue by historical reportable segment is discussed below. 
+Completion Solutions: Cost of revenue increased $51.6 million , or 9% , to $620.1 million in 2019 primarily related to additional costs of $46.7 million for materials installed and consumed while performing services, $2.5 million in facility costs, and $2.3 million in employee-related costs. The increase in these costs was due in large part to a full year of activity attributed to the Magnum Acquisition in 2019, compared to approximately two months of activity in 2018. In addition, the overall increase in 2019 was partly related to an increase in cost of revenue type integration costs of $3.1 million due mainly to the cost of inventory that was stepped up to fair value during purchase accounting for the Magnum Acquisition. Furthermore, the overall increase in cost of revenue was partly related to an increase in severance and other cost of revenue type restructuring charges of $2.3 million mainly associated with the 2019 wind-down of our wireline service offerings in Canada. The overall increase in cost of revenue in 2019 was partially offset by a decrease of $5.3 million in other costs, which was mainly driven by reductions in travel and meals and entertainment in comparison to 2018. 
+Production Solutions : Cost of revenue decreased $20.9 million , or 30% , to $49.9 million in 2019 . Employee-related costs decreased $13.3 million , costs related to materials consumed while performing services decreased $3.8 million , and other costs such as repairs and maintenance, insurance, and vehicle and expense, decreased $3.6 million in 2019. The primary driver behind the reduction of these costs of revenue related to the fact that, given the sale of the segment on August 30, 2019, only eight months of activity was recorded in 2019 compared to a full year of activity in 2018. 
+Adjusted Gross Profit 
+Completion Solutions : Adjusted gross profit (excluding depreciation and amortization) decreased $22.3 million to $154.5 million in 2019 as a result of the factors described above under “Revenues” and “Cost of Revenues.” 
+Production Solutions : Adjusted gross profit (excluding depreciation and amortization) decreased $2.6 million to $8.4 million in 2019 as a result of the factors described above under “Revenues” and “Cost of Revenues.” 
+39 
+General and Administrative Expenses 
+General and administrative expenses increased $8.2 million to $81.3 million in 2019. The increase was primarily related to an increase of $4.8 million in employee-related costs in comparison to 2018. The increase in these costs was due in large part to a full year of activity attributed to the Magnum Acquisition in 2019, compared to approximately two months of activity in 2018. The increase is also partly related to an increase in severance and other general and administrative type restructuring charges of $1.6 million mainly associated with the 2019 wind-down of our wireline service offerings in Canada, coupled with an increase in professional fees of $1.3 million , primarily related consulting costs. General and administrative expenses as a percentage of revenue was 9.8% for 2019, compared to 8.8% for 2018. 
+(Gain) Loss on Revaluation of Contingent Liabilities 
+We recorded a $21.2 million gain on the revaluation of contingent liabilities in 2019 in comparison to a $3.3 million loss on the revaluation of contingent liabilities recorded in 2018. The gain was primarily the result of the company not meeting the earnout requirements for the sale of certain dissolvable plug products in 2019 associated with the Magnum Acquisition, which contributed to the reduction in fair value of contingent liabilities year-over-year. 
+(Gain) Loss on Sale of Subsidiaries 
+We recorded a $15.9 million loss on the sale of subsidiaries in 2019 associated with the sale of the historical Production Solutions segment. We did not record a loss on the sale of subsidiaries in 2018. 
+Depreciation 
+Depreciation expense decreased $3.7 million to $50.5 million in 2019. The overall decrease was primarily within service offerings in the historical Production Solutions segment as we recorded a property and equipment impairment charge recorded in the fourth quarter of 2018. Furthermore, any remaining property and equipment associated with the historical Production Solutions segment was sold on August 30, 2019. The overall decrease in depreciation expense was partially offset with an increase in depreciation expense associated with certain service offerings the Completion Solutions segment, which increased capital expenditures year-over-year. 
+Amortization of Intangibles 
+Amortization of intangibles increased $8.8 million to $18.4 million in 2019 , primarily due to a $10.3 million increase in amortization associated with intangible assets acquired as part of the Magnum Acquisition and the acquisition of Frac Technology AS, a Norwegian private limited company. The overall increase was partially offset by a reduction in amortization associated with intangible assets in the historical Production Solutions segment, which were fully impaired in the fourth quarter of 2018, as well as a reduction in amortization associated with certain service offerings in the Completion Solutions segment, where the intangible asset reached its full finite life. 
+Impairment of Property and Equipment 
+In 2019, we recorded a property and equipment impairment charge of $66.2 million in our Completion Solutions segment due to a reduction of the need for coiled tubing during the drill-out phase of the overall completions process due to a recent decline in exploration and production capital budgets and activity, an over-supply of new coiled tubing units, and the introduction of dissolvable plug technology. 
+In 2018, we recorded a property and equipment impairment charge of $45.7 million in our Production Solutions segment due to deteriorating market conditions attributed to depressed commodity prices towards the end of the fourth quarter of 2018, coupled with customers focusing more on the completions business where there is more technological differentiation and value. 
+Impairment of Goodwill 
+In 2019, we recorded a goodwill impairment charge of $20.3 million in our Completion Solutions segment due to a reduction of the need for coiled tubing during the drill-out phase of the overall completions process due to a recent decline in exploration and production capital budgets and activity, an over-supply of new coiled tubing units, and the introduction of dissolvable plug technology. 
+In 2018, we recorded a goodwill impairment charge of $13.0 million , which represented a full write-off of goodwill in our Production Solutions segment due to deteriorating market conditions attributed to depressed commodity prices towards the 
+40 
+end of the fourth quarter of 2018, coupled with customers focusing more on the completions business where there is more technological differentiation and value. 
+Impairment of Intangibles 
+In 2019, we recorded intangible asset impairment charges of $107.7 million associated with indefinite-lived trade names and an intangible asset impairment charge of $7.1 million associated with definite-lived customer relationship intangible assets, all within our Completion Solutions segment. These intangible asset impairment charges were primarily due to the transitioning of certain Magnum trade names to our trade names. These intangible asset impairment charges are also partly attributed to a reduction of the need for coiled tubing during the drill-out phase of the overall completions process due to a recent decline in exploration and production capital budgets and activity, an over-supply of new coiled tubing units, and the introduction of dissolvable plug technology. 
+In 2018, we recorded an intangible asset impairment charge of $9.3 million associated with indefinite-lived trade names and an intangible asset impairment charge of $9.8 million associated with definite-lived customer relationship intangible assets, all within our Production Solutions segment, and primarily due to deteriorating market conditions attributed to depressed commodity prices towards the end of the fourth quarter of 2018, coupled with customers focusing more on the completions business where there is more technological differentiation and value. 
+Non-Operating Expenses 
+Non-operating expenses increased $16.6 million to $38.9 million in 2019 . The increase in comparison to 2018 was primarily related to an increase in interest expense related to higher indebtedness and an increased interest rate in conjunction with the Senior Notes, which were entered into in the fourth quarter of 2018 in connection with the Magnum Acquisition. 
+Provision (Benefit) for Income Taxes 
+Our effective tax rate was 1.8% for 2019 and (4.7)% for 2018. The valuation allowance against our deferred tax assets results in tax expense that does not directly correlate with changes in our income levels. Our tax benefit for 2019 is comprised of tax amortization and impairment of indefinite-lived intangible assets, which are excluded when calculating the amount of valuation allowance needed, offset by state jurisdictions where income is expected to exceed available net operating losses. 
+Adjusted EBITDA 
+Adjusted EBITDA decreased $28.0 million to $113.0 million for 2019 . The Adjusted EBITDA decrease is primarily due to the changes in revenue and expenses discussed above. See “Non-GAAP Financial Measures” below for further explanation. 
+Non-GAAP Financial Measures 
+EBITDA and Adjusted EBITDA 
+EBITDA and Adjusted EBITDA are supplemental non-GAAP financial measures that are used by management and external users of our financial statements, such as industry analysts, investors, lenders, and rating agencies. 
+We define EBITDA as net income (loss) before interest, depreciation, amortization of intangibles, and provision (benefit) for income taxes. 
+We define Adjusted EBITDA as EBITDA further adjusted for (i) property and equipment, goodwill, and/or intangible asset impairment charges, (ii) transaction and integration costs related to acquisitions and our IPO, (iii) loss or gain on equity investment method, (iv) loss or gain on revaluation of contingent liabilities, (v) loss or gain on the sale of subsidiaries, (vi) restructuring charges, (vii) stock-based compensation expense, (viii) loss or gain on sale of property and equipment, and (ix) other expenses or charges to exclude certain items which we believe are not reflective of ongoing performance of our business, such as legal expenses and settlement costs related to litigation outside the ordinary course of business. 
+41 
+Management believes EBITDA and Adjusted EBITDA are useful because they allow us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at these measures because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures, and the method by which the assets were acquired. These measures should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with accounting principles generally accepted in the United States of America (“GAAP”) or as an indicator of our operating performance. Certain items excluded from these measures are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of these measures. Our computations of these measures may not be comparable to other similarly titled measures of other companies. We believe that these are widely followed measures of operating performance. 
+The following table presents a reconciliation of the non-GAAP financial measures of EBITDA and Adjusted EBITDA to the GAAP financial measure of net income (loss): 
+Year Ended December 31, 
+2019 
+2018 
+(in thousands) 
+EBITDA reconciliation: 
+Net loss 
+$ 
+(217,751 
+) 
+$ 
+(52,983 
+) 
+Interest expense 
+39,770 
+22,939 
+Interest income 
+(860 
+) 
+(624 
+) 
+Depreciation 
+50,544 
+54,257 
+Amortization of intangibles 
+18,367 
+9,558 
+Provision (benefit) for income taxes 
+(3,887 
+) 
+2,375 
+EBITDA 
+$ 
+(113,817 
+) 
+$ 
+35,522 
+Adjusted EBITDA reconciliation: 
+EBITDA 
+$ 
+(113,817 
+) 
+$ 
+35,522 
+Impairment of property and equipment 
+66,200 
+45,694 
+Impairment of goodwill 
+20,273 
+12,986 
+Impairment of intangibles 
+114,804 
+19,065 
+Transaction and integration costs 
+13,047 
+10,327 
+Loss on equity method investment 
+— 
+347 
+(Gain) loss on revaluation of contingent liabilities 
+(21,187 
+) 
+3,262 
+Loss on sale of subsidiaries 
+15,896 
+— 
+Restructuring charges 
+3,976 
+— 
+Stock-based compensation expense 
+14,057 
+13,221 
+Loss on sale of property and equipment 
+(538 
+) 
+(1,731 
+) 
+Legal fees and settlements (2) 
+307 
+2,358 
+Adjusted EBITDA 
+$ 
+113,018 
+$ 
+141,051 
+(1) Amounts relate to the revaluation of contingent liabilities associated with our recent acquisitions. The impact is included in our Consolidated Statements of Income and Comprehensive Income (Loss) . For additional information on contingent liabilities, see Note 12 – Commitments and Contingencies included Item 8 of Part II of this Annual Report. 
+(2) Amounts represent fees and legal settlements associated with legal proceedings brought pursuant to the FLSA and/or similar state laws. 
+42 
+Return on Invested Capital 
+ROIC is a supplemental non-GAAP financial measure. We define ROIC as after-tax net operating profit (loss), divided by average total capital. We define after-tax net operating profit (loss) as net income (loss) plus (i) property and equipment, goodwill, and/or intangible asset impairment charges, (ii) transaction and integration costs related to acquisitions and our IPO, (iii) interest expense (income), (iv) restructuring charges, (v) loss or gain on the sale of subsidiaries, and (vi) the provision or benefit for deferred income taxes. We define total capital as book value of equity plus the book value of debt less balance sheet cash and cash equivalents. We then take the average of the current and prior year-end total capital for use in this analysis. 
+Management believes ROIC is a meaningful measure because it quantifies how well we generate operating income relative to the capital we have invested in our business and illustrates the profitability of a business or project taking into account the capital invested. Management uses ROIC to assist them in capital resource allocation decisions and in evaluating business performance. Although ROIC is commonly used as a measure of capital efficiency, definitions of ROIC differ, and our computation of ROIC may not be comparable to other similarly titled measures of other companies. 
+The following table provides an explanation of our calculation of ROIC for the years ended December 31, 2019 and 2018 : 
+Year Ended December 31, 
+2019 
+2018 
+(in thousands) 
+Net loss 
+$ 
+(217,751 
+) 
+$ 
+(52,983 
+) 
+Add back: 
+Impairment of property and equipment 
+66,200 
+45,694 
+Impairment of goodwill 
+20,273 
+12,986 
+Impairment of intangibles 
+114,804 
+19,065 
+Transaction and integration costs 
+13,047 
+10,327 
+Interest expense 
+39,770 
+22,939 
+Interest income 
+(860 
+) 
+(624 
+) 
+Restructuring charges 
+3,976 
+— 
+Loss on sale of subsidiaries 
+15,896 
+— 
+Provision (benefit) for deferred income taxes 
+(4,327 
+) 
+898 
+After-tax net operating profit 
+$ 
+51,028 
+$ 
+58,302 
+Total capital as of prior year-end: 
+Total stockholders’ equity 
+$ 
+594,823 
+$ 
+287,358 
+Total debt 
+435,000 
+242,235 
+Less cash and cash equivalents 
+(63,615 
+) 
+(17,513 
+) 
+Total capital as of prior year-end 
+$ 
+966,208 
+$ 
+512,080 
+Total capital as of year-end: 
+Total stockholders’ equity 
+$ 
+389,877 
+$ 
+594,823 
+Total debt 
+400,000 
+435,000 
+Less cash and cash equivalents 
+(92,989 
+) 
+(63,615 
+) 
+Total capital as of year-end 
+$ 
+696,888 
+$ 
+966,208 
+Average total capital 
+$ 
+831,548 
+$ 
+739,144 
+ROIC 
+6.1 
+% 
+7.9 
+% 
+43 
+Adjusted Gross Profit (Excluding Depreciation and Amortization) 
+GAAP defines gross profit as revenues less cost of revenues and includes depreciation and amortization in costs of revenues. We define adjusted gross profit (excluding depreciation and amortization) as revenues less direct and indirect costs of revenues (excluding depreciation and amortization). This measure differs from the GAAP definition of gross profit because we do not include the impact of depreciation and amortization, which represent non-cash expenses. 
+Management uses adjusted gross profit (excluding depreciation and amortization) to evaluate operating performance. We prepare adjusted gross profit (excluding depreciation and amortization) to eliminate the impact of depreciation and amortization because we do not consider depreciation and amortization indicative of our core operating performance. Adjusted gross profit (excluding depreciation and amortization) should not be considered as an alternative to gross profit (loss), operating income (loss), or any other measure of financial performance calculated and presented in accordance with GAAP. Adjusted gross profit (excluding depreciation and amortization) may not be comparable to similarly titled measures of other companies because other companies may not calculate adjusted gross profit (excluding depreciation and amortization) or similarly titled measures in the same manner as we do. 
+The following table presents a reconciliation of adjusted gross profit (excluding depreciation and amortization) to GAAP gross profit (loss). 
+Year Ended December 31, 
+2019 
+2018 
+(in thousands) 
+Calculation of gross profit 
+Revenues 
+$ 
+832,937 
+$ 
+827,174 
+Cost of revenues (exclusive of depreciation and amortization shown separately below) 
+669,979 
+639,298 
+Depreciation (related to cost of revenues) 
+47,006 
+53,358 
+Amortization of intangibles 
+18,367 
+9,558 
+Gross profit 
+$ 
+97,585 
+$ 
+124,960 
+Adjusted gross profit (excluding depreciation and amortization) reconciliation: 
+Gross profit 
+$ 
+97,585 
+$ 
+124,960 
+Depreciation (related to cost of revenues) 
+47,006 
+53,358 
+Amortization of intangibles 
+18,367 
+9,558 
+Adjusted gross profit (excluding depreciation and amortization) 
+$ 
+162,958 
+$ 
+187,876 
+44 
+Liquidity and Capital Resources 
+Sources and Uses of Liquidity 
+Historically, we have met our liquidity needs principally from cash flows from operating activities, external borrowings, proceeds from the IPO, and capital contributions (prior to the IPO). Our principal uses of cash are to fund capital expenditures and acquisitions, to service our outstanding debt, and to fund our working capital requirements. In 2018, we issued $400.0 million of Senior Notes to, together with cash on hand and borrowings under the 2018 ABL Credit Facility (as defined below), fund the Magnum Acquisition as well as fully repay and terminate the term loan borrowings and the outstanding revolving credit commitments under our prior credit facility. For additional information regarding the Senior Notes, see Note 9 – Debt Obligations included in Item 8 of Part II of this Annual Report. In the third quarter of 2019, we divested the Production Solutions segment for approximately $17.1 million in cash. We plan to use such proceeds to fund a portion of our 2020 capital expenditures. 
+We continually monitor potential capital sources, including equity and debt financing, to meet our investment and target liquidity requirements. Our future success and growth will be highly dependent on our ability to continue to access outside sources of capital. In addition, our ability to satisfy our liquidity requirements depends on our future operating performance, which is affected by prevailing economic conditions, the level of drilling, completion and production activity for North American onshore oil and natural gas resources, and financial and business and other factors, many of which are beyond our control. 
+Our total 2019 capital expenditure budget, excluding possible acquisitions, was between $60.0 million and $70.0 million , and the actual amount of capital expenditures incurred in 2019 was $62.1 million . Our capital expenditure budget for 2020, excluding possible acquisitions, is expected to be between $20.0 million and $25.0 million . The nature of our capital expenditures is comprised of a base level of investment required to support our current operations and amounts related to growth and company initiatives. Capital expenditures for growth and company initiatives are discretionary. We continually evaluate our capital expenditures and the amount we ultimately spend will depend on a number of factors including expected industry activity levels and company initiatives. 
+At December 31, 2019 , we had $93.0 million of cash and cash equivalents and $99.2 million of availability under the 2018 ABL Credit Facility, which resulted in a total liquidity position of $192.2 million . Based on our current forecasts, we believe that borrowings under the 2018 ABL Credit Facility, together with cash flows from operations, should be sufficient to fund our capital requirements for at least the next twelve months from the issuance date of our consolidated financial statements. However, we can make no assurance regarding our ability to achieve our forecasts. Furthermore, depending on our financial performance, we may implement certain cost-cutting measures, as necessary, to continue to meet our liquidity and capital resource needs for at least the next twelve months from the issuance date of our consolidated financial statements. We can make no assurance regarding our ability to successfully implement such measures, or whether such measures would be sufficient to mitigate a decline in our financial performance. 
+Although we do not budget for acquisitions, pursuing growth through acquisitions may continue to be a significant part of our business strategy. Our ability to make significant additional acquisitions for cash will require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all. 
+Senior Notes 
+On October 25, 2018, we issued $400.0 million principal amount of Senior Notes. The proceeds from the Senior Notes, together with cash on hand and borrowings under the 2018 ABL Credit Facility (as defined below), were used to (i) fund a portion of the upfront cash purchase price of the Magnum Acquisition, (ii) repay all indebtedness under the credit facility entered into in conjunction with our IPO, and (iii) pay fees and expenses associated with the issuance of the Senior Notes, the Magnum Acquisition, and the 2018 ABL Credit Facility (as defined below). For additional information on the Senior Notes, see Note 9 – Debt Obligations included in Item 8 of Part II of this Annual Report. 
+2018 ABL Credit Facility 
+On October 25, 2018, we entered into a credit agreement dated as of October 25, 2018 (the “2018 ABL Credit Agreement”), that permits aggregate borrowings of up to $200.0 million , subject to a borrowing base, including a Canadian tranche with a sub-limit of up to $25.0 million and a sub-limit of $50.0 million for letters of credit (the “2018 ABL Credit Facility”). The 2018 ABL Credit Facility will mature on October 25, 2023 or, if earlier, on the date that is 180 days before the scheduled maturity date of the Senior Notes if they have not been redeemed or repurchased by such date. 
+45 
+Loans to us and our domestic related subsidiaries (the “U.S. Credit Parties”) under the 2018 ABL Credit Facility may be base rate loans or LIBOR loans; and loans to Nine Energy Canada Inc., a corporation organized under the laws of Alberta, Canada, and its restricted subsidiaries (the “Canadian Credit Parties”) under the Canadian tranche may be CDOR loans or Canadian prime rate loans. The applicable margin for base rate loans and Canadian prime rate loans vary from 0.75% to 1.25% and the applicable margin for LIBOR loans or CDOR loans vary from 1.75% to 2.25% in each depending on our leverage ratio. In addition, a commitment fee of 0.50% per annum will be charged on the average daily unused portion of the revolving commitments. 
+The 2018 ABL Credit Agreement contains various affirmative and negative covenants, including financial reporting requirements and limitations on indebtedness, liens, mergers, consolidations, liquidations and dissolutions, sales of assets, dividends and other restricted payments, investments (including acquisitions) and transactions with affiliates. In addition, the 2018 ABL Credit Agreement contains a minimum fixed charge ratio covenant of 1.00 to 1.00 that is tested quarterly when the availability under the 2018 ABL Credit Facility drops below a certain threshold or a default has occurred until the availability exceeds such threshold for 30 consecutive days and such default is no longer outstanding. We were in compliance with all covenants under the 2018 ABL Credit Agreement as of December 31, 2019 . 
+All of the obligations under the 2018 ABL Credit Facility are secured by first priority perfected security interests (subject to permitted liens) in substantially all of the personal property of U.S. Credit Parties, excluding certain assets. The obligations under the Canadian tranche are further secured by first priority perfected security interests (subject to permitted liens) in substantially all of the personal property of Canadian Credit Parties excluding certain assets. The 2018 ABL Credit Facility is guaranteed by the U.S. Credit Parties, and the Canadian tranche is further guaranteed by the Canadian Credit Parties and the U.S. Credit Parties. 
+At December 31, 2019 , our availability under the 2018 ABL Credit Facility was approximately $99.2 million , net of an outstanding letter of credit of $0.2 million . During the second quarter of 2019, we repaid our outstanding revolver borrowings in full, and at December 31, 2019 , we had no outstanding revolver borrowings. 
+Cash Flows 
+Our cash flows for the years ended December 31, 2019 , and 2018 are presented below: 
+Year Ended December 31, 
+2019 
+2018 
+(in thousands) 
+Operating activities 
+$ 
+101,305 
+$ 
+89,577 
+Investing activities 
+(34,121 
+) 
+(389,765 
+) 
+Financing activities 
+(37,905 
+) 
+346,691 
+Impact of foreign exchange rate on cash 
+95 
+(401 
+) 
+Net change in cash and cash equivalents 
+$ 
+29,374 
+$ 
+46,102 
+Operating Activities 
+Net cash provided by operating activities was $101.3 million in 2019 compared to $89.6 million in net cash provided by operating activities in 2018 . The $11.7 million increase in net cash provided by operating activities was primarily a result of a $54.5 million increase in cash collections and other changes in working capital which provided an increased source of cash flow in 2019 in comparison to 2018. The overall increase in net cash provided by operating activities was partially offset by a $42.8 million decrease in cash flow provided by continuing operations, adjusted for any non-cash items, primarily due to a reduction in cash operating income driven by a deterioration in market conditions year-over-year. 
+Investing Activities 
+Net cash used in investing activities was $34.1 million in 2019 compared to $389.8 million in net cash used in investing activities in 2018 . The $355.7 million decrease in net cash used in investing activities was primarily related to a $350.0 million reduction in cash flow used in acquisitions in 2019 compared to 2018, as well as $16.9 million in proceeds received from the sale of our Production Solutions segment in 2019. In addition, the decrease in net cash used was partly due to an increase of $4.7 million in proceeds received in 2019 from notes receivable payments as well as an increase of $1.5 million in 2019 in cash payments received from the proceeds from the sale of property and equipment. The overall decrease in net cash used in investing activities was partially offset by an increase of $18.5 million in cash purchases of property and equipment in 2019 compared to 2018. 
+46 
+Financing Activities 
+Net cash used in financing activities was $37.9 million in 2019 compared to $346.7 million in net cash provided by financing activities in 2018 . The $384.6 million decrease in net cash provided by financing activities was primarily related to $171.8 million in proceeds received from the IPO and issuances of common stock in 2018 and $400.0 million in proceeds received from the Senior Notes in 2018 that did not recur in 2019. In addition, net cash provided by financing activities decreased $3.6 million in 2019 related to an increase in restricted stock vests and options exercised during the year. The overall decrease in net cash provided by financing activities was partially offset by a decrease in net payments made on prior term loans of $146.0 million in 2019 and a reduction of $16.3 million in deferred financing costs paid in 2019 compared to 2018. The overall decrease in net cash provided by financing activities was also partially offset by a reduction in net payments on revolving credit facilities in 2019 of $26.2 million . 
+Contractual Obligations 
+In the normal course of business, we enter into various contractual obligations that impact or could impact our liquidity. The table below contains our known contractual commitments at December 31, 2019 . 
+Payments Due by Period for the Year Ended December 31, 
+2020 
+2021 
+2022 
+2023 
+2024 
+Thereafter 
+Total 
+(in thousands) 
+Senior Notes (1) 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+400,000 
+$ 
+— 
+$ 
+— 
+$ 
+400,000 
+2018 ABL Credit Facility (2) 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+Interest expense (3) 
+35,000 
+35,000 
+35,000 
+28,575 
+— 
+— 
+133,575 
+Capital leases 
+1,253 
+1,253 
+1,099 
+66 
+— 
+— 
+3,671 
+Operating leases 
+10,597 
+8,504 
+7,485 
+6,649 
+4,470 
+17,105 
+54,810 
+Total 
+$ 
+46,850 
+$ 
+44,757 
+$ 
+43,584 
+$ 
+435,290 
+$ 
+4,470 
+$ 
+17,105 
+$ 
+592,056 
+(1) Includes principal only. 
+(2) The amount presented in the table above represents the outstanding principal borrowings under the 2018 ABL Credit Facility as of December 31, 2019 and does not include future commitment fees, amortization of deferred financing costs, interest expense, or other fees. These outstanding principal borrowings must be repaid prior to the maturity date, which is October 25, 2023 or, if earlier, on the date that is 180 days before the scheduled maturity date of the Senior Notes if they have not been redeemed or repurchased by such date. Any future borrowings or repayments could change the total amount outstanding under the 2018 ABL Credit Facility. 
+(3) Consists of fixed rate interest on the Senior Notes as of December 31, 2019 . 
+In addition, at December 31, 2019, we have recorded certain contingent liabilities associated with recent acquisitions. For additional information, see Note 12 – Commitments and Contingencies included in Item 8 of Part II of this Annual Report. 
+Off-Balance Sheet Arrangements 
+At December 31, 2019 , we had a letter of credit of $0.2 million , which represented an off-balance sheet arrangement as defined in Item 303(a)(4)(ii) of Regulation S-K. As of December 31, 2019 , no liability has been recognized in our Consolidated Balance Sheets for the letter of credit. 
+Critical Accounting Policies 
+The discussion and analysis of our financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. We provide expanded discussion of our more significant accounting policies, estimates, and judgments below. We believe that 
+47 
+most of these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. 
+Emerging Growth Company Status 
+We are an “emerging growth company” as defined in the JOBS Act. Under Section 107 of the JOBS Act, as an emerging growth company, we are taking advantage of an extended transition period for the adoption of new or revised financial accounting standards, including the reduced reporting requirements and exemptions, and the longer phase-in periods for the adoption of new or revised financial accounting standards, until we are no longer an emerging growth company. Our election to use the longer phase-in periods permitted by this election may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the longer phase-in periods under Section 107 of the JOBS Act and who will comply with new or revised financial accounting standards. If we were to subsequently elect instead to comply with these public company effective dates, such election would be irrevocable pursuant to Section 107 of the JOBS Act. 
+Revenue Recognition 
+For information about our revenue, see Note 4 – Revenue included in Item 8 of Part II of this Annual Report. 
+Property and Equipment 
+Property and equipment is stated at cost and depreciated under the straight-line method over the estimated useful lives of the asset. Equipment held under capital leases is stated at the present value of its future minimum lease payments and is depreciated under the straight-line method over the shorter of the lease term or the estimated useful life of the asset. When assets are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the accounts and any resulting gain or loss is recognized within operating expenses. Normal repair and maintenance costs are charged to operating expense as incurred. Significant renewals and betterments are capitalized. 
+Valuation of Long-Lived Assets 
+Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. In performing the review for impairment, future cash flows expected to result from the use of the asset and its eventual disposal are estimated. If the undiscounted future cash flows are less than the carrying amount of the assets, there is an indication that the asset may be impaired. The amount of the impairment is measured as the difference between the carrying value and the Level 3 fair value of the asset. The Level 3 fair value is determined either through the use of an external valuation, or by means of an analysis of discounted future cash flows based on expected utilization. Determining fair value requires the use of estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating profit margins, weighted average costs of capital, terminal growth rates, future market share, the impact of new product development, and future market conditions, among others. We believe that the estimates and assumptions used in impairment assessments are reasonable and appropriate. Impairment losses are reflected in “Income (loss) from operations” in our Consolidated Statements of Income and Comprehensive Income (Loss) . 
+In the fourth quarter of 2019, we recorded a property and equipment impairment charge of $66.2 million and a definite-lived customer relationship intangible asset impairment charge of $7.1 million . These impairment charges represent the difference between the carrying value and the estimated fair value of the long-lived assets in our coiled tubing asset group within our Completion Solutions segment and were due to a reduction of the need for coiled tubing during the drill-out phase of the overall completions process due to a recent decline in exploration and production capital budgets and activity, an over-supply of new coiled tubing units, and the introduction of dissolvable plug technology. 
+In the fourth quarter of 2018, we recorded a property and equipment impairment charge of $45.7 million and a definite-lived customer relationship intangible asset impairment charge of $9.8 million . These impairment charges represent the difference between the carrying value and the estimated fair value of the long-lived assets associated with our Production Solutions segment and were due to deteriorating conditions attributed to depressed commodity prices towards the end of the fourth quarter of 2018, coupled with customers focusing more on the completions business where there is more technological differentiation and value. On August 30, 2019, we sold our Production Solutions segment to Brigade. 
+For additional information on these impairment charges, see Note 6 – Property and Equipment included in Item 8 of Part II of this Annual Report. 
+For additional information on the Production Solutions divestiture, see Note 3 – Divestitures, Acquisitions, and Combinations included in Item 8 of Part II of this Annual Report. 
+48 
+Valuation of Goodwill and Intangible Assets 
+Goodwill has an indefinite useful life and is not subject to amortization. Intangible assets with indefinite useful lives (specifically trademarks and trade names) are also not subject to amortization. For goodwill and intangible assets with indefinite useful lives, an assessment for impairment is performed annually on December 31 or when there is an indication an impairment may have occurred. Goodwill is reviewed for impairment by comparing the carrying value of each of our reporting unit’s net assets (including allocated goodwill) to the Level 3 fair value of our reporting unit. The Level 3 fair value of our reporting unit is determined by using the income approach (discounted cash flows of forecasted income). Intangible assets with indefinite useful lives are reviewed for impairment by comparing the carrying value of the intangible asset to the Level 3 fair value of the intangible asset. The Level 3 fair value of intangible assets with indefinite useful lives (specifically trademarks and trade names) is estimated using the relief-from-royalty method of the income approach. This approach is based on the assumption that in lieu of ownership, a company would be willing to pay a royalty in order to exploit the related benefits of this intangible asset. Determining fair value requires the use of estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating profit margins, royalty rates, weighted average costs of capital, terminal growth rates, future market share, the impact of new product development, and future market conditions, among others. We believe that the estimates and assumptions used in impairment assessments are reasonable and appropriate. We recognize a goodwill impairment charge for the amount by which the carrying value of goodwill exceeds our reporting unit’s Level 3 fair value. We recognize an indefinite-lived intangible asset impairment charge of the amount by which the carrying value of the intangible asset exceeds the Level 3 fair value of the intangible asset. Any impairment losses are reflected in “Income (loss) from operations” in our Consolidated Statements of Income and Comprehensive Income (Loss) . 
+Intangible assets with definite lives include technology, customer relationships, and non-compete agreements. The Level 3 fair value of technology and the Level 3 fair value of customer relationships are estimated using the income approach, specifically the multi-period excess earnings method. The multi-period excess earnings method consists of isolating the cash flows attributed to the intangible asset, which are then discounted to present value to calculate the Level 3 fair value of the intangible asset. The Level 3 fair value of non-compete agreements is estimated using a with and without scenario where cash flows are projected through the term of the non-compete agreement assuming the non-compete agreement is in place and compared to cash flows assuming the non-compete agreement is not in place. 
+Intangible assets with definite lives are amortized based on the estimated consumption of the economic benefit over their estimated useful lives. Intangible assets with definite lives are tested for impairment whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. 
+In the fourth quarter of 2019, in connection with our annual goodwill impairment test, we recorded a goodwill impairment charge of $20.3 million , in our coiled tubing reporting unit within our Completion Solutions segment. In addition, in the fourth quarter of 2019, in connection with our annual indefinite-lived intangible asset impairment test, we recorded an intangible asset impairment charge of $12.7 million associated with the indefinite-lived trade names in our coiled tubing reporting unit and an intangible asset impairment charge of $95.0 million associated with the indefinite-lived trade names in our completion tools reporting unit, both within our Completion Solutions segment. As described above in “Critical Accounting Policies – Valuation of Long-Lived Assets” and also in the fourth quarter of 2019, we recorded an intangible asset impairment charge of $7.1 million associated with the definite-lived customer relationship intangible assets in our coiled tubing asset group within our Completion Solutions segment. 
+In the fourth quarter of 2018, in connection with our annual goodwill impairment test, we recorded a goodwill impairment charge of $13.0 million , which represented a full write-off of goodwill attributed to our Production Solutions segment. In addition, in the fourth quarter of 2018, in connection with our annual indefinite-lived intangible asset impairment test, we recorded an intangible asset impairment charge of $9.3 million associated with indefinite-lived trade names in our Production Solutions segment. As described above in “Critical Accounting Policies – Valuation of Long-Lived Assets” and also in the fourth quarter of 2018, we recorded an intangible asset impairment charge of $9.8 million related to definite-lived customer relationship intangible assets associated with our Production Solutions segment. On August 30, 2019, we sold our Production Solutions segment to Brigade Energy Service LLC (“Brigade”). 
+For additional information on goodwill and both indefinite-lived and definite-lived intangible asset impairment charges, see Note 7 – Goodwill and Intangible Assets included in Item 8 of Part II of this Annual Report. 
+For additional information on the Production Solutions divestiture, see Note 3 – Divestitures, Acquisitions, and Combinations included in Item 8 of Part II of this Annual Report. 
+49 
+Recognition of Provisions for Contingencies 
+In the ordinary course of business, we are subject to various claims, suits, and complaints. We, in consultation with internal and external advisors, will provide for a contingent loss in the financial statements if it is probable that a liability has been incurred at the date of the financial statements and the amount can be reasonably estimated. If it is determined that the reasonable estimate of the loss is a range and that there is no best estimate within the range, provision will be made for the lower amount of the range. Legal costs are expensed as incurred. 
+Stock-based Compensation 
+We account for awards of stock-based compensation at fair value on the date granted to employees and recognize the compensation expense in the financial statements over the requisite service period. Fair value of the stock-based compensation was measured using the Black-Scholes model for all of the options outstanding. These models require assumptions and estimates for inputs, especially the estimate of the volatility in the value of the underlying share price, that affect the resultant values and hence the amount of compensation expense recognized. We determine the estimate of volatility periodically based on the weighted averages for the stocks of comparable publicly traded companies. Fair value of the stock-based compensation was measured using a Monte Carlo simulation model for all of the performance share units outstanding . Forfeitures are recorded as they occur. All stock-based compensation expense is recorded using the straight-line method and is included in “General and administrative expenses” in our Consolidated Statements of Income and Comprehensive Income (Loss) . 
+Determining Fair Market Value 
+Determining the appropriate fair value model and calculating the fair value of options requires the input of highly subjective assumptions, including the expected volatility of the price of our stock, the risk-free rate, the expected term of the options, and the expected dividend yield of our common stock. These estimates involve inherent uncertainties and the application of management’s judgment. If factors change and different assumptions are used, our stock-based compensation expense could be materially different in the future. We estimate the fair value of each option grant using the Black-Scholes option-pricing model. The Black-Scholes option pricing model requires estimates of key assumptions based on both historical information and management judgment regarding market factors and trends. 
+Expected Life – The expected term of stock options represents the period the stock options are expected to remain outstanding and is based on the simplified method, which is the weighted average vesting term plus the original contractual term, divided by two. 
+Expected Volatility – Prior to our IPO, when our stock was not publicly traded, we determined volatility based on an analysis of the PHLX Oil Service Index that tracks publicly traded oilfield service stocks. Subsequent to our IPO and as a publicly traded company, we develop our expected volatility based upon a weighted average volatility of our peer group. 
+Risk-free Interest Rate – The risk-free interest rates for options granted are based on the average of five year and seven year constant maturity Treasury bond rates whose term is consistent with the expected term of an option from the date of grant. 
+Expected Term – The expected term is based on the midpoint between the vesting date and contractual term of an option. The expected term represents the period that our stock-based awards are expected to be outstanding. 
+Expected Dividend Yield – We do not anticipate paying cash dividends on our shares of common stock; therefore, the expected dividend yield is assumed to be zero. 
+Recent Accounting Pronouncements 
+For additional information on recent accounting pronouncements, see Note 2 – Significant Accounting Policies included in Item 8 of Part II of this Annual Report. 
+50 
+Item 7A. 
+Quantitative and Qualitative Disclosures About Market Risk 
+We are exposed to market risk in the ordinary course of our business. Market risk represents the risk of loss that may impact our financial position due to adverse changes in financial market prices and rates. Our market risk exposure is primarily a result of fluctuations in commodity prices and non-U.S. currency exchange rates. 
+Commodity Price Risk 
+Our fuel purchases expose us to commodity price risk. Our fuel costs consist primarily of diesel fuel used by our various trucks and other motorized equipment. The prices for fuel are volatile and are impacted by changes in supply and demand, as well as market uncertainty and regional shortages. Recently we have been able to pass along price increases to our customers; however, we may be unable to do so in the future. As of December 31, 2019 , we were not engaged in commodity price hedging activities, and we are not currently engaged in such activities. 
+Non-U.S. Currency Exchange Rates 
+Our operating facilities are in the U.S. and Canadian markets, and as a result our primary exposure to fluctuations in currency exchange rates relates to fluctuations between the U.S. dollar and the Canadian dollar. In Canada, the effects of currency fluctuations are largely mitigated because local expenses of such operations are also generally denominated in the local currency. However, there may be instances in which costs and revenue will not be matched with respect to currency denomination, and we may experience economic loss and a negative impact on earnings or net assets solely as a result of foreign currency exchange rate fluctuations. We do not hedge our exposure to changes in foreign exchange rates. For additional information on risk associated with Non-U.S. currency exchange rates, see “Risk Factors” in Item 1A of Part I of this Annual Report. 
+Assets and liabilities for which the functional currency is the local currency are translated using the exchange rates in effect at the balance sheet date, resulting in translation adjustments that are reflected as “Accumulated other comprehensive income (loss)” in the stockholders’ equity section on our Consolidated Balance Sheets . We recorded adjustments to our equity account of approximately $0.4 million and $1.2 million for the years ended December 31, 2019 and 2018 , respectively, to reflect the net impact of the changes in the strength of the Canadian dollar against the U.S. dollar. 
+51 
+Item 8. 
+Financial Statements and Supplementary Data 
+Index to Consolidated Financial Statements 
+Report of Independent Registered Public Accounting Firm 
+F-1 
+Consolidated Balance Sheets as of December 31, 2019 and 2018 
+F-2 
+Consolidated Statements of Income and Comprehensive Income (Loss) for the Years Ended December 31, 2019, 2018, and 2017 
+F-3 
+Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2019, 2018, and 2017 
+F-4 
+Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018, and 2017 
+F-5 
+Notes to Consolidated Financial Statements 
+F-6 
+52 
+Report of Independent Registered Public Accounting Firm 
+To the Board of Directors and Stockholders of Nine Energy Service, Inc. 
+Opinion on the Financial Statements 
+We have audited the accompanying consolidated balance sheets of Nine Energy Service, Inc. and its subsidiaries (the “Company”) as of December 31, 2019 and 2018 , and the related consolidated statements of income and comprehensive income (loss), of stockholders’ equity and of cash flows for each of the three years in the period ended December 31, 2019 , including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018 , and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America. 
+Basis for Opinion 
+These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. 
+Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. 
+/s/ PricewaterhouseCoopers LLP 
+Houston, Texas 
+March 9, 2020 
+We have served as the Company’s auditor since 2011. 
+F-1 
+NINE ENERGY SERVICE, INC. 
+CONSOLIDATED BALANCE SHEETS 
+(In thousands, except share and per share amounts) 
+December 31, 
+2019 
+2018 
+Assets 
+Current assets 
+Cash and cash equivalents 
+$ 
+92,989 
+$ 
+63,615 
+Accounts receivable, net 
+96,889 
+154,783 
+Income taxes receivable 
+660 
+— 
+Inventories, net 
+60,945 
+91,435 
+Prepaid expenses and other current assets 
+17,434 
+15,717 
+Notes receivable from shareholders (Note 15) 
+— 
+7,626 
+Total current assets 
+268,917 
+333,176 
+Property and equipment, net 
+128,604 
+211,644 
+Definite-lived intangible assets, net 
+147,991 
+173,451 
+Goodwill 
+296,196 
+307,804 
+Indefinite-lived intangible assets 
+1,000 
+108,711 
+Other long-term assets 
+8,187 
+6,386 
+Total assets 
+$ 
+850,895 
+$ 
+1,141,172 
+Liabilities and Stockholders’ Equity 
+Current liabilities 
+Accounts payable 
+$ 
+35,490 
+$ 
+46,132 
+Accrued expenses 
+24,730 
+61,434 
+Current portion of capital lease obligations 
+995 
+665 
+Income taxes payable 
+— 
+57 
+Total current liabilities 
+61,215 
+108,288 
+Long-term liabilities 
+Long-term debt 
+392,059 
+424,978 
+Deferred income taxes 
+1,588 
+5,915 
+Long-term capital lease obligations 
+2,201 
+2,330 
+Other long-term liabilities 
+3,955 
+4,838 
+Total liabilities 
+461,018 
+546,349 
+Commitments and contingencies (Note 12) 
+Stockholders’ equity 
+Common stock (120,000,000 shares authorized at $.01 par value; 30,555,677 and 30,163,408 shares issued and outstanding at December 31, 2019 and 2018 respectively) 
+306 
+302 
+Additional paid-in capital 
+758,853 
+746,428 
+Accumulated other comprehensive loss 
+(4,467 
+) 
+(4,843 
+) 
+Accumulated deficit 
+(364,815 
+) 
+(147,064 
+) 
+Total stockholders’ equity 
+389,877 
+594,823 
+Total liabilities and stockholders’ equity 
+$ 
+850,895 
+$ 
+1,141,172 
+All share data reflects the 8.0256 for 1 stock split that took place in January 2018. 
+The accompanying notes are an integral part of these consolidated financial statements. 
+F-2 
+NINE ENERGY SERVICE, INC. 
+CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (LOSS) 
+(In thousands, except share and per share amounts) 
+Year Ended December 31, 
+2019 
+2018 
+2017 
+Revenues (Note 4) 
+Service 
+$ 
+646,508 
+$ 
+708,750 
+$ 
+483,959 
+Product 
+186,429 
+118,424 
+59,701 
+832,937 
+827,174 
+543,660 
+Cost and expenses 
+Cost of revenues (exclusive of depreciation and amortization shown separately below) 
+Service 
+528,643 
+550,840 
+403,643 
+Product 
+141,336 
+88,458 
+44,824 
+General and administrative expenses 
+81,327 
+73,078 
+49,505 
+Depreciation 
+50,544 
+54,257 
+53,422 
+Amortization of intangibles 
+18,367 
+9,558 
+8,799 
+Impairment of property and equipment 
+66,200 
+45,694 
+— 
+Impairment of goodwill 
+20,273 
+12,986 
+31,530 
+Impairment of intangibles 
+114,804 
+19,065 
+3,800 
+(Gain) loss on revaluation of contingent liabilities 
+(21,187 
+) 
+3,262 
+415 
+Loss on sale of subsidiaries 
+15,896 
+— 
+— 
+(Gain) loss on sale of property and equipment 
+(538 
+) 
+(1,731 
+) 
+4,688 
+Loss from operations 
+(182,728 
+) 
+(28,293 
+) 
+(56,966 
+) 
+Interest expense 
+39,770 
+22,939 
+16,252 
+Interest income 
+(860 
+) 
+(624 
+) 
+(549 
+) 
+Loss before income taxes 
+(221,638 
+) 
+(50,608 
+) 
+(72,669 
+) 
+Provision (benefit) for income taxes 
+(3,887 
+) 
+2,375 
+(4,987 
+) 
+Net loss 
+$ 
+(217,751 
+) 
+$ 
+(52,983 
+) 
+$ 
+(67,682 
+) 
+Loss per share 
+Basic 
+$ 
+(7.43 
+) 
+$ 
+(2.17 
+) 
+$ 
+(4.55 
+) 
+Diluted 
+$ 
+(7.43 
+) 
+$ 
+(2.17 
+) 
+$ 
+(4.55 
+) 
+Weighted average shares outstanding 
+Basic 
+29,308,107 
+24,411,213 
+14,887,006 
+Diluted 
+29,308,107 
+24,411,213 
+14,887,006 
+Other comprehensive income (loss), net of tax 
+Foreign currency translation adjustments, net of $0 tax in each period 
+$ 
+376 
+$ 
+(1,159 
+) 
+$ 
+(198 
+) 
+Total other comprehensive income (loss), net of tax 
+376 
+(1,159 
+) 
+(198 
+) 
+Total comprehensive loss 
+$ 
+(217,375 
+) 
+$ 
+(54,142 
+) 
+$ 
+(67,880 
+) 
+All share data reflects the 8.0256 for 1 stock split that took place in January 2018. 
+The accompanying notes are an integral part of these consolidated financial statements. 
+F-3 
+NINE ENERGY SERVICE, INC. 
+CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY 
+(In thousands, except share amounts) 
+Common Stock 
+Additional 
+Paid-in 
+Accumulated 
+Other 
+Comprehensive 
+Retained 
+Earnings 
+(Accumulated 
+Total 
+Stockholders’ 
+Shares 
+Amounts 
+Capital 
+Income (Loss) 
+Deficit) 
+Equity 
+Stockholders’ equity as of December 31, 2016 
+13,386,986 
+$ 
+134 
+$ 
+317,937 
+$ 
+(3,486 
+) 
+$ 
+(26,399 
+) 
+$ 
+288,186 
+Issuance of common stock 
+2,501,643 
+25 
+61,897 
+— 
+— 
+61,922 
+Distribution to non-accredited investors 
+(78,089 
+) 
+(1 
+) 
+(2,437 
+) 
+— 
+— 
+(2,438 
+) 
+Stock-based compensation expense 
+— 
+— 
+7,568 
+— 
+— 
+7,568 
+Other comprehensive loss 
+— 
+— 
+— 
+(198 
+) 
+— 
+(198 
+) 
+Net loss 
+— 
+— 
+— 
+— 
+(67,682 
+) 
+(67,682 
+) 
+Stockholders’ equity as of December 31, 2017 
+15,810,540 
+$ 
+158 
+$ 
+384,965 
+$ 
+(3,684 
+) 
+$ 
+(94,081 
+) 
+$ 
+287,358 
+Issuance of common stock in IPO, net of offering costs 
+8,050,000 
+81 
+168,180 
+— 
+— 
+168,261 
+Issuance of common stock under stock compensation plan 
+1,166,587 
+12 
+(12 
+) 
+— 
+— 
+— 
+Issuance of common stock for acquisitions 
+5,015,745 
+50 
+177,797 
+— 
+— 
+177,847 
+Stock-based compensation expense 
+— 
+— 
+13,221 
+— 
+— 
+13,221 
+Exercise of stock options 
+135,817 
+1 
+2,904 
+— 
+— 
+2,905 
+Vesting of restricted stock 
+(28,324 
+) 
+— 
+(927 
+) 
+— 
+— 
+(927 
+) 
+Other issuances of common stock 
+13,043 
+— 
+300 
+— 
+— 
+300 
+Other comprehensive loss 
+— 
+— 
+— 
+(1,159 
+) 
+— 
+(1,159 
+) 
+Net loss 
+— 
+— 
+— 
+— 
+(52,983 
+) 
+(52,983 
+) 
+Stockholders’ equity as of December 31, 2018 
+30,163,408 
+$ 
+302 
+$ 
+746,428 
+$ 
+(4,843 
+) 
+$ 
+(147,064 
+) 
+$ 
+594,823 
+Issuance of common stock under stock compensation plan 
+462,622 
+5 
+(5 
+) 
+— 
+— 
+— 
+Stock-based compensation expense 
+— 
+— 
+14,057 
+— 
+— 
+14,057 
+Exercise of stock options 
+674 
+— 
+15 
+— 
+— 
+15 
+Vesting of restricted stock 
+(71,027 
+) 
+(1 
+) 
+(1,642 
+) 
+— 
+— 
+(1,643 
+) 
+Other comprehensive income 
+— 
+— 
+— 
+376 
+— 
+376 
+Net loss 
+— 
+— 
+— 
+— 
+(217,751 
+) 
+(217,751 
+) 
+Stockholders’ equity as of December 31, 2019 
+30,555,677 
+$ 
+306 
+$ 
+758,853 
+$ 
+(4,467 
+) 
+$ 
+(364,815 
+) 
+$ 
+389,877 
+All share data reflect the 8.0256 for 1 stock split that took place in January 2018. 
+The accompanying notes are an integral part of these consolidated financial statements. 
+F-4 
+NINE ENERGY SERVICE, INC. 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+(In thousands) 
+Year Ended December 31, 
+2019 
+2018 
+2017 
+Cash flows from operating activities 
+Net loss 
+$ 
+(217,751 
+) 
+$ 
+(52,983 
+) 
+$ 
+(67,682 
+) 
+Adjustments to reconcile net loss to net cash provided by operating activities 
+Depreciation 
+50,544 
+54,257 
+53,422 
+Amortization of intangibles 
+18,367 
+9,558 
+8,799 
+Amortization of deferred financing costs 
+2,984 
+2,966 
+1,615 
+Provision for (recovery of) doubtful accounts 
+849 
+(268 
+) 
+176 
+Provision (benefit) for deferred income taxes 
+(4,327 
+) 
+898 
+(5,815 
+) 
+Provision for inventory obsolescence 
+5,148 
+844 
+1,359 
+Impairment of property and equipment 
+66,200 
+45,694 
+— 
+Impairment of goodwill 
+20,273 
+12,986 
+31,530 
+Impairment of intangibles 
+114,804 
+19,065 
+3,800 
+Stock-based compensation expense 
+14,057 
+13,221 
+7,568 
+(Gain) loss on sale of property and equipment 
+(538 
+) 
+(1,731 
+) 
+4,688 
+(Gain) loss on revaluation of contingent liabilities (Note 12) 
+(21,187 
+) 
+3,262 
+415 
+Loss on sale of subsidiaries 
+15,896 
+— 
+— 
+Loss on equity method investment 
+— 
+347 
+368 
+Changes in operating assets and liabilities, net of effects from acquisitions 
+Accounts receivable, net 
+41,852 
+(24,972 
+) 
+(52,180 
+) 
+Inventories, net 
+22,545 
+(15,041 
+) 
+(8,212 
+) 
+Prepaid expenses and other current assets 
+2,395 
+(5,722 
+) 
+1,472 
+Accounts payable and accrued expenses 
+(27,901 
+) 
+27,156 
+12,530 
+Income taxes receivable/payable 
+(294 
+) 
+(255 
+) 
+15,158 
+Other assets and liabilities 
+(2,611 
+) 
+295 
+(3,340 
+) 
+Net cash provided by operating activities 
+101,305 
+89,577 
+5,671 
+Cash flows from investing activities 
+Acquisitions, net of cash acquired 
+1,020 
+(349,986 
+) 
+— 
+Proceeds from sale of subsidiaries 
+16,914 
+— 
+— 
+Proceeds from sales of property and equipment 
+3,702 
+2,183 
+1,452 
+Proceeds from property and equipment casualty losses 
+1,576 
+1,743 
+300 
+Proceeds from notes receivable payments 
+7,626 
+2,941 
+— 
+Purchases of property and equipment 
+(64,959 
+) 
+(46,646 
+) 
+(45,216 
+) 
+Equity method investment 
+— 
+— 
+(1,000 
+) 
+Net cash used in investing activities 
+(34,121 
+) 
+(389,765 
+) 
+(44,464 
+) 
+Cash flows from financing activities 
+Proceeds from revolving credit facilities 
+10,000 
+35,000 
+56,481 
+Payments on revolving credit facilities 
+(45,000 
+) 
+(96,182 
+) 
+(38,287 
+) 
+Proceeds from Senior Notes 
+— 
+400,000 
+— 
+Proceeds from term loan 
+— 
+125,000 
+— 
+Payments on term loans 
+— 
+(270,975 
+) 
+(22,475 
+) 
+Payments on notes payable – insurance premium financing 
+— 
+— 
+(272 
+) 
+Payments on capital leases 
+(903 
+) 
+(128 
+) 
+— 
+Payments of contingent liabilities 
+(374 
+) 
+(3,445 
+) 
+(1,325 
+) 
+Proceeds from issuance of common stock in IPO, net of offering costs 
+— 
+171,450 
+— 
+Proceeds from other issuances of common stock 
+— 
+300 
+61,374 
+Proceeds from exercise of stock options 
+15 
+2,905 
+— 
+Vesting of restricted stock 
+(1,643 
+) 
+(927 
+) 
+— 
+Distribution to non-accredited investors 
+— 
+— 
+(2,438 
+) 
+Cost of debt issuance 
+— 
+(16,307 
+) 
+(716 
+) 
+Net cash provided by (used in) financing activities 
+(37,905 
+) 
+346,691 
+52,342 
+Impact of foreign currency exchange on cash 
+95 
+(401 
+) 
+(110 
+) 
+Net increase in cash and cash equivalents 
+29,374 
+46,102 
+13,439 
+Cash and cash equivalents 
+Cash and cash equivalents at beginning of period 
+63,615 
+17,513 
+4,074 
+Cash and cash equivalents at end of period 
+$ 
+92,989 
+$ 
+63,615 
+$ 
+17,513 
+Supplemental disclosures of cash flow information: 
+Cash paid for interest 
+$ 
+37,376 
+$ 
+5,981 
+$ 
+14,987 
+Cash paid (refunded) for income taxes 
+$ 
+517 
+$ 
+1,697 
+$ 
+(14,344 
+) 
+Non-cash investing and financing activities: 
+Issuance of common stock related to business acquisitions 
+$ 
+— 
+$ 
+177,847 
+$ 
+547 
+Contingent liability related to business acquisitions 
+$ 
+— 
+$ 
+23,982 
+$ 
+— 
+Capital expenditures in accounts payable and accrued expenses 
+$ 
+10 
+$ 
+4,476 
+$ 
+1,675 
+Property and equipment obtained by capital leases 
+$ 
+1,621 
+$ 
+3,123 
+$ 
+— 
+Receivable from property and equipment sale (including insurance) 
+$ 
+5,949 
+$ 
+1,199 
+$ 
+— 
+The accompanying notes are an integral part of these consolidated financial statements. 
+F-5 
+NINE ENERGY SERVICE, INC. 
+NOTES TO THE FINANCIAL STATEMENTS 
+1. Company and Organization 
+Company Description 
+Nine Energy Service, Inc. (the “Company” or “Nine”), a Delaware corporation, is an oilfield services business that provides services integral to the completion of unconventional wells through a full range of tools and methodologies. The Company is headquartered in Houston, Texas. 
+Production Solutions Divestiture 
+On August 30, 2019, the Company entered into a Membership Interest Purchase Agreement (“ Production Solutions Purchase Agreement”) with Brigade Energy Service LLC (“Brigade”). Pursuant to the Production Solutions Purchase Agreement, on such date, through the sale of all of the limited liability interests of its wholly owned subsidiary, Beckman Holding Production Services, LLC, the Company sold its Production Solutions segment to Brigade for approximately $17.1 million in cash. The Production Solutions Purchase Agreement contains customary representations and warranties, covenants, and indemnification provisions. The Company recorded a loss of $15.9 million in connection with this divestiture during the year ended December 31, 2019. For additional information on the divestiture of the Production Solutions segment, see Note 3 – Divestitures, Acquisitions, and Combinations . 
+Magnum Acquisition 
+On October 25, 2018, pursuant to the terms of a Securities Purchase Agreement, dated October 15, 2018 (as amended on June 7, 2019, the “Magnum Purchase Agreement”), the Company acquired all of the equity interests of Magnum Oil Tools International, LTD, Magnum Oil Tools GP, LLC, and Magnum Oil Tools Canada Ltd. (such entities collectively, “Magnum” and such acquisition, the “Magnum Acquisition”) for approximately $334.5 million in upfront cash consideration, subject to customary adjustments, and 5.0 million shares of the Company’s common stock, which were issued to the sellers of Magnum in a private placement. The Magnum Purchase Agreement also includes the potential for additional future payments in cash of (i) up to 60% of net income (before interest, taxes, and certain gains or losses) for the “E-Set” tools business in 2019 through 2026 and (ii) up to $25.0 million based on sales of certain dissolvable plug products in 2019. For additional information on the Magnum Acquisition, see Note 3 – Divestitures, Acquisitions, and Combinations . 
+Initial Public Offering 
+In January 2018, the Company completed its initial public offering (“IPO”) of 8,050,000 shares of common stock (including 1,050,000 shares pursuant to an over-allotment option) at a price to the public of $23.00 per share pursuant to a registration statement on Form S-1 (File 333-217601), as amended and declared effective by the Securities and Exchange Commission on January 18, 2018. 
+Beckman Combination 
+On February 28, 2017, pursuant to the terms and conditions of a combination agreement dated February 3, 2017, the Company merged with Beckman Production Services, Inc. (“Beckman”), and all of the issued and outstanding shares of Beckman common stock were converted into shares of common stock of Nine Energy Service, Inc. (the “Beckman Combination”). Prior to the Beckman Combination, SCF-VII, L.P. had controlled a majority of the voting interests of Nine and Beckman since February 28, 2011 and July 31, 2012, respectively. The merger of the entities into the combined company was accounted for using reorganization accounting (i.e., “as if” pooling of interest) for entities under common control. For additional information on the Beckman Combination, see Note 3 – Divestitures, Acquisitions, and Combinations . 
+F-6 
+2. Significant Accounting Policies 
+Basis of Presentation 
+The accompanying consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). 
+Principles of Consolidation 
+The consolidated financial statements as of December 31, 2019 and 2018 , and for the years ended December 31, 2019 , 2018 , and 2017 , include the accounts of Nine and Beckman and their wholly owned subsidiaries. For additional information on the history of Nine, see Note 1 – Company and Organization . All inter-company balances and transactions have been eliminated in the consolidation. 
+Use of Estimates 
+The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. These estimates are based on management’s best knowledge of current events and actions that the Company may undertake in the future. Such estimates include fair value assumptions used in purchase accounting and in analyzing goodwill, definite and indefinite-lived intangible assets, and property and equipment for possible impairment, useful lives used in depreciation and amortization expense, stock-based compensation fair value, estimated realizable value on excess and obsolete inventories, deferred taxes and income tax contingencies, and losses on accounts receivable. It is at least reasonably possible that the estimates used will change within the next year. 
+Reclassifications 
+Certain reclassifications have been made to prior period amounts to conform to the current period financial statement presentation. These reclassifications primarily relate to presenting “(Gain) loss on revaluation of contingent liabilities” and “Interest income” as separate line items in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss) . 
+Revenue Recognition 
+For information regarding the Company’s revenue, see Note 4 – Revenue . 
+Cash and Cash Equivalents 
+The Company considers all highly liquid debt instruments with a maturity of three months or less when purchased to be cash equivalents. Throughout the year, the Company maintained cash balances that were in excess of their federally insured limits. The Company has not experienced any losses in such accounts. 
+Cash flows from the Company’s Canadian subsidiary are calculated based on its functional currency. As a result, amounts related to changes in assets and liabilities reported in the Company’s Consolidated Statements of Cash Flows will not necessarily agree to changes in the corresponding balances in the Company’s Consolidated Balance Sheets . 
+Foreign Currency 
+The Company’s functional currency is the U.S. Dollar (“USD”). The financial position and results of operations of the Company’s Canadian subsidiary are measured using the local currency as the functional currency. Revenues and expenses of the subsidiary have been translated into USD at average exchange rates prevailing during the period. Assets and liabilities have been translated at the rates of exchange on the date of the Company’s Consolidated Balance Sheets . The resulting translation gain and loss adjustments have been recorded as a separate component of other comprehensive income (loss) in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss) and its Consolidated Statements of Changes in Stockholders’ Equity. 
+Accounts Receivable 
+The Company extends credit to customers in the normal course of business. Accounts receivable are carried at their estimated collectible amount. Trade credit is generally extended on a short-term basis; thus, receivables do not bear interest, 
+F-7 
+although a finance charge may be applied to amounts past due. The Company maintains an allowance for doubtful accounts for estimated losses that may result from the inability of its customers to make required payments. Such allowances are based upon several factors including, but not limited to, credit approval practices, industry and customer historical experience, as well as the current and projected financial condition of the specific customer. Accounts receivable outstanding longer than contractual terms are considered past due. The Company writes off accounts receivable to the allowance for doubtful accounts when they become uncollectible. Any payments subsequently received on receivables previously written off are credited to bad debt expense. 
+The Company had $96.9 million and $154.8 million of “Accounts receivable, net” at December 31, 2019 and 2018 , respectively. The Company maintains an allowance for doubtful accounts based on the expected collectability of accounts receivable, which is included in “Accounts receivable, net” on the Company’s Consolidated Balance Sheets . The Company had an allowance for doubtful accounts of $0.8 million and $0.5 million at December 31, 2019 and 2018 , respectively. Bad debt expense was $0.8 million for the year ended December 31, 2019 , while bad debt expense recoveries was $0.3 million for the year ended December 31, 2018 . Bad debt expense was $0.2 million for the year ended December 31, 2017 . 
+Concentration of Credit Risk 
+The Company derives a significant portion of its revenues from companies in the exploration and production (“E&P”) industry, and its customer base includes a broad range of integrated and independent domestic E&P companies and international E&P companies operating in the markets that the Company serves. While current energy prices are important contributors to positive cash flow for the customers, expectations about future prices and price volatility are generally more important for determining future spending levels. Any prolonged increase or decrease in oil and natural gas prices affects the levels of exploration, development, and production activity as well as the entire health of the oil and natural gas industry and can therefore negatively impact spending by the Company’s customers. No customer accounted for more than 10% of revenues for the years ended December 31, 2019 , 2018 , and 2017 . 
+Concentration of Supplier Risk 
+Purchases during the year ended December 31, 2019 did not include purchases from any supplier that individually represented more than 10% of total operating purchases, whereas the years ended December 31, 2018 and 2017 included purchases from one supplier that individually represented more than 10% of total operating purchases. The accounts payable to this vendor totaled 15% of total accounts payable at December 31, 2018 . 
+Property and Equipment 
+Property and equipment is stated at cost and depreciated under the straight-line method over the estimated useful lives of the assets. Equipment held under capital leases is stated at the present value of its future minimum lease payments and is depreciated under the straight-line method over the shorter of the lease term or the estimated useful life of the asset. When assets are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is recognized within operating expenses. Normal repair and maintenance costs are charged to operating expense as incurred. Significant renewals and betterments are capitalized. 
+Valuation of Long-Lived Assets 
+Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. In performing the review for impairment, future cash flows expected to result from the use of the asset and its eventual disposal are estimated. If the undiscounted future cash flows are less than the carrying amount of the assets, there is an indication that the asset may be impaired. The amount of the impairment is measured as the difference between the carrying value and the Level 3 fair value of the asset. The Level 3 fair value is determined either through the use of an external valuation, or by means of an analysis of discounted future cash flows based on expected utilization. Determining fair value requires the use of estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating profit margins, weighted average costs of capital, terminal growth rates, future market share, the impact of new product development, and future market conditions, among others. The Company believes that the estimates and assumptions used in impairment assessments are reasonable and appropriate. Impairment losses are reflected in “Income (loss) from operations” in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss) . 
+In the fourth quarter of 2019, the Company recorded a property and equipment impairment charge of $66.2 million and a definite-lived customer relationship intangible asset impairment charge of $7.1 million . These impairment charges represent the difference between the carrying value and the estimated fair value of the long-lived assets in the Company’s coiled tubing asset group within its Completion Solutions segment and were due to a reduction of the need for coiled tubing 
+F-8 
+during the drill-out phase of the overall completions process due to a recent decline in exploration and production capital budgets and activity, an over-supply of new coiled tubing units, and the introduction of dissolvable plug technology. 
+In the fourth quarter of 2018, the Company recorded a property and equipment impairment charge of $45.7 million and a definite-lived customer relationship intangible asset impairment charge of $9.8 million . These impairment charges represent the difference between the carrying value and the estimated fair value of the long-lived assets associated with the Company’s Production Solutions segment and were due to deteriorating conditions attributed to depressed commodity prices towards the end of the fourth quarter of 2018, coupled with customers focusing more on the completions business where there is more technological differentiation and value. On August 30, 2019, the Company sold its Production Solutions segment to Brigade. 
+For additional information on these impairment charges, see Note 6 – Property and Equipment . 
+For additional information on the Production Solutions divestiture, see Note 3 – Divestitures, Acquisitions, and Combinations . 
+Valuation of Goodwill and Intangible Assets 
+Goodwill has an indefinite useful life and is not subject to amortization. Intangible assets with indefinite useful lives (specifically trademarks and trade names) are also not subject to amortization. For goodwill and intangible assets with indefinite useful lives, an assessment for impairment is performed annually on December 31 or when there is an indication an impairment may have occurred. Goodwill is reviewed for impairment by comparing the carrying value of each of the Company’s reporting unit’s net assets (including allocated goodwill) to the Level 3 fair value of the reporting unit. The Level 3 fair value of the reporting unit is determined by using the income approach (discounted cash flows of forecasted income). Intangible assets with indefinite useful lives are reviewed for impairment by comparing the carrying value of the intangible asset to the Level 3 fair value of the intangible asset. The Level 3 fair value of intangible assets with indefinite useful lives (specifically trademarks and trade names) is estimated using the relief-from-royalty method of the income approach. This approach is based on the assumption that in lieu of ownership, a company would be willing to pay a royalty in order to exploit the related benefits of this intangible asset. Determining fair value requires the use of estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating profit margins, royalty rates, weighted average costs of capital, terminal growth rates, future market share, the impact of new product development, and future market conditions, among others. The Company believe that the estimates and assumptions used in impairment assessments are reasonable and appropriate. The Company recognizes a goodwill impairment charge for the amount by which the carrying value of goodwill exceeds the reporting unit’s Level 3 fair value. The Company recognizes an indefinite-lived intangible asset impairment charge of the amount by which the carrying value of the intangible asset exceeds the Level 3 fair value of the intangible asset. Any impairment losses are reflected in “Income (loss) from operations” in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss) . 
+Intangible assets with definite lives include technology, customer relationships, and non-compete agreements. The Level 3 fair value of technology and the Level 3 fair value of customer relationships are estimated using the income approach, specifically the multi-period excess earnings method. The multi-period excess earnings method consists of isolating the cash flows attributed to the intangible asset, which are then discounted to present value to calculate the Level 3 fair value of the intangible asset. The Level 3 fair value of non-compete agreements is estimated using a with and without scenario where cash flows are projected through the term of the non-compete agreement assuming the non-compete agreement is in place and compared to cash flows assuming the non-compete agreement is not in place. 
+Intangible assets with definite lives are amortized based on the estimated consumption of the economic benefit over their estimated useful lives. Intangible assets with definite lives are tested for impairment whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. 
+In the fourth quarter of 2019, in connection with its annual goodwill impairment test, the Company recorded a goodwill impairment charge of $20.3 million in its coiled tubing reporting unit within its Completion Solutions segment. In addition, in the fourth quarter of 2019, in connection with its annual indefinite-lived intangible asset impairment test, the Company recorded an intangible asset impairment charge of $12.7 million associated with the indefinite-lived trade names in its coiled tubing reporting unit and an intangible asset impairment charge of $95.0 million associated with the indefinite-lived trade names in its completion tools reporting unit, both within its Completion Solutions segment. As described above in “Valuation of Long-Lived Assets” and also in the fourth quarter of 2019, the Company recorded an intangible asset impairment charge of $7.1 million associated with the definite-lived customer relationship intangible assets in its coiled tubing asset group within its Completion Solutions segment. 
+F-9 
+In the fourth quarter of 2018, in connection with its annual goodwill impairment test, the Company recorded a goodwill impairment charge of $13.0 million , which represented a full write-off of goodwill attributed to its Production Solutions segment. In addition, in the fourth quarter of 2018, in connection with its annual indefinite-lived intangible asset impairment test, the Company recorded an intangible asset impairment charge of $9.3 million associated with indefinite-lived trade names in its Production Solutions segment. As described above in “Valuation of Long-Lived Assets” and also in the fourth quarter of 2018, the Company recorded an intangible asset impairment charge of $9.8 million related to definite-lived customer relationship intangible assets associated with its Production Solutions segment. On August 30, 2019, the Company sold its Production Solutions segment to Brigade. For additional information on the Production Solutions divestiture, see Note 3 – Divestitures, Acquisitions, and Combinations . 
+In the fourth quarter of 2017, in connection with its annual goodwill impairment test, the Company recorded a goodwill impairment charge of $31.5 million associated with one reporting unit in its Completion Solutions segment. In the fourth quarter of 2017, the Company also recorded an intangible asset impairment charge of $3.8 million related to definite-lived customer relationship intangible assets associated with one asset group in its Completion Solutions segment. 
+For additional information on goodwill and both indefinite-lived and definite-lived intangible asset impairment charges, see Note 7 – Goodwill and Intangible Assets . 
+Equity 
+In January 2018, there was an 8.0256 for 1 stock split immediately preceding the IPO. All shares and per share data reflect the effect of the stock split. 
+Stock-based Compensation 
+The Company has stock-based compensation plans for certain of its employees. The Company measures employee stock-based compensation awards at fair value on the date they are granted to employees and recognizes compensation cost in its financial statements over the requisite service period. As a result of the adoption of Accounting Standards Update (“ASU”) No. 2016-09, the Company elected to account for stock-based compensation forfeitures as they occur. 
+Restricted Stock and Restricted Stock Units 
+Compensation expense is recorded for restricted stock and restricted stock units over the applicable vesting period based on the Company’s closing stock price as of the grant date. 
+Performance Units 
+Performance stock units are recorded at their fair value and expensed over their performance period. Fair value for performance stock units is measured using a Monte Carlo simulation model. 
+Options 
+Options are issued with an exercise price equal to the fair value of the stock on the date of grant. Compensation expense is recorded for the fair value of the stock options and is recognized over the period of the underlying security’s vesting schedule. Consideration paid on the exercise of stock options is credited to share capital and additional paid-in capital. For options, fair value of the stock-based compensation is measured by use of the Black-Scholes pricing model. The following discusses the assumptions used related to the Black-Scholes pricing model. 
+• 
+The expected term of stock options represents the period the stock options are expected to remain outstanding and is based on the simplified method, which is the weighted average vesting term plus the original contractual term, divided by two. 
+• 
+Expected volatility measures the amount that a stock price has fluctuated or is expected to fluctuate during a period. Prior to the Company’s IPO, when its stock was not publicly traded, the Company determined volatility based on an analysis of the PHLX Oil Service Index that tracks publicly traded oilfield service stocks. Subsequent to the IPO and as a publicly traded company, the Company developed its expected volatility based upon a weighted average volatility of its peer group. 
+• 
+At the time of the issuance of the options, the Company did not plan to pay cash dividends in the foreseeable future. Therefore, a zero expected dividend yield was used in the valuation model. 
+F-10 
+• 
+The risk-free interest rate is based on U.S. Treasury zero-coupon issues with remaining terms similar to the expected term on the options. 
+Prior to the Company’s IPO, the value of the Company’s stock at the time of each option grant used to establish the strike price was estimated by management in accordance with an internal valuation model and approved by the Company’s Board of Directors. The valuation model was based upon an average of cash flow and book value multiples of comparable companies. The comparable companies selected reflect the market’s view on key sector, geographic, and product type exposure that are similar to those that impact the Company’s business. The value was further subject to judgmental factors such as prevailing market conditions, changes in the stock prices of other oilfield service companies, and the overall outlook for the Company and its products in general. 
+Income Taxes 
+The Company accounts for income taxes under Accounting Standards Codification (“ASC”) 740. Under this method, deferred income tax assets and liabilities are determined based upon temporary differences between the carrying amounts and tax bases of the Company’s assets and liabilities at the balance sheet date and are measured using enacted tax rates and laws that will be in effect when the differences are expected to reverse. The effect on deferred tax assets and liabilities of a change in the tax rates is recognized in income in the period in which the change occurs. The Company records a valuation reserve in each reporting period when management believes that it is more likely than not that any deferred tax asset created will not be realized. 
+The Company recognizes the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. If a tax position meets the “more likely than not” recognition criteria, the tax position is measured at the largest amount of benefit greater than 50% likely of being realized upon ultimate settlement. 
+Fair Value of Financial Instruments 
+The carrying amounts for financial instruments classified as current assets and current liabilities approximate fair value, due to the short maturity of such instruments. 
+For financial assets and liabilities disclosed at fair value, fair value is determined as the exit price, or the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The established fair value hierarchy divides fair value measurement into three levels: 
+• Level 1 – inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date; 
+• Level 2 – inputs other than quoted prices included within Level 1 that are observable for the assets or liability, either directly or indirectly; and 
+• Level 3 – inputs are unobservable for the asset or liability, which reflect the best judgment of management. 
+Financial assets and liabilities that are disclosed at fair value are categorized in one of the above three levels based on the lowest level input that is significant to the fair value measurement in its entirety. Level 1 provides the most reliable measure of fair value, whereas Level 3 generally requires significant management judgment. 
+The fair value of the Company’s debt obligations is classified as Level 2 in the fair value hierarchy and is established based on observable inputs in less active markets. For additional information on the fair value of the Company’s debt obligations, see Note 9 – Debt Obligations . 
+The fair value of the Company’s contingent consideration is classified as Level 3 in the fair value hierarchy and is established on unobservable markets which reflect the best judgment of management. For additional information on the fair value of the Company’s contingent consideration, see Note 3 – Divestitures, Acquisitions, and Combinations and Note 12 – Commitments and Contingencies . 
+Earnings (Loss) Per Share 
+Basic earnings (loss) per share is calculated by dividing net income (loss) by the weighted average number of common shares outstanding during the period. Diluted earnings (loss) per share is calculated by dividing net income (loss) by the weighted average number of common shares outstanding during the period, taking into effect, if any, the exercise of potentially 
+F-11 
+dilutive stock options assumed to be purchased from the proceeds using the average market price of the Company’s stock for each of the periods presented as well as potentially dilutive restricted stock, restricted stock units, and performance stock units. There was no dilutive effect for the year ended December 31, 2019 , 2018 , or 2017 as the Company was in a net loss position for those years. For additional information on earnings (loss) per share, see Note 14 – Earnings (Loss) Per Share . 
+Accounting Pronouncements Recently Adopted – Revenue Recognition 
+In May 2014, the Financial Accounting Standards Board (the “FASB”) issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) , a comprehensive revenue recognition standard that supersedes nearly all pre-exiting revenue recognition guidance, including the current revenue recognition requirements in Revenue Recognition (Topic 605) . The standard and its related amendments, collectively referred to as ASC 606, outlines a single comprehensive model for revenue based on the core principle that an entity recognizes revenue when promised goods or services are transferred to customers in an amount reflecting the consideration to which an entity expects to be entitled in exchange for those goods and services. 
+The Company adopted ASC 606 on December 31, 2019, effective January 1, 2019, using the modified retrospective method. For additional information about the Company’s adoption of ASC 606, see Note 4 – Revenue . 
+Accounting Pronouncements Recently Adopted – Other 
+In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments . This guidance addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice, including: debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows and application of the predominance principle. ASU 2016-15 was effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. As an emerging growth company, the Company was permitted to adopt, and therefore adopted, the standard for the fiscal years beginning after December 15, 2018 and the interim periods within fiscal years beginning after December 15, 2019. The adoption of the standard did not impact the Company’s Consolidated Statements of Cash Flows . 
+In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business , in an effort to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments in this standard provide a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the integrated set of assets and activities is not a business. Although the standard was generally effective for fiscal years beginning after December 15, 2017, the Company, as an emerging growth company, was permitted to adopt, and therefore has adopted, the standard for the fiscal years beginning after December 15, 2018 and the interim periods within annual periods beginning after December 15, 2019. Entities are required to apply the guidance prospectively when adopted and therefore, there was no impact on its consolidated financial statements. 
+Accounting Pronouncements Not Yet Adopted 
+In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The standard, which requires the use of a modified retrospective transition approach, includes a number of optional practical expedients that entities may elect to apply. In July 2018, the FASB issued a new, optional transition method that will give companies the option to use the effective date as the date of initial application on transition. Based on initial evaluation, the Company expects to include operating leases with durations greater than twelve months on its Consolidated Balance Sheets . The Company is currently in the process of accumulating and evaluating all the necessary information required to properly account for its lease portfolio under the new standard. The Company will provide additional information about the expected financial impact as it progresses through the evaluation and implementation of the standard. The standard is effective for public business entities for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, and it has recently been updated to extend the application for all other entities to the fiscal years beginning after December 15, 2020 and the interim periods within the fiscal years beginning after December 15, 2021. Early application in allowed, and the Company, as an emerging growth company, plans to adopt the standard for the fiscal years beginning after December 15, 2019 and the interim periods within the fiscal years beginning after December 15, 2020. 
+In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework – 
+F-12 
+Changes to the Disclosure Requirements for Fair Value Measurement , which eliminates, adds, and modifies certain disclosure requirements for fair value measurements as part of its disclosure framework project. The ASU is effective for all entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. The ASU is required to be applied retrospectively, except the new Level 3 disclosure requirements are applied prospectively. The Company is currently evaluating the impact of the standard on its consolidated financial statements. 
+In August 2018, the FASB issued ASU No. 2018-15, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract . ASU No. 2018-15 provides additional guidance on the accounting for costs of implementation activities performed in a cloud computing arrangement that is a service contract. The amendments in ASU No. 2018-15 align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal-use software license). Costs for implementation activities in the application development stage are capitalized depending on the nature of the costs, while costs incurred during the preliminary project and post implementation stages are expensed as the activities are performed. ASU 2018-15 is effective for public businesses for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. As an emerging growth company, the Company is permitted, and plans, to adopt the new standard for the annual reporting periods beginning after December 15, 2020 and the interim periods within annual periods beginning after December 15, 2021. The Company is currently evaluating the impact of the standard on its consolidated financial statements. 
+3. Divestitures, Acquisitions, and Combinations 
+Production Solutions Divestiture 
+On August 30, 2019 (the “ Production Solutions Divestiture Date”), the Company entered into the Production Solutions Purchase Agreement with Brigade. Pursuant to the Production Solutions Purchase Agreement, on such date, through the sale of all of the limited liability interests of its wholly owned subsidiary, Beckman Holding Production Services, LLC, the Company sold its Production Solutions segment to Brigade for approximately $17.1 million in cash. The Production Solutions Purchase Agreement contains customary representations and warranties, covenants, and indemnification provisions. In connection with this divestiture, the Company recorded a loss of $15.9 million during the year ended December 31, 2019. This divestiture did not qualify as discontinued operations in accordance with ASU 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity as it did not represent a strategic shift that has a major effect on the Company’s operations and financial results. 
+Magnum Acquisition 
+On October 25, 2018 (the “Magnum Closing Date”), pursuant to the terms of the Magnum Purchase Agreement, the Company acquired all of the equity interests of Magnum for approximately $334.5 million in upfront cash consideration, subject to customary adjustments, and 5.0 million shares of the Company’s common stock, which were issued to the sellers of Magnum in a private placement. The Magnum Purchase Agreement also includes the potential for additional future payments in cash of (i) up to 60% of net income (before interest, taxes, and certain gains or losses) for the “E-Set” tools business in 2019 through 2026 and (ii) up to $25.0 million based on sales of certain dissolvable plug products in 2019 (the “Magnum Earnout”). 
+The Magnum Acquisition has been accounted for as a business combination using the acquisition method. Under the acquisition method of accounting, the fair value of the consideration transferred was allocated to the tangible and intangible assets acquired and the liabilities assumed based on their estimated fair values as of the acquisition date, with the remaining unallocated amount recorded as goodwill. 
+F-13 
+The following table summarizes the fair value of purchase consideration transferred on the Magnum Closing Date: 
+Fair Value 
+(in thousands) 
+Proceeds from newly issued Senior Notes and 2018 ABL Credit Facility (1) 
+$ 
+296,622 
+Cash provided from operations 
+57,740 
+Total upfront cash consideration 
+$ 
+354,362 
+Issuance of the Company’s common shares 
+177,350 
+Contingent consideration (2) 
+23,029 
+Total purchase consideration 
+$ 
+554,741 
+(1) Senior Notes and 2018 ABL Credit Facility are defined in Note 9 – Debt Obligations . 
+(2) The estimated fair value of the Magnum Earnout was based on a Monte Carlo simulation model with estimated outcomes ranging from $0 to $25.0 million . The estimated fair value of the Magnum Earnout was based upon available information and certain assumptions, known at the time of the Magnum Closing Date, which management believed were reasonable. Any difference in the actual Magnum Earnout from the estimated fair value of the Magnum Earnout is recorded in “Income (loss) from operations” in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss) . 
+The following table summarizes the allocation of the purchase price of the Magnum Acquisition to the assets acquired and liabilities assumed based on the fair value as of the Magnum Closing Date, with the excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill: 
+Purchase Price Allocation 
+(in thousands) 
+Cash and cash equivalents 
+$ 
+8,509 
+Accounts receivable, net 
+30,898 
+Income taxes receivable 
+695 
+Inventories, net 
+52,249 
+Prepaid expenses and other current assets 
+1,147 
+Property and equipment, net 
+3,729 
+Goodwill 
+234,504 
+Definite-lived intangible, assets 
+148,000 
+Indefinite-lived intangible assets, net 
+96,000 
+Other long-term assets 
+1,055 
+Accounts payable 
+(3,626 
+) 
+Accrued expenses 
+(18,404 
+) 
+Other long-term liabilities 
+(15 
+) 
+Total net assets acquired 
+$ 
+554,741 
+All goodwill acquired is attributable to expected synergies gained through the Magnum Acquisition as well as the assembled workforce. In addition, all goodwill acquired is included in the Completion Solutions segment and is deductible for tax purposes. For additional information on goodwill, see Note 7 – Goodwill and Intangible Assets . 
+F-14 
+A portion of the fair value consideration transferred has been assigned to identifiable intangible assets as follows: 
+Customer Relationships 
+Non-Compete Agreements 
+Technology 
+Definite-Lived Intangible Assets Total 
+Trade Names 
+Other Intangible Assets 
+Indefinite-Lived Intangible Assets Total 
+(in thousands, except weighted average useful life information) 
+Fair value 
+$25,000 
+$3,000 
+$120,000 
+$148,000 
+$95,000 
+$1,000 
+$96,000 
+Weighted average useful life 
+9.0 
+2.1 
+15.0 
+Indefinite 
+Indefinite 
+Pro Forma 
+Magnum’s results of operations are included in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss) , as part of its Completion Solutions segment, for the year ended December 31, 2019 and 2018 . It is impractical to quantify the contribution of Magnum since the Magnum Closing Date, as the business was fully integrated into the Company’s existing operations in 2018. 
+The following unaudited pro forma condensed combined financial information was derived from the Company’s historical consolidated financial statements and Magnum’s historical combined financial statements, gives effect to the Magnum Acquisition as if it had occurred on January 1, 2017, and reflects pro forma adjustments based on available information and certain assumptions the Company believes are reasonable. These pro forma adjustments include the following: 
+• 
+The pro forma impact of the amortization of intangible assets and depreciation of property, plant, and equipment based on the estimated fair values of the identifiable assets; 
+• 
+The pro forma impact of the elimination of sales commissions due from or paid by Magnum to an intercompany entity that was not included in the Magnum Acquisition; 
+• 
+The pro forma impact of the elimination of insurance premiums paid by Magnum to a captive insurance entity under common ownership that was not included in the Magnum Acquisition, for additional insurance coverage that was not replaced subsequent to the close of the transaction; 
+• 
+The pro forma impact of interest expense related to the Magnum Acquisition; 
+• 
+The tax benefit of the aforementioned pro forma adjustments; and 
+• 
+The pro forma impact to weighted average shares outstanding to reflect the issuance of 5.0 million shares to the sellers of Magnum as of the beginning of the period presented. 
+The unaudited pro forma condensed combined financial information is presented for illustrative purposes only and is not necessarily indicative of the financial position that would have existed or the financial results that would have occurred if the Magnum Acquisition had been consummated on January 1, 2017, nor is it necessarily indicative of the Company’s future financial position, or operating results. Further, the unaudited pro forma condensed combined financial information does not reflect the realization of any expected cost savings or other synergies from the Magnum Acquisition as a result of restructuring activities and other planned costs savings initiatives following the completion of the Magnum Acquisition. 
+The following table summarizes selected unaudited financial information of the Company on a pro forma basis: 
+2018 
+2017 
+(in thousands, except per share amounts) 
+Revenues 
+$ 
+948,282 
+$ 
+633,248 
+Net loss 
+$ 
+(55,447 
+) 
+$ 
+(78,993 
+) 
+Loss per share 
+Basic 
+$ 
+(1.89 
+) 
+$ 
+(3.97 
+) 
+Diluted 
+$ 
+(1.89 
+) 
+$ 
+(3.97 
+) 
+F-15 
+Frac Tech Acquisition 
+On October 1, 2018, pursuant to the terms and conditions of a Securities Purchase Agreement (the “Frac Tech Purchase Agreement”), the Company acquired Frac Technology AS, a Norwegian private limited company (“Frac Tech”) focused on the development of downhole technology, including a casing flotation tool and a number of patented downhole completion tools. This acquisition was not material to the Company’s consolidated financial statements. 
+Beckman Combination 
+On February 28, 2017 , pursuant to the terms and conditions of a combination agreement dated February 3, 2017 , the Company merged with Beckman and all of the issued and outstanding shares of Beckman common stock were converted into shares of common stock of Nine Energy Service, Inc. at a ratio of 0.567154 Nine shares per Beckman share, other than 1.6% of Beckman shares paid in cash. Prior to the Beckman Combination, SCF-VII, L.P. had controlled a majority of the voting interests of Nine and Beckman since February 28, 2011 and July 31, 2012 , respectively. The merger of the entities into the combined company was accounted for using reorganization accounting (i.e., “as if” pooling of interest) for entities under common control. 
+In conjunction with the Beckman Combination, in addition to the conversion of Beckman shares into Nine shares, other events occurred, including: 
+• 
+The conversion of Beckman shares owned by non-accredited shareholders of Beckman at the time of the Beckman Combination into cash at a price of $17.69 per Beckman share; 
+• 
+Payment of cash for Beckman shares that converted into fractional Nine shares at the price of $31.18 per Nine share; 
+• 
+The conversion of options to purchase Beckman common stock into options to purchase Nine common stock; 
+• 
+The conversion of Beckman restricted shares into Nine restricted shares; 
+• 
+The conversion of warrants to purchase Beckman common stock into warrants to purchase Nine common stock; 
+• 
+The issuance of options to purchase Nine common stock; 
+• 
+The issuance, on a pro-rata basis, to the Company’s shareholders of Nine common stock based on a subscription amount equal to the number of common shares issued at a price of $31.18 . The subscription was offered to all shareholders of record at the time of the Beckman Combination. Any unsubscribed shares were reallocated among the shareholders; and 
+• 
+The issuance to the Company’s shareholders of Nine warrants equal to one half of the amount of shares issued related to the subscription described above. 
+4. Revenue 
+Adoption of ASC Topic 606 
+The Company adopted ASC 606 on December 31, 2019 , effective January 1, 2019 , using the modified retrospective method in which the standard has been applied to all contracts which were not completed as of the date of initial application. Accordingly, results for the year ended December 31, 2019 are presented in accordance with ASC 606 while prior period results, including those presented in the previous quarters of 2019, have not been adjusted and continue to be reported under the previous revenue recognition guidance. As a practical expedient, the Company has not restated completed contracts that begin and end in the same annual reporting period. No adjustment to the beginning 2019 retained earnings was required as a result of the Company’s adoption of ASC 606, and no adjustment was recorded during the year. 
+Under ASC 606, the Company recognizes revenue similarly to how it recognized revenue in accordance with ASC 605, except for revenue from international sales of completion tools. Prior to the adoption of ASC 606, the Company recognized revenue when products were received by a customer’s domestic common carrier at the Company’s facility. Upon adoption of ASC 606, the Company now recognizes revenue when the product is received by the customer’s international carrier. The Company believes this change better reflects the point at which the customer has control of the product as required by ASC 606. The adoption of ASC 606 did not have a material impact on the Company’s consolidated financial statements. 
+F-16 
+Performance Obligations 
+A performance obligation is a promise in a contract to transfer a distinct good or service to the customer and is the unit of account in ASC 606. A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue when, or as, the performance obligation is satisfied. The Company excludes sales taxes, value added taxes, and other taxes it collects concurrent with revenue-producing activities from revenue. 
+The Company’s revenue is derived from the sale of products and services which are sold directly to customers or are consumed by customers on their well sites. For domestic product sales, the Company typically recognizes revenue when it meets its performance obligation upon the shipment of the products from its facilities to its customer. For international product sales, the Company typically recognizes revenue when it meets its performance obligation upon receipt of the products by the customer’s international carrier. The Company recognizes service revenue over the time the service is performed as the customer consumes and benefits from the use of the Company’s products and services for well service. Service revenues represent revenue recognized over time, as the Company’s customer arrangements typically provide agreed upon hourly or daily fixed-rates, and the Company recognizes service revenue based upon the number of hours or days services have been performed. At December 31, 2019 , the amount of remaining performance obligations was immaterial. 
+Contracts for the Company’s products and services are negotiated on a per-job basis at a regional level. Contracts vary in nature but typically have a duration of less than a month and have a single performance obligation either for a job, a series of distinct jobs, or a period the Company stands ready to provide its services to its client as needed. 
+The Company’s payment terms vary by the type and location of its customers and type of product and service offered. The Company receives cash equal to the invoice amount for most services and product sales, and payment terms typically range from 30 to 60 days from the date the Company invoices a customer. Since the period between the delivery of the Company’s products and services and the Company’s receipt of customer payment for these products and services is not expected to exceed one year, the Company has elected not to calculate or disclose a financing component for its customer contracts. 
+Contract Estimates 
+The Company receives reimbursements from its customers for the purchase of supplies, equipment, personnel services, and other services provided at a customer’s request. Reimbursable revenues are subject to uncertainty as the timing of the receipt of these amounts is dependent on factors outside of the Company’s influence. Accordingly, these revenues are not recognized until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of the customer. The Company is considered a principal in these transactions and records the associated revenues at the gross amount billed to the customer. 
+Changes and modifications to contracts are routine in the performance of the Company’s contracts due to the dynamic nature of well operations and the services the Company provides for its customers. The Company considers contract modifications to exist when the modification either creates a new contract or changes the existing enforceable rights and obligations of a contract. Most of the Company’s contract modifications are for services or goods that are not distinct from existing contracts due to the significant integration provided or significant interdependencies in the context of the contract and are accounted for as if they were part of the original contract. 
+Contract Balances 
+Any contract assets are included in “Accounts receivable, net” in the Company’s Consolidated Balance Sheets . Contract assets arise when recorded revenues for a contract exceed the amounts billed under the terms of the contracts. The Company classifies contract liabilities as unearned income which is included in “Accrued expenses” in the Company’s Consolidated Balance Sheets . Such deferred revenue typically results from advance payments received on well service orders prior to performance of the service. As of December 31, 2019 and 2018 , contract assets and contract liabilities were immaterial. 
+Disaggregation of Revenue 
+On August 30, 2019, also known as the Production Solutions Divestiture Date, the Company sold its Production Solutions segment to Brigade. Disaggregated revenue below for Production Solutions segment is provided through the Production Solutions Divestiture Date. For additional information on the Production Solutions divestiture, see Note 3 – Divestitures, Acquisitions, and Combinations . 
+F-17 
+The Company disaggregates revenue from contracts with customers by type of products or services as set forth in the tables below. 
+For the year ended December 31, 2019 
+Completion Solutions 
+Production Solutions 
+Total 
+(in thousands) 
+Coiled tubing 
+$ 
+134,543 
+$ 
+— 
+$ 
+134,543 
+Cement 
+217,893 
+— 
+217,893 
+Tools 
+186,429 
+— 
+186,429 
+Wireline 
+235,800 
+— 
+235,800 
+Well service 
+— 
+58,272 
+58,272 
+Total revenues 
+$ 
+774,665 
+$ 
+58,272 
+$ 
+832,937 
+For the year ended December 31, 2019 
+Completion Solutions 
+Production Solutions 
+Total 
+(in thousands) 
+Products (1) 
+$ 
+186,429 
+$ 
+— 
+$ 
+186,429 
+Services (1) 
+588,236 
+58,272 
+646,508 
+Total 
+$ 
+774,665 
+$ 
+58,272 
+$ 
+832,937 
+(1) The Company recognizes revenues from the sales of products at a point in time and revenues from the sales of services over time. 
+5. Inventories 
+Inventories, consisting primarily of finished goods and raw materials, are stated at the lower of cost or net realizable value. Cost is determined on an average cost basis. The Company reviews its inventory balances and writes down its inventory for estimated obsolescence or excess inventory equal to the difference between the cost of inventory and the estimated market value based upon assumptions about future demand and market conditions. The reserve for obsolescence was $5.4 million and $1.9 million at December 31, 2019 and 2018 , respectively. 
+Inventories, net as of December 31, 2019 and 2018 were comprised of the following: 
+December 31, 
+2019 
+2018 
+(in thousands) 
+Raw materials 
+$ 
+38,823 
+$ 
+38,890 
+Work in progress 
+— 
+130 
+Finished goods 
+27,555 
+54,301 
+Inventories 
+66,378 
+93,321 
+Reserve for obsolescence 
+(5,433 
+) 
+(1,886 
+) 
+Inventories, net 
+$ 
+60,945 
+$ 
+91,435 
+F-18 
+6. Property and Equipment 
+Property and equipment amounts as of December 31, 2019 and 2018 were as follows: 
+December 31, 
+Estimated 
+Useful Lives 
+2019 
+2018 
+(in thousands) 
+Operating equipment 
+1 to 12 years 
+$ 
+293,237 
+$ 
+394,881 
+Autos and trucks 
+1 to 7 years 
+15,053 
+30,770 
+Furniture, fixtures, and equipment 
+2 to 12 years 
+4,054 
+4,330 
+Shop equipment 
+3 to 15 years 
+16,144 
+17,300 
+Buildings 
+7 to 39 years 
+7,991 
+9,784 
+Leasehold improvements 
+3 to 11 years 
+1,653 
+1,488 
+Land 
+indefinite 
+791 
+1,618 
+338,923 
+460,171 
+Less: Accumulated depreciation 
+(210,319 
+) 
+(248,527 
+) 
+Property and equipment, net 
+$ 
+128,604 
+$ 
+211,644 
+Depreciation expense was $50.5 million , $54.3 million , and $53.4 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively. 
+2019 Property and Equipment Impairment 
+With a recent decline in exploration and production capital budgets and activity, coupled with an over-supply of new coiled tubing units, the demand for coiled tubing during the drill-out phase of the overall completions process diminished in the fourth quarter of 2019, shrinking the overall coiled tubing market. Additionally, in the fourth quarter of 2019, dissolvable plug technology became more widely adopted by operators, which significantly reduced and will potentially eliminate the need for coiled tubing drill-outs. This weakened market outlook indicated that the carrying amount of long-lived assets in the Company’s coiled tubing asset group within its Completion Solutions segment might not have been recoverable. As such, the Company performed an impairment assessment of all long-lived assets in its coiled tubing asset group within its Completion Solutions segment under ASC 360, Property, Plant and Equipment (“ASC 360”) at December 31, 2019. Based on this assessment, which was in consideration of its best internal projections, the Company determined that the carrying amount of long-lived assets in its coiled tubing reporting asset group within its Completion Solutions segment exceeded the estimated future undiscounted cash flows derived from its coiled tubing asset group’s long-lived assets. As such, the Company determined the fair value of the long-lived assets in its coiled tubing asset group within its Completion Solutions segment using the market approach (consideration of market sales values for similar assets). Based on its fair value determination, the Company recorded an impairment charge of $66.2 million related to property and equipment in its coiled tubing asset group within its Completion Solutions segment and an impairment charge of $7.1 million related to definite-lived customer relationship intangible assets in its coiled tubing asset group within its Completion Solutions segment. The property and equipment impairment charge is included in the line item “Impairment of property and equipment” in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss) for the year ended December 31, 2019, and the definite-lived intangible asset impairment charge is included in the line item “Impairment of intangibles” in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss) for the year ended December 31, 2019. The total impairment charge represents the difference between the carrying value and the estimated fair value of the long-lived assets in the Company’s coiled tubing asset group within its Completion Solutions segment and was allocated across the long-lived asset classifications in its coiled tubing asset group within its Completion Solutions segment. 
+2018 Property and Equipment Impairment 
+In the fourth quarter of 2018, market conditions in the Company’s Production Solutions segment began to deteriorate due to depressed commodity prices towards the end of the fourth quarter of 2018, coupled with customers focusing more on the completions business where there was more technological differentiation and value. This weakened market outlook indicated that the carrying amount of long-lived assets associated with the Company’s Production Solutions segment might not have been recoverable. As such, the Company performed an impairment assessment of all long-lived assets associated with its Production Solutions segment under ASC 360 at December 31, 2018. Based on this assessment, which was in consideration of its best internal projections, the Company determined that the carrying amount of long-lived assets associated with its Production 
+F-19 
+Solutions segment exceeded the estimated future undiscounted cash flows derived from the long-lived assets associated with the segment. As such, the Company determined the fair value of the long-lived assets associated with its Production Solutions segment using a combination of the income approach (discounted cash flows of forecasted income) and the market approach (consideration of market sales values for similar assets). Based on its fair value determination, the Company recorded an impairment charge of $45.7 million related to property and equipment associated with its Production Solutions segment and an impairment charge of $9.8 million related to definite-lived customer relationship intangible assets associated with its Production Solutions segment. The property and equipment impairment charge is included in the line item “Impairment of property and equipment” in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss) for the year ended December 31, 2018, and the definite-lived intangible asset impairment charge is included in the line item “Impairment of intangibles” in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss) for the year ended December 31, 2018. The total impairment charge represents the difference between the carrying value and the estimated fair value of the long-lived assets associated with its Production Solutions segment and was allocated across the long-lived asset classifications in the Production Solutions segment. 
+7. Goodwill and Intangible Assets 
+Goodwill 
+The changes in the net carrying amount of the components of goodwill for the years ended December 31, 2019 and 2018 were as follows: 
+Goodwill 
+Gross Value 
+Accumulated Impairment Loss 
+Net 
+(in thousands) 
+Balance as of December 31, 2017 
+$ 
+173,033 
+$ 
+(79,277 
+) 
+$ 
+93,756 
+Additions 
+227,034 
+— 
+227,034 
+Impairment 
+— 
+(12,986 
+) 
+(12,986 
+) 
+Balance as of December 31, 2018 
+$ 
+400,067 
+$ 
+(92,263 
+) 
+$ 
+307,804 
+Purchase price adjustments (1) 
+8,665 
+— 
+8,665 
+Impairment 
+— 
+(20,273 
+) 
+(20,273 
+) 
+Balance as of December 31, 2019 
+$ 
+408,732 
+$ 
+(112,536 
+) 
+$ 
+296,196 
+(1) The Company recorded adjustments to the fair value of goodwill in relation to the Magnum Acquisition. For additional information on the Magnum Acquisition and related purchase price adjustments, see Note 3 – Divestitures, Acquisitions, and Combinations . 
+Goodwill by segment for the years ended December 31, 2019 and 2018 was as follows: 
+Completion Solutions 
+Production Solutions 
+Total 
+(in thousands) 
+2019 
+2018 
+2019 
+2018 
+2019 
+2018 
+Balance as of January 1 
+$ 
+307,804 
+$ 
+80,770 
+$ 
+— 
+$ 
+12,986 
+$ 
+307,804 
+$ 
+93,756 
+Additions 
+— 
+227,034 
+— 
+— 
+— 
+227,034 
+Purchase price adjustments (1) 
+8,665 
+— 
+— 
+— 
+8,665 
+— 
+Impairment 
+(20,273 
+) 
+— 
+— 
+(12,986 
+) 
+(20,273 
+) 
+(12,986 
+) 
+Balance as of December 31 
+$ 
+296,196 
+$ 
+307,804 
+$ 
+— 
+$ 
+— 
+$ 
+296,196 
+$ 
+307,804 
+(1) The Company recorded adjustments to the fair value of goodwill in relation to the Magnum Acquisition. For additional information on the Magnum Acquisition and related purchase price adjustments, see Note 3 – Divestitures, Acquisitions, and Combinations . 
+The Company performs its annual goodwill impairment test on December 31 or when there is an indication an impairment may have occurred. Prior to 2017, Beckman performed its annual goodwill impairment test as of October 31. In the fourth quarter of 2017, the goodwill impairment test date for Beckman was changed to December 31 in order to align more closely with the Company’s planning and forecasting process. 
+F-20 
+2019 Goodwill Impairment 
+With a recent decline in exploration and production capital budgets and activity, coupled with an over-supply of new coiled tubing units, the demand for coiled tubing during the drill-out phase of the overall completions process diminished in the fourth quarter of 2019, shrinking the overall coiled tubing market. Additionally, in the fourth quarter of 2019, dissolvable plug technology became more widely adopted by operators, which significantly reduced and will potentially eliminate the need for coiled tubing drill-outs. As a consequence, the outlook for expected future cash flows in the Company’s coiled tubing reporting unit within its Completion Solutions segment reduced as the coiled tubing reporting unit’s carrying value exceeded its estimated Level 3 fair value. As such, in the fourth quarter of 2019, in connection with its annual goodwill impairment test, the Company recorded a goodwill impairment charge of $20.3 million , in its coiled tubing reporting unit within its Completion Solutions segment. This goodwill impairment charge is included in the line item “Impairment of goodwill” in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss) for the year ended December 31, 2019. 
+2018 Goodwill Impairment 
+In the fourth quarter of 2018, due to deteriorating market conditions in the Company’s Production Solutions segment attributed to depressed commodity prices towards the end of the fourth quarter of 2018, coupled with customers focusing more on the completions business where there is more technological differentiation and value, there was a reduction in the outlook for expected future cash flows in the segment and as a result, the segment’s carrying value exceeded its estimated Level 3 fair value. As such, in the fourth quarter of 2018, in connection with its annual goodwill impairment test, the Company recorded a goodwill impairment charge of $13.0 million , which represented a full write-off of goodwill attributed to its Production Solutions segment. This goodwill impairment charge is included in the line item “Impairment of goodwill” in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss) for the year ended December 31, 2018. 
+2017 Goodwill Impairment 
+In the fourth quarter of 2017, due to declining profitability and deteriorating market conditions, which included a shift from open hole completions to significantly less profitable cemented liners, there was a reduction in the outlook for expected future cash flows in one reporting unit in the Company’s Completion Solutions segment and as a result, the reporting unit’s carrying value exceeded its estimated Level 3 fair value. As such, in the fourth quarter of 2017, in connection with its annual goodwill impairment test, the Company recorded a goodwill impairment charge of $31.5 million associated with the reporting unit. This goodwill impairment charge is included in the line item “Impairment of goodwill” in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss) for the year ended December 31, 2017. 
+F-21 
+Intangible Assets 
+The changes in the net carrying amount of the components of intangible assets for the years ended December 31, 2019 and 2018 were as follows: 
+2019 
+Customer Relationships 
+Non-Compete Agreements 
+Technology 
+Definite-Lived Intangible Asset Total 
+Trade Names and Other 
+Indefinite-Lived Intangible Asset Total 
+(in thousands, except weighted average amortization period information) 
+Balance as of December 31, 2018 
+$ 
+47,964 
+$ 
+2,850 
+$ 
+122,637 
+$ 
+173,451 
+$ 
+108,711 
+$ 
+108,711 
+Amortization expense 
+(8,335 
+) 
+(1,316 
+) 
+(8,716 
+) 
+(18,367 
+) 
+— 
+— 
+Impairment 
+(7,093 
+) 
+— 
+— 
+(7,093 
+) 
+(107,711 
+) 
+(107,711 
+) 
+Balance as of December 31, 2019 
+$ 
+32,536 
+$ 
+1,534 
+$ 
+113,921 
+$ 
+147,991 
+$ 
+1,000 
+$ 
+1,000 
+Weighted average amortization period 
+6.0 
+3.8 
+13.6 
+Indefinite 
+2018 
+Customer Relationships 
+Non-Compete Agreements 
+Technology 
+Definite-Lived Intangible Asset Total 
+Trade Names and Other 
+Indefinite-Lived Intangible Asset Total 
+(in thousands, except weighted average amortization period information) 
+Balance as of December 31, 2017 
+$ 
+39,645 
+$ 
+725 
+$ 
+1,144 
+$ 
+41,514 
+$ 
+22,031 
+$ 
+22,031 
+Additions 
+25,000 
+3,000 
+123,240 
+151,240 
+96,000 
+96,000 
+Amortization expense 
+(6,962 
+) 
+(849 
+) 
+(1,747 
+) 
+(9,558 
+) 
+— 
+— 
+Impairment 
+(9,719 
+) 
+(26 
+) 
+— 
+(9,745 
+) 
+(9,320 
+) 
+(9,320 
+) 
+Balance as of December 31, 2018 
+$ 
+47,964 
+$ 
+2,850 
+$ 
+122,637 
+$ 
+173,451 
+$ 
+108,711 
+$ 
+108,711 
+Weighted average amortization period 
+7.3 
+3.5 
+14.6 
+Indefinite 
+2019 Indefinite-Lived Intangible Asset Impairment 
+With a recent decline in exploration and production capital budgets and activity, coupled with an over-supply of new coiled tubing units, the demand for coiled tubing during the drill-out phase of the overall completions process diminished in the fourth quarter of 2019, shrinking the overall coiled tubing market. Additionally, in the fourth quarter of 2019, dissolvable plug technology became more widely adopted by operators, which significantly reduced and will potentially eliminate the need for coiled tubing drill-outs. As a consequence, the outlook for expected future cash flows attributed to indefinite-lived trade names associated with the Company’s coiled tubing reporting unit within its Completion Solutions segment reduced as the trade names’ carrying value exceeded its estimated fair value. In addition, in the fourth quarter of 2019, the Company changed its marketing strategy and began the process of transitioning certain Magnum trade names to the Company’s trade names in order to better funnel and allocate resources, create a stronger identity, facilitate cross-selling, and streamline and simplify communication with existing customers. As a consequence, the outlook for expected future cash flows attributed to indefinite-lived trade names in the Company’s completion tools reporting unit within its Completion Solutions segment also reduced as the trade names’ carrying value exceeded its estimated fair value. As such, in the fourth quarter of 2019, in connection with its annual indefinite-lived intangible asset impairment test, the Company recorded an intangible asset impairment charge of $12.7 million associated with the indefinite-lived trade names associated in its coiled tubing reporting unit and an intangible asset impairment charge of $95.0 million associated with the indefinite-lived trade names in its completion tools reporting unit, both within its Completion Solutions segment. These indefinite-lived intangible asset impairment charges are included in the line item “Impairment of intangibles” in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss) for the year ended December 31, 2019. 
+2018 Indefinite-Lived Intangible Asset Impairment 
+In the fourth quarter of 2018, due to deteriorating market conditions in the Company’s Production Solutions segment attributed to depressed commodity prices towards the end of the fourth quarter of 2018, coupled with customers focusing more on the completions business where there is more technological differentiation and value, there was a reduction in the outlook for expected future cash flows attributed to indefinite-lived trade names associated with the segment, and as a result, the trade names’ carrying value exceeded its estimated fair value. As such, in the fourth quarter of 2018, in connection with its annual indefinite-lived intangible asset impairment test, the Company recorded an intangible asset impairment charge of $9.3 million 
+F-22 
+associated with the indefinite-lived trade names in its Production Solutions segment. This indefinite-lived intangible asset impairment charge is included in the line item “Impairment of intangibles” in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss) for the year ended December 31, 2018. 
+2019 Definite-Lived Intangible Asset Impairment 
+In the fourth quarter of 2019, the Company also recorded an impairment charge of $7.1 million related to definite-lived customer relationship intangible assets in its coiled tubing asset group within its Completion Solutions segment. This definite-lived intangible asset impairment charge is included in the line item “Impairment of intangibles” in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss) for the year ended December 31, 2019. For additional information on this definite-lived impairment charge, see Note 6 – Property and Equipment . 
+2018 Definite-Lived Intangible Asset Impairment 
+In the fourth quarter of 2018, the Company also recorded an impairment charge of $9.8 million related to definite-lived customer relationship intangible assets associated with its Production Solutions segment. This definite-lived intangible asset impairment charge is included in the line item “Impairment of intangibles” in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss) for the year ended December 31, 2018. For additional information on this definite-lived impairment charge, see Note 6 – Property and Equipment . 
+2017 Definite-Lived Intangible Asset Impairment 
+In the fourth quarter of 2017, completions methodology in the area of one of the Completion Solutions segment’s asset groups began to shift from open hole completions to significantly less profitable cemented liners, which resulted in declining revenue and profitability within the asset group. The Company determined that these factors indicated that the carrying amount of long-lived assets associated with the asset group might not be recoverable. As such, the Company performed an impairment assessment of all long-lived assets associated with the asset group under ASC 360 at December 31, 2017. Level 3 fair value of the long-lived assets associated with the asset group was determined by estimating the net present value of the future cash flows over the life of the long-lived assets. Using Level 3 inputs of the fair value hierarchy, critical assumptions for those valuations include estimated activity levels, revenue, and operating expenses. Based on this valuation, the Company recorded an impairment charge of $3.8 million related to definite-lived customer relationship intangible assets associated with this asset group. This definite-lived intangible asset impairment charge is included in the line item “Impairment of intangibles” in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss) for the year ended December 31, 2017. 
+Amortization of Intangibles 
+Amortization of intangibles was $18.4 million , $9.6 million , and $8.8 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively. 
+Future estimated amortization of intangibles is as follows: 
+Year Ending December 31, 
+(in thousands) 
+2020 
+$ 
+16,467 
+2021 
+16,116 
+2022 
+13,463 
+2023 
+11,516 
+2024 
+11,183 
+Thereafter 
+79,246 
+$ 
+147,991 
+F-23 
+8. Accrued Expenses 
+Accrued expenses as of December 31, 2019 and 2018 consisted of the following: 
+December 31, 
+2019 
+2018 
+(in thousands) 
+Accrued compensation and benefits 
+$ 
+7,009 
+$ 
+11,930 
+Accrued bonus 
+5,043 
+13,250 
+Sales tax payable 
+820 
+1,185 
+Contingent liabilities 
+391 
+20,922 
+Accrued interest 
+6,091 
+7,031 
+Other accrued expenses 
+5,376 
+7,116 
+Total accrued expenses 
+$ 
+24,730 
+$ 
+61,434 
+9. Debt Obligations 
+The Company’s debt obligations as of December 31, 2019 and 2018 were as follows: 
+December 31, 
+2019 
+2018 
+(in thousands) 
+Senior Notes 
+$ 
+400,000 
+$ 
+400,000 
+2018 ABL Credit Facility 
+— 
+35,000 
+2018 IPO Term Loan Credit Facility 
+— 
+— 
+Legacy Term Loans 
+— 
+— 
+Legacy Revolving Credit Facilities 
+— 
+— 
+Total debt before deferred financing costs 
+$ 
+400,000 
+$ 
+435,000 
+Deferred financing costs 
+(7,941 
+) 
+(10,022 
+) 
+Total debt 
+$ 
+392,059 
+$ 
+424,978 
+Less: Current portion of long-term debt 
+— 
+— 
+Long-term debt 
+$ 
+392,059 
+$ 
+424,978 
+Senior Notes 
+On October 25, 2018, the Company issued $400.0 million principal amount of 8.750% Senior Notes due 2023 (the “Senior Notes”). The Senior Notes were issued under an indenture, dated as of October 25, 2018 (the “Indenture”), by and among the Company, certain subsidiaries of the Company and Wells Fargo, National Association, as Trustee. The Senior Notes bear interest at an annual rate of 8.750% payable on May 1 and November 1 of each year with the first interest payment being due on May 1, 2019 . The Senior Notes are senior unsecured obligations of the Company and are fully and unconditionally guaranteed on a senior unsecured basis by each of the Company’s current domestic subsidiaries and by certain future subsidiaries. 
+F-24 
+At any time prior to November 1, 2020, the Company may, from time to time, redeem up to 35% of the aggregate principal amount of the Senior Notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a redemption price equal to 108.750% of the principal amount of the Senior Notes redeemed, plus accrued and unpaid interest, if any, to, but excluding the date of redemption, provided that at least 65% of the aggregate principal amount of the Senior Notes issued under the Indenture remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. Also, at any time prior to November 1, 2020, the Company may, on any one or more occasions, redeem all or a part of the Senior Notes at a redemption price equal to 100% of the principal amount of the Senior Notes redeemed, plus a “make-whole” premium plus accrued and unpaid interest, if any, to, but excluding, the date of redemption. On and after November 1, 2020, the Company may redeem the Senior Notes, in whole or in part, at the redemption prices (expressed as percentages of principal amount of the Senior Notes to be redeemed) set forth below, plus accrued and unpaid interest, if any, to, but excluding, the date of redemption if redeemed during the 12-month period beginning on November 1 of the years indicated below: 
+Year 
+Redemption Price 
+2020 
+104.375 
+% 
+2021 
+102.188 
+% 
+2022 and thereafter 
+100.000 
+% 
+If the Company experiences certain changes of control, each holder of Senior Notes may require the Company to repurchase all or a portion of its Senior Notes for cash at a price equal to 101% of the principal amount of such Senior Notes, plus any accrued but unpaid interest, if any, to, but excluding, the date of repurchase. 
+The Indenture contains covenants that, among other things and subject to certain exceptions and qualifications, limit the Company’s ability and the ability of its restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends or make other distributions or repurchase or redeem their capital stock; (iii) transfer or sell assets; (iv) make loans and investments; (v) incur liens; (vi) enter into agreements that restrict dividends or other payments from their non-guarantor restricted subsidiaries to them; (vii) consolidate, merge, or transfer all or substantially all of their assets; (viii) prepay, redeem, or repurchase certain debt; (ix) issue certain preferred stock or similar equity securities, (x) make certain acquisitions and investments; (xi) engage in transactions with affiliates; and (xii) create unrestricted subsidiaries. The Company was in compliance with the provisions of the Indenture at December 31, 2019 . 
+Upon an event of default, the trustee or the holders of at least 25% in aggregate principal amount of then outstanding Senior Notes may declare the Senior Notes immediately due and payable, except that a default resulting from certain events of bankruptcy or insolvency with respect to the Company, any restricted subsidiary of the Company that is a significant subsidiary or any group of restricted subsidiaries that, taken together, would constitute a significant subsidiary, will automatically cause all outstanding Senior Notes to become due and payable. 
+The proceeds from the Senior Notes, together with cash on hand and borrowings under the 2018 ABL Credit Facility (as defined and described below), were used to (i) fund a portion of the upfront cash purchase price of the Magnum Acquisition, (ii) repay all indebtedness under the 2018 IPO Credit Agreement (as defined and described below) and (iii) pay fees and expenses associated with the issuance of the Senior Notes, the Magnum Acquisition, and the 2018 ABL Credit Facility. 
+During the year ended December 31, 2018, the Company paid approximately $10.4 million of deferred financing costs in connection with the issuance of the Senior Notes. These costs are direct deductions from the carrying amount of the Senior Notes and are being amortized through interest expense through the maturity date of the Senior Notes using the effective interest method. The unamortized portion of these deferred financing costs was $7.9 million and $10.0 million at December 31, 2019 and 2018 , respectively. 
+2018 ABL Credit Facility 
+On October 25, 2018, the Company entered into a credit agreement dated as of October 25, 2018 (the “2018 ABL Credit Agreement”), by and among the Company, Nine Energy Canada, Inc., JP Morgan Chase Bank, N.A. (“JP Morgan”) as administrative agent and as an issuing lender, and certain other financial institutions party thereto as lenders and issuing lenders. The 2018 ABL Credit Agreement permits aggregate borrowings of up to $200.0 million , subject to a borrowing base, including a Canadian tranche with a sub-limit of up to $25.0 million and a sub-limit of $50.0 million for letters of credit (the “2018 ABL Credit Facility”). The 2018 ABL Credit Facility will mature on October 25, 2023 or, if earlier, on the date that is 180 days before the scheduled maturity date of the Senior Notes if they have not been redeemed or repurchased by such date. 
+Loans to the Company and its domestic related subsidiaries (the “U.S. Credit Parties”) under the 2018 ABL Credit 
+F-25 
+Facility may be base rate loans or London Interbank Offered Rate (“LIBOR”) loans; and loans to Nine Energy Canada Inc., a corporation organized under the laws of Alberta, Canada, and its restricted subsidiaries (the “Canadian Credit Parties”) under the Canadian tranche may be CDOR loans or Canadian prime rate loans. The applicable margin for base rate loans and Canadian prime rate loans vary from 0.75% to 1.25% and the applicable margin for LIBOR loans or CDOR loans vary from 1.75% to 2.25% , in each depending on the Company’s leverage ratio. The Company is permitted to repay any amounts borrowed prior to the maturity date without any premium or penalty subject to minimum amounts of prepayments and customary LIBOR breakage costs. In addition, a commitment fee of 0.50% per annum will be charged on the average daily unused portion of the revolving commitments. Such commitment fee is payable quarterly in arrears. 
+The 2018 ABL Credit Agreement contains various affirmative and negative covenants, including financial reporting requirements and limitations on indebtedness, liens, mergers, consolidations, liquidations and dissolutions, sales of assets, dividends and other restricted payments, investments (including acquisitions), and transactions with affiliates. In addition, the 2018 ABL Credit Agreement contains a minimum fixed charge ratio covenant of 1.00 to 1.00 that is tested quarterly when the availability under the 2018 ABL Credit Facility drops below a certain threshold or a default has occurred until the availability exceeds such threshold for 30 consecutive days and such default is no longer outstanding. The Company was in compliance with all covenants under the 2018 ABL Credit Agreement as of December 31, 2019 . 
+The Company’s obligations under the 2018 ABL Credit Facility may be accelerated, subject to customary grace and cure periods, upon the occurrence of certain events of default. Such events of default include customary events for a financing agreement of this type, including payment defaults, the inaccuracy of representation and warranties, defaults in the performance of affirmative or negative covenants, defaults on other material indebtedness of the Company or certain of its subsidiaries, defaults related to judgments, and the occurrence of a change in control. 
+All of the obligations under the 2018 ABL Credit Facility are secured by first priority perfected security interests (subject to permitted liens) in substantially all of the personal property of U.S. Credit Parties, excluding certain assets. The obligations under the Canadian tranche are further secured by first priority perfected security interests (subject to permitted liens) in substantially all of the personal property of Canadian Credit Parties, excluding certain assets. The 2018 ABL Credit Facility is guaranteed by the U.S. Credit Parties, and the Canadian tranche is further guaranteed by the Canadian Credit Parties and the U.S. Credit Parties. 
+Concurrent with the effectiveness of the 2018 ABL Credit Facility, the Company borrowed approximately $35.0 million to fund a portion of the upfront cash purchase of the Magnum Acquisition. The Company is permitted to repay any amounts borrowed prior to the maturity date without any premium or penalty, subject to minimum amounts of prepayments and customary LIBOR breakage costs. During the year ended December 31, 2019 , the Company repaid its outstanding revolver borrowings in full. 
+At December 31, 2019 , the Company’s availability under the 2018 ABL Credit Facility was approximately $99.2 million , net of an outstanding letter of credit of $0.2 million . The Company had no outstanding revolver borrowings. 
+2018 IPO Credit Agreement 
+On September 14, 2017, the Company entered into a credit agreement (as amended on November 20, 2017, the “2018 IPO Credit Agreement”) with JP Morgan as administrative agent and certain other financial institutions that became effective upon the consummation of the IPO in January 2018 (the “Effective Date”). Pursuant to the terms of the 2018 IPO Credit Agreement, the Company and its domestic restricted subsidiaries were entitled to borrow $125.0 million of term loans (the “2018 IPO Term Loan Credit Facility”), which the Company drew in full on the Effective Date. In January 2018, the Company also made a mandatory prepayment of $9.7 million against the 2018 IPO Term Loan Credit Facility, which approximated 50.0% of the estimated net proceeds from the IPO in excess of $150.0 million , as prescribed under the 2018 IPO Credit Agreement. 
+In addition, under the 2018 IPO Credit Agreement, the Company and its domestic restricted subsidiaries were entitled to borrow up to $50.0 million (including letters of credit) as revolving credit loans under the revolving commitments. 
+In the first quarter of 2018, concurrent with the effectiveness of the 2018 IPO Credit Agreement, using proceeds received from the IPO and borrowings under the 2018 IPO Term Loan Credit Facility, the Company fully repaid and terminated the term loans (the “Legacy Term Loans”) and revolving credit facilities (the “Legacy Revolving Credit Facilities”) under the Legacy Nine Credit Agreement (as defined below) and the Legacy Beckman Credit Agreement (as defined below). 
+All of the obligations under the 2018 IPO Credit Agreement were secured by first priority perfected security interests (subject to permitted liens) in substantially all of the personal property of the Company and its domestic restricted subsidiaries, 
+F-26 
+excluding certain assets. 
+Loans to the Company and its domestic restricted subsidiaries under the 2018 IPO Credit Agreement were either base rate loans or LIBOR loans. The applicable margin for base rate loans varied from 1.50% to 2.75% , and the applicable margin for LIBOR loans varied from 2.50% to 3.75% , in each case depending on the Company’s leverage ratio. In addition, a commitment fee of 0.50% per annum was charged on the average daily unused portion of the revolving commitments. On October 25, 2018, the Company fully repaid and terminated the 2018 IPO Credit Agreement. 
+Legacy Term Loans and Legacy Revolving Credit Facilities 
+In 2014, the Company entered into the Amended and Restated Credit Agreement (as amended, the “Legacy Nine Credit Agreement”) with HSBC Bank USA, N.A., as U.S. administrative agent, HSBC Bank Canada, as Canadian agent, and certain other financial institutions. All loans and other obligations under the Legacy Nine Credit Agreement were scheduled to mature on May 31, 2018. 
+In 2014, Beckman entered into a credit agreement (as amended, the “Legacy Beckman Credit Agreement” and together with the Legacy Nine Credit Agreement, the “Legacy Credit Agreements”) with Wells Fargo Bank, National Association, as administrative agent, and certain other financial institutions. All loans and other obligations under the Legacy Beckman Credit Agreement were scheduled to mature on June 30, 2018. Concurrent with the effectiveness of the 2018 IPO Credit Agreement in January 2018, the Company repaid all indebtedness under the Legacy Credit Agreements, which approximated $242.2 million . 
+As described above, in the first quarter of 2018, concurrent with the effectiveness of the 2018 IPO Credit Agreement, using proceeds received from the IPO and borrowings under the 2018 IPO Term Loan Credit Facility, the Company fully repaid and terminated the Legacy Term Loans and the Legacy Revolving Credit Facilities under the Legacy Nine Credit Agreement and the Legacy Beckman Credit Agreement. 
+Debt Extinguishment and Other Costs 
+During the year ended December 31, 2018, the Company recorded debt extinguishment costs of approximately $1.9 million , which consisted of $1.2 million in unamortized deferred financing costs associated with the termination of the 2018 IPO Credit Agreement in the fourth quarter of 2018 and $0.7 million in unamortized deferred financing costs associated with the termination of the Legacy Nine Credit Agreement and the Legacy Beckman Credit Agreement in the first quarter of 2018. The unamortized deferred financing costs were being amortized through the maturity dates of each agreement using the effective interest method. In addition, the Company recorded a $6.9 million commitment fee associated with a potential bridge financing in the fourth quarter of 2018. These costs are included in “Interest expense” in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss) for the year ended December 31, 2018 . 
+Fair Value of Debt Instruments 
+The estimated fair value of the Company’s debt obligations as of December 31, 2019 and 2018 was as follows: 
+December 31, 
+2019 
+2018 
+(in thousands) 
+Senior Notes 
+$ 
+324,000 
+$ 
+376,000 
+2018 ABL Credit Facility 
+$ 
+— 
+$ 
+35,000 
+2018 IPO Term Loan Credit Facility 
+$ 
+— 
+$ 
+— 
+Legacy Term Loans 
+$ 
+— 
+$ 
+— 
+Legacy Revolving Credit Facilities 
+$ 
+— 
+$ 
+— 
+The fair value of the Senior Notes is classified as Level 2 in the fair value hierarchy and is established based on observable inputs in less active markets. The 2018 ABL Credit Facility is also classified within Level 2 of the fair value hierarchy. The fair value of the 2018 ABL Credit Facility, approximates its carrying value. 
+10. Defined Contribution Plans 
+Background 
+Nine, Beckman, and Magnum sponsored defined contribution plans under Section 401(k) of the Internal Revenue 
+F-27 
+Code of 1986, as amended, for all qualified employees. 
+Effective January 1, 2018, the existing Nine Energy Service 401(k) Plan (the “Existing Nine Plan”) was terminated and merged with the Beckman 401(k) Plan (the “Beckman Plan”) into the new Nine Energy Service 401(k) Plan (the “New Nine Plan”). For the year ended December 31, 2018, under the New Nine Plan, employee contributions were matched by the Company as they were matched under the Existing Nine Plan, at 100% of the first 3% and 50% of the remaining up to 5% of the participant’s eligible compensation. Under the Beckman Plan, the Company had matched employee contributions at 50% of the first 5% of the participant’s eligible compensation. 
+Effective January 1, 2019, under the New Nine Plan, employee contributions were matched by the Company at 100% of the first 5% of the participant’s eligible compensation. 
+Effective April 1, 2019, the Magnum Oil Tools International Ltd. Profit Sharing & 401(k) Plan (the “Magnum Plan”) merged with the New Nine Plan. Prior to the merger, under the Magnum Plan, the Company had matched employee contributions at 100% of the first 3% and 50% of the remaining up to 5% of the participant’s eligible compensation. 
+Contributions 
+For the year ended December 31, 2019 , the Company made employer contributions of $4.8 million under the New Nine Plan and no contributions under the Magnum Plan. 
+For the year ended December 31, 2018 , the Company made employer contributions of $3.2 million under the New Nine Plan and $0.2 million of contributions under the Magnum Plan. 
+For the year ended December 31, 2017 , the Company made no contributions under the Existing Nine Plan. During 2017, for the Beckman Plan, the Company incurred a liability of $0.6 million for contributions that were made in 2018. 
+11. Stock-based Compensation 
+Nine 
+Stock Options 
+Information about stock option activity during the years ended December 31, 2019 and 2018 was as follows: 
+2019 Activity 
+Number of 
+Shares in 
+Underlying 
+Options 
+Weighted 
+Average 
+Exercise Price 
+Remaining 
+Weighted Average 
+Contractual Life 
+in Years 
+Intrinsic Value 
+(in thousands) 
+Beginning balance 
+957,659 
+$ 
+31.98 
+6.9 
+$ 
+6 
+Granted 
+— 
+— 
+— 
+— 
+Exercised 
+(674 
+) 
+22.63 
+— 
+2 
+Forfeited 
+(28,050 
+) 
+30.18 
+— 
+— 
+Expired 
+(112,508 
+) 
+28.66 
+— 
+— 
+Total outstanding 
+816,427 
+$ 
+32.51 
+5.8 
+$ 
+— 
+Options exercisable 
+704,944 
+$ 
+32.99 
+5.5 
+$ 
+— 
+F-28 
+2018 Activity 
+Number of 
+Shares in 
+Underlying 
+Options 
+Weighted 
+Average 
+Exercise Price 
+Remaining 
+Weighted Average 
+Contractual Life 
+in Years 
+Intrinsic Value 
+(in thousands) 
+Beginning balance 
+1,068,791 
+$ 
+30.79 
+7.6 
+$ 
+3,282 
+Granted 
+32,102 
+23.01 
+6.0 
+— 
+Exercised 
+(121,577 
+) 
+20.71 
+— 
+1,728 
+Forfeited 
+(14,759 
+) 
+29.80 
+— 
+5 
+Expired 
+(6,898 
+) 
+28.07 
+— 
+— 
+Total outstanding 
+957,659 
+$ 
+31.98 
+6.9 
+$ 
+6 
+Options exercisable 
+667,922 
+$ 
+33.20 
+6.2 
+$ 
+3 
+The intrinsic value at December 31, 2019 and 2018 is the amount by which the fair value of the underlying share exceeds the exercise price of an option as of December 31, 2019 and 2018 , respectively. 
+The Company granted no options in 2019 . The assumptions used in the Black-Scholes pricing model to estimate the fair value of the options granted in 2018 and 2017 are as follows: 
+2018 
+2017 
+Weighted average grant-date fair value 
+$ 
+13.11 
+$ 
+14.70 
+Assumptions 
+Expected life (in years) 
+6.0 
+6.0 
+Volatility 
+47.0 
+% 
+47.1 
+% 
+Dividend yield 
+0.0 
+% 
+0.0 
+% 
+Risk free interest rate 
+2.47 
+% 
+2.16 
+% 
+Compensation expense recorded was approximately $1.8 million , $3.5 million , and $3.3 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively. As of December 31, 2019 , the Company expects to record compensation expense of approximately $0.4 million over the remaining options term of approximately 0.5 years . Future stock option grants will result in additional compensation expense. 
+Restricted Stock and Restricted Stock Units 
+Information about restricted stock and restricted stock unit activity during the years ended December 31, 2019 , 2018 , and 2017 was as follows: 
+2019 
+2018 
+2017 
+Nonvested at the beginning of the year 
+1,017,945 
+373,861 
+131,179 
+Beckman restricted stock converted to Nine restricted stock 
+— 
+— 
+91,961 
+Granted 
+666,173 
+805,897 
+302,797 
+Vested 
+(292,326 
+) 
+(148,740 
+) 
+(77,093 
+) 
+Cancelled 
+(183,167 
+) 
+(13,073 
+) 
+(74,983 
+) 
+Nonvested at the end of the year 
+1,208,625 
+1,017,945 
+373,861 
+The weighted-average grant date fair value of the restricted stock and restricted stock units granted was $22.31 , $26.01 , and $31.18 during the years ended December 31, 2019 , 2018 , and 2017 , respectively. The total amount of compensation expense related to the restricted stock and restricted stock units recorded was approximately $11.7 million , $9.7 million , and $4.3 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively. As of December 31, 2019 , the Company expects to record compensation expense related to restricted stock and restricted stock units of approximately $16.4 million over the remaining term of approximately 1.7 years . 
+F-29 
+Performance Stock Units 
+The Company first granted performance stock units (“PSUs”) in 2019. The number of PSUs that will vest is contingent upon the Company’s achievement of certain specified targets. These awards have market conditions and were valued using a Monte Carlo simulation model. 
+The volatility of 49.7% was developed based upon the historical volatility of the Company as well as the volatilities of a group of peer companies, as the Company’s trading history needed to be supplemented with additional data as it went public in 2018. The risk-free rate, which was derived using the US Treasury security rates at the grant date, was 2.44% . 
+Beckman 
+Stock Options 
+During 2017, concurrent with the combination of Nine and Beckman, all Beckman stock options were converted to Nine stock options. All information related to Company stock option activity for the years ended December 31, 2019 and 2018 is shown in the “Nine – Stock Options” section above. Information about Beckman stock option activity for the year ended December 31, 2017 was as follows: 
+2017 Activity 
+Number of 
+Shares in 
+Underlying 
+Options 
+Weighted 
+Average 
+Exercise Price 
+Remaining 
+Weighted Average 
+Contractual Life 
+in Years 
+Intrinsic Value 
+(in thousands) 
+Beginning balance 
+17,313 
+$ 
+123.02 
+5.9 
+$ 
+— 
+Beckman options converted to Nine options 
+(17,313 
+) 
+123.02 
+5.9 
+— 
+Granted 
+— 
+— 
+— 
+— 
+Exercised 
+— 
+— 
+— 
+— 
+Forfeited 
+— 
+— 
+— 
+— 
+Total outstanding 
+— 
+$ 
+— 
+— 
+$ 
+— 
+Options exercisable 
+— 
+$ 
+— 
+— 
+$ 
+— 
+The intrinsic value at December 31, 2017 is the amount by which the fair value of the underlying share exceeds the exercise price of an option as of December 31, 2017 . 
+There was no compensation expense related to the Beckman options for the year ended December 31, 2017 . 
+Restricted Stock 
+During 2017, concurrent with the combination of Nine and Beckman, all Beckman restricted stock was converted to Nine restricted stock. All information related to Company restricted stock activity for the years ended December 31, 2019 and 2018 is shown in the “Nine – Restricted Stock” section above. Information about Beckman restricted stock activity for the year ended December 31, 2017 was as follows: 
+2017 
+Nonvested at the beginning of the year 
+20,225 
+Beckman restricted stock converted to Nine restricted stock 
+(20,225 
+) 
+Granted 
+— 
+Vested 
+— 
+Cancelled 
+— 
+Nonvested at the end of the year 
+— 
+There was no compensation expense related to the Beckman restricted stock awards for the year ended December 31, 2017 . 
+F-30 
+12. Commitments and Contingencies 
+Litigation 
+From time to time, the Company has various claims, lawsuits, and administrative proceedings that are pending or threatened with respect to personal injury, workers’ compensation, contractual matters, and other matters. Although no assurance can be given with respect to the outcome of these claims, lawsuits, or proceedings or the effect such outcomes may have, the Company believes any ultimate liability resulting from the outcome of such claims, lawsuits, or administrative proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on its business, operating results, or financial condition. 
+On August 31, 2017, an accident occurred while a five-employee crew of Big Lake Services, LLC, a subsidiary of Nine (“Big Lake Services”), was performing workover services at an oil and gas wellsite near Midland, Texas, operated by Pioneer Natural Resources USA, Inc. (“Pioneer Natural Resources”), resulting in the death of a Big Lake Services employee, Juan De La Rosa. On December 7, 2017, a lawsuit was filed on behalf of Mr. De La Rosa’s minor children in the Midland County District Court against Pioneer Natural Resources, Big Lake Services, and Phillip Hamilton related to this accident. The petition alleged, among other things, that the defendants acted negligently, resulting in the death of Mr. De La Rosa. On March 14, 2018, a plea in intervention was filed on behalf of Mr. De La Rosa’s parents, alleging similar claims. The plaintiffs and intervenors sought money damages, including punitive damages. On December 17, 2018, a mediation was held, and the parties reached an agreement in principle to settle this matter. In May 2019, the parties entered into settlement agreements, which have been approved by the court, and the court has dismissed the case. The Company has tendered this matter to its insurance company for defense and indemnification of Big Lake Services and the other defendants, and this settlement has been fully funded by its insurance company. 
+Leases 
+The Company leases equipment, vehicles, office space, yard facilities, and employee housing in the United States and in Canada where the Company operates, under leases classified as operating. The original lease terms require monthly rental payments and expire from 2019 through 2029. Other leases for various equipment and facilities are on a month-to-month basis or have expired during 2019 . Total rent expense for all operating leases was approximately $11.5 million , $13.0 million , and $7.2 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively. 
+The following schedule shows the future total minimum lease payments under these non-cancelable leases as of December 31, 2019 : 
+Year Ending December 31, 
+(in thousands) 
+2020 
+$ 
+10,597 
+2021 
+8,504 
+2022 
+7,485 
+2023 
+6,649 
+2024 
+4,470 
+Thereafter 
+17,105 
+$ 
+54,810 
+Self-insurance 
+The Company uses a combination of third-party insurance and self-insurance for health insurance claims. The self-insured liability represents an estimate of the undiscounted ultimate cost of uninsured claims incurred as of the balance sheet date. The estimate is based on an analysis of trailing months of incurred medical claims to project the amount of incurred but not reported claims liability. The estimated liability for self-insured medical claims was $1.8 million and $1.6 million at December 31, 2019 and 2018 , respectively, and is included under the caption “Accrued expenses” on the Company’s Consolidated Balance Sheets . 
+Although the Company does not expect the amounts ultimately paid to differ significantly from the estimates, the self-insurance liability could be affected if future claims experience differs significantly from historical trends and actuarial assumptions. 
+F-31 
+Contingent Liabilities 
+Contingent liabilities as of December 31, 2019 and 2018 consisted of the following: 
+Magnum Earnout 
+The Magnum Purchase Agreement includes the potential for additional future payments in cash of (i) up to 60% of net income (before interest, taxes, and certain gains or losses) for the “E-Set” tools business in 2019 through 2026 and (ii) up to $25.0 million based on sales of certain dissolvable plug products in 2019. 
+In 2019, the Company did not meet the sales requirement of certain dissolvable plug products during the year. As a result, the Company recorded a revaluation gain of approximately $20.9 million related to that portion of the contingent liability. 
+Frac Tech Earnout 
+On October 1, 2018, pursuant to the terms and conditions of the Frac Tech Purchase Agreement, the Company acquired Frac Tech. The Frac Tech Purchase Agreement includes, among other things, the potential for additional future payments, based on certain Frac Tech sales volume metrics through December 31, 2023. 
+Scorpion Earnout 
+In connection with the acquisition of Pat Greenlee Builders, LLC (“Scorpion”) in 2015 , the Company recorded a liability for contingent consideration to be paid in shares of Company common stock and in cash, contingent upon quantities of Scorpion Composite Plugs ™ sold during 2016 and gross margin related to the product sales for three years following the acquisition. 
+The following is a reconciliation of the beginning and ending amounts of the contingent liabilities (Level 3) for the year ended December 31, 2019 : 
+Magnum 
+Frac Tech 
+Total 
+(in thousands) 
+Balance at January 1, 2019 
+$ 
+24,521 
+$ 
+1,008 
+$ 
+25,529 
+Payments 
+— 
+(374 
+) 
+(374 
+) 
+Revaluation adjustments 
+(21,912 
+) 
+725 
+(21,187 
+) 
+Balance at December 31, 2019 
+$ 
+2,609 
+$ 
+1,359 
+$ 
+3,968 
+The following is a reconciliation of the beginning and ending amounts of the contingent liabilities (Level 3) for the year ended December 31, 2018 : 
+Magnum 
+Frac Tech 
+Scorpion 
+Total 
+(in thousands) 
+Balance at January 1, 2018 
+$ 
+— 
+$ 
+— 
+$ 
+1,730 
+$ 
+1,730 
+Fair value of contingent earnout liability initially recorded in connection with the acquisitions 
+23,029 
+953 
+— 
+23,982 
+Payment 
+— 
+— 
+(3,445 
+) 
+(3,445 
+) 
+Revaluation adjustments 
+1,492 
+55 
+1,715 
+3,262 
+Balance at December 31, 2018 
+$ 
+24,521 
+$ 
+1,008 
+$ 
+— 
+$ 
+25,529 
+The contingent consideration related to the contingent liabilities is reported at fair value, based on a Monte Carlo simulation model. Significant inputs used in the fair value measurement include estimated gross margin related to forecasted sales of the plugs, term of the agreement, and a risk adjusted discount factor. Contingent liabilities include $0.4 million and $20.9 million reported in “Accrued expenses” at December 31, 2019 and 2018 , respectively, and $3.6 million and $4.6 million reported in “Other long-term liabilities” at December 31, 2019 and 2018 , respectively, in the Company’s Consolidated Balance Sheets . The impact of the revaluation adjustments is included in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss) . 
+F-32 
+13. Taxes 
+The components of the provision (benefit) for income taxes for the years ended December 31, 2019 , 2018 , and 2017 were as follows: 
+Year Ended December 31, 
+2019 
+2018 
+2017 
+(in thousands) 
+Current 
+US federal 
+$ 
+(22 
+) 
+$ 
+(93 
+) 
+$ 
+(50 
+) 
+US state 
+452 
+1,558 
+878 
+Foreign 
+10 
+12 
+— 
+Total current provision 
+440 
+1,477 
+828 
+Deferred 
+US federal 
+(4,276 
+) 
+767 
+(5,455 
+) 
+US state 
+(51 
+) 
+131 
+(360 
+) 
+Foreign 
+— 
+— 
+— 
+Total deferred provision (benefit) 
+(4,327 
+) 
+898 
+(5,815 
+) 
+Total provision (benefit) for income taxes 
+$ 
+(3,887 
+) 
+$ 
+2,375 
+$ 
+(4,987 
+) 
+The provision (benefit) for income taxes for the years ended December 31, 2019 , 2018 , and 2017 differed from the provision (benefit) calculated using the applicable statutory federal income tax rate as follows: 
+Year Ended December 31, 
+2019 
+2018 
+2017 
+(in thousands) 
+Tax benefit at statutory rate 
+$ 
+(46,544 
+) 
+$ 
+(10,628 
+) 
+$ 
+(25,434 
+) 
+Foreign rate differential 
+(364 
+) 
+(56 
+) 
+241 
+State income taxes, net of federal benefit 
+306 
+108 
+70 
+Impact on deferred taxes from Beckman Combination 
+— 
+— 
+(2,025 
+) 
+Effects of Tax Act (1) 
+Effect of tax rate reduction on deferred tax 
+— 
+— 
+6,649 
+Effect of tax rate reduction on deferred tax valuation 
+— 
+— 
+(9,668 
+) 
+Nondeductible expenses 
+1,057 
+1,426 
+1,559 
+Impact from goodwill impairment 
+— 
+1,030 
+— 
+Valuation allowance (excluding impact of Tax Act) (1) 
+40,480 
+10,137 
+24,066 
+Other 
+1,178 
+358 
+(445 
+) 
+Total provision (benefit) for income taxes 
+$ 
+(3,887 
+) 
+$ 
+2,375 
+$ 
+(4,987 
+) 
+(1) On December 22, 2017, the United States enacted the Tax Cuts and Jobs Act (the “Tax Act”). 
+F-33 
+The tax effects of the cumulative temporary differences resulting in the net deferred tax asset (liabilities) at December 31, 2019 and 2018 were as follows: 
+December 31, 
+2019 
+2018 
+(in thousands) 
+Deferred income tax assets: 
+Inventories 
+$ 
+2,094 
+$ 
+626 
+Goodwill and intangible assets 
+34,092 
+13,581 
+Deferred tax benefit from net losses 
+38,501 
+30,139 
+Stock-based compensation 
+5,976 
+4,635 
+Tax credit carryforwards 
+680 
+660 
+Accrued expenses 
+2,763 
+4,188 
+Interest carryover 
+3,459 
+— 
+Other 
+163 
+168 
+Total deferred income tax assets 
+87,728 
+53,997 
+Less: Valuation allowance 
+(79,912 
+) 
+(28,862 
+) 
+Net deferred income tax assets 
+7,816 
+25,135 
+Deferred income tax liabilities: 
+Property and equipment 
+(9,404 
+) 
+(31,050 
+) 
+Prepaid expenses and other 
+— 
+— 
+Total deferred income tax liabilities 
+(9,404 
+) 
+(31,050 
+) 
+Net deferred income tax liability 
+$ 
+(1,588 
+) 
+$ 
+(5,915 
+) 
+As of December 31, 2019 , the Company had federal and state net operating losses (“NOLs”) of approximately $202.6 million . The federal NOLs related to tax years 2017 and prior can be used for a 20 -year period and, if unused, will begin to expire in 2034. The state NOLs can be used from 10 to 20 years and vary by state. A small portion of state NOLs will begin to expire in 2023. 
+The Company evaluates its deferred tax assets on a quarterly basis to determine whether a valuation allowance is required. The Company assesses whether a valuation allowance should be established based on its determination of whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible and prior to the expiration of its NOL and tax credit carryforwards. The Company considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Due to recent operating results and goodwill impairments recorded during 2019 , 2018 , and 2017 , the Company continues to be in a three -year cumulative loss position for the year ended December 31, 2019 . According to FASB ASC 740, Income Taxes, cumulative losses in recent years represent significant negative evidence in considering whether deferred tax assets are realizable. As a result, the Company continues to record a valuation allowance against its U.S. domestic and Canadian deferred tax assets. The Company has excluded the deferred tax liabilities related to certain indefinite-lived intangible assets when calculating the amount of valuation allowance needed as these liabilities cannot be considered as a source of income when determining the realizability of the net deferred tax assets. The 2019 results include an increase in the Company’s valuation allowance of approximately $51.1 million primarily due to the impairments recorded during the year. If the Company is able to generate sufficient taxable income in the future, and it becomes more likely than not that the Company will be able to fully utilize the net deferred tax assets on which a valuation allowance was recorded, the allowance will be released resulting in a potential decrease to its effective tax rate. 
+The Company is subject to U.S. federal income tax as well as income tax in multiple state jurisdictions. The earliest period the Company is subject to examination of federal income tax returns by the Internal Revenue Service is 2016. The state income tax returns and other state tax filings of the Company are subject to examination by the state taxing authorities for various periods, generally up to four years after they are filed. 
+F-34 
+The Company accounts for uncertain tax positions in accordance with guidance in FASB ASC 740, which prescribes the minimum recognition threshold a tax position taken or expected to be taken in a tax return is required to meet before being recognized in the financial statements. A reconciliation of the beginning and ending amount of uncertain tax positions is as follows: 
+2019 
+(in thousands) 
+Balance at January 1, 2019 
+$ 
+568 
+Additional based on tax positions related to prior years 
+— 
+Additional based on tax positions related to current year 
+— 
+Reduction based on tax positions related to prior years 
+— 
+Lapse of statute of limitations 
+— 
+Balance at December 31, 2019 
+$ 
+568 
+The total amount of unrecognized tax benefits at December 31, 2019 was $0.6 million . The total balance of unrecognized tax benefit would impact the Company’s future effective income tax rate if recognized. The Company recognizes interest and penalties related to uncertain tax positions within the provision for income taxes in its Consolidated Statements of Income and Comprehensive Income (Loss) . As of December 31, 2019 , no interest and penalties have been accrued. 
+14. Earnings (Loss) Per Share 
+Basic earnings (loss) per share is computed by dividing net income (loss) by the weighted average number of common shares outstanding for the period. Diluted earnings (loss) per share is based on the weighted average number of shares outstanding during each period and the exercise of potentially dilutive stock options assumed to be purchased from the proceeds using the average market price of the Company’s stock for each of the periods presented as well as the potentially dilutive restricted stock, restricted stock units, and performance stock units. 
+Basic and diluted earnings (loss) per common share was computed as follows: 
+2019 
+2018 
+2017 
+(in thousands, except for share and per share amounts) 
+Net loss 
+$ 
+(217,751 
+) 
+$ 
+(52,983 
+) 
+$ 
+(67,682 
+) 
+Average shares outstanding 
+29,308,107 
+24,411,213 
+14,887,006 
+Loss per share (basic and diluted) 
+$ 
+(7.43 
+) 
+$ 
+(2.17 
+) 
+$ 
+(4.55 
+) 
+The diluted earnings per share calculation excludes all stock options, unvested restricted stock, unvested restricted stock units, and unvested performance stock units for 2019 , 2018 , and 2017 because there is a net loss for each period and their inclusion would be anti-dilutive. 
+F-35 
+15. Related Party Transactions 
+During 2014, in conjunction with an exercise of warrants to provide a capital infusion, the Company issued promissory notes totaling $2.5 million to both a former executive officer of the Company and a current manager of the Company. The principal was due on June 30, 2019 (the “Maturity Date”), and interest of 4% per annum had been due and was payable on the Maturity Date. During the fourth quarter of 2018, the Company received full payment on the notes, resulting in no outstanding balance and no unpaid interest at December 31, 2018 . 
+As part of the acquisition of Crest Pumping Technologies, LLC (“Crest”) in 2014, the Company issued promissory notes totaling $9.4 million to former owners of Crest, including David Crombie, who is an executive officer of the Company. The principal was due on June 30, 2019 . The interest rate was based on the prime rate, the federal funds rate, or LIBOR, plus a margin to be determined in connection with the Company’s credit agreement and was due quarterly. Mr. Crombie paid $1.8 million during 2016 to pay his promissory note in full. At December 31, 2018 , the outstanding principal balance of the notes of the remaining individuals totaled $7.6 million and unpaid interest, included in “Prepaid expenses and other current assets” in the Company’s Consolidated Balance Sheets , totaled $10,000 . During the second quarter of 2019, the Company received the full principal balance of the notes outstanding as well as all unpaid interest. 
+The Company leases office space, yard facilities, and equipment and purchases building maintenance services from entities owned by Mr. Crombie. Total lease expense and building maintenance expense associated with these entities was $0.8 million , $0.8 million , and $0.8 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively. The Company also purchased of equipment of $1.4 million and $1.0 million for the years ended December 31, 2019 and 2018 , respectively, from an entity in which Mr. Crombie is a limited partner. There were outstanding payables due to this entity relating to equipment purchases of $0.1 million at the year ended December 31, 2019 . 
+In addition, the Company leases office space in Corpus Christi and Midland, Texas from an entity affiliated with Lynn Frazier, a beneficial owner of more than 5% of the Company’s stock. Total rental expense associated with this office space was $1.5 million and $0.2 million for the years ended December 31, 2019 and 2018 , respectively. 
+At December 31, 2018, the Company had an open receivable due from the sellers of Magnum primarily attributed to sales commissions paid to an intercompany entity that was not included in the Magnum Acquisition. The Company received payment in full in the first quarter of 2019. 
+The Company provides services to Citation Oil & Gas Corp. (“Citation”), an entity owned by a director of the Company. The Company billed $0.4 million , $0.7 million , and $0.7 million for services provided to Citation during the years ended December 31, 2019 , 2018 , and 2017 , respectively. There was an outstanding receivable due from Citation of $0.1 million as of December 31, 2018 . 
+The Company provides services to EOG Resources, Inc. (“EOG”). Gary L. Thomas, a director of the Company, acted as the President of EOG until his retirement on December 31, 2018. The Company generated revenue from EOG of $45.0 million and $34.4 million during the years ended December 31, 2018 and 2017 , respectively. There was an outstanding receivable due from EOG of $7.0 million at December 31, 2018 . 
+The Company purchases cable for its wireline trucks from an entity owned by Forum Energy Technologies (“Forum”). Two of the Company’s directors also serve as directors of Forum. The Company was billed $1.9 million , $1.7 million , and $1.2 million for cable during the years ended December 31, 2019 , 2018 , and 2017 , respectively. There was an outstanding payable due to the entity of $0.3 million and $0.1 million at December 31, 2019 and 2018 , respectively. The Company purchases coiled tubing string from another entity owned by Forum. The Company was billed $8.0 million , $8.1 million , and $5.0 million for coiled tubing string during the years ended December 31, 2019 , 2018 , and 2017 , respectively. There was an outstanding payable due to the entity of $0.9 million on December 31, 2019 . 
+The Company purchases chemical additives used in cementing from Select Energy Services, Inc. (“Select”). One of the Company’s directors also serves as a director of Select. The Company was billed $2.1 million , $2.0 million , and $1.8 million for chemicals during the years ended December 31, 2019 , 2018 , and 2017 , respectively. There was an outstanding payable due to Select of $0.1 million at December 31, 2019. 
+During the fourth quarter of 2019, the Company sold coiled tubing equipment for $5.9 million to National Energy Services Reunited (“NESR”). One of the Company’s directors also serves as a director of NESR. In 2019, the Company provided $0.9 million of products and rentals to NESR. At December 31, 2019, there was a receivable of $6.8 million for the coiled tubing equipment and the products and services. 
+On June 5, 2019, Ann G. Fox, President and Chief Executive Officer and a director of the Company, was elected as a director of Devon Energy Corporation (“Devon”). The Company generated revenue from Devon of $18.4 million for the year ended December 31, 2019 . There was an outstanding receivable due from Devon of $1.0 million at December 31, 2019 . 
+F-36 
+16. Segment Information 
+On August 30, 2019, the Company sold its Production Solutions segment to Brigade. For additional information on the Production Solutions divestiture, see Note 3 – Divestitures, Acquisitions, and Combinations . Prior to the Production Solutions Divestiture Date, the Company reported its results in two segments, the Completion Solutions segment and the Production Solutions segment. As a result of the Company’s sale of its Production Solutions segment, the Company considers the Completion Solutions segment to be its operating and reporting segment. This segmentation is representative of the manner in which the Chief Operating Decision Maker (“CODM”) and its Board of Directors view the business in allocating resources and measuring financial performance. The Company considers the CODM to be its Chief Executive Officer. 
+Financial data through the Production Solutions Divestiture Date is reported below for the Production Solutions segment. The amounts labeled “Corporate” relate to assets not allocated to either the Completion Solutions segment or the Production Solutions segment. 
+Year Ended December 31, 
+2019 
+2018 
+2017 
+(in thousands) 
+Revenues 
+Completion Solutions 
+$ 
+774,665 
+$ 
+745,316 
+$ 
+465,773 
+Production Solutions 
+58,272 
+81,858 
+77,887 
+$ 
+832,937 
+$ 
+827,174 
+$ 
+543,660 
+Cost of revenues (exclusive of depreciation and amortization shown separately below) 
+Completion Solutions 
+$ 
+620,125 
+$ 
+568,497 
+$ 
+384,641 
+Production Solutions 
+49,854 
+70,801 
+63,826 
+$ 
+669,979 
+$ 
+639,298 
+$ 
+448,467 
+Adjusted gross profit 
+Completion Solutions 
+$ 
+154,540 
+$ 
+176,819 
+$ 
+81,132 
+Production Solutions 
+8,418 
+11,057 
+14,061 
+$ 
+162,958 
+$ 
+187,876 
+$ 
+95,193 
+General and administrative expenses 
+81,327 
+73,078 
+49,505 
+Depreciation 
+50,544 
+54,257 
+53,422 
+Amortization of intangibles 
+18,367 
+9,558 
+8,799 
+Impairment of property and equipment 
+66,200 
+45,694 
+— 
+Impairment of goodwill 
+20,273 
+12,986 
+31,530 
+Impairment of intangibles 
+114,804 
+19,065 
+3,800 
+(Gain) loss on revaluation of contingent liabilities 
+(21,187 
+) 
+3,262 
+415 
+Loss on sale of subsidiaries 
+15,896 
+— 
+— 
+(Gain) loss on sale of property and equipment 
+(538 
+) 
+(1,731 
+) 
+4,688 
+Loss from operations 
+$ 
+(182,728 
+) 
+$ 
+(28,293 
+) 
+$ 
+(56,966 
+) 
+Non-operating expenses 
+38,910 
+22,315 
+15,703 
+Loss before income taxes 
+(221,638 
+) 
+(50,608 
+) 
+(72,669 
+) 
+Provision (benefit) for income taxes 
+(3,887 
+) 
+2,375 
+(4,987 
+) 
+Net loss 
+$ 
+(217,751 
+) 
+$ 
+(52,983 
+) 
+$ 
+(67,682 
+) 
+F-37 
+Capital expenditures by segment for years ended December 31, 2019 , 2018 , and 2017 were as follows: 
+Year Ended December 31, 
+2019 
+2018 
+2017 
+(in thousands) 
+Completion Solutions 
+$ 
+59,231 
+$ 
+48,361 
+$ 
+40,626 
+Production Solutions 
+2,790 
+3,548 
+4,590 
+Corporate 
+93 
+661 
+— 
+$ 
+62,114 
+$ 
+52,570 
+$ 
+45,216 
+Total assets by segment as of December 31, 2019 and 2018 were as follows: 
+December 31, 
+2019 
+2018 
+(in thousands) 
+Completion Solutions 
+$ 
+739,142 
+$ 
+1,045,643 
+Production Solutions 
+— 
+35,086 
+Corporate 
+111,753 
+60,443 
+$ 
+850,895 
+$ 
+1,141,172 
+Revenue by country for the years ended December 31, 2019 , 2018 , and 2017 were as follows: 
+2019 
+2018 
+2017 
+Amount 
+Percentage 
+Amount 
+Percentage 
+Amount 
+Percentage 
+(in thousands) 
+(in thousands) 
+(in thousands) 
+United States 
+$ 
+814,639 
+97.8 
+% 
+$ 
+796,221 
+96.3 
+% 
+$ 
+521,914 
+96.0 
+% 
+Canada and other 
+18,298 
+2.2 
+% 
+30,953 
+3.7 
+% 
+21,746 
+4.0 
+% 
+$ 
+832,937 
+100.0 
+% 
+$ 
+827,174 
+100.0 
+% 
+$ 
+543,660 
+100.0 
+% 
+Long-lived assets (defined as property and equipment and definite-lived intangible assets) by country as of December 31, 2019 and 2018 were as follows: 
+December 31, 
+2019 
+2018 
+(in thousands) 
+United States 
+$ 
+271,791 
+$ 
+377,623 
+Canada and other 
+4,804 
+7,472 
+$ 
+276,595 
+$ 
+385,095 
+F-38 
+17. Quarterly Financial Data (Unaudited) 
+Summarized quarterly financial data for the years ended December 31, 2019 and 2018 is presented below. 
+March 31, 2019 
+June 30, 2019 
+September 30, 2019 
+December 31, 2019 
+(in thousands, except per share amounts) 
+Revenue 
+$ 
+229,705 
+$ 
+237,517 
+$ 
+202,305 
+$ 
+163,410 
+Income (loss) from operations 
+26,936 
+13,955 
+(10,168 
+) 
+(213,451 
+) 
+Income (loss) before income taxes 
+17,770 
+3,352 
+(19,900 
+) 
+(222,860 
+) 
+Net income (loss) 
+17,310 
+6,087 
+(20,627 
+) 
+(220,521 
+) 
+Earnings (loss) per common share 
+Basic 
+$ 
+0.59 
+$ 
+0.21 
+$ 
+(0.70 
+) 
+$ 
+(7.51 
+) 
+Diluted 
+$ 
+0.59 
+$ 
+0.21 
+$ 
+(0.70 
+) 
+$ 
+(7.51 
+) 
+March 31, 2018 
+June 30, 2018 
+September 30, 2018 
+December 31, 2018 
+(in thousands, except per share amounts) 
+Revenue 
+$ 
+173,807 
+$ 
+205,492 
+$ 
+218,427 
+$ 
+229,448 
+Income (loss) from operations 
+4,698 
+11,486 
+16,356 
+(60,833 
+) 
+Income (loss) before income taxes 
+1,768 
+9,671 
+14,788 
+(76,835 
+) 
+Net income (loss) 
+1,675 
+9,019 
+13,658 
+(77,335 
+) 
+Earnings (loss) per common share 
+Basic 
+$ 
+0.08 
+$ 
+0.38 
+$ 
+0.57 
+$ 
+(2.78 
+) 
+Diluted 
+$ 
+0.08 
+$ 
+0.37 
+$ 
+0.56 
+$ 
+(2.78 
+) 
+Additional Notes 
+As a result of the shares issued during the year, earnings (loss) per share for each of the year’s four quarters, which are based on weighted average shares outstanding during each quarter, may not equal the annual earnings (loss) per share as reflected on the Company’s Consolidated Balance Sheets . 
+In the third quarter of 2019, the Company sold the Production Solutions segment to Brigade. For additional information on the divestiture of the Production Solutions segment, see Note 3 – Divestitures, Acquisitions, and Combinations . 
+F-39 
+Item 9. 
+Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+None. 
+Item 9A. 
+Controls and Procedures 
+Evaluation of Disclosure Controls and Procedures 
+Disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Exchange Act, is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC. As required by Rule 13a-15(b) under the Exchange Act, our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2019 . Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were not effective as of December 31, 2019 , due to the material weakness in internal control over financial reporting described below. 
+Management’s Report on Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act). Our internal control over financial reporting is a process designed under the supervision of our principal executive officer and principal financial officer, and effected by our board of directors, management, and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with GAAP. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+As of December 31, 2019 , our management assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework (2013). Based on its assessment using the COSO criteria, management has concluded that our internal control over financial reporting was not effective as of December 31, 2019 , due to the material weakness in internal control over financial reporting as described below. 
+As reported in Item 9A of our Annual Report on Form 10-K for the year ended December 31, 2018 , we did not design and maintain adequate controls to address the segregation of certain accounting duties related to journal entries, account reconciliations, and other accounting functions. Certain accounting personnel had the ability to prepare and post journal entries, as well as reconcile accounts, without an independent review by someone other than the preparer. Specifically, our internal controls were not designed or operating effectively to evidence that journal entries were appropriately recorded or were properly reviewed for validity, accuracy, and completeness. Immaterial misstatements were identified related to the inadequate segregation of accounting duties. This material weakness could result in misstatement of the aforementioned accounts and disclosures that would result in a material misstatement in our annual or interim consolidated financial statements that would not be prevented or detected on a timely basis. 
+Remediation Efforts to Address the Material Weakness 
+In response to the material weakness identified above, our management has performed the following: 
+• 
+Replaced the less sophisticated accounting systems used by the majority of our newly acquired subsidiaries with the enterprise resource planning system used by the majority of our existing subsidiaries. 
+• 
+Hired additional resources, including an experienced Internal Audit Director to lead the Company’s internal audit department, with responsibility for direction and oversight of all internal audit functions. 
+In addition, our management is in the process of performing the following: 
+• 
+Continuing to develop and implement additional controls and procedures and enhance existing controls and procedures to ensure the segregation of certain accounting duties related to journal entries, account reconciliations, and other accounting functions. 
+Until the remediation steps listed set forth above are fully developed, implemented, and operating for a sufficient amount of time to validate the remediation, the material weakness described above will continue to exist. 
+Attestation Report of the Independent Registered Public Accounting Firm 
+This Annual Report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Management’s report on internal control over financial reporting was not subject to attestation by our independent registered public accounting firm pursuant to rules of the SEC that permit us to provide only management’s report in this Annual Report. 
+Changes in Internal Control over Financial Reporting 
+There have been no changes in our internal control over financial reporting that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting during the quarterly period ended December 31, 2019 . 
+Item 9B. 
+Other Information 
+None. 
+53 
+PART III 
+Item 10. 
+Directors, Executive Officers and Corporate Governance 
+The information required in response to this item will be set forth in our definitive proxy statement for the 2020 annual meeting of stockholders and is incorporated herein by reference. 
+Item 11. 
+Executive Compensation 
+The information required in response to this item will be set forth in our definitive proxy statement for the 2020 annual meeting of stockholders and is incorporated herein by reference. 
+Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters 
+The information required in response to this item will be set forth in our definitive proxy statement for the 2020 annual meeting of stockholders and is incorporated herein by reference. 
+Item 13. 
+Certain Relationships and Related Transactions, and Director Independence 
+The information required in response to this item will be set forth in our definitive proxy statement for the 2020 annual meeting of stockholders and is incorporated herein by reference. 
+Item 14. 
+Principal Accounting Fees and Services 
+The information required in response to this item will be set forth in our definitive proxy statement for the 2020 annual meeting of stockholders and is incorporated herein by reference. 
+54 
+PART IV 
+Item 15. Exhibits, Financial Statement Schedules 
+(a) Documents Filed as Part of This Annual Report 
+1. Financial Statements 
+The following consolidated financial statements of the Company are filed as a part of this Annual Report: 
+Report of Independent Registered Public Accounting Firm 
+F-1 
+Consolidated Balance Sheets as of December 31, 2019 and 2018 
+F-2 
+Consolidated Statements of Income and Comprehensive Income (Loss) for the Years Ended December 31, 2019, 2018, and 2017 
+F-3 
+Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2019, 2018, and 2017 
+F-4 
+Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018, and 2017 
+F-5 
+Notes to Consolidated Financial Statements 
+F-6 
+2. Financial Statement Schedules 
+All financial statement schedules have been omitted because they are not applicable, or the required information is presented in the consolidated financial statements and related notes. 
+3. Exhibits 
+The exhibits to this Annual Report required to be filed pursuant to Item 15(b) are listed below. 
+Exhibit 
+Number 
+Description 
+2.1† 
+Securities Purchase Agreement, dated as of October 15, 2018, by and among Warren Lynn Frazier, Garrett Lynn Frazier 2018 DG Trust, Derrick Chase Frazier 2018 DG Trust, Frazier Family Foundation, Inc., as sellers, Warren Lynn Frazier, solely in his capacity as seller representative, MOTI Holdco, LLC and Nine Energy Canada Inc., as buyers, Nine Energy Service, Inc. and certain other parties named therein (Incorporated by reference to Exhibit 2.1 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on October 15, 2018). 
+2.2 
+First Amendment to Securities Purchase Agreement, dated June 7, 2019, by and among Warren Lynn Frazier, Garrett Lynn Frazier 2018 DG Trust, Derrick Chase Frazier 2018 DG Trust, and Frazier Family Foundation, Inc., as sellers, MOTI Holdco, LLC and Nine Energy Canada Inc., as buyers, and Nine Energy Service, Inc. (Incorporated by reference to Exhibit 2.2 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed August 12, 2019). 
+2.3†^ 
+Membership Interest Purchase Agreement, dated August 30, 2019, by and between Brigade Energy Services LLC and Nine Energy Service, Inc. (Incorporated by reference to Exhibit 2.1 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on September 6, 2019). 
+3.1 
+Third Amended and Restated Certificate of Incorporation of Nine Energy Service, Inc., dated January 23, 2018 (Incorporated by reference to Exhibit 3.1 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on January 23, 2018). 
+3.2 
+Fourth Amended and Restated Bylaws of Nine Energy Service, Inc., dated January 23, 2018 (Incorporated by reference to Exhibit 3.2 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on January 23, 2018). 
+4.1 
+Form of Common Stock Certificate (Incorporated by reference to Exhibit 4.1 of Nine Energy Service, Inc.’s Amendment No. 2 to Registration Statement on Form S-1 filed on May 24, 2017). 
+4.2 
+Second Amended and Restated Stockholders Agreement, dated as of February 28, 2017, by and among Nine Energy Service, Inc. and the parties thereto (Incorporated by reference to Exhibit 4.2 of Nine Energy Service, Inc.’s Amendment No. 2 to Registration Statement on Form S-1 filed on May 24, 2017). 
+4.3 
+First Amendment to Second Amended and Restated Stockholders Agreement, dated as of July 24, 2017, by and among Nine Energy Service, Inc. and the parties thereto (Incorporated by reference to Exhibit 4.3 of Nine Energy Service, Inc.’s Amendment No. 3 to Registration Statement on Form S-1 filed on August 14, 2017). 
+55 
+4.4 
+Indenture, dated as of October 25, 2018, by and among Nine Energy Service, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (including Form of Note) (Incorporated by reference to Exhibit 4.1 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on October 26, 2018). 
+4.5* 
+Supplemental Indenture and Guarantee, dated as of November 23, 2018, by and among MOTI Holdco, LLC, Magnum Oil Tools GP, LLC, and Magnum Oil Tools International, LTD, Nine Energy Service, Inc. and certain other subsidiaries and Wells Fargo Bank, National Association, as a trustee (Incorporated by reference to Exhibit 4.5 of Nine Energy Service, Inc.’s Annual Report on Form 10-K filed on March 7, 2019). 
+4.6 
+Registration Rights Agreement, dated as of October 25, 2018, by and among Nine Energy Service, Inc., the former owners of the equity interests of Magnum Oil Tools International, LTD, Magnum Oil Tools Canada Ltd. and Magnum Oil Tools GP, LLC and the other holders that may become party thereto from time to time (Incorporated by reference to Exhibit 4.2 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on October 26, 2018). 
+4.7* 
+Description of Common Stock. 
+10.1 
+Credit Agreement, dated as of October 25, 2018, by and among Nine Energy Service, Inc., Nine Energy Canada Inc., JPMorgan Chase Bank, N.A. and certain other financial institutions (Incorporated by reference to Exhibit 10.1 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on October 26, 2018). 
+10.2+ 
+Form of Indemnification Agreement between Nine Energy Service, Inc. and its directors and certain officers (Incorporated by reference to Exhibit 10.10 of Nine Energy Service, Inc.’s Amendment No. 2 to Registration Statement on Form S-1 filed on May 24, 2017). 
+10.3+ 
+Nine Energy Service, Inc. 2011 Stock Incentive Plan, as amended and restated effective February 28, 2017 (Incorporated by reference to Exhibit 10.10 of Nine Energy Service, Inc.’s Registration Statement on Form S-1 filed on May 2, 2017). 
+10.4+ 
+Form of Nine Energy Service, Inc. Restricted Stock Agreement for Executives (Incorporated by reference to Exhibit 10.1 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed on May 14, 2018). 
+10.5+ 
+Form of Nine Energy Service, Inc. Nonstatutory Stock Option Agreement for Executives (Incorporated by reference to Exhibit 10.2 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed on May 14, 2018). 
+10.6+ 
+Form of Nine Energy Service, Inc. Restricted Stock Agreement for Non-Employee Directors (Incorporated by reference to Exhibit 10.3 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed on May 14, 2018). 
+10.7+ 
+Form of Nine Energy Service, Inc. Nonstatutory Stock Option Agreement for Non-Employee Directors (Incorporated by reference to Exhibit 10.4 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed on May 14, 2018). 
+10.8+ 
+Form of Nine Energy Service, Inc. Performance Share Unit Grant Notice and Form of Performance Share Unit Agreement (Incorporated by reference to Exhibit 10.1 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed on May 8, 2019). 
+10.9+ 
+Amended and Restated Employment Agreement, dated August 28, 2018, by and between Nine Energy Service, LLC and Ann G. Fox (Incorporated by reference to Exhibit 10.1 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on August 30, 2018). 
+10.10+ 
+Amended and Restated Employment Agreement between Clinton Roeder and Nine Energy Service, LLC, dated as of November 20, 2018 (Incorporated by reference to Exhibit 10.2 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on November 26, 2018). 
+10.11+ 
+Amended and Restated Employment Agreement between David Crombie and Nine Energy Service, LLC, dated as of November 20, 2018 (Incorporated by reference to Exhibit 10.1 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on November 26, 2018). 
+10.12+ 
+Amended and Restated Employment Agreement between Edward Bruce Morgan and Nine Energy Service, LLC, dated as of November 20, 2018 (Incorporated by reference to Exhibit 10.3 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on November 26, 2018). 
+10.13+ 
+First Amendment to Amended and Restated Employment Agreement, by and among Nine Energy Service, LLC, Nine Energy Service, Inc. and Edward Bruce Morgan, effective as of August 30, 2019 (Incorporated by reference to Exhibit 10.1 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on September 6, 2019). 
+56 
+10.14+ 
+Amended and Restated Employment Agreement between Theodore R. Moore and Nine Energy Service, LLC, dated as of November 20, 2018 (Incorporated by reference to Exhibit 10.4 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on November 26, 2018). 
+21.1* 
+List of Subsidiaries of Nine Energy Service, Inc. 
+23.1* 
+Consent of PricewaterhouseCoopers LLP. 
+31.1* 
+Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+31.2* 
+Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+32.1** 
+Certifications by Chief Executive Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002. 
+32.2** 
+Certifications by Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002. 
+101* 
+Interactive Data Files. 
+_______________________________________ 
+* 
+Filed herewith. 
+** 
+Furnished herewith. 
+† 
+Certain schedules and similar attachments have been omitted pursuant to Item 601(a)(5) of Regulation S-K and will be provided to the SEC upon request. 
+^ 
+Pursuant to Item 601(b)(2) of Regulation S-K, certain immaterial provisions of the agreement that would likely cause competitive harm to the Company if publicly disclosed have been redacted. The Company hereby undertakes to furnish supplementally an unredacted copy of the agreement to the SEC upon request; provided, however, that the Company may request confidential treatment pursuant to Rule 24b-2 of the Exchange Act for any documents so furnished. 
++ 
+Management contract or compensatory plan or arrangement. 
+57 
+Item 16. 
+Form 10-K Summary. 
+None. 
+58 
+SIGNATURES 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+NINE ENERGY SERVICE, INC. 
+By: 
+/s/ Ann G. Fox 
+Ann G. Fox 
+President and Chief Executive Officer 
+Date: March 9, 2020 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 9, 2020 . 
+Signature 
+Title 
+/s/ Ann G. Fox 
+President, Chief Executive Officer, and Director (Principal Executive Officer) 
+Ann G. Fox 
+/s/ Clinton Roeder 
+Senior Vice President and Chief Financial Officer (Principal Financial Officer) 
+Clinton Roeder 
+/s/ S. Brett Luz 
+Chief Accounting Officer (Principal Accounting Officer) 
+S. Brett Luz 
+/s/ Ernie L. Danner 
+Chairman of the Board 
+Ernie L. Danner 
+/s/ David C. Baldwin 
+Director 
+David C. Baldwin 
+/s/ Mark E. Baldwin 
+Director 
+Mark E. Baldwin 
+/s/ Curtis F. Harrell 
+Director 
+Curtis F. Harrell 
+/s/ Scott E. Schwinger 
+Director 
+Scott E. Schwinger 
+/s/ Gary L. Thomas 
+Director 
+Gary L. Thomas 
+/s/ Andrew L. Waite 
+Director 
+Andrew L. Waite 
+/s/ Darryl K. Willis 
+Director 
+Darryl K. Willis 
+59
\ No newline at end of file
diff --git a/raw/filings/0001532286/2019/0001532286-20-000005/filing_metadata.csv b/raw/filings/0001532286/2019/0001532286-20-000005/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..183663489f72d8c41bcb2068060202aa693e6ab3
--- /dev/null
+++ b/raw/filings/0001532286/2019/0001532286-20-000005/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0001532286,NINE,"Nine Energy Service, Inc.",10-K,2020-03-10,2019-12-31,2020-03-09T21:50:42.000Z,0001532286-20-000005,nine-20191231x10k.htm,10-K,11462540,1,0,https://www.sec.gov/Archives/edgar/data/1532286/000153228620000005/nine-20191231x10k.htm,https://www.sec.gov/Archives/edgar/data/1532286/000153228620000005/,2019,2019,1
diff --git a/raw/filings/0001532286/2019/0001532286-20-000005/item1.txt b/raw/filings/0001532286/2019/0001532286-20-000005/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..c8b0b24c50aebafe9b4f1edae11d774065f41bb9
--- /dev/null
+++ b/raw/filings/0001532286/2019/0001532286-20-000005/item1.txt
@@ -0,0 +1,95 @@
+Item 1. 
+Business 
+Overview 
+Nine Energy Service, Inc. (either individually or together with its subsidiaries, as the context requires, the “Company,” “Nine,” “we,” “us,” and “our”) is a Delaware corporation that was formed in February 2013 through a combination of three service companies owned by SCF Partners, L.P. or its affiliates. Nine is a leading completion services provider that targets unconventional oil and gas resource development across all North American basins and abroad. We partner with our exploration and production (“E&P”) customers to design and deploy downhole solutions and technology to prepare horizontal, multistage wells for production. We focus on providing our customers with cost-effective and comprehensive completion solutions designed to maximize their production levels and operating efficiencies. We believe our success is a product of our culture, which is driven by our intense focus on performance and wellsite execution as well as our commitment to forward-leaning technologies that aid us in the development of smarter, customized applications that drive efficiencies. 
+We provide our comprehensive completion solutions across a diverse set of well-types, including on the most complex, technically demanding unconventional wells. Modern, high-intensity completion techniques are a more effective way for our customers to maximize resource extraction from horizontal oil and gas wells. These completion techniques provide improved estimated ultimate recovery per lateral foot and a superior return on investment by decreasing cycle time, which make them attractive to operators despite their associated increased well cost. We compete for the most intricate and demanding projects, which are characterized by extended reach horizontal laterals, increased stage counts per well, multi-well pad development, and increased proppant loading per lateral foot. As stage counts per well and wells per pad increase, so do our operating leverage and returns, as we are able to complete more jobs and stages with the same number of units and crews. Service providers for these demanding projects are selected based on their technical expertise and ability to execute safely and efficiently, rather than only price. As our customers continue to improve operational efficiencies in completions design, increasing its complexity and difficulty, oilfield service selection becomes much more critical and selective. 
+We offer a variety of completion applications and technologies to match customer needs across the broadest addressable completions market. Our comprehensive well solutions range from cementing the well at the initial stages of the completion, preparing the well for stimulation, isolating all the stages of an extended reach lateral, and the drilling out of isolation tools. Our completion techniques are specifically tailored to the customer and geology of each well. At the initial stage of a well completion, our lab facilities produce customized cementing slurries used to secure the production casing to ensure well integrity throughout the life of the well. Once the casing is in place, we utilize our proprietary tools at the toe (end) of the well, often called stage one, to prepare for the well stimulation process. We provide customers with plug-and-perf or pinpoint frac sleeve system technology to complete the remaining stages of the well. Through our wireline units, we provide plug-and-perf services that, when combined with our fully-composite or dissolvable frac plugs, create perforations to isolate and divert the fracture to the correct stage. Our pinpoint frac sleeve system involves packers, either hydraulic or swellable, to isolate sections of the wellbore and frac sleeves to provide access to each stage for stimulation and production. Our equipment also includes large-diameter coiled tubing units that are capable of reaching the farthest depths for the removal of plugs and cleaning of the wellbore to prepare for production. 
+In October 2018, we acquired Magnum Oil Tools International, LTD, Magnum Oil Tools GP, LLC, and Magnum Oil Tools Canada Ltd. (collectively, “Magnum” and such acquisition, the “Magnum Acquisition”). Magnum is a leading oilfield completion tools company that is focused on the development of innovative tools for unconventional oil and gas resource development. Magnum has a broad offering of proprietary downhole completions consumables products, including a comprehensive line of dissolvable and composite frac plugs; disk subs, including intervention-less designs, for wellbore isolation and casing flotation device applications; and dissolvable frac balls. 
+Our website is located at https://nineenergyservice.com, and our investor relations website is located at https://investor.nineenergyservice.com. The information posted on our website is not incorporated into this Annual Report. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to reports filed or furnished pursuant to Sections 13(a) and 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are available free of charge on our investor relations website as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (the “SEC”). You may also access all of our public filings through the SEC’s website at www.sec.gov. Investors and other interested parties should note that we use our investor relations website to publish important information about us, including information that may be deemed material to investors. We encourage investors and other interested parties to review the information we may publish through our investor relations website, in addition to our SEC filings, press releases, conference calls, and webcasts. 
+1 
+Our Services 
+We derive revenue by providing services integral to the completion of unconventional wells through a full range of tools and methodologies. On August 30, 2019, we sold our Production Solutions segment. For additional information on this divestiture, see Note 3 – Divestitures, Acquisitions, and Combinations included in Item 8 of Part II of this Annual Report. 
+The following is a description of our primary service offerings and deployment methods: 
+Cementing Services: Our cementing services consist of blending high-grade cement and water with various solid and liquid additives to create a cement slurry that is pumped between the casing and the wellbore of the well. We currently operate three high-quality laboratory facilities capable of designing and testing all of the current industry cement designs. The laboratory facilities operate twenty-four hours a day and are fully staffed by qualified technicians with the latest equipment and modeling software. Additionally, our technicians and engineers ensure that all tests are performed to American Petroleum Institute specifications and results are delivered to customers promptly. Our cement slurries are designed to achieve the proper cement thickening time, compressive strength, and fluid loss control. Our slurries can be modified to address a wide range of downhole needs of our E&P customers, including varying well depths, downhole temperatures, pressures, and formation characteristics. 
+We deploy our slurries by using our customized design twin-pumping units, which are fully redundant, containing two pumps, two hydraulic systems, two mixing pumps, and two electrical systems. This customized design significantly decreases our risk of downtime due to mechanical failure and eliminates the necessity to have an additional cementing unit on standby. We have invested in the highest quality cementing equipment, and since 2012, we have deployed only new equipment for use in the fields. As of December 31, 2019 , we had a total of 37 pumping units. 
+From January 2014 through December 2019, we completed approximately 19,600 cementing jobs, with an on-time rate of approximately 91% . Punctuality of service has become one of the primary metrics that E&P operators use to evaluate the cementing services they receive. Key contributors to our 91% on-time rate include our lab capabilities, personnel, close proximity to our customers’ acreage, dual-sided bulk loading plants, and our service-driven culture. 
+Completion Tools: We provide downhole solutions and technology used for multistage completions. Our comprehensive completion service offerings are complemented by our unconventional open hole and cemented completion tool products, such as liner hangers and accessories, fracture isolation packers, frac sleeves, stage one prep tools, fully-composite and dissolvable frac plugs, casing flotation tools, specialty open hole float equipment, disk subs, composite cement retainers, and centralizers. Our completion tools provide pinpoint frac sleeve system technologies as well as a portfolio of completion technologies used for completing the toe stage of a horizontal well and fully-composite, dissolvable, and extended range frac plugs to isolate stages during plug and perf operations. 
+Our systems provide completion efficiencies at the wellsite by reducing our customers’ equipment needs and stimulation time and allowing for specific zonal treatment. From March 2011 through December 2019, we deployed approximately 193,300 isolation, stage one, and casing flotation tools and approximately 22,500 frac sleeves. 
+Wireline Services: Our wireline services involve the use of a wireline unit equipped with a spool of wireline that is unwound and lowered into oil and gas wells to convey specialized tools or equipment for well completion, well intervention, or pipe recovery. We operate a fleet of modern and “fit-for-purpose” cased hole wireline units designed for operating in unconventional completion operations. We currently operate 47 wireline pumpdown units in the U.S. Our operation is equipped with the latest technology utilized to service long lateral completions, including head tension tools, ballistic release tools, and addressable switches. We currently have wireline units equipped with Coated Line, which is a coated wireline that significantly reduces injector oil use. Offering a lower dynamic coefficient of friction, Coated Line Wireline requires less pump down fluid to operate and is more conducive for reaching further depths in longer laterals. 
+The majority of our wireline work consists of plug-and-perf completions, which is a multistage well completion technique for cased-hole wells that consists of deploying perforating guns to a specified depth. We deploy proprietary specialized tools like our fully-composite and dissolvable frac plugs through our wireline units. From January 2014 through December 2019, we completed approximately 153,100 wireline stages with a success rate of approximately 99% . 
+Coiled Tubing Services: Coiled tubing services perform wellbore intervention operations utilizing a continuous steel pipe that is transported to the wellsite wound on a large spool in lengths of up to 30,000 feet. Coiled tubing provides a cost-effective solution for well work due to the ability to deploy efficiently and safely into a live well using specialized well-control equipment. The live well work capability limits the customer’s risk of formation damage associated with “killing” a well (the temporary placement of heavy fluids in a wellbore to keep reservoir fluids in place), while allowing for safer operations due to 
+2 
+minimal equipment handling. Coiled tubing facilitates a variety of services in both new and old wells, such as milling, drilling, fishing, production logging, artificial lift, cementing, and stimulation. 
+We currently operate 14 coiled tubing units serving the Permian Basin, SCOOP/STACK region, and Haynesville markets. Our coiled tubing units carry data acquisition and dissemination technology, allowing our customers to monitor jobs via a web interface. Of the 14 coiled tubing units, we consider 12 to be “extended reach” units capable of reaching the toe of wells with total measured depths of 24,000 feet and beyond, including lateral lengths in excess of 12,500 feet, keeping pace with the industry’s most challenging downhole environments. While we specialize in larger-diameter (2 3/8” and 2 5/8”) coiled tubing units, we also offer 2” and 1 1/4” diameter solutions to our customers. From April 2014 through December 2019, we have performed approximately 9,100 jobs and deployed more than 198 million running feet of coiled tubing, with a success rate of over 99% . 
+Geographic Areas of Operation 
+We operate in all major onshore basins in both the U.S. and Canada, including the Permian Basin, Marcellus and Utica Shales, Eagle Ford Shale, DJ Basin, SCOOP/STACK Formation, Bakken Formation, Haynesville Formation, and Western Canada Sedimentary Basin. We provide our services through strategically placed operating facilities located in-basin throughout North America. This local presence allows us to quickly respond to customer demands and operate efficiently. Additionally, through our extensive footprint, we are able to track and implement best practices around completion trends and technology across all divisions and geography. 
+We believe that our strategic geographic diversity will benefit us as activity increases or decreases in select basins by helping to mitigate basin-risk. Our broad geographic footprint provides us with exposure to potential increases in drilling and completion activity and will allow us to opportunistically pursue new business in basins with the most active drilling environments. 
+Seasonality 
+Our operations are subject to seasonal factors, and our overall financial results reflect seasonal variations. Specifically, we typically have experienced a pause by our customers around the holiday season in the fourth quarter, which may be compounded as our customers exhaust their annual capital spending budgets towards year end. 
+Additionally, our operations are directly affected by weather conditions. During the winter months (portions of the first and fourth quarters) and periods of heavy snow, ice, or rain, particularly in the northeastern U.S., North Dakota, Rockies, and western Canada, our customers may delay operations or we may not be able to operate or move our equipment between locations. Also, during the spring thaw, which normally starts in late March and continues through June, some areas, primarily in western Canada, impose transportation restrictions to prevent damage caused by the spring thaw. Throughout the year, heavy rains adversely affect activity levels because well locations and dirt access roads can become impassible in wet conditions. Weather conditions may also negatively affect our customers activity levels. 
+Sales and Marketing 
+Our sales activities are conducted through a network of sales representatives and business development personnel, which provides us coverage at both the corporate and field level of our customers. We have a technical sales organization with expertise and focus within our specific service lines. Sales representatives work closely with local operations managers to target potential opportunities through strategic focus and planning. Customers are identified as targets based on their drilling and completion activity, geographic location, and economic viability. Our marketing activities are performed internally with input and guidance from a third-party marketing agency. Our strategy is based on building a strong brand though multiple media outlets including our website, select social media accounts, print and online advertisements, billboard advertisements, press releases and various industry-specific conferences, publications, and lectures. 
+Customers 
+Our customer base includes a broad range of integrated and independent E&P companies. For the year ended December 31, 2019 , our top five customers collectively accounted for approximately 34% of our revenues. For the year ended December 31, 2019 , no single customer accounted for 10% or more of our revenues. 
+Demand for our services and products is cyclical and substantially dependent upon activity levels in the oil and gas industry, particularly our customers’ willingness to spend capital on the exploration for and development of oil and natural gas. Our customers’ spending plans are generally based on their outlook for near-term and long-term commodity prices. As a result, the demand for our services and products is highly sensitive to current and expected commodity prices. 
+3 
+Competition 
+We provide our services and products across the United States, Canada, and abroad, and we compete against different companies in each service and product line we offer. Our competition includes many large and small oilfield service companies, including the largest integrated oilfield services companies. We believe that the principal competitive factors in the markets we serve are technology offerings, wellsite execution, service quality, technical expertise, equipment capacity, work force competency, efficiency, safety record, reputation, and experience. Additionally, projects are often awarded on a bid basis, which tends to create a highly competitive environment. We seek to differentiate our company from our competitors by delivering the highest-quality services, technology, and equipment possible, coupled with superior execution and operating efficiency in a safe working environment. By focusing on cultivating our existing customer relationships and maintaining our high standard of customer service, technology, safety, performance, and quality of crews, equipment, and services, we believe we are differentiated in a competitive market. 
+Our major competitors include Halliburton Company, Schlumberger Limited, Baker Hughes, NCS Multistage, NexTier Oilfield Solutions, KLX Energy Services Holdings, and a significant number of private and locally-oriented businesses. 
+Suppliers 
+We purchase a wide variety of raw materials, parts, and components that are manufactured and supplied for our operations from various suppliers. While we are not dependent on any single supplier for those materials, parts, or components, certain product lines acquired in the Magnum Acquisition depend on a limited number of third-party suppliers and vendors. During the year ended December 31, 2019 , no supplier of the materials used in our services provided over 10% of our materials or equipment as a percentage of overall costs. 
+To date, we have generally been able to obtain the equipment, parts, and supplies necessary to support our operations on a timely basis. While we believe that we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers, we may not always be able to make alternative arrangements. In addition, certain materials for which we do not currently have long-term supply agreements could experience shortages and significant price increases in the future. As a result, we may be unable to mitigate any future supply shortages and our results of operations, prospects, and financial condition could be adversely affected. 
+Research & Technology, Intellectual Property 
+Our sales and earnings are influenced by our ability to successfully introduce new or improved products and services to the market. We believe we have become a “go-to” provider for piloting new technologies because of our service quality and offering, execution at the wellsite, and geographic footprint. 
+Our engineering and technology efforts are focused on providing efficient and cost-effective solutions to maximize production for our customers across major North American onshore basins and abroad. We have dedicated resources focused on internally developing new technology and equipment and evolving our existing proprietary tools, as well as resources focused on sourcing and commercializing new technologies through mergers and acquisitions and strategic partnerships, to stay ahead of industry trends and achieve lower completion and production costs for our customers. With the acquisition of Magnum, our internal research and development capabilities have increased substantially. 
+We have developed a suite of proprietary downhole tools, products, and techniques through both internal resources, as well as mergers and acquisitions and strategic partnerships with manufacturers and engineering companies looking for a reliable and expansive channel to market. In these partnerships, we have exclusive rights to market and sell technology unavailable to any other service providers in the designated regions, and we sell the technology directly to the customer and order from the manufacturer on an as-needed basis, with no minimum volume requirements and without having to hold excess inventory. These strategic partnerships provide us and our customers with access to unique downhole technology from independent innovators while allowing us to minimize exposure to potential technology adoption risks and the significant costs associated with developing and implementing research and development internally. 
+Although in the aggregate our patents, licenses, and strategic partnerships are important to us, we do not regard any single patent, license, or strategic partnership as critical or essential to our business as a whole. In general, we depend on our technological capabilities, customer service-oriented culture, and application of our know-how to distinguish ourselves from our competitors, rather than our right to exclude others through patents or exclusive licenses. We also consider the quality and timely delivery of our products, the service we provide to our customers, and the technical knowledge and skill of our personnel to be more important than our registered intellectual property in our ability to compete. 
+4 
+Risk Management and Insurance 
+Our operations are subject to hazards inherent in the oil and natural gas industry, including, but not limited to, accidents, blowouts, explosions, craterings, fires, oil spills, and hazardous materials spills. These conditions can cause personal injury or loss of life; damage to, or destruction of, property, the environment, and wildlife; and the suspension of our or our customers’ operations. 
+In addition, claims for loss of oil and gas production and damage to formations can occur in the oilfield services industry. If a serious accident were to occur at a location where our equipment and services are being used, it could result in us being named as a defendant in lawsuits asserting large claims. 
+Because our business involves the transportation of heavy equipment and materials, we may also experience traffic accidents which may result in spills, property damage, and personal injury. 
+Despite our efforts to maintain high safety standards, from time to time, we have suffered accidents, and there is a risk that we will experience accidents in the future. In addition to the property and personal losses from these accidents, the frequency and severity of these incidents affect our operating costs, insurability, and relationships with customers, employees, and regulatory agencies. In particular, in recent years many of our large customers have placed an increased emphasis on the safety records of their service providers. Any significant increase in the frequency or severity of these incidents, or the general level of compensatory payments, could adversely affect the cost of, or our ability to obtain, workers’ compensation and other forms of insurance and could have other material adverse effects on our financial condition and results of operations. 
+We maintain insurance coverage of types and amounts that we believe to be customary in the industry including workers’ compensation, employer’s liability, claims based pollution, umbrella, comprehensive commercial general liability, business automobile, and property. Our insurance coverage may be inadequate to cover our liabilities. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable and commercially justifiable or on terms as favorable as our current arrangements. 
+We endeavor to allocate potential liabilities and risks between the parties in our Master Service Agreements (“MSAs”). We retain the risk for any liability not indemnified by our customers in excess of our insurance coverage. These MSAs delineate our and our customers’ respective warranty and indemnification obligations with respect to the services we provide. We endeavor to negotiate MSAs with our customers that provide, among other things, that we and our customers assume (without regard to fault) liability for damages to our respective personnel and property. For catastrophic losses, we endeavor to negotiate MSAs that include industry-standard carve-outs from the knock-for-knock indemnities. Additionally, our MSAs often provide carve-outs to the “without regard to fault” concept that would permit, for example, us to be held responsible for events of catastrophic loss only if they arise as a result of our gross negligence or willful misconduct. Our MSAs typically provide for industry-standard pollution indemnities, pursuant to which we assume liability for surface pollution associated with our equipment and originating above the surface (without regard to fault), and our customer assumes (without regard to fault) liability arising from all other pollution, including, without limitation, underground pollution and pollution emanating from the wellbore as a result of an explosion, fire, or blowout. This description of our MSAs is a summary of the material terms of the typical MSA that we have in place and does not reflect every MSA that we have entered into or may enter into in the future, some of which may contain indemnity structures and risk allocations between our customers and us that are different than those described here. 
+Employees 
+As of December 31, 2019 , we had 1,469 employees. We are not a party to any collective bargaining agreements. 
+Government Regulations and Environmental, Health, and Safety Matters 
+Our operations are subject to numerous stringent and complex laws and regulations at the U.S. federal, state, and local levels governing the discharge of materials into the environment, environmental protection, and health and safety aspects of our operations. In addition, due to our operations in Canada, we are subject to Canadian environmental statutes and regulations. Failure to comply with these laws and regulations or to obtain or comply with permits may result in the assessment of administrative, civil, and criminal penalties, imposition of remedial or corrective action requirements, and the imposition of injunctions or other orders to prohibit certain activities, restrict certain operations, or force future compliance with environmental requirements. 
+There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons, other hazardous substances, and wastes, as a result of air emissions and 
+5 
+wastewater discharges related to our operations, and because of historical operations and waste disposal practices. Spills or other releases of regulated substances, including such spills and releases that occur in the future, could expose us to material losses, expenditures, and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. 
+The following is a summary of some of the existing laws, rules, and regulations to which we are subject. 
+Hazardous Substances and Waste Handling 
+The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Under the guidance issued by the U.S. Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. We are required to manage the disposal of hazardous and non-hazardous wastes in compliance with RCRA and analogous state laws. RCRA currently exempts many E&P wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes intrinsically associated with the exploration, development, or production of crude oil and natural gas. However, these oil and gas E&P wastes may still be regulated under state solid waste laws and regulations, and it is possible that certain oil and natural gas E&P wastes now classified as non-hazardous could be classified as hazardous waste in the future. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain E&P related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree required the EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. On April 23, 2019, the EPA determined that a revision of the regulations was not necessary. Stricter regulation of wastes generated during our or our customers’ operations could result in increased costs for our operations or the operations of our customers, which could in turn reduce demand for our services and adversely affect our business. 
+Comprehensive Environmental Response, Compensation, and Liability Act 
+The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owner or operator of the site where the release occurred and anyone who transported or disposed or arranged for the transport or disposal of a hazardous substance released at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA and any state analogs may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources and for the costs of certain health studies. We currently own, lease, or operate numerous properties that have been used for manufacturing and other operations for many years. These properties and the substances disposed or released on them may be subject to CERCLA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. 
+Worker Health and Safety 
+We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”), establishing requirements to protect the health and safety of workers. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require maintenance of information about hazardous materials used or produced in operations and provision of this information to employees, state and local government authorities, and citizens. In June 2016, OSHA finalized a new regulation regarding crystalline silica exposures, which included requirements that hydraulic fracturing operations implement dust controls to limit exposures to the substance by June 23, 2021. Additionally, the Federal Motor Carrier Safety Administration (the “FMCSA”) regulates and provides safety oversight of commercial motor vehicles, the EPA establishes requirements to protect human health and the environment, the federal Bureau of Alcohol, Tobacco, Firearms and Explosives establishes requirements for the safe use and storage of explosives, and the federal Nuclear Regulatory Commission establishes requirements for the protection against ionizing radiation. Substantial fines and penalties can be imposed, and orders or injunctions limiting or prohibiting certain operations may be issued, in connection with any failure to comply with these laws and regulations. 
+6 
+Transportation Safety and Compliance 
+Due to operating a fleet in excess of 750 commercial motor vehicles, we are subject to a number of federal and state laws and regulations, including the Federal Motor Carrier Safety Regulations and Hazardous Material Regulations for interstate travel and comparable state regulations for intrastate travel. Substantial fines and penalties can be imposed and orders or injunctions limiting or prohibiting certain operations may be issued in connection with any failure to comply with laws and regulations relating to the safe operation of commercial motor vehicles. 
+Water Discharges 
+The Federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters, including jurisdictional wetlands, is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. In September 2015, a new EPA and U.S. Army Corps of Engineers (the “Corps”) rule defining the scope of federal jurisdiction over wetlands and other waters became effective; however, this rule was repealed on October 22, 2019. On January 23, 2020, the EPA and the Corps issued a final rule re-defining the term “waters of the United States” as applied under the Clean Water Act and narrowing the scope of waters subject to federal regulation. This 2020 rule is subject to various pending legal challenges. Future implementation of this final rule is uncertain at this time. To the extent a future rule expands the range of properties subject to the Clean Water Act’s jurisdiction, certain energy companies could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas, which in turn could reduce demand for our services. The process for obtaining permits has the potential to delay our operations and those of our customers. Spill prevention, control, and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture, or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of wastewater and storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. The Clean Water Act and analogous state laws provide for administrative, civil, and criminal penalties for unauthorized discharges and, together with the Oil Pollution Act of 1990, impose rigorous requirements for spill prevention and response planning, as well as substantial potential liability for the costs of removal, remediation, and damages in connection with any unauthorized discharges. 
+Air Emissions 
+The federal Clean Air Act (the “CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. These regulations change frequently. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements, or utilize specific equipment or technologies to control emissions of certain pollutants. For example, in May 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements. In addition, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. In November 2017, the EPA published a list of areas that are in compliance with the new ozone standard and, separately in December 2017, issued responses to state recommendations for designating non-attainment areas. The EPA completed all initial area designations in July 2018. State implementation of the revised NAAQS could result in stricter permitting requirements, which in turn could delay or impair our or our customers’ ability to obtain air emission permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties, as well as injunctive relief, for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. 
+Climate Change 
+The EPA has determined that emissions of greenhouse gases, including carbon dioxide and methane, present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. The EPA has established greenhouse gas emission reporting requirements for sources in the oil and gas sector and has also promulgated rules requiring certain large stationary sources of greenhouse gases to obtain preconstruction permits under the CAA and follow “best available control technology” requirements. Although we are not likely to become subject to greenhouse gas emissions permitting and best available control technology requirements 
+7 
+because none of our facilities are presently major sources of greenhouse gas emissions, such requirements could become applicable to our customers and could have an adverse effect on their costs of operations or financial performance, thereby adversely affecting our business, financial condition, and results of operations. 
+In December 2015, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change resulted in 195 countries, including the United States, coming together to develop the Paris Agreement, which calls for the parties to undertake “ambitious efforts” to limit the average global temperature. The Paris Agreement went into effect on November 4, 2016 and establishes a framework for the parties to cooperate and report actions to reduce greenhouse gas emissions. The United States formally announced its intent to withdraw from the Paris Agreement on November 4, 2019, with withdrawal becoming effective on November 4, 2020. 
+Also, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, and many states have already established regional greenhouse gas “cap-and-trade” programs. The adoption of any legislation or regulation that restricts emissions of greenhouse gases from the equipment and operations of our customers or with respect to the oil and natural gas they produce could adversely affect demand for our products and services. Finally, most scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that could have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if such effects were to occur, they could have an adverse impact on our operations. 
+Hydraulic Fracturing 
+Our businesses are dependent on hydraulic fracturing and horizontal drilling activities. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. 
+There is considerable uncertainty surrounding regulation of the emissions of methane, which may be released during hydraulic fracturing. In 2016, the EPA issued final regulations under the CAA establishing performance standards, including standards for the capture of methane emissions released during hydraulic fracturing. However, the EPA has taken several steps to delay implementation of its methane standards, including most recently in September 2018, when the EPA announced a proposed rule that rolls back parts of the 2016 performance standards. Various industry and environmental groups have separately challenged both the original standards and the EPA’s attempts to delay implementation of the rule. Separately, in August 2019, the EPA issued proposed amendments that would rescind requirements related to the regulations of methane emissions from the oil and natural gas industry. Neither rulemaking has been finalized to date and, therefore, the scope of future obligations continues to remain uncertain. In addition, in April 2018, a coalition of states filed a lawsuit in the U.S. District Court for the District of Columbia aiming to force the EPA to establish guidelines for limiting methane emissions from existing sources in the oil and natural gas sector; that lawsuit is pending. On March 20, 2015, the U.S. Bureau of Land Management (the “BLM”) finalized a rule regulating hydraulic fracturing activities on federal lands, including requirements for the disclosure, wellbore integrity, and handling of flowback water; however, on December 29, 2017, the BLM issued a rescission of the hydraulic fracturing rule. This rescission and the rule as promulgated are subject to ongoing litigation. The BLM also previously finalized in 2016 similar limitations on methane emissions from venting and flaring and leaking equipment from oil and natural gas activities on public lands, but in September 2018 issued a final rule repealing certain provisions of the 2016 rule and reinstating the pre-2016 regulations. This repeal is the subject of legal challenges. As a result, future implementation of both the EPA and BLM methane rules is uncertain at this time. However, given the long-term trend towards increasing regulation, future federal regulation of methane and other greenhouse gas emissions from the oil and gas industry remain a possibility. 
+The EPA has also issued effluent limitation guidelines that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. These rules were finalized in June 2016. The EPA conducted a study on effluent guidelines for the oil and gas industry, and a draft of this study was published in May 2019. It is unclear how any additional federal regulation of hydraulic fracturing activities may affect our operations, but additional regulatory burdens on our customers could ultimately result in decreased demand for our services. 
+Various studies analyzing the potential environmental impacts of hydraulic fracturing have also been performed. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking 
+8 
+water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. As described elsewhere in this Annual Report, these risks are regulated under various state, federal, and local laws. 
+Some states, counties, and municipalities have enacted or are considering moratoria on hydraulic fracturing. For example, New York, Vermont, Maryland, and Washington have banned, or are in the process of banning, the use of high-volume hydraulic fracturing. Alternatively, some municipalities are, or have considered, zoning and other ordinances, the conditions of which could impose a de facto ban on drilling and/or hydraulic fracturing operations. Further, some states, counties, and municipalities are closely examining water use issues, such as permit and disposal options for processed water, which could have a material adverse impact on our financial condition, prospects, and results of operations if such additional permitting requirements are imposed upon our industry. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could reduce demand for our business by making it more difficult or costly for certain customers to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, the business and operations of our customers could be subject to additional permitting requirements, attendant permitting delays, increased operating and compliance costs and process prohibitions, which could have an adverse effect on our business, financial condition, and results of operations. 
+In light of concerns about seismic activity being triggered by the injection of produced waters into underground wells, certain regulators are also considering additional requirements related to seismic safety for hydraulic fracturing activities. A 2015 U.S. Geological Survey report identified eight states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. Any regulation that restricts the ability of our customers to dispose of produced waters or increases their cost of doing business could cause them to curtail operations, which in turn could decrease demand for our services and have a material adverse effect on our business. 
+National Environmental Policy Act 
+Businesses and operations of our customers that are carried out on federal lands may be subject to the National Environmental Policy Act (“NEPA”), which requires federal agencies, including the Department of the Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect, and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. On January 10, 2020, the Council on Environmental Quality issued a proposed rule designed to streamline approvals for projects under NEPA. Among other revisions, the proposed rule would redefine environmental “effects” or “impacts” as the effects “that are reasonably foreseeable and have a reasonably close causal relationship to the proposed action or alternatives.” The proposed rule would also eliminate the current “direct,” “indirect,” or “cumulative” categories of effects. This rulemaking process is ongoing. To the extent that our customers’ current activities, as well as proposed plans, on federal lands require governmental permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects. 
+Endangered Species Act 
+The Endangered Species Act was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or its habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. If our customers were to have areas within their business and operations designated as critical or suitable habitat or a protected species, it could decrease demand for our services and have a material adverse effect on our business. 
+9
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+Item 13. 
+Certain Relationships and Related Transactions, and Director Independence 
+The information required in response to this item will be set forth in our definitive proxy statement for the 2020 annual meeting of stockholders and is incorporated herein by reference.
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+Item 9A. 
+Controls and Procedures 
+Evaluation of Disclosure Controls and Procedures 
+Disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Exchange Act, is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC. As required by Rule 13a-15(b) under the Exchange Act, our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2019 . Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were not effective as of December 31, 2019 , due to the material weakness in internal control over financial reporting described below. 
+Management’s Report on Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act). Our internal control over financial reporting is a process designed under the supervision of our principal executive officer and principal financial officer, and effected by our board of directors, management, and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with GAAP. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+As of December 31, 2019 , our management assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework (2013). Based on its assessment using the COSO criteria, management has concluded that our internal control over financial reporting was not effective as of December 31, 2019 , due to the material weakness in internal control over financial reporting as described below. 
+As reported in Item 9A of our Annual Report on Form 10-K for the year ended December 31, 2018 , we did not design and maintain adequate controls to address the segregation of certain accounting duties related to journal entries, account reconciliations, and other accounting functions. Certain accounting personnel had the ability to prepare and post journal entries, as well as reconcile accounts, without an independent review by someone other than the preparer. Specifically, our internal controls were not designed or operating effectively to evidence that journal entries were appropriately recorded or were properly reviewed for validity, accuracy, and completeness. Immaterial misstatements were identified related to the inadequate segregation of accounting duties. This material weakness could result in misstatement of the aforementioned accounts and disclosures that would result in a material misstatement in our annual or interim consolidated financial statements that would not be prevented or detected on a timely basis. 
+Remediation Efforts to Address the Material Weakness 
+In response to the material weakness identified above, our management has performed the following: 
+• 
+Replaced the less sophisticated accounting systems used by the majority of our newly acquired subsidiaries with the enterprise resource planning system used by the majority of our existing subsidiaries. 
+• 
+Hired additional resources, including an experienced Internal Audit Director to lead the Company’s internal audit department, with responsibility for direction and oversight of all internal audit functions. 
+In addition, our management is in the process of performing the following: 
+• 
+Continuing to develop and implement additional controls and procedures and enhance existing controls and procedures to ensure the segregation of certain accounting duties related to journal entries, account reconciliations, and other accounting functions. 
+Until the remediation steps listed set forth above are fully developed, implemented, and operating for a sufficient amount of time to validate the remediation, the material weakness described above will continue to exist. 
+Attestation Report of the Independent Registered Public Accounting Firm 
+This Annual Report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Management’s report on internal control over financial reporting was not subject to attestation by our independent registered public accounting firm pursuant to rules of the SEC that permit us to provide only management’s report in this Annual Report. 
+Changes in Internal Control over Financial Reporting 
+There have been no changes in our internal control over financial reporting that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting during the quarterly period ended December 31, 2019 .
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+15. Related Party Transactions 
+During 2014, in conjunction with an exercise of warrants to provide a capital infusion, the Company issued promissory notes totaling $2.5 million to both a former executive officer of the Company and a current manager of the Company. The principal was due on June 30, 2019 (the “Maturity Date”), and interest of 4% per annum had been due and was payable on the Maturity Date. During the fourth quarter of 2018, the Company received full payment on the notes, resulting in no outstanding balance and no unpaid interest at December 31, 2018 . 
+As part of the acquisition of Crest Pumping Technologies, LLC (“Crest”) in 2014, the Company issued promissory notes totaling $9.4 million to former owners of Crest, including David Crombie, who is an executive officer of the Company. The principal was due on June 30, 2019 . The interest rate was based on the prime rate, the federal funds rate, or LIBOR, plus a margin to be determined in connection with the Company’s credit agreement and was due quarterly. Mr. Crombie paid $1.8 million during 2016 to pay his promissory note in full. At December 31, 2018 , the outstanding principal balance of the notes of the remaining individuals totaled $7.6 million and unpaid interest, included in “Prepaid expenses and other current assets” in the Company’s Consolidated Balance Sheets , totaled $10,000 . During the second quarter of 2019, the Company received the full principal balance of the notes outstanding as well as all unpaid interest. 
+The Company leases office space, yard facilities, and equipment and purchases building maintenance services from entities owned by Mr. Crombie. Total lease expense and building maintenance expense associated with these entities was $0.8 million , $0.8 million , and $0.8 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively. The Company also purchased of equipment of $1.4 million and $1.0 million for the years ended December 31, 2019 and 2018 , respectively, from an entity in which Mr. Crombie is a limited partner. There were outstanding payables due to this entity relating to equipment purchases of $0.1 million at the year ended December 31, 2019 . 
+In addition, the Company leases office space in Corpus Christi and Midland, Texas from an entity affiliated with Lynn Frazier, a beneficial owner of more than 5% of the Company’s stock. Total rental expense associated with this office space was $1.5 million and $0.2 million for the years ended December 31, 2019 and 2018 , respectively. 
+At December 31, 2018, the Company had an open receivable due from the sellers of Magnum primarily attributed to sales commissions paid to an intercompany entity that was not included in the Magnum Acquisition. The Company received payment in full in the first quarter of 2019. 
+The Company provides services to Citation Oil & Gas Corp. (“Citation”), an entity owned by a director of the Company. The Company billed $0.4 million , $0.7 million , and $0.7 million for services provided to Citation during the years ended December 31, 2019 , 2018 , and 2017 , respectively. There was an outstanding receivable due from Citation of $0.1 million as of December 31, 2018 . 
+The Company provides services to EOG Resources, Inc. (“EOG”). Gary L. Thomas, a director of the Company, acted as the President of EOG until his retirement on December 31, 2018. The Company generated revenue from EOG of $45.0 million and $34.4 million during the years ended December 31, 2018 and 2017 , respectively. There was an outstanding receivable due from EOG of $7.0 million at December 31, 2018 . 
+The Company purchases cable for its wireline trucks from an entity owned by Forum Energy Technologies (“Forum”). Two of the Company’s directors also serve as directors of Forum. The Company was billed $1.9 million , $1.7 million , and $1.2 million for cable during the years ended December 31, 2019 , 2018 , and 2017 , respectively. There was an outstanding payable due to the entity of $0.3 million and $0.1 million at December 31, 2019 and 2018 , respectively. The Company purchases coiled tubing string from another entity owned by Forum. The Company was billed $8.0 million , $8.1 million , and $5.0 million for coiled tubing string during the years ended December 31, 2019 , 2018 , and 2017 , respectively. There was an outstanding payable due to the entity of $0.9 million on December 31, 2019 . 
+The Company purchases chemical additives used in cementing from Select Energy Services, Inc. (“Select”). One of the Company’s directors also serves as a director of Select. The Company was billed $2.1 million , $2.0 million , and $1.8 million for chemicals during the years ended December 31, 2019 , 2018 , and 2017 , respectively. There was an outstanding payable due to Select of $0.1 million at December 31, 2019. 
+During the fourth quarter of 2019, the Company sold coiled tubing equipment for $5.9 million to National Energy Services Reunited (“NESR”). One of the Company’s directors also serves as a director of NESR. In 2019, the Company provided $0.9 million of products and rentals to NESR. At December 31, 2019, there was a receivable of $6.8 million for the coiled tubing equipment and the products and services. 
+On June 5, 2019, Ann G. Fox, President and Chief Executive Officer and a director of the Company, was elected as a director of Devon Energy Corporation (“Devon”). The Company generated revenue from Devon of $18.4 million for the year ended December 31, 2019 . There was an outstanding receivable due from Devon of $1.0 million at December 31, 2019 . 
+F-36
\ No newline at end of file
diff --git a/raw/filings/0001532286/2019/0001532286-20-000005/rpt_disclosure.txt b/raw/filings/0001532286/2019/0001532286-20-000005/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..cdc4668ebbe6fbee4ac451a06d95ae36d1d81c67
--- /dev/null
+++ b/raw/filings/0001532286/2019/0001532286-20-000005/rpt_disclosure.txt
@@ -0,0 +1,48 @@
+CERTAIN RELATIONSHIPS AND RELATED PERSON TRANSACTIONS 
+Our Board adopted a written related person transactions policy prior to the completion of our IPO, under which a “Related Person
+Transaction” is defined pursuant to Item 404 of Regulation S-K. Pursuant to this policy, the Audit Committee expects to review all material facts of all Related Person Transactions and either approve or
+disapprove entry into the Related Person Transaction, subject to certain limited exceptions. 
+In determining whether to approve or
+disapprove entry into a Related Person Transaction, the Audit Committee expects to take into account, among other factors, the following: (i) whether the Related Person Transaction is on terms no less favorable than terms generally available to
+an unaffiliated third-party under the same or similar circumstances and (ii) the extent of the Related Person’s interest in the transaction. Further, the policy would require that all Related Person Transactions required to be disclosed in
+our filings with the SEC be so disclosed in accordance with applicable laws, rules and regulations. 
+During 2014, in conjunction with an
+exercise of warrants to provide a capital infusion, the Company issued promissory notes totaling $2.5 million to both a former executive officer of the Company and a current manager of the Company. The principal was due on June 30, 2019
+(the “Maturity Date”), and interest of 4% per annum had been due and was payable on the Maturity Date. During the fourth quarter of 2018, the Company received full payment on the notes, resulting in no outstanding balance and no unpaid
+interest at December 31, 2018. 
+As part of the acquisition of Crest Pumping Technologies, LLC (“Crest”) in 2014, the
+Company issued promissory notes totaling $9.4 million to former owners of Crest, including David Crombie, who is an executive officer of the Company. The principal was due on June 30, 2019. The interest rate was based on the prime rate,
+the federal funds rate, or LIBOR, plus a margin to be determined in connection with the Company’s credit agreement and was due quarterly. Mr. Crombie paid $1.8 million during 2016 to pay his promissory note in full. At
+December 31, 2018, the outstanding principal balance of the notes of the remaining individuals totaled $7.6 million and unpaid interest, included in “Prepaid expenses and other current assets” in the Company’s Consolidated
+Balance Sheets, totaled $10,000. During the second quarter of 2019, the Company received the full principal balance of the notes outstanding as well as any unpaid interest. 
+The Company leases office space, yard facilities, and equipment and purchases building maintenance services from entities owned by
+Mr. Crombie. Total lease expense and building maintenance expense associated with these entities was $0.8 million, $0.8 million, and $0.8 million for the years ended December 31, 2019, 2018, and 2017, respectively. The
+Company also purchased of equipment of $1.4 million and $1.0 million for the years ended December 31, 2019 and 2018, respectively, from an entity in which Mr. Crombie is a limited partner. There were outstanding payables due to
+this entity relating to equipment purchases of $0.1 million at the year ended December 31, 2019. 
+In addition, the Company
+leases office space in Corpus Christi and Midland, Texas from an entity affiliated with Lynn Frazier, a beneficial owner of more than 5% of the Company’s stock. Total rental expense associated with this office space was $1.5 million and
+$0.2 million for the years ended December 31, 2019 and 2018, respectively. 
+At December 31, 2018, the Company had an open
+receivable due from the sellers of Magnum primarily attributed to sales commissions paid to an intercompany entity that was not included in the Magnum Acquisition. The Company received payment in full in the first quarter of 2019. 
+The Company provides services to Citation Oil & Gas Corp. (“Citation”), an entity owned by a director of the Company. The
+Company billed $0.4 million, $0.7 million, and $0.7 million for services provided to Citation during the years ended December 31, 2019, 2018, and 2017, respectively. There was an outstanding receivable due from Citation of
+$0.1 million as of December 31, 2018. 
+37 
+Table of Contents 
+The Company provides services to EOG Resources, Inc. (“EOG”). Gary L. Thomas, a
+director of the Company, acted as the President of EOG until his retirement on December 31, 2018. The Company generated revenue from EOG of $45.0 million and $34.4 million during the years ended December 31, 2018 and 2017,
+respectively. There was an outstanding receivable due from EOG of $7.0 million at December 31, 2018. 
+The Company purchases
+cable for its wireline trucks from an entity owned by Forum Energy Technologies (“Forum”). Two of the Company’s directors also serve as directors of Forum. The Company was billed $1.9 million, $1.7 million, and
+$1.2 million for cable during the years ended December 31, 2019, 2018, and 2017, respectively. There was an outstanding payable due to the entity of $0.3 million and $0.1 million at December 31, 2019 and 2018, respectively.
+The Company purchases coiled tubing string from another entity owned by Forum. The Company was billed $8.0 million, $8.1 million, and $5.0 million for coiled tubing string during the years ended December 31, 2019, 2018, and 2017,
+respectively. There was an outstanding payable due to the entity of $0.9 million on December 31, 2019. 
+The Company purchases
+chemical additives used in cementing from Select Energy Services, Inc. (“Select”). One of the Company’s directors also serves as a director of Select. The Company was billed $2.1 million, $2.0 million, and $1.8 million
+for chemicals during the years ended December 31, 2019, 2018, and 2017, respectively. There was an outstanding payable due to Select of $0.1 million at December 31, 2019. 
+During the fourth quarter of 2019, the Company sold coiled tubing equipment for $5.9 million to National Energy Services Reunited
+(“NESR”). One of the Company’s directors also serves as a director of NESR. In 2019, the Company provided $0.9 million of products and rentals to NESR. At December 31, 2019, there was a receivable of $6.8 million for
+the coiled tubing equipment and the products and services. 
+On June 5, 2019, Ann G. Fox, President and Chief Executive Officer and a
+director of the Company, was elected as a director of Devon Energy Corporation (“Devon”). The Company generated revenue from Devon of $18.4 million for the year ended December 31, 2019. There was an outstanding receivable due
+from Devon of $1.0 million at December 31, 2019.
\ No newline at end of file
diff --git a/raw/filings/0001532286/2020/0001532286-21-000006/filing_metadata.csv b/raw/filings/0001532286/2020/0001532286-21-000006/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..1b413afebb5a97dfbcaca130f6225a985f6d7593
--- /dev/null
+++ b/raw/filings/0001532286/2020/0001532286-21-000006/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0001532286,NINE,"Nine Energy Service, Inc.",10-K,2021-03-08,2020-12-31,2021-03-08T11:08:12.000Z,0001532286-21-000006,nine-20201231.htm,10-K,10386911,1,1,https://www.sec.gov/Archives/edgar/data/1532286/000153228621000006/nine-20201231.htm,https://www.sec.gov/Archives/edgar/data/1532286/000153228621000006/,2020,2020,1
diff --git a/raw/filings/0001532286/2020/0001532286-21-000006/item1.txt b/raw/filings/0001532286/2020/0001532286-21-000006/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..97f579debab57e14f48fbde657e7d2495b40a745
--- /dev/null
+++ b/raw/filings/0001532286/2020/0001532286-21-000006/item1.txt
@@ -0,0 +1,104 @@
+Item 1. Business 
+Overview 
+Nine Energy Service, Inc. (either individually or together with its subsidiaries, as the context requires, the “Company,” “Nine,” “we,” “us,” and “our”) is a Delaware corporation that was formed in February 2013 through a combination of three service companies owned by SCF Partners, L.P. or its affiliates. Nine is a leading completion services provider that targets unconventional oil and gas resource development across all North American basins and abroad. We partner with our exploration and production (“E&P”) customers to design and deploy downhole solutions and technology to prepare horizontal, multistage wells for production. We focus on providing our customers with cost-effective and comprehensive completion solutions designed to maximize their production levels and operating efficiencies. We believe our success is a product of our culture, which is driven by our intense focus on performance and wellsite execution as well as our commitment to forward-leaning technologies that aid us in the development of smarter, customized applications that drive efficiencies. 
+We provide our comprehensive completion solutions across a diverse set of well-types, including on the most complex, technically demanding unconventional wells. Modern, high-intensity completion techniques are a more effective way for our customers to maximize resource extraction from horizontal oil and gas wells. These completion techniques provide improved estimated ultimate recovery per lateral foot and a superior return on investment by decreasing cycle time, which make them attractive to operators despite their associated increased well cost. We compete for the most intricate and demanding projects, which are characterized by extended reach horizontal laterals, increased stage counts per well, multi-well pad development, and increased proppant loading per lateral foot. As stage counts per well and wells per pad increase, so do our operating leverage and returns, as we are able to complete more jobs and stages with the same number of units and crews. Service providers for these demanding projects are selected based on their technical expertise and ability to execute safely and efficiently, rather than only price. As our customers continue to improve operational efficiencies in completions design, increasing its complexity and difficulty, oilfield service selection becomes much more critical and selective. 
+We offer a variety of completion applications and technologies to match customer needs across the broadest addressable completions market. Our comprehensive well solutions range from cementing the well at the initial stages of the completion, preparing the well for stimulation, isolating all the stages of an extended reach lateral, and the drilling out of isolation tools. Our completion techniques are specifically tailored to the customer and geology of each well. At the initial stage of a well completion, our lab facilities produce customized cementing slurries used to secure the production casing to ensure well integrity throughout the life of the well. Once the casing is in place, we utilize our proprietary tools at the toe (end) of the well, often called stage one, to prepare for the well stimulation process. Following stage one, we perform plug-and-perf completions using a wireline truck and reel, as well as our composite or dissolvable frac plugs. We also offer a pinpoint frac sleeve system technology to complete the remaining stages of the well. Through our wireline units, we provide plug-and-perf services that, when combined with our fully-composite or dissolvable frac plugs, create perforations to isolate and divert the fracture to the correct stage. Our completion tool technology focuses on composite and dissolvable frac plugs that isolate stages in a completion but also includes a number of other patented technologies sold in North America and abroad. Our equipment also includes large-diameter coiled tubing units that are capable of reaching the farthest depths for the removal of plugs and cleaning of the wellbore to prepare for production. 
+Our website is located at https://nineenergyservice.com, and our investor relations website is located at https://investor.nineenergyservice.com. The information posted on our website is not incorporated into this Annual Report. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to reports filed or furnished pursuant to Sections 13(a) and 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are available free of charge on our investor relations website as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (the “SEC”). You may also access all of our public filings through the SEC’s website at www.sec.gov. Investors and other interested parties should note that we use our investor relations website to publish important information about us, including information that may be deemed material to investors. We encourage investors and other interested parties to review the information we may publish through our investor relations website, in addition to our SEC filings, press releases, conference calls, and webcasts. 
+Our Services 
+We derive revenue by providing services integral to the completion of unconventional wells through a full range of tools and methodologies. The following is a description of our primary service offerings and deployment methods: 
+Cementing Services: Our cementing services consist of blending high-grade cement and water with various solid and 
+3 
+liquid additives to create a cement slurry that is pumped between the casing and the wellbore of the well. We currently operate four high-quality laboratory facilities capable of designing and testing all of the current industry cement designs. The laboratory facilities operate twenty-four hours a day and are fully staffed by qualified technicians with the latest equipment and modeling software. Additionally, our technicians and engineers ensure that all tests are performed to American Petroleum Institute specifications and results are delivered to customers promptly. Our cement slurries are designed to achieve the proper cement thickening time, compressive strength, and fluid loss control. Our slurries can be modified to address a wide range of downhole needs of our E&P customers, including varying well depths, downhole temperatures, pressures, and formation characteristics. 
+We deploy our slurries by using our customized design twin-pumping units, which are fully redundant, containing two pumps, two hydraulic systems, two mixing pumps, and two electrical systems. This customized design significantly decreases our risk of downtime due to mechanical failure and eliminates the necessity to have an additional cementing unit on standby. We have invested in the highest quality cementing equipment, and since 2012, we have deployed only new equipment for use in the fields. As of December 31, 2020, we had a total of 40 pumping units. 
+From January 2014 through December 2020, we completed approximately 22,000 cementing jobs, with an on-time rate of approximately 91%. Punctuality of service has become one of the primary metrics that E&P operators use to evaluate the cementing services they receive. Key contributors to our 91% on-time rate include our lab capabilities, personnel, close proximity to our customers’ acreage, dual-sided bulk loading plants, and our service-driven culture. 
+Completion Tools: We provide downhole solutions and technology used for multistage completions. Our comprehensive completion service offerings are mostly comprised of composite and dissolvable frac plugs in a variety of sizes to isolate stages during plug-and-perf operations. We have coupled patented tool designs with proprietary materials for our dissolvable offering, enabling us to serve the entire addressable plug market. With this ability, we have traditional and long-range plugs to address every type of wellbore situation. Our frac plug technology is complemented by our unconventional open hole and cemented completion tool products, such as liner hangers and accessories, fracture isolation packers, frac sleeves, stage one prep tools, casing flotation tools, specialty open hole float equipment, disk subs, composite cement retainers, and centralizers. 
+Our systems provide completion efficiencies at the wellsite by reducing our customers’ equipment needs and stimulation time and allowing for specific zonal treatment. Our dissolvable frac plugs help operators reduce cycle times to bring production online faster, decrease the amount of equipment and people needed on location, and significantly reduce carbon emissions compared to a traditional composite plug completion. Through these reductions in cycle time, our dissolvable plugs can help increase our customers’ internal rate of return and provide a safer and more efficient working environment. From January 2014 through December 2020, we deployed approximately 241,200 isolation, stage one, and casing flotation tools. 
+Wireline Services: Our wireline services involve the use of a wireline unit equipped with a spool of wireline that is unwound and lowered into oil and gas wells to convey specialized tools or equipment for well completion, well intervention, or pipe recovery. We operate a fleet of modern and “fit-for-purpose” cased hole wireline units designed for operating in unconventional completion operations. We currently operate 47 wireline pumpdown units in the United States (the “U.S.”). Our operation is equipped with the latest technology utilized to service long lateral completions, including head tension tools, ballistic release tools, and addressable switches. We currently have wireline units equipped with Coated Line, which is a coated wireline that significantly reduces injector oil use. Offering a lower dynamic coefficient of friction, Coated Line Wireline requires less pump down fluid to operate and is more conducive for reaching further depths in longer laterals. 
+The majority of our wireline work consists of plug-and-perf completions, which is a multistage well completion technique for cased-hole wells that consists of deploying perforating guns to a specified depth. We deploy proprietary specialized tools like our fully-composite and dissolvable frac plugs through our wireline units. From January 2014 through December 2020, we completed approximately 171,000 wireline stages with a success rate of approximately 99%. 
+Coiled Tubing Services: Coiled tubing services perform wellbore intervention operations utilizing a continuous steel pipe that is transported to the wellsite wound on a large spool in lengths of up to 30,000 feet. Coiled tubing provides a cost-effective solution for well work due to the ability to deploy efficiently and safely into a live well using specialized well-control equipment. The live well work capability limits the customer’s risk of formation damage associated with “killing” a well (the temporary placement of heavy fluids in a wellbore to keep reservoir fluids in place), while allowing for safer operations due to minimal equipment handling. Coiled tubing facilitates a variety of services in both new and old wells, such as milling, drilling, fishing, production logging, artificial lift, cementing, and stimulation. 
+We currently operate 14 coiled tubing units serving the Permian Basin and Haynesville markets. Our coiled tubing units carry data acquisition and dissemination technology, allowing our customers to monitor jobs via a web interface. Of the 14 coiled tubing units, we consider 12 to be “extended reach” units capable of reaching the toe of wells with total measured 
+4 
+depths of 24,000 feet and beyond, including lateral lengths in excess of 12,500 feet, keeping pace with the industry’s most challenging downhole environments. While we specialize in larger-diameter (2 3/8” and 2 5/8”) coiled tubing units, we also offer 2” and 1 1/4” diameter solutions to our customers. From April 2014 through December 2020, we have performed approximately 9,800 jobs and deployed more than 218 million running feet of coiled tubing, with a success rate of over 99%. 
+Well Services: On August 30, 2019, we sold our Production Solutions segment. For additional information on this divestiture, see Note 16 – Segment Information included in Item 8 of Part II of this Annual Report. 
+Geographic Areas of Operation 
+We operate in all major onshore basins in the U.S., including the Permian Basin, Marcellus and Utica Shales, Eagle Ford Shale, DJ Basin, SCOOP/STACK Formation, Bakken Formation, and Haynesville Formation as well as the Western Canada Sedimentary Basin in Canada. We provide our services through strategically placed operating facilities located in-basin throughout the U.S. This local presence allows us to quickly respond to customer demands and operate efficiently. Additionally, through our extensive footprint, we are able to track and implement best practices around completion trends and technology across all divisions and geography. 
+We believe that our strategic geographic diversity will benefit us as activity increases or decreases in select basins by helping to mitigate basin and commodity-risk. Our broad geographic footprint provides us with exposure to potential increases in drilling and completion activity and will allow us to opportunistically pursue new business in basins with the most active drilling environments. 
+Seasonality 
+Our operations are subject to seasonal factors, and our overall financial results reflect seasonal variations. Specifically, we typically have experienced a pause by our customers around the holiday season in the fourth quarter, which may be compounded as our customers exhaust their annual capital spending budgets towards year end. 
+Additionally, our operations are directly affected by weather conditions. During the winter months (portions of the first and fourth quarters) and periods of heavy snow, ice, or rain, particularly in the northeastern U.S., North Dakota, Rockies, and western Canada, our customers may delay operations or we may not be able to operate or move our equipment between locations. Also, during the spring thaw, which normally starts in late March and continues through June, some areas, primarily in western Canada, impose transportation restrictions to prevent damage caused by the spring thaw. Throughout the year, heavy rains adversely affect activity levels because well locations and dirt access roads can become impassible in wet conditions. Weather conditions may also negatively affect our customers activity levels. 
+Sales and Marketing 
+Our sales activities are conducted through a network of sales representatives and business development personnel, which provides us coverage at both the corporate and field level of our customers. We have a technical sales organization with expertise and focus within our specific service lines. Sales representatives work closely with local operations managers to target potential opportunities through strategic focus and planning. Customers are identified as targets based on their drilling and completion activity, geographic location, and economic viability. Our marketing activities are performed internally with input and guidance from a third-party marketing agency. Our strategy is based on building a strong brand though multiple media outlets including our website, select social media accounts, print and online advertisements, billboard advertisements, press releases and various industry-specific conferences, publications, and lectures. 
+Customers 
+Our customer base includes a broad range of integrated and independent E&P companies. For the year ended December 31, 2020, our top five customers collectively accounted for approximately 37% of our revenues. 
+Demand for our services and products is cyclical and substantially dependent upon activity levels in the oil and gas industry, particularly our customers’ willingness to spend capital on the exploration for and development of oil and natural gas. Our customers’ spending plans are generally based on their outlook for near-term and long-term commodity prices. As a result, the demand for our services and products is highly sensitive to current and expected commodity prices. 
+Competition 
+We provide our services and products across the U.S., Canada, and abroad, and we compete against different companies in each service and product line we offer. Our competition includes many large and small oilfield service companies, 
+5 
+including the largest integrated oilfield services companies. We believe that the principal competitive factors in the markets we serve are technology offerings, wellsite execution, service quality, technical expertise, equipment capacity, work force competency, efficiency, safety record, reputation, and experience. Additionally, projects are often awarded on a bid basis, which tends to create a highly competitive environment. We seek to differentiate our company from our competitors by delivering the highest-quality services, technology, and equipment possible, coupled with superior execution and operating efficiency in a safe working environment. By focusing on cultivating our existing customer relationships and maintaining our high standard of customer service, technology, safety, performance, and quality of crews, equipment, and services, we believe we are differentiated in a competitive market. 
+Our major competitors include Halliburton Company, Schlumberger Limited, NCS Multistage, NexTier Oilfield Solutions, KLX Energy Services Holdings, and a significant number of private and locally-oriented businesses. 
+Suppliers 
+We purchase a wide variety of raw materials, parts, and components that are manufactured and supplied for our operations from various suppliers. While we are not dependent on any single supplier for those materials, parts, or components, certain product lines depend on a limited number of third-party suppliers and vendors. During the year ended December 31, 2020, no supplier of the materials used in our services provided over 10% of our materials or equipment as a percentage of overall costs. 
+To date, we have generally been able to obtain the equipment, parts, and supplies necessary to support our operations on a timely basis. While we believe that we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers, we may not always be able to make alternative arrangements. In addition, certain materials for which we do not currently have long-term supply agreements could experience shortages and significant price increases in the future. As a result, we may be unable to mitigate any future supply shortages, and our results of operations, prospects, and financial condition could be adversely affected. 
+Research & Technology, Intellectual Property 
+Our sales and earnings are influenced by our ability to successfully introduce new or improved products and services to the market. We believe we have become a “go-to” provider for piloting new technologies because of our service quality and offering, execution at the wellsite, and geographic footprint. 
+Our engineering and technology efforts are focused on providing efficient and cost-effective solutions to maximize production for our customers across major North American onshore basins and abroad. We have dedicated resources focused on internally developing new technology and equipment and evolving our existing proprietary tools, as well as resources focused on sourcing and commercializing new technologies through mergers and acquisitions and strategic partnerships, to stay ahead of industry trends and achieve lower completion and production costs for our customers. 
+We have developed a suite of proprietary downhole tools, products, and techniques through both internal resources, as well as mergers and acquisitions and strategic partnerships with manufacturers and engineering companies looking for a reliable and expansive channel to market. In these partnerships, we have exclusive rights to market and sell technology unavailable to any other service providers in the designated regions, and we sell the technology directly to the customer and order from the manufacturer on an as-needed basis, with no minimum volume requirements and without having to hold excess inventory. These strategic partnerships provide us and our customers with access to unique downhole technology from independent innovators while allowing us to minimize exposure to potential technology adoption risks and the significant costs associated with developing and implementing research and development internally. 
+Although in the aggregate our patents, licenses, and strategic partnerships are important to us, we do not regard any single patent, license, or strategic partnership as critical or essential to our business as a whole. In general, we depend on our technological capabilities, customer service-oriented culture, and application of our know-how to distinguish ourselves from our competitors, rather than our right to exclude others through patents or exclusive licenses. We also consider the quality and timely delivery of our products, the service we provide to our customers, and the technical knowledge and skill of our personnel to be more important than our registered intellectual property in our ability to compete. 
+Risk Management and Insurance 
+Our operations are subject to hazards inherent in the oil and natural gas industry, including, but not limited to, accidents, blowouts, explosions, craterings, fires, oil spills, and hazardous materials spills. These conditions can cause personal injury or loss of life; damage to, or destruction of, property, the environment, and wildlife; and the suspension of our or our 
+6 
+customers’ operations. 
+In addition, claims for loss of oil and gas production and damage to formations can occur in the oilfield services industry. If a serious accident were to occur at a location where our equipment and services are being used, it could result in us being named as a defendant in lawsuits asserting large claims. 
+Because our business involves the transportation of heavy equipment and materials, we may also experience traffic accidents which may result in spills, property damage, and personal injury. 
+Despite our efforts to maintain high safety standards, from time to time, we have suffered accidents, and there is a risk that we will experience accidents in the future. In addition to the property and personal losses from these accidents, the frequency and severity of these incidents affect our operating costs, insurability, and relationships with customers, employees, and regulatory agencies. In particular, in recent years many of our large customers have placed an increased emphasis on the safety records of their service providers. Any significant increase in the frequency or severity of these incidents, or the general level of compensatory payments, could adversely affect the cost of, or our ability to obtain, workers’ compensation and other forms of insurance and could have other material adverse effects on our financial condition and results of operations. 
+We maintain insurance coverage of types and amounts that we believe to be customary in the industry including workers’ compensation, employer’s liability, claims based pollution, umbrella, comprehensive commercial general liability, business automobile, and property. Our insurance coverage may be inadequate to cover our liabilities. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable and commercially justifiable or on terms as favorable as our current arrangements. 
+We endeavor to allocate potential liabilities and risks between the parties in our Master Service Agreements (“MSAs”). We retain the risk for any liability not indemnified by our customers in excess of our insurance coverage. These MSAs delineate our and our customers’ respective warranty and indemnification obligations with respect to the services we provide. We endeavor to negotiate MSAs with our customers that provide, among other things, that we and our customers assume (without regard to fault) liability for damages to our respective personnel and property. For catastrophic losses, we endeavor to negotiate MSAs that include industry-standard carve-outs from the knock-for-knock indemnities. Additionally, our MSAs often provide carve-outs to the “without regard to fault” concept that would permit, for example, us to be held responsible for events of catastrophic loss only if they arise as a result of our gross negligence or willful misconduct. Our MSAs typically provide for industry-standard pollution indemnities, pursuant to which we assume liability for surface pollution associated with our equipment and originating above the surface (without regard to fault), and our customer assumes (without regard to fault) liability arising from all other pollution, including, without limitation, underground pollution and pollution emanating from the wellbore as a result of an explosion, fire, or blowout. This description of our MSAs is a summary of the material terms of the typical MSA that we have in place and does not reflect every MSA that we have entered into or may enter into in the future, some of which may contain indemnity structures and risk allocations between our customers and us that are different than those described here. 
+Employees 
+As of December 31, 2020, we had 735 employees, of which 733 were full-time. We are not a party to any collective bargaining agreements. 
+Coronavirus Pandemic 
+The worldwide coronavirus outbreak in early 2020, which was declared a pandemic by the World Health Organization in March 2020, the uncertainty regarding its impact, and various governmental actions taken to mitigate its impact have resulted in an unprecedented decline in demand for oil. In the midst of the ongoing pandemic, the Organization of the Petroleum Exporting Countries (“OPEC”) and other oil producing nations, including Russia (collectively, “OPEC+”), were initially unable to reach an agreement on production levels for crude oil, at which point Saudi Arabia and Russia initiated efforts to aggressively increase production. The convergence of these events created the unprecedented dual impact of a massive decline in the demand for oil coupled with the risk of a substantial increase in supply. While OPEC+ agreed in April 2020 to cut production, downward pressure on commodity prices has remained and could continue for the foreseeable future. 
+In response to lower oil prices, our customers have generally revised their capital budgets downward and adjusted their operations accordingly, which has caused a significant decline in demand for our products and services. 
+While we cannot predict the length of time that market disruptions resulting from the coronavirus pandemic and efforts to mitigate its effects will continue, the ultimate impact on our business, or the pace or extent of any subsequent recovery, we 
+7 
+expect the coronavirus pandemic and related effects to continue to have a material adverse impact on commodity prices and our business generally. We have experienced inefficiencies and logistical challenges surrounding stay-at-home orders and remote work arrangements, travel restrictions, and an inability to commute to certain facilities and job sites, as we provide services and products to our customers. For more information, see “Risk Factors – Risks Related to the Coronavirus Pandemic” in Item 1A of Part I and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – Impact of the Coronavirus Pandemic; Industry Trends and Outlook” in Item 7 of Part II of this Annual Report. 
+During the pandemic, we have maintained our commitment to the safety of our employees, customers, vendors, and community at large, and we have taken, and are continuing to take, a proactive approach to navigating the pandemic. To mitigate exposure and risk, we have implemented processes and procedures across our entire organization based on federal, regional, and local guidelines and mandates, and our Health, Safety & Environment and management teams are in frequent communication with our entire employee base to ensure they are receiving updated guidelines, processes, and procedures. In response to the pandemic, we have implemented the following changes, for example: at the field level, we are working closely with our customers and vendors to update standard operating procedures, based on social distancing, hand washing, and other recommended best practices set forth by the Centers for Disease Control and Prevention; electronic assessments have been employed to check the health of employees prior to reporting to work, to ensure facilities are being properly cleaned and sanitized, and to check visitor health before arrival to a Nine location; internal case managers have been identified to handle all coronavirus-related cases, and all confirmed and potential cases are tracked through closure; many of our corporate and office employees are working virtually to avoid unnecessary risk and exposure; and we have significantly limited any work-related travel. We are actively monitoring updates from regulatory and government bodies and evolving our strategy accordingly in an effort to keep our workforce and communities healthy. 
+Regulatory Matters 
+Our operations are subject to numerous stringent and complex laws and regulations at the U.S. federal, state, and local levels governing the discharge of materials into the environment, environmental protection, and health and safety aspects of our operations. In addition, due to our operations in Canada, we are subject to Canadian environmental statutes and regulations. Failure to comply with these laws and regulations or to obtain or comply with permits may result in the assessment of administrative, civil, and criminal penalties, imposition of remedial or corrective action requirements, and the imposition of injunctions or other orders to prohibit certain activities, restrict certain operations, or force future compliance with environmental requirements. 
+There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons, other hazardous substances, and wastes, as a result of air emissions and wastewater discharges related to our operations, and because of historical operations and waste disposal practices. Spills or other releases of regulated substances, including such spills and releases that occur in the future, could expose us to material losses, expenditures, and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. 
+The following is a summary of some of the existing laws, rules, and regulations to which we are subject. 
+Hazardous Substances and Waste Handling 
+The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Under the guidance issued by the U.S. Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. We are required to manage the disposal of hazardous and non-hazardous wastes in compliance with RCRA and analogous state laws. RCRA currently exempts many E&P wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes intrinsically associated with the exploration, development, or production of crude oil and natural gas. However, these oil and gas E&P wastes may still be regulated under state solid waste laws and regulations, and it is possible that certain oil and natural gas E&P wastes now classified as non-hazardous could be classified as hazardous waste in the future. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain E&P related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree required the EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations was not necessary. On April 23, 2019, the EPA determined that a revision of the regulations was not necessary. Stricter regulation of wastes generated during our or our customers’ operations could result in increased costs for our 
+8 
+operations or the operations of our customers, which could in turn reduce demand for our services and adversely affect our business. 
+Comprehensive Environmental Response, Compensation, and Liability Act 
+The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owner or operator of the site where the release occurred and anyone who transported or disposed or arranged for the transport or disposal of a hazardous substance released at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA and any state analogs may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources and for the costs of certain health studies. We currently own, lease, or operate numerous properties that have been used for manufacturing and other operations for many years. These properties and the substances disposed or released on them may be subject to CERCLA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. 
+Worker Health and Safety 
+We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”), establishing requirements to protect the health and safety of workers. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require maintenance of information about hazardous materials used or produced in operations and provision of this information to employees, state and local government authorities, and citizens. In June 2016, OSHA finalized a regulation regarding crystalline silica exposures, which included requirements that hydraulic fracturing operations implement dust controls to limit exposures to the substance by June 23, 2021. Additionally, the Federal Motor Carrier Safety Administration (the “FMCSA”) regulates and provides safety oversight of commercial motor vehicles, the EPA establishes requirements to protect human health and the environment, the federal Bureau of Alcohol, Tobacco, Firearms and Explosives establishes requirements for the safe use and storage of explosives, and the federal Nuclear Regulatory Commission establishes requirements for the protection against ionizing radiation. Substantial fines and penalties can be imposed, and orders or injunctions limiting or prohibiting certain operations may be issued, in connection with any failure to comply with these laws and regulations. 
+Transportation Safety and Compliance 
+At December 31, 2020, we operated a fleet in excess of 550 commercial motor vehicles. As such, we are subject to a number of federal and state laws and regulations, including the Federal Motor Carrier Safety Regulations and Hazardous Material Regulations for interstate travel and comparable state regulations for intrastate travel. Substantial fines and penalties can be imposed and orders or injunctions limiting or prohibiting certain operations may be issued in connection with any failure to comply with laws and regulations relating to the safe operation of commercial motor vehicles. 
+Water Discharges 
+The Federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the U.S. The discharge of pollutants into regulated waters, including jurisdictional wetlands, is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. In September 2015, the EPA and U.S. Army Corps of Engineers (the “Corps”) issued a rule defining the scope of federal jurisdiction over wetlands and other waters; however, this rule was repealed on October 22, 2019. On January 23, 2020, the EPA and the Corps issued the Navigable Waters Protection Rule re-defining the term “waters of the United States” as applied under the Clean Water Act and narrowing the scope of waters subject to federal regulation, and the final rule became effective on June 22, 2020. This Navigable Waters Protection Rule is subject to various pending legal challenges, and a federal district court in Colorado stayed implementation of the rule. The stay is limited to application of the rule in Colorado; the rule has taken effect in all other states. At President Biden’s direction, the EPA and the Corps requested the litigation be stayed while the agencies review the rule. To the extent a future rule expands the range of properties subject to the Clean Water Act’s jurisdiction, certain energy companies could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas, which in turn could reduce demand for our services. The process for obtaining permits has the potential to delay our operations and those of our customers. Spill prevention, control, and countermeasure requirements of federal laws require appropriate containment berms and similar 
+9 
+structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture, or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of wastewater and storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. The Clean Water Act and analogous state laws provide for administrative, civil, and criminal penalties for unauthorized discharges and, together with the Oil Pollution Act of 1990, impose rigorous requirements for spill prevention and response planning, as well as substantial potential liability for the costs of removal, remediation, and damages in connection with any unauthorized discharges. 
+Air Emissions 
+The federal Clean Air Act (the “CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. These regulations change frequently. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements, or utilize specific equipment or technologies to control emissions of certain pollutants. In addition, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. In November 2017, the EPA published a list of areas that are in compliance with the new ozone standard and, separately in December 2017, issued responses to state recommendations for designating non-attainment areas. The EPA completed all initial area designations in July 2018. State implementation of the revised NAAQS could result in stricter permitting requirements, which in turn could delay or impair our or our customers’ ability to obtain air emission permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties, as well as injunctive relief, for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. 
+Climate Change 
+The EPA has determined that emissions of greenhouse gases, including carbon dioxide and methane, present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. The EPA has established greenhouse gas emission reporting requirements for sources in the oil and gas sector and has also promulgated rules requiring certain large stationary sources of greenhouse gases to obtain preconstruction permits under the CAA and follow “best available control technology” requirements. Although we are not likely to become subject to greenhouse gas emissions permitting and best available control technology requirements because none of our facilities are presently major sources of greenhouse gas emissions, such requirements could become applicable to our customers and could have an adverse effect on their costs of operations or financial performance, thereby adversely affecting our business, financial condition, and results of operations. 
+In December 2015, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change resulted in nearly 200 countries, including the U.S., coming together to develop the Paris Agreement, which calls for the parties to undertake “ambitious efforts” to limit the average global temperature. Although the agreement does not create any binding obligations for nations to limit their greenhouse gas emissions, it does include pledges to voluntarily limit or reduce future emissions. On June 1, 2017, President Trump announced that the U.S. would withdraw from the Paris Agreement and that it would potentially seek to renegotiate the Paris Agreement on more favorable terms. The U.S. completed the process of withdrawing from the Paris Agreement on November 4, 2020. In response to the United States’ withdrawal announcement, various corporations, investors, and U.S. state and local governments publicly pledged to further the goals of the Paris Agreement. On January 20, 2021, President Biden issued written notification to the United Nations of the United States’ intention to rejoin the Paris Agreement, which became effective on February 19, 2021. 
+Also, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, and many states have already established regional greenhouse gas “cap-and-trade” programs. The adoption of any legislation or regulation that restricts emissions of greenhouse gases from the equipment and operations of our customers or with respect to the oil and natural gas they produce could adversely affect demand for our products and services. Finally, most scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that could have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if such effects were to occur, they could have an adverse impact on our operations. 
+Hydraulic Fracturing 
+Our businesses are dependent on hydraulic fracturing and horizontal drilling activities. Hydraulic fracturing is an 
+10 
+important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. 
+There is considerable uncertainty surrounding regulation of the emissions of methane, which may be released during hydraulic fracturing. In 2016, the EPA issued final regulations under the CAA establishing performance standards, including standards for the capture of methane emissions released during hydraulic fracturing. However, the EPA has taken several steps to delay implementation of its methane standards, including most recently in September 2020, when the EPA finalized the Reconsideration Rule that rolls back parts of the 2016 performance standards. Various industry and environmental groups have separately challenged both the original standards and the EPA’s attempts to delay implementation of the rule. Separately, in September 2020, the EPA finalized the Review Rule rescinding requirements related to the regulations of methane emissions from the oil and natural gas industry. Both rules are subject to ongoing litigation and, on January 20, 2021, President Biden issued an Executive Order directing the EPA to rescind the Reconsideration Rule by September 2021 and consider revising the Review Rule. Therefore, the scope of future obligations continues to remain uncertain. In addition, in April 2018, a coalition of states filed a lawsuit in the U.S. District Court for the District of Columbia aiming to force the EPA to establish guidelines for limiting methane emissions from existing sources in the oil and natural gas sector; that lawsuit is pending. On March 20, 2015, the U.S. Bureau of Land Management (the “BLM”) finalized a rule regulating hydraulic fracturing activities on federal lands, including requirements for the disclosure, wellbore integrity, and handling of flowback water; however, on December 29, 2017, the BLM issued a rescission of the hydraulic fracturing rule. This rescission and the rule as promulgated are subject to ongoing litigation. The BLM also previously finalized in 2016 similar limitations on methane emissions from venting and flaring and leaking equipment from oil and natural gas activities on public lands, but in September 2018 issued a final rule repealing certain provisions of the 2016 rule and reinstating the pre-2016 regulations. The 2016 rule and the rescission were invalidated by separate federal district courts. As a result, future implementation of methane rules by either the EPA or the BLM is uncertain at this time. However, given the long-term trend towards increasing regulation, future federal regulation of methane and other greenhouse gas emissions from the oil and gas industry remains a possibility. 
+The EPA has also issued effluent limitation guidelines that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. These rules were finalized in June 2016, and after a legal challenge by environmental groups, in July 2019, the EPA declined to revise the rules. The EPA conducted a study on effluent guidelines for the oil and gas industry, and a draft of this study was published in May 2019. It is unclear how any additional federal regulation of hydraulic fracturing activities may affect our operations, but additional regulatory burdens on our customers could ultimately result in decreased demand for our services. 
+Various studies analyzing the potential environmental impacts of hydraulic fracturing have also been performed. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. As described elsewhere in this Annual Report, these risks are regulated under various state, federal, and local laws. 
+Some states, counties, and municipalities have enacted or are considering moratoria on hydraulic fracturing. For example, New York, Vermont, Maryland, and Washington have banned, or are in the process of banning, the use of high-volume hydraulic fracturing. Alternatively, some municipalities are, or have considered, zoning and other ordinances, the conditions of which could impose a de facto ban on drilling and/or hydraulic fracturing operations. Further, some states, counties, and municipalities are closely examining water use issues, such as permit and disposal options for processed water, which could have a material adverse impact on our financial condition, prospects, and results of operations if such additional permitting requirements are imposed upon our industry. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could reduce demand for our business by making it more difficult or costly for certain customers to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, the business and operations of our customers could be subject to additional permitting requirements, attendant permitting delays, increased operating and compliance costs 
+11 
+and process prohibitions, which could have an adverse effect on our business, financial condition, and results of operations. 
+In light of concerns about seismic activity being triggered by the injection of produced waters into underground wells, certain regulators are also considering additional requirements related to seismic safety for hydraulic fracturing activities. A 2015 U.S. Geological Survey report identified eight states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. Any regulation that restricts the ability of our customers to dispose of produced waters or increases their cost of doing business could cause them to curtail operations, which in turn could decrease demand for our services and have a material adverse effect on our business. 
+National Environmental Policy Act 
+Businesses and operations of our customers that are carried out on federal lands may be subject to the National Environmental Policy Act (“NEPA”), which requires federal agencies, including the Department of the Interior, to evaluate major agency actions having the potential to significantly impact the human environment. In the course of such evaluations, an agency will evaluate the potential direct, indirect, and cumulative impacts of a proposed project and, if necessary, will prepare a detailed Environmental Impact Statement that must be made available for public review and comment. On July 16, 2020, the Council on Environmental Quality revised NEPA’s implementing regulations in an effort to streamline approvals for projects. Among other revisions, the rules redefined environmental “effects” or “impacts” as the effects “that are reasonably foreseeable and have a reasonably close causal relationship to the proposed action or alternatives.” The rule also eliminated the current “direct,” “indirect,” or “cumulative” categories of effects. The new regulations are subject to ongoing litigation in several federal district courts, and future implementation of the regulations is unclear. To the extent that our customers’ current activities, as well as proposed plans, on federal lands require governmental permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects. 
+Endangered Species Act and Migratory Bird Treaty Act 
+The Endangered Species Act (the “ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or its habitat. The U.S. Fish and Wildlife Service (the “FWS”) must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. In August 2019, the FWS and National Marine Fisheries Service issued three rules amending implementation of the ESA regulations revising, among other things, the process for listing species and designating critical habitat. A coalition of states and environmental groups have challenged the three rules and the litigation remains pending. In addition, on December 18, 2020, the FWS amended its regulations governing critical habitat designations. We anticipate the rule will be subject to litigation. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”), which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit. This prohibition covers most bird species in the U.S. On January 7, 2021, the Department of the Interior finalized a rule limiting application of the MBTA; however the Department of the Interior under President Biden delayed the effective date of the rule and opened a public comment period for further review. Future implementation of the rules implementing the Endangered Species Act and the MBTA are uncertain. If our customers were to have areas within their business and operations designated as critical or suitable habitat for a protected species, it could decrease demand for our services and have a material adverse effect on our business. 
+12
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+Item 13. Certain Relationships and Related Transactions, and Director Independence 
+The information required in response to this Item will be set forth in our definitive proxy statement for the 2021 annual meeting of stockholders and is incorporated herein by reference.
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+Item 9A. Controls and Procedures 
+Evaluation of Disclosure Controls and Procedures 
+Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by an issuer in the reports the issuer files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time period specified in the rules and forms of the SEC. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in reports filed or submitted under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, as appropriate to allow timely decisions regarding required disclosure. 
+As required by Rule 13a-15(b) under the Exchange Act, our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2020. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2020. 
+Management’s Report on Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act). Our internal control over financial reporting is a process designed under the supervision of our principal executive officer and principal financial officer, and effected by our board of directors, management, and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with GAAP. 
+As of December 31, 2020, our management assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework (2013). Based on its assessment using the COSO criteria, management has concluded that our internal control over financial reporting was effective as of December 31, 2020. 
+Remediation of Previously Reported Material Weakness in our Internal Control Over Financial Reporting 
+As reported in Item 9A of Part II of our Annual Report on Form 10-K for the year ended December 31, 2019, we did not design and maintain adequate controls to address the segregation of certain accounting duties related to journal entries, account reconciliations, and other accounting functions. Certain accounting personnel had the ability to prepare and post journal entries, as well as reconcile accounts, without an independent review by someone other than the preparer. Specifically, our internal controls were not designed or operating effectively to evidence that journal entries were appropriately recorded or were properly reviewed for validity, accuracy, and completeness. Immaterial misstatements were identified related to the inadequate segregation of accounting duties. This material weakness could have resulted in misstatement of the aforementioned accounts and disclosures that would result in a material misstatement in our annual or interim consolidated financial statements that would not have been prevented or detected on a timely basis. 
+In response to the material weakness described above, our management has dedicated significant time and effort to improve our internal control over financial reporting and develop a detailed action plan to fully remediate the material weakness, as follows: 
+• Replaced the less sophisticated accounting systems used by the majority of our newly acquired subsidiaries with the enterprise resource planning system used by the majority of our existing subsidiaries. 
+• Hired additional resources, including an experienced Internal Audit Director to lead our internal audit department, with responsibility for direction and oversight of all internal audit functions. 
+• Completed a comprehensive risk assessment of the design of internal controls, including the implementation of new internal controls as needed to ensure the segregation of certain accounting duties related to journal entries, account reconciliations, and other accounting functions. 
+• Designed and implemented a monitoring control that captures key roles and responsibilities within our enterprise resource planning system with consideration of mitigating business process controls designed to reduce the risk of material misstatement related to inadequate segregation of certain accounting duties related to journal entries, account reconciliations, and other accounting functions. 
+• Removed access for certain accounting personnel to create and post journal entries and designed and implemented an internal control which has enforced a review of all journal entries by individuals without the ability to create and post. 
+• Instituted additional training programs for appropriate personnel regarding the application of our enterprise resource planning system. 
+We have completed the documentation, implementation, and testing of the corrective actions described above and, as of December 31, 2020, have concluded that the steps taken have remediated the material weakness related to the segregation of certain accounting duties related to journal entries, account reconciliations, and other accounting functions. 
+Attestation Report of the Independent Registered Public Accounting Firm 
+This Annual Report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting as we are an “emerging growth company” as defined under the JOBS Act. In addition, management’s report on internal control over financial reporting was not subject to attestation by our independent registered public accounting firm pursuant to rules of the SEC that permit us to provide only management’s report in this Annual Report. 
+Changes in Internal Control over Financial Reporting 
+There have been no changes in our internal control over financial reporting that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting during the quarterly period ended December 31, 2020.
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+15. Related Party Transactions 
+As part of the acquisition of Crest Pumping Technologies, LLC (“Crest”) in 2014, the Company issued promissory notes totaling $ 9.4 million to former owners of Crest, including David Crombie, who is an executive officer of the Company. The principal was due on June 30, 2019 . The interest rate was based on the prime rate, the federal funds rate, or LIBOR, plus a margin to be determined in connection with the Company’s credit agreement and was due quarterly. Mr. Crombie paid $ 1.8 million during 2016 to pay his promissory note in full. At December 31, 2018, the outstanding principal balance of the notes of the remaining individuals totaled $ 7.6 million and unpaid interest, included in “Prepaid expenses and other current assets” in the Company’s Consolidated Balance Sheets, totaled $ 10,000 . During the second quarter of 2019, the Company received the full principal balance of the notes outstanding as well as all unpaid interest. 
+The Company leases office space, yard facilities, and equipment and purchases building maintenance services from entities owned by Mr. Crombie. Total lease expense and building maintenance expense associated with these entities was $ 0.8 million for both the years ended December 31, 2020 and 2019. The Company also purchased equipment of $ 1.6 million and $ 1.4 million for the years ended December 31, 2020 and 2019, respectively, from an entity in which Mr. Crombie is a limited partner. There were outstanding payables due to this entity relating to equipment purchases of $ 0.2 million and $ 0.1 million at December 31, 2020 and 2019, respectively. 
+In addition, the Company leases office space in Corpus Christi and Midland, Texas from an entity affiliated with Warren Lynn Frazier, a beneficial owner of more than 5 % of the Company’s stock. In the third quarter of 2020, another entity affiliated with Mr. Frazier began to sub-lease a portion of such space in Corpus Christi, Texas from the Company. Total rental expense associated with this office space, net of sub-leasing income, was $ 1.3 million and $ 1.5 million for the years ended December 31, 2020 and 2019, respectively. There were net outstanding payables due to the entity of $ 0.1 million at December 31, 2020. Additionally, on June 30, 2020, the Company issued the Magnum Promissory Notes to the sellers of Magnum, including Mr. Frazier. At December 31, 2020, the outstanding principal balance payable to Mr. Frazier was $ 1.9 million. For additional information regarding the Magnum Promissory Notes, see Note 9 – Debt Obligations. 
+The Company purchases cable for its wireline trucks from an entity owned by Forum Energy Technologies (“Forum”). Two of the Company’s directors also serve as directors of Forum. The Company was billed $ 0.5 million and $ 1.9 million for cable during the years ended December 31, 2020 and 2019, respectively. There were outstanding payables due to the entity of $ 0.1 million and $ 0.3 million at December 31, 2020 and 2019, respectively. The Company purchases coiled tubing string from another entity owned by Forum. The Company was billed $ 4.6 million and $ 8.0 million for coiled tubing string during the years ended December 31, 2020 and 2019, respectively. There were outstanding payables due to the entity of $ 0.9 million at both December 31, 2020 and 2019. 
+The Company purchases chemical additives used in cementing from Select Energy Services, Inc. (“Select”). One of the Company’s directors also serves as a director of Select. The Company was billed $ 1.2 million and $ 2.1 million for chemicals during the years ended December 31, 2020 and 2019, respectively. There were outstanding payables due to this entity of $ 0.2 million and $ 0.1 million at December 31, 2020 and 2019, respectively. 
+The Company provides products and rentals to National Energy Reunited Corp. (“NESR”), where one of the Company’s directors serves as a director. The Company billed NESR $ 1.6 million for products and rentals and issued credit memos of $ 0.5 million during the year ended December 31, 2020. The Company billed NESR $ 0.9 million during the year ended December 31, 2019, and additionally, during the fourth quarter of 2019, the Company sold coiled tubing equipment for $ 5.9 million to NESR with payments due in 24 monthly equal installments beginning on January 31, 2020. Total outstanding receivables due to the Company from NESR (inclusive of the equipment sale above) were $ 3.7 million and $ 6.8 million at December 31, 2020 and 2019, respectively. 
+On June 5, 2019, Ann G. Fox, President and Chief Executive Officer and a director of the Company, was elected as a director of Devon Energy Corporation (“Devon”). The Company generated revenue from Devon of $ 5.8 million and $ 18.4 million for the years ended December 31, 2020 and 2019, respectively. There were outstanding receivables due from Devon of $ 0.4 million and $ 1.0 million at December 31, 2020 and 2019, respectively. 
+F-32
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+10-K
+1
+libertyoilfield1231201810-k.htm
+10-K
+Document 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+WASHINGTON, D.C. 20549 
+FORM 10-K 
+(Mark One) 
+☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the Fiscal Year Ended December 31, 2017 
+OR 
+☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+Commission File No. 001-38081 
+Liberty Oilfield Services Inc. 
+(Exact name of registrant as specified in its charter) 
+Delaware 
+81-4891595 
+(State or other jurisdiction of 
+incorporation or organization) 
+(I.R.S. Employer 
+Identification No.) 
+950 17 th Street, Suite 2400 
+Denver, Colorado 80202 
+80202 
+(Address of Principal Executive Offices) 
+(Zip Code) 
+(303) 515-2800 
+(Registrant’s telephone number, including area code) 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of each class 
+Class A Common Stock, par value $0.01 per share 
+Name of each exchange on which registered 
+New York Stock Exchange 
+Securities registered pursuant to Section 12(g) of the Act: None 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☐ 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐ 
+Indicate by check mark whether the registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No 
+Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this Chapter) during the presiding 12 months (or for such shorter period that the registrant was required to submit and post such files). ☐ Yes ☒ No 
+Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒ 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. 
+Large accelerated filer ☐ 
+Accelerated filer ☐ 
+Non-accelerated filer ☒ 
+Smaller reporting company ☐ 
+Emerging growth company ☐ (Do not check if a smaller reporting company) 
+If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act): ☐ Yes ☒ No 
+As of June 30, 2017, the last business day of Registrant’s most recently completed second fiscal quarter, the Registrant’s Class A Common Stock was not listed on a domestic exchange or over-the-counter market. The Registrant’s Class A Common Stock began trading on the New York Stock Exchange on January 12, 2018. 
+At March 16, 2018, the Registrant had 69,975,174 shares of Class A Common Stock and 48,207,372 shares of Class B Common Stock outstanding. 
+Documents Incorporated by Reference: None 
+Table of Contents 
+TABLE OF CONTENTS 
+Page No. 
+PART I 
+Item 1. 
+Business 
+1 
+Item 1A. 
+Risk Factors 
+15 
+Item 1B. 
+Unresolved Staff Comments 
+39 
+Item 2. 
+Properties 
+39 
+Item 3. 
+Legal Proceeding 
+39 
+Item 4. 
+Mine Safety Disclosures 
+39 
+PART II 
+Item 5. 
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+39 
+Item 6. 
+Selected Consolidated Financial Data 
+40 
+Item 7. 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+43 
+Item 7A. 
+Quantitative and Qualitative Disclosure about Market Risk 
+56 
+Item 8. 
+Financial Statements and Supplementary Data 
+57 
+Item 9. 
+Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+57 
+Item 9A. 
+Controls and Procedures 
+57 
+Item 9B. 
+Other Information 
+58 
+PART III 
+Item 10. 
+Directors, Executive Officers and Corporate Governance 
+59 
+Item 11. 
+Executive Compensation 
+64 
+Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+70 
+Item 13. 
+Certain Relationships and Related Transactions, and Director Independence 
+72 
+Item 14. 
+Principal Accountant Fees and Services 
+78 
+PART IV 
+Item 15. 
+Exhibits and Financial Statement Schedules 
+79 
+Item 16. 
+Form 10-K Summary 
+80 
+SIGNATURES 
+82 
+i 
+Table of Contents 
+CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS 
+This Annual Report on Form 10-K and certain other communications made by us contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange of 1934, as amended (the “Exchange Act”), including statements about our growth, future operating results, estimates, beliefs and expected performance. For this purpose, any statement that is not a statement of historical fact should be considered a forward-looking statement. We may use the words “believe,” “anticipate,” “plan,” “expect,” “intend,” “may,” “will,” “should” and similar expressions to help identify forward-looking statements. We cannot assure you that our assumptions and expectations will prove to be correct. Important factors could cause our actual results to differ materially from those indicated or implied by forward-looking statements. We undertake no intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise and readers should not rely on the forward-looking statements as representing the Company’s views as of any date subsequent to the date of the filing of this Annual Report on Form 10-K. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. 
+Forward-looking statements may include statements about: 
+• 
+our business strategy; 
+• 
+our operating cash flows, the availability of capital and our liquidity; 
+• 
+our future revenue, income and operating performance; 
+• 
+our ability to sustain and improve our utilization, revenue and margins; 
+• 
+our ability to maintain acceptable pricing for our services; 
+• 
+our future capital expenditures; 
+• 
+our ability to finance equipment, working capital and capital expenditures; 
+• 
+competition and government regulations; 
+• 
+our ability to obtain permits and governmental approvals; 
+• 
+pending legal or environmental matters; 
+• 
+oil and natural gas prices; 
+• 
+acquisitions; 
+• 
+general economic conditions; 
+• 
+credit markets; 
+• 
+our ability to successfully develop our research and technology capabilities and implement technological developments and enhancements; 
+• 
+uncertainty regarding our future operating results; and 
+• 
+plans, objectives, expectations and intentions contained in this Annual Report on Form 10-K that are not historical. 
+We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, decline in demand for our services, the cyclical nature and volatility of the oil and natural gas industry, a decline in, or substantial volatility of, crude oil and natural gas commodity prices, environmental risks, regulatory changes, the inability to comply with the financial and other covenants and metrics in our Credit Facilities (as defined herein), cash flow and access to capital, the timing of development expenditures and the other risks described under “Risk Factors” in this Annual Report on Form 10-K. 
+All forward-looking statements, expressed or implied, included in this Annual Report on Form 10-K are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. 
+This Annual Report on Form 10-K includes market and industry data and certain other statistical information based on third-party sources including independent industry publications, government publications and other publish independent sources, such as content and estimates provided by Coras Research, LLC as of December 31, 2017. Coras Research, LLC is not a member of the FINRA or the SIPC and is not a registered broker dealer or investment advisor. Although we believe these third-party sources are reliable as of their respective dates, we have not independently verified the accuracy or completeness of this information. Some data is also based on our own good faith estimates, which are supported by our management's knowledge of and experience in the markets and business in which we operate. 
+ii 
+Table of Contents 
+PART I 
+As used in this Annual Report on Form 10-K, unless the context otherwise requires, references to the terms “Company,” “Liberty Inc.,” “we,” “us” and “our” refer to, collectively, Liberty Oilfield Services LLC and LOS Acquisition Co I LLC and its subsidiaries (collectively, the “Predecessor”) for periods prior to the IPO (as defined herein), and, for periods as of and following the IPO (as defined herein), Liberty Oilfield Services Inc. and its consolidated subsidiaries. References to “Liberty LLC” refer to Liberty Oilfield Services New HoldCo LLC. References to “Liberty Holdings” refer to Liberty Oilfield Services Holdings LLC. 
+Item 1. Business 
+Overview 
+We are a growing independent provider of hydraulic fracturing services to onshore oil and natural gas exploration and production (“E&P”) companies in North America. We provide our services primarily in the Permian Basin, the Eagle Ford Shale, the Denver-Julesburg Basin (the “DJ Basin”), the Williston Basin and the Powder River Basin. 
+Initial Public Offering and Reorganization Transaction 
+Liberty Oilfield Services Inc. was incorporated as a Delaware corporation on December 21, 2016, to become a holding corporation for Liberty LLC and its subsidiaries upon completion of our Corporate Reorganization (as defined herein). 
+On January 17, 2018, we completed our initial public offering (the “IPO”) of 14,640,755 shares of our Class A common stock, par value $0.01 per share (the “Class A Common Stock”) at a public offering price of $17.00 per share, of which 14,340,214 shares were offered by us and 300,541 shares were offered by the selling shareholder. We received approximately $220.4 million in net proceeds after deducting approximately $23.4 million of underwriting discounts and commissions and other offering costs. We did not receive any proceeds from the sale of the shares of Class A Common Stock by the selling shareholder. We used approximately $25.9 million of net proceeds from the IPO to redeem ownership in us from certain Legacy Owners (as defined below) and contributed the remaining proceeds to Liberty LLC in exchange for units in Liberty LLC (the “Liberty LLC Units”). Liberty LLC used a portion of the net proceeds (i) to fully repay our outstanding borrowings and accrued interest under our ABL Credit Facility (as defined herein), totaling approximately $30.1 million , (ii) to repay 35% of our outstanding borrowings, accrued interest and prepayment premium under our Term Loan Facility (as defined herein), totaling approximately $62.5 million and (iii) for general corporate purposes, including repayment of additional indebtedness and funding a portion of our 2018 and other future capital expenditures. 
+We are a holding company with no direct operations. In connection with the IPO, we completed a series of organizational transactions (the “Corporate Reorganization”), including the following: 
+• 
+Liberty Holdings contributed all of its assets to Liberty LLC in exchange for Liberty LLC Units; 
+• 
+Liberty Holdings liquidated and distributed to its then-existing owners (the “Legacy Owners”) 105,451,454 Liberty LLC Units pursuant to the terms of the limited liability company agreement of Liberty Holdings and the Master Reorganization Agreement dated as of January 11, 2018, by and among the Company, Liberty Holdings, Liberty LLC, and the other parties named therein (the “Master Reorganization Agreement”); 
+• 
+Certain of the Legacy Owners directly or indirectly contributed all or a portion of their Liberty LLC Units to Liberty Inc. in exchange for 55,334,419 shares of our Class A Common Stock, including 1,258,514 shares of restricted stock; 
+• 
+Liberty Inc. issued the Legacy Owners that continued to own Liberty LLC Units (the “Liberty Unit Holders”) an aggregate amount of 48,207,372 shares of our Class B common stock, par value $0.01 per share (the “Class B Common Stock” and together with the Class A Common Stock, the “Common Stock”); and 
+• 
+Liberty Inc. contributed the net proceeds it received from the IPO to Liberty LLC in exchange for additional Liberty LLC Units such that Liberty Inc. holds a total number of Liberty LLC Units equal to the number of shares of Class A Common Stock outstanding following the IPO. 
+1 
+Table of Contents 
+The below structure chart shows our organization upon the completion of our IPO. This chart is provided for illustrative purposes only and does not represent all legal entities affiliated with us. 
+Each share of Class B Common Stock has no economic rights but entitles its holder to one vote on all matters to be voted on by shareholders generally. Holders of Class A Common Stock and Class B Common Stock will vote together as a single class on all matters presented to our shareholders for their vote or approval, except as otherwise required by applicable law or by our amended and restated certificate of incorporation. We do not intend to list Class B Common Stock on any exchange. 
+Under the Amended and Restated Limited Liability Company Agreement of Liberty LLC (the “Liberty LLC Agreement”), each Liberty Unit Holder has, subject to certain limitations, the right (the “Redemption Right”) to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units for, at Liberty LLC’s election, (i) shares of our Class A Common Stock at a redemption ratio of one share of Class A Common Stock for each Liberty LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions or (ii) an equivalent amount of cash. Alternatively, upon the exercise of the Redemption Right, Liberty Inc. (instead of Liberty LLC) will have the right (the “Call Right”) to, for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder for, at its election, (x) one share of Class A Common Stock or (y) an equivalent amount of cash. In addition, upon a change of control of Liberty Inc., Liberty Inc. has the right to require each holder of Liberty LLC Units (other than Liberty Inc.) to exercise its Redemption Right with respect to some or all of such unit holder’s Liberty LLC Units. In connection with any redemption of Liberty LLC Units pursuant to the Redemption Right or our Call Right, the corresponding number of shares of Class B Common Stock will be cancelled. 
+In connection with the IPO, Liberty Inc. entered into two tax receivable agreements, (the “Tax Receivable Agreements”) with the Liberty Unit Holders and the selling shareholder (each such person and any permitted transferee, a “TRA Holder” and together, the “TRA Holders”). 
+The first of the Tax Receivable Agreements, which Liberty Inc. entered into with the Liberty Unit Holders, generally provides for the payment by Liberty Inc. to such TRA Holders of 85% of the net cash savings, if any, in U.S. federal, state and local income and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that 
+2 
+Table of Contents 
+Liberty Inc. actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result of, as applicable to each such TRA Holder, (i) certain increases in tax basis that occur as a result of Liberty Inc.’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holder’s Liberty LLC Units in connection with the IPO or pursuant to the exercise of the Redemption Right or Liberty Inc.’s Call Right and (ii) imputed interest deemed to be paid by Liberty Inc. as a result of, and additional tax basis arising from, any payments Liberty Inc. makes under such Tax Receivable Agreement. 
+The second of the Tax Receivable Agreements, which Liberty Inc. entered into with the selling shareholder, generally provides for the payment by Liberty Inc. to such TRA Holder of 85% of the net cash savings, if any, in U.S. federal, state and local income and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that Liberty Inc. actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result of, as applicable to such TRA Holder, (i) any net operating losses available to Liberty Inc. as a result of the Corporate Reorganization and (ii) imputed interest deemed to be paid by Liberty Inc. as a result of any payments Liberty Inc. makes under such Tax Receivable Agreement. For further discussion regarding the potential acceleration of payments under the Tax Receivable Agreements and its potential impact, please read “Risk Factors—Risks Related to Our Class A Common Stock.” 
+Because Liberty Inc. is a holding company with no operations of its own, Liberty Inc.’s ability to make payments under the Tax Receivable Agreements is dependent on the ability of Liberty LLC to make distributions to Liberty Inc. in an amount sufficient to cover its obligations under the Tax Receivable Agreements. See “Risk Factors—Risks Related to Our Class A Common Stock—Liberty Inc. is a holding company. Liberty Inc.’s only material asset is its equity interest in Liberty LLC, and Liberty Inc. is accordingly dependent upon distributions from Liberty LLC to pay taxes, make payments under the Tax Receivable Agreements and cover its corporate and other overhead expenses.” If Liberty Inc. experiences a change of control (as defined under the Tax Receivable Agreements, which includes certain mergers, asset sales and other forms of business combinations) or the Tax Receivable Agreements terminate early (at Liberty Inc’s election or as a result of its breach), Liberty Inc. would be required to make a substantial, immediate lump-sum payment. 
+Our Company 
+We are a growing independent provider of hydraulic fracturing services to onshore oil and natural gas E&P companies in the United States. We have grown organically from one active hydraulic fracturing fleet in December 2011 to 21 active fleets in March 2018, representing approximately 885,000 hydraulic horsepower (“HHP”), including additional supporting horsepower. We expect to deploy one additional fleet in June 2018 and two additional fleets by the end of 2018, for a total of 24 active fleets, representing approximately 1,170,000 HHP, including supporting HHP. Our additional fleets are currently being built to our specifications. We provide our services primarily in the Permian Basin, the Eagle Ford Shale, the DJ Basin, the Williston Basin and the Powder River Basin. 
+Our founders and existing management were pioneers in the development of data-driven hydraulic fracturing technologies for application in shale plays. Prior to founding Liberty Holdings, the majority of our management team founded and built Pinnacle Technologies, Inc. (“Pinnacle Technologies”) into a leading fracturing technology company. In 1992, Pinnacle Technologies developed the first commercial hydraulic fracture mapping technologies, analytical tools that played a major role in launching the shale revolution. Our extensive experience with fracture technologies and customized fracture design has enabled us to develop new technologies and processes that provide our customers with real time solutions that significantly enhance their completions. These technologies include hydraulic fracture propagation models, reservoir engineering tools, large, proprietary shale production databases and multi-variable statistical analysis techniques. Taken together, these technologies have enabled us to be a leader in hydraulic fracture design innovation and application. 
+We believe the following characteristics distinguish us from our competitors and are the foundations of our business: forming ongoing partnerships of trust and innovation with our customers; developing and utilizing technology to maximize well performance; and promoting a people-centered culture focused on our employees, customers and suppliers. We have developed strong relationships with our customers by investing significant time in fracture design collaboration, which substantially enhances their production economics. Our technological innovations have become even more critical as E&P companies have increased the completion complexity and fracture intensity of horizontal wells. We are proactive in developing innovative solutions to industry challenges, including developing: (i) our proprietary databases of U.S. unconventional wells to which we apply our proprietary multi-variable statistical analysis technologies to provide differential insight into fracture design optimization; (ii) our Liberty Quiet Fleet ™ design which significantly reduces noise levels compared to conventional hydraulic fracturing fleets; and (iii) our hydraulic fracturing fluid system tailored to the reservoir properties in the DJ Basin which materially reduces completion costs without compromising production. We foster a people-centered culture built around honoring our commitments to customers, partnering with our suppliers and hiring, training and retaining people that we believe 
+3 
+Table of Contents 
+to be the best talent in our field, enabling us to be one of the safest and most efficient hydraulic fracturing companies in the United States. 
+Recent Developments 
+During the year ended December 31, 2017, we were an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”) and were not required to comply with certain requirements that were applicable to other public companies that are not “emerging growth companies.” 
+Effective as of January 17, 2018, we no longer qualify as an “emerging growth company” as defined in the JOBS Act. Accordingly, our independent registered public accounting firm will be required to formally attest to the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act in our Annual Report on Form 10-K for the year ending December 31, 2018. 
+Cyclical Nature of Industry 
+We operate in a highly cyclical industry. The key factor driving demand for our services is the level of drilling activity by E&P companies, which in turn depends largely on the current and anticipated economics of new well completions. Global supply and demand for oil and the domestic supply and demand for natural gas are critical in assessing industry outlook. Demand for oil and natural gas is cyclical and subject to large, rapid fluctuations. E&P companies tend to increase capital expenditures in response to increases in oil and natural gas prices, which generally results in greater revenues and profits for oilfield service companies such as ours. Increased capital expenditures also ultimately lead to greater production, which historically has resulted in increased supplies and reduced prices which in turn tend to reduce demand for oilfield services. For these reasons, the results of our operations may fluctuate from quarter to quarter and from year to year, and these fluctuations may distort comparisons of results across periods. 
+Seasonality 
+Our results of operations have historically reflected seasonal tendencies relating to holiday seasons, inclement weather and the conclusion of our customers’ annual drilling and completion capital expenditure budgets. Our most notable declines occur in the first and fourth quarters of the year for the reasons described above. Additionally, some of the areas in which we have operations, including the DJ Basin, Powder River Basin and Williston Basin, are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice or rain and frost law enforcement, we may be unable to move our equipment between locations, thereby reducing our ability to provide services and generate revenues. The exploration activities of our customers may also be affected during such periods of adverse weather conditions. Additionally, extended drought conditions in our operating regions could impact our ability or our customers’ ability to source sufficient water or increase the cost for such water. 
+Intellectual Property 
+Over the last several years we have significantly invested in our research and technology capabilities. Our efforts to date have been focused on developing innovative, fit-for-purpose solutions designed to enhance our core service offerings, increase completion efficiencies, provide cost savings to our operations and add value for our customers. 
+As a result of these efforts, we introduced several new products and progressed on differentiating technologies that we believe will provide a competitive advantage as our customers focus on extracting oil and natural gas in the most economical and efficient ways possible, including the Vorteq Missile ™ , a new technology, being developed with a third party, that is designed to add proppant downstream of the high pressure pumps, and our Liberty Quiet Fleet ™ , which materially reduces noise levels compared to conventional fracturing fleets. Additionally, several of these investments are delivering value added products and services that are creating increasing demand from key customers. 
+We seek patent and trademark protections for our technology when we deem it prudent, and we aggressively pursue protection of these rights. We believe our patents, trademarks, and other protections for our proprietary technologies are adequate for the conduct of our business and that no single patent or trademark is critical to our business. In addition, we rely, to a great extent, on the technical expertise and know-how of our personnel to maintain our competitive position, and we take commercially reasonable measures to protect trade secrets and other confidential and/or proprietary information relating to the technologies we develop. 
+4 
+Table of Contents 
+Risk Management and Insurance 
+Our operations are subject to significant hazards often found in the oil and natural gas industry, such as, but not limited to, accidents, blowouts, explosions, craterings, fires, natural gas leaks, oil and produced water spills and releases of hydraulic fracturing fluids or other well fluids into the environment. These conditions can cause: 
+• 
+disruption in operations; 
+• 
+substantial repair or remediation costs; 
+• 
+personal injury or loss of human life; 
+• 
+significant damage to or destruction of property and equipment; 
+• 
+environmental pollution, including groundwater contamination; 
+• 
+unusual or unexpected geological formations or pressures and industrial accidents; 
+• 
+impairment or suspension of operations; and 
+• 
+substantial revenue loss. 
+In addition, our operations are subject to, and exposed to, employee/employer liabilities and risks such as wrongful termination, discrimination, labor organizing, retaliation claims and general human resource related matters. 
+Claims for loss of oil and natural gas production and damage to formations can occur in the well services industry. Litigation arising from a catastrophic occurrence at a location where our equipment and services are being used may result in our being named as a defendant in lawsuits asserting large claims. 
+We do not have insurance against all foreseeable risks, either because insurance is not available or because of the high premium costs. The occurrence of an event not fully insured against or the failure of an insurer to meet its insurance obligations could result in substantial losses. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. Insurance may not be available to cover any or all of the risks to which we are subject, or, even if available, it may be inadequate, or insurance premiums or other costs could rise significantly in the future so as to make such insurance prohibitively expensive. 
+We enter into Master Service Agreements (“MSAs”) with substantially all of our customers. Our MSAs delineate our and our customer’s respective indemnification obligations with respect to the services we provide. Generally, under our MSAs, including those relating to our hydraulic fracturing services, we assume responsibility for pollution or contamination originating above the surface from our equipment or handling. However, our customers assume responsibility for all other pollution or contamination that may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling and completion fluids. The assumed responsibilities include the control, removal and clean-up of any pollution or contamination. In such cases, we may be exposed to additional liability if we are negligent or commit willful acts causing the pollution or contamination. Generally, our customers also agree to indemnify us against claims arising from their employees’ personal injury or death, in the case of our hydraulic fracturing operations, to the extent that their employees are injured by such operations, unless the loss is a result of our gross negligence or willful misconduct. Similarly, we generally agree to indemnify our customers for liabilities arising from personal injury to or death of any of our employees, unless resulting from the gross negligence or willful misconduct of our customer. The same principals apply to mutual indemnification for loss or destruction of customer-owned property or equipment, except such indemnification is not limited by negligence or misconduct. Losses due to catastrophic events, such as blowouts, are generally the responsibility of the customer. However, despite this general allocation of risk, we may be unsuccessful in enforcing contractual terms, incur an unforeseen liability that is not addressed by the scope of the contractual provisions or be required to enter into an MSA with terms that vary from our standard allocations of risk, as described above. Consequently, we may incur substantial losses that could materially and adversely affect our financial condition and results of operations. 
+Employees 
+As of December 31, 2017, we had 2,032 employees and no unionized labor. We believe we have good relations with our employees. 
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+Our Services 
+We provide hydraulic fracturing services to E&P companies, particularly to those operating in unconventional oil and natural gas reservoirs and requiring technically and operationally advanced services. Hydraulic fracturing services are performed to enhance production of oil and natural gas from formations with low permeability and restricted flow of hydrocarbons. Our customers benefit from our expertise in fracturing horizontal wells in shales and other unconventional geological formations. 
+The process of hydraulic fracturing involves pumping a pressurized stream of fracturing fluid—typically a mixture of water, chemicals and proppant—into a well casing or tubing in order to cause the underground formation to fracture or crack. These fractures release trapped hydrocarbon particles and provide a conductive channel for the oil or natural gas to flow freely to the wellbore for collection. The propping agent, or proppant,—typically sand—becomes lodged in the cracks created by the hydraulic fracturing process, “propping” them open to facilitate the flow of hydrocarbons from the reservoir to the well. The fracturing fluid is engineered to lose viscosity, or “break,” and is subsequently flowed back from the formation, leaving the proppant suspended in the mineral fractures. Once our customer has flushed the fracturing fluids from the well using a controlled flow-back process, the customer manages fluid and water recycling or disposal. 
+Our hydraulic fracturing fleets consist of mobile hydraulic fracturing units and other auxiliary heavy equipment to perform fracturing services. Our hydraulic fracturing units consist primarily of high-pressure hydraulic pumps, diesel engines, transmissions, radiators and other supporting equipment that are typically mounted on trailers. We refer to the group of units and other equipment, such as blenders, data vans, sand storage, tractors, manifolds and high pressure fracturing iron, which are necessary to perform a typical hydraulic fracturing job, as a “fleet,” and the personnel assigned to each fleet as a “crew.” As of March 2018, we had 21 active fleets, and expect to deploy one additional fleet by the end of the second quarter of 2018, and two additional fleets by the end of 2018, for a total of 24 active fleets by the end of the year. 
+An important element of our hydraulic fracturing services is our focus on providing custom-tailored completions solutions to our customers to maximize their well results. Our technologically innovative approach involves our review of a series of continually updated, proprietary databases of U.S. unconventional wells to which we apply our multi-variable data analysis, allowing us to gain differential insight into fracture design. The innovative completions solutions we provide to our customers help them complete more productive and cost efficient wells in shorter times with less environmental impact on their surroundings while increasing the useful lives of our equipment. 
+In addition to custom-tailored completions solutions, we also develop custom fluid systems, proppant logistics solutions, perforating strategies and pressure analysis techniques for our customers. An example of this is a hydraulic fracturing fluid that we developed for use in our DJ Basin operations called Liberty Spirit ™ , a specifically designed fracturing fluid system that enables material reductions in completion costs in the DJ Basin without compromising job execution or well results. 
+We provide our services in several of the most active basins in the United States, including the Permian Basin, the Eagle Ford Shale, the DJ Basin, the Williston Basin and the Powder River Basin. The map below represents our current areas of operations: 
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+Properties and Equipment 
+Properties 
+Our corporate headquarters are located at 950 17 th Street, Suite 2400, Denver, Colorado 80202. We lease our general office space at our corporate headquarters. The lease expires in December 2024. We currently own or lease the following additional principal properties: 
+District Facility Location 
+Size 
+Leased or Owned 
+Expiration of Lease 
+Odessa, TX 
+77,500 sq. ft on 47 acres 
+Owned 
+N/A 
+Henderson, CO 
+50,000 sq. ft on 13 acres 
+Leased 
+December 31, 2034 
+Williston, ND 
+30,000 sq. ft on 15 acres 
+Owned 
+N/A 
+Gillette, WY 
+32,757 sq. ft on 15 acres 
+Leased 
+December 31, 2034 
+Cibolo, TX 
+90,000 sq. ft on 34 acres 
+Owned 
+N/A 
+We also lease several smaller facilities, which leases generally have terms of one to three years. We believe that our existing facilities are adequate for our operations and their locations allow us to efficiently serve our customers. We do not believe that any single facility is material to our operations and, if necessary, we could readily obtain a replacement facility. 
+Equipment 
+We have 21 hydraulic fracturing fleets plus additional supporting HHP, comprising approximately 885,000 HHP. We expect to deploy three additional fleets by the end of 2018, for a total of 24 active fleets. Six of our fleets currently utilize our Liberty Quiet Fleet ™ technology, with three additional ordered fleets currently being built to our to Liberty Quiet Fleet ™ specifications; approximately 40% of our capacity has dual fuel capability. 
+Our hydraulic fracturing fleets are comprised of high-quality, heavy-duty equipment designed to reduce operational downtime and maintenance costs, while enhancing our ability to provide reliable, consistent service. The average age of our fleets is approximately 3.75 years. Each hydraulic fracturing fleet also includes the necessary blending units, manifolds, data vans and other ancillary equipment needed to provide a high level of service to our customers. 
+Our newbuild fleets are manufactured to a custom Liberty specification that identifies the input components, including such key parts as engines, transmissions and pumps and control systems. These components have been selected with our lowest total cost of ownership philosophy in mind. We have built a strong partnership with each of the key component suppliers that we believe will help ensure timely access to necessary components, early opportunities to adopt the latest technology, and high-level technical support. For example, our close partnership with Caterpillar Inc. enabled us to have ready access to their technical team as we worked through the development of the Liberty Quiet Fleet ™ technology. This relationship ensured that the end product was delivered without compromise to engine performance, reliability or maintainability. We have also a built a strong relationship with the assembler of the core equipment for our fracturing fleets. We believe the collaborative partnerships we have developed with our vendors should give us ready access to sufficient fabrication capacity for our growth. 
+Our Acquisitions 
+On June 13, 2016, we acquired certain inventories and long-lived field service assets related to hydraulic fracturing from Sanjel Corporation for $69.0 million in cash (the “Sanjel Acquisition”). These assets were acquired from Sanjel Corporation as part of its bankruptcy proceeding. On February 22, 2017, we acquired all the membership interests of Titan Frac Services LLC, a wholly-owned subsidiary of TPIH Group Inc., for $65.0 million in cash. 
+Marketing and Customers 
+Our sales and marketing activities typically are performed through our local sales representatives in each geographic region, and are supported by our corporate headquarters. For the years ended December 31, 2017 , 2016 and 2015 , our top five customers collectively accounted for approximately 53.0%, 58.5% and 57.5% of our revenues, respectively. Extraction Oil & Gas, Inc. and SM Energy Company each accounted for more than 10% of our revenues for the year ended December 31, 2017 . For the year ended December 31, 2016 , Extraction Oil & Gas, Inc., SM Energy Company and Noble Energy, Inc. each accounted for more than 10% of our revenues. Extraction Oil & Gas, Inc. also accounted for more than 10% of our revenues for the year ended December 31, 2015 . 
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+Suppliers 
+We have a dedicated supply chain team that manages sourcing and logistics to ensure flexibility and continuity of supply in a cost effective manner across our areas of operation. We have built long-term relationships with multiple industry leading suppliers of proppant, chemicals and hydraulic fracturing equipment. During the year ended December 31, 2015 , we purchased 10% or more of our materials or equipment, as a percentage of overall costs, from one sand supplier. For the years ended December 31, 2017 and 2016 , none of our suppliers accounted for more than 10% of overall costs. For 2018, we do not expect any single proppant supplier to account for more than 20% of our total supply. In addition, we have built a strong relationship with the assembler of our custom-designed hydraulic fracturing fleets and believe we will continue to have timely access to new, high capability fleets as we continue to grow. Our purchases from that assembler accounted for more than 10% of our total capital expenditures for the year ended December 31, 2017 . 
+We purchase a wide variety of raw materials, parts and components that are manufactured and supplied for our operations. We are not dependent on any single source of supply for those parts, supplies or materials. To date, we have generally been able to obtain the equipment, parts and supplies necessary to support our operations on a timely basis. While we believe that we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers, we may not always be able to do so. In addition, certain materials for which we do not currently have long-term supply agreements could experience shortages and significant price increases in the future. As a result, we may be unable to mitigate any future supply shortages and our results of operations, prospects and financial condition could be adversely affected. 
+Competition 
+The markets in which we operate are highly competitive. We provide services in various geographic regions across the United States, and our competitors include many large and small oilfield service providers, including some of the largest integrated service companies. Our hydraulic fracturing services compete with large, integrated companies such as Halliburton Company and Schlumberger Limited as well as other companies including Basic Energy Services, Inc., BJ Services Company, C&J Energy Services, Inc., Calfrac Well Services Ltd., FTS International, Inc., Keane Group, Inc., Patterson-UTI Energy, Inc., ProPetro Services, Inc., RPC, Inc., Superior Energy Services, Inc. and U.S. Well Services, LLC. In addition, our industry is highly fragmented and we compete regionally with a significant number of smaller service providers. 
+We believe that the principal competitive factors in the markets we serve are technical expertise, equipment capacity, work force competency, efficiency, safety record, reputation, experience and price. Additionally, projects are often awarded on a bid basis, which tends to create a highly competitive environment. We seek to differentiate ourselves from our competitors by delivering the highest-quality services and equipment possible, coupled with superior execution and operating efficiency in a safe working environment. 
+Our operations are organized into a single business segment, which consists of hydraulic fracturing services, and we have one reportable geographical business segment, the United States. Operating segments are defined under generally accepted accounting principals in the United States of America ( “ GAAP ” ) as components of an enterprise that engage in activities (i) from which it may earn revenues and incur expenses and (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance. 
+Environmental and Occupational Safety and Health Matters 
+Our operations in support of oil and natural gas exploration, development and production activities pursued by our customers are subject to stringent federal, tribal, state and local laws and regulations governing occupational safety and health, the discharge of materials into the environment and environmental protection. Numerous governmental entities, including the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. These laws and regulations may, among other things (i) require the acquisition of permits or other authorizations for conducting regulated activities, (ii) limit or prohibit our operations on certain lands lying within wilderness, wetlands and other protected areas; (iii) require remedial measures to mitigate pollution from former and ongoing operations; (iv) impose restrictions on the types, quantities and concentrations of various substances that can be released into the environment or injected in formations in connection with oil and natural gas drilling and production activities; (v) impose specific safety and health criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from our operations. Any failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the 
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+permitting or performance of projects; and the issuance of orders enjoining performance of some or all of our operations in a particular area. 
+The trend in environmental regulation is to place more restrictions and limitations on activities that may adversely affect the environment, and thus any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly completion activities, or waste handling, storage transport, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. Our customers may also incur increased costs or delays or restrictions in permitting or operating activities as a result of more stringent environmental laws and regulations, which may result in a curtailment of exploration, development or production activities that would reduce the demand for our services. Historically, our worker health and safety as well as our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our business and operating results. 
+The following is a summary of the more significant existing environmental and occupational safety and health laws, as amended from time to time, to which our business is subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position. 
+Worker Health and Safety 
+We are subject to the requirements of the federal Occupational Safety and Health Act, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the U.S. Occupational Safety and Health Administration (“OSHA”) hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and the public. These worker health and safety laws and regulations are subject to changes and any failure to comply with these laws could lead to the assertion of third-party claims against us, civil or criminal fines and changes in the way we operate our facilities, any of which could have an adverse effect on our financial position. 
+Motor Carrier Operations 
+In connection with the services we provide, we operate as a motor carrier and therefore are subject to regulation by the U.S. Department of Transportation (“DOT”) and analogous various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations; regulatory safety; hazardous materials labeling, placarding and marking; financial reporting; and certain mergers, consolidations and acquisitions. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive in any specific period and requiring onboard electronic logging devices or limits on vehicle weight and size. 
+Interstate motor carrier operations are subject to safety requirements prescribed by DOT. Intrastate motor carrier operations are subject to state safety regulations that often mirror federal regulations but may be more stringent. Such matters as weight and dimension of motor carrier-related equipment are also subject to federal and state regulations. DOT regulations also mandate drug testing of drivers. From time to time, various legislative proposals are introduced, including proposals to increase federal, state or local taxes, such as, for example, taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us would be enacted. 
+Radioactive Materials 
+Some of our operations utilize equipment that contains sealed, low-grade radioactive sources. Our activities involving the use of radioactive materials are regulated by the U.S. Nuclear Regulatory Commission (“NRC”) and state regulatory agencies under agreement with the NRC. Standards implemented by these regulatory agencies require us to obtain licenses or other approvals for the use of such radioactive materials. Additionally, these regulatory agencies impose certain requirements 
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+concerning worker protection with respect to radioactive sources and may otherwise issue regulations regarding the handling and storage of this equipment that may result in increased costs. The violation of these laws and regulations may result in the denial or revocation of licenses or other approvals, issuance of corrective action orders, injunctions prohibiting some or all of our operations in a particular area, and assessment of sanctions, including administrative, civil and criminal penalties. 
+Hazardous Substances and Wastes and Naturally Occurring Radioactive Materials 
+The federal Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, regulate the generation, treatment, storage, transportation, disposal and clean-up of hazardous and non-hazardous wastes. Pursuant to rules issued by the EPA, individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste provisions, state laws or other federal laws. However, it is possible that certain oil and gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. For example, in response to a lawsuit filed by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and natural gas wastes, the EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the U.S. District Court for the District of Columbia in December 2016. Under the consent decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes or sign a determination that revision of the regulations is not necessary. If the EPA proposes a rulemaking for revised oil and natural gas waste regulations, the consent decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our and the oil and natural gas exploration and production industry’s costs to manage and dispose of generated hazardous wastes, which could have a material adverse effect on our results of operations and financial position. Additionally, other wastes handled at exploration and production sites or generated in the course of providing well services may not fall within this exclusion. In the course of our operations, we generate some amounts of ordinary industrial wastes that may be regulated as hazardous wastes. 
+Moreover, there have been public concerns expressed about naturally occurring radioactive materials (“NORM”) being detected in flow back water resulting from hydraulic fracturing that may contaminate extraction and processing equipment used in the oil and natural gas industry. NORM is subject primarily to individual state radiation control regulations while NORM handling and management activities are governed by regulations promulgated by OSHA. These state and federal regulations impose certain requirements concerning worker protection with respect to NORM as well as the treatment, storage, and disposal of NORM and NORM waste, management of NORM-contaminated waste piles, containers and tanks, and limitations on the relinquishment of NORM contaminated land for unrestricted use under RCRA and state laws. Concern over NORM in general, or NORM in groundwater in particular, could result in further regulation in the treatment, storage, handling and discharge of flow back water generated from oil and natural gas activities, including hydraulic fracturing, or handling of NORM-impacted equipment that, if implemented, could limit drilling by our customers or increase our costs or liabilities associated with elevated levels of NORM. 
+The federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, and comparable state statutes impose liability, without regard to fault or legality of the original conduct, on classes of persons that are considered to have contributed to the release of a hazardous substance into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, these persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We own, lease, or operate numerous properties and facilities that for many years have been used for industrial activities, including oil and natural gas-related operations. Hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations where such substances have been taken for recycling or disposal. In addition, some of these properties have been operated by third parties or by previous owners whose treatment and disposal or release of hazardous substances, wastes, or hydrocarbons, was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes and remediate contaminated property (including groundwater contamination), including instances where the prior owner or operator caused the contamination, or perform remedial plugging of disposal wells or waste pit closure operations to prevent future contamination. These laws and regulations may also expose us to liability for our acts that were in compliance with applicable laws at the time the acts were performed. 
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+Water Discharges and Discharges into Belowground Formations 
+The Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”) and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and hazardous substances, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers (“Corps”). The CWA and analogous state laws also may impose substantial civil and criminal penalties for non-compliance including spills and other non-authorized discharges. 
+In May 2015, the EPA and the Corps released a final rule outlining their position on federal jurisdictional reach over waters of the United States, including wetlands, but legal challenges to this rule followed, and the rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals in October 2015, pending resolution of the court challenges. In January 2017, the United States Supreme Court accepted review of the rule to determine whether jurisdiction rests with the federal district or appellate courts and, in a decision issued on January 22, 2018, held that legal challenges of the rule must be heard at the district rather than appellate court level. The Sixth Circuit lifted its stay of the 2015 rule in February 2018. Additionally, following issuance of a presidential executive order to review the rule, the EPA and the Corps published a proposed rulemaking in July 2017 to repeal the 2015 rule. The EPA and the Corps also announced their intent to issue a new rule defining the CWA’s jurisdiction. On February 6, 2018, the EPA and the Corps published a final rule specifying that the contested 2015 rule would not take effect until February 6, 2020. As a result, future implementation of the 2015 rule is uncertain at this time. To the extent the 2015 rule or a revised rule expands the scope of the CWA’s jurisdiction in areas where we or our customers operate, it could impose additional permitting obligations on us and our customers. 
+The Oil Pollution Act of 1990 (“OPA”) amends the CWA and sets minimum standards for prevention, containment and cleanup of oil spills. OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties including owners and operators of onshore facilities may be held strictly liable for oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills. The OPA also requires owners or operators of certain onshore facilities to prepare facility response plans for responding to a worst-case discharge of oil into waters of the United States. 
+Our oil and natural gas producing customers dispose of flowback and produced water or certain other oilfield fluids gathered from oil and natural gas producing operations in accordance with permits issued by government authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change based on concerns of the public or governmental authorities regarding such disposal activities. One such concern relates to recent seismic events near underground disposal wells used for the disposal by injection of flowback and produced water or certain other oilfield fluids resulting from oil and natural gas activities. In 2016, the United States Geological Survey identified six states with the most significant hazards from seismicity events suspected of having been induced by injection of oilfield fluids into underground disposal wells, including Oklahoma, Kansas, Texas, Colorado, New Mexico, and Arkansas. In response to concerns between use of underground disposal wells and the occurrence of seismic events, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Texas and Oklahoma have issued rules for produced water disposal wells that impose certain permitting restrictions, operating restrictions and/or reporting requirements on disposal wells in proximity to faults. Additionally, from time to time, states may develop and implement plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations, as has occurred in Oklahoma. For example, in December 2016, the Oil and Gas Conservation Division of the Oklahoma Corporation Commission (“OCC”) and the Oklahoma Geological Survey released well completion seismicity guidance, which requires operators to take certain prescriptive actions, including an operator’s planned mitigation practices, following certain unusual seismic activity within 1.25 miles of hydraulic fracturing operations. In addition, in February 2017, the OCC’s Oil and Gas Conservation Division issued an order limiting future increases in the volume of oil and natural gas produced water injected belowground into the Arbuckle formation in an effort to reduce the number of earthquakes in the state, and imposed further restrictions in the Edmonds area of the state in August 2017. Another consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by our customers to dispose of flowback and produced water and certain other oilfield fluids. Increased regulation and 
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+attention given to seismicity events suspected of having been induced by injection of oilfield fluids into underground disposal wells also could lead to greater opposition to, and litigation concerning, oil and natural gas activities utilizing injection wells for waste disposal. Any one or more of these developments may result in our customers having to limit disposal well volumes, disposal rates or locations, or require our customers or third party disposal well operators that are used to dispose of customer produced water to shut down disposal wells, which developments could adversely affect our customers’ business and result in a corresponding decrease in the need for our services, which would could have a material adverse effect on our business, financial condition, and results of operations. 
+Air Emissions 
+Some of our operations also result in emissions of regulated air pollutants. The federal Clean Air Act (“CAA”) and analogous state laws require permits for certain facilities that have the potential to emit substances into the atmosphere that could adversely affect environmental quality. These laws and their implementing regulations also impose generally applicable limitations on air emissions and require adherence to maintenance, work practice, reporting and record keeping, and other requirements. Failure to obtain a permit or to comply with permit or other regulatory requirements could result in the imposition of sanctions, including administrative, civil and criminal penalties. In addition, we or our customers could be required to shut down or retrofit existing equipment, leading to additional expenses and operational delays. 
+Many of these regulatory requirements, including New Source Performance Standards (“NSPS”) and Maximum Achievable Control Technology (“MACT”) standards, are expected to be made more stringent over time as a result of stricter ambient air quality standards and other air quality protection goals adopted by the EPA. Compliance with these or other new or amended regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact on our business. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard, (“NAAQS”) for ozone from 75 to 70 parts per billion for both the 8-hour primary and secondary standards. The EPA published a final rule in November 2017 that issued area designations with respect to ground-level ozone for approximately 85% of the U.S. counties as either “attainment/unclassifiable” or “unclassifiable” and is expected to issue attainment or non-attainment designations for the remaining areas of the U.S. not addressed under the November 2017 final rule in the first half of 2018. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Additionally, states are expected to implement more stringent requirements as a result of the revised NAAQS for ozone, which could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. In a second example, the EPA finalized separate rules under the CAA in June 2016 regarding criteria for aggregating multiple sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small production facilities (such as tank batteries and compressor stations), on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements. Compliance with this and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase costs for us and our customers. Moreover, our business could be materially affected if our customers’ operations are significantly affected by these or other similar requirements. These requirements could increase the cost of doing business for us and our customers, reduce the demand for the oil and natural gas our customers produce, and thus have an adverse effect on the demand for our services. 
+Climate Change 
+Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of greenhouse gases (“GHGs”). These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. In the absence of federal GHG-limiting legislations, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted regulations that, among other things, restrict emissions of GHGs under existing provisions of the CAA and may require the installation of “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future if they would otherwise emit large volumes of GHGs together with other criteria pollutants. Also, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from oil and natural gas production, processing, transmission and storage facilities in the United States on an annual basis. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting stations as well as completions and workovers from hydraulically fractured oil wells. 
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+The EPA has also taken steps to limit methane emissions, a GHG, from certain new modified or reconstructed facilities in the oil and natural gas sector through the adoption of a final rule in June 2016 establishing NSPS Subpart OOOOa standards for methane emissions. These Subpart OOOOa standards will expand the previously issued NSPS Subpart OOOO requirements issued in 2012 by using certain equipment-specific emissions control practices. However, in June 2017, the EPA published a proposed rule to stay certain portions of the June 2016 standards for two years and re-evaluate the entirety of the 2016 standards but the EPA has not yet published a final rule and, as a result, the June 2016 rule remains in effect but future implementation of the 2016 standards is uncertain at this time. Furthermore, in November 2016, the federal Bureau of Land Management (“BLM”) published a final rule that established, among other things, requirements to reduce methane emissions arising from venting, flaring and leaks from oil and natural gas production activities on onshore federal and Native American lands. However, in December 2017, the BLM published a final rule to temporarily suspend or delay certain requirements contained in the November 2016 final rule until January 17, 2019, including those requirements relating to the venting, flaring and leakage from oil and natural gas production activities. The suspension of the November 2016 final rule is being challenged in court. Given the long-term trend towards increasing regulation, future federal GHG regulations of the oil and natural gas industry remain a possibility, and should the EPA’s June 2016 or the BLM’s November 2016 rules remain in effect, or any other new methane emission standards be imposed on the oil and natural gas sector, such requirements could result in increased costs to our or our customers’ operations as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect our business. 
+In December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that prepared an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered in force in November 2016; however, the GHG emission reductions called for by the Paris Agreement are not binding. In August 2017, the U.S. State Department informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas our customers produce and lower the value of their reserves, which developments could reduce demand for our services and have a corresponding material adverse effect on our results of operations and financial position. 
+Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production or midstream activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and natural gas will continue to represent a substantial percentage of global energy use over that time. Finally, it should be noted that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our operations. 
+Endangered Species 
+The federal Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the federal Migratory Bird Treaty Act (“MBTA”). As a result of one or more settlements entered into by the U.S. Fish and Wildlife Service, that agency is required to consider listing numerous species as endangered or threatened under the Endangered Species Act by specified timelines. Current ESA listings and the designation of previously unprotected species as threatened or endangered in areas where we or our customers operate could cause us or our customers to incur increased costs arising from species protection or mitigation measures and could result in delays or limitations in our or our customers' performance of operations, which could adversely affect or reduce demand for our services. 
+Hydraulic Fracturing 
+We perform hydraulic fracturing services for our customers. Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand or other proppant and chemical additives under pressure into the formation to fracture the surrounding rock and stimulate production. 
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+Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has conducted investigations or asserted federal regulatory authority pursuant to the U.S. Safe Drinking Water Act (“SDWA”) Underground Injection Control (“UIC”) program over certain aspects of the process. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances.” Additionally, the EPA asserted regulatory authority under the SDWA UIC program in 2014 over hydraulic fracturing activities involving the use of diesel fuel and issued permitting guidance covering such activities. The EPA also published final CAA regulations in 2012 and in June 2016 governing performance standards, including standards for the capture of emissions released during oil and natural gas hydraulic fracturing. Also in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of produced water from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants and, in May 2014, published an Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. The BLM published a final rule in March 2015 that imposed new or more stringent standards for performing hydraulic fracturing on federal and Native American lands. However, in June 2016, a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority to promulge the rule, the BLM appealed the decision to the U.S. Circuit Court of Appeals for the Tenth Circuit in July 2016, the appellate court issued a ruling in September 2017 to vacate the Wyoming trial court decision and dismiss the lawsuit challenging the rule in light of the BLM’s proposed rulemaking and, in December 2017, the BLM published a final rule rescinding the March 2015 rule. In January 2018, litigation challenging the BLM’s rescission of the 2015 rule was brought in federal court. 
+In addition, various state and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, disclosure requirements, well construction and temporary or permanent bans on hydraulic fracturing in certain areas. For example, Texas, Colorado and North Dakota, among others, have adopted regulations that impose new or more stringent permitting, disclosure, disposal, and well construction requirements on hydraulic fracturing operations. States could also elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York. Local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular. If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly to perform hydraulic fracturing. Any such regulations limiting or prohibiting hydraulic fracturing could result in decreased oil and natural gas exploration and production activities and, therefore, adversely affect demand for our services and our business. Such laws or regulations could also materially increase our costs of compliance and doing business. 
+Available Information 
+We file or furnish annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The public may read and copy any materials we file with the U.S. Securities and Exchange Commission (the “SEC”) at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549, on official business days during the hours of 10 a.m. to 3 p.m. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC. 
+Our Class A Common Stock is listed and traded on the New York Stock Exchange (“NYSE”) under the symbol “LBRT.” Our reports, proxy statements and other information filed with the SEC can also be inspected and copied at the offices of the NYSE, at 20 Broad Street, New York, New York 10005. 
+We also make available free of charge through our website, www.libertyfrac.com, electronic copies of certain documents that we file with the SEC, including our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. 
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+Item 1A. Risk Factors 
+Described below are certain risks that we believe apply to our business and the industry in which we operate. You should carefully consider each of the following risk factors in conjunction with other information provided in this Annual Report on Form 10-K and in our other public disclosures. The risks described below highlight potential events, trends or other circumstances that could adversely affect our business, financial condition, results of operations, cash flows, liquidity or access to sources of financing, and consequently, the market value of our common stock. These risks could cause our future results to differ materially from historical results and from guidance we may provide regarding our expectations of future financial performance. The risks described below are those that we have identified as material and is not an exhaustive list of all the risks we face. There may be other risks that we have not identified or that we have deemed to be immaterial. Please refer to the explanation of the qualifications and limitation on forward-looking statements set forth on page 1 hereof. 
+Risks Related to Our Business 
+Our business depends on domestic capital spending by the oil and natural gas industry, and reductions in capital spending could have a material adverse effewrightct on our liquidity, results of operations and financial condition. 
+Our business is directly affected by our customers’ capital spending to explore for, develop and produce oil and natural gas in the United States. The significant decline in oil and natural gas prices that began in late 2014 caused a reduction in the exploration, development and production activities of most of our customers and their spending on our services. These cuts in spending curtailed drilling programs, which resulted in a reduction in the demand for our services, as well as the prices we can charge. These reductions have negatively affected our revenue per average active fleet. While industry conditions improved and activity levels increased during 2017, there can be no assurance that these increased levels will be sustained. In addition, certain of our customers could become unable to pay their vendors and service providers, including us, as a result of a decline in commodity prices. Reduced discovery rates of new oil and natural gas reserves in our areas of operation as a result of decreased capital spending may also have a negative long-term impact on our business, even in an environment of stronger oil and natural gas prices. Any of these conditions or events could adversely affect our operating results. If the recent recovery increased activity levels do not continue or our customers fail to further increase their capital spending, it could have a material adverse effect on our liquidity, results of operations and financial condition. 
+Industry conditions are influenced by numerous factors over which we have no control, including: 
+• 
+expected economic returns to E&P companies of new well completions; 
+• 
+domestic and foreign economic conditions and supply of and demand for oil and natural gas; 
+• 
+the level of prices, and expectations about future prices, of oil and natural gas; 
+• 
+the level of global oil and natural gas exploration and production; 
+• 
+the level of domestic and global oil and natural gas inventories; 
+• 
+the supply of and demand for hydraulic fracturing and equipment in the United States; 
+• 
+federal, tribal, state and local laws, regulations and taxes, including the policies of governments regarding hydraulic fracturing and oil and natural gas exploration, development and production activities as well as non-U.S. governmental regulations and taxes; 
+• 
+governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves; 
+• 
+political and economic conditions in oil and natural gas producing countries; 
+• 
+actions by the members of the OPEC with respect to oil production levels and announcements of potential changes in such levels, including the failure of such countries to comply with production cuts announced in November 2016 and extended in November 2017; 
+• 
+global weather conditions and natural disasters; 
+• 
+worldwide political, military and economic conditions; 
+• 
+the cost of producing and delivering oil and natural gas; 
+• 
+lead times associated with acquiring equipment and products and availability of qualified personnel; 
+• 
+the discovery rates of new oil and natural gas reserves; 
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+• 
+stockholder activism or activities by non-governmental organizations to limit certain sources of funding for the energy sector or to restrict the exploration, development and production of oil and natural gas; 
+• 
+the availability of water resources, suitable proppant and chemical additives in sufficient quantities for use in hydraulic fracturing fluids; 
+• 
+advances in exploration, development and production technologies or in technologies affecting energy consumption; 
+• 
+the potential acceleration of development of alternative fuels; and 
+• 
+uncertainty in capital and commodities markets and the ability of oil and natural gas companies to raise equity capital and debt financing. 
+The volatility of oil and natural gas prices may adversely affect the demand for our hydraulic fracturing services and negatively impact our results of operations. 
+The demand for our hydraulic fracturing services is primarily determined by current and anticipated oil and natural gas prices and the related levels of capital spending and drilling activity in the areas in which we have operations. Volatility or weakness in oil prices or natural gas prices (or the perception that oil prices or natural gas prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells. This, in turn, could lead to lower demand for our services and may cause lower utilization of our assets. We have experienced, and may in the future experience significant fluctuations in operating results as a result of the reactions of our customers to changes in oil and natural gas prices. For example, prolonged low commodity prices experienced by the oil and natural gas industry beginning in late 2014 and uncertainty about future prices even when prices increased, combined with adverse changes in the capital and credit markets, caused many E&P companies to significantly reduce their capital budgets and drilling activity. This resulted in a significant decline in demand for oilfield services and adversely impacted the prices oilfield services companies could charge for their services. 
+Prices for oil and natural gas historically have been extremely volatile and are expected to continue to be volatile. During the past four years, the posted WTI price for oil has ranged from a low of $26.21 per Bbl in February 2016 to a high of $107.26 per Bbl in June 2014. During 2017, WTI prices ranged from $42.48 to $60.42 per Bbl. If the prices of oil and natural gas continue to be volatile, reverse their recent increases or decline, our operations, financial condition, cash flows and level of expenditures may be materially and adversely affected. 
+We may be adversely affected by uncertainty in the global financial markets and the deterioration of the financial condition of our customers. 
+Our future results may be impacted by the uncertainty caused by an economic downturn, volatility or deterioration in the debt and equity capital markets, inflation, deflation or other adverse economic conditions that may negatively affect us or parties with whom we do business resulting in a reduction in our customers’ spending and their non-payment or inability to perform obligations owed to us, such as the failure of customers to honor their commitments or the failure of major suppliers to complete orders. Additionally, during times when the crude oil or natural gas markets weaken, our customers are more likely to experience financial difficulties, including being unable to access debt or equity financing, which could result in a reduction in our customers’ spending for our services. In addition, in the course of our business we hold accounts receivable from our customers. In the event of the financial distress or bankruptcy of a customer, we could lose all or a portion of such outstanding accounts receivable associated with that customer. Further, if a customer was to enter into bankruptcy, it could also result in the cancellation of all or a portion of our service contracts with such customer at significant expense or loss of expected revenues to us. 
+Our operations are subject to significant risks, some of which are beyond our control. These risks may be self-insured, or may not be fully covered under our insurance policies. 
+Our operations are subject to significant hazards often found in the oil and natural gas industry, such as, but not limited to, accidents, blowouts, explosions, craterings, fires, natural gas leaks, oil and produced water spills and releases of hydraulic fracturing fluids or other well fluids into the environment. These conditions can cause: 
+• 
+disruption in operations; 
+• 
+substantial repair or remediation costs; 
+• 
+personal injury or loss of human life; 
+• 
+significant damage to or destruction of property, and equipment; 
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+• 
+environmental pollution, including groundwater contamination; 
+• 
+unusual or unexpected geological formations or pressures and industrial accidents; 
+• 
+impairment or suspension of operations; and 
+• 
+substantial revenue loss. 
+In addition, our operations are subject to, and exposed to, employee/employer liabilities and risks such as wrongful termination, discrimination, labor organizing, retaliation claims and general human resource related matters. 
+The occurrence of a significant event or adverse claim in excess of the insurance coverage that we maintain or that is not covered by insurance could have a material adverse effect on our liquidity, combined results of operations and combined financial condition. Claims for loss of oil and natural gas production and damage to formations can occur in the well services industry. Litigation arising from a catastrophic occurrence at a location where our equipment and services are being used may result in our being named as a defendant in lawsuits asserting large claims. 
+We do not have insurance against all foreseeable risks, either because insurance is not available or because of the high premium costs. The occurrence of an event not fully insured against or the failure of an insurer to meet its insurance obligations could result in substantial losses. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. Insurance may not be available to cover any or all of the risks to which we are subject, or, even if available, it may be inadequate, or insurance premiums or other costs could rise significantly in the future so as to make such insurance prohibitively expensive. 
+Reliance upon a few large customers may adversely affect our revenue and operating results. 
+Our top five customers represented approximately 53.0%, 58.5% and 57.5% of our consolidated revenue for the years ended December 31, 2017, 2016 and 2015, respectively. It is likely that we will continue to derive a significant portion of our revenue from a relatively small number of customers in the future. If a major customer fails to pay us, revenue would be impacted and our operating results and financial condition could be materially harmed. Additionally, if we were to lose any material customer, we may not be able to redeploy our equipment at similar utilization or pricing levels or within a short period of time and such loss could have a material adverse effect on our business until the equipment is redeployed at similar utilization or pricing levels. 
+We are exposed to the credit risk of our customers, and any material nonpayment or nonperformance by our customers could adversely affect our financial results. 
+We are subject to the risk of loss resulting from nonpayment or nonperformance by our customers, many of whose operations are concentrated solely in the domestic E&P industry which, as described above, is subject to volatility and, therefore, credit risk. Our credit procedures and policies may not be adequate to fully reduce customer credit risk. For example, for the year ended December 31, 2015, we had approximately $6.4 million of bad debt on which we could not collect due to the bankruptcy of certain of our customers. If we are unable to adequately assess the creditworthiness of existing or future customers or unanticipated deterioration in their creditworthiness, any resulting increase in nonpayment or nonperformance by them and our inability to re-market or otherwise use our equipment could have a material adverse effect on our business, financial condition, prospects or results of operations. 
+We face intense competition that may cause us to lose market share and could negatively affect our ability to market our services and expand our operations. 
+The oilfield services business is highly competitive. Some of our competitors have a broader geographic scope, greater financial and other resources, or other cost efficiencies. Additionally, there may be new companies that enter our business, or re-enter our business with significantly reduced indebtedness following emergence from bankruptcy, or our existing and potential customers may develop their own hydraulic fracturing business, or direct source sand, negatively affecting our revenue and potentially resulting in shortfall obligations under some of our supply agreements. Our ability to maintain current revenue and cash flows, and our ability to market our services and expand our operations, could be adversely affected by the activities of our competitors and our customers. If our competitors substantially increase the resources they devote to the development and marketing of competitive services or substantially decrease the prices at which they offer their services, we may be unable to effectively compete. All of these competitive pressures could have a material adverse effect on our business, results of operations and financial condition. Some of our larger competitors provide a broader range of services on a regional, national or worldwide basis. These companies may have a greater ability to continue oilfield service activities during periods of low commodity prices and to absorb the burden of present and future federal, tribal, state, local and other laws and regulations. 
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+Any inability to compete effectively with larger companies could have a material adverse impact on our financial condition and results of operations. 
+Our assets require significant amounts of capital for maintenance, upgrades and refurbishment and may require significant capital expenditures for new equipment. 
+Our hydraulic fracturing fleets and other completion service-related equipment require significant capital investment in maintenance, upgrades and refurbishment to maintain their competitiveness. For example, since January 1, 2011, we have deployed 21 hydraulic fracturing fleets to service customers at a total cost to deploy of approximately $683.5 million. The costs of components and labor have increased in the past and may increase in the future with increases in demand, which will require us to incur additional costs to upgrade any fleets we may acquire in the future. Our fleets and other equipment typically do not generate revenue while they are undergoing maintenance, upgrades or refurbishment. Any maintenance, upgrade or refurbishment project for our assets could increase our indebtedness or reduce cash available for other opportunities. Furthermore, such projects may require proportionally greater capital investments as a percentage of total asset value, which may make such projects difficult to finance on acceptable terms. To the extent we are unable to fund such projects, we may have less equipment available for service or our equipment may not be attractive to potential or current customers. Additionally, competition or advances in technology within our industry may require us to update or replace existing fleets or build or acquire new fleets. Such demands on our capital or reductions in demand for our hydraulic fracturing fleets and the increase in cost of labor necessary for such maintenance and improvement, in each case, could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations and may increase our costs. 
+We rely on a limited number of third parties for sand, proppant and chemical additives, and delays in deliveries of such materials, increases in the cost of such materials or our contractual obligations to pay for materials that we ultimately do not require could harm our business, results of operations and financial condition. 
+We have established relationships with a limited number of suppliers of our raw materials (such as proppant and chemical additives). Should any of our current suppliers be unable to provide the necessary materials or otherwise fail to deliver the materials in a timely manner and in the quantities required, any resulting delays in the provision of services could have a material adverse effect on our business, results of operations and financial condition. Additionally, increasing costs of such materials may negatively impact demand for our services or the profitability of our business operations. In the past, our industry faced sporadic proppant shortages associated with hydraulic fracturing operations requiring work stoppages, which are believed to have adversely impacted the operating results of several competitors. We may not be able to mitigate any future shortages of materials, including proppant. Furthermore, to the extent our contracts require us to purchase more materials, including proppant, than we ultimately require, we may be forced to pay for the excess amount under “take or pay” contract provisions. 
+We currently rely on one assembler and a limited number of suppliers for major equipment to both build new fleets and upgrade any fleets we acquire to our custom design, and our reliance on these vendors exposes us to risks including price and timing of delivery. 
+We currently rely on one assembler and a limited number of suppliers for major equipment to both build our new fleets and upgrade any fleets we may acquire to our custom design. If demand for hydraulic fracturing fleets or the components necessary to build such fleets increases or these vendors face financial distress or bankruptcy, these vendors may not be able to provide the new or upgraded fleets on schedule or at the current price. If this were to occur, we could be required to seek another assembler or other suppliers for major equipment to build or upgrade our fleets, which may adversely affect our revenues or increase our costs. 
+Interruptions of service on the rail lines by which we receive proppant could adversely affect our results of operations. 
+We receive a significant portion of the proppant used in our hydraulic fracturing services by rail. Rail operations are subject to various risks that may result in a delay or lack of service, including lack of available capacity, mechanical problems, extreme weather conditions, work stoppages, labor strikes, terrorist attacks and operating hazards. Additionally, if we increase the amount of proppant we require for delivery of our services, we may face difficulty in securing rail transportation for such additional amount of proppant. Any delay or failure in the rail services on which we rely could have a material adverse effect on our financial condition and results of operations. 
+Delays or restrictions in obtaining permits by us for our operations or by our customers for their operations could impair our business. 
+In most states, our operations and the operations of our oil and natural gas producing customers require permits from one or more governmental agencies in order to perform drilling and completion activities, secure water rights, or other regulated activities. Such permits are typically issued by state agencies, but federal and local governmental permits may also be required. 
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+The requirements for such permits vary depending on the location where such regulated activities will be conducted. As with all governmental permitting processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit to be issued, and the conditions that may be imposed in connection with the granting of the permit. In addition, some of our customers’ drilling and completion activities may take place on federal land or Native American lands, requiring leases and other approvals from the federal government or Native American tribes to conduct such drilling and completion activities or other regulated activities. Under certain circumstances, federal agencies may cancel proposed leases for federal lands and refuse to grant or delay required approvals. Therefore, our customers’ operations in certain areas of the United States may be interrupted or suspended for varying lengths of time, causing a loss of revenue to us and adversely affecting our results of operations in support of those customers. 
+Federal or state legislative and regulatory initiatives related to induced seismicity could result in operating restrictions or delays in the drilling and completion of oil and natural gas wells that may reduce demand for our services and could have a material adverse effect on our liquidity, combined results of operations and combined financial condition. 
+Our oil and natural gas producing customers dispose of flowback and produced water or certain other oilfield fluids gathered from oil and natural gas producing operations in accordance with permits issued by government authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change based on concerns of the public or governmental authorities regarding such disposal activities. One such concern relates to recent seismic events near underground disposal wells used for the disposal by injection of flowback and produced water or certain other oilfield fluids resulting from oil and natural gas activities. In 2016, the United States Geological Survey identified six states with the most significant hazards from seismicity events suspected of having been induced by injection of oilfield fluids into underground disposal wells, including Oklahoma, Kansas, Texas, Colorado, New Mexico, and Arkansas. In response to concerns between use of underground disposal wells and the occurrence of seismic events, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma has issued rules for produced water disposal wells that imposed certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, has developed and implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. The Texas Railroad Commission has adopted similar rules. In December 2016, the Oil and Gas Conservation Division of the OCC and the Oklahoma Geological Survey released well completion seismicity guidance, which requires operators to take certain prescriptive actions, including an operator’s planned mitigation practices, following certain unusual seismic activity within 1.25 miles of hydraulic fracturing operations. In addition, in February 2017, the OCC’s Oil and Gas Conservation Division issued an order limiting future increases in the volume of oil and natural gas produced water injected belowground into the Arbuckle formation in an effort to reduce the number of earthquakes in the state, and imposed further restrictions in the Edmonds area of the state in August 2017. Another consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by our customers to dispose of flowback and produced water and certain other oilfield fluids. Increased regulation and attention given to seismicity events suspected of having been induced by injection of oilfield fluids into underground disposal wells also could lead to greater opposition to, and litigation concerning, oil and natural gas activities utilizing injection wells for waste disposal. Any one or more of these developments may result in our customers having to limit disposal well volumes, disposal rates or locations, or require our customers or third party disposal well operators that are used to dispose of customers’ produced water to shut down disposal wells, which developments could adversely affect our customers’ business and result in a corresponding decrease in the need for our services, which could have a material adverse effect on our business, financial condition, and results of operations. 
+Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities may serve to limit future oil and natural gas exploration and production activities and could have a material adverse effect on our results of operations and business. 
+Currently, hydraulic fracturing is generally exempt from regulation under the SDWA UIC program and is typically regulated by state oil and gas commissions or similar agencies. 
+However, federal agencies have conducted investigations or asserted regulatory authority over certain aspects of the process. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances.” Additionally, the EPA asserted regulatory authority pursuant to the SDWA’s UIC program in 2014 over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities. Additionally, the EPA asserted regulatory authority under the SDWA UIC program in 2014 over hydraulic fracturing activities involving the use of diesel fuel and issued permitting guidance covering such activities. The EPA also published final CAA regulations in 2012 and in June 2016 governing performance standards, including standards for the capture of emissions 
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+released during oil and natural gas hydraulic fracturing. Also, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of produced water from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants and, in May 2014, published an Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. The BLM published a final rule in March 2015 that established new or more stringent standards relating to hydraulic fracturing on federal and Native American lands. However, in June 2016, a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority to promulge the rule, the BLM appealed the decision to the U.S. Circuit Court of Appeals for the Tenth Circuit in July 2016, the appellate court issued a ruling in September 2017 to vacate the Wyoming trial court decision and dismiss the lawsuit challenging the rule in light of the BLM’s proposed rulemaking and, in December 2017, the BLM published a final rule rescinding the March 2015 rule. In January 2018, litigation challenging the BLM’s rescission of the 2015 rule was brought in federal court. From time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. In the event that new federal restrictions relating to the hydraulic fracturing process are adopted in areas where we or our customers conduct business, we or our customers may incur additional costs or permitting requirements to comply with such federal requirements that may be significant and, in the case of our customers, also could result in added delays or curtailment in the pursuit of exploration, development, or production activities, which would in turn reduce the demand for our services. 
+Moreover, some states and local governments have adopted, and other governmental entities are considering adopting, regulations that could impose more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations, including states where we or our customers operate. For example, Texas, Colorado and North Dakota among others have adopted regulations that impose new or more stringent permitting, disclosure, disposal, and well construction requirements on hydraulic fracturing operations. States could also elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York. Local land use restrictions, such as city ordinances, may also restrict drilling in general and/or hydraulic fracturing in particular. 
+Furthermore, certain interest groups in Colorado opposed to oil and natural gas development generally, and hydraulic fracturing in particular, have from time to time advanced various options for ballot initiatives that, if approved, would allow revisions to the state constitution in a manner that would make such exploration and production activities in the state more difficult in the future. However, during the November 2016 voting process, one proposed amendment placed on the Colorado state ballot making it more difficult to place an initiative on the state ballot was passed by the voters. As a result, there are more stringent procedures now in place for placing an initiative on the state ballot. In the event that ballot initiatives or local or state restrictions or prohibitions are adopted in the future in areas where we or our customers conduct operations that impose more stringent limitations on the production and development of oil and natural gas, we may incur significant costs to comply with such requirements or our customers may experience delays or curtailment in the pursuit of exploration, development, or production activities. 
+Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to, and litigation concerning, oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays for our customers or increased operating costs in the production of oil and natural gas, including from the developing shale plays, or could make it more difficult for us and our customers to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and natural gas wells and an associated decrease in demand for our services and increased compliance costs and time, which could have a material adverse effect on our liquidity, combined results of operations, and combined financial condition. 
+Changes in transportation regulations may increase our costs and negatively impact our results of operations. 
+We are subject to various transportation regulations including as a motor carrier by the DOT and by various federal, state and tribal agencies, whose regulations include certain permit requirements of highway and safety authorities. These regulatory authorities exercise broad powers over our trucking operations, generally governing such matters as the authorization to engage in motor carrier operations, safety, equipment testing, driver requirements and specifications and insurance requirements. The trucking industry is subject to possible regulatory and legislative changes that may impact our operations, such as changes in fuel emissions limits, hours of service regulations that govern the amount of time a driver may drive or work in any specific period and requiring onboard electronic logging devices or limits on vehicle weight and size. As the federal government continues to develop and propose regulations relating to fuel quality, engine efficiency and greenhouse gas emissions, we may experience an increase in costs related to truck purchases and maintenance, impairment of equipment productivity, a decrease in the residual value of vehicles, unpredictable fluctuations in fuel prices and an increase in operating expenses. Increased truck traffic may contribute to deteriorating road conditions in some areas where our operations are performed. Our operations, including routing and weight restrictions, could be affected by road construction, road repairs, detours and state and local regulations and ordinances restricting access to certain roads. Proposals to increase federal, state or local taxes, including taxes on motor fuels, are also made from time to time, and any such increase would increase our operating costs. Also, state and local 
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+regulation of permitted routes and times on specific roadways could adversely affect our operations. We cannot predict whether, or in what form, any legislative or regulatory changes or municipal ordinances applicable to our logistics operations will be enacted and to what extent any such legislation or regulations could increase our costs or otherwise adversely affect our business or operations. 
+We are subject to environmental and occupational health and safety laws and regulations that may expose us to significant costs and liabilities. 
+Our operations and the operations of our customers are subject to numerous federal, tribal, regional, state and local laws and regulations relating to protection of the environment including natural resources, health and safety aspects of our operations and waste management, including the transportation and disposal of waste and other materials. These laws and regulations may impose numerous obligations on our operations and the operations of our customers, including the acquisition of permits or other approvals to conduct regulated activities, the imposition of restrictions on the types, quantities and concentrations of various substances that may be released into the environment or injected in non-productive formations below ground in connection with oil and natural gas drilling and production activities, the incurrence of capital expenditures to mitigate or prevent releases of materials from our equipment, facilities or from customer locations where we are providing services, the imposition of substantial liabilities for pollution resulting from our operations, and the application of specific health and safety criteria addressing worker protection. Any failure on our part or the part of our customers to comply with these laws and regulations could result in prohibitions or restrictions on operations, assessment of sanctions including administrative, civil and criminal penalties, issuance of corrective action orders requiring the performance of investigatory, remedial or curative activities or enjoining performance of some or all of our operations in a particular area, and the occurrence of delays in the permitting or performance of projects. 
+Our business activities present risks of incurring significant environmental costs and liabilities, including costs and liabilities resulting from our handling of oilfield and other wastes, because of air emissions and wastewater discharges related to our operations, and due to historical oilfield industry operations and waste disposal practices. In addition, private parties, including the owners of properties upon which we perform services and facilities where our wastes are taken for reclamation or disposal, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property or environmental natural resource damages. Some environmental laws and regulations may impose strict liability, which means that in some situations we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Remedial costs and other damages arising as a result of environmental laws and costs associated with changes in environmental laws and regulations could be significant and have a material adverse effect on our liquidity, combined results of operations and combined financial condition. 
+Laws and regulations protecting the environment generally have become more stringent in recent years and are expected to continue to do so, which could lead to material increases in costs for future environmental compliance and remediation. Changes in existing laws or regulations, or the adoption of new laws or regulations, could delay or curtail exploratory or developmental drilling for oil and natural gas by our customers and could limit our well servicing opportunities. For example, the EPA has designated energy extraction as one of seven national enforcement initiatives for 2017 to 2019, and has indicated that the agency will direct resources towards addressing incidences of noncompliance from natural gas extraction and production activities. We may not be able to recover some or any of our costs of compliance with these laws and regulations from insurance. 
+Silica-related legislation, health issues and litigation could have a material adverse effect on our business, reputation or results of operations. 
+We are subject to laws and regulations relating to human exposure to crystalline silica. In March 2016, OSHA amended its legal requirements, publishing a final rule that established a more stringent permissible exposure limit for exposure to respirable crystalline silica and provided other provisions to protect employees, such as requirements for exposure assessment, methods for controlling exposure, respiratory protection, medical surveillance, hazard communication, and recordkeeping. This final rule became effective in June 2016 and will require compliance with most applicable requirements by June 2018. Several industry groups had filed suit in the federal Court of Appeals for the D.C. Circuit to halt implementation of the rule but on December 22, 2017, the court dismissed the challenges to the rule. Historically, our environmental compliance costs with respect to existing crystalline silica requirements have not had a material adverse effect on our results of operations; however, federal and state regulatory authorities, including OSHA, may continue to propose changes in their regulations regarding workplace exposure to crystalline silica, such as permissible exposure limits and required controls and personal protective equipment. We may not be able to comply with any new laws and regulations that are adopted, and any new laws and regulations could have a material adverse effect on our operating results by requiring us to modify or cease our operations. 
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+In addition, the inhalation of respirable crystalline silica is associated with the lung disease silicosis. There is recent evidence of an association between crystalline silica exposure or silicosis and lung cancer and a possible association with other diseases, including immune system disorders such as scleroderma. These health risks have been, and may continue to be, a significant issue confronting the hydraulic fracturing industry. Concerns over silicosis and other potential adverse health effects, as well as concerns regarding potential liability from the use of hydraulic fracture sand, may have the effect of discouraging our customers’ use of our hydraulic fracture sand. The actual or perceived health risks of handling hydraulic fracture sand could materially and adversely affect hydraulic fracturing service providers, including us, through reduced use of hydraulic fracture sand, the threat of product liability or employee lawsuits, increased scrutiny by federal, state and local regulatory authorities of us and our customers or reduced financing sources available to the hydraulic fracturing industry. 
+Anti-indemnity provisions enacted by many states may restrict or prohibit a party’s indemnification of us. 
+We typically enter into agreements with our customers governing the provision of our services, which usually include certain indemnification provisions for losses resulting from operations. Such agreements may require each party to indemnify the other against certain claims regardless of the negligence or other fault of the indemnified party; however, many states place limitations on contractual indemnity agreements, particularly agreements that indemnify a party against the consequences of its own negligence. Furthermore, certain states, including Texas, New Mexico and Wyoming, have enacted statutes generally referred to as “oilfield anti-indemnity acts” expressly prohibiting certain indemnity agreements contained in or related to oilfield services agreements. Such anti-indemnity acts may restrict or void a party’s indemnification of us, which could have a material adverse effect on our business, financial condition, prospects and results of operations. 
+Oil and natural gas companies’ operations using hydraulic fracturing are substantially dependent on the availability of water. Restrictions on the ability to obtain water for exploration and production activities and the disposal of flowback and produced water may impact their operations and have a corresponding adverse effect on our business, results of operations and financial condition. 
+Water is an essential component of shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Our oil and natural gas producing customers’ access to water to be used in these processes may be adversely affected due to reasons such as periods of extended drought, privatization, third party competition for water in localized areas or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. The occurrence of these or similar developments may result in limitations being placed on allocations of water due to needs by third party businesses with more senior contractual or permitting rights to the water. Our customers’ inability to locate or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact their exploration and production operations and have a corresponding adverse effect on our business, results of operations and financial condition. 
+Moreover, the imposition of new environmental regulations and other regulatory initiatives could include increased restrictions on our producing customers’ ability to dispose of flowback and produced water generated in hydraulic fracturing or other fluids resulting from exploration and production activities. Applicable laws, including the CWA impose restrictions and strict controls regarding the discharge of pollutants into waters of the United States and require that permits or other approvals be obtained to discharge pollutants to such waters. In May 2015, the EPA and the Corps released a final rule outlining their position on the federal jurisdictional reach over waters of the United States, including wetlands, but legal challenges to this rule followed, and the rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals in October 2015, pending resolution of the court challenges. In January 2017, the United States Supreme Court accepted review of the rule to determine whether jurisdiction rests with the federal district or appellate courts and, in a decision issued on January 22, 2018, held that legal challenges of the rule must be heard at the district rather than appellate court level. The Sixth Circuit lifted its stay of the 2015 rule in February 2018. Additionally, following issuance of a presidential executive order to review the rule, the EPA and the Corps published a proposed rulemaking in July 2017 to repeal the 2015 rule. The EPA and the Corps also announced their intent to issue a new rule defining the CWA’s jurisdiction. On February 6, 2018, the EPA and the Corps published a final rule specifying that the contested 2015 rule would not take effect until February 6, 2020. As a result, future implementation of the 2015 rule is uncertain at this time. To the extent this rule or a revised rule expands the scope of the CWA’s jurisdiction in areas where we or our customers operate, it could impose additional permitting obligations on us and our customers. 
+Additionally, regulations implemented under the CWA and similar state laws prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. In June 2016, the EPA published final regulations produced water discharges from hydraulic fracturing and certain other natural gas operations to publicly-owned wastewater treatment plants. The CWA and analogous state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and hazardous substances. Compliance with current and future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells and any inability to secure transportation and access to disposal wells with sufficient capacity to accept all of our flowback and 
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+produced water on economic terms may increase our customers’ operating costs and cause delays, interruptions or termination of our customers’ operations, the extent of which cannot be predicted. 
+Our current and future indebtedness could adversely affect our financial condition. 
+As of March 23, 2018, we have no borrowings outstanding under our ABL Credit Facility and $113.5 million outstanding under our Term Loan Facility. In addition, we may be able to borrow up to $250 million under our ABL Credit Facility, subject to certain borrowing base limitations. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements.” 
+Moreover, subject to the limits contained in our ABL Credit Facility and Term Loan Credit Facility (collectively, the “Credit Facilities”), we may incur substantial additional debt from time to time. Any borrowings we may incur in the future would have several important consequences for our future operations, including that: 
+• 
+covenants contained in the documents governing such indebtedness may require us to meet or maintain certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our industry, such as being able to take advantage of acquisition opportunities when they arise; 
+• 
+our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes may be limited; 
+• 
+we may be competitively disadvantaged to our competitors that are less leveraged or have greater access to capital resources; and 
+• 
+we may be more vulnerable to adverse economic and industry conditions. 
+If we incur indebtedness in the future, we may have significant principal payments due at specified future dates under the documents governing such indebtedness. Our ability to meet such principal obligations will be dependent upon future performance, which in turn will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. Our business may not continue to generate sufficient cash flow from operations to repay any incurred indebtedness. If we are unable to generate sufficient cash flow from operations, we may be required to sell assets, to refinance all or a portion of such indebtedness or to obtain additional financing. 
+Our Credit Facilities subject us to financial and other restrictive covenants. These restrictions may limit our operational or financial flexibility and could subject us to potential defaults under our Credit Facilities. 
+Our Credit Facilities subject us to restrictive covenants, including, but not limited to, restrictions on incurring additional debt and certain distributions. Our ability to comply with these financial condition tests can be affected by events beyond our control and we may not be able to do so. 
+The Credit Facilities are not subject to financial covenants unless our liquidity, as defined in the agreements governing the Credit Facilities, drops below a specified level, at which time we will be required to maintain certain fixed charge coverage ratios. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreement.” 
+If our liquidity falls below the prescribed level and we are unable to remain in compliance with the financial covenants of our Credit Facilities, then amounts outstanding thereunder may be accelerated and become due immediately. Any such acceleration could have a material adverse effect on our financial condition and results of operations. 
+Increases in interest rates could adversely impact the price of our shares, our ability to issue equity or incur debt for acquisitions or other purposes. 
+Interest rates on future borrowings, credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our shares, and a rising interest rate environment could have an adverse impact on the price of our shares, our ability to issue equity or incur debt for acquisitions or other purposes. 
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+Fuel conservation measures could reduce demand for oil and natural gas which would in turn reduce the demand for our services. 
+Fuel conservation measures, alternative fuel requirements and increasing consumer demand for alternatives to oil and natural gas could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas may have a material adverse effect on our business, financial condition, prospects, results of operations and cash flows. Additionally, the increased competitiveness of alternative energy sources (such as wind, solar geothermal, tidal, and biofuels) could reduce demand for hydrocarbons and therefore for our services, which would lead to a reduction in our revenues. 
+Unsatisfactory safety performance may negatively affect our customer relationships and, to the extent we fail to retain existing customers or attract new customers, adversely impact our revenues. 
+Our ability to retain existing customers and attract new business is dependent on many factors, including our ability to demonstrate that we can reliably and safely operate our business in a manner that is consistent with applicable laws, rules and permits, which legal requirements are subject to change. Existing and potential customers consider the safety record of their third-party service providers to be of high importance in their decision to engage such providers. If one or more accidents were to occur at one of our operating sites, the affected customer may seek to terminate or cancel its use of our equipment or services and may be less likely to continue to use our services, which could cause us to lose substantial revenues. Furthermore, our ability to attract new customers may be impaired if they elect not to engage us because they view our safety record as unacceptable. In addition, it is possible that we will experience multiple or particularly severe accidents in the future, causing our safety record to deteriorate. This may be more likely as we continue to grow, if we experience high employee turnover or labor shortage, or hire inexperienced personnel to bolster our staffing needs. 
+Climate change legislation and regulations restricting or regulating emissions of greenhouse gases could result in increased operating and capital costs and reduced demand for our hydraulic fracturing services. 
+Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. 
+At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted rules under authority of the federal Clean Air Act that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions, which reviews could require securing PSD permits at covered facilities emitting GHGs and meeting “best available control technology” standards for those GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the U.S., including, among others, onshore and offshore production facilities, which include certain of our producing customers’ operations. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells, and in January 2016, the EPA proposed additional revisions to leak detection methodology to align the reporting rules with the new source performance standards. 
+Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published NSPS Subpart OOOOa, which requires certain new, modified or reconstructed equipment and processes in the oil and natural gas source category to reduce these methane gas and VOC emissions. These Subpart OOOOa standards will expand previously issued NSPS Subpart OOOO published by the EPA in 2012 by using certain equipment-specific emissions control practices. However, in June 2017, the EPA published a proposed rule to stay certain portions of the June 2016 standards for two years and re-evaluate the entirety of the 2016 standards but the EPA has not yet published a final rule and, as a result, the June 2016 rule remains in effect but future implementation of the 2016 standards is uncertain at this time. Furthermore, in November 2016, the BLM published a final rule that established, among other things, requirements to reduce methane emissions arising from venting, flaring and leaks from oil and natural gas production activities on onshore federal and Native American lands. However, in December 2017, the BLM published a final rule to temporarily suspend or delay certain requirements contained in the November 2016 final rule until January 17, 2019, including those requirements relating to the venting, flaring and leakage from oil and natural gas production activities. The suspension of the November 2016 final rule is being challenged in court. Given the long-term trend towards increasing regulation, future federal GHG regulations of the oil and natural gas industry remain a possibility, and should the EPA’s June 2016 or the BLM’s November 2016 rules remain in effect, or any other new methane emission standards be imposed on the oil and natural gas sector, such requirements could result in increased costs to our or our customers’ operations as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect our business. Additionally, in December 2015, the United States 
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+joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that prepared an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered in force in November 2016; however, the GHG emission reductions called for by the Paris Agreement are not binding. In August 2017, the U.S. State Department informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time. 
+The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production or midstream activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and natural gas will continue to represent a substantial percentage of global energy use over that time. Finally, some scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on our operations and the operations of our customers. 
+The Endangered Species Act and Migratory Bird Treaty Act and other restrictions intended to protect certain species of wildlife govern our and our oil and natural gas producing customers’ operations and additional restrictions may be imposed in the future, which constraints could have an adverse impact on our ability to expand some of our existing operations or limit our customers’ ability to develop new oil and natural gas wells. 
+Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife, which may limit our ability to operate in protected areas. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. 
+For example, the ESA restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the MBTA. To the extent species that are listed under the ESA or similar state laws, or are protected under the MBTA, live in the areas where we or our oil and natural gas producing customers’ operate, our and our customers’ abilities to conduct or expand operations and construct facilities could be limited or be forced to incur material additional costs. Moreover, our customer’s drilling activities may be delayed, restricted or precluded in protected habitat areas or during certain seasons, such as breeding and nesting seasons. Some of our operations and the operations of our customers are located in areas that are designated as habitats for protected species. 
+Moreover, as a result of one or more settlements approved by the federal government, the FWS must make determinations on the listing of numerous species as endangered or threatened under the ESA pursuant to specific timelines. The designation of previously unidentified endangered or threatened species could indirectly cause us to incur additional costs, cause our or our oil and natural gas producing customers’ operations to become subject to operating restrictions or bans, and limit future development activity in affected areas. The FWS and similar state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially restrict use of or access to federal, state and private lands. 
+We may have difficulty managing growth of our business, which could adversely affect our financial condition and results of operations. 
+As a recently formed company, growth of our business could place a significant strain on our financial, technical, operational and management resources. As we expand the scope of our activities and our geographic coverage through organic growth, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, engineers and other professionals in the oilfield services industry, could have a material adverse effect on our business, financial condition, results of operations and our ability to successfully or timely execute our business plan. 
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+We rely on a few key employees whose absence or loss could adversely affect our business. 
+Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team, including our chief executive officer, chief financial officer and president, could disrupt our operations. We do not have any written employment agreement with our executives at this time. Further, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees. 
+We may be subject to risks in connection with acquisitions. 
+We have completed and may, in the future, pursue asset acquisitions or acquisitions of businesses. The process of upgrading acquired assets to our specifications and integrating acquired assets or businesses may involve unforeseen costs and delays or other operational, technical and financial difficulties and may require a significant amount time and resources. Our failure to incorporate acquired assets or businesses into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations. Such events could also mean an acquisition that we expected to be accretive is not accretive and, in extreme cases, the asset is idle. 
+Our industry overall has experienced a high rate of employee turnover. Any difficulty we experience replacing or adding personnel could have a material adverse effect on our liquidity, results of operations and financial condition. 
+We are dependent upon the available labor pool of skilled employees and may not be able to find enough skilled labor to meet our needs, which could have a negative effect on our growth. We are also subject to the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions. Our services require skilled workers who can perform physically demanding work. As a result of our industry volatility, including the recent and pronounced decline in drilling activity, as well as the demanding nature of the work, many workers have left the hydraulic fracturing industry to pursue employment in different fields. Though our historical turnover rates have been significantly lower than those of our competitors, if we are unable to retain or meet growing demand for skilled technical personnel, our operating results and our ability to execute our growth strategies may be adversely affected. 
+Technology advancements in well service technologies, including those involving hydraulic fracturing, could have a material adverse effect on our business, financial condition and results of operations. 
+The hydraulic fracturing industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As competitors and others use or develop new technologies or technologies comparable to ours in the future, we may lose market share or be placed at a competitive disadvantage. Further, we may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of our competitors may have greater financial, technical and personnel resources than we do, which may allow them to gain technological advantages or implement new technologies before we can. Additionally, we may be unable to implement new technologies or services at all, on a timely basis or at an acceptable cost. New technology could also make it easier for our customers to vertically integrate their operations, thereby reducing or eliminating the need for our services. Limits on our ability to effectively use or implement new technologies may have a material adverse effect on our business, financial condition and results of operations. 
+We may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition, prospects and results of operations. 
+Our services are subject to inherent risks that can cause personal injury or loss of life, damage to or destruction of property, equipment or the environment or the suspension of our operations. Litigation arising from operations where our services are provided, may cause us to be named as a defendant in lawsuits asserting potentially large claims including claims for exemplary damages. We maintain what we believe is customary and reasonable insurance to protect our business against these potential losses, but such insurance may not be adequate to cover our liabilities, and we are not fully insured against all risks. 
+In addition, our customers assume responsibility for, including control and removal of, all other pollution or contamination which may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling and completion fluids. We may have liability in such cases if we are negligent or commit willful acts. Our customers generally agree to indemnify us against claims arising from their employees’ personal injury or death to the extent that, in the case of our hydraulic fracturing operations, their employees are injured or their properties are damaged by such operations, unless resulting from our gross negligence or willful misconduct. Our customers also generally agree to indemnify us for loss or destruction of customer-owned property or equipment. In turn, we agree to indemnify our customers for loss or 
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+destruction of property or equipment we own and for liabilities arising from personal injury to or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. However, we might not succeed in enforcing such contractual liability allocation or might incur an unforeseen liability falling outside the scope of such allocation. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operation. 
+Seasonal weather conditions and natural disasters could severely disrupt normal operations and harm our business. 
+Our operations are located in different regions of the United States. Some of these areas, including the DJ Basin, Powder River Basin and Williston Basin, are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice or rain, we may be unable to move our equipment between locations, thereby reducing our ability to provide services and generate revenues. The exploration activities of our customers may also be affected during such periods of adverse weather conditions. Additionally, extended drought conditions in our operating regions could impact our ability or our customers’ ability to source sufficient water or increase the cost for such water. As a result, a natural disaster or inclement weather conditions could severely disrupt the normal operation of our business and adversely impact our financial condition and results of operations. 
+If we are unable to fully protect our intellectual property rights, we may suffer a loss in our competitive advantage or market share. 
+We do not have patents or patent applications relating to many of our key processes and technology. If we are not able to maintain the confidentiality of our trade secrets, or if our competitors are able to replicate our technology or services, our competitive advantage would be diminished. We also cannot assure you that any patents we may obtain in the future would provide us with any significant commercial benefit or would allow us to prevent our competitors from employing comparable technologies or processes. 
+We may be adversely affected by disputes regarding intellectual property rights of third parties. 
+Third parties from time to time may initiate litigation against us by asserting that the conduct of our business infringes, misappropriates or otherwise violates intellectual property rights. We may not prevail in any such legal proceedings related to such claims, and our products and services may be found to infringe, impair, misappropriate, dilute or otherwise violate the intellectual property rights of others. If we are sued for infringement and lose, we could be required to pay substantial damages and/or be enjoined from using or selling the infringing products or technology. Any legal proceeding concerning intellectual property could be protracted and costly regardless of the merits of any claim and is inherently unpredictable and could have a material adverse effect on our financial condition, regardless of its outcome. For instance, SandBox Logistics, LLC and Oren Technologies, LLC (collectively, “SandBox”) have filed a suit against us, alleging, amongst other things, that we have infringed upon certain U.S. patents. Please see “Item 3. Legal Proceedings.” 
+If we were to discover that our technologies or products infringe valid intellectual property rights of third parties, we may need to obtain licenses from these parties or substantially re-engineer our products in order to avoid infringement. We may not be able to obtain the necessary licenses on acceptable terms, or at all, or be able to re-engineer our products successfully. If our inability to obtain required licenses for our technologies or products prevents us from selling our products, that could adversely impact our financial condition and results of operations. 
+Additionally, we currently license certain third party intellectual property in connection with our business, and the loss of any such license could adversely impact our financial condition and results of operations. 
+We may be subject to interruptions or failures in our information technology systems. 
+We rely on sophisticated information technology systems and infrastructure to support our business, including process control technology. Any of these systems may be susceptible to outages due to fire, floods, power loss, telecommunications failures, usage errors by employees, computer viruses, cyber-attacks or other security breaches, or similar events. The failure of any of our information technology systems may cause disruptions in our operations, which could adversely affect our sales and profitability. 
+We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss. 
+The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain processing activities. For example, we depend on digital technologies to perform many of our services and to process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, 
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+systems and networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we will likely be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. Our insurance coverage for cyberattacks may not be sufficient to cover all the losses we may experience as a result of such cyberattacks. 
+A terrorist attack or armed conflict could harm our business. 
+The occurrence or threat of terrorist attacks in the United States or other countries, anti-terrorist efforts and other armed conflicts involving the United States or other countries, including continued hostilities in the Middle East, may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all. 
+We engage in transactions with related parties and such transactions present possible conflicts of interest that could have an adverse effect on us. 
+We have entered into a significant number of transactions with related parties. The details of certain of these transactions are set forth in “Item 13. Certain Relationships and Related Party Transactions.” Related party transactions create the possibility of conflicts of interest with regard to our management, including that: 
+• 
+we may enter into contracts between us, on the one hand, and related parties, on the other, that are not the result of arm’s-length transactions; 
+• 
+our executive officers and directors that hold positions of responsibility with related parties may be aware of certain business opportunities that are appropriate for presentation to us as well as to such other related parties and may present such business opportunities to such other parties; and 
+• 
+our executive officers and directors that hold positions of responsibility with related parties may have significant duties with, and spend significant time serving, other entities and may have conflicts of interest in allocating time. 
+Such conflicts could cause an individual in our management to seek to advance his or her economic interests or the economic interests of certain related parties above ours. Further, the appearance of conflicts of interest created by related party transactions could impair the confidence of our investors. Our audit committee reviews these transactions. Notwithstanding this, it is possible that a conflict of interest could have a material adverse effect on our liquidity, results of operations and financial condition. 
+Our historical financial statements may not be indicative of future performance. 
+Due to the sharp decline in demand for well services beginning in late 2014, our acquisition of certain assets in June 2016 and the recent recovery of activity in our well services industry, comparisons of our current and future operating results with prior periods are difficult. As a result, our limited historical financial performance as the owner of the acquired assets may make it difficult for stockholders to evaluate our business and results of operations to date and to assess our future prospects and viability. Furthermore, as a result of a significant increase in our capacity, our movement into new basins and our future implementation of new business initiatives and strategies following the acquisition of assets, our historical results of operations are not necessarily indicative of our ongoing operations and the operating results to be expected in the future. 
+We may record losses or impairment charges related to idle assets or assets that we sell. 
+Prolonged periods of low utilization, changes in technology or the sale of assets below their carrying value may cause us to experience losses. These events could result in the recognition of impairment charges that negatively impact our financial results. Significant impairment charges as a result of a decline in market conditions or otherwise could have a material adverse effect on our results of operations in future periods. 
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+Risks Related to Our Class A Common Stock 
+Liberty Inc. is a holding company. Liberty Inc.’s only material asset is its equity interest in Liberty LLC, and Liberty Inc. is accordingly dependent upon distributions from Liberty LLC to pay taxes, make payments under the Tax Receivable Agreements and cover its corporate and other overhead expenses. 
+Liberty Inc. is a holding company and will have no material assets other than its equity interest in Liberty LLC. Please see “Item 1. Business—Initial Public Offering and Reorganization Transaction.” Liberty Inc. will have no independent means of generating revenue. To the extent Liberty LLC has available cash, Liberty Inc. intends to cause Liberty LLC to make (i) generally pro rata distributions to its unit holders, including Liberty Inc., in an amount sufficient to allow Liberty Inc. to pay its taxes and to allow it to make payments under the Tax Receivable Agreements and (ii) non-pro rata payments to Liberty Inc. to reimburse it for its corporate and other overhead expenses. To the extent that Liberty Inc. needs funds and Liberty LLC or its subsidiaries are restricted from making such distributions or payments under applicable law or regulation or under the terms of any future financing arrangements, or are otherwise unable to provide such funds, Liberty Inc.’s liquidity and financial condition could be materially adversely affected. 
+Moreover, because Liberty Inc. will have no independent means of generating revenue, Liberty Inc.’s ability to make payments under the Tax Receivable Agreements is dependent on the ability of Liberty LLC to make distributions to Liberty Inc. in an amount sufficient to cover its obligations under the Tax Receivable Agreements. This ability, in turn, may depend on the ability of Liberty LLC’s subsidiaries to make distributions to it. The ability of Liberty LLC, its subsidiaries and other entities in which it directly or indirectly holds an equity interest to make such distributions will be subject to, among other things, (i) the applicable provisions of Delaware law (or other applicable jurisdiction) that may limit the amount of funds available for distribution and (ii) restrictions in relevant debt instruments issued by Liberty LLC or its subsidiaries and other entities in which it directly or indirectly holds an equity interest. To the extent that Liberty Inc. is unable to make payments under the Tax Receivable Agreements for any reason, such payments will be deferred and will accrue interest until paid. 
+The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act, and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner. 
+As a public company, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the New York Stock Exchange (the “NYSE”), with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We will need to: 
+• 
+institute a more comprehensive compliance function; 
+• 
+comply with rules promulgated by the NYSE; 
+• 
+continue to prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws; 
+• 
+establish new internal policies, such as those relating to insider trading; and 
+• 
+involve and retain to a greater degree outside counsel and accountants in the above activities. 
+Furthermore, we are required to have our independent registered public accounting firm attest to the effectiveness of our internal controls, in accordance with Section 404 of the Sarbanes Oxley Act for our fiscal year ending December 31, 2018. Our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed. Compliance with these requirements may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner. 
+In addition, we expect that being a public company subject to these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. We are currently evaluating these rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs. 
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+If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our Class A Common Stock. 
+Effective internal controls are necessary for us to provide reliable financial reports, safeguard our assets, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports, safeguard our assets, or prevent fraud, our reputation and operating results could be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our existing internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. An ineffective system of internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our Class A Common Stock. 
+We have identified a material weakness in our internal control over financial reporting and may identify additional material weaknesses in the future or otherwise fail to maintain an effective system of internal controls, which may result in material misstatements of our financial statements or cause us to fail to meet our periodic reporting obligations. 
+Prior to the IPO, we were a private company with limited accounting personnel and other resources with which to address our internal controls and procedures. We have not completed an assessment of the effectiveness of our internal control over financial reporting, and our independent registered public accounting firm has not conducted an audit of our internal control over financial reporting. We have a material weakness in our internal control over financial reporting as of December 31, 2017, which was also identified and communicated to us by our independent registered public accounting firm. A “material weakness” is a deficiency, or combination of deficiencies, in internal controls such that there is a reasonable possibility that a material misstatement in financial statements will not be prevented or detected on a timely basis. 
+The material weakness identified relates to the lack of implementation and maintenance of effective segregation of duties, including controls over journal entries, that would provide a reasonable possibility that a material misstatement would be prevented or detected on a timely basis. 
+In early 2018, we began taking steps to implement controls to remediate the material weakness, including the following: 
+• 
+utilizing information technology personnel to review system authorization among users to ensure proper segregation of duties; and 
+• 
+engagement of a third party to assist in our documentation, implementation and testing of internal controls related to segregation of duties, including controls over journal entries. 
+We can give no assurance that these actions will remediate this deficiency in internal control or that additional material weaknesses or significant deficiencies in our internal control over financial reporting will not be identified in the future. Our failure to design, implement and maintain effective internal control over financial reporting could result in errors in our financial statements that could result in a restatement of our financial statements and cause us to fail to meet our reporting obligations. Please see “Risk Factors—The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act, and the requirements of the Sarbanes- Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.” 
+An active, liquid and orderly trading market for our Class A Common Stock may not be maintained, and our stock price may be volatile. 
+Prior to January 2018, our Class A Common Stock was not traded on any market. An active, liquid and orderly trading market for our Class A Common Stock may not be maintained. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. The market price of our Class A Common Stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our Class A Common Stock, you could lose a substantial part or all of your investment in our Class A Common Stock. 
+The following factors could affect our stock price: 
+• 
+quarterly variations in our financial and operating results; 
+• 
+the public reaction to our press releases, our other public announcements and our filings with the SEC; 
+• 
+strategic actions by our competitors; 
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+• 
+changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts; 
+• 
+speculation in the press or investment community; 
+• 
+the failure of specific research analysts to cover our Class A Common Stock; 
+• 
+sales of our Class A Common Stock by us, the selling shareholder or other stockholders, or the perception that such sales may occur; 
+• 
+changes in accounting principles, policies, guidance, interpretations or standards; 
+• 
+additions or departures of key management personnel; 
+• 
+actions by our stockholders; 
+• 
+general market conditions, including fluctuations in commodity prices; 
+• 
+domestic and international economic, legal and regulatory factors unrelated to our performance; and 
+• 
+the realization of any risks described under this “Risk Factors” section. 
+The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our Class A Common Stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management’s attention and resources and harm our business, operating results and financial condition. 
+We are a “controlled company” within the meaning of the NYSE rules and, as a result, qualify for and rely on exemptions from certain corporate governance requirements. As a result. our stockholders do not have the same protections afforded to stockholders of companies that cannot rely on such exemptions and are subject to such requirements. 
+Riverstone and the Legacy Owners party to the stockholders’ agreement (collectively, the “Principal Stockholders”) described in “Item 13. Certain Relationships and Related-Party Transactions and Director Independence—Stockholders’ Agreement” control a majority of the combined voting power of our Common Stock. As a result, we are a “controlled company” within the meaning of the NYSE corporate governance standards. Under these rules, a company of which more than 50% of the voting power is held by an individual, a group or another company is a “controlled company” and may elect not to comply with certain corporate governance requirements of the NYSE, including the requirement (1) that a majority of the board of directors consist of independent directors, (2) that we have a nominating and corporate governance committee composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities, and (3) that we have a compensation committee composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities. We intend to rely on some or all of these exemptions. As a result, we do not have a majority of independent directors or a nominating or governance committee, and our compensation committee does not consist entirely of independent directors. Accordingly, our stockholders do not have the same protections afforded to stockholders of companies subject to all of the corporate governance requirements of the NYSE. 
+The Legacy Owners collectively hold a substantial majority of the voting power of our common stock 
+The Legacy Owners hold approximately 87.6% of our voting stock. As a result, the Legacy Owners are able to control matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our Class A Common Stock will be able to affect the way we are managed or the direction of our business. The interests of the Legacy Owners with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other stockholders. 
+For example, the Legacy Owners may have different tax positions from us, especially in light of the Tax Receivable Agreements, that could influence their decisions regarding whether and when to support the disposition of assets, the incurrence or refinancing of new or existing indebtedness, or the termination of the Tax Receivable Agreements and acceleration of our obligations thereunder. In addition, the determination of future tax reporting positions, the structuring of future transactions and the handling of any challenge by any taxing authority to our tax reporting positions may take into consideration the Legacy Owners tax position or other considerations which may differ from the considerations of us or our other stockholders. Please read “Certain Relationships and Related Party Transactions—Tax Receivable Agreements.” 
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+Given this concentrated ownership, the Legacy Owners would have to approve any potential acquisition of us. Furthermore, in connection with the IPO, we entered into a stockholders’ agreement with Riverstone, affiliates of Laurel Road, LLC and Spruce Road, LLC and certain investors in Spruce Road, LLC (collectively, the “Principal Stockholders”). The stockholders’ agreement provides Riverstone with the right to designate a certain number of nominees to our board of directors so long as Riverstone and its affiliates collectively beneficially own at least 10% of the outstanding shares of our Class A Common Stock. In addition, the stockholders’ agreement provides Riverstone the right to approve certain material transactions so long as Riverstone and its affiliates own at least 20% of the outstanding shares of our Class A Common Stock. See “Certain Relationships and Related Party Transactions—Stockholders’ Agreement.” The existence of significant stockholders may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company. Moreover, the Legacy Owners concentration of stock ownership may adversely affect the trading price of our Class A Common Stock to the extent investors perceive a disadvantage in owning stock of a company with significant stockholders. 
+Certain of our executive officers and directors have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities. 
+Certain of our executive officers and directors, who are responsible for managing the direction of our operations, hold positions of responsibility with other entities (including affiliated entities) that are in the oil and natural gas industry. For example, Christopher Wright, our Chairman and Chief Executive Officer, is the Executive Chairman of Liberty Resources LLC (“Liberty Resources”), an E&P company operating primarily in the Williston Basin, a position which may require a significant portion of his time. These executive officers and directors may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, they may present potential business opportunities to other entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated, and as a result, they may elect not to present those opportunities to us. These conflicts may not be resolved in our favor. For additional discussion of our management’s business affiliations and the potential conflicts of interest of which our stockholders should be aware, see “Item 13. Certain Relationships and Related Party Transactions.” 
+Riverstone and its respective affiliates are not limited in their ability to compete with us, and the corporate opportunity provisions in our amended and restated certificate of incorporation could enable Riverstone to benefit from corporate opportunities that might otherwise be available to us. 
+Our governing documents provide that Riverstone and its respective affiliates (including portfolio investments of Riverstone its affiliates) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In particular, subject to the limitations of applicable law, our amended and restated certificate of incorporation will, among other things: 
+• 
+permits Riverstone and its respective affiliates to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and 
+• 
+provides that if Riverstone or its respective affiliates, or any employee, partner, member, manager, officer or director of Riverstone or its respective affiliates who is also one of our directors or officers, becomes aware of a potential business opportunity, transaction or other matter, they have no duty to communicate or offer that opportunity to us. 
+Riverstone or its respective affiliates may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Furthermore, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to not be available to us or causing them to be more expensive for us to pursue. In addition, Riverstone and its respective affiliates may dispose of oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase any of those assets. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to time presented to Riverstone and its respective affiliates could adversely impact our business or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours. 
+A significant reduction by Riverstone of its ownership interests in us could adversely affect us. 
+We believe that Riverstone’s ownership interests in us provides it with an economic incentive to assist us to be successful. Upon the expiration or earlier waiver of the lock-up restrictions on transfers or sales of our securities following the completion 
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+of the IPO, Riverstone will not be subject to any obligation to maintain its ownership interest in us and may elect at any time thereafter to sell all or a substantial portion of or otherwise reduce its ownership interest in us. If Riverstone sells all or a substantial portion of its ownership interest in us, it may have less incentive to assist in our success and its affiliate(s) that are expected to serve as members of our board of directors may resign. Such actions could adversely affect our ability to successfully implement our business strategies which could adversely affect our cash flows or results of operations. 
+Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A Common Stock and could deprive our investors of the opportunity to receive a premium for their shares. 
+Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval in one or more series, designate the number of shares constituting any series, and fix the rights, preferences, privileges and restrictions thereof, including dividend rights, voting rights, rights and terms of redemption, redemption price or prices and liquidation preferences of such series. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders. These provisions include: 
+• 
+after we cease to be a controlled company, dividing our board of directors into three classes of directors, with each class serving staggered three-year terms; 
+• 
+after we cease to be a controlled company, and subject to the terms of our stockholders’ agreement, providing that all vacancies, including newly created directorships, may, except as otherwise required by law or, if applicable, the rights of holders of a series of preferred stock, only be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum (prior to such time, vacancies may also be filled by stockholders holding a majority of the outstanding shares); 
+• 
+after we cease to be a controlled company, permitting any action by stockholders to be taken only at an annual meeting or special meeting rather than by a written consent of the stockholders, subject to the rights of any series of preferred stock with respect to such rights; 
+• 
+after we cease to be a controlled company, permitting special meetings of our stockholders to be called only by our Chief Executive Officer, the chairman of our board of directors and our board of directors pursuant to a resolution adopted by the affirmative vote of a majority of the total number of authorized directors whether or not there exist any vacancies in previously authorized directorships (prior to such time, a special meeting may also be called by our Corporate Secretary at the request of Riverstone); 
+• 
+after we cease to be a controlled company, and subject to the rights of the holders of shares of any series of our preferred stock and the terms of our stockholders’ agreement, requiring the affirmative vote of the holders of at least 66 2 ⁄ 3 % in voting power of all then outstanding common stock entitled to vote generally in the election of directors, voting together as a single class, to remove any or all of the directors from office at any time, and directors will be removable only for “cause”; 
+• 
+prohibiting cumulative voting in the election of directors; 
+• 
+establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders; and 
+• 
+providing that the board of directors is expressly authorized to adopt, or to alter or repeal our bylaws. 
+In addition, certain change of control events have the effect of accelerating the payments due under the Tax Receivable Agreements, which could be substantial and accordingly serve as a disincentive to a potential acquirer of our company. Please see “—In certain cases, payments under the Tax Receivable Agreements may be accelerated and/or significantly exceed the actual benefits, if any, Liberty Inc. realizes in respect of the tax attributes subject to the Tax Receivable Agreements.” 
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+Our amended and restated certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents. 
+Our amended and restated certificate of incorporation will provide that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim against us or any director or officer or other employee of ours arising pursuant to any provision of the Delaware General Corporation Law (the “DGCL”), our amended and restated certificate of incorporation or our bylaws, or (iv) any action asserting a claim against us or any director or officer or other employee of ours that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our amended and restated certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations. 
+If a substantial number of shares of Class A Common Stock becomes available for sale and are sold in a short period of time, the market price of our common stock could decline and our stockholders may be diluted. 
+If our Legacy Owners sell substantial amounts of our Class A Common Stock in the public market, the market price of our Class A Common Stock could decrease. The perception in the public market that our Legacy Owners might sell shares of our Class A Common Stock could also create a perceived overhang and depress our market price. We have 69,975,174 shares of Class A Common Stock outstanding of which 55,334,419 shares are held by our Legacy Owners. In addition, our Legacy Owners hold Liberty LLC Units and shares of our Class B Common Stock which are exchangeable for an additional 48,207,372 shares of Class A Common Stock. Prior to the IPO, we and our Legacy Owners agreed with the underwriters to a “lock-up” period, meaning that such parties may not, subject to certain exceptions, sell any of their existing shares of our common stock without the prior written consent of representatives of the underwriters for at least 180 days after January 11, 2018. In addition, all of our Legacy Owners will be subject to the holding period requirement of Rule 144 under the Securities Act (“Rule 144”). When the lock-up agreements expire, these shares will become eligible for sale, in some cases subject to the requirements of Rule 144. 
+In addition, our Legacy Owners, will have substantial demand and incidental registration rights, as described in “Item 13. Certain Relationships and Related-Party Transactions and Director Independence-Stockholders’ Agreement.” The market price for shares of our common stock may drop when the restrictions on resale by our Legacy Owners lapse. 
+Any sale of additional common stock by our Legacy Owners in the public market may result in additional dilution to our stockholders. 
+We do not currently plan to pay regular cash dividends on our Class A Common Stock, and our credit agreements will place certain restrictions on our ability to do so. Consequently, your primary opportunity to achieve a return on your investment is if the price of our Class A Common Stock appreciates. 
+We do not currently plan to declare regular cash dividends on shares of our Class A Common Stock in the foreseeable future. Additionally, our Credit Facilities place certain restrictions on our ability to pay cash dividends. Consequently, your primary opportunity to achieve a return on your investment in us will be if you sell your Class A Common Stock at a price greater than you paid for it. There is no guarantee that the price of our Class A Common Stock that will prevail in the market will ever exceed the price that you paid to purchase such Class A Common Stock. 
+Future sales of our Class A Common Stock in the public market, or the perception that such sales may occur, could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us. 
+We may sell additional shares of Class A Common Stock in subsequent public offerings. We may also issue additional shares of Class A Common Stock or convertible securities. We presently have 69,975,174 shares of Class A Common Stock issued and outstanding. The Legacy Owners own 55,334,419 shares of our Class A Common Stock and 48,207,372 shares of our Class B Common Stock, or approximately 87.6% of our total outstanding shares of common stock. The Liberty Unit 
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+Holders are party to a registration rights agreement, which requires us to effect the registration of any shares of Class A Common Stock that they receive in exchange for their Liberty LLC Units in certain circumstances no earlier than the expiration of the lock-up period contained in the underwriting agreement entered into in connection with the IPO. 
+We have 12,908,734 shares of our Class A Common Stock issued or reserved for issuance under our long term incentive plan. Subject to the satisfaction of vesting conditions, the expiration of lock-up agreements and the requirements of Rule 144, shares registered under the registration statement on Form S-8 may be made available for resale immediately in the public market without restriction. 
+We cannot predict the size of future issuances of our Class A Common Stock or securities convertible into Class A Common Stock or the effect, if any, that future issuances and sales of shares of our Class A Common Stock will have on the market price of our Class A Common Stock. Sales of substantial amounts of our Class A Common Stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A Common Stock. 
+The underwriters of the IPO may waive or release parties to the lock-up agreements entered into in connection with the IPO, which could adversely affect the price of our Class A Common Stock. 
+We, all of our directors that own equity in us, all of our executive officers, and other of our Legacy Owners have entered into lock-up agreements pursuant to which we and they are subject to certain restrictions with respect to the sale or other disposition of our Class A Common Stock for a period of 180 days following the date of the IPO. The underwriters, at any time and without notice, may release all or any portion of the Class A Common Stock subject to the foregoing lock-up agreements. If the restrictions under the lock-up agreements are waived, then the Class A Common Stock, subject to compliance with the Securities Act or exceptions therefrom, will be available for sale into the public markets, which could cause the market price of our Class A Common Stock to decline and impair our ability to raise capital. 
+Liberty Inc. will be required to make payments under the Tax Receivable Agreements for certain tax benefits that it may claim, and the amounts of such payments could be significant. 
+The Tax Receivable Agreements generally provide for the payment by Liberty Inc. to each TRA Holder of 85% of the net cash savings, if any, in U.S. federal, state and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that Liberty Inc. actually realizes (or is deemed to realize in certain circumstances) as a result of certain increases in tax basis, net operating losses available to Liberty Inc. as a result of the Corporate Reorganization, and certain benefits attributable to imputed interest. Liberty Inc. will retain the benefit of the remaining 15% of these cash savings. 
+The term of each Tax Receivable Agreement will continue until all tax benefits that are subject to such Tax Receivable Agreement have been utilized or expired, unless Liberty Inc. experiences a change of control (as defined in the Tax Receivable Agreements, which includes certain mergers, asset sales and other forms of business combinations) or the Tax Receivable Agreements are terminated early (at Liberty Inc’s election or as a result of its breach), and Liberty Inc. makes the termination payments specified in such Tax Receivable Agreement. In addition, payments Liberty Inc. makes under the Tax Receivable Agreements will be increased by any interest accrued from the due date (without extensions) of the corresponding tax return. In the event that the Tax Receivable Agreements are not terminated, the payments under the Tax Receivable Agreements are anticipated to commence in 2019 and to continue for 15 years after the date of the last redemption of the Liberty LLC Units. 
+The payment obligations under the Tax Receivable Agreements are Liberty Inc.’s obligations and not obligations of Liberty LLC, and Liberty Inc. expects that the payments Liberty Inc. will be required to make under the Tax Receivable Agreements will be substantial. Estimating the amount and timing of payments that may become due under the Tax Receivable Agreements is by its nature imprecise. For purposes of the Tax Receivable Agreements, cash savings in tax generally are calculated by comparing Liberty Inc.’s actual tax liability (determined by using the actual applicable U.S. federal income tax rate and an assumed combined state and local income tax rate) to the amount it would have been required to pay had it not been able to utilize any of the tax benefits subject to the Tax Receivable Agreements. The amounts payable, as well as the timing of any payments, under the Tax Receivable Agreements are dependent upon significant future events and assumptions, including the timing of the redemptions of Liberty LLC Units, the price of our Class A Common Stock at the time of each redemption, the extent to which such redemptions are taxable transactions, the amount of the redeeming unit holder’s tax basis in its Liberty LLC Units at the time of the relevant redemption, the depreciation and amortization periods that apply to the increase in tax basis, the amount of net operating losses available to Liberty Inc. as a result of the Corporate Reorganization, the amount and timing of taxable income Liberty Inc. generates in the future, the U.S. federal income tax rate then applicable, and the portion of Liberty Inc.’s payments under the Tax Receivable Agreements that constitute imputed interest or give rise to depreciable or amortizable tax basis. 
+35 
+Table of Contents 
+The payments under the Tax Receivable Agreements will not be conditioned upon a holder of rights under a Tax Receivable Agreement having a continued ownership interest in Liberty Inc. or Liberty LLC. For additional information regarding the Tax Receivable Agreements, see “Certain Relationships and Related Party Transactions—Tax Receivable Agreements.” 
+In certain cases, payments under the Tax Receivable Agreements may be accelerated and/or significantly exceed the actual benefits, if any, Liberty Inc. realizes in respect of the tax attributes subject to the Tax Receivable Agreements. 
+If Liberty Inc. experiences a change of control (as defined under the Tax Receivable Agreements, which includes certain mergers, asset sales and other forms of business combinations) or the Tax Receivable Agreements terminate early (at Liberty Inc.’s election or as a result of its breach), Liberty Inc. would be required to make a substantial, immediate lump-sum payment. This payment would equal the present value of hypothetical future payments that could be required to be paid under the Tax Receivable Agreements (determined by applying a discount rate equal to the long-term Treasury rate in effect on the applicable date plus 300 basis points). The calculation of hypothetical future payments will be based upon certain assumptions and deemed events set forth in the Tax Receivable Agreements, including (i) that Liberty Inc. has sufficient taxable income to fully utilize the tax benefits covered by the Tax Receivable Agreements, (ii) that any Liberty LLC Units (other than those held by Liberty Inc.) outstanding on the termination date are deemed to be redeemed on the termination date, and (iii) certain loss or credit carryovers will be utilized over five years beginning with the taxable year that includes the termination date. Any early termination payments may be made significantly in advance of, and may materially exceed, the actual realization, if any, of the future tax benefits to which the termination payments relate. 
+If Liberty Inc. experiences a change of control (as defined under the Tax Receivable Agreements) or the Tax Receivable Agreements otherwise terminate early, Liberty Inc.’s obligations under the Tax Receivable Agreements could have a substantial negative impact on its liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. For example, if the Tax Receivable Agreements were terminated immediately after the IPO, the estimated termination payments would, in the aggregate, be approximately $113.8 million (calculated using a discount rate equal to the long-term Treasury rate in effect on the applicable date plus 300 basis points, applied against an undiscounted liability of $173.5 million). The foregoing number is merely an estimate and the actual payment could differ materially. There can be no assurance that we will be able to finance our obligations under the Tax Receivable Agreements. 
+Please read ‘‘Item 13. Certain Relationships and Related Party Transactions—Tax Receivable Agreements.’’ 
+In the event that Liberty Inc. ’ s payment obligations under the Tax Receivable Agreements are accelerated upon certain mergers, other forms of business combinations or other changes of control, the consideration payable to holders of our Class A Common Stock could be substantially reduced. 
+If Liberty Inc. experiences a change of control (as defined under the Tax Receivable Agreements, which includes certain mergers, asset sales and other forms of business combinations), Liberty Inc. would be obligated to make a substantial, immediate lump-sum payment, and such payment may be significantly in advance of, and may materially exceed, the actual realization, if any, of the future tax benefits to which the payment relates. As a result of this payment obligation, holders of our Class A Common Stock could receive substantially less consideration in connection with a change of control transaction than they would receive in the absence of such obligation. Further, our payment obligations under the Tax Receivable Agreements will not be conditioned upon the TRA Holders’ having a continued interest in Liberty Inc. or Liberty LLC. Accordingly, the TRA Holders’ interests may conflict with those of the holders of our Class A Common Stock. Please read “Risk Factors—Risks Related to our Class A Common Stock—In certain cases, payments under the Tax Receivable Agreements may be accelerated and/or significantly exceed the actual benefits Liberty Inc. realizes, if any, in respect of the tax attributes subject to the Tax Receivable Agreements” and ‘‘Certain Relationships and Related Party Transactions-Tax Receivable Agreements.” 
+We will not be reimbursed for any payments made under the Tax Receivable Agreements in the event that any tax benefits are subsequently disallowed. 
+Payments under the Tax Receivable Agreements are based on the tax reporting positions that we will determine. The TRA Holders will not reimburse us for any payments previously made under the Tax Receivable Agreements if any tax benefits that have given rise to payments under the Tax Receivable Agreements are subsequently disallowed, except that excess payments made to any TRA Holder will be netted against payments that would otherwise be made to such TRA Holder, if any, after our determination of such excess. As a result, in such circumstances, Liberty Inc. could make payments that are greater than its actual cash tax savings, if any, and may not be able to recoup those payments, which could adversely affect Liberty Inc.’s liquidity. 
+36 
+Table of Contents 
+If Liberty LLC were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, Liberty Inc. and Liberty LLC might be subject to potentially significant tax inefficiencies, and Liberty Inc. would not be able to recover payments previously made by it. under the Tax Receivable Agreements even if the corresponding tax benefits were subsequently determined to have been unavailable due to such status. 
+Liberty Inc. intends to operate such that Liberty LLC does not become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes. A “publicly traded partnership” is a partnership the interests of which are traded on an established securities market or are readily tradable on a secondary market or the substantial equivalent thereof. Under certain circumstances, redemptions of Liberty LLC Units pursuant to the Redemption Right, Liberty Inc.’s Call Right or other transfers of Liberty LLC Units could cause Liberty LLC to be treated as a publicly traded partnership. Applicable U.S. Treasury regulations provide for certain safe harbors from treatment as a publicly traded partnership, and Liberty Inc. intends to operate such that redemptions or other transfers of Liberty LLC Units qualify for one or more such safe harbors. For example, Liberty Inc. intends to limit the number of unit holders of Liberty LLC, and the Liberty LLC Agreement, which was entered into in connection with the closing of the IPO, provides for limitations on the ability of holders of Liberty LLC Units to transfer their Liberty LLC Units and provides Liberty Inc., as managing member of Liberty LLC, with the right to impose restrictions (in addition to those already in place) on the ability of holders of Liberty LLC Units to redeem their Liberty LLC Units pursuant to the Redemption Right to the extent Liberty Inc. believes it is necessary to ensure that Liberty LLC will continue to be treated as a partnership for U.S. federal income tax purposes. 
+If Liberty LLC were to become a publicly traded partnership, significant tax inefficiencies might result for Liberty Inc. and for Liberty LLC, including as a result of Liberty Inc.’s inability to file a consolidated U.S. federal income tax return with Liberty LLC. In addition, Liberty Inc. would no longer have the benefit of certain increases in tax basis covered under the Tax Receivable Agreements, and Liberty Inc. would not be able to recover any payments previously made by it under the Tax Receivable Agreements, even if the corresponding tax benefits (including any claimed increase in the tax basis of Liberty LLC’s assets) were subsequently determined to have been unavailable. 
+In certain circumstances, Liberty LLC will be required to make tax distributions and tax advances to the Liberty Unit Holders, including us, and the tax distributions and tax advances that Liberty LLC will be required to make may be substantial. 
+Pursuant to the Liberty LLC Agreement, Liberty LLC will make generally pro rata cash distributions, or tax distributions, to the holders of Liberty LLC Units, including Liberty Inc., in an amount sufficient to allow Liberty Inc. to pay its taxes and to allow it to make payments under the Tax Receivable Agreements. In addition to these pro rata distributions, the Liberty Unit Holders will be entitled to receive tax advances in an amount sufficient to allow each of the Liberty Unit Holders to pay its respective taxes on such holder’s allocable share of Liberty LLC’s taxable income. Any such tax advance will be calculated after taking into account certain other distributions or payments received by the Liberty Unit Holders from Liberty LLC or Liberty Inc. Under the applicable tax rules, Liberty LLC is required to allocate net taxable income disproportionately to its members in certain circumstances. Tax advances will be determined based on an assumed individual tax rate and will be repaid upon exercise of the Redemption Right or the Call Right, as applicable. 
+Funds used by Liberty LLC to satisfy its tax distribution and tax advance obligations will not be available for reinvestment in our business. Moreover, the tax distributions and tax advances Liberty LLC will be required to make may be substantial, and is likely to exceed (as a percentage of Liberty LLC’s income) the overall effective tax rate applicable to a similarly situated corporate taxpayer. In addition, because these payments will be calculated with reference to an assumed tax rate, and because of the disproportionate allocation of net taxable income, these payments may exceed the actual tax liability for some of the holders of Liberty LLC Units. 
+We may issue preferred stock whose terms could adversely affect the voting power or value of our Class A Common Stock. 
+Our amended and restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A Common Stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our Class A Common Stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the Class A Common Stock. 
+37 
+Table of Contents 
+If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our Class A Common Stock or if our operating results do not meet their expectations, our stock price could decline. 
+The trading market for our Class A Common Stock may be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of the Company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover the Company downgrades our Class A Common Stock or if our operating results do not meet their expectations, our stock price could decline. 
+38 
+Table of Contents 
+Item 1B. Unresolved Staff Comments 
+None. 
+Item 2. Properties 
+Information regarding our properties is contained in “Item 1. Business” and is incorporated by reference herein. 
+Item 3. Legal Proceeding 
+On February 23, 2017, SandBox filed suit in the Houston Division of the U.S. District Court for the Southern District of Texas against Proppant Express Investments, LLC, Proppant Express Solutions, LLC (“PropX”), and Liberty Oilfield Services LLC (“LOS”). As described in “Related Party Transactions—Historical Transactions with Affiliates—PropX,” LOS is party to a services agreement with PropX. SandBox alleges that LOS willfully infringes multiple U.S. patents and has breached an agreement between SandBox and LOS by “directing, controlling, and funding” inter partes review (“IPR”) requests before the U.S. Patent and Trademark Office (“USPTO”). SandBox seeks both monetary and injunctive relief from the court, as well as attorney’s fees and costs. On August 14, 2017, the court denied SandBox’s request for a preliminary injunction to prevent LOS from filing a request for an IPR with the USPTO, and the court denied SandBox’s request for reconsideration of such order on March 13, 2018. Pursuant to the parties’ stipulation, all claims and counterclaims related to one of the four patents asserted by SandBox were dismissed without prejudice on November 6, 2017. A hearing on the construction of claim terms in the remaining asserted patents occurred on March 1, 2018. We intend to vigorously defend ourselves against the claims brought by SandBox. 
+We are named defendants in certain lawsuits, investigations and claims arising in the ordinary course of conducting our business, including certain environmental claims and employee-related matters, and we expect that we will be named defendants in similar lawsuits, investigations and claims in the future. While the outcome of these lawsuits, investigations and claims cannot be predicted with certainty, we do not expect these matters to have a material adverse impact on our business, results of operations, cash flows or financial condition. We have not assumed any liabilities arising out of these existing lawsuits, investigations and claims. 
+Item 4. Mine Safety Disclosures 
+Not applicable. 
+PART II 
+Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+Market Information 
+On January 17, 2018, we consummated an initial public offering of our Class A Common Stock at a price of $17.00 per share. Our Class A Common Stock is traded on the NYSE under the symbol “LBRT.” As of December 31, 2017, our Class A Common Stock was not listed on a domestic exchange or over-the-counter market. As a result we have not set forth quarterly information with respect to the high and low prices for our Class A Common Stock for the two most recent fiscal years. The price at the end of the trading day on the NYSE on March 16, 2018 was $17.73. There is no public market for our Class B Common Stock. 
+Holders of our Common Stock 
+As of March 16, 2018, there were 120 stockholders of record of our Class A Common Stock and five stockholders of record of our Class B Common Stock. The number of record holders is based upon the actual number of holders registered on the books of the Company at such date and does not include holders of shares in “street names” or persons, partnerships, associations, corporations or other entities identified in security position listings maintained by depositories. 
+39 
+Table of Contents 
+Dividend Policy 
+We have not paid any dividends since our inception and we do not intend to pay regular cash dividends in the foreseeable future. We are not required to pay dividends, and our stockholders will not be guaranteed, or have contractual or other rights to receive, dividends. The declaration and payment of any future dividends will be at the sole discretion of our board of directors and will depend upon, among other things, our earnings, financial condition, capital requirements, level of indebtedness, contractual restrictions to the extent there are any with respect to the payment of dividends, and other considerations that our board of directors deems relevant. 
+Use of Proceeds From Registered Securities 
+We had no sales of registered equity securities during the period covered by this Annual Report on Form 10-K that were not previously reported in a Current Report on Form 8-K. 
+Recent Sales of Unregistered Equity Securities 
+We had no sales of unregistered equity securities during the period covered by this Annual Report on Form 10-K that were not previously reported in a Current Report on Form 8-K. 
+Equity Compensation Plan Information 
+We did not maintain an equity compensation plan, and no securities were available for issuance under an equity compensation plan as of December 31, 2017. As previously discussed, we adopted the Liberty Oilfield Services Inc. Legacy Restricted Stock Plan (the “Legacy Plan”) and the Liberty Oilfield Services Inc. Long Term Incentive Plan (the “LTIP”) in connection with out IPO; however, these were not outstanding as of December 31, 2017. As such, no equity compensation plan table is provided. 
+Item 6. Selected Financial Data 
+The selected financial data set forth below was derived from the audited combined financial statements of our Predecessor, Liberty Oilfield Services LLC (“LOS”) and LOS Acquisition Co I LLC (“ACQI”), and should be read in conjunction with “Item 1A. Risk Factors,” “Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations” and our audited combined financial statements included in “Item 8. Financial Statements and Supplementary Data.” 
+40 
+Table of Contents 
+Years Ended 
+December 31, 
+2017 
+2016 
+2015 
+(in thousands, except share, per share, fleet and per fleet data) 
+Statement of Operations Data: 
+Revenue 
+$ 
+1,489,855 
+$ 
+374,773 
+$ 
+455,404 
+Costs of services, excluding depreciation and amortization shown separately 
+1,147,008 
+354,729 
+393,340 
+General and administrative 
+80,089 
+35,789 
+28,765 
+Depreciation and amortization 
+81,473 
+41,362 
+36,436 
+Loss (gain) on disposal of assets 
+148 
+(2,673 
+) 
+423 
+Operating income (loss) 
+181,137 
+(54,434 
+) 
+(3,560 
+) 
+Other expense 
+Interest expense 
+(12,636 
+) 
+(6,126 
+) 
+(5,501 
+) 
+Net income (loss) 
+$ 
+168,501 
+$ 
+(60,560 
+) 
+$ 
+(9,061 
+) 
+Pro Forma Income Tax and Net Income(1) 
+Pro forma tax expense (benefit) 
+$ 
+38,149 
+Pro forma net income (loss) 
+$ 
+130,352 
+Pre tax income (loss) attributable to noncontrolling interests 
+$ 
+68,782 
+Pro forma tax expense attributable to noncontrolling interests 
+— 
+Pro forma net income (loss) attributable to noncontrolling interests 
+$ 
+68,782 
+Pre tax income (loss) attributable to Liberty Inc. 
+$ 
+99,719 
+Pro forma tax expense (benefit) attributable to Liberty Inc. 
+38,149 
+Pro forma net income (loss) attributable to Liberty Inc. 
+$ 
+61,570 
+Pro Forma per Share Data (2) 
+Pro forma net income (loss) per share 
+Basic 
+$ 
+0.90 
+Diluted 
+$ 
+0.88 
+Pro forma weighted average shares outstanding 
+Basic 
+68,729,523 
+Diluted 
+117,713,945 
+Statement of Cash Flows Data: 
+Cash flows provided by (used in) operating activities 
+$ 
+195,109 
+$ 
+(40,708 
+) 
+$ 
+6,119 
+Cash flows used in investing activities 
+(310,043 
+) 
+(96,351 
+) 
+(38,492 
+) 
+Cash flows provided by financing activities 
+119,771 
+148,543 
+21,485 
+Other Financial Data: 
+Capital expenditures 
+$ 
+300,793 
+$ 
+102,428 
+$ 
+38,492 
+EBITDA(3) 
+$ 
+262,610 
+$ 
+(13,072 
+) 
+$ 
+32,876 
+Adjusted EBITDA(3) 
+$ 
+280,728 
+$ 
+(5,588 
+) 
+$ 
+41,213 
+Total Fleets at beginning of period (4) 
+10 
+6 
+5 
+Total Fleets at end of period (4) 
+19 
+10 
+6 
+Average Active Fleets (5) 
+15.1 
+7.4 
+5.9 
+Adjusted EBITDA per Average Active Fleet (6) 
+$ 
+18,591 
+$ 
+(755 
+) 
+$ 
+6,985 
+Balance Sheet Data (at end of period): 
+Total assets 
+$ 
+852,103 
+$ 
+451,845 
+$ 
+296,971 
+Long-term debt (including current portion) 
+196,357 
+103,805 
+110,232 
+Total liabilities 
+416,851 
+222,873 
+162,920 
+Redeemable common units (7) 
+42,486 
+— 
+— 
+Total member equity 
+392,766 
+228,972 
+134,051 
+41 
+Table of Contents 
+(1) 
+Pro forma net income attributable to Liberty Inc. reflects the income tax effects of the corporate reorganization described under “Item 1. Business—Initial Public Offering and Reorganization Transaction” and the IPO. The Predecessor is not subject to U.S. federal income tax. As a result, the combined net income in the historical financial statements do not reflect the tax expense we would have incurred if we were subject to U.S. federal income tax during such period. While Liberty Inc. a corporation and is subject to U.S. federal income tax, such pro forma tax expense is only reflected on the portion of pre tax income attributable to stockholders of Liberty Inc. and is estimated at $38.1 million for the year ended December 31, 2017 . Accordingly, no pro forma tax expense is reflected for noncontrolling interests which are not consolidated into Liberty's tax return until and unless such noncontrolling interests are redeemed and exchanged for Class A Common Stock. 
+(2) 
+Pro forma net income (loss) per share, basic, and weighted average shares outstanding, basic, reflect the number of shares of common stock outstanding upon the completion of our corporate reorganization described under “Item 1. Business—Initial Public Offering and Reorganization Transaction” associated with our IPO as if such reorganization had occurred at the beginning of the period presented. For the year ended December 31, 2017 pro forma net income per share, diluted, and weighted average shares outstanding, diluted, reflects the potential redemption of all Liberty LLC Units outstanding and cancellation of the corresponding shares of Class B Common Stock in exchange for Liberty Inc.'s issuance of additional Class A Common Stock under the if-converted method, and vesting of restricted stock issued in connection with the IPO under the treasury stock method. The table below shows the calculation of diluted pro forma net income for purposes of such diluted pro forma net income per share calculation. 
+For the year ended December 31, 2017 
+(in thousands) 
+Attributable to Liberty Inc. (Basic) 
+Pro forma effect of Conversion of Class B to Class A 
+Attributable to Liberty Inc. (Diluted) 
+Net income 
+$ 
+99,719 
+$ 
+68,782 
+$ 
+168,501 
+Pro forma tax expense 
+38,149 
+26,314 
+64,463 
+Pro forma net income 
+$ 
+61,570 
+$ 
+42,468 
+$ 
+104,038 
+(3) 
+EBITDA and Adjusted EBITDA are non-GAAP financial measures. For definitions of EBITDA and Adjusted EBITDA and a reconciliation of each to our most directly comparable financial measure calculated and presented in accordance with accounting principal generally accepted in the United States of America ("GAAP"), please read “Item 7. Management's Discussion and Analysis of Financial Conditions and Results of Operations—Non-GAAP Financial Measures.” 
+(4) 
+Total Fleets represents the number of deployed and active fleets as of the designated date. 
+(5) 
+Average Active Fleets is calculated as the daily average of the active fleets for the period presented. 
+(6) 
+Adjusted EBITDA per Average Active Fleet is calculated as Adjusted EBITDA for the period divided by the Average Active Fleets, as defined above. 
+(7) 
+Effective March 22, 2018, ACQI and LOS merged into the surviving entity, LOS, and ACQI ceased to exist. In connection with the merger and dissolution, the Redeemable Common Units were deemed extinguished and satisfied in full. 
+42 
+Table of Contents 
+Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 
+The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Item 6. Selected Financial Data” and our audited combined financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a variety of risks and uncertainties, including those described in this Annual Reporting on Form 10-K under “Cautionary Note Regarding Forward-Looking Statements” and “Item 1A. Risk Factors.” We assume no obligation to update any of these forward-looking statements. 
+Overview 
+We are a growing independent provider of hydraulic fracturing services to onshore oil and natural gas E&P companies in North America. We have grown from one active hydraulic fracturing fleet in December 2011 to 21 active fleets in March 2018. The demand for our hydraulic fracturing services exceeds our current capacity, and we expect, based on discussions with customers, to deploy one additional fleet, as well as add additional horsepower to existing fleets, by the end of the second quarter of 2018, and two additional fleets by the end of the year, for a total of 24 active fleets, representing approximately 1,170,000 HHP. Our additional fleets are currently being built to our specifications. We provide our services primarily in the Permian Basin, the Eagle Ford Shale, the DJ Basin, the Williston Basin and the Powder River Basin. 
+We believe the following characteristics both distinguish us from our competitors and are the foundations of our business: forming ongoing partnerships of trust and innovation with our customers; developing and utilizing technology to maximize well performance; and promoting a people-centered culture focused on our employees, customers and suppliers. We have developed strong relationships with our customers by investing significant time in fracture design collaboration, which substantially enhances their production economics. Our technological innovations have become even more critical as E&P companies have increased the completion complexity and fracture intensity of horizontal wells. We are proactive in developing innovative solutions to industry challenges, including developing: (i) our proprietary databases of U.S. unconventional wells to which we apply our proprietary multi-variable statistical analysis technologies to provide differential insight into fracture design optimization; (ii) our Liberty Quiet Fleet ™ design which significantly reduces noise levels compared to conventional hydraulic fracturing fleets; and (iii) our hydraulic fracturing fluid system tailored to the reservoir properties in the DJ Basin which materially reduces completion costs without compromising production. We foster a people-centered culture built around honoring our commitments to customers, partnering with our suppliers and hiring, training and retaining people that we believe to be the best talent in our field, enabling us to be one of the safest and most efficient hydraulic fracturing companies in the United States. 
+Recent Trends and Outlook 
+Demand for our hydraulic fracturing services is predominantly influenced by the level of drilling and completion by E&P companies, which, in turn, depends largely on the current and anticipated profitability of developing oil and natural gas reserves. More specifically, demand for our hydraulic fracturing services is driven by the completion of hydraulic fracturing stages in unconventional wells, which, in turn, is driven by several factors including rig count, well count, service intensity and the timing and style of well completions. 
+Recently Improving Macro Conditions 
+Hydrocarbon prices began a precipitous decline in the second half of 2014 after the posted West Texas Intermediate (“WTI”) price of oil reached a peak of $107.26 per barrel (“Bbl”) in June 2014 and the posted Henry Hub price of natural gas reached a peak of $6.15 per million British Thermal Units (“MMBtu”) in February 2014. This decline, sustained by a perceived glut of oil and natural gas, drove WTI prices to a low of $26.21 per Bbl in February 2016 and Henry Hub natural gas prices to a low of $1.64 per MMBtu in March 2016. 
+Lower hydrocarbon prices in 2015 and early 2016 influenced many E&P companies to reduce drilling and completion activity and capital spending in all basins across North America. As drilling and completion activity decline, demand for hydraulic fracturing services also decline, leading to an oversupply of fracturing capacity and a decline in fleet utilization. 
+Reduced capital spending on drilling and completion activity in 2015 and 2016 ultimately led to flattening of crude oil supply while global demand continued to rise. In the United States crude production fell as much as 13% from its peak in March 2015. Further, recent agreements by members of the Organization of Petroleum Exporting Countries (“OPEC”) and non-OPEC members to reduce their oil production quotas have also provided upward momentum for WTI prices, which has more than doubled to $62.12 per Bbl as of March 9, 2018. 
+43 
+Table of Contents 
+We expect this demand to continue to increase as E&P companies increase drilling and completion activities. According to Baker Hughes’ North American Rig Count, the number of active total rigs in the United States reached a low of 404, as reported on May 27, 2016, but has since increased by more than 144% to 984 active rigs as reported on March 9, 2018. If hydrocarbon prices stabilize at current levels or rise further, we expect to see further increased drilling and completion activity in the basins in which we operate. While the pricing for our hydraulic fracturing services declined substantially, negatively affecting our revenue per average active fleet, and has not returned to its 2014 highs, the industry witnessed an increase in demand for these services beginning in the third quarter of 2016 and continuing through 2017 as hydrocarbon prices have recovered somewhat, and we are currently experiencing price increases and increases in our revenue per average active fleet. Should hydrocarbon prices decrease, our pricing and revenue per average active fleet may decrease due to lower demand for our services, negatively affecting our liquidity and financial condition. Please see “Item 1A. Risk Factors—Risks Related to Our Business—Our business depends on domestic capital spending by the oil and natural gas industry, and reductions in capital spending could have a material adverse effect on our liquidity, results of operations and financial condition” and “Item 7. Management's Discussion and Analysis—How We Evaluate Our Operations.” 
+In addition to increased industry activity levels, we expect to benefit from increased horizontal drilling as well as other long-term macro industry trends that improve drilling economics such as (i) greater rig efficiencies that result in more wells drilled per rig in a given period and (ii) increased complexity and service intensity of well completions, including longer wellbore laterals, more and larger fracturing stages and higher proppant usage per well. 
+These industry trends will directly benefit hydraulic fracturing companies like us that have the expertise and technological ability to execute increasingly complex and intense well completions. Given the improved returns that E&P companies have reported for new well completions, we expect these industry trends to continue. 
+Increase in Drilling Efficiency and Service Intensity of Completions 
+Over the past decade, E&P companies have focused on exploiting the vast resource potential available across many of North America’s unconventional resource plays through the application of horizontal drilling and completion technologies, including the use of multi-stage hydraulic fracturing, in order to increase recovery of oil and natural gas. As E&P companies have improved drilling and completion techniques to maximize return and efficiency, we believe several long term trends have emerged which have materially increased the service intensity of current completions. 
+Improved drilling economics from horizontal drilling and greater rig efficiencies . Unconventional resources are increasingly being targeted through the use of horizontal drilling. According to Baker Hughes, as reported on March 9, 2018, horizontal rigs accounted for approximately 86% of all rigs drilling in the United States, up from 74% as of December 31, 2014. Over the past several years, North American E&P companies have benefited from improved drilling economics driven by technologies that reduce the number of days, and the cost, of drilling wells. North American drilling rigs have incorporated newer technologies, which allow them to drill rock more effectively and quickly, meaning each rig can drill more wells in a given period. These include improved drilling technologies and the incorporation of geosteering techniques which allow better placement of the wellbore. Drilling rigs have also incorporated new technology which allows fully-assembled rigs to automatically “walk” from one location to the next without disassembling and reassembling the rig, greatly reducing the time it takes to move from one drilling location to the next. At the same time, E&P companies are shifting their development plans to incorporate multi-well pad development, which allows them to drill multiple horizontal wellbores from the same pad or location. The aggregate effect of these improved techniques and technologies have reduced the average days required to drill a well, which according to Coras, has dropped from 28 days in 2014 to 22 days in 2017. 
+Increased complexity and service intensity of horizontal well completions . In addition to improved rig efficiencies discussed above, E&P companies are also improving the subsurface techniques and technologies used to exploit unconventional resources. These improvements have targeted increasing the exposure of each wellbore to the reservoir by drilling longer horizontal lateral sections of the wellbore. To complete the well, hydraulic fracturing is applied in stages along the wellbore to break-up the resource so that oil and gas can be produced. As wellbores have increased in length, the number of stages has also increased. From 2014 to 2017, the average stages per horizontal well have increased from 21 stages per well to 35 stages per well. Further, E&P companies have improved production from each stage by applying increasing amounts of proppant in each stage, which better connects the well to the resource. The aggregate effect of increased number of stages and the increasing amount of proppant in each stage has greatly increased the total amount of proppant used in each well, from six million pounds per well in 2014 to over 12 million pounds per well in 2017. 
+These industry trends will directly benefit hydraulic fracturing companies like us that have the expertise and technological innovations to effectively service today’s more efficient oilfield drilling activity and the increasing complexity and intensity of well completions. Given the expected returns that E&P companies have reported for new well development 
+44 
+Table of Contents 
+activities due to improved rig efficiencies and increasing well completion complexity and intensity, we expect these industry trends to continue. 
+How We Generate Revenue 
+We currently generate revenue through the provision of hydraulic fracturing services. These services are performed under a variety of contract structures, primarily master service agreements as supplemented by statements of work, pricing agreements and specific quotes. A portion of our statements of work, under master service agreements, include provisions that establish pricing arrangements for a period of up to one year in length. However, the majority of those agreements provide for pricing adjustments based on market conditions. The majority of our services are priced based on prevailing market conditions and changing input costs at the time the services are provided, giving consideration to the specific requirements of the customer. 
+Our hydraulic fracturing services are performed in sections, which we refer to as fracturing stages. The estimated number of fracturing stages to be completed for a particular horizontal well is determined by the customer’s well completion design. We recognize revenue for each fracturing stage completed, although our revenue per completed fracturing stage varies depending on the actual volumes and types of proppants, chemicals and fluid utilized for each fracturing stage. The number of fracturing stages that we are able to complete in a period is directly related to the number and utilization of our deployed fleets and size of stages. 
+Costs of Conducting Our Business 
+The principal expenses involved in conducting our business are direct cost of personnel, services and materials used in the provision of services, general and administrative expenses, and depreciation and amortization. A large portion of the costs we incur in our business are variable based on the number of hydraulic fracturing jobs and the requirements of services provided to our customers. We manage the level of our fixed costs, except depreciation and amortization, based on several factors, including industry conditions and expected demand for our services. 
+How We Evaluate Our Operations 
+We use a variety of qualitative, operational and financial metrics to assess our performance. First and foremost of these is a qualitative assessment of customer satisfaction because ensuring we are a valuable partner to our customers is the key to achieving our quantitative business metrics. Among other measures, management considers each of the following: 
+Revenue; 
+Operating Income (Loss); 
+EBITDA; 
+Adjusted EBITDA; 
+Adjusted EBITDA per Average Active Fleet; 
+Net Income; and 
+Earnings per Share. 
+Revenue 
+We analyze our revenue by comparing actual monthly revenue to our internal projections for a given period and to prior periods to assess our performance. We also assess our revenue in relation to the number of fleets we have deployed (revenue per average active fleet) from period to period. 
+Operating Income (Loss) 
+We analyze our operating income (loss), which we define as revenues less direct operating expenses, depreciation and amortization and general and administrative expenses, to measure our financial performance. We believe operating income is a meaningful metric because it provides insight on profitability and true operating performance based on the historical cost basis of our assets. We also compare operating income to our internal projections for a given period and to prior periods. 
+EBITDA and Adjusted EBITDA 
+We view EBITDA and Adjusted EBITDA as important indicators of performance. We define EBITDA as net income (loss) before interest, income taxes, depreciation and amortization. We define Adjusted EBITDA as EBITDA adjusted to eliminate the effects of items such as new fleet or new basin start-up costs, costs of asset acquisition, gain or loss on the 
+45 
+Table of Contents 
+disposal of assets, asset impairment charges, bad debt reserves, and non-recurring expenses that management does not consider in assessing ongoing operating performance. See “—Comparison of Non-GAAP Financial Measures” for more information and a reconciliation of EBITDA and Adjusted EBITDA to net income (loss), the most directly comparable financial measure calculated and presented in accordance with GAAP. 
+Results of Operations 
+Year Ended December 31, 2017 , Compared to Year Ended December 31, 2016 
+Years Ended December 31, 
+Description 
+2017 
+2016 
+Change 
+(in thousands) 
+Revenue 
+$ 
+1,489,855 
+$ 
+374,773 
+$ 
+1,115,082 
+Cost of services, excluding depreciation and amortization shown separately 
+1,147,008 
+354,729 
+792,279 
+General and administrative 
+80,089 
+35,789 
+44,300 
+Depreciation and amortization 
+81,473 
+41,362 
+40,111 
+Loss (gain) on disposal of assets 
+148 
+(2,673 
+) 
+2,821 
+Operating income (loss) 
+181,137 
+(54,434 
+) 
+235,571 
+Interest expense 
+(12,636 
+) 
+(6,126 
+) 
+(6,510 
+) 
+Net income (loss) 
+$ 
+168,501 
+$ 
+(60,560 
+) 
+$ 
+229,061 
+Revenue 
+Our revenue increased $1,115.1 million , or 297.5% , to $1,489.9 million for the year ended December 31, 2017 compared to $374.8 million for year ended December 31, 2016 . The increase was due to the combined effect of a 104.0% increase in average active fleets deployed and a 94.8% increase in revenue per average active fleet. Our revenue per average active fleet increased to approximately $97.8 million for the year ended December 31, 2017 as compared to approximately $50.6 million for the year ended December 31, 2016 , based on 15.1 and 7.4 average active fleets deployed during those respective periods. The increase in revenue per active fleet was due to improved pricing and throughput in conjunction with increased demand for our services. 
+Cost of Services 
+Cost of services (excluding depreciation and amortization) increased $792.3 million , or 223.3% , to $1,147.0 million for the year ended December 31, 2017 compared to $354.7 million for the year ended December 31, 2016 . The higher expense is due to an increase in services provided and reflects a $488.4 million increase attributable to materials, which was driven by a 235.7% increase in material volumes in the year ended December 31, 2017 compared to the same period in 2016 . Additionally, the cost of components used in our repairs and maintenance operations increased by $96.6 million and fuel costs increased by $52.0 million. Personnel costs increased by 163.7% to support the increased activity, including a 104.0% increase in average active fleets deployed, for the year ended December 31, 2017 as compared to the year ended December 31, 2016 . 
+General and Administrative Expenses 
+General and administrative expenses increased by $44.3 million , or 123.8% , to $80.1 million for the year ended December 31, 2017 compared to $35.8 million for the year ended December 31, 2016 . Payroll and benefits, related office expenses and fleet start-up expenses increased approximately $26.2 million, $5.4 million and $9.7 million, respectively, in connection with the increase in head count to support our expanded scope of operations and the nine fleets deployed during the year ended December 31, 2017 . Additionally, other general and administrative expenses increased $3.1 million, primarily driven by a $1.1 million increase in management fees owed to Riverstone. 
+As a result of becoming a public company, we expect to incur additional accounting, legal and non-cash stock compensation related expenses. Additionally, following the IPO, in connection with a one time issuance of 1,258,514 unvested shares of restricted stock under the Liberty Oilfield Services Inc. Legacy Restricted Stock Plan (the “Legacy Plan”) in connection with the IPO and Corporate Reorganization, we have $21.4 million of unrecognized compensation expense. In connection with this Legacy Plan issuance, we expect to recognize $6.6 million of non-cash stock compensation expense during the three months ending March 31, 2018. 
+46 
+Table of Contents 
+Depreciation and Amortization 
+Depreciation and amortization expense increased $40.1 million , or 97.0% , to $81.5 million for the year ended December 31, 2017 compared to $41.4 million for the year ended December 31, 2016 , due to additional hydraulic fracturing fleets deployed during the year ended December 31, 2017 . 
+Operating Income (Loss) 
+We realized operating income of $181.1 million for the year ended December 31, 2017 compared to an operating loss of $54.4 million for the year ended December 31, 2016 , primarily due to the increased number of hydraulic fracturing fleets deployed and the higher revenue per average active fleet in response to increased demand for our services described above. Generally, our financial results have improved significantly due to the increased drilling and completion activity by E&P companies during the recent recovery of the oil and gas industry beginning in the third quarter of 2016. 
+Interest Expense 
+The increase in interest expense of $6.5 million , or 106.3% , during the year ended December 31, 2017 compared to the year ended December 31, 2016 was primarily due to $1.2 million of deferred financing costs written off in connection with the termination of previously outstanding debt agreement and a $4.2 million increase in interest expense due to the increased average borrowings outstanding during the year ended December 31, 2017 compared to the same period in 2016 . Additionally, we incurred $0.8 million of interest on the $60.0 million of the Bridge Loan (as defined below) outstanding during a portion of the three months ended June 30, 2017. 
+Net Income (Loss) 
+We realized net income of $168.5 million for the year ended December 31, 2017 compared to a net loss of $60.6 million for the year ended December 31, 2016 . Our net loss for the year ended December 31, 2016 resulted from the significant decrease in pricing for our hydraulic fracturing services following the dramatic decrease in drilling activity by E&P companies during the industry downturn from late 2014 through the first half of 2016. Our net income for the year ended December 31, 2017 was driven by recovery of the oil and gas industry beginning in the third quarter of 2016, as well as our expanded scope of operations following deployment of nine additional hydraulic fracturing fleets during the year ended December 31, 2017 . 
+Year Ended December 31, 2016 , Compared to Year Ended December 31, 2015 
+Years Ended December 31, 
+Description 
+2016 
+2015 
+Change 
+(in thousands) 
+Revenue 
+$ 
+374,773 
+$ 
+455,404 
+$ 
+(80,631 
+) 
+Cost of services, excluding depreciation and amortization shown separately 
+354,729 
+393,340 
+(38,611 
+) 
+General and administrative 
+35,789 
+28,765 
+7,024 
+Depreciation and amortization 
+41,362 
+36,436 
+4,926 
+(Gain) loss on disposal of assets 
+(2,673 
+) 
+423 
+(3,096 
+) 
+Operating loss 
+(54,434 
+) 
+(3,560 
+) 
+(50,874 
+) 
+Interest expense 
+(6,126 
+) 
+(5,501 
+) 
+(625 
+) 
+Net loss 
+$ 
+(60,560 
+) 
+$ 
+(9,061 
+) 
+$ 
+(51,499 
+) 
+Revenue 
+Our revenue decreased $80.6 million , or 17.7% , to $374.8 million for the year ended December 31, 2016 compared to $455.4 million for the year ended December 31, 2015 . A $65.4 million increase in revenue attributable to an increase in average active fleets was offset by a $146.0 million decrease due to a reduction in revenue per average active fleet, including the impact of a material decrease in service pricing during the industry downturn. Service pricing trended downward throughout 2015 and through June 2016. Our revenue per average active fleet decreased 34.4% to approximately $50.6 million for the year ended December 31, 2016 as compared to approximately $77.2 million for the year ended December 31, 2015 , based on 7.4 and 5.9 average active fleets deployed during those respective periods. However, our revenue per average active fleet increased by approximately 14.3%, 14.7% and 31.1% in the second, third and fourth quarters of 2016 as compared to the respective prior year. 
+47 
+Table of Contents 
+Cost of Services 
+Cost of services (excluding depreciation and amortization) decreased $38.6 million , or 9.8% , to $354.7 million for the year ended December 31, 2016 compared to $393.3 million for the year ended December 31, 2015 . The lower expense in 2016 reflects a $44.4 million decrease attributable to materials and fuel, primarily due to the benefit of lower pricing which was partially offset by a 40% increase in material volumes. Additionally, the cost of components used in our repairs and maintenance operations decreased by $7.5 million. Those decreases were partially offset by higher personnel costs, which increased by 16.4% to support a 25.4% increase in average active fleets deployed during the year ended December 31, 2016 as compared to the year ended December 31, 2015 . 
+General and Administrative Expenses 
+General and administrative expenses increased by $7.0 million , or 24.4% , to $35.8 million for the year ended December 31, 2016 compared to $28.8 million for the year ended December 31, 2015 . Legal and other professional services fees and other transaction costs increased approximately $6.1 million and were primarily associated with the assets acquired in 2016 . Additionally, fleet start-up expenses increased by $3.2 million for the year ended December 31, 2016 compared to the year ended December 31, 2015 . These increases were partially offset by a $6.4 million decrease in bad debt expense. 
+Depreciation and Amortization 
+Depreciation and amortization expense increased $4.9 million , or 13.5% , to $41.4 million for the year ended December 31, 2016 compared to $36.4 million for the year ended December 31, 2015 , due to an increase in field services equipment in operation, primarily related to assets purchased in 2016 . 
+Operating Income (Loss) 
+We realized an operating loss of $54.4 million for the year ended December 31, 2016 compared to an operating loss of $3.6 million for the year ended December 31, 2015 , primarily due to the pricing driven reductions in revenues and expenses described above. Generally, our financial results were negatively impacted by the significant decrease in pricing for our hydraulic fracturing services following the dramatic decrease in drilling activity by E&P companies during the recent downturn. 
+Interest Expense 
+The increase in interest expense of $0.6 million , or 11.4% during the year ended December 31, 2016 compared to the year ended December 31, 2015 was primarily due to an increase in the average outstanding balance under our Prior Credit Facility, as well as a small increase in the weighted average interest rate. 
+Net Income (Loss) 
+We realized net losses of $60.6 million and $9.1 million for the years ended December 31, 2016 and 2015 , respectively. Our net losses resulted from the pricing driven reductions in revenues and expenses described above. Generally, our financial results were negatively impacted by the significant decrease in pricing for our hydraulic fracturing services following the dramatic decrease in drilling activity by E&P companies during the recent downturn. 
+Comparison of Non-GAAP Financial Measures 
+We view EBITDA and Adjusted EBITDA as important indicators of performance. We define EBITDA as net income (loss) before interest, income taxes, depreciation and amortization. We define Adjusted EBITDA as EBITDA adjusted to eliminate the effects of items such as new fleet or new basin start-up costs, costs of asset acquisitions, gain or loss on the disposal of assets, asset impairment charges, bad debt reserves, non-cash stock compensation expense incurred in connection with the IPO and Corporate Reorganization and non-recurring expenses that management does not consider in assessing ongoing performance. 
+Our board of directors, management, investors and lenders use EBITDA and Adjusted EBITDA to assess our financial performance because it allows them to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure (such as varying levels of interest expense), asset base (such as depreciation and amortization) and other items that impact the comparability of financial results from period to period. We present EBITDA and Adjusted EBITDA because we believe they provide useful information regarding the factors and trends affecting our business in addition to measures calculated under GAAP. Additionally, the calculation of Adjusted EBITDA complies with the definition of Consolidated EBITDA and other provisions of our Credit Facilities. See “—Liquidity and Capital Resources—Debt Agreements.” 
+Note Regarding Non-GAAP Financial Measures 
+EBITDA and Adjusted EBITDA are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures will provide useful information to investors in assessing our financial performance and results of operations. Net income (loss) is the GAAP measure most directly comparable to EBITDA and 
+48 
+Table of Contents 
+Adjusted EBITDA. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as an analytical tool due to exclusion of some but not all items that affect the most directly comparable GAAP financial measures. You should not consider EBITDA or Adjusted EBITDA in isolation or as substitutes for an analysis of our results as reported under GAAP. Because EBITDA and Adjusted EBITDA may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. For further discussion, please see “Summary—Summary Combined Financial Data.” 
+The following tables present a reconciliation of EBITDA and Adjusted EBITDA to our net income (loss), which is the most directly comparable GAAP measure for the periods presented: 
+Year Ended December 31, 2017 Compared to Year Ended December 31, 2016 : EBITDA and Adjusted EBITDA 
+Years Ended 
+December 31, 
+Description 
+2017 
+2016 
+Change 
+(in thousands) 
+Net income (loss) 
+$ 
+168,501 
+$ 
+(60,560 
+) 
+$ 
+229,061 
+Depreciation and amortization 
+81,473 
+41,362 
+40,111 
+Interest expense 
+12,636 
+6,126 
+6,510 
+EBITDA 
+$ 
+262,610 
+$ 
+(13,072 
+) 
+$ 
+275,682 
+Fleet start-up costs 
+13,955 
+4,280 
+9,675 
+Asset acquisition costs 
+2,470 
+5,420 
+(2,950 
+) 
+Loss (gain) on disposal of assets 
+148 
+(2,673 
+) 
+2,821 
+Advisory services fees 
+1,545 
+457 
+1,088 
+Adjusted EBITDA 
+$ 
+280,728 
+$ 
+(5,588 
+) 
+$ 
+286,316 
+EBITDA was $262.6 million for the year ended December 31, 2017 compared to $(13.1) million for the year ended December 31, 2016 . Adjusted EBITDA was $280.7 million for the year ended December 31, 2017 compared to $(5.6) million for the year ended December 31, 2016 . The increases in EBITDA and Adjusted EBITDA resulted from the increased revenue and other factors described above under the captions Revenue , Cost of Services and General and Administrative Expenses above. 
+Year Ended December 31, 2016 , Compared to Year Ended December 31, 2015 : EBITDA and Adjusted EBITDA 
+Years Ended December 31, 
+Description 
+2016 
+2015 
+Change 
+(in thousands) 
+Net loss 
+$ 
+(60,560 
+) 
+$ 
+(9,061 
+) 
+$ 
+(51,499 
+) 
+Depreciation and amortization 
+41,362 
+36,436 
+4,926 
+Interest expense 
+6,126 
+5,501 
+625 
+EBITDA 
+$ 
+(13,072 
+) 
+$ 
+32,876 
+$ 
+(45,948 
+) 
+Fleet start-up costs 
+4,280 
+1,044 
+3,236 
+Asset acquisition costs 
+5,420 
+— 
+5,420 
+(Gain) loss on disposal of assets 
+(2,673 
+) 
+423 
+(3,096 
+) 
+Bad debt reserve 
+— 
+6,424 
+(6,424 
+) 
+Advisory services fees 
+457 
+446 
+11 
+Adjusted EBITDA 
+$ 
+(5,588 
+) 
+$ 
+41,213 
+$ 
+(46,801 
+) 
+EBITDA was $(13.1) million for the year ended December 31, 2016 compared to $32.9 million for the year ended December 31, 2015 . Adjusted EBITDA was $(5.6) million for the year ended December 31, 2016 compared to $41.2 million for the year ended December 31, 2015 . The decreases in EBITDA and Adjusted EBITDA resulted from the declines in revenue and other items described above under the captions Revenue , Cost of Services and General and Administrative Expenses above. 
+49 
+Table of Contents 
+Liquidity and Capital Resources 
+Overview 
+Historically, our primary sources of liquidity to date have been cash flows from operations, capital contributions from our owners and borrowings under our Credit Facilities. We expect to fund operations and organic growth with the proceeds from our IPO and cash flows from operations. Our primary uses of capital have been capital expenditures to support organic growth and funding ongoing operations, including maintenance and fleet upgrades. 
+On January 17, 2018, we completed our IPO of 14,640,755 shares of our Class A Common Stock at a public offering price of $17.00 per share, of which 14,340,214 shares were offered by us and 300,541 shares were offered by the selling shareholder. We received approximately $220.4 million in net proceeds after deducting approximately $23.4 million of underwriting discounts and commissions and other offering costs. We did not receive any proceeds from the sale of the shares of Class A Common Stock by the selling shareholder. We used approximately $25.9 million of net proceeds from the IPO to redeem ownership in us from certain Legacy Owners (as defined below) and contributed the remaining proceeds to Liberty LLC in exchange for units in Liberty LLC (the “Liberty LLC Units”). Liberty LLC used a portion of the net proceeds (i) to fully repay our outstanding borrowings and accrued interest under our ABL Credit Facility (as defined herein), totaling approximately $30.1 million , (ii) to repay 35% of our outstanding borrowings, accrued interest and prepayment premium under our Term Loan Facility (as defined herein), totaling approximately $62.5 million and (iii) for general corporate purposes, including repayment of additional indebtedness and funding a portion of our 2018 and other future capital expenditures. Our cash on hand, expected cash flow from operations and availability under our Credit Facilities are expected to be sufficient to meet the Company ’ s liquidity requirements for the next twelve months. 
+As a result of our IPO, our cash on hand increased by approximately $101.9 million to $118.2 million, with $158.2 million available for borrowings under our ABL Credit Facility as of December 31, 2017 , on an adjusted basis. Going forward, we intend to finance the majority of our capital expenditures, contractual obligations and working capital needs with proceeds from the IPO and operating cash flows. We believe that our operating cash flow and available borrowings under our Credit Facilities will be sufficient to fund our operations for at least the next twelve months. 
+Cash Flows 
+The following table summarizes our cash flows for the periods indicated: 
+Years Ended December 31, 
+Description 
+2017 
+2016 
+Change 
+(in thousands) 
+Net cash provided by (used in) operating activities 
+$ 
+195,109 
+$ 
+(40,708 
+) 
+$ 
+235,817 
+Net cash used in investing activities 
+(310,043 
+) 
+(96,351 
+) 
+(213,692 
+) 
+Net cash provided by financing activities 
+119,771 
+148,543 
+(28,772 
+) 
+Net increase in cash and cash equivalents 
+$ 
+4,837 
+$ 
+11,484 
+$ 
+(6,647 
+) 
+Analysis of Cash Flow Changes Between the Years Ended December 31, 2017 and 2016 
+Operating Activities . Net cash provided by operating activities was $195.1 million for the year ended December 31, 2017 , compared to net cash used in operating activities of $(40.7) million for the year ended December 31, 2016 . The $235.8 million increase in cash from operating activities was attributable to the net impact of the increase in cash receipts for hydraulic fracturing services due to the combined effect of a 104.0% increase in average active fleets and 94.8% increase in revenue per active fleet, partially offset by the increased costs of those services and increased general and administrative expenses, and the changes in related working capital items. 
+Investing Activities . Net cash used in investing activities was $310.0 million for the year ended December 31, 2017 , compared to $96.4 million for the year ended December 31, 2016 . The $213.7 million increase in net cash used in investing activities was primarily due to the purchase of, and upgrades to, our hydraulic fracturing fleets, the acquisition of Titan Frac Services LLC, and real estate acquisitions in Texas. 
+Financing Activities . Net cash provided by financing activities was $119.8 million for the year ended December 31, 2017 , compared to $148.5 million for the year ended December 31, 2016 . The $28.8 million decrease in cash provided by financing activities was primarily due a $155.5 million decrease in member contributions, offset by a $97.1 million increase in net debt borrowings and repayments, $60.0 million in proceeds from related party bridge loans and $39.8 million in proceeds from 
+50 
+Table of Contents 
+issuance of redeemable common units. Additionally, during the year ended December 31, 2017, the Company redeemed $62.7 million of redeemable common units and paid $13.2 million in debt and equity issuance costs. 
+The following table summarizes our cash flows for the periods indicated: 
+Years Ended December 31, 
+Description 
+2016 
+2015 
+Change 
+(in thousands) 
+Net cash provided by (used in) operating activities 
+$ 
+(40,708 
+) 
+$ 
+6,119 
+$ 
+(46,827 
+) 
+Net cash used in investing activities 
+(96,351 
+) 
+(38,492 
+) 
+(57,859 
+) 
+Net cash provided by financing activities 
+148,543 
+21,485 
+127,058 
+Net change increase (decrease) in cash and cash equivalents 
+$ 
+11,484 
+$ 
+(10,888 
+) 
+$ 
+22,372 
+Analysis of Cash Flow Changes Between the Years Ended December 31, 2016 and 2015 
+Operating Activities . Net cash used in operating activities was $40.7 million for the year ended December 31, 2016 , compared to cash provided by operating activities of $6.1 million for the year ended December 31, 2015 . The $46.8 million decrease in cash from operating activities was attributable to the $15.1 million inventory purchase from Sanjel Corporation in 2016 , as well as the net impact of the decrease in cash receipts for hydraulic fracturing services and the increase in general and administrative expenses, which were partially offset by decreased costs of services during the year ended December 31, 2016 . 
+Investing Activities . Net cash used in investing activities was $96.4 million for the year ended December 31, 2016 , compared to $38.5 million for the year ended December 31, 2015 . The $57.9 million increase in net cash used in investing activities was primarily due to expenditures related to the acquisition of Sanjel Corporation in 2016 , the acquisition of two fleets from leasing companies, and increased payments for the assembly and upgrade of our hydraulic fracturing fleets. These expenditures were partially offset by $6.1 million of proceeds from the sale of assets. 
+Financing Activities . Net cash provided by financing activities was $148.5 million for the year ended December 31, 2016 , compared to $21.5 million for the year ended December 31, 2015 . The $127.1 million increase in cash provided by financing activities was primarily due to capital contributions from our owners totaling $155.5 million for the year ended December 31, 2016 , partially offset by a $29.0 million change in net cash activity under our prior credit facility ("the Prior Credit Facility"). For the year ended December 31, 2016 , we had a net repayment of $1.0 million under our Prior Credit Facility as compared to a net borrowing of $28.0 million for the year ended December 31, 2015 . 
+Debt Agreements 
+ABL Credit Facility 
+On September 19, 2017, we entered into the ABL Credit Facility. Under the terms of the ABL Credit Facility, up to $250.0 million may be borrowed, subject to certain borrowing base limitations based on a percentage of eligible accounts receivable and inventory. As of December 31, 2017 , the borrowing base was approximately $158.4 million, of which approximately $30.0 million was outstanding, excluding an outstanding letter of credit for $0.2 million, leaving $128.2 million of remaining availability. Following the completion of the IPO the Company had no borrowings outstanding. The ABL Credit Facility is collateralized by accounts receivable and inventory, and further secured by Liberty Holdings, as parent guarantor, and subsequent to the IPO by Liberty Inc., Liberty LLC and R/C IV Non-U.S. LOS Corp., a Delaware corporation and a subsidiary of Liberty Inc. The ABL Credit Facility matures on the earlier of September 19, 2022, or 90 days prior to the final maturity of the Term Loan Facility. 
+Borrowings under the ABL Credit Facility bear interest at LIBOR, plus an applicable LIBOR rate margin of 1.5% to 2.0% or base rate margin of 0.5% to 1.0%, as defined in the ABL Credit Facility credit agreement. Under the terms of the ABL Credit Facility, the weighted average interest rate on borrowings was 3.50% as of December 31, 2017 . The unused portion of the ABL Credit Facility is subject to an unused commitment fee of 0.375%-0.50%. Interest and fees (other than letter of credit fees) are payable in arrears on the first day of each month. All letter of credit fees are payable in arrears on the first business day of each month. 
+The ABL Credit Facility includes certain non-financial covenants, including but not limited to restrictions on incurring additional debt and certain distributions. The ABL Credit Facility is not subject to financial covenants unless excess availability (as defined in the credit agreement governing the ABL Credit Facility) is less than 10% of the borrowing base or $12.5 million, whichever is greater, at which point we are required to maintain a minimum fixed charge coverage ratio, as defined, of 1.0 to 1.0 for each fiscal quarter. We were in compliance with these covenants as of December 31, 2017 . 
+51 
+Table of Contents 
+Term Loan Facility 
+On September 19, 2017, we entered into the Term Loan Facility, which provides for a $175.0 million term loan, of which $174.6 million remained outstanding as of December 31, 2017 . Following the completion of the IPO, $113.5 million remained outstanding. The Term Loan Facility is collateralized by the fixed assets of LOS and ACQI and its subsidiaries, and is further secured by Liberty Holdings, as parent guarantor, and subsequent to the IPO by Liberty Inc., Liberty LLC and R/C IV Non-U.S. LOS Corp., a Delaware corporation and a subsidiary of Liberty Inc. The Term Loan Facility matures on September 19, 2022. 
+Borrowings under the Term Loan Facility bear interest at LIBOR or a base rate, plus an applicable margin of 7.625% or 6.625%, respectively, and the weighted average rate on borrowings was 9.21% as of December 31, 2017 . Interest and fees are payable in arrears on the first day of each month. 
+The Term Loan Facility includes certain non-financial covenants, including but not limited to restrictions on incurring additional debt and certain distributions. The Term Loan Facility is not subject to financial covenants unless liquidity, as defined, is less than $25.0 million for at least five consecutive business days, at which point, we are required to maintain a minimum fixed charge coverage ratio, as defined, of 1.2 to 1.0, for each trailing twelve month period. We were in compliance with these covenants as of December 31, 2017 . 
+Bridge Loan 
+During the second quarter of 2017, ACQI entered into a pledge and security agreement and irrevocable proxy with affiliates of Riverstone, Laurel Road, LLC and Spruce Road, LLC (collectively, the “Bridge Loan Lenders”) for an aggregate principal amount totaling $60.0 million, which was evidenced by three promissory notes (collectively, the “Bridge Loan”). The Bridge Loan was to mature on October 10, 2017, unless earlier terminated in connection with an initial public offering, and provided for interest at 12% per annum. 
+In June 2017, in connection with our entry into an amendment to the Prior Credit Facility, the Bridge Loan and accrued interest payable of $60.8 million were assigned from the Bridge Loan Lenders to Liberty Holdings and ACQI’s obligation under the Bridge Loan was canceled in exchange for 60,761,000 Redeemable Class 2 Common Units issued to Liberty Holdings. The Class 2 Redeemable Class 2 Common Units were redeemed in connection with the entry into the Credit Facilities on September 19, 2017. 
+Contractual Obligations 
+The table below provides estimates of the timing of future payments that we are contractually obligated to make based on agreements in place at December 31, 2017 . 
+52 
+Table of Contents 
+Payments Due by Period 
+(dollars in thousands) 
+Total 
+Less than 1 
+year 
+1 – 3 years 
+4 – 5 years 
+More than 5 years 
+ABL Credit Facility (1) 
+$ 
+30,000 
+$ 
+— 
+$ 
+— 
+$ 
+30,000 
+$ 
+— 
+Term Loan Facility (1) 
+174,562 
+1,750 
+3,500 
+169,312 
+— 
+Estimated interest payments (2) 
+79,715 
+17,075 
+33,667 
+28,973 
+— 
+Operating lease obligations (3) 
+100,813 
+25,724 
+42,396 
+9,859 
+22,834 
+Purchase commitments (4) 
+551,940 
+245,626 
+287,115 
+19,199 
+— 
+Total 
+$ 
+937,030 
+$ 
+290,175 
+$ 
+366,678 
+$ 
+257,343 
+$ 
+22,834 
+(1) 
+Payments on our ABL Credit Facility and Term Loan Facility exclude interest payments. Payments are based on debt balances as of December 31, 2017. In January 2018, the Company repaid the full balance on the ABL Credit Facility and 35% of the Term Loan Facility, $113.5 million remains outstanding on the Term Loan Facility. 
+(2) 
+Estimated interest payments are based on debt balances as of December 31, 2017 . Interest rates applied are based on the weighted average rate as of December 31, 2017 . In January 2018, the Company repaid the full balance on the ABL Credit Facility and 35% of the Term Loan Facility, therefore actual interest due in future periods is reduced. 
+(3) 
+Operating lease obligations include payments for leased facilities, equipment and vehicles. 
+(4) 
+Purchase commitments represent payments under supply agreements for the purchase and transportation of proppants. The agreements include minimum monthly purchase commitments, including one agreement under which a shortfall fee may be applied. The shortfall fee may be offset by purchases in excess of the minimum requirement during the three months following the shortfall month. 
+Tax Receivable Agreements 
+With respect to obligations Liberty Inc. expects to incur under the Tax Receivable Agreements (except in cases where Liberty Inc. elects to terminate the Tax Receivable Agreements early, the Tax Receivable Agreements are terminated early due to certain mergers, asset sales, or other changes of control or Liberty Inc. has available cash but fails to make payments when due), generally Liberty Inc. may elect to defer payments due under the Tax Receivable Agreements if Liberty Inc. does not have available cash to satisfy its payment obligations under the Tax Receivable Agreements or if its contractual obligations limit its ability to make such payments. Any such deferred payments under the Tax Receivable Agreements generally will accrue interest. In certain cases, payments under the Tax Receivable Agreements may be accelerated and/or significantly exceed the actual benefits, if any, Liberty Inc. realizes in respect of the tax attributes subject to the Tax Receivable Agreements. Liberty Inc. intends to account for any amounts payable under the Tax Receivable Agreements in accordance with ASC Topic 450, Contingent Consideration. For further discussion regarding the potential acceleration of payments under the Tax Receivable Agreements and its potential impact, please read “Item 1A. Risk Factors—Risks Related to Our Class A Common Stock.” For additional information regarding the Tax Receivable Agreements, see “Item 13. Certain Relationships and Related Party Transactions, and Director Independence—Tax Receivable Agreements.” 
+Income Taxes 
+For U.S. federal income tax purposes, the Predecessor is treated as a partnership. As such, any liability for federal income taxes is the responsibility of the members of the Predecessor. No provision for U.S. federal income taxes has been provided in the historical financial results of the Predecessor. Following the IPO, Liberty Inc. will be subject to income tax expense on the portion of pretax income attributable to stockholders of Liberty Inc. 
+On December 22, 2017, Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act (the "Tax Act"), was enacted by the U.S. government. While the enactment of the Tax Act does not have an impact on the historical financial data, our future tax liabilities may be impacted. Among other changes, the Tax Act: (i) reduces the U.S. federal corporate tax rate from 35% to 21%; (ii) allows for 100% expensing of the costs of certain qualified property acquired after September 27, 2017 and placed in service through December 31, 2022; (iii) modifies the provisions relating to the limitations on deductions for executive compensation of publicly traded corporations; (iv) enacts new limitations regarding the deductibility of interest expense and (v) imposes new limitations on the utilization of net operating losses arising in taxable years beginning after December 31, 2017. 
+53 
+Table of Contents 
+Critical Accounting Policies and Estimates 
+The preparation of financial statements requires the use of judgments and estimates. Our critical accounting policies are described below to provide a better understanding of how we develop our assumptions and judgments about future events and related estimates and how they can impact our financial statements. A critical accounting estimate is one that requires our most difficult, subjective or complex estimates and assessments and is fundamental to our results of operations. 
+We base our estimates on historical experience and on various other assumptions we believe to be reasonable according to the current facts and circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. We believe the following are the critical accounting policies used in the preparation of our combined financial statements, as well as the significant estimates and judgments affecting the application of these policies. This discussion and analysis should be read in conjunction with our combined financial statements and related notes included in “Item 8. Financial Statements and Supplementary Data. ” 
+Revenue Recognition: Revenue from hydraulic fracturing services is recognized as specific services are provided in accordance with contractual arrangements. If our assessment of performance under a particular contract changes, our revenue and / or costs under that contract may change. 
+Accounts Receivable: We analyze the need for an allowance for doubtful accounts for estimated losses related to potentially uncollectible accounts receivable on a case-by-case basis throughout the year. We reserve amounts based on specific identification after considering each customer’s situation, including payment patterns, current financial condition as well as general economic conditions. It is reasonably possible that our estimates of the allowance for doubtful accounts will change and that losses ultimately incurred could differ materially from the amounts estimated in determining the allowance. 
+Inventory: Inventory consists of raw materials used in the hydraulic fracturing process, such as proppants, chemicals and field service equipment maintenance parts, and is stated at the lower of cost or net realizable value, determined using the weighted average cost method. Net realizable value is determined based on our estimates of selling prices in the ordinary course of business, less reasonably predictable cost of completion, disposal, and transportation, each of which require us to apply judgment. 
+Property and Equipment: We calculate depreciation and amortization on our assets based on the estimated useful lives and estimated salvage values that we believe are reasonable. The estimated useful lives and salvage values are subject to key assumptions such as maintenance, utilization and job variation. These estimates may change due to a number of factors such as changes in operating conditions or advances in technology. 
+We incur maintenance costs on our major equipment. The determination of whether an expenditure should be capitalized or expensed requires management judgment in the application of how the costs benefit future periods, relative to our capitalization policy. Costs that either establish or increase the efficiency, productivity, functionality or life of a fixed asset are capitalized and depreciated over the remaining useful life of the asset. 
+Impairment of long-lived and other intangible assets: Long-lived assets, such as property and equipment and finite-lived intangible assets, are evaluated for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Recoverability is assessed using undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets. When alternative courses of action to recover the carrying amount of the asset group are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence, which require us to apply judgment. If the carrying amount of the asset is not recoverable based on its estimated undiscounted cash flows expected to result from the use and eventual disposition, an impairment loss is recognized in an amount by which its carrying amount exceeds its estimated fair value. The inputs used to determine such fair value are primarily based upon internally developed cash flow models. Our cash flow models are based on a number of estimates regarding future operations that may be subject to significant variability, are sensitive to changes in market conditions, and are reasonably likely to change in the future. No events or changes in circumstances occurred that would indicate a potential impairment of property and equipment during the years ended December 31, 2017 and 2016 . During 2015 , the significant decline in commodity prices along with other factors was deemed a triggering event, and the Company tested its long-lived assets for recoverability as of December 31, 2015 . No impairment was recognized during the years ended December 31, 2017 , 2016 and 2015 . 
+Unit-based awards: Unit-based awards have been granted with a benchmark value equal to or greater than the fair market value of the award as of the date of grant. We account for unit-based awards by measuring the awards at the grant date and recognizing the grant-date fair value, if any, as an expense over the requisite service period. Since we are not publicly traded we 
+54 
+Table of Contents 
+do not have a listed price with which to calculate fair value. We have historically and consistently calculated fair value using a combination of an income approach (discounted cash flow method) and market approach (guideline public company method and merger and acquisition method). Each of these valuation approaches involves significant judgments and estimates, including estimates regarding our future operations or the determination of a comparable public company peer group. Additionally, judgment is applied in the weighting of each valuation approach. We have elected to account for forfeitures when they occur, as permitted by Accounting Standards Updated ( “ ASU ” ) 2016-09, “ Compensation-Stock Compensation - Improvements to Employee Share-Based Payment Accounting. ” 
+Recent Accounting Pronouncements 
+See Note 2, “Significant Accounting Policies - Recently Issued Accounting Standards” and Note 2, “Significant Accounting Policies—Recently Adopted Accounting Standards” to the combined financial statements included in “Item 8. Financial Statements and Supplementary Data” for a discussion of recent accounting pronouncements. 
+Off Balance Sheet Arrangements 
+We have no material off balance sheet arrangements as of December 31, 2017, except for the operating leases and purchase commitments under supply agreements as disclosed above under “—Contractual Obligations.” As such, we are not materially exposed to any other financing, liquidity, market or credit risk that could arise if we had engaged in such financing arrangements. 
+55 
+Table of Contents 
+Item 7A. Quantitative and Qualitative Disclosure about Market Risk 
+Industry Risk 
+The demand, pricing and terms for hydraulic fracturing services provided by us are largely dependent upon the level of drilling activity in the U.S. oil and natural gas industry. These activity levels are influenced by numerous factors over which we have no control, including, but not limited to: the supply of and demand for oil and natural gas; the level of prices, and expectations about future prices of oil and natural gas; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; the discovery rates of new oil and natural gas reserves; available rail and other transportation capacity; weather conditions; domestic and worldwide economic conditions; political instability in oil-producing countries; environmental regulations; technical advances affecting energy consumption; the price and availability of alternative fuels; the ability of E&P companies to raise equity capital and debt financing; and merger and divestiture activity among E&P companies. 
+The level of U.S. oil and natural gas drilling is volatile. Expected trends in oil and natural gas production activities may not materialize and demand for our services may not reflect the level of activity in the industry. Any prolonged and substantial reduction in oil and natural gas prices would likely affect oil and natural gas production levels and therefore affect demand for our services. A material decline in oil and natural gas prices or U.S. activity levels could have a material adverse effect on our business, financial condition, results of operations and cash flows. 
+Interest Rate Risk 
+At December 31, 2017 , we had $204.6 million of debt outstanding, with a weighted average interest rate of 8.37%. Interest is calculated under the terms of our Credit Facilities based on our selection, from time to time, of one of the index rates available to us plus an applicable margin that varies based on certain factors. See “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements.” Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the weighted average interest rate would be approximately $2.0 million per year. We do not currently have or intend to enter into any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness. 
+56 
+Table of Contents 
+Item 8. Financial Statements and Supplementary Data 
+Our financial statements and supplementary data are included in this Annual Report on Form 10-K beginning on page F-1 and incorporated by reference herein. 
+Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 
+None. 
+Item 9A. Controls and Procedures 
+Management’s Report on Internal Control Over Financial Reporting 
+This Annual Report on Form 10-K does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of the Company's registered public accounting firm due to a transition period established by the SEC for newly public companies. 
+We have identified a material weakness in our internal control over financial reporting as of December 31, 2017, which was also identified and communicated to us by our independent registered public accounting firm. A “material weakness” is a deficiency, or combination of deficiencies, in internal controls such that there is a reasonable possibility that a material misstatement in financial statements will not be prevented or detected on a timely basis. 
+The material weakness identified relates to the lack of implementation and maintenance of effective segregation of duties, including controls over journal entries, that would provide a reasonable possibility that a material misstatement would not be prevented or detected on a timely basis. 
+In early 2018, we began taking steps to implement controls to remediate the material weakness, including the following: 
+• 
+utilizing information technology personnel to review system authorization among users to ensure proper segregation of duties; and 
+• 
+engagement of a third party to assist in our documentation, implementation and testing of internal controls related to segregation of duties, including controls over journal entries. 
+Evaluation of Disclosure Controls and Procedures 
+Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report on Form 10-K. The evaluation included certain internal control areas in which we have made and are continuing to make changes to improve and enhance controls. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to management, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure. Based on such evaluation, our principal executive officer and principal financial officer concluded that, as of December 31, 2017, our disclosure controls and procedures were effective, at the reasonable assurance level. Any controls and procedures, no matter how well designed and operated can only provide reasonable assurance of achieving the desired control objective and management necessarily applies its judgment in evaluating the cost-benefit relationship of all possible controls and procedures. 
+Notwithstanding the material weakness discussed above, management believes, based upon the substantive work performed, that our consolidated financial statements included in this Annual Report on Form 10-K fairly present in all material respects our financial condition, results of operations and cash flows at and for the periods presented in accordance with GAAP and that the other information required to be disclosed by us in this Annual Report on Form 10-K is complete and accurate in all material respects. 
+Changes in Internal Control Over Financial Reporting 
+Other than as described above, there were no changes in our internal control over financial reporting during the quarter ended December 31, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
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+Table of Contents 
+Attestation Report of the Registered Public Accounting Firm 
+This Annual Report on Form 10-K does not include an attestation report of our independent registered public accounting firm due to a transition period established by the rules of the SEC for newly public companies. 
+Item 9B. Other Information 
+None. 
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+Table of Contents 
+PART III 
+Item 10. Directors, Executive Officers and Corporate Governance 
+Set forth below are the name, age, position and description of the business experience of our executive officers and directors, as of December 31, 2017 . 
+Name 
+Age 
+Position with Liberty Oilfield Services Inc. 
+Christopher A. Wright 
+53 
+Chairman of the Board and Chief Executive Officer 
+Michael Stock 
+56 
+Chief Financial Officer 
+Ron Gusek 
+46 
+President 
+R. Sean Elliott 
+43 
+Vice President and General Counsel 
+Ryan T. Gosney 
+45 
+Chief Accounting Officer 
+Cary D. Steinbeck (a)(b) 
+46 
+Director 
+N. John Lancaster, Jr. 
+49 
+Director 
+Brett Staffieri (b) 
+39 
+Director 
+William F. Kimble (a) 
+58 
+Director 
+Peter A. Dea (a)(b) 
+64 
+Director 
+Ken Babcock 
+61 
+Director 
+Jesal Shah 
+32 
+Director 
+(a) Member, Audit Committee 
+(b) Member, Compensation Committee 
+Christopher A. Wright—Chairman of the Board and Chief Executive Officer. Chris Wright has served as our Chief Executive Officer since December 2016 and as the Chief Executive Officer of Liberty Holdings since its formation in March 2011 until the IPO. He is also the Executive Chairman of Liberty Resources, an E&P company focused in the Williston Basin, and was the Chief Executive Officer from its formation in September 2010 until March 2017. Mr. Wright has also served on our board of directors since the IPO. Mr. Wright is also a director of TAS Energy Inc., Liberty Resources and Kerogen Exploration, Inc. Mr. Wright founded Pinnacle Technologies, a company that developed and commercialized tiltmeter and microseismic fracture mapping, and served as CEO of Pinnacle Technologies from 1992 to 2006. From 2000 to 2006, Mr. Wright served as Chairman of Stroud Energy, Inc., a shale natural gas producer. Mr. Wright has a Bachelor of Science in Mechanical Engineering from the Massachusetts Institute of Technology (“MIT”) and conducted graduate work in electrical engineering at both the University of California-Berkeley and MIT. We believe that Mr. Wright’s experience leading our growth as our Chief Executive Officer and his extensive experience in the hydraulic fracturing services industry qualifies him to serve on our board of directors. 
+Michael Stock—Chief Financial Officer. Michael Stock has served as our Chief Financial Officer since December 2016 and as the Chief Financial Officer of Liberty Holdings from April 2012 until our IPO. Mr. Stock served as a director from December 2016 up until the IPO. Prior to joining Liberty Holdings, from 2009 to 2012, he was employed by TAS Energy Inc., an industrial energy technology company. During his tenure, he served as CFO and was a key part of the raising of equity from leading investment groups including Kleiner Perkins, Element Partners, Natural Gas Partners and Credit Suisse. From 1997 to 2009, Mr. Stock served as CFO for Pinnacle Technologies. 
+Ron Gusek—President. Ron Gusek has served as our President since December 2016 and as the President of Liberty Holdings from November 2016 until the IPO. Mr. Gusek served as the Vice President of Technology and Development of Liberty Holdings, from 2014 until his promotion. Prior to joining Liberty Holdings, from 2011 to 2014, Mr. Gusek served as Vice President, Corporate Engineering and Technology of Sanjel Corporation, a global energy service company. Prior to joining Sanjel Corporation, from 2009 to 2011, Mr. Gusek was Director of Engineering for Zodiac Exploration, an E&P company working in the central San Joaquin valley in California. From 2003 to 2008, Mr. Gusek was the Canadian Regional Manager of Pinnacle Technologies. Mr. Gusek has a Bachelor of Science in Mechanical Engineering from the University of Alberta. 
+R. Sean Elliott—Vice President and General Counsel. Sean Elliott has served as our Vice President and General Counsel since March 2017. Between September 2016 and March 2017, Mr. Elliott worked as Assistant General Counsel at USAA Real Estate Company, a real estate investment firm. Between June 2015 and September 2016, Mr. Elliott served as Counsel at Haynes and Boone, LLP, an international corporate law firm. Between November 2007 and May 2015, Mr. Elliott served as Vice President, General Counsel, Corporate Secretary and Chief Compliance Officer of CARBO Ceramics Inc., an oilfield services production enhancement company. Mr. Elliott has a Bachelor of Arts in Economics and Business Administration from Austin College and a Doctor in Jurisprudence degree from the University of Texas at Austin. 
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+Table of Contents 
+Ryan T. Gosney—Chief Accounting Officer . Ryan Gosney has been our Chief Accounting Officer since March 2017. Between July 2016 and February 2017, Mr. Gosney served as the Chief Accounting Officer of Vantage Energy Inc. (“Vantage”), an oil and gas exploration and production company. Prior to joining Vantage, Mr. Gosney served as Chief Financial Officer for Dorado E&P Partners, LLC, an oil and gas company, from January 2012 to January 2016. Mr. Gosney began his career as an auditor with Arthur Andersen, LLP in September 1995 where he served in increasing roles of responsibility up to Audit Manager until June 2002. Mr. Gosney has also served as Controller for Patina Oil & Gas Corporation from October 2002 to October 2005 and Delta Petroleum Corporation from October 2005 to January 2012. Mr. Gosney has a Bachelor of Business Administration from Texas Christian University. 
+Cary D. Steinbeck—Independent Director. Mr. Steinbeck has served on our board of directors since the IPO. Mr. Steinbeck has served on the board of managers of Liberty Holdings from October 2016 until the IPO. Mr. Steinbeck has been a Managing Director at Shea Ventures, an investment firm, since October 2014. From 2007 to 2014, Mr. Steinbeck served as a Managing Director at the Oakmont Corporation, an investment firm. Mr. Steinbeck is also a director at Liberty Resources and is a Chartered Financial Analyst ® charterholder. Mr. Steinbeck has a Bachelor of Arts in Economics from the University of California, Santa Barbara, and a Master of Business Administration from the University of Southern California. We believe that Mr. Steinbeck’s experience in the private equity industry, energy sector investing experience, extensive board participation and understanding of financial markets will provide valuable insights for our company and qualify him for service on our board of directors. 
+N. John Lancaster, Jr.—Director. Mr. Lancaster has served on our board of directors since the IPO. Mr. Lancaster is currently a Partner at Riverstone, an energy-focused private equity firm. Prior to joining Riverstone in 2000, Mr. Lancaster was a director with The Beacon Group, LLC, a privately held firm specializing in principal investing and strategic advisory services in the energy and other industries. Prior to joining Beacon, Mr. Lancaster was a Vice President with Credit Suisse First Boston’s Natural Resources Group in Houston, Texas. Mr. Lancaster served on the board of directors of Cobalt International Energy, Inc., an exploration and production company, from May 2010 to May 2013. Mr. Lancaster has a Bachelor of Business Administration from the University of Texas at Austin and a Master of Business Administration from Harvard Business School. Mr. Lancaster has been nominated to serve on our board of directors by Riverstone pursuant to the stockholders’ agreement. We believe Mr. Lancaster’s experience investing in the energy sector as well as his strong financial experience qualify him for service on our board of directors. 
+Brett Staffieri—Director. Mr. Staffieri has served our board of directors since the IPO. Mr. Staffieri has been a Managing Director at Riverstone, an energy-focused private equity firm, since 2014, and has worked at Riverstone since 2006. Mr. Staffieri has a Bachelor of Business Administration from the University of Texas at Austin and a Master of Business Administration from The Wharton School, where he graduated with honors. Mr. Staffieri has been nominated to serve on our board of directors by Riverstone pursuant to the stockholders’ agreement. We believe that Mr. Staffieri’s extensive experience investing in the energy sector, particularly with respect to his involvement in Liberty Holdings since its founding, qualifies him for service on our board of directors. 
+William F. Kimble—Independent Director. Mr. Kimble has served on our board of directors since the IPO. From 2009 until his retirement in 2015, Mr. Kimble served as the Office Managing Partner for the Atlanta office and Managing Partner - Southeastern United States at KPMG LLP (“KPMG”), one of the largest audit, tax and advisory services firms in the world. Mr. Kimble was also responsible for moderating KPMG’s Audit Committee Institute and Audit Committee Chair Sessions. Until his retirement, Mr. Kimble had been with KPMG or its predecessor firm since 1986. During his tenure with KPMG, Mr. Kimble also held numerous senior leadership positions, including Global Chairman of Industrial Markets. Mr. Kimble also served as KPMG’s Energy Sector Leader for 10 years and was the executive director of KPMG’s Global Energy Institute. Mr. Kimble serves on the board of directors and the audit committee of PRGX Global, Inc. Mr. Kimble also serves on the board of directors, the special committee, and is chair of the audit committee of DCP Midstream Partners, LP. Mr. Kimble has a Bachelor of Accounting and Business Administration from Southern Methodist University. We believe that Mr. Kimble’s extensive accounting background and his experience as a director of a public company qualify him for service on our board of directors. 
+Peter A. Dea—Independent Director. Mr. Dea has served on our board of directors since the IPO. Mr. Dea has been the Executive Chairman of Confluence Resources LP (“Confluence”) since September 2016. Mr. Dea has served as the President and Chief Executive Officer of Cirque Resources LP (“Cirque”) since May 2007. Both Confluence and Cirque are private oil and gas companies. From November 2001 through August 2006, Mr. Dea was President and Chief Executive Officer and a director of Western Gas Resources, Inc. (“Western Gas”). Mr. Dea joined Barrett Resources Corporation (“Barrett”) in November 1993 and served as Chief Executive Officer and director from November 1999 and as Chairman from February 2000 through August 2001. Western Gas and Barrett were public oil and gas companies. Prior to that Mr. Dea served in several geologic positions with Exxon Company, U.S.A. Mr. Dea currently serves as a director of Encana Corporation. Mr. Dea has a Bachelor of Arts in Geology from Western State Colorado University and a Masters of Science in Geology from the University of Montana. Mr. Dea also attended the Harvard Business School, Advanced Management Program. We believe that Mr. Dea’s 
+60 
+Table of Contents 
+extensive oil and gas exploration and production experience and involvement in state and national energy policies qualify him for service on our board of directors. 
+Ken Babcock—Independent Director. Mr. Babcock has served on our board of directors since the IPO. Mr. Babcock is currently the Chief Executive Officer of Abaco Energy Technologies LLC (“Abaco”), a private Houston-based company that was formed by Riverstone in 2013 to focus on opportunities in manufacturing and services related to North American drilling, completion, and production, and associated infrastructure. Prior to joining Abaco, Mr. Babcock was the President and Chief Executive Officer of Titan Specialties, Ltd. (“Titan”), a Riverstone portfolio company, from 2008 until its sale to Hunting PLC in September 2011. Following the sale, Mr. Babcock remained at Titan until June 2012. Prior to joining Titan, from 2005 until 2008, Mr. Babcock served as President and Chief Executive Officer of International Logging, Inc. (“ILI”), also a Riverstone portfolio company, where he took a narrowly-focused mud logging company of over 300 employees to a diverse well site services organization of over 1,800 employees spread over 60 countries in a little over two years. Prior to joining ILI, Mr. Babcock was Director of Strategic Sales at Baker Hughes INTEQ and Vice President of Business Development at Noble Technology Services. Mr. Babcock began his career with EXLOG in 1980. Mr. Babcock has a Bachelor of Science in Geology from Florida State University. Mr. Babcock has been nominated to serve on our board of directors by Riverstone pursuant to the stockholders’ agreement. We believe that Mr. Babcock’s strong business leadership experience qualifies him for service on our board of directors. 
+Jesal Shah—Director. Mr. Shah has served on our board of directors since the IPO. Mr. Shah is a Vice President of Riverstone, an energy-focused private equity firm. Mr. Shah joined Riverstone in 2010 and returned to Riverstone in 2015 after earning a Master of Business Administration. Prior to joining Riverstone, Mr. Shah worked in the Investment Banking Division of Credit Suisse. While at Credit Suisse, Mr. Shah worked on mergers and acquisitions and capital markets financings in the global energy sector. Mr. Shah has a Bachelor of Arts in Economics and Spanish from Tufts University and a Master of Business Administration from Harvard Business School. Mr. Shah has been nominated to serve on our board of directors by Riverstone pursuant to the stockholders’ agreement. We believe that Mr. Shah’s experience investing in the energy sector qualifies him for service on our board of directors. 
+Status as a Controlled Company 
+Because the Principal Stockholders, together with affiliates of Riverstone, own approximately 59.5% of the voting power of our capital stock, we are a controlled company as of March 16, 2018 under Sarbanes-Oxley and NYSE corporate governance standards. A controlled company does not need its board of directors to have a majority of independent directors or to form independent compensation and nominating and governance committees. As a controlled company, we are subject to rules of Sarbanes-Oxley and the NYSE that require us to have an audit committee composed entirely of independent directors. We are required to have at least two independent directors on our audit committee within 90 days of the listing date, and at least three independent directors on our audit committee within one year of the listing date. As of March 16, 2018, we have three independent directors on our audit committee. 
+If at any time we cease to be a controlled company, we will take all action necessary to comply with Sarbanes-Oxley and NYSE corporate governance standards, including by appointing a majority of independent directors to our board of directors and ensuring we have a nominating and corporate governance committee composed entirely of independent directors, subject to a permitted “phase-in” period. 
+Our board of directors consists of a single class of directors each serving one-year terms. After we cease to be a controlled company, our board of directors will be divided into three classes of directors, with each class as equal in number as possible, serving staggered three-year terms, and such directors will be removable only for “cause.” 
+Composition of Our Board of Directors 
+Our board of directors prior to the IPO consisted of one member, Michael Stock. In connection with the IPO, we expanded our board of directors from one to eight members, Michael Stock resigned and eight new members were appointed. 
+In connection with the IPO, we entered into a stockholders’ agreement with the Principal Stockholders. The stockholders’ agreement provides Riverstone with the right to designate a certain number of nominees to our board of directors so long as they and their affiliates collectively beneficially own more than 10% of the outstanding shares of our Class A Common Stock. 
+In evaluating director candidates, we assess whether a candidate possesses the integrity, judgment, knowledge, experience, skills and expertise that are likely to enhance the board’s ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the board to fulfill their duties of increasing the length of time necessary to change the composition of a majority of the board of directors. 
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+Table of Contents 
+Family Relationships 
+None of our officers or directors has any family relationship with any director or other officer. “Family relationship” for this purpose means any relationship by blood, marriage or adoption, not more remote than first cousin. 
+Director Independence 
+Our board of directors has determined that each of Cary D. Steinbeck, Peter A. Dea, Ken Babcock and William F. Kimble are independent within the meaning of the NYSE listing standards currently in effect and 10A-3 of the Exchange Act. 
+Committees of the Board of Directors 
+Audit Committee 
+Rules implemented by the NYSE and the SEC require us to have an audit committee comprised of at least three directors who meet the independence and experience standards established by the NYSE and the Exchange Act, subject to transitional relief during the one-year period following the completion of the IPO. Our audit committee currently consists of three directors, all of whom are independent under the rules of the SEC and the standards set forth by the NYSE applicable to members of an audit committee. William F. Kimble, Peter A. Dea and Cary D. Steinbeck are the members of our audit committee. Each member of the audit committee is financially literate, and our board of directors has determined that William F. Kimble qualifies as an “audit committee financial expert” as defined in applicable SEC rules. 
+This committee oversees, reviews, acts on and reports on various auditing and accounting matters to our board of directors, including: the selection of our independent accountants, the scope of our annual audits, fees to be paid to the independent accountants, the performance of our independent accountants and our accounting practices. In addition, the audit committee oversees our compliance programs relating to legal and regulatory requirements. The committee operates under an audit committee charter that defines the committee’s primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards. A current copy of the audit committee charter is posted under the Corporate Governance section of our website, which is located at www.libertyfrac.com. 
+Compensation Committee 
+While we are not currently required to do so because we are a “controlled company” within the meaning of the NYSE corporate governance standards, in early March 2018, our board of directors formed a compensation committee. Our compensation committee currently consists of three directors, Brett Staffieri, Peter A. Dea and Cary D. Steinbeck. Our compensation committee assists our board of directors in establishing salaries, incentives and other forms of compensation for officers and other employees. Our compensation committee also administers our incentive compensation and benefit plans. The committee operates under a compensation committee charter that defines the committee’s primary duties. A current copy of the compensation committee charter is posted under the Corporate Governance section of our website, which is located at www.libertyfrac.com. 
+The board of directors has determined that Peter A. Dea and Cary D. Steinbeck are independent under the standards set forth by the NYSE. Because we are a “controlled company” within the meaning of the NYSE corporate governance standards, we are not required to, and do not currently expect to, have a compensation committee comprised entirely of independent directors. If and when we are no longer a “controlled company” within the meaning of the NYSE corporate governance standards, we may be required to make changes to the composition of our compensation committee so that it is comprised entirely of independent directors. 
+Nominating and Corporate Governance Committee 
+Because we are a “controlled company” within the meaning of NYSE corporate governance standards, we will not be required to, and do not currently expect to, have a nominating and corporate governance committee. 
+If and when we are no longer a “controlled company” within the meaning of NYSE corporate governance standards, we will be required to establish a nominating and corporate governance committee. We anticipate that such a nominating and corporate governance committee would consist of three directors who will be “independent” under the rules of the SEC. This committee would identify, evaluate and recommend qualified nominees to serve on our board of directors, develop and oversee our internal corporate governance processes and maintain a management succession plan. Upon formation of a nominating and corporate governance committee, we would expect to adopt a nominating and corporate governance committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and NYSE standards. 
+62 
+Table of Contents 
+Corporate Code of Business Conduct and Ethics 
+Our board of directors has adopted a Corporate Code of Business Conduct and Ethics (the “Ethics Code”) applicable to our employees, directors and officers, in accordance with applicable U.S. federal securities laws and the corporate governance rules of the NYSE. Any waiver of the Ethics Code may be made only by our board of directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the NYSE. A current copy of the Ethics Code is posted under the Corporate Governance section of our website, which is located at www.libertyfrac.com. 
+Corporate Governance Guidelines 
+Our board of directors has adopted corporate governance guidelines in accordance with the corporate governance rules of the NYSE. A current copy of the corporate governance guidelines is posted under the Corporate Governance section of our website, which is located at www.libertyfrac.com. 
+63 
+Table of Contents 
+Item 11. Executive Compensation 
+Compensation Discussion and Analysis 
+We did not pay any compensation to officers or employees during the fiscal year ended December 31, 2017. However, the operations of our predecessors are being carried on by us and our subsidiaries following our initial public offering, and the executive officers of our Predecessor have been our executive officers since December 2016 or commencement of their employment if at a later date. As such, we believe that disclosure regarding our executive officers’ compensation, which was established and paid by our Predecessor, is generally appropriate and relevant to the stockholders, and as such, is disclosed in this Compensation Discussion and Analysis (“CD&A”) and the executive compensation tables and narrative that follow. 
+This CD&A describes our Predecessor’s practices with regard to the compensation of our named executive officers (our “Named Executive Officers”) for the fiscal year ended December 31, 2017. Our Named Executive officers for the fiscal year ended December 31, 2017 include: 
+Name 
+Title 
+Christopher A. Wright 
+Chairman of the Board and Chief Executive Officer* 
+Michael Stock 
+Chief Financial Officer* 
+Ron Gusek 
+President 
+R. Sean Elliott 
+Vice President and General Counsel 
+Ryan T. Gosney 
+Chief Accounting Officer 
+*In connection with our initial public offering, Mr. Stock ceased to be a member of our board of directors and Mr. Wright was appointed to our board of directors. 
+This CD&A is intended to provide context for the tabular disclosure provided in the executive compensation tables below and to provide investors with the material information necessary to understand our executive compensation program. 
+Process for Determining Compensation 
+The board of directors of our Predecessor was responsible for oversight of the compensation of our Chief Executive Officer, Chief Financial Officer and President during the fiscal year ended December 31, 2017, with the objective of attracting and retaining talented executives. The board of directors of our Predecessor had the authority to determine the compensation for these officers for the fiscal year ended December 31, 2017, although actual compensation determinations may have been delegated to one or more board members. The board of directors of our Predecessor considered input from our Chief Executive Officer in making determinations regarding our Predecessor’s executive compensation program and the individual compensation of these Named Executive Officers. Our Chief Executive Officer and management also provided the board of directors of our Predecessor information regarding the performance of our Company for the determination of annual bonuses. 
+Our Chief Executive Officer was responsible for approving, evaluating and making the final decisions concerning the compensation of our Vice President and General Counsel and our Chief Accounting Officer for the fiscal year ended December 31, 2017. Our Chief Executive Officer made these decisions with a goal of recruiting and retaining talented executives for these positions, and also considered performance of the Company in connection with the determination. 
+Elements of Compensation 
+Base Salaries 
+Each Named Executive Officer’s base salary is a fixed component of compensation for performing specific job duties and functions. The base salaries of the Named Executive Officers in effect for the fiscal year ended December 31, 2017 were established at a level that the board of directors of our Predecessor and our Chief Executive Officer determined was necessary to retain the individual’s services. The board of directors of our Predecessor has historically reviewed executive officers’ base salaries on an annual basis and made adjustments based upon consideration of any factors that it deems relevant. Our executive officers voluntarily reduced their base salaries for a portion of 2015 and for the full year in 2016 due to the significant downturn in our industry. On October 11, 2017, in light of the recovery in our industry and the increase in our earnings through the first three quarters of the fiscal year ended December 31, 2017, the board of directors of our Predecessor determined it was appropriate to provide for an increase in the base salaries of Messrs. Wright, Stock and Gusek, as reflected in the table below: 
+64 
+Table of Contents 
+For the year ended December 31, 
+Name 
+2016 
+2017 
+Christopher A. Wright 
+$ 
+124,313 
+$ 
+500,000 
+Michael Stock 
+183,921 
+375,000 
+Ron Gusek 
+150,820 
+375,000 
+R. Sean Elliott 
+N/A 
+350,000 
+Ryan T. Gosney 
+N/A 
+255,000 
+Annual Bonuses 
+Our annual bonus awards have historically been discretionary bonuses based on the net income performance of our Predecessor. Each of our Named Executive Officers received a discretionary bonus for the fiscal year ended December 31, 2017. Members of the board of directors of our Predecessor, in consultation with our Chief Executive Officer, determined that the discretionary bonuses awarded to our Chief Executive Officer, Chief Financial Officer and President for the fiscal year ended December 31, 2017 were appropriate in light of the lower annual bonuses provided in previous fiscal years, our IPO, and their efforts in managing our Predecessor through the larger industry downturn. Our Chief Executive Officer determined that the bonuses paid to our Vice President and General Counsel and our Chief Accounting Officer were appropriate given the significant efforts they played in preparing for our IPO and their contributions to enhancing our administrative processes in the legal and accounting areas, respectively. 
+Long-Term Incentive Compensation 
+We have historically offered long-term incentives to our Named Executive Officers through grants of restricted Class B Units in Liberty Holdings. These Class B Unit awards were subject to time-based vesting requirements and accelerated vesting upon the occurrence of certain terminations of employment and certain change in control events. The Class B Units were designed to provide a retention incentive and to encourage the Named Executive Officers to increase the long-term value of our Predecessor. We did not grant any Class B Units to our Named Executive Officers during the fiscal year ended December 31, 2017. 
+Other Compensation Elements 
+401(k) Plan — We currently maintain a retirement plan intended to provide benefits under section 401(k) of the Internal Revenue Code under which employees, including our Named Executive Officers, are allowed to contribute portions of their base compensation to a tax-qualified retirement account. Matching contributions were temporarily suspended in May 2015, but were resumed in April 2017 at a rate of $1.00 for each $1.00 of employee contribution, subject to a cap of 3% of the employee’s salary. In October 2017, the cap on these contributions was increased to 6% of the employee’s base salary. 
+Pension and Nonqualified Deferred Compensation — We have not maintained, and do not currently maintain, a defined benefit pension plan or nonqualified deferred compensation plan. 
+Employment Agreements — We have not entered into any employment or severance agreements with any of our Named Executive Officers. 
+Actions Taken Following Fiscal Year End 
+Legacy Restricted Stock Plan 
+In connection with our reorganization and the IPO, the Class B Units in Liberty Holdings previously granted to our Named Executive Officers that remained unvested were exchanged for restricted shares of our Class A common stock granted pursuant to the Liberty Oilfield Services Inc. Legacy Restricted Stock Plan (the “Legacy Plan”). These restricted stock awards are subject to the same vesting conditions applicable to the Class B Units immediately prior to the exchange. See below under “ — Potential Payments Upon a Termination or Change in Control” for additional information regarding the circumstances that could result in accelerated vesting of these awards. 
+Long-Term Incentive Plan 
+In order to incentivize individuals providing services to us or our affiliates, our Board adopted the Liberty Oilfield Services Inc. Long Term Incentive Plan (the “LTIP”) in connection with our IPO. The LTIP provides for the grant, from time to time, at the discretion of our Board or a committee thereof, of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, cash awards, substitute awards and performance awards. 
+65 
+Table of Contents 
+Board of Directors Report 
+Because the Company’s compensation committee is merely advisory in nature, the board of directors reviewed and discussed the Compensation Discussion and Analysis required by Item 402 of Regulation S-K promulgated by the SEC with management of the Company, and, based on such review and discussions, the board of directors approved the inclusion of such Compensation Discussion and Analysis in this Annual Report on Form 10-K for the fiscal year ended December 31, 2017. 
+Board of Directors 
+Christopher A. Wright 
+Cary D. Steinbeck 
+N. John Lancaster, Jr. 
+Brett Staffieri 
+William F. Kimble 
+Peter A. Dea 
+Ken Babcock 
+Jesal Shah 
+66 
+Table of Contents 
+Summary Compensation Table 
+The following table summarizes the compensation awarded to, earned by or paid to (i) our principal executive officer and our next two most highly-compensated executive officers for the fiscal years ended December 31, 2016 and 2015 and (ii) our principal executive officer, principal financial officer and our three other most highly-compensated executive officers (our “Named Executive Officers”) for the fiscal years ended December 31, 2017 . 
+Name and Principal Position 
+Year 
+Salary 
+($) 
+Bonus 
+($)(3) 
+Option 
+Awards 
+($)(4) 
+All Other 
+Compensation 
+($)(5) 
+Total 
+($) 
+Christopher A. Wright 
+(Chairman of the Board and Chief Executive Officer(1)) 
+2017 
+349,890 
+1,590,162 
+— 
+5,722 
+1,945,774 
+2016 
+124,313 
+— 
+— 
+— 
+124,313 
+2015 
+138,124 
+190,896 
+— 
+— 
+329,020 
+Michael Stock 
+(Chief Financial Officer & Director(1)) 
+2017 
+282,668 
+1,192,809 
+— 
+8,513 
+1,483,990 
+2016 
+183,921 
+25,000 
+— 
+— 
+208,921 
+2015 
+204,353 
+239,033 
+— 
+4,471 
+447,857 
+Ron Gusek 
+(President) 
+2017 
+242,885 
+1,192,809 
+— 
+7,603 
+1,443,297 
+2016 
+150,820 
+25,000 
+— 
+— 
+175,820 
+2015 
+167,574 
+179,275 
+— 
+3,666 
+350,515 
+R. Sean Elliott (2) 
+(Vice President & General Counsel) 
+2017 
+280,667 
+175,750 
+— 
+52,822 
+509,239 
+Ryan T. Gosney (2) 
+(Chief Accounting Officer) 
+2017 
+207,256 
+156,683 
+— 
+7,356 
+371,295 
+(1) 
+In connection with our initial public offering, Mr. Stock ceased to be a member of our board of directors and Mr. Wright was appointed to our board of directors. 
+(2) 
+Messrs. Elliott and Gosney joined us in March 2017, and as such, there is no compensation reported for Messrs. Elliott and Gosney for 2015 and 2016. 
+(3) 
+Amounts reported in the “Bonus” column reflect discretionary bonuses earned for service in 2017 . $750 of these bonuses for each Named Executive Officer were part of year-end bonuses we paid to all our employees. The remainder of these bonuses were paid in February 2018, other than quarterly bonuses totaling $36,720, which were received by Mr. Gosney during 2017 after the end of the second and third quarters. 
+(4) 
+Amounts reported in the “Option Awards” column reflect the aggregate grant date fair value, computed in accordance with FASB ASC Topic 718, of Class B-5 Units granted to Mr. Gusek during fiscal year 2016. The Class B-5 Units represent membership interests in Liberty Holdings that are intended to constitute profits interests for federal income tax purposes. Despite the fact that the Class B-5 Units do not require the payment of an exercise price, they are most similar economically to stock options. Accordingly, they are classified as “options” under the definition provided in Item 402(a)(6)(i) of Regulation S-K as an instrument with an “option-like feature.” 
+(5) 
+For Mr. Elliott, amounts reported in the “All Other Compensation” column reflect (a) $6,387 of discretionary matching contributions made by our Predecessor to his 401(k) plan account during the fiscal year ended December 31, 2017 and (b) $46,435 of travel, lodging, and related expenses during the fiscal year ended December 31, 2017. For the other Named Executive Officers, amounts reported in the “All Other Compensation” column reflect discretionary matching contributions made by our Predecessor to each Named Executive Officer’s 401(k) plan account during the fiscal year ended December 31, 2017. 
+Grants of Plan-Based Awards Table 
+We did not grant any plan-based awards to our Named Executive Officers during the fiscal year ended December 31, 2017. 
+67 
+Table of Contents 
+Outstanding Equity Awards at 2017 Fiscal Year-End 
+The following table reflects information regarding outstanding equity-based awards held by our Named Executive Officers as of December 31, 2017 , which consist exclusively of Class B Units in Liberty Holdings. 
+Name (a) 
+Option Awards (1) 
+Number of Securities 
+Underlying Unexercised 
+Options (#) 
+Exercisable 
+Number of Securities 
+Underlying Unexercised 
+Options (#) 
+Unexercisable 
+Option 
+Exercise Price 
+($)(4) 
+Option 
+Expiration Date 
+(4) 
+Christopher A. Wright 
+150,000 
+— 
+N/A 
+N/A 
+Michael Stock 
+80,000 
+— 
+N/A 
+N/A 
+Ron Gusek 
+37,500 
+12,500 
+(2) 
+N/A 
+N/A 
+6,250 
+18,750 
+(3) 
+N/A 
+N/A 
+R. Sean Elliott (5) 
+— 
+— 
+N/A 
+N/A 
+Ryan T. Gosney (5) 
+— 
+— 
+N/A 
+N/A 
+(1) 
+The equity awards disclosed in this table are restricted Class B Units in Liberty Holdings, which are intended to be profits interests for federal income tax purposes. The Class B Units are subject to time-based vesting conditions, and each award vests 25% each year over four years following the vesting start date, subject to the Named Executive Officer’s continued employment through the applicable vesting date. The treatment of these awards upon certain terminations of employment and change in control events is described below under “—Potential Payments Upon a Termination or Change in Control.” 
+(2) 
+The restricted stock awards received in exchange for these Class B Units vested on February 20, 2018. 
+(3) 
+The restricted stock awards received in exchange for these Class B Units will vest ratably on each of October 31, 2018, October 31, 2019 and October 31, 2020, so long as Mr. Gusek remains employed through such dates. 
+(4) 
+These equity awards are not traditional options, and therefore, there is no exercise price or option expiration date associated with them. 
+(5) 
+Messrs. Elliott and Gosney did not hold any equity awards as of December 31, 2017. 
+Option Exercises and Stock Vested 
+No option or stock awards have been granted to our Named Executive Officers as of December 31, 2017. Additionally, our Named Executive Officers did not dispose of any previously granted Class B Units in Liberty Holdings during the fiscal year ended December 31, 2017. 
+Pension Benefits and Nonqualified Deferred Compensation 
+We have not maintained, and do not currently maintain, a defined benefit pension plan or nonqualified deferred compensation plan. 
+Potential Payments Upon Termination or Change in Control 
+We do not currently maintain any employment agreements, severance agreements or change in control agreements with any of the Named Executive Officers. 
+As of December 31, 2017, Mr. Gusek was the only Named Executive Officer with unvested Class B Units in Liberty Holdings. As discussed above, these unvested Class B Units were exchanged for shares of our restricted Class A common stock in connection with our initial public offering. The restricted shares will accelerate and become 100% vested upon a “change in control,” which generally occurs upon (i) the acquisition of 50% or more of the total fair market value or total voting power of our outstanding securities, (ii) the acquisition (other than by Riverstone or its affiliates until such time as Riverstone or its affiliates holds less than 20% of the total voting power of our outstanding securities) of 30% or more of the total voting power of our outstanding securities, (iii) the replacement of a majority of our Board during any 12-month period with directors whose appointment or election is not endorsed by a majority of the Board prior to the date of the appointment or election, and (iv) a sale of 40% or more of the total gross fair market value of our assets. As of December 31, 2017, there was no value assigned to such acceleration as no monetization event had occurred. 
+Upon the termination of Mr. Gusek’s employment by us in circumstances which do not involve “cause” or his voluntary resignation with “good reason,” a percentage of the unvested restricted stock equal to the greater of (i) the percentage already 
+68 
+Table of Contents 
+vested at such time in accordance with the time-based vesting requirements and (ii) 50% will be deemed vested. As of December 31, 2017, there was no value assigned to such acceleration as no monetization event had occurred. 
+For purposes of the restricted stock awards, “cause” generally means any of the following: (A) conviction of, or plea of nolo contendere to, a felony or serious crime involving fraud, dishonesty or breach of trust; (B) gross negligence or intentional misconduct in the performance of his duties to us or our subsidiaries; (C) breach of a material obligation under the restricted unit agreement or our Predecessor’s Limited Liability Company Agreement; (D) willful dishonesty, fraud or misrepresentation intended to result in his gain or personal enrichment at the expense of us, any of our subsidiaries or our other equity holders; (E) public or consistent drunkenness or illegal use of narcotics that is reasonably likely to become materially injurious to the reputation or business of us or our subsidiaries or that is reasonably likely to impair his performance of duties to us or our subsidiaries; or (F) any other intentional conduct that materially injures us, our subsidiaries, or our reputation, including, but not limited to, knowingly participating in or allowing accounting or tax improprieties, embezzlement or theft. Certain of the actions and omissions described above are subject to a notice and cure period. 
+In addition, “good reason” generally means any of the following: (x) material diminution in Mr. Gusek’s responsibilities, duties or authority; (y) material diminution in Mr. Gusek’s base salary; or (z) breach by us of one of our material obligations under the restricted stock award agreement. Certain of the actions described above are subject to a notice and cure period. 
+Director Compensation 
+We did not have any non-employee directors at any time during the fiscal year ended December 31, 2017. Following our IPO, we adopted a non-employee director compensation program that is applicable to each of our non-employee directors who are not also officers or employees of us or Riverstone. Pursuant to this program, each non-employee director who is not an affiliate of Riverstone will receive the following compensation for their service on our board of directors: 
+• 
+A cash retainer of $65,000 per year, payable quarterly in arrears; 
+• 
+An additional cash retainer of $20,000 per year, payable quarterly in arrears if such non-employee director serves as the chairperson of our audit committee; 
+• 
+An additional payment of $1,500 for each board meeting attended in-person by such non-employee director; and 
+• 
+Annual equity based compensation with an aggregate grant date value of $100,000, subject to the terms of the LTIP and the award agreement pursuant to which such award is granted. 
+In addition, in the year in which a new non-employee director is elected to our board of directors for the first time, such director will also receive a one-time award under the LTIP with a grant date value equal to $100,000, subject to the terms and conditions of the LTIP and the award agreement pursuant to which such award is granted. The types of equity awards that will be granted to non-employee directors and any vesting conditions applicable to such awards have not yet been determined. In addition, each director will be reimbursed for out-of-pocket expenses incurred in connection with attending board and committee meetings. 
+69 
+Table of Contents 
+Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+The following table sets forth information with respect to the beneficial ownership of our Class A Common Stock and Class B common stock as of March 16, 2018 by: 
+• 
+each person known to us to beneficially own more than 5% of any class of our outstanding voting securities; 
+• 
+each member of our board of directors and each nominee to our board of directors; 
+• 
+the selling shareholder; 
+• 
+each of our named executive officers named in the Summary Compensation Table under “Item 11. Executive Compensation”; and 
+• 
+all of our directors and executive officers as a group. 
+All information with respect to beneficial ownership has been furnished by the respective 5% or more shareholders, the selling shareholder, directors or executive officers, as the case may be. Unless otherwise noted, the mailing address of each listed beneficial owner is 950 17th Street, Suite 2400, Denver, Colorado 80202. 
+Shares of commons stock beneficially owned 
+Class A 
+Common Stock 
+Class B 
+Common Stock(1) 
+Combined Voting 
+Power(2) 
+Number 
+% 
+Number 
+% 
+Number 
+% 
+Selling Shareholder 
+R/C Energy IV Direct Partnership, L.P. (3) 
+15,259,481 
+21.8 
+% 
+— 
+15,259,481 
+12.9 
+% 
+Other 5% Shareholders 
+R/C IV Liberty Holdings, L.P.(4) 
+4,413,442 
+6.3 
+% 
+31,368,322 
+65.1 
+% 
+35,781,764 
+30.3 
+% 
+Entities associated with Oakmont Corporation (5) 
+1,924,827 
+2.8 
+% 
+13,680,615 
+28.4 
+% 
+15,605,442 
+13.2 
+% 
+Entities and persons associated with GMT Capital Corp. (6) 
+4,669,498 
+6.7 
+% 
+— 
+4,669,498 
+4.0 
+% 
+Concentric Equity Partners II, LP (7) 
+4,579,307 
+6.5 
+% 
+— 
+4,579,307 
+3.9 
+% 
+SH Ventures LOS, LLC (8) 
+5,215,783 
+7.5 
+% 
+— 
+5,215,783 
+4.4 
+% 
+C. Mark Pearson 
+653,252 
+0.9 
+% 
+3,158,435 
+6.6 
+% 
+3,811,687 
+3.2 
+% 
+Directors and Named Executive Officers: 
+Christopher A. Wright 
+3,543,451 
+5.1 
+% 
+— 
+3,543,451 
+3.0 
+% 
+Michael Stock 
+1,499,327 
+2.1 
+% 
+— 
+1,499,327 
+1.3 
+% 
+Ron Gusek 
+1,311,538 
+1.9 
+% 
+— 
+1,311,538 
+1.1 
+% 
+Cary D. Steinbeck 
+— 
+— 
+— 
+N. John Lancaster, Jr. 
+— 
+— 
+— 
+Brett Staffieri 
+— 
+— 
+— 
+William F. Kimble 
+— 
+— 
+— 
+Peter A. Dea 
+— 
+— 
+— 
+Ken Babcock 
+58,823 
+0.1 
+% 
+— 
+58,823 
+0.0 
+% 
+Jesal Shah 
+— 
+— 
+— 
+Directors and executive officers as a group (12 persons) 
+6,413,139 
+9.2 
+% 
+— 
+6,413,139 
+5.4 
+% 
+Other Executive Officers: 
+R. Sean Elliott 
+— 
+— 
+— 
+Ryan T. Gosney 
+— 
+— 
+— 
+(1) 
+Under the Liberty LLC Agreement, each Liberty Unit Holder has, subject to certain limitations, the right to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units for, at Liberty LLC’s election, (i) shares of our Class A Common Stock at a redemption ratio of one share of Class A Common Stock for each Liberty LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions or (ii) an equivalent amount of cash. In connection with any redemption of Liberty LLC Units pursuant to the Redemption Right or our Call Right, the corresponding number of shares of Class B Common Stock will be cancelled. See “Item 13. Certain Relationships and Related Person Transactions-Liberty LLC Agreement.” Beneficial ownership of Liberty LLC Units is not reflected as beneficial ownership of shares of our Class A Common Stock for which such units may be redeemed. 
+(2) 
+Represents percentage of voting power of our Class A Common Stock and Class B common stock voting together as a single class. 
+70 
+Table of Contents 
+(3) 
+R/C Energy IV Direct Partnership, L.P. is an investment partnership affiliated with Riverstone/Carlyle Global Energy and Power Fund IV, L.P., or R/C IV. Management and control of R/C Energy IV Direct Partnership, L.P. is with its general partner, Riverstone/Carlyle Energy Partners IV, L.P., which is in turn managed and controlled by its general partner, R/C Energy GP IV, LLC, an affiliate of R/C IV. R/C Energy GP IV, LLC is managed by a management committee consisting of Pierre F. Lapeyre, Jr., David M. Leuschen, James T. Hackett, N. John Lancaster, Daniel A. D’Aniello and Edward J. Mathias. As a result, each of R/C Energy GP IV, LLC and Riverstone/Carlyle Energy Partners IV, L.P. may be deemed to share beneficial ownership of the shares held of record by R/C Energy IV Direct Partnership, L.P. The business address for each of the entities and individuals other than Messrs. D’Aniello and Mathias is c/o Riverstone Holdings, 712 Fifth Avenue, 36th Floor, New York, NY 10019. The business address for each of Messrs. D’Aniello and Mathias is c/o The Carlyle Group, 1001 Pennsylvania Avenue, N.W., Suite 200, Washington, D.C. 20004. 
+(4) 
+R/C IV Liberty Holdings, L.P. is an investment partnership affiliated with R/C IV. Management and control of R/C IV Liberty Holdings, L.P. is with its general partner, Riverstone/Carlyle Energy Partners IV, L.P., which is in turn managed and controlled by its general partner, R/C Energy GP IV, LLC, an affiliate of R/C IV. R/C Energy GP IV, LLC is managed by a management committee consisting of Pierre F. Lapeyre, Jr., David M. Leuschen, James T. Hackett, N. John Lancaster, Daniel A. D’Aniello and Edward J. Mathias. As a result, each of R/C Energy GP IV, LLC and Riverstone/Carlyle Energy Partners IV, L.P. may be deemed to share beneficial ownership of the shares held of record by R/C IV Liberty Holdings, L.P. The business address for each of the entities and individuals other than Messrs. D’Aniello and Mathias is c/o Riverstone Holdings, 712 Fifth Avenue, 36th Floor, New York, NY 10019. The business address for each of Messrs. D’Aniello and Mathias is c/o The Carlyle Group, 1001 Pennsylvania Avenue, N.W., Suite 200, Washington, D.C. 20004. 
+(5) 
+All shares may be deemed to be beneficially owned by Oakmont Corporation and Robert Day, who may be deemed to control Oakmont Corporation. The reporting herein of such shares shall not be construed as an admission by Oakmont Corporation or Mr. Day that either such person is the beneficial owner of such interests for purposes of Section 16 of the Securities Exchange Act of 1934 or for any other purpose. The principal business address of the Oakmont Corporation and Mr. Day is 865 S. Figueroa St., Suite 700, Los Angeles, CA 90017. 
+(6) 
+Entities and persons associated with GMT Capital Corp. are BRP Liberty, LLC, Bay Resource Partners, L.P., Bay II Resource Partners, L.P., Thomas E. Claugus, and GMT Exploration Company LLC. GMT Capital Corp. manages each of these entities, and is in turn majority owned and controlled by Thomas E. Claugus. Therefore, GMT Capital Corp. and Mr. Claugus may be deemed to share voting and dispositive power over the shares held by such entities and may also be deemed to be the beneficial owner of such shares. GMT Capital Corp. and Mr. Claugus disclaim beneficial ownership of these shares in excess of their pecuniary interest therein. The principal business address of each of GMT Capital Corp. and Mr. Claugus is 2300 Windy Ridge Parkway, Suite 550 South, Atlanta, GA 30339. 
+(7) 
+The general partner of Concentric Equity Partners II, LP is CEP-FIC GP, LP. The principal business address of CEP-FIC GP, LP is 50 E. Washington St. Suite 400, Chicago, Illinois 60602. 
+(8) 
+The principal business address of SH Ventures LOS, LLC is 655 Brea Canyon Road, Walnut, California 91789. 
+Securities Authorized for Issuance Under Equity Compensation Plans 
+As of December 31, 2017, we did not maintain an equity compensation plan and none of our securities were available for issuance under an equity compensation plan. While we adopted the Legacy Plan and the LTIP in connection with our IPO, these plans were not outstanding as of December 31, 2017. Accordingly, no equity compensation plan information table is provided. 
+71 
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+Item 13. Certain Relationships and Related Transactions, and Director Independence 
+The following discussion is a brief summary of certain material arrangements, agreements and transactions we have with related parties. It does not include all of the provisions of our material arrangements, agreements and transactions with related parties, does not purport to be complete and is qualified in its entirety by reference to the arrangements, agreements and transactions described. 
+IPO-Related Agreements 
+In connection with our Corporate Reorganization, we engaged in transactions with affiliates, such as Liberty LLC, and our Legacy Owners and entered into the agreements detailed herein. See also “Item 1. Business—Initial Public Offering and Reorganization Transactions” for a description of these transactions. 
+Liberty LLC Agreement 
+We entered into the Liberty LLC Agreement in connection with the closing of the IPO, which provides for limitations on the ability of Liberty Unit Holders to transfer their Liberty LLC Units and provides Liberty Inc., as managing member of Liberty LLC, with the right to impose restrictions (in addition to those already in place) on the ability of Liberty Unit Holders to redeem their Liberty LLC Units pursuant to the Redemption Right to the extent Liberty Inc. believes it is necessary to ensure that Liberty LLC will continue to be treated as a partnership for U.S. federal income tax purposes. 
+Redemption Rights 
+Under the Liberty LLC Agreement, each Liberty Unit Holder has, subject to certain limitations, the right to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units for, at Liberty LLC’s election, (i) shares of our Class A Common Stock at a redemption ratio of one share of Class A Common Stock for each Liberty LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions or (ii) an equivalent amount of cash. Alternatively, upon the exercise of the Redemption Right, Liberty Inc. (instead of Liberty LLC) will have the right to, for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder for, at its election, (x) one share of Class A Common Stock or (y) an equivalent amount of cash. In addition, upon a change of control of Liberty Inc., Liberty Inc. has the right to require each holder of Liberty LLC Units (other than Liberty Inc.) to exercise its Redemption Right with respect to some or all of such unit holder’s Liberty LLC Units. In connection with any redemption of Liberty LLC Units pursuant to the Redemption Right or our Call Right, the corresponding number of shares of Class B Common Stock will be cancelled. As the Liberty Unit Holders redeem their Liberty LLC Units, our membership interest in Liberty LLC will be correspondingly increased, the number of shares of Class A Common Stock outstanding will be increased, and the number of shares of Class B Common Stock outstanding will be reduced. 
+Distributions and Allocations 
+Under the Liberty LLC Agreement, Liberty Inc. has the right to determine when distributions will be made to the holders of Liberty LLC Units and the amount of any such distributions. If Liberty Inc. authorizes a distribution, such distribution will be made to the holders of Liberty LLC Units generally on a pro rata basis in accordance with their respective percentage ownership of Liberty LLC Units. 
+Liberty LLC will allocate its net income or net loss for each year to the holders of Liberty LLC Units pursuant to the terms of the Liberty LLC Agreement, and the holders of Liberty LLC Units, including Liberty Inc., will generally incur U.S. federal, state and local income taxes on their share of any taxable income of Liberty LLC. Net income and losses of Liberty LLC generally will be allocated to the holders of Liberty LLC Units on a pro rata basis in accordance with their respective percentage ownership of Liberty LLC Units, subject to requirements under U.S. federal income tax law that certain items of income, gain, loss or deduction be allocated disproportionately in certain circumstances. To the extent Liberty LLC has available cash and subject to the terms of any future debt instruments, Liberty Inc. intends to cause Liberty LLC to make (i) generally pro rata distributions to the holders of Liberty LLC Units, including Liberty Inc., in an amount sufficient to allow Liberty Inc. to pay its taxes and to allow it to make payments under the Tax Receivable Agreements, (ii) tax advances, which will be repaid upon exercise of the Redemption Right or the Call Right, as applicable, in an amount sufficient to allow each of the Liberty Unit Holders to pay its respective taxes on such holder’s allocable share of Liberty LLC’s taxable income after taking into account certain other distributions or payments received by the Liberty Unit Holders from Liberty LLC or Liberty Inc., and (iii) non-pro rata payments to Liberty Inc. to reimburse it for its corporate and other overhead expenses. 
+Issuance of Equity 
+The Liberty LLC Agreement provides that, except as otherwise determined by us, at any time Liberty Inc. issues a share of its Class A Common Stock or any other equity security, the net proceeds received by Liberty Inc. with respect to such issuance, if any, shall be concurrently invested in Liberty LLC, and Liberty LLC shall issue to Liberty Inc. one Liberty LLC 
+72 
+Table of Contents 
+Unit or other economically equivalent equity interest. Conversely, if at any time, any shares of Liberty Inc.’s Class A Common Stock are redeemed, repurchased or otherwise acquired, Liberty LLC shall redeem, repurchase or otherwise acquire an equal number of Liberty LLC Units held by Liberty Inc., upon the same terms and for the same price, as the shares of our Class A Common Stock are redeemed, repurchased or otherwise acquired. 
+Competition 
+Under the Liberty LLC Agreement, the members have agreed that the Riverstone and its affiliates will be permitted to engage in business activities or invest in or acquire businesses which may compete with our business or do business with our customers. 
+Dissolution 
+Liberty LLC will be dissolved only upon the first to occur of (i) the sale of substantially all of its assets or (ii) an election by us to dissolve the company. Upon dissolution, Liberty LLC will be liquidated and the proceeds from any liquidation will be applied and distributed in the following manner: (a) first, to creditors (including to the extent permitted by law, creditors who are members) in satisfaction of the liabilities of Liberty LLC, (b) second, to establish cash reserves for contingent or unforeseen liabilities and (c) third, to the members in proportion to the number of Liberty LLC Units owned by each of them. 
+Tax Receivable Agreements 
+As described in “Item 1. Business—Initial Public Offering and Reorganization Transaction,” Liberty Inc. acquired Liberty LLC Units from certain of the Liberty Unit Holders in exchange for cash. In addition, the Liberty Unit Holders may redeem their Liberty LLC Units for shares of Class A Common Stock or cash, as applicable, in the future pursuant to the Redemption Right or the Call Right. Liberty LLC intends to make for itself (and for each of its direct or indirect subsidiaries that is treated as a partnership for U.S. federal income tax purposes and that it controls) an election under Section 754 of the Code that will be effective for this taxable year (year of the IPO) and each taxable year in which a redemption of Liberty LLC Units pursuant to the Redemption Right or the Call Right occurs. Pursuant to the Section 754 election, our acquisition (or deemed acquisition for U.S. federal income tax purposes) of Liberty LLC Units for cash as a part of the Corporate Reorganization and redemptions of Liberty LLC Units pursuant to the Redemption Right or the Call Right are expected to result in adjustments to the tax basis of the tangible and intangible assets of Liberty LLC. These adjustments will be allocated to Liberty Inc. Such adjustments to the tax basis of the tangible and intangible assets of Liberty LLC would not have been available to Liberty Inc. absent its acquisition or deemed acquisition of Liberty LLC Units as a part of the Corporate Reorganization or pursuant to the exercise of the Redemption Right or the Call Right. The anticipated basis adjustments are expected to increase (for U.S. federal income tax purposes) Liberty Inc.’s depreciation, depletion and amortization deductions and may also decrease Liberty Inc.’s gains (or increase its losses) on future dispositions of certain assets to the extent tax basis is allocated to those assets. Such increased deductions and losses and reduced gains may reduce the amount of tax that Liberty Inc. would otherwise be required to pay in the future. 
+In connection with the IPO, Liberty Inc. entered into two Tax Receivable Agreements with the TRA Holders. The first of the Tax Receivable Agreements, which Liberty Inc. entered into with the Liberty Unit Holders, generally provides for the payment by Liberty Inc. to such TRA Holders of 85% of the net cash savings, if any, in U.S. federal, state and local income and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that Liberty Inc. actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result of, as applicable to each such TRA Holder, (i) certain increases in tax basis that occur as a result of Liberty Inc.’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holder’s Liberty LLC Units in connection with the IPO or pursuant to the exercise of the Redemption Right or Liberty Inc.’s Call Right and (ii) imputed interest deemed to be paid by Liberty Inc. as a result of, and additional tax basis arising from, any payments Liberty Inc. makes under such Tax Receivable Agreement. The second of the Tax Receivable Agreements, which Liberty Inc. entered into with the selling shareholder, generally provides for the payment by Liberty Inc. to such TRA Holder of 85% of the net cash savings, if any, in U.S. federal, state and local income and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that Liberty Inc. actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result of, as applicable to such TRA Holder, (i) any net operating losses available to Liberty Inc. as a result of the Corporate Reorganization and (ii) imputed interest deemed to be paid by Liberty Inc. as a result of any payments Liberty Inc. makes under such Tax Receivable Agreement. For further discussion regarding the potential acceleration of payments under the Tax Receivable Agreements and its potential impact, please read “Risk Factors—Risks Related to Our Class A Common Stock.” 
+As described in “Item 1. Business—Initial Public Offering and Reorganization Transaction,” Liberty Inc. acquired Liberty LLC Units from certain of the Liberty Unit Holders in exchange for cash. In addition, the Liberty Unit Holders may redeem their Liberty LLC Units for shares of Class A Common Stock or cash, as applicable, in the future pursuant to the Redemption Right or our Call Right. 
+73 
+Table of Contents 
+The Tax Receivable Agreements are incorporated by reference to the Current Report on Form 8-K, filed on January 18, 2018. 
+Stockholders’ Agreement 
+We are party to a stockholders’ agreement with the Principal Stockholders. Among other things, the stockholders’ agreement provides the right to designate nominees to our board of directors as follows: 
+• 
+so long as Riverstone and its affiliates collectively own at least 35% of our Class A Common Stock, Riverstone can designate up to five nominees to our board of directors, with the board size decreasing by one director when Riverstone and its affiliates no longer own at least 35% of our Class A Common Stock; 
+• 
+so long as Riverstone and its affiliates collectively own at least 30% of our Class A Common Stock, Riverstone can designate up to four nominees to our board of directors; 
+• 
+so long as Riverstone and its affiliates collectively own at least 20% of our Class A Common Stock but less than 30% of our Class A Common Stock, Riverstone can designate up to two nominees to our board of directors; and 
+• 
+so long as Riverstone and its affiliates collectively own at least 10% of our Class A Common Stock but less than 20% of our Class A common stock, Riverstone can designate up to one nominee to our board of directors. 
+Pursuant to the stockholders’ agreement we and the Principal Stockholders will be required to take all necessary actions, to the fullest extent permitted by applicable law (including with respect to any fiduciary duties under Delaware law), to cause the election of the nominees designated by Riverstone. At any time the members of our board of directors are allocated among separate classes of directors, (i) the directors designated by Riverstone pursuant to the stockholders’ agreement will be in different classes of directors to the extent practicable and (ii) Riverstone will be permitted to designate the class or classes to which each such director will be allocated. Riverstone will be entitled to designate the replacement for any of its board designees whose board service terminates prior to the end of such director’s term. Riverstone has the right to nominate another member to our board of directors. 
+In addition, the stockholders’ agreement provides that for so long as the Principal Stockholders and their affiliates own at least 20% of the outstanding shares of our Class A Common Stock, Riverstone will have the right to cause any committee of our board of directors to include in its membership at least one director designated by Riverstone, except to the extent that such membership would violate applicable securities laws or stock exchange rules. The rights granted to Riverstone to designate directors are additive to and not intended to limit in any way the rights that Riverstone or any of its affiliates may have to nominate, elect or remove our directors under our certificate of incorporation, bylaws or the DGCL. 
+Furthermore, so long as Riverstone and its affiliates collectively own at least 20% of the outstanding shares of Class A Common Stock, we have agreed not to take, and will take all necessary action to cause our subsidiaries not to take, the following direct or indirect actions (or enter into an agreement to take such actions) without the prior consent of Riverstone: 
+• 
+any material change, through any acquisition, disposition of assets or otherwise, in the nature of our business or operations and our subsidiaries as of the date of the stockholders’ agreement; 
+• 
+hiring or terminating our chief executive officer or the chief financial officer and their respective successors; 
+• 
+any transaction that, if consummated, would constitute a Change of Control (as defined in the stockholders’ agreement) or entering into any definitive agreement or series of related agreements that govern any transaction or series of related transactions that, if consummated, would result in a Change of Control; 
+• 
+entering into any agreement providing for certain acquisitions or dispositions, in each such case, involving consideration payable or receivable by us or any of our subsidiaries in excess of $100 million in the aggregate in any single transaction or series of related transactions during any 12-month period; 
+• 
+any incurrence by us or any of our subsidiaries of indebtedness for borrowed money (including through capital leases, the issuance of debt securities or the guarantee of indebtedness of another Person) in excess of $100 million in the aggregate in any single transaction or series of related transactions during any 12-month period; 
+• 
+any issuance or series of related issuances of equity securities by us or any of our subsidiaries for an aggregate consideration in excess of $100 million; 
+• 
+any payment or declaration of any dividend or other distribution of any shares of Class A Common Stock or entering into any recapitalization transaction the primary purpose of which is to pay a dividend; 
+• 
+any increase or decrease in the size of our board of directors, committees of the board of directors, and board and committees of our subsidiaries; 
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+Table of Contents 
+• 
+settling any litigation to which we or any of our subsidiaries is a party involving the payment by us or any of our subsidiaries of an aggregate amount equal to or greater than $25 million; 
+• 
+entering into any joint venture or similar business alliance involving investment, contribution or disposition by us or any of our subsidiaries of assets (including stock of subsidiaries) having an aggregate fair market value in excess of $100 million, other than transactions solely between and among us and our wholly owned subsidiaries; and 
+• 
+any amendment, modification or waiver of our certificate of incorporation, bylaws or any other governing document following the date of the stockholders’ agreement that (i) causes the number of board of director seats to be less than or greater than nine (although the current size of the board of directors, as ratified by the Riverstone directors, is eight) or (ii) materially and adversely affects any Principal Stockholder. 
+Registration Rights Agreement 
+In connection with the closing of the IPO, we entered into a registration rights agreement with the Legacy Owners. The agreement contains provisions by which we agree to register under the federal securities laws the offer and resale of shares of our Class A Common Stock by the Legacy Owners or certain of their affiliates or permitted transferees under the registration rights agreement. These registration rights will be subject to certain conditions and limitations. We will generally be obligated to pay all registration expenses in connection with these registration obligations, regardless of whether a registration statement is filed or becomes effective. 
+Historical Transactions with Affiliates 
+Advisory Services Agreement 
+Liberty Holdings entered into an advisory agreement, dated December 30, 2011, with Riverstone, in which Riverstone agreed to provide certain administrative advisory services to us. The service fees incurred to Riverstone, and reflected in the financials of our accounting predecessor, for the years ended December 31, 2017 , 2016 and 2015 were approximately $1.5 million , $0.5 million and $0.4 million , respectively and accrued as of December 31, 2017 and 2016 were $2.0 million and $0.5 million , respectively. We do not expect to incur future expense under this agreement. 
+Transactions with Liberty Resources 
+In September 2011, Liberty Resources entered into a services agreement (the “Services Agreement”) with LOS whereby Liberty Resources is to provide certain administrative support functions to Liberty Services. Liberty Resources also entered into a master service agreement with Liberty Services whereby LOS provides hydraulic fracturing service to Liberty Resources at market service rates. The amount incurred under the Services Agreement by LOS during the years ended December 31, 2017 , 2016 and 2015 was approximately $0 , $0.1 million and $0.2 million , respectively, and there were no outstanding balances for the respective periods. The amounts related to the provision of hydraulic fracturing services to Liberty Resources under the master services agreement for the years ended December 31, 2017 , 2016 and 2015 were approximately $24.7 million , $13.1 million and $28.8 million , respectively. Amounts reflected in accounts receivable from Liberty Resources were $4.0 million and $0 and of December 31, 2017 and 2016 , respectively, and $0.1 million and $2.5 million in unbilled revenue as of December 31, 2017 and 2016 , respectively. 
+Services to Zavanna, LLC 
+LOS provided hydraulic fracturing services under a standard master services agreement at market rates to Zavanna, LLC, an E&P company that partially owned one of Liberty Holdings’ investors through October 2016. For the years ended December 31, 2016 and 2015 , LOS derived revenue of approximately $4.8 million and $42.3 million , respectively. Amounts due from Zavanna as of December 31, 2016 and 2015 were $4.8 million and $0.5 million , respectively, and as of and for the year ended December 31, 2017 , Zavanna is no longer an affiliate. 
+PropX 
+During 2016, Liberty Holdings committed to make an investment and become a non-controlling minority member in Proppant Express Investments, LLC, (“PropX Investments”) the owner of PropX, a provider of proppant logistics equipment. LOS is party to a services agreement (the “PropX Services Agreement”) whereby LOS is to provide certain administrative support functions to PropX, and LOS is to purchase and lease proppant logistics equipment from PropX at market rates. Receivables from PropX as of December 31, 2017 and 2016 were $0 and $0.2 million , respectively. For the year ended December 31, 2017 the Company purchased and leased proppant logistics equipment of $13.5 million and $2.2 million . Payables to PropX as of December 31, 2017 and 2016 were $0.7 million and $0 , respectively. 
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+Table of Contents 
+Bridge Loan 
+During the second quarter of 2017, ACQI entered into the Bridge Loan with the Bridge Loan Lenders. The Bridge Loan was to mature on October 10, 2017, unless earlier terminated in connection with an initial public offering, and provided for interest at 12% per annum. In June 2017, in connection with our entry into an amendment to our Prior Credit Facility, the Bridge Loan and accrued interest payable of $60.8 million were assigned from the Bridge Loan Lenders to Liberty Holdings and ACQI’s obligation under the Bridge Loan was canceled in exchange for 60,761,000 Redeemable Class 2 Common Units issued to Liberty Holdings. The Redeemable Class 2 Common Units were redeemed by ACQI on September 19, 2017 for, including accrued return, $62.7 million . 
+Conflicts of Interest 
+The related party transactions described above may cause certain conflicts of interests, including that: 
+• 
+we may enter into contracts between us, on the one hand, and related parties, on the other, that are not as a result of arm’s-length transactions; 
+• 
+our executive officers and directors that hold positions of responsibility with related parties may be aware of certain business opportunities that are appropriate for presentation to us as well as to such other related parties and may present such business opportunities to such other parties; and 
+• 
+our executive officers and directors that hold positions of responsibility with related parties may have significant duties with, and spend significant time serving, other entities and may have conflicts of interest in allocating time. 
+For example, Christopher Wright, our Chief Executive Officer, is the Executive Chairman of Liberty Resources LLC, a position which may require a significant portion of his time and which may cause conflicts of interest in pursuing business opportunities of which he becomes aware. Furthermore, our governing documents provide that Riverstone and its respective affiliates (including portfolio investments of its affiliates) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. Riverstone or its respective affiliates may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Furthermore, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to not be available to us or causing them to be more expensive for us to pursue. In addition, Riverstone or its respective affiliates may dispose of oil and gas service or other assets in the future, without any obligation to offer us the opportunity to purchase any of those assets. Please see “Item 1A. Risk Factors—Risks Related to Our Business—We engage in transactions with related parties and such transactions present possible conflicts of interest that could have an adverse effect on us,” “Item 1A. Risk Factors—Risks Related to Our Class A Common Stock—Certain of our executive officers and directors have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities” and “Item 1A. Risk Factors—Risks Related to Our Class A Common Stock—Riverstone and its respective affiliates are not limited in their ability to compete with us, and the corporate opportunity provisions in our amended and restated certificate of incorporation could enable Riverstone to benefit from corporate opportunities that might otherwise be available to us.” 
+Policies and Procedures for Review of Related Party Transactions 
+A “Related Party Transaction” is a transaction, arrangement or relationship in which we or any of our subsidiaries was, is or will be a participant, the amount of which involved exceeds $120,000, and in which any related person had, has or will have a direct or indirect material interest. A “Related Person” means: 
+• 
+any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors; 
+• 
+any person who is known by us to be the beneficial owner of more than 5.0% of our Class A Common Stock; 
+• 
+any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, executive officer or a beneficial owner of more than 5.0% of our Class A Common Stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5.0% of our Class A common stock; and 
+• 
+any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10.0% or greater beneficial ownership interest. 
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+Table of Contents 
+Our board of directors adopted a written related party transactions policy in connection with the IPO. Pursuant to this policy, our audit committee will review all material facts of all Related Party Transactions and either approve or disapprove entry into the Related Party Transaction, subject to certain limited exceptions. In determining whether to approve or disapprove entry into a Related Party Transaction, our audit committee shall take into account, among other factors, the following: (i) whether the Related Party Transaction is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances and (ii) the extent of the Related Person’s interest in the transaction. Furthermore, the policy requires that all Related Party Transactions required to be disclosed in our filings with the SEC be so disclosed in accordance with applicable laws, rules and regulations. 
+77 
+Table of Contents 
+Item 14. Principal Accountant Fees and Services 
+Audit Fees 
+The following table summarizes fees paid or accrued to our independent registered public accounting firm, Deloitte & Touche LLP, for the fiscal years ended December 31, 2017 and 2016 . 
+2017 
+2016 
+Audit fees (1) 
+$ 
+1,124,792 
+$ 
+805,713 
+Audit-related fees (2) 
+1,381,930 
+706,026 
+Tax fees (3) 
+601,245 
+— 
+All other fees (4) 
+— 
+— 
+Total 
+$ 
+3,107,967 
+$ 
+1,511,739 
+(1) 
+Consists of fees for professional services rendered for the audits of our consolidated financial statements for fiscal years 2017 and 2016 included in our Annual Report on Form 10-K and Registration Statement on Form S-1. 
+(2) 
+Consists of fees billed for assurance and related services, primarily related to the IPO. 
+(3) 
+Consists of fees for professional services rend by our principal accountant for tax compliance, tax advice, and tax planning. 
+(4) 
+Consists of fees for products and services provided by our principal accountant, other than the services reported under “audit fees,” “audit-related fees,” and “tax fees.” 
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+Table of Contents 
+PART IV 
+Item 15. Exhibits and Financial Statement Schedules 
+(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules 
+Liberty Oilfield Services Inc. 
+Report of Independent Registered Public Accounting Firm 
+Balance Sheets as of December 31, 2017 and 2016 
+Notes to Balance Sheets 
+Liberty Oilfield Services LLC Predecessor 
+Reports of Independent Registered Public Accounting Firms 
+Combined Balance Sheets as of December 31, 2017 and 2016 
+Combined Statements of Operations for the Years Ended December 31, 2017, 2016 and 2015 
+Combined Statements of Changes in Member Equity for the Years Ended December 31, 2017, 2016 and 2015 
+Combined Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015 
+Notes to Combined Financial Statements 
+(a)(3) Exhibits 
+The Exhibits listed in the Exhibit Index are filed, furnished or incorporated by reference as part of this Annual Report on Form 10-K, and such Exhibit Index is incorporated herein by reference. 
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+Table of Contents 
+Item 16. Form 10-K Summary 
+None. 
+INDEX TO EXHIBITS 
+Exhibit 
+Number 
+Description 
+1.1 
+Underwriting Agreement, dated as of January 11, 2018, by and among Liberty Oilfield Services Inc., Liberty Oilfield Services New HoldCo LLC, R/C Energy IV Direct Partnership, L.P., Morgan Stanley & Co. LLC, Goldman Sachs & Co. LLC and Wells Fargo Securities, LLC, as representatives of the several underwriters named therein (2) 
+2.1 
+Master Reorganization Agreement, dated as of January 11, 2018, by and among Liberty Oilfield Services Inc., Liberty Oilfield Services Holdings LLC, Liberty Oilfield Services New HoldCo LLC, and the other parties named therein (2) 
+3.1 
+Amended and Restated Certificate of Incorporation of Liberty Oilfield Services Inc. (2) 
+3.2 
+Amended and Restated Bylaws of Liberty Oilfield Services Inc. (3) 
+4.1 
+Stockholder Agreement, dated as of January 17, 2018, by and among Liberty Oilfield Services Inc., R/C IV Liberty Oilfield Services Holdings, L.P., R/C Energy IV Direct Partnership, L.P., and other parties names therein (2) 
+10.1 
+Second Amended and Restated Limited Liability Company Operating Agreement of Liberty Oilfield Services New HoldCo LLC (2) 
+10.2 
+Tax Receivable Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Inc., R/C Energy IV Direct Partnership, L.P., and R/C Energy IV Direct Partnership, L.P., as agent (2) 
+10.3 
+Tax Receivable Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Inc., and the other parties names therein (2) 
+10.4 
+Registration Rights Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Inc. and the other parties named therein (2) 
+10.5 
+Liberty Oilfield Services Inc. Long Term Incentive Plan (2)† 
+10.6 
+Liberty Oilfield Services Inc. Legacy Restricted Stock Plan (2)† 
+10.7 
+Form of Restricted Stock Grant Notice and Restricted Stock Agreement under the Legacy Restricted Stock Plan (1)† 
+10.8 
+Credit Agreement, dated September 19, 2017, by and among Wells Fargo Bank, National Association, as Administrative Agent, Wells Fargo Bank, National Association, JPMorgan Chase Bank, N.A. and Citibank, N.A., as Joint Lead Arrangers, Wells Fargo Bank, National Association, as Book Runner, JPMorgan Chase Bank, N.A. and Citibank, N.A., as Syndication Agents, the lender parties thereto, Liberty Oilfield Services Holdings LLC, as Parent and Liberty Oilfield Services LLC and LOS Acquisition Co I LLC, each as a Borrower (1) 
+10.9 
+Amendment and Parent Joinder to Credit Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Holdings LLC, Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto * 
+10.10 
+Second Amendment and Parent Joinder to Credit Agreement, dated March 21, 2018, by and among Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto * 
+10.11 
+Credit Agreement, dated September 19, 2017, by and among Liberty Oilfield Services LLC and LOS Acquisition CO I LLC, each as a Borrower, Liberty Oilfield Services Holdings LLC, as Parent Guarantor and U.S. Bank National Association as Agent (1) 
+10.12 
+Amendment and Joinder to Credit Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Holdings LLC, Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, U.S. Bank National Association, as Administrative Agent, and the lenders signatory thereto * 
+80 
+Table of Contents 
+10.13 
+Second Amendment and Joinder to Credit Agreement, dated March 21, 2018, by and among Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, U.S. Bank National Association, as Administrative Agent, and the lenders signatory thereto * 
+10.14 
+Indemnification Agreement (Christopher A. Wright) (2)† 
+10.15 
+Indemnification Agreement (Michael Stock) (2)† 
+10.16 
+Indemnification Agreement (Ron Gusek) (2)† 
+10.17 
+Indemnification Agreement (Brett Staffieri) (2)† 
+10.18 
+Indemnification Agreement (N. John Lancaster Jr.) (2)† 
+10.19 
+Indemnification Agreement (Cary D. Steinbeck) (2)† 
+10.20 
+Indemnification Agreement (Peter A. Dea) (2)† 
+10.21 
+Indemnification Agreement (William F. Kimble) (2)† 
+10.22 
+Indemnification Agreement (Ken Babcock) (2)† 
+10.23 
+Indemnification Agreement (Jesal Shah) (2)† 
+10.24 
+Indemnification Agreement (R. Sean Elliot) (2)† 
+10.25 
+Indemnification Agreement (Ryan T. Gosney) (2)† 
+21.1 
+List of subsidiaries of Liberty Oilfield Services Inc. * 
+23.1 
+Consent of Deloitte & Touche LLP * 
+23.2 
+Consent of Deloitte & Touche LLP * 
+23.3 
+Consent of EKS&H LLLP * 
+31.1 
+Certification of Chief Executive Officer pursuant to Exchange Act Rule 13a-14(a) * 
+31.2 
+Certification of Chief Financial Officer pursuant to Exchange Act Rule 13a-14(a) * 
+32.1 
+Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 ** 
+32.2 
+Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 ** 
+(1) 
+Incorporated by reference to the exhibits to the registrant’s Registration Statement on Form S-1, as amended (SEC File 333-216050). 
+(2) 
+Incorporated by reference to the registrant’s Current Report on Form 8-K, filed on January 18, 2018. 
+(3) 
+Incorporated by reference to the registrant’s Amendment No. 1 to the Current Report on Form 8-K/A, filed on January 22, 2018. 
+* 
+Filed herewith. 
+** 
+Furnished herewith. 
+† 
+Denotes a management contract or compensatory plan or arrangement. 
+81 
+Table of Contents 
+SIGNATURES 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+LIBERTY OILFIELD SERVICES INC. 
+/s/ Christopher A. Wright 
+Date: 
+March 23, 2018 
+By: 
+Christopher A. Wright 
+Chief Executive Officer 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+Signature 
+Title 
+Date 
+/s/ Christopher A. Wright 
+Chief Executive Officer and Director 
+(Principal Executive Officer) 
+March 23, 2018 
+Christopher A. Wright 
+/s/ Michael Stock 
+Chief Financial Officer 
+(Principal Financial Officer) 
+March 23, 2018 
+Michael Stock 
+/s/ Ryan T. Gosney 
+Chief Accounting Officer 
+March 23, 2018 
+Ryan T. Gosney 
+(Principal Accounting Officer) 
+/s/ Cary D. Steinbeck 
+Director 
+March 23, 2018 
+Cary D. Steinbeck 
+/s/ N. John Lancaster, Jr. 
+Director 
+March 23, 2018 
+N. John Lancaster, Jr. 
+/s/ Brett Staffieri 
+Director 
+March 23, 2018 
+Brett Staffieri 
+/s/ William F. Kimble 
+Director 
+March 23, 2018 
+William F. Kimble 
+/s/ Peter A. Dea 
+Director 
+March 23, 2018 
+Peter A. Dea 
+/s/ Ken Babcock 
+Director 
+March 23, 2018 
+Ken Babcock 
+/s/ Jesal Shah 
+Director 
+March 23, 2018 
+Jesal Shah 
+82 
+Table of Contents 
+Index to Financial Statements 
+Liberty Oilfield Services Inc. 
+Report of Independent Registered Public Accounting Firm 
+F- 1 
+Balance Sheets as of December 31, 2017 and 2016 
+F- 2 
+Notes to Balance Sheets 
+F- 3 
+Liberty Oilfield Services LLC, Predecessor 
+Reports of Independent Registered Public Accounting Firms 
+F- 5 
+Combined Balance Sheets as of December 31, 2017 and 2016 
+F- 7 
+Combined Statements of Operations for the Years Ended December 31, 2017, 2016 and 2015 
+F- 8 
+Combined Statements of Changes in Member Equity for the Years Ended December 31, 2017, 2016 and 2015 
+F- 9 
+Combined Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015 
+F- 10 
+Notes to Combined Financial Statements 
+F- 11 
+Table of Contents 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the shareholders and the Board of Directors of Liberty Oilfield Services Inc. 
+Opinion on the Financial Statements 
+We have audited the accompanying balance sheets of Liberty Oilfield Services Inc. (the “Company”) as of December 31, 2017 and 2016, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, in conformity with accounting principles generally accepted in the United States of America. 
+Basis for Opinion 
+These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. 
+Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. 
+/s/ DELOITTE & TOUCHE LLP 
+Denver, Colorado 
+March 23, 2018 
+We have served as the Company’s auditor since 2016. 
+F- 1 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Balance Sheets 
+As of December 31, 2017 and 2016 
+2017 
+2016 
+Assets 
+Total assets 
+$ 
+— 
+$ 
+— 
+Liabilities and Stockholder’s Equity 
+Commitments and contingencies 
+Common stock, par value $0.01 per share, 1,000 shares authorized, issued and outstanding 
+$ 
+10 
+$ 
+10 
+Contribution receivable from parent 
+(10 
+) 
+(10 
+) 
+Total liabilities and stockholder’s equity 
+$ 
+— 
+$ 
+— 
+See accompanying Notes to Balance Sheets. 
+F- 2 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Balance Sheets 
+As of December 31, 2017 and 2016 
+Note 1-Organization and Operations 
+Liberty Oilfield Services Inc. (the “Company”) is a Delaware corporation, incorporated on December 21, 2016. Following an initial public offering (“IPO”) and related reorganization transactions, the Company is a holding corporation for Liberty Oilfield Services New HoldCo LLC (“Liberty LLC”) and its subsidiaries. The Company has no prior operating activities. 
+On January 17, 2018, the Company completed its IPO of 14,640,755 shares of its Class A common stock, par value $0.01 per share (the “Class A Common Stock”) at a public offering price of $17.00 per share, of which 14,340,214 shares were offered by the Company and 300,541 shares were offered by the selling shareholder. The Company received approximately $220.4 million in net proceeds after deducting approximately $23.4 million of underwriting discounts and commissions and other offering costs. The Company did not receive any proceeds from the sale of the shares of Class A Common Stock by the selling shareholder. Immediately prior to the IPO, Liberty Oilfield Services Holdings LLC contributed all of its assets to Liberty LLC, including the sole ownership of Liberty Oilfield Services LLC and LOS Acquisition Co I LLC (collectively, the “Predecessor”). The Company used $25.9 million of net proceeds to redeem ownership interests in Liberty LLC from then-existing owners of Liberty LLC (the “Legacy Owners”) and contributed the remaining net proceeds to Liberty LLC in exchange for units in Liberty LLC (the “Liberty LLC Units”). Liberty LLC used a portion of the net proceeds from the IPO (i) to repay outstanding borrowings and accrued interest under the Predecessor’s ABL Credit Facility (as defined herein), totaling approximately $30.1 million , (ii) to repay 35% of the Predecessor’s outstanding borrowings, accrued interest and prepayment premium under the Term Loan Facility (as defined herein), totaling approximately $62.5 million and (iii) for general corporate purposes, including repayment of additional indebtedness and funding a portion of 2018 and other future capital expenditures. The Company issued 1,258,514 unvested shares of restricted stock under the Liberty Oilfield Services Inc. Legacy Restricted Stock Plan. The shares vest over the same remaining vesting period associated with each unvested Legacy Unit (defined herein), ranging up to three years. As a result of the IPO, there are 69,975,174 shares of Class A Common Stock and 48,207,372 shares of Class B Common Stock issued and outstanding as of March 16, 2018, and the Company owns a 59.2% interest in Liberty LLC. 
+Note 2-Summary of Significant Accounting Policies 
+Basis of Presentation 
+The Company’s balance sheets as of December 31, 2017 and 2016 have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Separate statements of operations, cash flows, and changes in stockholder’s equity and comprehensive income have not been presented because this entity has no operations to date. 
+Underwriting Commissions and Offering Costs 
+Underwriting commissions and offering costs incurred in connection with the Company’s common share offerings will be reflected as a reduction of additional paid-in capital. Underwriting commissions and offering costs are not recorded in the Company’s balance sheets because such costs are not the Company’s liability until the Company completes an IPO. 
+Organizational Costs 
+Organizational costs are not recorded in the Company’s balance sheets because such costs are not the Company’s liability until the Company completes an IPO. Thereafter, costs incurred to organize the Company are expensed as incurred. 
+Note 3-Stockholder’s Equity 
+The Company is authorized to issue 1,000 shares of common stock with a par value $0.01 per share. Under the Company’s certificate of incorporation in effect as of December 21, 2016, all shares of common stock are identical. 
+Note 4-Commitments and Contingencies 
+As of the date of these balance sheets, the Company has no outstanding commitments and contingencies. 
+F- 3 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Balance Sheets 
+As of December 31, 2017 and 2016 
+Note 5-Subsequent Events 
+On January 17, 2018, the Company entered into amendments and joinders to both its ABL Facility and Term Loan Facility credit agreements (as discussed herein), whereby the Company became a parent guarantor to the debt agreements of the Predecessor. 
+The Company has evaluated subsequent events through the date of this report. There were no significant subsequent events requiring disclosure or recognition other than those disclosed in these notes to the balance sheets. 
+F- 4 
+Table of Contents 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the Board of Directors of Liberty Oilfield Services Inc. 
+Opinion on the Financial Statements 
+We have audited the accompanying combined balance sheets of Liberty Oilfield Services LLC, Predecessor (the "Company") as of December 31, 2017 and 2016, the related combined statements of operations, changes in member’s equity, and cash flows for each of the two years in the period ended December 31, 2017, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America. 
+Basis for Opinion 
+These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. 
+Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. 
+/s/ DELOITTE & TOUCHE LLP 
+Denver, Colorado 
+March 23, 2018 
+We have served as the Company's auditor since 2016. 
+F- 5 
+Table of Contents 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the Board of Directors and 
+the Member of Liberty Oilfield Services LLC 
+We have audited the accompanying balance sheet of Liberty Oilfield Services LLC (the “Company”) as of December 31, 2015, and the related statements of operations, changes in member’s equity, and cash flows for the year then ended. The Company’s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audit. 
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. 
+In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Liberty Oilfield Services LLC as of December 31, 2015, and the results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America. 
+/s/ EKS&H LLLP 
+January 9, 2017 
+Denver, Colorado 
+F- 6 
+Table of Contents 
+LIBERTY OILFIELD SERVICES LLC, PREDECESSOR 
+Combined Balance Sheets 
+As of December 31, 2017 and 2016 
+(Dollars in thousands) 
+2017 
+2016 
+Assets 
+Current assets: 
+Cash and cash equivalents 
+$ 
+16,321 
+$ 
+11,484 
+Accounts receivable—trade, net of allowance for uncollectible accounts of $0 and $497, respectively 
+195,961 
+94,749 
+Accounts receivable—related party 
+3,984 
+5,017 
+Unbilled revenue 
+58,784 
+26,307 
+Unbilled revenue—related party 
+59 
+2,487 
+Inventories 
+55,524 
+28,144 
+Prepaids and other current assets 
+21,396 
+5,903 
+Total current assets 
+352,029 
+174,091 
+Property and equipment, net 
+494,776 
+277,355 
+Other assets 
+5,298 
+399 
+Total assets 
+$ 
+852,103 
+$ 
+451,845 
+Liabilities and Member Equity 
+Current liabilities: 
+Accounts payable 
+$ 
+66,846 
+$ 
+42,862 
+Accrued liabilities: 
+Accrued vendor invoices 
+78,646 
+50,796 
+Operational accruals 
+32,208 
+17,392 
+Accrued salaries and benefits 
+24,990 
+3,893 
+Deferred revenue 
+9,231 
+— 
+Accrued interest and other 
+6,573 
+3,550 
+Accrued liabilities—related party 
+2,000 
+456 
+Current portion of capital lease obligations 
+— 
+119 
+Current portion of long-term debt, net of discount of $1,739 and $273, respectively 
+11 
+12,727 
+Total current liabilities 
+220,505 
+131,795 
+Long-term debt, net of discount of $6,466 and $922, respectively, less current portion 
+196,346 
+91,078 
+Total liabilities 
+416,851 
+222,873 
+Commitments & contingencies (Note 14) 
+Redeemable common units 
+42,486 
+— 
+Member equity 
+392,766 
+228,972 
+Total liabilities and member equity 
+$ 
+852,103 
+$ 
+451,845 
+See Notes to Combined Financial Statements. 
+F- 7 
+Table of Contents 
+LIBERTY OILFIELD SERVICES LLC, PREDECESSOR 
+Combined Statements of Operations 
+For the Years Ended December 31, 2017 , 2016 and 2015 
+(Dollars in thousands) 
+2017 
+2016 
+2015 
+Revenue: 
+Revenue 
+$ 
+1,465,133 
+$ 
+356,890 
+$ 
+384,330 
+Revenue—related parties 
+24,722 
+17,883 
+71,074 
+Total revenue 
+1,489,855 
+374,773 
+455,404 
+Operating costs and expenses: 
+Cost of services (exclusive of depreciation and amortization shown separately below) 
+1,147,008 
+354,729 
+393,340 
+General and administrative 
+80,089 
+35,789 
+28,765 
+Depreciation and amortization 
+81,473 
+41,362 
+36,436 
+Loss (gain) on disposal of assets 
+148 
+(2,673 
+) 
+423 
+Total operating costs and expenses 
+1,308,718 
+429,207 
+458,964 
+Operating income (loss) 
+181,137 
+(54,434 
+) 
+(3,560 
+) 
+Other expense: 
+Interest expense 
+(11,875 
+) 
+(6,126 
+) 
+(5,501 
+) 
+Interest expense—related party 
+(761 
+) 
+— 
+— 
+Total interest expense 
+(12,636 
+) 
+(6,126 
+) 
+(5,501 
+) 
+Net income (loss) 
+$ 
+168,501 
+$ 
+(60,560 
+) 
+$ 
+(9,061 
+) 
+See Notes to Combined Financial Statements. 
+F- 8 
+Table of Contents 
+LIBERTY OILFIELD SERVICES LLC, PREDECESSOR 
+Combined Statements of Changes in Member Equity 
+For the Years Ended December 31, 2017 , 2016 and 2015 
+(Dollars in thousands) 
+Member Equity 
+Balance—January 1, 2015 
+143,112 
+Net loss 
+(9,061 
+) 
+Balance—December 31, 2015 
+$ 
+134,051 
+Member contributions 
+155,481 
+Net loss 
+(60,560 
+) 
+Balance—December 31, 2016 
+228,972 
+Return on redeemable common units 
+(4,707 
+) 
+Net income 
+168,501 
+Balance—December 31, 2017 
+$ 
+392,766 
+See Notes to Combined Financial Statements. 
+F- 9 
+Table of Contents 
+LIBERTY OILFIELD SERVICES LLC, PREDECESSOR 
+Combined Statements of Cash Flows 
+For the Years Ended December 31, 2017 , 2016 and 2015 
+(Dollars in thousands) 
+2017 
+2016 
+2015 
+Cash flows from operating activities: 
+Net income (loss) 
+$ 
+168,501 
+$ 
+(60,560 
+) 
+$ 
+(9,061 
+) 
+Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: 
+Depreciation and amortization 
+81,473 
+41,362 
+36,436 
+Loss (gain) on disposal of assets 
+148 
+(2,673 
+) 
+423 
+Bad debt provision 
+6,424 
+Amortization of debt issuance costs 
+2,311 
+630 
+514 
+Inventory reserve 
+259 
+— 
+5,508 
+Changes in operating assets and liabilities: 
+Accounts receivable 
+(101,212 
+) 
+(14,716 
+) 
+(16,848 
+) 
+Accounts receivable—related party 
+1,032 
+(1,762 
+) 
+22,734 
+Unbilled revenue 
+(32,477 
+) 
+(26,307 
+) 
+5,714 
+Unbilled revenue—related party 
+2,428 
+(180 
+) 
+(2,307 
+) 
+Inventories 
+(27,639 
+) 
+(11,687 
+) 
+3,729 
+Prepaids and other current assets 
+(12,611 
+) 
+(3,388 
+) 
+(109 
+) 
+Accounts payable and accrued liabilities 
+111,352 
+38,563 
+(47,028 
+) 
+Accounts payable and accrued liabilities—related party 
+1,544 
+10 
+(10 
+) 
+Net cash provided by (used in) operating activities 
+195,109 
+(40,708 
+) 
+6,119 
+Cash flows from investing activities: 
+Capital expenditures 
+(311,794 
+) 
+(102,428 
+) 
+(38,492 
+) 
+Proceeds from disposal of assets 
+1,751 
+6,077 
+— 
+Net cash used in investing activities 
+(310,043 
+) 
+(96,351 
+) 
+(38,492 
+) 
+Cash flows from financing activities: 
+Proceeds from borrowings on term loan, net of discount 
+171,500 
+— 
+40,000 
+Repayments of borrowings on term loan 
+(57,438 
+) 
+(49,000 
+) 
+(12,000 
+) 
+Proceeds from borrowings on line-of-credit 
+140,559 
+84,700 
+40,000 
+Repayments of borrowings on line-of-credit 
+(158,559 
+) 
+(36,700 
+) 
+(40,000 
+) 
+Proceeds from related party bridge loans 
+60,000 
+— 
+— 
+Payments on capital lease obligations 
+(119 
+) 
+(5,525 
+) 
+(6,465 
+) 
+Payments of debt issuance costs 
+(9,036 
+) 
+(413 
+) 
+(50 
+) 
+Proceeds from issuance of redeemable common units 
+39,794 
+— 
+— 
+Payments for redemption of redeemable common units 
+(62,739 
+) 
+— 
+— 
+Member contributions 
+— 
+155,481 
+— 
+Payment of deferred equity offering costs 
+(4,191 
+) 
+— 
+— 
+Net cash provided by financing activities 
+119,771 
+148,543 
+21,485 
+Net increase in cash and cash equivalents 
+4,837 
+11,484 
+(10,888 
+) 
+Cash and cash equivalents—beginning of period 
+11,484 
+— 
+10,888 
+Cash and cash equivalents—end of period 
+$ 
+16,321 
+$ 
+11,484 
+$ 
+— 
+Supplemental disclosure of cash flow information: 
+Cash paid for interest 
+$ 
+9,766 
+$ 
+4,725 
+$ 
+5,026 
+Non-cash investing and financing activities: 
+Capital expenditures included in accounts payable and accrued liabilities 
+$ 
+18,687 
+$ 
+29,688 
+$ 
+2,000 
+Related party bridge loans exchanged for Redeemable Class 2 Common Units 
+$ 
+60,679 
+$ 
+— 
+$ 
+— 
+See Notes to Combined Financial Statements. 
+F- 10 
+Table of Contents 
+Note 1—Organization and Basis of Presentation 
+Liberty Oilfield Services LLC, Predecessor (the “Company” or “Predecessor”) includes the combined assets, liabilities, member equity, and results of operations of Liberty Oilfield Services LLC (“LOS”) and LOS Acquisition Co I LLC and its subsidiaries (“ACQI”), which includes Titan Frac Services LLC (“Titan”), LOS Odessa RE Investments, LLC (“Odessa”) and LOS Cibolo RE Investments, LLC (“Cibolo”). The Company is a multi-basin provider of hydraulic fracturing services, with a focus on deploying the latest technologies in the technically demanding oil and gas reservoirs in which it operates, principally in North Dakota, Colorado, Wyoming and Texas. As of December 31, 2017 LOS and ACQI were both wholly-owned subsidiaries of Liberty Oilfield Services Holdings LLC (the “Parent” or “Liberty Holdings”). 
+Liberty Oilfield Services Inc. (“Liberty Inc.”) was incorporated as a Delaware corporation on December 21, 2016, to become a holding corporation for Liberty Oilfield Services New HoldCo LLC (“Liberty LLC”) and its subsidiaries upon completion of a corporate reorganization in conjunction with a planned initial public offering (“IPO”). On January 17, 2018, Liberty Inc. completed its initial IPO of 14,640,755 shares of its Class A common stock, par value $0.01 per share (the "Class A Common Stock") at a public offering price of $17.00 per share, of which 14,340,214 shares were offered by Liberty Inc. and 300,541 were offered by the selling shareholder. Immediately prior to the completion of the IPO, Liberty Holdings contributed all of its assets to Liberty LLC in exchange for equity interests in Liberty LLC and then liquidated, distributing to Liberty Holdings’ then-existing owners ’ equity interests in Liberty LLC that were equivalent to the interests in Liberty Holdings held by each such member. Liberty Inc. used $25,851 of net proceeds to redeem ownership interests in Liberty LLC from then-existing owners of Liberty LLC (the “Legacy Owners”). Liberty Inc. contributed the remaining net proceeds to Liberty LLC in exchange for units in Liberty LLC (the “Liberty LLC Units”). Liberty LLC used a portion of these net proceeds (i) to repay outstanding borrowings and accrued interest under the Predecessor’s ABL Credit Facility (as defined herein), totaling approximately $30,088 , (ii) to repay 35% of the Predecessor’s outstanding borrowings, accrued interest and prepayment premium under the Term Loan Facility (as defined herein), totaling approximately $62,524 and (iii) for general corporate purposes, including repayment of additional indebtedness and funding a portion of 2018 and other future capital expenditures. Following the IPO the Company is wholly owned by Liberty LLC. 
+The accompanying combined financial statements and related notes present the combined financial position, results of operations, cash flows, and member equity of the Predecessor. All intercompany amounts have been eliminated in the presentation of these combined financial statements. Comprehensive income is not reported due to the absence of items of other comprehensive income or loss during the periods presented. The combined financial statements include financial data at historical cost as the contribution of assets is considered to be a reorganization of entities under common control. The combined financial statements may not be indicative of the actual level of assets, liabilities and costs that would have been incurred by the Predecessor if it had operated as an independent, publicly-traded company during the periods prior to the IPO or of the costs expected to be incurred in the future. In the opinion of management, the adjustments necessary for a fair presentation of the combined financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been made. 
+The Company’s operations are organized into a single reportable segment, which consists of hydraulic fracturing services. 
+Note 2-Significant Accounting Policies 
+Use of Estimates 
+The preparation of combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 
+The combined financial statements include some amounts that are based on management’s best estimates and judgments. The most significant estimates relate to the collectability of accounts receivable and estimates of allowance for doubtful accounts, the useful lives and salvage values of long-lived assets, future cash flows associated with long-lived assets, net realizable value of inventory, and equity unit valuation. These estimates may be adjusted as more current information becomes available. 
+Cash and Cash Equivalents 
+The Company considers all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. The Company continually monitors its positions with, and the credit quality of, the financial institutions with 
+F- 11 
+Table of Contents 
+which it has banking relationships. As of the balance sheet date, and periodically throughout the year, the Company has maintained balances in various operating accounts in excess of federally insured limits. 
+Accounts Receivable 
+The Company analyzes the need for an allowance for doubtful accounts for estimated losses related to potentially uncollectible accounts receivable on a case-by-case basis throughout the year. In establishing the required allowance, management considers historical losses adjusted to take into account current market conditions and the customers’ financial condition, the amount of receivables, the current receivables aging and current payment patterns. The Company reserves amounts based on specific identification. Account balances are charged to the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. It is reasonably possible that the Company’s estimate of the allowance for doubtful accounts will change and that losses ultimately incurred could differ materially from the amounts estimated in determining the allowance. 
+Inventories 
+Inventories consist of raw materials used in the hydraulic fracturing process, such as proppants, chemicals, and field service equipment maintenance parts and are stated at the lower of cost, determined using the weighted average cost method, or net realizable value. Inventories are charged to cost of services as used when providing hydraulic fracturing services. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable cost of completion, disposal, and transportation. 
+Property and Equipment 
+Property and equipment are stated at cost. Depreciation and amortization expense is recognized on property and equipment, excluding land, utilizing the straight-line method over the estimated useful lives, ranging from two to 30 years. The Company estimates salvage values that it does not depreciate. 
+Construction in-progress, a component of property and equipment, represents long-lived assets being developed by the Company. These assets are not subject to depreciation until they are completed and ready for their intended use, at which point the Company reclassifies them to field services equipment or vehicles, as appropriate. 
+The Company assesses its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is assessed using undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets. The Company determined the lowest level of identifiable cash flows to be at the asset group, which is the aggregate of the Company’s hydraulic fracturing fleets that are in service. A long-lived asset is not recoverable if its carrying amount exceeds the sum of estimated undiscounted cash flows expected to result from the use and eventual disposition. When alternative courses of action to recover the carrying amount of the asset group are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the asset is not recoverable, an impairment loss is recognized in an amount by which its carrying amount exceeds its estimated fair value, such that its carrying amount is adjusted to its estimated fair value, with an offsetting charge to impairment expense. 
+The Company measures the fair value of its property and equipment using the discounted cash flow method. The expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments of projected revenue growth, fleet count, utilization, gross margin rates, selling, general and administrative rates, working capital fluctuations, capital expenditures, discount rates and terminal growth rates. 
+During 2017 and 2016 , the Company did not test its long-lived assets for recoverability as there were no triggering events. During 2015 , the significant decline in commodity prices along with other factors was deemed a triggering event, and the Company tested its long-lived assets for recoverability as of December 31, 2015 . No impairment was recognized during the years ended December 31, 2017 , 2016 and 2015 . 
+Major Maintenance Activities 
+The Company incurs maintenance costs on its major equipment. The determination of whether an expenditure should be capitalized or expensed requires management judgment in the application of how the costs incurred benefit future periods, relative to the Company’s capitalization policy. Costs that either establish or increase the efficiency, productivity, functionality or life of a fixed asset are capitalized and depreciated over the remaining useful life of the asset. 
+F- 12 
+Table of Contents 
+Deferred Financing Costs 
+Costs associated with obtaining debt financing are deferred and amortized to interest expense using the effective interest method. In accordance with ASU No. 2015-03 and 2015-15, for all periods the Company has reflected deferred financing costs related to term loan debt as a direct deduction from the carrying amount, and costs associated with line-of-credit arrangements as other assets. 
+Income Taxes 
+For U.S. federal income tax purposes, the Company is treated as a partnership. As such, any liability for federal income taxes is the responsibility of the members of the Company. No provision for U.S. federal income taxes has been provided in the combined financial statements of the Company. 
+The Company is responsible for certain state income and Texas franchise taxes. These amounts are de minimis and are reflected as general and administrative expense in the combined financial statements of the Company. 
+Deferred income taxes are computed using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the combined financial statements. 
+The Company recognizes the financial statement effects of a tax position when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. Previously recognized tax positions are reversed in the first period in which it is no longer more-likely-than-not that the tax position would be sustained upon examination. Income tax related interest and penalties, if applicable, are recorded as a component of the provision for income tax expense. However, there were no material amounts recognized relating to interest and penalties in the combined statements of operations for the years ended December 31, 2017 , 2016 and 2015 . The Company had no uncertain income tax positions as of December 31, 2017 and 2016 . 
+Revenue Recognition 
+Revenue from hydraulic fracturing services is earned and recognized as services are rendered, which is generally on a per stage basis. Revenue is recognized when persuasive evidence of an arrangement exists, the service is complete, the amount is fixed and determinable and collectability is reasonably assured. The Company’s services are sold based upon contracts or other agreements with the customer that include fixed or determinable prices and do not include other post‑delivery obligations. Rates for services are typically determined per the contract or agreement with customers. Revenue recognized in excess of amounts billed is included in the accompanying combined balance sheets as unbilled revenue. 
+Deferred Revenue 
+From time to time, the Company may require partial payment in advance from new customers to secure credit or from existing customers in order to secure additional hydraulic fracturing services. Initially, such payments are recorded in the accompanying combined financial statements as deferred revenue, and upon performance of the agreed services, the Company recognizes revenue consistent with its revenue recognition policy described above. As of December 31, 2017, the Company had $9,231 recorded as deferred revenue related to the unearned portion of a prepayment from an existing customer to secure additional services from a new fleet by the end of 2017. The new fleet commenced services in December 2017, and the Company applies the prepayment in accordance with the customer agreement as services are performed. 
+Fleet Start-up Costs 
+The Company incurs start-up costs to commission a new fleet or district. These costs include hiring and training of personnel, and acquisition of consumable parts and tools. Start-up costs are expensed as incurred, and are reflected in general and administrative expense in the combined statement of operations. Start-up costs for the years ended December 31, 2017 , 2016 and 2015 , were $13,955 , $4,280 and $1,044 , respectively. Start-up costs incurred during the years ended December 31, 2017 , 2016 and 2015 related to the establishment of nine, two and one new fleets, respectively. The terms and conditions of the Credit Facilities between the Company and its lenders provides for the add-back of costs or expenses incurred in connection with the acquisition, deployment and opening of any new hydraulic fracturing fleet or district in the computation of certain financial covenants. (See Note 6). 
+F- 13 
+Table of Contents 
+Recently Adopted Accounting Standards 
+In May 2014 the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers. This ASU supersedes the revenue recognition requirements in FASB ASC Topic 605, “Revenue Recognition,” and most industry-specific guidance. This ASU sets forth a five-step model for determining when and how revenue is recognized. Under the model, an entity will be required to recognize revenue to depict the transfer of goods or services to a customer at an amount reflecting the consideration it expects to receive in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers,” which deferred the effective date of ASU 2014-09 for all entities by one year and is effective for fiscal years and interim periods within fiscal years beginning after December 15, 2017. Entities may choose to adopt the standard using either a full retrospective approach or a modified retrospective approach. The Company does not expect the impact of adopting ASU 2014-09 to be material to total net revenues and operating income (loss) or to the combined balance sheet because performance obligations, which determine when and how revenue is recognized, are not materially changed under the new standard; thus, revenue associated with the majority of the Company’s contracts will continue to be recognized as services are provided to the customer. The Company adopted this standard on January 1, 2018 using the modified retrospective method. The Company finalized its documentation and assessment of the impact of the standard on its financial results and related disclosures, and concluded the adoption of this new accounting standard will not have a material impact on the combined financial statements. 
+In January 2016, the FASB issued ASU 2016-01, “Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities,” which requires equity investments (except those accounted for under the equity method of accounting, or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income, requires public business entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes, requires separate presentation of financial assets and financial liabilities by measurement category and form of financial asset, and eliminates the requirement for public business entities to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost. The ASU is effective for annual periods beginning after December 15, 2017. The adoption of ASU 2016-01 did not have a material impact on the consolidated financial statements of the Company. 
+In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,” which is effective for fiscal years and interim periods within fiscal years beginning after December 15, 2017, with a full retrospective approach to be used upon implementation and early adoption allowed. ASU 2016-15 provides guidance on eight different issues, intended to reduce diversity in practice on how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The adoption of ASU 2016-15 did not have a material impact on the consolidated financial statements of the Company. 
+In October 2016, the FASB issued ASU 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory,” which requires entities to recognize the tax consequences of intercompany asset transfers in the period in which the transfer takes place, with the exception of inventory transfers. The ASU is effective for fiscal years and interim periods within fiscal years beginning after December 15, 2017. Entities must adopt the standard using a modified retrospective approach with a cumulative effect adjustment to accumulated earnings as of the beginning of the period of adoption. The cumulative effect adjustments may include recognition of the income tax consequences of intra-entity transfers of assets other than inventory that occur before the adoption date. Early adoption is permitted but only at the beginning of an annual period for which no financial statements (interim or annual) have already been issued or made available for issuance. The adoption of ASU 2016-16 did not have a material impact on the consolidated financial statements of the Company. 
+Recently Issued Accounting Standards 
+In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842),” which sets out the principles for the recognition, measurement, presentation and disclosure of leases for both lessees and lessors. The new standard requires lessees to apply a dual approach, classifying leases as either finance or operating leases based on the principle of whether or not the lease is effectively a purchase financed by the lessee. This classification will determine whether lease expense is recognized based on an effective interest method or on a straight-line basis over the term of the lease, respectively. A lessee is also required to record a right-of-use asset and a lease liability for all leases with a term of greater than 12 months regardless of their classification. Leases with a term of 12 months or less may be accounted for similarly to existing guidance for operating leases today. The new standard requires lessors to account for leases using an approach that is substantially equivalent to existing guidance for sales-type leases, direct financing leases and operating leases. The ASU is expected to impact the Company’s combined 
+F- 14 
+Table of Contents 
+financial statements as the Company has certain operating and real property lease arrangements for which it is the lessee. The standard is effective on January 1, 2019, with early adoption permitted. The Company is currently evaluating the impact the adoption of this standard will have on its combined financial statements. 
+In June 2016, the FASB issued ASU 2016-13, “Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,” which is effective for fiscal years and interim periods within fiscal years beginning after December 15, 2019, with a modified-retrospective approach to be used for implementation. ASU 2016-13 changes the impairment model for most financial assets and certain other instruments. Specifically, this new guidance requires using a forward looking, expected loss model for trade and other receivables, held-to-maturity debt securities, loans and other instruments. This will replace the currently used model and may result in an earlier recognition of allowance for losses. The Company is currently evaluating the impact the adoption of this standard will have on its combined financial statements. 
+In October 2016, the FASB issued ASU 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory,” which requires entities to recognize the tax consequences of intercompany asset transfers in the period in which the transfer takes place, with the exception of inventory transfers. The ASU is effective for fiscal years and interim periods within fiscal years beginning after December 15, 2017. Entities must adopt the standard using a modified retrospective approach with a cumulative effect adjustment to accumulated earnings as of the beginning of the period of adoption. The cumulative effect adjustments may include recognition of the income tax consequences of intra-entity transfers of assets other than inventory that occur before the adoption date. Early adoption is permitted but only at the beginning of an annual period for which no financial statements (interim or annual) have already been issued or made available for issuance. The Company is currently evaluating the impact the adoption of this standard will have on its combined financial statements. 
+Note 3-Inventories 
+Inventories consist of the following: 
+December 31, 
+2017 
+2016 
+Proppants 
+$ 
+30,523 
+$ 
+11,654 
+Chemicals 
+10,660 
+6,365 
+Maintenance parts 
+14,341 
+10,125 
+$ 
+55,524 
+$ 
+28,144 
+Note 4-Asset Acquisitions 
+Titan Frac Services LLC 
+On February 22, 2017, the Company acquired all the membership interests of Titan Frac Services LLC (“Titan”), a wholly-owned subsidiary of TPIH Group Inc., for $65,000 in cash, subject to normal closing adjustments. The net assets of Titan include certain long-lived field service assets related to hydraulic fracturing. The Company accounted for the acquisition as an asset acquisition under the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 805, “Business Combinations”. The majority of the assets were ready for their intended use, subject to modifications necessary to achieve equipment requirements specific to the Company, and were reflected in construction in-progress until placed into service. 
+LOS Odessa RE Investments, LLC and LOS Cibolo RE Investments, LLC 
+During May 2017, the Company formed LOS Odessa RE Investments, LLC and LOS Cibolo RE Investments, LLC to facilitate the May 30, 2017 acquisition of certain real estate comprised of land and warehouse facilities located in Odessa and Cibolo, Texas from an unrelated third-party seller for $18,500 in cash, subject to normal closing adjustments. The Company accounted for the asset acquisition under the FASB ASC Topic 805, “Business Combinations”. The assets are ready for their intended use and, of the purchase price, $11,000 and $7,500 were allocated to Odessa and Cibolo facilities, respectively, and $4,045 and $14,455 were allocated to land and buildings and facilities, respectively. 
+F- 15 
+Table of Contents 
+Note 5-Property and Equipment 
+Property and equipment consist of the following: 
+Estimated 
+useful lives 
+(in years) 
+December 31, 
+2017 
+2016 
+Land 
+N/A 
+$ 
+4,495 
+$ 
+450 
+Field services equipment 
+2-7 
+572,096 
+269,346 
+Vehicles 
+4-7 
+60,815 
+47,492 
+Buildings and facilities 
+5-30 
+24,260 
+8,010 
+Office equipment, furniture, and software 
+2-7 
+5,879 
+4,639 
+667,545 
+329,937 
+Less accumulated depreciation and amortization 
+(198,453 
+) 
+(117,779 
+) 
+469,092 
+212,158 
+Construction in-progress 
+N/A 
+25,684 
+65,197 
+$ 
+494,776 
+$ 
+277,355 
+Note 6-Debt 
+The following is a summary of debt: 
+December 31, 
+2017 
+2016 
+Term Loan Outstanding 
+$ 
+174,562 
+$ 
+57,000 
+Revolving Line of Credit 
+30,000 
+48,000 
+Deferred financing costs and original issue discount 
+(8,205 
+) 
+(1,195 
+) 
+Total debt, net of deferred financing costs and original issue discount 
+$ 
+196,357 
+$ 
+103,805 
+Current portion of long-term debt, net of discount 
+$ 
+11 
+$ 
+12,727 
+Long-term debt, net of discount and current portion 
+196,346 
+91,078 
+$ 
+196,357 
+$ 
+103,805 
+On September 19, 2017, the Company entered into two new credit agreements for a revolving line of credit up to $250,000 (the “ABL Facility”) and a $175,000 term loan (the “Term Loan Facility”, and together with the ABL Facility the “New Credit Facilities”). The initial proceeds from the New Credit Facilities were used to repay outstanding principal and terminate the prior credit facility (the “Prior Credit Facility”), pay debt issuance costs, and redeem all of the Redeemable Class 2 Common Units (see Note 8). In connection with the termination of the Prior Credit Facility, the Company wrote off $1,209 of deferred financing costs. Following is a description of the Prior Credit Facility, the ABL Facility and the Term Loan Facility. 
+Prior Credit Facility 
+At December 31, 2015, LOS had a $180,000 senior secured facility that provided for a $60,000 revolving line-of-credit (“Prior Revolver”), an $80,000 term loan (“Term Loan Tranche A”), and a $40,000 term loan (“Term Loan Tranche B”). In February 2016, the Prior Credit Facility was amended which reduced the total commitments from $180,000 to $140,000 by eliminating the Term Loan Tranche B. LOS repaid the entire $37,000 then outstanding under the Term Loan Tranche B with $17,500 of proceeds from an equity contribution and $19,500 from advances under the Prior Revolver. 
+The Company entered into Amendment No. 8 and Joinder Agreement (the “Amendment”) to the Prior Credit Facility, as amended, on June 14, 2017. The Amendment increased the revolver commitments by $50,000 to $110,000 , and added ACQI as a borrower. 
+ABL Facility 
+Under the terms of the ABL Facility, up to $250,000 may be borrowed, subject to certain borrowing base limitations based on a percentage of eligible accounts receivable and inventory. As of December 31, 2017 , the borrowing base was calculated to be $158,363 , and the Company had $30,000 drawn, and an outstanding letter of credit for $161 , with $128,202 of 
+F- 16 
+Table of Contents 
+remaining availability. Borrowings under the ABL Facility bear interest at LIBOR or a base rate, plus an applicable LIBOR margin of 1.5% to 2.0% or base rate margin of 0.5% to 1.0% , as defined in the ABL Facility credit agreement. The weighted average interest rate on borrowings was 3.5% as of December 31, 2017 . The unused commitment is subject to an unused commitment fee of 0.375% - 0.50% . Interest and fees are payable in arrears at the end of each month, or, in the case of LIBOR loans, at the end of each interest period. The ABL Facility matures on the earlier of September 19, 2022, or 90 days prior to the final maturity of the Term Loan Facility. Borrowings under the ABL Facility are collateralized by accounts receivable and inventory, and further secured by Liberty Holdings, as parent guarantor. 
+Term Loan Facility 
+The Term Loan Facility provides for a $175,000 term loan, of which $174,562 remained outstanding as of December 31, 2017 . Amounts outstanding bear interest at LIBOR or a base rate, plus an applicable margin of 7.625% or 6.625% , respectively, and the weighted average rate on borrowings was 9.2% as of December 31, 2017 . The Company is required to make quarterly principal payments of 1% per annum of the outstanding principal balance, commencing on December 31, 2017 , with final payment due at maturity on September 19, 2022. The Term Loan Facility is collateralized by the fixed assets of LOS and ACQI and its subsidiaries, and is further secured by Liberty Holdings, as parent guarantor. 
+The New Credit Facilities include certain non-financial covenants, including but not limited to restrictions on incurring additional debt and certain distributions. Moreover, the ability of the Company to incur additional debt and to make distributions is dependent on maintaining a maximum leverage ratio. The Term Loan Facility requires mandatory prepayments upon certain dispositions of property or issuance of other indebtedness, as defined, and annually a percentage of excess cash flow ( 25% to 50% , depending on leverage ratio, of consolidated net income less capital expenditures and other permitted payments, commencing with the year ending December 31, 2018). Certain mandatory prepayments and optional prepayments are subject to a prepayment premium of 3% of the prepaid principal declining annually to 1% during the first three years of the term of the Term Loan Facility. 
+The New Credit Facilities are not subject to financial covenants unless liquidity, as defined, drops below a specified level. Under the ABL Facility, the Company is required to maintain a minimum fixed charge coverage ratio, as defined, of 1.0 to 1.0 for each period if excess availability is less than 10% of the borrowing base or $12,500 , whichever is greater. Under the Term Loan Facility, the Company is required to maintain a minimum fixed charge coverage ratio, as defined, of 1.2 to 1.0 for each trailing twelve-month report if the Company’s liquidity, as defined, is less than $25,000 for at least five consecutive business days. 
+The Company was in compliance with these covenants as of December 31, 2017 . 
+Maturities of debt are as follows: 
+Years Ending December 31, 
+2018 
+$ 
+1,750 
+2019 
+1,750 
+2020 
+1,750 
+2021 
+1,750 
+2022 
+197,562 
+$ 
+204,562 
+ACQI Bridge Loan 
+During the second quarter of 2017, ACQI received $40,000 of bridge loan financing (the “Initial Bridge Loan”) from, and entered into a pledge and security agreement to provide all assets of ACQI as collateral for the Initial Bridge Loan, with two members of the Parent and two affiliates of another member of the Parent (the “Bridge Loan Lenders”). In May 2017, the Bridge Loan Lenders provided an additional $20,000 of bridge loan financing (the “Additional Bridge Loan”, and together with the Initial Bridge Loan the “Bridge Loans”) to ACQI. The Bridge Loans were due October 10, 2017, unless earlier terminated in connection with an initial public offering, and provided for interest at 12% per annum. 
+In June 2017, in connection with the amendment to the Prior Credit Facility, the Bridge Loan and accrued interest payable of $60,761 were assigned from the Bridge Loan Lenders to Liberty Holdings and ACQI’s obligation under the Bridge Loan was canceled in exchange for 60,761 Redeemable Class 2 Common Units issued to Liberty Holdings (see Note 8). In connection 
+F- 17 
+Table of Contents 
+with the entry into the ABL Facility and Term Loan Facility, these Redeemable Class 2 Common Units were redeemed by ACQI on September 19, 2017 for, including accrued return, $62,739 . 
+Note 7-Capital Leases 
+The Company has acquired assets under the provisions of long-term leases. For financial reporting purposes, minimum lease payments relating to the assets have been capitalized. The leases matured during the first quarter of 2017 and were paid in full. Amortization of capitalized leased property is included in depreciation and amortization expense and approximated $0 , $2,808 and $3,509 for the years ended December 31, 2017 , 2016 , and 2015 respectively. 
+The assets under capital lease have cost and accumulated amortization as follows: 
+December 31, 
+2017 
+2016 
+Field services equipment 
+$ 
+— 
+$ 
+5,190 
+Less accumulated depreciation 
+— 
+(2,524 
+) 
+$ 
+— 
+$ 
+2,666 
+During the years ended December 31, 2017 , 2016 and 2015 , the Company reflected interest expense of $0 , $176 and $711 , respectively, from capital leases in the combined statements of operations. 
+Note 8-Redeemable Common Units 
+During February 2017, ACQI received $39,794 in cash from the Parent in exchange for 40,000 Redeemable Common Units of ACQI which accrue a return of 8% per annum. On June 12, 2017, Bridge Loans and accrued interest payable of $60,761 were returned from Holdings to ACQI in exchange for the issuance by ACQI to Holdings of 60,761 Redeemable Class 2 Common Units of ACQI which accrue a return of 12% per annum. The Bridge Loans previously issued by ACQI were cancelled upon their contribution by Holdings to ACQI in exchange for the issuance of the Redeemable Class 2 Common Units (see Note 6). 
+The Redeemable Common Units may be redeemed at the option of the holder on the later of (A) the earlier of the Offering or March 23, 2020 and (B) the second business day after all principal and interest outstanding under the ABL Facility have been paid in full and commitments thereunder are terminated. In accordance with ASC 505, “Equity ” , due to their conditional redemption feature, the Redeemable Common Units are classified as temporary equity in the accompanying combined balance sheet as of December 31, 2017 . The temporary equity classification will continue until the Redeemable Common Units are redeemed or until the redemption period expires. 
+The Redeemable Class 2 Common Units were redeemed in connection with the payoff of the Prior Credit Facility (see Note 6). Subsequent to year end, the Redeemable Common Units were deemed extinguished and satisfied in full in connection with the merger and dissolution of ACQI (see Note 16). 
+Note 9-Fair Value Measurements and Financial Instruments 
+The fair values of the Company’s assets and liabilities represent the amounts that would be received to sell those assets or that would be paid to transfer those liabilities in an orderly transaction at the reporting date. These fair value measurements maximize the use of observable inputs. However, in situations where there is little, if any, market activity for the asset or liability at the measurement date, the fair value measurement reflects the Company’s own judgments about the assumptions that market participants would use in pricing the asset or liability. The Company discloses the fair values of its assets and liabilities according to the quality of valuation inputs under the following hierarchy: 
+• 
+Level 1 Inputs: Quoted prices (unadjusted) in an active market for identical assets or liabilities. 
+• 
+Level 2 Inputs: Inputs other than quoted prices that are directly or indirectly observable. 
+• 
+Level 3 Inputs: Unobservable inputs that are significant to the fair value of assets or liabilities. 
+F- 18 
+Table of Contents 
+The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those that are initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from unobservable inputs is inconsequential to the overall fair value, or if corroborated market data becomes available. Assets and liabilities that are initially reported as Level 2 are subsequently reported as Level 3 if corroborated market data is no longer available. Transfers occur at the end of the reporting period. There were no transfers into or out of Levels 1, 2 and 3 during the years ended December 31, 2017 and 2016. 
+The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities, long-term debt, and capital lease obligations. These financial instruments do not require disclosure by level. The carrying values of all the Company’s financial instruments included in the accompanying balance sheets approximated or equaled their fair values at December 31, 2017 and 2016 . 
+• 
+The carrying values of cash and cash equivalents, accounts receivable and accounts payable (including accrued liabilities) approximated fair value at December 31, 2017 and 2016 , due to their short-term nature. 
+• 
+The carrying value of amounts outstanding under long-term debt agreements with variable rates approximated fair value at December 31, 2017 and 2016 , as the effective interest rates approximated market rates. 
+Nonfinancial assets 
+The Company estimates fair value to perform impairment tests as required on long-lived assets. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3 in the event that such assets were required to be measured and recorded at fair value within the combined financial statements. There were no such measurements required as of December 31, 2017 and 2016 . 
+Credit Risk 
+The Company’s financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents, and trade receivables. 
+The Company’s cash balances on deposit with financial institutions total $16,321 and $11,484 as of December 31, 2017 and 2016 , respectively, which, as of certain dates, exceeded FDIC insured limits. The Company regularly monitors these institutions’ financial condition. 
+The majority of the Company’s customers have payment terms of 60 days or less. As of December 31, 2017 and 2016 , one customer and two customers accounted for 22% and 51% of total accounts receivable and unbilled revenue, respectively. The Company mitigates the associated credit risk by performing credit evaluations and monitoring the payment patterns of its customers. During the years December 31, 2017 , 2016 and 2015 , two , three and five customers accounted for 36% , 45% and 57% of total revenue, respectively. 
+As of December 31, 2017 and 2016 , the Company had an allowance for doubtful accounts of $0 and $497 . The balance at December 31, 2016 represented one specific entity engaged in the business of oil and gas exploration and production that had filed for bankruptcy primarily as a result of the significant decline in the oil and gas industry. Such balance was written off during the year ended December 31, 2017 as no funds were able to be recovered through the bankruptcy proceedings. 
+2017 
+2016 
+Allowance for doubtful accounts, beginning of year 
+$ 
+497 
+$ 
+6,921 
+Bad debt expense: 
+Provision for doubtful accounts 
+— 
+— 
+Write off of uncollectible accounts against reserve 
+(497 
+) 
+(6,424 
+) 
+Allowance for doubtful accounts, end of year 
+$ 
+— 
+$ 
+497 
+Note 10-Member Equity 
+As described in Note 1, the Company is wholly-owned by the Parent, member equity includes cash capital contributions from the Parent. The Company received cash contributions of $0 , $155,481 and $0 during the years ended December 31, 2017 , 2016 and 2015 . 
+F- 19 
+Table of Contents 
+Note 11-Unit-Based Compensation (benchmark values are not in thousands) 
+Class B units of Parent (“Legacy Unit”) were granted to certain eligible employees of the Company. The Parent’s Class B units are non-voting, except with respect to such matters that units are entitled to vote as a matter of law. In such cases, each Class B unit shall entitle the holder to 1/1000th of one vote. Class B units granted to eligible participants may have an assigned benchmark value and vest according to the terms of each award letter. Upon termination for any reason, the Parent has the right, but not the obligation, to repurchase from the recipient those vested Class B units at fair value. 
+The Company recognizes compensation expense for equity-based Class B units issued to employees based on the grant-date fair value of the awards and each award’s requisite service period. During the years ended December 31, 2017 and 2016, no compensation expense was recognized, as the Company, with the assistance from a third-party valuation expert, determined that the Class B units issued to employees were deemed to have a de minimis grant-date fair value based on their assigned benchmark values. A summary of Class B unit activity is as follows (not in thousands): 
+Outstanding, January 1, 2016 
+686,500 
+Granted 
+98,350 
+Forfeited 
+(50,000 
+) 
+Outstanding, December 31, 2016 
+734,850 
+Granted 
+— 
+Forfeited 
+(5,375 
+) 
+Outstanding, December 31, 2017 
+729,475 
+The units issued and outstanding to employees of LOS as of December 31, 2017 and 2016 are 729,475 and 734,850 , respectively, at a weighted average benchmark value of $9.08 and $9.04 , respectively. The units vested to employees of LOS as of December 31, 2017 and 2016 are 651,481 and 595,625 , respectively, at a weighted average benchmark value of $4.44 and $1.97 , respectively. 
+Note 12-Defined Contribution Plan 
+The Company sponsors a 401(k) defined contribution retirement plan covering eligible employees. The Company makes matching contributions, which were temporarily suspended in May 2015, but were resumed in April 2017 at a rate of $1.00 for each $1.00 of employee contribution, subject to a cap of 3% of the employee’s salary. In October 2017, the cap on these contributions was increased to 6% of the employee’s base salary. Contributions made by the Company were $5,130 , $0 and $955 for the years ended December 31, 2017 , 2016 and 2015 . 
+Note 13-Related Party Transactions 
+In September 2011, Liberty Resources LLC, an oil and gas exploration and production company, and its successor entity (collectively, the “Affiliate”) and LOS, companies with common ownership and management, entered into a services agreement (the “Services Agreement”) whereby the Affiliate is to provide certain administrative support functions to LOS and a master service agreement whereby LOS provides hydraulic fracturing services to the Affiliate at market service rates. The amounts incurred under the Services Agreement by LOS during the years ended December 31, 2017 , 2016 and 2015 , were $0 , $93 and $160 , respectively, and there was no outstanding balance for the respective periods. The amounts of the Company’s revenue related to hydraulic fracturing services provided to the Affiliate for the years ended December 31, 2017 , 2016 and 2015 , were $24,722 , $13,060 and $28,786 , respectively. As of December 31, 2017 and 2016 , $3,984 and $0 , respectively, of the Company’s accounts receivable, and $59 and $2,487 , respectively, of the Company’s unbilled revenue was with the Affiliate. 
+The Company has an advisory agreement dated December 30, 2011 in which Riverstone is to provide certain administrative advisory services. The service fees incurred during the years ended December 31, 2017 , 2016 and 2015 were $1,545 , $456 and $446 , respectively, and accrued as of December 31, 2017 and 2016 were $2,000 and $456 , respectively. 
+During the second quarter of 2017 , bridge loan financing in the aggregate amount of $60,000 was outstanding from members and affiliates of the parent. The Bridge Loans were returned on June 12, 2017, inclusive of accrued interest, in exchange for Redeemable Class 2 Common Units of ACQI. The Redeemable Class 2 Common Units were redeemed on September 19, 2017, as discussed in Note 6 - Debt, ACQI 2017 Bridge Notes . 
+F- 20 
+Table of Contents 
+The Company provided hydraulic fracturing services under a standard master services agreement at market rates to an oil and gas exploration and production company (“Zavanna LLC”) which was an equity holder of an entity that, through October 2016, was a member of the Parent. For the year ended December 31, 2016 and 2015 the Company derived revenue of $4,823 and $42,288 . As of December 31, 2016 , $4,801 of the Company’s accounts receivable-related party, were from Zavanna LLC. 
+During 2016 , the Parent entered into a future commitment to invest and become a non-controlling minority member in Proppant Express Investments, LLC (“PropX Investments”), the owner of Proppant Express Solutions, LLC (“PropX”), a provider of proppant logistics equipment. LOS is party to a services agreement (the “PropX Services Agreement”) whereby LOS is to provide certain administrative support functions to PropX, and LOS is to purchase and lease proppant logistics equipment from PropX. For the years ended December 31, 2017 and 2016 the Company purchased proppant logistics equipment of $13,536 and $2,218 and leased proppant logistics equipment for $496 . Receivables from PropX as of December 31, 2017 and 2016 were $0 and $216 , which is reflected in accounts receivable-related party. Payables to PropX as of December 31, 2017 and 2016 were $684 and $0 , respectively. 
+Note 14-Commitments & Contingencies 
+Operating Leases 
+The Company leases office space, facilities, equipment, and vehicles under non-cancelable operating leases. Rent expense for the years ended December 31, 2017 and 2016 , was $20,839 and $10,703 , respectively. 
+Future minimum lease payments are as follows: 
+Years Ending December 31, 
+2018 
+$ 
+25,724 
+2019 
+18,840 
+2020 
+23,556 
+2021 
+6,553 
+2022 
+3,306 
+Thereafter 
+22,834 
+100,813 
+Purchase Commitments (tons, per ton, gallons, per gallon and per rail car prices are not in thousands) 
+To secure supply and pricing of proppant, the Company entered into three separate purchase and supply agreements during 2014, which were amended during 2015 and 2016 . During 2017 , the Company amended one of the three agreements, and entered into eight more purchase and supply agreements. Certain of the 2017 agreements provide for price adjustments depending on the price of crude oil or rig counts. 
+As of December 31, 2017 and 2016 , the agreements commit the Company to purchase 10,108,000 and 2,368,000 tons of proppant through December 31, 2021 and December 31, 2020, respectively, during the remaining terms of the agreements at per ton prices varying from approximately $30 to $102 , respectively, depending on the final delivery location and type of proppant. Terms and conditions of one of the agreements commit the Company to pay for a minimum of 100 railcars per month to transport the proppant at $630 per railcar, or $63 per month through October 31, 2020, and another commits the Company to pay for a minimum of 100 railcars per month to transport the proppant at $750 per railcar, or $75 per month, through May 31, 2018. 
+Certain agreements contain a clause whereby in the event that the Company fails to purchase minimum monthly volumes, as defined in the agreement, during any particular calendar month, a shortfall fee varying from $17.50 to $35.00 will be applied to each shortfall ton. The Company has the ability to mitigate the shortfall penalty in a certain period by purchasing proppant in excess of the requirement in another period. There were no shortfalls as of December 31, 2017 and 2016 . 
+During 2017 , the Company entered into two agreements for the purchase of chemicals. As of December 31, 2017 , the agreements commit the Company to purchase 27,278,000 gallons of chemicals through December 31, 2020 at prices ranging from $1.08 to $1.83 per gallon. 
+F- 21 
+Table of Contents 
+Future proppant, chemical and rail car commitments are as follows: 
+Year ending December 31, 
+2018 
+$ 
+245,626 
+2019 
+166,899 
+2020 
+120,216 
+2021 
+19,199 
+2022 
+— 
+$ 
+551,940 
+Litigation 
+From time to time, the Company is subject to legal and administrative proceedings, settlements, investigations, claims and actions. The Company’s assessment of the likely outcome of litigation matters is based on its judgment of a number of factors including experience with similar matters, past history, precedents, relevant financial and other evidence and facts specific to the matter. Notwithstanding the uncertainty as to the final outcome, based upon the information currently available, management does not believe any matters in aggregate will have a material adverse effect on its financial position or results of operations. 
+On February 23, 2017, SandBox Logistics, LLC and Oren Technologies, LLC (collectively, “SandBox”) filed suit in the Houston Division of the U.S. District Court for the Southern District of Texas against PropX Investments, PropX and LOS. As described in Note 13, LOS is party to the PropX Services Agreement. SandBox alleges that LOS willfully infringes multiple U.S. patents and has breached an agreement between SandBox and LOS by “directing, controlling, and funding” inter partes review (“IPR”) requests before the U.S. Patent and Trademark Office (“USPTO”). SandBox seeks both monetary and injunctive relief from the court, as well as attorney’s fees and costs. On August 14, 2017, the court denied SandBox’s request for a preliminary injunction to prevent LOS from filing a request for an IPR with the USPTO, and the court denied SandBox’s request for reconsideration of such order on March 13, 2018. Pursuant to the parties’ stipulation, all claims and counterclaims related to one of the four patents asserted by SandBox were dismissed without prejudice on November 6, 2017. A hearing on the construction of claim terms in the remaining asserted patents occurred on March 1, 2018. LOS intends to vigorously defend against the claims brought by SandBox. The Company cannot predict with any degree of certainty the outcome of the suit or determine the extent of any potential liability or damages. 
+Environmental 
+The Company is subject to various federal, state and local environmental laws and regulations that establish standards and requirements for protection of the environment. The Company cannot predict the future impact of such standards and requirements which are subject to change and can have retroactive effectiveness. The Company continues to monitor the status of these laws and regulations. Currently, the Company has not been fined, cited or notified of any environmental violations that would have a material adverse effect upon its financial position, liquidity or capital resources. 
+However, management does recognize that by the very nature of its business, material costs could be incurred in the near term to maintain compliance. The amount of such future expenditures is not determinable due to several factors, including the unknown magnitude of possible regulation or liabilities, the unknown timing and extent of the corrective actions which may be required, the determination of the Company’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnification. As of December 31, 2017 and 2016 , there are no environmental liabilities recognized in the combined balance sheets. 
+Note 15-Selected Quarterly Financial Data (unaudited) 
+The following table sets forth certain unaudited financial and operating information for each quarter of the year ended December 31, 2017 , and 2016 . The unaudited quarterly information includes all adjustments that, in the opinion of management, are necessary for the fair presentation of information presented. Operating results for interim periods are not necessarily indicative of the results that may be expected for the full fiscal year. 
+F- 22 
+Table of Contents 
+Year Ended December 31, 2017 
+Selected Financial Data: 
+First Quarter 
+Second Quarter 
+Third Quarter 
+Fourth Quarter 
+Revenue: 
+Revenue 
+249,218 
+334,740 
+436,333 
+444,842 
+Revenue—related parties 
+3,176 
+11,985 
+5,520 
+4,041 
+Total revenue 
+252,394 
+346,725 
+441,853 
+448,883 
+Operating costs and expenses: 
+Cost of services (exclusive of depreciation and amortization shown separately below) 
+211,633 
+267,626 
+328,434 
+339,315 
+General and administrative 
+17,084 
+20,022 
+22,245 
+20,738 
+Depreciation and amortization 
+14,146 
+17,521 
+24,164 
+25,642 
+Loss (gain) on disposal of assets 
+(43 
+) 
+10 
+21 
+160 
+Total operating costs and expenses 
+242,820 
+305,179 
+374,864 
+385,855 
+Operating income 
+9,574 
+41,546 
+66,989 
+63,028 
+Other expense: 
+Interest expense, net 
+(1,452 
+) 
+(1,750 
+) 
+(3,326 
+) 
+(5,347 
+) 
+Interest expense—related party 
+— 
+(761 
+) 
+— 
+— 
+Total interest expense 
+(1,452 
+) 
+(2,511 
+) 
+(3,326 
+) 
+(5,347 
+) 
+Net income 
+8,122 
+39,035 
+63,663 
+57,681 
+Year Ended December 31, 2016 
+Selected Financial Data: 
+First Quarter 
+Second Quarter 
+Third Quarter 
+Fourth Quarter 
+Revenue: 
+Revenue 
+$ 
+50,358 
+$ 
+55,425 
+$ 
+100,359 
+$ 
+150,748 
+Revenue—related parties 
+7,837 
+3,723 
+1,400 
+4,923 
+Total revenue 
+58,195 
+59,148 
+101,759 
+155,671 
+Operating costs and expenses: 
+Cost of services (exclusive of depreciation and amortization shown separately below) 
+64,117 
+59,714 
+94,325 
+136,573 
+General and administrative 
+4,685 
+4,967 
+12,729 
+13,408 
+Depreciation and amortization 
+9,584 
+9,753 
+10,864 
+11,161 
+Loss (gain) on disposal of assets 
+— 
+15 
+(42 
+) 
+(2,646 
+) 
+Total operating costs and expenses 
+78,386 
+74,449 
+117,876 
+158,496 
+Operating loss 
+(20,191 
+) 
+(15,301 
+) 
+(16,117 
+) 
+(2,825 
+) 
+Other expense: 
+Interest expense, net 
+(1,657 
+) 
+(1,487 
+) 
+(1,388 
+) 
+(1,594 
+) 
+Interest expense—related party 
+— 
+— 
+Total interest expense 
+(1,657 
+) 
+(1,487 
+) 
+(1,388 
+) 
+(1,594 
+) 
+Net loss 
+$ 
+(21,848 
+) 
+$ 
+(16,788 
+) 
+$ 
+(17,505 
+) 
+$ 
+(4,419 
+) 
+Note 16-Subsequent Events 
+On January 17, 2018, the Company signed an Amendment and Joinder to Credit Agreement that replaced Liberty Holdings with Liberty Inc. and Liberty LLC as parent guarantors on the ABL Facility. 
+On January 17, 2018, the Company signed an Amendment and Joinder to Credit Agreement that replaced Liberty Holdings with Liberty Inc. and Liberty LLC as parent guarantors on the Term Loan Facility. 
+F- 23 
+Table of Contents 
+On March 21, 2018, the Company signed an Amendment and Joinder to Credit Agreement that added R/C IV Non-U.S. LOS Corp, a wholly owned subsidiary of Liberty Inc. as an additional parent guarantor on the ABL Facility. 
+On March 21, 2018, the Company signed an Amendment and Joinder to Credit Agreement that added R/C IV Non-U.S. LOS Corp, a wholly owned subsidiary of Liberty Inc. as an additional parent guarantor on the Term Loan Facility. 
+Effective March 22, 2018, Titan, a wholly owned subsidiary of ACQI, assigned, transfered and conveyed all of its rights, title and interest in its assets to LOS and dissolved. 
+Effective March 22, 2018, ACQI was merged with and into LOS and the separate existence of ACQI ceased thereby making LOS the surviving entity. In conjunction with the merger and dissolution, Cibolo and Odessa, both wholly owned subsidiaries of ACQI, became wholly owned subsidiaries of LOS and the Redeemable Common Units were deemed extinguished and satisfied in full. 
+The Company has evaluated subsequent events through the date of this report. There were no significant subsequent events requiring disclosure or recognition other than those disclosed in these notes to the combined financial statements. 
+F- 24
\ No newline at end of file
diff --git a/raw/filings/0001694028/2017/0001628280-18-003509/filing_metadata.csv b/raw/filings/0001694028/2017/0001628280-18-003509/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..6b25b56d7a48fb4ea8fafc258b63191b67b6a00d
--- /dev/null
+++ b/raw/filings/0001694028/2017/0001628280-18-003509/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0001694028,LBRT,Liberty Energy Inc.,10-K,2018-03-23,2017-12-31,2018-03-23T22:46:53.000Z,0001628280-18-003509,libertyoilfield1231201810-k.htm,10-K,2564653,0,0,https://www.sec.gov/Archives/edgar/data/1694028/000162828018003509/libertyoilfield1231201810-k.htm,https://www.sec.gov/Archives/edgar/data/1694028/000162828018003509/,2017,2017,1
diff --git a/raw/filings/0001694028/2017/0001628280-18-003509/item1.txt b/raw/filings/0001694028/2017/0001628280-18-003509/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..d4e2e064c478214b41fa730798d166e7a45ac7a3
--- /dev/null
+++ b/raw/filings/0001694028/2017/0001628280-18-003509/item1.txt
@@ -0,0 +1,184 @@
+Item 1. Business 
+Overview 
+We are a growing independent provider of hydraulic fracturing services to onshore oil and natural gas exploration and production (“E&P”) companies in North America. We provide our services primarily in the Permian Basin, the Eagle Ford Shale, the Denver-Julesburg Basin (the “DJ Basin”), the Williston Basin and the Powder River Basin. 
+Initial Public Offering and Reorganization Transaction 
+Liberty Oilfield Services Inc. was incorporated as a Delaware corporation on December 21, 2016, to become a holding corporation for Liberty LLC and its subsidiaries upon completion of our Corporate Reorganization (as defined herein). 
+On January 17, 2018, we completed our initial public offering (the “IPO”) of 14,640,755 shares of our Class A common stock, par value $0.01 per share (the “Class A Common Stock”) at a public offering price of $17.00 per share, of which 14,340,214 shares were offered by us and 300,541 shares were offered by the selling shareholder. We received approximately $220.4 million in net proceeds after deducting approximately $23.4 million of underwriting discounts and commissions and other offering costs. We did not receive any proceeds from the sale of the shares of Class A Common Stock by the selling shareholder. We used approximately $25.9 million of net proceeds from the IPO to redeem ownership in us from certain Legacy Owners (as defined below) and contributed the remaining proceeds to Liberty LLC in exchange for units in Liberty LLC (the “Liberty LLC Units”). Liberty LLC used a portion of the net proceeds (i) to fully repay our outstanding borrowings and accrued interest under our ABL Credit Facility (as defined herein), totaling approximately $30.1 million , (ii) to repay 35% of our outstanding borrowings, accrued interest and prepayment premium under our Term Loan Facility (as defined herein), totaling approximately $62.5 million and (iii) for general corporate purposes, including repayment of additional indebtedness and funding a portion of our 2018 and other future capital expenditures. 
+We are a holding company with no direct operations. In connection with the IPO, we completed a series of organizational transactions (the “Corporate Reorganization”), including the following: 
+• 
+Liberty Holdings contributed all of its assets to Liberty LLC in exchange for Liberty LLC Units; 
+• 
+Liberty Holdings liquidated and distributed to its then-existing owners (the “Legacy Owners”) 105,451,454 Liberty LLC Units pursuant to the terms of the limited liability company agreement of Liberty Holdings and the Master Reorganization Agreement dated as of January 11, 2018, by and among the Company, Liberty Holdings, Liberty LLC, and the other parties named therein (the “Master Reorganization Agreement”); 
+• 
+Certain of the Legacy Owners directly or indirectly contributed all or a portion of their Liberty LLC Units to Liberty Inc. in exchange for 55,334,419 shares of our Class A Common Stock, including 1,258,514 shares of restricted stock; 
+• 
+Liberty Inc. issued the Legacy Owners that continued to own Liberty LLC Units (the “Liberty Unit Holders”) an aggregate amount of 48,207,372 shares of our Class B common stock, par value $0.01 per share (the “Class B Common Stock” and together with the Class A Common Stock, the “Common Stock”); and 
+• 
+Liberty Inc. contributed the net proceeds it received from the IPO to Liberty LLC in exchange for additional Liberty LLC Units such that Liberty Inc. holds a total number of Liberty LLC Units equal to the number of shares of Class A Common Stock outstanding following the IPO. 
+1 
+Table of Contents 
+The below structure chart shows our organization upon the completion of our IPO. This chart is provided for illustrative purposes only and does not represent all legal entities affiliated with us. 
+Each share of Class B Common Stock has no economic rights but entitles its holder to one vote on all matters to be voted on by shareholders generally. Holders of Class A Common Stock and Class B Common Stock will vote together as a single class on all matters presented to our shareholders for their vote or approval, except as otherwise required by applicable law or by our amended and restated certificate of incorporation. We do not intend to list Class B Common Stock on any exchange. 
+Under the Amended and Restated Limited Liability Company Agreement of Liberty LLC (the “Liberty LLC Agreement”), each Liberty Unit Holder has, subject to certain limitations, the right (the “Redemption Right”) to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units for, at Liberty LLC’s election, (i) shares of our Class A Common Stock at a redemption ratio of one share of Class A Common Stock for each Liberty LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions or (ii) an equivalent amount of cash. Alternatively, upon the exercise of the Redemption Right, Liberty Inc. (instead of Liberty LLC) will have the right (the “Call Right”) to, for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder for, at its election, (x) one share of Class A Common Stock or (y) an equivalent amount of cash. In addition, upon a change of control of Liberty Inc., Liberty Inc. has the right to require each holder of Liberty LLC Units (other than Liberty Inc.) to exercise its Redemption Right with respect to some or all of such unit holder’s Liberty LLC Units. In connection with any redemption of Liberty LLC Units pursuant to the Redemption Right or our Call Right, the corresponding number of shares of Class B Common Stock will be cancelled. 
+In connection with the IPO, Liberty Inc. entered into two tax receivable agreements, (the “Tax Receivable Agreements”) with the Liberty Unit Holders and the selling shareholder (each such person and any permitted transferee, a “TRA Holder” and together, the “TRA Holders”). 
+The first of the Tax Receivable Agreements, which Liberty Inc. entered into with the Liberty Unit Holders, generally provides for the payment by Liberty Inc. to such TRA Holders of 85% of the net cash savings, if any, in U.S. federal, state and local income and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that 
+2 
+Table of Contents 
+Liberty Inc. actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result of, as applicable to each such TRA Holder, (i) certain increases in tax basis that occur as a result of Liberty Inc.’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holder’s Liberty LLC Units in connection with the IPO or pursuant to the exercise of the Redemption Right or Liberty Inc.’s Call Right and (ii) imputed interest deemed to be paid by Liberty Inc. as a result of, and additional tax basis arising from, any payments Liberty Inc. makes under such Tax Receivable Agreement. 
+The second of the Tax Receivable Agreements, which Liberty Inc. entered into with the selling shareholder, generally provides for the payment by Liberty Inc. to such TRA Holder of 85% of the net cash savings, if any, in U.S. federal, state and local income and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that Liberty Inc. actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result of, as applicable to such TRA Holder, (i) any net operating losses available to Liberty Inc. as a result of the Corporate Reorganization and (ii) imputed interest deemed to be paid by Liberty Inc. as a result of any payments Liberty Inc. makes under such Tax Receivable Agreement. For further discussion regarding the potential acceleration of payments under the Tax Receivable Agreements and its potential impact, please read “Risk Factors—Risks Related to Our Class A Common Stock.” 
+Because Liberty Inc. is a holding company with no operations of its own, Liberty Inc.’s ability to make payments under the Tax Receivable Agreements is dependent on the ability of Liberty LLC to make distributions to Liberty Inc. in an amount sufficient to cover its obligations under the Tax Receivable Agreements. See “Risk Factors—Risks Related to Our Class A Common Stock—Liberty Inc. is a holding company. Liberty Inc.’s only material asset is its equity interest in Liberty LLC, and Liberty Inc. is accordingly dependent upon distributions from Liberty LLC to pay taxes, make payments under the Tax Receivable Agreements and cover its corporate and other overhead expenses.” If Liberty Inc. experiences a change of control (as defined under the Tax Receivable Agreements, which includes certain mergers, asset sales and other forms of business combinations) or the Tax Receivable Agreements terminate early (at Liberty Inc’s election or as a result of its breach), Liberty Inc. would be required to make a substantial, immediate lump-sum payment. 
+Our Company 
+We are a growing independent provider of hydraulic fracturing services to onshore oil and natural gas E&P companies in the United States. We have grown organically from one active hydraulic fracturing fleet in December 2011 to 21 active fleets in March 2018, representing approximately 885,000 hydraulic horsepower (“HHP”), including additional supporting horsepower. We expect to deploy one additional fleet in June 2018 and two additional fleets by the end of 2018, for a total of 24 active fleets, representing approximately 1,170,000 HHP, including supporting HHP. Our additional fleets are currently being built to our specifications. We provide our services primarily in the Permian Basin, the Eagle Ford Shale, the DJ Basin, the Williston Basin and the Powder River Basin. 
+Our founders and existing management were pioneers in the development of data-driven hydraulic fracturing technologies for application in shale plays. Prior to founding Liberty Holdings, the majority of our management team founded and built Pinnacle Technologies, Inc. (“Pinnacle Technologies”) into a leading fracturing technology company. In 1992, Pinnacle Technologies developed the first commercial hydraulic fracture mapping technologies, analytical tools that played a major role in launching the shale revolution. Our extensive experience with fracture technologies and customized fracture design has enabled us to develop new technologies and processes that provide our customers with real time solutions that significantly enhance their completions. These technologies include hydraulic fracture propagation models, reservoir engineering tools, large, proprietary shale production databases and multi-variable statistical analysis techniques. Taken together, these technologies have enabled us to be a leader in hydraulic fracture design innovation and application. 
+We believe the following characteristics distinguish us from our competitors and are the foundations of our business: forming ongoing partnerships of trust and innovation with our customers; developing and utilizing technology to maximize well performance; and promoting a people-centered culture focused on our employees, customers and suppliers. We have developed strong relationships with our customers by investing significant time in fracture design collaboration, which substantially enhances their production economics. Our technological innovations have become even more critical as E&P companies have increased the completion complexity and fracture intensity of horizontal wells. We are proactive in developing innovative solutions to industry challenges, including developing: (i) our proprietary databases of U.S. unconventional wells to which we apply our proprietary multi-variable statistical analysis technologies to provide differential insight into fracture design optimization; (ii) our Liberty Quiet Fleet ™ design which significantly reduces noise levels compared to conventional hydraulic fracturing fleets; and (iii) our hydraulic fracturing fluid system tailored to the reservoir properties in the DJ Basin which materially reduces completion costs without compromising production. We foster a people-centered culture built around honoring our commitments to customers, partnering with our suppliers and hiring, training and retaining people that we believe 
+3 
+Table of Contents 
+to be the best talent in our field, enabling us to be one of the safest and most efficient hydraulic fracturing companies in the United States. 
+Recent Developments 
+During the year ended December 31, 2017, we were an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”) and were not required to comply with certain requirements that were applicable to other public companies that are not “emerging growth companies.” 
+Effective as of January 17, 2018, we no longer qualify as an “emerging growth company” as defined in the JOBS Act. Accordingly, our independent registered public accounting firm will be required to formally attest to the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act in our Annual Report on Form 10-K for the year ending December 31, 2018. 
+Cyclical Nature of Industry 
+We operate in a highly cyclical industry. The key factor driving demand for our services is the level of drilling activity by E&P companies, which in turn depends largely on the current and anticipated economics of new well completions. Global supply and demand for oil and the domestic supply and demand for natural gas are critical in assessing industry outlook. Demand for oil and natural gas is cyclical and subject to large, rapid fluctuations. E&P companies tend to increase capital expenditures in response to increases in oil and natural gas prices, which generally results in greater revenues and profits for oilfield service companies such as ours. Increased capital expenditures also ultimately lead to greater production, which historically has resulted in increased supplies and reduced prices which in turn tend to reduce demand for oilfield services. For these reasons, the results of our operations may fluctuate from quarter to quarter and from year to year, and these fluctuations may distort comparisons of results across periods. 
+Seasonality 
+Our results of operations have historically reflected seasonal tendencies relating to holiday seasons, inclement weather and the conclusion of our customers’ annual drilling and completion capital expenditure budgets. Our most notable declines occur in the first and fourth quarters of the year for the reasons described above. Additionally, some of the areas in which we have operations, including the DJ Basin, Powder River Basin and Williston Basin, are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice or rain and frost law enforcement, we may be unable to move our equipment between locations, thereby reducing our ability to provide services and generate revenues. The exploration activities of our customers may also be affected during such periods of adverse weather conditions. Additionally, extended drought conditions in our operating regions could impact our ability or our customers’ ability to source sufficient water or increase the cost for such water. 
+Intellectual Property 
+Over the last several years we have significantly invested in our research and technology capabilities. Our efforts to date have been focused on developing innovative, fit-for-purpose solutions designed to enhance our core service offerings, increase completion efficiencies, provide cost savings to our operations and add value for our customers. 
+As a result of these efforts, we introduced several new products and progressed on differentiating technologies that we believe will provide a competitive advantage as our customers focus on extracting oil and natural gas in the most economical and efficient ways possible, including the Vorteq Missile ™ , a new technology, being developed with a third party, that is designed to add proppant downstream of the high pressure pumps, and our Liberty Quiet Fleet ™ , which materially reduces noise levels compared to conventional fracturing fleets. Additionally, several of these investments are delivering value added products and services that are creating increasing demand from key customers. 
+We seek patent and trademark protections for our technology when we deem it prudent, and we aggressively pursue protection of these rights. We believe our patents, trademarks, and other protections for our proprietary technologies are adequate for the conduct of our business and that no single patent or trademark is critical to our business. In addition, we rely, to a great extent, on the technical expertise and know-how of our personnel to maintain our competitive position, and we take commercially reasonable measures to protect trade secrets and other confidential and/or proprietary information relating to the technologies we develop. 
+4 
+Table of Contents 
+Risk Management and Insurance 
+Our operations are subject to significant hazards often found in the oil and natural gas industry, such as, but not limited to, accidents, blowouts, explosions, craterings, fires, natural gas leaks, oil and produced water spills and releases of hydraulic fracturing fluids or other well fluids into the environment. These conditions can cause: 
+• 
+disruption in operations; 
+• 
+substantial repair or remediation costs; 
+• 
+personal injury or loss of human life; 
+• 
+significant damage to or destruction of property and equipment; 
+• 
+environmental pollution, including groundwater contamination; 
+• 
+unusual or unexpected geological formations or pressures and industrial accidents; 
+• 
+impairment or suspension of operations; and 
+• 
+substantial revenue loss. 
+In addition, our operations are subject to, and exposed to, employee/employer liabilities and risks such as wrongful termination, discrimination, labor organizing, retaliation claims and general human resource related matters. 
+Claims for loss of oil and natural gas production and damage to formations can occur in the well services industry. Litigation arising from a catastrophic occurrence at a location where our equipment and services are being used may result in our being named as a defendant in lawsuits asserting large claims. 
+We do not have insurance against all foreseeable risks, either because insurance is not available or because of the high premium costs. The occurrence of an event not fully insured against or the failure of an insurer to meet its insurance obligations could result in substantial losses. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. Insurance may not be available to cover any or all of the risks to which we are subject, or, even if available, it may be inadequate, or insurance premiums or other costs could rise significantly in the future so as to make such insurance prohibitively expensive. 
+We enter into Master Service Agreements (“MSAs”) with substantially all of our customers. Our MSAs delineate our and our customer’s respective indemnification obligations with respect to the services we provide. Generally, under our MSAs, including those relating to our hydraulic fracturing services, we assume responsibility for pollution or contamination originating above the surface from our equipment or handling. However, our customers assume responsibility for all other pollution or contamination that may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling and completion fluids. The assumed responsibilities include the control, removal and clean-up of any pollution or contamination. In such cases, we may be exposed to additional liability if we are negligent or commit willful acts causing the pollution or contamination. Generally, our customers also agree to indemnify us against claims arising from their employees’ personal injury or death, in the case of our hydraulic fracturing operations, to the extent that their employees are injured by such operations, unless the loss is a result of our gross negligence or willful misconduct. Similarly, we generally agree to indemnify our customers for liabilities arising from personal injury to or death of any of our employees, unless resulting from the gross negligence or willful misconduct of our customer. The same principals apply to mutual indemnification for loss or destruction of customer-owned property or equipment, except such indemnification is not limited by negligence or misconduct. Losses due to catastrophic events, such as blowouts, are generally the responsibility of the customer. However, despite this general allocation of risk, we may be unsuccessful in enforcing contractual terms, incur an unforeseen liability that is not addressed by the scope of the contractual provisions or be required to enter into an MSA with terms that vary from our standard allocations of risk, as described above. Consequently, we may incur substantial losses that could materially and adversely affect our financial condition and results of operations. 
+Employees 
+As of December 31, 2017, we had 2,032 employees and no unionized labor. We believe we have good relations with our employees. 
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+Our Services 
+We provide hydraulic fracturing services to E&P companies, particularly to those operating in unconventional oil and natural gas reservoirs and requiring technically and operationally advanced services. Hydraulic fracturing services are performed to enhance production of oil and natural gas from formations with low permeability and restricted flow of hydrocarbons. Our customers benefit from our expertise in fracturing horizontal wells in shales and other unconventional geological formations. 
+The process of hydraulic fracturing involves pumping a pressurized stream of fracturing fluid—typically a mixture of water, chemicals and proppant—into a well casing or tubing in order to cause the underground formation to fracture or crack. These fractures release trapped hydrocarbon particles and provide a conductive channel for the oil or natural gas to flow freely to the wellbore for collection. The propping agent, or proppant,—typically sand—becomes lodged in the cracks created by the hydraulic fracturing process, “propping” them open to facilitate the flow of hydrocarbons from the reservoir to the well. The fracturing fluid is engineered to lose viscosity, or “break,” and is subsequently flowed back from the formation, leaving the proppant suspended in the mineral fractures. Once our customer has flushed the fracturing fluids from the well using a controlled flow-back process, the customer manages fluid and water recycling or disposal. 
+Our hydraulic fracturing fleets consist of mobile hydraulic fracturing units and other auxiliary heavy equipment to perform fracturing services. Our hydraulic fracturing units consist primarily of high-pressure hydraulic pumps, diesel engines, transmissions, radiators and other supporting equipment that are typically mounted on trailers. We refer to the group of units and other equipment, such as blenders, data vans, sand storage, tractors, manifolds and high pressure fracturing iron, which are necessary to perform a typical hydraulic fracturing job, as a “fleet,” and the personnel assigned to each fleet as a “crew.” As of March 2018, we had 21 active fleets, and expect to deploy one additional fleet by the end of the second quarter of 2018, and two additional fleets by the end of 2018, for a total of 24 active fleets by the end of the year. 
+An important element of our hydraulic fracturing services is our focus on providing custom-tailored completions solutions to our customers to maximize their well results. Our technologically innovative approach involves our review of a series of continually updated, proprietary databases of U.S. unconventional wells to which we apply our multi-variable data analysis, allowing us to gain differential insight into fracture design. The innovative completions solutions we provide to our customers help them complete more productive and cost efficient wells in shorter times with less environmental impact on their surroundings while increasing the useful lives of our equipment. 
+In addition to custom-tailored completions solutions, we also develop custom fluid systems, proppant logistics solutions, perforating strategies and pressure analysis techniques for our customers. An example of this is a hydraulic fracturing fluid that we developed for use in our DJ Basin operations called Liberty Spirit ™ , a specifically designed fracturing fluid system that enables material reductions in completion costs in the DJ Basin without compromising job execution or well results. 
+We provide our services in several of the most active basins in the United States, including the Permian Basin, the Eagle Ford Shale, the DJ Basin, the Williston Basin and the Powder River Basin. The map below represents our current areas of operations: 
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+Properties and Equipment 
+Properties 
+Our corporate headquarters are located at 950 17 th Street, Suite 2400, Denver, Colorado 80202. We lease our general office space at our corporate headquarters. The lease expires in December 2024. We currently own or lease the following additional principal properties: 
+District Facility Location 
+Size 
+Leased or Owned 
+Expiration of Lease 
+Odessa, TX 
+77,500 sq. ft on 47 acres 
+Owned 
+N/A 
+Henderson, CO 
+50,000 sq. ft on 13 acres 
+Leased 
+December 31, 2034 
+Williston, ND 
+30,000 sq. ft on 15 acres 
+Owned 
+N/A 
+Gillette, WY 
+32,757 sq. ft on 15 acres 
+Leased 
+December 31, 2034 
+Cibolo, TX 
+90,000 sq. ft on 34 acres 
+Owned 
+N/A 
+We also lease several smaller facilities, which leases generally have terms of one to three years. We believe that our existing facilities are adequate for our operations and their locations allow us to efficiently serve our customers. We do not believe that any single facility is material to our operations and, if necessary, we could readily obtain a replacement facility. 
+Equipment 
+We have 21 hydraulic fracturing fleets plus additional supporting HHP, comprising approximately 885,000 HHP. We expect to deploy three additional fleets by the end of 2018, for a total of 24 active fleets. Six of our fleets currently utilize our Liberty Quiet Fleet ™ technology, with three additional ordered fleets currently being built to our to Liberty Quiet Fleet ™ specifications; approximately 40% of our capacity has dual fuel capability. 
+Our hydraulic fracturing fleets are comprised of high-quality, heavy-duty equipment designed to reduce operational downtime and maintenance costs, while enhancing our ability to provide reliable, consistent service. The average age of our fleets is approximately 3.75 years. Each hydraulic fracturing fleet also includes the necessary blending units, manifolds, data vans and other ancillary equipment needed to provide a high level of service to our customers. 
+Our newbuild fleets are manufactured to a custom Liberty specification that identifies the input components, including such key parts as engines, transmissions and pumps and control systems. These components have been selected with our lowest total cost of ownership philosophy in mind. We have built a strong partnership with each of the key component suppliers that we believe will help ensure timely access to necessary components, early opportunities to adopt the latest technology, and high-level technical support. For example, our close partnership with Caterpillar Inc. enabled us to have ready access to their technical team as we worked through the development of the Liberty Quiet Fleet ™ technology. This relationship ensured that the end product was delivered without compromise to engine performance, reliability or maintainability. We have also a built a strong relationship with the assembler of the core equipment for our fracturing fleets. We believe the collaborative partnerships we have developed with our vendors should give us ready access to sufficient fabrication capacity for our growth. 
+Our Acquisitions 
+On June 13, 2016, we acquired certain inventories and long-lived field service assets related to hydraulic fracturing from Sanjel Corporation for $69.0 million in cash (the “Sanjel Acquisition”). These assets were acquired from Sanjel Corporation as part of its bankruptcy proceeding. On February 22, 2017, we acquired all the membership interests of Titan Frac Services LLC, a wholly-owned subsidiary of TPIH Group Inc., for $65.0 million in cash. 
+Marketing and Customers 
+Our sales and marketing activities typically are performed through our local sales representatives in each geographic region, and are supported by our corporate headquarters. For the years ended December 31, 2017 , 2016 and 2015 , our top five customers collectively accounted for approximately 53.0%, 58.5% and 57.5% of our revenues, respectively. Extraction Oil & Gas, Inc. and SM Energy Company each accounted for more than 10% of our revenues for the year ended December 31, 2017 . For the year ended December 31, 2016 , Extraction Oil & Gas, Inc., SM Energy Company and Noble Energy, Inc. each accounted for more than 10% of our revenues. Extraction Oil & Gas, Inc. also accounted for more than 10% of our revenues for the year ended December 31, 2015 . 
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+Suppliers 
+We have a dedicated supply chain team that manages sourcing and logistics to ensure flexibility and continuity of supply in a cost effective manner across our areas of operation. We have built long-term relationships with multiple industry leading suppliers of proppant, chemicals and hydraulic fracturing equipment. During the year ended December 31, 2015 , we purchased 10% or more of our materials or equipment, as a percentage of overall costs, from one sand supplier. For the years ended December 31, 2017 and 2016 , none of our suppliers accounted for more than 10% of overall costs. For 2018, we do not expect any single proppant supplier to account for more than 20% of our total supply. In addition, we have built a strong relationship with the assembler of our custom-designed hydraulic fracturing fleets and believe we will continue to have timely access to new, high capability fleets as we continue to grow. Our purchases from that assembler accounted for more than 10% of our total capital expenditures for the year ended December 31, 2017 . 
+We purchase a wide variety of raw materials, parts and components that are manufactured and supplied for our operations. We are not dependent on any single source of supply for those parts, supplies or materials. To date, we have generally been able to obtain the equipment, parts and supplies necessary to support our operations on a timely basis. While we believe that we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers, we may not always be able to do so. In addition, certain materials for which we do not currently have long-term supply agreements could experience shortages and significant price increases in the future. As a result, we may be unable to mitigate any future supply shortages and our results of operations, prospects and financial condition could be adversely affected. 
+Competition 
+The markets in which we operate are highly competitive. We provide services in various geographic regions across the United States, and our competitors include many large and small oilfield service providers, including some of the largest integrated service companies. Our hydraulic fracturing services compete with large, integrated companies such as Halliburton Company and Schlumberger Limited as well as other companies including Basic Energy Services, Inc., BJ Services Company, C&J Energy Services, Inc., Calfrac Well Services Ltd., FTS International, Inc., Keane Group, Inc., Patterson-UTI Energy, Inc., ProPetro Services, Inc., RPC, Inc., Superior Energy Services, Inc. and U.S. Well Services, LLC. In addition, our industry is highly fragmented and we compete regionally with a significant number of smaller service providers. 
+We believe that the principal competitive factors in the markets we serve are technical expertise, equipment capacity, work force competency, efficiency, safety record, reputation, experience and price. Additionally, projects are often awarded on a bid basis, which tends to create a highly competitive environment. We seek to differentiate ourselves from our competitors by delivering the highest-quality services and equipment possible, coupled with superior execution and operating efficiency in a safe working environment. 
+Our operations are organized into a single business segment, which consists of hydraulic fracturing services, and we have one reportable geographical business segment, the United States. Operating segments are defined under generally accepted accounting principals in the United States of America ( “ GAAP ” ) as components of an enterprise that engage in activities (i) from which it may earn revenues and incur expenses and (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance. 
+Environmental and Occupational Safety and Health Matters 
+Our operations in support of oil and natural gas exploration, development and production activities pursued by our customers are subject to stringent federal, tribal, state and local laws and regulations governing occupational safety and health, the discharge of materials into the environment and environmental protection. Numerous governmental entities, including the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. These laws and regulations may, among other things (i) require the acquisition of permits or other authorizations for conducting regulated activities, (ii) limit or prohibit our operations on certain lands lying within wilderness, wetlands and other protected areas; (iii) require remedial measures to mitigate pollution from former and ongoing operations; (iv) impose restrictions on the types, quantities and concentrations of various substances that can be released into the environment or injected in formations in connection with oil and natural gas drilling and production activities; (v) impose specific safety and health criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from our operations. Any failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the 
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+permitting or performance of projects; and the issuance of orders enjoining performance of some or all of our operations in a particular area. 
+The trend in environmental regulation is to place more restrictions and limitations on activities that may adversely affect the environment, and thus any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly completion activities, or waste handling, storage transport, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. Our customers may also incur increased costs or delays or restrictions in permitting or operating activities as a result of more stringent environmental laws and regulations, which may result in a curtailment of exploration, development or production activities that would reduce the demand for our services. Historically, our worker health and safety as well as our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our business and operating results. 
+The following is a summary of the more significant existing environmental and occupational safety and health laws, as amended from time to time, to which our business is subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position. 
+Worker Health and Safety 
+We are subject to the requirements of the federal Occupational Safety and Health Act, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the U.S. Occupational Safety and Health Administration (“OSHA”) hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and the public. These worker health and safety laws and regulations are subject to changes and any failure to comply with these laws could lead to the assertion of third-party claims against us, civil or criminal fines and changes in the way we operate our facilities, any of which could have an adverse effect on our financial position. 
+Motor Carrier Operations 
+In connection with the services we provide, we operate as a motor carrier and therefore are subject to regulation by the U.S. Department of Transportation (“DOT”) and analogous various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations; regulatory safety; hazardous materials labeling, placarding and marking; financial reporting; and certain mergers, consolidations and acquisitions. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive in any specific period and requiring onboard electronic logging devices or limits on vehicle weight and size. 
+Interstate motor carrier operations are subject to safety requirements prescribed by DOT. Intrastate motor carrier operations are subject to state safety regulations that often mirror federal regulations but may be more stringent. Such matters as weight and dimension of motor carrier-related equipment are also subject to federal and state regulations. DOT regulations also mandate drug testing of drivers. From time to time, various legislative proposals are introduced, including proposals to increase federal, state or local taxes, such as, for example, taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us would be enacted. 
+Radioactive Materials 
+Some of our operations utilize equipment that contains sealed, low-grade radioactive sources. Our activities involving the use of radioactive materials are regulated by the U.S. Nuclear Regulatory Commission (“NRC”) and state regulatory agencies under agreement with the NRC. Standards implemented by these regulatory agencies require us to obtain licenses or other approvals for the use of such radioactive materials. Additionally, these regulatory agencies impose certain requirements 
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+concerning worker protection with respect to radioactive sources and may otherwise issue regulations regarding the handling and storage of this equipment that may result in increased costs. The violation of these laws and regulations may result in the denial or revocation of licenses or other approvals, issuance of corrective action orders, injunctions prohibiting some or all of our operations in a particular area, and assessment of sanctions, including administrative, civil and criminal penalties. 
+Hazardous Substances and Wastes and Naturally Occurring Radioactive Materials 
+The federal Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, regulate the generation, treatment, storage, transportation, disposal and clean-up of hazardous and non-hazardous wastes. Pursuant to rules issued by the EPA, individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste provisions, state laws or other federal laws. However, it is possible that certain oil and gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. For example, in response to a lawsuit filed by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and natural gas wastes, the EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the U.S. District Court for the District of Columbia in December 2016. Under the consent decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes or sign a determination that revision of the regulations is not necessary. If the EPA proposes a rulemaking for revised oil and natural gas waste regulations, the consent decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our and the oil and natural gas exploration and production industry’s costs to manage and dispose of generated hazardous wastes, which could have a material adverse effect on our results of operations and financial position. Additionally, other wastes handled at exploration and production sites or generated in the course of providing well services may not fall within this exclusion. In the course of our operations, we generate some amounts of ordinary industrial wastes that may be regulated as hazardous wastes. 
+Moreover, there have been public concerns expressed about naturally occurring radioactive materials (“NORM”) being detected in flow back water resulting from hydraulic fracturing that may contaminate extraction and processing equipment used in the oil and natural gas industry. NORM is subject primarily to individual state radiation control regulations while NORM handling and management activities are governed by regulations promulgated by OSHA. These state and federal regulations impose certain requirements concerning worker protection with respect to NORM as well as the treatment, storage, and disposal of NORM and NORM waste, management of NORM-contaminated waste piles, containers and tanks, and limitations on the relinquishment of NORM contaminated land for unrestricted use under RCRA and state laws. Concern over NORM in general, or NORM in groundwater in particular, could result in further regulation in the treatment, storage, handling and discharge of flow back water generated from oil and natural gas activities, including hydraulic fracturing, or handling of NORM-impacted equipment that, if implemented, could limit drilling by our customers or increase our costs or liabilities associated with elevated levels of NORM. 
+The federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, and comparable state statutes impose liability, without regard to fault or legality of the original conduct, on classes of persons that are considered to have contributed to the release of a hazardous substance into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, these persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We own, lease, or operate numerous properties and facilities that for many years have been used for industrial activities, including oil and natural gas-related operations. Hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations where such substances have been taken for recycling or disposal. In addition, some of these properties have been operated by third parties or by previous owners whose treatment and disposal or release of hazardous substances, wastes, or hydrocarbons, was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes and remediate contaminated property (including groundwater contamination), including instances where the prior owner or operator caused the contamination, or perform remedial plugging of disposal wells or waste pit closure operations to prevent future contamination. These laws and regulations may also expose us to liability for our acts that were in compliance with applicable laws at the time the acts were performed. 
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+Water Discharges and Discharges into Belowground Formations 
+The Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”) and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and hazardous substances, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers (“Corps”). The CWA and analogous state laws also may impose substantial civil and criminal penalties for non-compliance including spills and other non-authorized discharges. 
+In May 2015, the EPA and the Corps released a final rule outlining their position on federal jurisdictional reach over waters of the United States, including wetlands, but legal challenges to this rule followed, and the rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals in October 2015, pending resolution of the court challenges. In January 2017, the United States Supreme Court accepted review of the rule to determine whether jurisdiction rests with the federal district or appellate courts and, in a decision issued on January 22, 2018, held that legal challenges of the rule must be heard at the district rather than appellate court level. The Sixth Circuit lifted its stay of the 2015 rule in February 2018. Additionally, following issuance of a presidential executive order to review the rule, the EPA and the Corps published a proposed rulemaking in July 2017 to repeal the 2015 rule. The EPA and the Corps also announced their intent to issue a new rule defining the CWA’s jurisdiction. On February 6, 2018, the EPA and the Corps published a final rule specifying that the contested 2015 rule would not take effect until February 6, 2020. As a result, future implementation of the 2015 rule is uncertain at this time. To the extent the 2015 rule or a revised rule expands the scope of the CWA’s jurisdiction in areas where we or our customers operate, it could impose additional permitting obligations on us and our customers. 
+The Oil Pollution Act of 1990 (“OPA”) amends the CWA and sets minimum standards for prevention, containment and cleanup of oil spills. OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties including owners and operators of onshore facilities may be held strictly liable for oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills. The OPA also requires owners or operators of certain onshore facilities to prepare facility response plans for responding to a worst-case discharge of oil into waters of the United States. 
+Our oil and natural gas producing customers dispose of flowback and produced water or certain other oilfield fluids gathered from oil and natural gas producing operations in accordance with permits issued by government authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change based on concerns of the public or governmental authorities regarding such disposal activities. One such concern relates to recent seismic events near underground disposal wells used for the disposal by injection of flowback and produced water or certain other oilfield fluids resulting from oil and natural gas activities. In 2016, the United States Geological Survey identified six states with the most significant hazards from seismicity events suspected of having been induced by injection of oilfield fluids into underground disposal wells, including Oklahoma, Kansas, Texas, Colorado, New Mexico, and Arkansas. In response to concerns between use of underground disposal wells and the occurrence of seismic events, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Texas and Oklahoma have issued rules for produced water disposal wells that impose certain permitting restrictions, operating restrictions and/or reporting requirements on disposal wells in proximity to faults. Additionally, from time to time, states may develop and implement plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations, as has occurred in Oklahoma. For example, in December 2016, the Oil and Gas Conservation Division of the Oklahoma Corporation Commission (“OCC”) and the Oklahoma Geological Survey released well completion seismicity guidance, which requires operators to take certain prescriptive actions, including an operator’s planned mitigation practices, following certain unusual seismic activity within 1.25 miles of hydraulic fracturing operations. In addition, in February 2017, the OCC’s Oil and Gas Conservation Division issued an order limiting future increases in the volume of oil and natural gas produced water injected belowground into the Arbuckle formation in an effort to reduce the number of earthquakes in the state, and imposed further restrictions in the Edmonds area of the state in August 2017. Another consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by our customers to dispose of flowback and produced water and certain other oilfield fluids. Increased regulation and 
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+attention given to seismicity events suspected of having been induced by injection of oilfield fluids into underground disposal wells also could lead to greater opposition to, and litigation concerning, oil and natural gas activities utilizing injection wells for waste disposal. Any one or more of these developments may result in our customers having to limit disposal well volumes, disposal rates or locations, or require our customers or third party disposal well operators that are used to dispose of customer produced water to shut down disposal wells, which developments could adversely affect our customers’ business and result in a corresponding decrease in the need for our services, which would could have a material adverse effect on our business, financial condition, and results of operations. 
+Air Emissions 
+Some of our operations also result in emissions of regulated air pollutants. The federal Clean Air Act (“CAA”) and analogous state laws require permits for certain facilities that have the potential to emit substances into the atmosphere that could adversely affect environmental quality. These laws and their implementing regulations also impose generally applicable limitations on air emissions and require adherence to maintenance, work practice, reporting and record keeping, and other requirements. Failure to obtain a permit or to comply with permit or other regulatory requirements could result in the imposition of sanctions, including administrative, civil and criminal penalties. In addition, we or our customers could be required to shut down or retrofit existing equipment, leading to additional expenses and operational delays. 
+Many of these regulatory requirements, including New Source Performance Standards (“NSPS”) and Maximum Achievable Control Technology (“MACT”) standards, are expected to be made more stringent over time as a result of stricter ambient air quality standards and other air quality protection goals adopted by the EPA. Compliance with these or other new or amended regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact on our business. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard, (“NAAQS”) for ozone from 75 to 70 parts per billion for both the 8-hour primary and secondary standards. The EPA published a final rule in November 2017 that issued area designations with respect to ground-level ozone for approximately 85% of the U.S. counties as either “attainment/unclassifiable” or “unclassifiable” and is expected to issue attainment or non-attainment designations for the remaining areas of the U.S. not addressed under the November 2017 final rule in the first half of 2018. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Additionally, states are expected to implement more stringent requirements as a result of the revised NAAQS for ozone, which could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. In a second example, the EPA finalized separate rules under the CAA in June 2016 regarding criteria for aggregating multiple sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small production facilities (such as tank batteries and compressor stations), on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements. Compliance with this and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase costs for us and our customers. Moreover, our business could be materially affected if our customers’ operations are significantly affected by these or other similar requirements. These requirements could increase the cost of doing business for us and our customers, reduce the demand for the oil and natural gas our customers produce, and thus have an adverse effect on the demand for our services. 
+Climate Change 
+Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of greenhouse gases (“GHGs”). These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. In the absence of federal GHG-limiting legislations, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted regulations that, among other things, restrict emissions of GHGs under existing provisions of the CAA and may require the installation of “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future if they would otherwise emit large volumes of GHGs together with other criteria pollutants. Also, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from oil and natural gas production, processing, transmission and storage facilities in the United States on an annual basis. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting stations as well as completions and workovers from hydraulically fractured oil wells. 
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+The EPA has also taken steps to limit methane emissions, a GHG, from certain new modified or reconstructed facilities in the oil and natural gas sector through the adoption of a final rule in June 2016 establishing NSPS Subpart OOOOa standards for methane emissions. These Subpart OOOOa standards will expand the previously issued NSPS Subpart OOOO requirements issued in 2012 by using certain equipment-specific emissions control practices. However, in June 2017, the EPA published a proposed rule to stay certain portions of the June 2016 standards for two years and re-evaluate the entirety of the 2016 standards but the EPA has not yet published a final rule and, as a result, the June 2016 rule remains in effect but future implementation of the 2016 standards is uncertain at this time. Furthermore, in November 2016, the federal Bureau of Land Management (“BLM”) published a final rule that established, among other things, requirements to reduce methane emissions arising from venting, flaring and leaks from oil and natural gas production activities on onshore federal and Native American lands. However, in December 2017, the BLM published a final rule to temporarily suspend or delay certain requirements contained in the November 2016 final rule until January 17, 2019, including those requirements relating to the venting, flaring and leakage from oil and natural gas production activities. The suspension of the November 2016 final rule is being challenged in court. Given the long-term trend towards increasing regulation, future federal GHG regulations of the oil and natural gas industry remain a possibility, and should the EPA’s June 2016 or the BLM’s November 2016 rules remain in effect, or any other new methane emission standards be imposed on the oil and natural gas sector, such requirements could result in increased costs to our or our customers’ operations as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect our business. 
+In December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that prepared an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered in force in November 2016; however, the GHG emission reductions called for by the Paris Agreement are not binding. In August 2017, the U.S. State Department informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas our customers produce and lower the value of their reserves, which developments could reduce demand for our services and have a corresponding material adverse effect on our results of operations and financial position. 
+Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production or midstream activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and natural gas will continue to represent a substantial percentage of global energy use over that time. Finally, it should be noted that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our operations. 
+Endangered Species 
+The federal Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the federal Migratory Bird Treaty Act (“MBTA”). As a result of one or more settlements entered into by the U.S. Fish and Wildlife Service, that agency is required to consider listing numerous species as endangered or threatened under the Endangered Species Act by specified timelines. Current ESA listings and the designation of previously unprotected species as threatened or endangered in areas where we or our customers operate could cause us or our customers to incur increased costs arising from species protection or mitigation measures and could result in delays or limitations in our or our customers' performance of operations, which could adversely affect or reduce demand for our services. 
+Hydraulic Fracturing 
+We perform hydraulic fracturing services for our customers. Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand or other proppant and chemical additives under pressure into the formation to fracture the surrounding rock and stimulate production. 
+13 
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+Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has conducted investigations or asserted federal regulatory authority pursuant to the U.S. Safe Drinking Water Act (“SDWA”) Underground Injection Control (“UIC”) program over certain aspects of the process. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances.” Additionally, the EPA asserted regulatory authority under the SDWA UIC program in 2014 over hydraulic fracturing activities involving the use of diesel fuel and issued permitting guidance covering such activities. The EPA also published final CAA regulations in 2012 and in June 2016 governing performance standards, including standards for the capture of emissions released during oil and natural gas hydraulic fracturing. Also in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of produced water from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants and, in May 2014, published an Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. The BLM published a final rule in March 2015 that imposed new or more stringent standards for performing hydraulic fracturing on federal and Native American lands. However, in June 2016, a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority to promulge the rule, the BLM appealed the decision to the U.S. Circuit Court of Appeals for the Tenth Circuit in July 2016, the appellate court issued a ruling in September 2017 to vacate the Wyoming trial court decision and dismiss the lawsuit challenging the rule in light of the BLM’s proposed rulemaking and, in December 2017, the BLM published a final rule rescinding the March 2015 rule. In January 2018, litigation challenging the BLM’s rescission of the 2015 rule was brought in federal court. 
+In addition, various state and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, disclosure requirements, well construction and temporary or permanent bans on hydraulic fracturing in certain areas. For example, Texas, Colorado and North Dakota, among others, have adopted regulations that impose new or more stringent permitting, disclosure, disposal, and well construction requirements on hydraulic fracturing operations. States could also elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York. Local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular. If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly to perform hydraulic fracturing. Any such regulations limiting or prohibiting hydraulic fracturing could result in decreased oil and natural gas exploration and production activities and, therefore, adversely affect demand for our services and our business. Such laws or regulations could also materially increase our costs of compliance and doing business. 
+Available Information 
+We file or furnish annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The public may read and copy any materials we file with the U.S. Securities and Exchange Commission (the “SEC”) at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549, on official business days during the hours of 10 a.m. to 3 p.m. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC. 
+Our Class A Common Stock is listed and traded on the New York Stock Exchange (“NYSE”) under the symbol “LBRT.” Our reports, proxy statements and other information filed with the SEC can also be inspected and copied at the offices of the NYSE, at 20 Broad Street, New York, New York 10005. 
+We also make available free of charge through our website, www.libertyfrac.com, electronic copies of certain documents that we file with the SEC, including our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. 
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+Item 13. Certain Relationships and Related Transactions, and Director Independence 
+The following discussion is a brief summary of certain material arrangements, agreements and transactions we have with related parties. It does not include all of the provisions of our material arrangements, agreements and transactions with related parties, does not purport to be complete and is qualified in its entirety by reference to the arrangements, agreements and transactions described. 
+IPO-Related Agreements 
+In connection with our Corporate Reorganization, we engaged in transactions with affiliates, such as Liberty LLC, and our Legacy Owners and entered into the agreements detailed herein. See also “Item 1. Business—Initial Public Offering and Reorganization Transactions” for a description of these transactions. 
+Liberty LLC Agreement 
+We entered into the Liberty LLC Agreement in connection with the closing of the IPO, which provides for limitations on the ability of Liberty Unit Holders to transfer their Liberty LLC Units and provides Liberty Inc., as managing member of Liberty LLC, with the right to impose restrictions (in addition to those already in place) on the ability of Liberty Unit Holders to redeem their Liberty LLC Units pursuant to the Redemption Right to the extent Liberty Inc. believes it is necessary to ensure that Liberty LLC will continue to be treated as a partnership for U.S. federal income tax purposes. 
+Redemption Rights 
+Under the Liberty LLC Agreement, each Liberty Unit Holder has, subject to certain limitations, the right to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units for, at Liberty LLC’s election, (i) shares of our Class A Common Stock at a redemption ratio of one share of Class A Common Stock for each Liberty LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions or (ii) an equivalent amount of cash. Alternatively, upon the exercise of the Redemption Right, Liberty Inc. (instead of Liberty LLC) will have the right to, for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder for, at its election, (x) one share of Class A Common Stock or (y) an equivalent amount of cash. In addition, upon a change of control of Liberty Inc., Liberty Inc. has the right to require each holder of Liberty LLC Units (other than Liberty Inc.) to exercise its Redemption Right with respect to some or all of such unit holder’s Liberty LLC Units. In connection with any redemption of Liberty LLC Units pursuant to the Redemption Right or our Call Right, the corresponding number of shares of Class B Common Stock will be cancelled. As the Liberty Unit Holders redeem their Liberty LLC Units, our membership interest in Liberty LLC will be correspondingly increased, the number of shares of Class A Common Stock outstanding will be increased, and the number of shares of Class B Common Stock outstanding will be reduced. 
+Distributions and Allocations 
+Under the Liberty LLC Agreement, Liberty Inc. has the right to determine when distributions will be made to the holders of Liberty LLC Units and the amount of any such distributions. If Liberty Inc. authorizes a distribution, such distribution will be made to the holders of Liberty LLC Units generally on a pro rata basis in accordance with their respective percentage ownership of Liberty LLC Units. 
+Liberty LLC will allocate its net income or net loss for each year to the holders of Liberty LLC Units pursuant to the terms of the Liberty LLC Agreement, and the holders of Liberty LLC Units, including Liberty Inc., will generally incur U.S. federal, state and local income taxes on their share of any taxable income of Liberty LLC. Net income and losses of Liberty LLC generally will be allocated to the holders of Liberty LLC Units on a pro rata basis in accordance with their respective percentage ownership of Liberty LLC Units, subject to requirements under U.S. federal income tax law that certain items of income, gain, loss or deduction be allocated disproportionately in certain circumstances. To the extent Liberty LLC has available cash and subject to the terms of any future debt instruments, Liberty Inc. intends to cause Liberty LLC to make (i) generally pro rata distributions to the holders of Liberty LLC Units, including Liberty Inc., in an amount sufficient to allow Liberty Inc. to pay its taxes and to allow it to make payments under the Tax Receivable Agreements, (ii) tax advances, which will be repaid upon exercise of the Redemption Right or the Call Right, as applicable, in an amount sufficient to allow each of the Liberty Unit Holders to pay its respective taxes on such holder’s allocable share of Liberty LLC’s taxable income after taking into account certain other distributions or payments received by the Liberty Unit Holders from Liberty LLC or Liberty Inc., and (iii) non-pro rata payments to Liberty Inc. to reimburse it for its corporate and other overhead expenses. 
+Issuance of Equity 
+The Liberty LLC Agreement provides that, except as otherwise determined by us, at any time Liberty Inc. issues a share of its Class A Common Stock or any other equity security, the net proceeds received by Liberty Inc. with respect to such issuance, if any, shall be concurrently invested in Liberty LLC, and Liberty LLC shall issue to Liberty Inc. one Liberty LLC 
+72 
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+Unit or other economically equivalent equity interest. Conversely, if at any time, any shares of Liberty Inc.’s Class A Common Stock are redeemed, repurchased or otherwise acquired, Liberty LLC shall redeem, repurchase or otherwise acquire an equal number of Liberty LLC Units held by Liberty Inc., upon the same terms and for the same price, as the shares of our Class A Common Stock are redeemed, repurchased or otherwise acquired. 
+Competition 
+Under the Liberty LLC Agreement, the members have agreed that the Riverstone and its affiliates will be permitted to engage in business activities or invest in or acquire businesses which may compete with our business or do business with our customers. 
+Dissolution 
+Liberty LLC will be dissolved only upon the first to occur of (i) the sale of substantially all of its assets or (ii) an election by us to dissolve the company. Upon dissolution, Liberty LLC will be liquidated and the proceeds from any liquidation will be applied and distributed in the following manner: (a) first, to creditors (including to the extent permitted by law, creditors who are members) in satisfaction of the liabilities of Liberty LLC, (b) second, to establish cash reserves for contingent or unforeseen liabilities and (c) third, to the members in proportion to the number of Liberty LLC Units owned by each of them. 
+Tax Receivable Agreements 
+As described in “Item 1. Business—Initial Public Offering and Reorganization Transaction,” Liberty Inc. acquired Liberty LLC Units from certain of the Liberty Unit Holders in exchange for cash. In addition, the Liberty Unit Holders may redeem their Liberty LLC Units for shares of Class A Common Stock or cash, as applicable, in the future pursuant to the Redemption Right or the Call Right. Liberty LLC intends to make for itself (and for each of its direct or indirect subsidiaries that is treated as a partnership for U.S. federal income tax purposes and that it controls) an election under Section 754 of the Code that will be effective for this taxable year (year of the IPO) and each taxable year in which a redemption of Liberty LLC Units pursuant to the Redemption Right or the Call Right occurs. Pursuant to the Section 754 election, our acquisition (or deemed acquisition for U.S. federal income tax purposes) of Liberty LLC Units for cash as a part of the Corporate Reorganization and redemptions of Liberty LLC Units pursuant to the Redemption Right or the Call Right are expected to result in adjustments to the tax basis of the tangible and intangible assets of Liberty LLC. These adjustments will be allocated to Liberty Inc. Such adjustments to the tax basis of the tangible and intangible assets of Liberty LLC would not have been available to Liberty Inc. absent its acquisition or deemed acquisition of Liberty LLC Units as a part of the Corporate Reorganization or pursuant to the exercise of the Redemption Right or the Call Right. The anticipated basis adjustments are expected to increase (for U.S. federal income tax purposes) Liberty Inc.’s depreciation, depletion and amortization deductions and may also decrease Liberty Inc.’s gains (or increase its losses) on future dispositions of certain assets to the extent tax basis is allocated to those assets. Such increased deductions and losses and reduced gains may reduce the amount of tax that Liberty Inc. would otherwise be required to pay in the future. 
+In connection with the IPO, Liberty Inc. entered into two Tax Receivable Agreements with the TRA Holders. The first of the Tax Receivable Agreements, which Liberty Inc. entered into with the Liberty Unit Holders, generally provides for the payment by Liberty Inc. to such TRA Holders of 85% of the net cash savings, if any, in U.S. federal, state and local income and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that Liberty Inc. actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result of, as applicable to each such TRA Holder, (i) certain increases in tax basis that occur as a result of Liberty Inc.’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holder’s Liberty LLC Units in connection with the IPO or pursuant to the exercise of the Redemption Right or Liberty Inc.’s Call Right and (ii) imputed interest deemed to be paid by Liberty Inc. as a result of, and additional tax basis arising from, any payments Liberty Inc. makes under such Tax Receivable Agreement. The second of the Tax Receivable Agreements, which Liberty Inc. entered into with the selling shareholder, generally provides for the payment by Liberty Inc. to such TRA Holder of 85% of the net cash savings, if any, in U.S. federal, state and local income and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that Liberty Inc. actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result of, as applicable to such TRA Holder, (i) any net operating losses available to Liberty Inc. as a result of the Corporate Reorganization and (ii) imputed interest deemed to be paid by Liberty Inc. as a result of any payments Liberty Inc. makes under such Tax Receivable Agreement. For further discussion regarding the potential acceleration of payments under the Tax Receivable Agreements and its potential impact, please read “Risk Factors—Risks Related to Our Class A Common Stock.” 
+As described in “Item 1. Business—Initial Public Offering and Reorganization Transaction,” Liberty Inc. acquired Liberty LLC Units from certain of the Liberty Unit Holders in exchange for cash. In addition, the Liberty Unit Holders may redeem their Liberty LLC Units for shares of Class A Common Stock or cash, as applicable, in the future pursuant to the Redemption Right or our Call Right. 
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+The Tax Receivable Agreements are incorporated by reference to the Current Report on Form 8-K, filed on January 18, 2018. 
+Stockholders’ Agreement 
+We are party to a stockholders’ agreement with the Principal Stockholders. Among other things, the stockholders’ agreement provides the right to designate nominees to our board of directors as follows: 
+• 
+so long as Riverstone and its affiliates collectively own at least 35% of our Class A Common Stock, Riverstone can designate up to five nominees to our board of directors, with the board size decreasing by one director when Riverstone and its affiliates no longer own at least 35% of our Class A Common Stock; 
+• 
+so long as Riverstone and its affiliates collectively own at least 30% of our Class A Common Stock, Riverstone can designate up to four nominees to our board of directors; 
+• 
+so long as Riverstone and its affiliates collectively own at least 20% of our Class A Common Stock but less than 30% of our Class A Common Stock, Riverstone can designate up to two nominees to our board of directors; and 
+• 
+so long as Riverstone and its affiliates collectively own at least 10% of our Class A Common Stock but less than 20% of our Class A common stock, Riverstone can designate up to one nominee to our board of directors. 
+Pursuant to the stockholders’ agreement we and the Principal Stockholders will be required to take all necessary actions, to the fullest extent permitted by applicable law (including with respect to any fiduciary duties under Delaware law), to cause the election of the nominees designated by Riverstone. At any time the members of our board of directors are allocated among separate classes of directors, (i) the directors designated by Riverstone pursuant to the stockholders’ agreement will be in different classes of directors to the extent practicable and (ii) Riverstone will be permitted to designate the class or classes to which each such director will be allocated. Riverstone will be entitled to designate the replacement for any of its board designees whose board service terminates prior to the end of such director’s term. Riverstone has the right to nominate another member to our board of directors. 
+In addition, the stockholders’ agreement provides that for so long as the Principal Stockholders and their affiliates own at least 20% of the outstanding shares of our Class A Common Stock, Riverstone will have the right to cause any committee of our board of directors to include in its membership at least one director designated by Riverstone, except to the extent that such membership would violate applicable securities laws or stock exchange rules. The rights granted to Riverstone to designate directors are additive to and not intended to limit in any way the rights that Riverstone or any of its affiliates may have to nominate, elect or remove our directors under our certificate of incorporation, bylaws or the DGCL. 
+Furthermore, so long as Riverstone and its affiliates collectively own at least 20% of the outstanding shares of Class A Common Stock, we have agreed not to take, and will take all necessary action to cause our subsidiaries not to take, the following direct or indirect actions (or enter into an agreement to take such actions) without the prior consent of Riverstone: 
+• 
+any material change, through any acquisition, disposition of assets or otherwise, in the nature of our business or operations and our subsidiaries as of the date of the stockholders’ agreement; 
+• 
+hiring or terminating our chief executive officer or the chief financial officer and their respective successors; 
+• 
+any transaction that, if consummated, would constitute a Change of Control (as defined in the stockholders’ agreement) or entering into any definitive agreement or series of related agreements that govern any transaction or series of related transactions that, if consummated, would result in a Change of Control; 
+• 
+entering into any agreement providing for certain acquisitions or dispositions, in each such case, involving consideration payable or receivable by us or any of our subsidiaries in excess of $100 million in the aggregate in any single transaction or series of related transactions during any 12-month period; 
+• 
+any incurrence by us or any of our subsidiaries of indebtedness for borrowed money (including through capital leases, the issuance of debt securities or the guarantee of indebtedness of another Person) in excess of $100 million in the aggregate in any single transaction or series of related transactions during any 12-month period; 
+• 
+any issuance or series of related issuances of equity securities by us or any of our subsidiaries for an aggregate consideration in excess of $100 million; 
+• 
+any payment or declaration of any dividend or other distribution of any shares of Class A Common Stock or entering into any recapitalization transaction the primary purpose of which is to pay a dividend; 
+• 
+any increase or decrease in the size of our board of directors, committees of the board of directors, and board and committees of our subsidiaries; 
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+• 
+settling any litigation to which we or any of our subsidiaries is a party involving the payment by us or any of our subsidiaries of an aggregate amount equal to or greater than $25 million; 
+• 
+entering into any joint venture or similar business alliance involving investment, contribution or disposition by us or any of our subsidiaries of assets (including stock of subsidiaries) having an aggregate fair market value in excess of $100 million, other than transactions solely between and among us and our wholly owned subsidiaries; and 
+• 
+any amendment, modification or waiver of our certificate of incorporation, bylaws or any other governing document following the date of the stockholders’ agreement that (i) causes the number of board of director seats to be less than or greater than nine (although the current size of the board of directors, as ratified by the Riverstone directors, is eight) or (ii) materially and adversely affects any Principal Stockholder. 
+Registration Rights Agreement 
+In connection with the closing of the IPO, we entered into a registration rights agreement with the Legacy Owners. The agreement contains provisions by which we agree to register under the federal securities laws the offer and resale of shares of our Class A Common Stock by the Legacy Owners or certain of their affiliates or permitted transferees under the registration rights agreement. These registration rights will be subject to certain conditions and limitations. We will generally be obligated to pay all registration expenses in connection with these registration obligations, regardless of whether a registration statement is filed or becomes effective. 
+Historical Transactions with Affiliates 
+Advisory Services Agreement 
+Liberty Holdings entered into an advisory agreement, dated December 30, 2011, with Riverstone, in which Riverstone agreed to provide certain administrative advisory services to us. The service fees incurred to Riverstone, and reflected in the financials of our accounting predecessor, for the years ended December 31, 2017 , 2016 and 2015 were approximately $1.5 million , $0.5 million and $0.4 million , respectively and accrued as of December 31, 2017 and 2016 were $2.0 million and $0.5 million , respectively. We do not expect to incur future expense under this agreement. 
+Transactions with Liberty Resources 
+In September 2011, Liberty Resources entered into a services agreement (the “Services Agreement”) with LOS whereby Liberty Resources is to provide certain administrative support functions to Liberty Services. Liberty Resources also entered into a master service agreement with Liberty Services whereby LOS provides hydraulic fracturing service to Liberty Resources at market service rates. The amount incurred under the Services Agreement by LOS during the years ended December 31, 2017 , 2016 and 2015 was approximately $0 , $0.1 million and $0.2 million , respectively, and there were no outstanding balances for the respective periods. The amounts related to the provision of hydraulic fracturing services to Liberty Resources under the master services agreement for the years ended December 31, 2017 , 2016 and 2015 were approximately $24.7 million , $13.1 million and $28.8 million , respectively. Amounts reflected in accounts receivable from Liberty Resources were $4.0 million and $0 and of December 31, 2017 and 2016 , respectively, and $0.1 million and $2.5 million in unbilled revenue as of December 31, 2017 and 2016 , respectively. 
+Services to Zavanna, LLC 
+LOS provided hydraulic fracturing services under a standard master services agreement at market rates to Zavanna, LLC, an E&P company that partially owned one of Liberty Holdings’ investors through October 2016. For the years ended December 31, 2016 and 2015 , LOS derived revenue of approximately $4.8 million and $42.3 million , respectively. Amounts due from Zavanna as of December 31, 2016 and 2015 were $4.8 million and $0.5 million , respectively, and as of and for the year ended December 31, 2017 , Zavanna is no longer an affiliate. 
+PropX 
+During 2016, Liberty Holdings committed to make an investment and become a non-controlling minority member in Proppant Express Investments, LLC, (“PropX Investments”) the owner of PropX, a provider of proppant logistics equipment. LOS is party to a services agreement (the “PropX Services Agreement”) whereby LOS is to provide certain administrative support functions to PropX, and LOS is to purchase and lease proppant logistics equipment from PropX at market rates. Receivables from PropX as of December 31, 2017 and 2016 were $0 and $0.2 million , respectively. For the year ended December 31, 2017 the Company purchased and leased proppant logistics equipment of $13.5 million and $2.2 million . Payables to PropX as of December 31, 2017 and 2016 were $0.7 million and $0 , respectively. 
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+Bridge Loan 
+During the second quarter of 2017, ACQI entered into the Bridge Loan with the Bridge Loan Lenders. The Bridge Loan was to mature on October 10, 2017, unless earlier terminated in connection with an initial public offering, and provided for interest at 12% per annum. In June 2017, in connection with our entry into an amendment to our Prior Credit Facility, the Bridge Loan and accrued interest payable of $60.8 million were assigned from the Bridge Loan Lenders to Liberty Holdings and ACQI’s obligation under the Bridge Loan was canceled in exchange for 60,761,000 Redeemable Class 2 Common Units issued to Liberty Holdings. The Redeemable Class 2 Common Units were redeemed by ACQI on September 19, 2017 for, including accrued return, $62.7 million . 
+Conflicts of Interest 
+The related party transactions described above may cause certain conflicts of interests, including that: 
+• 
+we may enter into contracts between us, on the one hand, and related parties, on the other, that are not as a result of arm’s-length transactions; 
+• 
+our executive officers and directors that hold positions of responsibility with related parties may be aware of certain business opportunities that are appropriate for presentation to us as well as to such other related parties and may present such business opportunities to such other parties; and 
+• 
+our executive officers and directors that hold positions of responsibility with related parties may have significant duties with, and spend significant time serving, other entities and may have conflicts of interest in allocating time. 
+For example, Christopher Wright, our Chief Executive Officer, is the Executive Chairman of Liberty Resources LLC, a position which may require a significant portion of his time and which may cause conflicts of interest in pursuing business opportunities of which he becomes aware. Furthermore, our governing documents provide that Riverstone and its respective affiliates (including portfolio investments of its affiliates) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. Riverstone or its respective affiliates may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Furthermore, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to not be available to us or causing them to be more expensive for us to pursue. In addition, Riverstone or its respective affiliates may dispose of oil and gas service or other assets in the future, without any obligation to offer us the opportunity to purchase any of those assets. Please see “Item 1A. Risk Factors—Risks Related to Our Business—We engage in transactions with related parties and such transactions present possible conflicts of interest that could have an adverse effect on us,” “Item 1A. Risk Factors—Risks Related to Our Class A Common Stock—Certain of our executive officers and directors have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities” and “Item 1A. Risk Factors—Risks Related to Our Class A Common Stock—Riverstone and its respective affiliates are not limited in their ability to compete with us, and the corporate opportunity provisions in our amended and restated certificate of incorporation could enable Riverstone to benefit from corporate opportunities that might otherwise be available to us.” 
+Policies and Procedures for Review of Related Party Transactions 
+A “Related Party Transaction” is a transaction, arrangement or relationship in which we or any of our subsidiaries was, is or will be a participant, the amount of which involved exceeds $120,000, and in which any related person had, has or will have a direct or indirect material interest. A “Related Person” means: 
+• 
+any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors; 
+• 
+any person who is known by us to be the beneficial owner of more than 5.0% of our Class A Common Stock; 
+• 
+any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, executive officer or a beneficial owner of more than 5.0% of our Class A Common Stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5.0% of our Class A common stock; and 
+• 
+any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10.0% or greater beneficial ownership interest. 
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+Our board of directors adopted a written related party transactions policy in connection with the IPO. Pursuant to this policy, our audit committee will review all material facts of all Related Party Transactions and either approve or disapprove entry into the Related Party Transaction, subject to certain limited exceptions. In determining whether to approve or disapprove entry into a Related Party Transaction, our audit committee shall take into account, among other factors, the following: (i) whether the Related Party Transaction is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances and (ii) the extent of the Related Person’s interest in the transaction. Furthermore, the policy requires that all Related Party Transactions required to be disclosed in our filings with the SEC be so disclosed in accordance with applicable laws, rules and regulations. 
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+Item 9A. Controls and Procedures 
+Management’s Report on Internal Control Over Financial Reporting 
+This Annual Report on Form 10-K does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of the Company's registered public accounting firm due to a transition period established by the SEC for newly public companies. 
+We have identified a material weakness in our internal control over financial reporting as of December 31, 2017, which was also identified and communicated to us by our independent registered public accounting firm. A “material weakness” is a deficiency, or combination of deficiencies, in internal controls such that there is a reasonable possibility that a material misstatement in financial statements will not be prevented or detected on a timely basis. 
+The material weakness identified relates to the lack of implementation and maintenance of effective segregation of duties, including controls over journal entries, that would provide a reasonable possibility that a material misstatement would not be prevented or detected on a timely basis. 
+In early 2018, we began taking steps to implement controls to remediate the material weakness, including the following: 
+• 
+utilizing information technology personnel to review system authorization among users to ensure proper segregation of duties; and 
+• 
+engagement of a third party to assist in our documentation, implementation and testing of internal controls related to segregation of duties, including controls over journal entries. 
+Evaluation of Disclosure Controls and Procedures 
+Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report on Form 10-K. The evaluation included certain internal control areas in which we have made and are continuing to make changes to improve and enhance controls. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to management, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure. Based on such evaluation, our principal executive officer and principal financial officer concluded that, as of December 31, 2017, our disclosure controls and procedures were effective, at the reasonable assurance level. Any controls and procedures, no matter how well designed and operated can only provide reasonable assurance of achieving the desired control objective and management necessarily applies its judgment in evaluating the cost-benefit relationship of all possible controls and procedures. 
+Notwithstanding the material weakness discussed above, management believes, based upon the substantive work performed, that our consolidated financial statements included in this Annual Report on Form 10-K fairly present in all material respects our financial condition, results of operations and cash flows at and for the periods presented in accordance with GAAP and that the other information required to be disclosed by us in this Annual Report on Form 10-K is complete and accurate in all material respects. 
+Changes in Internal Control Over Financial Reporting 
+Other than as described above, there were no changes in our internal control over financial reporting during the quarter ended December 31, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+57 
+Table of Contents 
+Attestation Report of the Registered Public Accounting Firm 
+This Annual Report on Form 10-K does not include an attestation report of our independent registered public accounting firm due to a transition period established by the rules of the SEC for newly public companies.
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diff --git a/raw/filings/0001694028/2017/0001628280-18-003509/rpt_disclosure.txt b/raw/filings/0001694028/2017/0001628280-18-003509/rpt_disclosure.txt
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+Item 13. Certain Relationships and Related Transactions, and Director Independence 
+The following discussion is a brief summary of certain material arrangements, agreements and transactions we have with related parties. It does not include all of the provisions of our material arrangements, agreements and transactions with related parties, does not purport to be complete and is qualified in its entirety by reference to the arrangements, agreements and transactions described. 
+IPO-Related Agreements 
+In connection with our Corporate Reorganization, we engaged in transactions with affiliates, such as Liberty LLC, and our Legacy Owners and entered into the agreements detailed herein. See also “Item 1. Business—Initial Public Offering and Reorganization Transactions” for a description of these transactions. 
+Liberty LLC Agreement 
+We entered into the Liberty LLC Agreement in connection with the closing of the IPO, which provides for limitations on the ability of Liberty Unit Holders to transfer their Liberty LLC Units and provides Liberty Inc., as managing member of Liberty LLC, with the right to impose restrictions (in addition to those already in place) on the ability of Liberty Unit Holders to redeem their Liberty LLC Units pursuant to the Redemption Right to the extent Liberty Inc. believes it is necessary to ensure that Liberty LLC will continue to be treated as a partnership for U.S. federal income tax purposes. 
+Redemption Rights 
+Under the Liberty LLC Agreement, each Liberty Unit Holder has, subject to certain limitations, the right to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units for, at Liberty LLC’s election, (i) shares of our Class A Common Stock at a redemption ratio of one share of Class A Common Stock for each Liberty LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions or (ii) an equivalent amount of cash. Alternatively, upon the exercise of the Redemption Right, Liberty Inc. (instead of Liberty LLC) will have the right to, for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder for, at its election, (x) one share of Class A Common Stock or (y) an equivalent amount of cash. In addition, upon a change of control of Liberty Inc., Liberty Inc. has the right to require each holder of Liberty LLC Units (other than Liberty Inc.) to exercise its Redemption Right with respect to some or all of such unit holder’s Liberty LLC Units. In connection with any redemption of Liberty LLC Units pursuant to the Redemption Right or our Call Right, the corresponding number of shares of Class B Common Stock will be cancelled. As the Liberty Unit Holders redeem their Liberty LLC Units, our membership interest in Liberty LLC will be correspondingly increased, the number of shares of Class A Common Stock outstanding will be increased, and the number of shares of Class B Common Stock outstanding will be reduced. 
+Distributions and Allocations 
+Under the Liberty LLC Agreement, Liberty Inc. has the right to determine when distributions will be made to the holders of Liberty LLC Units and the amount of any such distributions. If Liberty Inc. authorizes a distribution, such distribution will be made to the holders of Liberty LLC Units generally on a pro rata basis in accordance with their respective percentage ownership of Liberty LLC Units. 
+Liberty LLC will allocate its net income or net loss for each year to the holders of Liberty LLC Units pursuant to the terms of the Liberty LLC Agreement, and the holders of Liberty LLC Units, including Liberty Inc., will generally incur U.S. federal, state and local income taxes on their share of any taxable income of Liberty LLC. Net income and losses of Liberty LLC generally will be allocated to the holders of Liberty LLC Units on a pro rata basis in accordance with their respective percentage ownership of Liberty LLC Units, subject to requirements under U.S. federal income tax law that certain items of income, gain, loss or deduction be allocated disproportionately in certain circumstances. To the extent Liberty LLC has available cash and subject to the terms of any future debt instruments, Liberty Inc. intends to cause Liberty LLC to make (i) generally pro rata distributions to the holders of Liberty LLC Units, including Liberty Inc., in an amount sufficient to allow Liberty Inc. to pay its taxes and to allow it to make payments under the Tax Receivable Agreements, (ii) tax advances, which will be repaid upon exercise of the Redemption Right or the Call Right, as applicable, in an amount sufficient to allow each of the Liberty Unit Holders to pay its respective taxes on such holder’s allocable share of Liberty LLC’s taxable income after taking into account certain other distributions or payments received by the Liberty Unit Holders from Liberty LLC or Liberty Inc., and (iii) non-pro rata payments to Liberty Inc. to reimburse it for its corporate and other overhead expenses. 
+Issuance of Equity 
+The Liberty LLC Agreement provides that, except as otherwise determined by us, at any time Liberty Inc. issues a share of its Class A Common Stock or any other equity security, the net proceeds received by Liberty Inc. with respect to such issuance, if any, shall be concurrently invested in Liberty LLC, and Liberty LLC shall issue to Liberty Inc. one Liberty LLC 
+72 
+Table of Contents 
+Unit or other economically equivalent equity interest. Conversely, if at any time, any shares of Liberty Inc.’s Class A Common Stock are redeemed, repurchased or otherwise acquired, Liberty LLC shall redeem, repurchase or otherwise acquire an equal number of Liberty LLC Units held by Liberty Inc., upon the same terms and for the same price, as the shares of our Class A Common Stock are redeemed, repurchased or otherwise acquired. 
+Competition 
+Under the Liberty LLC Agreement, the members have agreed that the Riverstone and its affiliates will be permitted to engage in business activities or invest in or acquire businesses which may compete with our business or do business with our customers. 
+Dissolution 
+Liberty LLC will be dissolved only upon the first to occur of (i) the sale of substantially all of its assets or (ii) an election by us to dissolve the company. Upon dissolution, Liberty LLC will be liquidated and the proceeds from any liquidation will be applied and distributed in the following manner: (a) first, to creditors (including to the extent permitted by law, creditors who are members) in satisfaction of the liabilities of Liberty LLC, (b) second, to establish cash reserves for contingent or unforeseen liabilities and (c) third, to the members in proportion to the number of Liberty LLC Units owned by each of them. 
+Tax Receivable Agreements 
+As described in “Item 1. Business—Initial Public Offering and Reorganization Transaction,” Liberty Inc. acquired Liberty LLC Units from certain of the Liberty Unit Holders in exchange for cash. In addition, the Liberty Unit Holders may redeem their Liberty LLC Units for shares of Class A Common Stock or cash, as applicable, in the future pursuant to the Redemption Right or the Call Right. Liberty LLC intends to make for itself (and for each of its direct or indirect subsidiaries that is treated as a partnership for U.S. federal income tax purposes and that it controls) an election under Section 754 of the Code that will be effective for this taxable year (year of the IPO) and each taxable year in which a redemption of Liberty LLC Units pursuant to the Redemption Right or the Call Right occurs. Pursuant to the Section 754 election, our acquisition (or deemed acquisition for U.S. federal income tax purposes) of Liberty LLC Units for cash as a part of the Corporate Reorganization and redemptions of Liberty LLC Units pursuant to the Redemption Right or the Call Right are expected to result in adjustments to the tax basis of the tangible and intangible assets of Liberty LLC. These adjustments will be allocated to Liberty Inc. Such adjustments to the tax basis of the tangible and intangible assets of Liberty LLC would not have been available to Liberty Inc. absent its acquisition or deemed acquisition of Liberty LLC Units as a part of the Corporate Reorganization or pursuant to the exercise of the Redemption Right or the Call Right. The anticipated basis adjustments are expected to increase (for U.S. federal income tax purposes) Liberty Inc.’s depreciation, depletion and amortization deductions and may also decrease Liberty Inc.’s gains (or increase its losses) on future dispositions of certain assets to the extent tax basis is allocated to those assets. Such increased deductions and losses and reduced gains may reduce the amount of tax that Liberty Inc. would otherwise be required to pay in the future. 
+In connection with the IPO, Liberty Inc. entered into two Tax Receivable Agreements with the TRA Holders. The first of the Tax Receivable Agreements, which Liberty Inc. entered into with the Liberty Unit Holders, generally provides for the payment by Liberty Inc. to such TRA Holders of 85% of the net cash savings, if any, in U.S. federal, state and local income and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that Liberty Inc. actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result of, as applicable to each such TRA Holder, (i) certain increases in tax basis that occur as a result of Liberty Inc.’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holder’s Liberty LLC Units in connection with the IPO or pursuant to the exercise of the Redemption Right or Liberty Inc.’s Call Right and (ii) imputed interest deemed to be paid by Liberty Inc. as a result of, and additional tax basis arising from, any payments Liberty Inc. makes under such Tax Receivable Agreement. The second of the Tax Receivable Agreements, which Liberty Inc. entered into with the selling shareholder, generally provides for the payment by Liberty Inc. to such TRA Holder of 85% of the net cash savings, if any, in U.S. federal, state and local income and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that Liberty Inc. actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result of, as applicable to such TRA Holder, (i) any net operating losses available to Liberty Inc. as a result of the Corporate Reorganization and (ii) imputed interest deemed to be paid by Liberty Inc. as a result of any payments Liberty Inc. makes under such Tax Receivable Agreement. For further discussion regarding the potential acceleration of payments under the Tax Receivable Agreements and its potential impact, please read “Risk Factors—Risks Related to Our Class A Common Stock.” 
+As described in “Item 1. Business—Initial Public Offering and Reorganization Transaction,” Liberty Inc. acquired Liberty LLC Units from certain of the Liberty Unit Holders in exchange for cash. In addition, the Liberty Unit Holders may redeem their Liberty LLC Units for shares of Class A Common Stock or cash, as applicable, in the future pursuant to the Redemption Right or our Call Right. 
+73 
+Table of Contents 
+The Tax Receivable Agreements are incorporated by reference to the Current Report on Form 8-K, filed on January 18, 2018. 
+Stockholders’ Agreement 
+We are party to a stockholders’ agreement with the Principal Stockholders. Among other things, the stockholders’ agreement provides the right to designate nominees to our board of directors as follows: 
+• 
+so long as Riverstone and its affiliates collectively own at least 35% of our Class A Common Stock, Riverstone can designate up to five nominees to our board of directors, with the board size decreasing by one director when Riverstone and its affiliates no longer own at least 35% of our Class A Common Stock; 
+• 
+so long as Riverstone and its affiliates collectively own at least 30% of our Class A Common Stock, Riverstone can designate up to four nominees to our board of directors; 
+• 
+so long as Riverstone and its affiliates collectively own at least 20% of our Class A Common Stock but less than 30% of our Class A Common Stock, Riverstone can designate up to two nominees to our board of directors; and 
+• 
+so long as Riverstone and its affiliates collectively own at least 10% of our Class A Common Stock but less than 20% of our Class A common stock, Riverstone can designate up to one nominee to our board of directors. 
+Pursuant to the stockholders’ agreement we and the Principal Stockholders will be required to take all necessary actions, to the fullest extent permitted by applicable law (including with respect to any fiduciary duties under Delaware law), to cause the election of the nominees designated by Riverstone. At any time the members of our board of directors are allocated among separate classes of directors, (i) the directors designated by Riverstone pursuant to the stockholders’ agreement will be in different classes of directors to the extent practicable and (ii) Riverstone will be permitted to designate the class or classes to which each such director will be allocated. Riverstone will be entitled to designate the replacement for any of its board designees whose board service terminates prior to the end of such director’s term. Riverstone has the right to nominate another member to our board of directors. 
+In addition, the stockholders’ agreement provides that for so long as the Principal Stockholders and their affiliates own at least 20% of the outstanding shares of our Class A Common Stock, Riverstone will have the right to cause any committee of our board of directors to include in its membership at least one director designated by Riverstone, except to the extent that such membership would violate applicable securities laws or stock exchange rules. The rights granted to Riverstone to designate directors are additive to and not intended to limit in any way the rights that Riverstone or any of its affiliates may have to nominate, elect or remove our directors under our certificate of incorporation, bylaws or the DGCL. 
+Furthermore, so long as Riverstone and its affiliates collectively own at least 20% of the outstanding shares of Class A Common Stock, we have agreed not to take, and will take all necessary action to cause our subsidiaries not to take, the following direct or indirect actions (or enter into an agreement to take such actions) without the prior consent of Riverstone: 
+• 
+any material change, through any acquisition, disposition of assets or otherwise, in the nature of our business or operations and our subsidiaries as of the date of the stockholders’ agreement; 
+• 
+hiring or terminating our chief executive officer or the chief financial officer and their respective successors; 
+• 
+any transaction that, if consummated, would constitute a Change of Control (as defined in the stockholders’ agreement) or entering into any definitive agreement or series of related agreements that govern any transaction or series of related transactions that, if consummated, would result in a Change of Control; 
+• 
+entering into any agreement providing for certain acquisitions or dispositions, in each such case, involving consideration payable or receivable by us or any of our subsidiaries in excess of $100 million in the aggregate in any single transaction or series of related transactions during any 12-month period; 
+• 
+any incurrence by us or any of our subsidiaries of indebtedness for borrowed money (including through capital leases, the issuance of debt securities or the guarantee of indebtedness of another Person) in excess of $100 million in the aggregate in any single transaction or series of related transactions during any 12-month period; 
+• 
+any issuance or series of related issuances of equity securities by us or any of our subsidiaries for an aggregate consideration in excess of $100 million; 
+• 
+any payment or declaration of any dividend or other distribution of any shares of Class A Common Stock or entering into any recapitalization transaction the primary purpose of which is to pay a dividend; 
+• 
+any increase or decrease in the size of our board of directors, committees of the board of directors, and board and committees of our subsidiaries; 
+74 
+Table of Contents 
+• 
+settling any litigation to which we or any of our subsidiaries is a party involving the payment by us or any of our subsidiaries of an aggregate amount equal to or greater than $25 million; 
+• 
+entering into any joint venture or similar business alliance involving investment, contribution or disposition by us or any of our subsidiaries of assets (including stock of subsidiaries) having an aggregate fair market value in excess of $100 million, other than transactions solely between and among us and our wholly owned subsidiaries; and 
+• 
+any amendment, modification or waiver of our certificate of incorporation, bylaws or any other governing document following the date of the stockholders’ agreement that (i) causes the number of board of director seats to be less than or greater than nine (although the current size of the board of directors, as ratified by the Riverstone directors, is eight) or (ii) materially and adversely affects any Principal Stockholder. 
+Registration Rights Agreement 
+In connection with the closing of the IPO, we entered into a registration rights agreement with the Legacy Owners. The agreement contains provisions by which we agree to register under the federal securities laws the offer and resale of shares of our Class A Common Stock by the Legacy Owners or certain of their affiliates or permitted transferees under the registration rights agreement. These registration rights will be subject to certain conditions and limitations. We will generally be obligated to pay all registration expenses in connection with these registration obligations, regardless of whether a registration statement is filed or becomes effective. 
+Historical Transactions with Affiliates 
+Advisory Services Agreement 
+Liberty Holdings entered into an advisory agreement, dated December 30, 2011, with Riverstone, in which Riverstone agreed to provide certain administrative advisory services to us. The service fees incurred to Riverstone, and reflected in the financials of our accounting predecessor, for the years ended December 31, 2017 , 2016 and 2015 were approximately $1.5 million , $0.5 million and $0.4 million , respectively and accrued as of December 31, 2017 and 2016 were $2.0 million and $0.5 million , respectively. We do not expect to incur future expense under this agreement. 
+Transactions with Liberty Resources 
+In September 2011, Liberty Resources entered into a services agreement (the “Services Agreement”) with LOS whereby Liberty Resources is to provide certain administrative support functions to Liberty Services. Liberty Resources also entered into a master service agreement with Liberty Services whereby LOS provides hydraulic fracturing service to Liberty Resources at market service rates. The amount incurred under the Services Agreement by LOS during the years ended December 31, 2017 , 2016 and 2015 was approximately $0 , $0.1 million and $0.2 million , respectively, and there were no outstanding balances for the respective periods. The amounts related to the provision of hydraulic fracturing services to Liberty Resources under the master services agreement for the years ended December 31, 2017 , 2016 and 2015 were approximately $24.7 million , $13.1 million and $28.8 million , respectively. Amounts reflected in accounts receivable from Liberty Resources were $4.0 million and $0 and of December 31, 2017 and 2016 , respectively, and $0.1 million and $2.5 million in unbilled revenue as of December 31, 2017 and 2016 , respectively. 
+Services to Zavanna, LLC 
+LOS provided hydraulic fracturing services under a standard master services agreement at market rates to Zavanna, LLC, an E&P company that partially owned one of Liberty Holdings’ investors through October 2016. For the years ended December 31, 2016 and 2015 , LOS derived revenue of approximately $4.8 million and $42.3 million , respectively. Amounts due from Zavanna as of December 31, 2016 and 2015 were $4.8 million and $0.5 million , respectively, and as of and for the year ended December 31, 2017 , Zavanna is no longer an affiliate. 
+PropX 
+During 2016, Liberty Holdings committed to make an investment and become a non-controlling minority member in Proppant Express Investments, LLC, (“PropX Investments”) the owner of PropX, a provider of proppant logistics equipment. LOS is party to a services agreement (the “PropX Services Agreement”) whereby LOS is to provide certain administrative support functions to PropX, and LOS is to purchase and lease proppant logistics equipment from PropX at market rates. Receivables from PropX as of December 31, 2017 and 2016 were $0 and $0.2 million , respectively. For the year ended December 31, 2017 the Company purchased and leased proppant logistics equipment of $13.5 million and $2.2 million . Payables to PropX as of December 31, 2017 and 2016 were $0.7 million and $0 , respectively. 
+75 
+Table of Contents 
+Bridge Loan 
+During the second quarter of 2017, ACQI entered into the Bridge Loan with the Bridge Loan Lenders. The Bridge Loan was to mature on October 10, 2017, unless earlier terminated in connection with an initial public offering, and provided for interest at 12% per annum. In June 2017, in connection with our entry into an amendment to our Prior Credit Facility, the Bridge Loan and accrued interest payable of $60.8 million were assigned from the Bridge Loan Lenders to Liberty Holdings and ACQI’s obligation under the Bridge Loan was canceled in exchange for 60,761,000 Redeemable Class 2 Common Units issued to Liberty Holdings. The Redeemable Class 2 Common Units were redeemed by ACQI on September 19, 2017 for, including accrued return, $62.7 million . 
+Conflicts of Interest 
+The related party transactions described above may cause certain conflicts of interests, including that: 
+• 
+we may enter into contracts between us, on the one hand, and related parties, on the other, that are not as a result of arm’s-length transactions; 
+• 
+our executive officers and directors that hold positions of responsibility with related parties may be aware of certain business opportunities that are appropriate for presentation to us as well as to such other related parties and may present such business opportunities to such other parties; and 
+• 
+our executive officers and directors that hold positions of responsibility with related parties may have significant duties with, and spend significant time serving, other entities and may have conflicts of interest in allocating time. 
+For example, Christopher Wright, our Chief Executive Officer, is the Executive Chairman of Liberty Resources LLC, a position which may require a significant portion of his time and which may cause conflicts of interest in pursuing business opportunities of which he becomes aware. Furthermore, our governing documents provide that Riverstone and its respective affiliates (including portfolio investments of its affiliates) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. Riverstone or its respective affiliates may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Furthermore, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to not be available to us or causing them to be more expensive for us to pursue. In addition, Riverstone or its respective affiliates may dispose of oil and gas service or other assets in the future, without any obligation to offer us the opportunity to purchase any of those assets. Please see “Item 1A. Risk Factors—Risks Related to Our Business—We engage in transactions with related parties and such transactions present possible conflicts of interest that could have an adverse effect on us,” “Item 1A. Risk Factors—Risks Related to Our Class A Common Stock—Certain of our executive officers and directors have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities” and “Item 1A. Risk Factors—Risks Related to Our Class A Common Stock—Riverstone and its respective affiliates are not limited in their ability to compete with us, and the corporate opportunity provisions in our amended and restated certificate of incorporation could enable Riverstone to benefit from corporate opportunities that might otherwise be available to us.” 
+Policies and Procedures for Review of Related Party Transactions 
+A “Related Party Transaction” is a transaction, arrangement or relationship in which we or any of our subsidiaries was, is or will be a participant, the amount of which involved exceeds $120,000, and in which any related person had, has or will have a direct or indirect material interest. A “Related Person” means: 
+• 
+any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors; 
+• 
+any person who is known by us to be the beneficial owner of more than 5.0% of our Class A Common Stock; 
+• 
+any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, executive officer or a beneficial owner of more than 5.0% of our Class A Common Stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5.0% of our Class A common stock; and 
+• 
+any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10.0% or greater beneficial ownership interest. 
+76 
+Table of Contents 
+Our board of directors adopted a written related party transactions policy in connection with the IPO. Pursuant to this policy, our audit committee will review all material facts of all Related Party Transactions and either approve or disapprove entry into the Related Party Transaction, subject to certain limited exceptions. In determining whether to approve or disapprove entry into a Related Party Transaction, our audit committee shall take into account, among other factors, the following: (i) whether the Related Party Transaction is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances and (ii) the extent of the Related Person’s interest in the transaction. Furthermore, the policy requires that all Related Party Transactions required to be disclosed in our filings with the SEC be so disclosed in accordance with applicable laws, rules and regulations. 
+77 
+Table of Contents
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+10-K
+1
+libertyoilfield1231201810-k.htm
+10-K
+Document 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+WASHINGTON, D.C. 20549 
+FORM 10-K 
+(Mark One) 
+☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the Fiscal Year Ended December 31, 2018 
+OR 
+☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+Commission File No. 001-38081 
+Liberty Oilfield Services Inc. 
+(Exact name of registrant as specified in its charter) 
+Delaware 
+81-4891595 
+(State or other jurisdiction of 
+incorporation or organization) 
+(I.R.S. Employer 
+Identification No.) 
+950 17 th Street, Suite 2400 
+Denver, Colorado 80202 
+80202 
+(Address of Principal Executive Offices) 
+(Zip Code) 
+(303) 515-2800 
+(Registrant’s telephone number, including area code) 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of each class 
+Class A Common Stock, par value $0.01 per share 
+Name of each exchange on which registered 
+New York Stock Exchange 
+Securities registered pursuant to Section 12(g) of the Act: None 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☒ Yes ☐ No 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐ Yes ☒ No 
+Indicate by check mark whether the registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No 
+Indicate by check mark whether the registrant has submitted electronically, every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this Chapter) during the presiding 12 months (or for such shorter period that the registrant was required to submit and post such files). ☒ Yes ☐ No 
+Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☐ 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. 
+Large accelerated filer ☐ 
+Accelerated filer ☐ 
+Non-accelerated filer ☒ 
+Smaller reporting company ☐ 
+Emerging growth company ☐ (Do not check if a smaller reporting company) 
+If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act): ☐ Yes ☒ No 
+As of June 29, 2018, the last business day of the registrant ’ s most recently completed second fiscal quarter, the aggregate market value of voting and non-voting common stock held by non-affiliates of the registrant was approximately $780.0 million, determined using the per share closing price on the New York Stock Exchange on that date of $18.72. Shares of common stock held by each director and executive officer (and their respective affiliates) and each person who owns 10 percent or more of the outstanding common stock or who is otherwise believed by the registrant to be in a control position have been excluded. This determination of affiliate status is not necessarily a conclusive determination for other purposes. 
+At February 26, 2019, the Registrant had 68,741,273 shares of Class A Common Stock and 43,572,803 shares of Class B Common Stock outstanding. 
+Documents Incorporated by Reference: Part III of this Annual Report on Form 10-K incorporates certain information by reference from the registrant ’ s proxy statement for the 2019 annual meeting of stockholders to be filed no later than 120 days after the end of the registrant ’ s fiscal year. 
+Table of Contents 
+TABLE OF CONTENTS 
+Page No. 
+PART I 
+Item 1. 
+Business 
+1 
+Item 1A. 
+Risk Factors 
+16 
+Item 1B. 
+Unresolved Staff Comments 
+38 
+Item 2. 
+Properties 
+38 
+Item 3. 
+Legal Proceeding 
+38 
+Item 4. 
+Mine Safety Disclosures 
+38 
+PART II 
+Item 5. 
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+39 
+Item 6. 
+Selected Consolidated Financial Data 
+40 
+Item 7. 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+42 
+Item 7A. 
+Quantitative and Qualitative Disclosure about Market Risk 
+55 
+Item 8. 
+Financial Statements and Supplementary Data 
+56 
+Item 9. 
+Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+56 
+Item 9A. 
+Controls and Procedures 
+56 
+Item 9B. 
+Other Information 
+57 
+PART III 
+Item 10. 
+Directors, Executive Officers and Corporate Governance 
+58 
+Item 11. 
+Executive Compensation 
+58 
+Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+58 
+Item 13. 
+Certain Relationships and Related Transactions, and Director Independence 
+58 
+Item 14. 
+Principal Accountant Fees and Services 
+58 
+PART IV 
+Item 15. 
+Exhibits and Financial Statement Schedules 
+59 
+Item 16. 
+Form 10-K Summary 
+60 
+SIGNATURES 
+64 
+i 
+Table of Contents 
+CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS 
+This Annual Report on Form 10-K and certain other communications made by us contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange of 1934, as amended (the “Exchange Act”), including statements about our growth, future operating results, estimates, beliefs and expected performance. For this purpose, any statement that is not a statement of historical fact should be considered a forward-looking statement. We may use the words “believe,” “anticipate,” “plan,” “expect,” “intend,” “may,” “will,” “should” and similar expressions to help identify forward-looking statements. We cannot assure you that our assumptions and expectations will prove to be correct. Important factors could cause our actual results to differ materially from those indicated or implied by forward-looking statements. We undertake no intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise and readers should not rely on the forward-looking statements as representing the Company’s views as of any date subsequent to the date of the filing of this Annual Report on Form 10-K. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. 
+Forward-looking statements may include statements about: 
+• 
+our business strategy; 
+• 
+our operating cash flows, the availability of capital and our liquidity; 
+• 
+our future revenue, income and operating performance; 
+• 
+our ability to sustain and improve our utilization, revenue and margins; 
+• 
+our ability to maintain acceptable pricing for our services; 
+• 
+our future capital expenditures; 
+• 
+our ability to finance equipment, working capital and capital expenditures; 
+• 
+competition and government regulations; 
+• 
+our ability to obtain permits and governmental approvals; 
+• 
+pending legal or environmental matters; 
+• 
+oil and natural gas prices; 
+• 
+acquisitions; 
+• 
+general economic conditions; 
+• 
+credit markets; 
+• 
+our ability to successfully develop our research and technology capabilities and implement technological developments and enhancements; 
+• 
+uncertainty regarding our future operating results; 
+• 
+return of capital to shareholders; and 
+• 
+plans, objectives, expectations and intentions contained in this Annual Report on Form 10-K that are not historical. 
+We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, decline in demand for our services, the cyclical nature and volatility of the oil and natural gas industry, a decline in, or substantial volatility of, crude oil and natural gas commodity prices, environmental risks, regulatory changes, the inability to comply with the financial and other covenants and metrics in our Credit Facilities (as defined herein), cash flow and access to capital, the timing of development expenditures and the other risks described under “Risk Factors” in this Annual Report on Form 10-K. 
+All forward-looking statements, expressed or implied, included in this Annual Report on Form 10-K are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. 
+This Annual Report on Form 10-K includes market and industry data and certain other statistical information based on third-party sources including independent industry publications, government publications and other publish independent sources, such as content and estimates provided by Coras Research, LLC as of December 31, 2018. Coras Research, LLC is not a member of the FINRA or the SIPC and is not a registered broker dealer or investment advisor. Although we believe these third-party sources are reliable as of their respective dates, we have not independently verified the accuracy or completeness of this information. Some data is also based on our own good faith estimates, which are supported by our management's knowledge of and experience in the markets and business in which we operate. 
+ii 
+Table of Contents 
+PART I 
+As used in this Annual Report on Form 10-K, unless the context otherwise requires, references to the term “Liberty Inc.” refers to Liberty Oilfield Services Inc. and references to the terms “Company,” “we,” “us” and “our” refer to, collectively, Liberty Oilfield Services LLC and LOS Acquisition Co I LLC and its subsidiaries (collectively, the “Predecessor”) for periods prior to the IPO (as defined herein), and, for periods as of and following the IPO, Liberty Inc. and its consolidated subsidiaries. References to “Liberty LLC” refer to Liberty Oilfield Services New HoldCo LLC. References to “Liberty Holdings” refer to Liberty Oilfield Services Holdings LLC. 
+Item 1. Business 
+Overview 
+We are an independent provider of hydraulic fracturing services to onshore oil and natural gas exploration and production (“E&P”) companies in North America. We provide our services primarily in the Permian Basin, the Eagle Ford Shale, the Denver-Julesburg Basin (the “DJ Basin”), the Williston Basin and the Powder River Basin. 
+Initial Public Offering and Corporate Reorganization Transaction 
+Liberty Inc. was incorporated as a Delaware corporation on December 21, 2016, to become a holding corporation for Liberty LLC and its subsidiaries upon completion of a corporate reorganization (as detailed below, the “Corporate Reorganization”) and planned initial public offering of the Company (“IPO”). The Company has no material assets other than its ownership in Liberty LLC. 
+On January 17, 2018, we completed our IPO of 14,640,755 shares of our Class A common stock, par value $0.01 per share (the “Class A Common Stock”) at a public offering price of $17.00 per share, of which 14,340,214 shares were offered by us and 300,541 shares were offered by the selling shareholder. We received approximately $220.0 million in net proceeds after deducting approximately $23.8 million of underwriting discounts and commissions and other offering costs. We did not receive any proceeds from the sale of the shares of Class A Common Stock by the selling shareholder. We used approximately $25.9 million of net proceeds from the IPO to redeem ownership in us from certain Legacy Owners (as defined below) and contributed the remaining proceeds to Liberty LLC in exchange for units in Liberty LLC (the “Liberty LLC Units”). Liberty LLC used a portion of the net proceeds (i) to fully repay our outstanding borrowings and accrued interest under our ABL Facility (as defined herein), totaling approximately $30.1 million , (ii) to repay 35% of our outstanding borrowings, accrued interest and prepayment premium under our Term Loan Facility (as defined herein), totaling approximately $62.5 million and (iii) for general corporate purposes, including repayment of additional indebtedness and funding capital expenditures. 
+We are a holding company with no direct operations. In connection with the IPO, we completed the Corporate Reorganization, including the following series of transactions: 
+• 
+Liberty Holdings contributed all of its assets to Liberty LLC in exchange for Liberty LLC Units; 
+• 
+Liberty Holdings liquidated and distributed to its then-existing owners (the “Legacy Owners”) Liberty LLC Units pursuant to the terms of the limited liability company agreement of Liberty Holdings and the Master Reorganization Agreement dated as of January 11, 2018, by and among the Company, Liberty Holdings, Liberty LLC, and the other parties named therein (the “Master Reorganization Agreement”); 
+• 
+Certain of the Legacy Owners directly or indirectly contributed all or a portion of their Liberty LLC Units to Liberty Inc. in exchange for 55,685,027 shares of our Class A Common Stock, and 1,258,514 shares of restricted stock. Subsequent to the initial exchange, 1,609,122 shares of Class A Common Stock were redeemed for an aggregate purchase price of $25.9 million upon the exercise of the underwriters' overallotment option; 
+• 
+Liberty Inc. issued the Legacy Owners that continued to own Liberty LLC Units (the “Liberty Unit Holders”) an aggregate amount of 48,207,372 shares of our Class B common stock, par value $0.01 per share (the “Class B Common Stock” and, together with the Class A Common Stock, the “Common Stock”); and 
+• 
+Liberty Inc. contributed the net proceeds it received from the IPO to Liberty LLC in exchange for additional Liberty LLC Units such that Liberty Inc. held a total number of Liberty LLC Units equal to the number of shares of Class A Common Stock outstanding immediately following the IPO. 
+1 
+Table of Contents 
+The below structure chart shows our organization upon the completion of our IPO. This chart is provided for illustrative purposes only and, does not represent all legal entities affiliated with us. 
+Each share of Class B Common Stock has no economic rights but entitles its holder to one vote on all matters to be voted on by shareholders generally. Holders of Class A Common Stock and Class B Common Stock will vote together as a single class on all matters presented to our shareholders for their vote or approval, except as otherwise required by applicable law or by our amended and restated certificate of incorporation. We do not intend to list our Class B Common Stock on any exchange. 
+Under the Second Amended and Restated Limited Liability Company Agreement of Liberty LLC (the “Liberty LLC Agreement”), each Liberty Unit Holder has, subject to certain limitations, the right (the “Redemption Right”) to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units for, at Liberty LLC’s election, (i) shares of our Class A Common Stock at a redemption ratio of one share of Class A Common Stock for each Liberty LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions or (ii) an equivalent amount of cash. Alternatively, upon the exercise of the Redemption Right, Liberty Inc. (instead of Liberty LLC) will have the right (the “Call Right”) to, for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder for, at its election, (x) one share of Class A Common Stock or (y) an equivalent amount of cash. In addition, upon a change of control of Liberty Inc., Liberty Inc. has the right to require each holder of Liberty LLC Units (other than Liberty Inc.) to exercise its Redemption Right with respect to some or all of such unit holder’s Liberty LLC Units. In connection with any redemption of Liberty LLC Units pursuant to the Redemption Right or the Call Right, the corresponding number of shares of Class B Common Stock will be canceled. 
+In connection with the IPO, Liberty Inc. entered into two tax receivable agreements, (the “TRAs”) with the Liberty Unit Holders and the selling shareholder (each such person and any permitted transferee, a “TRA Holder” and together, the “TRA Holders”). 
+The first of the TRAs, which Liberty Inc. entered into with the Liberty Unit Holders, generally provides for the payment by Liberty Inc. to such TRA Holders of 85% of the net cash savings, if any, in U.S. federal, state and local income and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that Liberty Inc. actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result of, as applicable to each such TRA 
+2 
+Table of Contents 
+Holder, (i) certain increases in tax basis that occur as a result of Liberty Inc.’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holder’s Liberty LLC Units in connection with the IPO or pursuant to the exercise of the Redemption Right or Liberty Inc.’s Call Right and (ii) imputed interest deemed to be paid by Liberty Inc. as a result of, and additional tax basis arising from, any payments Liberty Inc. makes under such TRAs. 
+The second of the TRAs, which Liberty Inc. entered into with the selling shareholder, generally provides for the payment by Liberty Inc. to such TRA Holder of 85% of the net cash savings, if any, in U.S. federal, state and local income and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that Liberty Inc. actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result of, as applicable to such TRA Holder, (i) any net operating losses available to Liberty Inc. as a result of the Corporate Reorganization and (ii) imputed interest deemed to be paid by Liberty Inc. as a result of any payments Liberty Inc. makes under such TRAs. For further discussion regarding the potential acceleration of payments under the TRAs and its potential impact, please read “Risk Factors—Risks Related to Our Class A Common Stock.” 
+Because Liberty Inc. is a holding company with no operations of its own, Liberty Inc.’s ability to make payments under the TRAs is dependent on the ability of Liberty LLC to make distributions to Liberty Inc. in an amount sufficient to cover its obligations under the TRAs. See “Risk Factors—Risks Related to Our Class A Common Stock—Liberty Inc. is a holding company. Liberty Inc.’s only material asset is its equity interest in Liberty LLC, and Liberty Inc. is accordingly dependent upon distributions from Liberty LLC to pay taxes, make payments under the TRAs and cover its corporate and other overhead expenses.” If Liberty Inc. experiences a change of control (as defined under the TRAs, which includes certain mergers, asset sales and other forms of business combinations) or the TRAs terminate early (at Liberty Inc.’s election or as a result of its breach), Liberty Inc. would be required to make a substantial, immediate lump-sum payment. 
+Our Company 
+We are an independent provider of hydraulic fracturing services to onshore oil and natural gas E&P companies in the United States. We have grown organically from one active hydraulic fracturing fleet in December 2011 to 22 active fleets in February 2019. We expect to take delivery of additional equipment in 2019. However, decisions whether or not to deploy these additional fleets in 2019 will be made considering customer demand, long term return profile and market conditions. We provide our services primarily in the Permian Basin, the Eagle Ford Shale, the DJ Basin, the Williston Basin and the Powder River Basin. 
+Our founders and existing management were pioneers in the development of data-driven hydraulic fracturing technologies for application in shale plays. Prior to founding Liberty Holdings, the majority of our management team founded and built Pinnacle Technologies, Inc. (“Pinnacle Technologies”) into a leading fracturing technology company. In 1992, Pinnacle Technologies developed the first commercial hydraulic fracture mapping technologies, analytical tools that played a major role in launching the shale revolution. Our extensive experience with fracture technologies and customized fracture design has enabled us to develop new technologies and processes that provide our customers with real time solutions that significantly enhance their completions. These technologies include hydraulic fracture propagation models, reservoir engineering tools, large, proprietary shale production databases and multi-variable statistical analysis techniques. Taken together, these technologies have enabled us to be a leader in hydraulic fracture design innovation and application. 
+We believe the following characteristics distinguish us from our competitors and are the foundations of our business: forming ongoing partnerships of trust and innovation with our customers; developing and utilizing technology to maximize well performance; and promoting a people-centered culture focused on our employees, customers and suppliers. We have developed strong relationships with our customers by investing significant time in fracture design collaboration, which substantially enhances their production economics. Our technological innovations have become even more critical as E&P companies have increased the completion complexity and fracture intensity of horizontal wells. We are proactive in developing innovative solutions to industry challenges, including developing: (i) our proprietary databases of U.S. unconventional wells to which we apply our proprietary multi-variable statistical analysis technologies to provide differential insight into fracture design optimization; (ii) our Liberty Quiet Fleet® design which significantly reduces noise levels compared to conventional hydraulic fracturing fleets; and (iii) hydraulic fracturing fluid systems tailored to the specific reservoir properties in the basins in which we operate. We foster a people-centered culture built around honoring our commitments to customers, partnering with our suppliers and hiring, training and retaining people that we believe to be the best talent in our field, enabling us to be one of the safest and most efficient hydraulic fracturing companies in the United States. 
+Recent Developments 
+On January 22, 2019, our board of directors (the “Board”) authorized a share repurchase plan to repurchase shares of our Class A Common Stock, par value $0.01 per share, in an amount not to exceed $100 million through January 31, 2021. This 
+3 
+Table of Contents 
+program is in addition to the $100 million share repurchase program we previously announced on September 10, 2018, which has been substantially completed. We expect to fund repurchases made under this plan from existing cash on hand and future operating cash flow. The share repurchase program was approved by the Board who believe that a share repurchase program at this time is in the best interests of us and our shareholders and will not impact our ability to execute our growth plans. 
+We also announced on January 22, 2019 that the Board approved a quarterly cash dividend of $0.05 per share of Class A Common Stock, to be paid on March 20, 2019 to holders of record as of March 6, 2019. A distribution of $0.05 per unit has been approved for holders of units in Liberty LLC, which will use the same record and payment date. 
+Future declarations of dividends are subject to approval by the Board and to the Board’s continuing determination that the declarations of dividends are in the best interests of us and our stockholders. Future dividends may be adjusted at the Board’s discretion based on market conditions and capital availability. 
+Cyclical Nature of Industry 
+We operate in a highly cyclical industry. The key factor driving demand for our services is the level of drilling activity by E&P companies, which in turn depends largely on the current and anticipated economics of new well completions. Global supply and demand for oil and the domestic supply and demand for natural gas are critical in assessing industry outlook. Demand for oil and natural gas is cyclical and subject to large, rapid fluctuations. E&P companies tend to increase capital expenditures in response to increases in oil and natural gas prices, which generally results in greater revenues and profits for oilfield service companies such as ours. Increased capital expenditures also ultimately lead to greater production, which historically has resulted in increased supplies and reduced prices which in turn tend to reduce demand for oilfield services. For these reasons, the results of our operations may fluctuate from quarter to quarter and from year to year, and these fluctuations may distort comparisons of results across periods. 
+Seasonality 
+Our results of operations have historically reflected seasonal tendencies relating to holiday seasons, inclement weather and the conclusion of our customers’ annual drilling and completion capital expenditure budgets. Our most notable declines typically occur in the first and fourth quarters of the year for the reasons described above. Additionally, some of the areas in which we have operations, including the DJ Basin, Powder River Basin and Williston Basin, are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice or rain and frost law enforcement, we may be unable to move our equipment between locations, thereby reducing our ability to provide services and generate revenues. The exploration activities of our customers may also be affected during such periods of adverse weather conditions. Additionally, extended drought conditions in our operating regions could impact our ability or our customers’ ability to source sufficient water or increase the cost for such water. 
+Intellectual Property 
+Over the last several years we have significantly invested in our research and technology capabilities. Our efforts to date have been focused on developing innovative, fit-for-purpose solutions designed to enhance our core service offerings, increase completion efficiencies, provide cost savings to our operations and add value for our customers. 
+As a result of these efforts, we introduced several new products and progressed on differentiating technologies that we believe will provide a competitive advantage as our customers focus on extracting oil and natural gas in the most economical and efficient ways possible, including, for example, our Liberty Quiet Fleet®, which materially reduces noise levels compared to conventional fracturing fleets. These investments are delivering value added products and services that support our customers and create increasing demand for our services. 
+We seek patent and trademark protections for our technology when we deem it prudent, and we aggressively pursue protection of these rights when warranted. We believe our patents, trademarks, and other protections for our proprietary technologies are adequate for the conduct of our business and that no single patent or trademark is critical to our business. In addition, we rely, to a great extent, on the technical expertise and know-how of our personnel to maintain our competitive position, and we take commercially reasonable measures to protect trade secrets and other confidential and/or proprietary information relating to the technologies we develop. 
+Risk Management and Insurance 
+Our operations are subject to significant hazards often found in the oil and natural gas industry, such as, but not limited to, accidents, blowouts, explosions, craterings, fires, natural gas leaks, oil and produced water spills and releases of hydraulic fracturing fluids or other well fluids into the environment. These conditions can cause: 
+4 
+Table of Contents 
+• 
+disruption in operations; 
+• 
+substantial repair or remediation costs; 
+• 
+personal injury or loss of human life; 
+• 
+significant damage to or destruction of property and equipment; 
+• 
+environmental pollution, including groundwater contamination; 
+• 
+unusual or unexpected geological formations or pressures and industrial accidents; 
+• 
+impairment or suspension of operations; and 
+• 
+substantial revenue loss. 
+In addition, our operations are subject to, and exposed to, employee/employer liabilities and risks such as wrongful termination, discrimination, labor organizing, retaliation claims and general human resource related matters. 
+Claims for loss of oil and natural gas production and damage to formations can occur in the well services industry. Litigation arising from a catastrophic occurrence at a location where our equipment and services are being used may result in our being named as a defendant in lawsuits asserting large claims. 
+We do not have insurance against all foreseeable risks, either because insurance is not available or because of the high premium costs. The occurrence of an event not fully insured against or the failure of an insurer to meet its insurance obligations could result in substantial losses. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. Insurance may not be available to cover any or all of the risks to which we are subject, or, even if available, it may be inadequate, or insurance premiums or other costs could rise significantly in the future so as to make such insurance prohibitively expensive. 
+We enter into Master Service Agreements (“MSAs”) with substantially all of our customers. Our MSAs delineate our and our customer’s respective indemnification obligations with respect to the services we provide. Generally, under our MSAs, including those relating to our hydraulic fracturing services, we assume responsibility for pollution or contamination originating above the surface from our equipment or handling. However, our customers assume responsibility for all other pollution or contamination that may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling and completion fluids. The assumed responsibilities include the control, removal and clean-up of any pollution or contamination. In such cases, we may be exposed to additional liability if we are grossly negligent or commit willful acts causing the pollution or contamination. Generally, our customers also agree to indemnify us against claims arising from their employees’ personal injury or death, in the case of our hydraulic fracturing operations, to the extent that their employees are injured by such operations, unless the loss is a result of our gross negligence or willful misconduct. Similarly, we generally agree to indemnify our customers for liabilities arising from personal injury to or death of any of our employees, unless resulting from the gross negligence or willful misconduct of our customer. The same principles apply to mutual indemnification for loss or destruction of customer-owned property or equipment. Losses due to catastrophic events, such as blowouts, are generally the responsibility of the customer. However, despite this general allocation of risk, we may be unsuccessful in enforcing contractual terms, incur an unforeseen liability that is not addressed by the scope of the contractual provisions or be required to enter into an MSA with terms that vary from our standard allocations of risk, as described above. Consequently, we may incur substantial losses that could materially and adversely affect our financial condition and results of operations. 
+Employees 
+As of December 31, 2018, we had 2,437 employees and no unionized labor. We believe we have good relations with our employees. 
+Our Services 
+We provide hydraulic fracturing services to E&P companies, particularly to those operating in unconventional oil and natural gas reservoirs and requiring technically and operationally advanced services. Hydraulic fracturing services are performed to enhance production of oil and natural gas from formations with low permeability and restricted flow of hydrocarbons. Our customers benefit from our expertise in fracturing horizontal wells in shales and other unconventional geological formations. 
+The process of hydraulic fracturing involves pumping a pressurized stream of fracturing fluid—typically a mixture of water, chemicals and proppant—into a well casing or tubing in order to cause the underground formation to fracture or crack. These fractures release trapped hydrocarbon particles and provide a conductive channel for the oil or natural gas to flow freely 
+5 
+Table of Contents 
+to the wellbore for collection. The propping agent, or proppant,—typically sand—becomes lodged in the cracks created by the hydraulic fracturing process, “propping” them open to facilitate the flow of hydrocarbons from the reservoir to the well. The fracturing fluid is engineered to lose viscosity, or “break,” and is subsequently flowed back from the formation, leaving the proppant suspended in the mineral fractures. Once our customer has flushed the fracturing fluids from the well using a controlled flow-back process, the customer manages fluid and water recycling or disposal. 
+Our hydraulic fracturing fleets consist of mobile hydraulic fracturing units and other auxiliary heavy equipment to perform fracturing services. Our hydraulic fracturing units consist primarily of high-pressure hydraulic pumps, diesel engines, transmissions, radiators and other supporting equipment that are typically mounted on trailers. We refer to the group of units and other equipment, such as blenders, data vans, sand storage, tractors, manifolds and high pressure fracturing iron, which are necessary to perform a typical hydraulic fracturing job, as a “fleet,” and the personnel assigned to each fleet as a “crew.” As of February 2019, we had 22 active fleets. 
+An important element of our hydraulic fracturing services is our focus on providing custom-tailored completions solutions to our customers to maximize their well results. Our technologically innovative approach involves our review of a series of continually updated, proprietary databases of U.S. unconventional wells to which we apply our multi-variable data analysis, allowing us to gain differential insight into fracture design. The innovative completions solutions we provide to our customers help them complete more productive and cost efficient wells in shorter times with less environmental impact on their surroundings while increasing the useful lives of our equipment. 
+In addition to custom-tailored completions solutions, we also develop custom fluid systems, proppant logistics solutions, perforating strategies and pressure analysis techniques for our customers. An example of this is a hydraulic fracturing fluid that we developed for use in our DJ Basin operations called Liberty Spirit ™ , a specifically designed fracturing fluid system that enables material reductions in completion costs in the DJ Basin without compromising job execution or well results. 
+We provide our services in several of the most active basins in the United States, including the Permian Basin, the Eagle Ford Shale, the DJ Basin, the Williston Basin and the Powder River Basin. The map below represents our current areas of operations: 
+6 
+Table of Contents 
+Properties and Equipment 
+Properties 
+Our corporate headquarters are located at 950 17 th Street, Suite 2400, Denver, Colorado 80202. We lease our general office space at our corporate headquarters. The lease expires in December 2024. We currently own or lease the following additional principal properties: 
+District Facility Location 
+Size 
+Leased or Owned 
+Expiration of Lease 
+Odessa, TX 
+77,500 sq. ft on 47 acres 
+Owned 
+N/A 
+Henderson, CO 
+50,000 sq. ft on 13 acres 
+Leased 
+December 31, 2034 
+Williston, ND 
+30,000 sq. ft on 15 acres 
+Owned 
+N/A 
+Gillette, WY 
+32,757 sq. ft on 15 acres 
+Leased 
+December 31, 2034 
+Cibolo, TX 
+90,000 sq. ft on 34 acres 
+Owned 
+N/A 
+Sedalia, CO 
+11,805 sq. ft on 112 acres 
+Owned 
+N/A 
+We also lease several smaller facilities, which leases generally have terms of one to three years. We believe that our existing facilities are adequate for our operations and their locations allow us to efficiently serve our customers. We do not believe that any single facility is material to our operations and, if necessary, we could readily obtain a replacement facility. 
+Equipment 
+We currently have 22 hydraulic fracturing fleets, and expect to take delivery of additional equipment in 2019. However, decisions whether or not to deploy these additional fleets in 2019 will be made considering customer demand, long term return profile and market conditions. Eight of our fleets currently utilize our Liberty Quiet Fleet® technology and approximately 40% of our capacity has dual fuel capability. 
+Our hydraulic fracturing fleets are comprised of high-quality, heavy-duty equipment designed to reduce operational downtime and maintenance costs, while enhancing our ability to provide reliable, consistent service. Each hydraulic fracturing fleet includes the necessary blending units, manifolds, data vans and other ancillary equipment needed to provide a high level of service to our customers. 
+Our newbuild fleets are manufactured to a custom Liberty specification that identifies the input components, including such key parts as engines, transmissions and pumps and control systems. These components have been selected with our lowest total cost of ownership philosophy in mind. We have built a strong partnership with each of the key component suppliers that we believe will help ensure timely access to necessary components, early opportunities to adopt the latest technology, and high-level technical support. For example, our close partnership with Caterpillar Inc. enabled us to have ready access to their technical team as we worked through the development of the Liberty Quiet Fleet® technology. This relationship ensured that the end product was delivered without compromise to engine performance, reliability or maintainability. We have also a built a strong relationship with the assembler of the core equipment for our fracturing fleets. We believe the collaborative partnerships we have developed with our vendors should give us ready access to sufficient fabrication capacity for our growth. 
+Our Acquisitions 
+On June 13, 2016, we acquired certain inventories and long-lived field service assets related to hydraulic fracturing from Sanjel Corporation for $69.0 million in cash (the “Sanjel Acquisition”). These assets were acquired from Sanjel Corporation as part of its bankruptcy proceeding. On February 22, 2017, we acquired all the membership interests of Titan Frac Services LLC, a wholly-owned subsidiary of TPIH Group Inc., for $65.0 million in cash. 
+Marketing and Customers 
+Our sales and marketing activities typically are performed through our local sales representatives in each geographic region, and are supported by our corporate headquarters. For the years ended December 31, 2018 , 2017 and 2016 , our top five customers collectively accounted for approximately 42%, 53% and 59% of our revenues, respectively. Extraction Oil & Gas, Inc. accounted for more than 10% of our revenues for the year ended December 31, 2018 . For the year ended December 31, 2017 , Extraction Oil & Gas, Inc. and SM Energy Company each accounted for more than 10% of our revenues. Extraction Oil & Gas, Inc., SM Energy Company and Noble Energy, Inc. each accounted for more than 10% of our revenues for the year ended December 31, 2016 . 
+7 
+Table of Contents 
+Suppliers 
+We have a dedicated supply chain team that manages sourcing and logistics to ensure flexibility and continuity of supply in a cost effective manner across our areas of operation. We have built long-term relationships with multiple industry leading suppliers of proppant, chemicals and hydraulic fracturing equipment. For the years ended December 31, 2018 , 2017 and 2016 none of our suppliers accounted for more than 10% of overall costs. For 2019, we do not expect any single proppant supplier to account for more than 20% of our total supply. In addition, we have built a strong relationship with the assembler of our custom-designed hydraulic fracturing fleets and believe we will continue to have timely access to new, high capability fleets as we continue to grow. Our purchases from that assembler accounted for more than 10% of our total capital expenditures for the year ended December 31, 2018 . 
+We purchase a wide variety of raw materials, parts and components that are manufactured and supplied for our operations. We are not dependent on any single source of supply for those parts, supplies or materials. To date, we have generally been able to obtain the equipment, parts and supplies necessary to support our operations on a timely basis. While we believe that we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers, we may not always be able to do so. In addition, certain materials for which we do not currently have long-term supply agreements could experience shortages and significant price increases in the future. As a result, we may be unable to mitigate any future supply shortages and our results of operations, prospects and financial condition could be adversely affected. 
+Competition 
+The markets in which we operate are highly competitive. We provide services in various geographic regions across the United States, and our competitors include many large and small oilfield service providers, including some of the largest integrated service companies. Our hydraulic fracturing services compete with large, integrated companies such as Halliburton Company and Schlumberger Limited as well as other companies including Basic Energy Services, Inc., BJ Services Company, C&J Energy Services, Inc., Calfrac Well Services Ltd., FTS International, Inc., Keane Group, Inc., Patterson-UTI Energy, Inc., ProPetro Services, Inc., RPC, Inc., Superior Energy Services, Inc. and U.S. Well Services, Inc. In addition, our industry is highly fragmented and we compete regionally with a significant number of smaller service providers. 
+We believe that the principal competitive factors in the markets we serve are technical expertise, equipment capacity, work force competency, efficiency, safety record, reputation, experience and price. Additionally, projects are often awarded on a bid basis, which tends to create a highly competitive environment. We seek to differentiate ourselves from our competitors by delivering the highest-quality services and equipment possible, coupled with superior execution and operating efficiency in a safe working environment. 
+Our operations are organized into a single business segment, which consists of hydraulic fracturing services, and we have one reportable geographical business segment, the United States. Operating segments are defined under generally accepted accounting principles in the United States of America ( “ GAAP ” ) as components of an enterprise that engage in activities (i) from which it may earn revenues and incur expenses and (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance. 
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+Environmental and Occupational Safety and Health Matters 
+Our operations in support of oil and natural gas exploration, development and production activities pursued by our customers are subject to stringent federal, tribal, regional, state and local laws and regulations governing occupational safety and health, the discharge of materials into the environment and environmental protection. Numerous governmental entities, including the U.S. Environmental Protection Agency (“EPA”), the U.S. Occupational Safety and Health Administration (“OSHA”), and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions, including the incurrence of potentially significant capital or operating expenditures to mitigate or prevent the releases of materials from our equipment, facilities or from customer locations where we provide our services. These laws and regulations may, among other things (i) require the acquisition of permits or other authorizations for conducting regulated activities, (ii) limit or prohibit our operations on certain lands lying within wilderness, wetlands and other protected areas; (iii) require remedial measures to mitigate pollution from former and ongoing operations; (iv) impose restrictions on the types, quantities and concentrations of various substances that can be released into the environment or injected in formations in connection with oil and natural gas drilling and production activities; (v) impose specific safety and health criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from our operations. Any failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties; the imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures; the occurrence of restrictions, delays or cancellations in the permitting, performance or development of projects or operations; and the issuance of orders enjoining performance of some or all of our operations in a particular area. 
+The trend in environmental regulation is to place more restrictions and limitations on activities that may adversely affect the environment, and thus any new laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased government enforcement with respect to environmental matters that result in more stringent and costly completion activities, pollution control equipment, waste handling, storage transport, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for injuries to persons or damages to properties or natural resources. Our customers may also incur increased costs, or restrictions, delays or cancellations in permitting or operating activities as a result of more stringent environmental laws and regulations, which may result in a curtailment of exploration, development or production activities that would reduce the demand for our services. Historically, our worker health and safety as well as our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our business and operating results. 
+The following is a summary of the more significant existing environmental and occupational safety and health laws, as amended from time to time, to which our business is subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position. 
+Worker Health and Safety 
+We are subject to the requirements of the federal Occupational Safety and Health Act, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and the public. These worker health and safety laws and regulations are subject to amendment including, for example, rulemaking adopted by OSHA in 2016 imposing more stringent permissible exposure limits for worker exposure to respirable crystalline silica, and any failure to comply with these laws could lead to the assertion of third-party claims against us, civil or criminal fines and changes in the way we operate our facilities, any of which could have an adverse effect on our financial position. 
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+Motor Carrier Operations 
+In connection with the services we provide, we operate as a motor carrier and therefore are subject to regulation by the U.S. Department of Transportation (“DOT”) and analogous state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations; regulatory safety; hazardous materials labeling, placarding and marking; financial reporting; and certain mergers, consolidations and acquisitions. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may increase our costs as well as affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations that govern the amount of time a driver may drive in any specific period and requiring onboard electronic logging devices or limits on vehicle weight and size. 
+Interstate motor carrier operations are subject to safety requirements prescribed by DOT. Intrastate motor carrier operations are subject to state safety regulations that often mirror federal regulations but may be more stringent. Such matters as weight and dimension of motor carrier-related equipment are also subject to federal and state regulations. DOT regulations also mandate drug testing of drivers. From time to time, various legislative proposals are introduced, including proposals to increase federal, state or local taxes, such as, for example, taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us would be enacted. 
+Radioactive Materials 
+Certain of our operations utilize equipment that contains sealed, low-grade radioactive sources. Our activities involving the use of radioactive materials are regulated by the U.S. Nuclear Regulatory Commission (“NRC”) and state regulatory agencies under agreement with the NRC. Standards implemented by these regulatory agencies require us to obtain licenses or other approvals for the use of such radioactive materials. Additionally, these regulatory agencies impose certain requirements concerning worker protection with respect to radioactive sources and may otherwise issue regulations regarding the handling and storage of this equipment that may result in increased costs. The violation of these laws and regulations may result in the denial or revocation of licenses or other approvals, issuance of corrective action orders, injunctions prohibiting some or all of our operations in a particular area, and assessment of sanctions, including administrative, civil and criminal penalties. 
+Hazardous Substances and Wastes and Naturally Occurring Radioactive Materials 
+The federal Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, regulate the generation, treatment, storage, transportation, disposal and clean-up of hazardous and non-hazardous wastes. Pursuant to rules issued by the EPA, individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste provisions, state laws or other federal laws. However, it is possible that certain oil and gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. For example, pursuant to a consent decree issued by the U.S. District Court for the District of Columbia in 2016 the EPA is required to propose, no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations that could result in oil and natural gas exploration and production wastes being regulated as hazardous wastes, or sign a determination that revision of the regulations is unnecessary. If the EPA proposes a rulemaking for revised oil and natural gas waste regulations, the consent decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our and the oil and natural gas exploration and production industry’s costs to manage and dispose of generated hazardous wastes, which could have a material adverse effect on our results of operations and financial position. Additionally, other wastes handled at exploration and production sites or generated in the course of providing well services may not fall within this exclusion. In the course of our operations, we generate some amounts of ordinary industrial wastes that may be regulated as hazardous wastes. 
+Moreover, there have been public concerns expressed about naturally occurring radioactive materials (“NORM”) being detected in flow back water resulting from hydraulic fracturing that may contaminate extraction and processing equipment used in the oil and natural gas industry. NORM is subject primarily to individual state radiation control regulations while NORM handling and management activities are governed by regulations promulgated by OSHA. These state and federal regulations impose certain requirements concerning worker protection with respect to NORM as well as the treatment, storage, and disposal of NORM and NORM waste, management of NORM-contaminated waste piles, containers and tanks, and limitations on the relinquishment of NORM contaminated land for unrestricted use under RCRA and state laws. Concern over NORM in 
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+general, or NORM in groundwater in particular, could result in further regulation in the treatment, storage, handling and discharge of flow back water generated from oil and natural gas activities, including hydraulic fracturing, or handling of NORM-impacted equipment that, if implemented, could increase our or our customers’ costs or liabilities associated with elevated levels of NORM as well as limit drilling by our customers, which developments may reduce demand for our services. 
+The federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, and comparable state statutes impose liability, without regard to fault or legality of the original conduct, on classes of persons that are considered to have contributed to the release of a hazardous substance into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, these persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources even if the liability results from conduct that was lawful at the time it occurred or is due to the conduct, or conditions caused by, prior operators or third parties. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We own, lease, or operate numerous properties and facilities that for many years have been used for industrial activities, including oil and natural gas-related operations. Hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations where such substances have been taken for recycling or disposal. In addition, some of these properties have been operated by third parties or by previous owners whose treatment and disposal or release of hazardous substances, wastes, or hydrocarbons, was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes and remediate contaminated property (including groundwater contamination), including instances where the prior owner or operator caused the contamination, or perform remedial plugging of disposal wells or waste pit closure operations to prevent future contamination. 
+Water Discharges and Discharges into Belowground Formations 
+The Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”) and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and hazardous substances, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers (“Corps”). The CWA and analogous state laws also may impose substantial civil and criminal penalties for non-compliance including spills and other non-authorized discharges. 
+In 2015, the EPA and the Corps published a final rule outlining their position on federal jurisdictional reach over waters of the United States, including wetlands, but legal challenges to this rule followed. Beginning in the first quarter of 2017, the EPA and the Corps agreed to reconsider the 2015 rule and, thereafter, the agencies (i) published a proposed rule in 2017 to rescind the 2015 rule and recodify the regulatory text that governed waters of the United States prior to promulgation of the 2015 rule, (ii) published a final rule in February 2018 adding a February 6, 2020 applicable date to the 2015 rule, and (iii) published a proposed rule in December 2018 re-defining the CWA’s jurisdiction over waters of the United States for which the agencies will seek public comment. The 2015 and February 2018 final rules are being challenged by various factions in the federal district court and implementation of the 2018 rule has been enjoined to twenty-eight states pending resolution of various federal district court challenges. As a result of these legal developments, future implementation of the 2015 rule is uncertain at this time. Any expansion of the CWA’s jurisdiction in areas where we or our customers operate, could impose additional permitting obligations on us and our customers. 
+The Oil Pollution Act of 1990 (“OPA”) amends the CWA and sets minimum standards for prevention, containment and cleanup of oil spills. OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties including owners and operators of onshore facilities may be held strictly liable for oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills. The OPA also requires owners or operators of certain onshore facilities to prepare facility response plans for responding to a worst-case discharge of oil into waters of the United States. 
+Our oil and natural gas producing customers dispose of flowback and produced water or certain other oilfield fluids gathered from oil and natural gas producing operations in accordance with permits issued by government authorities overseeing 
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+such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change based on concerns of the public or governmental authorities regarding such disposal activities. One such concern relates to seismic events near underground disposal wells used for the disposal by injection of flowback and produced water or certain other oilfield fluids resulting from oil and natural gas activities. In 2016, the United States Geological Survey identified six states with the most significant hazards from seismicity events suspected of having been induced by injection of oilfield fluids into underground disposal wells, including Oklahoma, Kansas, Texas, Colorado, New Mexico, and Arkansas. In response to concerns between use of underground disposal wells and the occurrence of seismic events, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Texas and Oklahoma have issued rules for produced water disposal wells that impose certain permitting restrictions, operating restrictions and/or reporting requirements on disposal wells in proximity to faults. Additionally, from time to time, states may develop and implement plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations, as has occurred in Oklahoma. For example, in late 2016, the Oil and Gas Conservation Division of the Oklahoma Corporation Commission (“OCC”) and the Oklahoma Geological Survey released well completion seismicity guidance, which requires operators to take certain prescriptive actions, including an operator’s planned mitigation practices, following certain unusual seismic activity within 1.25 miles of hydraulic fracturing operations. In recent years, including during 2018, the OCC’s Oil and Gas Conservation Division has issued orders limiting future increases in the volume of oil and natural gas produced water injected belowground into the Arbuckle formation in an effort to reduce the number of earthquakes in the state. Another consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by our customers to dispose of flowback and produced water and certain other oilfield fluids. Increased regulation and attention given to seismicity events suspected of having been induced by injection of oilfield fluids into underground disposal wells also could lead to greater opposition to, and litigation concerning, oil and natural gas activities utilizing injection wells for waste disposal. Any of these developments may result in our customers having to limit disposal well volumes, disposal rates or locations, or require our customers or third party disposal well operators that are used to dispose of customer produced water to shut down disposal wells, which developments could adversely affect our customers’ business and result in a corresponding decrease in the need for our services, which would could have a material adverse effect on our business, financial condition, and results of operations. 
+Air Emissions 
+Certain of our operations also result in emissions of regulated air pollutants. The federal Clean Air Act (“CAA”) and analogous state laws require permits for certain facilities that have the potential to emit substances into the atmosphere that could adversely affect environmental quality. These laws and their implementing regulations also impose generally applicable limitations on air emissions and require adherence to maintenance, work practice, reporting and record keeping, and other requirements. Failure to obtain a permit or to comply with permit or other regulatory requirements could result in the imposition of sanctions, including administrative, civil and criminal penalties. In addition, we or our customers could be required to shut down or retrofit existing equipment, leading to additional expenses and operational delays. 
+Many of these regulatory requirements, including New Source Performance Standards (“NSPS”) and Maximum Achievable Control Technology (“MACT”) standards, are expected to be made more stringent over time as a result of stricter ambient air quality standards and other air quality protection goals adopted by the EPA. Compliance with these or other new or amended regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact on our business. For example, in 2015, the EPA lowered the National Ambient Air Quality Standard, (“NAAQS”) for ozone from 75 to 70 parts per billion for both the 8-hour primary and secondary standards. In 2017 and 2018, the EPA issued area designations with respect to ground-level ozone as either “attainment/unclassifiable,” “unclassifiable” or “nonattainment.” Additionally, in November 2018, the EPA issued final requirements that apply to state, local, and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Additionally, states are expected to implement more stringent requirements as a result of the revised NAAQS for ozone, which could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. Compliance with this and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase costs for us and our customers. Moreover, our business could be materially affected if our customers’ operations are significantly affected by these or other similar requirements. These requirements could increase the cost of doing business for us and our customers, reduce the demand for the oil and natural gas our customers produce, and thus have an adverse effect on the demand for our services. 
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+Climate Change 
+Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of greenhouse gases (“GHGs”). These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. In the absence of federal GHG-limiting legislations, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted regulations that, among other things, restrict emissions of GHGs under existing provisions of the CAA and may require the installation of “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future if they would otherwise emit large volumes of GHGs together with other criteria pollutants. Also, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from oil and natural gas production, processing, transmission and storage facilities in the United States. In 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting stations as well as completions and workovers from hydraulically fractured oil wells. 
+The EPA has also taken steps to limit methane emissions, a GHG, from certain new modified or reconstructed facilities in the oil and natural gas sector through the adoption of a final rule in 2016 establishing NSPS Subpart OOOOa standards for methane emissions. However, in June 2017, the EPA published a proposed rule to stay certain portions of these Subpart OOOOa standards for two years but the rule was not finalized. Rather, in February 2018, the EPA finalized amendments to certain requirements of the 2016 final rule, and in September 2018 the EPA proposed additional amendments, including rescission of certain requirements and revisions to other requirements, such as fugitive emission monitoring frequency. Further more, in late 2016, the federal Bureau of Land Management (“BLM”) published a final rule that established, among other things, requirements to reduce methane emissions by regulating venting, flaring and leaks from oil and natural gas production activities on onshore federal and Native American lands. However, in September 2018, the BLM published a final rule that rescinds most of the new requirements of the 2016 final rule and codifies the BLM's prior approach to venting and flaring but the rule rescinding the 2016 final rule has been challenged in federal court and remains pending. In the event that the EPA’s 2016 or the BLM’s 2016 rules should remain or be placed in effect, or should any other new methane emission standards be imposed on the oil and natural gas sector, such requirements could result in increased costs to our or our customers’ operations as well as result in restrictions, delays or cancellations in such operations, which costs, restrictions delays or cancellations could adversely affect our business. 
+Internationally, in April 2016, the United States joined other countries in entering into a United Nations-sponsored non-binding agreement negotiated in Paris, France (the “Paris Agreement”) for nations to limit their GHG emissions through individually determined reduction goals every five years beginning in 2020. However, in August 2017, the U.S. State Department informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016. The United States’ adherence to the exit process and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas our customers produce and lower the value of their reserves, which developments could reduce demand for our services and have a corresponding material adverse effect on our results of operations and financial position. 
+Notwithstanding potential risks related to climate change, the International Energy Agency estimates that oil and natural gas will continue to represent a major share of global energy use through 2040, and other studies by the private sector project continued growth in demand for the next two decades. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector. Ultimately this could make it more difficult to secure funding for exploration and production or midstream activities. Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our operations. 
+Endangered Species 
+The federal Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the federal Migratory Bird Treaty Act (“MBTA”). Customer oil and natural gas operations may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife, which may limit their ability to operate in protected areas. Permanent restrictions imposed to protect endangered and threatened species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. Moreover, as a result of one or more settlements entered into by the U.S. Fish and Wildlife Service (“FWS”), that agency is required to consider listing numerous species as endangered or threatened under the Endangered Species Act by 
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+specified timelines. Current ESA listings and the designation of previously unprotected species as threatened or endangered in areas where we or our customers operate could cause us or our customers to incur increased costs arising from species protection or mitigation measures and could result in restrictions, delays or cancellations in our or our customers’ performance of operations, which could adversely affect or reduce demand for our services. 
+Hydraulic Fracturing 
+We perform hydraulic fracturing services for our customers. Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppant and chemical additives under pressure into the formation to fracture the surrounding rock and stimulate production. 
+Hydraulic fracturing typically is regulated by state oil and natural gas commissions or similar agencies, but the EPA has conducted investigations or asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act (“SDWA”) Underground Injection Control (“UIC”) program over certain aspects of the process. For example, in late 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. Additionally, the EPA has asserted regulatory authority under the SDWA UIC program over hydraulic fracturing activities involving the use of diesel fuel and issued permitting guidance covering such activities, as well as published an Advanced Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. The EPA also published final CAA regulations in 2012 and 2016 governing performance standards, including standards for the capture of emissions released during oil and natural gas hydraulic fracturing. Moreover, in 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of produced water from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The BLM published a final rule in 2015 that imposed new or more stringent standards for performing hydraulic fracturing on federal and Native American lands but the BLM rescinded the 2015 rule in later 2017; however, litigation challenging the BLM’s decisions to rescind the 2015 rule is pending in federal district court. 
+Additionally, various state and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, disclosure requirements, well construction and temporary or permanent bans on hydraulic fracturing in certain areas. For example, Texas, Colorado and North Dakota, among others, have adopted regulations that impose new or more stringent permitting, disclosure, disposal, and well construction requirements on hydraulic fracturing operations. States could also elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York. Local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular. Also, non-governmental organizations may seek to restrict hydraulic fracturing, as has been the case in Colorado in recent years, when certain interest groups therein have unsuccessfully pursued ballot initiatives in recent general election cycles that, had they been successful, would have revised the state constitution or state statutes in a manner that would have made exploration and production activities in the state more difficult or costly in the future, for example, by increasing mandatory setback distances of oil and natural gas operations, including hydraulic fracturing, from specific occupied structures and/or certain environmentally sensitive or recreational areas. 
+If new federal, state or local laws, regulations or ballot initiatives that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly to perform hydraulic fracturing. Any such laws, regulations or ballot initiatives limiting or prohibiting hydraulic fracturing could result in decreased oil and natural gas exploration and production activities and, therefore, adversely affect demand for our services and our business. Such laws, regulations or ballot initiatives could also materially increase our costs of compliance and doing business. 
+Available Information 
+We file or furnish annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The SEC also maintains an internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC. 
+Our Class A Common Stock is listed and traded on the New York Stock Exchange (“NYSE”) under the symbol “LBRT.” Our reports, proxy statements and other information filed with the SEC can also be inspected and copied at the offices of the NYSE, at 20 Broad Street, New York, New York 10005. 
+We also make available free of charge through our website, www.libertyfrac.com, electronic copies of certain documents that we file with the SEC, including our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on 
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+Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. 
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+Item 1A. Risk Factors 
+Described below are certain risks that we believe apply to our business and the industry in which we operate. You should carefully consider each of the following risk factors in conjunction with other information provided in this Annual Report on Form 10-K and in our other public disclosures. The risks described below highlight potential events, trends or other circumstances that could adversely affect our business, financial condition, results of operations, cash flows, liquidity or access to sources of financing, and consequently, the market value of our Class A Common Stock. These risks could cause our future results to differ materially from historical results and from guidance we may provide regarding our expectations of future financial performance. The risks described below are those that we have identified as material and is not an exhaustive list of all the risks we face. There may be other risks that we have not identified or that we have deemed to be immaterial. Please refer to the explanation of the qualifications and limitation on forward-looking statements set forth on page ii hereof. 
+Risks Related to Our Business 
+Our business depends on domestic capital spending by the oil and natural gas industry, and reductions in capital spending could have a material adverse effect on our liquidity, results of operations and financial condition. 
+Our business is directly affected by our customers’ capital spending to explore for, develop and produce oil and natural gas in the United States. The significant decline in oil and natural gas prices that began in late 2014 caused a reduction in the exploration, development and production activities of most of our customers and their spending on our services. These cuts in spending curtailed drilling programs, which resulted in a reduction in the demand for our services, as well as the prices we can charge. These reductions negatively affected our revenue per average active fleet in 2015 and 2016. While industry conditions improved and activity levels increased during 2017 and part of 2018, there can be no assurance that these increased levels will be sustained. In addition, certain of our customers could become unable to pay their vendors and service providers, including us, as a result of a decline in commodity prices. Reduced discovery rates of new oil and natural gas reserves in our areas of operation as a result of decreased capital spending may also have a negative long-term impact on our business, even in an environment of stronger oil and natural gas prices. Any of these conditions or events could adversely affect our operating results. If the recent recovery and increased activity levels do not continue or our customers fail to further increase their capital spending, it could have a material adverse effect on our liquidity, results of operations and financial condition. 
+Industry conditions are influenced by numerous factors over which we have no control, including: 
+• 
+expected economic returns to E&P companies of new well completions; 
+• 
+domestic and foreign economic conditions and supply of and demand for oil and natural gas; 
+• 
+the level of prices, and expectations about future prices, of oil and natural gas; 
+• 
+the level of global oil and natural gas exploration and production; 
+• 
+the level of domestic and global oil and natural gas inventories; 
+• 
+the supply of and demand for hydraulic fracturing services and equipment in the United States; 
+• 
+federal, tribal, state and local laws, regulations and taxes, including the policies of governments regarding hydraulic fracturing and oil and natural gas exploration, development and production activities as well as non-U.S. governmental regulations and taxes; 
+• 
+governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves; 
+• 
+political and economic conditions in oil and natural gas producing countries; 
+• 
+actions by the members of the Organization of Petroleum Exporting Countries with respect to oil production levels and potential changes in such levels, including the failure of such countries to comply with production cuts announced in December 2018, to take effect at the beginning of 2019 and to last for six months; 
+• 
+global weather conditions and natural disasters; 
+• 
+worldwide political, military and economic conditions; 
+• 
+the cost of producing and delivering oil and natural gas; 
+• 
+lead times associated with acquiring equipment and products and availability of qualified personnel; 
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+• 
+the discovery rates of new oil and natural gas reserves; 
+• 
+stockholder activism or activities by non-governmental organizations to limit certain sources of funding for the energy sector or to restrict the exploration, development and production of oil and natural gas; 
+• 
+the availability of water resources, suitable proppant and chemical additives in sufficient quantities for use in hydraulic fracturing fluids; 
+• 
+advances in exploration, development and production technologies or in technologies affecting energy consumption; 
+• 
+the potential acceleration of development of alternative fuels; and 
+• 
+uncertainty in capital and commodities markets and the ability of oil and natural gas companies to raise equity capital and debt financing. 
+The volatility of oil and natural gas prices may adversely affect the demand for our hydraulic fracturing services and negatively impact our results of operations. 
+The demand for our hydraulic fracturing services is primarily determined by current and anticipated oil and natural gas prices and the related levels of capital spending and drilling activity in the areas in which we have operations. Volatility or weakness in oil prices or natural gas prices (or the perception that oil prices or natural gas prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells. This, in turn, could lead to lower demand for our services and may cause lower utilization of our assets. We have experienced, and may in the future experience significant fluctuations in operating results as a result of the reactions of our customers to changes in oil and natural gas prices. For example, prolonged low commodity prices experienced by the oil and natural gas industry beginning in late 2014 and uncertainty about future prices even when prices increased, combined with adverse changes in the capital and credit markets, caused many E&P companies to significantly reduce their capital budgets and drilling activity. This resulted in a significant decline in demand for oilfield services and adversely impacted the prices oilfield services companies could charge for their services. 
+Prices for oil and natural gas historically have been extremely volatile and are expected to continue to be volatile. During the past four years, the posted West Texas Intermediate (“WTI”) price for oil has ranged from a low of $26.19 per barrel (“Bbl”) in February 2016 to a high of $77.41 per Bbl in June 2018. During 2018, WTI prices ranged from $44.48 to $77.41 per Bbl. If the prices of oil and natural gas continue to be volatile, our operations, financial condition, cash flows and level of expenditures may be materially and adversely affected. 
+We may be adversely affected by uncertainty in the global financial markets and the deterioration of the financial condition of our customers. 
+Our future results may be impacted by the uncertainty caused by an economic downturn, volatility or deterioration in the debt and equity capital markets, inflation, deflation or other adverse economic conditions that may negatively affect us or parties with whom we do business resulting in a reduction in our customers’ spending and their non-payment or inability to perform obligations owed to us, such as the failure of customers to honor their commitments or the failure of major suppliers to complete orders. Additionally, during times when the crude oil or natural gas markets weaken, our customers are more likely to experience financial difficulties, including being unable to access debt or equity financing, which could result in a reduction in our customers’ spending for our services. In addition, in the course of our business we hold accounts receivable from our customers. In the event of the financial distress or bankruptcy of a customer, we could lose all or a portion of such outstanding accounts receivable associated with that customer. Further, if a customer was to enter into bankruptcy, it could also result in the cancellation of all or a portion of our service contracts with such customer at significant expense or loss of expected revenues to us. 
+Our operations are subject to significant risks, some of which are beyond our control. These risks may be self-insured, or may not be fully covered under our insurance policies. 
+Our operations are subject to significant hazards often found in the oil and natural gas industry, such as, but not limited to, accidents, blowouts, explosions, craterings, fires, natural gas leaks, oil and produced water spills and releases of hydraulic fracturing fluids or other well fluids into the environment. These conditions can cause: 
+• 
+disruption in operations; 
+• 
+substantial repair or remediation costs; 
+• 
+personal injury or loss of human life; 
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+• 
+significant damage to or destruction of property, and equipment; 
+• 
+environmental pollution, including groundwater contamination; 
+• 
+unusual or unexpected geological formations or pressures and industrial accidents; 
+• 
+impairment or suspension of operations; and 
+• 
+substantial revenue loss. 
+In addition, our operations are subject to, and exposed to, employee/employer liabilities and risks such as wrongful termination, discrimination, labor organizing, retaliation claims and general human resource related matters. 
+The occurrence of a significant event or adverse claim in excess of the insurance coverage that we maintain or that is not covered by insurance could have a material adverse effect on our liquidity, combined results of operations and combined financial condition. Claims for loss of oil and natural gas production and damage to formations can occur in the well services industry. Litigation arising from a catastrophic occurrence at a location where our equipment and services are being used may result in our being named as a defendant in lawsuits asserting large claims. 
+We do not have insurance against all foreseeable risks, either because insurance is not available or because of the high premium costs. The occurrence of an event not fully insured against or the failure of an insurer to meet its insurance obligations could result in substantial losses. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. Insurance may not be available to cover any or all of the risks to which we are subject, or, even if available, it may be inadequate, or insurance premiums or other costs could rise significantly in the future so as to make such insurance prohibitively expensive. 
+Reliance upon a few large customers may adversely affect our revenue and operating results. 
+Our top five customers represented approximately 42%, 53%, and 59% of our consolidated and combined revenue for the years ended December 31, 2018, 2017 and 2016, respectively. It is likely that we will continue to derive a significant portion of our revenue from a relatively small number of customers in the future. If a major customer fails to pay us, revenue would be impacted and our operating results and financial condition could be materially harmed. Additionally, if we were to lose any material customer, we may not be able to redeploy our equipment at similar utilization or pricing levels or within a short period of time and such loss could have a material adverse effect on our business until the equipment is redeployed at similar utilization or pricing levels. 
+We are exposed to the credit risk of our customers, and any material nonpayment or nonperformance by our customers could adversely affect our financial results. 
+We are subject to the risk of loss resulting from nonpayment or nonperformance by our customers, many of whose operations are concentrated solely in the domestic E&P industry which, as described above, is subject to volatility and, therefore, credit risk. Our credit procedures and policies may not be adequate to fully reduce customer credit risk. If we are unable to adequately assess the creditworthiness of existing or future customers or unanticipated deterioration in their creditworthiness, any resulting increase in nonpayment or nonperformance by them and our inability to re-market or otherwise use our equipment could have a material adverse effect on our business, financial condition, prospects or results of operations. 
+We face intense competition that may cause us to lose market share and could negatively affect our ability to market our services and expand our operations. 
+The oilfield services business is highly competitive. Some of our competitors have a broader geographic scope, greater financial and other resources, or other cost efficiencies. Additionally, there may be new companies that enter our business, or re-enter our business with significantly reduced indebtedness following emergence from bankruptcy, or our existing and potential customers may develop their own hydraulic fracturing business, or direct source proppant, negatively affecting our revenue and potentially resulting in shortfall obligations under some of our supply agreements. Our ability to maintain current revenue and cash flows, and our ability to market our services and expand our operations, could be adversely affected by the activities of our competitors and our customers. If our competitors substantially increase the resources they devote to the development and marketing of competitive services or substantially decrease the prices at which they offer their services, we may be unable to effectively compete. All of these competitive pressures could have a material adverse effect on our business, results of operations and financial condition. Some of our larger competitors provide a broader range of services on a regional, national or worldwide basis. These companies may have a greater ability to continue oilfield service activities during periods of low commodity prices and to absorb the burden of present and future federal, tribal, state, local and other laws and regulations. 
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+Any inability to compete effectively with larger companies could have a material adverse impact on our financial condition and results of operations. 
+Our assets require significant amounts of capital for maintenance, upgrades and refurbishment and may require significant capital expenditures for new equipment. 
+Our hydraulic fracturing fleets and other completion service-related equipment require significant capital investment in maintenance, upgrades and refurbishment to maintain their competitiveness. For example, since January 1, 2011, we have deployed 22 hydraulic fracturing fleets to service customers at a total cost to deploy of approximately $838.1 million. The costs of components and labor have increased in the past and may increase in the future with increases in demand, which will require us to incur additional costs to upgrade any fleets we may acquire in the future. Our fleets and other equipment typically do not generate revenue while they are undergoing maintenance, upgrades or refurbishment. Any maintenance, upgrade or refurbishment project for our assets could increase our indebtedness or reduce cash available for other opportunities. Furthermore, such projects may require proportionally greater capital investments as a percentage of total asset value, which may make such projects difficult to finance on acceptable terms. To the extent we are unable to fund such projects, we may have less equipment available for service or our equipment may not be attractive to potential or current customers. Additionally, competition or advances in technology within our industry may require us to update or replace existing fleets or build or acquire new fleets. Such demands on our capital or reductions in demand for our hydraulic fracturing fleets and the increase in cost of labor necessary for such maintenance and improvement, in each case, could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations and may increase our costs. 
+We rely on a limited number of third parties for proppant and chemical additives, and delays in deliveries of such materials, increases in the cost of such materials or our contractual obligations to pay for materials that we ultimately do not require could harm our business, results of operations and financial condition. 
+We have established relationships with a limited number of suppliers of our raw materials (such as proppant and chemical additives). Should any of our current suppliers be unable to provide the necessary materials or otherwise fail to deliver the materials in a timely manner and in the quantities required, any resulting delays in the provision of services could have a material adverse effect on our business, results of operations and financial condition. Additionally, increasing costs of such materials may negatively impact demand for our services or the profitability of our business operations. In the past, our industry faced sporadic proppant shortages associated with hydraulic fracturing operations requiring work stoppages, which are believed to have adversely impacted the operating results of several competitors. We may not be able to mitigate any future shortages of materials, including proppant. Furthermore, to the extent our contracts require us to purchase more materials, including proppant, than we ultimately require, we may be forced to pay for the excess amount under “take or pay” contract provisions. 
+We currently rely on one assembler and a limited number of suppliers for major equipment to both build new fleets and upgrade any fleets we acquire to our custom design, and our reliance on these vendors exposes us to risks including price and timing of delivery. 
+We currently rely on one assembler and a limited number of suppliers for major equipment to both build our new fleets and upgrade any fleets we may acquire to our custom design. If demand for hydraulic fracturing fleets or the components necessary to build such fleets increases or these vendors face financial distress or bankruptcy, these vendors may not be able to provide the new or upgraded fleets on schedule or at the current price. If this were to occur, we could be required to seek another assembler or other suppliers for major equipment to build or upgrade our fleets, which may adversely affect our revenues or increase our costs. 
+Interruptions of service on the rail lines by which we receive proppant could adversely affect our results of operations. 
+We receive a significant portion of the proppant used in our hydraulic fracturing services by rail. Rail operations are subject to various risks that may result in a delay or lack of service, including lack of available capacity, mechanical problems, extreme weather conditions, work stoppages, labor strikes, terrorist attacks and operating hazards. Additionally, if we increase the amount of proppant we require for delivery of our services, we may face difficulty in securing rail transportation for such additional amount of proppant. Any delay or failure in the rail services on which we rely could have a material adverse effect on our financial condition and results of operations. 
+Delays or restrictions in obtaining permits by us for our operations or by our customers for their operations could impair our business. 
+In most states, our operations and the operations of our oil and natural gas producing customers require permits from one or more governmental agencies in order to perform drilling and completion activities, secure water rights, or other regulated activities. Such permits are typically issued by state agencies, but federal and local governmental permits may also be required. 
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+The requirements for such permits vary depending on the location where such regulated activities will be conducted. As with all governmental permitting processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit to be issued, and the conditions that may be imposed in connection with the granting of the permit. In addition, some of our customers’ drilling and completion activities may take place on federal land or Native American lands, requiring leases and other approvals from the federal government or Native American tribes to conduct such drilling and completion activities or other regulated activities. Under certain circumstances, federal agencies may cancel proposed leases for federal lands and refuse to grant or delay required approvals. Therefore, our customers’ operations in certain areas of the United States may be interrupted or suspended for varying lengths of time, causing a loss of revenue to us and adversely affecting our results of operations in support of those customers. 
+Federal or state legislative and regulatory initiatives related to induced seismicity could result in operating restrictions or delays in the drilling and completion of oil and natural gas wells that may reduce demand for our services and could have a material adverse effect on our liquidity, combined results of operations and combined financial condition. 
+Our oil and natural gas producing customers dispose of flowback and produced water or certain other oilfield fluids gathered from oil and natural gas producing operations in accordance with permits issued by government authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change based on concerns of the public or governmental authorities regarding such disposal activities. One such concern relates to seismic events near underground disposal wells used for the disposal by injection of flowback and produced water or certain other oilfield fluids resulting from oil and natural gas activities. In 2016, the United States Geological Survey identified six states with the most significant hazards from seismicity events suspected of having been induced by injection of oilfield fluids into underground disposal wells, including Oklahoma, Kansas, Texas, Colorado, New Mexico, and Arkansas. In response to concerns regarding the use of underground disposal wells and the occurrence of seismic events, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma has issued rules for produced water disposal wells that imposed certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, has developed and implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. The Texas Railroad Commission has adopted similar rules. In late 2016, the Oil and Gas Conservation Division of the OCC and the Oklahoma Geological Survey released well completion seismicity guidance, which requires operators to take certain prescriptive actions, including an operator’s planned mitigation practices, following certain unusual seismic activity within 1.25 miles of hydraulic fracturing operations. In recent years, including during 2018, the OCC’s Oil and Gas Conservation Division issued orders limiting future increases in the volume of oil and natural gas produced water injected belowground into the Arbuckle formation in an effort to reduce the number of earthquakes in the state. Another consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by our customers to dispose of flowback and produced water and certain other oilfield fluids. Increased regulation and attention given to seismicity events suspected of having been induced by injection of oilfield fluids into underground disposal wells also could lead to greater opposition to, and litigation concerning, oil and natural gas activities utilizing injection wells for waste disposal. Any of these developments may result in our customers having to limit disposal well volumes, disposal rates or locations, or require our customers or third party disposal well operators that are used to dispose of customers’ produced water to shut down disposal wells, which developments could adversely affect our customers’ business and result in a corresponding decrease in the need for our services, which could have a material adverse effect on our business, financial condition, and results of operations. 
+Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities may serve to limit future oil and natural gas exploration and production activities and could have a material adverse effect on our results of operations and business. 
+Currently, hydraulic fracturing is generally exempt from regulation under the SDWA UIC program and is typically regulated by state oil and gas commissions or similar agencies. However, federal agencies have conducted investigations or asserted regulatory authority over certain aspects of the process. For example, in late 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. Additionally, the EPA has asserted regulatory authority pursuant to the SDWA’s UIC program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities, as well as published an Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. The EPA also published final CAA regulations in 2012 and 2016 governing performance standards, including standards for the capture of emissions released during oil and natural gas hydraulic fracturing. Moreover, in 2016, the EPA published an effluent limit guideline final 
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+rule prohibiting the discharge of produced water from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The BLM published a final rule in 2015 that established new or more stringent standards relating to hydraulic fracturing on federal and Native American lands, but the BLM rescinded the 2015 rule in late 2017; however, litigation challenging the BLM’s decision to rescind the 2015 rule is pending in federal district court. From time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. In the event that new federal restrictions relating to the hydraulic fracturing process are adopted in areas where we or our customers conduct business, we or our customers may incur additional costs or permitting requirements to comply with such federal requirements that may be significant and, in the case of our customers, also could result in added restrictions, delays or curtailments in the pursuit of exploration, development, or production activities, which would in turn reduce the demand for our services. 
+Moreover, some states and local governments have adopted, and other governmental entities are considering adopting, regulations that could impose more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations, including states where we or our customers operate. For example, Texas, Colorado and North Dakota among others have adopted regulations that impose new or more stringent permitting, disclosure, disposal, and well construction requirements on hydraulic fracturing operations. States could also elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York. Local land use restrictions, such as city ordinances, may also restrict drilling in general and/or hydraulic fracturing in particular. 
+Additionally, certain interest groups in Colorado opposed to oil and natural gas development generally, and hydraulic fracturing in particular, have from time to time advanced various options for ballot initiatives that, if approved, would revise either statutory law or the state constitution in a manner that would effectively prohibit or make such exploration and production activities in the state more difficult or expensive in the future. For example, in each of the November 2014, 2016 and 2018 general election cycles, ballot initiatives have been pursued, with the 2018 initiative making the November 2018 ballot, seeking to increase setback distances between new oil and natural gas development and specific occupied structures and/or certain environmentally sensitive or recreational areas that, if adopted, may have had significant adverse impacts on new oil and natural gas developments in the state. However, in each election cycle, the ballot initiative either did not secure a place on the general ballot or, as was the case in November 2018, was defeated. In the event that ballot initiatives or other regulatory programs arising out of protests or opposition by non-governmental organizations are adopted and result in more stringent limitations on the production and development of oil and natural gas in areas where we or our customers conduct operations, whether in Colorado or in another state, we may incur significant costs to comply with such requirements or our customers may experience restrictions, delays or curtailments in the permitting or pursuit of exploration, development, or production activities, which could reduce demand for our services. Such compliance costs or reduced demand for our services could have a material adverse effect on our business, prospects, results of operations, financial conditions, and liquidity. 
+Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to, and litigation concerning, oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays for our customers or increased operating costs in the production of oil and natural gas, including from the developing shale plays, or could make it more difficult for us and our customers to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and natural gas wells and an associated decrease in demand for our services and increased compliance costs and time, which could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition. 
+Changes in transportation regulations may increase our costs and negatively impact our results of operations. 
+We are subject to various transportation regulations including as a motor carrier by the DOT and by various federal, state and tribal agencies, whose regulations include certain permit requirements of highway and safety authorities. These regulatory authorities exercise broad powers over our trucking operations, generally governing such matters as the authorization to engage in motor carrier operations, safety, equipment testing, driver requirements and specifications and insurance requirements. The trucking industry is subject to possible regulatory and legislative changes that may impact our operations, such as changes in fuel emissions limits, hours of service regulations that govern the amount of time a driver may drive or work in any specific period and requiring onboard electronic logging devices or limits on vehicle weight and size. As the federal government continues to develop and propose regulations relating to fuel quality, engine efficiency and GHG emissions, we may experience an increase in costs related to truck purchases and maintenance, impairment of equipment productivity, a decrease in the residual value of vehicles, unpredictable fluctuations in fuel prices and an increase in operating expenses. Increased truck traffic may contribute to deteriorating road conditions in some areas where our operations are performed. Our operations, including routing and weight restrictions, could be affected by road construction, road repairs, detours and state and local regulations and ordinances restricting access to certain roads. Proposals to increase federal, state or local taxes, including taxes on motor fuels, are also made from time to time, and any such increase would increase our operating costs. Also, state and local regulation of permitted routes and times on specific roadways could adversely affect our operations. We cannot predict whether, or in what 
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+form, any legislative or regulatory changes or municipal ordinances applicable to our logistics operations will be enacted and to what extent any such legislation or regulations could increase our costs or otherwise adversely affect our business or operations. 
+We are subject to environmental and occupational health and safety laws and regulations that may expose us to significant costs and liabilities. 
+Our operations and the operations of our customers are subject to numerous federal, tribal, regional, state and local laws and regulations relating to protection of the environment including natural resources, health and safety aspects of our operations and waste management, including the transportation and disposal of waste and other materials. These laws and regulations may impose numerous obligations on our operations and the operations of our customers, including the acquisition of permits or other approvals to conduct regulated activities, the imposition of restrictions on the types, quantities and concentrations of various substances that may be released into the environment or injected in non-productive formations below ground in connection with oil and natural gas drilling and production activities, the incurrence of capital expenditures to mitigate or prevent releases of materials from our equipment, facilities or from customer locations where we are providing services, the imposition of substantial liabilities for pollution resulting from our operations, and the application of specific health and safety criteria addressing worker protection. Any failure on our part or the part of our customers to comply with these laws and regulations could result in assessment of sanctions including administrative, civil and criminal penalties; imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures; the occurrence of restrictions, delays or cancellations in the permitting, performance or development of projects or operations; and the issuance of orders enjoining performance of some or all of our operations in a particular area. 
+Our business activities present risks of incurring significant environmental costs and liabilities, including costs and liabilities resulting from our handling of oilfield and other wastes, because of air emissions and wastewater discharges related to our operations, and due to historical oilfield industry operations and waste disposal practices. Moreover, accidental releases or spills may occur in the course of our operations or at facilities where our wastes are taken for reclamation or disposal, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for injuries to persons or damages to properties or natural resources. Some environmental laws and regulations may impose strict liability, which means that in some situations we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Remedial costs and other damages arising as a result of environmental laws and costs associated with changes in environmental laws and regulations could be significant and have a material adverse effect on our liquidity, combined results of operations and combined financial condition. 
+Laws and regulations protecting the environment generally have become more stringent in recent years and are expected to continue to do so, which could lead to material increases in costs for future environmental compliance and remediation. New laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement with respect to environmental matters could restrict, delay or curtail exploratory or developmental drilling for oil and natural gas by our customers and could limit our well servicing opportunities. For example, in 2015 the EPA issued a final rule under the CAA, lowering the NAAQS for ground-level ozone from 75 parts per billion to 70 parts per billion under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. In 2017 and 2018, the EPA issued area designations with respect to ground-level ozone as either “attainment/unclassifiable,” “unclassifiable” or “nonattainment.” Additionally, in November 2018, the EPA issued final requirements that apply to state, local, and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone. State implementation of the revised NAAQS could, among other things, require installation of new emission controls on some of our or our customer’s equipment, result in longer permitting timelines, and significantly increase our or our customers’ capital expenditures and operating costs. In another example, pursuant to a consent decree issued by the U.S. District Court for the District of Columbia in 2016, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations that could result in oil and natural gas exploration and production wastes being regulated as hazardous wastes, or sign a determination that revision of the regulations is necessary. If the EPA proposes a rulemaking for revised oil and natural gas wastes regulations, the consent decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. We may not be able to recover some or any of our costs of compliance with these laws and regulations from insurance. 
+Silica-related legislation, health issues and litigation could have a material adverse effect on our business, reputation or results of operations. 
+We are subject to laws and regulations relating to human exposure to crystalline silica. For example, in 2016, OSHA published a final rule that established a more stringent permissible exposure limit for exposure to respirable crystalline silica and provided other provisions to protect employees, such as requirements for exposure assessments, methods for controlling exposure, respiratory protection, medical surveillance, hazard communication, and recording. Compliance with most aspects of the 2016 rule relating to hydraulic fracturing was required by June 2018, and the 2016 rule further requires compliance with 
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+engineering control obligations to limit exposures to respirable crystalline silica in connection with hydraulic fracturing activities by June 2021. Historically, our environmental compliance costs with respect to existing crystalline silica requirements have not had a material adverse effect on our results of operations; however, federal regulatory authorities, including OSHA, and analogous state agencies may continue to propose changes in their regulations regarding workplace exposure to crystalline silica, such as permissible exposure limits and required controls and personal protective equipment. We may not be able to comply with any new laws and regulations that are adopted, and any new laws and regulations could have a material adverse effect on our operating results by requiring us to modify or cease our operations. 
+In addition, the inhalation of respirable crystalline silica is associated with the lung disease silicosis. There is evidence of an association between crystalline silica exposure or silicosis and lung cancer and a possible association with other diseases, including immune system disorders such as scleroderma. These health risks have been, and may continue to be, a significant issue confronting the hydraulic fracturing industry. Concerns over silicosis and other potential adverse health effects, as well as concerns regarding potential liability from the use of hydraulic fracture sand, may have the effect of discouraging our customers’ use of our hydraulic fracture sand. The actual or perceived health risks of handling hydraulic fracture sand could materially and adversely affect hydraulic fracturing service providers, including us, through reduced use of hydraulic fracture sand, the threat of product liability or employee lawsuits, increased scrutiny by federal, state and local regulatory authorities of us and our customers or reduced financing sources available to the hydraulic fracturing industry. 
+Anti-indemnity provisions enacted by many states may restrict or prohibit a party’s indemnification of us. 
+We typically enter into agreements with our customers governing the provision of our services, which usually include certain indemnification provisions for losses resulting from operations. Such agreements may require each party to indemnify the other against certain claims regardless of the negligence or other fault of the indemnified party; however, many states place limitations on contractual indemnity agreements, particularly agreements that indemnify a party against the consequences of its own negligence. Furthermore, certain states, including Texas, New Mexico and Wyoming, have enacted statutes generally referred to as “oilfield anti-indemnity acts” expressly prohibiting certain indemnity agreements contained in or related to oilfield services agreements. Such anti-indemnity acts may restrict or void a party’s indemnification of us, which could have a material adverse effect on our business, financial condition, prospects and results of operations. 
+Oil and natural gas companies’ operations using hydraulic fracturing are substantially dependent on the availability of water. Restrictions on the ability to obtain water for exploration and production activities and the disposal of flowback and produced water may impact their operations and have a corresponding adverse effect on our business, results of operations and financial condition. 
+Water is an essential component of shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Our oil and natural gas producing customers’ access to water to be used in these processes may be adversely affected due to reasons such as periods of extended drought, privatization, third party competition for water in localized areas or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. The occurrence of these or similar developments may result in limitations being placed on allocations of water due to needs by third party businesses with more senior contractual or permitting rights to the water. Our customers’ inability to locate or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact their exploration and production operations and have a corresponding adverse effect on our business, results of operations and financial condition. 
+Moreover, the imposition of new environmental regulations and other regulatory initiatives could include increased restrictions on our producing customers’ ability to dispose of flowback and produced water generated in hydraulic fracturing or other fluids resulting from exploration and production activities. Applicable laws, including the CWA, impose restrictions and strict controls regarding the discharge of pollutants into waters of the United States and require that permits or other approvals be obtained to discharge pollutants to such waters. In 2015, the EPA and the Corps released a final rule outlining their position on the federal jurisdictional reach over waters of the United States, including wetlands, but legal challenges to this rule followed. Beginning in the first quarter of 2017, the EPA and the Corps agreed to reconsider the 2015 rule and, thereafter, the agencies have (i) published a proposed rule in 2017 to rescind the 2015 rule and recodify the regulatory text that governed waters of the United States prior to promulgation of the 2015 rule, (ii) published a final rule in February 2018 adding a February 6, 2020 applicable date to the 2015 rule, and (iii) published a proposed rule in December 2018 re-defining the CWA’s jurisdiction over waters of the United States for which the agencies will seek public comment. The 2015 and February 2018 final rules are being challenged by various factions in the federal district court and implementation of the 2018 rule has been enjoined to twenty-eight states pending resolution of various federal district court challenges. As a result of these legal developments, future implementation of the 2015 rule is uncertain at this time. Any expansion of the CWA’s jurisdiction in areas where we or our customers operate, could impose additional permitting obligations on us and our customers. 
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+Additionally, regulations implemented under the CWA and similar state laws prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. In 2016, the EPA published final regulations concerning produced water discharges from hydraulic fracturing and certain other natural gas operations to publicly-owned wastewater treatment plants. The CWA and analogous state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and hazardous substances. Compliance with current and future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells and any inability to secure transportation and access to disposal wells with sufficient capacity to accept all of our flowback and produced water on economic terms may increase our customers’ operating costs and could result in restrictions, delays, or cancellations of our customers’ operations, the extent of which cannot be predicted. 
+Our current and future indebtedness could adversely affect our financial condition. 
+As of February 28, 2019, we had $111.7 million outstanding under our Term Loan Facility and no borrowings outstanding under our ABL Facility (defined herein) with a borrowing base of $177.4 million, except for a letter of credit in the amount of $0.3 million. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements.” 
+Moreover, subject to the limits contained in our ABL Facility and Term Loan Facility (collectively, the “Credit Facilities”), we may incur substantial additional debt from time to time. Any borrowings we may incur in the future would have several important consequences for our future operations, including that: 
+• 
+covenants contained in the documents governing such indebtedness may require us to meet or maintain certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our industry, such as being able to take advantage of acquisition opportunities when they arise; 
+• 
+our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes may be limited; 
+• 
+we may be competitively disadvantaged to our competitors that are less leveraged or have greater access to capital resources; and 
+• 
+we may be more vulnerable to adverse economic and industry conditions. 
+If we incur indebtedness in the future, we may have significant principal payments due at specified future dates under the documents governing such indebtedness. Our ability to meet such principal obligations will be dependent upon future performance, which in turn will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. Our business may not continue to generate sufficient cash flow from operations to repay any incurred indebtedness. If we are unable to generate sufficient cash flow from operations, we may be required to sell assets, to refinance all or a portion of such indebtedness or to obtain additional financing. 
+Our Credit Facilities subject us to financial and other restrictive covenants. These restrictions may limit our operational or financial flexibility and could subject us to potential defaults under our Credit Facilities. 
+Our Credit Facilities subject us to restrictive covenants, including, but not limited to, restrictions on incurring additional debt and certain distributions. Our ability to comply with these financial condition tests can be affected by events beyond our control and we may not be able to do so. 
+The Credit Facilities are not subject to financial covenants unless our liquidity, as defined in the agreements governing the Credit Facilities, drops below a specified level, at which time we will be required to maintain certain fixed charge coverage ratios. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements.” 
+If our liquidity falls below the prescribed level and we are unable to remain in compliance with the financial covenants of our Credit Facilities, then amounts outstanding thereunder may be accelerated and become due immediately. Any such acceleration could have a material adverse effect on our financial condition and results of operations. 
+Increases in interest rates could adversely impact the price of our shares, our ability to issue equity or incur debt for acquisitions or other purposes. 
+Interest rates on future borrowings, credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our shares, and a rising interest rate environment could have an adverse impact on the price of our shares, our ability to issue equity or incur debt for acquisitions or other purposes. 
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+Fuel conservation measures could reduce demand for oil and natural gas which would in turn reduce the demand for our services. 
+Fuel conservation measures, alternative fuel requirements and increasing consumer demand for alternatives to oil and natural gas could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas may have a material adverse effect on our business, financial condition, prospects, results of operations and cash flows. Additionally, the increased competitiveness of alternative energy sources (such as wind, solar geothermal, tidal, and biofuels) could reduce demand for hydrocarbons and therefore for our services, which would lead to a reduction in our revenues. 
+Unsatisfactory safety performance may negatively affect our customer relationships and, to the extent we fail to retain existing customers or attract new customers, adversely impact our revenues. 
+Our ability to retain existing customers and attract new business is dependent on many factors, including our ability to demonstrate that we can reliably and safely operate our business in a manner that is consistent with applicable laws, rules and permits, which legal requirements are subject to change. Existing and potential customers consider the safety record of their third-party service providers to be of high importance in their decision to engage such providers. If one or more accidents were to occur at one of our operating sites, the affected customer may seek to terminate or cancel its use of our equipment or services and may be less likely to continue to use our services, which could cause us to lose substantial revenues. Furthermore, our ability to attract new customers may be impaired if they elect not to engage us because they view our safety record as unacceptable. In addition, it is possible that we will experience multiple or particularly severe accidents in the future, causing our safety record to deteriorate. This may be more likely as we continue to grow, if we experience high employee turnover or labor shortage, or hire inexperienced personnel to bolster our staffing needs. 
+Climate change legislation and regulations restricting or regulating emissions of greenhouse gases could result in increased operating and capital costs and reduced demand for our hydraulic fracturing services. 
+Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. 
+At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted rules under authority of the existing CAA that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions, which reviews could require securing PSD permits at covered facilities emitting GHGs and meeting “best available control technology” standards for those GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the U.S., including, among others, onshore and offshore production facilities, which include certain of our producing customers’ operations. In 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. 
+Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In 2016, the EPA published NSPS Subpart OOOOa, which requires certain new, modified or reconstructed equipment and processes in the oil and natural gas source category to reduce these methane gas and volatile organic compound (“VOC”) emissions. These Subpart OOOOa standards will expand previously issued NSPS Subpart OOOO published by the EPA in 2012 by using certain equipment-specific emissions control practices. However, in 2017, the EPA published a proposed rule to stay certain portions of these Subpart OOOOa standards for two years but the rule was not finalized. Rather, in February 2018, the EPA finalized amendments to certain requirements of the 2016 final rule, and in September 2018 the EPA proposed additional amendments, including rescission of certain requires and revisions to other requirements, such as fugitive emissions monitoring frequency. Furthermore, in late 2016, the BLM published a final rule that established, among other things, requirements to reduce methane emissions by regulating venting, flaring and leaks from oil and natural gas production activities on onshore federal and Native American lands. However, in September 2018, the BLM published a final rule that rescinds most of the new requirements of the 2016 final rule and codifies the BLM’s prior approach to venting and flaring but the rule rescinding the 2016 final rule has been challenged in federal court and remains pending. In the event that the EPA’s 2016 or the BLM’s 2016 rules should remain or be placed in effect, or should any other new methane emission standards be imposed on the oil and natural gas sector, such requirements could result in increased costs to our or our customers’ operations as well as result in restrictions, delays or curtailments in such operations, which costs, restrictions, delays or curtailments could adversely affect our business. In April 2016 the United States entered into the Paris Agreement to limit GHG emissions through individually determined reduction goals every five years beginning in 2020. However, in August 2017, the U.S. State Department informed 
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+the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time. The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows. 
+Notwithstanding potential risks related to climate change, the International Energy Agency estimates that oil and natural gas will continue to represent a major share of global energy use through 2040, and other studies by the private sector project continued growth in demand for the next two decades. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector. Ultimately this could make it more difficult to secure funding for exploration and production or midstream activities. Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our operations. 
+The Endangered Species Act and Migratory Bird Treaty Act and other restrictions intended to protect certain species of wildlife govern our and our oil and natural gas producing customers’ operations and additional restrictions may be imposed in the future, which constraints could have an adverse impact on our ability to expand some of our existing operations or limit our customers’ ability to develop new oil and natural gas wells. 
+Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife, which may limit our ability to operate in protected areas. Permanent restrictions imposed to protect endangered or threatened species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. 
+For example, the ESA restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the MBTA. To the extent species that are listed under the ESA or similar state laws, or are protected under the MBTA, live in the areas where we or our oil and natural gas producing customers’ operate, our and our customers’ abilities to conduct or expand operations and construct facilities could be limited or be forced to incur material additional costs. Moreover, our customer’s drilling activities may be delayed, restricted or precluded in protected habitat areas or during certain seasons, such as breeding and nesting seasons. Some of our operations and the operations of our customers are located in areas that are designated as habitats for protected species. 
+Moreover, as a result of one or more settlements approved by the federal government, the FWS must make determinations on the listing of numerous species as endangered or threatened under the ESA pursuant to specific timelines. The designation of previously unidentified endangered or threatened species could indirectly cause us to incur additional costs, cause our or our oil and natural gas producing customers’ operations to become subject to operating restrictions or bans, and limit future development activity in affected areas. The FWS and similar state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially restrict use of or access to federal, state and private lands. 
+We may have difficulty managing growth of our business, which could adversely affect our financial condition and results of operations. 
+As a recently formed company, growth of our business could place a significant strain on our financial, technical, operational and management resources. As we expand the scope of our activities and our geographic coverage through organic growth, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, engineers and other professionals in the oilfield services industry, could have a material adverse effect on our business, financial condition, results of operations and our ability to successfully or timely execute our business plan. 
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+We rely on a few key employees whose absence or loss could adversely affect our business. 
+Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team, including our chief executive officer, chief financial officer and president, could disrupt our operations. We do not have any written employment agreement with our executives at this time. Further, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of any of our key employees. 
+We may be subject to risks in connection with acquisitions. 
+We have completed and may, in the future, pursue asset acquisitions or acquisitions of businesses. The process of upgrading acquired assets to our specifications and integrating acquired assets or businesses may involve unforeseen costs and delays or other operational, technical and financial difficulties and may require a significant amount time and resources. Our failure to incorporate acquired assets or businesses into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations. Such events could also mean an acquisition that we expected to be accretive is not accretive and, in extreme cases, the asset is idle. 
+Our industry overall has experienced a high rate of employee turnover. Any difficulty we experience replacing or adding personnel could have a material adverse effect on our liquidity, results of operations and financial condition. 
+We are dependent upon the available labor pool of skilled employees and may not be able to find enough skilled labor to meet our needs, which could have a negative effect on our growth. We are also subject to the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions. Our services require skilled workers who can perform physically demanding work. As a result of our industry volatility, including pronounced declines in drilling activity, as well as the demanding nature of the work, many workers have left the hydraulic fracturing industry to pursue employment in different fields. Though our historical turnover rates have been significantly lower than those of our competitors, if we are unable to retain or meet growing demand for skilled technical personnel, our operating results and our ability to execute our growth strategies may be adversely affected. 
+Technology advancements in well service technologies, including those involving hydraulic fracturing, could have a material adverse effect on our business, financial condition and results of operations. 
+The hydraulic fracturing industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As competitors and others use or develop new technologies or technologies comparable to ours in the future, we may lose market share or be placed at a competitive disadvantage. Further, we may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of our competitors may have greater financial, technical and personnel resources than we do, which may allow them to gain technological advantages or implement new technologies before we can. Additionally, we may be unable to implement new technologies or services at all, on a timely basis or at an acceptable cost. New technology could also make it easier for our customers to vertically integrate their operations, thereby reducing or eliminating the need for our services. Limits on our ability to effectively use or implement new technologies may have a material adverse effect on our business, financial condition and results of operations. 
+We may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition, prospects and results of operations. 
+Our services are subject to inherent risks that can cause personal injury or loss of life, damage to or destruction of property, equipment or the environment or the suspension of our operations. Litigation arising from operations where our services are provided, may cause us to be named as a defendant in lawsuits asserting potentially large claims including claims for exemplary damages. We maintain what we believe is customary and reasonable insurance to protect our business against these potential losses, but such insurance may not be adequate to cover our liabilities, and we are not fully insured against all risks. 
+In addition, our customers assume responsibility for, including control and removal of, all other pollution or contamination which may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling and completion fluids. We may have liability in such cases if we are grossly negligent or commit willful acts. Our customers generally agree to indemnify us against claims arising from their employees’ personal injury or death to the extent that, in the case of our hydraulic fracturing operations, their employees are injured by such operations, unless resulting from our gross negligence or willful misconduct. Our customers also generally agree to indemnify us for loss or destruction of customer-owned property or equipment. In turn, we agree to indemnify our customers for loss or destruction of property or 
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+equipment we own and for liabilities arising from personal injury to or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. However, we might not succeed in enforcing such contractual liability allocation or might incur an unforeseen liability falling outside the scope of such allocation. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operation. 
+Seasonal weather conditions and natural disasters could severely disrupt normal operations and harm our business. 
+Our operations are located in different regions of the United States. Some of these areas, including the DJ Basin, Powder River Basin and Williston Basin, are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice or rain, we may be unable to move our equipment between locations, thereby reducing our ability to provide services and generate revenues. The exploration activities of our customers may also be affected during such periods of adverse weather conditions. Additionally, extended drought conditions in our operating regions could impact our ability or our customers’ ability to source sufficient water or increase the cost for such water. As a result, a natural disaster or inclement weather conditions could severely disrupt the normal operation of our business and adversely impact our financial condition and results of operations. 
+If we are unable to fully protect our intellectual property rights, we may suffer a loss in our competitive advantage or market share. 
+We do not have patents or patent applications relating to many of our key processes and technology. If we are not able to maintain the confidentiality of our trade secrets, or if our competitors are able to replicate our technology or services, our competitive advantage would be diminished. We also cannot assure you that any patents we may obtain in the future would provide us with any significant commercial benefit or would allow us to prevent our competitors from employing comparable technologies or processes. 
+We may be adversely affected by disputes regarding intellectual property rights of third parties. 
+Third parties from time to time may initiate litigation against us by asserting that the conduct of our business infringes, misappropriates or otherwise violates intellectual property rights. We may not prevail in any such legal proceedings related to such claims, and our products and services may be found to infringe, impair, misappropriate, dilute or otherwise violate the intellectual property rights of others. If we are sued for infringement and lose, we could be required to pay substantial damages and/or be enjoined from using or selling the infringing products or technology. Any legal proceeding concerning intellectual property could be protracted and costly regardless of the merits of any claim and is inherently unpredictable and could have a material adverse effect on our financial condition, regardless of its outcome. 
+If we were to discover that our technologies or products infringe valid intellectual property rights of third parties, we may need to obtain licenses from these parties or substantially re-engineer our products in order to avoid infringement. We may not be able to obtain the necessary licenses on acceptable terms, or at all, or be able to re-engineer our products successfully. If our inability to obtain required licenses for our technologies or products prevents us from selling our products, that could adversely impact our financial condition and results of operations. 
+Additionally, we currently license certain third party intellectual property in connection with our business, and the loss of any such license could adversely impact our financial condition and results of operations. 
+We may be subject to interruptions or failures in our information technology systems. 
+We rely on sophisticated information technology systems and infrastructure to support our business, including process control technology. Any of these systems may be susceptible to outages due to fire, floods, power loss, telecommunications failures, usage errors by employees, computer viruses, cyber-attacks or other security breaches, or similar events. The failure of any of our information technology systems may cause disruptions in our operations, which could adversely affect our sales and profitability. 
+We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss. 
+The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain processing activities. For example, we depend on digital technologies to perform many of our services and to process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems and networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of business operations. In addition, certain cyber incidents, such as 
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+surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we will likely be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. Our insurance coverage for cyberattacks may not be sufficient to cover all the losses we may experience as a result of such cyberattacks. 
+A terrorist attack or armed conflict could harm our business. 
+The occurrence or threat of terrorist attacks in the United States or other countries, anti-terrorist efforts and other armed conflicts involving the United States or other countries, including continued hostilities in the Middle East, may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all. 
+We engage in transactions with related parties and such transactions present possible conflicts of interest that could have an adverse effect on us. 
+We have entered into a significant number of transactions with related parties. Related party transactions create the possibility of conflicts of interest with regard to our management, including that: 
+• 
+we may enter into contracts between us, on the one hand, and related parties, on the other, that are not the result of arm’s-length transactions; 
+• 
+our executive officers and directors that hold positions of responsibility with related parties may be aware of certain business opportunities that are appropriate for presentation to us as well as to such other related parties and may present such business opportunities to such other parties; and 
+• 
+our executive officers and directors that hold positions of responsibility with related parties may have significant duties with, and spend significant time serving, other entities and may have conflicts of interest in allocating time. 
+Such conflicts could cause an individual in our management to seek to advance his or her economic interests or the economic interests of certain related parties above ours. Further, the appearance of conflicts of interest created by related party transactions could impair the confidence of our investors. Our audit committee reviews these transactions. Notwithstanding this, it is possible that a conflict of interest could have a material adverse effect on our liquidity, results of operations and financial condition. 
+Our historical financial statements may not be indicative of future performance. 
+Due to the significant increase in our capacity, our movement into new basins and our acquisitions of certain assets, comparisons of our current and future operating results with prior periods are difficult. As a result, our limited historical financial performance as the owner of the acquired assets may make it difficult for stockholders to evaluate our business and results of operations to date and to assess our future prospects and viability. Furthermore, as a result of the volatility in the demand for well services and our future implementation of new business initiatives and strategies, our historical results of operations are not necessarily indicative of our ongoing operations and the operating results to be expected in the future. 
+We may record losses or impairment charges related to idle assets or assets that we sell. 
+Prolonged periods of low utilization, changes in technology or the sale of assets below their carrying value may cause us to experience losses. These events could result in the recognition of impairment charges that negatively impact our financial results. Significant impairment charges as a result of a decline in market conditions or otherwise could have a material adverse effect on our results of operations in future periods. 
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+Risks Related to Our Class A Common Stock 
+Liberty Inc. is a holding company. Liberty Inc.’s only material asset is its equity interest in Liberty LLC, and Liberty Inc. is accordingly dependent upon distributions from Liberty LLC to pay taxes, make payments under the TRAs and cover its corporate and other overhead expenses. 
+Liberty Inc. is a holding company and has no material assets other than its equity interest in Liberty LLC. Please see “Item 1. Business—Initial Public Offering and Corporate Reorganization Transaction.” Liberty Inc. has no independent means of generating revenue. To the extent Liberty LLC has available cash, Liberty Inc. intends to cause Liberty LLC to make (i) generally pro rata distributions to its unit holders, including Liberty Inc., in an amount sufficient to allow Liberty Inc. to pay its taxes and to allow it to make payments under the TRAs and (ii) non-pro rata payments to Liberty Inc. to reimburse it for its corporate and other overhead expenses. To the extent that Liberty Inc. needs funds and Liberty LLC or its subsidiaries are restricted from making such distributions or payments under applicable law or regulation or under the terms of any future financing arrangements, or are otherwise unable to provide such funds, Liberty Inc.’s liquidity and financial condition could be materially adversely affected. 
+Moreover, because Liberty Inc. has no independent means of generating revenue, Liberty Inc.’s ability to make payments under the TRAs is dependent on the ability of Liberty LLC to make distributions to Liberty Inc. in an amount sufficient to cover its obligations under the TRAs. This ability, in turn, may depend on the ability of Liberty LLC’s subsidiaries to make distributions to it. The ability of Liberty LLC, its subsidiaries and other entities in which it directly or indirectly holds an equity interest to make such distributions will be subject to, among other things, (i) the applicable provisions of Delaware law (or other applicable jurisdiction) that may limit the amount of funds available for distribution and (ii) restrictions in relevant debt instruments issued by Liberty LLC or its subsidiaries and other entities in which it directly or indirectly holds an equity interest. To the extent that Liberty Inc. is unable to make payments under the TRAs for any reason, such payments will be deferred and will accrue interest until paid. 
+The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act, and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner. 
+As a public company, we need to comply with various laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act, related regulations of the SEC and the requirements of the NYSE, which we were not required to comply with as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of the Board and management and will significantly increase our costs and expenses. 
+Furthermore, we are required to have our independent registered public accounting firm attest to the effectiveness of our internal controls, in accordance with Section 404 of the Sarbanes Oxley Act for our fiscal year ending December 31, 2019. Our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed. Compliance with these requirements may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner. 
+In addition, it is possible that being a public company subject to these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on the Board or as executive officers. We cannot predict or estimate the amount of additional costs we may incur or the timing of such costs. 
+If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our Class A Common Stock. 
+Effective internal controls are necessary for us to provide reliable financial reports, safeguard our assets, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports, safeguard our assets, or prevent fraud, our reputation and operating results could be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our existing internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. An ineffective system of internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our Class A Common Stock. 
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+We are subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we are unable to timely comply with Section 404 or if the costs related to compliance are significant, our profitability, stock price, results of operations and financial condition could be materially adversely affected. 
+We are required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002. Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. During 2018, we evaluated our existing controls against the standards adopted by the Committee of Sponsoring Organizations of the Treadway Commission and concluded our internal control over financial reporting was effective as of December 31, 2018. As we are not an accelerated filer nor a large accelerated filer as defined in Rule 12b-2 under Section 404, our independent registered public accounting firm is not yet required to formally attest to the effectiveness of our internal control over financial reporting for the year ended December 31, 2018. During the course of our ongoing evaluation and integration of the internal control over financial reporting, we may identify areas requiring improvement, and we may have to design enhanced processes and controls to address issues identified through this review. 
+An active, liquid and orderly trading market for our Class A Common Stock may not be maintained, and our stock price may be volatile. 
+Prior to January 2018, our Class A Common Stock was not traded on any market. An active, liquid and orderly trading market for our Class A Common Stock may not be maintained. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. The market price of our Class A Common Stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our Class A Common Stock, you could lose a substantial part or all of your investment in our Class A Common Stock. 
+The following factors could affect our stock price: 
+• 
+quarterly variations in our financial and operating results; 
+• 
+the public reaction to our press releases, our other public announcements and our filings with the SEC; 
+• 
+strategic actions by our competitors; 
+• 
+changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts; 
+• 
+speculation in the press or investment community; 
+• 
+the failure of specific research analysts to cover our Class A Common Stock; 
+• 
+sales of our Class A Common Stock by us or other stockholders, or the perception that such sales may occur; 
+• 
+changes in accounting principles, policies, guidance, interpretations or standards; 
+• 
+additions or departures of key management personnel; 
+• 
+actions by our stockholders; 
+• 
+general market conditions, including fluctuations in commodity prices; 
+• 
+domestic and international economic, legal and regulatory factors unrelated to our performance; and 
+• 
+the realization of any risks described under this “Risk Factors” section. 
+The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our Class A Common Stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management’s attention and resources and harm our business, operating results and financial condition. 
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+We are a “controlled company” within the meaning of the NYSE rules and, as a result, qualify for and rely on exemptions from certain corporate governance requirements. As a result, our stockholders do not have the same protections afforded to stockholders of companies that cannot rely on such exemptions and are subject to such requirements. 
+Riverstone/Carlyle Energy Partners IV, L.P., R/C IV Liberty Holdings, L.P. and R/C Energy IV Direct Partnership, L.P. (collectively “Riverstone”) and certain of the Legacy Owners (with Riverstone, collectively, the “Principal Stockholders”) party to a stockholders’ agreement with us control a majority of the combined voting power of our Common Stock. As a result, we are a “controlled company” within the meaning of the NYSE corporate governance standards. Under these rules, a company of which more than 50% of the voting power is held by an individual, a group or another company is a “controlled company” and may elect not to comply with certain corporate governance requirements of the NYSE, including the requirement (1) that a majority of the board of directors consist of independent directors, (2) that we have a nominating and corporate governance committee composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities, and (3) that we have a compensation committee composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities. We intend to rely on some or all of these exemptions. As a result, we do not have a majority of independent directors or a nominating or governance committee, and our compensation committee does not consist entirely of independent directors. Accordingly, our stockholders do not have the same protections afforded to stockholders of companies subject to all of the corporate governance requirements of the NYSE. 
+The Principal Stockholders collectively hold a substantial majority of the voting power of our Common Stock 
+The Principal Stockholders hold over 50% of our Common Stock. As a result, such owners are able to control matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our Class A Common Stock will be able to affect the way we are managed or the direction of our business. The interests of the Principal Stockholders with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other stockholders. 
+For example, the Principal Stockholders may have different tax positions from us, especially in light of the TRAs, that could influence their decisions regarding whether and when to support the disposition of assets, the incurrence or refinancing of new or existing indebtedness, or the termination of the TRAs and acceleration of our obligations thereunder. In addition, the determination of future tax reporting positions, the structuring of future transactions and the handling of any challenge by any taxing authority to our tax reporting positions may take into consideration the Principal Stockholders tax position or other considerations which may differ from the considerations of us or our other stockholders. For further details of the TRAs, see Note 10, “Income Taxes” to the consolidated and combined financial statements included in “Item 8. Financial Statements and Supplementary Data.” 
+Given this concentrated ownership, the Principal Stockholders would have to approve any potential acquisition of us. Furthermore, in connection with the IPO, we entered into a stockholders’ agreement with the Principal Stockholders. The stockholders’ agreement provides Riverstone with the right to designate a certain number of nominees to the Board so long as Riverstone and its affiliates collectively beneficially own at least 10% of the outstanding shares of our Class A Common Stock. In addition, the stockholders’ agreement provides Riverstone the right to approve certain material transactions so long as Riverstone and its affiliates own at least 20% of the outstanding shares of our Class A Common Stock. The existence of significant stockholders may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company. Moreover, the Principal Stockholders concentration of stock ownership may adversely affect the trading price of our Class A Common Stock to the extent investors perceive a disadvantage in owning stock of a company with significant stockholders. 
+Certain of our executive officers and directors have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities. 
+Certain of our executive officers and directors, who are responsible for managing the direction of our operations, hold positions of responsibility with other entities (including affiliated entities) that are in the oil and natural gas industry. For example, Christopher Wright, our Chairman and Chief Executive Officer, is the Executive Chairman of Liberty Resources LLC (“Liberty Resources”), an E&P company operating primarily in the Williston Basin, a position which may require a portion of his time. These executive officers and directors may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, they may present potential business opportunities to other entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for 
+32 
+Table of Contents 
+other entities with which they are affiliated, and as a result, they may elect not to present those opportunities to us. These conflicts may not be resolved in our favor. 
+Riverstone and its respective affiliates are not limited in their ability to compete with us, and the corporate opportunity provisions in our amended and restated certificate of incorporation could enable Riverstone to benefit from corporate opportunities that might otherwise be available to us. 
+Our governing documents provide that Riverstone and its respective affiliates (including portfolio investments of Riverstone and its affiliates) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In particular, subject to the limitations of applicable law, our amended and restated certificate of incorporation will, among other things: 
+• 
+permits Riverstone and its respective affiliates to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and 
+• 
+provides that if Riverstone or its respective affiliates, or any employee, partner, member, manager, officer or director of Riverstone or its respective affiliates who is also one of our directors or officers, becomes aware of a potential business opportunity, transaction or other matter, they have no duty to communicate or offer that opportunity to us. 
+Riverstone or its respective affiliates may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Furthermore, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to not be available to us or causing them to be more expensive for us to pursue. In addition, Riverstone and its respective affiliates may dispose of oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase any of those assets. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to time presented to Riverstone and its respective affiliates could adversely impact our business or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours. 
+Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A Common Stock and could deprive our investors of the opportunity to receive a premium for their shares. 
+Our amended and restated certificate of incorporation authorizes the Board to issue preferred stock without stockholder approval in one or more series, designate the number of shares constituting any series, and fix the rights, preferences, privileges and restrictions thereof, including dividend rights, voting rights, rights and terms of redemption, redemption price or prices and liquidation preferences of such series. If the Board elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders. These provisions include: 
+• 
+after we cease to be a controlled company, dividing the Board into three classes of directors, with each class serving staggered three-year terms; 
+• 
+after we cease to be a controlled company, and subject to the terms of our stockholders’ agreement, providing that all vacancies, including newly created directorships, may, except as otherwise required by law or, if applicable, the rights of holders of a series of preferred stock, only be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum (prior to such time, vacancies may also be filled by stockholders holding a majority of the outstanding Common Stock); 
+• 
+after we cease to be a controlled company, permitting any action by stockholders to be taken only at an annual meeting or special meeting rather than by a written consent of the stockholders, subject to the rights of any series of preferred stock with respect to such rights; 
+• 
+after we cease to be a controlled company, permitting special meetings of our stockholders to be called only by our Chief Executive Officer, the chairman of the Board and the Board pursuant to a resolution adopted by the affirmative vote of a majority of the total number of authorized directors whether or not there exist any vacancies in previously authorized directorships (prior to such time, a special meeting may also be called by our Corporate Secretary at the request of Riverstone); 
+• 
+after we cease to be a controlled company, and subject to the rights of the holders of shares of any series of our preferred stock and the terms of our stockholders’ agreement, requiring the affirmative vote of the holders of at least 66 2 ⁄ 3 % in voting power of all then outstanding Common Stock entitled to vote generally in the election of 
+33 
+Table of Contents 
+directors, voting together as a single class, to remove any or all of the directors from office at any time, and directors will be removable only for “cause”; 
+• 
+prohibiting cumulative voting in the election of directors; 
+• 
+establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders; and 
+• 
+providing that the board of directors is expressly authorized to adopt, or to alter or repeal our bylaws. 
+In addition, certain change of control events have the effect of accelerating the payments due under the TRAs, which could be substantial and accordingly serve as a disincentive to a potential acquirer of our Company. Please see “—In certain cases, payments under the TRAs may be accelerated and/or significantly exceed the actual benefits, if any, Liberty Inc. realizes in respect of the tax attributes subject to the TRAs.” 
+Our amended and restated certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents. 
+Our amended and restated certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim against us or any director or officer or other employee of ours arising pursuant to any provision of the Delaware General Corporation Law (the “DGCL”), our amended and restated certificate of incorporation or our bylaws, or (iv) any action asserting a claim against us or any director or officer or other employee of ours that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our Common Stock will be deemed to have notice of, and consented to, the provisions of our amended and restated certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations. 
+If a substantial number of shares of Class A Common Stock becomes available for sale and are sold in a short period of time, the market price of our Class A Common Stock could decline and our stockholders may be diluted. 
+If our Principal Stockholders sell substantial amounts of our Class A Common Stock in the public market, the market price of our Class A Common Stock could decrease. The perception in the public market that our Principal Stockholders might sell shares of our Class A Common Stock could also create a perceived overhang and depress our market price. Over 50% of our Class A Common Stock outstanding is held by our Legacy Owners. In addition, our Legacy Owners, which includes the Principal Stockholders, hold Liberty LLC Units and shares of our Class B Common Stock which were exchangeable for an additional 45,207,372 shares of Class A Common Stock as of December 31, 2018. In addition, our Principal Stockholders, will have substantial demand and incidental registration rights for their shares. 
+Future sales or issuances of our Class A Common Stock in the public market, or the perception that such sales may occur, could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us. 
+We may sell additional shares of Class A Common Stock in subsequent public offerings. We may also issue additional shares of Class A Common Stock or convertible securities. We presently have 68,741,273 shares of Class A Common Stock issued and outstanding. The Liberty Unit Holders are party to a registration rights agreement, which requires us to effect the registration of any shares of Class A Common Stock that they receive in exchange for their Liberty LLC Units in certain circumstances. 
+We have 12,908,734 shares of our Class A Common Stock issued or reserved for issuance under our long term incentive plan. Subject to the satisfaction of vesting conditions and the requirements of Rule 144, shares registered under the registration statement on Form S-8 may be made available for resale immediately in the public market without restriction. 
+We cannot predict the size of future issuances of our Class A Common Stock or securities convertible into Class A Common Stock or the effect, if any, that future issuances and sales of shares of our Class A Common Stock will have on the 
+34 
+Table of Contents 
+market price of our Class A Common Stock. Sales of substantial amounts of our Class A Common Stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A Common Stock. 
+Liberty Inc. is required to make payments under the TRAs for certain tax benefits that it may claim, and the amounts of such payments could be significant. 
+The TRAs generally provide for the payment by Liberty Inc. to each TRA Holder of 85% of the net cash savings, if any, in U.S. federal, state and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that Liberty Inc. actually realizes (or is deemed to realize in certain circumstances) as a result of certain increases in tax basis, net operating losses available to Liberty Inc. as a result of the Corporate Reorganization, and certain benefits attributable to imputed interest. Liberty Inc. will retain the benefit of the remaining 15% of these cash savings. 
+The term of each of the TRAs continues until all tax benefits that are subject to such TRAs have been utilized or expired, unless Liberty Inc. experiences a change of control (as defined in the TRAs, which includes certain mergers, asset sales and other forms of business combinations) or the TRAs are terminated early (at Liberty Inc.’s election or as a result of its breach), and Liberty Inc. makes the termination payments specified in such TRAs. In addition, payments Liberty Inc. makes under the TRAs will be increased by any interest accrued from the due date (without extensions) of the corresponding tax return. In the event that the TRAs are not terminated, the payments under the TRAs are anticipated to commence in 2020 and to continue for 15 years after the date of the last redemption of the Liberty LLC Units. 
+The payment obligations under the TRAs are Liberty Inc.’s obligations and not obligations of Liberty LLC, and Liberty Inc. expects that the payments Liberty Inc. will be required to make under the TRAs will be substantial. Estimating the amount and timing of payments that may become due under the TRAs is by its nature imprecise. For purposes of the TRAs, cash savings in tax generally are calculated by comparing Liberty Inc.’s actual tax liability (determined by using the actual applicable U.S. federal income tax rate and an assumed combined state and local income tax rate) to the amount it would have been required to pay had it not been able to utilize any of the tax benefits subject to the TRAs. The amounts payable, as well as the timing of any payments, under the TRAs are dependent upon significant future events and assumptions, including the timing of the redemptions of Liberty LLC Units, the price of our Class A Common Stock at the time of each redemption, the extent to which such redemptions are taxable transactions, the amount of the redeeming unit holder’s tax basis in its Liberty LLC Units at the time of the relevant redemption, the depreciation and amortization periods that apply to the increase in tax basis, the amount of net operating losses available to Liberty Inc. as a result of the Corporate Reorganization, the amount and timing of taxable income Liberty Inc. generates in the future, the U.S. federal income tax rate then applicable, and the portion of Liberty Inc.’s payments under the TRAs that constitute imputed interest or give rise to depreciable or amortizable tax basis. 
+The payments under the TRAs will not be conditioned upon a holder of rights under each of the TRAs having a continued ownership interest in Liberty Inc. or Liberty LLC. For further details of the TRAs, see Note 10, “Income Taxes” to the consolidated and combined financial statements included in “Item 8. Financial Statements and Supplementary Data.” 
+In certain cases, payments under the TRAs may be accelerated and/or significantly exceed the actual benefits, if any, Liberty Inc. realizes in respect of the tax attributes subject to the TRAs. 
+If Liberty Inc. experiences a change of control (as defined under the TRAs, which includes certain mergers, asset sales and other forms of business combinations) or the TRAs terminate early (at Liberty Inc.’s election or as a result of its breach), Liberty Inc. would be required to make a substantial, immediate lump-sum payment. This payment would equal the present value of hypothetical future payments that could be required to be paid under the TRAs (determined by applying a discount rate equal to the long-term Treasury rate in effect on the applicable date plus 300 basis points). The calculation of hypothetical future payments will be based upon certain assumptions and deemed events set forth in the TRAs, including (i) that Liberty Inc. has sufficient taxable income to fully utilize the tax benefits covered by the TRAs, (ii) that any Liberty LLC Units (other than those held by Liberty Inc.) outstanding on the termination date are deemed to be redeemed on the termination date, and (iii) certain loss or credit carryovers will be utilized over five years beginning with the taxable year that includes the termination date. Any early termination payments may be made significantly in advance of, and may materially exceed, the actual realization, if any, of the future tax benefits to which the termination payments relate. 
+If Liberty Inc. experiences a change of control (as defined under the TRAs) or the TRAs otherwise terminate early, Liberty Inc.’s obligations under the TRAs could have a substantial negative impact on its liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. For example, if the TRAs were terminated at December 31, 2018, the estimated termination payments would, in the aggregate, be approximately $67.3 million (calculated using a discount rate equal to the long-term Treasury rate in effect on the applicable date plus 300 basis points, applied against an undiscounted liability of $110.0 million ). The foregoing number is merely an 
+35 
+Table of Contents 
+estimate and the actual payment could differ materially. There can be no assurance that we will be able to finance our obligations under the TRAs. 
+For further details of the TRAs, see Note 10, “Income Taxes” to the consolidated and combined financial statements included in “Item 8. Financial Statements and Supplementary Data.” 
+In the event that Liberty Inc. ’ s payment obligations under the TRAs are accelerated upon certain mergers, other forms of business combinations or other changes of control, the consideration payable to holders of our Class A Common Stock could be substantially reduced. 
+If Liberty Inc. experiences a change of control (as defined under the TRAs, which includes certain mergers, asset sales and other forms of business combinations), Liberty Inc. would be obligated to make a substantial, immediate lump-sum payment, and such payment may be significantly in advance of, and may materially exceed, the actual realization, if any, of the future tax benefits to which the payment relates. As a result of this payment obligation, holders of our Class A Common Stock could receive substantially less consideration in connection with a change of control transaction than they would receive in the absence of such obligation. Further, our payment obligations under the TRAs will not be conditioned upon the TRA Holders’ having a continued interest in Liberty Inc. or Liberty LLC. Accordingly, the TRA Holders’ interests may conflict with those of the holders of our Class A Common Stock. Please read “Risk Factors—Risks Related to our Class A Common Stock—In certain cases, payments under the TRAs may be accelerated and/or significantly exceed the actual benefits Liberty Inc. realizes, if any, in respect of the tax attributes subject to the TRAs” and Note 10, “Income Taxes” to the consolidated and combined financial statements included in “Item 8. Financial Statements and Supplementary Data.” 
+We will not be reimbursed for any payments made under the TRAs in the event that any tax benefits are subsequently disallowed. 
+Payments under the TRAs are based on the tax reporting positions that we will determine. The TRA Holders will not reimburse us for any payments previously made under the TRAs if any tax benefits that have given rise to payments under the TRAs are subsequently disallowed, except that excess payments made to any TRA Holder will be netted against payments that would otherwise be made to such TRA Holder, if any, after our determination of such excess. As a result, in such circumstances, Liberty Inc. could make payments that are greater than its actual cash tax savings, if any, and may not be able to recoup those payments, which could adversely affect Liberty Inc.’s liquidity. 
+If Liberty LLC were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, Liberty Inc. and Liberty LLC might be subject to potentially significant tax inefficiencies, and Liberty Inc. would not be able to recover payments previously made by it under the TRAs even if the corresponding tax benefits were subsequently determined to have been unavailable due to such status. 
+Liberty Inc. intends to operate such that Liberty LLC does not become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes. A “publicly traded partnership” is a partnership the interests of which are traded on an established securities market or are readily tradable on a secondary market or the substantial equivalent thereof. Under certain circumstances, redemptions of Liberty LLC Units pursuant to the Redemption Right, Liberty Inc.’s Call Right or other transfers of Liberty LLC Units could cause Liberty LLC to be treated as a publicly traded partnership. Applicable U.S. Treasury regulations provide for certain safe harbors from treatment as a publicly traded partnership, and Liberty Inc. intends to operate such that redemptions or other transfers of Liberty LLC Units qualify for one or more such safe harbors. For example, Liberty Inc. intends to limit the number of unit holders of Liberty LLC, and the Liberty LLC Agreement, which was entered into in connection with the closing of the IPO, provides for limitations on the ability of holders of Liberty LLC Units to transfer their Liberty LLC Units and provides Liberty Inc., as managing member of Liberty LLC, with the right to impose restrictions (in addition to those already in place) on the ability of holders of Liberty LLC Units to redeem their Liberty LLC Units pursuant to the Redemption Right to the extent Liberty Inc. believes it is necessary to ensure that Liberty LLC will continue to be treated as a partnership for U.S. federal income tax purposes. 
+If Liberty LLC were to become a publicly traded partnership, significant tax inefficiencies might result for Liberty Inc. and for Liberty LLC, including as a result of Liberty Inc.’s inability to file a consolidated U.S. federal income tax return with Liberty LLC. In addition, Liberty Inc. would no longer have the benefit of certain increases in tax basis covered under the TRAs, and Liberty Inc. would not be able to recover any payments previously made by it under the TRAs, even if the corresponding tax benefits (including any claimed increase in the tax basis of Liberty LLC’s assets) were subsequently determined to have been unavailable. 
+36 
+Table of Contents 
+In certain circumstances, Liberty LLC is required to make tax distributions and tax advances to the Liberty Unit Holders, including us, and the tax distributions and tax advances that Liberty LLC is required to make may be substantial. 
+Pursuant to the Liberty LLC Agreement, Liberty LLC makes generally pro rata cash distributions, or tax distributions, to the holders of Liberty LLC Units, including Liberty Inc., in an amount sufficient to allow Liberty Inc. to pay its taxes and to allow it to make payments under the TRAs. In addition to these pro rata distributions, the Liberty Unit Holders are entitled to receive tax advances in an amount sufficient to allow each of the Liberty Unit Holders to pay its respective taxes on such holder’s allocable share of Liberty LLC’s taxable income. Any such tax advance is calculated after taking into account certain other distributions or payments received by the Liberty Unit Holders from Liberty LLC or Liberty Inc. Under the applicable tax rules, Liberty LLC is required to allocate net taxable income disproportionately to its members in certain circumstances. Tax advances are determined based on an assumed individual tax rate and are repaid upon exercise of the Redemption Right or the Call Right, as applicable. 
+Funds used by Liberty LLC to satisfy its tax distribution and tax advance obligations are not available for reinvestment in our business. Moreover, the tax distributions and tax advances Liberty LLC is required to make may be substantial, and is likely to exceed (as a percentage of Liberty LLC’s income) the overall effective tax rate applicable to a similarly situated corporate taxpayer. In addition, because these payments are calculated with reference to an assumed tax rate, and because of the disproportionate allocation of net taxable income, these payments may exceed the actual tax liability for some of the holders of Liberty LLC Units. 
+We may issue preferred stock whose terms could adversely affect the voting power or value of our Class A Common Stock. 
+Our amended and restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A Common Stock respecting dividends and distributions, as the Board may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our Class A Common Stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the Class A Common Stock. 
+If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our Class A Common Stock or if our operating results do not meet their expectations, our stock price could decline. 
+The trading market for our Class A Common Stock may be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of the Company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover the Company downgrades our Class A Common Stock or if our operating results do not meet their expectations, our stock price could decline. 
+37 
+Table of Contents 
+Item 1B. Unresolved Staff Comments 
+None. 
+Item 2. Properties 
+Information regarding our properties is contained in “Item 1. Business” and is incorporated by reference herein. 
+Item 3. Legal Proceedings 
+On February 23, 2017, SandBox Logistics, LLC and Oren Technologies, LLC (collectively “Sandbox”) filed suit in the Houston Division of the U.S. District Court for the Southern District of Texas against Proppant Express Investments, LLC, Proppant Express Solutions, LLC, and Liberty Oilfield Services LLC (“LOS”). SandBox alleged that LOS willfully infringed multiple U.S. patents and breached an agreement between SandBox and LOS by “directing, controlling, and funding” inter partes review requests before the U.S. Patent and Trademark Office. In July 2018, SandBox requested permission from the court to allege additional breach of contract claims against LOS, including alleged breaches of a confidentiality agreement and an exclusive purchasing covenant. The court denied these requests in September 2018. On December 19, 2018, the U.S. District Court for the Southern District of Texas entered an order dismissing the claims against LOS with prejudice. 
+We are named defendants in certain lawsuits, investigations and claims arising in the ordinary course of conducting our business, including certain environmental claims and employee-related matters, and we expect that we will be named defendants in similar lawsuits, investigations and claims in the future. While the outcome of these lawsuits, investigations and claims cannot be predicted with certainty, we do not expect these matters to have a material adverse impact on our business, results of operations, cash flows or financial condition. We have not assumed any liabilities arising out of these existing lawsuits, investigations and claims. 
+Item 4. Mine Safety Disclosures 
+Not applicable. 
+38 
+Table of Contents 
+PART II 
+Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+Market Information 
+On January 17, 2018, we consummated an initial public offering of our Class A Common Stock at a price of $17.00 per share. Our Class A Common Stock is traded on the NYSE under the symbol “LBRT.” Prior to that time, there was no public market for our Class A Common Stock. There is no public market for our Class B Common Stock. 
+Holders of our Common Stock 
+As of February 26, 2019, there were 72 stockholders of record of our Class A Common Stock and 15 stockholders of record of our Class B Common Stock. The number of record holders is based upon the actual number of holders registered on the books of the Company at such date and does not include holders of shares in “street names” or persons, partnerships, associations, corporations or other entities identified in security position listings maintained by depositories. 
+Dividend Policy 
+The Company paid quarterly cash dividends of $0.05 per share of Class A Common Stock on September 20 and December 20, 2018 to shareholders of record as of September 6 and December 6, 2018, respectively. The declaration of dividends is subject to approval by the Board and to the Board’s continuing determination that such declaration of dividends is in the best interests of the Company and its stockholders. Future dividends may be adjusted at the Board’s discretion based on market conditions and capital availability. We are not required to pay dividends, and our stockholders will not be guaranteed, or have contractual or other rights to receive, dividends. 
+Recent Sales of Unregistered Equity Securities 
+We had no sales of unregistered equity securities during the period covered by this Annual Report on Form 10-K that were not previously reported in a Current Report on Form 8-K. 
+Purchase of Equity Securities By the Issuer and Affiliated Purchasers 
+On September 10, 2018, the Board authorized a share repurchase plan to repurchase up to $100.0 million of the Company’s Class A Common Stock through September 30, 2019. During the quarter ended December 31, 2018, Liberty LLC redeemed and retired 1,750,490 Liberty LLC Units from the Company for $ 29.0 million , and the Company repurchased and retired 1,750,490 shares of Class A Common Stock for $29.0 million , or $16.53 average price per share excluding commissions. The total remaining authorized amount available for future repurchases of Class A Common Stock under the share repurchase program was $17.1 million as of December 31, 2018 . 
+Period 
+Total number of shares purchased 
+Average price paid per share 
+Total number of shares purchased as part of publicly announced plans or programs (1) 
+Approximate dollar value of shares that may yet be purchased under the plans or programs 
+October 
+— 
+$ 
+— 
+— 
+$ 
+— 
+November 
+191,712 
+18.83 
+191,712 
+42,463,090 
+December 
+1,558,778 
+16.25 
+1,558,778 
+17,096,596 
+Total 
+1,750,490 
+$ 
+16.53 
+1,750,490 
+$ 
+17,096,596 
+(1) All repurchases are made under the share repurchase plan approved on September 10, 2018 by the Board. 
+The Company accounts for the purchase price of repurchased Class A Common Stock in excess of par value ($0.01 per share of Class A Common Stock) as a reduction of additional paid-in capital, and will continue to do so until additional paid-in capital is reduced to zero. Thereafter, any excess purchase price will be recorded as a reduction to retained earnings. 
+39 
+Table of Contents 
+Item 6. Selected Financial Data 
+The selected financial data set forth below was derived from our audited consolidated and combined financial statements and should be read in conjunction with “Item 1A. Risk Factors,” “Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations” and our audited consolidated and combined financial statements included in “Item 8. Financial Statements and Supplementary Data.” 
+Years Ended 
+December 31, 
+2018 
+2017 
+2016 
+2015 
+(in thousands, except per share and fleet data) 
+Statement of Operations Data: 
+Revenue: 
+Revenue 
+$ 
+2,132,032 
+$ 
+1,465,133 
+$ 
+356,890 
+$ 
+384,330 
+Revenue—related parties 
+23,104 
+24,722 
+17,883 
+71,074 
+Total revenue 
+2,155,136 
+1,489,855 
+374,773 
+455,404 
+Operating costs and expenses: 
+Cost of services (exclusive of depreciation and amortization shown separately below) 
+1,628,753 
+1,147,008 
+354,729 
+393,340 
+General and administrative 
+99,052 
+80,089 
+35,789 
+28,765 
+Depreciation and amortization 
+125,110 
+81,473 
+41,362 
+36,436 
+(Gain) loss on disposal of assets 
+(4,342 
+) 
+148 
+(2,673 
+) 
+423 
+Total operating costs and expenses 
+1,848,573 
+1,308,718 
+429,207 
+458,964 
+Operating income (loss) 
+306,563 
+181,137 
+(54,434 
+) 
+(3,560 
+) 
+Other expense: 
+Interest expense 
+(17,145 
+) 
+(11,875 
+) 
+(6,126 
+) 
+(5,501 
+) 
+Interest expense—related party 
+— 
+(761 
+) 
+— 
+— 
+Total interest expense 
+(17,145 
+) 
+(12,636 
+) 
+(6,126 
+) 
+(5,501 
+) 
+Net income (loss) before income taxes 
+289,418 
+168,501 
+(60,560 
+) 
+(9,061 
+) 
+Income tax expense 
+40,385 
+— 
+— 
+— 
+Net income (loss) 
+249,033 
+168,501 
+(60,560 
+) 
+(9,061 
+) 
+Less: Net income (loss) attributable to Predecessor, prior to Corporate Reorganization 
+8,705 
+168,501 
+(60,560 
+) 
+(9,061 
+) 
+Less: Net income attributable to noncontrolling interests 
+113,979 
+— 
+— 
+— 
+Net income attributable to Liberty Oilfield Services Inc. stockholders 
+$ 
+126,349 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+Net Income Per Share Data (1): 
+Net income attributable to Liberty Oilfield Services Inc. stockholders per common share 
+Basic 
+$ 
+1.84 
+Diluted 
+$ 
+1.81 
+Weighted average common shares outstanding 
+Basic 
+68,838 
+Diluted 
+117,838 
+Statement of Cash Flows Data: 
+Cash flows provided by (used in) operating activities 
+$ 
+351,258 
+$ 
+195,109 
+$ 
+(40,708 
+) 
+$ 
+6,119 
+Cash flows used in investing activities 
+255,492 
+310,043 
+96,351 
+38,492 
+Cash flows (used in) provided by financing activities 
+(8,775 
+) 
+119,771 
+148,543 
+21,485 
+Other Financial Data: 
+Capital expenditures 
+$ 
+258,835 
+$ 
+311,794 
+$ 
+102,428 
+$ 
+38,492 
+EBITDA (2) 
+$ 
+431,673 
+$ 
+262,610 
+$ 
+(13,072 
+) 
+$ 
+32,876 
+Adjusted EBITDA (2) 
+$ 
+438,234 
+$ 
+280,728 
+$ 
+(5,588 
+) 
+$ 
+41,213 
+Total Fleets at beginning of period (3) 
+19 
+10 
+6 
+5 
+Total Fleets at end of period (3) 
+22 
+19 
+10 
+6 
+Average Active Fleets (4) 
+21.3 
+15.1 
+7.4 
+5.9 
+Adjusted EBITDA per Average Active Fleet (5) 
+$ 
+20,574 
+$ 
+18,591 
+$ 
+(755 
+) 
+$ 
+6,985 
+40 
+Table of Contents 
+Balance Sheet Data (at end of period): 
+Total assets 
+$ 
+1,116,501 
+$ 
+852,103 
+$ 
+451,845 
+$ 
+296,971 
+Long-term debt (including current portion) 
+106,524 
+196,357 
+103,805 
+110,232 
+Total liabilities 
+375,687 
+416,851 
+222,873 
+162,920 
+Redeemable common units (6) 
+— 
+42,486 
+— 
+— 
+Total equity or member equity 
+740,814 
+392,766 
+228,972 
+134,051 
+(1) 
+Net Income Per Share Data above reflects the net income to Class A Common Stock and net income per share for the period indicated based on a weighted average number of Class A Common Stock outstanding for period subsequent to the Corporate Reorganization on January 17, 2018. 
+(2) 
+EBITDA and Adjusted EBITDA are non-GAAP financial measures. For definitions of EBITDA and Adjusted EBITDA and a reconciliation of each to our most directly comparable financial measure calculated and presented in accordance with accounting principles generally accepted in the United States of America (“GAAP”), please read “Item 7. Management's Discussion and Analysis of Financial Conditions and Results of Operations—Comparison of Non-GAAP Financial Measures.” 
+(3) 
+Total Fleets represents the number of deployed and active fleets as of the designated date. 
+(4) 
+Average Active Fleets is calculated as the daily average of the active fleets for the period presented. 
+(5) 
+Adjusted EBITDA per Average Active Fleet is calculated as Adjusted EBITDA for the period divided by the Average Active Fleets, as defined above. 
+(6) 
+The redeemable common units were deemed extinguished and satisfied in full in the Corporate Reorganization. 
+41 
+Table of Contents 
+Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 
+The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Item 6. Selected Financial Data” and our audited consolidated and combined financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a variety of risks and uncertainties, including those described in this Annual Reporting on Form 10-K under “Cautionary Note Regarding Forward-Looking Statements” and “Item 1A. Risk Factors.” We assume no obligation to update any of these forward-looking statements. 
+Overview 
+We are an independent provider of hydraulic fracturing services to onshore oil and natural gas E&P companies in North America. We have grown from one active hydraulic fracturing fleet in December 2011 to 22 active fleets in February 2019. We added three fleets during the year ended December 31, 2018. We provide our services primarily in the Permian Basin, the Eagle Ford Shale, the DJ Basin, the Williston Basin and the Powder River Basin. 
+We believe the following characteristics both distinguish us from our competitors and are the foundations of our business: forming ongoing partnerships of trust and innovation with our customers; developing and utilizing technology to maximize well performance; and promoting a people-centered culture focused on our employees, customers and suppliers. We have developed strong relationships with our customers by investing significant time in fracture design collaboration, which substantially enhances their production economics. Our technological innovations have become even more critical as E&P companies have increased the completion complexity and fracture intensity of horizontal wells. We are proactive in developing innovative solutions to industry challenges, including developing: (i) our proprietary databases of U.S. unconventional wells to which we apply our proprietary multi-variable statistical analysis technologies to provide differential insight into fracture design optimization; (ii) our Liberty Quiet Fleet® design which significantly reduces noise levels compared to conventional hydraulic fracturing fleets; and (iii) hydraulic fracturing fluid systems tailored to the specific reservoir properties in the basins in which we operate. We foster a people-centered culture built around honoring our commitments to customers, partnering with our suppliers and hiring, training and retaining people that we believe to be the best talent in our field, enabling us to be one of the safest and most efficient hydraulic fracturing companies in the United States. 
+Recent Trends and Outlook 
+Demand for our hydraulic fracturing services is predominantly influenced by the level of drilling and completion by E&P companies, which, in turn, depends largely on the current and anticipated profitability of developing oil and natural gas reserves. More specifically, demand for our hydraulic fracturing services is driven by the completion of hydraulic fracturing stages in unconventional wells, which, in turn, is driven by several factors including rig count, well count, service intensity and the timing and style of well completions. 
+Macro Conditions 
+From the second half of 2016 and through the first half of 2018, we benefited from an upward trajectory in both crude oil prices and horizontal rig count, leading to price increases for our services, including increases in our revenue per average active fleet. The price of WTI crude oil averaged of $43.29, $50.80 and $65.23 during 2016, 2017 and 2018, respectively. According to a report by Baker Hughes, a GE company (“Baker Hughes”), the horizontal rig count in North America average 400, 737, and 900 during 2016, 2017 and 2018, respectively. 
+However, during the second half of 2018, the price of WTI crude oil decreased from an average of $70.98 in July 2018 to an average of $49.52 in December of 2018. Reductions in customer activity, in part due to the reduction in commodity prices, and an oversupply of staffed frac fleets led to a reduction in pricing for frac services in late 2018. 
+According to the U.S. Energy Information Administration Short-Term Energy Outlook released in January 2019, worldwide crude oil supply is expected to increase by 1.4 million barrels per day in 2019 led by production growth from the United States. 
+We expect to benefit from long-term macro industry trends that improve drilling economics such as (i) greater rig efficiencies that result in more wells drilled per rig in a given period and (ii) increased complexity and service intensity of well completions, including longer wellbore laterals, more and larger fracturing stages and higher proppant usage per well. We expect these industry trends to directly benefit hydraulic fracturing companies like us that have the expertise and technological ability to execute increasingly complex and intense well completions. 
+42 
+Table of Contents 
+Although there is uncertainty in the market about the level of customers’ drilling and completion activity in 2019, we expect demand for Liberty Inc.’s high-efficiency frac fleets to remain strong during 2019 due to the diversity of Liberty Inc.’s operating footprint, conversations with our customers and other factors. However, we cannot predict with any certainty when pricing for our frac services will increase. Customer activity levels influenced by commodity prices and the level of frac service supply will continue to impact the prices we charge our customers for our services. 
+Increase in Drilling Efficiency and Service Intensity of Completions 
+Over the past decade, E&P companies have focused on exploiting the vast resource potential available across many of North America’s unconventional resource plays through the application of horizontal drilling and completion technologies, including the use of multi-stage hydraulic fracturing, in order to increase recovery of oil and natural gas. As E&P companies have improved drilling and completion techniques to maximize return and efficiency, we believe several long term trends have emerged which have materially increased the service intensity of current completions. 
+Improved drilling economics from horizontal drilling and greater rig efficiencies . Unconventional resources are increasingly being targeted through the use of horizontal drilling. According to Baker Hughes, as reported on January 25, 2019, horizontal rigs accounted for approximately 88% of all rigs drilling in the United States, up from 74% as of December 31, 2014. Over the past several years, North American E&P companies have benefited from improved drilling economics driven by technologies that reduce the number of days, and the cost, of drilling wells. North American drilling rigs have incorporated newer technologies, which allow them to drill rock more effectively and quickly, meaning each rig can drill more wells in a given period. These include improved drilling technologies and the incorporation of geosteering techniques which allow better placement of the wellbore. Drilling rigs have also incorporated new technology which allows fully-assembled rigs to automatically “walk” from one location to the next without disassembling and reassembling the rig, greatly reducing the time it takes to move from one drilling location to the next. At the same time, E&P companies are shifting their development plans to incorporate multi-well pad development, which allows them to drill multiple horizontal wellbores from the same pad or location. The aggregate effect of these improved techniques and technologies have reduced the average days required to drill a well, which according to Coras Research, LLC (“Coras”), has dropped from 28 days in 2014 to 21 days in 2018. 
+Increased complexity and service intensity of horizontal well completions . In addition to improved rig efficiencies discussed above, E&P companies are also improving the subsurface techniques and technologies used to exploit unconventional resources. These improvements have targeted increasing the exposure of each wellbore to the reservoir by drilling longer horizontal lateral sections of the wellbore. To complete the well, hydraulic fracturing is applied in stages along the wellbore to break-up the resource so that oil and gas can be produced. As wellbores have increased in length, the number of stages has also increased. From 2014 to 2018, the average stages per horizontal well have increased from 21 stages per well to 38 stages per well, according to Coras. Further, E&P companies have improved production from each stage by applying increasing amounts of proppant in each stage, which better connects the well to the resource. The aggregate effect of increased number of stages and the increasing amount of proppant in each stage has greatly increased the total amount of proppant used in each well, according to Coras, from six million pounds per well in 2014 to over 13 million pounds per well in 2018. 
+These industry trends will directly benefit hydraulic fracturing companies like us that have the expertise and technological innovations to effectively service today’s more efficient oilfield drilling activity and the increasing complexity and intensity of well completions. Given the expected returns that E&P companies have reported for new well development activities due to improved rig efficiencies and increasing well completion complexity and intensity, we expect these industry trends to continue. 
+How We Generate Revenue 
+We currently generate revenue through the provision of hydraulic fracturing services. These services are performed under a variety of contract structures, primarily master service agreements as supplemented by statements of work, pricing agreements and specific quotes. A portion of our statements of work, under master service agreements, include provisions that establish pricing arrangements for a period of up to one year in length. However, the majority of those agreements provide for pricing adjustments based on market conditions. The majority of our services are priced based on prevailing market conditions and changing input costs at the time the services are provided, giving consideration to the specific requirements of the customer. 
+Our hydraulic fracturing services are performed in sections, which we refer to as fracturing stages. The estimated number of fracturing stages to be completed for a particular horizontal well is determined by the customer’s well completion design. We recognize revenue for each fracturing stage completed, although our revenue per completed fracturing stage varies depending on the actual volumes and types of proppants, chemicals and fluid utilized for each fracturing stage. The number of 
+43 
+Table of Contents 
+fracturing stages that we are able to complete in a period is directly related to the number and utilization of our deployed fleets and size of stages. 
+Costs of Conducting Our Business 
+The principal expenses involved in conducting our business are direct cost of personnel, services and materials used in the provision of services, general and administrative expenses, and depreciation and amortization. A large portion of the costs we incur in our business are variable based on the number of hydraulic fracturing jobs and the requirements of services provided to our customers. We manage the level of our fixed costs, except depreciation and amortization, based on several factors, including industry conditions and expected demand for our services. 
+How We Evaluate Our Operations 
+We use a variety of qualitative, operational and financial metrics to assess our performance. First and foremost of these is a qualitative assessment of customer satisfaction because ensuring we are a valuable partner to our customers is the key to achieving our quantitative business metrics. Among other measures, management considers each of the following: 
+Revenue; 
+Operating Income (Loss); 
+EBITDA; 
+Adjusted EBITDA; 
+Annualized Adjusted EBITDA per Average Active Fleet; 
+Net Income Before Taxes; and 
+Earnings per Share. 
+Revenue 
+We analyze our revenue by comparing actual monthly revenue to our internal projections for a given period and to prior periods to assess our performance. We also assess our revenue in relation to the number of fleets we have deployed (revenue per average active fleet) from period to period. 
+Operating Income (Loss) 
+We analyze our operating income (loss), which we define as revenues less direct operating expenses, depreciation and amortization and general and administrative expenses, to measure our financial performance. We believe operating income is a meaningful metric because it provides insight on profitability and true operating performance based on the historical cost basis of our assets. We also compare operating income to our internal projections for a given period and to prior periods. 
+EBITDA and Adjusted EBITDA 
+We view EBITDA and Adjusted EBITDA as important indicators of performance. We define EBITDA as net income (loss) before interest, income taxes, depreciation and amortization. We define Adjusted EBITDA as EBITDA adjusted to eliminate the effects of items such as new fleet or new basin start-up costs, costs of asset acquisition, gain or loss on the disposal of assets, asset impairment charges, bad debt reserves, and non-recurring expenses that management does not consider in assessing ongoing operating performance. Annualized Adjusted EBITDA per Average Active Fleet is calculated as Adjusted EBITDA annualized, divided by the Average Active Fleets for the same period. See “—Comparison of Non-GAAP Financial Measures” for more information and a reconciliation of EBITDA and Adjusted EBITDA to net income (loss), the most directly comparable financial measure calculated and presented in accordance with GAAP. 
+44 
+Table of Contents 
+Results of Operations 
+Year Ended December 31, 2018 , Compared to Year Ended December 31, 2017 
+Years Ended December 31, 
+Description 
+2018 
+2017 
+Change 
+(in thousands) 
+Revenue 
+$ 
+2,155,136 
+$ 
+1,489,855 
+$ 
+665,281 
+Cost of services, excluding depreciation and amortization shown separately 
+1,628,753 
+1,147,008 
+481,745 
+General and administrative 
+99,052 
+80,089 
+18,963 
+Depreciation and amortization 
+125,110 
+81,473 
+43,637 
+(Gain) loss on disposal of assets 
+(4,342 
+) 
+148 
+(4,490 
+) 
+Operating income 
+306,563 
+181,137 
+125,426 
+Interest expense 
+(17,145 
+) 
+(12,636 
+) 
+(4,509 
+) 
+Net income before taxes 
+289,418 
+168,501 
+120,917 
+Income tax expense 
+40,385 
+— 
+40,385 
+Net income 
+249,033 
+168,501 
+80,532 
+Less: Net income attributable to Predecessor, prior to the Corporate Reorganization 
+8,705 
+168,501 
+(159,796 
+) 
+Less: Net income attributable to noncontrolling interests 
+113,979 
+— 
+113,979 
+Net income attributable to Liberty Oilfield Services Inc. stockholders 
+$ 
+126,349 
+$ 
+— 
+$ 
+126,349 
+Revenue 
+Our revenue increased $665.3 million , or 44.7% , to $2.2 billion for the year ended December 31, 2018 compared to $1.5 billion for year ended December 31, 2017 . The increase was due to the combined effect of a 41.1% increase in average active fleets deployed and a 2.5% increase in revenue per average active fleet. Our revenue per average active fleet increased to approximately $101.2 million for the year ended December 31, 2018 as compared to approximately $98.7 million for the year ended December 31, 2017 , based on 21.3 and 15.1 average active fleets during those respective periods. The increase in revenue per active fleet was due to improved pricing and throughput, compared to the prior year, in conjunction with increased demand for our services. 
+Cost of Services 
+Cost of services (excluding depreciation and amortization) increased $481.7 million , or 42.0% , to $1.6 billion for the year ended December 31, 2018 compared to $1.1 billion for the year ended December 31, 2017 . The higher expense is due to an increase in services provided and reflects a $280.0 million increase attributable to materials, which was driven by a 34.8% increase in material volumes in the year ended December 31, 2018 compared to the same period in 2017 . Additionally, the cost of components used in our repairs and maintenance operations increased by $81.9 million , offset by fuel costs which decreased across the same period by $4.8 million . Personnel costs increased by 39.4% to support the increased activity, including a 41.1% increase in average active fleets deployed, for the year ended December 31, 2018 as compared to the year ended December 31, 2017 . 
+General and Administrative Expenses 
+General and administrative expenses increased by $19.0 million , or 23.7% , to $99.1 million for the year ended December 31, 2018 compared to $80.1 million for the year ended December 31, 2017 . Payroll and benefits, related office expenses and finance expenses increased approximately $3.9 million, $2.7 million and $4.8 million, respectively, in connection with the increase in head count to support our expanded scope of operations, as well as increased finance and legal services associated with the IPO during the year ended December 31, 2018 . In addition, non-cash stock based compensation expense of $4.3 million was recognized during the year ended December 31, 2018 compared to $0 during the prior year. 
+Depreciation and Amortization 
+Depreciation and amortization expense increased $43.6 million , or 53.6% , to $125.1 million for the year ended December 31, 2018 compared to $81.5 million for the year ended December 31, 2017 , due to nine additional hydraulic fracturing fleets deployed during 2017 that were in service for all of 2018, as well as three additional fleets deployed during the year ended December 31, 2018 . 
+45 
+Table of Contents 
+(Gain) Loss on Disposal of Assets 
+(Gain) loss on disposal of assets in 2018 increased $4.5 million to a gain of $4.3 million for the year ended December 31, 2018 compared to a loss of $0.1 million for the year ended December 31, 2017 . The increase is primarily due to a $11.5 million gain recognized during the year ended December 31, 2018 on insurance proceeds received in excess of losses incurred for damaged equipment resulting from an accidental fire in November 2018. 
+Operating Income 
+We realized operating income of $306.6 million for the year ended December 31, 2018 compared to operating income of $181.1 million for the year ended December 31, 2017 , primarily due to a 41.1% increase in average active fleets deployed described above. 
+Interest Expense 
+The increase in interest expense of $4.5 million , or 35.7% , to $17.1 million during the year ended December 31, 2018 compared to $12.6 million during the year ended December 31, 2017 , was primarily due to an increase of $5.8 million for interest expense on the term loan due to a higher weighted average interest rate on borrowings outstanding during the year ended December 31, 2018 , as well as a $1.6 million increase from debt issuance costs amortization. This increase was offset by a $1.9 million decrease in interest expense on the outstanding borrowings under our ABL Facility that was paid in full in January 2018 with the proceeds from the IPO. 
+Net Income Before Taxes 
+We realized net income before taxes of $289.4 million for the year ended December 31, 2018 compared to net income of $168.5 million for the year ended December 31, 2017 . The increase in net income is primarily attributable to our expanded scope of operations from the 41.1% increase in average active fleets deployed during the year ended December 31, 2018 . 
+Income Tax Expense 
+As a pass through entity prior to the IPO, the Predecessor was subject only to the Texas margin tax at a statutory rate of 1.0% and was not subject to U.S. federal income tax. Subsequent to the IPO, the pre-tax net income attributable to the Company is taxed at a combined U.S. federal and state tax rate of approximately 23.0%, while no tax is provided for the income attributable to the noncontrolling interests, which remains pass through income attributable to the holders of noncontrolling interests. We recognized $40.4 million of tax expense in the year ended December 31, 2018 , an effective rate of 14.0% , compared to $0 recognized during the year ended December 31, 2017 . This increase was attributable to our status as a corporation subject to U.S. federal income tax as well as a net increase in operating income, the components of which are discussed above. 
+Year Ended December 31, 2017 , Compared to Year Ended December 31, 2016 
+Years Ended December 31, 
+Description 
+2017 
+2016 
+Change 
+(in thousands) 
+Revenue 
+$ 
+1,489,855 
+$ 
+374,773 
+$ 
+1,115,082 
+Cost of services, excluding depreciation and amortization shown separately 
+1,147,008 
+354,729 
+792,279 
+General and administrative 
+80,089 
+35,789 
+44,300 
+Depreciation and amortization 
+81,473 
+41,362 
+40,111 
+Loss (gain) on disposal of assets 
+148 
+(2,673 
+) 
+2,821 
+Operating income (loss) 
+181,137 
+(54,434 
+) 
+235,571 
+Interest expense 
+(12,636 
+) 
+(6,126 
+) 
+(6,510 
+) 
+Net income (loss) 
+$ 
+168,501 
+$ 
+(60,560 
+) 
+$ 
+229,061 
+Revenue 
+Our revenue increased $1,115.1 million , or 297.5% , to $1,489.9 million for the year ended December 31, 2017 compared to $374.8 million for the year ended December 31, 2016 . The increase was due to the combined effect of a 104.0% increase in average active fleets deployed and a 94.8% increase in revenue per average active fleet. Our revenue per average active fleet increased to approximately $98.7 million for the year ended December 31, 2017 as compared to approximately $50.6 million for the year ended December 31, 2016 , based on 15.1 and 7.4 average active fleets deployed during those respective periods. 
+46 
+Table of Contents 
+The increase in revenue per active fleet was due to improved pricing and throughput in conjunction with increased demand for our services. 
+Cost of Services 
+Cost of services (excluding depreciation and amortization) increased $792.3 million , or 223.3% , to $1,147.0 million for the year ended December 31, 2017 compared to $354.7 million for the year ended December 31, 2016 . The higher expense is due to an increase in services provided and reflects a $488.4 million increase attributable to materials, which was driven by a 235.7% increase in material volumes in the year ended December 31, 2017 compared to the same period in 2016 . Additionally, the cost of components used in our repairs and maintenance operations increased by $96.6 million and fuel costs increased by $52.0 million. Personnel costs increased by 163.7% to support the increased activity, including a 104.0% increase in average active fleets deployed, for the year ended December 31, 2017 as compared to the year ended December 31, 2016 . 
+General and Administrative Expenses 
+General and administrative expenses increased by $44.3 million , or 123.8% , to $80.1 million for the year ended December 31, 2017 compared to $35.8 million for the year ended December 31, 2016 . Payroll and benefits, related office expenses and fleet start-up expenses increased approximately $26.2 million, $5.4 million and $9.7 million, respectively, in connection with the increase in head count to support our expanded scope of operations and the nine fleets deployed during the year ended December 31, 2017 . Additionally, other general and administrative expenses increased $3.1 million, primarily driven by a $1.1 million increase in management fees owed to Riverstone/Carlyle Energy Partners IV, L.P. 
+Depreciation and Amortization 
+Depreciation and amortization expense increased $40.1 million , or 97.0% , to $81.5 million for the year ended December 31, 2017 compared to $41.4 million for the year ended December 31, 2016 , due to four additional hydraulic fracturing fleets deployed during 2016 that were in service for all of 2017, as well as nine additional fleets deployed during the year ended December 31, 2017 . 
+Operating Income (Loss) 
+We realized operating income of $181.1 million for the year ended December 31, 2017 compared to an operating loss of $54.4 million for the year ended December 31, 2016 , primarily due to the increased number of hydraulic fracturing fleets deployed and the higher revenue per average active fleet in response to increased demand for our services. 
+Interest Expense 
+Interest expense increased $6.5 million , or 106.3% , to $12.6 million during the year ended December 31, 2017 compared to $6.1 million during the year ended December 31, 2016 , primarily due to $1.2 million of deferred financing costs written off in connection with the termination of previously outstanding debt and a $4.2 million increase in interest expense due to the increased average borrowings outstanding during the year ended December 31, 2017 compared to the same period in 2016. Additionally, we incurred $0.8 million of interest on a $60.0 million related party bridge loan that was outstanding during a portion of the three months ended June 30, 2017. 
+Net Income (Loss) 
+We realized net income of $168.5 million for the year ended December 31, 2017 compared to a net loss of $60.6 million for the year ended December 31, 2016 . Our net loss for the year ended December 31, 2016 resulted from the significant decrease in pricing for our hydraulic fracturing services following the dramatic decrease in drilling activity by E&P companies during the industry downturn from late 2014 through the first half of 2016. Our net income for the year ended December 31, 2017 was driven by recovery of the oil and gas industry beginning in the third quarter of 2016, as well as our expanded scope of operations following deployment of nine additional hydraulic fracturing fleets during the year ended December 31, 2017. 
+Comparison of Non-GAAP Financial Measures 
+We view EBITDA and Adjusted EBITDA as important indicators of performance. We define EBITDA as net income (loss) before interest, income taxes, depreciation and amortization. We define Adjusted EBITDA as EBITDA adjusted to eliminate the effects of items such as new fleet or new basin start-up costs, costs of asset acquisitions, gain or loss on the disposal of assets, asset impairment charges, bad debt reserves and non-recurring expenses that management does not consider in assessing ongoing performance. 
+47 
+Table of Contents 
+Our board of directors, management, investors and lenders use EBITDA and Adjusted EBITDA to assess our financial performance because it allows them to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure (such as varying levels of interest expense), asset base (such as depreciation and amortization) and other items that impact the comparability of financial results from period to period. We present EBITDA and Adjusted EBITDA because we believe they provide useful information regarding the factors and trends affecting our business in addition to measures calculated under GAAP. Additionally, the calculation of Adjusted EBITDA complies with the definition of Consolidated EBITDA, as defined in our Credit Facilities. See “—Liquidity and Capital Resources—Debt Agreements.” 
+Note Regarding Non-GAAP Financial Measures 
+EBITDA and Adjusted EBITDA are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures will provide useful information to investors in assessing our financial performance and results of operations. Net income (loss) is the GAAP measure most directly comparable to EBITDA and Adjusted EBITDA. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as an analytical tool due to exclusion of some but not all items that affect the most directly comparable GAAP financial measures. You should not consider EBITDA or Adjusted EBITDA in isolation or as substitutes for an analysis of our results as reported under GAAP. Because EBITDA and Adjusted EBITDA may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. 
+The following tables present a reconciliation of EBITDA and Adjusted EBITDA to our net income (loss), which is the most directly comparable GAAP measure for the periods presented: 
+Year Ended December 31, 2018 Compared to Year Ended December 31, 2017 : EBITDA and Adjusted EBITDA 
+Years Ended 
+December 31, 
+Description 
+2018 
+2017 
+Change 
+(in thousands) 
+Net income 
+$ 
+249,033 
+$ 
+168,501 
+$ 
+80,532 
+Depreciation and amortization 
+125,110 
+81,473 
+43,637 
+Interest expense 
+17,145 
+12,636 
+4,509 
+Income tax expense 
+40,385 
+— 
+40,385 
+EBITDA 
+$ 
+431,673 
+$ 
+262,610 
+$ 
+169,063 
+Fleet start-up costs 
+10,069 
+13,955 
+(3,886 
+) 
+Asset acquisition costs 
+632 
+2,470 
+(1,838 
+) 
+(Gain) loss on disposal of assets 
+(4,342 
+) 
+148 
+(4,490 
+) 
+Advisory services fees 
+202 
+1,545 
+(1,343 
+) 
+Adjusted EBITDA 
+$ 
+438,234 
+$ 
+280,728 
+$ 
+157,506 
+EBITDA was $431.7 million for the year ended December 31, 2018 compared to $262.6 million for the year ended December 31, 2017 . Adjusted EBITDA was $438.2 million for the year ended December 31, 2018 compared to $280.7 million for the year ended December 31, 2017 . The increases in EBITDA and Adjusted EBITDA resulted from the increased revenue and other factors described above under the captions Revenue , Cost of Services and General and Administrative Expenses above. 
+48 
+Table of Contents 
+Year Ended December 31, 2017 , Compared to Year Ended December 31, 2016 : EBITDA and Adjusted EBITDA 
+Years Ended December 31, 
+Description 
+2017 
+2016 
+Change 
+(in thousands) 
+Net income (loss) 
+$ 
+168,501 
+$ 
+(60,560 
+) 
+$ 
+229,061 
+Depreciation and amortization 
+81,473 
+41,362 
+40,111 
+Interest expense 
+12,636 
+6,126 
+6,510 
+EBITDA 
+$ 
+262,610 
+$ 
+(13,072 
+) 
+$ 
+275,682 
+Fleet start-up costs 
+13,955 
+4,280 
+9,675 
+Asset acquisition costs 
+2,470 
+5,420 
+(2,950 
+) 
+Loss (gain) on disposal of assets 
+148 
+(2,673 
+) 
+2,821 
+Advisory services fees 
+1,545 
+457 
+1,088 
+Adjusted EBITDA 
+$ 
+280,728 
+$ 
+(5,588 
+) 
+$ 
+286,316 
+EBITDA was $262.6 million for the year ended December 31, 2017 compared to $(13.1) million for the year ended December 31, 2016 . Adjusted EBITDA was $280.7 million for the year ended December 31, 2017 compared to $(5.6) million for the year ended December 31, 2016 . The increases in EBITDA and Adjusted EBITDA resulted from the increased revenue and other factors described above under the captions Revenue , Cost of Services and General and Administrative Expenses above. 
+Liquidity and Capital Resources 
+Overview 
+Historically, our primary sources of liquidity to date have been cash flows from operations, capital contributions from our owners and borrowings under our Credit Facilities. We expect to fund operations and organic growth with the proceeds from our IPO and cash flows from operations. Our primary uses of capital have been capital expenditures to support organic growth and funding ongoing operations, including maintenance and fleet upgrades. 
+On January 17, 2018, we completed our IPO of 14,640,755 shares of our Class A Common Stock at a public offering price of $17.00 per share, of which 14,340,214 shares were offered by us and 300,541 shares were offered by the selling shareholder. We received approximately $220.0 million in net proceeds after deducting approximately $23.8 million of underwriting discounts and commissions and other offering costs. We did not receive any proceeds from the sale of the shares of Class A Common Stock by the selling shareholder. We used approximately $25.9 million of net proceeds from the IPO to redeem ownership in us from certain Legacy Owners and contributed the remaining proceeds to Liberty LLC in exchange for Liberty LLC Units. Liberty LLC used a portion of the net proceeds (i) to fully repay our outstanding borrowings and accrued interest under our ABL Facility (as defined herein), totaling approximately $30.1 million , (ii) to repay 35% of our outstanding borrowings, accrued interest and prepayment premium under our Term Loan Facility (as defined herein), totaling approximately $62.5 million and (iii) for general corporate purposes, including repayment of additional indebtedness and funding capital expenditures. 
+Cash and cash equivalents increased by $87.0 million to $103.3 million as of December 31, 2018 compared to $16.3 million as of December 31, 2017, primarily attributable to net proceeds from the IPO. Going forward, we intend to finance the majority of our capital expenditures, contractual obligations and working capital needs with proceeds from the IPO and operating cash flows. We believe that our operating cash flow and available borrowings under our Credit Facilities will be sufficient to fund our operations for at least the next twelve months. 
+Cash Flows 
+The following table summarizes our cash flows for the periods indicated: 
+Years Ended December 31, 
+Description 
+2018 
+2017 
+Change 
+(in thousands) 
+Net cash provided by operating activities 
+$ 
+351,258 
+$ 
+195,109 
+$ 
+156,149 
+Net cash used in investing activities 
+(255,492 
+) 
+(310,043 
+) 
+54,551 
+Net cash (used in) provided by financing activities 
+(8,775 
+) 
+119,771 
+(128,546 
+) 
+Net increase in cash and cash equivalents 
+$ 
+86,991 
+$ 
+4,837 
+$ 
+82,154 
+49 
+Table of Contents 
+Analysis of Cash Flow Changes Between the Years Ended December 31, 2018 and 2017 
+Operating Activities . Net cash provided by operating activities was $351.3 million for the year ended December 31, 2018 , compared to net cash provided by operating activities of $195.1 million for the year ended December 31, 2017 . The $156.1 million increase in cash from operating activities was primarily attributable to a $665.3 million increase in revenues, offset by a $495.4 million increase in cash based operating expenses, both resulting from the increase in average active fleets from 15.1 in 2017 to 21.3 in 2018. Further, cash provided by operating activities during 2018 was reduced by $27.3 million cash paid for income taxes, and a $13.0 million decrease in funds used to satisfy working capital obligations. 
+Investing Activities . Net cash used in investing activities was $255.5 million for the year ended December 31, 2018 , compared to $310.0 million for the year ended December 31, 2017 . The $54.6 million decrease in net cash used in investing activities was primarily due to the acquisition of Titan Frac Services LLC and Texas real estate properties during the year ended December 31, 2017. 
+Financing Activities . Net cash used in financing activities was $8.8 million for the year ended December 31, 2018 , compared to net cash provided by financing activities of $119.8 million for the year ended December 31, 2017 . The $128.5 million decrease in cash provided by financing activities was primarily due to net repayment on debt of $92.8 million, equity repurchases of $82.9 million, distributions for taxes and advances to noncontrolling interest owners of $21.3 million, and dividend and distributions paid of $11.6 million during the year ended December 31, 2018, offset by $198.0 million net proceeds from the IPO, compared to net borrowings of $156.1 million, net payments of $23.0 million from the issuance and redemption of redeemable common units, and $13.2 million of payments for debt issuance and equity offering costs during the year ended December 31, 2017. 
+The following table summarizes our cash flows for the periods indicated: 
+Years Ended December 31, 
+Description 
+2017 
+2016 
+Change 
+(in thousands) 
+Net cash provided by (used in) operating activities 
+$ 
+195,109 
+$ 
+(40,708 
+) 
+$ 
+235,817 
+Net cash used in investing activities 
+(310,043 
+) 
+(96,351 
+) 
+(213,692 
+) 
+Net cash provided by financing activities 
+119,771 
+148,543 
+(28,772 
+) 
+Net increase in cash and cash equivalents 
+$ 
+4,837 
+$ 
+11,484 
+$ 
+(6,647 
+) 
+Analysis of Cash Flow Changes Between the Years Ended December 31, 2017 and 2016 
+Operating Activities . Net cash provided by operating activities was $195.1 million for the year ended December 31, 2017 , compared to cash used in operating activities of $40.7 million for the year ended December 31, 2016 . The $235.8 million increase in cash from operating activities was attributable to the net impact of the increase in cash receipts for hydraulic fracturing services due to the combined effect of a 104.0% increase in average active fleets and 94.8% increase in revenue per active fleet, partially offset by the increased costs of those services and increased general and administrative expenses, and the changes in related working capital items. 
+Investing Activities . Net cash used in investing activities was $310.0 million for the year ended December 31, 2017 , compared to $96.4 million for the year ended December 31, 2016 . The $213.7 million increase in net cash used in investing activities was primarily due to the purchase of, and upgrades to, our hydraulic fracturing fleets, the acquisition of Titan Frac Services LLC, and real estate acquisitions in Texas. 
+Financing Activities . Net cash provided by financing activities was $119.8 million for the year ended December 31, 2017 , compared to $148.5 million for the year ended December 31, 2016 . The $28.8 million decrease in cash provided by financing activities was primarily due to a $155.5 million decrease in member contributions, offset by a $97.1 million increase in net debt borrowings and repayments, $60.0 million in proceeds from related party bridge loans and $39.8 million in proceeds from issuance of redeemable common units. Additionally, during the year ended December 31, 2017, the Company redeemed $62.7 million of redeemable common units and paid $13.2 million in debt and equity issuance costs. 
+50 
+Table of Contents 
+Debt Agreements 
+On September 19, 2017, the Company entered into two new credit agreements for a revolving line of credit up to $250.0 million (the “ABL Facility”) and a $175.0 million term loan (the “Term Loan Facility”, and together with the ABL Facility the “Credit Facilities”). Following is a description of the ABL Facility and the Term Loan Facility. 
+ABL Facility 
+Under the terms of the ABL Facility, up to $250.0 million may be borrowed, subject to certain borrowing base limitations based on a percentage of eligible accounts receivable and inventory. As of December 31, 2018 , the borrowing base was calculated to be $224.6 million, and the Company had no borrowings outstanding, except for a letter of credit in the amount of $0.3 million, with $224.3 million of remaining availability. Borrowings under the ABL Facility bear interest at LIBOR or a base rate, plus an applicable LIBOR margin of 1.5% to 2.0% or base rate margin of 0.5% to 1.0%, as defined in the ABL Facility credit agreement. The unused commitment is subject to an unused commitment fee of 0.375% to 0.5%. Interest and fees are payable in arrears at the end of each month, or, in the case of LIBOR loans, at the end of each interest period. The ABL Facility matures on the earlier of (i) September 19, 2022 and (ii) to the extent the debt under the Term Loan Facility remains outstanding, 90 days prior to the final maturity of the Term Loan Facility, which matures on September 19, 2022. Borrowings under the ABL Facility are collateralized by accounts receivable and inventory, and further secured by the Company, Liberty LLC and R/C IV Non-U.S. LOS Corp., a Delaware corporation (“R/C IV”) and a subsidiary of the Company, as parent guarantors. 
+Term Loan Facility 
+The Term Loan Facility provides for a $175.0 million term loan, of which $111.7 million remained outstanding as of December 31, 2018 . Amounts outstanding bear interest at LIBOR or a base rate, plus an applicable margin of 7.625% or 6.625%, respectively, and the weighted average rate on borrowings was 10.1% as of December 31, 2018 . The Company is required to make quarterly principal payments of 1% per annum of the initial principal balance, commencing on December 31, 2017, with final payment due at maturity on September 19, 2022. The Term Loan Facility is collateralized by the fixed assets of LOS and its subsidiaries, and is further secured by the Company, Liberty LLC and R/C IV, as parent guarantors. 
+The Credit Facilities include certain non-financial covenants, including but not limited to restrictions on incurring additional debt and certain distributions. Moreover, the ability of the Company to incur additional debt and to make distributions is dependent on maintaining a maximum leverage ratio. The Term Loan Facility requires mandatory prepayments upon certain dispositions of property or issuance of other indebtedness, as defined, and annually a percentage of excess cash flow (25% to 50%, depending on leverage ratio, of consolidated net income less capital expenditures and other permitted payments, commencing with the year ending December 31, 2018). Certain mandatory prepayments and optional prepayments are subject to a prepayment premium of 3% of the prepaid principal declining annually to 1% during the first three years of the term of the Term Loan Facility. 
+The Credit Facilities are not subject to financial covenants unless liquidity, as defined in the respective credit agreements, drops below a specified level. Under the ABL Facility, the Company is required to maintain a minimum fixed charge coverage ratio, as defined in the credit agreement governing the ABL Facility, of 1.0 to 1.0 for each period if excess availability is less than 10% of the borrowing base or $12.5 million, whichever is greater. Under the Term Loan Facility, the Company is required to maintain a minimum fixed charge coverage ratio, as defined, of 1.2 to 1.0 for each trailing twelve-month period if the Company’s liquidity, as defined, is less than $25.0 million for at least five consecutive business days. The Company was in compliance with these covenants as of December 31, 2018 . 
+51 
+Table of Contents 
+Contractual Obligations 
+The table below provides estimates of the timing of future payments that we are contractually obligated to make based on agreements in place at December 31, 2018 . 
+Payments Due by Period 
+(dollars in thousands) 
+Total 
+Less than 1 
+year 
+1 – 3 years 
+4 – 5 years 
+More than 5 years 
+ABL Facility (1) 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+Term Loan Facility (1) 
+111,715 
+1,750 
+3,500 
+106,465 
+— 
+Estimated interest payments (2) 
+41,533 
+11,407 
+22,307 
+7,819 
+— 
+Operating lease obligations (3) 
+153,930 
+42,717 
+81,075 
+10,396 
+19,742 
+Purchase commitments (4) 
+690,862 
+341,970 
+344,947 
+3,945 
+— 
+Obligations under the TRAs(5) 
+16,818 
+— 
+5 
+3,994 
+1,947 
+10,877 
+Total 
+$ 
+1,014,858 
+$ 
+397,844 
+$ 
+455,823 
+$ 
+130,572 
+$ 
+30,619 
+(1) 
+Payments on our ABL Facility and Term Loan Facility exclude interest payments. Payments are based on debt balances as of December 31, 2018. 
+(2) 
+Estimated interest payments are based on debt balances as of December 31, 2018 . Interest rates applied are based on the weighted average rate as of December 31, 2018 . 
+(3) 
+Operating lease obligations include payments for leased facilities, equipment and vehicles. 
+(4) 
+Purchase commitments represent payments under supply agreements for the purchase and transportation of proppants. The agreements include minimum monthly purchase commitments, including agreements under which a shortfall fee may be applied. The shortfall fee may be offset by purchases in excess of the minimum requirement during future periods, as allowed for by each agreement. 
+(5) 
+The timing and amount(s) of the aggregate payments due under the TRAs may vary based on a number of factors, including the timing and amount of the taxable income we generate each year and the tax rate then applicable. 
+Tax Receivable Agreements 
+In connection with the IPO, on January 17, 2018, the Company entered into two TRAs with the TRA Holders. The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that the Company actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result, as applicable to each of the TRA Holders, of (i) certain increases in tax basis that occur as a result of the Company’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holders’ Liberty LLC Units in connection with the IPO or pursuant to the exercise of the Redemption Right or the Company’s Call Right, (ii) any net operating losses available to the Company as a result of the Corporate Reorganization, and (iii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRAs. 
+With respect to obligations the Company expects to incur under the TRAs (except in cases where the Company elects to terminate the TRAs early, the TRAs are terminated early due to certain mergers, asset sales, or other changes of control or the Company has available cash but fails to make payments when due), generally the Company may elect to defer payments due under the TRAs if the Company does not have available cash to satisfy its payment obligations under the TRAs or if its contractual obligations limit its ability to make such payments. Any such deferred payments under the TRAs generally will accrue interest. In certain cases, payments under the TRAs may be accelerated and/or significantly exceed the actual benefits, if any, the Company realizes in respect of the tax attributes subject to the TRAs. The Company accounts for amounts payable under the TRAs in accordance with ASC Topic 450, Contingencies. 
+If the Company experiences a change of control (as defined under the TRAs) or the TRAs otherwise terminate early, the Company’s obligations under the TRAs could have a substantial negative impact on its liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. There can be no assurance that we will be able to finance our obligations under the TRAs. 
+52 
+Table of Contents 
+Income Taxes 
+Following the IPO, the Company is a corporation and is subject to U.S. federal, state and local income tax on its share of Liberty LLC’s taxable income. As a result of the IPO and Corporate Reorganization, the Company recorded deferred tax assets and liabilities for the difference between the book value of assets and liabilities for financial reporting purposes and those amounts applicable for income tax purposes. Deferred tax assets have been recorded for tax attributes contributed to the Company as part of the reorganization. Deferred tax liabilities of $29.3 million have been recorded relating to the Liberty LLC Units acquired through the Corporate Reorganization. 
+The effective combined U.S. federal and state income tax rate applicable to the Company for the year ended December 31, 2018 was 14.0% . The Company’s effective tax rate is significantly less than the federal statutory income tax rate of 21.0% primarily because no taxes are payable by the Company for the noncontrolling interest’s share of Liberty LLC’s pass-through income for federal, state and local income tax reporting. The Company recognized income tax expense of $40.4 million for the twelve months ended December 31, 2018 . 
+Critical Accounting Policies and Estimates 
+The preparation of financial statements requires the use of judgments and estimates. Our critical accounting policies are described below to provide a better understanding of how we develop our assumptions and judgments about future events and related estimates and how they can impact our financial statements. A critical accounting estimate is one that requires our most difficult, subjective or complex estimates and assessments and is fundamental to our results of operations. 
+We base our estimates on historical experience and on various other assumptions we believe to be reasonable according to the current facts and circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. We believe the following are the critical accounting policies used in the preparation of our combined financial statements, as well as the significant estimates and judgments affecting the application of these policies. This discussion and analysis should be read in conjunction with our combined financial statements and related notes included in “Item 8. Financial Statements and Supplementary Data. ” 
+Revenue Recognition: Revenue from hydraulic fracturing services is recognized as specific services are provided in accordance with contractual arrangements. If our assessment of performance under a particular contract changes, our revenue and / or costs under that contract may change. 
+Accounts Receivable: We analyze the need for an allowance for doubtful accounts for estimated losses related to potentially uncollectible accounts receivable on a case-by-case basis throughout the year. We reserve amounts based on specific identification after considering each customer’s situation, including payment patterns, current financial condition as well as general economic conditions. It is reasonably possible that our estimates of the allowance for doubtful accounts will change and that losses ultimately incurred could differ materially from the amounts estimated in determining the allowance. 
+Inventory: Inventory consists of raw materials used in the hydraulic fracturing process, such as proppants, chemicals and field service equipment maintenance parts, and is stated at the lower of cost or net realizable value, determined using the weighted average cost method. Net realizable value is determined based on our estimates of selling prices in the ordinary course of business, less reasonably predictable cost of completion, disposal, and transportation, each of which require us to apply judgment. 
+Property and Equipment: We calculate depreciation and amortization on our assets based on the estimated useful lives and estimated salvage values that we believe are reasonable. The estimated useful lives and salvage values are subject to key assumptions such as maintenance, utilization and job variation. These estimates may change due to a number of factors such as changes in operating conditions or advances in technology. 
+We incur maintenance costs on our major equipment. The determination of whether an expenditure should be capitalized or expensed requires management judgment in the application of how the costs benefit future periods, relative to our capitalization policy. Costs that either establish or increase the efficiency, productivity, functionality or life of a fixed asset are capitalized and depreciated over the remaining useful life of the asset. 
+Impairment of long-lived and other intangible assets: Long-lived assets, such as property and equipment and finite-lived intangible assets, are evaluated for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Recoverability is assessed using undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets. When alternative 
+53 
+Table of Contents 
+courses of action to recover the carrying amount of the asset group are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence, which require us to apply judgment. If the carrying amount of the asset is not recoverable based on its estimated undiscounted cash flows expected to result from the use and eventual disposition, an impairment loss is recognized in an amount by which its carrying amount exceeds its estimated fair value. The inputs used to determine such fair value are primarily based upon internally developed cash flow models. Our cash flow models are based on a number of estimates regarding future operations that may be subject to significant variability, are sensitive to changes in market conditions, and are reasonably likely to change in the future. No events or changes in circumstances occurred that would indicate a potential impairment of property and equipment as of December 31, 2018 and 2017 . No impairment was recognized during the years ended December 31, 2018 , 2017 and 2016 . 
+Tax Receivable Agreements: In connection with the IPO, on January 17, 2018, the Company entered into two TRAs with the TRA Holders. The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax that the Company actually realizes in periods after the IPO as a result of certain tax attributes applicable to each TRA Holder. The Company accounts for amounts payable under the TRAs in accordance with ASC Topic 450, Contingencies. 
+Recent Accounting Pronouncements 
+See Note 2, “Significant Accounting Policies—Recently Issued Accounting Standards” and Note 2, “Significant Accounting Policies—Recently Adopted Accounting Standards” to the consolidated and combined financial statements included in “Item 8. Financial Statements and Supplementary Data” for a discussion of recent accounting pronouncements. 
+Off Balance Sheet Arrangements 
+We have no material off balance sheet arrangements as of December 31, 2018 , except for the operating leases and purchase commitments under supply agreements as disclosed above under “—Contractual Obligations.” As such, we are not materially exposed to any other financing, liquidity, market or credit risk that could arise if we had engaged in such financing arrangements. 
+54 
+Table of Contents 
+Item 7A. Quantitative and Qualitative Disclosure about Market Risk 
+Industry Risk 
+The demand, pricing and terms for hydraulic fracturing services provided by us are largely dependent upon the level of drilling activity in the U.S. oil and natural gas industry, as well as the available supply of hydraulic fracturing equipment. These activity levels are influenced by numerous factors over which we have no control, including, but not limited to: the supply of and demand for oil and natural gas; the level of prices, and expectations about future prices of oil and natural gas; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; the discovery rates of new oil and natural gas reserves; available rail and other transportation capacity; weather conditions; domestic and worldwide economic conditions; political instability in oil-producing countries; environmental regulations; technical advances affecting energy consumption; the price and availability of alternative fuels; the ability of E&P companies to raise equity capital and debt financing; and merger and divestiture activity among E&P companies. 
+The level of U.S. oil and natural gas drilling is volatile. Expected trends in oil and natural gas production activities may not materialize and demand for our services may not reflect the level of activity in the industry. Any prolonged and substantial reduction in oil and natural gas prices would likely affect oil and natural gas production levels and therefore affect demand for our services. A material decline in oil and natural gas prices or U.S. activity levels could have a material adverse effect on our business, financial condition, results of operations and cash flows. 
+Interest Rate Risk 
+At December 31, 2018 , we had $111.7 million of debt outstanding, with a weighted average interest rate of 10.1%. Interest is calculated under the terms of our Credit Facilities based on our selection, from time to time, of one of the index rates available to us plus an applicable margin that varies based on certain factors. See “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements.” Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the weighted average interest rate would be approximately $1.1 million per year. We do not currently have or intend to enter into any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness. 
+Commodity Price Risk 
+Our material and fuel purchases expose us to commodity price risk. Material costs primarily include inventory consumed while performing hydraulic fracturing services. Fuel costs consist of diesel fuel used by trucks and other motorized equipment used for hydraulic fracturing services. We have been able to pass along price increases for material costs and fuel costs to customers, depending on market conditions. Further, we have purchase commitments with certain vendors to supply proppant inventory used in our operations at a fixed purchase price, including certain commitments which include minimum purchase obligations. Refer to Note 13 “Commitments and Contingencies” included in “Item 8. Financial Statements and Supplementary Data” for further discussion regarding purchase commitments. 
+55 
+Table of Contents 
+Item 8. Financial Statements and Supplementary Data 
+Our financial statements and supplementary data are included in this Annual Report on Form 10-K beginning on page F-1 and incorporated by reference herein. 
+Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 
+None. 
+Item 9A. Controls and Procedures 
+Evaluation of Disclosure Controls and Procedures 
+As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer, principal financial officer and principal accounting officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report on Form 10-K. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Security and Exchange Commission (the “SEC”) rules and forms and that such information is accumulated and communicated to management, including our principal executive officer, principal financial officer and principal accounting officer, to allow timely decisions regarding required disclosure. Based upon that evaluation, our principal executive officer, principal financial officer and principal accounting officer concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of December 31, 2018. 
+Management ’ s Annual Report on Internal Control Over Financial Reporting 
+During the year ended December 31, 2017, we were an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”) and were not required to comply with certain requirements that were applicable to other public companies that are not “emerging growth companies.” 
+Effective as of January 17, 2018, we no longer qualify as an “emerging growth company” as defined in the JOBS Act. However, in accordance with Section 13(a) and 15(d) of the Exchange Act, a company is required to have been subject to the SEC’s requirements for a period of at least 12 calendar months in order to be designated as a large accelerated filer or an accelerated filer. We completed our IPO on January 17, 2018, and therefore do not meet the requirements to be designated as a large accelerated filer or an accelerated filer as of December 31, 2018. Section 404(c) of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”) provides that Section 404(b) of the Sarbanes-Oxley Act shall not apply with respect to any audit report prepared for an issuer that is neither an accelerated filer nor a large accelerated filer as defined in Rule 12b-2 under the Exchange Act. Accordingly, our independent registered public accounting firm is not yet required to formally attest to the effectiveness of our internal control over financial reporting for the year ended December 31, 2018. 
+Our management, including our principal executive officer and principal financial officer, is responsible for establishing and maintaining adequate internal control over financial reporting for us as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. This system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. 
+Our internal control over financial reporting includes those policies and procedures that: 
+i. 
+pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of the assets; 
+ii. 
+provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and 
+iii. 
+provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements. Further, because of changes in conditions, effectiveness of internal controls over financial reporting may vary over time. 
+Under the supervision of, and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based 
+56 
+Table of Contents 
+on the framework and criteria established in Internal Control-Integrated Framework (2013) , issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2018 . 
+Changes in Internal Control Over Financial Reporting 
+During the quarter ended December 31, 2018 , we developed and implemented new controls and took additional actions to address a previously identified material weakness in our internal control over financial reporting as of December 31, 2017 related to segregation of duties, including internal controls over journal entries. The new internal controls and additional actions included, among other things, hiring additional personnel, engaging a third party to assist in the documentation, implementation and testing of internal controls, and developing and implementing improved policies, processes and procedures to ensure proper segregation of duties are followed. After completion of the testing of the design and operating effectiveness of these new internal controls, we concluded that we had remediated the previously identified material weakness as of December 31, 2018. Other than the internal controls implemented to address the previously identified material weakness, there were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended December 31, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+Attestation Report of the Registered Public Accounting Firm 
+Management’s report was not subject to attestation by our independent registered public accounting firm, pursuant to Rule 12b-2 of the Exchange Act, that permits us to provide only management’s report in this Annual Report on Form 10-K. Therefore, this Annual Report on Form 10-K does not include such an attestation. 
+Item 9B. Other Information 
+None. 
+57 
+Table of Contents 
+PART III 
+Item 10. Directors, Executive Officers and Corporate Governance 
+The information required by this item concerning our executive officers, directors and corporate governance is incorporated herein by reference to our definitive proxy statement for our 2019 annual meeting of shareholders, which will be filed with the SEC no later than 120 days after December 31, 2018. 
+Item 11. Executive Compensation 
+The information required by this item concerning executive compensation is incorporated herein by reference to our definitive proxy statement for our 2019 annual meeting of shareholders, which will be filed with the SEC no later than 120 days after December 31, 2018. 
+Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+The information required by this item concerning the security ownership of certain beneficial owners and management and related stockholder matters are incorporated herein by reference to our definitive proxy statement for our 2019 annual meeting of shareholders, which will be filed with the SEC no later than 120 days after December 31, 2018. 
+Item 13. Certain Relationships and Related Transactions, and Director Independence 
+The information required by this item concerning certain relationships and related person transactions and director independence is incorporated herein by reference to our definitive proxy statement for our 2019 annual meeting of shareholders, which will be filed with the SEC no later than 120 days after December 31, 2018. 
+Item 14. Principal Accountant Fees and Services 
+The information required by this item concerning principal accounting fees and services is incorporated herein by reference to our definitive proxy statement for our 2019 annual meeting of shareholders, which will be filed with the SEC no later than 120 days after December 31, 2018. 
+58 
+Table of Contents 
+PART IV 
+Item 15. Exhibits, Financial Statement Schedules 
+(a) Financial Statements and Financial Statement Schedules 
+Refer to Index to Financial Statements on page 65. 
+All schedules are omitted as information required is inapplicable or the information is presented in the consolidated and combined financial statements and the related notes. 
+(b) Exhibits 
+The documents listed in the Index to Exhibits are filed, furnished or incorporated by reference as part of this Annual Report on Form 10-K, and such Index to Exhibits are incorporated herein by reference. 
+59 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Item 16. Form 10-K Summary 
+None. 
+60 
+Table of Contents 
+INDEX TO EXHIBITS 
+Exhibit 
+Number 
+Description 
+1.1 
+Underwriting Agreement, dated as of January 11, 2018, by and among Liberty Oilfield Services Inc., Liberty Oilfield Services New HoldCo LLC, R/C Energy IV Direct Partnership, L.P., Morgan Stanley & Co. LLC, Goldman Sachs & Co. LLC and Wells Fargo Securities, LLC, as representatives of the several underwriters named therein (2) 
+2.1 
+Master Reorganization Agreement, dated as of January 11, 2018, by and among Liberty Oilfield Services Inc., Liberty Oilfield Services Holdings LLC, Liberty Oilfield Services New HoldCo LLC, and the other parties named therein (2) 
+3.1 
+Amended and Restated Certificate of Incorporation of Liberty Oilfield Services Inc. (2) 
+3.2 
+Amended and Restated Bylaws of Liberty Oilfield Services Inc. (3) 
+4.1 
+Stockholder Agreement, dated as of January 17, 2018, by and among Liberty Oilfield Services Inc., R/C IV Liberty Oilfield Services Holdings, L.P., R/C Energy IV Direct Partnership, L.P., and other parties names therein (2) 
+10.1 
+Second Amended and Restated Limited Liability Company Operating Agreement of Liberty Oilfield Services New HoldCo LLC (2) 
+10.2 
+Tax Receivable Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Inc., R/C Energy IV Direct Partnership, L.P., and R/C Energy IV Direct Partnership, L.P., as agent (2) 
+10.3 
+Tax Receivable Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Inc., and the other parties named therein (2) 
+10.4 
+Registration Rights Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Inc. and the other parties named therein (2) 
+10.5 
+Liberty Oilfield Services Inc. Long Term Incentive Plan (2)† 
+10.6 
+Liberty Oilfield Services Inc. Legacy Restricted Stock Plan (2)† 
+10.7 
+Form of Restricted Stock Grant Notice and Restricted Stock Agreement under the Legacy Restricted Stock Plan (1)† 
+10.8 
+Credit Agreement, dated September 19, 2017, by and among Wells Fargo Bank, National Association, as Administrative Agent, Wells Fargo Bank, National Association, JPMorgan Chase Bank, N.A. and Citibank, N.A., as Joint Lead Arrangers, Wells Fargo Bank, National Association, as Book Runner, JPMorgan Chase Bank, N.A. and Citibank, N.A., as Syndication Agents, the lender parties thereto, Liberty Oilfield Services Holdings LLC, as Parent and Liberty Oilfield Services LLC and LOS Acquisition Co I LLC, each as a Borrower (1) 
+10.9 
+Amendment and Parent Joinder to Credit Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Holdings LLC, Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto (4) 
+10.10 
+Second Amendment and Parent Joinder to Credit Agreement, dated March 21, 2018, by and among Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto (4) 
+10.11 
+Credit Agreement, dated September 19, 2017, by and among Liberty Oilfield Services LLC and LOS Acquisition CO I LLC, each as a Borrower, Liberty Oilfield Services Holdings LLC, as Parent Guarantor and U.S. Bank National Association as Agent (1) 
+10.12 
+Amendment and Joinder to Credit Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Holdings LLC, Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, U.S. Bank National Association, as Administrative Agent, and the lenders signatory thereto (4) 
+10.13 
+Second Amendment and Joinder to Credit Agreement, dated March 21, 2018, by and among Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, U.S. Bank National Association, as Administrative Agent, and the lenders signatory thereto (4) 
+10.14 
+Indemnification Agreement (Christopher A. Wright) (2)† 
+61 
+Table of Contents 
+10.15 
+Indemnification Agreement (Michael Stock) (2)† 
+10.16 
+Indemnification Agreement (Ron Gusek) (2)† 
+10.17 
+Indemnification Agreement (Brett Staffieri) (2)† 
+10.18 
+Indemnification Agreement (N. John Lancaster Jr.) (2)† 
+10.19 
+Indemnification Agreement (Cary D. Steinbeck) (2)† 
+10.20 
+Indemnification Agreement (Peter A. Dea) (2)† 
+10.21 
+Indemnification Agreement (William F. Kimble) (2)† 
+10.22 
+Indemnification Agreement (Ken Babcock) (2)† 
+10.23 
+Indemnification Agreement (Jesal Shah) (2)† 
+10.24 
+Indemnification Agreement (R. Sean Elliot) (2)† 
+10.25 
+Indemnification Agreement (Ryan T. Gosney) (2)† 
+10.26 
+Liberty Oilfield Services 401(k) Savings Plan (5)† 
+10.27 
+Stock Purchase and Sale Agreement, dated as of September 14, 2018, by and among Liberty Oilfield Services Inc., R/C Energy IV Direct Partnership, L.P., R/C IV Liberty Holdings, L.P. and Riverstone/Carlyle Energy Partners IV, L.P. (6) 
+10.28 
+Form of Restricted Stock Unit Grant Notice and Restricted Stock Unit Award Agreement under the Long Term Incentive Plan (7)† 
+21.1 
+List of subsidiaries of Liberty Oilfield Services Inc. * 
+23.1 
+Consent of Deloitte & Touche LLP * 
+31.1 
+Certification of Chief Executive Officer pursuant to Rule 13a-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 * 
+31.2 
+Certification of Chief Financial Officer pursuant to 13a-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 * 
+32.1 
+Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 ** 
+32.2 
+Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 ** 
+101.INS 
+XBRL Instance Document * 
+101.SCH 
+XBRL Taxonomy Extension Schema Document * 
+101.CAL 
+XBRL Taxonomy Extension Calculation Linkbase Document * 
+101.DEF 
+XBRL Taxonomy Extension Definition Linkbase Document * 
+101.LAB 
+XBRL Taxonomy Extension Label Linkbase Document * 
+101.PRE 
+XBRL Taxonomy Extension Presentation Linkbase Document * 
+(1) 
+Incorporated by reference to the exhibits to the registrant’s Registration Statement on Form S-1, as amended (SEC File 333-216050). 
+(2) 
+Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on January 18, 2018. 
+(3) 
+Incorporated by reference to the exhibits to the registrant’s Amendment No. 1 to the Current Report on Form 8-K/A, filed on January 22, 2018. 
+(4) 
+Incorporated by reference to the exhibits to the registrant’s Annual Report on Form 10-K, filed on March 23, 2018. 
+62 
+Table of Contents 
+(5) 
+Incorporated by reference to the exhibits to the registrant’s Registration Statement on Form S-8, filed on June 28, 2018 (SEC File 333-225948). 
+(6) 
+Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on September 17, 2018. 
+(7) 
+Incorporated by reference to the exhibits to the registrant’s Quarterly Report on Form 10-Q, filed on May 10, 2018. 
+* 
+Filed herewith. 
+** 
+Furnished herewith. 
+† 
+Denotes a management contract or compensatory plan or arrangement. 
+63 
+Table of Contents 
+SIGNATURES 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+LIBERTY OILFIELD SERVICES INC. 
+/s/ Christopher A. Wright 
+Date: 
+February 28, 2019 
+By: 
+Christopher A. Wright 
+Chief Executive Officer 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+Signature 
+Title 
+Date 
+/s/ Christopher A. Wright 
+Chief Executive Officer and Director 
+(Principal Executive Officer) 
+February 28, 2019 
+Christopher A. Wright 
+/s/ Michael Stock 
+Chief Financial Officer 
+(Principal Financial Officer) 
+February 28, 2019 
+Michael Stock 
+/s/ Ryan T. Gosney 
+Chief Accounting Officer 
+February 28, 2019 
+Ryan T. Gosney 
+(Principal Accounting Officer) 
+/s/ Cary D. Steinbeck 
+Director 
+February 28, 2019 
+Cary D. Steinbeck 
+/s/ N. John Lancaster, Jr. 
+Director 
+February 28, 2019 
+N. John Lancaster, Jr. 
+/s/ Brett Staffieri 
+Director 
+February 28, 2019 
+Brett Staffieri 
+/s/ William F. Kimble 
+Director 
+February 28, 2019 
+William F. Kimble 
+/s/ Peter A. Dea 
+Director 
+February 28, 2019 
+Peter A. Dea 
+/s/ Ken Babcock 
+Director 
+February 28, 2019 
+Ken Babcock 
+/s/ Jesal Shah 
+Director 
+February 28, 2019 
+Jesal Shah 
+64 
+Table of Contents 
+Index to Financial Statements 
+Liberty Oilfield Services Inc. 
+Report of Independent Registered Public Accounting Firm 
+F- 1 
+Consolidated and Combined Balance Sheets as of December 31, 2018 and 2017 
+F- 2 
+Consolidated and Combined Statements of Operations for the Years Ended December 31, 2018, 2017 and 2016 
+F- 3 
+Consolidated and Combined Statements of Changes in Equity for the Years Ended December 31, 2018, 2017 and 2016 
+F- 4 
+Consolidated and Combined Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016 
+F- 5 
+Notes to Consolidated and Combined Financial Statements 
+F- 6 
+65 
+Table of Contents 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the Stockholders and the Board of Directors of Liberty Oilfield Services Inc. 
+Opinion on the Financial Statements 
+We have audited the accompanying consolidated and combined balance sheets of Liberty Oilfield Services Inc. and its subsidiaries (the “Company”) as of December 31, 2018 and 2017, the related consolidated and combined statements of operations, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America. 
+Basis for Opinion 
+These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. 
+Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. 
+/s/ DELOITTE & TOUCHE LLP 
+Denver, Colorado 
+February 28, 2019 
+We have served as the Company's auditor since 2016. 
+F- 1 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Consolidated and Combined Balance Sheets 
+As of December 31, 2018 and 2017 
+(Dollars in thousands, except share data) 
+2018 
+2017 
+Assets 
+Current assets: 
+Cash and cash equivalents 
+$ 
+103,312 
+$ 
+16,321 
+Accounts receivable—trade 
+153,589 
+195,961 
+Accounts receivable—related party 
+15,139 
+3,984 
+Unbilled revenue 
+79,233 
+58,784 
+Unbilled revenue—related party 
+— 
+59 
+Inventories 
+60,024 
+55,524 
+Prepaid and other current assets 
+49,924 
+21,396 
+Total current assets 
+461,221 
+352,029 
+Property and equipment, net 
+627,053 
+494,776 
+Other assets 
+28,227 
+5,298 
+Total assets 
+$ 
+1,116,501 
+$ 
+852,103 
+Liabilities and Equity 
+Current liabilities: 
+Accounts payable 
+$ 
+80,490 
+$ 
+66,846 
+Accrued liabilities: 
+Accrued vendor invoices 
+67,771 
+78,646 
+Operational accruals 
+36,414 
+32,208 
+Accrued salaries and benefits 
+22,791 
+24,990 
+Deferred revenue 
+— 
+9,231 
+Accrued interest and other 
+9,585 
+6,573 
+Accrued liabilities—related party 
+2,300 
+2,000 
+Current portion of long-term debt, net of discount of $1,365 and $1,739, respectively 
+385 
+11 
+Total current liabilities 
+219,736 
+220,505 
+Long-term debt, net of discount of $3,826 and $6,466, respectively, less current portion 
+106,139 
+196,346 
+Deferred tax liability 
+32,994 
+— 
+Payable pursuant to tax receivable agreements 
+16,818 
+— 
+Total liabilities 
+375,687 
+416,851 
+Commitments & contingencies (Note 13) 
+Redeemable common units 
+— 
+42,486 
+Members’ equity: 
+Members’ equity 
+— 
+392,766 
+Stockholders’ equity: 
+Preferred Stock, $0.01 par value, 10,000 shares authorized and none issued and outstanding 
+— 
+— 
+Common Stock: 
+Class A, $0.01 par value, 400,000,000 shares authorized and 68,359,871 issued and outstanding as of December 31, 2018 and none issued and outstanding as of December 31, 2017 
+684 
+— 
+Class B, $0.01 par value, 400,000,000 shares authorized and 45,207,372 issued and outstanding as of December 31, 2018 and none issued and outstanding as of December 31, 2017 
+452 
+— 
+Additional paid in capital 
+312,659 
+— 
+Retained earnings 
+119,274 
+— 
+Total stockholders’ equity 
+433,069 
+— 
+Noncontrolling interest 
+307,745 
+— 
+Total equity 
+740,814 
+392,766 
+Total liabilities and equity 
+$ 
+1,116,501 
+$ 
+852,103 
+See Notes to Consolidated and Combined Financial Statements. 
+F- 2 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Consolidated and Combined Statements of Operations 
+For the Years Ended December 31, 2018 , 2017 and 2016 
+(In thousands, except per share data) 
+2018 
+2017 
+2016 
+Revenue: 
+Revenue 
+$ 
+2,132,032 
+$ 
+1,465,133 
+$ 
+356,890 
+Revenue—related parties 
+23,104 
+24,722 
+17,883 
+Total revenue 
+2,155,136 
+1,489,855 
+374,773 
+Operating costs and expenses: 
+Cost of services (exclusive of depreciation and amortization shown separately below) 
+1,628,753 
+1,147,008 
+354,729 
+General and administrative 
+99,052 
+80,089 
+35,789 
+Depreciation and amortization 
+125,110 
+81,473 
+41,362 
+(Gain) loss on disposal of assets 
+(4,342 
+) 
+148 
+(2,673 
+) 
+Total operating costs and expenses 
+1,848,573 
+1,308,718 
+429,207 
+Operating income (loss) 
+306,563 
+181,137 
+(54,434 
+) 
+Other expense: 
+Interest expense 
+(17,145 
+) 
+(11,875 
+) 
+(6,126 
+) 
+Interest expense related party 
+— 
+(761 
+) 
+— 
+Total interest expense 
+(17,145 
+) 
+(12,636 
+) 
+(6,126 
+) 
+Net income (loss) before income taxes 
+289,418 
+168,501 
+(60,560 
+) 
+Income tax expense 
+40,385 
+— 
+— 
+Net income (loss) 
+249,033 
+168,501 
+(60,560 
+) 
+Less: Net income (loss) attributable to Predecessor, prior to Corporate Reorganization 
+8,705 
+168,501 
+(60,560 
+) 
+Less: Net income attributable to noncontrolling interests 
+113,979 
+— 
+— 
+Net income attributable to Liberty Oilfield Services Inc. stockholders 
+$ 
+126,349 
+$ 
+— 
+$ 
+— 
+Net income attributable to Liberty Oilfield Services Inc. stockholders per common share: 
+Basic 
+$ 
+1.84 
+Diluted 
+$ 
+1.81 
+Weighted average common shares outstanding: 
+Basic 
+68,838 
+Diluted 
+117,838 
+See Notes to Consolidated and Combined Financial Statements. 
+F- 3 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Consolidated and Combined Statements of Changes in Equity 
+For the Years Ended December 31, 2018 , 2017 and 2016 
+(Amounts in thousands) 
+Members ’ Equity 
+Shares of Class A Common Stock 
+Shares of Class B Common Stock 
+Class A Common Stock, Par Value 
+Class B Common Stock, Par Value 
+Additional Paid in Capital 
+Retained Earnings 
+Total Stockholders ’ equity 
+Noncontrolling Interest 
+Total Equity 
+Balance—December 31, 2016 
+$ 
+228,972 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+$ 
+228,972 
+Return on redeemable common units 
+(4,707 
+) 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+(4,707 
+) 
+Net income 
+168,501 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+168,501 
+Balance—December 31, 2017 
+$ 
+392,766 
+— 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+392,766 
+Return on redeemable common units 
+(149 
+) 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+(149 
+) 
+Net income prior to Corporate Reorganization 
+8,705 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+8,705 
+Balance prior to Corporate Reorganization 
+$ 
+401,322 
+— 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+401,322 
+Corporate Reorganization 
+Exchange of Liberty LLC Units for Class A Common Stock and Class B Common Stock and extinguishment of redeemable common units 
+(401,322 
+) 
+55,986 
+48,207 
+560 
+482 
+444,824 
+— 
+445,866 
+— 
+44,544 
+Net deferred tax liability due to Corporate Reorganization 
+— 
+— 
+— 
+— 
+— 
+(29,287 
+) 
+— 
+(29,287 
+) 
+— 
+(29,287 
+) 
+Initial Public Offering 
+Issuance of Class A Common Stock, net of underwriter discount and offering costs 
+— 
+14,340 
+— 
+143 
+— 
+219,847 
+— 
+219,990 
+— 
+219,990 
+Redemption of Legacy Ownership, net of underwriter discount 
+— 
+(1,609 
+) 
+— 
+- 
+(16 
+) 
+— 
+(25,881 
+) 
+— 
+(25,897 
+) 
+— 
+(25,897 
+) 
+Issuance of restricted stock 
+— 
+1,259 
+— 
+13 
+— 
+(13 
+) 
+— 
+— 
+— 
+— 
+Liability due to tax receivable agreements 
+— 
+— 
+— 
+— 
+— 
+(2,291 
+) 
+— 
+(2,291 
+) 
+— 
+(2,291 
+) 
+Initial allocation of noncontrolling interest of Liberty LLC effective on the date of the IPO 
+— 
+— 
+— 
+— 
+— 
+(261,048 
+) 
+— 
+(261,048 
+) 
+261,048 
+— 
+Results Subsequent to Initial Public Offering 
+Distributions and advances paid to noncontrolling interest unitholders 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+(21,288 
+) 
+(21,288 
+) 
+Exchange of Class B Common Stock for Class A Common Stock 
+— 
+3,000 
+(3,000 
+) 
+30 
+(30 
+) 
+20,534 
+— 
+20,534 
+(20,534 
+) 
+— 
+Effect of exchange on deferred tax asset, net of liability under tax receivable agreements 
+— 
+— 
+— 
+— 
+— 
+2,592 
+— 
+2,592 
+— 
+2,592 
+Restricted stock forfeited 
+— 
+(22 
+) 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+Stock based compensation expense 
+— 
+— 
+— 
+— 
+— 
+5,450 
+— 
+5,450 
+— 
+5,450 
+Regular cash dividends declared and distributions paid 
+— 
+— 
+— 
+— 
+— 
+— 
+(7,075 
+) 
+(7,075 
+) 
+(4,671 
+) 
+(11,746 
+) 
+Share repurchases 
+— 
+(4,594 
+) 
+— 
+(46 
+) 
+— 
+(62,068 
+) 
+— 
+(62,114 
+) 
+(20,789 
+) 
+(82,903 
+) 
+Net income subsequent to Corporate Reorganization and IPO 
+— 
+— 
+— 
+— 
+— 
+— 
+126,349 
+126,349 
+113,979 
+240,328 
+Balance—December 31, 2018 
+$ 
+— 
+68,360 
+45,207 
+$ 
+684 
+$ 
+452 
+$ 
+312,659 
+$ 
+119,274 
+$ 
+433,069 
+$ 
+307,745 
+$ 
+740,814 
+See Notes to Consolidated and Combined Financial Statements. 
+F- 4 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Consolidated and Combined Statements of Cash Flows 
+For the Years Ended December 31, 2018 , 2017 and 2016 
+(Dollars in thousands) 
+2018 
+2017 
+2016 
+Cash flows from operating activities: 
+Net income (loss) 
+$ 
+249,033 
+$ 
+168,501 
+$ 
+(60,560 
+) 
+Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: 
+Depreciation and amortization 
+125,110 
+81,473 
+41,362 
+(Gain) loss on disposal of assets 
+(4,342 
+) 
+148 
+(2,673 
+) 
+Amortization of debt issuance costs 
+4,031 
+2,311 
+630 
+Inventory write down 
+3,389 
+259 
+— 
+Stock based compensation expense 
+5,450 
+Deferred tax expense 
+20,488 
+Changes in operating assets and liabilities: 
+Accounts receivable and unbilled revenue 
+23,074 
+(133,689 
+) 
+(41,023 
+) 
+Accounts receivable and unbilled revenue—related party 
+(11,096 
+) 
+3,460 
+(1,942 
+) 
+Inventories 
+(4,610 
+) 
+(27,639 
+) 
+(11,687 
+) 
+Prepaids and other current assets 
+(32,771 
+) 
+(12,611 
+) 
+(3,388 
+) 
+Accounts payable and accrued liabilities 
+(26,798 
+) 
+111,352 
+38,563 
+Accounts payable and accrued liabilities—related party 
+300 
+1,544 
+10 
+Net cash provided by (used in) operating activities 
+351,258 
+195,109 
+(40,708 
+) 
+Cash flows from investing activities: 
+Capital expenditures 
+(258,835 
+) 
+(311,794 
+) 
+(102,428 
+) 
+Proceeds from disposal of assets 
+3,343 
+1,751 
+6,077 
+Net cash used in investing activities 
+(255,492 
+) 
+(310,043 
+) 
+(96,351 
+) 
+Cash flows from financing activities: 
+Proceeds from issuance of Class A Common Stock, net of underwriter discount 
+230,174 
+— 
+— 
+Redemption of LLC Units from Legacy Owners 
+(25,897 
+) 
+— 
+— 
+Proceeds from borrowings on term loan, net of discount 
+— 
+171,500 
+— 
+Repayments of borrowings on term loan 
+(62,847 
+) 
+(57,438 
+) 
+(49,000 
+) 
+Proceeds from borrowings on line-of-credit 
+— 
+140,559 
+84,700 
+Repayments of borrowings on line-of-credit 
+(30,000 
+) 
+(158,559 
+) 
+(36,700 
+) 
+Proceeds from Liberty Oilfield Services Holdings LLC 
+2,115 
+— 
+— 
+Distributions and dividends paid to noncontrolling interest unitholders and Class A Common Stock shareholders 
+(11,578 
+) 
+— 
+— 
+Share Repurchase 
+(82,903 
+) 
+— 
+— 
+Proceeds from related party bridge loans 
+— 
+60,000 
+— 
+Payments on capital lease obligations 
+— 
+(119 
+) 
+(5,525 
+) 
+Payments of debt issuance costs 
+(315 
+) 
+(9,036 
+) 
+(413 
+) 
+Proceeds from issuance of redeemable common units 
+— 
+39,794 
+— 
+Payments for redemption of redeemable common units 
+— 
+(62,739 
+) 
+— 
+Member contributions 
+— 
+— 
+155,481 
+Distributions paid to noncontrolling interest unitholders 
+(21,288 
+) 
+— 
+— 
+Payment of deferred equity offering costs 
+(6,236 
+) 
+(4,191 
+) 
+— 
+Net cash (used in) provided by financing activities 
+(8,775 
+) 
+119,771 
+148,543 
+Net increase in cash and cash equivalents 
+86,991 
+4,837 
+11,484 
+Cash and cash equivalents—beginning of period 
+16,321 
+11,484 
+— 
+Cash and cash equivalents—end of period 
+$ 
+103,312 
+$ 
+16,321 
+$ 
+11,484 
+Supplemental disclosure of cash flow information: 
+Cash paid for income taxes 
+$ 
+27,263 
+$ 
+— 
+$ 
+— 
+Cash paid for interest 
+$ 
+13,957 
+$ 
+9,766 
+$ 
+4,725 
+Non-cash investing and financing activities: 
+Capital expenditures included in accounts payable and accrued liabilities 
+$ 
+45,703 
+$ 
+18,687 
+$ 
+29,688 
+Related party bridge loans exchanged for Redeemable Class 2 Common Units 
+$ 
+— 
+$ 
+60,679 
+$ 
+— 
+See Notes to Consolidated and Combined Financial Statements. 
+F- 5 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Note 1—Organization and Basis of Presentation 
+Organization 
+Liberty Oilfield Services Inc. (the “Company”) was incorporated as a Delaware corporation on December 21, 2016, to become a holding corporation for Liberty Oilfield Services New HoldCo LLC (“Liberty LLC”) and its subsidiaries upon completion of a corporate reorganization (as detailed below, the “Corporate Reorganization”) and planned initial public offering of the Company (“IPO”). The Company has no material assets other than its ownership in Liberty LLC. 
+Prior to the Corporate Reorganization, Liberty Oilfield Services Holdings LLC (“Liberty Holdings”) wholly owned Liberty Oilfield Services LLC (“LOS”) and LOS Acquisition CO I LLC (“ACQI” and, together with LOS, the “Predecessor”), which includes the assets and liabilities of LOS Odessa RE Investments, LLC (“Odessa”) and LOS Cibolo RE Investments, LLC (“Cibolo”). Following the Corporate Reorganization, Liberty LLC wholly owns the Predecessor. Effective March 22, 2018, the assets of ACQI were contributed into LOS and ACQI was dissolved. 
+The Company, together with its subsidiaries, is a multi-basin provider of hydraulic fracturing services, with a focus on deploying the latest technologies in the technically demanding oil and gas reservoirs in which it operates, principally in North Dakota, Colorado, Wyoming and Texas. 
+Corporate Reorganization 
+In connection with the IPO, the Company completed the Corporate Reorganization, including the following series of transactions: 
+• 
+Liberty Holdings contributed all of its assets to Liberty LLC in exchange for Liberty LLC Units (as defined below); 
+• 
+Liberty Holdings liquidated and distributed to its then-existing owners (the “Legacy Owners”) Liberty LLC Units pursuant to the terms of the limited liability company agreement of Liberty Holdings and the Master Reorganization Agreement dated as of January 11, 2018, by and among the Company, Liberty Holdings, Liberty LLC, and the other parties named therein (the “Master Reorganization Agreement”); 
+• 
+Certain of the Legacy Owners directly or indirectly contributed all or a portion of their Liberty LLC Units to the Company in exchange for 55,685,027 shares of our Class A common stock, par value $0.01 per share (the “Class A Common Stock”), and 1,258,514 restricted shares of Class A Common Stock. Subsequent to the initial exchange, 1,609,122 shares of Class A Common Stock were redeemed for an aggregate price of $25.9 million , upon the exercise of the underwriters’ overallotment option; 
+• 
+the Company issued, at par, the Legacy Owners that continued to own Liberty LLC Units (the “Liberty Unit Holders”) an aggregate amount of 48,207,372 shares of our Class B common stock, par value $0.01 per share (the “Class B Common Stock”); and 
+• 
+the Company contributed the net proceeds it received from the IPO to Liberty LLC in exchange for additional Liberty LLC Units such that the Company held a total number of Liberty LLC Units equal to the number of shares of Class A Common Stock outstanding immediately following the IPO. 
+Initial Public Offering 
+On January 17, 2018, the Company completed its IPO of 14,640,755 shares of its Class A Common Stock, par value $0.01 per share (the “Class A Common Stock”) at a public offering price of $17.00 per share, of which 14,340,214 shares were offered by the Company and 300,541 were offered by the selling shareholder. The Company received $ 220.0 million net proceeds from the IPO, after deducting approximately $ 13.4 million in underwriting discounts and commissions and $ 10.4 million in other offering costs. The Company did not receive any proceeds from the sale of the shares of Class A Common Stock by the selling shareholder. The Company used $25.9 million of net proceeds to redeem ownership interests in Liberty LLC from the Legacy Owners. The Company contributed the remaining net proceeds to Liberty LLC in exchange for units in Liberty LLC (the “Liberty LLC Units”). Liberty LLC used a portion of these net proceeds (i) to repay outstanding borrowings and accrued interest under the Predecessor’s ABL Facility (as defined herein), totaling approximately $30.1 million, (ii) to repay 35% of the Predecessor’s outstanding borrowings, accrued interest and prepayment premium under the Term Loan Facility (as defined herein), totaling approximately $62.5 million and (iii) for general corporate purposes, including repayment 
+F- 6 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+of additional indebtedness and funding capital expenditures. As of December 31, 2018 , the Company owned 60.2% of Liberty LLC. 
+Basis of Presentation 
+The accompanying consolidated and combined financial statements were prepared using generally accepted accounting principles in the United States of America (“GAAP”) and the instructions to Form 10-K, Regulation S-X and the rules and regulations of the Securities and Exchange Commission. 
+The accompanying consolidated and combined financial statements and related notes present the consolidated financial position, results of operations, cash flows, and equity of the Company as of and for the year ended December 31, 2018 and the combined financial position of the Predecessor as of December 31, 2017, and the combined results of operations, cash flows, and equity of the Predecessor for the years ended December 31, 2017 and 2016. 
+All intercompany amounts have been eliminated in the presentation of the consolidated financial statements of the Company and the combined financial statements of the Predecessor. Comprehensive income is not reported due to the absence of items of other comprehensive income or loss during the periods presented. The consolidated and combined financial statements include financial data at historical cost as the contribution of assets is considered to be a reorganization of entities under common control. The consolidated and combined financial statements may not be indicative of the actual level of assets, liabilities and costs that would have been incurred by the Predecessor if it had operated as an independent, publicly-traded company during the periods prior to the IPO or of the costs expected to be incurred in the future. 
+The consolidated and combined financial statements for periods prior to January 17, 2018, reflect the historical results of the Predecessor. The consolidated financial statements include the amounts of the Company and all majority owned subsidiaries where the Company has the ability to exercise control. 
+The Company’s operations are organized into a single reportable segment, which consists of hydraulic fracturing services. 
+Note 2—Significant Accounting Policies 
+Use of Estimates 
+The preparation of consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 
+The consolidated and combined financial statements include certain amounts that are based on management’s best estimates and judgments. The most significant estimates relate to the collectibility of accounts receivable and estimates of allowance for doubtful accounts, the useful lives and salvage values of long-lived assets, future cash flows associated with long-lived assets, net realizable value of inventory, and equity unit valuation. These estimates may be adjusted as more current information becomes available. 
+Cash and Cash Equivalents 
+The Company considers all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. The Company continually monitors its positions with, and the credit quality of, the financial institutions with which it has banking relationships. As of the balance sheet date, and periodically throughout the year, the Company has maintained balances in various operating accounts in excess of federally insured limits. 
+Accounts Receivable 
+The Company analyzes the need for an allowance for doubtful accounts for estimated losses related to potentially uncollectible accounts receivable on a case-by-case basis throughout the year. In establishing the required allowance, management considers historical losses adjusted to take into account current market conditions and the customers’ financial condition, the amount of receivables, the current receivables aging and current payment patterns. The Company reserves amounts based on specific identification. Account balances are charged to the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. It is reasonably possible that the Company’s estimate of the allowance for doubtful accounts will change and that losses ultimately incurred could differ materially from the amounts estimated in determining the allowance. 
+F- 7 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Inventories 
+Inventories consist of raw materials used in the hydraulic fracturing process, such as proppants, chemicals, and field service equipment maintenance parts and are stated at the lower of cost, determined using the weighted average cost method, or net realizable value. Inventories are charged to cost of services as used when providing hydraulic fracturing services. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable cost of completion, disposal, and transportation. 
+Property and Equipment 
+Property and equipment are stated at cost. Depreciation and amortization expense is recognized on property and equipment, excluding land, utilizing the straight-line method over the estimated useful lives, ranging from two to 30 years. The Company estimates salvage values that it does not depreciate. 
+Construction in-progress, a component of property and equipment, represents long-lived assets being developed by the Company. These assets are not subject to depreciation until they are completed and ready for their intended use, at which point the Company reclassifies them to field services equipment or vehicles, as appropriate. 
+The Company assesses its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is assessed using undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets. The Company determined the lowest level of identifiable cash flows to be at the asset group, which is the aggregate of the Company’s hydraulic fracturing fleets that are in service. A long-lived asset is not recoverable if its carrying amount exceeds the sum of estimated undiscounted cash flows expected to result from the use and eventual disposition. When alternative courses of action to recover the carrying amount of the asset group are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the asset is not recoverable, an impairment loss is recognized in an amount by which its carrying amount exceeds its estimated fair value, such that its carrying amount is adjusted to its estimated fair value, with an offsetting charge to impairment expense. 
+The Company measures the fair value of its property and equipment using the discounted cash flow method. The expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments of projected revenue growth, fleet count, utilization, gross margin rates, selling, general and administrative rates, working capital fluctuations, capital expenditures, discount rates and terminal growth rates. 
+During 2018 , 2017 and 2016 , the Company did not test its long-lived assets for recoverability as there were no triggering events. No impairment was recognized during the years ended December 31, 2018 , 2017 and 2016 . 
+Major Maintenance Activities 
+The Company incurs maintenance costs on its major equipment. The determination of whether an expenditure should be capitalized or expensed requires management judgment in the application of how the costs incurred benefit future periods, relative to the Company’s capitalization policy. Costs that either establish or increase the efficiency, productivity, functionality or life of a fixed asset are capitalized and depreciated over the remaining useful life of the asset. 
+Deferred Financing Costs 
+Costs associated with obtaining debt financing are deferred and amortized to interest expense using the effective interest method. In accordance with Accounting Standards Update (“ASU”) No. 2015-03 and 2015-15, for all periods the Company has reflected deferred financing costs related to term loan debt as a direct deduction from the carrying amount, and costs associated with line-of-credit arrangements as other assets. 
+Income Taxes 
+Following the IPO, the Company is a corporation and is subject to U.S. federal, state and local income tax on its share of Liberty LLC’s taxable income. As a result of the IPO and Corporate Reorganization, the Company recorded deferred tax assets and liabilities for the difference between the book value of assets and liabilities for financial reporting purposes and those amounts applicable for income tax purposes. 
+Deferred income taxes are computed using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Deferred tax assets and liabilities are calculated using the enacted tax rates in effect for the year in which the deferred tax asset or liability is expected to reverse. The Company classifies all deferred tax assets and liabilities as non-current. 
+The Company recognizes the financial statement effects of a tax position when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not 
+F- 8 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. Previously recognized tax positions are reversed in the first period in which it is no longer more-likely-than-not that the tax position would be sustained upon examination. Income tax related interest and penalties, if applicable, are recorded as a component of the provision for income tax expense. 
+Tax Receivable Agreements 
+In connection with the IPO, on January 17, 2018, the Company entered into two Tax Receivable Agreements (the “TRAs”) with the R/C Energy IV Direct Partnership, L.P. and the Legacy Owners that continued to own Liberty LLC Units (each such person and any permitted transferee, a “Tax Receivable Agreement Holder” and together, the “Tax Receivable Agreement Holders”). The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that the Company actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result, as applicable to each Tax Receivable Agreement Holder, of (i) certain increases in tax basis that occur as a result of the Company’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such Tax Receivable Agreement Holder’s Liberty LLC Units in connection with the IPO or pursuant to the exercise of the right (the “Redemption Right”) or the Company’s right (the “Call Right”), (ii) any net operating losses available to the Company as a result of the Corporate Reorganization, and (iii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRAs. 
+With respect to obligations the Company expects to incur under the TRAs (except in cases where the Company elects to terminate the TRAs early, the TRAs are terminated early due to certain mergers, asset sales, or other changes of control or the Company has available cash but fails to make payments when due), generally the Company may elect to defer payments due under the TRAs if the Company does not have available cash to satisfy its payment obligations under the TRAs or if its contractual obligations limit its ability to make such payments. Any such deferred payments under the TRAs generally will accrue interest. In certain cases, payments under the TRAs may be accelerated and/or significantly exceed the actual benefits, if any, the Company realizes in respect of the tax attributes subject to the TRAs. The Company accounts for amounts payable under the TRAs in accordance with Accounting Standards Codification (“ASC”) Topic 450, Contingencies. 
+If the Company experiences a change of control (as defined under the TRAs) or the TRAs otherwise terminate early, the Company’s obligations under the TRAs could have a substantial negative impact on its liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. 
+Revenue Recognition 
+Effective January 1, 2018, the Company adopted a comprehensive new revenue recognition standard, ASC Topic 606-Revenue from Contracts with Customers. The details of the significant changes to accounting policies resulting from the adoption of the new standard are set out below. The Company adopted the standard using a modified retrospective method; accordingly, the comparative information for the years ended December 31, 2017 and 2016 has not been adjusted and continues to be reported under the previous revenue standard. The adoption of this standard did not have a material impact to the consolidated financial position, reported revenue, results of operations or cash flows as of and for the year ended December 31, 2018. 
+Under the new standard, revenue recognition is based on the transfer of control, or the customer’s ability to benefit from the services and products in an amount that reflects the consideration expected to be received in exchange for those services and products. In recognizing revenue for services and products, the transaction price is determined from sales orders or contracts with customers. Revenue is recognized at the completion of each fracturing stage, and in most cases the price at the end of each stage is fixed, however, in limited circumstances contracts may contain variable consideration. 
+Variable consideration typically may relate to discounts, price concessions and incentives. We estimate variable consideration based on the amount of consideration we expect to receive. The Company accrues revenue on an ongoing basis to reflect updated information for variable consideration as performance obligations are met. 
+The Company also assesses customers’ ability and intention to pay, which is based on a variety of factors including historical payment experience and financial condition. Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30 to 45 days. 
+Deferred Revenue 
+From time to time, the Company may require partial payment in advance from new customers to secure credit or from existing customers in order to secure additional hydraulic fracturing services. Initially, such payments are recorded in the accompanying consolidated and combined financial statements as deferred revenue, and upon performance of the agreed 
+F- 9 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+services, the Company recognizes revenue consistent with its revenue recognition policy described above. As of December 31, 2017 , the Company had $9.2 million recorded as deferred revenue related to the unearned portion of a prepayment from an existing customer to secure additional services from a new fleet by the end of 2017. The new fleet commenced services in December 2017, and the Company applied the prepayment in accordance with the customer agreement as services were performed. During the year ended December 31, 2018 , the Company recognized $9.2 million of the prepayment to revenue. 
+Fleet Start-up Costs 
+The Company incurs start-up costs to commission a new fleet or district. These costs include hiring and training of personnel, and acquisition of consumable parts and tools. Start-up costs are expensed as incurred, and are reflected in general and administrative expense in the consolidated and combined statement of operations. Start-up costs for the years ended December 31, 2018 , 2017 and 2016 , were $10.1 million, $14.0 million and $4.3 million, respectively. Start-up costs incurred during the years ended December 31, 2018 , 2017 and 2016 related to the establishment of three, nine , and two new fleets, respectively. 
+The terms and conditions of the Credit Facilities between the Company and its lenders provides for the add-back of costs or expenses incurred in connection with the acquisition, deployment and opening of any new hydraulic fracturing fleet or district in the computation of certain financial covenants. (See Note 5—Debt). 
+Recently Adopted Accounting Standards 
+In August 2018, the Financial Accounting Standards Board (“FASB”) issued ASU 2018-15, “Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40),” which amends ASC 350-40 to address a customer's accounting for implementation costs incurred in a cloud computing arrangement (“CCA”) that is a service contract. ASU 2018-15 aligns the accounting for costs incurred to implement a CCA that is a service arrangement with the guidance on capitalizing costs associated with developing or obtaining internal-use software. Specifically, ASU 2018-15 amends ASC 350-40 to include in its scope implementation costs of a CCA that is a service contract and clarifies that a customer should apply ASC 350-40 to determine which implementation costs should be capitalized. The update is effective for fiscal years beginning after December 15, 2019, and early adoption is permitted. The Company adopted this standard for the September 30, 2018 reporting period using the prospective approach. The adoption of this standard did not materially impact the consolidated financial statements as of and for the year ended December 31, 2018. 
+In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers. This ASU sets forth a five-step model for determining when and how revenue is recognized. Under the model, an entity is required to recognize revenue to depict the transfer of goods or services to a customer at an amount reflecting the consideration it expects to receive in exchange for those goods or services. Additional disclosures are required to describe the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts (see “ Revenue Recognition ” above). The Company adopted this standard on January 1, 2018 using the modified retrospective method. The Company did not record a cumulative effect adjustment to the opening balance of retained earnings, as no adjustment was necessary. The adoption of this standard did not impact the Company’s reported revenue, net income or cash flows. 
+In May 2017, the FASB issued ASU 2017-09, “Compensation-Stock Compensation (Topic 718): Scope of Modification Accounting”, which provides guidance to increase clarity and reduce both diversity in practice and cost and complexity when applying the existing accounting guidance on changes to the terms or conditions of a share-based payment award. The amendments in ASU 2017-09 require an entity to account for the effects of a modification unless all the following conditions are met: (i) the fair value of the modified award is the same as the fair value of the original award immediately before the original award is modified; (ii) the vesting conditions of the modified award are the same as the vesting conditions of the original award immediately before the original award is modified; and (iii) the classification of the modified award as an equity instrument or a liability instrument is the same as the classification of the original award immediately before the original award is modified. The guidance in ASU 2017-09 is applied prospectively. The amendments in ASU 2017-09 are effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The Company’s adoption of this guidance effective January 1, 2018, did not materially impact its consolidated and combined financial statements. 
+In January 2016, the FASB issued ASU 2016-01, “Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities,” which requires equity investments (except those accounted for under the equity method of accounting, or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income, requires public business entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes, requires separate presentation of financial assets and financial liabilities by measurement category and form of financial asset, and eliminates the requirement for public business entities to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for financial 
+F- 10 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+instruments measured at amortized cost. The ASU is effective for annual periods beginning after December 15, 2017 and was prospectively adopted on January 1, 2018. The adoption of ASU 2016-01 did not have a material impact on the consolidated financial statements of the Company. 
+In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,” which is effective for fiscal years and interim periods within fiscal years beginning after December 15, 2017, with a full retrospective approach to be used upon implementation and early adoption allowed. ASU 2016-15 provides guidance on eight different issues, intended to reduce diversity in practice on how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The adoption of ASU 2016-15 on January 1, 2018 did not have a material impact on the consolidated and combined financial statements of the Company. 
+In October 2016, the FASB issued ASU 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory,” which requires entities to recognize the tax consequences of intercompany asset transfers in the period in which the transfer takes place, with the exception of inventory transfers. The ASU is effective for fiscal years and interim periods within fiscal years beginning after December 15, 2017. Entities must adopt the standard using a modified retrospective approach with a cumulative effect adjustment to accumulated earnings as of the beginning of the period of adoption. The cumulative effect adjustments may include recognition of the income tax consequences of intra-entity transfers of assets other than inventory that occur before the adoption date. Early adoption is permitted but only at the beginning of an annual period for which no financial statements (interim or annual) have already been issued or made available for issuance. The adoption of ASU 2016-16 on January 1, 2018 did not have a material impact on the consolidated and combined financial statements of the Company. 
+Recently Issued Accounting Standards 
+In June 2016, the FASB issued ASU 2016-13, “Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,” which is effective for fiscal years and interim periods within fiscal years beginning after December 15, 2019, with a modified-retrospective approach to be used for implementation. ASU 2016-13 changes the impairment model for most financial assets and certain other instruments. Specifically, this new guidance requires using a forward looking, expected loss model for trade and other receivables, held-to-maturity debt securities, loans and other instruments. This will replace the currently used model and may result in an earlier recognition of allowance for losses. The Company is currently evaluating the impact the adoption of this standard will have on its consolidated and combined financial statements. 
+In February 2016, the FASB established Topic 842, Leases, by issuing ASU No. 2016-02, “Leases (Topic 842),” which requires lessees to recognize leases on-balance sheet and disclose key information about leasing arrangements. Topic 842 was subsequently amended by ASU No. 2018-01, “Land Easement Practical Expedient for Transition to Topic 842”; ASU No. 2018-10, “Codification Improvements to Topic 842, Leases”; and ASU No. 2018-11, “Targeted Improvements.” The new standard establishes a right-of-use model (“ROU”) that requires a lessee to recognize a ROU asset and lease liability on the balance sheet for all leases with a term longer than 12 months. Leases will be classified as finance or operating, with classification affecting the pattern and classification of expense recognition in the income statement. 
+The new standard is effective for the Company on January 1, 2019, with early adoption permitted. A modified retrospective transition approach is required, applying the new standard to all leases existing at the date of initial application. An entity may choose to use either (1) its effective date or (2) the beginning of the earliest comparative period presented in the financial statements as its date of initial application. If an entity chooses the second option, the transition requirements for existing leases also apply to leases entered into between the date of initial application and the effective date. The entity must also recast its comparative period financial statements and provide the disclosures required by the new standard for the comparative periods. The Company adopted the new standard on January 1, 2019 and used the effective date as the date of initial application. Consequently, financial information will not be updated and the disclosures required under the new standard will not be provided for dates and periods before January 1, 2019. 
+The modified retrospective approach includes several practical expedients that entities may elect to apply upon transition. The Company has determined it will elect the package of practical expedients permitted under the transition guidance within the new standard, which allows a lessee to carryforward their population of existing leases, the classification of each lease, as well as the treatment of initial direct costs as of the period of adoption. In addition, the Company will elect the practical expedient related to lease and non-lease components, as an accounting policy for all asset classes, which allows a lessee to not separate non-lease from lease components and instead account for consideration paid in a contract as a single component. Furthermore, the Company has made the policy election to not recognize right-of-use assets and lease liabilities that arise from leases with an initial term of 12 months or less on the consolidated statements of financial position. Lastly, the Company has determined it will not elect the practical expedient related to hindsight in determining the lease term and in assessing impairment of right-of-use assets. 
+F- 11 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+The Company has executed a comprehensive approach to identify arrangements that may contain a lease, has performed completeness assessments over the identified lease populations, and has implemented system solutions and processes to appropriately account for the lease right-of-use assets and lease liabilities upon transition and an ongoing basis. 
+The Company expects that this standard will have a material effect on its consolidated statements of financial position as the Company recognizes right-of-use assets and lease liabilities for the future minimum lease payments of the Company’s existing operating leases, with the exception of those with a term less than 12 months, included in Note 13—Commitments & Contingencies as of December 31, 2018, adjusted for an applied incremental borrowing rate, determined to be appropriate for each lease. The Company does not anticipate that the new standard will have a significant impact on the consolidated statements of operations or cash flows. 
+Note 3—Inventories 
+Inventories consist of the following: 
+December 31, 
+($ in thousands) 
+2018 
+2017 
+Proppants 
+$ 
+22,038 
+$ 
+30,523 
+Chemicals 
+10,781 
+10,660 
+Maintenance parts 
+27,205 
+14,341 
+$ 
+60,024 
+$ 
+55,524 
+During the year ended December 31, 2018, the lower of cost or net realizable value analysis resulted in the Company recording a write-down to inventory carrying values of $3.4 million , included as a component in cost of services in the consolidated statement of income for the year ended December 31, 2018 . 
+F- 12 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Note 4—Property and Equipment 
+Property and equipment consist of the following: 
+Estimated 
+useful lives 
+(in years) 
+December 31, 
+2018 
+2017 
+($ in thousands) 
+Land 
+N/A 
+$ 
+5,400 
+$ 
+4,495 
+Field services equipment 
+2-7 
+778,423 
+572,096 
+Vehicles 
+4-7 
+59,807 
+60,815 
+Buildings and facilities 
+5-30 
+27,795 
+24,260 
+Office equipment and furniture 
+2-7 
+6,200 
+5,879 
+877,625 
+667,545 
+Less accumulated depreciation and amortization 
+(307,277 
+) 
+(198,453 
+) 
+570,348 
+469,092 
+Construction in-progress 
+N/A 
+56,705 
+25,684 
+$ 
+627,053 
+$ 
+494,776 
+During the years ended December 31, 2018, 2017 and 2016, the Company recognized depreciation expense of $124.9 million , 81.5 million and 41.4 million respectively. 
+In November 2018, one of the Company’s hydraulic frac fleets was involved in an accidental fire, which resulted in damage to a portion of the equipment in that fleet. The Company accrued $15.7 million of insurance proceeds for replacement cost of the damaged equipment, which is presented in prepaid and other current assets on the accompanying consolidated balance sheets as of December 31, 2018. The accrued insurance proceeds offset the $4.3 million loss recognized on the damaged equipment. The resulting net gain of $11.5 million was recognized in (gain) loss on disposal of assets for the year ended December 31, 2018 in the accompanying consolidated statements of operations. 
+Note 5—Debt 
+The following is a summary of debt: 
+December 31, 
+2018 
+2017 
+Term Loan Outstanding 
+$ 
+111,715 
+$ 
+174,562 
+Revolving Line of Credit 
+— 
+30,000 
+Deferred financing costs and original issue discount 
+(5,191 
+) 
+(8,205 
+) 
+Total debt, net of deferred financing costs and original issue discount 
+$ 
+106,524 
+$ 
+196,357 
+Current portion of long-term debt, net of discount 
+$ 
+385 
+$ 
+11 
+Long-term debt, net of discount and current portion 
+106,139 
+196,346 
+$ 
+106,524 
+$ 
+196,357 
+On September 19, 2017, the Company entered into two new credit agreements for a revolving line of credit up to $250.0 million (the “ABL Facility”) and a $175.0 million term loan (the “Term Loan Facility”, and together with the ABL Facility the “Credit Facilities”). 
+ABL Facility 
+Under the terms of the ABL Facility, up to $250.0 million may be borrowed, subject to certain borrowing base limitations based on a percentage of eligible accounts receivable and inventory. As of December 31, 2018 , the borrowing base was calculated to be $224.6 million , and the Company had no borrowings outstanding, except for a letter of credit in the amount of $0.3 million , with $224.3 million of remaining availability. Borrowings under the ABL Facility bear interest at LIBOR or a base rate, plus an applicable LIBOR margin of 1.5% to 2.0% or base rate margin of 0.5% to 1.0% , as defined in the ABL Facility credit agreement. The unused commitment is subject to an unused commitment fee of 0.375% to 0.5% . Interest and fees are payable in arrears at the end of each month, or, in the case of LIBOR loans, at the end of each interest period. The ABL Facility 
+F- 13 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+matures on the earlier of (i) September 19, 2022, and (ii) to the extent the debt under the Term Loan Facility remains outstanding, 90 days prior to the final maturity of the Term Loan Facility, which matures on September 19, 2022. Borrowings under the ABL Facility are collateralized by accounts receivable and inventory, and further secured by the Company, Liberty LLC and R/C IV Non-U.S. LOS Corp., a Delaware corporation and a subsidiary of the Company, as parent guarantors. 
+Term Loan Facility 
+The Term Loan Facility provides for a $175.0 million term loan, of which 111.7 million remained outstanding as of December 31, 2018 . Amounts outstanding bear interest at LIBOR or a base rate, plus an applicable margin of 7.625% or 6.625% , respectively, and the weighted average rate on borrowings was 10.1% as of December 31, 2018 . The Company is required to make quarterly principal payments of 1% per annum of the outstanding principal balance, commencing on December 31, 2017, with final payment due at maturity on September 19, 2022. The Term Loan Facility is collateralized by the fixed assets of LOS and its subsidiaries, and is further secured by the Company, Liberty LLC and R/C IV Non-U.S. LOS Corp., a Delaware corporation and a subsidiary of the Company, as parent guarantors. 
+The Credit Facilities include certain non-financial covenants, including but not limited to restrictions on incurring additional debt and certain distributions. Moreover, the ability of the Company to incur additional debt and to make distributions is dependent on maintaining a maximum leverage ratio. The Term Loan Facility requires mandatory prepayments upon certain dispositions of property or issuance of other indebtedness, as defined, and annually a percentage of excess cash flow ( 25% to 50% , depending on leverage ratio, of consolidated net income less capital expenditures and other permitted payments, commencing with the year ending December 31, 2018). Certain mandatory prepayments and optional prepayments are subject to a prepayment premium of 3% of the prepaid principal declining annually to 1% during the first three years of the term of the Term Loan Facility. 
+The Credit Facilities are not subject to financial covenants unless liquidity, as defined in the respective credit agreements, drops below a specified level. Under the ABL Facility, the Company is required to maintain a minimum fixed charge coverage ratio, as defined in the credit agreement governing the ABL Facility, of 1.0 to 1.0 for each period if excess availability is less than 10% of the borrowing base or $12.5 million, whichever is greater. Under the Term Loan Facility, the Company is required to maintain a minimum fixed charge coverage ratio, as defined, of 1.2 to 1.0 for each trailing twelve-month report if the Company’s liquidity, as defined, is less than $25.0 million for at least five consecutive business days. 
+The Company was in compliance with these covenants as of December 31, 2018 . 
+Maturities of debt are as follows: 
+($ in thousands) 
+Years Ending December 31, 
+2019 
+$ 
+1,750 
+2020 
+1,750 
+2021 
+1,750 
+2022 
+106,465 
+2023 
+— 
+$ 
+111,715 
+Note 6—Redeemable Common Units 
+During February 2017, ACQI received $39.8 million in cash from Liberty Holdings in exchange for 40,000,000 Redeemable Common Units of ACQI which accrue a return of 8% per annum (the “Redeemable Common Units”). The Redeemable Common Units were redeemable at the option of the holder on the later of (A) the earlier of an initial public offering or March 23, 2020 and (B) the second business day after all principal and interest outstanding under the ABL Facility have been paid in full and commitments thereunder are terminated. In accordance with ASC 505, “Equity”, due to their conditional redemption feature, the Redeemable Common Units are classified as temporary equity in the accompanying combined balance sheet as of December 31, 2017. 
+The Redeemable Common Units were deemed extinguished and satisfied in full in connection with the Corporate Reorganization (see Note 1—Organization and Basis of Presentation). 
+F- 14 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Note 7—Fair Value Measurements and Financial Instruments 
+The fair values of the Company’s assets and liabilities represent the amounts that would be received to sell those assets or that would be paid to transfer those liabilities in an orderly transaction at the reporting date. These fair value measurements maximize the use of observable inputs. However, in situations where there is little, if any, market activity for the asset or liability at the measurement date, the fair value measurement reflects the Company’s own judgments about the assumptions that market participants would use in pricing the asset or liability. The Company discloses the fair values of its assets and liabilities according to the quality of valuation inputs under the following hierarchy: 
+• 
+Level 1 Inputs: Quoted prices (unadjusted) in an active market for identical assets or liabilities. 
+• 
+Level 2 Inputs: Inputs other than quoted prices that are directly or indirectly observable. 
+• 
+Level 3 Inputs: Unobservable inputs that are significant to the fair value of assets or liabilities. 
+The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those that are initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from unobservable inputs is inconsequential to the overall fair value, or if corroborated market data becomes available. Assets and liabilities that are initially reported as Level 2 are subsequently reported as Level 3 if corroborated market data is no longer available. Transfers occur at the end of the reporting period. There were no transfers into or out of Levels 1, 2 and 3 during the years ended December 31, 2018 and 2017 . 
+The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities and long-term debt. These financial instruments do not require disclosure by level. The carrying values of all the Company’s financial instruments included in the accompanying balance sheets approximated or equaled their fair values at December 31, 2018 and 2017 . 
+• 
+The carrying values of cash and cash equivalents, accounts receivable and accounts payable (including accrued liabilities) approximated fair value at December 31, 2018 and 2017 , due to their short-term nature. 
+• 
+The carrying value of amounts outstanding under long-term debt agreements with variable rates approximated fair value at December 31, 2018 and 2017 , as the effective interest rates approximated market rates. 
+Nonfinancial assets 
+The Company estimates fair value to perform impairment tests as required on long-lived assets. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3 in the event that such assets were required to be measured and recorded at fair value within the consolidated and combined financial statements. There were no such measurements required as of December 31, 2018 and 2017 . 
+Credit Risk 
+The Company’s financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents, and trade receivables. 
+The Company’s cash balances on deposit with financial institutions total $103.3 million and $16.3 million as of December 31, 2018 and 2017 , respectively, which, as of certain dates, exceeded FDIC insured limits. The Company regularly monitors these institutions’ financial condition. 
+The majority of the Company’s customers have payment terms of 45 days or less. As of December 31, 2018 and 2017 , two and one customers accounted for 28% and 22% , respectively, of total accounts receivable and unbilled revenue. The Company mitigates the associated credit risk by performing credit evaluations and monitoring the payment patterns of its customers. During the years December 31, 2018 , 2017 and 2016 , one , two and three customers accounted for 11% , 36% and 45% of total revenue, respectively. 
+As of December 31, 2018 and 2017 , the Company had no provision for doubtful accounts, and the balance as of December 31, 2016 represented one specific entity engaged in the business of oil and gas exploration and production that had filed for bankruptcy primarily as a result of the significant decline in the oil and gas industry. 
+F- 15 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+($ in thousands) 
+2018 
+2017 
+2016 
+Allowance for doubtful accounts, beginning of year 
+$ 
+— 
+$ 
+497 
+6,921 
+Bad debt expense: 
+Provision for doubtful accounts 
+— 
+— 
+— 
+Write off of uncollectible accounts against reserve 
+— 
+(497 
+) 
+(6,424 
+) 
+Allowance for doubtful accounts, end of year 
+$ 
+— 
+$ 
+— 
+497 
+Note 8—Equity 
+Preferred Stock 
+As of December 31, 2018 the Company had 10,000 shares of preferred stock authorized, par value $0.01 , with none issued and outstanding. If issued, each class or series of preferred stock will cover the number of shares and will have the powers, preferences, rights, qualifications, limitations and restrictions determined by the Company's board of directors, which may include, among others, dividend rights, liquidation preferences, voting rights, conversion rights, preemptive rights and redemption rights. Except as provided by law or in a preferred stock designation, the holders of preferred stock will not be entitled to vote at or receive notice of any meeting of shareholders. 
+Class A Common Stock 
+The Company had a total of 68,359,871 shares of Class A Common Stock outstanding as of December 31, 2018 , which includes 634,653 shares of restricted stock. Holders of Class A Common Stock are entitled to one vote per share on all matters to be voted upon by the stockholders and are entitled to ratably receive dividends when and if declared by the Company’s board of directors. 
+Class B Common Stock 
+The Company had a total 45,207,372 shares of Class B Common Stock outstanding as of December 31, 2018 . Holders of the Class B Common Stock are entitled to one vote per share on all matters to be voted upon by stockholders. Holders of Class A Common Stock and Class B Common Stock vote together as a single class on all matters presented to the Company’s stockholders for their vote or approval, except with respect to amendment of certain provisions of the Company’s certificate of incorporation that would alter or change the powers, preferences or special rights of the Class B Common Stock so as to affect them adversely, which amendments must be by a majority of the votes entitled to be cast by the holders of the shares affected by the amendment, voting as a separate class, or as otherwise required by applicable law. 
+Holders of Class B Common Stock do not have any right to receive dividends, unless the dividend consists of Class B Common Stock or of rights, options, warrants or other securities convertible or exercisable into or exchangeable for shares of Class B Common Stock paid proportionally with respect to each outstanding share of Class B Common Stock and a dividend consisting of shares of Class A Common Stock or of rights, options, warrants or other securities convertible or exercisable into or exchangeable for shares of Class A Common Stock on the same terms is simultaneously paid to the holders of Class A Common Stock. Holders of Class B Common Stock do not have any right to receive a distribution upon liquidation or winding up of the Company. 
+Under the Second Amended and Restated Limited Liability Company Agreement of Liberty LLC, each Liberty Unit Holder has, subject to certain limitations, the Redemption Right to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units, for, at Liberty LLC’s election, (i) shares of Class A Common Stock at a redemption ratio of one share of Class A Common Stock for each Liberty LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions or (ii) an equivalent amount of cash. Alternatively, upon the exercise of the Redemption Right, the Company (instead of Liberty LLC) will have the Call Right to, for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder for, at its election, (x) one share of Class A Common Stock or (y) an equivalent amount of cash. In addition, upon a change of control of the Company, the Company has the right to require each holder of Liberty LLC Units (other than the Company) to exercise its Redemption Right with respect to some or all of such unitholder’s Liberty LLC Units. In connection with any redemption of Liberty LLC Units pursuant to the Redemption Right or the Call Right, the corresponding number of shares of Class B Common Stock will be canceled. 
+F- 16 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+LLC Interest Issuance 
+Prior to the IPO and Corporate Reorganization, as described in Note 1, Liberty Holdings issued membership interests to investors in exchange for cash consideration. Total member contributions as of December 31, 2017 were $275.7 million , net of commitment and issuance fees. On January 17, 2018, in connection with the Corporate Reorganization, these membership interests were exchanged for Liberty LLC Units. See Note 1 for additional information regarding the Corporate Reorganization. 
+Unit-Based Compensation 
+Prior to the IPO and Corporate Reorganization, Liberty Holdings issued Class B units of Liberty Holdings (“Legacy Units”) to certain eligible employees of the Company. The Legacy Units were non-voting, except with respect to such matters that units are entitled to vote as a matter of law. In such cases, each Legacy Unit entitled the holder to 1/1000th of one vote. Certain Legacy Units granted to eligible participants had an assigned benchmark value and were subject to vesting in accordance with the terms of each award letter. Upon termination of the holder’s employment for any reason, Liberty Holdings had the right, but not the obligation, to repurchase from the recipient those vested Legacy Units at fair value. 
+The Company recognizes compensation expense for equity-based Legacy Units issued to employees based on the grant-date fair value of the awards and each award’s requisite service period. With the assistance from a third-party valuation expert, the Predecessor determined that the Legacy Units issued to employees were deemed to have a de minimis grant-date fair value based on their assigned benchmark values. In connection with the Corporate Reorganization, the unvested Legacy Units were exchanged for 1,258,514 shares of restricted stock with the same terms and requisite vesting conditions as the Legacy Units. 
+Restricted Stock Awards 
+Restricted stock awards are awards of Class A Common Stock that are subject to restrictions on transfer and to a risk of forfeitures if the award recipient is no longer an employee or director of the Company for any reason prior to the lapse of the restrictions. 
+The following table summarizes the Company’s unvested restricted stock activity for the year ended December 31, 2018 : 
+Number of Shares 
+Grant Date Fair Value per Share (1) 
+Shares of Restricted Stock Issued in Exchange for Legacy Units 
+1,258,514 
+— 
+Vested 
+(602,413 
+) 
+— 
+Forfeited 
+(21,448 
+) 
+— 
+Outstanding at December 31, 2018 
+634,653 
+$ 
+— 
+(1) As discussed above, the shares of restricted stock retain the grant date fair value of the Legacy Units. 
+Long Term Incentive Plan 
+On January 11, 2018, the Company adopted the Long Term Incentive Plan (“LTIP”) to incentivize employees, officers, directors and other service providers of the Company and its affiliates. The LTIP provides for the grant, from time to time, at the discretion of the Company's board of directors or a committee thereof, of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, cash awards, substitute awards and performance awards. Subject to adjustment in the event of certain transaction or changes of capitalization in accordance with the LTIP, 12,908,734 shares of Class A Common Stock have been reserved for issuance pursuant to awards under the LTIP. Class A Common stock subject to an award that expires or is canceled, forfeited, exchanged, settled in cash or otherwise terminated without delivery of shares and shares withheld to pay the exercise price of, or to satisfy the withholding obligations with respect to, an award will again be available for delivery pursuant to other awards under the LTIP. 
+F- 17 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Restricted Stock Units 
+Restricted stock units (“RSUs”) granted pursuant to the LTIP, if they vest, will be settled in shares of the Company’s Class A Common Stock. RSUs were granted with vesting terms up to five years. Changes in non-vested RSUs outstanding under the LTIP during the year ended December 31, 2018 were as follows: 
+Number of Units 
+Weighted Average Grant Date Fair Value per Unit 
+Non-vested as of December 31, 2017 
+— 
+$ 
+— 
+Granted 
+1,203,433 
+19.25 
+Vested 
+— 
+— 
+Forfeited 
+(9,750 
+) 
+20.07 
+Outstanding at December 31, 2018 
+1,193,683 
+$ 
+19.24 
+Stock-based compensation is included in cost of services and general and administrative expenses in the Company’s consolidated and combined statements of operations. The Company recognized stock based compensation expense of $5.4 million for the year ended December 31, 2018 . The Company recognized no stock based compensation expense prior to the Corporate Reorganization. There was approximately $17.5 million of unrecognized compensation expense relating to outstanding RSUs as of December 31, 2018 . The unrecognized compensation expense will be recognized on a straight-line basis over the weighted average remaining vesting period of 2.1 years . 
+Dividends 
+The Company paid quarterly cash dividends of $0.05 per share of Class A Common Stock on September 20 and December 20, 2018 to shareholders of record as of September 6, and December 6, 2018, respectively. Liberty LLC paid distributions of $11.6 million , or $0.05 per Liberty LLC Unit, to all Liberty LLC unitholders as of the dates above, $7.0 million of which was paid to the Company. The Company used the proceeds of the distributions to pay the dividends to all holders of Class A Common Stock as of September 6 and December 6, 2018, which totaled $7.0 million . Additionally, the Company accrued $0.2 million of dividends payable related to restricted stock and RSUs to be paid upon vesting. Dividends related to forfeited restricted stock and RSUs will be forfeited. 
+Share Repurchase Program 
+On September 10, 2018 the Company's board of directors authorized a share repurchase plan to repurchase up to $100.0 million of the Company's Class A Common Stock through September 30, 2019. During the year ended December 31, 2018 , Liberty LLC redeemed and retired 4,593,855 Liberty LLC Units from the Company for $82.9 million , and the Company repurchased and retired 4,593,855 shares of Class A Common Stock for 82.9 million , or $18.05 average price per share including commissions. The total remaining authorized amount available for future repurchases of Class A Common Stock under the share repurchase program was $17.1 million as of December 31, 2018 . Of the total amount of Class A Common Stock repurchased, 2,491,160 shares were repurchased pursuant to a Stock Purchase and Sale Agreement, dated as of September 14, 2018, by and among the Company, R/C Energy IV Direct Partnership, L.P., R/C IV Liberty Holdings, L.P. and Riverstone/Carlyle Energy Partners IV, L.P. (collectively, the “Riverstone Sellers”). For further details of this related party transaction see Note 12. 
+The Company accounts for the purchase price of repurchased common shares in excess of par value ( $0.01 per share of Class A Common Stock) as a reduction of additional paid-in capital, and will continue to do so until additional paid-in capital is reduced to zero. Thereafter, any excess purchase price will be recorded as a reduction to retained earnings. 
+F- 18 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Note 9—Net Income per Share 
+Basic net income per share measures the performance of an entity over the reporting period. Diluted net income per share measures the performance of an entity over the reporting period while giving effect to all potentially dilutive common shares that were outstanding during the period. The Company uses the “if-converted” method to determine the potential dilutive effect of its Class B Common Stock and the treasury stock method to determine the potential dilutive effect of outstanding restricted stock and RSUs. 
+The following table reflects the allocation of net income to common stockholders and net income per share computations for the periods indicated based on a weighted average number of common stock outstanding for the period subsequent to the Corporate Reorganization on January 17, 2018: 
+(In thousands, except per share data) 
+Year Ended December 31, 2018 
+Basic Net Income Per Share 
+Numerator: 
+Net income attributable to Liberty Oilfield Services Inc. Stockholders 
+$ 
+126,349 
+Denominator: 
+Basic weighted average shares outstanding 
+68,838 
+Basic net income per share attributable to Liberty Oilfield Services Inc. Stockholders 
+$ 
+1.84 
+Diluted Net Income Per Share 
+Numerator: 
+Net income attributable to Liberty Oilfield Services Inc. Stockholders 
+$ 
+126,349 
+Effect of exchange of the shares of Class B Common stock for shares of Class A Common Stock 
+86,577 
+Diluted net income attributable to Liberty Oilfield Services Inc. Stockholders 
+$ 
+212,926 
+Denominator: 
+Basic weighted average shares outstanding 
+68,838 
+Effect of dilutive securities: 
+Restricted stock 
+906 
+Restricted stock units 
+602 
+Class B Common Stock 
+47,492 
+Diluted weighted average shares outstanding 
+117,838 
+Diluted net income per share attributable to Liberty Oilfield Services Inc. Stockholders 
+$ 
+1.81 
+Note 10—Income Taxes 
+Prior to the IPO, the Predecessor was treated as a partnership for U.S. federal, state and local income tax purposes. As such, any liability for federal income tax was the responsibility of the members of the Predecessor. Accordingly, no provision for U.S. federal, state and local income tax has been provided in the combined financial statements of the Company for periods ending prior to the IPO. 
+Following the IPO, the Company is a corporation and is subject to U.S. federal, state and local income tax on its share of Liberty LLC’s taxable income. Liberty LLC is treated as a partnership, and its income is passed through to its owners, for income tax purposes. Liberty LLC’s members, including the Company, are liable for federal, state and local income taxes based on their share of Liberty LLC’s pass-through taxable income. As of December 31, 2018 , tax reporting by the Company's Predecessor for the years ended December 31, 2015 , 2016 , and 2017 is subject to examination by the tax authorities. With few exceptions, as of December 31, 2018 , the Company is no longer subject to U.S. federal, state or local examinations by tax authorities for tax years ended before December 31, 2015. 
+F- 19 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Income tax expense reflected in the consolidated statement of operations consisted of: 
+($ in thousands) 
+Year Ended December 31, 2018 
+Current: 
+Federal 
+16,684 
+State 
+3,213 
+Total Current 
+$ 
+19,897 
+Deferred: 
+Federal 
+19,063 
+State 
+1,425 
+Total Deferred 
+$ 
+20,488 
+Income tax expense 
+$ 
+40,385 
+A reconciliation of the statutory U.S. federal income tax rate of 21.0% to the Company's effective income tax rate is as follows: 
+($ in thousands) 
+Year Ended December 31, 2018 
+Federal income tax expense at statutory rate 
+$ 
+60,778 
+State and local income tax expense, net 
+4,456 
+Pre-IPO income before income taxes attributable to the Predecessor 
+(1,958 
+) 
+Noncontrolling interest 
+(24,606 
+) 
+Other 
+1,715 
+Total income tax expense 
+$ 
+40,385 
+The effective combined U.S. federal and state income tax rate applicable to the Company for the period commencing on January 17, 2018, the date of the Corporate Reorganization, through December 31, 2018 was 14.0% . 
+The Company recognized income tax expense of $40.4 million for the period commencing on January 17, 2018, the date of the Corporate Reorganization, through December 31, 2018 . The Company’s effective tax rate is significantly less than the statutory federal income tax rate of 21.0% because no taxes are payable by the Company for the noncontrolling interest’s share of Liberty LLC’s pass-through income for federal, state and local income tax reporting and due to the shortened taxable period, as the Company was a pass-through entity prior to the IPO. During 2018, the noncontrolling interest effect resulted in a $ 24.6 million reduction in income tax expenses, while income before taxes and income attributable to the Predecessor resulted in a $ 2.0 million reduction in income tax expenses. 
+F- 20 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+The tax effects of temporary differences that give rise to the deferred tax assets and deferred tax liabilities are presented below: 
+($ in thousands) 
+Year-Ended December 31, 2018 
+Deferred tax assets: 
+Federal net operating losses 
+$ 
+1,638 
+State net operating losses 
+160 
+Realized tax benefit - TRAs 
+15,845 
+Total deferred tax assets 
+17,643 
+Deferred tax liabilities: 
+Investment in Liberty LLC 
+$ 
+50,325 
+Other 
+312 
+Total deferred tax liabilities 
+50,637 
+Net deferred tax liability 
+$ 
+32,994 
+As of December 31, 2018 , the Company had significant deferred tax assets and liabilities. The deferred tax assets include U.S. federal and state net operating losses and the step up in basis of depreciable assets under Section 754 of the Internal Revenue Code of 1986, as amended. As a result of the IPO and Corporate Reorganization, the Company recorded a deferred tax asset and liability for the difference between the book value and the tax value of the Company's investment in Liberty LLC. The deferred tax assets have been recorded for tax attributes contributed to the Company as part of the Corporate Reorganization. Deferred tax liabilities of $29.3 million have been recorded in connection with the Liberty LLC Units acquired through reorganization. The initial deferred tax liability is recorded as a long term liability and additional paid in capital on the consolidated balance sheet as of December 31, 2018 . 
+As of December 31, 2018 , the Company has available U.S. federal net operating loss carryforwards to reduce future taxable income of $4.5 million , expiring in 2027. 
+Uncertain Tax Positions 
+The Company records uncertain tax positions on the basis of a two-step process in which (1) the Company determines whether it is more likely than not the tax positions will be sustained on the basis of the technical merits of the position and (2) for those tax positions meeting the more likely than not recognition threshold, the Company recognizes the largest amount of tax benefit that is more than 50% likely to be realized upon ultimate settlement with the related tax authority. 
+The Company determined that no liability for unrecognized tax benefits for uncertain tax positions was required at December 31, 2018 . In addition, the Company does not believe that it has any tax positions for which it is reasonably possible that it will be required to record a significant liability for unrecognized tax benefits within the next twelve months. If the Company were to record an unrecognized tax benefit, the Company will recognize interest and penalties related to income tax matters in income tax expense. 
+Tax Distributions 
+Liberty LLC is treated as a partnership for income tax purposes. Federal, state and local taxes resulting from the pass-through taxable income of Liberty LLC are obligations of its members. Net profits and losses are generally allocated to the members of Liberty LLC (including the Company) in accordance with the number of Liberty LLC Units held by each member for tax purposes. The amended and restated operating agreement of Liberty LLC provides for cash distributions and advances to assist members (including the Company) in paying their income tax liabilities. Liberty LLC paid to noncontrolling interest holders tax distributions and advances of $17.6 million and $3.7 million , respectively, for the year ended December 31, 2018. 
+F- 21 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Tax Receivable Agreements 
+The term of each TRA commenced on January 17, 2018, and will continue until all such tax benefits that are subject to such TRA have been utilized or expired, unless the Company experiences a change of control (as defined in the TRAs, which includes certain mergers, asset sales and other forms of business combinations) or the TRAs are terminated early (at the Company’s election or as a result of its breach), and the Company makes the termination payments specified in such TRA. 
+The amounts payable, as well as the timing of any payments, under the TRAs are dependent upon significant future events and assumptions, including the timing of the redemptions of Liberty LLC Units, the price of our Class A Common Stock at the time of each redemption, the extent to which such redemptions are taxable transactions, the amount of the redeeming unit holder’s tax basis in its Liberty LLC Units at the time of the relevant redemption, the depreciation and amortization periods that apply to the increase in tax basis, the amount of net operating losses available to the Company as a result of the Corporate Reorganization, the amount and timing of taxable income the Company generates in the future, the U.S. federal income tax rate then applicable, and the portion of the Company’s payments under the TRAs that constitute imputed interest or give rise to depreciable or amortizable tax basis. 
+Prior to the Corporate Reorganization, one of the Legacy Owners distributed a portion of its member interest in Liberty Holdings to R/C IV Non-U.S. LOS Corp. (“R/C IV”). Subsequently, in conjunction with the Corporate Reorganization, R/C IV was contributed to the Company. At the time of the contribution, R/C IV had net operating loss carryforwards totaling $10.9 million for federal income tax purposes and $10.9 million for certain state income tax purposes, which became available for the Company's use as a result of the contribution. As a result of the Company being in a net income position and the expected utilization of deferred tax assets, the Company recognized a deferred tax asset of $2.6 million and a corresponding $2.3 million liability pursuant to the TRAs. 
+During the year ended December 31, 2018 , exchanges of Liberty LLC Units and shares of Class B Common Stock resulted in an increase of $14.5 million in amounts payable under the TRAs, and a net increase of $17.1 million in deferred tax assets, all of which were recorded through equity. At December 31, 2018 , the Company’s liability under the TRA was $ 16.8 million , all of which is presented as a component of long term liabilities, and the related deferred tax assets totaled $19.7 million . 
+Note 11—Defined Contribution Plan 
+The Company sponsors a 401(k) defined contribution retirement plan covering eligible employees. The Company makes matching contributions, which were temporarily suspended in May 2015, but were resumed in April 2017 at a rate of $1.00 for each $1.00 of employee contribution, subject to a cap of 3% of the employee’s salary. In October 2017, the cap on these contributions was increased to 6% of the employee’s base salary. Contributions made by the Company were $13.8 million, $5.1 million and $0 for the years ended December 31, 2018 , 2017 and 2016 , respectively. 
+Note 12—Related Party Transactions 
+During September 2018, the Company repurchased 2,491,160 shares of Class A Common Stock from the Riverstone Sellers, at a weighted average purchase price of $18.96 per share, pursuant to the share repurchase program (see Note 8—Equity - Share Repurchase Program ). 
+In connection with the Corporate Reorganization, the Company engaged in transactions with affiliates (see Note 1—Organization and Basis of Presentation) including entering into the TRAs with affiliates (see Note 10). Also in conjunction with the Corporate Reorganization, Liberty Holdings contributed $2.1 million of additional assets to Liberty LLC and Redeemable Common Units in the amount of $42.6 million were settled (see Note 6). 
+In September 2011, Liberty Resources LLC, an oil and gas exploration and production company, and its successor entity (collectively, the “Affiliate”) and LOS, companies with common ownership and management, entered into a services agreement (the “Services Agreement”) whereby the Affiliate is to provide certain administrative support functions to LOS and a master service agreement whereby LOS provides hydraulic fracturing services to the Affiliate at market service rates. The amounts incurred under the Services Agreement by LOS during the years ended December 31, 2018 , 2017 and 2016 , were $0.2 million , $0 and $0.1 million , respectively, and there was no outstanding balance for the respective periods. On June 14, 2018, the Services Agreement was formally terminated. 
+F- 22 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+The amounts of the Company’s revenue related to hydraulic fracturing services provided to the Affiliate for the years ended December 31, 2018 , 2017 and 2016 , were $23.1 million , $24.7 million and $13.1 million , respectively. As of December 31, 2018 and 2017 , $15.1 million and $4.0 million , respectively, of the Company’s accounts receivable, and $0 and $0.1 million , respectively, of the Company’s unbilled revenue was with the Affiliate. 
+Liberty Holdings entered into an advisory agreement, dated December 30, 2011, with Riverstone/Carlyle Energy Partners IV, L.P. (“R/C”), in which R/C agreed to provide certain administrative advisory services to Liberty Holdings. The service fees incurred to R/C for the years ended December 31, 2018 , 2017 and 2016 were approximately $0 , $1.5 million and $0.5 million , respectively. The advisory services agreement was terminated pursuant to an agreement effective as of January 11, 2018. On January 11, 2018, Liberty Holdings, R/C and other parties entered into a Master Reorganization Agreement that, among other things, crystallized the “waterfall” provisions of Article VI of the Third Amended and Restated Limited Liability Agreement of Liberty Holdings, dated October 11, 2016 (the “Holdings LLC Agreement”) in connection with the initial public offering of shares of Class A Common Stock. As part of this crystallization, R/C and affiliated entities (collectively, the “R/C Affiliates”) received shares of Class A Common Stock, including 117,647 shares of Class A Common Stock (such 117,647 referred to as the “Issued Shares”) to compensate R/C Affiliates for certain accrued preferred returns but which would not have been issued had the $2.0 million in fees owing under the advisory agreement been paid in cash. Had this fee been paid in cash on or prior to January 11, 2018, R/C and Liberty Holdings acknowledge that R/C Affiliates would not have received the Issued Shares in the crystallization pursuant to the provisions of the Holdings LLC Agreement. Subsequently, during the fourth quarter of 2018, R/C asserted that certain provisions of the termination of services agreement provided for R/C to receive $2.0 million in cash as payment of those accrued fees. To resolve this matter, the Company agreed to pay R/C Affiliates $2.0 million in cash in exchange for the purchase, at the IPO price, or return of the Issued Shares and $0.3 million for interest and the settlement of the matter. Accordingly, $2.3 million was recorded as accrued liabilities - related party in the accompanying consolidated balance sheet as of December 31, 2018 and subsequently paid in January 2019. The purchased and returned shares of Class A Common Stock were canceled and retired, and the Company does not expect to incur future expense related to the advisory agreement or termination thereof. 
+During 2016, Liberty Holdings entered into a future commitment to invest and become a non-controlling minority member in Proppant Express Investments, LLC (“PropX Investments”), the owner of Proppant Express Solutions, LLC (“PropX”), a provider of proppant logistics equipment. LOS is party to a services agreement (the “PropX Services Agreement”) whereby LOS is to provide certain administrative support functions to PropX, and LOS is to purchase and lease proppant logistics equipment from PropX. The PropX Services Agreement was terminated on May 29, 2018, the Company continues to purchase and lease equipment from PropX. For the years ended December 31, 2018 and 2017 the Company purchased proppant logistics equipment of $3.1 million and $9.9 million and leased proppant logistics equipment during the years ended December 31, 2018 , 2017 and 2016 for $4.4 million , $3.7 million and $0 , respectively. During the three months ended March 31, 2018, in exchange for a 5% discount, the Company made a prepayment to PropX for rented equipment in the amount of $5.4 million , all of which was recognized during the year ended December 31, 2018. 
+Receivables from PropX as of December 31, 2018 and 2017 were $0 . Payables to PropX as of December 31, 2018 and 2017 were $0.2 million and $0.7 million , respectively. 
+Note 13—Commitments & Contingencies 
+Operating Leases 
+The Company leases office space, facilities, equipment, and vehicles under non-cancelable operating leases. Rent expense for the years ended December 31, 2018 and 2017 , was $40.9 million and $20.8 million , respectively. 
+F- 23 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Future minimum lease payments are as follows: 
+($ in thousands) 
+Years Ending December 31, 
+2019 
+$ 
+42,717 
+2020 
+48,685 
+2021 
+32,390 
+2022 
+6,093 
+2023 
+4,303 
+Thereafter 
+19,742 
+153,930 
+Purchase Commitments (tons, per ton, gallons, per gallon and per rail car prices are not in thousands) 
+The Company enters into purchase and supply agreements to secure supply and pricing of proppants and chemicals. As of December 31, 2018 and 2017 , the agreements commit the Company to purchase 11,266,000 and 10,108,000 tons, respectively, of proppant through December 31, 2021. Amounts above also include commitments to pay for transport fees on minimum amounts of proppants or railcars. 
+Certain proppant supply agreements contain a clause whereby in the event that the Company fails to purchase minimum volumes, as defined in the agreement, during a specific time period, a shortfall fee may apply. There were no shortfalls as of December 31, 2018 . 
+As of December 31, 2018 and 2017 , the Company has commitments to purchase 18,852,000 and 27,278,000 gallons of chemicals through December 31, 2020. 
+Future proppant, chemical and rail car commitments are as follows: 
+Year ending December 31, 
+2019 
+$ 
+341,970 
+2020 
+247,989 
+2021 
+96,958 
+2022 
+3,945 
+2023 
+— 
+$ 
+690,862 
+Litigation 
+From time to time, the Company is subject to legal and administrative proceedings, settlements, investigations, claims and actions. The Company’s assessment of the likely outcome of litigation matters is based on its judgment of a number of factors including experience with similar matters, past history, precedents, relevant financial and other evidence and facts specific to the matter. Notwithstanding the uncertainty as to the final outcome, based upon the information currently available, management does not believe any matters in aggregate will have a material adverse effect on its financial position or results of operations. 
+On February 23, 2017, SandBox Logistics and Oren Technologies, LLC (collectively, “Sandbox”) filed suit in the Houston Division of the U.S. District Court for the Southern District of Texas against PropX and LOS. SandBox alleged that LOS willfully infringed multiple U.S. patents and breached an agreement between SandBox and LOS by “directing, controlling, and funding” inter partes review requests before the U.S. Patent and Trademark Office. In July 2018, SandBox requested permission from the court to allege additional breach of contract claims against LOS, including alleged breaches of a confidentiality agreement and an exclusive purchasing covenant. The court denied these requests in September 2018. On December 19, 2018, the U.S. District Court for the Southern District of Texas entered an order dismissing the claims against LOS with prejudice. 
+F- 24 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Note 14—Selected Quarterly Financial Data (unaudited) 
+The following table sets forth certain unaudited financial and operating information for each quarter of the years ended December 31, 2018 and 2017 . The unaudited quarterly information includes all adjustments that, in the opinion of management, are necessary for the fair presentation of information presented. Operating results for interim periods are not necessarily indicative of the results that may be expected for the full fiscal year. 
+($ in thousands) 
+Year Ended December 31, 2018 
+Selected Financial Data: 
+First Quarter 
+Second Quarter 
+Third Quarter 
+Fourth Quarter 
+Revenue 
+$ 
+495,160 
+$ 
+628,084 
+$ 
+558,777 
+$ 
+473,115 
+Operating costs and expenses: 
+Cost of services (exclusive of depreciation and amortization shown separately below) 
+376,827 
+455,469 
+418,867 
+377,590 
+General and administrative 
+21,677 
+27,313 
+24,659 
+25,403 
+Depreciation and amortization 
+28,016 
+30,606 
+32,305 
+34,183 
+Loss (gain) on disposal of assets 
+80 
+485 
+701 
+(5,608 
+) 
+Total operating costs and expenses 
+426,600 
+513,873 
+476,532 
+431,568 
+Operating income 
+68,560 
+114,211 
+82,245 
+41,547 
+Other expense: 
+Interest expense 
+(6,494 
+) 
+(3,540 
+) 
+(3,648 
+) 
+(3,463 
+) 
+Net income before income taxes 
+62,066 
+110,671 
+78,597 
+38,084 
+Income tax expense 
+8,079 
+15,930 
+12,229 
+4,147 
+Net income 
+53,987 
+94,741 
+66,368 
+33,937 
+Less: Net income attributable to Predecessor, prior to Corporate Reorganization 
+8,705 
+— 
+— 
+— 
+Less: Net income attributable to noncontrolling interests 
+21,607 
+45,146 
+32,275 
+14,951 
+Net income attributable to Liberty Oilfield Services Inc. stockholders 
+$ 
+23,675 
+$ 
+49,595 
+$ 
+34,093 
+$ 
+18,986 
+($ in thousands) 
+Year ended December 31, 2017 
+Selected Financial Data: 
+First Quarter 
+Second Quarter 
+Third Quarter 
+Fourth Quarter 
+Revenue 
+$ 
+252,394 
+$ 
+346,725 
+$ 
+441,853 
+$ 
+448,883 
+Operating costs and expenses: 
+Cost of services (exclusive of depreciation and amortization shown separately below) 
+211,633 
+267,626 
+328,434 
+339,315 
+General and administrative 
+17,084 
+20,022 
+22,245 
+20,738 
+Depreciation and amortization 
+14,146 
+17,521 
+24,164 
+25,642 
+Loss (gain) on disposal of assets 
+(43 
+) 
+10 
+21 
+160 
+Total operating costs and expenses 
+242,820 
+305,179 
+374,864 
+385,855 
+Operating income 
+9,574 
+41,546 
+66,989 
+63,028 
+Other expense: 
+Interest expense 
+(1,452 
+) 
+(2,511 
+) 
+(3,326 
+) 
+(5,347 
+) 
+Net income 
+$ 
+8,122 
+$ 
+39,035 
+$ 
+63,663 
+$ 
+57,681 
+F- 25 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Note 15—Subsequent Events 
+In the month ended January 31, 2019, Liberty LLC purchased and retired 1,185,356 Liberty LLC Units from the Company for 17.1 million , and the Company repurchased and retired 1,185,356 shares of Class A Common Stock for 17.1 million , or $14.42 average price per share. These repurchases completed the $100.0 million share repurchase plan previously announced on September 19, 2018. 
+On January 22, 2019, the Company announced that its Board of Directors has authorized the implementation of an additional share repurchase plan to repurchase shares of the Company’s Class A Common Stock, par value $0.01 per share, in an amount not to exceed $100.0 million through January 31, 2021. 
+Subsequent to December 31, 2018, certain holders of Class B Common Stock exercised their Redemption Right and exchanged 1,634,569 Liberty LLC Units and 1,634,569 shares of Class B Common Stock for 1,634,569 shares of Class A Common Stock. The exchanged shares of Class B Common Stock were canceled and retired. 
+There were no significant subsequent events requiring disclosure or recognition other than those disclosed in these notes to the consolidated and combined financial statements. 
+F- 26
\ No newline at end of file
diff --git a/raw/filings/0001694028/2018/0001694028-19-000015/filing_metadata.csv b/raw/filings/0001694028/2018/0001694028-19-000015/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..7e400896449e138899dc208489a0f1b2ebf36310
--- /dev/null
+++ b/raw/filings/0001694028/2018/0001694028-19-000015/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0001694028,LBRT,Liberty Energy Inc.,10-K,2019-02-28,2018-12-31,2019-03-01T00:14:47.000Z,0001694028-19-000015,libertyoilfield1231201810-k.htm,10-K,7518539,1,0,https://www.sec.gov/Archives/edgar/data/1694028/000169402819000015/libertyoilfield1231201810-k.htm,https://www.sec.gov/Archives/edgar/data/1694028/000169402819000015/,2018,2018,1
diff --git a/raw/filings/0001694028/2018/0001694028-19-000015/item1.txt b/raw/filings/0001694028/2018/0001694028-19-000015/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..5cf2321c630234c0978c89370d7b3ae58fa2d465
--- /dev/null
+++ b/raw/filings/0001694028/2018/0001694028-19-000015/item1.txt
@@ -0,0 +1,194 @@
+Item 1. Business 
+Overview 
+We are an independent provider of hydraulic fracturing services to onshore oil and natural gas exploration and production (“E&P”) companies in North America. We provide our services primarily in the Permian Basin, the Eagle Ford Shale, the Denver-Julesburg Basin (the “DJ Basin”), the Williston Basin and the Powder River Basin. 
+Initial Public Offering and Corporate Reorganization Transaction 
+Liberty Inc. was incorporated as a Delaware corporation on December 21, 2016, to become a holding corporation for Liberty LLC and its subsidiaries upon completion of a corporate reorganization (as detailed below, the “Corporate Reorganization”) and planned initial public offering of the Company (“IPO”). The Company has no material assets other than its ownership in Liberty LLC. 
+On January 17, 2018, we completed our IPO of 14,640,755 shares of our Class A common stock, par value $0.01 per share (the “Class A Common Stock”) at a public offering price of $17.00 per share, of which 14,340,214 shares were offered by us and 300,541 shares were offered by the selling shareholder. We received approximately $220.0 million in net proceeds after deducting approximately $23.8 million of underwriting discounts and commissions and other offering costs. We did not receive any proceeds from the sale of the shares of Class A Common Stock by the selling shareholder. We used approximately $25.9 million of net proceeds from the IPO to redeem ownership in us from certain Legacy Owners (as defined below) and contributed the remaining proceeds to Liberty LLC in exchange for units in Liberty LLC (the “Liberty LLC Units”). Liberty LLC used a portion of the net proceeds (i) to fully repay our outstanding borrowings and accrued interest under our ABL Facility (as defined herein), totaling approximately $30.1 million , (ii) to repay 35% of our outstanding borrowings, accrued interest and prepayment premium under our Term Loan Facility (as defined herein), totaling approximately $62.5 million and (iii) for general corporate purposes, including repayment of additional indebtedness and funding capital expenditures. 
+We are a holding company with no direct operations. In connection with the IPO, we completed the Corporate Reorganization, including the following series of transactions: 
+• 
+Liberty Holdings contributed all of its assets to Liberty LLC in exchange for Liberty LLC Units; 
+• 
+Liberty Holdings liquidated and distributed to its then-existing owners (the “Legacy Owners”) Liberty LLC Units pursuant to the terms of the limited liability company agreement of Liberty Holdings and the Master Reorganization Agreement dated as of January 11, 2018, by and among the Company, Liberty Holdings, Liberty LLC, and the other parties named therein (the “Master Reorganization Agreement”); 
+• 
+Certain of the Legacy Owners directly or indirectly contributed all or a portion of their Liberty LLC Units to Liberty Inc. in exchange for 55,685,027 shares of our Class A Common Stock, and 1,258,514 shares of restricted stock. Subsequent to the initial exchange, 1,609,122 shares of Class A Common Stock were redeemed for an aggregate purchase price of $25.9 million upon the exercise of the underwriters' overallotment option; 
+• 
+Liberty Inc. issued the Legacy Owners that continued to own Liberty LLC Units (the “Liberty Unit Holders”) an aggregate amount of 48,207,372 shares of our Class B common stock, par value $0.01 per share (the “Class B Common Stock” and, together with the Class A Common Stock, the “Common Stock”); and 
+• 
+Liberty Inc. contributed the net proceeds it received from the IPO to Liberty LLC in exchange for additional Liberty LLC Units such that Liberty Inc. held a total number of Liberty LLC Units equal to the number of shares of Class A Common Stock outstanding immediately following the IPO. 
+1 
+Table of Contents 
+The below structure chart shows our organization upon the completion of our IPO. This chart is provided for illustrative purposes only and, does not represent all legal entities affiliated with us. 
+Each share of Class B Common Stock has no economic rights but entitles its holder to one vote on all matters to be voted on by shareholders generally. Holders of Class A Common Stock and Class B Common Stock will vote together as a single class on all matters presented to our shareholders for their vote or approval, except as otherwise required by applicable law or by our amended and restated certificate of incorporation. We do not intend to list our Class B Common Stock on any exchange. 
+Under the Second Amended and Restated Limited Liability Company Agreement of Liberty LLC (the “Liberty LLC Agreement”), each Liberty Unit Holder has, subject to certain limitations, the right (the “Redemption Right”) to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units for, at Liberty LLC’s election, (i) shares of our Class A Common Stock at a redemption ratio of one share of Class A Common Stock for each Liberty LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions or (ii) an equivalent amount of cash. Alternatively, upon the exercise of the Redemption Right, Liberty Inc. (instead of Liberty LLC) will have the right (the “Call Right”) to, for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder for, at its election, (x) one share of Class A Common Stock or (y) an equivalent amount of cash. In addition, upon a change of control of Liberty Inc., Liberty Inc. has the right to require each holder of Liberty LLC Units (other than Liberty Inc.) to exercise its Redemption Right with respect to some or all of such unit holder’s Liberty LLC Units. In connection with any redemption of Liberty LLC Units pursuant to the Redemption Right or the Call Right, the corresponding number of shares of Class B Common Stock will be canceled. 
+In connection with the IPO, Liberty Inc. entered into two tax receivable agreements, (the “TRAs”) with the Liberty Unit Holders and the selling shareholder (each such person and any permitted transferee, a “TRA Holder” and together, the “TRA Holders”). 
+The first of the TRAs, which Liberty Inc. entered into with the Liberty Unit Holders, generally provides for the payment by Liberty Inc. to such TRA Holders of 85% of the net cash savings, if any, in U.S. federal, state and local income and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that Liberty Inc. actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result of, as applicable to each such TRA 
+2 
+Table of Contents 
+Holder, (i) certain increases in tax basis that occur as a result of Liberty Inc.’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holder’s Liberty LLC Units in connection with the IPO or pursuant to the exercise of the Redemption Right or Liberty Inc.’s Call Right and (ii) imputed interest deemed to be paid by Liberty Inc. as a result of, and additional tax basis arising from, any payments Liberty Inc. makes under such TRAs. 
+The second of the TRAs, which Liberty Inc. entered into with the selling shareholder, generally provides for the payment by Liberty Inc. to such TRA Holder of 85% of the net cash savings, if any, in U.S. federal, state and local income and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that Liberty Inc. actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result of, as applicable to such TRA Holder, (i) any net operating losses available to Liberty Inc. as a result of the Corporate Reorganization and (ii) imputed interest deemed to be paid by Liberty Inc. as a result of any payments Liberty Inc. makes under such TRAs. For further discussion regarding the potential acceleration of payments under the TRAs and its potential impact, please read “Risk Factors—Risks Related to Our Class A Common Stock.” 
+Because Liberty Inc. is a holding company with no operations of its own, Liberty Inc.’s ability to make payments under the TRAs is dependent on the ability of Liberty LLC to make distributions to Liberty Inc. in an amount sufficient to cover its obligations under the TRAs. See “Risk Factors—Risks Related to Our Class A Common Stock—Liberty Inc. is a holding company. Liberty Inc.’s only material asset is its equity interest in Liberty LLC, and Liberty Inc. is accordingly dependent upon distributions from Liberty LLC to pay taxes, make payments under the TRAs and cover its corporate and other overhead expenses.” If Liberty Inc. experiences a change of control (as defined under the TRAs, which includes certain mergers, asset sales and other forms of business combinations) or the TRAs terminate early (at Liberty Inc.’s election or as a result of its breach), Liberty Inc. would be required to make a substantial, immediate lump-sum payment. 
+Our Company 
+We are an independent provider of hydraulic fracturing services to onshore oil and natural gas E&P companies in the United States. We have grown organically from one active hydraulic fracturing fleet in December 2011 to 22 active fleets in February 2019. We expect to take delivery of additional equipment in 2019. However, decisions whether or not to deploy these additional fleets in 2019 will be made considering customer demand, long term return profile and market conditions. We provide our services primarily in the Permian Basin, the Eagle Ford Shale, the DJ Basin, the Williston Basin and the Powder River Basin. 
+Our founders and existing management were pioneers in the development of data-driven hydraulic fracturing technologies for application in shale plays. Prior to founding Liberty Holdings, the majority of our management team founded and built Pinnacle Technologies, Inc. (“Pinnacle Technologies”) into a leading fracturing technology company. In 1992, Pinnacle Technologies developed the first commercial hydraulic fracture mapping technologies, analytical tools that played a major role in launching the shale revolution. Our extensive experience with fracture technologies and customized fracture design has enabled us to develop new technologies and processes that provide our customers with real time solutions that significantly enhance their completions. These technologies include hydraulic fracture propagation models, reservoir engineering tools, large, proprietary shale production databases and multi-variable statistical analysis techniques. Taken together, these technologies have enabled us to be a leader in hydraulic fracture design innovation and application. 
+We believe the following characteristics distinguish us from our competitors and are the foundations of our business: forming ongoing partnerships of trust and innovation with our customers; developing and utilizing technology to maximize well performance; and promoting a people-centered culture focused on our employees, customers and suppliers. We have developed strong relationships with our customers by investing significant time in fracture design collaboration, which substantially enhances their production economics. Our technological innovations have become even more critical as E&P companies have increased the completion complexity and fracture intensity of horizontal wells. We are proactive in developing innovative solutions to industry challenges, including developing: (i) our proprietary databases of U.S. unconventional wells to which we apply our proprietary multi-variable statistical analysis technologies to provide differential insight into fracture design optimization; (ii) our Liberty Quiet Fleet® design which significantly reduces noise levels compared to conventional hydraulic fracturing fleets; and (iii) hydraulic fracturing fluid systems tailored to the specific reservoir properties in the basins in which we operate. We foster a people-centered culture built around honoring our commitments to customers, partnering with our suppliers and hiring, training and retaining people that we believe to be the best talent in our field, enabling us to be one of the safest and most efficient hydraulic fracturing companies in the United States. 
+Recent Developments 
+On January 22, 2019, our board of directors (the “Board”) authorized a share repurchase plan to repurchase shares of our Class A Common Stock, par value $0.01 per share, in an amount not to exceed $100 million through January 31, 2021. This 
+3 
+Table of Contents 
+program is in addition to the $100 million share repurchase program we previously announced on September 10, 2018, which has been substantially completed. We expect to fund repurchases made under this plan from existing cash on hand and future operating cash flow. The share repurchase program was approved by the Board who believe that a share repurchase program at this time is in the best interests of us and our shareholders and will not impact our ability to execute our growth plans. 
+We also announced on January 22, 2019 that the Board approved a quarterly cash dividend of $0.05 per share of Class A Common Stock, to be paid on March 20, 2019 to holders of record as of March 6, 2019. A distribution of $0.05 per unit has been approved for holders of units in Liberty LLC, which will use the same record and payment date. 
+Future declarations of dividends are subject to approval by the Board and to the Board’s continuing determination that the declarations of dividends are in the best interests of us and our stockholders. Future dividends may be adjusted at the Board’s discretion based on market conditions and capital availability. 
+Cyclical Nature of Industry 
+We operate in a highly cyclical industry. The key factor driving demand for our services is the level of drilling activity by E&P companies, which in turn depends largely on the current and anticipated economics of new well completions. Global supply and demand for oil and the domestic supply and demand for natural gas are critical in assessing industry outlook. Demand for oil and natural gas is cyclical and subject to large, rapid fluctuations. E&P companies tend to increase capital expenditures in response to increases in oil and natural gas prices, which generally results in greater revenues and profits for oilfield service companies such as ours. Increased capital expenditures also ultimately lead to greater production, which historically has resulted in increased supplies and reduced prices which in turn tend to reduce demand for oilfield services. For these reasons, the results of our operations may fluctuate from quarter to quarter and from year to year, and these fluctuations may distort comparisons of results across periods. 
+Seasonality 
+Our results of operations have historically reflected seasonal tendencies relating to holiday seasons, inclement weather and the conclusion of our customers’ annual drilling and completion capital expenditure budgets. Our most notable declines typically occur in the first and fourth quarters of the year for the reasons described above. Additionally, some of the areas in which we have operations, including the DJ Basin, Powder River Basin and Williston Basin, are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice or rain and frost law enforcement, we may be unable to move our equipment between locations, thereby reducing our ability to provide services and generate revenues. The exploration activities of our customers may also be affected during such periods of adverse weather conditions. Additionally, extended drought conditions in our operating regions could impact our ability or our customers’ ability to source sufficient water or increase the cost for such water. 
+Intellectual Property 
+Over the last several years we have significantly invested in our research and technology capabilities. Our efforts to date have been focused on developing innovative, fit-for-purpose solutions designed to enhance our core service offerings, increase completion efficiencies, provide cost savings to our operations and add value for our customers. 
+As a result of these efforts, we introduced several new products and progressed on differentiating technologies that we believe will provide a competitive advantage as our customers focus on extracting oil and natural gas in the most economical and efficient ways possible, including, for example, our Liberty Quiet Fleet®, which materially reduces noise levels compared to conventional fracturing fleets. These investments are delivering value added products and services that support our customers and create increasing demand for our services. 
+We seek patent and trademark protections for our technology when we deem it prudent, and we aggressively pursue protection of these rights when warranted. We believe our patents, trademarks, and other protections for our proprietary technologies are adequate for the conduct of our business and that no single patent or trademark is critical to our business. In addition, we rely, to a great extent, on the technical expertise and know-how of our personnel to maintain our competitive position, and we take commercially reasonable measures to protect trade secrets and other confidential and/or proprietary information relating to the technologies we develop. 
+Risk Management and Insurance 
+Our operations are subject to significant hazards often found in the oil and natural gas industry, such as, but not limited to, accidents, blowouts, explosions, craterings, fires, natural gas leaks, oil and produced water spills and releases of hydraulic fracturing fluids or other well fluids into the environment. These conditions can cause: 
+4 
+Table of Contents 
+• 
+disruption in operations; 
+• 
+substantial repair or remediation costs; 
+• 
+personal injury or loss of human life; 
+• 
+significant damage to or destruction of property and equipment; 
+• 
+environmental pollution, including groundwater contamination; 
+• 
+unusual or unexpected geological formations or pressures and industrial accidents; 
+• 
+impairment or suspension of operations; and 
+• 
+substantial revenue loss. 
+In addition, our operations are subject to, and exposed to, employee/employer liabilities and risks such as wrongful termination, discrimination, labor organizing, retaliation claims and general human resource related matters. 
+Claims for loss of oil and natural gas production and damage to formations can occur in the well services industry. Litigation arising from a catastrophic occurrence at a location where our equipment and services are being used may result in our being named as a defendant in lawsuits asserting large claims. 
+We do not have insurance against all foreseeable risks, either because insurance is not available or because of the high premium costs. The occurrence of an event not fully insured against or the failure of an insurer to meet its insurance obligations could result in substantial losses. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. Insurance may not be available to cover any or all of the risks to which we are subject, or, even if available, it may be inadequate, or insurance premiums or other costs could rise significantly in the future so as to make such insurance prohibitively expensive. 
+We enter into Master Service Agreements (“MSAs”) with substantially all of our customers. Our MSAs delineate our and our customer’s respective indemnification obligations with respect to the services we provide. Generally, under our MSAs, including those relating to our hydraulic fracturing services, we assume responsibility for pollution or contamination originating above the surface from our equipment or handling. However, our customers assume responsibility for all other pollution or contamination that may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling and completion fluids. The assumed responsibilities include the control, removal and clean-up of any pollution or contamination. In such cases, we may be exposed to additional liability if we are grossly negligent or commit willful acts causing the pollution or contamination. Generally, our customers also agree to indemnify us against claims arising from their employees’ personal injury or death, in the case of our hydraulic fracturing operations, to the extent that their employees are injured by such operations, unless the loss is a result of our gross negligence or willful misconduct. Similarly, we generally agree to indemnify our customers for liabilities arising from personal injury to or death of any of our employees, unless resulting from the gross negligence or willful misconduct of our customer. The same principles apply to mutual indemnification for loss or destruction of customer-owned property or equipment. Losses due to catastrophic events, such as blowouts, are generally the responsibility of the customer. However, despite this general allocation of risk, we may be unsuccessful in enforcing contractual terms, incur an unforeseen liability that is not addressed by the scope of the contractual provisions or be required to enter into an MSA with terms that vary from our standard allocations of risk, as described above. Consequently, we may incur substantial losses that could materially and adversely affect our financial condition and results of operations. 
+Employees 
+As of December 31, 2018, we had 2,437 employees and no unionized labor. We believe we have good relations with our employees. 
+Our Services 
+We provide hydraulic fracturing services to E&P companies, particularly to those operating in unconventional oil and natural gas reservoirs and requiring technically and operationally advanced services. Hydraulic fracturing services are performed to enhance production of oil and natural gas from formations with low permeability and restricted flow of hydrocarbons. Our customers benefit from our expertise in fracturing horizontal wells in shales and other unconventional geological formations. 
+The process of hydraulic fracturing involves pumping a pressurized stream of fracturing fluid—typically a mixture of water, chemicals and proppant—into a well casing or tubing in order to cause the underground formation to fracture or crack. These fractures release trapped hydrocarbon particles and provide a conductive channel for the oil or natural gas to flow freely 
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+to the wellbore for collection. The propping agent, or proppant,—typically sand—becomes lodged in the cracks created by the hydraulic fracturing process, “propping” them open to facilitate the flow of hydrocarbons from the reservoir to the well. The fracturing fluid is engineered to lose viscosity, or “break,” and is subsequently flowed back from the formation, leaving the proppant suspended in the mineral fractures. Once our customer has flushed the fracturing fluids from the well using a controlled flow-back process, the customer manages fluid and water recycling or disposal. 
+Our hydraulic fracturing fleets consist of mobile hydraulic fracturing units and other auxiliary heavy equipment to perform fracturing services. Our hydraulic fracturing units consist primarily of high-pressure hydraulic pumps, diesel engines, transmissions, radiators and other supporting equipment that are typically mounted on trailers. We refer to the group of units and other equipment, such as blenders, data vans, sand storage, tractors, manifolds and high pressure fracturing iron, which are necessary to perform a typical hydraulic fracturing job, as a “fleet,” and the personnel assigned to each fleet as a “crew.” As of February 2019, we had 22 active fleets. 
+An important element of our hydraulic fracturing services is our focus on providing custom-tailored completions solutions to our customers to maximize their well results. Our technologically innovative approach involves our review of a series of continually updated, proprietary databases of U.S. unconventional wells to which we apply our multi-variable data analysis, allowing us to gain differential insight into fracture design. The innovative completions solutions we provide to our customers help them complete more productive and cost efficient wells in shorter times with less environmental impact on their surroundings while increasing the useful lives of our equipment. 
+In addition to custom-tailored completions solutions, we also develop custom fluid systems, proppant logistics solutions, perforating strategies and pressure analysis techniques for our customers. An example of this is a hydraulic fracturing fluid that we developed for use in our DJ Basin operations called Liberty Spirit ™ , a specifically designed fracturing fluid system that enables material reductions in completion costs in the DJ Basin without compromising job execution or well results. 
+We provide our services in several of the most active basins in the United States, including the Permian Basin, the Eagle Ford Shale, the DJ Basin, the Williston Basin and the Powder River Basin. The map below represents our current areas of operations: 
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+Properties and Equipment 
+Properties 
+Our corporate headquarters are located at 950 17 th Street, Suite 2400, Denver, Colorado 80202. We lease our general office space at our corporate headquarters. The lease expires in December 2024. We currently own or lease the following additional principal properties: 
+District Facility Location 
+Size 
+Leased or Owned 
+Expiration of Lease 
+Odessa, TX 
+77,500 sq. ft on 47 acres 
+Owned 
+N/A 
+Henderson, CO 
+50,000 sq. ft on 13 acres 
+Leased 
+December 31, 2034 
+Williston, ND 
+30,000 sq. ft on 15 acres 
+Owned 
+N/A 
+Gillette, WY 
+32,757 sq. ft on 15 acres 
+Leased 
+December 31, 2034 
+Cibolo, TX 
+90,000 sq. ft on 34 acres 
+Owned 
+N/A 
+Sedalia, CO 
+11,805 sq. ft on 112 acres 
+Owned 
+N/A 
+We also lease several smaller facilities, which leases generally have terms of one to three years. We believe that our existing facilities are adequate for our operations and their locations allow us to efficiently serve our customers. We do not believe that any single facility is material to our operations and, if necessary, we could readily obtain a replacement facility. 
+Equipment 
+We currently have 22 hydraulic fracturing fleets, and expect to take delivery of additional equipment in 2019. However, decisions whether or not to deploy these additional fleets in 2019 will be made considering customer demand, long term return profile and market conditions. Eight of our fleets currently utilize our Liberty Quiet Fleet® technology and approximately 40% of our capacity has dual fuel capability. 
+Our hydraulic fracturing fleets are comprised of high-quality, heavy-duty equipment designed to reduce operational downtime and maintenance costs, while enhancing our ability to provide reliable, consistent service. Each hydraulic fracturing fleet includes the necessary blending units, manifolds, data vans and other ancillary equipment needed to provide a high level of service to our customers. 
+Our newbuild fleets are manufactured to a custom Liberty specification that identifies the input components, including such key parts as engines, transmissions and pumps and control systems. These components have been selected with our lowest total cost of ownership philosophy in mind. We have built a strong partnership with each of the key component suppliers that we believe will help ensure timely access to necessary components, early opportunities to adopt the latest technology, and high-level technical support. For example, our close partnership with Caterpillar Inc. enabled us to have ready access to their technical team as we worked through the development of the Liberty Quiet Fleet® technology. This relationship ensured that the end product was delivered without compromise to engine performance, reliability or maintainability. We have also a built a strong relationship with the assembler of the core equipment for our fracturing fleets. We believe the collaborative partnerships we have developed with our vendors should give us ready access to sufficient fabrication capacity for our growth. 
+Our Acquisitions 
+On June 13, 2016, we acquired certain inventories and long-lived field service assets related to hydraulic fracturing from Sanjel Corporation for $69.0 million in cash (the “Sanjel Acquisition”). These assets were acquired from Sanjel Corporation as part of its bankruptcy proceeding. On February 22, 2017, we acquired all the membership interests of Titan Frac Services LLC, a wholly-owned subsidiary of TPIH Group Inc., for $65.0 million in cash. 
+Marketing and Customers 
+Our sales and marketing activities typically are performed through our local sales representatives in each geographic region, and are supported by our corporate headquarters. For the years ended December 31, 2018 , 2017 and 2016 , our top five customers collectively accounted for approximately 42%, 53% and 59% of our revenues, respectively. Extraction Oil & Gas, Inc. accounted for more than 10% of our revenues for the year ended December 31, 2018 . For the year ended December 31, 2017 , Extraction Oil & Gas, Inc. and SM Energy Company each accounted for more than 10% of our revenues. Extraction Oil & Gas, Inc., SM Energy Company and Noble Energy, Inc. each accounted for more than 10% of our revenues for the year ended December 31, 2016 . 
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+Suppliers 
+We have a dedicated supply chain team that manages sourcing and logistics to ensure flexibility and continuity of supply in a cost effective manner across our areas of operation. We have built long-term relationships with multiple industry leading suppliers of proppant, chemicals and hydraulic fracturing equipment. For the years ended December 31, 2018 , 2017 and 2016 none of our suppliers accounted for more than 10% of overall costs. For 2019, we do not expect any single proppant supplier to account for more than 20% of our total supply. In addition, we have built a strong relationship with the assembler of our custom-designed hydraulic fracturing fleets and believe we will continue to have timely access to new, high capability fleets as we continue to grow. Our purchases from that assembler accounted for more than 10% of our total capital expenditures for the year ended December 31, 2018 . 
+We purchase a wide variety of raw materials, parts and components that are manufactured and supplied for our operations. We are not dependent on any single source of supply for those parts, supplies or materials. To date, we have generally been able to obtain the equipment, parts and supplies necessary to support our operations on a timely basis. While we believe that we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers, we may not always be able to do so. In addition, certain materials for which we do not currently have long-term supply agreements could experience shortages and significant price increases in the future. As a result, we may be unable to mitigate any future supply shortages and our results of operations, prospects and financial condition could be adversely affected. 
+Competition 
+The markets in which we operate are highly competitive. We provide services in various geographic regions across the United States, and our competitors include many large and small oilfield service providers, including some of the largest integrated service companies. Our hydraulic fracturing services compete with large, integrated companies such as Halliburton Company and Schlumberger Limited as well as other companies including Basic Energy Services, Inc., BJ Services Company, C&J Energy Services, Inc., Calfrac Well Services Ltd., FTS International, Inc., Keane Group, Inc., Patterson-UTI Energy, Inc., ProPetro Services, Inc., RPC, Inc., Superior Energy Services, Inc. and U.S. Well Services, Inc. In addition, our industry is highly fragmented and we compete regionally with a significant number of smaller service providers. 
+We believe that the principal competitive factors in the markets we serve are technical expertise, equipment capacity, work force competency, efficiency, safety record, reputation, experience and price. Additionally, projects are often awarded on a bid basis, which tends to create a highly competitive environment. We seek to differentiate ourselves from our competitors by delivering the highest-quality services and equipment possible, coupled with superior execution and operating efficiency in a safe working environment. 
+Our operations are organized into a single business segment, which consists of hydraulic fracturing services, and we have one reportable geographical business segment, the United States. Operating segments are defined under generally accepted accounting principles in the United States of America ( “ GAAP ” ) as components of an enterprise that engage in activities (i) from which it may earn revenues and incur expenses and (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance. 
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+Environmental and Occupational Safety and Health Matters 
+Our operations in support of oil and natural gas exploration, development and production activities pursued by our customers are subject to stringent federal, tribal, regional, state and local laws and regulations governing occupational safety and health, the discharge of materials into the environment and environmental protection. Numerous governmental entities, including the U.S. Environmental Protection Agency (“EPA”), the U.S. Occupational Safety and Health Administration (“OSHA”), and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions, including the incurrence of potentially significant capital or operating expenditures to mitigate or prevent the releases of materials from our equipment, facilities or from customer locations where we provide our services. These laws and regulations may, among other things (i) require the acquisition of permits or other authorizations for conducting regulated activities, (ii) limit or prohibit our operations on certain lands lying within wilderness, wetlands and other protected areas; (iii) require remedial measures to mitigate pollution from former and ongoing operations; (iv) impose restrictions on the types, quantities and concentrations of various substances that can be released into the environment or injected in formations in connection with oil and natural gas drilling and production activities; (v) impose specific safety and health criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from our operations. Any failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties; the imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures; the occurrence of restrictions, delays or cancellations in the permitting, performance or development of projects or operations; and the issuance of orders enjoining performance of some or all of our operations in a particular area. 
+The trend in environmental regulation is to place more restrictions and limitations on activities that may adversely affect the environment, and thus any new laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased government enforcement with respect to environmental matters that result in more stringent and costly completion activities, pollution control equipment, waste handling, storage transport, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for injuries to persons or damages to properties or natural resources. Our customers may also incur increased costs, or restrictions, delays or cancellations in permitting or operating activities as a result of more stringent environmental laws and regulations, which may result in a curtailment of exploration, development or production activities that would reduce the demand for our services. Historically, our worker health and safety as well as our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our business and operating results. 
+The following is a summary of the more significant existing environmental and occupational safety and health laws, as amended from time to time, to which our business is subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position. 
+Worker Health and Safety 
+We are subject to the requirements of the federal Occupational Safety and Health Act, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and the public. These worker health and safety laws and regulations are subject to amendment including, for example, rulemaking adopted by OSHA in 2016 imposing more stringent permissible exposure limits for worker exposure to respirable crystalline silica, and any failure to comply with these laws could lead to the assertion of third-party claims against us, civil or criminal fines and changes in the way we operate our facilities, any of which could have an adverse effect on our financial position. 
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+Motor Carrier Operations 
+In connection with the services we provide, we operate as a motor carrier and therefore are subject to regulation by the U.S. Department of Transportation (“DOT”) and analogous state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations; regulatory safety; hazardous materials labeling, placarding and marking; financial reporting; and certain mergers, consolidations and acquisitions. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may increase our costs as well as affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations that govern the amount of time a driver may drive in any specific period and requiring onboard electronic logging devices or limits on vehicle weight and size. 
+Interstate motor carrier operations are subject to safety requirements prescribed by DOT. Intrastate motor carrier operations are subject to state safety regulations that often mirror federal regulations but may be more stringent. Such matters as weight and dimension of motor carrier-related equipment are also subject to federal and state regulations. DOT regulations also mandate drug testing of drivers. From time to time, various legislative proposals are introduced, including proposals to increase federal, state or local taxes, such as, for example, taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us would be enacted. 
+Radioactive Materials 
+Certain of our operations utilize equipment that contains sealed, low-grade radioactive sources. Our activities involving the use of radioactive materials are regulated by the U.S. Nuclear Regulatory Commission (“NRC”) and state regulatory agencies under agreement with the NRC. Standards implemented by these regulatory agencies require us to obtain licenses or other approvals for the use of such radioactive materials. Additionally, these regulatory agencies impose certain requirements concerning worker protection with respect to radioactive sources and may otherwise issue regulations regarding the handling and storage of this equipment that may result in increased costs. The violation of these laws and regulations may result in the denial or revocation of licenses or other approvals, issuance of corrective action orders, injunctions prohibiting some or all of our operations in a particular area, and assessment of sanctions, including administrative, civil and criminal penalties. 
+Hazardous Substances and Wastes and Naturally Occurring Radioactive Materials 
+The federal Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, regulate the generation, treatment, storage, transportation, disposal and clean-up of hazardous and non-hazardous wastes. Pursuant to rules issued by the EPA, individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste provisions, state laws or other federal laws. However, it is possible that certain oil and gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. For example, pursuant to a consent decree issued by the U.S. District Court for the District of Columbia in 2016 the EPA is required to propose, no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations that could result in oil and natural gas exploration and production wastes being regulated as hazardous wastes, or sign a determination that revision of the regulations is unnecessary. If the EPA proposes a rulemaking for revised oil and natural gas waste regulations, the consent decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our and the oil and natural gas exploration and production industry’s costs to manage and dispose of generated hazardous wastes, which could have a material adverse effect on our results of operations and financial position. Additionally, other wastes handled at exploration and production sites or generated in the course of providing well services may not fall within this exclusion. In the course of our operations, we generate some amounts of ordinary industrial wastes that may be regulated as hazardous wastes. 
+Moreover, there have been public concerns expressed about naturally occurring radioactive materials (“NORM”) being detected in flow back water resulting from hydraulic fracturing that may contaminate extraction and processing equipment used in the oil and natural gas industry. NORM is subject primarily to individual state radiation control regulations while NORM handling and management activities are governed by regulations promulgated by OSHA. These state and federal regulations impose certain requirements concerning worker protection with respect to NORM as well as the treatment, storage, and disposal of NORM and NORM waste, management of NORM-contaminated waste piles, containers and tanks, and limitations on the relinquishment of NORM contaminated land for unrestricted use under RCRA and state laws. Concern over NORM in 
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+general, or NORM in groundwater in particular, could result in further regulation in the treatment, storage, handling and discharge of flow back water generated from oil and natural gas activities, including hydraulic fracturing, or handling of NORM-impacted equipment that, if implemented, could increase our or our customers’ costs or liabilities associated with elevated levels of NORM as well as limit drilling by our customers, which developments may reduce demand for our services. 
+The federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, and comparable state statutes impose liability, without regard to fault or legality of the original conduct, on classes of persons that are considered to have contributed to the release of a hazardous substance into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, these persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources even if the liability results from conduct that was lawful at the time it occurred or is due to the conduct, or conditions caused by, prior operators or third parties. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We own, lease, or operate numerous properties and facilities that for many years have been used for industrial activities, including oil and natural gas-related operations. Hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations where such substances have been taken for recycling or disposal. In addition, some of these properties have been operated by third parties or by previous owners whose treatment and disposal or release of hazardous substances, wastes, or hydrocarbons, was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes and remediate contaminated property (including groundwater contamination), including instances where the prior owner or operator caused the contamination, or perform remedial plugging of disposal wells or waste pit closure operations to prevent future contamination. 
+Water Discharges and Discharges into Belowground Formations 
+The Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”) and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and hazardous substances, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers (“Corps”). The CWA and analogous state laws also may impose substantial civil and criminal penalties for non-compliance including spills and other non-authorized discharges. 
+In 2015, the EPA and the Corps published a final rule outlining their position on federal jurisdictional reach over waters of the United States, including wetlands, but legal challenges to this rule followed. Beginning in the first quarter of 2017, the EPA and the Corps agreed to reconsider the 2015 rule and, thereafter, the agencies (i) published a proposed rule in 2017 to rescind the 2015 rule and recodify the regulatory text that governed waters of the United States prior to promulgation of the 2015 rule, (ii) published a final rule in February 2018 adding a February 6, 2020 applicable date to the 2015 rule, and (iii) published a proposed rule in December 2018 re-defining the CWA’s jurisdiction over waters of the United States for which the agencies will seek public comment. The 2015 and February 2018 final rules are being challenged by various factions in the federal district court and implementation of the 2018 rule has been enjoined to twenty-eight states pending resolution of various federal district court challenges. As a result of these legal developments, future implementation of the 2015 rule is uncertain at this time. Any expansion of the CWA’s jurisdiction in areas where we or our customers operate, could impose additional permitting obligations on us and our customers. 
+The Oil Pollution Act of 1990 (“OPA”) amends the CWA and sets minimum standards for prevention, containment and cleanup of oil spills. OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties including owners and operators of onshore facilities may be held strictly liable for oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills. The OPA also requires owners or operators of certain onshore facilities to prepare facility response plans for responding to a worst-case discharge of oil into waters of the United States. 
+Our oil and natural gas producing customers dispose of flowback and produced water or certain other oilfield fluids gathered from oil and natural gas producing operations in accordance with permits issued by government authorities overseeing 
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+such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change based on concerns of the public or governmental authorities regarding such disposal activities. One such concern relates to seismic events near underground disposal wells used for the disposal by injection of flowback and produced water or certain other oilfield fluids resulting from oil and natural gas activities. In 2016, the United States Geological Survey identified six states with the most significant hazards from seismicity events suspected of having been induced by injection of oilfield fluids into underground disposal wells, including Oklahoma, Kansas, Texas, Colorado, New Mexico, and Arkansas. In response to concerns between use of underground disposal wells and the occurrence of seismic events, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Texas and Oklahoma have issued rules for produced water disposal wells that impose certain permitting restrictions, operating restrictions and/or reporting requirements on disposal wells in proximity to faults. Additionally, from time to time, states may develop and implement plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations, as has occurred in Oklahoma. For example, in late 2016, the Oil and Gas Conservation Division of the Oklahoma Corporation Commission (“OCC”) and the Oklahoma Geological Survey released well completion seismicity guidance, which requires operators to take certain prescriptive actions, including an operator’s planned mitigation practices, following certain unusual seismic activity within 1.25 miles of hydraulic fracturing operations. In recent years, including during 2018, the OCC’s Oil and Gas Conservation Division has issued orders limiting future increases in the volume of oil and natural gas produced water injected belowground into the Arbuckle formation in an effort to reduce the number of earthquakes in the state. Another consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by our customers to dispose of flowback and produced water and certain other oilfield fluids. Increased regulation and attention given to seismicity events suspected of having been induced by injection of oilfield fluids into underground disposal wells also could lead to greater opposition to, and litigation concerning, oil and natural gas activities utilizing injection wells for waste disposal. Any of these developments may result in our customers having to limit disposal well volumes, disposal rates or locations, or require our customers or third party disposal well operators that are used to dispose of customer produced water to shut down disposal wells, which developments could adversely affect our customers’ business and result in a corresponding decrease in the need for our services, which would could have a material adverse effect on our business, financial condition, and results of operations. 
+Air Emissions 
+Certain of our operations also result in emissions of regulated air pollutants. The federal Clean Air Act (“CAA”) and analogous state laws require permits for certain facilities that have the potential to emit substances into the atmosphere that could adversely affect environmental quality. These laws and their implementing regulations also impose generally applicable limitations on air emissions and require adherence to maintenance, work practice, reporting and record keeping, and other requirements. Failure to obtain a permit or to comply with permit or other regulatory requirements could result in the imposition of sanctions, including administrative, civil and criminal penalties. In addition, we or our customers could be required to shut down or retrofit existing equipment, leading to additional expenses and operational delays. 
+Many of these regulatory requirements, including New Source Performance Standards (“NSPS”) and Maximum Achievable Control Technology (“MACT”) standards, are expected to be made more stringent over time as a result of stricter ambient air quality standards and other air quality protection goals adopted by the EPA. Compliance with these or other new or amended regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact on our business. For example, in 2015, the EPA lowered the National Ambient Air Quality Standard, (“NAAQS”) for ozone from 75 to 70 parts per billion for both the 8-hour primary and secondary standards. In 2017 and 2018, the EPA issued area designations with respect to ground-level ozone as either “attainment/unclassifiable,” “unclassifiable” or “nonattainment.” Additionally, in November 2018, the EPA issued final requirements that apply to state, local, and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Additionally, states are expected to implement more stringent requirements as a result of the revised NAAQS for ozone, which could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. Compliance with this and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase costs for us and our customers. Moreover, our business could be materially affected if our customers’ operations are significantly affected by these or other similar requirements. These requirements could increase the cost of doing business for us and our customers, reduce the demand for the oil and natural gas our customers produce, and thus have an adverse effect on the demand for our services. 
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+Climate Change 
+Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of greenhouse gases (“GHGs”). These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. In the absence of federal GHG-limiting legislations, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted regulations that, among other things, restrict emissions of GHGs under existing provisions of the CAA and may require the installation of “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future if they would otherwise emit large volumes of GHGs together with other criteria pollutants. Also, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from oil and natural gas production, processing, transmission and storage facilities in the United States. In 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting stations as well as completions and workovers from hydraulically fractured oil wells. 
+The EPA has also taken steps to limit methane emissions, a GHG, from certain new modified or reconstructed facilities in the oil and natural gas sector through the adoption of a final rule in 2016 establishing NSPS Subpart OOOOa standards for methane emissions. However, in June 2017, the EPA published a proposed rule to stay certain portions of these Subpart OOOOa standards for two years but the rule was not finalized. Rather, in February 2018, the EPA finalized amendments to certain requirements of the 2016 final rule, and in September 2018 the EPA proposed additional amendments, including rescission of certain requirements and revisions to other requirements, such as fugitive emission monitoring frequency. Further more, in late 2016, the federal Bureau of Land Management (“BLM”) published a final rule that established, among other things, requirements to reduce methane emissions by regulating venting, flaring and leaks from oil and natural gas production activities on onshore federal and Native American lands. However, in September 2018, the BLM published a final rule that rescinds most of the new requirements of the 2016 final rule and codifies the BLM's prior approach to venting and flaring but the rule rescinding the 2016 final rule has been challenged in federal court and remains pending. In the event that the EPA’s 2016 or the BLM’s 2016 rules should remain or be placed in effect, or should any other new methane emission standards be imposed on the oil and natural gas sector, such requirements could result in increased costs to our or our customers’ operations as well as result in restrictions, delays or cancellations in such operations, which costs, restrictions delays or cancellations could adversely affect our business. 
+Internationally, in April 2016, the United States joined other countries in entering into a United Nations-sponsored non-binding agreement negotiated in Paris, France (the “Paris Agreement”) for nations to limit their GHG emissions through individually determined reduction goals every five years beginning in 2020. However, in August 2017, the U.S. State Department informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016. The United States’ adherence to the exit process and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas our customers produce and lower the value of their reserves, which developments could reduce demand for our services and have a corresponding material adverse effect on our results of operations and financial position. 
+Notwithstanding potential risks related to climate change, the International Energy Agency estimates that oil and natural gas will continue to represent a major share of global energy use through 2040, and other studies by the private sector project continued growth in demand for the next two decades. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector. Ultimately this could make it more difficult to secure funding for exploration and production or midstream activities. Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our operations. 
+Endangered Species 
+The federal Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the federal Migratory Bird Treaty Act (“MBTA”). Customer oil and natural gas operations may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife, which may limit their ability to operate in protected areas. Permanent restrictions imposed to protect endangered and threatened species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. Moreover, as a result of one or more settlements entered into by the U.S. Fish and Wildlife Service (“FWS”), that agency is required to consider listing numerous species as endangered or threatened under the Endangered Species Act by 
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+specified timelines. Current ESA listings and the designation of previously unprotected species as threatened or endangered in areas where we or our customers operate could cause us or our customers to incur increased costs arising from species protection or mitigation measures and could result in restrictions, delays or cancellations in our or our customers’ performance of operations, which could adversely affect or reduce demand for our services. 
+Hydraulic Fracturing 
+We perform hydraulic fracturing services for our customers. Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppant and chemical additives under pressure into the formation to fracture the surrounding rock and stimulate production. 
+Hydraulic fracturing typically is regulated by state oil and natural gas commissions or similar agencies, but the EPA has conducted investigations or asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act (“SDWA”) Underground Injection Control (“UIC”) program over certain aspects of the process. For example, in late 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. Additionally, the EPA has asserted regulatory authority under the SDWA UIC program over hydraulic fracturing activities involving the use of diesel fuel and issued permitting guidance covering such activities, as well as published an Advanced Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. The EPA also published final CAA regulations in 2012 and 2016 governing performance standards, including standards for the capture of emissions released during oil and natural gas hydraulic fracturing. Moreover, in 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of produced water from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The BLM published a final rule in 2015 that imposed new or more stringent standards for performing hydraulic fracturing on federal and Native American lands but the BLM rescinded the 2015 rule in later 2017; however, litigation challenging the BLM’s decisions to rescind the 2015 rule is pending in federal district court. 
+Additionally, various state and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, disclosure requirements, well construction and temporary or permanent bans on hydraulic fracturing in certain areas. For example, Texas, Colorado and North Dakota, among others, have adopted regulations that impose new or more stringent permitting, disclosure, disposal, and well construction requirements on hydraulic fracturing operations. States could also elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York. Local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular. Also, non-governmental organizations may seek to restrict hydraulic fracturing, as has been the case in Colorado in recent years, when certain interest groups therein have unsuccessfully pursued ballot initiatives in recent general election cycles that, had they been successful, would have revised the state constitution or state statutes in a manner that would have made exploration and production activities in the state more difficult or costly in the future, for example, by increasing mandatory setback distances of oil and natural gas operations, including hydraulic fracturing, from specific occupied structures and/or certain environmentally sensitive or recreational areas. 
+If new federal, state or local laws, regulations or ballot initiatives that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly to perform hydraulic fracturing. Any such laws, regulations or ballot initiatives limiting or prohibiting hydraulic fracturing could result in decreased oil and natural gas exploration and production activities and, therefore, adversely affect demand for our services and our business. Such laws, regulations or ballot initiatives could also materially increase our costs of compliance and doing business. 
+Available Information 
+We file or furnish annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The SEC also maintains an internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC. 
+Our Class A Common Stock is listed and traded on the New York Stock Exchange (“NYSE”) under the symbol “LBRT.” Our reports, proxy statements and other information filed with the SEC can also be inspected and copied at the offices of the NYSE, at 20 Broad Street, New York, New York 10005. 
+We also make available free of charge through our website, www.libertyfrac.com, electronic copies of certain documents that we file with the SEC, including our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on 
+14 
+Table of Contents 
+Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. 
+15 
+Table of Contents
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+Item 13. Certain Relationships and Related Transactions, and Director Independence 
+The information required by this item concerning certain relationships and related person transactions and director independence is incorporated herein by reference to our definitive proxy statement for our 2019 annual meeting of shareholders, which will be filed with the SEC no later than 120 days after December 31, 2018.
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+Item 9A. Controls and Procedures 
+Evaluation of Disclosure Controls and Procedures 
+As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer, principal financial officer and principal accounting officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report on Form 10-K. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Security and Exchange Commission (the “SEC”) rules and forms and that such information is accumulated and communicated to management, including our principal executive officer, principal financial officer and principal accounting officer, to allow timely decisions regarding required disclosure. Based upon that evaluation, our principal executive officer, principal financial officer and principal accounting officer concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of December 31, 2018. 
+Management ’ s Annual Report on Internal Control Over Financial Reporting 
+During the year ended December 31, 2017, we were an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”) and were not required to comply with certain requirements that were applicable to other public companies that are not “emerging growth companies.” 
+Effective as of January 17, 2018, we no longer qualify as an “emerging growth company” as defined in the JOBS Act. However, in accordance with Section 13(a) and 15(d) of the Exchange Act, a company is required to have been subject to the SEC’s requirements for a period of at least 12 calendar months in order to be designated as a large accelerated filer or an accelerated filer. We completed our IPO on January 17, 2018, and therefore do not meet the requirements to be designated as a large accelerated filer or an accelerated filer as of December 31, 2018. Section 404(c) of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”) provides that Section 404(b) of the Sarbanes-Oxley Act shall not apply with respect to any audit report prepared for an issuer that is neither an accelerated filer nor a large accelerated filer as defined in Rule 12b-2 under the Exchange Act. Accordingly, our independent registered public accounting firm is not yet required to formally attest to the effectiveness of our internal control over financial reporting for the year ended December 31, 2018. 
+Our management, including our principal executive officer and principal financial officer, is responsible for establishing and maintaining adequate internal control over financial reporting for us as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. This system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. 
+Our internal control over financial reporting includes those policies and procedures that: 
+i. 
+pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of the assets; 
+ii. 
+provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and 
+iii. 
+provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements. Further, because of changes in conditions, effectiveness of internal controls over financial reporting may vary over time. 
+Under the supervision of, and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based 
+56 
+Table of Contents 
+on the framework and criteria established in Internal Control-Integrated Framework (2013) , issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2018 . 
+Changes in Internal Control Over Financial Reporting 
+During the quarter ended December 31, 2018 , we developed and implemented new controls and took additional actions to address a previously identified material weakness in our internal control over financial reporting as of December 31, 2017 related to segregation of duties, including internal controls over journal entries. The new internal controls and additional actions included, among other things, hiring additional personnel, engaging a third party to assist in the documentation, implementation and testing of internal controls, and developing and implementing improved policies, processes and procedures to ensure proper segregation of duties are followed. After completion of the testing of the design and operating effectiveness of these new internal controls, we concluded that we had remediated the previously identified material weakness as of December 31, 2018. Other than the internal controls implemented to address the previously identified material weakness, there were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended December 31, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+Attestation Report of the Registered Public Accounting Firm 
+Management’s report was not subject to attestation by our independent registered public accounting firm, pursuant to Rule 12b-2 of the Exchange Act, that permits us to provide only management’s report in this Annual Report on Form 10-K. Therefore, this Annual Report on Form 10-K does not include such an attestation.
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diff --git a/raw/filings/0001694028/2018/0001694028-19-000015/rpt_disclosure.txt b/raw/filings/0001694028/2018/0001694028-19-000015/rpt_disclosure.txt
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+CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS 
+Policies and Procedures for Review of Related Party Transactions 
+A “Related Party Transaction” is a transaction, arrangement or relationship in which the Company or any of its subsidiaries was, is or will be a participant, the amount of which involved exceeds $120,000, and in which any related person had, has or will have a direct or indirect material interest. A “Related Person” is: 
+♦ any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors; 
+♦ any person who is known by us to be the beneficial owner of more than 5% of our Class A Common Stock; 
+♦ any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, executive officer or a beneficial owner of more than 5% of our Class A Common Stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5% of our Class A Common Stock; and 
+♦ any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10.0% or greater beneficial ownership interest. 
+Our Board adopted a written related party transactions policy in connection with the IPO. Pursuant to this policy, our Audit Committee reviews all material facts of all Related Party Transactions and either approves or disapproves entry into the Related Party Transaction, subject to certain limited exceptions. The determination of the Audit Committee is documented in the Audit Committee’s minutes. In determining whether to approve or disapprove entry into a Related Party Transaction, our Audit Committee takes into account, among other factors, the following: (i) whether the Related Party Transaction is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances and (ii) the extent of the Related Person’s interest in the transaction. Furthermore, the policy requires that all Related Party Transactions required to be disclosed in our filings with the SEC be so disclosed in accordance with applicable laws, rules and regulations. 
+The following discussion is a brief summary of our corporate reorganization and certain material arrangements, agreements and transactions we have with related parties. It does not include all of the provisions of our material arrangements, agreements and transactions with related parties, does not purport to be complete and is qualified in its entirety by reference to the arrangements, agreements and transactions described. 
+Corporate Reorganization 
+On January 17, 2018, we completed our IPO of 14,640,755 shares of our Class A Common Stock at a public offering price of $17.00 per share, of which 14,340,214 shares were offered by us and 300,541 shares were offered by the selling shareholder. We used our net proceeds from the IPO to redeem ownership in us from certain Legacy Owners (as defined below) and contributed the remaining proceeds to Liberty Oilfield Services New HoldCo LLC (“ Liberty LLC ”) in exchange for units in Liberty LLC (the “ Liberty LLC Units ”). In connection with the IPO, we completed a corporate reorganization which included the following restructuring steps: 
+• Liberty Holdings contributed all of its assets to Liberty LLC in exchange for Liberty LLC Units; 
+• Liberty Holdings liquidated and distributed to its then-existing owners (the “ Legacy Owners ”) Liberty LLC Units pursuant to the terms of the limited liability company agreement of Liberty Holdings and the Master Reorganization Agreement dated as of January 11, 2018, by and among the Company, Liberty Holdings, Liberty LLC, and the other parties nam ed therein; 
+• Certain of the Legacy Owners directly or indirectly contributed all or a portion of their Liberty LLC Units to the Company in exchange for 55,685,027 shares of our Class A Common Stock, and 1,258,514 shares of restricted stock. Subsequent to the initial exchange, 1,609,122 shares of Class A Common Stock were redeemed for an aggregate purchase price of $25.9 million upon the exercise of the underwriters’ overallotment option; 
+• We issued the Legacy Owners that continued to own Liberty LLC Units (the “ Liberty Unit Holders ”) an aggregate amount of 48,207,372 shares of our Class B Common Stock; and 
+• We then contributed the net proceeds it received from the IPO to Liberty LLC in exchange for additional Liberty LLC Units such that the Company holds a total number of Liberty LLC Units equal to the number of shares of Class A Common Stock outstanding following the IPO. 
+36 
+Related Party Transactions 
+The following is a description of transactions entered into, or in effect, after January 1, 2019 to which we have been a party, in which the amount involved in the transaction exceeds $120,000, and in which any of our directors, executive officers or beneficial owners of more than 5% of our voting securities, or affiliates or immediate family members of any of our directors, executive officers or beneficial owners of more than 5% of our voting securities, had or will have a direct or indirect material interest. We believe the terms obtained or consideration that we paid or received, as applicable, in connection with the transactions described below were comparable to terms available or the amounts that would be paid or received, as applicable, from unrelated third parties. 
+Liberty LLC Agreement 
+We entered into the Second Amended and Restated Limited Liability Company Agreement of Liberty LLC (the “ Liberty LLC Agreement ”) in connection with the closing of our IPO, which provides for limitations on the ability of Liberty Unit Holders to transfer their Liberty LLC Units and provides the Company, as managing member of Liberty LLC, with the right to impose restrictions (in addition to those already in place) on the ability of Liberty Unit Holders to redeem their Liberty LLC Units pursuant to the Redemption Right (as defined below) to the extent the Company believes it is necessary to ensure that Liberty LLC will continue to be treated as a partnership for U.S. federal income tax purposes. 
+Redemption Rights 
+Under the Liberty LLC Agreement, each Liberty Unit Holder has, subject to certain limitations, the right (the “ Redemption Right ”) to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units for, at Liberty LLC’s election, (i) shares of our Class A Common Stock at a redemption ratio of one share of Class A Common Stock for each Liberty LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions or (ii) an equivalent amount of cash. Alternatively, upon the exercise of the Redemption Right, the Company (instead of Liberty LLC) h as the right (the “ Call Right ”) to, for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder for, at the Company’s election, (x) one share of Class A Common Stock or (y) an equivalent amount of cash. In addition, upon a change of control of the Company, the Company has the right to require each holder of Liberty LLC Units (other than the Company) to exercise its Redemption Right with respect to some or all of such unit holder’s Liberty LLC Units. In connection with any redemption of Liberty LLC Units pursuant to the Redemption Right or the Call Right, the corresponding number of shares of Class B Common Stock will be cancelled. As the Liberty Unit Holders redeem their Liberty LLC Units, our membership interest in Liberty LLC will be correspondingly increased, the number of shares of Class A Common Stock outstanding will be increased, and the number of shares of Class B Common Stock outstanding will be reduced. 
+Distributions and Allocations 
+Under the Liberty LLC Agreement, the Company has the right to determine when distributions will be made to the holders of Liberty LLC Units and the amount of any such distributions. If the Company authorizes a distribution, such distribution will be made to the holders of Liberty LLC Units generally on a pro rata basis in accordance with their respective percentage ownership of Liberty LLC Units. 
+Liberty LLC will allocate its net income or net loss for each year to the holders of Liberty LLC Units pursuant to the terms of the Liberty LLC Agreement, and the holders of Liberty LLC Units, including the Company, will generally incur U.S. federal, state and local income taxes on their share of any taxable income of Liberty LLC. Net income and losses of Liberty LLC generally will be allocated to the holders of Liberty LLC Units on a pro rata basis in accordance with their respective percentage ownership of Liberty LLC Units, subject to requirements under U.S. federal income tax law that certain items of income, gain, loss or deduction be allocated disproportionately in certain circumstances. To the extent Liberty LLC has available cash and subject to the terms of any debt instruments, the Company intends to cause Liberty LLC to make (i) generally pro rata distributions to the holders of Liberty LLC Units, including the Company, in an amount sufficient to allow the Company to pay its taxes and to allow it to make payments under the Tax Receivable Agreements (as defined below), (ii) tax advances, which will be repaid upon exercise of the Redemption Right or the Call Right, as applicable, in an amount sufficient to allow each of the Liberty Unit Holders to pay its respective taxes on such holder’s allocable share of Liberty LLC’s taxable income after taking into account certain other distributions or payments received by the Liberty Unit Holders from Liberty LLC or the Company, and (iii) non-pro rata payments to the Company to reimburse it for its corporate and other overhead expenses. 
+Issuance of Equity 
+The Liberty LLC Agreement generally provides that at any time the Company issues a share of its Class A Common Stock or any other equity security, the net proceeds received by the Company with respect to such issuance, if any, shall be concurrently invested in Liberty LLC, and Liberty LLC shall issue to the Company one Liberty LLC Unit or other economically equivalent equity interest. Conversely, if at any time, any shares of Class A Common Stock are redeemed, repurchased or otherwise acquired, Liberty LLC shall redeem, repurchase or otherwise acquire an equal number of Liberty LLC Units held by the Company, upon the same terms and for the same price, as the shares of the Class A Common Stock are redeemed, repurchased or otherwise acquired. 
+37 
+Competition 
+Under the Liberty LLC Agreement, the members have agreed that Riverstone and its affiliates will be permitted to engage in business activities or invest in or acquire businesses which may compete with our business or do business with our customers. 
+Dissolution 
+Liberty LLC will be dissolved only upon the first to occur of (i) the sale of substantially all of its assets or (ii) an election by us to dissolve the company. Upon dissolution, Liberty LLC will be liquidated and the proceeds from any liquidation will be applied and distributed in the following manner: (i) first, to creditors (including to the extent permitted by law, creditors who are members) in satisfaction of the liabilities of Liberty LLC; (ii) second, to establish cash reserves for contingent or unforeseen liabilities; and (iii) third, to the members in proportion to the number of Liberty LLC Units owned by each of them. 
+Tax Receivable Agreements 
+In connection with the IPO, on January 17, 2018, the Company entered into two tax receivable agreements, (the “ TRAs ”) with the Liberty Unit Holders and the selling shareholder (each such person and any permitted transferee, a “ TRA Holder ” and together, the “ TR A Hold ers ”). The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that the Company actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result, as applicable to each TRA Holder, of (i) certain increases in tax basis that occur as a result of the Company’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holder’s Liberty LLC Units in connection with the IPO or pursuant to the exercise of the Redemption Right or the Call Right, (ii) any net operating losses available to the Company as a result of the corporate reorganization, and (iii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRAs. 
+Stockholders’ Agreements 
+We are party to a stockholders’ agreement with Riverstone and certain Legacy Owners (collectively, the “ Principal Stockholders ”). Among other things, the stockholders’ agreement provides the right to designate nominees to our Board as follows: 
+• so long as Riverstone and its affiliates collectively own at least 35% of our Class A Common Stock, Riverstone can designate up to five (5) nominees to the Board, with the Board size decreasing by one (1) director when Riverstone and its affiliates no longer own at least 35% of our Class A Common Stock; 
+• so long as Riverstone and its affiliates collectively own at least 30% of our Class A Common Stock, Riverstone can designate up to four (4) nominees to our Board; 
+• so long as Riverstone and its affiliates collectively own at least 20% of our Class A Common Stock but less than 30% of our Class A Common Stock, Riverstone can designate up to two (2) nominees to our Board; and 
+• so long as Riverstone and its affiliates collectively own at least 10% of our Class A Common Stock but less than 20% of our Class A common stock, Riverstone can designate up to one (1) nominee to our Board. 
+In connection with the appointment of Ms. Norton and the expansion of the Board in July 2019, the Company, R/C Energy IV Direct Partnership, L.P. and R/C IV Liberty Holdings, L.P. entered into an additional stockholders agreement (the “ Additional Agreement ”). Pursuant to the Additional Agreement, the Company agreed to use reasonable best efforts to cause the Board to, in the case where Riverstone and its affiliates beneficially own at least 10% of the outstanding shares of our Class A Common Stock, and the Board is comprised of five (5) or more directors that are not Riverstone nominees, elect one (1) additional nominee designated by Riverstone to serve on the Board. The Additional Agreement does not limit or replace the rights of Riverstone under the stockholders agreement entered into in con nection with the IPO. 
+Pursuant to the stockholders’ agreement we and the Principal Stockholders will be required to take all necessary actions, to the fullest extent permitted by applicable law (including with respect to any fiduciary duties under Delaware law), to cause the election of the nominees designated by Riverstone. At any time the members of our Board are allocated among separate classes of directors, (i) the directors designated by Riverstone pursuant to the stockholders’ agreement will be in different classes of directors to the extent practicable and (ii) Riverstone will be permitted to designate the class or classes to which each such director will be allocated. Riverstone will be entitled to designate the replacement for any of its Board designees whose service terminates prior to the end of such director’s term. 
+38 
+In addition, the stockholders’ agreement provides that for so long as the Principal Stockholders and their affiliates own at least 20% of the outstanding shares of our Class A Common Stock, Riverstone will have the right to cause any committee of our Board to include in its membership at least one (1) director designated by Riverstone, except to the extent that such membership would violate applicable securities laws or stock exchange rules. The rights granted to Riverstone to designate directors are additive to and not intended to limit in any way the rights that Riverstone or any of its affiliates may have to nominate, elect or remove our directors under our certificate of incorporation, bylaws or the Delaware General Corporation Law. 
+Furthermore, so long as Riverstone and its affiliates collectively own at least 20% of the outstanding shares of Class A Common Stock, we have agreed not to take, and will take all necessary action to cause our subsidiaries not to take, the following direct or indirect actions (or enter into an agreement to take such actions) without the prior consent of Riverstone: 
+• any material change, through any acquisition, disposition of assets or otherwise, in the nature of our business or operations and our subsidiaries as of the date of the stockholders’ agreement; 
+• hiring or terminating our Chief Executive Officer or the Chief Financial Officer and their respective successors; 
+• any transaction that, if consummated, would constitute a Change of Control (as defined in the stockholders’ agreement) or entering into any definitive agreement or series of related agreements that govern any transaction or series of related transactions that, if consummated, would result in a Change of Control; 
+• entering into any agreement providing for certain acquisitions or dispositions, in each such case, involving consideration payable or receivable by us or any of our subsidiaries in excess of $100 million in the aggregate in any single transaction or series of related transactions during any 12-month period; 
+• any incurrence by us or any of our subsidiaries of indebtedness for borrowed money (including through capital leases, the issuance of debt securities or the guarantee of indebtedness of another person) in excess of $100 million in the aggregate in any single transaction or series of related transactions during any 12-month period; 
+• any issuance or series of related issuances of equity securities by us or any of our subsidiaries for an aggregate consideration in excess of $100 million; 
+• any payment or declaration of any dividend or other distribution of any shares of Class A Common Stock or entering into any recapitalization transaction the primary purpose of which is to pay a dividend; 
+• any increase or decrease in the size of our Board, committees of the Board, and board and committees of our subsidiaries; 
+• settling any litigation to which we or any of our subsidiaries is a party involving the payment by us or any of our subsidiaries of an aggregate amount equal to or greater than $25 million; 
+• entering into any joint venture or similar business alliance involving investment, contribution or disposition by us or any of our subsidiaries of assets (including stock of subsidiaries) having an aggregate fair market value in excess of $100 million, other than transactions solely between and among us and our wholly owned subsidiaries; and 
+• any amendment, modification or waiver of our certificate of incorporation, bylaws or any other governing document following the date of the stockholders’ agreement that (i) causes the number of Board seats to be less than or greater than nine (9) or (ii) materially and adversely affects any Principal Stockholder. 
+Registration Rights Agreement 
+In connection with the closing of the IPO, we entered into a registration rights agreement with the Legacy Owners. The agreement contains provisions by which we agree to register under the federal securities laws the offer and resale of shares of our Class A Common Stock by the Legacy Owners or certain of their affiliates or permitted transferees under the registration rights agreement. These registration rights will be subject to certain conditions and limitations. We will generally be obligated to pay all registration expenses in connection with these registration obligations, regardless of whether a registration statement is filed or becomes effective. 
+Indemnification for Officers and Directors 
+Our certificate of incorporation and bylaws provide indemnification rights to our directors and officers and permit us to purchase insurance on behalf of any officer, director, employee or other agent for any liability arising out of that person’s actions as our officer, director, employee or agent, regardless of whether Delaware law would mandate indemnification. Additionally, we have entered into separate indemnity agreements with our directors and officers to provide additional indemnification benefits, including the right to receive, in advance, reimbursements for expenses incurred in connection with a defense for which the director or officer is entitled to indemnification. We believe that the limitation of liability provisions in our certificate of incorporation, bylaws and the indemnity agreements will facilitate our ability to continue to attract and retain qualified individuals to serve as directors and officers. 
+39 
+Underwriting Agreement 
+On July 8, 2019, we entered into an underwriting agreement (the “ Underwriting Agreement ”) with R/C Energy IV Direct Partnership, L.P. and R/C IV Liberty Holdings, L.P. (together, the “ Selling Stockholders ”) and Barclays Capital Inc. (the “ Underwriter ”), pursuant to which the Selling Stockholders agreed to sell to the Underwriter, and the Underwriter agreed to purchase from the Selling Stockholders, subject to and upon the terms and conditions set forth therein, an aggregate of 8,000,000 shares of our Class A Common Stock (the “ Offering ”). The Offering closed on July 11, 2019. We did not receive any proceeds from the sale of shares of Class A Common Stock in the Offering. The Underwriting Agreement contains customary representations, warranties and agreements of the Company and the Selling Stockholders and other customary obligations of the parties and termination provisions. 
+Share Repurchases 
+On September 10, 2018, the Board authorized a share repurchase plan to repurchase up to $100 million of the Company’s Class A Common Stock through September 30, 2019. On January 22, 2019, the Board authorized an additional $100.0 million under the share repurchase plan through January 31, 2021. The Company repurchased 117,647 shares and 2,491,160 shares of Class A Common Stock from Riverstone sellers, at a weighted average purchase price of $17.00 per share and $18.96 per share, pursuant to a share repurchase program for the years ended December 31, 2019 and 2018, respectively. 
+Transactions with Liberty Resources 
+Liberty Resources LLC (“ Liberty Resources ”), an oil and gas exploration and production company, entered into a master service agreement with L iberty Oilfield Services LLC (“ Liberty Services ”), whereby Liberty Services provides hydraulic fracturing service to Liberty Resources at market service rates. The amounts related to the provision of hydraulic fracturing services to Liberty Resources under the master services agreement for the years ended December 31, 2019, 2018 and 2017 were approximately $18.3 million, $23.1 million and $24.7 million, respectively. As of December 31, 2019 and 2018, $7.1 million and $15.1 million, respectively, of the Company’s accounts receivable, and $0.0 million and $0.0 million, respectively, of the Company’s unbilled revenue was with Liberty Resources. On June 24, 2019 (the “Agreement Date”), the Company entered into an agreement with Liberty Resources to amend payment terms for outstanding invoices due as of the Agreement Date to be due on July 31, 2020. On September 30, 2019, the agreement was amended to extend the due date of the remaining amounts outstanding to October 31, 2020. Amounts outstanding from Liberty Resources as of the Agreement Date were $15.6 million. As of December 31, 2019, amounts outstanding under the amended payment terms from Liberty Resources were $2.5 million. The balance outstanding is subject to interest at 13% annual percent yield, retroactively applied to the respective invoice date. During the year ended December 31, 2019, interest income from Liberty Resources was $1.8 million, and accrued interest as of December 31, 2019 was $0.0 million. Receivables earned for services performed after the Agreement Date continue to be subject to normal 30-day payment terms, provided that any amount unpaid after 60 days will be subject to 13% interest. 
+Transactions with PropX 
+Liberty Oilfield Services LLC (“ LOS ”), a subsidiary of the Company, currently leases equipment from Proppant Express Solutions, LLC (“ PropX ”), a provider of proppant logistics equipment. R/C IV Liberty Big Box Holdings, L.P., a Riverstone fund, holds a majority interest in PropX. Accordingly, funds associated with Riverstone hold over a 10% interest in both the Company and PropX. For the year ended December 31, 2019, LOS paid PropX $9.8 million for the lease of proppant logistics equipment. 
+Advisory Agreement 
+Liberty Holdings entered into an advisory agreement, dated December 30, 2011, with Riverstone/Carlyle Energy Partners IV, L.P. (“ R/C ”), in which R/C agreed to provide certain administrative advisory services to Liberty Holdings. The advisory services agreement was terminated pursuant to an agreement effective as of January 11, 2018. On January 11, 2018, Liberty Holdings, R/C and other parties entered into a Master Reorganization Agreement that, among other things, crystallized the “waterfall” provisions of Article VI of the Third Amended and Restated Limited Liability Agreement of Liberty Holdings, dated October 11, 2016 (the “ Holdings LLC Agreement ”), in connection with the IPO. As part of this crystallization, R/C and affiliated entities (collectively, the “ R/C Affiliates ”) received shares of Class A Common Stock, including 117,647 shares of Class A Common Stock (such 117,647 referred to as the “ Issued Shares ”) to compensate R/C Affiliates for certain accrued preferred returns but which would not have been issued had the $2.0 million in fees owing under the advisory agreement been paid in cash. Had this fee been paid in cash on or prior to January 11, 2018, R/C and Liberty Holdings acknowledge that R/C Affiliates would not have received the Issued Shares in the crystallization pursuant to the provisions of the Holdings LLC Agreement. Subsequently, during the fourth quarter of 2018, R/C asserted that certain provisions of the termination of services agreement provided for R/C to receive $2.0 million in cash as payment of those accrued fees. To resolve this matter, the Company agreed to pay R/C Affiliates $2.0 million in cash in exchange for the return, at the IPO price, of the Issued Shares and $0.3 million for interest and the settlement of the matter. Accordingly, $2.3 million was recorded as accrued liabilities - related party in the accompanying consolidated balance sheet as of December 31, 2018 and subsequently paid in January 2019. The returned shares of Class A Common Stock were canceled and retired, and the Company does not expect to incur future expense related to the advisory agreement or termination thereof. 
+40 
+Conflicts of Interest 
+The related party transactions described herein may cause certain conflicts of interests, including that: 
+♦ we may enter into contracts between us, on the one hand, and related parties, on the other, that are not as a result of arm’s-length transactions; 
+♦ our executive officers and directors that hold positions of responsibility with related parties may be aware of certain business opportunities that are appropriate for presentation to us as well as to such other related parties and may present such business opportunities to such other parties; and 
+♦ our executive officers and directors that hold positions of responsibility with related parties may have significant duties with, and spend significant time serving, other entities and may have conflicts of interest in allocating time. 
+For example, Mr. Wright, our Chief Executive Officer, is the Executive Chairman of Liberty Resources, a position which may require a portion of his time and which may cause conflicts of interest in pursuing business opportunities of which he becomes aware. Furthermore, our governing documents provide that Riverstone and its respective affiliates (including portfolio investments of its affiliates) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. Riverstone or its respective affiliates may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Furthermore, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to not be available to us or causing them to be more expensive for us to pursue. In addition, Riverstone or its respective affiliates may dispose of oil and gas service or other assets in the future, without any obligation to offer us the opportunity to purchase any of those assets. 
+41
\ No newline at end of file
diff --git a/raw/filings/0001694028/2019/0001694028-20-000019/filing.txt b/raw/filings/0001694028/2019/0001694028-20-000019/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..2606940011d43b1e2fca9be3741291354ef67564
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+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+WASHINGTON, D.C. 20549 
+FORM 10-K 
+(Mark One) 
+☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the Fiscal Year Ended December 31, 2019 
+OR 
+☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+Commission File No. 001-38081 
+Liberty Oilfield Services Inc. 
+(Exact Name of Registrant as Specified in its Charter) 
+Delaware 
+81-4891595 
+(State or Other Jurisdiction of Incorporation or Organization) (I.R.S. Employer Identification No.) 
+950 17th Street , Suite 2400 
+Denver , Colorado 
+80202 
+(Address of Principal Executive Offices) (Zip Code) 
+( 303 ) 515-2800 
+(Registrant’s Telephone Number, Including Area Code) 
+Securities registered pursuant to section 12(b) of the Act: 
+Title of each class Trading symbol(s) Name of each exchange on which registered 
+Class A Common Stock, par value $0.01 LBRT New York Stock Exchange 
+Securities registered pursuant to Section 12(g) of the Act: None 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☒ Yes ☐ No 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐ Yes ☒ No 
+Indicate by check mark whether the registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No 
+Indicate by check mark whether the registrant has submitted electronically, every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this Chapter) during the presiding 12 months (or for such shorter period that the registrant was required to submit and post such files). ☒ Yes ☐ No 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. 
+Large accelerated Filer ☒ 
+Accelerated filer ☐ Non-accelerated filer ☐ 
+Smaller reporting company ☐ 
+Emerging growth company ☐ 
+If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act): ☐ Yes ☒ No 
+As of June 28, 2019, the last business day of the registrant ’ s most recently completed second fiscal quarter, the aggregate market value of voting and non-voting common stock held by non-affiliates of the registrant was approximately $ 732.8 million, determined using the per share closing price on the New York Stock Exchange on that date of $16.18. Shares of common stock held by each director and executive officer (and their respective affiliates) and each person who owns 10 percent or more of the outstanding common stock or who is otherwise believed by the registrant to be in a control position have been excluded. This determination of affiliate status is not necessarily a conclusive determination for other purposes. 
+At February 21, 2020, the Registrant had 81,920,347 shares of Class A Common Stock and 30,638,960 shares of Class B Common Stock outstanding. 
+Documents Incorporated by Reference: Part III of this Annual Report on Form 10-K incorporates certain information by reference from the registrant ’ s proxy statement for the 2020 annual meeting of stockholders to be filed no later than 120 days after the end of the registrant ’ s fiscal year. 
+Table of Contents 
+TABLE OF CONTENTS 
+Page No. 
+PART I 
+Item 1. 
+Business 
+1 
+Item 1A. 
+Risk Factors 
+15 
+Item 1B. 
+Unresolved Staff Comments 
+38 
+Item 2. 
+Properties 
+38 
+Item 3. 
+Legal Proceeding s 
+38 
+Item 4. 
+Mine Safety Disclosures 
+38 
+PART II 
+Item 5. 
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+39 
+Item 6. 
+Selected Consolidated Financial Data 
+41 
+Item 7. 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+44 
+Item 7A. 
+Quantitative and Qualitative Disclosure about Market Risk 
+54 
+Item 8. 
+Financial Statements and Supplementary Data 
+55 
+Item 9. 
+Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+55 
+Item 9A. 
+Controls and Procedures 
+55 
+Item 9B. 
+Other Information 
+55 
+PART III 
+Item 10. 
+Directors, Executive Officers and Corporate Governance 
+56 
+Item 11. 
+Executive Compensation 
+56 
+Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+56 
+Item 13. 
+Certain Relationships and Related Transactions, and Director Independence 
+56 
+Item 14. 
+Principal Accountant Fees and Services 
+56 
+PART IV 
+Item 15. 
+Exhibits and Financial Statement Schedules 
+57 
+Item 16. 
+Form 10-K Summary 
+58 
+SIGNATURES 
+62 
+i 
+Table of Contents 
+CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS 
+This Annual Report on Form 10-K and certain other communications made by us contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange of 1934, as amended (the “Exchange Act”), including statements about our growth, future operating results, estimates, beliefs and expected performance. For this purpose, any statement that is not a statement of historical fact should be considered a forward-looking statement. We may use the words “believe,” “anticipate,” “plan,” “expect,” “intend,” “may,” “will,” “should” and similar expressions to help identify forward-looking statements. We cannot assure you that our assumptions and expectations will prove to be correct. Important factors could cause our actual results to differ materially from those indicated or implied by forward-looking statements. We undertake no intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise and readers should not rely on the forward-looking statements as representing the Company’s views as of any date subsequent to the date of the filing of this Annual Report on Form 10-K. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. 
+Forward-looking statements may include statements about: 
+• our business strategy; 
+• our operating cash flows, the availability of capital and our liquidity; 
+• our future revenue, income and operating performance; 
+• our ability to sustain and improve our utilization, revenue and margins; 
+• our ability to maintain acceptable pricing for our services; 
+• our future capital expenditures; 
+• our ability to finance equipment, working capital and capital expenditures; 
+• competition and government regulations; 
+• our ability to obtain permits and governmental approvals; 
+• pending legal or environmental matters; 
+• oil and natural gas prices; 
+• acquisitions; 
+• general economic conditions; 
+• credit markets; 
+• demand for services in our industry; 
+• our ability to successfully develop our research and technology capabilities and implement technological developments and enhancements; 
+• uncertainty regarding our future operating results; 
+• return of capital to shareholders; and 
+• plans, objectives, expectations and intentions contained in this Annual Report on Form 10-K that are not historical. 
+We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, decline in demand for our services, the cyclical nature and volatility of the oil and natural gas industry, a decline in, or substantial volatility of, oil and natural gas commodity prices, environmental risks, regulatory changes, the inability to comply with the financial and other covenants and metrics in our Credit Facilities (as defined herein), cash flow and access to capital, the timing of development expenditures and the other risks described under “Risk Factors” in this Annual Report on Form 10-K. 
+All forward-looking statements, expressed or implied, included in this Annual Report on Form 10-K are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. 
+This Annual Report on Form 10-K includes market and industry data and certain other statistical information based on third-party sources including independent industry publications, government publications and other publish independent 
+ii 
+Table of Contents 
+sources, such as content and estimates provided by Coras Research, LLC as of December 31, 2019. Coras Research, LLC is not a member of the Financial Industry Regulator Authority (FINRA) or the Securities Investor Protection Corporation (SIPC) and is not a registered broker dealer or investment advisor. Although we believe these third-party sources are reliable as of their respective dates, we have not independently verified the accuracy or completeness of this information. Some data is also based on our own good faith estimates, which are supported by our management's knowledge of and experience in the markets and business in which we operate. 
+iii 
+Table of Contents 
+PART I 
+As used in this Annual Report on Form 10-K, unless the context otherwise requires, references to the term “Liberty Inc.” refers to Liberty Oilfield Services Inc. and references to the terms “Company,” “we,” “us” and “our” refer to, collectively, Liberty Oilfield Services LLC and LOS Acquisition Co I LLC and its subsidiaries (collectively, the “Predecessor”) for periods prior to the IPO (as defined herein), and, for periods as of and following the IPO, Liberty Inc. and its consolidated subsidiaries. References to “Liberty LLC” refer to Liberty Oilfield Services New HoldCo LLC. References to “Liberty Holdings” refer to Liberty Oilfield Services Holdings LLC. 
+Item 1. Business 
+Our Company 
+We are an independent provider of hydraulic fracturing services and goods to onshore oil and natural gas exploration and production (“E&P”) companies in North America. We provide our services primarily in the Permian Basin, the Eagle Ford Shale, the Denver-Julesburg Basin (the “DJ Basin”), the Williston Basin, the San Juan Basin and the Powder River Basin. 
+We have grown organically from one active hydraulic fracturing fleet in December 2011 to 24 active fleets in February 2020. 
+Our founders and existing management were pioneers in the development of data-driven hydraulic fracturing technologies for application in shale plays. Prior to founding Liberty Holdings, the majority of our management team founded and built Pinnacle Technologies, Inc. (“Pinnacle Technologies”) into a leading fracturing technology company. In 1992, Pinnacle Technologies developed the first commercial hydraulic fracture mapping technologies, analytical tools that played a major role in launching the shale revolution. Our extensive experience with fracture technologies and customized fracture design has enabled us to develop new technologies and processes that provide our customers with real time solutions that significantly enhance their completions. These technologies include hydraulic fracture propagation models, reservoir engineering tools, large, proprietary shale production databases and multi-variable statistical analysis techniques. Taken together, these technologies have enabled us to be a leader in hydraulic fracture design innovation and application. 
+We believe the following characteristics distinguish us from our competitors and are the foundations of our business: forming ongoing partnerships of trust and innovation with our customers; developing and utilizing technology to maximize well performance; and promoting a people-centered culture focused on our employees, customers and suppliers. We have developed strong relationships with our customers by investing significant time in fracture design collaboration, which substantially enhances their production economics. Our technological innovations have become even more critical as E&P companies have increased the completion complexity and fracture intensity of horizontal wells. We are proactive in developing innovative solutions to industry challenges, including developing: (i) our proprietary databases of U.S. unconventional wells to which we apply our proprietary multi-variable statistical analysis technologies to provide differential insight into fracture design optimization; (ii) our Liberty Quiet Fleet® design which significantly reduces noise levels compared to conventional hydraulic fracturing fleets; and (iii) hydraulic fracturing fluid systems tailored to the specific reservoir properties in the basins in which we operate. We foster a people-centered culture built around honoring our commitments to customers, partnering with our suppliers and hiring, training and retaining people that we believe to be the best talent in our field, enabling us to be one of the safest and most efficient hydraulic fracturing companies in the United States. 
+Recent Developments 
+In January 2020, we put our 24 th fleet into production for a long-term existing customer. This fleet will utilize our Liberty Quiet Fleet® technology and have dual fuel capability. We expect our 25 th fleet to be deployed later in 2020. 
+Initial Public Offering and Corporate Reorganization Transaction 
+Liberty Inc. was incorporated as a Delaware corporation on December 21, 2016, to become a holding corporation for Liberty LLC and its subsidiaries upon completion of a corporate reorganization (as detailed below, the “Corporate Reorganization”) and planned initial public offering of the Company (“IPO”). Liberty Inc. has no material assets other than its ownership in Liberty LLC. 
+On January 17, 2018, we completed our IPO of 14,640,755 shares of our Class A common stock, par value $0.01 per share (the “Class A Common Stock”) at a public offering price of $17.00 per share, of which 14,340,214 shares were offered by us and 300,541 shares were offered by the selling shareholder. We received approximately $ 220.0 million in net proceeds after deducting approximately $23.8 million of underwriting discounts and commissions and other offering costs. We did not receive any proceeds from the sale of the shares of Class A Common Stock by the selling shareholder. 
+1 
+Table of Contents 
+We are a holding company with no direct operations. In connection with the IPO, we completed the Corporate Reorganization, including the following series of transactions: 
+• Liberty Holdings contributed all of its assets to Liberty LLC in exchange for units in Liberty LLC (the “Liberty LLC Units”); 
+• Liberty Holdings liquidated and distributed to its then-existing owners (the “Legacy Owners”) Liberty LLC Units pursuant to the terms of the limited liability company agreement of Liberty Holdings and the Master Reorganization Agreement dated as of January 11, 2018, by and among the Company, Liberty Holdings, Liberty LLC, and the other parties named therein (the “Master Reorganization Agreement”); 
+• certain of the Legacy Owners directly or indirectly contributed all or a portion of their Liberty LLC Units to Liberty Inc. in exchange for 55,685,027 shares of our Class A Common Stock, and 1,258,514 shares of restricted stock. Subsequent to the initial exchange, 1,609,122 shares of Class A Common Stock were redeemed for an aggregate purchase price of $25.9 million upon the exercise of the underwriters' overallotment option; 
+• Liberty Inc. issued the Legacy Owners that continued to own Liberty LLC Units (the “Liberty Unit Holders”) an aggregate amount of 48,207,372 shares of our Class B common stock, par value $0.01 per share (the “Class B Common Stock” and, together with the Class A Common Stock, the “Common Stock”); and 
+• Liberty Inc. contributed the net proceeds it received from the IPO to Liberty LLC in exchange for additional Liberty LLC Units such that Liberty Inc. held a total number of Liberty LLC Units equal to the number of shares of Class A Common Stock outstanding immediately following the IPO. 
+The below structure chart shows our organization upon the completion of our IPO. This chart is provided for illustrative purposes only and does not represent all legal entities affiliated with us. 
+Each share of Class B Common Stock has no economic rights but entitles its holder to one vote on all matters to be voted on by shareholders generally. Holders of Class A Common Stock and Class B Common Stock will vote together as a single 
+2 
+Table of Contents 
+class on all matters presented to our shareholders for their vote or approval, except as otherwise required by applicable law or by our amended and restated certificate of incorporation. We do not intend to list our Class B Common Stock on any exchange. 
+Under the Second Amended and Restated Limited Liability Company Agreement of Liberty LLC (the “Liberty LLC Agreement”), each Liberty Unit Holder has, subject to certain limitations, the right (the “Redemption Right”) to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units for, at Liberty LLC’s election, (i) shares of our Class A Common Stock at a redemption ratio of one share of Class A Common Stock for each Liberty LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions or (ii) an equivalent amount of cash. Alternatively, upon the exercise of the Redemption Right, Liberty Inc. (instead of Liberty LLC) will have the right (the “Call Right”) to, for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder for, at its election, (i) one share of Class A Common Stock or (ii) an equivalent amount of cash. In addition, upon a change of control of Liberty Inc., Liberty Inc. has the right to require each holder of Liberty LLC Units (other than Liberty Inc.) to exercise its Redemption Right with respect to some or all of such unit holder’s Liberty LLC Units. In connection with any redemption of Liberty LLC Units pursuant to the Redemption Right or the Call Right, the corresponding number of shares of Class B Common Stock will be canceled. 
+In connection with the IPO, Liberty Inc. entered into two tax receivable agreements, (the “TRAs”) with the Liberty Unit Holders and the selling shareholder (each such person and any permitted transferee, a “TRA Holder” and together, the “TRA Holders”). 
+The first of the TRAs, which Liberty Inc. entered into with the Liberty Unit Holders, generally provides for the payment by Liberty Inc. to such TRA Holders of 85% of the net cash savings, if any, in U.S. federal, state and local income and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that Liberty Inc. actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result of, as applicable to each such TRA Holder, (i) certain increases in tax basis that occur as a result of Liberty Inc.’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holder’s Liberty LLC Units in connection with the IPO or pursuant to the exercise of the Redemption Right or Liberty Inc.’s Call Right and (ii) imputed interest deemed to be paid by Liberty Inc. as a result of, and additional tax basis arising from, any payments Liberty Inc. makes under such TRAs. 
+The second of the TRAs, which Liberty Inc. entered into with the selling shareholder, generally provides for the payment by Liberty Inc. to such TRA Holder of 85% of the net cash savings, if any, in U.S. federal, state and local income and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that Liberty Inc. actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result of, as applicable to such TRA Holder, (i) any net operating losses available to Liberty Inc. as a result of the Corporate Reorganization and (ii) imputed interest deemed to be paid by Liberty Inc. as a result of any payments Liberty Inc. makes under such TRAs. For further discussion regarding the potential acceleration of payments under the TRAs and its potential impact, please read “Risk Factors—Risks Related to Our Class A Common Stock.” 
+Because Liberty Inc. is a holding company with no operations of its own, Liberty Inc.’s ability to make payments under the TRAs is dependent on the ability of Liberty LLC to make distributions to Liberty Inc. in an amount sufficient to cover its obligations under the TRAs. See “Risk Factors—Risks Related to Our Class A Common Stock—Liberty Inc. is a holding company. Liberty Inc.’s only material asset is its equity interest in Liberty LLC, and Liberty Inc. is accordingly dependent upon distributions from Liberty LLC to pay taxes, make payments under the TRAs and cover its corporate and other overhead expenses.” If Liberty Inc. experiences a change of control (as defined under the TRAs, which includes certain mergers, asset sales and other forms of business combinations) or the TRAs terminate early (at Liberty Inc.’s election or as a result of its breach), Liberty Inc. would be required to make a substantial, immediate lump-sum payment. 
+Cyclical Nature of Industry 
+We operate in a highly cyclical industry. The key factor driving demand for our services is the level of drilling activity by E&P companies, which in turn depends largely on the current and anticipated economics of new well completions. Global supply and demand for oil and the domestic supply and demand for natural gas are critical in assessing industry outlook. Demand for oil and natural gas is cyclical and subject to large, rapid fluctuations. E&P companies tend to increase capital expenditures in response to increases in oil and natural gas prices, which generally results in greater revenues and profits for oilfield service companies such as ours. Increased capital expenditures also ultimately lead to greater production, which historically has resulted in increased supplies and reduced prices which in turn tend to reduce demand for oilfield services. For these reasons, the results of our operations may fluctuate from quarter to quarter and from year to year, and these fluctuations may distort comparisons of results across periods. 
+3 
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+Seasonality 
+Our results of operations have historically reflected seasonal tendencies relating to holiday seasons, inclement weather and the conclusion of our customers’ annual drilling and completion capital expenditure budgets. Our most notable declines typically occur in the fourth quarter of the year for the reasons described above. Additionally, some of the areas in which we have operations, including the DJ Basin, Powder River Basin and Williston Basin, are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice or rain and frost law enforcement, we may be unable to move our equipment between locations, thereby reducing our ability to provide services and generate revenues. The exploration activities of our customers may also be affected during such periods of adverse weather conditions. Additionally, extended drought conditions in our operating regions could impact our ability or our customers’ ability to source sufficient water or increase the cost for such water. 
+Intellectual Property 
+Over the last several years we have significantly invested in our research and technology capabilities. Our efforts to date have been focused on developing innovative, fit-for-purpose solutions designed to enhance our core service offerings, increase completion efficiencies, provide cost savings to our operations and add value for our customers. 
+As a result of these efforts, we introduced several new products and progressed on differentiating technologies that we believe will provide a competitive advantage as our customers focus on extracting oil and natural gas in the most economical and efficient ways possible, including, for example, our Liberty Quiet Fleet®, which materially reduces noise levels compared to conventional fracturing fleets. These investments are delivering value added products and services that support our customers and create increasing demand for our services. 
+We seek patent and trademark protections for our technology when we deem it prudent, and we aggressively pursue protection of these rights when warranted. We believe our patents, trademarks, and other protections for our proprietary technologies are adequate for the conduct of our business and that no single patent or trademark is critical to our business. In addition, we rely, to a great extent, on the technical expertise and know-how of our personnel to maintain our competitive position, and we take commercially reasonable measures to protect trade secrets and other confidential and/or proprietary information relating to the technologies we develop. 
+Risk Management and Insurance 
+Our operations are subject to significant hazards often found in the oil and natural gas industry, such as, but not limited to, accidents, including accidents related to trucking operations provided in connection with our services, blowouts, explosions, craterings, fires, natural gas leaks, oil and produced water spills and releases of hydraulic fracturing fluids or other well fluids into the environment. These conditions can cause: 
+• disruption in operations; 
+• substantial repair or remediation costs; 
+• personal injury or loss of human life; 
+• significant damage to or destruction of property and equipment; 
+• environmental pollution, including groundwater contamination; 
+• unusual or unexpected geological formations or pressures and industrial accidents; 
+• impairment or suspension of operations; and 
+• substantial revenue loss. 
+In addition, our operations are subject to, and exposed to, employee/employer liabilities and risks such as wrongful termination, discrimination, labor organizing, retaliation claims and general human resource related matters. 
+Claims for loss of oil and natural gas production and damage to formations can occur in the well services industry. Litigation arising from a catastrophic occurrence at a location where our equipment and services are being used or trucking services provided in connection therewith may result in our being named as a defendant in lawsuits asserting large claims. 
+We do not have insurance against all foreseeable risks, either because insurance is not available or because of the high premium costs. The occurrence of an event not fully insured against or the failure of an insurer to meet its insurance obligations could result in substantial losses. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. Insurance may not be available to cover any or all of the risks to which we are subject, or, even if 
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+available, it may be inadequate, or insurance premiums or other costs could rise significantly in the future so as to make such insurance prohibitively expensive. 
+We enter into Master Service Agreements (“MSAs”) with substantially all of our customers for our hydraulic fracturing services. Such MSAs delineate our and our customer’s respective indemnification obligations with respect to the services we provide. Generally, under our MSAs relating to our hydraulic fracturing services, we assume responsibility for pollution or contamination originating above the surface from our equipment or handling. However, our customers assume responsibility for all other pollution or contamination that may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling and completion fluids. The assumed responsibilities include the control, removal and clean-up of any pollution or contamination. In such cases, we may be exposed to additional liability if we are grossly negligent or commit willful acts causing the pollution or contamination. Generally, our customers also agree to indemnify us against claims arising from their employees’ personal injury or death, in the case of our hydraulic fracturing operations, to the extent that their employees are injured by such operations, unless the loss is a result of our gross negligence or willful misconduct. Similarly, we generally agree to indemnify our customers for liabilities arising from personal injury to or death of any of our employees, unless resulting from the gross negligence or willful misconduct of our customer. The same principles apply to mutual indemnification for loss or destruction of property or equipment. Losses due to catastrophic events, such as blowouts, are generally the responsibility of the customer. However, despite this general allocation of risk, we may be unsuccessful in enforcing contractual terms, incur an unforeseen liability that is not addressed by the scope of the contractual provisions or be required to enter into an MSA with terms that vary from our standard allocations of risk, as described above. Consequently, we may incur substantial losses that could materially and adversely affect our financial condition and results of operations. 
+Employees 
+As of December 31, 2019, we had 2,571 employees and no unionized labor. We believe we have good relations with our employees. 
+Our Services 
+We primarily provide hydraulic fracturing services and goods to onshore oil and natural gas E&P companies operating in unconventional oil and natural gas reservoirs and requiring technically and operationally advanced services. Hydraulic fracturing services are performed to enhance production of oil and natural gas from formations with low permeability and restricted flow of hydrocarbons. Our customers benefit from our expertise in fracturing horizontal wells in shales and other unconventional geological formations. 
+The process of hydraulic fracturing involves pumping a pressurized stream of fracturing fluid—typically a mixture of water, chemicals and proppant—into a well casing or tubing in order to cause the underground formation to fracture or crack. These fractures release trapped hydrocarbon particles and provide a conductive channel for the oil or natural gas to flow freely to the wellbore for collection. The propping agent, or proppant,—typically sand—becomes lodged in the cracks created by the hydraulic fracturing process, “propping” them open to facilitate the flow of hydrocarbons from the reservoir to the well. The fracturing fluid is engineered to lose viscosity, or “break,” and is subsequently flowed back from the formation, leaving the proppant suspended in the mineral fractures. Once our customer has flushed the fracturing fluids from the well using a controlled flow-back process, the customer manages fluid and water recycling or disposal. 
+Our hydraulic fracturing fleets consist of mobile hydraulic fracturing units and other auxiliary heavy equipment to perform fracturing services. Our hydraulic fracturing units consist primarily of high-pressure hydraulic pumps, diesel engines, transmissions, radiators and other supporting equipment that are typically mounted on trailers. We refer to the group of units and other equipment, such as blenders, data vans, sand storage, tractors, manifolds and high pressure fracturing iron, which are necessary to perform a typical hydraulic fracturing job, as a “fleet,” and the personnel assigned to each fleet as a “crew.” As of February 2020, we had 24 active fleets. 
+An important element of our hydraulic fracturing services is our focus on providing custom-tailored completions solutions to our customers to maximize their well results. Our technologically innovative approach involves our review of a series of continually updated, proprietary databases of U.S. unconventional wells to which we apply our multi-variable data analysis, allowing us to gain differential insight into fracture design. The innovative completions solutions we provide to our customers help them complete more productive and cost efficient wells in shorter times with less environmental impact on their surroundings while increasing the useful lives of our equipment. 
+In addition to custom-tailored completions solutions, we also develop custom fluid systems, proppant logistics solutions, perforating strategies and pressure analysis techniques for our customers. An example of this is a hydraulic fracturing fluid that we developed for use in our DJ Basin operations called Liberty Spirit ™ , a specifically designed fracturing fluid system that enables material reductions in completion costs in the DJ Basin without compromising job execution or well results. 
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+We provide our services in several of the most active basins in the United States, including the Permian Basin, the Eagle Ford Shale, the DJ Basin, the Williston Basin, the San Juan Basin and the Powder River Basin. The map below represents our current areas of operations: 
+Properties and Equipment 
+Properties 
+Our corporate headquarters are located at 950 17 th Street, Suite 2400, Denver, Colorado 80202. We lease our general office space at our corporate headquarters. The lease expires in December 2024. We currently own or lease the following additional principal properties: 
+District Facility Location Size Leased or Owned Expiration of Lease 
+Odessa, TX 77,500 sq. ft on 47 acres Owned N/A 
+Henderson, CO 50,000 sq. ft on 13 acres Leased December 31, 2034 
+Williston, ND 30,000 sq. ft on 15 acres Owned N/A 
+Gillette, WY 32,757 sq. ft on 15 acres Leased December 31, 2034 
+Cibolo, TX 90,000 sq. ft on 34 acres Owned N/A 
+We also lease several smaller facilities, which leases generally have terms of one to three years. We believe that our existing facilities are adequate for our operations and their locations allow us to efficiently serve our customers. We do not believe that any single facility is material to our operations and, if necessary, we could readily obtain a replacement facility. 
+Equipment 
+As of February 2020, we have 24 hydraulic fracturing fleets. Eleven of our fleets currently utilize our Liberty Quiet Fleet® technology, approximately 28% of our capacity has dual fuel capability, and approximately 22% of our capacity utilizes the latest Tier 4 diesel engines. 
+Our hydraulic fracturing fleets are comprised of high-quality, heavy-duty equipment designed to reduce operational downtime and maintenance costs, while enhancing our ability to provide reliable, consistent service. Each hydraulic fracturing fleet includes the necessary blending units, manifolds, data vans and other ancillary equipment needed to provide a high level of service to our customers. 
+Our newbuild fleets are manufactured to a custom Liberty specification that identifies the input components, including such key parts as engines, transmissions and pumps and control systems. These components have been selected with our lowest total cost of ownership philosophy in mind. We have built a strong partnership with each of the key component suppliers that we believe will help ensure timely access to necessary components, early opportunities to adopt the latest technology, and high-level technical support. For example, our close partnership with Caterpillar Inc. enabled us to have ready access to their technical team as we worked through the development of the Liberty Quiet Fleet® technology and to be on the early test site for their new low-emission Tier 4 diesel and dynamic gas blending engines. This relationship ensured that the end product was delivered without compromise to engine performance, reliability or maintainability. We have also a built a strong relationship 
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+with the assembler of the core equipment for our fracturing fleets. We believe the collaborative partnerships we have developed with our vendors should give us ready access to sufficient fabrication capacity for our growth. 
+Our Acquisitions 
+On February 22, 2017, we acquired all membership interests of Titan Frac Services LLC, a wholly owned subsidiary of TPIH Group Inc., for $65.0 million in cash. 
+Marketing and Customers 
+Our sales and marketing activities typically are performed through our local sales representatives in each geographic region, and are supported by our corporate headquarters. For the years ended December 31, 2019, 2018 and 2017, our top five customers collectively accounted for approximatel y 35% , 42% and 53% of our revenues, respectively. No customer accounted for more than 10% of our revenues for the year ended December 31, 2019. For the year ended December 31, 2018, Extraction Oil & Gas, Inc. accounted for more than 10% of our revenues. Extraction Oil & Gas, Inc. and SM Energy Company each accounted for more than 10% of our revenues for the year ended December 31, 2017. 
+Suppliers 
+We have a dedicated supply chain team that manages sourcing and logistics to ensure flexibility and continuity of supply in a cost effective manner across our areas of operation. We have built long-term relationships with multiple industry leading suppliers of proppant, chemicals and hydraulic fracturing equipment and have started to internally design and assemble key pump and maintenance parts. In addition, we have built a strong relationship with the assembler of our custom-designed hydraulic fracturing fleets and believe we will continue to have timely access to new, high capability fleets as we continue to grow. 
+We purchase a wide variety of raw materials, parts and components that are manufactured and supplied for our operations. We are not dependent on any single source of supply for those parts, supplies or materials. To date, we have generally been able to obtain the equipment, parts and supplies necessary to support our operations on a timely basis. While we believe that we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers, we may not always be able to do so. In addition, certain materials for which we do not currently have long-term supply agreements could experience shortages and significant price increases in the future. As a result, we may be unable to mitigate any future supply shortages and our results of operations, prospects and financial condition could be adversely affected. 
+Competition 
+The markets in which we operate are highly competitive. We provide services in various geographic regions across the United States, and our competitors include many large and small oilfield service providers, including some of the largest integrated service companies. Our hydraulic fracturing services compete with large, integrated companies such as Halliburton Company and Schlumberger Limited as well as other companies including BJ Services Company, Calfrac Well Services Ltd., FTS International, Inc., NexTier Oilfield Solutions Inc., Patterson-UTI Energy, Inc., ProPetro Services, Inc., RPC, Inc. and U.S. Well Services, Inc. In addition, our industry is highly fragmented and we compete regionally with a significant number of smaller service providers. 
+We believe that the principal competitive factors in the markets we serve are technical expertise, equipment capacity, work force competency, efficiency, safety record, reputation, experience and price. Additionally, projects are often awarded on a bid basis, which tends to create a highly competitive environment. We seek to differentiate ourselves from our competitors by delivering the highest-quality services and equipment possible, coupled with superior execution and operating efficiency in a safe working environment. 
+Our operations are organized into a single business segment, which consists of hydraulic fracturing services and goods, and we have one reportable geographical business segment, the United States. Operating segments are defined under generally accepted accounting principles in the United States of America ( “ GAAP ” ) as components of an enterprise that engage in activities (i) from which it may earn revenues and incur expenses and (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance. 
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+Environmental and Occupational Safety and Health Matters 
+Our operations in support of oil and natural gas exploration, development and production activities pursued by our customers are subject to stringent federal, tribal, regional, state and local laws and regulations governing occupational safety and health, the discharge of materials into the environment and environmental protection. Numerous governmental entities, including the U.S. Environmental Protection Agency (“EPA”), the U.S. Occupational Safety and Health Administration (“OSHA”), and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions, including the incurrence of potentially significant capital or operating expenditures to mitigate or prevent the releases of materials from our equipment, facilities or from customer locations where we provide our services. These laws and regulations may, among other things, (i) require the acquisition of permits or other authorizations for conducting regulated activities; (ii) limit or prohibit our operations on certain lands lying within wilderness, wetlands and other protected areas; (iii) require remedial measures to mitigate pollution from former and ongoing operations; (iv) impose restrictions on the types, quantities and concentrations of various substances that can be released into the environment or injected in formations in connection with oil and natural gas drilling and production activities; (v) impose specific safety and health criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from our operations. Any failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties; the imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures; the occurrence of restrictions, delays or cancellations in the permitting, performance or development of projects or operations; and the issuance of orders enjoining performance of some or all of our operations in a particular area. 
+The trend in environmental regulation is to place more restrictions and limitations on activities that may adversely affect the environment, and thus any new laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased government enforcement with respect to environmental matters that result in more stringent and costly completion activities, pollution control equipment, waste handling, storage transport, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for injuries to persons or damages to properties or natural resources. Our customers may also incur increased costs, or restrictions, delays or cancellations in permitting or operating activities as a result of more stringent environmental laws and regulations, which may result in a curtailment of exploration, development or production activities that would reduce the demand for our services. Historically, our worker health and safety as well as our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our business and operating results. 
+The following is a summary of the more significant existing environmental and occupational safety and health laws, as amended from time to time, to which our business is subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position. 
+Worker Health and Safety 
+We are subject to the requirements of the federal Occupational Safety and Health Act, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and the public. These worker health and safety laws and regulations are subject to amendment including, for example, rulemaking adopted by OSHA in 2016 imposing more stringent permissible exposure limits for worker exposure to respirable crystalline silica, and any failure to comply with these laws could lead to the assertion of third-party claims against us, civil or criminal fines and changes in the way we operate our facilities, any of which could have an adverse effect on our financial position. 
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+Motor Carrier Operations 
+In connection with the services we provide, we operate as a motor carrier and therefore are subject to regulation by the U.S. Department of Transportation (“DOT”) and analogous state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations; regulatory safety; hazardous materials labeling, placarding and marking; financial reporting; and certain mergers, consolidations and acquisitions. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may increase our costs as well as affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations that govern the amount of time a driver may drive in any specific period and requiring onboard electronic logging devices or limits on vehicle weight and size. 
+Interstate motor carrier operations are subject to safety requirements prescribed by DOT. Intrastate motor carrier operations are subject to state safety regulations that often mirror federal regulations but may be more stringent. Such matters as weight and dimension of motor carrier-related equipment are also subject to federal and state regulations. DOT regulations also mandate drug testing of drivers. From time to time, various legislative proposals are introduced, including proposals to increase federal, state or local taxes, such as, for example, taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us would be enacted. 
+Radioactive Materials 
+Certain of our operations utilize equipment that contains sealed, low-grade radioactive sources. Our activities involving the use of radioactive materials are regulated by the U.S. Nuclear Regulatory Commission (“NRC”) and state regulatory agencies under agreement with the NRC. Standards implemented by these regulatory agencies require us to obtain licenses or other approvals for the use of such radioactive materials. Additionally, these regulatory agencies impose certain requirements concerning worker protection with respect to radioactive sources and may otherwise issue regulations regarding the handling and storage of this equipment that may result in increased costs. The violation of these laws and regulations may result in the denial or revocation of licenses or other approvals, issuance of corrective action orders, injunctions prohibiting some or all of our operations in a particular area, and assessment of sanctions, including administrative, civil and criminal penalties. 
+Hazardous Substances and Wastes and Naturally Occurring Radioactive Materials 
+The federal Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, regulate the generation, treatment, storage, transportation, disposal and clean-up of hazardous and non-hazardous wastes. Pursuant to rules issued by the EPA, individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste provisions, state laws or other federal laws. However, it is possible that certain oil and gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. For example, in response to a federal consent decree issued in 2016, the EPA was required during 2019 to determine whether certain Subtitle D criteria regulations required revision in a manner that could result in oil and natural gas wastes being regulated as RCRA hazardous wastes. In April 2019, the EPA made a determination that such revision of the regulations was unnecessary. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our and the oil and natural gas exploration and production industry’s costs to manage and dispose of generated hazardous wastes, which could have a material adverse effect on our results of operations and financial position. Additionally, other wastes handled at exploration and production sites or generated in the course of providing well services may not fall within this exclusion. In the course of our operations, we generate some amounts of ordinary industrial wastes that may be regulated as hazardous wastes. 
+Moreover, there have been public concerns expressed about naturally occurring radioactive materials (“NORM”) being detected in flow back water resulting from hydraulic fracturing that may contaminate extraction and processing equipment used in the oil and natural gas industry. NORM is subject primarily to individual state radiation control regulations while NORM handling and management activities are governed by regulations promulgated by OSHA. These state and federal regulations impose certain requirements concerning worker protection with respect to NORM as well as the treatment, storage, and disposal of NORM and NORM waste, management of NORM-contaminated waste piles, containers and tanks, and limitations on the relinquishment of NORM contaminated land for unrestricted use under RCRA and state laws. Concern over NORM in general, or NORM in groundwater in particular, could result in further regulation in the treatment, storage, handling and discharge of flow back water generated from oil and natural gas activities, including hydraulic fracturing, or handling of NORM-impacted 
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+equipment that, if implemented, could increase our or our customers’ costs or liabilities associated with elevated levels of NORM as well as limit drilling by our customers, which developments may reduce demand for our services. 
+The federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, and comparable state statutes impose liability, without regard to fault or legality of the original conduct, on classes of persons that are considered to have contributed to the release of a hazardous substance into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, these persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources even if the liability results from conduct that was lawful at the time it occurred or is due to the conduct, or conditions caused by, prior operators or third parties. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We own, lease, or operate numerous properties and facilities that for many years have been used for industrial activities, including oil and natural gas-related operations. Hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations where such substances have been taken for recycling or disposal. In addition, some of these properties have been operated by third parties or by previous owners whose treatment and disposal or release of hazardous substances, wastes, or hydrocarbons, was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes and remediate contaminated property (including groundwater contamination), including instances where the prior owner or operator caused the contamination, or perform remedial plugging of disposal wells or waste pit closure operations to prevent future contamination. 
+Water Discharges and Discharges into Belowground Formations 
+The Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”) and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and hazardous substances, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers (“Corps”). The CWA and analogous state laws also may impose substantial civil and criminal penalties for non-compliance including spills and other non-authorized discharges. 
+In 2015, the EPA and the Corps under the Obama Administration published a final rule outlining their position on federal jurisdictional reach over waters of the United States, including wetlands. In 2017, the EPA and the Corps under the Trump Administration agreed to reconsider the 2015 rule and, thereafter, on October 22, 2019, the agencies published a final rule made effective on December 23, 2019, rescinding the 2015 rule. On January 23, 2020, the two agencies issued a final rule re-defining the CWA's jurisdiction over waters of the United States, which redefinition is narrower than found in the 2015 rule. Upon being published in the Federal Register and the passage of 60 days thereafter, the January 23, 2020 final rule will become effective, at which point the United States will be covered under a single regulatory scheme as it relates to federal jurisdictional reach over waters of the United States. However, there remains the expectation that the January 23, 2020 final rule also will be legally challenged in federal district court. To the extent that any challenge to the January 23, 2020 final rule is successful and the 2015 rule or a revised rule expands the scope of the CWA's jurisdiction in areas where we or our oil and natural gas exploration and production customers conduct operations, we or our customers could incur increased costs and our customers could incur delays or cancellations in permitting or projects, which could reduce demand for our products and services. 
+The Oil Pollution Act of 1990 (“OPA”) amends the CWA and sets minimum standards for prevention, containment and cleanup of oil spills. OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties including owners and operators of onshore facilities may be held strictly liable for oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills. The OPA also requires owners or operators of certain onshore facilities to prepare facility response plans for responding to a worst-case discharge of oil into waters of the United States. 
+Our oil and natural gas producing customers dispose of flowback and produced water or certain other oilfield fluids gathered from oil and natural gas producing operations in accordance with permits issued by government authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are 
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+subject to change based on concerns of the public or governmental authorities regarding such disposal activities. One such concern relates to seismic events near underground disposal wells used for the disposal by injection of flowback and produced water or certain other oilfield fluids resulting from oil and natural gas activities. In 2016, the United States Geological Survey identified six states with more significant rates of induced seismicity that could be attributed to injection of oilfield fluids into underground disposal wells, including Oklahoma, Kansas, Texas, Colorado, New Mexico, and Arkansas. Since that time, the United States Geological Survey indicates that these rates have decreased in these states, although concern continues to exist over quakes arising from induced seismic activities. In response to concerns between use of underground disposal wells and the occurrence of seismic events, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Texas and Oklahoma have issued rules for produced water disposal wells that impose certain permitting restrictions, operating restrictions and/or reporting requirements on disposal wells in proximity to faults. Additionally, from time to time, states may develop and implement plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations, as has occurred in Oklahoma. For example, in late 2016, the Oil and Gas Conservation Division of the Oklahoma Corporation Commission (“OCC”) and the Oklahoma Geological Survey released well completion seismicity guidance, which requires operators to take certain prescriptive actions, including an operator’s planned mitigation practices, following certain unusual seismic activity within 1.25 miles of hydraulic fracturing operations. In recent years the OCC’s Oil and Gas Conservation Division has issued orders limiting future increases in the volume of oil and natural gas produced water injected belowground into the Arbuckle formation in an effort to reduce the number of earthquakes in the state. Another consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by our customers to dispose of flowback and produced water and certain other oilfield fluids. Increased regulation and attention given to seismicity events suspected of having been induced by injection of oilfield fluids into underground disposal wells also could lead to greater opposition to, and litigation concerning, oil and natural gas activities utilizing injection wells for waste disposal. Any of these developments may result in our customers having to limit disposal well volumes, disposal rates or locations, or require our customers or third party disposal well operators that are used to dispose of customer produced water to shut down disposal wells, which developments could adversely affect our customers’ business and result in a corresponding decrease in the need for our services, which would could have a material adverse effect on our business, financial condition, and results of operations. 
+Air Emissions 
+Certain of our operations also result in emissions of regulated air pollutants. The federal Clean Air Act (“CAA”) and analogous state and local laws require permits for certain facilities that have the potential to emit substances into the atmosphere that could adversely affect environmental quality. These laws and their implementing regulations also impose generally applicable limitations on air emissions and require adherence to maintenance, work practice, reporting and record keeping, and other requirements. Failure to obtain a permit or to comply with permit or other regulatory requirements could result in the imposition of sanctions, including administrative, civil and criminal penalties. In addition, we or our customers could be required to shut down or retrofit existing equipment, leading to additional expenses and operational delays. 
+Many of these regulatory requirements, including New Source Performance Standards and Maximum Achievable Control Technology standards, are expected to be made more stringent over time as a result of stricter ambient air quality standards and other air quality protection goals adopted by the EPA. Compliance with these or other new or amended regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact on our business. For example, in 2015, the EPA lowered the National Ambient Air Quality Standard, (“NAAQS”) for ozone from 75 to 70 parts per billion for both the 8-hour primary and secondary standards. Since that time, the EPA issued area designations with respect to ground-level ozone and final requirements that apply to state, local, and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Additionally, states are expected to implement more stringent requirements as a result of the revised NAAQS for ozone, which could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. Compliance with this and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase costs for us and our customers. Moreover, our business could be materially affected if our customers’ operations are significantly affected by these or other similar requirements. These requirements could increase the cost of doing business for us and our customers, reduce the demand for the oil and natural gas our customers produce, and thus have an adverse effect on the demand for our services. 
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+Climate Change 
+Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of greenhouse gases (“GHGs”) as well as to restrict or eliminate such future emissions. As a result, our operations as well as the operations of our customers are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHGs. 
+The U.S. Congress (“Congress”) and the EPA, in addition to some state and regional efforts, have in recent years considered legislation or regulations to reduce emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. In the absence of federal GHG-limiting legislations, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources, implement CAA emission standards directing the reduction of methane from certain new, modified, or reconstructed facilities in the oil and natural gas sector, and together with the DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there exists the United Nations-sponsored “Paris Agreement,” which is a non-binding agreement for nations to limit their GHG emissions through individually-determined reduction goals every five years after 2020, although the United States has announced its withdrawal from such agreement, effective November 4, 2020. 
+Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, in the form of pledges made by certain candidates seeking the office of the President of the United States in 2020. Critical declarations made by one or more presidential candidates include proposals to ban hydraulic fracturing of oil and natural gas wells and ban new leases for production of minerals on federal properties. Other actions to limit oil and natural gas production activities that could be pursued by presidential candidates may include more restrictive requirements for the establishment of pipeline infrastructure or the permitting of liquified natural gas export facilities, as well as the rescission of the United States’ withdrawal from the Paris Agreement in November 2020. Litigation risks are also increasing, as a number of cities, local governments, and other plaintiffs have sought to bring suit against the largest oil and natural gas E&P companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts. 
+There are also increasing financial risks for fossil fuel producers, as stockholders and bondholders currently invested in fossil fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-fossil fuel energy related sectors. Institutional investors who provide financing to fossil fuel energy companies also have become more attentive to sustainability lending practices and some of them may elect not to provide funding for fossil fuel energy companies. Additionally, the lending and investment practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in nature, by environmental activists, proponents of the international Paris Agreement, and foreign citizenry concerned about climate change not to provide funding for fossil fuel producers. Limitation of investments in and financings for fossil fuel energy could result in the restriction, delay, or cancellation of drilling programs or development of production activities. 
+The adoption and implementation of any international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for oil and natural gas, which could reduce demand for our products and services. Additionally, political, litigation, and financial risks may result in our oil and natural gas customers restricting or cancelling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing their ability to continue to operate in an economic manner, which also could reduce demand for our products and services. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation. Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our operations. 
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+Endangered Species 
+The federal Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the federal Migratory Bird Treaty Act (“MBTA”). Customer oil and natural gas operations may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife, which may limit their ability to operate in protected areas. Permanent restrictions imposed to protect endangered and threatened species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. Moreover, the U.S. Fish and Wildlife Service (“FWS”) may make determinations on the listing of species as endangered or threatened under the ESA and litigation with respect to the listing or non-listing of certain species as endangered or threatened may result in more fulsome protections for non-protected or lesser-protected species. For example, in 2015, the FWS decided to list the northern long-eared bat, whose range covers more than two-thirds of the states in the eastern and north-central regions of the U.S., as threatened rather than the more protective designation, endangered. However, a federal court decision issued in January 2020 found that the FWS failed to conduct a sufficient analysis that could have resulted in the bat being declared as endangered and the court remanded the listing decision to the FWS for a new determination on the species’ protected status. Current ESA listings and the designation of previously unprotected species or re-designation of lesser-protected species as threatened or endangered in areas where we or our customers operate could cause us or our customers to incur increased costs arising from species protection or mitigation measures and could result in restrictions, delays or cancellations in our or our customers’ performance of operations, which could adversely affect or reduce demand for our services. 
+Hydraulic Fracturing 
+We perform hydraulic fracturing services for our customers. Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppant and chemical additives under pressure into the formation to fracture the surrounding rock and stimulate production. 
+Hydraulic fracturing typically is regulated by state oil and natural gas commissions or similar agencies, but the EPA has conducted investigations or asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act (“SDWA”) Underground Injection Control (“UIC”) program over certain aspects of the process. For example, in late 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. Additionally, the EPA has asserted regulatory authority under the SDWA UIC program over hydraulic fracturing activities involving the use of diesel fuel and issued permitting guidance covering such activities, as well as published an Advanced Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. The EPA also published final CAA regulations in 2012 and 2016 governing performance standards, including standards for the capture of emissions of methane and volatile organic compounds (“VOCs”) released during oil and natural gas hydraulic fracturing. However, in September 2019, the EPA proposed an amendment to the methane and VOC standards that would remove the methane-specific requirements that currently apply in favor of relying on the emission limits for VOCs. Moreover, in 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of produced water from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The BLM published a final rule in 2015 that imposed new or more stringent standards for performing hydraulic fracturing on federal and Native American lands but the BLM rescinded the 2015 rule in later 2017; however, litigation challenging the BLM’s decisions to rescind the 2015 rule remains pending in federal district court. 
+From time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. However, concern over the threat of climate change has resulted in the making of pledges by certain candidates seeking the office of the President of the United States in 2020 to ban hydraulic fracturing of oil and natural gas wells. Additionally, presidential candidate Senator Bernie Sanders (D-VT) introduced a bill in the Senate on January 28, 2020 that, if enacted as proposed, would ban hydraulic fracturing nationwide by 2025. 
+Additionally, various state and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, disclosure requirements, well construction and temporary or permanent bans on hydraulic fracturing in certain areas. For example, Texas, Colorado and North Dakota, among others, have adopted regulations that impose new or more stringent permitting, disclosure, disposal, and well construction requirements on hydraulic fracturing operations. In April 2019, the Governor of Colorado signed Senate Bill 19-181 (“SB 181”) into law, which legislation, among other things, revises the mission of the state oil and gas agency from fostering energy development in the state to instead focusing on regulating the industry in a manner that is protective of public health and safety and the environment, as well as authorizing cities and counties to regulate oil and natural gas operations, 
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+including hydraulic fracturing activities, within their jurisdiction. States could also elect to place certain prohibitions on hydraulic fracturing, following the approach taken by the States of Maryland, New York and Vermont. Local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular. Also, non-governmental organizations may seek to restrict hydraulic fracturing; notwithstanding the adoption of Colorado SB 181 in 2019, one or more interest groups have already filed new ballot initiatives with the state in January 2020, in hopes of extending drilling setbacks from oil and natural gas development. 
+If new federal, state or local laws, regulations, presidential executive orders or ballot initiatives that significantly restrict or ban some or all of hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and prohibit or make it more difficult or costly to perform hydraulic fracturing. Any such laws, regulations or ballot initiatives limiting or prohibiting hydraulic fracturing could result in decreased oil and natural gas exploration and production activities and, therefore, adversely affect demand for our services and our business. Such laws, regulations, presidential executive orders or ballot initiatives could also materially increase our costs of compliance and doing business as well as result in decreased oil and natural gas activities and, therefore, adversely affect demand for our products and services. 
+Available Information 
+We file or furnish annual, quarterly and current reports, proxy statements and other documents with the U.S Security and Exchange Commission (the “SEC”) under the Exchange Act. The SEC also maintains an internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC. 
+Our Class A Common Stock is listed and traded on the New York Stock Exchange (“NYSE”) under the symbol “LBRT.” Our reports, proxy statements and other information filed with the SEC can also be inspected and copied at the offices of the NYSE, at 20 Broad Street, New York, New York 10005. 
+We also make available free of charge through our website, www.libertyfrac.com, electronic copies of certain documents that we file with the SEC, including our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. 
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+Item 1A. Risk Factors 
+Described below are certain risks that we believe apply to our business and the industry in which we operate. You should carefully consider each of the following risk factors in conjunction with other information provided in this Annual Report on Form 10-K and in our other public disclosures. The risks described below highlight potential events, trends or other circumstances that could adversely affect our business, financial condition, results of operations, cash flows, liquidity or access to sources of financing, and consequently, the market value of our Class A Common Stock. These risks could cause our future results to differ materially from historical results and from guidance we may provide regarding our expectations of future financial performance. The risks described below are those that we have identified as material and is not an exhaustive list of all the risks we face. There may be other risks that we have not identified or that we have deemed to be immaterial. Please refer to the explanation of the qualifications and limitation on forward-looking statements set forth on page ii hereof. 
+Risks Related to Our Business 
+Our business depends on domestic capital spending by the oil and natural gas industry, and reductions in capital spending could have a material adverse effect on our liquidity, results of operations and financial condition. 
+Our business is directly affected by our customers’ capital spending to explore for, develop and produce oil and natural gas in the United States. The significant decline in oil and natural gas prices that began in late 2014 caused a reduction in the exploration, development and production activities of most of our customers and their spending on our services. These cuts in spend ing curtailed drilling programs, which resulted in a reduction in the demand for our services, as well as the prices we can charge. These reductions negatively affected our revenue per average active fleet in 2015 and 2016. Although industry conditions improved and activity levels increased from 2017 through the third quarter of 2018, a reduction in customer activity negatively affected our revenue per average active fleet throughout the remainder of 2018 and throughout 2019. In addition, certain of our customers could become unable to pay their vendors and service providers, including us, as a result of a decline in commodity prices. Reduced discovery rates of new oil and natural gas reserves in our areas of operation as a result of decreased capital spending may also have a negative long-term impact on our business, even in an environment of stronger oil and natural gas prices. Any of these conditions or events could adversely affect our operating results. If current activity levels decrease or our customers further reduce their capital spending, it could have a material adverse effect on our liquidity, results of operations and financial condition. 
+Industry conditions are influenced by numerous factors over which we have no control, including: 
+• expected economic returns to E&P companies of new well completions; 
+• domestic and foreign economic conditions and supply of and demand for oil and natural gas; 
+• the level of prices, and expectations about future prices, of oil and natural gas; 
+• the level of global oil and natural gas exploration and production; 
+• the level of domestic and global oil and natural gas inventories; 
+• the supply of and demand for hydraulic fracturing services and equipment in the United States; 
+• federal, tribal, state and local laws, regulations and taxes, including the policies of governments regarding hydraulic fracturing and oil and natural gas exploration, development and production activities as well as non-U.S. governmental regulations and taxes; 
+• governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves; 
+• political and economic conditions in oil and natural gas producing countries; 
+• actions by the members of the Organization of Petroleum Exporting Countries with respect to oil production levels and potential changes in such levels; 
+• global weather conditions and natural disasters; 
+• worldwide political, military and economic conditions; 
+• the cost of producing and delivering oil and natural gas; 
+• lead times associated with acquiring equipment and products and availability of qualified personnel; 
+• the discovery rates of new oil and natural gas reserves; 
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+• stockholder activism or activities by non-governmental organizations to limit certain sources of funding for the energy sector or to restrict the exploration, development and production of oil and natural gas; 
+• the availability of water resources, suitable proppant and chemical additives in sufficient quantities for use in hydraulic fracturing fluids; 
+• advances in exploration, development and production technologies or in technologies affecting energy consumption; 
+• the availability, proximity and capacity of oil and natural gas pipelines and other transportation facilities; 
+• merger and divestiture activity among oil and natural gas producers; 
+• the price and availability of alternative fuels and energy sources; and 
+• uncertainty in capital and commodities markets and the ability of oil and natural gas companies to raise equity capital and debt financing. 
+The volatility of oil and natural gas prices may adversely affect the demand for our hydraulic fracturing services and negatively impact our results of operations. 
+The demand for our hydraulic fracturing services is primarily determined by current and anticipated oil and natural gas prices and the related levels of capital spending and drilling activity in the areas in which we have operations. Volatility or weakness in oil prices or natural gas prices (or the perception that oil prices or natural gas prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells. This, in turn, could lead to lower demand for our services and may cause lower utilization of our assets. We have experienced, and may in the future experience significant fluctuations in operating results as a result of the reactions of our customers to changes in oil and natural gas prices. For example, prolonged low commodity prices experienced by the oil and natural gas industry beginning in late 2014 and uncertainty about future prices even when prices increased, combined with adverse changes in the capital and credit markets, caused many E&P companies to significantly reduce their capital budgets and drilling activity. This resulted in a significant decline in demand for oilfield services and adversely impacted the prices oilfield services companies could charge for their services. 
+Prices for oil and natural gas historically have been extremely volat ile and are expected to continue to be volatile. During the past five years, the posted West Texas Intermediate (“WTI”) price for oil has ranged from a low of $26.19 per barrel (“Bbl”) in February 2016 to a high of $77.41 per Bbl in June 2018. During 2019, WTI prices ranged from $46.31 to $66.24 per Bbl. If the prices of oil and natural gas continue to be volatile, our operations, financial condition, cash flows and level of expenditures may be materially and adversely affected. 
+We may be adversely affected by uncertainty in the global financial markets and the deterioration of the financial condition of our customers. 
+Our future results may be impacted by the uncertainty caused by an economic downturn, volatility or deterioration in the debt and equity capital markets, inflation, deflation or other adverse economic conditions that may negatively affect us or parties with whom we do business resulting in a reduction in our customers’ spending and their non-payment or inability to perform obligations owed to us, such as the failure of customers to honor their commitments or the failure of major suppliers to complete orders. Additionally, during times when the oil or natural gas markets weaken, our customers are more likely to experience financial difficulties, including being unable to access debt or equity financing, which could result in a reduction in our customers’ spending for our services. In addition, in the course of our business we hold accounts receivable from our customers. In the event of the financial distress or bankruptcy of a customer, we could lose all or a portion of such outstanding accounts receivable associated with that customer. For example, during 2019 the Company recorded an allowance for doubtful accounts related a portion of the receivables outstanding from one customer in bankruptcy. Further, if a customer was to enter into bankruptcy, it could also result in the cancellation of all or a portion of our service contracts with such customer at significant expense or loss of expected revenues to us. 
+Our operations are subject to significant risks, some of which are beyond our control. These risks may be self-insured, or may not be fully covered under our insurance policies. 
+Our operations are subject to significant hazards often found in the oil and natural gas industry, such as, but not limited to, accidents, including accidents related to trucking operations provided in connection with our services, blowouts, explosions, craterings, fires, natural gas leaks, oil and produced water spills and releases of hydraulic fracturing fluids or other well fluids into the environment. These conditions can cause: 
+• disruption in operations; 
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+• substantial repair or remediation costs; 
+• personal injury or loss of human life; 
+• significant damage to or destruction of property, and equipment; 
+• environmental pollution, including groundwater contamination; 
+• unusual or unexpected geological formations or pressures and industrial accidents; 
+• impairment or suspension of operations; and 
+• substantial revenue loss. 
+In addition, our operations are subject to, and exposed to, employee/employer liabilities and risks such as wrongful termination, discrimination, labor organizing, retaliation claims and general human resource related matters. 
+The occurrence of a significant event or adverse claim in excess of the insurance coverage that we maintain or that is not covered by insurance could have a material adverse effect on our liquidity, consolidated results of operations and financial condition. Claims for loss of oil and natural gas production and damage to formations can occur in the well services industry. Litigation arising from a catastrophic occurrence at a location where our equipment and services are being used or trucking services provided in connection therewith may result in our being named as a defendant in lawsuits asserting large claims. 
+We do not have insurance against all foreseeable risks, either because insurance is not available or because of the high premium costs. The occurrence of an event not fully insured against or the failure of an insurer to meet its insurance obligations could result in substantial losses. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. Insurance may not be available to cover any or all of the risks to which we are subject, or, even if available, it may be inadequate, or insurance premiums or other costs could rise significantly in the future so as to make such insurance prohibitively expensive. 
+Reliance upon a few large customers may adversely affect our revenue and operating results. 
+Our top five customers represented approximately 35%, 42%, and 53% of our consolidated and combined revenue for the years ended December 31, 2019, 2018 and 2017, respectively. It is likely that we will continue to derive a significant portion of our revenue from a relatively small number of customers in the future. If a major customer fails to pay us, revenue would be impacted and our operating results and financial condition could be materially harmed. Additionally, if we were to lose any material customer, we may not be able to redeploy our equipment at similar utilization or pricing levels or within a short period of time and such loss could have a material adverse effect on our business until the equipment is redeployed at similar utilization or pricing levels. 
+We are exposed to the credit risk of our customers, and any material nonpayment or nonperformance by our customers could adversely affect our financial results. 
+We are subject to the risk of loss resulting from nonpayment or nonperformance by our customers, many of whose operations are concentrated solely in the domestic E&P industry which, as described above, is subject to volatility and, therefore, credit risk. Our credit procedures and policies may not be adequate to fully reduce customer credit risk. If we are unable to adequately assess the creditworthiness of existing or future customers or unanticipated deterioration in their creditworthiness, any resulting increase in nonpayment or nonperformance by them and our inability to re-market or otherwise use our equipment could have a material adverse effect on our business, financial condition, prospects or results of operations. 
+We face intense competition that may cause us to lose market share and could negatively affect our ability to market our services and expand our operations. 
+The oilfield services business is highly competitive. Some of our competitors have a broader geographic scope, greater financial and other resources, or other cost efficiencies. Additionally, there may be new companies that enter our business, or re-enter our business with significantly reduced indebtedness following emergence from bankruptcy, or our existing and potential customers may develop their own hydraulic fracturing business, or direct source proppant, negatively affecting our revenue and potentially resulting in shortfall obligations under some of our supply agreements. Our ability to maintain current revenue and cash flows, and our ability to market our services and expand our operations, could be adversely affected by the activities of our competitors and our customers. If our competitors substantially increase the resources they devote to the development and marketing of competitive services or substantially decrease the prices at which they offer their services, we may be unable to effectively compete. All of these competitive pressures could have a material adverse effect on our business, results of operations and financial condition. Some of our larger competitors provide a broader range of services on a regional, national or worldwide basis. These companies may have a greater ability to continue oilfield service activities during periods of low commodity prices and to absorb the burden of present and future federal, tribal, state, local and other laws and regulations. 
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+Any inability to compete effectively with larger companies could have a material adverse impact on our financial condition and results of operations. 
+Our assets require significant amounts of capital for maintenance, upgrades and refurbishment and may require significant capital expenditures for new equipment. 
+Our hydraulic fracturing fleets and other completion service-related equipment require significant capital investment in maintenance, upgrades and refurbishment to maintain their competitiveness. For example, since January 1, 2011 through December 31, 2019, we have deployed 23 hydraulic fracturing fleets to service customers at a total cost to deploy of approximately $1.0 billion. The costs of components and labor have increased in the past and may increase in the future with increases in demand, which will require us to incur additional costs for any fleets we may acquire in the future. Our fleets and other equipment typically do not generate revenue while they are undergoing maintenance, upgrades or refurbishment. Any maintenance, upgrade or refurbishment project for our assets could increase our indebtedness or reduce cash available for other opportunities. Furthermore, such projects may require proportionally greater capital investments as a percentage of total asset value, which may make such projects difficult to finance on acceptable terms. To the extent we are unable to fund such projects, we may have less equipment available for service or our equipment may not be attractive to potential or current customers. Additionally, competition or advances in technology within our industry may require us to update or replace existing fleets or build or acquire new fleets. Such demands on our capital or reductions in demand for our hydraulic fracturing fleets and the increase in cost of labor necessary for such maintenance and improvement, in each case, could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations and may increase our costs. 
+We rely on certain third parties for proppant and chemical additives, and delays in deliveries of such materials, increases in the cost of such materials or our contractual obligations to pay for materials that we ultimately do not require could harm our business, results of operations and financial condition. 
+We have established relationships with certain suppliers of our raw materials (such as proppant and chemical additives). Should any of our current suppliers be unable to provide the necessary materials or otherwise fail to deliver the materials in a timely manner and in the quantities required, any resulting delays in the provision of services could have a material adverse effect on our business, results of operations and financial condition. Additionally, increasing costs of such materials may negatively impact demand for our services or the profitability of our business operations. In the past, our industry faced sporadic proppant shortages associated with hydraulic fracturing operations requiring work stoppages, which are believed to have adversely impacted the operating results of several competitors. We may not be able to mitigate any future shortages of materials, including proppant. Furthermore, to the extent our contracts require us to purchase more materials, including proppant, than we ultimately require, we may be forced to pay for the excess amount under “take or pay” contract provisions. 
+We currently utilize one preferred assembler and a limited number of suppliers for major equipment to both build new fleets and upgrade any fleets we acquire to our preferred specifications, and our reliance on these vendors exposes us to risks including price and timing of delivery. 
+We currently utilize one preferred assembler and a limited number of suppliers for major equipment to both build our new fleets and upgrade any fleets we may acquire to our custom design. If demand for hydraulic fracturing fleets or the components necessary to build such fleets increases or these vendors face financial distress or bankruptcy, these vendors may not be able to provide the new or upgraded fleets on schedule or at the current price. If this were to occur, we could be required to seek another assembler or other suppliers for major equipment to build or upgrade our fleets, which may adversely affect our revenues or increase our costs. 
+Interruptions of service on the rail lines by which we receive proppant could adversely affect our results of operations. 
+We receive a portion of the proppant used in our hydraulic fracturing services by rail. Rail operations are subject to various risks that may result in a delay or lack of service, including lack of available capacity, mechanical problems, extreme weather conditions, work stoppages, labor strikes, terrorist attacks and operating hazards. Additionally, if we increase the amount of proppant we require for delivery of our services, we may face difficulty in securing rail transportation for such additional amount of proppant. Any delay or failure in the rail services on which we rely could have a material adverse effect on our financial condition and results of operations. 
+Delays or restrictions in obtaining permits by us for our operations or by our customers for their operations could impair our business. 
+In most states, our operations and the operations of our oil and natural gas producing customers require permits from one or more governmental agencies in order to perform drilling and completion activities, secure water rights, or other regulated activities. Such permits are typically issued by state agencies, but federal and local governmental permits may also be required. The requirements for such permits vary depending on the location where such regulated activities will be conducted. As with all 
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+governmental permitting processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit to be issued, and the conditions that may be imposed in connection with the granting of the permit. In addition, some of our customers’ drilling and completion activities may take place on federal land or Native American lands, requiring leases and other approvals from the federal government or Native American tribes to conduct such drilling and completion activities or other regulated activities. Under certain circumstances, federal agencies may cancel proposed leases for federal lands and refuse to grant or delay required approvals. Therefore, our customers’ operations in certain areas of the United States may be interrupted or suspended for varying lengths of time, causing a loss of revenue to us and adversely affecting our results of operations in support of those customers. 
+Federal or state legislative and regulatory initiatives related to induced seismicity could result in operating restrictions or delays in the drilling and completion of oil and natural gas wells that may reduce demand for our services and could have a material adverse effect on our liquidity, combined results of operations and combined financial condition. 
+Our oil and natural gas producing customers dispose of flowback and produced water or certain other oilfield fluids gathered from oil and natural gas producing operations in accordance with permits issued by government authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change based on concerns of the public or governmental authorities regarding such disposal activities. One such concern relates to seismic events near underground disposal wells used for the disposal by injection of flowback and produced water or certain other oilfield fluids resulting from oil and natural gas activities. In 2016, the United States Geological Survey identified six states with more significant rates of induced seismicity that could be attributed to injection of oilfield fluids into underground disposal wells, including Oklahoma, Kansas, Texas, Colorado, New Mexico, and Arkansas. Since that time, the United States Geological Survey indicates that these rates have decreased in these states, although concern continues to exist over quakes arising from induced seismic activities. In response to concerns regarding the use of underground disposal wells and the occurrence of seismic events, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma has issued rules for produced water disposal wells that imposed certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, has developed and implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. The Texas Railroad Commission has adopted similar rules. In late 2016, the Oil and Gas Conservation Division of the OCC and the Oklahoma Geological Survey released well completion seismicity guidance, which requires operators to take certain prescriptive actions, including an operator’s planned mitigation practices, following certain unusual seismic activity within 1.25 miles of hydraulic fracturing operations. In recent years, including during 2018, the OCC’s Oil and Gas Conservation Division issued orders limiting future increases in the volume of oil and natural gas produced water injected belowground into the Arbuckle formation in an effort to reduce the number of earthquakes in the state. Another consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by our customers to dispose of flowback and produced water and certain other oilfield fluids. Increased regulation and attention given to seismicity events suspected of having been induced by injection of oilfield fluids into underground disposal wells also could lead to greater opposition to, and litigation concerning, oil and natural gas activities utilizing injection wells for waste disposal. Any of these developments may result in our customers having to limit disposal well volumes, disposal rates or locations, or require our customers or third party disposal well operators that are used to dispose of customers’ produced water to shut down disposal wells, which developments could adversely affect our customers’ business and result in a corresponding decrease in the need for our services, which could have a material adverse effect on our business, financial condition, and results of operations. 
+Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities may serve to limit future oil and natural gas exploration and production activities and could have a material adverse effect on our results of operations and business. 
+Currently, hydraulic fracturing is generally exempt from regulation under the SDWA UIC program and is typically regulated by state oil and gas commissions or similar agencies. However, federal agencies have conducted investigations or asserted regulatory authority over certain aspects of the process. For example, in late 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. Additionally, the EPA has asserted regulatory authority pursuant to the SDWA’s UIC program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities, as well as published an Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. The EPA also published final CAA regulations in 2012 and 2016 governing performance standards, including standards for the capture of methane and VOC emissions released during oil and natural gas hydraulic fracturing. However, in September 2019, the EPA proposed an amendment to the methane and VOC standards that would remove the methane-specific requirements that currently apply in 
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+favor of relying on the emission limits for VOCs. Moreover, in 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of produced water from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The BLM published a final rule in 2015 that established new or more stringent standards relating to hydraulic fracturing on federal and Native American lands, but the BLM rescinded the 2015 rule in late 2017; however, litigation challenging the BLM’s decision to rescind the 2015 rule remains pending in federal district court. 
+From time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process and with the upcoming presidential election in 2020, hydraulic fracturing has been a frequent topic of the candidates. Certain presidential candidates are advocating for a complete ban on hydraulic fracturing, and one of the candidates, Senator Bernie Sanders (D-VT), introduced a bill in the Senate on January 28, 2020 that, if enacted as proposed, would ban hydraulic fracturing nationwide by 2025. At this time, it remains unclear how a new administration will address hydraulic fracturing. In the event that new federal restrictions relating to the hydraulic fracturing process are adopted in areas where we or our customers conduct business, we or our customers may incur additional costs or permitting requirements to comply with such federal requirements that may be significant and, in the case of our customers, also could result in added restrictions, delays or curtailments in the pursuit of exploration, development, or production activities, which would in turn reduce the demand for our services. 
+Moreover, some states and local governments have adopted, and other governmental entities are considering adopting, regulations that could impose more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations, including states where we or our customers operate. For example, Texas, Colorado and North Dakota among others have adopted regulations that impose new or more stringent permitting, disclosure, disposal, and well construction requirements on hydraulic fracturing operations. States could also elect to place prohibitions on hydraulic fracturing following the approach taken by the States of Maryland, New York and Vermont. Local land use restrictions, such as city ordinances, may also restrict drilling in general and/or hydraulic fracturing in particular. 
+Additionally, certain interest groups in Colorado opposed to oil and natural gas development generally, and hydraulic fracturing in particular, have from time to time advanced various options for ballot initiatives that, if approved, would revise either statutory law or the state constitution in a manner that would effectively prohibit or make such exploration and production activities in the state more difficult or expensive in the future. For example, in each of the November 2014, 2016 and 2018 general election cycles, ballot initiatives have been pursued, with the 2018 initiative making the November 2018 ballot, seeking to increase setback distances between new oil and natural gas development and specific occupied structures and/or certain environmentally sensitive or recreational areas that, if adopted, may have had significant adverse impacts on new oil and natural gas developments in the state. However, in each election cycle thus far, the ballot initiative either did not secure a place on the general ballot or, as was the case in November 2018, was defeated. More recently, despite Colorado’s adoption of SB 181 during 2019, one or more interest groups in the state have already filed new ballot initiatives with the state in January 2020, in hopes of extending drilling setbacks from oil and natural gas development In the event that ballot initiatives or other regulatory programs arising out of protests or opposition by non-governmental organizations are adopted and result in more stringent limitations on the production and development of oil and natural gas in areas where we or our customers conduct operations, whether in Colorado or in another state, we may incur significant costs to comply with such requirements or our customers may experience restrictions, delays or curtailments in the permitting or pursuit of exploration, development, or production activities, which could reduce demand for our services. Such compliance costs or reduced demand for our services could have a material adverse effect on our business, prospects, results of operations, financial conditions, and liquidity. 
+Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to, and litigation concerning, oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays for our customers or increased operating costs in the production of oil and natural gas, including from the developing shale plays, or could make it more difficult for us and our customers to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and natural gas wells and an associated decrease in demand for our services and increased compliance costs and time, which could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition. 
+Colorado SB 181 may have a material adverse impact on new oil and gas development in the state and materially reduce the demand for our hydraulic fracturing services in the state. 
+On April 16, 2019, Governor Jared Polis signed Colorado SB 181, also known as “Protect Public Welfare Oil and Gas Operations” into law. SB 181 has been referred to as an “energy overhaul bill” and includes sweeping oil and gas reform legislation that revises the mission of the Colorado Oil and Gas Conservation Commission (“COGCC”) from fostering oil and natural gas development to regulating oil and natural gas development in a reasonable manner to protect and minimize adverse impacts to public health, safety, and welfare, the environment and wildlife resources, which fundamental change increases industry regulation in the State of Colorado. Although it is still unclear how SB 181 will be practically applied, pursuant to its 
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+text, SB 181 gives localities, such as cities and counties, the authority to regulate the oil and gas development in their area as they do other development to the extent necessary and reasonable to protect public health, safety, welfare and the environment and specifies that local governments have the authority to establish requirements that are more stringent than the state requirements for the industry. This newer increased authority provides local governments with the power to establish stringent setback distances for oil and gas facilities; impose fines for leaks, spills and emissions; and impose fees on operators to cover the reasonably foreseeable direct and indirect costs of permitting and regulation and the costs of any monitoring and inspection program necessary to address the impacts of development. SB 181 also repeals an exemption for oil and gas production from local governments’ authority to regulate noise. Furthermore, SB 181 restructures the Colorado Oil and Gas Conservation Commission (“COGCC”) by reducing the number of oil and gas industry members currently sitting on the COGCC from three members to one and directs the COGCC to revisit its existing rules to consider stricter requirements including pipeline inspection, emissions from pneumatic tools, leak detection and repair, and continuous methane monitoring. Since coming into effect, SB 181 has resulted in more stringent local monitoring of oil and gas operations in certain counties within Colorado in which our customers operate. Passage of this legislation could lead to delays in the state in issuing new drilling permits while the COGCC codifies the new law or reassesses its existing rules. The change in mission of the COGCC requires realignment and reform of the agency’s rules. The COGCC has commenced the process for evaluating the revision of its rules, which may include, among other things, the filing of emergency and tactical response plans upon permit filing, requiring takeaway capacity to minimize flaring, improving mechanical integrity testing requirements, reforming spill reporting, using cumulative impacts in permit review and implementing of cumulative impact noise, odor and other nuisance rules. Public hearings on rulemaking changes are currently expected to begin during the second quarter of 2020. Given the passing of SB 181, our customers in the state, from whom we currently derive a significant portion of our consolidated revenue, may experience material curtailment in the permitting of new exploration, development, or production activities or incur additional fines and increased costs. Any such curtailment or added costs may materially reduce the demand for our hydraulic fracturing services in the state and could have a material adverse effect on our business and results of operations. 
+Changes in transportation regulations may increase our costs and negatively impact our results of operations. 
+We are subject to various transportation regulations including as a motor carrier by the DOT and by various federal, state and tribal agencies, whose regulations include certain permit requirements of highway and safety authorities. These regulatory authorities exercise broad powers over our equipment transportation operations, generally governing such matters as the authorization to engage in motor carrier operations, safety, equipment testing, driver requirements and specifications and insurance requirements. The trucking industry is subject to possible regulatory and legislative changes that may impact our operations, such as changes in fuel emissions limits, hours of service regulations that govern the amount of time a driver may drive or work in any specific period and requiring onboard electronic logging devices or limits on vehicle weight and size. As the federal government continues to develop and propose regulations relating to fuel quality, engine efficiency and GHG emissions, we may experience an increase in costs related to truck purchases and maintenance, impairment of equipment productivity, a decrease in the residual value of vehicles, unpredictable fluctuations in fuel prices and an increase in operating expenses. Additionally, we rely on third parties to provide trucking services, including hauling proppant to our customer work sites, and these third parties may fail to comply with various transportation regulations, resulting in our inability to use such third party providers. Increased truck traffic may contribute to deteriorating road conditions in some areas where our operations are performed. Our operations, including routing and weight restrictions, could be affected by road construction, road repairs, detours and state and local regulations and ordinances restricting access to certain roads. Proposals to increase federal, state or local taxes, including taxes on motor fuels, are also made from time to time, and any such increase would increase our operating costs. Also, state and local regulation of permitted routes and times on specific roadways could adversely affect our operations. We cannot predict whether, or in what form, any legislative or regulatory changes or municipal ordinances applicable to our logistics operations will be enacted and to what extent any such legislation or regulations could increase our costs or otherwise adversely affect our business or operations. 
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+We are subject to environmental and occupational health and safety laws and regulations that may expose us to significant costs and liabilities. 
+Our operations and the operations of our customers are subject to numerous federal, tribal, regional, state and local laws and regulations relating to protection of the environment including natural resources, health and safety aspects of our operations and waste management, including the transportation and disposal of waste and other materials. These laws and regulations may impose numerous obligations on our operations and the operations of our customers, including the acquisition of permits or other approvals to conduct regulated activities, the imposition of restrictions on the types, quantities and concentrations of various substances that may be released into the environment or injected in non-productive formations below ground in connection with oil and natural gas drilling and production activities, the incurrence of capital expenditures to mitigate or prevent releases of materials from our equipment, facilities or from customer locations where we are providing services, the imposition of substantial liabilities for pollution resulting from our operations, and the application of specific health and safety criteria addressing worker protection. Any failure on our part or the part of our customers to comply with these laws and regulations could result in assessment of sanctions including administrative, civil and criminal penalties; imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures; the occurrence of restrictions, delays or cancellations in the permitting, performance or development of projects or operations; and the issuance of orders enjoining performance of some or all of our operations in a particular area. 
+Our business activities present risks of incurring significant environmental costs and liabilities, including costs and liabilities resulting from our handling of oilfield and other wastes, because of air emissions and wastewater discharges related to our operations, and due to historical oilfield industry operations and waste disposal practices. Moreover, accidental releases or spills may occur in the course of our operations or at facilities where our wastes are taken for reclamation or disposal, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for injuries to persons or damages to properties or natural resources. Some environmental laws and regulations may impose strict liability, which means that in some situations we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Remedial costs and other damages arising as a result of environmental laws and costs associated with changes in environmental laws and regulations could be significant and have a material adverse effect on our liquidity, consolidated results of operations and financial condition. 
+Laws and regulations protecting the environment generally have become more stringent in recent years and are expected to continue to do so, which could lead to material increases in costs for future environmental compliance and remediation. New laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement with respect to environmental matters could restrict, delay or curtail exploratory or developmental drilling for oil and natural gas by our customers and could limit our well servicing opportunities. For example, in 2015 the EPA issued a final rule under the CAA, lowering the NAAQS for ground-level ozone from 75 parts per billion to 70 parts per billion under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. Since that time, the EPA issued area designations with respect to ground-level ozone and issued final requirements that apply to state, local, and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone. State implementation of the revised NAAQS could, among other things, require installation of new emission controls on some of our or our customer’s equipment, result in longer permitting timelines, and significantly increase our or our customers’ capital expenditures and operating costs. In another example, in response to a federal consent decree issued in 2016, the EPA was required during 2019 to determine whether certain Subtitle D criteria regulations required revision in a manner that could result in oil and natural gas wastes being regulated as RCRA hazardous wastes. In April 2019, the EPA made a determination that such revision of the regulations was unnecessary. Any future loss of the RCRA exclusion, whereby certain oil and natural gas exploration and production wastes such as drilling fluids, produced waters and related wastes are regulated as hazardous wastes could result in an increase in our, as well as the oil and natural gas industry’s, costs to manage and dispose of generated wastes, which could have a material adverse effect on the industry as well as on our business. We may not be able to recover some or any of our costs of compliance with these laws and regulations from insurance. 
+Silica-related legislation, health issues and litigation could have a material adverse effect on our business, reputation or results of operations. 
+We are subject to laws and regulations relating to human exposure to crystalline silica. For example, in 2016, OSHA published a final rule that established a more stringent permissible exposure limit for exposure to respirable crystalline silica and provided other provisions to protect employees, such as requirements for exposure assessments, methods for controlling exposure, respiratory protection, medical surveillance, hazard communication, and recording. Compliance with most aspects of the 2016 rule relating to hydraulic fracturing was required by June 2018, and the 2016 rule further requires compliance with engineering control obligations to limit exposures to respirable crystalline silica in connection with hydraulic fracturing activities by June 2021. Historically, our environmental compliance costs with respect to existing crystalline silica requirements have not had a material adverse effect on our results of operations; however, federal regulatory authorities, including OSHA, 
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+and analogous state agencies may continue to propose changes in their regulations regarding workplace exposure to crystalline silica, such as permissible exposure limits and required controls and personal protective equipment. We may not be able to comply with any new laws and regulations that are adopted, and any new laws and regulations could have a material adverse effect on our operating results by requiring us to modify or cease our operations. 
+In addition, the inhalation of respirable crystalline silica is associated with the lung disease silicosis. There is evidence of an association between crystalline silica exposure or silicosis and lung cancer and a possible association with other diseases, including immune system disorders such as scleroderma. These health risks have been, and may continue to be, a significant issue confronting the hydraulic fracturing industry. Concerns over silicosis and other potential adverse health effects, as well as concerns regarding potential liability from the use of hydraulic fracture sand, may have the effect of discouraging our customers’ use of our hydraulic fracture sand. The actual or perceived health risks of handling hydraulic fracture sand could materially and adversely affect hydraulic fracturing service providers, including us, through reduced use of hydraulic fracture sand, the threat of product liability or employee lawsuits, increased scrutiny by federal, state and local regulatory authorities of us and our customers or reduced financing sources available to the hydraulic fracturing industry. Furthermore, we may incur additional costs with respect to purchasing specialized equipment designed to reduce exposure to crystalline silica in connection with our operations or invest capital in new equipment. 
+Anti-indemnity provisions enacted by many states may restrict or prohibit a party’s indemnification of us. 
+We typically enter into agreements with our customers governing the provision of our services, which usually include certain indemnification provisions for losses resulting from operations. Such agreements may require each party to indemnify the other against certain claims regardless of the negligence or other fault of the indemnified party; however, many states place limitations on contractual indemnity agreements, particularly agreements that indemnify a party against the consequences of its own negligence. Furthermore, certain states, including Texas, New Mexico and Wyoming, have enacted statutes generally referred to as “oilfield anti-indemnity acts” expressly prohibiting certain indemnity agreements contained in or related to oilfield services agreements. Such anti-indemnity acts may restrict or void a party’s indemnification of us, which could have a material adverse effect on our business, financial condition, prospects and results of operations. 
+Oil and natural gas companies’ operations using hydraulic fracturing are substantially dependent on the availability of water. Restrictions on the ability to obtain water for exploration and production activities and the disposal of flowback and produced water may impact their operations and have a corresponding adverse effect on our business, results of operations and financial condition. 
+Water is an essential component of shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Our oil and natural gas producing customers’ access to water to be used in these processes may be adversely affected due to reasons such as periods of extended drought, privatization, third party competition for water in localized areas or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. The occurrence of these or similar developments may result in limitations being placed on allocations of water due to needs by third party businesses with more senior contractual or permitting rights to the water. Our customers’ inability to locate or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact their exploration and production operations and have a corresponding adverse effect on our business, results of operations and financial condition. 
+Moreover, the imposition of new environmental regulations and other regulatory initiatives could include increased restrictions on our producing customers’ ability to dispose of flowback and produced water generated in hydraulic fracturing or other fluids resulting from exploration and production activities. Applicable laws, including the CWA, impose restrictions and strict controls regarding the discharge of pollutants into waters of the United States and require that permits or other approvals be obtained to discharge pollutants to such waters. In 2015, the EPA and the Corps under the Obama Administration released a final rule outlining their position on the federal jurisdictional reach over waters of the United States, including wetlands. In 2017, the EPA and the Corps under the Trump Administration agreed to reconsider the 2015 rule and, thereafter, on October 22, 2019, the agencies published a final rule made effective on December 23, 2019, rescinding the 2015 rule. On January 23, 2020, the two agencies issued a final rule re-defining the CWA’s jurisdiction over waters of the United States, which redefinition is narrower than found in the 2015 rule. Upon being published in the Federal Register and the passage of 60 days thereafter, the January 23, 2020 final rule will become effective, at which point the United States will be covered under a single regulatory scheme as it relates to federal jurisdictional reach over waters of the United States. However, there remains the expectation that the January 23, 2020 final rule also will be legally challenged in federal district court. To the extent that any challenge to the January 23, 2020 final rule is successful and the 2015 rule or a revised rule expands the scope of the CWA’s jurisdiction in areas where we or our customers conduct operations, we or our customers could incur increased costs and our customers could incur delays or cancellations in permitting or projects, which could reduce demand for our products and services. 
+Additionally, regulations implemented under the CWA and similar state laws prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. 
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+In 2016, the EPA published final regulations concerning produced water discharges from hydraulic fracturing and certain other natural gas operations to publicly-owned wastewater treatment plants. The CWA and analogous state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and hazardous substances. Compliance with current and future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells and any inability to secure transportation and access to disposal wells with sufficient capacity to accept all of our flowback and produced water on economic terms may increase our customers’ operating costs and could result in restrictions, delays, or cancellations of our customers’ operations, the extent of which cannot be predicted. 
+Fuel conservation measures could reduce demand for oil and natural gas which would in turn reduce the demand for our services. 
+Fuel conservation measures, alternative fuel requirements and increasing consumer demand for alternatives to oil and natural gas could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas may have a material adverse effect on our business, financial condition, prospects, results of operations and cash flows. Additionally, the increased competitiveness of alternative energy sources (such as wind, solar geothermal, tidal, and biofuels) could reduce demand for hydrocarbons and therefore for our services, which would lead to a reduction in our revenues. 
+Our and our customers’ operations are subject to a number of risks arising out of the threat of climate change that could result in increased operating and capital costs, limit the areas in which oil and natural gas production may occur and reduce demand for our hydraulic fracturing services. 
+Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs as well as to restrict or eliminate such future emissions. As a result, our operations as well as the operations of our customers are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHGs. 
+Congress and the EPA, in addition to some state and regional efforts, have in recent years considered legislation or regulations to reduce emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. In the absence of federal GHG-limiting legislations, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources, implement CAA emission standards directing the reduction of methane from certain new, modified, or reconstructed facilities in the oil and natural gas sector, and together with the DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there exists the United Nations-sponsored “Paris Agreement,” which is a non-binding agreement for nations to limit their GHG emissions through individually-determined reduction goals every five years after 2020, although the United States has announced its withdrawal from such agreement, effective November 4, 2020. 
+Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, in the form of pledges made by certain candidates seeking the office of the President of the United States in 2020. Critical declarations made by one or more presidential candidates include proposals to ban hydraulic fracturing of oil and natural gas wells and ban new leases for production of minerals on federal properties. Other actions to oil and natural gas production activities that could be pursued by presidential candidates may include more restrictive requirements for the establishment of pipeline infrastructure or the permitting of liquified natural gas export facilities, as well as the rescission of the United States’ withdrawal from the Paris Agreement in November 2020. Litigation risks are also increasing, as a number of cities, local governments, and other plaintiffs have sought to bring suit against the largest oil and natural gas E&P companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts. 
+There are also increasing financial risks for fossil fuel producers, as stockholders and bondholders currently invested in fossil fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-fossil fuel energy related sectors. Institutional investors who provide financing to fossil fuel energy companies also have become more attentive to sustainability lending practices and some of them may elect not to provide funding for fossil fuel energy companies. Additionally, the lending and investment practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in nature, by environmental activists, 
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+proponents of the international Paris Agreement, and foreign citizenry concerned about climate change not to provide funding for fossil fuel producers. Limitation of investments in and financings for fossil fuel energy re could result in the restriction, delay, or cancellation of drilling programs or development of production activities. 
+The adoption and implementation of any international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for oil and natural gas, which could reduce demand for our products and services. Additionally, political, litigation, and financial risks may result in our customers restricting or cancelling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing their ability to continue to operate in an economic manner, which also could reduce demand for our products and services. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation. Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our operations. 
+Our current and future indebtedness could adversely affect our financial condition. 
+As of February 21, 2020, we had $110.0 million outstanding under our Term Loan Facility and no borrowings outstanding under our ABL Facility (defined herein) with a borrowing base of $194.3 million, except for a letter of credit in the amount of $0.3 million. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements.” 
+Moreover, subject to the limits contained in our ABL Facility and Term Loan Facility (collectively, the “Credit Facilities”), we may incur substantial additional debt from time to time. Any borrowings we may incur in the future would have several important consequences for our future operations, including that: 
+• covenants contained in the documents governing such indebtedness may require us to meet or maintain certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our industry, such as being able to take advantage of acquisition opportunities when they arise; 
+• our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes may be limited; 
+• we may be competitively disadvantaged to our competitors that are less leveraged or have greater access to capital resources; and 
+• we may be more vulnerable to adverse economic and industry conditions. 
+If we incur indebtedness in the future, we may have significant principal payments due at specified future dates under the documents governing such indebtedness. Our ability to meet such principal obligations will be dependent upon future performance, which in turn will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. Our business may not continue to generate sufficient cash flow from operations to repay any incurred indebtedness. If we are unable to generate sufficient cash flow from operations, we may be required to sell assets, to refinance all or a portion of such indebtedness or to obtain additional financing. 
+Our Credit Facilities subject us to financial and other restrictive covenants. These restrictions may limit our operational or financial flexibility and could subject us to potential defaults under our Credit Facilities. 
+Our Credit Facilities subject us to restrictive covenants, including, but not limited to, restrictions on incurring additional debt and certain distributions. Our ability to comply with these financial condition tests can be affected by events beyond our control and we may not be able to do so. 
+The Credit Facilities are not subject to financial covenants unless our liquidity, as defined in the agreements governing the Credit Facilities, drops below a specified level, at which time we will be required to maintain certain fixed charge coverage ratios. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements.” 
+If our liquidity falls below the prescribed level and we are unable to remain in compliance with the financial covenants of our Credit Facilities, then amounts outstanding thereunder may be accelerated and become due immediately. Any such acceleration could have a material adverse effect on our financial condition and results of operations. 
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+Increases in interest rates could adversely impact the price of our shares, our ability to issue equity or incur debt for acquisitions or other purposes. 
+Interest rates on future borrowings, credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our shares, and a rising interest rate environment could have an adverse impact on the price of our shares, our ability to issue equity or incur debt for acquisitions or other purposes. 
+Unsatisfactory safety performance may negatively affect our customer relationships and, to the extent we fail to retain existing customers or attract new customers, adversely impact our revenues. 
+Our ability to retain existing customers and attract new business is dependent on many factors, including our ability to demonstrate that we can reliably and safely operate our business in a manner that is consistent with applicable laws, rules and permits, which legal requirements are subject to change. Existing and potential customers consider the safety record of their third-party service providers to be of high importance in their decision to engage such providers. If one or more accidents were to occur at one of our operating sites, the affected customer may seek to terminate or cancel its use of our equipment or services and may be less likely to continue to use our services, which could cause us to lose substantial revenues. Furthermore, our ability to attract new customers may be impaired if they elect not to engage us because they view our safety record as unacceptable. In addition, it is possible that we will experience multiple or particularly severe accidents in the future, causing our safety record to deteriorate. This may be more likely as we continue to grow, if we experience high employee turnover or labor shortage, or hire inexperienced personnel to bolster our staffing needs. 
+The ESA and MBTA and other restrictions intended to protect certain species of wildlife govern our and our oil and natural gas producing customers’ operations and additional restrictions may be imposed in the future, which constraints could have an adverse impact on our ability to expand some of our existing operations or limit our customers’ ability to develop new oil and natural gas wells. 
+Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife, which may limit our ability to operate in protected areas. Permanent restrictions imposed to protect endangered or threatened species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. 
+For example, the ESA restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the MBTA. To the extent species that are listed under the ESA or similar state laws, or are protected under the MBTA, live in the areas where we or our oil and natural gas producing customers’ operate, our and our customers’ abilities to conduct or expand operations and construct facilities could be limited or be forced to incur material additional costs. Moreover, our customer’s drilling activities may be delayed, restricted or precluded in protected habitat areas or during certain seasons, such as breeding and nesting seasons. Some of our operations and the operations of our customers are located in areas that are designated as habitats for protected species. 
+Moreover, the FWS may make determinations on the listing of species as endangered or threatened under the ESA and litigation with respect to the listing or non-listing of certain species as endangered or threatened may result in more fulsome protections for non-protected or lesser-protected species. For example, in 2015, the FWS decided to list the northern long-eared bat, whose range covers more than two-thirds of the states in the eastern and north-central regions of the U.S., as threatened rather than the more protective designation, endangered. However, a federal court decision issued in January 2020 found that the FWS failed to conduct a sufficient analysis that could have resulted in the bat being declared as endangered and the court remanded the listing decision to the FWS for a new determination on the species’ status. The designation of previously unidentified endangered or threatened species or the re-designation of under protected species could indirectly cause us to incur additional costs, cause our or our oil and natural gas producing customers’ operations to become subject to operating restrictions or bans, and limit future development activity in affected areas. The FWS and similar state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially restrict use of or access to federal, state and private lands. 
+We may have difficulty managing growth of our business, which could adversely affect our financial condition and results of operations. 
+Growth of our business could place a significant strain on our financial, technical, operational and management resources. As we continue to expand the scope of our activities and our geographic coverage through organic growth, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, engineers and other professionals in the oilfield services 
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+industry, could have a material adverse effect on our business, financial condition, results of operations and our ability to successfully or timely execute our business plan. 
+We rely on a few key employees whose absence or loss could adversely affect our business. 
+Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team, including our chief executive officer, chief financial officer and president, could disrupt our operations. We do not have any written employment agreement with our executives at this time. Further, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of any of our key employees. 
+We may be subject to risks in connection with acquisitions. 
+We have completed and may, in the future, pursue asset acquisitions or acquisitions of businesses. The process of upgrading acquired assets to our specifications and integrating acquired assets or businesses may involve unforeseen costs and delays or other operational, technical and financial difficulties and may require a significant amount time and resources. Our failure to incorporate acquired assets, personnel or businesses into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations. Such events could also mean an acquisition that we expected to be accretive is not accretive and, in extreme cases, is detrimental to our financial condition or results of operations. 
+Our industry overall has experienced a high rate of employee turnover. Any difficulty we experience replacing or adding personnel could have a material adverse effect on our liquidity, results of operations and financial condition. 
+We are dependent upon the available labor pool of skilled employees and may not be able to find enough skilled labor to meet our needs, which could have a negative effect on our growth. We are also subject to the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions. Our services require skilled workers who can perform physically demanding work. As a result of our industry volatility, including pronounced declines in drilling activity, as well as the demanding nature of the work, many workers have left the hydraulic fracturing industry to pursue employment in different fields. Though our historical turnover rates have been significantly lower than those of our competitors, if we are unable to retain or meet growing demand for skilled technical personnel, our operating results and our ability to execute our growth strategies may be adversely affected. 
+Technology advancements in well service technologies, including those involving hydraulic fracturing, could have a material adverse effect on our business, financial condition and results of operations. 
+The hydraulic fracturing industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As competitors and others use or develop new technologies or technologies comparable to ours in the future, we may lose market share or be placed at a competitive disadvantage. Further, we may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of our competitors may have greater financial, technical and personnel resources than we do, which may allow them to gain technological advantages or implement new technologies before we can. Additionally, we may be unable to implement new technologies or services at all, on a timely basis or at an acceptable cost. New technology could also make it easier for our customers to vertically integrate their operations, thereby reducing or eliminating the need for our services. Limits on our ability to effectively use or implement new technologies may have a material adverse effect on our business, financial condition and results of operations. 
+We may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition, prospects and results of operations. 
+Our services are subject to inherent risks that can cause personal injury or loss of life, damage to or destruction of property, equipment or the environment or the suspension of our operations. Litigation arising from operations where our services are provided, may cause us to be named as a defendant in lawsuits asserting potentially large claims including claims for exemplary damages. We maintain what we believe is customary and reasonable insurance to protect our business against these potential losses, but such insurance may not be adequate to cover our liabilities, and we are not fully insured against all risks. 
+In addition, our customers assume responsibility for, including control and removal of, all other pollution or contamination which may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling and completion fluids. We may have liability in such cases if we are grossly negligent or commit willful acts. Our customers generally agree to indemnify us against claims arising from their employees’ personal injury or death to the extent that, in the case of our hydraulic fracturing operations, their employees are injured by such operations, unless resulting 
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+from our gross negligence or willful misconduct. Our customers also generally agree to indemnify us for loss or destruction of customer-owned property or equipment. In turn, we agree to indemnify our customers for loss or destruction of property or equipment we own and for liabilities arising from personal injury to or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. However, we might not succeed in enforcing such contractual liability allocation or might incur an unforeseen liability falling outside the scope of such allocation. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operation. 
+Seasonal weather conditions, natural disasters, public health crises, and other catastrophic events outside of our control could severely disrupt normal operations and harm our business. 
+Our operations are located in different regions of the United States. Some of these areas, including the DJ Basin, Powder River Basin and Williston Basin, are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice or rain, we may be unable to move our equipment between locations, thereby reducing our ability to provide services and generate revenues. The exploration activities of our customers may also be affected during such periods of adverse weather conditions. Additionally, extended drought conditions in our operating regions could impact our ability or our customers’ ability to source sufficient water or increase the cost for such water. As a result, a natural disaster or inclement weather conditions could severely disrupt the normal operation of our business and adversely impact our financial condition and results of operations. Furthermore, if the area in which we operate or the market demand for oil and natural gas is affected by a public health crises, such as the coronavirus, or other similar catastrophic event outside of our control, our business and results of operations could suffer. 
+If we are unable to fully protect our intellectual property rights, we may suffer a loss in our competitive advantage or market share. 
+We do not have patents or patent applications relating to many of our key processes and technology. If we are not able to maintain the confidentiality of our trade secrets, or if our competitors are able to replicate our technology or services, our competitive advantage would be diminished. We also cannot ensure that any patents we may obtain in the future would provide us with any significant commercial benefit or would allow us to prevent our competitors from employing comparable technologies or processes. 
+We may be adversely affected by disputes regarding intellectual property rights of third parties. 
+Third parties from time to time may initiate litigation against us by asserting that the conduct of our business infringes, misappropriates or otherwise violates intellectual property rights. We may not prevail in any such legal proceedings related to such claims, and our products and services may be found to infringe, impair, misappropriate, dilute or otherwise violate the intellectual property rights of others. If we are sued for infringement and lose, we could be required to pay substantial damages and/or be enjoined from using or selling the infringing products or technology. Any legal proceeding concerning intellectual property could be protracted and costly regardless of the merits of any claim and is inherently unpredictable and could have a material adverse effect on our financial condition, regardless of its outcome. 
+If we were to discover that our technologies or products infringe valid intellectual property rights of third parties, we may need to obtain licenses from these parties or substantially re-engineer our products in order to avoid infringement. We may not be able to obtain the necessary licenses on acceptable terms, or at all, or be able to re-engineer our products successfully. If our inability to obtain required licenses for our technologies or products prevents us from selling our products, that could adversely impact our financial condition and results of operations. 
+Additionally, we currently license certain third party intellectual property in connection with our business, and the loss of any such license could adversely impact our financial condition and results of operations. 
+We may be subject to interruptions or failures in our information technology systems. 
+We rely on sophisticated information technology systems and infrastructure to support our business, including process control technology. Any of these systems may be susceptible to outages due to fire, floods, power loss, telecommunications failures, usage errors by employees, computer viruses, cyber-attacks or other security breaches, or similar events. In addition, we recently implemented new enterprise resource planning software (“ERP”) and it is possible that such ERP software may not perform as intended. The failure of any of our information technology systems may cause disruptions in our operations, which could adversely affect our revenues and profitability. 
+We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss. 
+The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain processing activities. For example, we depend on digital technologies to perform many of our services and to process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks, have increased. The U.S. government has 
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+issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems and networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we will likely be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. Our insurance coverage for cyberattacks may not be sufficient to cover all the losses we may experience as a result of such cyberattacks. 
+A terrorist attack or armed conflict could harm our business. 
+The occurrence or threat of terrorist attacks in the United States or other countries, anti-terrorist efforts and other armed conflicts involving the United States or other countries, including continued hostilities in the Middle East, may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all. 
+We engage in transactions with related parties and such transactions present possible conflicts of interest that could have an adverse effect on us. 
+We have entered into a significant number of transactions with related parties and expect to continue to engage in transactions with related parties in the future. Related party transactions create the possibility of conflicts of interest with regard to our management, including that: 
+• we may enter into contracts between us, on the one hand, and related parties, on the other, that are not the result of arm’s-length transactions; 
+• our executive officers and directors that hold positions of responsibility with related parties may be aware of certain business opportunities that are appropriate for presentation to us as well as to such other related parties and may present such business opportunities to such other parties; and 
+• our executive officers and directors that hold positions of responsibility with related parties may have significant duties with, and spend significant time serving, other entities and may have conflicts of interest in allocating time. 
+Such conflicts could cause an individual in our management to seek to advance his or her economic interests or the economic interests of certain related parties above ours. Further, the appearance of conflicts of interest created by related party transactions could impair the confidence of our investors. Our audit committee reviews these transactions. Notwithstanding this, it is possible that a conflict of interest could have a material adverse effect on our liquidity, results of operations and financial condition. 
+Our historical financial statements may not be indicative of future performance. 
+Due to the significant increase in our capacity, our movement into new basins and our acquisitions, comparisons of our current and future operating results with prior periods are difficult. As a result, our limited historical financial performance as the owner of the acquired assets may make it difficult for stockholders to evaluate our business and results of operations to date and to assess our future prospects and viability. Furthermore, as a result of the volatility in the demand for well services and our future implementation of new business initiatives and strategies, our historical results of operations are not necessarily indicative of our ongoing operations and the operating results to be expected in the future. 
+We may record losses or impairment charges related to idle assets or assets that we sell. 
+Prolonged periods of low utilization, changes in technology or the sale of assets below their carrying value may cause us to experience losses. These events could result in the recognition of impairment charges that negatively impact our financial results. Significant impairment charges as a result of a decline in market conditions or otherwise could have a material adverse effect on our results of operations in future periods. 
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+Risks Related to Our Class A Common Stock 
+Liberty Inc. is a holding company. Liberty Inc.’s only material asset is its equity interest in Liberty LLC, and Liberty Inc. is accordingly dependent upon distributions from Liberty LLC to pay taxes, make payments under the TRAs and cover its corporate and other overhead expenses. 
+Liberty Inc. is a holding company and has no material assets other than its equity interest in Liberty LLC. Please see “Item 1. Business—Initial Public Offering and Corporate Reorganization Transaction.” Liberty Inc. has no independent means of generating revenue. To the extent Liberty LLC has available cash, Liberty Inc. intends to cause Liberty LLC to make (i) generally pro rata distributions to its unit holders, including Liberty Inc., in an amount sufficient to allow Liberty Inc. to pay its taxes and to allow it to make payments under the TRAs and (ii) non-pro rata payments to Liberty Inc. to reimburse it for its corporate and other overhead expenses. To the extent that Liberty Inc. needs funds and Liberty LLC or its subsidiaries are restricted from making such distributions or payments under applicable law or regulation or under the terms of any future financing arrangements, or are otherwise unable to provide such funds, Liberty Inc.’s liquidity and financial condition could be materially adversely affected. 
+Moreover, because Liberty Inc. has no independent means of generating revenue, Liberty Inc.’s ability to make payments under the TRAs is dependent on the ability of Liberty LLC to make distributions to Liberty Inc. in an amount sufficient to cover its obligations under the TRAs. This ability, in turn, may depend on the ability of Liberty LLC’s subsidiaries to make distributions to it. The ability of Liberty LLC, its subsidiaries and other entities in which it directly or indirectly holds an equity interest to make such distributions will be subject to, among other things, (i) the applicable provisions of Delaware law (or other applicable jurisdiction) that may limit the amount of funds available for distribution and (ii) restrictions in relevant debt instruments issued by Liberty LLC or its subsidiaries and other entities in which it directly or indirectly holds an equity interest. To the extent that Liberty Inc. is unable to make payments under the TRAs for any reason, such payments will be deferred and will accrue interest until paid. 
+We are subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we are unable to timely comply with Section 404 or if the costs related to compliance are significant, our profitability, stock price, results of operations and financial condition could be materially adversely affected. 
+We are required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”). Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. During 2019, we evaluated our existing controls against the standards adopted by the Committee of Sponsoring Organizations of the Treadway Commission and concluded our internal control over financial reporting was effective as of December 31, 2019. Effective internal controls over financial reporting are necessary for us to provide reliable financial reports and, together with adequate disclosure controls and procedures, are designed to prevent fraud, safeguard our assets and operate successfully as a public company. Any failure to implement required controls, or difficulties encountered in implementing new or improved controls, could cause us to fail to meet our reporting obligations. In addition, any testing by us conducted in connection with Section 404 of the Sarbanes-Oxley Act, or the subsequent testing by our independent registered public accounting firm, may reveal deficiencies in our internal controls over financial reporting that are deemed to be material weaknesses or that may require prospective or retroactive changes to our financial statements or identify other areas for further attention or improvement. Inferior internal controls could also cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our Class A Common Stock. 
+An active, liquid and orderly trading market for our Class A Common Stock may not be maintained, and our stock price may be volatile. 
+Prior to January 2018, our Class A Common Stock was not traded on any market. An active, liquid and orderly trading market for our Class A Common Stock may not be maintained. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. The market price of our Class A Common Stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our Class A Common Stock, you could lose a substantial part or all of your investment in our Class A Common Stock. 
+The following factors could affect our stock price: 
+• quarterly variations in our financial and operating results; 
+• the public reaction to our press releases, our other public announcements and our filings with the SEC; 
+• strategic actions by our competitors; 
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+• changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts; 
+• speculation in the press or investment community; 
+• the failure of specific research analysts to cover our Class A Common Stock; 
+• sales of our Class A Common Stock by us or other stockholders, or the perception that such sales may occur; 
+• changes in accounting principles, policies, guidance, interpretations or standards; 
+• additions or departures of key management personnel; 
+• actions by our stockholders; 
+• general market conditions, including fluctuations in commodity prices; 
+• domestic and international economic, legal and regulatory factors unrelated to our performance; and 
+• the realization of any risks described under this “Risk Factors” section. 
+The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our Class A Common Stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management’s attention and resources and harm our business, operating results and financial condition. 
+The Principal Stockholders collectively hold a significant amount of the voting power of our Common Stock and continue to have influence over us. 
+As of July 11, 2019, Riverstone/Carlyle Energy Partners IV, L.P., R/C IV Liberty Holdings, L.P. and R/C Energy IV Direct Partnership, L.P. (collectively “Riverstone”) and certain of the Legacy Owners (with Riverstone, collectively, the “Principal Stockholders”) no longer controlled a majority of our outstanding Common Stock. As a result, we ceased being a “controlled company” within the meaning of the NYSE rules. Even though the Principal Stockholders no longer control a majority of our Common Stock, the Principal Stockholders continue to have significant influence over us with respect to matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions due to their significant voting power and right to designate nominees to Liberty Inc.’s board of directors (the “Board”). The interests of the Principal Stockholders with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other stockholders. 
+For example, the Principal Stockholders may have different tax positions from us, especially in light of the TRAs, that could influence their decisions regarding whether and when to support the disposition of assets, the incurrence or refinancing of new or existing indebtedness, or the termination of the TRAs and acceleration of our obligations thereunder. In addition, the determination of future tax reporting positions, the structuring of future transactions and the handling of any challenge by any taxing authority to our tax reporting positions may take into consideration the Principal Stockholders tax position or other considerations which may differ from the considerations of us or our other stockholders. For further details of the TRAs, see Note 10—Income Taxes to the consolidated and combined financial statements included in “Item 8. Financial Statements and Supplementary Data.” 
+Furthermore, in connection with the IPO and separately in July 2019, we entered into stockholders’ agreements with the Principal Stockholders and certain Riverstone affiliates, respectively. The stockholders’ agreements provide Riverstone with the right to designate a certain number of nominees to our Board so long as Riverstone and its affiliates collectively beneficially own at least 10% of the outstanding shares of our Class A Common Stock. In addition, the stockholders’ agreements provides Riverstone the right to approve certain material transactions so long as Riverstone and its affiliates own at least 20% of the outstanding shares of our Class A Common Stock. The existence of significant stockholders may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company. Moreover, the Principal Stockholders concentration of stock ownership may adversely affect the trading price of our Class A Common Stock to the extent investors perceive a disadvantage in owning stock of a company with significant stockholders. 
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+Certain of our executive officers and directors have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities. 
+Certain of our executive officers and directors, who are responsible for managing the direction of our operations, hold positions of responsibility with other entities (including affiliated entities) that are in the oil and natural gas industry. For example, Christopher Wright, our Chairman and Chief Executive Officer, is the Executive Chairman of Liberty Resources LLC (“Liberty Resources”), an E&P company operating primarily in the Williston Basin, a position which may require a portion of his time. These executive officers and directors may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, they may present potential business opportunities to other entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated, and as a result, they may elect not to present those opportunities to us. These conflicts may not be resolved in our favor. 
+Riverstone and its respective affiliates are not limited in their ability to compete with us, and the corporate opportunity provisions in our amended and restated certificate of incorporation could enable Riverstone to benefit from corporate opportunities that might otherwise be available to us. 
+Our governing documents provide that Riverstone and its respective affiliates (including portfolio investments of Riverstone and its affiliates) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In particular, subject to the limitations of applicable law, our amended and restated certificate of incorporation, among other things: 
+• permits Riverstone and its respective affiliates to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and 
+• provides that if Riverstone or its respective affiliates, or any employee, partner, member, manager, officer or director of Riverstone or its respective affiliates who is also one of our directors or officers, becomes aware of a potential business opportunity, transaction or other matter, they have no duty to communicate or offer that opportunity to us. 
+Riverstone or its respective affiliates may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Furthermore, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to not be available to us or causing them to be more expensive for us to pursue. In addition, Riverstone and its respective affiliates may dispose of oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase any of those assets. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to time presented to Riverstone and its respective affiliates could adversely impact our business or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours. 
+Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A Common Stock and could deprive our investors of the opportunity to receive a premium for their shares. 
+Our amended and restated certificate of incorporation authorizes the Board to issue preferred stock without stockholder approval in one or more series, designate the number of shares constituting any series, and fix the rights, preferences, privileges and restrictions thereof, including dividend rights, voting rights, rights and terms of redemption, redemption price or prices and liquidation preferences of such series. If the Board elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders. These provisions include: 
+• division of the Board into three classes of directors, with each class serving staggered three-year terms; 
+• subject to the terms of our stockholders’ agreements, all vacancies, including newly created directorships, may, except as otherwise required by law or, if applicable, the rights of holders of a series of preferred stock, only be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum; 
+• permitting any action by stockholders to be taken only at an annual meeting or special meeting rather than by a written consent of the stockholders, subject to the rights of any series of preferred stock with respect to such rights; 
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+• permitting special meetings of our stockholders to be called only by our Chief Executive Officer, the chairman of the Board and the Board pursuant to a resolution adopted by the affirmative vote of a majority of the total number of authorized directors whether or not there exist any vacancies in previously authorized directorships; 
+• subject to the rights of the holders of shares of any series of our preferred stock and the terms of our stockholders’ agreements, requiring the affirmative vote of the holders of at least 66 2⁄3% in voting power of all then outstanding Common Stock entitled to vote generally in the election of directors, voting together as a single class, to remove any or all of the directors from office at any time, and directors will be removable only for “cause”; 
+• prohibiting cumulative voting in the election of directors; 
+• establishing advance notice provisions for stockholder proposals and nominations for elections to the Board to be acted upon at meetings of stockholders; and 
+• providing that the Board is expressly authorized to adopt, or to alter or repeal our bylaws. 
+In addition, certain change of control events have the effect of accelerating the payments due under the TRAs, which could be substantial and accordingly serve as a disincentive to a potential acquirer of our Company. Please see “—In certain cases, payments under the TRAs may be accelerated and/or significantly exceed the actual benefits, if any, Liberty Inc. realizes in respect of the tax attributes subject to the TRAs.” 
+Our amended and restated certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents. 
+Our amended and restated certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim against us or any director or officer or other employee of ours arising pursuant to any provision of the Delaware General Corporation Law, our amended and restated certificate of incorporation or our bylaws, or (iv) any action asserting a claim against us or any director or officer or other employee of ours that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our Common Stock will be deemed to have notice of, and consented to, the provisions of our amended and restated certificate of incorporation described in the preceding sentence. The exclusive forum provision would not apply to suits brought to enforce any liability or duty created by the Securities Act or the Exchange Act or any other claim for which the federal courts have exclusive jurisdiction. To the extent that any such claims may be based upon federal law claims, Section 27 of the Exchange Act creates exclusive federal jurisdiction over all suits brought to enforce any duty or liability created by the Exchange Act or the rules and regulations thereunder. Furthermore, Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules and regulations thereunder. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons.The enforceability of similar choice of forum provisions in other companies’ certificates of incorporation or similar governing documents has been challenged in legal proceedings, and it is possible that a court could find the choice of forum provisions contained in our amended and restated certificate of incorporation to be inapplicable or unenforceable, including with respect to claims arising under the U.S. federal securities laws. If a court were to find these provisions of our amended and restated certificate of incorporation inapplicable to, or unenforceable, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations. 
+If a substantial number of shares of Class A Common Stock becomes available for sale and are sold in a short period of time, the market price of our Class A Common Stock could decline and our stockholders may be diluted. 
+If our Principal Stockholders sell substantial amounts of our Class A Common Stock in the public market, the market price of our Class A Common Stock could decrease. The perception in the public market that our Principal Stockholders might sell shares of our Class A Common Stock could also create a perceived overhang and depress our market price. Our Legacy Owners, which includes the Principal Stockholders, hold Liberty LLC Units and shares of our Class B Common Stock which were exchangeable for an additional 30,638,960 shares of Class A Common Stock as of December 31, 2019. In addition, our Principal Stockholders, have substantial demand and incidental registration rights for their shares. 
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+Future sales or issuances of our Class A Common Stock in the public market, or the perception that such sales may occur, could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us. 
+We may sell additional shares of Class A Common Stock in subsequent public offerings. We may also issue additional shares of Class A Common Stock or convertible securities. At February 21, 2020, we had 81,920,347 shares of Class A Common Stock issued and outstanding. The Liberty Unit Holders are party to a registration rights agreement, which requires us to effect the registration of any shares of Class A Common Stock that they receive in exchange for their Liberty LLC Units in certain circumstances. 
+We have 12,580,935 shares of our Class A Common Stock authorized for issuance under our long term incentive plan, including up to 2,393,089 shares reserved for issuance upon the vesting of granted but unvested restricted and performance units. Subject to the satisfaction of vesting conditions and the requirements of Rule 144, shares registered under the registration statement on Form S-8 may be made available for resale immediately in the public market without restriction. 
+We cannot predict the size of future issuances of our Class A Common Stock or securities convertible into Class A Common Stock or the effect, if any, that future issuances and sales of shares of our Class A Common Stock will have on the market price of our Class A Common Stock. Sales of substantial amounts of our Class A Common Stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A Common Stock. 
+Liberty Inc. is required to make payments under the TRAs for certain tax benefits that it may claim, and the amounts of such payments could be significant. 
+The TRAs generally provide for the payment by Liberty Inc. to each TRA Holder of 85% of the net cash savings, if any, in U.S. federal, state and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that Liberty Inc. actually realizes (or is deemed to realize in certain circumstances) as a result of certain increases in tax basis, net operating losses available to Liberty Inc. as a result of the Corporate Reorganization, and certain benefits attributable to imputed interest. Liberty Inc. will retain the benefit of the remaining 15% of these cash savings. 
+The term of each of the TRAs continues until all tax benefits that are subject to such TRAs have been utilized or expired, unless Liberty Inc. experiences a change of control (as defined in the TRAs, which includes certain mergers, asset sales and other forms of business combinations) or the TRAs are terminated early (at Liberty Inc.’s election or as a result of its breach), and Liberty Inc. makes the termination payments specified in such TRAs. In addition, payments Liberty Inc. makes under the TRAs will be increased by any interest earned from the due date (without extensions) of the corresponding tax return. Payments under the TRAs commenced in 2020 and so long as the TRAs are not terminated, are anticipated to continue for 15 years after the date of the last redemption of the Liberty LLC Units. 
+The payment obligations under the TRAs are Liberty Inc.’s obligations and not obligations of Liberty LLC, and Liberty Inc. expects that the payments Liberty Inc. will be required to make under the TRAs will be substantial. Estimating the amount and timing of payments that may become due under the TRAs is by its nature imprecise. For purposes of the TRAs, cash savings in tax generally are calculated by comparing Liberty Inc.’s actual tax liability (determined by using the actual applicable U.S. federal income tax rate and an assumed combined state and local income tax rate) to the amount it would have been required to pay had it not been able to utilize any of the tax benefits subject to the TRAs. The amounts payable, as well as the timing of any payments, under the TRAs are dependent upon significant future events and assumptions, including the timing of the redemptions of Liberty LLC Units, the price of our Class A Common Stock at the time of each redemption, the extent to which such redemptions are taxable transactions, the amount of the redeeming unit holder’s tax basis in its Liberty LLC Units at the time of the relevant redemption, the depreciation and amortization periods that apply to the increase in tax basis, the amount of net operating losses available to Liberty Inc. as a result of the Corporate Reorganization, the amount and timing of taxable income Liberty Inc. generates in the future, the U.S. federal income tax rate then applicable, and the portion of Liberty Inc.’s payments under the TRAs that constitute imputed interest or give rise to depreciable or amortizable tax basis. 
+The payments under the TRAs will not be conditioned upon a holder of rights under each of the TRAs having a continued ownership interest in Liberty Inc. or Liberty LLC. For further details of the TRAs, see Note 10 —Income Taxes to the consolidated and combined financial statements included in “Item 8. Financial Statements and Supplementary Data.” 
+In certain cases, payments under the TRAs may be accelerated and/or significantly exceed the actual benefits, if any, Liberty Inc. realizes in respect of the tax attributes subject to the TRAs. 
+If Liberty Inc. experiences a change of control (as defined under the TRAs, which includes certain mergers, asset sales and other forms of business combinations) or the TRAs terminate early (at Liberty Inc.’s election or as a result of its breach), Liberty Inc. would be required to make a substantial, immediate lump-sum payment. This payment would equal the present value of hypothetical future payments that could be required to be paid under the TRAs (determined by applying a discount rate 
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+equal to the long-term Treasury rate in effect on the applicable date plus 300 basis points). The calculation of hypothetical future payments will be based upon certain assumptions and deemed events set forth in the TRAs, including (i) that Liberty Inc. has sufficient taxable income to fully utilize the tax benefits covered by the TRAs, (ii) that any Liberty LLC Units (other than those held by Liberty Inc.) outstanding on the termination date are deemed to be redeemed on the termination date, and (iii) certain loss or credit carryovers will be utilized over five years beginning with the taxable year that includes the termination date. Any early termination payments may be made significantly in advance of, and may materially exceed, the actual realization, if any, of the future tax benefits to which the termination payments relate. 
+If Liberty Inc. experiences a change of control (as defined under the TRAs) or the TRAs otherwise terminate early, Liberty Inc.’s obligations under the TRAs could have a substantial negative impact on its liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. For example, if the TRAs were terminated at December 31, 2019, the estimated termination payments would, in the aggregate, be approximately $79.0 million (calculated using a discount rate equal to the long-term Treasury rate in effect on the applicable date plus 300 basis points, applied against an estimated undiscounted liability of $104.0 million). The foregoing number is merely an estimate and the actual payment could differ materially. There can be no assurance that we will be able to finance our obligations under the TRAs. 
+For further details of the TRAs, see Note 10 —Income Taxes to t he consolidated and combined financial statements included in “Item 8. Financial Statements and Supplementary Data.” 
+In the event that Liberty Inc. ’ s payment obligations under the TRAs are accelerated upon certain mergers, other forms of business combinations or other changes of control, the consideration payable to holders of our Class A Common Stock could be substantially reduced. 
+If Liberty Inc. experiences a change of control (as defined under the TRAs, which includes certain mergers, asset sales and other forms of business combinations), Liberty Inc. would be obligated to make a substantial, immediate lump-sum payment, and such payment may be significantly in advance of, and may materially exceed, the actual realization, if any, of the future tax benefits to which the payment relates. As a result of this payment obligation, holders of our Class A Common Stock could receive substantially less consideration in connection with a change of control transaction than they would receive in the absence of such obligation. Further, our payment obligations under the TRAs will not be conditioned upon the TRA Holders’ having a continued interest in Liberty Inc. or Liberty LLC. Accordingly, the TRA Holders’ interests may conflict with those of the holders of our Class A Common Stock. Please read “Risk Factors—Risks Related to our Class A Common Stock—In certain cases, payments under the TRAs may be accelerated and/or significantly exceed the actual benefits Liberty Inc. realizes, if any, in respect of the tax attributes subject to the TRAs” and Note 10—Income Taxes to the consolidated and combined financial statements included in “Item 8. Financial Statements and Supplementary Data.” 
+We will not be reimbursed for any payments made under the TRAs in the event that any tax benefits are subsequently disallowed. 
+Payments under the TRAs are based on the tax reporting positions that we will determine. The TRA Holders will not reimburse us for any payments previously made under the TRAs if any tax benefits that have given rise to payments under the TRAs are subsequently disallowed, except that excess payments made to any TRA Holder will be netted against payments that would otherwise be made to such TRA Holder, if any, after our determination of such excess. As a result, in such circumstances, Liberty Inc. could make payments that are greater than its actual cash tax savings, if any, and may not be able to recoup those payments, which could adversely affect Liberty Inc.’s liquidity. 
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+If Liberty LLC were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, Liberty Inc. and Liberty LLC might be subject to potentially significant tax inefficiencies, and Liberty Inc. would not be able to recover payments previously made by it under the TRAs even if the corresponding tax benefits were subsequently determined to have been unavailable due to such status. 
+Liberty Inc. intends to operate such that Liberty LLC does not become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes. A “publicly traded partnership” is a partnership the interests of which are traded on an established securities market or are readily tradable on a secondary market or the substantial equivalent thereof. Under certain circumstances, redemptions of Liberty LLC Units pursuant to the Redemption Right, Liberty Inc.’s Call Right or other transfers of Liberty LLC Units could cause Liberty LLC to be treated as a publicly traded partnership. Applicable U.S. Treasury regulations provide for certain safe harbors from treatment as a publicly traded partnership, and Liberty Inc. intends to operate such that redemptions or other transfers of Liberty LLC Units qualify for one or more such safe harbors. For example, Liberty Inc. intends to limit the number of unit holders of Liberty LLC, and the Liberty LLC Agreement, which was entered into in connection with the closing of the IPO, provides for limitations on the ability of holders of Liberty LLC Units to transfer their Liberty LLC Units and provides Liberty Inc., as managing member of Liberty LLC, with the right to impose restrictions (in addition to those already in place) on the ability of holders of Liberty LLC Units to redeem their Liberty LLC Units pursuant to the Redemption Right to the extent Liberty Inc. believes it is necessary to ensure that Liberty LLC will continue to be treated as a partnership for U.S. federal income tax purposes. 
+If Liberty LLC were to become a publicly traded partnership, significant tax inefficiencies might result for Liberty Inc. and for Liberty LLC, including as a result of Liberty Inc.’s inability to file a consolidated U.S. federal income tax return with Liberty LLC. In addition, Liberty Inc. would no longer have the benefit of certain increases in tax basis covered under the TRAs, and Liberty Inc. would not be able to recover any payments previously made by it under the TRAs, even if the corresponding tax benefits (including any claimed increase in the tax basis of Liberty LLC’s assets) were subsequently determined to have been unavailable. 
+In certain circumstances, Liberty LLC is required to make tax distributions and tax advances to the Liberty Unit Holders, including us, and the tax distributions and tax advances that Liberty LLC is required to make may be substantial. 
+Pursuant to the Liberty LLC Agreement, Liberty LLC makes generally pro rata cash distributions, or tax distributions, to the holders of Liberty LLC Units, including Liberty Inc., in an amount sufficient to allow Liberty Inc. to pay its taxes and to allow it to make payments under the TRAs. In addition to these pro rata distributions, the Liberty Unit Holders are entitled to receive tax advances in an amount sufficient to allow each of the Liberty Unit Holders to pay its respective taxes on such holder’s allocable share of Liberty LLC’s taxable income. Any such tax advance is calculated after taking into account certain other distributions or payments received by the Liberty Unit Holders from Liberty LLC or Liberty Inc. Under the applicable tax rules, Liberty LLC is required to allocate net taxable income disproportionately to its members in certain circumstances. Tax advances are determined based on an assumed individual tax rate and are repaid upon exercise of the Redemption Right or the Call Right, as applicable. 
+Funds used by Liberty LLC to satisfy its tax distribution and tax advance obligations are not available for reinvestment in our business. Moreover, the tax distributions and tax advances Liberty LLC is required to make may be substantial, and is likely to exceed (as a percentage of Liberty LLC’s income) the overall effective tax rate applicable to a similarly situated corporate taxpayer. In addition, because these payments are calculated with reference to an assumed tax rate, and because of the disproportionate allocation of net taxable income, these payments may exceed the actual tax liability for some of the holders of Liberty LLC Units. 
+We may issue preferred stock whose terms could adversely affect the voting power or value of our Class A Common Stock. 
+Our amended and restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A Common Stock respecting dividends and distributions, as the Board may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our Class A Common Stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the Class A Common Stock. 
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+If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our Class A Common Stock or if our operating results do not meet their expectations, our stock price could decline. 
+The trading market for our Class A Common Stock may be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of the Company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover the Company downgrades our Class A Common Stock or if our operating results do not meet their expectations, our stock price could decline. 
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+Item 1B. Unresolved Staff Comments 
+None. 
+Item 2. Properties 
+Information regarding our properties is contained in “Item 1. Business” and is incorporated by reference herein. 
+Item 3. Legal Proceedings 
+We are named defendants in certain lawsuits, investigations and claims arising in the ordinary course of conducting our business, including certain environmental claims and employee-related matters, and we expect that we will be named defendants in similar lawsuits, investigations and claims in the future. While the outcome of these lawsuits, investigations and claims cannot be predicted with certainty, we do not expect these matters to have a material adverse impact on our business, results of operations, cash flows or financial condition. We have not assumed any liabilities arising out of these existing lawsuits, investigations and claims. 
+Item 4. Mine Safety Disclosures 
+Not applicable. 
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+PART II 
+Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+Market Information 
+On January 17, 2018, we consummated an initial public offering of our Class A Common Stock at a price of $17.00 per share. Our Class A Common Stock is traded on the NYSE under the symbol “LBRT.” Prior to that time, there was no public market for our Class A Common Stock. There is no public market for our Class B Common Stock. 
+Holders of our Common Stock 
+As of February 21, 2020, there were 39 stockholders of record of our Class A Common Stock and 10 stockholders of record of our Class B Common Stock. The number of record holders is based upon the actual number of holders registered on the books of the Company at such date and does not include holders of shares in “street names” or persons, partnerships, associations, corporations or other entities identified in security position listings maintained by depositories. 
+Dividend Policy 
+The Company paid quarterly cash dividends of $ 0.05 per share of Class A Common Stock on March, June, September and December 20, 2019 to shareholders of record as of March, June, September and December 6, 2019, respectively. The declaration of dividends is subject to approval by the Board and to the Board’s continuing determination that such declaration of dividends is in the best interests of the Company and its stockholders. Future dividends may be adjusted at the Board’s discretion based on market conditions and capital availability. We are not required to pay dividends, and our stockholders will not be guaranteed, or have contractual or other rights to receive, dividends. 
+Recent Sales of Unregistered Equity Securities 
+We had no sales of unregistered equity securities during the period covered by this Annual Report on Form 10-K that were not previously reported in a Current Report on Form 8-K. 
+Purchase of Equity Securities By the Issuer and Affiliated Purchasers 
+On September 10, 2018 the Board authorized a share repurchase plan to repurchase up to $ 100.0 million of the Company’s Class A Common Stock through September 30, 2019. On January 22, 2019, the Board authorized an additional $ 100.0 million under the share repurchase plan through January 31, 2021. During the year ended December 31, 2019, Liberty LLC redeemed and retired 1,303,003 Liberty LLC Units from the Company for $18.4 million, and the Company repurchased and retired 1,303,003 shares of Class A Common Stock for $18.4 million, or $ 14.66 average price per share. The share repurchase plan authorized on September 10, 2018 was completed in January 2019. Of the total amount of Class A Common Stock repurchased, 117,647 shares were repurchased from R/C Energy IV Direct Partnership, L.P., R/C IV Liberty Holdings, L.P., and Riverstone/Carlyle Energy Partners IV, L.P. (“R/C” and collectively, the “Riverstone Sellers”). For further details of this related party transaction, see Note 12—Related Party Transactions to the consolidated and combined financial statements included in “Item 8. Financial Statements and Supplementary Data.” 
+The Company accounts for the purchase price of repurchased Class A Common Stock in excess of par value ($0.01 per share of Class A Common Stock) as a reduction of additional paid-in capital, and will continue to do so until additional paid-in capital is reduced to zero. Thereafter, any excess purchase price will be recorded as a reduction to retained earnings. 
+As of December 31, 2019, $ 98.7 million remains authorized for future repurchases of Class A Common Stock under the share repurchase program. 
+We did not purchase any shares of our Class A Common Stock during the three months ended December 31, 2019. 
+39 
+Table of Contents 
+Stock Performance Graph 
+The following graph and table compares the cumulative total return on our Class A Common Stock with the cumulative total return on the Standard & Poor’s 500 ® Index and the Philadelphia Oil Service Index, since January 12, 2018, the first day on which shares of our Common Stock issued in our IPO commenced trading on the NYSE and each fiscal quarter thereafter through December 31, 2019. The graph assumes that $100 was invested in our Class A Common Stock in each index on January 12, 2018 and that any dividends were reinvested. The cumulative total return set forth is not necessarily indicative of future performance. 
+The following graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that we specifically incorporate it by reference into such filing. 
+For Year Ended 2018 For Year Ended 2019 
+January 
+12, March 
+31, June 
+30, September 
+30, December 
+31, March 
+31, June 
+30, September 
+30, December 
+31, 
+Liberty Oilfield Services, Inc. $ 100.00 $ 77.66 $ 86.07 $ 99.40 $ 59.91 $ 71.43 $ 75.33 $ 50.65 $ 52.24 
+Standard & Poor’s 500 ® Index 100.00 94.78 97.56 104.58 89.97 101.73 105.58 106.84 115.95 
+Philadelphia Oil Service Index 100.00 82.65 94.34 91.05 49.10 57.70 49.55 39.90 47.69 
+40 
+Table of Contents 
+Item 6. Selected Consolidated Financial Data 
+The selected financial data set forth below was derived from our audited consolidated and combined financial statements and should be read in conjunction with “Item 1A. Risk Factors,” “Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations” and our audited consolidated and combined financial statements included in “Item 8. Financial Statements and Supplementary Data.” 
+41 
+Table of Contents 
+Years Ended 
+December 31, 
+2019 2018 2017 2016 2015 
+(in thousands, except per share and fleet data) 
+Statement of Operations Data: 
+Revenue: 
+Revenue $ 1,972,073 $ 2,132,032 $ 1,465,133 $ 356,890 $ 384,330 
+Revenue—related parties 18,273 23,104 24,722 17,883 71,074 
+Total revenue 1,990,346 2,155,136 1,489,855 374,773 455,404 
+Operating costs and expenses: 
+Cost of services (exclusive of depreciation and amortization shown separately below) 1,621,180 1,628,753 1,147,008 354,729 393,340 
+General and administrative 97,589 99,052 80,089 35,789 28,765 
+Depreciation and amortization 165,379 125,110 81,473 41,362 36,436 
+(Gain) loss on disposal of assets 2,601 (4,342) 148 (2,673) 423 
+Total operating costs and expenses 1,886,749 1,848,573 1,308,718 429,207 458,964 
+Operating income (loss) 103,597 306,563 181,137 (54,434) (3,560) 
+Other expense: 
+Interest expense, net of interest income 16,502 17,145 11,875 6,126 5,501 
+Interest (income) expense—related party (1,821) — 761 — — 
+Total interest expense 14,681 17,145 12,636 6,126 5,501 
+Net income (loss) before income taxes 88,916 289,418 168,501 (60,560) (9,061) 
+Income tax expense 14,052 40,385 — — — 
+Net income (loss) 74,864 249,033 168,501 (60,560) (9,061) 
+Less: Net income (loss) attributable to Predecessor, prior to Corporate Reorganization — 8,705 168,501 (60,560) (9,061) 
+Less: Net income attributable to non-controlling interests 35,861 113,979 — — — 
+Net income attributable to Liberty Oilfield Services Inc. stockholders $ 39,003 $ 126,349 $ — $ — $ — 
+Net Income Per Share Data (1): 
+Net income attributable to Liberty Oilfield Services Inc. stockholders per common share 
+Basic $ 0.54 $ 1.84 
+Diluted $ 0.53 $ 1.81 
+Weighted average common shares outstanding 
+Basic 72,334 68,838 
+Diluted (2) 105,256 117,838 
+Statement of Cash Flows Data: 
+Cash flows provided by (used in) operating activities $ 261,100 $ 351,258 $ 195,109 $ (40,708) $ 6,119 
+Cash flows used in investing activities 194,347 255,492 310,043 96,351 38,492 
+Cash flows (used in) provided by financing activities (57,375) (8,775) 119,771 148,543 21,485 
+Other Financial Data: 
+Capital expenditures $ 195,173 $ 258,835 $ 311,794 $ 102,428 $ 38,492 
+EBITDA (3) $ 268,976 $ 431,673 $ 262,610 $ (13,072) $ 32,876 
+Adjusted EBITDA (3) $ 277,149 $ 438,234 $ 280,728 $ (5,588) $ 41,213 
+Total Fleets at beginning of period (4) 22 19 10 6 5 
+Total Fleets at end of period (4) 23 22 19 10 6 
+Average Active Fleets (5) 22.8 21.3 15.1 7.4 5.9 
+Adjusted EBITDA per Average Active Fleet (6) $ 12,156 $ 20,574 $ 18,591 $ (755) $ 6,985 
+Balance Sheet Data (at end of period): 
+Total assets $ 1,283,429 $ 1,116,501 $ 852,103 $ 451,845 $ 296,971 
+Long-term debt (including current portion) 106,140 106,524 196,357 103,805 110,232 
+Total liabilities 501,937 375,687 416,851 222,873 162,920 
+Redeemable common units (7) — — 42,486 — — 
+Total equity or member equity 781,492 740,814 392,766 228,972 134,051 
+Cash dividends declared per share of Class A Common Stock $ 0.20 $ 0.10 
+42 
+Table of Contents 
+(1) Net Income Per Share Data above reflects the net income to Class A Common Stock and net income per share for the period indicated based on a weighted average number of Class A Common Stock outstanding for period subsequent to the Corporate Reorganization on January 17, 2018. 
+(2) In accordance with GAAP, diluted weighted average common shares outstanding for the year ended December 31, 2019, excludes the weighted average shares of Class B Common Stock (9,057) exchanged during the period (share counts presented in 000’s). 
+(3) EBITDA and Adjusted EBITDA are non-GAAP financial measures. For definitions of EBITDA and Adjusted EBITDA and a reconciliation of each to our most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Item 7. Management's Discussion and Analysis of Financial Conditions and Results of Operations—Comparison of Non-GAAP Financial Measures.” 
+(4) Total Fleets represents the number of deployed and active fleets as of the designated date. 
+(5) Average Active Fleets is calculated as the daily average of the active fleets for the period presented. 
+(6) Adjusted EBITDA per Average Active Fleet is calculated as Adjusted EBITDA for the period divided by the Average Active Fleets, as defined above. 
+(7) The redeemable common units were deemed extinguished and satisfied in full in the Corporate Reorganization. 
+43 
+Table of Contents 
+Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Item 6. Selected Financial Data” and our audited consolidated and combined financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a variety of risks and uncertainties, including those described in this Annual Reporting on Form 10-K under “Cautionary Note Regarding Forward-Looking Statements” and “Item 1A. Risk Factors.” We assume no obligation to update any of these forward-looking statements. This section of this Annual Report on Form 10-K generally discusses 2019 and 2018 items and year-to-year comparisons between 2019 and 2018. For discussion of year ended December 31, 2017, as well as the year ended 2018 compared to the year ended December 31, 2017, refer to Part II, Item 7— “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2018 Annual Report on Form 10-K. 
+Overview 
+We are an independent provider of hydraulic fracturing services and goods to onshore oil and natural gas E&P companies in North America. We have grown from one active hydraulic fracturing fleet in December 2011 to 24 active fleets in February 2020. We added one fleet during the year ended December 31, 2019 and one one fleet in January 2020. We provide our services primarily in the Permian Basin, the Eagle Ford Shale, the DJ Basin, the Williston Basin, the San Juan Basin and the Powder River Basin. 
+We believe the following characteristics both distinguish us from our competitors and are the foundations of our business: forming ongoing partnerships of trust and innovation with our customers; developing and utilizing technology to maximize well performance; and promoting a people-centered culture focused on our employees, customers and suppliers. We have developed strong relationships with our customers by investing significant time in fracture design collaboration, which substantially enhances their production economics. Our technological innovations have become even more critical as E&P companies have increased the completion complexity and fracture intensity of horizontal wells. We are proactive in developing innovative solutions to industry challenges, including developing: (i) our proprietary databases of U.S. unconventional wells to which we apply our proprietary multi-variable statistical analysis technologies to provide differential insight into fracture design optimization; (ii) our Liberty Quiet Fleet® design which significantly reduces noise levels compared to conventional hydraulic fracturing fleets; and (iii) hydraulic fracturing fluid systems tailored to the specific reservoir properties in the basins in which we operate. We foster a people-centered culture built around honoring our commitments to customers, partnering with our suppliers and hiring, training and retaining people that we believe to be the best talent in our field, enabling us to be one of the safest and most efficient hydraulic fracturing companies in the United States. 
+Recent Trends and Outlook 
+Demand for hydraulic fracturing services and goods is predominantly influenced by the level of drilling and completion activity by E&P companies, which, in turn, depends largely on the current and anticipated profitability of developing oil and natural gas reserves, the availability of capital to E&P companies, and takeaway capacity in each basin. More specifically, demand for hydraulic fracturing services is driven by the completion of hydraulic fracturing stages in unconventional wells, which, in turn, is driven by several factors including rig count, well count, service intensity and the timing and style of well completions. Additionally, pricing for hydraulic fracturing services is impacted by the demand factors described above, as well as by the supply of actively marketed and staffed hydraulic fracturing fleets. 
+The price of WTI in 2019 decreased from 2018. The price of WTI averaged $56.98, $65.23, and $50.80 during 2019, 2018, and 2017, respectively. According to a report by Baker Hughes, a GE company (“Baker Hughes”), the horizontal rig count in North America averaged 826, 900, and 737 during 2019, 2018 and 2017, respectively. 
+During 2019 and 2018, E&P companies have increasingly come under investor pressure for better returns than those achieved over the last decade. As a result, debt and equity capital markets, which previously funded drilling and completions activity beyond E&P companies’ operating cash flow, tightened, causing an increased level of capital discipline that has resulted in a lower level of drilling and completions expenditures. 2019 E&P capital expenditures were lower than those in 2018 and 2020 E&P capital expenditures are expected to be less than 2019. 
+The pricing dynamic entering into 2020 is challenging. Total industry horizontal frac stages in North America were up marginally in 2019, 6% from 2018, compared to a 34% increase in 2018 from 2017, according to Coras Research, LLC (“Coras”). However, efficiency gains across the industry have raised the number of frac stages completed by each fleet, which implies a decrease in the active frac fleets needed to meet demand. The slowing pace of frac activity led to progressively lower demand for frac fleets through the second half of 2019, resulting in pricing pressure on our services. The substantial oversupply of frac equipment in the second half of 2019 was the pricing backdrop for 2020 dedicated fleet negotiations. 
+44 
+Table of Contents 
+Although we are seeing reductions in the supply of staffed frac fleets in the market and announcements of permanent retirement of older equipment, there continues to be an oversupply of frac fleets in the market which is holding down pricing. As such, while we cannot predict with any certainty when pricing of our frac services will increase, we would not expect pricing to improve until the supply of actively staffed frac equipment better balances with the demand. Until pricing improves, we expect that increased profitability will have to come from technology, increased efficiency and enhanced processes. 
+Although there is uncertainty in the market about the level of customers’ drilling and completion activity in 2020, we expect demand for Liberty’s high-efficiency frac fleets to remain strong during 2020 due to the diversity of Liberty’s operating footprint, conversations with our customers and other factors and, as a result, we chose to activate our 24 th frac fleet earlier this year as part of growing our business with larger customers to support their long-term development programs. Based on our current visibility into our customers’ plans for 2020, we believe this level of demand is likely to continue through the year. 
+Increase in Drilling Efficiency and Service Intensity of Completions 
+Over the past decade, E&P companies have focused on exploiting the vast resource potential available across many of North America’s unconventional resource plays through the application of horizontal drilling and completion technologies, including the use of multi-stage hydraulic fracturing, in order to increase recovery of oil and natural gas. As E&P companies have improved drilling and completion techniques to maximize return and efficiency, we believe several long term trends have emerged which have materially increased the service intensity of current completions. 
+Improved drilling economics from horizontal drilling and greater rig efficiencies . Unconventional resources are increasingly being targeted through the use of horizontal drilling. According to Baker Hughes, as reported on January 10, 2020, horizontal rigs accounted for approximately 89% of all rigs drilling in the United States, up from 74% as of December 31, 2014. Over the past several years, North American E&P companies have benefited from improved drilling economics driven by technologies that reduce the number of days, and the cost, of drilling wells. North American drilling rigs have incorporated newer technologies, which allow them to drill rock more effectively and quickly, meaning each rig can drill more wells in a given period. These include improved drilling technologies and the incorporation of geosteering techniques which allow better placement of the wellbore. Drilling rigs have also incorporated new technology which allows fully-assembled rigs to automatically “walk” from one location to the next without disassembling and reassembling the rig, greatly reducing the time it takes to move from one drilling location to the next. At the same time, E&P companies are shifting their development plans to incorporate multi-well pad development, which allows them to drill multiple horizontal wellbores from the same pad or location. The aggregate effect of these improved techniques and technologies have reduced the average days required to drill a well, which according to Coras, has dropped from 28 days in 2014 to 20 days in 2019. 
+Increased complexity and service intensity of horizontal well completions . In addition to improved rig efficiencies discussed above, E&P companies are also improving the subsurface techniques and technologies used to exploit unconventional resources. These improvements have targeted increasing the exposure of each wellbore to the reservoir by drilling longer horizontal lateral sections of the wellbore. To complete the well, hydraulic fracturing is applied in stages along the wellbore to break-up the resource so that oil and gas can be produced. As wellbores have increased in length, the number of stages has also increased. From 2012 to 2019, the average stages per horizontal well have increased from 23 stages per well to 40 stages per well, according to Liberty FracTrends evaluation of wells in 12 liquid rich formations. Further, E&P companies have improved production from each stage by applying increasing amounts of proppant in each stage, which better connects the well to the resource. The aggregate effect of increased number of stages and the increasing amount of proppant in each stage has greatly increased the total amount of proppant used in each well, according to Coras, from six million pounds per well in 2014 to over 14 million pounds per well in 2019. 
+These industry trends will directly benefit hydraulic fracturing companies like us that have the expertise and technological innovations to effectively service today’s more efficient oilfield drilling activity and the increasing complexity and intensity of well completions. Given the expected returns that E&P companies have reported for new well development activities due to improved rig efficiencies and increasing well completion complexity and intensity, we expect these industry trends to continue. 
+How We Generate Revenue 
+We currently generate revenue through the provision of hydraulic fracturing services and goods. These services and goods are performed under a variety of contract structures, primarily MSAs as supplemented by statements of work, pricing agreements and specific quotes. A portion of our statements of work, under MSAs, include provisions that establish pricing arrangements for a period of up to one year in length. However, the majority of those agreements provide for pricing adjustments based on market conditions. The majority of our services are priced based on prevailing market conditions and changing input costs at the time the services are provided, giving consideration to the specific requirements of the customer. 
+45 
+Table of Contents 
+Our hydraulic fracturing services are performed in sections, which we refer to as fracturing stages. The estimated number of fracturing stages to be completed for a particular horizontal well is determined by the customer’s well completion design. We recognize revenue for each fracturing stage completed, although our revenue per completed fracturing stage varies depending on the actual volumes and types of proppants, chemicals and fluid utilized for each fracturing stage. The number of fracturing stages that we are able to complete in a period is directly related to the number and utilization of our deployed fleets and size of stages. 
+Costs of Conducting Our Business 
+The principal expenses involved in conducting our business are direct cost of personnel, services and materials used in the provision of services, general and administrative expenses, and depreciation and amortization. A large portion of the costs we incur in our business are variable based on the number of hydraulic fracturing jobs and the requirements of services provided to our customers. We manage the level of our fixed costs, except depreciation and amortization, based on several factors, including industry conditions and expected demand for our services. 
+How We Evaluate Our Operations 
+We use a variety of qualitative, operational and financial metrics to assess our performance. First and foremost of these is a qualitative assessment of customer satisfaction because ensuring we are a valuable partner to our customers is the key to achieving our quantitative business metrics. Among other measures, management considers each of the following: 
+• Revenue; 
+• Operating Income; 
+• EBITDA; 
+• Adjusted EBITDA; 
+• Annualized Adjusted EBITDA per Average Active Fleet; 
+• Net Income Before Taxes; and 
+• Earnings per Share. 
+Revenue 
+We analyze our revenue by comparing actual monthly revenue to our internal projections for a given period and to prior periods to assess our performance. We also assess our revenue in relation to the number of fleets we have deployed (revenue per average active fleet) from period to period. 
+Operating Income 
+We analyze our operating income, which we define as revenues less direct operating expenses, depreciation and amortization and general and administrative expenses, to measure our financial performance. We believe operating income is a meaningful metric because it provides insight on profitability and true operating performance based on the historical cost basis of our assets. We also compare operating income to our internal projections for a given period and to prior periods. 
+EBITDA and Adjusted EBITDA 
+We view EBITDA and Adjusted EBITDA as important indicators of performance. We define EBITDA as net income (loss) before interest, income taxes, depreciation and amortization. We define Adjusted EBITDA as EBITDA adjusted to eliminate the effects of items such as new fleet or new basin start-up costs, costs of asset acquisition, gain or loss on the disposal of assets, asset impairment charges, bad debt reserves, and non-recurring expenses that management does not consider in assessing ongoing operating performance. Annualized Adjusted EBITDA per Average Active Fleet is calculated as Adjusted EBITDA annualized, divided by the Average Active Fleets for the same period. See “—Comparison of Non-GAAP Financial Measures” for more information and a reconciliation of EBITDA and Adjusted EBITDA to net income, the most directly comparable financial measure calculated and presented in accordance with GAAP. 
+46 
+Table of Contents 
+Results of Operations 
+Year Ended December 31, 2019, Compared to Year Ended December 31, 2018 
+Years Ended December 31, 
+Description 2019 2018 Change 
+(in thousands) 
+Revenue $ 1,990,346 $ 2,155,136 $ (164,790) 
+Cost of services, excluding depreciation and amortization shown separately 1,621,180 1,628,753 (7,573) 
+General and administrative 97,589 99,052 (1,463) 
+Depreciation and amortization 165,379 125,110 40,269 
+Loss (gain) on disposal of assets 2,601 (4,342) 6,943 
+Operating income 103,597 306,563 (202,966) 
+Interest expense, net 14,681 17,145 (2,464) 
+Net income before taxes 88,916 289,418 (200,502) 
+Income tax expense 14,052 40,385 (26,333) 
+Net income 74,864 249,033 (174,169) 
+Less: Net income attributable to Predecessor, prior to the Corporate Reorganization — 8,705 (8,705) 
+Less: Net income attributable to non-controlling interests 35,861 113,979 (78,118) 
+Net income attributable to Liberty Oilfield Services Inc. stockholders $ 39,003 $ 126,349 $ (87,346) 
+Revenue 
+Our revenue decreased $164.8 million, or 7.6%, to $2.0 billion for the year ended December 31, 2019 compared to $2.2 billion for the year ended December 31, 2018. The overall decrease was due to a 13.7% decrease in revenue per average active fleet offset by a 7.0% increase in average active fleets deployed. Our revenue per average active fleet decreased to approximately $87.3 million for the year ended December 31, 2019 as compared to approximately $101.2 million for the year ended December 31, 2018, based on 22.8 and 21.3 average active fleets during those respective periods. The decrease in revenue per active fleet was due to decreases in market prices for fracturing services compared to the prior year. 
+Cost of Services 
+Cost of services (excluding depreciation and amortization) decreased $7.6 million, or 0.5%, to $1.6 billion for the year ended December 31, 2019 compared to $1.6 billion for the year ended December 31, 2018. The lower expense is primarily due to a $78.2 million decrease in materials for the year ended December 31, 2019 compared to the same period in 2018. While material volumes increased significantly during 2019 as compared to 2018, unit prices have come down with the increased use of lower cost local sand. The decrease in costs were partially offset by higher repairs and maintenance costs which increased by $31.1 million as well as increased personnel costs of approximately $30.6 million compared to the same period in 2018. 
+General and Administrative Expenses 
+General and administrative expenses decreased by $1.5 million, or 1.5%, to $97.6 million for the year ended December 31, 2019 compared to $99.1 million for the year ended December 31, 2018. This decrease is primarily attributed to a decrease in start up costs of approximately $5.5 million, partially offset by an increase of approximately $4.9 million in non cash stock based compensation expense attributable to the Company's second year of restricted stock unit grants under its Long Term Incentive Plan. 
+Depreciation and Amortization 
+Depreciation and amortization expense increased $40.3 million, or 32.2%, to $165.4 million for the year ended December 31, 2019 compared to $125.1 million for the year ended December 31, 2018, primarily due to three additional hydraulic fracturing fleets deployed during 2018 that were in service for all of 2019, as well as one additional fleet deployed during the year ended December 31, 2019. 
+Loss (Gain) on Disposal of Assets 
+Loss (gain) on disposal of assets in 2019 decreased $6.9 million to a loss of $2.6 million for the year ended December 31, 2019 compared to a gain of $4.3 million for the year ended December 31, 2018. The decrease is primarily due to a gain recognized during the year ended December 31, 2018 on insurance proceeds received in excess of losses incurred for damaged equipment resulting from an accidental fire in November 2018. 
+47 
+Table of Contents 
+Operating Income 
+We realized operating income of $103.6 million for the year ended December 31, 2019 compared to operating income of $306.6 million for the year ended December 31, 2018, primarily due to a decrease in revenue related to a decrease in demand for our services in conjunction with a decrease in market prices as well as an increase in depreciation and amortization costs related to additional fleets deployed during 2019 and 2018. 
+Interest Expense, net 
+The decrease in interest expense, net of $2.5 million, or 14.4%, to $14.7 million during the year ended December 31, 2019 compared to $17.1 million during the year ended December 31, 2018, was primarily due to an increase of approximately $2.4 million from higher interest income primarily driven by an agreement entered into with Liberty Resources in 2019 for a note receivable as well as interest income earned on short term cash investments. For further details of this related party transaction, see Note 12—Related Party Transactions to the consolidated and combined financial statements included in “Item 8. Financial Statements and Supplementary Data.” 
+Net Income Before Taxes 
+We realized net income before taxes of $88.9 million for the year ended December 31, 2019 compared to net income of $289.4 million for the year ended December 31, 2018. The decrease in net income before taxes is primarily attributable to a decrease in market prices for our services related to oversupply of North American hydraulic fracturing fleets for the year ended December 31, 2019. 
+Income Tax Expense 
+As a pass-through entity prior to the IPO, the Predecessor was subject only to the Texas margin tax at a statutory rate of 1.0% and was not subject to U.S. federal income tax. Subsequent to the IPO, the pre-tax net income attributable to the Company is taxed at a combined U.S. federal and state tax rate of approximately 23.0%, while no tax is provided for the income attributable to the non-controlling interests, which remains pass-through income attributable to the holders of non-controlling interests. We recognized $14.1 million of tax expense in the year ended December 31, 2019, an effective rate of 15.8%, compared to $40.4 million recognized during the year ended December 31, 2018, an effective rate of 14.0%. This decrease in income tax expense is mainly attributable to the net decrease in operating income, the components of which are discussed above. 
+Comparison of Non-GAAP Financial Measures 
+We view EBITDA and Adjusted EBITDA as important indicators of performance. We define EBITDA as net income before interest, income taxes, depreciation and amortization. We define Adjusted EBITDA as EBITDA adjusted to eliminate the effects of items such as new fleet or new basin start-up costs, costs of asset acquisitions, gain or loss on the disposal of assets, asset impairment charges, bad debt reserves and non-recurring expenses that management does not consider in assessing ongoing performance. 
+Our Board, management, investors and lenders use EBITDA and Adjusted EBITDA to assess our financial performance because it allows them to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure (such as varying levels of interest expense), asset base (such as depreciation and amortization) and other items that impact the comparability of financial results from period to period. We present EBITDA and Adjusted EBITDA because we believe they provide useful information regarding the factors and trends affecting our business in addition to measures calculated under GAAP. 
+Note Regarding Non-GAAP Financial Measures 
+EBITDA and Adjusted EBITDA are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures will provide useful information to investors in assessing our financial performance and results of operations. Net income (loss) is the GAAP measure most directly comparable to EBITDA and Adjusted EBITDA. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as an analytical tool due to exclusion of some but not all items that affect the most directly comparable GAAP financial measures. You should not consider EBITDA or Adjusted EBITDA in isolation or as substitutes for an analysis of our results as reported under GAAP. Because EBITDA and Adjusted EBITDA may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. 
+48 
+Table of Contents 
+The following tables present a reconciliation of EBITDA and Adjusted EBITDA to our net income, which is the most directly comparable GAAP measure for the periods presented: 
+Year Ended December 31, 2019 Compared to Year Ended December 31, 2018: EBITDA and Adjusted EBITDA 
+Years Ended December 31, 
+Description 2019 2018 Change 
+(in thousands) 
+Net income $ 74,864 $ 249,033 $ (174,169) 
+Depreciation and amortization 165,379 125,110 40,269 
+Interest expense, net 14,681 17,145 (2,464) 
+Income tax expense 14,052 40,385 (26,333) 
+EBITDA $ 268,976 $ 431,673 $ (162,697) 
+Fleet start-up costs 4,519 10,069 (5,550) 
+Asset acquisition costs — 632 (632) 
+(Gain) loss on disposal of assets 2,601 (4,342) 6,943 
+Bad debt reserve 1,053 — 1,053 
+Advisory services fees — 202 (202) 
+Adjusted EBITDA $ 277,149 $ 438,234 $ (161,085) 
+EBITDA was $269.0 million for the year ended December 31, 2019 compared to $431.7 million for the year ended December 31, 2018. Adjusted EBITDA was $277.1 million for the year ended December 31, 2019 compared to $438.2 million for the year ended December 31, 2018. The decreases in EBITDA and Adjusted EBITDA resulted from the decreased revenue and other factors described above under the captions Revenue , Cost of Services, General and Administrative Expenses and Depreciation and Amortization for Year Ended December 31, 2019, Compared to Year Ended December 31, 2018 . 
+Liquidity and Capital Resources 
+Overview 
+Historically, our primary sources of liquidity to date have been cash flows from operations, proceeds from our IPO, and borrowings under our Credit Facilities. We expect to fund operations and organic growth with cash flows from operations and available borrowings under our Credit Facilities. We may incur additional indebtedness or issue equity in order to fund growth opportunities that we pursue via acquisition. Our primary uses of capital have been capital expenditures to support organic growth and funding ongoing operations, including maintenance and fleet upgrades. 
+Cash and cash equivalent s increased by $9.4 million to $112.7 million as of December 31, 2019 compared to $103.3 million as of December 31, 2018. We believe that our operating cash flow and available borrowings under our Credit Facilities will be sufficient to fund our operations for at least the next twelve months. 
+Cash Flows 
+The following table summarizes our cash flows for the periods indicated: 
+Years Ended December 31, 
+Description 2019 2018 Change 
+(in thousands) 
+Net cash provided by operating activities $ 261,100 $ 351,258 $ (90,158) 
+Net cash used in investing activities (194,347) (255,492) 61,145 
+Net cash used in financing activities (57,375) (8,775) (48,600) 
+Net increase in cash and cash equivalents $ 9,378 $ 86,991 $ (77,613) 
+Analysis of Cash Flow Changes Between the Years Ended December 31, 2019 and December 31, 2018 
+Operating Activities . Net cash provided by operating activities was $261.1 million for the year ended December 31, 2019, compared to net cash provided by operating activities of $351.3 million for the year ended December 31, 2018. The $90.2 million decrease in cash from operating activities was primarily attributable to a $164.8 million decrease in revenues, offset by an increase of $24.9 million from changes in working capital between periods, and to a lesser extent by lower cash taxes, costs of goods sold, and general and administrative expenses. 
+49 
+Table of Contents 
+Investing Activities . Net cash used in investing activities was $194.3 million for the year ended December 31, 2019, compared to $255.5 million for the year ended December 31, 2018. The $61.1 million decrease in net cash used in investing activities was primarily due to fewer hydraulic frac fleets deployed during 2019 than were deployed during 2018. 
+Financing Activities . Net cash used in financing activities was $57.4 million for the year ended December 31, 2019, compared to net cash used in financing activities of $8.8 million for the year ended December 31, 2018. The $48.6 million increase in cash used in financing activities was primarily due to cash provided by financing activities in 2018 from the IPO and Corporate Reorganization offset by increased repayments under the Credit Facilities and increased share repurchases in 2018 compared to 2019. During 2018, $200.2 million of net proceeds were raised from the IPO and Corporate Reorganization. Share repurchases were $82.9 million in 2018 compared to $18.4 million in 2019. Repayments of borrowings under the Credit Facilities were $92.8 million in 2018 compared to $1.8 million in 2019. Quarterly dividends and distributions were $11.6 million in 2018 compared to $22.5 million in 2019. Payments on finance lease obligations were zero in 2018 compared to $12.1 million in 2019. Other distributions and advances to non-controlling interest holders were $21.3 million in 2018 compared to de minimis amounts in 2019. 
+Debt Agreements 
+On September 19, 2017, the Company entered into two new credit agreements for a revolving line of credit up to $250.0 million (the “ABL Facility”) and a $175.0 million term loan (the “Term Loan Facility”, and together with the ABL Facility the “Credit Facilities”). Following is a description of the ABL Facility and the Term Loan Facility. 
+ABL Facility 
+Under the terms of the ABL Facility, up to $250.0 million may be borrowed, subject to certain borrowing base limitations based on a percentage of eligible accounts receivable and inventory. As of December 31, 2019, the borrowing base was calculated to be $171.1 million, and the Company had no borrowings outstanding, except for a letter of credit in the amount of $0.3 million, with $170.8 million of remaining availability. Borrowings under the ABL Facility bear interest at LIBOR or a base rate, plus an applicable LIBOR margin of 1.5% to 2.0% or base rate margin of 0.5% to 1.0%, as defined in the ABL Facility credit agreement. The unused commitment is subject to an unused commitment fee of 0.375% to 0.5%. Interest and fees are payable in arrears at the end of each month, or, in the case of LIBOR loans, at the end of each interest period. The ABL Facility matures on the earlier of (i) September 19, 2022 and (ii) to the extent the debt under the Term Loan Facility remains outstanding, 90 days prior to the final maturity of the Term Loan Facility, which matures on September 19, 2022. Borrowings under the ABL Facility are collateralized by accounts receivable and inventory, and further secured by the Company, Liberty LLC and R/C IV Non-U.S. LOS Corp., a Delaware corporation (“R/C IV”) and a subsidiary of the Company, as parent guarantors. 
+Term Loan Facility 
+The Term Loan Facility provides for a $175.0 million term loan, of which $110.0 million remained outstanding as of December 31, 2019. Amounts outstanding bear interest at LIBOR or a base rate, plus an applicable margin of 7.625% or 6.625%, respectively, and the weighted average rate on borrowings was 9.4% as of December 31, 2019. The Company is required to make quarterly principal payments of 1% per annum of the initial principal balance, commencing on December 31, 2017, with final payment due at maturity on September 19, 2022. The Term Loan Facility is collateralized by the fixed assets of LOS and its subsidiaries, and is further secured by the Company, Liberty LLC and R/C IV, as parent guarantors. 
+The Credit Facilities include certain non-financial covenants, including but not limited to restrictions on incurring additional debt and certain distributions. Moreover, the ability of the Company to incur additional debt and to make distributions is dependent on maintaining a maximum leverage ratio. The Term Loan Facility requires mandatory prepayments upon certain dispositions of property or issuance of other indebtedness, as defined, and annually a percentage of excess cash flow (25% to 50%, depending on leverage ratio, of consolidated net income less capital expenditures and other permitted payments, commencing with the year ending December 31, 2018). Certain mandatory prepayments and optional prepayments are subject to a prepayment premium of 3% of the prepaid principal declining annually to 1% during the first three years of the term of the Term Loan Facility. 
+The Credit Facilities are not subject to financial covenants unless liquidity, as defined in the respective credit agreements, drops below a specified level. Under the ABL Facility, the Company is required to maintain a minimum fixed charge coverage ratio, as defined in the credit agreement governing the ABL Facility, of 1.0 to 1.0 for each period if excess availability is less than 10% of the borrowing base or $12.5 million, whichever is greater. Under the Term Loan Facility, the Company is required to maintain a minimum fixed charge coverage ratio, as defined, of 1.2 to 1.0 for each trailing twelve-month period if the Company’s liquidity, as defined, is less than $25.0 million for at least five consecutive business days. The Company was in compliance with these covenants as of December 31, 2019. 
+50 
+Table of Contents 
+Contractual Obligations 
+The table below provides estimates of the timing of future payments that we are contractually obligated to make based on agreements in place at December 31, 2019. 
+Payments Due by Period 
+($ in thousands) 
+Total Less than 1 
+year 1 – 3 years 4 – 5 years More than 5 years 
+ABL Facility(1) $ — $ — $ — $ — $ — 
+Term Loan Facility(1) 109,966 1,750 108,216 — — 
+Estimated interest payments(2) 28,024 10,473 17,551 — — 
+Operating lease obligations(3) 63,235 18,262 20,945 8,011 16,017 
+Finance lease obligations(4) 51,168 26,407 24,761 — — 
+Purchase commitments(5) 525,507 349,096 157,408 19,003 — 
+Obligations under the TRAs(6) 50,302 1,821 20,470 8,111 19,900 
+Total $ 828,202 $ 407,809 $ 349,351 $ 35,125 $ 35,917 
+(1) Payments on our ABL Facility and Term Loan Facility exclude interest payments. Payments are based on debt balances as of December 31, 2019. 
+(2) Estimated interest payments are based on debt balances as of December 31, 2019. Interest rates applied are based on the weighted average rate as of December 31, 2019. 
+(3) Operating lease obligations include payments for leased facilities, equipment and vehicles. 
+(4) Finance lease obligations include payments for leased vehicles. 
+(5) Purchase commitments represent payments under supply agreements for the purchase and transportation of proppants. Some of the agreements include minimum monthly purchase commitments, including agreements under which a shortfall fee may be applied. The shortfall fee may be offset by purchases in excess of the minimum requirement during future periods, as allowed for by each agreement. 
+(6) The timing and amount(s) of the aggregate payments due under the TRAs may vary based on a number of factors, including the timing and amount of the taxable income we generate each year and the tax rate then applicable. 
+Tax Receivable Agreements 
+In connection with the IPO, on January 17, 2018, the Company entered into two TRAs with the TRA Holders. The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that the Company actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result, as applicable to each of the TRA Holders, of (i) certain increases in tax basis that occur as a result of the Company’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holders’ Liberty LLC Units in connection with the IPO or pursuant to the exercise of the right of each Liberty Unit Holder (the “Redemption Right”), subject to certain limitations, to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units for, at Liberty LLC’s election, (A) shares of our Class A Common Stock at the specific redemption ratio or (B) an equivalent amount of cash, or, upon the exercise of the Redemption Right, the right of Liberty Inc. (instead of Liberty LLC) to, for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder (the “Call Right”) for, at its election, (1) one share of Class A Common Stock or (2) an equivalent amount of cash, (ii) any net operating losses available to the Company as a result of the Corporate Reorganization, and (iii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRAs. 
+With respect to obligations the Company expects to incur under the TRAs (except in cases where the Company elects to terminate the TRAs early, the TRAs are terminated early due to certain mergers, asset sales, or other changes of control or the Company has available cash but fails to make payments when due), generally the Company may elect to defer payments due under the TRAs if the Company does not have available cash to satisfy its payment obligations under the TRAs or if its contractual obligations limit its ability to make such payments. Any such deferred payments under the TRAs generally will accrue interest. In certain cases, payments under the TRAs may be accelerated and/or significantly exceed the actual benefits, if any, the Company realizes in respect of the tax attributes subject to the TRAs. The Company accounts for amounts payable under the TRAs in accordance with Accounting Standard Codification (“ASC”) Topic 450, Contingencies . 
+If the Company experiences a change of control (as defined under the TRAs) or the TRAs otherwise terminate early, the Company’s obligations under the TRAs could have a substantial negative impact on its liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. There can be no assurance that we will be able to finance our obligations under the TRAs. 
+51 
+Table of Contents 
+Income Taxes 
+Following the IPO, the Company is a corporation and is subject to U.S. federal, state and local income tax on its share of Liberty LLC’s taxable income. As a result of the IPO and Corporate Reorganization, the Company recorded deferred tax assets and liabilities for the difference between the book value of assets and liabilities for financial reporting purposes and those amounts applicable for income tax purposes. Deferred tax assets have been recorded for tax attributes contributed to the Company as part of the reorganization. Deferred tax liabilities of $29.3 million were recorded relating to the Liberty LLC Units acquired through the Corporate Reorganization. 
+The effective combined U.S. federal and state income tax rate applicable to the Company for the year ended December 31, 2019 and 2018 was 15.8% and 14.0%, respectively. The Company’s effective tax rate is significantly less than the federal statutory income tax rate of 21.0% primarily because no taxes are payable by the Company for the non-controlling interest’s share of Liberty LLC’s pass-through income for federal, state and local income tax reporting. The Company recognized income tax expense of $14.1 million and $40.4 million for the year ended December 31, 2019 and 2018, respectively. 
+Critical Accounting Policies and Estimates 
+The preparation of financial statements requires the use of judgments and estimates. Our critical accounting policies are described below to provide a better understanding of how we develop our assumptions and judgments about future events and related estimates and how they can impact our financial statements. A critical accounting estimate is one that requires our most difficult, subjective or complex estimates and assessments and is fundamental to our results of operations. 
+We base our estimates on historical experience and on various other assumptions we believe to be reasonable according to the current facts and circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. We believe the following are the critical accounting policies used in the preparation of our combined financial statements, as well as the significant estimates and judgments affecting the application of these policies. This discussion and analysis should be read in conjunction with our combined financial statements and related notes included in “Item 8. Financial Statements and Supplementary Data. ” 
+Revenue Recognition: Revenue from hydraulic fracturing services is recognized as specific services are provided in accordance with contractual arrangements. If our assessment of performance under a particular contract changes, our revenue and / or costs under that contract may change. In connection with ASC Topic 842, the Company determined that certain of its service revenue contracts contain a lease component. The Company elected to adopt a practical expedient available to lessors, which allows the Company to combine the lease and service component for certain of the Company’s service contracts when the service component is the predominant component and continues to account for the combined component under ASC Topic 606, Revenue from Contracts with Customers . 
+Accounts Receivable: We analyze the need for an allowance for doubtful accounts for estimated losses related to potentially uncollectible accounts receivable on a case-by-case basis throughout the year. We reserve amounts based on specific identification after considering each customer’s situation, including payment patterns, current financial condition as well as general economic conditions. It is reasonably possible that our estimates of the allowance for doubtful accounts will change and that losses ultimately incurred could differ materially from the amounts estimated in determining the allowance. 
+Inventory: Inventory consists of raw materials used in the hydraulic fracturing process, such as proppants, chemicals and field service equipment maintenance parts, and is stated at the lower of cost or net realizable value, determined using the weighted average cost method. Net realizable value is determined based on our estimates of selling prices in the ordinary course of business, less reasonably predictable cost of completion, disposal, and transportation, each of which require us to apply judgment. 
+Property and Equipment: We calculate depreciation and amortization on our assets based on the estimated useful lives and estimated salvage values that we believe are reasonable. The estimated useful lives and salvage values are subject to key assumptions such as maintenance, utilization and job variation. These estimates may change due to a number of factors such as changes in operating conditions or advances in technology. 
+We incur maintenance costs on our major equipment. The determination of whether an expenditure should be capitalized or expensed requires management judgment in the application of how the costs benefit future periods, relative to our capitalization policy. Costs that either establish or increase the efficiency, productivity, functionality or life of a fixed asset are capitalized and depreciated over the remaining useful life of the asset. 
+Impairment of long-lived and other intangible assets: Long-lived assets, such as property and equipment and finite-lived intangible assets, are evaluated for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Recoverability is assessed using undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets. When alternative 
+52 
+Table of Contents 
+courses of action to recover the carrying amount of the asset group are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence, which require us to apply judgment. If the carrying amount of the asset is not recoverable based on its estimated undiscounted cash flows expected to result from the use and eventual disposition, an impairment loss is recognized in an amount by which its carrying amount exceeds its estimated fair value. The inputs used to determine such fair value are primarily based upon internally developed cash flow models. Our cash flow models are based on a number of estimates regarding future operations that may be subject to significant variability, are sensitive to changes in market conditions, and are reasonably likely to change in the future. No events or changes in circumstances occurred that would indicate a potential impairment of property and equipment as of December 31, 2019 and 2018. No impairment was recognized during the years ended December 31, 2019, 2018 and 2017. 
+Leases: The Company adopted Accounting Standards Update (“ASU”) No. 2016-02, Leases ASC Topic 842 effective January 1, 2019. We elected the modified retrospective transition method under ASC Topic 842 and as such information prior to January 1, 2019 has not been restated and continues to be reported under the accounting standards in effect for the period (ASC Topic 840). We carried forward the historical lease classifications and assessment of initial direct costs, account for lease and non-lease components as a single component, and exclude leases with an initial term of less than 12 months in the lease assets and liabilities. For leases entered into after January 1, 2019, the Company determines if an arrangement is a lease at inception and evaluates identified leases for operating or finance lease treatment. Operating or finance lease right-of-use assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. We use our incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments. Lease terms may include options to renew; however, we typically cannot determine our intent to renew a lease with reasonable certainty at inception. 
+Tax Receivable Agreements: In connection with the IPO, on January 17, 2018, the Company entered into two TRAs with the TRA Holders. The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax that the Company actually realizes in periods after the IPO as a result of certain tax attributes applicable to each TRA Holder. The Company accounts for amounts payable under the TRAs in accordance with ASC Topic 450, Contingencies . 
+Share Repurchases: The Company accounts for the purchase price of repurchased Class A Common Stock in excess of par value ($0.01 per share of Class A Common Stock) as a reduction of additional paid-in capital, and will continue to do so until additional paid-in capital is reduced to zero. Thereafter, any excess purchase price will be recorded as a reduction to retained earnings. 
+Recent Accounting Pronouncements 
+See Note 2—Significant Accounting Policies— Recently Issued Accounting Standards to the consolidated and combined financial statements included in “Item 8. Financial Statements and Supplementary Data” for a discussion of recent accounting pronouncements. 
+Off Balance Sheet Arrangements 
+We have no material off balance sheet arrangements as of December 31, 2019, except for purchase commitments under supply agreements as disclosed above under “—Contractual Obligations.” As such, we are not materially exposed to any other financing, liquidity, market or credit risk that could arise if we had engaged in such financing arrangements. 
+53 
+Table of Contents 
+Item 7A. Quantitative and Qualitative Disclosure about Market Risk 
+Industry Risk 
+The demand, pricing and terms for hydraulic fracturing services and related goods provided by us are largely dependent upon the level of drilling activity in the U.S. oil and natural gas industry, as well as the available supply of hydraulic fracturing equipment. These activity levels are influenced by numerous factors over which we have no control, including, but not limited to: the supply of and demand for oil and natural gas; the level of prices, and expectations about future prices of oil and natural gas; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; the discovery rates of new oil and natural gas reserves; supply of actively marketed and staffed fracturing fleets; available rail and other transportation capacity; weather conditions; domestic and worldwide economic conditions; political instability in oil-producing countries; environmental regulations; technical advances affecting energy consumption; the price and availability of alternative fuels; the ability of E&P companies to raise equity capital and debt financing; and merger and divestiture activity among E&P companies. 
+The level of U.S. oil and natural gas drilling is volatile. Expected trends in oil and natural gas production activities may not materialize and demand for our services may not reflect the level of activity in the industry. Any prolonged and substantial reduction in oil and natural gas prices would likely affect oil and natural gas production levels and therefore affect demand for our services. A material decline in oil and natural gas prices or U.S. activity levels could have a material adverse effect on our business, financial condition, results of operations and cash flows. 
+Interest Rate Risk 
+At December 31, 2019, we had $110.0 million of debt outstanding, with a weighted average interest rate of 9.4%. Interest is calculated under the terms of our Credit Facilities based on our selection, from time to time, of one of the index rates available to us plus an applicable margin that varies based on certain factors. See “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements.” Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the weighted average interest rate would be approximately $1.1 million per year. We do not currently have or intend to enter into any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness. 
+Commodity Price Risk 
+Our material and fuel purchases expose us to commodity price risk. Material costs primarily include inventory consumed while performing hydraulic fracturing services. Fuel costs consist of diesel fuel used by trucks and other motorized equipment used for hydraulic fracturing services. At times, we have been able to pass along price increases for material costs and fuel costs to customers and conversely have been required to pass along price decreases for material costs to our customers, depending on market conditions. Further, we have purchase commitments with certain vendors to supply proppant inventory used in our operations at a fixed purchase price, including certain commitments which include minimum purchase obligations. Refer t o Note 13, “Commitments and Contingencies” included in “Item 8. Financial Statements and Supplementary Data” for further discussion regarding pur chase commitments. 
+54 
+Table of Contents 
+Item 8. Financial Statements and Supplementary Data 
+Our financial statements and supplementary data are included in this Annual Report on Form 10-K beginning on page F-1 and incorporated by reference herein. 
+Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+None. 
+Item 9A. Controls and Procedures 
+Evaluation of Disclosure Controls and Procedures 
+In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2019 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures. 
+There has been no change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the three months ended December 31, 2019 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. 
+See page F-1 for Management’s Report on Internal Control Over Financial Reporting and page F-4 for Report of Independent Registered Public Accounting Firm on its assessment of our internal control over financial reporting. 
+Item 9B. Other Information 
+None. 
+55 
+Table of Contents 
+PART III 
+Item 10. Directors, Executive Officers and Corporate Governance 
+The information required by this item concerning our executive officers, directors and corporate governance is incorporated herein by reference to our definitive proxy statement for our 2020 annual meeting of shareholders, which will be filed with the SEC no later than 120 days after December 31, 2019, under the captions “Proposal 1 — Election of Directors,” “The Board and its Committees,” “Executive Officers” and “Delinquent Section 16(a) Reports.” 
+Item 11. Executive Compensation 
+The information required by this item concerning executive compensation is incorporated herein by reference to our definitive proxy statement for our 2020 annual meeting of shareholders, which will be filed with the SEC no later than 120 days after December 31, 2019, under the captions “The Board and its Committees,” “Compensation Discussion & Analysis,” “Compensation Committee Report,” “Executive Compensation Tables,” “Director Compensation” and “CEO Pay Ratio.” 
+Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+The information required by this item concerning the security ownership of certain beneficial owners and management and related stockholder matters are incorporated herein by reference to our definitive proxy statement for our 2020 annual meeting of shareholders, which will be filed with the SEC no later than 120 days after December 31, 2019, under the captions “Security Ownership of Certain Beneficial Owners and Management” and “Equity Compensation Plan Information.” 
+Item 13. Certain Relationships and Related Transactions, and Director Independence 
+The information required by this item concerning certain relationships and related person transactions and director independence is incorporated herein by reference to our definitive proxy statement for our 2020 annual meeting of shareholders, which will be filed with the SEC no later than 120 days after December 31, 2019, under the captions “Certain Relationships and Related Party Transactions” and “the Board and its Committees.” 
+Item 14. Principal Accountant Fees and Services 
+The information required by this item concerning principal accounting fees and services is incorporated herein by reference to our definitive proxy statement for our 2020 annual meeting of shareholders, which will be filed with the SEC no later than 120 days after December 31, 2019, under the caption “Proposal 2 — Ratification of Appointment of the Company’s Independent Registered Public Accounting Firm.” 
+56 
+Table of Contents 
+PART IV 
+Item 15. Exhibits and Financial Statement Schedules 
+(a) Financial Statements and Financial Statement Schedules 
+Refer to Index to Financial Statements on page 63. 
+All schedules are omitted as information required is inapplicable or the information is presented in the consolidated and combined financial statements and the related notes. 
+(b) Exhibits 
+The documents listed in the Index to Exhibits are filed, furnished or incorporated by reference as part of this Annual Report on Form 10-K, and such Index to Exhibits are incorporated herein by reference. 
+57 
+Table of Contents 
+Item 16. Form 10-K Summary 
+None. 
+58 
+Table of Contents 
+INDEX TO EXHIBITS 
+Exhibit 
+Number 
+Description 
+2.1 
+Master Reorganization Agreement, dated as of January 11, 2018, by and among Liberty Oilfield Services Inc., Liberty Oilfield Services Holdings LLC, Liberty Oilfield Services New HoldCo LLC, and the other parties named therein (2) 
+3.1 
+Amended and Restated Certificate of Incorporation of Liberty Oilfield Services Inc. (2) 
+3.2 
+Amended and Restated Bylaws of Liberty Oilfield Services Inc. (3) 
+4.1 
+Stockholder Agreement, dated as of January 17, 2018, by and among Liberty Oilfield Services Inc., R/C IV Liberty Oilfield Services Holdings, L.P., R/C Energy IV Direct Partnership, L.P., and other parties names therein (2) 
+4.2 
+Stockholders Agreement, dated as of July 23, 2019, by and among Liberty Oilfield Services Inc., R/C IV Liberty Holdings, L.P. and R/C Energy IV Direct Partnership, L.P. (9) 
+4.3 
+Description of the Registrant’s Securities Registered pursuant to Section 12 of the Securities Exchange Act of 1934. * 
+10.1 
+Second Amended and Restated Limited Liability Company Operating Agreement of Liberty Oilfield Services New HoldCo LLC (2) 
+10.2 
+Tax Receivable Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Inc., R/C Energy IV Direct Partnership, L.P., and R/C Energy IV Direct Partnership, L.P., as agent (2) 
+10.3 
+Tax Receivable Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Inc., and the other parties named therein (2) 
+10.4 
+Registration Rights Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Inc. and the other parties named therein (2) 
+10.5 
+Liberty Oilfield Services Inc. Long Term Incentive Plan (2)† 
+10.6 
+Liberty Oilfield Services Inc. Legacy Restricted Stock Plan (2)† 
+10.7 
+Form of Restricted Stock Grant Notice and Restricted Stock Agreement under the Legacy Restricted Stock Plan (1)† 
+10.8 
+Credit Agreement, dated September 19, 2017, by and among Wells Fargo Bank, National Association, as Administrative Agent, Wells Fargo Bank, National Association, JPMorgan Chase Bank, N.A. and Citibank, N.A., as Joint Lead Arrangers, Wells Fargo Bank, National Association, as Book Runner, JPMorgan Chase Bank, N.A. and Citibank, N.A., as Syndication Agents, the lender parties thereto, Liberty Oilfield Services Holdings LLC, as Parent and Liberty Oilfield Services LLC and LOS Acquisition Co I LLC, each as a Borrower (1) 
+10.9 
+Amendment and Parent Joinder to Credit Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Holdings LLC, Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto (4) 
+10.10 
+Second Amendment and Parent Joinder to Credit Agreement, dated March 21, 2018, by and among Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto (4) 
+10.11 
+Credit Agreement, dated September 19, 2017, by and among Liberty Oilfield Services LLC and LOS Acquisition CO I LLC, each as a Borrower, Liberty Oilfield Services Holdings LLC, as Parent Guarantor and U.S. Bank National Association as Agent (1) 
+10.12 
+Amendment and Joinder to Credit Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Holdings LLC, Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, U.S. Bank National Association, as Administrative Agent, and the lenders signatory thereto (4) 
+10.13 
+Second Amendment and Joinder to Credit Agreement, dated March 21, 2018, by and among Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, U.S. Bank National Association, as Administrative Agent, and the lenders signatory thereto (4) 
+59 
+Table of Contents 
+10.14 
+Liberty Oilfield Services 401(k) Savings Plan (5)† 
+10.15 
+Stock Purchase and Sale Agreement, dated as of September 14, 2018, by and among Liberty Oilfield Services Inc., R/C Energy IV Direct Partnership, L.P., R/C IV Liberty Holdings, L.P. and Riverstone/Carlyle Energy Partners IV, L.P. (6) 
+10.16 
+Form of Restricted Stock Unit Grant Notice and Restricted Stock Unit Award Agreement under the Long Term Incentive Plan (7)† 
+10.17 
+Form of Performance Restricted Stock Unit Grant Notice and Performance Restricted Stock Unit Agreement under the Liberty Oilfield Services Inc. Long Term Incentive Plan (8)† 
+10.18 
+Form of Change in Control Agreement (10)† 
+10.19 
+Form of Indemnification Agreement between the Company and each of its Directors and Executive Officers * 
+21.1 
+List of subsidiaries of Liberty Oilfield Services Inc. * 
+23.1 
+Consent of Deloitte & Touche LLP * 
+31.1 
+Certification of Chief Executive Officer pursuant to Rule 13a-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 * 
+31.2 
+Certification of Chief Financial Officer pursuant to 13a-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 * 
+32.1 
+Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 ** 
+32.2 
+Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 ** 
+101.INS XBRL Instance Document * 
+101.SCH XBRL Taxonomy Extension Schema Document * 
+101.CAL XBRL Taxonomy Extension Calculation Linkbase Document * 
+101.DEF XBRL Taxonomy Extension Definition Linkbase Document * 
+101.LAB XBRL Taxonomy Extension Label Linkbase Document * 
+101.PRE XBRL Taxonomy Extension Presentation Linkbase Document * 
+104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)* 
+(1) Incorporated by reference to the exhibits to the registrant’s Registration Statement on Form S-1, as amended (SEC File 333-216050). 
+(2) Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on January 18, 2018. 
+(3) Incorporated by reference to the exhibits to the registrant’s Amendment No. 1 to the Current Report on Form 8-K/A, filed on January 22, 2018. 
+(4) Incorporated by reference to the exhibits to the registrant’s Annual Report on Form 10-K, filed on March 23, 2018. 
+(5) Incorporated by reference to the exhibits to the registrant’s Registration Statement on Form S-8, filed on June 28, 2018 (SEC File 333-225948). 
+(6) Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on September 17, 2018. 
+(7) Incorporated by reference to the exhibits to the registrant’s Quarterly Report on Form 10-Q, filed on May 10, 2018. 
+(8) Incorporated by reference to the exhibits to the registrant’s Quarterly Report on Form 10-Q, filed on May 3, 2019. 
+(9) Incorporated by reference to the registrant’s Current Report on Form 8-K, filed on July 29, 2019. 
+(10) Incorporated by reference to the registrant’s Current Report on Form 8-K, filed on August 30, 2019. 
+* Filed herewith. 
+60 
+Table of Contents 
+** Furnished herewith. 
+† Denotes a management contract or compensatory plan or arrangement. 
+61 
+Table of Contents 
+SIGNATURES 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+LIBERTY OILFIELD SERVICES INC. 
+/s/ Christopher A. Wright 
+Date: February 26, 2020 By: 
+Christopher A. Wright 
+Chief Executive Officer 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+Signature Title Date 
+/s/ Christopher A. Wright 
+Chief Executive Officer and Director 
+(Principal Executive Officer) 
+February 26, 2020 
+Christopher A. Wright 
+/s/ Michael Stock 
+Chief Financial Officer 
+(Principal Financial Officer) 
+February 26, 2020 
+Michael Stock 
+/s/ Ryan T. Gosney Chief Accounting Officer February 26, 2020 
+Ryan T. Gosney (Principal Accounting Officer) 
+/s/ Cary D. Steinbeck Director February 26, 2020 
+Cary D. Steinbeck 
+/s/ N. John Lancaster, Jr. Director February 26, 2020 
+N. John Lancaster, Jr. 
+/s/ Brett Staffieri Director February 26, 2020 
+Brett Staffieri 
+/s/ William F. Kimble Director February 26, 2020 
+William F. Kimble 
+/s/ Peter A. Dea Director February 26, 2020 
+Peter A. Dea 
+/s/ Ken Babcock Director February 26, 2020 
+Ken Babcock 
+/s/ Jesal Shah Director February 26, 2020 
+Jesal Shah 
+/s/ Gale A. Norton Director February 26, 2020 
+Gale Norton 
+62 
+Table of Contents 
+Index to Financial Statements 
+Liberty Oilfield Services Inc. 
+Management’s Report on Internal Control Over Financial Reporting 
+F-1 
+Report s of Independent Registered Public Accounting Firm 
+F- 2 
+Consolidated Balance Sheets as of December 31, 2019 and 2018 
+F- 5 
+Consolidated and Combined Statements of Operations for the Years Ended December 31, 2019, 2018 , and 2017 
+F- 6 
+Consolidated and Combined Statements of Changes in Equity for the Years Ended December 31, 2019 and 2018 
+F- 7 
+Consolidated and Combined Statements of Cash Flows for the Years Ended December 31, 2019, 2018 , and 2017 
+F- 9 
+Notes to Consolidated and Combined Financial Statements 
+F- 11 
+63 
+Table of Contents 
+MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING 
+The management of Liberty Oilfield Services Inc. is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act. 
+Internal control over financial reporting, no matter how well designed, has inherent limitations. Therefore, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements. Further, because of changes in conditions, effectiveness of internal controls over financial reporting may vary over time. 
+Under the supervision of, and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2019 based on the framework and criteria established in Internal Control-Integrated Framework (2013) , issued by the Committee of Sponsoring Organizations of the Treadway Commission. 
+Based on this evaluation, management concluded that, as of December 31, 2019, our internal control over financial reporting was effective. The effectiveness of Liberty Oilfield Services Inc. ’ s internal control over financial reporting as of December 31, 2019 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report that is included herein. 
+F-1 
+Table of Contents 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the shareholders and the Board of Directors of Liberty Oilfield Services Inc. 
+Opinion on the Financial Statements 
+We have audited the accompanying consolidated balance sheets of Liberty Oilfield Services Inc. and subsidiaries (the “Company”) as of December 31, 2019 and 2018, the related consolidated and combined statements of operations, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America. 
+We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company ’ s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2020, expressed an unqualified opinion on the Company ’ s internal control over financial reporting. 
+Change in Accounting Principle 
+As discussed in Note 2 to the financial statements, the Company changed its method of accounting for leases effective January 1, 2019 due to adoption of Accounting Standards Codification Topic 842 - Leases . 
+Basis for Opinion 
+These financial statements are the responsibility of the Company ’ s management. Our responsibility is to express an opinion on the Company ’ s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. 
+Critical Audit Matter 
+The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. 
+Income Taxes — Tax Receivable Agreements — Refer to Note 10 to the financial statements 
+Critical Audit Matter Description 
+The amounts payable, as well as the timing of such payments, under the tax receivable agreements (“TRA”) are dependent upon significant future events and assumptions, including among others: (i) the amount of the redeeming unit holder’s tax basis in its Liberty Oilfield Services New HoldCo LLC class B units at the time of the relevant redemption, (ii) the characterization of the tax basis step-up, (iii) the depreciation and amortization periods that apply to the increase in tax 
+F-2 
+Table of Contents 
+basis (iv), the amount and timing of taxable income the Company generates in future periods until the TRA payable is settled, and (v) the portion of the Company’s payments under the TRA that constitute imputed interest or give rise to depreciable or amortizable tax basis. 
+During the year ended December 31, 2019, exchanges of Liberty Oilfield Services New HoldCo LLC class B units and shares of Class B Common Stock resulted in an increase of $34.0 million in amounts payable pursuant to tax receivable agreements (“TRA payable”), and a net increase of $40.0 million in deferred tax assets, all of which were recorded as equity transactions, with no impact to the statement of operations. At December 31, 2019, the Company ’ s TRA payable was $50.3 million, a portion of which is presented as a component of current liabilities of $1.8 million and a portion of which is presented as a component of long-term liabilities of $48.5 million. 
+We identified the computation of adjustments to the TRA payable as a critical audit matter because of the multiple owners and complex calculations required to arrive at the correct tax basis upon which to calculate the corresponding TRA payable adjustment. This involved complexity in applying relevant tax law and an increased extent of effort, including the need to involve income tax specialists, when performing audit procedures to evaluate the reasonableness of management’s calculation of tax basis, iterative impact of the computation of adjustments to the TRA payable, and TRA payable as of year end. 
+How the Critical Audit Matter Was Addressed in the Audit 
+Our audit procedures related to the computation of adjustments to the TRA payable included the following, among others: 
+• We tested the effectiveness of controls over the computation of adjustments to the TRA payable, including management ’ s calculation of the step-up in tax basis that serves as the basis for the computation of adjustments to the TRA payable. 
+• With the assistance of our income tax specialists, we read the individual TRAs and compared the terms in the agreements for consistency with the mathematical model used by management to calculate the adjustments to the TRA payable. 
+• With the assistance of our income tax specialists, we evaluated management’s computation of adjustments to the TRA payable, and the TRA payable as of year end that is payable over the contractual period by comparing to our independently recalculated value, taking into account the various class B unit exchanges for Class B Common Stock occurring during the year as well as the adjustments in the TRA payable for each exchange. 
+/s/ DELOITTE & TOUCHE LLP 
+Denver, Colorado 
+February 26, 2020 
+We have served as the Company ’ s auditor since 2016. 
+F-3 
+Table of Contents 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the shareholders and the Board of Directors of Liberty Oilfield Services Inc. 
+Opinion on Internal Control over Financial Reporting 
+We have audited the internal control over financial reporting of Liberty Oilfield Services Inc. and subsidiaries (the “Company”) as of December 31, 2019, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO. 
+We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated and combined financial statements as of and for the year ended December 31, 2019, of the Company and our report dated February 26, 2020, expressed an unqualified opinion on those financial statements. 
+Basis for Opinion 
+The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+Definition and Limitations of Internal Control over Financial Reporting 
+A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+/s/ DELOITTE & TOUCHE LLP 
+Denver, Colorado 
+February 26, 2020 
+F-4 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Consolidated Balance Sheets 
+As of December 31, 2019 and 2018 
+(Dollars in thousands, except share data) 
+2019 2018 
+Assets 
+Current assets: 
+Cash and cash equivalents $ 112,690 $ 103,312 
+Accounts receivable—trade, net allowances for bad debt of $ 1,053 and $ 0 , respectively 
+204,413 153,589 
+Accounts and notes receivable—related party 9,629 15,139 
+Unbilled revenue 38,868 79,233 
+Inventories 88,547 60,024 
+Prepaid and other current assets 34,827 49,924 
+Total current assets 488,974 461,221 
+Property and equipment, net 651,703 627,053 
+Other assets 34,339 28,227 
+Finance lease right-of-use assets 55,337 — 
+Operating lease right-of-use assets 53,076 — 
+Total assets $ 1,283,429 $ 1,116,501 
+Liabilities and Equity 
+Current liabilities: 
+Accounts payable $ 117,613 $ 80,490 
+Accrued liabilities: 
+Accrued vendor invoices 42,753 67,771 
+Operational accruals 26,753 36,414 
+Accrued salaries and benefits 28,805 22,791 
+Accrued interest and other (including payables to related parties of $ 1,329 and $ 0 , respectively) 
+10,643 9,585 
+Accrued liabilities—related party — 2,300 
+Current portion of long-term debt, net of discount of $ 1,341 and $ 1,365 , respectively 
+409 385 
+Current portion of finance lease liabilities 23,646 — 
+Current portion of operating lease liabilities 15,873 — 
+Total current liabilities 266,495 219,736 
+Long-term debt, net of discount of $ 2,485 and $ 3,826 , respectively, less current portion 
+105,731 106,139 
+Deferred tax liability 19,659 32,994 
+Payable pursuant to tax receivable agreements, including payables to related parties of $ 23,797 and $ 2,857 , respectively 
+48,481 16,818 
+Noncurrent portion of finance lease liabilities 24,884 — 
+Noncurrent portion of operating lease liabilities 36,687 — 
+Total liabilities 501,937 375,687 
+Commitments & contingencies (Note 13) 
+Stockholders’ equity: 
+Preferred Stock, $ 0.01 par value, 10,000 shares authorized and no ne issued and outstanding 
+— — 
+Common Stock: 
+Class A, $ 0.01 par value, 400,000,000 shares authorized and 81,885,384 issued and outstanding as of December 31, 2019 and 68,359,871 issued and outstanding as of December 31, 2018 
+819 684 
+Class B, $ 0.01 par value, 400,000,000 shares authorized and 30,638,960 issued and outstanding as of December 31, 2019 and 45,207,372 issued and outstanding as of December 31, 2018 
+307 452 
+Additional paid in capital 410,596 312,659 
+Retained earnings 143,105 119,274 
+Total stockholders’ equity 554,827 433,069 
+Non-controlling interest 226,665 307,745 
+Total equity 781,492 740,814 
+Total liabilities and equity $ 1,283,429 $ 1,116,501 
+See Notes to Consolidated and Combined Financial Statements. 
+F-5 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Consolidated and Combined Statements of Operations 
+For the Years Ended December 31, 2019, 2018, and 2017 
+(In thousands, except per share data) 
+2019 2018 2017 
+Revenue: 
+Revenue $ 1,972,073 $ 2,132,032 $ 1,465,133 
+Revenue—related parties 18,273 23,104 24,722 
+Total revenue 1,990,346 2,155,136 1,489,855 
+Operating costs and expenses: 
+Cost of services (exclusive of depreciation and amortization shown separately below) 1,621,180 1,628,753 1,147,008 
+General and administrative 97,589 99,052 80,089 
+Depreciation and amortization 165,379 125,110 81,473 
+Loss (gain) on disposal of assets 2,601 ( 4,342 ) 148 
+Total operating costs and expenses 1,886,749 1,848,573 1,308,718 
+Operating income 103,597 306,563 181,137 
+Other (income) and expense: 
+Interest income ( 983 ) ( 382 ) ( 53 ) 
+Interest expense 17,485 17,527 11,928 
+Interest (income) expense—related party ( 1,821 ) — 761 
+Total interest expense 14,681 17,145 12,636 
+Net income before income taxes 88,916 289,418 168,501 
+Income tax expense 14,052 40,385 — 
+Net income 74,864 249,033 168,501 
+Less: Net income attributable to Predecessor, prior to Corporate Reorganization — 8,705 168,501 
+Less: Net income attributable to non-controlling interests 35,861 113,979 — 
+Net income attributable to Liberty Oilfield Services Inc. stockholders $ 39,003 $ 126,349 $ — 
+Net income attributable to Liberty Oilfield Services Inc. stockholders per common share: 
+Basic $ 0.54 $ 1.84 
+Diluted $ 0.53 $ 1.81 
+Weighted average common shares outstanding: 
+Basic 72,334 68,838 
+Diluted 105,256 117,838 
+See Notes to Consolidated and Combined Financial Statements. 
+F-6 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Consolidated and Combined Statements of Changes in Equity 
+For the Years Ended December 31, 2019 and 2018 
+(In thousands, except share and per unit data) 
+Shares of Class A Common Stock Shares of Class B Common Stock Class A Common Stock, Par Value Class B Common Stock, Par Value Additional Paid in Capital Retained Earnings Total Stockholders’ equity Non-controlling Interest Total Equity 
+Balance - December 31, 2018 68,360 45,207 $ 684 $ 452 $ 312,659 $ 119,274 $ 433,069 $ 307,745 $ 740,814 
+Exchange of Class B Common Stock for Class A Common Stock 14,568 ( 14,568 ) 145 ( 145 ) 110,852 — 110,852 ( 110,852 ) — 
+Offering Costs — — — — ( 1,012 ) — ( 1,012 ) ( 504 ) ( 1,516 ) 
+Effect of exchange on deferred tax asset, net of liability under tax receivable agreements — — — — 5,930 — 5,930 — 5,930 
+Deferred tax impact of ownership changes from exchanges and repurchases — — — — ( 11,130 ) — ( 11,130 ) — ( 11,130 ) 
+$ 0.20 /share of Class A Common Stock dividend 
+— — — — — ( 15,177 ) ( 15,177 ) — ( 15,177 ) 
+$ 0.20 /unit distributions to non-controlling unitholders 
+— — — — — — — ( 7,747 ) ( 7,747 ) 
+Other distributions and advance payments to non-controlling interest unitholders — — — — — — — ( 6 ) ( 6 ) 
+Share repurchases ( 1,303 ) — ( 13 ) — ( 13,017 ) — ( 13,030 ) ( 4,068 ) ( 17,098 ) 
+Stock based compensation expense — — — 6,638 — 6,638 6,954 13,592 
+Vesting of restricted stock units 268 — 3 — ( 302 ) — ( 299 ) ( 740 ) ( 1,039 ) 
+Restricted Stock and RSU Forfeitures ( 8 ) — — — ( 22 ) 5 ( 17 ) 22 5 
+Net income — — — — — 39,003 39,003 35,861 74,864 
+Balance - December 31, 2019 81,885 30,639 $ 819 $ 307 $ 410,596 $ 143,105 $ 554,827 $ 226,665 $ 781,492 
+F-7 
+Table of Contents 
+Members’ Equity Shares of Class A Common Stock Shares of Class B Common Stock Class A Common Stock, Par Value Class B Common Stock, Par Value Additional Paid in Capital Retained Earnings Total Stockholders’ equity Non-controlling Interest Total Equity 
+Balance—December 31, 2017 $ 392,766 — — $ — $ — $ — $ — $ — $ — $ 392,766 
+Return on redeemable common units ( 149 ) — — — — — — — — ( 149 ) 
+Net income prior to Corporate Reorganization 8,705 — — — — — — — — 8,705 
+Balance prior to Corporate Reorganization $ 401,322 — — $ — $ — $ — $ — $ — $ — $ 401,322 
+Corporate Reorganization 
+Exchange of Liberty LLC Units for Class A Common Stock and Class B Common Stock and extinguishment of redeemable common units ( 401,322 ) 55,986 48,207 560 482 444,824 — 445,866 — 44,544 
+Net deferred tax liability due to Corporate Reorganization — — — — — ( 29,287 ) — ( 29,287 ) — ( 29,287 ) 
+Initial Public Offering 
+Issuance of Class A Common Stock, net of underwriter discount and offering costs — 14,340 — 143 — 219,847 — 219,990 — 219,990 
+Redemption of Legacy Ownership, net of underwriter discount — ( 1,609 ) — ( 16 ) — ( 25,881 ) — ( 25,897 ) — ( 25,897 ) 
+Issuance of restricted stock — 1,259 — 13 — ( 13 ) — — — — 
+Liability due to tax receivable agreements — — — — — ( 2,291 ) — ( 2,291 ) — ( 2,291 ) 
+Initial allocation of non-controlling interest of Liberty LLC effective on the date of the IPO — — — — — ( 261,048 ) — ( 261,048 ) 261,048 — 
+Results Subsequent to Initial Public Offering 
+Distributions and advances paid to non-controlling interest unitholders — — — — — — — — ( 21,288 ) ( 21,288 ) 
+Exchange of Class B Common Stock for Class A Common Stock — 3,000 ( 3,000 ) 30 ( 30 ) 20,534 — 20,534 ( 20,534 ) — 
+Effect of exchange on deferred tax asset, net of liability under tax receivable agreements — — — — — 2,592 — 2,592 — 2,592 
+Restricted stock forfeited — ( 22 ) — — — — — — — — 
+Stock based compensation expense — — — — — 5,450 — 5,450 — 5,450 
+Regular cash dividends declared and distributions paid — — — — — — ( 7,075 ) ( 7,075 ) ( 4,671 ) ( 11,746 ) 
+Share repurchases — ( 4,594 ) — ( 46 ) — ( 62,068 ) — ( 62,114 ) ( 20,789 ) ( 82,903 ) 
+Net income subsequent to Corporate Reorganization and IPO — — — — — — 126,349 126,349 113,979 240,328 
+Balance—December 31, 2018 $ — 68,360 45,207 $ 684 $ 452 $ 312,659 $ 119,274 $ 433,069 $ 307,745 $ 740,814 
+See Notes to Consolidated and Combined Financial Statements. 
+F-8 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Consolidated and Combined Statements of Cash Flows 
+For the Years Ended December 31, 2019, 2018, and 2017 
+(Dollars in thousands) 
+2019 2018 2017 
+Cash flows from operating activities: 
+Net income $ 74,864 $ 249,033 $ 168,501 
+Adjustments to reconcile net income to net cash provided by operating activities: 
+Depreciation and amortization 165,379 125,110 81,473 
+Loss (gain) on disposal of assets 2,601 ( 4,342 ) 148 
+Gain on tax receivable agreements ( 122 ) — — 
+Amortization of debt issuance costs 2,205 4,031 2,311 
+Inventory write down 1,953 3,389 259 
+Non-cash lease expense 3,192 — — 
+Stock based compensation expense 13,592 5,450 — 
+Deferred income tax expense 23,408 20,488 — 
+Bad debt provision 1,053 — — 
+Changes in operating assets and liabilities: 
+Accounts receivable and unbilled revenue ( 11,512 ) 23,074 ( 133,689 ) 
+Accounts receivable and unbilled revenue—related party 5,510 ( 11,096 ) 3,460 
+Inventories ( 30,476 ) ( 4,610 ) ( 27,639 ) 
+Other assets ( 6,464 ) ( 32,771 ) ( 12,611 ) 
+Accounts payable and accrued liabilities 22,386 ( 26,798 ) 111,352 
+Accounts payable and accrued liabilities—related party ( 1,000 ) 300 1,544 
+Payment of operating lease liability ( 5,469 ) — — 
+Net cash provided by operating activities 261,100 351,258 195,109 
+Cash flows from investing activities: 
+Capital expenditures ( 195,173 ) ( 258,835 ) ( 311,794 ) 
+Proceeds from disposal of assets 826 3,343 1,751 
+Net cash used in investing activities ( 194,347 ) ( 255,492 ) ( 310,043 ) 
+Cash flows from financing activities: 
+Proceeds from issuance of Class A Common Stock, net of underwriter discount — 230,174 — 
+Redemption of LLC Units from Legacy Owners — ( 25,897 ) — 
+Proceeds from borrowings on term loan — — 171,500 
+Repayments of borrowings on term loan ( 1,750 ) ( 62,847 ) ( 57,438 ) 
+Proceeds from borrowings on line-of-credit — — 140,559 
+Repayments of borrowings on line-of-credit — ( 30,000 ) ( 158,559 ) 
+Proceeds from Liberty Oilfield Services Holdings LLC — 2,115 — 
+Payments on finance lease and capital lease obligations ( 12,143 ) — ( 119 ) 
+Class A Common Stock dividends ( 14,776 ) ( 6,907 ) — 
+Per unit distributions to non-controlling interest unitholders ( 7,747 ) ( 4,671 ) — 
+Other distributions and advance payments to non-controlling interest unitholders ( 6 ) ( 21,288 ) — 
+Tax withholding on restricted stock unit vesting ( 1,039 ) — — 
+Share repurchases ( 18,398 ) ( 82,903 ) — 
+Proceeds from related party bridge loans — — 60,000 
+Payments of debt issuance costs — ( 315 ) ( 9,036 ) 
+Proceeds from issuance of redeemable common units — — 39,794 
+Payments for redemption of redeemable common units — — ( 62,739 ) 
+Payment of equity offering costs ( 1,516 ) ( 6,236 ) ( 4,191 ) 
+Net cash (used in) provided by financing activities ( 57,375 ) ( 8,775 ) 119,771 
+Net increase in cash and cash equivalents 9,378 86,991 4,837 
+Cash and cash equivalents—beginning of period 103,312 16,321 11,484 
+Cash and cash equivalents—end of period $ 112,690 $ 103,312 $ 16,321 
+F-9 
+Table of Contents 
+Supplemental disclosure of cash flow information: 
+Cash paid for income taxes $ 1,042 $ 27,263 $ — 
+Cash paid for interest $ 12,642 $ 13,957 $ 9,766 
+Non-cash investing and financing activities: 
+Capital expenditures included in accounts payable and accrued liabilities $ 32,143 $ 45,703 $ 18,687 
+Related party bridge loans exchanged for Redeemable Class 2 Common Units $ — $ — $ 60,679 
+See Notes to Consolidated and Combined Financial Statements. 
+F-10 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Note 1— Organization and Basis of Presentation 
+Organization 
+Liberty Oilfield Services Inc. (the “Company”) was incorporated as a Delaware corporation on December 21, 2016, to become a holding corporation for Liberty Oilfield Services New HoldCo LLC (“Liberty LLC”) and its subsidiaries upon completion of a corporate reorganization (as detailed below, the “Corporate Reorganization”) and planned initial public offering of the Company (“IPO”). The Company has no material assets other than its ownership in Liberty LLC. 
+Prior to the Corporate Reorganization, Liberty Oilfield Services Holdings LLC (“Liberty Holdings”) wholly owned Liberty Oilfield Services LLC (“LOS”) and LOS Acquisition CO I LLC (“ACQI” and, together with LOS, the “Predecessor”), which includes the assets and liabilities of LOS Odessa RE Investments, LLC (“Odessa”) and LOS Cibolo RE Investments, LLC (“Cibolo”). Following the Corporate Reorganization, Liberty LLC wholly owns the Predecessor. Effective March 22, 2018, the assets of ACQI were contributed into LOS and ACQI was dissolved. 
+The Company, together with its subsidiaries, is a multi-basin provider of hydraulic fracturing services and goods, with a focus on deploying the latest technologies in the technically demanding oil and gas reservoirs in which it operates, principally in North Dakota, Colorado, Wyoming and Texas. 
+Corporate Reorganization 
+In connection with the IPO, the Company completed the Corporate Reorganization, including the following series of transactions: 
+• Liberty Holdings contributed all of its assets to Liberty LLC in exchange for Liberty LLC Units (as defined below); 
+• Liberty Holdings liquidated and distributed to its then-existing owners (the “Legacy Owners”) Liberty LLC Units pursuant to the terms of the limited liability company agreement of Liberty Holdings and the Master Reorganization Agreement dated as of January 11, 2018, by and among the Company, Liberty Holdings, Liberty LLC, and the other parties named therein (the “Master Reorganization Agreement”); 
+• Certain of the Legacy Owners directly or indirectly contributed all or a portion of their Liberty LLC Units to the Company in exchange for 55,685,027 shares of our Class A common stock, par value $ 0.01 per share (the “Class A Common Stock”), and 1,258,514 restricted shares of Class A Common Stock. Subsequent to the initial exchange, 1,609,122 shares of Class A Common Stock were redeemed for an aggregate price of $ 25.9 million, upon the exercise of the underwriters’ overallotment option; 
+• the Company issued, at par, the Legacy Owners that continued to own Liberty LLC Units (the “Liberty Unit Holders”) an aggregate amount of 48,207,372 shares of our Class B common stock, par value $ 0.01 per share (the “Class B Common Stock”); and 
+• the Company contributed the net proceeds it received from the IPO to Liberty LLC in exchange for additional Liberty LLC Units such that the Company held a total number of Liberty LLC Units equal to the number of shares of Class A Common Stock outstanding immediately following the IPO. 
+Initial Public Offering 
+On January 17, 2018, the Company completed its IPO of 14,640,755 shares of Class A Common Stock at a public offering price of $ 17.00 per share, of which 14,340,214 shares were offered by the Company and 300,541 were offered by the selling shareholder. The Company received $ 220.0 million net proceeds from the IPO, after deducting approximately $ 13.4 million in underwriting discounts and commissions and $ 10.4 million in other offering costs. The Company did not receive any proceeds from the sale of the shares of Class A Common Stock by the selling shareholder. The Company used $ 25.9 million of net proceeds to redeem ownership interests in Liberty LLC from the Legacy Owners. The Company contributed the remaining net proceeds to Liberty LLC in exchange for units in Liberty LLC (the “Liberty LLC Units”). Liberty LLC used a portion of these net proceeds (i) to repay outstanding borrowings and accrued interest under the Predecessor’s ABL Facility (as defined herein), totaling approximately $ 30.1 million, (ii) to repay 35 % of the Predecessor’s outstanding borrowings, accrued interest and prepayment premium under the Term Loan Facility (as defined herein), totaling approximately $ 62.5 million and (iii) for general corporate purposes, including repayment of additional indebtedness and funding capital expenditures. As of December 31, 2019 and 2018, the Company owned 72.8 %, and 60.2 % of Liberty LLC, respectively. 
+F-11 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Basis of Presentation 
+The accompanying consolidated and combined financial statements were prepared using generally accepted accounting principles in the United States of America (“GAAP”) and the instructions to Form 10-K, Regulation S-X and the rules and regulations of the Securities and Exchange Commission. 
+The accompanying consolidated and combined financial statements and related notes present the consolidated financial position, results of operations, cash flows, and equity of the Company as of and for the years ended December 31, 2019 and 2018, and the combined results of operations and cash flows of the Predecessor for the year ended December 31, 2017. 
+All intercompany amounts have been eliminated in the presentation of the consolidated financial statements of the Company and the combined financial statements of the Predecessor. Comprehensive income is not reported due to the absence of items of other comprehensive income or loss during the periods presented. The consolidated and combined financial statements include financial data at historical cost as the contribution of assets is considered to be a reorganization of entities under common control. The consolidated and combined financial statements may not be indicative of the actual level of assets, liabilities and costs that would have been incurred by the Predecessor if it had operated as an independent, publicly-traded company during the periods prior to the IPO or of the costs expected to be incurred in the future. 
+The consolidated and combined financial statements for periods prior to January 17, 2018, reflect the historical results of the Predecessor. The consolidated financial statements include the amounts of the Company and all majority owned subsidiaries where the Company has the ability to exercise control. 
+The Company’s operations are organized into a single reportable segment, which consists of hydraulic fracturing services and goods. 
+Note 2— Significant Accounting Policies 
+Use of Estimates 
+The preparation of consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 
+The consolidated and combined financial statements include certain amounts that are based on management’s best estimates and judgments. The most significant estimates relate to the collectibility of accounts receivable and estimates of allowance for doubtful accounts, the useful lives and salvage values of long-lived assets, future cash flows associated with long-lived assets, net realizable value of inventory, and equity unit valuation. These estimates may be adjusted as more current information becomes available. 
+Cash and Cash Equivalents 
+The Company considers all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. The Company continually monitors its positions with, and the credit quality of, the financial institutions with which it has banking relationships. As of the balance sheet date, and periodically throughout the year, the Company has maintained balances in various operating accounts in excess of federally insured limits. 
+Accounts Receivable 
+The Company analyzes the need for an allowance for doubtful accounts for estimated losses related to potentially uncollectible accounts receivable on a case-by-case basis throughout the year. In establishing the required allowance, management considers historical losses adjusted to take into account current market conditions and the customers’ financial condition, the amount of receivables, the current receivables aging and current payment patterns. The Company reserves amounts based on specific identification. Account balances are charged to the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. It is reasonably possible that the Company’s estimate of the allowance for doubtful accounts will change and that losses ultimately incurred could differ materially from the amounts estimated in determining the allowance. 
+Inventories 
+Inventories consist of raw materials used in the hydraulic fracturing process, such as proppants, chemicals, and field service equipment maintenance parts and are stated at the lower of cost, determined using the weighted average cost method, or net realizable value. Inventories are charged to cost of services as used when providing hydraulic fracturing services. Net 
+F-12 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable cost of completion, disposal, and transportation. 
+Property and Equipment 
+Property and equipment are stated at cost. Depreciation and amortization expense is recognized on property and equipment, excluding land, utilizing the straight-line method over the estimated useful lives, ranging from two to 30 years. The Company estimates salvage values that it does not depreciate. 
+Construction in-progress, a component of property and equipment, represents long-lived assets being developed by the Company. These assets are not subject to depreciation until they are completed and ready for their intended use, at which point the Company reclassifies them to field services equipment or vehicles, as appropriate. 
+The Company assesses its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is assessed using undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets. The Company determined the lowest level of identifiable cash flows to be at the asset group, which is the aggregate of the Company’s hydraulic fracturing fleets that are in service. A long-lived asset is not recoverable if its carrying amount exceeds the sum of estimated undiscounted cash flows expected to result from the use and eventual disposition. When alternative courses of action to recover the carrying amount of the asset group are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the asset is not recoverable, an impairment loss is recognized in an amount by which its carrying amount exceeds its estimated fair value, such that its carrying amount is adjusted to its estimated fair value, with an offsetting charge to impairment expense. 
+The Company measures the fair value of its property and equipment using the discounted cash flow method. The expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments of projected revenue growth, fleet count, utilization, gross margin rates, selling, general and administrative rates, working capital fluctuations, capital expenditures, discount rates and terminal growth rates. 
+During 2019, 2018 and 2017, the Company did not test its long-lived assets for recoverability as there were no triggering events. No impairment was recognized during the years ended December 31, 2019, 2018 and 2017 . 
+Major Maintenance Activities 
+The Company incurs maintenance costs on its major equipment. The determination of whether an expenditure should be capitalized or expensed requires management judgment in the application of how the costs incurred benefit future periods, relative to the Company’s capitalization policy. Costs that either establish or increase the efficiency, productivity, functionality or life of a fixed asset are capitalized and depreciated over the remaining useful life of the asset. 
+Leases 
+On January 1, 2019, the Company adopted Accounting Standards Update (“ASU”) No. 2016-02, Leases (Accounting Standard Codification (“ASC”) Topic 842), as amended by other ASUs issued since February 2016 (“ASU 2016-02” or “ASC Topic 842”), using the modified retrospective transition method applied at the effective date of the standard. By electing this optional transition method, information prior to January 1, 2019 has not been restated and continues to be reported under the accounting standards in effect for the period (ASC Topic 840). 
+The Company elected the package of practical expedients permitted under the transition guidance within the new standard, including the option to carry forward the historical lease classifications and assessment of initial direct costs. The Company also elected to account for lease and non-lease components as a single component, and to not include leases with an initial term of less than 12 months in the lease assets and liabilities. 
+The adoption of ASC Topic 842 resulted in the recognition of finance lease right-of-use assets, operating lease right-of-use assets, and lease liabilities for finance and operating leases. As of January 1, 2019, the adoption of the new standard resulted in the recognition of finance lease assets of $ 57.2 million, including $ 2.1 million and $ 2.0 million reclassified from prepaid and other current assets and other assets, respectively, and finance lease liabilities of $ 53.2 million. Additionally, the Company recorded operating lease assets of $ 64.0 million, including $ 1.9 million reclassified from prepaid and other current assets, and operating lease liabilities of $ 63.6 million, including $ 1.5 million reclassified from accrued interest and other liabilities as of January 1, 2019. There was no significant impact to the consolidated statements of income, equity or cash flows. 
+For leases entered into after January 1, 2019, the Company determines if an arrangement is a lease at inception and evaluates identified leases for operating or finance lease treatment. Operating or finance lease right-of-use assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. The Company uses the rate implicit in the lease, when available, or an estimated fully collateralized incremental borrowing rate corresponding with 
+F-13 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+the lease term and the information available at the commencement date in determining the present value of lease payments. Lease terms may include options to renew, however, the Company typically cannot determine its intent to renew a lease with reasonable certainty at inception. 
+Deferred Financing Costs 
+Costs associated with obtaining debt financing are deferred and amortized to interest expense using the effective interest method. In accordance with ASU No. 2015-03 and 2015-15, for all periods the Company has reflected deferred financing costs related to term loan debt as a direct deduction from the carrying amount, and costs associated with line-of-credit arrangements as other assets. 
+Income Taxes 
+Following the IPO, the Company is a corporation and is subject to U.S. federal, state and local income tax on its share of Liberty LLC’s taxable income. As a result of the IPO and Corporate Reorganization, the Company recorded deferred tax assets and liabilities for the difference between the book value of assets and liabilities for financial reporting purposes and those amounts applicable for income tax purposes. 
+Deferred income taxes are computed using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Deferred tax assets and liabilities are calculated using the enacted tax rates in effect for the year in which the deferred tax asset or liability is expected to reverse. The Company classifies all deferred tax assets and liabilities as non-current. 
+The Company recognizes the financial statement effects of a tax position when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. Previously recognized tax positions are reversed in the first period in which it is no longer more-likely-than-not that the tax position would be sustained upon examination. Income tax related interest and penalties, if applicable, are recorded as a component of the provision for income tax expense. 
+Tax Receivable Agreements 
+In connection with the IPO, on January 17, 2018, the Company entered into two Tax Receivable Agreements (the “TRAs”) with the R/C Energy IV Direct Partnership, L.P. and the Legacy Owners that continued to own Liberty LLC Units (each such person and any permitted transferee, a “Tax Receivable Agreement Holder” and together, the “Tax Receivable Agreement Holders”). The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that the Company actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result, as applicable to each Tax Receivable Agreement Holder, of (i) certain increases in tax basis that occur as a result of the Company’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such Tax Receivable Agreement Holder’s Liberty LLC Units in connection with the IPO or pursuant to the exercise of the right (the “Redemption Right”) or the Company’s right (the “Call Right”), (ii) any net operating losses available to the Company as a result of the Corporate Reorganization, and (iii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRAs. 
+With respect to obligations the Company expects to incur under the TRAs (except in cases where the Company elects to terminate the TRAs early, the TRAs are terminated early due to certain mergers, asset sales, or other changes of control or the Company has available cash but fails to make payments when due), generally the Company may elect to defer payments due under the TRAs if the Company does not have available cash to satisfy its payment obligations under the TRAs or if its contractual obligations limit its ability to make such payments. Any such deferred payments under the TRAs generally will accrue interest. In certain cases, payments under the TRAs may be accelerated and/or significantly exceed the actual benefits, if any, the Company realizes in respect of the tax attributes subject to the TRAs. The Company accounts for amounts payable under the TRAs in accordance with ASC Topic 450, Contingencies . 
+If the Company experiences a change of control (as defined under the TRAs) or the TRAs otherwise terminate early, the Company’s obligations under the TRAs could have a substantial negative impact on its liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. 
+F-14 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Share Repurchases 
+The Company accounts for the purchase price of repurchased Class A Common Stock in excess of par value ($0.01 per share of Class A Common Stock) as a reduction of additional paid-in capital, and will continue to do so until additional paid-in capital is reduced to zero. Thereafter, any excess purchase price will be recorded as a reduction to retained earnings. 
+Revenue Recognition 
+Effective January 1, 2018, the Company adopted a comprehensive new revenue recognition standard, ASC Topic 606- Revenue from Contracts with Customers . The details of the significant changes to accounting policies resulting from the adoption of the new standard are set out below. The Company adopted the standard using a modified retrospective method; accordingly, the comparative information for the year ended December 31, 2017 has not been adjusted and continues to be reported under the previous revenue standard. The adoption of this standard did not have a material impact to the consolidated financial position, reported revenue, results of operations or cash flows as of and for the year ended December 31, 2018. 
+Under the new standard, revenue recognition is based on the transfer of control, or the customer’s ability to benefit from the services and products in an amount that reflects the consideration expected to be received in exchange for those services and products. In recognizing revenue for services and products, the transaction price is determined from sales orders or contracts with customers. Revenue is recognized at the completion of each fracturing stage, and in most cases the price at the end of each stage is fixed, however, in limited circumstances contracts may contain variable consideration. 
+Variable consideration typically may relate to discounts, price concessions and incentives. We estimate variable consideration based on the amount of consideration we expect to receive. The Company accrues revenue on an ongoing basis to reflect updated information for variable consideration as performance obligations are met. 
+The Company also assesses customers’ ability and intention to pay, which is based on a variety of factors including historical payment experience and financial condition. Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30 to 45 days. 
+In connection with the adoption of ASC Topic 842, the Company determined that certain of its service revenue contracts contain a lease component. The Company elected to adopt a practical expedient available to lessors, which allows the Company to combine the lease and non-lease components and account for the combined component in accordance with the accounting treatment for the predominant component. Therefore, the Company combines the lease and service component for certain of the Company’s service contracts and continues to account for the combined component under ASC Topic 606, Revenue from Contracts with Customers. 
+Deferred Revenue 
+From time to time, the Company may require partial payment in advance from new customers to secure credit or from existing customers in order to secure additional hydraulic fracturing services. Initially, such payments are recorded in the accompanying consolidated and combined financial statements as deferred revenue, and upon performance of the agreed services, the Company recognizes revenue consistent with its revenue recognition policy described above. As of December 31, 2019 and December 31, 2018, the Company had no amounts recorded as deferred revenue. During the year ended December 31, 2018, the Company recognized to revenue $ 9.2 million of customer prepayments initially recorded as deferred revenue. 
+Fleet Start-up Costs 
+The Company incurs start-up costs to commission a new fleet or district. These costs include hiring and training of personnel, and acquisition of consumable parts and tools. Start-up costs are expensed as incurred, and are reflected in general and administrative expense in the consolidated and combined statement of operations. Start-up costs for the years ended December 31, 2019, 2018 and 2017, were $ 4.5 million, $ 10.1 million and $ 14.0 million, respectively. Start-up costs incurred during the years ended December 31, 2019, 2018 and 2017 related to the establishment of one , three , and nine new fleets, respectively. 
+The terms and conditions of the Credit Facilities between the Company and its lenders provides for the add-back of costs or expenses incurred in connection with the acquisition, deployment and opening of any new hydraulic fracturing fleet or district in the computation of certain financial covenants. (See Note 6—Debt). 
+Reclassifications 
+Certain amounts in the prior period financial statements have been reclassified to conform to the presentation of the current period financial statements. These reclassifications had no effect on the previously reported net income. 
+F-15 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Recently Adopted Accounting Standards 
+On January 1, 2019, the Company adopted ASC Topic 842 using the modified retrospective transition method applied at the effective date of the standard. By electing the modified retrospective transition method, information prior to January 1, 2019 has not been restated and continues to be reported under the accounting standards in effect for the period (Topic 840). The adoption of this standard impacted the consolidated statements of financial position by requiring the recognition of a right-of-use asset and a lease liability; however, the adoption of this standard did not have a significant impact on the consolidated statements of operations or cash flows. See Significant Accounting Policies - Leases for additional information regarding this accounting policy. 
+Recently Issued Accounting Standards 
+In June 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-13, “ Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments ,” which is effective for fiscal years and interim periods within fiscal years beginning after December 15, 2019, with a modified-retrospective approach to be used for implementation. ASU 2016-13 changes the impairment model for most financial assets and certain other instruments. Specifically, this new guidance requires using a forward looking, expected loss model for trade and other receivables, held-to-maturity debt securities, loans, and other instruments. This will replace the currently used model and may result in an earlier recognition of allowance for losses. The Company plans to adopt the standard effective January 1, 2020. Although the Company is continuing to evaluate the impact the adoption will have, the Company currently does not expect the adoption to have a material impact on its consolidated financial statements. 
+Note 3— Inventories 
+Inventories consist of the following: 
+December 31, 
+($ in thousands) 2019 2018 
+Proppants $ 14,013 $ 22,038 
+Chemicals 10,076 10,781 
+Maintenance parts 64,458 27,205 
+$ 88,547 $ 60,024 
+During the year ended December 31, 2019 and December 31, 2018, the lower of cost or net realizable value analysis resulted in the Company recording a write-down to inventory carrying values of $ 2.0 million and $ 3.4 million, respectively, included as a component in cost of services in the consolidated statements of income for the years ended December 31, 2019 and December 31, 2018. 
+F-16 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Note 4— Property and Equipment 
+Property and equipment consist of the following: 
+Estimated 
+useful lives 
+(in years) December 31, 
+2019 2018 
+($ in thousands) 
+Land N/A $ 5,400 $ 5,400 
+Field services equipment 
+2 - 7 
+978,418 778,423 
+Vehicles 
+4 - 7 
+60,290 59,807 
+Buildings and facilities 
+5 - 30 
+29,930 27,795 
+Office equipment and furniture 
+2 - 7 
+6,623 6,200 
+1,080,661 877,625 
+Less accumulated depreciation and amortization ( 455,687 ) ( 307,277 ) 
+624,974 570,348 
+Construction in-progress N/A 26,729 56,705 
+$ 651,703 $ 627,053 
+During the years ended December 31, 2019, 2018 and 2017, the Company recognized depreciation expense of $ 153.6 million, $ 124.9 million and $ 81.5 million respectively. 
+In November 2018, one of the Company’s hydraulic frac fleets was involved in an accidental fire, which resulted in damage to a portion of the equipment in that fleet. The Company accrued $ 15.7 million of insurance proceeds for replacement cost of the damaged equipment, which is presented in prepaid and other current assets on the accompanying consolidated balance sheets as of December 31, 2018. The accrued insurance proceeds offset the $ 4.3 million loss recognized on the damaged equipment. The resulting net gain of $ 11.5 million was recognized in (gain) loss on disposal of assets for the year ended December 31, 2018. 
+Note 5— Leases 
+The Company has operating and finance leases primarily for vehicles, equipment, railcars, office space, and facilities. The terms and conditions for these leases vary by the type of underlying asset. 
+Certain leases include variable lease payments for items such as property taxes, insurance, maintenance, and other operating expenses associated with leased assets. Payments that vary based on an index or rate are included in the measurement of lease assets and liabilities at the rate as of the commencement date. All other variable lease payments are excluded from the measurement of lease assets and liabilities, and are recognized in the period in which the obligation for those payments is incurred. 
+The components of lease expense as of December 31, 2019 were as follows: 
+($ in thousands) December 31, 2019 
+Finance lease cost: 
+Amortization of right-of-use assets $ 10,256 
+Interest on lease liabilities 2,652 
+Operating lease cost 20,731 
+Variable lease cost 3,118 
+Total lease cost $ 36,757 
+In accordance with prior guidance, ASC 840, Leases , total rent expense was $ 40.9 million and $ 20.8 million for the years ended December, 31, 2018 and 2017, respectively. 
+F-17 
+Supplemental cash flow and other information related to leases as of December 31, 2019 were as follows: 
+($ in thousands) December 31, 2019 
+Cash paid for amounts included in measurement of liabilities: 
+Operating leases $ 20,849 
+Finance leases 14,795 
+Right-of-use assets upon adoption of ASC 842 and obtained in exchange for new lease liabilities: 
+Operating leases 70,611 
+Finance leases 65,333 
+Lease terms and discount rates as of December 31, 2019 were as follows: 
+December 31, 2019 
+Weighted-average remaining lease term: 
+Operating leases 6.4 years 
+Finance leases 1.3 years 
+Weighted-average discount rate: 
+Operating leases 5.4 % 
+Finance leases 5.2 % 
+Future minimum lease commitments as of December 31, 2019 are as follows: 
+($ in thousands) Finance Operating 
+2020 $ 26,407 $ 18,262 
+2021 20,626 13,696 
+2022 4,135 7,249 
+2023 — 4,365 
+2024 — 3,646 
+Thereafter — 16,017 
+Total lease payments 51,168 63,235 
+Less imputed interest ( 2,638 ) ( 10,675 ) 
+Total $ 48,530 $ 52,560 
+The Company’s vehicle leases typically include a residual value guarantee. For the Company’s vehicle leases classified as operating leases, the total residual value guaranteed as of December 31, 2019 is $ 2.9 million; the payment is not probable and therefore has not been included in the measurement of the lease liability and right-of-use asset. For vehicle leases that are classified as finance leases, the Company includes the residual value guarantee, estimated in the lease agreement, in the financing lease liability. 
+In accordance with the prior guidance, ASC 840, Leases , the future minimum lease payments as determined prior to the adoption of ASC 842, Leases , for the fiscal year ended December 31, 2018, were as follows: 
+($ in thousands) 
+2019 $ 42,717 
+2020 48,685 
+2021 32,390 
+2022 6,093 
+2023 4,303 
+Thereafter 19,742 
+$ 153,930 
+F-18 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Note 6— Debt 
+Debt consists of the following : 
+December 31, 
+2019 2018 
+Term Loan Outstanding $ 109,966 $ 111,715 
+Revolving Line of Credit — — 
+Deferred financing costs and original issue discount ( 3,826 ) ( 5,191 ) 
+Total debt, net of deferred financing costs and original issue discount $ 106,140 $ 106,524 
+Current portion of long-term debt, net of discount $ 409 $ 385 
+Long-term debt, net of discount and current portion 105,731 106,139 
+$ 106,140 $ 106,524 
+On September 19, 2017, the Company entered into two new credit agreements for a revolving line of credit up to $ 250.0 million (the “ABL Facility”) and a $ 175.0 million term loan (the “Term Loan Facility”, and together with the ABL Facility the “Credit Facilities”). 
+ABL Facility 
+Under the terms of the ABL Facility, up to $ 250.0 million may be borrowed, subject to certain borrowing base limitations based on a percentage of eligible accounts receivable and inventory. As of December 31, 2019, the borrowing base was calculated to be $ 171.1 million, and the Company had no borrowings outstanding, except for a letter of credit in the amount of $ 0.3 million, with $ 170.8 million of remaining availability. Borrowings under the ABL Facility bear interest at LIBOR or a base rate, plus an applicable LIBOR margin of 1.5 % to 2.0 % or base rate margin of 0.5 % to 1.0 %, as defined in the ABL Facility credit agreement. The unused commitment is subject to an unused commitment fee of 0.375 % to 0.5 %. Interest and fees are payable in arrears at the end of each month, or, in the case of LIBOR loans, at the end of each interest period. The ABL Facility matures on the earlier of (i) September 19, 2022, and (ii) to the extent the debt under the Term Loan Facility remains outstanding, 90 days prior to the final maturity of the Term Loan Facility, which matures on September 19, 2022. Borrowings under the ABL Facility are collateralized by accounts receivable and inventory, and further secured by the Company, Liberty LLC and R/C IV Non-U.S. LOS Corp., a Delaware corporation and a subsidiary of the Company, as parent guarantors. 
+Term Loan Facility 
+The Term Loan Facility provides for a $ 175.0 million term loan, of which $ 110.0 million remained outstanding as of December 31, 2019. Amounts outstanding bear interest at LIBOR or a base rate, plus an applicable margin of 7.625 % or 6.625 %, respectively, and the weighted average rate on borrowings was 9.4 % as of December 31, 2019. The Company is required to make quarterly principal payments of 1 % per annum of the outstanding principal balance, commencing on December 31, 2017, with final payment due at maturity on September 19, 2022. The Term Loan Facility is collateralized by the fixed assets of LOS and its subsidiaries, and is further secured by the Company, Liberty LLC and R/C IV Non-U.S. LOS Corp., a Delaware corporation and a subsidiary of the Company, as parent guarantors. 
+The Credit Facilities include certain non-financial covenants, including but not limited to restrictions on incurring additional debt and certain distributions. Moreover, the ability of the Company to incur additional debt and to make distributions is dependent on maintaining a maximum leverage ratio. The Term Loan Facility requires mandatory prepayments upon certain dispositions of property or issuance of other indebtedness, as defined, and annually a percentage of excess cash flow ( 25 % to 50 %, depending on leverage ratio, of consolidated net income less capital expenditures and other permitted payments, commencing with the year ending December 31, 2018). Certain mandatory prepayments and optional prepayments are subject to a prepayment premium of 3 % of the prepaid principal declining annually to 1 % during the first three years of the term of the Term Loan Facility. 
+The Credit Facilities are not subject to financial covenants unless liquidity, as defined in the respective credit agreements, drops below a specified level. Under the ABL Facility, the Company is required to maintain a minimum fixed charge coverage ratio, as defined in the credit agreement governing the ABL Facility, of 1.0 to 1.0 for each period if excess availability is less than 10 % of the borrowing base or $ 12.5 million, whichever is greater. Under the Term Loan Facility, the Company is required to maintain a minimum fixed charge coverage ratio, as defined, of 1.2 to 1.0 for each trailing twelve-month report if the Company’s liquidity, as defined, is less than $ 25.0 million for at least five consecutive business days. 
+The Company was in compliance with these covenants as of December 31, 2019. 
+F-19 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Maturities of debt are as follows: 
+($ in thousands) 
+Years Ending December 31, 
+2020 $ 1,750 
+2021 1,750 
+2022 106,466 
+2023 — 
+2024 — 
+$ 109,966 
+Note 7— Fair Value Measurements and Financial Instruments 
+The fair values of the Company’s assets and liabilities represent the amounts that would be received to sell those assets or that would be paid to transfer those liabilities in an orderly transaction at the reporting date. These fair value measurements maximize the use of observable inputs. However, in situations where there is little, if any, market activity for the asset or liability at the measurement date, the fair value measurement reflects the Company’s own judgments about the assumptions that market participants would use in pricing the asset or liability. The Company discloses the fair values of its assets and liabilities according to the quality of valuation inputs under the following hierarchy: 
+• Level 1 Inputs: Quoted prices (unadjusted) in an active market for identical assets or liabilities. 
+• Level 2 Inputs: Inputs other than quoted prices that are directly or indirectly observable. 
+• Level 3 Inputs: Unobservable inputs that are significant to the fair value of assets or liabilities. 
+The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those that are initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from unobservable inputs is inconsequential to the overall fair value, or if corroborated market data becomes available. Assets and liabilities that are initially reported as Level 2 are subsequently reported as Level 3 if corroborated market data is no longer available. Transfers occur at the end of the reporting period. There were no transfers into or out of Levels 1, 2 and 3 during the years ended December 31, 2019 and 2018. 
+The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, notes receivable, accounts payable, accrued liabilities, long-term debt, and finance and operating lease obligations. These financial instruments do not require disclosure by level. The carrying values of all the Company’s financial instruments included in the accompanying balance sheets approximated or equaled their fair values at December 31, 2019 and 2018. 
+• The carrying values of cash and cash equivalents, accounts receivable and accounts payable (including accrued liabilities) approximated fair value at December 31, 2019 and 2018, due to their short-term nature. 
+• The carrying value of amounts outstanding under long-term debt agreements with variable rates approximated fair value at December 31, 2019 and 2018, as the effective interest rates approximated market rates. 
+Nonrecurring Measurements 
+Certain assets are measured at fair value on a nonrecurring basis. These assets are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances. These assets consist of notes receivable—related party from the Affiliate, as defined and described in Note 12—Related Party Transactions. The note was initially recorded for the trade receivables, created in the normal course of business, due from the Affiliate as of the Agreement Date, as defined in Note 12—Related Party Transactions. There were no identified events or changes in circumstances that had a significant adverse effect on the fair value of the notes receivable. These notes are classified as Level 3 in the fair value hierarchy as the inputs to the determination of fair value are based upon unobservable inputs. As of December 31, 2019 and December 31, 2018, notes receivable—related party from the Affiliate totaled $ 2.5 million and $ 0 , respectively. 
+Recurring Measurements 
+The fair values of the Company’s cash equivalents measured on a recurring basis pursuant to ASC 820-10 Fair Value Measurements and Disclosures are carried at estimated fair value. Cash equivalents consist of money market accounts which 
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+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+the Company has classified as Level 1 given the active market for these accounts. As of December 31, 2019 and 2018, the Company had cash equivalents, measured at fair value, of $ 86.9 million and $ 0 , respectively. 
+Nonfinancial assets 
+The Company estimates fair value to perform impairment tests as required on long-lived assets. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3 in the event that such assets were required to be measured and recorded at fair value within the consolidated and combined financial statements. There were no such measurements required as of December 31, 2019 and 2018. 
+Credit Risk 
+The Company’s financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents, and trade receivables. 
+The Company’s cash and cash equivalents balance on deposit with financial institutions total $ 112.7 million and $ 103.3 million as of December 31, 2019 and 2018, respectively, which, as of certain dates, exceeded FDIC insured limits. The Company regularly monitors these institutions’ financial condition. 
+The majority of the Company’s customers have payment terms of 45 days or less. As of December 31, 2019 and 2018, customer A accounted for 12 % and customers A and B accounted for 28 % of total accounts receivable and unbilled revenue, respectively. The Company mitigates the associated credit risk by performing credit evaluations and monitoring the payment patterns of its customers. For the year ended December 31, 2019, no customers accounted for more than 10 % of total revenue. For the years ended December 31, 2018 and 2017, customer B accounted for 11 % and customers C and D accounted for 36 % of total revenue, respectively. 
+As of December 31, 2019, the Company recorded a provision for doubtful accounts related to one specific entity engaged in the business of oil and gas exploration and production that has filed for bankruptcy. As of December 31, 2018, the Company had no provision for doubtful accounts, and the balance as of December 31, 2017 represented the bankruptcy of one specific entity. 
+($ in thousands) 2019 2018 2017 
+Allowance for doubtful accounts, beginning of year $ — $ — $ 497 
+Bad debt expense: 
+Provision for doubtful accounts 1,053 — — 
+Write off of uncollectible accounts against reserve — — ( 497 ) 
+Allowance for doubtful accounts, end of year $ 1,053 $ — $ — 
+Note 8— Equity 
+Preferred Stock 
+As of December 31, 2019 and 2018 the Company had 10,000 shares of preferred stock authorized, par value $ 0.01 , with none issued and outstanding. If issued, each class or series of preferred stock will cover the number of shares and will have the powers, preferences, rights, qualifications, limitations and restrictions determined by the Company's board of directors, which may include, among others, dividend rights, liquidation preferences, voting rights, conversion rights, preemptive rights and redemption rights. Except as provided by law or in a preferred stock designation, the holders of preferred stock will not be entitled to vote at or receive notice of any meeting of shareholders. 
+Class A Common Stock 
+The Company had a total of 81,885,384 shares of Class A Common Stock outstanding as of December 31, 2019, which includes 268,205 shares of restricted stock. As of December 31, 2018, the Company had a total of 68,359,871 shares of Class A Common Stock outstanding, which included 634,653 shares of restricted stock. Holders of Class A Common Stock are entitled to one vote per share on all matters to be voted upon by the stockholders and are entitled to ratably receive dividends when and if declared by the Company’s board of directors. 
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+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Class B Common Stock 
+The Company had a total of 30,638,960 and 45,207,372 shares of Class B Common Stock outstanding as of December 31, 2019 and 2018, respectively. Holders of the Class B Common Stock are entitled to one vote per share on all matters to be voted upon by stockholders. Holders of Class A Common Stock and Class B Common Stock vote together as a single class on all matters presented to the Company’s stockholders for their vote or approval, except with respect to amendment of certain provisions of the Company’s certificate of incorporation that would alter or change the powers, preferences or special rights of the Class B Common Stock so as to affect them adversely, which amendments must be by a majority of the votes entitled to be cast by the holders of the shares affected by the amendment, voting as a separate class, or as otherwise required by applicable law. 
+Holders of Class B Common Stock do not have any right to receive dividends, unless the dividend consists of shares of Class B Common Stock or of rights, options, warrants or other securities convertible or exercisable into or exchangeable for shares of Class B Common Stock paid proportionally with respect to each outstanding share of Class B Common Stock and a dividend consisting of shares of Class A Common Stock or of rights, options, warrants or other securities convertible or exercisable into or exchangeable for shares of Class A Common Stock on the same terms is simultaneously paid to the holders of Class A Common Stock. Holders of Class B Common Stock do not have any right to receive a distribution upon liquidation or winding up of the Company. 
+Under the Second Amended and Restated Limited Liability Company Agreement of Liberty LLC (the “Liberty LLC Agreement”), each Liberty Unit Holder has, subject to certain limitations, the Redemption Right, which allows it to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units, for, at Liberty LLC’s election, (i) shares of Class A Common Stock at a redemption ratio of one share of Class A Common Stock for each Liberty LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions or (ii) an equivalent amount of cash. Alternatively, upon the exercise of the Redemption Right, the Company (instead of Liberty LLC) will have the Call Right, which allows it to, for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder for, at its election, (x) one share of Class A Common Stock or (y) an equivalent amount of cash. In addition, upon a change of control of the Company, the Company has the right to require each holder of Liberty LLC Units (other than the Company) to exercise its Redemption Right with respect to some or all of such unitholder’s Liberty LLC Units. In connection with any redemption of Liberty LLC Units pursuant to the Redemption Right or the Call Right, the corresponding number of shares of Class B Common Stock will be canceled. 
+LLC Interest Issuance 
+Prior to the IPO and Corporate Reorganization, as described in Note 1, Liberty Holdings issued membership interests to investors in exchange for cash consideration. Total member contributions as of December 31, 2017 were $ 275.7 million, net of commitment and issuance fees. On January 17, 2018, in connection with the Corporate Reorganization, these membership interests were exchanged for Liberty LLC Units. See Note 1 for additional information regarding the Corporate Reorganization. 
+Unit-Based Compensation 
+Prior to the IPO and Corporate Reorganization, Liberty Holdings issued Class B units of Liberty Holdings (“Legacy Units”) to certain eligible employees of the Company. The Legacy Units were non-voting, except with respect to such matters that units are entitled to vote as a matter of law. In such cases, each Legacy Unit entitled the holder to 1/1000 th of one vote. Certain Legacy Units granted to eligible participants had an assigned benchmark value and were subject to vesting in accordance with the terms of each award letter. Upon termination of the holder’s employment for any reason, Liberty Holdings had the right, but not the obligation, to repurchase from the recipient those vested Legacy Units at fair value. 
+The Company recognizes compensation expense for equity-based Legacy Units issued to employees based on the grant-date fair value of the awards and each award’s requisite service period. With the assistance from a third-party valuation expert, the Predecessor determined that the Legacy Units issued to employees were deemed to have a de minimis grant-date fair value based on their assigned benchmark values. In connection with the Corporate Reorganization, the unvested Legacy Units were exchanged for 1,258,514 shares of restricted stock with the same terms and requisite vesting conditions as the Legacy Units. 
+Restricted Stock Awards 
+Restricted stock awards are awards of Class A Common Stock that are subject to restrictions on transfer and to a risk of forfeitures if the award recipient is no longer an employee or director of the Company for any reason prior to the lapse of the restrictions. 
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+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+The following table summarizes the Company’s unvested restricted stock activity for the year ended December 31, 2019: 
+Number of Shares 
+Grant Date Fair Value per Share (1) 
+Restricted Shares as of December 31, 2018 634,653 — 
+Vested ( 366,448 ) — 
+Forfeited — — 
+Outstanding at December 31, 2019 268,205 $ — 
+(1) As discussed above, the shares of restricted stock retain the grant date fair value of the Legacy Units. 
+Long Term Incentive Plan 
+On January 11, 2018, the Company adopted the Long Term Incentive Plan (“LTIP”) to incentivize employees, officers, directors and other service providers of the Company and its affiliates. The LTIP provides for the grant, from time to time, at the discretion of the Company's board of directors or a committee thereof, of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, cash awards, substitute awards and performance awards. Subject to adjustment in the event of certain transaction or changes of capitalization in accordance with the LTIP, 12,908,734 shares of Class A Common Stock have been reserved for issuance pursuant to awards under the LTIP. Class A Common stock subject to an award that expires or is canceled, forfeited, exchanged, settled in cash or otherwise terminated without delivery of shares and shares withheld to pay the exercise price of, or to satisfy the withholding obligations with respect to, an award will again be available for delivery pursuant to other awards under the LTIP. 
+Restricted Stock Units 
+Restricted stock units (“RSUs”) granted pursuant to the LTIP, if they vest, will be settled in shares of the Company’s Class A Common Stock. RSUs were granted with vesting terms up to five years . Changes in non-vested RSUs outstanding under the LTIP during the year ended December 31, 2019 were as follows: 
+Number of Units Weighted Average Grant Date Fair Value per Unit 
+Non-vested as of December 31, 2018 1,193,683 $ 19.24 
+Granted 899,696 15.08 
+Vested ( 327,799 ) 19.97 
+Forfeited ( 31,045 ) 17.78 
+Outstanding at December 31, 2019 1,734,535 $ 16.97 
+Performance Restricted Stock Units 
+Performance restricted stock units (“PSUs”) granted pursuant to the LTIP, if they vest, will be settled in shares of the Company’s Class A Common Stock. PSUs were granted with a three year cliff vesting schedule, subject to a performance target compared to an index of competitors ’ results over the three year period from January 1, 2019 through December 31, 2021. The Company records compensation expense based on the Company’s best estimate of the number of PSUs that will vest at the end of the performance period. If such performance targets are not met, or are not expected to be met, no compensation expense is recognized and any recognized compensation expense is reversed. Changes in non-vested PSUs outstanding under the LTIP during the year ended December 31, 2019 were as follows: 
+Number of Units Weighted Average Grant Date Fair Value per Unit 
+Non-vested as of December 31, 2018 — $ — 
+Granted 356,908 14.93 
+Vested — — 
+Forfeited ( 27,631 ) 14.93 
+Outstanding at December 31, 2019 329,277 $ 14.93 
+Stock-based compensation is included in cost of services and general and administrative expenses in the Company’s consolidated and combined statements of operations. The Company recognized stock based compensation expense of 
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+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+$ 13.6 million for the year ended December 31, 2019 and $ 5.4 million for the year ended December, 31, 2018. There was approximately $ 21.9 million of unrecognized compensation expense relating to outstanding RSUs and PSUs as of December 31, 2019. The unrecognized compensation expense will be recognized on a straight-line basis over the weighted average remaining vesting period of 1.8 years. 
+Dividends 
+Liberty LLC paid quarterly distributions for a total of $ 22.5 million, or $ 0.05 per Liberty LLC Unit, to all Liberty LLC unitholders during the year ended December 31, 2019, of which $ 14.7 million was paid to the Company. For the year ended December 31, 2018, Liberty LLC paid quarterly distributions for a total of $ 11.6 million, or $ 0.05 per Liberty LLC Unit, to all Liberty LLC unitholders, of which $ 7.0 million was paid to the Company. The Company used the proceeds of the distributions to pay quarterly dividends to all holders of Class A Common Stock, which totaled $ 14.7 million and $ 7.0 million as of December 31, 2019 and December 31, 2018, respectively. Additionally, as of December 31, 2019 and December 31, 2018, the Company accrued $ 0.5 million and $ 0.2 million of dividends payable related to restricted stock and RSUs to be paid upon vesting, respectively. Dividends related to forfeited restricted stock and RSUs will be forfeited. 
+Share Repurchase Program 
+On September 10, 2018 the Company’s board of directors authorized a share repurchase plan to repurchase up to $ 100.0 million of the Company’s Class A Common Stock through September 30, 2019. On January 22, 2019, the Company’s board of directors authorized an additional $ 100.0 million under the share repurchase plan through January 31, 2021. 
+During the year ended December 31, 2019, Liberty LLC redeemed and retired 1,303,003 Liberty LLC Units from the Company for $ 18.4 million, and the Company repurchased and retired 1,303,003 shares of Class A Common Stock for $ 18.4 million, or $ 14.66 average price per share. During the year ended December 31, 2018, Liberty LLC redeemed and retired 4,593,855 Liberty LLC Units from the Company for $ 82.9 million, and the Company repurchased and retired 4,593,855 shares of Class A Common Stock for $ 82.9 million, or $ 18.05 price per share including commissions. 
+The repurchase in January 2019 completed the share repurchase amount authorized on September 10, 2018. During the year ended December 31, 2019, of the total amount of Class A Common Stock repurchased, 117,647 shares were repurchased from R/C Energy IV Direct Partnership, L.P., R/C IV Liberty Holdings, L.P., and Riverstone/Carlyle Energy Partners IV, L.P. (“R/C” and collectively, the “Riverstone Sellers”). During the year ended December 31, 2018, of the total amount of Class A Common Stock repurchased, 2,491,160 shares were repurchased pursuant to a Stock Purchase and Sale Agreement, dated as of September 14, 2018, by the Riverstone Sellers. For further details of this related party transaction, see Note 12—Related Party Transactions. 
+As of December 31, 2019 and 2018, $ 98.7 million and $ 17.1 million remained authorized for future repurchases of Class A Common Stock under the share repurchase program, respectively. 
+The Company accounts for the purchase price of repurchased common shares in excess of par value ($ 0.01 per share of Class A Common Stock) as a reduction of additional paid-in capital, and will continue to do so until additional paid-in capital is reduced to zero. Thereafter, any excess purchase price will be recorded as a reduction to retained earnings. 
+F-24 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Note 9— Net Income per Share 
+Basic net income per share measures the performance of an entity over the reporting period. Diluted net income per share measures the performance of an entity over the reporting period while giving effect to all potentially dilutive common shares that were outstanding during the period. The Company uses the “if-converted” method to determine the potential dilutive effect of its Class B Common Stock and the treasury stock method to determine the potential dilutive effect of outstanding restricted stock and RSUs. 
+The following table reflects the allocation of net income to common stockholders and net income per share computations for the periods indicated based on a weighted average number of common stock outstanding for the period subsequent to the Corporate Reorganization on January 17, 2018: 
+(In thousands, except per share data) Year Ended December 31, 2019 Year Ended December 31, 2018 
+Basic Net Income Per Share 
+Numerator: 
+Net income attributable to Liberty Oilfield Services Inc. Stockholders $ 39,003 $ 126,349 
+Denominator: 
+Basic weighted average shares outstanding 72,334 68,838 
+Basic net income per share attributable to Liberty Oilfield Services Inc. Stockholders $ 0.54 $ 1.84 
+Diluted Net Income Per Share 
+Numerator: 
+Net income attributable to Liberty Oilfield Services Inc. Stockholders $ 39,003 $ 126,349 
+Effect of exchange of the shares of Class B Common stock for shares of Class A Common Stock 16,521 86,577 
+Diluted net income attributable to Liberty Oilfield Services Inc. Stockholders $ 55,524 $ 212,926 
+Denominator: 
+Basic weighted average shares outstanding 72,334 68,838 
+Effect of dilutive securities: 
+Restricted stock 512 906 
+Restricted stock units 1,771 602 
+Class B Common Stock 30,639 47,492 
+Diluted weighted average shares outstanding 105,256 117,838 
+Diluted net income per share attributable to Liberty Oilfield Services Inc. Stockholders $ 0.53 $ 1.81 
+Note 10— Income Taxes 
+Prior to the IPO, the Predecessor was treated as a partnership for U.S. federal, state and local income tax purposes. As such, any liability for federal income tax was the responsibility of the members of the Predecessor. Accordingly, no provision for U.S. federal, state and local income tax has been provided in the combined financial statements of the Company for periods ending prior to the IPO. 
+Following the IPO, the Company is a corporation and is subject to U.S. federal, state and local income tax on its share of Liberty LLC’s taxable income. Liberty LLC is treated as a partnership, and its income is passed through to its owners, for income tax purposes. Liberty LLC’s members, including the Company, are liable for federal, state and local income taxes based on their share of Liberty LLC’s pass-through taxable income. As of December 31, 2019, tax reporting by the Company's Predecessor for the years ended December 31, 2016 and 2017 is subject to examination by the tax authorities. With few exceptions, as of December 31, 2019, the Company is no longer subject to U.S. federal, state or local examinations by tax authorities for tax years ended before December 31, 2016. 
+F-25 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Income tax (benefit) expense reflected in the consolidated statement of operations consisted of: 
+($ in thousands) Year Ended December 31, 2019 Year Ended December 31, 2018 
+Current: 
+Federal ( 9,907 ) 16,684 
+State 551 3,213 
+Total Current $ ( 9,356 ) $ 19,897 
+Deferred: 
+Federal 23,419 19,063 
+State ( 11 ) 1,425 
+Total Deferred $ 23,408 $ 20,488 
+Income tax expense $ 14,052 $ 40,385 
+A reconciliation of the statutory U.S. federal income tax rate of 21.0% to the Company ’ s effective income tax rate is as follows: 
+($ in thousands) Year Ended December 31, 2019 Year Ended December 31, 2018 
+Federal income tax expense at statutory rate $ 18,672 $ 60,778 
+State and local income tax expense, net 1,525 4,456 
+Pre-IPO income before income taxes attributable to the Predecessor — ( 1,958 ) 
+Non-controlling interest ( 7,531 ) ( 24,606 ) 
+Other 1,386 1,715 
+Total income tax expense $ 14,052 $ 40,385 
+The effective combined U.S. federal and state income tax rate applicable to the Company for the period commencing on January 17, 2018, the date of the Corporate Reorganization, through December 31, 2019 was 15.8 %. 
+The Company recognized income tax expense of $ 14.1 million during the year ended December 31, 2019. The Company’s effective tax rate is less than the statutory federal income tax rate of 21.0% because no taxes are payable by the Company for the non-controlling interest’s share of Liberty LLC’s pass-through income for federal, state and local income tax reporting. During 2019, the non-controlling interest effect resulted in a $ 7.5 million reduction in income tax expenses. 
+The tax effects of temporary differences that give rise to the deferred tax assets and deferred tax liabilities are presented below: 
+($ in thousands) Year-Ended December 31, 2019 Year Ended December 31, 2018 
+Deferred tax assets: 
+Federal net operating losses $ 10,486 $ 1,638 
+State net operating losses 925 160 
+Realized tax benefit - TRAs 48,575 15,845 
+Total deferred tax assets 59,986 17,643 
+Deferred tax liabilities: 
+Investment in Liberty LLC $ 79,099 $ 50,325 
+Other 546 312 
+Total deferred tax liabilities 79,645 50,637 
+Net deferred tax liability $ 19,659 $ 32,994 
+F-26 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+As of December 31, 2019, the Company had significant deferred tax assets and liabilities. The deferred tax assets include U.S. federal and state net operating losses and the step-up in basis of depreciable assets under Section 754 of the Internal Revenue Code of 1986, as amended. As a result of the IPO and Corporate Reorganization, the Company recorded a deferred tax asset and liability for the difference between the book value and the tax value of the Company's investment in Liberty LLC. The deferred tax assets have been recorded for tax attributes contributed to the Company as part of the Corporate Reorganization. Deferred tax liabilities of $ 29.3 million were recorded relating to Liberty LLC Units acquired through the reorganization. The initial deferred tax liability is recorded as a long term liability and additional paid in capital on the consolidated balance sheet as of December 31, 2019. 
+As of December 31, 2019, the Company has available U.S. federal net operating loss carryforwards to reduce future taxable income of $ 3.7 million expiring in 2027, and $ 44.3 million with no expiration date. 
+Uncertain Tax Positions 
+The Company records uncertain tax positions on the basis of a two-step process in which (1) the Company determines whether it is more likely than not the tax positions will be sustained on the basis of the technical merits of the position and (2) for those tax positions meeting the more likely than not recognition threshold, the Company recognizes the largest amount of tax benefit that is more than 50% likely to be realized upon ultimate settlement with the related tax authority. 
+The Company determined that no liability for unrecognized tax benefits for uncertain tax positions was required at December 31, 2019. In addition, the Company does not believe that it has any tax positions for which it is reasonably possible that it will be required to record a significant liability for unrecognized tax benefits within the next twelve months. If the Company were to record an unrecognized tax benefit, the Company will recognize interest and penalties related to income tax matters in income tax expense. 
+Tax Distributions 
+Liberty LLC is treated as a partnership for income tax purposes. Federal, state and local taxes resulting from the pass-through taxable income of Liberty LLC are obligations of its members. Net profits and losses are generally allocated to the members of Liberty LLC (including the Company) in accordance with the number of Liberty LLC Units held by each member for tax purposes. The Liberty LLC Agreement provides for pro rata cash distributions, and in certain cases non-pro rata cash advances, to assist members (including the Company) in paying their income tax liabilities. The Liberty LLC Agreement requires any tax advances to be proportionally repaid in connection with any redemption of Liberty LLC Units pursuant to the Redemption Right or the Call Right. Net distributions and advances paid by Liberty LLC to non-controlling interest holders were de minimis and $ 21.3 million, respectively, for the years ended December 31, 2019 and 2018. 
+Tax Receivable Agreements 
+The term of each TRA commenced on January 17, 2018, and will continue until all such tax benefits that are subject to such TRA have been utilized or expired, unless the Company experiences a change of control (as defined in the TRAs, which includes certain mergers, asset sales and other forms of business combinations) or the TRAs are terminated early (at the Company’s election or as a result of its breach), and the Company makes the termination payments specified in such TRA. 
+The amounts payable, as well as the timing of any payments, under the TRAs are dependent upon significant future events and assumptions, including the timing of the redemptions of Liberty LLC Units, the price of our Class A Common Stock at the time of each redemption, the extent to which such redemptions are taxable transactions, the amount of the redeeming unit holder’s tax basis in its Liberty LLC Units at the time of the relevant redemption, the characterization of the tax basis step-up, the depreciation and amortization periods that apply to the increase in tax basis, the amount of net operating losses available to the Company as a result of the Corporate Reorganization, the amount and timing of taxable income the Company generates in the future, the U.S. federal income tax rate then applicable, and the portion of the Company’s payments under the TRAs that constitute imputed interest or give rise to depreciable or amortizable tax basis. 
+Prior to the Corporate Reorganization, one of the Legacy Owners distributed a portion of its member interest in Liberty Holdings to R/C IV Non-U.S. LOS Corp. (“R/C IV”). Subsequently, in conjunction with the Corporate Reorganization, R/C IV was contributed to the Company. At the time of the contribution, R/C IV had net operating loss carryforwards totaling $ 10.9 million for federal income tax purposes and $ 10.9 million for certain state income tax purposes, which became available for the Company's use as a result of the contribution. As a result of the Company being in a net income position and the expected utilization of deferred tax assets, the Company recognized a deferred tax asset of $ 2.6 million and a corresponding $ 2.3 million liability pursuant to the TRAs. 
+F-27 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+During the year ended December 31, 2018, exchanges of Liberty LLC Units and shares of Class B Common Stock resulted in an increase of $ 14.5 million in amounts payable under the TRAs, and a net increase of $ 17.1 million in deferred tax assets, all of which were recorded through equity. At December 31, 2018, the Company’s liability under the TRAs was $ 16.8 million, all of which is presented as a component of long term liabilities, and the related deferred tax assets totaled $ 19.7 million. 
+During the year ended December 31, 2019, exchanges of Liberty LLC Units and shares of Class B Common Stock resulted in an increase of $ 34.0 million in amounts payable under the TRAs, and a net increase of $ 40.0 million in deferred tax assets, all of which were recorded through equity. 
+At December 31, 2019, the Company’s liability under the TRAs was $ 50.3 million, a portion of which is presented as a component of current liabilities of $ 1.8 million, and a portion of which is presented as a component of long term liabilities of $ 48.5 million, and the related deferred tax assets totaled $ 49.9 million . 
+Note 11— Defined Contribution Plan 
+The Company sponsors a 401(k) defined contribution retirement plan covering eligible employees. The Company makes matching contributions, which were temporarily suspended in May 2015, but were resumed in April 2017 at a rate of $ 1.00 for each $1.00 of employee contribution, subject to a cap of 3 % of the employee’s salary. In October 2017, the cap on these contributions was increased to 6 % of the employee’s base salary. Contributions made by the Company were $ 15.7 million, $ 13.8 million, and $ 5.1 million for the years ended December 31, 2019, 2018 and 2017, respectively. 
+Note 12— Related Party Transactions 
+Prior to the Corporate Reorganization, one of the members of Liberty Holdings contributed a portion of its member interest in Liberty Holdings to R/C IV Non-U.S. LOS Corp (“R/C IV”). Subsequently, in conjunction with the Corporate Reorganization, R/C IV was contributed to Liberty LLC. R/C IV had net operating loss carryforwards for federal and state income tax purposes which resulted in the recognition of a $ 2.9 million payable pursuant to the TRAs. During the year ended December 31, 2019, R/C IV Liberty Holdings, L.P. exercised its redemption right and redeemed 9,605,786 shares of Class B Common Stock resulting in an increase in tax basis, as described in Note—10 Income Taxes— Tax Receivable Agreements , and recognition of $ 22.3 million in amounts payable under the TRAs. As of December 31, 2019 and 2018, the Company’s current liabilities under the TRAs payable to R/C IV Liberty Holdings, L.P. and R/C IV Non-US were $ 1.3 million and $ 0 , respectively, included in accrued interest and other and non-current liabilities were $ 23.8 million and $ 2.9 million, respectively, in payable pursuant to tax receivable agreements in the accompanying condensed consolidated balance sheets. 
+The Company repurchased 117,647 shares and 2,491,160 shares of Class A Common Stock from the Riverstone Sellers, at a weighted average purchase price of $ 17.00 per share and $ 18.96 per share pursuant to the share repurchase program (see Note 8—Equity —Share Repurchase Program ) for the years ended December 31, 2019 and 2018, respectively. 
+In connection with the Corporate Reorganization, the Company engaged in transactions with affiliates (see Note 1—Organization and Basis of Presentation) including entering into the TRAs with affiliates (see Note 10—Income Taxes— Tax Receivable Agreements ). Also in conjunction with the Corporate Reorganization, Liberty Holdings contributed $ 2.1 million of additional assets to Liberty LLC and Redeemable Common Units in the amount of $ 42.6 million were settled. 
+In September 2011, Liberty Resources LLC, an oil and gas exploration and production company, and its successor entity (collectively, the “Affiliate”) and LOS, companies with common ownership and management, entered into a services agreement (the “Services Agreement”) whereby the Affiliate is to provide certain administrative support functions to LOS and a master service agreement whereby LOS provides hydraulic fracturing services to the Affiliate at market service rates. The amounts incurred under the Services Agreement by LOS during the years ended December 31, 2019, 2018 and 2017, were $ 0 , $ 0.2 million, and $ 0 , respectively. The Services Agreement was terminated during June 2018. 
+The amounts of the Company’s revenue related to hydraulic fracturing services provided to the Affiliate for the years ended December 31, 2019, 2018 and 2017, were $ 18.3 million, $ 23.1 million and $ 24.7 million, respectively. As of December 31, 2019 and 2018, $ 7.1 million and $ 15.1 million, respectively, of the Company’s accounts receivable—related party was with the Affiliate. On June 24, 2019 (the “Agreement Date”), the Company entered into an agreement with the Affiliate to amend payment terms for outstanding invoices due as of the Agreement Date to be due on July 31, 2020. On September 30, 2019, the agreement was amended to extend the due date of the remaining amounts outstanding to October 31, 2020. Amounts outstanding from the Affiliate as of the Agreement Date were $ 15.6 million. As of December 31, 2019, amounts outstanding under the amended payment terms from the Affiliate are $ 2.5 million, all of which is presented in accounts and notes receivable 
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+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+—related party in the accompanying consolidated balance sheet. The balance outstanding is subject to interest at 13 % annual percent yield, retroactively applied to the respective invoice date. During the year ended December 31, 2019, interest income from the Affiliate was $ 1.8 million, and accrued interest as of December 31, 2019 was $ 0 . Receivables earned for services performed after the Agreement Date continue to be subject to normal 30-day payment terms, provided that any amount unpaid after 60 days is subject to 13 % interest. 
+Liberty Holdings entered into an advisory agreement, dated December 30, 2011, with Riverstone/Carlyle Energy Partners IV, L.P. (“R/C”), in which R/C agreed to provide certain administrative advisory services to Liberty Holdings. The service fees incurred to R/C for the years ended December 31, 2019, 2018 and 2017 were approximately $ 0 , $ 0 and $ 1.5 million, respectively. The advisory services agreement was terminated pursuant to an agreement effective as of January 11, 2018. On January 11, 2018, Liberty Holdings, R/C and other parties entered into a Master Reorganization Agreement that, among other things, crystallized the “waterfall” provisions of Article VI of the Third Amended and Restated Limited Liability Agreement of Liberty Holdings, dated October 11, 2016 (the “Holdings LLC Agreement”), in connection with the initial public offering of shares of Class A Common Stock. As part of this crystallization, R/C and affiliated entities (collectively, the “R/C Affiliates”) received shares of Class A Common Stock, including 117,647 shares of Class A Common Stock (such 117,647 referred to as the “Issued Shares”) to compensate R/C Affiliates for certain accrued preferred returns but which would not have been issued had the $ 2.0 million in fees owing under the advisory agreement been paid in cash. Had this fee been paid in cash on or prior to January 11, 2018, R/C and Liberty Holdings acknowledge that R/C Affiliates would not have received the Issued Shares in the crystallization pursuant to the provisions of the Holdings LLC Agreement. Subsequently, during the fourth quarter of 2018, R/C asserted that certain provisions of the termination of services agreement provided for R/C to receive $ 2.0 million in cash as payment of those accrued fees. To resolve this matter, the Company agreed to pay R/C Affiliates $ 2.0 million in cash in exchange for the return, at the IPO price, of the Issued Shares and $ 0.3 million for interest and the settlement of the matter. Accordingly, $ 2.3 million was recorded as accrued liabilities—related party in the accompanying consolidated balance sheet as of December 31, 2018 and subsequently paid in January 2019. The returned shares of Class A Common Stock were canceled and retired, and the Company does not expect to incur future expense related to the advisory agreement or termination thereof. 
+During 2016, Liberty Holdings entered into a future commitment to invest and become a non-controlling minority member in Proppant Express Investments, LLC (“PropX Investments”), the owner of Proppant Express Solutions, LLC (“PropX”), a provider of proppant logistics equipment. LOS is party to a services agreement (the “PropX Services Agreement”) whereby LOS is to provide certain administrative support functions to PropX, and LOS is to purchase and lease proppant logistics equipment from PropX. The PropX Services Agreement was terminated on May 29, 2018; however, the Company continues to purchase and lease equipment from PropX. For the years ended December 31, 2019 and 2018 the Company purchased proppant logistics equipment of $ 0 and $ 3.1 million and leased proppant logistics equipment during the years ended December 31, 2019, 2018 and 2017 for $ 9.8 million, $ 4.4 million and $ 3.7 million, respectively. 
+Receivables from PropX as of December 31, 2019 and 2018 were $ 0 . Payables to PropX as of December 31, 2019 and 2018 were $ 0.8 million and $ 0.2 million, respectively. 
+Note 13— Commitments & Contingencies 
+Purchase Commitments (tons, per ton, gallons, per gallon and per rail car prices are not in thousands) 
+The Company enters into purchase and supply agreements to secure supply and pricing of proppants, and related proppant transportation, as well as chemicals. As of December 31, 2019 and 2018, the agreements commit the Company to purchase 7,978,300 and 11,266,000 tons, respectively, of proppant through February 1, 2022. Amounts above also include commitments to pay for transport fees on minimum amounts of proppants or railcars. Certain proppant supply agreements contain a clause whereby in the event that the Company fails to purchase minimum volumes, as defined in the agreement, during a specific time period, a shortfall fee may apply. Additionally, related proppant transload service commitments extend through 2024. 
+As of December 31, 2019 and 2018, the Company has commitments to purchase 3,339,534 and 18,852,000 gallons of chemicals through December 31, 2020. 
+F-29 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Future proppant, transload, chemical and rail car commitments are as follows: 
+Year ending December 31, 
+2020 $ 349,096 
+2021 139,937 
+2022 17,471 
+2023 12,598 
+2024 6,405 
+Thereafter — 
+$ 525,507 
+Litigation 
+From time to time, the Company is subject to legal and administrative proceedings, settlements, investigations, claims and actions. The Company’s assessment of the likely outcome of litigation matters is based on its judgment of a number of factors including experience with similar matters, past history, precedents, relevant financial and other evidence and facts specific to the matter. Notwithstanding the uncertainty as to the final outcome, based upon the information currently available, management does not believe any matters in aggregate will have a material adverse effect on its financial position or results of operations. 
+Note 14— Selected Quarterly Financial Data (unaudited) 
+The following table sets forth certain unaudited financial and operating information for each quarter of the years ended December 31, 2019 and 2018. The unaudited quarterly information includes all adjustments that, in the opinion of management, are necessary for the fair presentation of information presented. Operating results for interim periods are not necessarily indicative of the results that may be expected for the full fiscal year. 
+($ in thousands) Year Ended December 31, 2019 
+Selected Financial Data: First Quarter Second Quarter Third Quarter Fourth Quarter 
+Revenue $ 535,148 $ 542,147 $ 515,079 $ 397,971 
+Operating costs and expenses: 
+Cost of services (exclusive of depreciation and amortization shown separately below) 429,299 426,444 421,007 344,430 
+General and administrative 22,088 23,989 25,302 26,210 
+Depreciation and amortization 38,387 40,368 42,324 44,299 
+Loss (gain) on disposal of assets 1,223 143 ( 124 ) 1,359 
+Total operating costs and expenses 490,997 490,944 488,509 416,298 
+Operating income (loss) 44,151 51,203 26,570 ( 18,327 ) 
+Other expense: 
+Interest expense, net 4,182 3,597 3,726 3,176 
+Net income (loss) before income taxes 39,969 47,606 22,844 ( 21,503 ) 
+Income tax expense (benefit) 6,060 7,083 4,004 ( 3,095 ) 
+Net income (loss) 33,909 40,523 18,840 ( 18,408 ) 
+Less: Net income (loss) attributable to non-controlling interests 15,788 18,491 7,842 ( 6,260 ) 
+Net income (loss) attributable to Liberty Oilfield Services Inc. stockholders $ 18,121 $ 22,032 $ 10,998 $ ( 12,148 ) 
+Net income (loss) attributable to Liberty Oilfield Services Inc. stockholders per common share: 
+Basic $ 0.27 $ 0.32 $ 0.15 $ ( 0.15 ) 
+Diluted $ 0.26 $ 0.32 $ 0.15 $ ( 0.15 ) 
+F-30 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+($ in thousands) Year ended December 31, 2018 
+Selected Financial Data: First Quarter Second Quarter Third Quarter Fourth Quarter 
+Revenue $ 495,160 $ 628,084 $ 558,777 $ 473,115 
+Operating costs and expenses: 
+Cost of services (exclusive of depreciation and amortization shown separately below) 376,827 455,469 418,867 377,590 
+General and administrative 21,677 27,313 24,659 25,403 
+Depreciation and amortization 28,016 30,606 32,305 34,183 
+Loss (gain) on disposal of assets 80 485 701 ( 5,608 ) 
+Total operating costs and expenses 426,600 513,873 476,532 431,568 
+Operating income 68,560 114,211 82,245 41,547 
+Other expense: 
+Interest expense, net 6,494 3,540 3,648 3,463 
+Net income before income taxes 62,066 110,671 78,597 38,084 
+Income tax expense 8,079 15,930 12,229 4,147 
+Net income 53,987 94,741 66,368 33,937 
+Less: Net income attributable to Predecessor, prior to Corporate Reorganization 8,705 — — — 
+Less: Net income attributable to non-controlling interests 21,607 45,146 32,275 14,951 
+Net income attributable to Liberty Oilfield Services Inc. stockholders $ 23,675 $ 49,595 $ 34,093 $ 18,986 
+Net income attributable to Liberty Oilfield Services Inc. stockholders per common share: 
+Basic $ 0.34 $ 0.72 $ 0.50 $ 0.28 
+Diluted $ 0.34 $ 0.71 $ 0.49 $ 0.27 
+Note 15— Subsequent Events 
+On January 22, 2020, the Company announced a cash dividend of $ 0.05 per share of Class A common stock, to be paid on March 20, 2020 to holders of record as of March 6, 2020. A distribution of $ 0.05 per unit has also been approved for holders of units in Liberty LLC, which will use the same record and payment date. 
+There were no other significant subsequent events requiring disclosure or recognition other than those disclosed in these notes to the consolidated and combined financial statements. 
+F-31
\ No newline at end of file
diff --git a/raw/filings/0001694028/2019/0001694028-20-000019/filing_metadata.csv b/raw/filings/0001694028/2019/0001694028-20-000019/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..b40125a41cec0b32a15701f86abc07f317117a70
--- /dev/null
+++ b/raw/filings/0001694028/2019/0001694028-20-000019/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0001694028,LBRT,Liberty Energy Inc.,10-K,2020-02-27,2019-12-31,2020-02-27T04:56:15.000Z,0001694028-20-000019,lbrt-20191231.htm,10-K,11834687,1,1,https://www.sec.gov/Archives/edgar/data/1694028/000169402820000019/lbrt-20191231.htm,https://www.sec.gov/Archives/edgar/data/1694028/000169402820000019/,2019,2019,1
diff --git a/raw/filings/0001694028/2019/0001694028-20-000019/item13.txt b/raw/filings/0001694028/2019/0001694028-20-000019/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..d2f74b689c07cab0215b87aabb5de97ca106003e
--- /dev/null
+++ b/raw/filings/0001694028/2019/0001694028-20-000019/item13.txt
@@ -0,0 +1,2 @@
+Item 13. Certain Relationships and Related Transactions, and Director Independence 
+The information required by this item concerning certain relationships and related person transactions and director independence is incorporated herein by reference to our definitive proxy statement for our 2020 annual meeting of shareholders, which will be filed with the SEC no later than 120 days after December 31, 2019, under the captions “Certain Relationships and Related Party Transactions” and “the Board and its Committees.”
\ No newline at end of file
diff --git a/raw/filings/0001694028/2019/0001694028-20-000019/item9a.txt b/raw/filings/0001694028/2019/0001694028-20-000019/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..657e4028ab9d78daeea408ea0c30e5f8d22ecc4c
--- /dev/null
+++ b/raw/filings/0001694028/2019/0001694028-20-000019/item9a.txt
@@ -0,0 +1,5 @@
+Item 9A. Controls and Procedures 
+Evaluation of Disclosure Controls and Procedures 
+In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2019 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures. 
+There has been no change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the three months ended December 31, 2019 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. 
+See page F-1 for Management’s Report on Internal Control Over Financial Reporting and page F-4 for Report of Independent Registered Public Accounting Firm on its assessment of our internal control over financial reporting.
\ No newline at end of file
diff --git a/raw/filings/0001694028/2019/0001694028-20-000019/rp_note.txt b/raw/filings/0001694028/2019/0001694028-20-000019/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..9af5c1c7d4ac7e90551a27c42d75132e042bda5f
--- /dev/null
+++ b/raw/filings/0001694028/2019/0001694028-20-000019/rp_note.txt
@@ -0,0 +1,14 @@
+Note 12— Related Party Transactions 
+Prior to the Corporate Reorganization, one of the members of Liberty Holdings contributed a portion of its member interest in Liberty Holdings to R/C IV Non-U.S. LOS Corp (“R/C IV”). Subsequently, in conjunction with the Corporate Reorganization, R/C IV was contributed to Liberty LLC. R/C IV had net operating loss carryforwards for federal and state income tax purposes which resulted in the recognition of a $ 2.9 million payable pursuant to the TRAs. During the year ended December 31, 2019, R/C IV Liberty Holdings, L.P. exercised its redemption right and redeemed 9,605,786 shares of Class B Common Stock resulting in an increase in tax basis, as described in Note—10 Income Taxes— Tax Receivable Agreements , and recognition of $ 22.3 million in amounts payable under the TRAs. As of December 31, 2019 and 2018, the Company’s current liabilities under the TRAs payable to R/C IV Liberty Holdings, L.P. and R/C IV Non-US were $ 1.3 million and $ 0 , respectively, included in accrued interest and other and non-current liabilities were $ 23.8 million and $ 2.9 million, respectively, in payable pursuant to tax receivable agreements in the accompanying condensed consolidated balance sheets. 
+The Company repurchased 117,647 shares and 2,491,160 shares of Class A Common Stock from the Riverstone Sellers, at a weighted average purchase price of $ 17.00 per share and $ 18.96 per share pursuant to the share repurchase program (see Note 8—Equity —Share Repurchase Program ) for the years ended December 31, 2019 and 2018, respectively. 
+In connection with the Corporate Reorganization, the Company engaged in transactions with affiliates (see Note 1—Organization and Basis of Presentation) including entering into the TRAs with affiliates (see Note 10—Income Taxes— Tax Receivable Agreements ). Also in conjunction with the Corporate Reorganization, Liberty Holdings contributed $ 2.1 million of additional assets to Liberty LLC and Redeemable Common Units in the amount of $ 42.6 million were settled. 
+In September 2011, Liberty Resources LLC, an oil and gas exploration and production company, and its successor entity (collectively, the “Affiliate”) and LOS, companies with common ownership and management, entered into a services agreement (the “Services Agreement”) whereby the Affiliate is to provide certain administrative support functions to LOS and a master service agreement whereby LOS provides hydraulic fracturing services to the Affiliate at market service rates. The amounts incurred under the Services Agreement by LOS during the years ended December 31, 2019, 2018 and 2017, were $ 0 , $ 0.2 million, and $ 0 , respectively. The Services Agreement was terminated during June 2018. 
+The amounts of the Company’s revenue related to hydraulic fracturing services provided to the Affiliate for the years ended December 31, 2019, 2018 and 2017, were $ 18.3 million, $ 23.1 million and $ 24.7 million, respectively. As of December 31, 2019 and 2018, $ 7.1 million and $ 15.1 million, respectively, of the Company’s accounts receivable—related party was with the Affiliate. On June 24, 2019 (the “Agreement Date”), the Company entered into an agreement with the Affiliate to amend payment terms for outstanding invoices due as of the Agreement Date to be due on July 31, 2020. On September 30, 2019, the agreement was amended to extend the due date of the remaining amounts outstanding to October 31, 2020. Amounts outstanding from the Affiliate as of the Agreement Date were $ 15.6 million. As of December 31, 2019, amounts outstanding under the amended payment terms from the Affiliate are $ 2.5 million, all of which is presented in accounts and notes receivable 
+F-28 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+—related party in the accompanying consolidated balance sheet. The balance outstanding is subject to interest at 13 % annual percent yield, retroactively applied to the respective invoice date. During the year ended December 31, 2019, interest income from the Affiliate was $ 1.8 million, and accrued interest as of December 31, 2019 was $ 0 . Receivables earned for services performed after the Agreement Date continue to be subject to normal 30-day payment terms, provided that any amount unpaid after 60 days is subject to 13 % interest. 
+Liberty Holdings entered into an advisory agreement, dated December 30, 2011, with Riverstone/Carlyle Energy Partners IV, L.P. (“R/C”), in which R/C agreed to provide certain administrative advisory services to Liberty Holdings. The service fees incurred to R/C for the years ended December 31, 2019, 2018 and 2017 were approximately $ 0 , $ 0 and $ 1.5 million, respectively. The advisory services agreement was terminated pursuant to an agreement effective as of January 11, 2018. On January 11, 2018, Liberty Holdings, R/C and other parties entered into a Master Reorganization Agreement that, among other things, crystallized the “waterfall” provisions of Article VI of the Third Amended and Restated Limited Liability Agreement of Liberty Holdings, dated October 11, 2016 (the “Holdings LLC Agreement”), in connection with the initial public offering of shares of Class A Common Stock. As part of this crystallization, R/C and affiliated entities (collectively, the “R/C Affiliates”) received shares of Class A Common Stock, including 117,647 shares of Class A Common Stock (such 117,647 referred to as the “Issued Shares”) to compensate R/C Affiliates for certain accrued preferred returns but which would not have been issued had the $ 2.0 million in fees owing under the advisory agreement been paid in cash. Had this fee been paid in cash on or prior to January 11, 2018, R/C and Liberty Holdings acknowledge that R/C Affiliates would not have received the Issued Shares in the crystallization pursuant to the provisions of the Holdings LLC Agreement. Subsequently, during the fourth quarter of 2018, R/C asserted that certain provisions of the termination of services agreement provided for R/C to receive $ 2.0 million in cash as payment of those accrued fees. To resolve this matter, the Company agreed to pay R/C Affiliates $ 2.0 million in cash in exchange for the return, at the IPO price, of the Issued Shares and $ 0.3 million for interest and the settlement of the matter. Accordingly, $ 2.3 million was recorded as accrued liabilities—related party in the accompanying consolidated balance sheet as of December 31, 2018 and subsequently paid in January 2019. The returned shares of Class A Common Stock were canceled and retired, and the Company does not expect to incur future expense related to the advisory agreement or termination thereof. 
+During 2016, Liberty Holdings entered into a future commitment to invest and become a non-controlling minority member in Proppant Express Investments, LLC (“PropX Investments”), the owner of Proppant Express Solutions, LLC (“PropX”), a provider of proppant logistics equipment. LOS is party to a services agreement (the “PropX Services Agreement”) whereby LOS is to provide certain administrative support functions to PropX, and LOS is to purchase and lease proppant logistics equipment from PropX. The PropX Services Agreement was terminated on May 29, 2018; however, the Company continues to purchase and lease equipment from PropX. For the years ended December 31, 2019 and 2018 the Company purchased proppant logistics equipment of $ 0 and $ 3.1 million and leased proppant logistics equipment during the years ended December 31, 2019, 2018 and 2017 for $ 9.8 million, $ 4.4 million and $ 3.7 million, respectively. 
+Receivables from PropX as of December 31, 2019 and 2018 were $ 0 . Payables to PropX as of December 31, 2019 and 2018 were $ 0.8 million and $ 0.2 million, respectively.
\ No newline at end of file
diff --git a/raw/filings/0001694028/2019/0001694028-20-000019/rpt_disclosure.txt b/raw/filings/0001694028/2019/0001694028-20-000019/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..8d1a8118c0e7c4cb14d93412284869fbc7d1c795
--- /dev/null
+++ b/raw/filings/0001694028/2019/0001694028-20-000019/rpt_disclosure.txt
@@ -0,0 +1,80 @@
+CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS 
+Policies and Procedures for Review of Related Party Transactions 
+A “Related Party Transaction” is a transaction, arrangement or relationship in which the Company or any of its subsidiaries was, is or will be a participant, the amount of which involved exceeds $120,000, and in which any related person had, has or will have a direct or indirect material interest. A “Related Person” is: 
+♦ any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors; 
+♦ any person who is known by us to be the beneficial owner of more than 5% of our Class A Common Stock; 
+♦ any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, executive officer or a beneficial owner of more than 5% of our Class A Common Stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5% of our Class A Common Stock; and 
+♦ any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10.0% or greater beneficial ownership interest. 
+Our Board adopted a written related party transactions policy in connection with the IPO. Pursuant to this policy, our Audit Committee reviews all material facts of all Related Party Transactions and either approves or disapproves entry into the Related Party Transaction, subject to certain limited exceptions. The determination of the Audit Committee is documented in the Audit Committee’s minutes. In determining whether to approve or disapprove entry into a Related Party Transaction, our Audit Committee takes into account, among other factors, the following: (i) whether the Related Party Transaction is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances and (ii) the extent of the Related Person’s interest in the transaction. Furthermore, the policy requires that all Related Party Transactions required to be disclosed in our filings with the SEC be so disclosed in accordance with applicable laws, rules and regulations. 
+The following discussion is a brief summary of our corporate reorganization and certain material arrangements, agreements and transactions we have with related parties. It does not include all of the provisions of our material arrangements, agreements and transactions with related parties, does not purport to be complete and is qualified in its entirety by reference to the arrangements, agreements and transactions described. 
+Corporate Reorganization 
+On January 17, 2018, we completed our IPO of 14,640,755 shares of our Class A Common Stock at a public offering price of $17.00 per share, of which 14,340,214 shares were offered by us and 300,541 shares were offered by the selling shareholder. We used our net proceeds from the IPO to redeem ownership in us from certain Legacy Owners (as defined below) and contributed the remaining proceeds to Liberty Oilfield Services New HoldCo LLC (“ Liberty LLC ”) in exchange for units in Liberty LLC (the “ Liberty LLC Units ”). In connection with the IPO, we completed a corporate reorganization which included the following restructuring steps: 
+• Liberty Holdings contributed all of its assets to Liberty LLC in exchange for Liberty LLC Units; 
+• Liberty Holdings liquidated and distributed to its then-existing owners (the “ Legacy Owners ”) Liberty LLC Units pursuant to the terms of the limited liability company agreement of Liberty Holdings and the Master Reorganization Agreement dated as of January 11, 2018, by and among the Company, Liberty Holdings, Liberty LLC, and the other parties nam ed therein; 
+• Certain of the Legacy Owners directly or indirectly contributed all or a portion of their Liberty LLC Units to the Company in exchange for 55,685,027 shares of our Class A Common Stock, and 1,258,514 shares of restricted stock. Subsequent to the initial exchange, 1,609,122 shares of Class A Common Stock were redeemed for an aggregate purchase price of $25.9 million upon the exercise of the underwriters’ overallotment option; 
+• We issued the Legacy Owners that continued to own Liberty LLC Units (the “ Liberty Unit Holders ”) an aggregate amount of 48,207,372 shares of our Class B Common Stock; and 
+• We then contributed the net proceeds it received from the IPO to Liberty LLC in exchange for additional Liberty LLC Units such that the Company holds a total number of Liberty LLC Units equal to the number of shares of Class A Common Stock outstanding following the IPO. 
+36 
+Related Party Transactions 
+The following is a description of transactions entered into, or in effect, after January 1, 2019 to which we have been a party, in which the amount involved in the transaction exceeds $120,000, and in which any of our directors, executive officers or beneficial owners of more than 5% of our voting securities, or affiliates or immediate family members of any of our directors, executive officers or beneficial owners of more than 5% of our voting securities, had or will have a direct or indirect material interest. We believe the terms obtained or consideration that we paid or received, as applicable, in connection with the transactions described below were comparable to terms available or the amounts that would be paid or received, as applicable, from unrelated third parties. 
+Liberty LLC Agreement 
+We entered into the Second Amended and Restated Limited Liability Company Agreement of Liberty LLC (the “ Liberty LLC Agreement ”) in connection with the closing of our IPO, which provides for limitations on the ability of Liberty Unit Holders to transfer their Liberty LLC Units and provides the Company, as managing member of Liberty LLC, with the right to impose restrictions (in addition to those already in place) on the ability of Liberty Unit Holders to redeem their Liberty LLC Units pursuant to the Redemption Right (as defined below) to the extent the Company believes it is necessary to ensure that Liberty LLC will continue to be treated as a partnership for U.S. federal income tax purposes. 
+Redemption Rights 
+Under the Liberty LLC Agreement, each Liberty Unit Holder has, subject to certain limitations, the right (the “ Redemption Right ”) to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units for, at Liberty LLC’s election, (i) shares of our Class A Common Stock at a redemption ratio of one share of Class A Common Stock for each Liberty LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions or (ii) an equivalent amount of cash. Alternatively, upon the exercise of the Redemption Right, the Company (instead of Liberty LLC) h as the right (the “ Call Right ”) to, for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder for, at the Company’s election, (x) one share of Class A Common Stock or (y) an equivalent amount of cash. In addition, upon a change of control of the Company, the Company has the right to require each holder of Liberty LLC Units (other than the Company) to exercise its Redemption Right with respect to some or all of such unit holder’s Liberty LLC Units. In connection with any redemption of Liberty LLC Units pursuant to the Redemption Right or the Call Right, the corresponding number of shares of Class B Common Stock will be cancelled. As the Liberty Unit Holders redeem their Liberty LLC Units, our membership interest in Liberty LLC will be correspondingly increased, the number of shares of Class A Common Stock outstanding will be increased, and the number of shares of Class B Common Stock outstanding will be reduced. 
+Distributions and Allocations 
+Under the Liberty LLC Agreement, the Company has the right to determine when distributions will be made to the holders of Liberty LLC Units and the amount of any such distributions. If the Company authorizes a distribution, such distribution will be made to the holders of Liberty LLC Units generally on a pro rata basis in accordance with their respective percentage ownership of Liberty LLC Units. 
+Liberty LLC will allocate its net income or net loss for each year to the holders of Liberty LLC Units pursuant to the terms of the Liberty LLC Agreement, and the holders of Liberty LLC Units, including the Company, will generally incur U.S. federal, state and local income taxes on their share of any taxable income of Liberty LLC. Net income and losses of Liberty LLC generally will be allocated to the holders of Liberty LLC Units on a pro rata basis in accordance with their respective percentage ownership of Liberty LLC Units, subject to requirements under U.S. federal income tax law that certain items of income, gain, loss or deduction be allocated disproportionately in certain circumstances. To the extent Liberty LLC has available cash and subject to the terms of any debt instruments, the Company intends to cause Liberty LLC to make (i) generally pro rata distributions to the holders of Liberty LLC Units, including the Company, in an amount sufficient to allow the Company to pay its taxes and to allow it to make payments under the Tax Receivable Agreements (as defined below), (ii) tax advances, which will be repaid upon exercise of the Redemption Right or the Call Right, as applicable, in an amount sufficient to allow each of the Liberty Unit Holders to pay its respective taxes on such holder’s allocable share of Liberty LLC’s taxable income after taking into account certain other distributions or payments received by the Liberty Unit Holders from Liberty LLC or the Company, and (iii) non-pro rata payments to the Company to reimburse it for its corporate and other overhead expenses. 
+Issuance of Equity 
+The Liberty LLC Agreement generally provides that at any time the Company issues a share of its Class A Common Stock or any other equity security, the net proceeds received by the Company with respect to such issuance, if any, shall be concurrently invested in Liberty LLC, and Liberty LLC shall issue to the Company one Liberty LLC Unit or other economically equivalent equity interest. Conversely, if at any time, any shares of Class A Common Stock are redeemed, repurchased or otherwise acquired, Liberty LLC shall redeem, repurchase or otherwise acquire an equal number of Liberty LLC Units held by the Company, upon the same terms and for the same price, as the shares of the Class A Common Stock are redeemed, repurchased or otherwise acquired. 
+37 
+Competition 
+Under the Liberty LLC Agreement, the members have agreed that Riverstone and its affiliates will be permitted to engage in business activities or invest in or acquire businesses which may compete with our business or do business with our customers. 
+Dissolution 
+Liberty LLC will be dissolved only upon the first to occur of (i) the sale of substantially all of its assets or (ii) an election by us to dissolve the company. Upon dissolution, Liberty LLC will be liquidated and the proceeds from any liquidation will be applied and distributed in the following manner: (i) first, to creditors (including to the extent permitted by law, creditors who are members) in satisfaction of the liabilities of Liberty LLC; (ii) second, to establish cash reserves for contingent or unforeseen liabilities; and (iii) third, to the members in proportion to the number of Liberty LLC Units owned by each of them. 
+Tax Receivable Agreements 
+In connection with the IPO, on January 17, 2018, the Company entered into two tax receivable agreements, (the “ TRAs ”) with the Liberty Unit Holders and the selling shareholder (each such person and any permitted transferee, a “ TRA Holder ” and together, the “ TR A Hold ers ”). The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that the Company actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result, as applicable to each TRA Holder, of (i) certain increases in tax basis that occur as a result of the Company’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holder’s Liberty LLC Units in connection with the IPO or pursuant to the exercise of the Redemption Right or the Call Right, (ii) any net operating losses available to the Company as a result of the corporate reorganization, and (iii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRAs. 
+Stockholders’ Agreements 
+We are party to a stockholders’ agreement with Riverstone and certain Legacy Owners (collectively, the “ Principal Stockholders ”). Among other things, the stockholders’ agreement provides the right to designate nominees to our Board as follows: 
+• so long as Riverstone and its affiliates collectively own at least 35% of our Class A Common Stock, Riverstone can designate up to five (5) nominees to the Board, with the Board size decreasing by one (1) director when Riverstone and its affiliates no longer own at least 35% of our Class A Common Stock; 
+• so long as Riverstone and its affiliates collectively own at least 30% of our Class A Common Stock, Riverstone can designate up to four (4) nominees to our Board; 
+• so long as Riverstone and its affiliates collectively own at least 20% of our Class A Common Stock but less than 30% of our Class A Common Stock, Riverstone can designate up to two (2) nominees to our Board; and 
+• so long as Riverstone and its affiliates collectively own at least 10% of our Class A Common Stock but less than 20% of our Class A common stock, Riverstone can designate up to one (1) nominee to our Board. 
+In connection with the appointment of Ms. Norton and the expansion of the Board in July 2019, the Company, R/C Energy IV Direct Partnership, L.P. and R/C IV Liberty Holdings, L.P. entered into an additional stockholders agreement (the “ Additional Agreement ”). Pursuant to the Additional Agreement, the Company agreed to use reasonable best efforts to cause the Board to, in the case where Riverstone and its affiliates beneficially own at least 10% of the outstanding shares of our Class A Common Stock, and the Board is comprised of five (5) or more directors that are not Riverstone nominees, elect one (1) additional nominee designated by Riverstone to serve on the Board. The Additional Agreement does not limit or replace the rights of Riverstone under the stockholders agreement entered into in con nection with the IPO. 
+Pursuant to the stockholders’ agreement we and the Principal Stockholders will be required to take all necessary actions, to the fullest extent permitted by applicable law (including with respect to any fiduciary duties under Delaware law), to cause the election of the nominees designated by Riverstone. At any time the members of our Board are allocated among separate classes of directors, (i) the directors designated by Riverstone pursuant to the stockholders’ agreement will be in different classes of directors to the extent practicable and (ii) Riverstone will be permitted to designate the class or classes to which each such director will be allocated. Riverstone will be entitled to designate the replacement for any of its Board designees whose service terminates prior to the end of such director’s term. 
+38 
+In addition, the stockholders’ agreement provides that for so long as the Principal Stockholders and their affiliates own at least 20% of the outstanding shares of our Class A Common Stock, Riverstone will have the right to cause any committee of our Board to include in its membership at least one (1) director designated by Riverstone, except to the extent that such membership would violate applicable securities laws or stock exchange rules. The rights granted to Riverstone to designate directors are additive to and not intended to limit in any way the rights that Riverstone or any of its affiliates may have to nominate, elect or remove our directors under our certificate of incorporation, bylaws or the Delaware General Corporation Law. 
+Furthermore, so long as Riverstone and its affiliates collectively own at least 20% of the outstanding shares of Class A Common Stock, we have agreed not to take, and will take all necessary action to cause our subsidiaries not to take, the following direct or indirect actions (or enter into an agreement to take such actions) without the prior consent of Riverstone: 
+• any material change, through any acquisition, disposition of assets or otherwise, in the nature of our business or operations and our subsidiaries as of the date of the stockholders’ agreement; 
+• hiring or terminating our Chief Executive Officer or the Chief Financial Officer and their respective successors; 
+• any transaction that, if consummated, would constitute a Change of Control (as defined in the stockholders’ agreement) or entering into any definitive agreement or series of related agreements that govern any transaction or series of related transactions that, if consummated, would result in a Change of Control; 
+• entering into any agreement providing for certain acquisitions or dispositions, in each such case, involving consideration payable or receivable by us or any of our subsidiaries in excess of $100 million in the aggregate in any single transaction or series of related transactions during any 12-month period; 
+• any incurrence by us or any of our subsidiaries of indebtedness for borrowed money (including through capital leases, the issuance of debt securities or the guarantee of indebtedness of another person) in excess of $100 million in the aggregate in any single transaction or series of related transactions during any 12-month period; 
+• any issuance or series of related issuances of equity securities by us or any of our subsidiaries for an aggregate consideration in excess of $100 million; 
+• any payment or declaration of any dividend or other distribution of any shares of Class A Common Stock or entering into any recapitalization transaction the primary purpose of which is to pay a dividend; 
+• any increase or decrease in the size of our Board, committees of the Board, and board and committees of our subsidiaries; 
+• settling any litigation to which we or any of our subsidiaries is a party involving the payment by us or any of our subsidiaries of an aggregate amount equal to or greater than $25 million; 
+• entering into any joint venture or similar business alliance involving investment, contribution or disposition by us or any of our subsidiaries of assets (including stock of subsidiaries) having an aggregate fair market value in excess of $100 million, other than transactions solely between and among us and our wholly owned subsidiaries; and 
+• any amendment, modification or waiver of our certificate of incorporation, bylaws or any other governing document following the date of the stockholders’ agreement that (i) causes the number of Board seats to be less than or greater than nine (9) or (ii) materially and adversely affects any Principal Stockholder. 
+Registration Rights Agreement 
+In connection with the closing of the IPO, we entered into a registration rights agreement with the Legacy Owners. The agreement contains provisions by which we agree to register under the federal securities laws the offer and resale of shares of our Class A Common Stock by the Legacy Owners or certain of their affiliates or permitted transferees under the registration rights agreement. These registration rights will be subject to certain conditions and limitations. We will generally be obligated to pay all registration expenses in connection with these registration obligations, regardless of whether a registration statement is filed or becomes effective. 
+Indemnification for Officers and Directors 
+Our certificate of incorporation and bylaws provide indemnification rights to our directors and officers and permit us to purchase insurance on behalf of any officer, director, employee or other agent for any liability arising out of that person’s actions as our officer, director, employee or agent, regardless of whether Delaware law would mandate indemnification. Additionally, we have entered into separate indemnity agreements with our directors and officers to provide additional indemnification benefits, including the right to receive, in advance, reimbursements for expenses incurred in connection with a defense for which the director or officer is entitled to indemnification. We believe that the limitation of liability provisions in our certificate of incorporation, bylaws and the indemnity agreements will facilitate our ability to continue to attract and retain qualified individuals to serve as directors and officers. 
+39 
+Underwriting Agreement 
+On July 8, 2019, we entered into an underwriting agreement (the “ Underwriting Agreement ”) with R/C Energy IV Direct Partnership, L.P. and R/C IV Liberty Holdings, L.P. (together, the “ Selling Stockholders ”) and Barclays Capital Inc. (the “ Underwriter ”), pursuant to which the Selling Stockholders agreed to sell to the Underwriter, and the Underwriter agreed to purchase from the Selling Stockholders, subject to and upon the terms and conditions set forth therein, an aggregate of 8,000,000 shares of our Class A Common Stock (the “ Offering ”). The Offering closed on July 11, 2019. We did not receive any proceeds from the sale of shares of Class A Common Stock in the Offering. The Underwriting Agreement contains customary representations, warranties and agreements of the Company and the Selling Stockholders and other customary obligations of the parties and termination provisions. 
+Share Repurchases 
+On September 10, 2018, the Board authorized a share repurchase plan to repurchase up to $100 million of the Company’s Class A Common Stock through September 30, 2019. On January 22, 2019, the Board authorized an additional $100.0 million under the share repurchase plan through January 31, 2021. The Company repurchased 117,647 shares and 2,491,160 shares of Class A Common Stock from Riverstone sellers, at a weighted average purchase price of $17.00 per share and $18.96 per share, pursuant to a share repurchase program for the years ended December 31, 2019 and 2018, respectively. 
+Transactions with Liberty Resources 
+Liberty Resources LLC (“ Liberty Resources ”), an oil and gas exploration and production company, entered into a master service agreement with L iberty Oilfield Services LLC (“ Liberty Services ”), whereby Liberty Services provides hydraulic fracturing service to Liberty Resources at market service rates. The amounts related to the provision of hydraulic fracturing services to Liberty Resources under the master services agreement for the years ended December 31, 2019, 2018 and 2017 were approximately $18.3 million, $23.1 million and $24.7 million, respectively. As of December 31, 2019 and 2018, $7.1 million and $15.1 million, respectively, of the Company’s accounts receivable, and $0.0 million and $0.0 million, respectively, of the Company’s unbilled revenue was with Liberty Resources. On June 24, 2019 (the “Agreement Date”), the Company entered into an agreement with Liberty Resources to amend payment terms for outstanding invoices due as of the Agreement Date to be due on July 31, 2020. On September 30, 2019, the agreement was amended to extend the due date of the remaining amounts outstanding to October 31, 2020. Amounts outstanding from Liberty Resources as of the Agreement Date were $15.6 million. As of December 31, 2019, amounts outstanding under the amended payment terms from Liberty Resources were $2.5 million. The balance outstanding is subject to interest at 13% annual percent yield, retroactively applied to the respective invoice date. During the year ended December 31, 2019, interest income from Liberty Resources was $1.8 million, and accrued interest as of December 31, 2019 was $0.0 million. Receivables earned for services performed after the Agreement Date continue to be subject to normal 30-day payment terms, provided that any amount unpaid after 60 days will be subject to 13% interest. 
+Transactions with PropX 
+Liberty Oilfield Services LLC (“ LOS ”), a subsidiary of the Company, currently leases equipment from Proppant Express Solutions, LLC (“ PropX ”), a provider of proppant logistics equipment. R/C IV Liberty Big Box Holdings, L.P., a Riverstone fund, holds a majority interest in PropX. Accordingly, funds associated with Riverstone hold over a 10% interest in both the Company and PropX. For the year ended December 31, 2019, LOS paid PropX $9.8 million for the lease of proppant logistics equipment. 
+Advisory Agreement 
+Liberty Holdings entered into an advisory agreement, dated December 30, 2011, with Riverstone/Carlyle Energy Partners IV, L.P. (“ R/C ”), in which R/C agreed to provide certain administrative advisory services to Liberty Holdings. The advisory services agreement was terminated pursuant to an agreement effective as of January 11, 2018. On January 11, 2018, Liberty Holdings, R/C and other parties entered into a Master Reorganization Agreement that, among other things, crystallized the “waterfall” provisions of Article VI of the Third Amended and Restated Limited Liability Agreement of Liberty Holdings, dated October 11, 2016 (the “ Holdings LLC Agreement ”), in connection with the IPO. As part of this crystallization, R/C and affiliated entities (collectively, the “ R/C Affiliates ”) received shares of Class A Common Stock, including 117,647 shares of Class A Common Stock (such 117,647 referred to as the “ Issued Shares ”) to compensate R/C Affiliates for certain accrued preferred returns but which would not have been issued had the $2.0 million in fees owing under the advisory agreement been paid in cash. Had this fee been paid in cash on or prior to January 11, 2018, R/C and Liberty Holdings acknowledge that R/C Affiliates would not have received the Issued Shares in the crystallization pursuant to the provisions of the Holdings LLC Agreement. Subsequently, during the fourth quarter of 2018, R/C asserted that certain provisions of the termination of services agreement provided for R/C to receive $2.0 million in cash as payment of those accrued fees. To resolve this matter, the Company agreed to pay R/C Affiliates $2.0 million in cash in exchange for the return, at the IPO price, of the Issued Shares and $0.3 million for interest and the settlement of the matter. Accordingly, $2.3 million was recorded as accrued liabilities - related party in the accompanying consolidated balance sheet as of December 31, 2018 and subsequently paid in January 2019. The returned shares of Class A Common Stock were canceled and retired, and the Company does not expect to incur future expense related to the advisory agreement or termination thereof. 
+40 
+Conflicts of Interest 
+The related party transactions described herein may cause certain conflicts of interests, including that: 
+♦ we may enter into contracts between us, on the one hand, and related parties, on the other, that are not as a result of arm’s-length transactions; 
+♦ our executive officers and directors that hold positions of responsibility with related parties may be aware of certain business opportunities that are appropriate for presentation to us as well as to such other related parties and may present such business opportunities to such other parties; and 
+♦ our executive officers and directors that hold positions of responsibility with related parties may have significant duties with, and spend significant time serving, other entities and may have conflicts of interest in allocating time. 
+For example, Mr. Wright, our Chief Executive Officer, is the Executive Chairman of Liberty Resources, a position which may require a portion of his time and which may cause conflicts of interest in pursuing business opportunities of which he becomes aware. Furthermore, our governing documents provide that Riverstone and its respective affiliates (including portfolio investments of its affiliates) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. Riverstone or its respective affiliates may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Furthermore, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to not be available to us or causing them to be more expensive for us to pursue. In addition, Riverstone or its respective affiliates may dispose of oil and gas service or other assets in the future, without any obligation to offer us the opportunity to purchase any of those assets. 
+41
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+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+WASHINGTON, D.C. 20549 
+FORM 10-K 
+(Mark One) 
+☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the Fiscal Year Ended December 31 , 2020 
+OR 
+☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+Commission File No. 001-38081 
+Liberty Oilfield Services Inc. 
+(Exact Name of Registrant as Specified in its Charter) 
+Delaware 
+81-4891595 
+(State or Other Jurisdiction of Incorporation or Organization) (I.R.S. Employer Identification No.) 
+950 17th Street , Suite 2400 
+Denver , Colorado 
+80202 
+(Address of Principal Executive Offices) (Zip Code) 
+( 303 ) 515-2800 
+(Registrant’s Telephone Number, Including Area Code) 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of each class Trading symbol(s) Name of each exchange on which registered 
+Class A Common Stock, par value $0.01 LBRT New York Stock Exchange 
+Securities registered pursuant to Section 12(g) of the Act: None 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☒ Yes ☐ No 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐ Yes ☒ No 
+Indicate by check mark whether the registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No 
+Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this Chapter) during the presiding 12 months (or for such shorter period that the registrant was required to submit and post such files). ☒ Yes ☐ No 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. 
+Large accelerated Filer ☐ 
+Accelerated Filer ☒ 
+Non-accelerated filer ☐ 
+Smaller reporting company ☐ 
+Emerging growth company ☐ 
+If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ 
+Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act): ☐ Yes ☒ No 
+As of June 30, 2020, the last business day of the registrant ’ s most recently completed second fiscal quarter, the aggregate market value of voting and non-voting common stock held by non-affiliates of the registrant was approximately $ 356.7 million, determined using the per share closing price on the New York Stock Exchange on that date of $5.48. Shares of common stock held by each director and executive officer (and their respective affiliates) and each person who owns 10 percent or more of the outstanding common stock or who is otherwise believed by the registrant to be in a control position have been excluded. This determination of affiliate status is not necessarily a conclusive determination for other purposes. 
+At February 19, 2021 the Registrant had 165,068,515 shares of Class A Common Stock and 14,472,440 shares of Class B Common Stock outstanding. 
+Documents Incorporated by Reference: Part III of this Annual Report on Form 10-K incorporates certain information by reference from the registrant ’ s proxy statement for the 2021 annual meeting of stockholders to be filed no later than 120 days after the end of the registrant ’ s fiscal year. 
+Table of Contents 
+TABLE OF CONTENTS 
+Page No. 
+PART I 
+Item 1. 
+Business 
+1 
+Item 1A. 
+Risk Factors 
+6 
+Item 1B. 
+Unresolved Staff Comments 
+20 
+Item 2. 
+Properties 
+20 
+Item 3. 
+Legal Proceeding s 
+20 
+Item 4. 
+Mine Safety Disclosures 
+20 
+PART II 
+Item 5. 
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+21 
+Item 6. 
+Selected Consolidated Financial Data 
+23 
+Item 7. 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+25 
+Item 7A. 
+Quantitative and Qualitative Disclosure about Market Risk 
+37 
+Item 8. 
+Financial Statements and Supplementary Data 
+38 
+Item 9. 
+Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+38 
+Item 9A. 
+Controls and Procedures 
+38 
+Item 9B. 
+Other Information 
+38 
+PART III 
+Item 10. 
+Directors, Executive Officers and Corporate Governance 
+39 
+Item 11. 
+Executive Compensation 
+39 
+Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+39 
+Item 13. 
+Certain Relationships and Related Transactions, and Director Independence 
+39 
+Item 14. 
+Principal Accountant Fees and Services 
+39 
+PART IV 
+Item 15. 
+Exhibits and Financial Statement Schedules 
+40 
+Item 16. 
+Form 10-K Summary 
+41 
+SIGNATURES 
+45 
+i 
+Table of Contents 
+CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS 
+This Annual Report on Form 10-K and certain other communications made by us contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange of 1934, as amended (the “Exchange Act”), including statements about our growth including from the OneStim Acquisition (as defined below), expected performance, future operating results, oil and natural gas demand and prices, future global economic conditions, the impacts of the COVID-19 pandemic, improvements in operating procedures and technology, the business strategies of our customers, in addition to other estimates, and beliefs. For this purpose, any statement that is not a statement of historical fact should be considered a forward-looking statement. We may use the words “estimate,” “outlook,” “project,” “position,” “potential,” “likely,” “believe,” “anticipate,” “plan,” “expect,” “intend,” “achievable,” “anticipate,” “may,” “will,” “continue,” “should,” “could” and similar expressions to help identify forward-looking statements. We cannot assure you that our assumptions and expectations will prove to be correct. Important factors could cause our actual results to differ materially from those indicated or implied by forward-looking statements, including but not limited to the risks described in this Annual Report on Form 10-K (“Annual Report”) and other filings that we make with the U.S. Securities Exchange Commission (the “SEC”). We undertake no intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise and readers should not rely on the forward-looking statements as representing the Company’s views as of any date subsequent to the date of the filing of this Annual Report. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. 
+All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. 
+This Annual Report includes market and industry data and certain other statistical information based on third-party sources including independent industry publications, government publications and other publish independent sources, such as content and estimates provided by Coras Research, LLC as of December 31, 2020. Coras Research, LLC (“CORAS”) is not a member of the Financial Industry Regulator Authority (FINRA) or the Securities Investor Protection Corporation (SIPC) and is not a registered broker dealer or investment advisor. Although we believe these third-party sources are reliable as of their respective dates, we have not independently verified the accuracy or completeness of this information. Some data is also based on our own good faith estimates, which are supported by our management's knowledge of and experience in the markets and business in which we operate. 
+ii 
+Table of Contents 
+PART I 
+As used in this Annual Report on Form 10-K, unless the context otherwise requires, references to the terms “Company,” “we,” “us” and “our” refer to, collectively, Liberty Oilfield Services LLC and LOS Acquisition Co I LLC and its subsidiaries (collectively, the “Predecessor”) for periods prior to the IPO (as defined herein), and, for periods as of and following the IPO, Liberty Oilfield Services Inc. and its consolidated subsidiaries. References to “Liberty LLC” refer to Liberty Oilfield Services New HoldCo LLC. References to “Liberty Holdings” refer to Liberty Oilfield Services Holdings LLC. 
+Item 1. Business 
+Our Company 
+We are an independent provider of hydraulic fracturing and wireline services and related goods to onshore oil and natural gas exploration and production (“E&P”) companies in North America. We provide our services primarily in the Permian Basin, the Eagle Ford Shale, the Denver-Julesburg Basin (the “DJ Basin”), the Williston Basin, the San Juan Basin and the Powder River Basin. Following the completion of the OneStim Acquisition (as defined below) we now also provide services in the Haynesville Shale, the South Central Oklahoma Oil Province and Sooner Trend Anadarko Canadian Kingfisher (collectively the “SCOOP/STACK”), the Marcellus Shale, Utica Shale, and the Western Canadian Sedimentary Basin. 
+The process of hydraulic fracturing involves pumping a pressurized stream of fracturing fluid—typically a mixture of water, chemicals and proppant—into a well casing or tubing in order to cause the underground formation to fracture or crack. These fractures release trapped hydrocarbon particles and provide a conductive channel for the oil or natural gas to flow freely to the wellbore for collection. The propping agent, or proppant,—typically sand—becomes lodged in the cracks created by the hydraulic fracturing process, “propping” them open to facilitate the flow of hydrocarbons from the reservoir to the well. The fracturing fluid is engineered to lose viscosity, or “break,” and is subsequently flowed back from the formation, leaving the proppant suspended in the formation fractures. Once our customer has flushed the fracturing fluids from the well using a controlled flow-back process, the customer manages fluid and water recycling or disposal. 
+Our hydraulic fracturing fleets consist of mobile hydraulic fracturing units and other auxiliary heavy equipment to perform fracturing services. Our hydraulic fracturing units consist primarily of high-pressure hydraulic pumps, engines, transmissions, radiators and other supporting equipment that are typically mounted on trailers. We refer to the group of units and other equipment, such as blenders, data vans, sand storage, tractors, manifolds and high pressure fracturing iron, which are necessary to perform a typical hydraulic fracturing job, as a “fleet,” and the personnel assigned to each fleet as a “crew,” the size of each fleet and crew can vary depending on the requirements of each job design. 
+We have wireline operations after December 31, 2020 as a result of the OneStim Acquisition (as defined below). Our wireline units consist of a truck equipped with a spool of wireline that is lowered into wells to convey specialized tools or equipment necessary to connect the wellbore with the target formation. This operation is performed between each hydraulic fracturing stage. We offer our wireline service on a stand alone basis or alongside our hydraulic fracturing services. When offered along side our hydraulic fracturing services, we are able to maximize efficiency for our customers through optimized coordination of the wireline and hydraulic fracturing services. 
+Our operations are organized into a single business segment, which consists of hydraulic fracturing services, including wireline, and goods, including our Permian sand mines, and we have one reportable geographical segment, North America. We have grown from one active hydraulic fracturing fleet in December 2011 to approximately 30 fleets in the first quarter of 2021, including the addition of active fleets as a result of the OneStim Acquisition (as defined below). 
+Our founders and existing management were pioneers in the development of data-driven hydraulic fracturing technologies for application in shale plays. Prior to founding the Company, the majority of our management team founded and built Pinnacle Technologies, Inc. (“Pinnacle Technologies”) into a leading fracturing technology company. In 1992, Pinnacle Technologies developed the first commercial hydraulic fracture mapping technologies, analytical tools that played a major role in launching the shale revolution. Our extensive experience with fracture technologies and customized fracture design has enabled us to develop new technologies and processes that provide our customers with real time solutions that significantly enhance their completions. These technologies include hydraulic fracture propagation models, reservoir engineering tools, large, proprietary shale production databases and multi-variable statistical analysis techniques. Taken together, these technologies have enabled us to be a leader in hydraulic fracture design innovation and application. 
+We believe the following characteristics distinguish us from our competitors and are the foundations of our business: forming ongoing partnerships of trust and innovation with our customers; developing and utilizing technology to maximize well performance; and promoting a people-centered culture focused on our employees, customers and suppliers. We have developed strong relationships with our customers by investing significant time in fracture design collaboration, which substantially 
+1 
+Table of Contents 
+enhances their production economics. Our technological innovations have become even more critical as E&P companies have increased the completion complexity and fracture intensity of horizontal wells. We are proactive in developing innovative solutions to industry challenges, including developing: (i) our databases of U.S. unconventional wells to which we apply our proprietary multi-variable statistical analysis technologies to provide differential insight into fracture design optimization; (ii) our Liberty Quiet Fleet® design which significantly reduces noise levels compared to conventional hydraulic fracturing fleets; (iii) hydraulic fracturing fluid systems tailored to the specific reservoir properties in the basins in which we operate; and (iv) our dual fuel dynamic gas blending fleets that allow our engines to run diesel or a combination of diesel and natural gas, to optimize fuel use, reduce emissions and lower costs. We foster a people-centered culture built around honoring our commitments to customers, partnering with our suppliers and hiring, training and retaining people that we believe to be the best talent in our field, enabling us to be one of the safest and most efficient hydraulic fracturing companies in North America. 
+Recent Developments 
+On December 31, 2020, the Company acquired certain assets and liabilities of Schlumberger Limited’s (“Schlumberger”) OneStim® business, which provides hydraulic fracturing pressure pumping services in onshore United States and Canada, including its pressure pumping, pumpdown perforating and Permian frac sand business (such entire business of Schlumberger, “OneStim,” and the portion of OneStim acquired pursuant by the Company, the “Transferred Business”) in exchange for consideration resulting in a total of 66,326,134 shares of Class A common stock, par value $0.01 per share, of the Company (the “Class A Common Stock”) being issued in connection with the transaction (such transaction, the “OneStim Acquisition”; see Note 3—The OneStim Acquisition to the consolidated and combined financial statements included in “Item 8. Financial Statements and Supplementary Data”). Effective December 31, 2020, Schlumberger owned 37% of the issued and outstanding shares of our combined Class A Common Stock and our Class B common stock, par value $0.01 per share (the “Class B Common Stock” and, together with the Class A Common Stock, the “Common Stock”). 
+The OneStim Acquisition substantially increased the Company’s geographical reach and expanded operations, allowing the Company to serve a broader range of customers and utilize the increase in scale, vertical integration and technological know-how to better serve new and existing customers. The Transferred Business includes over 500 fully operational hydraulic fracturing pumps, district facilities, pumpdown perforating wireline units, two state-of-the-art sand mines in the Permian Basin and a highly experienced team of employees. Additionally, the Company added over 400 owned and licensed patents, significant internally developed software intellectual property and a strategic alliance agreement, which increases access to technology portfolios and advances the technological collaborations we are able to offer our customers. The combined company offers best-in-class completion services for the sustainable development of unconventional resource plays in the United States and Canada onshore markets. 
+Cyclical Nature of Industry 
+We operate in a highly cyclical industry. The key factor driving demand for our services is the level of drilling activity by E&P companies, which in turn depends largely on the current and anticipated economics of new well completions. Global supply and demand for oil and the domestic supply and demand for natural gas are critical in assessing industry outlook. Demand for oil and natural gas is cyclical and subject to large, rapid fluctuations, such as those experienced in 2020. E&P companies tend to increase capital expenditures in response to increases in oil and natural gas prices, which generally results in greater revenues and profits for oilfield service companies such as ours. Increased capital expenditures also ultimately lead to greater production, which historically has resulted in increased supplies of hydrocarbons and reduced prices which in turn tend to drive a future reduction in E&P companies capital expenditures and reduce demand for oilfield services. For these reasons, the results of our operations may fluctuate from quarter to quarter and from year to year, and these fluctuations may distort comparisons of results across periods. 
+Seasonality 
+Our results of operations have historically reflected seasonal tendencies relating to holiday seasons, inclement weather and the conclusion of our customers’ annual drilling and completion capital expenditure budgets. Our most notable declines typically occur in the fourth quarter of the year for the reasons described above. Additionally, some of the areas in which we have operations, including Canada, the DJ Basin, Powder River Basin and Williston Basin, are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice, rain, or frost, and related road restrictions, we may be unable to move our equipment between locations, thereby reducing our ability to provide services and generate revenues. The exploration activities of our customers may also be affected during such periods of adverse weather conditions. Additionally, extended drought conditions in our operating regions could impact our ability or our customers’ ability to source sufficient water or increase the cost for such water. 
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+Intellectual Property 
+Over the last several years and in connection with the OneStim Acquisition, we have significantly invested in our research and technology capabilities. Our efforts to date have been focused on developing innovative, fit-for-purpose solutions designed to enhance our core service offerings, increase completion efficiencies, provide cost savings to our operations and add value for our customers. 
+We seek patent and trademark protections for our technology when we deem it prudent, and we aggressively pursue protection of these rights when warranted. We believe our patents, trademarks, and other protections for our proprietary technologies are adequate for the conduct of our business and that no single patent or trademark is critical to our business. In addition, we rely, to a great extent, on the technical expertise and know-how of our personnel to maintain our competitive position, and we take commercially reasonable measures to protect trade secrets and other confidential and/or proprietary information relating to the technologies we develop. 
+Human Capital Management 
+As of December 31, 2020, we had 1,946 employees and no unionized labor. We believe we have good relations with our employees. We promote a people-centered culture focused heavily on our employees and believe that the strength of our workforce is critical to our success as a company. We consistently assess the current business environment and labor market to refine our compensation and benefits programs in order to attract and retain top talent in our industry. We generally strive to hire people with integrity, a positive attitude and hunger to learn and contribute to a team. In response to the COVID-19 pandemic, we reduced our headcount and implemented a company-wide employee furlough plan in order to align with the uncertain level of frac demand we experienced during the second and third quarters of 2020. As of September 30, 2020, all furloughed employees had returned from furlough. We have implemented and continue to implement safety measures in all of our facilities to address the COVID-19 pandemic. 
+Additionally, as a result of the OneStim Acquisition, we expect to hire approximately 800 employees following a brief transition period during which their continuing service is provided while on secondment from Schlumberger. 
+Health and Safety 
+Our people are our most important asset and ensuring their safety and the safety of those around them is the most important thing we do. Making certain that the Liberty team is well trained to handle the complexities of daily field operations, and that their training and competency remains current with the latest technology and standards is a key component. In order to facilitate this training, we have developed the Liberty Frac Academy, a thorough program where employees are trained on various aspects of the Company, from safety in equipment operation to leadership skills. The Liberty Frac Academy not only ensures dissemination of high-quality training material, but also provides a forum for sharing best practices and lessons learned across the Company. 
+Programs and Benefits 
+One way we have demonstrated a history of investing in our workforce is by offering competitive salaries and wages. To foster a strong sense of ownership, restricted stock units are provided to eligible non-executive employees under our stock incentive program. Furthermore, we offer innovative benefits to all eligible employees, including, among others, comprehensive health insurance coverage, parental leave to all new parents, for birth or adoption, financial support for child adoption, leave to care for partners with serious health conditions, 401(k) savings plan and educational tuition assistance for both bachelor’s degree and master’s degree programs. We are also passionate about community investment and, in 2019, we joined the Ban the Box initiative which provides work opportunities for formerly incarcerated individuals. 
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+Properties 
+Properties 
+Our corporate headquarters are located at 950 17 th Street, Suite 2400, Denver, Colorado 80202. We lease our general office space at our corporate headquarters. The lease expires in December 2027. We currently own or lease the following additional principal properties: 
+District Facility Location Size Leased or Owned 
+Midland, TX 160,000 sq. ft on 147 acres Owned 
+Odessa, TX 77,500 sq. ft on 47 acres Owned 
+Cibolo, TX 90,000 sq. ft on 34 acres Owned 
+Kermit, TX 5,000 acres Owned 
+Monahans, TX 3,200 acres Owned 
+Shreveport, LA 225,000 sq ft. on 50 acres Owned 
+Cheyenne, WY 115,000 sq. ft on 60 acres Owned 
+Gillette, WY 32,757 sq. ft on 15 acres Leased (through December 31, 2034) 
+Henderson, CO 50,000 sq. ft on 13 acres Leased (through December 31, 2034) 
+Williston, ND 30,000 sq. ft on 15 acres Owned 
+El Reno, OK 80,000 sq. ft on 33 acres Owned 
+Red Deer, AB 170,000 sq. ft on 42 acres Owned 
+Grand Prairie, AB 135,000 sq. ft on 40 acres Owned 
+Huallen, AB 80 acres Owned 
+We also lease several smaller facilities, which leases generally have terms of one to six years. We believe that our existing facilities are adequate for our operations and their locations allow us to efficiently serve our customers. We do not believe that any single facility is material to our operations and, if necessary, we could readily obtain a replacement facility. 
+Marketing and Customers 
+Our sales and marketing activities typically are performed through our local sales representatives in each geographic region, and are supported by our corporate headquarters. For the years ended December 31, 2020, 2019 and 2018, our top five customers collectively accounted for approximatel y 48% , 35% and 42% of our revenues, respectively. For the year ended December 31, 2020, PDC Energy Inc., ConocoPhillips Company, Parsley Energy Operations, LLC, and WPX Energy each accounted for more than 10% of our revenues. No customer accounted for more than 10% of our revenues for the year ended December 31, 2019. For the year ended December 31, 2018, Extraction Oil & Gas, Inc. accounted for more than 10% of our revenues. 
+Suppliers and Raw Materials 
+We have a dedicated supply chain team that manages sourcing and logistics to ensure flexibility and continuity of supply in a cost effective manner across our areas of operation. We have built long-term relationships with multiple industry leading suppliers of proppant, chemicals and hydraulic fracturing equipment and have started to internally design and assemble key pump and maintenance parts. In addition, we have built a strong relationship with the assembler of our custom-designed hydraulic fracturing fleets and believe we will continue to have timely access to new, high capability fleets as we continue to grow. In 2018, we also vertically integrated a supplier of certain major components through the acquisition of ST9 Gas and Oil LLC. 
+We purchase a wide variety of raw materials, parts and components that are manufactured and supplied for our operations. We are not dependent on any single source of supply for those parts, supplies or materials. To date, we have generally been able to obtain the equipment, parts and supplies necessary to support our operations on a timely basis. While we believe that we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers, we may not always be able to do so. In addition, certain materials for which we do not currently have long-term supply agreements could experience shortages and significant price increases in the future. As a result, we may be unable to mitigate any future supply shortages and our results of operations, prospects and financial condition could be adversely affected. The OneStim Acquisition included two state-of-the-art sand mines in the Permian Basin, which further alleviates the risk of potential future material supply shortages. 
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+Competition 
+The markets in which we operate are highly competitive. We provide services in various geographic regions across the United States and Canada, and our competitors include many large and small oilfield service providers, including some of the largest integrated service companies. Our hydraulic fracturing services compete with large, integrated companies such as Halliburton Company as well as other companies including Calfrac Well Services Ltd., FTS International, Inc., NexTier Oilfield Solutions Inc., Universal Pressure Pumping, Inc., ProPetro Services, Inc., RPC, Inc., STEP Energy Services and U.S. Well Services, Inc. In addition, our industry is highly fragmented and we compete regionally with a significant number of smaller service providers. 
+We believe that the principal competitive factors in the markets we serve are technical expertise, equipment capacity, work force competency, efficiency, safety record, reputation, experience and price. Additionally, projects are often awarded on a bid basis, which tends to create a highly competitive environment. We seek to differentiate ourselves from our competitors by delivering the highest-quality services and equipment possible, coupled with superior execution and operating efficiency in a safe working environment. 
+Governmental Regulation 
+As a company with operations in both the United States and Canada, we are subject to the laws of both jurisdictions in which we operate and the rules and regulations of various governing bodies, which may differ among those jurisdictions. Compliance with these laws, rules and regulations has not had, and is not expected to have, a material effect on our capital expenditures, results of operations and competitive position as compared to prior periods. We are also subject to numerous environmental and regulatory requirements related to our operations. For further information related to such regulation, see “Item 1A. Risk Factors.” 
+Available Information 
+We file or furnish annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The SEC also maintains an internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC. 
+We also make available free of charge through our website, www.libertyfrac.com, electronic copies of certain documents that we file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. 
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+Item 1A. Risk Factors 
+Described below are certain risks that we believe apply to our business and the industry in which we operate. You should carefully consider each of the following risk factors in conjunction with other information provided in this Annual Report on Form 10-K and in our other public disclosures. The risks described below highlight potential events, trends or other circumstances that could adversely affect our business, financial condition, results of operations, cash flows, liquidity or access to sources of financing, and consequently, the market value of our Class A Common Stock. These risks could cause our future results to differ materially from historical results and from guidance we may provide regarding our expectations of future financial performance. The risks described below are those that we have identified as material and is not an exhaustive list of all the risks we face. There may be other risks that we have not identified or that we have deemed to be immaterial. Please refer to the explanation of the qualifications and limitation on forward-looking statements set forth on page ii hereof. 
+Risks Related to the COVID-19 Pandemic 
+The COVID-19 pandemic has significantly reduced demand for our services, and has had, and may continue to have, a material adverse effect on our operations, business and financial results. 
+We face risks related to public health crises, including the ongoing COVID-19 pandemic. Although our operations have been deemed essential by the Department of Homeland Security, the effects of the COVID-19 pandemic, including travel bans, prohibitions on group events and gatherings, shutdowns of certain businesses, curfews, shelter-in-place orders and recommendations to practice social distancing in addition to other actions taken by both businesses and governments, have resulted in a significant and swift reduction in international and U.S. economic activity. The collapse in the demand for oil caused by this unprecedented global health and economic crisis, coupled with the current oil oversupply, has had, and may continue to have, a material adverse impact on the demand for our services. The decline in our customers’ demand for our services has had, and is likely to continue to have, a material adverse impact on our financial condition, results of operations and cash flows. 
+We are closely monitoring the effects of the pandemic on our customers, operations, and employees. These effects have included, and may continue to include, adverse revenue and net income effects, financial health of our customers and therefore their ability to drill and complete wells or pay for services provided, financial health of our suppliers and therefore their ability to deliver necessary goods and services, disruptions to our operations, and ultimately the financial health and results of the Company. As we cannot predict the duration or scope of the COVID-19 pandemic, the anticipated negative financial impact to our operating results cannot be reasonably estimated, but it may last for an extended period of time. 
+The extent to which our operating and financial results are affected by COVID-19 will depend on various factors and consequences beyond our control, such as the duration and scope of the pandemic, additional actions by businesses and governments in response to the pandemic, and the speed and effectiveness of responses to combat the virus. COVID-19, and the volatile regional and global economic conditions stemming from the pandemic, could also aggravate the other risk factors that we identify herein. COVID-19 may also materially adversely affect our operating and financial results in a manner that is not currently known to us or that we do not currently consider to present significant risks to our operations. 
+We are exposed to counterparty credit risk. Nonpayment and nonperformance by our customers, suppliers or vendors could adversely impact our operations, cash flows and financial condition. 
+Weak economic conditions and widespread financial distress, including the significantly reduced global and national economic activity caused by the COVID-19 pandemic, could reduce the liquidity of our customers, suppliers or vendors, making it more difficult for them to meet their obligations to us. We are therefore subject to heightened risks of loss resulting from nonpayment or nonperformance by our customers, suppliers and vendors. Severe financial problems encountered by our customers, suppliers and vendors could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements. In the event that any of our customers was to enter into bankruptcy, we could lose all or a portion of the amounts owed to us by such customer, and we may be forced to cancel all or a portion of our service contracts with such customer at significant expense to us. 
+In addition, nonperformance by suppliers or vendors who have committed to provide us with critical products or services could raise our costs or interfere with our ability to successfully conduct our business. All of the above may be exacerbated in the future as the COVID-19 outbreak and the governmental responses to the outbreak continue. These factors, combined with volatile prices of oil and natural gas, may precipitate a continued economic slowdown and/or a recession. 
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+Risks Related to the OneStim Acquisition 
+The integration of the Transferred Business may not be as successful as anticipated, and the Company may not achieve the intended benefits or do so within the intended timeframe. 
+The OneStim Acquisition involves numerous operational, strategic, financial, accounting, legal, tax and other risks. Difficulties in integrating the Transferred Business, particularly during the COVID-19 pandemic, may result in the Company performing differently than expected, in operational challenges or in the delay or failure to realize anticipated expense-related efficiencies, and could have an adverse effect on the Company’s financial condition, results of operations or cash flows. Potential difficulties that may be encountered in the integration process include, among other factors: 
+• the inability to successfully integrate the Transferred Business, operationally and culturally, in a manner that permits the Company to achieve the full revenue anticipated from the OneStim Acquisition; 
+• performance shortfalls due to COVID-19 pandemic and related decline in demand for our services; 
+• complexities associated with managing a larger, more complex, integrated business, including the potential diversion of management’s attention; 
+• not realizing anticipated operating synergies; 
+• potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with the OneStim Acquisition; 
+• integrating relationships with customers, vendors and business partners; 
+• performance shortfalls as a result of the diversion of management’s attention caused by completing the OneStim Acquisition and integrating the Transferred Business operations; and 
+• the disruption of, or the loss of momentum in, the Company’s ongoing business or inconsistencies in standards, controls, procedures and policies. 
+Additionally, the success of the OneStim Acquisition will depend, in part, on the Company’s ability to realize the anticipated benefits from combining the Transferred Business and the Company’s business, including operational and other synergies that the Company believes we will achieve. The anticipated benefits of the OneStim Acquisition may not be realized fully or at all, may take longer to realize than expected or could have other adverse effects that the Company does not currently foresee. Some of the assumptions that the Company has made, such as the achievement of operating synergies, may not be realized. 
+The Company’s results may suffer if it does not effectively manage its expanded operations following the OneStim Acquisition. 
+Since the OneStim Acquisition, the size of the Company’s business has increased significantly. In addition, we now own and operate two sand mines. While we have retained qualified personnel to operate the mines, we have not undertaken mining operations in the past. The Company’s future success will depend, in part, on the Company’s ability to manage this expanded business, which poses numerous risks and uncertainties, including the need to integrate the Transferred Business and their operations into the Company’s existing business in an efficient and timely manner, to combine systems and management controls and to integrate relationships with customers, vendors and business partners. Failure to successfully manage the Transferred Business may have an adverse effect on the Company’s financial condition, results of operations or cash flows. 
+The Schlumberger Parties now have significant influence over us. 
+As of December 31, 2020, Schlumberger owned approximately 37% of the outstanding shares of Common Stock. As long as Schlumberger owns or controls a significant percentage of the Company’s outstanding voting power, they will have the ability to significantly influence corporate actions requiring stockholder approval, including the election and removal of directors and the size of the board of directors (the “Board”), any amendment to the Company’s certificate of incorporation or bylaws, or the approval of any merger or other significant corporate transaction, including a sale of substantially all of the Company’s assets. Schlumberger’s influence over our management could have the effect of delaying or preventing a change in control or otherwise discouraging a potential acquirer from attempting to obtain control of us, which could cause the market price of the shares of Class A Common Stock to decline or prevent stockholders from realizing a premium over the market price for the shares of Class A Common Stock. 
+Pursuant to the A&R Stockholders Agreement, Schlumberger has designated two directors to the Company’s board of directors. Schlumberger’s right to designate directors to our Board is subject to the Schlumberger’s ownership percentage of the total outstanding shares of Common Stock. If Schlumberger and its affiliates collectively beneficially own: (a) 20% or greater of the outstanding shares of Common Stock, they will have the right to appoint two directors or (b) at least 10% but less than 20% of the outstanding shares of Common Stock, they will have the right to appoint one director. 
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+Schlumberger’s interests may not align with the Company’s interests or the interests of the Company’s other stockholders. 
+Sales of substantial amounts of shares of Class A Common Stock in the open market by Schlumberger could depress the Company’s stock price. 
+Shares of Class A Common Stock that were issued to Schlumberger in the OneStim Acquisition will become freely tradable once registered pursuant to the amended and restated registration rights agreement entered into in connection with the OneStim Acquisition (“A&R Registration Rights Agreement”). As a result, the shares of Class A Common Stock held by Schlumberger will have no restrictions other than described below or require further registration under the Securities Act, provided, however, that any stockholders, including Schlumberger, who are deemed the Company’s affiliates will be subject to the resale restrictions of Rule 144 under the Securities Act. 
+Pursuant to the A&R Stockholders Agreement, Schlumberger is subject to certain lock-up and transfer restrictions. Schlumberger will not, (a) for a period of nine months from December 31, 2020 (the “Closing”), transfer or dispose of (or take other analogous actions in accordance with the terms of the A&R Stockholders Agreement) any economic, voting or other rights in or to their shares of Class A Common Stock, other than certain permitted transfers, and (b) for a period of four years from the Closing, make any transfer of shares of Class A Common Stock to any direct competitor of the Company or to any person that is subject to, or by virtue of such transfer would become subject to, the reporting obligations under Schedule 13D under the Exchange Act, with respect to shares of Common Stock. 
+Following the lock-up and transfer restrictions period described above, Schlumberger may wish to dispose of some or all of its interests in the Company, and as a result may seek to sell its shares of Class A Common Stock. These sales (or the perception that these sales may occur), coupled with the increase in the outstanding number of shares of Class A Common Stock, may affect the market for, and the market price of, shares of Class A Common Stock in an adverse manner. 
+If Schlumberger sells substantial amounts of Class A Common Stock in the public market, the market price of the Class A Common Stock may decrease. 
+Following the OneStim Acquisition, we expanded our operations to Canada and may be subject to increased business and economic risks. 
+The Company has historically owned and operated its assets exclusively within the United States. In connection with the OneStim Acquisition, we acquired certain Canadian assets and liabilities, which marked our entry into a new geographical territory where we have limited or no experience in owning and operating assets and providing our services. As a result, we are subject to a variety of risks inherent in doing business internationally, including: risks related to the legal and regulatory environment in foreign jurisdictions; fluctuations in currency exchange rates; complying with multiple tax jurisdictions; difficulties in staffing and managing international operations and the increased travel, infrastructure and compliance costs associated with international locations and employees; regulations that might add difficulties in repatriating cash earned outside the United States and otherwise preventing us from freely moving cash; complying with statutory equity requirements; and complying with the U.S. Foreign Corrupt Practices Act and similar laws in Canada. If we fail to manage our operations in Canada successfully, our business may suffer. 
+Risks Related to the Oil and Natural Gas Industry 
+Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews and investment practices for such activities may serve to limit future oil and natural gas E&P activities and could have a material adverse effect on our results of operations and business. 
+Various federal, state and local legislative and regulatory initiatives have been, or could be undertaken which could result in additional requirements or restrictions being imposed on hydraulic fracturing operations. Currently, hydraulic fracturing is generally exempt from federal regulation under the Safe Drinking Water Act Underground Injection Control (the “SDWA UIC”) program and is typically regulated by state oil and gas commissions or similar agencies but increased scrutiny and regulation, by federal agencies does occur. For example, in late 2016, the Environmental Protection Agency (the “EPA”) released a final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources. Additionally, the EPA has asserted regulatory authority pursuant to the SDWA UIC program over hydraulic fracturing activities involving the use of diesel fuel in the fracturing fluid and issued guidance of such activities. Furthermore, the U.S. Bureau of Land Management (the “BLM”) published a final rule in 2015 that established stringent standards relating to hydraulic fracturing on federal and Native American lands. The rule was since rescinded, but the rescission is currently on appeal to the U.S. Court of Appeals for the Ninth Circuit. Similarly, the EPA has adopted rules on the capture of methane and other emissions released during hydraulic fracturing. These rules have been the subject of ongoing legal challenges. Notwithstanding these legal challenges, President Biden issued an executive order in January 2021 that called for issuance of proposed rules by no later than September 2021 that would restore rules for methane standards applicable to new, modified, and reconstructed sources and establish new methane and volatile organic compound standards applicable to existing oil and gas operations, including the production, transmission, 
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+processing and storage segments. In addition to federal regulatory actions, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. 
+The Biden Administration is expected to place significant emphasis on steps to address climate change. Although the U.S. had withdrawn from the Paris Agreement, which requested that nations limit their greenhouse gas emissions through individually-determined reduction goals every five years after 2020, President Biden issued an executive order in January 2021 recommitting the United States to the Paris Agreement. With this recommitment, executive orders may be issued or federal legislation or regulatory initiatives may be adopted to achieve the agreement’s goals, including additional restrictions on hydraulic fracturing or related oil and gas development activities. Additionally, in January 2021, the U.S. Department of the Interior issued an order that effectively suspends new oil and gas leases and drilling permits on non-Indian federal lands and waters for a period of 60 days, but the suspension does not limit existing operations under valid leases. President Biden followed with an executive order that ordered the Secretary of the Interior to pause the issuance of new oil and gas leases on federal public lands and offshore waters pending completion of a comprehensive review of federal oil and gas permitting and leasing practices that take into consideration potential climate and other impacts associated with oil and gas activities. This order further directs agencies to identify fossil fuel subsidies provided by such agencies and take measures to ensure that federal funding is not directly subsidizing fossil fuels, with an objective of eliminating fossil fuel subsidies from federal budget requests beginning in 2022. This order is currently being challenged by industry groups. It remains to be seen to what extent the Biden Administration will pursue legislation, additional executive actions, regulations or other regulatory initiatives to limit, delay or prohibit hydraulic fracturing or other aspects of oil and gas development. In the event that these or other new federal restrictions, delays or prohibitions relating to the hydraulic fracturing process are adopted in areas where we or our customers conduct business, we or our customers may incur additional costs or permitting requirements to comply with such federal requirements that may be significant and, in the case of our customers, also could result in added restrictions or delays in the pursuit of exploration, development, or production activities, which would in turn reduce the demand for our services and have a material adverse effect on our results of operations. 
+Moreover, many states and local governments have adopted regulations that impose more stringent permitting, disclosure, disposal and well-construction requirements on hydraulic fracturing operations, including states where we or our customers operate, such as Texas, Colorado and North Dakota. States could also elect to place prohibitions on hydraulic fracturing, as several states have already done. In addition, some states have adopted broader sets of requirements related to oil and gas development more generally that could impact hydraulic fracturing activities. For example, in 2019 the Colorado legislature adopted SB 19-181, which gave greater regulatory authority to local jurisdictions. In response, the Colorado Oil and Gas Conservation Commission modified its rules to address the requirements of the legislation, adopting increased setback requirements and provisions for assessing alternative sites for well pads to minimize environmental impacts. Environmental groups, local citizens groups and others continue to seek to use a variety of means to force action on additional restrictions on hydraulic fracturing and oil and gas development generally. 
+A theme of avoiding or limiting investment in companies that engage in hydraulic fracturing has entered into capital markets. For example, in July 2020, Deutsche Bank announced that it would no longer finance oil and gas projects that use hydraulic fracturing in countries with scarce water supplies. Moreover, BlackRock recently affirmed its commitment to divest from investments in fossil fuels due to concerns over climate change. While a substantial number major banks and financing sources remain active in investments related to hydraulic fracturing, it is possible that the investment avoidance or limitation theme could expand in the future and restrict access to capital for companies like us. 
+Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to, and litigation concerning, oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays for our customers or increased operating costs in the production of oil and natural gas, including from the developing shale plays, or could make it more difficult for us and our customers to perform hydraulic fracturing. The adoption of any additional laws or regulations regarding hydraulic fracturing or a furtherance of themes of investment avoidance or limitation in hydraulic fracturing could potentially cause a decrease in the completion of new oil and natural gas wells and an associated decrease in demand for our services and increased compliance costs and time. Such a decrease could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition. Moreover, the increased competitiveness of alternative energy sources (such as wind, solar, geothermal, tidal and biofuels) or increased focus on reducing the use of combustion engines in transportation (such as governmental mandates that ban the sale of new gasoline-powered automobiles) could reduce demand for hydrocarbons and therefore for our services, which would lead to a reduction in our revenues. 
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+Our business depends on domestic capital spending by the oil and natural gas industry, and reductions in capital spending could have a material adverse effect on our liquidity, results of operations and financial condition. 
+Our business is directly affected by our customers’ capital spending to explore for, develop and produce oil and natural gas in the United States. In addition, certain of our customers could become unable to pay their vendors and service providers, including us, as a result of a decline in commodity prices. Reduced discovery rates of new oil and natural gas reserves in our areas of operation as a result of decreased capital spending may also have a negative long-term impact on our business, even in an environment of stronger oil and natural gas prices. Any of these conditions or events could adversely affect our operating results. If current activity levels decrease or our customers further reduce their capital spending, it could have a material adverse effect on our liquidity, results of operations and financial condition. 
+Industry conditions are influenced by numerous factors over which we have no control, including: 
+• expected economic returns to E&P companies of new well completions; 
+• domestic and foreign economic conditions and supply of and demand for oil and natural gas; 
+• the level of prices, and expectations about future prices, of oil and natural gas; 
+• the level of global oil and natural gas exploration and production; 
+• the level of domestic and global oil and natural gas inventories; 
+• the supply of and demand for hydraulic fracturing services and equipment in the United States; 
+• federal, tribal, state and local laws, regulations and taxes, including the policies of governments regarding hydraulic fracturing and oil and natural gas exploration, development and production activities as well as non-U.S. governmental regulations and taxes; 
+• governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves; 
+• political and economic conditions in oil and natural gas producing countries; 
+• actions by the members of the Organization of Petroleum Exporting Countries with respect to oil production levels and potential changes in such levels; 
+• global weather conditions and natural disasters; 
+• worldwide political, military and economic conditions; 
+• the cost of producing and delivering oil and natural gas; 
+• lead times associated with acquiring equipment and products and availability of qualified personnel; 
+• the discovery rates of new oil and natural gas reserves; 
+• stockholder activism or activities by non-governmental organizations to limit certain sources of funding for the energy sector or to restrict the exploration, development and production of oil and natural gas; 
+• the availability of water resources, suitable proppant and chemical additives in sufficient quantities for use in hydraulic fracturing fluids; 
+• advances in exploration, development and production technologies or in technologies affecting energy consumption; 
+• the availability, proximity and capacity of oil and natural gas pipelines and other transportation facilities; 
+• merger and divestiture activity among oil and natural gas producers; 
+• the price and availability of alternative fuels and energy sources; and 
+• uncertainty in capital and commodities markets and the ability of oil and natural gas companies to raise equity capital and debt financing. 
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+The volatility of oil and natural gas prices may adversely affect the demand for our hydraulic fracturing services and negatively impact our results of operations. 
+The demand for our hydraulic fracturing services is primarily determined by current and anticipated oil and natural gas prices and the related levels of capital spending and drilling activity in the areas in which we have operations. Volatility or weakness in oil prices or natural gas prices (or the perception that oil prices or natural gas prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells. This, in turn, could lead to lower demand for our services and may cause lower utilization of our assets. We have experienced, and may in the future experience significant fluctuations in operating results as a result of the reactions of our customers to changes in oil and natural gas prices. 
+Prices for oil and natural gas historically have been extremely volatile and are expected to continue to be volatile. During the year 2020, the posted West Texas Intermediate (“WTI”) price traded at an average of $39.16 per barrel (“Bbl”), well below the 2019 average of $56.99 per Bbl. As discussed elsewhere, the combined impact of the COVID-19 pandemic and the breakdown of the Organization of the Petroleum Exporting Countries (“OPEC”) and non-OPEC suppliers (collectively, “OPEC+”) production cut negotiations in the spring caused oil prices to drop to historical lows in April 2020. Prices have started to recover, and averaged $53.93 per Bbl since the beginning of 2021 through February 16, 2021. If the prices of oil and natural gas continue to be volatile, our operations, financial condition, cash flows and level of expenditures may be materially and adversely affected. 
+Delays or restrictions in obtaining permits by us for our operations or by our customers for their operations could impair our business. 
+In most states, our operations and the operations of our oil and natural gas producing customers require permits from one or more governmental agencies in order to perform drilling and completion activities, secure water rights, or other regulated activities. Such permits are typically issued by state agencies, but federal and local governmental permits may also be required. The requirements for such permits vary depending on the location where such regulated activities will be conducted. As with all governmental permitting processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit to be issued, and the conditions that may be imposed in connection with the granting of the permit. In addition, some of our customers’ drilling and completion activities may take place on federal land or Native American lands, requiring leases and other approvals from the federal government or Native American tribes to conduct such drilling and completion activities or other regulated activities. Under certain circumstances, federal agencies may cancel proposed leases for federal lands and refuse to grant or delay required approvals. Therefore, our customers’ operations in certain areas may be interrupted or suspended for varying lengths of time, causing a loss of revenue to us and adversely affecting our results of operations in support of those customers. 
+Oil and natural gas companies’ operations using hydraulic fracturing are substantially dependent on the availability of water. Restrictions on the ability to obtain water for E&P activities and the disposal of flowback and produced water may impact their operations and have a corresponding adverse effect on our business, results of operations and financial condition. 
+Water is an essential component of shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Our oil and natural gas producing customers’ access to water to be used in these processes may be adversely affected due to reasons such as periods of extended drought, privatization, third party competition for water in localized areas or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. The occurrence of these or similar developments may result in limitations being placed on allocations of water due to needs by third party businesses with more senior contractual or permitting rights to the water. Our customers’ inability to locate or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact their E&P operations and have a corresponding adverse effect on our business, results of operations and financial condition. 
+Moreover, the imposition of new environmental regulations and other regulatory initiatives could include increased restrictions on our producing customers’ ability to dispose of flowback and produced water generated in hydraulic fracturing or other fluids resulting from E&P activities. Applicable laws impose restrictions and strict controls regarding the discharge of pollutants into waters of the United States and require that permits or other approvals be obtained to discharge pollutants to such waters. Additionally, regulations implemented under both federal and state laws prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. These laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and hazardous substances. Compliance with current and future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells and any inability to secure transportation and access to disposal wells with sufficient capacity to accept all of our flowback and produced water on economic terms may increase our customers’ operating costs and could result in restrictions, delays, or cancellations of our customers’ operations, the extent of which cannot be predicted. 
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+Fuel conservation measures could reduce demand for oil and natural gas which would in turn reduce the demand for our services. 
+Fuel conservation measures, alternative fuel requirements and increasing consumer demand for alternatives to oil and natural gas could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas may have a material adverse effect on our business, financial condition, prospects, results of operations and cash flows. Additionally, the increased competitiveness of alternative energy sources (such as wind, solar geothermal, tidal, and biofuels) could reduce demand for hydrocarbons and therefore for our services, which would lead to a reduction in our revenues. 
+Our operations are subject to significant risks, some of which are beyond our control. These risks may be self-insured, or may not be fully covered under our insurance policies. 
+Our operations are subject to significant hazards often found in the oil and natural gas industry, such as, but not limited to, accidents, including accidents related to trucking operations provided in connection with our services, blowouts, explosions, craterings, fires, natural gas leaks, oil and produced water spills and releases of hydraulic fracturing fluids or other well fluids into the environment. These conditions can cause: 
+• disruption in operations; 
+• substantial repair or remediation costs; 
+• personal injury or loss of human life; 
+• significant damage to or destruction of property, and equipment; 
+• environmental pollution, including groundwater contamination; 
+• unusual or unexpected geological formations or pressures and industrial accidents; 
+• impairment or suspension of operations; and 
+• substantial revenue loss. 
+In addition, our operations are subject to, and exposed to, employee/employer liabilities and risks such as wrongful termination, discrimination, labor organizing, retaliation claims and general human resource related matters. 
+The occurrence of a significant event or adverse claim in excess of the insurance coverage that we maintain or that is not covered by insurance could have a material adverse effect on our liquidity, consolidated results of operations and financial condition. Claims for loss of oil and natural gas production and damage to formations can occur in the well services industry. Litigation arising from a catastrophic occurrence at a location where our equipment and services are being used or trucking services provided in connection therewith may result in our being named as a defendant in lawsuits asserting large claims. 
+We do not have insurance against all foreseeable risks, either because insurance is not available or because of the high premium costs. The occurrence of an event not fully insured against or the failure of an insurer to meet its insurance obligations could result in substantial losses. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. Insurance may not be available to cover any or all of the risks to which we are subject, or, even if available, it may be inadequate, or insurance premiums or other costs could rise significantly in the future so as to make such insurance prohibitively expensive. 
+We may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition, prospects and results of operations. 
+Our services are subject to inherent risks that can cause personal injury or loss of life, damage to or destruction of property, equipment or the environment or the suspension of our operations. Litigation arising from operations where our services are provided, may cause us to be named as a defendant in lawsuits asserting potentially large claims including claims for exemplary damages. We maintain what we believe is customary and reasonable insurance to protect our business against these potential losses, but such insurance may not be adequate to cover our liabilities, and we are not fully insured against all risks. 
+In addition, our customers usually assume responsibility for, including control and removal of, all other pollution or contamination which may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling and completion fluids. We may have liability in such cases if we are grossly negligent or commit willful acts. Our customers generally agree to indemnify us against claims arising from their employees’ personal injury or death to the extent that, in the case of our hydraulic fracturing operations, their employees are injured by such operations, unless resulting from our gross negligence or willful misconduct. Our customers also generally agree to indemnify us for loss or destruction of customer-owned property or equipment. In turn, we agree to indemnify our customers for loss or destruction of property or 
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+equipment we own and for liabilities arising from personal injury to or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. However, we might not succeed in enforcing such contractual liability allocation or might incur an unforeseen liability falling outside the scope of such allocation. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operation. 
+We are subject to environmental and occupational health and safety laws and regulations that may expose us to significant costs and liabilities. 
+Our operations and the operations of our customers are subject to numerous federal, tribal, regional, state and local laws and regulations relating to protection of the environment including natural resources, health and safety aspects of our operations and waste management, including the transportation and disposal of waste and other materials. These laws and regulations may impose numerous obligations on our operations and the operations of our customers, including the acquisition of permits or other approvals to conduct regulated activities, the imposition of restrictions on the types, quantities and concentrations of various substances that may be released into the environment or injected in non-productive formations below ground in connection with oil and natural gas drilling and production activities, the incurrence of capital expenditures to mitigate or prevent releases of materials from our equipment, facilities or from customer locations where we are providing services, the imposition of substantial liabilities for pollution resulting from our operations, and the application of specific health and safety criteria addressing worker protection. Any failure on our part or the part of our customers to comply with these laws and regulations could result in assessment of sanctions including administrative, civil and criminal penalties; imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures; the occurrence of restrictions, delays or cancellations in the permitting, performance or development of projects or operations; and the issuance of orders enjoining performance of some or all of our operations in a particular area. 
+Our business activities present risks of incurring significant environmental costs and liabilities, including costs and liabilities resulting from our handling of oilfield and other wastes, because of air emissions and wastewater discharges related to our operations, and due to historical oilfield industry operations and waste disposal practices. Moreover, accidental releases or spills may occur in the course of our operations or at facilities where our wastes are taken for reclamation or disposal, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for injuries to persons or damages to properties or natural resources. Some environmental laws and regulations may impose strict liability, which means that in some situations we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Remedial costs and other damages arising as a result of environmental laws and costs associated with changes in environmental laws and regulations could be significant and have a material adverse effect on our liquidity, consolidated results of operations and financial condition. 
+Laws and regulations protecting the environment generally have become more stringent in recent years and are expected to continue to do so, which could lead to material increases in costs for future environmental compliance and remediation. In particular, the federal Endangered Special Act (“ESA”) restricts activities that may result in a “take” of endangered or threatened species and provides for substantial penalties in cases where listed species are taken by being harmed. The dunes sagebrush lizard is one example of a species that, if listed as endangered or threatened under the ESA, could impact our operations and the operations of our customers. The dunes sagebrush lizard is found in the active and semi-stable shinnery oak dunes of southeastern New Mexico and adjacent portions of Texas, including areas where our customers operate and our frac sand facilities are located. The U .S. Fish and Wildlife Service is currently conducting a thorough review to determine whether listing the dunes sagebrush lizard as endangered or threatened under the ESA is warranted. If the dunes sagebrush lizard is listed as an endangered or threatened species, our operations and the operations of our customers in any area that is designated as the dunes sagebrush lizard’s habitat may be limited, delayed or, in some circumstances, prohibited, and we and our customers could be required to comply with expensive mitigation measures intended to protect the dunes sagebrush lizard and its habitat. Furthermore, new laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement with respect to environmental matters could restrict, delay or curtail exploratory or developmental drilling for oil and natural gas by our customers and could limit our well servicing opportunities. 
+Oilfield anti-indemnity provisions enacted by many states may restrict or prohibit a party’s indemnification of us. 
+We typically enter into agreements with our customers governing the provision of our services, which usually include certain indemnification provisions for losses resulting from operations. Such agreements may require each party to indemnify the other against certain claims regardless of the negligence or other fault of the indemnified party; however, many states place limitations on contractual indemnity agreements, particularly agreements that indemnify a party against the consequences of its own negligence. Furthermore, certain states, including Texas, New Mexico and Wyoming, have enacted statutes generally referred to as “oilfield anti-indemnity acts” expressly prohibiting certain indemnity agreements contained in or related to oilfield services agreements. Such anti-indemnity acts may restrict or void a party’s indemnification of us, which could have a material adverse effect on our business, financial condition, prospects and results of operations. 
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+Technology advancements in well service technologies, including those involving hydraulic fracturing, could have a material adverse effect on our business, financial condition and results of operations. 
+The hydraulic fracturing industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As competitors and others use or develop new technologies or technologies comparable to ours in the future, we may lose market share or be placed at a competitive disadvantage. Further, we may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of our competitors may have greater financial, technical and personnel resources than we do, which may allow them to gain technological advantages or implement new technologies before we can. Additionally, we may be unable to implement new technologies or services at all, on a timely basis or at an acceptable cost. New technology could also make it easier for our customers to vertically integrate their operations, thereby reducing or eliminating the need for our services. Limits on our ability to effectively use or implement new technologies may have a material adverse effect on our business, financial condition and results of operations. 
+Risks Related to our Mines and Wireline Service 
+The sand mining operations are subject to a number of risks relating to the proppant industry. 
+In connection with the OneStim Acquisition, we acquired two state-of-the-art sand mines in the Permian Basin. Sand mining operations are subject to risks normally encountered in the proppant industry. These risks include, among others: unanticipated ground, grade or water conditions; inability to acquire or maintain, or public or nongovernmental organization opposition to, necessary permits for mining, access or water rights; our ability to timely obtain necessary authorizations, approvals and permits from regulatory agencies (including environmental agencies, such as the U.S. Fish and Wildlife Service, where our operations in West Texas may be slowed, limited or halted due to conservation efforts targeted at the habitat of the dunes sagebrush lizard); pit wall or pond failures, and sluffing events; costs associated with environmental compliance or as a result of unauthorized releases into the environment; restrictions imposed on our operations related to the protection of natural resources, including plant and animal species; and reduction in the amount of water available for processing. Any of these risks could result in delays, limitations or cancellations in mining or processing activities, losses or possible legal liability. 
+Silica-related legislation, health issues and litigation could have a material adverse effect on our business, reputation or results of operations. 
+We are subject to laws and regulations relating to human exposure to crystalline silica. Historically, our environmental compliance costs with respect to existing crystalline silica requirements have not had a material adverse effect on our results of operations; however, federal regulatory authorities and analogous state agencies may continue to propose changes in their regulations regarding workplace exposure to crystalline silica, such as permissible exposure limits, required controls and personal protective equipment. We may not be able to comply with any new laws and regulations that are adopted, and any new laws and regulations could have a material adverse effect on our operating results by requiring us to modify or cease our operations. 
+In addition, the inhalation of respirable crystalline silica is associated with the lung disease silicosis. There is evidence of an association between crystalline silica exposure or silicosis and lung cancer and a possible association with other diseases, including immune system disorders such as scleroderma. The actual or perceived health risks of handling hydraulic fracture sand could materially and adversely affect hydraulic fracturing service providers, including us, through reduced use of hydraulic fracture sand, the threat of product liability or employee lawsuits, increased scrutiny by federal, state and local regulatory authorities of us and our customers or reduced financing sources available to the industry. Furthermore, we may incur additional costs with respect to purchasing specialized equipment designed to reduce exposure to crystalline silica in connection with our operations or invest capital in new equipment. 
+We are subject to the Federal Mine Safety and Health Act of 1977, which imposes stringent health and safety standards on numerous aspects of its operations. 
+Our operations are subject to the Federal Mine Safety and Health Act of 1977, as amended by the Mine Improvement and New Emergency Response Act of 2006, which imposes stringent health and safety standards on numerous aspects of mineral extraction and processing operations, including the training of personnel, operating procedures, operating equipment, and other matters. Our failure to comply with such standards, or changes in such standards or the re-interpretation or more stringent enforcement thereof, could have a material adverse effect on our business and financial condition or otherwise impose significant restrictions on its ability to conduct mineral extraction and processing operations. 
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+The occurrence of explosive incidents could disrupt our operations and could adversely affect our business, financial condition and results of operations. 
+The wireline service we provide to oil and natural gas E&P customers involves the storage and handling of explosive materials. Despite the use of specialized facilities to store explosive materials and intensive employee training programs, the handling of explosive materials could result in incidents that temporarily shut down or otherwise disrupt our or E&P customers’ operations or could cause restrictions, delays or cancellations in the delivery of services. It is possible that an explosion could result in death or significant injuries to employees and other persons. Material property damage to us, E&P customers and third parties could also occur. Any explosive incident could expose us to adverse publicity or liability for damages or cause production restrictions, delays or cancellations, any of which developments could have a material adverse effect on our ability to compete, business, financial condition and results of operations. 
+Risks Related to the TRAs 
+The Company is required to make payments under the TRAs for certain tax benefits that it may claim, and the amounts of such payments could be significant. 
+In connection with the Company’s initial public offering (the “IPO”), on January 17, 2018, the Company entered into two Tax Receivable Agreements (the “TRAs”) with R/C Energy IV Direction Partnership, L.P. and the then-existing owners of Liberty Holdings that continued to own Liberty LLC Units (the “Legacy Owners” and each such person and any permitted transferee, a “TRA Holder” ). The TRAs generally provide for the payment by the Company to each TRA Holder of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that the Company actually realizes (or is deemed to realize in certain circumstances) as a result of certain increases in tax basis, net operating losses available to the Company as a result of the corporate reorganization performed in connection with the IPO (“Corporate Reorganization”), and certain benefits attributable to imputed interest. The Company will retain the benefit of the remaining 15% of these cash savings. 
+The Company is a holding company and has no material assets other than its equity interest in Liberty LLC. Because the Company has no independent means of generating revenue, its ability to make payments under the TRAs is dependent on the ability of Liberty LLC to make distributions to the Company in an amount sufficient to cover its obligations under the TRAs. To the extent that the Company is unable to make payments under the TRAs for any reason, such payments will be deferred and will accrue interest until paid. 
+The term of each of the TRAs continues until all tax benefits that are subject to such TRAs have been utilized or expired, unless the Company experiences a change of control (as defined in the TRAs, which includes certain mergers, asset sales and other forms of business combinations) or the TRAs are terminated early (at the Company’s election or as a result of its breach), and the Company makes the termination payments specified in such TRAs. In addition, payments the Company makes under the TRAs will be increased by any interest earned from the due date (without extensions) of the corresponding tax return. Payments under the TRAs commenced in 2020 and so long as the TRAs are not terminated, are anticipated to continue for 15 years after the date of the last redemption of the Liberty LLC Units. 
+In certain cases, if the Company experiences a change of control (as defined under the TRAs, which includes certain mergers, asset sales and other forms of business combinations) or the TRAs terminate early (at the Company’s election or as a result of its breach),the Company would be required to make a substantial, immediate lump-sum payment. As a result, the Company’s obligations under the TRAs could have a substantial negative impact on its liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. There can be no assurance that we will be able to finance our obligations under the TRAs. Furthermore, as a result of this payment obligation, holders of our Class A Common Stock could receive substantially less consideration in connection with a change in control transaction than they would receive in the absence of such obligation. Since our payment obligations under the TRAs will not be conditioned upon the TRA Holders’ having continued interest in the Company or liberty LLC, the TRA Holders’ interests may conflict with those of the holders of our Class A Common Stock. 
+Payments under the TRAs are based on the tax reporting positions that we will determine. The TRA Holders will not reimburse us for any payments previously made under the TRAs if any tax benefits that have given rise to payments under the TRAs are subsequently disallowed, except that excess payments made to any TRA Holder will be netted against payments that would otherwise be made to such TRA Holder, if any, after our determination of such excess. As a result, in such circumstances the Company could make payments that are greater than its actual cash tax savings, if any, and may not be able to recoup those payments, which could adversely affect the Company’s liquidity. Furthermore, the payments under the TRAs will not be conditioned upon a holder of rights under each of the TRAs having a continued ownership interest in the Company or Liberty LLC. For further details of the TRAs, see Note 11 —Income Taxes to the consolidated and combined financial statements included in “Item 8. Financial Statements and Supplementary Data.” 
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+General Risks Related to our Business 
+We may be adversely affected by uncertainty in the global financial markets and the deterioration of the financial condition of our customers. 
+Our future results may be impacted by the uncertainty caused by an economic downturn, volatility or deterioration in the debt and equity capital markets, inflation, deflation or other adverse economic conditions that may negatively affect us or parties with whom we do business resulting in a reduction in our customers’ spending and their non-payment or inability to perform obligations owed to us, such as the failure of customers to honor their commitments or the failure of major suppliers to complete orders. Additionally, during times when the oil or natural gas markets weaken, our customers are more likely to experience financial difficulties, including being unable to access debt or equity financing, which could result in a reduction in our customers’ spending for our services. In addition, in the course of our business we hold accounts receivable from our customers. In the event of the financial distress or bankruptcy of a customer, we could lose all or a portion of such outstanding accounts receivable associated with that customer. Further, if a customer was to enter into bankruptcy, it could also result in the cancellation of all or a portion of our service contracts with such customer at significant expense or loss of expected revenues to us. 
+Reliance upon a few large customers may adversely affect our revenue and operating results. 
+Our top five customers represented approximately 48%, 35%, and 42%, of our consolidated and combined revenue for the years ended December 31, 2020, 2019, and 2018, respectively. It is possible that we will derive a significant portion of our revenue from a concentrated group of customers in the future. If a major customer fails to pay us, revenue would be impacted and our operating results and financial condition could be materially harmed. Additionally, if we were to lose any material customer or our customers were to consolidated or merger with other operators, we may not be able to redeploy our equipment at similar utilization or pricing levels or within a short period of time and such loss could have a material adverse effect on our business until the equipment is redeployed at similar utilization or pricing levels. 
+We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss. 
+The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain processing activities. For example, we depend on digital technologies to perform many of our services and to process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. In early 2020, we experienced a denial of service cyberattack that targeted a portion of our non-financial data. We immediately shutdown critical systems, diagnosed the root cause of the attack and then methodically returned systems online. This cyberattack disrupted certain non-financial aspects of our internal system for a period of less than one day, while limited and non-critical portions of our systems were kept offline for up to one week in order to properly evaluate the breach. We determined that this cyberattack did not materially affect any of our operations. We engaged in extensive data evaluation for potential damage and concluded that minimal to no data loss had occurred as a result of this cyberattack. Our technologies, systems and networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches in the future that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we will likely be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. Our insurance coverage for cyberattacks may not be sufficient to cover all the losses we may experience as a result of such cyberattacks. 
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+Our assets require significant amounts of capital for maintenance, upgrades and refurbishment and may require significant capital expenditures for new equipment. 
+Our hydraulic fracturing fleets and other completion service-related equipment require significant capital investment in maintenance, upgrades and refurbishment to maintain their competitiveness. For example, since January 1, 2011 through December 31, 2020, we have deployed over 30 hydraulic fracturing fleets to service customers at a total cost to deploy of approximately $1.3 billion. The costs of components and labor have increased in the past and may increase in the future with increases in demand, which will require us to incur additional costs for any fleets we may acquire in the future. Our fleets and other equipment typically do not generate revenue while they are undergoing maintenance, upgrades or refurbishment. Any maintenance, upgrade or refurbishment project for our assets could increase our indebtedness or reduce cash available for other opportunities. Furthermore, such projects may require proportionally greater capital investments as a percentage of total asset value, which may make such projects difficult to finance on acceptable terms. To the extent we are unable to fund such projects, we may have less equipment available for service or our equipment may not be attractive to potential or current customers. Additionally, competition or advances in technology within our industry may require us to update or replace existing fleets or build or acquire new fleets. Such demands on our capital or reductions in demand for our hydraulic fracturing fleets and the increase in cost of labor necessary for such maintenance and improvement, in each case, could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations and may increase our costs. 
+We rely on certain third parties for proppant and chemical additives, and delays in deliveries of such materials, increases in the cost of such materials or our contractual obligations to pay for materials that we ultimately do not require could harm our business, results of operations and financial condition. 
+We have established relationships with certain suppliers of our raw materials (such as proppant and chemical additives). Delays or shortages in raw materials can result from a variety of reasons, including those caused by weather and natural disasters. Even once the root cause of a shortage or delay has passed, it can take time for our supply chain to recover and run in a regular fashion. Should any of our current suppliers be unable to provide the necessary materials or otherwise fail to deliver the materials in a timely manner and in the quantities required, any resulting delays in the provision of services could have a material adverse effect on our business, results of operations and financial condition. Additionally, increasing costs of such materials may negatively impact demand for our services or the profitability of our business operations. In the past, our industry faced sporadic proppant shortages associated with hydraulic fracturing operations requiring work stoppages, which are believed to have adversely impacted the operating results of several competitors. We may not be able to mitigate any future shortages of materials, including proppant. Furthermore, to the extent our contracts require us to purchase more materials, including proppant, than we ultimately require, we may be forced to pay for the excess amount under “take or pay” contract provisions. 
+We currently utilize one preferred assembler and a limited number of suppliers for major equipment to both build new fleets and upgrade any fleets we acquire to our preferred specifications, and our reliance on these vendors exposes us to risks including price and timing of delivery. 
+We currently utilize one preferred assembler and a limited number of suppliers for major equipment to both build our new fleets and upgrade any fleets we may acquire to our custom design. If demand for hydraulic fracturing fleets or the components necessary to build such fleets increases or these vendors face financial distress or bankruptcy, these vendors may not be able to provide the new or upgraded fleets on schedule or at the current price. If this were to occur, we could be required to seek another assembler or other suppliers for major equipment to build or upgrade our fleets, which may adversely affect our revenues or increase our costs. 
+Interruptions of service on the rail lines by which we receive proppant could adversely affect our results of operations. 
+We receive a portion of the proppant used in our hydraulic fracturing services by rail. Rail operations are subject to various risks that may result in a delay or lack of service, including lack of available capacity, mechanical problems, extreme weather conditions, work stoppages, labor strikes, terrorist attacks and operating hazards. Additionally, if we increase the amount of proppant we require for delivery of our services, we may face difficulty in securing rail transportation for such additional amount of proppant. Any delay or failure in the rail services on which we rely could have a material adverse effect on our financial condition and results of operations. 
+Changes in transportation regulations may increase our costs and negatively impact our results of operations. 
+We are subject to various transportation regulations including as a motor carrier by the DOT and by various federal, state and tribal agencies, whose regulations include certain permit requirements of highway and safety authorities. These regulatory authorities exercise broad powers over our equipment transportation operations, generally governing such matters as the authorization to engage in motor carrier operations, safety, equipment testing, driver requirements and specifications and insurance requirements. The trucking industry is subject to possible regulatory and legislative changes that may impact our operations, such as changes in fuel emissions limits, hours of service regulations that govern the amount of time a driver may 
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+drive or work in any specific period and requiring onboard electronic logging devices or limits on vehicle weight and size. As the federal government continues to develop and propose regulations relating to fuel quality, engine efficiency and greenhouse gasses emissions, we may experience an increase in costs related to truck purchases and maintenance, impairment of equipment productivity, a decrease in the residual value of vehicles, unpredictable fluctuations in fuel prices and an increase in operating expenses. Additionally, we rely on third parties to provide trucking services, including hauling proppant to our customer work sites, and these third parties may fail to comply with various transportation regulations, resulting in our inability to use such third party providers. Increased truck traffic may contribute to deteriorating road conditions in some areas where our operations are performed. Our operations, including routing and weight restrictions, could be affected by road construction, road repairs, detours and state and local regulations and ordinances restricting access to certain roads. Proposals to increase federal, state or local taxes, including taxes on motor fuels, are also made from time to time, and any such increase would increase our operating costs. Also, state and local regulation of permitted routes and times on specific roadways could adversely affect our operations. We cannot predict whether, or in what form, any legislative or regulatory changes or municipal ordinances applicable to our logistics operations will be enacted and to what extent any such legislation or regulations could increase our costs or otherwise adversely affect our business or operations. 
+Our current and future indebtedness could adversely affect our financial condition. 
+As of February 19, 2021, we had $108.2 million outstanding under our Term Loan Facility and no borrowings outstanding under our ABL Facility (defined herein) with a borrowing base of $130.7 million, except for a letter of credit in the amount of $0.8 million. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements.” 
+Moreover, subject to the limits contained in our ABL Facility and Term Loan Facility (collectively, the “Credit Facilities”), we may incur substantial additional debt from time to time. Any borrowings we may incur in the future would have several important consequences for our future operations, including that: 
+• covenants contained in the documents governing such indebtedness may require us to meet or maintain certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our industry, such as being able to take advantage of acquisition opportunities when they arise; 
+• our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes may be limited; 
+• we may be competitively disadvantaged to our competitors that are less leveraged or have greater access to capital resources; and 
+• we may be more vulnerable to adverse economic and industry conditions. 
+If we incur indebtedness in the future, we may have significant principal payments due at specified future dates under the documents governing such indebtedness. Our ability to meet such principal obligations will be dependent upon future performance, which in turn will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. Our business may not continue to generate sufficient cash flow from operations to repay any incurred indebtedness. If we are unable to generate sufficient cash flow from operations, we may be required to sell assets, to refinance all or a portion of such indebtedness or to obtain additional financing. 
+Unsatisfactory safety performance may negatively affect our customer relationships and, to the extent we fail to retain existing customers or attract new customers, adversely impact our revenues. 
+Our ability to retain existing customers and attract new business is dependent on many factors, including our ability to demonstrate that we can reliably and safely operate our business in a manner that is consistent with applicable laws, rules and permits, which legal requirements are subject to change. Existing and potential customers consider the safety record of their third-party service providers to be of high importance in their decision to engage such providers. If one or more accidents were to occur at one of our operating sites, the affected customer may seek to terminate or cancel its use of our equipment or services and may be less likely to continue to use our services, which could cause us to lose substantial revenues. Furthermore, our ability to attract new customers may be impaired if they elect not to engage us because they view our safety record as unacceptable. In addition, it is possible that we will experience multiple or particularly severe accidents in the future, causing our safety record to deteriorate. This may be more likely as we continue to grow, if we experience high employee turnover or labor shortage, or hire inexperienced personnel to bolster our staffing needs. 
+18 
+Table of Contents 
+If we are unable to fully protect our intellectual property rights, we may suffer a loss in our competitive advantage or market share. 
+We do not have patents or patent applications relating to many of our key processes and technology. If we are not able to maintain the confidentiality of our trade secrets, or if our competitors are able to replicate our technology or services, our competitive advantage would be diminished. We also cannot ensure that any patents we may obtain in the future would provide us with any significant commercial benefit or would allow us to prevent our competitors from employing comparable technologies or processes. 
+We may be adversely affected by disputes regarding intellectual property rights of third parties. 
+Third parties from time to time may initiate litigation against us by asserting that the conduct of our business infringes, misappropriates or otherwise violates intellectual property rights. We may not prevail in any such legal proceedings related to such claims, and our products and services may be found to infringe, impair, misappropriate, dilute or otherwise violate the intellectual property rights of others. If we are sued for infringement and lose, we could be required to pay substantial damages and/or be enjoined from using or selling the infringing products or technology. Any legal proceeding concerning intellectual property could be protracted and costly regardless of the merits of any claim and is inherently unpredictable and could have a material adverse effect on our financial condition, regardless of its outcome. 
+If we were to discover that our technologies or products infringe valid intellectual property rights of third parties, we may need to obtain licenses from these parties or substantially re-engineer our products in order to avoid infringement. We may not be able to obtain the necessary licenses on acceptable terms, or at all, or be able to re-engineer our products successfully. If our inability to obtain required licenses for our technologies or products prevents us from selling our products, that could adversely impact our financial condition and results of operations. 
+Additionally, we currently license certain third party intellectual property in connection with our business, and the loss of any such license could adversely impact our financial condition and results of operations. 
+Seasonal weather conditions, natural disasters, public health crises, and other catastrophic events outside of our control could severely disrupt normal operations and harm our business. 
+Our operations are located in different regions of the United States. Some of these areas, including the DJ Basin, Powder River Basin, Williston Basin and our Canadian operations, are adversely affected by seasonal weather conditions, primarily in the winter and spring. However, as evidenced by the severe winter weather experienced in the southern United States and Canada during February 2021, weather-related hazards can exist in almost all the areas where we operate. During periods of heavy snow, ice or rain, we may be unable to move our equipment between locations or obtain adequate supplies of raw material or fuel, thereby reducing our ability to provide services and generate revenues. The exploration activities of our customers may also be affected during such periods of adverse weather conditions. Additionally, extended drought conditions in our operating regions could impact our ability or our customers’ ability to source sufficient water or increase the cost for such water. As a result, a natural disaster or inclement weather conditions could severely disrupt the normal operation of our business and adversely impact our financial condition and results of operations. Furthermore, if the area in which we operate or the market demand for oil and natural gas is affected by a public health crises, such as the coronavirus, or other similar catastrophic event outside of our control, our business and results of operations could suffer. 
+19 
+Table of Contents 
+Item 1B. Unresolved Staff Comments 
+None. 
+Item 2. Properties 
+Information regarding our properties is contained in “Item 1. Business” and is incorporated by reference herein. 
+Item 3. Legal Proceedings 
+The information with respect to this Item 3. Legal Proceedings is set forth in Note 14—Commitments and Contingencies included in “Item 8. Financial Statements and Supplementary Data.” 
+Item 4. Mine Safety Disclosures 
+Information concerning mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this Form 10-K. 
+20 
+Table of Contents 
+PART II 
+Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+Market Information 
+On January 17, 2018, we consummated an initial public offering of our Class A Common Stock at a price of $17.00 per share. Our Class A Common Stock is traded on the NYSE under the symbol “LBRT.” Prior to that time, there was no public market for our Class A Common Stock. There is no public market for our Class B Common Stock. 
+Holders of our Common Stock 
+As of February 19, 2021, there were 33 stockholders of record of our Class A Common Stock and 8 stockholders of record of our Class B Common Stock. The number of record holders is based upon the actual number of holders registered on the books of the Company at such date and does not include holders of shares in “street names” or persons, partnerships, associations, corporations or other entities identified in security position listings maintained by depositories. 
+Dividend Policy 
+The Company paid quarterly cash dividends of $ 0.05 per share of Class A Common Stock on March 20, 2020 to shareholders of record as of March 6, 2020, respectively. The declaration of dividends is subject to approval by the Board and to the Board’s continuing determination that such declaration of dividends is in the best interests of the Company and its stockholders. Future dividends may be adjusted at the Board’s discretion based on market conditions and capital availability. We are not required to pay dividends, and our stockholders will not be guaranteed, or have contractual or other rights to receive, dividends. On April 2, 2020 the Company suspended future quarterly dividends until business conditions warrant reinstatement. 
+Recent Sales of Unregistered Equity Securities 
+We had no sales of unregistered equity securities during the period covered by this Annual Report that were not previously reported in a Current Report on Form 8-K. 
+Purchase of Equity Securities By the Issuer and Affiliated Purchasers 
+On September 10, 2018 the Board authorized a share repurchase plan to repurchase up to $ 100.0 million of the Company’s Class A Common Stock through September 30, 2019. On January 22, 2019, the Board authorized an additional $ 100.0 million under the share repurchase plan through January 31, 2021. During the year ended December 31, 2020, the Company did not purchase any shares of Class A Common Stock. 
+As of December 31, 2020, $ 98.7 million remained authorized for future repurchases of Class A Common Stock under the share repurchase program, however effective February 1, 2021, no amounts are authorized for future repurchases. 
+Stock Performance Graph 
+The following graph and table compares the cumulative total return on our Class A Common Stock with the cumulative total return on the Standard & Poor’s 500 ® Index and the Philadelphia Oil Service Index, since January 12, 2018, the first day on which shares of our Common Stock issued in our IPO commenced trading on the NYSE and each semi-annual period thereafter through December 31, 2020. The graph assumes that $100 was invested in our Class A Common Stock in each index on January 12, 2018 and that any dividends were reinvested on the last day of the month in which they were paid. The cumulative total return set forth is not necessarily indicative of future performance. 
+The following graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that we specifically incorporate it by reference into such filing. 
+21 
+Table of Contents 
+For Year Ended 2018 For the Year Ended 2019 For the Year Ended 2020 
+January 
+12, June 
+30, December 
+31, June 
+30, December 
+31, June 
+30, December 
+31, 
+Liberty Oilfield Services, Inc. $ 100.00 $ 83.87 $ 58.38 $ 73.40 $ 50.91 $ 25.55 $ 48.08 
+Standard & Poor’s 500 ® Index 100.00 97.97 91.03 108.02 119.66 115.59 141.70 
+Philadelphia Oil Service Index 100.00 95.91 49.91 50.37 48.48 20.67 27.45 
+22 
+Table of Contents 
+Item 6. Selected Consolidated Financial Data 
+The selected financial data set forth below was derived from our audited consolidated and combined financial statements and should be read in conjunction with “Item 1A. Risk Factors,” “Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations” and our audited consolidated and combined financial statements included in “Item 8. Financial Statements and Supplementary Data.” 
+Years Ended 
+December 31, 
+2020 2019 2018 2017 2016 
+(in thousands, except per share and fleet data) 
+Statement of Operations Data: 
+Revenue: 
+Revenue $ 965,787 $ 1,972,073 $ 2,132,032 $ 1,465,133 $ 356,890 
+Revenue—related parties — 18,273 23,104 24,722 17,883 
+Total revenue 965,787 1,990,346 2,155,136 1,489,855 374,773 
+Operating costs and expenses: 
+Cost of services (exclusive of depreciation and amortization shown separately below) 857,981 1,621,180 1,628,753 1,147,008 354,729 
+General and administrative 84,098 97,589 98,420 80,089 35,789 
+Transaction, severance and other costs 21,061 — 632 — — 
+Depreciation and amortization of intangible assets 180,084 165,379 125,110 81,473 41,362 
+(Gain) loss on disposal of assets (411) 2,601 (4,342) 148 (2,673) 
+Total operating costs and expenses 1,142,813 1,886,749 1,848,573 1,308,718 429,207 
+Operating (loss) income (177,026) 103,597 306,563 181,137 (54,434) 
+Interest expense, net 14,505 14,681 17,145 12,636 6,126 
+Net (loss) income before income taxes (191,531) 88,916 289,418 168,501 (60,560) 
+Income tax (benefit) expense (30,857) 14,052 40,385 — — 
+Net (loss) income (160,674) 74,864 249,033 168,501 (60,560) 
+Less: Net income (loss) attributable to Predecessor, prior to Corporate Reorganization — — 8,705 168,501 (60,560) 
+Less: Net (loss) income attributable to non-controlling interests (45,091) 35,861 113,979 — — 
+Net (loss) income attributable to Liberty Oilfield Services Inc. stockholders $ (115,583) $ 39,003 $ 126,349 $ — $ — 
+Net Income Per Share Data (1): 
+Net (loss) income attributable to Liberty Oilfield Services Inc. stockholders per common share 
+Basic $ (1.36) $ 0.54 1.84 
+Diluted $ (1.36) $ 0.53 1.81 
+Weighted average common shares outstanding 
+Basic 85,242 72,334 68,838 
+Diluted (2) 85,242 105,256 117,838 
+Statement of Cash Flows Data: 
+Cash flows provided by (used in) operating activities $ 85,425 $ 261,100 $ 351,258 $ 195,109 $ (40,708) 
+Cash flows used in investing activities (100,269) (194,347) (255,492) (310,043) (96,351) 
+Cash flows (used in) provided by financing activities (28,868) (57,375) (8,775) 119,771 148,543 
+Other Financial Data: 
+Capital expenditures $ 103,637 $ 195,173 $ 258,835 $ 311,794 $ 102,428 
+EBITDA (3) $ 3,058 $ 268,976 $ 431,673 $ 262,610 $ (13,072) 
+Adjusted EBITDA (3) $ 57,899 $ 290,741 $ 443,684 $ 280,728 $ (5,588) 
+Average Active Fleets (4) 13.2 22.8 21.3 15.1 7.4 
+Adjusted EBITDA per Average Active Fleet (5) $ 4,386 $ 12,752 $ 20,830 $ 18,591 $ (755) 
+Balance Sheet Data (at end of period): 
+Total assets $ 1,889,942 $ 1,283,429 $ 1,116,501 $ 852,103 $ 451,845 
+Long-term debt (including current portion) 105,775 106,140 106,524 196,357 103,805 
+Total liabilities 579,899 501,937 375,687 416,851 222,873 
+Redeemable common units (6) — — — 42,486 — 
+Total equity or member equity 1,310,043 781,492 740,814 392,766 228,972 
+23 
+Table of Contents 
+(1) Net Income Per Share Data above reflects the net income to Class A Common Stock and net income per share for the period indicated based on a weighted average number of Class A Common Stock outstanding for period subsequent to the Corporate Reorganization on January 17, 2018. 
+(2) In accordance with generally accepted accounting principals in the United States (“GAAP”), diluted weighted average common shares outstanding for the year ended December 31, 2020, diluted weighted average common shares outstanding exclude 27,427 weighted average shares of Class B Common Stock, 207 weighted average shares of restricted stock, and 2,460 weighted average shares of restricted stock units. For the year ended December 31, 2019, excludes 9,057 weighted average shares of Class B Common Stock exchanged during the period (share counts presented in 000’s). 
+(3) EBITDA and Adjusted EBITDA are non-GAAP financial measures. For definitions of EBITDA and Adjusted EBITDA and a reconciliation of each to our most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Item 7. Management's Discussion and Analysis of Financial Conditions and Results of Operations—Comparison of Non-GAAP Financial Measures.” 
+(4) Average Active Fleets is calculated as the daily average of the active fleets for the period presented. 
+(5) Adjusted EBITDA per Average Active Fleet is calculated as Adjusted EBITDA for the period divided by the Average Active Fleets, as defined above. 
+(6) The redeemable common units were deemed extinguished and satisfied in full in the Corporate Reorganization. 
+24 
+Table of Contents 
+Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Item 6. Selected Financial Data” and our audited consolidated and combined financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a variety of risks and uncertainties, including those described in this Annual Report on Form 10-K under “Cautionary Note Regarding Forward-Looking Statements” and “Item 1A. Risk Factors.” We assume no obligation to update any of these forward-looking statements. This section of this Annual Report on Form 10-K generally discusses 2020 and 2019 items and year-to-year comparisons between 2020 and 2019. For discussion of year ended December 31, 2018, as well as the year ended 2019 compared to the year ended December 31, 2018, refer to Part II, Item 7— “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2019 Annual Report on Form 10-K. 
+Overview 
+We are an independent provider of hydraulic fracturing services and goods to onshore oil and natural gas E&P companies in North America. 
+We have grown from one active hydraulic fracturing fleet in December 2011 to approximately 30 active fleets in the first quarter of 2021, including the addition of fleets from the OneStim Acquisition in December 2020. We are an independent provider of hydraulic fracturing and wireline services and related goods to onshore oil and natural gas exploration and production (“E&P”) companies in North America. We provide our services primarily in the Permian Basin, the Eagle Ford Shale, the Denver-Julesburg Basin (the “DJ Basin”), the Williston Basin, the San Juan Basin and the Powder River Basin. Following the completion of the OneStim Acquisition (as defined below) we now also provide services in the Haynesville Shale, the SCOOP/STACK, the Marcellus Shale, Utica Shale, and the Western Canadian Sedimentary Basin. Additionally, we operate two sand mines in the Permian Basin. 
+In response to market conditions described below, in April 2020, we reduced our headcount consistent with the temporary idling of approximately half of our frac fleets that were operating during the first quarter of 2020, while further temporary reductions in active fleets were managed through employee furloughs. As of December 31, 2020, no employees remained on furlough, and with the completion of the OneStim Acquisition we had a total of approximately 30 active frac fleets and 20 active wireline units. 
+On December 31, 2020, the Company acquired certain assets and liabilities of Schlumberger Limited’s (“Schlumberger”) OneStim® business, which provides hydraulic fracturing pressure pumping services in onshore United States and Canada, including its pressure pumping, pumpdown perforating and Permian frac sand business (such entire business of Schlumberger, “OneStim,” and the portion of OneStim acquired pursuant by the Company, the “Transferred Business”) in exchange for consideration resulting in a total of 66,326,134 shares of Class A common stock, par value $0.01 per share, of the Company (the “Class A Common Stock”) being issued in connection with the transaction (such transaction, the “OneStim Acquisition”; see Note 3—The OneStim Acquisition to the consolidated and combined financial statements included in “Item 8. Financial Statements and Supplementary Data”). Effective December 31, 2020, Schlumberger owned 37% of the issued and outstanding shares of our Common Stock. The combined company will deliver best-in-class completion services for the sustainable development of unconventional resource plays in the United States and Canada onshore markets. 
+We believe the following characteristics both distinguish us from our competitors and are the foundations of our business: forming ongoing partnerships of trust and innovation with our customers; developing and utilizing technology to maximize well performance; and promoting a people-centered culture focused on our employees, customers and suppliers. We have developed strong relationships with our customers by investing significant time in fracture design collaboration, which substantially enhances their production economics. Our technological innovations have become even more critical as E&P companies have increased the completion complexity and fracture intensity of horizontal wells. We are proactive in developing innovative solutions to industry challenges, including developing: (i) our proprietary databases of U.S. unconventional wells to which we apply our proprietary multi-variable statistical analysis technologies to provide differential insight into fracture design optimization; (ii) our Liberty Quiet Fleet® design which significantly reduces noise levels compared to conventional hydraulic fracturing fleets; (iii) hydraulic fracturing fluid systems tailored to the specific reservoir properties in the basins in which we operate; and (iv) our dual fuel dynamic gas blending fleets that allow our engines to run diesel or a combination of diesel and natural gas, to optimize fuel use, reduce emissions and lower costs. We foster a people-centered culture built around honoring our commitments to customers, partnering with our suppliers and hiring, training and retaining people that we believe to be the best talent in our field to drive innovation, enabling us to be one of the safest and most efficient hydraulic fracturing companies in the United States. 
+25 
+Table of Contents 
+Recent Trends and Outlook 
+During the first quarter of 2020, the emergence of the COVID-19 pandemic placed significant downward pressure on the global economy and oil demand and prices, leading North America operators to announce significant cuts to planned 2020 capital expenditures. Reduced activity levels led to a plunging rig count and an abrupt curtailment of frac activity. As a result, OPEC, coupled with production curtailment and a drop in frac activity amongst North America operators, removed significant oil supply from and eased pressure on the market. During the second half of 2020, OPEC+ suppliers worked to maintain oil production through an agreed upon quota, and North America operators largely remained disciplined in capital spending. Many operators have announced that they are targeting oil and gas production at the end of 2021 to be consistent with production at the end of 2020. 
+Early signs of a potential global economic recovery have emerged, driven by the rollout of COVID-19 vaccines, fiscal and monetary stimulus policies, and pent-up demand for goods and services. These factors support continued improvement in energy demand, while controlled OPEC+ production and discipline amongst E&P operators are supporting oil and gas prices. WTI prices that have largely stabilized in the second half of 2020, relative to the volatility observed during the second quarter of 2020. In the fourth quarter of 2020, the price of WTI averaged $42.52 compared with an average of $40.89 for the third quarter of 2020, which was much improved from an average of $27.96 for the second quarter of 2020. Subsequent to December 31, 2020, the price of WTI has averaged $53.93 through February 16, 2021. The recovery of energy demand is also reflected in incremental improvement to rig count, as the most recent domestic onshore rig count for North America was 381 rigs reported on February 19, 2021, up from the average in the fourth quarter of 2020 of 297, according to a report by Baker Hughes, a GE company. 
+The number of total marketable frac fleets has declined significantly from 2019 as the pandemic accelerated the pace of rationalization and cannibalization of frac equipment. As customer demand is shifting towards next generation technologies that support their emissions and efficiency goals, attrition of older equipment is expected to continue. This supply shrinkage is a necessary part of moving the market towards balance. The current pricing dynamic remains challenging, but the Company is having many productive discussions with customers to phase in modest price improvements throughout the year. The Company was proactive in working with customers as oil prices collapsed, and that partnership works both ways. 
+With continued uncertainty surrounding the magnitude and timing of oil demand recovery, OPEC+ supply concerns, and ongoing investor pressure for better returns by E&P companies than those achieved over the last decade, we are unable to predict the degree and duration of many factors that may impact our future operating results. The volatile global economic conditions stemming from the pandemic, the liquidity situation for North American oil producers and the reaction of international oil producers could also exacerbate the risk factors identified in this Annual Report, see also the risk factor relating to COVID-19 disclosed in “Item 1A.–Risk Factors” of this Annual Report. 
+In response to these developments, the continued duration and ultimate severity of which is unknown, we have taken the following steps to protect our employees, customers and business. During February 2020, we formed a COVID-19 response team to implement safety procedures and contingency plans at both our customer locations and in our facilities to ensure our ability to continue providing safe and efficient services to our customers, while protecting the health of both employees and customers. 
+We have been proactive in protecting our business during these unprecedented events. During the second quarter, we moved quickly to preserve cash and protect our balance sheet and announced strategic actions to align our cost structure with demand for frac services. Regrettably, for the first time in the Company’s history we undertook a reduction of our personnel and staffed fleet count by approximately 50% and implemented a company-wide furlough plan. We also suspended variable compensation plans and our 401(k) match, implemented base salary reductions, executive and director compensation reductions, operating cost rationalization, reduction of planned 2020 capital expenditures, and suspended our quarterly dividend. Further, we implemented a company-wide employee furlough plan that flexes our cost structure to align with the uncertain level of frac demand we experienced during the second and third quarters of 2020. As of September 30, 2020 all employees were returned from furlough, additionally, effective January 1, 2021 the Company restored 401(k) match and base salaries. 
+E&P operators are navigating through significant challenges, including industry consolidation, a change in the political climate and capital constraints while maintaining general commitments to flat production with 2021 levels relative to 2020 exit rates. Dedicated fleet negotiations for 2021, which started in the fall of 2020, saw continued pricing pressure. However, WTI crude oil prices have improved since the fall bid season. 
+We believe the frac market will probably experience flat to slightly rising demand for frac services in 2021, based on current visibility into customer plans. Demand of publicly-traded operators is expected to be relatively level during the year, whereas private operator demand is more likely to be focused on the second half of the year. Against this backdrop, the Company expects to maintain approximately 30 active frac fleets in the first quarter of 2021, with the potential of adding more 
+26 
+Table of Contents 
+fleets later in the year if the economics improve. Increased efficiencies that lower our cost of delivery coupled with a gradual, modest rise in frac pricing are the factors that can drive improved fleet profitability. 
+Increase in Drilling Efficiency and Service Intensity of Completions 
+Over the past decade, E&P companies have focused on exploiting the vast resource potential available across many of North America’s unconventional resource plays through the application of horizontal drilling and completion technologies, including the use of multi-stage hydraulic fracturing, in order to increase recovery of oil and natural gas. As E&P companies have improved drilling and completion techniques to maximize return and efficiency, we believe that their “break-even oil prices” continue to decline. These improvements in well economics have kept American Shale oil and gas production competitive even as oil and gas prices have declined. Liberty has been a significant partner with our customers in driving these continued improvements. 
+Improved drilling economics from horizontal drilling and greater rig efficiencies . Unconventional resources are increasingly being targeted through the use of horizontal drilling. According to Baker Hughes, as reported on February 19, 2021, horizontal rigs accounted for approximately 90% of all rigs drilling in the United States, up from 74% as of December 31, 2014. Over the past several years, North American E&P companies have benefited from improved drilling economics driven by technologies that reduce the number of days, and the cost, of drilling wells. North American drilling rigs have incorporated newer technologies, which allow them to drill rock more effectively and quickly, meaning each rig can drill more wells in a given period. These include improved drilling technologies and the incorporation of geosteering techniques which allow better placement of the wellbore. Drilling rigs have also incorporated new technology which allows fully-assembled rigs to automatically “walk” from one location to the next without disassembling and reassembling the rig, greatly reducing the time it takes to move from one drilling location to the next. Today the majority of E&P drilling is on multi-well pad development, allowing efficient drilling of multiple horizontal wellbores from the same pad or location. The aggregate effect of these improved techniques and technologies have reduced the average days required to drill a well, which according to Coras, has dropped from 28 days in 2014 to 20 days in 2020. 
+Increased complexity and service intensity of horizontal well completions . In addition to improved rig efficiencies discussed above, E&P companies are also improving the subsurface techniques and technologies used to exploit unconventional resources. These improvements have targeted increasing the exposure of each wellbore to the reservoir by drilling longer horizontal lateral sections of the wellbore. To complete the well, hydraulic fracturing is applied in stages along the wellbore to break-up the resource so that oil and gas can be produced. As wellbores have increased in length, the number of frac stages and/or the number of perf clusters (frac initiation points) has also increased. Further, E&P companies have improved production from each stage by applying increasing amounts of proppant in each stage, which better connects the well to the resource. The aggregate effect of increased number of stages and the increasing amount of proppant in each stage has greatly increased the total amount of proppant used in each well, according to Coras, from six million pounds per well in 2014 to over 16 million pounds per well in 2020. Further efficiency gains are being sought via the “simul-frac” technique. Utilizing a larger frac fleet (1.25x to 2x the normal horsepower), operators are fracturing stages in two separate wells on a pad simultaneously as a single operation. When compared to typical zipper-frac operations, this new method allows for more lateral feet to be completed in a day. This emerging trend will allow operators to complete a pad of wells quicker, thereby shortening the time from spud to first production. 
+These industry trends continue to keep our customers as important suppliers to the global oil and natural gas markets, which directly benefit hydraulic fracturing companies like us that have the expertise and technological innovations to effectively service today’s more efficient oilfield drilling activity and the increasing complexity and intensity of well completions. Given the expected returns that E&P companies have reported for new well development activities due to improved rig efficiencies and increasing well completion complexity and intensity, we expect these industry trends to continue. 
+How We Generate Revenue 
+We currently generate revenue through the provision of hydraulic fracturing and wireline services and goods, including sand from our Permian Basin sand mines. These services and goods are performed under a variety of contract structures, primarily master service agreements (“MSAs”) as supplemented by statements of work, pricing agreements and specific quotes. A portion of our statements of work, under MSAs, include provisions that establish pricing arrangements for a period of up to one year in length. However, the majority of those agreements provide for pricing adjustments based on market conditions. The majority of our services are priced based on prevailing market conditions and changing input costs at the time the services are provided, giving consideration to the specific requirements of the customer. 
+Our hydraulic fracturing and wireline services are performed in sections, which we refer to as fracturing stages. The estimated number of fracturing stages to be completed for a particular horizontal well is determined by the customer’s well completion design. We recognize revenue for each fracturing stage completed, although our revenue per completed fracturing 
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+Table of Contents 
+stage varies depending on the actual volumes and types of proppants, chemicals and fluid utilized for each fracturing stage. The number of fracturing stages that we are able to complete in a period is directly related to the number and utilization of our deployed fleets and size of stages. 
+Costs of Conducting Our Business 
+The principal expenses involved in conducting our business are direct cost of personnel, services and materials used in the provision of services, general and administrative expenses, and depreciation and amortization. A large portion of the costs we incur in our business are variable based on the number of hydraulic fracturing jobs and the requirements of services provided to our customers. We manage the level of our fixed costs, except depreciation and amortization, based on several factors, including industry conditions and expected demand for our services. 
+How We Evaluate Our Operations 
+We use a variety of qualitative, operational and financial metrics to assess our performance. First and foremost of these is a qualitative assessment of customer satisfaction because ensuring we are a valuable partner to our customers is the key to achieving our quantitative business metrics. Among other measures, management considers each of the following: 
+• Revenue; 
+• Operating Income; 
+• EBITDA; 
+• Adjusted EBITDA; 
+• Annualized Adjusted EBITDA per Average Active Fleet; 
+• Net Income Before Taxes; and 
+• Earnings per Share. 
+Revenue 
+We analyze our revenue by comparing actual monthly revenue to our internal projections for a given period and to prior periods to assess our performance. We also assess our revenue in relation to the number of fleets we have deployed (revenue per average active fleet) from period to period. 
+Operating Income 
+We analyze our operating income, which we define as revenues less direct operating expenses, depreciation and amortization and general and administrative expenses, to measure our financial performance. We believe operating income is a meaningful metric because it provides insight on profitability and true operating performance based on the historical cost basis of our assets. We also compare operating income to our internal projections for a given period and to prior periods. 
+EBITDA and Adjusted EBITDA 
+We view EBITDA and Adjusted EBITDA as important indicators of performance. We define EBITDA as net income (loss) before interest, income taxes, depreciation and amortization. We define Adjusted EBITDA as EBITDA adjusted to eliminate the effects of items such as non-cash stock based compensation expense, new fleet or new basin start-up costs, fleet lay-down costs, costs of asset acquisition, gain or loss on the disposal of assets, asset impairment charges, bad debt reserves, and non-recurring expenses that management does not consider in assessing ongoing operating performance. Annualized Adjusted EBITDA per Average Active Fleet is calculated as Adjusted EBITDA annualized, divided by the Average Active Fleets for the same period. See “—Comparison of Non-GAAP Financial Measures” for more information and a reconciliation of EBITDA and Adjusted EBITDA to net income, the most directly comparable financial measure calculated and presented in accordance with GAAP. 
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+Table of Contents 
+Results of Operations 
+Year Ended December 31, 2020, Compared to Year Ended December 31, 2019 
+Years Ended December 31, 
+Description 2020 2019 Change 
+(in thousands) 
+Revenue $ 965,787 $ 1,990,346 $ (1,024,559) 
+Cost of services, excluding depreciation and amortization shown separately 857,981 1,621,180 (763,199) 
+General and administrative 84,098 97,589 (13,491) 
+Transaction, severance and other costs 21,061 — 21,061 
+Depreciation and amortization of intangible assets 180,084 165,379 14,705 
+(Gain) loss on disposal of assets (411) 2,601 (3,012) 
+Operating (loss) income (177,026) 103,597 (280,623) 
+Interest expense, net 14,505 14,681 (176) 
+Net (loss) income before taxes (191,531) 88,916 (280,447) 
+Income tax (benefit) expense (30,857) 14,052 (44,909) 
+Net (loss) income (160,674) 74,864 (235,538) 
+Less: Net (loss) income attributable to non-controlling interests (45,091) 35,861 (80,952) 
+Net (loss) income attributable to Liberty Oilfield Services Inc. stockholders $ (115,583) $ 39,003 $ (154,586) 
+Revenue 
+Our revenue decreased $1.0 billion, or 51.5%, to $965.8 million for the year ended December 31, 2020 compared to $2.0 billion for the year ended December 31, 2019. Average active fleets decreased 42.1% to 13.2 from 22.8 average active fleets deployed during the year ended December 31, 2020 and 2019, respectively, as the Company reduced the staffed fleets in April 2020 in response to market conditions, as discussed in “Recent Trends and Outlook” above. Further, revenue per average active fleet decreased 16.2% to $73.2 million for the year ended December 31, 2020 compared to $87.3 million for the year ended December 31, 2019, attributable to lower demand for frac services in the market as previously discussed. 
+Cost of Services 
+Cost of services (excluding depreciation and amortization) decreased $763.2 million, or 47.1%, to $858.0 million for the year ended December 31, 2020 compared to $1.6 billion for the year ended December 31, 2019. The lower expense was primarily related to the reduced levels of activity from fewer average active fleets deployed during 2020, as described above, and to a lesser extent from cost-cutting measures related to personnel costs enacted during 2020 including reduction in headcount and furloughs, as well as a temporary suspension of bonus and 401(k) match programs. 
+General and Administrative Expenses 
+General and administrative expenses decreased by $13.5 million, or 13.8%, to $84.1 million for the year ended December 31, 2020 compared to $97.6 million for the year ended December 31, 2019 primarily related to a decrease in personnel costs, excluding share based compensation, of $15.1 million due to the reduction in headcount, furlough and flexible cost structure, as well as the temporary suspension of bonus and 401(k) match programs. Partially offsetting this decrease, general and administrative expense included $12.9 million of share based compensation expense during the year ended December 31, 2020 compared to $9.2 million for the year ended December 31, 2019. 
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+Transaction, Severance and Other Costs 
+Transaction costs were $ 8.5 million for the year ended December 31, 2020 compared to $0 for the year ended December 31, 2019. Such costs were incurred in connection with the OneStim Acquisition and included investment banking, legal, accounting and other professional services provided in connection with closing the transaction. 
+Severance and other costs were $12.6 million for the year ended December 31, 2020 compared to $0 for the year ended December 31, 2019. The costs were primarily related to the reduction in our workforce in April 2020 and the commencement of furlough schedules for remaining employees in May 2020 during which the Company continued to pay insurance and other benefits. The Company did not lay-off or furlough any employees during 2019. 
+Depreciation and Amortization of Intangible Assets 
+Depreciation and amortization of intangible assets expense increased $14.7 million, or 8.9%, to $180.1 million for the year ended December 31, 2020 compared to $165.4 million for the year ended December 31, 2019. The increase in 2020 was due to a full year of depreciation for one fleet deployed during 2019, as well as one additional fleet deployed during early 2020. 
+(Gain) Loss on Disposal of Assets 
+(Gain) loss on disposal of assets increased $3.0 million to a gain of $0.4 million for the year ended December 31, 2020 compared to a loss of $2.6 million for the year ended December 31, 2019. During 2020, we reduced the number of light duty pick-ups in our fleet based on our lower levels of activity and realized gains upon sale commensurate with lease terminations. 
+Operating (Loss) Income 
+We realized an operating loss of $177.0 million for the year ended December 31, 2020 compared to operating income of $103.6 million for the year ended December 31, 2019. The decrease is primarily due to the $1.0 billion, or 51.5%, decrease in total revenue only partially offset by a $743.9 million decrease in total operating expenses, the significant components of which are discussed above. The decline in operating income was significantly impacted by reduced customer work as a result of the COVID-19 pandemic and steep decline in oil prices in March and April 2020. 
+Interest Expense, net 
+The decrease in interest expense, net of $0.2 million, or 1.2%, to $14.5 million during the year ended December 31, 2020 compared to $14.7 million during the year ended December 31, 2019, was due to lower interest expense on credit facilities and from finance leases, largely offset by reduced interest income from excess cash on hand. 
+Net (Loss) Income Before Taxes 
+We realized a net loss before taxes of $191.5 million for the year ended December 31, 2020 compared to net income before taxes of $88.9 million for the year ended December 31, 2019. The decrease is primarily attributable to a decrease in revenue, as discussed above, related to the decrease in pricing and activity. 
+Income Tax (Benefit) Expense 
+We recognized a tax benefit of $30.9 million for the year ended December 31, 2020, an effective rate of 16.1 %, compared to expense of $14.1 million for the year ended December 31, 2019, an effective rate of 15.8%. The decrease in tax expense is primarily attributable to a decrease in revenue, as discussed above, related to the decrease in pricing and activity. 
+Comparison of Non-GAAP Financial Measures 
+We view EBITDA and Adjusted EBITDA as important indicators of performance. We define EBITDA as net income before interest, income taxes, depreciation and amortization. We define Adjusted EBITDA as EBITDA adjusted to eliminate the effects of items such as non-cash stock based compensation, new fleet or new basin start-up costs, fleet lay-down costs, costs of asset acquisitions, gain or loss on the disposal of assets, asset impairment charges, bad debt reserves and non-recurring expenses that management does not consider in assessing ongoing performance. 
+Our Board, management, investors and lenders use EBITDA and Adjusted EBITDA to assess our financial performance because it allows them to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure (such as varying levels of interest expense), asset base (such as depreciation and amortization) and other items that impact the comparability of financial results from period to period. We present EBITDA and Adjusted EBITDA because we believe they provide useful information regarding the factors and trends affecting our business in addition to measures calculated under GAAP. 
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+Note Regarding Non-GAAP Financial Measures 
+EBITDA and Adjusted EBITDA are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures will provide useful information to investors in assessing our financial performance and results of operations. Net income (loss) is the GAAP measure most directly comparable to EBITDA and Adjusted EBITDA. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as an analytical tool due to exclusion of some but not all items that affect the most directly comparable GAAP financial measures. You should not consider EBITDA or Adjusted EBITDA in isolation or as substitutes for an analysis of our results as reported under GAAP. Because EBITDA and Adjusted EBITDA may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. 
+The following tables present a reconciliation of EBITDA and Adjusted EBITDA to our net income, which is the most directly comparable GAAP measure for the periods presented: 
+Year Ended December 31, 2020 Compared to Year Ended December 31, 2019: EBITDA and Adjusted EBITDA 
+Years Ended December 31, 
+Description 2020 2019 Change 
+(in thousands) 
+Net (loss) income $ (160,674) $ 74,864 $ (235,538) 
+Depreciation and amortization 180,084 165,379 14,705 
+Interest expense, net 14,505 14,681 (176) 
+Income tax (benefit) expense (30,857) 14,052 (44,909) 
+EBITDA $ 3,058 $ 268,976 $ (265,918) 
+Stock based compensation expense 17,139 13,592 3,547 
+Fleet start-up and lay-down costs 12,175 4,519 7,656 
+Asset acquisition costs 8,497 — 8,497 
+(Gain) loss on disposal of assets (411) 2,601 (3,012) 
+Provision for credit losses 4,877 1,053 3,824 
+Non-recurring payroll expense 2,398 — 2,398 
+Severance and related costs 10,166 — 10,166 
+Adjusted EBITDA $ 57,899 $ 290,741 $ (232,842) 
+EBITDA was $3.1 million for the year ended December 31, 2020 compared to $269.0 million for the year ended December 31, 2019. Adjusted EBITDA was $57.9 million for the year ended December 31, 2020 compared to $290.7 million for the year ended December 31, 2019. The decreases in EBITDA and Adjusted EBITDA resulted from the decreased revenue and other factors described above under the captions Revenue , Cost of Services, and General and Administrative Expenses for Year Ended December 31, 2020, Compared to Year Ended December 31, 2019 . 
+Liquidity and Capital Resources 
+Overview 
+Historically, our primary sources of liquidity to date have been cash flows from operations, proceeds from our IPO, and borrowings under our Credit Facilities. We expect to fund operations and organic growth with cash flows from operations and available borrowings under our Credit Facilities. We may incur additional indebtedness or issue equity in order to fund growth opportunities that we pursue via acquisition, such as with the OneStim Acquisition. Our primary uses of capital have been capital expenditures to support organic growth and funding ongoing operations, including maintenance and fleet upgrades. 
+Cash and cash equivalent s decreased by $43.7 million to $69.0 million as of December 31, 2020 compared to $112.7 million as of December 31, 2019. We believe that cash on hand, our operating cash flows and available borrowings under our Credit Facilities will be sufficient to fund our operations for at least the next twelve months. 
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+Cash Flows 
+The following table summarizes our cash flows for the periods indicated: 
+Years Ended December 31, 
+Description 2020 2019 Change 
+(in thousands) 
+Net cash provided by operating activities $ 85,425 $ 261,100 $ (175,675) 
+Net cash used in investing activities (100,269) (194,347) 94,078 
+Net cash used in financing activities (28,868) (57,375) 28,507 
+Net increase in cash and cash equivalents $ (43,712) $ 9,378 $ (53,090) 
+Analysis of Cash Flow Changes Between the Years Ended December 31, 2020 and December 31, 2019 
+Operating Activities . Net cash provided by operating activities was $85.4 million for the year ended December 31, 2020, compared to net cash provided by operating activities of $261.1 million for the year ended December 31, 2019. The $175.7 million decrease in cash from operating activities was primarily attributable to a $1.0 billion decrease in revenues, offset by a $743.9 million decrease in operating expenses and a $63.3 million increase in cash from changes in working capital for the year ended December 31, 2020, compared to a $21.6 million decrease in cash from changes in working capital for the year ended December 31, 2019. 
+Investing Activities . Net cash used in investing activities was $100.3 million for the year ended December 31, 2020, compared to $194.3 million for the year ended December 31, 2019. The $94.1 million decrease in net cash used in investing activities is attributable to a decrease in capital expenditures in an effort to reduce spending and as a result of the lower fleet count in 2020. 
+Financing Activities . Net cash used in financing activities was $28.9 million for the year ended December 31, 2020, compared to $57.4 million for the year ended December 31, 2019. The $28.5 million decrease in cash used in financing activities was primarily due to an $18.4 million decrease in share repurchases and a $16.6 million reduction in dividends and per unit distributions to non-controlling interest unitholders as a result of the suspension of the dividend in April 2020. Partially offsetting the decreases was a $6.8 million increase in cash used in financing activities as a result of payments made to non-controlling interest unitholders under the TRAs as a result of the 2020 refund of a portion of cash taxes paid in 2018. 
+Debt Agreements 
+On September 19, 2017, the Company entered into two new credit agreements for a revolving line of credit up to $250.0 million (the “ABL Facility”) and a $175.0 million term loan (the “Term Loan Facility”, and together with the ABL Facility the “Credit Facilities”). Following is a description of the ABL Facility and the Term Loan Facility. 
+ABL Facility 
+Under the terms of the ABL Facility, up to $250.0 million may be borrowed, subject to certain borrowing base limitations based on a percentage of eligible accounts receivable and inventory. On May 29, 2020 the Company amended the ABL Facility to allow accounts receivables that are more than 90 but less than 120 days past their original invoice date to be included in the determination of eligible accounts receivables, up to a limit of $ 37.5 million when combined with receivable that are more than 60 but less than 90 days past their due date to be included in the borrowing base. The expanded borrowing base terms were in effect from May 1, 2020 through December 31, 2020. 
+As of December 31, 2020, the borrowing base was calculated to be $115.1 million, and the Company had no borrowings outstanding, except for a letter of credit in the amount of $0.8 million, with $114.3 million of remaining availability. Borrowings under the ABL Facility bear interest at the London InterBank Offered Rate (“LIBOR”) or a base rate, plus an applicable LIBOR margin of 1.5% to 2.0% or base rate margin of 0.5% to 1.0%, as defined in the ABL Facility credit agreement. The unused commitment is subject to an unused commitment fee of 0.375% to 0.5%. Interest and fees are payable in arrears at the end of each month, or, in the case of LIBOR loans, at the end of each interest period. The ABL Facility matures on the earlier of (i) September 19, 2022 and (ii) to the extent the debt under the Term Loan Facility remains outstanding, 90 days prior to the final maturity of the Term Loan Facility, which matures on September 19, 2022. Borrowings under the ABL Facility are collateralized by accounts receivable and inventory, and further secured by the Company, Liberty LLC and R/C IV Non-U.S. LOS Corp., a Delaware corporation (“R/C IV”) and a subsidiary of the Company, as parent guarantors. 
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+Term Loan Facility 
+The Term Loan Facility provides for a $175.0 million term loan, of which $108.2 million remained outstanding as of December 31, 2020. Amounts outstanding bear interest at LIBOR or a base rate, plus an applicable margin of 7.625% or 6.625%, respectively, and the weighted average rate on borrowings was 8.6% as of December 31, 2020. The Company is required to make quarterly principal payments of 1% per annum of the initial principal balance, commencing on December 31, 2017, with final payment due at maturity on September 19, 2022. The Term Loan Facility is collateralized by the fixed assets of LOS and its subsidiaries, and is further secured by the Company, Liberty LLC and R/C IV, as parent guarantors. 
+The Credit Facilities include certain non-financial covenants, including but not limited to restrictions on incurring additional debt and certain distributions. Moreover, the ability of the Company to incur additional debt and to make distributions is dependent on maintaining a maximum leverage ratio. The Term Loan Facility requires mandatory prepayments upon certain dispositions of property or issuance of other indebtedness, as defined, and annually a percentage of excess cash flow (25% to 50%, depending on leverage ratio, of consolidated net income less capital expenditures and other permitted payments, commencing with the year ending December 31, 2018). Certain mandatory prepayments and optional prepayments are subject to a prepayment premium of 3% of the prepaid principal declining annually to 1% during the first three years of the term of the Term Loan Facility. 
+The Credit Facilities are not subject to financial covenants unless liquidity, as defined in the respective credit agreements, drops below a specified level. Under the ABL Facility, the Company is required to maintain a minimum fixed charge coverage ratio, as defined in the credit agreement governing the ABL Facility, of 1.0 to 1.0 for each period if excess availability is less than 10% of the borrowing base or $12.5 million, whichever is greater. Under the Term Loan Facility, the Company is required to maintain a minimum fixed charge coverage ratio, as defined, of 1.2 to 1.0 for each trailing twelve-month period if the Company’s liquidity, as defined, is less than $25.0 million for at least five consecutive business days. The Company was in compliance with these covenants as of December 31, 2020. 
+Contractual Obligations 
+The table below provides estimates of the timing of future payments that we are contractually obligated to make based on agreements in place at December 31, 2020. 
+Payments Due by Period 
+($ in thousands) 
+Total Less than 1 
+year 1 – 3 years 4 – 5 years More than 5 years 
+ABL Facility(1) $ — $ — $ — $ — $ — 
+Term Loan Facility(1) 108,215 1,750 106,465 — — 
+Estimated interest payments(2) 16,062 9,406 6,656 — — 
+Operating lease obligations(3) 85,628 26,546 27,197 9,905 21,980 
+Finance lease obligations(4) 33,731 21,270 12,461 — — 
+Purchase commitments(5) 127,420 82,141 27,347 17,932 — 
+Obligations under the TRAs(6) 56,594 — 25,841 9,293 21,460 
+Total $ 427,650 $ 141,113 $ 205,967 $ 37,130 $ 43,440 
+(1) Payments on our ABL Facility and Term Loan Facility exclude interest payments. Payments are based on debt balances as of December 31, 2020. 
+(2) Estimated interest payments are based on debt balances as of December 31, 2020. Interest rates applied are based on the weighted average rate as of December 31, 2020. 
+(3) Operating lease obligations include payments for leased facilities, equipment and vehicles. 
+(4) Finance lease obligations include payments for leased vehicles. 
+(5) Purchase commitments represent payments under supply agreements for the purchase and transportation of proppants. Some of the agreements include minimum monthly purchase commitments, including agreements under which a shortfall fee may be applied. The shortfall fee may be offset by purchases in excess of the minimum requirement during future periods, as allowed for by each agreement. 
+(6) The timing and amount(s) of the aggregate payments due under the TRAs may vary based on a number of factors, including the timing and amount of the taxable income we generate each year and the tax rate then applicable. 
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+Tax Receivable Agreements 
+In connection with the IPO, on January 17, 2018, the Company entered into two TRAs with the TRA Holders. The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that the Company actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result, as applicable to each of the TRA Holders, of (i) certain increases in tax basis that occur as a result of the Company’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holders’ Liberty LLC Units in connection with the IPO or pursuant to the exercise of the right of each Liberty Unit Holder (the “Redemption Right”), subject to certain limitations, to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units for, at Liberty LLC’s election, (A) shares of our Class A Common Stock at the specific redemption ratio or (B) an equivalent amount of cash, or, upon the exercise of the Redemption Right, the right of the Company (instead of Liberty LLC) to, for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder (the “Call Right”) for, at its election, (1) one share of Class A Common Stock or (2) an equivalent amount of cash, (ii) any net operating losses available to the Company as a result of the Corporate Reorganization, and (iii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRAs. 
+With respect to obligations the Company expects to incur under the TRAs (except in cases where the Company elects to terminate the TRAs early, the TRAs are terminated early due to certain mergers, asset sales, or other changes of control or the Company has available cash but fails to make payments when due), generally the Company may elect to defer payments due under the TRAs if the Company does not have available cash to satisfy its payment obligations under the TRAs or if its contractual obligations limit its ability to make such payments. Any such deferred payments under the TRAs generally will accrue interest. In certain cases, payments under the TRAs may be accelerated and/or significantly exceed the actual benefits, if any, the Company realizes in respect of the tax attributes subject to the TRAs. The Company accounts for amounts payable under the TRAs in accordance with Accounting Standard Codification (“ASC”) Topic 450, Contingencies (“ASC Topic 450”). 
+If the Company experiences a change of control (as defined under the TRAs) or the TRAs otherwise terminate early, the Company’s obligations under the TRAs could have a substantial negative impact on its liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. There can be no assurance that we will be able to finance our obligations under the TRAs. 
+Income Taxes 
+Following the IPO, the Company is a corporation and is subject to U.S. federal, state and local income tax on its share of Liberty LLC’s taxable income. As a result of the IPO and Corporate Reorganization, the Company recorded deferred tax assets and liabilities for the difference between the book value of assets and liabilities for financial reporting purposes and those amounts applicable for income tax purposes. 
+The effective combined U.S. federal and state income tax rate applicable to the Company for the year ended December 31, 2020 and 2019 was 16.1% and 15.8%, respectively. The Company’s effective tax rate is significantly less than the federal statutory income tax rate of 21.0% primarily because no taxes are payable by the Company for the non-controlling interest’s share of Liberty LLC’s pass-through income for federal, state and local income tax reporting. The Company recognized income tax benefit of $30.9 million and income tax expense of $14.1 million for the years ended December 31, 2020 and 2019, respectively. 
+Critical Accounting Policies and Estimates 
+The preparation of financial statements requires the use of judgments and estimates. Our critical accounting policies are described below to provide a better understanding of how we develop our assumptions and judgments about future events and related estimates and how they can impact our financial statements. A critical accounting estimate is one that requires our most difficult, subjective or complex estimates and assessments and is fundamental to our results of operations. 
+We base our estimates on historical experience and on various other assumptions we believe to be reasonable according to the current facts and circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. We believe the following are the critical accounting policies used in the preparation of our combined financial statements, as well as the significant estimates and judgments affecting the application of these policies. This discussion and analysis should be read in conjunction with our combined financial statements and related notes included in “Item 8. Financial Statements and Supplementary Data. ” 
+Business Combinations : Business combinations are accounted for using the acquisition method of accounting in accordance with the ASC Topic 805 - Business Combinations, as amended by Accounting Standards Update (“ASU”) 2017-01, Business Combinations (Topic 805), Clarifying the Definition of a Business. The purchase price is allocated to the assets acquired and liabilities assumed based on their estimated fair values. Fair value of the acquired assets and liabilities is measured 
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+in accordance with the guidance of ASC 850 - Fair Value Measurements, using discounted cash flows and other applicable valuation techniques. Any acquisitions related costs incurred by the Company are expensed as incurred. Any excess purchase price over the fair value of the net identifiable assets acquired is recorded as goodwill if the definition of a business is met. Operating results of an acquired business are included in our results of operations from the date of acquisition. 
+Revenue Recognition: Revenue from hydraulic fracturing services is recognized as specific services are provided in accordance with contractual arrangements. If our assessment of performance under a particular contract changes, our revenue and / or costs under that contract may change. In connection with ASC Topic 842 - Leases (“Topic 842”), the Company determined that certain of its service revenue contracts contain a lease component. The Company elected to adopt a practical expedient available to lessors, which allows the Company to combine the lease and service component for certain of the Company’s service contracts when the service component is the predominant component and continues to account for the combined component under ASC Topic 606 - Revenue from Contracts with Customers . 
+Accounts Receivable: On January 1, 2020, the Company adopted ASU 2016-13, Financial Instruments-Credit Losses (Topic 326) : Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”), which changes the impairment model for most financial assets and certain other instruments. Specifically, this new guidance requires using a forward looking, expected loss model for trade and other receivables, held-to-maturity debt securities, loans, and other instruments. Under ASU 2016-13, a company recognizes as an allowance, the estimate of lifetime expected credit losses, which is expected to result in more timely recognition of such losses. 
+The Company applies historic loss factors to its receivable portfolio segments that were not expected to be further impacted by current economic developments, and an additional economic conditions factor to portfolio segments anticipated to experience greater losses in the current economic environment. The Company continuously evaluates customers based on risk characteristics, such as historical losses and current economic conditions. Due to the cyclical nature of the oil and gas industry, the Company often evaluates its customers’ estimated losses on a case-by-case basis. It is reasonably possible that our estimates of the allowance for doubtful accounts will change and that losses ultimately incurred could differ materially from the amounts estimated in determining the allowance. 
+Inventory: Inventory consists of raw materials used in the hydraulic fracturing process, such as proppants, chemicals and field service equipment maintenance parts, and is stated at the lower of cost or net realizable value, determined using the weighted average cost method. Net realizable value is determined based on our estimates of selling prices in the ordinary course of business, less reasonably predictable cost of completion, disposal, and transportation, each of which require us to apply judgment. 
+Property and Equipment: We calculate depreciation and amortization on our assets based on the estimated useful lives and estimated salvage values that we believe are reasonable. The estimated useful lives and salvage values are subject to key assumptions such as maintenance, utilization and job variation. These estimates may change due to a number of factors such as changes in operating conditions or advances in technology. 
+We incur maintenance costs on our major equipment. The determination of whether an expenditure should be capitalized or expensed requires management judgment in the application of how the costs benefit future periods, relative to our capitalization policy. Costs that either establish or increase the efficiency, productivity, functionality or life of a fixed asset are capitalized and depreciated over the remaining useful life of the asset. 
+Impairment of long-lived and other intangible assets: Long-lived assets, such as property and equipment, right-of-use lease assets and intangible assets, are evaluated for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Recoverability is assessed using undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets. When alternative courses of action to recover the carrying amount of the asset group are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence, which require us to apply judgment. If the carrying amount of the asset is not recoverable based on its estimated undiscounted cash flows expected to result from the use and eventual disposition, an impairment loss is recognized in an amount by which its carrying amount exceeds its estimated fair value. The inputs used to determine such fair value are primarily based upon internally developed cash flow models. Our cash flow models are based on a number of estimates regarding future operations that may be subject to significant variability, are sensitive to changes in market conditions, and are reasonably likely to change in the future. 
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+During the year ended December 31, 2020, as a result of negative market indicators including the COVID-19 pandemic, the increased supply of low-priced oil, and customer cancellations, the Company concluded these triggering events could indicate possible impairment of property and equipment. The Company performed a quantitative and qualitative impairment analysis and determined that no impairment had occurred as of March 31, 2020. As of December 31, 2020, the Company concluded that no additional triggering events occurred and the conclusion reached at March 31, 2020 is still appropriate. Such analysis required management to make estimates and assumptions based on historical data and consideration of future market conditions. Given the uncertainty inherent in any projection, heightened by the possibility of unforeseen additional effects of COVID-19, actual results may differ from the estimates and assumptions used, or conditions may change, which could result in impairment charges in the future. 
+No impairment was recognized during the years ended December 31, 2020, 2019 and 2018. 
+Leases: The Company adopted Accounting Standards Update (“ASU”) No. 2016-02, Leases ASC Topic 842 effective January 1, 2019. We elected the modified retrospective transition method under ASC Topic 842 and as such information prior to January 1, 2019 has not been restated and continues to be reported under the accounting standards in effect for the period ( ASC Topic 840-Leases ). We carried forward the historical lease classifications and assessment of initial direct costs, account for lease and non-lease components as a single component, and exclude leases with an initial term of less than 12 months in the lease assets and liabilities. For leases entered into after January 1, 2019, the Company determines if an arrangement is a lease at inception and evaluates identified leases for operating or finance lease treatment. Operating or finance lease right-of-use assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. We use our incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments. Lease terms may include options to renew; however, we typically cannot determine our intent to renew a lease with reasonable certainty at inception. 
+Tax Receivable Agreements: In connection with the IPO, on January 17, 2018, the Company entered into two TRAs with the TRA Holders. The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax that the Company actually realizes in periods after the IPO as a result of certain tax attributes applicable to each TRA Holder. The Company accounts for amounts payable under the TRAs in accordance with ASC Topic 450, Contingencies . 
+Share Repurchases: The Company accounts for the purchase price of repurchased Class A Common Stock in excess of par value ($0.01 per share of Class A Common Stock) as a reduction of additional paid-in capital, and will continue to do so until additional paid-in capital is reduced to zero. Thereafter, any excess purchase price will be recorded as a reduction to retained earnings. 
+Recent Accounting Pronouncements 
+See Note 2—Significant Accounting Policies— Recently Issued Accounting Standards to the consolidated and combined financial statements included in “Item 8. Financial Statements and Supplementary Data” for a discussion of recent accounting pronouncements. 
+Off Balance Sheet Arrangements 
+We have no material off balance sheet arrangements as of December 31, 2020, except for purchase commitments under supply agreements as disclosed above under “—Contractual Obligations.” As such, we are not materially exposed to any other financing, liquidity, market or credit risk that could arise if we had engaged in such financing arrangements. 
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+Item 7A. Quantitative and Qualitative Disclosure about Market Risk 
+Industry Risk 
+The demand, pricing and terms for hydraulic fracturing services and related goods provided by us are largely dependent upon the level of drilling activity in the U.S. oil and natural gas industry, as well as the available supply of hydraulic fracturing equipment. These activity levels are influenced by numerous factors over which we have no control, including, but not limited to: the supply of and demand for oil and natural gas; the level of prices, and expectations about future prices of oil and natural gas; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; the discovery rates of new oil and natural gas reserves; supply of actively marketed and staffed fracturing fleets; available rail and other transportation capacity; weather conditions; domestic and worldwide economic conditions; political instability in oil-producing countries; environmental regulations; technical advances affecting energy consumption; the price and availability of alternative fuels; the ability of E&P companies to raise equity capital and debt financing; and merger and divestiture activity among E&P companies. 
+The level of U.S. oil and natural gas drilling is volatile. Expected trends in oil and natural gas production activities may not materialize and demand for our services may not reflect the level of activity in the industry. Any prolonged and substantial reduction in oil and natural gas prices would likely affect oil and natural gas production levels and therefore affect demand for our services. A material decline in oil and natural gas prices or U.S. activity levels could have a material adverse effect on our business, financial condition, results of operations and cash flows. 
+Interest Rate Risk 
+At December 31, 2020, we had $108.2 million of debt outstanding, with a weighted average interest rate of 8.6%. Interest is calculated under the terms of our Credit Facilities based on our selection, from time to time, of one of the index rates available to us plus an applicable margin that varies based on certain factors. See “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements.” Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the weighted average interest rate would be approximately $1.1 million per year. We do not currently have or intend to enter into any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness. 
+Commodity Price Risk 
+Our material and fuel purchases expose us to commodity price risk. Material costs primarily include inventory consumed while performing hydraulic fracturing services. Fuel costs consist of diesel fuel used by trucks and other motorized equipment used for hydraulic fracturing services. At times, we have been able to pass along price increases for material costs and fuel costs to customers and conversely have been required to pass along price decreases for material costs to our customers, depending on market conditions. Further, we have purchase commitments with certain vendors to supply proppant inventory used in our operations at a fixed purchase price, including certain commitments which include minimum purchase obligations. Refer t o Note 14, “Commitments and Contingencies” included in “Item 8. Financial Statements and Supplementary Data” for further discussion regarding pur chase commitments. 
+37 
+Table of Contents 
+Item 8. Financial Statements and Supplementary Data 
+Our financial statements and supplementary data are included in this Annual Report on Form 10-K beginning on page F-1 and incorporated by reference herein. 
+Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+None. 
+Item 9A. Controls and Procedures 
+Evaluation of Disclosure Controls and Procedures 
+In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2020 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures. 
+As noted in Management’s Report on Internal Control Over Financial Reporting, management ’ s evaluation of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of the entities acquired in the OneStim Acquisition, as defined herein, on December 31, 2020. Under guidelines established by the SEC, companies are permitted to exclude acquisitions from their assessment of internal control over financial reporting during the first year of an acquisition while integrating the acquired company. The Company is in the process of integrating OneStim ’s and our internal controls over financial reporting. As a result of these integration activities, certain controls will be evaluated and may be changed. Except as noted above, there were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+See page F-1 for Management’s Report on Internal Control Over Financial Reporting and page F-4 for Report of Independent Registered Public Accounting Firm on its assessment of our internal control over financial reporting. 
+Item 9B. Other Information 
+None. 
+38 
+Table of Contents 
+PART III 
+Item 10. Directors, Executive Officers and Corporate Governance 
+The information required by this item concerning our executive officers, directors and corporate governance is incorporated herein by reference to our definitive proxy statement for our 2021 annual meeting of shareholders, which will be filed with the SEC no later than 120 days after December 31, 2020, under the captions “Proposal 1 — Election of Directors,” “The Board and its Committees,” “Executive Officers” and “Delinquent Section 16(a) Reports.” 
+Item 11. Executive Compensation 
+The information required by this item concerning executive compensation is incorporated herein by reference to our definitive proxy statement for our 2021 annual meeting of shareholders, which will be filed with the SEC no later than 120 days after December 31, 2020, under the captions “The Board and its Committees,” “Compensation Discussion & Analysis,” “Compensation Committee Report,” “Executive Compensation Tables,” “Director Compensation” and “CEO Pay Ratio.” 
+Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+The information required by this item concerning the security ownership of certain beneficial owners and management and related stockholder matters are incorporated herein by reference to our definitive proxy statement for our 2021 annual meeting of shareholders, which will be filed with the SEC no later than 120 days after December 31, 2020, under the captions “Security Ownership of Certain Beneficial Owners and Management” and “Equity Compensation Plan Information.” 
+Item 13. Certain Relationships and Related Transactions, and Director Independence 
+The information required by this item concerning certain relationships and related person transactions and director independence is incorporated herein by reference to our definitive proxy statement for our 2021 annual meeting of shareholders, which will be filed with the SEC no later than 120 days after December 31, 2020, under the captions “Certain Relationships and Related Party Transactions” and “the Board and its Committees.” 
+Item 14. Principal Accountant Fees and Services 
+The information required by this item concerning principal accounting fees and services is incorporated herein by reference to our definitive proxy statement for our 2021 annual meeting of shareholders, which will be filed with the SEC no later than 120 days after December 31, 2020, under the caption “Proposal 2 — Ratification of Appointment of the Company’s Independent Registered Public Accounting Firm.” 
+39 
+Table of Contents 
+PART IV 
+Item 15. Exhibits and Financial Statement Schedules 
+(a) Financial Statements and Financial Statement Schedules 
+Refer to Index to Financial Statements on page 46. 
+All schedules are omitted as information required is inapplicable or the information is presented in the consolidated and combined financial statements and the related notes. 
+(b) Exhibits 
+The documents listed in the Index to Exhibits are filed, furnished or incorporated by reference as part of this Annual Report on Form 10-K, and such Index to Exhibits are incorporated herein by reference. 
+40 
+Table of Contents 
+Item 16. Form 10-K Summary 
+None. 
+41 
+Table of Contents 
+INDEX TO EXHIBITS 
+Exhibit 
+Number 
+Description 
+2.1 
+Master Reorganization Agreement, dated as of January 11, 2018, by and among Liberty Oilfield Services Inc., Liberty Oilfield Services Holdings LLC, Liberty Oilfield Services New HoldCo LLC, and the other parties named therein (2) 
+2.2 
+Master Transaction Agreement, dated as of August 31, 2020, by and among Schlumberger Technology Corporation, Schlumberger Canada Limited, Liberty Oilfield Services Holdings LLC, Liberty Canada Operations Inc. and Liberty Oilfield Services Inc. (11) 
+3.1 
+Amended and Restated Certificate of Incorporation of Liberty Oilfield Services Inc. (2) 
+3.2 
+Amended and Restated Bylaws of Liberty Oilfield Services Inc. (3) 
+4.1 
+Amended and Restated Stockholders Agreement, dated as of December 13, 2020, by and among Liberty Oilfield Services Inc., Riverstone and the Schlumberger Parties (12) 
+4.2 
+Description of the Registrant’s Securities Registered pursuant to Section 12 of the Securities Exchange Act of 1934. (8) 
+10.1 
+Second Amended and Restated Limited Liability Company Operating Agreement of Liberty Oilfield Services New HoldCo LLC (2) 
+10.2 
+Tax Receivable Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Inc., R/C Energy IV Direct Partnership, L.P., and R/C Energy IV Direct Partnership, L.P., as agent (2) 
+10.3 
+Tax Receivable Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Inc., and the other parties named therein (2) 
+10.4 
+Amended and Restated Registration Rights Agreement, dated as of December 31, 2020, by and among Liberty Oilfield Services Inc., the Schlumberger Parties, and the Holders (12) 
+10.5 
+Liberty Oilfield Services Inc. Long Term Incentive Plan (2)† 
+10.6 
+Liberty Oilfield Services Inc. Legacy Restricted Stock Plan (2)† 
+10.7 
+Form of Restricted Stock Grant Notice and Restricted Stock Agreement under the Legacy Restricted Stock Plan (1)† 
+10.8 
+Credit Agreement, dated September 19, 2017, by and among Wells Fargo Bank, National Association, as Administrative Agent, Wells Fargo Bank, National Association, JPMorgan Chase Bank, N.A. and Citibank, N.A., as Joint Lead Arrangers, Wells Fargo Bank, National Association, as Book Runner, JPMorgan Chase Bank, N.A. and Citibank, N.A., as Syndication Agents, the lender parties thereto, Liberty Oilfield Services Holdings LLC, as Parent and Liberty Oilfield Services LLC and LOS Acquisition Co I LLC, each as a Borrower (1) 
+10.9 
+Amendment and Parent Joinder to Credit Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Holdings LLC, Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto (4) 
+10.10 
+Second Amendment and Parent Joinder to Credit Agreement, dated March 21, 2018, by and among Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto (4) 
+10.11 
+Third Amendment to Credit Agreement, dated May 29, 2020, by and among Liberty Oilfield Services LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, and Wells Fargo Bank, National Association as Administrative Agent, and the lenders signatory thereto (9) 
+10.12 
+Fourth Amendment to Credit Agreement, dated August 12, 2020, by and among Liberty Oilfield Services LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto (10) 
+10.13 
+Consent and Fifth Amendment to Credit Agreement, dated December 29, 2020, by and among Liberty Oilfield Services LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, LOS Cibolo RE Investments, LLC, LOS Odessa RE Investments, LLC, ST9 Gas and Oil LLC, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto * 
+42 
+Table of Contents 
+10.14 
+Credit Agreement, dated September 17, 2017, by and among Liberty Oilfield Services LLC and LOS Acquisition CO I LLC, each as Borrower, Liberty Oilfield Services Holdings LLC, as Parent Guarantor and U.S. Bank National Association as Agent (1) 
+10.15 
+Amendment and Joinder to Credit Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Holdings LLC, Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, U.S. Bank National Association, as Administrative Agent, and the lenders signatory thereto (4) 
+10.16 
+Second Amendment and Joinder to Credit Agreement, dated March 21, 2018, by and among Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, U.S. Bank National Association, as Administrative Agent, and the lenders signatory thereto (4) 
+10.17 
+Third Amendment to Credit Agreement, dated August 12, 2020, by and among Liberty Oilfield Services LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, U.S. Bank National Association, as Administrative Agent, and the lenders signatory thereto (10) 
+10.18 
+Waiver, Consent and Fourth Amendment to Credit Agreement and First Amendment to Guaranty and Security Agreement, dated December 29, 2020, by and among Liberty Oilfield Services LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, LOS Cibolo RE Investments, LLC, LOS Odessa RE Investments, LLC, ST9 Gas and Oil LLC, U.S. Bank National Association, as Administrative Agent, and the lenders signatory thereto * 
+10.19 
+Liberty Oilfield Services 401(k) Savings Plan *† 
+10.20 
+Form of Restricted Stock Unit Grant Notice and Restricted Stock Unit Award Agreement under the Long Term Incentive Plan (5)† 
+10.21 
+Form of Restricted Stock Unit Grant Notice under the Long Term Incentive Plan *† 
+10.22 
+Form of Performance Restricted Stock Unit Grant Notice and Performance Restricted Stock Unit Agreement under the Liberty Oilfield Services Inc. Long Term Incentive Plan (6)† 
+10.23 
+Form of Change in Control Agreement (7)† 
+10.24 
+Form of Indemnification Agreement between the Company and each of its Directors and Executive Officers (8) 
+21.1 
+List of subsidiaries of Liberty Oilfield Services Inc. * 
+23.1 
+Consent of Deloitte & Touche LLP * 
+31.1 
+Certification of Chief Executive Officer pursuant to Rule 13a-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 * 
+31.2 
+Certification of Chief Financial Officer pursuant to 13a-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 * 
+32.1 
+Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 ** 
+32.2 
+Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 ** 
+95 
+Mine Safety Disclosure * 
+101.INS XBRL Instance Document * 
+101.SCH XBRL Taxonomy Extension Schema Document * 
+101.CAL XBRL Taxonomy Extension Calculation Linkbase Document * 
+101.DEF XBRL Taxonomy Extension Definition Linkbase Document * 
+101.LAB XBRL Taxonomy Extension Label Linkbase Document * 
+101.PRE XBRL Taxonomy Extension Presentation Linkbase Document * 
+104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)* 
+(1) Incorporated by reference to the exhibits to the registrant’s Registration Statement on Form S-1, as amended (SEC File 333-216050). 
+(2) Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on January 18, 2018. 
+43 
+Table of Contents 
+(3) Incorporated by reference to the exhibits to the registrant’s Amendment No. 1 to the Current Report on Form 8-K/A, filed on January 22, 2018. 
+(4) Incorporated by reference to the exhibits to the registrant’s Annual Report on Form 10-K, filed on March 23, 2018. 
+(5) Incorporated by reference to the exhibits to the registrant’s Quarterly Report on Form 10-Q, filed on May 10, 2018. 
+(6) Incorporated by reference to the exhibits to the registrant’s Quarterly Report on Form 10-Q, filed on May 3, 2019. 
+(7) Incorporated by reference to the registrant’s Current Report on Form 8-K, filed on August 30, 2019. 
+(8) Incorporated by reference to the exhibits to the registrant’s Annual Report on Form 10-K, filed on February 27, 2020. 
+(9) Incorporated by reference to the registrant’s Current Report on Form 8-K, filed on June 3, 2020. 
+(10) Incorporated by reference to the registrant’s Quarterly Report on Form 8-K, filed on October 30, 2020. 
+(11) Incorporated by reference to the registrant’s Current Report on Form 8-K, filed on September 1, 2020. 
+(12) Incorporated by reference to the registrant’s Current Report on Form 8-K, filed on January 4, 2021. 
+* Filed herewith. 
+** Furnished herewith. 
+† Denotes a management contract or compensatory plan or arrangement. 
+44 
+Table of Contents 
+SIGNATURES 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+LIBERTY OILFIELD SERVICES INC. 
+/s/ Christopher A. Wright 
+Date: February 24, 2021 By: 
+Christopher A. Wright 
+Chief Executive Officer 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+Signature Title Date 
+/s/ Christopher A. Wright 
+Chief Executive Officer and Director 
+(Principal Executive Officer) 
+February 24, 2021 
+Christopher A. Wright 
+/s/ Michael Stock 
+Chief Financial Officer 
+(Principal Financial Officer) 
+February 24, 2021 
+Michael Stock 
+/s/ Ryan T. Gosney Chief Accounting Officer February 24, 2021 
+Ryan T. Gosney (Principal Accounting Officer) 
+/s/ Simon Ayat Director February 24, 2021 
+Simon Ayat 
+/s/ Ken Babcock Director February 24, 2021 
+Ken Babcock 
+/s/ Peter A. Dea Director February 24, 2021 
+Peter A. Dea 
+/s/ William F. Kimble Director February 24, 2021 
+William F. Kimble 
+/s/ James R. McDonald Director February 24, 2021 
+James R. McDonald 
+/s/ Gale A. Norton Director February 24, 2021 
+Gale A. Norton 
+/s/ Brett Staffieri Director February 24, 2021 
+Brett Staffieri 
+/s/ Cary D. Steinbeck Director February 24, 2021 
+Cary D. Steinbeck 
+45 
+Table of Contents 
+Index to Financial Statements 
+Liberty Oilfield Services Inc. 
+Management’s Report on Internal Control Over Financial Reporting 
+F-1 
+Reports of Independent Registered Public Accounting Firm 
+F- 2 
+Consolidated Balance Sheets as of December 31, 2020 and 2019 
+F- 5 
+Consolidated and Combined Statements of Operations for the Years Ended December 31, 2020, 2019, and 2018 
+F- 6 
+Consolidated Statements of Changes in Equity for the Years Ended December 31, 2020 and 2019 
+F- 7 
+Consolidated and Combined Statements of Cash Flows for the Years Ended December 31, 2020, 2019, and 2018 
+F- 8 
+Notes to Consolidated and Combined Financial Statements 
+F- 9 
+46 
+Table of Contents 
+MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING 
+The management of Liberty Oilfield Services Inc. is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act. 
+Internal control over financial reporting, no matter how well designed, has inherent limitations. Therefore, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements. Further, because of changes in conditions, effectiveness of internal controls over financial reporting may vary over time. 
+Under the supervision of, and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2020 based on the framework and criteria established in Internal Control-Integrated Framework (2013) , issued by the Committee of Sponsoring Organizations of the Treadway Commission. 
+Based on this evaluation, management concluded that, as of December 31, 2020, our internal control over financial reporting was effective. Management ’ s evaluation of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of the entities acquired in the OneStim Acquisition, as defined herein, on December 31, 2020. The acquired business ’ financial statements constitute 52% and 43% of net and total assets as of December 31, 2020. 
+The effectiveness of Liberty Oilfield Services Inc. ’ s internal control over financial reporting as of December 31, 2020 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report that is included herein. 
+F-1 
+Table of Contents 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the shareholders and the Board of Directors of Liberty Oilfield Services Inc. 
+Opinion on the Financial Statements 
+We have audited the accompanying consolidated balance sheets of Liberty Oilfield Services Inc. and subsidiaries (the “Company”) as of December 31, 2020 and 2019, the related consolidated and combined statements of operations, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2020, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America. 
+We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company ’ s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2021, expressed an unqualified opinion on the Company ’ s internal control over financial reporting. 
+Change in Accounting Principle 
+As discussed in Note 2 to the financial statements, the Company changed its method of accounting for leases effective January 1, 2019 due to the adoption of Accounting Standards Codification Topic 842—Leases. 
+Basis for Opinion 
+These financial statements are the responsibility of the Company ’ s management. Our responsibility is to express an opinion on the Company ’ s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. 
+Critical Audit Matter 
+The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. 
+Income Taxes — Tax Receivable Agreements — Refer to Note 11 to the financial statements 
+Critical Audit Matter Description 
+The amounts payable, as well as the timing of such payments, under the tax receivable agreements (“TRA”) are dependent upon significant future events and assumptions, including among others: (i) the amount of the redeeming unit holder’s tax basis in its Liberty Oilfield Services New HoldCo LLC class B units at the time of the relevant redemption, (ii) the characterization of the tax basis step-up, (iii) the depreciation and amortization periods that apply to the increase in tax 
+F-2 
+Table of Contents 
+basis (iv), the amount and timing of taxable income the Company generates in future periods until the TRA payable is settled, and (v) the portion of the Company’s payments under the TRA that constitute imputed interest or give rise to depreciable or amortizable tax basis. 
+During the year ended December 31, 2020, exchanges of Liberty Oilfield Services New HoldCo LLC class B units and shares of Class B Common Stock resulted in an increase of $13.1 million in amounts payable pursuant to tax receivable agreements (“TRA payable”), and a net increase of $15.5 million in deferred tax assets, all of which were recorded as equity transactions, with no impact to the statement of operations. At December 31, 2020, the Company ’ s TRA payable was $56.6 million, all of which is presented as a component of long-term liabilities. 
+We identified the computation of adjustments to the TRA payable as a critical audit matter because of the multiple owners and complex calculations required to arrive at the correct tax basis upon which to calculate the corresponding TRA payable adjustment. This involved complexity in applying relevant tax law and an increased extent of effort, including the need to involve income tax specialists, when performing audit procedures to evaluate the reasonableness of management’s calculation of tax basis, iterative impact of the computation of adjustments to the TRA payable, and TRA payable as of year end. 
+How the Critical Audit Matter Was Addressed in the Audit 
+Our audit procedures related to the computation of adjustments to the TRA payable included the following, among others: 
+• We tested the effectiveness of controls over the computation of adjustments to the TRA payable, including management ’ s calculation of the step-up in tax basis that serves as the basis for the computation of adjustments to the TRA payable. 
+• With the assistance of our income tax specialists, we read the individual TRAs and compared the terms in the agreements for consistency with the mathematical model used by management to calculate the adjustments to the TRA payable. 
+• With the assistance of our income tax specialists, we evaluated management’s computation of adjustments to the TRA payable, and the TRA payable as of year end that is payable over the contractual period by comparing to our independently recalculated value, taking into account the various class B unit exchanges for Class B Common Stock occurring during the year as well as the adjustments in the TRA payable for each exchange. 
+/s/ DELOITTE & TOUCHE LLP 
+Denver, Colorado 
+February 24, 2021 
+We have served as the Company ’ s auditor since 2016. 
+F-3 
+Table of Contents 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the shareholders and the Board of Directors of Liberty Oilfield Services Inc. 
+Opinion on Internal Control over Financial Reporting 
+We have audited the internal control over financial reporting of Liberty Oilfield Services Inc. and subsidiaries (the “Company”) as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO. 
+We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2020, of the Company and our report dated February 24, 2021, expressed an unqualified opinion on those financial statements. 
+As described in Management's Report on Internal Control Over Financial Reporting, management excluded from its assessment the internal control over financial reporting at Schlumberger ’ s OneStim® business (“OneStim”), which was acquired on December 31, 2020 and whose financial statements constitute 52% and 43% of net and total assets, respectively of the consolidated financial statement amounts as of and for the year ended December 31, 2020. Accordingly, our audit did not include the internal control over financial reporting at OneStim. 
+Basis for Opinion 
+The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+Definition and Limitations of Internal Control over Financial Reporting 
+A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+/s/ DELOITTE & TOUCHE LLP 
+Denver, Colorado 
+February 24, 2021 
+F-4 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Consolidated Balance Sheets 
+As of December 31, 2020 and 2019 
+(Dollars in thousands, except share data) 
+2020 2019 
+Assets 
+Current assets: 
+Cash and cash equivalents $ 68,978 $ 112,690 
+Accounts receivable—trade, net of provisions for credit losses of $ 773 and $ 1,053 , respectively 
+244,433 204,413 
+Accounts and notes receivable—related party — 9,629 
+Unbilled revenue 69,516 38,868 
+Inventories 118,568 88,547 
+Prepaid and other current assets (including receivables from related parties of $ 24,708 and $ 0 , respectively) 
+65,638 34,827 
+Total current assets 567,133 488,974 
+Property and equipment, net 1,120,950 651,703 
+Finance lease right-of-use assets 38,733 55,337 
+Operating lease right-of-use assets 75,878 53,076 
+Other assets 81,888 34,339 
+Deferred tax asset 5,360 — 
+Total assets $ 1,889,942 $ 1,283,429 
+Liabilities and Equity 
+Current liabilities: 
+Accounts payable $ 193,338 $ 117,613 
+Accrued liabilities: 
+Accrued vendor invoices 61,210 42,753 
+Operational accruals 28,932 26,753 
+Accrued benefits and other (including payables to related parties of $ 0 and $ 1,329 , respectively) 
+28,241 39,448 
+Current portion of long-term debt, net of discount of $ 1,386 and $ 1,341 , respectively 
+364 409 
+Current portion of finance lease liabilities 20,580 23,646 
+Current portion of operating lease liabilities 23,481 15,873 
+Total current liabilities 356,146 266,495 
+Long-term debt, net of discount of $ 1,054 and $ 2,485 , respectively, less current portion 
+105,411 105,731 
+Deferred tax liability — 19,659 
+Payable pursuant to tax receivable agreements, including payables to related parties of $ 27,173 and $ 23,797 , respectively 
+56,594 48,481 
+Noncurrent portion of finance lease liabilities 11,318 24,884 
+Noncurrent portion of operating lease liabilities 50,430 36,687 
+Total liabilities 579,899 501,937 
+Commitments & contingencies (Note 14) 
+Stockholders’ equity: 
+Preferred Stock, $ 0.01 par value, 10,000 shares authorized and no ne issued and outstanding 
+— — 
+Common Stock: 
+Class A, $ 0.01 par value, 400,000,000 shares authorized and 157,952,213 issued and outstanding as of December 31, 2020 and 81,885,384 issued and outstanding as of December 31, 2019 
+1,579 819 
+Class B, $ 0.01 par value, 400,000,000 shares authorized and 21,550,282 issued and outstanding as of December 31, 2020 and 30,638,960 issued and outstanding as of December 31, 2019 
+216 307 
+Additional paid in capital 1,125,554 410,596 
+Retained earnings 23,288 143,105 
+Total stockholders’ equity 1,150,637 554,827 
+Non-controlling interest 159,406 226,665 
+Total equity 1,310,043 781,492 
+Total liabilities and equity $ 1,889,942 $ 1,283,429 
+See Notes to Consolidated and Combined Financial Statements. 
+F-5 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Consolidated and Combined Statements of Operations 
+For the Years Ended December 31, 2020, 2019, and 2018 
+(In thousands, except per share data) 
+2020 2019 2018 
+Revenue: 
+Revenue $ 965,787 $ 1,972,073 $ 2,132,032 
+Revenue—related parties — 18,273 23,104 
+Total revenue 965,787 1,990,346 2,155,136 
+Operating costs and expenses: 
+Cost of services (exclusive of depreciation and amortization shown separately below) 857,981 1,621,180 1,628,753 
+General and administrative 84,098 97,589 98,420 
+Transaction, severance and other costs 21,061 — 632 
+Depreciation and amortization of intangible assets 180,084 165,379 125,110 
+(Gain) loss on disposal of assets ( 411 ) 2,601 ( 4,342 ) 
+Total operating costs and expenses 1,142,813 1,886,749 1,848,573 
+Operating (loss) income ( 177,026 ) 103,597 306,563 
+Other (income) and expense: 
+Interest income ( 297 ) ( 983 ) ( 382 ) 
+Interest expense 15,065 17,485 17,527 
+Interest income—related party ( 263 ) ( 1,821 ) — 
+Total interest expense 14,505 14,681 17,145 
+Net (loss) income before income taxes ( 191,531 ) 88,916 289,418 
+Income tax (benefit) expense ( 30,857 ) 14,052 40,385 
+Net (loss) income ( 160,674 ) 74,864 249,033 
+Less: Net (loss) income attributable to Predecessor, prior to Corporate Reorganization — — 8,705 
+Less: Net (loss) income attributable to non-controlling interests ( 45,091 ) 35,861 113,979 
+Net (loss) income attributable to Liberty Oilfield Services Inc. stockholders $ ( 115,583 ) $ 39,003 $ 126,349 
+Net (loss) income attributable to Liberty Oilfield Services Inc. stockholders per common share: 
+Basic $ ( 1.36 ) $ 0.54 $ 1.84 
+Diluted $ ( 1.36 ) $ 0.53 $ 1.81 
+Weighted average common shares outstanding: 
+Basic 85,242 72,334 68,838 
+Diluted 85,242 105,256 117,838 
+See Notes to Consolidated and Combined Financial Statements. 
+F-6 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Consolidated Statements of Changes in Equity 
+For the Years Ended December 31, 2020 and 2019 
+(In thousands, except share and per unit data) 
+Shares of Class A Common Stock Shares of Class B Common Stock Class A Common Stock, Par Value Class B Common Stock, Par Value Additional Paid in Capital Retained Earnings Total Stockholders’ equity Non-controlling Interest Total Equity 
+Balance—December 31, 2019 81,885 30,639 $ 819 $ 307 $ 410,596 $ 143,105 $ 554,827 $ 226,665 $ 781,492 
+Exchange of Class B Common Stock for Class A Common Stock 9,089 ( 9,089 ) 91 ( 91 ) 59,474 — 59,474 ( 59,474 ) — 
+Effect of exchange on deferred tax asset, net of liability under tax receivable agreements — — — — 2,430 — 2,430 — 2,430 
+Issuance of Class A Common Stock, net of issuance costs 66,326 — 663 — 599,618 — 600,281 81,900 682,181 
+Impact of ownership changes from issuance of Class A Common Stock — — — — 46,400 — 46,400 ( 46,400 ) — 
+Deferred tax impact of ownership changes from issuance of Class A Common Stock — — — — ( 6,337 ) — ( 6,337 ) — ( 6,337 ) 
+$ 0.05 /share of Class A Common Stock dividend 
+— — — — — ( 4,244 ) ( 4,244 ) — ( 4,244 ) 
+$ 0.05 /unit distribution to non-controlling unitholders 
+— — — — — — — ( 1,532 ) ( 1,532 ) 
+Other distributions and advance payments to non-controlling interest unitholders — — — — ( 1 ) — ( 1 ) 569 568 
+Stock based compensation expense — — — — 12,976 — 12,976 4,163 17,139 
+Vesting of Restricted Stock Units 657 — 7 — 407 — 414 ( 1,402 ) ( 988 ) 
+Restricted stock forfeited ( 5 ) — ( 1 ) — ( 9 ) 10 — 8 8 
+Net loss — — — — — ( 115,583 ) ( 115,583 ) ( 45,091 ) ( 160,674 ) 
+Balance—December 31, 2020 157,952 21,550 $ 1,579 $ 216 $ 1,125,554 $ 23,288 $ 1,150,637 $ 159,406 $ 1,310,043 
+Shares of Class A Common Stock Shares of Class B Common Stock Class A Common Stock, Par Value Class B Common Stock, Par Value Additional Paid in Capital Retained Earnings Total Stockholders’ equity Non-controlling Interest Total Equity 
+Balance - December 31, 2018 68,360 45,207 $ 684 $ 452 $ 312,659 $ 119,274 $ 433,069 $ 307,745 $ 740,814 
+Exchange of Class B Common Stock for Class A Common Stock 14,568 ( 14,568 ) 145 ( 145 ) 110,852 — 110,852 ( 110,852 ) — 
+Offering Costs — — — — ( 1,012 ) — ( 1,012 ) ( 504 ) ( 1,516 ) 
+Effect of exchange on deferred tax asset, net of liability under tax receivable agreements — — — — 5,930 — 5,930 — 5,930 
+Deferred tax impact of ownership changes from exchanges and repurchases — — — — ( 11,130 ) — ( 11,130 ) — ( 11,130 ) 
+$ 0.20 /share of Class A Common Stock dividend 
+— — — — — ( 15,177 ) ( 15,177 ) — ( 15,177 ) 
+$ 0.20 /unit distributions to non-controlling unitholders 
+— — — — — — — ( 7,747 ) ( 7,747 ) 
+Other distributions and advance payments to non-controlling interest unitholders — — — — — — — ( 6 ) ( 6 ) 
+Share repurchases ( 1,303 ) — ( 13 ) — ( 13,017 ) — ( 13,030 ) ( 4,068 ) ( 17,098 ) 
+Stock based compensation expense — — — 6,638 — 6,638 6,954 13,592 
+Vesting of restricted stock units 268 — 3 — ( 302 ) — ( 299 ) ( 740 ) ( 1,039 ) 
+Restricted Stock and RSU Forfeitures ( 8 ) — — — ( 22 ) 5 ( 17 ) 22 5 
+Net income — — — — — 39,003 39,003 35,861 74,864 
+Balance - December 31, 2019 81,885 30,639 $ 819 $ 307 $ 410,596 $ 143,105 $ 554,827 $ 226,665 $ 781,492 
+See Notes to Consolidated and Combined Financial Statements. 
+F-7 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Consolidated and Combined Statements of Cash Flows 
+For the Years Ended December 31, 2020, 2019, and 2018 
+(Dollars in thousands) 
+2020 2019 2018 
+Cash flows from operating activities: 
+Net (loss) income $ ( 160,674 ) $ 74,864 $ 249,033 
+Adjustments to reconcile net income to net cash provided by operating activities: 
+Depreciation and amortization 180,084 165,379 125,110 
+(Gain) loss on disposal of assets ( 411 ) 2,601 ( 4,342 ) 
+Loss (gain) on tax receivable agreements 543 ( 122 ) — 
+Amortization of debt issuance costs 2,232 2,205 4,031 
+Inventory write down 1,087 1,953 3,389 
+Non-cash lease expense 3,668 3,192 — 
+Stock based compensation expense 17,139 13,592 5,450 
+Deferred income tax (benefit) expense ( 25,546 ) 23,408 20,488 
+Bad debt provision 4,877 1,053 — 
+Changes in operating assets and liabilities: 
+Accounts receivable and unbilled revenue 53,057 ( 11,512 ) 23,074 
+Accounts receivable and unbilled revenue—related party 9,629 5,510 ( 11,096 ) 
+Inventories 2,137 ( 30,476 ) ( 4,610 ) 
+Other assets 13,780 ( 6,464 ) ( 32,771 ) 
+Accounts payable and accrued liabilities ( 15,282 ) 22,386 ( 26,798 ) 
+Accounts payable and accrued liabilities—related party — ( 1,000 ) 300 
+Payment of operating lease liability ( 895 ) ( 5,469 ) — 
+Net cash provided by operating activities 85,425 261,100 351,258 
+Cash flows from investing activities: 
+Capital expenditures ( 103,637 ) ( 195,173 ) ( 258,835 ) 
+Proceeds from disposal of assets 3,368 826 3,343 
+Net cash used in investing activities ( 100,269 ) ( 194,347 ) ( 255,492 ) 
+Cash flows from financing activities: 
+Proceeds from issuance of Class A Common Stock, net of underwriter discount — — 230,174 
+Redemption of LLC Units from Legacy Owners — — ( 25,897 ) 
+Repayments of borrowings on term loan ( 1,750 ) ( 1,750 ) ( 62,847 ) 
+Repayments of borrowings on line-of-credit — — ( 30,000 ) 
+Proceeds from Liberty Oilfield Services Holdings LLC — — 2,115 
+Payments on finance lease obligations ( 11,663 ) ( 12,143 ) — 
+Class A Common Stock dividends ( 4,431 ) ( 14,776 ) ( 6,907 ) 
+Per unit distributions to non-controlling interest unitholders ( 1,532 ) ( 7,747 ) ( 4,671 ) 
+Other distributions and advance payments to non-controlling interest unitholders ( 6,800 ) ( 6 ) ( 21,288 ) 
+Tax withholding on restricted stock unit vesting ( 988 ) ( 1,039 ) — 
+Share repurchases — ( 18,398 ) ( 82,903 ) 
+Payments of debt issuance costs ( 63 ) — ( 315 ) 
+Payment of equity offering costs ( 1,641 ) ( 1,516 ) ( 6,236 ) 
+Net cash used in financing activities ( 28,868 ) ( 57,375 ) ( 8,775 ) 
+Net (decrease) increase in cash and cash equivalents ( 43,712 ) 9,378 86,991 
+Cash and cash equivalents—beginning of period 112,690 103,312 16,321 
+Cash and cash equivalents—end of period $ 68,978 $ 112,690 $ 103,312 
+Supplemental disclosure of cash flow information: 
+Net cash (received) paid for income taxes $ ( 9,653 ) $ 1,042 $ 27,263 
+Cash paid for interest $ 11,218 $ 12,642 $ 13,957 
+Non-cash investing and financing activities: 
+Capital expenditures included in accounts payable and accrued liabilities $ 10,920 $ 32,143 $ 45,703 
+Equity issued in exchange for assets and liabilities $ 683,822 $ — $ — 
+See Notes to Consolidated and Combined Financial Statements. 
+F-8 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Note 1— Organization and Basis of Presentation 
+Organization 
+Liberty Oilfield Services Inc. (the “Company”) was incorporated as a Delaware corporation on December 21, 2016, to become a holding corporation for Liberty Oilfield Services New HoldCo LLC (“Liberty LLC”) and its subsidiaries upon completion of a corporate reorganization (the “Corporate Reorganization”) and planned initial public offering of the Company (“IPO”). The Company has no material assets other than its ownership in Liberty LLC. Prior to the Corporate Reorganization, Liberty Oilfield Services Holdings LLC (“Liberty Holdings”) wholly owned Liberty Oilfield Services LLC (“LOS”) and LOS Acquisition CO I LLC (“ACQI” and, together with LOS, the “Predecessor”). 
+The Company, together with its subsidiaries, is a multi-basin provider of hydraulic fracturing services and goods, with a focus on deploying the latest technologies in the technically demanding oil and gas reservoirs in which it operates, principally in North Dakota, Colorado, Louisiana, Oklahoma, New Mexico, Wyoming, Texas and the provinces of Alberta and British Columbia, Canada. 
+Basis of Presentation 
+The accompanying consolidated and combined financial statements were prepared using generally accepted accounting principles in the United States of America (“GAAP”) and the instructions to Form 10-K, Regulation S-X and the rules and regulations of the Securities and Exchange Commission. 
+The accompanying consolidated and combined financial statements and related notes present the consolidated financial position, results of operations, cash flows, and equity of the Company as of and for the years ended December 31, 2020 and 2019, and the combined results of operations and cash flows of the Predecessor for the year ended December 31, 2018. 
+All intercompany amounts have been eliminated in the presentation of the consolidated financial statements of the Company and the combined financial statements of the Predecessor. Comprehensive income is not reported due to the absence of items of other comprehensive income or loss during the periods presented. 
+The consolidated and combined financial statements for periods prior to January 17, 2018, reflect the historical results of the Predecessor. The consolidated and combined financial statements include the amounts of the Company and all majority owned subsidiaries where the Company has the ability to exercise control. 
+The Company’s operations are organized into a single reportable segment, which consists of hydraulic fracturing services and goods. 
+Note 2— Significant Accounting Policies 
+Business Combinations 
+Business combinations are accounted for using the acquisition method of accounting in accordance with the Accounting Standard Codification (“ASC”) Topic 805 - Business Combinations, as amended by Accounting Standards Update (“ASU”) 2017-01, Business Combinations (Topic 805), Clarifying the Definition of a Business. The purchase price is allocated to the assets acquired and liabilities assumed based on their estimated fair values. Fair value of the acquired assets and liabilities is measured in accordance with the guidance of ASC 850, Fair Value Measurements, using discounted cash flows and other applicable valuation techniques. Any acquisition related costs incurred by the Company are expensed as incurred. Any excess purchase price over the fair value of the net identifiable assets acquired is recorded as goodwill if the definition of a business is met. Operating results of an acquired business are included in our results of operations from the date of acquisition. Refer to Note 3—The OneStim Acquisition. 
+Use of Estimates 
+The preparation of consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 
+The consolidated and combined financial statements include certain amounts that are based on management’s best estimates and judgments. The most significant estimates relate to the fair value of assets acquired and liabilities assumed, collectibility of accounts receivable and estimates of allowance for doubtful accounts, the useful lives and salvage values of 
+F-9 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+long-lived assets, future cash flows associated with long-lived assets, net realizable value of inventory, and equity unit valuation. These estimates may be adjusted as more current information becomes available. 
+Cash and Cash Equivalents 
+The Company considers all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. The Company continually monitors its positions with, and the credit quality of, the financial institutions with which it has banking relationships. As of the balance sheet date, and periodically throughout the year, the Company has maintained balances in various operating accounts in excess of federally insured limits. 
+Accounts Receivable 
+On January 1, 2020, the Company adopted ASU 2016-13, Financial Instruments-Credit Losses (Topic 326) : Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”) using the modified-retrospective approach, which allows for a cumulative-effect adjustment to the consolidated balance sheet as of the beginning of the first reporting period in which the guidance is effective. Periods prior to the adoption date that are presented for comparative purposes are not adjusted. 
+The Company applies historic loss factors to its receivable portfolio segments that were not expected to be further impacted by current economic developments, and additional economic conditions factor to portfolio segments anticipated to experience greater losses in the current economic environment. Additionally, the Company continuously evaluates customers based on risk characteristics, such as historical losses and current economic conditions. Due to the cyclical nature of the oil and gas industry, the Company often evaluates its customers’ estimated losses on a case-by-case basis. While there was no impact to the financial statements as a result of adoption of ASU 2016-13, as a result of deteriorating economic conditions for the oil and gas industry brought on by the COVID-19 pandemic, during the year ended December 31, 2020 the Company recorded a provision for credit losses of $ 4.9 million. During the year ended December 31, 2019 the Company recorded a provision for credit losses of $ 1.1 million related to one customer that filed for bankruptcy. Provisions for credit losses are included in general and administrative expenses in the accompanying consolidated statement of operations, in accordance with the new standard. Refer to “Credit Risk” within Note 8—Fair Value Measurements and Financial Instruments for additional disclosures required under ASU 2016-13. 
+Inventories 
+Inventories consist of raw materials used in the hydraulic fracturing process, such as proppants, chemicals, and field service equipment maintenance parts and other and are stated at the lower of cost, determined using the weighted average cost method, or net realizable value. Inventories are charged to cost of services as used when providing hydraulic fracturing services. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable cost of completion, disposal, and transportation. 
+Property and Equipment 
+Property and equipment are stated at cost. Depreciation and amortization expense is recognized on property and equipment, excluding land, utilizing the straight-line method over the estimated useful lives, ranging from two to 30 years. The Company estimates salvage values that it does not depreciate. 
+Construction in-progress, a component of property and equipment, represents long-lived assets not yet in service or being developed by the Company. These assets are not subject to depreciation until they are completed and ready for their intended use, at which point the Company reclassifies them to field services equipment or vehicles, as appropriate. 
+The Company assesses its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is assessed using undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets. The Company determined the lowest level of identifiable cash flows to be at the asset group, which is the aggregate of the Company’s hydraulic fracturing fleets that are in service. A long-lived asset is not recoverable if its carrying amount exceeds the sum of estimated undiscounted cash flows expected to result from the use and eventual disposition. When alternative courses of action to recover the carrying amount of the asset group are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the asset is not recoverable, an impairment loss is recognized in an amount by which its carrying amount exceeds its estimated fair value, such that its carrying amount is adjusted to its estimated fair value, with an offsetting charge to impairment expense. 
+The Company measures the fair value of its property and equipment using the discounted cash flow method. The expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments of projected revenue growth, fleet count, utilization, gross margin rates, selling, general and administrative rates, working capital fluctuations, capital expenditures, discount rates and terminal growth rates. 
+F-10 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+During the first quarter of 2020, as a result of negative market indicators including the COVID-19 pandemic, the increased supply of low-priced oil, and customer cancellations, the Company concluded these triggering events could indicate possible impairment of property and equipment. The Company performed a quantitative and qualitative impairment analysis and determined that no impairment had occurred as of March 31, 2020. As of December 31, 2020, the Company concluded that no additional triggering events occurred and the conclusion reached at March 31, 2020 is still appropriate, and no impairment was recognized during the year ended December 31, 2020. 
+During 2019 and 2018, the Company did not test its long-lived assets for recoverability as there were no triggering events. No impairment was recognized during the years ended December 31, 2019 and 2018 . 
+Major Maintenance Activities 
+The Company incurs maintenance costs on its major equipment. The determination of whether an expenditure should be capitalized or expensed requires management judgment in the application of how the costs incurred benefit future periods, relative to the Company’s capitalization policy. Costs that either establish or increase the efficiency, productivity, functionality or life of a fixed asset are capitalized and depreciated over the remaining useful life of the asset. 
+Leases 
+On January 1, 2019, the Company adopted Accounting Standards Update (“ASU”) No. 2016-02, Leases (Accounting Standard Codification (“ASC”) Topic 842), as amended by other ASUs issued since February 2016 (“ASU 2016-02” or “ASC Topic 842”), using the modified retrospective transition method applied at the effective date of the standard. By electing this optional transition method, information prior to January 1, 2019 has not been restated and continues to be reported under the accounting standards in effect for the period (ASC Topic 840). 
+In accordance with ASC Topic 842, the Company determines if an arrangement is a lease at inception and evaluates identified leases for operating or finance lease treatment. Operating or finance lease right-of-use assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. The Company uses the rate implicit in the lease, when available, or an estimated fully collateralized incremental borrowing rate corresponding with the lease term and the information available at the commencement date in determining the present value of lease payments. Lease terms may include options to renew, however, the Company typically cannot determine its intent to renew a lease with reasonable certainty at inception. 
+Deferred Financing Costs 
+Costs associated with obtaining debt financing are deferred and amortized to interest expense using the effective interest method. In accordance with ASU No. 2015-03 and 2015-15, for all periods the Company has reflected deferred financing costs related to term loan debt as a direct deduction from the carrying amount, and costs associated with line-of-credit arrangements as other assets. 
+Income Taxes 
+Following the IPO, the Company is a corporation and is subject to U.S. federal, state and local income tax on its share of Liberty LLC’s taxable income. As a result of the IPO and Corporate Reorganization, the Company recorded deferred tax assets and liabilities for the difference between the book value of assets and liabilities for financial reporting purposes and those amounts applicable for income tax purposes. 
+Deferred income taxes are computed using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Deferred tax assets and liabilities are calculated using the enacted tax rates in effect for the year in which the deferred tax asset or liability is expected to reverse. The Company classifies all deferred tax assets and liabilities as non-current. 
+The Company recognizes the financial statement effects of a tax position when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. Previously recognized tax positions are reversed in the first period in which it is no longer more-likely-than-not that the tax position would be sustained upon examination. Income tax related interest and penalties, if applicable, are recorded as a component of the provision for income tax expense. 
+F-11 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Tax Receivable Agreements 
+In connection with the IPO, on January 17, 2018, the Company entered into two Tax Receivable Agreements (the “TRAs”) with the R/C Energy IV Direct Partnership, L.P. and certain legacy owners that continued to own Liberty LLC Units (each such person and any permitted transferee, a “Tax Receivable Agreement Holder” and together, the “Tax Receivable Agreement Holders”). The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that the Company actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result, as applicable to each Tax Receivable Agreement Holder, of (i) certain increases in tax basis that occur as a result of the Company’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such Tax Receivable Agreement Holder’s Liberty LLC Units in connection with the IPO or pursuant to the exercise of the right (the “Redemption Right”) or the Company’s right (the “Call Right”), (ii) any net operating losses available to the Company as a result of the Corporate Reorganization, and (iii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRAs. 
+With respect to obligations the Company expects to incur under the TRAs (except in cases where the Company elects to terminate the TRAs early, the TRAs are terminated early due to certain mergers, asset sales, or other changes of control or the Company has available cash but fails to make payments when due), generally the Company may elect to defer payments due under the TRAs if the Company does not have available cash to satisfy its payment obligations under the TRAs or if its contractual obligations limit its ability to make such payments. Any such deferred payments under the TRAs generally will accrue interest. In certain cases, payments under the TRAs may be accelerated and/or significantly exceed the actual benefits, if any, the Company realizes in respect of the tax attributes subject to the TRAs. The Company accounts for amounts payable under the TRAs in accordance with ASC Topic 450, Contingencies . 
+If the Company experiences a change of control (as defined under the TRAs) or the TRAs otherwise terminate early, the Company’s obligations under the TRAs could have a substantial negative impact on its liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. 
+Share Repurchases 
+The Company accounts for the purchase price of repurchased Class A Common Stock in excess of par value ($ 0.01 per share of Class A Common Stock) as a reduction of additional paid-in capital, and will continue to do so until additional paid-in capital is reduced to zero. Thereafter, any excess purchase price will be recorded as a reduction to retained earnings. 
+Revenue Recognition 
+Effective January 1, 2018, the Company adopted a comprehensive new revenue recognition standard, ASC Topic 606- Revenue from Contracts with Customers . The Company adopted the standard using a modified retrospective method. The adoption of this standard did not have a material impact to the consolidated financial position, reported revenue, results of operations or cash flows as of and for the year ended December 31, 2018. 
+Under ASC Topic 606, revenue recognition is based on the transfer of control, or the customer’s ability to benefit from the services and products in an amount that reflects the consideration expected to be received in exchange for those services and products. In recognizing revenue for services and products, the transaction price is determined from sales orders or contracts with customers. Revenue is recognized at the completion of each fracturing stage, and in most cases the price at the end of each stage is fixed, however, in limited circumstances contracts may contain variable consideration. 
+Variable consideration typically may relate to discounts, price concessions and incentives. The Company estimates variable consideration based on the amount of consideration we expect to receive. The Company accrues revenue on an ongoing basis to reflect updated information for variable consideration as performance obligations are met. 
+The Company also assesses customers’ ability and intention to pay, which is based on a variety of factors including historical payment experience and financial condition. Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30 to 45 days. 
+In connection with the adoption of ASC Topic 842, the Company determined that certain of its service revenue contracts contain a lease component. The Company elected to adopt a practical expedient available to lessors, which allows the Company to combine the lease and non-lease components and account for the combined component in accordance with the accounting treatment for the predominant component. Therefore, the Company combines the lease and service component for certain of the Company’s service contracts and continues to account for the combined component under ASC Topic 606, Revenue from Contracts with Customers. 
+F-12 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Deferred Revenue 
+From time to time, the Company may require partial payment in advance from new customers to secure credit or from existing customers in order to secure additional hydraulic fracturing services. Initially, such payments are recorded in the accompanying consolidated and combined financial statements as deferred revenue, and upon performance of the agreed services, the Company recognizes revenue consistent with its revenue recognition policy described above. As of December 31, 2020 and December 31, 2019, the Company had no amounts recorded as deferred revenue. During the year ended December 31, 2018, the Company recognized to revenue $ 9.2 million of customer prepayments initially recorded as deferred revenue. 
+Fleet Start-up and Lay-down Costs 
+The Company incurs start-up costs to commission a new fleet or district. These costs include hiring and training of personnel, and acquisition of consumable parts and tools. During 2020, as a result of declining oil prices and reduced demand from the impact of global efforts to combat COVID-19, the Company also incurred lay-down costs between the time customer work was completed and prior to personnel lay-offs or furloughs. Start-up and lay-down costs are expensed as incurred, and are reflected in general and administrative expense in the consolidated and combined statement of operations. Start-up and lay-down costs incurred during the year ended December 31, 2020 of $ 12.2 million related to the temporary lay-down and subsequent reactivation of 16 fleets for various periods during 2020. Start-up costs incurred during the years ended December 31, 2019 and 2018 of $ 4.5 million and $ 10.1 million, respectively, related to the establishment of one and three new fleets, respectively. 
+The terms and conditions of the Credit Facilities between the Company and its lenders provides for the add-back of costs or expenses incurred in connection with the acquisition, deployment and opening of any new hydraulic fracturing fleet or district in the computation of certain financial covenants. (See Note 7—Debt). 
+Transaction, Severance and Other Costs 
+The Company incurred transaction related costs in connection with the OneStim Acquisition (as defined below). Such costs include investment banking, legal, accounting and other professional services provided in connection with closing the transaction, and are expensed as incurred . 
+The Company also incurred severance and other costs related to the reduction in workforce in April 2020 and the commencement of furlough schedules for remaining employees in May 2020. Payments made to employees leaving the Company, as well as benefits paid to employees while on furlough are recorded to transaction, severance and other costs in the accompanying consolidated statements of operations for the year ended December 31, 2020. As of December 31, 2020, no employees were on furlough. 
+Reclassifications 
+Certain amounts in the prior period financial statements have been reclassified to conform to the presentation of the current period financial statements. These reclassifications had no effect on the previously reported net income. 
+Recently Adopted Accounting Standards 
+Credit Losses 
+In June 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-13, Financial Instruments-Credit Losses (Topic 326) : Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”), which changes the impairment model for most financial assets and certain other instruments. Specifically, this new guidance requires using a forward looking, expected loss model for trade and other receivables, held-to-maturity debt securities, loans, and other instruments. Under ASU 2016-13, a company recognizes, as an allowance, the estimate of lifetime expected credit losses, which is expected to result in more timely recognition of such losses. Refer to “Credit Risk” within Note 8—Fair Value Measurements and Financial Instruments for additional disclosures required under ASU 2016-13. 
+Fair Value Measurement 
+In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”), which eliminates, adds and modifies certain disclosure requirements for fair value measurements. The Company adopted ASU 2018-13 on January 1, 2020 and determined the adoption of this standard did not impact the Company’s consolidated financial statements. Refer to Note 8—Fair Value Measurements and Financial Instruments for the disclosures required under ASU 2018-13. 
+F-13 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Leases 
+In April 2020, the FASB issued FASB Staff Q&A Topic 842 and Topic 840: Accounting for Lease Concessions Related to the Effects of the COVID-19 Pandemic (the “Q&A”), which allows companies to elect to recognize the impact of COVID-19 rent concessions, including rent deferrals, within the current period, rather than recognizing these concessions as a lease modification in accordance with lease guidance, ASU No. 2016-02, Leases (ASC Topic 842) , if the total lease payments of the modified lease are substantially the same as or less than the total original lease payments. According to the Q&A, entities are to make an election to account for lease concessions related to the effects of the COVID-19 pandemic consistent with how those concessions would be accounted for under Topic 842 and ASC Topic 840, Leases as though enforceable rights and obligations for those concessions existed. The adoption of the Q&A did not have a material impact on the accompanying consolidated financial statements. 
+Recently Issued Accounting Standards 
+Simplification of Accounting for Income Taxes 
+In December 2019, the FASB issued ASU No. 2019-12, Simplification of Accounting for Income Taxes , which simplifies the accounting for income taxes by providing new guidance to reduce complexity and eliminate certain exceptions to the general approach to the income tax accounting model. The guidance is effective for annual periods beginning after December 15, 2020. The Company plans to adopt the new rules in the first quarter of 2021 and does not expect it will have a material impact on the financial statements. 
+Reference Rate Reform 
+In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform, which provides temporary optional guidance to companies impacted by the transition away from the London Interbank Offered Rate (“LIBOR”). The guidance provides certain expedients and exceptions to applying GAAP in order to lessen the potential accounting burden when contracts, hedging relationships, and other transactions that reference LIBOR as a benchmark rate are modified. This guidance is effective upon issuance and expires on December 31, 2022. The Company is currently assessing the impact of the LIBOR transition and this ASU on the Company’s consolidated financial statements. 
+Codification Improvements 
+In October 2020, the FASB issued ASU No. 2020-10, Codification Improvements, which clarifies various topics, including the addition of existing disclosure requirements to the relevant disclosure sections. This update does not change GAAP, and therefore, is not expected to result in a significant change in accounting practices. The guidance is effective for fiscal periods beginning after December 15, 2020, as the amendment pertains to disclosure items only, the Company plans to adopt the new rules for the first quarter of 2021. 
+F-14 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Note 3— The OneStim Acquisition 
+On August 31, 2020 the Company and certain of its subsidiaries entered into the certain Master Transaction Agreement (the “Transaction Agreement”) with Schlumberger Technology Corporation and Schlumberger Canada Limited (collectively “Schlumberger”), pursuant to which the Company acquired certain assets and liabilities of Schlumberger’s OneStim® business, which provides hydraulic fracturing pressure pumping services in onshore United States and Canada (such entire business of Schlumberger “OneStim,” and the portion of OneStim acquired pursuant to the Transaction Agreement the “Transferred Business”) in exchange for 57,377,232 shares of Class A Common Stock and a non-interest bearing demand promissory note (the “Canadian Buyer Note” and such acquisition, the “OneStim Acquisition”). The Canadian Buyer Note was settled for 8,948,902 shares of Class A Common Stock, and a total of 66,326,134 shares of Class A Common Stock were issued in connection with the OneStim Acquisition. Effective December 31, 2020, Schlumberger owns 37.0 % of the Company’s issued and outstanding shares of common stock, including Class A Common Stock and Class B Common Stock. In connection with the issuance of 66,326,134 shares of Class A Common Stock, Liberty LLC also issued 66,326,134 Liberty LLC Units to the Company. 
+The OneStim Acquisition was completed for total consideration of approximately $ 683.8 million based on the value of the Canadian Buyer Note and the closing price of Liberty’s Class A Common Stock on December 31, 2020. The Company accounted for the OneStim Acquisition using the acquisition method of accounting. The aggregate purchase price noted above was allocated to the major categories of assets acquired and liabilities assumed based upon their estimated fair value at the date of the acquisition. The estimated fair values of certain assets and liabilities, including accounts receivable, require significant judgments and estimates. The majority of the measurements of assets acquired and liabilities assumed, are based on inputs that are not observable in the market and thus represent Level 3 inputs. 
+In accordance with ASC Topic 805, an acquirer is allowed a period, referred to as the measurement period, in which to complete its accounting for the transaction. Such measurement period ends at the earliest date that the acquirer a) receives the information necessary or b) determines that it cannot obtain further information, and such period may not exceed one year. As the OneStim Acquisition closed on December 31, 2020 the Company is in the process of completing the initial purchase price allocation, particularly as it relates to current assets and current liabilities, which are subject to certain minimum working capital contribution requirements under the Transaction Agreement. Such minimum working capital contribution calculations are subject to review and adjustment in order to determine final settlement. In addition, certain inventories are considered provisional until the Company has completed physical inventory counts at each warehouse. 
+The following table summarizes the fair value of the consideration transferred in the OneStim Acquisition and the preliminary allocation of the purchase price to the fair value of the assets acquired and liabilities assumed as of December 31, 2020, the date of the closing of the OneStim Acquisition: 
+($ in thousands) 
+Total Purchase Consideration: 
+Consideration $ 683,822 
+Accounts receivable and unbilled revenue $ 128,602 
+Inventories 33,245 
+Prepaid and other current assets 30,859 
+Property and equipment (1) 
+559,716 
+Intangible assets (included in other assets in the accompanying consolidated balance sheet as of December 31, 2020) (2) 
+54,000 
+Total identifiable assets acquired 806,422 
+Accounts payable 75,522 
+Accrued liabilities 47,078 
+Total liabilities assumed 122,600 
+Total purchase consideration $ 683,822 
+(1) Useful lives ranging from two to greater than 25 years, see Note 5—Property and Equipment 
+(2) Definite lived intangibles with an average amortization period of five years 
+F-15 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Transaction costs, costs associated with issuing additional equity and integration costs were recognized separately from the acquisition of assets and assumptions of liabilities in the OneStim Acquisition. Transaction costs consist of legal and professional fees and pre-merger notification fees. Equity offering costs consist of expenses incurred related to the Special Meeting of Stockholders, including the costs to prepare the required filings associated with such meeting, held on November 3, 2020. Integration costs consist of expenses incurred to integrate OneStim’s operations, aligning accounting processes and procedures, and integrating its enterprise resource planning system with those of the Company. Merger and integration costs are expensed as incurred, and equity offering costs were recorded as a reduction to additional paid in capital. 
+Transaction costs were $ 8.5 million, for the year ended December 31, 2020 and are recorded as a component of transaction, severance and other costs in the accompanying consolidated statements of operations. Equity offering costs totaled $ 1.6 million for the year ended December 31, 2020 and are recorded as a reduction to additional paid in capital in the accompanying consolidated balance sheets. 
+The following combined pro forma information assumes the OneStim Acquisition occurred on January 1, 2020. The pro forma information presented below is for illustrative purposes only and does not reflect future events that occurred after December 31, 2020 or any operating efficiencies of inefficiencies that may result from the OneStim Acquisition. Additionally, the pro forma information excludes acquisition related costs incurred by the Company of approximately $ 8.5 million for the year ended December 31, 2020. The information is not necessarily indicative of results that would have been achieved had the Company controlled OneStim during the periods presented. 
+Years ended December 31, 
+(unaudited, in thousands) 2020 2019 
+Revenue $ 2,191,894 $ 5,174,346 
+Net loss ( 1,052,807 ) ( 1,074,735 ) 
+Less: Net loss attributable to non-controlling interests ( 196,020 ) ( 285,178 ) 
+Net loss attributable to Liberty Oilfield Services Inc. stockholders $ ( 856,787 ) $ ( 789,557 ) 
+Net loss attributable to Liberty Oilfield Services Inc. stockholders per common share: 
+Basic $ ( 5.65 ) $ ( 5.69 ) 
+Diluted $ ( 5.65 ) $ ( 5.69 ) 
+Weighted average common shares outstanding: 
+Basic 151,568 138,660 
+Diluted 151,568 138,660 
+The Company’s consolidated statements of operations for the year ended December 31, 2020 does not include any results from OneStim operations as the OneStim Acquisition closed on December 31, 2020. 
+F-16 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Note 4— Inventories 
+Inventories consist of the following: 
+December 31, 
+($ in thousands) 2020 2019 
+Proppants $ 13,658 $ 14,013 
+Chemicals 16,434 10,076 
+Maintenance parts 88,476 64,458 
+$ 118,568 $ 88,547 
+During the years ended December 31, 2020 and December 31, 2019, the lower of cost or net realizable value analysis resulted in the Company recording a write-down to inventory carrying values of $ 1.1 million and $ 2.0 million, respectively, included as a component in cost of services in the consolidated statements of operations. 
+Note 5— Property and Equipment 
+Property and equipment consist of the following: 
+Estimated 
+useful lives 
+(in years) December 31, 
+2020 2019 
+($ in thousands) 
+Land N/A $ 38,346 $ 5,400 
+Field services equipment 
+2 - 7 
+1,249,933 978,418 
+Vehicles 
+4 - 7 
+59,741 60,290 
+Buildings and facilities 
+5 - 30 
+156,109 29,930 
+Mineral reserves 
+> 25 
+78,793 — 
+Office equipment and furniture 
+2 - 7 
+6,840 6,623 
+1,589,762 1,080,661 
+Less accumulated depreciation and amortization ( 622,530 ) ( 455,687 ) 
+967,232 624,974 
+Construction in-progress N/A 153,718 26,729 
+$ 1,120,950 $ 651,703 
+During the years ended December 31, 2020, 2019 and 2018, the Company recognized depreciation expense of $ 169.9 million, $ 153.6 million and $ 124.9 million respectively. 
+During the year ended December 31, 2020, as a result of negative market indicators including the COVID-19 pandemic, the increased supply of low-priced oil, and customer cancellations, the Company concluded these triggering events could indicate possible impairment of property and equipment. The Company performed a quantitative and qualitative impairment analysis and determined that no impairment had occurred as of March 31, 2020. As of December 31, 2020, the Company concluded that no additional triggering events occurred and the conclusion reached at March 31, 2020 is still appropriate. Such analysis required management to make estimates and assumptions based on historical data and consideration of future market conditions. Given the uncertainty inherent in any projection, heightened by the possibility of unforeseen additional effects of COVID-19, actual results may differ from the estimates and assumptions used, or conditions may change, which could result in impairment charges in the future. 
+In November 2018, one of the Company’s hydraulic frac fleets was involved in an accidental fire, which resulted in damage to a portion of the equipment in that fleet. The Company accrued $ 15.7 million of insurance proceeds for replacement cost of the damaged equipment, which is presented in prepaid and other current assets on the accompanying consolidated balance sheets as of December 31, 2018. The accrued insurance proceeds offset the $ 4.3 million loss recognized on the damaged equipment. The resulting net gain of $ 11.5 million was recognized in (gain) loss on disposal of assets for the year ended December 31, 2018. 
+F-17 
+Note 6— Leases 
+The Company has operating and finance leases primarily for vehicles, equipment, railcars, office space, and facilities. The terms and conditions for these leases vary by the type of underlying asset. 
+Certain leases include variable lease payments for items such as property taxes, insurance, maintenance, and other operating expenses associated with leased assets. Payments that vary based on an index or rate are included in the measurement of lease assets and liabilities at the rate as of the commencement date. All other variable lease payments are excluded from the measurement of lease assets and liabilities, and are recognized in the period in which the obligation for those payments is incurred. 
+The components of lease expense for the years ended as of December 31, 2020, and 2019 were as follows: 
+($ in thousands) 2020 2019 
+Finance lease cost: 
+Amortization of right-of-use assets $ 8,115 $ 10,256 
+Interest on lease liabilities 1,770 2,652 
+Operating lease cost 25,817 20,731 
+Variable lease cost 2,935 3,118 
+Sublease (income) ( 113 ) — 
+Total lease cost, net $ 38,524 $ 36,757 
+In accordance with prior guidance, ASC 840, Leases , total rent expense was $ 40.9 million for the year ended December, 31, 2018. 
+Supplemental cash flow and other information related to leases as of December 31, 2020 and 2019 were as follows: 
+($ in thousands) 2020 2019 
+Cash paid for amounts included in measurement of liabilities: 
+Operating leases $ 23,612 $ 20,849 
+Finance leases 13,433 14,795 
+Right-of-use assets upon adoption of ASC 842 and obtained in exchange for new lease liabilities: 
+Operating leases 29,663 70,611 
+Finance leases 10,921 65,333 
+During the year ended December 31, 2020, the Company amended certain finance leases, the change in terms of which caused the leases to be reclassified to operating leases. In connection with the amendments, the Company wrote-off finance lease right-of-use assets and liabilities of $ 22.5 million and $ 19.0 million, respectively, and recognized operating lease right-of-use assets and liabilities of $ 18.6 million and $ 15.1 million, respectively. There was no gain or loss recognized as a result of these amendments. 
+Lease terms and discount rates as of December 31, 2020 and 2019 were as follows: 
+December 31, 2020 December 31, 2019 
+Weighted-average remaining lease term: 
+Operating leases 5.9 years 6.4 years 
+Finance leases 1.5 years 1.3 years 
+Weighted-average discount rate: 
+Operating leases 4.8 % 5.4 % 
+Finance leases 5.8 % 5.2 % 
+F-18 
+Future minimum lease commitments as of December 31, 2020 are as follows: 
+($ in thousands) Finance Operating 
+2021 $ 21,270 $ 26,546 
+2022 8,298 18,773 
+2023 4,163 8,424 
+2024 — 5,750 
+2025 — 4,155 
+Thereafter — 21,980 
+Total lease payments 33,731 85,628 
+Less imputed interest ( 1,833 ) ( 11,717 ) 
+Total $ 31,898 $ 73,911 
+The Company’s vehicle leases typically include a residual value guarantee. For the Company’s vehicle leases classified as operating leases, the total residual value guaranteed as of December 31, 2020 is $ 8.7 million; the payment is not probable and therefore has not been included in the measurement of the lease liability and right-of-use asset. For vehicle leases that are classified as finance leases, the Company includes the residual value guarantee, estimated in the lease agreement, in the financing lease liability. 
+Note 7— Debt 
+Debt consists of the following: 
+December 31, 
+2020 2019 
+Term Loan Outstanding $ 108,215 $ 109,966 
+Revolving Line of Credit — — 
+Deferred financing costs and original issue discount ( 2,440 ) ( 3,826 ) 
+Total debt, net of deferred financing costs and original issue discount $ 105,775 $ 106,140 
+Current portion of long-term debt, net of discount $ 364 $ 409 
+Long-term debt, net of discount and current portion 105,411 105,731 
+$ 105,775 $ 106,140 
+On September 19, 2017, the Company entered into two new credit agreements for a revolving line of credit up to $ 250.0 million (the “ABL Facility”) and a $ 175.0 million term loan (the “Term Loan Facility”, and together with the ABL Facility the “Credit Facilities”). 
+ABL Facility 
+Under the terms of the ABL Facility, up to $ 250.0 million may be borrowed, subject to certain borrowing base limitations based on a percentage of eligible accounts receivable and inventory. On May 29, 2020 the Company amended the ABL Facility to allow accounts receivables that are more than 90 but less than 120 days past their original invoice date to be included in the determination of eligible accounts receivables, up to a limit of $ 37.5 million when combined with receivables that are more than 60 but less than 90 days past their due date to be included in the borrowing base. The expanded borrowing base terms were in effect from May 1, 2020 through December 31, 2020. 
+As of December 31, 2020, the borrowing base was calculated to be $ 115.1 million, and the Company had no borrowings outstanding, except for a letter of credit in the amount of $ 0.8 million, with $ 114.3 million of remaining availability. Borrowings under the ABL Facility bear interest at LIBOR or a base rate, plus an applicable LIBOR margin of 1.5 % to 2.0 % or base rate margin of 0.5 % to 1.0 %, as defined in the ABL Facility credit agreement. The unused commitment is subject to an unused commitment fee of 0.375 % to 0.5 %. Interest and fees are payable in arrears at the end of each month, or, in the case of LIBOR loans, at the end of each interest period. The ABL Facility matures on the earlier of (i) September 19, 2022, and (ii) to the extent the debt under the Term Loan Facility remains outstanding, 90 days prior to the final maturity of the Term Loan Facility, which matures on September 19, 2022. Borrowings under the ABL Facility are collateralized by accounts receivable 
+F-19 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+and inventory, and further secured by the Company, Liberty LLC and R/C IV Non-U.S. LOS Corp., a Delaware corporation and a subsidiary of the Company, as parent guarantors. 
+Term Loan Facility 
+The Term Loan Facility provides for a $ 175.0 million term loan, of which $ 108.2 million remained outstanding as of December 31, 2020. Amounts outstanding bear interest at LIBOR or a base rate, plus an applicable margin of 7.625 % or 6.625 %, respectively, and the weighted average rate on borrowings was 8.6 % as of December 31, 2020. The Company is required to make quarterly principal payments of 1 % per annum of the outstanding principal balance, commencing on December 31, 2017, with final payment due at maturity on September 19, 2022. The Term Loan Facility is collateralized by the fixed assets of LOS and its subsidiaries, and is further secured by the Company, Liberty LLC and R/C IV Non-U.S. LOS Corp., a Delaware corporation and a subsidiary of the Company, as parent guarantors. 
+The Credit Facilities include certain non-financial covenants, including but not limited to restrictions on incurring additional debt and certain distributions. Moreover, the ability of the Company to incur additional debt and to make distributions is dependent on maintaining a maximum leverage ratio. The Term Loan Facility requires mandatory prepayments upon certain dispositions of property or issuance of other indebtedness, as defined, and annually a percentage of excess cash flow ( 25 % to 50 %, depending on leverage ratio, of consolidated net income less capital expenditures and other permitted payments, commencing with the year ending December 31, 2018). Certain mandatory prepayments and optional prepayments are subject to a prepayment premium of 3 % of the prepaid principal declining annually to 1 % during the first three years of the term of the Term Loan Facility. 
+The Credit Facilities are not subject to financial covenants unless liquidity, as defined in the respective credit agreements, drops below a specified level. Under the ABL Facility, the Company is required to maintain a minimum fixed charge coverage ratio, as defined in the credit agreement governing the ABL Facility, of 1.0 to 1.0 for each period if excess availability is less than 10 % of the borrowing base or $ 12.5 million, whichever is greater. Under the Term Loan Facility, the Company is required to maintain a minimum fixed charge coverage ratio, as defined, of 1.2 to 1.0 for each trailing twelve-month period if the Company’s liquidity, as defined, is less than $ 25.0 million for at least five consecutive business days. 
+The Company was in compliance with these covenants as of December 31, 2020. 
+Maturities of debt are as follows: 
+($ in thousands) 
+Years Ending December 31, 
+2021 $ 1,750 
+2022 106,465 
+2023 — 
+2024 — 
+2025 — 
+$ 108,215 
+Note 8— Fair Value Measurements and Financial Instruments 
+The fair values of the Company’s assets and liabilities represent the amounts that would be received to sell those assets or that would be paid to transfer those liabilities in an orderly transaction at the reporting date. These fair value measurements maximize the use of observable inputs. However, in situations where there is little, if any, market activity for the asset or liability at the measurement date, the fair value measurement reflects the Company’s own judgments about the assumptions that market participants would use in pricing the asset or liability. The Company discloses the fair values of its assets and liabilities according to the quality of valuation inputs under the following hierarchy: 
+• Level 1 Inputs: Quoted prices (unadjusted) in an active market for identical assets or liabilities. 
+• Level 2 Inputs: Inputs other than quoted prices that are directly or indirectly observable. 
+• Level 3 Inputs: Unobservable inputs that are significant to the fair value of assets or liabilities. 
+The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those that are initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from unobservable inputs is inconsequential to the overall fair value, or if corroborated market data becomes available. Assets and liabilities that are initially 
+F-20 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+reported as Level 2 are subsequently reported as Level 3 if corroborated market data is no longer available. Transfers occur at the end of the reporting period. There were no transfers into or out of Levels 1, 2 and 3 during the years ended December 31, 2020 and 2019. 
+The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, notes receivable, accounts payable, accrued liabilities, long-term debt, and finance and operating lease obligations. These financial instruments do not require disclosure by level. The carrying values of all the Company’s financial instruments included in the accompanying balance sheets approximated or equaled their fair values at December 31, 2020 and 2019. 
+• The carrying values of cash and cash equivalents, accounts receivable and accounts payable (including accrued liabilities) approximated fair value at December 31, 2020 and 2019, due to their short-term nature. 
+• The carrying value of amounts outstanding under long-term debt agreements with variable rates approximated fair value at December 31, 2020 and 2019, as the effective interest rates approximated market rates. 
+Nonrecurring Measurements 
+Certain assets and liabilities are measured at fair value on a nonrecurring basis. These items are not measured at fair value on an ongoing basis but may be subject to fair value adjustments in certain circumstances. These assets and liabilities include those acquired through the OneStim Acquisition, which are required to be measured at fair value on the acquisition date in accordance with ASC Topic 805 . See Note 3—The OneStim Acquisition. 
+Other assets measured at fair value on a nonrecurring basis consist of notes receivable—related party from the Affiliate, as defined and described in Note 13—Related Party Transactions. The note was initially recorded for the trade receivables, created in the normal course of business, due from the Affiliate as of the Agreement Date, as defined in Note 13—Related Party Transactions. There were no identified events or changes in circumstances that had a significant adverse effect on the fair value of the notes receivable. These notes are classified as Level 3 in the fair value hierarchy as the inputs to the determination of fair value are based upon unobservable inputs. As of December 31, 2020 and December 31, 2019, notes receivable—related party from the Affiliate totaled $ 0 and $ 2.5 million, respectively. 
+Recurring Measurements 
+The fair values of the Company’s cash equivalents measured on a recurring basis pursuant to ASC 820-10 Fair Value Measurements and Disclosures are carried at estimated fair value. Cash equivalents consist of money market accounts which the Company has classified as Level 1 given the active market for these accounts. As of December 31, 2020 and 2019, the Company had cash equivalents, measured at fair value, of $ 21.3 million and $ 86.9 million, respectively. 
+Nonfinancial assets 
+The Company estimates fair value to perform impairment tests as required on long-lived assets. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3 in the event that such assets were required to be measured and recorded at fair value within the consolidated financial statements. Although a triggering event occurred during the year ended December 31, 2020 (see Note 5—Property and Equipment), no such measurements were required as of December 31, 2020 and 2019. 
+Credit Risk 
+The Company’s financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents, and trade receivables. 
+The Company’s cash and cash equivalents balance on deposit with financial institutions total $ 69.0 million and $ 112.7 million as of December 31, 2020 and 2019, respectively, which, as of certain dates, exceeded FDIC insured limits. The Company regularly monitors these institutions’ financial condition. 
+The majority of the Company’s customers have payment terms of 45 days or less. The Company mitigates the associated credit risk by performing credit evaluations and monitoring the payment patterns of its customers. Concentrations of receivables and revenues were as follows: 
+F-21 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Portion of total of consolidated accounts receivable and unbilled revenue as of December 31, Portion of consolidated revenues for the year ended December 31, 
+2020 2019 2020 2019 2018 
+Customer A 11 % — % 12 % — % — % 
+Customer B 11 % — % 11 % — % — % 
+Customer C — % 12 % 10 % — % — % 
+Customer D — % — % 10 % — % — % 
+Customer E — % — % — % — % 11 % 
+As of December 31, 2020, the Company had $ 0.8 million in allowance for credit losses. Subsequent to the adoption of ASU 2016-13 (see “Credit Losses” within Note 2—Significant Accounting Policies— Recently Adopted Accounting Standards ) on January 1, 2020, the Company recognized a $ 4.9 million allowance for credit losses, to the Company’s accounts receivables in consideration of both historic collection experience and the expected impact of deteriorating economic conditions for the oil and gas industry at the time, and one customer that entered bankruptcy proceedings during the year. 
+The Company applied historic loss factors to its receivable portfolio segments that were not expected to be further impacted by current economic developments, and an additional economic conditions factor to portfolio segments anticipated to experience greater losses in the current economic environment. While the Company has not experienced significant credit losses in the past and did not see during 2020 material changes to the payment patterns of its customers, the Company cannot predict with any certainty the degree to which the ongoing impacts of COVID-19, including the potential impact of periodically adjusted borrowing base limits, level of hedged production, or unforeseen well shut-ins may affect the ability of its customers to timely pay receivables when due. Accordingly, in future periods, the Company may revise its estimates of expected credit losses. 
+As of December 31, 2019, the Company recorded a provision related to one specific entity engaged in the business of oil and gas exploration and production that had filed for bankruptcy. As of December 31, 2018 the Company had no provision for credit losses. 
+($ in thousands) 2020 2019 2018 
+Allowance for credit losses, beginning of year $ 1,053 $ — $ — 
+Credit losses: 
+Current period provision 4,877 1,053 — 
+Amounts written off, net of recoveries ( 5,157 ) — — 
+Allowance for credit losses, end of year $ 773 $ 1,053 $ — 
+Note 9— Equity 
+Preferred Stock 
+As of December 31, 2020 and 2019 the Company had 10,000 shares of preferred stock authorized, par value $ 0.01 , with none issued and outstanding. If issued, each class or series of preferred stock will cover the number of shares and will have the powers, preferences, rights, qualifications, limitations and restrictions determined by the Company's board of directors, which may include, among others, dividend rights, liquidation preferences, voting rights, conversion rights, preemptive rights and redemption rights. Except as provided by law or in a preferred stock designation, the holders of preferred stock will not be entitled to vote at or receive notice of any meeting of shareholders. 
+Class A Common Stock 
+The Company had a total of 157,952,213 shares of Class A Common Stock outstanding as of December 31, 2020, none of which were restricted. As of December 31, 2019, the Company had a total of 81,885,384 shares of Class A Common Stock outstanding, which included 268,205 shares of restricted stock. Holders of Class A Common Stock are entitled to one vote per share on all matters to be voted upon by the stockholders and are entitled to ratably receive dividends when and if declared by the Company’s board of directors. 
+F-22 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Class B Common Stock 
+The Company had a total of 21,550,282 and 30,638,960 shares of Class B Common Stock outstanding as of December 31, 2020 and 2019, respectively. Holders of the Class B Common Stock are entitled to one vote per share on all matters to be voted upon by stockholders. Holders of Class A Common Stock and Class B Common Stock vote together as a single class on all matters presented to the Company’s stockholders for their vote or approval, except with respect to amendment of certain provisions of the Company’s certificate of incorporation that would alter or change the powers, preferences or special rights of the Class B Common Stock so as to affect them adversely, which amendments must be by a majority of the votes entitled to be cast by the holders of the shares affected by the amendment, voting as a separate class, or as otherwise required by applicable law. 
+Holders of Class B Common Stock do not have any right to receive dividends, unless the dividend consists of shares of Class B Common Stock or of rights, options, warrants or other securities convertible or exercisable into or exchangeable for shares of Class B Common Stock paid proportionally with respect to each outstanding share of Class B Common Stock and a dividend consisting of shares of Class A Common Stock or of rights, options, warrants or other securities convertible or exercisable into or exchangeable for shares of Class A Common Stock on the same terms is simultaneously paid to the holders of Class A Common Stock. Holders of Class B Common Stock do not have any right to receive a distribution upon liquidation or winding up of the Company. 
+Under the Second Amended and Restated Limited Liability Company Agreement of Liberty LLC (the “Liberty LLC Agreement”), each Liberty Unit Holder has, subject to certain limitations, the Redemption Right, which allows it to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units, for, at Liberty LLC’s election, (i) shares of Class A Common Stock at a redemption ratio of one share of Class A Common Stock for each Liberty LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions or (ii) an equivalent amount of cash. Alternatively, upon the exercise of the Redemption Right, the Company (instead of Liberty LLC) will have the Call Right, which allows it to, for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder for, at its election, (x) one share of Class A Common Stock or (y) an equivalent amount of cash. In addition, upon a change of control of the Company, the Company has the right to require each holder of Liberty LLC Units (other than the Company) to exercise its Redemption Right with respect to some or all of such unitholder’s Liberty LLC Units. In connection with any redemption of Liberty LLC Units pursuant to the Redemption Right or the Call Right, the corresponding number of shares of Class B Common Stock will be canceled. 
+Unit-Based Compensation 
+Prior to the IPO and Corporate Reorganization, Liberty Holdings issued Class B units of Liberty Holdings (“Legacy Units”) to certain eligible employees of the Company. The Legacy Units were non-voting, except with respect to such matters that units are entitled to vote as a matter of law. In such cases, each Legacy Unit entitled the holder to 1/1000 th of one vote. Certain Legacy Units granted to eligible participants had an assigned benchmark value and were subject to vesting in accordance with the terms of each award letter. Upon termination of the holder’s employment for any reason, Liberty Holdings had the right, but not the obligation, to repurchase from the recipient those vested Legacy Units at fair value. 
+The Company recognizes compensation expense for equity-based Legacy Units issued to employees based on the grant-date fair value of the awards and each award’s requisite service period. With the assistance from a third-party valuation expert, the Predecessor determined that the Legacy Units issued to employees were deemed to have a de minimis grant-date fair value based on their assigned benchmark values. In connection with the Corporate Reorganization, the unvested Legacy Units were exchanged for 1,258,514 shares of restricted stock with the same terms and requisite vesting conditions as the Legacy Units. All shares of restricted stock were vested as of December 31, 2020. 
+Restricted Stock Awards 
+Restricted stock awards are awards of Class A Common Stock that are subject to restrictions on transfer and to a risk of forfeitures if the award recipient is no longer an employee or director of the Company for any reason prior to the lapse of the restrictions. 
+The following table summarizes the Company’s unvested restricted stock activity for the year ended December 31, 2020: 
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+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Number of Shares 
+Grant Date Fair Value per Share (1) 
+Restricted Shares as of December 31, 2019 268,205 — 
+Vested ( 263,818 ) — 
+Forfeited ( 4,387 ) — 
+Outstanding at December 31, 2020 — $ — 
+(1) As discussed above, the shares of restricted stock retain the grant date fair value of the Legacy Units. 
+Long Term Incentive Plan 
+On January 11, 2018, the Company adopted the Long Term Incentive Plan (“LTIP”) to incentivize employees, officers, directors and other service providers of the Company and its affiliates. The LTIP provides for the grant, from time to time, at the discretion of the Company’s board of directors or a committee thereof, of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, cash awards, substitute awards and performance awards. Subject to adjustment in the event of certain transaction or changes of capitalization in accordance with the LTIP, 12,908,734 shares of Class A Common Stock have been reserved for issuance pursuant to awards under the LTIP. Class A Common stock subject to an award that expires or is canceled, forfeited, exchanged, settled in cash or otherwise terminated without delivery of shares and shares withheld to pay the exercise price of, or to satisfy the withholding obligations with respect to, an award will again be available for delivery pursuant to other awards under the LTIP. 
+Restricted Stock Units 
+Restricted stock units (“RSUs”) granted pursuant to the LTIP, if they vest, will be settled in shares of the Company’s Class A Common Stock. RSUs were granted with vesting terms up to five years . Changes in non-vested RSUs outstanding under the LTIP during the year ended December 31, 2020 were as follows: 
+Number of Units Weighted Average Grant Date Fair Value per Unit 
+Non-vested as of December 31, 2019 1,734,535 $ 16.97 
+Granted 1,449,329 7.72 
+Vested ( 935,124 ) 17.15 
+Forfeited ( 65,706 ) 11.93 
+Outstanding at December 31, 2020 2,183,034 $ 10.90 
+Performance Restricted Stock Units 
+Performance restricted stock units (“PSUs”) granted pursuant to the LTIP, if they vest, will be settled in shares of the Company’s Class A Common Stock. PSUs were granted with a three year cliff vesting schedule, subject to a performance target compared to an index of competitors ’ results over a three year period as designated in the award. The Company records compensation expense based on the Company’s best estimate of the number of PSUs that will vest at the end of the performance period. If such performance targets are not met, or are not expected to be met, no compensation expense is recognized and any recognized compensation expense is reversed. Changes in non-vested PSUs outstanding under the LTIP during the year ended December 31, 2020 were as follows: 
+Number of Units Weighted Average Grant Date Fair Value per Unit 
+Non-vested as of December 31, 2019 329,277 $ 14.93 
+Granted 392,948 9.62 
+Vested — — 
+Forfeited — — 
+Outstanding at December 31, 2020 722,225 $ 12.04 
+Stock-based compensation is included in cost of services and general and administrative expenses in the Company’s consolidated and combined statements of operations. The Company recognized stock based compensation expense of $ 17.1 million for the year ended December 31, 2020 and $ 13.6 million for the year ended December, 31, 2019. There was 
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+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+approximately $ 18.9 million of unrecognized compensation expense relating to outstanding RSUs and PSUs as of December 31, 2020. The unrecognized compensation expense will be recognized on a straight-line basis over the weighted average remaining vesting period of 2 years. 
+Dividends 
+On April 2, 2020, the Company suspended future quarterly dividends until business conditions warrant reinstatement. 
+The Company paid cash dividends of $ 0.05 per share of Class A Common Stock on March 20, 2020 to stockholders of record as of March 6, 2020. Liberty LLC paid a distribution of total of $ 5.6 million, or $ 0.05 per Liberty LLC Unit, to all Liberty LLC unit holders during the year ended December 31, 2020, of which $ 4.1 million was paid to the Company. The Company used the proceeds of the distribution to pay the dividend to all holders of shares of Class A Common Stock as of March 6, 2020, which totaled $ 4.1 million. For the year ended December 31, 2019, Liberty LLC paid quarterly distributions for a total of $ 22.5 million, or $ 0.05 per Liberty LLC Unit, to all Liberty LLC unit holders, of which $ 14.7 million was paid to the Company. The Company used the proceeds of the distributions to pay quarterly dividends to all holders of Class A Common Stock, which totaled $ 14.7 million. Additionally, as of December 31, 2020 and December 31, 2019, the Company had $ 0.4 million and $ 0.5 million of accrued dividends payable related to restricted stock and RSUs to be paid upon vesting, respectively. Dividends related to forfeited restricted stock and RSUs will be forfeited. 
+Share Repurchase Program 
+On September 10, 2018 the Company’s board of directors authorized a share repurchase plan to repurchase up to $ 100.0 million of the Company’s Class A Common Stock through September 30, 2019. On January 22, 2019, the Company’s board of directors authorized an additional $ 100.0 million under the share repurchase plan through January 31, 2021. 
+During the year ended December 31, 2020, no shares were repurchased under the share repurchase program. During the year ended December 31, 2019, Liberty LLC redeemed and retired 1,303,003 Liberty LLC Units from the Company for $ 18.4 million, and the Company repurchased and retired 1,303,003 shares of Class A Common Stock for $ 18.4 million, or $ 14.66 average price per share. 
+The repurchase in January 2019 completed the share repurchase amount authorized on September 10, 2018. During the year ended December 31, 2019, of the total amount of Class A Common Stock repurchased, 117,647 shares were repurchased from R/C Energy IV Direct Partnership, L.P., R/C IV Liberty Holdings, L.P., and Riverstone/Carlyle Energy Partners IV, L.P. (“R/C” and collectively, the “Riverstone Sellers”). During the year ended December 31, 2018, of the total amount of Class A Common Stock repurchased, 2,491,160 shares were repurchased pursuant to a Stock Purchase and Sale Agreement, dated as of September 14, 2018, by the Riverstone Sellers. For further details of this related party transaction, see Note 13—Related Party Transactions. 
+As of December 31, 2020 and 2019, $ 98.7 million remained authorized for future repurchases of Class A Common Stock under the share repurchase program, respectively. Following the expiration of the most recent authorization on January 31, 2021, no amounts remain authorized under the share repurchase plan. 
+The Company accounts for the purchase price of repurchased common shares in excess of par value ($ 0.01 per share of Class A Common Stock) as a reduction of additional paid-in capital, and will continue to do so until additional paid-in capital is reduced to zero. Thereafter, any excess purchase price will be recorded as a reduction to retained earnings. 
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+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Note 10— Net (Loss) Income per Share 
+Basic net (loss) income per share measures the performance of an entity over the reporting period. Diluted net (loss) income per share measures the performance of an entity over the reporting period while giving effect to all potentially dilutive common shares that were outstanding during the period. The Company uses the “if-converted” method to determine the potential dilutive effect of its Class B Common Stock and the treasury stock method to determine the potential dilutive effect of outstanding restricted stock and RSUs. 
+The following table reflects the allocation of net (loss) income to common stockholders and net (loss) income per share computations for the periods indicated based on a weighted average number of common stock outstanding: 
+(In thousands, except per share data) Year Ended December 31, 2020 Year Ended December 31, 2019 
+Basic Net (Loss) Income Per Share 
+Numerator: 
+Net (loss) income attributable to Liberty Oilfield Services Inc. Stockholders $ ( 115,583 ) $ 39,003 
+Denominator: 
+Basic weighted average shares outstanding 85,242 72,334 
+Basic net (loss) income per share attributable to Liberty Oilfield Services Inc. Stockholders $ ( 1.36 ) $ 0.54 
+Diluted Net (Loss) Income Per Share 
+Numerator: 
+Net (loss) income attributable to Liberty Oilfield Services Inc. Stockholders $ ( 115,583 ) $ 39,003 
+Effect of exchange of the shares of Class B Common stock for shares of Class A Common Stock — 16,521 
+Diluted net (loss) income attributable to Liberty Oilfield Services Inc. Stockholders $ ( 115,583 ) $ 55,524 
+Denominator: 
+Basic weighted average shares outstanding 85,242 72,334 
+Effect of dilutive securities: 
+Restricted stock — 512 
+Restricted stock units — 1,771 
+Class B Common Stock — 30,639 
+Diluted weighted average shares outstanding 85,242 105,256 
+Diluted net (loss) income per share attributable to Liberty Oilfield Services Inc. Stockholders $ ( 1.36 ) $ 0.53 
+Diluted weighted average common shares outstanding for the year ended December 31, 2020 exclude 27,427 weighted average shares of Class B Common Stock, 207 weighted average shares of restricted stock, and 2,460 weighted average shares of restricted stock units. Diluted weighted average common shares outstanding for the year ended December 31, 2019 exclude 9,057 weighted average shares of Class B Common Stock exchanged during the period (share counts presented in 000’s). 
+Note 11— Income Taxes 
+Prior to the IPO, the Predecessor was treated as a partnership for U.S. federal, state and local income tax purposes. As such, any liability for federal income tax was the responsibility of the members of the Predecessor. Accordingly, no provision for U.S. federal, state and local income tax has been provided in the combined financial statements of the Company for periods ending prior to the IPO. 
+Following the IPO, the Company is a corporation and is subject to U.S. federal, state and local income tax on its share of Liberty LLC’s taxable income. Liberty LLC is treated as a partnership, and its income is passed through to its owners, for income tax purposes. Liberty LLC’s members, including the Company, are liable for federal, state and local income taxes based on their share of Liberty LLC’s pass-through taxable income. As of December 31, 2020, tax reporting by the Company’s Predecessor for the years ended December 31, 2017 and 2018 is subject to examination by the tax authorities. With few exceptions, as of December 31, 2020, the Company is no longer subject to U.S. federal, state or local examinations by tax authorities for tax years ended before December 31, 2017. 
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+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Income tax (benefit) expense reflected in the consolidated statement of operations consisted of: 
+($ in thousands) Year Ended December 31, 2020 Year Ended December 31, 2019 Year Ended December 31, 2018 
+Current: 
+Federal $ ( 5,541 ) $ ( 9,907 ) $ 16,684 
+State 230 551 3,213 
+Total Current $ ( 5,311 ) $ ( 9,356 ) 19,897 
+Deferred: 
+Federal ( 23,103 ) 23,419 19,063 
+State ( 2,443 ) ( 11 ) 1,425 
+Total Deferred $ ( 25,546 ) $ 23,408 20,488 
+Income tax (benefit) expense $ ( 30,857 ) $ 14,052 40,385 
+A reconciliation of the statutory U.S. federal income tax rate of 21.0% to the Company’s effective income tax rate is as follows: 
+($ in thousands) Year Ended December 31, 2020 Year Ended December 31, 2019 Year Ended December 31, 2018 
+Federal income tax (benefit) expense at statutory rate $ ( 40,222 ) $ 18,672 $ 60,778 
+State and local income tax (benefit) expense, net ( 2,212 ) 1,525 4,456 
+Pre-IPO income before income taxes attributable to the Predecessor — — ( 1,958 ) 
+Non-controlling interest 9,463 ( 7,531 ) ( 24,606 ) 
+Stock Compensation 2,157 227 — 
+Other ( 43 ) 1,159 1,715 
+Total income tax (benefit) expense $ ( 30,857 ) $ 14,052 $ 40,385 
+The effective tax rate for the years ended December 31, 2020 and 2019 was 16.1 % and 15.8 %, respectively. The effective tax rate for the period commencing on January 17, 2018, the date of the Corporate Reorganization, through December 31, 2018 was 14.1 %. 
+The Company recognized income tax benefit of $ 30.9 million during the year ended December 31, 2020. The Company’s effective tax rate is less than the statutory federal income tax rate of 21.0% because no taxes are payable by the Company for the non-controlling interest’s share of Liberty LLC’s pass-through income for federal, state and local income tax reporting. During 2020, the non-controlling interest effect resulted in a $ 9.5 million reduction in income tax benefit. 
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+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+The tax effects of temporary differences that give rise to the deferred tax assets and deferred tax liabilities are presented below: 
+($ in thousands) December 31, 2020 December 31, 2019 
+Deferred tax assets: 
+Federal net operating losses $ 15,632 $ 10,486 
+State net operating losses 2,697 925 
+Realized tax benefit - TRAs 52,561 48,575 
+Total deferred tax assets 70,890 59,986 
+Deferred tax liabilities: 
+Investment in Liberty LLC $ ( 64,765 ) $ ( 79,099 ) 
+Other ( 765 ) ( 546 ) 
+Total deferred tax liabilities ( 65,530 ) ( 79,645 ) 
+Net deferred tax asset (liability) $ 5,360 $ ( 19,659 ) 
+As of December 31, 2020, the Company had significant deferred tax assets and liabilities. The deferred tax assets include U.S. federal and state net operating losses and the step-up in basis of depreciable assets under Section 754 of the Internal Revenue Code of 1986, as amended. As a result of the IPO and Corporate Reorganization, the Company recorded a deferred tax asset and liability for the difference between the book value and the tax value of the Company's investment in Liberty LLC. The deferred tax assets have been recorded for tax attributes contributed to the Company as part of the Corporate Reorganization. Deferred tax liabilities of $ 29.3 million were recorded relating to Liberty LLC Units acquired through the reorganization. The initial deferred tax liability is recorded as a long term liability and additional paid in capital on the consolidated balance sheet as of December 31, 2020. 
+As of December 31, 2020, the Company has available U.S. federal net operating loss carryforwards to reduce future taxable income of $ 3.7 million expiring in 2027, and $ 69.3 million with no expiration date. Per the Coronavirus Aid, Relief and Economic Security (“CARES”) Act enacted March 27, 2020, net operating losses (“NOL”) incurred in 2018, 2019, and 2020 may be carried back to each of the five preceding taxable years to generate a refund of previously paid income taxes. The Company will apply for and expects to receive a NOL carryback refund to recover $ 5.5 million of cash taxes paid by the Company in 2018. This amount has been reflected as a receivable in prepaids and other assets. 
+On December 31, 2020, the Company completed the OneStim Acquisition in a taxable exchange for 66,326,134 shares of Class A Common Stock. The Transferred Business was operated by a limited liability company that was treated as a disregarded entity for federal tax purposes prior to the acquisition date. Upon acquisition the fair market value of assets were recorded for federal tax purposes. Therefore, no goodwill and deferred taxes have been recorded related to the acquisition. See Note 3—The OneStim Acquisition for additional information regarding the OneStim Acquisition. 
+Uncertain Tax Positions 
+The Company records uncertain tax positions on the basis of a two-step process in which (1) the Company determines whether it is more likely than not the tax positions will be sustained on the basis of the technical merits of the position and (2) for those tax positions meeting the more likely than not recognition threshold, the Company recognizes the largest amount of tax benefit that is more than 50% likely to be realized upon ultimate settlement with the related tax authority. 
+The Company determined that no liability for unrecognized tax benefits for uncertain tax positions was required at December 31, 2020. In addition, the Company does not believe that it has any tax positions for which it is reasonably possible that it will be required to record a significant liability for unrecognized tax benefits within the next twelve months. If the Company were to record an unrecognized tax benefit, the Company will recognize applicable interest and penalties related to income tax matters in income tax expense. 
+Tax Distributions 
+Liberty LLC is treated as a partnership for income tax purposes. Federal, state and local taxes resulting from the pass-through taxable income of Liberty LLC are obligations of its members. Net profits and losses are generally allocated to the 
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+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+members of Liberty LLC (including the Company) in accordance with the number of Liberty LLC Units held by each member for tax purposes. The Liberty LLC Agreement provides for pro rata cash distributions, and in certain cases non-pro rata cash advances, to assist members (including the Company) in paying their income tax liabilities. The Liberty LLC Agreement requires any tax advances to be proportionally repaid in connection with any redemption of Liberty LLC Units pursuant to the Redemption Right or the Call Right. Net advances received by Liberty LLC from non-controlling interest holders were $ 1.4 million and de minimis, respectively, for the years ended December 31, 2020 and 2019. 
+Tax Receivable Agreements 
+The term of each TRA commenced on January 17, 2018, and will continue until all such tax benefits that are subject to such TRA have been utilized or expired, unless the Company experiences a change of control (as defined in the TRAs, which includes certain mergers, asset sales and other forms of business combinations) or the TRAs are terminated early (at the Company’s election or as a result of its breach), and the Company makes the termination payments specified in such TRA. 
+The amounts payable, as well as the timing of any payments, under the TRAs are dependent upon significant future events and assumptions, including the timing of the redemptions of Liberty LLC Units, the price of our Class A Common Stock at the time of each redemption, the extent to which such redemptions are taxable transactions, the amount of the redeeming unit holder’s tax basis in its Liberty LLC Units at the time of the relevant redemption, the characterization of the tax basis step-up, the depreciation and amortization periods that apply to the increase in tax basis, the amount of net operating losses available to the Company as a result of the Corporate Reorganization, the amount and timing of taxable income the Company generates in the future, the U.S. federal income tax rate then applicable, and the portion of the Company’s payments under the TRAs that constitute imputed interest or give rise to depreciable or amortizable tax basis. 
+Prior to the Corporate Reorganization, one of the Legacy Owners distributed a portion of its member interest in Liberty Holdings to R/C IV Non-U.S. LOS Corp. (“R/C IV”). Subsequently, in conjunction with the Corporate Reorganization, R/C IV was contributed to the Company. At the time of the contribution, R/C IV had net operating loss carryforwards totaling $ 10.9 million for federal income tax purposes and $ 10.9 million for certain state income tax purposes, which became available for the Company’s use as a result of the contribution. As a result of the Company being in a net income position in 2018 and the expected utilization of deferred tax assets, the Company recognized a deferred tax asset of $ 2.6 million and a corresponding $ 2.3 million liability pursuant to the TRAs. Of the contributed net operating loss carryforwards, $ 6.4 million for federal income tax purposes and $ 6.4 million of certain state income tax purposes have been utilized. As a result, the Company has remaining $ 1.5 million of deferred tax asset and a corresponding $ 1.4 million liability pursuant to the TRAs. 
+During the year ended December 31, 2020, exchanges of Liberty LLC Units and shares of Class B Common Stock resulted in an increase of $ 13.1 million in amounts payable under the TRAs, and a net increase of $ 15.5 million in deferred tax assets, all of which were recorded through equity. The Company also made TRA payments of $ 1.9 million and $ 5.5 million, totaling $ 7.4 million for the year ended December 31, 2020. The TRA payments were related to tax benefits realized in prior years and for the Company’s NOL carryback of 2019 NOL to 2018 taxable income under the CARES Act. 
+During the year ended December 31, 2019, exchanges of Liberty LLC Units and shares of Class B Common Stock resulted in an increase of $ 34.0 million in amounts payable under the TRAs, and a net increase of $ 40.0 million in deferred tax assets, all of which were recorded through equity. 
+At December 31, 2020, the Company’s liability under the TRAs was $ 56.6 million, all of which is presented as a component of long term liabilities, and the related deferred tax assets totaled $ 54.0 million. 
+Note 12— Defined Contribution Plan 
+The Company sponsors a 401(k) defined contribution retirement plan covering eligible employees. However, effective April 1, 2020, in connection with other cost savings measures undertaken in response to declining demand for frac services as a result of the impacts of the COVID-19 pandemic, the Company suspended its 6 % matching contribution. Prior to April 1, 2020, the Company made matching contributions at a rate of $ 1.00 for each $1.00 of employee contribution, subject to a cap of 6 % of the employee’s salary and federal limits. Contributions made by the Company were $ 4.2 million, $ 15.7 million, and $ 13.8 million for the years ended December 31, 2020, 2019 and 2018, respectively. 
+Effective January 1, 2021 the Company restored its 6 % matching contribution. 
+F-29 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+Note 13— Related Party Transactions 
+As of December 31, 2020 Schlumberger owns 66,326,134 shares of Class A Common Stock of the Company, or 37.0 % of the issued and outstanding shares of common stock of the Company, including Class A Common Stock and Class B Common Stock. Under the Transaction agreement, to the extent the net working capital, as defined, of the Transferred Business is less than $ 54.6 million, the difference shall be payable in cash to the Company. Additionally, the Company and Schlumberger agreed to an $ 8.0 million true-up payment related to the estimated costs to bring certain assets to full working condition. As of December 31, 2020, the Company recorded an estimated receivable from Schlumberger of $ 24.7 million related to these true-up payments. The Company collected $ 8.0 million in January 2021. Additionally, in conjunction with closing the OneStim Acquisition, the Company entered unto a transition services agreement with Schlumberger, under which Schlumberger will provide certain administrative transition services for a rate of approximately $ 2.5 million per month, until the Company fully integrates the acquired business. 
+Prior to the Corporate Reorganization, one of the members of Liberty Holdings contributed a portion of its member interest in Liberty Holdings to R/C IV Non-U.S. LOS Corp (“R/C IV”). Subsequently, in conjunction with the Corporate Reorganization, R/C IV was contributed to Liberty LLC. R/C IV had net operating loss carryforwards for federal and state income tax purposes which resulted in the recognition of a $ 2.9 million payable pursuant to the TRAs. During the years ended December 31, 2020 and December 31, 2019, R/C IV Liberty Holdings, L.P. exercised its redemption right and redeemed 4,016,965 and 9,605,786 shares of Class B Common Stock resulting in an increase in tax basis, as described in Note—11 Income Taxes— Tax Receivable Agreements , and recognition of $ 6.1 million and $ 22.3 million in amounts payable under the TRAs, respectively. As of December 31, 2020 and 2019, the Company’s current liabilities under the TRAs payable to R/C IV Liberty Holdings, L.P. and R/C IV Non-US were $ 0 and $ 1.3 million, respectively, included in accrued interest and other and non-current liabilities were $ 27.2 million and $ 23.8 million, respectively, in payable pursuant to tax receivable agreements in the accompanying condensed consolidated balance sheets. 
+In September 2011, Liberty Resources LLC, an oil and gas exploration and production company, and its successor entity (collectively, the “Affiliate”) and LOS, companies with common ownership and management, entered into a services agreement (the “Services Agreement”) whereby the Affiliate is to provide certain administrative support functions to LOS and a master service agreement whereby LOS provides hydraulic fracturing services to the Affiliate at market service rates. The amounts incurred under the Services Agreement by LOS during the years ended December 31, 2020, 2019 and 2018, were $ 0 , $ 0 million, and $ 0.2 million, respectively. The Services Agreement was terminated during June 2018. 
+The amounts of the Company’s revenue related to hydraulic fracturing services provided to the Affiliate for the years ended December 31, 2020, 2019 and 2018, were $ 0.0 million, $ 18.3 million and $ 23.1 million, respectively. As of December 31, 2020 and 2019, $ 0.0 million and $ 7.1 million, respectively, of the Company’s accounts receivable—related party was with the Affiliate. On June 24, 2019 (the “Agreement Date”), the Company entered into an agreement with the Affiliate to amend payment terms for outstanding invoices due as of the Agreement Date to be due on July 31, 2020. On September 30, 2019, the agreement was amended to extend the due date of the remaining amounts outstanding to October 31, 2020. Amounts outstanding from the Affiliate as of the Agreement Date were $ 15.6 million. The amounts outstanding, including all accrued interest was paid in full in January 2020. As of December 31, 2020 and December 31, 2019, amounts outstanding under the amended payment terms from the Affiliate were $ 0 and $ 2.5 million, all of which is presented in accounts and notes receivable—related party in the accompanying consolidated balance sheet. The balance outstanding is subject to interest at 13 % annual percent yield, retroactively applied to the respective invoice date. During the year ended December 31, 2020 and 2019, interest income from the Affiliate was $ 0.3 million and $ 1.8 million, respectively, and accrued interest as of December 31, 2020 and 2019 was $ 0 . Receivables earned for services performed after the Agreement Date continue to be subject to normal 30-day payment terms, provided that any amount unpaid after 60 days is subject to 13 % interest. 
+Liberty Holdings entered into an advisory agreement, dated December 30, 2011, with Riverstone/Carlyle Energy Partners IV, L.P. (“R/C”), in which R/C agreed to provide certain administrative advisory services to Liberty Holdings. The advisory services agreement was terminated pursuant to an agreement effective as of January 11, 2018. On January 11, 2018, Liberty Holdings, R/C and other parties entered into a Master Reorganization Agreement that, among other things, crystallized the “waterfall” provisions of Article VI of the Third Amended and Restated Limited Liability Agreement of Liberty Holdings, dated October 11, 2016 (the “Holdings LLC Agreement”), in connection with the initial public offering of shares of Class A Common Stock. As part of this crystallization, R/C and affiliated entities (collectively, the “R/C Affiliates”) received shares of Class A Common Stock, including 117,647 shares of Class A Common Stock (such 117,647 referred to as the “Issued Shares”) to compensate R/C Affiliates for certain accrued preferred returns but which would not have been issued had the $ 2.0 million in fees owing under the advisory agreement been paid in cash. Had this fee been paid in cash on or prior to January 11, 2018, R/C and Liberty Holdings acknowledge that R/C Affiliates would not have received the Issued Shares in the crystallization pursuant 
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+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+to the provisions of the Holdings LLC Agreement. Subsequently, during the fourth quarter of 2018, R/C asserted that certain provisions of the termination of services agreement provided for R/C to receive $ 2.0 million in cash as payment of those accrued fees. To resolve this matter, the Company agreed to pay R/C Affiliates $ 2.0 million in cash in exchange for the return, at the IPO price, of the Issued Shares and $ 0.3 million for interest and the settlement of the matter. Accordingly, $ 2.3 million was recorded as accrued liabilities—related party in the consolidated balance sheet as of December 31, 2018 and subsequently paid in January 2019. The returned shares of Class A Common Stock were canceled and retired, and the Company does not expect to incur future expense related to the advisory agreement or termination thereof. 
+During 2016, Liberty Holdings entered into a future commitment to invest and become a non-controlling minority member in Proppant Express Investments, LLC, the owner of Proppant Express Solutions, LLC (“PropX”), a provider of proppant logistics equipment. LOS is party to a services agreement (the “PropX Services Agreement”) whereby LOS is to provide certain administrative support functions to PropX, and LOS is to purchase and lease proppant logistics equipment from PropX. The PropX Services Agreement was terminated on May 29, 2018; however, the Company continues to lease equipment from PropX. During the years ended December 31, 2020, 2019 and 2018 for $ 8.7 million, $ 9.8 million and $ 4.4 million, respectively. 
+Payables to PropX as of December 31, 2020 and 2019 were $ 1.5 million and $ 0.8 million, respectively. 
+Note 14— Commitments & Contingencies 
+Purchase Commitments (tons are not in thousands) 
+The Company enters into purchase and supply agreements to secure supply and pricing of proppants, and related proppant transportation, as well as chemicals. As of December 31, 2020 and 2019, the agreements commit the Company to purchase 1,580,750 and 7,978,300 tons, respectively, of proppant through February 1, 2022. Amounts above also include commitments to pay for transport fees on minimum amounts of proppants. Certain proppant supply agreements contain a clause whereby in the event that the Company fails to purchase minimum volumes, as defined in the agreement, during a specific time period, a shortfall fee may apply. Additionally, related proppant transload service commitments extend through 2024. 
+Future proppant, transload and mancamp commitments are as follows: 
+Year ending December 31, 
+2021 $ 82,141 
+2022 17,823 
+2023 9,524 
+2024 10,268 
+2025 7,664 
+Thereafter — 
+$ 127,420 
+Certain supply agreements contain a clause whereby in the event that the Company fails to purchase minimum volumes, as defined in the agreement, during a specific time period, a shortfall fee may apply. In circumstances where the Company does not make the minimum purchase required under the contract, the Company and its suppliers have a history of amending such minimum purchase contractual terms and in rare cases does the Company incur shortfall fees. In the Company were unable to make any of the minimum purchases and the Company and its suppliers cannot come to an agreement to avoid such fees, the Company could incur shortfall fees in the amounts of $ 51.8 million, $ 17.9 million, $ 9.5 million, $ 10.3 million, and $ 7.7 million for the years ended 2021, 2022, 2023, 2024, and 2025, respectively. Based on forecasted levels of activity, the Company does not currently expect to incur significant shortfall fees. 
+Included in the commitments for the year ending December 31, 2021 are $ 12.3 million of payments expected to be due to Schlumberger, in conjunction with transition services provided by Schlumberger, in the first quarter of 2021 for the use of certain light duty trucks, heavy tractors and field equipment used to various degrees in OneStim’s frac and wireline operations. The Company is in negotiations with the third party owner of such equipment to lease or purchase some or all of such 
+F-31 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+aforementioned vehicles and equipment, subject to agreement on terms and conditions. No gain or loss is expected upon consummation of any such agreement. 
+Litigation 
+Securities Class Actions 
+On March 11, 2020, Marshall Cobb, on behalf of himself and all other persons similarly situated, filed a putative class action lawsuit in the state District Court of Denver County, Colorado against the Company and certain officers and board members of the Company along with other defendants in connection with the IPO (the “Cobb Complaint”). The Cobb Complaint alleges that the Company and certain officers and board members of the Company violated Section 11 of the Securities Act of 1933 by virtue of inaccurate or misleading statements allegedly contained in the registration statement filed in connection with the IPO and requests unspecified damages and costs. The Cobb Plaintiffs also allege control person liability claims under Section 15 of the Securities Act of 1933 against certain officers and board members of the Company and other defendants. 
+On April 3, 2020, Marc Joseph, on behalf of himself and all other persons similarly situated, filed a putative class action lawsuit in the United States District Court in Denver, Colorado against the Company and certain officers and board members of the Company along with other defendants in connection with the IPO and requests unspecified damages and costs (the “Joseph Complaint,” and collectively with the Cobb Complaint, the “Securities Lawsuits”). The Joseph Complaint, which is based on similar factual allegations made in the Cobb Complaint, alleges that the defendants violated Sections 11 and 12(a)(2) of the Securities Act of 1933 by virtue of inaccurate or misleading statements allegedly contained in the registration statement and prospectus filed in connection with the IPO. The Joseph Complaint also alleges control person liability claims under Section 15 of the Securities Act of 1933 against certain officers and board members of the Company and other defendants. 
+The Company has hired counsel and plans to vigorously defend against the allegations in the Securities Lawsuits. 
+Other Litigation 
+In addition to the matters described above, from time to time, the Company is subject to legal and administrative proceedings, settlements, investigations, claims and actions. The Company’s assessment of the likely outcome of litigation matters is based on its judgment of a number of factors including experience with similar matters, past history, precedents, relevant financial and other evidence and facts specific to the matter. Notwithstanding the uncertainty as to the final outcome, based upon the information currently available, management does not believe any matters in aggregate will have a material adverse effect on its financial position or results of operations. 
+The Company cannot predict the ultimate outcome or duration of any lawsuit described in this report. 
+Note 15— Selected Quarterly Financial Data (unaudited) 
+The following table sets forth certain unaudited financial and operating information for each quarter of the years ended December 31, 2020 and 2019. The unaudited quarterly information includes all adjustments that, in the opinion of management, are necessary for the fair presentation of information presented. Operating results for interim periods are not necessarily indicative of the results that may be expected for the full fiscal year. 
+F-32 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+($ in thousands) Year Ended December 31, 2020 
+Selected Financial Data: First Quarter Second Quarter Third Quarter Fourth Quarter 
+Revenue $ 472,344 $ 88,362 $ 147,495 $ 257,586 
+Operating costs and expenses: 
+Cost of services (exclusive of depreciation and amortization shown separately below) 392,716 89,518 139,237 236,510 
+General and administrative 28,613 18,064 17,307 20,114 
+Transaction, severance and other costs — 9,057 2,609 9,395 
+Depreciation and amortization 44,831 44,931 44,496 45,826 
+(Gain) loss on disposal of assets ( 102 ) 334 ( 752 ) 109 
+Total operating costs and expenses 466,058 161,904 202,897 311,954 
+Operating income (loss) 6,286 ( 73,542 ) ( 55,402 ) ( 54,368 ) 
+Other expense: 
+Interest expense, net 3,608 3,656 3,595 3,646 
+Net income (loss) before income taxes 2,678 ( 77,198 ) ( 58,997 ) ( 58,014 ) 
+Income tax expense (benefit) 261 ( 11,363 ) ( 9,972 ) ( 9,783 ) 
+Net income (loss) 2,417 ( 65,835 ) ( 49,025 ) ( 48,231 ) 
+Less: Net income (loss) attributable to non-controlling interests 697 ( 20,064 ) ( 14,523 ) ( 11,201 ) 
+Net income (loss) attributable to Liberty Oilfield Services Inc. stockholders $ 1,720 $ ( 45,771 ) $ ( 34,502 ) $ ( 37,030 ) 
+Net income (loss) attributable to Liberty Oilfield Services Inc. stockholders per common share: 
+Basic $ 0.02 $ ( 0.55 ) $ ( 0.41 ) $ ( 0.41 ) 
+Diluted $ 0.02 $ ( 0.55 ) $ ( 0.41 ) $ ( 0.41 ) 
+F-33 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+($ in thousands) Year ended December 31, 2019 
+Selected Financial Data: First Quarter Second Quarter Third Quarter Fourth Quarter 
+Revenue $ 535,148 $ 542,147 $ 515,079 $ 397,971 
+Operating costs and expenses: 
+Cost of services (exclusive of depreciation and amortization shown separately below) 429,299 426,444 421,007 344,430 
+General and administrative 22,088 23,989 25,302 26,210 
+Depreciation and amortization 38,387 40,368 42,324 44,299 
+Loss (gain) on disposal of assets 1,223 143 ( 124 ) 1,359 
+Total operating costs and expenses 490,997 490,944 488,509 416,298 
+Operating income (loss) 44,151 51,203 26,570 ( 18,327 ) 
+Other expense: 
+Interest expense, net 4,182 3,597 3,726 3,176 
+Net income (loss) before income taxes 39,969 47,606 22,844 ( 21,503 ) 
+Income tax expense (benefit) 6,060 7,083 4,004 ( 3,095 ) 
+Net income (loss) 33,909 40,523 18,840 ( 18,408 ) 
+Less: Net income (loss) attributable to non-controlling interests 15,788 18,491 7,842 ( 6,260 ) 
+Net income (loss) attributable to Liberty Oilfield Services Inc. stockholders $ 18,121 $ 22,032 $ 10,998 $ ( 12,148 ) 
+Net income (loss) attributable to Liberty Oilfield Services Inc. stockholders per common share: 
+Basic $ 0.27 $ 0.32 $ 0.15 $ ( 0.15 ) 
+Diluted $ 0.26 $ 0.32 $ 0.15 $ ( 0.15 ) 
+Note 16— Subsequent Events 
+On February 8, 2021, certain Liberty LLC Unitholders exercised their redemption rights and redeemed 6.1 million (or up to 7.0 million if the underwriters exercise the option to purchase additional shares) Liberty LLC Units (and an equivalent number of shares of Class B Common Stock) for an equivalent numbers of shares of Class A Common Stock of the Company. This exchange resulted in an increase to the ownership percentage of Liberty LLC owned by the Company. The Company expects to record an increase to the Company’s deferred tax asset as a result. In addition, the Company expects to record an increase to the payable pursuant to the TRAs. 
+There were no other significant subsequent events requiring disclosure or recognition other than those disclosed in these notes to the consolidated financial statements. 
+F-34
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diff --git a/raw/filings/0001694028/2020/0001694028-21-000007/filing_metadata.csv b/raw/filings/0001694028/2020/0001694028-21-000007/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..5ed9f6cf932e867c810ebf9d95d38eb7baf81e7f
--- /dev/null
+++ b/raw/filings/0001694028/2020/0001694028-21-000007/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0001694028,LBRT,Liberty Energy Inc.,10-K,2021-02-24,2020-12-31,2021-02-25T02:13:48.000Z,0001694028-21-000007,lbrt-20201231.htm,10-K,12088419,1,1,https://www.sec.gov/Archives/edgar/data/1694028/000169402821000007/lbrt-20201231.htm,https://www.sec.gov/Archives/edgar/data/1694028/000169402821000007/,2020,2020,1
diff --git a/raw/filings/0001694028/2020/0001694028-21-000007/item1.txt b/raw/filings/0001694028/2020/0001694028-21-000007/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..d1397f9352edd4e30d2e52bbf882a01777618b1b
--- /dev/null
+++ b/raw/filings/0001694028/2020/0001694028-21-000007/item1.txt
@@ -0,0 +1,69 @@
+Item 1. Business 
+Our Company 
+We are an independent provider of hydraulic fracturing and wireline services and related goods to onshore oil and natural gas exploration and production (“E&P”) companies in North America. We provide our services primarily in the Permian Basin, the Eagle Ford Shale, the Denver-Julesburg Basin (the “DJ Basin”), the Williston Basin, the San Juan Basin and the Powder River Basin. Following the completion of the OneStim Acquisition (as defined below) we now also provide services in the Haynesville Shale, the South Central Oklahoma Oil Province and Sooner Trend Anadarko Canadian Kingfisher (collectively the “SCOOP/STACK”), the Marcellus Shale, Utica Shale, and the Western Canadian Sedimentary Basin. 
+The process of hydraulic fracturing involves pumping a pressurized stream of fracturing fluid—typically a mixture of water, chemicals and proppant—into a well casing or tubing in order to cause the underground formation to fracture or crack. These fractures release trapped hydrocarbon particles and provide a conductive channel for the oil or natural gas to flow freely to the wellbore for collection. The propping agent, or proppant,—typically sand—becomes lodged in the cracks created by the hydraulic fracturing process, “propping” them open to facilitate the flow of hydrocarbons from the reservoir to the well. The fracturing fluid is engineered to lose viscosity, or “break,” and is subsequently flowed back from the formation, leaving the proppant suspended in the formation fractures. Once our customer has flushed the fracturing fluids from the well using a controlled flow-back process, the customer manages fluid and water recycling or disposal. 
+Our hydraulic fracturing fleets consist of mobile hydraulic fracturing units and other auxiliary heavy equipment to perform fracturing services. Our hydraulic fracturing units consist primarily of high-pressure hydraulic pumps, engines, transmissions, radiators and other supporting equipment that are typically mounted on trailers. We refer to the group of units and other equipment, such as blenders, data vans, sand storage, tractors, manifolds and high pressure fracturing iron, which are necessary to perform a typical hydraulic fracturing job, as a “fleet,” and the personnel assigned to each fleet as a “crew,” the size of each fleet and crew can vary depending on the requirements of each job design. 
+We have wireline operations after December 31, 2020 as a result of the OneStim Acquisition (as defined below). Our wireline units consist of a truck equipped with a spool of wireline that is lowered into wells to convey specialized tools or equipment necessary to connect the wellbore with the target formation. This operation is performed between each hydraulic fracturing stage. We offer our wireline service on a stand alone basis or alongside our hydraulic fracturing services. When offered along side our hydraulic fracturing services, we are able to maximize efficiency for our customers through optimized coordination of the wireline and hydraulic fracturing services. 
+Our operations are organized into a single business segment, which consists of hydraulic fracturing services, including wireline, and goods, including our Permian sand mines, and we have one reportable geographical segment, North America. We have grown from one active hydraulic fracturing fleet in December 2011 to approximately 30 fleets in the first quarter of 2021, including the addition of active fleets as a result of the OneStim Acquisition (as defined below). 
+Our founders and existing management were pioneers in the development of data-driven hydraulic fracturing technologies for application in shale plays. Prior to founding the Company, the majority of our management team founded and built Pinnacle Technologies, Inc. (“Pinnacle Technologies”) into a leading fracturing technology company. In 1992, Pinnacle Technologies developed the first commercial hydraulic fracture mapping technologies, analytical tools that played a major role in launching the shale revolution. Our extensive experience with fracture technologies and customized fracture design has enabled us to develop new technologies and processes that provide our customers with real time solutions that significantly enhance their completions. These technologies include hydraulic fracture propagation models, reservoir engineering tools, large, proprietary shale production databases and multi-variable statistical analysis techniques. Taken together, these technologies have enabled us to be a leader in hydraulic fracture design innovation and application. 
+We believe the following characteristics distinguish us from our competitors and are the foundations of our business: forming ongoing partnerships of trust and innovation with our customers; developing and utilizing technology to maximize well performance; and promoting a people-centered culture focused on our employees, customers and suppliers. We have developed strong relationships with our customers by investing significant time in fracture design collaboration, which substantially 
+1 
+Table of Contents 
+enhances their production economics. Our technological innovations have become even more critical as E&P companies have increased the completion complexity and fracture intensity of horizontal wells. We are proactive in developing innovative solutions to industry challenges, including developing: (i) our databases of U.S. unconventional wells to which we apply our proprietary multi-variable statistical analysis technologies to provide differential insight into fracture design optimization; (ii) our Liberty Quiet Fleet® design which significantly reduces noise levels compared to conventional hydraulic fracturing fleets; (iii) hydraulic fracturing fluid systems tailored to the specific reservoir properties in the basins in which we operate; and (iv) our dual fuel dynamic gas blending fleets that allow our engines to run diesel or a combination of diesel and natural gas, to optimize fuel use, reduce emissions and lower costs. We foster a people-centered culture built around honoring our commitments to customers, partnering with our suppliers and hiring, training and retaining people that we believe to be the best talent in our field, enabling us to be one of the safest and most efficient hydraulic fracturing companies in North America. 
+Recent Developments 
+On December 31, 2020, the Company acquired certain assets and liabilities of Schlumberger Limited’s (“Schlumberger”) OneStim® business, which provides hydraulic fracturing pressure pumping services in onshore United States and Canada, including its pressure pumping, pumpdown perforating and Permian frac sand business (such entire business of Schlumberger, “OneStim,” and the portion of OneStim acquired pursuant by the Company, the “Transferred Business”) in exchange for consideration resulting in a total of 66,326,134 shares of Class A common stock, par value $0.01 per share, of the Company (the “Class A Common Stock”) being issued in connection with the transaction (such transaction, the “OneStim Acquisition”; see Note 3—The OneStim Acquisition to the consolidated and combined financial statements included in “Item 8. Financial Statements and Supplementary Data”). Effective December 31, 2020, Schlumberger owned 37% of the issued and outstanding shares of our combined Class A Common Stock and our Class B common stock, par value $0.01 per share (the “Class B Common Stock” and, together with the Class A Common Stock, the “Common Stock”). 
+The OneStim Acquisition substantially increased the Company’s geographical reach and expanded operations, allowing the Company to serve a broader range of customers and utilize the increase in scale, vertical integration and technological know-how to better serve new and existing customers. The Transferred Business includes over 500 fully operational hydraulic fracturing pumps, district facilities, pumpdown perforating wireline units, two state-of-the-art sand mines in the Permian Basin and a highly experienced team of employees. Additionally, the Company added over 400 owned and licensed patents, significant internally developed software intellectual property and a strategic alliance agreement, which increases access to technology portfolios and advances the technological collaborations we are able to offer our customers. The combined company offers best-in-class completion services for the sustainable development of unconventional resource plays in the United States and Canada onshore markets. 
+Cyclical Nature of Industry 
+We operate in a highly cyclical industry. The key factor driving demand for our services is the level of drilling activity by E&P companies, which in turn depends largely on the current and anticipated economics of new well completions. Global supply and demand for oil and the domestic supply and demand for natural gas are critical in assessing industry outlook. Demand for oil and natural gas is cyclical and subject to large, rapid fluctuations, such as those experienced in 2020. E&P companies tend to increase capital expenditures in response to increases in oil and natural gas prices, which generally results in greater revenues and profits for oilfield service companies such as ours. Increased capital expenditures also ultimately lead to greater production, which historically has resulted in increased supplies of hydrocarbons and reduced prices which in turn tend to drive a future reduction in E&P companies capital expenditures and reduce demand for oilfield services. For these reasons, the results of our operations may fluctuate from quarter to quarter and from year to year, and these fluctuations may distort comparisons of results across periods. 
+Seasonality 
+Our results of operations have historically reflected seasonal tendencies relating to holiday seasons, inclement weather and the conclusion of our customers’ annual drilling and completion capital expenditure budgets. Our most notable declines typically occur in the fourth quarter of the year for the reasons described above. Additionally, some of the areas in which we have operations, including Canada, the DJ Basin, Powder River Basin and Williston Basin, are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice, rain, or frost, and related road restrictions, we may be unable to move our equipment between locations, thereby reducing our ability to provide services and generate revenues. The exploration activities of our customers may also be affected during such periods of adverse weather conditions. Additionally, extended drought conditions in our operating regions could impact our ability or our customers’ ability to source sufficient water or increase the cost for such water. 
+2 
+Table of Contents 
+Intellectual Property 
+Over the last several years and in connection with the OneStim Acquisition, we have significantly invested in our research and technology capabilities. Our efforts to date have been focused on developing innovative, fit-for-purpose solutions designed to enhance our core service offerings, increase completion efficiencies, provide cost savings to our operations and add value for our customers. 
+We seek patent and trademark protections for our technology when we deem it prudent, and we aggressively pursue protection of these rights when warranted. We believe our patents, trademarks, and other protections for our proprietary technologies are adequate for the conduct of our business and that no single patent or trademark is critical to our business. In addition, we rely, to a great extent, on the technical expertise and know-how of our personnel to maintain our competitive position, and we take commercially reasonable measures to protect trade secrets and other confidential and/or proprietary information relating to the technologies we develop. 
+Human Capital Management 
+As of December 31, 2020, we had 1,946 employees and no unionized labor. We believe we have good relations with our employees. We promote a people-centered culture focused heavily on our employees and believe that the strength of our workforce is critical to our success as a company. We consistently assess the current business environment and labor market to refine our compensation and benefits programs in order to attract and retain top talent in our industry. We generally strive to hire people with integrity, a positive attitude and hunger to learn and contribute to a team. In response to the COVID-19 pandemic, we reduced our headcount and implemented a company-wide employee furlough plan in order to align with the uncertain level of frac demand we experienced during the second and third quarters of 2020. As of September 30, 2020, all furloughed employees had returned from furlough. We have implemented and continue to implement safety measures in all of our facilities to address the COVID-19 pandemic. 
+Additionally, as a result of the OneStim Acquisition, we expect to hire approximately 800 employees following a brief transition period during which their continuing service is provided while on secondment from Schlumberger. 
+Health and Safety 
+Our people are our most important asset and ensuring their safety and the safety of those around them is the most important thing we do. Making certain that the Liberty team is well trained to handle the complexities of daily field operations, and that their training and competency remains current with the latest technology and standards is a key component. In order to facilitate this training, we have developed the Liberty Frac Academy, a thorough program where employees are trained on various aspects of the Company, from safety in equipment operation to leadership skills. The Liberty Frac Academy not only ensures dissemination of high-quality training material, but also provides a forum for sharing best practices and lessons learned across the Company. 
+Programs and Benefits 
+One way we have demonstrated a history of investing in our workforce is by offering competitive salaries and wages. To foster a strong sense of ownership, restricted stock units are provided to eligible non-executive employees under our stock incentive program. Furthermore, we offer innovative benefits to all eligible employees, including, among others, comprehensive health insurance coverage, parental leave to all new parents, for birth or adoption, financial support for child adoption, leave to care for partners with serious health conditions, 401(k) savings plan and educational tuition assistance for both bachelor’s degree and master’s degree programs. We are also passionate about community investment and, in 2019, we joined the Ban the Box initiative which provides work opportunities for formerly incarcerated individuals. 
+3 
+Table of Contents 
+Properties 
+Properties 
+Our corporate headquarters are located at 950 17 th Street, Suite 2400, Denver, Colorado 80202. We lease our general office space at our corporate headquarters. The lease expires in December 2027. We currently own or lease the following additional principal properties: 
+District Facility Location Size Leased or Owned 
+Midland, TX 160,000 sq. ft on 147 acres Owned 
+Odessa, TX 77,500 sq. ft on 47 acres Owned 
+Cibolo, TX 90,000 sq. ft on 34 acres Owned 
+Kermit, TX 5,000 acres Owned 
+Monahans, TX 3,200 acres Owned 
+Shreveport, LA 225,000 sq ft. on 50 acres Owned 
+Cheyenne, WY 115,000 sq. ft on 60 acres Owned 
+Gillette, WY 32,757 sq. ft on 15 acres Leased (through December 31, 2034) 
+Henderson, CO 50,000 sq. ft on 13 acres Leased (through December 31, 2034) 
+Williston, ND 30,000 sq. ft on 15 acres Owned 
+El Reno, OK 80,000 sq. ft on 33 acres Owned 
+Red Deer, AB 170,000 sq. ft on 42 acres Owned 
+Grand Prairie, AB 135,000 sq. ft on 40 acres Owned 
+Huallen, AB 80 acres Owned 
+We also lease several smaller facilities, which leases generally have terms of one to six years. We believe that our existing facilities are adequate for our operations and their locations allow us to efficiently serve our customers. We do not believe that any single facility is material to our operations and, if necessary, we could readily obtain a replacement facility. 
+Marketing and Customers 
+Our sales and marketing activities typically are performed through our local sales representatives in each geographic region, and are supported by our corporate headquarters. For the years ended December 31, 2020, 2019 and 2018, our top five customers collectively accounted for approximatel y 48% , 35% and 42% of our revenues, respectively. For the year ended December 31, 2020, PDC Energy Inc., ConocoPhillips Company, Parsley Energy Operations, LLC, and WPX Energy each accounted for more than 10% of our revenues. No customer accounted for more than 10% of our revenues for the year ended December 31, 2019. For the year ended December 31, 2018, Extraction Oil & Gas, Inc. accounted for more than 10% of our revenues. 
+Suppliers and Raw Materials 
+We have a dedicated supply chain team that manages sourcing and logistics to ensure flexibility and continuity of supply in a cost effective manner across our areas of operation. We have built long-term relationships with multiple industry leading suppliers of proppant, chemicals and hydraulic fracturing equipment and have started to internally design and assemble key pump and maintenance parts. In addition, we have built a strong relationship with the assembler of our custom-designed hydraulic fracturing fleets and believe we will continue to have timely access to new, high capability fleets as we continue to grow. In 2018, we also vertically integrated a supplier of certain major components through the acquisition of ST9 Gas and Oil LLC. 
+We purchase a wide variety of raw materials, parts and components that are manufactured and supplied for our operations. We are not dependent on any single source of supply for those parts, supplies or materials. To date, we have generally been able to obtain the equipment, parts and supplies necessary to support our operations on a timely basis. While we believe that we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers, we may not always be able to do so. In addition, certain materials for which we do not currently have long-term supply agreements could experience shortages and significant price increases in the future. As a result, we may be unable to mitigate any future supply shortages and our results of operations, prospects and financial condition could be adversely affected. The OneStim Acquisition included two state-of-the-art sand mines in the Permian Basin, which further alleviates the risk of potential future material supply shortages. 
+4 
+Table of Contents 
+Competition 
+The markets in which we operate are highly competitive. We provide services in various geographic regions across the United States and Canada, and our competitors include many large and small oilfield service providers, including some of the largest integrated service companies. Our hydraulic fracturing services compete with large, integrated companies such as Halliburton Company as well as other companies including Calfrac Well Services Ltd., FTS International, Inc., NexTier Oilfield Solutions Inc., Universal Pressure Pumping, Inc., ProPetro Services, Inc., RPC, Inc., STEP Energy Services and U.S. Well Services, Inc. In addition, our industry is highly fragmented and we compete regionally with a significant number of smaller service providers. 
+We believe that the principal competitive factors in the markets we serve are technical expertise, equipment capacity, work force competency, efficiency, safety record, reputation, experience and price. Additionally, projects are often awarded on a bid basis, which tends to create a highly competitive environment. We seek to differentiate ourselves from our competitors by delivering the highest-quality services and equipment possible, coupled with superior execution and operating efficiency in a safe working environment. 
+Governmental Regulation 
+As a company with operations in both the United States and Canada, we are subject to the laws of both jurisdictions in which we operate and the rules and regulations of various governing bodies, which may differ among those jurisdictions. Compliance with these laws, rules and regulations has not had, and is not expected to have, a material effect on our capital expenditures, results of operations and competitive position as compared to prior periods. We are also subject to numerous environmental and regulatory requirements related to our operations. For further information related to such regulation, see “Item 1A. Risk Factors.” 
+Available Information 
+We file or furnish annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The SEC also maintains an internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC. 
+We also make available free of charge through our website, www.libertyfrac.com, electronic copies of certain documents that we file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. 
+5 
+Table of Contents
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diff --git a/raw/filings/0001694028/2020/0001694028-21-000007/item13.txt b/raw/filings/0001694028/2020/0001694028-21-000007/item13.txt
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@@ -0,0 +1,2 @@
+Item 13. Certain Relationships and Related Transactions, and Director Independence 
+The information required by this item concerning certain relationships and related person transactions and director independence is incorporated herein by reference to our definitive proxy statement for our 2021 annual meeting of shareholders, which will be filed with the SEC no later than 120 days after December 31, 2020, under the captions “Certain Relationships and Related Party Transactions” and “the Board and its Committees.”
\ No newline at end of file
diff --git a/raw/filings/0001694028/2020/0001694028-21-000007/item9a.txt b/raw/filings/0001694028/2020/0001694028-21-000007/item9a.txt
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@@ -0,0 +1,5 @@
+Item 9A. Controls and Procedures 
+Evaluation of Disclosure Controls and Procedures 
+In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2020 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures. 
+As noted in Management’s Report on Internal Control Over Financial Reporting, management ’ s evaluation of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of the entities acquired in the OneStim Acquisition, as defined herein, on December 31, 2020. Under guidelines established by the SEC, companies are permitted to exclude acquisitions from their assessment of internal control over financial reporting during the first year of an acquisition while integrating the acquired company. The Company is in the process of integrating OneStim ’s and our internal controls over financial reporting. As a result of these integration activities, certain controls will be evaluated and may be changed. Except as noted above, there were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+See page F-1 for Management’s Report on Internal Control Over Financial Reporting and page F-4 for Report of Independent Registered Public Accounting Firm on its assessment of our internal control over financial reporting.
\ No newline at end of file
diff --git a/raw/filings/0001694028/2020/0001694028-21-000007/rp_note.txt b/raw/filings/0001694028/2020/0001694028-21-000007/rp_note.txt
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index 0000000000000000000000000000000000000000..b37a407da1dde1f16a5cc56c2a287efd0e993539
--- /dev/null
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@@ -0,0 +1,13 @@
+Note 13— Related Party Transactions 
+As of December 31, 2020 Schlumberger owns 66,326,134 shares of Class A Common Stock of the Company, or 37.0 % of the issued and outstanding shares of common stock of the Company, including Class A Common Stock and Class B Common Stock. Under the Transaction agreement, to the extent the net working capital, as defined, of the Transferred Business is less than $ 54.6 million, the difference shall be payable in cash to the Company. Additionally, the Company and Schlumberger agreed to an $ 8.0 million true-up payment related to the estimated costs to bring certain assets to full working condition. As of December 31, 2020, the Company recorded an estimated receivable from Schlumberger of $ 24.7 million related to these true-up payments. The Company collected $ 8.0 million in January 2021. Additionally, in conjunction with closing the OneStim Acquisition, the Company entered unto a transition services agreement with Schlumberger, under which Schlumberger will provide certain administrative transition services for a rate of approximately $ 2.5 million per month, until the Company fully integrates the acquired business. 
+Prior to the Corporate Reorganization, one of the members of Liberty Holdings contributed a portion of its member interest in Liberty Holdings to R/C IV Non-U.S. LOS Corp (“R/C IV”). Subsequently, in conjunction with the Corporate Reorganization, R/C IV was contributed to Liberty LLC. R/C IV had net operating loss carryforwards for federal and state income tax purposes which resulted in the recognition of a $ 2.9 million payable pursuant to the TRAs. During the years ended December 31, 2020 and December 31, 2019, R/C IV Liberty Holdings, L.P. exercised its redemption right and redeemed 4,016,965 and 9,605,786 shares of Class B Common Stock resulting in an increase in tax basis, as described in Note—11 Income Taxes— Tax Receivable Agreements , and recognition of $ 6.1 million and $ 22.3 million in amounts payable under the TRAs, respectively. As of December 31, 2020 and 2019, the Company’s current liabilities under the TRAs payable to R/C IV Liberty Holdings, L.P. and R/C IV Non-US were $ 0 and $ 1.3 million, respectively, included in accrued interest and other and non-current liabilities were $ 27.2 million and $ 23.8 million, respectively, in payable pursuant to tax receivable agreements in the accompanying condensed consolidated balance sheets. 
+In September 2011, Liberty Resources LLC, an oil and gas exploration and production company, and its successor entity (collectively, the “Affiliate”) and LOS, companies with common ownership and management, entered into a services agreement (the “Services Agreement”) whereby the Affiliate is to provide certain administrative support functions to LOS and a master service agreement whereby LOS provides hydraulic fracturing services to the Affiliate at market service rates. The amounts incurred under the Services Agreement by LOS during the years ended December 31, 2020, 2019 and 2018, were $ 0 , $ 0 million, and $ 0.2 million, respectively. The Services Agreement was terminated during June 2018. 
+The amounts of the Company’s revenue related to hydraulic fracturing services provided to the Affiliate for the years ended December 31, 2020, 2019 and 2018, were $ 0.0 million, $ 18.3 million and $ 23.1 million, respectively. As of December 31, 2020 and 2019, $ 0.0 million and $ 7.1 million, respectively, of the Company’s accounts receivable—related party was with the Affiliate. On June 24, 2019 (the “Agreement Date”), the Company entered into an agreement with the Affiliate to amend payment terms for outstanding invoices due as of the Agreement Date to be due on July 31, 2020. On September 30, 2019, the agreement was amended to extend the due date of the remaining amounts outstanding to October 31, 2020. Amounts outstanding from the Affiliate as of the Agreement Date were $ 15.6 million. The amounts outstanding, including all accrued interest was paid in full in January 2020. As of December 31, 2020 and December 31, 2019, amounts outstanding under the amended payment terms from the Affiliate were $ 0 and $ 2.5 million, all of which is presented in accounts and notes receivable—related party in the accompanying consolidated balance sheet. The balance outstanding is subject to interest at 13 % annual percent yield, retroactively applied to the respective invoice date. During the year ended December 31, 2020 and 2019, interest income from the Affiliate was $ 0.3 million and $ 1.8 million, respectively, and accrued interest as of December 31, 2020 and 2019 was $ 0 . Receivables earned for services performed after the Agreement Date continue to be subject to normal 30-day payment terms, provided that any amount unpaid after 60 days is subject to 13 % interest. 
+Liberty Holdings entered into an advisory agreement, dated December 30, 2011, with Riverstone/Carlyle Energy Partners IV, L.P. (“R/C”), in which R/C agreed to provide certain administrative advisory services to Liberty Holdings. The advisory services agreement was terminated pursuant to an agreement effective as of January 11, 2018. On January 11, 2018, Liberty Holdings, R/C and other parties entered into a Master Reorganization Agreement that, among other things, crystallized the “waterfall” provisions of Article VI of the Third Amended and Restated Limited Liability Agreement of Liberty Holdings, dated October 11, 2016 (the “Holdings LLC Agreement”), in connection with the initial public offering of shares of Class A Common Stock. As part of this crystallization, R/C and affiliated entities (collectively, the “R/C Affiliates”) received shares of Class A Common Stock, including 117,647 shares of Class A Common Stock (such 117,647 referred to as the “Issued Shares”) to compensate R/C Affiliates for certain accrued preferred returns but which would not have been issued had the $ 2.0 million in fees owing under the advisory agreement been paid in cash. Had this fee been paid in cash on or prior to January 11, 2018, R/C and Liberty Holdings acknowledge that R/C Affiliates would not have received the Issued Shares in the crystallization pursuant 
+F-30 
+Table of Contents 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated and Combined Financial Statements 
+to the provisions of the Holdings LLC Agreement. Subsequently, during the fourth quarter of 2018, R/C asserted that certain provisions of the termination of services agreement provided for R/C to receive $ 2.0 million in cash as payment of those accrued fees. To resolve this matter, the Company agreed to pay R/C Affiliates $ 2.0 million in cash in exchange for the return, at the IPO price, of the Issued Shares and $ 0.3 million for interest and the settlement of the matter. Accordingly, $ 2.3 million was recorded as accrued liabilities—related party in the consolidated balance sheet as of December 31, 2018 and subsequently paid in January 2019. The returned shares of Class A Common Stock were canceled and retired, and the Company does not expect to incur future expense related to the advisory agreement or termination thereof. 
+During 2016, Liberty Holdings entered into a future commitment to invest and become a non-controlling minority member in Proppant Express Investments, LLC, the owner of Proppant Express Solutions, LLC (“PropX”), a provider of proppant logistics equipment. LOS is party to a services agreement (the “PropX Services Agreement”) whereby LOS is to provide certain administrative support functions to PropX, and LOS is to purchase and lease proppant logistics equipment from PropX. The PropX Services Agreement was terminated on May 29, 2018; however, the Company continues to lease equipment from PropX. During the years ended December 31, 2020, 2019 and 2018 for $ 8.7 million, $ 9.8 million and $ 4.4 million, respectively. 
+Payables to PropX as of December 31, 2020 and 2019 were $ 1.5 million and $ 0.8 million, respectively.
\ No newline at end of file
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+CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS 
+Policies and Procedures for Review of Related Party Transactions 
+A “ Related Party Transaction ” is a transaction, arrangement or relationship in which the Company or any of its subsidiaries was, is or will be a participant, the amount of which involved exceeds $120,000, and in which any related person had, has or will have a direct or indirect material interest. A “ Related Person ” is: 
+♦ any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors; 
+♦ any person who is known by us to be the beneficial owner of more than 5% of our Class A Common Stock; 
+♦ any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, executive officer or a beneficial owner of more than 5% of our Class A Common Stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5% of our Class A Common Stock; and 
+♦ any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10.0% or greater beneficial ownership interest. 
+Our Board adopted a written related party transactions policy in connection with the IPO. Pursuant to this policy, our Audit Committee reviews all material facts of all Related Party Transactions and either approves or disapproves entry into the Related Party Transaction, subject to certain limited exceptions. The determination of the Audit Committee is documented in the Audit Committee’s minutes. In determining whether to approve or disapprove entry into a Related Party Transaction, our Audit Committee takes into account, among other factors, the following: (i) whether the Related Party Transaction is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances and (ii) the extent of the Related Person’s interest in the transaction. Furthermore, the policy requires that all Related Party Transactions required to be disclosed in our filings with the SEC be so disclosed in accordance with applicable laws, rules and regulations. 
+Related Party Transactions 
+The following is a description of transactions entered into, or in effect, after January 1, 2021 to which we have been a party, in which the amount involved in the transaction exceeds $120,000, and in which any of our directors, executive officers or beneficial owners of more than 5% of our voting securities, or affiliates or immediate family members of any of our directors, executive officers or beneficial owners of more than 5% of our voting securities, had or will have a direct or indirect material interest. We believe the terms obtained or consideration that we paid or received, as applicable, in connection with the transactions described below were comparable to terms available or the amounts that would be paid or received, as applicable, from unrelated third parties. 
+Liberty LLC Agreement 
+We entered into the Second Amended and Restated Limited Liability Company Agreement of Liberty Oilfield Services New HoldCo LLC (“ Liberty LLC ”) (the “ Liberty LLC Agreement ”) in connection with the closing of our IPO, which provides for limitations on the ability of holders of units of Liberty LLC (the “ Liberty LLC Units, ” and the holders of Liberty LLC Units “ Liberty Unit Holders ”) to transfer their Liberty LLC Units and provides the Company, as managing member of Liberty LLC, with the right to impose restrictions (in addition to those already in place) on the ability of Liberty Unit Holders to redeem their Liberty LLC Units pursuant to the Redemption Right (as defined below) to the extent the Company believes it is necessary to ensure that Liberty LLC will continue to be treated as a partnership for U.S. federal income tax purposes. 
+Redemption Rights 
+Under the Liberty LLC Agreement, each Liberty Unit Holder has, subject to certain limitations, the right (the “ Redemption Right ”) to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units for, at Liberty LLC’s election, (i) shares of our Class A Common Stock at a redemption ratio of one share of Class A Common Stock for each Liberty LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions or (ii) an equivalent amount of cash. Alternatively, upon the exercise of the Redemption Right, the Company (instead of Liberty LLC) has the right (the “ Call Right ”) to, for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder for, at the Company’s election, (x) one share of Class A Common Stock or (y) an equivalent amount of cash. In addition, upon a change of control of the Company, the Company has the right to require each holder of Liberty LLC Units (other than the Company) to exercise its Redemption Right with respect to some or all of such unit holder’s Liberty LLC Units. In connection with any redemption of Liberty LLC Units pursuant to the Redemption Right or the Call Right, the corresponding number of shares of Class B Common Stock will be 
+42 
+cancelled. As the Liberty Unit Holders redeem their Liberty LLC Units, our membership interest in Liberty LLC will be correspondingly increased, the number of shares of Class A Common Stock outstanding will be increased, and the number of shares of Class B Common Stock outstanding will be reduced. 
+Distributions and Allocations 
+Under the Liberty LLC Agreement, the Company has the right to determine when distributions will be made to the holders of Liberty LLC Units and the amount of any such distributions. If the Company authorizes a distribution, such distribution will be made to the holders of Liberty LLC Units generally on a pro rata basis in accordance with their respective percentage ownership of Liberty LLC Units. 
+Liberty LLC will allocate its net income or net loss for each year to the holders of Liberty LLC Units pursuant to the terms of the Liberty LLC Agreement, and the holders of Liberty LLC Units, including the Company, will generally incur U.S. federal, state and local income taxes on their share of any taxable income of Liberty LLC. Net income and losses of Liberty LLC generally will be allocated to the holders of Liberty LLC Units on a pro rata basis in accordance with their respective percentage ownership of Liberty LLC Units, subject to requirements under U.S. federal income tax law that certain items of income, gain, loss or deduction be allocated disproportionately in certain circumstances. To the extent Liberty LLC has available cash and subject to the terms of any debt instruments, the Company intends to cause Liberty LLC to make (i) generally pro rata distributions to the holders of Liberty LLC Units, including the Company, in an amount sufficient to allow the Company to pay its taxes and to allow it to make payments under the Tax Receivable Agreements (as defined below), (ii) tax advances, which will be repaid upon exercise of the Redemption Right or the Call Right, as applicable, in an amount sufficient to allow each of the Liberty Unit Holders to pay its respective taxes on such holder’s allocable share of Liberty LLC’s taxable income after taking into account certain other distributions or payments received by the Liberty Unit Holders from Liberty LLC or the Company, and (iii) non-pro rata payments to the Company to reimburse it for its corporate and other overhead expenses. 
+Issuance of Equity 
+The Liberty LLC Agreement generally provides that at any time the Company issues a share of its Class A Common Stock or any other equity security, the net proceeds received by the Company with respect to such issuance, if any, shall be concurrently invested in Liberty LLC, and Liberty LLC shall issue to the Company one Liberty LLC Unit or other economically equivalent equity interest. Conversely, if at any time, any shares of Class A Common Stock are redeemed, repurchased or otherwise acquired, Liberty LLC shall redeem, repurchase or otherwise acquire an equal number of Liberty LLC Units held by the Company, upon the same terms and for the same price, as the shares of the Class A Common Stock are redeemed, repurchased or otherwise acquired. 
+Dissolution 
+Liberty LLC will be dissolved only upon the first to occur of (i) the sale of substantially all of its assets or (ii) an election by us to dissolve the company. Upon dissolution, Liberty LLC will be liquidated and the proceeds from any liquidation will be applied and distributed in the following manner: (i) first, to creditors (including to the extent permitted by law, creditors who are members) in satisfaction of the liabilities of Liberty LLC; (ii) second, to establish cash reserves for contingent or unforeseen liabilities; and (iii) third, to the members in proportion to the number of Liberty LLC Units owned by each of them. 
+Tax Receivable Agreements 
+In connection with the IPO, on January 17, 2018, the Company entered into two tax receivable agreements, (the “ TRAs ”) with the Liberty Unit Holders and the selling stockholder (each such person and any permitted transferee, a “ TRA Holder ” and together, the “ TRA Holders ”). The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that the Company actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result, as applicable to each TRA Holder, of (i) certain increases in tax basis that occur as a result of the Company’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holder’s Liberty LLC Units in connection with the IPO or pursuant to the exercise of the Redemption Right or the Call Right, (ii) any net operating losses available to the Company as a result of the corporate reorganization, and (iii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRAs. For the year ended December 31, 2020, the Company made TRA payments of $1.9 million and $5.5 million, totaling $7.4 million. These TRA payments were related to tax benefits realized in prior years and for the Company’s carryback of 2019 net operating losses to 2018 taxable income under the CARES Act. 
+Schlumberger 
+Master Transaction Agreement 
+On August 31, 2020, the Company, entered into a Master Transaction Agreement (the “ MTA ”) with Schlumberger, Schlumberger Canada Limited, (“ Schlumberger Canada ” and, together with Schlumberger, the “ Schlumberger Parties ”), Liberty LLC, and LOS Canada Operations Inc. (“ Canadian Buyer ”), pursuant to which the Liberty LLC and Canadian Buyer acquired the Schlumberger Parties’ 
+43 
+OneStim business in exchange for 57,377,232 shares of Class A Common Stock and a non-interest bearing demand promissory note, which note was satisfied with 8,948,902 shares of Class A Common Stock, resulting in a total of 66,326,134 shares of Class A Common Stock being issued in connection with the transaction. The Schlumberger Parties are affiliated with Messrs. Ayat and McDonald, who are on our Board. The transactions contemplated by the MTA closed on December 31, 2020. 
+Until December 31, 2024, subject to certain exceptions and as more specifically set forth in the MTA, without the prior written consent of the Company, each of Schlumberger and Schlumberger Canada will not, and will cause each of their respective affiliates (including Schlumberger Limited) not to, directly or indirectly engage in any business or enterprise that is competitive with OneStim within onshore United States and Canada. 
+On December 31, 2020, in connection with the closing of the transactions contemplated by the MTA, the Company (and/or one or more of its subsidiaries) and the Schlumberger Parties entered into the following agreements, each of which may involve amounts in excess of $120,000: (i) an intellectual property license agreement, whereby the Schlumberger Parties granted to Liberty LLC and the Company exclusive and non-exclusive licenses to certain intellectual property, and Liberty LLC granted to the Schlumberger Parties a non-exclusive license to certain patents acquired by Liberty LLC under the MTA; (ii) an employee matters agreement, pursuant to which the applicable Schlumberger Party agreed to lease employees to the Company or a subsidiary of the Company until March 1, 2021, subject to certain exceptions and extensions; (iii) an alliance agreement whereby Schlumberger and Liberty LLC agreed to collaborate to advance each of their product portfolios and technology offerings; (iv) a transition services agreement whereby Schlumberger or its designee agreed to provide certain back-office, administrative, field operations, supply chain and other specified services to the Company until March 1, 2021, subject to certain exceptions and extensions; and (v) a strategic supply agreement intended to provide the Company with an opportunity to purchase from the various business lines of Schlumberger, products and services with competitive pricing terms for a term not to exceed the term of the non-compete covenant in the MTA discussed above. 
+Amended and Restated Stockholders Agreement 
+In connection with the OneStim Acquisition, we entered into an amended and restated stockholders agreement with affiliates of Riverstone, and the Schlumberger Parties. Among other things, the amended and restated stockholders agreement provides the right to designate nominees to our Board as follows: 
+• so long as the Schlumberger Parties and its affiliates collectively beneficially own at least 20% of the outstanding shares of our Common Stock, the Schlumberger Parties can designate up to two (2) nominees to our Board; and 
+• so long as the Schlumberger Parties and their affiliates collectively beneficially own at least 10% of the outstanding shares of our Common Stock, the Schlumberger Parties can designate up to one (1) nominee to our Board. 
+Pursuant to the amended and restated stockholders agreement, the Schlumberger Parties will not, (i) for a period of nine months from the closing of the OneStim Acquisition, transfer or dispose of (or take other analogous actions in accordance with the terms of the agreement) any economic, voting or other rights in or to their issued shares, other than certain permitted transfers and, (ii) for a period of four years from the closing of the OneStim Acquisition, make any transfer of Common Stock to any direct competitor of the Company or to any person that is subject to, or by virtue of such transfer would become subject to, the reporting obligations under Schedule 13D under the Exchange Act, with respect to Common Stock (the “ Lock-Up and Transfer Restrictions ”). 
+Pursuant to the amended and restated stockholders agreement, the Schlumberger Parties and their affiliates are subject to customary standstill restrictions in accordance with which such parties will agree not to, among other things, acquire beneficial ownership of any equity securities of the Company or publicly seek or encourage any offer or proposal for a merger or similar transaction involving the Company during the period commencing on the date of the agreement and continuing until the fourth anniversary of the closing of the OneStim Acquisition (the “ Standstill ”). 
+Pursuant to the amended and restated stockholders agreement, we will be required to take all necessary actions, to the fullest extent permitted by applicable law (including with respect to any fiduciary duties under Delaware law), to cause the election of the nominees designated by either the Riverstone affiliates or the Schlumberger Parties. At any time the members of our Board are allocated among separate classes of directors, (i) the directors designated by the Riverstone affiliates pursuant to the amended and restated stockholders agreement will be to the classes as mutually agreed between us and the Riverstone affiliates, and (ii) the directors designated by the Schlumberger Parties pursuant to the amended and restated stockholders agreement will be to the classes as mutually agreed between us and the Schlumberger Parties. The Riverstone affiliates will be entitled to designate the replacement for any of its Board designees whose service terminates prior to the end of such director’s term. The Schlumberger Parties will be entitled to designate the replacement for any of its Board designees whose service terminates prior to the end of such director’s term. 
+The amended and restated stockholders agreement will terminate with respect to the Schlumberger Parties at the earliest of (a) such time as the Schlumberger Parties no longer beneficially own at least 10% of the outstanding shares of Common Stock and are no longer subject to the Standstill and the Lock-Up and Transfer Restrictions, (b) such time as the Schlumberger Parties do not beneficially own 
+44 
+any shares of Common Stock, and (c) the written agreement of the Schlumberger Parties and the Company terminating the agreement. The amended and restated stockholders agreement will terminate with respect to Riverstone at the earliest of (i) such time as Riverstone and its affiliates no longer beneficially own at least 10% of the outstanding shares of Common Stock, and (ii) the delivery of written notice to the Company by Riverstone of the termination of the agreement with respect to Riverstone. 
+Amended and Restated Registration Rights Agreement 
+In connection with the OneStim Acquisition, we entered into an amended and restated registration rights agreement with Schlumberger, Schlumberger Canada and each of the other holders identified therein (the “ Holders ”), pursuant to which, among other things, certain Holders, including affiliates of Riverstone, Schlumberger and Schlumberger Canada (the “ Sponsoring Holders ”), have customary demand registration rights and we are obligated to prepare and file a registration statement registering the offer and sale of all of Schlumberger and Schlumberger Canada’s shares of Class A Common Stock. In addition, pursuant to this agreement, the Sponsoring Holders have the right to require us, subject to certain limitations set forth therein, to effect a distribution of any or all of their shares of Class A Common Stock by means of an underwritten offering. We are not obligated to effect any underwritten offering unless the dollar amount of the registrable securities of the Sponsoring Holder(s) demanding such underwritten offering to be included therein is reasonably likely to result in gross sale proceeds of at least $25 million. The amended and restated registration rights agreement also provides Holders with certain customary piggyback registration rights. These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a registration or offering and the Company’s right to delay or withdraw a registration statement under certain circumstances. 
+Property Swap 
+During 2021, a subsidiary of the Company and Schlumberger entered into a property swap agreement under which the Company exchanged with Schlumberger a property acquired in the OneStim Acquisition and $4.9 million in cash for a separate property that the Company has utilized with its existing operations. 
+Working Capital Settlement 
+Under the MTA, to the extent the net working capital, as defined therein, of the transferred OneStim business is less than $54.6 million, the difference shall be payable in cash to the Company. In 2021, the Company agreed on a working capital settlement from Schlumberger of $15.8 million, most of which was netted against transaction services costs and cash settlements during the transition services period. 
+Purchase of Chemicals, Proppant and Equipment 
+Following the OneStim Acquisition, in the normal course of business, the Company purchases chemicals, proppant and other equipment and maintenance parts from Schlumberger and its subsidiaries. For the year ended December 31, 2021, total purchases from Schlumberger were approximately $28.2 million, and as of December 31, 2021, amounts due to Schlumberger were $3.8 million. 
+Underwriting Agreement 
+On February 8, 2021, the Company, R/C Energy IV Direct Partnership, L.P. and R/C IV Liberty Holdings, L.P. (together, the “ Riverstone Affiliates ”) and Morgan Stanley & Co. LLC (the “ Underwriter ”), entered into an underwriting agreement (the “ Underwriting Agreement ”), pursuant to which the Riverstone Affiliates agreed to sell to the Underwriter, and the Underwriter agreed to purchase from the Riverstone Affiliates, subject to and upon the terms and conditions set forth therein, an aggregate of 8,700,000 shares of Class A Common Stock of the Company (the “ Offering ”). The Offering closed on February 11, 2021. Pursuant to the Underwriting Agreement, the Riverstone Affiliates also granted the Underwriter a 30-day option to purchase from the Riverstone Affiliates up to 1,305,000 additional shares of Class A Common Stock at the public offering price, less the underwriting discount. The Company will not receive any proceeds from the sale of shares of Class A Common Stock in the Offering. The Underwriting Agreement contains customary representations, warranties and agreements of the Company and the Riverstone Affiliates and other customary obligations of the parties and termination provisions. 
+Transactions with Liberty Resources 
+Liberty Resources LLC (“ Liberty Resources ”) is an oil and gas exploration and production company of which Mr. Wright is the Executive Chairman. Mr. Wright previously served as the Chief Executive Officer at Liberty Resources from its formation in September 2010 until March 2017. Liberty Resources entered into a master service agreement with Liberty Oilfield Services LLC, a subsidiary of the Company (“ Liberty Services ”), whereby Liberty Services provides hydraulic fracturing service to Liberty Resources at market service rates. For the year ended December 31, 2021, the amounts related to the provision of hydraulic fracturing services to Liberty Resources under the master services agreement was $2.8 million. 
+45 
+Transactions with Franklin Mountain 
+Franklin Mountain Energy LLC (“ Franklin Mountain ”) is an oil and gas exploration and production company of which Ms. Robertson serves as the Chief Financial Officer. Franklin Mountain entered into a master service agreement with Liberty Services, whereby Liberty Services provides hydraulic fracturing service to Franklin Mountain at market service rates. For the year ended December 31, 2021, the amounts related to the provision of hydraulic fracturing services to Franklin Mountain under the master services agreement was $20.5 million or 0.8% of the Company’s revenues for such period. 
+Transactions with PropX 
+Liberty Services currently leases equipment from Proppant Express Solutions, LLC (“ PropX ”), a provider of proppant logistics equipment. Liberty Services acquired PropX in October of 2021 (the “ PropX Acquisition ”), resulting in PropX now being a wholly-owned subsidiary of Liberty Services. R/C IV Liberty Big Box Holdings, L.P., a Riverstone fund and a former significant stockholder of the Company, held a greater than 10% equity interest in PropX. Christopher A. Wright, the Chief Executive Officer, Michael Stock, the Chief Financial Officer and Ron Gusek, the President of the Company, held a less than 5% equity interest in PropX through Big Box Proppant Investments LLC. Cary Steinbeck, a director of the Company, served on the PropX Board and held a less than 5% indirect equity interest in PropX. In addition, Brett Staffieri, a Riverstone appointed director, served on the Board of the Company until June 15, 2021 and on the PropX board of directors until the PropX Acquisition. The PropX Acquisition was reviewed and approved by the disinterested members of the Board and pursuant to the Company’s related party transactions policy. From January 1, 2021 through the PropX Acquisition date, Liberty Services paid PropX $7.3 million for the lease of proppant logistics equipment. In connection with the PropX Acquisition, each of the sellers and certain of their investors that received Liberty LLC units, entered into a joinder to the Liberty LLC Agreement. See “ Certain Relationships and Related Person Transactions – Liberty LLC Agreement ” above for a description of the material terms of the Liberty LLC Agreement. 
+Transactions with Tim Babcock 
+Tim Babcock is currently employed at ST9 Gas and Oil LLC, a wholly-owned subsidiary of Liberty Services (“ ST9 ”) as a key account manager. Tim Babcock is the son of Ken Babcock, who serves on the Board. For the year ended December 31, 2021, ST9 paid Tim Babcock $121,772.92. 
+Indemnification for Officers and Directors 
+Our Amended and Restated Certificate of Incorporation and Amended and Restated Bylaws provide indemnification rights to our directors and officers and permit us to purchase insurance on behalf of any officer, director, employee or other agent for any liability arising out of that person’s actions as our officer, director, employee or agent, regardless of whether Delaware law would mandate indemnification. Additionally, we have entered into separate indemnity agreements with our directors and officers to provide additional indemnification benefits, including the right to receive, in advance, reimbursements for expenses incurred in connection with a defense for which the director or officer is entitled to indemnification. We believe that the limitation of liability provisions in our certificate of incorporation, bylaws and the indemnity agreements will facilitate our ability to continue to attract and retain qualified individuals to serve as directors and officers. 
+Conflicts of Interest 
+The related party transactions described herein may cause certain conflicts of interests, including that: 
+♦ we may enter into contracts between us, on the one hand, and related parties, on the other, that are not as a result of arm’s-length transactions; 
+♦ our executive officers and directors that hold positions of responsibility with related parties may be aware of certain business opportunities that are appropriate for presentation to us as well as to such other related parties and may present such business opportunities to such other parties; and 
+♦ our executive officers and directors that hold positions of responsibility with related parties may have significant duties with, and spend significant time serving, other entities and may have conflicts of interest in allocating time. 
+For example, Mr. Wright, our Chief Executive Officer, is the Executive Chairman of Liberty Resources, a position which may require a portion of his time and which may cause conflicts of interest in pursuing business opportunities of which he becomes aware. 
+46
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+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+WASHINGTON, D.C. 20549 
+FORM 10-K 
+(Mark One) 
+☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the Fiscal Year Ended December 31 , 2021 
+OR 
+☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+Commission File No. 001-38081 
+Liberty Oilfield Services Inc. 
+(Exact Name of Registrant as Specified in its Charter) 
+Delaware 
+81-4891595 
+(State or Other Jurisdiction of Incorporation or Organization) (I.R.S. Employer Identification No.) 
+950 17th Street , Suite 2400 
+Denver , Colorado 
+80202 
+(Address of Principal Executive Offices) (Zip Code) 
+( 303 ) 515-2800 
+(Registrant’s Telephone Number, Including Area Code) 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of each class Trading symbol(s) Name of each exchange on which registered 
+Class A Common Stock, par value $0.01 LBRT New York Stock Exchange 
+Securities registered pursuant to Section 12(g) of the Act: None 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☒ Yes ☐ No 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐ Yes ☒ No 
+Indicate by check mark whether the registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No 
+Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this Chapter) during the presiding 12 months (or for such shorter period that the registrant was required to submit and post such files). ☒ Yes ☐ No 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. 
+Large Accelerated Filer ☒ 
+Accelerated Filer ☐ Non-accelerated filer ☐ 
+Smaller reporting company ☐ 
+Emerging growth company ☐ 
+If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ 
+Indicate by check mark whether the registrant has filed a report on an attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act): ☐ Yes ☒ No 
+As of June 30, 2021, the last business day of the registrant ’ s most recently completed second fiscal quarter, the aggregate market value of voting and non-voting common stock held by non-affiliates of the registrant was approximately $ 1.5 billion, determined using the per share closing price on the New York Stock Exchange on that date of $14.16. Shares of common stock held by each director and executive officer (and their respective affiliates) and each person who owns 10 percent or more of the outstanding common stock or who is otherwise believed by the registrant to be in a control position have been excluded. This determination of affiliate status is not necessarily a conclusive determination for other purposes. 
+At February 18, 2022 the Registrant had 183,645,580 shares of Class A Common Stock and 2,449,191 shares of Class B Common Stock outstanding. 
+Documents Incorporated by Reference: Part III of this Annual Report on Form 10-K incorporates certain information by reference from the registrant ’ s proxy statement for the 2022 annual meeting of stockholders to be filed no later than 120 days after the end of the registrant ’ s fiscal year. 
+TABLE OF CONTENTS 
+Page No. 
+PART I 
+Item 1. 
+Business 
+1 
+Item 1A. 
+Risk Factors 
+12 
+Item 1B. 
+Unresolved Staff Comments 
+26 
+Item 2. 
+Properties 
+26 
+Item 3. 
+Legal Proceedings 
+26 
+Item 4. 
+Mine Safety Disclosures 
+26 
+PART II 
+Item 5. 
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+27 
+Item 6. 
+[Reserved] 
+28 
+Item 7. 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+30 
+Item 7A. 
+Quantitative and Qualitative Disclosure about Market Risk 
+41 
+Item 8. 
+Financial Statements and Supplementary Data 
+42 
+Item 9. 
+Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+42 
+Item 9A. 
+Controls and Procedures 
+42 
+Item 9B. 
+Other Information 
+42 
+PART III 
+Item 10. 
+Directors, Executive Officers and Corporate Governance 
+43 
+Item 11. 
+Executive Compensation 
+43 
+Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+43 
+Item 13. 
+Certain Relationships and Related Transactions, and Director Independence 
+43 
+Item 14. 
+Principal Accountant Fees and Services 
+43 
+PART IV 
+Item 15. 
+Exhibits and Financial Statement Schedules 
+44 
+Item 16. 
+Form 10-K Summary 
+45 
+SIGNATURES 
+49 
+i 
+CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS 
+This Annual Report on Form 10-K (“Annual Report”) and certain other communications made by us contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange of 1934, as amended (the “Exchange Act”), including statements about our expected growth from recent acquisitions such as the PropX Acquisition (as defined below) and OneStim Acquisition (as defined below), expected performance, future operating results, oil and natural gas demand and prices and the outlook for the oil and gas industry, future global economic conditions, the impacts of the novel strain of the coronavirus (“COVID-19”) pandemic, improvements in operating procedures and technology, our business strategy and the business strategies of our customers, in addition to other estimates, and beliefs. For this purpose, any statement that is not a statement of historical fact should be considered a forward-looking statement. We may use the words “estimate,” “outlook,” “project,” “position,” “potential,” “likely,” “believe,” “anticipate,” “plan,” “expect,” “intend,” “achievable,” “anticipate,” “may,” “will,” “continue,” “should,” “could” and similar expressions to help identify forward-looking statements. However, the absence of these words does not mean that the statements are not forward-looking. We cannot assure you that our assumptions and expectations will prove to be correct. Important factors could cause our actual results to differ materially from those indicated or implied by forward-looking statements, including but not limited to the risks described in this Annual Report and other filings that we make with the U.S. Securities Exchange Commission (the “SEC”). We undertake no intention or obligation to update or revise any forward-looking statements, except as required by law, whether as a result of new information, future events or otherwise and readers should not rely on the forward-looking statements as representing the Company’s views as of any date subsequent to the date of the filing of this Annual Report. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. 
+All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. 
+MARKET AND INDUSTRY DATA 
+This Annual Report includes market and industry data and certain other statistical information based on third-party sources including independent industry publications, government publications and other published independent sources, such as content and estimates provided by Lium, LLC (“Lium Research”) as of December 31, 2021 and industry content and figures provided by Baker Hughes Co. (“Baker Hughes”) as of December 31, 2021. Neither Lium Research nor Baker Hughes is a member of the Financial Industry Regulator Authority or the Securities Investor Protection Corporation and neither is a registered broker dealer or investment advisor. Although we believe these third-party sources are reliable as of their respective dates, we have not independently verified the accuracy or completeness of this information. Some data is also based on our own good faith estimates, which are supported by our management's knowledge of and experience in the markets and business in which we operate. 
+TRADEMARKS, SERVICE MARKS AND TRADENAMES 
+This Annual Report contains trademarks, tradenames, and service marks that are owned by us or other companies, which are our property. Solely for convenience, the trademarks, tradenames, and service marks referred to in this Annual Report may appear without the ® and TM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the rights of the applicable licensors to these trademarks, tradenames, and service marks. We do not intend our use or display of other parties’ trademarks, tradenames, or service marks to imply, and such use or display should not be construed to imply, a relationship with, or endorsement or sponsorship of us by, these other parties. 
+ii 
+PART I 
+As used in this Annual Report, except as otherwise indicated or required by the context, all references in this Annual Report to (i) the “Company,” “we,” “us” and “our” refer to Liberty Oilfield Services Inc. and its consolidated subsidiaries; (ii) “Liberty LLC” refer to Liberty Oilfield Services New HoldCo LLC; (iii) “Schlumberger” refer to, collectively, Schlumberger Technology Corporation and Schlumberger Canada Limited; and (iv) “PropX” refer to Proppant Solutions, LLC and its predecessor in interest. 
+Item 1. Business 
+Our Company 
+We are a leading integrated oilfield services and technology company focused on providing innovative hydraulic services and related technologies to onshore oil and natural gas exploration and production (“E&P”) companies in North America. We offer customers hydraulic fracturing services, together with complementary services including wireline services, proppant delivery solutions, data analytics, related goods (including our sand mine operations), and technologies that will facilitate lower emission completions, thereby helping our customers reduce their emissions profile. 
+Our primary locations of operation include the Permian Basin, the Eagle Ford Shale, the Denver-Julesburg Basin (the “DJ Basin”), the Williston Basin, the San Juan Basin, the Powder River Basin, the Haynesville Shale, the South Central Oklahoma Oil Province and Sooner Trend Anadarko Canadian Kingfisher (collectively, the “SCOOP/STACK”), the Marcellus Shale, the Utica Shale, and the Western Canadian Sedimentary Basin, which are among the most active basins in North America. The breadth of our operational footprint provides us an opportunity to leverage our fixed costs and to efficiently reposition our equipment in response to customer requirements. The map below represents our current areas of operation. 
+The process of hydraulic fracturing involves pumping a pressurized stream of fracturing fluid (typically a mixture of water, chemicals and proppant) into a well casing or tubing to cause the underground formation to fracture or crack. These fractures release trapped hydrocarbon particles and provide a conductive channel for the oil or natural gas to flow freely to the wellbore for collection. The propping agent, or proppant, typically sand, becomes lodged in the cracks created by the hydraulic fracturing process, “propping” them open to facilitate the flow of hydrocarbons from the reservoir to the well. The fracturing 
+1 
+fluid is engineered to lose viscosity, or “break,” and is subsequently flowed back from the formation, leaving the proppant suspended in the formation fractures. Once our customer has flushed the fracturing fluids from the well using a controlled flow-back process, the customer manages fluid and water recycling or disposal. 
+Our hydraulic fracturing fleets consist of mobile hydraulic fracturing units and other auxiliary heavy equipment to perform fracturing services. Our hydraulic fracturing units consist primarily of high-pressure hydraulic pumps, engines, transmissions, radiators and other supporting equipment that are typically mounted on trailers. We refer to the group of units and other equipment, such as blenders, data vans, sand storage, tractors, manifolds and high pressure fracturing iron, which are necessary to perform a typical hydraulic fracturing job, as a “fleet,” and the personnel assigned to each fleet as a “crew.” The size of each fleet and crew can vary depending on the requirements of each job design. 
+We also have wireline operations as a result of the acquisition of Schlumberger’s OneStim business in December 2020, whereby we obtained certain assets and liabilities of the OneStim business including OneStim’s hydraulic fracturing pressure pumping services business in onshore United States and Canada (the “OneStim Acquisition”). Our wireline units consist of a truck equipped with a spool of wireline that is lowered into wells to convey specialized tools or equipment, such as perforating guns and charges, that are necessary to connect the wellbore with the target formation. This operation is performed between each hydraulic fracturing stage. Our wireline service is primarily offered alongside our hydraulic fracturing services, which allows us to maximize efficiency for our customers through optimized coordination of the wireline and hydraulic fracturing services. In addition, we also offer our wireline service on a stand-alone basis. 
+As a result of the PropX Acquisition, which was completed in October 2021 (described in this Annual Report under “—Recent Developments—PropX Acquisition”), we are now a leading provider of last-mile proppant delivery solutions, including proppant handling equipment and logistics software across North America. PropX offers innovative environmentally friendly technology with optimized dry and wet sand containers and wellsite proppant handling equipment that drive logistics efficiency and reduce noise and emissions. We believe that PropX wet sand handling technology is a key enabler of the next step of cost and emissions reductions in the proppant industry. PropX also offers customers the latest real-time logistics software, PropConnect™, for sale or as hosted software as a service. 
+Our operations are organized into a single business segment, which consists of hydraulic fracturing services, including wireline, proppant delivery and goods, including our Permian Basin sand mines, and we have one reportable geographical segment, North America. We have grown from one active hydraulic fracturing fleet as of December 2011 to over 30 active fleets as of December 31, 2021. We are focused on providing “next-generation” frac fleets and technologies to assist our customers with completing their wells in an ESG-friendly manner. 
+Our founders and management are pioneers in the development of data-driven hydraulic fracturing technologies for application in shale plays. Prior to founding the Company, the majority of our management team founded and built Pinnacle Technologies, Inc. (“Pinnacle Technologies”) into a leading fracturing technology company. In 1992, Pinnacle Technologies developed the first commercial hydraulic fracture mapping technologies, analytical tools that played a major role in launching the shale revolution. Our extensive experience with fracture technologies and customized fracture design has enabled us to develop new technologies and processes that provide our customers with real-time solutions that significantly enhance their completions. These technologies include hydraulic fracture propagation models, reservoir engineering tools, large, proprietary shale production databases and multi-variable statistical analysis techniques. Taken together, these technologies have enabled us to be a leader in hydraulic fracture design innovation and application. Our management team has an average of over 20 years of oilfield services experience, and the majority of our management team worked together before founding our company. 
+We believe technical innovation and strong relationships with our customer and supplier bases distinguish us from our competitors and are the foundations of our business. We expect that E&P companies will continue to focus on technological innovation as completion complexity and fracture intensity of horizontal wells increases, particularly as customers are increasingly focused on reducing emissions from their completions operations. We remain proactive in developing innovative solutions to industry challenges, including developing: (i) our databases of U.S. unconventional wells to which we apply our proprietary multi-variable statistical analysis technologies to provide differential insight into fracture design optimization; (ii) our Liberty Quiet Fleet® design which significantly reduces noise levels compared to conventional hydraulic fracturing fleets; (iii) hydraulic fracturing fluid systems tailored to the specific reservoir properties in the basins in which we operate and (iv) our dual fuel dynamic gas blending fleets that allow our engines to run diesel or a combination of diesel and natural gas, to optimize fuel use, reduce emissions and lower costs. In addition, our integrated supply chain includes proppant, chemicals, equipment, logistics and integrated software which we believe promotes wellsite efficiency and leads to more pumping hours and higher productivity throughout the year to better service our customers. In order to achieve our technological objectives, we carefully manage our liquidity and debt position to promote operational flexibility and invest in the business throughout the full commodity cycle. 
+2 
+Recent Developments 
+PropX Acquisition 
+On October 26, 2021, the Company acquired Proppant Express Investments, LLC in exchange for $11.9 million in cash and 3,405,526 shares of Class A Common Stock and 2,441,010 shares of Class B common stock, par value $0.01 per share (“Class B Common Stock” and, together with Class A Common Stock, the “Common Stock”), and 2,441,010 units of Liberty LLC (“Liberty LLC Units”), for total consideration of $103.0 million, based on the Class A Common Stock closing price of $15.58 on October 26, 2021, subject to customary post-closing adjustments (the “PropX Acquisition”). The Liberty LLC Units are redeemable for an equivalent number of shares of Class A Common Stock at any time, at the election of the shareholder. See Note 3 —Acquisitions to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.” 
+Joinder to Liberty LLC Agreement 
+In connection with the PropX Acquisition, each of the sellers and certain of their investors that received Liberty LLC units, entered into a joinder to the Second Amended and Restated Limited Liability Company Agreement of Liberty LLC (the “Liberty LLC Agreement”). Under the Liberty LLC Agreement, holders, subject to certain limitations, have the right, pursuant to a redemption right, to cause Liberty LLC to acquire all or a portion of their Liberty LLC Units for, at Liberty LLC’s election, (i) shares of our Class A Common Stock at a redemption ratio of one share of Class A Common Stock for each Liberty LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification or (ii) an equivalent amount of cash. Alternatively, upon the exercise of the redemption right, we (instead of Liberty LLC) have a call right to acquire each tendered Liberty LLC Unit directly from the holder for, at its election, (x) one share of Class A Common Stock or (y) an equivalent amount of cash. In addition, upon a change of control, we have the right to require each holder of Liberty LLC Units (other than us) to exercise its redemption right with respect to some or all of such unitholder’s Liberty LLC Units. As the holders redeem their Liberty LLC Units, our membership interest in Liberty LLC will be correspondingly increased, the number of shares of Class A Common Stock outstanding will be increased, and the number of shares of Class B Common Stock outstanding will be reduced. 
+ABL Facility 
+On October 22, 2021, we entered into an amendment with respect to our ABL Facility. Under the terms of the amendment, the maximum borrowing amount was increased to $350.0 million, subject to certain borrowing base limitations based on a percentage of eligible accounts receivable and inventory (with the ability to request an increase in the size of the ABL Facility by $75 million). Additionally, limits under certain covenants related to allowable indebtedness and other activities were expanded. The ABL Facility maturity was extended to the earlier of (i) October 22, 2026 and (ii) to the extent the debt under the Term Loan Facility remains outstanding 90 days prior to the final maturity of the Term Loan Facility. All other financial provisions under the original agreement are still applicable to the ABL Facility aside from the aforementioned changes to the borrowing base. 
+Term Loan Facility 
+On October 22, 2021, we entered into a Fifth Amendment to Credit Agreement, Second Amendment to Guaranty and Security Agreement and Termination of Right of First Offer Letter (the “Term Loan Credit Agreement Amendment”). The Term Loan Credit Agreement Amendment further amends the credit agreement and guaranty and security agreement and terminates the right of first offer letter originally entered into by the parties on September 19, 2017 (the “Right of First Offer Letter”), which governs our Term Loan Facility. Along with other revisions, the Term Loan Credit Agreement Amendment (i) increased certain indebtedness baskets; (ii) provided additional flexibility for a potential future internal structuring; (iii) extended the maturity date through September 19, 2024; and (iv) terminated a right of first offer in favor of the Term Loan Facility lenders. 
+ESG Focused 
+While we recognize the various environmental and social impacts of hydrocarbon energy, we believe that access to life-enhancing modern energy presents the most pressing global energy challenge. We passionately work to better the process of bringing hydrocarbons to the surface in a clean, safe and efficient fashion and view ESG principles as foundational to our business. We focus on developing and adding technologies to our operations that assist our customers in implementing their ESG goals. The list below sets forth specific examples of our efforts towards ESG principles: 
+• In 2013, we introduced Tier 2 dual-fuel technology to our fleets which allows our frac pumps to use natural gas in place of some diesel fuel to lower particulate emissions. 
+3 
+• In 2014, we began the use of containerized sand delivery at frac locations, which reduces dust, noise and truck traffic. 
+• In 2016, we introduced Quiet Fleet® technology, which significantly reduces noise levels associated with frac operations. 
+• In 2018, we began a partnership with an equipment supplier to introduce Tier 4 dynamic gas blending, or DGB, engines to our frac fleet that can substitute up to 80% of the diesel typically used by a frac pump with natural gas and significantly lower emission levels in frac operations. Tier 4 DGB engines were added to our fleet in 2020. 
+• In 2021, we announced the successful test of digiFrac™, our innovative, purpose-built electric frac pump that has approximately a 25% lower CO2e emission profile than the Tier IV DGB. We have entered into two multi-year arrangements with customers for digiFrac fleets and expect to deliver the first fleet into commercial service in 2022. 
+• In October 2021, we closed the acquisition of PropX. PropX offers innovative, environmentally friendly technology with optimized dry and wet sand containers and wellsite proppant handling equipment that drive logistics efficiency and reduce noise and emissions. 
+We are continuously committed to engagement in our communities. We provide K-12 scholarships to low-income children through ACE (Alliance for Choice in Education) and we have launched a Liberty Scholars program at Montana Technological University to enable lower income students to obtain a college engineering education. In 2021, over 100 students received Liberty scholarships. We have numerous other efforts targeting schools, veterans, poverty abatement, low-income housing, criminal justice reform and job opportunities for those who had a disadvantaged start in life. In 2021, we launched Love, Liberty, our matching program that is aimed to encourage our employees to get involved in their communities. 
+Cyclical Nature of Industry 
+We operate in a highly cyclical industry. The key factor driving demand for our services is the level of drilling activity by E&P companies, which in turn depends largely on the current and anticipated economics of new well completions. Global supply and demand for oil and the domestic supply and demand for natural gas are critical in assessing industry outlook. Demand for oil and natural gas is cyclical and subject to large, rapid fluctuations, such as those experienced in 2020. E&P companies tend to increase capital expenditures in response to increases in oil and natural gas prices, which generally results in greater revenues and profits for oilfield service companies such as ours. Increased capital expenditures also ultimately lead to greater production, which historically has resulted in increased supplies of hydrocarbons and reduced prices which in turn tend to drive a future reduction in E&P companies capital expenditures and reduce demand for oilfield services. For these reasons, the results of our operations may fluctuate from quarter to quarter and from year to year, and these fluctuations may distort comparisons of results across periods. 
+Seasonality 
+Our results of operations have historically reflected seasonal tendencies relating to holiday seasons, inclement weather and the conclusion of our customers’ annual drilling and completion capital expenditure budgets. Our most notable declines typically occur in the fourth quarter of the year for the reasons described above. Additionally, some of the areas in which we have operations, including Canada, the DJ Basin, Powder River Basin and Williston Basin, are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice, rain, or frost, and related road restrictions, we may be unable to move our equipment between locations, thereby reducing our ability to provide services and generate revenues. The exploration activities of our customers may also be affected during such periods of adverse weather conditions. Additionally, extended drought conditions in our operating regions could impact our ability or our customers’ ability to source sufficient water or increase the cost for such water. 
+Intellectual Property 
+Over the last several years and in connection with the acquisitions of OneStim and PropX, we have significantly invested in our research and technology capabilities. Our efforts to date have been focused on developing innovative, fit-for-purpose solutions designed to enhance our core service offerings, increase completion efficiencies, provide cost savings to our operations and add value for our customers. A cornerstone of our technological advantage is a series of proprietary databases of U.S. unconventional wells that include production data, completion designs and reservoir characteristics. We utilize these databases to perform multi-variable statistical analysis that generates differential insight into fracture design optimization to enhance our customers’ production economics. Our emphasis on data analytics is also deployed during job execution through the use of real-time feedback on variables that maximizes customer returns by improving cost-effective hydraulic fracturing operations. 
+Today, we hold over 500 patents and patent licenses relating to our engineering and technology solutions. We seek patent and trademark protections for our technology when we deem it prudent, and we aggressively pursue protection of these rights when warranted. We believe our patents, trademarks, and other protections for our proprietary technologies are adequate for the conduct of our business and that no single patent or trademark is critical to our business. In addition, we rely, to a great extent, 
+4 
+on the technical expertise and know-how of our personnel to maintain our competitive position, and we take commercially reasonable measures to protect trade secrets and other confidential and/or proprietary information relating to the technologies we develop. 
+Human Capital Management 
+As of December 31, 2021, we had 3,601 employees and no unionized labor. We believe we have good relations with our employees and that one of our key competitive advantages is our people. Our highly trained, experienced and motivated employees are critical to delivering our hydraulic fracturing services. Taking care of our employees is one of our top priorities, and we continually invest in hiring, training and retaining the employees we believe to be the best in our field. We consistently assess the current business environment and labor market to refine our compensation and benefits programs in order to attract and retain top talent in our industry. We temporarily implemented a company-wide employee furlough plan in connection with COVID-19 due to the uncertain level of frac demand we experienced during the second and third quarters of 2020, but as of September 30, 2020, all employees were returned from furlough. During 2021, we experienced increased turnover in field employee positions; however that trend improved in the later part of the year and into 2022. We strive to promote from within our existing employee base to manage new hydraulic fracturing fleets and organically grow our operating expertise. This organic growth is essential in achieving the expertise and level of customer service we strive to provide each of our customers. As a result, we plan to continue to invest in our employees through both personal and professional training to attract and retain the best individuals in our areas of operation. Overall, we focus on individual contributions and team success to foster a culture built around operational excellence and superior safety. 
+Health and Safety 
+Our people are our most important asset and ensuring their safety and the safety of those around them is the most important thing we do. Making certain that the Liberty team is well trained to handle the complexities of daily field operations, and that their training and competency remains current with the latest technology and standards is a key component. In order to facilitate this training, we have developed the Liberty Frac Academy, a thorough program where employees are trained on various aspects of the Company, from safety in equipment operation to leadership skills. The Liberty Frac Academy not only ensures dissemination of high-quality training material, but also provides a forum for sharing best practices and lessons learned across the Company. As a result, we are among the safest service providers in the industry with a constant focus on Health, Safety and Environmental performance and service quality, as evidenced by an average incident rate that was 10% less than the industry average from 2019 to 2021. Our employee-centered focus and reputation for safety has enabled us to obtain projects from industry leaders with some of the most demanding safety and operational requirements. We have implemented and continue to implement safety measures in all of our facilities to address the COVID-19 pandemic. 
+Programs and Benefits 
+One way we have demonstrated a history of investing in our workforce is by offering competitive salaries and wages. To foster a strong sense of ownership, restricted stock units are provided to eligible employees under our long term incentive plan. Furthermore, we offer innovative benefits to all eligible employees, including, among others, comprehensive health insurance coverage, parental leave to all new parents, for birth or adoption, financial support for child adoption, leave to care for partners with serious health conditions, 401(k) savings plan and educational tuition assistance for both bachelor’s degree and master’s degree programs. We are also passionate about community investment and, in 2019, we joined the Ban the Box initiative which provides work opportunities for formerly incarcerated individuals. 
+Governmental Regulation and Climate Change 
+As a company with operations in both the United States and Canada, we are subject to the laws of both jurisdictions in which we operate and the rules and regulations of various governing bodies, which may differ among those jurisdictions. Compliance with these laws, rules and regulations has not had, and is not expected to have, a material effect on our capital expenditures, results of operations and competitive position as compared to prior periods. We are also subject to numerous environmental and regulatory requirements related to our operations. For further information related to such regulation, see the risks described under the heading “Risk Factors” in this Annual Report. 
+Our operations are subject to numerous stringent and complex laws and regulations at the federal, state, and local levels governing the discharge of materials into the environment, environmental protection, and health and safety aspects of our operations. Failure to comply with these laws and regulations or to obtain or comply with permits may result in the assessment of administrative, civil, and criminal penalties, imposition of remedial or corrective action requirements, and the imposition of injunctions or other orders to prohibit certain activities, restrict certain operations, or force future compliance with environmental requirements. 
+5 
+There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons, other hazardous substances, and wastes, as a result of air emissions and wastewater discharges related to our operations, and because of historical operations and waste disposal practices. Spills or other releases of regulated substances, including such spills and releases that occur in the future, could expose us to material losses, expenditures, and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. The following is a summary of some of the existing laws, rules, and regulations to which we are subject. 
+U.S. Laws and Regulations 
+Hazardous Substances and Waste Handling 
+The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Under guidance issued by the U.S. Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. RCRA currently exempts many E&P wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes intrinsically associated with the exploration, development, or production of crude oil and natural gas. However, these E&P wastes may still be regulated under state solid waste laws and regulations, and it is possible that certain oil and natural gas E&P wastes now classified as non-hazardous could be classified as hazardous waste in the future. Stricter regulation of wastes generated during our or our customers’ operations could result in increased costs for our operations or the operations of our customers, which could in turn reduce demand for our services and adversely affect our business. We cannot guarantee that the EPA will not revisit the exemption of E&P waste or that waste will not become more heavily regulated at the federal or state level. 
+Comprehensive Environmental Response, Compensation, and Liability Act 
+The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owner or operator of the site where the release occurred and anyone who transported or disposed or arranged for the transport or disposal of a hazardous substance released at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA and any state analogs may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources and for the costs of certain health studies. We currently own, lease, or operate numerous properties that have been used for manufacturing and other operations for many years. These properties and the substances disposed or released on them may be subject to CERCLA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. 
+Worker Health and Safety 
+We are subject to a number of federal and state laws and regulations, including the OSHA, establishing requirements to protect the health and safety of workers. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require maintenance of information about hazardous materials used or produced in operations and provision of this information to employees, state and local government authorities, and citizens. Specifically, OSHA has enacted a regulation regarding crystalline silica exposures, which included requirements that hydraulic fracturing operations implement dust controls to limit exposures to the substance. Additionally, the Federal Motor Carrier Safety Administration (the “FMCSA”) regulates and provides safety oversight of commercial motor vehicles, the EPA establishes requirements to protect human health and the environment, the federal Bureau of Alcohol, Tobacco, Firearms and Explosives establishes requirements for the safe use and storage of explosives, and the federal Nuclear Regulatory Commission establishes requirements for the protection against ionizing radiation. Substantial fines and penalties can be imposed, and orders or injunctions limiting or prohibiting certain operations may be issued, in connection with any failure to comply with these laws and regulations. 
+6 
+Water Discharges 
+The federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the U.S. The discharge of pollutants into regulated waters, including jurisdictional wetlands, is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. To the extent the agencies expanding the range of properties subject to the Clean Water Act’s jurisdiction, certain energy companies could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas, which in turn could reduce demand for our services. Furthermore, the process for obtaining permits has the potential to delay our operations and those of our customers. Spill prevention, control, and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture, or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of wastewater and storm water runoff from certain types of facilities. The Clean Water Act and analogous state laws provide for administrative, civil, and criminal penalties for unauthorized discharges and, together with the Oil Pollution Act of 1990, impose rigorous requirements for spill prevention and response planning, as well as substantial potential liability for the costs of removal, remediation, and damages in connection with any unauthorized discharges. 
+Air Emissions 
+The federal Clean Air Act (the “CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. These regulations change frequently. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements, or utilize specific equipment or technologies to control emissions of certain pollutants. In recent years, the CAA has been used to impose additional stringent requirements upon oil and gas production operations. While these rules may not be directly applicable to our business, they are applicable to the business of our customers. Promulgation of stricter permitting requirements could delay or impair our or our customers’ ability to obtain air emission permits, to develop new wells and to continue to operate existing wells, and result in fewer wells being drilled or redeveloped, causing a decrease in demand for our services. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties, as well as injunctive relief, for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. 
+Climate Change 
+The EPA has determined that emissions of greenhouse gases, including carbon dioxide and methane, present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. The EPA has established greenhouse gas emissions reporting requirements for sources in the oil and gas sector and has also promulgated rules requiring certain large stationary sources of greenhouse gases to obtain preconstruction permits under the CAA and follow “best available control technology” requirements. Although we are not likely to become subject to greenhouse gas emissions permitting and best available control technology requirements because none of our facilities are presently major sources of greenhouse gas emissions, such requirements could become applicable to our customers. In addition, the EPA has used the CAA to impose additional greenhouse gas emissions control requirements upon our customers. These additional requirements on greenhouse gas emissions from our customers could have an adverse effect on their costs of operations or financial performance, thereby adversely affecting our business, financial condition, and results of operations. Also, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, and many states have already established regional greenhouse gas “cap-and-trade” programs. The adoption of any legislation or regulation that restricts emissions of greenhouse gases from the equipment and operations of our customers or with respect to the oil and natural gas they produce could adversely affect demand for our products and services. 
+Hydraulic Fracturing 
+Our business is clearly dependent on hydraulic fracturing and horizontal drilling activities. As further described herein, hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shale. The process, which involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. Specifically, there is considerable uncertainty surrounding regulation of the emissions of methane, which may be released during hydraulic fracturing, chemicals used in the hydraulic fracturing process, the discharge of wastewater from hydraulic 
+7 
+fracturing operations and concerns about the triggering of seismic activity by the injection of produced waters into underground wells. Certain proposed regulation could make it significantly more difficult and/or costly to drill and operate oil and gas wells. If adopted, such regulation could result in a decline in the completion of new oil and gas wells or the recompletion of existing wells, which could negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the demand for our services. Given the long-term trend towards increasing regulation, future regulation in the industry remains a possibility. 
+Some states, counties, and municipalities have enacted or are considering moratoria on hydraulic fracturing. For example, New York, Vermont, Maryland, and Washington have banned, or are in the process of banning, the use of high-volume hydraulic fracturing. Alternatively, some municipalities are, or have considered, zoning and other ordinances, the conditions of which could impose a de facto ban on drilling and/or hydraulic fracturing operations. Further, some states, counties, and municipalities are closely examining water use issues, such as permit and disposal options for processed water, which could have a material adverse impact on our financial condition, prospects, and results of operations if such additional permitting requirements are imposed upon our industry. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could reduce demand for our business by making it more difficult or costly for certain customers to perform fracturing to stimulate production from tight formations. 
+National Environmental Policy Act 
+Businesses and operations of our customers that are carried out on federal lands may be subject to the National Environmental Policy Act (“NEPA”), which requires federal agencies, including the U.S. Department of the Interior, to evaluate major agency actions having the potential to significantly impact the human environment. In the course of such evaluations, an agency will evaluate the potential direct, indirect, and cumulative impacts of a proposed project and, if necessary, will prepare a detailed Environmental Impact Statement that must be made available for public review and comment. To the extent that our customers’ current activities, as well as proposed plans, on federal lands require governmental permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects which in turn could reduce demand for our services. 
+Endangered Species Act and Migratory Bird Treaty Act 
+The federal Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or its habitat. The U.S. Fish and Wildlife Service (the “FWS”) must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”), which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit. This prohibition covers most bird species in the U.S. Future implementation of the rules implementing the ESA and the MBTA are uncertain. If our customers were to have areas within their business and operations designated as critical or suitable habitat for a protected species, it could decrease demand for our services and have a material adverse effect on our business. 
+Canadian Laws and Regulations 
+Companies such as us offering oilfield services that include hydraulic fracturing, engineering, and wireline services in the Province of Alberta in Canada are regulated by both the provincial government of Alberta (“Province”) and the federal government of Canada (“Canada”). This includes, but is not limited to, regulation related to environmental protection legislation, climate change legislation, fracking legislation, and legislation related to wildlife. In addition to being regulated by the Province and Canada, oilfield services companies may also be subject to other international, national, and subnational laws, regulations, and policies. 
+Provincial Legislation 
+Oilfield services companies are primarily regulated by provincial governments in Canada. For example, in Alberta, provincial legislation potentially applicable to our Canadian operations includes the Environmental Protection and Enhancement Act, RSA 2000, e E-12. This Act promotes the protection, enhancement and wise use of the environment, and deals with matters such as air emissions, water discharges, and the handling of hazardous substances and waste control (for example, under the Waste Control Regulation, Alta Reg 192/1996). 
+Other potentially applicable provincial legislation in Alberta includes legislation directed at the transportation of dangerous goods, including oil (the Dangerous Goods Transportation and Handling Act, RSA 2000, c D-4 and associated regulations), legislation intended to provide for the responsible management of oil wells and associated sites (the Oil and Gas 
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+Conservation Act, RSA 2000, c O-6), legislation establishing regulatory bodies overseeing oil and gas and electricity in Alberta (the Responsible Energy Development Act, SA 2012, c R-17.3 and the Alberta Utilities Commission Act, SA 2007, c A-37.2), legislation governing the removal of gas or propane from Alberta (the Gas Resources Preservation Act, RSA 2000, c G-4), legislation to effect conservation and prevent waste of the oil sands resource in Alberta (the Oil Sands Conservation Act, RSA 2000, c O-7) and legislation governing worker safety (the Occupational Health and Safety Act, SA 2017, c O-2.1). 
+The Alberta Energy Regulator has a number directives that are applicable to oilfield services companies, such as Directive 050 which addresses salinity ranges for soils that can receive drilling wastes, and Directive 058, which sets out regulatory requirements for the handling, treatment, and disposal of upstream oilfield waste. Other provinces in Canada have their own statutory regime applicable to oilfield service companies. 
+Federal Legislation 
+The Federal government in Canada shares certain jurisdiction with the provinces over certain environmental matters. Federal legislation potentially applicable to our Canadian operations includes legislation focused on regulating greenhouse gases (the Greenhouse Gas Pollution Pricing Act, SC 2018, c 12, s 186), legislation aimed at protecting wildlife (the Species at Risk Act, SC 2002, c 29), legislation governing approvals for projects (the Impact Assessment Act, SC 2019, c 28, s 1), and legislation governing the transportation of potentially dangerous substances (the Transportation of Dangerous Goods Act, 1992, SC 1992, c 34). 
+Properties 
+Properties 
+Our corporate headquarters are located at 950 17 th Street, Suite 2400, Denver, Colorado 80202. We lease our general office space at our corporate headquarters. The lease expires in December 2027. We currently own or lease the following additional principal properties: 
+District Facility Location Size Leased or Owned 
+Midland, TX 160,000 sq. ft on 147 acres Owned 
+Odessa, TX 77,500 sq. ft on 47 acres Owned 
+Cibolo, TX 90,000 sq. ft on 34 acres Owned 
+Kermit, TX 5,000 acres Owned 
+Monahans, TX 3,200 acres Owned 
+Magnolia, TX 63,350 sq. ft. Leased (through May 31, 2031) 
+Shreveport, LA 225,000 sq ft. on 50 acres Owned 
+Cheyenne, WY 115,000 sq. ft on 60 acres Owned 
+Gillette, WY 32,757 sq. ft on 15 acres Leased (through December 31, 2034) 
+Henderson, CO 50,000 sq. ft on 13 acres Leased (through December 31, 2034) 
+Henderson, CO 96,582 sq. ft on 12 acres Owned 
+Williston, ND 30,000 sq. ft on 15 acres Owned 
+El Reno, OK 80,000 sq. ft on 33 acres Owned 
+Red Deer, AB 170,000 sq. ft on 42 acres Owned 
+Grand Prairie, AB 135,000 sq. ft on 40 acres Owned 
+Huallen, AB 80 acres Owned 
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+We also lease several smaller facilities, which leases generally have terms of one to six years. We believe that our existing facilities are adequate for our operations and their locations allow us to efficiently serve our customers. We do not believe that any single facility is material to our operations and, if necessary, we could readily obtain a replacement facility. 
+Marketing and Customers 
+We have developed long-term partnerships with our customers through a continuous dialogue focused on their production economics. Further, we have a proven track record of executing our customers’ plans and delivering on time and in line with expected costs. Our customer base includes a broad range of integrated and independent E&P companies, including some of the largest E&P companies in our areas of operation such as Occidental Petroleum Corp, ConocoPhillips Company and ExxonMobil. We believe our customer relationships enabled us to maintain higher utilization than many of our competitors during the downturn resulting from the COVID-19 pandemic. Our technological innovations, customer-tailored approach and track record of consistently providing high-quality, safe and reliable service has allowed us to develop long-term customer partnerships, which we believe makes us the service provider of choice for many of our customers. 
+Our sales and marketing activities typically are performed through our local sales representatives in each geographic region, and are supported by our corporate headquarters. For the years ended December 31, 2021, 2020 and 2019, our top five customers collectively accounted for approximatel y 27% , 48%, and 35% of our revenues, respectively. For the years ended December 31, 2021 and 2019, no customer accounted for more than 10% of our revenues. For the year ended December 31, 2020, PDC Energy Inc., WPX Energy, Conoco-Phillips Company, and Parsley Energy Operations, LLC each accounted for more than 10% of our revenues. 
+Suppliers and Raw Materials 
+We have a dedicated supply chain team that manages sourcing and logistics to ensure flexibility and continuity of supply in a cost effective manner across our areas of operation. We have built long-term relationships with multiple industry leading suppliers of proppant, chemicals and hydraulic fracturing equipment and have started to internally design and assemble key pump and maintenance parts. In addition, we have built a strong relationship with the assemblers of our custom-designed hydraulic fracturing fleets and believe we will continue to have timely access to new, high capability fleets as we continue to grow. In 2018, we vertically integrated a supplier of certain major components through the acquisition of ST9 Gas and Oil LLC. In October 2021, we vertically integrated a supplier of our containerized sand and last mile proppant logistics solutions with the acquisition of PropX. 
+We purchase a wide variety of raw materials, parts and components that are manufactured and supplied for our operations. We are not dependent on any single source of supply for those parts, supplies or materials. To date, we have generally been able to obtain the equipment, parts and supplies necessary to support our operations, although we have experienced delivery delays and shortages on some items. While we believe that we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers, we may not always be able to do so. In addition, certain materials for which we do not currently have long-term supply agreements could experience shortages and significant price increases in the future. As a result, we may be unable to mitigate any future supply shortages and our results of operations, prospects and financial condition could be adversely affected. The OneStim Acquisition included two state-of-the-art sand mines in the Permian Basin, which helps alleviate the risk of proppant supply shortages. 
+Competition 
+The markets in which we operate are highly competitive. We provide services in various geographic regions across the United States and Canada, and our competitors include many large and small oilfield service providers, including some of the largest integrated service companies. Our hydraulic fracturing services compete with large, integrated companies such as Halliburton Company as well as other companies including Calfrac Well Services Ltd., FTS International, Inc., NexTier Oilfield Solutions Inc., Universal Pressure Pumping, Inc., ProPetro Services, Inc., RPC, Inc., STEP Energy Services and U.S. Well Services, Inc. In addition, our industry is highly fragmented and we compete regionally with a significant number of smaller service providers. 
+We believe that the principal competitive factors in the markets we serve are technical expertise, equipment capacity, work force competency, efficiency, safety record, reputation, experience and price. Additionally, projects are often awarded on a bid basis, which tends to create a highly competitive environment. We seek to differentiate ourselves from our competitors by delivering the highest-quality services and equipment possible, coupled with superior execution and operating efficiency in a safe working environment. 
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+Available Information 
+We file or furnish annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The SEC also maintains an internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC. 
+We also make available free of charge through our website, www.libertyfrac.com, electronic copies of certain documents that we file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. 
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+Item 1A. Risk Factors 
+Described below are certain risks that we believe apply to our business and the industry in which we operate. You should carefully consider each of the risks described below in conjunction with other information including the financial statements and related notes provided in this Annual Report and in our other public disclosures. The risks described below highlight potential events, trends or other circumstances that could adversely affect our business, financial condition, results of operations, cash flows, liquidity or access to sources of financing, and consequently, the market value of our Class A Common Stock. These risks could cause our future results to differ materially from historical results and from guidance we may provide regarding our expectations of future financial performance. The risks described below are those that we have identified as material and is not an exhaustive list of all the risks we face. There may be other risks and uncertainties not currently known to us or that we currently deem to be immaterial which may also materially and adversely affect our business operations in the future. Please refer to the explanation of the qualifications and limitation on forward-looking statements set forth on page ii hereof. 
+Risks Related to the COVID-19 Pandemic 
+The COVID-19 pandemic significantly reduced demand for our services, and had, and may in the future have, a material adverse effect on our operations, business and financial results. 
+We face risks related to public health crises, including the ongoing COVID-19 pandemic. Many of the COVID-19 precautions taken by governments and businesses, including travel bans, prohibitions on group events and gatherings, shutdowns of certain businesses, curfews and shelter-in-place orders that were enacted in 2020 have been lifted or reduced. However, during 2020 these actions resulted in a significant and swift reduction in international and U.S. economic activity. The collapse in the demand for oil during 2020 caused by this unprecedented global health and economic crisis, coupled with an oil oversupply, had a material adverse impact on the demand for our services and on our financial condition, results of operations and cash flows. Additionally, the COVID-19 pandemic could worsen despite the increased availability of vaccines in certain jurisdictions, including as a result of the emergence of more infectious strains of the virus, vaccine hesitancy or increased business and social activities, which may cause governmental authorities to reconsider restrictions on business and social activities. 
+We are closely monitoring the continuing effects of the pandemic on our customers, operations, and employees. During 2021, oil demand and the demand for our services recovered from the lows experienced during the onset of the pandemic. The extent to which our operating and financial results will be affected by COVID-19 in the future will depend on various factors and consequences, such as the ultimate duration and scope of the pandemic, any additional actions by businesses and governments in response to the pandemic, and the speed and effectiveness of responses to combat the virus. COVID-19, and the volatile regional and global economic conditions stemming from the pandemic, could also aggravate the other risk factors that we identify herein. COVID-19 may also materially adversely affect our operating and financial results in a manner that is not currently known to us or that we do not currently consider presenting significant risks to us. 
+We cannot predict the ultimate duration or scope of the COVID-19 pandemic. Accordingly, if the pandemic worsens or if actions taken by governments and businesses in response to the pandemic in 2020 are re-enacted, the demand for our services may fall again, which would have a material adverse impact on our financial condition, results of operations and cash flows. 
+Potential future vaccine mandates for employers could have a material adverse impact on our business and results of operations. 
+On September 9, 2021, President Biden announced plans for the federal Occupational Safety and Health Administration (“OSHA”) to issue an Emergency Temporary Standard (“ETS”) mandating that all employers with more than 100 employees ensure their workers are either fully vaccinated against COVID-19 or produce, on a weekly basis, a negative COVID-19 test (the “Vaccine Mandate”). OSHA issued the ETS on November 4, 2021, requiring covered employers to comply with the Vaccine Mandate beginning with January 4, 2022 or face substantial penalties for non-compliance. The U.S. Supreme Court issued a stay on the Vaccine Mandate on January 13, 2022, and OSHA thereafter withdrew the ETS. It is possible that future vaccine mandates may be announced by the federal, state or local jurisdictions in which we operate. Although it is not possible to predict with certainty the impact of these measures on our business and workforce, these requirements may result in attrition, including attrition of skilled labor, and difficulty securing future labor needs, which could have a material adverse effect on our business, financial condition and results of operations. 
+12 
+Risks Related to the OneStim Acquisition 
+The Company's results may suffer if it does not effectively manage its expanded operations following the OneStim Acquisition. 
+Since the OneStim Acquisition, the size of the Company’s business has increased significantly. In addition, we now own and operate two sand mines. While we have retained qualified personnel to operate the mines, we have not undertaken mining operations in the past. The Company’s future success will depend, in part, on the Company’s ability to manage this expanded business, which poses numerous risks and uncertainties. 
+The Schlumberger Parties have significant influence over us. 
+As of February 18, 2022, Schlumberger owned approximately 30.5% of the outstanding shares of Common Stock. As long as Schlumberger owns or controls a significant percentage of the Company’s outstanding voting power, they will have the ability to significantly influence corporate actions requiring stockholder approval, including the election and removal of directors, any amendment to the Company’s certificate of incorporation or bylaws, or the approval of any merger or other significant corporate transaction, including a sale of substantially all of the Company’s assets. Schlumberger’s influence over our management could have the effect of delaying or preventing a change in control or otherwise discouraging a potential acquirer from attempting to obtain control of us, which could cause the market price of the shares of Class A Common Stock to decline or prevent stockholders from realizing a premium over the market price for the shares of Class A Common Stock. 
+Pursuant to the Amended and Restated Stockholders Agreement, dated as of December 13, 2020, Schlumberger has designated two directors to the Company’s board of directors. Schlumberger’s right to designate directors to our Board is subject to the Schlumberger’s ownership percentage of the total outstanding shares of Common Stock. If Schlumberger and its affiliates collectively beneficially own: (a) 20% or greater of the outstanding shares of Common Stock, they will have the right to appoint two directors or (b) at least 10% but less than 20% of the outstanding shares of Common Stock, they will have the right to appoint one director. 
+Schlumberger’s interests may not align with the Company’s interests or the interests of the Company’s other stockholders. 
+Following the OneStim Acquisition, we expanded our operations to Canada and may be subject to increased business and economic risks. 
+The Company has historically owned and operated its assets exclusively within the United States. In connection with the OneStim Acquisition, we acquired certain Canadian assets and liabilities, which marked our entry into a new geographical territory where we had limited experience in owning and operating assets and providing our services. As a result, we are subject to a variety of risks inherent in doing business internationally, including: risks related to the legal and regulatory environment in foreign jurisdictions; fluctuations in currency exchange rates; complying with multiple tax jurisdictions; difficulties in staffing and managing international operations and the increased travel, infrastructure and compliance costs associated with international locations and employees; regulations that might add difficulties in repatriating cash earned outside the United States and otherwise preventing us from freely moving cash; complying with statutory equity requirements; and complying with the U.S. Foreign Corrupt Practices Act and the Corruption of Foreign Public Officials Act (Canada) and other similar laws in Canada. If we fail to manage our operations in Canada successfully, our business may suffer. 
+13 
+Risks Related to the Oil and Natural Gas Industry 
+Federal, state, local and other applicable legislative and regulatory initiatives relating to hydraulic fracturing may serve to limit future oil and natural gas E&P activities and could have a material adverse effect on our results of operations and business. 
+Various federal, state, local and other applicable legislative and regulatory initiatives have been, or could be undertaken which could result in additional requirements or restrictions being imposed on hydraulic fracturing operations. Currently, hydraulic fracturing is generally exempt from federal regulation under the Safe Drinking Water Act Underground Injection Control (the “SDWA UIC”) program and is typically regulated by state oil and gas commissions or similar agencies but increased scrutiny and regulation, by federal agencies does occur. For example, in late 2016, the EPA released a final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources. Additionally, the EPA has asserted regulatory authority pursuant to the SDWA UIC program over hydraulic fracturing activities involving the use of diesel fuel in the fracturing fluid and issued guidance regarding the permitting of such activities. Furthermore, the U.S. Bureau of Land Management has previously published rules that established stringent standards relating to hydraulic fracturing on federal and Native American lands. Similarly, the EPA has adopted rules on the capture of methane and other emissions released during hydraulic fracturing. These rules have been the subject of ongoing legal challenges. In January 2021, President Biden issued an executive order that called for issuance of proposed rules by no later than September 2021 that would restore rules for methane standards applicable to new, modified, and reconstructed sources and establish new methane and volatile organic compound standards applicable to existing oil and gas operations, including the production, transmission, processing and storage segments. On November 2021, the EPA proposed such a rule. Such a rule could make it significantly more difficult and/or costly to drill and operate oil and gas wells. As a result, such rule, if adopted, could result in a decline in the completion of new oil and gas wells or the recompletion of existing wells, which could negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the demand for our services. In addition to federal regulatory actions, legislation has been introduced, but not enacted, in Congress to provide for further federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. 
+Moreover, many states and local governments have adopted regulations that impose more stringent permitting, disclosure, disposal and well-construction requirements on hydraulic fracturing operations, including states where we or our customers operate, such as Texas, Colorado and North Dakota. States could also elect to place prohibitions on hydraulic fracturing, as several states have already done. In addition, some states have adopted broader sets of requirements related to oil and gas development more generally that could impact hydraulic fracturing activities. For example, in 2019 the Colorado legislature adopted SB 19-181, which gave greater regulatory authority to local jurisdictions and reoriented the mandate of the Colorado Oil and Gas Conservation Commission to place more emphasis on the protection of human health and the environment. In response, a reconstituted Colorado Oil and Gas Conservation Commission modified its rules to address the requirements of the legislation, adopting increased setback requirements, provisions for assessing alternative sites for well pads to minimize environmental impacts, and consideration to cumulative impacts, among other provisions. Environmental groups, local citizens groups and others continue to seek to use a variety of means to force action on additional restrictions on hydraulic fracturing and oil and gas development generally. 
+Additionally, in July 2021, a non-governmental organization issued a report that raised concerns that chemicals used in hydraulic fracturing could be within the class of chemicals known as per- and polyfluoroalkylated substances (“PFAS”) or precursors to such substances. PFAS is the subject of intense federal and state regulatory scrutiny. Should PFAS be in hydraulic fracturing chemicals, this could open up a new front for the regulation of hydraulic fracturing. 
+Some states in which we operate require the disclosure of some or all of the chemicals used in our hydraulic fracturing operations. Certain aspects of one or more of these chemicals may be considered proprietary by us or our chemical suppliers. Disclosure of our proprietary chemical information to third parties or to the public, even if inadvertent, could diminish the value of our trade secrets or those of the chemicals suppliers and could result in competitive harm to us, which could have an adverse impact on our business, financial condition, prospects and results of operations. 
+In recent years, there have been allegations that hydraulic fracturing may result in seismic activities. Although the extent of any correlation between hydraulic fracturing and seismic activity has been and remains the subject of studies and debate, some parties believe that there is a causal relationship. As a result, federal and state legislatures and agencies may seek to further regulate, restrict or prohibit hydraulic fracturing. Such actions could result in a decline in the completion of new oil and gas wells, which could negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the demand for our services. 
+14 
+Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to, and litigation concerning, oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays for our customers or increased operating costs in the production of oil and natural gas, including from the developing shale plays, or could make it more difficult for (or could result in a prohibition for) us and our customers to perform hydraulic fracturing. The adoption of any additional laws or regulations regarding hydraulic fracturing or limitation in hydraulic fracturing could potentially cause a decrease in the completion of new oil and natural gas wells and an associated decrease in demand for our services and increased compliance costs and time. Such events could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition. 
+Additionally, in January 2021, the U.S. Department of the Interior issued an order that effectively suspends new oil and gas leases and drilling permits on non-Indian federal lands and waters for a period of 60 days, but the suspension does not limit existing operations under valid leases. President Biden followed with an executive order that ordered the Secretary of the Interior to pause the issuance of new oil and gas leases on federal public lands and offshore waters pending completion of a comprehensive review of federal oil and gas permitting and leasing practices that take into consideration potential climate and other impacts associated with oil and gas activities. This order further directs agencies to identify fossil fuel subsidies provided by such agencies and take measures to ensure that federal funding is not directly subsidizing fossil fuels, with an objective of eliminating fossil fuel subsidies from federal budget requests beginning in 2022. This order is currently being challenged in court by industry groups. 
+Additional legislation, executive actions, regulations or other regulatory initiatives to limit, delay or prohibit hydraulic fracturing or other aspects of oil and gas development may be pursued. In the event that these or other new federal restrictions, delays or prohibitions relating to the hydraulic fracturing process are adopted in areas where we or our customers conduct business, we or our customers may incur additional costs or permitting requirements to comply with such federal requirements that may be significant and, in the case of our customers, also could result in added restrictions or delays in the pursuit of exploration, development, or production activities, which would in turn reduce the demand for our services and have a material adverse effect on our results of operations. 
+Our business depends on domestic capital spending by the oil and natural gas industry, and reductions in capital spending could have a material adverse effect on our liquidity, results of operations and financial condition. 
+Our business is directly affected by our customers’ capital spending to explore for, develop and produce oil and natural gas in the United States and Canada. In addition, certain of our customers could become unable to pay their vendors and service providers, including us, as a result of a decline in commodity prices. Reduced discovery rates of new oil and natural gas reserves in our areas of operation as a result of decreased capital spending may also have a negative long-term impact on our business, even in an environment of stronger oil and natural gas prices. Any of these conditions or events could adversely affect our operating results. If current activity levels decrease or our customers further reduce their capital spending, it could have a material adverse effect on our liquidity, results of operations and financial condition. 
+Industry conditions are influenced by numerous factors over which we have no control, including: 
+• expected economic returns to E&P companies of new well completions; 
+• domestic and foreign economic conditions and supply of and demand for oil and natural gas; 
+• the level of prices, and expectations about future prices, of oil and natural gas; 
+• the level of global oil and natural gas exploration and production; 
+• the level of domestic and global oil and natural gas inventories; 
+• the supply of and demand for hydraulic fracturing services and equipment in the United States and Canada; 
+• federal, tribal, state and local laws, regulations and taxes, including the policies of governments regarding hydraulic fracturing, oil and natural gas exploration, development and production activities and the transportation of oil and gas by pipeline, as well as non-U.S. governmental regulations and taxes; 
+• governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves; 
+• political and economic conditions in oil and natural gas producing countries; 
+• actions by the members of the Organization of Petroleum Exporting Countries and other oil exporting nations with respect to oil production levels and potential changes in such levels; 
+• global weather conditions and natural disasters; 
+• worldwide political, military and economic conditions; 
+• the cost of producing and delivering oil and natural gas; 
+• lead times associated with acquiring equipment and products and availability of qualified personnel; 
+• the discovery rates of new oil and natural gas reserves; 
+• the production decline rate of existing oil and gas wells; 
+• stockholder activism or activities by non-governmental organizations to limit certain sources of funding for the energy sector or to restrict the exploration, development, production and transportation of oil and natural gas; 
+• the availability of water resources, suitable proppant and chemical additives in sufficient quantities for use in hydraulic fracturing fluids; 
+15 
+• advances in exploration, development and production technologies or in technologies affecting energy consumption; 
+• the availability, proximity and capacity of oil and natural gas pipelines and other transportation facilities; 
+• merger and divestiture activity among oil and natural gas producers; 
+• the price and availability of alternative fuels and energy sources; and 
+• uncertainty in capital and commodities markets and the ability of oil and natural gas companies to raise equity capital and debt financing. 
+The volatility of oil and natural gas prices may adversely affect the demand for our hydraulic fracturing services and negatively impact our results of operations. 
+The demand for our hydraulic fracturing services is primarily determined by current and anticipated oil and natural gas prices and the related levels of capital spending and drilling activity in the areas in which we have operations. Volatility or weakness in oil prices or natural gas prices (or the perception that oil prices or natural gas prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells. This, in turn, could lead to lower demand for our services and may cause lower utilization of our assets. We have experienced, and may in the future experience significant fluctuations in operating results as a result of the reactions of our customers to changes in oil and natural gas prices. 
+Prices for oil and natural gas historically have been extremely volatile and are expected to continue to be volatile. During the year 2021, the posted WTI price traded at an average of $68.13 per barrel (“Bbl”), as compared to the 2020 average of $39.16 per Bbl and the 2019 average of $56.99 per Bbl. The combined impact of the COVID-19 pandemic and the breakdown of OPEC+ production cut negotiations in Spring 2020 caused oil prices to drop to historical lows in April 2020. During the fourth quarter of 2021, WTI oil prices averaged $77.33 compared to $70.58 in the third quarter of 2021 and $42.52 in the fourth quarter of 2020. If the prices of oil and natural gas remain or become more volatile, our operations, financial condition, cash flows and level of expenditures may be materially and adversely affected. 
+Delays or restrictions in obtaining permits by us for our operations or by our customers for their operations could impair our business. 
+In most states, our operations and the operations of our oil and natural gas producing customers require permits from one or more governmental agencies in order to perform drilling and completion activities, secure water rights, or other regulated activities. Such permits are typically issued by state agencies, but federal and local governmental permits may also be required. The requirements for such permits vary depending on the location where such regulated activities will be conducted. As with all governmental permitting processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit to be issued, and the conditions that may be imposed in connection with the granting of the permit. In addition, some of our customers’ drilling and completion activities may take place on federal land or Native American lands, requiring leases and other approvals from the federal government or Native American tribes to conduct such drilling and completion activities or other regulated activities. Under certain circumstances, federal agencies may cancel proposed leases for federal lands and refuse to grant or delay required approvals. Therefore, our customers’ operations in certain areas may be interrupted or suspended for varying lengths of time, causing a loss of revenue to us and adversely affecting our results of operations in support of those customers. In January 2021, the U.S. Department of the Interior issued an order that effectively suspends new oil and gas leases and drilling permits on non-Indian federal lands and waters for a period of 60 days, but the suspension does not limit existing operations under valid leases. President Biden followed with an executive order that ordered the Secretary of the Interior to pause the issuance of new oil and gas leases on federal public lands and offshore waters pending completion of a comprehensive review of federal oil and gas permitting and leasing practices that take into consideration potential climate and other impacts associated with oil and gas activities. This order further directs agencies to identify fossil fuel subsidies provided by such agencies and take measures to ensure that federal funding is not directly subsidizing fossil fuels, with an objective of eliminating fossil fuel subsidies from federal budget requests beginning in 2022. This order is currently being challenged by industry groups. 
+Oil and natural gas companies’ operations using hydraulic fracturing are substantially dependent on the availability of water. Restrictions on the ability to obtain water for E&P activities and the disposal of flowback and produced water may impact their operations and have a corresponding adverse effect on our business, results of operations and financial condition. 
+Water is an essential component of shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Our oil and natural gas producing customers’ access to water to be used in these processes may be adversely affected due to reasons such as periods of extended drought, privatization, third party competition for water in localized areas or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. The occurrence of these or similar developments may result in limitations being placed on allocations of water due to needs by third party businesses with more senior contractual or permitting rights to the water. Our customers’ inability to locate or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact their E&P operations and have a corresponding adverse effect on our business, results of operations and financial condition. 
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+Moreover, the imposition of new environmental regulations and other regulatory initiatives could include increased restrictions on our producing customers’ ability to dispose of flowback and produced water generated in hydraulic fracturing or other fluids resulting from E&P activities. Applicable laws impose restrictions and strict controls regarding the discharge of pollutants into waters of the United States and require that permits or other approvals be obtained to discharge pollutants to such waters. Additionally, in 2016 EPA engaged a pretreatment standard that prohibits the discharge of wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly owned treatment works. Further, regulations implemented under both federal and state laws prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. These laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and hazardous substances. Compliance with current and future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells and any inability to secure transportation and access to disposal wells with sufficient capacity to accept all of our flowback and produced water on economic terms may increase our customers’ operating costs and could result in restrictions, delays, or cancellations of our customers’ operations, the extent of which cannot be predicted. 
+Our operations are subject to risks associated with climate change and potential regulatory programs meant to address climate change; these programs may impact or limit our business plans, result in significant expenditures or reduce demand for our services and reduce our revenues. 
+Climate change continues to be the focus of political and societal attention. Numerous proposals have been made and are likely to be forthcoming on the international, national, regional, state and local levels to reduce GHG emissions. These efforts have included or may include cap-and-trade programs, carbon taxes, GHG reporting obligations and other regulatory programs that limit or require control of GHG’s from certain sources. Upon taking office, President Biden issued several Executive Orders relating climate change, envisioning a “government-wide approach” to climate policy. At the 26 th Conference of the Parties of the United Nations Framework Convention on Climate Change held in October and November 2021, President Biden announced a commitment to significantly reduce GHG’s and transition the U.S. economy to net-zero carbon by 2050. Programs addressing climate change may limit the ability to produce crude oil and natural gas, require stricter limits on the release of methane or other GHGs, increase reporting and/or other compliance obligations associated with GHG emissions, limit the ability to explore in new areas, limit the construction of pipelines and related equipment or may make it more expensive to produce, any of which may decrease the demand for our services and our revenues. Related, President Biden has called on OPEC+ to produce more oil, which if heeded could result in lower oil and gas prices and lower domestic production. As of February 2, 2022, OPEC+ authorized a 400,000-barrel-per-day increase for March 2022. 
+Incentives to conserve energy or use alternative energy sources, which can be part of climate change programs, may increase the competitiveness of alternative energy sources (such as wind, solar, geothermal, tidal and biofuels) or increase the focus on reducing the use of combustion engines in transportation (such as governmental mandates that ban the sale of new gasoline-powered automobiles). These actions could, in turn, reduce demand for hydrocarbons and therefore for our services, which would lead to a reduction in our revenues. 
+An increased societal and governmental focus on ESG and climate change issues may adversely impact our business, impact our access to investors and financing, and decrease demand for our services. 
+An increased expectation that companies address environmental (including climate change), social and governance (“ESG”) matters may have a myriad of impacts on our business. Some investors and lenders are factoring these issues into investment and financing decisions. They may rely upon companies that assign ratings to a company’s ESG performance. Unfavorable ESG ratings, as well as recent activism around fossil fuels, may dissuade investors or lenders from us and toward other industries, which could negatively impact our stock price or our access to capital. Additionally, some potential sources of investment or financing have announced an intention to avoid or limit investment in companies that engage in hydraulic fracturing. For example, in 2020, Deutsche Bank announced that it would no longer finance oil and gas projects that use hydraulic fracturing in countries with scarce water supplies, and BlackRock affirmed its commitment to divest from investments in fossil fuels due to concerns over climate change. In 2021, BlackRock announced a continuing commitment to the goal of net zero GHG emissions by 2050 or sooner, and noted that key actions for 2021 included asking companies to disclose a business plan aligned with the goal of achieving net zero global GHG emissions by 2050 and using “investment stewardship” to ensure companies its clients invest in are mitigating climate risk and considering opportunities presented by the net zero transition. While a substantial number of major banks and financing sources remain active in investments related to hydraulic fracturing, it is possible that the investment avoidance or limitation theme could expand in the future and restrict access to capital for companies like us. 
+Moreover, while we have and may continue to create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures are based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to 
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+misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. 
+In addition, ESG and climate change issues may cause consumer preference to shift toward other alternative sources of energy, lowering demand for oil and natural gas and consequently lowering demand for our services. In some areas these concerns have caused governments to adopt or consider adopting regulations to transition to a lower-carbon economy. These measures may include adoption of cap-and-trade programs, carbon taxes, increased efficiency standards, prohibitions on the manufacture of certain types of equipment (such as new automobiles with internal combustion engines), and requirements for the use of alternate energy sources such as wind or solar. These types of programs may reduce the demand for oil and natural gas and consequently the demand for our services. 
+Approaches to climate change and a transition to a lower-carbon economy, including government regulation, company policies, and consumer behavior, are continuously evolving. At this time, we cannot predict how such approaches may develop or otherwise reasonably or reliably estimate their impact on our financial condition, results of operations and ability to compete. However, any long-term material adverse effect on the oil and gas industry may adversely affect our financial condition, results of operations and cash flows. 
+Our operations are subject to significant risks, some of which are beyond our control. These risks may be self-insured, or may not be fully covered under our insurance policies. 
+Our operations are subject to significant hazards often found in the oil and natural gas industry, such as, but not limited to, accidents, including accidents related to trucking operations provided in connection with our services, blowouts, explosions, craterings, fires, natural gas leaks, oil and produced water spills and releases of hydraulic fracturing fluids or other well fluids into the environment. These conditions can cause: 
+• disruption in operations; 
+• substantial repair or remediation costs; 
+• personal injury or loss of human life; 
+• significant damage to or destruction of property, and equipment; 
+• environmental pollution, including groundwater contamination; 
+• unusual or unexpected geological formations or pressures and industrial accidents; 
+• impairment or suspension of operations; and 
+• substantial revenue loss. 
+In addition, our operations are subject to, and exposed to, employee/employer liabilities and risks such as wrongful termination, discrimination, labor organizing, retaliation claims and general human resource related matters. 
+The occurrence of a significant event or adverse claim in excess of the insurance coverage that we maintain or that is not covered by insurance could have a material adverse effect on our liquidity, consolidated results of operations and financial condition. Claims for loss of oil and natural gas production and damage to formations can occur in the well services industry. Litigation arising from a catastrophic occurrence at a location where our equipment and services are being used or trucking services provided in connection therewith may result in our being named as a defendant in lawsuits asserting large claims. 
+We do not have insurance against all foreseeable risks, either because insurance is not available or because of the high premium costs. The occurrence of an event not fully insured against or the failure of an insurer to meet its insurance obligations could result in substantial losses. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. Insurance may not be available to cover any or all of the risks to which we are subject, or, even if available, it may be inadequate, or insurance premiums or other costs could rise significantly in the future so as to make such insurance prohibitively expensive. 
+We could experience continued or increased severity of trucking related issues or trucking accidents, which could materially affect our results of operations. 
+Trucking services can be adversely impacted by traffic congestion, shortage of drivers and weather delays which could hinder our service levels. During 2021 and into 2022 there has been a shortage of available trucking services in the United States due to the industry not having enough qualified drivers, which has impacted our field operations at times. In addition, our field employees are generally required to have a commercial driver’s license (“CDL”) so they can drive trucks and move our frac pumps and other equipment from location to location. Obtaining employees with CDLs can be challenging during times when the trucking industry has driver shortages, as competition for qualified employees is often more intense. If we are unable to obtain trucking services on a timely basis or the services of a sufficient number of field employees with CDLs, it could have a material adverse impact on our financial condition, results of operations and cash flows. 
+In addition, potential liability and unfavorable publicity associated with accidents in the trucking industry can be severe and occurrences are unpredictable. The number and severity of litigation claims may be worsened by distracted driving by both 
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+truck drivers and other motorists. Our transportation operations often involve traveling on unpaved roads located in rural areas, increasing the risk of accidents. If we are involved in an accident involving hazardous substances, if there are releases of hazardous substances we transport, if soil or groundwater contamination is found at our facilities or results from our operations, or if we are found to be in violation of applicable environmental laws or regulations, we could owe cleanup costs and incur related liabilities, including substantial fines or penalties or civil and criminal liability. A material increase in the frequency or severity of accidents or workers’ compensation claims or the unfavorable development of existing claims could materially adversely affect our results of operations. In the event that accidents occur, we may be unable to obtain desired contractual indemnities, and our insurance may be inadequate in certain cases which could result in substantial losses. Any such lawsuits in the future may result in the payment of substantial settlements or damages and increases to our insurance costs. 
+We may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition, prospects and results of operations. 
+Our services are subject to inherent risks that can cause personal injury or loss of life, damage to or destruction of property, equipment or the environment or the suspension of our operations. Litigation arising from operations where our services are provided, may cause us to be named as a defendant in lawsuits asserting potentially large claims including claims for exemplary damages. We maintain what we believe is customary and reasonable insurance to protect our business against these potential losses, but such insurance may not be adequate to cover our liabilities, and we are not fully insured against all risks. 
+In addition, our customers usually assume responsibility for, including control and removal of, all other pollution or contamination which may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling and completion fluids. We may have liability in such cases if we are grossly negligent or commit willful acts. Our customers generally agree to indemnify us against claims arising from their employees’ personal injury or death to the extent that, in the case of our hydraulic fracturing operations, their employees are injured by such operations, unless resulting from our gross negligence or willful misconduct. Our customers also generally agree to indemnify us for loss or destruction of customer-owned property or equipment. In turn, we agree to indemnify our customers for loss or destruction of property or equipment we own and for liabilities arising from personal injury to or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. However, we might not succeed in enforcing such contractual liability allocation or might incur an unforeseen liability falling outside the scope of such allocation. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operation. 
+We are subject to environmental and occupational health and safety laws and regulations that may expose us to significant costs and liabilities. 
+Our operations and the operations of our customers are subject to numerous federal, tribal, regional, state and local laws and regulations relating to protection of the environment including natural resources, health and safety aspects of our operations and waste management, including the transportation and disposal of waste and other materials. These laws and regulations may impose numerous obligations on our operations and the operations of our customers, including the acquisition of permits or other approvals to conduct regulated activities, the imposition of restrictions on the types, quantities and concentrations of various substances that may be released into the environment or injected in non-productive formations below ground in connection with oil and natural gas drilling and production activities, the incurrence of capital expenditures to mitigate or prevent releases of materials from our equipment, facilities or from customer locations where we are providing services, the imposition of substantial liabilities for pollution resulting from our operations, and the application of specific health and safety criteria addressing worker protection. Any failure on our part or the part of our customers to comply with these laws and regulations could result in assessment of sanctions including administrative, civil and criminal penalties; imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures; the occurrence of restrictions, delays or cancellations in the permitting, performance or development of projects or operations; and the issuance of orders enjoining performance of some or all of our operations in a particular area. In addition to civil and other penalties associated with enforcement activities regarding compliance with occupational health and safety laws, our operations may be subject to abatement obligations that could require significant modifications to existing operations to achieve compliance. 
+Our business activities present risks of incurring significant environmental costs and liabilities, including costs and liabilities resulting from our handling of oilfield and other wastes, because of air emissions and wastewater discharges related to our operations, and due to historical oilfield industry operations and waste disposal practices. Moreover, accidental releases or spills may occur in the course of our operations or at facilities where our wastes are taken for reclamation or disposal, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for injuries to persons or damages to properties or natural resources. Some environmental laws and regulations may impose strict liability, which means that in some situations we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Remedial and abatement costs and other damages arising as a result of environmental and occupational health and safety laws and costs associated with changes in these laws and regulations could be significant and have a material adverse effect on our liquidity, consolidated results of operations and financial condition. 
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+Laws and regulations protecting the environment generally have become more stringent in recent years and are expected to continue to do so, which could lead to material increases in costs for future environmental compliance and remediation. In particular, the ESA restricts activities that may result in a “take” of endangered or threatened species and provides for substantial penalties in cases where listed species are taken by being harmed. The dunes sagebrush lizard is one example of a species that, if listed as endangered or threatened under the ESA, could impact our operations and the operations of our customers. The dunes sagebrush lizard is found in the active and semi-stable shinnery oak dunes of southeastern New Mexico and adjacent portions of Texas, including areas where our customers operate and our frac sand facilities are located. The FWS is currently conducting a review to determine whether listing the dunes sagebrush lizard as endangered or threatened under the ESA is warranted. In July 2020, the FWS published a 90-day finding that a 2018 petition seeking that the dunes sagebrush lizard be listed as endangered or threatened presented substantial evidence indicating that listing may be warranted. In November 2021, an environmental group filed a notice of intent to sue the U.S. Department of the Interior and the FWS for unlawfully delaying protection of the dunes sagebrush lizard and five other species. According to the petition, if a determination is not made by January 2022, the environmental group will file suit to enforce the ESA. If the dunes sagebrush lizard is listed as an endangered or threatened species, our operations and the operations of our customers in any area that is designated as the dunes sagebrush lizard’s habitat may be limited, delayed or, in some circumstances, prohibited, and we and our customers could be required to comply with expensive mitigation measures intended to protect the dunes sagebrush lizard and its habitat. Furthermore, new laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement with respect to environmental matters could restrict, delay or curtail exploratory or developmental drilling for oil and natural gas by our customers and could limit our well servicing opportunities. 
+Oilfield anti-indemnity provisions enacted by many states may restrict or prohibit a party’s indemnification of us. 
+We typically enter into agreements with our customers governing the provision of our services, which usually include certain indemnification provisions for losses resulting from operations. Such agreements may require each party to indemnify the other against certain claims regardless of the negligence or other fault of the indemnified party; however, many states place limitations on contractual indemnity agreements, particularly agreements that indemnify a party against the consequences of its own negligence. Furthermore, certain states, including Texas, New Mexico and Wyoming, have enacted statutes generally referred to as “oilfield anti-indemnity acts” expressly prohibiting certain indemnity agreements contained in or related to oilfield services agreements. Such anti-indemnity acts may restrict or void a party’s indemnification of us, which could have a material adverse effect on our business, financial condition, prospects and results of operations. 
+Technology advancements in well service technologies, including those involving hydraulic fracturing, could have a material adverse effect on our business, financial condition and results of operations. 
+The hydraulic fracturing industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As competitors and others use or develop new technologies or technologies comparable to ours in the future, we may lose market share or be placed at a competitive disadvantage. Further, we may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of our competitors may have greater financial, technical and personnel resources than we do, which may allow them to gain technological advantages or implement new technologies before we can. Additionally, we may be unable to implement new technologies or services at all, on a timely basis or at an acceptable cost. New technology could also make it easier for our customers to vertically integrate their operations, thereby reducing or eliminating the need for our services. Limits on our ability to effectively use or implement new technologies may have a material adverse effect on our business, financial condition and results of operations. 
+Risks Related to the TRAs 
+The Company is required to make payments under the TRAs for certain tax benefits that it may claim, and the amounts of such payments could be significant. 
+In connection with the Company’s initial public offering (the “IPO”), on January 17, 2018, the Company entered into two Tax Receivable Agreements (the “TRAs”) with R/C Energy IV Direction Partnership, L.P. and the then-existing owners of Liberty Oilfield Services Holdings LLC (“Liberty Holdings”) that continued to own Liberty LLC Units (each such person and any permitted transferee, a “TRA Holder”). The TRAs generally provide for the payment by the Company to each TRA Holder of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that the Company actually realizes (or is deemed to realize in certain circumstances) as a result of certain increases in tax basis, net operating losses available to the Company as a result of the corporate reorganization performed in connection with the IPO (the “Corporate Reorganization”), and certain benefits attributable to imputed interest. The Company will retain the benefit of the remaining 15% of these cash savings. 
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+The Company is a holding company and has no material assets other than its equity interest in Liberty LLC. Because the Company has no independent means of generating revenue, its ability to make payments under the TRAs is dependent on the ability of Liberty LLC to make distributions to the Company in an amount sufficient to cover its obligations under the TRAs. To the extent that the Company is unable to make payments under the TRAs for any reason, such payments will be deferred and will accrue interest until paid. 
+The term of each of the TRAs continues until all tax benefits that are subject to such TRAs have been utilized or expired, unless the Company experiences a change of control (as defined in the TRAs, which includes certain mergers, asset sales and other forms of business combinations) or the TRAs are terminated early (at the Company’s election or as a result of its breach), and the Company makes the termination payments specified in such TRAs. In addition, payments the Company makes under the TRAs will be increased by any interest earned from the due date (without extensions) of the corresponding tax return. Payments under the TRAs commenced in 2020 and so long as the tax savings are realized and the TRAs are not terminated, payments are anticipated to continue for 15 years after the date of the last redemption of the Liberty LLC Units. Accordingly, if the applicable U.S. federal corporate tax rate is increased, then the amount of TRA payments paid in the future may also increase. 
+In certain cases, if the Company experiences a change of control (as defined under the TRAs, which includes certain mergers, asset sales and other forms of business combinations) or the TRAs terminate early (at the Company’s election or as a result of its breach), the Company would be required to make an immediate lump-sum payment, and such payment may be significantly in advance of, and may materially exceed, the actual realization, if any, of the future tax benefits to which the payment relates. As a result, the Company’s obligations under the TRAs could have a substantial negative impact on its liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. There can be no assurance that we will be able to finance our obligations under the TRAs. Furthermore, as a result of this payment obligation, holders of our Class A Common Stock could receive substantially less consideration in connection with a change in control transaction than they would receive in the absence of such obligation. Since our payment obligations under the TRAs will not be conditioned upon the TRA Holders’ having continued interest in the Company or liberty LLC, the TRA Holders’ interests may conflict with those of the holders of our Class A Common Stock. 
+Payments under the TRAs are based on the tax reporting positions that we will determine. The TRA Holders will not reimburse us for any payments previously made under the TRAs if any tax benefits that have given rise to payments under the TRAs are subsequently disallowed, except that excess payments made to any TRA Holder will be netted against payments that would otherwise be made to such TRA Holder, if any, after our determination of such excess. As a result, in such circumstances the Company could make payments that are greater than its actual cash tax savings, if any, and may not be able to recoup those payments, which could adversely affect the Company’s liquidity. Furthermore, the payments under the TRAs will not be conditioned upon a holder of rights under each of the TRAs having a continued ownership interest in the Company or Liberty LLC. For further details of the TRAs, see Note 12 —Income Taxes to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.” 
+General Risks Related to our Business 
+We may be adversely affected by uncertainty in the global financial markets and the deterioration of the financial condition of our customers. 
+Our future results may be impacted by the uncertainty caused by an economic downturn, volatility or deterioration in the debt and equity capital markets, inflation, deflation or other adverse economic conditions that may negatively affect us or parties with whom we do business resulting in a reduction in our customers’ spending and their non-payment or inability to perform obligations owed to us, such as the failure of customers to honor their commitments or the failure of major suppliers to complete orders. Additionally, during times when the oil or natural gas markets weaken, our customers are more likely to experience financial difficulties, including being unable to access debt or equity financing, which could result in a reduction in our customers’ spending for our services. In addition, in the course of our business we hold accounts receivable from our customers. In the event of the financial distress or bankruptcy of a customer, we could lose all or a portion of such outstanding accounts receivable associated with that customer. Further, if a customer was to enter into bankruptcy, it could also result in the cancellation of all or a portion of our service contracts with such customer at significant expense or loss of expected revenues to us. 
+Reliance upon a few large customers may adversely affect our revenue and operating results. 
+Our top five customers represented approximately 27%, 48%, and 35%, of our consolidated revenue for the years ended December 31, 2021, 2020, and 2019, respectively. It is possible that we will derive a significant portion of our revenue from a concentrated group of customers in the future. If a major customer fails to pay us, revenue would be impacted and our operating results and financial condition could be materially harmed. Additionally, if we were to lose any material customer or our customers were to consolidate or merge with other operators, we may not be able to redeploy our equipment at similar 
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+utilization or pricing levels or within a short period of time and such loss could have a material adverse effect on our business until the equipment is redeployed at similar utilization or pricing levels. 
+We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss. 
+The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain processing activities. For example, we depend on digital technologies to perform many of our services and to process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. In early 2020, we experienced a denial of service cyberattack that targeted a portion of our non-financial data. We immediately shutdown critical systems, diagnosed the root cause of the attack and then methodically returned systems online. This cyberattack disrupted certain non-financial aspects of our internal system for a period of less than one day, while limited and non-critical portions of our systems were kept offline for up to one week in order to properly evaluate the breach. We determined that this cyberattack did not materially affect any of our operations. We engaged in extensive data evaluation for potential damage and concluded that minimal to no data loss had occurred as a result of this cyberattack. Our technologies, systems and networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches in the future that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we will likely be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. Our insurance coverage for cyberattacks may not be sufficient to cover all the losses we may experience as a result of such cyberattacks. 
+Our assets require significant amounts of capital for maintenance, upgrades and refurbishment and may require significant capital expenditures for new equipment. 
+Our hydraulic fracturing fleets and other completion service-related equipment require significant capital investment in maintenance, upgrades and refurbishment to maintain their competitiveness. The costs of components and labor have increased in the past and may increase in the future with increases in demand, which will require us to incur additional costs for any fleets we may acquire in the future. Our fleets and other equipment typically do not generate revenue while they are undergoing maintenance, upgrades or refurbishment. Any maintenance, upgrade or refurbishment project for our assets could increase our indebtedness or reduce cash available for other opportunities. Furthermore, such projects may require proportionally greater capital investments as a percentage of total asset value, which may make such projects difficult to finance on acceptable terms. To the extent we are unable to fund such projects, we may have less equipment available for service or our equipment may not be attractive to potential or current customers. Additionally, competition or advances in technology within our industry may require us to update or replace existing fleets or build or acquire new fleets. Such demands on our capital or reductions in demand for our hydraulic fracturing fleets and the increase in cost of labor necessary for such maintenance and improvement, in each case, could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations and may increase our costs. 
+We rely on certain third parties for materials, and delays in deliveries of such materials, increases in the cost of such materials or our contractual obligations to pay for materials that we ultimately do not require could harm our business, results of operations and financial condition. 
+We have established relationships with certain suppliers of our materials (such as, but not limited to, proppant and chemical additives) and other parts, supplies and items needed for our operations. Delays or shortages in materials can result from a variety of reasons, including those caused by weather and natural disasters. Presently, the United States is undergoing a supply chain disruption due to backlogged ports and trucking shortages, and our business is not immune from these effects. Even once the root cause of the supply chain disruption or any future shortage or delay has passed, it can take time for our supply chain to recover and run in a regular fashion. Should the nationwide supply chain disruption continue, or should any of our current suppliers be unable to provide the necessary materials or otherwise fail to deliver the materials in a timely manner and in the quantities required, any resulting delays in the provision of services could have a material adverse effect on our business, results of operations and financial condition. Additionally, increasing costs of such materials may negatively impact demand for our services or the profitability of our business operations. In the past, our industry faced sporadic proppant shortages associated with hydraulic fracturing operations requiring work stoppages, which are believed to have adversely impacted the operating results of several competitors. We may not be able to mitigate any future shortages of materials, including proppant, or the impact of supply chain disruptions. Furthermore, to the extent our contracts require us to purchase more materials, including proppant, than we ultimately require, we may be forced to pay for the excess amount under “take or pay” contract provisions. 
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+We currently utilize two preferred assemblers and a limited number of suppliers for major equipment to both build new fleets and upgrade any fleets we acquire to our preferred specifications, and our reliance on these vendors exposes us to risks including price and timing of delivery. 
+We currently utilize two preferred assemblers and a limited number of suppliers for major equipment to both build our new fleets and upgrade any fleets we may acquire to our custom design. If demand for hydraulic fracturing fleets or the components necessary to build such fleets increases or these vendors face financial distress or bankruptcy, these vendors may not be able to provide the new or upgraded fleets on schedule or at the current price. If this were to occur, we could be required to seek another assembler or other suppliers for major equipment to build or upgrade our fleets, which may adversely affect our revenues or increase our costs. 
+Interruptions of service on the rail lines by which we receive proppant could adversely affect our results of operations. 
+We receive a portion of the proppant used in our hydraulic fracturing services by rail. Rail operations are subject to various risks that may result in a delay or lack of service, including lack of available capacity, mechanical problems, extreme weather conditions, work stoppages, labor strikes, terrorist attacks and operating hazards. Additionally, if we increase the amount of proppant we require for delivery of our services, we may face difficulty in securing rail transportation for such additional amount of proppant. Any delay or failure in the rail services on which we rely could have a material adverse effect on our financial condition and results of operations. 
+Changes in transportation regulations may increase our costs and negatively impact our results of operations. 
+We are subject to various transportation regulations including as a motor carrier by the Department of Transportation and by various federal, state, provincial and tribal agencies, whose regulations include certain permit requirements of highway and safety authorities. These regulatory authorities exercise broad powers over our equipment transportation operations, generally governing such matters as the authorization to engage in motor carrier operations, safety, equipment testing, driver requirements and specifications and insurance requirements. The trucking industry is subject to possible regulatory and legislative changes that may impact our operations, such as changes in fuel emissions limits, hours of service regulations that govern the amount of time a driver may drive or work in any specific period and requiring onboard electronic logging devices or limits on vehicle weight and size. As the federal government continues to develop and propose regulations relating to fuel quality, engine efficiency and greenhouse gasses emissions, we may experience an increase in costs related to truck purchases and maintenance, impairment of equipment productivity, a decrease in the residual value of vehicles, unpredictable fluctuations in fuel prices and an increase in operating expenses. Additionally, we rely on third parties to provide trucking services, including hauling proppant to our customer work sites, and these third parties may fail to comply with various transportation regulations, resulting in our inability to use such third party providers. Increased truck traffic may contribute to deteriorating road conditions in some areas where our operations are performed. Our operations, including routing and weight restrictions, could be affected by road construction, road repairs, detours and state and local regulations and ordinances restricting access to certain roads. Proposals to increase federal, state, provincial or local taxes, including taxes on motor fuels, are also made from time to time, and any such increase would increase our operating costs. Also, state and local regulation of permitted routes and times on specific roadways could adversely affect our operations. We cannot predict whether, or in what form, any legislative or regulatory changes or municipal ordinances applicable to our logistics operations will be enacted and to what extent any such legislation or regulations could increase our costs or otherwise adversely affect our business or operations. 
+Our current and future indebtedness could adversely affect our financial condition. 
+As of February 18, 2022, we had $106.5 million outstanding under our Term Loan Facility and $133.0 million outstanding under our ABL Facility (defined herein), as well as a letter of credit in the amount of $1.5 million, with a borrowing base of $273.1 million. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements.” 
+Moreover, subject to the limits contained in our ABL Facility and Term Loan Facility (collectively, the “Credit Facilities”), we may incur substantial additional debt from time to time. Any borrowings we may incur in the future would have several important consequences for our future operations, including that: 
+• covenants contained in the documents governing such indebtedness may require us to meet or maintain certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our industry, such as being able to take advantage of acquisition opportunities when they arise; 
+• our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes may be limited; 
+• our ability to use operating cash flow in other areas of our business may be limited because we must dedicate a substantial portion of these funds to make principal and interest payments on our indebtedness; 
+23 
+• we may be more vulnerable to interest rate increases to the extent that we incur variable rate indebtedness; 
+• we may be competitively disadvantaged to our competitors that are less leveraged or have greater access to capital resources; and 
+• we may be more vulnerable to adverse economic and industry conditions. 
+If we incur indebtedness in the future, we may have significant principal payments due at specified future dates under the documents governing such indebtedness. Our ability to meet such principal obligations will be dependent upon future performance, which in turn will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. Our business may not continue to generate sufficient cash flow from operations to repay any incurred indebtedness. If we are unable to generate sufficient cash flow from operations, we may be required to sell assets, to refinance all or a portion of such indebtedness or to obtain additional financing. 
+Unsatisfactory safety performance may negatively affect our customer relationships and, to the extent we fail to retain existing customers or attract new customers, adversely impact our revenues. 
+Our ability to retain existing customers and attract new business is dependent on many factors, including our ability to demonstrate that we can reliably and safely operate our business in a manner that is consistent with applicable laws, rules and permits, which legal requirements are subject to change. Existing and potential customers consider the safety record of their third-party service providers to be of high importance in their decision to engage such providers. If one or more accidents were to occur at one of our operating sites, the affected customer may seek to terminate or cancel its use of our equipment or services and may be less likely to continue to use our services, which could cause us to lose substantial revenues. Furthermore, our ability to attract new customers may be impaired if they elect not to engage us because they view our safety record as unacceptable. In addition, it is possible that we will experience multiple or particularly severe accidents in the future, causing our safety record to deteriorate. This may be more likely as we continue to grow, if we experience high employee turnover or labor shortage, or hire inexperienced personnel to bolster our staffing needs. 
+If we are unable to fully protect our intellectual property rights, we may suffer a loss in our competitive advantage or market share. 
+We do not have patents or patent applications relating to many of our key processes and technology. If we are not able to maintain the confidentiality of our trade secrets, or if our competitors are able to replicate our technology or services, our competitive advantage would be diminished. We also cannot ensure that any patents we may obtain in the future would provide us with any significant commercial benefit or would allow us to prevent our competitors from employing comparable technologies or processes. 
+We may be adversely affected by disputes regarding intellectual property rights of third parties. 
+Third parties from time to time may initiate litigation against us by asserting that the conduct of our business infringes, misappropriates or otherwise violates intellectual property rights. We may not prevail in any such legal proceedings related to such claims, and our products and services may be found to infringe, impair, misappropriate, dilute or otherwise violate the intellectual property rights of others. If we are sued for infringement and lose, we could be required to pay substantial damages and/or be enjoined from using or selling the infringing products or technology. Any legal proceeding concerning intellectual property could be protracted and costly regardless of the merits of any claim and is inherently unpredictable and could have a material adverse effect on our financial condition, regardless of its outcome. 
+If we were to discover that our technologies or products infringe valid intellectual property rights of third parties, we may need to obtain licenses from these parties or substantially re-engineer our products in order to avoid infringement. We may not be able to obtain the necessary licenses on acceptable terms, or at all, or be able to re-engineer our products successfully. If our inability to obtain required licenses for our technologies or products prevents us from selling our products, that could adversely impact our financial condition and results of operations. 
+Additionally, we currently license certain third party intellectual property in connection with our business, and the loss of any such license could adversely impact our financial condition and results of operations. 
+Seasonal weather conditions, natural disasters, public health crises, and other catastrophic events outside of our control could severely disrupt normal operations and harm our business. 
+Our operations are located in different regions of the United States and Canada. Some of these areas, including the DJ Basin, Powder River Basin, Williston Basin and our Canadian operations, are adversely affected by seasonal weather conditions, primarily in the winter and spring. However, as evidenced by the severe winter weather experienced in the southern United States and Canada during February 2021, weather-related hazards can exist in almost all the areas where we operate. During periods of heavy snow, ice or rain, we may be unable to move our equipment between locations or obtain adequate 
+24 
+supplies of raw material or fuel, thereby reducing our ability to provide services and generate revenues. The exploration activities of our customers may also be affected during such periods of adverse weather conditions. Additionally, extended drought conditions in our operating regions could impact our ability or our customers’ ability to source sufficient water or increase the cost for such water. As a result, a natural disaster or inclement weather conditions could severely disrupt the normal operation of our business and adversely impact our financial condition and results of operations. Furthermore, if the area in which we operate or the market demand for oil and natural gas is affected by a public health crises, such as the coronavirus, or other similar catastrophic event outside of our control, our business and results of operations could suffer. 
+The sand mining operations are subject to a number of risks relating to the proppant industry. 
+In connection with the OneStim Acquisition, we acquired two state-of-the-art sand mines in the Permian Basin. Sand mining operations are subject to risks normally encountered in the proppant industry. These risks include, among others: unanticipated ground, grade or water conditions; inability to acquire or maintain, or public or nongovernmental organization opposition to, necessary permits for mining, access or water rights; our ability to timely obtain necessary authorizations, approvals and permits from regulatory agencies (including environmental agencies, such as the FWS, where our operations in West Texas may be slowed, limited or halted due to conservation efforts targeted at the habitat of the dunes sagebrush lizard); pit wall or pond failures, and sluffing events; costs associated with environmental compliance or as a result of unauthorized releases into the environment; restrictions imposed on our operations related to the protection of natural resources, including plant and animal species; and reduction in the amount of water available for processing. Any of these risks could result in delays, limitations or cancellations in mining or processing activities, losses or possible legal liability. 
+Silica-related legislation, health issues and litigation could have a material adverse effect on our business, reputation or results of operations. 
+We are subject to laws and regulations relating to human exposure to crystalline silica. Historically, our environmental compliance costs with respect to existing crystalline silica requirements have not had a material adverse effect on our results of operations; however, federal regulatory authorities and analogous state agencies may continue to propose changes in their regulations regarding workplace exposure to crystalline silica, such as permissible exposure limits, required controls and personal protective equipment. We may not be able to comply with any new laws and regulations that are adopted, and any new laws and regulations could have a material adverse effect on our operating results by requiring us to modify or cease our operations. 
+In addition, the inhalation of respirable crystalline silica is associated with the lung disease silicosis. There is evidence of an association between crystalline silica exposure or silicosis and lung cancer and a possible association with other diseases, including immune system disorders such as scleroderma. The actual or perceived health risks of handling hydraulic fracture sand could materially and adversely affect hydraulic fracturing service providers, including us, through reduced use of hydraulic fracture sand, the threat of product liability or employee lawsuits, increased scrutiny by federal, state and local regulatory authorities of us and our customers or reduced financing sources available to the industry. Furthermore, we may incur additional costs with respect to purchasing specialized equipment designed to reduce exposure to crystalline silica in connection with our operations or invest capital in new equipment. 
+We are subject to the Federal Mine Safety and Health Act of 1977, which imposes stringent health and safety standards on numerous aspects of its operations. 
+Our operations are subject to the Federal Mine Safety and Health Act of 1977, as amended by the Mine Improvement and New Emergency Response Act of 2006, which imposes stringent health and safety standards on numerous aspects of mineral extraction and processing operations, including the training of personnel, operating procedures, operating equipment, and other matters. Our failure to comply with such standards, or changes in such standards or the re-interpretation or more stringent enforcement thereof, could have a material adverse effect on our business and financial condition or otherwise impose significant restrictions on its ability to conduct mineral extraction and processing operations. 
+The occurrence of explosive incidents could disrupt our operations and could adversely affect our business, financial condition and results of operations. 
+The wireline service we provide to oil and natural gas E&P customers involves the storage and handling of explosive materials. Despite the use of specialized facilities to store explosive materials and intensive employee training programs, the handling of explosive materials could result in incidents that temporarily shut down or otherwise disrupt our or E&P customers’ operations or could cause restrictions, delays or cancellations in the delivery of services. It is possible that an explosion could result in death or significant injuries to employees and other persons. Material property damage to us, E&P customers and third parties could also occur. Any explosive incident could expose us to adverse publicity or liability for damages or cause production restrictions, delays or cancellations, any of which developments could have a material adverse effect on our ability to compete, business, financial condition and results of operations. 
+25 
+Item 1B. Unresolved Staff Comments 
+None. 
+Item 2. Properties 
+Information regarding our properties is contained in “Item 1. Business” and is incorporated by reference herein. 
+Item 3. Legal Proceedings 
+The information with respect to this Item 3. Legal Proceedings is set forth in Note 15—Commitments and Contingencies included in “Item 8. Financial Statements and Supplementary Data.” 
+Item 4. Mine Safety Disclosures 
+Information concerning mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this Form 10-K. 
+26 
+PART II 
+Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+Market Information 
+On January 17, 2018, we consummated an initial public offering of our Class A Common Stock at a price of $17.00 per share. Our Class A Common Stock is traded on the NYSE under the symbol “LBRT.” Prior to that time, there was no public market for our Class A Common Stock. There is no public market for our Class B Common Stock. 
+Holders of our Common Stock 
+As of February 18, 2022, there were 29 stockholders of record of our Class A Common Stock and 22 stockholders of record of our Class B Common Stock. The number of record holders is based upon the actual number of holders registered on the books of the Company at such date and does not include holders of shares in “street names” or persons, partnerships, associations, corporations or other entities identified in security position listings maintained by depositories. 
+Dividend Policy 
+Although the Company has previously paid quarterly cash dividends to stockholders of Class A Common Stock, in 2020, the Company suspended future quarterly dividends until business conditions warrant reinstatement. As a result, the Company did not pay any dividends in the year ended December 31, 2021. The declaration of dividends is subject to approval by the Board and to the Board’s continuing determination that such declaration of dividends is in the best interests of the Company and its stockholders. Future dividends may be adjusted at the Board’s discretion based on market conditions and capital availability. We are not required to pay dividends, and our stockholders will not be guaranteed, or have contractual or other rights to receive, dividends. 
+Recent Sales of Unregistered Equity Securities 
+We had no sales of unregistered equity securities during the period covered by this Annual Report that were not previously reported in a Current Report on Form 8-K (or on Form 10-Q in lieu of Form 8-K). 
+Purchase of Equity Securities By the Issuer and Affiliated Purchasers 
+On September 10, 2018 the Board authorized a share repurchase plan to repurchase up to $100.0 million of the Company’s Class A Common Stock through September 30, 2019. On January 22, 2019, the Board authorized an additional $100.0 million under the share repurchase plan through January 31, 2021. During the year ended December 31, 2021, the Company did not purchase any shares of Class A Common Stock. 
+As of December 31, 2021, no amounts remained authorized for future repurchases of Class A Common Stock under the share repurchase program. 
+Stock Performance Graph 
+The following graph and table compares the cumulative total return on our Class A Common Stock with the cumulative total return on the Standard & Poor’s 500 ® Index and the Philadelphia Oil Service Index, since January 12, 2018, the first day on which shares of our Common Stock issued in our IPO commenced trading on the NYSE and each semi-annual period thereafter through December 31, 2021. The graph assumes that $100 was invested in our Class A Common Stock in each index on January 12, 2018 and that any dividends were reinvested on the last day of the month in which they were paid. The cumulative total return set forth is not necessarily indicative of future performance. 
+The following graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that we specifically incorporate it by reference into such filing. 
+27 
+For Year Ended 2018 For the Year Ended 2019 For the Year Ended 2020 For the Year Ended 2021 
+January 
+12, June 
+30, December 
+31, June 
+30, December 
+31, June 
+30, December 
+31, June 
+30, December 
+31, 
+Liberty Oilfield Services, Inc. $ 100.00 $ 83.87 $ 58.38 $ 73.40 $ 50.91 $ 25.55 $ 48.08 $ 66.03 $ 45.23 
+Standard & Poor’s 500 ® Index 100.00 97.00 89.45 104.97 115.28 110.62 134.02 153.34 170.07 
+Philadelphia Oil Service Index 100.00 95.91 49.91 50.37 48.48 20.67 27.45 39.47 32.65 
+28 
+Item 6. [Reserved] 
+29 
+Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our audited consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a variety of risks and uncertainties, including those described in this Annual Report under “Cautionary Note Regarding Forward-Looking Statements” and “Item 1A. Risk Factors.” Except as required by law, we assume no obligation to update any of these forward-looking statements. This section of this Annual Report generally discusses 2021 and 2020 items and year-to-year comparisons between 2021 and 2020. For discussion of year ended December 31, 2019, as well as the year ended 2020 compared to the year ended December 31, 2019, refer to Part II, Item 7— “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2020 Annual Report. 
+Overview 
+We are an independent provider of hydraulic fracturing services and wireline services and related goods to onshore oil and natural gas E&P companies in North America. We have grown from one active hydraulic fracturing fleet in December 2011 to over 30 active fleets as of December 31, 2021. We provide our services primarily in the Permian Basin, the Eagle Ford Shale, the DJ Basin, the Williston Basin, the San Juan Basin and the Powder River Basin. Following the completion of the OneStim Acquisition (as defined below) we now also provide services in the Haynesville Shale, the SCOOP/STACK, the Marcellus Shale, Utica Shale, and the Western Canadian Sedimentary Basin. Additionally, we operate two sand mines in the Permian Basin. 
+On December 31, 2020, the Company acquired certain assets and liabilities of Schlumberger’s OneStim business, which provides hydraulic fracturing pressure pumping services in onshore United States and Canada, including its pressure pumping, pumpdown perforating and Permian frac sand business, in exchange for consideration resulting in a total of 66,326,134 shares of the Class A Common Stock being issued in connection with the OneStim Acquisition. As of February 18, 2022, Schlumberger owned 30.5% of the issued and outstanding shares of our Common Stock. The combined company delivers best-in-class completion services for the sustainable development of unconventional resource plays in the United States and Canada onshore markets. 
+On October 26, 2021, the Company acquired PropX in exchange for $11.9 million in cash and 3,405,526 shares of Class A Common Stock and 2,441,010 shares of Class B Common Stock, and 2,441,010 Liberty LLC Units, for total consideration of $103.0 million, based on the Class A Common Stock closing price of $15.58 on October 26, 2021, subject to customary post closing adjustments. The Liberty LLC Units are redeemable for an equivalent number of shares of Class A Common Stock at any time, at the election of the shareholder. Founded in 2016, PropX is a leading provider of last-mile proppant delivery solutions including proppant handling equipment and logistics software across North America. PropX offers innovative environmentally friendly technology with optimized dry and wet sand containers and wellsite proppant handling equipment that drive logistics efficiency and reduce noise and emissions. We believe that PropX wet sand handling technology is a key enabler of the next step of cost and emissions reductions in the proppant industry. PropX also offers customers the latest real-time logistics software, PropConnect, for sale or as hosted software as a service. 
+We believe technical innovation and strong relationships with our customer and supplier bases distinguish us from our competitors and are the foundations of our business. We expect that E&P companies will continue to focus on technological innovation as completion complexity and fracture intensity of horizontal wells increases, particularly as customers are increasingly focused on reducing emissions from their completions operations. We remain proactive in developing innovative solutions to industry challenges, including developing: (i) our databases of U.S. unconventional wells to which we apply our proprietary multi-variable statistical analysis technologies to provide differential insight into fracture design optimization; (ii) our Liberty Quiet Fleet® design which significantly reduces noise levels compared to conventional hydraulic fracturing fleets; (iii) hydraulic fracturing fluid systems tailored to the specific reservoir properties in the basins in which we operate; (iv) our dual fuel dynamic gas blending fleets that allow our engines to run diesel or a combination of diesel and natural gas, to optimize fuel use, reduce emissions and lower costs; and (v) the successful test of digiFrac™, our innovative, purpose-built electric frac pump that has approximately 25% lower CO2e emission profile than the Tier IV DGB. In addition, our integrated supply chain includes proppant, chemicals, equipment, logistics and integrated software which we believe promotes wellsite efficiency and leads to more pumping hours and higher productivity throughout the year to better service our customers. In order to achieve our technological objectives, we carefully manage our liquidity and debt position to promote operational flexibility and invest in the business throughout the full commodity cycle. 
+30 
+Recent Trends and Outlook 
+During the year 2021, the posted WTI price traded at an average of $68.13 per barrel (“Bbl”), as compared to the 2020 average of $39.16 per Bbl and the 2019 average of $56.99 Bbl. The recovery of energy demand is also reflected in the incremental improvement to rig count, as the average domestic onshore rig count for the United States and Canada was 704 rigs reported in the fourth quarter of 2021, up from the average in the fourth quarter of 2020 of 384, according to a report from Baker Hughes, a GE Company. 
+E&P operators are responding to oil and gas price signals. The public operators are maintaining discipline and we expect will show only modest production growth this year, while the private operators are likely reacting more robustly to strong commodity prices. 
+The transformative work our team accomplished in 2021 positions us well as we believe our industry is beginning an upcycle driven by rapidly tightening markets for oil & gas. Years of reduced global investment in upstream oil and gas production is now colliding with record global demand for natural gas and natural gas liquids today, and potential record global demand for oil later this year. Oil and gas are central to the global economy which is well along the way of recovering from the global COVID-19 pandemic. 
+Within the frac market, two years of supply attrition and cannibalization plus constraints from labor shortages, and a secular shift towards next generation frac fleet technologies has led to tightness in the supply of fleets. Liberty has focused on finding the right long-term customer partnerships for the future and has been very disciplined in holding our active frac fleet count steady until financial returns justify significant additional fleet deployments. 
+During 2021, we worked on the integration of the OneStim Acquisition into Liberty, which was exacerbated by COVID-impacted supply chain and difficult labor challenges. Integration-related costs are still with us today, impacting our financial results. However, we made improvements in these costs during January 2022, and believe these costs will lessen during 2022. We expect sequential revenue growth in the first quarter of 2022, along with improvement in our margins as integration costs start to fade away. We will also benefit from increased pricing in the first quarter of 2022, driven by a pass-through of inflationary costs and higher net service pricing. We expect modest rises in pricing during subsequent quarters in 2022, along with the opportunity for margin growth associated with lowering our cost of operations and increasing efficiencies. 
+Increase in Drilling Efficiency and Service Intensity of Completions 
+Over the past decade, E&P companies have focused on exploiting the vast resource potential available across many of North America’s unconventional resource plays through the application of horizontal drilling and completion technologies, including the use of multi-stage hydraulic fracturing, in order to increase recovery of oil and natural gas. As E&P companies have improved drilling and completion techniques to maximize return and efficiency, we believe that their “break-even oil prices” continue to decline. These improvements in well economics have kept U.S. Shale oil and gas production competitive even as oil and gas prices have declined. Liberty has been a significant partner with our customers in driving these continued improvements. 
+Improved drilling economics from horizontal drilling and greater rig efficiencies . Unconventional resources are increasingly being targeted through the use of horizontal drilling. According to Baker Hughes, as reported on February 11, 2022, horizontal rigs accounted for approximately 94% of all rigs drilling in the United States and Canada, up from 77% as of December 26, 2014. Over the past several years, North American E&P companies have benefited from improved drilling economics driven by technologies that reduce the number of days, and the cost, of drilling wells. North American drilling rigs have incorporated newer technologies, which allow them to drill rock more effectively and quickly, meaning each rig can drill more wells in a given period. These include improved drilling technologies and the incorporation of geosteering techniques which allow better placement of the wellbore. Drilling rigs have also incorporated new technology which allows fully-assembled rigs to automatically “walk” from one location to the next without disassembling and reassembling the rig, greatly reducing the time it takes to move from one drilling location to the next. Today the majority of E&P drilling is on multi-well pad development, allowing efficient drilling of multiple horizontal wellbores from the same pad or location. The aggregate effect of these improved techniques and technologies have reduced the average days required to drill a well, which according to Lium Research, has dropped from 28 days in 2014 to 17 days in 2021. 
+Increased complexity and service intensity of horizontal well completions . In addition to improved rig efficiencies discussed above, E&P companies are also improving the subsurface techniques and technologies used to exploit unconventional resources. These improvements have targeted increasing the exposure of each wellbore to the reservoir by drilling longer horizontal lateral sections of the wellbore. To complete the well, hydraulic fracturing is applied in stages along the wellbore to break-up the resource so that oil and gas can be produced. As wellbores have increased in length, the number of frac stages and/or the number of perforation clusters (frac initiation points) has also increased. Further, E&P companies have improved production from each stage by applying increasing amounts of proppant in each stage, which better connects the well to the 
+31 
+resource. The aggregate effect of increased number of stages and the increasing amount of proppant in each stage has greatly increased the total amount of proppant used in each well, according to Liberty’s FracTrends database, from six million pounds per well in 2014 to over 18.6 million pounds per well in 2021. Further efficiency gains are being sought via the “simul-frac” technique. Utilizing a larger frac fleet (1.25x to 2x the normal horsepower), operators are fracturing stages in two separate wells on a pad simultaneously as a single operation. When compared to typical zipper-frac operations, this new method allows for more lateral feet to be completed in a day. This emerging trend will allow operators to complete a pad of wells quicker, thereby shortening the time from spud to first production. 
+These industry trends continue to keep our customers as important suppliers to the global oil and natural gas markets, which directly benefit hydraulic fracturing companies like us that have the expertise and innovative technology to effectively service today’s more efficient oilfield drilling activity and the increasing complexity and intensity of well completions. Given the expected returns that E&P companies have reported for new well development activities due to improved rig efficiencies and increasing well completion complexity and intensity, we expect these industry trends to continue. 
+How We Generate Revenue 
+We currently generate revenue through the provision of hydraulic fracturing and wireline services and goods, including sand from our Permian Basin sand mines. These services and goods are provided under a variety of contract structures, primarily master service agreements (“MSAs”) as supplemented by statements of work, pricing agreements and specific quotes. A portion of our statements of work, under MSAs, include provisions that establish pricing arrangements for a period of up to approximately one year in length. However, the majority of those agreements provide for pricing adjustments based on market conditions. The majority of our services are priced based on prevailing market conditions and changing input costs at the time the services are provided, giving consideration to the specific requirements of the customer. 
+Our hydraulic fracturing and wireline services are performed in sections, which we refer to as fracturing stages. The estimated number of fracturing stages to be completed for a particular horizontal well is determined by the customer’s well completion design. We recognize revenue for each fracturing stage completed, although our revenue per completed fracturing stage varies depending on the actual volumes and types of proppants, chemicals and fluid utilized for each fracturing stage. The number of fracturing stages that we are able to complete in a period is directly related to the number and utilization of our deployed fleets and size of stages. 
+Costs of Conducting Our Business 
+The principal expenses involved in conducting our business are direct cost of personnel, services and materials used in the provision of services, general and administrative expenses, and depreciation and amortization. A large portion of the costs we incur in our business are variable based on the number of hydraulic fracturing jobs and the requirements of services provided to our customers. We manage the level of our fixed costs, except depreciation and amortization, based on several factors, including industry conditions and expected demand for our services. 
+How We Evaluate Our Operations 
+We use a variety of qualitative, operational and financial metrics to assess our performance. First and foremost of these is a qualitative assessment of customer satisfaction because ensuring we are a valuable partner to our customers is the key to achieving our quantitative business metrics. Among other measures, management considers each of the following: 
+• Revenue; 
+• Operating Income; 
+• EBITDA; 
+• Adjusted EBITDA; 
+• Net Income Before Taxes; and 
+• Earnings per Share. 
+Revenue 
+We analyze our revenue by comparing actual monthly revenue to our internal projections for a given period and to prior periods to assess our performance. We also assess our revenue in relation to the number of fleets we have deployed (revenue per average active fleet) from period to period. 
+32 
+Operating Income 
+We analyze our operating income, which we define as revenues less direct operating expenses, depreciation and amortization and general and administrative expenses, to measure our financial performance. We believe operating income is a meaningful metric because it provides insight on profitability and true operating performance based on the historical cost basis of our assets. We also compare operating income to our internal projections for a given period and to prior periods. 
+EBITDA and Adjusted EBITDA 
+We view EBITDA and Adjusted EBITDA as important indicators of performance. We define EBITDA as net income (loss) before interest, income taxes, depreciation and amortization. We define Adjusted EBITDA as EBITDA adjusted to eliminate the effects of items such as non-cash stock based compensation expense, new fleet or new basin start-up costs, fleet lay-down costs, costs of asset acquisition, gain or loss on the disposal of assets, asset impairment charges, bad debt reserves, and non-recurring expenses that management does not consider in assessing ongoing operating performance. See “Comparison of Non-GAAP Financial Measures” for more information and a reconciliation of EBITDA and Adjusted EBITDA to net income (loss), the most directly comparable financial measure calculated and presented in accordance with GAAP. 
+Results of Operations 
+Year Ended December 31, 2021, Compared to Year Ended December 31, 2020 
+Years Ended December 31, 
+Description 2021 2020 Change 
+(in thousands) 
+Revenue $ 2,470,782 $ 965,787 $ 1,504,995 
+Cost of services, excluding depreciation and amortization shown separately 2,249,926 857,981 1,391,945 
+General and administrative 123,406 84,098 39,308 
+Transaction, severance and other costs 15,138 21,061 (5,923) 
+Depreciation, depletion and amortization 262,757 180,084 82,673 
+Loss (gain) on disposal of assets 779 (411) 1,190 
+Operating loss (181,224) (177,026) (4,198) 
+Other (income) expense, net (3,436) 14,505 (17,941) 
+Net loss before taxes (177,788) (191,531) 13,743 
+Income tax expense (benefit) 9,216 (30,857) 40,073 
+Net loss (187,004) (160,674) (26,330) 
+Less: Net loss attributable to non-controlling interests (7,760) (45,091) 37,331 
+Net loss attributable to Liberty Oilfield Services Inc. stockholders $ (179,244) $ (115,583) $ (63,661) 
+Revenue 
+Our revenue increased $1.5 billion, or 156%, to $2.5 billion for the year ended December 31, 2021 compared to $1.0 billion for the year ended December 31, 2020. The increase is attributable to higher fleet utilization and service prices, as well as additional fleets and service lines obtained through the OneStim Acquisition, which drove higher revenue, commensurate with the energy demand recovery. 
+Cost of Services 
+Cost of services (excluding depreciation and amortization) increased $1.4 billion, or 162%, to $2.2 billion for the year ended December 31, 2021 compared to $0.9 billion for the year ended December 31, 2020. The higher expense was primarily related to the increase in activity, as discussed above, as well as increases in material, personnel, and repairs and maintenance costs related to global supply chain challenges, inflationary pressures and material prices. The Company also reinstated bonus programs and the 401(k) match program, both of which we temporarily suspended during 2020. 
+General and Administrative Expenses 
+General and administrative expenses increased $39.3 million, or 47%, to $123.4 million for the year ended December 31, 2021 compared to $84.1 million for the year ended December 31, 2020 primarily related to an increase in personnel benefits due to additional headcount commensurate with the acquisitions of OneStim and PropX. The furlough and flexible cost structure implemented in 2020 also ended prior to 2021. Additionally, during 2021, the Company reinstated bonus programs and the 401(k) match program, both of which we temporarily suspended during 2020. 
+33 
+Transaction, Severance and Other Costs 
+Transaction costs were $15.1 million for the year ended December 31, 2021 compared to $8.5 million for the year ended December 31, 2020. Such costs incurred primarily relate to investment banking, legal, accounting, other professional services provided and integration costs in connection with the acquisitions of OneStim and PropX. 
+Severance and other costs were $0 during the year ended December 31, 2021 compared to $12.6 million for the year ended December 31, 2020 which were related to one time severance costs and insurance and other benefits for furloughed employees. The Company did not lay-off or furlough any employees during 2021. 
+Depreciation, Depletion and Amortization 
+Depreciation, depletion and amortization expense increased $82.7 million, or 45.9%, to $262.8 million for the year ended December 31, 2021 compared to $180.1 million for the year ended December 31, 2020. The increase in 2021 was due to the addition of active fleets and other property from the acquisitions of OneStim and PropX. 
+Loss (gain) on Disposal of Assets 
+The Company recorded a loss on disposal of assets of $0.8 million for the year ended December 31, 2021 compared to a gain of $0.4 million for the year ended December 31, 2020. In an effort to consolidate operations in certain basins after the OneStim Acquisition, the Company sold three real estate properties during the fourth quarter of 2021, which collectively resulted in a small loss on sale, along with regular sales of equipment that was no longer being used. During 2020, the Company reduced the number of light duty pick-ups used in fleets based on lower levels of activity; and the Company realized gains upon sale commensurate with lease terminations. 
+Operating Loss 
+Operating loss increased $4.2 million, or 2.4%, to $181.2 million for the year ended December 31, 2021 compared to operating loss of $177.0 million for the year ended December 31, 2020. The increased operating loss is primarily due to the cost of services rising at a slightly higher rate than revenue increases through the rebound in activity levels in 2021. 
+Other (Income) Expense, net 
+The Company recorded other income, net of $3.4 million for the year ended December 31, 2021 compared to other expense, net of $14.5 million during the year ended December 31, 2020. Other (income) expense, net is comprised of gain on remeasurement of liability under the TRAs and interest expense, net. During the second quarter of 2021, the Company entered into a three-year cumulative pre-tax book loss primarily due to COVID-19 related losses and recognized a valuation allowance on a portion of its deferred tax assets in accordance with ASC 740. As a result of the recognition of a valuation allowance, the Company also remeasured the liability under the TRAs resulting in a gain of $19.0 million during the year ended December 31, 2021. Interest expense, net was consistent between periods, increasing $1.1 million as a result of increased borrowings under the credit facility and lower interest income during the year ended December 31, 2021 compared to the year ended December 31, 2020. 
+Net Loss Before Taxes 
+Net loss before taxes decreased $13.7 million, or 7.2%, to $177.8 million for the year ended December 31, 2021 compared $191.5 million for the year ended December 31, 2020. The decrease in loss is primarily due to the gain recognized upon remeasurement of the TRAs during the year ended December 31, 2021 as compared to the year ended December 31, 2020 partially offset by the increase in operating loss discussed above. 
+Income Tax Expense (Benefit) 
+Tax expense of $9.2 million was recognized for the year ended December 31, 2021, an effective rate of (5.2)%, compared to an income tax benefit of $30.9 million, at an effective rate of 16.1%, recognized for the year ended December 31, 2020. The income tax expense is primarily attributable to the full valuation allowance recorded on the net deferred tax assets as of June 30, 2021, and Canada income and provincial taxes. 
+Comparison of Non-GAAP Financial Measures 
+We view EBITDA and Adjusted EBITDA as important indicators of performance. We define EBITDA as net income (loss) (the most directly comparable GAAP financial measure) before interest, income taxes, depreciation, depletion and amortization. We define Adjusted EBITDA as EBITDA adjusted to eliminate the effects of items such as non-cash stock based compensation expense, new fleet or new basin start-up costs, fleet lay-down costs, costs of asset acquisitions, gain or loss on the disposal of assets, bad debt reserves and non-recurring expenses that management does not consider in assessing ongoing performance. 
+34 
+Our board of directors, management, investors, and lenders use EBITDA and Adjusted EBITDA to assess our financial performance because it allows them to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure (such as varying levels of interest expense), asset base (such as depreciation, depletion and amortization) and other items that impact the comparability of financial results from period to period. We present EBITDA and Adjusted EBITDA because we believe they provide useful information regarding the factors and trends affecting our business in addition to measures calculated under GAAP. 
+Note Regarding Non-GAAP Financial Measures 
+EBITDA and Adjusted EBITDA are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures will provide useful information to investors in assessing our financial performance and results of operations. Net income is the GAAP measure most directly comparable to EBITDA and Adjusted EBITDA. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as an analytical tool due to exclusion of some but not all items that affect the most directly comparable GAAP financial measures. You should not consider EBITDA or Adjusted EBITDA in isolation or as substitutes for an analysis of our results as reported under GAAP. Because EBITDA and Adjusted EBITDA may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. 
+The following tables present a reconciliation of EBITDA and Adjusted EBITDA to our net income, which is the most directly comparable GAAP measure for the periods presented: 
+Year Ended December 31, 2021 Compared to Year Ended December 31, 2020: EBITDA and Adjusted EBITDA 
+Years Ended December 31, 
+Description 2021 2020 Change 
+(in thousands) 
+Net loss $ (187,004) $ (160,674) $ (26,330) 
+Depreciation and amortization 262,757 180,084 82,673 
+Interest expense, net 15,603 14,505 1,098 
+Income tax expense (benefit) 9,216 (30,857) 40,073 
+EBITDA $ 100,572 $ 3,058 $ 97,514 
+Stock based compensation expense 19,946 17,139 2,807 
+Fleet start-up and lay-down costs 2,751 12,175 (9,424) 
+Transaction, severance and other costs 15,138 21,061 (5,923) 
+Loss (gain) on disposal of assets 779 (411) 1,190 
+Provision for credit losses 745 4,877 (4,132) 
+Gain on remeasurement of liability under tax receivable agreement (19,039) — (19,039) 
+Adjusted EBITDA $ 120,892 $ 57,899 $ 62,993 
+EBITDA was $100.6 million for the year ended December 31, 2021 compared to $3.1 million for the year ended December 31, 2020. Adjusted EBITDA was $120.9 million for the year ended December 31, 2021 compared to $57.9 million for the year ended December 31, 2020. The increases in EBITDA and Adjusted EBITDA primarily resulted from improved market conditions and increased activity levels as described above under the captions Revenue , Cost of Services, and General and Administrative Expenses for the Year Ended December 31, 2021, Compared to Year Ended December 31, 2020 . 
+Liquidity and Capital Resources 
+Overview 
+Historically, our primary sources of liquidity to date have been cash flows from operations, proceeds from our IPO, and borrowings under our Credit Facilities. We expect to fund operations and organic growth with cash flows from operations and available borrowings under our Credit Facilities. We monitor the availability of capital resources such as equity and debt financings that could be leverage for current or future financial obligations including those related to acquisitions, capital expenditures, working capital and other liquidity requirements. We may incur additional indebtedness or issue equity in order to meet our capital expenditure activities and liquidity requirements, as well as to fund growth opportunities that we pursue, including via acquisition, such as with the acquisitions of OneStim and PropX. Our primary uses of capital have been capital expenditures to support organic growth and funding ongoing operations, including maintenance and fleet upgrades. 
+35 
+Cash and cash equivalent s decreased by $49.0 million to $20.0 million as of December 31, 2021 compared to $69.0 million as of December 31, 2020, while working capital excluding cash and current liabilities under debt and lease arrangements decreased $104.5 million. 
+We have $350.0 million committed under the ABL Facility (net of any outstanding letters of credit), subject to certain borrowing base limitations based on a percentage of eligible accounts receivable and inventory (with the ability to request an increase in the size of the ABL Facility by $75 million) available to finance working capital needs. As of December 31, 2021, the borrowing base was calculated to be $269.0 million, and the Company had $18.0 million outstanding in addition to a letter of credit in the amount of $1.5 million, with $249.5 million of remaining availability. 
+Additionally, we have $106.5 million borrowings remaining on the Term Loan Facility, which was originally $175.0 million. 
+On October 22, 2021, the Company entered into an amendment to the ABL Facility (the “Revolving Credit Agreement Amendment”). The Revolving Credit Agreement Amendment further amends the credit agreement and guaranty and security agreement originally entered into by the parties on September 19, 2017, which governs the Company’s ABL Facility. Along with other revisions, the Revolving Credit Agreement Amendment (i) expanded the definition of borrowing base to include certain eligible US investment grade accounts, Canadian accounts solely after a specified event, and both chemical and spare parts inventory; (ii) increased the maximum revolver amount from $250.0 million to $350.0 million (with the ability to request an increase in the size of the ABL Facility by $75 million); (iii) increased certain indebtedness baskets; (iv) provided additional flexibility for a potential future internal structuring; (v) added new lenders to the facility; and (vi) extended the maturity date to the earlier of (a) October 22, 2026 and (b) to the extent the debt under the Term Loan Facility remains outstanding 90 days prior to the final maturity of the Term Loan Facility. The ABL Facility was initially scheduled to mature on the earlier to occur of (i) September 19, 2022 and (ii) to the extent the debt under the Term Loan Facility remains outstanding, 90 days prior to the final maturity of the Term Loan Facility. 
+On October 22, 2021, the Company entered into a Fifth Amendment to Credit Agreement, Second Amendment to Guaranty and Security Agreement and Termination of Right of First Offer Letter. The Term Loan Credit Agreement Amendment further amends the credit agreement and guaranty and security agreement and terminates the Right of First Offer Letter originally entered into by the parties on September 19, 2017, which governs the Company’s Term Loan Facility. Along with other revisions, the Term Loan Credit Agreement Amendment (i) increased certain indebtedness baskets; (ii) provided additional flexibility for a potential future internal structuring; (iii) extended the maturity date through September 19, 2024; and (iv) terminated a right of first offer in favor of the Term Loan Facility lenders. The Term Loan Facility was initially scheduled to mature on September 19, 2022. 
+The Credit Facilities contain covenants that restrict our ability to take certain actions. At December 31, 2021, we were in compliance with all debt covenants. 
+See Note 8 —Debt to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for further details. 
+Cash Flows 
+The following table summarizes our cash flows for the periods indicated: 
+Years Ended December 31, 
+Description 2021 2020 Change 
+(in thousands) 
+Net cash provided by operating activities $ 135,467 $ 85,425 $ 50,042 
+Net cash used in investing activities (186,494) (100,269) (86,225) 
+Net cash provided by (used in) financing activities 2,056 (28,868) 30,924 
+Analysis of Cash Flow Changes Between the Years Ended December 31, 2021 and December 31, 2020 
+Operating Activities . Net cash provided by operating activities was $135.5 million for the year ended December 31, 2021, compared to net cash provided by operating activities of $85.4 million for the year ended December 31, 2020. The $50.0 million increase in cash from operating activities was primarily attributable to a $1.5 billion increase in revenues, offset by a $1.4 billion increase in cash operating expenses and a $46.9 million increase in cash from changes in working capital for the year ended December 31, 2021, compared to a $63.3 million increase in cash from changes in working capital for the year ended December 31, 2020. 
+36 
+Investing Activities . Net cash used in investing activities was $186.5 million for the year ended December 31, 2021, compared to $100.3 million for the year ended December 31, 2020. The $86.2 million increase in cash used in investment activities related to a decrease in spend in 2020 starting in the second quarter and remaining throughout the year due to the COVID-19 pandemic. Investing increased during 2021 when the markets recovered to pre-pandemic levels and $11.9 million was used in the fourth quarter for the PropX Acquisition. 
+Financing Activities . Net cash provided by financing activities was $2.1 million for the year ended December 31, 2021, compared to net cash used in financing activities of $28.9 million for the year ended December 31, 2020. The $30.9 million change in financing activities was primarily due to net borrowings of $18.0 million on the ABL Facility during the year ended December 31, 2021, compared to no borrowings on the ABL Facility for the year ended December 31, 2020. Additionally, there was a $5.8 million decrease in dividends and per unit distributions to non-controlling interest unitholders as a result of the suspension of the dividend in April 2020. Other distributions and advance payments to non-controlling interest unitholders was a net receipt of $1.4 million during the year ended December 31, 2021, compared to net payment of $6.8 million during the year ended December 31, 2020 due to a decrease in payments made under the TRAs. These decreases were offset by a $2.6 million increase in payments made for tax withholding on restricted stock unit vesting as a larger number of units vested at a higher stock price in 2021 compared to 2020. 
+Cash Requirements 
+Our material cash commitments consists primarily of obligations under long-term debt, TRAs, finance and operating leases for property and equipment, and purchase obligations as part of normal operations. Certain amounts included in our contractual obligations as of December 31, 2021 are based on our estimates and assumptions about these obligations, including pricing, volumes and duration. We have no material off balance sheet arrangements as of December 31, 2021, except for purchase commitments under supply agreements disclosed below. 
+See Note 8 —Debt to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding scheduled maturities of our long-term debt. See Note 6 —Leases to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding scheduled maturities of finance and operating leases. 
+As of December 31, 2021, we had expected cash payments for estimated interest on our long-term debt and finance lease obligations of $10.6 million payable within the next twelve months and $17.4 million payable thereafter. 
+As of December 31, 2021, we had purchase obligations of $24.6 million payable within the next twelve months and $1.4 million payable thereafter. See Note 15 —Commitments & Contingencies to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding scheduled contractual obligations. 
+We currently do not expect to make any payments under the TRAs within the next twelve months, future amounts payable under the TRAs are dependent upon future events. See Note 12 —Income Taxes to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding the TRAs. 
+Other Factors Affecting Liquidity 
+Customer receivables: In line with industry practice, we typically bill our customers for services provided in arrears dependent upon contractual terms. In weak economic environments, we may experience delays in collection from our customers. Due to the impact of the COVID-19 pandemic on the industry, we have experienced delays in customer payments and agreed to extended payment terms, however, we have not experienced any material non-payment events. 
+37 
+Tax Receivable Agreements 
+In connection with the IPO, on January 17, 2018, the Company entered into two TRAs with the TRA Holders. The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that the Company actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result, as applicable to each of the TRA Holders, of (i) certain increases in tax basis that occur as a result of the Company’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holders’ Liberty LLC Units in connection with the IPO or pursuant to the exercise of the right of each Liberty Unit Holder (the “Redemption Right”), subject to certain limitations, to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units for, at Liberty LLC’s election, (A) shares of our Class A Common Stock at the specific redemption ratio or (B) an equivalent amount of cash, or, upon the exercise of the Redemption Right, the right of the Company (instead of Liberty LLC) to, for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder (the “Call Right”) for, at its election, (1) one share of Class A Common Stock or (2) an equivalent amount of cash, (ii) any net operating losses available to the Company as a result of the Corporate Reorganization, and (iii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRAs. 
+With respect to obligations the Company expects to incur under the TRAs (except in cases where the Company elects to terminate the TRAs early, the TRAs are terminated early due to certain mergers, asset sales, or other changes of control or the Company has available cash but fails to make payments when due), generally the Company may elect to defer payments due under the TRAs if the Company does not have available cash to satisfy its payment obligations under the TRAs or if its contractual obligations limit its ability to make such payments. Any such deferred payments under the TRAs generally will accrue interest. In certain cases, payments under the TRAs may be accelerated and/or significantly exceed the actual benefits, if any, the Company realizes in respect of the tax attributes subject to the TRAs. The Company accounts for amounts payable under the TRAs in accordance with Accounting Standard Codification (“ASC”) Topic 450, Contingencies (“ASC Topic 450”). 
+If the Company experiences a change of control (as defined under the TRAs) or the TRAs otherwise terminate early, the Company’s obligations under the TRAs could have a substantial negative impact on its liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. There can be no assurance that we will be able to finance our obligations under the TRAs. 
+Income Taxes 
+The Company is a corporation and is subject to U.S. federal, state and local income tax on its share of Liberty LLC’s taxable income. The Company is also subject to Canada federal and provincial income taxes on its foreign operations. 
+The combined effective tax rate applicable to the Company for the year ended December 31, 2021 and 2020 was (5.2)% and 16.1%, respectively. The Company’s effective tax rate is significantly less than the federal statutory income tax rate of 21.0% due to the Company recording a valuation allowance on its U.S. net deferred tax assets as of December 31, 2021, due to entering into a three year cumulative pre-tax book loss position, primarily as a result of COVID-19 related losses in 2021. The Company’s effective tax rate is also less than the statutory rate because of foreign operations for 2021, and the non-controlling interest’s share of Liberty LLC’s pass-through results for federal, state and local income tax reporting, upon which no taxes are payable by the Company for the years ended December 31, 2021 and 2020. The Company recognized income tax expense of $9.2 million and an income tax benefit of $30.9 million for the years ended December 31, 2021 and 2020, respectively. 
+Per the Coronavirus Aid, Relief and Economic Security (“CARES”) Act enacted on March 27, 2020, net operating losses (“NOL”) incurred in 2018, 2019, and 2020 may be carried back to each of the five preceding taxable years to generate a refund of previously paid income taxes. The Company has previously applied for and expects to receive a NOL carryback refund to recover $5.5 million of cash taxes paid by the Company in 2018. This amount has been reflected as a receivable in the prepaids and other current assets line item in the accompanying audited consolidated balance sheets. 
+Refer to Note 12— Income Taxes to the consolidated financial statements for additional information related to income tax expense. 
+Critical Accounting Policies and Estimates 
+The preparation of financial statements requires the use of judgments and estimates. Our critical accounting policies are described below to provide a better understanding of how we develop our assumptions and judgments about future events and related estimates and how they can impact our financial statements. A critical accounting estimate is one that requires our most difficult, subjective or complex estimates and assessments and is fundamental to our results of operations. 
+38 
+We base our estimates on historical experience and on various other assumptions we believe to be reasonable according to the current facts and circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. We believe the following are the critical accounting policies used in the preparation of our consolidated financial statements, as well as the significant estimates and judgments affecting the application of these policies. This discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included in “Item 8. Financial Statements and Supplementary Data. ” 
+Business Combinations : Business combinations are accounted for using the acquisition method of accounting in accordance with the ASC Topic 805 - Business Combinations, as amended by Accounting Standards Update (“ASU”) 2017-01, Business Combinations (Topic 805), Clarifying the Definition of a Business. The purchase price is allocated to the assets acquired and liabilities assumed based on their estimated fair values. Fair value of the acquired assets and liabilities is measured in accordance with the guidance of ASC 850 - Fair Value Measurements, using discounted cash flows and other applicable valuation techniques. Any acquisitions related costs incurred by the Company are expensed as incurred. Any excess purchase price over the fair value of the net identifiable assets acquired is recorded as goodwill if the definition of a business is met. Operating results of an acquired business are included in our results of operations from the date of acquisition. 
+Revenue Recognition: Revenue from hydraulic fracturing services is recognized as specific services are provided in accordance with contractual arrangements. If our assessment of performance under a particular contract changes, our revenue and / or costs under that contract may change. In connection with ASC Topic 842 - Leases (“Topic 842”), the Company determined that certain of its service revenue contracts contain a lease component. The Company elected to adopt a practical expedient available to lessors, which allows the Company to combine the lease and service component for certain of the Company’s service contracts when the service component is the predominant component and continues to account for the combined component under ASC Topic 606 - Revenue from Contracts with Customers . 
+Accounts Receivable: On January 1, 2020, the Company adopted ASU 2016-13, Financial Instruments-Credit Losses (Topic 326) : Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”), which changes the impairment model for most financial assets and certain other instruments. Specifically, this new guidance requires using a forward looking, expected loss model for trade and other receivables, held-to-maturity debt securities, loans, and other instruments. Under ASU 2016-13, a company recognizes as an allowance, the estimate of lifetime expected credit losses, which is expected to result in more timely recognition of such losses. 
+The Company applies historic loss factors to its receivable portfolio segments that were not expected to be further impacted by current economic developments, and an additional economic conditions factor to portfolio segments anticipated to experience greater losses in the current economic environment. The Company continuously evaluates customers based on risk characteristics, such as historical losses and current economic conditions. Due to the cyclical nature of the oil and gas industry, the Company often evaluates its customers’ estimated losses on a case-by-case basis. It is reasonably possible that our estimates of the allowance for doubtful accounts will change and that losses ultimately incurred could differ materially from the amounts estimated in determining the allowance. 
+Inventory: Inventory consists of raw materials used in the hydraulic fracturing process, such as proppants, chemicals and field service equipment maintenance parts, and is stated at the lower of cost or net realizable value, determined using the weighted average cost method. Net realizable value is determined based on our estimates of selling prices in the ordinary course of business, less reasonably predictable cost of completion, disposal, and transportation, each of which require us to apply judgment. 
+Property and Equipment: We calculate depreciation and amortization on our assets based on the estimated useful lives and estimated salvage values that we believe are reasonable. The estimated useful lives and salvage values are subject to key assumptions such as maintenance, utilization and job variation. These estimates may change due to a number of factors such as changes in operating conditions or advances in technology. 
+We incur maintenance costs on our major equipment. The determination of whether an expenditure should be capitalized or expensed requires management judgment in the application of how the costs benefit future periods, relative to our capitalization policy. Costs that either establish or increase the efficiency, productivity, functionality or life of a fixed asset are capitalized and depreciated over the remaining useful life of the asset. 
+Impairment of long-lived and other intangible assets: Long-lived assets, such as property and equipment, right-of-use lease assets and intangible assets, are evaluated for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Recoverability is assessed using undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets. When alternative courses of action to recover the carrying amount of the asset group are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence, which require us to apply judgment. If the carrying amount of the asset is not recoverable based on its estimated undiscounted cash flows expected to result from the use and eventual disposition, an impairment loss is recognized in an amount by which its carrying amount 
+39 
+exceeds its estimated fair value. The inputs used to determine such fair value are primarily based upon internally developed cash flow models. Our cash flow models are based on a number of estimates regarding future operations that may be subject to significant variability, are sensitive to changes in market conditions, and are reasonably likely to change in the future. 
+During the year ended December 31, 2020, as a result of negative market indicators including the COVID-19 pandemic, the increased supply of low-priced oil, and customer cancellations, the Company concluded these triggering events could indicate possible impairment of property and equipment. The Company performed a quantitative and qualitative impairment analysis and determined that no impairment had occurred as of March 31, 2020. As of December 31, 2020, the Company concluded that no additional triggering events occurred and the conclusion reached at March 31, 2020 is still appropriate. Such analysis required management to make estimates and assumptions based on historical data and consideration of future market conditions. Given the uncertainty inherent in any projection, heightened by the possibility of unforeseen additional effects of COVID-19, actual results may differ from the estimates and assumptions used, or conditions may change, which could result in impairment charges in the future. 
+No impairment was recognized during the years ended December 31, 2021, 2020 and 2019. 
+Leases: The Company adopted Accounting Standards Update (“ASU”) No. 2016-02, Leases ASC Topic 842 effective January 1, 2019. We elected the modified retrospective transition method under ASC Topic 842 and as such information prior to January 1, 2019 has not been restated and continues to be reported under the accounting standards in effect for the period ( ASC Topic 840-Leases ). We carried forward the historical lease classifications and assessment of initial direct costs, account for lease and non-lease components as a single component, and exclude leases with an initial term of less than 12 months in the lease assets and liabilities. For leases entered into after January 1, 2019, the Company determines if an arrangement is a lease at inception and evaluates identified leases for operating or finance lease treatment. Operating or finance lease right-of-use assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. We use our incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments. Lease terms may include options to renew; however, we typically cannot determine our intent to renew a lease with reasonable certainty at inception. 
+Tax Receivable Agreements: In connection with the IPO, on January 17, 2018, the Company entered into two TRAs with the TRA Holders. The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax that the Company actually realizes in periods after the IPO as a result of certain tax attributes applicable to each TRA Holder. The Company accounts for amounts payable under the TRAs in accordance with ASC Topic 450, Contingencies . 
+Share Repurchases: The Company accounts for the purchase price of repurchased Class A Common Stock in excess of par value ($0.01 per share of Class A Common Stock) as a reduction of additional paid-in capital, and will continue to do so until additional paid-in capital is reduced to zero. Thereafter, any excess purchase price will be recorded as a reduction to retained earnings. 
+Foreign Currency Translation: Effective January 1, 2021, the Company commenced operations in Canada and therefore added a critical accounting policy for foreign currency translation. See Note 2―Significant Accounting Policies in the accompanying audited consolidated financial statements included herein and incorporated by reference into this offering memorandum. 
+Recent Accounting Pronouncements 
+See Note 2—Significant Accounting Policies— Recently Issued Accounting Standards to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for a discussion of recent accounting pronouncements. 
+40 
+Item 7A. Quantitative and Qualitative Disclosure about Market Risk 
+Industry Risk 
+The demand, pricing and terms for hydraulic fracturing services and related goods provided by us are largely dependent upon the level of drilling activity in the U.S. oil and natural gas industry, as well as the available supply of hydraulic fracturing equipment. These activity levels are influenced by numerous factors over which we have no control, including, but not limited to: the supply of and demand for oil and natural gas; the level of prices, and expectations about future prices of oil and natural gas; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; the discovery rates of new oil and natural gas reserves; supply of actively marketed and staffed fracturing fleets; available rail and other transportation capacity; weather conditions; domestic and worldwide economic conditions; political instability in oil-producing countries; environmental regulations; technical advances affecting energy consumption; the price and availability of alternative fuels; the ability of E&P companies to raise equity capital and debt financing; and merger and divestiture activity among E&P companies. 
+The level of U.S. oil and natural gas drilling is volatile. Expected trends in oil and natural gas production activities may not materialize and demand for our services may not reflect the level of activity in the industry. Any prolonged and substantial reduction in oil and natural gas prices would likely affect oil and natural gas production levels and therefore affect demand for our services. A material decline in oil and natural gas prices or U.S. activity levels could have a material adverse effect on our business, financial condition, results of operations and cash flows. 
+Interest Rate Risk 
+At December 31, 2021, we had $124.5 million of debt outstanding, with a weighted average interest rate of 8.6%. Interest is calculated under the terms of our Credit Facilities based on our selection, from time to time, of one of the index rates available to us plus an applicable margin that varies based on certain factors. See “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements.” Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the weighted average interest rate would be approximately $1.2 million per year. We do not currently have or intend to enter into any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness. 
+Commodity Price Risk 
+Our material and fuel purchases expose us to commodity price risk. Material costs primarily include inventory consumed while performing hydraulic fracturing services. Fuel costs consist of diesel fuel used by trucks and other motorized equipment used for hydraulic fracturing services. At times, we have been able to pass along price increases for material costs and fuel costs to customers and conversely have been required to pass along price decreases for material costs to our customers, depending on market conditions. Further, we have purchase commitments with certain vendors to supply proppant inventory used in our operations at a fixed purchase price, including certain commitments which include minimum purchase obligations. Refer t o Note 15 — Commitments and Contingencies included in “Item 8. Financial Statements and Supplementary Data” for further discussion regarding pur chase commitments. 
+41 
+Item 8. Financial Statements and Supplementary Data 
+Our financial statements and supplementary data are included in this Annual Report beginning on page F-1 and incorporated by reference herein. 
+Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+None. 
+Item 9A. Controls and Procedures 
+Evaluation of Disclosure Controls and Procedures’ 
+In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2021 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures. 
+As noted in Management’s Report on Internal Control Over Financial Reporting, management’s evaluation of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of the entities acquired in the PropX Acquisition, as defined herein, on October 26, 2021. Under guidelines established by the SEC, companies are permitted to exclude acquisitions from their assessment of internal control over financial reporting during the first year of an acquisition while integrating the acquired company. The Company is in the process of integrating PropX’s and our internal controls over financial reporting. As a result of these integration activities, certain controls will be evaluated and may be changed. Except as noted above, there were no changes to our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+See page F-1 for Management’s Report on Internal Control Over Financial Reporting and page F-4 for Report of Independent Registered Public Accounting Firm on its assessment of our internal control over financial reporting. 
+Item 9B. Other Information 
+None. 
+42 
+PART III 
+Item 10. Directors, Executive Officers and Corporate Governance 
+The information required by this item concerning our executive officers, directors and corporate governance is incorporated herein by reference to our definitive proxy statement for our 2022 annual meeting of stockholders, which will be filed with the SEC no later than 120 days after December 31, 2021, under the captions “Proposal 1 — Election of Directors,” “The Board and its Committees,” “Executive Officers” and “Delinquent Section 16(a) Reports.” 
+Item 11. Executive Compensation 
+The information required by this item concerning executive compensation is incorporated herein by reference to our definitive proxy statement for our 2022 annual meeting of stockholders, which will be filed with the SEC no later than 120 days after December 31, 2021, under the captions “The Board and its Committees,” “Compensation Discussion & Analysis,” “Compensation Committee Report,” “Executive Compensation Tables,” “Director Compensation” and “CEO Pay Ratio.” 
+Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+The information required by this item concerning the security ownership of certain beneficial owners and management and related stockholder matters are incorporated herein by reference to our definitive proxy statement for our 2022 annual meeting of stockholders, which will be filed with the SEC no later than 120 days after December 31, 2021, under the captions “Security Ownership of Certain Beneficial Owners and Management” and “Equity Compensation Plan Information.” 
+Item 13. Certain Relationships and Related Transactions, and Director Independence 
+The information required by this item concerning certain relationships and related person transactions and director independence is incorporated herein by reference to our definitive proxy statement for our 2022 annual meeting of stockholders, which will be filed with the SEC no later than 120 days after December 31, 2021, under the captions “Certain Relationships and Related Party Transactions” and “the Board and its Committees.” 
+Item 14. Principal Accountant Fees and Services 
+The information required by this item concerning principal accounting fees and services is incorporated herein by reference to our definitive proxy statement for our 2022 annual meeting of stockholders, which will be filed with the SEC no later than 120 days after December 31, 2021, under the caption “Proposal 3 — Ratification of Appointment of the Company’s Independent Registered Public Accounting Firm.” 
+43 
+PART IV 
+Item 15. Exhibits and Financial Statement Schedules 
+(a) Financial Statements and Financial Statement Schedules 
+Refer to Index to Financial Statements on page 49. 
+All schedules are omitted as information required is inapplicable or the information is presented in the consolidated financial statements and the related notes. 
+(b) Exhibits 
+The documents listed in the Index to Exhibits are filed, furnished or incorporated by reference as part of this Annual Report, and such Index to Exhibits are incorporated herein by reference. 
+44 
+Item 16. Form 10-K Summary 
+None. 
+45 
+INDEX TO EXHIBITS 
+Exhibit 
+Number 
+Description 
+1.1 
+Underwriting Agreement, dated June 7, 2021, by and among Liberty Oilfield Services Inc., R/C Energy IV Direct Partnership, L.P., R/C IV Liberty Holdings, L.P. and Morgan Stanley & Co. LLC (14) 
+2.1 
+Master Reorganization Agreement, dated as of January 11, 2018, by and among Liberty Oilfield Services Inc., Liberty Oilfield Services Holdings LLC, Liberty Oilfield Services New HoldCo LLC, and the other parties named therein (2) 
+2.2 
+Master Transaction Agreement, dated as of August 31, 2020, by and among Schlumberger Technology Corporation, Schlumberger Canada Limited, Liberty Oilfield Services Holdings LLC, Liberty Canada Operations Inc. and Liberty Oilfield Services Inc. (11) 
+3.1 
+Amended and Restated Certificate of Incorporation of Liberty Oilfield Services Inc. (2) 
+3.2 
+Amended and Restated Bylaws of Liberty Oilfield Services Inc. (3) 
+4.1 
+Amended and Restated Stockholders Agreement, dated as of December 3 1 , 2020, by and among Liberty Oilfield Services Inc., Riverstone and the Schlumberger Parties (12) 
+4.2 
+Description of the Registrant’s Securities Registered pursuant to Section 12 of the Securities Exchange Act of 1934. (8) 
+10.1 
+Second Amended and Restated Limited Liability Company Operating Agreement of Liberty Oilfield Services New HoldCo LLC (2) 
+10.2 
+Form of Joinder Agreement to Second Amended and Restated Limited Liability Company Operating Agreement of Liberty Oilfield Services New HoldCo LLC (15) 
+10.3 
+Registration Rights Agreement, dated October 26, 2021, by and among Liberty Oilfield Services Inc. and the other parties named therein (15) 
+10.4 
+Tax Receivable Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Inc., R/C Energy IV Direct Partnership, L.P., and R/C Energy IV Direct Partnership, L.P., as agent (2) 
+10.5 
+Tax Receivable Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Inc., and the other parties named therein (2) 
+10.6 
+Amended and Restated Registration Rights Agreement, dated as of December 31, 2020, by and among Liberty Oilfield Services Inc., the Schlumberger Parties, and the Holders (12) 
+10.7 
+Liberty Oilfield Services Inc. Long Term Incentive Plan (2)† 
+10.8 
+Credit Agreement, dated September 19, 2017, by and among Wells Fargo Bank, National Association, as Administrative Agent, Wells Fargo Bank, National Association, JPMorgan Chase Bank, N.A. and Citibank, N.A., as Joint Lead Arrangers, Wells Fargo Bank, National Association, as Book Runner, JPMorgan Chase Bank, N.A. and Citibank, N.A., as Syndication Agents, the lender parties thereto, Liberty Oilfield Services Holdings LLC, as Parent and Liberty Oilfield Services LLC and LOS Acquisition Co I LLC, each as a Borrower (1) 
+10.9 
+Amendment and Parent Joinder to Credit Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Holdings LLC, Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto (4) 
+1010 
+Second Amendment and Parent Joinder to Credit Agreement, dated March 21, 2018, by and among Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto (4) 
+10.11 
+Third Amendment to Credit Agreement, dated May 29, 2020, by and among Liberty Oilfield Services LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, and Wells Fargo Bank, National Association as Administrative Agent, and the lenders signatory thereto (9) 
+10.12 
+Fourth Amendment to Credit Agreement, dated August 12, 2020, by and among Liberty Oilfield Services LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto (10) 
+46 
+10.13 
+Consent and Fifth Amendment to Credit Agreement, dated December 29, 2020, by and among Liberty Oilfield Services LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, LOS Cibolo RE Investments, LLC, LOS Odessa RE Investments, LLC, ST9 Gas and Oil LLC, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto (13) 
+10.14 
+Sixth Amendment to Credit Agreement and Second Amendment to Guaranty and Security Agreement, dated October 22, 2021, by and among Liberty Oilfield Services LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New HoldCo LLC, R/C IV Non-U.S. LOS Corp, LOS Solar Acquisition LLC, Freedom Proppant LLC, LOS Kermit LLC, LOS Cibolo RE Investments, LLC, LOS Odessa RE Investments, LLC, ST9 Gas and Oil LLC, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto (15) 
+10.15 
+Joinder Agreement, dated December 31, 2021, by and among LOS Leasing Company LLC and Wells Fargo Bank, National Association, as Administrative Agent * 
+10.16 
+Credit Agreement, dated September 1 9 , 2017, by and among Liberty Oilfield Services LLC and LOS Acquisition CO I LLC, each as Borrower, Liberty Oilfield Services Holdings LLC, as Parent Guarantor and U.S. Bank National Association as Agent (1) 
+10.17 
+Amendment and Joinder to Credit Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Holdings LLC, Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, U.S. Bank National Association, as Administrative Agent, and the lenders signatory thereto (4) 
+10.18 
+Second Amendment and Joinder to Credit Agreement, dated March 21, 2018, by and among Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, U.S. Bank National Association, as Administrative Agent, and the lenders signatory thereto (4) 
+10.19 
+Third Amendment to Credit Agreement, dated August 12, 2020, by and among Liberty Oilfield Services LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, U.S. Bank National Association, as Administrative Agent, and the lenders signatory thereto (10) 
+10.20 
+Waiver, Consent and Fourth Amendment to Credit Agreement and First Amendment to Guaranty and Security Agreement, dated December 29, 2020, by and among Liberty Oilfield Services LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, LOS Cibolo RE Investments, LLC, LOS Odessa RE Investments, LLC, ST9 Gas and Oil LLC, U.S. Bank National Association, as Administrative Agent, and the lenders signatory thereto (13) 
+10.21 
+Fifth Amendment to Credit Agreement, Second Amendment to Guaranty and Security Agreement and Termination of Right of First Offer Letter, dated October 22, 2021, by and among Liberty Oilfield Services LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New HoldCo LLC, R/C IV Non-U.S. LOS Corp, LOS Cibolo RE Investments, LLC, LOS Odessa RE Investments, LLC, ST9 Gas and Oil LLC, LOS Solar Acquisition LLC, Freedom Proppant LLC, LOS Kermit LLC, U.S. Bank National Association, as Administrative Agent, and the lenders signatory thereto (15) 
+10.22 
+Liberty Oilfield Services 401(k) Savings Plan (13)† 
+10.23 
+Form of Restricted Stock Unit Grant Notice and Restricted Stock Unit Award Agreement under the Long Term Incentive Plan (5)† 
+10.24 
+Form of Restricted Stock Unit Grant Notice under the Long Term Incentive Plan (13)† 
+10.25 
+Form of Performance Restricted Stock Unit Grant Notice and Performance Restricted Stock Unit Agreement under the Liberty Oilfield Services Inc. Long Term Incentive Plan (6)† 
+10.26 
+Form of Change in Control Agreement (7)† 
+10.27 
+Form of Indemnification Agreement between the Company and each of its Directors and Executive Officers (8) 
+21.1 
+List of subsidiaries of Liberty Oilfield Services Inc. * 
+23.1 
+Consent of Deloitte & Touche LLP * 
+31.1 
+Certification of Chief Executive Officer pursuant to Rule 13a-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 * 
+31.2 
+Certification of Chief Financial Officer pursuant to 13a-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 * 
+32.1 
+Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 ** 
+47 
+32.2 
+Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 ** 
+95 
+Mine Safety Disclosure * 
+101.INS XBRL Instance Document * 
+101.SCH XBRL Taxonomy Extension Schema Document * 
+101.CAL XBRL Taxonomy Extension Calculation Linkbase Document * 
+101.DEF XBRL Taxonomy Extension Definition Linkbase Document * 
+101.LAB XBRL Taxonomy Extension Label Linkbase Document * 
+101.PRE XBRL Taxonomy Extension Presentation Linkbase Document * 
+104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)* 
+(1) Incorporated by reference to the exhibits to the registrant’s Registration Statement on Form S-1, as amended (SEC File 333-216050). 
+(2) Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on January 18, 2018. 
+(3) Incorporated by reference to the exhibits to the registrant’s Amendment No. 1 to the Current Report on Form 8-K/A, filed on January 22, 2018. 
+(4) Incorporated by reference to the exhibits to the registrant’s Annual Report on Form 10-K, filed on March 23, 2018. 
+(5) Incorporated by reference to the exhibits to the registrant’s Quarterly Report on Form 10-Q, filed on May 10, 2018. 
+(6) Incorporated by reference to the exhibits to the registrant’s Quarterly Report on Form 10-Q, filed on May 3, 2019. 
+(7) Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on August 30, 2019. 
+(8) Incorporated by reference to the exhibits to the registrant’s Annual Report on Form 10-K, filed on February 27, 2020. 
+(9) Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on June 3, 2020. 
+(10) Incorporated by reference to the exhibits to the registrant’s Quarterly Report on Form 10-Q, filed on October 30, 2020. 
+(11) Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on September 1, 2020. 
+(12) Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on January 4, 2021. 
+(13) Incorporated by reference to the exhibits to the registrant’s Annual Report on Form 10-K, filed on February 24, 2021. 
+(14) Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on June 10, 2021. 
+Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on January 4, 2021. 
+(15) Incorporated by reference to the exhibits to the registrant’s Quarterly Report on Form 10-Q, filed on October 28, 2021. 
+* Filed herewith. 
+** Furnished herewith. 
+† Denotes a management contract or compensatory plan or arrangement. 
+48 
+SIGNATURES 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+LIBERTY OILFIELD SERVICES INC. 
+/s/ Christopher A. Wright 
+Date: February 22, 2022 By: 
+Christopher A. Wright 
+Chief Executive Officer 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+Signature Title Date 
+/s/ Christopher A. Wright 
+Chief Executive Officer and Director 
+(Principal Executive Officer) 
+February 22, 2022 
+Christopher A. Wright 
+/s/ Michael Stock 
+Chief Financial Officer 
+(Principal Financial Officer) 
+February 22, 2022 
+Michael Stock 
+/s/ Ryan T. Gosney Chief Accounting Officer February 22, 2022 
+Ryan T. Gosney (Principal Accounting Officer) 
+/s/ Simon Ayat Director February 22, 2022 
+Simon Ayat 
+/s/ Ken Babcock Director February 22, 2022 
+Ken Babcock 
+/s/ Peter A. Dea Director February 22, 2022 
+Peter A. Dea 
+/s/ William F. Kimble Director February 22, 2022 
+William F. Kimble 
+/s/ James R. McDonald Director February 22, 2022 
+James R. McDonald 
+/s/ Gale A. Norton Director February 22, 2022 
+Gale A. Norton 
+/s/ Audrey Robertson Director February 22, 2022 
+Audrey Robertson 
+/s/ Cary D. Steinbeck Director February 22, 2022 
+Cary D. Steinbeck 
+49 
+Index to Financial Statements 
+Liberty Oilfield Services Inc. 
+Management’s Report on Internal Control Over Financial Reporting 
+F-1 
+Reports of Independent Registered Public Accounting Firm (PCAOB ID No. 34 ) 
+F- 2 
+Consolidated Balance Sheets as of December 31, 202 1 and 20 20 
+F- 5 
+Consolidated Statements of Operations for the Years Ended December 31, 202 1 , 20 20 , and 20 19 
+F- 6 
+Consolidated Statements of Changes in Equity for the Years Ended December 31, 202 1 and 20 20 
+F- 8 
+Consolidated Statements of Cash Flows for the Years Ended December 31, 202 1 , 20 20 , and 20 19 
+F- 9 
+Notes to Consolidated Financial Statements 
+F- 10 
+50 
+MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING 
+The management of Liberty Oilfield Services Inc. is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act. 
+Internal control over financial reporting, no matter how well designed, has inherent limitations. Therefore, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements. Further, because of changes in conditions, effectiveness of internal controls over financial reporting may vary over time. 
+Under the supervision of, and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2021 based on the framework and criteria established in Internal Control-Integrated Framework (2013) , issued by the Committee of Sponsoring Organizations of the Treadway Commission. 
+Based on this evaluation, management concluded that, as of December 31, 2021, our internal control over financial reporting was effective. Management’s evaluation of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of the entity acquired in the PropX Acquisition, as defined herein, on October 26, 2021. The acquired business’ financial statements constitute 9% and 6% of net and total assets as of December 31, 2021. 
+The effectiveness of Liberty Oilfield Services Inc. ’ s internal control over financial reporting as of December 31, 2021 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report that is included herein. 
+F-1 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the shareholders and the Board of Directors of Liberty Oilfield Services Inc. 
+Opinion on the Financial Statements 
+We have audited the accompanying consolidated balance sheets of Liberty Oilfield Services Inc. and subsidiaries (the “Company”) as of December 31, 2021 and 2020, the related consolidated statements of operations, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America. 
+We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company ’ s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 2022, expressed an unqualified opinion on the Company ’ s internal control over financial reporting. 
+Basis for Opinion 
+These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company ’ s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. 
+Critical Audit Matter 
+The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. 
+Income Taxes — Tax Receivable Agreements — Refer to Note 12 to the financial statements 
+Critical Audit Matter Description 
+The amounts payable, as well as the timing of such payments, under the tax receivable agreements (“TRA”) are dependent upon significant future events and assumptions, including among others: (i) the amount of the redeeming unit holder’s tax basis in its Liberty Oilfield Services New HoldCo LLC class B units at the time of the relevant redemption, (ii) the characterization of the tax basis step-up, (iii) the depreciation and amortization periods that apply to the increase in tax basis (iv), the amount and timing of taxable income the Company generates in future periods until the TRA payable is settled, and (v) the portion of the Company’s payments under the TRA that constitute imputed interest or give rise to depreciable or amortizable tax basis. 
+During the year ended December 31, 2021, exchanges of Liberty Oilfield Services New HoldCo LLC class B units and shares of Class B Common Stock resulted in an increase of $58.5 million in amounts payable pursuant to tax receivable 
+F-2 
+agreements (“TRA payable”), and a net increase of $68.8 million in deferred tax assets, all of which are subject to the valuation allowance and remeasurement of TRA liability. At December 31, 2021, the Company's TRA payable was $37.6 million, all of which is presented as a component of long-term liabilities. 
+We identified the computation of adjustments to the TRA payable as a critical audit matter because of the multiple owners and complex calculations required to arrive at the correct tax basis upon which to calculate the corresponding TRA payable adjustment. This involved complexity in applying relevant tax law and an increased extent of effort, including the need to involve income tax specialists, when performing audit procedures to evaluate the reasonableness of management’s calculation of tax basis, iterative impact of the computation of adjustments to the TRA payable, and TRA payable as of year-end. 
+How the Critical Audit Matter Was Addressed in the Audit 
+Our audit procedures related to the computation of adjustments to the TRA payable included the following, among others: 
+• We tested the effectiveness of controls over the computation of adjustments to the TRA payable, including management’s calculation of the step-up in tax basis that serves as the basis for the computation of adjustments to the TRA payable. 
+• With the assistance of our income tax specialists, we read the individual TRAs and compared the terms in the agreements for consistency with the mathematical model used by management to calculate the adjustments to the TRA payable. 
+• With the assistance of our income tax specialists, we evaluated management’s computation of adjustments to the TRA payable, and the TRA payable as of year-end that is payable over the contractual period by comparing to our independently recalculated value, taking into account the various class B unit exchanges for Class B Common Stock occurring during the year as well as the adjustments in the TRA payable for each exchange. 
+/s/ DELOITTE & TOUCHE LLP 
+Denver, Colorado 
+February 22, 2022 
+We have served as the Company ’ s auditor since 2016. 
+F-3 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the shareholders and the Board of Directors of Liberty Oilfield Services Inc. 
+Opinion on Internal Control over Financial Reporting 
+We have audited the internal control over financial reporting of Liberty Oilfield Services Inc. and subsidiaries (the “Company”) as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO. 
+We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2021, of the Company and our report dated February 22, 2022, expressed an unqualified opinion on those financial statements. 
+As described in Management’s Report on Internal Control Over Financial Reporting, management excluded from its assessment the internal control over financial reporting at Proppant Express Solutions, LLC (“PropX”), which was acquired on October 26, 2021 and whose financial statements constitute 9% and 6% of net and total assets, respectively of the consolidated financial statement amounts as of and for the year ended December 31, 2021. Accordingly, our audit did not include the internal control over financial reporting at PropX. 
+Basis for Opinion 
+The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+Definition and Limitations of Internal Control over Financial Reporting 
+A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+/s/ DELOITTE & TOUCHE LLP 
+Denver, Colorado 
+February 22, 2022 
+F-4 
+LIBERTY OILFIELD SERVICES INC. 
+Consolidated Balance Sheets 
+As of December 31, 2021 and 2020 
+(Dollars in thousands, except share data) 
+2021 2020 
+Assets 
+Current assets: 
+Cash and cash equivalents $ 19,998 $ 68,978 
+Accounts receivable—trade, net of allowances for credit losses of $ 884 and $ 773 , respectively 
+298,531 244,433 
+Unbilled revenue 108,923 69,516 
+Inventories 134,593 118,568 
+Prepaid and other current assets (including receivables from related parties of $ 0 and $ 24,708 , respectively) 
+68,332 65,638 
+Total current assets 630,377 567,133 
+Property and equipment, net 1,199,287 1,120,950 
+Finance lease right-of-use assets 18,201 38,733 
+Operating lease right-of-use assets 109,899 75,878 
+Other assets 82,289 81,888 
+Deferred tax asset 607 5,360 
+Total assets $ 2,040,660 $ 1,889,942 
+Liabilities and Equity 
+Current liabilities: 
+Accounts payable (including payables to related parties of $ 2,732 and $ 0 , respectively) 
+$ 288,801 $ 193,338 
+Accrued liabilities (including amounts due to related parties of $ 1,142 and $ 0 , respectively) 
+235,115 118,383 
+Deferred revenue 4,552 — 
+Current portion of long-term debt, net of discount of $ 743 and $ 1,386 , respectively 
+1,007 364 
+Current portion of finance lease liabilities 8,743 20,580 
+Current portion of operating lease liabilities 31,029 23,481 
+Total current liabilities 569,247 356,146 
+Long-term debt, net of discount of $ 1,270 and $ 1,054 , respectively, less current portion 
+121,445 105,411 
+Deferred tax liability 563 — 
+Payable pursuant to tax receivable agreements, including payables to related parties of $ 0 and $ 27,173 , respectively 
+37,555 56,594 
+Noncurrent portion of finance lease liabilities 4,445 11,318 
+Noncurrent portion of operating lease liabilities 76,966 50,430 
+Total liabilities 810,221 579,899 
+Commitments & contingencies (Note 15) 
+Stockholders’ equity: 
+Preferred Stock, $ 0.01 par value, 10,000 shares authorized and none issued and outstanding 
+— — 
+Common Stock: 
+Class A, $ 0.01 par value, 400,000,000 shares authorized and 183,385,111 issued and outstanding as of December 31, 2021 and 157,952,213 issued and outstanding as of December 31, 2020 
+1,834 1,579 
+Class B, $ 0.01 par value, 400,000,000 shares authorized and 2,632,347 issued and outstanding as of December 31, 2021 and 21,550,282 issued and outstanding as of December 31, 2020 
+26 216 
+Additional paid in capital 1,367,642 1,125,554 
+(Accumulated deficit) retained earnings ( 155,954 ) 23,288 
+Accumulated other comprehensive (loss) ( 306 ) — 
+Total stockholders’ equity 1,213,242 1,150,637 
+Non-controlling interest 17,197 159,406 
+Total equity 1,230,439 1,310,043 
+Total liabilities and equity $ 2,040,660 $ 1,889,942 
+See Notes to Consolidated Financial Statements. 
+F-5 
+LIBERTY OILFIELD SERVICES INC. 
+Consolidated Statements of Operations 
+For the Years Ended December 31, 2021, 2020, and 2019 
+(In thousands, except per share data) 
+2021 2020 2019 
+Revenue: 
+Revenue $ 2,447,140 $ 965,787 $ 1,972,073 
+Revenue—related parties 23,642 — 18,273 
+Total revenue 2,470,782 965,787 1,990,346 
+Operating costs and expenses: 
+Cost of services (exclusive of depreciation, depletion, and amortization shown separately below) 2,249,926 857,981 1,621,180 
+General and administrative 123,406 84,098 97,589 
+Transaction, severance and other costs 15,138 21,061 — 
+Depreciation, depletion, and amortization 262,757 180,084 165,379 
+Loss (gain) on disposal of assets 779 ( 411 ) 2,601 
+Total operating costs and expenses 2,652,006 1,142,813 1,886,749 
+Operating (loss) income ( 181,224 ) ( 177,026 ) 103,597 
+Other (income) and expense: 
+Gain on remeasurement of liability under tax receivable agreement ( 19,039 ) — — 
+Interest income ( 2 ) ( 297 ) ( 983 ) 
+Interest income—related party — ( 263 ) ( 1,821 ) 
+Interest expense 15,605 15,065 17,485 
+Total other (income) expense, net ( 3,436 ) 14,505 14,681 
+Net (loss) income before income taxes ( 177,788 ) ( 191,531 ) 88,916 
+Income tax expense (benefit) 9,216 ( 30,857 ) 14,052 
+Net (loss) income ( 187,004 ) ( 160,674 ) 74,864 
+Less: Net (loss) income attributable to non-controlling interests ( 7,760 ) ( 45,091 ) 35,861 
+Net (loss) income attributable to Liberty Oilfield Services Inc. stockholders $ ( 179,244 ) $ ( 115,583 ) $ 39,003 
+Net (loss) income attributable to Liberty Oilfield Services Inc. stockholders per common share: 
+Basic $ ( 1.03 ) $ ( 1.36 ) $ 0.54 
+Diluted $ ( 1.03 ) $ ( 1.36 ) $ 0.53 
+Weighted average common shares outstanding: 
+Basic 174,019 85,242 72,334 
+Diluted 174,019 85,242 105,256 
+See Notes to Consolidated Financial Statements. 
+F-6 
+LIBERTY OILFIELD SERVICES INC. 
+Consolidated Statements of Comprehensive (Loss) Income 
+For the Years Ended December 31, 2021, 2020, and 2019 
+(In thousands) 
+2021 2020 2019 
+Net (loss) income $ ( 187,004 ) $ ( 160,674 ) $ 74,864 
+Other comprehensive loss 
+Foreign currency translation ( 102 ) — — 
+Comprehensive (loss) income $ ( 187,106 ) $ ( 160,674 ) $ 74,864 
+Comprehensive (loss) income attributable to non-controlling interest ( 7,556 ) ( 45,091 ) 35,861 
+Comprehensive (loss) income attributable to Liberty Oilfield Services, Inc. $ ( 179,550 ) $ ( 115,583 ) $ 39,003 
+See Notes to Consolidated Financial Statements. 
+F-7 
+LIBERTY OILFIELD SERVICES INC. 
+Consolidated Statements of Changes in Equity 
+For the Years Ended December 31, 2021 and 2020 
+(In thousands, except share and per unit data) 
+Shares of Class A Common Stock Shares of Class B Common Stock Class A Common Stock, Par Value Class B Common Stock, Par Value Additional Paid in Capital Retained Earnings Accumulated Other Comprehensive Income Total Stockholders’ equity Non-controlling Interest Total Equity 
+Balance—December 31, 2020 157,952 21,550 $ 1,579 $ 216 $ 1,125,554 $ 23,288 $ — $ 1,150,637 $ 159,406 $ 1,310,043 
+Exchange of Class B Common Stock for Class A Common Stock 21,359 ( 21,359 ) 214 ( 214 ) 153,641 — — 153,641 ( 153,641 ) — 
+Offering Costs — — — — ( 1,247 ) — — ( 1,247 ) ( 75 ) ( 1,322 ) 
+Issuance of Class A and Class B Common Stock for the PropX Acquisition 3,406 2,441 34 24 88,979 — — 89,037 2,052 91,089 
+Impact of ownership changes from issuance of Class A and Class B Common Stock — — — — ( 15,325 ) — — ( 15,325 ) 15,325 — 
+Other distributions and advance payments to non-controlling interest unitholders — — — — — — — — 1,372 1,372 
+Stock based compensation expense — — — — 19,122 — — 19,122 824 19,946 
+Vesting of restricted stock units 668 — 7 — ( 3,082 ) — — ( 3,075 ) ( 510 ) ( 3,585 ) 
+Restricted stock and RSU forfeitures — — — — — 2 — 2 — 2 
+Currency translation adjustment — — — — — — ( 306 ) ( 306 ) 204 ( 102 ) 
+Net loss — — — — — ( 179,244 ) — ( 179,244 ) ( 7,760 ) ( 187,004 ) 
+Balance—December 31, 2021 183,385 2,632 $ 1,834 $ 26 $ 1,367,642 $ ( 155,954 ) $ ( 306 ) $ 1,213,242 $ 17,197 $ 1,230,439 
+Shares of Class A Common Stock Shares of Class B Common Stock Class A Common Stock, Par Value Class B Common Stock, Par Value Additional Paid in Capital Retained Earnings Accumulated Other Comprehensive Income Total Stockholders’ equity Non-controlling Interest Total Equity 
+Balance - December 31, 2019 81,885 30,639 $ 819 $ 307 $ 410,596 $ 143,105 $ — $ 554,827 $ 226,665 $ 781,492 
+Exchange of Class B Common Stock for Class A Common Stock 9,089 ( 9,089 ) 91 ( 91 ) 59,474 — — 59,474 ( 59,474 ) — 
+Effect of exchange on deferred tax asset, net of liability under tax receivable agreements — — — — 2,430 — 2,430 — 2,430 
+Issuance of Class A Common Stock, net of issuance costs 66,326 — 663 — 599,618 — — 600,281 81,900 682,181 
+Impact of changes in ownership from the issuance of Class A Common Stock — — — — 46,400 — — 46,400 ( 46,400 ) — 
+Deferred tax impact of ownership changes from exchanges and repurchases — — — — ( 6,337 ) — — ( 6,337 ) — ( 6,337 ) 
+$ 0.05 /share of Class A Common Stock dividend 
+— — — — — ( 4,244 ) — ( 4,244 ) — ( 4,244 ) 
+$ 0.05 /unit distributions to non-controlling unitholders 
+— — — — — — — — ( 1,532 ) ( 1,532 ) 
+Other distributions and advance payments to non-controlling interest unitholders — — — — ( 1 ) — — ( 1 ) 569 568 
+Stock based compensation expense — — — 12,976 — 12,976 4,163 17,139 
+Vesting of restricted stock units 657 — 7 — 407 — — 414 ( 1,402 ) ( 988 ) 
+Restricted stock and RSU Forfeitures ( 5 ) — ( 1 ) — ( 9 ) 10 — — 8 8 
+Net loss — — — — — ( 115,583 ) — ( 115,583 ) ( 45,091 ) ( 160,674 ) 
+Balance - December 31, 2020 157,952 21,550 $ 1,579 $ 216 $ 1,125,554 $ 23,288 $ — $ 1,150,637 $ 159,406 $ 1,310,043 
+See Notes to Consolidated Financial Statements. 
+F-8 
+LIBERTY OILFIELD SERVICES INC. 
+Consolidated Statements of Cash Flows 
+For the Years Ended December 31, 2021, 2020, and 2019 
+(Dollars in thousands) 
+2021 2020 2019 
+Cash flows from operating activities: 
+Net (loss) income $ ( 187,004 ) $ ( 160,674 ) $ 74,864 
+Adjustments to reconcile net income to net cash provided by operating activities: 
+Depreciation, depletion, and amortization 262,757 180,084 165,379 
+Loss (gain) on disposal of assets 779 ( 411 ) 2,601 
+(Gain) loss on tax receivable agreements ( 19,039 ) 543 ( 122 ) 
+Amortization of debt issuance costs 2,037 2,232 2,205 
+Inventory write-down — 1,087 1,953 
+Non-cash lease expense 3,823 3,668 3,192 
+Stock based compensation expense 19,946 17,139 13,592 
+Deferred income tax expense (benefit) 5,079 ( 25,546 ) 23,408 
+Provision for credit losses 745 4,877 1,053 
+Changes in operating assets and liabilities: 
+Accounts receivable and unbilled revenue ( 90,142 ) 53,057 ( 11,512 ) 
+Accounts receivable and unbilled revenue—related party — 9,629 5,510 
+Inventories ( 24,612 ) 2,137 ( 30,476 ) 
+Other assets ( 30,955 ) 13,780 ( 6,464 ) 
+Prepaid and other current assets—related party 24,708 — — 
+Deferred revenue 3,452 — — 
+Accounts payable and accrued liabilities 160,584 ( 15,282 ) 22,386 
+Accounts payable and accrued liabilities—related party 3,874 — ( 1,000 ) 
+Payment of operating lease liability ( 565 ) ( 895 ) ( 5,469 ) 
+Net cash provided by operating activities 135,467 85,425 261,100 
+Cash flows from investing activities: 
+Purchases of property and equipment and construction in-progress ( 198,794 ) ( 103,637 ) ( 195,173 ) 
+Investment in sand logistics ( 13,106 ) — — 
+Proceeds from sales of assets 25,406 3,368 826 
+Net cash used in investing activities ( 186,494 ) ( 100,269 ) ( 194,347 ) 
+Cash flows from financing activities: 
+Repayments of borrowings on term loan ( 1,750 ) ( 1,750 ) ( 1,750 ) 
+Proceeds from borrowings on line-of-credit 274,000 — — 
+Repayments of borrowings on line-of-credit ( 256,000 ) — — 
+Payments on finance lease obligations ( 7,363 ) ( 11,663 ) ( 12,143 ) 
+Class A Common Stock dividends and dividend equivalents upon RSU vesting ( 168 ) ( 4,431 ) ( 14,776 ) 
+Per unit distributions to non-controlling interest unitholders — ( 1,532 ) ( 7,747 ) 
+Other distributions and advance payments to non-controlling interest unitholders 1,372 ( 6,800 ) ( 6 ) 
+Tax withholding on restricted stock units ( 3,585 ) ( 988 ) ( 1,039 ) 
+Share repurchases — — ( 18,398 ) 
+Payments of debt issuance costs ( 3,120 ) ( 63 ) — 
+Payment of equity issuance costs ( 1,330 ) ( 1,641 ) ( 1,516 ) 
+Net cash provided by (used in) financing activities 2,056 ( 28,868 ) ( 57,375 ) 
+Net (decrease) increase in cash and cash equivalents ( 48,971 ) ( 43,712 ) 9,378 
+Translation effect on cash ( 9 ) — — 
+Cash and cash equivalents—beginning of period 68,978 112,690 103,312 
+Cash and cash equivalents—end of period $ 19,998 $ 68,978 $ 112,690 
+Supplemental disclosure of cash flow information: 
+Net cash (received) paid for income taxes $ ( 9,481 ) $ ( 9,653 ) $ 1,042 
+Cash paid for interest $ 13,268 $ 11,218 $ 12,642 
+Non-cash investing and financing activities: 
+Capital expenditures included in accounts payable and accrued liabilities $ 57,475 $ 10,920 $ 32,143 
+Equity issued in exchange for assets and liabilities $ 91,089 $ 683,822 $ — 
+See Notes to Consolidated Financial Statements. 
+F-9 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated Financial Statements 
+Note 1— Organization and Basis of Presentation 
+Organization 
+Liberty Oilfield Services Inc. (the “Company”) was incorporated as a Delaware corporation on December 21, 2016, to become a holding corporation for Liberty Oilfield Services New HoldCo LLC (“Liberty LLC”) and its subsidiaries upon completion of a corporate reorganization (the “Corporate Reorganization”) and planned initial public offering of the Company (“IPO”). The Company has no material assets other than its ownership of units in Liberty LLC (“Liberty LLC Units”). 
+The Company, together with its subsidiaries, is a multi-basin provider of hydraulic fracturing services and goods, with a focus on deploying the latest technologies in the technically demanding oil and gas reservoirs in which it operates, principally in North Dakota, Colorado, Louisiana, Oklahoma, New Mexico, Wyoming, Texas and the provinces of Alberta and British Columbia, Canada. 
+Basis of Presentation 
+The accompanying consolidated financial statements were prepared using generally accepted accounting principles in the United States of America (“GAAP”) and the instructions to Form 10-K, Regulation S-X and the rules and regulations of the Securities and Exchange Commission. 
+The accompanying consolidated financial statements and related notes present the consolidated financial position of the Company, the results of operations, cash flows, and equity of the Company as of and for the years ended December 31, 2021, 2020 and 2019. 
+The consolidated financial statements include the amounts of the Company and all majority owned subsidiaries where the Company has the ability to exercise control. All intercompany amounts have been eliminated in the presentation of the consolidated financial statements of the Company. 
+The Company’s operations are organized into a single reportable segment, which consists of hydraulic fracturing and related goods and services. 
+Note 2— Significant Accounting Policies 
+Business Combinations 
+Business combinations are accounted for using the acquisition method of accounting in accordance with the Accounting Standard Codification (“ASC”) Topic 805 - Business Combinations, as amended by Accounting Standards Update (“ASU”) 2017-01, Business Combinations (Topic 805), Clarifying the Definition of a Business. The purchase price is allocated to the assets acquired and liabilities assumed based on their estimated fair values. Fair value of the acquired assets and liabilities is measured in accordance with the guidance of ASC 850, Fair Value Measurements, using discounted cash flows and other applicable valuation techniques. Any acquisition related costs incurred by the Company are expensed as incurred. Any excess purchase price over the fair value of the net identifiable assets acquired is recorded as goodwill if the definition of a business is met. Operating results of an acquired business are included in our results of operations from the date of acquisition. Refer to Note 3—Acquisitions. 
+Use of Estimates 
+The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 
+The consolidated financial statements include certain amounts that are based on management’s best estimates and judgments. The most significant estimates relate to the fair value of assets acquired and liabilities assumed, collectability of accounts receivable and estimates of allowance for doubtful accounts, the useful lives and salvage values of long-lived assets, future cash flows associated with long-lived assets, net realizable value of inventory, and equity unit valuation. These estimates may be adjusted as more current information becomes available. 
+Cash and Cash Equivalents 
+The Company considers all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. The Company continually monitors its positions with, and the credit quality of, the financial institutions with 
+F-10 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated Financial Statements 
+which it has banking relationships. As of the balance sheet date, and periodically throughout the year, the Company has maintained balances in various operating accounts in excess of federally insured limits. 
+Accounts Receivable 
+On January 1, 2020, the Company adopted ASU 2016-13, Financial Instruments-Credit Losses (Topic 326) : Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”) using the modified-retrospective approach, which allows for a cumulative-effect adjustment to the consolidated balance sheet as of the beginning of the first reporting period in which the guidance is effective. Periods prior to the adoption date that are presented for comparative purposes are not adjusted. 
+The Company applies historic loss factors to its receivable portfolio segments that were not expected to be further impacted by current economic developments, and additional economic conditions factor to portfolio segments anticipated to experience greater losses in the current economic environment. Additionally, the Company continuously evaluates customers based on risk characteristics, such as historical losses and current economic conditions. Due to the cyclical nature of the oil and gas industry, the Company often evaluates its customers’ estimated losses on a case-by-case basis. While there was no impact to the financial statements as a result of adoption of ASU 2016-13, as a result of two customers inability to pay, during the year ended December 31, 2021 the Company recorded a provision for credit losses of $ 0.7 million. During the year ended December 31, 2020 the Company recorded a provision for credit losses of $ 4.9 million related to the deteriorating economic conditions for the oil and gas industry brought on by the COVID-19 pandemic. Provisions for credit losses are included in general and administrative expenses in the accompanying consolidated statement of operations, in accordance with the new standard. Refer to “Credit Risk” within Note 9—Fair Value Measurements and Financial Instruments for additional disclosures required under ASU 2016-13. 
+Inventories 
+Inventories consist of raw materials used in the hydraulic fracturing process, such as proppants, chemicals, and field service equipment maintenance parts and other and are stated at the lower of cost, determined using the weighted average cost method, or net realizable value. Inventories are charged to cost of services as used when providing hydraulic fracturing services. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable cost of completion, disposal, and transportation. 
+Property and Equipment 
+Property and equipment are stated at cost. Depreciation and amortization expense is recognized on property and equipment, excluding land, utilizing the straight-line method over the estimated useful lives, ranging from two to 30 years. The Company estimates salvage values that it does not depreciate. 
+Construction in-progress, a component of property and equipment, represents long-lived assets not yet in service or being developed by the Company. These assets are not subject to depreciation until they are completed and ready for their intended use, at which point the Company reclassifies them to field services equipment or vehicles, as appropriate. 
+The Company assesses its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is assessed using undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets. The Company determined the lowest level of identifiable cash flows to be at the asset group, which is the aggregate of the Company’s hydraulic fracturing fleets that are in service. A long-lived asset is not recoverable if its carrying amount exceeds the sum of estimated undiscounted cash flows expected to result from the use and eventual disposition. When alternative courses of action to recover the carrying amount of the asset group are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the asset is not recoverable, an impairment loss is recognized in an amount by which its carrying amount exceeds its estimated fair value, such that its carrying amount is adjusted to its estimated fair value, with an offsetting charge to impairment expense. 
+The Company measures the fair value of its property and equipment using the discounted cash flow method. The expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments of projected revenue growth, fleet count, utilization, gross margin rates, selling, general and administrative rates, working capital fluctuations, capital expenditures, discount rates and terminal growth rates. 
+During the year ended December 31, 2020, as a result of negative market indicators including the COVID-19 pandemic, the increased supply of low-priced oil, and customer cancellations, the Company concluded these triggering events could indicate possible impairment of property and equipment. The Company performed a quantitative and qualitative impairment analysis and determined that no impairment had occurred as of June 30, 2020. As of December 31, 2021 and 2020, the Company concluded that no additional triggering events had occurred, and no impairment was recognized during the years ended December 31, 2021 and 2020. 
+F-11 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated Financial Statements 
+During 2019, the Company did not test its long-lived assets for recoverability as there were no triggering events. No impairment was recognized during the years ended December 31, 2019. 
+Major Maintenance Activities 
+The Company incurs maintenance costs on its major equipment. The determination of whether an expenditure should be capitalized or expensed requires management judgment in the application of how the costs incurred benefit future periods, relative to the Company’s capitalization policy. Costs that either establish or increase the efficiency, productivity, functionality or life of a fixed asset are capitalized and depreciated over the remaining useful life of the asset. 
+Leases 
+On January 1, 2019, the Company adopted Accounting Standards Update (“ASU”) No. 2016-02, Leases (Accounting Standard Codification (“ASC”) Topic 842), as amended by other ASUs issued since February 2016 (“ASU 2016-02” or “ASC Topic 842”), using the modified retrospective transition method applied at the effective date of the standard. By electing this optional transition method, information prior to January 1, 2019 has not been restated and continues to be reported under the accounting standards in effect for the period (ASC Topic 840). 
+In accordance with ASC Topic 842, the Company determines if an arrangement is a lease at inception and evaluates identified leases for operating or finance lease treatment. Operating or finance lease right-of-use assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. The Company uses the rate implicit in the lease, when available, or an estimated fully collateralized incremental borrowing rate corresponding with the lease term and the information available at the commencement date in determining the present value of lease payments. Lease terms may include options to renew, however, the Company typically cannot determine its intent to renew a lease with reasonable certainty at inception. 
+Additionally, the Company is a lessor in several operating leases in which the lease equipment is carried at amortized cost. Depreciation expense is recorded on a straight-line basis over its useful life to the estimated residual value. The lessee may not purchase the leased equipment and must return such equipment by the lease's scheduled maturity date. 
+Deferred Financing Costs 
+Costs associated with obtaining debt financing are deferred and amortized to interest expense using the effective interest method. In accordance with ASU No. 2015-03 and 2015-15, for all periods the Company has reflected deferred financing costs related to term loan debt as a direct deduction from the carrying amount, and costs associated with line-of-credit arrangements as other assets. 
+Income Taxes 
+Deferred income taxes are computed using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Deferred tax assets and liabilities are calculated using the enacted tax rates in effect for the year in which the deferred tax asset or liability is expected to reverse. The Company classifies all deferred tax assets and liabilities as non-current. The Company records Global Intangible Low Tax Income as a current period expense. 
+The Company evaluates its deferred tax assets quarterly and considers both positive and negative evidence in applying the guidance of ASC 740 Income Taxes (“ASC 740”) related to the realizability of its deferred tax assets. On June 30, 2021, in accordance with ASC 740, the objective negative evidence of entering into a three year cumulative pre-tax book loss position prevented the consideration of the Company’s subjective positive evidence of expected future profitability in evaluation the realizability of deferred tax assets. As a result, the Company recorded a valuation allowance against U.S. net deferred tax assets. 
+The Company recognizes the financial statement effects of a tax position when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. Previously recognized tax positions are reversed in the first period in which it is no longer more-likely-than-not that the tax position would be sustained upon examination. Income tax related interest and penalties, if applicable, are recorded as a component of the provision for income tax expense. 
+F-12 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated Financial Statements 
+Tax Receivable Agreements 
+In connection with the IPO, on January 17, 2018, the Company entered into two Tax Receivable Agreements (the “TRAs”) with the R/C Energy IV Direct Partnership, L.P. and certain legacy owners that continued to own Liberty LLC Units (each such person and any permitted transferee, a “Tax Receivable Agreement Holder” and together, the “Tax Receivable Agreement Holders”). The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that the Company actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result, as applicable to each Tax Receivable Agreement Holder, of (i) certain increases in tax basis that occur as a result of the Company’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such Tax Receivable Agreement Holder’s Liberty LLC Units in connection with the IPO or pursuant to the exercise of the right (the “Redemption Right”) or the Company’s right (the “Call Right”), (ii) any net operating losses available to the Company as a result of the Corporate Reorganization, and (iii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRAs. 
+With respect to obligations the Company expects to incur under the TRAs (except in cases where the Company elects to terminate the TRAs early, the TRAs are terminated early due to certain mergers, asset sales, or other changes of control or the Company has available cash but fails to make payments when due), generally the Company may elect to defer payments due under the TRAs if the Company does not have available cash to satisfy its payment obligations under the TRAs or if its contractual obligations limit its ability to make such payments. Any such deferred payments under the TRAs generally will accrue interest. In certain cases, payments under the TRAs may be accelerated and/or significantly exceed the actual benefits, if any, the Company realizes in respect of the tax attributes subject to the TRAs. The Company accounts for amounts payable under the TRAs in accordance with ASC Topic 450, Contingencies . 
+If the Company experiences a change of control (as defined under the TRAs) or the TRAs otherwise terminate early, the Company’s obligations under the TRAs could have a substantial negative impact on its liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. 
+Share Repurchases 
+The Company accounts for the purchase price of repurchased Class A Common Stock in excess of par value ($ 0.01 per share of Class A Common Stock) as a reduction of additional paid-in capital, and will continue to do so until additional paid-in capital is reduced to zero. Thereafter, any excess purchase price will be recorded as an increase to accumulated deficit. 
+Revenue Recognition 
+Under ASC Topic 606- Revenue from Contracts with Customers , revenue recognition is based on the transfer of control, or the customer’s ability to benefit from the services and products in an amount that reflects the consideration expected to be received in exchange for those services and products. In recognizing revenue for services and products, the transaction price is determined from sales orders or contracts with customers. Revenue is recognized at the completion of each fracturing stage, and in most cases the price at the end of each stage is fixed, however, in limited circumstances contracts may contain variable consideration. 
+Variable consideration typically may relate to discounts, price concessions and incentives. The Company estimates variable consideration based on the amount of consideration we expect to receive. The Company accrues revenue on an ongoing basis to reflect updated information for variable consideration as performance obligations are met. 
+The Company also assesses customers’ ability and intention to pay, which is based on a variety of factors including historical payment experience and financial condition. Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30 to 45 days. 
+In connection with the adoption of ASC Topic 842, the Company determined that certain of its service revenue contracts contain a lease component. The Company elected to adopt a practical expedient available to lessors, which allows the Company to combine the lease and non-lease components and account for the combined component in accordance with the accounting treatment for the predominant component. Therefore, the Company combines the lease and service component for certain of the Company’s service contracts and continues to account for the combined component under ASC Topic 606, Revenue from Contracts with Customers. 
+Deferred Revenue 
+From time to time, the Company may require partial payment in advance from new customers to secure credit or from existing customers in order to secure additional hydraulic fracturing services. Initially, such payments are recorded in the accompanying consolidated financial statements as deferred revenue, and upon performance of the agreed services, the 
+F-13 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated Financial Statements 
+Company recognizes revenue consistent with its revenue recognition policy described above. As of December 31, 2021 and 2020, the Company had $ 4.6 million and $ 0.0 million recorded as deferred revenue, respectively. 
+Transaction, Severance and Other Costs 
+During 2021, the Company incurred transaction and integration related costs in connection with the OneStim Acquisition (as defined below) and PropX Acquisition (as defined below). Such costs include investment banking, legal, accounting and other professional services provided in connection with closing the transaction and are expensed as incurred . 
+The Company incurred transaction costs in 2020 related to the OneStim Acquisition and severance and other costs related to the reduction in workforce in April 2020 and the commencement of furlough schedules for remaining employees in May 2020. Payments made to employees leaving the Company, as well as benefits paid to employees while on furlough are recorded to transaction, severance and other costs in the accompanying consolidated statements of operations for the year ended December 31, 2020. 
+Foreign Currency Translation 
+The Company records foreign currency translation adjustments from the process of translating the functional currency of the financial statements of its foreign subsidiary into the U.S. dollar reporting currency. The Canadian dollar is the functional currency of the Company’s foreign subsidiary as it is the primary currency within the economic environment in which the subsidiary operates. Assets and liabilities of the subsidiary’s operations are translated into U.S. dollars at the rate of exchange in effect on the balance sheet date and income and expenses are translated at the average exchange rate in effect during the reporting period. Adjustments resulting from the translation of the subsidiary’s financial statements are reported in other comprehensive income. 
+Recently Adopted Accounting Standards 
+Simplification of Accounting for Income Taxes 
+In December 2019, the FASB issued ASU No. 2019-12, Simplification of Accounting for Income Taxes , which simplifies the accounting for income taxes by providing new guidance to reduce complexity and eliminate certain exceptions to the general approach to the income tax accounting model. The Company adopted this guidance effective January 1, 2021, which did not have a material impact on the accompanying consolidated financial statements. 
+Codification Improvements 
+In October 2020, the FASB issued ASU No. 2020-10, Codification Improvements, which clarifies various topics, including the addition of existing disclosure requirements to the relevant disclosure sections. This update does not change GAAP, and therefore, does not result in a significant change in the Company’s accounting practices. The guidance is effective for fiscal periods beginning after December 15, 2020, as the amendment pertains to disclosure items only. The Company adopted the new rules effective January 1, 2021 and the adoption did not have a material impact on the accompanying consolidated financial statements. 
+Reference Rate Reform 
+In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform, which provides temporary optional guidance to companies impacted by the transition away from the London Interbank Offered Rate (“LIBOR”). The guidance provides certain expedients and exceptions to applying GAAP in order to lessen the potential accounting burden when contracts, hedging relationships, and other transactions that reference LIBOR as a benchmark rate are modified. This guidance is effective upon issuance and expires on December 31, 2022. The Company is currently assessing the impact of the LIBOR transition and this ASU on the Company’s consolidated financial statements. 
+Business Combinations: Accounting for Contract Assets and Contract Liabilities from Contracts with Customers 
+In October 2021, the FASB issued ASU No. 2021-08, Business Combinations: Accounting for Contract Assets and Contract Liabilities from Contracts with Customers, which changes the accounting for the recognition and measurement of contract assets and contract liabilities acquired in a business combination in accordance with ASC 606. The update changes GAAP surrounding the recognition of contract assets and contract liabilities from fair value on the acquisition date to guidance under ASC 606. The guidance is effective for fiscal periods beginning after December 15, 2022. The Company adopted the new rules upon issuance and the adoption did not have a material impact on the accompanying consolidated financial statements. 
+Reclassifications 
+Certain amounts in the prior period financial statements have been reclassified from general and administrative to transaction, severance and other costs in the accompanying consolidated statements of operation to conform to the presentation of the current period financial statements. These reclassifications had no effect on the previously reported net income or loss. 
+F-14 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated Financial Statements 
+Note 3— Acquisitions 
+PropX Acquisition 
+On October 26, 2021, the Company entered into the certain Master Transaction Agreement (the “Transaction Agreement”) with Proppant Express Investments, LLC to acquire the assets and liabilities of Proppant Express Solutions, LLC “PropX”, which provides last-mile proppant delivery solutions, including proppant handling equipment and logistics software across North America. PropX was acquired in exchange for $ 11.9 million in cash and 3,405,526 shares of the Company’s Class A Common Stock, par value $ 0.01 per share (the “Class A Common Stock”) and 2,441,010 shares of the Company’s Class B Common Stock, par value $ 0.01 per share (the “Class B Common Stock”, and together with the Class A Common Stock, the “Common Stock”), for total consideration of $ 103.0 million based on the October 26, 2021 closing price of Class A Common Stock of $ 15.58 . In connection with the issuance of 2,441,010 shares of Class B Common Stock, Liberty LLC also issued 2,441,010 Liberty LLC Units to the Company. The Liberty LLC Units are redeemable for an equivalent number of shares of Class A Common Stock at anytime, at the election of the shareholder. 
+The Company accounted for the PropX Acquisition using the acquisition method of accounting. The aggregate purchase price noted above was allocated to the major categories of assets acquired and liabilities assumed based upon their estimated fair value at the date of the acquisition. The estimated fair values of certain assets and liabilities require significant judgments and estimates. The majority of the measurements of assets acquired and liabilities assumed, are based on inputs that are not observable in the market and thus represent Level 3 inputs. 
+In accordance with ASC Topic 805, an acquirer is allowed a period, referred to as the measurement period, in which to complete its accounting for the transaction. Such measurement period ends at the earliest date that the acquirer a) receives the information necessary or b) determines that it cannot obtain further information, and such period may not exceed one year. As the PropX Acquisition closed on October 26, 2021 the Company is in the process of completing the initial purchase price allocation, particularly as it relates to current assets and current liabilities. 
+The following table summarizes the fair value of the consideration transferred in the PropX Acquisition and the preliminary allocation of the purchase price to the fair value of the assets acquired and liabilities assumed as of October 26, 2021, the date of the closing of the PropX Acquisition: 
+($ in thousands) 
+Total Purchase Consideration: 
+Consideration $ 103,023 
+Cash and cash equivalents $ 53 
+Accounts receivable and unbilled revenue 4,089 
+Inventory 8 
+Prepaid and other current assets 1,722 
+Property and equipment (1) 
+94,137 
+Intangible assets (included in other assets in the accompanying consolidated balance sheet as of December 31, 2021) (2) 
+7,100 
+Total identifiable assets acquired 107,109 
+Accounts payable 2,152 
+Accrued liabilities 1,934 
+Total liabilities assumed 4,086 
+Total purchase consideration $ 103,023 
+(1) Useful lives average of 10 years, see Note 5—Property and Equipment 
+(2) Definite lived intangibles with an amortization period ranging from seven to 10 years 
+Transaction costs, costs associated with issuing additional equity and integration costs were recognized separately from the acquisition of assets and assumptions of liabilities in the PropX Acquisition. Transaction costs consist of legal and professional fees. Integration costs consist of expenses incurred to integrate PropX’s operations, aligning accounting processes and procedures, and integrating its enterprise resource planning system with those of the Company. Merger and integration costs are expensed as incurred, and equity offering costs were recorded as a reduction to additional paid in capital. 
+F-15 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated Financial Statements 
+The Company’s consolidated statements of operations for the year ended December 31, 2021 includes 66 days of PropX operations as the PropX Acquisition closed on October 26, 2021. The Company does not present pro forma financial information for the periods prior to the PropX Acquisition as such information, after elimination of PropX’s historical transactions with the Company, is not materially different than the results presented in the accompanying Consolidated Statements of Operations for years ended December 31, 2021 and 2020. 
+OneStim Acquisition 
+On August 31, 2020 the Company and certain of its subsidiaries entered into the certain Master Transaction Agreement (the “Transaction Agreement”) with Schlumberger Technology Corporation and Schlumberger Canada Limited (collectively “Schlumberger”), pursuant to which the Company acquired certain assets and liabilities of Schlumberger’s OneStim® business, which provides hydraulic fracturing pressure pumping services in onshore United States and Canada (such entire business of Schlumberger “OneStim,” and the portion of OneStim acquired pursuant to the Transaction Agreement the “Transferred Business”) in exchange for 57,377,232 shares of Class A Common Stock and a non-interest bearing demand promissory note (the “Canadian Buyer Note” and such acquisition, the “OneStim Acquisition”). The Canadian Buyer Note was settled for 8,948,902 shares of Class A Common Stock, and a total of 66,326,134 shares of Class A Common Stock were issued in connection with the OneStim Acquisition. Effective December 31, 2020, Schlumberger owned approximately 37.0 % of the Company’s issued and outstanding shares of Common Stock. In connection with the issuance of 66,326,134 shares of Class A Common Stock, Liberty LLC also issued 66,326,134 Liberty LLC Units to the Company. 
+The OneStim Acquisition was completed for total consideration of approximately $ 683.8 million based on the value of the Canadian Buyer Note and the closing price of the Class A Common Stock on December 31, 2020. The Company accounted for the OneStim Acquisition using the acquisition method of accounting. The aggregate purchase price noted above was allocated to the major categories of assets acquired and liabilities assumed based upon their estimated fair value at the date of the acquisition. The estimated fair values of certain assets and liabilities, including accounts receivable, require significant judgments and estimates. The majority of the measurements of assets acquired and liabilities assumed, are based on inputs that are not observable in the market and thus represent Level 3 inputs. 
+In accordance with ASC Topic 805, an acquirer is allowed a period, referred to as the measurement period, in which to complete its accounting for the transaction. Such measurement period ends at the earliest date that the acquirer a) receives the information necessary or b) determines that it cannot obtain further information, and such period may not exceed one year. As the OneStim Acquisition closed on December 31, 2020 the Company completed the purchase price allocation, particularly as it relates to current assets and current liabilities, which were subject to certain minimum working capital contribution requirements under the Transaction Agreement during the year ended December 31, 2021. 
+The following table summarizes the fair value of the consideration transferred in the OneStim Acquisition and the allocation of the purchase price to the fair value of the assets acquired and liabilities assumed (which are included within the accompanying consolidated balance sheet as of December 31, 2020) as of December 31, 2020, the date of the closing of the OneStim Acquisition: 
+($ in thousands) 
+Total Purchase Consideration: 
+Consideration $ 683,822 
+Accounts receivable and unbilled revenue $ 128,602 
+Inventories 33,245 
+Prepaid and other current assets 30,859 
+Property and equipment (1) 
+559,716 
+Intangible assets (included in other assets in the accompanying consolidated balance sheet as of December 31, 2020) (2) 
+54,000 
+Total identifiable assets acquired 806,422 
+Accounts payable 75,522 
+Accrued liabilities 47,078 
+Total liabilities assumed 122,600 
+Total purchase consideration $ 683,822 
+(1) Useful lives ranging from two to greater than 25 years, see Note 5—Property and Equipment 
+(2) Definite lived intangibles with an average amortization period of five years 
+F-16 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated Financial Statements 
+Transaction costs, costs associated with issuing additional equity and integration costs were recognized separately from the acquisition of assets and assumptions of liabilities in the OneStim Acquisition. Transaction costs consist of legal and professional fees and pre-merger notification fees. Equity offering costs consist of expenses incurred related to the Special Meeting of Stockholders, including the costs to prepare the required filings associated with such meeting, held on November 3, 2020. Integration costs consist of expenses incurred to integrate OneStim’s operations, aligning accounting processes and procedures, and integrating its enterprise resource planning system with those of the Company. Merger and integration costs are expensed as incurred, and equity offering costs were recorded as a reduction to additional paid in capital. 
+The following combined pro forma information assumes the OneStim Acquisition occurred on January 1, 2019. The pro forma information presented below is for illustrative purposes only and does not reflect future events that occurred after December 31, 2020 or any operating efficiencies or inefficiencies that may result from the OneStim Acquisition. The information is not necessarily indicative of results that would have been achieved had the Company controlled OneStim during the periods presented. 
+Years ended December 31, 
+(unaudited, in thousands) 2020 2019 
+Revenue $ 2,191,894 $ 5,174,346 
+Net loss ( 1,052,807 ) ( 1,074,735 ) 
+Less: Net loss attributable to non-controlling interests ( 196,020 ) ( 285,178 ) 
+Net loss attributable to Liberty Oilfield Services Inc. stockholders $ ( 856,787 ) $ ( 789,557 ) 
+Net loss attributable to Liberty Oilfield Services Inc. stockholders per common share: 
+Basic $ ( 5.65 ) $ ( 5.69 ) 
+Diluted $ ( 5.65 ) $ ( 5.69 ) 
+Weighted average common shares outstanding: 
+Basic 151,568 138,660 
+Diluted 151,568 138,660 
+The Company’s consolidated statements of operations for the year ended December 31, 2020 does not include any results from OneStim operations as the OneStim Acquisition closed on December 31, 2020. 
+Transaction and integration costs incurred related to both transactions were $ 13.6 million and $ 8.5 million, for the years ended December 31, 2021 and 2020, respectively, and are recorded as a component of transaction, severance and other costs in the accompanying consolidated statements of operations. Equity offering costs totaled $ 1.3 million and $ 1.6 million, for the years ended December 31, 2021 and 2020, respectively, and are recorded as a reduction to additional paid in capital in the accompanying consolidated balance sheets. 
+F-17 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated Financial Statements 
+Note 4— Inventories 
+Inventories consist of the following: 
+December 31, 
+($ in thousands) 2021 2020 
+Proppants $ 23,413 $ 13,658 
+Chemicals 17,996 16,434 
+Maintenance parts 93,184 88,476 
+$ 134,593 $ 118,568 
+The Company did not record any write-down to the inventory carrying value during the year ended December 31, 2021. During the year ended December 31, 2020, the lower of cost or net realizable value analysis resulted in the Company recording a write-down to inventory carrying values of $ 1.1 million, which is included as a component in cost of services in the consolidated statements of operations. 
+Note 5— Property and Equipment 
+Property and equipment consist of the following: 
+Estimated 
+useful lives 
+(in years) December 31, 
+2021 2020 
+($ in thousands) 
+Land N/A $ 33,812 $ 38,346 
+Field services equipment 
+2 - 7 
+1,579,420 1,249,933 
+Vehicles 
+4 - 7 
+61,282 59,741 
+Lease Equipment 10 64,770 — 
+Buildings and facilities 
+5 - 30 
+148,555 156,109 
+Mineral reserves 
+> 25 
+76,823 78,793 
+Office equipment and furniture 
+2 - 7 
+8,218 6,840 
+1,972,880 1,589,762 
+Less accumulated depreciation and amortization ( 863,194 ) ( 622,530 ) 
+1,109,686 967,232 
+Construction in-progress N/A 89,601 153,718 
+$ 1,199,287 $ 1,120,950 
+During the years ended December 31, 2021, 2020, and 2019, the Company recognized depreciation expense of $ 243.0 million, $ 169.9 million, and $ 153.6 million, respectively. Depletion expense for the year ended December 31, 2021 was $ 1.2 million. 
+During the year ended December 31, 2020, as a result of negative market indicators including the COVID-19 pandemic, the increased supply of low-priced oil, and customer cancellations, the Company concluded these triggering events could indicate possible impairment of property and equipment. The Company performed a quantitative and qualitative impairment analysis and determined that no impairment had occurred as of June 30, 2020. As of December 31, 2021, and 2020, the Company concluded that no additional triggering events occurred. Such analysis required management to make estimates and assumptions based on historical data and consideration of future market conditions. Given the uncertainty inherent in any projection, heightened by the possibility of unforeseen additional effects of COVID-19, actual results may differ from the estimates and assumptions used, or conditions may change, which could result in impairment charges in the future. 
+F-18 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated Financial Statements 
+Note 6— Leases 
+Lessee Arrangements 
+The Company has operating and finance leases primarily for vehicles, equipment, railcars, office space, and facilities. The terms and conditions for these leases vary by the type of underlying asset. 
+Certain leases include variable lease payments for items such as property taxes, insurance, maintenance, and other operating expenses associated with leased assets. Payments that vary based on an index or rate are included in the measurement of lease assets and liabilities at the rate as of the commencement date. All other variable lease payments are excluded from the measurement of lease assets and liabilities, and are recognized in the period in which the obligation for those payments is incurred. 
+The components of lease expense for the years ended as of December 31, 2021, and 2020 were as follows: 
+($ in thousands) 2021 2020 
+Finance lease cost: 
+Amortization of right-of-use assets $ 5,490 $ 8,115 
+Interest on lease liabilities 1,598 1,770 
+Operating lease cost 40,365 25,817 
+Variable lease cost 4,183 2,935 
+Short-term lease cost 5,026 — 
+Sublease (income) — ( 113 ) 
+Total lease cost, net $ 56,662 $ 38,524 
+Supplemental cash flow and other information related to leases as of December 31, 2021 and 2020 were as follows: 
+($ in thousands) 2021 2020 
+Cash paid for amounts included in measurement of liabilities: 
+Operating leases $ 37,121 $ 23,612 
+Finance leases 8,598 13,433 
+Right-of-use assets obtained in exchange for new lease liabilities: 
+Operating leases 71,477 29,663 
+Finance leases 1,500 10,921 
+During the years ended December 31, 2021 and 2020, the Company amended certain finance leases, the change in terms of which caused the leases to be reclassified to operating leases. In connection with the amendments, the Company wrote-off finance lease right-of-use assets of $ 16.6 million and $ 22.5 million, respectively, and liabilities of $ 12.8 million and $ 19.0 million, respectively. Additionally, the Company recognized operating lease right-of-use assets of $ 14.3 million and $ 18.6 million and liabilities of $ 10.7 million and $ 15.1 million, respectively. There was no gain or loss recognized as a result of these amendments. 
+Lease terms and discount rates as of December 31, 2021 and 2020 were as follows: 
+December 31, 2021 December 31, 2020 
+Weighted-average remaining lease term: 
+Operating leases 5.2 years 5.9 years 
+Finance leases 1.5 years 1.5 years 
+Weighted-average discount rate: 
+Operating leases 4.2 % 4.8 % 
+Finance leases 8.6 % 5.8 % 
+F-19 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated Financial Statements 
+Future minimum lease commitments as of December 31, 2021 are as follows: 
+($ in thousands) Finance Operating 
+2022 $ 9,464 $ 34,829 
+2023 5,051 24,928 
+2024 — 18,306 
+2025 — 15,975 
+2026 — 8,388 
+Thereafter — 17,833 
+Total lease payments 14,515 120,259 
+Less imputed interest 1,327 12,264 
+Total $ 13,188 $ 107,995 
+The Company’s vehicle leases typically include a residual value guarantee. For the Company’s vehicle leases classified as operating leases, the total residual value guaranteed as of December 31, 2021 is $ 11.6 million; the payment is not probable and therefore has not been included in the measurement of the lease liability and right-of-use asset. For vehicle leases that are classified as finance leases, the Company includes the residual value guarantee, estimated in the lease agreement, in the financing lease liability. 
+Lessor Arrangements 
+The Company leases dry and wet sand containers and conveyor belts to customers through PropX. PropX leases to customers through operating leases, where the lessor for tax purposes is considered to be the owner of the equipment during the term of the lease. The lease agreements do not include options for the lessee to purchase the underlying asset at the end of the lease term for either a stated fixed price or fair market value. However, some of the leases contain a termination clause in which the customer can cancel the contract. The leases can be subject to variable lease payments if the customer requests more units than what is agreed upon in the lease. The Company does not record any lease assets or liabilities related to these variable items. 
+The carrying amount of equipment leased to others, included in property, plant and equipment, under operating leases as of December 31, 2021 and 2020 were as follows: 
+($ in thousands) December 31, 2021 December 31, 2020 
+Equipment leased to others - at original cost $ 64,770 $ — 
+Less: Accumulated depreciation ( 1,377 ) — 
+Equipment leased to others - net $ 63,393 $ — 
+Future payments receivable for operating leases commenced and committed but not delivered as of December 31, 2021 are as follows: 
+($ in thousands) 
+2022 $ 10,209 
+2023 10,099 
+2024 4,197 
+2025 800 
+2026 — 
+Thereafter — 
+Total $ 25,305 
+Revenues from operating leases for the years ended December 31, 2021 and 2020 were $ 3.2 million and $ — million , respectively. The Company had no lease revenue and no lease receivables with related parties for the year ended December 31, 2021 . 
+F-20 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated Financial Statements 
+Note 7— Accrued Liabilities 
+Accrued liabilities consist of the following: 
+($ in thousands) December 31, 2021 December 31, 2020 
+Accrued vendor invoices $ 109,903 $ 61,210 
+Operations accruals 64,707 28,932 
+Accrued benefits and other 60,505 28,241 
+$ 235,115 $ 118,383 
+Note 8— Debt 
+Debt consists of the following: 
+December 31, 
+2021 2020 
+Term Loan Outstanding $ 106,465 $ 108,215 
+Revolving Line of Credit 18,000 — 
+Deferred financing costs and original issue discount ( 2,013 ) ( 2,440 ) 
+Total debt, net of deferred financing costs and original issue discount $ 122,452 $ 105,775 
+Current portion of long-term debt, net of discount $ 1,007 $ 364 
+Long-term debt, net of discount and current portion 121,445 105,411 
+$ 122,452 $ 105,775 
+On September 19, 2017, the Company entered into two credit agreements, a revolving line of credit up to $ 250.0 million (the “ABL Facility”) and a $ 175.0 million term loan (the “Term Loan Facility”, and together with the ABL Facility the “Credit Facilities”). 
+On October 22, 2021, the Company entered into an amendment to the ABL Facility (the “Revolving Credit Agreement Amendment”). The Revolving Credit Agreement Amendment further amends the credit agreement and guaranty and security agreement originally entered into by the parties on September 19, 2017, which governs the Company’s ABL Facility. Along with other revisions, the Revolving Credit Agreement Amendment (i) expanded the definition of borrowing base to include certain eligible US investment grade accounts, Canadian accounts solely after a specified event, and both chemical and spare parts inventory; (ii) increased the maximum revolver amount from $ 250.0 million to $ 350.0 million (with the ability to request an increase in the size of the ABL Facility by $ 75.0 million); (iii) increased certain indebtedness baskets; (iv) provided additional flexibility for a potential future internal structuring; (v) added new lenders to the facility; and (vi) extended the maturity date to the earlier of (a) October 22, 2026 and (b) to the extent the debt under the Term Loan Facility remains outstanding 90 days prior to the final maturity of the Term Loan Facility. The ABL Facility was initially scheduled to mature on the earlier to occur of (i) September 19, 2022 and (ii) to the extent the debt under the Term Loan Facility remains outstanding, 90 days prior to the final maturity of the Term Loan Facility. 
+Additionally, on October 22, 2021, the Company entered into a Fifth Amendment to Credit Agreement, Second Amendment to Guaranty and Security Agreement and Termination of Right of First Offer Letter. The Term Loan Credit Agreement Amendment further amends the credit agreement and guaranty and security agreement and terminates the Right of First Offer Letter originally entered into by the parties on September 19, 2017, which governs the Company’s Term Loan Facility. Along with other revisions, the Term Loan Credit Agreement Amendment (i) increased certain indebtedness baskets; (ii) provided additional flexibility for a potential future internal structuring; (iii) extended the maturity date through September 19, 2024; and (iv) terminated a right of first offer in favor of the Term Loan Facility lenders. The Term Loan Facility was initially scheduled to mature on September 19, 2022. 
+The weighted average interest rate on all borrowings outstanding as of December 31, 2021 and December 31, 2020 was 7.9 % and 8.6 %, respectively. 
+ABL Facility 
+Under the terms of the ABL Facility, up to $ 350.0 million may be borrowed, subject to certain borrowing base limitations based on a percentage of eligible accounts receivable and inventory. As of December 31, 2021, the borrowing base was calculated to be $ 269.0 million, and the Company had $ 18.0 million outstanding in addition to a letter of credit in the amount of $ 1.5 million, with $ 249.5 million of remaining availability. Borrowings under the ABL Facility bear interest at LIBOR or a 
+F-21 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated Financial Statements 
+base rate, plus an applicable LIBOR margin of 1.5 % to 2.0 % or base rate margin of 0.5 % to 1.0 %, as defined in the ABL Facility credit agreement. The unused commitment is subject to an unused commitment fee of 0.375 % to 0.5 %. Interest and fees are payable in arrears at the end of each month, or, in the case of LIBOR loans, at the end of each interest period. The ABL Facility matures on the earlier of (i) October 22, 2026, and (ii) to the extent the debt under the Term Loan Facility remains outstanding, 90 days prior to the final maturity of the Term Loan Facility, which matures on September 19, 2024. Borrowings under the ABL Facility are collateralized by accounts receivable and inventory, and further secured by the Company, Liberty LLC and R/C IV Non-U.S. LOS Corp., a Delaware corporation and a subsidiary of the Company, as parent guarantors. 
+Term Loan Facility 
+The Term Loan Facility provides for a $ 175.0 million term loan, of which $ 106.5 million remained outstanding as of December 31, 2021. Amounts outstanding bear interest at LIBOR or a base rate, plus an applicable margin of 7.625 % or 6.625 %, respectively, and borrowings as of December 31, 2021 incurred interest at a rate of 8.625 %. The Company is required to make quarterly principal payments of 1 % per annum of the outstanding principal balance, commencing on December 31, 2017, with final payment due at maturity on September 19, 2024. The Term Loan Facility is collateralized by the fixed assets of LOS and its subsidiaries, and is further secured by the Company, Liberty LLC and R/C IV Non-U.S. LOS Corp., a Delaware corporation and a subsidiary of the Company, as parent guarantors. 
+The Credit Facilities include certain non-financial covenants, including but not limited to restrictions on incurring additional debt and certain distributions. Moreover, the ability of the Company to incur additional debt and to make distributions is dependent on maintaining a maximum leverage ratio. The Term Loan Facility requires mandatory prepayments upon certain dispositions of property or issuance of other indebtedness, as defined, and annually a percentage of excess cash flow ( 25 % to 50 %, depending on leverage ratio, of consolidated net income less capital expenditures and other permitted payments, commencing with the year ending December 31, 2018). Certain mandatory prepayments and optional prepayments are subject to a prepayment premium of 3% of the prepaid principal declining annually to 1% during the first three years of the term of the Term Loan Facility. 
+The Credit Facilities are not subject to financial covenants unless liquidity, as defined in the respective credit agreements, drops below a specified level. Under the ABL Facility, the Company is required to maintain a minimum fixed charge coverage ratio, as defined in the credit agreement governing the ABL Facility, of 1.0 to 1.0 for each period if excess availability is less than 10 % of the borrowing base or $ 12.5 million, whichever is greater. Under the Term Loan Facility, the Company is required to maintain a minimum fixed charge coverage ratio, as defined, of 1.2 to 1.0 for each trailing twelve-month period if the Company’s liquidity, as defined, is less than $ 25.0 million for at least five consecutive business days. 
+The Company was in compliance with these covenants as of December 31, 2021. 
+Maturities of debt are as follows: 
+($ in thousands) 
+Years Ending December 31, 
+2022 $ 1,750 
+2023 1,750 
+2024 120,965 
+2025 — 
+2026 — 
+$ 124,465 
+Note 9— Fair Value Measurements and Financial Instruments 
+The fair values of the Company’s assets and liabilities represent the amounts that would be received to sell those assets or that would be paid to transfer those liabilities in an orderly transaction at the reporting date. These fair value measurements maximize the use of observable inputs. However, in situations where there is little, if any, market activity for the asset or liability at the measurement date, the fair value measurement reflects the Company’s own judgments about the assumptions that market participants would use in pricing the asset or liability. The Company discloses the fair values of its assets and liabilities according to the quality of valuation inputs under the following hierarchy: 
+• Level 1 Inputs: Quoted prices (unadjusted) in an active market for identical assets or liabilities. 
+• Level 2 Inputs: Inputs other than quoted prices that are directly or indirectly observable. 
+• Level 3 Inputs: Unobservable inputs that are significant to the fair value of assets or liabilities. 
+F-22 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated Financial Statements 
+The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those that are initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from unobservable inputs is inconsequential to the overall fair value, or if corroborating market data becomes available. Assets and liabilities that are initially reported as Level 2 are subsequently reported as Level 3 if corroborated market data is no longer available. Transfers occur at the end of the reporting period. There were no transfers into or out of Levels 1, 2, and 3 during the years ended December 31, 2021 and 2020. 
+The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, notes receivable, accounts payable, accrued liabilities, long-term debt, and finance and operating lease obligations. These financial instruments do not require disclosure by level. The carrying values of all the Company’s financial instruments included in the accompanying balance sheets approximated or equaled their fair values at December 31, 2021 and 2020. 
+• The carrying values of cash and cash equivalents, accounts receivable and accounts payable (including accrued liabilities) approximated fair value at December 31, 2021 and 2020, due to their short-term nature. 
+• The carrying value of amounts outstanding under long-term debt agreements with variable rates approximated fair value at December 31, 2021 and 2020, as the effective interest rates approximated market rates. 
+Nonrecurring Measurements 
+Certain assets and liabilities are measured at fair value on a nonrecurring basis. These items are not measured at fair value on an ongoing basis but may be subject to fair value adjustments in certain circumstances. These assets and liabilities include those acquired through the PropX Acquisition and OneStim Acquisition, which are required to be measured at fair value on the acquisition date in accordance with ASC Topic 805 . See Note 3 — Acquisitions. 
+Recurring Measurements 
+The fair values of the Company’s cash equivalents measured on a recurring basis pursuant to ASC 820-10 Fair Value Measurements and Disclosures are carried at estimated fair value. Cash equivalents consist of money market accounts which the Company has classified as Level 1 given the active market for these accounts. As of December 31, 2021 and 2020, the Company had cash equivalents, measured at fair value, of $ 0.3 million and $ 21.3 million, respectively. 
+Nonfinancial assets 
+The Company estimates fair value to perform impairment tests as required on long-lived assets. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3 in the event that such assets were required to be measured and recorded at fair value within the consolidated financial statements. Although a triggering event occurred during the year ended December 31, 2020 (see Note 5—Property and Equipment), no such measurements were required as of December 31, 2021 and 2020. 
+Credit Risk 
+The Company’s financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents, and trade receivables. 
+The Company’s cash and cash equivalents balance on deposit with financial institutions total $ 20.0 million and $ 69.0 million as of December 31, 2021 and 2020, respectively, which exceeded FDIC insured limits. The Company regularly monitors these institutions’ financial condition. 
+The majority of the Company’s customers have payment terms of 45 days or less. 
+As of December 31, 2021 and 2020, the below customers accounted for the following percentages of the Company's consolidated accounts receivable and unbilled revenue and consolidated revenues, respectively: 
+F-23 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated Financial Statements 
+Portion of total of consolidated accounts receivable and unbilled revenue as of December 31, Portion of consolidated revenues for the year ended December 31, 
+2021 2020 2021 2020 2019 
+Customer A 12 % — % — % — % — % 
+Customer B — % 11 % — % 12 % — % 
+Customer C — % 11 % — % 11 % — % 
+Customer D — % — % — % 10 % — % 
+Customer E — % — % — % 10 % — % 
+The Company mitigates the associated credit risk by performing credit evaluations and monitoring the payment patterns of its customers. 
+As of December 31, 2021, the Company had $ 0.9 million in allowance for credit losses and recorded a provision related to two entities inability to pay. 
+As of December 31, 2020, the Company had $ 0.8 million in allowance for credit losses. Subsequent to the adoption of ASU 2016-13 (see “Accounts Receivable” within Note 2—Significant Accounting Policies— Recently Adopted Accounting Standards ) on January 1, 2020, the Company recognized a $ 4.9 million allowance for credit losses, to the Company’s accounts receivables in consideration of both historic collection experience and the expected impact of deteriorating economic conditions for the oil and gas industry as of such date. 
+The Company applied historic loss factors to its receivable portfolio segments that were not expected to be further impacted by current economic developments, and an additional economic conditions factor to portfolio segments anticipated to experience greater losses in the current economic environment. While the Company has not experienced significant credit losses in the past and has not seen material changes to the payment patterns of its customers, the Company cannot predict with any certainty the degree to which the ongoing impacts of COVID-19, including the potential impact of periodically adjusted borrowing base limits, level of hedged production, or unforeseen well shut-ins may affect the ability of its customers to timely pay receivables when due. Accordingly, in future periods, the Company may revise its estimates of expected credit losses. 
+As of December 31, 2019 the Company recorded a provision related to one specific entity engaged in the business of oil and gas exploration and production that had filed for bankruptcy. 
+($ in thousands) 2021 2020 2019 
+Allowance for credit losses, beginning of year $ 773 $ 1,053 $ — 
+Credit losses: 
+Current period provision 745 4,877 1,053 
+Amounts written off, net of recoveries ( 634 ) ( 5,157 ) — 
+Allowance for credit losses, end of year $ 884 $ 773 $ 1,053 
+Note 10— Equity 
+Preferred Stock 
+As of December 31, 2021 and 2020 the Company had 10,000 shares of preferred stock authorized, par value $ 0.01 , with none issued and outstanding. If issued, each class or series of preferred stock will cover the number of shares and will have the powers, preferences, rights, qualifications, limitations and restrictions determined by the Company’s board of directors, which may include, among others, dividend rights, liquidation preferences, voting rights, conversion rights, preemptive rights and redemption rights. Except as provided by law or in a preferred stock designation, the holders of preferred stock will not be entitled to vote at or receive notice of any meeting of shareholders. 
+Class A Common Stock 
+The Company had a total of 183,385,111 and 157,952,213 shares of Class A Common Stock outstanding as of December 31, 2021 and 2020, none of which were restricted. Holders of Class A Common Stock are entitled to one vote per share on all matters to be voted upon by the stockholders and are entitled to ratably receive dividends when and if declared by the Company’s board of directors. 
+F-24 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated Financial Statements 
+Class B Common Stock 
+The Company had a total of 2,632,347 and 21,550,282 shares of Class B Common Stock outstanding as of December 31, 2021 and 2020, respectively. Holders of the Class B Common Stock are entitled to one vote per share on all matters to be voted upon by stockholders. Holders of Class A Common Stock and Class B Common Stock vote together as a single class on all matters presented to the Company’s stockholders for their vote or approval, except with respect to amendment of certain provisions of the Company’s certificate of incorporation that would alter or change the powers, preferences or special rights of the Class B Common Stock so as to affect them adversely, which amendments must be by a majority of the votes entitled to be cast by the holders of the shares affected by the amendment, voting as a separate class, or as otherwise required by applicable law. 
+Holders of Class B Common Stock do not have any right to receive dividends, unless the dividend consists of shares of Class B Common Stock or of rights, options, warrants or other securities convertible or exercisable into or exchangeable for shares of Class B Common Stock paid proportionally with respect to each outstanding share of Class B Common Stock and a dividend consisting of shares of Class A Common Stock or of rights, options, warrants or other securities convertible or exercisable into or exchangeable for shares of Class A Common Stock on the same terms is simultaneously paid to the holders of Class A Common Stock. Holders of Class B Common Stock do not have any right to receive a distribution upon liquidation or winding up of the Company. 
+Under the Second Amended and Restated Limited Liability Company Agreement of Liberty LLC (the “Liberty LLC Agreement”), each Liberty Unit Holder has, subject to certain limitations, the Redemption Right, which allows it to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units, for, at Liberty LLC’s election, (i) shares of Class A Common Stock at a redemption ratio of one share of Class A Common Stock for each Liberty LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions or (ii) an equivalent amount of cash. Alternatively, upon the exercise of the Redemption Right, the Company (instead of Liberty LLC) will have the Call Right, which allows it to, for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder for, at its election, (x) one share of Class A Common Stock or (y) an equivalent amount of cash. In addition, upon a change of control of the Company, the Company has the right to require each holder of Liberty LLC Units (other than the Company) to exercise its Redemption Right with respect to some or all of such unitholder’s Liberty LLC Units. In connection with any redemption of Liberty LLC Units pursuant to the Redemption Right or the Call Right, the corresponding number of shares of Class B Common Stock will be canceled. 
+Long Term Incentive Plan 
+On January 11, 2018, the Company adopted the Long Term Incentive Plan (“LTIP”) to incentivize employees, officers, directors and other service providers of the Company and its affiliates. The LTIP provides for the grant, from time to time, at the discretion of the Company’s board of directors or a committee thereof, of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, cash awards, substitute awards and performance awards. Subject to adjustment in the event of certain transaction or changes of capitalization in accordance with the LTIP, 12,908,734 shares of Class A Common Stock have been reserved for issuance pursuant to awards under the LTIP. Class A Common Stock subject to an award that expires or is canceled, forfeited, exchanged, settled in cash or otherwise terminated without delivery of shares and shares withheld to pay the exercise price of, or to satisfy the withholding obligations with respect to, an award will again be available for delivery pursuant to other awards under the LTIP. 
+Restricted Stock Units 
+Restricted stock units (“RSUs”) granted pursuant to the LTIP, if they vest, will be settled in shares of the Company’s Class A Common Stock. RSUs were granted with vesting terms up to five years . Changes in non-vested RSUs outstanding under the LTIP during the year ended December 31, 2021 were as follows: 
+Number of Units Weighted Average Grant Date Fair Value per Unit 
+Non-vested as of December 31, 2020 2,183,034 $ 10.90 
+Granted 1,572,463 11.29 
+Vested ( 959,356 ) 12.47 
+Forfeited ( 55,080 ) 8.38 
+Outstanding at December 31, 2021 2,741,061 $ 10.62 
+F-25 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated Financial Statements 
+Performance Restricted Stock Units 
+Performance restricted stock units (“PSUs”) granted pursuant to the LTIP, if they vest, will be settled in shares of the Company’s Class A Common Stock. PSUs were granted with a three year cliff vesting schedule, subject to a performance target compared to an index of competitors ’ results over a three year period as designated in the award. The Company records compensation expense based on the Company’s best estimate of the number of PSUs that will vest at the end of the performance period. If such performance targets are not met, or are not expected to be met, no compensation expense is recognized and any recognized compensation expense is reversed. Changes in non-vested PSUs outstanding under the LTIP during the year ended December 31, 2021 were as follows: 
+Number of Units Weighted Average Grant Date Fair Value per Unit 
+Non-vested as of December 31, 2020 722,225 $ 12.04 
+Granted 584,720 12.95 
+Vested — — 
+Forfeited — — 
+Outstanding at December 31, 2021 1,306,945 $ 12.45 
+Stock-based compensation is included in cost of services and general and administrative expenses in the Company’s consolidated statements of operations. The Company recognized stock based compensation expense of $ 19.9 million for the year ended December 31, 2021 and $ 17.1 million for the year ended December 31, 2020. There was approximately $ 25.5 million of unrecognized compensation expense relating to outstanding RSUs and PSUs as of December 31, 2021. The unrecognized compensation expense will be recognized on a straight-line basis over the weighted average remaining vesting period of two years . 
+Dividends 
+On April 2, 2020, the Company suspended future quarterly dividends until business conditions warrant reinstatement. 
+The Company paid cash dividends of $ 0.05 per share of Class A Common Stock on March 20, 2020 to stockholders of record as of March 6, 2020. Liberty LLC paid a distribution of total of $ 5.6 million, or $ 0.05 per Liberty LLC Unit, to all Liberty LLC unit holders as of March 6, 2020, $ 4.1 million of which was paid to the Company. The Company used the proceeds of the distribution to pay the dividend to all holders of shares of Class A Common Stock as of March 6, 2020, which totaled $ 4.1 million. Additionally, as of December 31, 2021 and 2020, the Company had $ 0.2 million and $ 0.4 million of accrued dividends payable related to restricted stock and RSUs to be paid upon vesting, respectively. Dividends related to forfeited restricted stock and RSUs will be forfeited. 
+Share Repurchase Program 
+On January 22, 2019, the Company’s board of directors authorized an additional $ 100.0 million under the share repurchase plan through January 31, 2021. 
+During the years ended December 31, 2021 and 2020, no shares were repurchased under the share repurchase program and, as of December 31, 2021, no amounts remained authorized for future repurchases of Class A Common Stock under the share repurchase program. 
+The Company accounts for the purchase price of repurchased common shares in excess of par value ($ 0.01 per share of Class A Common Stock) as a reduction of additional paid-in capital, and will continue to do so until additional paid-in capital is reduced to zero. Thereafter, any excess purchase price will be recorded as a reduction to retained earnings. 
+Note 11— Net Loss per Share 
+Basic net loss per share measures the performance of an entity over the reporting period. Diluted net loss per share measures the performance of an entity over the reporting period while giving effect to all potentially dilutive common shares that were outstanding during the period. The Company uses the “if-converted” method to determine the potential dilutive effect of its Class B Common Stock and the treasury stock method to determine the potential dilutive effect of outstanding restricted stock and RSUs. 
+F-26 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated Financial Statements 
+The following table reflects the allocation of net loss to common stockholders and net loss per share computations for the periods indicated based on a weighted average number of common stock outstanding: 
+(In thousands, except per share data) Year Ended December 31, 2021 Year Ended December 31, 2020 
+Basic Net Loss Per Share 
+Numerator: 
+Net loss attributable to Liberty Oilfield Services Inc. Stockholders $ ( 179,244 ) $ ( 115,583 ) 
+Denominator: 
+Basic weighted average shares outstanding 174,019 85,242 
+Basic net loss per share attributable to Liberty Oilfield Services Inc. Stockholders $ ( 1.03 ) $ ( 1.36 ) 
+Diluted Net Loss Per Share 
+Numerator: 
+Net loss attributable to Liberty Oilfield Services Inc. Stockholders $ ( 179,244 ) $ ( 115,583 ) 
+Effect of exchange of the shares of Class B Common stock for shares of Class A Common Stock — — 
+Diluted net loss attributable to Liberty Oilfield Services Inc. Stockholders $ ( 179,244 ) $ ( 115,583 ) 
+Denominator: 
+Basic weighted average shares outstanding 174,019 85,242 
+Effect of dilutive securities: 
+Restricted stock units — — 
+Class B Common Stock — — 
+Diluted weighted average shares outstanding 174,019 85,242 
+Diluted net loss per share attributable to Liberty Oilfield Services Inc. Stockholders $ ( 1.03 ) $ ( 1.36 ) 
+In accordance with GAAP, diluted weighted average common shares outstanding for the year ended December 31, 2021 exclude 7,052 weighted average shares of Class B Common Stock and 3,589 weighted average shares of restricted stock units. Additionally, diluted weighted average common shares outstanding for the year ended December 31, 2020 exclude 27,427 weighted average shares of Class B Common Stock, 207 weighted average shares of restricted stock, and 2,460 weighted average shares of restricted stock units. 
+Note 12— Income Taxes 
+The Company is a corporation and is subject to taxation in the United States, Canada and various state, local and provincial jurisdictions. Liberty LLC is treated as a partnership, and its income is passed through to its owners for income tax purposes. Liberty LLC’s members, including the Company, are liable for federal, state and local income taxes based on their share of Liberty LLC’s pass-through taxable income. As of December 31, 2021, tax reporting by the Company for the years ended December 31, 2018, 2019, and 2020 is subject to examination by the tax authorities. With few exceptions, as 
+F-27 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated Financial Statements 
+of December 31, 2021, the Company is no longer subject to U.S. federal, state or local examinations by tax authorities for tax years ended before December 31, 2017. 
+The components of the Company’s income (loss) from continuing operations before income taxes on which the provision for income taxes was computed consisted of the following: 
+Year Ended December 31, 
+($ in thousands) 2021 2020 2019 
+United States ( 191,774 ) ( 191,531 ) 88,916 
+Foreign 13,986 — — 
+Total $ ( 177,788 ) $ ( 191,531 ) $ 88,916 
+The components of the provision for incomes taxes from continuing operations are summarized as follows: 
+Year Ended December 31, 
+($ in thousands) 2021 2020 2019 
+Current: 
+Federal $ — $ ( 5,541 ) $ ( 9,907 ) 
+State 29 230 551 
+Foreign 4,108 — — 
+Total Current $ 4,137 $ ( 5,311 ) $ ( 9,356 ) 
+Deferred: 
+Federal 6,125 ( 23,103 ) 23,419 
+State ( 439 ) ( 2,443 ) ( 11 ) 
+Foreign $ ( 607 ) $ — — 
+Total Deferred $ 5,079 $ ( 25,546 ) $ 23,408 
+Income tax expense (benefit) $ 9,216 $ ( 30,857 ) $ 14,052 
+Income tax expense (benefit) attributable to net loss before income taxes differed from the amounts computed by applying the statutory U.S. federal income tax rate of 21.0% to pre-tax income as a result of the following: 
+Year Ended December 31, 
+($ in thousands) 2021 2020 2019 
+Computed tax (benefit) expense at the statutory rate $ ( 37,336 ) $ ( 40,222 ) $ 18,672 
+Increase (decrease) in tax expense resulting from: 
+State and local income tax (benefit) expense, net ( 5,204 ) ( 2,212 ) 1,525 
+Non-controlling interest 1,565 9,463 ( 7,531 ) 
+Effect of foreign tax rates 478 — — 
+Stock based compensation ( 535 ) 2,157 227 
+Change in valuation allowance 50,111 — — 
+Other, net 137 ( 43 ) 1,159 
+Total income tax expense (benefit) $ 9,216 $ ( 30,857 ) $ 14,052 
+The effective tax rate for the years ended December 31, 2021, 2020, and 2019 was (5.2)%, 16.1 %, and 15.8 %, respectively. 
+The Company recognized income tax benefit of $ 9.2 million during the year ended December 31, 2021. The Company’s effective tax rate is less than the statutory federal income tax rate of 21.0% due to the Company recording a valuation allowance on its U.S. net deferred tax assets as of December 31, 2020, due to entering into a three year cumulative pre-tax book loss position, primarily as a result of COVID-19 related losses. The Company’s effective tax rate is also less than the statutory rate because of foreign operations and the non-controlling interest’s share of Liberty LLC’s pass-through results for federal, state and local income tax reporting, upon which no taxes are payable by the Company. 
+F-28 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated Financial Statements 
+The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are presented below: 
+($ in thousands) December 31, 2021 December 31, 2020 
+Deferred tax assets: 
+Federal net operating losses $ 50,093 $ 15,632 
+State net operating losses 7,576 2,697 
+Realized tax benefit - TRAs 91,312 52,561 
+Intangibles 301 — 
+Other 219 — 
+Total deferred tax assets 149,501 70,890 
+Less valuation allowance ( 91,336 ) — 
+Net deferred tax assets 58,165 70,890 
+Deferred tax liabilities: 
+Investment in Liberty LLC $ ( 57,461 ) $ ( 64,765 ) 
+Property and equipment ( 97 ) — 
+Other ( 563 ) ( 765 ) 
+Total deferred tax liabilities ( 58,121 ) ( 65,530 ) 
+Net deferred tax asset $ 44 $ 5,360 
+During the quarter ended June 30, 2021 the Company established a valuation allowance resulting in the recognition of income tax expense on the Company’s beginning U.S. net deferred tax assets of $ 6.1 million. As of December 31, 2021, the Company had significant deferred tax assets and liabilities. The deferred tax assets include U.S. federal and state net operating losses and the step-up in basis of depreciable assets under Section 754 (“Section 754”) of the Internal Revenue Code of 1986, as amended, subject to the valuation allowance. In addition, the Company recorded a deferred tax asset and liability for the difference between the book value and the tax value of the Company's investment in Liberty LLC, in which a valuation allowance has been recorded against the net US deferred tax assets. The Company also has deferred tax assets for foreign operations driven by net deductible reversing temporary differences related to differences between book and taxable income. Since the Company’s establishment of the valuation allowance, increased deferred tax benefit and deferred tax assets related to the step-up in basis of depreciation assets under Section 754 resulted in a change in valuation allowance of $ 85.2 million. 
+As of December 31, 2021, the Company has available U.S. federal net operating loss carryforwards to reduce future taxable income of $ 3.7 million expiring in 2027, and $ 231.5 million with no expiration date. Per the Coronavirus Aid, Relief and Economic Security (“CARES”) Act enacted March 27, 2020, net operating losses (“NOL”) incurred in 2018, 2019, and 2020 may be carried back to each of the five preceding taxable years to generate a refund of previously paid income taxes. The Company has applied for and expects to receive a NOL carryback refund to recover $ 5.5 million of cash taxes paid by the Company in 2018. This amount has been reflected as a receivable in prepaids and other assets. The remaining deferred tax asset for net operating losses available for carryforward are presented net of the Company’s valuation allowance. 
+The Company may distribute cash from foreign subsidiaries to its U.S. parent as business needs arise. The Company has not provided for deferred income taxes on the undistributed earnings from certain foreign subsidiaries earnings as such earnings are considered to be indefinitely reinvested. If such earnings were to be distributed, any income and/or withholding tax would not be significant. 
+Uncertain Tax Positions 
+The Company records uncertain tax positions on the basis of a two-step process in which (1) the Company determines whether it is more likely than not the tax positions will be sustained on the basis of the technical merits of the position and (2) for those tax positions meeting the more likely than not recognition threshold, the Company recognizes the largest amount of tax benefit that is more than 50% likely to be realized upon ultimate settlement with the related tax authority. 
+The Company determined that no liability for unrecognized tax benefits for uncertain tax positions was required at December 31, 2021. In addition, the Company does not believe that it has any tax positions for which it is reasonably possible that it will be required to record a significant liability for unrecognized tax benefits within the next twelve months. If 
+F-29 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated Financial Statements 
+the Company were to record an unrecognized tax benefit, the Company will recognize applicable interest and penalties related to income tax matters in income tax expense. 
+Tax Distributions 
+Liberty LLC is treated as a partnership for income tax purposes. Federal, state and local taxes resulting from the pass-through taxable income of Liberty LLC are obligations of its members. Net profits and losses are generally allocated to the members of Liberty LLC (including the Company) in accordance with the number of Liberty LLC Units held by each member for tax purposes. The Liberty LLC Agreement provides for pro rata cash distributions, and in certain cases non-pro rata cash advances, to assist members (including the Company) in paying their income tax liabilities. The Liberty LLC Agreement requires any tax advances to be proportionally repaid in connection with any redemption of Liberty LLC Units pursuant to the Redemption Right or the Call Right. Net advances received by Liberty LLC from non-controlling interest holders were $ 1.4 million and $ 1.4 million, respectively, for the years ended December 31, 2021 and 2020. 
+Tax Receivable Agreements 
+The term of each TRA commenced on January 17, 2018, and will continue until all such tax benefits that are subject to such TRA have been utilized or expired, unless the Company experiences a change of control (as defined in the TRAs, which includes certain mergers, asset sales and other forms of business combinations) or the TRAs are terminated early (at the Company’s election or as a result of its breach), and the Company makes the termination payments specified in such TRA. 
+The amounts payable, as well as the timing of any payments, under the TRAs are dependent upon significant future events and assumptions, including the timing of the redemptions of Liberty LLC Units, the price of our Class A Common Stock at the time of each redemption, the extent to which such redemptions are taxable transactions, the amount of the redeeming unit holder’s tax basis in its Liberty LLC Units at the time of the relevant redemption, the characterization of the tax basis step-up, the depreciation and amortization periods that apply to the increase in tax basis, the amount of net operating losses available to the Company as a result of the Corporate Reorganization, the amount and timing of taxable income the Company generates in the future, the U.S. federal income tax rate then applicable, and the portion of the Company’s payments under the TRAs that constitute imputed interest or give rise to depreciable or amortizable tax basis. 
+Prior to the Corporate Reorganization, one of the Legacy Owners distributed a portion of its member interest in Liberty Holdings to R/C IV Non-U.S. LOS Corp. (“R/C IV”). Subsequently, in conjunction with the Corporate Reorganization, R/C IV was contributed to the Company. At the time of the contribution, R/C IV had net operating loss carryforwards totaling $ 10.9 million for federal income tax purposes and $ 10.9 million for certain state income tax purposes, which became available for the Company’s use as a result of the contribution. As a result of the Company being in a net income position in 2018 and the expected utilization of deferred tax assets, the Company recognized a deferred tax asset of $ 2.6 million and a corresponding $ 2.3 million liability pursuant to the TRAs. Of the contributed net operating loss carryforwards, $ 6.4 million for federal income tax purposes and $ 6.4 million of certain state income tax purposes have been utilized. As a result, the Company has remaining $ 0.8 million of deferred tax asset and a corresponding $ 0.7 million liability pursuant to the TRAs. 
+At December 31, 2021, the Company’s liability under the TRAs was $ 37.6 million, all of which is presented as a component of long term liabilities, and the related deferred tax assets totaled $ 91.3 million of which a valuation allowance on the net deferred tax asset has been recorded. The Company also remeasured the liability under the TRAs as of December 31, 2021 as it relates to the recording of a valuation allowance and recorded a gain on remeasurement of liabilities subject to the TRAs of $ 19.0 million recorded as part of continuing operations. The reduction in the liability under the TRA is primarily driven by current generated net operating losses and amortization of expected tax benefits that is subject to the valuation allowance and not expected to be realized in the foreseeable future. 
+During the year ended December 31, 2021, exchanges of Liberty LLC Units and shares of Class B Common Stock resulted in an increase of $ 58.5 million in amounts payable under the TRAs, and a net increase of $ 68.8 million in deferred tax assets, all of which are subject to the valuation allowance and remeasurement of TRA liability discussed above. The Company did not make any TRA payments for the year ended December 31, 2021. 
+During the year ended December 31, 2020, exchanges of Liberty LLC Units and shares of Class B Common Stock resulted in an increase of $13.1 million in amounts payable under the TRAs, and a net increase of $ 15.5 million in deferred tax assets, all of which were recorded through equity. The Company also made TRA payments of $ 1.9 million and $ 5.5 million, totaling $ 7.4 million for the year ended December 31, 2020. The TRA payments were related to tax benefits realized in prior years and for the Company’s NOL carryback of 2019 NOL to 2018 taxable income under the CARES Act. 
+F-30 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated Financial Statements 
+Note 13— Defined Contribution Plan 
+The Company sponsors a 401(k) defined contribution retirement plan covering eligible employees. During 2020, in connection with other cost savings measures undertaken in response to declining demand for frac services as a result of the impacts of the COVID-19 pandemic, employer matching contributions were temporarily suspended from April 1, 2020 through December 31, 2020. The Company makes a matching contribution at a rate of $ 1.00 for each $1.00 of employee contribution, subject to a cap of 6 % of the employee’s salary and federal limits. Contributions made by the Company were $ 19.0 million, $ 4.2 million, and $ 15.7 million for the years ended December 31, 2021, 2020 and 2019, respectively. 
+Effective January 1, 2021 the Company restored its 6 % matching contribution. 
+Note 14— Related Party Transactions 
+As of December 31, 2021 Schlumberger owns 56,826,134 shares of Class A Common Stock of the Company, or approximately 30.5 % of the issued and outstanding shares of common stock of the Company, including Class A Common Stock and Class B Common Stock. Under the Transaction agreement, to the extent the net working capital, as defined in the Transaction Agreement, of the Transferred Business is less than $ 54.6 million, the difference shall be payable in cash to the Company. As of December 31, 2020, the Company recorded a receivable from Schlumberger of $ 24.7 million for the working capital settlement and an agreed upon $ 8.0 million true-up payment related to the estimated costs to bring certain assets to full working condition, which was collected during the three months ended March 31, 2021. During the three months ended September 30, 2021, the Company agreed on a working capital settlement from Schlumberger of $ 15.8 million, most of which was netted against transaction services costs and cash settlements during the transition services period. In conjunction with closing the OneStim Acquisition, the Company entered into a transition services agreement with Schlumberger, under which Schlumberger provides certain administrative and other transition services until the Company fully integrates the acquired business. During the year ended December 31, 2021, the Company incurred $ 5.7 million of fees for such transaction services. The Company does not expect to incur any additional transition services related fees in future periods. 
+During the year ended December 31, 2021, a subsidiary of the Company and Schlumberger entered into a property swap agreement under which the Company exchanged with Schlumberger a property acquired in the OneStim Acquisition and $ 4.9 million in cash for a separate property that the Company will utilize with its existing operations. The Company did not recognize any gain or loss on the transaction. In a separate transaction, the Company sold equipment to Schlumberger for $ 1.3 million and recognized a gain on the sale of equipment of $ 0.9 million. 
+Following the OneStim Acquisition, in the normal course of business, the Company purchases chemicals, proppant and other equipment and maintenance parts from Schlumberger and its subsidiaries. During the year ended December 31, 2021, total purchases from Schlumberger were approximately $ 28.2 million, and as of December 31, 2021 amounts due to Schlumberger were $ 2.7 million and $ 1.1 million included in accounts payable and accrued liabilities, respectively, in the consolidated balance sheet. 
+On June 7, 2021 R/C Energy IV Direct Partnership, L.P., a Delaware limited partnership (“R/C Direct”) and R/C Liberty entered into an underwriting agreement, dated as of June 7, 2021, by and among the Company, Liberty LLC, R/C Direct, R/C Liberty and Morgan Stanley & Co. LLC, pursuant to which R/C Direct sold 3,707,187 shares of Class A Common Stock and R/C Liberty sold 8,592,809 shares of Class A Common Stock, at a price of $ 15.20 per share, to the underwriter (the “Sale”). In connection with the Sale, 6,918,142 shares of Class B Common Stock held by R/C Liberty were redeemed by the Company for an equal amount of Class A Common Stock. On June 10, 2021, the Sale closed. Following the Sale, R/C Direct and R/C Liberty no longer hold any Class A Common Stock or Class B Common Stock and are no longer considered related parties of the Company. 
+Prior to the Sale, R/C IV Liberty Holdings, L.P. (“R/C Liberty”) exercised its redemption right and redeemed 10,269,457 shares of Class B Common Stock resulting in an increase in tax basis, as described under “Tax Receivable Agreements” in Note—12 Income Taxes, which was subsequently offset by an increase in valuation allowance during the year ended December 31, 2021. During the year ended December 31, 2020, R/C Liberty exercised its redemption right and redeemed 4,016,965 shares of Class B Common Stock resulting in the recognition of $ 6.1 million in amounts payable under the TRAs. 
+Effective on June 15, 2021, Audrey Robertson was appointed to the board of directors of Liberty Oilfield Services Inc. Ms. Robertson serves as the Chief Financial Officer of Franklin Mountain Energy, LLC (“Franklin Mountain”). During the year ended December 31, 2021 the Company performed hydraulic fracturing services for Franklin Mountain in the amount of $ 20.5 million or 0.8 % of the Company’s revenues for such period. Receivables from Franklin Mountain as of December 31, 2021 were $ 0.0 million . 
+Liberty Resources LLC, an oil and gas exploration and production company, and its successor entity (collectively, the “Affiliate”) has certain common ownership and management with the Company. The amounts of the Company’s revenue 
+F-31 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated Financial Statements 
+related to hydraulic fracturing services provided to the Affiliate for the years ended December 31, 2021, 2020 and 2019, were $ 2.8 million, $ 0.0 million and $ 18.3 million, respectively. 
+As of December 31, 2021 and 2020, there were no receivables within the Company’s accounts receivable—related party line item attributable to the Affiliate. On June 24, 2019 (the “Agreement Date”), the Company entered into an agreement with the Affiliate to amend payment terms for outstanding invoices due as of the Agreement Date to be due on July 31, 2020. On September 30, 2019, the agreement was amended to extend the due date of the remaining amounts outstanding to October 31, 2020. Amounts outstanding from the Affiliate as of the Agreement Date were $ 15.6 million. The amounts outstanding, including all accrued interest was paid in full in January 2020. As of December 31, 2021 and December 31, 2020, no amounts were outstanding under the amended payment terms from the Affiliate. During the years ended December 31, 2021, 2020 and 2019, interest income from the Affiliate was $ 0.0 million , $ 0.3 million and $ 1.8 million, respectively. Receivables earned for services performed after the Agreement Date continue to be subject to normal 30-day payment terms, provided that any amount unpaid after 60 days is subject to 13 % interest. 
+During 2016, Liberty Holdings entered into a future commitment to invest and become a non-controlling minority member in Proppant Express Investments, LLC, the owner of Proppant Express Solutions, LLC (“PropX”), a provider of proppant logistics equipment. LOS is party to a services agreement (the “PropX Services Agreement”) whereby LOS is to provide certain administrative support functions to PropX, and LOS is to purchase and lease proppant logistics equipment from PropX. The PropX Services Agreement was terminated on May 29, 2018; however, the Company continues to lease equipment from PropX. Effective October 26, 2021, the Company completed the purchase of all membership interest in PropX, refer to Note 3—Acquisitions for further discussion of the transaction. During the period from January 1, 2021 until October 26, 2021, the Company leased proppant logistics equipment from PropX for $ 7.3 million. During the years ended December 31, 2020 and 2019 the Company leased proppant logistics equipment from PropX for $ 8.7 million and $ 9.8 million, respectively. Payables to PropX as of December 31, 2020 were $ 1.5 million. 
+R/C IV Liberty Big Box Holdings, L.P., a Riverstone Holdings LLC (“Riverstone”) fund and a former significant stockholder of the Company, held a greater than 10 % equity interest in PropX. Christopher Wright, the Chief Executive Officer, Michael Stock, the Chief Financial Officer and Ron Gusek, the President of the Company, held a less than 5 % equity interest in PropX through Big Box Proppant Investments LLC. Cary Steinbeck, a director of the Company, served on the PropX board of the directors and held a less than 5 % indirect equity interest in PropX. In addition, Brett Staffieri, a Riverstone appointed director, served on the board of the directors of the Company until June 15, 2021 and on the PropX board of directors until the acquisition date. The PropX Acquisition was reviewed and approved by the disinterested members of the Board and pursuant to the Company’s related party transactions policy. 
+Note 15— Commitments & Contingencies 
+Purchase Commitments (tons are not in thousands) 
+The Company enters into purchase and supply agreements to secure supply and pricing of proppants and chemicals. As of December 31, 2021 and 2020, the agreements provide pricing and committed supply sources for the Company to purchase 89,317 and 1,580,750 tons, respectively, of proppant through June 30, 2022. Amounts above also include commitments to pay for transport fees on minimum amounts of proppants. Additionally, related proppant transload service commitments extend into 2023. 
+Future proppant, transload, equipment and mancamp commitments are as follows: 
+($ in thousands) 
+2022 $ 24,605 
+2023 1,353 
+2024 — 
+2025 — 
+2026 — 
+Thereafter — 
+$ 25,958 
+Certain supply agreements contain a clause whereby in the event that the Company fails to purchase minimum volumes, as defined in the agreement, during a specific time period, a shortfall fee may apply. In circumstances where the Company does not make the minimum purchase required under the contract, the Company and its suppliers have a history of amending such minimum purchase contractual terms and in rare cases does the Company incur shortfall fees. If the Company were unable to 
+F-32 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated Financial Statements 
+make any of the minimum purchases and the Company and its suppliers cannot come to an agreement to avoid such fees, the Company could incur shortfall fees in the amounts of $ 16.1 million and $ 1.4 million for the years ended 2022 and 2023 respectively. Based on forecasted levels of activity, the Company does not currently expect to incur significant shortfall fees. 
+Included in the commitments for the year ending December 31, 2021 are approximately $ 8.5 million of payments expected to be made to Schlumberger, in conjunction with a permissive use agreement provided by Schlumberger, in the first quarter of 2022 for the use of certain light duty trucks, heavy tractors and field equipment used to various degrees in OneStim’s frac and wireline operations. The Company is in negotiations with the third party owner of such equipment to lease or purchase some or all of such aforementioned vehicles and equipment, subject to agreement on terms and conditions. No gain or loss is expected upon consummation of any such agreement. 
+Litigation 
+Securities Class Actions 
+On March 11, 2020, Marshall Cobb, on behalf of himself and all other persons similarly situated, filed a putative class action lawsuit in the state District Court of Denver County, Colorado against the Company and certain officers and board members of the Company along with other defendants in connection with the IPO (the “Cobb Complaint”). The Cobb Complaint alleges that the Company and certain officers and board members of the Company violated Section 11 of the Securities Act of 1933 by virtue of inaccurate or misleading statements allegedly contained in the registration statement filed in connection with the IPO and requests unspecified damages and costs. The Cobb Plaintiffs also allege control person liability claims under Section 15 of the Securities Act of 1933 against certain officers and board members of the Company and other defendants. 
+On April 3, 2020, Marc Joseph, on behalf of himself and all other persons similarly situated, filed a putative class action lawsuit in the United States District Court in Denver, Colorado against the Company and certain officers and board members of the Company along with other defendants in connection with the IPO and requests unspecified damages and costs (the “Joseph Complaint,” and collectively with the Cobb Complaint, the “Securities Lawsuits”). The Joseph Complaint, which is based on similar factual allegations made in the Cobb Complaint, alleges that the defendants violated Sections 11 and 12(a)(2) of the Securities Act of 1933 by virtue of inaccurate or misleading statements allegedly contained in the registration statement and prospectus filed in connection with the IPO. The Joseph Complaint also alleges control person liability claims under Section 15 of the Securities Act of 1933 against certain officers and board members of the Company and other defendants. 
+The Company has hired counsel and plans to vigorously defend against the allegations in the Securities Lawsuits. 
+Other Litigation 
+In addition to the matters described above, from time to time, the Company is subject to legal and administrative proceedings, settlements, investigations, claims and actions. The Company’s assessment of the likely outcome of litigation matters is based on its judgment of a number of factors including experience with similar matters, past history, precedents, relevant financial and other evidence and facts specific to the matter. Notwithstanding the uncertainty as to the final outcome, based upon the information currently available, management does not believe any matters in aggregate will have a material adverse effect on its financial position or results of operations. 
+The Company cannot predict the ultimate outcome or duration of any lawsuit described in this report. 
+Note 16— Subsequent Events 
+As of the date of these financial statements, there were no significant subsequent events requiring disclosure or recognition in the consolidated financial statements and notes thereto. 
+F-33
\ No newline at end of file
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index 0000000000000000000000000000000000000000..2b3125ca7673144b85b55c7631fafaff12388c19
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@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0001694028,LBRT,Liberty Energy Inc.,10-K,2022-02-22,2021-12-31,2022-02-22T16:33:58.000Z,0001694028-22-000006,lbrt-20211231.htm,10-K,10475069,1,1,https://www.sec.gov/Archives/edgar/data/1694028/000169402822000006/lbrt-20211231.htm,https://www.sec.gov/Archives/edgar/data/1694028/000169402822000006/,2021,2021,1
diff --git a/raw/filings/0001694028/2021/0001694028-22-000006/item1.txt b/raw/filings/0001694028/2021/0001694028-22-000006/item1.txt
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index 0000000000000000000000000000000000000000..3de01a80e2f99231c8553cad649b62b369211235
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@@ -0,0 +1,122 @@
+Item 1. Business 
+Our Company 
+We are a leading integrated oilfield services and technology company focused on providing innovative hydraulic services and related technologies to onshore oil and natural gas exploration and production (“E&P”) companies in North America. We offer customers hydraulic fracturing services, together with complementary services including wireline services, proppant delivery solutions, data analytics, related goods (including our sand mine operations), and technologies that will facilitate lower emission completions, thereby helping our customers reduce their emissions profile. 
+Our primary locations of operation include the Permian Basin, the Eagle Ford Shale, the Denver-Julesburg Basin (the “DJ Basin”), the Williston Basin, the San Juan Basin, the Powder River Basin, the Haynesville Shale, the South Central Oklahoma Oil Province and Sooner Trend Anadarko Canadian Kingfisher (collectively, the “SCOOP/STACK”), the Marcellus Shale, the Utica Shale, and the Western Canadian Sedimentary Basin, which are among the most active basins in North America. The breadth of our operational footprint provides us an opportunity to leverage our fixed costs and to efficiently reposition our equipment in response to customer requirements. The map below represents our current areas of operation. 
+The process of hydraulic fracturing involves pumping a pressurized stream of fracturing fluid (typically a mixture of water, chemicals and proppant) into a well casing or tubing to cause the underground formation to fracture or crack. These fractures release trapped hydrocarbon particles and provide a conductive channel for the oil or natural gas to flow freely to the wellbore for collection. The propping agent, or proppant, typically sand, becomes lodged in the cracks created by the hydraulic fracturing process, “propping” them open to facilitate the flow of hydrocarbons from the reservoir to the well. The fracturing 
+1 
+fluid is engineered to lose viscosity, or “break,” and is subsequently flowed back from the formation, leaving the proppant suspended in the formation fractures. Once our customer has flushed the fracturing fluids from the well using a controlled flow-back process, the customer manages fluid and water recycling or disposal. 
+Our hydraulic fracturing fleets consist of mobile hydraulic fracturing units and other auxiliary heavy equipment to perform fracturing services. Our hydraulic fracturing units consist primarily of high-pressure hydraulic pumps, engines, transmissions, radiators and other supporting equipment that are typically mounted on trailers. We refer to the group of units and other equipment, such as blenders, data vans, sand storage, tractors, manifolds and high pressure fracturing iron, which are necessary to perform a typical hydraulic fracturing job, as a “fleet,” and the personnel assigned to each fleet as a “crew.” The size of each fleet and crew can vary depending on the requirements of each job design. 
+We also have wireline operations as a result of the acquisition of Schlumberger’s OneStim business in December 2020, whereby we obtained certain assets and liabilities of the OneStim business including OneStim’s hydraulic fracturing pressure pumping services business in onshore United States and Canada (the “OneStim Acquisition”). Our wireline units consist of a truck equipped with a spool of wireline that is lowered into wells to convey specialized tools or equipment, such as perforating guns and charges, that are necessary to connect the wellbore with the target formation. This operation is performed between each hydraulic fracturing stage. Our wireline service is primarily offered alongside our hydraulic fracturing services, which allows us to maximize efficiency for our customers through optimized coordination of the wireline and hydraulic fracturing services. In addition, we also offer our wireline service on a stand-alone basis. 
+As a result of the PropX Acquisition, which was completed in October 2021 (described in this Annual Report under “—Recent Developments—PropX Acquisition”), we are now a leading provider of last-mile proppant delivery solutions, including proppant handling equipment and logistics software across North America. PropX offers innovative environmentally friendly technology with optimized dry and wet sand containers and wellsite proppant handling equipment that drive logistics efficiency and reduce noise and emissions. We believe that PropX wet sand handling technology is a key enabler of the next step of cost and emissions reductions in the proppant industry. PropX also offers customers the latest real-time logistics software, PropConnect™, for sale or as hosted software as a service. 
+Our operations are organized into a single business segment, which consists of hydraulic fracturing services, including wireline, proppant delivery and goods, including our Permian Basin sand mines, and we have one reportable geographical segment, North America. We have grown from one active hydraulic fracturing fleet as of December 2011 to over 30 active fleets as of December 31, 2021. We are focused on providing “next-generation” frac fleets and technologies to assist our customers with completing their wells in an ESG-friendly manner. 
+Our founders and management are pioneers in the development of data-driven hydraulic fracturing technologies for application in shale plays. Prior to founding the Company, the majority of our management team founded and built Pinnacle Technologies, Inc. (“Pinnacle Technologies”) into a leading fracturing technology company. In 1992, Pinnacle Technologies developed the first commercial hydraulic fracture mapping technologies, analytical tools that played a major role in launching the shale revolution. Our extensive experience with fracture technologies and customized fracture design has enabled us to develop new technologies and processes that provide our customers with real-time solutions that significantly enhance their completions. These technologies include hydraulic fracture propagation models, reservoir engineering tools, large, proprietary shale production databases and multi-variable statistical analysis techniques. Taken together, these technologies have enabled us to be a leader in hydraulic fracture design innovation and application. Our management team has an average of over 20 years of oilfield services experience, and the majority of our management team worked together before founding our company. 
+We believe technical innovation and strong relationships with our customer and supplier bases distinguish us from our competitors and are the foundations of our business. We expect that E&P companies will continue to focus on technological innovation as completion complexity and fracture intensity of horizontal wells increases, particularly as customers are increasingly focused on reducing emissions from their completions operations. We remain proactive in developing innovative solutions to industry challenges, including developing: (i) our databases of U.S. unconventional wells to which we apply our proprietary multi-variable statistical analysis technologies to provide differential insight into fracture design optimization; (ii) our Liberty Quiet Fleet® design which significantly reduces noise levels compared to conventional hydraulic fracturing fleets; (iii) hydraulic fracturing fluid systems tailored to the specific reservoir properties in the basins in which we operate and (iv) our dual fuel dynamic gas blending fleets that allow our engines to run diesel or a combination of diesel and natural gas, to optimize fuel use, reduce emissions and lower costs. In addition, our integrated supply chain includes proppant, chemicals, equipment, logistics and integrated software which we believe promotes wellsite efficiency and leads to more pumping hours and higher productivity throughout the year to better service our customers. In order to achieve our technological objectives, we carefully manage our liquidity and debt position to promote operational flexibility and invest in the business throughout the full commodity cycle. 
+2 
+Recent Developments 
+PropX Acquisition 
+On October 26, 2021, the Company acquired Proppant Express Investments, LLC in exchange for $11.9 million in cash and 3,405,526 shares of Class A Common Stock and 2,441,010 shares of Class B common stock, par value $0.01 per share (“Class B Common Stock” and, together with Class A Common Stock, the “Common Stock”), and 2,441,010 units of Liberty LLC (“Liberty LLC Units”), for total consideration of $103.0 million, based on the Class A Common Stock closing price of $15.58 on October 26, 2021, subject to customary post-closing adjustments (the “PropX Acquisition”). The Liberty LLC Units are redeemable for an equivalent number of shares of Class A Common Stock at any time, at the election of the shareholder. See Note 3 —Acquisitions to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.” 
+Joinder to Liberty LLC Agreement 
+In connection with the PropX Acquisition, each of the sellers and certain of their investors that received Liberty LLC units, entered into a joinder to the Second Amended and Restated Limited Liability Company Agreement of Liberty LLC (the “Liberty LLC Agreement”). Under the Liberty LLC Agreement, holders, subject to certain limitations, have the right, pursuant to a redemption right, to cause Liberty LLC to acquire all or a portion of their Liberty LLC Units for, at Liberty LLC’s election, (i) shares of our Class A Common Stock at a redemption ratio of one share of Class A Common Stock for each Liberty LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification or (ii) an equivalent amount of cash. Alternatively, upon the exercise of the redemption right, we (instead of Liberty LLC) have a call right to acquire each tendered Liberty LLC Unit directly from the holder for, at its election, (x) one share of Class A Common Stock or (y) an equivalent amount of cash. In addition, upon a change of control, we have the right to require each holder of Liberty LLC Units (other than us) to exercise its redemption right with respect to some or all of such unitholder’s Liberty LLC Units. As the holders redeem their Liberty LLC Units, our membership interest in Liberty LLC will be correspondingly increased, the number of shares of Class A Common Stock outstanding will be increased, and the number of shares of Class B Common Stock outstanding will be reduced. 
+ABL Facility 
+On October 22, 2021, we entered into an amendment with respect to our ABL Facility. Under the terms of the amendment, the maximum borrowing amount was increased to $350.0 million, subject to certain borrowing base limitations based on a percentage of eligible accounts receivable and inventory (with the ability to request an increase in the size of the ABL Facility by $75 million). Additionally, limits under certain covenants related to allowable indebtedness and other activities were expanded. The ABL Facility maturity was extended to the earlier of (i) October 22, 2026 and (ii) to the extent the debt under the Term Loan Facility remains outstanding 90 days prior to the final maturity of the Term Loan Facility. All other financial provisions under the original agreement are still applicable to the ABL Facility aside from the aforementioned changes to the borrowing base. 
+Term Loan Facility 
+On October 22, 2021, we entered into a Fifth Amendment to Credit Agreement, Second Amendment to Guaranty and Security Agreement and Termination of Right of First Offer Letter (the “Term Loan Credit Agreement Amendment”). The Term Loan Credit Agreement Amendment further amends the credit agreement and guaranty and security agreement and terminates the right of first offer letter originally entered into by the parties on September 19, 2017 (the “Right of First Offer Letter”), which governs our Term Loan Facility. Along with other revisions, the Term Loan Credit Agreement Amendment (i) increased certain indebtedness baskets; (ii) provided additional flexibility for a potential future internal structuring; (iii) extended the maturity date through September 19, 2024; and (iv) terminated a right of first offer in favor of the Term Loan Facility lenders. 
+ESG Focused 
+While we recognize the various environmental and social impacts of hydrocarbon energy, we believe that access to life-enhancing modern energy presents the most pressing global energy challenge. We passionately work to better the process of bringing hydrocarbons to the surface in a clean, safe and efficient fashion and view ESG principles as foundational to our business. We focus on developing and adding technologies to our operations that assist our customers in implementing their ESG goals. The list below sets forth specific examples of our efforts towards ESG principles: 
+• In 2013, we introduced Tier 2 dual-fuel technology to our fleets which allows our frac pumps to use natural gas in place of some diesel fuel to lower particulate emissions. 
+3 
+• In 2014, we began the use of containerized sand delivery at frac locations, which reduces dust, noise and truck traffic. 
+• In 2016, we introduced Quiet Fleet® technology, which significantly reduces noise levels associated with frac operations. 
+• In 2018, we began a partnership with an equipment supplier to introduce Tier 4 dynamic gas blending, or DGB, engines to our frac fleet that can substitute up to 80% of the diesel typically used by a frac pump with natural gas and significantly lower emission levels in frac operations. Tier 4 DGB engines were added to our fleet in 2020. 
+• In 2021, we announced the successful test of digiFrac™, our innovative, purpose-built electric frac pump that has approximately a 25% lower CO2e emission profile than the Tier IV DGB. We have entered into two multi-year arrangements with customers for digiFrac fleets and expect to deliver the first fleet into commercial service in 2022. 
+• In October 2021, we closed the acquisition of PropX. PropX offers innovative, environmentally friendly technology with optimized dry and wet sand containers and wellsite proppant handling equipment that drive logistics efficiency and reduce noise and emissions. 
+We are continuously committed to engagement in our communities. We provide K-12 scholarships to low-income children through ACE (Alliance for Choice in Education) and we have launched a Liberty Scholars program at Montana Technological University to enable lower income students to obtain a college engineering education. In 2021, over 100 students received Liberty scholarships. We have numerous other efforts targeting schools, veterans, poverty abatement, low-income housing, criminal justice reform and job opportunities for those who had a disadvantaged start in life. In 2021, we launched Love, Liberty, our matching program that is aimed to encourage our employees to get involved in their communities. 
+Cyclical Nature of Industry 
+We operate in a highly cyclical industry. The key factor driving demand for our services is the level of drilling activity by E&P companies, which in turn depends largely on the current and anticipated economics of new well completions. Global supply and demand for oil and the domestic supply and demand for natural gas are critical in assessing industry outlook. Demand for oil and natural gas is cyclical and subject to large, rapid fluctuations, such as those experienced in 2020. E&P companies tend to increase capital expenditures in response to increases in oil and natural gas prices, which generally results in greater revenues and profits for oilfield service companies such as ours. Increased capital expenditures also ultimately lead to greater production, which historically has resulted in increased supplies of hydrocarbons and reduced prices which in turn tend to drive a future reduction in E&P companies capital expenditures and reduce demand for oilfield services. For these reasons, the results of our operations may fluctuate from quarter to quarter and from year to year, and these fluctuations may distort comparisons of results across periods. 
+Seasonality 
+Our results of operations have historically reflected seasonal tendencies relating to holiday seasons, inclement weather and the conclusion of our customers’ annual drilling and completion capital expenditure budgets. Our most notable declines typically occur in the fourth quarter of the year for the reasons described above. Additionally, some of the areas in which we have operations, including Canada, the DJ Basin, Powder River Basin and Williston Basin, are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice, rain, or frost, and related road restrictions, we may be unable to move our equipment between locations, thereby reducing our ability to provide services and generate revenues. The exploration activities of our customers may also be affected during such periods of adverse weather conditions. Additionally, extended drought conditions in our operating regions could impact our ability or our customers’ ability to source sufficient water or increase the cost for such water. 
+Intellectual Property 
+Over the last several years and in connection with the acquisitions of OneStim and PropX, we have significantly invested in our research and technology capabilities. Our efforts to date have been focused on developing innovative, fit-for-purpose solutions designed to enhance our core service offerings, increase completion efficiencies, provide cost savings to our operations and add value for our customers. A cornerstone of our technological advantage is a series of proprietary databases of U.S. unconventional wells that include production data, completion designs and reservoir characteristics. We utilize these databases to perform multi-variable statistical analysis that generates differential insight into fracture design optimization to enhance our customers’ production economics. Our emphasis on data analytics is also deployed during job execution through the use of real-time feedback on variables that maximizes customer returns by improving cost-effective hydraulic fracturing operations. 
+Today, we hold over 500 patents and patent licenses relating to our engineering and technology solutions. We seek patent and trademark protections for our technology when we deem it prudent, and we aggressively pursue protection of these rights when warranted. We believe our patents, trademarks, and other protections for our proprietary technologies are adequate for the conduct of our business and that no single patent or trademark is critical to our business. In addition, we rely, to a great extent, 
+4 
+on the technical expertise and know-how of our personnel to maintain our competitive position, and we take commercially reasonable measures to protect trade secrets and other confidential and/or proprietary information relating to the technologies we develop. 
+Human Capital Management 
+As of December 31, 2021, we had 3,601 employees and no unionized labor. We believe we have good relations with our employees and that one of our key competitive advantages is our people. Our highly trained, experienced and motivated employees are critical to delivering our hydraulic fracturing services. Taking care of our employees is one of our top priorities, and we continually invest in hiring, training and retaining the employees we believe to be the best in our field. We consistently assess the current business environment and labor market to refine our compensation and benefits programs in order to attract and retain top talent in our industry. We temporarily implemented a company-wide employee furlough plan in connection with COVID-19 due to the uncertain level of frac demand we experienced during the second and third quarters of 2020, but as of September 30, 2020, all employees were returned from furlough. During 2021, we experienced increased turnover in field employee positions; however that trend improved in the later part of the year and into 2022. We strive to promote from within our existing employee base to manage new hydraulic fracturing fleets and organically grow our operating expertise. This organic growth is essential in achieving the expertise and level of customer service we strive to provide each of our customers. As a result, we plan to continue to invest in our employees through both personal and professional training to attract and retain the best individuals in our areas of operation. Overall, we focus on individual contributions and team success to foster a culture built around operational excellence and superior safety. 
+Health and Safety 
+Our people are our most important asset and ensuring their safety and the safety of those around them is the most important thing we do. Making certain that the Liberty team is well trained to handle the complexities of daily field operations, and that their training and competency remains current with the latest technology and standards is a key component. In order to facilitate this training, we have developed the Liberty Frac Academy, a thorough program where employees are trained on various aspects of the Company, from safety in equipment operation to leadership skills. The Liberty Frac Academy not only ensures dissemination of high-quality training material, but also provides a forum for sharing best practices and lessons learned across the Company. As a result, we are among the safest service providers in the industry with a constant focus on Health, Safety and Environmental performance and service quality, as evidenced by an average incident rate that was 10% less than the industry average from 2019 to 2021. Our employee-centered focus and reputation for safety has enabled us to obtain projects from industry leaders with some of the most demanding safety and operational requirements. We have implemented and continue to implement safety measures in all of our facilities to address the COVID-19 pandemic. 
+Programs and Benefits 
+One way we have demonstrated a history of investing in our workforce is by offering competitive salaries and wages. To foster a strong sense of ownership, restricted stock units are provided to eligible employees under our long term incentive plan. Furthermore, we offer innovative benefits to all eligible employees, including, among others, comprehensive health insurance coverage, parental leave to all new parents, for birth or adoption, financial support for child adoption, leave to care for partners with serious health conditions, 401(k) savings plan and educational tuition assistance for both bachelor’s degree and master’s degree programs. We are also passionate about community investment and, in 2019, we joined the Ban the Box initiative which provides work opportunities for formerly incarcerated individuals. 
+Governmental Regulation and Climate Change 
+As a company with operations in both the United States and Canada, we are subject to the laws of both jurisdictions in which we operate and the rules and regulations of various governing bodies, which may differ among those jurisdictions. Compliance with these laws, rules and regulations has not had, and is not expected to have, a material effect on our capital expenditures, results of operations and competitive position as compared to prior periods. We are also subject to numerous environmental and regulatory requirements related to our operations. For further information related to such regulation, see the risks described under the heading “Risk Factors” in this Annual Report. 
+Our operations are subject to numerous stringent and complex laws and regulations at the federal, state, and local levels governing the discharge of materials into the environment, environmental protection, and health and safety aspects of our operations. Failure to comply with these laws and regulations or to obtain or comply with permits may result in the assessment of administrative, civil, and criminal penalties, imposition of remedial or corrective action requirements, and the imposition of injunctions or other orders to prohibit certain activities, restrict certain operations, or force future compliance with environmental requirements. 
+5 
+There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons, other hazardous substances, and wastes, as a result of air emissions and wastewater discharges related to our operations, and because of historical operations and waste disposal practices. Spills or other releases of regulated substances, including such spills and releases that occur in the future, could expose us to material losses, expenditures, and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. The following is a summary of some of the existing laws, rules, and regulations to which we are subject. 
+U.S. Laws and Regulations 
+Hazardous Substances and Waste Handling 
+The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Under guidance issued by the U.S. Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. RCRA currently exempts many E&P wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes intrinsically associated with the exploration, development, or production of crude oil and natural gas. However, these E&P wastes may still be regulated under state solid waste laws and regulations, and it is possible that certain oil and natural gas E&P wastes now classified as non-hazardous could be classified as hazardous waste in the future. Stricter regulation of wastes generated during our or our customers’ operations could result in increased costs for our operations or the operations of our customers, which could in turn reduce demand for our services and adversely affect our business. We cannot guarantee that the EPA will not revisit the exemption of E&P waste or that waste will not become more heavily regulated at the federal or state level. 
+Comprehensive Environmental Response, Compensation, and Liability Act 
+The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owner or operator of the site where the release occurred and anyone who transported or disposed or arranged for the transport or disposal of a hazardous substance released at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA and any state analogs may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources and for the costs of certain health studies. We currently own, lease, or operate numerous properties that have been used for manufacturing and other operations for many years. These properties and the substances disposed or released on them may be subject to CERCLA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. 
+Worker Health and Safety 
+We are subject to a number of federal and state laws and regulations, including the OSHA, establishing requirements to protect the health and safety of workers. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require maintenance of information about hazardous materials used or produced in operations and provision of this information to employees, state and local government authorities, and citizens. Specifically, OSHA has enacted a regulation regarding crystalline silica exposures, which included requirements that hydraulic fracturing operations implement dust controls to limit exposures to the substance. Additionally, the Federal Motor Carrier Safety Administration (the “FMCSA”) regulates and provides safety oversight of commercial motor vehicles, the EPA establishes requirements to protect human health and the environment, the federal Bureau of Alcohol, Tobacco, Firearms and Explosives establishes requirements for the safe use and storage of explosives, and the federal Nuclear Regulatory Commission establishes requirements for the protection against ionizing radiation. Substantial fines and penalties can be imposed, and orders or injunctions limiting or prohibiting certain operations may be issued, in connection with any failure to comply with these laws and regulations. 
+6 
+Water Discharges 
+The federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the U.S. The discharge of pollutants into regulated waters, including jurisdictional wetlands, is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. To the extent the agencies expanding the range of properties subject to the Clean Water Act’s jurisdiction, certain energy companies could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas, which in turn could reduce demand for our services. Furthermore, the process for obtaining permits has the potential to delay our operations and those of our customers. Spill prevention, control, and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture, or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of wastewater and storm water runoff from certain types of facilities. The Clean Water Act and analogous state laws provide for administrative, civil, and criminal penalties for unauthorized discharges and, together with the Oil Pollution Act of 1990, impose rigorous requirements for spill prevention and response planning, as well as substantial potential liability for the costs of removal, remediation, and damages in connection with any unauthorized discharges. 
+Air Emissions 
+The federal Clean Air Act (the “CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. These regulations change frequently. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements, or utilize specific equipment or technologies to control emissions of certain pollutants. In recent years, the CAA has been used to impose additional stringent requirements upon oil and gas production operations. While these rules may not be directly applicable to our business, they are applicable to the business of our customers. Promulgation of stricter permitting requirements could delay or impair our or our customers’ ability to obtain air emission permits, to develop new wells and to continue to operate existing wells, and result in fewer wells being drilled or redeveloped, causing a decrease in demand for our services. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties, as well as injunctive relief, for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. 
+Climate Change 
+The EPA has determined that emissions of greenhouse gases, including carbon dioxide and methane, present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. The EPA has established greenhouse gas emissions reporting requirements for sources in the oil and gas sector and has also promulgated rules requiring certain large stationary sources of greenhouse gases to obtain preconstruction permits under the CAA and follow “best available control technology” requirements. Although we are not likely to become subject to greenhouse gas emissions permitting and best available control technology requirements because none of our facilities are presently major sources of greenhouse gas emissions, such requirements could become applicable to our customers. In addition, the EPA has used the CAA to impose additional greenhouse gas emissions control requirements upon our customers. These additional requirements on greenhouse gas emissions from our customers could have an adverse effect on their costs of operations or financial performance, thereby adversely affecting our business, financial condition, and results of operations. Also, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, and many states have already established regional greenhouse gas “cap-and-trade” programs. The adoption of any legislation or regulation that restricts emissions of greenhouse gases from the equipment and operations of our customers or with respect to the oil and natural gas they produce could adversely affect demand for our products and services. 
+Hydraulic Fracturing 
+Our business is clearly dependent on hydraulic fracturing and horizontal drilling activities. As further described herein, hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shale. The process, which involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. Specifically, there is considerable uncertainty surrounding regulation of the emissions of methane, which may be released during hydraulic fracturing, chemicals used in the hydraulic fracturing process, the discharge of wastewater from hydraulic 
+7 
+fracturing operations and concerns about the triggering of seismic activity by the injection of produced waters into underground wells. Certain proposed regulation could make it significantly more difficult and/or costly to drill and operate oil and gas wells. If adopted, such regulation could result in a decline in the completion of new oil and gas wells or the recompletion of existing wells, which could negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the demand for our services. Given the long-term trend towards increasing regulation, future regulation in the industry remains a possibility. 
+Some states, counties, and municipalities have enacted or are considering moratoria on hydraulic fracturing. For example, New York, Vermont, Maryland, and Washington have banned, or are in the process of banning, the use of high-volume hydraulic fracturing. Alternatively, some municipalities are, or have considered, zoning and other ordinances, the conditions of which could impose a de facto ban on drilling and/or hydraulic fracturing operations. Further, some states, counties, and municipalities are closely examining water use issues, such as permit and disposal options for processed water, which could have a material adverse impact on our financial condition, prospects, and results of operations if such additional permitting requirements are imposed upon our industry. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could reduce demand for our business by making it more difficult or costly for certain customers to perform fracturing to stimulate production from tight formations. 
+National Environmental Policy Act 
+Businesses and operations of our customers that are carried out on federal lands may be subject to the National Environmental Policy Act (“NEPA”), which requires federal agencies, including the U.S. Department of the Interior, to evaluate major agency actions having the potential to significantly impact the human environment. In the course of such evaluations, an agency will evaluate the potential direct, indirect, and cumulative impacts of a proposed project and, if necessary, will prepare a detailed Environmental Impact Statement that must be made available for public review and comment. To the extent that our customers’ current activities, as well as proposed plans, on federal lands require governmental permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects which in turn could reduce demand for our services. 
+Endangered Species Act and Migratory Bird Treaty Act 
+The federal Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or its habitat. The U.S. Fish and Wildlife Service (the “FWS”) must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”), which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit. This prohibition covers most bird species in the U.S. Future implementation of the rules implementing the ESA and the MBTA are uncertain. If our customers were to have areas within their business and operations designated as critical or suitable habitat for a protected species, it could decrease demand for our services and have a material adverse effect on our business. 
+Canadian Laws and Regulations 
+Companies such as us offering oilfield services that include hydraulic fracturing, engineering, and wireline services in the Province of Alberta in Canada are regulated by both the provincial government of Alberta (“Province”) and the federal government of Canada (“Canada”). This includes, but is not limited to, regulation related to environmental protection legislation, climate change legislation, fracking legislation, and legislation related to wildlife. In addition to being regulated by the Province and Canada, oilfield services companies may also be subject to other international, national, and subnational laws, regulations, and policies. 
+Provincial Legislation 
+Oilfield services companies are primarily regulated by provincial governments in Canada. For example, in Alberta, provincial legislation potentially applicable to our Canadian operations includes the Environmental Protection and Enhancement Act, RSA 2000, e E-12. This Act promotes the protection, enhancement and wise use of the environment, and deals with matters such as air emissions, water discharges, and the handling of hazardous substances and waste control (for example, under the Waste Control Regulation, Alta Reg 192/1996). 
+Other potentially applicable provincial legislation in Alberta includes legislation directed at the transportation of dangerous goods, including oil (the Dangerous Goods Transportation and Handling Act, RSA 2000, c D-4 and associated regulations), legislation intended to provide for the responsible management of oil wells and associated sites (the Oil and Gas 
+8 
+Conservation Act, RSA 2000, c O-6), legislation establishing regulatory bodies overseeing oil and gas and electricity in Alberta (the Responsible Energy Development Act, SA 2012, c R-17.3 and the Alberta Utilities Commission Act, SA 2007, c A-37.2), legislation governing the removal of gas or propane from Alberta (the Gas Resources Preservation Act, RSA 2000, c G-4), legislation to effect conservation and prevent waste of the oil sands resource in Alberta (the Oil Sands Conservation Act, RSA 2000, c O-7) and legislation governing worker safety (the Occupational Health and Safety Act, SA 2017, c O-2.1). 
+The Alberta Energy Regulator has a number directives that are applicable to oilfield services companies, such as Directive 050 which addresses salinity ranges for soils that can receive drilling wastes, and Directive 058, which sets out regulatory requirements for the handling, treatment, and disposal of upstream oilfield waste. Other provinces in Canada have their own statutory regime applicable to oilfield service companies. 
+Federal Legislation 
+The Federal government in Canada shares certain jurisdiction with the provinces over certain environmental matters. Federal legislation potentially applicable to our Canadian operations includes legislation focused on regulating greenhouse gases (the Greenhouse Gas Pollution Pricing Act, SC 2018, c 12, s 186), legislation aimed at protecting wildlife (the Species at Risk Act, SC 2002, c 29), legislation governing approvals for projects (the Impact Assessment Act, SC 2019, c 28, s 1), and legislation governing the transportation of potentially dangerous substances (the Transportation of Dangerous Goods Act, 1992, SC 1992, c 34). 
+Properties 
+Properties 
+Our corporate headquarters are located at 950 17 th Street, Suite 2400, Denver, Colorado 80202. We lease our general office space at our corporate headquarters. The lease expires in December 2027. We currently own or lease the following additional principal properties: 
+District Facility Location Size Leased or Owned 
+Midland, TX 160,000 sq. ft on 147 acres Owned 
+Odessa, TX 77,500 sq. ft on 47 acres Owned 
+Cibolo, TX 90,000 sq. ft on 34 acres Owned 
+Kermit, TX 5,000 acres Owned 
+Monahans, TX 3,200 acres Owned 
+Magnolia, TX 63,350 sq. ft. Leased (through May 31, 2031) 
+Shreveport, LA 225,000 sq ft. on 50 acres Owned 
+Cheyenne, WY 115,000 sq. ft on 60 acres Owned 
+Gillette, WY 32,757 sq. ft on 15 acres Leased (through December 31, 2034) 
+Henderson, CO 50,000 sq. ft on 13 acres Leased (through December 31, 2034) 
+Henderson, CO 96,582 sq. ft on 12 acres Owned 
+Williston, ND 30,000 sq. ft on 15 acres Owned 
+El Reno, OK 80,000 sq. ft on 33 acres Owned 
+Red Deer, AB 170,000 sq. ft on 42 acres Owned 
+Grand Prairie, AB 135,000 sq. ft on 40 acres Owned 
+Huallen, AB 80 acres Owned 
+9 
+We also lease several smaller facilities, which leases generally have terms of one to six years. We believe that our existing facilities are adequate for our operations and their locations allow us to efficiently serve our customers. We do not believe that any single facility is material to our operations and, if necessary, we could readily obtain a replacement facility. 
+Marketing and Customers 
+We have developed long-term partnerships with our customers through a continuous dialogue focused on their production economics. Further, we have a proven track record of executing our customers’ plans and delivering on time and in line with expected costs. Our customer base includes a broad range of integrated and independent E&P companies, including some of the largest E&P companies in our areas of operation such as Occidental Petroleum Corp, ConocoPhillips Company and ExxonMobil. We believe our customer relationships enabled us to maintain higher utilization than many of our competitors during the downturn resulting from the COVID-19 pandemic. Our technological innovations, customer-tailored approach and track record of consistently providing high-quality, safe and reliable service has allowed us to develop long-term customer partnerships, which we believe makes us the service provider of choice for many of our customers. 
+Our sales and marketing activities typically are performed through our local sales representatives in each geographic region, and are supported by our corporate headquarters. For the years ended December 31, 2021, 2020 and 2019, our top five customers collectively accounted for approximatel y 27% , 48%, and 35% of our revenues, respectively. For the years ended December 31, 2021 and 2019, no customer accounted for more than 10% of our revenues. For the year ended December 31, 2020, PDC Energy Inc., WPX Energy, Conoco-Phillips Company, and Parsley Energy Operations, LLC each accounted for more than 10% of our revenues. 
+Suppliers and Raw Materials 
+We have a dedicated supply chain team that manages sourcing and logistics to ensure flexibility and continuity of supply in a cost effective manner across our areas of operation. We have built long-term relationships with multiple industry leading suppliers of proppant, chemicals and hydraulic fracturing equipment and have started to internally design and assemble key pump and maintenance parts. In addition, we have built a strong relationship with the assemblers of our custom-designed hydraulic fracturing fleets and believe we will continue to have timely access to new, high capability fleets as we continue to grow. In 2018, we vertically integrated a supplier of certain major components through the acquisition of ST9 Gas and Oil LLC. In October 2021, we vertically integrated a supplier of our containerized sand and last mile proppant logistics solutions with the acquisition of PropX. 
+We purchase a wide variety of raw materials, parts and components that are manufactured and supplied for our operations. We are not dependent on any single source of supply for those parts, supplies or materials. To date, we have generally been able to obtain the equipment, parts and supplies necessary to support our operations, although we have experienced delivery delays and shortages on some items. While we believe that we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers, we may not always be able to do so. In addition, certain materials for which we do not currently have long-term supply agreements could experience shortages and significant price increases in the future. As a result, we may be unable to mitigate any future supply shortages and our results of operations, prospects and financial condition could be adversely affected. The OneStim Acquisition included two state-of-the-art sand mines in the Permian Basin, which helps alleviate the risk of proppant supply shortages. 
+Competition 
+The markets in which we operate are highly competitive. We provide services in various geographic regions across the United States and Canada, and our competitors include many large and small oilfield service providers, including some of the largest integrated service companies. Our hydraulic fracturing services compete with large, integrated companies such as Halliburton Company as well as other companies including Calfrac Well Services Ltd., FTS International, Inc., NexTier Oilfield Solutions Inc., Universal Pressure Pumping, Inc., ProPetro Services, Inc., RPC, Inc., STEP Energy Services and U.S. Well Services, Inc. In addition, our industry is highly fragmented and we compete regionally with a significant number of smaller service providers. 
+We believe that the principal competitive factors in the markets we serve are technical expertise, equipment capacity, work force competency, efficiency, safety record, reputation, experience and price. Additionally, projects are often awarded on a bid basis, which tends to create a highly competitive environment. We seek to differentiate ourselves from our competitors by delivering the highest-quality services and equipment possible, coupled with superior execution and operating efficiency in a safe working environment. 
+10 
+Available Information 
+We file or furnish annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The SEC also maintains an internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC. 
+We also make available free of charge through our website, www.libertyfrac.com, electronic copies of certain documents that we file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. 
+11
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diff --git a/raw/filings/0001694028/2021/0001694028-22-000006/item13.txt b/raw/filings/0001694028/2021/0001694028-22-000006/item13.txt
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@@ -0,0 +1,2 @@
+Item 13. Certain Relationships and Related Transactions, and Director Independence 
+The information required by this item concerning certain relationships and related person transactions and director independence is incorporated herein by reference to our definitive proxy statement for our 2022 annual meeting of stockholders, which will be filed with the SEC no later than 120 days after December 31, 2021, under the captions “Certain Relationships and Related Party Transactions” and “the Board and its Committees.”
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diff --git a/raw/filings/0001694028/2021/0001694028-22-000006/item9a.txt b/raw/filings/0001694028/2021/0001694028-22-000006/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..da85d63f7f9ca8defc492779f760e661c267aebd
--- /dev/null
+++ b/raw/filings/0001694028/2021/0001694028-22-000006/item9a.txt
@@ -0,0 +1,5 @@
+Item 9A. Controls and Procedures 
+Evaluation of Disclosure Controls and Procedures’ 
+In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2021 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures. 
+As noted in Management’s Report on Internal Control Over Financial Reporting, management’s evaluation of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of the entities acquired in the PropX Acquisition, as defined herein, on October 26, 2021. Under guidelines established by the SEC, companies are permitted to exclude acquisitions from their assessment of internal control over financial reporting during the first year of an acquisition while integrating the acquired company. The Company is in the process of integrating PropX’s and our internal controls over financial reporting. As a result of these integration activities, certain controls will be evaluated and may be changed. Except as noted above, there were no changes to our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+See page F-1 for Management’s Report on Internal Control Over Financial Reporting and page F-4 for Report of Independent Registered Public Accounting Firm on its assessment of our internal control over financial reporting.
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diff --git a/raw/filings/0001694028/2021/0001694028-22-000006/rp_note.txt b/raw/filings/0001694028/2021/0001694028-22-000006/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..a88f3921c9e235475512c96c4b8842ac91a3525b
--- /dev/null
+++ b/raw/filings/0001694028/2021/0001694028-22-000006/rp_note.txt
@@ -0,0 +1,15 @@
+Note 14— Related Party Transactions 
+As of December 31, 2021 Schlumberger owns 56,826,134 shares of Class A Common Stock of the Company, or approximately 30.5 % of the issued and outstanding shares of common stock of the Company, including Class A Common Stock and Class B Common Stock. Under the Transaction agreement, to the extent the net working capital, as defined in the Transaction Agreement, of the Transferred Business is less than $ 54.6 million, the difference shall be payable in cash to the Company. As of December 31, 2020, the Company recorded a receivable from Schlumberger of $ 24.7 million for the working capital settlement and an agreed upon $ 8.0 million true-up payment related to the estimated costs to bring certain assets to full working condition, which was collected during the three months ended March 31, 2021. During the three months ended September 30, 2021, the Company agreed on a working capital settlement from Schlumberger of $ 15.8 million, most of which was netted against transaction services costs and cash settlements during the transition services period. In conjunction with closing the OneStim Acquisition, the Company entered into a transition services agreement with Schlumberger, under which Schlumberger provides certain administrative and other transition services until the Company fully integrates the acquired business. During the year ended December 31, 2021, the Company incurred $ 5.7 million of fees for such transaction services. The Company does not expect to incur any additional transition services related fees in future periods. 
+During the year ended December 31, 2021, a subsidiary of the Company and Schlumberger entered into a property swap agreement under which the Company exchanged with Schlumberger a property acquired in the OneStim Acquisition and $ 4.9 million in cash for a separate property that the Company will utilize with its existing operations. The Company did not recognize any gain or loss on the transaction. In a separate transaction, the Company sold equipment to Schlumberger for $ 1.3 million and recognized a gain on the sale of equipment of $ 0.9 million. 
+Following the OneStim Acquisition, in the normal course of business, the Company purchases chemicals, proppant and other equipment and maintenance parts from Schlumberger and its subsidiaries. During the year ended December 31, 2021, total purchases from Schlumberger were approximately $ 28.2 million, and as of December 31, 2021 amounts due to Schlumberger were $ 2.7 million and $ 1.1 million included in accounts payable and accrued liabilities, respectively, in the consolidated balance sheet. 
+On June 7, 2021 R/C Energy IV Direct Partnership, L.P., a Delaware limited partnership (“R/C Direct”) and R/C Liberty entered into an underwriting agreement, dated as of June 7, 2021, by and among the Company, Liberty LLC, R/C Direct, R/C Liberty and Morgan Stanley & Co. LLC, pursuant to which R/C Direct sold 3,707,187 shares of Class A Common Stock and R/C Liberty sold 8,592,809 shares of Class A Common Stock, at a price of $ 15.20 per share, to the underwriter (the “Sale”). In connection with the Sale, 6,918,142 shares of Class B Common Stock held by R/C Liberty were redeemed by the Company for an equal amount of Class A Common Stock. On June 10, 2021, the Sale closed. Following the Sale, R/C Direct and R/C Liberty no longer hold any Class A Common Stock or Class B Common Stock and are no longer considered related parties of the Company. 
+Prior to the Sale, R/C IV Liberty Holdings, L.P. (“R/C Liberty”) exercised its redemption right and redeemed 10,269,457 shares of Class B Common Stock resulting in an increase in tax basis, as described under “Tax Receivable Agreements” in Note—12 Income Taxes, which was subsequently offset by an increase in valuation allowance during the year ended December 31, 2021. During the year ended December 31, 2020, R/C Liberty exercised its redemption right and redeemed 4,016,965 shares of Class B Common Stock resulting in the recognition of $ 6.1 million in amounts payable under the TRAs. 
+Effective on June 15, 2021, Audrey Robertson was appointed to the board of directors of Liberty Oilfield Services Inc. Ms. Robertson serves as the Chief Financial Officer of Franklin Mountain Energy, LLC (“Franklin Mountain”). During the year ended December 31, 2021 the Company performed hydraulic fracturing services for Franklin Mountain in the amount of $ 20.5 million or 0.8 % of the Company’s revenues for such period. Receivables from Franklin Mountain as of December 31, 2021 were $ 0.0 million . 
+Liberty Resources LLC, an oil and gas exploration and production company, and its successor entity (collectively, the “Affiliate”) has certain common ownership and management with the Company. The amounts of the Company’s revenue 
+F-31 
+LIBERTY OILFIELD SERVICES INC. 
+Notes to Consolidated Financial Statements 
+related to hydraulic fracturing services provided to the Affiliate for the years ended December 31, 2021, 2020 and 2019, were $ 2.8 million, $ 0.0 million and $ 18.3 million, respectively. 
+As of December 31, 2021 and 2020, there were no receivables within the Company’s accounts receivable—related party line item attributable to the Affiliate. On June 24, 2019 (the “Agreement Date”), the Company entered into an agreement with the Affiliate to amend payment terms for outstanding invoices due as of the Agreement Date to be due on July 31, 2020. On September 30, 2019, the agreement was amended to extend the due date of the remaining amounts outstanding to October 31, 2020. Amounts outstanding from the Affiliate as of the Agreement Date were $ 15.6 million. The amounts outstanding, including all accrued interest was paid in full in January 2020. As of December 31, 2021 and December 31, 2020, no amounts were outstanding under the amended payment terms from the Affiliate. During the years ended December 31, 2021, 2020 and 2019, interest income from the Affiliate was $ 0.0 million , $ 0.3 million and $ 1.8 million, respectively. Receivables earned for services performed after the Agreement Date continue to be subject to normal 30-day payment terms, provided that any amount unpaid after 60 days is subject to 13 % interest. 
+During 2016, Liberty Holdings entered into a future commitment to invest and become a non-controlling minority member in Proppant Express Investments, LLC, the owner of Proppant Express Solutions, LLC (“PropX”), a provider of proppant logistics equipment. LOS is party to a services agreement (the “PropX Services Agreement”) whereby LOS is to provide certain administrative support functions to PropX, and LOS is to purchase and lease proppant logistics equipment from PropX. The PropX Services Agreement was terminated on May 29, 2018; however, the Company continues to lease equipment from PropX. Effective October 26, 2021, the Company completed the purchase of all membership interest in PropX, refer to Note 3—Acquisitions for further discussion of the transaction. During the period from January 1, 2021 until October 26, 2021, the Company leased proppant logistics equipment from PropX for $ 7.3 million. During the years ended December 31, 2020 and 2019 the Company leased proppant logistics equipment from PropX for $ 8.7 million and $ 9.8 million, respectively. Payables to PropX as of December 31, 2020 were $ 1.5 million. 
+R/C IV Liberty Big Box Holdings, L.P., a Riverstone Holdings LLC (“Riverstone”) fund and a former significant stockholder of the Company, held a greater than 10 % equity interest in PropX. Christopher Wright, the Chief Executive Officer, Michael Stock, the Chief Financial Officer and Ron Gusek, the President of the Company, held a less than 5 % equity interest in PropX through Big Box Proppant Investments LLC. Cary Steinbeck, a director of the Company, served on the PropX board of the directors and held a less than 5 % indirect equity interest in PropX. In addition, Brett Staffieri, a Riverstone appointed director, served on the board of the directors of the Company until June 15, 2021 and on the PropX board of directors until the acquisition date. The PropX Acquisition was reviewed and approved by the disinterested members of the Board and pursuant to the Company’s related party transactions policy.
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diff --git a/raw/filings/0001694028/2021/0001694028-22-000006/rpt_disclosure.txt b/raw/filings/0001694028/2021/0001694028-22-000006/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..88361878840104eb464d7592fd88e0f3d7cddc3b
--- /dev/null
+++ b/raw/filings/0001694028/2021/0001694028-22-000006/rpt_disclosure.txt
@@ -0,0 +1,70 @@
+CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS 
+Policies and Procedures for Review of Related Party Transactions 
+A “ Related Party Transaction ” is a transaction, arrangement or relationship in which the Company or any of its subsidiaries was, is or will be a participant, the amount of which involved exceeds $120,000, and in which any related person had, has or will have a direct or indirect material interest. A “ Related Person ” is: 
+♦ any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors; 
+♦ any person who is known by us to be the beneficial owner of more than 5% of our Class A Common Stock; 
+♦ any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, executive officer or a beneficial owner of more than 5% of our Class A Common Stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5% of our Class A Common Stock; and 
+♦ any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10.0% or greater beneficial ownership interest. 
+Our Board adopted a written related party transactions policy in connection with the IPO. Pursuant to this policy, our Audit Committee reviews all material facts of all Related Party Transactions and either approves or disapproves entry into the Related Party Transaction, subject to certain limited exceptions. The determination of the Audit Committee is documented in the Audit Committee’s minutes. In determining whether to approve or disapprove entry into a Related Party Transaction, our Audit Committee takes into account, among other factors, the following: (i) whether the Related Party Transaction is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances and (ii) the extent of the Related Person’s interest in the transaction. Furthermore, the policy requires that all Related Party Transactions required to be disclosed in our filings with the SEC be so disclosed in accordance with applicable laws, rules and regulations. 
+Related Party Transactions 
+The following is a description of transactions entered into, or in effect, after January 1, 2021 to which we have been a party, in which the amount involved in the transaction exceeds $120,000, and in which any of our directors, executive officers or beneficial owners of more than 5% of our voting securities, or affiliates or immediate family members of any of our directors, executive officers or beneficial owners of more than 5% of our voting securities, had or will have a direct or indirect material interest. We believe the terms obtained or consideration that we paid or received, as applicable, in connection with the transactions described below were comparable to terms available or the amounts that would be paid or received, as applicable, from unrelated third parties. 
+Liberty LLC Agreement 
+We entered into the Second Amended and Restated Limited Liability Company Agreement of Liberty Oilfield Services New HoldCo LLC (“ Liberty LLC ”) (the “ Liberty LLC Agreement ”) in connection with the closing of our IPO, which provides for limitations on the ability of holders of units of Liberty LLC (the “ Liberty LLC Units, ” and the holders of Liberty LLC Units “ Liberty Unit Holders ”) to transfer their Liberty LLC Units and provides the Company, as managing member of Liberty LLC, with the right to impose restrictions (in addition to those already in place) on the ability of Liberty Unit Holders to redeem their Liberty LLC Units pursuant to the Redemption Right (as defined below) to the extent the Company believes it is necessary to ensure that Liberty LLC will continue to be treated as a partnership for U.S. federal income tax purposes. 
+Redemption Rights 
+Under the Liberty LLC Agreement, each Liberty Unit Holder has, subject to certain limitations, the right (the “ Redemption Right ”) to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units for, at Liberty LLC’s election, (i) shares of our Class A Common Stock at a redemption ratio of one share of Class A Common Stock for each Liberty LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions or (ii) an equivalent amount of cash. Alternatively, upon the exercise of the Redemption Right, the Company (instead of Liberty LLC) has the right (the “ Call Right ”) to, for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder for, at the Company’s election, (x) one share of Class A Common Stock or (y) an equivalent amount of cash. In addition, upon a change of control of the Company, the Company has the right to require each holder of Liberty LLC Units (other than the Company) to exercise its Redemption Right with respect to some or all of such unit holder’s Liberty LLC Units. In connection with any redemption of Liberty LLC Units pursuant to the Redemption Right or the Call Right, the corresponding number of shares of Class B Common Stock will be 
+42 
+cancelled. As the Liberty Unit Holders redeem their Liberty LLC Units, our membership interest in Liberty LLC will be correspondingly increased, the number of shares of Class A Common Stock outstanding will be increased, and the number of shares of Class B Common Stock outstanding will be reduced. 
+Distributions and Allocations 
+Under the Liberty LLC Agreement, the Company has the right to determine when distributions will be made to the holders of Liberty LLC Units and the amount of any such distributions. If the Company authorizes a distribution, such distribution will be made to the holders of Liberty LLC Units generally on a pro rata basis in accordance with their respective percentage ownership of Liberty LLC Units. 
+Liberty LLC will allocate its net income or net loss for each year to the holders of Liberty LLC Units pursuant to the terms of the Liberty LLC Agreement, and the holders of Liberty LLC Units, including the Company, will generally incur U.S. federal, state and local income taxes on their share of any taxable income of Liberty LLC. Net income and losses of Liberty LLC generally will be allocated to the holders of Liberty LLC Units on a pro rata basis in accordance with their respective percentage ownership of Liberty LLC Units, subject to requirements under U.S. federal income tax law that certain items of income, gain, loss or deduction be allocated disproportionately in certain circumstances. To the extent Liberty LLC has available cash and subject to the terms of any debt instruments, the Company intends to cause Liberty LLC to make (i) generally pro rata distributions to the holders of Liberty LLC Units, including the Company, in an amount sufficient to allow the Company to pay its taxes and to allow it to make payments under the Tax Receivable Agreements (as defined below), (ii) tax advances, which will be repaid upon exercise of the Redemption Right or the Call Right, as applicable, in an amount sufficient to allow each of the Liberty Unit Holders to pay its respective taxes on such holder’s allocable share of Liberty LLC’s taxable income after taking into account certain other distributions or payments received by the Liberty Unit Holders from Liberty LLC or the Company, and (iii) non-pro rata payments to the Company to reimburse it for its corporate and other overhead expenses. 
+Issuance of Equity 
+The Liberty LLC Agreement generally provides that at any time the Company issues a share of its Class A Common Stock or any other equity security, the net proceeds received by the Company with respect to such issuance, if any, shall be concurrently invested in Liberty LLC, and Liberty LLC shall issue to the Company one Liberty LLC Unit or other economically equivalent equity interest. Conversely, if at any time, any shares of Class A Common Stock are redeemed, repurchased or otherwise acquired, Liberty LLC shall redeem, repurchase or otherwise acquire an equal number of Liberty LLC Units held by the Company, upon the same terms and for the same price, as the shares of the Class A Common Stock are redeemed, repurchased or otherwise acquired. 
+Dissolution 
+Liberty LLC will be dissolved only upon the first to occur of (i) the sale of substantially all of its assets or (ii) an election by us to dissolve the company. Upon dissolution, Liberty LLC will be liquidated and the proceeds from any liquidation will be applied and distributed in the following manner: (i) first, to creditors (including to the extent permitted by law, creditors who are members) in satisfaction of the liabilities of Liberty LLC; (ii) second, to establish cash reserves for contingent or unforeseen liabilities; and (iii) third, to the members in proportion to the number of Liberty LLC Units owned by each of them. 
+Tax Receivable Agreements 
+In connection with the IPO, on January 17, 2018, the Company entered into two tax receivable agreements, (the “ TRAs ”) with the Liberty Unit Holders and the selling stockholder (each such person and any permitted transferee, a “ TRA Holder ” and together, the “ TRA Holders ”). The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that the Company actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result, as applicable to each TRA Holder, of (i) certain increases in tax basis that occur as a result of the Company’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holder’s Liberty LLC Units in connection with the IPO or pursuant to the exercise of the Redemption Right or the Call Right, (ii) any net operating losses available to the Company as a result of the corporate reorganization, and (iii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRAs. For the year ended December 31, 2020, the Company made TRA payments of $1.9 million and $5.5 million, totaling $7.4 million. These TRA payments were related to tax benefits realized in prior years and for the Company’s carryback of 2019 net operating losses to 2018 taxable income under the CARES Act. 
+Schlumberger 
+Master Transaction Agreement 
+On August 31, 2020, the Company, entered into a Master Transaction Agreement (the “ MTA ”) with Schlumberger, Schlumberger Canada Limited, (“ Schlumberger Canada ” and, together with Schlumberger, the “ Schlumberger Parties ”), Liberty LLC, and LOS Canada Operations Inc. (“ Canadian Buyer ”), pursuant to which the Liberty LLC and Canadian Buyer acquired the Schlumberger Parties’ 
+43 
+OneStim business in exchange for 57,377,232 shares of Class A Common Stock and a non-interest bearing demand promissory note, which note was satisfied with 8,948,902 shares of Class A Common Stock, resulting in a total of 66,326,134 shares of Class A Common Stock being issued in connection with the transaction. The Schlumberger Parties are affiliated with Messrs. Ayat and McDonald, who are on our Board. The transactions contemplated by the MTA closed on December 31, 2020. 
+Until December 31, 2024, subject to certain exceptions and as more specifically set forth in the MTA, without the prior written consent of the Company, each of Schlumberger and Schlumberger Canada will not, and will cause each of their respective affiliates (including Schlumberger Limited) not to, directly or indirectly engage in any business or enterprise that is competitive with OneStim within onshore United States and Canada. 
+On December 31, 2020, in connection with the closing of the transactions contemplated by the MTA, the Company (and/or one or more of its subsidiaries) and the Schlumberger Parties entered into the following agreements, each of which may involve amounts in excess of $120,000: (i) an intellectual property license agreement, whereby the Schlumberger Parties granted to Liberty LLC and the Company exclusive and non-exclusive licenses to certain intellectual property, and Liberty LLC granted to the Schlumberger Parties a non-exclusive license to certain patents acquired by Liberty LLC under the MTA; (ii) an employee matters agreement, pursuant to which the applicable Schlumberger Party agreed to lease employees to the Company or a subsidiary of the Company until March 1, 2021, subject to certain exceptions and extensions; (iii) an alliance agreement whereby Schlumberger and Liberty LLC agreed to collaborate to advance each of their product portfolios and technology offerings; (iv) a transition services agreement whereby Schlumberger or its designee agreed to provide certain back-office, administrative, field operations, supply chain and other specified services to the Company until March 1, 2021, subject to certain exceptions and extensions; and (v) a strategic supply agreement intended to provide the Company with an opportunity to purchase from the various business lines of Schlumberger, products and services with competitive pricing terms for a term not to exceed the term of the non-compete covenant in the MTA discussed above. 
+Amended and Restated Stockholders Agreement 
+In connection with the OneStim Acquisition, we entered into an amended and restated stockholders agreement with affiliates of Riverstone, and the Schlumberger Parties. Among other things, the amended and restated stockholders agreement provides the right to designate nominees to our Board as follows: 
+• so long as the Schlumberger Parties and its affiliates collectively beneficially own at least 20% of the outstanding shares of our Common Stock, the Schlumberger Parties can designate up to two (2) nominees to our Board; and 
+• so long as the Schlumberger Parties and their affiliates collectively beneficially own at least 10% of the outstanding shares of our Common Stock, the Schlumberger Parties can designate up to one (1) nominee to our Board. 
+Pursuant to the amended and restated stockholders agreement, the Schlumberger Parties will not, (i) for a period of nine months from the closing of the OneStim Acquisition, transfer or dispose of (or take other analogous actions in accordance with the terms of the agreement) any economic, voting or other rights in or to their issued shares, other than certain permitted transfers and, (ii) for a period of four years from the closing of the OneStim Acquisition, make any transfer of Common Stock to any direct competitor of the Company or to any person that is subject to, or by virtue of such transfer would become subject to, the reporting obligations under Schedule 13D under the Exchange Act, with respect to Common Stock (the “ Lock-Up and Transfer Restrictions ”). 
+Pursuant to the amended and restated stockholders agreement, the Schlumberger Parties and their affiliates are subject to customary standstill restrictions in accordance with which such parties will agree not to, among other things, acquire beneficial ownership of any equity securities of the Company or publicly seek or encourage any offer or proposal for a merger or similar transaction involving the Company during the period commencing on the date of the agreement and continuing until the fourth anniversary of the closing of the OneStim Acquisition (the “ Standstill ”). 
+Pursuant to the amended and restated stockholders agreement, we will be required to take all necessary actions, to the fullest extent permitted by applicable law (including with respect to any fiduciary duties under Delaware law), to cause the election of the nominees designated by either the Riverstone affiliates or the Schlumberger Parties. At any time the members of our Board are allocated among separate classes of directors, (i) the directors designated by the Riverstone affiliates pursuant to the amended and restated stockholders agreement will be to the classes as mutually agreed between us and the Riverstone affiliates, and (ii) the directors designated by the Schlumberger Parties pursuant to the amended and restated stockholders agreement will be to the classes as mutually agreed between us and the Schlumberger Parties. The Riverstone affiliates will be entitled to designate the replacement for any of its Board designees whose service terminates prior to the end of such director’s term. The Schlumberger Parties will be entitled to designate the replacement for any of its Board designees whose service terminates prior to the end of such director’s term. 
+The amended and restated stockholders agreement will terminate with respect to the Schlumberger Parties at the earliest of (a) such time as the Schlumberger Parties no longer beneficially own at least 10% of the outstanding shares of Common Stock and are no longer subject to the Standstill and the Lock-Up and Transfer Restrictions, (b) such time as the Schlumberger Parties do not beneficially own 
+44 
+any shares of Common Stock, and (c) the written agreement of the Schlumberger Parties and the Company terminating the agreement. The amended and restated stockholders agreement will terminate with respect to Riverstone at the earliest of (i) such time as Riverstone and its affiliates no longer beneficially own at least 10% of the outstanding shares of Common Stock, and (ii) the delivery of written notice to the Company by Riverstone of the termination of the agreement with respect to Riverstone. 
+Amended and Restated Registration Rights Agreement 
+In connection with the OneStim Acquisition, we entered into an amended and restated registration rights agreement with Schlumberger, Schlumberger Canada and each of the other holders identified therein (the “ Holders ”), pursuant to which, among other things, certain Holders, including affiliates of Riverstone, Schlumberger and Schlumberger Canada (the “ Sponsoring Holders ”), have customary demand registration rights and we are obligated to prepare and file a registration statement registering the offer and sale of all of Schlumberger and Schlumberger Canada’s shares of Class A Common Stock. In addition, pursuant to this agreement, the Sponsoring Holders have the right to require us, subject to certain limitations set forth therein, to effect a distribution of any or all of their shares of Class A Common Stock by means of an underwritten offering. We are not obligated to effect any underwritten offering unless the dollar amount of the registrable securities of the Sponsoring Holder(s) demanding such underwritten offering to be included therein is reasonably likely to result in gross sale proceeds of at least $25 million. The amended and restated registration rights agreement also provides Holders with certain customary piggyback registration rights. These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a registration or offering and the Company’s right to delay or withdraw a registration statement under certain circumstances. 
+Property Swap 
+During 2021, a subsidiary of the Company and Schlumberger entered into a property swap agreement under which the Company exchanged with Schlumberger a property acquired in the OneStim Acquisition and $4.9 million in cash for a separate property that the Company has utilized with its existing operations. 
+Working Capital Settlement 
+Under the MTA, to the extent the net working capital, as defined therein, of the transferred OneStim business is less than $54.6 million, the difference shall be payable in cash to the Company. In 2021, the Company agreed on a working capital settlement from Schlumberger of $15.8 million, most of which was netted against transaction services costs and cash settlements during the transition services period. 
+Purchase of Chemicals, Proppant and Equipment 
+Following the OneStim Acquisition, in the normal course of business, the Company purchases chemicals, proppant and other equipment and maintenance parts from Schlumberger and its subsidiaries. For the year ended December 31, 2021, total purchases from Schlumberger were approximately $28.2 million, and as of December 31, 2021, amounts due to Schlumberger were $3.8 million. 
+Underwriting Agreement 
+On February 8, 2021, the Company, R/C Energy IV Direct Partnership, L.P. and R/C IV Liberty Holdings, L.P. (together, the “ Riverstone Affiliates ”) and Morgan Stanley & Co. LLC (the “ Underwriter ”), entered into an underwriting agreement (the “ Underwriting Agreement ”), pursuant to which the Riverstone Affiliates agreed to sell to the Underwriter, and the Underwriter agreed to purchase from the Riverstone Affiliates, subject to and upon the terms and conditions set forth therein, an aggregate of 8,700,000 shares of Class A Common Stock of the Company (the “ Offering ”). The Offering closed on February 11, 2021. Pursuant to the Underwriting Agreement, the Riverstone Affiliates also granted the Underwriter a 30-day option to purchase from the Riverstone Affiliates up to 1,305,000 additional shares of Class A Common Stock at the public offering price, less the underwriting discount. The Company will not receive any proceeds from the sale of shares of Class A Common Stock in the Offering. The Underwriting Agreement contains customary representations, warranties and agreements of the Company and the Riverstone Affiliates and other customary obligations of the parties and termination provisions. 
+Transactions with Liberty Resources 
+Liberty Resources LLC (“ Liberty Resources ”) is an oil and gas exploration and production company of which Mr. Wright is the Executive Chairman. Mr. Wright previously served as the Chief Executive Officer at Liberty Resources from its formation in September 2010 until March 2017. Liberty Resources entered into a master service agreement with Liberty Oilfield Services LLC, a subsidiary of the Company (“ Liberty Services ”), whereby Liberty Services provides hydraulic fracturing service to Liberty Resources at market service rates. For the year ended December 31, 2021, the amounts related to the provision of hydraulic fracturing services to Liberty Resources under the master services agreement was $2.8 million. 
+45 
+Transactions with Franklin Mountain 
+Franklin Mountain Energy LLC (“ Franklin Mountain ”) is an oil and gas exploration and production company of which Ms. Robertson serves as the Chief Financial Officer. Franklin Mountain entered into a master service agreement with Liberty Services, whereby Liberty Services provides hydraulic fracturing service to Franklin Mountain at market service rates. For the year ended December 31, 2021, the amounts related to the provision of hydraulic fracturing services to Franklin Mountain under the master services agreement was $20.5 million or 0.8% of the Company’s revenues for such period. 
+Transactions with PropX 
+Liberty Services currently leases equipment from Proppant Express Solutions, LLC (“ PropX ”), a provider of proppant logistics equipment. Liberty Services acquired PropX in October of 2021 (the “ PropX Acquisition ”), resulting in PropX now being a wholly-owned subsidiary of Liberty Services. R/C IV Liberty Big Box Holdings, L.P., a Riverstone fund and a former significant stockholder of the Company, held a greater than 10% equity interest in PropX. Christopher A. Wright, the Chief Executive Officer, Michael Stock, the Chief Financial Officer and Ron Gusek, the President of the Company, held a less than 5% equity interest in PropX through Big Box Proppant Investments LLC. Cary Steinbeck, a director of the Company, served on the PropX Board and held a less than 5% indirect equity interest in PropX. In addition, Brett Staffieri, a Riverstone appointed director, served on the Board of the Company until June 15, 2021 and on the PropX board of directors until the PropX Acquisition. The PropX Acquisition was reviewed and approved by the disinterested members of the Board and pursuant to the Company’s related party transactions policy. From January 1, 2021 through the PropX Acquisition date, Liberty Services paid PropX $7.3 million for the lease of proppant logistics equipment. In connection with the PropX Acquisition, each of the sellers and certain of their investors that received Liberty LLC units, entered into a joinder to the Liberty LLC Agreement. See “ Certain Relationships and Related Person Transactions – Liberty LLC Agreement ” above for a description of the material terms of the Liberty LLC Agreement. 
+Transactions with Tim Babcock 
+Tim Babcock is currently employed at ST9 Gas and Oil LLC, a wholly-owned subsidiary of Liberty Services (“ ST9 ”) as a key account manager. Tim Babcock is the son of Ken Babcock, who serves on the Board. For the year ended December 31, 2021, ST9 paid Tim Babcock $121,772.92. 
+Indemnification for Officers and Directors 
+Our Amended and Restated Certificate of Incorporation and Amended and Restated Bylaws provide indemnification rights to our directors and officers and permit us to purchase insurance on behalf of any officer, director, employee or other agent for any liability arising out of that person’s actions as our officer, director, employee or agent, regardless of whether Delaware law would mandate indemnification. Additionally, we have entered into separate indemnity agreements with our directors and officers to provide additional indemnification benefits, including the right to receive, in advance, reimbursements for expenses incurred in connection with a defense for which the director or officer is entitled to indemnification. We believe that the limitation of liability provisions in our certificate of incorporation, bylaws and the indemnity agreements will facilitate our ability to continue to attract and retain qualified individuals to serve as directors and officers. 
+Conflicts of Interest 
+The related party transactions described herein may cause certain conflicts of interests, including that: 
+♦ we may enter into contracts between us, on the one hand, and related parties, on the other, that are not as a result of arm’s-length transactions; 
+♦ our executive officers and directors that hold positions of responsibility with related parties may be aware of certain business opportunities that are appropriate for presentation to us as well as to such other related parties and may present such business opportunities to such other parties; and 
+♦ our executive officers and directors that hold positions of responsibility with related parties may have significant duties with, and spend significant time serving, other entities and may have conflicts of interest in allocating time. 
+For example, Mr. Wright, our Chief Executive Officer, is the Executive Chairman of Liberty Resources, a position which may require a portion of his time and which may cause conflicts of interest in pursuing business opportunities of which he becomes aware. 
+46
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+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+WASHINGTON, D.C. 20549 
+FORM 10-K 
+(Mark One) 
+☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the Fiscal Year Ended December 31 , 2022 
+OR 
+☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+Commission File No. 001-38081 
+Liberty Energy Inc. 
+(Exact Name of Registrant as Specified in its Charter) 
+Delaware 
+81-4891595 
+(State or Other Jurisdiction of Incorporation or Organization) (I.R.S. Employer Identification No.) 
+950 17th Street , Suite 2400 
+Denver , Colorado 
+80202 
+(Address of Principal Executive Offices) (Zip Code) 
+( 303 ) 515-2800 
+(Registrant’s Telephone Number, Including Area Code) 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of each class Trading symbol(s) Name of each exchange on which registered 
+Class A Common Stock, par value $0.01 LBRT New York Stock Exchange 
+Securities registered pursuant to Section 12(g) of the Act: None 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☒ Yes ☐ No 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐ Yes ☒ No 
+Indicate by check mark whether the registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No 
+Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this Chapter) during the presiding 12 months (or for such shorter period that the registrant was required to submit and post such files). ☒ Yes ☐ No 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. 
+Large Accelerated Filer ☒ 
+Accelerated Filer ☐ Non-accelerated filer ☐ 
+Smaller reporting company ☐ 
+Emerging growth company ☐ 
+If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ 
+Indicate by check mark whether the registrant has filed a report on an attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act): ☐ Yes ☒ No 
+As of June 30, 2022, the last business day of the registrant ’ s most recently completed second fiscal quarter, the aggregate market value of voting and non-voting common stock held by non-affiliates of the registrant was approximately $ 2.0 billion, determined using the per share closing price on the New York Stock Exchange on that date of $12.76. Shares of common stock held by each director and executive officer (and their respective affiliates) and each person who owns 10 percent or more of the outstanding common stock or who is otherwise believed by the registrant to be in a control position have been excluded. This determination of affiliate status is not necessarily a conclusive determination for other purposes. 
+At February 6, 2023 the Registrant had 176,111,866 shares of Class A Common Stock and 0 shares of Class B Common Stock outstanding. 
+Documents Incorporated by Reference: Part III of this Annual Report on Form 10-K incorporates certain information by reference from the registrant ’ s proxy statement for the 2022 annual meeting of stockholders to be filed no later than 120 days after the end of the registrant ’ s fiscal year. 
+TABLE OF CONTENTS 
+Page No. 
+PART I 
+Item 1. 
+Business 
+1 
+Item 1A. 
+Risk Factors 
+11 
+Item 1B. 
+Unresolved Staff Comments 
+27 
+Item 2. 
+Properties 
+27 
+Item 3. 
+Legal Proceedings 
+27 
+Item 4. 
+Mine Safety Disclosures 
+27 
+PART II 
+Item 5. 
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+28 
+Item 6. 
+[Reserved] 
+28 
+Item 7. 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+32 
+Item 7A. 
+Quantitative and Qualitative Disclosure about Market Risk 
+43 
+Item 8. 
+Financial Statements and Supplementary Data 
+43 
+Item 9. 
+Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+43 
+Item 9A. 
+Controls and Procedures 
+44 
+Item 9B. 
+Other Information 
+44 
+PART III 
+Item 10. 
+Directors, Executive Officers and Corporate Governance 
+45 
+Item 11. 
+Executive Compensation 
+45 
+Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+45 
+Item 13. 
+Certain Relationships and Related Transactions, and Director Independence 
+45 
+Item 14. 
+Principal Accountant Fees and Services 
+45 
+PART IV 
+Item 15. 
+Exhibits and Financial Statement Schedules 
+46 
+Item 16. 
+Form 10-K Summary 
+47 
+SIGNATURES 
+52 
+i 
+CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS 
+This Annual Report on Form 10-K (“Annual Report”) and certain other communications made by us contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange of 1934, as amended (the “Exchange Act”), including statements about our expected growth from recent acquisitions such as the PropX Acquisition (as defined below) and OneStim Acquisition (as defined below), expected performance, future operating results, oil and natural gas demand and prices and the outlook for the oil and gas industry, future global economic conditions, the impact of the Russian invasion of Ukraine, the impacts of the novel strain of the coronavirus (“COVID-19”) pandemic, improvements in operating procedures and technology, our business strategy and the business strategies of our customers, in addition to other estimates, and beliefs. For this purpose, any statement that is not a statement of historical fact should be considered a forward-looking statement. We may use the words “estimate,” “outlook,” “project,” “position,” “potential,” “likely,” “believe,” “anticipate,” “plan,” “expect,” “intend,” “achievable,” “anticipate,” “may,” “will,” “continue,” “should,” “could” and similar expressions to help identify forward-looking statements. However, the absence of these words does not mean that the statements are not forward-looking. We cannot assure you that our assumptions and expectations will prove to be correct. Important factors could cause our actual results to differ materially from those indicated or implied by forward-looking statements, including but not limited to the risks described in this Annual Report and other filings that we make with the U.S. Securities Exchange Commission (the “SEC”). We undertake no intention or obligation to update or revise any forward-looking statements, except as required by law, whether as a result of new information, future events or otherwise and readers should not rely on the forward-looking statements as representing the Company’s views as of any date subsequent to the date of the filing of this Annual Report. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. 
+All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. 
+MARKET AND INDUSTRY DATA 
+This Annual Report includes market and industry data and certain other statistical information based on third-party sources including independent industry publications, government publications and other published independent sources, such as content and estimates provided by Lium, LLC (“Lium Research”) as of December 31, 2022, and industry content and figures provided by Baker Hughes Co. (“Baker Hughes”) as of December 31, 2022. Neither Lium Research nor Baker Hughes is a member of the Financial Industry Regulator Authority or the Securities Investor Protection Corporation and neither is a registered broker dealer or investment advisor. Although we believe these third-party sources are reliable as of their respective dates, we have not independently verified the accuracy or completeness of this information. Some data is also based on our own good faith estimates, which are supported by our management's knowledge of and experience in the markets and business in which we operate. 
+TRADEMARKS, SERVICE MARKS AND TRADENAMES 
+This Annual Report contains trademarks, tradenames, and service marks that are owned by us or other companies, which are our property. Solely for convenience, the trademarks, tradenames, and service marks referred to in this Annual Report may appear without the ® and TM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the rights of the applicable licensors to these trademarks, tradenames, and service marks. We do not intend our use or display of other parties’ trademarks, tradenames, or service marks to imply, and such use or display should not be construed to imply a relationship with, or endorsement or sponsorship of us by, these other parties. 
+ii 
+PART I 
+As used in this Annual Report, except as otherwise indicated or required by the context, all references in this Annual Report to (i) the “Company,” “we,” “us” and “our” refer to Liberty Energy Inc. and its consolidated subsidiaries; (ii) “Liberty LLC” refer to Liberty Oilfield Services New HoldCo LLC; (iii) “Schlumberger” refer to, collectively, Schlumberger Technology Corporation and Schlumberger Canada Limited; and (iv) “PropX” refer to Proppant Solutions, LLC and its predecessor in interest. 
+Item 1. Business 
+Our Company 
+We are a leading integrated energy services and technology company focused on providing innovative hydraulic services and related technologies to onshore oil and natural gas exploration and production (“E&P”) companies in North America. We offer customers hydraulic fracturing services, together with complementary services including wireline services, proppant delivery solutions, data analytics, related goods (including our sand mine operations), and technologies that will facilitate lower emission completions, thereby helping our customers reduce their emissions profile. 
+Our primary locations of operation include the Permian Basin, the Eagle Ford Shale, the Denver-Julesburg Basin (the “DJ Basin”), the Williston Basin, the San Juan Basin, the Powder River Basin, the Haynesville Shale, the South Central Oklahoma Oil Province and Sooner Trend Anadarko Canadian Kingfisher (collectively, the “SCOOP/STACK”), the Marcellus Shale, the Utica Shale, and the Western Canadian Sedimentary Basin, which are among the most active basins in North America. The breadth of our operational footprint provides us an opportunity to leverage our fixed costs and to efficiently reposition our equipment in response to customer requirements. The map below represents our current areas of operation. 
+The process of hydraulic fracturing involves pumping a pressurized stream of fracturing fluid (typically a mixture of water, chemicals and proppant) into a well casing or tubing to cause the underground formation to fracture or crack. These fractures release trapped hydrocarbon particles and provide a conductive channel for the oil or natural gas to flow freely to the wellbore for collection. The propping agent, or proppant, typically sand, becomes lodged in the cracks created by the hydraulic fracturing process, “propping” them open to facilitate the flow of hydrocarbons from the reservoir to the well. The fracturing 
+1 
+fluid is engineered to lose viscosity, or “break,” and is subsequently flowed back from the formation, leaving the proppant suspended in the formation fractures. Once our customer has flushed the fracturing fluids from the well using a controlled flow-back process, the customer manages fluid and water recycling or disposal. 
+Our hydraulic fracturing fleets consist of mobile hydraulic fracturing units and other auxiliary heavy equipment to perform fracturing services. Our hydraulic fracturing units consist primarily of high-pressure hydraulic pumps, engines, transmissions, radiators and other supporting equipment that are typically mounted on trailers. We refer to the group of units and other equipment, such as blenders, data vans, sand storage, tractors, manifolds and high-pressure fracturing iron, which are necessary to perform a typical hydraulic fracturing job, as a “fleet,” and the personnel assigned to each fleet as a “crew.” The size of each fleet and crew can vary depending on the requirements of each job design. 
+We also have wireline operations as a result of the acquisition of Schlumberger’s OneStim business in December 2020, whereby we obtained certain assets and liabilities of the OneStim business including OneStim’s hydraulic fracturing pressure pumping services business in onshore United States and Canada (the “OneStim Acquisition”). Our wireline units consist of a truck equipped with a spool of wireline that is lowered into wells to convey specialized tools or equipment, such as perforating guns and charges, which are necessary to connect the wellbore with the target formation. This operation is performed between each hydraulic fracturing stage. Our wireline service is primarily offered alongside our hydraulic fracturing services, which allows us to maximize efficiency for our customers through optimized coordination of the wireline and hydraulic fracturing services. In addition, we also offer our wireline service on a stand-alone basis. 
+As a result of the PropX Acquisition, which was completed in October 2021, we are now a leading provider of last-mile proppant delivery solutions, including proppant handling equipment and logistics software across North America. PropX offers innovative environmentally friendly technology with optimized dry and wet sand containers and wellsite proppant handling equipment that drive logistics efficiency and reduce noise and emissions. We believe that PropX wet sand handling technology is a key enabler of the next step of cost and emissions reductions in the proppant industry. PropX also offers customers the latest real-time logistics software, PropConnect™, for sale or as hosted software as a service. 
+Our operations are organized into a single business segment, which consists of hydraulic fracturing services, including wireline, proppant delivery and goods, including our Permian Basin sand mines, and we have one reportable geographical segment, North America. We have grown from one active hydraulic fracturing fleet as of December 2011 to over 40 active fleets as of December 31, 2022. We are focused on providing “next-generation” frac fleets and technologies to assist our customers with completing their wells in an environmental, social, and governance (“ESG”)-friendly manner. 
+Our founders and management are pioneers in the development of data-driven hydraulic fracturing technologies for application in shale plays. Prior to founding the Company, the majority of our management team founded and built Pinnacle Technologies, Inc. (“Pinnacle Technologies”) into a leading fracturing technology company. In 1992, Pinnacle Technologies developed the first commercial hydraulic fracture mapping technologies, analytical tools that played a major role in launching the shale revolution. Our extensive experience with fracture technologies and customized fracture design has enabled us to develop new technologies and processes that provide our customers with real-time solutions that significantly enhance their completions. These technologies include hydraulic fracture propagation models, reservoir engineering tools, large, proprietary shale production databases and multi-variable statistical analysis techniques. Taken together, these technologies have enabled us to be a leader in hydraulic fracture design innovation and application. Our management team has an average of over 20 years of energy services experience, and the majority of our management team worked together before founding our company. 
+We believe technical innovation and strong relationships with our customer and supplier bases distinguish us from our competitors and are the foundations of our business. We expect that E&P companies will continue to focus on technological innovation as completion complexity and fracture intensity of horizontal wells increases, particularly as customers are increasingly focused on reducing emissions from their completions operations. We remain proactive in developing innovative solutions to industry challenges, including developing: (i) our databases of U.S. unconventional wells to which we apply our proprietary multi-variable statistical analysis technologies to provide differential insight into fracture design optimization; (ii) our Liberty Quiet Fleet® design which significantly reduces noise levels compared to conventional hydraulic fracturing fleets; (iii) hydraulic fracturing fluid systems tailored to the specific reservoir properties in the basins in which we operate and (iv) our dual fuel dynamic gas blending fleets that allow our engines to run diesel or a combination of diesel and natural gas, to optimize fuel use, reduce emissions and lower costs; (v) the successful test of digiFrac™, our innovative, purpose-built electric frac pump that has approximately 25% lower CO2e emission profile than the Tier IV DGB; and (vi) our PropX wet sand handling technology which eliminates the need to dry sand, enabling the deployment of mobile mines nearer to wellsites. In addition, our integrated supply chain includes proppant, chemicals, equipment, logistics and integrated software which we believe promotes wellsite efficiency and leads to more pumping hours and higher productivity throughout the year to better service our customers. In order to achieve our technological objectives, we carefully manage our liquidity and debt position to promote operational flexibility and invest in the business throughout the full commodity cycle. 
+2 
+ESG Focused 
+While we recognize the various environmental and social impacts of hydrocarbon energy, we believe that access to life-enhancing modern energy presents the most pressing global energy challenge. We passionately work to better the process of bringing hydrocarbons to the surface in a clean, safe and efficient fashion and view ESG principles as foundational to our business. We focus on developing and adding technologies to our operations that assist our customers in implementing their ESG goals. The list below sets forth specific examples of our efforts towards ESG principles: 
+• In 2013, we introduced Tier 2 dual-fuel technology to our fleets which allows our frac pumps to use natural gas in place of some diesel fuel to lower particulate emissions. 
+• In 2014, we began the use of containerized sand delivery at frac locations, which reduces dust, noise and truck traffic. 
+• In 2016, we introduced Quiet Fleet® technology, which significantly reduces noise levels associated with frac operations. 
+• In 2018, we began a partnership with an equipment supplier to introduce Tier 4 dynamic gas blending, or DGB, engines to our frac fleet that can substitute up to 80% of the diesel typically used by a frac pump with natural gas and significantly lower emission levels in frac operations. Tier 4 DGB engines were added to our fleet in 2020. 
+• In 2021, we announced the successful test of digiFrac™, our innovative, purpose-built electric frac pump that has approximately a 25% lower CO2e emission profile than the Tier IV DGB. We have entered into two multi-year arrangements with customers for digiFrac fleets and commenced delivery of commercial pumps in the fourth quarter of 2022. 
+• In October 2021, we closed the acquisition of PropX. PropX offers innovative, environmentally friendly technology with optimized dry and wet sand containers and wellsite proppant handling equipment that drive logistics efficiency and reduce noise and emissions. 
+• In August 2022, we released our second annual Bettering Human Lives report, highlighting the importance of energy in the modern world and Liberty’s ESG 2021 data, which was updated to cover the critical link hydrocarbons play in geopolitics, food, and their role in enabling the modern world. 
+We are continuously committed to engagement in our communities. We provide K-12 scholarships to low-income children through ACE (Alliance for Choice in Education), and we have launched a Liberty Scholars program at Montana Technological University to enable lower-income students to obtain a college engineering education. In 2022, over 100 students received Liberty scholarships. We have numerous other efforts encompassing our three pillars of outreach: education, military services, and alleviating poverty. Since launching Liberty’s matching program in 2021, Love Liberty, we have supported an additional 25 organizations near and dear to our employee’s hearts across all districts. Every year we strive to create lasting relationships and impacts throughout all our communities with the mission to better human lives through the growth of individual liberty and opportunity. 
+Cyclical Nature of Industry 
+We operate in a highly cyclical industry. The key factor driving demand for our services is the level of drilling activity by E&P companies, which in turn depends largely on the current and anticipated economics of new well completions. Global supply and demand for oil and the domestic supply and demand for natural gas are critical in assessing industry outlook. Demand for oil and natural gas is cyclical and subject to large, rapid fluctuations. E&P companies tend to increase capital expenditures in response to increases in oil and natural gas prices, which generally results in greater revenues and profits for oilfield service companies such as ours. Increased capital expenditures also ultimately lead to greater production, which historically has resulted in increased supplies of hydrocarbons and reduced prices which in turn tend to drive a future reduction in E&P companies capital expenditures and reduce demand for energy services. For these reasons, the results of our operations may fluctuate from quarter to quarter and from year to year, and these fluctuations may distort comparisons of results across periods. 
+3 
+Seasonality 
+Our results of operations have historically reflected seasonal tendencies relating to holiday seasons, inclement weather and the conclusion of our customers’ annual drilling and completion capital expenditure budgets. Our most notable declines typically occur in the fourth quarter of the year for the reasons described above. Additionally, some of the areas in which we have operations, including Canada, the DJ Basin, Powder River Basin and Williston Basin, are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice, rain, or frost, and related road restrictions, we may be unable to move our equipment between locations, thereby reducing our ability to provide services and generate revenues. The exploration activities of our customers may also be affected during such periods of adverse weather conditions. Additionally, extended drought conditions in our operating regions could impact our ability or our customers’ ability to source sufficient water or increase the cost for such water. 
+Intellectual Property 
+Over the last several years and in connection with the acquisitions of OneStim and PropX, we have significantly invested in our research and technology capabilities. Our efforts to date have been focused on developing innovative, fit-for-purpose solutions designed to enhance our core service offerings, increase completion efficiencies, provide cost savings to our operations and add value for our customers. A cornerstone of our technological advantage is a series of proprietary databases of U.S. unconventional wells that include production data, completion designs and reservoir characteristics. We utilize these databases to perform multi-variable statistical analysis that generates differential insight into fracture design optimization to enhance our customers’ production economics. Our emphasis on data analytics is also deployed during job execution through the use of real-time feedback on variables that maximizes customer returns by improving cost-effective hydraulic fracturing operations. 
+Today, we hold approximately 500 patents and patent licenses relating to our engineering and technology solutions. We seek patent and trademark protections for our technology when we deem it prudent, and we aggressively pursue protection of these rights when warranted. We believe our patents, trademarks, and other protections for our proprietary technologies are adequate for the conduct of our business and that no single patent or trademark is critical to our business. In addition, we rely, to a great extent, on the technical expertise and know-how of our personnel to maintain our competitive position, and we take commercially reasonable measures to protect trade secrets and other confidential and/or proprietary information relating to the technologies we develop. 
+Human Capital Management 
+As of December 31, 2022, we had 4,580 employees and no unionized labor. We believe we have good relations with our employees and that one of our key competitive advantages is our people. Our highly trained, experienced and motivated employees are critical to delivering our hydraulic fracturing services. Taking care of our employees is one of our top priorities, and we continually invest in hiring, training and retaining the employees we believe to be the best in our field. We consistently assess the current business environment and labor market to refine our compensation and benefits programs in order to attract and retain top talent in our industry. We strive to promote from within our existing employee base to manage new hydraulic fracturing fleets and organically grow our operating expertise. This organic growth is essential in achieving the expertise and level of customer service we strive to provide each of our customers. As a result, we plan to continue to invest in our employees through both personal and professional training to attract and retain the best individuals in our areas of operation. Overall, we focus on individual contributions and team success to foster a culture built around operational excellence and superior safety. 
+Health and Safety 
+Our people are our most important asset and ensuring their safety and the safety of those around them is the most important thing we do. Making certain that the Liberty team is well trained to handle the complexities of daily field operations, and that their training and competency remains current with the latest technology and standards is a key component. In order to facilitate this training, we have developed the Liberty Frac Academy, a thorough program where employees are trained on various aspects of the Company, from safety in equipment operation to leadership skills. The Liberty Frac Academy not only ensures dissemination of high-quality training material, but also provides a forum for sharing best practices and lessons learned across the Company. As a result, we are among the safest service providers in the industry with a constant focus on Health, Safety and Environmental performance and service quality, as evidenced by an average incident rate that was 29% less than the industry average from 2020 to 2022. Our employee-centered focus and reputation for safety has enabled us to obtain projects from industry leaders with some of the most demanding safety and operational requirements. 
+4 
+Programs and Benefits 
+One way we have demonstrated a history of investing in our workforce is by offering competitive salaries and wages. To foster a strong sense of ownership, restricted stock units are provided to eligible employees under our long-term incentive plan. Furthermore, we offer innovative benefits to all eligible employees, including, among others, comprehensive health insurance coverage, parental leave to all new parents, for birth or adoption, financial support for child adoption, leave to care for partners with serious health conditions, 401(k) savings plan and educational tuition assistance for both bachelor’s degree and master’s degree programs. We are also passionate about community investment and, in 2019, we joined the Ban the Box initiative which provides work opportunities for formerly incarcerated individuals. 
+Governmental Regulation and Climate Change 
+As a company with operations in both the United States and Canada, we are subject to the laws of both jurisdictions in which we operate and the rules and regulations of various governing bodies, which may differ among those jurisdictions. Compliance with these laws, rules and regulations has not had, and is not expected to have, a material effect on our capital expenditures, results of operations and competitive position as compared to prior periods. We are also subject to numerous environmental and regulatory requirements related to our operations. For further information related to such regulation, see the risks described under the heading “Risk Factors” in this Annual Report. 
+Our operations are subject to numerous stringent and complex laws and regulations at the federal, state, and local levels governing the discharge of materials into the environment, environmental protection, and health and safety aspects of our operations. Failure to comply with these laws and regulations or to obtain or comply with permits may result in the assessment of administrative, civil, and criminal penalties, imposition of remedial or corrective action requirements, and the imposition of injunctions or other orders to prohibit certain activities, restrict certain operations, or force future compliance with environmental requirements. 
+There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons, other hazardous substances, and wastes, as a result of air emissions and wastewater discharges related to our operations, and because of historical operations and waste disposal practices. Spills or other releases of regulated substances, including such spills and releases that occur in the future, could expose us to material losses, expenditures, and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. The following is a summary of some of the existing laws, rules, and regulations to which we are subject. 
+U.S. Laws and Regulations 
+Hazardous Substances and Waste Handling 
+The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Under guidance issued by the U.S. Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. RCRA currently exempts many E&P wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes intrinsically associated with the exploration, development, or production of crude oil and natural gas. However, these E&P wastes may still be regulated under state solid waste laws and regulations, and it is possible that certain oil and natural gas E&P wastes now classified as non-hazardous could be classified as hazardous waste in the future. Stricter regulation of wastes generated during our or our customers’ operations could result in increased costs for our operations or the operations of our customers, which could in turn reduce demand for our services and adversely affect our business. We cannot guarantee that the EPA will not revisit the exemption of E&P waste or that waste will not become more heavily regulated at the federal or state level. 
+Comprehensive Environmental Response, Compensation, and Liability Act 
+The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owner or operator of the site where the release occurred and anyone who transported or disposed or arranged for the transport or disposal of a hazardous substance released at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA and any state analogs may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources and for the costs of certain health studies. We currently own, lease, or operate numerous properties that have been used for manufacturing and other operations for many years. These properties and the substances disposed or released on them may be 
+5 
+subject to CERCLA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. 
+Worker Health and Safety 
+We are subject to a number of federal and state laws and regulations, including the OSHA, establishing requirements to protect the health and safety of workers. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require maintenance of information about hazardous materials used or produced in operations and provision of this information to employees, state and local government authorities, and citizens. Specifically, OSHA has enacted a regulation regarding crystalline silica exposures, which included requirements that hydraulic fracturing operations implement dust controls to limit exposures to the substance. Additionally, the Federal Motor Carrier Safety Administration (the “FMCSA”) regulates and provides safety oversight of commercial motor vehicles, the EPA establishes requirements to protect human health and the environment, the federal Bureau of Alcohol, Tobacco, Firearms and Explosives establishes requirements for the safe use and storage of explosives, and the federal Nuclear Regulatory Commission establishes requirements for the protection against ionizing radiation. Substantial fines and penalties can be imposed, and orders or injunctions limiting or prohibiting certain operations may be issued, in connection with any failure to comply with these laws and regulations. 
+Water Discharges 
+The federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the U.S. The discharge of pollutants into regulated waters, including jurisdictional wetlands, is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. To the extent the agencies expanding the range of properties subject to the Clean Water Act’s jurisdiction, certain energy companies could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas, which in turn could reduce demand for our services. Furthermore, the process for obtaining permits has the potential to delay our operations and those of our customers. Spill prevention, control, and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture, or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of wastewater and storm water runoff from certain types of facilities. The Clean Water Act and analogous state laws provide for administrative, civil, and criminal penalties for unauthorized discharges and, together with the Oil Pollution Act of 1990, impose rigorous requirements for spill prevention and response planning, as well as substantial potential liability for the costs of removal, remediation, and damages in connection with any unauthorized discharges. 
+Air Emissions 
+The federal Clean Air Act (the “CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. These regulations change frequently. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements, or utilize specific equipment or technologies to control emissions of certain pollutants. In recent years, the CAA has been used to impose additional stringent requirements upon oil and gas production operations. While these rules may not be directly applicable to our business, they are applicable to the business of our customers. Promulgation of stricter permitting or emission control requirements could delay or impair our or our customers’ ability to obtain air emission permits, to develop new wells and to continue to operate existing wells, and result in fewer wells being drilled or redeveloped, causing a decrease in demand for our services. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties, as well as injunctive relief, for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. 
+Climate Change 
+The EPA has determined that emissions of greenhouse gases, including carbon dioxide and methane, present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. The EPA has established greenhouse gas emissions reporting requirements for sources in the oil and gas sector and has also promulgated rules requiring certain large stationary sources of greenhouse gases to obtain preconstruction permits under the CAA and follow “best available control technology” requirements. Although we are not likely to become subject to greenhouse gas emissions permitting and best available control technology requirements because none of our facilities are presently major sources of greenhouse gas emissions, such requirements could become applicable to our customers. In addition, the EPA has used the CAA to impose additional greenhouse gas emissions control 
+6 
+requirements upon our customers. The recently passed Inflation Reduction Act (“IRA 2022”) imposes a methane emissions charge on certain emissions from specific classes of sources that are required to report their greenhouse gas emissions. The fee will start in calendar year 2024. This fee as well as additional requirements on greenhouse gas emissions from our customers could have an adverse effect on their costs of operations or financial performance, thereby adversely affecting our business, financial condition, and results of operations. Also, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, and many states have already established regional greenhouse gas “cap-and-trade” programs. The adoption of any legislation or regulation that restricts emissions of greenhouse gases from the equipment and operations of our customers or with respect to the oil and natural gas they produce could adversely affect demand for our products and services. 
+Hydraulic Fracturing 
+Our business is clearly dependent on hydraulic fracturing and horizontal drilling activities. As further described herein, hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shale. The process, which involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. Specifically, there is considerable uncertainty surrounding regulation of the emissions of methane, which may be released during hydraulic fracturing, chemicals used in the hydraulic fracturing process, the discharge of wastewater from hydraulic fracturing operations and concerns about the triggering of seismic activity by the injection of produced waters into underground wells. Certain proposed regulation could make it significantly more difficult and/or costly to drill and operate oil and gas wells. If adopted, such regulation could result in a decline in the completion of new oil and gas wells or the recompletion of existing wells, which could negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the demand for our services. Given the long-term trend towards increasing regulation, future regulation in the industry remains a possibility. 
+Some states, counties, and municipalities have enacted or are considering moratoria on hydraulic fracturing. For example, New York, Vermont, Maryland, and Washington have banned, or are in the process of banning, the use of high-volume hydraulic fracturing. Alternatively, some municipalities are, or have considered, zoning and other ordinances, the conditions of which could impose a de facto ban on drilling and/or hydraulic fracturing operations. Further, some states, counties, and municipalities are closely examining water use issues, such as permit and disposal options for processed water, which could have a material adverse impact on our financial condition, prospects, and results of operations if such additional permitting requirements are imposed upon our industry. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could reduce demand for our business by making it more difficult or costly for certain customers to perform fracturing to stimulate production from tight formations. 
+National Environmental Policy Act 
+Businesses and operations of our customers that are carried out on federal lands may be subject to the National Environmental Policy Act (“NEPA”), which requires federal agencies, including the U.S. Department of the Interior, to evaluate major agency actions having the potential to significantly impact the human environment. In the course of such evaluations, an agency will evaluate the potential direct, indirect, and cumulative impacts of a proposed project and, if necessary, will prepare a detailed Environmental Impact Statement that must be made available for public review and comment. To the extent that our customers’ current activities, as well as proposed plans, on federal lands require governmental permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects which in turn could reduce demand for our services. 
+Endangered Species Act and Migratory Bird Treaty Act 
+The federal Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or its habitat. The U.S. Fish and Wildlife Service (the “FWS”) must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development and development of sand mines used for hydraulic fracturing. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”), which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit. This prohibition covers most bird species in the U.S. Future implementation of the rules implementing the ESA and the MBTA are uncertain. If we or our customers were to have areas within our respective operations designated as critical or suitable habitat for a protected species, it could decrease demand for our services and have a material adverse effect on our business. 
+7 
+Canadian Laws and Regulations 
+Companies such as us offering energy services that include hydraulic fracturing, engineering, and wireline services in the Province of Alberta in Canada are regulated by both the provincial government of Alberta (“Province”) and the federal government of Canada (“Canada”). This includes, but is not limited to, regulation related to environmental protection legislation, climate change legislation, fracking legislation, and legislation related to wildlife. In addition to being regulated by the Province and Canada, energy services companies may also be subject to other international, national, and subnational laws, regulations, and policies. 
+Provincial Legislation 
+Energy services companies are primarily regulated by provincial governments in Canada. For example, in Alberta, provincial legislation potentially applicable to our Canadian operations includes the Environmental Protection and Enhancement Act, RSA 2000, e E-12. This Act promotes the protection, enhancement and wise use of the environment, and deals with matters such as air emissions, water discharges, and the handling of hazardous substances and waste control (for example, under the Waste Control Regulation, Alta Reg 192/1996). 
+Other potentially applicable provincial legislation in Alberta includes legislation directed at the transportation of dangerous goods, including oil (the Dangerous Goods Transportation and Handling Act, RSA 2000, c D-4 and associated regulations), legislation intended to provide for the responsible management of oil wells and associated sites (the Oil and Gas Conservation Act, RSA 2000, c O-6), legislation establishing regulatory bodies overseeing oil and gas and electricity in Alberta (the Responsible Energy Development Act, SA 2012, c R-17.3 and the Alberta Utilities Commission Act, SA 2007, c A-37.2), legislation governing the removal of gas or propane from Alberta (the Gas Resources Preservation Act, RSA 2000, c G-4), legislation to effect conservation and prevent waste of the oil sands resource in Alberta (the Oil Sands Conservation Act, RSA 2000, c O-7) and legislation governing worker safety (the Occupational Health and Safety Act, SA 2017, c O-2.1). 
+The Alberta Energy Regulator has a number of directives that are applicable to energy services companies, such as Directive 050 which addresses salinity ranges for soils that can receive drilling wastes, and Directive 058, which sets out regulatory requirements for the handling, treatment, and disposal of upstream oilfield waste. Other provinces in Canada have their own statutory regime applicable to oilfield service companies. 
+Federal Legislation 
+The Federal government in Canada shares certain jurisdiction with the provinces over certain environmental matters. Federal legislation potentially applicable to our Canadian operations includes legislation focused on regulating greenhouse gases (the Greenhouse Gas Pollution Pricing Act, SC 2018, c 12, s 186), legislation aimed at protecting wildlife (the Species at Risk Act, SC 2002, c 29), legislation governing approvals for projects (the Impact Assessment Act, SC 2019, c 28, s 1), and legislation governing the transportation of potentially dangerous substances (the Transportation of Dangerous Goods Act, 1992, SC 1992, c 34). 
+8 
+Properties 
+Properties 
+Our corporate headquarters are located at 950 17 th Street, Suite 2400, Denver, Colorado 80202. We lease our general office space at our corporate headquarters. The lease expires in December 2027. We currently own or lease the following additional principal properties: 
+District Facility Location Size Leased or Owned 
+Midland, TX 160,000 sq. ft on 147 acres Owned 
+Odessa, TX 77,500 sq. ft on 47 acres Owned 
+Cibolo, TX 90,000 sq. ft on 34 acres Owned 
+Kermit, TX 5,000 acres Owned 
+Monahans, TX 3,200 acres Owned 
+Magnolia, TX 63,350 sq. ft. Leased (through May 31, 2031) 
+Gainesville, TX 170,000 sq. ft. Leased (through August 31, 2023) 
+Shreveport, LA 225,000 sq ft. on 50 acres Owned 
+Cheyenne, WY 115,000 sq. ft on 60 acres Owned 
+Gillette, WY 32,757 sq. ft on 15 acres Leased (through December 31, 2034) 
+Henderson, CO 50,000 sq. ft on 13 acres Leased (through December 31, 2034) 
+Henderson, CO 96,582 sq. ft on 12 acres Owned 
+Williston, ND 30,000 sq. ft on 15 acres Owned 
+Farmington, NM 34,000 sq. ft on 30 acres Owned 
+El Reno, OK 80,000 sq. ft on 33 acres Owned 
+Red Deer, AB 170,000 sq. ft on 42 acres Owned 
+Grand Prairie, AB 135,000 sq. ft on 40 acres Owned 
+Huallen, AB 80 acres Owned 
+We also lease several smaller facilities, which leases generally have terms of one to six years. We believe that our existing facilities are adequate for our operations and their locations allow us to efficiently serve our customers. We do not believe that any single facility is material to our operations and, if necessary, we could readily obtain a replacement facility. 
+Marketing and Customers 
+We have developed long-term partnerships with our customers through a continuous dialogue focused on their production economics. Further, we have a proven track record of executing our customers’ plans and delivering on time and in line with expected costs. Our customer base includes a broad range of integrated and independent E&P companies, including some of the largest E&P companies in our areas of operation such as Occidental Petroleum Corp, ConocoPhillips Company, BP p.l.c., and ExxonMobil. Our technological innovations, customer-tailored approach and track record of consistently providing high-quality, safe and reliable service has allowed us to develop long-term customer partnerships, which we believe makes us the service provider of choice for many of our customers. 
+Our sales and marketing activities typically are performed through our local sales representatives in each geographic region and are supported by our corporate headquarters. For the years ended December 31, 2022, 2021 and 2020, our top five customers collectively accounted for approximatel y 30% , 27%, and 48% of our revenues, respectively. For the years ended December 31, 2022 and 2021, no customer accounted for more than 10% of our revenues. For the year ended December 31, 2020, PDC Energy Inc., WPX Energy, Conoco-Phillips Company, and Parsley Energy Operations, LLC each accounted for more than 10% of our revenues. 
+Suppliers and Raw Materials 
+We have a dedicated supply chain team that manages sourcing and logistics to ensure flexibility and continuity of supply in a cost-effective manner across our areas of operation. We have built long-term relationships with multiple industry leading suppliers of proppant, chemicals and hydraulic fracturing equipment and have started to internally design and assemble key pump and maintenance parts. In addition, we have built a strong relationship with the assemblers of our custom-designed hydraulic fracturing fleets and believe we will continue to have timely access to new, high capability fleets as we continue to grow. In 2018, we vertically integrated a supplier of certain major components through the acquisition of ST9 Gas and Oil LLC. In October 2021, we vertically integrated a supplier of our containerized sand and last mile proppant logistics solutions with the acquisition of PropX. 
+9 
+We purchase a wide variety of raw materials, parts and components that are manufactured and supplied for our operations. We are not dependent on any single source of supply for those parts, supplies or materials. To date, we have generally been able to obtain the equipment, parts and supplies necessary to support our operations, although we have experienced delivery delays and shortages on some items. While we believe that we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers, we may not always be able to do so. In addition, certain materials for which we do not currently have long-term supply agreements could experience shortages and significant price increases in the future. As a result, we may be unable to mitigate any future supply shortages and our results of operations, prospects and financial condition could be adversely affected. The OneStim Acquisition included two state-of-the-art sand mines in the Permian Basin, which helps alleviate the risk of proppant supply shortages. 
+Competition 
+The markets in which we operate are highly competitive. We provide services in various geographic regions across the United States and Canada, and our competitors include many large and small oilfield service providers, including some of the largest integrated service companies. Our hydraulic fracturing services compete with large, integrated companies such as Halliburton Company as well as other companies including Calfrac Well Services Ltd., ProFrac Holding Corp., NexTier Oilfield Solutions Inc., Universal Pressure Pumping, Inc., ProPetro Services, Inc., RPC, Inc., and STEP Energy Services. In addition, we compete regionally with smaller service providers. 
+We believe that the principal competitive factors in the markets we serve are technical expertise, equipment capacity, work force competency, efficiency, safety record, reputation, experience and price. Additionally, projects are often awarded on a bid basis, which tends to create a highly competitive environment. We seek to differentiate ourselves from our competitors by delivering the highest-quality services and equipment possible, coupled with superior execution and operating efficiency in a safe working environment. 
+Available Information 
+We file or furnish annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The SEC also maintains an internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC. 
+We also make available free of charge through our website, www.libertyfrac.com, electronic copies of certain documents that we file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. 
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+Item 1A. Risk Factors 
+Described below are certain risks that we believe apply to our business and the industry in which we operate. You should carefully consider each of the risks described below in conjunction with other information including the financial statements and related notes provided in this Annual Report and in our other public disclosures. The risks described below highlight potential events, trends or other circumstances that could adversely affect our business, financial condition, results of operations, cash flows, liquidity or access to sources of financing, and consequently, the market value of our Class A Common Stock. These risks could cause our future results to differ materially from historical results and from guidance we may provide regarding our expectations of future financial performance. The risks described below are those that we have identified as material and is not an exhaustive list of all the risks we face. There may be other risks and uncertainties not currently known to us or that we currently deem to be immaterial which may also materially and adversely affect our business operations in the future. Please refer to the explanation of the qualifications and limitation on forward-looking statements set forth on page ii hereof. 
+Risks Related to the Oil and Natural Gas Industry 
+Federal, state, local and other applicable legislative and regulatory initiatives relating to hydraulic fracturing may serve to limit future oil and natural gas E&P activities and could have a material adverse effect on our results of operations and business. 
+Various federal, state, local and other applicable legislative and regulatory initiatives have been, or could be undertaken which could result in additional requirements or restrictions being imposed on hydraulic fracturing operations. Currently, hydraulic fracturing is generally exempt from federal regulation under the Safe Drinking Water Act Underground Injection Control (the “SDWA UIC”) program and is typically regulated by state oil and gas commissions or similar agencies but increased scrutiny and regulation by federal agencies does occur. For example, in late 2016, the EPA released a final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources. Additionally, the EPA has asserted regulatory authority pursuant to the SDWA UIC program over hydraulic fracturing activities involving the use of diesel fuel in the fracturing fluid and issued guidance regarding the permitting of such activities. Furthermore, the U.S. Bureau of Land Management has previously published rules that established stringent standards relating to hydraulic fracturing on federal and Native American lands. Similarly, the EPA has adopted rules on the capture of methane and other emissions released during hydraulic fracturing. These rules have been the subject of ongoing legal challenges. In January 2021, President Biden issued an executive order that called for issuance of proposed rules by no later than September 2021 that would restore rules for methane standards applicable to new, modified, and reconstructed sources and establish new methane and volatile organic compound standards applicable to existing oil and gas operations, including the production, transmission, processing and storage segments. On November 2021, the EPA proposed such a rule and in November 2022, EPA issued a proposal that updates and expands on the November 2021 proposal. If adopted, such a rule could make it significantly more difficult and/or costly to drill and operate oil and gas wells. As a result, such rule, if adopted, could result in a decline in the completion of new oil and gas wells or the recompletion of existing wells, which could negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the demand for our services. In addition to federal regulatory actions, legislation has been introduced, but not enacted, in Congress to provide for further federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. 
+Moreover, many states and local governments have adopted regulations that impose more stringent permitting, disclosure, disposal and well-construction requirements on hydraulic fracturing operations, including states where we or our customers operate, such as Texas, Colorado and North Dakota. States could also elect to place prohibitions on hydraulic fracturing, as several states have already done. In addition, some states have adopted broader sets of requirements related to oil and gas development more generally that could impact hydraulic fracturing activities. For example, in 2019 the Colorado legislature adopted SB 19-181, which gave greater regulatory authority to local jurisdictions and reoriented the mandate of the Colorado Oil and Gas Conservation Commission to place more emphasis on the protection of human health and the environment. In response, a reconstituted Colorado Oil and Gas Conservation Commission modified its rules to address the requirements of the legislation, adopting increased setback requirements, provisions for assessing alternative sites for well pads to minimize environmental impacts, and consideration to cumulative impacts, among other provisions. Environmental groups, local citizens groups and others continue to seek to use a variety of means to force action on additional restrictions on hydraulic fracturing and oil and gas development generally. 
+Additionally, in July 2021, a non-governmental organization issued a report that raised concerns that chemicals used in hydraulic fracturing could be within the class of chemicals known as per- and polyfluoroalkylated substances (“PFAS”) or precursors to such substances. PFAS is the subject of intense federal and state regulatory scrutiny. Should PFAS be in hydraulic fracturing chemicals, this could open up a new front for the regulation of hydraulic fracturing. 
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+Some states in which we operate require the disclosure of some or all of the chemicals used in our hydraulic fracturing operations. Certain aspects of one or more of these chemicals may be considered proprietary by us or our chemical suppliers. Disclosure of our proprietary chemical information to third parties or to the public, even if inadvertent, could diminish the value of our trade secrets or those of the chemicals suppliers and could result in competitive harm to us, which could have an adverse impact on our business, financial condition, prospects and results of operations. 
+In recent years, there have been allegations that hydraulic fracturing may result in seismic activities. Although the extent of any correlation between hydraulic fracturing and seismic activity has been and remains the subject of studies and debate, some parties believe that there is a causal relationship. As a result, federal and state legislatures and agencies may seek to further regulate, restrict or prohibit hydraulic fracturing. Such actions could result in a decline in the completion of new oil and gas wells, which could negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the demand for our services. 
+Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to, and litigation concerning, oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays for our customers or increased operating costs in the production of oil and natural gas, including from the developing shale plays, or could make it more difficult for (or could result in a prohibition for) us and our customers to perform hydraulic fracturing. The adoption of any additional laws or regulations regarding hydraulic fracturing or limitation in hydraulic fracturing could potentially cause a decrease in the completion of new oil and natural gas wells and an associated decrease in demand for our services and increased compliance costs and time. Such events could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition. 
+Additional legislation, executive actions, regulations or other regulatory initiatives to limit, delay or prohibit hydraulic fracturing or other aspects of oil and gas development may be pursued. In the event that these or other new federal restrictions, delays or prohibitions relating to the hydraulic fracturing process are adopted in areas where we or our customers conduct business, we or our customers may incur additional costs or permitting requirements to comply with such federal requirements that may be significant and, in the case of our customers, also could result in added restrictions or delays in the pursuit of exploration, development, or production activities, which would in turn reduce the demand for our services and have a material adverse effect on our results of operations. 
+Federal legislation and regulatory initiatives relating to drilling on federal lands could harm our business and negatively impact the oil and natural gas industry. 
+Businesses and operations of our customers may be carried out on federal lands. The Biden administration has announced that it is considering more stringent regulations for operations on such lands, and in January 2021, the U.S. Department of the Interior issued an order that effectively suspends new oil and gas leases and drilling permits on non-Indian federal lands and waters for a period of 60 days. However, the suspension does not limit existing operations under valid leases. 
+President Biden followed with an executive order directing the Secretary of the Interior to pause the issuance of new oil and gas leases on federal public lands and offshore waters pending completion of a comprehensive review of federal oil and gas permitting and leasing practices that take into consideration potential climate and other impacts associated with oil and gas activities. The leasing suspension has been the subject of several lawsuits, resulting in conflicting decisions on the legality of the lease suspension. For example, in August 2022, the U.S. District Court for the Western District of Louisiana blocked the Biden administration’s ability to unilaterally pause oil and gas leasing in 13 states, holding that the U.S. Department of the Interior violated federal law when it canceled onshore and offshore leasing on federal lands. While the various lawsuits were pending, in August 2022, Congress passed the 2022 IRA which, among other things, makes changes to the federal oil and gas leasing program (including increasing royalty rates and implementing policies to discourage venting and flaring) and requires the Biden administration to hold several oil and gas lease auctions, including many that had been suspended or cancelled. 
+Additionally, in November 2021, the U.S. Department of the Interior released a report on the federal oil and gas leasing program, which found that the current program fails to serve the public interest. The report makes several recommendations, including increasing royalty rates and adding new restrictions on what lands are made available for oil and gas development to minimize leasing of lands with low potential for development. The U.S. Department of the Interior is expected to propose rules based on these recommendations. In April 2022, the U.S. Department of the Interior also announced that the U.S. Bureau of Land Management would post notices for significantly reformed onshore lease sales that would promote the public interest in public lands while addressing deficiencies in the current federal oil and gas leasing program. The new lease sales will incorporate many of the recommendations in the U.S. Department of the Interior report on the federal leasing program. Such scheduled sales began in June 2022. 
+Furthermore, a group of oil and gas related interests has also sued alleging that lease sales are not occurring as required under the Mineral Leasing Act. In addition, where lease sales have occurred, environmental groups have sued to block the sales. On June 1, 2022, the U.S. District Court for the District of Columbia granted a motion to voluntarily dismiss three cases after the U.S. Bureau of Land Management and other defendants agreed to conduct more robust environmental reviews of certain oil and gas leases and reconsider the cumulative climate effects of these leases. The settlement agreements apply to nearly four 
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+million acres of land in Colorado, Wyoming, Utah, Montana, and New Mexico. If the U.S. Bureau of Land Management fails to complete its obligations under the settlement agreements, the plaintiffs can reinstate the litigation. 
+To the extent our customers operate on leased federal land, these and other regulatory actions could have a material adverse effect on the Company and our industry. 
+Our business depends on domestic capital spending by the oil and natural gas industry, and reductions in capital spending could have a material adverse effect on our liquidity, results of operations and financial condition. 
+Our business is directly affected by our customers’ capital spending to explore for, develop and produce oil and natural gas in the United States and Canada. In addition, certain of our customers could become unable to pay their vendors and service providers, including us, as a result of a decline in commodity prices. Reduced discovery rates of new oil and natural gas reserves in our areas of operation as a result of decreased capital spending may also have a negative long-term impact on our business, even in an environment of stronger oil and natural gas prices. Any of these conditions or events could adversely affect our operating results. If current activity levels decrease or our customers further reduce their capital spending, it could have a material adverse effect on our liquidity, results of operations and financial condition. 
+Industry conditions are influenced by numerous factors over which we have no control, including: 
+• expected economic returns to E&P companies of new well completions; 
+• domestic and foreign economic conditions and supply of and demand for oil and natural gas; 
+• the level of prices, and expectations about future prices, of oil and natural gas; 
+• the level of global oil and natural gas exploration and production; 
+• the level of domestic and global oil and natural gas inventories; 
+• the supply of and demand for hydraulic fracturing services and equipment in the United States and Canada; 
+• federal, tribal, state and local laws, regulations and taxes, including the policies of governments regarding hydraulic fracturing, oil and natural gas exploration, development and production activities and the transportation of oil and gas by pipeline, as well as non-U.S. governmental regulations and taxes; 
+• governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves; 
+• political and economic conditions in oil and natural gas producing countries; 
+• actions by the members of the Organization of Petroleum Exporting Countries and other oil exporting nations with respect to oil production levels and potential changes in such levels; 
+• global weather conditions and natural disasters; 
+• worldwide political, military and economic conditions; 
+• the cost of producing and delivering oil and natural gas; 
+• lead times associated with acquiring equipment and products and availability of qualified personnel; 
+• the discovery rates of new oil and natural gas reserves; 
+• the production decline rate of existing oil and gas wells; 
+• stockholder activism or activities by non-governmental organizations to limit certain sources of funding for the energy sector or to restrict the exploration, development, production and transportation of oil and natural gas; 
+• the availability of water resources, suitable proppant and chemical additives in sufficient quantities for use in hydraulic fracturing fluids; 
+• advances in exploration, development and production technologies or in technologies affecting energy consumption; 
+• the availability, proximity and capacity of oil and natural gas pipelines and other transportation facilities; 
+• merger and divestiture activity among oil and natural gas producers; 
+• the price and availability of alternative fuels and energy sources; and 
+• uncertainty in capital and commodities markets and the ability of oil and natural gas companies to raise equity capital and debt financing. 
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+The volatility of oil and natural gas prices may adversely affect the demand for our hydraulic fracturing services and negatively impact our results of operations. 
+The demand for our hydraulic fracturing services is primarily determined by current and anticipated oil and natural gas prices and the related levels of capital spending and drilling activity in the areas in which we have operations. Volatility or weakness in oil prices or natural gas prices (or the perception that oil prices or natural gas prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells. This, in turn, could lead to lower demand for our services and may cause lower utilization of our assets. We have experienced, and may in the future experience significant fluctuations in operating results as a result of the reactions of our customers to changes in oil and natural gas prices. 
+Prices for oil and natural gas historically have been extremely volatile and are expected to continue to be volatile. During the year 2022, the posted WTI price traded at an average of $94.90 per barrel (“Bbl”), as compared to the 2021 average of $68.13 per Bbl and the 2020 average of $39.16 per Bbl. During the fourth quarter of 2022, WTI oil prices averaged $82.79 compared to $93.06 in the third quarter of 2022 and $77.33 in the fourth quarter of 2021. If the prices of oil and natural gas remain or become more volatile, our operations, financial condition, cash flows and level of expenditures may be materially and adversely affected. 
+Delays or restrictions in obtaining permits by us for our operations or by our customers for their operations could impair our business. 
+In most states, our operations and the operations of our oil and natural gas producing customers require permits from one or more governmental agencies in order to perform drilling and completion activities, secure water rights, or other regulated activities. Such permits are typically issued by state agencies, but federal and local governmental permits may also be required. The requirements for such permits vary depending on the location where such regulated activities will be conducted. As with all governmental permitting processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit to be issued, and the conditions that may be imposed in connection with the granting of the permit. In addition, some of our customers’ drilling and completion activities may take place on federal land or Native American lands, requiring leases and other approvals from the federal government or Native American tribes to conduct such drilling and completion activities or other regulated activities. Under certain circumstances, federal agencies may cancel proposed leases for federal lands and refuse to grant or delay required approvals. Therefore, our customers’ operations in certain areas may be interrupted or suspended for varying lengths of time, causing a loss of revenue to us and adversely affecting our results of operations in support of those customers. 
+As described above, in January 2021, the U.S. Department of the Interior issued an order that effectively suspends new oil and gas leases and drilling permits on non-Indian federal lands and waters for a period of 60 days, but the suspension does not limit existing operations under valid leases. President Biden followed with an executive order that ordered the Secretary of the Interior to pause the issuance of new oil and gas leases on federal public lands and offshore waters pending completion of a comprehensive review of federal oil and gas permitting and leasing practices that take into consideration potential climate and other impacts associated with oil and gas activities. This order further directs agencies to identify fossil fuel subsidies provided by such agencies and take measures to ensure that federal funding is not directly subsidizing fossil fuels, with an objective of eliminating fossil fuel subsidies from federal budget requests beginning in 2022. This order is currently being challenged by industry groups. While the various lawsuits were pending, in August 2022, Congress passed the 2022 IRA which, among other things, makes changes to the federal oil and gas leasing program (including increasing royalty rates and implementing policies to discourage venting and flaring) and requires the Biden administration to hold several oil and gas lease auctions, including many that had been suspended or cancelled. For additional information, see the risk factor titled “Federal legislation and regulatory initiatives relating to drilling on federal lands could harm our business and negatively impact the oil and natural gas industry.” 
+Oil and natural gas companies’ operations using hydraulic fracturing are substantially dependent on the availability of water. Restrictions on the ability to obtain water for E&P activities and the disposal of flowback and produced water may impact their operations and have a corresponding adverse effect on our business, results of operations and financial condition. 
+Water is an essential component of shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Our oil and natural gas producing customers’ access to water to be used in these processes may be adversely affected due to reasons such as periods of extended drought, privatization, third party competition for water in localized areas or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. The occurrence of these or similar developments may result in limitations being placed on allocations of water due to needs by third party businesses with more senior contractual or permitting rights to the water. Our customers’ inability to locate or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact their E&P operations and have a corresponding adverse effect on our business, results of operations and financial condition. 
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+Moreover, the imposition of new environmental regulations and other regulatory initiatives could include increased restrictions on our producing customers’ ability to dispose of flowback and produced water generated in hydraulic fracturing or other fluids resulting from E&P activities. Applicable laws impose restrictions and strict controls regarding the discharge of pollutants into waters of the United States and require that permits or other approvals be obtained to discharge pollutants to such waters. Additionally, in 2016 EPA adopted a pretreatment standard that prohibits the discharge of wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly owned treatment works. Further, regulations implemented under both federal and state laws prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. These laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and hazardous substances. Compliance with current and future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells and any inability to secure transportation and access to disposal wells with sufficient capacity to accept all of our flowback and produced water on economic terms may increase our customers’ operating costs and could result in restrictions, delays, or cancellations of our customers’ operations, the extent of which cannot be predicted. 
+Our operations are subject to risks associated with climate change and potential regulatory programs meant to address climate change; these programs may impact or limit our business plans, result in significant expenditures or reduce demand for our services and reduce our revenues. 
+Climate change continues to be the focus of political and societal attention. Numerous proposals have been made and are likely to be forthcoming on the international, national, regional, state and local levels to reduce GHG emissions. These efforts have included or may include cap-and-trade programs, carbon taxes, GHG reporting obligations and other regulatory programs that limit or require control of GHG’s from certain sources. Upon taking office, President Biden issued several Executive Orders relating climate change, envisioning a “government-wide approach” to climate policy. At the 26 th Conference of the Parties of the United Nations Framework Convention on Climate Change held in October and November 2021, President Biden announced a commitment to significantly reduce GHG’s and transition the U.S. economy to net-zero carbon by 2050. At the 27th Conference of the Parties in 2022, President Biden reinforced these commitments and emphasized efforts to reduce methane emissions from the oil and gas sector. Programs addressing climate change may limit the ability to produce crude oil and natural gas, require stricter limits on the release of methane or other GHGs, increase reporting and/or other compliance obligations associated with GHG emissions, limit the ability to explore in new areas, limit the construction of pipelines and related equipment or may make it more expensive to produce, any of which may decrease the demand for our services and our revenues. 
+Incentives to conserve energy or use alternative energy sources, which can be part of climate change programs, may increase the competitiveness of alternative energy sources (such as wind, solar, geothermal, tidal and biofuels) or increase the focus on reducing the use of combustion engines in transportation (such as governmental mandates that ban the sale of new gasoline-powered automobiles). These actions could, in turn, reduce demand for hydrocarbons and therefore for our services, which would lead to a reduction in our revenues. 
+An increased societal and governmental focus on ESG and climate change issues may adversely impact our business, impact our access to investors and financing, and decrease demand for our services. 
+An increased expectation that companies address ESG matters (including climate change) may have a myriad of impacts on our business. Some investors and lenders are factoring these issues into investment and financing decisions. They may rely upon companies that assign ratings to a company’s ESG performance. Unfavorable ESG ratings, as well as recent activism around fossil fuels, may dissuade investors or lenders from us and toward other industries, which could negatively impact our stock price or our access to capital. Additionally, some potential sources of investment or financing have announced an intention to avoid or limit investment in companies that engage in hydraulic fracturing. While a substantial number of major banks and financing sources remain active in investments related to hydraulic fracturing, it is possible that the investment avoidance or limitation theme could expand in the future and restrict access to capital for companies like us. 
+Moreover, while we have and may continue to create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures are based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. Additionally, to the extent that we report GHG emissions data, the methodologies that we use to calculate our emissions may change over time based upon changing industry standards. We note that standards and expectations regarding the processes for measuring and counting GHG emissions and GHG emission reductions are evolving, and it is possible that our approach to measuring our emissions maybe considered inconsistent with common or best practices with respect to measuring and accounting for such matters. If our approaches to such matters fall out of step with common or best practice, we may be subject to additional scrutiny, criticism, regulatory and investor engagement or litigation, any of which may adversely impact our business, financial condition or results of operation. 
+Furthermore, the SEC has announced proposed rules that, among other matters, will establish a framework for reporting climate related risks. To the extent that any proposed rules impose additional reporting obligations, we could face increased 
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+costs. Separately, the SEC has also announced that it is scrutinizing existing climate change related disclosure in public filings, increasing the potential for enforcement if the SEC were to allege our existing climate disclosures are misleading or deficient. Furthermore, in November 2022, the U.S. Department of Labor adopted final rules that allow plan fiduciaries to consider climate change and other ESG factors when they select retirement investments and exercise shareholder rights, such as proxy voting. Should plan investors decide to not invest in us based on ESG factors, our business and access to capital may be negatively impacted. 
+In addition, ESG and climate change issues may cause consumer preference to shift toward other alternative sources of energy, lowering demand for oil and natural gas and consequently lowering demand for our services. In some areas these concerns have caused governments to adopt or consider adopting regulations to transition to a lower-carbon economy. These measures may include adoption of cap-and-trade programs, carbon taxes, increased efficiency standards, prohibitions on the manufacture of certain types of equipment (such as new automobiles with internal combustion engines), and requirements for the use of alternate energy sources such as wind or solar. These types of programs may reduce the demand for oil and natural gas and consequently the demand for our services. 
+Approaches to climate change and a transition to a lower-carbon economy, including government regulation, company policies, and consumer behavior, are continuously evolving. At this time, we cannot predict how such approaches may develop or otherwise reasonably or reliably estimate their impact on our financial condition, results of operations and ability to compete. However, any long-term material adverse effect on the oil and gas industry may adversely affect our financial condition, results of operations and cash flows. 
+Our operations are subject to significant risks, some of which are beyond our control. These risks may be self-insured, or may not be fully covered under our insurance policies. 
+Our operations are subject to significant hazards often found in the oil and natural gas industry, such as, but not limited to, accidents, including accidents related to trucking operations provided in connection with our services, blowouts, explosions, craterings, fires, natural gas leaks, oil and produced water spills and releases of hydraulic fracturing fluids or other well fluids into the environment. These conditions can cause: 
+• disruption in operations; 
+• substantial repair or remediation costs; 
+• personal injury or loss of human life; 
+• significant damage to or destruction of property, and equipment; 
+• environmental pollution, including groundwater contamination; 
+• unusual or unexpected geological formations or pressures and industrial accidents; 
+• impairment or suspension of operations; and 
+• substantial revenue loss. 
+In addition, our operations are subject to, and exposed to, employee/employer liabilities and risks such as wrongful termination, discrimination, labor organizing, retaliation claims and general human resource related matters. 
+The occurrence of a significant event or adverse claim in excess of the insurance coverage that we maintain or that is not covered by insurance could have a material adverse effect on our liquidity, consolidated results of operations and financial condition. Claims for loss of oil and natural gas production and damage to formations can occur in the well services industry. Litigation arising from a catastrophic occurrence at a location where our equipment and services are being used or trucking services provided in connection therewith may result in our being named as a defendant in lawsuits asserting large claims. 
+We do not have insurance against all foreseeable risks, either because insurance is not available or because of the high premium costs. The occurrence of an event not fully insured against or the failure of an insurer to meet its insurance obligations could result in substantial losses. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. Insurance may not be available to cover any or all of the risks to which we are subject, or, even if available, it may be inadequate, or insurance premiums or other costs could rise significantly in the future so as to make such insurance prohibitively expensive. 
+We could experience continued or increased severity of trucking related issues or trucking accidents, which could materially affect our results of operations. 
+Trucking services can be adversely impacted by traffic congestion, shortage of drivers and weather delays which could hinder our service levels. During 2021 and into 2022 there has been a shortage of available trucking services in the United States due to the industry not having enough qualified drivers, which has impacted our field operations at times. In addition, our field employees are generally required to have a commercial driver’s license (“CDL”) so they can drive trucks and move our frac pumps and other equipment from location to location. Obtaining employees with CDLs can be challenging during times when the trucking industry has driver shortages, as competition for qualified employees is often more intense. If we are unable 
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+to obtain trucking services on a timely basis or the services of a sufficient number of field employees with CDLs, it could have a material adverse impact on our financial condition, results of operations and cash flows. 
+In addition, potential liability and unfavorable publicity associated with accidents in the trucking industry can be severe and occurrences are unpredictable. The number and severity of litigation claims may be worsened by distracted driving by both truck drivers and other motorists. Our transportation operations often involve traveling on unpaved roads located in rural areas, increasing the risk of accidents. If we are involved in an accident involving hazardous substances, if there are releases of hazardous substances we transport, if soil or groundwater contamination is found at our facilities or results from our operations, or if we are found to be in violation of applicable environmental laws or regulations, we could owe cleanup costs and incur related liabilities, including substantial fines or penalties or civil and criminal liability. A material increase in the frequency or severity of accidents or workers’ compensation claims or the unfavorable development of existing claims could materially adversely affect our results of operations. In the event that accidents occur, we may be unable to obtain desired contractual indemnities, and our insurance may be inadequate in certain cases which could result in substantial losses. Any such lawsuits in the future may result in the payment of substantial settlements or damages and increases to our insurance costs. 
+We may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition, prospects and results of operations. 
+Our services are subject to inherent risks that can cause personal injury or loss of life, damage to or destruction of property, equipment or the environment or the suspension of our operations. Litigation arising from operations where our services are provided, may cause us to be named as a defendant in lawsuits asserting potentially large claims including claims for exemplary damages. We maintain what we believe is customary and reasonable insurance to protect our business against these potential losses, but such insurance may not be adequate to cover our liabilities, and we are not fully insured against all risks. 
+In addition, our customers usually assume responsibility for, including control and removal of, all other pollution or contamination which may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling and completion fluids. We may have liability in such cases if we are grossly negligent or commit willful acts. Our customers generally agree to indemnify us against claims arising from their employees’ personal injury or death to the extent that, in the case of our hydraulic fracturing operations, their employees are injured by such operations, unless resulting from our gross negligence or willful misconduct. Our customers also generally agree to indemnify us for loss or destruction of customer-owned property or equipment. In turn, we agree to indemnify our customers for loss or destruction of property or equipment we own and for liabilities arising from personal injury to or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. However, we might not succeed in enforcing such contractual liability allocation or might incur an unforeseen liability falling outside the scope of such allocation. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operation. 
+We are subject to environmental and occupational health and safety laws and regulations that may expose us to significant costs and liabilities. 
+Our operations and the operations of our customers are subject to numerous federal, tribal, regional, state and local laws and regulations relating to protection of the environment including natural resources, health and safety aspects of our operations and waste management, including the transportation and disposal of waste and other materials. These laws and regulations may impose numerous obligations on our operations and the operations of our customers, including the acquisition of permits or other approvals to conduct regulated activities, the imposition of restrictions on the types, quantities and concentrations of various substances that may be released into the environment or injected in non-productive formations below ground in connection with oil and natural gas drilling and production activities, the incurrence of capital expenditures to mitigate or prevent releases of materials from our equipment, facilities or from customer locations where we are providing services, the imposition of substantial liabilities for pollution resulting from our operations, and the application of specific health and safety criteria addressing worker protection. Any failure on our part or the part of our customers to comply with these laws and regulations could result in assessment of sanctions including administrative, civil and criminal penalties; imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures; the occurrence of restrictions, delays or cancellations in the permitting, performance or development of projects or operations; and the issuance of orders enjoining performance of some or all of our operations in a particular area. In addition to civil and other penalties associated with enforcement activities regarding compliance with occupational health and safety laws, our operations may be subject to abatement obligations that could require significant modifications to existing operations to achieve compliance. 
+Our business activities present risks of incurring significant environmental costs and liabilities, including costs and liabilities resulting from our handling of oilfield and other wastes, because of air emissions and wastewater discharges related to our operations, and due to historical oilfield industry operations and waste disposal practices. Moreover, accidental releases or spills may occur in the course of our operations or at facilities where our wastes are taken for reclamation or disposal, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for injuries to persons or damages to properties or natural resources. Some environmental laws and regulations may impose strict liability, which means that in some situations we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Remedial and abatement costs and other damages arising as a result of environmental and occupational health and safety laws and costs 
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+associated with changes in these laws and regulations could be significant and have a material adverse effect on our liquidity, consolidated results of operations and financial condition. 
+Laws and regulations protecting the environment generally have become more stringent in recent years and are expected to continue to do so, which could lead to material increases in costs for future environmental compliance and remediation. In particular, the ESA restricts activities that may result in a “take” of endangered or threatened species and provides for substantial penalties in cases where listed species are taken by being harmed. The dunes sagebrush lizard is one example of a species that, if listed as endangered or threatened under the ESA, could impact our operations and the operations of our customers. The dunes sagebrush lizard is found in the active and semi-stable shinnery oak dunes of southeastern New Mexico and adjacent portions of Texas, including areas where our customers operate and our frac sand facilities are located. The FWS is currently conducting a review to determine whether listing the dunes sagebrush lizard as endangered or threatened under the ESA is warranted. In July 2020, the FWS published a 90-day finding that a 2018 petition seeking that the dunes sagebrush lizard be listed as endangered or threatened presented substantial evidence indicating that listing may be warranted. In May 2022, an environmental group filed suit against the U.S. Department of the Interior and the FWS alleging that they have unlawfully delayed protection of the dunes sagebrush. If the dunes sagebrush lizard is listed as an endangered or threatened species, our operations and the operations of our customers in any area that is designated as the dunes sagebrush lizard’s habitat may be limited, delayed or, in some circumstances, prohibited, and we and our customers could be required to comply with expensive mitigation measures intended to protect the dunes sagebrush lizard and its habitat. Furthermore, new laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement with respect to environmental matters could restrict, delay or curtail exploratory or developmental drilling for oil and natural gas by our customers and could limit our well servicing opportunities. 
+Oilfield anti-indemnity provisions enacted by many states may restrict or prohibit a party’s indemnification of us. 
+We typically enter into agreements with our customers governing the provision of our services, which usually include certain indemnification provisions for losses resulting from operations. Such agreements may require each party to indemnify the other against certain claims regardless of the negligence or other fault of the indemnified party; however, many states place limitations on contractual indemnity agreements, particularly agreements that indemnify a party against the consequences of its own negligence. Furthermore, certain states, including Texas, New Mexico and Wyoming, have enacted statutes generally referred to as “oilfield anti-indemnity acts” expressly prohibiting certain indemnity agreements contained in or related to oilfield services agreements. Such anti-indemnity acts may restrict or void a party’s indemnification of us, which could have a material adverse effect on our business, financial condition, prospects and results of operations. 
+Technology advancements in well service technologies, including those involving hydraulic fracturing, could have a material adverse effect on our business, financial condition and results of operations. 
+The hydraulic fracturing industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As competitors and others use or develop new technologies or technologies comparable to ours in the future, we may lose market share or be placed at a competitive disadvantage. Further, we may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of our competitors may have greater financial, technical and personnel resources than we do, which may allow them to gain technological advantages or implement new technologies before we can. Additionally, we may be unable to implement new technologies or services at all, on a timely basis or at an acceptable cost. New technology could also make it easier for our customers to vertically integrate their operations, thereby reducing or eliminating the need for our services. Limits on our ability to effectively use or implement new technologies may have a material adverse effect on our business, financial condition and results of operations. 
+The ability or willingness of OPEC and other oil exporting nations to set and maintain production levels and/or the impact of sanctions on Russia related to the war in Ukraine may have a significant impact on natural gas commodity prices. 
+The Organization of Petroleum Exporting Countries and their allies (collectively, OPEC+), is an intergovernmental organization that seeks to manage the price and supply of oil on the global energy market. Actions taken by OPEC+ members, including those taken alongside other oil exporting nations, have a significant impact on global oil supply and pricing. For example, OPEC+ and certain other oil exporting nations have previously agreed to take measures, including production cuts, to support crude oil prices. In March 2020, members of OPEC+ considered extending and potentially increasing these oil production cuts, however these negotiations were unsuccessful. As a result, Saudi Arabia announced an immediate reduction in export prices and Russia announced that all previously agreed oil production cuts expired on April 1, 2020. These actions led to an immediate and steep decrease in oil prices. Conversely, sanctions imposed on Russia in the last few months have increased prices. In October 2022, OPEC+ again determined to reduce production of oil, by approximately 2 million barrels per day. At its meeting on December 4, 2022, OPEC+ agreed to keep its current policy unchanged as the oil markets struggle to assess the impact of a slowing Chinese economy on demand, and the Group of Seven Nations agreed on a price cap on Russian oil supply. 
+There can be no assurance that OPEC+ members and other oil exporting nations will agree to future production cuts or other actions to support and stabilize oil prices, nor can there be any assurance that sanctions or other global conflicts will not further impact oil prices. Uncertainty regarding future sanctions or actions to be taken by OPEC+ members or other oil 
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+exporting countries could lead to increased volatility in the price of oil and natural gas, which could adversely affect our business, future financial condition and results of operations. 
+Risks Related to the TRAs 
+The Company is required to make payments under the TRAs for certain tax benefits that it may claim, and the amounts of such payments could be significant. 
+In connection with the Company’s initial public offering (the “IPO”), on January 17, 2018, the Company entered into two Tax Receivable Agreements (the “TRAs”) with R/C Energy IV Direction Partnership, L.P. and the then-existing owners of Liberty Oilfield Services Holdings LLC (“Liberty Holdings”) that continued to own Liberty LLC Units (each such person and any permitted transferee, a “TRA Holder”). The TRAs generally provide for the payment by the Company to each TRA Holder of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that the Company actually recognizes (or is deemed to recognize in certain circumstances) as a result of certain increases in tax basis, net operating losses available to the Company as a result of the corporate reorganization performed in connection with the IPO (the “Corporate Reorganization”), and certain benefits attributable to imputed interest. The Company will retain the benefit of the remaining 15% of these cash savings. 
+The Company is a holding company and has no material assets other than its direct and indirect equity interests in its subsidiaries. Because the Company has no independent means of generating revenue, its ability to make payments under the TRAs is dependent on the ability of its subsidiaries to make distributions to the Company in an amount sufficient to cover its obligations under the TRAs. To the extent that the Company is unable to make payments under the TRAs for any reason, such payments will be deferred and will accrue interest until paid. 
+The term of each of the TRAs continues until all tax benefits that are subject to such TRAs have been utilized or expired, unless the Company experiences a change of control (as defined in the TRAs, which includes certain mergers, asset sales and other forms of business combinations) or the TRAs are terminated early (at the Company’s election or as a result of its breach), and the Company makes the termination payments specified in such TRAs. In addition, payments the Company makes under the TRAs will be increased by any interest earned from the due date (without extensions) of the corresponding tax return. Payments under the TRAs commenced in 2020 and so long as the tax savings are recognized and the TRAs are not terminated, payments are anticipated to continue for 15 years after the date of the last redemption of the Liberty LLC Units, which occurred on January 31, 2023. Accordingly, if the applicable U.S. federal corporate tax rate is increased, then the amount of TRA payments paid in the future may also increase. 
+In certain cases, if the Company experiences a change of control (as defined under the TRAs, which includes certain mergers, asset sales and other forms of business combinations) or the TRAs terminate early (at the Company’s election or as a result of its breach), the Company would be required to make an immediate lump-sum payment, and such payment may be significantly in advance of, and may materially exceed, the actual realization, if any, of the future tax benefits to which the payment relates. As a result, the Company’s obligations under the TRAs could have a substantial negative impact on its liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. There can be no assurance we will be able to finance our obligations under the TRAs. Furthermore, as a result of this payment obligation, holders of our Class A Common Stock could receive substantially less consideration in connection with a change in control transaction than they would receive in the absence of such obligation. Because our payment obligations under the TRAs will not be conditioned upon the TRA Holders’ having continued interest in the Company or Liberty LLC, the TRA Holders’ interests may conflict with those of the holders of our Class A Common Stock. 
+Payments under the TRAs are based on the tax reporting positions that we will determine. The TRA Holders will not reimburse us for any payments previously made under the TRAs if any tax benefits that have given rise to payments under the TRAs are subsequently disallowed in an audit, except that excess payments made to any TRA Holder will be netted against payments that would otherwise be made to such TRA Holder, if any, after our determination of such excess. As a result, in such circumstances the Company could make payments that are greater than its actual cash tax savings, if any, and may not be able to recoup those payments, which could adversely affect the Company’s liquidity. Furthermore, the payments under the TRAs will not be conditioned upon a holder of rights under each of the TRAs having a continued ownership interest in the Company or Liberty LLC. For further details of the TRAs, see Note 12 —Income Taxes to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.” 
+19 
+General Risks Related to our Business 
+COVID-19 has had in the past, and may in the future have, a material adverse effect on the demand for our services, our operations, business and financial results. 
+The COVID-19 pandemic created significant uncertainty and economic disruption, as well as heightened volatility in the prices of oil and natural gas. Although government response measures to COVID-19 have generally relaxed, the ultimate impact of this pandemic is uncertain and subject to change. The collapse in the demand for oil during 2020 caused by this unprecedented global health and economic crisis, coupled with an oil oversupply, had a material adverse impact on the demand for our services and on our financial condition, results of operations and cash flows. 
+We are closely monitoring the continuing effects of the pandemic on our customers, operations, and employees. Oil demand and the demand for our services have since recovered from the lows experienced during the onset of the pandemic. The extent to which our operating and financial results will be affected by COVID-19 in the future will depend on various factors and consequences, such as the ultimate duration and scope of the pandemic, any additional actions by businesses and governments in response to the pandemic, and the speed and effectiveness of responses to combat the virus. COVID-19, and the volatile regional and global economic conditions stemming from the pandemic, could also aggravate the other risk factors that we identify herein. COVID-19 may also materially adversely affect our operating and financial results in a manner that is not currently known to us or that we do not currently consider presenting significant risks to us. 
+We cannot predict the ultimate duration or scope of the COVID-19 pandemic or the response of the overall economy and the financial markets to the COVID-19 pandemic and response measures. Accordingly, if the pandemic worsens or if actions taken by governments and businesses in response to the pandemic in 2020 are re-enacted, the demand for our services may fall again, which would have a material adverse impact on our financial condition, results of operations and cash flows. 
+We may be adversely affected by uncertainty in the global financial markets and the deterioration of the financial condition of our customers. 
+Our future results may be impacted by the uncertainty caused by an economic downturn, volatility or deterioration in the debt and equity capital markets, inflation, deflation or other adverse economic conditions that may negatively affect us or parties with whom we do business resulting in a reduction in our customers’ spending and their non-payment or inability to perform obligations owed to us, such as the failure of customers to honor their commitments or the failure of major suppliers to complete orders. Additionally, during times when the oil or natural gas markets weaken, our customers are more likely to experience financial difficulties, including being unable to access debt or equity financing, which could result in a reduction in our customers’ spending for our services. In addition, in the course of our business we hold accounts receivable from our customers. In the event of the financial distress or bankruptcy of a customer, we could lose all or a portion of such outstanding accounts receivable associated with that customer. Further, if a customer was to enter into bankruptcy, it could also result in the cancellation of all or a portion of our service contracts with such customer at significant expense or loss of expected revenues to us. 
+Our business, financial condition and results of operations may be adversely impacted by the effects of inflation. 
+Inflation has the potential to adversely affect our business, financial condition and results of operations by increasing our overall cost structure, particularly if we are unable to achieve commensurate increases in the prices we charge our customers. Other inflationary pressures could affect wages, the cost and availability of components, materials and other inputs and our ability to meet customer demand. Inflation may further exacerbate other risk factors, including supply chain disruptions, risks related to international operations and the recruitment and retention of qualified employees. 
+Reliance upon a few large customers may adversely affect our revenue and operating results. 
+Our top five customers represented approximately 30%, 27%, and 48%, of our consolidated revenue for the years ended December 31, 2022, 2021, and 2020, respectively. It is possible that we will derive a significant portion of our revenue from a concentrated group of customers in the future. If a major customer fails to pay us, revenue would be impacted and our operating results and financial condition could be materially harmed. Additionally, if we were to lose any material customer or our customers were to consolidate or merge with other operators, we may not be able to redeploy our equipment at similar utilization or pricing levels or within a short period of time and such loss could have a material adverse effect on our business until the equipment is redeployed at similar utilization or pricing levels. 
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+We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss. 
+The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain processing activities. For example, we depend on digital technologies to perform many of our services and to process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. In early 2020, we experienced a denial of service cyberattack that targeted a portion of our non-financial data. We immediately shutdown critical systems, diagnosed the root cause of the attack and then methodically returned systems online. This cyberattack disrupted certain non-financial aspects of our internal system for a period of less than one day, while limited and non-critical portions of our systems were kept offline for up to one week in order to properly evaluate the breach. We determined that this cyberattack did not materially affect any of our operations. We engaged in extensive data evaluation for potential damage and concluded that minimal to no data loss had occurred as a result of this cyberattack. Our technologies, systems and networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches in the future that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we will likely be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. Our insurance coverage for cyberattacks may not be sufficient to cover all the losses we may experience as a result of such cyberattacks. 
+Our assets require significant amounts of capital for maintenance, upgrades and refurbishment and may require significant capital expenditures for new equipment. 
+Our hydraulic fracturing fleets and other completion service-related equipment require significant capital investment in maintenance, upgrades and refurbishment to maintain their competitiveness. The costs of components and labor have increased in the past and may increase in the future with increases in demand, which will require us to incur additional costs for any fleets we may acquire in the future. Our fleets and other equipment typically do not generate revenue while they are undergoing maintenance, upgrades or refurbishment. Any maintenance, upgrade or refurbishment project for our assets could increase our indebtedness or reduce cash available for other opportunities. Furthermore, such projects may require proportionally greater capital investments as a percentage of total asset value, which may make such projects difficult to finance on acceptable terms. To the extent we are unable to fund such projects, we may have less equipment available for service or our equipment may not be attractive to potential or current customers. Additionally, competition or advances in technology within our industry may require us to update or replace existing fleets or build or acquire new fleets. Such demands on our capital or reductions in demand for our hydraulic fracturing fleets and the increase in cost of labor necessary for such maintenance and improvement, in each case, could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations and may increase our costs. 
+We rely on certain third parties for materials, and delays in deliveries of such materials, increases in the cost of such materials or our contractual obligations to pay for materials that we ultimately do not require could harm our business, results of operations and financial condition. 
+We have established relationships with certain suppliers of our materials (such as, but not limited to, proppant and chemical additives) and other parts, supplies and items needed for our operations. Delays or shortages in materials can result from a variety of reasons, including those caused by weather and natural disasters. Presently, the United States is undergoing a supply chain disruption due to backlogged ports and trucking shortages, and our business is not immune from these effects. Even once the root cause of the supply chain disruption or any future shortage or delay has passed, it can take time for our supply chain to recover and run in a regular fashion. Should the nationwide supply chain disruption continue, or should any of our current suppliers be unable to provide the necessary materials or otherwise fail to deliver the materials in a timely manner and in the quantities required, any resulting delays in the provision of services could have a material adverse effect on our business, results of operations and financial condition. Additionally, increasing costs of such materials may negatively impact demand for our services or the profitability of our business operations. In the past, our industry faced sporadic proppant shortages associated with hydraulic fracturing operations requiring work stoppages, which are believed to have adversely impacted the operating results of several competitors. We may not be able to mitigate any future shortages of materials, including proppant, or the impact of supply chain disruptions. Furthermore, to the extent our contracts require us to purchase more materials, including proppant, than we ultimately require, we may be forced to pay for the excess amount under “take or pay” contract provisions. 
+21 
+We currently utilize two preferred assemblers and a limited number of suppliers for major equipment to both build new fleets and upgrade any fleets we acquire to our preferred specifications, and our reliance on these vendors exposes us to risks including price and timing of delivery. 
+We currently utilize two preferred assemblers and a limited number of suppliers for major equipment to both build our new fleets and upgrade any fleets we may acquire to our custom design. If demand for hydraulic fracturing fleets or the components necessary to build such fleets increases or these vendors face financial distress or bankruptcy, these vendors may not be able to provide the new or upgraded fleets on schedule or at the current price. If this were to occur, we could be required to seek another assembler or other suppliers for major equipment to build or upgrade our fleets, which may adversely affect our revenues or increase our costs. 
+Interruptions of service on the rail lines by which we receive proppant could adversely affect our results of operations. 
+We receive a portion of the proppant used in our hydraulic fracturing services by rail. Rail operations are subject to various risks that may result in a delay or lack of service, including lack of available capacity, mechanical problems, extreme weather conditions, work stoppages, labor strikes, terrorist attacks and operating hazards. Additionally, if we increase the amount of proppant we require for delivery of our services, we may face difficulty in securing rail transportation for such additional amount of proppant. Any delay or failure in the rail services on which we rely could have a material adverse effect on our financial condition and results of operations. 
+Changes in transportation regulations may increase our costs and negatively impact our results of operations. 
+We are subject to various transportation regulations including as a motor carrier by the Department of Transportation and by various federal, state, provincial and tribal agencies, whose regulations include certain permit requirements of highway and safety authorities. These regulatory authorities exercise broad powers over our equipment transportation operations, generally governing such matters as the authorization to engage in motor carrier operations, safety, equipment testing, driver requirements and specifications and insurance requirements. The trucking industry is subject to possible regulatory and legislative changes that may impact our operations, such as changes in fuel emissions limits, hours of service regulations that govern the amount of time a driver may drive or work in any specific period and requiring onboard electronic logging devices or limits on vehicle weight and size. As the federal government continues to develop and propose regulations relating to fuel quality, engine efficiency and greenhouse gasses emissions, we may experience an increase in costs related to truck purchases and maintenance, impairment of equipment productivity, a decrease in the residual value of vehicles, unpredictable fluctuations in fuel prices and an increase in operating expenses. Additionally, we rely on third parties to provide trucking services, including hauling proppant to our customer work sites, and these third parties may fail to comply with various transportation regulations, resulting in our inability to use such third party providers. Increased truck traffic may contribute to deteriorating road conditions in some areas where our operations are performed. Our operations, including routing and weight restrictions, could be affected by road construction, road repairs, detours and state and local regulations and ordinances restricting access to certain roads. Proposals to increase federal, state, provincial or local taxes, including taxes on motor fuels, are also made from time to time, and any such increase would increase our operating costs. Also, state and local regulation of permitted routes and times on specific roadways could adversely affect our operations. We cannot predict whether, or in what form, any legislative or regulatory changes or municipal ordinances applicable to our logistics operations will be enacted and to what extent any such legislation or regulations could increase our costs or otherwise adversely affect our business or operations. 
+Our current and future indebtedness could adversely affect our financial condition. 
+Effective January 23, 2023, using proceeds from borrowings on our ABL Facility, we repaid all amounts outstanding under the Term Loan Facility. As of February 6, 2023, we had $284.0 million outstanding under our ABL Facility (defined herein), as well as a letter of credit in the amount of $2.6 million, with a borrowing base of $430.4 million. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements.” 
+Moreover, subject to the limits contained in our ABL Facility, we may incur substantial additional debt from time to time. Any borrowings we may incur in the future would have several important consequences for our future operations, including that: 
+• covenants contained in the documents governing such indebtedness may require us to meet or maintain certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our industry, such as being able to take advantage of acquisition opportunities when they arise; 
+• our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes may be limited; 
+• our ability to use operating cash flow in other areas of our business may be limited because we must dedicate a substantial portion of these funds to make principal and interest payments on our indebtedness; 
+• we may be more vulnerable to interest rate increases to the extent that we incur variable rate indebtedness; 
+22 
+• we may be competitively disadvantaged to our competitors that are less leveraged or have greater access to capital resources; and 
+• we may be more vulnerable to adverse economic and industry conditions. 
+If we incur indebtedness in the future, we may have significant principal payments due at specified future dates under the documents governing such indebtedness. Our ability to meet such principal obligations will be dependent upon future performance, which in turn will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. Our business may not continue to generate sufficient cash flow from operations to repay any incurred indebtedness. If we are unable to generate sufficient cash flow from operations, we may be required to sell assets, to refinance all or a portion of such indebtedness or to obtain additional financing. 
+Unsatisfactory safety performance may negatively affect our customer relationships and, to the extent we fail to retain existing customers or attract new customers, adversely impact our revenues. 
+Our ability to retain existing customers and attract new business is dependent on many factors, including our ability to demonstrate that we can reliably and safely operate our business in a manner that is consistent with applicable laws, rules and permits, which legal requirements are subject to change. Existing and potential customers consider the safety record of their third-party service providers to be of high importance in their decision to engage such providers. If one or more accidents were to occur at one of our operating sites, the affected customer may seek to terminate or cancel its use of our equipment or services and may be less likely to continue to use our services, which could cause us to lose substantial revenues. Furthermore, our ability to attract new customers may be impaired if they elect not to engage us because they view our safety record as unacceptable. In addition, it is possible that we will experience multiple or particularly severe accidents in the future, causing our safety record to deteriorate. This may be more likely as we continue to grow, if we experience high employee turnover or labor shortage, or hire inexperienced personnel to bolster our staffing needs. 
+If we are unable to fully protect our intellectual property rights, we may suffer a loss in our competitive advantage or market share. 
+We do not have patents or patent applications relating to many of our key processes and technology. If we are not able to maintain the confidentiality of our trade secrets, or if our competitors are able to replicate our technology or services, our competitive advantage would be diminished. We also cannot ensure that any patents we may obtain in the future would provide us with any significant commercial benefit or would allow us to prevent our competitors from employing comparable technologies or processes. 
+We may be adversely affected by disputes regarding intellectual property rights of third parties. 
+Third parties from time to time may initiate litigation against us by asserting that the conduct of our business infringes, misappropriates or otherwise violates intellectual property rights. We may not prevail in any such legal proceedings related to such claims, and our products and services may be found to infringe, impair, misappropriate, dilute or otherwise violate the intellectual property rights of others. If we are sued for infringement and lose, we could be required to pay substantial damages and/or be enjoined from using or selling the infringing products or technology. Any legal proceeding concerning intellectual property could be protracted and costly regardless of the merits of any claim and is inherently unpredictable and could have a material adverse effect on our financial condition, regardless of its outcome. 
+If we were to discover that our technologies or products infringe valid intellectual property rights of third parties, we may need to obtain licenses from these parties or substantially re-engineer our products in order to avoid infringement. We may not be able to obtain the necessary licenses on acceptable terms, or at all, or be able to re-engineer our products successfully. If our inability to obtain required licenses for our technologies or products prevents us from selling our products, that could adversely impact our financial condition and results of operations. 
+Additionally, we currently license certain third party intellectual property in connection with our business, and the loss of any such license could adversely impact our financial condition and results of operations. 
+Seasonal weather conditions, natural disasters, public health crises, and other catastrophic events outside of our control could severely disrupt normal operations and harm our business. 
+Our operations are located in different regions of the United States and Canada. Some of these areas, including the DJ Basin, Powder River Basin, Williston Basin and our Canadian operations, are adversely affected by seasonal weather conditions, primarily in the winter and spring. However, as evidenced by the severe winter weather experienced in the southern United States and Canada during December 2022, weather-related hazards can exist in almost all the areas where we operate. During periods of heavy snow, ice or rain, we may be unable to move our equipment between locations or obtain adequate supplies of raw material or fuel, thereby reducing our ability to provide services and generate revenues. The exploration activities of our customers may also be affected during such periods of adverse weather conditions. Additionally, extended drought conditions in our operating regions could impact our ability or our customers’ ability to source sufficient water or 
+23 
+increase the cost for such water. As a result, a natural disaster or inclement weather conditions could severely disrupt the normal operation of our business and adversely impact our financial condition and results of operations. Furthermore, if the area in which we operate or the market demand for oil and natural gas is affected by a public health crisis, such as the coronavirus, or other similar catastrophic event outside of our control, our business and results of operations could suffer. 
+The sand mining operations are subject to a number of risks relating to the proppant industry. 
+In connection with the OneStim Acquisition, we acquired two state-of-the-art sand mines in the Permian Basin. Sand mining operations are subject to risks normally encountered in the proppant industry. These risks include, among others: unanticipated ground, grade or water conditions; inability to acquire or maintain, or public or nongovernmental organization opposition to, necessary permits for mining, access or water rights; our ability to timely obtain necessary authorizations, approvals and permits from regulatory agencies (including environmental agencies, such as the FWS, where our operations in West Texas may be slowed, limited or halted due to conservation efforts targeted at the habitat of the dunes sagebrush lizard); pit wall or pond failures, and sluffing events; costs associated with environmental compliance or as a result of unauthorized releases into the environment; restrictions imposed on our operations related to the protection of natural resources, including plant and animal species; and reduction in the amount of water available for processing. Any of these risks could result in delays, limitations or cancellations in mining or processing activities, losses or possible legal liability. 
+Silica-related legislation, health issues and litigation could have a material adverse effect on our business, reputation or results of operations. 
+We are subject to laws and regulations relating to human exposure to crystalline silica. Historically, our environmental compliance costs with respect to existing crystalline silica requirements have not had a material adverse effect on our results of operations; however, federal regulatory authorities and analogous state agencies may continue to propose changes in their regulations regarding workplace exposure to crystalline silica, such as permissible exposure limits, required controls and personal protective equipment. We may not be able to comply with any new laws and regulations that are adopted, and any new laws and regulations could have a material adverse effect on our operating results by requiring us to modify or cease our operations. 
+In addition, the inhalation of respirable crystalline silica is associated with the lung disease silicosis. There is evidence of an association between crystalline silica exposure or silicosis and lung cancer and a possible association with other diseases, including immune system disorders such as scleroderma. The actual or perceived health risks of handling hydraulic fracture sand could materially and adversely affect hydraulic fracturing service providers, including us, through reduced use of hydraulic fracture sand, the threat of product liability or employee lawsuits, increased scrutiny by federal, state and local regulatory authorities of us and our customers or reduced financing sources available to the industry. Furthermore, we may incur additional costs with respect to purchasing specialized equipment designed to reduce exposure to crystalline silica in connection with our operations or invest capital in new equipment. 
+We are subject to the Federal Mine Safety and Health Act of 1977, which imposes stringent health and safety standards on numerous aspects of its operations. 
+Our operations are subject to the Federal Mine Safety and Health Act of 1977, as amended by the Mine Improvement and New Emergency Response Act of 2006, which imposes stringent health and safety standards on numerous aspects of mineral extraction and processing operations, including the training of personnel, operating procedures, operating equipment, and other matters. Our failure to comply with such standards, or changes in such standards or the re-interpretation or more stringent enforcement thereof, could have a material adverse effect on our business and financial condition or otherwise impose significant restrictions on its ability to conduct mineral extraction and processing operations. 
+The occurrence of explosive incidents could disrupt our operations and could adversely affect our business, financial condition and results of operations. 
+The wireline service we provide to oil and natural gas E&P customers involves the storage and handling of explosive materials. Despite the use of specialized facilities to store explosive materials and intensive employee training programs, the handling of explosive materials could result in incidents that temporarily shut down or otherwise disrupt our or E&P customers’ operations or could cause restrictions, delays or cancellations in the delivery of services. It is possible that an explosion could result in death or significant injuries to employees and other persons. Material property damage to us, E&P customers and third parties could also occur. Any explosive incident could expose us to adverse publicity or liability for damages or cause production restrictions, delays or cancellations, any of which developments could have a material adverse effect on our ability to compete, business, financial condition and results of operations. 
+24 
+The ongoing military action between Russia and Ukraine could adversely affect our business, financial condition and results of operations. 
+In February of 2022, Russian military forces invaded Ukraine, resulting in conflict and disruption in the region. The length, impact and outcome of the ongoing military conflict in Ukraine is highly unpredictable. This conflict has led and may continue to lead to significant market and other disruptions, including significant volatility in commodity prices and supply of energy resources, instability in financial markets, higher inflation, supply chain interruptions, political and social instability, changes in consumer or purchaser preferences as well as increase in cyberattacks and espionage. As a result of the invasion and ongoing military conflict, governments in the European Union, the United States, the United Kingdom, Switzerland and other countries have implemented and may implement additional sanctions, export controls or other measures against Russia, Belarus and other countries, regions, officials, individuals or industries in the respective territories. Such sanctions, and other measures, as well as the existing and potential further responses from Russia or other countries to such sanctions, supply chain disruptions, tensions and military actions, could adversely affect the global economy and financial markets and could adversely affect our business, financial condition and results of operations, and could also aggravate the other risk factors that we identify herein. 
+The choice of forum provisions in our charter and bylaws could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us. 
+Our Amended and Restated Certificate of Incorporation (as amended, the “Charter”) provides that unless the Company consents in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on behalf of the Company, (ii) any action asserting a claim of breach of a fiduciary duty owed by any director, officer, employee or agent of the Company to the Company or the Company’s stockholders, (iii) any action asserting a claim against the Company or any director or officer or other employee of the Company arising pursuant to any provision of the General Corporation Law of the State of Delaware, the Charter or the Company’s bylaws, or (iv) any action asserting a claim against the Company or any director or officer or other employee of the Company governed by the internal affairs doctrine, in each such case subject to Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Our Second Amended and Restated Bylaws (the “Bylaws”) further provide that unless the Company consents in writing to the selection of an alternative forum, the federal district courts of the United States of America will be the sole and exclusive forum for the resolution of any complaint asserting a cause of action arising under the Securities Act of 1933 (the “Securities Act”). Under the Securities Act, federal and state courts have concurrent jurisdiction over all suits brought to enforce any duty or liability created by the Securities Act, and stockholders cannot waive compliance with the federal securities laws and the rules and regulations thereunder. Accordingly, there is uncertainty as to whether a court would enforce such a forum selection provision as written in connection with claims arising under the Securities Act. Any person or entity purchasing or otherwise acquiring any interest in shares of common stock of the Company will be deemed to have notice of and have consented to the provisions of our Charter and Bylaws related to choice of forum. The choice of forum provisions in our Charter and Bylaws may limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us. Additionally, the enforceability of choice of forum provisions in other companies’ governing documents has been challenged in legal proceedings, and it is possible that, in connection with any applicable action brought against us, a court could find the choice of forum provisions contained in our Charter and Bylaws to be inapplicable or unenforceable in such action. If so, we may incur additional costs associated with resolving such action in other jurisdictions, which could harm our business, results of operations, and financial condition. 
+There can be no assurance we will repurchase shares of our Class A Common Stock in any particular amounts. 
+The stock markets in general have experienced substantial price and trading fluctuations, which have resulted in volatility in the market prices of securities that often are unrelated or disproportionate to changes in operating performance. These broad market fluctuations may adversely affect the trading price of our Class A Common Stock. Price volatility over a given period may also cause the average price at which we repurchase our own Class A Common Stock to exceed the stock’s price at a given point in time. In addition, significant changes in the trading price of our Class A Common Stock and our ability to access capital on terms favorable to us could impact our ability to repurchase shares of our Class A Common Stock. The timing and amount of any repurchases will be determined by the Company’s management based on its evaluation of market conditions, capital allocation alternatives and other factors beyond our control. Our share repurchase program may be modified, suspended, extended or terminated by the Company at any time and without notice. 
+Risks Related to the OneStim Acquisition 
+The Company's results may suffer if it does not effectively manage its expanded operations following the OneStim Acquisition. 
+Since the OneStim Acquisition, the size of the Company’s business has increased significantly. In addition, we now own and operate two sand mines. While we have retained qualified personnel to operate the mines, we have not undertaken mining operations in the past. The Company’s future success will depend, in part, on the Company’s ability to manage this expanded business, which poses numerous risks and uncertainties. 
+25 
+Following the OneStim Acquisition, we expanded our operations to Canada and may be subject to increased business and economic risks. 
+The Company has historically owned and operated its assets exclusively within the United States. In connection with the OneStim Acquisition, we acquired certain Canadian assets and liabilities, which marked our entry into a new geographical territory where we had limited experience in owning and operating assets and providing our services. As a result, we are subject to a variety of risks inherent in doing business internationally, including: risks related to the legal and regulatory environment in foreign jurisdictions; fluctuations in currency exchange rates; complying with multiple tax jurisdictions; difficulties in staffing and managing international operations and the increased travel, infrastructure and compliance costs associated with international locations and employees; regulations that might add difficulties in repatriating cash earned outside the United States and otherwise preventing us from freely moving cash; complying with statutory equity requirements; and complying with the U.S. Foreign Corrupt Practices Act and the Corruption of Foreign Public Officials Act (Canada) and other similar laws in Canada. If we fail to manage our operations in Canada successfully, our business may suffer. 
+26 
+Item 1B. Unresolved Staff Comments 
+None. 
+Item 2. Properties 
+Information regarding our properties is contained in “Item 1. Business” and is incorporated by reference herein. 
+Item 3. Legal Proceedings 
+The information with respect to this Item 3. Legal Proceedings is set forth in Note 15—Commitments and Contingencies included in “Item 8. Financial Statements and Supplementary Data.” 
+Item 4. Mine Safety Disclosures 
+Information concerning mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this Form 10-K. 
+27 
+PART II 
+Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+Market Information 
+On January 17, 2018, we consummated an initial public offering of our Class A Common Stock at a price of $17.00 per share. Our Class A Common Stock is traded on the NYSE under the symbol “LBRT.” Prior to that time, there was no public market for our Class A Common Stock. There is no public market for our Class B Common Stock. 
+Holders of our Common Stock 
+As of February 6, 2023, there were 24 stockholders of record of our Class A Common Stock and no stockholders of record of our Class B Common Stock. The number of record holders is based upon the actual number of holders registered on the books of the Company at such date and does not include holders of shares in “street names” or persons, partnerships, associations, corporations or other entities identified in security position listings maintained by depositories. 
+Dividend Policy 
+On April 2, 2020, the Company suspended future quarterly dividends until they were reinstated on October 18, 2022 by the Company’s Board of Directors (the “Board”). The Company paid cash dividends of $0.05 per share of Class A Common Stock on December 20, 2022 to stockholders of record as of December 6, 2022. The declaration of dividends is subject to approval by the Board and to the Board’s continuing determination that such declaration of dividends is in the best interests of the Company and its stockholders. Future dividends may be adjusted at the Board’s discretion based on market conditions and capital availability. We are not required to pay dividends, and our stockholders will not be guaranteed, or have contractual or other rights to receive, dividends. 
+Recent Sales of Unregistered Equity Securities 
+We had no sales of unregistered equity securities during the period covered by this Annual Report that were not previously reported in a Current Report on Form 8-K (or on Form 10-Q in lieu of Form 8-K). 
+Purchase of Equity Securities by the Issuer and Affiliated Purchasers 
+On July 25, 2022, the Board authorized and the Company announced a share repurchase program that allows the Company to repurchase up to $250.0 million of the Company’s Class A Common Stock beginning immediately and continuing through and including July 31, 2024. Additionally, on January 24, 2023 the Board authorized and the Company announced an increase to the share repurchase program that increased the Company’s cumulative repurchase authorization to $500.0 million. The shares may be repurchased from time to time in open market or privately negotiated transactions or by other means in accordance with applicable state and federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will be determined by the Company at its discretion and will depend on a variety of factors, including management’s assessment of the intrinsic value of the Company’s Class A Common Stock, the market price of the Company’s Class A Common Stock, general market and economic conditions, available liquidity, compliance with the Company’s debt and other agreements, applicable legal requirements, and other considerations. The exact number of shares to be repurchased by the Company is not guaranteed, and the program may be suspended, modified, or discontinued at any time without prior notice. The Company expects to fund the repurchases by using cash on hand, borrowings under its revolving credit facility and expected free cash flow to be generated through July 2024. 
+During the year ended December 31, 2022, the Company repurchased and retired 8,185,890 shares of Class A Common Stock for $125.3 million or $15.31 average price per share including commissions, under the share repurchase program. Included in these repurchases, on November 15, 2022, the Company repurchased and retired 1,700,000 shares of Class A Common Stock for $27.8 million or $16.35 average price per share from Schlumberger, under the share repurchase program. 
+As of December 31, 2022, $124.7 million remained authorized for future repurchases of Class A Common Stock under the share repurchase program and $329.7 million as of February 6, 2023, following the authorization increase. 
+28 
+The following sets forth information with respect to our repurchases of shares of Class A Common Stock during the three months ended December 31, 2022: 
+Period Total number of shares purchased Average price paid per share (2) Total number of shares purchased as part of publicly announced plans or programs (1) Approximate dollar value of shares that may yet be purchased under the plans or programs 
+October 1, 2022 - October 31, 2022 — — — 180,000,041 
+November 1, 2022 - November 30, 2022 1,906,221 16.30 1,906,221 148,922,516 
+December 1, 2022 - December 31, 2022 1,577,503 15.28 1,577,503 124,816,890 
+Total 3,483,724 15.84 3,483,724 124,816,890 
+(1) On July 25, 2022, the Board authorized and the Company announced a share repurchase program that allows the Company to repurchase up to $250.0 million of the Company’s Class A Common Stock beginning immediately and continuing through and including July 31, 2024. Additionally, on January 24, 2023 the Board authorized and the Company announced an increase to the share repurchase program that increased the Company’s cumulative repurchase authorization to $500.0 million. The $250.0 million increase is not represented in the dollar value of shares that may yet be purchased under the plans or programs in the chart above. The shares may be repurchased from time to time in open market or privately negotiated transactions or by other means in accordance with applicable state and federal securities laws. 
+(2) The average price paid per share of $15.84 was calculated excluding commissions. 
+29 
+Stock Performance Graph 
+The following graph and table compares the cumulative total return on our Class A Common Stock with the cumulative total return on the Standard & Poor’s 500 ® Index and the Philadelphia Oil Service Index, since January 12, 2018, the first day on which shares of our Common Stock issued in our IPO commenced trading on the NYSE and each semi-annual period thereafter through December 31, 2022. The graph assumes that $100 was invested in our Class A Common Stock in each index on January 12, 2018 and that any dividends were reinvested on the last day of the month in which they were paid. The cumulative total return set forth is not necessarily indicative of future performance. 
+The following graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that we specifically incorporate it by reference into such filing. 
+For Year Ended 2018 For the Year Ended 2019 For the Year Ended 2020 
+January 
+12, June 
+30, December 
+31, June 
+30, December 
+31, June 
+30, December 
+31, 
+Liberty Energy Inc. $ 100.00 $ 83.87 $ 58.38 $ 73.40 $ 50.91 $ 25.55 $ 48.08 
+Standard & Poor’s 500 ® Index 100.00 97.00 89.45 104.97 115.28 110.62 134.02 
+Philadelphia Oil Service Index 100.00 95.91 49.91 50.37 48.48 20.67 27.45 
+For the Year Ended 2021 For the Year Ended 2022 
+June 
+30, December 
+31, June 
+30, December 
+31, 
+Liberty Energy Inc. $ 66.03 $ 45.23 $ 59.50 $ 74.89 
+Standard & Poor’s 500 ® Index 153.34 170.07 135.07 137.00 
+Philadelphia Oil Service Index 39.47 32.65 41.05 51.93 
+30 
+Item 6. [Reserved] 
+31 
+Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our audited consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a variety of risks and uncertainties, including those described in this Annual Report under “Cautionary Note Regarding Forward-Looking Statements” and “Item 1A. Risk Factors.” Except as required by law, we assume no obligation to update any of these forward-looking statements. This section of this Annual Report generally discusses 2022 and 2021 items and year-to-year comparisons between 2022 and 2021. For discussion of year ended December 31, 2020, as well as the year ended 2021 compared to the year ended December 31, 2020, refer to Part II, Item 7— “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2021 Annual Report. 
+Overview 
+The Company, together with its subsidiaries, is a leading integrated energy services and technology company focused on providing innovative hydraulic fracturing services and related technologies to onshore oil and natural gas E&P companies in North America. We offer customers hydraulic fracturing services, together with complementary services including wireline services, proppant delivery solutions, data analytics, related goods (including our sand mine operations), and technologies that will facilitate lower emission completions, thereby helping our customers reduce their emissions profile. We have grown from one active hydraulic fracturing fleet in December 2011 to over 40 active fleets as of December 31, 2022. We provide our services primarily in the Permian Basin, the Eagle Ford Shale, the DJ Basin, the Williston Basin, the San Juan Basin, the Powder River Basin, the Haynesville Shale, the SCOOP/STACK, the Marcellus Shale, Utica Shale, and the Western Canadian Sedimentary Basin. Additionally, we operate two sand mines in the Permian Basin. 
+We believe technical innovation and strong relationships with our customer and supplier bases distinguish us from our competitors and are the foundations of our business. We expect that E&P companies will continue to focus on technological innovation as completion complexity and fracture intensity of horizontal wells increases, particularly as customers are increasingly focused on reducing emissions from their completions operations. We remain proactive in developing innovative solutions to industry challenges, including developing: (i) our databases of U.S. unconventional wells to which we apply our proprietary multi-variable statistical analysis technologies to provide differential insight into fracture design optimization; (ii) our Liberty Quiet Fleet® design which significantly reduces noise levels compared to conventional hydraulic fracturing fleets; (iii) hydraulic fracturing fluid systems tailored to the specific reservoir properties in the basins in which we operate; (iv) our dual fuel dynamic gas blending fleets that allow our engines to run diesel or a combination of diesel and natural gas, to optimize fuel use, reduce emissions and lower costs; (v) the successful test of digiFrac™, our innovative, purpose-built electric frac pump that has approximately 25% lower CO2e emission profile than the Tier IV DGB; and (vi) our PropX wet sand handling technology which eliminates the need to dry sand, enabling the deployment of mobile mines nearer to wellsites. In addition, our integrated supply chain includes proppant, chemicals, equipment, logistics and integrated software which we believe promotes wellsite efficiency and leads to more pumping hours and higher productivity throughout the year to better service our customers. In order to achieve our technological objectives, we carefully manage our liquidity and debt position to promote operational flexibility and invest in the business throughout the full commodity cycle in the regions we operate. 
+Recent Trends and Outlook 
+We believe the fundamental outlook for North American hydrocarbons remains healthy. E&P customers continue to see attractive drilling returns, particularly in oil, even as breakeven prices have increased from the pandemic lows. Major operators are redirecting capital spending to North America and domestic E&P operators’ pronouncements of returns targets infer a continuation of resource development to at least offset natural production declines. As North American oil and gas production reaches new heights, we expect to experience a rising level of frac demand to simply keep production flat. While some industry pullback in natural gas regions is possible, due to decreasing prices, demand in oilier areas continues to outstrip supply and we do not expect this possible pullback will have an impact on overall frac demand in 2023. 
+While demand currently remains strong, we acknowledge there is an elevated recession risk looming in global markets. However, we believe the impact of a possible recession on the industry in 2023 would be relatively muted due to disruptions in global oil supply, rather low spare global production capacity, and increased demand from the gradual reopening of China and rising global travel. We believe oil supply growth remains challenged as the release of U.S. strategic petroleum reserves subsides, the impact of the Russian oil products export embargo hits in the first quarter of 2023, and reduced investment across the Russian industry gradually impacts production. 
+In addition to the overall strong demand for frac supply, E&P operators are also focused on obtaining top tier equipment and service providers. Demand for natural gas powered fleets, in an effort to reduce fuel costs and emissions is strong and the 
+32 
+transition to natural gas-powered fleets is happening at a measured pace, which so far is roughly aligned with the attrition of the industry’s older generation diesel frac capacity. 
+During the year 2022, the posted WTI price traded at an average of $94.90 per barrel (“Bbl”), as compared to the 2021 average of $68.13 per Bbl, and the 2020 average of $39.16 per Bbl. In addition, the average domestic onshore rig count for the United States and Canada was 947 rigs reported in the fourth quarter of 2022, up from the average in the fourth quarter of 2021 of 704, according to a report from Baker Hughes. 
+Acquisitions 
+On December 31, 2020, the Company acquired certain assets and liabilities of Schlumberger’s OneStim business, which provides hydraulic fracturing pressure pumping services in onshore United States and Canada, including its pressure pumping, pumpdown perforating and Permian frac sand business, in exchange for consideration resulting in a total of 66,326,134 shares of the Class A Common Stock being issued in connection with the OneStim Acquisition. The combined company delivers best-in-class completion services for the sustainable development of unconventional resource plays in the United States and Canada onshore markets. 
+On October 26, 2021, the Company acquired PropX in exchange for $ 11.9 million in cash, 3,405,526 shares of Class A Common Stock and 2,441,010 shares of Class B Common Stock, and 2,441,010 Liberty LLC Units, for total consideration of $ 103.0 million, based on the Class A Common Stock closing price of $ 15.58 on October 26, 2021, subject to customary post-closing adjustments. The Liberty LLC Units were redeemable for an equivalent number of shares of Class A Common Stock at any time, at the election of the shareholder. Founded in 2016, PropX is a leading provider of last-mile proppant delivery solutions including proppant handling equipment and logistics software across North America. PropX offers innovative environmentally friendly technology with optimized dry and wet sand containers and wellsite proppant handling equipment that drive logistics efficiency and reduce noise and emissions. We believe that PropX wet sand handling technology is a key enabler of the next step of cost and emissions reductions in the proppant industry. PropX also offers customers the latest real-time logistics software, PropConnect, for sale or as hosted software as a service. 
+Increase in Drilling Efficiency and Service Intensity of Completions 
+Over the past decade, E&P companies have focused on exploiting the vast resource potential available across many of North America’s unconventional resource plays through the application of horizontal drilling and completion technologies, including the use of multi-stage hydraulic fracturing, in order to increase recovery of oil and natural gas. As E&P companies have improved drilling and completion techniques to maximize return and efficiency, we believe that their “break-even oil prices” continue to decline. These improvements in well economics have kept U.S. Shale oil and gas production competitive even as oil and gas prices have declined. Liberty has been a significant partner with our customers in driving these continued improvements. 
+Improved drilling economics from horizontal drilling and greater rig efficiencies . Unconventional resources are increasingly being targeted through the use of horizontal drilling. According to Baker Hughes, as reported on January 27, 2023, horizontal rigs accounted for approximately 91% of all rigs drilling in the United States and Canada, up from 77% as of December 26, 2014. Over the past several years, North American E&P companies have benefited from improved drilling economics driven by technologies that reduce the number of days, and the cost, of drilling wells. North American drilling rigs have incorporated newer technologies, which allow them to drill rock more effectively and quickly, meaning each rig can drill more wells in a given period. These include improved drilling technologies and the incorporation of geosteering techniques which allow better placement of the wellbore. Drilling rigs have also incorporated new technology which allows fully assembled rigs to automatically “walk” from one location to the next without disassembling and reassembling the rig, greatly reducing the time it takes to move from one drilling location to the next. Today the majority of E&P drilling is on multi-well pad development, allowing efficient drilling of multiple horizontal wellbores from the same pad or location. The aggregate effect of these improved techniques and technologies have reduced the average days required to drill a well, which according to Lium Research, has dropped from 28 days in 2014 to 18 days in 2022. 
+Increased complexity and service intensity of horizontal well completions . In addition to improved rig efficiencies discussed above, E&P companies are also improving the subsurface techniques and technologies used to exploit unconventional resources. These improvements have targeted increasing the exposure of each wellbore to the reservoir by drilling longer horizontal lateral sections of the wellbore. To complete the well, hydraulic fracturing is applied in stages along the wellbore to break-up the resource so that oil and gas can be produced. As wellbores have increased in length, the number of frac stages and/or the number of perforation clusters (frac initiation points) has also increased. Further, E&P companies have improved production from each stage by applying increasing amounts of proppant in each stage, which better connects the well to the resource. The aggregate effect of increased number of stages and the increasing amount of proppant in each stage has greatly increased the total amount of proppant used in each well, according to Liberty’s FracTrends database, from six million pounds per well in 2014 to over 20 million pounds per well in 2022. Further efficiency gains are being sought via the “simul-frac” 
+33 
+technique. Utilizing a larger frac fleet (1.25x to 2x the normal horsepower), operators are fracturing stages in two separate wells on a pad simultaneously as a single operation. When compared to typical zipper-frac operations, this new method allows for more lateral feet to be completed in a day. This emerging trend will allow operators to complete a pad of wells quicker, thereby shortening the time from spud to first production. 
+These industry trends continue to keep our customers as important suppliers to the global oil and natural gas markets, which directly benefit hydraulic fracturing companies like us that have the expertise and innovative technology to effectively service today’s more efficient oilfield drilling activity and the increasing complexity and intensity of well completions. Given the expected returns that E&P companies have reported for new well development activities due to improved rig efficiencies and increasing well completion complexity and intensity, we expect these industry trends to continue. 
+How We Generate Revenue 
+We currently generate revenue through the provision of hydraulic fracturing and wireline services and goods, including sand from our Permian Basin sand mines. These services and goods are provided under a variety of contract structures, primarily master service agreements (“MSAs”) as supplemented by statements of work, pricing agreements and specific quotes. A portion of our statements of work, under MSAs, include provisions that establish pricing arrangements for a period of up to approximately one year in length. However, the majority of those agreements provide for pricing adjustments based on market conditions. The majority of our services are priced based on prevailing market conditions and changing input costs at the time the services are provided, giving consideration to the specific requirements of the customer. 
+Our hydraulic fracturing and wireline services are performed in sections, which we refer to as fracturing stages. The estimated number of fracturing stages to be completed for a particular horizontal well is determined by the customer’s well completion design. We recognize revenue for each fracturing stage completed, although our revenue per completed fracturing stage varies depending on the actual volumes and types of proppants, chemicals, and fluid utilized for each fracturing stage. The number of fracturing stages that we are able to complete in a period is directly related to the number and utilization of our deployed fleets and size of stages. 
+Costs of Conducting Our Business 
+The principal expenses involved in conducting our business are direct cost of personnel, services, and materials used in the provision of services, general and administrative expenses, and depreciation, depletion, and amortization. A large portion of the costs we incur in our business are variable based on the number of hydraulic fracturing jobs and the requirements of services provided to our customers. We manage the level of our fixed costs, except depreciation, depletion, and amortization, based on several factors, including industry conditions and expected demand for our services. 
+How We Evaluate Our Operations 
+We use a variety of qualitative, operational and financial metrics to assess our performance. First and foremost, of these is a qualitative assessment of customer satisfaction because ensuring we are a valuable partner to our customers is the key to achieving our quantitative business metrics. Among other measures, management considers each of the following: 
+• Revenue; 
+• Operating Income; 
+• EBITDA; 
+• Adjusted EBITDA; 
+• Net Income Before Taxes; and 
+• Earnings per Share. 
+Revenue 
+We analyze our revenue by comparing actual monthly revenue to our internal projections for a given period and to prior periods to assess our performance. 
+Operating Income 
+We analyze our operating income, which we define as revenues less direct operating expenses, depreciation and amortization and general and administrative expenses, to measure our financial performance. We believe operating income is a meaningful metric because it provides insight on profitability and true operating performance based on the historical cost basis of our assets. We also compare operating income to our internal projections for a given period and to prior periods. 
+34 
+EBITDA and Adjusted EBITDA 
+We view EBITDA and Adjusted EBITDA as important indicators of performance. We define EBITDA as net income (loss) before interest, income taxes, depreciation, depletion, and amortization. We define Adjusted EBITDA as EBITDA adjusted to eliminate the effects of items such as non-cash stock-based compensation, new fleet or new basin start-up costs, fleet lay-down costs, costs of asset acquisitions, gain or loss on the disposal of assets, bad debt reserves, transaction, severance, and other costs, the loss or gain on remeasurement of liability under our tax receivable agreements, the gain or loss on investments and other non-recurring expenses that management does not consider in assessing ongoing performance. See “Comparison of Non-GAAP Financial Measures” for more information and a reconciliation of EBITDA and Adjusted EBITDA to net income (loss), the most directly comparable financial measure calculated and presented in accordance with GAAP. 
+Results of Operations 
+Year Ended December 31, 2022, Compared to Year Ended December 31, 2021 
+Years Ended December 31, 
+Description 2022 2021 Change 
+(in thousands) 
+Revenue $ 4,149,228 $ 2,470,782 $ 1,678,446 
+Cost of services, excluding depreciation, depletion, and amortization shown separately 3,149,036 2,249,926 899,110 
+General and administrative 180,040 123,406 56,634 
+Transaction, severance and other costs 5,837 15,138 (9,301) 
+Depreciation, depletion, and amortization 323,028 262,757 60,271 
+(Gain) loss on disposal of assets (4,603) 779 (5,382) 
+Operating income (loss) 495,890 (181,224) 677,114 
+Other expense (income), net 96,381 (3,436) 99,817 
+Net income (loss) before income taxes 399,509 (177,788) 577,297 
+Income tax (benefit) expense (793) 9,216 (10,009) 
+Net income (loss) 400,302 (187,004) 587,306 
+Less: Net income (loss) attributable to non-controlling interests 700 (7,760) 8,460 
+Net income (loss) attributable to Liberty Energy Inc. stockholders $ 399,602 $ (179,244) $ 578,846 
+Revenue 
+Our revenue increased $1.7 billion, or 68%, to $4.1 billion for the year ended December 31, 2022 compared to $2.5 billion for the year ended December 31, 2021. The increase in revenue is attributable to higher service pricing, the reactivation of several fleets during the year, and an activity-driven increase in fleet utilization and efficiency commensurate with increased demand for hydraulic fracturing services. 
+Cost of Services 
+Cost of services (excluding depreciation, depletion, and amortization) increased $0.9 billion, or 40%, to $3.1 billion for the year ended December 31, 2022 compared to $2.2 billion for the year ended December 31, 2021. The increase in expense was primarily related to increases in materials and parts consumption and higher labor costs related to additional fleets and higher fleet utilization as well as ongoing inflationary increases impacting costs for materials, labor, and maintenance parts. 
+General and Administrative 
+General and administrative expenses increased $56.6 million, or 46%, to $180.0 million for the year ended December 31, 2022 compared to $123.4 million for the year ended December 31, 2021 primarily related to an increase in performance-based variable compensation, labor cost inflation, and corporate costs related to increased levels of activity. 
+35 
+Transaction, Severance and Other Costs 
+Transaction, severance and other costs of $5.8 million and $15.1 million for the years ended December 31, 2022 and 2021, respectively, consist of integration cost, investment banking, legal, accounting, and other professional services provided in connection with the OneStim Acquisition and PropX Acquisition. Such costs were lower during the year ended December 31, 2022 as the integration efforts were completed during the year. 
+Depreciation, Depletion, and Amortization 
+Depreciation, depletion, and amortization expense increased $60.3 million, or 23%, to $323.0 million for the year ended December 31, 2022 compared to $262.8 million for the year ended December 31, 2021. The increase in 2022 was due to additional equipment placed in service since the prior year period and additional depreciation from property acquired in the PropX Acquisition. 
+(Gain) Loss on Disposal of Assets 
+The Company recorded a gain on disposal of assets of $4.6 million for the year ended December 31, 2022 due to miscellaneous equipment disposals and sales of facilities in the normal course of business, compared to a loss of $0.8 million for the year ended December 31, 2021. The gain as of December 31, 2022 was a result of the sale of used field equipment and light duty trucks in a strong used vehicle and equipment market offset by a loss on sale of two non-strategic facilities acquired in the OneStim Acquisition and a loss on plan of sale for two other non-strategic facilities. The loss as of December 31, 2021 related to the sale of three non-strategic facilities acquired in the OneStim Acquisition, which collectively resulted in a small loss on sale, along with regular sales of equipment that was no longer being used. 
+Operating Income (Loss) 
+The Company recorded operating income of $495.9 million for the year ended December 31, 2022 compared to operating loss of $181.2 million for the year ended December 31, 2021. The operating income is primarily due to the $1.7 billion, or 68%, increase in total revenue partially offset by a $1.0 billion increase in total operating expenses, the significant components of which are discussed above. 
+Other Expense (Income), net 
+The Company recorded other expense, net of $96.4 million for the year ended December 31, 2022 compared to other income, net of $3.4 million during the year ended December 31, 2021. Other expense (income), net is comprised of loss on remeasurement of liability under the TRAs, gain on investments, and interest expense, net. As a result of the valuation allowance on the U.S. net deferred tax assets, discussed below, the Company remeasured the liability under the TRAs resulting in a loss of $76.2 million during the year ended December 31, 2022, compared to a gain of $19.0 million for the year ended December 31, 2021. A $2.5 million gain on investments was recorded during the year ended December 31, 2022, compared to no gain for the year ended December 31, 2021. Additionally, interest expense, net increased between periods, increasing $7.1 million as a result of increased borrowings and higher interest rates under the credit facility during the year ended December 31, 2022 compared to the year ended December 31, 2021. 
+Net Income (Loss) Before Income Taxes 
+The Company realized net income before income taxes of $399.5 million for the year ended December 31, 2022 compared to a net loss before income taxes of $177.8 million for the year ended December 31, 2021. The increase in results is primarily attributable to an increase in revenue, as discussed above, related to the fleet deployments and an increase in activity and service pricing. 
+Income Tax (Benefit) Expense 
+The Company recognized an income tax benefit of $0.8 million for the year ended December 31, 2022, at an effective rate of (0.2)%, compared to income tax expense of $9.2 million, at an effective rate of (5.2)%, recognized for the year ended December 31, 2021. The decrease in income tax expense is primarily attributable to the Company releasing the valuation allowance on its U.S. net deferred tax assets in the current year, compared to the prior year recording of a valuation allowance on its U.S. net deferred tax assets. 
+36 
+Comparison of Non-GAAP Financial Measures 
+We view EBITDA and Adjusted EBITDA as important indicators of performance. We define EBITDA as net income (loss) before interest, income taxes, and depreciation, depletion, and amortization. We define Adjusted EBITDA as EBITDA adjusted to eliminate the effects of items such as non-cash stock-based compensation, new fleet or new basin start-up costs, fleet lay-down costs, costs of asset acquisitions, gain or loss on the disposal of assets, bad debt reserves, transaction, severance, and other costs, the loss or gain on remeasurement of liability under our tax receivable agreements, the gain or loss on investments and other non-recurring expenses that management does not consider in assessing ongoing performance. 
+Our board of directors, management, investors, and lenders use EBITDA and Adjusted EBITDA to assess our financial performance because it allows them to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure (such as varying levels of interest expense), asset base (such as depreciation, depletion, and amortization) and other items that impact the comparability of financial results from period to period. We present EBITDA and Adjusted EBITDA because we believe they provide useful information regarding the factors and trends affecting our business in addition to measures calculated under GAAP. 
+Note Regarding Non-GAAP Financial Measures 
+EBITDA and Adjusted EBITDA are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures will provide useful information to investors in assessing our financial performance and results of operations. Net income (loss) is the GAAP measure most directly comparable to EBITDA and Adjusted EBITDA. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as an analytical tool due to exclusion of some but not all items that affect the most directly comparable GAAP financial measures. You should not consider EBITDA or Adjusted EBITDA in isolation or as substitutes for an analysis of our results as reported under GAAP. Because EBITDA and Adjusted EBITDA may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. 
+The following tables present a reconciliation of EBITDA and Adjusted EBITDA to our net income (loss), which is the most directly comparable GAAP measure for the periods presented: 
+Year Ended December 31, 2022 Compared to Year Ended December 31, 2021: EBITDA and Adjusted EBITDA 
+Years Ended December 31, 
+Description 2022 2021 Change 
+(in thousands) 
+Net income (loss) $ 400,302 $ (187,004) $ 587,306 
+Depreciation, depletion, and amortization 323,028 262,757 60,271 
+Interest expense, net 22,715 15,603 7,112 
+Income tax (benefit) expense (793) 9,216 (10,009) 
+EBITDA $ 745,252 $ 100,572 $ 644,680 
+Stock-based compensation expense 23,108 19,946 3,162 
+Fleet start-up and lay-down costs 17,007 2,751 14,256 
+Transaction, severance and other costs 5,837 15,138 (9,301) 
+(Gain) loss on disposal of assets (4,603) 779 (5,382) 
+Provision for credit losses — 745 (745) 
+Loss (gain) on remeasurement of liability under tax receivable agreements 76,191 (19,039) 95,230 
+Gain on investments $ (2,525) $ — $ (2,525) 
+Adjusted EBITDA $ 860,267 $ 120,892 $ 739,375 
+EBITDA was $745.3 million for the year ended December 31, 2022 compared to $100.6 million for the year ended December 31, 2021. Adjusted EBITDA was $860.3 million for the year ended December 31, 2022 compared to $120.9 million for the year ended December 31, 2021. The increases in EBITDA and Adjusted EBITDA primarily resulted from improved market conditions and increased activity levels as described above under the captions Revenue , Cost of Services, and General and Administrative Expenses for the Year Ended December 31, 2022, Compared to Year Ended December 31, 2021 . 
+37 
+Liquidity and Capital Resources 
+Overview 
+Historically, our primary sources of liquidity to date have been cash flows from operations, proceeds from our IPO, and borrowings under our ABL Facility and Term Loan Facility (collectively, the “Credit Facilities”). We expect to fund operations and organic growth with cash flows from operations and available borrowings under our ABL Facility. We monitor the availability of capital resources such as equity and debt financings that could be leverage for current or future financial obligations including those related to acquisitions, capital expenditures, working capital and other liquidity requirements. We may incur additional indebtedness or issue equity in order to meet our capital expenditure activities and liquidity requirements, as well as to fund growth opportunities that we pursue, including via acquisition, such as with the OneStim Acquisition and the PropX Acquisition. Our primary uses of capital have been capital expenditures to support organic growth and funding ongoing operations, including maintenance and fleet upgrades. 
+Cash and cash equivalent s increased by $23.7 million to $43.7 million as of December 31, 2022 compared to $20.0 million as of December 31, 2021, while working capital excluding cash and current liabilities under debt and lease arrangements increased $221.3 million. 
+As of December 31, 2022, we had $425.0 million committed under the ABL Facility subject to certain borrowing base limitations based on a percentage of eligible accounts receivable and inventory available to finance working capital needs. As of December 31, 2022, the borrowing base was calculated to be $425.0 million, and the Company had $115.0 million outstanding, in addition to a letter of credit in the amount of $2.6 million, with $307.4 million of remaining availability. 
+Additionally, as of December 31, 2022, we have $104.7 million borrowings remaining on the Term Loan Facility, which was originally $175.0 million. 
+The ABL Facility has a maturity date of the earlier of (a) October 22, 2026 and (b) to the extent the debt under the Term Loan Facility remains outstanding 90 days prior to the final maturity of the Term Loan Facility, which matures on September 19, 2024. 
+On July 18, 2022, the Company entered into an amendment to the ABL Facility (the “Seventh ABL Amendment”). The Seventh ABL Amendment amended certain terms, provisions, and covenants of the ABL Facility, including among other things: (i) increasing the maximum borrowing amount by $75.0 million to $425.0 million, subject to certain borrowing base limitations based on percentage of eligible accounts receivable and inventory, (ii) modifying certain covenant and reporting-related baskets, and (iii) replacing LIBOR with the secured overnight financing rate (“SOFR”) as the interest rate benchmark. 
+On August 12, 2022, the Company entered into an amendment to the Term Loan Facility (the “Sixth Term Loan Amendment”). The Sixth Term Loan Amendment amended certain terms, provisions and covenants of the Term Loan Facility, including among other things: (i) a waiver of the fixed charge coverage ratio requirements for up to $100.0 million of restricted payments made in connection with the Company’s 2022 stock repurchase program for its common stock; (ii) the addition of a minimum liquidity requirement of $150.0 million in order to make selected restricted payments, including those made under the 2022 stock repurchase program; (iii) the modification of certain covenant and reporting-related terms, including an increase in the allowance for permitted purchase money indebtedness from $50.0 million to $70.0 million; (iv) the addition of a prepayment premium of 1.0% through the first anniversary of the Sixth Term Loan Amendment effective date; and (v) the addition and modification of several provisions to replace LIBOR with SOFR as the interest rate benchmark. 
+On November 4, 2022, the Company entered into an amendment to the Term Loan Facility (the “Seventh Term Loan Amendment”). The Seventh Term Loan Amendment amended the restricted payments negative covenant of the Term Loan Facility so that the fixed charge coverage ratio requirements for dividend payments are waived, so long as the total of dividends paid and payments made in connection with the Company’s 2022 stock repurchase program does not exceed $100.0 million. During the fourth quarter of 2022 the restricted payments negative covenant pertaining to the fixed charge coverage ratio requirements were satisfied and the $100.0 million limit no longer applied. 
+Subsequent to the fiscal year end, on January 23, 2023, the Company entered into an Eighth Amendment to the ABL Facility (the “Eighth ABL Amendment”). The Eighth ABL Amendment amends certain terms, provisions and covenants of the ABL Facility, including, among other things: (i) increasing the maximum revolver amount from $425.0 million to $525.0 million (the “Upsized Revolver”); (ii) increasing the amount of the accordion feature from $75.0 million to $100.0 million; (iii) extending the maturity date from October 22, 2026 to January 23, 2028; (iv) modifying the dollar amounts of various credit facility triggers and tests proportionally to the Upsized Revolver; (v) permitting repayment under the Term Loan Facility prior to February 10, 2023; and (vi) increasing certain indebtedness, intercompany advance, and investment baskets. The Eighth ABL Amendment also includes an agreement from the Wells Fargo Bank, National Association, as administrative agent, to release its second priority liens and security interests on all collateral that served as first priority collateral under the Term Loan Facility, with such release to occur within 120 days after January 23, 2023. 
+Additionally, on January 23, 2023 the Company withdrew $106.7 million on the ABL Facility and used the proceeds to pay off the Term Loan Facility. The balance of the Term Loan Facility upon pay off was $104.7 million and included $0.9 
+38 
+million of accrued interest and a $1.1 million prepayment premium or 1% of the principal. Additionally, there were $0.2 million in bank and legal fees included in the pay off. As such, the only outstanding debt facility after January 23, 3023 is the ABL Facility. Refer to “Our current and future indebtedness could adversely affect our financial condition” included in “Item 1A. Risk Factors” above for further details on the outstanding balance of the ABL Facility as of the filing date. 
+The Credit Facilities contain covenants that restrict our ability to take certain actions. At December 31, 2022, we were in compliance with all debt covenants. 
+See Note 8 —Debt to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for further details. 
+We have no material off balance sheet arrangements as of December 31, 2022, except for purchase commitments under supply agreements as disclosed below under Note 15—Commitments & Contingencies in “Item 8. Financial Statements and Supplementary Data.” As such, we are not materially exposed to any other financing, liquidity, market, or credit risk that could arise if we had engaged in such financing arrangements. 
+Share Repurchase Program 
+Under our share repurchase program, the Company is authorized to repurchase up to $250.0 million of outstanding Class A Common Stock through and including July 31, 2024. Additionally, on January 24, 2023 the Board authorized and the Company announced an increase to the share repurchase program that increased the Company’s cumulative repurchase authorization to $500.0 million. Shares may be repurchased from time to time for cash in the open market transactions, through block trades, in privately negotiated transactions, through derivative transactions or by other means in accordance with applicable federal securities laws. The timing and the amount of repurchases will be determined by the Company at its discretion based on an evaluation of market conditions, capital allocation alternatives and other factors. The share repurchase program does not require us to purchase any dollar amount or number of shares of our Class A Common Stock and may be modified, suspended, extended or terminated at any time without prior notice. The Company expects to fund the repurchases by using cash on hand, borrowings under its revolving credit facility and expected free cash flow to be generated over the next two years. 
+Cash Flows 
+The following table summarizes our cash flows for the periods indicated: 
+Years Ended December 31, 
+Description 2022 2021 Change 
+(in thousands) 
+Net cash provided by operating activities 
+$ 530,364 $ 135,467 $ 394,897 
+Net cash used in investing activities 
+(450,656) (186,494) (264,162) 
+Net cash (used in) provided by financing activities 
+(55,770) 2,056 (57,826) 
+Analysis of Cash Flow Changes Between the Years Ended December 31, 2022 and December 31, 2021 
+Operating Activities . Net cash provided by operating activities was $530.4 million for the year ended December 31, 2022, compared to $135.5 million for the year ended December 31, 2021. The $394.9 million increase in cash from operating activities is primarily attributable to a $1.7 billion increase in revenues, offset by a $0.9 billion increase in cash operating expenses and a $277.9 million decrease in cash from changes in working capital for the year ended December 31, 2022, compared to a $46.9 million increase in cash from changes in working capital for the year ended December 31, 2021. 
+Investing Activities . Net cash used in investing activities was $450.7 million for the year ended December 31, 2022, compared to $186.5 million for the year ended December 31, 2021. Cash used in investing activities was higher during the year ended December 31, 2022, compared to the year ended December 31, 2021 as the Company continued to invest in equipment, including building new digiFrac™ fleets and deploying additional fleets, to support increased customer demand in next generation equipment and technology. 
+Financing Activities . Net cash used in financing activities was $55.8 million for the year ended December 31, 2022, compared to net cash provided by financing activities of $2.1 million for the year ended December 31, 2021. The $57.8 million change in cash used in financing activities was primarily due to $125.3 million of cash payments made in connection with share repurchases for the year ended December 31, 2022, compared to none in the year ended December 31, 2021 as the Company reinstated the share buyback program. Additionally, the Company reinstated quarterly dividends during the fourth quarter of 2022 resulting in a $9.0 million increase in dividends and per unit distributions to non-controlling interest unitholders. The increases in cash outflows as a result of reinstated shareholder return programs were offset by net borrowings of $97.0 million 
+39 
+on the ABL Facility during the year ended December 31, 2022, compared to $18.0 million net borrowings on the ABL Facility for the year ended December 31, 2021. Other changes in financing activity included a $6.1 million increase in payments made for tax withholding on restricted stock unit vesting as a larger number of units vested at a higher stock price in 2022 compared to 2021, and a slight decrease in other distributions and advance payments received from non-controlling interest holders. 
+Cash Requirements 
+Our material cash commitments consist primarily of obligations under long-term debt, TRAs, finance and operating leases for property and equipment, cash used to pay for repurchases of shares of our Class A Common Stock, and purchase obligations as part of normal operations. Certain amounts included in our contractual obligations as of December 31, 2022 are based on our estimates and assumptions about these obligations, including pricing, volumes and duration. We have no material off balance sheet arrangements as of December 31, 2022, except for purchase commitments under supply agreements disclosed below. 
+See Note 8 —Debt to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding scheduled maturities of our long-term debt. See Note 6 —Leases to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding scheduled maturities of finance and operating leases. 
+As of December 31, 2022, we had expected cash payments for estimated interest on our finance lease obligations of $2.3 million payable within the next twelve months and $3.4 million payable thereafter. 
+Effective January 23, 2023 the Company withdrew $106.7 million on the ABL Facility and used the proceeds to pay off the Term Loan Facility. The balance of the Term Loan Facility upon pay off was $104.7 million and included $0.9 million of accrued interest and a $1.1 million prepayment premium. As such, the only outstanding debt facility after January 23, 3023 is the ABL Facility. 
+As of December 31, 2022, we had purchase obligations of $158.7 million payable within the next twelve months and $44.8 million payable thereafter. See Note 15 —Commitments & Contingencies to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding scheduled contractual obligations. 
+As of December 31, 2022, we do not expect to make any payments under the TRAs within the next twelve months, future amounts payable under the TRAs are dependent upon future events. See Note 12 —Income Taxes to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for information regarding the TRAs. 
+Other Factors Affecting Liquidity 
+Customer receivables: In line with industry practice, we typically bill our customers for services provided in arrears dependent upon contractual terms. In weak economic environments, we may experience delays in collection from our customers. In the past, including as a result of the COVID-19 pandemic on the industry, we have experienced delays in customer payments and agreed to extended payment terms, however, we have not experienced any material non-payment events. 
+Tax Receivable Agreements 
+In connection with the IPO, on January 17, 2018, the Company entered into two TRAs with the TRA Holders. The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that the Company actually recognizes (or is deemed to recognize in certain circumstances) in periods after the IPO as a result, as applicable to each of the TRA Holders, of (i) certain increases in tax basis that occur as a result of the Company’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holders’ Liberty LLC Units in connection with the IPO or pursuant to the exercise of the right of each Liberty Unit Holder (the “Redemption Right”), subject to certain limitations, to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units for, at Liberty LLC’s election, (A) shares of our Class A Common Stock at the specific redemption ratio or (B) an equivalent amount of cash, or, upon the exercise of the Redemption Right, the right of the Company (instead of Liberty LLC) to, for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder (the “Call Right”) for, at its election, (1) one share of Class A Common Stock or (2) an equivalent amount of cash, (ii) any net operating losses available to the Company as a result of the Corporate Reorganization, and (iii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRAs. On January 31, 2023, the last redemption of the Liberty LLC Units occurred. 
+40 
+With respect to obligations the Company expects to incur under the TRAs (except in cases where the Company elects to terminate the TRAs early, the TRAs are terminated early due to certain mergers, asset sales, or other changes of control or the Company has available cash but fails to make payments when due), generally the Company may elect to defer payments due under the TRAs if the Company does not have available cash to satisfy its payment obligations under the TRAs or if its contractual obligations limit its ability to make such payments. Any such deferred payments under the TRAs generally will accrue interest. In certain cases, payments under the TRAs may be accelerated and/or significantly exceed the actual benefits, if any, the Company realizes in respect of the tax attributes subject to the TRAs. The Company accounts for amounts payable under the TRAs in accordance with Accounting Standard Codification (“ASC”) Topic 450, Contingencies (“ASC Topic 450”). 
+If the Company experiences a change of control (as defined under the TRAs) or the TRAs otherwise terminate early, the Company’s obligations under the TRAs could have a substantial negative impact on its liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. There can be no assurance that we will be able to finance our obligations under the TRAs. 
+Income Taxes 
+The Company is a corporation and is subject to U.S. federal, state, and local income tax on its share of Liberty LLC’s taxable income. The Company is also subject to Canada federal and provincial income tax on its foreign operations. 
+The combined effective tax rate applicable to the Company for the year ended December 31, 2022 and 2021 was (0.2)% and (5.2)%, respectively. The Company’s effective tax rate is significantly less than the federal statutory income tax rate of 21.0% due to the Company releasing the valuation allowance on its U.S. net deferred tax assets as of December 31, 2022, primarily due to entering into a three-year cumulative pre-tax book income position and improved operating results. For 2021, the Company’s effective tax rate is less than the statutory rate due to the Company recording a valuation allowance on its U.S. net deferred tax assets as well as tax on foreign operations, and the non-controlling interest’s share of Liberty LLC’s pass-through results for federal, state and local income tax reporting, upon which no taxes are payable by the Company. 
+The Company recognized an income tax benefit of $(0.8) million and income tax expense of $9.2 million for the years ended December 31, 2022 and 2021, respectively. The Company’s effective tax rate can be volatile and may change with, among other things, the amount of jurisdiction pre-tax income or loss, ability to utilize foreign tax credits, excess tax benefits or deficiencies from share-based compensation and changes in tax laws in the jurisdictions that we operate. 
+Per the Coronavirus Aid, Relief and Economic Security (“CARES”) Act enacted on March 27, 2020, net operating losses (“NOL”) incurred in 2019, and 2020 may be carried back to each of the five preceding taxable years to generate a refund of previously paid income taxes. The Company has previously applied for and expects to receive a NOL carryback refund to recover $5.5 million of cash taxes paid by the Company in 2018. This amount has been reflected as a receivable in the prepaids and other current assets line item in the accompanying audited consolidated balance sheets. 
+Deferred income tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial reporting and tax bases of assets and liabilities, and are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. In the year ended December 31, 2022, we released a valuation allowance on our U.S. net deferred tax assets. As of December 31, 2021, the Company’s net deferred tax assets were primarily comprised of U.S. NOL, investment in Liberty LLC, and TRA tax attributes of $91.3 million. For the year ended December 31, 2022, the Company recorded a tax benefit of $91.3 million related to the release of the valuation allowance on U.S. net deferred tax assets that are more like than not to be recognized. In addition, the release of the valuation allowance resulted in an increase in the tax receivable agreement liability and a loss on remeasurement of liability under tax receivable agreements of $76.2 million for the year ended December 31, 2022. 
+Refer to Note 12— Income Taxes to the consolidated financial statements for additional information related to income tax expense. 
+Critical Accounting Policies and Estimates 
+The preparation of financial statements requires the use of judgments and estimates. Our critical accounting policies are described below to provide a better understanding of how we develop our assumptions and judgments about future events and related estimates and how they can impact our financial statements. A critical accounting estimate is one that requires our most difficult, subjective or complex estimates and assessments and is fundamental to our results of operations. 
+We base our estimates on historical experience and on various other assumptions we believe to be reasonable according to the current facts and circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. We believe the following are the critical accounting policies used in the preparation of our consolidated financial statements, as well as the significant estimates and judgments affecting the application of these policies. This discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included in “Item 8. Financial Statements and Supplementary Data. ” 
+41 
+Revenue Recognition: Revenue from hydraulic fracturing services is recognized as specific services are provided in accordance with contractual arrangements. If our assessment of performance under a particular contract change, our revenue and / or costs under that contract may change. In connection with ASC Topic 842 - Leases (“Topic 842”), the Company determined that certain of its service revenue contracts contain a lease component. The Company elected to adopt a practical expedient available to lessors, which allows the Company to combine the lease and service component for certain of the Company’s service contracts when the service component is the predominant component and continues to account for the combined component under ASC Topic 606 - Revenue from Contracts with Customers . 
+Inventory: Inventory consists of raw materials used in the hydraulic fracturing process, such as proppants, chemicals and field service equipment maintenance parts, and is stated at the lower of cost or net realizable value, determined using the weighted average cost method. Net realizable value is determined based on our estimates of selling prices in the ordinary course of business, less reasonably predictable cost of completion, disposal, and transportation, each of which require us to apply judgment. 
+Property and Equipment: We calculate depreciation and amortization on our assets based on the estimated useful lives and estimated salvage values that we believe are reasonable. The estimated useful lives and salvage values are subject to key assumptions such as maintenance, utilization and job variation. These estimates may change due to a number of factors such as changes in operating conditions or advances in technology. 
+We incur maintenance costs on our major equipment. The determination of whether an expenditure should be capitalized or expensed requires management judgment in the application of how the costs benefit future periods, relative to our capitalization policy. Costs that either establish or increase the efficiency, productivity, functionality or life of a fixed asset are capitalized and depreciated over the remaining useful life of the asset. 
+Impairment of long-lived and other intangible assets: Long-lived assets, such as property and equipment, right-of-use lease assets and intangible assets, are evaluated for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Recoverability is assessed using undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets. When alternative courses of action to recover the carrying amount of the asset group are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence, which require us to apply judgment. If the carrying amount of the asset is not recoverable based on its estimated undiscounted cash flows expected to result from the use and eventual disposition, an impairment loss is recognized in an amount by which its carrying amount exceeds its estimated fair value. The inputs used to determine such fair value are primarily based upon internally developed cash flow models. Our cash flow models are based on a number of estimates regarding future operations that may be subject to significant variability, are sensitive to changes in market conditions, and are reasonably likely to change in the future. 
+No impairment was recognized during the years ended December 31, 2022 and 2021. 
+Leases: In accordance with ASC Topic 842, Leases , the Company determines if an arrangement is a lease at inception and evaluates identified leases for operating or finance lease treatment. Operating or finance lease right-of-use assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. We use our incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments. Lease terms may include options to renew; however, we typically cannot determine our intent to renew a lease with reasonable certainty at inception. 
+Tax Receivable Agreements: In connection with the IPO, on January 17, 2018, the Company entered into two TRAs with the TRA Holders. The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax that the Company actually realizes in periods after the IPO as a result of certain tax attributes applicable to each TRA Holder. The Company accounts for amounts payable under the TRAs in accordance with ASC Topic 450, Contingencies . 
+Share Repurchases: The Company accounts for the purchase price of repurchased Class A Common Stock in excess of par value ($0.01 per share of Class A Common Stock) as a reduction of additional paid-in capital, and will continue to do so until additional paid-in capital is reduced to zero. Thereafter, any excess purchase price will be recorded as a reduction to retained earnings. All Class A Common Stock shares repurchased are retired upon repurchase. 
+42 
+Item 7A. Quantitative and Qualitative Disclosure about Market Risk 
+Industry Risk 
+The demand, pricing and terms for hydraulic fracturing services and related goods provided by us are largely dependent upon the level of drilling activity in the U.S. oil and natural gas industry, as well as the available supply of hydraulic fracturing equipment. These activity levels are influenced by numerous factors over which we have no control, including, but not limited to: the supply of and demand for oil and natural gas; the level of prices, and expectations about future prices of oil and natural gas; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; the discovery rates of new oil and natural gas reserves; supply of actively marketed and staffed fracturing fleets; available rail and other transportation capacity; weather conditions; domestic and worldwide economic conditions; political instability in oil-producing countries; environmental regulations; technical advances affecting energy consumption; the price and availability of alternative fuels; the ability of E&P companies to raise equity capital and debt financing; and merger and divestiture activity among E&P companies. 
+The level of U.S. oil and natural gas drilling is volatile. Expected trends in oil and natural gas production activities may not materialize and demand for our services may not reflect the level of activity in the industry. Any prolonged and substantial reduction in oil and natural gas prices would likely affect oil and natural gas production levels and therefore affect demand for our services. A material decline in oil and natural gas prices or U.S. activity levels could have a material adverse effect on our business, financial condition, results of operations and cash flows. 
+Interest Rate Risk 
+At December 31, 2022, we had $219.7 million of debt outstanding, with a weighted average interest rate of 9.0%. Interest is calculated under the terms of our Credit Facilities based on our selection, from time to time, of one of the index rates available to us plus an applicable margin that varies based on certain factors. See “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements.” Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the weighted average interest rate would be approximately $2.2 million per year. We do not currently have or intend to enter into any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness. 
+Commodity Price Risk 
+Our material and fuel purchases expose us to commodity price risk. Material costs primarily include inventory consumed while performing hydraulic fracturing services. Fuel costs consist of diesel fuel used by trucks and other motorized equipment used for hydraulic fracturing services. At times, we have been able to pass along price increases for material costs and fuel costs to customers and conversely have been required to pass along price decreases for material costs to our customers, depending on market conditions. Further, we have purchase commitments with certain vendors to supply proppant inventory used in our operations at a fixed purchase price, including certain commitments which include minimum purchase obligations. Refer t o Note 15 — Commitments and Contingencies included in “Item 8. Financial Statements and Supplementary Data” for further discussion regarding pur chase commitments. 
+Foreign Translation Risk 
+Our consolidated financial statements are expressed in U.S. dollars, but, effective January 1, 2021, a portion of our operations is conducted in a currency other than U.S. dollars. The Canadian dollar is the functional currency of the Company’s foreign subsidiary as it is the primary currency within the economic environment in which the subsidiary operates. Changes in the exchange rate can affect our revenues, earnings, and the carrying value of our assets and liabilities in our consolidated balance sheet, either positively or negatively. Adjustments resulting from the translation of the subsidiary’s financial statements are reported in other comprehensive income (loss). During the years ended December 31, 2022 and 2021, the Company recorded foreign currency translation losses to comprehensive income (loss) of $7.1 million and $0.1 million, respectively. 
+Item 8. Financial Statements and Supplementary Data 
+Our financial statements and supplementary data are included in this Annual Report beginning on page F-1 and incorporated by reference herein. 
+Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+None. 
+43 
+Item 9A. Controls and Procedures 
+Evaluation of Disclosure Controls and Procedures’ 
+In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2022 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures. 
+There were no changes to our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+See page F-1 for Management’s Report on Internal Control Over Financial Reporting and page F-4 for Report of Independent Registered Public Accounting Firm on its assessment of our internal control over financial reporting. 
+Item 9B. Other Information 
+None. 
+44 
+PART III 
+Item 10. Directors, Executive Officers and Corporate Governance 
+The information required by this item concerning our executive officers, directors and corporate governance is incorporated herein by reference to our definitive proxy statement for our 2023 annual meeting of stockholders, which will be filed with the SEC no later than 120 days after December 31, 2022, under the captions “Proposal 1 — Election of Directors,” “The Board and its Committees,” “Executive Officers” and “Delinquent Section 16(a) Reports.” 
+Item 11. Executive Compensation 
+The information required by this item concerning executive compensation is incorporated herein by reference to our definitive proxy statement for our 2023 annual meeting of stockholders, which will be filed with the SEC no later than 120 days after December 31, 2022, under the captions “The Board and its Committees,” “Compensation Discussion & Analysis,” “Compensation Committee Report,” “Executive Compensation Tables,” “Director Compensation,” “Pay versus Performance” and “CEO Pay Ratio.” 
+Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+The information required by this item concerning the security ownership of certain beneficial owners and management and related stockholder matters are incorporated herein by reference to our definitive proxy statement for our 2023 annual meeting of stockholders, which will be filed with the SEC no later than 120 days after December 31, 2022, under the captions “Security Ownership of Certain Beneficial Owners and Management” and “Equity Compensation Plan Information.” 
+Item 13. Certain Relationships and Related Transactions, and Director Independence 
+The information required by this item concerning certain relationships and related person transactions and director independence is incorporated herein by reference to our definitive proxy statement for our 2023 annual meeting of stockholders, which will be filed with the SEC no later than 120 days after December 31, 2022, under the captions “Certain Relationships and Related Party Transactions” and “the Board and its Committees.” 
+Item 14. Principal Accountant Fees and Services 
+The information required by this item concerning principal accounting fees and services is incorporated herein by reference to our definitive proxy statement for our 2023 annual meeting of stockholders, which will be filed with the SEC no later than 120 days after December 31, 2022, under the caption “Proposal 3 — Ratification of Appointment of the Company’s Independent Registered Public Accounting Firm.” 
+45 
+PART IV 
+Item 15. Exhibits and Financial Statement Schedules 
+(a) Financial Statements and Financial Statement Schedules 
+Refer to Index to Financial Statements on page 53. 
+All schedules are omitted as information required is inapplicable or the information is presented in the consolidated financial statements and the related notes. 
+(b) Exhibits 
+The documents listed in the Index to Exhibits are filed, furnished or incorporated by reference as part of this Annual Report, and such Index to Exhibits are incorporated herein by reference. 
+46 
+Item 16. Form 10-K Summary 
+None. 
+47 
+INDEX TO EXHIBITS 
+Exhibit 
+Number 
+Description 
+2.1 
+Master Reorganization Agreement, dated as of January 11, 2018, by and among Liberty Oilfield Services Inc., Liberty Oilfield Services Holdings LLC, Liberty Oilfield Services New HoldCo LLC, and the other parties named therein (2) 
+2.2 
+Master Transaction Agreement, dated as of August 31, 2020, by and among Schlumberger Technology Corporation, Schlumberger Canada Limited, Liberty Oilfield Services Holdings LLC, Liberty Canada Operations Inc. and Liberty Oilfield Services Inc. (11) 
+3.1 
+Amended and Restated Certificate of Incorporation of Liberty Oilfield Services Inc. (2) 
+3.2 
+Certificate of Amendment to Amended and Restated Certificate of Incorporation (16) 
+3.3 
+Second Amended and Restated Bylaws of Liberty Energy Inc., as amended effective January 24, 2023 (21) 
+4.1 
+Amended and Restated Stockholders Agreement, dated as of December 31, 2020, by and among Liberty Oilfield Services Inc., Riverstone and the Schlumberger Parties (12) 
+4.2 
+Description of the Registrant’s Securities Registered pursuant to Section 12 of the Securities Exchange Act of 1934. * 
+10.1 
+Second Amended and Restated Limited Liability Company Operating Agreement of Liberty Oilfield Services New HoldCo LLC (2) 
+10.2 
+Form of Joinder Agreement to Second Amended and Restated Limited Liability Company Operating Agreement of Liberty Oilfield Services New HoldCo LLC (15) 
+10.3 
+Registration Rights Agreement, dated October 26, 2021, by and among Liberty Oilfield Services Inc. and the other parties named therein (15) 
+10.4 
+Tax Receivable Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Inc., R/C Energy IV Direct Partnership, L.P., and R/C Energy IV Direct Partnership, L.P., as agent (2) 
+10.5 
+Tax Receivable Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Inc., and the other parties named therein (2) 
+10.6 
+Agent Designation Amendment to the Tax Receivable Agreement, dated as of February 22, 2022, by and among Liberty Oilfield Services Inc. and R/C Energy IV Direct Partnership, L.P. (19) 
+10.7 
+Amended and Restated Registration Rights Agreement, dated as of December 31, 2020, by and among Liberty Oilfield Services Inc., the Schlumberger Parties, and the Holders (12) 
+10.8 
+Liberty Oilfield Services Inc. Long Term Incentive Plan (2)† 
+10.9 
+Credit Agreement, dated September 19, 2017, by and among Wells Fargo Bank, National Association, as Administrative Agent, Wells Fargo Bank, National Association, JPMorgan Chase Bank, N.A. and Citibank, N.A., as Joint Lead Arrangers, Wells Fargo Bank, National Association, as Book Runner, JPMorgan Chase Bank, N.A. and Citibank, N.A., as Syndication Agents, the lender parties thereto, Liberty Oilfield Services Holdings LLC, as Parent and Liberty Oilfield Services LLC and LOS Acquisition Co I LLC, each as a Borrower (1) 
+10.10 
+Amendment and Parent Joinder to Credit Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Holdings LLC, Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto (4) 
+10.11 
+Second Amendment and Parent Joinder to Credit Agreement, dated March 21, 2018, by and among Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto (4) 
+10.12 
+Third Amendment to Credit Agreement, dated May 29, 2020, by and among Liberty Oilfield Services LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, and Wells Fargo Bank, National Association as Administrative Agent, and the lenders signatory thereto (9) 
+10.13 
+Fourth Amendment to Credit Agreement, dated August 12, 2020, by and among Liberty Oilfield Services LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto (10) 
+48 
+10.14 
+Consent and Fifth Amendment to Credit Agreement, dated December 29, 2020, by and among Liberty Oilfield Services LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, LOS Cibolo RE Investments, LLC, LOS Odessa RE Investments, LLC, ST9 Gas and Oil LLC, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto (13) 
+10.15 
+Sixth Amendment to Credit Agreement and Second Amendment to Guaranty and Security Agreement, dated October 22, 2021, by and among Liberty Oilfield Services LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New HoldCo LLC, R/C IV Non-U.S. LOS Corp, LOS Solar Acquisition LLC, Freedom Proppant LLC, LOS Kermit LLC, LOS Cibolo RE Investments, LLC, LOS Odessa RE Investments, LLC, ST9 Gas and Oil LLC, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto (15) 
+10.16 
+Increase Joinder and Seventh Amendment to Credit Agreement, dated July 18, 2022, by and among Liberty Oilfield Services LLC, Liberty Energy Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, Freedom Proppant LLC, LOS Kermit LLC, LOS Leasing Company LLC, LOS Cibolo RE Investments, LLC, LOS Odessa RE Investments, LLC, Proppant Express Solutions, LLC, ST9 Gas and Oil LLC, Well Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto. (18) 
+10.17 
+Eighth Amendment to Credit Agreement, dated January 23, 2023, by and among Liberty Oilfield Services LLC, Liberty Energy Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, Freedom Proppant LLC, LOS Kermit LLC, LOS Leasing Company LLC, LOS Cibolo RE Investments, LLC, LOS Odessa RE Investments, LLC, Proppant Express Solutions, LLC, ST9 Gas and Oil LLC, Well Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto. (21) 
+10.18 
+Joinder Agreement, dated December 31, 2021, by and among LOS Leasing Company LLC and Wells Fargo Bank, National Association, as Administrative Agent (20) 
+10.19 
+Credit Agreement, dated September 19, 2017, by and among Liberty Oilfield Services LLC and LOS Acquisition CO I LLC, each as Borrower, Liberty Oilfield Services Holdings LLC, as Parent Guarantor and U.S. Bank National Association as Agent (1) 
+10.20 
+Amendment and Joinder to Credit Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Holdings LLC, Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, U.S. Bank National Association, as Administrative Agent, and the lenders signatory thereto (4) 
+10.21 
+Second Amendment and Joinder to Credit Agreement, dated March 21, 2018, by and among Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, U.S. Bank National Association, as Administrative Agent, and the lenders signatory thereto (4) 
+10.22 
+Third Amendment to Credit Agreement, dated August 12, 2020, by and among Liberty Oilfield Services LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, U.S. Bank National Association, as Administrative Agent, and the lenders signatory thereto (10) 
+10.23 
+Waiver, Consent and Fourth Amendment to Credit Agreement and First Amendment to Guaranty and Security Agreement, dated December 29, 2020, by and among Liberty Oilfield Services LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, LOS Cibolo RE Investments, LLC, LOS Odessa RE Investments, LLC, ST9 Gas and Oil LLC, U.S. Bank National Association, as Administrative Agent, and the lenders signatory thereto (13) 
+10.24 
+Fifth Amendment to Credit Agreement, Second Amendment to Guaranty and Security Agreement and Termination of Right of First Offer Letter, dated October 22, 2021, by and among Liberty Oilfield Services LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New HoldCo LLC, R/C IV Non-U.S. LOS Corp, LOS Cibolo RE Investments, LLC, LOS Odessa RE Investments, LLC, ST9 Gas and Oil LLC, LOS Solar Acquisition LLC, Freedom Proppant LLC, LOS Kermit LLC, U.S. Bank National Association, as Administrative Agent, and the lenders signatory thereto (15) 
+10.25 
+Sixth Amendment to Credit Agreement, dated August 12, 2022, by and among Liberty Oilfield Services LLC, Liberty Energy Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, LOS Cibolo RE Investments, LLC, LOS Odessa RE Investments, LLC, ST9 Gas and Oil LLC, Freedom Proppant LLC, LOS Kermit LLC, LOS Leasing Company LLC, Proppant Express Solutions, LLC, U.S. Bank National Association, as Administrative Agent, and the lenders signatory thereto. (17) 
+10.26 
+Seventh Amendment to Credit Agreement, dated November 4, 2022, by and among Liberty Oilfield Services LLC, Liberty Energy Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, LOS Cibolo RE Investments, LLC, LOS Odessa RE Investments, LLC, ST9 Gas and Oil LLC, Freedom Proppant LLC, LOS Kermit LLC, LOS Leasing Company LLC, Proppant Express Solutions, LLC, U.S. Bank National Association, as Administrative Agent, and the lenders signatory thereto. * 
+49 
+10.27 
+First Amendment to Amended and Restated Registration Rights Agreement, dated as of December 1, 2022, by and between Liberty Energy Inc. and Schlumberger Technology Corporation. * 
+10.28 
+Liberty Oilfield Services 401(k) Savings Plan (13)† 
+10.29 
+Form of Restricted Stock Unit Grant Notice and Restricted Stock Unit Award Agreement under the Long Term Incentive Plan (5)† 
+10.30 
+Form of Restricted Stock Unit Grant Notice under the Long Term Incentive Plan (13)† 
+10.31 
+Form of Performance Restricted Stock Unit Grant Notice and Performance Restricted Stock Unit Agreement under the Liberty Oilfield Services Inc. Long Term Incentive Plan (6)† 
+10.32 
+Form of Change in Control Agreement (7)† 
+10.33 
+Form of Indemnification Agreement between the Company and each of its Directors and Executive Officers (8) 
+21.1 
+List of subsidiaries of Liberty Energy Inc. * 
+23.1 
+Consent of Deloitte & Touche LLP * 
+31.1 
+Certification of Chief Executive Officer pursuant to Rule 13a-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 * 
+31.2 
+Certification of Chief Financial Officer pursuant to 13a-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 * 
+32.1 
+Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 ** 
+32.2 
+Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 ** 
+95 
+Mine Safety Disclosure * 
+101.INS XBRL Instance Document * 
+101.SCH XBRL Taxonomy Extension Schema Document * 
+101.CAL XBRL Taxonomy Extension Calculation Linkbase Document * 
+101.DEF XBRL Taxonomy Extension Definition Linkbase Document * 
+101.LAB XBRL Taxonomy Extension Label Linkbase Document * 
+101.PRE XBRL Taxonomy Extension Presentation Linkbase Document * 
+104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)* 
+(1) Incorporated by reference to the exhibits to the registrant’s Registration Statement on Form S-1, as amended (SEC File 333-216050). 
+(2) Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on January 18, 2018. 
+(3) Incorporated by reference to the exhibits to the registrant’s Amendment No. 1 to the Current Report on Form 8-K/A, filed on January 22, 2018. 
+(4) Incorporated by reference to the exhibits to the registrant’s Annual Report on Form 10-K, filed on March 23, 2018. 
+(5) Incorporated by reference to the exhibits to the registrant’s Quarterly Report on Form 10-Q, filed on May 10, 2018. 
+(6) Incorporated by reference to the exhibits to the registrant’s Quarterly Report on Form 10-Q, filed on May 3, 2019. 
+(7) Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on August 30, 2019. 
+(8) Incorporated by reference to the exhibits to the registrant’s Annual Report on Form 10-K, filed on February 27, 2020. 
+(9) Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on June 3, 2020. 
+50 
+(10) Incorporated by reference to the exhibits to the registrant’s Quarterly Report on Form 10-Q, filed on October 30, 2020. 
+(11) Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on September 1, 2020. 
+(12) Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on January 4, 2021. 
+(13) Incorporated by reference to the exhibits to the registrant’s Annual Report on Form 10-K, filed on February 24, 2021. 
+(14) Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on June 10, 2021. 
+Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on January 4, 2021. 
+(15) Incorporated by reference to the exhibits to the registrant’s Quarterly Report on Form 10-Q, filed on October 28, 2021. 
+(16) Incorporated by reference to the registrant’s Current Report on Form 8-K, filed on April 21, 2022. 
+(17) Incorporated by reference to the registrant’s Current Report on Form 8-K, filed on August 17, 2022. 
+(18) Incorporated by reference to the registrant’s Current Report on Form 8-K, filed on July 22, 2022. 
+(19) Incorporated by reference to the exhibits to the registrant’s Quarterly Report on Form 10-Q, filed on April 25, 2022. 
+(20) Incorporated by reference to the exhibits to the registrant’s Annual Report on Form 10-K, filed on February 22, 2022. 
+(21) Incorporated by reference to the registrant’s Current Report on Form 8-K, filed on January 26, 2023. 
+* Filed herewith. 
+** Furnished herewith. 
+† Denotes a management contract or compensatory plan or arrangement. 
+51 
+SIGNATURES 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+LIBERTY ENERGY INC. 
+/s/ Christopher A. Wright 
+Date: February 10, 2023 By: 
+Christopher A. Wright 
+Chief Executive Officer 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+Signature Title Date 
+/s/ Christopher A. Wright 
+Chief Executive Officer and Director 
+(Principal Executive Officer) 
+February 10, 2023 
+Christopher A. Wright 
+/s/ Michael Stock 
+Chief Financial Officer 
+(Principal Financial Officer) 
+February 10, 2023 
+Michael Stock 
+/s/ Ryan T. Gosney Chief Accounting Officer February 10, 2023 
+Ryan T. Gosney (Principal Accounting Officer) 
+/s/ Simon Ayat Director February 10, 2023 
+Simon Ayat 
+/s/ Ken Babcock Director February 10, 2023 
+Ken Babcock 
+/s/ Peter A. Dea Director February 10, 2023 
+Peter A. Dea 
+/s/ William F. Kimble Director February 10, 2023 
+William F. Kimble 
+/s/ James R. McDonald Director February 10, 2023 
+James R. McDonald 
+/s/ Gale A. Norton Director February 10, 2023 
+Gale A. Norton 
+/s/ Audrey Robertson Director February 10, 2023 
+Audrey Robertson 
+/s/ Cary D. Steinbeck Director February 10, 2023 
+Cary D. Steinbeck 
+52 
+Index to Financial Statements 
+Liberty Energy Inc. 
+Management’s Report on Internal Control Over Financial Reporting 
+F-1 
+Reports of Independent Registered Public Accounting Firm (PCAOB ID No. 34 ) 
+F- 2 
+Consolidated Balance Sheets as of December 31, 202 2 and 20 21 
+F- 5 
+Consolidated Statements of Operations for the Years Ended December 31, 202 2 , 202 1 , and 2 020 
+F- 6 
+Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2022, 2021, and 2020 
+F-7 
+Consolidated Statements of Changes in Equity for the Years Ended December 31, 202 2 and 202 1 
+F- 8 
+Consolidated Statements of Cash Flows for the Years Ended December 31, 202 2 , 202 1 , and 20 20 
+F- 9 
+Notes to Consolidated Financial Statements 
+F- 11 
+53 
+MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING 
+The management of Liberty Energy Inc. is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act. 
+Internal control over financial reporting, no matter how well designed, has inherent limitations. Therefore, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements. Further, because of changes in conditions, effectiveness of internal controls over financial reporting may vary over time. 
+Under the supervision of, and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2022 based on the framework and criteria established in Internal Control-Integrated Framework (2013) , issued by the Committee of Sponsoring Organizations of the Treadway Commission. 
+Based on this evaluation, management concluded that, as of December 31, 2022, our internal control over financial reporting was effective. 
+The effectiveness of Liberty Energy Inc. ’ s internal control over financial reporting as of December 31, 2022 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report that is included herein. 
+F-1 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the stockholders and the Board of Directors of Liberty Energy Inc. 
+Opinion on the Financial Statements 
+We have audited the accompanying consolidated balance sheets of Liberty Energy Inc. and subsidiaries (the “Company”) as of December 31, 2022 and 2021, the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows, for each of the three years in the period ended December 31, 2022, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, in conformity with accounting principles generally accepted in the United States of America. 
+We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 10, 2023 expressed an unqualified opinion on the Company’s internal control over financial reporting. 
+Basis for Opinion 
+These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. 
+Critical Audit Matter 
+The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. 
+Income Taxes — Tax Receivable Agreements — Refer to Note 12 to the financial statements 
+Critical Audit Matter Description 
+The amounts payable, as well as the timing of such payments, under the tax receivable agreements (“TRAs”) are dependent upon significant future events and assumptions, including among others: (i) the amount of the redeeming unit holder’s tax basis in its Liberty Oilfield Services New HoldCo LLC class B units at the time of the relevant redemption, (ii) the characterization of the tax basis step-up, (iii) the depreciation and amortization periods that apply to the increase in tax basis (iv), the amount and timing of taxable income the Company generates in the future (v) the U.S. federal income tax rate then applicable, and (vi) the portion of the Company’s payments under the TRAs that constitute imputed interest or give rise to depreciable or amortizable tax basis. 
+During the year ended December 31, 2022, exchanges of Liberty Oilfield Services New HoldCo LLC class B units and shares of Class B Common Stock resulted in an increase of $5.1 million in amounts payable pursuant to tax receivable agreements (“TRA payable”), and a net increase of $6.0 million in deferred tax assets, all of which were recorded as equity 
+F-2 
+transactions, with no impact to the statement of operations. Upon the release of the valuation allowance, the Company recorded a loss on remeasurement of the TRA payable of $76.2 million recorded as part of continuing operations in the current year. At December 31, 2022, the Company’s TRA payable was $118.9 million, all of which is presented as a component of long-term liabilities. 
+We identified the computation of adjustments to the TRA payable as a critical audit matter because of the multiple owners and complex calculations required to arrive at the correct tax basis upon which to calculate the corresponding TRA payable adjustment. This involved complexity in applying relevant tax law and an increased extent of effort, including the need to involve income tax specialists, when performing audit procedures to evaluate the reasonableness of management’s calculation of tax basis, iterative impact of the computation of adjustments to the TRA payable, and TRA payable as of year-end. 
+How the Critical Audit Matter Was Addressed in the Audit: 
+Our audit procedures related to the computation of adjustments to the TRA payable included the following, among others: 
+• We tested the effectiveness of controls over the computation of adjustments to the TRA payable, including management’s calculation of the step-up in tax basis that serves as the basis for the computation of adjustments to the TRA payable. 
+• With the assistance of our income tax specialists, we read the individual TRAs and compared the terms in the agreements for consistency with the mathematical model used by management to calculate the adjustments to the TRA payable. 
+• With the assistance of our income tax specialists, we evaluated management’s computation of adjustments to the TRA payable, and the TRA payable as of year-end that is payable over the contractual period by comparing to our independently recalculated value, taking into account the various class B unit exchanges for Class B Common Stock occurring during the year as well as the adjustments in the TRA payable for each exchange. 
+/s/ DELOITTE & TOUCHE LLP 
+Denver, Colorado 
+February 10, 2023 
+We have served as the Company ’ s auditor since 2016. 
+F-3 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the stockholders and the Board of Directors of Liberty Energy Inc. 
+Opinion on Internal Control over Financial Reporting 
+We have audited the internal control over financial reporting of Liberty Energy Inc. and subsidiaries (the “Company”) as of December 31, 2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO. 
+We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2022, of the Company and our report dated February 10, 2023, expressed an unqualified opinion on those financial statements. 
+Basis for Opinion 
+The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+Definition and Limitations of Internal Control over Financial Reporting 
+A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+/s/ DELOITTE & TOUCHE LLP 
+Denver, Colorado 
+February 10, 2023 
+F-4 
+LIBERTY ENERGY INC. 
+Consolidated Balance Sheets 
+As of December 31, 2022 and 2021 
+(Dollars in thousands, except share data) 
+2022 2021 
+Assets 
+Current assets: 
+Cash and cash equivalents $ 43,676 $ 19,998 
+Accounts receivable—trade, net of allowances for credit losses of $ 884 and $ 884 , respectively 
+410,308 298,531 
+Unbilled revenue (including amounts from related parties of $ 13,854 and $ 0 , respectively) 
+175,704 108,923 
+Inventories 214,454 134,593 
+Prepaid and other current assets 112,531 68,332 
+Total current assets 956,673 630,377 
+Property and equipment, net 1,362,364 1,199,287 
+Finance lease right-of-use assets 41,771 18,201 
+Operating lease right-of-use assets 97,232 109,899 
+Other assets (including amounts from related parties of $ 11,799 and $ 0 , respectively) 
+105,300 82,289 
+Deferred tax asset 12,592 607 
+Total assets $ 2,575,932 $ 2,040,660 
+Liabilities and Equity 
+Current liabilities: 
+Accounts payable (including payables to related parties of $ 2,629 and $ 2,732 , respectively) 
+$ 326,818 $ 288,801 
+Accrued liabilities (including amounts due to related parties of $ 730 and $ 1,142 , respectively) 
+279,113 235,115 
+Deferred revenue 3,859 4,552 
+Current portion of long-term debt, net of discount of $ 730 and $ 743 , respectively 
+1,020 1,007 
+Current portion of finance lease liabilities 11,393 8,743 
+Current portion of operating lease liabilities 27,294 31,029 
+Total current liabilities 649,497 569,247 
+Long-term debt, net of discount of $ 540 and $ 1,270 , respectively, less current portion 
+217,426 121,445 
+Deferred tax liability 1,044 563 
+Payable pursuant to tax receivable agreements 118,874 37,555 
+Noncurrent portion of finance lease liabilities 22,490 4,445 
+Noncurrent portion of operating lease liabilities 69,295 76,966 
+Total liabilities 1,078,626 810,221 
+Commitments & contingencies (Note 15) 
+Stockholders’ equity: 
+Preferred Stock, $ 0.01 par value, 10,000 shares authorized and none issued and outstanding 
+— — 
+Common Stock: 
+Class A, $ 0.01 par value, 400,000,000 shares authorized and 178,753,125 issued and outstanding as of December 31, 2022 and 183,385,111 issued and outstanding as of December 31, 2021 
+1,788 1,834 
+Class B, $ 0.01 par value, 400,000,000 shares authorized and 250,222 issued and outstanding as of December 31, 2022 and 2,632,347 issued and outstanding as of December 31, 2021 
+3 26 
+Additional paid in capital 1,266,097 1,367,642 
+Retained earnings (accumulated deficit) 234,525 ( 155,954 ) 
+Accumulated other comprehensive loss ( 7,396 ) ( 306 ) 
+Total stockholders’ equity 1,495,017 1,213,242 
+Non-controlling interest 2,289 17,197 
+Total equity 1,497,306 1,230,439 
+Total liabilities and equity $ 2,575,932 $ 2,040,660 
+See Notes to Consolidated Financial Statements. 
+F-5 
+LIBERTY ENERGY INC. 
+Consolidated Statements of Operations 
+For the Years Ended December 31, 2022, 2021, and 2020 
+(In thousands, except per share data) 
+2022 2021 2020 
+Revenue: 
+Revenue $ 4,000,780 $ 2,447,140 $ 965,787 
+Revenue—related parties 148,448 23,642 — 
+Total revenue 4,149,228 2,470,782 965,787 
+Operating costs and expenses: 
+Cost of services (exclusive of depreciation, depletion, and amortization shown separately below) 3,149,036 2,249,926 857,981 
+General and administrative 180,040 123,406 84,098 
+Transaction, severance, and other costs 5,837 15,138 21,061 
+Depreciation, depletion, and amortization 323,028 262,757 180,084 
+(Gain) loss on disposal of assets ( 4,603 ) 779 ( 411 ) 
+Total operating costs and expenses 3,653,338 2,652,006 1,142,813 
+Operating income (loss) 495,890 ( 181,224 ) ( 177,026 ) 
+Other expense (income): 
+Loss (gain) on remeasurement of liability under tax receivable agreements 76,191 ( 19,039 ) — 
+Gain on investments ( 2,525 ) — — 
+Interest income—related party — — ( 263 ) 
+Interest expense, net 22,715 15,603 14,768 
+Total other expense (income), net 96,381 ( 3,436 ) 14,505 
+Net income (loss) before income taxes 399,509 ( 177,788 ) ( 191,531 ) 
+Income tax (benefit) expense ( 793 ) 9,216 ( 30,857 ) 
+Net income (loss) 400,302 ( 187,004 ) ( 160,674 ) 
+Less: Net income (loss) attributable to non-controlling interests 700 ( 7,760 ) ( 45,091 ) 
+Net income (loss) attributable to Liberty Energy Inc. stockholders $ 399,602 $ ( 179,244 ) $ ( 115,583 ) 
+Net income (loss) attributable to Liberty Energy Inc. stockholders per common share: 
+Basic $ 2.17 $ ( 1.03 ) $ ( 1.36 ) 
+Diluted $ 2.11 $ ( 1.03 ) $ ( 1.36 ) 
+Weighted average common shares outstanding: 
+Basic 184,334 174,019 85,242 
+Diluted 189,349 174,019 85,242 
+See Notes to Consolidated Financial Statements. 
+F-6 
+LIBERTY ENERGY INC. 
+Consolidated Statements of Comprehensive Income (Loss) 
+For the Years Ended December 31, 2022, 2021, and 2020 
+(In thousands) 
+2022 2021 2020 
+Net income (loss) $ 400,302 $ ( 187,004 ) $ ( 160,674 ) 
+Other comprehensive loss 
+Foreign currency translation ( 7,097 ) ( 102 ) — 
+Comprehensive income (loss) $ 393,205 $ ( 187,106 ) $ ( 160,674 ) 
+Comprehensive income (loss) attributable to non-controlling interest 693 ( 7,556 ) ( 45,091 ) 
+Comprehensive income (loss) attributable to Liberty Energy Inc. $ 392,512 $ ( 179,550 ) $ ( 115,583 ) 
+See Notes to Consolidated Financial Statements. 
+F-7 
+LIBERTY ENERGY INC. 
+Consolidated Statements of Changes in Equity 
+For the Years Ended December 31, 2022 and 2021 
+(In thousands, except per share and per unit data) 
+Shares of Class A Common Stock Shares of Class B Common Stock Class A Common Stock, Par Value Class B Common Stock, Par Value Additional Paid in Capital (Accumulated Deficit) Retained Earnings Accumulated Other Comprehensive Loss Total Stockholders’ equity Non-controlling Interest Total Equity 
+Balance—December 31, 2021 183,385 2,632 $ 1,834 $ 26 $ 1,367,642 $ ( 155,954 ) $ ( 306 ) $ 1,213,242 $ 17,197 $ 1,230,439 
+Exchange of Class B Common Stock for Class A Common Stock 2,382 ( 2,382 ) 23 ( 23 ) 16,495 — — 16,495 ( 16,495 ) — 
+Offering Costs — — — — ( 79 ) — — ( 79 ) — ( 79 ) 
+Effect of exchange on deferred tax asset, net of liability under tax receivable agreements — — — — 3,757 — — 3,757 — 3,757 
+Deferred tax impact of ownership changes from issuance of Class A Common Stock — — — — ( 9,879 ) — — ( 9,879 ) — ( 9,879 ) 
+$ 0.05 /share of Class A Common Stock dividend 
+— — — — — ( 9,123 ) — ( 9,123 ) — ( 9,123 ) 
+$ 0.05 /unit distribution to non-controlling unitholders 
+— — — — — — — — ( 13 ) ( 13 ) 
+Other distributions and advance payments to non-controlling interest unitholders — — — — — — — — 920 920 
+Share repurchases ( 8,186 ) — ( 81 ) — ( 125,134 ) — — ( 125,215 ) ( 98 ) ( 125,313 ) 
+Stock-based compensation expense — — — — 23,003 — — 23,003 105 23,108 
+Vesting of restricted stock units 1,172 — 12 — 8 — — 20 ( 20 ) — 
+Tax withheld on vesting of restricted stock units — — — — ( 9,716 ) — — ( 9,716 ) — ( 9,716 ) 
+Currency translation adjustment — — — — — — ( 7,090 ) ( 7,090 ) ( 7 ) ( 7,097 ) 
+Net income — — — — — 399,602 — 399,602 700 400,302 
+Balance—December 31, 2022 178,753 250 $ 1,788 $ 3 $ 1,266,097 $ 234,525 $ ( 7,396 ) $ 1,495,017 $ 2,289 $ 1,497,306 
+Shares of Class A Common Stock Shares of Class B Common Stock Class A Common Stock, Par Value Class B Common Stock, Par Value Additional Paid in Capital Retained Earnings (Accumulated Deficit) Accumulated Other Comprehensive Loss Total Stockholders’ equity Non-controlling Interest Total Equity 
+Balance - December 31, 2020 157,952 21,550 $ 1,579 $ 216 $ 1,125,554 $ 23,288 $ — $ 1,150,637 $ 159,406 $ 1,310,043 
+Exchange of Class B Common Stock for Class A Common Stock 21,359 ( 21,359 ) 214 ( 214 ) 153,641 — — 153,641 ( 153,641 ) — 
+Offering Costs — — — — ( 1,247 ) — — ( 1,247 ) ( 75 ) ( 1,322 ) 
+Issuance of Class A and Class B Common Stock for the PropX Acquisition 3,406 2,441 34 24 88,979 — — 89,037 2,052 91,089 
+Impact of ownership changes from issuance of Class A and Class B Common Stock — — — — ( 15,325 ) — — ( 15,325 ) 15,325 — 
+Other distributions and advance payments to non-controlling interest unitholders — — — — — — — — 1,372 1,372 
+Stock-based compensation expense — — — — 19,122 — — 19,122 824 19,946 
+Vesting of restricted stock units 668 — 7 — ( 3,082 ) — — ( 3,075 ) ( 510 ) ( 3,585 ) 
+Restricted stock and RSU Forfeitures — — — — — 2 — 2 — 2 
+Currency translation adjustment — — — — — — ( 306 ) ( 306 ) 204 ( 102 ) 
+Net loss — — — — — ( 179,244 ) — ( 179,244 ) ( 7,760 ) ( 187,004 ) 
+Balance - December 31, 2021 183,385 2,632 $ 1,834 $ 26 $ 1,367,642 $ ( 155,954 ) $ ( 306 ) $ 1,213,242 $ 17,197 $ 1,230,439 
+See Notes to Consolidated Financial Statements. 
+F-8 
+LIBERTY ENERGY INC. 
+Consolidated Statements of Cash Flows 
+For the Years Ended December 31, 2022, 2021, and 2020 
+(Dollars in thousands) 
+2022 2021 2020 
+Cash flows from operating activities: 
+Net income (loss) $ 400,302 $ ( 187,004 ) $ ( 160,674 ) 
+Adjustments to reconcile net income (loss) to net cash provided by operating activities: 
+Depreciation, depletion, and amortization 323,028 262,757 180,084 
+(Gain) loss on disposal of assets ( 4,603 ) 779 ( 411 ) 
+Inventory write-down 1,724 — 1,087 
+Non-cash lease expense 3,733 3,823 3,668 
+Stock-based compensation expense 23,108 19,946 17,139 
+Deferred income tax (benefit) expense ( 12,472 ) 5,079 ( 25,546 ) 
+Loss (gain) on remeasurement of liability under tax receivable agreements 76,191 ( 19,039 ) 543 
+Other non-cash expense, net 4 2,037 2,232 
+Provision for credit losses — 745 4,877 
+Changes in operating assets and liabilities: 
+Accounts receivable and unbilled revenue ( 166,605 ) ( 90,142 ) 53,057 
+Accounts receivable and unbilled revenue—related party ( 25,522 ) — 9,629 
+Inventories ( 84,989 ) ( 24,612 ) 2,137 
+Other assets ( 56,161 ) ( 30,955 ) 13,780 
+Prepaid and other current assets—related party — 24,708 — 
+Deferred revenue ( 593 ) 3,452 — 
+Accounts payable and accrued liabilities 57,796 160,584 ( 15,282 ) 
+Accounts payable and accrued liabilities—related party ( 1,864 ) 3,874 — 
+Initial payment of operating lease liability ( 2,713 ) ( 565 ) ( 895 ) 
+Net cash provided by operating activities 
+530,364 135,467 85,425 
+Cash flows from investing activities: 
+Purchases of property and equipment and construction in-progress ( 451,905 ) ( 198,794 ) ( 103,637 ) 
+Investment in sand logistics ( 7,415 ) ( 13,106 ) — 
+Investment in Fervo Energy Company and Natron Energy, Inc. ( 15,000 ) — — 
+Proceeds from sales of assets 23,664 25,406 3,368 
+Net cash used in investing activities 
+( 450,656 ) ( 186,494 ) ( 100,269 ) 
+Cash flows from financing activities: 
+Proceeds from borrowings on line-of-credit 713,000 274,000 — 
+Repayments of borrowings on line-of-credit ( 616,000 ) ( 256,000 ) — 
+Repayments of borrowings on term loan ( 1,750 ) ( 1,750 ) ( 1,750 ) 
+Payments on finance lease obligations ( 6,947 ) ( 7,363 ) ( 11,663 ) 
+Class A Common Stock dividends and dividend equivalents upon restricted stock vesting ( 9,164 ) ( 168 ) ( 4,431 ) 
+Per unit distributions to non-controlling interest unitholders ( 13 ) — ( 1,532 ) 
+Other distributions and advance payments to non-controlling interest unitholders 920 1,372 ( 6,800 ) 
+Share repurchases ( 125,313 ) — — 
+Tax withholding on restricted stock units ( 9,716 ) ( 3,585 ) ( 988 ) 
+Payment of equity issuance costs ( 79 ) ( 1,330 ) ( 1,641 ) 
+Payments of debt issuance costs ( 708 ) ( 3,120 ) ( 63 ) 
+Net cash (used in) provided by financing activities 
+( 55,770 ) 2,056 ( 28,868 ) 
+Net increase (decrease) in cash and cash equivalents 23,938 ( 48,971 ) ( 43,712 ) 
+Translation effect on cash ( 260 ) ( 9 ) — 
+Cash and cash equivalents—beginning of period 19,998 68,978 112,690 
+Cash and cash equivalents—end of period $ 43,676 $ 19,998 $ 68,978 
+F-9 
+LIBERTY ENERGY INC. 
+Consolidated Statements of Cash Flows (cont.) 
+For the Years Ended December 31, 2022, 2021, and 2020 
+(Dollars in thousands) 
+2022 2021 2020 
+Supplemental disclosure of cash flow information: 
+Net cash paid (received) for income taxes $ 10,744 $ ( 9,481 ) $ ( 9,653 ) 
+Cash paid for interest $ 20,310 $ 13,268 $ 11,218 
+Non-cash investing and financing activities: 
+Capital expenditures included in accounts payable and accrued liabilities $ 107,514 $ 57,475 $ 10,920 
+Capital expenditures reclassified from prepaid and other current assets $ 14,922 $ — $ — 
+Equity issued in exchange for assets and liabilities $ — $ 91,089 $ 683,822 
+See Notes to Consolidated Financial Statements. 
+F-10 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Note 1— Organization and Basis of Presentation 
+Organization 
+Liberty Energy Inc., formerly known as Liberty Oilfield Services Inc. (the “Company”) was incorporated as a Delaware corporation on December 21, 2016, to become a holding corporation for Liberty Oilfield Services New HoldCo LLC (“Liberty LLC”) and its subsidiaries upon completion of a corporate reorganization (the “Corporate Reorganization”) and planned initial public offering of the Company (“IPO”). On April 19, 2022, the stockholders of the Company approved an amendment to the Company’s Amended and Restated Certificate of Incorporation for the purpose of changing the Company’s name from “Liberty Oilfield Services Inc.” to “Liberty Energy Inc.” and thereafter, the Company filed with the Secretary of State of the State of Delaware a Certificate of Amendment to the Company’s Amended and Restated Certificate of Incorporation to reflect the new name, effective April 25, 2022. The Company has no material assets other than its ownership of units in Liberty LLC (“Liberty LLC Units”). 
+Effective January 31, 2023, Liberty LLC was merged into the Company, with the Company surviving the merger. In connection with the merger all outstanding shares of the Company’s Class B Common Stock, par value $ 0.01 per share (the “Class B Common Stock”) were redeemed and exchanged for an equal number of shares of the Company’s Class A Common Stock, par value $ 0.01 per share (the “Class A Common Stock”, and together with the Class A Common Stock, the “Common Stock”). The Company did not make any distributions or receive any proceeds in connection with this exchange. Refer to Note 16 — Subsequent Events for more information. 
+The Company, together with its subsidiaries, is a leading integrated energy services and technology company focused on providing innovative hydraulic fracturing services and related technologies to onshore oil and natural gas exploration and production (“E&P”) companies in North America. We offer customers hydraulic fracturing services, together with complementary services including wireline services, proppant delivery solutions, data analytics, related goods (including our sand mine operations), and technologies that will facilitate lower emission completions, thereby helping our customers reduce their emissions profile. 
+Basis of Presentation 
+The accompanying consolidated financial statements were prepared using generally accepted accounting principles in the United States of America (“GAAP”) and the instructions to Form 10-K, Regulation S-X and the rules and regulations of the Securities and Exchange Commission. 
+The accompanying consolidated financial statements and related notes present the consolidated financial position of the Company and equity of the Company as of and for the years ended December 31, 2022 and 2021, and the results of operations and cash flows of the Company for the years ended December 31, 2022, 2021, and 2020. 
+The consolidated financial statements include the amounts of the Company and all majority owned subsidiaries where the Company has the ability to exercise control. All intercompany amounts have been eliminated in the presentation of the consolidated financial statements of the Company. 
+The Company’s operations are organized into a single reportable segment, which consists of hydraulic fracturing and related goods and services. 
+Note 2— Significant Accounting Policies 
+Business Combinations 
+Business combinations are accounted for using the acquisition method of accounting in accordance with the Accounting Standard Codification (“ASC”) Topic 805 - Business Combinations, as amended by Accounting Standards Update (“ASU”) 2017-01, Business Combinations (Topic 805), Clarifying the Definition of a Business. The purchase price is allocated to the assets acquired and liabilities assumed based on their estimated fair values. Fair value of the acquired assets and liabilities is measured in accordance with the guidance of ASC 850, Fair Value Measurements, using discounted cash flows and other applicable valuation techniques. Any acquisition related costs incurred by the Company are expensed as incurred. Any excess purchase price over the fair value of the net identifiable assets acquired is recorded as goodwill if the definition of a business is 
+F-11 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+met. Operating results of an acquired business are included in our results of operations from the date of acquisition. Refer to Note 3—Acquisitions. 
+Use of Estimates 
+The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 
+The consolidated financial statements include certain amounts that are based on management’s best estimates and judgments. The most significant estimates relate to the fair value of assets acquired and liabilities assumed, collectability of accounts receivable and estimates of allowance for doubtful accounts, the useful lives and salvage values of long-lived assets, future cash flows associated with long-lived assets, net realizable value of inventory, equity unit valuation, deferred taxes, and the tax receivable agreements value. These estimates may be adjusted as more current information becomes available. 
+Cash and Cash Equivalents 
+The Company considers all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. The Company continually monitors its positions with, and the credit quality of, the financial institutions with which it has banking relationships. As of the balance sheet date, and periodically throughout the year, the Company has maintained balances in various operating accounts in excess of federally insured limits. 
+Accounts Receivable 
+In accordance with Accounting Standards Updates ASU 2016-13, Financial Instruments-Credit Losses (Topic 326) : Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”), the Company applies historic loss factors to its receivable portfolio segments that were not expected to be further impacted by current economic developments, and additional economic conditions factor to portfolio segments anticipated to experience greater losses in the current economic environment. Additionally, the Company continuously evaluates customers based on risk characteristics, such as historical losses and current economic conditions. Due to the cyclical nature of the oil and gas industry, the Company often evaluates its customers’ estimated losses on a case-by-case basis. The Company did not record an additional provision for credit losses during the year ended December 31, 2022. During the years ended December 31, 2021 and 2020, the Company recorded a provision for credit losses of $ 0.7 million and $ 4.9 million, respectively, related to two customers inability to pay and the deteriorating economic conditions for the oil and gas industry brought on by the COVID-19 pandemic. Provisions for credit losses are included in general and administrative expenses in the accompanying consolidated statement of operations, in accordance with the new standard. Refer to “Credit Risk” within Note 9—Fair Value Measurements and Financial Instruments for additional disclosures required under ASU 2016-13. 
+Inventories 
+Inventories consist of raw materials used in the hydraulic fracturing process, such as proppants, chemicals, and field service equipment maintenance parts and other and are stated at the lower of cost, determined using the weighted average cost method, or net realizable value. Inventories are charged to cost of services as used when providing hydraulic fracturing services. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable cost of completion, disposal, and transportation. 
+Property and Equipment 
+Property and equipment are stated at cost. Depreciation and amortization expense is recognized on property and equipment, excluding land, utilizing the straight-line method over the estimated useful lives, ranging from two to 30 years. The Company estimates salvage values that it does not depreciate. 
+Construction in-progress, a component of property and equipment, represents long-lived assets not yet in service or being developed by the Company. These assets are not subject to depreciation until they are completed and ready for their intended use, at which point the Company reclassifies them to field services equipment or vehicles, as appropriate. 
+The Company assesses its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is assessed using undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets. The Company determined the lowest level of identifiable cash flows to be at the asset group, which is the aggregate of the Company’s hydraulic fracturing fleets that are in service. A long-lived asset is not recoverable if its carrying amount exceeds the sum of estimated undiscounted cash flows expected to result from the use and eventual disposition. When 
+F-12 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+alternative courses of action to recover the carrying amount of the asset group are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the asset is not recoverable, an impairment loss is recognized in an amount by which its carrying amount exceeds its estimated fair value, such that its carrying amount is adjusted to its estimated fair value, with an offsetting charge to impairment expense. 
+The Company measures the fair value of its property and equipment using the discounted cash flow method. The expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments of projected revenue growth, fleet count, utilization, gross margin rates, selling, general and administrative rates, working capital fluctuations, capital expenditures, discount rates and terminal growth rates. 
+As of December 31, 2022 and 2021, the Company concluded that no triggering events had occurred, and no impairment was recognized during the years ended December 31, 2022 and 2021. 
+During the year ended December 31, 2020, as a result of negative market indicators including the COVID-19 pandemic, the increased supply of low-priced oil, and customer cancellations, the Company concluded these triggering events could indicate possible impairment of property and equipment. The Company performed a quantitative and qualitative impairment analysis and determined that no impairment had occurred as of June 30, 2020. As of December 31, 2020, the Company concluded that no additional triggering events had occurred, and no impairment was recognized during the year ended December 31, 2020. 
+Major Maintenance Activities 
+The Company incurs maintenance costs on its major equipment. The determination of whether an expenditure should be capitalized or expensed requires management judgment in the application of how the costs incurred benefit future periods, relative to the Company’s capitalization policy. Costs that either establish or increase the efficiency, productivity, functionality or life of a fixed asset are capitalized and depreciated over the remaining useful life of the asset. 
+Leases 
+In accordance with Accounting Standard Codification (“ASC”) Topic 842, the Company determines if an arrangement is a lease at inception and evaluates identified leases for operating or finance lease treatment. Operating or finance lease right-of-use assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. The Company uses the rate implicit in the lease, when available, or an estimated fully collateralized incremental borrowing rate corresponding with the lease term and the information available at the commencement date in determining the present value of lease payments. Lease terms may include options to renew, however, the Company typically cannot determine its intent to renew a lease with reasonable certainty at inception. 
+Additionally, the Company is a lessor in several operating leases in which the lease equipment is carried at amortized cost. Depreciation expense is recorded on a straight-line basis over its useful life to the estimated residual value. The lessee may not purchase the leased equipment and must return such equipment by the lease's scheduled maturity date. 
+Deferred Financing Costs 
+Costs associated with obtaining debt financing are deferred and amortized to interest expense using the effective interest method. In accordance with ASU No. 2015-03 and 2015-15, for all periods the Company has reflected deferred financing costs related to term loan debt as a direct deduction from the carrying amount, and costs associated with line-of-credit arrangements as other assets. 
+Income Taxes 
+Deferred income taxes are computed using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Deferred tax assets and liabilities are calculated using the enacted tax rates in effect for the year in which the deferred tax asset or liability is expected to reverse. The Company classifies all deferred tax assets and liabilities as non-current. The Company records Global Intangible Low Tax Income as a current period expense. 
+The Company evaluates its deferred tax assets quarterly and considers both positive and negative evidence in applying the guidance of ASC 740 Income Taxes (“ASC 740”) related to the realizability of its deferred tax assets. On December 31, 2022, in accordance with ASC 740, the objective positive evidence of entering into a three-year cumulative pre-tax book income position, along with considering all available positive and negative evidence resulted in the release of the previously recorded valuation allowance against the Company’s U.S. net deferred tax assets. 
+The Company recognizes the financial statement effects of a tax position when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not 
+F-13 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. Previously recognized tax positions are reversed in the first period in which it is no longer more-likely-than-not that the tax position would be sustained upon examination. Income tax related interest and penalties, if applicable, are recorded as a component of the provision for income tax expense. 
+Tax Receivable Agreements 
+In connection with the IPO, on January 17, 2018, the Company entered into two Tax Receivable Agreements (the “TRAs”) with the R/C Energy IV Direct Partnership, L.P. and certain legacy owners that continued to own Liberty LLC Units (each such person and any permitted transferee, a “Tax Receivable Agreement Holder” and together, the “Tax Receivable Agreement Holders”). The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that the Company actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result, as applicable to each Tax Receivable Agreement Holder, of (i) certain increases in tax basis that occur as a result of the Company’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such Tax Receivable Agreement Holder’s Liberty LLC Units in connection with the IPO or pursuant to the exercise of the right (the “Redemption Right”) or the Company’s right (the “Call Right”), (ii) any net operating losses available to the Company as a result of the Corporate Reorganization, and (iii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRAs. 
+With respect to obligations the Company expects to incur under the TRAs (except in cases where the Company elects to terminate the TRAs early, the TRAs are terminated early due to certain mergers, asset sales, or other changes of control or the Company has available cash but fails to make payments when due), generally the Company may elect to defer payments due under the TRAs if the Company does not have available cash to satisfy its payment obligations under the TRAs or if its contractual obligations limit its ability to make such payments. Any such deferred payments under the TRAs generally will accrue interest. In certain cases, payments under the TRAs may be accelerated and/or significantly exceed the actual benefits, if any, the Company realizes in respect of the tax attributes subject to the TRAs. The Company accounts for amounts payable under the TRAs in accordance with ASC Topic 450, Contingencies . 
+If the Company experiences a change of control (as defined under the TRAs) or the TRAs otherwise terminate early, the Company’s obligations under the TRAs could have a substantial negative impact on its liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. 
+Share Repurchases 
+The Company accounts for the purchase price of repurchased Class A Common Stock in excess of par value ($ 0.01 per share of Class A Common Stock) as a reduction of additional paid-in capital, and will continue to do so until additional paid-in capital is reduced to zero. Thereafter, any excess purchase price will be recorded as an reduction to retained earnings. All Class A Common Stock shares repurchased are retired upon repurchase. 
+Revenue Recognition 
+Under ASC Topic 606- Revenue from Contracts with Customers , revenue recognition is based on the transfer of control, or the customer’s ability to benefit from the services and products in an amount that reflects the consideration expected to be received in exchange for those services and products. In recognizing revenue for services and products, the transaction price is determined from sales orders or contracts with customers. Revenue is recognized at the completion of each fracturing stage, and in most cases the price at the end of each stage is fixed, however, in limited circumstances contracts may contain variable consideration. 
+Variable consideration typically may relate to discounts, price concessions and incentives. The Company estimates variable consideration based on the amount of consideration we expect to receive. The Company accrues revenue on an ongoing basis to reflect updated information for variable consideration as performance obligations are met. 
+The Company also assesses customers’ ability and intention to pay, which is based on a variety of factors including historical payment experience and financial condition. Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30 to 45 days. 
+In connection with the adoption of ASC Topic 842, the Company determined that certain of its service revenue contracts contain a lease component. The Company elected to adopt a practical expedient available to lessors, which allows the Company to combine the lease and non-lease components and account for the combined component in accordance with the accounting treatment for the predominant component. Therefore, the Company combines the lease and service component for certain of the 
+F-14 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Company’s service contracts and continues to account for the combined component under ASC Topic 606, Revenue from Contracts with Customers. 
+Deferred Revenue 
+From time to time, the Company may require partial payment in advance from new customers to secure credit or from existing customers in order to secure additional hydraulic fracturing services. Initially, such payments are recorded in the accompanying consolidated financial statements as deferred revenue, and upon performance of the agreed services, the Company recognizes revenue consistent with its revenue recognition policy described above. As of December 31, 2022 and 2021, the Company had $ 3.9 million and $ 4.6 million recorded as deferred revenue, respectively. 
+Transaction, Severance and Other Costs 
+During 2022, the Company incurred transaction and integration related costs in connection with the PropX Acquisition (as defined below). Such costs include investment banking, legal, accounting and other professional services provided in connection with closing the transaction and are expensed as incurred . Additionally, during 2021, the Company incurred transaction and integration related costs in connection with the OneStim Acquisition (as defined below) and PropX Acquisition. 
+The Company incurred transaction costs in 2020 related to the OneStim Acquisition and severance and other costs related to the reduction in workforce in April 2020 and the commencement of furlough schedules for remaining employees in May 2020. Payments made to employees leaving the Company, as well as benefits paid to employees while on furlough are recorded to transaction, severance and other costs in the accompanying consolidated statements of operations for the year ended December 31, 2020. 
+Foreign Currency Translation 
+The Company records foreign currency translation adjustments from the process of translating the functional currency of the financial statements of its foreign subsidiary into the U.S. dollar reporting currency. The Canadian dollar is the functional currency of the Company’s foreign subsidiary as it is the primary currency within the economic environment in which the subsidiary operates. Assets and liabilities of the subsidiary’s operations are translated into U.S. dollars at the rate of exchange in effect on the balance sheet date and income and expenses are translated at the average exchange rate in effect during the reporting period. Adjustments resulting from the translation of the subsidiary’s financial statements are reported in other comprehensive income. 
+Reclassifications 
+Certain amounts in the prior period financial statements have been reclassified from interest income to interest expense, net in the accompanying consolidated statements of operation to conform to the presentation of the current period financial statements. Additionally, amounts in the prior period financial statements have been reclassified from amortization of debt issuance costs to other non-cash (income) expense, net in the accompanying consolidated statement of cash flows to conform to the presentation of the current period financial statements. These reclassifications had no effect on the previously reported net income or loss. 
+Note 3— Acquisitions 
+PropX Acquisition 
+On October 26, 2021, the Company entered into the certain Unit Purchase Agreement (the “Transaction Agreement”) with Proppant Express Investments, LLC to acquire the assets and liabilities of Proppant Express Solutions, LLC (“PropX”), which provides last-mile proppant delivery solutions, including proppant handling equipment and logistics software across North America (the “PropX Acquisition”). PropX was acquired in exchange for $ 11.9 million in cash and 3,405,526 shares of the Company’s Class A Common Stock and 2,441,010 shares of the Company’s Class B Common Stock, for total consideration of $ 103.0 million based on the October 26, 2021 closing price of Class A Common Stock of $ 15.58 . In connection with the issuance of 2,441,010 shares of Class B Common Stock, Liberty LLC also issued 2,441,010 Liberty LLC Units to the Company. The Liberty LLC Units are redeemable for an equivalent number of shares of Class A Common Stock at any time, at the election of the shareholder. 
+The Company accounted for the PropX Acquisition using the acquisition method of accounting. The aggregate purchase price noted above was allocated to the major categories of assets acquired and liabilities assumed based upon their estimated fair value at the date of the acquisition. The estimated fair values of certain assets and liabilities require significant judgments and estimates. The majority of the measurements of assets acquired and liabilities assumed, are based on inputs that are not observable in the market and thus represent Level 3 inputs. 
+F-15 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+In accordance with ASC Topic 805, an acquirer is allowed a period, referred to as the measurement period, in which to complete its accounting for the transaction. Such measurement period ends at the earliest date that the acquirer a) receives the information necessary or b) determines that it cannot obtain further information, and such period may not exceed one year. As the PropX Acquisition closed on October 26, 2021 the Company completed the purchase price allocation, particularly as it relates to current assets and current liabilities, during the year ended December 31, 2022. 
+The following table summarizes the fair value of the consideration transferred in the PropX Acquisition and the allocation of the purchase price to the fair value of the assets acquired and liabilities assumed as of October 26, 2021, the date of the closing of the PropX Acquisition: 
+($ in thousands) 
+Total Purchase Consideration: 
+Consideration $ 103,023 
+Cash and cash equivalents $ 53 
+Accounts receivable and unbilled revenue 4,089 
+Inventory 8 
+Prepaid and other current assets 1,722 
+Property and equipment (1) 
+94,137 
+Intangible assets (included in other assets in the accompanying consolidated balance sheet as of December 31, 2021) (2) 
+7,100 
+Total identifiable assets acquired 107,109 
+Accounts payable 2,152 
+Accrued liabilities 1,934 
+Total liabilities assumed 4,086 
+Total purchase consideration $ 103,023 
+(1) Useful lives average of 10 years, see Note 5—Property and Equipment 
+(2) Definite lived intangibles with an amortization period ranging from seven to 10 years 
+Transaction costs, costs associated with issuing additional equity and integration costs were recognized separately from the acquisition of assets and assumptions of liabilities in the PropX Acquisition. Transaction costs consist of legal and professional fees. Integration costs consist of expenses incurred to integrate PropX’s operations, aligning accounting processes and procedures, and integrating its enterprise resource planning system with those of the Company. Merger and integration costs are expensed as incurred, and equity offering costs were recorded as a reduction to additional paid in capital. 
+The Company’s consolidated statements of operations for the year ended December 31, 2021 includes 66 days of PropX operations as the PropX Acquisition closed on October 26, 2021. The Company does not present pro forma financial information for the periods prior to the PropX Acquisition as such information, after elimination of PropX’s historical transactions with the Company, is not materially different than the results presented in the accompanying Consolidated Statements of Operations for years ended December 31, 2021 and 2020. 
+OneStim Acquisition 
+On August 31, 2020 the Company and certain of its subsidiaries entered into the certain Master Transaction Agreement (the “Transaction Agreement”) with Schlumberger Technology Corporation and Schlumberger Canada Limited (collectively “Schlumberger”), pursuant to which the Company acquired certain assets and liabilities of Schlumberger’s OneStim® business, which provides hydraulic fracturing pressure pumping services in onshore United States and Canada (such entire business of Schlumberger “OneStim,” and the portion of OneStim acquired pursuant to the Transaction Agreement the “Transferred Business”) in exchange for 57,377,232 shares of Class A Common Stock and a non-interest bearing demand promissory note (the “Canadian Buyer Note” and such acquisition, the “OneStim Acquisition”). The Canadian Buyer Note was settled for 8,948,902 shares of Class A Common Stock, and a total of 66,326,134 shares of Class A Common Stock were issued in connection with the OneStim Acquisition. Effective December 31, 2020, Schlumberger owned approximately 37.0 % of the Company’s issued and outstanding shares of Common Stock. In connection with the issuance of 66,326,134 shares of Class A Common Stock, Liberty LLC also issued 66,326,134 Liberty LLC Units to the Company. 
+F-16 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+The OneStim Acquisition was completed for total consideration of approximately $ 683.8 million based on the value of the Canadian Buyer Note and the closing price of the Class A Common Stock on December 31, 2020. The Company accounted for the OneStim Acquisition using the acquisition method of accounting. The aggregate purchase price noted above was allocated to the major categories of assets acquired and liabilities assumed based upon their estimated fair value at the date of the acquisition. The estimated fair values of certain assets and liabilities, including accounts receivable, require significant judgments and estimates. The majority of the measurements of assets acquired and liabilities assumed, are based on inputs that are not observable in the market and thus represent Level 3 inputs. 
+In accordance with ASC Topic 805, an acquirer is allowed a period, referred to as the measurement period, in which to complete its accounting for the transaction. Such measurement period ends at the earliest date that the acquirer a) receives the information necessary or b) determines that it cannot obtain further information, and such period may not exceed one year. As the OneStim Acquisition closed on December 31, 2020 the Company completed the purchase price allocation during the year ended December 31, 2021. 
+Transaction costs, costs associated with issuing additional equity and integration costs were recognized separately from the acquisition of assets and assumptions of liabilities in the OneStim Acquisition. Transaction costs consist of legal and professional fees and pre-merger notification fees. Equity offering costs consist of expenses incurred related to the Special Meeting of Stockholders, including the costs to prepare the required filings associated with such meeting, held on November 3, 2020. Integration costs consist of expenses incurred to integrate OneStim’s operations, aligning accounting processes and procedures, and integrating its enterprise resource planning system with those of the Company. Merger and integration costs are expensed as incurred, and equity offering costs were recorded as a reduction to additional paid in capital. 
+The following combined pro forma information assumes the OneStim Acquisition occurred on January 1, 2020. The pro forma information presented below is for illustrative purposes only and does not reflect future events that occurred after December 31, 2020 or any operating efficiencies or inefficiencies that may result from the OneStim Acquisition. The information is not necessarily indicative of results that would have been achieved had the Company controlled OneStim during the periods presented. 
+Year ended December 31, 
+(unaudited, in thousands) 2020 
+Revenue $ 2,191,894 
+Net loss ( 1,052,807 ) 
+Less: Net loss attributable to non-controlling interests ( 196,020 ) 
+Net loss attributable to Liberty Energy Inc. stockholders $ ( 856,787 ) 
+Net loss attributable to Liberty Energy Inc. stockholders per common share: 
+Basic $ ( 5.65 ) 
+Diluted $ ( 5.65 ) 
+Weighted average common shares outstanding: 
+Basic 151,568 
+Diluted 151,568 
+The Company’s consolidated statements of operations for the year ended December 31, 2020 does not include any results from OneStim operations as the OneStim Acquisition closed on December 31, 2020. 
+Transaction and integration costs incurred related to both transactions were $ 5.8 million, $ 13.6 million, and $ 8.5 million, for the years ended December 31, 2022, 2021, and 2020, respectively, and are recorded as a component of transaction, severance and other costs in the accompanying consolidated statements of operations. Equity offering costs totaled $ 0.1 million, $ 1.3 million, and $ 1.6 million, for the years ended December 31, 2022, 2021, and 2020, respectively, and are recorded as a reduction to additional paid in capital in the accompanying consolidated balance sheets. 
+F-17 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Note 4— Inventories 
+Inventories consist of the following: 
+December 31, 
+($ in thousands) 2022 2021 
+Proppants $ 31,350 $ 23,413 
+Chemicals 32,392 17,996 
+Maintenance parts 150,712 93,184 
+$ 214,454 $ 134,593 
+During the year ended December 31, 2022, the lower of cost or net realizable value analysis resulted in the Company recording a write-down to the inventory carrying value of $ 1.7 million, which is included as a component in cost of services in the consolidated statements of operations. The Company did not record any write-down to the inventory carrying value during the year ended December 31, 2021. 
+Note 5— Property and Equipment 
+Property and equipment consist of the following: 
+Estimated 
+useful lives 
+(in years) December 31, 
+2022 2021 
+($ in thousands) 
+Land N/A $ 29,276 $ 33,812 
+Field services equipment 
+2 - 10 
+1,925,848 1,579,420 
+Vehicles 
+4 - 7 
+62,683 61,282 
+Lease Equipment 10 106,087 64,770 
+Buildings and facilities 
+5 - 30 
+135,281 148,555 
+Mineral reserves 
+> 25 
+76,823 76,823 
+Office equipment and furniture 
+2 - 7 
+9,504 8,218 
+2,345,502 1,972,880 
+Less accumulated depreciation and depletion ( 1,141,656 ) ( 863,194 ) 
+1,203,846 1,109,686 
+Construction in-progress N/A 158,518 89,601 
+$ 1,362,364 $ 1,199,287 
+During the years ended December 31, 2022, 2021, and 2020, the Company recognized depreciation expense of $ 302.3 million, $ 243.0 million, and $ 169.9 million, respectively. Depletion expense for the years ended December 31, 2022, 2021, and 2020 was $ 1.2 million, $ 1.2 million, and $ 0.0 million , respectively. 
+As of December 31, 2022 and December 31, 2021, the Company concluded that no triggering events that could indicate possible impairment of property and equipment had occurred, other than related to the assets held for sale discussed below. 
+As of December 31, 2022, the Company classified $ 1.1 million of land and $ 6.2 million of buildings, net of accumulated depreciation, of two properties that it intends to sell within the next year, and that meets the held for sale criteria, to assets held for sale, included in prepaid and other current assets in the accompanying consolidated balance sheet. The Company estimates that the carrying value of the assets were greater than the fair value less the estimated costs to sell, and therefore recorded a $ 1.0 million loss during the year ended December 31, 2022, included as a component of gain on disposal of assets in the accompanying consolidated statements of operations. As of December 31, 2021, the Company determined no assets met the held for sale criteria. 
+Note 6— Leases 
+Lessee Arrangements 
+The Company has operating and finance leases primarily for vehicles, equipment, railcars, office space, and facilities. The terms and conditions for these leases vary by the type of underlying asset. 
+F-18 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Certain leases include variable lease payments for items such as property taxes, insurance, maintenance, and other operating expenses associated with leased assets. Payments that vary based on an index or rate are included in the measurement of lease assets and liabilities at the rate as of the commencement date. All other variable lease payments are excluded from the measurement of lease assets and liabilities, and are recognized in the period in which the obligation for those payments is incurred. 
+The components of lease expense for the years ended as of December 31, 2022, and 2021 were as follows: 
+($ in thousands) 2022 2021 
+Finance lease cost: 
+Amortization of right-of-use assets $ 5,827 $ 5,490 
+Interest on lease liabilities 1,707 1,598 
+Operating lease cost 43,214 40,365 
+Variable lease cost 4,801 4,183 
+Short-term lease cost 6,931 5,026 
+Total lease cost, net $ 62,480 $ 56,662 
+Supplemental cash flow and other information related to leases for the year ended December 31, 2022 and 2021 were as follows: 
+($ in thousands) 2022 2021 
+Cash paid for amounts included in measurement of liabilities: 
+Operating leases $ 42,108 $ 37,121 
+Finance leases 10,889 8,598 
+Right-of-use assets obtained in exchange for new lease liabilities: 
+Operating leases 25,862 71,477 
+Finance leases 25,888 1,500 
+During the years ended December 31, 2022 and 2021, the Company amended certain operating leases, the change in terms of which caused the leases to be reclassified to finance leases. In connection with the amendments, the Company recognized finance lease right-of-use assets of $ 3.5 million and liabilities of $ 3.5 million. Additionally, the Company wrote-off operating lease right-of-use assets of $ 0.2 million and liabilities of $ 0.1 million. During the year ended December 31, 2021, the Company amended certain finance leases, the change in terms of which caused the leases to be reclassified to operating leases. In connection with the amendments the Company wrote-off finance lease right-of-use assets of $ 16.6 million and liabilities of $ 12.8 million. Additionally, the Company recognized operating lease right-of-use assets of $ 14.3 million and liabilities of $ 10.7 million. There was no gain or loss recognized as a result of these amendments. 
+Lease terms and discount rates as of December 31, 2022 and 2021 were as follows: 
+December 31, 2022 December 31, 2021 
+Weighted-average remaining lease term: 
+Operating leases 4.8 years 5.2 years 
+Finance leases 3.1 years 1.5 years 
+Weighted-average discount rate: 
+Operating leases 4.6 % 4.2 % 
+Finance leases 8.2 % 8.6 % 
+F-19 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Future minimum lease commitments as of December 31, 2022 are as follows: 
+($ in thousands) Finance Operating 
+2023 $ 11,737 $ 31,073 
+2024 7,300 24,560 
+2025 7,411 22,238 
+2023 12,663 11,110 
+2027 154 4,572 
+Thereafter — 14,504 
+Total lease payments 39,265 108,057 
+Less imputed interest 5,382 11,468 
+Total $ 33,883 $ 96,589 
+The Company’s vehicle leases typically include a residual value guarantee. For the Company’s vehicle leases classified as operating leases, the total residual value guaranteed as of December 31, 2022 is $ 13.1 million; the payment is not probable and therefore has not been included in the measurement of the lease liability and right-of-use asset. For vehicle leases that are classified as finance leases, the Company includes the residual value guarantee, estimated in the lease agreement, in the financing lease liability. 
+Lessor Arrangements 
+The Company leases dry and wet sand containers and conveyor belts to customers through PropX. PropX leases to customers through operating leases, where the lessor for tax purposes is considered to be the owner of the equipment during the term of the lease. The lease agreements do not include options for the lessee to purchase the underlying asset at the end of the lease term for either a stated fixed price or fair market value. However, some of the leases contain a termination clause in which the customer can cancel the contract. The leases can be subject to variable lease payments if the customer requests more units than what is agreed upon in the lease. The Company does not record any lease assets or liabilities related to these variable items. 
+The carrying amount of equipment leased to others, included in property, plant and equipment, under operating leases as of December 31, 2022 and 2021 were as follows: 
+($ in thousands) December 31, 2022 December 31, 2021 
+Equipment leased to others - at original cost $ 106,087 $ 64,770 
+Less: Accumulated depreciation ( 11,408 ) ( 1,377 ) 
+Equipment leased to others - net $ 94,679 $ 63,393 
+Future payments receivable for operating leases commenced and committed but not delivered as of December 31, 2022 are as follows: 
+($ in thousands) 
+2023 $ 16,704 
+2024 9,218 
+2025 1,051 
+2026 — 
+2027 — 
+Thereafter — 
+Total $ 26,973 
+Revenues from operating leases for the years ended December 31, 2022 and 2021 were $ 25.5 million and $ 3.2 million, respectively. 
+F-20 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Note 7— Accrued Liabilities 
+Accrued liabilities consist of the following: 
+($ in thousands) December 31, 2022 December 31, 2021 
+Accrued vendor invoices $ 119,801 $ 109,903 
+Operations accruals 72,348 64,707 
+Accrued benefits and other 86,964 60,505 
+$ 279,113 $ 235,115 
+Note 8— Debt 
+Debt consists of the following: 
+December 31, 
+2022 2021 
+Term Loan Outstanding $ 104,716 $ 106,465 
+Revolving Line of Credit 115,000 18,000 
+Deferred financing costs and original issue discount ( 1,270 ) ( 2,013 ) 
+Total debt, net of deferred financing costs and original issue discount $ 218,446 $ 122,452 
+Current portion of long-term debt, net of discount $ 1,020 $ 1,007 
+Long-term debt, net of discount and current portion 217,426 121,445 
+$ 218,446 $ 122,452 
+On September 19, 2017, the Company entered into two credit agreements, a revolving line of credit up to $ 250.0 million subsequently increased to $ 425.0 million, see below, (the “ABL Facility”) and a $ 175.0 million term loan (the “Term Loan Facility”, and together with the ABL Facility the “Credit Facilities”). 
+On July 18, 2022, the Company entered into an amendment to the ABL Facility (the “Seventh ABL Amendment”). The Seventh ABL Amendment amended certain terms, provisions and covenants of the ABL Facility, including among other things: (i) increasing the maximum borrowing amount by $ 75.0 million to $ 425.0 million, subject to certain borrowing base limitations based on percentage of eligible accounts receivable and inventory, (ii) modifying certain covenant and reporting-related baskets, and (iii) replacing LIBOR with the secured overnight financing rate (“SOFR”) as the interest rate benchmark. 
+On August 12, 2022, the Company entered into an amendment to the Term Loan Facility (the “Sixth Term Loan Amendment”). The Sixth Term Loan Amendment amended certain terms, provisions and covenants of the Term Loan Facility, including among other things: (i) a waiver of the fixed charge coverage ratio requirements for up to $ 100.0 million of restricted payments made in connection with the Company’s 2022 stock repurchase program for its common stock; (ii) the addition of a minimum liquidity requirement of $ 150.0 million in order to make selected restricted payments, including those made under the 2022 stock repurchase program; (iii) the modification of certain covenant and reporting-related terms, including an increase in the allowance for permitted purchase money indebtedness from $ 50.0 million to $ 70.0 million; (iv) the addition of a prepayment premium of 1.0 % through the first anniversary of the Sixth Term Loan Amendment effective date; and (v) the addition and modification of several provisions to replace LIBOR with SOFR as the interest rate benchmark. 
+On November 4, 2022, the Company entered into an amendment to the Term Loan Facility (the “Seventh Term Loan Amendment”). The Seventh Term Loan Amendment amended the restricted payments negative covenant of the Term Loan Facility so that the fixed charge coverage ratio requirements for dividend payments are waived, so long as the total of dividends paid and payments made in connection with the Company’s 2022 stock repurchase program does not exceed $ 100.0 million. During the fourth quarter of 2022 the restricted payments negative covenant pertaining to the fixed charge coverage ratio requirements were satisfied and the $ 100.0 million limit no longer applied. 
+Effective January 23, 2023, the Company entered into an Eighth Amendment to the ABL Facility (the “Eighth ABL Amendment”). The Eighth ABL Amendment amends certain terms, provisions and covenants of the ABL Facility, including, among other things: (i) increasing the maximum revolver amount from $ 425.0 million to $ 525.0 million (the “Upsized Revolver”); (ii) increasing the amount of the accordion feature from $ 75.0 million to $ 100.0 million; (iii) extending the maturity date from October 22, 2026 to January 23, 2028; (iv) modifying the dollar amounts of various credit facility triggers and tests proportionally to the Upsized Revolver; (v) permitting repayment under the Term Loan Facility prior to February 10, 2023; and (vi) increasing certain indebtedness, intercompany advance, and investment baskets. The Eighth ABL Amendment also includes an agreement from the Wells Fargo Bank, National Association, as administrative agent, to release its second priority liens and security interests on all collateral that served as first priority collateral under the Term Loan Facility, with such release to occur within 120 days after January 23, 2023, refer to Note 16—Subsequent Events for more information. 
+F-21 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Also on January 23, 2023, the Company withdrew $ 106.7 million on the ABL Facility and used the proceeds to pay off the Term Loan Facility. The balance of the Term Loan Facility upon pay off was $ 104.7 million and included $ 0.9 million of accrued interest and a $ 1.1 million prepayment premium or 1 % of the principal. Additionally, there were $ 0.2 million in bank and legal fees included in the pay off, refer to Note 16—Subsequent Events for more information. 
+The weighted average interest rate on all borrowings outstanding as of December 31, 2022 and December 31, 2021 was 9.0 % and 7.9 %, respectively. 
+ABL Facility 
+Under the terms of the ABL Facility, up to $ 425.0 million may be borrowed, subject to certain borrowing base limitations based on a percentage of eligible accounts receivable and inventory. As of December 31, 2022, the borrowing base was calculated to be $ 425.0 million, and the Company had $ 115.0 million outstanding in addition to letters of credit in the amount of $ 2.6 million, with $ 307.4 million of remaining availability. Borrowings under the ABL Facility bear interest at SOFR or a base rate, plus an applicable SOFR margin of 1.5 % to 2.0 % or base rate margin of 0.5 % to 1.0 %, as defined in the ABL Facility credit agreement. Additionally, borrowings as of December 31, 2022 incurred interest at a weighted average rate of 6.3 %. The average monthly unused commitment is subject to an unused commitment fee of 0.25 % to 0.375 %. Interest and fees are payable in arrears at the end of each month, or, in the case of SOFR loans, at the end of each interest period. The ABL Facility matures on the earlier of (i) October 22, 2026 and (ii) to the extent the debt under the Term Loan Facility remains outstanding, 90 days prior to the final maturity of the Term Loan Facility, which matures on September 19, 2024. Borrowings under the ABL Facility are collateralized by accounts receivable and inventory, and further secured by the Company, Liberty LLC, and R/C IV Non-U.S. LOS Corp., a Delaware corporation and a subsidiary of the Company, as parent guarantors. 
+Term Loan Facility 
+The Term Loan Facility provides for a $ 175.0 million term loan, of which $ 104.7 million remained outstanding as of December 31, 2022. Amounts outstanding bear interest at SOFR or a base rate, plus an applicable margin of 7.625 % or 6.625 %, respectively, and borrowings as of December 31, 2022 incurred interest at a rate of approximately 12.0 %. The Company is required to make quarterly principal payments of 1 % per annum of the outstanding principal balance, commencing on December 31, 2017, with final payment due at maturity on September 19, 2024. The Term Loan Facility is collateralized by the fixed assets of LOS and its subsidiaries, and is further secured by the Company, Liberty LLC, and R/C IV Non-U.S. LOS Corp., a Delaware corporation and a subsidiary of the Company, as parent guarantors. 
+The Credit Facilities include certain non-financial covenants, including but not limited to restrictions on incurring additional debt and certain distributions. Moreover, the ability of the Company to incur additional debt and to make distributions is dependent on maintaining a maximum leverage ratio. The Term Loan Facility requires mandatory prepayments upon certain dispositions of property or issuance of other indebtedness, as defined, and annually a percentage of excess cash flow ( 25 % to 50 %, depending on leverage ratio, of consolidated net income less capital expenditures and other permitted payments, commencing with the year ending December 31, 2018). Certain mandatory prepayments and optional prepayments are subject to a prepayment premium of 1 % of the prepaid principal declining annually to 0 % after the first anniversary of the Sixth Term Loan Amendment effective date. 
+The Credit Facilities are not subject to financial covenants unless liquidity, as defined in the respective credit agreements, drops below a specified level. Under the ABL Facility, the Company is required to maintain a minimum fixed charge coverage ratio, as defined in the credit agreement governing the ABL Facility, of 1.0 to 1.0 for each period if excess availability is less than 10 % of the borrowing base or $ 12.5 million, whichever is greater. Under the Term Loan Facility, the Company is required to maintain a minimum fixed charge coverage ratio, as defined, of 1.2 to 1.0 for each trailing twelve-month period if the Company’s liquidity, as defined, is less than $ 25.0 million for at least five consecutive business days. 
+The Company was in compliance with these covenants as of December 31, 2022. 
+Maturities of debt are as follows: 
+($ in thousands) 
+Years Ending December 31, 
+2023 $ 1,750 
+2024 217,966 
+2025 — 
+2026 — 
+2027 — 
+$ 219,716 
+F-22 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Note 9— Fair Value Measurements and Financial Instruments 
+The fair values of the Company’s assets and liabilities represent the amounts that would be received to sell those assets or that would be paid to transfer those liabilities in an orderly transaction on the reporting date. These fair value measurements maximize the use of observable inputs. However, in situations where there is little, if any, market activity for the asset or liability on the measurement date, the fair value measurement reflects the Company’s own judgments about the assumptions that market participants would use in pricing the asset or liability. The Company discloses the fair values of its assets and liabilities according to the quality of valuation inputs under the following hierarchy: 
+• Level 1 Inputs: Quoted prices (unadjusted) in an active market for identical assets or liabilities. 
+• Level 2 Inputs: Inputs other than quoted prices that are directly or indirectly observable. 
+• Level 3 Inputs: Unobservable inputs that are significant to the fair value of assets or liabilities. 
+The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those that are initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from unobservable inputs is inconsequential to the overall fair value, or if corroborating market data becomes available. Assets and liabilities that are initially reported as Level 2 are subsequently reported as Level 3 if corroborating market data is no longer available. Transfers occur at the end of the reporting period. There were no transfers into or out of Levels 1, 2, and 3 during the years ended December 31, 2022 and 2021. 
+The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, notes receivable, accounts payable, accrued liabilities, long-term debt, and finance and operating lease obligations. These financial instruments do not require disclosure by level. The carrying values of all of the Company’s financial instruments included in the accompanying consolidated balance sheets approximated or equaled their fair values on December 31, 2022 and 2021. 
+• The carrying values of cash and cash equivalents, accounts receivable and accounts payable (including accrued liabilities) approximated fair value on December 31, 2022 and 2021, due to their short-term nature. 
+• The carrying value of amounts outstanding under long-term debt agreements with variable rates approximated fair value on December 31, 2022 and 2021, as the effective interest rates approximated market rates. 
+Nonrecurring Measurements 
+Certain assets and liabilities are measured at fair value on a nonrecurring basis. These items are not measured at fair value on an ongoing basis but may be subject to fair value adjustments in certain circumstances. These assets and liabilities include those acquired through the PropX Acquisition and OneStim Acquisition, which are required to be measured at fair value on the acquisition date in accordance with ASC Topic 805 . See Note 3—Acquisitions. 
+As of December 31, 2022, the Company recorded $ 1.1 million of land and $ 6.2 million of buildings of two properties that met the held for sale criteria, to assets held for sale at a total fair value of $ 6.3 million, which are included in prepaid and other current assets in the accompanying consolidated balance sheet. The Company estimated the fair value of the properties based on a purchase and sale agreement and a communicated selling price, which are Level 3 inputs. 
+Recurring Measurements 
+The fair values of the Company’s cash equivalents measured on a recurring basis pursuant to ASC 820-10 Fair Value Measurements and Disclosures are carried at estimated fair value. Cash equivalents consist of money market accounts which the Company has classified as Level 1 given the active market for these accounts. As of December 31, 2022 and 2021, the Company had cash equivalents, measured at fair value, of $ 0.3 million and $ 0.3 million, respectively. 
+Nonfinancial assets 
+The Company estimates fair value to perform impairment tests as required on long-lived assets. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3 in the event that such assets were required to be measured and recorded at fair value within the consolidated financial statements. No such measurements were required as of December 31, 2022 and 2021 as no triggering event was identified. 
+Credit Risk 
+The Company’s financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents, and trade receivables. 
+F-23 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+The Company’s cash and cash equivalents balance on deposit with financial institutions total $ 43.7 million and $ 20.0 million as of December 31, 2022 and 2021, respectively, which exceeded FDIC insured limits. The Company regularly monitors these institutions’ financial condition. 
+The majority of the Company’s customers have payment terms of 45 days or less. 
+As of December 31, 2022 and 2021, customer A accounted for 11.0 % and 11.8 %, respectively, of total consolidated accounts receivable and unbilled revenue. During the years ended December 31, 2022 and 2021, no customers accounted for 10% of consolidated revenues. During the year ended December 31, 2020, customer B accounted for 12.1 %, customer C accounted for 10.7 %, customer D accounted for 10.3 %, and customer E accounted for 10.2 %, of total consolidated revenues. 
+The Company mitigates the associated credit risk by performing credit evaluations and monitoring the payment patterns of its customers. 
+As of December 31, 2022, the Company had $ 0.9 million in allowance for credit losses. As of December 31, 2021, the Company had $ 0.9 million in allowance for credit losses and recorded a provision related to two entities inability to pay. As of December 31, 2020 the Company had $ 0.8 million in allowance for credit losses. Subsequent to the adoption of ASU 2016-13 on January 1, 2020, the Company recognized a $ 4.9 million allowance for credit losses, to the Company’s accounts receivables in consideration of both historic collection experience and the expected impact of deteriorating economic conditions for the oil and gas industry as of such date. 
+The Company applied historic loss factors to its receivable portfolio segments that were not expected to be further impacted by current economic developments, and an additional economic conditions factor to portfolio segments anticipated to experience greater losses in the current economic environment. While the Company has not experienced significant credit losses in the past and has not seen material changes to the payment patterns of its customers, the Company cannot predict with any certainty the degree to which the ongoing impacts of COVID-19, including the potential impact of periodically adjusted borrowing base limits, level of hedged production, or unforeseen well shut-ins may affect the ability of its customers to timely pay receivables when due. Accordingly, in future periods, the Company may revise its estimates of expected credit losses. 
+($ in thousands) 2022 2021 2020 
+Allowance for credit losses, beginning of year $ 884 $ 773 $ 1,053 
+Credit losses: 
+Current period provision — 745 4,877 
+Amounts written off, net of recoveries — ( 634 ) ( 5,157 ) 
+Allowance for credit losses, end of year $ 884 $ 884 $ 773 
+Note 10— Equity 
+Preferred Stock 
+As of December 31, 2022 and 2021 the Company had 10,000 shares of preferred stock authorized, par value $ 0.01 , with none issued and outstanding. If issued, each class or series of preferred stock will cover the number of shares and will have the powers, preferences, rights, qualifications, limitations and restrictions determined by the Company’s board of directors, which may include, among others, dividend rights, liquidation preferences, voting rights, conversion rights, preemptive rights and redemption rights. Except as provided by law or in a preferred stock designation, the holders of preferred stock will not be entitled to vote at or receive notice of any meeting of shareholders. 
+Class A Common Stock 
+The Company had a total of 178,753,125 and 183,385,111 shares of Class A Common Stock outstanding as of December 31, 2022 and 2021, none of which were restricted. Holders of Class A Common Stock are entitled to one vote per share on all matters to be voted upon by the stockholders and are entitled to ratably receive dividends when and if declared by the Company’s board of directors. 
+F-24 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Class B Common Stock 
+The Company had a total of 250,222 and 2,632,347 shares of Class B Common Stock outstanding as of December 31, 2022 and 2021, respectively. Holders of the Class B Common Stock are entitled to one vote per share on all matters to be voted upon by stockholders. Holders of Class A Common Stock and Class B Common Stock vote together as a single class on all matters presented to the Company’s stockholders for their vote or approval, except with respect to amendment of certain provisions of the Company’s certificate of incorporation that would alter or change the powers, preferences or special rights of the Class B Common Stock so as to affect them adversely, which amendments must be by a majority of the votes entitled to be cast by the holders of the shares affected by the amendment, voting as a separate class, or as otherwise required by applicable law. 
+Holders of Class B Common Stock do not have any right to receive dividends, unless the dividend consists of shares of Class B Common Stock or of rights, options, warrants or other securities convertible or exercisable into or exchangeable for shares of Class B Common Stock paid proportionally with respect to each outstanding share of Class B Common Stock and a dividend consisting of shares of Class A Common Stock or of rights, options, warrants or other securities convertible or exercisable into or exchangeable for shares of Class A Common Stock on the same terms is simultaneously paid to the holders of Class A Common Stock. Holders of Class B Common Stock do not have any right to receive a distribution upon liquidation or winding up of the Company. 
+Under the Second Amended and Restated Limited Liability Company Agreement of Liberty LLC (the “Liberty LLC Agreement”), each Liberty Unit Holder has, subject to certain limitations, the Redemption Right, which allows it to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units, for, at Liberty LLC’s election, (i) shares of Class A Common Stock at a redemption ratio of one share of Class A Common Stock for each Liberty LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions or (ii) an equivalent amount of cash. Alternatively, upon the exercise of the Redemption Right, the Company (instead of Liberty LLC) will have the Call Right, which allows it to, for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder for, at its election, (x) one share of Class A Common Stock or (y) an equivalent amount of cash. In addition, upon a change of control of the Company, the Company has the right to require each holder of Liberty LLC Units (other than the Company) to exercise its Redemption Right with respect to some or all of such unitholder’s Liberty LLC Units. In connection with any redemption of Liberty LLC Units pursuant to the Redemption Right or the Call Right, the corresponding number of shares of Class B Common Stock will be canceled. 
+Long Term Incentive Plan 
+On January 11, 2018, the Company adopted the Long Term Incentive Plan (“LTIP”) to incentivize employees, officers, directors and other service providers of the Company and its affiliates. The LTIP provides for the grant, from time to time, at the discretion of the Company’s board of directors or a committee thereof, of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, cash awards, substitute awards and performance awards. Subject to adjustment in the event of certain transaction or changes of capitalization in accordance with the LTIP, 12,908,734 shares of Class A Common Stock have been reserved for issuance pursuant to awards under the LTIP. Class A Common Stock subject to an award that expires or is canceled, forfeited, exchanged, settled in cash or otherwise terminated without delivery of shares and shares withheld to pay the exercise price of, or to satisfy the withholding obligations with respect to, an award will again be available for delivery pursuant to other awards under the LTIP. 
+Restricted Stock Units 
+Restricted stock units (“RSUs”) granted pursuant to the LTIP, if they vest, will be settled in shares of the Company’s Class A Common Stock. RSUs were granted with vesting terms up to five years. Changes in non-vested RSUs outstanding under the LTIP during the year ended December 31, 2022 were as follows: 
+Number of Units Weighted Average Grant Date Fair Value per Unit 
+Non-vested as of December 31, 2021 2,741,061 $ 11.04 
+Granted 1,727,721 12.89 
+Vested ( 1,354,312 ) 11.00 
+Forfeited ( 128,743 ) 10.55 
+Outstanding at December 31, 2022 2,985,727 $ 12.15 
+F-25 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Performance Restricted Stock Units 
+Performance restricted stock units (“PSUs”) granted pursuant to the LTIP, if they vest, will be settled in shares of the Company’s Class A Common Stock. PSUs were granted with a three -year cliff vesting schedule, subject to a performance target compared to an index of competitors ’ results over the three -year period as designated in the award. The Company records compensation expense based on the Company’s best estimate of the number of PSUs that will vest at the end of the performance period. If such performance targets are not met, or are not expected to be met, no compensation expense is recognized and any recognized compensation expense is reversed. Changes in non-vested PSUs outstanding under the LTIP during the year ended December 31, 2022 were as follows: 
+Number of Units Weighted Average Grant Date Fair Value per Unit 
+Non-vested as of December 31, 2021 1,306,945 $ 12.45 
+Granted 412,920 12.47 
+Vested ( 329,277 ) 14.93 
+Forfeited — — 
+Outstanding at December 31, 2022 1,390,588 $ 11.87 
+Stock-based compensation is included in cost of services and general and administrative expenses in the Company’s consolidated statements of operations. The Company recognized stock-based compensation expense of $ 23.1 million for the year ended December 31, 2022 and $ 19.9 million for the year ended December 31, 2021. There was approximately $ 29.9 million of unrecognized compensation expense relating to outstanding RSUs and PSUs as of December 31, 2022. The unrecognized compensation expense will be recognized on a straight-line basis over the weighted average remaining vesting period of two years . 
+Dividends 
+On April 2, 2020, the Company suspended future quarterly dividends until they were reinstated on October 18, 2022 by the Company’s board of directors. 
+The Company paid cash dividends of $ 0.05 per share of Class A Common Stock on December 20, 2022 to stockholders of record as of December 6, 2022. Liberty LLC paid a distribution of $ 9.0 million, or $ 0.05 per Liberty LLC Unit, to all Liberty LLC unit holders as of December 6, 2022, $ 9.0 million of which was paid to the Company. The Company used the proceeds of the distribution to pay the dividend to all holders of shares of Class A Common Stock as of December 6, 2022, which totaled $ 9.0 million. 
+The Company paid cash dividends of $ 0.05 per share of Class A Common Stock on March 20, 2020 to stockholders of record as of March 6, 2020. Liberty LLC paid a distribution of $ 5.6 million, or $ 0.05 per Liberty LLC Unit, to all Liberty LLC unit holders as of March 6, 2020, $ 4.1 million of which was paid to the Company. The Company used the proceeds of the distribution to pay the dividend to all holders of shares of Class A Common Stock as of March 6, 2020, which totaled $ 4.1 million. 
+Additionally, as of December 31, 2022 and 2021, the Company had $ 0.2 million and $ 0.2 million of dividend equivalents payable related to RSUs and PSUs to be paid upon vesting, respectively. Dividends related to forfeited RSUs or PSUs will be forfeited. 
+Share Repurchase Program 
+On July 25, 2022, the Company’s board of directors authorized and the Company announced a share repurchase program that allows the Company to repurchase up to $ 250.0 million of the Company’s Class A Common Stock beginning immediately and continuing through and including July 31, 2024. Additionally, on January 24, 2023 the Board authorized and the Company announced an increase to the share repurchase program that increased the Company’s cumulative repurchase authorization to $ 500.0 million. The shares may be repurchased from time to time in open market or privately negotiated transactions or by other means in accordance with applicable state and federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will be determined by the Company at its discretion and will depend on a variety of factors, including management’s assessment of the intrinsic value of the Company’s Class A Common Stock, the market price of the Company’s Class A Common Stock, general market and economic conditions, available liquidity, compliance with the Company’s debt and other agreements, applicable legal requirements, and other considerations. The exact number of shares to be repurchased by the Company is not guaranteed, and the program may be suspended, modified, or discontinued at any time without prior notice. The Company expects to fund the repurchases by using cash on hand, borrowings under its revolving credit facility and expected free cash flow to be generated through July 2024. 
+F-26 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+During the year ended December 31, 2022, Liberty LLC purchased and retired 8,185,890 LLC Units from the Company for $ 125.3 million, and the Company repurchased and retired 8,185,890 shares of Class A Common Stock for $ 125.3 million or $ 15.31 average price per share including commissions, under the share repurchase program. 
+As of December 31, 2022, $ 124.7 million remained authorized for future repurchases of Class A Common Stock under the share repurchase program. 
+During the years ended December 31, 2021 and 2020, under the prior share repurchase program, no shares were repurchased and retired under the share repurchase program. 
+The Company accounts for the purchase price of repurchased common shares in excess of par value ($ 0.01 per share of Class A Common Stock) as a reduction of additional paid-in capital, and will continue to do so until additional paid-in capital is reduced to zero. Thereafter, any excess purchase price will be recorded as a reduction to retained earnings. 
+Note 11— Net Income (Loss) per Share 
+Basic net income (loss) per share measures the performance of an entity over the reporting period. Diluted net income (loss) per share measures the performance of an entity over the reporting period while giving effect to all potentially dilutive common shares that were outstanding during the period. The Company uses the “if-converted” method to determine the potential dilutive effect of its Class B Common Stock and the treasury stock method to determine the potential dilutive effect of outstanding restricted stock and RSUs. 
+The following table reflects the allocation of net income (loss) to common stockholders and net income (loss) per share computations for the periods indicated based on a weighted average number of common stock outstanding: 
+(In thousands, except per share data) Year Ended December 31, 2022 Year Ended December 31, 2021 
+Basic Net Income (Loss) Per Share 
+Numerator: 
+Net income (loss) attributable to Liberty Energy Inc. stockholders $ 399,602 $ ( 179,244 ) 
+Denominator: 
+Basic weighted average common shares outstanding 184,334 174,019 
+Basic net income (loss) per share attributable to Liberty Energy Inc. stockholders $ 2.17 $ ( 1.03 ) 
+Diluted Net Income (Loss) Per Share 
+Numerator: 
+Net income (loss) attributable to Liberty Energy Inc. stockholders $ 399,602 $ ( 179,244 ) 
+Effect of exchange of the shares of Class B Common Stock for shares of Class A Common Stock 716 — 
+Diluted net income (loss) attributable to Liberty Energy Inc. stockholders $ 400,318 $ ( 179,244 ) 
+Denominator: 
+Basic weighted average shares outstanding 184,334 174,019 
+Effect of dilutive securities: 
+Restricted stock units 4,262 — 
+Class B Common Stock 753 — 
+Diluted weighted average shares outstanding 189,349 174,019 
+Diluted net income (loss) per share attributable to Liberty Energy Inc. stockholders $ 2.11 $ ( 1.03 ) 
+In accordance with GAAP, diluted weighted average common shares presented above do not include certain weighted average shares of Class B Common Stock and restricted stock units, because to do so would have had an antidilutive effect, as follows: 
+Year Ended Year Ended 
+(In thousands) December 31, 2022 December 31, 2021 
+Weighted average shares of Class B Common Stock — 7,052 
+Weighted average shares of restricted stock units — 3,589 
+F-27 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Note 12— Income Taxes 
+The Company is a corporation and is subject to taxation in the United States, Canada and various state, local and provincial jurisdictions. Liberty LLC is treated as a partnership, and its income is passed through to its owners for income tax purposes. Liberty LLC’s members, including the Company, are liable for federal, state and local income taxes based on their share of Liberty LLC’s pass-through taxable income. As of December 31, 2022, tax reporting by the Company for the years ended December 31, 2019, 2020, and 2021 is subject to examination by the tax authorities. With few exceptions, as of December 31, 2022, the Company is no longer subject to U.S. federal, state or local examinations by tax authorities for tax years ended before December 31, 2018. 
+The components of the Company’s income (loss) from continuing operations before income taxes on which the provision for income taxes was computed consisted of the following: 
+Year Ended December 31, 
+($ in thousands) 2022 2021 2020 
+United States $ 375,758 $ ( 191,774 ) $ ( 191,531 ) 
+Foreign 23,751 13,986 — 
+Total $ 399,509 $ ( 177,788 ) $ ( 191,531 ) 
+The components of the provision for incomes taxes from continuing operations are summarized as follows: 
+Year Ended December 31, 
+($ in thousands) 2022 2021 2020 
+Current: 
+Federal $ 4,679 $ — $ ( 5,541 ) 
+State 2,579 29 230 
+Foreign 4,421 4,108 — 
+Total Current $ 11,679 $ 4,137 $ ( 5,311 ) 
+Deferred: 
+Federal $ ( 12,967 ) $ 6,125 $ ( 23,103 ) 
+State ( 1,182 ) ( 439 ) ( 2,443 ) 
+Foreign 1,677 ( 607 ) — 
+Total Deferred $ ( 12,472 ) $ 5,079 $ ( 25,546 ) 
+Income tax (benefit) expense $ ( 793 ) $ 9,216 $ ( 30,857 ) 
+Income tax (benefit) expense attributable to net income (loss) before income taxes differed from the amounts computed by applying the statutory U.S. federal income tax rate of 21.0% to pre-tax income as a result of the following: 
+Year Ended December 31, 
+($ in thousands) 2022 2021 2020 
+Computed tax expense (benefit) at the statutory rate $ 83,897 $ ( 37,336 ) $ ( 40,222 ) 
+Increase (decrease) in tax expense resulting from: 
+State and local income tax expense (benefit), net 10,224 ( 5,204 ) ( 2,212 ) 
+Non-controlling interest ( 151 ) 1,565 9,463 
+Effect of foreign tax rates 697 478 — 
+Stock-based compensation ( 2,724 ) ( 535 ) 2,157 
+Change in valuation allowance ( 91,336 ) 50,111 — 
+Other TRA adjustment ( 2,763 ) — — 
+U.S. impact of foreign earnings 315 — — 
+Other, net 1,048 137 ( 43 ) 
+Total income tax (benefit) expense $ ( 793 ) $ 9,216 $ ( 30,857 ) 
+F-28 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+The effective tax rate for the years ended December 31, 2022, 2021, and 2020 was ( 0.2 )%, ( 5.2 )%, and 16.1 %, respectively. 
+The Company recognized income tax benefit of $( 0.8 ) million during the year ended December 31, 2022. The Company’s effective tax rate is less than the statutory federal income tax rate of 21.0% due to the Company releasing the valuation allowance on its U.S. net deferred tax assets as of December 31, 2021, due to entering into a three-year cumulative pre-tax book income position, as a result of improved operations. 
+The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are presented below: 
+($ in thousands) December 31, 2022 December 31, 2021 
+Deferred tax assets: 
+Federal net operating losses $ 25,570 $ 50,093 
+State net operating losses 5,762 7,576 
+Realized tax benefit - TRAs 99,153 91,312 
+Intangibles 576 301 
+Property and equipment 4,638 — 
+Other 450 219 
+Total deferred tax assets 136,149 149,501 
+Less valuation allowance — ( 91,336 ) 
+Net deferred tax assets 136,149 58,165 
+Deferred tax liabilities: 
+Investment in Liberty LLC $ ( 121,861 ) $ ( 57,461 ) 
+Property and equipment — ( 97 ) 
+Other ( 2,740 ) ( 563 ) 
+Total deferred tax liabilities ( 124,601 ) ( 58,121 ) 
+Net deferred tax asset $ 11,548 $ 44 
+During the year ended December 31, 2022 the Company released the valuation allowance on the Company’s beginning U.S. net deferred tax assets, resulting in the recognition of an income tax benefit of $ 91.3 million. As of December 31, 2022, the Company had significant deferred tax assets and liabilities, deferred tax assets include U.S. federal and state net operating losses and the step-up in basis of depreciable assets under Section 754 (“Section 754”) of the Internal Revenue Code of 1986, as amended. In addition, the Company recorded a deferred tax liability for the difference between the book value and the tax value of the Company's investment in Liberty LLC. The Company also has deferred tax liabilities for foreign operations driven by net deductible reversing temporary differences related to differences between book and taxable income. 
+As of December 31, 2022, the Company has available U.S. federal net operating loss carryforwards to reduce future taxable income of $ 121.6 million with no expiration date. Per the Coronavirus Aid, Relief and Economic Security (“CARES”) Act enacted March 27, 2020, net operating losses (“NOL”) incurred in 2018, 2019, and 2020 may be carried back to each of the five preceding taxable years to generate a refund of previously paid income taxes. The Company has applied for and expects to receive a NOL carryback refund to recover $ 5.5 million of cash taxes paid by the Company in 2018. This amount has been reflected as a receivable in prepaids and other assets. The remaining deferred tax asset for net operating losses available for carryforward are presented as part of deferred tax assets. 
+The Company may distribute cash from foreign subsidiaries to its U.S. parent as business needs arise. The Company has not provided for deferred income taxes on the undistributed earnings from certain foreign subsidiaries earnings as such earnings are considered to be indefinitely reinvested. If such earnings were to be distributed, any income and/or withholding tax would not be significant. 
+Uncertain Tax Positions 
+The Company records uncertain tax positions on the basis of a two-step process in which (1) the Company determines whether it is more likely than not the tax positions will be sustained on the basis of the technical merits of the position and (2) 
+F-29 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+for those tax positions meeting the more likely than not recognition threshold, the Company recognizes the largest amount of tax benefit that is more than 50% likely to be realized upon ultimate settlement with the related tax authority. 
+The Company determined that no liability for unrecognized tax benefits for uncertain tax positions was required at December 31, 2022. In addition, the Company does not believe that it has any tax positions for which it is reasonably possible that it will be required to record a significant liability for unrecognized tax benefits within the next twelve months. If the Company were to record an unrecognized tax benefit, the Company will recognize applicable interest and penalties related to income tax matters in income tax expense. 
+Tax Distributions 
+Liberty LLC is treated as a partnership for income tax purposes. Federal, state and local taxes resulting from the pass-through taxable income of Liberty LLC are obligations of its members. Net profits and losses are generally allocated to the members of Liberty LLC (including the Company) in accordance with the number of Liberty LLC Units held by each member for tax purposes. The Liberty LLC Agreement provides for pro rata cash distributions, and in certain cases non-pro rata cash advances, to assist members (including the Company) in paying their income tax liabilities. The Liberty LLC Agreement requires any tax advances to be proportionally repaid in connection with any redemption of Liberty LLC Units pursuant to the Redemption Right or the Call Right. Net advances received by Liberty LLC from non-controlling interest holders were $ 0.9 million and $ 1.4 million, respectively, for the years ended December 31, 2022 and 2021. Additionally, Liberty LLC distributed $ 2.8 million of which $ 2.8 million was paid to the Company and $ 0.0 million to non-controlling interest holders for the year ended December 31, 2022. Liberty LLC distributed $ 0.0 million for the year ended December 31, 2021. 
+Tax Receivable Agreements 
+The term of each TRA commenced on January 17, 2018, and will continue until all such tax benefits that are subject to such TRA have been utilized or expired, unless the Company experiences a change of control (as defined in the TRAs, which includes certain mergers, asset sales and other forms of business combinations) or the TRAs are terminated early (at the Company’s election or as a result of its breach), and the Company makes the termination payments specified in such TRA. 
+The amounts payable, as well as the timing of any payments, under the TRAs are dependent upon significant future events and assumptions, including the timing of the redemptions of Liberty LLC Units, the price of our Class A Common Stock at the time of each redemption, the extent to which such redemptions are taxable transactions, the amount of the redeeming unit holder’s tax basis in its Liberty LLC Units at the time of the relevant redemption, the characterization of the tax basis step-up, the depreciation and amortization periods that apply to the increase in tax basis, the amount of net operating losses available to the Company as a result of the Corporate Reorganization, the amount and timing of taxable income the Company generates in the future, the U.S. federal income tax rate then applicable, and the portion of the Company’s payments under the TRAs that constitute imputed interest or give rise to depreciable or amortizable tax basis. 
+Prior to the Corporate Reorganization, one of the Legacy Owners distributed a portion of its member interest in Liberty Holdings to R/C IV Non-U.S. LOS Corp. (“R/C IV”). Subsequently, in conjunction with the Corporate Reorganization, R/C IV was contributed to the Company. At the time of the contribution, R/C IV had net operating loss carryforwards totaling $ 10.9 million for federal income tax purposes and $ 10.9 million for certain state income tax purposes, which became available for the Company’s use as a result of the contribution. As a result of the Company being in a net income position in 2018 and the expected utilization of deferred tax assets, the Company recognized a deferred tax asset of $ 2.6 million and a corresponding $ 2.3 million liability pursuant to the TRAs. Of the contributed net operating loss carryforwards, $ 6.4 million for federal income tax purposes and $ 6.4 million of certain state income tax purposes have been utilized. As a result, the Company has remaining $ 0.8 million of deferred tax asset and a corresponding $ 0.7 million liability pursuant to the TRAs. 
+At December 31, 2022, the Company’s liability under the TRAs was $ 118.9 million, all of which is presented as a component of long-term liabilities, and the related deferred tax assets totaled $ 99.9 million. Upon the release of the valuation allowance, the Company recorded a loss on remeasurement of the liabilities subject to the TRA of $ 76.2 million recorded as part of continuing operations in the current year. 
+During the year ended December 31, 2022, exchanges of Liberty LLC Units and shares of Class B Common Stock resulted in an increase of $ 5.1 million in amounts payable under the TRAs, and a net increase of $ 6.0 million in deferred tax assets, all of which were recorded through equity. The Company did not make any TRA payments for the year ended December 31, 2022. 
+During the year ended December 31, 2021, exchanges of Liberty LLC Units and shares of Class B Common Stock resulted in an increase of $ 58.5 million in amounts payable under the TRAs, and a net increase of $ 68.8 million in deferred tax assets, all of which were recorded through equity. The Company did not make any TRA payments for the year ended December 31, 2021. 
+F-30 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Note 13— Defined Contribution Plan 
+The Company sponsors a 401(k) defined contribution retirement plan covering eligible employees. The Company has historically made matching contribution at a rate of $ 1.00 for each $1.00 of employee contribution, subject to a cap of 6 % of the employee’s salary and federal limits. Contributions made by the Company were $ 25.8 million, $ 19.0 million, and $ 4.2 million for the years ended December 31, 2022, 2021 and 2020, respectively. 
+During 2020, in connection with other cost savings measures undertaken in response to declining demand for frac services as a result of the impacts of the COVID-19 pandemic, employer matching contributions were temporarily suspended from April 1, 2020 through December 31, 2020. Effective January 1, 2021 the Company restored its 6 % matching contribution. 
+Note 14— Related Party Transactions 
+Schlumberger Limited 
+As of December 31, 2022 Schlumberger owns 9,001,961 shares of Class A Common Stock of the Company, or approximately 5.0 % of the issued and outstanding shares of Common Stock. Under the Transaction Agreement, to the extent the net working capital, as defined in the Transaction Agreement, of the Transferred Business is less than $ 54.6 million, the difference shall be payable in cash to the Company. During the three months ended September 30, 2021, the Company agreed on a working capital settlement from Schlumberger of $ 15.8 million, most of which was netted against transaction services costs and cash settlements during the transition services period. In conjunction with closing the OneStim Acquisition, the Company entered into a transition services agreement with Schlumberger, under which Schlumberger provides certain administrative transition services until the Company fully integrates the acquired business. During the years ended December 31, 2022 and 2021, the Company incurred $ 0.0 million and $ 5.7 million of fees payable to Schlumberger such transaction services. The Company does not expect to incur any additional transition services related fees in future periods. 
+During the year ended December 31, 2022, the Company repurchased and retired 1,700,000 shares of Class A Common Stock for $ 27.8 million or $ 16.35 average price per share from Schlumberger, under the share repurchase program. 
+During 2021, a subsidiary of the Company and Schlumberger entered into a property swap agreement under which the Company exchanged with Schlumberger a property acquired in the OneStim Acquisition and $ 4.9 million in cash for a separate property that the Company will utilize with its existing operations. The Company did not recognize any gain or loss on the transaction. In separate transactions, the Company has sold equipment to Schlumberger including $ 0.1 million and $ 1.3 million during the years ended December 31, 2022 and 2021, respectively. The Company recognized a gain on the sale of equipment of $ 0.0 million and $ 0.9 million, respectively. 
+Following the OneStim Acquisition, in the normal course of business, the Company purchases chemicals, proppant and other equipment and maintenance parts from Schlumberger and its subsidiaries. During the year ended December 31, 2022 and 2021, total purchases from Schlumberger were approximately $ 21.7 million and $ 28.2 million, respectively. As of December 31, 2022 amounts due to Schlumberger were $ 2.6 million and $ 0.7 million included in accounts payable and accrued liabilities, respectively. As of December 31, 2021 amounts due to Schlumberger were $ 2.7 million and $ 1.1 million included in accounts payable and accrued liabilities, respectively, in the consolidated balance sheet. 
+Franklin Mountain Energy, LLC 
+Effective on June 15, 2021, Audrey Robertson was appointed to the board of directors of the Company. Ms. Robertson serves as the Chief Financial Officer of Franklin Mountain Energy, LLC (“Franklin Mountain”). During the year ended December 31, 2022 the Company performed hydraulic fracturing services for Franklin Mountain in the amount of $ 131.8 million or 3.2 % of the Company’s revenues for such period. During the year ended December 31, 2021 the Company performed hydraulic fracturing services for Franklin Mountain in the amount of $ 20.5 million or 0.8 % of the Company’s revenues for such period. Amounts included in unbilled revenue from Franklin Mountain as of December 31, 2022 and 2021, were $ 13.9 million and $ 0.0 million , respectively. Receivables from Franklin Mountain as of December 31, 2022 and 2021, were $ 0.0 million and $ 0.0 million , respectively. 
+Liberty Resources LLC 
+Liberty Resources LLC, an oil and gas exploration and production company, and its successor entity (collectively, the “Affiliate”) has certain common ownership and management with the Company. The amounts of the Company’s revenue related to hydraulic fracturing services provided to the Affiliate for the years ended December 31, 2022, 2021 and 2020, were $ 16.7 million, $ 2.8 million and $ 0.0 million , respectively. As of December 31, 2022 and 2021, there were $ 0.0 million and $ 0.0 million , respectively, outstanding receivables within the Company’s accounts receivable-trade and unbilled revenue line items attributable to the Affiliate. 
+F-31 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+On December 28, 2022 (the “Agreement Date”), the Company entered into an agreement with the Affiliate to amend payment terms for outstanding invoices due as of the Agreement Date to be due on April 1, 2024. Amounts outstanding from the Affiliate as of the Agreement Date were $ 11.8 million. Any receivable amount outstanding at the end of each month is subject to 12 % interest through March 31, 2023, 15 % from April 1, 2023 through September 30, 2023, and 18 % thereafter. 
+During the years ended December 31, 2022, 2021 and 2020, interest income from the Affiliate was $ 0.0 million , $ 0.0 million and $ 0.3 million, respectively. 
+PropX Acquisition 
+During 2016, Liberty Holdings entered into a future commitment to invest and become a non-controlling minority member in PropX, the provider of proppant logistics equipment. Effective October 26, 2021, the Company completed the purchase of all membership interest in PropX, refer to Note 3—Acquisitions for further discussion of the transaction. During the period from January 1, 2021 until October 26, 2021, the Company leased proppant logistics equipment from PropX for $ 7.3 million. During the year ended December 31, 2020 the Company leased proppant logistics equipment from PropX for $ 8.7 million. 
+R/C IV Liberty Big Box Holdings, L.P., a Riverstone Holdings LLC (“Riverstone”) fund and a former significant stockholder of the Company, held a greater than 10 % equity interest in PropX. Christopher Wright, the Chief Executive Officer, Michael Stock, the Chief Financial Officer and Ron Gusek, the President of the Company, held a less than 5 % equity interest in PropX through Big Box Proppant Investments LLC. Cary Steinbeck, a director of the Company, served on the PropX board of directors and held a less than 5 % indirect equity interest in PropX. In addition, Brett Staffieri, a Riverstone appointed director, served on the board of the directors of the Company until June 15, 2021 and on the PropX board of directors until the acquisition date. The PropX Acquisition was reviewed and approved by the disinterested members of the Board and pursuant to the Company’s related party transactions policy. 
+Secondary Offering by Selling Stockholder 
+On April 29, 2022, the Company, Liberty LLC, Schlumberger, and BofA Securities, Inc. and J.P. Morgan Securities LLC (together, the “Underwriters”), entered into an underwriting agreement, dated as of April 29, 2022, pursuant to which Schlumberger sold 14,500,000 shares of Class A Common Stock at a price of $ 15.50 per share to the Underwriters (the “Sale”). The Sale closed on May 3, 2022. Following the Sale, Schlumberger held 35,101,961 shares of Class A Common Stock. The Company did not receive any proceeds from the Sale. 
+Note 15— Commitments & Contingencies 
+Purchase Commitments (tons are not in thousands) 
+The Company enters into purchase and supply agreements to secure supply and pricing of proppants, chemicals, and equipment. As of December 31, 2022 and 2021, the agreements provide pricing and committed supply sources for the Company to purchase 2,915,172 and 89,317 tons, respectively, of proppant through December 31, 2024. Amounts above also include commitments to pay for transport fees on minimum amounts of proppants. Additionally, related proppant transload service commitments extend into 2023. 
+Future proppant, transload, and equipment commitments are as follows: 
+($ in thousands) 
+2023 $ 158,653 
+2024 44,772 
+2025 — 
+2026 — 
+2027 — 
+Thereafter — 
+$ 203,425 
+Certain supply agreements contain a clause whereby in the event that the Company fails to purchase minimum volumes, as defined in the agreement, during a specific time period, a shortfall fee may apply. In circumstances where the Company does not make the minimum purchase required under the contract, the Company and its suppliers have a history of amending such minimum purchase contractual terms and in rare cases does the Company incur shortfall fees. If the Company were unable to make any of the minimum purchases and the Company and its suppliers cannot come to an agreement to avoid such fees, the 
+F-32 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Company could incur shortfall fees in the amounts of $ 27.9 million and $ 6.9 million for the years ended 2023 and 2024, respectively. Based on forecasted levels of activity, the Company does not currently expect to incur significant shortfall fees. 
+Included in the commitments for the year ending December 31, 2022 are approximately $ 7.8 million of payments expected to be made in the first quarter of 2023 for the use of certain light duty trucks, heavy tractors and field equipment used to various degrees in frac and wireline operations. The Company is in negotiations with the third-party owner of such equipment to lease or purchase some or all of such aforementioned vehicles and equipment, subject to agreement on terms and conditions. No gain or loss is expected upon consummation of any such agreement. 
+Litigation 
+From time to time, the Company is subject to legal and administrative proceedings, settlements, investigations, claims and actions. The Company’s assessment of the likely outcome of litigation matters is based on its judgment of a number of factors including experience with similar matters, past history, precedents, relevant financial and other evidence and facts specific to the matter. Notwithstanding the uncertainty as to the final outcome, based upon the information currently available, management does not believe any matters in aggregate will have a material adverse effect on its financial position or results of operations. 
+Note 16— Subsequent Events 
+On January 23, 2023, the Company, Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, Liberty Oilfield Services LLC, other subsidiaries of the Company, Wells Fargo Bank, National Association, as administrative agent (the “Agent”), and other lenders entered into an Eighth Amendment to the ABL Facility (the “Eighth ABL Amendment”). 
+The Eighth ABL Amendment amends certain terms, provisions and covenants of the ABL Facility, including, among other things: (i) increasing the maximum revolver amount from $ 425.0 million to $ 525.0 million (the “Upsized Revolver”); (ii) increasing the amount of the accordion feature from $ 75.0 million to $ 100.0 million; (iii) extending the maturity date from October 22, 2026 to January 23, 2028; (iv) modifying the dollar amounts of various credit facility triggers and tests proportionally to the Upsized Revolver; (v) permitting repayment under the Term Loan Facility prior to February 10, 2023; and (vi) increasing certain indebtedness, intercompany advance, and investment baskets. The Eighth ABL Amendment also includes an agreement from the Wells Fargo Bank, National Association, as administrative agent, to release its second priority liens and security interests on all collateral that served as first priority collateral under the Term Loan Facility, with such release to occur within 120 days after January 23, 2023. 
+Also on January 23, 2023, the Company withdrew $ 106.7 million on the ABL Facility and used the proceeds to pay off the Term Loan Facility. The balance of the Term Loan Facility upon pay off was $ 104.7 million and included $ 0.9 million of accrued interest and a $ 1.1 million prepayment premium or 1 % of the principal. Additionally, there were $ 0.2 million in bank and legal fees included in the pay off. As such, the only outstanding debt facility after January 23, 3023 is the ABL Facility. Refer to “Our current and future indebtedness could adversely affect our financial condition” included in “Item 1A. Risk Factors” above for further details on the outstanding balance of the ABL Facility as of the filing date. 
+On January 24, 2023, the Company’s board of directors approved a quarterly dividend of $ 0.05 per share of Class A Common Stock to be paid on March 20, 2023 to holders of record as of March 6, 2023. 
+Additionally, on January 24, 2023, the Company’s board of directors authorized an increase of the share repurchase program that allows the Company to repurchase an additional $ 250.0 million for a total up to $ 500.0 million of the Company’s Class A Common Stock. 
+Effective January 31, 2023, Liberty LLC was merged into the Company, with the Company surviving the merger. In connection with the merger all outstanding shares of the Company’s Class B Common Stock were redeemed and exchanged for an equal number of shares of the Company’s Class A Common Stock. The Company did not make any distributions or receive any proceeds in connection with this exchange. The merger is not expected to have a significant impact on the Company’s consolidated financial statements. 
+No other significant subsequent events have occurred that would require recognition or disclosure in the consolidated financial statements and notes thereto. 
+F-33
\ No newline at end of file
diff --git a/raw/filings/0001694028/2022/0001694028-23-000010/filing_metadata.csv b/raw/filings/0001694028/2022/0001694028-23-000010/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..36edd518636bc5ef430d65fbcdb4ba37a7175ef2
--- /dev/null
+++ b/raw/filings/0001694028/2022/0001694028-23-000010/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0001694028,LBRT,Liberty Energy Inc.,10-K,2023-02-10,2022-12-31,2023-02-11T02:05:22.000Z,0001694028-23-000010,lbrt-20221231.htm,10-K,10863745,1,1,https://www.sec.gov/Archives/edgar/data/1694028/000169402823000010/lbrt-20221231.htm,https://www.sec.gov/Archives/edgar/data/1694028/000169402823000010/,2022,2022,1
diff --git a/raw/filings/0001694028/2022/0001694028-23-000010/item1.txt b/raw/filings/0001694028/2022/0001694028-23-000010/item1.txt
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index 0000000000000000000000000000000000000000..d5c4f1d7403da624802c873249b48052fbaf5730
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+++ b/raw/filings/0001694028/2022/0001694028-23-000010/item1.txt
@@ -0,0 +1,114 @@
+Item 1. Business 
+Our Company 
+We are a leading integrated energy services and technology company focused on providing innovative hydraulic services and related technologies to onshore oil and natural gas exploration and production (“E&P”) companies in North America. We offer customers hydraulic fracturing services, together with complementary services including wireline services, proppant delivery solutions, data analytics, related goods (including our sand mine operations), and technologies that will facilitate lower emission completions, thereby helping our customers reduce their emissions profile. 
+Our primary locations of operation include the Permian Basin, the Eagle Ford Shale, the Denver-Julesburg Basin (the “DJ Basin”), the Williston Basin, the San Juan Basin, the Powder River Basin, the Haynesville Shale, the South Central Oklahoma Oil Province and Sooner Trend Anadarko Canadian Kingfisher (collectively, the “SCOOP/STACK”), the Marcellus Shale, the Utica Shale, and the Western Canadian Sedimentary Basin, which are among the most active basins in North America. The breadth of our operational footprint provides us an opportunity to leverage our fixed costs and to efficiently reposition our equipment in response to customer requirements. The map below represents our current areas of operation. 
+The process of hydraulic fracturing involves pumping a pressurized stream of fracturing fluid (typically a mixture of water, chemicals and proppant) into a well casing or tubing to cause the underground formation to fracture or crack. These fractures release trapped hydrocarbon particles and provide a conductive channel for the oil or natural gas to flow freely to the wellbore for collection. The propping agent, or proppant, typically sand, becomes lodged in the cracks created by the hydraulic fracturing process, “propping” them open to facilitate the flow of hydrocarbons from the reservoir to the well. The fracturing 
+1 
+fluid is engineered to lose viscosity, or “break,” and is subsequently flowed back from the formation, leaving the proppant suspended in the formation fractures. Once our customer has flushed the fracturing fluids from the well using a controlled flow-back process, the customer manages fluid and water recycling or disposal. 
+Our hydraulic fracturing fleets consist of mobile hydraulic fracturing units and other auxiliary heavy equipment to perform fracturing services. Our hydraulic fracturing units consist primarily of high-pressure hydraulic pumps, engines, transmissions, radiators and other supporting equipment that are typically mounted on trailers. We refer to the group of units and other equipment, such as blenders, data vans, sand storage, tractors, manifolds and high-pressure fracturing iron, which are necessary to perform a typical hydraulic fracturing job, as a “fleet,” and the personnel assigned to each fleet as a “crew.” The size of each fleet and crew can vary depending on the requirements of each job design. 
+We also have wireline operations as a result of the acquisition of Schlumberger’s OneStim business in December 2020, whereby we obtained certain assets and liabilities of the OneStim business including OneStim’s hydraulic fracturing pressure pumping services business in onshore United States and Canada (the “OneStim Acquisition”). Our wireline units consist of a truck equipped with a spool of wireline that is lowered into wells to convey specialized tools or equipment, such as perforating guns and charges, which are necessary to connect the wellbore with the target formation. This operation is performed between each hydraulic fracturing stage. Our wireline service is primarily offered alongside our hydraulic fracturing services, which allows us to maximize efficiency for our customers through optimized coordination of the wireline and hydraulic fracturing services. In addition, we also offer our wireline service on a stand-alone basis. 
+As a result of the PropX Acquisition, which was completed in October 2021, we are now a leading provider of last-mile proppant delivery solutions, including proppant handling equipment and logistics software across North America. PropX offers innovative environmentally friendly technology with optimized dry and wet sand containers and wellsite proppant handling equipment that drive logistics efficiency and reduce noise and emissions. We believe that PropX wet sand handling technology is a key enabler of the next step of cost and emissions reductions in the proppant industry. PropX also offers customers the latest real-time logistics software, PropConnect™, for sale or as hosted software as a service. 
+Our operations are organized into a single business segment, which consists of hydraulic fracturing services, including wireline, proppant delivery and goods, including our Permian Basin sand mines, and we have one reportable geographical segment, North America. We have grown from one active hydraulic fracturing fleet as of December 2011 to over 40 active fleets as of December 31, 2022. We are focused on providing “next-generation” frac fleets and technologies to assist our customers with completing their wells in an environmental, social, and governance (“ESG”)-friendly manner. 
+Our founders and management are pioneers in the development of data-driven hydraulic fracturing technologies for application in shale plays. Prior to founding the Company, the majority of our management team founded and built Pinnacle Technologies, Inc. (“Pinnacle Technologies”) into a leading fracturing technology company. In 1992, Pinnacle Technologies developed the first commercial hydraulic fracture mapping technologies, analytical tools that played a major role in launching the shale revolution. Our extensive experience with fracture technologies and customized fracture design has enabled us to develop new technologies and processes that provide our customers with real-time solutions that significantly enhance their completions. These technologies include hydraulic fracture propagation models, reservoir engineering tools, large, proprietary shale production databases and multi-variable statistical analysis techniques. Taken together, these technologies have enabled us to be a leader in hydraulic fracture design innovation and application. Our management team has an average of over 20 years of energy services experience, and the majority of our management team worked together before founding our company. 
+We believe technical innovation and strong relationships with our customer and supplier bases distinguish us from our competitors and are the foundations of our business. We expect that E&P companies will continue to focus on technological innovation as completion complexity and fracture intensity of horizontal wells increases, particularly as customers are increasingly focused on reducing emissions from their completions operations. We remain proactive in developing innovative solutions to industry challenges, including developing: (i) our databases of U.S. unconventional wells to which we apply our proprietary multi-variable statistical analysis technologies to provide differential insight into fracture design optimization; (ii) our Liberty Quiet Fleet® design which significantly reduces noise levels compared to conventional hydraulic fracturing fleets; (iii) hydraulic fracturing fluid systems tailored to the specific reservoir properties in the basins in which we operate and (iv) our dual fuel dynamic gas blending fleets that allow our engines to run diesel or a combination of diesel and natural gas, to optimize fuel use, reduce emissions and lower costs; (v) the successful test of digiFrac™, our innovative, purpose-built electric frac pump that has approximately 25% lower CO2e emission profile than the Tier IV DGB; and (vi) our PropX wet sand handling technology which eliminates the need to dry sand, enabling the deployment of mobile mines nearer to wellsites. In addition, our integrated supply chain includes proppant, chemicals, equipment, logistics and integrated software which we believe promotes wellsite efficiency and leads to more pumping hours and higher productivity throughout the year to better service our customers. In order to achieve our technological objectives, we carefully manage our liquidity and debt position to promote operational flexibility and invest in the business throughout the full commodity cycle. 
+2 
+ESG Focused 
+While we recognize the various environmental and social impacts of hydrocarbon energy, we believe that access to life-enhancing modern energy presents the most pressing global energy challenge. We passionately work to better the process of bringing hydrocarbons to the surface in a clean, safe and efficient fashion and view ESG principles as foundational to our business. We focus on developing and adding technologies to our operations that assist our customers in implementing their ESG goals. The list below sets forth specific examples of our efforts towards ESG principles: 
+• In 2013, we introduced Tier 2 dual-fuel technology to our fleets which allows our frac pumps to use natural gas in place of some diesel fuel to lower particulate emissions. 
+• In 2014, we began the use of containerized sand delivery at frac locations, which reduces dust, noise and truck traffic. 
+• In 2016, we introduced Quiet Fleet® technology, which significantly reduces noise levels associated with frac operations. 
+• In 2018, we began a partnership with an equipment supplier to introduce Tier 4 dynamic gas blending, or DGB, engines to our frac fleet that can substitute up to 80% of the diesel typically used by a frac pump with natural gas and significantly lower emission levels in frac operations. Tier 4 DGB engines were added to our fleet in 2020. 
+• In 2021, we announced the successful test of digiFrac™, our innovative, purpose-built electric frac pump that has approximately a 25% lower CO2e emission profile than the Tier IV DGB. We have entered into two multi-year arrangements with customers for digiFrac fleets and commenced delivery of commercial pumps in the fourth quarter of 2022. 
+• In October 2021, we closed the acquisition of PropX. PropX offers innovative, environmentally friendly technology with optimized dry and wet sand containers and wellsite proppant handling equipment that drive logistics efficiency and reduce noise and emissions. 
+• In August 2022, we released our second annual Bettering Human Lives report, highlighting the importance of energy in the modern world and Liberty’s ESG 2021 data, which was updated to cover the critical link hydrocarbons play in geopolitics, food, and their role in enabling the modern world. 
+We are continuously committed to engagement in our communities. We provide K-12 scholarships to low-income children through ACE (Alliance for Choice in Education), and we have launched a Liberty Scholars program at Montana Technological University to enable lower-income students to obtain a college engineering education. In 2022, over 100 students received Liberty scholarships. We have numerous other efforts encompassing our three pillars of outreach: education, military services, and alleviating poverty. Since launching Liberty’s matching program in 2021, Love Liberty, we have supported an additional 25 organizations near and dear to our employee’s hearts across all districts. Every year we strive to create lasting relationships and impacts throughout all our communities with the mission to better human lives through the growth of individual liberty and opportunity. 
+Cyclical Nature of Industry 
+We operate in a highly cyclical industry. The key factor driving demand for our services is the level of drilling activity by E&P companies, which in turn depends largely on the current and anticipated economics of new well completions. Global supply and demand for oil and the domestic supply and demand for natural gas are critical in assessing industry outlook. Demand for oil and natural gas is cyclical and subject to large, rapid fluctuations. E&P companies tend to increase capital expenditures in response to increases in oil and natural gas prices, which generally results in greater revenues and profits for oilfield service companies such as ours. Increased capital expenditures also ultimately lead to greater production, which historically has resulted in increased supplies of hydrocarbons and reduced prices which in turn tend to drive a future reduction in E&P companies capital expenditures and reduce demand for energy services. For these reasons, the results of our operations may fluctuate from quarter to quarter and from year to year, and these fluctuations may distort comparisons of results across periods. 
+3 
+Seasonality 
+Our results of operations have historically reflected seasonal tendencies relating to holiday seasons, inclement weather and the conclusion of our customers’ annual drilling and completion capital expenditure budgets. Our most notable declines typically occur in the fourth quarter of the year for the reasons described above. Additionally, some of the areas in which we have operations, including Canada, the DJ Basin, Powder River Basin and Williston Basin, are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice, rain, or frost, and related road restrictions, we may be unable to move our equipment between locations, thereby reducing our ability to provide services and generate revenues. The exploration activities of our customers may also be affected during such periods of adverse weather conditions. Additionally, extended drought conditions in our operating regions could impact our ability or our customers’ ability to source sufficient water or increase the cost for such water. 
+Intellectual Property 
+Over the last several years and in connection with the acquisitions of OneStim and PropX, we have significantly invested in our research and technology capabilities. Our efforts to date have been focused on developing innovative, fit-for-purpose solutions designed to enhance our core service offerings, increase completion efficiencies, provide cost savings to our operations and add value for our customers. A cornerstone of our technological advantage is a series of proprietary databases of U.S. unconventional wells that include production data, completion designs and reservoir characteristics. We utilize these databases to perform multi-variable statistical analysis that generates differential insight into fracture design optimization to enhance our customers’ production economics. Our emphasis on data analytics is also deployed during job execution through the use of real-time feedback on variables that maximizes customer returns by improving cost-effective hydraulic fracturing operations. 
+Today, we hold approximately 500 patents and patent licenses relating to our engineering and technology solutions. We seek patent and trademark protections for our technology when we deem it prudent, and we aggressively pursue protection of these rights when warranted. We believe our patents, trademarks, and other protections for our proprietary technologies are adequate for the conduct of our business and that no single patent or trademark is critical to our business. In addition, we rely, to a great extent, on the technical expertise and know-how of our personnel to maintain our competitive position, and we take commercially reasonable measures to protect trade secrets and other confidential and/or proprietary information relating to the technologies we develop. 
+Human Capital Management 
+As of December 31, 2022, we had 4,580 employees and no unionized labor. We believe we have good relations with our employees and that one of our key competitive advantages is our people. Our highly trained, experienced and motivated employees are critical to delivering our hydraulic fracturing services. Taking care of our employees is one of our top priorities, and we continually invest in hiring, training and retaining the employees we believe to be the best in our field. We consistently assess the current business environment and labor market to refine our compensation and benefits programs in order to attract and retain top talent in our industry. We strive to promote from within our existing employee base to manage new hydraulic fracturing fleets and organically grow our operating expertise. This organic growth is essential in achieving the expertise and level of customer service we strive to provide each of our customers. As a result, we plan to continue to invest in our employees through both personal and professional training to attract and retain the best individuals in our areas of operation. Overall, we focus on individual contributions and team success to foster a culture built around operational excellence and superior safety. 
+Health and Safety 
+Our people are our most important asset and ensuring their safety and the safety of those around them is the most important thing we do. Making certain that the Liberty team is well trained to handle the complexities of daily field operations, and that their training and competency remains current with the latest technology and standards is a key component. In order to facilitate this training, we have developed the Liberty Frac Academy, a thorough program where employees are trained on various aspects of the Company, from safety in equipment operation to leadership skills. The Liberty Frac Academy not only ensures dissemination of high-quality training material, but also provides a forum for sharing best practices and lessons learned across the Company. As a result, we are among the safest service providers in the industry with a constant focus on Health, Safety and Environmental performance and service quality, as evidenced by an average incident rate that was 29% less than the industry average from 2020 to 2022. Our employee-centered focus and reputation for safety has enabled us to obtain projects from industry leaders with some of the most demanding safety and operational requirements. 
+4 
+Programs and Benefits 
+One way we have demonstrated a history of investing in our workforce is by offering competitive salaries and wages. To foster a strong sense of ownership, restricted stock units are provided to eligible employees under our long-term incentive plan. Furthermore, we offer innovative benefits to all eligible employees, including, among others, comprehensive health insurance coverage, parental leave to all new parents, for birth or adoption, financial support for child adoption, leave to care for partners with serious health conditions, 401(k) savings plan and educational tuition assistance for both bachelor’s degree and master’s degree programs. We are also passionate about community investment and, in 2019, we joined the Ban the Box initiative which provides work opportunities for formerly incarcerated individuals. 
+Governmental Regulation and Climate Change 
+As a company with operations in both the United States and Canada, we are subject to the laws of both jurisdictions in which we operate and the rules and regulations of various governing bodies, which may differ among those jurisdictions. Compliance with these laws, rules and regulations has not had, and is not expected to have, a material effect on our capital expenditures, results of operations and competitive position as compared to prior periods. We are also subject to numerous environmental and regulatory requirements related to our operations. For further information related to such regulation, see the risks described under the heading “Risk Factors” in this Annual Report. 
+Our operations are subject to numerous stringent and complex laws and regulations at the federal, state, and local levels governing the discharge of materials into the environment, environmental protection, and health and safety aspects of our operations. Failure to comply with these laws and regulations or to obtain or comply with permits may result in the assessment of administrative, civil, and criminal penalties, imposition of remedial or corrective action requirements, and the imposition of injunctions or other orders to prohibit certain activities, restrict certain operations, or force future compliance with environmental requirements. 
+There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons, other hazardous substances, and wastes, as a result of air emissions and wastewater discharges related to our operations, and because of historical operations and waste disposal practices. Spills or other releases of regulated substances, including such spills and releases that occur in the future, could expose us to material losses, expenditures, and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. The following is a summary of some of the existing laws, rules, and regulations to which we are subject. 
+U.S. Laws and Regulations 
+Hazardous Substances and Waste Handling 
+The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Under guidance issued by the U.S. Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. RCRA currently exempts many E&P wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes intrinsically associated with the exploration, development, or production of crude oil and natural gas. However, these E&P wastes may still be regulated under state solid waste laws and regulations, and it is possible that certain oil and natural gas E&P wastes now classified as non-hazardous could be classified as hazardous waste in the future. Stricter regulation of wastes generated during our or our customers’ operations could result in increased costs for our operations or the operations of our customers, which could in turn reduce demand for our services and adversely affect our business. We cannot guarantee that the EPA will not revisit the exemption of E&P waste or that waste will not become more heavily regulated at the federal or state level. 
+Comprehensive Environmental Response, Compensation, and Liability Act 
+The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owner or operator of the site where the release occurred and anyone who transported or disposed or arranged for the transport or disposal of a hazardous substance released at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA and any state analogs may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources and for the costs of certain health studies. We currently own, lease, or operate numerous properties that have been used for manufacturing and other operations for many years. These properties and the substances disposed or released on them may be 
+5 
+subject to CERCLA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. 
+Worker Health and Safety 
+We are subject to a number of federal and state laws and regulations, including the OSHA, establishing requirements to protect the health and safety of workers. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require maintenance of information about hazardous materials used or produced in operations and provision of this information to employees, state and local government authorities, and citizens. Specifically, OSHA has enacted a regulation regarding crystalline silica exposures, which included requirements that hydraulic fracturing operations implement dust controls to limit exposures to the substance. Additionally, the Federal Motor Carrier Safety Administration (the “FMCSA”) regulates and provides safety oversight of commercial motor vehicles, the EPA establishes requirements to protect human health and the environment, the federal Bureau of Alcohol, Tobacco, Firearms and Explosives establishes requirements for the safe use and storage of explosives, and the federal Nuclear Regulatory Commission establishes requirements for the protection against ionizing radiation. Substantial fines and penalties can be imposed, and orders or injunctions limiting or prohibiting certain operations may be issued, in connection with any failure to comply with these laws and regulations. 
+Water Discharges 
+The federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the U.S. The discharge of pollutants into regulated waters, including jurisdictional wetlands, is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. To the extent the agencies expanding the range of properties subject to the Clean Water Act’s jurisdiction, certain energy companies could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas, which in turn could reduce demand for our services. Furthermore, the process for obtaining permits has the potential to delay our operations and those of our customers. Spill prevention, control, and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture, or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of wastewater and storm water runoff from certain types of facilities. The Clean Water Act and analogous state laws provide for administrative, civil, and criminal penalties for unauthorized discharges and, together with the Oil Pollution Act of 1990, impose rigorous requirements for spill prevention and response planning, as well as substantial potential liability for the costs of removal, remediation, and damages in connection with any unauthorized discharges. 
+Air Emissions 
+The federal Clean Air Act (the “CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. These regulations change frequently. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements, or utilize specific equipment or technologies to control emissions of certain pollutants. In recent years, the CAA has been used to impose additional stringent requirements upon oil and gas production operations. While these rules may not be directly applicable to our business, they are applicable to the business of our customers. Promulgation of stricter permitting or emission control requirements could delay or impair our or our customers’ ability to obtain air emission permits, to develop new wells and to continue to operate existing wells, and result in fewer wells being drilled or redeveloped, causing a decrease in demand for our services. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties, as well as injunctive relief, for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. 
+Climate Change 
+The EPA has determined that emissions of greenhouse gases, including carbon dioxide and methane, present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. The EPA has established greenhouse gas emissions reporting requirements for sources in the oil and gas sector and has also promulgated rules requiring certain large stationary sources of greenhouse gases to obtain preconstruction permits under the CAA and follow “best available control technology” requirements. Although we are not likely to become subject to greenhouse gas emissions permitting and best available control technology requirements because none of our facilities are presently major sources of greenhouse gas emissions, such requirements could become applicable to our customers. In addition, the EPA has used the CAA to impose additional greenhouse gas emissions control 
+6 
+requirements upon our customers. The recently passed Inflation Reduction Act (“IRA 2022”) imposes a methane emissions charge on certain emissions from specific classes of sources that are required to report their greenhouse gas emissions. The fee will start in calendar year 2024. This fee as well as additional requirements on greenhouse gas emissions from our customers could have an adverse effect on their costs of operations or financial performance, thereby adversely affecting our business, financial condition, and results of operations. Also, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, and many states have already established regional greenhouse gas “cap-and-trade” programs. The adoption of any legislation or regulation that restricts emissions of greenhouse gases from the equipment and operations of our customers or with respect to the oil and natural gas they produce could adversely affect demand for our products and services. 
+Hydraulic Fracturing 
+Our business is clearly dependent on hydraulic fracturing and horizontal drilling activities. As further described herein, hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shale. The process, which involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. Specifically, there is considerable uncertainty surrounding regulation of the emissions of methane, which may be released during hydraulic fracturing, chemicals used in the hydraulic fracturing process, the discharge of wastewater from hydraulic fracturing operations and concerns about the triggering of seismic activity by the injection of produced waters into underground wells. Certain proposed regulation could make it significantly more difficult and/or costly to drill and operate oil and gas wells. If adopted, such regulation could result in a decline in the completion of new oil and gas wells or the recompletion of existing wells, which could negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the demand for our services. Given the long-term trend towards increasing regulation, future regulation in the industry remains a possibility. 
+Some states, counties, and municipalities have enacted or are considering moratoria on hydraulic fracturing. For example, New York, Vermont, Maryland, and Washington have banned, or are in the process of banning, the use of high-volume hydraulic fracturing. Alternatively, some municipalities are, or have considered, zoning and other ordinances, the conditions of which could impose a de facto ban on drilling and/or hydraulic fracturing operations. Further, some states, counties, and municipalities are closely examining water use issues, such as permit and disposal options for processed water, which could have a material adverse impact on our financial condition, prospects, and results of operations if such additional permitting requirements are imposed upon our industry. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could reduce demand for our business by making it more difficult or costly for certain customers to perform fracturing to stimulate production from tight formations. 
+National Environmental Policy Act 
+Businesses and operations of our customers that are carried out on federal lands may be subject to the National Environmental Policy Act (“NEPA”), which requires federal agencies, including the U.S. Department of the Interior, to evaluate major agency actions having the potential to significantly impact the human environment. In the course of such evaluations, an agency will evaluate the potential direct, indirect, and cumulative impacts of a proposed project and, if necessary, will prepare a detailed Environmental Impact Statement that must be made available for public review and comment. To the extent that our customers’ current activities, as well as proposed plans, on federal lands require governmental permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects which in turn could reduce demand for our services. 
+Endangered Species Act and Migratory Bird Treaty Act 
+The federal Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or its habitat. The U.S. Fish and Wildlife Service (the “FWS”) must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development and development of sand mines used for hydraulic fracturing. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”), which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit. This prohibition covers most bird species in the U.S. Future implementation of the rules implementing the ESA and the MBTA are uncertain. If we or our customers were to have areas within our respective operations designated as critical or suitable habitat for a protected species, it could decrease demand for our services and have a material adverse effect on our business. 
+7 
+Canadian Laws and Regulations 
+Companies such as us offering energy services that include hydraulic fracturing, engineering, and wireline services in the Province of Alberta in Canada are regulated by both the provincial government of Alberta (“Province”) and the federal government of Canada (“Canada”). This includes, but is not limited to, regulation related to environmental protection legislation, climate change legislation, fracking legislation, and legislation related to wildlife. In addition to being regulated by the Province and Canada, energy services companies may also be subject to other international, national, and subnational laws, regulations, and policies. 
+Provincial Legislation 
+Energy services companies are primarily regulated by provincial governments in Canada. For example, in Alberta, provincial legislation potentially applicable to our Canadian operations includes the Environmental Protection and Enhancement Act, RSA 2000, e E-12. This Act promotes the protection, enhancement and wise use of the environment, and deals with matters such as air emissions, water discharges, and the handling of hazardous substances and waste control (for example, under the Waste Control Regulation, Alta Reg 192/1996). 
+Other potentially applicable provincial legislation in Alberta includes legislation directed at the transportation of dangerous goods, including oil (the Dangerous Goods Transportation and Handling Act, RSA 2000, c D-4 and associated regulations), legislation intended to provide for the responsible management of oil wells and associated sites (the Oil and Gas Conservation Act, RSA 2000, c O-6), legislation establishing regulatory bodies overseeing oil and gas and electricity in Alberta (the Responsible Energy Development Act, SA 2012, c R-17.3 and the Alberta Utilities Commission Act, SA 2007, c A-37.2), legislation governing the removal of gas or propane from Alberta (the Gas Resources Preservation Act, RSA 2000, c G-4), legislation to effect conservation and prevent waste of the oil sands resource in Alberta (the Oil Sands Conservation Act, RSA 2000, c O-7) and legislation governing worker safety (the Occupational Health and Safety Act, SA 2017, c O-2.1). 
+The Alberta Energy Regulator has a number of directives that are applicable to energy services companies, such as Directive 050 which addresses salinity ranges for soils that can receive drilling wastes, and Directive 058, which sets out regulatory requirements for the handling, treatment, and disposal of upstream oilfield waste. Other provinces in Canada have their own statutory regime applicable to oilfield service companies. 
+Federal Legislation 
+The Federal government in Canada shares certain jurisdiction with the provinces over certain environmental matters. Federal legislation potentially applicable to our Canadian operations includes legislation focused on regulating greenhouse gases (the Greenhouse Gas Pollution Pricing Act, SC 2018, c 12, s 186), legislation aimed at protecting wildlife (the Species at Risk Act, SC 2002, c 29), legislation governing approvals for projects (the Impact Assessment Act, SC 2019, c 28, s 1), and legislation governing the transportation of potentially dangerous substances (the Transportation of Dangerous Goods Act, 1992, SC 1992, c 34). 
+8 
+Properties 
+Properties 
+Our corporate headquarters are located at 950 17 th Street, Suite 2400, Denver, Colorado 80202. We lease our general office space at our corporate headquarters. The lease expires in December 2027. We currently own or lease the following additional principal properties: 
+District Facility Location Size Leased or Owned 
+Midland, TX 160,000 sq. ft on 147 acres Owned 
+Odessa, TX 77,500 sq. ft on 47 acres Owned 
+Cibolo, TX 90,000 sq. ft on 34 acres Owned 
+Kermit, TX 5,000 acres Owned 
+Monahans, TX 3,200 acres Owned 
+Magnolia, TX 63,350 sq. ft. Leased (through May 31, 2031) 
+Gainesville, TX 170,000 sq. ft. Leased (through August 31, 2023) 
+Shreveport, LA 225,000 sq ft. on 50 acres Owned 
+Cheyenne, WY 115,000 sq. ft on 60 acres Owned 
+Gillette, WY 32,757 sq. ft on 15 acres Leased (through December 31, 2034) 
+Henderson, CO 50,000 sq. ft on 13 acres Leased (through December 31, 2034) 
+Henderson, CO 96,582 sq. ft on 12 acres Owned 
+Williston, ND 30,000 sq. ft on 15 acres Owned 
+Farmington, NM 34,000 sq. ft on 30 acres Owned 
+El Reno, OK 80,000 sq. ft on 33 acres Owned 
+Red Deer, AB 170,000 sq. ft on 42 acres Owned 
+Grand Prairie, AB 135,000 sq. ft on 40 acres Owned 
+Huallen, AB 80 acres Owned 
+We also lease several smaller facilities, which leases generally have terms of one to six years. We believe that our existing facilities are adequate for our operations and their locations allow us to efficiently serve our customers. We do not believe that any single facility is material to our operations and, if necessary, we could readily obtain a replacement facility. 
+Marketing and Customers 
+We have developed long-term partnerships with our customers through a continuous dialogue focused on their production economics. Further, we have a proven track record of executing our customers’ plans and delivering on time and in line with expected costs. Our customer base includes a broad range of integrated and independent E&P companies, including some of the largest E&P companies in our areas of operation such as Occidental Petroleum Corp, ConocoPhillips Company, BP p.l.c., and ExxonMobil. Our technological innovations, customer-tailored approach and track record of consistently providing high-quality, safe and reliable service has allowed us to develop long-term customer partnerships, which we believe makes us the service provider of choice for many of our customers. 
+Our sales and marketing activities typically are performed through our local sales representatives in each geographic region and are supported by our corporate headquarters. For the years ended December 31, 2022, 2021 and 2020, our top five customers collectively accounted for approximatel y 30% , 27%, and 48% of our revenues, respectively. For the years ended December 31, 2022 and 2021, no customer accounted for more than 10% of our revenues. For the year ended December 31, 2020, PDC Energy Inc., WPX Energy, Conoco-Phillips Company, and Parsley Energy Operations, LLC each accounted for more than 10% of our revenues. 
+Suppliers and Raw Materials 
+We have a dedicated supply chain team that manages sourcing and logistics to ensure flexibility and continuity of supply in a cost-effective manner across our areas of operation. We have built long-term relationships with multiple industry leading suppliers of proppant, chemicals and hydraulic fracturing equipment and have started to internally design and assemble key pump and maintenance parts. In addition, we have built a strong relationship with the assemblers of our custom-designed hydraulic fracturing fleets and believe we will continue to have timely access to new, high capability fleets as we continue to grow. In 2018, we vertically integrated a supplier of certain major components through the acquisition of ST9 Gas and Oil LLC. In October 2021, we vertically integrated a supplier of our containerized sand and last mile proppant logistics solutions with the acquisition of PropX. 
+9 
+We purchase a wide variety of raw materials, parts and components that are manufactured and supplied for our operations. We are not dependent on any single source of supply for those parts, supplies or materials. To date, we have generally been able to obtain the equipment, parts and supplies necessary to support our operations, although we have experienced delivery delays and shortages on some items. While we believe that we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers, we may not always be able to do so. In addition, certain materials for which we do not currently have long-term supply agreements could experience shortages and significant price increases in the future. As a result, we may be unable to mitigate any future supply shortages and our results of operations, prospects and financial condition could be adversely affected. The OneStim Acquisition included two state-of-the-art sand mines in the Permian Basin, which helps alleviate the risk of proppant supply shortages. 
+Competition 
+The markets in which we operate are highly competitive. We provide services in various geographic regions across the United States and Canada, and our competitors include many large and small oilfield service providers, including some of the largest integrated service companies. Our hydraulic fracturing services compete with large, integrated companies such as Halliburton Company as well as other companies including Calfrac Well Services Ltd., ProFrac Holding Corp., NexTier Oilfield Solutions Inc., Universal Pressure Pumping, Inc., ProPetro Services, Inc., RPC, Inc., and STEP Energy Services. In addition, we compete regionally with smaller service providers. 
+We believe that the principal competitive factors in the markets we serve are technical expertise, equipment capacity, work force competency, efficiency, safety record, reputation, experience and price. Additionally, projects are often awarded on a bid basis, which tends to create a highly competitive environment. We seek to differentiate ourselves from our competitors by delivering the highest-quality services and equipment possible, coupled with superior execution and operating efficiency in a safe working environment. 
+Available Information 
+We file or furnish annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The SEC also maintains an internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC. 
+We also make available free of charge through our website, www.libertyfrac.com, electronic copies of certain documents that we file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. 
+10
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diff --git a/raw/filings/0001694028/2022/0001694028-23-000010/item13.txt b/raw/filings/0001694028/2022/0001694028-23-000010/item13.txt
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--- /dev/null
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@@ -0,0 +1,2 @@
+Item 13. Certain Relationships and Related Transactions, and Director Independence 
+The information required by this item concerning certain relationships and related person transactions and director independence is incorporated herein by reference to our definitive proxy statement for our 2023 annual meeting of stockholders, which will be filed with the SEC no later than 120 days after December 31, 2022, under the captions “Certain Relationships and Related Party Transactions” and “the Board and its Committees.”
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diff --git a/raw/filings/0001694028/2022/0001694028-23-000010/item9a.txt b/raw/filings/0001694028/2022/0001694028-23-000010/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..a4e4db0302c192c59cdc3ac5612661f39ca72af1
--- /dev/null
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@@ -0,0 +1,5 @@
+Item 9A. Controls and Procedures 
+Evaluation of Disclosure Controls and Procedures’ 
+In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2022 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures. 
+There were no changes to our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+See page F-1 for Management’s Report on Internal Control Over Financial Reporting and page F-4 for Report of Independent Registered Public Accounting Firm on its assessment of our internal control over financial reporting.
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diff --git a/raw/filings/0001694028/2022/0001694028-23-000010/rp_note.txt b/raw/filings/0001694028/2022/0001694028-23-000010/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..f97c47445ea24a2bd3f7bb1503771e8d233a15c6
--- /dev/null
+++ b/raw/filings/0001694028/2022/0001694028-23-000010/rp_note.txt
@@ -0,0 +1,20 @@
+Note 14— Related Party Transactions 
+Schlumberger Limited 
+As of December 31, 2022 Schlumberger owns 9,001,961 shares of Class A Common Stock of the Company, or approximately 5.0 % of the issued and outstanding shares of Common Stock. Under the Transaction Agreement, to the extent the net working capital, as defined in the Transaction Agreement, of the Transferred Business is less than $ 54.6 million, the difference shall be payable in cash to the Company. During the three months ended September 30, 2021, the Company agreed on a working capital settlement from Schlumberger of $ 15.8 million, most of which was netted against transaction services costs and cash settlements during the transition services period. In conjunction with closing the OneStim Acquisition, the Company entered into a transition services agreement with Schlumberger, under which Schlumberger provides certain administrative transition services until the Company fully integrates the acquired business. During the years ended December 31, 2022 and 2021, the Company incurred $ 0.0 million and $ 5.7 million of fees payable to Schlumberger such transaction services. The Company does not expect to incur any additional transition services related fees in future periods. 
+During the year ended December 31, 2022, the Company repurchased and retired 1,700,000 shares of Class A Common Stock for $ 27.8 million or $ 16.35 average price per share from Schlumberger, under the share repurchase program. 
+During 2021, a subsidiary of the Company and Schlumberger entered into a property swap agreement under which the Company exchanged with Schlumberger a property acquired in the OneStim Acquisition and $ 4.9 million in cash for a separate property that the Company will utilize with its existing operations. The Company did not recognize any gain or loss on the transaction. In separate transactions, the Company has sold equipment to Schlumberger including $ 0.1 million and $ 1.3 million during the years ended December 31, 2022 and 2021, respectively. The Company recognized a gain on the sale of equipment of $ 0.0 million and $ 0.9 million, respectively. 
+Following the OneStim Acquisition, in the normal course of business, the Company purchases chemicals, proppant and other equipment and maintenance parts from Schlumberger and its subsidiaries. During the year ended December 31, 2022 and 2021, total purchases from Schlumberger were approximately $ 21.7 million and $ 28.2 million, respectively. As of December 31, 2022 amounts due to Schlumberger were $ 2.6 million and $ 0.7 million included in accounts payable and accrued liabilities, respectively. As of December 31, 2021 amounts due to Schlumberger were $ 2.7 million and $ 1.1 million included in accounts payable and accrued liabilities, respectively, in the consolidated balance sheet. 
+Franklin Mountain Energy, LLC 
+Effective on June 15, 2021, Audrey Robertson was appointed to the board of directors of the Company. Ms. Robertson serves as the Chief Financial Officer of Franklin Mountain Energy, LLC (“Franklin Mountain”). During the year ended December 31, 2022 the Company performed hydraulic fracturing services for Franklin Mountain in the amount of $ 131.8 million or 3.2 % of the Company’s revenues for such period. During the year ended December 31, 2021 the Company performed hydraulic fracturing services for Franklin Mountain in the amount of $ 20.5 million or 0.8 % of the Company’s revenues for such period. Amounts included in unbilled revenue from Franklin Mountain as of December 31, 2022 and 2021, were $ 13.9 million and $ 0.0 million , respectively. Receivables from Franklin Mountain as of December 31, 2022 and 2021, were $ 0.0 million and $ 0.0 million , respectively. 
+Liberty Resources LLC 
+Liberty Resources LLC, an oil and gas exploration and production company, and its successor entity (collectively, the “Affiliate”) has certain common ownership and management with the Company. The amounts of the Company’s revenue related to hydraulic fracturing services provided to the Affiliate for the years ended December 31, 2022, 2021 and 2020, were $ 16.7 million, $ 2.8 million and $ 0.0 million , respectively. As of December 31, 2022 and 2021, there were $ 0.0 million and $ 0.0 million , respectively, outstanding receivables within the Company’s accounts receivable-trade and unbilled revenue line items attributable to the Affiliate. 
+F-31 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+On December 28, 2022 (the “Agreement Date”), the Company entered into an agreement with the Affiliate to amend payment terms for outstanding invoices due as of the Agreement Date to be due on April 1, 2024. Amounts outstanding from the Affiliate as of the Agreement Date were $ 11.8 million. Any receivable amount outstanding at the end of each month is subject to 12 % interest through March 31, 2023, 15 % from April 1, 2023 through September 30, 2023, and 18 % thereafter. 
+During the years ended December 31, 2022, 2021 and 2020, interest income from the Affiliate was $ 0.0 million , $ 0.0 million and $ 0.3 million, respectively. 
+PropX Acquisition 
+During 2016, Liberty Holdings entered into a future commitment to invest and become a non-controlling minority member in PropX, the provider of proppant logistics equipment. Effective October 26, 2021, the Company completed the purchase of all membership interest in PropX, refer to Note 3—Acquisitions for further discussion of the transaction. During the period from January 1, 2021 until October 26, 2021, the Company leased proppant logistics equipment from PropX for $ 7.3 million. During the year ended December 31, 2020 the Company leased proppant logistics equipment from PropX for $ 8.7 million. 
+R/C IV Liberty Big Box Holdings, L.P., a Riverstone Holdings LLC (“Riverstone”) fund and a former significant stockholder of the Company, held a greater than 10 % equity interest in PropX. Christopher Wright, the Chief Executive Officer, Michael Stock, the Chief Financial Officer and Ron Gusek, the President of the Company, held a less than 5 % equity interest in PropX through Big Box Proppant Investments LLC. Cary Steinbeck, a director of the Company, served on the PropX board of directors and held a less than 5 % indirect equity interest in PropX. In addition, Brett Staffieri, a Riverstone appointed director, served on the board of the directors of the Company until June 15, 2021 and on the PropX board of directors until the acquisition date. The PropX Acquisition was reviewed and approved by the disinterested members of the Board and pursuant to the Company’s related party transactions policy. 
+Secondary Offering by Selling Stockholder 
+On April 29, 2022, the Company, Liberty LLC, Schlumberger, and BofA Securities, Inc. and J.P. Morgan Securities LLC (together, the “Underwriters”), entered into an underwriting agreement, dated as of April 29, 2022, pursuant to which Schlumberger sold 14,500,000 shares of Class A Common Stock at a price of $ 15.50 per share to the Underwriters (the “Sale”). The Sale closed on May 3, 2022. Following the Sale, Schlumberger held 35,101,961 shares of Class A Common Stock. The Company did not receive any proceeds from the Sale.
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diff --git a/raw/filings/0001694028/2022/0001694028-23-000010/rpt_disclosure.txt b/raw/filings/0001694028/2022/0001694028-23-000010/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..ca489b60adf4680ce29630321d71891c27b91fcd
--- /dev/null
+++ b/raw/filings/0001694028/2022/0001694028-23-000010/rpt_disclosure.txt
@@ -0,0 +1,69 @@
+CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS 
+Policies and Procedures for Review of Related Party Transactions 
+A “ Related Party Transaction ” is a transaction, arrangement or relationship in which the Company or any of its subsidiaries was, is or will be a participant, the amount of which involved exceeds $120,000, and in which any related person had, has or will have a direct or indirect material interest. A “ Related Person ” is: 
+♦ any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors; 
+♦ any person who is known by us to be the beneficial owner of more than 5% of our Class A Common Stock; 
+♦ any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, executive officer or a beneficial owner of more than 5% of our Class A Common Stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5% of our Class A Common Stock; and 
+♦ any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10.0% or greater beneficial ownership interest. 
+Our Board has adopted a written related party transactions policy. Pursuant to this policy, our Audit Committee reviews all material facts of all Related Party Transactions and either approves or disapproves entry into the Related Party Transaction, subject to certain limited exceptions. The determination of the Audit Committee is documented in the Audit Committee’s minutes. In determining whether to approve or disapprove entry into a Related Party Transaction, our Audit Committee takes into account, among other factors, the following: (i) whether the Related Party Transaction is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances and (ii) the extent of the Related Person’s interest in the transaction. Furthermore, the policy requires that all Related Party Transactions required to be disclosed in our filings with the SEC be so disclosed in accordance with applicable laws, rules and regulations. 
+Related Party Transactions 
+The following is a description of transactions entered into, or in effect, after January 1, 2022 to which we have been a party, in which the amount involved in the transaction exceeds $120,000, and in which any of our directors, executive officers or beneficial owners of more than 5% of our voting securities, or affiliates or immediate family members of any of our directors, executive officers or beneficial owners of more than 5% of our voting securities, had or will have a direct or indirect material interest. We believe the terms obtained or consideration that we paid or received, as applicable, in connection with the transactions described below were comparable to terms available or the amounts that would be paid or received, as applicable, from un related third parties. 
+Liberty LLC Agreement 
+We entered into the Second Amended and Restated Limited Liability Company Agreement of Liberty Oilfield Services New HoldCo LLC (“ Liberty LLC ”) (the “ Liberty LLC Agreement ”) in connection with the closing of our IPO, which provides for limitations on the ability of holders of units of Liberty LLC (the “ Liberty LLC Units, ” and the holders of Liberty LLC Units “ Liberty Unit Holders ”) to transfer their Liberty LLC Units and provides the Company, as managing member of Liberty LLC, with the right to impose restrictions (in addition to those already in place) on the ability of Liberty Unit Holders to redeem their Liberty LLC Units pursuant to the Redemption Right (as defined below) to the extent the Company believes it is necessary to ensure that Liberty LLC will continue to be treated as a partnership for U.S. federal income tax purposes. 
+Effective January 31, 2023, the Liberty LLC Merger occurred, with the Company being the surviving entity of the Liberty LLC Merger. In connection with Liberty LLC Merger, all outstanding shares of our Class B Common Stock were redeemed and exchanged for an equal number of shares of our Class A Common Stock. Also effective January 31, 2023, as a result of the Liberty LLC Merger, the Liberty LLC Agreement terminated. 
+Redemption Rights 
+Under the Liberty LLC Agreement, each Liberty Unit Holder had, subject to certain limitations, the right (the “ Redemption Right ”) to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units for, at Liberty LLC’s election, (i) shares of our Class A Common Stock at a redemption ratio of one share of Class A Common Stock for each Liberty LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions or (ii) an equivalent amount of cash. Alternatively, upon the exercise of the Redemption Right, the Company (instead of Liberty LLC) had the right (the “ Call Right ”) to, 
+44 
+for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder for, at the Company’s election, (x) one share of Class A Common Stock or (y) an equivalent amount of cash. In addition, upon a change of control of the Company, the Company had the right to require each holder of Liberty LLC Units (other than the Company) to exercise its Redemption Right with respect to some or all of such unit holder’s Liberty LLC Units. In connection with any redemption of Liberty LLC Units pursuant to the Redemption Right or the Call Right, the corresponding number of shares of Class B Common Stock would be cancelled. 
+As of January 31, 2023, and, as a result of the Liberty LLC Merger, all outstanding Redemption Rights for Liberty LLC Units had been exercised, and no further redemption of Liberty LLC Units will occur in the future. 
+Distributions and Allocations 
+Under the Liberty LLC Agreement, the Company had the right to determine when distributions will be made to the holders of Liberty LLC Units and the amount of any such distributions. If the Company authorized a distribution, such distribution would be made to the holders of Liberty LLC Units generally on a pro rata basis in accordance with their respective percentage ownership of Liberty LLC Units. 
+Liberty LLC allocated its net income or net loss for each year to the holders of Liberty LLC Units pursuant to the terms of the Liberty LLC Agreement, and the holders of Liberty LLC Units, including the Company, generally incurred U.S. federal, state and local income taxes on their share of any taxable income of Liberty LLC. Net income and losses of Liberty LLC generally were allocated to the holders of Liberty LLC Units on a pro rata basis in accordance with their respective percentage ownership of Liberty LLC Units, subject to requirements under U.S. federal income tax law that certain items of income, gain, loss or deduction be allocated disproportionately in certain circumstances. To the extent Liberty LLC had available cash and subject to the terms of any debt instruments, the Company intended to cause Liberty LLC to make (i) generally pro rata distributions to the holders of Liberty LLC Units, including the Company, in an amount sufficient to allow the Company to pay its taxes and to allow it to make payments under the Tax Receivable Agreements (as defined below), (ii) tax advances, which will be repaid upon exercise of the Redemption Right or the Call Right, as applicable, in an amount sufficient to allow each of the Liberty Unit Holders to pay its respective taxes on such holder’s allocable share of Liberty LLC’s taxable income after taking into account certain other distributions or payments received by the Liberty Unit Holders from Liberty LLC or the Company, and (iii) non-pro rata payments to the Company to reimburse it for its corporate and other overhead expenses. 
+Issuance of Equity 
+The Liberty LLC Agreement generally provided that at any time the Company issues a share of its Class A Common Stock or any other equity security, the net proceeds received by the Company with respect to such issuance, if any, shall be concurrently invested in Liberty LLC, and Liberty LLC shall issue to the Company one Liberty LLC Unit or other economically equivalent equity interest. Conversely, if at any time, any shares of Class A Common Stock were redeemed, repurchased or otherwise acquired, Liberty LLC would redeem, repurchase or otherwise acquire an equal number of Liberty LLC Units held by the Company, upon the same terms and for the same price, as the shares of the Class A Common Stock are redeemed, repurchased or otherwise acquired. 
+Schlumberger 
+Master Transaction Agreement 
+On August 31, 2020, the Company, entered into a Master Transaction Agreement (the “ MTA ”) with SLB, Schlumberger Canada Limited, (“ SLB Canada ” and, together with SLB, the “ SLB Parties ”), Liberty LLC, and LOS Canada Operations Inc. (“ Canadian Buyer ”), pursuant to which the Liberty LLC and Canadian Buyer acquired the SLB Parties’ OneStim business (the “OneStim Acquisition”) in exchange for 57,377,232 shares of Class A Common Stock and a non-interest bearing demand promissory note, which note was satisfied with 8,948,902 shares of Class A Common Stock, resulting in a total of 66,326,134 shares of Class A Common Stock being issued in connection with the transaction. The SLB Parties are affiliated with Messrs. Ayat and McDonald, who are on our Board. The transactions contemplated by the MTA closed on December 31, 2020. 
+Until December 31, 2024, subject to certain exceptions and as more specifically set forth in the MTA, without the prior written consent of the Company, each of SLB and SLB Canada will not, and will cause each of their respective affiliates (including Schlumberger Limited) not to, directly or indirectly engage in any business or enterprise that is competitive with OneStim within onshore United States and Canada. 
+On December 31, 2020, in connection with the closing of the transactions contemplated by the MTA, the Company (and/or one or more of its subsidiaries) and the SLB Parties entered into the following agreements, each of which may involve amounts in excess of $120,000: (i) an intellectual property license agreement, whereby the SLB Parties granted to Liberty LLC and the Company exclusive and non-exclusive licenses to certain intellectual property, and Liberty LLC granted to the SLB Parties a non-exclusive license to 
+45 
+certain patents acquired by Liberty LLC under the MTA; (ii) an employee matters agreement, pursuant to which the applicable SLB Party agreed to lease employees to the Company or a subsidiary of the Company until March 1, 2021, subject to certain exceptions and extensions; (iii) an alliance agreement whereby SLB and Liberty LLC agreed to collaborate to advance each of their product portfolios and technology offerings; (iv) a transition services agreement whereby SLB or its design ee agreed to provide certain back-office, administrative, field operations, supply chain and other specified services to the Company until March 1, 2021, subject to certain exceptions and extensions; and (v) a strategic supply agreement intended to provide the Company with an opportunity to purchase from the various business lines of SLB, products and services with competitive pricing terms for a term not to exceed the term of the non-compete covenant in the MTA discussed above. 
+Amended and Restated Stockholders Agreement 
+In connection with the OneStim Acquisition, we entered into an amended and restated stockholders agreement with affiliates of Riverstone, and the SLB Parties. Among other things, the amended and restated stockholders agreement provides the right to designate nominees to our Board as follows: 
+• so long as the SLB Parties and its affiliates collectively beneficially own at least 20% of the outstanding shares of our Common Stock, the SLB Parties can designate up to two (2) nominees to our Board; and 
+• so long as the SLB Parties and their affiliates collectively beneficially own at least 10% of the outstanding shares of our Common Stock, the SLB Parties can designate up to one (1) nominee to our Board. 
+As of December 31, 2022, neither Riverstone nor the SLB Parties had the right to designate any nominees to our Board, however, such previously designated nominees will remain on the Board until their term is complete or, pursuant to the stockholders agreement, until the Nominating and Governance Committee requests that such director designated by the Riverstone or SLB Parties resign. 
+Pursuant to the amended and restated stockholders agreement, the SLB Parties will not, for a period of four years from the closing of the OneStim Acquisition, make any transfer of Common Stock to any direct competitor of the Company or to any person that is subject to, or by virtue of such transfer would become subject to, the reporting obligations under Schedule 13D under the Exchange Act, with respect to Common Stock (the “ Lock-Up and Transfer Restrictions ”). 
+Pursuant to the amended and restated stockholders agreement, the SLB Parties and their affiliates are subject to customary standstill restrictions in accordance with which such parties will agree not to, among other things, acquire beneficial ownership of any equity securities of the Company or publicly seek or encourage any offer or proposal for a merger or similar transaction involving the Company during the period commencing on the date of the agreement and continuing until the fourth anniversary of the closing of the OneStim Acquisition (the “ Standstill ”). 
+Pursuant to the amended and restated stockholders agreement, we will be required to take all necessary actions, to the fullest extent permitted by applicable law (including with respect to any fiduciary duties under Delaware law), to cause the election of the nominees designated by either the Riverstone affiliates or the SLB Parties. At any time the members of our Board are allocated among separate classes of directors, (i) the directors designated by the Riverstone affiliates pursuant to the amended and restated stockholders agreement will be to the classes as mutually agreed between us and the Riverstone affiliates, and (ii) the directors designated by the SLB Parties pursuant to the amended and restated stockholders agreement will be to the classes as mutually agreed between us and the SLB Parties. The Riverstone affiliates will be entitled to designate the replacement for any of its Board designees whose service terminates prior to the end of such director’s term. The SLB Parties will be entitled to designate the replacement for any of its Board designees whose service terminates prior to the end of such director’s term. 
+The amended and restated stockholders agreement will terminate with respect to the SLB Parties at the earliest of (a) such time as the SLB Parties no longer beneficially own at least 10% of the outstanding shares of Common Stock and are no longer subject to the Standstill and the Lock-Up and Transfer Restrictions, (b) such time as the SLB Parties do not beneficially own any shares of Common Stock, and (c) the written agreement of the SLB Parties and the Company terminating the agreement. The amended and restated stockholders agreement will terminate with respect to Riverstone at the earliest of (i) such time as Riverstone and its affiliates no longer beneficially own at least 10% of the outstanding shares of Common Stock, and (ii) the delivery of written notice to the Company by Riverstone of the termination of the agreement with respect to Riverstone. 
+As of December 31, 2022, Riverstone did not beneficially own 10% of the outstanding shares of Common Stock, and, as a result, the amended and restated stockholders agreement terminated with respect to Riverstone. 
+Amended and Restated Registration Rights Agreement 
+In connection with the OneStim Acquisition, we entered into an amended and restated registration rights agreement with SLB, SLB Canada and each of the other holders identified therein (the “ Holders ”), pursuant to which, among other things, certain Holders, including affiliates of Riverstone, SLB and SLB Canada (the “ Sponsoring Holders ”), have customary demand registration rights and we 
+46 
+are obligated to prepare and file a registration statement registering the offer and sale of all of SLB and SLB Canada’s shares of Class A Common Stock. In addition, pursuant to this agreement, the Sponsoring Holders have the right to require us, subject to certain limitations set forth therein, to effect a distribution of any or all of their shares of Class A Common Stock by means of an underwritten offering. We are not obligated to effect any underwritten offering unless the dollar amount of the registrable securities of the Sponsoring Holder(s) demanding such underwritten offering to be included therein is reasonably likely to result in gross sale proceeds of at least $25 million. The amended and restated registration rights agreement also provides Holders with certain customary piggyback registration rights. These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a registration or offering and the Company’s right to delay or withdraw a registration statement under certain circumstances. 
+Stock Repurchase 
+During the year ended December 31, 2022, the Company repurchased and retired 1,700,000 shares of Common Stock for $27.8 million or $16.35 average price per share from SLB, under the Company’s share repurchase program announced in July 2023. 
+Purchase of Chemicals, Proppant and Equipment 
+Following the OneStim Acquisition, in the normal course of business, the Company purchases chemicals, proppant and other equipment and maintenance parts from SLB and its subsidiaries. For the year ended December 31, 2022, total purchases from SLB were approximately $21.7 million, and as of December 31, 2022, amounts due to SLB were $2.6 million. 
+Underwriting Agreement 
+On April 29, 2022, the Company, Liberty LLC, SLB, and BofA Securities, Inc. and J.P. Morgan Securities LLC (together, the “ Underwriters ”), entered into an underwriting agreement, dated as of April 29, 2022, pursuant to which SLB sold 14,500,000 shares of Class A Common Stock at a price of $15.50 per share to the Underwriters (the “ Sale ”). The Sale closed on May 3, 2022. The Company did not receive any proceeds from the Sale. The underwriting agreement contains customary representations, warranties and agreements of the Company and SLB and other customary obligations of the parties and termination provisions. 
+Transactions with Liberty Resources 
+Liberty Resources LLC (“ Liberty Resources ”) is an oil and gas exploration and production company of which Mr. Wright is the Executive Chairman and an equity owner. Mr. Wright previously served as th e Chief Executive Officer at Liberty Resources from its formation in September 2010 until March 2017. Liberty Resources entered into a master service agreement with Liberty Oilfield Services LLC, a subsidiary of the Company (“ Liberty Services ”), whereby Liberty Services provides hydraulic fracturing service to Liberty Resources at market service rates. For the year ended December 31, 2022, the amounts related to the provision of hydraulic fracturing services to Liberty Resources under the master services agreement was $16.7 million. 
+In December 2022, the Company entered into a letter agreement with Liberty Resources to extend the payment terms for certain accounts receivable until April 1, 2014, subject to timely payment of monthly interest charges ranging from 12-18%. As of December 31 , 2022, the amount of receivables subject to this letter agreement was approximately $11.8 million. 
+Transactions with Franklin Mountain 
+Franklin Mountain Energy LLC (“ Franklin Mountain ”) is an oil and gas exploration and production company of which Ms. Robertson serves as the Chief Financial Officer. Franklin Mountain entered into a master service agreement with Liberty Services, whereby Liberty Services provides hydraulic fracturing service to Franklin Mountain at market service rates. For the year ended December 31, 2022, the amounts related to the provision of hydraulic fracturing services to Franklin Mountain under the master services agreement was $131.8 million or 3.2% of the Company’s revenues for such period. 
+Transactions with Tim Babcock 
+Tim Babcock is currently employed at ST9 Gas and Oil LLC, a wholly-owned subsidiary of Liberty Services (“ ST9 ”) as a key account manager. Tim Babcock is the son of Ken Babcock, who serves on the Board. For the year ended December 31, 2022, ST9 paid Tim Babcock $177,219. 
+47 
+Indemnification for Officers and Directors 
+Our Amended and Restated Certificate of Incorporation and Second Amended and Restated Bylaws provide indemnification rights to our directors and officers and permit us to purchase insurance on behalf of any officer, director, employee or other agent for any liability arising out of that person’s actions as our officer, director, employee or agent, regardless of whether Delaware law would mandate indemnification. Additionally, we have entered into separate indemnity agreements with our directors and certain officers to provide additional indemnification benefits, including the right to receive, in advance, reimbursements for expenses incurred in connection with a defense for which the director or officer is entitled to indemnification. We believe that the limitation of liability provisions in our Amended and Restated Certificate of Incorporation, Second Amended and Restated Bylaws and the indemnity agreements will facilitate our ability to continue to attract and retain qualified individuals to serve as directors and officers. 
+Conflicts of Interest 
+The related party transactions described herein may cause certain conflicts of interests, including that: 
+♦ we may enter into contracts between us, on the one hand, and related parties, on the other, that are not as a result of arm’s-length transactions; 
+♦ our executive officers and directors that hold positions of responsibility with related parties may be aware of certain business opportunities that are appropriate for presentation to us as well as to such other related parties and may present such business opportunities to such other parties; and 
+♦ our executive officers and directors that hold positions of responsibility with related parties may have significant duties with, and spend significant time serving, other entities and may have conflicts of interest in allocating time. 
+For example, Mr. Wright, our Chief Executive Officer, is the Executive Chairman of Liberty Resources, a position which may require a portion of his time and which may cause conflicts of interest in pursuing business opportunities of which he becomes aware. 
+48 
+HOUSEHOLDING 
+The SEC permits companies and intermediaries (such as brokers and banks) to satisfy delivery requirements for proxy statements and annual reports with respect to two or more stockholders sharing the same address by delivering a single proxy statement and annual report to those stockholders. This process, which is commonly referred to as “householding,” is intended to reduce the volume of duplicate information stockholders receive and reduce expenses for companies. Both the Company and some of our intermediaries may be householding our proxy materials and Annual Report on Form 10-K. Once you have received notice from your broker or another intermediary that they will be householding materials sent to your address, householding will continue until you are notified otherwise or until you revoke your consent. Should you wish to receive separate copies of our Annual Report on Form 10-K and proxy statement in the future, we will promptly deliver a separate copy of each of these documents to you if you send a written or oral request to us at our phone number or address appearing on the cover of this Proxy Statement, to the attention of the Corporate Secretary. If you hold your shares through an intermediary that is householding and you want to receive separate copies of our Annual Report on Form 10-K and proxy statement in the future, you should contact your bank, broker or other nominee record holder.
\ No newline at end of file
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+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+WASHINGTON, D.C. 20549 
+FORM 10-K 
+(Mark One) 
+☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the Fiscal Year Ended December 31 , 2023 
+OR 
+☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+Commission File No. 001-38081 
+Liberty Energy Inc. 
+(Exact Name of Registrant as Specified in its Charter) 
+Delaware 
+81-4891595 
+(State or Other Jurisdiction of Incorporation or Organization) (I.R.S. Employer Identification No.) 
+950 17th Street , Suite 2400 
+Denver , Colorado 
+80202 
+(Address of Principal Executive Offices) (Zip Code) 
+( 303 ) 515-2800 
+(Registrant’s Telephone Number, Including Area Code) 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of each class Trading symbol(s) Name of each exchange on which registered 
+Class A Common Stock, par value $0.01 LBRT New York Stock Exchange 
+Securities registered pursuant to Section 12(g) of the Act: None 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☒ Yes ☐ No 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐ Yes ☒ No 
+Indicate by check mark whether the registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No 
+Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this Chapter) during the presiding 12 months (or for such shorter period that the registrant was required to submit and post such files). ☒ Yes ☐ No 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. 
+Large Accelerated Filer ☒ 
+Accelerated Filer ☐ Non-accelerated filer ☐ 
+Smaller reporting company ☐ 
+Emerging growth company ☐ 
+If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ 
+Indicate by check mark whether the registrant has filed a report on an attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ 
+If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐ 
+Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant ’ s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐ 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act): ☐ Yes ☒ No 
+As of June 30, 2023, the last business day of the registrant ’ s most recently completed second fiscal quarter, the aggregate market value of voting and non-voting common stock held by non-affiliates of the registrant was approximately $ 2.2 billion, determined using the per share closing price on the New York Stock Exchange on that date of $13.37. Shares of common stock held by each director and executive officer (and their respective affiliates) and each person who owns 10 percent or more of the outstanding common stock or who is otherwise believed by the registrant to be in a control position have been excluded. This determination of affiliate status is not necessarily a conclusive determination for other purposes. 
+At February 5, 2024 the Registrant had 166,682,012 shares of Class A Common Stock and 0 shares of Class B Common Stock outstanding. 
+Documents Incorporated by Reference: Part III of this Annual Report on Form 10-K incorporates certain information by reference from the registrant ’ s proxy statement for the 2024 annual meeting of stockholders to be filed no later than 120 days after the end of the registrant ’ s fiscal year. 
+TABLE OF CONTENTS 
+Page No. 
+PART I 
+Item 1. 
+Business 
+1 
+Item 1A. 
+Risk Factors 
+12 
+Item 1B. 
+Unresolved Staff Comments 
+27 
+Item 1C. 
+Cybersecurity 
+27 
+Item 2. 
+Properties 
+28 
+Item 3. 
+Legal Proceedings 
+28 
+Item 4. 
+Mine Safety Disclosures 
+28 
+PART II 
+Item 5. 
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+29 
+Item 6. 
+[Reserved] 
+28 
+Item 7. 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+33 
+Item 7A. 
+Quantitative and Qualitative Disclosure about Market Risk 
+44 
+Item 8. 
+Financial Statements and Supplementary Data 
+44 
+Item 9. 
+Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+44 
+Item 9A. 
+Controls and Procedures 
+45 
+Item 9B. 
+Other Information 
+45 
+PART III 
+Item 10. 
+Directors, Executive Officers and Corporate Governance 
+46 
+Item 11. 
+Executive Compensation 
+46 
+Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+46 
+Item 13. 
+Certain Relationships and Related Transactions, and Director Independence 
+46 
+Item 14. 
+Principal Accountant Fees and Services 
+46 
+PART IV 
+Item 15. 
+Exhibits and Financial Statement Schedules 
+47 
+Item 16. 
+Form 10-K Summary 
+48 
+SIGNATURES 
+52 
+i 
+CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS 
+This Annual Report on Form 10-K (“Annual Report”) and certain other communications made by us contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange of 1934, as amended (the “Exchange Act”), including among others, expected performance, future operating results, oil and natural gas demand and prices and the outlook for the oil and gas industry, future global economic conditions, the impact of global conflicts, improvements in operating procedures and technology, our business strategy and the business strategies of our customers, in addition to other estimates, and beliefs. For this purpose, any statement that is not a statement of historical fact should be considered a forward-looking statement. We may use the words “estimate,” “outlook,” “project,” “forecast,” “position,” “potential,” “likely,” “believe,” “anticipate,” “assume,” “plan,” “expect,” “intend,” “achievable,” “may,” “will,” “continue,” “should,” “could” and similar expressions to help identify forward-looking statements. However, the absence of these words does not mean that the statements are not forward-looking. We cannot assure you that our assumptions and expectations will prove to be correct. Important factors could cause our actual results to differ materially from those indicated or implied by forward-looking statements, including but not limited to the risks described in this Annual Report and other filings that we make with the U.S. Securities Exchange Commission (the “SEC”). We undertake no intention or obligation to update or revise any forward-looking statements, except as required by law, whether as a result of new information, future events or otherwise and readers should not rely on the forward-looking statements as representing the Company’s views as of any date subsequent to the date of the filing of this Annual Report. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. 
+All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. 
+MARKET AND INDUSTRY DATA 
+This Annual Report includes market and industry data and certain other statistical information based on third-party sources including independent industry publications, government publications and other published independent sources, such as content and estimates provided by Lium, LLC (“Lium Research”) as of December 31, 2023, and industry content and figures provided by Baker Hughes Co. (“Baker Hughes”) as of December 31, 2023. Neither Lium Research nor Baker Hughes is a member of the Financial Industry Regulatory Authority or the Securities Investor Protection Corporation and neither is a registered broker dealer or investment advisor. Although we believe these third-party sources are reliable as of their respective dates, we have not independently verified the accuracy or completeness of this information. Some data is also based on our own good faith estimates, which are supported by our management's knowledge of and experience in the markets and business in which we operate. 
+TRADEMARKS, SERVICE MARKS AND TRADENAMES 
+This Annual Report contains trademarks, tradenames, and service marks that are owned by us or other companies, which are our property. Solely for convenience, the trademarks, tradenames, and service marks referred to in this Annual Report may appear without the ®, TM, and SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the rights of the applicable licensors to these trademarks, tradenames, and service marks. We do not intend our use or display of other parties’ trademarks, tradenames, or service marks to imply, and such use or display should not be construed to imply a relationship with, or endorsement or sponsorship of us by, these other parties. 
+ii 
+PART I 
+As used in this Annual Report, except as otherwise indicated or required by the context, all references in this Annual Report to (i) the “Company,” “Liberty,” “we,” “us” and “our” refer to Liberty Energy Inc. and its consolidated subsidiaries; (ii) “Liberty LLC” refer to Liberty Oilfield Services New HoldCo LLC; and (iii) “PropX” refer to Proppant Solutions, LLC and its predecessor in interest. 
+Item 1. Business 
+Our Company 
+We are a leading integrated energy services and technology company focused on providing innovative hydraulic services and related technologies to onshore oil and natural gas exploration and production (“E&P”) companies in North America. We offer customers hydraulic fracturing services, together with complementary services including wireline services, proppant delivery solutions, field gas processing and treating, compressed natural gas (“CNG”) delivery, data analytics, related goods (including our sand mine operations), and technologies that will facilitate lower emission completions, thereby helping our customers reduce their emissions profile. 
+Our areas of operations are in all of the most active shale basins in North America, including the Permian Basin, the Williston Basin, the Eagle Ford Shale, the Haynesville Shale, the Appalachian Basin (Marcellus Shale and Utica Shale), the Western Canadian Sedimentary Basin, the Denver-Julesburg Basin (the “DJ Basin”), and the Anadarko Basin. Our operations also extend to a few smaller shale basins, including the Uinta Basin, the Powder River Basin, and the San Juan Basin. The breadth of our operational footprint provides us an opportunity to leverage our fixed costs and to efficiently reposition our equipment in response to customer requirements. The map below represents our current primary areas of operation. 
+The process of hydraulic fracturing involves pumping a pressurized stream of fracturing fluid (typically a mixture of water, chemicals and proppant) into a well casing or tubing to cause the underground formation to fracture or crack. These fractures release trapped hydrocarbon particles and provide a conductive channel for the oil or natural gas to flow freely to the wellbore for collection. The propping agent, or proppant, typically sand, becomes lodged in the cracks created by the hydraulic fracturing process, “propping” them open to facilitate the flow of hydrocarbons from the reservoir to the well. The fracturing 
+1 
+fluid is engineered to lose viscosity, or “break,” and is subsequently flowed back from the formation, leaving the proppant suspended in the formation fractures. Once our customer has flushed the fracturing fluids from the well using a controlled flow-back process, the customer manages fluid and water recycling or disposal. 
+Our hydraulic fracturing fleets consist of mobile hydraulic fracturing units and other auxiliary heavy equipment to perform fracturing services. Our hydraulic fracturing units consist primarily of high-pressure hydraulic pumps, engines, transmissions, radiators and other supporting equipment that are typically mounted on trailers. We refer to the group of units and other equipment, such as blenders, data vans, sand storage, tractors, manifolds and high-pressure fracturing iron, which are necessary to perform a typical hydraulic fracturing job, as a “fleet,” and the personnel assigned to each fleet as a “crew.” The size of each fleet and crew can vary depending on the requirements of each job design. 
+Wireline operations supplement our hydraulic fracturing fleets, which consist of a truck equipped with a spool of wireline that is lowered into wells to convey specialized tools or equipment, such as perforating guns and charges, which are necessary to connect the wellbore with the target formation. This operation is performed between each hydraulic fracturing stage. Our wireline service is primarily offered alongside our hydraulic fracturing services, which allows us to maximize efficiency for our customers through optimized coordination of the wireline and hydraulic fracturing services. In addition, we also offer our wireline service on a stand-alone basis. 
+We also operate two sand mines that allows us to vertically integrate our supply-chain in the Permian Basin. The mines provide sand to Liberty hydraulic fracturing fleets as well as to third parties. With a secured supply of regional sand in the basin, we reduce our dependency on other providers and any downtime that could result from sand supply issues. 
+As a result of the acquisition of PropX, which was completed in October 2021, we are a leading provider of last-mile proppant delivery solutions, including proppant handling equipment and logistics software across North America. PropX offers innovative environmentally friendly technology with optimized dry and wet sand containers and wellsite proppant handling equipment that drive logistics efficiency and reduce noise and emissions. We believe that PropX wet sand handling technology is a key enabler of the next step of cost and emissions reductions in the proppant industry. PropX also offers customers the latest real-time logistics software, PropConnect™, as a hosted software as a service. 
+In early 2023, we launched Liberty Power Innovations LLC (“LPI”), an integrated alternative fuel and power solutions provider for remote applications. On April 6, 2023, LPI expanded its footprint with the acquisition of Siren Energy & Logistics, LLC (“Siren”) (“the Siren Acquisition”), a Permian focused integrated natural gas compression and CNG delivery business. LPI provides CNG supply, field gas processing and treating, and well site fueling and logistics. LPI was formed with the initial focus on supporting Liberty’s transition towards our next generation digiFleets℠ and dual fuel fleets, as CNG fueling services are limited in the market, yet critical to maintaining highly efficient well site operations. Currently, LPI is primarily focused on supporting an industry transition to natural gas fueled technologies, serving as a key enabler of the next step of cost and emissions reductions in the oilfield. 
+Our operations are organized into a single business segment, which consists of hydraulic fracturing services, including wireline, proppant delivery and goods, including our Permian Basin sand mines, and natural gas compression and delivery, and we have one reportable geographical segment, North America. We have grown from one active hydraulic fracturing fleet as of December 2011 to over 40 active fleets as of December 31, 2023. We are focused on providing “next-generation” frac fleets and technologies to assist our customers with completing their wells in an environmental, social, and governance (“ESG”) friendly manner. 
+Our founders and management are pioneers in the development of data-driven hydraulic fracturing technologies for application in shale plays. Prior to founding the Company, the majority of our management team founded and built Pinnacle Technologies, Inc. (“Pinnacle Technologies”) into a leading fracturing technology company. In 1992, Pinnacle Technologies developed the first commercial hydraulic fracture mapping technologies, analytical tools that played a major role in launching the shale revolution. Our extensive experience with fracture technologies and customized fracture design has enabled us to develop new technologies and processes that provide our customers with real-time solutions that significantly enhance their completions. These technologies include hydraulic fracture propagation models, reservoir engineering tools, large, proprietary shale production databases and multi-variable statistical analysis techniques. Taken together, these technologies have enabled us to be a leader in hydraulic fracture design innovation and application. Our management team has an average of over 20 years of energy services experience, and the majority of our management team worked together before founding our company. 
+We believe technical innovation and strong relationships with our customer and supplier bases distinguish us from our competitors and are the foundations of our business. We expect that E&P companies will continue to focus on technological innovation as completion complexity and fracture intensity of horizontal wells increases, particularly as customers are increasingly focused on reducing emissions from their completions operations. We remain proactive in developing innovative solutions to industry challenges, including developing: (i) our databases of U.S. unconventional wells to which we apply our proprietary multi-variable statistical analysis technologies to provide differential insight into fracture design optimization; (ii) 
+2 
+our Liberty Quiet Fleet® design which significantly reduces noise levels compared to conventional hydraulic fracturing fleets; (iii) hydraulic fracturing fluid systems tailored to the specific reservoir properties in the basins in which we operate; (iv) our dual fuel dynamic gas blending (“DGB”) fleets that allow our engines to run diesel or a combination of diesel and natural gas, to optimize fuel use, reduce emissions and lower costs; (v) our digiFleets℠, comprising of digiFrac℠ and digiPrime℠ pumps, our innovative, purpose-built electric and hybrid frac pumps that have approximately 25% lower CO2e emission profile than the Tier IV DGB; (vi) our wet sand handling technology which eliminates the need to dry sand, enabling the deployment of mobile mines nearer to wellsites; and (vii) the launch of LPI to support the transition to our digiFleets as well as the transition to lower costs and emissions in the oilfield. In addition, our integrated supply chain includes proppant, chemicals, equipment, natural gas fueling services, logistics and integrated software which we believe promotes wellsite efficiency and leads to more pumping hours and higher productivity throughout the year to better service our customers. In order to achieve our technological objectives, we carefully manage our liquidity and debt position to promote operational flexibility and invest in the business throughout the full commodity cycle in the regions we operate. 
+ESG Focused 
+We support all energy sources that improve our energy system and better lives. We passionately work to better the process of bringing hydrocarbons to the surface in a clean, safe and efficient fashion and view these principles as foundational to our business. We focus on developing and adding technologies to our operations that assist our customers in implementing their goals. The list below sets forth specific examples of our efforts in this regard: 
+• In 2013, we introduced Tier II dual-fuel technology to our fleets which allows our frac pumps to use natural gas in place of some diesel fuel to lower particulate emissions. 
+• In 2014, we began the use of containerized sand delivery at frac locations, which reduces dust, noise and truck traffic. 
+• In 2016, we introduced Quiet Fleet® technology, which significantly reduces noise levels associated with frac operations. 
+• In 2018, we partnered with an equipment supplier to introduce Tier IV dynamic gas blending, or DGB, engines to our frac fleet that can substitute up to 80% of the diesel typically used by a frac pump with natural gas and significantly lower emission levels in frac operations. Tier IV DGB engines were added to our fleet in 2020. 
+• In 2018, we began the design and development of digiFrac SM , our innovative, purpose-built electric frac pump that has approximately a 25% lower CO2e emission profile than the Tier IV DGB. 
+• In 2021, we announced the successful test of digiFrac and in 2022 commenced delivery of commercial pumps. 
+• In October 2021, we acquired PropX, a leading provider of last-mile proppant delivery solutions including proppant handling equipment and logistics software. PropX offers innovative, environmentally friendly technology with optimized dry and wet sand containers and wellsite proppant handling equipment that drive logistics efficiency and reduce noise and emissions. 
+• In 2022, we began the design and development of digiPrime SM , the first hybrid pump technology, utilizing direct mechanical drive for the pumps while simultaneously generating power capable of electrifying supporting equipment at the well site. These pumps have a lower CO2e emissions profile than digiFrac. 
+• In 2023, we launched LPI and closed the acquisition of Siren. We believe that the shift in fuel consumption from diesel to cleaner natural gas has the potential to promote emissions reductions in the industry. 
+• In 2023, we commenced deployment of digiFleets SM , comprised of digiFrac and digiPrime pump technology along with other complementary equipment from our digiTechnologies SM suite. 
+• In January 2024, we established the Bettering Human Lives Foundation, a non-profit organization dedicated to improving the well-being of communities worldwide with an early focus on promoting clean cooking solutions. 
+• In February 2024, we released the third edition of our Bettering Human Lives report, emphasizing energy’s central role in human lives. The report has been updated to include real-world case studies and is now segmented into six sections: Energy, Energy and the Modern World, Energy Poverty, Climate Change, Climate Economics, and an in-depth section on Liberty Energy. 
+3 
+Furthermore, we are continuously committed to engagement in our communities. We provide K-12 scholarships to low-income children through ACE (Alliance for Choice in Education) and we have launched a Liberty Scholars program at Montana Technological University to enable lower-income students to obtain a college education. In total, over 140 students received Liberty scholarships across the U.S. and Canada in 2023. In addition to our educational initiatives, we have other efforts targeting veterans, poverty abatement, low-income housing, criminal justice reform, and job opportunities for those who had a disadvantaged start in life. To double our impact and encourage our employees to get involved in their communities, we launched Love, Liberty, our corporate matching program in 2021. In 2023, Liberty processed over 100 match requests to nearly 50 different organizations, totaling nearly $30,000 in matching contributions. 
+Cyclical Nature of Industry 
+We operate in a cyclical industry reflecting global oil and gas supply and demand dynamics, current and expected future oil and gas commodity prices, and the perceived stability and sustainability of those prices. Global oil and gas supply and demand can be impacted by general domestic and international economic conditions, inflationary pressures, geopolitical developments, government regulations, and other factors. Such factors also impact capital expenditures and drilling and completions activities of E&P companies, which in turn can impact demand for our services. For these reasons, the results of our operations may fluctuate from quarter to quarter and from year to year, and these fluctuations may distort comparisons of results across periods. 
+Seasonality 
+Our results of operations have historically reflected seasonal tendencies relating to holiday seasons, inclement weather and the conclusion of our customers’ annual drilling and completion capital expenditure budgets. Our most notable declines typically occur in the fourth quarter of the year for the reasons described above. Additionally, some of the areas in which we have operations, including Canada, the DJ Basin, Powder River Basin and Williston Basin, are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice, rain, or frost, and related road restrictions, we may be unable to move our equipment between locations, thereby reducing our ability to provide services and generate revenues. The exploration activities of our customers may also be affected during such periods of adverse weather conditions. Additionally, extended drought conditions in our operating regions could impact our ability or our customers’ ability to source sufficient water or increase the cost for such water. 
+Intellectual Property 
+Over the last several years and in connection with the acquisitions of PropX, Siren, and others in prior periods, we have significantly invested in our research and technology capabilities. Our efforts to date have been focused on developing innovative, fit-for-purpose solutions designed to enhance our core service offerings, increase completion efficiencies, provide cost savings to our operations and add value for our customers. A cornerstone of our technological advantage is a series of proprietary databases of U.S. unconventional wells that include production data, completion designs and reservoir characteristics. We utilize these databases to perform multi-variable statistical analysis that generates differential insight into fracture design optimization to enhance our customers’ production economics. Our emphasis on data analytics is also deployed during job execution through the use of real-time feedback on variables that maximizes customer returns by improving cost-effective hydraulic fracturing operations. 
+Today, we hold approximately 500 patents and patent licenses relating to our engineering and technology solutions. We seek patent and trademark protections for our technology when we deem it prudent, and we aggressively pursue protection of these rights when warranted. We believe our patents, trademarks, and other protections for our proprietary technologies are adequate for the conduct of our business and that no single patent or trademark is critical to our business. In addition, we rely, to a great extent, on the technical expertise and know-how of our personnel to maintain our competitive position, and we take commercially reasonable measures to protect trade secrets and other confidential and/or proprietary information relating to the technologies we develop. 
+4 
+Human Capital Management 
+As of December 31, 2023, we had approximately 5,500 employees and no unionized labor. We believe we have good relations with our employees and that one of our key competitive advantages is our people. Our highly trained, experienced and motivated employees are critical to delivering our hydraulic fracturing services. Taking care of our employees is one of our top priorities, and we continually invest in hiring, training and retaining the employees we believe to be the best in our field. We consistently assess the current business environment and labor market to refine our compensation and benefits programs in order to attract and retain top talent in our industry. We strive to promote from within our existing employee base to manage new hydraulic fracturing fleets and organically grow our operating expertise. This organic growth is essential in achieving the expertise and level of customer service we strive to provide each of our customers. As a result, we plan to continue to invest in our employees through both personal and professional training to attract and retain the best individuals in our areas of operation. Overall, we focus on individual contributions and team success to foster a culture built around operational excellence and superior safety. 
+Health and Safety 
+Our people are our most important asset and ensuring their safety and the safety of those around them is the most important thing we do. Making certain that the Liberty team is well trained to handle the complexities of daily field operations, and that their training and competency remains current with the latest technology and standards is a key component. In order to facilitate this training, we have developed the Liberty Frac Academy, a thorough program where employees are trained on various aspects of the Company, from safety in equipment operation to leadership skills. The Liberty Frac Academy not only ensures dissemination of high-quality training material, but also provides a forum for sharing best practices and lessons learned across the Company. As a result, we are among the safest service providers in the industry with a constant focus on Health, Safety and Environmental performance and service quality, as evidenced by an average incident rate that was consistently lower than the industry average from 2021 to 2023. Our employee-centered focus and reputation for safety has enabled us to obtain projects from industry leaders with some of the most demanding safety and operational requirements. 
+Programs and Benefits 
+One way we have demonstrated a history of investing in our workforce is by offering competitive salaries and wages. To foster a strong sense of ownership, restricted stock units are provided to eligible employees under our long-term incentive plan. Furthermore, we offer innovative benefits to all eligible employees, including, among others, comprehensive health insurance coverage, parental leave to all new parents, for birth or adoption, financial support for child adoption, leave to care for partners with serious health conditions, 401(k) savings plan and educational tuition assistance for both bachelor’s degree and master’s degree programs. We are also passionate about community investment and are a part of the Ban the Box initiative which provides work opportunities for formerly incarcerated individuals. 
+Governmental Regulation and Climate Change 
+As a company with operations in both the United States and Canada, we are subject to the laws of both jurisdictions in which we operate and the rules and regulations of various governing bodies, which may differ among those jurisdictions. Compliance with these laws, rules and regulations has not had, and is not expected to have, a material effect on our capital expenditures, results of operations and competitive position as compared to prior periods. We are also subject to numerous environmental and regulatory requirements related to our operations. For further information related to such regulation, see the risks described under the heading “Risk Factors” in this Annual Report. 
+Our operations are subject to numerous stringent and complex laws and regulations at the federal, state, and local levels governing the discharge of materials into the environment, environmental protection, and health and safety aspects of our operations. Failure to comply with these laws and regulations or to obtain or comply with permits may result in the assessment of administrative, civil, and criminal penalties, imposition of remedial or corrective action requirements, and the imposition of injunctions or other orders to prohibit certain activities, restrict certain operations, or force future compliance with environmental requirements. 
+There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons, other hazardous substances, and wastes, as a result of air emissions and wastewater discharges related to our operations, and because of historical operations and waste disposal practices. Spills or other releases of regulated substances, including such spills and releases that occur in the future, could expose us to material losses, expenditures, and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. The following is a summary of some of the existing laws, rules, and regulations to which we are subject. 
+5 
+U.S. Laws and Regulations 
+Hazardous Substances and Waste Handling 
+The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Under guidance issued by the U.S. Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. RCRA currently exempts many E&P wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes intrinsically associated with the exploration, development, or production of crude oil and natural gas. However, these E&P wastes may still be regulated under state solid waste laws and regulations, and it is possible that certain oil and natural gas E&P wastes now classified as non-hazardous could be classified as hazardous waste in the future. Stricter regulation of wastes generated during our or our customers’ operations could result in increased costs for our operations or the operations of our customers, which could in turn reduce demand for our services and adversely affect our business. We cannot guarantee that the EPA will not revisit the exemption of E&P waste or that waste will not become more heavily regulated at the federal or state level. 
+Comprehensive Environmental Response, Compensation, and Liability Act 
+The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owner or operator of the site where the release occurred and anyone who transported or disposed or arranged for the transport or disposal of a hazardous substance released at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA and any state analogs may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources and for the costs of certain health studies. We currently own, lease, or operate numerous properties that have been used for manufacturing and other operations for many years. These properties and the substances disposed or released on them may be subject to CERCLA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. 
+Worker Health and Safety 
+We are subject to a number of federal and state laws and regulations, including the OSHA regulatory standards, which establish requirements to protect the health and safety of workers. Among others, we may be subject to OSHA regulations for safe operation of cranes, power industrial trucks and similar equipment at our worksites, safe practices for working in hazardous locations and permit-required confined spaces, and proper use of required personal protective equipment by workers. OSHA’s hazard communication standard requires tracking of hazardous chemicals present at the worksite, sharing of such information with the workers, and training the workers to handle the chemicals appropriately. The EPA’s community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes also require maintenance of information about hazardous materials used or produced in operations and provision of this information to employees, state and local government authorities, and citizens. We are also subject to OSHA’s regulatory standard for respirable crystalline silica, which provides measures to protect workers in hydraulic fracturing operations from exposure to this chemical including limiting exposure to airborne respirable crystalline silica in excess of a specified limit. Additionally, the Federal Motor Carrier Safety Administration (the “FMCSA”) regulates and provides safety oversight of commercial motor vehicles, the EPA establishes requirements to protect human health and the environment, the federal Bureau of Alcohol, Tobacco, Firearms and Explosives establishes requirements for the safe use and storage of explosives, and the federal Nuclear Regulatory Commission establishes requirements for the protection against ionizing radiation. We are subject to Mine Safety & Health Administration regulations related to operation of sand mines including regulations for training and retraining of workers engaged in sand mine operations. Substantial fines and penalties can be imposed, and orders or injunctions limiting or prohibiting certain operations may be issued, in connection with any failure to comply with these laws and regulations. 
+6 
+Water Discharges 
+The federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the U.S. The discharge of pollutants into regulated waters, including jurisdictional wetlands, is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. To the extent the agencies expanding the range of properties subject to the Clean Water Act’s jurisdiction or impose more stringent requirements on discharges of wastewater, certain energy companies could face increased costs and delays with respect to obtaining permits, including for the discharge of dredge and fill activities in waters of the U.S. or wetland areas, which in turn could reduce demand for our services. Furthermore, the process for obtaining permits has the potential to delay our operations and those of our customers. Spill prevention, control, and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture, or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of wastewater and storm water runoff from certain types of facilities. The Clean Water Act and analogous state laws provide for administrative, civil, and criminal penalties for unauthorized discharges and, together with the Oil Pollution Act of 1990, impose rigorous requirements for spill prevention and response planning, as well as substantial potential liability for the costs of removal, remediation, and damages in connection with any unauthorized discharges. 
+Air Emissions 
+The federal Clean Air Act (the “CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants and other air emissions at specified sources. These regulations change frequently. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements, utilize specific equipment or technologies to control emissions of certain pollutants or prohibit certain types of emissions management practices. In recent years, the CAA has been used to impose additional stringent requirements upon oil and gas production operations. While these rules may not be directly applicable to our business, they are applicable to the business of our customers. Promulgation of stricter permitting or emission control requirements could delay or impair our or our customers’ ability to obtain air emission permits, to develop new wells and to continue to operate existing wells, and result in fewer wells being drilled or redeveloped, causing a decrease in demand for our services. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties, as well as injunctive relief, for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. 
+Climate Change 
+The EPA has determined that emissions of greenhouse gases, including carbon dioxide and methane, present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. The EPA has established greenhouse gas emissions reporting requirements for sources in the oil and gas sector and has also promulgated rules requiring certain large stationary sources of greenhouse gases to obtain preconstruction permits under the CAA and follow “best available control technology” requirements. Although we are not likely to become subject to greenhouse gas emissions permitting and best available control technology requirements because none of our facilities are presently major sources of greenhouse gas emissions, such requirements could become applicable to our customers. In addition, the EPA has used the CAA to impose additional greenhouse gas emissions control requirements upon our customers. Furthermore, the Inflation Reduction Act (“IRA 2022”) imposes a methane emissions charge on certain emissions from specific classes of sources that are required to report their greenhouse gas emissions, which began in calendar year 2024. This fee as well as additional requirements on greenhouse gas emissions from our customers could have an adverse effect on their costs of operations or financial performance, thereby adversely affecting our business, financial condition, and results of operations. Also, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, and many states have already established regional greenhouse gas “cap-and-trade” programs. The adoption of any legislation or regulation that restricts emissions of greenhouse gases from the equipment and operations of our customers or with respect to the oil and natural gas they produce could adversely affect demand for our products and services. 
+7 
+Hydraulic Fracturing 
+Our business is clearly dependent on hydraulic fracturing and horizontal drilling activities. As further described herein, hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shale. The process, which involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. Specifically, there is considerable uncertainty surrounding regulation of the emissions of methane, which may be released during hydraulic fracturing, chemicals used in the hydraulic fracturing process, the discharge of wastewater from hydraulic fracturing operations and concerns about the triggering of seismic activity by the injection of produced waters into underground wells. Certain proposed regulation could make it significantly more difficult and/or costly to drill and operate oil and gas wells. If adopted, such regulation could result in a decline in the completion of new oil and gas wells or the recompletion of existing wells, which could negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the demand for our services. Given the long-term trend towards increasing regulation, future regulation in the industry remains a possibility. 
+Some states, counties, and municipalities have enacted or are considering moratoria on hydraulic fracturing. For example, New York, Vermont, Maryland, and Washington have banned the use of high-volume hydraulic fracturing. Alternatively, some municipalities are, or have considered, zoning and other ordinances, the conditions of which could impose a de facto ban on drilling and/or hydraulic fracturing operations. Further, some states, counties, and municipalities are closely examining water use issues, such as permit and disposal options for processed water, which could have a material adverse impact on our financial condition, prospects, and results of operations if such additional permitting requirements are imposed upon our industry. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could reduce demand for our business by making it more difficult or costly for certain customers to perform fracturing to stimulate production from tight formations. 
+National Environmental Policy Act 
+Businesses and operations of our customers that are carried out on federal lands may be subject to the National Environmental Policy Act (“NEPA”), which requires federal agencies, including the U.S. Department of the Interior, to evaluate major agency actions having the potential to significantly impact the human environment. In the course of such evaluations, an agency will evaluate the potential direct, indirect, and cumulative impacts of a proposed project and, if necessary, will prepare a detailed Environmental Impact Statement that must be made available for public review and comment. To the extent that our customers’ current activities, as well as proposed plans, on federal lands require governmental permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects which in turn could reduce demand for our services. 
+Endangered Species Act and Migratory Bird Treaty Act 
+The federal Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or its habitat. The U.S. Fish and Wildlife Service (the “FWS”) must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development and development of sand mines used for hydraulic fracturing. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”), which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit. This prohibition covers most bird species in the U.S. Future implementation of the rules implementing the ESA and the MBTA are uncertain. If we or our customers were to have areas within our respective operations designated as critical or suitable habitat for a protected species, it could decrease demand for our services and have a material adverse effect on our business. 
+Canadian Laws and Regulations 
+Companies such as us offering energy services that include hydraulic fracturing, engineering, and wireline services in the Province of Alberta in Canada are regulated by both the provincial government of Alberta (“Province”) and the federal government of Canada (“Canada”). This includes, but is not limited to, regulation related to environmental protection legislation, climate change legislation, fracking legislation, and legislation related to wildlife. In addition to being regulated by the Province and Canada, energy services companies may also be subject to other international, national, and subnational laws, regulations, and policies. 
+Provincial Legislation 
+Energy services companies are primarily regulated by provincial governments in Canada. For example, in Alberta, provincial legislation potentially applicable to our Canadian operations includes the Environmental Protection and 
+8 
+Enhancement Act , RSA 2000, e E-12. This Act promotes the protection, enhancement and wise use of the environment, and deals with matters such as air emissions, water discharges, and the handling of hazardous substances and waste control (for example, under the Waste Control Regulation , Alta Reg 192/1996). Other environmental legislation in the Province that applies to energy service companies includes: the Water Act, RCA 2000, c W-3 and associated regulations, under which companies must apply for a license for any water use; and the Wildlife Act, RCA 2000, c W-10 which provides for the protection and conservation of wild animals and endangered species in Alberta. 
+Other potentially applicable provincial legislation in Alberta includes legislation directed at the transportation of dangerous goods, including oil (the Dangerous Goods Transportation and Handling Act , RSA 2000, c D-4 and associated regulations), legislation intended to provide for the responsible management of oil wells and associated sites, including remediation responsibilities (the Oil and Gas Conservation Act , RSA 2000, c O-6 and associated regulations), legislation establishing regulatory bodies overseeing oil and gas and electricity in Alberta (the Responsible Energy Development Act , SA 2012, c R-17.3 and the Alberta Utilities Commission Act , SA 2007, c A-37.2), legislation governing the removal of gas or propane from Alberta (the Gas Resources Preservation Act , RSA 2000, c G-4), legislation to effect conservation and prevent waste of the oil sands resource in Alberta (the Oil Sands Conservation Act , RSA 2000, c O-7), and legislation governing worker safety (the Occupational Health and Safety Act , SA 2017, c O-2.1). 
+The Alberta Energy Regulator has a number of directives that are applicable to energy services companies, such as Directive 050, updated in March 2023, which addresses salinity ranges for soils that can receive drilling wastes, Directive 058, which sets out regulatory requirements for the handling, treatment, and disposal of upstream oilfield waste, and Directive 083, updated April 2023, which sets out the requirements for managing subsurface integrity associated with hydraulic fracturing, including seismic monitoring in certain areas of Alberta. Other provinces in Canada have their own statutory regime applicable to oilfield service companies. 
+Federal Legislation 
+The Federal government in Canada shares certain jurisdiction with the provinces over certain environmental matters. Federal legislation potentially applicable to our Canadian operations includes legislation focused on regulating greenhouse gases (the Greenhouse Gas Pollution Pricing Act, SC 2018, c 12, s 186), legislation aimed at protecting wildlife (the Species at Risk Act , SC 2002, c 29, Fisheries Act, RSC 1985, c F-14, and Migratory Birds Convention Act, 1994, SC 1994, c 22), and legislation governing the transportation of potentially dangerous substances and prevention of pollution (the Transportation of Dangerous Goods Act, 1992 , SC 1992, c 34 and Canadian Environmental Protection Act, 1999, SC 1999, c 33). 
+Environmental assessment of major projects in Canada is shared between the federal and provincial governments. In October 2023 the Supreme Court of Canada ruled that Canada’s Impact Assessment Act , SC 2019, c 28, s1, which governs approvals for federally regulated projects, is largely unconstitutional ( Reference re Impact Assessment Act , 2023 SCC 23). The federal government is currently amending its environmental impact assessment legislation in response to the decision. 
+9 
+Properties 
+Properties 
+Our corporate headquarters are located at 950 17 th Street, Suite 2400, Denver, Colorado 80202. We lease our general office space at our corporate headquarters. The lease expires in December 2027. We currently own or lease the following additional principal properties: 
+District Facility Location Size Leased or Owned 
+Midland, TX 90,000 sq. ft on 35 acres Owned 
+Midland, TX 70,000 sq. ft on 12 acres Owned 
+Odessa, TX 77,500 sq. ft on 48 acres Owned 
+Cibolo, TX 90,000 sq. ft on 34 acres Owned 
+Kermit, TX 5,000 acres Owned 
+Monahans, TX 3,200 acres Owned 
+Magnolia, TX 63,350 sq. ft. Leased (through May 31, 2031) 
+Magnolia, TX 11,680 sq. ft Leased (through February 28, 2025) 
+Gainesville, TX 170,000 sq. ft. Leased (through May 31, 2024) 
+Shreveport, LA 215,000 sq ft. on 45 acres Owned 
+Cheyenne, WY 115,000 sq. ft on 60 acres Owned 
+Gillette, WY 32,757 sq. ft on 15 acres Leased (through December 31, 2034) 
+Henderson, CO 50,000 sq. ft on 13 acres Leased (through December 31, 2034) 
+Henderson, CO 96,582 sq. ft on 12 acres Owned 
+Williston, ND 55,000 sq. ft on 50 acres Owned 
+Vernal, UT 30,901 sq. ft on 10 acres Leased (through September 30, 2025) 
+Farmington, NM 34,000 sq. ft on 30 acres Owned 
+Farmington, NM 23,000 sq. ft on 9 acres Owned 
+El Reno, OK 80,000 sq. ft on 33 acres Owned 
+Red Deer, AB 170,000 sq. ft on 42 acres Owned 
+Grand Prairie, AB 135,000 sq. ft on 40 acres Owned 
+Huallen, AB 80 acres Owned 
+We also lease several smaller facilities, which leases generally have terms of one to six years. We believe that our existing facilities are adequate for our operations and their locations allow us to efficiently serve our customers. We do not believe that any single facility is material to our operations and, if necessary, we could readily obtain a replacement facility. 
+Marketing and Customers 
+We have developed long-term partnerships with our customers through a continuous dialogue focused on their production economics. Further, we have a proven track record of executing our customers’ plans and delivering on time and in line with expected costs. Our customer base includes a broad range of integrated and independent E&P companies, including some of the largest E&P companies in our areas of operation. Our technological innovations, customer-tailored approach and track record of consistently providing high-quality, safe and reliable service has allowed us to develop long-term customer partnerships, which we believe makes us the service provider of choice for many of our customers. 
+Our sales and marketing activities typically are performed through our local sales representatives in each geographic region and are supported by our corporate headquarters. For the years ended December 31, 2023, 2022 and 2021, our top five customers collectively accounted for approximatel y 34% , 30%, and 27% of our revenues, respectively. For the years ended December 31, 2023, 2022, and 2021, no customer accounted for more than 10% of our revenues. 
+10 
+Suppliers and Raw Materials 
+We have a dedicated supply chain team that manages sourcing and logistics to ensure flexibility and continuity of supply in a cost-effective manner across our areas of operation. We have built long-term relationships with multiple industry leading suppliers of proppant, chemicals and hydraulic fracturing equipment and have started to internally design and assemble key pump and maintenance parts. In addition, we have built a strong relationship with the assemblers of our custom-designed hydraulic fracturing fleets and believe we will continue to have timely access to new, high capability fleets as we continue to grow. In 2018, we vertically integrated a supplier of certain major components through the acquisition of ST9 Gas and Oil LLC, which recently changed its name to Liberty Advanced Equipment Technologies LLC. In October 2021, we vertically integrated a supplier of our containerized sand and last mile proppant logistics solutions with the acquisition of PropX. This, along with our two state-of-the-art sand mines in the Permian Basin, help us alleviate the risk of proppant supply shortages. 
+We purchase a wide variety of raw materials, parts and components that are manufactured and supplied for our operations. We are not dependent on any single source of supply for those parts, supplies or materials. To date, we have generally been able to obtain the equipment, parts and supplies necessary to support our operations, although we have experienced delivery delays and shortages on some items. While we believe that we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers, we may not always be able to do so. In addition, certain materials for which we do not currently have long-term supply agreements could experience shortages and significant price increases in the future. As a result, we may be unable to mitigate any future supply shortages and our results of operations, prospects and financial condition could be adversely affected. 
+Competition 
+The markets in which we operate are highly competitive. We provide services in various geographic regions across the United States and Canada, and our competitors include many large and small oilfield service providers, including some of the largest integrated service companies. Our hydraulic fracturing services compete with large, integrated companies such as Halliburton Company as well as other companies including Patterson-UTI Energy Inc., ProFrac Holding Corp., and ProPetro Services, Inc. In addition, we compete regionally with smaller service providers. 
+We believe that the principal competitive factors in the markets we serve are technical expertise, equipment capacity, work force competency, efficiency, safety record, reputation, experience and price. Additionally, projects are often awarded on a bid basis, which tends to create a highly competitive environment. We seek to differentiate ourselves from our competitors by delivering the highest-quality services and equipment possible, coupled with superior execution and operating efficiency in a safe working environment. 
+Available Information 
+We file or furnish annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The SEC also maintains an internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC. 
+We also make available free of charge through our website, www.libertyenergy.com, electronic copies of certain documents that we file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. 
+11 
+Item 1A. Risk Factors 
+Described below are certain risks that we believe apply to our business and the industry in which we operate. You should carefully consider each of the risks described below in conjunction with other information including the financial statements and related notes provided in this Annual Report and in our other public disclosures. The risks described below highlight potential events, trends or other circumstances that could adversely affect our business, financial condition, results of operations, cash flows, liquidity or access to sources of financing, and consequently, the market value of our Class A common stock, par value $0.01 per share (“Class A Common Stock”). These risks could cause our future results to differ materially from historical results and from guidance we may provide regarding our expectations of future financial performance. The risks described below are those that we have identified as material and is not an exhaustive list of all the risks we face. There may be other risks and uncertainties not currently known to us or that we currently deem to be immaterial which may also materially and adversely affect our business operations in the future. Please refer to the explanation of the qualifications and limitation on forward-looking statements set forth on page ii hereof. 
+Risks Related to the Oil and Natural Gas Industry 
+Federal, state, local and other applicable legislative and regulatory initiatives relating to hydraulic fracturing may serve to limit future oil and natural gas E&P activities and could have a material adverse effect on our results of operations and business. 
+Various federal, state, local and other applicable legislative and regulatory initiatives have been, or could be undertaken which could result in additional requirements or restrictions being imposed on hydraulic fracturing operations. Currently, hydraulic fracturing is generally exempt from federal regulation under the Safe Drinking Water Act Underground Injection Control (the “SDWA UIC”) program and is typically regulated by state oil and gas commissions or similar agencies but increased scrutiny and regulation by federal agencies does occur. For example, in late 2016, the EPA released a final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources. Additionally, the EPA has asserted regulatory authority pursuant to the SDWA UIC program over hydraulic fracturing activities involving the use of diesel fuel in the fracturing fluid and issued guidance regarding the permitting of such activities. Furthermore, the U.S. Bureau of Land Management has previously published rules that established stringent standards relating to hydraulic fracturing on federal and Native American lands. Similarly, the EPA has adopted rules on the capture of methane and other emissions released during hydraulic fracturing. These rules have been the subject of ongoing legal challenges. Most recently, in December 2022, the EPA finalized additional methane rules for new and existing petroleum operations. The EPA rules could make it more difficult and/or costly to drill and operate oil and gas wells. These rules may result in a decline in the completion of new oil and gas wells or the recompletion of existing wells, which could negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the demand for our services. In addition to federal regulatory actions, legislation has been introduced, but not enacted, in Congress to provide for further federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. 
+Moreover, many states and local governments have adopted, or are considering, regulations that impose new or more stringent permitting, disclosure, disposal and well-construction requirements on hydraulic fracturing operations, including states where we or our customers operate, such as Texas, Colorado and North Dakota. States could also elect to place prohibitions on hydraulic fracturing, as several states have already done. In addition, some states have adopted broader sets of requirements related to oil and gas development more generally that could impact hydraulic fracturing activities. For example, in 2019 the Colorado legislature adopted SB 19-181, which gave greater regulatory authority to local jurisdictions and reoriented the mandate of the Colorado Oil and Gas Conservation Commission to place more emphasis on the protection of human health and the environment. In response, a reconstituted Colorado Oil and Gas Conservation Commission modified its rules to address the requirements of the legislation, adopting increased setback requirements, provisions for assessing alternative sites for well pads to minimize environmental impacts, and consideration to cumulative impacts, among other provisions. The Colorado Department of Public Health and the Environment also finalized rules related to the control of emissions from certain pre-production activities. In Texas, there has been increased pressure on the Railroad Commission (“RRC”) to impose more stringent limitations on the flaring of gas from wells to prevent waste and because of increased concerns related to the environmental effects of flaring. The RRC continues to approve flaring permits, but at least one lawsuit has been filed by a pipeline operator challenging the RRC’s flaring approval practices. Environmental groups, local citizens groups and others continue to seek to use a variety of means to force action on additional restrictions on hydraulic fracturing and oil and gas development generally. 
+Additionally, some states have enacted legislation limiting PFAS usage in certain products or limiting PFAS usage generally. For example, Colorado has banned the use of PFAS in oil and gas products including hydraulic fracturing fluids, drilling fluids and proppants. Should PFAS be in hydraulic fracturing chemicals, this could open up a new front for the regulation of hydraulic fracturing and result in additional exposure to liability for contamination resulting from the use or release of hydraulic fracturing chemicals. 
+12 
+Some states in which we operate require the disclosure of some or all of the chemicals used in our hydraulic fracturing operations. Certain aspects of one or more of these chemicals may be considered proprietary by us or our chemical suppliers. Disclosure of our proprietary chemical information to third parties or to the public, even if inadvertent, could diminish the value of our trade secrets or those of the chemicals suppliers and could result in competitive harm to us, which could have an adverse impact on our business, financial condition, prospects and results of operations. 
+In recent years, there have been allegations that hydraulic fracturing may result in seismic activities. Although the extent of any correlation between hydraulic fracturing and seismic activity has been and remains the subject of studies and debate, some parties believe that there is a causal relationship. As a result, federal and state legislatures and agencies may seek to further regulate, restrict or prohibit hydraulic fracturing. Such actions could result in a decline in the completion of new oil and gas wells, which could negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the demand for our services. 
+Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to, and litigation concerning, oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays for our customers or increased operating costs in the production of oil and natural gas, including from the developing shale plays, or could make it more difficult for (or could result in a prohibition for) us and our customers to perform hydraulic fracturing. The adoption of any additional laws or regulations regarding hydraulic fracturing or limitation in hydraulic fracturing could potentially cause a decrease in the completion of new oil and natural gas wells and an associated decrease in demand for our services and increased compliance costs and time. Such events could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition. 
+Additional legislation, executive actions, regulations or other regulatory initiatives to limit, delay or prohibit hydraulic fracturing or other aspects of oil and gas development may be pursued. In the event that these or other new federal restrictions, delays or prohibitions relating to the hydraulic fracturing process are adopted in areas where we or our customers conduct business, we or our customers may incur additional costs or permitting requirements to comply with such federal requirements that may be significant and, in the case of our customers, also could result in added restrictions or delays in the pursuit of exploration, development, or production activities, which would in turn reduce the demand for our services and have a material adverse effect on our results of operations. 
+Federal legislation and regulatory initiatives relating to drilling on federal lands could harm our business and negatively impact the oil and natural gas industry. 
+Businesses and operations of our customers may be carried out on federal lands. The Biden administration has announced that it is considering more stringent regulations for operations on such lands, and in January 2021, the U.S. Department of the Interior issued an order that effectively suspends new oil and gas leases and drilling permits on non-Indian federal lands and waters for a period of 60 days. However, the suspension does not limit existing operations under valid leases. 
+President Biden followed with an executive order directing the Secretary of the Interior to pause the issuance of new oil and gas leases on federal public lands and offshore waters pending completion of a comprehensive review of federal oil and gas permitting and leasing practices that take into consideration potential climate and other impacts associated with oil and gas activities. The leasing suspension has been the subject of several lawsuits, resulting in conflicting decisions on the legality of the lease suspension. For example, in August 2022, the U.S. District Court for the Western District of Louisiana blocked the Biden administration’s ability to unilaterally pause oil and gas leasing in 13 states, holding that the U.S. Department of the Interior violated federal law when it canceled onshore and offshore leasing on federal lands. While the various lawsuits were pending, in August 2022, Congress passed the IRA 2022 which, among other things, makes changes to the federal oil and gas leasing program (including increasing royalty rates and implementing policies to discourage venting and flaring) and requires the Biden administration to hold several oil and gas lease auctions, including many that had been suspended or cancelled. 
+Additionally, in November 2021, the U.S. Department of the Interior released a report on the federal oil and gas leasing program, which found that the current program fails to serve the public interest. The report makes several recommendations, including increasing royalty rates and adding new restrictions on what lands are made available for oil and gas development to minimize leasing of lands with low potential for development. The U.S. Department of the Interior is expected to propose rules based on these recommendations. In April 2022, the U.S. Department of the Interior also announced that the U.S. Bureau of Land Management would post notices for significantly reformed onshore lease sales that would promote the public interest in public lands while addressing deficiencies in the current federal oil and gas leasing program. The new lease sales will incorporate many of the recommendations in the U.S. Department of the Interior report on the federal leasing program. Such scheduled sales began in June 2022. 
+Furthermore, a group of oil and gas related interests has also sued alleging that lease sales are not occurring as required under the Mineral Leasing Act. In addition, where lease sales have occurred, environmental groups have sued to block the sales. On June 1, 2022, the U.S. District Court for the District of Columbia granted a motion to voluntarily dismiss three cases after the U.S. Bureau of Land Management and other defendants agreed to conduct more robust environmental reviews of certain oil and gas leases and reconsider the cumulative climate effects of these leases. The settlement agreements apply to nearly four 
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+million acres of land in Colorado, Wyoming, Utah, Montana, and New Mexico. If the U.S. Bureau of Land Management fails to complete its obligations under the settlement agreements, the plaintiffs can reinstate the litigation. 
+To the extent our customers operate on leased federal land, these and other regulatory actions could have a material adverse effect on the Company and our industry. 
+Our business depends on domestic capital spending by the oil and natural gas industry, and reductions in capital spending could have a material adverse effect on our liquidity, results of operations and financial condition. 
+Our business is directly affected by our customers’ capital spending to explore for, develop and produce oil and natural gas in the United States and Canada. In addition, certain of our customers could become unable to pay their vendors and service providers, including us, as a result of a decline in commodity prices. Reduced discovery rates of new oil and natural gas reserves in our areas of operation as a result of decreased capital spending may also have a negative long-term impact on our business, even in an environment of stronger oil and natural gas prices. Any of these conditions or events could adversely affect our operating results. If current activity levels decrease or our customers further reduce their capital spending, it could have a material adverse effect on our liquidity, results of operations and financial condition. 
+Industry conditions are influenced by numerous factors over which we have no control, including: 
+• expected economic returns to E&P companies of new well completions; 
+• domestic and foreign economic conditions and supply of and demand for oil and natural gas; 
+• the level of prices, and expectations about future prices, of oil and natural gas; 
+• the level of global oil and natural gas exploration and production; 
+• the level of domestic and global oil and natural gas inventories; 
+• the supply of and demand for hydraulic fracturing services and equipment in the United States and Canada; 
+• federal, tribal, state and local laws, regulations and taxes, including the policies of governments regarding hydraulic fracturing, oil and natural gas exploration, development and production activities and the transportation of oil and gas by pipeline, as well as non-U.S. governmental regulations and taxes; 
+• governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves; 
+• political and economic conditions in oil and natural gas producing countries; 
+• actions by the members of the Organization of Petroleum Exporting Countries and other oil exporting nations (“OPEC+”) with respect to oil production levels and potential changes in such levels; 
+• global weather conditions and natural disasters; 
+• worldwide political, military and armed conflict, and economic conditions; 
+• the cost of producing and delivering oil and natural gas; 
+• lead times associated with acquiring equipment and products and availability of qualified personnel; 
+• the discovery rates of new oil and natural gas reserves; 
+• the production decline rate of existing oil and gas wells; 
+• stockholder activism or activities by non-governmental organizations to limit certain sources of funding for the energy sector or to restrict the exploration, development, production and transportation of oil and natural gas; 
+• the availability of water resources, suitable proppant and chemical additives in sufficient quantities for use in hydraulic fracturing fluids; 
+• advances in exploration, development and production technologies or in technologies affecting energy consumption; 
+• the availability, proximity and capacity of oil and natural gas pipelines and other transportation facilities; 
+• merger and divestiture activity among oil and natural gas producers; 
+• the price and availability of alternative fuels and energy sources; and 
+• uncertainty in capital and commodities markets and the ability of oil and natural gas companies to raise equity capital and debt financing. 
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+The volatility of oil and natural gas prices may adversely affect the demand for our hydraulic fracturing services and negatively impact our results of operations. 
+The demand for our hydraulic fracturing services is primarily determined by current and anticipated oil and natural gas prices and the related levels of capital spending and drilling activity in the areas in which we have operations. Volatility or weakness in oil prices or natural gas prices (or the perception that oil prices or natural gas prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells. This, in turn, could lead to lower demand for our services and may cause lower utilization of our assets. We have experienced, and may in the future experience significant fluctuations in operating results as a result of the reactions of our customers to changes in oil and natural gas prices. 
+Prices for oil and natural gas historically have been extremely volatile and are expected to continue to be volatile. During the year 2023, the posted WTI price traded at an average of $77.58 per barrel (“Bbl”), as compared to the 2022 average of $94.90 per Bbl and the 2021 average of $68.13 per Bbl. During this three-year period, the WTI price fluctuated between a high of $123.64 per Bbl and a low of $47.47 per Bbl. If the prices of oil and natural gas remain or become more volatile, our operations, financial condition, cash flows and level of expenditures may be materially and adversely affected. 
+Delays or restrictions in obtaining permits by us for our operations or by our customers for their operations could impair our business. 
+In most states, our hydraulic fracturing services, our natural gas compression and CNG delivery operations, and the operations of our oil and natural gas producing customers require permits from one or more governmental agencies in order to perform drilling and completion activities, secure water rights, or other regulated activities. Such permits are typically issued by state agencies, but federal and local governmental permits may also be required. The requirements for such permits vary depending on the location where such regulated activities will be conducted. As with all governmental permitting processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit to be issued, and the conditions that may be imposed in connection with the granting of the permit. In addition, some of our customers’ drilling and completion activities may take place on federal land or Native American lands, requiring leases and other approvals from the federal government or Native American tribes to conduct such drilling and completion activities or other regulated activities. Under certain circumstances, federal agencies may cancel proposed leases for federal lands and refuse to grant or delay required approvals. Therefore, our customers’ operations in certain areas may be interrupted or suspended for varying lengths of time, causing a loss of revenue to us and adversely affecting our results of operations in support of those customers. 
+As described above, in January 2021, the U.S. Department of the Interior issued an order that effectively suspends new oil and gas leases and drilling permits on non-Indian federal lands and waters for a period of 60 days, but the suspension does not limit existing operations under valid leases. President Biden followed with an executive order that ordered the Secretary of the Interior to pause the issuance of new oil and gas leases on federal public lands and offshore waters pending completion of a comprehensive review of federal oil and gas permitting and leasing practices that take into consideration potential climate and other impacts associated with oil and gas activities. This order further directs agencies to identify fossil fuel subsidies provided by such agencies and take measures to ensure that federal funding is not directly subsidizing fossil fuels, with an objective of eliminating fossil fuel subsidies from federal budget requests beginning in 2022. This order is currently being challenged by industry groups. While the various lawsuits were pending, in August 2022, Congress passed the IRA 2022 which, among other things, makes changes to the federal oil and gas leasing program (including increasing royalty rates and implementing policies to discourage venting and flaring) and requires the Biden administration to hold several oil and gas lease auctions, including many that had been suspended or cancelled. For additional information, see the risk factor titled “Federal legislation and regulatory initiatives relating to drilling on federal lands could harm our business and negatively impact the oil and natural gas industry.” 
+Oil and natural gas companies’ operations using hydraulic fracturing are substantially dependent on the availability of water. Restrictions on the ability to obtain water for E&P activities and the disposal of flowback and produced water may impact their operations and have a corresponding adverse effect on our business, results of operations and financial condition. 
+Water is an essential component of shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Our oil and natural gas producing customers’ access to water to be used in these processes may be adversely affected due to reasons such as periods of extended drought, privatization, third party competition for water in localized areas or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. The occurrence of these or similar developments may result in limitations being placed on allocations of water due to needs by third party businesses with more senior contractual or permitting rights to the water. Our customers’ inability to locate or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact their E&P operations and have a corresponding adverse effect on our business, results of operations and financial condition. 
+Moreover, the imposition of new environmental regulations and other regulatory initiatives could include increased restrictions on our producing customers’ ability to dispose of flowback and produced water generated in hydraulic fracturing or other fluids resulting from E&P activities. Applicable laws impose restrictions and strict controls regarding the discharge of 
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+pollutants into waters of the United States and require that permits or other approvals be obtained to discharge pollutants to such waters. Additionally, in 2016, the EPA adopted a pretreatment standard that prohibits the discharge of wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly owned treatment works. Further, regulations implemented under both federal and state laws prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. These laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and hazardous substances. Compliance with current and future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells and any inability to secure transportation and access to disposal wells with sufficient capacity to accept all of our flowback and produced water on economic terms may increase our customers’ operating costs and could result in restrictions, delays, or cancellations of our customers’ operations, the extent of which cannot be predicted. 
+Our operations are subject to risks associated with climate change and potential regulatory programs meant to address climate change; these programs may impact or limit our business plans, result in significant expenditures or reduce demand for our services and reduce our revenues. 
+Climate change continues to be the focus of political and societal attention. Numerous proposals have been made and are likely to be forthcoming on the international, national, regional, state and local levels to reduce GHG emissions. These efforts have included or may include cap-and-trade programs, carbon taxes, GHG reporting obligations and other regulatory programs that limit or require control of GHG’s from certain sources. Upon taking office, President Biden issued several Executive Orders relating climate change, envisioning a “government-wide approach” to climate policy. At the 26 th Conference of the Parties of the United Nations Framework Convention on Climate Change held in October and November 2021, President Biden announced a commitment to significantly reduce GHG’s and transition the U.S. economy to net-zero carbon by 2050. At the 27th Conference of the Parties in 2022, President Biden reinforced these commitments and emphasized efforts to reduce methane emissions from the oil and gas sector. At the 28 th Conference of the Parties (the “COP28”) in 2023, the United States announced a new rule on requiring reductions in methane and other air pollutants from oil and natural gas industry. Programs addressing climate change may limit the ability to produce crude oil and natural gas, require stricter limits on the release of methane or other GHGs, increase reporting and/or other compliance obligations associated with GHG emissions, limit the ability to explore in new areas, limit the construction of pipelines and related equipment or may make it more expensive to produce, any of which may decrease the demand for our services and our revenues. 
+Incentives to conserve energy or use alternative energy sources, which can be part of climate change programs, may increase the competitiveness of alternative energy sources (such as wind, solar, geothermal, tidal and biofuels) or increase the focus on reducing the use of combustion engines in transportation (such as governmental mandates that ban the sale of new gasoline-powered automobiles). At COP28, the parties adopted a statement calling for “transitioning away from fossil fuels” and an increased focus on renewable energy capacity and energy efficiency. These actions could, in turn, reduce demand for hydrocarbons and therefore for our services, which would lead to a reduction in our revenues. Additionally, on January 26, 2024, the Biden Administration announced a temporary pause on pending decisions regarding exports of liquified natural gas until the U.S. Department of Energy can update the underlying analyses for authorization. 
+An increased societal and governmental focus on ESG and climate change issues may adversely impact our business, impact our access to investors and financing, and decrease demand for our services. 
+An increased expectation that companies address ESG matters (including climate change) may have a myriad of impacts on our business. Some investors and lenders are factoring these issues into investment and financing decisions. They may rely upon companies that assign ratings to a company’s ESG performance. Unfavorable ESG ratings, as well as recent activism around fossil fuels, may dissuade investors or lenders from us and toward other industries, which could negatively impact our stock price or our access to capital. Additionally, some potential sources of investment or financing have announced an intention to avoid or limit investment in companies that engage in hydraulic fracturing. While a substantial number of major banks and financing sources remain active in investments related to hydraulic fracturing, it is possible that the investment avoidance or limitation theme could expand in the future and restrict access to capital for companies like us. 
+Moreover, while we have and may continue to create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures are based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. Additionally, to the extent that we report GHG emissions data, the methodologies that we use to calculate our emissions may change over time based upon changing industry standards. We note that standards and expectations regarding the processes for measuring and counting GHG emissions and GHG emission reductions are evolving, and it is possible that our approach to measuring our emissions maybe considered inconsistent with common or best practices with respect to measuring and accounting for such matters. If our approaches to such matters fall out of step with common or best practice, we may be subject to additional scrutiny, criticism, regulatory and investor engagement or litigation, any of which may adversely impact our business, financial condition or results of operation. 
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+Furthermore, the SEC has announced proposed rules that, among other matters, will establish a framework for reporting climate related risks. To the extent that any proposed rules impose additional reporting obligations, we could face increased costs. Separately, the SEC has also announced that it is scrutinizing existing climate change related disclosure in public filings, increasing the potential for enforcement if the SEC were to allege our existing climate disclosures are misleading or deficient. Furthermore, in November 2022, the U.S. Department of Labor adopted final rules that allow plan fiduciaries to consider climate change and other ESG factors when they select retirement investments and exercise shareholder rights, such as proxy voting. Should plan investors decide to not invest in us based on ESG factors, our business and access to capital may be negatively impacted. In 2023, the State of California enacted legislation that will require large U.S. companies doing business in California to make broad-based climate-related disclosures starting as early as 2026, and other jurisdictions, domestically and internationally, are also considering various climate change disclosure requirements. 
+In addition, ESG and climate change issues may cause consumer preference to shift toward other alternative sources of energy, lowering demand for oil and natural gas and consequently lowering demand for our services. In some areas these concerns have caused governments to adopt or consider adopting regulations to transition to a lower-carbon economy. These measures may include adoption of cap-and-trade programs, carbon taxes, increased efficiency standards, prohibitions on the manufacture of certain types of equipment (such as new automobiles with internal combustion engines), and requirements for the use of alternate energy sources such as wind or solar. These types of programs may reduce the demand for oil and natural gas and consequently the demand for our services. 
+Approaches to climate change and a transition to a lower-carbon economy, including government regulation, company policies, and consumer behavior, are continuously evolving. At this time, we cannot predict how such approaches may develop or otherwise reasonably or reliably estimate their impact on our financial condition, results of operations and ability to compete. However, any long-term material adverse effect on the oil and gas industry may adversely affect our financial condition, results of operations and cash flows. 
+Our operations are subject to significant risks, some of which are beyond our control. These risks may be self-insured, or may not be fully covered under our insurance policies. 
+Our operations are subject to significant hazards often found in the oil and natural gas industry, such as, but not limited to, accidents, including accidents related to trucking operations provided in connection with our services, blowouts, explosions, craterings, fires, natural gas leaks, oil and produced water spills and releases of hydraulic fracturing fluids or other well fluids into the environment. These conditions can cause: 
+• disruption in operations; 
+• substantial repair or remediation costs; 
+• personal injury or loss of human life; 
+• significant damage to or destruction of property, and equipment; 
+• environmental pollution, including groundwater contamination; 
+• unusual or unexpected geological formations or pressures and industrial accidents; 
+• impairment or suspension of operations; and 
+• substantial revenue loss. 
+In addition, our operations are subject to, and exposed to, employee/employer liabilities and risks such as wrongful termination, discrimination, labor organizing, retaliation claims and general human resource related matters. 
+The occurrence of a significant event or adverse claim in excess of the insurance coverage that we maintain or that is not covered by insurance could have a material adverse effect on our liquidity, consolidated results of operations and financial condition. Claims for loss of oil and natural gas production and damage to formations can occur in the well services industry. Litigation arising from a catastrophic occurrence at a location where our equipment and services are being used or trucking services provided in connection therewith may result in our being named as a defendant in lawsuits asserting large claims. 
+We do not have insurance against all foreseeable risks, either because insurance is not available or because of the high premium costs. The occurrence of an event not fully insured against or the failure of an insurer to meet its insurance obligations could result in substantial losses. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. Insurance may not be available to cover any or all of the risks to which we are subject, or, even if available, it may be inadequate, or insurance premiums or other costs could rise significantly in the future so as to make such insurance prohibitively expensive. 
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+We could experience continued or increased severity of trucking related issues or trucking accidents, which could materially affect our results of operations. 
+Trucking services can be adversely impacted by traffic congestion, shortage of drivers and weather delays which could hinder our service levels. During 2021 and into 2022 there was a shortage of available trucking services in the United States due to the industry not having enough qualified drivers, which impacted our field operations at times. In addition, our field employees are generally required to have a commercial driver’s license (“CDL”) so they can drive trucks and move our frac pumps and other equipment from location to location. Obtaining employees with CDLs can be challenging during times when the trucking industry has driver shortages, as competition for qualified employees is often more intense. If we are unable to obtain trucking services on a timely basis or the services of a sufficient number of field employees with CDLs, it could have a material adverse impact on our financial condition, results of operations and cash flows. 
+In addition, potential liability and unfavorable publicity associated with accidents in the trucking industry can be severe and occurrences are unpredictable. The number and severity of litigation claims may be worsened by distracted driving by both truck drivers and other motorists. Our transportation operations often involve traveling on unpaved roads located in rural areas, increasing the risk of accidents. If we are involved in an accident involving hazardous substances, if there are releases of hazardous substances we transport, if soil or groundwater contamination is found at our facilities or results from our operations, or if we are found to be in violation of applicable environmental laws or regulations, we could owe cleanup costs and incur related liabilities, including substantial fines or penalties or civil and criminal liability. A material increase in the frequency or severity of accidents or workers’ compensation claims or the unfavorable development of existing claims could materially adversely affect our results of operations. In the event that accidents occur, we may be unable to obtain desired contractual indemnities, and our insurance may be inadequate in certain cases which could result in substantial losses. Any such lawsuits in the future may result in the payment of substantial settlements or damages and increases to our insurance costs. 
+We may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition, prospects and results of operations. 
+Our services are subject to inherent risks that can cause personal injury or loss of life, damage to or destruction of property, equipment or the environment or the suspension of our operations. Litigation arising from operations where our services are provided, may cause us to be named as a defendant in lawsuits asserting potentially large claims including claims for exemplary damages. We maintain what we believe is customary and reasonable insurance to protect our business against these potential losses, but such insurance may not be adequate to cover our liabilities, and we are not fully insured against all risks. 
+In addition, our customers usually assume responsibility for, including control and removal of, all other pollution or contamination which may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling and completion fluids. We may have liability in such cases if we are grossly negligent or commit willful acts. Our customers generally agree to indemnify us against claims arising from their employees’ personal injury or death to the extent that, in the case of our hydraulic fracturing operations, their employees are injured by such operations, unless resulting from our gross negligence or willful misconduct. Our customers also generally agree to indemnify us for loss or destruction of customer-owned property or equipment. In turn, we agree to indemnify our customers for loss or destruction of property or equipment we own and for liabilities arising from personal injury to or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. However, we might not succeed in enforcing such contractual liability allocation or might incur an unforeseen liability falling outside the scope of such allocation. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operation. 
+We are subject to environmental and occupational health and safety laws and regulations that may expose us to significant costs and liabilities. 
+Our operations and the operations of our customers are subject to numerous federal, tribal, regional, state and local laws and regulations relating to protection of the environment including natural resources, health and safety aspects of our operations and waste management, including the transportation and disposal of waste and other materials. These laws and regulations may impose numerous obligations on our operations and the operations of our customers, including the acquisition of permits or other approvals to conduct regulated activities, the imposition of restrictions on the types, quantities and concentrations of various substances that may be released into the environment or injected in non-productive formations below ground in connection with oil and natural gas drilling and production activities, the incurrence of capital expenditures to mitigate or prevent releases of materials from our equipment, facilities or from customer locations where we are providing services, the imposition of substantial liabilities for pollution resulting from our operations, and the application of specific health and safety criteria addressing worker protection. Any failure on our part or the part of our customers to comply with these laws and regulations could result in assessment of sanctions including administrative, civil and criminal penalties; imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures; the occurrence of restrictions, delays or cancellations in the permitting, performance or development of projects or operations; and the issuance of orders enjoining performance of some or all of our operations in a particular area. In addition to civil and other penalties associated 
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+with enforcement activities regarding compliance with occupational health and safety laws, our operations may be subject to abatement obligations that could require significant modifications to existing operations to achieve compliance. 
+Our business activities present risks of incurring significant environmental costs and liabilities, including costs and liabilities resulting from our handling of oilfield and other wastes, because of air emissions and wastewater discharges related to our operations, and due to historical oilfield industry operations and waste disposal practices. Moreover, accidental releases or spills may occur in the course of our operations or at facilities where our wastes are taken for reclamation or disposal, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for injuries to persons or damages to properties or natural resources. Some environmental laws and regulations may impose strict liability, which means that in some situations we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Remedial and abatement costs and other damages arising as a result of environmental and occupational health and safety laws and costs associated with changes in these laws and regulations could be significant and have a material adverse effect on our liquidity, consolidated results of operations and financial condition. 
+Laws and regulations protecting the environment generally have become more stringent in recent years and are expected to continue to do so, which could lead to material increases in costs for future environmental compliance and remediation. In particular, the ESA restricts activities that may result in a “take” of endangered or threatened species and provides for substantial penalties in cases where listed species are taken by being harmed. The dunes sagebrush lizard is one example of a species that, if listed as endangered or threatened under the ESA, could impact our operations and the operations of our customers. The dunes sagebrush lizard is found in the active and semi-stable shinnery oak dunes of southeastern New Mexico and adjacent portions of Texas, including areas where our customers operate and our frac sand facilities are located. The FWS is currently conducting a review to determine whether listing the dunes sagebrush lizard as endangered or threatened under the ESA is warranted. In July 2020, the FWS published a 90-day finding that a 2018 petition seeking that the dunes sagebrush lizard be listed as endangered or threatened presented substantial evidence indicating that listing may be warranted. In May 2022, an environmental group filed suit against the U.S. Department of the Interior and the FWS alleging that they have unlawfully delayed protection of the dunes sagebrush. In July 2023, the FWS proposed to list the dunes sagebrush lizard as endangered. If the dunes sagebrush lizard is listed as an endangered or threatened species, our operations and the operations of our customers in any area that is designated as the dunes sagebrush lizard’s habitat may be limited, delayed or, in some circumstances, prohibited, and we and our customers could be required to comply with expensive mitigation measures intended to protect the dunes sagebrush lizard and its habitat. Furthermore, new laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement with respect to environmental matters could restrict, delay or curtail exploratory or developmental drilling for oil and natural gas by our customers and could limit our well servicing opportunities. 
+Oilfield anti-indemnity provisions enacted by many states may restrict or prohibit a party’s indemnification of us. 
+We typically enter into agreements with our customers governing the provision of our services, which usually include certain indemnification provisions for losses resulting from operations. Such agreements may require each party to indemnify the other against certain claims regardless of the negligence or other fault of the indemnified party; however, many states place limitations on contractual indemnity agreements, particularly agreements that indemnify a party against the consequences of its own negligence. Furthermore, certain states, including Texas, New Mexico and Wyoming, have enacted statutes generally referred to as “oilfield anti-indemnity acts” expressly prohibiting certain indemnity agreements contained in or related to oilfield services agreements. Such anti-indemnity acts may restrict or void a party’s indemnification of us, which could have a material adverse effect on our business, financial condition, prospects and results of operations. 
+Technology advancements in well service technologies, including those involving hydraulic fracturing, could have a material adverse effect on our business, financial condition and results of operations. 
+The hydraulic fracturing industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As competitors and others use or develop new technologies or technologies comparable to ours in the future, we may lose market share or be placed at a competitive disadvantage. Further, we may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of our competitors may have greater financial, technical and personnel resources than we do, which may allow them to gain technological advantages or implement new technologies before we can. Additionally, we may be unable to implement new technologies or services at all, on a timely basis or at an acceptable cost. New technology could also make it easier for our customers to vertically integrate their operations, thereby reducing or eliminating the need for our services. Limits on our ability to effectively use or implement new technologies may have a material adverse effect on our business, financial condition and results of operations. 
+The ability or willingness of OPEC+ and other oil exporting nations to set and maintain production levels and/or the impact of sanctions and global conflicts may have a significant impact on natural gas commodity prices. 
+OPEC+ is an intergovernmental organization that seeks to manage the price and supply of oil on the global energy market. Actions taken by OPEC+ members, including those taken alongside other oil exporting nations, have a significant impact on 
+19 
+global oil supply and pricing. For example, OPEC+ and certain other oil exporting nations have previously agreed to take measures, including production cuts, to support crude oil prices. In 2020, largely as a result of the COVID-19 pandemic, oil prices decreased dramatically, and OPEC+ agreed to historic production cuts in an effort to support prices. Conversely, sanctions imposed on Russia as a result of the Russia-Ukraine conflict in 2022 increased prices. In October 2022, OPEC+ again determined to reduce production of oil, by approximately 2 million barrels per day. At its meeting on December 4, 2022, OPEC+ agreed to keep its current policy unchanged as the oil markets struggle to assess the impact of a slowing Chinese economy on demand, and the Group of Seven Nations agreed on a price cap on Russian oil supply. In June 2023, OPEC+ members announced they would extend crude oil production cuts through 2024, limiting global crude oil supplies. In November 2023, OPEC+ agreed to cut production by an additional 1 million barrels per day beginning in January 2024. 
+There can be no assurance that OPEC+ members and other oil exporting nations will agree to future production cuts or other actions to support and stabilize oil prices, nor can there be any assurance that sanctions or other global conflicts, including the Russia-Ukraine conflict and various conflicts in the broader Middle East, will not further impact oil prices. Uncertainty regarding future sanctions or actions to be taken by OPEC+ members or other oil exporting countries could lead to increased volatility in the price of oil and natural gas, which could adversely affect our business, future financial condition and results of operations. 
+Risks Related to the TRAs 
+The Company is required to make payments under the TRAs for certain tax benefits that it may claim, and the amounts of such payments could be significant. 
+In connection with the Company’s initial public offering (the “IPO”), on January 17, 2018, the Company entered into two Tax Receivable Agreements (the “TRAs”) with R/C Energy IV Direct Partnership, L.P. and the then-existing owners of Liberty Oilfield Services Holdings LLC (“Liberty Holdings”) that continued to own Liberty LLC Units (each such person and any permitted transferee, a “TRA Holder”). The TRAs generally provide for the payment by the Company to each TRA Holder of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that the Company actually recognizes (or is deemed to recognize in certain circumstances) as a result of certain increases in tax basis, net operating losses available to the Company as a result of the corporate reorganization performed in connection with the IPO (the “Corporate Reorganization”), and certain benefits attributable to imputed interest. The Company will retain the benefit of the remaining 15% of these cash savings. 
+The Company is a holding company and has no material assets other than its direct and indirect equity interests in its subsidiaries. Because the Company has no independent means of generating revenue, its ability to make payments under the TRAs is dependent on the ability of its subsidiaries to make distributions to the Company in an amount sufficient to cover its obligations under the TRAs. To the extent that the Company is unable to make payments under the TRAs for any reason, such payments will be deferred and will accrue interest until paid. 
+The term of each of the TRAs continues until all tax benefits that are subject to such TRAs have been utilized or expired, unless the Company experiences a change of control (as defined in the TRAs, which includes certain mergers, asset sales and other forms of business combinations) or the TRAs are terminated early (at the Company’s election or as a result of its breach), and the Company makes the termination payments specified in such TRAs. In addition, payments the Company makes under the TRAs will be increased by any interest earned from the due date (without extensions) of the corresponding tax return. Payments under the TRAs commenced in 2020 and so long as the tax savings are recognized and the TRAs are not terminated, payments are anticipated to continue for 15 years after the date of the last redemption of the Liberty LLC Units, which occurred on January 31, 2023. Accordingly, if the applicable U.S. federal corporate tax rate is increased, then the amount of TRA payments paid in the future may also increase. 
+In certain cases, if the Company experiences a change of control (as defined under the TRAs, which includes certain mergers, asset sales and other forms of business combinations) or the TRAs terminate early (at the Company’s election or as a result of its breach), the Company would be required to make an immediate lump-sum payment, and such payment may be significantly in advance of, and may materially exceed, the actual realization, if any, of the future tax benefits to which the payment relates. As a result, the Company’s obligations under the TRAs could have a substantial negative impact on its liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. There can be no assurance we will be able to finance our obligations under the TRAs. Furthermore, as a result of this payment obligation, holders of our Class A Common Stock could receive substantially less consideration in connection with a change in control transaction than they would receive in the absence of such obligation. Because our payment obligations under the TRAs will not be conditioned upon the TRA Holders’ having continued interest in the Company or Liberty LLC, the TRA Holders’ interests may conflict with those of the holders of our Class A Common Stock. 
+Payments under the TRAs are based on the tax reporting positions that we will determine. The TRA Holders will not reimburse us for any payments previously made under the TRAs if any tax benefits that have given rise to payments under the TRAs are subsequently disallowed in an audit, except that excess payments made to any TRA Holder will be netted against payments that would otherwise be made to such TRA Holder, if any, after our determination of such excess. As a result, in such circumstances the Company could make payments that are greater than its actual cash tax savings, if any, and may not be able 
+20 
+to recoup those payments, which could adversely affect the Company’s liquidity. Furthermore, the payments under the TRAs will not be conditioned upon a holder of rights under each of the TRAs having a continued ownership interest in the Company or Liberty LLC. For further details of the TRAs, see Note 12 —Income Taxes to the consolidated financial statements included in Part II, Item 8 of this Annual Report. 
+General Risks Related to our Business 
+We may be adversely affected by uncertainty in the global financial markets and the deterioration of the financial condition of our customers. 
+Our future results may be impacted by the uncertainty caused by an economic downturn, volatility or deterioration in the debt and equity capital markets, inflation, deflation or other adverse economic conditions that may negatively affect us or parties with whom we do business resulting in a reduction in our customers’ spending and their non-payment or inability to perform obligations owed to us, such as the failure of customers to honor their commitments or the failure of major suppliers to complete orders. Additionally, during times when the oil or natural gas markets weaken, our customers are more likely to experience financial difficulties, including being unable to access debt or equity financing, which could result in a reduction in our customers’ spending for our services. In addition, in the course of our business we hold accounts receivable from our customers. In the event of the financial distress or bankruptcy of a customer, we could lose all or a portion of such outstanding accounts receivable associated with that customer. Further, if a customer was to enter into bankruptcy, it could also result in the cancellation of all or a portion of our service contracts with such customer at significant expense or loss of expected revenues to us. 
+Our business, financial condition and results of operations may be adversely impacted by the effects of inflation. 
+Inflation has the potential to adversely affect our business, financial condition and results of operations by increasing our overall cost structure, particularly if we are unable to achieve commensurate increases in the prices we charge our customers. Other inflationary pressures could affect wages, the cost and availability of components, materials and other inputs and our ability to meet customer demand. Inflation may further exacerbate other risk factors, including supply chain disruptions, risks related to international operations and the recruitment and retention of qualified employees. 
+Reliance upon a few large customers may adversely affect our revenue and operating results. 
+Our top five customers represented approximately 34%, 30%, and 27%, of our consolidated revenue for the years ended December 31, 2023, 2022, and 2021, respectively. It is possible that we will derive a significant portion of our revenue from a concentrated group of customers in the future. If a major customer fails to pay us, revenue would be impacted and our operating results and financial condition could be materially harmed. Additionally, if we were to lose any material customer or our customers were to consolidate or merge with other operators, we may not be able to redeploy our equipment at similar utilization or pricing levels or within a short period of time and such loss could have a material adverse effect on our business until the equipment is redeployed at similar utilization or pricing levels. 
+We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss. 
+The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain processing activities. For example, we depend on digital technologies to perform many of our services and to process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. In early 2020, we experienced a denial of service cyberattack that targeted a portion of our non-financial data. We immediately shutdown critical systems, diagnosed the root cause of the attack and then methodically returned systems online. This cyberattack disrupted certain non-financial aspects of our internal system for a period of less than one day, while limited and non-critical portions of our systems were kept offline for up to one week in order to properly evaluate the breach. We determined that this cyberattack did not materially affect us or any of our operations. We engaged in extensive data evaluation for potential damage and concluded that minimal to no data loss had occurred as a result of this cyberattack. Our technologies, systems and networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches in the future that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we will likely be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. Our insurance coverage for cyberattacks may not be sufficient to cover all the losses we may experience as a result of such cyberattacks. 
+21 
+Our assets require significant amounts of capital for maintenance, upgrades and refurbishment and may require significant capital expenditures for new equipment. 
+Our hydraulic fracturing fleets and other completion service-related equipment require significant capital investment in maintenance, upgrades and refurbishment to maintain their competitiveness. The costs of components and labor have increased in the past and may increase in the future with increases in demand, which will require us to incur additional costs for any fleets we may acquire in the future. Our fleets and other equipment typically do not generate revenue while they are undergoing maintenance, upgrades or refurbishment. Any maintenance, upgrade or refurbishment project for our assets could increase our indebtedness or reduce cash available for other opportunities. Furthermore, such projects may require proportionally greater capital investments as a percentage of total asset value, which may make such projects difficult to finance on acceptable terms. To the extent we are unable to fund such projects, we may have less equipment available for service or our equipment may not be attractive to potential or current customers. Additionally, competition or advances in technology within our industry may require us to update or replace existing fleets or build or acquire new fleets. Such demands on our capital or reductions in demand for our hydraulic fracturing fleets and the increase in cost of labor necessary for such maintenance and improvement, in each case, could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations and may increase our costs. 
+We rely on certain third parties for materials, and delays in deliveries of such materials, increases in the cost of such materials or our contractual obligations to pay for materials that we ultimately do not require could harm our business, results of operations and financial condition. 
+We have established relationships with certain suppliers of our materials (such as, but not limited to, proppant and chemical additives) and other parts, supplies and items needed for our operations. Delays or shortages in materials can result from a variety of reasons, including those caused by weather and natural disasters. Presently, the United States is undergoing a supply chain disruption due to backlogged ports and trucking shortages, and our business is not immune from these effects. Even once the root cause of the supply chain disruption or any future shortage or delay has passed, it can take time for our supply chain to recover and run in a regular fashion. Should the nationwide supply chain disruption continue, or should any of our current suppliers be unable to provide the necessary materials or otherwise fail to deliver the materials in a timely manner and in the quantities required, any resulting delays in the provision of services could have a material adverse effect on our business, results of operations and financial condition. Additionally, increasing costs of such materials may negatively impact demand for our services or the profitability of our business operations. In the past, our industry faced sporadic proppant shortages associated with hydraulic fracturing operations requiring work stoppages, which are believed to have adversely impacted the operating results of several competitors. We may not be able to mitigate any future shortages of materials, including proppant, or the impact of supply chain disruptions. Furthermore, to the extent our contracts require us to purchase more materials, including proppant, than we ultimately require, we may be forced to pay for the excess amount under “take or pay” contract provisions. 
+We currently utilize a limited number of assemblers and suppliers for major equipment to both build new fleets and upgrade any fleets we acquire to our preferred specifications, and our reliance on these vendors exposes us to risks including price and timing of delivery. 
+We currently utilize a limited number of assemblers and suppliers for major equipment to both build our new fleets and upgrade any fleets we may acquire to our custom design. If demand for hydraulic fracturing fleets or the components necessary to build such fleets increases or these vendors face financial distress or bankruptcy, these vendors may not be able to provide the new or upgraded fleets on schedule or at the current price. If this were to occur, we could be required to seek another assembler or other suppliers for major equipment to build or upgrade our fleets, which may adversely affect our revenues or increase our costs. 
+Interruptions of service on the rail lines by which we receive proppant could adversely affect our results of operations. 
+We receive a portion of the proppant used in our hydraulic fracturing services by rail. Rail operations are subject to various risks that may result in a delay or lack of service, including lack of available capacity, mechanical problems, extreme weather conditions, work stoppages, labor strikes, terrorist attacks and operating hazards. Additionally, if we increase the amount of proppant we require for delivery of our services, we may face difficulty in securing rail transportation for such additional amount of proppant. Any delay or failure in the rail services on which we rely could have a material adverse effect on our financial condition and results of operations. 
+Changes in transportation regulations may increase our costs and negatively impact our results of operations. 
+We are subject to various transportation regulations including as a motor carrier by the Department of Transportation and by various federal, state, provincial and tribal agencies, whose regulations include certain permit requirements of highway and safety authorities. These regulatory authorities exercise broad powers over our equipment transportation operations, generally governing such matters as the authorization to engage in motor carrier operations, safety, equipment testing, driver requirements and specifications and insurance requirements. The trucking industry is subject to possible regulatory and legislative changes that may impact our operations, such as changes in fuel emissions limits, hours of service regulations that govern the amount of 
+22 
+time a driver may drive or work in any specific period and requiring onboard electronic logging devices or limits on vehicle weight and size. As the federal government continues to develop and propose regulations relating to fuel quality, engine efficiency and greenhouse gasses emissions, we may experience an increase in costs related to truck purchases and maintenance, impairment of equipment productivity, a decrease in the residual value of vehicles, unpredictable fluctuations in fuel prices and an increase in operating expenses. Additionally, we rely on third parties to provide trucking services, including hauling proppant to our customer work sites, and these third parties may fail to comply with various transportation regulations, resulting in our inability to use such third party providers. Increased truck traffic may contribute to deteriorating road conditions in some areas where our operations are performed. Our operations, including routing and weight restrictions, could be affected by road construction, road repairs, detours and state and local regulations and ordinances restricting access to certain roads. Proposals to increase federal, state, provincial or local taxes, including taxes on motor fuels, are also made from time to time, and any such increase would increase our operating costs. Also, state and local regulation of permitted routes and times on specific roadways could adversely affect our operations. We cannot predict whether, or in what form, any legislative or regulatory changes or municipal ordinances applicable to our logistics operations will be enacted and to what extent any such legislation or regulations could increase our costs or otherwise adversely affect our business or operations. 
+Our current and future indebtedness could adversely affect our financial condition. 
+Effective January 23, 2023, using proceeds from borrowings on our ABL Facility (as defined herein), we repaid all amounts outstanding under the Term Loan Facility (as defined herein). As of February 5, 2024, the Company had $159.0 million outstanding under our ABL Facility, in addition to letters of credit in the amount of $7.4 million, with $235.1 million of remaining availability. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.” 
+Moreover, subject to the limits contained in our ABL Facility, we may incur substantial additional debt from time to time. Any borrowings we may incur in the future would have several important consequences for our future operations, including that: 
+• covenants contained in the documents governing such indebtedness may require us to meet or maintain certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our industry, such as being able to take advantage of acquisition opportunities when they arise; 
+• our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes may be limited; 
+• our ability to use operating cash flow in other areas of our business may be limited because we must dedicate a substantial portion of these funds to make principal and interest payments on our indebtedness; 
+• we may be more vulnerable to interest rate increases to the extent that we incur variable rate indebtedness; 
+• we may be competitively disadvantaged to our competitors that are less leveraged or have greater access to capital resources; and 
+• we may be more vulnerable to adverse economic and industry conditions. 
+If we incur indebtedness in the future, we may have significant principal payments due at specified future dates under the documents governing such indebtedness. Our ability to meet such principal obligations will be dependent upon future performance, which in turn will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. Our business may not continue to generate sufficient cash flow from operations to repay any incurred indebtedness. If we are unable to generate sufficient cash flow from operations, we may be required to sell assets, to refinance all or a portion of such indebtedness or to obtain additional financing. 
+Unsatisfactory safety performance may negatively affect our customer relationships and, to the extent we fail to retain existing customers or attract new customers, adversely impact our revenues. 
+Our ability to retain existing customers and attract new business is dependent on many factors, including our ability to demonstrate that we can reliably and safely operate our business in a manner that is consistent with applicable laws, rules and permits, which legal requirements are subject to change. Existing and potential customers consider the safety record of their third-party service providers to be of high importance in their decision to engage such providers. If one or more accidents were to occur at one of our operating sites, the affected customer may seek to terminate or cancel its use of our equipment or services and may be less likely to continue to use our services, which could cause us to lose substantial revenues. Furthermore, our ability to attract new customers may be impaired if they elect not to engage us because they view our safety record as unacceptable. In addition, it is possible that we will experience multiple or particularly severe accidents in the future, causing our safety record to deteriorate. This may be more likely as we continue to grow, if we experience high employee turnover or labor shortage, or hire inexperienced personnel to bolster our staffing needs. 
+23 
+If we are unable to fully protect our intellectual property rights, we may suffer a loss in our competitive advantage or market share. 
+We do not have patents or patent applications relating to many of our key processes and technology. If we are not able to maintain the confidentiality of our trade secrets, or if our competitors are able to replicate our technology or services, our competitive advantage would be diminished. We also cannot ensure that any patents we may obtain in the future would provide us with any significant commercial benefit or would allow us to prevent our competitors from employing comparable technologies or processes. 
+We may be adversely affected by disputes regarding intellectual property rights of third parties. 
+Third parties from time to time may initiate litigation against us by asserting that the conduct of our business infringes, misappropriates or otherwise violates intellectual property rights. We may not prevail in any such legal proceedings related to such claims, and our products and services may be found to infringe, impair, misappropriate, dilute or otherwise violate the intellectual property rights of others. If we are sued for infringement and lose, we could be required to pay substantial damages and/or be enjoined from using or selling the infringing products or technology. Any legal proceeding concerning intellectual property could be protracted and costly regardless of the merits of any claim and is inherently unpredictable and could have a material adverse effect on our financial condition, regardless of its outcome. 
+If we were to discover that our technologies or products infringe valid intellectual property rights of third parties, we may need to obtain licenses from these parties or substantially re-engineer our products in order to avoid infringement. We may not be able to obtain the necessary licenses on acceptable terms, or at all, or be able to re-engineer our products successfully. If our inability to obtain required licenses for our technologies or products prevents us from selling our products, that could adversely impact our financial condition and results of operations. 
+Additionally, we currently license certain third party intellectual property in connection with our business, and the loss of any such license could adversely impact our financial condition and results of operations. 
+Seasonal weather conditions, natural disasters, public health crises, and other catastrophic events outside of our control could severely disrupt normal operations and harm our business. 
+Our operations are located in different regions of the United States and Canada. Some of these areas, including the DJ Basin, Powder River Basin, Williston Basin and our Canadian operations, are adversely affected by seasonal weather conditions, primarily in the winter and spring. However, as evidenced by the severe winter weather experienced in the southern United States and Canada during December 2022, weather-related hazards can exist in almost all the areas where we operate. During periods of heavy snow, ice or rain, we may be unable to move our equipment between locations or obtain adequate supplies of raw material or fuel, thereby reducing our ability to provide services and generate revenues. The exploration activities of our customers may also be affected during such periods of adverse weather conditions. Additionally, extended drought conditions in our operating regions could impact our ability or our customers’ ability to source sufficient water or increase the cost for such water. As a result, a natural disaster or inclement weather conditions could severely disrupt the normal operation of our business and adversely impact our financial condition and results of operations. Furthermore, if the area in which we operate or the market demand for oil and natural gas is affected by a public health crisis, such as the COVID-19 pandemic, or other similar catastrophic event outside of our control, our business and results of operations could be adversely impacted. 
+The sand mining operations are subject to a number of risks relating to the proppant industry. 
+We operate two sand mines in the Permian Basin. Sand mining operations are subject to risks normally encountered in the proppant industry. These risks include, among others: unanticipated ground, grade or water conditions; inability to acquire or maintain, or public or nongovernmental organization opposition to, necessary permits for mining, access or water rights; our ability to timely obtain necessary authorizations, approvals and permits from regulatory agencies (including environmental agencies, such as the FWS, where our operations in West Texas may be slowed, limited or halted due to conservation efforts targeted at the habitat of the dunes sagebrush lizard); pit wall or pond failures, and sluffing events; costs associated with environmental compliance or as a result of unauthorized releases into the environment; restrictions imposed on our operations related to the protection of natural resources, including plant and animal species; and reduction in the amount of water available for processing. Any of these risks could result in delays, limitations or cancellations in mining or processing activities, losses or possible legal liability. 
+Silica-related legislation, health issues and litigation could have a material adverse effect on our business, reputation or results of operations. 
+We are subject to laws and regulations relating to human exposure to crystalline silica. Historically, our environmental compliance costs with respect to existing crystalline silica requirements have not had a material adverse effect on our results of operations; however, federal regulatory authorities and analogous state agencies may continue to propose changes in their regulations regarding workplace exposure to crystalline silica, such as permissible exposure limits, required controls and personal protective equipment. We may not be able to comply with any new laws and regulations that are adopted, and any new 
+24 
+laws and regulations could have a material adverse effect on our operating results by requiring us to modify or cease our operations. 
+In addition, the inhalation of respirable crystalline silica is associated with the lung disease silicosis. There is evidence of an association between crystalline silica exposure or silicosis and lung cancer and a possible association with other diseases, including immune system disorders such as scleroderma. The actual or perceived health risks of handling hydraulic fracture sand could materially and adversely affect hydraulic fracturing service providers, including us, through reduced use of hydraulic fracture sand, the threat of product liability or employee lawsuits, increased scrutiny by federal, state and local regulatory authorities of us and our customers or reduced financing sources available to the industry. Furthermore, we may incur additional costs with respect to purchasing specialized equipment designed to reduce exposure to crystalline silica in connection with our operations or invest capital in new equipment. 
+We are subject to the Federal Mine Safety and Health Act of 1977, which imposes stringent health and safety standards on certain aspects of our operations. 
+Our operations are subject to the Federal Mine Safety and Health Act of 1977, as amended by the Mine Improvement and New Emergency Response Act of 2006, which imposes stringent health and safety standards on numerous aspects of mineral extraction and processing operations, including the training of personnel, operating procedures, operating equipment, and other matters. Our failure to comply with such standards, or changes in such standards or the re-interpretation or more stringent enforcement thereof, could have a material adverse effect on our business and financial condition or otherwise impose significant restrictions on its ability to conduct mineral extraction and processing operations. 
+The occurrence of explosive incidents could disrupt our operations and could adversely affect our business, financial condition and results of operations. 
+The wireline service we provide to oil and natural gas E&P customers involves the storage and handling of explosive materials. Despite the use of specialized facilities to store explosive materials and intensive employee training programs, the handling of explosive materials could result in incidents that temporarily shut down or otherwise disrupt our or E&P customers’ operations or could cause restrictions, delays or cancellations in the delivery of services. It is possible that an explosion could result in death or significant injuries to employees and other persons. Material property damage to us, E&P customers and third parties could also occur. Any explosive incident could expose us to adverse publicity or liability for damages or cause production restrictions, delays or cancellations, any of which developments could have a material adverse effect on our ability to compete, business, financial condition and results of operations. 
+The ongoing military action between Russia and Ukraine could adversely affect our business, financial condition and results of operations. 
+In February of 2022, Russian military forces invaded Ukraine, resulting in conflict and disruption in the region. The length, impact and outcome of the ongoing military conflict in Ukraine is highly unpredictable. This conflict has led and may continue to lead to significant market and other disruptions, including significant volatility in commodity prices and supply of energy resources, instability in financial markets, higher inflation, supply chain interruptions, political and social instability, changes in consumer or purchaser preferences as well as increase in cyberattacks and espionage. As a result of the invasion and ongoing military conflict, governments in the European Union, the United States, the United Kingdom, Switzerland and other countries have implemented and may implement additional sanctions, export controls or other measures against Russia, Belarus and other countries, regions, officials, individuals or industries in the respective territories. Such sanctions, and other measures, as well as the existing and potential further responses from Russia or other countries to such sanctions, supply chain disruptions, tensions and military actions, could adversely affect the global economy and financial markets and could adversely affect our business, financial condition and results of operations, and could also aggravate the other risk factors that we identify herein. 
+The choice of forum provisions in our charter and bylaws could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us. 
+Our Amended and Restated Certificate of Incorporation (as amended, the “Charter”) provides that unless the Company consents in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on behalf of the Company, (ii) any action asserting a claim of breach of a fiduciary duty owed by any director, officer, employee or agent of the Company to the Company or the Company’s stockholders, (iii) any action asserting a claim against the Company or any director or officer or other employee of the Company arising pursuant to any provision of the General Corporation Law of the State of Delaware, the Charter or the Company’s bylaws, or (iv) any action asserting a claim against the Company or any director or officer or other employee of the Company governed by the internal affairs doctrine, in each such case subject to Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Our Second Amended and Restated Bylaws (the “Bylaws”) further provide that unless the Company consents in writing to the selection of an alternative forum, the federal district courts of the United States of America will be the sole and exclusive forum for the resolution of any complaint asserting a cause of action arising under the Securities Act. Under the Securities Act, federal and 
+25 
+state courts have concurrent jurisdiction over all suits brought to enforce any duty or liability created by the Securities Act, and stockholders cannot waive compliance with the federal securities laws and the rules and regulations thereunder. Accordingly, there is uncertainty as to whether a court would enforce such a forum selection provision as written in connection with claims arising under the Securities Act. Any person or entity purchasing or otherwise acquiring any interest in shares of common stock of the Company will be deemed to have notice of and have consented to the provisions of our Charter and Bylaws related to choice of forum. The choice of forum provisions in our Charter and Bylaws may limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us. Additionally, the enforceability of choice of forum provisions in other companies’ governing documents has been challenged in legal proceedings, and it is possible that, in connection with any applicable action brought against us, a court could find the choice of forum provisions contained in our Charter and Bylaws to be inapplicable or unenforceable in such action. If so, we may incur additional costs associated with resolving such action in other jurisdictions, which could harm our business, results of operations, and financial condition. 
+There can be no assurance we will repurchase shares of our Class A Common Stock in any particular amounts. 
+The stock markets in general have experienced substantial price and trading fluctuations, which have resulted in volatility in the market prices of securities that often are unrelated or disproportionate to changes in operating performance. These broad market fluctuations may adversely affect the trading price of our Class A Common Stock. Price volatility over a given period may also cause the average price at which we repurchase our own Class A Common Stock to exceed the stock’s price at a given point in time. In addition, significant changes in the trading price of our Class A Common Stock and our ability to access capital on terms favorable to us could impact our ability to repurchase shares of our Class A Common Stock. The timing and amount of any repurchases will be determined by the Company’s management based on its evaluation of market conditions, capital allocation alternatives and other factors beyond our control. Our share repurchase program may be modified, suspended, extended or terminated by the Company at any time and without notice. 
+26 
+Item 1B. Unresolved Staff Comments 
+None. 
+Item 1C. Cybersecurity 
+Risk Management and Strategy 
+We recognize the critical importance of developing, implementing, and maintaining robust cybersecurity measures to safeguard our information systems and protect the confidentiality, integrity, and availability of our information systems and the data residing therein. 
+We have integrated cybersecurity risk management into our broader risk management framework to promote a company-wide practice of cybersecurity risk management. This integration ensures that cybersecurity considerations are part of our decision-making processes. Our cybersecurity risk management processes include technical security controls, policy enforcement mechanisms, monitoring systems, employee training, contractual arrangements, tools and related services from third-party providers, and management oversight to identify, assess, and manage material risks from cybersecurity threats. As part of our cybersecurity risk management process, we have conducted simulated cybersecurity incidents to ensure that we are prepared to respond to such an incident and to highlight any areas for potential improvement in our cyber incident preparedness. 
+Engagement of Third-Parties 
+Recognizing the complexity and evolving nature of cybersecurity threats, we may periodically engage a range of external experts, including cybersecurity assessors, consultants, and auditors to evaluate and test our information systems. These partnerships enable us to leverage specialized knowledge and insights, ensuring our cybersecurity strategies and processes generally follow industry-recognized standards and frameworks, and are compliant with applicable laws. 
+Oversight of Third-Party Risk 
+Because we are aware of the risks associated with third-party service providers, we implement processes to oversee and manage these risks. We conduct security assessments of critical third-party providers before engagement and maintain ongoing monitoring to ensure compliance with our cybersecurity standards. The monitoring includes regular assessments by our Chief Information Officer (“CIO”) and cybersecurity staff and advisors. This approach is designed to mitigate risks related to data breaches or other security incidents involving third-parties. 
+Risks from Cybersecurity Threats 
+We have experienced, and may in the future experience, directly or indirectly through our third-party service providers, cybersecurity incidents. While prior cybersecurity incidents have not had a material impact on us, future incidents could have a material impact on our business strategy, results of operations, and financial condition. For more information about the cybersecurity risks we face, see “We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss” in “Risk Factors” in Part I, Item 1A of this Annual Report on Form 10-K. 
+Cybersecurity Governance 
+Board of Directors Oversight 
+Our Board of Directors has designated the Audit Committee to oversee risk management associated with cybersecurity threats. The Audit Committee is comprised of board members with diverse expertise including risk management, technology, and finance, which we believe enables them to oversee cybersecurity risks. 
+Management’s Role 
+We have a cybersecurity risk management committee comprised of senior leadership, including our CIO. The committee evaluates and addresses cybersecurity risks in alignment with our business objectives and operational needs. The Company’s cybersecurity risk management committee is also responsible for informing the Audit Committee on cybersecurity risks. The committee provides briefings to the Audit Committee on at least a quarterly basis, performs a comprehensive annual review of cybersecurity risks and threats, and assesses and adjusts the Company’s processes to prevent, detect, mitigate, and remediate any such risks and threats. 
+Primary responsibility for assessing, monitoring and managing our cybersecurity risks rests with our CIO. With over 30 years of experience in the field of information systems and cybersecurity, our CIO brings a wealth of expertise to this role. His background includes extensive experience as an enterprise CIO and his in-depth knowledge and experience are instrumental in developing and executing our cybersecurity strategies. Our CIO oversees our governance programs, tests our compliance with standards, remediates known risks, and leads our employee training program as such items relate to cybersecurity. Our CIO 
+27 
+manages our cybersecurity risks with the help of key personnel overseeing cybersecurity, information technology networks and infrastructure, operational technology, and critical software applications. 
+Our CIO and information technology team are continually informed about the latest developments in cybersecurity, including potential threats and innovative risk management techniques. The CIO and information technology team implements and oversees processes for the regular monitoring of our information systems. This includes the deployment of advanced security measures and regular system audits to identify potential vulnerabilities. In the event of a cybersecurity incident, the CIO and information technology team are equipped with a well-defined incident response plan, which includes escalation to the cybersecurity risk management committee and the Audit Committee, and relevant public disclosure, as appropriate. 
+Item 2. Properties 
+Information regarding our properties is contained in “Item 1. Business” and is incorporated by reference herein. 
+Item 3. Legal Proceedings 
+The information with respect to this Item 3. Legal Proceedings is set forth in Note 15—Commitments & Contingencies in Part II, Item 8 of this Annual Report. 
+Item 4. Mine Safety Disclosures 
+Information concerning mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this Form 10-K. 
+28 
+PART II 
+Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+Market Information 
+On January 17, 2018, we consummated an initial public offering of our Class A Common Stock at a price of $17.00 per share. Our Class A Common Stock is traded on the NYSE under the symbol “LBRT.” Prior to that time, there was no public market for our Class A Common Stock. There is no public market for our Class B Common Stock. 
+Holders of our Common Stock 
+As of February 5, 2024, there were 17 stockholders of record of our Class A Common Stock and no stockholders of record of our Class B Common Stock. The number of record holders is based upon the actual number of holders registered on the books of the Company at such date and does not include holders of shares in “street names” or persons, partnerships, associations, corporations or other entities identified in security position listings maintained by depositories. 
+Dividend Policy 
+On October 18, 2022, the Company’s Board of Directors (the “Board”) reinstated quarterly dividends after they were suspended on April 2, 2020. The Company paid cash dividends of $0.05 per share of Class A Common Stock on December 20, 2022, March 20, 2023, June 20, 2023, and September 20, 2023 to stockholders of record as of December 6, 2022, March 6, 2023, June 6, 2023, and September 6, 2023, respectively. Additionally, the Company paid cash dividends of $0.07 per share of Class A Common Stock on December 20, 2023 to stockholders of record as of December 6, 2023. The declaration of dividends is subject to approval by the Board and to the Board’s continuing determination that such declaration of dividends is in the best interests of the Company and its stockholders. Future dividends may be adjusted at the Board’s discretion based on market conditions and capital availability. We are not required to pay dividends, and our stockholders will not be guaranteed, or have contractual or other rights to receive, dividends. 
+During the years ended December 31, 2023 and 2022, dividend payments totaled $37.5 million and $9.0 million, respectively. 
+Recent Sales of Unregistered Equity Securities 
+We had no sales of unregistered equity securities during the period covered by this Annual Report that were not previously reported in a Current Report on Form 8-K (or on Form 10-Q in lieu of Form 8-K). 
+Purchase of Equity Securities by the Issuer and Affiliated Purchasers 
+On July 25, 2022, the Board authorized and the Company announced a share repurchase program that allowed the Company to repurchase up to $250.0 million of the Company’s Class A Common Stock beginning immediately and continuing through and including July 31, 2024. On January 24, 2023, the Board authorized and the Company announced an increase to the share repurchase program that increased the Company’s cumulative repurchase authorization to $500.0 million. Furthermore, on January 23, 2024, the Board authorized and the Company announced an increase to the share repurchase program that increased the Company’s cumulative repurchase authorization to $750.0 million and extended the authorization through July 31, 2026. The shares may be repurchased from time to time in open market or privately negotiated transactions or by other means in accordance with applicable state and federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will be determined by the Company at its discretion and will depend on a variety of factors, including management’s assessment of the intrinsic value of the Company’s Class A Common Stock, the market price of the Company’s Class A Common Stock, general market and economic conditions, available liquidity, compliance with the Company’s debt and other agreements, applicable legal requirements, and other considerations. The exact number of shares to be repurchased by the Company is not guaranteed, and the program may be suspended, modified, or discontinued at any time without prior notice. The Company expects to fund any repurchases by using cash on hand, borrowings under the ABL Facility and expected free cash flow to be generated through the duration of the share repurchase program. 
+During the year ended December 31, 2023, the Company repurchased and retired 13,705,622 shares of Class A Common Stock for $203.1 million or $14.82 average price per share including commissions, under the share repurchase program. 
+As of December 31, 2023, $171.9 million remained authorized for future repurchases of Class A Common Stock under the share repurchase program and $417.5 million as of February 5, 2024, following the authorization increase. 
+29 
+The following sets forth information with respect to our repurchases of shares of Class A Common Stock during the three months ended December 31, 2023: 
+Period Total number of shares purchased Average price paid per share (2) Total number of shares purchased as part of publicly announced plans or programs (1) Approximate dollar value of shares that may yet be purchased under the plans or programs (1) 
+October 1, 2023 - October 31, 2023 351,632 19.91 351,632 203,968,909 
+November 1, 2023 - November 30, 2023 1,161,489 19.45 1,161,489 181,379,741 
+December 1, 2023 - December 31, 2023 518,615 18.22 518,615 171,930,956 
+Total 2,031,736 19.21 2,031,736 171,930,956 
+(1) On July 25, 2022, the Board authorized and the Company announced a share repurchase program that allowed the Company to repurchase up to $250.0 million of the Company’s Class A Common Stock beginning immediately and continuing through and including July 31, 2024. On January 24, 2023, the Board authorized and the Company announced an increase to the share repurchase program that increased the Company’s cumulative repurchase authorization to $500.0 million. Furthermore, on January 23, 2024, the Board authorized and the Company announced an increase to the share repurchase program that increased the Company’s cumulative repurchase authorization to $750.0 million and extended the authorization through July 31, 2026. The shares may be repurchased from time to time in open market or privately negotiated transactions or by other means in accordance with applicable state and federal securities laws. 
+(2) The average price paid per share of $19.21 was calculated excluding commissions. 
+30 
+Stock Performance Graph 
+The following graph and table compares the cumulative total return on our Class A Common Stock with the cumulative total return on the Standard & Poor’s 500 ® Index and the Philadelphia Oil Service Index, since December 31, 2018 and each annual period thereafter through December 31, 2023. The graph assumes that $100 was invested in our Class A Common Stock in each index on December 31, 2018 and that any dividends were reinvested on the last day of the month in which they were paid. The cumulative total return set forth is not necessarily indicative of future performance. 
+The following graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that we specifically incorporate it by reference into such filing. 
+For the Years Ended December 31 
+2018 2019 2020 2021 2022 2023 
+Liberty Energy Inc. $ 100.00 $ 87.20 $ 82.35 $ 77.48 $ 128.28 $ 147.43 
+Standard & Poor’s 500 ® Index 100.00 131.49 155.68 200.37 164.08 207.21 
+Philadelphia Oil Service Index 100.00 99.44 57.60 69.54 112.31 114.47 
+31 
+Item 6. [Reserved] 
+32 
+Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our audited consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a variety of risks and uncertainties, including those described in this Annual Report under “Cautionary Note Regarding Forward-Looking Statements” and “Item 1A. Risk Factors.” Except as required by law, we assume no obligation to update any of these forward-looking statements. This section of this Annual Report generally discusses 2023 and 2022 items and year-to-year comparisons between 2023 and 2022. For discussion of year ended December 31, 2021, as well as the year ended 2022 compared to the year ended December 31, 2021, refer to Part II, Item 7— Management’s Discussion and Analysis of Financial Condition and Results of Operations of our 2022 Annual Report. 
+Overview 
+The Company, together with its subsidiaries, is a leading integrated energy services and technology company focused on providing innovative hydraulic fracturing services and related technologies to onshore oil and natural gas E&P companies in North America. We offer customers hydraulic fracturing services, together with complementary services including wireline services, proppant delivery solutions, field gas processing and treating, CNG delivery, data analytics, related goods (including our sand mine operations), and technologies that will facilitate lower emission completions, thereby helping our customers reduce their emissions profile. We have grown from one active hydraulic fracturing fleet in December 2011 to over 40 active fleets as of December 31, 2023. We provide our services primarily in the Permian Basin, the Williston Basin, the Eagle Ford Shale, the Haynesville Shale, the Appalachian Basin (Marcellus Shale and Utica Shale), the Western Canadian Sedimentary Basin, the DJ Basin, and the Anadarko Basin. Our operations also extend to a few smaller shale basins, including the Uinta Basin, the Powder River Basin, and the San Juan Basin, as well as to two sand mines in the Permian Basin. 
+In early 2023, the Company launched Liberty Power Innovations LLC (“LPI”), an integrated alternative fuel and power solutions provider for remote applications. LPI provides CNG supply, field gas processing and treating, and well site fueling and logistics. LPI was formed with the initial focus on supporting Liberty’s transition towards our next generation digiFleets℠ and dual fuel fleets, as CNG fueling services are limited in the market, yet critical to maintaining highly efficient well site operations. Currently, LPI is primarily focused on supporting an industry transition to natural gas fueled technologies, serving as a key enabler of the next step of cost and emissions reductions in the oilfield. 
+We believe technical innovation and strong relationships with our customer and supplier bases distinguish us from our competitors and are the foundations of our business. We expect that E&P companies will continue to focus on technological innovation as completion complexity and fracture intensity of horizontal wells increases, particularly as customers are increasingly focused on reducing emissions from their completions operations. We remain proactive in developing innovative solutions to industry challenges, including developing: (i) our databases of U.S. unconventional wells to which we apply our proprietary multi-variable statistical analysis technologies to provide differential insight into fracture design optimization; (ii) our Liberty Quiet Fleet® design which significantly reduces noise levels compared to conventional hydraulic fracturing fleets; (iii) hydraulic fracturing fluid systems tailored to the specific reservoir properties in the basins in which we operate; (iv) our dual fuel dynamic gas blending (“DGB”) fleets that allow our engines to run diesel or a combination of diesel and natural gas, to optimize fuel use, reduce emissions and lower costs; (v) our digiFleets℠, comprising of digiFrac℠ and digiPrime℠ pumps, our innovative, purpose-built electric and hybrid frac pumps that have approximately 25% lower CO2e emission profile than the Tier IV DGB; (vi) our wet sand handling technology which eliminates the need to dry sand, enabling the deployment of mobile mines nearer to wellsites; and (vii) the launch of LPI to support the transition to our digiFleets as well as the transition to lower costs and emissions in the oilfield.. In addition, our integrated supply chain includes proppant, chemicals, equipment, natural gas fueling services, logistics and integrated software which we believe promotes wellsite efficiency and leads to more pumping hours and higher productivity throughout the year to better service our customers. In order to achieve our technological objectives, we carefully manage our liquidity and debt position to promote operational flexibility and invest in the business throughout the full commodity cycle in the regions we operate. 
+Recent Trends and Outlook 
+Entering 2024, we believe the fundamental outlook for the frac industry is stable. Service prices remain relatively steady as the industry’s supply of marketed fleets was right sized in response to lower completions activity. Many fleets exited the market both from accelerated attrition of older equipment and the deliberate idling of underutilized fleets to match customer demand. Operators continue to demand technologies that provide significant emissions reductions and fuel savings. 
+We believe E&P operators are now better served with larger, well capitalized integrated frac companies that can meet their technical demands and more complex needs. Engineering and innovation have led to rising shale productivity. Service companies have worked with operators to drive efficiencies, including faster completions, longer laterals and completion design 
+33 
+optimization, helping to offset the gradual decline in reservoir quality. The trend toward higher intensity fracs should raise demand for horsepower, which is expected to keep frac assets well utilized and drive service company returns during 2024. 
+Global oil and gas markets continue to contend with commodity price fluctuations, owing to developments in geopolitics, interest rates, and macroeconomic data. Range bound oil prices have not meaningfully changed E&P operator plans to deliver flat to modest production growth for 2024. Further, as North American oil production continues to reach record levels, more frac activity may be required during 2024 and future years to offset production decline. Near term natural gas markets are under pressure, but domestic power demand growth and increased liquified natural gas exports are currently expected to lead to improved conditions in 2025. 
+During the year 2023, the posted WTI price traded at an average of $77.58 per barrel (“Bbl”), as compared to the 2022 average of $94.90 per Bbl, and the 2021 average of $68.13 per Bbl. In addition, the average domestic onshore rig count for the United States and Canada was 781 rigs reported in the fourth quarter of 2023, down from the average in the fourth quarter of 2022 of 947, according to a report from Baker Hughes. 
+Acquisitions 
+On October 26, 2021, the Company acquired PropX in exchange for $11.9 million in cash, 3,405,526 shares of Class A Common Stock and 2,441,010 shares of Class B Common Stock, and 2,441,010 Liberty LLC Units, for total consideration of $103.0 million, based on the Class A Common Stock closing price of $15.58 on October 26, 2021, subject to customary post-closing adjustments. The Liberty LLC Units were redeemable for an equivalent number of shares of Class A Common Stock at any time, at the election of the shareholder. Founded in 2016, PropX is a leading provider of last-mile proppant delivery solutions including proppant handling equipment and logistics software across North America. PropX offers innovative environmentally friendly technology with optimized dry and wet sand containers and wellsite proppant handling equipment that drive logistics efficiency and reduce noise and emissions. We believe that PropX wet sand handling technology and logistics is a key enabler of the next step of cost and emissions reductions in the proppant industry. PropX also offers customers the latest real-time logistics software, PropConnect, as a hosted software as a service. 
+On April 6, 2023, LPI accelerated its expansion by acquiring Siren, a Permian focused integrated natural gas compression and CNG delivery business with 16 MMcf per day of natural gas compression capacity at two expandable Permian sites and transportation, logistics, and pressure reduction services, for cash consideration of $75.7 million, after post-closing adjustments and net of cash received. LPI currently delivers fuel to customers in both the drilling and completions markets, and its logistics system is designed to deliver CNG, renewable natural gas, or hydrogen to remote locations. We believe that the added natural gas compression capability is a key enabler of the next step of cost and emissions reductions in the industry. 
+Increase in Drilling Efficiency and Service Intensity of Completions 
+Over the past decade, E&P companies have focused on exploiting the vast resource potential available across many of North America’s unconventional resource plays through the application of horizontal drilling and completion technologies, including the use of multi-stage hydraulic fracturing, in order to increase recovery of oil and natural gas. As E&P companies have improved drilling and completion techniques to maximize return and efficiency, we believe that well economics have improved and unconventional oil and gas production is globally competitive. Liberty has been a significant partner with our customers in driving these continued improvements. 
+Improved drilling economics from horizontal drilling and greater rig efficiencies . Unconventional resources are increasingly being targeted through the use of horizontal drilling. According to Baker Hughes, as reported on January 26, 2024, horizontal rigs accounted for approximately 90% of all rigs drilling in the United States and Canada, up from 77% as of December 26, 2014. Over the past several years, North American E&P companies have benefited from improved drilling economics driven by technologies that reduce the number of days, and the cost, of drilling wells. North American drilling rigs have incorporated newer technologies, which allow them to drill rock more effectively and quickly, meaning each rig can drill more wells in a given period. These include improved drilling technologies and the incorporation of geosteering techniques which allow better placement of the wellbore. Drilling rigs have also incorporated new technology which allows fully assembled rigs to automatically “walk” from one location to the next without disassembling and reassembling the rig, greatly reducing the time it takes to move from one drilling location to the next. Today the majority of E&P drilling is on multi-well pad development, allowing efficient drilling of multiple horizontal wellbores from the same pad or location. The aggregate effect of these improved techniques and technologies have reduced the average days required to drill a well, which according to Lium Research, has dropped from 28 days in 2014 to 18 days in 2023. 
+Increased complexity and service intensity of horizontal well completions . In addition to improved rig efficiencies discussed above, E&P companies are also improving the subsurface techniques and technologies used to exploit unconventional resources. These improvements have targeted increasing the exposure of each wellbore to the reservoir by drilling longer horizontal lateral sections of the wellbore. To complete the well, hydraulic fracturing is applied in stages along the wellbore to break-up the resource so that oil and gas can be produced. As wellbores have increased in length, the number of frac stages and/ 
+34 
+or the number of perforation clusters (frac initiation points) has also increased. Further, E&P companies have improved production from each stage by applying increasing amounts of proppant in each stage, which better connects the well to the resource. The aggregate effect of increased number of stages and the increasing amount of proppant in each stage has greatly increased the total amount of proppant used in each well, according to Liberty’s FracTrends database, from six million pounds per well in 2014 to over 20 million pounds per well in 2023. Further efficiency gains are being sought via the “simul-frac,” “trimul-frac,” and other techniques. When compared to typical zipper-frac operations, these methods allow operators to complete a pad of wells quicker, thereby shortening the time from spud to first production. 
+These industry trends continue to keep our customers as important suppliers to the global oil and natural gas markets, which directly benefit hydraulic fracturing companies like us that have the expertise and innovative technology to effectively service today’s more efficient oilfield drilling activity and the increasing complexity and intensity of well completions. Given the expected returns that E&P companies have reported for new well development activities due to improved rig efficiencies and increasing well completion complexity and intensity, we expect these industry trends to continue. 
+How We Generate Revenue 
+We currently generate revenue through the provision of hydraulic fracturing, wireline services and goods, including sand from our Permian Basin sand mines, proppant delivery and logistics, and natural gas compression and delivery. These services and goods are provided under a variety of contract structures, primarily master service agreements (“MSAs”) as supplemented by statements of work, pricing agreements and specific quotes. A portion of our statements of work, under MSAs, include provisions that establish pricing arrangements for a period of up to approximately one year in length. However, the majority of those agreements provide for pricing adjustments based on market conditions. The majority of our services are priced based on prevailing market conditions and changing input costs at the time the services are provided, giving consideration to the specific requirements of the customer. 
+Our hydraulic fracturing and wireline services are performed in sections, which we refer to as fracturing stages. The estimated number of fracturing stages to be completed for a particular horizontal well is determined by the customer’s well completion design. We recognize revenue for each fracturing stage completed, although our revenue per completed fracturing stage varies depending on the actual volumes and types of proppants, chemicals, and fluid utilized for each fracturing stage. The number of fracturing stages that we are able to complete in a period is directly related to the number and utilization of our deployed fleets and size of stages. 
+Costs of Conducting Our Business 
+The principal expenses involved in conducting our business are direct cost of personnel, services, and materials used in the provision of services, general and administrative expenses, and depreciation, depletion, and amortization. A large portion of the costs we incur in our business are variable based on the number of hydraulic fracturing jobs and the requirements of services provided to our customers. We manage the level of our fixed costs, except depreciation, depletion, and amortization, based on several factors, including industry conditions and expected demand for our services. 
+How We Evaluate Our Operations 
+We use a variety of qualitative, operational and financial metrics to assess our performance. First and foremost, of these is a qualitative assessment of customer satisfaction because ensuring we are a valuable partner to our customers is the key to achieving our quantitative business metrics. Among other measures, management considers each of the following: 
+• Revenue; 
+• Operating Income; 
+• EBITDA; 
+• Adjusted EBITDA; 
+• Net Income; and 
+• Earnings per Share. 
+Revenue 
+We analyze our revenue by comparing actual revenue to our internal projections for a given period and to prior periods to assess our performance. 
+Operating Income 
+We analyze our operating income, which we define as revenues less direct operating expenses, depreciation, depletion, and amortization and general and administrative expenses, to measure our financial performance. We believe operating income is a meaningful metric because it provides insight on profitability and true operating performance based on the historical cost basis of our assets. We also compare operating income to our internal projections for a given period and to prior periods. 
+35 
+EBITDA and Adjusted EBITDA 
+We view EBITDA and Adjusted EBITDA as important indicators of performance. We define EBITDA as net income before interest, income taxes, and depreciation, depletion, and amortization. We define Adjusted EBITDA as EBITDA adjusted to eliminate the effects of items such as non-cash stock-based compensation, new fleet or new basin start-up costs, fleet lay-down costs, costs of asset acquisitions, gain or loss on the disposal of assets, provision for credit losses, transaction, severance, and other costs, the gain or loss on remeasurement of liability under our tax receivable agreements, the gain or loss on investments, and other non-recurring expenses that management does not consider in assessing ongoing performance. See “Comparison of Non-GAAP Financial Measures” for more information and a reconciliation of EBITDA and Adjusted EBITDA to net income, the most comparable financial measures calculated and presented in accordance with GAAP. 
+Results of Operations 
+Year Ended December 31, 2023, Compared to Year Ended December 31, 2022 
+Years Ended December 31, 
+Description 2023 2022 Change 
+(in thousands) 
+Revenue $ 4,747,928 $ 4,149,228 $ 598,700 
+Cost of services, excluding depreciation, depletion, and amortization shown separately 3,349,370 3,149,036 200,334 
+General and administrative 221,406 180,040 41,366 
+Transaction, severance, and other costs 2,053 5,837 (3,784) 
+Depreciation, depletion, and amortization 421,514 323,028 98,486 
+Gain on disposal of assets, net (6,994) (4,603) (2,391) 
+Operating income 760,579 495,890 264,689 
+Other expense, net 25,689 96,381 (70,692) 
+Net income before income taxes 734,890 399,509 335,381 
+Income tax expense (benefit) 178,482 (793) 179,275 
+Net income 556,408 400,302 156,106 
+Less: Net income attributable to non-controlling interests 91 700 (609) 
+Net income attributable to Liberty Energy Inc. stockholders $ 556,317 $ 399,602 $ 156,715 
+Revenue 
+Our revenue increased $598.7 million, or 14%, to $4.7 billion for the year ended December 31, 2023 compared to $4.1 billion for the year ended December 31, 2022. The increase in revenue was primarily attributable to higher service pricing, the reactivation of several fleets not fully reflected in the prior year, and an activity-driven increase in fleet efficiency commensurate with consistent demand for hydraulic fracturing services. 
+Cost of Services 
+Cost of services (excluding depreciation, depletion, and amortization) increased $200.3 million, or 6%, to $3.3 billion for the year ended December 31, 2023 compared to $3.1 billion for the year ended December 31, 2022. The increase in expense was primarily related to increases in materials and parts consumption and higher labor costs related to reactivated fleets and higher fleet efficiency during the year ended December 31, 2023. 
+General and Administrative 
+General and administrative expenses increased $41.4 million, or 23%, to $221.4 million for the year ended December 31, 2023 compared to $180.0 million for the year ended December 31, 2022 primarily related to increases from labor cost inflation, various corporate costs related to increased levels of activity, and increased share-based compensation expense related to Company performance. 
+36 
+Transaction, Severance and Other Costs 
+Transaction, severance and other costs decreased $3.8 million, or 65%, to $2.1 million for the year ended December 31, 2023 compared to $5.8 million for the year ended December 31, 2022. The costs incurred during the year ended December 31, 2023 primarily related to integration cost, legal, accounting, and other professional services provided in connection with the Siren Acquisition, while costs incurred during the year ended December 31, 2022 related to ongoing integration costs from prior period acquisitions. 
+Depreciation, Depletion, and Amortization 
+Depreciation, depletion, and amortization expense increased $98.5 million, or 30%, to $421.5 million for the year ended December 31, 2023 compared to $323.0 million for the year ended December 31, 2022. The increase in 2023 was due to additional equipment placed in service not fully reflected in the prior year, including the deployment of our digiTechnologies SM . 
+Gain on Disposal of Assets, net 
+The Company recorded a gain on disposal of assets, net of $7.0 million for the year ended December 31, 2023 compared to $4.6 million for the year ended December 31, 2022. The gain recognized in the year ended December 31, 2023 was primarily the result of the Company selling used field equipment and light duty trucks in a strong used vehicle and equipment market. The gain recognized in the year ended December 31, 2022 was a result of the sale of used field equipment and light duty trucks in a strong used vehicle and equipment market offset by a loss on sale of two non-strategic facilities acquired in a previous acquisition and a loss on plan of sale for two other non-strategic facilities. 
+Operating Income 
+The Company recorded operating income of $760.6 million for the year ended December 31, 2023 compared to $495.9 million for the year ended December 31, 2022. The change in operating income was primarily due to the $598.7 million, or 14%, increase in total revenue partially offset by a $334.0 million increase in total operating expenses, the significant components of which are discussed above. 
+Other Expense, net 
+Other expense, net decreased by $70.7 million to $25.7 million for the year ended December 31, 2023 compared to $96.4 million during the year ended December 31, 2022. Other expense, net is comprised of (gain) loss on remeasurement of liability under the TRAs, gain on investments, interest income—related party, and interest expense, net. As a result of the release of a valuation allowance on the U.S. net deferred tax assets the Company remeasured the liability under the TRAs resulting in a loss of $76.2 million, offset by a $2.5 million gain on investments during the year ended December 31, 2022, compared to a $1.8 million gain on remeasurement of the liability under the TRAs, due to a change in the overall expected effective tax rate, during the year ended December 31, 2023. Interest income—related party increased $2.0 million related to an extension of credit executed in December 2022 and extended in August 2023. These decreases were partially offset by the $6.8 million increase in interest expense, net as a result of new finance leases added and higher interest rates under the ABL Facility during the year ended December 31, 2023 compared to the year ended December 31, 2022. 
+Net Income Before Income Taxes 
+The Company realized net income before income taxes of $734.9 million for the year ended December 31, 2023 compared to $399.5 million for the year ended December 31, 2022. The increase in results was primarily attributable to the increase in revenues and the decrease in other expense, net, as noted above, partially offset by the increase in operating expenses discussed above. 
+Income Tax Expense (Benefit) 
+The Company recognized income tax expense of $178.5 million for the year ended December 31, 2023, an effective rate of 24.3%, compared to an income tax benefit of $0.8 million, an effective rate of (0.2)%, recognized for the year ended December 31, 2022. The increase in income tax expense was primarily attributable to the Company recording taxes on the Company ’ s U.S. activity during the year ended December 31, 2023, compared to the release of a valuation allowance on its U.S. net deferred tax assets during the year ended December 31, 2022 largely offsetting taxes on 2022 activity. 
+Comparison of Non-GAAP Financial Measures 
+We view EBITDA and Adjusted EBITDA as important indicators of performance. We define EBITDA as net income before interest, income taxes, and depreciation, depletion, and amortization. We define Adjusted EBITDA as EBITDA adjusted to eliminate the effects of items such as non-cash stock-based compensation, new fleet or new basin start-up costs, fleet lay-down costs, costs of asset acquisitions, gain or loss on the disposal of assets, bad debt reserves, transaction, severance, and other costs, the gain or loss on remeasurement of liability under our tax receivable agreements, the gain or loss on investments, and other non-recurring expenses that management does not consider in assessing ongoing performance. 
+37 
+Our board of directors, management, investors, and lenders use EBITDA and Adjusted EBITDA to assess our financial performance because it allows them to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure (such as varying levels of interest expense), asset base (such as depreciation, depletion, and amortization) and other items that impact the comparability of financial results from period to period. We present EBITDA and Adjusted EBITDA because we believe they provide useful information regarding the factors and trends affecting our business in addition to measures calculated under GAAP. 
+Note Regarding Non-GAAP Financial Measures 
+EBITDA and Adjusted EBITDA are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures will provide useful information to investors in assessing our financial performance and results of operations. Net income is the GAAP measure most directly comparable to EBITDA and Adjusted EBITDA. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as an analytical tool due to exclusion of some but not all items that affect the most directly comparable GAAP financial measures. You should not consider EBITDA or Adjusted EBITDA in isolation or as substitutes for an analysis of our results as reported under GAAP. Because EBITDA and Adjusted EBITDA may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. 
+The following tables present a reconciliation of EBITDA and Adjusted EBITDA to our net income, which is the most directly comparable GAAP financial measure for the periods presented: 
+Year Ended December 31, 2023, Compared to Year Ended December 31, 2022: EBITDA and Adjusted EBITDA 
+Years Ended December 31, 
+Description 2023 2022 Change 
+(in thousands) 
+Net income $ 556,408 $ 400,302 $ 156,106 
+Depreciation, depletion, and amortization 421,514 323,028 98,486 
+Interest expense, net 27,506 22,715 4,791 
+Income tax expense 178,482 (793) 179,275 
+EBITDA $ 1,183,910 $ 745,252 $ 438,658 
+Stock-based compensation expense 33,026 23,108 9,918 
+Fleet start-up and lay-down costs 2,082 17,007 (14,925) 
+Transaction, severance, and other costs 2,053 5,837 (3,784) 
+Gain on disposal of assets, net (6,994) (4,603) (2,391) 
+Provision for credit losses 808 — 808 
+(Gain) loss on remeasurement of liability under tax receivable agreements (1,817) 76,191 (78,008) 
+Gain on investments — (2,525) 2,525 
+Adjusted EBITDA $ 1,213,068 $ 860,267 $ 352,801 
+EBITDA was $1.2 billion for the year ended December 31, 2023 compared to $745.3 million for the year ended December 31, 2022. Adjusted EBITDA was $1.2 billion for the year ended December 31, 2023 compared to $860.3 million for the year ended December 31, 2022. The increases in EBITDA and Adjusted EBITDA primarily resulted from increased activity levels in 2023 as described above under the captions Revenue , Cost of Services, and General and Administrative Expenses for the Year Ended December 31, 2023, Compared to Year Ended December 31, 2022 . 
+Liquidity and Capital Resources 
+Overview 
+Our primary sources of liquidity consist of cash flows from operations and borrowings under our ABL Facility. We expect to fund operations and organic growth with these sources. We monitor the availability and cost of capital resources such as equity and debt financings that could be leveraged for current or future financial obligations including those related to acquisitions, capital expenditures, working capital, and other liquidity requirements. We may incur additional indebtedness or issue equity in order to meet our capital expenditure activities and liquidity requirements, as well as to fund growth opportunities that we pursue, including via acquisition. Our primary uses of capital have been capital expenditures to support organic growth and funding ongoing operations, including maintenance and fleet upgrades, as well as the repurchases of, and dividends on, shares of our Class A Common Stock. 
+38 
+Cash and cash equivalent s decreased by $6.9 million to $36.8 million as of December 31, 2023 compared to $43.7 million as of December 31, 2022, while working capital excluding cash and current liabilities under debt and lease arrangements increased $42.2 million. 
+On September 19, 2017, the Company entered into two credit agreements, (i) a revolving line of credit up to $250.0 million, subsequently increased to $525.0 million, see below, (the “ABL Facility”) and (ii) a $175.0 million term loan (the “Term Loan Facility”, and together with the ABL Facility the “Credit Facilities”). 
+As of December 31, 2023, we had $525.0 million committed under the ABL Facility, subject to certain borrowing base limitations based on a percentage of eligible accounts receivable and inventory available to finance working capital needs. As of December 31, 2023, the borrowing base was calculated to be $420.3 million, and the Company had $140.0 million outstanding, in addition to a letter of credit in the amount of $2.6 million, with $277.7 million of remaining availability. 
+On January 23, 2023, the Company entered into an Eighth Amendment to the ABL Facility (the “Eighth ABL Amendment”). The Eighth ABL Amendment amends certain terms, provisions and covenants of the ABL Facility, including, among other things: (i) increasing the maximum revolver amount from $425.0 million to $525.0 million (the “Upsized Revolver”); (ii) increasing the amount of the accordion feature from $75.0 million to $100.0 million; (iii) extending the maturity date from October 22, 2026 to January 23, 2028; (iv) modifying the dollar amounts of various credit facility triggers and tests proportionally to the Upsized Revolver; (v) permitting repayment under the Term Loan Facility prior to February 10, 2023; and (vi) increasing certain indebtedness, intercompany advance, and investment baskets. The Eighth ABL Amendment also includes an agreement from Wells Fargo Bank, National Association, as administrative agent, to release its second priority liens and security interests on all collateral that served as first priority collateral under the Term Loan Facility. This release was completed during the three months ended June 30, 2023. 
+Additionally, on January 23, 2023, the Company borrowed $106.7 million on the ABL Facility and used the proceeds to pay off and and terminate the Term Loan Facility. The amount paid included the balance of the Term Loan Facility upon payoff of $104.7 million, $0.9 million of accrued interest, and a $1.1 million prepayment premium. Additionally, there were $0.2 million in administrative agent and lender legal fees included in the pay off. 
+The ABL Facility contains covenants that restrict our ability to take certain actions. At December 31, 2023, we were in compliance with all debt covenants. 
+See Note 8 —Debt to the consolidated financial statements included in Part II, Item 8 of this Annual Report for further details. 
+We have no material off balance sheet arrangements as of December 31, 2023, except for purchase commitments under supply agreements as disclosed below under Note 15—Commitments & Contingencies in Part II, Item 8 of this Annual Report. As such, we are not materially exposed to any other financing, liquidity, market, or credit risk that could arise if we had engaged in such financing arrangements. 
+Share Repurchase Program 
+Under our share repurchase program, the Company was initially authorized to repurchase up to $250.0 million of outstanding Class A Common Stock through and including July 31, 2024. On January 24, 2023, the Board authorized and the Company announced an increase to the share repurchase program that increased the Company’s cumulative repurchase authorization to $500.0 million. Furthermore, on January 23, 2024, the Board authorized and the Company announced an increase to the share repurchase program that increased the Company’s cumulative repurchase authorization to $750.0 million and extended the authorization through July 31, 2026. Shares may be repurchased from time to time for cash in the open market transactions, through block trades, in privately negotiated transactions, through derivative transactions or by other means in accordance with applicable federal securities laws. The timing and the amount of repurchases will be determined by the Company at its discretion based on an evaluation of market conditions, capital allocation alternatives and other factors. The share repurchase program does not require us to purchase any dollar amount or number of shares of our Class A Common Stock and may be modified, suspended, extended or terminated at any time without prior notice. The Company expects to fund any repurchases by using cash on hand, borrowings under its revolving credit facility and expected free cash flow to be generated through the duration of the share repurchase program. During the year ended December 31, 2023, the Company repurchased and retired shares of Class A Common Stock for $203.1 million, under the share repurchase program. 
+39 
+Cash Flows 
+The following table summarizes our cash flows for the periods indicated: 
+Years Ended December 31, 
+Description 2023 2022 Change 
+(in thousands) 
+Net cash provided by operating activities 
+$ 1,014,583 $ 530,364 $ 484,219 
+Net cash used in investing activities 
+(672,328) (450,656) (221,672) 
+Net cash used in financing activities 
+(349,315) (55,770) (293,545) 
+Analysis of Cash Flow Changes Between the Years Ended December 31, 2023 and December 31, 2022 
+Operating Activities . Net cash provided by operating activities was $1.0 billion for the year ended December 31, 2023, compared to $530.4 million for the year ended December 31, 2022. The $484.2 million increase in cash from operating activities is primarily attributable to a $598.7 million increase in revenues, offset by a $280.7 million increase in cash operating expenses, interest expense, net, and income tax, and a $111.7 million decrease in cash from changes in working capital for the year ended December 31, 2023, compared to a $277.9 million decrease in cash from changes in working capital for the year ended December 31, 2022. 
+Investing Activities . Net cash used in investing activities was $672.3 million for the year ended December 31, 2023, compared to $450.7 million for the year ended December 31, 2022. Cash used in investing activities was higher during the year ended December 31, 2023, compared to the year ended December 31, 2022 as the Company continued to invest in equipment, including the new digiTechnologies SM suite, to support increased customer demand in next generation equipment and technology. Additionally, during the year ended December 31, 2023, the Company acquired Siren for $75.7 million in cash, net of cash received and normal post-closing matters, refer to Note 3—Acquisitions to the consolidated financial statements in Part II, Item 8 of this Annual Report for additional information related to the Siren Acquisition. 
+Financing Activities . Net cash used in financing activities was $349.3 million for the year ended December 31, 2023, compared to net cash used in financing activities of $55.8 million for the year ended December 31, 2022. The $293.5 million change in cash used in financing activities was primarily due to a $77.8 million increase in cash payments made in connection with share repurchases to $203.1 million for the year ended December 31, 2023, compared to $125.3 million for the year ended December 31, 2022. Additionally, cash paid for quarterly dividends increased $28.5 million to $37.7 million for the year ended December 31, 2023, compared to $9.2 million for the year ended December 31, 2022. Net pay down of $79.7 million on the Credit Facilities during the year ended December 31, 2023, including the $104.7 million pay off and termination of the Term Loan Facility, contributed to the financing cash outflow during the year ended December 31, 2023, compared to $95.3 million of net borrowings on the Credit Facilities for the year ended December 31, 2022. 
+40 
+Cash Requirements 
+Our material cash commitments consist primarily of obligations under long-term debt, TRAs, finance and operating leases for property and equipment, cash used to pay for repurchases of, and dividends on, shares of our Class A Common Stock, and purchase obligations as part of normal operations. Certain amounts included in our contractual obligations as of December 31, 2023 are based on our estimates and assumptions about these obligations, including pricing, volumes and duration. We have no material off balance sheet arrangements as of December 31, 2023, except for purchase commitments under supply agreements disclosed below. 
+See Note 8 —Debt to the consolidated financial statements included in Part II, Item 8 of this Annual Report for information regarding scheduled maturities of our long-term debt. See Note 6 —Leases to the consolidated financial statements included in Part II, Item 8 of this Annual Report for information regarding scheduled maturities of finance and operating leases. 
+As of December 31, 2023, the Company had expected cash payments for estimated interest on our finance lease obligations of $12.2 million payable within the next twelve months and $16.9 million payable thereafter. 
+On January 23, 2023, the Company borrowed $106.7 million on the ABL Facility and used the proceeds to pay off and terminate the Term Loan Facility. The balance of the Term Loan Facility at pay off was $104.7 million and included $0.9 million of accrued interest, and a $1.1 million prepayment premium. As such, the only outstanding debt facility as of December 31, 2023 was the ABL Facility. 
+As of December 31, 2023, the Company has purchase obligations of $143.9 million payable within the next twelve months and $13.0 million payable thereafter. See Note 15 —Commitments & Contingencies to the consolidated financial statements in Part II, Item 8 of this Annual Report for information regarding scheduled contractual obligations. 
+As of December 31, 2023, the Company expects to make a $5.2 million payment under the TRAs within the next twelve months. Future amounts payable under the TRAs are dependent upon future events. See No te 12 —Income Taxes to the consolidated financial statements included in Part II, Item 8 of this Annual Report for information regarding the TRAs. 
+During the year ended December 31, 2023, the Company expanded certain equipment lease facilities and entered into a new equipment lease facility with an additional lessor resulting in new finance lease obligations of $160.5 million. The term on these new leases range from two to five years. The Company had finance lease obligations of $51.1 million payable within the next twelve months and $151.6 million payable thereafter. 
+There have been no other material changes to cash requirements during the year ended December 31, 2023. 
+Other Factors Affecting Liquidity 
+Customer receivables: In line with industry practice, we typically bill our customers for services provided in arrears dependent upon contractual terms. In weak economic environments, we may experience delays in collection from our customers. In the past, we have experienced delays in customer payments and periodically agreed to extended payment terms, however, we have not experienced any material non-payment events. 
+Tax Receivable Agreements 
+In connection with the IPO, on January 17, 2018, the Company entered into two TRAs with the TRA Holders. The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that the Company actually recognizes (or is deemed to recognize in certain circumstances) in periods after the IPO as a result, as applicable to each of the TRA Holders, of (i) certain increases in tax basis that occur as a result of the Company’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holders’ Liberty LLC Units in connection with the IPO or pursuant to the exercise of the right of each Liberty Unit Holder (the “Redemption Right”), subject to certain limitations, to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units for, at Liberty LLC’s election, (A) shares of our Class A Common Stock at the specific redemption ratio or (B) an equivalent amount of cash, or, upon the exercise of the Redemption Right, the right of the Company (instead of Liberty LLC) to, for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder (the “Call Right”) for, at its election, (1) one share of Class A Common Stock or (2) an equivalent amount of cash, (ii) any net operating losses available to the Company as a result of the Corporate Reorganization, and (iii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRAs. On January 31, 2023, the last redemption of the Liberty LLC Units occurred. 
+41 
+With respect to obligations the Company expects to incur under the TRAs (except in cases where the Company elects to terminate the TRAs early, the TRAs are terminated early due to certain mergers, asset sales, or other changes of control or the Company has available cash but fails to make payments when due), generally the Company may elect to defer payments due under the TRAs if the Company does not have available cash to satisfy its payment obligations under the TRAs or if its contractual obligations limit its ability to make such payments. Any such deferred payments under the TRAs generally will accrue interest. In certain cases, payments under the TRAs may be accelerated and/or significantly exceed the actual benefits, if any, the Company realizes in respect of the tax attributes subject to the TRAs. The Company accounts for amounts payable under the TRAs in accordance with Accounting Standard Codification (“ASC”) Topic 450, Contingencies (“ASC Topic 450”). 
+If the Company experiences a change of control (as defined under the TRAs) or the TRAs otherwise terminate early, the Company’s obligations under the TRAs could have a substantial negative impact on its liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. There can be no assurance that we will be able to finance our obligations under the TRAs. 
+Income Taxes 
+The Company is a corporation and is subject to U.S. federal, state, and local income tax on its share of Liberty LLC’s taxable income. The Company is also subject to Canada federal and provincial income tax on its foreign operations. 
+The effective global income tax rate applicable to the Company for the year ended December 31, 2023 was 24.3% compared to (0.2)% for the year ended December 31, 2022. The Company’s effective tax rate is greater than the statutory federal income tax rate of 21.0% due to the Company’s Canadian operations, state income taxes in the states the Company operates, as well as nondeductible executive compensation. For 2022, the Company’s effective tax rate was less than the statutory federal income tax rate due to the Company releasing the valuation allowance recorded in a previous year on its U.S. net deferred tax assets as of December 31, 2022, primarily due to entering into a three-year cumulative pre-tax book income position and improved operating results. 
+The Company recognized income tax expense of $178.5 million and an income tax benefit of $0.8 million for the years ended December 31, 2023 and 2022, respectively. The Company’s effective tax rate can be volatile and may change with, among other things, the amount of jurisdiction pre-tax income or loss, ability to utilize foreign tax credits, excess tax benefits or deficiencies from share-based compensation and changes in tax laws in the jurisdictions that we operate. 
+Deferred income tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial reporting and tax bases of assets and liabilities, and are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. In the year ended December 31, 2023, the Company’s net deferred tax liabilities were $102.3 million. The Company has not recorded a valuation allowance against the deferred tax assets for the year ended December 31, 2023. 
+Refer to Note 12— Income Taxes to the consolidated financial statements in Part II, Item 8 of this Annual Report for additional information related to income tax expense. 
+Critical Accounting Policies and Estimates 
+The preparation of financial statements requires the use of judgments and estimates. Our critical accounting policies are described below to provide a better understanding of how we develop our assumptions and judgments about future events and related estimates and how they can impact our financial statements. A critical accounting estimate is one that requires our most difficult, subjective or complex estimates and assessments and is fundamental to our results of operations. 
+We base our estimates on historical experience and on various other assumptions we believe to be reasonable according to the current facts and circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. We believe the following are the critical accounting policies used in the preparation of our consolidated financial statements, as well as the significant estimates and judgments affecting the application of these policies. This discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included in Part II, Item 8 of this Annual Report. 
+Revenue Recognition: Revenue from hydraulic fracturing services is recognized as specific services are provided in accordance with contractual arrangements. If our assessment of performance under a particular contract change, our revenue and / or costs under that contract may change. In connection with ASC Topic 842 - Leases (“Topic 842”), the Company determined that certain of its service revenue contracts contain a lease component. The Company elected to adopt a practical expedient available to lessors, which allows the Company to combine the lease and service component for certain of the Company’s service contracts when the service component is the predominant component and continues to account for the combined component under ASC Topic 606 - Revenue from Contracts with Customers . 
+Inventory: Inventory consists of raw materials used in the hydraulic fracturing process, such as proppants, chemicals and field service equipment maintenance parts, and is stated at the lower of cost or net realizable value, determined using the 
+42 
+weighted average cost method. Net realizable value is determined based on our estimates of selling prices in the ordinary course of business, less reasonably predictable cost of completion, disposal, and transportation, each of which require us to apply judgment. 
+Property and Equipment: We calculate depreciation and amortization on our assets based on the estimated useful lives and estimated salvage values that we believe are reasonable. The estimated useful lives and salvage values are subject to key assumptions such as maintenance, utilization and job variation. These estimates may change due to a number of factors such as changes in operating conditions or advances in technology. 
+We incur maintenance costs on our major equipment. The determination of whether an expenditure should be capitalized or expensed requires management judgment in the application of how the costs benefit future periods, relative to our capitalization policy. Costs that either establish or increase the efficiency, productivity, functionality or life of a fixed asset are capitalized and depreciated over the remaining useful life of the asset. 
+Impairment of long-lived assets: Long-lived assets, such as property and equipment, right-of-use lease assets and intangible assets, are evaluated for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Possible indicators of impairment may include events or changes in circumstances affecting the manner in which the assets are being used, historical and estimated future profitability measures, and other adverse events or changes that could affect the value of the assets. If a triggering event is identified, recoverability is assessed using undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets. When alternative courses of action to recover the carrying amount of the asset group are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence, which require us to apply judgment. If the carrying amount of the asset is not recoverable based on its estimated undiscounted cash flows expected to result from the use and eventual disposition, an impairment loss is recognized in an amount by which its carrying amount exceeds its estimated fair value. The inputs used to determine such fair value are primarily based upon internally developed cash flow models. Our cash flow models are based on a number of estimates regarding future operations that may be subject to significant variability, are sensitive to changes in market conditions, and are reasonably likely to change in the future. 
+Leases: In accordance with ASC Topic 842, Leases , the Company determines if an arrangement is a lease at inception and evaluates identified leases for operating or finance lease treatment. Operating or finance lease right-of-use assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. We use our incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments. Lease terms may include options to renew; however, we typically cannot determine our intent to renew a lease with reasonable certainty at inception. 
+Tax Receivable Agreements: In connection with the IPO, on January 17, 2018, the Company entered into two TRAs with the TRA Holders. The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax that the Company actually realizes in periods after the IPO as a result of certain tax attributes applicable to each TRA Holder. The Company accounts for amounts payable under the TRAs in accordance with ASC Topic 450, Contingencies . 
+Share Repurchases: The Company accounts for the purchase price of repurchased Class A Common Stock in excess of par value ($0.01 per share of Class A Common Stock) as a reduction of additional paid-in capital, and will continue to do so until additional paid-in capital is reduced to zero. Thereafter, any excess purchase price will be recorded as a reduction to retained earnings. All Class A Common Stock shares repurchased to date have been retired upon repurchase. 
+43 
+Item 7A. Quantitative and Qualitative Disclosure about Market Risk 
+Industry Risk 
+The demand, pricing and terms for hydraulic fracturing services and related goods provided by us are largely dependent upon the level of drilling and completions activity in the U.S. oil and natural gas industry, as well as the available supply of hydraulic fracturing equipment. These activity levels are influenced by numerous factors over which we have no control, including, but not limited to: the supply of and demand for oil and natural gas; the level of prices, and expectations about future prices of oil and natural gas; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; the discovery rates of new oil and natural gas reserves; supply of actively marketed and staffed fracturing fleets; available rail and other transportation capacity; weather conditions; domestic and worldwide economic conditions; political instability in oil-producing countries; environmental regulations; technical advances affecting energy consumption; the price and availability of alternative fuels; the ability of E&P companies to raise equity capital and debt financing; and merger and divestiture activity among E&P companies. 
+The level of U.S. oil and natural gas drilling can be volatile. Expected trends in oil and natural gas production activities may not materialize and demand for our services may not reflect the level of activity in the industry. Any prolonged and substantial reduction in oil and natural gas prices would likely affect oil and natural gas production levels and therefore affect demand for our services. A material decline in oil and natural gas prices or U.S. activity levels could have a material adverse effect on our business, financial condition, results of operations and cash flows. 
+Interest Rate Risk 
+At December 31, 2023, we had $140.0 million of debt outstanding, with a weighted average interest rate of 7.6%. Interest is calculated under the terms of our ABL Facility based on our selection, from time to time, of one of the index rates available to us plus an applicable margin that varies based on certain factors. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources. Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the weighted average interest rate would be approximately $1.4 million per year. We do not currently have or intend to enter into any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness. 
+Commodity Price Risk 
+Our material and fuel purchases expose us to commodity price risk. Material costs primarily include inventory consumed while performing hydraulic fracturing services. Fuel costs consist of diesel fuel and natural gas used by trucks and other motorized equipment used for hydraulic fracturing services. At times, we have been able to pass along price increases for material costs and fuel costs to customers and conversely have been required to pass along price decreases for material costs to our customers, depending on market conditions. Further, we have purchase commitments with certain vendors to supply proppant inventory used in our operations at a fixed purchase price, including certain commitments which include minimum purchase obligations. Refer t o Note 15 — Commitments & Contingencies included in Part II, Item 8. of this Annual Report for further discussion regarding pur chase commitments. 
+Foreign Translation Risk 
+Our consolidated financial statements are expressed in U.S. dollars, but, effective January 1, 2021, a portion of our operations is conducted in a currency other than U.S. dollars. The Canadian dollar is the functional currency of the Company’s foreign subsidiary as it is the primary currency within the economic environment in which the subsidiary operates. Changes in the exchange rate can affect our revenues, earnings, and the carrying value of our assets and liabilities in our consolidated balance sheet, either positively or negatively. Adjustments resulting from the translation of the subsidiary’s financial statements are reported in other comprehensive income (loss). During the years ended December 31, 2023 and 2022, the Company recorded a foreign currency translation gain of $1.3 million and foreign currency translation loss of $7.1 million to comprehensive income (loss), respectively. 
+Item 8. Financial Statements and Supplementary Data 
+Our financial statements and supplementary data are included in this Annual Report beginning on page F-1 and incorporated by reference herein. 
+Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+None. 
+44 
+Item 9A. Controls and Procedures 
+Evaluation of Disclosure Controls and Procedures’ 
+In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2023 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures. 
+During the year ended December 31, 2023, we integrated accounting functions of the entity acquired in the Siren Acquisition on April 6, 2023. In connection with the integration, we updated documentation of our internal controls over financial reporting, as necessary, to reflect modifications to business processes and accounting procedures impacted. 
+There were no other changes to our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+See page F-1 for Management’s Report on Internal Control Over Financial Reporting and page F-4 for Report of Independent Registered Public Accounting Firm on its assessment of our internal control over financial reporting. 
+Item 9B. Other Information 
+On December 4, 2023 , Michael Stock , our Chief Financial Officer , adopted a trading plan intended to satisfy Rule 10b5-1(c) under the Securities Exchange Act of 1934, as amended, providing for the potential sale of up to 200,000 shares of our Class A common stock between March 4, 2024 and December 31, 2024, which shares were acquired by vesting of compensatory restricted stock units. 
+On December 13, 2023 , Chris Wright , our Chairman of the Board and Chief Executive Officer , adopted a trading plan intended to satisfy Rule 10b5-1(c) under the Securities Exchange Act of 1934, as amended, providing for the potential sale of up to 240,000 shares of our Class A common stock between March 18, 2024 and August 16, 2024, which shares were acquired by vesting of compensatory restricted stock units. 
+During the quarter ended December 31, 2023, none of our directors or Section 16 officers, other than Mr. Wright and Mr. Stock, informed us of the adoption , modification, or termination of any “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement” (in each case, as defined in Item 408(a) of Regulation S-K). 
+45 
+PART III 
+Item 10. Directors, Executive Officers and Corporate Governance 
+The information required by this item concerning our executive officers, directors and corporate governance is incorporated herein by reference to our definitive proxy statement for our 2023 annual meeting of stockholders, which will be filed with the SEC no later than 120 days after December 31, 2023, under the captions “Proposal 1 — Election of Directors,” “The Board and its Committees,” “Executive Officers” and “Delinquent Section 16(a) Reports.” 
+Item 11. Executive Compensation 
+The information required by this item concerning executive compensation is incorporated herein by reference to our definitive proxy statement for our 2023 annual meeting of stockholders, which will be filed with the SEC no later than 120 days after December 31, 2023, under the captions “The Board and its Committees,” “Compensation Discussion & Analysis,” “Compensation Committee Report,” “Executive Compensation Tables,” “Director Compensation,” and “CEO Pay Ratio,” except for the information required by Item 402(v) of Regulation S-K, which is specifically not incorporated by reference. 
+Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+The information required by this item concerning the security ownership of certain beneficial owners and management and related stockholder matters are incorporated herein by reference to our definitive proxy statement for our 2023 annual meeting of stockholders, which will be filed with the SEC no later than 120 days after December 31, 2023, under the captions “Security Ownership of Certain Beneficial Owners and Management” and “Equity Compensation Plan Information.” 
+Item 13. Certain Relationships and Related Transactions, and Director Independence 
+The information required by this item concerning certain relationships and related person transactions and director independence is incorporated herein by reference to our definitive proxy statement for our 2023 annual meeting of stockholders, which will be filed with the SEC no later than 120 days after December 31, 2023, under the captions “Certain Relationships and Related Party Transactions” and “the Board and its Committees.” 
+Item 14. Principal Accountant Fees and Services 
+The information required by this item concerning principal accounting fees and services is incorporated herein by reference to our definitive proxy statement for our 2023 annual meeting of stockholders, which will be filed with the SEC no later than 120 days after December 31, 2023, under the caption “Proposal 3 — Ratification of Appointment of the Company’s Independent Registered Public Accounting Firm.” 
+46 
+PART IV 
+Item 15. Exhibits and Financial Statement Schedules 
+(a) Financial Statements and Financial Statement Schedules 
+Refer to Index to Financial Statements on page 53. 
+All schedules are omitted as information required is inapplicable or the information is presented in the consolidated financial statements and the related notes. 
+(b) Exhibits 
+The documents listed in the Index to Exhibits are filed, furnished or incorporated by reference as part of this Annual Report, and such Index to Exhibits are incorporated herein by reference. 
+47 
+Item 16. Form 10-K Summary 
+None. 
+48 
+INDEX TO EXHIBITS 
+Exhibit 
+Number 
+Description 
+2.1 
+Master Reorganization Agreement, dated as of January 11, 2018, by and among Liberty Oilfield Services Inc., Liberty Oilfield Services Holdings LLC, Liberty Oilfield Services New HoldCo LLC, and the other parties named therein (2) 
+2.2 
+Master Transaction Agreement, dated as of August 31, 2020, by and among Schlumberger Technology Corporation, Schlumberger Canada Limited, Liberty Oilfield Services Holdings LLC, Liberty Canada Operations Inc. and Liberty Oilfield Services Inc. (10) 
+3.1 
+Amended and Restated Certificate of Incorporation of Liberty Oilfield Services Inc. (2) 
+3.2 
+Certificate of Amendment to Amended and Restated Certificate of Incorporation (13) 
+3.3 
+Second Amended and Restated Bylaws of Liberty Energy Inc., as amended effective January 24, 2023 (17) 
+4.1 
+Description of the Registrant’s Securities Registered pursuant to Section 12 of the Securities Exchange Act of 1934. * 
+10.1 
+Second Amended and Restated Limited Liability Company Operating Agreement of Liberty Oilfield Services New HoldCo LLC (2) 
+10.2 
+Form of Joinder Agreement to Second Amended and Restated Limited Liability Company Operating Agreement of Liberty Oilfield Services New HoldCo LLC (12) 
+10.3 
+Tax Receivable Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Inc., R/C Energy IV Direct Partnership, L.P., and R/C Energy IV Direct Partnership, L.P., as agent (2) 
+10.4 
+Tax Receivable Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Inc., and the other parties named therein (2) 
+10.5 
+Agent Designation Amendment to the Tax Receivable Agreement, dated as of February 22, 2022, by and among Liberty Oilfield Services Inc. and R/C Energy IV Direct Partnership, L.P. (15) 
+10.6 
+Liberty Oilfield Services Inc. Long Term Incentive Plan (2)† 
+10.7 
+Credit Agreement, dated September 19, 2017, by and among Wells Fargo Bank, National Association, as Administrative Agent, Wells Fargo Bank, National Association, JPMorgan Chase Bank, N.A. and Citibank, N.A., as Joint Lead Arrangers, Wells Fargo Bank, National Association, as Book Runner, JPMorgan Chase Bank, N.A. and Citibank, N.A., as Syndication Agents, the lender parties thereto, Liberty Oilfield Services Holdings LLC, as Parent and Liberty Oilfield Services LLC and LOS Acquisition Co I LLC, each as a Borrower (1) 
+10.8 
+Amendment and Parent Joinder to Credit Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Holdings LLC, Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto (3) 
+10.9 
+Second Amendment and Parent Joinder to Credit Agreement, dated March 21, 2018, by and among Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto (3) 
+10.10 
+Third Amendment to Credit Agreement, dated May 29, 2020, by and among Liberty Oilfield Services LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, and Wells Fargo Bank, National Association as Administrative Agent, and the lenders signatory thereto (8) 
+10.11 
+Fourth Amendment to Credit Agreement, dated August 12, 2020, by and among Liberty Oilfield Services LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto (9) 
+10.12 
+Consent and Fifth Amendment to Credit Agreement, dated December 29, 2020, by and among Liberty Oilfield Services LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, LOS Cibolo RE Investments, LLC, LOS Odessa RE Investments, LLC, ST9 Gas and Oil LLC, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto (11) 
+49 
+10.13 
+Sixth Amendment to Credit Agreement and Second Amendment to Guaranty and Security Agreement, dated October 22, 2021, by and among Liberty Oilfield Services LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New HoldCo LLC, R/C IV Non-U.S. LOS Corp, LOS Solar Acquisition LLC, Freedom Proppant LLC, LOS Kermit LLC, LOS Cibolo RE Investments, LLC, LOS Odessa RE Investments, LLC, ST9 Gas and Oil LLC, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto (12) 
+10.14 
+Increase Joinder and Seventh Amendment to Credit Agreement, dated July 18, 2022, by and among Liberty Oilfield Services LLC, Liberty Energy Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, Freedom Proppant LLC, LOS Kermit LLC, LOS Leasing Company LLC, LOS Cibolo RE Investments, LLC, LOS Odessa RE Investments, LLC, Proppant Express Solutions, LLC, ST9 Gas and Oil LLC, Well Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto. (14) 
+10.15 
+Eighth Amendment to Credit Agreement, dated January 23, 2023, by and among Liberty Oilfield Services LLC, Liberty Energy Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, Freedom Proppant LLC, LOS Kermit LLC, LOS Leasing Company LLC, LOS Cibolo RE Investments, LLC, LOS Odessa RE Investments, LLC, Proppant Express Solutions, LLC, ST9 Gas and Oil LLC, Well Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto. (17) 
+10.16 
+Joinder Agreement, dated December 31, 2021, by and among LOS Leasing Company LLC and Wells Fargo Bank, National Association, as Administrative Agent (16) 
+10.17 
+Liberty Oilfield Services 401(k) Savings Plan (11)† 
+10.18 
+Form of Restricted Stock Unit Grant Notice and Restricted Stock Unit Award Agreement under the Long Term Incentive Plan (4)† 
+10.19 
+Form of Restricted Stock Unit Grant Notice under the Long Term Incentive Plan (11)† 
+10.20 
+Form of Performance Restricted Stock Unit Grant Notice and Performance Restricted Stock Unit Agreement under the Liberty Oilfield Services Inc. Long Term Incentive Plan (5)† 
+10.21 
+Form of Change in Control Agreement (6)† 
+10.22 
+Form of Indemnification Agreement between the Company and each of its Directors and Executive Officers (8) 
+19.1 
+Insider Trading Policy * 
+21.1 
+List of subsidiaries of Liberty Energy Inc. * 
+23.1 
+Consent of Deloitte & Touche LLP * 
+31.1 
+Certification of Chief Executive Officer pursuant to Rule 13a-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 * 
+31.2 
+Certification of Chief Financial Officer pursuant to 13a-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 * 
+32.1 
+Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 ** 
+32.2 
+Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 ** 
+95 
+Mine Safety Disclosure * 
+97 
+Compensation Recovery Policy * 
+101.INS XBRL Instance Document * 
+101.SCH XBRL Taxonomy Extension Schema Document * 
+101.CAL XBRL Taxonomy Extension Calculation Linkbase Document * 
+101.DEF XBRL Taxonomy Extension Definition Linkbase Document * 
+101.LAB XBRL Taxonomy Extension Label Linkbase Document * 
+101.PRE XBRL Taxonomy Extension Presentation Linkbase Document * 
+104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)* 
+(1) Incorporated by reference to the exhibits to the registrant’s Registration Statement on Form S-1, as amended (SEC File 333-216050). 
+50 
+(2) Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on January 18, 2018. 
+(3) Incorporated by reference to the exhibits to the registrant’s Annual Report on Form 10-K, filed on March 23, 2018. 
+(4) Incorporated by reference to the exhibits to the registrant’s Quarterly Report on Form 10-Q, filed on May 10, 2018. 
+(5) Incorporated by reference to the exhibits to the registrant’s Quarterly Report on Form 10-Q, filed on May 3, 2019. 
+(6) Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on August 30, 2019. 
+(7) Incorporated by reference to the exhibits to the registrant’s Annual Report on Form 10-K, filed on February 27, 2020. 
+(8) Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on June 3, 2020. 
+(9) Incorporated by reference to the exhibits to the registrant’s Quarterly Report on Form 10-Q, filed on October 30, 2020. 
+(10) Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on September 1, 2020. 
+(11) Incorporated by reference to the exhibits to the registrant’s Annual Report on Form 10-K, filed on February 24, 2021. 
+(12) Incorporated by reference to the exhibits to the registrant’s Quarterly Report on Form 10-Q, filed on October 28, 2021. 
+(13) Incorporated by reference to the registrant’s Current Report on Form 8-K, filed on April 21, 2022. 
+(14) Incorporated by reference to the registrant’s Current Report on Form 8-K, filed on July 22, 2022. 
+(15) Incorporated by reference to the exhibits to the registrant’s Quarterly Report on Form 10-Q, filed on April 25, 2022. 
+(16) Incorporated by reference to the exhibits to the registrant’s Annual Report on Form 10-K, filed on February 22, 2022. 
+(17) Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on January 26, 2023. 
+* Filed herewith. 
+** Furnished herewith. 
+† Denotes a management contract or compensatory plan or arrangement. 
+51 
+SIGNATURES 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+LIBERTY ENERGY INC. 
+/s/ Christopher A. Wright 
+Date: February 8, 2024 By: 
+Christopher A. Wright 
+Chief Executive Officer 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+Signature Title Date 
+/s/ Christopher A. Wright 
+Chief Executive Officer and Director 
+(Principal Executive Officer) 
+February 8, 2024 
+Christopher A. Wright 
+/s/ Michael Stock 
+Chief Financial Officer 
+(Principal Financial Officer) 
+February 8, 2024 
+Michael Stock 
+/s/ Ryan T. Gosney Chief Accounting Officer February 8, 2024 
+Ryan T. Gosney (Principal Accounting Officer) 
+/s/ Simon Ayat Director February 8, 2024 
+Simon Ayat 
+/s/ Ken Babcock Director February 8, 2024 
+Ken Babcock 
+/s/ Peter A. Dea Director February 8, 2024 
+Peter A. Dea 
+/s/ William F. Kimble Director February 8, 2024 
+William F. Kimble 
+/s/ James R. McDonald Director February 8, 2024 
+James R. McDonald 
+/s/ Gale A. Norton Director February 8, 2024 
+Gale A. Norton 
+/s/ Audrey Robertson Director February 8, 2024 
+Audrey Robertson 
+/s/ Cary D. Steinbeck Director February 8, 2024 
+Cary D. Steinbeck 
+52 
+Index to Financial Statements 
+Liberty Energy Inc. 
+Management’s Report on Internal Control Over Financial Reporting 
+F-1 
+Reports of Independent Registered Public Accounting Firm (PCAOB ID No. 34 ) 
+F- 2 
+Consolidated Balance Sheets as of December 31, 202 3 and 202 2 
+F- 5 
+Consolidated Statements of Operations for the Years Ended December 31, 202 3 , 202 2 , and 202 1 
+F- 6 
+Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 202 3 , 202 2 , and 202 1 
+F-7 
+Consolidated Statements of Changes in Equity for the Years Ended December 31, 202 3 and 202 2 
+F- 8 
+Consolidated Statements of Cash Flows for the Years Ended December 31, 202 3 , 202 2 , and 202 1 
+F- 9 
+Notes to Consolidated Financial Statements 
+F- 11 
+53 
+MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING 
+The management of Liberty Energy Inc. is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act. 
+Internal control over financial reporting, no matter how well designed, has inherent limitations. Therefore, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements. Further, because of changes in conditions, effectiveness of internal controls over financial reporting may vary over time. 
+Under the supervision of, and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2023 based on the framework and criteria established in Internal Control-Integrated Framework (2013) , issued by the Committee of Sponsoring Organizations of the Treadway Commission. 
+Based on this evaluation, management concluded that, as of December 31, 2023, our internal control over financial reporting was effective. 
+The effectiveness of Liberty Energy Inc. ’ s internal control over financial reporting as of December 31, 2023 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report that is included herein. 
+F-1 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the stockholders and the Board of Directors of Liberty Energy Inc. 
+Opinion on the Financial Statements 
+We have audited the accompanying consolidated balance sheets of Liberty Energy Inc. and subsidiaries (the "Company") as of December 31, 2023 and 2022, the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows, for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America. 
+We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 8, 2024, expressed an unqualified opinion on the Company’s internal control over financial reporting. 
+Basis for Opinion 
+These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. 
+Critical Audit Matter 
+The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. 
+Property and equipment — Determination of Impairment Indicators — Refer to Note 2 to the financial statements 
+Critical Audit Matter Description 
+As described in Note 2 to the consolidated financial statements, the Company assesses its property and equipment for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable, referred to as triggering events. Possible indications of impairment may include events or changes in circumstances affecting the manner in which the assets are being used, historical and estimated future profitability measures, and other adverse events or changes that could affect the value of the assets. If a triggering event is identified, the Company evaluates its property and equipment for impairment by comparing undiscounted future cash flows expected to be generated over the life of the assets to the respective carrying amount. If the carrying amount of the assets exceeds the undiscounted future cash flows, an analysis is performed to determine the fair value of the assets. 
+We identified the evaluation of property and equipment for impairment triggering events as a critical audit matter. The Company makes assumptions to evaluate property and equipment for possible indications of impairment. Changes in these assumptions could have a significant impact on the assets identified for further analysis. For the year ended December 31, 2023, the Company concluded that no triggering events had occurred, and no impairment was recognized. 
+Given the Company’s evaluation of possible indications of impairment of property and equipment requires management to make assumptions, performing audit procedures to evaluate whether management appropriately identified events or 
+F-2 
+changes in circumstances indicating that the carrying amounts of property and equipment may not be recoverable required a high degree of auditor judgment. 
+How the Critical Audit Matter Was Addressed in the Audit 
+Our audit procedures related to the evaluation of property and equipment for possible indications of impairment included the following, among others: 
+• We tested the effectiveness of internal controls over financial reporting related to management’s evaluation of impairment. This included controls related to the Company’s process to identify and evaluate triggering events, including the consideration of forecasted to actual results and market conditions in determining whether a triggering event exists. 
+• We considered the completeness of management’s identification of impairment indicators by: 
+◦ Considering industry and analysts reports and the impact of macroeconomic factors, such as adverse changes in the regulatory environment, legislation or other factors that may represent impairment indicators not previously contemplated in management’s analysis. 
+◦ Inspecting minutes of the board of directors and committees to understand if there were factors that would represent potential impairment indicators for property and equipment. 
+◦ Developing an independent expectation of impairment indicators and compared such expectation to management’s analysis. 
+• We evaluated management’s determination of the property and equipment’s estimated useful life as well as any factors impacting the useful life, such as plans to sell and any relevant purchase and sales agreements for assets sold. 
+/s/ DELOITTE & TOUCHE LLP 
+Denver, CO 
+February 8, 2024 
+We have served as the Company’s auditor since 2016. 
+F-3 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the stockholders and the Board of Directors of Liberty Energy Inc. 
+Opinion on Internal Control over Financial Reporting 
+We have audited the internal control over financial reporting of Liberty Energy Inc. (the “Company”) as of December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO. 
+We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2023, of the Company and our report dated February 8, 2024, expressed an unqualified opinion on those financial statements. 
+Basis for Opinion 
+The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+Definition and Limitations of Internal Control over Financial Reporting 
+A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+/s/ DELOITTE & TOUCHE LLP 
+Denver, Colorado 
+February 8, 2024 
+F-4 
+LIBERTY ENERGY INC. 
+Consolidated Balance Sheets 
+As of December 31, 2023 and 2022 
+(Dollars in thousands, except share data) 
+2023 2022 
+Assets 
+Current assets: 
+Cash and cash equivalents $ 36,784 $ 43,676 
+Accounts receivable, net of allowances for credit losses of $ 939 and $ 884 , respectively 
+381,185 410,308 
+Accounts receivable—related party 17,345 — 
+Unbilled revenue (including amounts from related parties of $ 13,379 and $ 13,854 , respectively) 
+188,940 175,704 
+Inventories 205,865 214,454 
+Prepaid and other current assets 124,135 112,531 
+Total current assets 954,254 956,673 
+Property and equipment, net 1,645,368 1,362,364 
+Finance lease right-of-use assets 182,319 41,771 
+Operating lease right-of-use assets 92,640 97,232 
+Other assets (including amounts from related parties of $ 14,785 and $ 11,799 , respectively) 
+158,976 105,300 
+Deferred tax asset — 12,592 
+Total assets $ 3,033,557 $ 2,575,932 
+Liabilities and Equity 
+Current liabilities: 
+Accounts payable (including payables to related parties of $ 0 and $ 2,629 , respectively) 
+$ 293,733 $ 326,818 
+Accrued liabilities (including amounts due to related parties of $ 0 and $ 730 , respectively) 
+261,066 280,678 
+Income taxes payable 12,060 2,294 
+Current portion of payable pursuant to tax receivable agreements 5,170 — 
+Current portion of long-term debt, net of discount of $ 0 and $ 730 , respectively 
+— 1,020 
+Current portion of finance lease liabilities 39,867 11,393 
+Current portion of operating lease liabilities 27,528 27,294 
+Total current liabilities 639,424 649,497 
+Long-term debt, net of discount of $ 0 and $ 540 , respectively, less current portion 
+140,000 217,426 
+Deferred tax liability 102,340 1,044 
+Payable pursuant to tax receivable agreements 112,471 118,874 
+Noncurrent portion of finance lease liabilities 133,654 22,490 
+Noncurrent portion of operating lease liabilities 64,260 69,295 
+Total liabilities 1,192,149 1,078,626 
+Commitments & contingencies (Note 15) 
+Stockholders’ equity: 
+Preferred Stock, $ 0.01 par value, 10,000 shares authorized and none issued and outstanding 
+— — 
+Common Stock: 
+Class A, $ 0.01 par value, 400,000,000 shares authorized and 166,610,199 issued and outstanding as of December 31, 2023 and 178,753,125 issued and outstanding as of December 31, 2022 
+1,666 1,788 
+Class B, $ 0.01 par value, 400,000,000 shares authorized and none issued and outstanding as of December 31, 2023 and 250,222 issued and outstanding as of December 31, 2022 
+— 3 
+Additional paid in capital 1,093,498 1,266,097 
+Retained earnings 752,328 234,525 
+Accumulated other comprehensive loss ( 6,084 ) ( 7,396 ) 
+Total stockholders’ equity 1,841,408 1,495,017 
+Non-controlling interest — 2,289 
+Total equity 1,841,408 1,497,306 
+Total liabilities and equity $ 3,033,557 $ 2,575,932 
+See Notes to Consolidated Financial Statements. 
+F-5 
+LIBERTY ENERGY INC. 
+Consolidated Statements of Operations 
+For the Years Ended December 31, 2023, 2022, and 2021 
+(In thousands, except per share data) 
+2023 2022 2021 
+Revenue: 
+Revenue $ 4,533,048 $ 4,000,780 $ 2,447,140 
+Revenue—related parties 214,880 148,448 23,642 
+Total revenue 4,747,928 4,149,228 2,470,782 
+Operating costs and expenses: 
+Cost of services (exclusive of depreciation, depletion, and amortization shown separately below) 3,349,370 3,149,036 2,249,926 
+General and administrative 221,406 180,040 123,406 
+Transaction, severance, and other costs 2,053 5,837 15,138 
+Depreciation, depletion, and amortization 421,514 323,028 262,757 
+(Gain) loss on disposal of assets, net ( 6,994 ) ( 4,603 ) 779 
+Total operating costs and expenses 3,987,349 3,653,338 2,652,006 
+Operating income (loss) 760,579 495,890 ( 181,224 ) 
+Other expense (income): 
+(Gain) loss on remeasurement of liability under tax receivable agreements ( 1,817 ) 76,191 ( 19,039 ) 
+Gain on investments — ( 2,525 ) — 
+Interest income—related party ( 1,987 ) — — 
+Interest expense, net 29,493 22,715 15,603 
+Total other expense (income), net 25,689 96,381 ( 3,436 ) 
+Net income (loss) before income taxes 734,890 399,509 ( 177,788 ) 
+Income tax expense (benefit) 178,482 ( 793 ) 9,216 
+Net income (loss) 556,408 400,302 ( 187,004 ) 
+Less: Net income (loss) attributable to non-controlling interests 91 700 ( 7,760 ) 
+Net income (loss) attributable to Liberty Energy Inc. stockholders $ 556,317 $ 399,602 $ ( 179,244 ) 
+Net income (loss) attributable to Liberty Energy Inc. stockholders per common share: 
+Basic $ 3.24 $ 2.17 $ ( 1.03 ) 
+Diluted $ 3.15 $ 2.11 $ ( 1.03 ) 
+Weighted average common shares outstanding: 
+Basic 171,845 184,334 174,019 
+Diluted 176,360 189,349 174,019 
+See Notes to Consolidated Financial Statements. 
+F-6 
+LIBERTY ENERGY INC. 
+Consolidated Statements of Comprehensive Income (Loss) 
+For the Years Ended December 31, 2023, 2022, and 2021 
+(In thousands) 
+2023 2022 2021 
+Net income (loss) $ 556,408 $ 400,302 $ ( 187,004 ) 
+Other comprehensive income (loss) 
+Foreign currency translation adjustments 1,313 ( 7,097 ) ( 102 ) 
+Comprehensive income (loss) $ 557,721 $ 393,205 $ ( 187,106 ) 
+Comprehensive income (loss) attributable to non-controlling interest 92 693 ( 7,556 ) 
+Comprehensive income (loss) attributable to Liberty Energy Inc. $ 557,629 $ 392,512 $ ( 179,550 ) 
+See Notes to Consolidated Financial Statements. 
+F-7 
+LIBERTY ENERGY INC. 
+Consolidated Statements of Changes in Equity 
+For the Years Ended December 31, 2023 and 2022 
+(In thousands, except per share and per unit data) 
+Shares of Class A Common Stock Shares of Class B Common Stock Class A Common Stock, Par Value Class B Common Stock, Par Value Additional Paid in Capital Retained Earnings Accumulated Other Comprehensive Loss Total Stockholders’ equity Non-controlling Interest Total Equity 
+Balance—December 31, 2022 178,753 250 $ 1,788 $ 3 $ 1,266,097 $ 234,525 $ ( 7,396 ) $ 1,495,017 $ 2,289 $ 1,497,306 
+Exchange of Class B Common Stock for Class A Common Stock 250 ( 250 ) 3 ( 3 ) 2,360 — — 2,360 ( 2,360 ) — 
+Offering Costs — — — — ( 223 ) — — ( 223 ) — ( 223 ) 
+Deferred tax and tax receivable agreements impact of Liberty LLC merger into the Company — — — — 6,681 — — 6,681 — 6,681 
+$ 0.22 /share of Class A Common Stock dividend 
+— — — — — ( 38,514 ) — ( 38,514 ) — ( 38,514 ) 
+Share repurchases ( 13,706 ) — ( 137 ) — ( 202,940 ) — — ( 203,077 ) ( 23 ) ( 203,100 ) 
+Excise tax on share repurchases — — — — ( 1,855 ) — — ( 1,855 ) — ( 1,855 ) 
+Stock-based compensation expense — — — — 33,023 — — 33,023 3 33,026 
+Vesting of restricted stock units 1,313 — 12 — ( 11 ) — — 1 ( 1 ) — 
+Tax withheld on vesting of restricted stock units — — — — ( 9,634 ) — — ( 9,634 ) — ( 9,634 ) 
+Currency translation adjustment — — — — — — 1,312 1,312 1 1,313 
+Net income — — — — — 556,317 — 556,317 91 556,408 
+Balance—December 31, 2023 166,610 — $ 1,666 $ — $ 1,093,498 $ 752,328 $ ( 6,084 ) $ 1,841,408 $ — $ 1,841,408 
+Shares of Class A Common Stock Shares of Class B Common Stock Class A Common Stock, Par Value Class B Common Stock, Par Value Additional Paid in Capital (Accumulated Deficit) Retained Earnings Accumulated Other Comprehensive Loss Total Stockholders’ equity Non-controlling Interest Total Equity 
+Balance - December 31, 2021 183,385 2,632 $ 1,834 $ 26 $ 1,367,642 $ ( 155,954 ) $ ( 306 ) $ 1,213,242 $ 17,197 $ 1,230,439 
+Exchange of Class B Common Stock for Class A Common Stock 2,382 ( 2,382 ) 23 ( 23 ) 16,495 — — 16,495 ( 16,495 ) — 
+Offering Costs — — — — ( 79 ) — — ( 79 ) — ( 79 ) 
+Effect of exchange on deferred tax asset, net of liability under tax receivable agreements — — — — 3,757 — — 3,757 — 3,757 
+Deferred tax impact of ownership changes from issuance of Class A Common Stock — — — — ( 9,879 ) — ( 9,879 ) — ( 9,879 ) 
+$ 0.05 /share of Class A Common Stock dividend 
+— — — — — ( 9,123 ) — ( 9,123 ) — ( 9,123 ) 
+$ 0.05 /unit distributions to non-controlling unitholders 
+— — — — — — — — ( 13 ) ( 13 ) 
+Other distributions and advance payments to non-controlling interest unitholders — — — — — — — — 920 920 
+Share repurchases ( 8,186 ) — ( 81 ) — ( 125,134 ) — — ( 125,215 ) ( 98 ) ( 125,313 ) 
+Stock-based compensation expense — — — — 23,003 — — 23,003 105 23,108 
+Vesting of restricted stock units 1,172 — 12 — 8 — — 20 ( 20 ) — 
+Tax withheld on vesting of restricted stock units ( 9,716 ) ( 9,716 ) ( 9,716 ) 
+Currency translation adjustment — — — — — — ( 7,090 ) ( 7,090 ) ( 7 ) ( 7,097 ) 
+Net income — — — — — 399,602 — 399,602 700 400,302 
+Balance - December 31, 2022 178,753 250 $ 1,788 $ 3 $ 1,266,097 $ 234,525 $ ( 7,396 ) $ 1,495,017 $ 2,289 $ 1,497,306 
+See Notes to Consolidated Financial Statements. 
+F-8 
+LIBERTY ENERGY INC. 
+Consolidated Statements of Cash Flows 
+For the Years Ended December 31, 2023, 2022, and 2021 
+(Dollars in thousands) 
+2023 2022 2021 
+Cash flows from operating activities: 
+Net income (loss) $ 556,408 $ 400,302 $ ( 187,004 ) 
+Adjustments to reconcile net income (loss) to net cash provided by operating activities: 
+Depreciation, depletion, and amortization 421,514 323,028 262,757 
+(Gain) loss on disposal of assets, net ( 6,994 ) ( 4,603 ) 779 
+Stock-based compensation expense 33,026 23,108 19,946 
+Deferred income tax expense (benefit) 120,312 ( 12,472 ) 5,079 
+(Gain) loss on remeasurement of liability under tax receivable agreements ( 1,817 ) 76,191 ( 19,039 ) 
+Other non-cash items, net 7,111 5,461 6,605 
+Changes in operating assets and liabilities: 
+Accounts receivable and unbilled revenue 19,612 ( 166,605 ) ( 90,142 ) 
+Accounts receivable and unbilled revenue—related party ( 19,855 ) ( 25,522 ) — 
+Inventories ( 114 ) ( 84,989 ) ( 24,612 ) 
+Other assets ( 66,182 ) ( 56,161 ) ( 30,955 ) 
+Prepaid and other current assets—related party — — 24,708 
+Accounts payable and accrued liabilities ( 45,133 ) 57,203 164,036 
+Accounts payable and accrued liabilities—related party — ( 1,864 ) 3,874 
+Initial payment of operating lease liability ( 3,305 ) ( 2,713 ) ( 565 ) 
+Net cash provided by operating activities 
+1,014,583 530,364 135,467 
+Cash flows from investing activities: 
+Purchases of property and equipment and construction in-progress ( 603,298 ) ( 451,905 ) ( 198,794 ) 
+Investment in sand logistics — ( 7,415 ) ( 13,106 ) 
+Investment in Tamboran Resources Ltd. and Oklo Inc. (2023) and Fervo Energy Company and Natron Energy, Inc. (2022) ( 20,283 ) ( 15,000 ) — 
+Acquisition of Siren Energy, net of cash received ( 75,656 ) — — 
+Proceeds from sales of assets 26,909 23,664 25,406 
+Net cash used in investing activities 
+( 672,328 ) ( 450,656 ) ( 186,494 ) 
+Cash flows from financing activities: 
+Proceeds from borrowings on line-of-credit 1,153,000 713,000 274,000 
+Repayments of borrowings on line-of-credit ( 1,128,000 ) ( 616,000 ) ( 256,000 ) 
+Repayments of borrowings on term loan ( 104,716 ) ( 1,750 ) ( 1,750 ) 
+Payments on finance lease obligations ( 17,392 ) ( 6,947 ) ( 7,363 ) 
+Class A Common Stock dividends and dividend equivalents upon restricted stock vesting ( 37,684 ) ( 9,164 ) ( 168 ) 
+Per unit distributions to non-controlling interest unitholders — ( 13 ) — 
+Other distributions and advance payments to non-controlling interest unitholders — 920 1,372 
+Share repurchases ( 203,100 ) ( 125,313 ) — 
+Tax withholding on restricted stock units ( 9,634 ) ( 9,716 ) ( 3,585 ) 
+Payment of equity issuance costs ( 223 ) ( 79 ) ( 1,330 ) 
+Payments of debt issuance costs ( 1,566 ) ( 708 ) ( 3,120 ) 
+Net cash (used in) provided by financing activities 
+( 349,315 ) ( 55,770 ) 2,056 
+Net (decrease) increase in cash and cash equivalents ( 7,060 ) 23,938 ( 48,971 ) 
+Translation effect on cash 168 ( 260 ) ( 9 ) 
+Cash and cash equivalents—beginning of period 43,676 19,998 68,978 
+Cash and cash equivalents—end of period $ 36,784 $ 43,676 $ 19,998 
+F-9 
+LIBERTY ENERGY INC. 
+Consolidated Statements of Cash Flows (cont.) 
+For the Years Ended December 31, 2023, 2022, and 2021 
+(Dollars in thousands) 
+2023 2022 2021 
+Supplemental disclosure of cash flow information: 
+Net cash paid (received) for income taxes $ 66,685 $ 10,744 $ ( 9,481 ) 
+Cash paid for interest $ 26,651 $ 20,310 $ 13,268 
+Non-cash investing and financing activities: 
+Capital expenditures included in accounts payable and accrued liabilities $ 99,165 $ 107,514 $ 57,475 
+Capital expenditures reclassified from prepaid and other current assets $ 50,313 $ 14,922 $ — 
+Equity issued in exchange for assets and liabilities $ — $ — $ 91,089 
+See Notes to Consolidated Financial Statements. 
+F-10 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Note 1— Organization and Basis of Presentation 
+Organization 
+Liberty Energy Inc., formerly known as Liberty Oilfield Services Inc. (the “Company”), was incorporated as a Delaware corporation on December 21, 2016, to become a holding corporation for Liberty Oilfield Services New HoldCo LLC (“Liberty LLC”) and its subsidiaries upon completion of a corporate reorganization (the “Corporate Reorganization”) and planned initial public offering of the Company (“IPO”). On April 19, 2022, the stockholders of the Company approved an amendment to the Company’s Amended and Restated Certificate of Incorporation for the purpose of changing the Company’s name from “Liberty Oilfield Services Inc.” to “Liberty Energy Inc.” and thereafter, the Company filed with the Secretary of State of the State of Delaware a Certificate of Amendment to the Company’s Amended and Restated Certificate of Incorporation to reflect the new name, effective April 25, 2022. 
+Effective January 31, 2023, Liberty LLC was merged into the Company, with the Company surviving the merger (the “Merger”). In connection with the Merger, all outstanding shares of the Company’s Class B Common Stock, par value $ 0.01 per share (the “Class B Common Stock”), were redeemed and exchanged for an equal number of shares of the Company’s Class A Common Stock, par value $ 0.01 per share (the “Class A Common Stock”). The Company did not make any distributions or receive any proceeds in connection with this exchange. The Merger did not have a significant impact on the Company’s consolidated financial statements. 
+The Company, together with its subsidiaries, is a leading integrated energy services and technology company focused on providing innovative hydraulic fracturing services and related technologies to onshore oil and natural gas exploration and production companies in North America. We offer customers hydraulic fracturing services, together with complementary services including wireline services, proppant delivery solutions, field gas processing, compressed natural gas delivery, data analytics, related goods (including our sand mine operations), and technologies that will facilitate lower emission completions, thereby helping our customers reduce their emissions profile. 
+Basis of Presentation 
+The accompanying consolidated financial statements were prepared using generally accepted accounting principles in the United States of America (“GAAP”) and the instructions to Form 10-K, Regulation S-X and the rules and regulations of the Securities and Exchange Commission. 
+The accompanying consolidated financial statements and related notes present the consolidated financial position of the Company and equity of the Company as of and for the years ended December 31, 2023 and 2022, and the results of operations and cash flows of the Company for the years ended December 31, 2023, 2022, and 2021. 
+The consolidated financial statements include the amounts of the Company and all majority owned subsidiaries where the Company has the ability to exercise control. All intercompany amounts have been eliminated in the presentation of the consolidated financial statements of the Company. 
+The Company’s operations are organized into a single reportable segment, which consists of hydraulic fracturing and related goods and services. 
+Note 2— Significant Accounting Policies 
+Business Combinations 
+Business combinations are accounted for using the acquisition method of accounting in accordance with the Accounting Standard Codification (“ASC”) Topic 805 - Business Combinations, as amended by Accounting Standards Update (“ASU”) 2017-01, Business Combinations (Topic 805), Clarifying the Definition of a Business, and ASU No. 2021-08, Business Combinations: Accounting for Contract Assets and Contract Liabilities from Contracts with Customers. The purchase price is allocated to the assets acquired and liabilities assumed based on their estimated fair values. Fair value of the acquired assets and liabilities is measured in accordance with the guidance of ASC 850, Fair Value Measurements, using discounted cash flows and other applicable valuation techniques. Any acquisition related costs incurred by the Company are expensed as incurred. Any excess purchase price over the fair value of the net identifiable assets acquired is recorded as goodwill if the definition of a 
+F-11 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+business is met. Operating results of an acquired business are included in our results of operations from the date of acquisition. Refer to Note 3—Acquisitions. 
+Use of Estimates 
+The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 
+The consolidated financial statements include certain amounts that are based on management’s best estimates and judgments. The most significant estimates relate to the fair value of assets acquired and liabilities assumed, collectability of accounts receivable and estimates of allowance for doubtful accounts, the useful lives and salvage values of long-lived assets, future cash flows associated with long-lived assets, net realizable value of inventory, equity unit valuation, deferred taxes, and the tax receivable agreements value. These estimates may be adjusted as more current information becomes available. 
+Cash and Cash Equivalents 
+The Company considers all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. The Company continually monitors its positions with, and the credit quality of, the financial institutions with which it has banking relationships. As of the balance sheet date, and periodically throughout the year, the Company has maintained balances in various operating accounts in excess of federally insured limits. 
+Accounts Receivable 
+In accordance with Accounting Standards Updates ASU 2016-13, Financial Instruments-Credit Losses (Topic 326) : Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”), the Company applies historic loss factors to its receivable portfolio segments that were not expected to be further impacted by current economic developments, and additional economic conditions factor to portfolio segments anticipated to experience greater losses in the current economic environment. Additionally, the Company continuously evaluates customers based on risk characteristics, such as historical losses and current economic conditions. Due to the cyclical nature of the oil and gas industry, the Company often evaluates its customers’ estimated losses on a case-by-case basis. During the year ended December 31, 2023 the Company recorded a provision for credit losses of $ 0.8 million, related to certain customers’ expected inability to pay. The Company did not record an additional provision for credit losses during the year ended December 31, 2022. During the year ended December 31, 2021, the Company recorded a provision for credit losses of $ 0.7 million, related to two customers’ inability to pay. Provisions for credit losses are included in general and administrative expenses in the accompanying consolidated statements of operations. Refer to “Credit Risk” within Note 9—Fair Value Measurements and Financial Instruments for additional disclosures required under ASU 2016-13. 
+Inventories 
+Inventories consist of raw materials used in the hydraulic fracturing process, such as proppants, chemicals, and field service equipment maintenance parts and other and are stated at the lower of cost, determined using the weighted average cost method, or net realizable value. Inventories are charged to cost of services as used when providing hydraulic fracturing services. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable cost of completion, disposal, and transportation. 
+Property and Equipment 
+Property and equipment are stated at cost. Depreciation expense is recognized on property and equipment, excluding land, utilizing the straight-line method over the estimated useful lives, ranging from two to 30 years. The Company estimates salvage values that it does not depreciate. 
+Construction in-progress, a component of property and equipment, represents long-lived assets not yet in service or being developed by the Company. These assets are not subject to depreciation until they are completed and ready for their intended use, at which point the Company reclassifies them to field services equipment or vehicles, as appropriate. 
+The Company incurs maintenance costs on its major equipment. The determination of whether an expenditure should be capitalized or expensed requires management judgment in the application of how the costs incurred benefit future periods, relative to the Company’s capitalization policy. Costs that either establish or increase the efficiency, productivity, functionality or life of a fixed asset are capitalized and depreciated over the remaining useful life of the asset. 
+F-12 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Impairment of long-lived assets 
+Long-lived assets, such as property and equipment, right-of-use lease assets and intangible assets, are evaluated for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Possible indicators of impairment may include events or changes in circumstances affecting the manner in which the assets are being used, historical and estimated future profitability measures, and other adverse events or changes that could affect the value of the assets. If a triggering event is identified, recoverability is assessed using undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets. The Company determined the lowest level of identifiable cash flows to be at the asset group, which is the aggregate of the Company’s hydraulic fracturing fleets that are in service. A long-lived asset is not recoverable if its carrying amount exceeds the sum of estimated undiscounted cash flows expected to result from the use and eventual disposition. When alternative courses of action to recover the carrying amount of the asset group are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the asset is not recoverable, an impairment loss is recognized in an amount by which its carrying amount exceeds its estimated fair value, such that its carrying amount is adjusted to its estimated fair value, with an offsetting charge to impairment expense. 
+The Company measures the fair value of its long-lived assets using the discounted cash flow method. The expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments of projected revenue growth, fleet count, utilization, gross margin rates, selling, general and administrative rates, working capital fluctuations, capital expenditures, discount rates and terminal growth rates. 
+Goodwill 
+Goodwill represents the excess of the acquisition purchase price over the estimated fair value of net tangible and intangible assets required. Goodwill is not amortized, but instead tested for impairment at least annually, June 30, or more frequently if events and circumstances indicate that the asset might be impaired. In testing goodwill for impairment, the Company performs a qualitative assessment to determine whether the existence of events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If the qualitative assessment determines that an impairment is more likely than not, then the Company performs the one-step quantitative impairment test by determining the fair value of the reporting unit. The fair value of the reporting unit is determined using either the income approach by utilizing estimated discounted future cash flows or the market approach utilizing recent transaction activity for comparable properties. These approaches are considered Level 3 fair value measurements. If the carrying amount of a reporting unit exceeds the fair value, an impairment loss is recognized in the current period in an amount equal to the excess. 
+For purposes of assessing goodwill, the Company has one reporting unit. No goodwill impairment was identified during the years ended December 31, 2023 and 2022. 
+Leases 
+In accordance with ASC Topic 842, the Company determines if an arrangement is a lease at inception and evaluates identified leases for operating or finance lease treatment. Operating or finance lease right-of-use assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. The Company uses the rate implicit in the lease, when available, or an estimated fully collateralized incremental borrowing rate corresponding with the lease term and the information available at the commencement date in determining the present value of lease payments. Lease terms may include options to renew, however, the Company typically cannot determine its intent to renew a lease with reasonable certainty at inception. 
+Additionally, the Company is a lessor in several operating leases in which the lease equipment is carried at amortized cost. Depreciation expense is recorded on a straight-line basis over its useful life to the estimated residual value. The lessee may not purchase the leased equipment and must return such equipment by the lease’s scheduled maturity date. 
+Income Taxes 
+Deferred income taxes are computed using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Deferred tax assets and liabilities are measured using the enacted tax rates in effect for the year in which the deferred tax asset or liability are expected to reverse. The Company classifies all deferred tax assets and liabilities as non-current. The Company records Global Intangible Low-Tax Income inclusion as a current period expense. 
+The Company evaluates its deferred tax assets quarterly and considers both positive and negative evidence in applying the guidance of ASC 740 Income Taxes (“ASC 740”) related to the realizability of its deferred tax assets. On December 31, 2022, in accordance with ASC 740, the objective positive evidence of entering into a three-year cumulative pre-tax book income position, along with considering all available positive and negative evidence resulted in the release of the previously recorded 
+F-13 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+valuation allowance against the Company’s U.S. net deferred tax assets. On December 31, 2023, the Company continues to not record a valuation allowance against the Company’s deferred tax assets. 
+The Company recognizes the financial statement effects of a tax position when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. Previously recognized tax positions are reversed in the first period in which it is no longer more-likely-than-not that the tax position would be sustained upon examination. Income tax related interest and penalties, if applicable, are recorded as a component of the provision for income tax expense. 
+Tax Receivable Agreements 
+In connection with the IPO, on January 17, 2018, the Company entered into two Tax Receivable Agreements (the “TRAs”) with the R/C Energy IV Direct Partnership, L.P. and certain legacy owners that continued to own Liberty LLC Units (each such person and any permitted transferee, a “Tax Receivable Agreement Holder” and together, the “Tax Receivable Agreement Holders”). The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that the Company actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result, as applicable to each Tax Receivable Agreement Holder, of (i) certain increases in tax basis that occur as a result of the Company’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such Tax Receivable Agreement Holder’s Liberty LLC Units in connection with the IPO or pursuant to the exercise of the right (the “Redemption Right”) or the Company’s right (the “Call Right”), (ii) any net operating losses available to the Company as a result of the Corporate Reorganization, and (iii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRAs. 
+With respect to obligations the Company expects to incur under the TRAs (except in cases where the Company elects to terminate the TRAs early, the TRAs are terminated early due to certain mergers, asset sales, or other changes of control or the Company has available cash but fails to make payments when due), generally the Company may elect to defer payments due under the TRAs if the Company does not have available cash to satisfy its payment obligations under the TRAs or if its contractual obligations limit its ability to make such payments. Any such deferred payments under the TRAs generally will accrue interest. In certain cases, payments under the TRAs may be accelerated and/or significantly exceed the actual benefits, if any, the Company realizes in respect of the tax attributes subject to the TRAs. The Company accounts for amounts payable under the TRAs in accordance with ASC Topic 450, Contingencies . 
+If the Company experiences a change of control (as defined under the TRAs) or the TRAs otherwise terminate early, the Company’s obligations under the TRAs could have a substantial negative impact on its liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. 
+Share Repurchases 
+The Company accounts for the purchase price of repurchased Class A Common Stock in excess of par value ($ 0.01 per share of Class A Common Stock) as a reduction of additional paid-in capital, and will continue to do so until additional paid-in capital is reduced to zero. Thereafter, any excess purchase price will be recorded as an reduction to retained earnings. All Class A Common Stock shares repurchased to date have been retired upon repurchase. 
+Revenue Recognition 
+Under ASC Topic 606- Revenue from Contracts with Customers , revenue recognition is based on the transfer of control, or the customer’s ability to benefit from the services and products in an amount that reflects the consideration expected to be received in exchange for those services and products. In recognizing revenue for services and products, the transaction price is determined from sales orders or contracts with customers. Revenue is recognized at the completion of each fracturing stage, and in most cases the price at the end of each stage is fixed, however, in limited circumstances contracts may contain variable consideration. 
+Variable consideration typically may relate to discounts, price concessions and incentives. The Company estimates variable consideration based on the amount of consideration we expect to receive. The Company accrues revenue on an ongoing basis to reflect updated information for variable consideration as performance obligations are met. 
+The Company also assesses customers’ ability and intention to pay, which is based on a variety of factors including historical payment experience and financial condition. Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30 to 45 days. 
+In connection with the adoption of ASC Topic 842, the Company determined that certain of its service revenue contracts contain a lease component. The Company elected to adopt a practical expedient available to lessors, which allows the Company 
+F-14 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+to combine the lease and non-lease components and account for the combined component in accordance with the accounting treatment for the predominant component. Therefore, the Company combines the lease and service component for certain of the Company’s service contracts and continues to account for the combined component under ASC Topic 606, Revenue from Contracts with Customers. 
+Transaction, Severance and Other Costs 
+During 2023, the Company incurred transaction and integration related costs in connection with the Siren Acquisition (as defined below). Such costs include investment banking, legal, accounting and other professional services provided in connection with closing the transaction and are expensed as incurred . 
+During 2022 and 2021, the Company incurred transaction and integration related costs in connection with the PropX Acquisition (as defined below). Such costs include investment banking, legal, accounting and other professional services provided in connection with closing the transaction and are expensed as incurred . 
+Additionally, during 2021, the Company incurred transaction and integration related costs in connection with other prior period acquisitions. 
+Foreign Currency Translation 
+The Company records foreign currency translation adjustments from the process of translating the functional currency of the financial statements of its foreign subsidiary into the U.S. dollar reporting currency. The Canadian dollar is the functional currency of the Company’s foreign subsidiary as it is the primary currency within the economic environment in which the subsidiary operates. Assets and liabilities of the subsidiary’s operations are translated into U.S. dollars at the rate of exchange in effect on the balance sheet date and income and expenses are translated at the average exchange rate in effect during the reporting period. Adjustments resulting from the translation of the subsidiary’s financial statements are reported in other comprehensive income. 
+Recently Adopted Accounting Standards 
+Business Combinations: Accounting for Contract Assets and Contract Liabilities 
+In October 2021, the Federal Accounting Standards Board (the “FASB”) issued ASU No. 2021-08, Business Combinations: Accounting for Contract Assets and Contract Liabilities from Contracts with Customers , which requires that the acquiring entity recognize and measure contract assets and contract liabilities acquired in a business combination in accordance with Topic 606. The Company adopted this guidance effective December 15, 2022, and the adoption did not have a material impact on the accompanying consolidated financial statements. 
+Recently Issued Accounting Standards 
+Income Taxes: Improvements to Income Tax Disclosures 
+In December 2023, the FASB issued ASU No. 2023-09, Income Taxes: Improvements to Income Tax Disclosures , which requires disaggregation of certain components included in the Company’s effective tax rate and income taxes paid disclosures. The guidance is effective for annual periods beginning after December 15, 2024. The Company is currently assessing the impact of this ASU on the Company’s financial statements but does not expect it will have a material impact. 
+Reclassifications 
+Certain amounts in the prior period financial statements have been reclassified to conform to current period financial statement presentation. In the accompanying consolidated balance sheets $ 2.3 million was reclassified from accrued liabilities to income taxes payable and $ 3.9 million was reclassified from deferred revenue to accrued liabilities, additionally changes in deferred revenue were reclassified to changes in accounts payable and accrued liabilities in the accompanying consolidated statements of cash flows. 
+In the accompanying consolidated statements of operations amounts were reclassified from interest income to interest expense, net. 
+In the accompanying consolidated statement of cash flows amounts in the prior period financial statements have been reclassified from amortization of debt issuance costs, inventory write-down, non-cash lease expense, provision for credit-losses, and other non-cash expense, net to other non-cash items, net. 
+F-15 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Note 3— Acquisitions 
+Siren Acquisition 
+On April 6, 2023, the Company completed the acquisition of a Permian focused integrated natural gas compression and compressed natural gas delivery business, Siren Energy & Logistics, LLC, for cash consideration of $ 75.7 million, after post closing adjustments and net of cash received, (the “Siren Acquisition”). The Siren Acquisition was accounted for under the acquisition method of accounting for business combinations. Accordingly, the Company conducted assessments of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. In connection with the Siren Acquisition, the Company recorded goodwill of $ 42.0 million, property and equipment of $ 34.9 million, net working capital of $ 2.5 million, deferred revenue of $ 5.2 million, and other assets of $ 1.8 million. Goodwill is recorded in other assets in the accompanying consolidated balance sheets. Due to the immateriality of the Siren Acquisition, the related revenue and earnings, supplemental pro forma financial information, and detailed purchase price allocation are not disclosed. 
+In accordance with ASC Topic 805, an acquirer is allowed a period, referred to as the measurement period, in which to complete its accounting for the transaction. Such measurement period ends at the earliest date that the acquirer a) receives the information necessary or b) determines that it cannot obtain further information, and such period may not exceed one year. As the Siren Acquisition closed on April 6, 2023, the Company completed the purchase price allocation during the year ended December 31, 2023. 
+PropX Acquisition 
+On October 26, 2021, the Company entered into the certain Unit Purchase Agreement (the “Transaction Agreement”) with Proppant Express Investments, LLC to acquire the assets and liabilities of Proppant Express Solutions, LLC (“PropX”), which provides last-mile proppant delivery solutions, including proppant handling equipment and logistics software across North America (the “PropX Acquisition”). PropX was acquired in exchange for $ 11.9 million in cash and 3,405,526 shares of the Company’s Class A Common Stock and 2,441,010 shares of the Company’s Class B Common Stock, for total consideration of $ 103.0 million based on the October 26, 2021 closing price of Class A Common Stock of $ 15.58 . In connection with the issuance of 2,441,010 shares of Class B Common Stock, Liberty LLC also issued 2,441,010 Liberty LLC Units to the Company. The Liberty LLC Units are redeemable for an equivalent number of shares of Class A Common Stock at any time, at the election of the shareholder. 
+The Company accounted for the PropX Acquisition using the acquisition method of accounting. The aggregate purchase price noted above was allocated to the major categories of assets acquired and liabilities assumed based upon their estimated fair value at the date of the acquisition. The estimated fair values of certain assets and liabilities require significant judgments and estimates. The majority of the measurements of assets acquired and liabilities assumed, are based on inputs that are not observable in the market and thus represent Level 3 inputs. 
+In accordance with ASC Topic 805, an acquirer is allowed a period, referred to as the measurement period, in which to complete its accounting for the transaction. Such measurement period ends at the earliest date that the acquirer a) receives the information necessary or b) determines that it cannot obtain further information, and such period may not exceed one year. As the PropX Acquisition closed on October 26, 2021 the Company completed the purchase price allocation, particularly as it relates to current assets and current liabilities, during the year ended December 31, 2022. 
+The following table summarizes the fair value of the consideration transferred in the PropX Acquisition and the allocation of the purchase price to the fair value of the assets acquired and liabilities assumed as of October 26, 2021, the date of the closing of the PropX Acquisition: 
+F-16 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+($ in thousands) 
+Total Purchase Consideration: 
+Consideration $ 103,023 
+Cash and cash equivalents $ 53 
+Accounts receivable and unbilled revenue 4,089 
+Inventory 8 
+Prepaid and other current assets 1,722 
+Property and equipment (1) 
+94,137 
+Intangible assets (included in other assets in the accompanying consolidated balance sheet as of December 31, 2021) (2) 
+7,100 
+Total identifiable assets acquired 107,109 
+Accounts payable 2,152 
+Accrued liabilities 1,934 
+Total liabilities assumed 4,086 
+Total purchase consideration $ 103,023 
+(1) Useful lives average of 10 years, see Note 5—Property and Equipment 
+(2) Definite lived intangibles with an amortization period ranging from seven to 10 years 
+Transaction costs, costs associated with issuing additional equity and integration costs were recognized separately from the acquisition of assets and assumptions of liabilities in the PropX Acquisition. Transaction costs consist of legal and professional fees. Integration costs consist of expenses incurred to integrate PropX’s operations, aligning accounting processes and procedures, and integrating its enterprise resource planning system with those of the Company. Merger and integration costs are expensed as incurred, and equity offering costs were recorded as a reduction to additional paid in capital. 
+The Company’s consolidated statements of operations for the year ended December 31, 2021 includes 66 days of PropX operations as the PropX Acquisition closed on October 26, 2021. The Company does not present pro forma financial information for the periods prior to the PropX Acquisition as such information, after elimination of PropX’s historical transactions with the Company, is not materially different than the results presented in the accompanying Consolidated Statements of Operations for year ended December 31, 2021. 
+Note 4— Inventories 
+Inventories consist of the following: 
+December 31, 
+($ in thousands) 2023 2022 
+Proppants $ 17,124 $ 31,350 
+Chemicals 16,896 32,392 
+Maintenance parts and other 171,845 150,712 
+$ 205,865 $ 214,454 
+During the year ended December 31, 2023, the lower of cost or net realizable value analysis resulted in the Company recording a write-down to the inventory carrying value of $ 5.8 million. During the year ended December 31, 2022, the lower of cost or net realizable value analysis resulted in the Company recording a write-down to the inventory carrying value of $ 1.7 million. Both are included as a component in cost of services in the consolidated statements of operations. The Company did not record any write-down to the inventory carrying value during the year ended December 31, 2021. 
+F-17 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Note 5— Property and Equipment 
+Property and equipment consist of the following: 
+Estimated 
+useful lives 
+(in years) December 31, 
+2023 2022 
+($ in thousands) 
+Land N/A $ 29,384 $ 29,276 
+Field services equipment 
+2 - 10 
+2,520,336 1,925,848 
+Vehicles 
+4 - 7 
+63,423 62,683 
+Lease equipment 10 138,781 106,087 
+Buildings and facilities 
+5 - 30 
+149,876 135,281 
+Mineral reserves 
+> 25 
+76,823 76,823 
+Office equipment and furniture 
+2 - 7 
+11,836 9,504 
+2,990,459 2,345,502 
+Less accumulated depreciation and depletion ( 1,501,685 ) ( 1,141,656 ) 
+1,488,774 1,203,846 
+Construction in-progress N/A 156,594 158,518 
+Property and equipment, net $ 1,645,368 $ 1,362,364 
+Depreciation expense for the years ended December 31, 2023, 2022, and 2021 was $ 387.8 million, $ 302.3 million, and $ 243.0 million, respectively. Depletion expense for the years ended December 31, 2023, 2022, and 2021 was $ 1.1 million, $ 1.2 million, and $ 1.2 million, respectively. 
+As of December 31, 2023 and December 31, 2022, the Company concluded that no triggering events that could indicate possible impairment of property and equipment had occurred, other than related to the assets held for sale discussed below. 
+As of December 31, 2023, the Company classified $ 0.7 million of land and $ 0.8 million of buildings, net of accumulated depreciation, of one property that it intends to sell within the next year, and that meets the held for sale criteria, to assets held for sale, included in prepaid and other current assets in the accompanying consolidated balance sheet. The Company estimates that the carrying value of the assets is equal to the fair value less the estimated costs to sell, net of write-downs taken in the prior period, and therefore no gain or loss was recorded during the year ended December 31, 2023. 
+Additionally, as of December 31, 2022, the Company classified $ 1.1 million of land and $ 6.2 million of buildings, net of accumulated depreciation, of two properties that it intends to sell within the next year, and that meets the held for sale criteria, to assets held for sale, included in prepaid and other current assets in the accompanying consolidated balance sheet. The Company estimates that the carrying value of the assets were greater than the fair value less the estimated costs to sell, and therefore recorded a $ 1.0 million loss during the year ended December 31, 2022, included as a component of gain on disposal of assets, net in the accompanying consolidated statements of operations. 
+One of the properties classified as held for sale as of December 31, 2022, was sold during the year ended December 31, 2023, resulting in a nominal loss included as a component of (gain) loss on disposal of assets, net in the accompanying consolidated statements of income. 
+Note 6— Leases 
+Lessee Arrangements 
+The Company has operating and finance leases primarily for vehicles, equipment, railcars, office space, and facilities. The terms and conditions for these leases vary by the type of underlying asset. 
+Certain leases include variable lease payments for items such as property taxes, insurance, maintenance, and other operating expenses associated with leased assets. Payments that vary based on an index or rate are included in the measurement of lease assets and liabilities at the rate as of the commencement date. All other variable lease payments are excluded from the measurement of lease assets and liabilities, and are recognized in the period in which the obligation for those payments is incurred. 
+F-18 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+The components of lease expense for the years ended as of December 31, 2023, and 2022 were as follows: 
+($ in thousands) 2023 2022 
+Finance lease cost: 
+Amortization of right-of-use assets $ 19,040 $ 5,827 
+Interest on lease liabilities 6,060 1,707 
+Operating lease cost 40,275 43,214 
+Variable lease cost 5,116 4,801 
+Short-term lease cost 7,717 6,931 
+Total lease cost, net $ 78,208 $ 62,480 
+Supplemental cash flow and other information related to leases for the years ended December 31, 2023 and 2022 were as follows: 
+($ in thousands) 2023 2022 
+Cash paid for amounts included in measurement of liabilities: 
+Operating leases $ 41,143 $ 42,108 
+Finance leases 23,463 10,889 
+Right-of-use assets obtained in exchange for new lease liabilities: 
+Operating leases 31,449 25,862 
+Finance leases 160,546 25,888 
+During the year ended December 31, 2023, the Company did not amend any operating leases. During the year ended December 31, 2022, the Company amended certain operating leases, the change in terms of which caused the leases to be reclassified to finance leases. In connection with the amendments, the Company recognized finance lease right-of-use assets of $ 3.5 million and liabilities of $ 3.5 million. Additionally, the Company wrote-off operating lease right-of-use assets of $ 0.2 million and liabilities of $ 0.1 million. There was no gain or loss recognized as a result of these amendments. 
+Lease terms and discount rates as of December 31, 2023 and 2022 were as follows: 
+December 31, 2023 December 31, 2022 
+Weighted-average remaining lease term: 
+Operating leases 4.3 years 4.8 years 
+Finance leases 3.3 years 3.1 years 
+Weighted-average discount rate: 
+Operating leases 6.0 % 4.6 % 
+Finance leases 8.0 % 8.2 % 
+Future minimum lease commitments as of December 31, 2023 are as follows: 
+($ in thousands) Finance Operating 
+2024 $ 51,059 $ 31,490 
+2025 51,103 29,520 
+2026 53,139 18,718 
+2027 27,545 8,677 
+2028 19,816 2,485 
+Thereafter — 12,569 
+Total lease payments 202,662 103,459 
+Less imputed interest 29,141 11,671 
+Total $ 173,521 $ 91,788 
+The Company’s vehicle leases typically include a residual value guarantee. For the Company’s vehicle leases classified as operating leases, the total residual value guaranteed as of December 31, 2023 is $ 14.6 million; the payment is not probable and 
+F-19 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+therefore has not been included in the measurement of the lease liability and right-of-use asset. For vehicle leases that are classified as finance leases, the Company includes the residual value guarantee, estimated in the lease agreement, in the financing lease liability. 
+Lessor Arrangements 
+The Company leases dry and wet sand containers and conveyor belts to customers through operating leases, where the lessor for tax purposes is considered to be the owner of the equipment during the term of the lease. The lease agreements do not include options for the lessee to purchase the underlying asset at the end of the lease term for either a stated fixed price or fair market value. However, some of the leases contain a termination clause in which the customer can cancel the contract. The leases can be subject to variable lease payments if the customer requests more units than what is agreed upon in the lease. The Company does not record any lease assets or liabilities related to these variable items. 
+The carrying amount of equipment leased to others, included in property, plant and equipment, under operating leases as of December 31, 2023 and 2022 were as follows: 
+($ in thousands) December 31, 2023 December 31, 2022 
+Equipment leased to others - at original cost $ 138,781 $ 106,087 
+Less: Accumulated depreciation ( 25,819 ) ( 11,408 ) 
+Equipment leased to others - net $ 112,962 $ 94,679 
+Future payments receivable for operating leases as of December 31, 2023 are as follows: 
+($ in thousands) 
+2024 $ 9,893 
+2025 5,412 
+2026 1,919 
+2027 — 
+2028 — 
+Thereafter — 
+Total $ 17,224 
+Revenues from operating leases for the years ended December 31, 2023 and 2022 were $ 36.6 million and $ 25.5 million, respectively. 
+Note 7— Accrued Liabilities 
+Accrued liabilities consist of the following: 
+($ in thousands) December 31, 2023 December 31, 2022 
+Accrued vendor invoices $ 99,620 $ 119,801 
+Operations accruals 61,150 72,348 
+Accrued benefits and other 100,296 88,529 
+$ 261,066 $ 280,678 
+F-20 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Note 8— Debt 
+Debt consists of the following: 
+December 31, 
+2023 2022 
+Term Loan Outstanding $ — $ 104,716 
+Revolving Line of Credit 140,000 115,000 
+Deferred financing costs and original issue discount — ( 1,270 ) 
+Total debt, net of deferred financing costs and original issue discount $ 140,000 $ 218,446 
+Current portion of long-term debt, net of discount $ — $ 1,020 
+Long-term debt, net of discount and current portion 140,000 217,426 
+$ 140,000 $ 218,446 
+On September 19, 2017, the Company entered into two credit agreements, (i) a revolving line of credit up to $ 250.0 million, subsequently increased to $ 525.0 million, see below, (the “ABL Facility”) and (ii) a $ 175.0 million term loan (the “Term Loan Facility”, and together with the ABL Facility the “Credit Facilities”). 
+Effective January 23, 2023, the Company entered into an Eighth Amendment to the ABL Facility (the “Eighth ABL Amendment”). The Eighth ABL Amendment amends certain terms, provisions and covenants of the ABL Facility, including, among other things: (i) increasing the maximum revolver amount from $ 425.0 million to $ 525.0 million (the “Upsized Revolver”); (ii) increasing the amount of the accordion feature from $ 75.0 million to $ 100.0 million; (iii) extending the maturity date from October 22, 2026 to January 23, 2028; (iv) modifying the dollar amounts of various credit facility triggers and tests proportionally to the Upsized Revolver; (v) permitting repayment under the Term Loan Facility prior to February 10, 2023; and (vi) increasing certain indebtedness, intercompany advance, and investment baskets. The Eighth ABL Amendment included an agreement from the Wells Fargo Bank, National Association, as administrative agent, to release its second priority liens and security interests on all collateral that served as first priority collateral under the Term Loan Facility, which was completed during the three months ended June 30, 2023. 
+Additionally, on January 23, 2023, the Company borrowed $ 106.7 million on the ABL Facility and used the proceeds to pay off and terminate the Term Loan Facility. The amount paid included the balance of the Term Loan Facility at pay off of $ 104.7 million, $ 0.9 million of accrued interest, and a $ 1.1 million prepayment premium. Additionally, there were $ 0.2 million in administrative and lender legal fees incurred in connection with the pay off. 
+The weighted average interest rate on all borrowings outstanding as of December 31, 2023 and December 31, 2022 was 7.6 % and 9.0 %, respectively. 
+Term Loan Facility 
+The Term Loan Facility provided for a $ 175.0 million term loan. In connection with the Eighth ABL Amendment and payoff of the Term Loan Facility, on January 23, 2023, the Company terminated the Term Loan Facility. See above for further discussion. 
+ABL Facility 
+Under the terms of the ABL Facility, up to $ 525.0 million may be borrowed, subject to certain borrowing base limitations based on a percentage of eligible accounts receivable and inventory. As of December 31, 2023, the borrowing base was calculated to be $ 420.3 million, and the Company had $ 140.0 million outstanding in addition to letters of credit in the amount of $ 2.6 million, with $ 277.7 million of remaining availability. Borrowings under the ABL Facility bear interest at Secured Overnight Financing Rate (“SOFR”) or a base rate, plus an applicable SOFR margin of 1.5 % to 2.0 % or base rate margin of 0.5 % to 1.0 %, as described in the ABL Facility credit agreement (the “ABL Facility credit agreement”). Additionally, borrowings as of December 31, 2023 incurred interest at a weighted average rate of 7.6 %. The average monthly unused commitment is subject to an unused commitment fee of 0.25 % to 0.375 %. Interest and fees are payable in arrears at the end of each month, or, in the case of SOFR loans, at the end of each interest period. The ABL Facility matures on January 23, 2028. Borrowings under the ABL Facility are collateralized by accounts receivable and inventory, and further secured by the Company, as parent guarantor. 
+The ABL Facility includes certain non-financial covenants, including but not limited to restrictions on incurring additional debt and certain distributions. Moreover, the ability of the Company to incur additional debt and to make distributions is dependent on maintaining a maximum leverage ratio. 
+The ABL Facility is not subject to financial covenants unless liquidity, as defined in the ABL Facility credit agreement, drops below a specific level. The Company is required to maintain a minimum fixed charge coverage ratio, as defined in the 
+F-21 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+ABL Facility credit agreement, of 1.0 to 1.0 for each period if excess availability is less than 10 % of the borrowing base or $ 52.5 million, whichever is greater. 
+The Company was in compliance with these covenants as of December 31, 2023. 
+Maturities of debt are as follows: 
+($ in thousands) 
+Years Ending December 31, 
+2024 $ — 
+2025 — 
+2026 — 
+2027 — 
+2028 140,000 
+$ 140,000 
+Note 9— Fair Value Measurements and Financial Instruments 
+The fair values of the Company’s assets and liabilities represent the amounts that would be received to sell those assets or that would be paid to transfer those liabilities in an orderly transaction on the reporting date. These fair value measurements maximize the use of observable inputs. However, in situations where there is little, if any, market activity for the asset or liability on the measurement date, the fair value measurement reflects the Company’s own judgments about the assumptions that market participants would use in pricing the asset or liability. The Company discloses the fair values of its assets and liabilities according to the quality of valuation inputs under the following hierarchy: 
+• Level 1 Inputs: Quoted prices (unadjusted) in an active market for identical assets or liabilities. 
+• Level 2 Inputs: Inputs other than quoted prices that are directly or indirectly observable. 
+• Level 3 Inputs: Unobservable inputs that are significant to the fair value of assets or liabilities. 
+The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those that are initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from unobservable inputs is inconsequential to the overall fair value, or if corroborating market data becomes available. Assets and liabilities that are initially reported as Level 2 are subsequently reported as Level 3 if corroborating market data is no longer available. Transfers occur at the end of the reporting period. There were no transfers into or out of Levels 1, 2, and 3 during the years ended December 31, 2023 and 2022. 
+The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, notes receivable, accounts payable, accrued liabilities, long-term debt, and finance and operating lease obligations. These financial instruments do not require disclosure by level. The carrying values of all of the Company’s financial instruments included in the accompanying consolidated balance sheets approximated or equaled their fair values on December 31, 2023 and 2022. 
+• The carrying values of cash and cash equivalents, accounts receivable, and accounts payable (including accrued liabilities) approximated fair value on December 31, 2023 and 2022, due to their short-term nature. 
+• The carrying value of amounts outstanding under long-term debt agreements with variable rates approximated fair value on December 31, 2023 and 2022, as the effective interest rates approximated market rates. 
+• The carrying values of amounts outstanding under finance and operating lease obligations approximated fair value on December 31, 2023 and 2022, as the effective borrowing rates approximated market rates. 
+Nonrecurring Measurements 
+Certain assets and liabilities are measured at fair value on a nonrecurring basis. These items are not measured at fair value on an ongoing basis but may be subject to fair value adjustments in certain circumstances. These assets and liabilities include those acquired through the Siren Acquisition and PropX Acquisition, which are required to be measured at fair value on the acquisition date in accordance with ASC Topic 805 . See Note 3—Acquisitions. 
+As of December 31, 2023, the Company recorded $ 0.7 million of land and $ 0.8 million of buildings of one property that met the held for sale criteria, to assets held for sale at a total fair value of $ 0.8 million, which are included in prepaid and other current assets in the accompanying consolidated balance sheets. The Company estimated the fair value of the property based on a communicated selling price for one property, which is a Level 3 input. The Company estimates that the carrying value of the assets is equal to the fair value less the estimated costs to sell, net of write-downs taken in the prior period, and therefore no gain or loss was recorded during the year ended December 31, 2023. 
+F-22 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+As of December 31, 2022, the Company recorded $ 1.1 million of land and $ 6.2 million of buildings of two properties that met the held for sale criteria, to assets held for sale at a total fair value of $ 6.3 million, which are included in prepaid and other current assets in the accompanying consolidated balance sheets. The Company estimated that the carrying value of the assets were greater than the fair value less the estimated costs to sell, and therefore recorded a $ 1.0 million loss during the year ended December 31, 2022, included as a component of gain on disposal of assets, net in the accompanying consolidated statements of operations. 
+Other assets measured at fair value on a nonrecurring basis consist of notes receivable—related party from the Affiliate, as defined and described in Note 14—Related Party Transactions. The note was initially recorded for the trade receivables, created in the normal course of business, due from the Affiliate as of the Agreement Date, as defined in Note 14—Related Party Transactions. There were no identified events or changes in circumstances that had a significant adverse effect on the fair value of the notes receivable. These notes are classified as Level 3 in the fair value hierarchy as the inputs to the determination of fair value are based upon unobservable inputs. As of December 31, 2023 and 2022, notes receivable—related party from the Affiliate totaled $ 14.8 million and $ 11.8 million, respectively. 
+Recurring Measurements 
+The fair values of the Company’s cash equivalents measured on a recurring basis pursuant to ASC 820-10 Fair Value Measurements and Disclosures are carried at estimated fair value. Cash equivalents consist of money market accounts which the Company has classified as Level 1 given the active market for these accounts. As of December 31, 2023 and 2022, the Company had cash equivalents, measured at fair value, of $ 0.3 million and $ 0.3 million, respectively. 
+Nonfinancial assets 
+The Company estimates fair value to perform impairment tests as required on long-lived assets. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3 in the event that such assets were required to be measured and recorded at fair value within the consolidated financial statements. No such measurements were required as of December 31, 2023 and 2022 as no triggering event was identified. 
+Credit Risk 
+The Company’s financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents, and trade receivables. 
+The Company’s cash and cash equivalents balance on deposit with financial institutions total $ 36.8 million and $ 43.7 million as of December 31, 2023 and 2022, respectively, which exceeded Federal Deposit Insurance Corporation insured limits. The Company regularly monitors these institutions’ financial condition. 
+The majority of the Company’s customers have payment terms of 45 days or less. 
+During the year ended December 31, 2023, no customers accounted for 10% of total consolidated accounts receivable and unbilled revenue. As of December 31, 2022, customer A accounted for 11.0 %, of total consolidated accounts receivable and unbilled revenue. During the years ended December 31, 2023, 2022, and 2021, no customers accounted for 10% of consolidated revenues. 
+The Company mitigates the associated credit risk by performing credit evaluations and monitoring the payment patterns of its customers. 
+As of December 31, 2023, the Company had $ 0.9 million in allowance for credit losses and recorded a provision related to certain customers’ expected inability to pay. As of December 31, 2022, the Company had $ 0.9 million in allowance for credit losses. As of December 31, 2021, the Company had $ 0.9 million in allowance for credit losses and recorded a provision related to two entities inability to pay. 
+The Company applies historic loss factors to its receivable portfolio segments that are not expected to be further impacted by current economic developments, and an additional economic conditions factor to portfolio segments anticipated to experience greater losses in the current economic environment. While the Company has not experienced significant credit losses in the past and has not seen material changes to the payment patterns of its customers, the Company cannot predict with any certainty the degree to which unforeseen events may affect the ability of its customers to timely pay receivables when due. 
+F-23 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Accordingly, in future periods, the Company may revise its estimates of expected credit losses. 
+($ in thousands) 2023 2022 2021 
+Allowance for credit losses, beginning of year $ 884 $ 884 $ 773 
+Credit losses: 
+Current period provision 808 — 745 
+Amounts written off, net of recoveries ( 753 ) — ( 634 ) 
+Allowance for credit losses, end of year $ 939 $ 884 $ 884 
+Note 10— Equity 
+Preferred Stock 
+As of December 31, 2023 and 2022, the Company had 10,000 shares of preferred stock authorized, par value $ 0.01 , with none issued and outstanding. If issued, each class or series of preferred stock will cover the number of shares and will have the powers, preferences, rights, qualifications, limitations and restrictions determined by the Company’s board of directors, which may include, among others, dividend rights, liquidation preferences, voting rights, conversion rights, preemptive rights and redemption rights. Except as provided by law or in a preferred stock designation, the holders of preferred stock will not be entitled to vote at or receive notice of any meeting of shareholders. 
+Class A Common Stock 
+The Company had a total of 166,610,199 and 178,753,125 shares of Class A Common Stock outstanding as of December 31, 2023 and 2022, respectively, none of which were restricted. Holders of Class A Common Stock are entitled to one vote per share on all matters to be voted upon by the stockholders and are entitled to ratably receive dividends when and if declared by the Company’s board of directors. 
+Class B Common Stock 
+The Company had a total of 0 and 250,222 shares of Class B Common Stock outstanding as of December 31, 2023 and 2022, respectively. Effective January 31, 2023, in connection with the Merger, all outstanding shares of the Class B Common Stock were redeemed and exchanged, with no shares remaining outstanding as of December 31, 2023. 
+Long Term Incentive Plan 
+On January 11, 2018, the Company adopted the Long Term Incentive Plan (“LTIP”) to incentivize employees, officers, directors and other service providers of the Company and its affiliates. The LTIP provides for the grant, from time to time, at the discretion of the Company’s board of directors or a committee thereof, of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, cash awards, substitute awards and performance awards. Subject to adjustment in the event of certain transaction or changes of capitalization in accordance with the LTIP, 12,908,734 shares of Class A Common Stock were initially reserved for issuance pursuant to awards under the LTIP. Class A Common Stock subject to an award that expires or is canceled, forfeited, exchanged, settled in cash or otherwise terminated without delivery of shares and shares withheld to pay the exercise price of, or to satisfy the withholding obligations with respect to, an award will again be available for delivery pursuant to other awards under the LTIP. 
+Restricted Stock Units 
+Restricted stock units (“RSUs”) granted pursuant to the LTIP, if they vest, will be settled in shares of the Company’s Class A Common Stock. RSUs were granted with vesting terms up to three years . Changes in non-vested RSUs outstanding under the LTIP during the year ended December 31, 2023 were as follows: 
+Number of Units Weighted Average Grant Date Fair Value per Unit 
+Non-vested as of December 31, 2022 2,985,727 $ 12.15 
+Granted 1,599,151 14.93 
+Vested ( 1,466,822 ) 11.56 
+Forfeited ( 132,838 ) 12.84 
+Outstanding at December 31, 2023 2,985,218 $ 13.90 
+F-24 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Performance Restricted Stock Units 
+Performance restricted stock units (“PSUs”) granted pursuant to the LTIP, if they vest, will be settled in shares of the Company’s Class A Common Stock. PSUs were granted with a three -year cliff vesting schedule, subject to a performance target compared to an index of competitors ’ results over the three -year period as designated in the award. The Company records compensation expense based on the Company’s best estimate of the number of PSUs that will vest at the end of the performance period. If such performance targets are not met, or are not expected to be met, no compensation expense is recognized and any recognized compensation expense is reversed. Changes in non-vested PSUs outstanding under the LTIP during the year ended December 31, 2023 were as follows: 
+Number of Units Weighted Average Grant Date Fair Value per Unit 
+Non-vested as of December 31, 2022 1,390,588 $ 11.87 
+Granted 341,928 15.64 
+Vested ( 392,948 ) 9.62 
+Forfeited — — 
+Outstanding at December 31, 2023 1,339,568 $ 13.49 
+Stock-based compensation is included in cost of services and general and administrative expenses in the Company’s consolidated statements of operations. The Company recognized stock-based compensation expense of $ 33.0 million, $ 23.1 million, and $ 19.9 million for the years ended December 31, 2023, 2022, and 2021, respectively. There was approximately $ 33.9 million of unrecognized compensation expense relating to outstanding RSUs and PSUs as of December 31, 2023. The unrecognized compensation expense will be recognized on a straight-line basis over the weighted average remaining vesting period of two years . 
+Dividends 
+On October 18, 2022, the Company’s Board of Directors (the “Board”) reinstated quarterly dividends after they were suspended on April 2, 2020. 
+The Company paid cash dividends of $ 0.05 per share of Class A Common Stock on March 20, 2023, June 20, 2023, and September 20, 2023 to stockholders of record as of March 6, 2023, June 6, 2023, and September 6, 2023, respectively. Additionally, the Company paid cash dividends of $ 0.07 per share of Class A Common Stock on December 20, 2023 to stockholders of record as of December 6, 2023. During the year ended December 31, 2023, dividend payments totaled $ 37.5 million. 
+The Company paid cash dividends of $ 0.05 per share of Class A Common Stock on December 20, 2022 to stockholders of record as of December 6, 2022. Liberty LLC paid a distribution of $ 9.0 million, or $ 0.05 per Liberty LLC Unit, to all Liberty LLC unit holders as of December 6, 2022, $ 9.0 million of which was paid to the Company. The Company used the proceeds of the distribution to pay the dividend to all holders of shares of Class A Common Stock as of December 6, 2022, which totaled $ 9.0 million. 
+Additionally, the Company paid an accrued dividend equivalent upon vesting for the RSUs and PSUs with a 2023 vesting date, which totaled $ 0.2 million for the year ended December 31, 2023. As of December 31, 2023 and 2022, the Company had $ 1.0 million and $ 0.2 million of dividend equivalents payable related to RSUs and PSUs to be paid upon vesting, respectively. Dividend equivalents related to forfeited RSUs or PSUs will be forfeited. 
+F-25 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Share Repurchase Program 
+On July 25, 2022, the Company’s board of directors authorized and the Company announced a share repurchase program that allowed the Company to repurchase up to $ 250.0 million of the Company’s Class A Common Stock beginning immediately and continuing through and including July 31, 2024. On January 24, 2023, the Board authorized and the Company announced an increase to the share repurchase program that increased the Company’s cumulative repurchase authorization to $ 500.0 million. Furthermore, on January 23, 2024 the Board authorized and the Company announced an increase to the share repurchase program that increased the Company’s cumulative repurchase authorization to $ 750.0 million and extended the authorization through July 31, 2026. The shares may be repurchased from time to time in open market or privately negotiated transactions or by other means in accordance with applicable state and federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will be determined by the Company at its discretion and will depend on a variety of factors, including management’s assessment of the intrinsic value of the Company’s Class A Common Stock, the market price of the Company’s Class A Common Stock, general market and economic conditions, available liquidity, compliance with the Company’s debt and other agreements, applicable legal requirements, and other considerations. The exact number of shares to be repurchased by the Company is not guaranteed, and the program may be suspended, modified, or discontinued at any time without prior notice. The Company expects to fund any repurchases by using cash on hand, borrowings under its revolving credit facility and expected free cash flow to be generated through the duration of the share repurchase program. 
+During the year ended December 31, 2023, the Company repurchased and retired 13,705,622 shares of Class A Common Stock for $ 203.1 million or $ 14.82 average price per share including commissions, under the share repurchase program. 
+As of December 31, 2023, $ 171.9 million remained authorized for future repurchases of Class A Common Stock under the share repurchase program. 
+During the year ended December 31, 2022, the Company repurchased and retired 8,185,890 shares of Class A Common Stock for $ 125.3 million or $ 15.31 average price per share including commissions, under the share repurchase program. 
+During the year ended December 31, 2021, under the prior share repurchase program, no shares were repurchased and retired under the share repurchase program. 
+The Company accounts for the purchase price of repurchased common shares in excess of par value ($ 0.01 per share of Class A Common Stock) as a reduction of additional paid-in capital, and will continue to do so until additional paid-in capital is reduced to zero. Thereafter, any excess purchase price will be recorded as a reduction to retained earnings. 
+As enacted by the Inflation Reduction Act of 2022 (“IRA”), the Company accrued stock repurchase excise tax of $ 1.9 million for the year ended December 31, 2023. 
+Note 11— Net Income per Share 
+Basic net income per share measures the performance of an entity over the reporting period. Diluted net income per share measures the performance of an entity over the reporting period while giving effect to all potentially dilutive common shares that were outstanding during the period. The Company uses the “if-converted” method to determine the potential dilutive effect of its Class B Common Stock and the treasury stock method to determine the potential dilutive effect of outstanding RSUs and PSUs. 
+F-26 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+The following table reflects the allocation of net income to common stockholders and net income per share computations for the periods indicated based on a weighted average number of shares of Class A Common Stock and Class B Common Stock outstanding: 
+(In thousands, except per share data) Year Ended December 31, 2023 Year Ended December 31, 2022 
+Basic Net Income Per Share 
+Numerator: 
+Net income attributable to Liberty Energy Inc. stockholders $ 556,317 $ 399,602 
+Denominator: 
+Basic weighted average common shares outstanding 171,845 184,334 
+Basic net income per share attributable to Liberty Energy Inc. stockholders $ 3.24 $ 2.17 
+Diluted Net Income Per Share 
+Numerator: 
+Net income attributable to Liberty Energy Inc. stockholders $ 556,317 $ 399,602 
+Effect of exchange of the shares of Class B Common Stock for shares of Class A Common Stock 73 716 
+Diluted net income attributable to Liberty Energy Inc. stockholders $ 556,390 $ 400,318 
+Denominator: 
+Basic weighted average shares outstanding 171,845 184,334 
+Effect of dilutive securities: 
+Restricted stock units 4,494 4,262 
+Class B Common Stock 21 753 
+Diluted weighted average shares outstanding 176,360 189,349 
+Diluted net income per share attributable to Liberty Energy Inc. stockholders $ 3.15 $ 2.11 
+Note 12— Income Taxes 
+The Company is a corporation and is subject to taxation in the United States, Canada and various state, local and provincial jurisdictions. Historically, Liberty LLC was treated as a partnership, and its income was passed through to its owners for income tax purposes. Liberty LLC’s members, including the Company, were liable for federal, state and local income taxes based on their share of Liberty LLC’s pass-through taxable income. 
+Effective January 31, 2023, the Company adopted a plan of merger, pursuant to which Liberty LLC merged into the Company, ceasing the existence of Liberty LLC, with the Company remaining as the surviving entity. Liberty LLC filed a final tax return during the 2023 calendar year. 
+As of December 31, 2023, tax reporting by the Company for the years ended December 31, 2020, 2021, 2022, and the short period ended January 31, 2023 are subject to examination by the tax authorities. With few exceptions, as of December 31, 2023, the Company is no longer subject to U.S. federal, state or local examinations by tax authorities for tax years ended before December 31, 2019. 
+F-27 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+The components of the Company’s income (loss) from continuing operations before income taxes on which the provision for income taxes was computed consisted of the following: 
+Year Ended December 31, 
+($ in thousands) 2023 2022 2021 
+United States $ 668,338 $ 375,758 $ ( 191,774 ) 
+Foreign 66,552 23,751 13,986 
+Total $ 734,890 $ 399,509 $ ( 177,788 ) 
+The components of the provision for incomes taxes from continuing operations are summarized as follows: 
+Year Ended December 31, 
+($ in thousands) 2023 2022 2021 
+Current: 
+Federal $ 36,319 $ 4,679 $ — 
+State 4,662 2,579 29 
+Foreign 17,189 4,421 4,108 
+Total Current $ 58,170 $ 11,679 $ 4,137 
+Deferred: 
+Federal $ 109,399 $ ( 12,967 ) $ 6,125 
+State 11,913 ( 1,182 ) ( 439 ) 
+Foreign ( 1,000 ) 1,677 ( 607 ) 
+Total Deferred $ 120,312 $ ( 12,472 ) $ 5,079 
+Income tax expense (benefit) $ 178,482 $ ( 793 ) $ 9,216 
+Income tax expense (benefit) attributable to net income (loss) before income taxes differed from the amounts computed by applying the statutory U.S. federal income tax rate of 21.0% to pre-tax income as a result of the following: 
+Year Ended December 31, 
+($ in thousands) 2023 2022 2021 
+Computed tax expense (benefit) at the statutory rate $ 154,327 $ 83,897 $ ( 37,336 ) 
+Increase (decrease) in tax expense resulting from: 
+State and local income tax expense (benefit), net 15,745 10,224 ( 5,204 ) 
+Non-controlling interest ( 19 ) ( 151 ) 1,565 
+Effect of foreign tax rates 1,818 697 478 
+Stock-based compensation ( 239 ) ( 2,724 ) ( 535 ) 
+Change in valuation allowance — ( 91,336 ) 50,111 
+Other TRA adjustment ( 248 ) ( 2,763 ) — 
+Nondeductible executive compensation 6,514 — — 
+U.S. impact of foreign earnings — 315 — 
+Other, net 584 1,048 137 
+Total income tax expense (benefit) $ 178,482 $ ( 793 ) $ 9,216 
+The effective tax rate for the years ended December 31, 2023, 2022, and 2021 was 24.3 %, ( 0.2 )%, and ( 5.2 )%, respectively. 
+The Company’s effective tax rate is greater than the statutory federal income tax rate of 21.0% due to the Company’s Canadian operations, state income taxes in the states the Company operates, as well as nondeductible executive compensation. 
+F-28 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are presented below: 
+($ in thousands) December 31, 2023 December 31, 2022 
+Deferred tax assets: 
+Federal net operating losses $ — $ 25,570 
+State net operating losses 1,286 5,762 
+Realized tax benefit - TRAs 87,260 99,153 
+Intangibles 22,825 576 
+Lease liabilities 51,504 — 
+Property and equipment — 4,638 
+Stock-based compensation 4,279 — 
+Inventory 3,361 — 
+Other 5,133 450 
+Total deferred tax assets 175,648 136,149 
+Less valuation allowance — — 
+Net deferred tax assets 175,648 136,149 
+Deferred tax liabilities: 
+Investment in Liberty LLC $ — $ ( 121,861 ) 
+Property and equipment ( 221,337 ) — 
+Lease assets ( 55,801 ) — 
+Other ( 850 ) ( 2,740 ) 
+Total deferred tax liabilities ( 277,988 ) ( 124,601 ) 
+Net deferred tax (liability) asset $ ( 102,340 ) $ 11,548 
+During the year ended December 31, 2023, the Company adopted a plan of merger, pursuant to which Liberty LLC merged into the Company, ceasing the existence of Liberty LLC with the Company remaining as the surviving entity. As a result of this change, the Company no longer has a deferred tax liability for the difference between the book value and the tax value of the Company’s investment in Liberty LLC and the associated net deferred tax liability balances have been allocated to the deferred tax asset and liability line items above. Significant deferred tax assets include the step up in basis of depreciable assets under Section 754 (“Section 754”) of the Internal Revenue Code of 1986, as amended and deferred tax liabilities related to property and equipment. 
+As of December 31, 2023, the Company has utilized all U.S. federal net operating loss carryforwards and has $ 1.3 million state net operating loss carryforwards that will not expire in the foreseeable future. 
+The Company may distribute cash from foreign subsidiaries to its U.S. parent as business needs arise. The Company has not provided for deferred income taxes on the undistributed earnings from certain foreign subsidiaries earnings as such earnings are considered to be indefinitely reinvested. If such earnings were to be distributed, any income and/or withholding tax would not be significant. 
+Uncertain Tax Positions 
+The Company records uncertain tax positions on the basis of a two-step process in which (1) the Company determines whether it is more likely than not the tax positions will be sustained on the basis of the technical merits of the position and (2) for those tax positions meeting the more likely than not recognition threshold, the Company recognizes the largest amount of tax benefit that is more than 50% likely to be realized upon ultimate settlement with the related tax authority. 
+The Company determined that no liability for unrecognized tax benefits for uncertain tax positions was required at December 31, 2023. In addition, the Company does not believe that it has any tax positions for which it is reasonably possible that it will be required to record a significant liability for unrecognized tax benefits within the next twelve months. If the Company were to record an unrecognized tax benefit, the Company will recognize applicable interest and penalties related to income tax matters in income tax expense. 
+F-29 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Tax Receivable Agreements 
+The term of each TRA commenced on January 17, 2018, and will continue until all such tax benefits that are subject to such TRA have been utilized or expired, unless the Company experiences a change of control (as defined in the TRAs, which includes certain mergers, asset sales and other forms of business combinations) or the TRAs are terminated early (at the Company’s election or as a result of its breach), and the Company makes the termination payments specified in such TRA. 
+The amounts payable, as well as the timing of any payments, under the TRAs are dependent upon significant future events and assumptions, including the timing of the redemptions of Liberty LLC Units, the price of our Class A Common Stock at the time of each redemption, the extent to which such redemptions are taxable transactions, the amount of the redeeming unit holder’s tax basis in its Liberty LLC Units at the time of the relevant redemption, the characterization of the tax basis step-up, the depreciation and amortization periods that apply to the increase in tax basis, the amount of net operating losses available to the Company as a result of the Corporate Reorganization, the amount and timing of taxable income the Company generates in the future, the U.S. federal income tax rate then applicable, and the portion of the Company’s payments under the TRAs that constitute imputed interest or give rise to depreciable or amortizable tax basis. 
+At December 31, 2023, the Company’s liability under the TRAs was $ 117.7 million of which $ 5.2 million is recorded as a current liability and $ 112.5 million is recorded as a component of long-term liabilities. The Company recorded a gain on remeasurement of the liabilities subject to the TRA of $ 1.8 million recorded as part of continuing operations in the current year. 
+At December 31, 2022, the Company’s liability under the TRAs was $ 118.9 million, all of which was recorded as a component of long-term liabilities, and the related deferred tax assets totaled $ 99.9 million. Upon the release of the valuation allowance, the Company recorded a loss on remeasurement of the liabilities subject to the TRA of $ 76.2 million recorded as part of continuing operations in the prior year. 
+During the year ended December 31, 2023, exchanges of Liberty LLC Units and shares of Class B Common Stock resulted in an increase of $ 0.6 million in amounts payable under the TRAs, and a net increase of $ 0.7 million in deferred tax assets, all of which were recorded through equity. The Company did not make any TRA payments during the year ended December 31, 2023. On January 31, 2023, the Company recorded an increase of $ 6.6 million of deferred tax assets for the impact of the adopted plan of merger for Liberty LLC into the Company, all of which was recorded through equity. 
+During the year ended December 31, 2022, exchanges of Liberty LLC Units and shares of Class B Common Stock resulted in an increase of $ 5.1 million in amounts payable under the TRAs, and a net increase of $ 6.0 million in deferred tax assets, all of which were recorded through equity. The Company did not make any TRA payments during the year ended December 31, 2022. 
+F-30 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Note 13— Defined Contribution Plan 
+The Company sponsors a 401(k) defined contribution retirement plan covering eligible employees. The Company makes matching contribution at a rate of $ 1.00 for each $1.00 of employee contribution, subject to a cap of 6 % of the employee’s salary and federal limits. Contributions made by the Company were $ 32.9 million, $ 25.8 million, and $ 19.0 million for the years ended December 31, 2023, 2022 and 2021, respectively. 
+Note 14— Related Party Transactions 
+Schlumberger Limited 
+During 2020, the Company acquired certain assets and liabilities of Schlumberger Technology Corporation (“Schlumberger”) in exchange for the issuance of shares of the Company ’ s Class A Common Stock amongst other consideration. During the year ended December 31, 2023, the Company repurchased and retired 3,000,000 shares of Class A Common Stock for $ 45.0 million or $ 15.00 average price per share from Schlumberger, under the share repurchase program. Effective January 31, 2023, after the repurchase and retirement, Schlumberger owns no shares of Class A Common Stock of the Company and no longer qualifies as a related party. 
+During the year ended December 31, 2022, the Company repurchased and retired 1,700,000 shares of Class A Common Stock for $ 27.8 million or $ 16.35 average price per share from Schlumberger, under the share repurchase program. 
+On April 29, 2022, the Company, Liberty LLC, Schlumberger, and BofA Securities, Inc. and J.P. Morgan Securities LLC (together, the “Underwriters”), entered into an underwriting agreement, dated as of April 29, 2022, pursuant to which Schlumberger sold 14,500,000 shares of Class A Common Stock at a price of $ 15.50 per share to the Underwriters (the “Sale”). The Sale closed on May 3, 2022. Following the Sale, Schlumberger held 35,101,961 shares of Class A Common Stock. The Company did not receive any proceeds from the Sale. 
+Within the normal course of business, the Company purchases chemicals, proppant and other equipment and maintenance parts from Schlumberger and its subsidiaries. During the period from January 1, 2023 until January 31, 2023, total purchases from Schlumberger were approximately $ 1.7 million. During the years ended December 31, 2022 and 2021, total purchases from Schlumberger were approximately $ 21.7 million and $ 28.2 million, respectively. As of December 31, 2022 amounts due to Schlumberger were $ 2.6 million and $ 0.7 million included in accounts payable and accrued liabilities, respectively, in the consolidated balance sheets. 
+During 2021, a subsidiary of the Company and Schlumberger entered into a property swap agreement under which the Company exchanged with Schlumberger a property and $ 4.9 million in cash for a separate property that the Company will utilize with its existing operations. The Company did not recognize any gain or loss on the transaction. In separate transactions, the Company has sold equipment to Schlumberger including $ 0.1 million and $ 1.3 million during the years ended December 31, 2022 and 2021, respectively. The Company recognized a gain on the sale of equipment of $ 0.0 million and $ 0.9 million, respectively. 
+Franklin Mountain Energy, LLC 
+A member of the board of directors of the Company, Audrey Robertson, serves as Executive Vice President of Finance of Franklin Mountain Energy, LLC (“Franklin Mountain”). During the years ended December 31, 2023, 2022 and 2021, the Company performed hydraulic fracturing services for Franklin Mountain in the amount of $ 176.1 million, $ 131.8 million, and $ 20.5 million, respectively. 
+Amounts included in unbilled revenue from Franklin Mountain as of December 31, 2023 and 2022, were $ 13.4 million and $ 13.9 million, respectively. There were $ 12.1 million and $ 0.0 million in receivables from Franklin Mountain as of December 31, 2023 and 2022, respectively. 
+Liberty Resources LLC 
+Liberty Resources LLC, an oil and gas exploration and production company, and its successor entity (collectively, the “Affiliate”) has certain common ownership and management with the Company. The amounts of the Company’s revenue related to hydraulic fracturing services provided to the Affiliate for the years ended December 31, 2023, 2022 and 2021, were $ 38.8 million, $ 16.7 million and $ 2.8 million, respectively. Amounts included in unbilled revenue and accounts receivable—related party from the Affiliate as of December 31, 2023 were $ 0.0 million and $ 5.2 million, respectively. There were no amounts included in unbilled revenue and accounts receivable—related party from the Affiliate as of December 31, 2022. 
+On December 28, 2022 (the “Agreement Date”), the Company entered into an agreement with the Affiliate to amend payment terms for outstanding invoices due as of the Agreement Date to extend the due dates to April 1, 2024. Additionally, on August 15, 2023, the agreement was further amended in order to extend the due dates for certain invoices to January 1, 2025. Amounts outstanding from the Affiliate, under such agreement, as of December 31, 2023 and 2022 were $ 14.8 million and 
+F-31 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+$ 11.8 million, respectively, included in other assets in the consolidated balance sheets. Any receivable amount outstanding at the end of each month is subject to interest through the end of the agreement. 
+During the years ended December 31, 2023, 2022 and 2021, interest income from the Affiliate was $ 2.0 million, $ 0.0 million , and $ 0.0 million , respectively. 
+PropX Acquisition 
+During 2016, Liberty Holdings entered into a future commitment to invest and become a non-controlling minority member in PropX, the provider of proppant logistics equipment. Effective October 26, 2021, the Company completed the purchase of all membership interest in PropX, refer to Note 3—Acquisitions for further discussion of the transaction. During the period from January 1, 2021 until October 26, 2021, the Company leased proppant logistics equipment from PropX for $ 7.3 million. 
+R/C IV Liberty Big Box Holdings, L.P., a Riverstone Holdings LLC (“Riverstone”) fund and a former significant stockholder of the Company, held a greater than 10 % equity interest in PropX. Christopher Wright, the Chief Executive Officer, Michael Stock, the Chief Financial Officer and Ron Gusek, the President of the Company, held a less than 5 % equity interest in PropX through Big Box Proppant Investments LLC. Cary Steinbeck, a director of the Company, served on the PropX board of directors and held a less than 5 % indirect equity interest in PropX. In addition, Brett Staffieri, a Riverstone appointed director, served on the board of the directors of the Company until June 15, 2021 and on the PropX board of directors until the acquisition date. The PropX Acquisition was reviewed and approved by the disinterested members of the Board and pursuant to the Company’s related party transactions policy . 
+Note 15— Commitments & Contingencies 
+Purchase Commitments (tons are not in thousands) 
+The Company enters into purchase and supply agreements to secure supply and pricing of proppants, transload, and equipment. As of December 31, 2023 and 2022, the agreements provide pricing and committed supply sources for the Company to purchase 1,854,000 tons and 2,915,172 tons, respectively, of proppant through December 31, 2025. Amounts below also include commitments to pay for transport fees on minimum amounts of proppants. Additionally, related proppant transload service commitments run through 2024. 
+Future proppant, transload, and equipment commitments are as follows: 
+($ in thousands) 
+2024 $ 143,884 
+2025 12,960 
+2026 — 
+2027 — 
+2028 — 
+Thereafter — 
+$ 156,844 
+Certain supply agreements contain a clause whereby in the event that the Company fails to purchase minimum volumes, as defined in the agreement, during a specific time period, a shortfall fee may apply. In circumstances where the Company does not make the minimum purchase required under the contract, the Company and its suppliers have a history of amending such minimum purchase contractual terms and in rare cases does the Company incur shortfall fees. If the Company were unable to make any of the minimum purchases and the Company and its suppliers cannot come to an agreement to avoid such fees, the Company could incur shortfall fees in the amounts of $ 25.2 million and $ 5.4 million for the years ended December 31, 2024 and December 31, 2025, respectively. Based on forecasted levels of activity, the Company does not currently expect to incur significant shortfall fees. 
+Included in the commitments for the year ending December 31, 2023 are $ 3.2 million of payments expected to be made in the first quarter of 2024 for the use of certain light duty trucks, heavy tractors, and field equipment used to various degrees in frac and wireline operations. The Company is in negotiations with the third-party owner of such equipment to lease or purchase some or all of such aforementioned vehicles and equipment, subject to agreement on terms and conditions. No gain or loss is expected upon consummation of any such agreement. 
+Litigation 
+From time to time, the Company is subject to legal and administrative proceedings, settlements, investigations, claims and actions. The Company’s assessment of the likely outcome of litigation matters is based on its judgment of a number of factors 
+F-32 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+including experience with similar matters, past history, precedents, relevant financial and other evidence and facts specific to the matter. Notwithstanding the uncertainty as to the final outcome, based upon the information currently available, management does not believe any matters individually or in the aggregate will have a material adverse effect on its financial position or results of operations. 
+Note 16— Subsequent Events 
+On January 23, 2024, the Company’s board of directors approved a quarterly dividend of $ 0.07 per share of Class A Common Stock to be paid on March 20, 2024 to holders of record as of March 6, 2024. 
+Additionally, on January 23, 2024, the Company’s board of directors authorized an increase of the share repurchase program that allows the Company to repurchase an additional $ 250.0 million for a total up to $ 750.0 million of the Company’s Class A Common Stock and extended the authorization through July 31, 2026. 
+No other significant subsequent events have occurred that would require recognition or disclosure in the consolidated financial statements and notes thereto. 
+F-33
\ No newline at end of file
diff --git a/raw/filings/0001694028/2023/0001694028-24-000006/filing_metadata.csv b/raw/filings/0001694028/2023/0001694028-24-000006/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..b5eea8dcbf3e9356e594e3d6bb36daa715a8a1f4
--- /dev/null
+++ b/raw/filings/0001694028/2023/0001694028-24-000006/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0001694028,LBRT,Liberty Energy Inc.,10-K,2024-02-09,2023-12-31,2024-02-09T03:41:06.000Z,0001694028-24-000006,lbrt-20231231.htm,10-K,9846976,1,1,https://www.sec.gov/Archives/edgar/data/1694028/000169402824000006/lbrt-20231231.htm,https://www.sec.gov/Archives/edgar/data/1694028/000169402824000006/,2023,2023,1
diff --git a/raw/filings/0001694028/2023/0001694028-24-000006/item1.txt b/raw/filings/0001694028/2023/0001694028-24-000006/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..c085d331eb6c38b6b128bc5520b1090acdb8efd1
--- /dev/null
+++ b/raw/filings/0001694028/2023/0001694028-24-000006/item1.txt
@@ -0,0 +1,127 @@
+Item 1. Business 
+Our Company 
+We are a leading integrated energy services and technology company focused on providing innovative hydraulic services and related technologies to onshore oil and natural gas exploration and production (“E&P”) companies in North America. We offer customers hydraulic fracturing services, together with complementary services including wireline services, proppant delivery solutions, field gas processing and treating, compressed natural gas (“CNG”) delivery, data analytics, related goods (including our sand mine operations), and technologies that will facilitate lower emission completions, thereby helping our customers reduce their emissions profile. 
+Our areas of operations are in all of the most active shale basins in North America, including the Permian Basin, the Williston Basin, the Eagle Ford Shale, the Haynesville Shale, the Appalachian Basin (Marcellus Shale and Utica Shale), the Western Canadian Sedimentary Basin, the Denver-Julesburg Basin (the “DJ Basin”), and the Anadarko Basin. Our operations also extend to a few smaller shale basins, including the Uinta Basin, the Powder River Basin, and the San Juan Basin. The breadth of our operational footprint provides us an opportunity to leverage our fixed costs and to efficiently reposition our equipment in response to customer requirements. The map below represents our current primary areas of operation. 
+The process of hydraulic fracturing involves pumping a pressurized stream of fracturing fluid (typically a mixture of water, chemicals and proppant) into a well casing or tubing to cause the underground formation to fracture or crack. These fractures release trapped hydrocarbon particles and provide a conductive channel for the oil or natural gas to flow freely to the wellbore for collection. The propping agent, or proppant, typically sand, becomes lodged in the cracks created by the hydraulic fracturing process, “propping” them open to facilitate the flow of hydrocarbons from the reservoir to the well. The fracturing 
+1 
+fluid is engineered to lose viscosity, or “break,” and is subsequently flowed back from the formation, leaving the proppant suspended in the formation fractures. Once our customer has flushed the fracturing fluids from the well using a controlled flow-back process, the customer manages fluid and water recycling or disposal. 
+Our hydraulic fracturing fleets consist of mobile hydraulic fracturing units and other auxiliary heavy equipment to perform fracturing services. Our hydraulic fracturing units consist primarily of high-pressure hydraulic pumps, engines, transmissions, radiators and other supporting equipment that are typically mounted on trailers. We refer to the group of units and other equipment, such as blenders, data vans, sand storage, tractors, manifolds and high-pressure fracturing iron, which are necessary to perform a typical hydraulic fracturing job, as a “fleet,” and the personnel assigned to each fleet as a “crew.” The size of each fleet and crew can vary depending on the requirements of each job design. 
+Wireline operations supplement our hydraulic fracturing fleets, which consist of a truck equipped with a spool of wireline that is lowered into wells to convey specialized tools or equipment, such as perforating guns and charges, which are necessary to connect the wellbore with the target formation. This operation is performed between each hydraulic fracturing stage. Our wireline service is primarily offered alongside our hydraulic fracturing services, which allows us to maximize efficiency for our customers through optimized coordination of the wireline and hydraulic fracturing services. In addition, we also offer our wireline service on a stand-alone basis. 
+We also operate two sand mines that allows us to vertically integrate our supply-chain in the Permian Basin. The mines provide sand to Liberty hydraulic fracturing fleets as well as to third parties. With a secured supply of regional sand in the basin, we reduce our dependency on other providers and any downtime that could result from sand supply issues. 
+As a result of the acquisition of PropX, which was completed in October 2021, we are a leading provider of last-mile proppant delivery solutions, including proppant handling equipment and logistics software across North America. PropX offers innovative environmentally friendly technology with optimized dry and wet sand containers and wellsite proppant handling equipment that drive logistics efficiency and reduce noise and emissions. We believe that PropX wet sand handling technology is a key enabler of the next step of cost and emissions reductions in the proppant industry. PropX also offers customers the latest real-time logistics software, PropConnect™, as a hosted software as a service. 
+In early 2023, we launched Liberty Power Innovations LLC (“LPI”), an integrated alternative fuel and power solutions provider for remote applications. On April 6, 2023, LPI expanded its footprint with the acquisition of Siren Energy & Logistics, LLC (“Siren”) (“the Siren Acquisition”), a Permian focused integrated natural gas compression and CNG delivery business. LPI provides CNG supply, field gas processing and treating, and well site fueling and logistics. LPI was formed with the initial focus on supporting Liberty’s transition towards our next generation digiFleets℠ and dual fuel fleets, as CNG fueling services are limited in the market, yet critical to maintaining highly efficient well site operations. Currently, LPI is primarily focused on supporting an industry transition to natural gas fueled technologies, serving as a key enabler of the next step of cost and emissions reductions in the oilfield. 
+Our operations are organized into a single business segment, which consists of hydraulic fracturing services, including wireline, proppant delivery and goods, including our Permian Basin sand mines, and natural gas compression and delivery, and we have one reportable geographical segment, North America. We have grown from one active hydraulic fracturing fleet as of December 2011 to over 40 active fleets as of December 31, 2023. We are focused on providing “next-generation” frac fleets and technologies to assist our customers with completing their wells in an environmental, social, and governance (“ESG”) friendly manner. 
+Our founders and management are pioneers in the development of data-driven hydraulic fracturing technologies for application in shale plays. Prior to founding the Company, the majority of our management team founded and built Pinnacle Technologies, Inc. (“Pinnacle Technologies”) into a leading fracturing technology company. In 1992, Pinnacle Technologies developed the first commercial hydraulic fracture mapping technologies, analytical tools that played a major role in launching the shale revolution. Our extensive experience with fracture technologies and customized fracture design has enabled us to develop new technologies and processes that provide our customers with real-time solutions that significantly enhance their completions. These technologies include hydraulic fracture propagation models, reservoir engineering tools, large, proprietary shale production databases and multi-variable statistical analysis techniques. Taken together, these technologies have enabled us to be a leader in hydraulic fracture design innovation and application. Our management team has an average of over 20 years of energy services experience, and the majority of our management team worked together before founding our company. 
+We believe technical innovation and strong relationships with our customer and supplier bases distinguish us from our competitors and are the foundations of our business. We expect that E&P companies will continue to focus on technological innovation as completion complexity and fracture intensity of horizontal wells increases, particularly as customers are increasingly focused on reducing emissions from their completions operations. We remain proactive in developing innovative solutions to industry challenges, including developing: (i) our databases of U.S. unconventional wells to which we apply our proprietary multi-variable statistical analysis technologies to provide differential insight into fracture design optimization; (ii) 
+2 
+our Liberty Quiet Fleet® design which significantly reduces noise levels compared to conventional hydraulic fracturing fleets; (iii) hydraulic fracturing fluid systems tailored to the specific reservoir properties in the basins in which we operate; (iv) our dual fuel dynamic gas blending (“DGB”) fleets that allow our engines to run diesel or a combination of diesel and natural gas, to optimize fuel use, reduce emissions and lower costs; (v) our digiFleets℠, comprising of digiFrac℠ and digiPrime℠ pumps, our innovative, purpose-built electric and hybrid frac pumps that have approximately 25% lower CO2e emission profile than the Tier IV DGB; (vi) our wet sand handling technology which eliminates the need to dry sand, enabling the deployment of mobile mines nearer to wellsites; and (vii) the launch of LPI to support the transition to our digiFleets as well as the transition to lower costs and emissions in the oilfield. In addition, our integrated supply chain includes proppant, chemicals, equipment, natural gas fueling services, logistics and integrated software which we believe promotes wellsite efficiency and leads to more pumping hours and higher productivity throughout the year to better service our customers. In order to achieve our technological objectives, we carefully manage our liquidity and debt position to promote operational flexibility and invest in the business throughout the full commodity cycle in the regions we operate. 
+ESG Focused 
+We support all energy sources that improve our energy system and better lives. We passionately work to better the process of bringing hydrocarbons to the surface in a clean, safe and efficient fashion and view these principles as foundational to our business. We focus on developing and adding technologies to our operations that assist our customers in implementing their goals. The list below sets forth specific examples of our efforts in this regard: 
+• In 2013, we introduced Tier II dual-fuel technology to our fleets which allows our frac pumps to use natural gas in place of some diesel fuel to lower particulate emissions. 
+• In 2014, we began the use of containerized sand delivery at frac locations, which reduces dust, noise and truck traffic. 
+• In 2016, we introduced Quiet Fleet® technology, which significantly reduces noise levels associated with frac operations. 
+• In 2018, we partnered with an equipment supplier to introduce Tier IV dynamic gas blending, or DGB, engines to our frac fleet that can substitute up to 80% of the diesel typically used by a frac pump with natural gas and significantly lower emission levels in frac operations. Tier IV DGB engines were added to our fleet in 2020. 
+• In 2018, we began the design and development of digiFrac SM , our innovative, purpose-built electric frac pump that has approximately a 25% lower CO2e emission profile than the Tier IV DGB. 
+• In 2021, we announced the successful test of digiFrac and in 2022 commenced delivery of commercial pumps. 
+• In October 2021, we acquired PropX, a leading provider of last-mile proppant delivery solutions including proppant handling equipment and logistics software. PropX offers innovative, environmentally friendly technology with optimized dry and wet sand containers and wellsite proppant handling equipment that drive logistics efficiency and reduce noise and emissions. 
+• In 2022, we began the design and development of digiPrime SM , the first hybrid pump technology, utilizing direct mechanical drive for the pumps while simultaneously generating power capable of electrifying supporting equipment at the well site. These pumps have a lower CO2e emissions profile than digiFrac. 
+• In 2023, we launched LPI and closed the acquisition of Siren. We believe that the shift in fuel consumption from diesel to cleaner natural gas has the potential to promote emissions reductions in the industry. 
+• In 2023, we commenced deployment of digiFleets SM , comprised of digiFrac and digiPrime pump technology along with other complementary equipment from our digiTechnologies SM suite. 
+• In January 2024, we established the Bettering Human Lives Foundation, a non-profit organization dedicated to improving the well-being of communities worldwide with an early focus on promoting clean cooking solutions. 
+• In February 2024, we released the third edition of our Bettering Human Lives report, emphasizing energy’s central role in human lives. The report has been updated to include real-world case studies and is now segmented into six sections: Energy, Energy and the Modern World, Energy Poverty, Climate Change, Climate Economics, and an in-depth section on Liberty Energy. 
+3 
+Furthermore, we are continuously committed to engagement in our communities. We provide K-12 scholarships to low-income children through ACE (Alliance for Choice in Education) and we have launched a Liberty Scholars program at Montana Technological University to enable lower-income students to obtain a college education. In total, over 140 students received Liberty scholarships across the U.S. and Canada in 2023. In addition to our educational initiatives, we have other efforts targeting veterans, poverty abatement, low-income housing, criminal justice reform, and job opportunities for those who had a disadvantaged start in life. To double our impact and encourage our employees to get involved in their communities, we launched Love, Liberty, our corporate matching program in 2021. In 2023, Liberty processed over 100 match requests to nearly 50 different organizations, totaling nearly $30,000 in matching contributions. 
+Cyclical Nature of Industry 
+We operate in a cyclical industry reflecting global oil and gas supply and demand dynamics, current and expected future oil and gas commodity prices, and the perceived stability and sustainability of those prices. Global oil and gas supply and demand can be impacted by general domestic and international economic conditions, inflationary pressures, geopolitical developments, government regulations, and other factors. Such factors also impact capital expenditures and drilling and completions activities of E&P companies, which in turn can impact demand for our services. For these reasons, the results of our operations may fluctuate from quarter to quarter and from year to year, and these fluctuations may distort comparisons of results across periods. 
+Seasonality 
+Our results of operations have historically reflected seasonal tendencies relating to holiday seasons, inclement weather and the conclusion of our customers’ annual drilling and completion capital expenditure budgets. Our most notable declines typically occur in the fourth quarter of the year for the reasons described above. Additionally, some of the areas in which we have operations, including Canada, the DJ Basin, Powder River Basin and Williston Basin, are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice, rain, or frost, and related road restrictions, we may be unable to move our equipment between locations, thereby reducing our ability to provide services and generate revenues. The exploration activities of our customers may also be affected during such periods of adverse weather conditions. Additionally, extended drought conditions in our operating regions could impact our ability or our customers’ ability to source sufficient water or increase the cost for such water. 
+Intellectual Property 
+Over the last several years and in connection with the acquisitions of PropX, Siren, and others in prior periods, we have significantly invested in our research and technology capabilities. Our efforts to date have been focused on developing innovative, fit-for-purpose solutions designed to enhance our core service offerings, increase completion efficiencies, provide cost savings to our operations and add value for our customers. A cornerstone of our technological advantage is a series of proprietary databases of U.S. unconventional wells that include production data, completion designs and reservoir characteristics. We utilize these databases to perform multi-variable statistical analysis that generates differential insight into fracture design optimization to enhance our customers’ production economics. Our emphasis on data analytics is also deployed during job execution through the use of real-time feedback on variables that maximizes customer returns by improving cost-effective hydraulic fracturing operations. 
+Today, we hold approximately 500 patents and patent licenses relating to our engineering and technology solutions. We seek patent and trademark protections for our technology when we deem it prudent, and we aggressively pursue protection of these rights when warranted. We believe our patents, trademarks, and other protections for our proprietary technologies are adequate for the conduct of our business and that no single patent or trademark is critical to our business. In addition, we rely, to a great extent, on the technical expertise and know-how of our personnel to maintain our competitive position, and we take commercially reasonable measures to protect trade secrets and other confidential and/or proprietary information relating to the technologies we develop. 
+4 
+Human Capital Management 
+As of December 31, 2023, we had approximately 5,500 employees and no unionized labor. We believe we have good relations with our employees and that one of our key competitive advantages is our people. Our highly trained, experienced and motivated employees are critical to delivering our hydraulic fracturing services. Taking care of our employees is one of our top priorities, and we continually invest in hiring, training and retaining the employees we believe to be the best in our field. We consistently assess the current business environment and labor market to refine our compensation and benefits programs in order to attract and retain top talent in our industry. We strive to promote from within our existing employee base to manage new hydraulic fracturing fleets and organically grow our operating expertise. This organic growth is essential in achieving the expertise and level of customer service we strive to provide each of our customers. As a result, we plan to continue to invest in our employees through both personal and professional training to attract and retain the best individuals in our areas of operation. Overall, we focus on individual contributions and team success to foster a culture built around operational excellence and superior safety. 
+Health and Safety 
+Our people are our most important asset and ensuring their safety and the safety of those around them is the most important thing we do. Making certain that the Liberty team is well trained to handle the complexities of daily field operations, and that their training and competency remains current with the latest technology and standards is a key component. In order to facilitate this training, we have developed the Liberty Frac Academy, a thorough program where employees are trained on various aspects of the Company, from safety in equipment operation to leadership skills. The Liberty Frac Academy not only ensures dissemination of high-quality training material, but also provides a forum for sharing best practices and lessons learned across the Company. As a result, we are among the safest service providers in the industry with a constant focus on Health, Safety and Environmental performance and service quality, as evidenced by an average incident rate that was consistently lower than the industry average from 2021 to 2023. Our employee-centered focus and reputation for safety has enabled us to obtain projects from industry leaders with some of the most demanding safety and operational requirements. 
+Programs and Benefits 
+One way we have demonstrated a history of investing in our workforce is by offering competitive salaries and wages. To foster a strong sense of ownership, restricted stock units are provided to eligible employees under our long-term incentive plan. Furthermore, we offer innovative benefits to all eligible employees, including, among others, comprehensive health insurance coverage, parental leave to all new parents, for birth or adoption, financial support for child adoption, leave to care for partners with serious health conditions, 401(k) savings plan and educational tuition assistance for both bachelor’s degree and master’s degree programs. We are also passionate about community investment and are a part of the Ban the Box initiative which provides work opportunities for formerly incarcerated individuals. 
+Governmental Regulation and Climate Change 
+As a company with operations in both the United States and Canada, we are subject to the laws of both jurisdictions in which we operate and the rules and regulations of various governing bodies, which may differ among those jurisdictions. Compliance with these laws, rules and regulations has not had, and is not expected to have, a material effect on our capital expenditures, results of operations and competitive position as compared to prior periods. We are also subject to numerous environmental and regulatory requirements related to our operations. For further information related to such regulation, see the risks described under the heading “Risk Factors” in this Annual Report. 
+Our operations are subject to numerous stringent and complex laws and regulations at the federal, state, and local levels governing the discharge of materials into the environment, environmental protection, and health and safety aspects of our operations. Failure to comply with these laws and regulations or to obtain or comply with permits may result in the assessment of administrative, civil, and criminal penalties, imposition of remedial or corrective action requirements, and the imposition of injunctions or other orders to prohibit certain activities, restrict certain operations, or force future compliance with environmental requirements. 
+There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons, other hazardous substances, and wastes, as a result of air emissions and wastewater discharges related to our operations, and because of historical operations and waste disposal practices. Spills or other releases of regulated substances, including such spills and releases that occur in the future, could expose us to material losses, expenditures, and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. The following is a summary of some of the existing laws, rules, and regulations to which we are subject. 
+5 
+U.S. Laws and Regulations 
+Hazardous Substances and Waste Handling 
+The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Under guidance issued by the U.S. Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. RCRA currently exempts many E&P wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes intrinsically associated with the exploration, development, or production of crude oil and natural gas. However, these E&P wastes may still be regulated under state solid waste laws and regulations, and it is possible that certain oil and natural gas E&P wastes now classified as non-hazardous could be classified as hazardous waste in the future. Stricter regulation of wastes generated during our or our customers’ operations could result in increased costs for our operations or the operations of our customers, which could in turn reduce demand for our services and adversely affect our business. We cannot guarantee that the EPA will not revisit the exemption of E&P waste or that waste will not become more heavily regulated at the federal or state level. 
+Comprehensive Environmental Response, Compensation, and Liability Act 
+The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owner or operator of the site where the release occurred and anyone who transported or disposed or arranged for the transport or disposal of a hazardous substance released at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA and any state analogs may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources and for the costs of certain health studies. We currently own, lease, or operate numerous properties that have been used for manufacturing and other operations for many years. These properties and the substances disposed or released on them may be subject to CERCLA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. 
+Worker Health and Safety 
+We are subject to a number of federal and state laws and regulations, including the OSHA regulatory standards, which establish requirements to protect the health and safety of workers. Among others, we may be subject to OSHA regulations for safe operation of cranes, power industrial trucks and similar equipment at our worksites, safe practices for working in hazardous locations and permit-required confined spaces, and proper use of required personal protective equipment by workers. OSHA’s hazard communication standard requires tracking of hazardous chemicals present at the worksite, sharing of such information with the workers, and training the workers to handle the chemicals appropriately. The EPA’s community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes also require maintenance of information about hazardous materials used or produced in operations and provision of this information to employees, state and local government authorities, and citizens. We are also subject to OSHA’s regulatory standard for respirable crystalline silica, which provides measures to protect workers in hydraulic fracturing operations from exposure to this chemical including limiting exposure to airborne respirable crystalline silica in excess of a specified limit. Additionally, the Federal Motor Carrier Safety Administration (the “FMCSA”) regulates and provides safety oversight of commercial motor vehicles, the EPA establishes requirements to protect human health and the environment, the federal Bureau of Alcohol, Tobacco, Firearms and Explosives establishes requirements for the safe use and storage of explosives, and the federal Nuclear Regulatory Commission establishes requirements for the protection against ionizing radiation. We are subject to Mine Safety & Health Administration regulations related to operation of sand mines including regulations for training and retraining of workers engaged in sand mine operations. Substantial fines and penalties can be imposed, and orders or injunctions limiting or prohibiting certain operations may be issued, in connection with any failure to comply with these laws and regulations. 
+6 
+Water Discharges 
+The federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the U.S. The discharge of pollutants into regulated waters, including jurisdictional wetlands, is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. To the extent the agencies expanding the range of properties subject to the Clean Water Act’s jurisdiction or impose more stringent requirements on discharges of wastewater, certain energy companies could face increased costs and delays with respect to obtaining permits, including for the discharge of dredge and fill activities in waters of the U.S. or wetland areas, which in turn could reduce demand for our services. Furthermore, the process for obtaining permits has the potential to delay our operations and those of our customers. Spill prevention, control, and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture, or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of wastewater and storm water runoff from certain types of facilities. The Clean Water Act and analogous state laws provide for administrative, civil, and criminal penalties for unauthorized discharges and, together with the Oil Pollution Act of 1990, impose rigorous requirements for spill prevention and response planning, as well as substantial potential liability for the costs of removal, remediation, and damages in connection with any unauthorized discharges. 
+Air Emissions 
+The federal Clean Air Act (the “CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants and other air emissions at specified sources. These regulations change frequently. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements, utilize specific equipment or technologies to control emissions of certain pollutants or prohibit certain types of emissions management practices. In recent years, the CAA has been used to impose additional stringent requirements upon oil and gas production operations. While these rules may not be directly applicable to our business, they are applicable to the business of our customers. Promulgation of stricter permitting or emission control requirements could delay or impair our or our customers’ ability to obtain air emission permits, to develop new wells and to continue to operate existing wells, and result in fewer wells being drilled or redeveloped, causing a decrease in demand for our services. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties, as well as injunctive relief, for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. 
+Climate Change 
+The EPA has determined that emissions of greenhouse gases, including carbon dioxide and methane, present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. The EPA has established greenhouse gas emissions reporting requirements for sources in the oil and gas sector and has also promulgated rules requiring certain large stationary sources of greenhouse gases to obtain preconstruction permits under the CAA and follow “best available control technology” requirements. Although we are not likely to become subject to greenhouse gas emissions permitting and best available control technology requirements because none of our facilities are presently major sources of greenhouse gas emissions, such requirements could become applicable to our customers. In addition, the EPA has used the CAA to impose additional greenhouse gas emissions control requirements upon our customers. Furthermore, the Inflation Reduction Act (“IRA 2022”) imposes a methane emissions charge on certain emissions from specific classes of sources that are required to report their greenhouse gas emissions, which began in calendar year 2024. This fee as well as additional requirements on greenhouse gas emissions from our customers could have an adverse effect on their costs of operations or financial performance, thereby adversely affecting our business, financial condition, and results of operations. Also, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, and many states have already established regional greenhouse gas “cap-and-trade” programs. The adoption of any legislation or regulation that restricts emissions of greenhouse gases from the equipment and operations of our customers or with respect to the oil and natural gas they produce could adversely affect demand for our products and services. 
+7 
+Hydraulic Fracturing 
+Our business is clearly dependent on hydraulic fracturing and horizontal drilling activities. As further described herein, hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shale. The process, which involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. Specifically, there is considerable uncertainty surrounding regulation of the emissions of methane, which may be released during hydraulic fracturing, chemicals used in the hydraulic fracturing process, the discharge of wastewater from hydraulic fracturing operations and concerns about the triggering of seismic activity by the injection of produced waters into underground wells. Certain proposed regulation could make it significantly more difficult and/or costly to drill and operate oil and gas wells. If adopted, such regulation could result in a decline in the completion of new oil and gas wells or the recompletion of existing wells, which could negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the demand for our services. Given the long-term trend towards increasing regulation, future regulation in the industry remains a possibility. 
+Some states, counties, and municipalities have enacted or are considering moratoria on hydraulic fracturing. For example, New York, Vermont, Maryland, and Washington have banned the use of high-volume hydraulic fracturing. Alternatively, some municipalities are, or have considered, zoning and other ordinances, the conditions of which could impose a de facto ban on drilling and/or hydraulic fracturing operations. Further, some states, counties, and municipalities are closely examining water use issues, such as permit and disposal options for processed water, which could have a material adverse impact on our financial condition, prospects, and results of operations if such additional permitting requirements are imposed upon our industry. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could reduce demand for our business by making it more difficult or costly for certain customers to perform fracturing to stimulate production from tight formations. 
+National Environmental Policy Act 
+Businesses and operations of our customers that are carried out on federal lands may be subject to the National Environmental Policy Act (“NEPA”), which requires federal agencies, including the U.S. Department of the Interior, to evaluate major agency actions having the potential to significantly impact the human environment. In the course of such evaluations, an agency will evaluate the potential direct, indirect, and cumulative impacts of a proposed project and, if necessary, will prepare a detailed Environmental Impact Statement that must be made available for public review and comment. To the extent that our customers’ current activities, as well as proposed plans, on federal lands require governmental permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects which in turn could reduce demand for our services. 
+Endangered Species Act and Migratory Bird Treaty Act 
+The federal Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or its habitat. The U.S. Fish and Wildlife Service (the “FWS”) must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development and development of sand mines used for hydraulic fracturing. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”), which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit. This prohibition covers most bird species in the U.S. Future implementation of the rules implementing the ESA and the MBTA are uncertain. If we or our customers were to have areas within our respective operations designated as critical or suitable habitat for a protected species, it could decrease demand for our services and have a material adverse effect on our business. 
+Canadian Laws and Regulations 
+Companies such as us offering energy services that include hydraulic fracturing, engineering, and wireline services in the Province of Alberta in Canada are regulated by both the provincial government of Alberta (“Province”) and the federal government of Canada (“Canada”). This includes, but is not limited to, regulation related to environmental protection legislation, climate change legislation, fracking legislation, and legislation related to wildlife. In addition to being regulated by the Province and Canada, energy services companies may also be subject to other international, national, and subnational laws, regulations, and policies. 
+Provincial Legislation 
+Energy services companies are primarily regulated by provincial governments in Canada. For example, in Alberta, provincial legislation potentially applicable to our Canadian operations includes the Environmental Protection and 
+8 
+Enhancement Act , RSA 2000, e E-12. This Act promotes the protection, enhancement and wise use of the environment, and deals with matters such as air emissions, water discharges, and the handling of hazardous substances and waste control (for example, under the Waste Control Regulation , Alta Reg 192/1996). Other environmental legislation in the Province that applies to energy service companies includes: the Water Act, RCA 2000, c W-3 and associated regulations, under which companies must apply for a license for any water use; and the Wildlife Act, RCA 2000, c W-10 which provides for the protection and conservation of wild animals and endangered species in Alberta. 
+Other potentially applicable provincial legislation in Alberta includes legislation directed at the transportation of dangerous goods, including oil (the Dangerous Goods Transportation and Handling Act , RSA 2000, c D-4 and associated regulations), legislation intended to provide for the responsible management of oil wells and associated sites, including remediation responsibilities (the Oil and Gas Conservation Act , RSA 2000, c O-6 and associated regulations), legislation establishing regulatory bodies overseeing oil and gas and electricity in Alberta (the Responsible Energy Development Act , SA 2012, c R-17.3 and the Alberta Utilities Commission Act , SA 2007, c A-37.2), legislation governing the removal of gas or propane from Alberta (the Gas Resources Preservation Act , RSA 2000, c G-4), legislation to effect conservation and prevent waste of the oil sands resource in Alberta (the Oil Sands Conservation Act , RSA 2000, c O-7), and legislation governing worker safety (the Occupational Health and Safety Act , SA 2017, c O-2.1). 
+The Alberta Energy Regulator has a number of directives that are applicable to energy services companies, such as Directive 050, updated in March 2023, which addresses salinity ranges for soils that can receive drilling wastes, Directive 058, which sets out regulatory requirements for the handling, treatment, and disposal of upstream oilfield waste, and Directive 083, updated April 2023, which sets out the requirements for managing subsurface integrity associated with hydraulic fracturing, including seismic monitoring in certain areas of Alberta. Other provinces in Canada have their own statutory regime applicable to oilfield service companies. 
+Federal Legislation 
+The Federal government in Canada shares certain jurisdiction with the provinces over certain environmental matters. Federal legislation potentially applicable to our Canadian operations includes legislation focused on regulating greenhouse gases (the Greenhouse Gas Pollution Pricing Act, SC 2018, c 12, s 186), legislation aimed at protecting wildlife (the Species at Risk Act , SC 2002, c 29, Fisheries Act, RSC 1985, c F-14, and Migratory Birds Convention Act, 1994, SC 1994, c 22), and legislation governing the transportation of potentially dangerous substances and prevention of pollution (the Transportation of Dangerous Goods Act, 1992 , SC 1992, c 34 and Canadian Environmental Protection Act, 1999, SC 1999, c 33). 
+Environmental assessment of major projects in Canada is shared between the federal and provincial governments. In October 2023 the Supreme Court of Canada ruled that Canada’s Impact Assessment Act , SC 2019, c 28, s1, which governs approvals for federally regulated projects, is largely unconstitutional ( Reference re Impact Assessment Act , 2023 SCC 23). The federal government is currently amending its environmental impact assessment legislation in response to the decision. 
+9 
+Properties 
+Properties 
+Our corporate headquarters are located at 950 17 th Street, Suite 2400, Denver, Colorado 80202. We lease our general office space at our corporate headquarters. The lease expires in December 2027. We currently own or lease the following additional principal properties: 
+District Facility Location Size Leased or Owned 
+Midland, TX 90,000 sq. ft on 35 acres Owned 
+Midland, TX 70,000 sq. ft on 12 acres Owned 
+Odessa, TX 77,500 sq. ft on 48 acres Owned 
+Cibolo, TX 90,000 sq. ft on 34 acres Owned 
+Kermit, TX 5,000 acres Owned 
+Monahans, TX 3,200 acres Owned 
+Magnolia, TX 63,350 sq. ft. Leased (through May 31, 2031) 
+Magnolia, TX 11,680 sq. ft Leased (through February 28, 2025) 
+Gainesville, TX 170,000 sq. ft. Leased (through May 31, 2024) 
+Shreveport, LA 215,000 sq ft. on 45 acres Owned 
+Cheyenne, WY 115,000 sq. ft on 60 acres Owned 
+Gillette, WY 32,757 sq. ft on 15 acres Leased (through December 31, 2034) 
+Henderson, CO 50,000 sq. ft on 13 acres Leased (through December 31, 2034) 
+Henderson, CO 96,582 sq. ft on 12 acres Owned 
+Williston, ND 55,000 sq. ft on 50 acres Owned 
+Vernal, UT 30,901 sq. ft on 10 acres Leased (through September 30, 2025) 
+Farmington, NM 34,000 sq. ft on 30 acres Owned 
+Farmington, NM 23,000 sq. ft on 9 acres Owned 
+El Reno, OK 80,000 sq. ft on 33 acres Owned 
+Red Deer, AB 170,000 sq. ft on 42 acres Owned 
+Grand Prairie, AB 135,000 sq. ft on 40 acres Owned 
+Huallen, AB 80 acres Owned 
+We also lease several smaller facilities, which leases generally have terms of one to six years. We believe that our existing facilities are adequate for our operations and their locations allow us to efficiently serve our customers. We do not believe that any single facility is material to our operations and, if necessary, we could readily obtain a replacement facility. 
+Marketing and Customers 
+We have developed long-term partnerships with our customers through a continuous dialogue focused on their production economics. Further, we have a proven track record of executing our customers’ plans and delivering on time and in line with expected costs. Our customer base includes a broad range of integrated and independent E&P companies, including some of the largest E&P companies in our areas of operation. Our technological innovations, customer-tailored approach and track record of consistently providing high-quality, safe and reliable service has allowed us to develop long-term customer partnerships, which we believe makes us the service provider of choice for many of our customers. 
+Our sales and marketing activities typically are performed through our local sales representatives in each geographic region and are supported by our corporate headquarters. For the years ended December 31, 2023, 2022 and 2021, our top five customers collectively accounted for approximatel y 34% , 30%, and 27% of our revenues, respectively. For the years ended December 31, 2023, 2022, and 2021, no customer accounted for more than 10% of our revenues. 
+10 
+Suppliers and Raw Materials 
+We have a dedicated supply chain team that manages sourcing and logistics to ensure flexibility and continuity of supply in a cost-effective manner across our areas of operation. We have built long-term relationships with multiple industry leading suppliers of proppant, chemicals and hydraulic fracturing equipment and have started to internally design and assemble key pump and maintenance parts. In addition, we have built a strong relationship with the assemblers of our custom-designed hydraulic fracturing fleets and believe we will continue to have timely access to new, high capability fleets as we continue to grow. In 2018, we vertically integrated a supplier of certain major components through the acquisition of ST9 Gas and Oil LLC, which recently changed its name to Liberty Advanced Equipment Technologies LLC. In October 2021, we vertically integrated a supplier of our containerized sand and last mile proppant logistics solutions with the acquisition of PropX. This, along with our two state-of-the-art sand mines in the Permian Basin, help us alleviate the risk of proppant supply shortages. 
+We purchase a wide variety of raw materials, parts and components that are manufactured and supplied for our operations. We are not dependent on any single source of supply for those parts, supplies or materials. To date, we have generally been able to obtain the equipment, parts and supplies necessary to support our operations, although we have experienced delivery delays and shortages on some items. While we believe that we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers, we may not always be able to do so. In addition, certain materials for which we do not currently have long-term supply agreements could experience shortages and significant price increases in the future. As a result, we may be unable to mitigate any future supply shortages and our results of operations, prospects and financial condition could be adversely affected. 
+Competition 
+The markets in which we operate are highly competitive. We provide services in various geographic regions across the United States and Canada, and our competitors include many large and small oilfield service providers, including some of the largest integrated service companies. Our hydraulic fracturing services compete with large, integrated companies such as Halliburton Company as well as other companies including Patterson-UTI Energy Inc., ProFrac Holding Corp., and ProPetro Services, Inc. In addition, we compete regionally with smaller service providers. 
+We believe that the principal competitive factors in the markets we serve are technical expertise, equipment capacity, work force competency, efficiency, safety record, reputation, experience and price. Additionally, projects are often awarded on a bid basis, which tends to create a highly competitive environment. We seek to differentiate ourselves from our competitors by delivering the highest-quality services and equipment possible, coupled with superior execution and operating efficiency in a safe working environment. 
+Available Information 
+We file or furnish annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The SEC also maintains an internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC. 
+We also make available free of charge through our website, www.libertyenergy.com, electronic copies of certain documents that we file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. 
+11
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+Item 13. Certain Relationships and Related Transactions, and Director Independence 
+The information required by this item concerning certain relationships and related person transactions and director independence is incorporated herein by reference to our definitive proxy statement for our 2023 annual meeting of stockholders, which will be filed with the SEC no later than 120 days after December 31, 2023, under the captions “Certain Relationships and Related Party Transactions” and “the Board and its Committees.”
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+Item 9A. Controls and Procedures 
+Evaluation of Disclosure Controls and Procedures’ 
+In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2023 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures. 
+During the year ended December 31, 2023, we integrated accounting functions of the entity acquired in the Siren Acquisition on April 6, 2023. In connection with the integration, we updated documentation of our internal controls over financial reporting, as necessary, to reflect modifications to business processes and accounting procedures impacted. 
+There were no other changes to our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+See page F-1 for Management’s Report on Internal Control Over Financial Reporting and page F-4 for Report of Independent Registered Public Accounting Firm on its assessment of our internal control over financial reporting.
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+Note 14— Related Party Transactions 
+Schlumberger Limited 
+During 2020, the Company acquired certain assets and liabilities of Schlumberger Technology Corporation (“Schlumberger”) in exchange for the issuance of shares of the Company ’ s Class A Common Stock amongst other consideration. During the year ended December 31, 2023, the Company repurchased and retired 3,000,000 shares of Class A Common Stock for $ 45.0 million or $ 15.00 average price per share from Schlumberger, under the share repurchase program. Effective January 31, 2023, after the repurchase and retirement, Schlumberger owns no shares of Class A Common Stock of the Company and no longer qualifies as a related party. 
+During the year ended December 31, 2022, the Company repurchased and retired 1,700,000 shares of Class A Common Stock for $ 27.8 million or $ 16.35 average price per share from Schlumberger, under the share repurchase program. 
+On April 29, 2022, the Company, Liberty LLC, Schlumberger, and BofA Securities, Inc. and J.P. Morgan Securities LLC (together, the “Underwriters”), entered into an underwriting agreement, dated as of April 29, 2022, pursuant to which Schlumberger sold 14,500,000 shares of Class A Common Stock at a price of $ 15.50 per share to the Underwriters (the “Sale”). The Sale closed on May 3, 2022. Following the Sale, Schlumberger held 35,101,961 shares of Class A Common Stock. The Company did not receive any proceeds from the Sale. 
+Within the normal course of business, the Company purchases chemicals, proppant and other equipment and maintenance parts from Schlumberger and its subsidiaries. During the period from January 1, 2023 until January 31, 2023, total purchases from Schlumberger were approximately $ 1.7 million. During the years ended December 31, 2022 and 2021, total purchases from Schlumberger were approximately $ 21.7 million and $ 28.2 million, respectively. As of December 31, 2022 amounts due to Schlumberger were $ 2.6 million and $ 0.7 million included in accounts payable and accrued liabilities, respectively, in the consolidated balance sheets. 
+During 2021, a subsidiary of the Company and Schlumberger entered into a property swap agreement under which the Company exchanged with Schlumberger a property and $ 4.9 million in cash for a separate property that the Company will utilize with its existing operations. The Company did not recognize any gain or loss on the transaction. In separate transactions, the Company has sold equipment to Schlumberger including $ 0.1 million and $ 1.3 million during the years ended December 31, 2022 and 2021, respectively. The Company recognized a gain on the sale of equipment of $ 0.0 million and $ 0.9 million, respectively. 
+Franklin Mountain Energy, LLC 
+A member of the board of directors of the Company, Audrey Robertson, serves as Executive Vice President of Finance of Franklin Mountain Energy, LLC (“Franklin Mountain”). During the years ended December 31, 2023, 2022 and 2021, the Company performed hydraulic fracturing services for Franklin Mountain in the amount of $ 176.1 million, $ 131.8 million, and $ 20.5 million, respectively. 
+Amounts included in unbilled revenue from Franklin Mountain as of December 31, 2023 and 2022, were $ 13.4 million and $ 13.9 million, respectively. There were $ 12.1 million and $ 0.0 million in receivables from Franklin Mountain as of December 31, 2023 and 2022, respectively. 
+Liberty Resources LLC 
+Liberty Resources LLC, an oil and gas exploration and production company, and its successor entity (collectively, the “Affiliate”) has certain common ownership and management with the Company. The amounts of the Company’s revenue related to hydraulic fracturing services provided to the Affiliate for the years ended December 31, 2023, 2022 and 2021, were $ 38.8 million, $ 16.7 million and $ 2.8 million, respectively. Amounts included in unbilled revenue and accounts receivable—related party from the Affiliate as of December 31, 2023 were $ 0.0 million and $ 5.2 million, respectively. There were no amounts included in unbilled revenue and accounts receivable—related party from the Affiliate as of December 31, 2022. 
+On December 28, 2022 (the “Agreement Date”), the Company entered into an agreement with the Affiliate to amend payment terms for outstanding invoices due as of the Agreement Date to extend the due dates to April 1, 2024. Additionally, on August 15, 2023, the agreement was further amended in order to extend the due dates for certain invoices to January 1, 2025. Amounts outstanding from the Affiliate, under such agreement, as of December 31, 2023 and 2022 were $ 14.8 million and 
+F-31 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+$ 11.8 million, respectively, included in other assets in the consolidated balance sheets. Any receivable amount outstanding at the end of each month is subject to interest through the end of the agreement. 
+During the years ended December 31, 2023, 2022 and 2021, interest income from the Affiliate was $ 2.0 million, $ 0.0 million , and $ 0.0 million , respectively. 
+PropX Acquisition 
+During 2016, Liberty Holdings entered into a future commitment to invest and become a non-controlling minority member in PropX, the provider of proppant logistics equipment. Effective October 26, 2021, the Company completed the purchase of all membership interest in PropX, refer to Note 3—Acquisitions for further discussion of the transaction. During the period from January 1, 2021 until October 26, 2021, the Company leased proppant logistics equipment from PropX for $ 7.3 million. 
+R/C IV Liberty Big Box Holdings, L.P., a Riverstone Holdings LLC (“Riverstone”) fund and a former significant stockholder of the Company, held a greater than 10 % equity interest in PropX. Christopher Wright, the Chief Executive Officer, Michael Stock, the Chief Financial Officer and Ron Gusek, the President of the Company, held a less than 5 % equity interest in PropX through Big Box Proppant Investments LLC. Cary Steinbeck, a director of the Company, served on the PropX board of directors and held a less than 5 % indirect equity interest in PropX. In addition, Brett Staffieri, a Riverstone appointed director, served on the board of the directors of the Company until June 15, 2021 and on the PropX board of directors until the acquisition date. The PropX Acquisition was reviewed and approved by the disinterested members of the Board and pursuant to the Company’s related party transactions policy .
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diff --git a/raw/filings/0001694028/2023/0001694028-24-000006/rpt_disclosure.txt b/raw/filings/0001694028/2023/0001694028-24-000006/rpt_disclosure.txt
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@@ -0,0 +1,43 @@
+CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS 
+Policies and Procedures for Review of Related Party Transactions 
+A “ Related Party Transaction ” is a transaction, arrangement or relationship in which the Company or any of its subsidiaries was, is or will be a participant, the amount of which involved exceeds $120,000, and in which any related person had, has or will have a direct or indirect material interest. A “ Related Person ” is: 
+♦ any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors; 
+♦ any person who is known by us to be the beneficial owner of more than 5% of our Class A Common Stock; 
+♦ any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, executive officer or a beneficial owner of more than 5% of our Class A Common Stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5% of our Class A Common Stock; and 
+♦ any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10.0% or greater beneficial ownership interest. 
+Our Board has adopted a written related party transactions policy. Pursuant to this policy, our Audit Committee reviews all material facts of all Related Party Transactions and either approves or disapproves entry into the Related Party Transaction, subject to certain limited exceptions. The determination of the Audit Committee is documented in the Audit Committee’s minutes. In determining whether to approve or disapprove entry into a Related Party Transaction, our Audit Committee takes into account, among other factors, the following: (i) whether the Related Party Transaction is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances and (ii) the extent of the Related Person’s interest in the transaction. Furthermore, the policy requires that all Related Party Transactions required to be disclosed in our filings with the SEC be so disclosed in accordance with applicable laws, rules and regulations. 
+Related Party Transactions 
+The following is a description of transactions entered into, or in effect, after January 1, 2023 to which we have been a party, in which the amount involved in the transaction exceeds $120,000, and in which any of our directors, executive officers or beneficial owners of more than 5% of our voting securities, or affiliates or immediate family members of any of our directors, executive officers or beneficial owners of more than 5% of our voting securities, had or will have a direct or indirect material interest. We believe the terms obtained or consideration that we paid or received, as applicable, in connection with the transactions described below were comparable to terms available or the amounts that would be paid or received, as applicable, from unrelated third parties. 
+Liberty LLC Agreement 
+We entered into the Second Amended and Restated Limited Liability Company Agreement of Liberty Oilfield Services New HoldCo LLC (“ Liberty LLC ”) (the “ Liberty LLC Agreement ”) in connection with the closing of our IPO, which provides for limitations on the ability of holders of units of Liberty LLC (the “ Liberty LLC Units, ” and the holders of Liberty LLC Units “ Liberty Unit Holders ”) to transfer their Liberty LLC Units and provides the Company, as managing member of Liberty LLC, with the right to impose restrictions (in addition to those already in place) on the ability of Liberty Unit Holders to redeem their Liberty LLC Units pursuant to the Redemption Right (as defined below) to the extent the Company believes it is necessary to ensure that Liberty LLC will continue to be treated as a partnership for U.S. federal income tax purposes. 
+Effective January 31, 2023, Liberty LLC was merged into the Company (such merger, the “ Liberty LLC Merger ”), with the Company being the surviving entity of the Liberty LLC Merger. In connection with Liberty LLC Merger, all outstanding shares of our Class B Common Stock were redeemed and exchanged for an equal number of shares of our Class A Common Stock. Also effective January 31, 2023, as a result of the Liberty LLC Merger, the Liberty LLC Agreement terminated. 
+Redemption Rights 
+Under the Liberty LLC Agreement, each Liberty Unit Holder had, subject to certain limitations, the right (the “ Redemption Right ”) to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units for, at Liberty LLC’s election, (i) shares of our Class A Common Stock at a redemption ratio of one share of Class A Common Stock for each Liberty LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions or (ii) an equivalent amount of cash. Alternatively, upon the exercise of the Redemption Right, the Company (instead of Liberty LLC) had the right (the “ Call Right ”) to, 
+49 
+for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder for, at the Company’s election, (x) one share of Class A Common Stock or (y) an equivalent amount of cash. In addition, upon a change of control of the Company, the Company had the right to require each holder of Liberty LLC Units (other than the Company) to exercise its Redemption Right with respect to some or all of such unit holder’s Liberty LLC Units. In connection with any redemption of Liberty LLC Units pursuant to the Redemption Right or the Call Right, the corresponding number of shares of Class B Common Stock would be cancelled. 
+As of January 31, 2023, and, as a result of the Liberty LLC Merger, all outstanding Redemption Rights for Liberty LLC Units had been exercised, and no further redemption of Liberty LLC Units will occur in the future. 
+Distributions and Allocations 
+Under the Liberty LLC Agreement, the Company had the right to determine when distributions will be made to the holders of Liberty LLC Units and the amount of any such distributions. If the Company authorized a distribution, such distribution would be made to the holders of Liberty LLC Units generally on a pro rata basis in accordance with their respective percentage ownership of Liberty LLC Units. 
+Liberty LLC allocated its net income or net loss for each year to the holders of Liberty LLC Units pursuant to the terms of the Liberty LLC Agreement, and the holders of L iberty LLC Units, including the Company, generally incurred U.S. federal, state and local income taxes on their share of any taxable income of Liberty LLC. Net income and losses of Liberty LLC generally were allocated to the holders of Liberty LLC Units on a pro rata basis in accordance with their respective percentage ownership of Liberty LLC Units, subject to requirements under U.S. federal income tax law that certain items of income, gain, loss or deduction be allocated disproportionately in certain circumstances. To the extent Liberty LLC had available cash and subject to the terms of any debt instruments, the Company intended to cause Liberty LLC to make (i) generally pro rata distributions to the holders of Liberty LLC Units, including the Company, in an amount sufficient to allow the Company to pay its taxes and to allow it to make payments under the Tax Receivable Agreements (as defined below), (ii) tax advances, which will be repaid upon exercise of the Redemption Right or the Call Right, as applicable, in an amount sufficient to allow each of the Liberty Unit Holders to pay its respective taxes on such holder’s allocable share of Liberty LLC’s taxable income after taking into account certain other distributions or payments received by the Liberty Unit Holders from Liberty LLC or the Company, and (iii) non-pro rata payments to the Company to reimburse it for its corporate and other overhead expenses. 
+Issuance of Equity 
+The Liberty LLC Agreement generally provided that at any time the Company issues a share of its Class A Common Stock or any other equity security, the net proceeds received by the Company with respect to such issuance, if any, shall be concurrently invested in Liberty LLC, and Liberty LLC shall issue to the Company one Liberty LLC Unit or other economically equivalent equity interest. Conversely, if at any time, any shares of Class A Common Stock were redeemed, repurchased or otherwise acquired, Liberty LLC would redeem, repurchase or otherwise acquire an equal number of Liberty LLC Units held by the Company, upon the same terms and for the same price, as the shares of the Class A Common Stock are redeemed, repurchased or otherwise acquired. 
+Transactions with Liberty Resources 
+Liberty Resources LLC (“ Liberty Resources ”) is an oil and gas exploration and production company of which Mr. Wright is the Executive Chairman and an equity owner. Mr. Wright previously served as the Chief Executive Officer at Liberty Resources from its formation in September 2010 until March 2017. Liberty Resources entered into a master service agreement with Liberty Oilfield Services LLC, a subsidiary of the Company (“ Liberty Services ”), whereby Liberty Services provides hydraulic fracturing service to Liberty Resources at market service rates. For the year ended December 31, 2023, the amounts related to the provision of hydraulic fracturing services to Liberty Resources under the master services agreement were $38.8 million. 
+In December 2022, the Company entered into a letter agreement with Liberty Resources to extend the payment terms for certain accounts receivable until April 1, 2024, and, in August 2023, the parties revised such letter agreement to make various modifications including further extending payment terms until January 1, 2025, subject to timely payment of monthly interest charges ranging from 15-20%. As of December 31, 2023, the amount of receivables subject to this letter agreement was approximately $15 million. 
+Transactions with Franklin Mountain 
+Franklin Mountain Energy LLC (“ Franklin Mountain ”) is an oil and gas exploration and production company of which Ms. Robertson serves as the Chief Financial Officer. Franklin Mountain entered into a master service agreement with Liberty Services, whereby Liberty Services provides hydraulic fracturing service to Franklin Mountain at market service rates. For the year ended December 31, 2023, the amounts related to the provision of hydraulic fracturing services to Franklin Mountain under the master services agreement was $176.1 million or 3.7% of the Company’s revenues for such period. 
+50 
+Transactions with Tim Babcock 
+Tim Babcock is currently employed by a subsidiary of the Company as a director of operations. Tim Babcock is the son of Ken Babcock, who serves on the Board. For the year ended December 31, 2023, Tim Babcock was paid $218,780 for his services as an employee. 
+Transactions with the Bettering Human Lives Foundation 
+In December 2023, the Company established the Bettering Human Lives Foundation (the “ Foundation ”), a nonprofit organization dedicated to promoting clean cooking solutions and improving the well-being of communities worldwide. Mr. Wright, the Company’s CEO, serves as the Chairman of the Foundation, and Anne Hyre serves as its executive director. Ms. Hyre is the sister-in-law of M r. Wright. I n December 2023, the Company made an initial commitment to make a charitable contribution of $1 million to the Foundation. In addition, effective January 2024, Ms. Hyre is employed by a subsidiary of the Company and seconded to the Foundation. We expect that Ms. Hyre will receive total compensation of approximately $250,000 from the Company for the year ended De cember 31, 202 4. 
+Indemnification for Officers and Directors 
+Our Amended and Restated Certificate of Incorporation and Second Amended and Restated Bylaws provide indemnification rights to our directors and officers and permit us to purchase insurance on behalf of any officer, director, employee or other agent for any liability arising out of that person’s actions as our officer, director, employee or agent, regardless of whether Delaware law would mandate indemnification. Additionally, we have entered into separate indemnity agreements with our directors and certain officers to provide additional indemnification benefits, including the right to receive, in advance, reimbursements for expenses incurred in connection with a defense for which the director or officer is entitled to indemnification. We believe that the limitation of liability provisions in our Amended and Restated Certificate of Incorporation, Second Amended and Restated Bylaws and the indemnity agreements will facilitate our ability to continue to attract and retain qualified individuals to serve as directors and officers. 
+Conflicts of Interest 
+The related party transactions described herein may cause certain conflicts of interests, including that: 
+♦ we may enter into contracts between us, on the one hand, and related parties, on the other, that are not as a result of arm’s-length transactions; 
+♦ our executive officers and directors that hold positions of responsibility with related parties may be aware of certain business opportunities that are appropriate for presentation to us as well as to such other related parties and may present such business opportunities to such other parties; and 
+♦ our executive officers and directors that hold positions of responsibility with related parties may have significant duties with, and spend significant time serving, other entities and may have conflicts of interest in allocating time. 
+For example, Mr. Wright, our Chief Executive Officer, is the Executive Chairman of Liberty Resources, a position which may require a portion of his time and which may cause conflicts of interest in pursuing business opportunities of which he becomes aware. 
+51 
+DELINQUENT
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+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+WASHINGTON, D.C. 20549 
+FORM 10-K 
+(Mark One) 
+☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the Fiscal Year Ended December 31 , 2024 
+OR 
+☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+Commission File No. 001-38081 
+Liberty Energy Inc. 
+(Exact Name of Registrant as Specified in its Charter) 
+Delaware 
+81-4891595 
+(State or Other Jurisdiction of Incorporation or Organization) (I.R.S. Employer Identification No.) 
+950 17th Street , Suite 2400 
+Denver , Colorado 
+80202 
+(Address of Principal Executive Offices) (Zip Code) 
+( 303 ) 515-2800 
+(Registrant’s Telephone Number, Including Area Code) 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of each class Trading symbol(s) Name of each exchange on which registered 
+Class A Common Stock, par value $0.01 LBRT New York Stock Exchange 
+Securities registered pursuant to Section 12(g) of the Act: None 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☒ Yes ☐ No 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐ Yes ☒ No 
+Indicate by check mark whether the registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No 
+Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this Chapter) during the presiding 12 months (or for such shorter period that the registrant was required to submit and post such files). ☒ Yes ☐ No 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. 
+Large Accelerated Filer ☒ 
+Accelerated Filer ☐ Non-accelerated filer ☐ 
+Smaller reporting company ☐ 
+Emerging growth company ☐ 
+If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ 
+Indicate by check mark whether the registrant has filed a report on an attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ 
+If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐ 
+Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant ’ s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐ 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act): ☐ Yes ☒ No 
+As of June 28, 2024, the last business day of the registrant ’ s most recently completed second fiscal quarter, the aggregate market value of voting and non-voting common stock held by non-affiliates of the registrant was approximately $ 3.3 billion, determined using the per share closing price on the New York Stock Exchange on that date of $20.89. Shares of common stock held by each director and executive officer (and their respective affiliates) and each person who owns 10 percent or more of the outstanding common stock or who is otherwise believed by the registrant to be in a control position have been excluded. This determination of affiliate status is not necessarily a conclusive determination for other purposes. 
+As of January 31, 2025, the Registrant had 161,923,807 shares of Class A Common Stock and 0 shares of Class B Common Stock outstanding. 
+Documents Incorporated by Reference: Part III of this Annual Report on Form 10-K incorporates certain information by reference from the registrant ’ s proxy statement for the 2025 annual meeting of stockholders to be filed no later than 120 days after the end of the registrant ’ s fiscal year. 
+TABLE OF CONTENTS 
+Page No. 
+PART I 
+Item 1. 
+Business 
+1 
+Item 1A. 
+Risk Factors 
+12 
+Item 1B. 
+Unresolved Staff Comments 
+28 
+Item 1C. 
+Cybersecurity 
+28 
+Item 2. 
+Properties 
+29 
+Item 3. 
+Legal Proceedings 
+29 
+Item 4. 
+Mine Safety Disclosures 
+29 
+PART II 
+Item 5. 
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+30 
+Item 6. 
+[Reserved] 
+28 
+Item 7. 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+34 
+Item 7A. 
+Quantitative and Qualitative Disclosure about Market Risk 
+45 
+Item 8. 
+Financial Statements and Supplementary Data 
+45 
+Item 9. 
+Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+45 
+Item 9A. 
+Controls and Procedures 
+46 
+Item 9B. 
+Other Information 
+46 
+PART III 
+Item 10. 
+Directors, Executive Officers and Corporate Governance 
+47 
+Item 11. 
+Executive Compensation 
+47 
+Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+47 
+Item 13. 
+Certain Relationships and Related Transactions, and Director Independence 
+47 
+Item 14. 
+Principal Accountant Fees and Services 
+47 
+PART IV 
+Item 15. 
+Exhibits and Financial Statement Schedules 
+48 
+Item 16. 
+Form 10-K Summary 
+49 
+SIGNATURES 
+53 
+i 
+CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS 
+This Annual Report on Form 10-K (“Annual Report”) and certain other communications made by us contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange of 1934, as amended (the “Exchange Act”), including, among others, expected performance, future operating results, oil and natural gas demand and prices and the outlook for the oil and gas industry, future global economic conditions, the impact of worldwide political, military and armed conflict, the impact of announcements and changes in oil production quotas by oil exporting countries, improvements in operating procedures and technology, our business strategy and the business strategies of our customers, in addition to other estimates, and beliefs. For this purpose, any statement that is not a statement of historical fact should be considered a forward-looking statement. We may use the words “estimate,” “outlook,” “project,” “forecast,” “position,” “potential,” “likely,” “believe,” “anticipate,” “assume,” “plan,” “expect,” “intend,” “achievable,” “may,” “will,” “continue,” “should,” “could” and similar expressions to help identify forward-looking statements. However, the absence of these words does not mean that the statements are not forward-looking. We cannot assure you that our assumptions and expectations will prove to be correct. Important factors, many of which are beyond our control, could cause our actual results to differ materially from those indicated or implied by forward-looking statements, including but not limited to the risks and uncertainties described in this Annual Report and other filings that we make with the U.S. Securities Exchange Commission (the “SEC”). We undertake no intention or obligation to update or revise any forward-looking statements, except as required by law, whether as a result of new information, future events or otherwise and readers should not rely on the forward-looking statements as representing the Company’s views as of any date subsequent to the date of the filing of this Annual Report. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. 
+All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. 
+MARKET AND INDUSTRY DATA 
+This Annual Report includes market and industry data and certain other statistical information based on third-party sources including independent industry publications, government publications and other published independent sources, such as content and estimates provided by Lium, LLC (“Lium Research”) as of December 31, 2024, and industry content and figures provided by Baker Hughes Co. (“Baker Hughes”) as of December 31, 2024. Neither Lium Research nor Baker Hughes is a member of the Financial Industry Regulatory Authority or the Securities Investor Protection Corporation and neither is a registered broker dealer or investment advisor. Although we believe these third-party sources are reliable as of their respective dates, we have not independently verified the accuracy or completeness of this information. Some data is also based on our own good faith estimates, which are supported by our management's knowledge of and experience in the markets and business in which we operate. 
+TRADEMARKS, SERVICE MARKS AND TRADENAMES 
+This Annual Report contains trademarks, tradenames, and service marks that are owned by us or other companies, which are our property. Solely for convenience, the trademarks, tradenames, and service marks referred to in this Annual Report may appear without the ®, TM, and SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the rights of the applicable licensors to these trademarks, tradenames, and service marks. We do not intend our use or display of other parties’ trademarks, tradenames, or service marks to imply, and such use or display should not be construed to imply a relationship with, or endorsement or sponsorship of us by, these other parties. 
+ii 
+PART I 
+As used in this Annual Report, except as otherwise indicated or required by the context, all references in this Annual Report to (i) the “Company,” “Liberty,” “we,” “us” and “our” refer to Liberty Energy Inc. and its consolidated subsidiaries; and (ii) “Liberty LLC” refer to Liberty Oilfield Services New HoldCo LLC. 
+Item 1. Business 
+Our Company 
+The Company, together with its subsidiaries, is a leading integrated energy services and technology company focused on providing innovative hydraulic fracturing services and related technologies to onshore oil and natural gas exploration and production (“E&P”) companies. We offer customers hydraulic fracturing services, together with complementary services including wireline services, proppant delivery solutions, field gas processing and treating, compressed natural gas (“CNG”) delivery, data analytics, related goods (including our sand mine operations), and technologies to facilitate lower emission completions, thereby helping our customers reduce their emissions profile. 
+Our areas of operations are in all of the most active shale basins in North America, including the Permian Basin, the Williston Basin, the Haynesville Shale, the Eagle Ford Shale, the Denver-Julesburg Basin (the “DJ Basin”), the Western Canadian Sedimentary Basin, the Powder River Basin, and the Appalachian Basin (Marcellus Shale and Utica Shale). Our operations also extend to a few smaller shale basins, including the Anadarko Basin, the Uinta Basin, the San Juan Basin, as well as the Beetaloo Basin in Northern Territory, Australia. The breadth of our operational footprint provides us an opportunity to leverage our fixed costs and to efficiently reposition our equipment in response to customer requirements. 
+Areas of North American Operations 
+The process of hydraulic fracturing involves pumping a pressurized stream of fracturing fluid (typically a mixture of water, chemicals and proppant) into a well casing or tubing to cause the underground formation to fracture or crack. These fractures release trapped hydrocarbon particles and provide a conductive channel for the oil or natural gas to flow freely to the wellbore for collection. The propping agent, or proppant, typically sand, becomes lodged in the cracks created by the hydraulic 
+1 
+fracturing process, “propping” them open to facilitate the flow of hydrocarbons from the reservoir to the well. The fracturing fluid is engineered to lose viscosity, or “break,” and is subsequently flowed back from the formation, leaving the proppant suspended in the formation fractures. Once our customer has flushed the fracturing fluids from the well using a controlled flow-back process, the customer manages fluid and water recycling or disposal. 
+Our hydraulic fracturing fleets consist of mobile hydraulic fracturing units and other auxiliary heavy equipment to perform fracturing services. Our hydraulic fracturing units consist primarily of high-pressure hydraulic pumps, engines, transmissions, radiators and other supporting equipment (including power generation units for electric fleets) that are typically mounted on trailers. We refer to the group of units and other equipment, such as blenders, data vans, sand storage, tractors, manifolds and high-pressure fracturing iron, which are necessary to perform a typical hydraulic fracturing job, as a “fleet,” and the personnel assigned to each fleet as a “crew.” The size of each fleet and crew can vary depending on the requirements of each job design. 
+Wireline operations supplement our hydraulic fracturing fleets, which consist of a truck equipped with a spool of wireline that is lowered into wells to convey specialized tools or equipment, such as perforating guns and charges, which are necessary to connect the wellbore with the target formation. This operation is performed between each hydraulic fracturing stage. Our wireline service is primarily offered alongside our hydraulic fracturing services, which allows us to maximize efficiency for our customers through optimized coordination of the wireline and hydraulic fracturing services. In addition, we also offer our wireline service on a stand-alone basis. 
+We also operate two sand mines that allows us to vertically integrate our supply-chain in the Permian Basin. The mines provide sand to Liberty hydraulic fracturing fleets as well as to third parties. With a secured supply of regional sand in the basin, we reduce our dependency on other providers and any downtime that could result from sand supply issues. 
+We are a leading provider of last-mile proppant delivery solutions, including proppant handling equipment and logistics software across North America. We offer innovative environmentally friendly technology with optimized dry and wet sand containers and wellsite proppant handling equipment that drive logistics efficiency and reduce noise and emissions. We believe that our wet sand handling technology is a key enabler of the next step of cost and emissions reductions in the proppant industry. We also offer customers the latest real-time logistics software, PropConnect™, as a hosted software as a service. 
+We also own and operate Liberty Power Innovations LLC (“LPI”), an integrated alternative fuel and power solutions provider for remote applications. On April 6, 2023, LPI expanded its footprint with the acquisition of Siren Energy & Logistics, LLC (“Siren” and such acquisition, the “Siren Acquisition”), a Permian focused integrated natural gas compression and CNG delivery business that we have since expanded to other basins. LPI provides CNG supply, field gas processing and treating, and well site fueling and logistics. LPI was formed with the initial focus on supporting Liberty’s transition towards our next generation digiFleets℠ and dual fuel fleets, by providing consistent and reliable CNG fueling services, which are critical to maintaining highly efficient well site operations. Through 2024, LPI was primarily focused on supporting an industry transition to natural gas fueled technologies, serving as a key enabler of the next step of cost and emissions reductions in the oilfield. In January 2025, we announced LPI’s expansion into the distributed power business, where we expect to leverage our experience in providing electric power for our digiFrac pumps into other areas inside and outside of the oilfield. 
+Our operations are organized into a single business segment, which consists of hydraulic fracturing services, including wireline, proppant delivery and goods, including our Permian Basin sand mines, and natural gas compression and delivery, and we have one reportable geographical segment, North America. We have grown from one active hydraulic fracturing fleet as of December 2011 to approximately 40 active fleets as of December 31, 2024. We are focused on providing “next-generation” frac fleets and technologies to assist our customers with completing their wells in an efficient and responsible manner. 
+Our founders and management are pioneers in the development of data-driven hydraulic fracturing technologies for application in shale plays. Prior to founding the Company, several members of the senior executive management team founded and built Pinnacle Technologies, Inc. (“Pinnacle Technologies”) into a leading fracturing technology company. In 1992, Pinnacle Technologies developed the first commercial hydraulic fracture mapping technologies, analytical tools that played a major role in launching the shale revolution. Our extensive experience with fracture technologies and customized fracture design has enabled us to develop new technologies and processes that provide our customers with real-time solutions that significantly enhance their completions. These technologies include hydraulic fracture propagation models, reservoir engineering tools, large, proprietary shale production databases and multi-variable statistical analysis techniques. Taken together, these technologies have enabled us to be a leader in hydraulic fracture design innovation and application. Our management team has an average of over 20 years of energy services experience. 
+We believe technical innovation and strong relationships with our customers and suppliers distinguish us from our competitors and are the foundations of our business. We expect that E&P companies will continue to focus on technological innovation as completion complexity and fracture intensity of horizontal wells increases, particularly as customers are increasingly focused on reducing emissions from their completions operations. We remain proactive in developing innovative solutions to industry challenges, including developing: (i) our databases of U.S. unconventional wells to which we apply our 
+2 
+proprietary multi-variable statistical analysis technologies to provide differential insight into fracture design optimization; (ii) our Liberty Quiet Fleet® design which significantly reduces noise levels compared to conventional hydraulic fracturing fleets; (iii) hydraulic fracturing fluid systems tailored to the specific reservoir properties in the basins in which we operate; (iv) our dual fuel dynamic gas blending (“DGB”) fleets that allow our engines to run diesel or a combination of diesel and natural gas, to optimize fuel use, reduce emissions and lower costs; (v) our digiFleets℠, comprising of digiFrac℠ and digiPrime℠ pumps and other complementary equipment, including power generation units (together “digiTechnologies℠”), our innovative, purpose-built electric and hybrid frac pumps that have approximately 25% lower CO 2e emission profile than the Tier IV DGB; (vi) our wet sand handling technology which eliminates the need to dry sand, enabling the deployment of mobile mines nearer to wellsites; and (vii) the launch of LPI to support the transition to our digiFleets as well as the transition to lower costs and emissions in the oilfield. In addition, our integrated supply chain includes proppant, chemicals, equipment, natural gas fueling services, logistics and integrated software which we believe promotes wellsite efficiency and leads to more pumping hours and higher productivity throughout the year to better service our customers. In order to achieve our technological objectives, we carefully manage our liquidity and debt position to promote operational flexibility and invest in the business throughout the full commodity cycle in the regions we operate. 
+Recent Leadership Updates 
+On February 3, 2025, Christopher A. Wright, our Chief Executive Officer and Chairman of the Board, was confirmed to the position of Secretary of Energy of the United States and resigned from his positions as Chairman of the Board, Director, and Chief Executive Officer of the Company. Also, on February 3, 2025, in accordance with the Company’s succession plan, the Board appointed William Kimble as the non-executive Chairman of the Board and Ron Gusek as the Company’s Chief Executive Officer and Director. Lastly, on January 22, 2025, the Board approved an increase to the size of the Board from nine to 10 directors and appointed Arjun Murti to fill the newly created vacancy. 
+Focused on Continuous Improvement 
+We support all energy sources that improve our energy system and better lives. We passionately work to better the process of bringing hydrocarbons to the surface in a clean, safe and efficient fashion and view these principles as foundational to our business. We focus on developing and adding technologies to our operations that assist our customers in implementing their goals. The list below sets forth specific examples of our efforts in this regard: 
+• In 2013, we introduced Tier II dual-fuel technology to our fleets which allows our frac pumps to use natural gas in place of some diesel fuel to lower particulate emissions. 
+• In 2014, we began the use of containerized sand delivery at frac locations, which reduces dust, noise and truck traffic. 
+• In 2016, we introduced Quiet Fleet® technology, which significantly reduces noise levels associated with frac operations. 
+• In 2018, we partnered with an equipment supplier to introduce Tier IV dynamic gas blending, or DGB, engines to our frac fleet that can substitute up to 80% of the diesel typically used by a frac pump with natural gas and significantly lower emission levels in frac operations. Tier IV DGB engines were added to our fleet in 2020. 
+• In 2018, we began the design and development of digiFrac SM , our innovative, purpose-built electric frac pump that has approximately a 25% lower CO 2e emission profile than the Tier IV DGB. 
+• In 2021, we announced the successful test of digiFrac and in 2022 commenced delivery of commercial pumps. 
+• In October 2021, we became a leading provider of last-mile proppant delivery solutions including proppant handling equipment and logistics software. We offer innovative, environmentally friendly technology with optimized dry and wet sand containers and wellsite proppant handling equipment that drive logistics efficiency and reduce noise and emissions. 
+• In 2022, we began the design and development of digiPrime SM , the first hybrid pump technology, utilizing direct mechanical drive for the pumps while simultaneously generating power capable of electrifying supporting equipment at the well site. These pumps have a lower CO 2e emissions profile than digiFrac. 
+• In 2023, we launched LPI and closed the acquisition of Siren. We believe that the shift in fuel consumption from diesel to cleaner natural gas has the potential to promote emissions reductions in the industry. 
+• In 2023, we commenced deployment of digiFleets SM , comprised of digiFrac and digiPrime pump technology along with other complementary equipment from our digiTechnologies SM suite. This deployment also included mobile generation units to provide the needed electricity to power our digiFrac pumps in remote locations. 
+• In 2024, the Bettering Human Lives Foundation, a non-profit organization dedicated to improving the well-being of communities worldwide with an early focus on promoting clean cooking solutions, supported two companies in Kenya 
+3 
+and Ghana to convert schools from burning firewood to liquid petroleum gas. During 2024, we made charitable contributions of $0.9 million to the Bettering Human Lives Foundation. 
+• The third edition of Liberty’s Bettering Human Lives report, emphasizing energy’s central role in human lives, was released in February 2024. Over 30,000 copies of the report have been distributed worldwide to date. 
+• In January 2025, we announced LPI’s expansion into the distributed power business, where we expect to leverage our experience in providing electric power for our digiFrac pumps into other areas inside and outside of the oilfield. 
+Furthermore, we are continuously committed to engagement in our communities. We provide K-12 scholarships to low-income children through Alliance for Choice in Education, and we proudly fund a Liberty Scholars program at Montana Technological University to enable lower-income students to obtain a college education. In total, over 100 students received Liberty scholarships across the U.S. and Canada in 2024. In addition to our educational initiatives, we have targeted outreach to organizations focused on veterans, poverty abatement, low-income housing, criminal justice reform, and job opportunities for those who had a disadvantaged start in life. 
+In 2024, we created a charitable giving committee to facilitate communication across all areas of Liberty operations and direct support to organizations where our employees live and work. In 2021, we launched Love, Liberty, our corporate matching program, to double our impact and encourage our employees to get involved in their communities. In 2024, Liberty processed over 200 match requests to nearly 50 different organizations, totaling nearly $40,000 in matching contributions. 
+Cyclical Nature of Industry 
+We operate in a cyclical industry reflecting global oil and gas supply and demand dynamics, current and expected future oil and gas commodity prices, and the perceived stability and sustainability of those prices. Global oil and gas supply and demand can be impacted by general domestic and international economic conditions, inflationary pressures, geopolitical developments, government regulations, and other factors. Such factors also impact capital expenditures and drilling and completions activities of E&P companies, which in turn can impact demand for our services. For these reasons, the results of our operations may fluctuate from quarter to quarter and from year to year, and these fluctuations may distort comparisons of results across periods. 
+Seasonality 
+Our results of operations have historically reflected seasonal tendencies relating to holiday seasons, inclement weather and the conclusion of our customers’ annual drilling and completion capital expenditure budgets. Our most notable declines typically occur in the fourth quarter of the year for the reasons described above. Additionally, some of the areas in which we have operations, including Canada, the DJ Basin, Powder River Basin and Williston Basin, are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice, rain, or frost, and related road restrictions, we may be unable to move our equipment between locations, thereby reducing our ability to provide services and generate revenues. The exploration activities of our customers may also be affected during such periods of adverse weather conditions. Additionally, extended drought conditions in our operating regions could impact our ability or our customers’ ability to source sufficient water or increase the cost for such water. 
+Intellectual Property 
+Over the last several years and in connection with the acquisition of Siren, and others in prior periods, we have significantly invested in our research and technology capabilities. Our efforts to date have been focused on developing innovative, fit-for-purpose solutions designed to enhance our core service offerings, increase completion efficiencies, provide cost savings to our operations and add value for our customers. A cornerstone of our technological advantage is a series of proprietary databases of U.S. unconventional wells that include production data, completion designs and reservoir characteristics. We utilize these databases to perform multi-variable statistical analysis that generates differential insight into fracture design optimization to enhance our customers’ production economics. Our emphasis on data analytics is also deployed during job execution through the use of real-time feedback on variables that maximizes customer returns by improving cost-effective hydraulic fracturing operations. 
+Today, we hold approximately 500 patents and patent licenses relating to our engineering and technology solutions. We seek patent and trademark protections for our technology when we deem it prudent, and we aggressively pursue protection of these rights when warranted. We believe our patents, trademarks, and other protections for our proprietary technologies are adequate for the conduct of our business and that no single patent or trademark is critical to our business. In addition, we rely, to a great extent, on the technical expertise and know-how of our personnel to maintain our competitive position, and we take commercially reasonable measures to protect trade secrets and other confidential and/or proprietary information relating to the technologies we develop. 
+4 
+Human Capital Management 
+As of December 31, 2024, we had approximately 5,700 employees and no unionized labor. We believe we have good relations with our employees and that one of our key competitive advantages is our people. Our highly trained, experienced and motivated employees are critical to delivering our hydraulic fracturing services. Taking care of our employees is one of our top priorities, and we continually invest in hiring, training and retaining the employees we believe to be the best in our field. We consistently assess the current business environment and labor market to refine our compensation and benefits programs in order to attract and retain top talent in our industry. We strive to promote from within our existing employee base to manage new hydraulic fracturing fleets and organically grow our operating expertise. This organic growth is essential in achieving the expertise and level of customer service we strive to provide each of our customers. As a result, we plan to continue to invest in our employees through both personal and professional training to attract and retain the best individuals in our areas of operation. Overall, we focus on individual contributions and team success to foster a culture built around operational excellence and superior safety. 
+Health and Safety 
+Our people are our most important asset and ensuring their safety and the safety of those around them is the most important thing we do. Making certain that the Liberty team is well trained to handle the complexities of daily field operations, and that their training and competency remains current with the latest technology and standards is a key component. In order to facilitate this training, we have developed the Liberty Frac Academy, a thorough program where employees are trained on various aspects of the Company, from safety in equipment operation to leadership skills. The Liberty Frac Academy not only ensures dissemination of high-quality training material, but also provides a forum for sharing best practices and lessons learned across the Company. As a result, we are among the safest service providers in the industry with a constant focus on Health, Safety and Environmental performance and service quality, as evidenced by an average incident rate that was consistently lower than the industry average from 2022 to 2024. Our employee-centered focus and reputation for safety has enabled us to obtain projects from industry leaders with some of the most demanding safety and operational requirements. 
+Programs and Benefits 
+One way we have demonstrated a history of investing in our workforce is by offering competitive salaries and wages. To foster a strong sense of ownership, restricted stock units are provided to eligible employees under our long-term incentive plan. Furthermore, we offer innovative benefits to all eligible employees, including, among others, comprehensive health insurance coverage, parental leave to all new parents, for birth or adoption, financial support for child adoption, leave to care for partners with serious health conditions, 401(k) savings plan and educational tuition assistance for both bachelor’s degree and master’s degree programs. We are also passionate about community investment and are a part of the Ban the Box initiative which provides work opportunities for formerly incarcerated individuals. 
+Governmental Regulation and Climate Change 
+As a company with operations primarily in the United States and Canada, we are subject to the laws of both jurisdictions in which we operate and the rules and regulations of various governing bodies, which may differ among those jurisdictions. Compliance with these laws, rules and regulations has not had, and is not expected to have, a material effect on our capital expenditures, results of operations and competitive position as compared to prior periods. We are also subject to numerous environmental and regulatory requirements related to our operations. For further information related to such regulation, see the risks described under the heading “Risk Factors” in this Annual Report. 
+Our operations are subject to numerous stringent and complex laws and regulations at the federal, state, and local levels governing the discharge of materials into the environment, environmental protection, and health and safety aspects of our operations. Failure to comply with these laws and regulations or to obtain or comply with permits may result in the assessment of administrative, civil, and criminal penalties, imposition of remedial or corrective action requirements, and the imposition of injunctions or other orders to prohibit certain activities, restrict certain operations, or force future compliance with environmental requirements. 
+There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons, other hazardous substances, and wastes, as a result of air emissions and wastewater discharges related to our operations, and because of historical operations and waste disposal practices. Spills or other releases of regulated substances, including such spills and releases that occur in the future, could expose us to material losses, expenditures, and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. The following is a summary of some of the existing laws, rules, and regulations to which we are subject. 
+5 
+U.S. Laws and Regulations 
+Hazardous Substances and Waste Handling 
+The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Under guidance issued by the U.S. Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. RCRA currently exempts many E&P wastes from classification as hazardous waste. Specifically, RCRA excludes produced waters and other wastes intrinsically associated with the exploration, development, or production of crude oil and natural gas from the definition of hazardous waste. However, these E&P wastes may still be regulated under state solid waste laws and regulations, and it is possible that certain oil and natural gas E&P wastes now classified as non-hazardous could be classified as hazardous waste in the future. Stricter regulation of wastes generated during our or our customers’ operations could result in increased costs for our operations or the operations of our customers, which could in turn reduce demand for our services and adversely affect our business. We cannot guarantee that the EPA will not revisit the exemption of E&P waste or that waste will not become more heavily regulated at the federal or state level. 
+Comprehensive Environmental Response, Compensation, and Liability Act 
+The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owner or operator of the site where the release occurred and anyone who transported or disposed or arranged for the transport or disposal of a hazardous substance released at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA and any state analogs may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources and for the costs of certain health studies. We currently own, lease, or operate, and previously owned, leased, or operated numerous properties that have been used for manufacturing and other operations for many years. These properties and the substances disposed or released on them may be subject to CERCLA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. 
+Worker Health and Safety 
+We are subject to a number of federal and state laws and regulations, including the OSHA regulatory standards, which establish requirements to protect the health and safety of workers. Among others, we may be subject to OSHA regulations for safe operation of cranes, power industrial trucks and similar equipment at our worksites, safe practices for working in hazardous locations and permit-required confined spaces, and proper use of required personal protective equipment by workers. OSHA’s hazard communication standard requires tracking of hazardous chemicals present at the worksite, sharing of such information with the workers, and training the workers to handle the chemicals appropriately. The EPA’s community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes also require maintenance of information about hazardous materials used or produced in operations and provision of this information to employees, state and local government authorities, and citizens. We are also subject to OSHA’s regulatory standard for respirable crystalline silica, which provides measures to protect workers in hydraulic fracturing operations from exposure to this chemical including limiting exposure to airborne respirable crystalline silica in excess of a specified limit. Additionally, the Federal Motor Carrier Safety Administration (the “FMCSA”) regulates and provides safety oversight of commercial motor vehicles, the EPA establishes requirements to protect human health and the environment, the federal Bureau of Alcohol, Tobacco, Firearms and Explosives establishes requirements for the safe use and storage of explosives, and the federal Nuclear Regulatory Commission establishes requirements for the protection against ionizing radiation. We are subject to Mine Safety & Health Administration regulations related to operation of sand mines including regulations for training and retraining of workers engaged in sand mine operations. Substantial fines and penalties can be imposed, and orders or injunctions limiting or prohibiting certain operations may be issued, in connection with any failure to comply with these laws and regulations. 
+6 
+Water Discharges 
+The federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the U.S. The discharge of pollutants into regulated waters, including jurisdictional wetlands, is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. To the extent the agencies expanding the range of properties subject to the Clean Water Act’s jurisdiction or impose more stringent requirements on discharges of wastewater, certain energy companies could face increased costs and delays with respect to obtaining permits, including for the discharge of dredge and fill activities in waters of the U.S. or wetland areas, which in turn could reduce demand for our services. Furthermore, the process for obtaining permits has the potential to delay our operations and those of our customers. Spill prevention, control, and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture, or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of wastewater and storm water runoff from certain types of facilities. The Clean Water Act and analogous state laws provide for administrative, civil, and criminal penalties for unauthorized discharges and, together with the Oil Pollution Act of 1990, impose rigorous requirements for spill prevention and response planning, as well as substantial potential liability for the costs of removal, remediation, and damages in connection with any unauthorized discharges. 
+Air Emissions 
+The federal Clean Air Act (the “CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants and other air emissions at specified sources. These regulations change frequently. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements, utilize specific equipment or technologies to control emissions of certain pollutants or prohibit certain types of emissions management practices. In recent years, the CAA has been used to impose additional stringent requirements upon oil and gas production operations. While many of these rules may not be directly applicable to our business, they are applicable to the business of our customers. Promulgation of stricter permitting or emission control requirements could delay or impair our or our customers’ ability to obtain air emission permits, to develop new wells and to continue to operate existing wells, and result in fewer wells being drilled or redeveloped, causing a decrease in demand for our services. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties, as well as injunctive relief, for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. 
+Climate Change 
+The EPA has determined that emissions of greenhouse gases, including carbon dioxide and methane, present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. The EPA has established greenhouse gas emissions reporting requirements for sources in the oil and gas sector and has also promulgated rules requiring certain large stationary sources of greenhouse gases to obtain preconstruction permits under the CAA and follow “best available control technology” requirements. Although we are not likely to become subject to greenhouse gas emissions permitting and best available control technology requirements because none of our facilities are presently major sources of greenhouse gas emissions, such requirements could become applicable to our customers. In addition, the EPA has used the CAA to impose additional greenhouse gas emissions control requirements upon our customers. Furthermore, the Inflation Reduction Act (“IRA 2022”) imposes a methane emissions charge on certain emissions from specific classes of sources that are required to report their greenhouse gas emissions, which began in calendar year 2024. This fee as well as additional requirements on greenhouse gas emissions from our customers could have an adverse effect on their costs of operations or financial performance, thereby adversely affecting our business, financial condition, and results of operations. Also, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, and many states have already established regional greenhouse gas “cap-and-trade” programs. The adoption of any legislation or regulation that restricts emissions of greenhouse gases from the equipment and operations of our customers or with respect to the oil and natural gas they produce could adversely affect demand for our products and services. 
+7 
+Hydraulic Fracturing 
+Our business is clearly dependent on hydraulic fracturing and horizontal drilling activities. As further described herein, hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shale. The process, which involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. There is considerable legislative and regulatory focus on the emissions of methane, which may be released during hydraulic fracturing, chemicals used in the hydraulic fracturing process, the discharge of wastewater from hydraulic fracturing operations and concerns about the triggering of seismic activity by the injection of produced waters into underground wells. The adoption of new or revised legislation or regulation could make it significantly more difficult and/or costly to drill and operate oil and gas wells. If adopted, such legislation or regulation could result in a decline in the completion of new oil and gas wells or the recompletion of existing wells, which could negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the demand for our services. Given the long-term trend towards increasing regulation, future regulation in the industry remains a possibility. 
+Some states, counties, and municipalities have enacted or are considering moratoria on hydraulic fracturing. For example, New York, Vermont, Maryland, and Washington have banned the use of high-volume hydraulic fracturing. Alternatively, some municipalities are, or have considered, zoning and other ordinances, the conditions of which could impose a de facto ban on drilling and/or hydraulic fracturing operations. Further, some states, counties, and municipalities are closely examining water use issues, such as permit and disposal options for processed water, which could have a material adverse impact on our financial condition, prospects, and results of operations if such additional permitting requirements are imposed upon our industry. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could reduce demand for our business by making it more difficult or costly for certain customers to perform fracturing to stimulate production from tight formations. 
+National Environmental Policy Act 
+Businesses and operations of our customers that are carried out on federal lands may be subject to the National Environmental Policy Act (“NEPA”), which requires federal agencies, including the U.S. Department of the Interior, to evaluate major agency actions having the potential to significantly impact the human environment. In the course of such evaluations, an agency will evaluate the potential direct, indirect, and cumulative impacts of a proposed project and, if necessary, will prepare a detailed Environmental Impact Statement that must be made available for public review and comment. To the extent that our customers’ current activities, as well as proposed plans, on federal lands require governmental permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects which in turn could reduce demand for our services. 
+Endangered Species Act and Migratory Bird Treaty Act 
+The federal Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or its habitat. The U.S. Fish and Wildlife Service (the “FWS”) must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development and development of sand mines used for hydraulic fracturing. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”), which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit. This prohibition covers most bird species in the U.S. Future implementation of the rules implementing the ESA and the MBTA are uncertain. If we or our customers were to have areas within our respective operations designated as critical or suitable habitat for a protected species, it could decrease demand for our services and have a material adverse effect on our business. 
+Canadian Laws and Regulations 
+Companies such as us offering energy services that include hydraulic fracturing, engineering, and wireline services in the Provinces of Alberta and British Columbia in Canada are regulated by both the provincial governments of Alberta and British Columbia (“Province”) and the federal government of Canada (“Canada”). This includes, but is not limited to, regulation related to environmental protection legislation, climate change legislation, fracking legislation, and legislation related to wildlife. In addition to being regulated by the Province and Canada, energy services companies may also be subject to other international, national, and subnational laws, regulations, and policies. 
+Provincial Legislation 
+Energy services companies are primarily regulated by provincial governments in Canada. For example, in Alberta, provincial legislation potentially applicable to our Canadian operations includes the Environmental Protection and 
+8 
+Enhancement Act , RSA 2000, e E-12. This Act promotes the protection, enhancement and wise use of the environment, and deals with matters such as air emissions, water discharges, and the handling of hazardous substances and waste control (for example, under the Waste Control Regulation , Alta Reg 192/1996). Other environmental legislation in the Province that applies to energy service companies includes: the Water Act, RSA 2000, c W-3 and associated regulations, under which companies must apply for a license for any water use; and the Wildlife Act, RSA 2000, c W-10 which provides for the protection and conservation of wild animals and endangered species in Alberta. 
+Other potentially applicable provincial legislation in Alberta includes legislation directed at the transportation of dangerous goods, including oil (the Dangerous Goods Transportation and Handling Act , RSA 2000, c D-4 and associated regulations), legislation intended to provide for the responsible management of oil wells and associated sites, including remediation responsibilities (the Oil and Gas Conservation Act , RSA 2000, c O-6 and associated regulations), legislation establishing regulatory bodies overseeing oil and gas and electricity in Alberta (the Responsible Energy Development Act , SA 2012, c R-17.3 and the Alberta Utilities Commission Act , SA 2007, c A-37.2), legislation governing the removal of gas or propane from Alberta (the Gas Resources Preservation Act , RSA 2000, c G-4), legislation to effect conservation and prevent waste of the oil sands resource in Alberta (the Oil Sands Conservation Act , RSA 2000, c O-7), and legislation governing worker safety (the Occupational Health and Safety Act , SA 2017, c O-2.1). 
+The Alberta Energy Regulator has a number of directives that are applicable to energy services companies, such as Directive 050, updated in November 2024, which addresses salinity ranges for soils that can receive drilling wastes, Directive 058, updated in October 2022, which sets out regulatory requirements for the handling, treatment, and disposal of upstream oilfield waste, and Directive 083, updated in November 2024, which sets out the requirements for managing subsurface integrity associated with hydraulic fracturing, including seismic monitoring in certain areas of Alberta. Other provinces in Canada have their own statutory regime applicable to oilfield service companies. 
+Federal Legislation 
+The Federal government in Canada shares certain jurisdiction with the provinces over certain environmental matters. Federal legislation potentially applicable to our Canadian operations includes legislation focused on regulating greenhouse gases (the Greenhouse Gas Pollution Pricing Act , SC 2018, c 12, s 186), legislation aimed at protecting wildlife (the Species at Risk Act , SC 2002, c 29, Fisheries Act, RSC 1985, c F-14, and Migratory Birds Convention Act, 1994, SC 1994, c 22), and legislation governing the transportation of potentially dangerous substances and prevention of pollution (the Transportation of Dangerous Goods Act, 1992 , SC 1992, c 34 and Canadian Environmental Protection Act, 1999, SC 1999, c 33). 
+Environmental assessment of major projects in Canada is shared between the federal and provincial governments. The federal environmental assessment legislation, the Impact Assessment Act , SC 2019, c 28, s1, governs approvals for federally regulated projects and was amended in June 2024. 
+9 
+Properties 
+Properties 
+Our corporate headquarters are located at 950 17 th Street, Suite 2400, Denver, Colorado 80202. We lease our general office space at our corporate headquarters. The lease expires in December 2027. We currently own or lease the following additional principal properties: 
+District Facility Location Size Leased or Owned 
+Midland, TX 90,000 sq. ft on 35 acres Owned 
+Midland, TX 70,000 sq. ft on 12 acres Owned 
+Midland, TX 14,000 sq. ft on 22 acres Owned 
+Odessa, TX 77,500 sq. ft on 48 acres Owned 
+Cibolo, TX 90,000 sq. ft on 34 acres Owned 
+Kermit, TX 5,000 acres Owned 
+Monahans, TX 3,200 acres Owned 
+Magnolia, TX 63,350 sq. ft Leased (through May 31, 2031) 
+Magnolia, TX 29,402 sq. ft Leased (through December 31, 2026) 
+Orla, TX 4 acres Leased 
+Shreveport, LA 215,000 sq ft. on 45 acres Owned 
+Cheyenne, WY 115,000 sq. ft on 60 acres Owned 
+Henderson, CO 50,000 sq. ft on 13 acres Leased (through December 31, 2034) 
+Henderson, CO 96,582 sq. ft on 12 acres Owned 
+Briggsdale, CO 7 acres Leased 
+Williston, ND 55,000 sq. ft on 50 acres Owned 
+Vernal, UT 30,901 sq. ft on 10 acres Leased (through September 30, 2025) 
+El Reno, OK 80,000 sq. ft on 33 acres Owned 
+Red Deer, AB 170,000 sq. ft on 42 acres Owned 
+Grand Prairie, AB 135,000 sq. ft on 40 acres Owned 
+We also lease several smaller facilities, which leases generally have terms of one to six years. We believe that our existing facilities are adequate for our operations and their locations allow us to efficiently serve our customers. We do not believe that any single facility is material to our operations and, if necessary, we could readily obtain a replacement facility. 
+Marketing and Customers 
+We have developed long-term partnerships with our customers through a continuous dialogue focused on their production economics. Further, we have a proven track record of executing our customers’ plans and delivering on time and in line with expected costs. Our customer base includes a broad range of integrated and independent E&P companies, including some of the largest E&P companies in our areas of operation. Our technological innovations, customer-tailored approach and track record of consistently providing high-quality, safe and reliable service has allowed us to develop long-term customer partnerships, which we believe makes us the service provider of choice for many of our customers. 
+Our sales and marketing activities typically are performed through our local sales representatives in each geographic region and are supported by our corporate headquarters. For the years ended December 31, 2024, 2023 and 2022, our top five customers collectively accounted for approximatel y 43% , 34%, and 30% of our revenues, respectively. For the year ended December 31, 2024, Occidental Petroleum Corporation accounted for more than 10% of consolidated revenues. For the years ended December 31, 2023, and 2022, no customers accounted for more than 10% of consolidated revenues. 
+10 
+Suppliers and Raw Materials 
+We have a dedicated supply chain team that manages sourcing and logistics to ensure flexibility and continuity of supply in a cost-effective manner across our areas of operation. We have built long-term relationships with multiple industry leading suppliers of proppant, chemicals and hydraulic fracturing equipment and have started to internally design and assemble key pump and maintenance parts. In addition, we have built a strong relationship with the assemblers of our custom-designed hydraulic fracturing fleets and believe we will continue to have timely access to new, high capability fleets as we continue to grow. In 2018, we vertically integrated a supplier of certain major components through the acquisition of ST9 Gas and Oil LLC, which subsequently changed its name to Liberty Advanced Equipment Technologies LLC, and now provides engineering design and packaging for certain equipment used in our operations. In October 2021, we vertically integrated a supplier of our containerized sand and last mile proppant logistics solutions with the acquisition of Proppant Express Solutions LLC. This, along with our two state-of-the-art sand mines in the Permian Basin, help us alleviate the risk of proppant supply shortages. 
+We purchase a wide variety of raw materials, parts and components that are manufactured and supplied for our operations. We are not dependent on any single source of supply for those parts, supplies or materials. To date, we have generally been able to obtain the equipment, parts and supplies necessary to support our operations, although we have experienced delivery delays and shortages on some items. While we believe that we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers, we may not always be able to do so. In addition, certain materials for which we do not currently have long-term supply agreements could experience shortages and significant price increases in the future. As a result, we may be unable to mitigate any future supply shortages and our results of operations, prospects and financial condition could be adversely affected. 
+Competition 
+The markets in which we operate are highly competitive. We provide services in various geographic regions across the United States and Canada, and our competitors include many large and small oilfield service providers, including some of the largest integrated service companies. Our hydraulic fracturing services compete with large, integrated companies such as Halliburton Company as well as other companies including Patterson-UTI Energy Inc. and ProFrac Holding Corp. In addition, we compete regionally with ProPetro Services, Inc. and other smaller service providers. 
+We believe that the principal competitive factors in the markets we serve are technical expertise, equipment capacity, work force competency, efficiency, safety record, reputation, experience and price. Additionally, projects are often awarded on a bid basis, which tends to create a highly competitive environment. We seek to differentiate ourselves from our competitors by delivering the highest-quality services and equipment possible, coupled with superior execution and operating efficiency in a safe working environment. 
+Available Information 
+We file or furnish annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The SEC also maintains an internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC. 
+We also make available free of charge through our website, www.libertyenergy.com, electronic copies of certain documents that we file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. 
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+Item 1A. Risk Factors 
+Described below are certain risks that we believe apply to our business and the industry in which we operate. You should carefully consider each of the risks described below in conjunction with other information including the financial statements and related notes provided in this Annual Report and in our other public disclosures. The risks described below highlight potential events, trends or other circumstances that could adversely affect our business, financial condition, results of operations, cash flows, liquidity or access to sources of financing, and consequently, the market value of our Class A common stock, par value $0.01 per share (“Class A Common Stock”). These risks could cause our future results to differ materially from historical results and from guidance we may provide regarding our expectations of future financial performance. The risks described below are those that we have identified as material and is not an exhaustive list of all the risks we face. There may be other risks and uncertainties not currently known to us or that we currently deem to be immaterial which may also materially and adversely affect our business operations in the future. Please refer to the explanation of the qualifications and limitation on forward-looking statements set forth on page ii hereof. 
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+Risks Related to the Oil and Natural Gas Industry 
+Federal, state, local and other applicable legislative and regulatory initiatives relating to hydraulic fracturing may serve to limit future oil and natural gas E&P activities and could have a material adverse effect on our results of operations and business. 
+Various federal, state, local and other applicable legislative and regulatory initiatives have been, or could be undertaken which could result in additional requirements or restrictions being imposed on hydraulic fracturing operations. Currently, hydraulic fracturing is generally exempt from federal regulation under the Safe Drinking Water Act Underground Injection Control (the “SDWA UIC”) program and is typically regulated by state oil and gas commissions or similar agencies but increased scrutiny and regulation by federal agencies does occur. For example, in late 2016, the EPA released a final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources. Additionally, the EPA has asserted regulatory authority pursuant to the SDWA UIC program over hydraulic fracturing activities involving the use of diesel fuel in the fracturing fluid and issued guidance regarding the permitting of such activities. Furthermore, the U.S. Bureau of Land Management has previously published rules that established stringent standards relating to hydraulic fracturing on federal and Native American lands. Similarly, the EPA has adopted rules on the capture of methane and other emissions released during hydraulic fracturing. These rules have been the subject of ongoing legal challenges. In recent years, the EPA has enacted additional methane rules for new and existing petroleum operations. The EPA rules could make it more difficult and/or costly to drill and operate oil and gas wells. These rules may result in a decline in the completion of new oil and gas wells or the recompletion of existing wells, which could negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the demand for our services. In addition to federal regulatory actions, legislation has been introduced, but not enacted, in Congress to provide for further federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. 
+Moreover, many states and local governments have adopted, or are considering, regulations that impose new or more stringent permitting, disclosure, disposal and well-construction requirements on hydraulic fracturing operations, including states where we or our customers operate, such as Texas, Colorado and North Dakota. States could also elect to place prohibitions on hydraulic fracturing, as several states have already done. In addition, some states have adopted broader sets of requirements related to oil and gas development more generally that could impact hydraulic fracturing activities. For example, the Colorado legislature adopted SB 19-181, which gave greater regulatory authority to local jurisdictions and reoriented the mandate of the Colorado Oil and Gas Conservation Commission to place more emphasis on the protection of human health and the environment. In response, a reconstituted Colorado Oil and Gas Conservation Commission modified its rules to address the requirements of the legislation, adopting increased setback requirements, provisions for assessing alternative sites for well pads to minimize environmental impacts, and consideration to cumulative impacts, among other provisions. The Colorado Department of Public Health and the Environment also finalized rules related to the control of emissions from certain pre-production activities. In Texas, there has been increased pressure on the Railroad Commission (“RRC”) to impose more stringent limitations on the flaring of gas from wells to prevent waste and because of increased concerns related to the environmental effects of flaring. The RRC continues to approve flaring permits, but at least one lawsuit was filed by a pipeline operator challenging the RRC’s flaring approval practices, but the suit was subsequently dismissed without any substantive opinion on the issue of flaring. Environmental groups, local citizens groups and others continue to seek to use a variety of means to force action on additional restrictions on hydraulic fracturing and oil and gas development generally. 
+Additionally, some states have enacted legislation limiting PFAS usage in certain products or limiting PFAS usage generally. For example, Colorado has banned the use of PFAS in oil and gas products including hydraulic fracturing fluids, drilling fluids and proppants. Should PFAS be in hydraulic fracturing chemicals, this could open up a new front for the regulation of hydraulic fracturing and result in additional exposure to liability for contamination resulting from the use or release of hydraulic fracturing chemicals. Additionally, various regulatory actions have been taken with respect to PFAS, including listing of certain PFAS as hazardous substances under CERCLA, that may result in additional exposure to liability for contamination resulting from the use or release of these chemicals. 
+Some states in which we operate require the disclosure of some or all of the chemicals used in our hydraulic fracturing operations. Certain aspects of one or more of these chemicals may be considered proprietary by us or our chemical suppliers. Disclosure of our proprietary chemical information to third parties or to the public, even if inadvertent, could diminish the value of our trade secrets or those of the chemicals suppliers and could result in competitive harm to us, which could have an adverse impact on our business, financial condition, prospects and results of operations. 
+In recent years, there have been allegations that hydraulic fracturing may result in seismic activities. Although the extent of any correlation between hydraulic fracturing and seismic activity has been and remains the subject of studies and debate, some parties believe that there is a causal relationship. As a result, federal and state legislatures and agencies may seek to further regulate, restrict or prohibit hydraulic fracturing. Such actions could result in a decline in the completion of new oil and 
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+gas wells, which could negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the demand for our services. 
+Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to, and litigation concerning, oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays for our customers or increased operating costs in the production of oil and natural gas, including from the developing shale plays, or could make it more difficult for (or could result in a prohibition for) us and our customers to perform hydraulic fracturing. The adoption of any additional laws or regulations regarding hydraulic fracturing or limitation in hydraulic fracturing could potentially cause a decrease in the completion of new oil and natural gas wells and an associated decrease in demand for our services and increased compliance costs and time. Such events could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition. 
+Additional legislation, executive actions, regulations or other regulatory initiatives to limit, delay or prohibit hydraulic fracturing or other aspects of oil and gas development may be pursued. In the event that these or other new federal restrictions, delays or prohibitions relating to the hydraulic fracturing process are adopted in areas where we or our customers conduct business, we or our customers may incur additional costs or permitting requirements to comply with such federal requirements that may be significant and, in the case of our customers, also could result in added restrictions or delays in the pursuit of exploration, development, or production activities, which would in turn reduce the demand for our services and have a material adverse effect on our results of operations. 
+Federal legislation and regulatory initiatives relating to drilling on federal lands could harm our business and negatively impact the oil and natural gas industry. 
+Businesses and operations of our customers may be carried out on federal lands. As an example, in January 2021, based on a directive from President Biden, the U.S. Department of the Interior issued an order that effectively suspended new oil and gas leases and drilling permits on non-Indian federal lands and waters for a period of 60 days. However, the suspension did not limit existing operations under valid leases. 
+President Biden followed with an executive order directing the Secretary of the Interior to pause the issuance of new oil and gas leases on federal public lands and offshore waters pending completion of a comprehensive review of federal oil and gas permitting and leasing practices that take into consideration potential climate and other impacts associated with oil and gas activities. The leasing suspension was the subject of several lawsuits, resulting in conflicting decisions on the legality of the lease suspension. While the various lawsuits were pending, in August 2022, Congress passed the IRA 2022 which, among other things, made changes to the federal oil and gas leasing program (including increasing royalty rates and implementing policies to discourage venting and flaring) and require several oil and gas lease auctions, including some that had been suspended or cancelled. 
+Additionally, in November 2021, the U.S. Department of the Interior released a report on the federal oil and gas leasing program, which found that the then current program failed to serve the public interest. The report made several recommendations, including increasing royalty rates and adding new restrictions on what lands are made available for oil and gas development to minimize leasing of lands with low potential for development. The U.S. Department of the Interior promulgated rules in 2024 based on the recommendations. In April 2022, the U.S. Department of the Interior also announced that the U.S. Bureau of Land Management would post notices for significantly reformed onshore lease sales that would promote the public interest in public lands while addressing deficiencies in the current federal oil and gas leasing program. The new lease sales will incorporate many of the recommendations in the U.S. Department of the Interior report on the federal leasing program. Such scheduled sales began in June 2022. 
+Furthermore, a group of oil and gas related interests has also sued alleging that lease sales are not occurring as required under the Mineral Leasing Act. In addition, where lease sales have occurred, environmental groups have sued to block the sales. On June 1, 2022, the U.S. District Court for the District of Columbia granted a motion to voluntarily dismiss three cases after the U.S. Bureau of Land Management and other defendants agreed to conduct more robust environmental reviews of certain oil and gas leases and reconsider the cumulative climate effects of these leases. The settlement agreements apply to nearly four million acres of land in Colorado, Wyoming, Utah, Montana, and New Mexico. If the U.S. Bureau of Land Management fails to complete its obligations under the settlement agreements, the plaintiffs can reinstate the litigation. 
+To the extent our customers operate on leased federal land, these and other regulatory actions could have a material adverse effect on the Company and our industry. 
+Our business depends on domestic capital spending by the oil and natural gas industry, and reductions in capital spending could have a material adverse effect on our liquidity, results of operations and financial condition. 
+Our business is directly affected by our customers’ capital spending to explore for, develop and produce oil and natural gas in the United States and Canada. In addition, certain of our customers could become unable to pay their vendors and service 
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+providers, including us, as a result of a decline in commodity prices. Reduced discovery rates of new oil and natural gas reserves in our areas of operation as a result of decreased capital spending may also have a negative long-term impact on our business, even in an environment of stronger oil and natural gas prices. Any of these conditions or events could adversely affect our operating results. If current activity levels decrease or our customers further reduce their capital spending, it could have a material adverse effect on our liquidity, results of operations and financial condition. 
+Industry conditions are influenced by numerous factors over which we have no control, including: 
+• expected economic returns to E&P companies of new well completions; 
+• domestic and foreign economic conditions and supply of and demand for oil and natural gas; 
+• the level of prices, and expectations about future prices, of oil and natural gas; 
+• the level of global oil and natural gas exploration and production; 
+• the level of domestic and global oil and natural gas inventories; 
+• the supply of and demand for hydraulic fracturing services and equipment in the United States and Canada; 
+• federal, tribal, state and local laws, regulations and taxes, including the policies of governments regarding hydraulic fracturing, oil and natural gas exploration, development and production activities and the transportation of oil and gas by pipeline, as well as non-U.S. governmental regulations and taxes; 
+• governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves; 
+• political and economic conditions in oil and natural gas producing countries; 
+• actions by the members of the Organization of Petroleum Exporting Countries and other oil exporting nations (“OPEC+”) with respect to oil production levels and potential changes in such levels; 
+• global weather conditions and natural disasters; 
+• worldwide political, military and armed conflict, and economic conditions; 
+• the cost of producing and delivering oil and natural gas; 
+• lead times associated with acquiring equipment and products and availability of qualified personnel; 
+• the discovery rates of new oil and natural gas reserves; 
+• the production decline rate of existing oil and gas wells; 
+• stockholder activism or activities by non-governmental organizations to limit certain sources of funding for the energy sector or to restrict the exploration, development, production and transportation of oil and natural gas; 
+• the availability of water resources, suitable proppant and chemical additives in sufficient quantities for use in hydraulic fracturing fluids; 
+• advances in exploration, development and production technologies or in technologies affecting energy consumption; 
+• the availability, proximity and capacity of oil and natural gas pipelines and other transportation facilities; 
+• merger and divestiture activity among oil and natural gas producers; 
+• the price and availability of alternative fuels and energy sources; and 
+• uncertainty in capital and commodities markets and the ability of oil and natural gas companies to raise equity capital and debt financing. 
+The volatility of oil and natural gas prices may adversely affect the demand for our hydraulic fracturing services and negatively impact our results of operations. 
+The demand for our hydraulic fracturing services is primarily determined by current and anticipated oil and natural gas prices and the related levels of capital spending and drilling activity in the areas in which we have operations. Volatility or weakness in oil prices or natural gas prices (or the perception that oil prices or natural gas prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells. This, in turn, could lead to lower demand for our services and may cause lower utilization of our assets. We have experienced, and may in the future experience significant fluctuations in operating results as a result of the reactions of our customers to changes in oil and natural gas prices. 
+Prices for oil and natural gas historically have been volatile and are expected to continue to be volatile. During the year 2024, the posted WTI price traded at an average of $76.63 per barrel (“Bbl”), as compared to the 2023 average of $77.58 per 
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+Bbl and the 2022 average of $94.90 per Bbl. During this three-year period, the WTI price fluctuated between a high of $123.64 per Bbl and a low of $66.61 per Bbl. If the prices of oil and natural gas remain or become more volatile, our operations, financial condition, cash flows and level of expenditures may be materially and adversely affected. 
+Delays or restrictions in obtaining permits by us for our operations or by our customers for their operations could impair our business. 
+In most states, our hydraulic fracturing services, our natural gas compression and CNG delivery operations, and the operations of our oil and natural gas producing customers require permits from one or more governmental agencies in order to perform drilling and completion activities, secure water rights, or other regulated activities. Such permits are typically issued by state agencies, but federal and local governmental permits may also be required. The requirements for such permits vary depending on the location where such regulated activities will be conducted. As with all governmental permitting processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit to be issued, and the conditions that may be imposed in connection with the granting of the permit. In addition, some of our customers’ drilling and completion activities may take place on federal land or Native American lands, requiring leases and other approvals from the federal government or Native American tribes to conduct such drilling and completion activities or other regulated activities. Under certain circumstances, federal agencies may cancel proposed leases for federal lands and refuse to grant or delay required approvals. Therefore, our customers’ operations in certain areas may be interrupted or suspended for varying lengths of time, causing a loss of revenue to us and adversely affecting our results of operations in support of those customers. 
+Oil and natural gas companies’ operations using hydraulic fracturing are substantially dependent on the availability of water. Restrictions on the ability to obtain water for E&P activities and the disposal of flowback and produced water may impact their operations and have a corresponding adverse effect on our business, results of operations and financial condition. 
+Water is an essential component of shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Our oil and natural gas producing customers’ access to water to be used in these processes may be adversely affected due to reasons such as periods of extended drought, privatization, third party competition for water in localized areas or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. The occurrence of these or similar developments may result in limitations being placed on allocations of water due to needs by third party businesses with more senior contractual or permitting rights to the water. Our customers’ inability to locate or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact their E&P operations and have a corresponding adverse effect on our business, results of operations and financial condition. 
+Moreover, the imposition of new environmental regulations and other regulatory initiatives could include increased restrictions on our producing customers’ ability to dispose of flowback and produced water generated in hydraulic fracturing or other fluids resulting from E&P activities. Applicable laws impose restrictions and strict controls regarding the discharge of pollutants into waters of the United States and require that permits or other approvals be obtained to discharge pollutants to such waters. Additionally, in 2016, the EPA adopted a pretreatment standard that prohibits the discharge of wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly owned treatment works. Further, regulations implemented under both federal and state laws prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. These laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and hazardous substances. Compliance with current and future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells and any inability to secure transportation and access to disposal wells with sufficient capacity to accept all of our flowback and produced water on economic terms may increase our customers’ operating costs and could result in restrictions, delays, or cancellations of our customers’ operations, the extent of which cannot be predicted. 
+Our operations are subject to risks associated with climate change and potential regulatory programs meant to address climate change; these programs may impact or limit our business plans, result in significant expenditures or reduce demand for our services and reduce our revenues. 
+Climate change continues to be the focus of political and societal attention. Numerous proposals have been made and are likely to be forthcoming on the international, national, regional, state and local levels to reduce GHG emissions. These efforts have included or may include cap-and-trade programs, carbon taxes, GHG reporting obligations and other regulatory programs that limit or require control of GHG’s from certain sources. Programs addressing climate change may limit the ability to produce crude oil and natural gas, require stricter limits on the release of methane or other GHGs, increase reporting and/or other compliance obligations associated with GHG emissions, limit the ability to explore in new areas, limit the construction of pipelines and related equipment or may make it more expensive to produce, any of which may decrease the demand for our services and our revenues. 
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+Incentives to conserve energy or use alternative energy sources, which can be part of climate change programs, may increase the competitiveness of alternative energy sources (such as wind, solar, geothermal, tidal and biofuels) or increase the focus on reducing the use of combustion engines in transportation (such as governmental mandates that ban the sale of new gasoline-powered automobiles). At various Conferences of the Parties of the United Nations Framework Convention on Climate Change, the parties adopted a statement calling for “transitioning away from fossil fuels” and an increased focus on renewable energy capacity and energy efficiency. These actions could, in turn, reduce demand for hydrocarbons and therefore for our services, which would lead to a reduction in our revenues. 
+An increased societal and governmental focus on ESG and climate change issues may adversely impact our business, impact our access to investors and financing, and decrease demand for our services. 
+An increased expectation that companies address ESG matters (including climate change) may have a myriad of impacts on our business. Some investors and lenders are factoring these issues into investment and financing decisions. They may rely upon companies that assign ratings to a company’s ESG performance. Unfavorable ESG ratings, as well as recent activism around fossil fuels, may dissuade investors or lenders from us and toward other industries, which could negatively impact our stock price or our access to capital. Additionally, some potential sources of investment or financing have announced an intention to avoid or limit investment in companies that engage in hydraulic fracturing. While a substantial number of major banks and financing sources remain active in investments related to hydraulic fracturing, it is possible that the investment avoidance or limitation theme could expand in the future and restrict access to capital for companies like us. 
+Moreover, while we have and may continue to create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures are based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. Additionally, to the extent that we report GHG emissions data, the methodologies that we use to calculate our emissions may change over time based upon changing industry standards. We note that standards and expectations regarding the processes for measuring and counting GHG emissions and GHG emission reductions are evolving, and it is possible that our approach to measuring our emissions maybe considered inconsistent with common or best practices with respect to measuring and accounting for such matters. If our approaches to such matters fall out of step with common or best practice, we may be subject to additional scrutiny, criticism, regulatory and investor engagement or litigation, any of which may adversely impact our business, financial condition or results of operation. 
+In 2023, the State of California enacted legislation that will require large U.S. companies doing business in California to make broad-based climate-related disclosures starting as early as 2026, and other jurisdictions, domestically and internationally, are also considering various climate change disclosure requirements. 
+In addition, ESG and climate change issues may cause consumer preference to shift toward other alternative sources of energy, lowering demand for oil and natural gas and consequently lowering demand for our services. In some areas these concerns have caused governments to adopt or consider adopting regulations to transition to a lower-carbon economy. These measures may include adoption of cap-and-trade programs, carbon taxes, increased efficiency standards, prohibitions on the manufacture of certain types of equipment (such as new automobiles with internal combustion engines), and requirements for the use of alternate energy sources such as wind or solar. These types of programs may reduce the demand for oil and natural gas and consequently the demand for our services. 
+Approaches to climate change and a transition to a lower-carbon economy, including government regulation, company policies, and consumer behavior, are continuously evolving. At this time, we cannot predict how such approaches may develop or otherwise reasonably or reliably estimate their impact on our financial condition, results of operations and ability to compete. However, any long-term material adverse effect on the oil and gas industry may adversely affect our financial condition, results of operations and cash flows. 
+Our operations are subject to significant risks, some of which are beyond our control. These risks may be self-insured, or may not be fully covered under our insurance policies. 
+Our operations are subject to significant hazards often found in the oil and natural gas industry, such as, but not limited to, accidents, including accidents related to trucking operations provided in connection with our services, blowouts, explosions, craterings, fires, natural gas leaks, oil and produced water spills and releases of hydraulic fracturing fluids or other well fluids into the environment. These conditions can cause: 
+• disruption in operations; 
+• substantial repair or remediation costs; 
+• personal injury or loss of human life; 
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+• significant damage to or destruction of property, and equipment; 
+• environmental pollution, including groundwater contamination; 
+• unusual or unexpected geological formations or pressures and industrial accidents; 
+• impairment or suspension of operations; and 
+• substantial revenue loss. 
+In addition, our operations are subject to, and exposed to, employee/employer liabilities and risks such as wrongful termination, discrimination, labor organizing, retaliation claims and general human resource related matters. 
+The occurrence of a significant event or adverse claim in excess of the insurance coverage that we maintain or that is not covered by insurance could have a material adverse effect on our liquidity, consolidated results of operations and financial condition. Claims for loss of oil and natural gas production and damage to formations can occur in the well services industry. Litigation arising from a catastrophic occurrence at a location where our equipment and services are being used or trucking services provided in connection therewith may result in our being named as a defendant in lawsuits asserting large claims. 
+We do not have insurance against all foreseeable risks, either because insurance is not available or because of the high premium costs. The occurrence of an event not fully insured against or the failure of an insurer to meet its insurance obligations could result in substantial losses. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. Insurance may not be available to cover any or all of the risks to which we are subject, or, even if available, it may be inadequate, or insurance premiums or other costs could rise significantly in the future so as to make such insurance prohibitively expensive. 
+We could experience continued or increased severity of trucking related issues or trucking accidents, which could materially affect our results of operations. 
+Trucking services can be adversely impacted by traffic congestion, shortage of drivers and weather delays which could hinder our service levels. We have experienced in the past, and we may experience in the future, a shortage of available trucking services in the United States due to the industry not having enough qualified drivers, which impacted our field operations at times. In addition, our field employees are generally required to have a commercial driver’s license (“CDL”) so they can drive trucks and move our frac pumps and other equipment from location to location. Obtaining employees with CDLs can be challenging during times when the trucking industry has driver shortages, as competition for qualified employees is often more intense. If we are unable to obtain trucking services on a timely basis or the services of a sufficient number of field employees with CDLs, it could have a material adverse impact on our financial condition, results of operations and cash flows. 
+In addition, potential liability and unfavorable publicity associated with accidents in the trucking industry can be severe and occurrences are unpredictable. The number and severity of litigation claims may be worsened by distracted driving by both truck drivers and other motorists. Our transportation operations often involve traveling on unpaved roads located in rural areas, increasing the risk of accidents. If we are involved in an accident involving hazardous substances, if there are releases of hazardous substances we transport, if soil or groundwater contamination is found at our facilities or results from our operations, or if we are found to be in violation of applicable environmental laws or regulations, we could owe cleanup costs and incur related liabilities, including substantial fines or penalties or civil and criminal liability. A material increase in the frequency or severity of accidents or workers’ compensation claims or the unfavorable development of existing claims could materially adversely affect our results of operations. In the event that accidents occur, we may be unable to obtain desired contractual indemnities, and our insurance may be inadequate in certain cases which could result in substantial losses. Any such lawsuits in the future may result in the payment of substantial settlements or damages and increases to our insurance costs. 
+We may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition, prospects and results of operations. 
+Our services are subject to inherent risks that can cause personal injury or loss of life, damage to or destruction of property, equipment or the environment or the suspension of our operations. Litigation arising from operations where our services are provided, may cause us to be named as a defendant in lawsuits asserting potentially large claims including claims for exemplary damages. We maintain what we believe is customary and reasonable insurance to protect our business against these potential losses, but such insurance may not be adequate to cover our liabilities, and we are not fully insured against all risks. 
+In addition, our customers usually assume responsibility for, including control and removal of, all other pollution or contamination which may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling and completion fluids. We may have liability in such cases if we are grossly negligent or commit willful acts. Our customers generally agree to indemnify us against claims arising from their employees’ personal injury or death to the extent that, in the case of our hydraulic fracturing operations, their employees are injured by such operations, unless resulting from our gross negligence or willful misconduct. Our customers also generally agree to indemnify us for loss or destruction of 
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+customer-owned property or equipment. In turn, we agree to indemnify our customers for loss or destruction of property or equipment we own and for liabilities arising from personal injury to or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. However, we might not succeed in enforcing such contractual liability allocation or might incur an unforeseen liability falling outside the scope of such allocation. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operation. 
+We are subject to environmental and occupational health and safety laws and regulations that may expose us to significant costs and liabilities. 
+Our operations and the operations of our customers are subject to numerous federal, tribal, regional, state and local laws and regulations relating to protection of the environment including natural resources, health and safety aspects of our operations and waste management, including the transportation and disposal of waste and other materials. These laws and regulations may impose numerous obligations on our operations and the operations of our customers, including the acquisition of permits or other approvals to conduct regulated activities, the imposition of restrictions on the types, quantities and concentrations of various substances that may be released into the environment or injected in non-productive formations below ground in connection with oil and natural gas drilling and production activities, the incurrence of capital expenditures to mitigate or prevent releases of materials from our equipment, facilities or from customer locations where we are providing services, the imposition of substantial liabilities for pollution resulting from our operations, and the application of specific health and safety criteria addressing worker protection. Any failure on our part or the part of our customers to comply with these laws and regulations could result in assessment of sanctions including administrative, civil and criminal penalties; imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures; the occurrence of restrictions, delays or cancellations in the permitting, performance or development of projects or operations; and the issuance of orders enjoining performance of some or all of our operations in a particular area. In addition to civil and other penalties associated with enforcement activities regarding compliance with occupational health and safety laws, our operations may be subject to abatement obligations that could require significant modifications to existing operations to achieve compliance. 
+Our business activities present risks of incurring significant environmental costs and liabilities, including costs and liabilities resulting from our handling of oilfield and other wastes, because of air emissions and wastewater discharges related to our operations, and due to historical oilfield industry operations and waste disposal practices. Moreover, accidental releases or spills may occur in the course of our operations or at facilities where our wastes are taken for reclamation or disposal, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for injuries to persons or damages to properties or natural resources. Some environmental laws and regulations may impose strict liability, which means that in some situations we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Remedial and abatement costs and other damages arising as a result of environmental and occupational health and safety laws and costs associated with changes in these laws and regulations could be significant and have a material adverse effect on our liquidity, consolidated results of operations and financial condition. 
+Laws and regulations protecting the environment generally have become more stringent in recent years and are expected to continue to do so, which could lead to material increases in costs for future environmental compliance and remediation. In particular, the ESA restricts activities that may result in a “take” of endangered or threatened species and provides for substantial penalties in cases where listed species are taken by being harmed. The dunes sagebrush lizard is one example of a species that was recently listed as an endangered species. The State of Texas has filed suit challenging the listing. The dunes sagebrush lizard is found in the active and semi-stable shinnery oak dunes of southeastern New Mexico and adjacent portions of Texas, including areas where our customers operate and our frac sand facilities are located. The listing of the dunes sagebrush lizard as an endangered species, may impact our operations and the operations of our customers in any area that is designated as the dunes sagebrush lizard’s habitat. Depending on the locations of our operations, we and our customers may be required to comply with expensive mitigation measures intended to protect the dunes sagebrush lizard and its habitat. If the U.S. Department of the Interior and Fish and Wildlife Service lists additional species as endangered or protected, it could negatively impact our business activities or the business activities of our customers which could subsequently impact demand for our services and thereafter our revenue. Furthermore, new laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement with respect to environmental matters could restrict, delay or curtail exploratory or developmental drilling for oil and natural gas by our customers and could limit our well servicing opportunities. 
+Oilfield anti-indemnity provisions enacted by many states may restrict or prohibit a party’s indemnification of us. 
+We typically enter into agreements with our customers governing the provision of our services, which usually include certain indemnification provisions for losses resulting from operations. Such agreements may require each party to indemnify the other against certain claims regardless of the negligence or other fault of the indemnified party; however, many states place limitations on contractual indemnity agreements, particularly agreements that indemnify a party against the consequences of its own negligence. Furthermore, certain states, including Texas, New Mexico and Wyoming, have enacted statutes generally 
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+referred to as “oilfield anti-indemnity acts” expressly prohibiting certain indemnity agreements contained in or related to oilfield services agreements. Such anti-indemnity acts may restrict or void a party’s indemnification of us, which could have a material adverse effect on our business, financial condition, prospects and results of operations. 
+Technology advancements in well service technologies, including those involving hydraulic fracturing, could have a material adverse effect on our business, financial condition and results of operations. 
+The hydraulic fracturing industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As competitors and others use or develop new technologies or technologies comparable to ours in the future, we may lose market share or be placed at a competitive disadvantage. Further, we may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of our competitors may have greater financial, technical and personnel resources than we do, which may allow them to gain technological advantages or implement new technologies before we can. Additionally, we may be unable to implement new technologies or services at all, on a timely basis or at an acceptable cost. New technology could also make it easier for our customers to vertically integrate their operations, thereby reducing or eliminating the need for our services. Limits on our ability to effectively use or implement new technologies may have a material adverse effect on our business, financial condition and results of operations. 
+The ability or willingness of OPEC+ and other oil exporting nations to set and maintain production levels and/or the impact of sanctions and global conflicts may have a significant impact on natural gas commodity prices. 
+OPEC+ is an intergovernmental organization that seeks to manage the price and supply of oil on the global energy market. Actions taken by OPEC+ members, including those taken alongside other oil exporting nations, have a significant impact on global oil supply and pricing. For example, OPEC+ and certain other oil exporting nations have previously agreed to take measures, including production cuts, to support crude oil prices. In 2020, largely as a result of the COVID-19 pandemic, oil prices decreased dramatically, and OPEC+ agreed to historic production cuts in an effort to support prices. Conversely, sanctions imposed on Russia as a result of the Russia-Ukraine conflict in 2022 increased prices. In October 2022, OPEC+ again determined to reduce production of oil, by approximately 2 million barrels per day. At its meeting on December 4, 2022, OPEC+ agreed to keep its current policy unchanged as the oil markets struggle to assess the impact of a slowing Chinese economy on demand, and the Group of Seven Nations agreed on a price cap on Russian oil supply. In June 2023, OPEC+ members announced they would extend crude oil production cuts through 2024, limiting global crude oil supplies. In November 2023, OPEC+ agreed to cut production by an additional 1 million barrels per day beginning in January 2024. In December 2024, OPEC+ agreed to delay the beginning of output rises and extended the full unwinding of previous production cuts until the end of 2026. 
+There can be no assurance that OPEC+ members and other oil exporting nations will agree to future production cuts or other actions to support and stabilize oil prices, nor can there be any assurance that sanctions or other global conflicts, including the Russia-Ukraine conflict and various conflicts in the broader Middle East, will not further impact oil prices. Uncertainty regarding future sanctions or actions to be taken by OPEC+ members or other oil exporting countries could lead to increased volatility in the price of oil and natural gas, which could adversely affect our business, future financial condition and results of operations. 
+Risks Related to the TRAs 
+The Company is required to make payments under the TRAs for certain tax benefits that it may claim, and the amounts of such payments could be significant. 
+In connection with the Company’s initial public offering (the “IPO”), on January 17, 2018, the Company entered into two Tax Receivable Agreements (the “TRAs”) with R/C Energy IV Direct Partnership, L.P. and the then-existing owners of Liberty Oilfield Services Holdings LLC (“Liberty Holdings”) that continued to own Liberty LLC Units (each such person and any permitted transferee, a “TRA Holder”). The TRAs generally provide for the payment by the Company to each TRA Holder of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that the Company actually recognizes (or is deemed to recognize in certain circumstances) as a result of certain increases in tax basis, net operating losses available to the Company as a result of the corporate reorganization performed in connection with the IPO (the “Corporate Reorganization”), and certain benefits attributable to imputed interest. The Company will retain the benefit of the remaining 15% of these cash savings. 
+The Company is a holding company and has no material assets other than its direct and indirect equity interests in its subsidiaries. Because the Company has no independent means of generating revenue, its ability to make payments under the TRAs is dependent on the ability of its subsidiaries to make distributions to the Company in an amount sufficient to cover its obligations under the TRAs. To the extent that the Company is unable to make payments under the TRAs for any reason, such payments will be deferred and will accrue interest until paid. 
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+The term of each of the TRAs continues until all tax benefits that are subject to such TRAs have been utilized or expired, unless the Company experiences a change of control (as defined in the TRAs, which includes certain mergers, asset sales and other forms of business combinations) or the TRAs are terminated early (at the Company’s election or as a result of its breach), and the Company makes the termination payments specified in such TRAs. In addition, payments the Company makes under the TRAs will be increased by any interest earned from the due date (without extensions) of the corresponding tax return. Payments under the TRAs commenced in 2020 and so long as the tax savings are recognized and the TRAs are not terminated, payments are anticipated to continue for 15 years after the date of the last redemption of the Liberty LLC Units, which occurred on January 31, 2023. Accordingly, if the applicable U.S. federal corporate tax rate is increased, then the amount of TRA payments paid in the future may also increase. 
+In certain cases, if the Company experiences a change of control (as defined under the TRAs, which includes certain mergers, asset sales and other forms of business combinations) or the TRAs terminate early (at the Company’s election or as a result of its breach), the Company would be required to make an immediate lump-sum payment, and such payment may be significantly in advance of, and may materially exceed, the actual realization, if any, of the future tax benefits to which the payment relates. As a result, the Company’s obligations under the TRAs could have a substantial negative impact on its liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. There can be no assurance we will be able to finance our obligations under the TRAs. Furthermore, as a result of this payment obligation, holders of our Class A Common Stock could receive substantially less consideration in connection with a change in control transaction than they would receive in the absence of such obligation. Because our payment obligations under the TRAs will not be conditioned upon the TRA Holders’ having continued interest in the Company or Liberty LLC, the TRA Holders’ interests may conflict with those of the holders of our Class A Common Stock. 
+Payments under the TRAs are based on the tax reporting positions that we will determine. The TRA Holders will not reimburse us for any payments previously made under the TRAs if any tax benefits that have given rise to payments under the TRAs are subsequently disallowed in an audit, except that excess payments made to any TRA Holder will be netted against payments that would otherwise be made to such TRA Holder, if any, after our determination of such excess. As a result, in such circumstances the Company could make payments that are greater than its actual cash tax savings, if any, and may not be able to recoup those payments, which could adversely affect the Company’s liquidity. Furthermore, the payments under the TRAs will not be conditioned upon a holder of rights under each of the TRAs having a continued ownership interest in the Company or Liberty LLC. For further details of the TRAs, see Note 12 —Income Taxes to the consolidated financial statements included in Part II, Item 8 of this Annual Report. 
+General Risks Related to our Business 
+We may be adversely affected by uncertainty in the global financial markets and the deterioration of the financial condition of our customers. 
+Our future results may be impacted by the uncertainty caused by an economic downturn, volatility or deterioration in the debt and equity capital markets, inflation, deflation or other adverse economic conditions that may negatively affect us or parties with whom we do business resulting in a reduction in our customers’ spending and their non-payment or inability to perform obligations owed to us, such as the failure of customers to honor their commitments or the failure of major suppliers to complete orders. Additionally, during times when the oil or natural gas markets weaken, our customers are more likely to experience financial difficulties, including being unable to access debt or equity financing, which could result in a reduction in our customers’ spending for our services. In addition, in the course of our business we hold accounts receivable from our customers. In the event of the financial distress or bankruptcy of a customer, we could lose all or a portion of such outstanding accounts receivable associated with that customer. Further, if a customer was to enter into bankruptcy, it could also result in the cancellation of all or a portion of our service contracts with such customer at significant expense or loss of expected revenues to us. 
+Our business, financial condition and results of operations may be adversely impacted by the effects of inflation. 
+Inflation has the potential to adversely affect our business, financial condition and results of operations by increasing our overall cost structure, particularly if we are unable to achieve commensurate increases in the prices we charge our customers. Other inflationary pressures could affect wages, the cost and availability of components, materials and other inputs and our ability to meet customer demand. Inflation may further exacerbate other risk factors, including supply chain disruptions, risks related to international operations and the recruitment and retention of qualified employees. 
+Reliance upon a few large customers may adversely affect our revenue and operating results. 
+Our top five customers represented approximately 43%, 34%, and 30%, of our consolidated revenue for the years ended December 31, 2024, 2023, and 2022, respectively. It is possible that we will derive a significant portion of our revenue from a concentrated group of customers in the future. If a major customer fails to pay us, revenue would be impacted, and our operating results and financial condition could be materially harmed. Additionally, if we were to lose any material customer or our customers were to consolidate or merge with other operators, we may not be able to redeploy our equipment at similar 
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+utilization or pricing levels or within a short period of time and such loss could have a material adverse effect on our business until the equipment is redeployed at similar utilization or pricing levels. 
+We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss. 
+The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain processing activities. For example, we depend on digital technologies to perform many of our services and to process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. In early 2020, we experienced a denial of service cyberattack that targeted a portion of our non-financial data. We immediately shutdown critical systems, diagnosed the root cause of the attack and then methodically returned systems online. This cyberattack disrupted certain non-financial aspects of our internal system for a period of less than one day, while limited and non-critical portions of our systems were kept offline for up to one week in order to properly evaluate the breach. We determined that this cyberattack did not materially affect us or any of our operations. We engaged in extensive data evaluation for potential damage and concluded that minimal to no data loss had occurred as a result of this cyberattack. Our technologies, systems and networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches in the future that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we will likely be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. Our insurance coverage for cyberattacks may not be sufficient to cover all the losses we may experience as a result of such cyberattacks. 
+Our assets require significant amounts of capital for maintenance, upgrades and refurbishment and may require significant capital expenditures for new equipment. 
+Our hydraulic fracturing fleets and other completion service-related equipment require significant capital investment in maintenance, upgrades and refurbishment to maintain their competitiveness. The costs of components and labor have increased in the past and may increase in the future with increases in demand, which will require us to incur additional costs for any fleets we may acquire in the future. Our fleets and other equipment typically do not generate revenue while they are undergoing maintenance, upgrades or refurbishment. Any maintenance, upgrade or refurbishment project for our assets could increase our indebtedness or reduce cash available for other opportunities. Furthermore, such projects may require proportionally greater capital investments as a percentage of total asset value, which may make such projects difficult to finance on acceptable terms. To the extent we are unable to fund such projects, we may have less equipment available for service or our equipment may not be attractive to potential or current customers. Additionally, competition or advances in technology within our industry may require us to update or replace existing fleets or build or acquire new fleets. Such demands on our capital or reductions in demand for our hydraulic fracturing fleets and the increase in cost of labor necessary for such maintenance and improvement, in each case, could have a material adverse effect on our business, liquidity position, financial condition, prospects and results of operations and may increase our costs. 
+We rely on certain third parties for materials, and delays in deliveries of such materials, increases in the cost of such materials or our contractual obligations to pay for materials that we ultimately do not require could harm our business, results of operations and financial condition. 
+We have established relationships with certain suppliers of our materials (such as, but not limited to, proppant and chemical additives) and other parts, supplies and items needed for our operations. Delays or shortages in materials can result from a variety of reasons, including those caused by weather and natural disasters. Historically, the United States has undergone supply chain disruptions due to backlogged ports and trucking shortages, and our business is not immune from these effects. Even once the root cause of the supply chain disruption or any future shortage or delay has passed, it can take time for our supply chain to recover and run in a regular fashion. Should the nationwide supply chain disruption continue, or should any of our current suppliers be unable to provide the necessary materials or otherwise fail to deliver the materials in a timely manner and in the quantities required, any resulting delays in the provision of services could have a material adverse effect on our business, results of operations and financial condition. Additionally, increasing costs of such materials may negatively impact demand for our services or the profitability of our business operations. In the past, our industry faced sporadic proppant shortages associated with hydraulic fracturing operations requiring work stoppages, which are believed to have adversely impacted the operating results of several competitors. We may not be able to mitigate any future shortages of materials, including proppant, or the impact of supply chain disruptions. Furthermore, to the extent our contracts require us to purchase more materials, including proppant, than we ultimately require, we may be forced to pay for the excess amount under “take or pay” contract provisions. 
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+We currently utilize a limited number of assemblers and suppliers for major equipment to both build new fleets and upgrade any fleets we acquire to our preferred specifications, and our reliance on these vendors exposes us to risks including price and timing of delivery. 
+We currently utilize a limited number of assemblers and suppliers for major equipment to both build our new fleets and upgrade any fleets we may acquire to our custom design. If demand for hydraulic fracturing fleets or the components necessary to build such fleets increases or these vendors face financial distress or bankruptcy, these vendors may not be able to provide the new or upgraded fleets on schedule or at the current price. If this were to occur, we could be required to seek another assembler or other suppliers for major equipment to build or upgrade our fleets, which may adversely affect our revenues or increase our costs. 
+Interruptions of service on the rail lines by which we receive proppant could adversely affect our results of operations. 
+We receive a portion of the proppant used in our hydraulic fracturing services by rail. Rail operations are subject to various risks that may result in a delay or lack of service, including lack of available capacity, mechanical problems, extreme weather conditions, work stoppages, labor strikes, terrorist attacks and operating hazards. Additionally, if we increase the amount of proppant we require for delivery of our services, we may face difficulty in securing rail transportation for such additional amount of proppant. Any delay or failure in the rail services on which we rely could have a material adverse effect on our financial condition and results of operations. 
+Changes in transportation regulations may increase our costs and negatively impact our results of operations. 
+We are subject to various transportation regulations including as a motor carrier by the Department of Transportation and by various federal, state, provincial and tribal agencies, whose regulations include certain permit requirements of highway and safety authorities. These regulatory authorities exercise broad powers over our equipment transportation operations, generally governing such matters as the authorization to engage in motor carrier operations, safety, equipment testing, driver requirements and specifications and insurance requirements. The trucking industry is subject to possible regulatory and legislative changes that may impact our operations, such as changes in fuel emissions limits, hours of service regulations that govern the amount of time a driver may drive or work in any specific period and requiring onboard electronic logging devices or limits on vehicle weight and size. As the federal government continues to develop and propose regulations relating to fuel quality, engine efficiency and greenhouse gasses emissions, we may experience an increase in costs related to truck purchases and maintenance, impairment of equipment productivity, a decrease in the residual value of vehicles, unpredictable fluctuations in fuel prices and an increase in operating expenses. Additionally, we rely on third parties to provide trucking services, including hauling proppant to our customer work sites, and these third parties may fail to comply with various transportation regulations, resulting in our inability to use such third-party providers. Increased truck traffic may contribute to deteriorating road conditions in some areas where our operations are performed. Our operations, including routing and weight restrictions, could be affected by road construction, road repairs, detours and state and local regulations and ordinances restricting access to certain roads. Proposals to increase federal, state, provincial or local taxes, including taxes on motor fuels, are also made from time to time, and any such increase would increase our operating costs. Also, state and local regulation of permitted routes and times on specific roadways could adversely affect our operations. We cannot predict whether, or in what form, any legislative or regulatory changes or municipal ordinances applicable to our logistics operations will be enacted and to what extent any such legislation or regulations could increase our costs or otherwise adversely affect our business or operations. 
+We face a variety of risks related to our diversification and entry into a new line of business. 
+The proposed diversification of our business as a scaled distributed power and energy storage solutions provider carries a number of risks. We will become subject to laws and regulations previously inapplicable to our existing business and this could lead to additional litigation and regulatory risk. Our expansion into the distributed power solutions business will create the need for additional capital and other resources, the cost and availability of which may depend on market conditions, regulatory landscape, financial and operating results, interest rates, inflationary considerations, compliance with covenants under our credit facility, and other considerations. Furthermore, while our management team has a track record of successfully executing on the growth of our existing business, the team has not directly engaged in the distributed power solutions business before and this lack of experience could have adverse impacts and complications such as on cost and timing to execute on the new business and the overall success of the program. If we are unable to successfully execute on this new line of business, our revenue and profitability may not grow as expected, our competitiveness may be materially and adversely affected, and our reputation and business may be harmed. 
+As we continue our diversification into a new line of business, the market price for our common stock will become subject to factors different from those that have historically and currently impacted our common stock. 
+Our financial performance and results of operations with respect to the proposed new line of business will be subject to certain factors that may differ or be inapplicable to our existing business. Accordingly, the market price and performance of our common stock may be impacted differently in connection with our expansion into the distributed power systems line of business. 
+23 
+Our current and future indebtedness could adversely affect our financial condition. 
+Effective January 23, 2023, using proceeds from borrowings on our ABL Facility (as defined herein), we repaid all amounts outstanding under the Term Loan Facility (as defined herein). As of February 3, 2025, the Company had $261.0 million outstanding under our ABL Facility, in addition to letters of credit in the amount of $14.0 million, with $93.0 million of remaining availability. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.” 
+Moreover, subject to the limits contained in our ABL Facility, we may incur substantial additional debt from time to time. Any borrowings we may incur in the future would have several important consequences for our future operations, including that: 
+• covenants contained in the documents governing such indebtedness may require us to meet or maintain certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our industry, such as being able to take advantage of acquisition opportunities when they arise; 
+• our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes may be limited; 
+• our ability to use operating cash flow in other areas of our business may be limited because we must dedicate a substantial portion of these funds to make principal and interest payments on our indebtedness; 
+• we may be more vulnerable to interest rate increases to the extent that we incur variable rate indebtedness; 
+• we may be competitively disadvantaged to our competitors that are less leveraged or have greater access to capital resources; and 
+• we may be more vulnerable to adverse economic and industry conditions. 
+If we incur indebtedness in the future, we may have significant principal payments due at specified future dates under the documents governing such indebtedness. Our ability to meet such principal obligations will be dependent upon future performance, which in turn will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. Our business may not continue to generate sufficient cash flow from operations to repay any incurred indebtedness. If we are unable to generate sufficient cash flow from operations, we may be required to sell assets, to refinance all or a portion of such indebtedness or to obtain additional financing. 
+Unsatisfactory safety performance may negatively affect our customer relationships and, to the extent we fail to retain existing customers or attract new customers, adversely impact our revenues. 
+Our ability to retain existing customers and attract new business is dependent on many factors, including our ability to demonstrate that we can reliably and safely operate our business in a manner that is consistent with applicable laws, rules and permits, which legal requirements are subject to change. Existing and potential customers consider the safety record of their third-party service providers to be of high importance in their decision to engage such providers. If one or more accidents were to occur at one of our operating sites, the affected customer may seek to terminate or cancel its use of our equipment or services and may be less likely to continue to use our services, which could cause us to lose substantial revenues. Furthermore, our ability to attract new customers may be impaired if they elect not to engage us because they view our safety record as unacceptable. In addition, it is possible that we will experience multiple or particularly severe accidents in the future, causing our safety record to deteriorate. This may be more likely as we continue to grow, if we experience high employee turnover or labor shortage, or hire inexperienced personnel to bolster our staffing needs. 
+If we are unable to fully protect our intellectual property rights, we may suffer a loss in our competitive advantage or market share. 
+We do not have patents or patent applications relating to many of our key processes and technology. If we are not able to maintain the confidentiality of our trade secrets, or if our competitors are able to replicate our technology or services, our competitive advantage would be diminished. We also cannot ensure that any patents we may obtain in the future would provide us with any significant commercial benefit or would allow us to prevent our competitors from employing comparable technologies or processes. 
+We may be adversely affected by disputes regarding intellectual property rights of third parties. 
+Third parties from time to time may initiate litigation against us by asserting that the conduct of our business infringes, misappropriates or otherwise violates intellectual property rights. We may not prevail in any such legal proceedings related to such claims, and our products and services may be found to infringe, impair, misappropriate, dilute or otherwise violate the intellectual property rights of others. If we are sued for infringement and lose, we could be required to pay substantial damages and/or be enjoined from using or selling the infringing products or technology. Any legal proceeding concerning intellectual 
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+property could be protracted and costly regardless of the merits of any claim and is inherently unpredictable and could have a material adverse effect on our financial condition, regardless of its outcome. 
+If we were to discover that our technologies or products infringe valid intellectual property rights of third parties, we may need to obtain licenses from these parties or substantially re-engineer our products in order to avoid infringement. We may not be able to obtain the necessary licenses on acceptable terms, or at all, or be able to re-engineer our products successfully. If our inability to obtain required licenses for our technologies or products prevents us from selling our products, that could adversely impact our financial condition and results of operations. 
+Additionally, we currently license certain third-party intellectual property in connection with our business, and the loss of any such license could adversely impact our financial condition and results of operations. 
+Seasonal weather conditions, natural disasters, public health crises, and other catastrophic events outside of our control could severely disrupt normal operations and harm our business. 
+Our operations are located in different regions of the United States and Canada. Some of these areas, including the DJ Basin, Powder River Basin, Williston Basin and our Canadian operations, are adversely affected by seasonal weather conditions, primarily in the winter and spring. Weather-related hazards exist in almost all the areas where we operate. During periods of heavy snow, ice or rain, we may be unable to move our equipment between locations or obtain adequate supplies of raw material or fuel, thereby reducing our ability to provide services and generate revenues. The exploration activities of our customers may also be affected during such periods of adverse weather conditions. Additionally, extended drought conditions in our operating regions could impact our ability or our customers’ ability to source sufficient water or increase the cost for such water. As a result, a natural disaster or inclement weather conditions could severely disrupt the normal operation of our business and adversely impact our financial condition and results of operations. Furthermore, if the area in which we operate or the market demand for oil and natural gas is affected by a public health crisis, such as the COVID-19 pandemic, or other similar catastrophic event outside of our control, our business and results of operations could be adversely impacted. 
+The sand mining operations are subject to a number of risks relating to the proppant industry. 
+We operate two sand mines in the Permian Basin. Sand mining operations are subject to risks normally encountered in the proppant industry. These risks include, among others: unanticipated ground, grade or water conditions; inability to acquire or maintain, or public or nongovernmental organization opposition to, necessary permits for mining, access or water rights; our ability to timely obtain necessary authorizations, approvals and permits from regulatory agencies (including environmental agencies, such as the FWS, where our operations in West Texas may be slowed, limited or halted due to conservation efforts targeted at the habitat of the dunes sagebrush lizard); pit wall or pond failures, and sluffing events; costs associated with environmental compliance or as a result of unauthorized releases into the environment; restrictions imposed on our operations related to the protection of natural resources, including plant and animal species; and reduction in the amount of water available for processing. Any of these risks could result in delays, limitations or cancellations in mining or processing activities, losses or possible legal liability. 
+Silica-related legislation, health issues and litigation could have a material adverse effect on our business, reputation or results of operations. 
+We are subject to laws and regulations relating to human exposure to crystalline silica. Historically, our environmental compliance costs with respect to existing crystalline silica requirements have not had a material adverse effect on our results of operations; however, federal regulatory authorities and analogous state agencies may continue to propose changes in their regulations regarding workplace exposure to crystalline silica, such as permissible exposure limits, required controls and personal protective equipment. We may not be able to comply with any new laws and regulations that are adopted, and any new laws and regulations could have a material adverse effect on our operating results by requiring us to modify or cease our operations. 
+In addition, the inhalation of respirable crystalline silica is associated with the lung disease silicosis. There is evidence of an association between crystalline silica exposure or silicosis and lung cancer and a possible association with other diseases, including immune system disorders such as scleroderma. The actual or perceived health risks of handling hydraulic fracture sand could materially and adversely affect hydraulic fracturing service providers, including us, through reduced use of hydraulic fracture sand, the threat of product liability or employee lawsuits, increased scrutiny by federal, state and local regulatory authorities of us and our customers or reduced financing sources available to the industry. Furthermore, we may incur additional costs with respect to purchasing specialized equipment designed to reduce exposure to crystalline silica in connection with our operations or invest capital in new equipment. 
+We are subject to the Federal Mine Safety and Health Act of 1977, which imposes stringent health and safety standards on certain aspects of our operations. 
+Our operations are subject to the Federal Mine Safety and Health Act of 1977, as amended by the Mine Improvement and New Emergency Response Act of 2006, which imposes stringent health and safety standards on numerous aspects of mineral 
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+extraction and processing operations, including the training of personnel, operating procedures, operating equipment, and other matters. Our failure to comply with such standards, or changes in such standards or the re-interpretation or more stringent enforcement thereof, could have a material adverse effect on our business and financial condition or otherwise impose significant restrictions on its ability to conduct mineral extraction and processing operations. 
+Distributed power systems involve long sales cycles. 
+The sales cycle for distributed power systems, from initial contact with potential customers to the commencement of operations, may be lengthy. Customers generally consider a wide range of solutions before deciding to rent or to purchase power systems. Before a customer commits to rent or purchase power systems, they often require a significant technical review, assessment of competitive offerings and approval at a number of management levels within their organization. During the time customers are evaluating our power solutions offerings, we may incur substantial sales and marketing, engineering, and research and development expenses. 
+The occurrence of explosive incidents could disrupt our operations and could adversely affect our business, financial condition and results of operations. 
+The wireline service we provide to oil and natural gas E&P customers involves the storage and handling of explosive materials. Despite the use of specialized facilities to store explosive materials and intensive employee training programs, the handling of explosive materials could result in incidents that temporarily shut down or otherwise disrupt our or E&P customers’ operations or could cause restrictions, delays or cancellations in the delivery of services. It is possible that an explosion could result in death or significant injuries to employees and other persons. Material property damage to us, E&P customers and third parties could also occur. Any explosive incident could expose us to adverse publicity or liability for damages or cause production restrictions, delays or cancellations, any of which developments could have a material adverse effect on our ability to compete, business, financial condition and results of operations. 
+Geopolitical conditions, including political turmoil and volatility, regional conflicts, terrorism and war could result in market instability, which could adversely affect our business, financial condition and results of operations. 
+The global economy has been negatively impacted by geopolitical conflicts, such as the continuing military conflict between Russia and Ukraine and the conflict between Israel and Hamas, which has resulted in instability in the Middle East. Such conflicts have led and may continue to lead to significant market and other disruptions, including significant volatility in commodity prices and supply of energy resources, instability in financial markets, higher inflation, supply chain interruptions, political and social instability, changes in consumer or purchaser preferences as well as increase in cyberattacks and espionage. As a result of the invasion and ongoing military conflict in Ukraine, governments in the European Union, the United States, the United Kingdom, Switzerland and other countries have implemented and may implement additional sanctions, export controls or other measures against Russia, Belarus and other countries, regions, officials, individuals or industries in the respective territories. Such sanctions, and other measures, as well as the existing and potential further responses from Russia or other countries to such sanctions, supply chain disruptions, tensions and military actions, could adversely affect the global economy and financial markets and could adversely affect our business, financial condition and results of operations, and could also aggravate the other risk factors that we identify herein. 
+The choice of forum provisions in our charter and bylaws could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us. 
+Our Amended and Restated Certificate of Incorporation (as amended, the “Charter”) provides that unless the Company consents in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on behalf of the Company, (ii) any action asserting a claim of breach of a fiduciary duty owed by any director, officer, employee or agent of the Company to the Company or the Company’s stockholders, (iii) any action asserting a claim against the Company or any director or officer or other employee of the Company arising pursuant to any provision of the General Corporation Law of the State of Delaware, the Charter or the Company’s bylaws, or (iv) any action asserting a claim against the Company or any director or officer or other employee of the Company governed by the internal affairs doctrine, in each such case subject to Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Our Second Amended and Restated Bylaws (the “Bylaws”) further provide that unless the Company consents in writing to the selection of an alternative forum, the federal district courts of the United States of America will be the sole and exclusive forum for the resolution of any complaint asserting a cause of action arising under the Securities Act. Under the Securities Act, federal and state courts have concurrent jurisdiction over all suits brought to enforce any duty or liability created by the Securities Act, and stockholders cannot waive compliance with the federal securities laws and the rules and regulations thereunder. Accordingly, there is uncertainty as to whether a court would enforce such a forum selection provision as written in connection with claims arising under the Securities Act. Any person or entity purchasing or otherwise acquiring any interest in shares of common stock of the Company will be deemed to have notice of and have consented to the provisions of our Charter and Bylaws related to choice of forum. The choice of forum provisions in our Charter and Bylaws may limit our stockholders’ ability to obtain a 
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+favorable judicial forum for disputes with us. Additionally, the enforceability of choice of forum provisions in other companies’ governing documents has been challenged in legal proceedings, and it is possible that, in connection with any applicable action brought against us, a court could find the choice of forum provisions contained in our Charter and Bylaws to be inapplicable or unenforceable in such action. If so, we may incur additional costs associated with resolving such action in other jurisdictions, which could harm our business, results of operations, and financial condition. 
+There can be no assurance we will repurchase shares of our Class A Common Stock in any particular amounts. 
+The stock markets in general have experienced substantial price and trading fluctuations, which have resulted in volatility in the market prices of securities that often are unrelated or disproportionate to changes in operating performance. These broad market fluctuations may adversely affect the trading price of our Class A Common Stock. Price volatility over a given period may also cause the average price at which we repurchase our own Class A Common Stock to exceed the stock’s price at a given point in time. In addition, significant changes in the trading price of our Class A Common Stock and our ability to access capital on terms favorable to us could impact our ability to repurchase shares of our Class A Common Stock. The timing and amount of any repurchases will be determined by the Company’s management based on its evaluation of market conditions, capital allocation alternatives and other factors beyond our control. Our share repurchase program may be modified, suspended, extended or terminated by the Company at any time and without notice. 
+27 
+Item 1B. Unresolved Staff Comments 
+None. 
+Item 1C. Cybersecurity 
+Risk Management and Strategy 
+We recognize the critical importance of developing, implementing, and maintaining robust cybersecurity measures to safeguard our information systems and protect the confidentiality, integrity, and availability of our information systems and the data residing therein. 
+We have integrated cybersecurity risk management into our broader risk management framework to promote a company-wide practice of cybersecurity risk management. This integration ensures that cybersecurity considerations are part of our decision-making processes. Our cybersecurity risk management processes include technical security controls, policy enforcement mechanisms, monitoring systems, employee training, contractual arrangements, tools and related services from third-party providers, and management oversight to identify, assess, and manage material risks from cybersecurity threats. As part of our cybersecurity risk management process, we have conducted simulated cybersecurity incidents to ensure that we are prepared to respond to such an incident and to highlight any areas for potential improvement in our cyber incident preparedness . 
+Engagement of Third-Parties 
+Recognizing the complexity and evolving nature of cybersecurity threats, we may periodically engage a range of external experts, including cybersecurity assessors, consultants, and auditors to evaluate and test our information systems. These partnerships enable us to leverage specialized knowledge and insights, ensuring our cybersecurity strategies and processes generally follow industry-recognized standards and frameworks, and are compliant with applicable laws. 
+Oversight of Third-Party Risk 
+Because we are aware of the risks associated with third-party service providers, we implement processes to oversee and manage these risks. We conduct security assessments of critical third-party providers before engagement and maintain ongoing monitoring to ensure compliance with our cybersecurity standards. The monitoring includes regular assessments by our Chief Information Officer (“CIO”) and cybersecurity staff and advisors. This approach is designed to mitigate risks related to data breaches or other security incidents involving third-parties. 
+Risks from Cybersecurity Threats 
+We have experienced, and may in the future experience, directly or indirectly through our third-party service providers, cybersecurity incidents. While prior cybersecurity incidents have not had a material impact on us, future incidents could have a material impact on our business strategy, results of operations, and financial condition. For more information about the cybersecurity risks we face, see “We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss” in “Risk Factors” in Part I, Item 1A of this Annual Report on Form 10-K. 
+Cybersecurity Governance 
+Board of Directors Oversight 
+Our Board of Directors (the “Board”) has designated the Audit Committee to oversee risk management associated with cybersecurity threats. The Audit Committee is comprised of board members with diverse expertise including risk management, technology, and finance, which we believe enables them to oversee cybersecurity risks. 
+Management’s Role 
+We have a cybersecurity risk management committee comprised of senior leadership, including our CIO . The committee evaluates and addresses cybersecurity risks in alignment with our business objectives and operational needs. The Company’s cybersecurity risk management committee is also responsible for informing the Audit Committee on cybersecurity risks. The committee provides briefings to the Audit Committee on at least a quarterly basis, performs a comprehensive annual review of cybersecurity risks and threats, and assesses and adjusts the Company’s processes to prevent, detect, mitigate, and remediate any such risks and threats. 
+Primary responsibility for assessing, monitoring and managing our cybersecurity risks rests with our CIO. With over 30 years of experience in the field of information systems and cybersecurity, our CIO brings a wealth of expertise to this role. His background includes extensive experience as an enterprise CIO and his in-depth knowledge and experience are instrumental in developing and executing our cybersecurity strategies. Our CIO oversees our governance programs, tests our compliance with standards, remediates known risks, and leads our employee training program as such items relate to cybersecurity. Our CIO 
+28 
+manages our cybersecurity risks with the help of key personnel overseeing cybersecurity, information technology networks and infrastructure, operational technology, and critical software applications. 
+Our CIO and information technology team are continually informed about the latest developments in cybersecurity, including potential threats and innovative risk management techniques. The CIO and information technology team implements and oversees processes for the regular monitoring of our information systems. This includes the deployment of advanced security measures and regular system audits to identify potential vulnerabilities. In the event of a cybersecurity incident, the CIO and information technology team are equipped with a well-defined incident response plan, which includes escalation to the cybersecurity risk management committee and the Audit Committee, and relevant public disclosure, as appropriate. 
+Item 2. Properties 
+Information regarding our properties is contained in “Item 1. Business” and is incorporated by reference herein. 
+Item 3. Legal Proceedings 
+The information with respect to this Item 3. Legal Proceedings is set forth in Note 15—Commitments & Contingencies in Part II, Item 8 of this Annual Report. 
+Item 4. Mine Safety Disclosures 
+Our mining operations are subject to regulation by the federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this Annual Report. 
+29 
+PART II 
+Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+Market Information 
+On January 17, 2018, we consummated an initial public offering of our Class A Common Stock at a price of $17.00 per share. Our Class A Common Stock is traded on the NYSE under the symbol “LBRT.” Prior to that time, there was no public market for our Class A Common Stock. There is no public market for our Class B Common Stock. 
+Holders of our Common Stock 
+As of February 3, 2025, there were 14 stockholders of record of our Class A Common Stock and no stockholders of record of our Class B Common Stock. The number of record holders is based upon the actual number of holders registered on the books of the Company at such date and does not include holders of shares in “street names” or persons, partnerships, associations, corporations or other entities identified in security position listings maintained by depositories. 
+Dividend Policy 
+The Company has paid consecutive quarterly cash dividends since December 2022. Dividends are usually declared in January, April, July, and October, paid on the 20th of March, June, September, and December to stockholders of record as of the 6th of each respective payment month. If the record or payment date falls on a weekend or holiday, it is moved to the preceding or following business day. 
+The declaration of dividends is subject to approval by the Board and to the Board’s continuing determination that such declaration of dividends is in the best interests of the Company and its stockholders. Future dividends may be adjusted at the Board’s discretion based on market conditions and capital availability. We are not required to pay dividends, and our stockholders will not be guaranteed, or have contractual or other rights to receive, dividends. 
+See Note 10—Equity to the consolidated financial statements included in Part II, Item 8 of this Annual Report for further details. 
+Recent Sales of Unregistered Equity Securities 
+We had no sales of unregistered equity securities during the period covered by this Annual Report that were not previously reported in a Current Report on Form 8-K (or on Form 10-Q in lieu of Form 8-K). 
+Purchase of Equity Securities by the Issuer and Affiliated Purchasers 
+On July 25, 2022, the Board authorized and the Company announced a share repurchase program that allowed the Company to repurchase up to $250.0 million of the Company’s Class A Common Stock beginning immediately and continuing through July 31, 2024. Additionally, on January 24, 2023, the Board authorized and the Company announced an increase of the cumulative repurchase authorization to $500.0 million. Furthermore, on January 23, 2024, the Board authorized and the Company announced an increase of the cumulative repurchase authorization to $750.0 million and extended the authorization through July 31, 2026 (collectively “the Share Repurchase Plan”). Shares may be repurchased from time to time for cash in open market transactions, through block trades, in privately negotiated transactions, through derivative transactions, or by other means in accordance with applicable federal securities laws. The timing and the amount of repurchases will be determined by the Company at its discretion based on an evaluation of market conditions, capital allocation alternatives and other factors. The share repurchase program does not require us to purchase any dollar amount or number of shares of our Class A Common Stock and may be modified, suspended, extended or terminated at any time without prior notice. The Company expects to fund any repurchases by using cash on hand, borrowings under the ABL Facility, and expected free cash flow to be generated through the duration of the share repurchase program. 
+As of December 31, 2024, $294.2 million remained authorized for future repurchases of Class A Common Stock under the share repurchase program. 
+30 
+The following sets forth information with respect to our repurchases of shares of Class A Common Stock during the three months ended December 31, 2024: 
+Period Total number of shares purchased Average price paid per share (2) Total number of shares purchased as part of publicly announced plans or programs (1) Approximate dollar value of shares that may yet be purchased under the plans or programs (1) 
+October 1, 2024 - October 31, 2024 539,005 17.60 539,005 313,005,770 
+November 1, 2024 - November 30, 2024 700,687 17.92 700,687 300,451,128 
+December 1, 2024 - December 31, 2024 341,803 18.31 341,803 294,191,766 
+Total 1,581,495 17.90 1,581,495 294,191,766 
+(1) All share repurchases are executed under the Share Repurchase Plan, as defined above. The shares may be repurchased from time to time in open market transactions, through block trades, in privately negotiated transactions, through derivative transactions, or by other means in accordance with applicable state and federal securities laws. 
+(2) The average price paid per share of $17.90 was calculated including commissions. 
+31 
+Stock Performance Graph 
+The following graph and table compares the cumulative total return on our Class A Common Stock with the cumulative total return on the Standard & Poor’s 500 ® Index and the Philadelphia Oil Service Index, since December 31, 2019 and each annual period thereafter through December 31, 2024. The graph assumes that $100 was invested in our Class A Common Stock in each index on December 31, 2019 and that any dividends were reinvested on the last day of the month in which they were paid. The cumulative total return set forth is not necessarily indicative of future performance. 
+The following graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that we specifically incorporate it by reference into such filing. 
+For the Years Ended December 31 
+2019 2020 2021 2022 2023 2024 
+Liberty Energy Inc. $ 100.00 $ 94.44 $ 88.85 $ 147.11 $ 169.06 $ 188.06 
+Standard & Poor’s 500 ® Index 100.00 118.40 152.39 124.79 157.59 197.02 
+Philadelphia Oil Service Index 100.00 57.92 69.93 112.94 115.11 101.68 
+32 
+Item 6. [Reserved] 
+33 
+Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our audited consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a variety of risks and uncertainties, including those described in this Annual Report under “Cautionary Note Regarding Forward-Looking Statements” and “Item 1A. Risk Factors.” Except as required by law, we assume no obligation to update any of these forward-looking statements. This section of this Annual Report generally discusses 2024 and 2023 items and year-to-year comparisons between 2024 and 2023. For discussion of year ended December 31, 2022, as well as the year ended 2023 compared to the year ended December 31, 2022, refer to Part II, Item 7— Management’s Discussion and Analysis of Financial Condition and Results of Operations of our 2023 Annual Report. 
+Overview 
+The Company, together with its subsidiaries, is a leading integrated energy services and technology company focused on providing innovative hydraulic fracturing services and related technologies to onshore oil and natural gas E&P companies. We offer customers hydraulic fracturing services, together with complementary services including wireline services, proppant delivery solutions, field gas processing and treating, CNG delivery, data analytics, related goods (including our sand mine operations), and technologies to facilitate lower emission completions, thereby helping our customers reduce their emissions profile. We have grown from one active hydraulic fracturing fleet in December 2011 to approximately 40 active fleets as of December 31, 2024. We provide our services primarily in the Permian Basin, the Williston Basin, the Haynesville Shale, the Eagle Ford Shale, the Denver-Julesburg Basin (the “DJ Basin”), the Western Canadian Sedimentary Basin, the Powder River Basin, and the Appalachian Basin (Marcellus Shale and Utica Shale). Our operations also extend to a few smaller shale basins, including the Anadarko Basin, the Uinta Basin, the San Juan Basin, and the Beetaloo Basin in Northern Territory, Australia, as well as to two sand mines in the Permian Basin. 
+In early 2023, the Company launched Liberty Power Innovations LLC (“LPI”), an integrated alternative fuel and power solutions provider for remote applications. LPI provides CNG supply, field gas processing and treating, and well site fueling and logistics. LPI was formed with the initial focus on supporting the Company’s transition towards our next generation digiFleets℠ and dual fuel fleets, as CNG fueling services can be limited in the market, yet critical to maintaining highly efficient well site operations. Through 2024, LPI was primarily focused on supporting an industry transition to natural gas fueled technologies, serving as a key enabler of the next step of cost and emissions reductions in the oilfield. In January 2025, we announced LPI’s expansion into the distributed power business, where we expect to leverage our experience in providing electric power for our digiFrac pumps into other areas inside and outside of the oilfield. 
+We believe technical innovation and strong relationships with our customer and supplier bases distinguish us from our competitors and are the foundations of our business. We expect that E&P companies will continue to focus on technological innovation as completion complexity and fracture intensity of horizontal wells increases, particularly as customers are increasingly focused on reducing emissions from their completions operations. We remain proactive in developing innovative solutions to industry challenges, including developing: (i) our databases of U.S. unconventional wells to which we apply our proprietary multi-variable statistical analysis technologies to provide differential insight into fracture design optimization; (ii) our Liberty Quiet Fleet® design which significantly reduces noise levels compared to conventional hydraulic fracturing fleets; (iii) hydraulic fracturing fluid systems tailored to the specific reservoir properties in the basins in which we operate; (iv) our dual fuel dynamic gas blending (“DGB”) fleets that allow our engines to run diesel or a combination of diesel and natural gas, to optimize fuel use, reduce emissions and lower costs; (v) our digiFleets℠, comprising of digiFrac℠ and digiPrime℠ pumps and other complementary equipment, including power generation units (together “digiTechnologies℠”), our innovative, purpose-built electric and hybrid frac pumps that have approximately 25% lower CO 2e emission profile than the Tier IV DGB; (vi) our wet sand handling technology which eliminates the need to dry sand, enabling the deployment of mobile mines nearer to wellsites; and (vii) the launch of LPI to support the transition to our digiFleets as well as the transition to lower costs and emissions in the oilfield. In addition, our integrated supply chain includes proppant, chemicals, equipment, natural gas fueling services, logistics and integrated software which we believe promotes wellsite efficiency and leads to more pumping hours and higher productivity throughout the year to better service our customers. In order to achieve our technological objectives, we carefully manage our liquidity and debt position to promote operational flexibility and invest in the business throughout the full commodity cycle in the regions we operate. 
+34 
+Recent Trends and Outlook 
+Moderate declines in frac activity, that started in 2023, continued throughout 2024. However, the market appears to have reached an inflection point in early 2025 as completions activity emerges from 2024 lows. In 2025, E&P operators, especially those with an oil exploration focus, are working to maintain production levels from 2024. Improving natural gas fundamentals are encouraging as well. For the full year, industry-wide lateral footage completed is expected to be approximately flat with 2024. 
+The slowing pace of activity in late 2024 resulted in near term price pressure to start 2025, most notably impacting conventional fleets. The fundamental outlook for next generation, higher quality fleets remains strong, as operators continue to demand technologies that provide significant emissions reductions, fuel savings, and operational efficiency advantages. The growing complexities of E&P demands and the continued drive for efficiency gains promote continued investment in technology and partnering with high quality service companies. 
+Global oil markets reflect ongoing uncertainties in geopolitics, Chinese economic growth, OPEC+ production plans, and a change in the domestic political climate, but the resulting commodity price fluctuation has not led to a meaningful change in E&P activity plans. Natural gas demand is supported by LNG export capacity expansion and a large projected multi-year increase in North American power consumption. 
+During the year 2024, the posted WTI price traded at an average of $76.63 per barrel (“Bbl”), as compared to the 2023 average of $77.58 per Bbl, and the 2022 average of $94.90 per Bbl. In addition, the average domestic onshore rig count for the United States and Canada was 765 rigs reported in the fourth quarter of 2024, down from the average in the fourth quarter of 2023 of 781, according to a report from Baker Hughes. 
+Acquisitions 
+On April 6, 2023, LPI accelerated its expansion by acquiring Siren, a Permian focused integrated natural gas compression and CNG delivery business with 16 MMcf per day of natural gas compression capacity at two expandable Permian sites and transportation, logistics, and pressure reduction services, for cash consideration of $75.7 million, after post-closing adjustments and net of cash received. LPI currently delivers fuel to customers in both the drilling and completions markets, and its logistics system is designed to deliver CNG, renewable natural gas, or hydrogen to remote locations. We believe that the added natural gas compression capability is a key enabler of the next step of cost and emissions reductions in the industry. 
+Increase in Drilling Efficiency and Service Intensity of Completions 
+Over the past decade, E&P companies have focused on exploiting the vast resource potential available across many of North America’s unconventional resource plays through the application of horizontal drilling and completion technologies, including the use of multi-stage hydraulic fracturing, in order to increase recovery of oil and natural gas. As E&P companies have improved drilling and completion techniques to maximize return and efficiency, we believe that well economics have improved, and unconventional oil and gas production is globally competitive. Liberty has been a significant partner with our customers in driving these continued improvements. 
+Improved drilling economics from horizontal drilling and greater rig efficiencies . According to Baker Hughes, as reported on January 24, 2025, horizontal rigs accounted for approximately 90% of all rigs drilling in the United States and Canada, up from 77% as of December 26, 2014. Over the past several years, North American E&P companies have benefited from improved drilling economics driven by technologies that reduce the number of days, and the cost, of drilling wells. North American drilling rigs have incorporated newer technologies, which allow them to drill rock more effectively and quickly, meaning each rig can drill more wells in a given period. These include improved drilling technologies and the incorporation of geosteering techniques which allow better placement of the wellbore. Drilling rigs have also incorporated new technology which allows fully assembled rigs to automatically “walk” from one location to the next without disassembling and reassembling the rig, greatly reducing the time it takes to move from one drilling location to the next. Today the majority of E&P drilling is on multi-well pad development, allowing efficient drilling of multiple horizontal wellbores from the same pad or location. The aggregate effect of these improved techniques and technologies have reduced the average days required to drill a well, which according to Lium Research, has dropped from 28 days in 2014 to 16 days in 2024. 
+Increased complexity and service intensity of horizontal well completions . In addition to improved rig efficiencies discussed above, E&P companies are also improving the subsurface techniques and technologies used to exploit unconventional resources. These improvements have targeted increasing the exposure of each wellbore to the reservoir by drilling longer horizontal lateral sections of the wellbore. To complete the well, hydraulic fracturing is applied in stages along the wellbore to break-up the resource so that oil and gas can be produced. As wellbores have increased in length, the number of frac stages and/or the number of perforation clusters (frac initiation points) has also increased. Further, E&P companies have improved production from each stage by applying increasing amounts of proppant in each stage, which better connects the well to the resource. The aggregate effect of increased number of stages and the increasing amount of proppant in each stage has greatly increased the total amount of proppant used in each well, according to Liberty’s FracTrends database, from six million pounds 
+35 
+per well in 2014 to roughly 22 million pounds per well in 2024. Further efficiency gains are being sought via the “simul-frac,” “trimul-frac,” and other techniques. When compared to typical zipper-frac operations, these methods allow operators to complete a pad of wells quicker, thereby shortening the time from spud to first production. 
+These industry trends continue to keep our customers as important suppliers to the global oil and natural gas markets, which directly benefit hydraulic fracturing companies like us that have the expertise and innovative technology to effectively service today’s more efficient oilfield drilling activity and the increasing complexity and intensity of well completions. Given the expected returns that E&P companies have reported for new well development activities due to improved rig efficiencies and increasing well completion complexity and intensity, we expect these industry trends to continue. 
+Recent Leadership Updates 
+On February 3, 2025, Christopher A. Wright, our Chief Executive Officer and Chairman of the Board, was confirmed to the position of Secretary of Energy of the United States and resigned from his positions as Chairman of the Board, Director, and Chief Executive Officer of the Company. Also, on February 3, 2025, in accordance with the Company’s succession plan, the Board appointed William Kimble as the non-executive Chairman of the Board and Ron Gusek as the Company’s Chief Executive Officer and Director. Lastly, on January 22, 2025, the Board approved an increase to the size of the Board from nine to 10 directors and appointed Arjun Murti to fill the newly created vacancy. 
+How We Generate Revenue 
+We currently generate revenue through the provision of hydraulic fracturing, wireline services and goods, including sand from our Permian Basin sand mines, proppant delivery and logistics, and natural gas compression and delivery. These services and goods are provided under a variety of contract structures, primarily master service agreements (“MSAs”) as supplemented by statements of work, pricing agreements and specific quotes. A portion of our statements of work, under MSAs, include provisions that establish pricing arrangements for a period of up to approximately one year in length. However, the majority of those agreements provide for pricing adjustments based on market conditions. The majority of our services are priced based on prevailing market conditions and changing input costs at the time the services are provided, giving consideration to the specific requirements of the customer. 
+Our hydraulic fracturing and wireline services are performed in sections, which we refer to as fracturing stages. The estimated number of fracturing stages to be completed for a particular horizontal well is determined by the customer’s well completion design. We primarily recognize revenue based on pump hours, fracturing stages, or days on location, although total revenue depends on the actual volumes and types of proppants, chemicals, and fluid utilized on each pad. The number of fracturing stages that we are able to complete in a period is directly related to the number and utilization of our deployed fleets and size of stages. 
+Costs of Conducting Our Business 
+The principal expenses involved in conducting our business are direct cost of personnel, services, and materials used in the provision of services, general and administrative expenses, and depreciation, depletion, and amortization. A large portion of the costs we incur in our business are variable based on the number of hydraulic fracturing jobs and the requirements of services provided to our customers. We manage the level of our fixed costs, except depreciation, depletion, and amortization, based on several factors, including industry conditions and expected demand for our services. 
+How We Evaluate Our Operations 
+We use a variety of qualitative, operational and financial metrics to assess our performance. First and foremost, of these is a qualitative assessment of customer satisfaction because ensuring we are a valuable partner to our customers is the key to achieving our quantitative business metrics. Among other measures, management considers each of the following: 
+• Revenue; 
+• Operating Income; 
+• Net Income; 
+• EBITDA; and 
+• Adjusted EBITDA; 
+Revenue 
+We analyze our revenue by comparing actual revenue to our internal projections for a given period and to prior periods to assess our performance. 
+36 
+Operating Income 
+We analyze our operating income, which we define as revenues less direct operating expenses, depreciation, depletion, and amortization and general and administrative expenses, to measure our financial performance. We believe operating income is a meaningful metric because it provides insight on profitability and true operating performance based on the historical cost basis of our assets. We also compare operating income to our internal projections for a given period and to prior periods. 
+Net Income 
+We analyze our net income, which we define as operating income adjusted for other income or expense, net, including interest expense, net, and income tax expense. We analyze net income by comparing actual net income to our internal projections for a given period and to prior periods to assess our performance. 
+EBITDA and Adjusted EBITDA 
+We view EBITDA and Adjusted EBITDA as important indicators of performance. We define EBITDA as net income before interest, income taxes, and depreciation, depletion, and amortization. We define Adjusted EBITDA as EBITDA adjusted to eliminate the effects of items such as non-cash stock-based compensation, new fleet or new basin start-up costs, fleet lay-down costs, costs of asset acquisitions, gain or loss on the disposal of assets, provision for credit losses, transaction, severance, and other costs, the gain or loss on remeasurement of liability under our tax receivable agreements, the gain or loss on investments, and other non-recurring expenses that management does not consider in assessing ongoing performance. See “Comparison of Non-GAAP Financial Measures” for more information and a reconciliation of EBITDA and Adjusted EBITDA to net income, the most comparable financial measures calculated and presented in accordance with GAAP. 
+Results of Operations 
+Year Ended December 31, 2024, Compared to Year Ended December 31, 2023 
+Years Ended December 31, 
+Description 2024 2023 Change 
+(in thousands) 
+Revenue $ 4,315,161 $ 4,747,928 $ (432,767) 
+Cost of services, excluding depreciation, depletion, and amortization shown separately 3,200,506 3,349,370 (148,864) 
+General and administrative 225,474 221,406 4,068 
+Transaction and other costs — 2,053 (2,053) 
+Depreciation, depletion, and amortization 505,050 421,514 83,536 
+Gain on disposal of assets, net (5,337) (6,994) 1,657 
+Operating income 389,468 760,579 (371,111) 
+Other (income) expense, net (13,803) 25,689 (39,492) 
+Net income before income taxes 403,271 734,890 (331,619) 
+Income tax expense 87,261 178,482 (91,221) 
+Net income 316,010 556,408 (240,398) 
+Less: Net income attributable to non-controlling interests — 91 (91) 
+Net income attributable to Liberty Energy Inc. stockholders $ 316,010 $ 556,317 $ (240,307) 
+Revenue 
+Our revenue decreased $432.8 million, or 9%, to $4.3 billion for the year ended December 31, 2024 compared to $4.7 billion for the year ended December 31, 2023. The decrease in revenue was primarily attributable to a decrease in service and materials pricing, partially offset by higher activity levels primarily from increased fleet efficiency. 
+Cost of Services 
+Cost of services (excluding depreciation, depletion, and amortization) decreased $148.9 million, or 4%, to $3.2 billion for the year ended December 31, 2024 compared to $3.3 billion for the year ended December 31, 2023. The decrease in expense was primarily related to decreases in materials costs and lower repairs and maintenance costs, partially offset by increased personnel costs related to higher activity levels discussed above, during the year ended December 31, 2024. 
+General and Administrative 
+General and administrative expenses increased $4.1 million, or 2%, to $225.5 million for the year ended December 31, 2024 compared to $221.4 million for the year ended December 31, 2023 primarily related to increased corporate costs to 
+37 
+support our additional service offerings, partially offset by a decrease in cash incentive and stock-based compensation expense due to lower operating results compared to the prior year period. 
+Transaction and Other Costs 
+Transaction and other costs decreased $2.1 million, or 100%, as the Company did not incur such costs for the year ended December 31, 2024 compared to $2.1 million for the year ended December 31, 2023. The costs incurred during the year ended December 31, 2023 primarily consisted of due diligence and integration costs for the Siren Acquisition. See Note 3—Acquisitions to the consolidated financial statements included in Part II, Item 8 of this Annual Report for further details. 
+Depreciation, Depletion, and Amortization 
+Depreciation, depletion, and amortization expense increased $83.5 million, or 20%, to $505.1 million for the year ended December 31, 2024 compared to $421.5 million for the year ended December 31, 2023. The increase in 2024 was due to additional equipment placed in service since the prior year period, including equipment related to the deployment of our digiTechnologies SM . 
+Gain on Disposal of Assets, net 
+The Company recorded a gain on disposal of assets, net of $5.3 million for the year ended December 31, 2024 compared to $7.0 million for the year ended December 31, 2023. The gain recognized in the year ended December 31, 2024 was primarily related to the disposal of used older technology field equipment that was no longer operational. The gain recognized in the year ended December 31, 2023 was a result of the Company selling used field equipment and light duty trucks in a strong used vehicle and equipment market. 
+Other (Income) Expense, net 
+Other (income) expense, net changed by $39.5 million to $13.8 million income for the year ended December 31, 2024 compared to $25.7 million expense during the year ended December 31, 2023. Other (income) expense, net is comprised of loss on remeasurement of liability under the TRAs of $3.2 million during the year ended December 31, 2024, compared to a gain of $1.8 million for the year ended December 31, 2023. It also includes an unrealized gain on investments, net of $49.2 million related to investments in equity securities measured at fair value during the year ended December 31, 2024, compared to $0 for the year ended December 31, 2023. Interest expense, net increased $3.2 million primarily as a result of the addition of finance lease liabilities, refer to “Liquidity and Capital Resources” below for further discussion of the Company’s finance leases. Additionally, interest income—related party decreased $1.5 million related to a note receivable agreement executed in December 2022, amended in August 2023, and fully collected in March 2024. 
+Income Tax Expense 
+The Company recognized income tax expense of $87.3 million for the year ended December 31, 2024, an effective rate of 21.6%, compared to $178.5 million, for the year ended December 31, 2023, an effective rate of 24.3%. The decrease in income tax expense was primarily attributable to the decrease in net income before income taxes and increased U.S. federal tax credits. 
+Comparison of Non-GAAP Financial Measures 
+We view EBITDA and Adjusted EBITDA as important indicators of performance. We define EBITDA as net income before interest, income taxes, and depreciation, depletion, and amortization. We define Adjusted EBITDA as EBITDA adjusted to eliminate the effects of items such as non-cash stock-based compensation, new fleet or new basin start-up costs, fleet lay-down costs, gain or loss on the disposal of assets, net, bad debt reserves, transaction and other costs, the gain or loss on remeasurement of liability under our tax receivable agreements, the unrealized gain or loss on investments, net, and other non-recurring expenses that management does not consider in assessing ongoing performance. 
+Our Board, management, investors, and lenders use EBITDA and Adjusted EBITDA to assess our financial performance because it allows them to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure (such as varying levels of interest expense), asset base (such as depreciation, depletion, and amortization) and other items that impact the comparability of financial results from period to period. We present EBITDA and Adjusted EBITDA because we believe they provide useful information regarding the factors and trends affecting our business in addition to measures calculated under GAAP. 
+38 
+Note Regarding Non-GAAP Financial Measures 
+EBITDA and Adjusted EBITDA are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures will provide useful information to investors in assessing our financial performance and results of operations. Net income is the GAAP financial measure most directly comparable to EBITDA and Adjusted EBITDA. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as an analytical tool due to exclusion of some but not all items that affect the most directly comparable GAAP financial measures. You should not consider EBITDA or Adjusted EBITDA in isolation or as substitutes for an analysis of our results as reported under GAAP. Because EBITDA and Adjusted EBITDA may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. 
+The following tables present a reconciliation of EBITDA and Adjusted EBITDA to our net income, which is the most directly comparable GAAP financial measure for the periods presented: 
+Year Ended December 31, 2024, Compared to Year Ended December 31, 2023: EBITDA and Adjusted EBITDA 
+Years Ended December 31, 
+Description 2024 2023 Change 
+(in thousands) 
+Net income $ 316,010 $ 556,408 $ (240,398) 
+Depreciation, depletion, and amortization 505,050 421,514 83,536 
+Interest expense, net 32,214 27,506 4,708 
+Income tax expense 87,261 178,482 (91,221) 
+EBITDA $ 940,535 $ 1,183,910 $ (243,375) 
+Stock-based compensation expense 32,412 33,026 (614) 
+Gain on disposal of assets, net (5,337) (6,994) 1,657 
+Unrealized gain on investments, net (49,227) — (49,227) 
+Loss (gain) on remeasurement of liability under tax receivable agreements 3,210 (1,817) 5,027 
+Provision for credit losses — 808 (808) 
+Transaction and other costs — 2,053 (2,053) 
+Fleet start-up and lay-down costs — 2,082 (2,082) 
+Adjusted EBITDA $ 921,593 $ 1,213,068 $ (291,475) 
+EBITDA was $940.5 million for the year ended December 31, 2024 compared to $1.2 billion for the year ended December 31, 2023. Adjusted EBITDA was $921.6 million for the year ended December 31, 2024 compared to $1.2 billion for the year ended December 31, 2023. The decreases in EBITDA and Adjusted EBITDA primarily resulted from lower pricing and partially offset by changes in activity levels in 2024 as described above under the captions Revenue , Cost of Services, and General and Administrative Expenses for the Year Ended December 31, 2024, Compared to Year Ended December 31, 2023 . 
+Liquidity and Capital Resources 
+Overview 
+Our primary sources of liquidity consist of cash flows from operations and borrowings under our ABL Facility (as defined below). We believe that we can fund operations and current organic growth plans with these sources. We monitor the availability and cost of capital resources such as equity, debt, and lease financings that could be leveraged for current or future financial obligations including those related to acquisitions, capital expenditures, working capital, and other liquidity requirements. We may incur additional indebtedness or issue equity in order to meet our capital expenditure activities and liquidity requirements, as well as to fund organic and other growth opportunities that we pursue, including via acquisition. Our primary uses of capital have been capital expenditures to support organic growth and funding ongoing operations, including maintenance and fleet upgrades, as well as the repurchases of, and dividends on, shares of our Class A Common Stock. 
+Cash and cash equivalent s decreased by $16.8 million to $20.0 million as of December 31, 2024 compared to $36.8 million as of December 31, 2023, while working capital excluding cash and current liabilities under debt and lease arrangements decreased $88.2 million. 
+39 
+On September 19, 2017, the Company entered into two credit agreements, (i) a revolving line of credit up to $250.0 million, subsequently increased to $525.0 million, see below, (the “ABL Facility”) and (ii) a $175.0 million term loan (the “Term Loan Facility”, and together with the ABL Facility the “Credit Facilities”). 
+As of December 31, 2024, the Company had $525.0 million committed under the ABL Facility, subject to certain borrowing base limitations based on a percentage of eligible accounts receivable and inventory available to finance working capital needs. As of December 31, 2024, the borrowing base was calculated to be $319.8 million, and the Company had $190.5 million outstanding, in addition to letters of credit totaling $14.0 million, with $115.3 million of remaining availability. 
+On January 23, 2023, the Company entered into an Eighth Amendment to the ABL Facility (the “Eighth ABL Amendment”). The Eighth ABL Amendment amends certain terms, provisions and covenants of the ABL Facility, including, among other things: (i) increasing the maximum revolver amount from $425.0 million to $525.0 million (the “Upsized Revolver”); (ii) increasing the amount of the accordion feature from $75.0 million to $100.0 million; (iii) extending the maturity date from October 22, 2026 to January 23, 2028; (iv) modifying the dollar amounts of various credit facility triggers and tests proportionally to the Upsized Revolver; (v) permitting repayment under the Term Loan Facility prior to February 10, 2023; and (vi) increasing certain indebtedness, intercompany advance, and investment baskets. The Eighth ABL Amendment also includes an agreement from Wells Fargo Bank, National Association, as administrative agent, to release its second priority liens and security interests on all collateral that served as first priority collateral under the Term Loan Facility. This release was completed during the three months ended June 30, 2023. 
+Additionally, on January 23, 2023, the Company borrowed $106.7 million on the ABL Facility and used the proceeds to pay off and terminate the Term Loan Facility. The amount paid included the balance of the Term Loan Facility upon payoff of $104.7 million, $0.9 million of accrued interest, and a $1.1 million prepayment premium. Additionally, there were $0.2 million in administrative agent and lender legal fees included in the pay off. 
+The ABL Facility contains covenants that restrict our ability to take certain actions. At December 31, 2024, we were in compliance with all debt covenants. 
+See Note 8 —Debt to the consolidated financial statements included in Part II, Item 8 of this Annual Report for further details. 
+We have no material off balance sheet arrangements as of December 31, 2024, except for purchase commitments under supply agreements as disclosed below under Note 15—Commitments & Contingencies in Part II, Item 8 of this Annual Report. As such, we are not materially exposed to any other financing, liquidity, market, or credit risk that could arise if we had engaged in such financing arrangements. 
+Share Repurchase Program 
+Under our share repurchase program, the Company is authorized to repurchase up to $750.0 million of outstanding Class A Common Stock through and including July 31, 2026. Shares may be repurchased from time to time for cash in open market transactions, through block trades, in privately negotiated transactions, through derivative transactions, or by other means in accordance with applicable federal securities laws. The timing and the amount of repurchases will be determined by the Company at its discretion based on an evaluation of market conditions, capital allocation alternatives and other factors. The share repurchase program does not require us to purchase any dollar amount or number of shares of our Class A Common Stock and may be modified, suspended, extended or terminated at any time without prior notice. The Company expects to fund any repurchases by using cash on hand, borrowings under the ABL Facility, and expected free cash flow to be generated through the duration of the share repurchase program. During the year ended December 31, 2024, the Company repurchased and retired shares of Class A Common Stock for $127.4 million, under the share repurchase program. 
+40 
+Cash Flows 
+The following table summarizes our cash flows for the periods indicated: 
+Years Ended December 31, 
+Description 2024 2023 Change 
+(in thousands) 
+Net cash provided by operating activities 
+$ 829,374 $ 1,014,583 $ (185,209) 
+Net cash used in investing activities 
+(643,113) (672,328) 29,215 
+Net cash used in financing activities 
+(202,705) (349,315) 146,610 
+Analysis of Cash Flow Changes Between the Years Ended December 31, 2024 and December 31, 2023 
+Operating Activities . Net cash provided by operating activities was $829.4 million for the year ended December 31, 2024, compared to $1.0 billion for the year ended December 31, 2023. The $185.2 million decrease in cash from operating activities is primarily attributable to a $432.8 million decrease in revenues, offset by a $145.3 million decrease in cash operating expenses, interest expense, net, and income tax expense, and a $9.4 million decrease in cash from changes in working capital for the year ended December 31, 2024, compared to a $111.7 million decrease in cash from changes in working capital for the year ended December 31, 2023. 
+Investing Activities . Net cash used in investing activities was $643.1 million for the year ended December 31, 2024, compared to $672.3 million for the year ended December 31, 2023. Cash used in investing activities was lower during the year ended December 31, 2024, compared to the year ended December 31, 2023 primarily due to the Siren Acquisition and higher equity investments in the prior year period, offset by higher capital spending in the current year period, and lower proceeds from asset sales. The Company purchased Siren Energy for $75.7 million in cash, net of cash received, during the year ended December 31, 2023. Refer to Note 3—Acquisitions to the consolidated financial statements in Part II, Item 8 of this Annual Report for additional information related to the Siren Acquisition. Investments in equipment, including the new digiTechnologies SM suite and capitalized maintenance of existing equipment increased $47.7 million, from $603.3 million for the year ended December 31, 2023 to $651.0 million for the year ended December 31, 2024. Proceeds from asset sales decreased $2.9 million, from $26.9 million to $24.0 million as the Company benefited from strong used vehicle and equipment markets in the prior period. Finally, during the year ended December 31, 2024, the Company invested $16.1 million for equity investments in Tamboran Resources Corporation, Empire Energy Group Ltd., and Falcon Oil & Gas Ltd, compared to $20.3 million for equity investments in Tamboran Resources Corporation and Oklo Inc. during the year ended December 31, 2023. 
+Financing Activities . Net cash used in financing activities was $202.7 million for the year ended December 31, 2024, compared to $349.3 million for the year ended December 31, 2023. The $146.6 million decrease in cash used in financing activities was primarily due to net borrowings of $50.5 million during the current year period compared to $79.7 million in net repayment of borrowings during the prior year as well as a $73.9 million decrease in share repurchases for the year ended December 31, 2024, compared to the year ended December 31, 2023. These decreases in cash used in financing activities were offset by a $32.9 million increase in cash paid for finance leases, a $10.5 million increase in cash tax withholding on restricted stock unit vestings, and a $10.6 million increase in dividends paid. 
+41 
+Cash Requirements 
+Our material cash commitments consist primarily of obligations under long-term debt on the ABL Facility, TRAs, finance and operating leases for property and equipment, cash used to pay for repurchases of, and dividends on, shares of our Class A Common Stock, and purchase obligations as part of normal operations. Certain amounts included in our contractual obligations as of December 31, 2024 are based on our estimates and assumptions about these obligations, including pricing, volumes, and duration. We have no material off balance sheet arrangements as of December 31, 2024, except for purchase commitments under supply agreements disclosed below. 
+See Note 8 —Debt to the consolidated financial statements included in Part II, Item 8 of this Annual Report for information regarding scheduled maturities of our long-term debt. See Note 6 —Leases to the consolidated financial statements included in Part II, Item 8 of this Annual Report for information regarding scheduled maturities of finance and operating leases. 
+During the year ended December 31, 2024, the Company expanded its equipment lease facilities resulting in the addition of $149.0 million in new finance lease obligations. The term on these new leases range from three to five years. As of December 31, 2024, the Company had finance lease obligations of $87.5 million payable within the next twelve months and $222.5 million payable thereafter. Included in those liabilities, the Company had expected cash payments for estimated interest on our finance lease obligations of $17.1 million payable within the next twelve months and $22.4 million payable thereafter. 
+On January 23, 2023, the Company borrowed $106.7 million on the ABL Facility and used the proceeds to pay off and terminate the Term Loan Facility. The balance of the Term Loan Facility at pay off was $104.7 million and included $0.9 million of accrued interest, and a $1.1 million prepayment premium. As such, the only outstanding debt facility as of December 31, 2024 and 2023 was the ABL Facility. 
+As of December 31, 2024, the Company has purchase obligations of $26.3 million payable within the next twelve months. See Note 15 —Commitments & Contingencies to the consolidated financial statements in Part II, Item 8 of this Annual Report for information regarding scheduled contractual obligations. 
+As of December 31, 2024, the Company expects to make a $40.8 million payment under the TRAs within the next twelve months. Future amounts payable under the TRAs are dependent upon future events. See No te 12 —Income Taxes to the consolidated financial statements included in Part II, Item 8 of this Annual Report for information regarding the TRAs. 
+There have been no other material changes to cash requirements during the year ended December 31, 2024. 
+Other Factors Affecting Liquidity 
+Customer receivables: In line with industry practice, we typically bill our customers for services provided in arrears dependent upon contractual terms. In weak economic environments, we may experience delays in collection from our customers. In the past, we have experienced delays in customer payments and periodically agreed to extended payment terms, however, we have not experienced any material non-payment events. 
+Tax Receivable Agreements 
+In connection with the IPO, on January 17, 2018, the Company entered into two TRAs with the TRA Holders. The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that the Company actually recognizes (or is deemed to recognize in certain circumstances) in periods after the IPO as a result, as applicable to each of the TRA Holders, of (i) certain increases in tax basis that occur as a result of the Company’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holders’ Liberty LLC Units in connection with the IPO or pursuant to the exercise of the right of each Liberty Unit Holder (the “Redemption Right”), subject to certain limitations, to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units for, at Liberty LLC’s election, (A) shares of our Class A Common Stock at the specific redemption ratio or (B) an equivalent amount of cash, or, upon the exercise of the Redemption Right, the right of the Company (instead of Liberty LLC) to, for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder (the “Call Right”) for, at its election, (1) one share of Class A Common Stock or (2) an equivalent amount of cash, (ii) any net operating losses available to the Company as a result of the Corporate Reorganization, and (iii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRAs. On January 31, 2023, the last redemption of the Liberty LLC Units occurred. 
+42 
+With respect to obligations the Company expects to incur under the TRAs (except in cases where the Company elects to terminate the TRAs early, the TRAs are terminated early due to certain mergers, asset sales, or other changes of control or the Company has available cash but fails to make payments when due), generally the Company may elect to defer payments due under the TRAs if the Company does not have available cash to satisfy its payment obligations under the TRAs or if its contractual obligations limit its ability to make such payments. Any such deferred payments under the TRAs generally will accrue interest. In certain cases, payments under the TRAs may be accelerated and/or significantly exceed the actual benefits, if any, the Company realizes in respect of the tax attributes subject to the TRAs. The Company accounts for amounts payable under the TRAs in accordance with Accounting Standard Codification (“ASC”) Topic 450, Contingencies (“ASC Topic 450”). 
+If the Company experiences a change of control (as defined under the TRAs) or the TRAs otherwise terminate early, the Company’s obligations under the TRAs could have a substantial negative impact on its liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. There can be no assurance that we will be able to finance our obligations under the TRAs. 
+Income Taxes 
+The Company is a corporation and is subject to U.S. federal, state, and local income tax. The Company is also subject to Canada and Australia federal and provincial income tax on its foreign operations. 
+The effective global income tax rate applicable to the Company for the year ended December 31, 2024 was 21.6% compared to 24.3% for the year ended December 31, 2023. The Company’s effective tax rate for both years is greater than the statutory federal income tax rate of 21.0% due to the Company’s Canadian operations, state income taxes in the states the Company operates, as well as nondeductible executive compensation, partially offset by U.S. federal income tax credits. 
+The Company recognized income tax expense of $87.3 million and $178.5 million for the years ended December 31, 2024 and 2023, respectively. The Company’s effective tax rate can be volatile and may change with, among other things, the amount of jurisdiction pre-tax income or loss, ability to utilize foreign tax credits, excess tax benefits or deficiencies from share-based compensation and changes in tax laws in the jurisdictions that we operate. 
+Deferred income tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial reporting and tax bases of assets and liabilities, and are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. In the year ended December 31, 2024, the Company’s U.S. net deferred tax liabilities were $137.7 million and Canada net deferred tax assets were $1.5 million. The Company has no valuation allowances recorded against the deferred tax assets for the year ended December 31, 2024 and 2023. 
+Refer to Note 12— Income Taxes to the consolidated financial statements in Part II, Item 8 of this Annual Report for additional information related to income tax expense. 
+Critical Accounting Policies and Estimates 
+The preparation of financial statements requires the use of judgments and estimates. Our critical accounting policies are described below to provide a better understanding of how we develop our assumptions and judgments about future events and related estimates and how they can impact our financial statements. A critical accounting estimate is one that requires our most difficult, subjective or complex estimates and assessments and is fundamental to our results of operations. 
+We base our estimates on historical experience and on various other assumptions we believe to be reasonable according to the current facts and circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. We believe the following are the critical accounting policies used in the preparation of our consolidated financial statements, as well as the significant estimates and judgments affecting the application of these policies. This discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included in Part II, Item 8 of this Annual Report. 
+Revenue Recognition: Revenue from hydraulic fracturing services is recognized as specific services are provided in accordance with contractual arrangements. If our assessment of performance under a particular contract change, our revenue and / or costs under that contract may change. In connection with ASC Topic 842 - Leases (“Topic 842”), the Company determined that certain of its service revenue contracts contain a lease component. The Company elected to adopt a practical expedient available to lessors, which allows the Company to combine the lease and service component for certain of the Company’s service contracts when the service component is the predominant component and continues to account for the combined component under ASC Topic 606 - Revenue from Contracts with Customers . 
+Inventory: Inventory consists of raw materials used in the hydraulic fracturing process, such as proppants, chemicals and field service equipment maintenance parts, and is stated at the lower of cost or net realizable value, determined using the weighted average cost method. Net realizable value is determined based on our estimates of selling prices in the ordinary course 
+43 
+of business, less reasonably predictable cost of completion, disposal, and transportation, each of which require us to apply judgment. 
+Property and Equipment: We calculate depreciation and amortization on our assets based on the estimated useful lives and estimated salvage values that we believe are reasonable. The estimated useful lives and salvage values are subject to key assumptions such as maintenance, utilization and job variation. These estimates may change due to a number of factors such as changes in operating conditions or advances in technology. 
+We incur maintenance costs on our major equipment. The determination of whether an expenditure should be capitalized or expensed requires management judgment in the application of how the costs benefit future periods, relative to our capitalization policy. Costs that either establish or increase the efficiency, productivity, functionality or life of a fixed asset are capitalized and depreciated over the remaining useful life of the asset. 
+Impairment of long-lived assets: Long-lived assets, such as property and equipment, right-of-use lease assets and intangible assets, are evaluated for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Possible indicators of impairment may include events or changes in circumstances affecting the manner in which the assets are being used, historical and estimated future profitability measures, and other adverse events or changes that could affect the value of the assets. If a triggering event is identified, recoverability is assessed using undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets. When alternative courses of action to recover the carrying amount of the asset group are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence, which require us to apply judgment. If the carrying amount of the asset is not recoverable based on its estimated undiscounted cash flows expected to result from the use and eventual disposition, an impairment loss is recognized in an amount by which its carrying amount exceeds its estimated fair value. The inputs used to determine such fair value are primarily based upon internally developed cash flow models. Our cash flow models are based on a number of estimates regarding future operations that may be subject to significant variability, are sensitive to changes in market conditions, and are reasonably likely to change in the future. 
+Leases: In accordance with ASC Topic 842, Leases , the Company determines if an arrangement is a lease at inception and evaluates identified leases for operating or finance lease treatment. Operating or finance lease right-of-use assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. We use our incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments. Lease terms may include options to renew; however, we typically cannot determine our intent to renew a lease with reasonable certainty at inception. 
+Tax Receivable Agreements: In connection with the IPO, on January 17, 2018, the Company entered into two TRAs with the TRA Holders. The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax that the Company actually realizes in periods after the IPO as a result of certain tax attributes applicable to each TRA Holder. The Company accounts for amounts payable under the TRAs in accordance with ASC Topic 450, Contingencies . 
+Share Repurchases: The Company accounts for the purchase price of repurchased Class A Common Stock in excess of par value ($0.01 per share of Class A Common Stock) as a reduction of additional paid-in capital, and will continue to do so until additional paid-in capital is reduced to zero. Thereafter, any excess purchase price will be recorded as a reduction to retained earnings. All Class A Common Stock shares repurchased to date have been retired upon repurchase. 
+44 
+Item 7A. Quantitative and Qualitative Disclosure about Market Risk 
+Industry Risk 
+The demand, pricing and terms for hydraulic fracturing services and related goods provided by us are largely dependent upon the level of drilling and completions activity in the U.S. oil and natural gas industry, as well as the available supply of hydraulic fracturing equipment. These activity levels are influenced by numerous factors over which we have no control, including, but not limited to: the supply of and demand for oil and natural gas; the level of prices, and expectations about future prices of oil and natural gas; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; the discovery rates of new oil and natural gas reserves; supply of actively marketed and staffed fracturing fleets; available rail and other transportation capacity; weather conditions; domestic and worldwide economic conditions; political instability in oil-producing countries; environmental regulations; technical advances affecting energy consumption; the price and availability of alternative fuels; the ability of E&P companies to raise equity capital and debt financing; and merger and divestiture activity among E&P companies. 
+The level of U.S. oil and natural gas drilling can be volatile. Expected trends in oil and natural gas production activities may not materialize and demand for our services may not reflect the level of activity in the industry. Any prolonged and substantial reduction in oil and natural gas prices would likely affect oil and natural gas production levels and therefore affect demand for our services. A material decline in oil and natural gas prices or U.S. activity levels could have a material adverse effect on our business, financial condition, results of operations and cash flows. 
+Interest Rate Risk 
+As of December 31, 2024, the Company had $190.5 million of debt outstanding, with a weighted average interest rate of 6.8%. Interest is calculated under the terms of our ABL Facility based on our selection, from time to time, of one of the index rates available to us plus an applicable margin that varies based on certain factors. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources. Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the weighted average interest rate would be approximately $1.9 million per year. We do not currently have or intend to enter into any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness. 
+Commodity Price Risk 
+Our material and fuel purchases expose us to commodity price risk. Material costs primarily include inventory consumed while performing hydraulic fracturing services. Fuel costs consist of diesel fuel and natural gas used by trucks and other motorized equipment used for hydraulic fracturing services. At times, we have been able to pass along price increases for material costs and fuel costs to customers and conversely have been required to pass along price decreases for material costs to our customers, depending on market conditions. Further, we have purchase commitments with certain vendors to supply proppant inventory used in our operations at a fixed purchase price, including certain commitments which include minimum purchase obligations. Refer t o Note 15 — Commitments & Contingencies included in Part II, Item 8. of this Annual Report for further discussion regarding pur chase commitments. 
+Foreign Translation Risk 
+Our consolidated financial statements are expressed in U.S. dollars but a portion of our operations is conducted in a currency other than U.S. dollars. The Canadian dollar and the Australian dollar are the functional currencies of the Company’s foreign subsidiaries as it is the primary currency within the economic environment in which the subsidiaries operate. Changes in the exchange rate can affect our revenues, earnings, and the carrying value of our assets and liabilities in our consolidated balance sheet, either positively or negatively. Adjustments resulting from the translation of the subsidiary’s financial statements are reported in other comprehensive (loss) income. During the years ended December 31, 2024 and 2023, the Company recorded a foreign currency translation loss of $13.7 million and a foreign currency translation gain of $1.3 million to comprehensive income, respectively. 
+Item 8. Financial Statements and Supplementary Data 
+Our financial statements and supplementary data are included in this Annual Report beginning on page F-1 and incorporated by reference herein. 
+Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+None. 
+45 
+Item 9A. Controls and Procedures 
+Evaluation of Disclosure Controls and Procedures 
+In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2024 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures. 
+There were no changes to our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+See page F-1 for Management’s Report on Internal Control Over Financial Reporting and page F-4 for Report of Independent Registered Public Accounting Firm on its assessment of our internal control over financial reporting. 
+Item 9B. Other Information 
+During the quarter ended December 31, 2024, none of our directors or Section 16 officers informed us of the adoption , modification, or termination of any “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement” (in each case, as defined in Item 408(a) of Regulation S-K). 
+46 
+PART III 
+Item 10. Directors, Executive Officers and Corporate Governance 
+The information required by this item concerning our executive officers, directors and corporate governance is incorporated herein by reference to our definitive proxy statement for our 2025 annual meeting of stockholders, which will be filed with the SEC no later than 120 days after December 31, 2024, under the captions “Proposal 1 — Election of Directors,” “The Board and its Committees,” “Executive Officers” and “Delinquent Section 16(a) Reports.” 
+Item 11. Executive Compensation 
+The information required by this item concerning executive compensation is incorporated herein by reference to our definitive proxy statement for our 2025 annual meeting of stockholders, which will be filed with the SEC no later than 120 days after December 31, 2024, under the captions “The Board and its Committees,” “Compensation Discussion & Analysis,” “Compensation Committee Report,” “Executive Compensation Tables,” “Director Compensation,” and “CEO Pay Ratio,” except for the information required by Item 402(v) of Regulation S-K, which is specifically not incorporated by reference. 
+Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+The information required by this item concerning the security ownership of certain beneficial owners and management and related stockholder matters are incorporated herein by reference to our definitive proxy statement for our 2025 annual meeting of stockholders, which will be filed with the SEC no later than 120 days after December 31, 2024, under the captions “Security Ownership of Certain Beneficial Owners and Management” and “Equity Compensation Plan Information.” 
+Item 13. Certain Relationships and Related Transactions, and Director Independence 
+The information required by this item concerning certain relationships and related person transactions and director independence is incorporated herein by reference to our definitive proxy statement for our 2025 annual meeting of stockholders, which will be filed with the SEC no later than 120 days after December 31, 2024, under the captions “Certain Relationships and Related Party Transactions” and “the Board and its Committees.” 
+Item 14. Principal Accountant Fees and Services 
+The information required by this item concerning principal accounting fees and services is incorporated herein by reference to our definitive proxy statement for our 2025 annual meeting of stockholders, which will be filed with the SEC no later than 120 days after December 31, 2024, under the caption “Proposal 3 — Ratification of Appointment of the Company’s Independent Registered Public Accounting Firm.” 
+47 
+PART IV 
+Item 15. Exhibits and Financial Statement Schedules 
+(a) Financial Statements and Financial Statement Schedules 
+Refer to Index to Financial Statements on page 53. 
+All schedules are omitted as information required is inapplicable or the information is presented in the consolidated financial statements and the related notes. 
+(b) Exhibits 
+The documents listed in the Index to Exhibits are filed, furnished or incorporated by reference as part of this Annual Report, and such Index to Exhibits are incorporated herein by reference. 
+48 
+Item 16. Form 10-K Summary 
+None. 
+49 
+INDEX TO EXHIBITS 
+Exhibit 
+Number 
+Description 
+2.1 
+Master Reorganization Agreement, dated as of January 11, 2018, by and among Liberty Oilfield Services Inc., Liberty Oilfield Services Holdings LLC, Liberty Oilfield Services New HoldCo LLC, and the other parties named therein (2) 
+2.2 
+Master Transaction Agreement, dated as of August 31, 2020, by and among Schlumberger Technology Corporation, Schlumberger Canada Limited, Liberty Oilfield Services Holdings LLC, Liberty Canada Operations Inc. and Liberty Oilfield Services Inc. (10) 
+3.1 
+Amended and Restated Certificate of Incorporation of Liberty Oilfield Services Inc. (2) 
+3.2 
+Certificate of Amendment to Amended and Restated Certificate of Incorporation (13) 
+3.3 
+Second Amended and Restated Bylaws of Liberty Energy Inc., as amended effective January 24, 2023 (17) 
+4.1 
+Description of the Registrant’s Securities Registered pursuant to Section 12 of the Securities Exchange Act of 1934. (20) 
+10.1 
+Second Amended and Restated Limited Liability Company Operating Agreement of Liberty Oilfield Services New HoldCo LLC (2) 
+10.2 
+Form of Joinder Agreement to Second Amended and Restated Limited Liability Company Operating Agreement of Liberty Oilfield Services New HoldCo LLC (12) 
+10.3 
+Tax Receivable Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Inc., R/C Energy IV Direct Partnership, L.P., and R/C Energy IV Direct Partnership, L.P., as agent (2) 
+10.4 
+Tax Receivable Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Inc., and the other parties named therein (2) 
+10.5 
+Agent Designation Amendment to the Tax Receivable Agreement, dated as of February 22, 2022, by and among Liberty Oilfield Services Inc. and R/C Energy IV Direct Partnership, L.P. (15) 
+10.6 
+Credit Agreement, dated September 19, 2017, by and among Wells Fargo Bank, National Association, as Administrative Agent, Wells Fargo Bank, National Association, JPMorgan Chase Bank, N.A. and Citibank, N.A., as Joint Lead Arrangers, Wells Fargo Bank, National Association, as Book Runner, JPMorgan Chase Bank, N.A. and Citibank, N.A., as Syndication Agents, the lender parties thereto, Liberty Oilfield Services Holdings LLC, as Parent and Liberty Oilfield Services LLC and LOS Acquisition Co I LLC, each as a Borrower (1) 
+10.7 
+Amendment and Parent Joinder to Credit Agreement, dated January 17, 2018, by and among Liberty Oilfield Services Holdings LLC, Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto (3) 
+10.8 
+Second Amendment and Parent Joinder to Credit Agreement, dated March 21, 2018, by and among Liberty Oilfield Services LLC, LOS Acquisition Co I LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto (3) 
+10.9 
+Third Amendment to Credit Agreement, dated May 29, 2020, by and among Liberty Oilfield Services LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, and Wells Fargo Bank, National Association as Administrative Agent, and the lenders signatory thereto (8) 
+10.10 
+Fourth Amendment to Credit Agreement, dated August 12, 2020, by and among Liberty Oilfield Services LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto (9) 
+10.11 
+Consent and Fifth Amendment to Credit Agreement, dated December 29, 2020, by and among Liberty Oilfield Services LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, LOS Cibolo RE Investments, LLC, LOS Odessa RE Investments, LLC, ST9 Gas and Oil LLC, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto (11) 
+50 
+10.12 
+Sixth Amendment to Credit Agreement and Second Amendment to Guaranty and Security Agreement, dated October 22, 2021, by and among Liberty Oilfield Services LLC, Liberty Oilfield Services Inc., Liberty Oilfield Services New HoldCo LLC, R/C IV Non-U.S. LOS Corp, LOS Solar Acquisition LLC, Freedom Proppant LLC, LOS Kermit LLC, LOS Cibolo RE Investments, LLC, LOS Odessa RE Investments, LLC, ST9 Gas and Oil LLC, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto (12) 
+10.13 
+Increase Joinder and Seventh Amendment to Credit Agreement, dated July 18, 2022, by and among Liberty Oilfield Services LLC, Liberty Energy Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, Freedom Proppant LLC, LOS Kermit LLC, LOS Leasing Company LLC, LOS Cibolo RE Investments, LLC, LOS Odessa RE Investments, LLC, Proppant Express Solutions, LLC, ST9 Gas and Oil LLC, Well Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto. (14) 
+10.14 
+Eighth Amendment to Credit Agreement, dated January 23, 2023, by and among Liberty Oilfield Services LLC, Liberty Energy Inc., Liberty Oilfield Services New Holdco LLC, R/C IV Non-U.S. LOS Corp, Freedom Proppant LLC, LOS Kermit LLC, LOS Leasing Company LLC, LOS Cibolo RE Investments, LLC, LOS Odessa RE Investments, LLC, Proppant Express Solutions, LLC, ST9 Gas and Oil LLC, Well Fargo Bank, National Association, as Administrative Agent, and the lenders signatory thereto. (17) 
+10.15 
+Joinder Agreement, dated December 31, 2021, by and among LOS Leasing Company LLC and Wells Fargo Bank, National Association, as Administrative Agent (16) 
+10.16 
+Liberty Energy Services 401(k) Savings Plan * 
+10.17 
+Form of Restricted Stock Unit Grant Notice and Restricted Stock Unit Award Agreement under the Long Term Incentive Plan (4)† 
+10.18 
+Form of Restricted Stock Unit Grant Notice under the Long Term Incentive Plan (11)† 
+10.19 
+Form of Performance Restricted Stock Unit Grant Notice and Performance Restricted Stock Unit Agreement under the Liberty Oilfield Services Inc. Long Term Incentive Plan (5)† 
+10.20 
+Liberty Energy Inc. Amended and Restated Long Term Incentive Plan (18)† 
+10.21 
+Form of Performance Restricted Stock unit Grant Notice and Agreement under the Liberty Energy Inc. Amended and Restated Long Term Incentive Plan (19)† 
+10.22 
+Form of Restricted Stock unit Grant Notice and Agreement under the Liberty Energy Inc. Amended and Restated Long Term Incentive Plan (19)† 
+10.23 
+Form of Restricted Stock unit Grant Notice under the Liberty Energy Inc. Amended and Restated Long Term Incentive Plan (19)† 
+10.24 
+Form of Director and Officer Indemnification Agreement * 
+10.25 
+Form of Change in Control Agreement (6)† 
+10.26 
+Form of Indemnification Agreement between the Company and each of its Directors and Executive Officers (7) 
+19.1 
+Insider Trading Policy (20) 
+21.1 
+List of subsidiaries of Liberty Energy Inc. * 
+23.1 
+Consent of Deloitte & Touche LLP * 
+31.1 
+Certification of Chief Executive Officer pursuant to Rule 13a-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 * 
+31.2 
+Certification of Chief Financial Officer pursuant to 13a-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 * 
+32.1 
+Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 ** 
+32.2 
+Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 ** 
+95 
+Mine Safety Disclosure * 
+97 
+Compensation Recovery Policy (20) 
+101.INS XBRL Instance Document * 
+101.SCH XBRL Taxonomy Extension Schema Document * 
+51 
+101.CAL XBRL Taxonomy Extension Calculation Linkbase Document * 
+101.DEF XBRL Taxonomy Extension Definition Linkbase Document * 
+101.LAB XBRL Taxonomy Extension Label Linkbase Document * 
+101.PRE XBRL Taxonomy Extension Presentation Linkbase Document * 
+104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)* 
+(1) Incorporated by reference to the exhibits to the registrant’s Registration Statement on Form S-1, as amended (SEC File 333-216050). 
+(2) Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on January 18, 2018. 
+(3) Incorporated by reference to the exhibits to the registrant’s Annual Report on Form 10-K, filed on March 23, 2018. 
+(4) Incorporated by reference to the exhibits to the registrant’s Quarterly Report on Form 10-Q, filed on May 10, 2018. 
+(5) Incorporated by reference to the exhibits to the registrant’s Quarterly Report on Form 10-Q, filed on May 3, 2019. 
+(6) Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on August 30, 2019. 
+(7) Incorporated by reference to the exhibits to the registrant’s Annual Report on Form 10-K, filed on February 27, 2020. 
+(8) Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on June 3, 2020. 
+(9) Incorporated by reference to the exhibits to the registrant’s Quarterly Report on Form 10-Q, filed on October 30, 2020. 
+(10) Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on September 1, 2020. 
+(11) Incorporated by reference to the exhibits to the registrant’s Annual Report on Form 10-K, filed on February 24, 2021. 
+(12) Incorporated by reference to the exhibits to the registrant’s Quarterly Report on Form 10-Q, filed on October 28, 2021. 
+(13) Incorporated by reference to the registrant’s Current Report on Form 8-K, filed on April 21, 2022. 
+(14) Incorporated by reference to the registrant’s Current Report on Form 8-K, filed on July 22, 2022. 
+(15) Incorporated by reference to the exhibits to the registrant’s Quarterly Report on Form 10-Q, filed on April 25, 2022. 
+(16) Incorporated by reference to the exhibits to the registrant’s Annual Report on Form 10-K, filed on February 22, 2022. 
+(17) Incorporated by reference to the exhibits to the registrant’s Current Report on Form 8-K, filed on January 26, 2023. 
+(18) Incorporated by reference to Annex A of the registrant’s Definitive Proxy Statement on Schedule 14A, filed on March 7, 2024. 
+(19) Incorporated by reference to the registrant’s Registration Statement on Form S-8, filed on May 17, 2024. 
+(20) Incorporated by reference to the registrant’s Annual Report on Form 10-K, filed on February 9, 2024. 
+* Filed herewith. 
+** Furnished herewith. 
+† Denotes a management contract or compensatory plan or arrangement. 
+52 
+SIGNATURES 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+LIBERTY ENERGY INC. 
+/s/ Ron Gusek 
+Date: February 6, 2025 By: 
+Ron Gusek 
+Chief Executive Officer 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+Signature Title Date 
+/s/ Ron Gusek 
+Chief Executive Officer and Director 
+(Principal Executive Officer) 
+February 6, 2025 
+Ron Gusek 
+/s/ Michael Stock 
+Chief Financial Officer 
+(Principal Financial Officer) 
+February 6, 2025 
+Michael Stock 
+/s/ Ryan T. Gosney Chief Accounting Officer and Vice President of Finance February 6, 2025 
+Ryan T. Gosney (Principal Accounting Officer) 
+/s/ Simon Ayat Director February 6, 2025 
+Simon Ayat 
+/s/ Ken Babcock Director February 6, 2025 
+Ken Babcock 
+/s/ Peter A. Dea Director February 6, 2025 
+Peter A. Dea 
+/s/ William F. Kimble Director February 6, 2025 
+William F. Kimble 
+/s/ James R. McDonald Director February 6, 2025 
+James R. McDonald 
+/s/ Gale A. Norton Director February 6, 2025 
+Gale A. Norton 
+/s/ Audrey Robertson Director February 6, 2025 
+Audrey Robertson 
+/s/ Cary D. Steinbeck Director February 6, 2025 
+Cary D. Steinbeck 
+/s/ Arjun Murti Director February 6, 2025 
+Arjun Murti 
+53 
+Index to Financial Statements 
+Liberty Energy Inc. 
+Management’s Report on Internal Control Over Financial Reporting 
+F-1 
+Reports of Independent Registered Public Accounting Firm (PCAOB ID No. 34 ) 
+F- 2 
+Consolidated Balance Sheets as of December 31, 202 4 and 202 3 
+F- 5 
+Consolidated Statements of Operations for the Years Ended December 31, 202 4 , 202 3 , and 202 2 
+F- 6 
+Consolidated Statements of Comprehensive Income for the Years Ended December 31, 202 4 , 202 3 , and 202 2 
+F-7 
+Consolidated Statements of Changes in Equity for the Years Ended December 31, 202 4 and 202 3 
+F- 8 
+Consolidated Statements of Cash Flows for the Years Ended December 31, 202 4 , 202 3 and 202 2 
+F- 9 
+Notes to Consolidated Financial Statements 
+F- 11 
+54 
+MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING 
+The management of Liberty Energy Inc. is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act. 
+Internal control over financial reporting, no matter how well designed, has inherent limitations. Therefore, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements. Further, because of changes in conditions, effectiveness of internal controls over financial reporting may vary over time. 
+Under the supervision of, and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2024 based on the framework and criteria established in Internal Control-Integrated Framework (2013) , issued by the Committee of Sponsoring Organizations of the Treadway Commission. 
+Based on this evaluation, management concluded that, as of December 31, 2024, our internal control over financial reporting was effective. 
+The effectiveness of Liberty Energy Inc. ’ s internal control over financial reporting as of December 31, 2024 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report that is included herein. 
+F-1 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the stockholders and the Board of Directors of Liberty Energy Inc. 
+Opinion on the Financial Statements 
+We have audited the accompanying consolidated balance sheets of Liberty Energy Inc. and subsidiaries (the "Company") as of December 31, 2024 and 2023, the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2024, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America. 
+We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 6, 2025, expressed an unqualified opinion on the Company’s internal control over financial reporting. 
+Basis for Opinion 
+These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. 
+Critical Audit Matters 
+The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing separate opinions on the critical audit matter or on the accounts or disclosures to which it relates. 
+Property and equipment — Determination of Impairment Indicators — Refer to Note 2 to the financial statements 
+Critical Audit Matter Description 
+As described in Note 2 to the consolidated financial statements, the Company assesses its property and equipment for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable, referred to as triggering events. Possible indications of impairment may include events or changes in circumstances affecting the manner in which the assets are being used, historical and estimated future profitability measures, and other adverse events or changes that could affect the value of the assets. If a triggering event is identified, the Company evaluates its property and equipment for impairment by comparing undiscounted future cash flows expected to be generated over the life of the assets to the respective carrying amount. If the carrying amount of the assets exceeds the undiscounted future cash flows, an analysis is performed to determine the fair value of the assets. 
+We identified the evaluation of property and equipment for impairment triggering events as a critical audit matter. The Company makes assumptions to evaluate property and equipment for possible indications of impairment. Changes in these assumptions could have a significant impact on the assets identified for further analysis. For the year ended December 31, 2024, the Company concluded that no triggering events had occurred, and no impairment was recognized. 
+Given the Company’s evaluation of possible indications of impairment of property and equipment requires management to make assumptions, performing audit procedures to evaluate whether management appropriately identified events or 
+F-2 
+changes in circumstances indicating that the carrying amounts of property and equipment may not be recoverable required a high degree of auditor judgment. 
+How the Critical Audit Matter Was Addressed in the Audit 
+Our audit procedures related to the evaluation of property and equipment for possible indications of impairment included the following, among others: 
+• We tested the effectiveness of internal controls over financial reporting related to management’s evaluation of impairment. This included controls related to the Company’s process to identify and evaluate triggering events, including the consideration of forecasted to actual results and market conditions in determining whether a triggering event exists. 
+• We considered the completeness of management’s identification of impairment indicators by: 
+◦ Considering industry and analysts reports and the impact of macroeconomic factors, such as adverse changes in the regulatory environment, legislation or other factors that may represent impairment indicators not previously contemplated in management’s analysis. 
+◦ Inspecting minutes of the board of directors and committees to understand if there were factors that would represent potential impairment indicators for property and equipment. 
+◦ Developing an independent expectation of impairment indicators and compared such expectation to management’s analysis. 
+• We evaluated management’s determination of the property and equipment’s estimated useful life as well as any factors impacting the useful life, such as plans to sell and any relevant purchase and sales agreements for assets sold. 
+/s/ DELOITTE & TOUCHE LLP 
+Denver, Colorado 
+February 6, 2025 
+We have served as the Company’s auditor since 2016. 
+F-3 
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 
+To the stockholders and the Board of Directors of Liberty Energy Inc. 
+Opinion on Internal Control over Financial Reporting 
+We have audited the internal control over financial reporting of Liberty Energy Inc. (the “Company”) as of December 31, 2024, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO. 
+We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2024, of the Company and our report dated February 6, 2025, expressed an unqualified opinion on those financial statements. 
+Basis for Opinion 
+The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+Definition and Limitations of Internal Control over Financial Reporting 
+A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+/s/ DELOITTE & TOUCHE LLP 
+Denver, Colorado 
+February 6, 2025 
+F-4 
+LIBERTY ENERGY INC. 
+Consolidated Balance Sheets 
+As of December 31, 2024 and 2023 
+(Dollars in thousands, except share data) 
+2024 2023 
+Assets 
+Current assets: 
+Cash and cash equivalents $ 19,984 $ 36,784 
+Accounts receivable—trade, net of allowances for credit losses of $ 848 and $ 939 , respectively 
+350,412 381,185 
+Accounts receivable—related party 4,234 17,345 
+Unbilled revenue (including amounts from related parties of $ 0 and $ 13,379 , respectively) 
+185,210 188,940 
+Inventories 203,469 205,865 
+Prepaid and other current assets 85,214 124,135 
+Total current assets 848,523 954,254 
+Property and equipment, net 1,890,998 1,645,368 
+Finance lease right-of-use assets 283,113 182,319 
+Operating lease right-of-use assets 73,322 92,640 
+Other assets (including amounts from related parties of $ 0 and $ 14,785 , respectively) 
+119,402 127,330 
+Investment in Nomad Proppant Services LLC 10,674 11,363 
+Investment in Oklo Inc. 51,611 10,000 
+Investment in Tamboran Resources Corporation 18,751 10,283 
+Total assets $ 3,296,394 $ 3,033,557 
+Liabilities and Equity 
+Current liabilities: 
+Accounts payable (including amounts due to related parties of $ 582 and $ 0 , respectively) 
+$ 314,123 $ 293,733 
+Accrued liabilities 206,713 261,066 
+Income taxes payable 9,693 12,060 
+Current portion of payable pursuant to tax receivable agreements 40,776 5,170 
+Current portion of finance lease liabilities 66,648 39,867 
+Current portion of operating lease liabilities 28,570 27,528 
+Total current liabilities 666,523 639,424 
+Long-term debt 190,500 140,000 
+Deferred tax liability 137,728 102,340 
+Payable pursuant to tax receivable agreements 74,886 112,471 
+Noncurrent portion of finance lease liabilities 203,511 133,654 
+Noncurrent portion of operating lease liabilities 44,377 64,260 
+Total liabilities 1,317,525 1,192,149 
+Commitments & contingencies (Note 15) 
+Stockholders’ equity: 
+Preferred Stock, $ 0.01 par value, 10,000 shares authorized and none issued and outstanding 
+— — 
+Common Stock: 
+Class A, $ 0.01 par value, 400,000,000 shares authorized and 161,858,784 issued and outstanding as of December 31, 2024 and 166,610,199 issued and outstanding as of December 31, 2023 
+1,619 1,666 
+Class B, $ 0.01 par value, 400,000,000 shares authorized and none issued and outstanding 
+— — 
+Additional paid in capital 977,484 1,093,498 
+Retained earnings 1,019,517 752,328 
+Accumulated other comprehensive loss ( 19,751 ) ( 6,084 ) 
+Total stockholders’ equity 1,978,869 1,841,408 
+Total liabilities and equity $ 3,296,394 $ 3,033,557 
+See Notes to Consolidated Financial Statements. 
+F-5 
+LIBERTY ENERGY INC. 
+Consolidated Statements of Operations 
+For the Years Ended December 31, 2024, 2023, and 2022 
+(In thousands, except per share data) 
+2024 2023 2022 
+Revenue: 
+Revenue $ 4,183,821 $ 4,533,048 $ 4,000,780 
+Revenue—related parties 131,340 214,880 148,448 
+Total revenue 4,315,161 4,747,928 4,149,228 
+Operating costs and expenses: 
+Cost of services (exclusive of depreciation, depletion, and amortization shown separately below) 3,200,506 3,349,370 3,149,036 
+General and administrative 225,474 221,406 180,040 
+Transaction and other costs — 2,053 5,837 
+Depreciation, depletion, and amortization 505,050 421,514 323,028 
+Gain on disposal of assets, net ( 5,337 ) ( 6,994 ) ( 4,603 ) 
+Total operating costs and expenses 3,925,693 3,987,349 3,653,338 
+Operating income 389,468 760,579 495,890 
+Other (income) expense: 
+Loss (gain) on remeasurement of liability under tax receivable agreements 3,210 ( 1,817 ) 76,191 
+Unrealized gain on investments, net ( 49,227 ) — ( 2,525 ) 
+Interest income—related party ( 478 ) ( 1,987 ) — 
+Interest expense, net 32,692 29,493 22,715 
+Total other (income) expense, net ( 13,803 ) 25,689 96,381 
+Net income before income taxes 403,271 734,890 399,509 
+Income tax expense (benefit) 87,261 178,482 ( 793 ) 
+Net income 316,010 556,408 400,302 
+Less: Net income attributable to non-controlling interests — 91 700 
+Net income attributable to Liberty Energy Inc. stockholders $ 316,010 $ 556,317 $ 399,602 
+Net income attributable to Liberty Energy Inc. stockholders per common share: 
+Basic $ 1.91 $ 3.24 $ 2.17 
+Diluted $ 1.87 $ 3.15 $ 2.11 
+Weighted average common shares outstanding: 
+Basic 165,026 171,845 184,334 
+Diluted 169,398 176,360 189,349 
+See Notes to Consolidated Financial Statements. 
+F-6 
+LIBERTY ENERGY INC. 
+Consolidated Statements of Comprehensive Income 
+For the Years Ended December 31, 2024, 2023, and 2022 
+(In thousands) 
+2024 2023 2022 
+Net income $ 316,010 $ 556,408 $ 400,302 
+Other comprehensive (loss) income 
+Foreign currency translation adjustments ( 13,667 ) 1,313 ( 7,097 ) 
+Comprehensive income $ 302,343 $ 557,721 $ 393,205 
+Comprehensive income attributable to non-controlling interest — 92 693 
+Comprehensive income attributable to Liberty Energy Inc. $ 302,343 $ 557,629 $ 392,512 
+See Notes to Consolidated Financial Statements. 
+F-7 
+LIBERTY ENERGY INC. 
+Consolidated Statements of Changes in Equity 
+For the Years Ended December 31, 2024 and 2023 
+(In thousands, except per share and per unit data) 
+Shares of Class A Common Stock Shares of Class B Common Stock Class A Common Stock, Par Value Class B Common Stock, Par Value Additional Paid in Capital Retained Earnings Accumulated Other Comprehensive Loss Total Equity 
+Balance—December 31, 2023 166,610 — $ 1,666 $ — $ 1,093,498 $ 752,328 $ ( 6,084 ) $ 1,841,408 
+$ 0.29 /share of Class A Common Stock dividend 
+— — — — — ( 48,821 ) — ( 48,821 ) 
+Share repurchases ( 6,321 ) — ( 63 ) — ( 127,332 ) — — ( 127,395 ) 
+Excise tax on share repurchases — — — — ( 924 ) — — ( 924 ) 
+Stock-based compensation expense — — — — 32,412 — — 32,412 
+Vesting of restricted stock units, net 1,570 — 16 — ( 20,170 ) — — ( 20,154 ) 
+Currency translation adjustment — — — — — — ( 13,667 ) ( 13,667 ) 
+Net income — — — — — 316,010 — 316,010 
+Balance—December 31, 2024 161,859 — $ 1,619 $ — $ 977,484 $ 1,019,517 $ ( 19,751 ) $ 1,978,869 
+Shares of Class A Common Stock Shares of Class B Common Stock Class A Common Stock, Par Value Class B Common Stock, Par Value Additional Paid in Capital (Accumulated Deficit) Retained Earnings Accumulated Other Comprehensive Loss Total Stockholders’ equity Non-controlling Interest Total Equity 
+Balance - December 31, 2022 178,753 250 $ 1,788 $ 3 $ 1,266,097 $ 234,525 $ ( 7,396 ) $ 1,495,017 $ 2,289 $ 1,497,306 
+Exchange of Class B Common Stock for Class A Common Stock 250 ( 250 ) 3 ( 3 ) 2,360 — — 2,360 ( 2,360 ) — 
+Offering Costs — — — — ( 223 ) — — ( 223 ) — ( 223 ) 
+Deferred tax and tax receivable agreements impact of Liberty LLC merger into the Company — — — — 6,681 — — 6,681 — 6,681 
+$ 0.22 /share of Class A Common Stock dividend 
+— — — — — ( 38,514 ) — ( 38,514 ) — ( 38,514 ) 
+Share repurchases ( 13,706 ) — ( 137 ) — ( 202,940 ) — — ( 203,077 ) ( 23 ) ( 203,100 ) 
+Excise tax on share repurchases — — — — ( 1,855 ) — — ( 1,855 ) — ( 1,855 ) 
+Stock-based compensation expense — — — — 33,023 — — 33,023 3 33,026 
+Vesting of restricted stock units, net 1,313 — 12 — ( 9,645 ) — — ( 9,633 ) ( 1 ) ( 9,634 ) 
+Currency translation adjustment — — — — — — 1,312 1,312 1 1,313 
+Net income — — — — — 556,317 — 556,317 91 556,408 
+Balance - December 31, 2023 166,610 — $ 1,666 $ — $ 1,093,498 $ 752,328 $ ( 6,084 ) $ 1,841,408 $ — $ 1,841,408 
+See Notes to Consolidated Financial Statements. 
+F-8 
+LIBERTY ENERGY INC. 
+Consolidated Statements of Cash Flows 
+For the Years Ended December 31, 2024, 2023, and 2022 
+(Dollars in thousands) 
+2024 2023 2022 
+Cash flows from operating activities: 
+Net income $ 316,010 $ 556,408 $ 400,302 
+Adjustments to reconcile net income to net cash provided by operating activities: 
+Depreciation, depletion, and amortization 505,050 421,514 323,028 
+Gain on disposal of assets, net ( 5,337 ) ( 6,994 ) ( 4,603 ) 
+Stock-based compensation expense 32,412 33,026 23,108 
+Deferred income tax expense (benefit) 33,844 120,312 ( 12,472 ) 
+Unrealized gain on investments, net ( 49,227 ) — ( 2,525 ) 
+Cash return on equity method investment 3,967 — — 
+Loss (gain) on remeasurement of liability under tax receivable agreements 3,210 ( 1,817 ) 76,191 
+Other non-cash items, net 178 7,111 7,986 
+Changes in operating assets and liabilities: 
+Accounts receivable and unbilled revenue 18,187 19,612 ( 166,605 ) 
+Accounts receivable and unbilled revenue—related party 41,275 ( 19,855 ) ( 25,522 ) 
+Inventories 66 ( 114 ) ( 84,989 ) 
+Prepaid and other assets ( 28,196 ) ( 66,182 ) ( 56,161 ) 
+Accounts payable and accrued liabilities ( 41,319 ) ( 45,133 ) 57,203 
+Accounts payable and accrued liabilities—related party 582 — ( 1,864 ) 
+Initial payment of operating lease liability ( 1,328 ) ( 3,305 ) ( 2,713 ) 
+Net cash provided by operating activities 
+829,374 1,014,583 530,364 
+Cash flows from investing activities: 
+Purchases of property and equipment and construction in-progress ( 651,034 ) ( 603,298 ) ( 451,905 ) 
+Investment in sand logistics — — ( 7,415 ) 
+Investment in equity securities ( 16,056 ) ( 20,283 ) ( 15,000 ) 
+Acquisition of Siren Energy, net of cash received — ( 75,656 ) — 
+Proceeds from sales of assets 23,977 26,909 23,664 
+Net cash used in investing activities 
+( 643,113 ) ( 672,328 ) ( 450,656 ) 
+Cash flows from financing activities: 
+Proceeds from borrowings on line-of-credit 2,238,000 1,153,000 713,000 
+Repayments of borrowings on line-of-credit ( 2,187,500 ) ( 1,128,000 ) ( 616,000 ) 
+Repayments of borrowings on term loan — ( 104,716 ) ( 1,750 ) 
+Payments on finance lease obligations ( 50,302 ) ( 17,392 ) ( 6,947 ) 
+Class A Common Stock dividends and dividend equivalents upon restricted stock vesting ( 48,310 ) ( 37,684 ) ( 9,164 ) 
+Per unit distributions to non-controlling interest unitholders — — ( 13 ) 
+Other distributions and advance payments to non-controlling interest unitholders — — 920 
+Share repurchases, including related excise tax ( 129,250 ) ( 203,100 ) ( 125,313 ) 
+Tax withholding on restricted stock units ( 20,154 ) ( 9,634 ) ( 9,716 ) 
+Payments under TRA liability ( 5,189 ) — — 
+Payment of equity issuance costs — ( 223 ) ( 79 ) 
+Payments of debt issuance costs — ( 1,566 ) ( 708 ) 
+Net cash used in financing activities 
+( 202,705 ) ( 349,315 ) ( 55,770 ) 
+Net (decrease) increase in cash and cash equivalents ( 16,444 ) ( 7,060 ) 23,938 
+Translation effect on cash ( 356 ) 168 ( 260 ) 
+Cash and cash equivalents—beginning of period 36,784 43,676 19,998 
+Cash and cash equivalents—end of period $ 19,984 $ 36,784 $ 43,676 
+F-9 
+LIBERTY ENERGY INC. 
+Consolidated Statements of Cash Flows (cont.) 
+For the Years Ended December 31, 2024, 2023, and 2022 
+(Dollars in thousands) 
+2024 2023 2022 
+Supplemental disclosure of cash flow information: 
+Net cash paid for income taxes $ 35,857 $ 66,685 $ 10,744 
+Cash paid for interest $ 33,077 $ 26,651 $ 20,310 
+Non-cash investing and financing activities: 
+Capital expenditures included in accounts payable and accrued liabilities $ 102,203 $ 99,165 $ 107,514 
+Capital expenditures reclassified from prepaid and other current assets $ 58,288 $ 50,313 $ 14,922 
+Capital expenditures reclassified from finance lease right-of-use assets $ 6,894 $ — $ — 
+See Notes to Consolidated Financial Statements. 
+F-10 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Note 1— Organization and Basis of Presentation 
+Organization 
+Liberty Energy Inc., formerly known as Liberty Oilfield Services Inc. (the “Company”), was incorporated as a Delaware corporation on December 21, 2016, to become a holding corporation for Liberty Oilfield Services New HoldCo LLC (“Liberty LLC”) and its subsidiaries upon completion of a corporate reorganization (the “Corporate Reorganization”) and planned initial public offering of the Company (“IPO”). On April 19, 2022, the stockholders of the Company approved an amendment to the Company’s Amended and Restated Certificate of Incorporation for the purpose of changing the Company’s name from “Liberty Oilfield Services Inc.” to “Liberty Energy Inc.” and thereafter, the Company filed with the Secretary of State of the State of Delaware a Certificate of Amendment to the Company’s Amended and Restated Certificate of Incorporation to reflect the new name, effective April 25, 2022. 
+Effective January 31, 2023, Liberty LLC was merged into the Company, with the Company surviving the merger (the “Merger”). In connection with the Merger, all outstanding shares of the Company’s Class B Common Stock, par value $ 0.01 per share (the “Class B Common Stock”), were redeemed and exchanged for an equal number of shares of the Company’s Class A Common Stock, par value $ 0.01 per share (the “Class A Common Stock”). The Company did not make any distributions or receive any proceeds in connection with this exchange. The Merger did not have a significant impact on the Company’s consolidated financial statements. 
+The Company, together with its subsidiaries, is a leading integrated energy services and technology company focused on providing innovative hydraulic fracturing services and related technologies to onshore oil and natural gas exploration and production (“E&P”) companies. We offer customers hydraulic fracturing services, together with complementary services including wireline services, proppant delivery solutions, field gas processing, compressed natural gas (“CNG”) delivery, data analytics, related goods (including our sand mine operations), and technologies to facilitate lower emission completions, thereby helping our customers reduce their emissions profile. 
+Basis of Presentation 
+The accompanying consolidated financial statements were prepared using generally accepted accounting principles in the United States of America (“GAAP”) and the instructions to Form 10-K, Regulation S-X and the rules and regulations of the Securities and Exchange Commission. 
+The accompanying consolidated financial statements and related notes present the consolidated financial position of the Company and equity of the Company as of and for the years ended December 31, 2024 and 2023, and the results of operations and cash flows of the Company for the years ended December 31, 2024, 2023, and 2022. 
+The consolidated financial statements include the amounts of the Company and all majority owned subsidiaries where the Company has the ability to exercise control. All intercompany amounts have been eliminated in the presentation of the consolidated financial statements of the Company. 
+Our chief operating decision maker (“CODM”), the Chief Executive Officer, manages the Company’s business activities as a single operating and reportable segment at the consolidated level. Accordingly, our CODM uses consolidated net income to measure segment profit or loss, allocate resources, and assess performance. Further, the CODM is regularly provided with and utilizes consolidated functional expenses, as presented in the accompanying consolidated statements of operations, and total assets at the consolidated level, as included in the consolidated balance sheets herein, to manage the Company’s operations. 
+Note 2— Significant Accounting Policies 
+Business Combinations 
+Business combinations are accounted for using the acquisition method of accounting in accordance with the Accounting Standard Codification (“ASC”) Topic 805 - Business Combinations, as amended by Accounting Standards Update (“ASU”) 2017-01, Business Combinations (Topic 805), Clarifying the Definition of a Business, and ASU No. 2021-08, Business Combinations: Accounting for Contract Assets and Contract Liabilities from Contracts with Customers. The purchase price is allocated to the assets acquired and liabilities assumed based on their estimated fair values. Fair value of the acquired assets and liabilities is measured in accordance with the guidance of ASC 850, Fair Value Measurements, using discounted cash flows and other applicable valuation techniques. Any acquisition related costs incurred by the Company are expensed as incurred. Any excess purchase price over the fair value of the net identifiable assets acquired is recorded as goodwill if the definition of a 
+F-11 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+business is met. Operating results of an acquired business are included in our results of operations from the date of acquisition. Refer to Note 3—Acquisitions. 
+Use of Estimates 
+The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 
+The consolidated financial statements include certain amounts that are based on management’s best estimates and judgments. The most significant estimates relate to the fair value of assets acquired and liabilities assumed, collectability of accounts receivable and estimates of allowance for doubtful accounts, the useful lives and salvage values of long-lived assets, future cash flows associated with long-lived assets, net realizable value of inventory, equity unit valuation, deferred taxes, and the tax receivable agreements value. These estimates may be adjusted as more current information becomes available. 
+Cash and Cash Equivalents 
+The Company considers all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. The Company continually monitors its positions with, and the credit quality of, the financial institutions with which it has banking relationships. As of the balance sheet date, and periodically throughout the year, the Company has maintained balances in various operating accounts in excess of federally insured limits. 
+Accounts Receivable 
+In accordance with Accounting Standards Updates ASU 2016-13, Financial Instruments-Credit Losses (Topic 326) : Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”), the Company applies historic loss factors to its receivable portfolio segments that were not expected to be further impacted by current economic developments, and additional economic conditions factor to portfolio segments anticipated to experience greater losses in the current economic environment. Additionally, the Company continuously evaluates customers based on risk characteristics, such as historical losses and current economic conditions. Due to the cyclical nature of the oil and gas industry, the Company often evaluates its customers’ estimated losses on a case-by-case basis. The Company did not record an additional provision for credit losses during the year ended December 31, 2024 and 2022. During the year ended December 31, 2023, the Company recorded a provision for credit losses of $ 0.8 million, related to certain customers’ inability to pay. Provisions for credit losses are included in general and administrative expenses in the accompanying consolidated statements of operations. Refer to “Credit Risk” within Note 9—Fair Value Measurements and Financial Instruments for additional disclosures required under ASU 2016-13. 
+Inventories 
+Inventories consist of raw materials used in the hydraulic fracturing process, such as proppants, chemicals, and field service equipment maintenance parts and other and are stated at the lower of cost, determined using the weighted average cost method, or net realizable value. Inventories are charged to cost of services as used when providing hydraulic fracturing services. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable cost of completion, disposal, and transportation. 
+Property and Equipment 
+Property and equipment are stated at cost. Depreciation expense is recognized on property and equipment, excluding land, utilizing the straight-line method over the estimated useful lives, ranging from two to 30 years. The Company estimates salvage values that it does not depreciate. 
+Construction in-progress, a component of property and equipment, represents long-lived assets not yet in service or being developed by the Company. These assets are not subject to depreciation until they are completed and ready for their intended use, at which point the Company reclassifies them to field services equipment, vehicles, or buildings and facilities, as appropriate. 
+The Company incurs maintenance costs on its major equipment. The determination of whether an expenditure should be capitalized or expensed requires management judgment in the application of how the costs incurred benefit future periods, relative to the Company’s capitalization policy. Costs that either establish or increase the efficiency, productivity, functionality or life of a fixed asset are capitalized and depreciated over the remaining useful life of the asset. 
+Impairment of long-lived assets 
+Long-lived assets, such as property and equipment, right-of-use lease assets and intangible assets, are evaluated for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Possible 
+F-12 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+indicators of impairment may include events or changes in circumstances affecting the manner in which the assets are being used, historical and estimated future profitability measures, and other adverse events or changes that could affect the value of the assets. If a triggering event is identified, recoverability is assessed using undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets. The Company determined the lowest level of identifiable cash flows to be at the asset group, which is the aggregate of the Company’s hydraulic fracturing fleets that are in service. A long-lived asset is not recoverable if its carrying amount exceeds the sum of estimated undiscounted cash flows expected to result from the use and eventual disposition. When alternative courses of action to recover the carrying amount of the asset group are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the asset is not recoverable, an impairment loss is recognized in an amount by which its carrying amount exceeds its estimated fair value, such that its carrying amount is adjusted to its estimated fair value, with an offsetting charge to impairment expense. 
+The Company measures the fair value of its long-lived assets using the discounted cash flow method. The expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments of projected revenue growth, fleet count, utilization, gross margin rates, selling, general and administrative rates, working capital fluctuations, capital expenditures, discount rates and terminal growth rates. 
+Goodwill 
+Goodwill represents the excess of the acquisition purchase price over the estimated fair value of net tangible and intangible assets required. Goodwill is not amortized, but instead tested for impairment at least annually, June 30, or more frequently if events and circumstances indicate that the asset might be impaired. In testing goodwill for impairment, the Company performs a qualitative assessment to determine whether the existence of events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If the qualitative assessment determines that an impairment is more likely than not, then the Company performs the one-step quantitative impairment test by determining the fair value of the reporting unit. The fair value of the reporting unit is determined using either the income approach by utilizing estimated discounted future cash flows or the market approach utilizing recent transaction activity for comparable properties. These approaches are considered Level 3 fair value measurements. If the carrying amount of a reporting unit exceeds the fair value, an impairment loss is recognized in the current period in an amount equal to the excess. 
+For purposes of assessing goodwill, the Company has one reporting unit. No goodwill impairment was identified during the years ended December 31, 2024 and 2023. 
+Leases 
+In accordance with ASC Topic 842, the Company determines if an arrangement is a lease at inception and evaluates identified leases for operating or finance lease treatment. Operating or finance lease right-of-use assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. The Company uses the rate implicit in the lease, when available, or an estimated fully collateralized incremental borrowing rate corresponding with the lease term and the information available at the commencement date in determining the present value of lease payments. Lease terms may include options to renew, however, the Company typically cannot determine its intent to renew a lease with reasonable certainty at inception. 
+Additionally, the Company is a lessor in several operating leases in which the lease equipment is carried at amortized cost. Depreciation expense is recorded on a straight-line basis over its useful life to the estimated residual value. The lessee may not purchase the leased equipment and must return such equipment by the lease’s scheduled maturity date. 
+Equity Investments 
+The Company may from time to time invest in equity securities of public and private companies. Equity investments are measured and recorded as follows: 
+Marketable equity investments are equity investments with a readily determinable fair value and are recorded at fair value on a recurring basis with changes in fair value, whether realized or unrealized, recorded through the income statement. Unrealized gains and losses resulting from changes in fair value are recorded in unrealized gain on investments, net. 
+Equity method investments are equity securities in investees we do not control, but over which we have the ability to exercise significant influence. Equity method investments are measured at cost minus impairment, if any, plus or minus the Company’s share of equity method investee income or loss, less distributions received as return on investment. 
+The Company’s share of equity method investee income or loss is recorded as a component of cost of services as the investee is a supplier of the Company, refer to Note 14—Related Party Transactions Nomad Proppant Services LLC for further discussion of the Company’s equity method investment. Equity method investments are monitored for other-than-temporary 
+F-13 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+decreases in investment value, which considers the severity and duration of a potential decline in fair value below cost and our ability and intent to hold the investment for a sufficient period of time to allow for recovery. 
+Income Taxes 
+Deferred income taxes are computed using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Deferred tax assets and liabilities are measured using the enacted tax rates in effect for the year in which the deferred tax asset or liability are expected to reverse. The Company classifies all deferred tax assets and liabilities as non-current. The Company records Global Intangible Low-Tax Income inclusion as a current period expense. 
+The Company evaluates its deferred tax assets quarterly and considers both positive and negative evidence in applying the guidance of ASC 740 Income Taxes (“ASC 740”) related to the realizability of its deferred tax assets. As of December 31, 2024 and 2023 there were no valuation allowances recorded against the Company’s deferred tax assets. 
+The Company recognizes the financial statement effects of a tax position when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. Previously recognized tax positions are reversed in the first period in which it is no longer more-likely-than-not that the tax position would be sustained upon examination. Income tax related interest and penalties, if applicable, are recorded as a component of the provision for income tax expense. 
+Tax Receivable Agreements 
+In connection with the IPO, on January 17, 2018, the Company entered into two Tax Receivable Agreements (the “TRAs”) with the R/C Energy IV Direct Partnership, L.P. and certain legacy owners that continued to own Liberty LLC Units (each such person and any permitted transferee, a “Tax Receivable Agreement Holder” and together, the “Tax Receivable Agreement Holders”). The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that the Company actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result, as applicable to each Tax Receivable Agreement Holder, of (i) certain increases in tax basis that occur as a result of the Company’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such Tax Receivable Agreement Holder’s Liberty LLC Units in connection with the IPO or pursuant to the exercise of the right (the “Redemption Right”) or the Company’s right (the “Call Right”), (ii) any net operating losses available to the Company as a result of the Corporate Reorganization, and (iii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRAs. 
+With respect to obligations the Company expects to incur under the TRAs (except in cases where the Company elects to terminate the TRAs early, the TRAs are terminated early due to certain mergers, asset sales, or other changes of control or the Company has available cash but fails to make payments when due), generally the Company may elect to defer payments due under the TRAs if the Company does not have available cash to satisfy its payment obligations under the TRAs or if its contractual obligations limit its ability to make such payments. Any such deferred payments under the TRAs generally will accrue interest. In certain cases, payments under the TRAs may be accelerated and/or significantly exceed the actual benefits, if any, the Company realizes in respect of the tax attributes subject to the TRAs. The Company accounts for amounts payable under the TRAs in accordance with ASC Topic 450, Contingencies . 
+If the Company experiences a change of control (as defined under the TRAs) or the TRAs otherwise terminate early, the Company’s obligations under the TRAs could have a substantial negative impact on its liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. 
+Share Repurchases 
+The Company accounts for the purchase price of repurchased Class A Common Stock in excess of par value ($ 0.01 per share of Class A Common Stock) as a reduction of additional paid-in capital, and will continue to do so until additional paid-in capital is reduced to zero. Thereafter, any excess purchase price will be recorded as a reduction to retained earnings. All Class A Common Stock shares repurchased to date have been retired upon repurchase. 
+Revenue Recognition 
+Under ASC Topic 606- Revenue from Contracts with Customers , revenue recognition is based on the transfer of control, or the customer’s ability to benefit from the services and products in an amount that reflects the consideration expected to be received in exchange for those services and products. In recognizing revenue for services and products, the transaction price is determined from sales orders or contracts with customers. Revenue is recognized at the completion of each fracturing stage, and 
+F-14 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+in most cases the price at the end of each stage is fixed, however, in limited circumstances contracts may contain variable consideration. 
+Variable consideration typically may relate to discounts, price concessions and incentives. The Company estimates variable consideration based on the amount of consideration we expect to receive. The Company accrues revenue on an ongoing basis to reflect updated information for variable consideration as performance obligations are met. 
+The Company also assesses customers’ ability and intention to pay, which is based on a variety of factors including historical payment experience and financial condition. Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30 to 45 days. 
+In connection with the adoption of ASC Topic 842, the Company determined that certain of its service revenue contracts contain a lease component. The Company elected to adopt a practical expedient available to lessors, which allows the Company to combine the lease and non-lease components and account for the combined component in accordance with the accounting treatment for the predominant component. Therefore, the Company combines the lease and service component for certain of the Company’s service contracts and continues to account for the combined component under ASC Topic 606, Revenue from Contracts with Customers. 
+Transaction and Other Costs 
+During 2024, the Company did not incur transaction and integration related costs. 
+During 2023, the Company incurred transaction and integration related costs in connection with the Siren Acquisition (as defined in Note 3—Acquisitions). Such costs include investment banking, legal, accounting and other professional services provided in connection with closing the transaction and are expensed as incurred . 
+During 2022, the Company incurred transaction and integration related costs in connection with a prior period acquisition. Such costs include investment banking, legal, accounting and other professional services provided in connection with closing the transaction and are expensed as incurred . 
+Foreign Currency Translation 
+The Company records foreign currency translation adjustments from the process of translating the functional currency of the financial statements of its foreign subsidiaries into the U.S. dollar reporting currency. The Canadian dollar and the Australian dollar are the functional currencies of the Company’s foreign subsidiaries as they are the primary currencies within the economic environment in which the subsidiaries operates. Assets and liabilities of the subsidiary’s operations are translated into U.S. dollars at the rate of exchange in effect on the balance sheet date and income and expenses are translated at the average exchange rate in effect during the reporting period. Adjustments resulting from the translation of the subsidiary’s financial statements are reported in other comprehensive income. 
+Recently Adopted Accounting Standards 
+Segment Reporting: Improvements to Reportable Segment Disclosures 
+In November 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2023-07, Segment Reporting: Improvements to Reportable Segment Disclosures , which requires more detailed disclosures, on an annual and interim basis, related to the Company’s reportable segment. The guidance is effective for annual periods beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. The Company adopted this guidance during the most recent quarter. See Note 1—Organization and Basis of Presentation for further detail. 
+Recently Issued Accounting Standards 
+Income Taxes: Improvements to Income Tax Disclosures 
+In December 2023, the FASB issued ASU No. 2023-09, Income Taxes: Improvements to Income Tax Disclosures , which requires disaggregation of certain components included in the Company’s effective tax rate and income taxes paid disclosures. The guidance is effective for annual periods beginning after December 15, 2024. The Company is currently assessing the impact of this ASU on the Company’s financial statements but does not expect it will have a material impact. 
+F-15 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures: Disaggregation of Income Statement Expenses 
+In November 2024, the FASB issued ASU No. 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures: Disaggregation of Income Statement Expenses , which requires disclosure of specified information about certain costs and expenses. The guidance is effective for annual periods beginning after December 15, 2026 and interim periods beginning after December 15, 2027. The Company is currently assessing the impact of this ASU on the Company’s financial statements. 
+Reclassifications 
+Certain amounts in the prior period financial statements have been reclassified to conform to current period financial statement presentation. Amounts in the prior period financial statements have been reclassified from “Tax withheld on vesting of restricted stock units” into “Vesting of restricted stock units, net” in the accompanying consolidated statements of changes in equity. 
+In the accompanying consolidated balance sheets, amounts in the prior period financial statements have been reclassified from “Other assets” into “Investment in Nomad Proppant Services LLC,” “Investment in Oklo Inc.,” and “Investment in Tamboran Resources Corporation”. 
+Additionally, in the accompanying consolidated statement of cash flows, amounts in the prior period financial statements have been reclassified from “Other non-cash items, net” into “Unrealized gain on investments, net”. 
+These reclassifications had no effect on the previously reported net income. 
+Note 3— Acquisitions 
+Siren Acquisition 
+On April 6, 2023, the Company completed the acquisition of a Permian focused integrated natural gas compression and compressed natural gas delivery business, Siren Energy & Logistics, LLC, for cash consideration of $ 75.7 million, after post closing adjustments and net of cash received (the “Siren Acquisition”). The Siren Acquisition was accounted for under the acquisition method of accounting for business combinations. Accordingly, the Company conducted assessments of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. In connection with the Siren Acquisition, the Company recorded goodwill of $ 42.0 million, property and equipment of $ 34.9 million, net working capital of $ 2.5 million, deferred revenue of $ 5.2 million, and other assets of $ 1.8 million. Goodwill is recorded in other assets in the accompanying consolidated balance sheets. Due to the immateriality of the Siren Acquisition, the related revenue and earnings, supplemental pro forma financial information, and detailed purchase price allocation are not disclosed. 
+In accordance with ASC Topic 805, an acquirer is allowed a period, referred to as the measurement period, in which to complete its accounting for the transaction. Such measurement period ends at the earliest date that the acquirer a) receives the information necessary or b) determines that it cannot obtain further information, and such period may not exceed one year. As the Siren Acquisition closed on April 6, 2023, the Company completed the purchase price allocation during the year ended December 31, 2023. 
+Note 4— Inventories 
+Inventories consist of the following: 
+December 31, 
+($ in thousands) 2024 2023 
+Proppants $ 9,341 $ 17,124 
+Chemicals 18,629 16,896 
+Maintenance parts and other 175,499 171,845 
+$ 203,469 $ 205,865 
+During the years ended December 31, 2024, 2023, and 2022, the lower of cost or net realizable value analysis resulted in the Company recording write-downs to the inventory carrying value of $ 1.0 million, $ 5.8 million, and $ 1.7 million, respectively. All are included as a component in cost of services in the consolidated statements of operations. 
+F-16 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Note 5— Property and Equipment 
+Property and equipment consist of the following: 
+Estimated 
+useful lives 
+(in years) December 31, 
+2024 2023 
+($ in thousands) 
+Land N/A $ 30,041 $ 29,384 
+Field services equipment 
+2 - 10 
+3,068,681 2,520,336 
+Vehicles 
+4 - 7 
+61,433 63,423 
+Lease equipment 10 163,889 138,781 
+Buildings and facilities 
+5 - 30 
+180,010 149,876 
+Mineral reserves 
+> 25 
+80,070 76,823 
+Office equipment and furniture 
+2 - 7 
+12,532 11,836 
+3,596,656 2,990,459 
+Less accumulated depreciation and depletion ( 1,917,551 ) ( 1,501,685 ) 
+1,679,105 1,488,774 
+Construction in-progress N/A 211,893 156,594 
+Property and equipment, net $ 1,890,998 $ 1,645,368 
+Depreciation expense for the years ended December 31, 2024, 2023, and 2022 was $ 448.1 million, $ 387.8 million, and $ 302.3 million, respectively. Depletion expense for the years ended December 31, 2024, 2023, and 2022 was $ 1.2 million, $ 1.1 million, and $ 1.2 million, respectively. 
+As of December 31, 2024 and December 31, 2023, the Company concluded that no triggering events that could indicate possible impairment of property and equipment had occurred, other than related to the assets held for sale discussed below. 
+As of December 31, 2024, the Company had no property that met the assets held for sale criteria. 
+However, as of December 31, 2023, the Company classified $ 0.7 million of land and $ 0.8 million of buildings, net of accumulated depreciation, of one property as held for sale. 
+During the year ended December 31, 2024, the Company sold two properties, including the property that was classified as held for sale as of December 31, 2023, resulting in a nominal gain included as a component of gain on disposal of assets, net in the accompanying consolidated statements of operations. 
+Note 6— Leases 
+Lessee Arrangements 
+The Company has operating and finance leases primarily for vehicles, equipment, railcars, office space, and facilities. The terms and conditions for these leases vary by the type of underlying asset. 
+Certain leases include variable lease payments for items such as property taxes, insurance, maintenance, and other operating expenses associated with leased assets. Payments that vary based on an index or rate are included in the measurement of lease assets and liabilities at the rate as of the commencement date. All other variable lease payments are excluded from the measurement of lease assets and liabilities, and are recognized in the period in which the obligation for those payments is incurred. 
+The components of lease expense for the years ended as of December 31, 2024, and 2023 were as follows: 
+($ in thousands) 2024 2023 
+Finance lease cost: 
+Amortization of right-of-use assets $ 43,364 $ 19,040 
+Interest on lease liabilities 16,972 6,060 
+Operating lease cost 35,861 40,275 
+Variable lease cost 6,392 5,116 
+Short-term lease cost 3,422 7,717 
+Total lease cost, net $ 106,011 $ 78,208 
+F-17 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Supplemental cash flow and other information related to leases for the years ended December 31, 2024 and 2023 were as follows: 
+($ in thousands) 2024 2023 
+Cash paid for amounts included in measurement of liabilities: 
+Operating leases $ 35,653 $ 41,143 
+Finance leases 67,181 23,463 
+Right-of-use assets obtained in exchange for new lease liabilities: 
+Operating leases 14,581 31,449 
+Finance leases 149,005 160,546 
+During the year ended December 31, 2024, the Company amended certain operating leases, the change in terms of which caused the leases to be reclassified as finance leases. Additionally, the Company recognized finance lease right-of-use assets of $ 4.4 million and liabilities of $ 4.3 million. There was no gain or loss recognized as a result of these amendments. During the year ended December 31, 2023, the Company did not amend any operating or finance leases. 
+Lease terms and discount rates as of December 31, 2024 and 2023 were as follows: 
+December 31, 2024 December 31, 2023 
+Weighted-average remaining lease term: 
+Operating leases 3.8 years 4.3 years 
+Finance leases 3.2 years 3.3 years 
+Weighted-average discount rate: 
+Operating leases 6.7 % 6.0 % 
+Finance leases 7.4 % 8.0 % 
+Future minimum lease commitments as of December 31, 2024 are as follows: 
+($ in thousands) Finance Operating 
+2025 $ 87,476 $ 31,771 
+2026 85,503 21,496 
+2027 55,016 11,932 
+2028 60,381 3,935 
+2029 21,625 2,795 
+Thereafter — 9,874 
+Total lease payments 310,001 81,803 
+Less imputed interest 39,842 8,856 
+Total $ 270,159 $ 72,947 
+The Company’s vehicle leases typically include a residual value guarantee. For the Company’s vehicle leases classified as operating leases, the total residual value guaranteed as of December 31, 2024 is $ 11.6 million; the payment is not probable and therefore has not been included in the measurement of the lease liability and right-of-use asset. For vehicle leases that are classified as finance leases, the Company includes the residual value guarantee, estimated in the lease agreement, in the financing lease liability. 
+Lessor Arrangements 
+The Company leases dry and wet sand containers, conveyor belts, and other equipment to customers through operating leases, where the lessor for tax purposes is considered to be the owner of the equipment during the term of the lease. The lease agreements do not include options for the lessee to purchase the underlying asset at the end of the lease term for either a stated fixed price or fair market value. However, some of the leases contain a termination clause in which the customer can cancel the contract. The leases can be subject to variable lease payments if the customer requests more units than what is agreed upon in the lease. The Company does not record any lease assets or liabilities related to these variable items. 
+F-18 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+The carrying amount of equipment leased to others, included in property, plant and equipment, under operating leases as of December 31, 2024 and 2023 were as follows: 
+($ in thousands) December 31, 2024 December 31, 2023 
+Equipment leased to others - at original cost $ 163,889 $ 138,781 
+Less: Accumulated depreciation ( 41,223 ) ( 25,819 ) 
+Equipment leased to others - net $ 122,666 $ 112,962 
+Future payments receivable for operating leases as of December 31, 2024 are as follows: 
+($ in thousands) 
+2025 $ 5,412 
+2026 2,239 
+2027 — 
+2028 — 
+2029 — 
+Thereafter — 
+Total $ 7,651 
+Revenues from operating leases for the years ended December 31, 2024 and 2023 were $ 39.0 million and $ 36.6 million, respectively. 
+Note 7— Accrued Liabilities 
+Accrued liabilities consist of the following: 
+($ in thousands) December 31, 2024 December 31, 2023 
+Accrued vendor invoices $ 73,591 $ 99,620 
+Operations accruals 56,375 61,150 
+Accrued benefits and other 76,747 100,296 
+$ 206,713 $ 261,066 
+Note 8— Debt 
+Debt consists of the following: 
+($ in thousands) December 31, 2024 December 31, 2023 
+Revolving Line of Credit $ 190,500 $ 140,000 
+On September 19, 2017, the Company entered into two credit agreements, (i) a revolving line of credit up to $ 250.0 million, subsequently increased to $ 525.0 million, see below, (the “ABL Facility”) and (ii) a $ 175.0 million term loan (the “Term Loan Facility”). 
+Effective January 23, 2023, the Company entered into an Eighth Amendment to the ABL Facility (the “Eighth ABL Amendment”). The Eighth ABL Amendment amends certain terms, provisions and covenants of the ABL Facility, including, among other things: (i) increasing the maximum revolver amount from $ 425.0 million to $ 525.0 million (the “Upsized Revolver”); (ii) increasing the amount of the accordion feature from $ 75.0 million to $ 100.0 million; (iii) extending the maturity date from October 22, 2026 to January 23, 2028; (iv) modifying the dollar amounts of various credit facility triggers and tests proportionally to the Upsized Revolver; (v) permitting repayment under the Term Loan Facility prior to February 10, 2023; and (vi) increasing certain indebtedness, intercompany advance, and investment baskets. The Eighth ABL Amendment included an agreement from the Wells Fargo Bank, National Association, as administrative agent, to release its second priority liens and security interests on all collateral that served as first priority collateral under the Term Loan Facility, which was completed during the three months ended June 30, 2023. 
+Additionally, on January 23, 2023, the Company borrowed $ 106.7 million on the ABL Facility and used the proceeds to pay off and terminate the Term Loan Facility. The amount paid included the balance of the Term Loan Facility at pay off of $ 104.7 million, $ 0.9 million of accrued interest, and a $ 1.1 million prepayment premium. Additionally, there were $ 0.2 million in administrative and lender legal fees incurred in connection with the pay off. 
+F-19 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+The weighted average interest rate on all borrowings outstanding as of December 31, 2024 and December 31, 2023 was 6.8 % and 7.6 %, respectively. 
+Term Loan Facility 
+The Term Loan Facility provided for a $ 175.0 million term loan. In connection with the Eighth ABL Amendment and payoff of the Term Loan Facility, on January 23, 2023, the Company terminated the Term Loan Facility. See above for further discussion. 
+ABL Facility 
+Under the terms of the ABL Facility, up to $ 525.0 million may be borrowed, subject to certain borrowing base limitations based on a percentage of eligible accounts receivable and inventory. As of December 31, 2024, the borrowing base was calculated to be $ 319.8 million, and the Company had $ 190.5 million outstanding in addition to letters of credit totaling $ 14.0 million, with $ 115.3 million of remaining availability. Borrowings under the ABL Facility bear interest at Secured Overnight Financing Rate (“SOFR”) or a base rate, plus an applicable SOFR margin of 1.5 % to 2.0 % or base rate margin of 0.5 % to 1.0 %, as described in the ABL Facility credit agreement (the “ABL Facility credit agreement”). Additionally, borrowings as of December 31, 2024 incurred interest at a weighted average rate of 6.8 %. The average monthly unused commitment is subject to an unused commitment fee of 0.25 % to 0.375 %. Interest and fees are payable in arrears at the end of each month, or, in the case of SOFR loans, at the end of each interest period. The ABL Facility matures on January 23, 2028. Borrowings under the ABL Facility are collateralized by accounts receivable and inventory, and further secured by the Company, as parent guarantor. 
+The ABL Facility includes certain non-financial covenants, including but not limited to restrictions on incurring additional debt and certain distributions. Moreover, the ability of the Company to incur additional debt and to make distributions is dependent on maintaining a maximum leverage ratio. 
+The ABL Facility is not subject to financial covenants unless liquidity, as defined in the ABL Facility credit agreement, drops below a specific level. The Company is required to maintain a minimum fixed charge coverage ratio, as defined in the ABL Facility credit agreement, of 1.0 to 1.0 for each period if excess availability is less than 10 % of the borrowing base or $ 52.5 million, whichever is greater. 
+The Company was in compliance with these covenants as of December 31, 2024. 
+Maturities of debt are as follows: 
+($ in thousands) 
+Years Ending December 31, 
+2025 $ — 
+2026 — 
+2027 — 
+2028 190,500 
+Thereafter — 
+$ 190,500 
+Note 9— Fair Value Measurements and Financial Instruments 
+The fair values of the Company’s assets and liabilities represent the amounts that would be received to sell those assets or that would be paid to transfer those liabilities in an orderly transaction on the reporting date. These fair value measurements maximize the use of observable inputs. However, in situations where there is little, if any, market activity for the asset or liability on the measurement date, the fair value measurement reflects the Company’s own judgments about the assumptions that market participants would use in pricing the asset or liability. The Company discloses the fair values of its assets and liabilities according to the quality of valuation inputs under the following hierarchy: 
+• Level 1 Inputs: Quoted prices (unadjusted) in an active market for identical assets or liabilities. 
+• Level 2 Inputs: Inputs other than quoted prices that are directly or indirectly observable. 
+• Level 3 Inputs: Unobservable inputs that are significant to the fair value of assets or liabilities. 
+The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those that are initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from unobservable inputs is inconsequential to the overall fair value, or if corroborating market data becomes available. Assets and liabilities that are initially reported as Level 2 are subsequently reported as Level 3 if corroborating market data is no longer available. Transfers 
+F-20 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+occur at the end of the reporting period. There were no transfers into or out of Levels 1, 2, and 3 during the years ended December 31, 2024 and 2023. 
+The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, notes receivable, investments in equity securities, accounts payable, accrued liabilities, long-term debt, and finance and operating lease obligations. The carrying values of all of the Company’s financial instruments included in the accompanying consolidated balance sheets approximated or equaled their fair values on December 31, 2024 and 2023. 
+• The carrying values of cash and cash equivalents, accounts receivable, and accounts payable (including accrued liabilities) approximated fair value on December 31, 2024 and 2023, due to their short-term nature. 
+• The carrying value of investments in equity securities were measured at fair value on December 31, 2024 based on quoted prices in active markets. 
+• The carrying value of amounts outstanding under long-term debt agreements with variable rates approximated fair value on December 31, 2024 and 2023, as the effective interest rates approximated market rates. 
+• The carrying values of amounts outstanding under finance and operating lease obligations approximated fair value on December 31, 2024 and 2023, as the effective borrowing rates approximated market rates. 
+Nonrecurring Measurements 
+Certain assets and liabilities are measured at fair value on a nonrecurring basis. These items are not measured at fair value on an ongoing basis but may be subject to fair value adjustments in certain circumstances. These assets and liabilities include those acquired through the Siren Acquisition, which are required to be measured at fair value on the acquisition date in accordance with ASC Topic 805 . See Note 3—Acquisitions. 
+During the year ended December 31, 2024, the Company sold two properties classified as held for sale resulting in a nominal gain included as a component of gain on disposal of assets, net in the accompanying consolidated statements of operations. Therefore, as of December 31, 2024, the Company had no property that met the assets held for sale criteria. 
+As of December 31, 2023, the Company recorded $ 0.7 million of land and $ 0.8 million of buildings of one property that met the held for sale criteria, to assets held for sale at a total fair value of $ 0.8 million, which are included in prepaid and other current assets in the accompanying consolidated balance sheets. The Company estimated the fair value of the property based on a communicated selling price for one property, which is a Level 3 input. The Company estimated that the carrying value of the assets is equal to the fair value less the estimated costs to sell, net of write-downs taken in the prior period, and therefore no gain or loss was recorded during the year ended December 31, 2023. 
+Other assets measured at fair value on a nonrecurring basis consisted of notes receivable—related party, which was recorded for trade receivables, created in the normal course of business, due from the Affiliate as of the Agreement Date, as defined and described in Note 14—Related Party Transactions. These notes were classified as Level 3 in the fair value hierarchy as the inputs to the determination of fair value were based upon unobservable inputs. During the year ended December 31, 2024, the notes were paid in full and therefore none was outstanding as of December 31, 2024. As of December 31, 2023, notes receivable—related party from the Affiliate was $ 14.8 million. 
+Recurring Measurements 
+The fair values of the Company’s cash equivalents measured on a recurring basis pursuant to ASC 820-10 Fair Value Measurements and Disclosures are carried at estimated fair value. Cash equivalents consist of money market accounts which the Company has classified as Level 1 given the active market for these accounts. As of December 31, 2024 and 2023, the Company had cash equivalents, measured at fair value, of $ 0.3 million and $ 0.3 million, respectively. 
+The Company holds an investment in Oklo Inc. (“Oklo”) made during the three months ended September 30, 2023. In May 2024, Oklo was acquired by a publicly traded special purpose acquisition company which resulted in the conversion of the Company’s investment into common shares of Oklo, which are traded on the New York Stock Exchange. The Company measures this investment in equity securities at fair value using Level 1 inputs based on quoted prices in an active market. As of December 31, 2024, the fair value of the investment was estimated at $ 51.6 million. The change in Oklo’s fair value resulted in an unrealized gain of $ 41.6 million during the year ended December 31, 2024, included in unrealized gain on investments, net in the accompanying consolidated statements of operations. 
+F-21 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Additionally, during the three months ended December 31, 2023, the Company purchased depository interests representing shares of common stock in Tamboran Resources Corporation (“Tamboran”). In June 2024, Tamboran completed an initial public offering and listed its common stock on the New York Stock Exchange. In addition to the prior purchase of depository interests, the Company participated in Tamboran’s initial public offering by purchasing an additional $ 10.0 million of Tamboran’s common stock. The Company measures this investment in equity securities at fair value using Level 1 inputs based on quoted prices in an active market. As of December 31, 2024, the fair value of the investment was estimated at $ 18.8 million. The change in Tamboran’s fair value resulted in an unrealized loss of $ 1.5 million during the year ended December 31, 2024, included in unrealized gain on investments, net in the accompanying consolidated statements of operations. 
+Nonfinancial assets 
+The Company estimates fair value to perform impairment tests as required on long-lived assets. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3 in the event that such assets were required to be measured and recorded at fair value within the consolidated financial statements. No such measurements were required as of December 31, 2024 and 2023 as no triggering event was identified. 
+Credit Risk 
+The Company’s financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents, and trade receivables. 
+The Company’s cash and cash equivalents balance on deposit with financial institutions total $ 20.0 million and $ 36.8 million as of December 31, 2024 and 2023, respectively, which exceeded Federal Deposit Insurance Corporation insured limits. The Company regularly monitors these institutions’ financial condition. 
+The majority of the Company’s customers have payment terms of 45 days or less. 
+As of December 31, 2024, Customer A and Customer B accounted for 13.7 % and 10.4 %, respectively, of total consolidated accounts receivable and unbilled revenue. As of December 31, 2023, no customers accounted for 10% of total consolidated accounts receivable and unbilled revenue. During the year ended December 31, 2024, Customer C accounted for 11.8 % of consolidated revenues. During the years ended December 31, 2023, and 2022, no customers accounted for 10% of consolidated revenues. 
+The Company mitigates the associated credit risk by performing credit evaluations and monitoring the payment patterns of its customers. 
+As of December 31, 2024, the Company had $ 0.8 million in allowance for credit losses. As of December 31, 2023 and 2022, the Company had $ 0.9 million in allowance for credit losses and recorded a provision in 2023 related to certain customers’ expected inability to pay. 
+The Company applies historic loss factors to its receivable portfolio segments that are not expected to be further impacted by current economic developments, and an additional economic conditions factor to portfolio segments anticipated to experience greater losses in the current economic environment. While the Company has not experienced significant credit losses in the past and has not seen material changes to the payment patterns of its customers, the Company cannot predict with any certainty the degree to which unforeseen events may affect the ability of its customers to timely pay receivables when due. Accordingly, in future periods, the Company may revise its estimates of expected credit losses. 
+($ in thousands) 2024 2023 2022 
+Allowance for credit losses, beginning of year $ 939 $ 884 $ 884 
+Credit losses: 
+Current period provision — 808 — 
+Amounts written off, net of recoveries ( 91 ) ( 753 ) — 
+Allowance for credit losses, end of year $ 848 $ 939 $ 884 
+F-22 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Note 10— Equity 
+Preferred Stock 
+As of December 31, 2024 and 2023, the Company had 10,000 shares of preferred stock authorized, par value $ 0.01 , with none issued and outstanding. If issued, each class or series of preferred stock will cover the number of shares and will have the powers, preferences, rights, qualifications, limitations and restrictions determined by the Company’s board of directors, which may include, among others, dividend rights, liquidation preferences, voting rights, conversion rights, preemptive rights and redemption rights. Except as provided by law or in a preferred stock designation, the holders of preferred stock will not be entitled to vote at or receive notice of any meeting of shareholders. 
+Class A Common Stock 
+The Company had a total of 161,858,784 and 166,610,199 shares of Class A Common Stock outstanding as of December 31, 2024 and 2023, respectively, none of which were restricted. Holders of Class A Common Stock are entitled to one vote per share on all matters to be voted upon by the stockholders and are entitled to ratably receive dividends when and if declared by the Company’s board of directors. 
+Class B Common Stock 
+The Company had no shares of Class B Common Stock outstanding as of December 31, 2024 and 2023, respectively. Effective January 31, 2023, in connection with the Merger, all outstanding shares of the Class B Common Stock were redeemed and exchanged, with no shares remaining outstanding as of December 31, 2024. 
+Long Term Incentive Plan 
+On January 11, 2018, the Company adopted the Long Term Incentive Plan (“LTIP”) to incentivize employees, officers, directors and other service providers of the Company and its affiliates. The LTIP provides for the grant, from time to time, at the discretion of the Company’s board of directors or a committee thereof, of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, cash awards, substitute awards and performance awards. Subject to adjustment in the event of certain transaction or changes of capitalization in accordance with the LTIP, 12,908,734 shares of Class A Common Stock were initially reserved for issuance pursuant to awards under the LTIP. Effective April 16, 2024, following receipt of stockholder approval, the Company adopted the amended and restated the LTIP, which, among other things, increased the total number of shares authorized for issuance under the amended and restated LTIP, including shares already issued, to 21,239,244 shares of Class A Common Stock. Class A Common Stock subject to an award that expires or is canceled, forfeited, exchanged, settled in cash or otherwise terminated without delivery of shares will again be available for delivery pursuant to other awards under the LTIP. 
+Restricted Stock Units 
+Restricted stock units (“RSUs”) granted pursuant to the LTIP, if they vest, will be settled in shares of the Company’s Class A Common Stock. RSUs were granted with vesting terms up to three years . Changes in non-vested RSUs outstanding under the LTIP during the year ended December 31, 2024 were as follows: 
+Number of Units Weighted Average Grant Date Fair Value per Unit 
+Non-vested as of December 31, 2023 2,985,218 $ 13.90 
+Granted 1,519,597 19.46 
+Vested ( 1,491,085 ) 13.53 
+Forfeited ( 75,322 ) 15.18 
+Outstanding at December 31, 2024 2,938,408 $ 16.93 
+F-23 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Performance Restricted Stock Units 
+Performance restricted stock units (“PSUs”) granted pursuant to the LTIP, if they vest, will be settled in shares of the Company’s Class A Common Stock. PSUs were granted with a three-year cliff vesting and performance period, with the vesting percentage of the target award dependent on the satisfaction of the performance goals set forth in the applicable award agreement. The Company records compensation expense based on the Company’s best estimate of the number of PSUs that will vest at the end of the performance period. If such performance targets are not met, or are not expected to be met, no compensation expense is recognized and any recognized compensation expense is reversed. Changes in non-vested PSUs outstanding under the LTIP during the year ended December 31, 2024 were as follows: 
+Number of Units Weighted Average Grant Date Fair Value per Unit 
+Non-vested as of December 31, 2023 1,339,568 $ 13.49 
+Granted 352,091 17.65 
+Vested ( 584,720 ) 12.95 
+Forfeited — — 
+Outstanding at December 31, 2024 1,106,939 $ 15.10 
+Stock-based compensation is included in cost of services and general and administrative expenses in the Company’s consolidated statements of operations. The Company recognized stock-based compensation expense of $ 32.4 million, $ 33.0 million, and $ 23.1 million for the years ended December 31, 2024, 2023, and 2022, respectively. There was approximately $ 39.3 million of unrecognized compensation expense relating to outstanding RSUs and PSUs as of December 31, 2024. The unrecognized compensation expense will be recognized on a straight-line basis over the weighted average remaining vesting period of two years . 
+Dividends 
+On October 18, 2022, the Company’s Board of Directors (the “Board”) reinstated quarterly dividends after they were suspended on April 2, 2020. 
+The Company paid cash dividends of $ 0.07 per share of Class A Common Stock on March 20, 2024, June 20, 2024, and September 20, 2024 to stockholders of record as of March 6, 2024, June 6, 2024, and September 6, 2024, respectively. Additionally, the Company paid cash dividends of $ 0.08 per share of Class A Common Stock on December 20, 2024 to stockholders of record as of December 6, 2024. During the year ended December 31, 2024, dividend payments totaled $ 47.7 million. 
+The Company paid cash dividends of $ 0.05 per share of Class A Common Stock on March 20, 2023, June 20, 2023, and September 20, 2023 to stockholders of record as of March 6, 2023, June 6, 2023, and September 6, 2023, respectively. Additionally, the Company paid cash dividends of $ 0.07 per share of Class A Common Stock on December 20, 2023 to stockholders of record as of December 6, 2023. During the year ended December 31, 2023, dividend payments totaled $ 37.5 million. 
+The Company paid cash dividends of $ 0.05 per share of Class A Common Stock on December 20, 2022 to stockholders of record as of December 6, 2022. Liberty LLC paid a distribution of $ 9.0 million, or $ 0.05 per Liberty LLC Unit, to all Liberty LLC unit holders as of December 6, 2022, $ 9.0 million of which was paid to the Company. The Company used the proceeds of the distribution to pay the dividend to all holders of shares of Class A Common Stock as of December 6, 2022, which totaled $ 9.0 million. 
+Additionally, the Company paid an accrued dividend equivalent upon vesting for the RSUs and PSUs with a 2024 vesting date, which totaled $ 0.7 million and $ 0.2 million for the years ended December 31, 2024 and 2023, respectively. As of December 31, 2024 and 2023, the Company had $ 1.5 million and $ 1.0 million of dividend equivalents payable related to RSUs and PSUs to be paid upon vesting, respectively. Dividend equivalents related to forfeited RSUs or PSUs will be forfeited. 
+F-24 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Share Repurchase Program 
+On July 25, 2022, the Company’s board of directors authorized and the Company announced a share repurchase program that allowed the Company to repurchase up to $ 250.0 million of the Company’s Class A Common Stock beginning immediately and continuing through July 31, 2024. On January 24, 2023, the Board authorized and the Company announced an increase of the cumulative repurchase authorization to $ 500.0 million. Furthermore, on January 23, 2024 the Board authorized and the Company announced an increase of the cumulative repurchase authorization to $ 750.0 million and extended the authorization through July 31, 2026. The shares may be repurchased from time to time in open market transactions, through block trades, in privately negotiated transactions, through derivative transactions, or by other means in accordance with applicable state and federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will be determined by the Company at its discretion and will depend on a variety of factors, including management’s assessment of the intrinsic value of the Company’s Class A Common Stock, the market price of the Company’s Class A Common Stock, general market and economic conditions, available liquidity, compliance with the Company’s debt and other agreements, applicable legal requirements, and other considerations. The exact number of shares to be repurchased by the Company is not guaranteed, and the program may be suspended, modified, or discontinued at any time without prior notice. The Company expects to fund any repurchases by using cash on hand, borrowings under the ABL Facility and expected free cash flow to be generated through the duration of the share repurchase program. 
+Year Ended December 31, Year Ended December 31, Year Ended December 31, 
+($ in thousands, except share count and per share data) 2024 2023 2022 
+Shares of Class A Common Stock 6,320,536 13,705,622 8,185,890 
+Cost of shares repurchased $ 127,395 $ 203,100 $ 125,313 
+Average price per share including commissions $ 20.16 $ 14.82 $ 15.31 
+As of December 31, 2024, $ 294.2 million remained authorized for future repurchases of Class A Common Stock under the share repurchase program. 
+The Company accounts for the purchase price of repurchased common shares in excess of par value ($ 0.01 per share of Class A Common Stock) as a reduction of additional paid-in capital, and will continue to do so until additional paid-in capital is reduced to zero. Thereafter, any excess purchase price will be recorded as a reduction to retained earnings. 
+As enacted by the Inflation Reduction Act of 2022 (the “Inflation Reduction Act”), the Company accrued stock repurchase excise tax of $ 0.9 million and $ 1.9 million for the years ended December 31, 2024 and 2023, respectively. As of December 31, 2024 and 2023, the Company had excise tax payables of $ 0.9 million and $ 1.9 million, respectively, in accrued liabilities in the accompanying consolidated balance sheets. 
+Note 11— Net Income per Share 
+Basic net income per share measures the performance of an entity over the reporting period. Diluted net income per share measures the performance of an entity over the reporting period while giving effect to all potentially dilutive common shares that were outstanding during the period. The Company uses the “if-converted” method to determine the potential dilutive effect of its Class B Common Stock and the treasury stock method to determine the potential dilutive effect of outstanding RSUs and PSUs. 
+F-25 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+The following table reflects the allocation of net income to common stockholders and net income per share computations for the periods indicated based on a weighted average number of shares of Class A Common Stock and Class B Common Stock outstanding: 
+(In thousands, except per share data) Year Ended December 31, 2024 Year Ended December 31, 2023 
+Basic Net Income Per Share 
+Numerator: 
+Net income attributable to Liberty Energy Inc. stockholders $ 316,010 $ 556,317 
+Denominator: 
+Basic weighted average common shares outstanding 165,026 171,845 
+Basic net income per share attributable to Liberty Energy Inc. stockholders $ 1.91 $ 3.24 
+Diluted Net Income Per Share 
+Numerator: 
+Net income attributable to Liberty Energy Inc. stockholders $ 316,010 $ 556,317 
+Effect of exchange of the shares of Class B Common Stock for shares of Class A Common Stock — 73 
+Diluted net income attributable to Liberty Energy Inc. stockholders $ 316,010 $ 556,390 
+Denominator: 
+Basic weighted average shares outstanding 165,026 171,845 
+Effect of dilutive securities: 
+Restricted stock units 4,372 4,494 
+Class B Common Stock — 21 
+Diluted weighted average shares outstanding 169,398 176,360 
+Diluted net income per share attributable to Liberty Energy Inc. stockholders $ 1.87 $ 3.15 
+Note 12— Income Taxes 
+The Company is a corporation and is subject to taxation in the United States, Canada, Australia and various state, local and provincial jurisdictions. Historically, Liberty LLC was treated as a partnership, and its income was passed through to its owners for income tax purposes. Liberty LLC’s members, including the Company, were liable for federal, state and local income taxes based on their share of Liberty LLC’s pass-through taxable income. 
+Effective January 31, 2023, the Company adopted a plan of merger, pursuant to which Liberty LLC merged into the Company, ceasing the existence of Liberty LLC with the Company remaining as the surviving entity. Liberty LLC filed a final tax return during the 2023 calendar year. The Company is still party to the TRAs; the associated liabilities are discussed below. 
+As of December 31, 2024, tax reporting by the Company for the years ended December 31, 2021, 2022, 2023, and the short period ended January 31, 2023 are subject to examination by the tax authorities. With few exceptions, as of December 31, 2024, the Company is no longer subject to U.S. federal, state or local examinations by tax authorities for tax years ended on or before December 31, 2020. 
+The components of the Company’s income from continuing operations before income taxes on which the provision for income taxes was computed consisted of the following: 
+Year Ended December 31, 
+($ in thousands) 2024 2023 2022 
+United States $ 356,340 $ 668,338 $ 375,758 
+Foreign 46,931 66,552 23,751 
+Total $ 403,271 $ 734,890 $ 399,509 
+F-26 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+The components of the provision for incomes taxes from continuing operations are summarized as follows: 
+Year Ended December 31, 
+($ in thousands) 2024 2023 2022 
+Current: 
+Federal $ 33,474 $ 36,319 $ 4,679 
+State 6,637 4,662 2,579 
+Foreign 13,306 17,189 4,421 
+Total Current $ 53,417 $ 58,170 $ 11,679 
+Deferred: 
+Federal $ 32,087 $ 109,399 $ ( 12,967 ) 
+State 3,289 11,913 ( 1,182 ) 
+Foreign ( 1,532 ) ( 1,000 ) 1,677 
+Total Deferred $ 33,844 $ 120,312 $ ( 12,472 ) 
+Income tax expense (benefit) $ 87,261 $ 178,482 $ ( 793 ) 
+Income tax expense (benefit) attributable to net income (loss) before income taxes differed from the amounts computed by applying the statutory U.S. federal income tax rate of 21.0% to pre-tax income as a result of the following: 
+Year Ended December 31, 
+($ in thousands) 2024 2023 2022 
+Computed tax expense at the statutory rate $ 84,687 $ 154,327 $ 83,897 
+Increase (decrease) in tax expense resulting from: 
+State and local income tax expense, net 9,340 15,745 10,224 
+Non-controlling interest — ( 19 ) ( 151 ) 
+Effect of foreign tax rates 1,231 1,818 697 
+Stock-based compensation ( 1,771 ) ( 239 ) ( 2,724 ) 
+Change in valuation allowance — — ( 91,336 ) 
+Other TRA adjustment 181 ( 248 ) ( 2,763 ) 
+U.S. Federal tax credits ( 6,743 ) — — 
+Nondeductible executive compensation 2,920 6,514 — 
+U.S. impact of foreign earnings — — 315 
+Other, net ( 2,584 ) 584 1,048 
+Total income tax expense (benefit) $ 87,261 $ 178,482 $ ( 793 ) 
+The effective tax rate for the years ended December 31, 2024, 2023, and 2022 was 21.6 %, 24.3 %, and ( 0.2 )%, respectively. 
+The Company’s effective tax rate is greater than the statutory federal income tax rate of 21.0% due to the Company’s Canadian operations, state income taxes in the states the Company operates, as well as nondeductible executive compensation, partially offset by U.S. federal income tax credits. 
+F-27 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are presented below: 
+($ in thousands) December 31, 2024 December 31, 2023 
+Deferred tax assets: 
+Federal tax credit $ 9,615 $ — 
+State net operating losses 859 1,286 
+Foreign net operating losses 920 — 
+Realized tax benefit - TRAs 79,175 87,260 
+Intangibles 22,440 22,825 
+Lease liabilities 67,603 51,504 
+Stock-based compensation 4,494 4,279 
+Inventory 2,604 3,361 
+Other 10,674 5,133 
+Total deferred tax assets 198,384 175,648 
+Deferred tax liabilities: 
+Property and equipment ( 233,649 ) ( 221,337 ) 
+Lease assets ( 83,137 ) ( 55,801 ) 
+Other ( 17,782 ) ( 850 ) 
+Total deferred tax liabilities ( 334,568 ) ( 277,988 ) 
+Net deferred tax (liability) $ ( 136,184 ) $ ( 102,340 ) 
+During the year ended December 31, 2023, the Company adopted a plan of merger, pursuant to which Liberty LLC merged into the Company, ceasing the existence of Liberty LLC with the Company remaining as the surviving entity. As a result of this change, the Company no longer has a deferred tax liability for the difference between the book value and the tax value of the Company’s investment in Liberty LLC and the associated net deferred tax liability balances have been allocated to the deferred tax asset and liability line items above. Significant deferred tax assets include the step up in basis of depreciable assets under Section 754 (“Section 754”) of the Internal Revenue Code of 1986, as amended and deferred tax liabilities related to property and equipment. 
+As of December 31, 2024, the Company has utilized all U.S. federal net operating loss carryforwards and has $ 0.9 million state net operating loss carryforwards that will not expire in the foreseeable future. The Company also has $ 9.6 million U.S. federal income tax credits that will not expire for twenty years . 
+On October 8, 2021, the Organization for Economic Co-operation and Development (“OECD”) released a statement on the OECD/G20 Inclusive Framework on Base Erosion and Profit Shifting, which agreed to a two-pillar solution to address tax challenges of the digital economy. On December 20, 2021, the OECD released Pillar Two model rules defining a 15% global minimum tax rate for large multinational corporations (the “Pillar Two Framework”). On June 20, 2024 and December 23, 2024, Canada and Australia, respectively, enacted the Pillar Two global minimum tax regime, which is not expected to have a material impact on the Company’s financial statements for the fiscal year ended December 31, 2024. The OECD continues to release additional guidance and countries are implementing legislation, with widespread adoption of the Pillar Two Framework expected by 2025. The Company is continuing to evaluate the Pillar Two Framework and its potential impact on future periods, including any legislation enacted in the jurisdictions in which the Company operates. 
+The Company may distribute cash from foreign subsidiaries to its U.S. parent as business needs arise. The Company has not provided for deferred income taxes on the undistributed earnings from certain foreign subsidiaries earnings as such earnings are considered to be indefinitely reinvested. If such earnings were to be distributed, any income and/or withholding tax would not be significant. 
+During the year ended December 31, 2024, the Company entered into a Tax Credit Transfer Agreement (“TCTA”) with a third-party seller, pursuant to which the Company agreed to purchase up to $ 33.5 million of transferable tax credits under the Inflation Reduction Act. The benefit for the federal income tax credits purchased has been recognized as a reduction to the Company’s income tax expense in the current period. 
+F-28 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Uncertain Tax Positions 
+The Company records uncertain tax positions on the basis of a two-step process in which (1) the Company determines whether it is more likely than not the tax positions will be sustained on the basis of the technical merits of the position and (2) for those tax positions meeting the more likely than not recognition threshold, the Company recognizes the largest amount of tax benefit that is more than 50% likely to be realized upon ultimate settlement with the related tax authority. 
+The Company determined that no liability for unrecognized tax benefits for uncertain tax positions was required at December 31, 2024. In addition, the Company does not believe that it has any tax positions for which it is reasonably possible that it will be required to record a significant liability for unrecognized tax benefits within the next twelve months. If the Company were to record an unrecognized tax benefit, the Company will recognize applicable interest and penalties related to income tax matters in income tax expense. 
+Tax Receivable Agreements 
+The term of each TRA commenced on January 17, 2018, and will continue until all such tax benefits that are subject to such TRA have been utilized or expired, unless the Company experiences a change of control (as defined in the TRAs, which includes certain mergers, asset sales and other forms of business combinations) or the TRAs are terminated early (at the Company’s election or as a result of its breach), and the Company makes the termination payments specified in such TRA. 
+The amounts payable, as well as the timing of any payments, under the TRAs are dependent upon significant future events and assumptions, including the timing of the redemptions of Liberty LLC Units, the price of our Class A Common Stock at the time of each redemption, the extent to which such redemptions are taxable transactions, the amount of the redeeming unit holder’s tax basis in its Liberty LLC Units at the time of the relevant redemption, the characterization of the tax basis step-up, the depreciation and amortization periods that apply to the increase in tax basis, the amount of net operating losses available to the Company as a result of the Corporate Reorganization, the amount and timing of taxable income the Company generates in the future, the U.S. federal income tax rate then applicable, and the portion of the Company’s payments under the TRAs that constitute imputed interest or give rise to depreciable or amortizable tax basis. 
+At December 31, 2024, the Company’s liability under the TRAs was $ 115.7 million of which $ 40.8 million is recorded as a current liability and $ 74.9 million is recorded as a component of long-term liabilities. The Company recorded a loss on remeasurement of the liabilities subject to the TRA of $ 3.2 million recorded as part of continuing operations in the current year. 
+At December 31, 2023, the Company’s liability under the TRAs was $ 117.7 million, of which $ 5.2 million was presented as a current liability, and $ 112.5 million was presented as a long-term liability. The Company recorded a gain on remeasurement of the liabilities subject to the TRA of $ 1.8 million recorded as part of continuing operations in the prior year. 
+The Company made $ 5.2 million of TRA payments during the year ended December 31, 2024. 
+During the year ended December 31, 2023, exchanges of Liberty LLC Units and shares of Class B Common Stock resulted in an increase of $ 0.6 million in amounts payable under the TRAs, and a net increase of $ 0.7 million in deferred tax assets, all of which were recorded through equity. The Company did not make any TRA payments during the year ended December 31, 2023. On January 31, 2023, the Company recorded an increase of $ 6.6 million of deferred tax assets for the impact of the adopted plan of merger for Liberty LLC into the Company, all of which was recorded through equity. 
+F-29 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Note 13— Defined Contribution Plan 
+The Company sponsors a 401(k) defined contribution retirement plan covering eligible employees. The Company makes matching contribution at a rate of $ 1.00 for each $1.00 of employee contribution, subject to a cap of 6 % of the employee’s salary and federal limits. Contributions made by the Company were $ 36.9 million, $ 32.9 million, and $ 25.8 million for the years ended December 31, 2024, 2023 and 2022, respectively. 
+Note 14— Related Party Transactions 
+Schlumberger Limited 
+During 2020, the Company acquired certain assets and liabilities of Schlumberger Technology Corporation (“Schlumberger”) in exchange for the issuance of shares of the Company ’ s Class A Common Stock amongst other consideration. During the year ended December 31, 2023, the Company repurchased and retired 3,000,000 shares of Class A Common Stock for $ 45.0 million or $ 15.00 average price per share from Schlumberger, under the share repurchase program. Effective January 31, 2023, after the repurchase and retirement, Schlumberger owns no shares of Class A Common Stock of the Company and no longer qualified as a related party. 
+During the year ended December 31, 2022, the Company repurchased and retired 1,700,000 shares of Class A Common Stock for $ 27.8 million or $ 16.35 average price per share from Schlumberger, under the share repurchase program. 
+On April 29, 2022, the Company, Liberty LLC, Schlumberger, and BofA Securities, Inc. and J.P. Morgan Securities LLC (together, the “Underwriters”), entered into an underwriting agreement, dated as of April 29, 2022, pursuant to which Schlumberger sold 14,500,000 shares of Class A Common Stock at a price of $ 15.50 per share to the Underwriters (the “Sale”). The Sale closed on May 3, 2022. Following the Sale, Schlumberger held 35,101,961 shares of Class A Common Stock. The Company did not receive any proceeds from the Sale. 
+Within the normal course of business, the Company purchased chemicals, proppant, other equipment, and maintenance parts from Schlumberger and its subsidiaries. During the period from January 1, 2023 until January 31, 2023, total purchases from Schlumberger were approximately $ 1.7 million. Although the Company continues to do business with Schlumberger, the Company no longer presents cash flows with Schlumberger as related party in the accompanying consolidated statements of cash flows. During the year ended December 31, 2022, total purchases from Schlumberger were approximately $ 21.7 million. 
+Additionally, the Company sold equipment to Schlumberger including $ 0.1 million during the year ended December 31, 2022. The Company recognized a minimal gain on the sale of equipment. 
+Franklin Mountain Energy, LLC 
+A member of the board of directors of the Company, Audrey Robertson, serves as Executive Vice President of Finance of Franklin Mountain Energy, LLC (“Franklin Mountain”). During the years ended December 31, 2024, 2023 and 2022, the Company performed hydraulic fracturing services for Franklin Mountain in the amount of $ 120.3 million, $ 176.1 million, and $ 131.8 million, respectively. 
+Amounts included in unbilled revenue from Franklin Mountain as of December 31, 2024 and 2023, were $ 0.0 million and $ 13.4 million, respectively. Receivables from Franklin Mountain as of December 31, 2024 and 2023, were $ 4.2 million and $ 12.1 million, respectively. 
+Liberty Resources LLC 
+Liberty Resources LLC, an oil and gas exploration and production company, and its successor entity (collectively, the “Affiliate”) had certain common ownership and management with the Company. Effective March 14, 2024, the Affiliate was no longer a related party, following its acquisition by an unaffiliated party. The amounts of the Company’s revenue related to hydraulic fracturing services provided to the Affiliate for the period January 1, 2024 through March 13, 2024, and the years ended December 31, 2023 and 2022, were $ 11.1 million, $ 38.8 million and $ 16.7 million, respectively. 
+On December 28, 2022 (the “Agreement Date”), the Company entered into an agreement with the Affiliate to amend payment terms for outstanding invoices due as of the Agreement Date to extend the due dates to April 1, 2024. Additionally, on August 15, 2023, the agreement was further amended in order to extend the due dates for certain invoices to January 1, 2025. Amounts outstanding from the Affiliate as of December 31, 2023 were $ 14.8 million, included in other assets in the consolidated balance sheets. All amounts outstanding with the Affiliate under the agreement were collected in full during the three months ended March 31, 2024. 
+Receivables from the Affiliate as of December 31, 2023 were $ 5.2 million, included in accounts receivable—related party. 
+During the period January 1, 2024 through March 13, 2024, and the years ended December 31, 2023 and 2022, interest income from the Affiliate was $ 0.5 million, $ 2.0 million, and $ 0.0 million, respectively. 
+F-30 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Oklo Inc. 
+During the three months ended September 30, 2023, the Company invested $ 10.0 million in a fission power and nuclear fuel recycling company, Oklo. Effective May 10, 2024, through an acquisition by a special purpose acquisition company, the Company ’ s investment converted into shares traded on the New York Stock Exchange. Additionally, Chris Wright, the Company ’ s Chief Executive Officer and Chairman of the Board during fiscal year 2024, was appointed to the Oklo board of directors. During the year ended December 31, 2024, the Company recorded an unrealized gain of $ 41.6 million, included in unrealized gain on investments, net in the accompanying consolidated statements of operations. As of December 31, 2024, the fair value of the Company ’ s investment using Level 1 inputs was $ 51.6 million. The Company was not party to any other transactions with Oklo during the years ended December 31, 2024, and 2023. 
+Nomad Proppant Services LLC 
+During the year ended December 31, 2021, the Company committed to investing $ 10.0 million in Nomad Proppant Services LLC (“Nomad”), a mobile sand mine company. Upon the commitment, the Company had a significant but non-controlling financial interest in Nomad. Within the normal course of business, the Company purchased proppant from Nomad for $ 5.5 million during the year ended December 31, 2024. Payables to Nomad as of December 31, 2024, were $ 0.6 million. Prior to the year ended December 31, 2024 the Company did not purchase any goods from Nomad. 
+As of December 31, 2024 and 2023, the value of the Company ’ s investment using the equity method accounting was $ 10.7 million and $ 11.4 million, respectively. During the years ended December 31, 2024 and 2023, the Company received cash distributions from Nomad in the amounts of $ 4.0 million and $ 0.8 million, respectively. 
+Bettering Human Lives Foundation 
+In December 2023, the Company established the Bettering Human Lives Foundation (the “Foundation”), a nonprofit organization dedicated to promoting clean cooking solutions and improving the well-being of communities worldwide. Mr. Wright, the Company’s CEO during fiscal year 2024, serves as the Chairman of the Foundation, and Anne Hyre serves as its executive director. Ms. Hyre is the sister-in-law of Mr. Wright. In December 2023, the Company made an initial commitment to make a charitable contribution of $ 1.0 million to the Foundation. In addition, effective January 1, 2024 Ms. Hyre is employed by a subsidiary of the Company and seconded to the Foundation, and Company and the Foundation entered into a professional services agreement (the “Professional Services Agreement”), whereby the Company provides certain administrative services for the Foundation. During the year ended December 31, 2024, the Company made charitable contributions of $ 0.9 million to the Foundation, and received $ 0.5 million in other service revenue under the Professional Services Agreement. 
+Note 15— Commitments & Contingencies 
+Purchase Commitments (tons are not in thousands) 
+The Company enters into purchase and supply agreements to secure supply and pricing of proppant and equipment. As of December 31, 2024 and 2023, the agreements provide pricing and committed supply sources for the Company to purchase 360,000 tons and 1,854,000 tons, respectively, of proppant through December 31, 2025. Amounts below also include commitments to pay for transport fees on minimum amounts of proppants. 
+Future proppant and equipment commitments are as follows: 
+($ in thousands) 
+2025 $ 26,348 
+2026 — 
+2027 — 
+2028 — 
+2029 — 
+Thereafter — 
+$ 26,348 
+Certain supply agreements contain a clause whereby in the event that the Company fails to purchase minimum volumes, as defined in the agreement, during a specific time period, a shortfall fee may apply. In circumstances where the Company does not make the minimum purchase required under the contract, the Company and its suppliers have a history of amending such minimum purchase contractual terms and in rare cases does the Company incur shortfall fees. If the Company were unable to make any of the minimum purchases and the Company and its suppliers cannot come to an agreement to avoid such fees, the 
+F-31 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Company could incur shortfall fees in the amounts of $ 5.4 million for the year ended December 31, 2025. Based on forecasted levels of activity, the Company does not currently expect to incur significant shortfall fees. 
+Included in the commitments for the year ending December 31, 2024 are $ 2.5 million of payments expected to be made in the first quarter of 2025 for the use of certain light duty trucks, heavy tractors, and field equipment used to various degrees in frac and wireline operations. The Company is in negotiations with the third-party owner of such equipment to lease or purchase some or all of such aforementioned vehicles and equipment, subject to agreement on terms and conditions. No gain or loss is expected upon consummation of any such agreement. 
+Litigation 
+From time to time, the Company is subject to legal and administrative proceedings, settlements, investigations, claims and actions. The Company’s assessment of the likely outcome of litigation matters is based on its judgment of a number of factors including experience with similar matters, past history, precedents, relevant financial and other evidence and facts specific to the matter. Notwithstanding the uncertainty as to the final outcome, based upon the information currently available, management does not believe any matters, individually or in aggregate, will have a material adverse effect on the Company ’ s financial position or results of operations. 
+Note 16— Subsequent Events 
+On January 22, 2025, the Company’s Board of Directors (the “Board” ) approved a quarterly dividend of $ 0.08 per share of Class A Common Stock to be paid on March 20, 2025 to holders of record as of March 6, 2025. 
+On February 3, 2025, Christopher A. Wright, the Company ’s CEO was confirmed to the position of Secretary of Energy of the United States and resigned from his positions as Chairman of the Board, Director and Chief Executive Officer of the Company. In connection with Mr. Wright’s resignation, the Company modified certain terms and conditions of Mr. Wright’s stock awards granted under the LTIP. Unvested RSUs and PSUs granted to Mr. Wright in 2022, 2023, and 2024 vested effective February 3, 2025. In total 412,292 shares of Class A Common Stock were issued, net of tax withholding. As a result of the modification the Company expects to recognize $ 10.3 million of incremental non-cash stock-based compensation expense during the three months ended March 31, 2025. 
+No other significant subsequent events have occurred that would require recognition or disclosure in the consolidated financial statements and notes thereto. 
+F-32
\ No newline at end of file
diff --git a/raw/filings/0001694028/2024/0001694028-25-000056/filing_metadata.csv b/raw/filings/0001694028/2024/0001694028-25-000056/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..55ed786491cc9e348b253daa506bb264d5b55905
--- /dev/null
+++ b/raw/filings/0001694028/2024/0001694028-25-000056/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0001694028,LBRT,Liberty Energy Inc.,10-K,2025-02-06,2024-12-31,2025-02-07T02:36:24.000Z,0001694028-25-000056,lbrt-20241231.htm,10-K,10835793,1,1,https://www.sec.gov/Archives/edgar/data/1694028/000169402825000056/lbrt-20241231.htm,https://www.sec.gov/Archives/edgar/data/1694028/000169402825000056/,2024,2024,1
diff --git a/raw/filings/0001694028/2024/0001694028-25-000056/item1.txt b/raw/filings/0001694028/2024/0001694028-25-000056/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..fc60f5143d93fbfedda985ac7bc714290010925d
--- /dev/null
+++ b/raw/filings/0001694028/2024/0001694028-25-000056/item1.txt
@@ -0,0 +1,131 @@
+Item 1. Business 
+Our Company 
+The Company, together with its subsidiaries, is a leading integrated energy services and technology company focused on providing innovative hydraulic fracturing services and related technologies to onshore oil and natural gas exploration and production (“E&P”) companies. We offer customers hydraulic fracturing services, together with complementary services including wireline services, proppant delivery solutions, field gas processing and treating, compressed natural gas (“CNG”) delivery, data analytics, related goods (including our sand mine operations), and technologies to facilitate lower emission completions, thereby helping our customers reduce their emissions profile. 
+Our areas of operations are in all of the most active shale basins in North America, including the Permian Basin, the Williston Basin, the Haynesville Shale, the Eagle Ford Shale, the Denver-Julesburg Basin (the “DJ Basin”), the Western Canadian Sedimentary Basin, the Powder River Basin, and the Appalachian Basin (Marcellus Shale and Utica Shale). Our operations also extend to a few smaller shale basins, including the Anadarko Basin, the Uinta Basin, the San Juan Basin, as well as the Beetaloo Basin in Northern Territory, Australia. The breadth of our operational footprint provides us an opportunity to leverage our fixed costs and to efficiently reposition our equipment in response to customer requirements. 
+Areas of North American Operations 
+The process of hydraulic fracturing involves pumping a pressurized stream of fracturing fluid (typically a mixture of water, chemicals and proppant) into a well casing or tubing to cause the underground formation to fracture or crack. These fractures release trapped hydrocarbon particles and provide a conductive channel for the oil or natural gas to flow freely to the wellbore for collection. The propping agent, or proppant, typically sand, becomes lodged in the cracks created by the hydraulic 
+1 
+fracturing process, “propping” them open to facilitate the flow of hydrocarbons from the reservoir to the well. The fracturing fluid is engineered to lose viscosity, or “break,” and is subsequently flowed back from the formation, leaving the proppant suspended in the formation fractures. Once our customer has flushed the fracturing fluids from the well using a controlled flow-back process, the customer manages fluid and water recycling or disposal. 
+Our hydraulic fracturing fleets consist of mobile hydraulic fracturing units and other auxiliary heavy equipment to perform fracturing services. Our hydraulic fracturing units consist primarily of high-pressure hydraulic pumps, engines, transmissions, radiators and other supporting equipment (including power generation units for electric fleets) that are typically mounted on trailers. We refer to the group of units and other equipment, such as blenders, data vans, sand storage, tractors, manifolds and high-pressure fracturing iron, which are necessary to perform a typical hydraulic fracturing job, as a “fleet,” and the personnel assigned to each fleet as a “crew.” The size of each fleet and crew can vary depending on the requirements of each job design. 
+Wireline operations supplement our hydraulic fracturing fleets, which consist of a truck equipped with a spool of wireline that is lowered into wells to convey specialized tools or equipment, such as perforating guns and charges, which are necessary to connect the wellbore with the target formation. This operation is performed between each hydraulic fracturing stage. Our wireline service is primarily offered alongside our hydraulic fracturing services, which allows us to maximize efficiency for our customers through optimized coordination of the wireline and hydraulic fracturing services. In addition, we also offer our wireline service on a stand-alone basis. 
+We also operate two sand mines that allows us to vertically integrate our supply-chain in the Permian Basin. The mines provide sand to Liberty hydraulic fracturing fleets as well as to third parties. With a secured supply of regional sand in the basin, we reduce our dependency on other providers and any downtime that could result from sand supply issues. 
+We are a leading provider of last-mile proppant delivery solutions, including proppant handling equipment and logistics software across North America. We offer innovative environmentally friendly technology with optimized dry and wet sand containers and wellsite proppant handling equipment that drive logistics efficiency and reduce noise and emissions. We believe that our wet sand handling technology is a key enabler of the next step of cost and emissions reductions in the proppant industry. We also offer customers the latest real-time logistics software, PropConnect™, as a hosted software as a service. 
+We also own and operate Liberty Power Innovations LLC (“LPI”), an integrated alternative fuel and power solutions provider for remote applications. On April 6, 2023, LPI expanded its footprint with the acquisition of Siren Energy & Logistics, LLC (“Siren” and such acquisition, the “Siren Acquisition”), a Permian focused integrated natural gas compression and CNG delivery business that we have since expanded to other basins. LPI provides CNG supply, field gas processing and treating, and well site fueling and logistics. LPI was formed with the initial focus on supporting Liberty’s transition towards our next generation digiFleets℠ and dual fuel fleets, by providing consistent and reliable CNG fueling services, which are critical to maintaining highly efficient well site operations. Through 2024, LPI was primarily focused on supporting an industry transition to natural gas fueled technologies, serving as a key enabler of the next step of cost and emissions reductions in the oilfield. In January 2025, we announced LPI’s expansion into the distributed power business, where we expect to leverage our experience in providing electric power for our digiFrac pumps into other areas inside and outside of the oilfield. 
+Our operations are organized into a single business segment, which consists of hydraulic fracturing services, including wireline, proppant delivery and goods, including our Permian Basin sand mines, and natural gas compression and delivery, and we have one reportable geographical segment, North America. We have grown from one active hydraulic fracturing fleet as of December 2011 to approximately 40 active fleets as of December 31, 2024. We are focused on providing “next-generation” frac fleets and technologies to assist our customers with completing their wells in an efficient and responsible manner. 
+Our founders and management are pioneers in the development of data-driven hydraulic fracturing technologies for application in shale plays. Prior to founding the Company, several members of the senior executive management team founded and built Pinnacle Technologies, Inc. (“Pinnacle Technologies”) into a leading fracturing technology company. In 1992, Pinnacle Technologies developed the first commercial hydraulic fracture mapping technologies, analytical tools that played a major role in launching the shale revolution. Our extensive experience with fracture technologies and customized fracture design has enabled us to develop new technologies and processes that provide our customers with real-time solutions that significantly enhance their completions. These technologies include hydraulic fracture propagation models, reservoir engineering tools, large, proprietary shale production databases and multi-variable statistical analysis techniques. Taken together, these technologies have enabled us to be a leader in hydraulic fracture design innovation and application. Our management team has an average of over 20 years of energy services experience. 
+We believe technical innovation and strong relationships with our customers and suppliers distinguish us from our competitors and are the foundations of our business. We expect that E&P companies will continue to focus on technological innovation as completion complexity and fracture intensity of horizontal wells increases, particularly as customers are increasingly focused on reducing emissions from their completions operations. We remain proactive in developing innovative solutions to industry challenges, including developing: (i) our databases of U.S. unconventional wells to which we apply our 
+2 
+proprietary multi-variable statistical analysis technologies to provide differential insight into fracture design optimization; (ii) our Liberty Quiet Fleet® design which significantly reduces noise levels compared to conventional hydraulic fracturing fleets; (iii) hydraulic fracturing fluid systems tailored to the specific reservoir properties in the basins in which we operate; (iv) our dual fuel dynamic gas blending (“DGB”) fleets that allow our engines to run diesel or a combination of diesel and natural gas, to optimize fuel use, reduce emissions and lower costs; (v) our digiFleets℠, comprising of digiFrac℠ and digiPrime℠ pumps and other complementary equipment, including power generation units (together “digiTechnologies℠”), our innovative, purpose-built electric and hybrid frac pumps that have approximately 25% lower CO 2e emission profile than the Tier IV DGB; (vi) our wet sand handling technology which eliminates the need to dry sand, enabling the deployment of mobile mines nearer to wellsites; and (vii) the launch of LPI to support the transition to our digiFleets as well as the transition to lower costs and emissions in the oilfield. In addition, our integrated supply chain includes proppant, chemicals, equipment, natural gas fueling services, logistics and integrated software which we believe promotes wellsite efficiency and leads to more pumping hours and higher productivity throughout the year to better service our customers. In order to achieve our technological objectives, we carefully manage our liquidity and debt position to promote operational flexibility and invest in the business throughout the full commodity cycle in the regions we operate. 
+Recent Leadership Updates 
+On February 3, 2025, Christopher A. Wright, our Chief Executive Officer and Chairman of the Board, was confirmed to the position of Secretary of Energy of the United States and resigned from his positions as Chairman of the Board, Director, and Chief Executive Officer of the Company. Also, on February 3, 2025, in accordance with the Company’s succession plan, the Board appointed William Kimble as the non-executive Chairman of the Board and Ron Gusek as the Company’s Chief Executive Officer and Director. Lastly, on January 22, 2025, the Board approved an increase to the size of the Board from nine to 10 directors and appointed Arjun Murti to fill the newly created vacancy. 
+Focused on Continuous Improvement 
+We support all energy sources that improve our energy system and better lives. We passionately work to better the process of bringing hydrocarbons to the surface in a clean, safe and efficient fashion and view these principles as foundational to our business. We focus on developing and adding technologies to our operations that assist our customers in implementing their goals. The list below sets forth specific examples of our efforts in this regard: 
+• In 2013, we introduced Tier II dual-fuel technology to our fleets which allows our frac pumps to use natural gas in place of some diesel fuel to lower particulate emissions. 
+• In 2014, we began the use of containerized sand delivery at frac locations, which reduces dust, noise and truck traffic. 
+• In 2016, we introduced Quiet Fleet® technology, which significantly reduces noise levels associated with frac operations. 
+• In 2018, we partnered with an equipment supplier to introduce Tier IV dynamic gas blending, or DGB, engines to our frac fleet that can substitute up to 80% of the diesel typically used by a frac pump with natural gas and significantly lower emission levels in frac operations. Tier IV DGB engines were added to our fleet in 2020. 
+• In 2018, we began the design and development of digiFrac SM , our innovative, purpose-built electric frac pump that has approximately a 25% lower CO 2e emission profile than the Tier IV DGB. 
+• In 2021, we announced the successful test of digiFrac and in 2022 commenced delivery of commercial pumps. 
+• In October 2021, we became a leading provider of last-mile proppant delivery solutions including proppant handling equipment and logistics software. We offer innovative, environmentally friendly technology with optimized dry and wet sand containers and wellsite proppant handling equipment that drive logistics efficiency and reduce noise and emissions. 
+• In 2022, we began the design and development of digiPrime SM , the first hybrid pump technology, utilizing direct mechanical drive for the pumps while simultaneously generating power capable of electrifying supporting equipment at the well site. These pumps have a lower CO 2e emissions profile than digiFrac. 
+• In 2023, we launched LPI and closed the acquisition of Siren. We believe that the shift in fuel consumption from diesel to cleaner natural gas has the potential to promote emissions reductions in the industry. 
+• In 2023, we commenced deployment of digiFleets SM , comprised of digiFrac and digiPrime pump technology along with other complementary equipment from our digiTechnologies SM suite. This deployment also included mobile generation units to provide the needed electricity to power our digiFrac pumps in remote locations. 
+• In 2024, the Bettering Human Lives Foundation, a non-profit organization dedicated to improving the well-being of communities worldwide with an early focus on promoting clean cooking solutions, supported two companies in Kenya 
+3 
+and Ghana to convert schools from burning firewood to liquid petroleum gas. During 2024, we made charitable contributions of $0.9 million to the Bettering Human Lives Foundation. 
+• The third edition of Liberty’s Bettering Human Lives report, emphasizing energy’s central role in human lives, was released in February 2024. Over 30,000 copies of the report have been distributed worldwide to date. 
+• In January 2025, we announced LPI’s expansion into the distributed power business, where we expect to leverage our experience in providing electric power for our digiFrac pumps into other areas inside and outside of the oilfield. 
+Furthermore, we are continuously committed to engagement in our communities. We provide K-12 scholarships to low-income children through Alliance for Choice in Education, and we proudly fund a Liberty Scholars program at Montana Technological University to enable lower-income students to obtain a college education. In total, over 100 students received Liberty scholarships across the U.S. and Canada in 2024. In addition to our educational initiatives, we have targeted outreach to organizations focused on veterans, poverty abatement, low-income housing, criminal justice reform, and job opportunities for those who had a disadvantaged start in life. 
+In 2024, we created a charitable giving committee to facilitate communication across all areas of Liberty operations and direct support to organizations where our employees live and work. In 2021, we launched Love, Liberty, our corporate matching program, to double our impact and encourage our employees to get involved in their communities. In 2024, Liberty processed over 200 match requests to nearly 50 different organizations, totaling nearly $40,000 in matching contributions. 
+Cyclical Nature of Industry 
+We operate in a cyclical industry reflecting global oil and gas supply and demand dynamics, current and expected future oil and gas commodity prices, and the perceived stability and sustainability of those prices. Global oil and gas supply and demand can be impacted by general domestic and international economic conditions, inflationary pressures, geopolitical developments, government regulations, and other factors. Such factors also impact capital expenditures and drilling and completions activities of E&P companies, which in turn can impact demand for our services. For these reasons, the results of our operations may fluctuate from quarter to quarter and from year to year, and these fluctuations may distort comparisons of results across periods. 
+Seasonality 
+Our results of operations have historically reflected seasonal tendencies relating to holiday seasons, inclement weather and the conclusion of our customers’ annual drilling and completion capital expenditure budgets. Our most notable declines typically occur in the fourth quarter of the year for the reasons described above. Additionally, some of the areas in which we have operations, including Canada, the DJ Basin, Powder River Basin and Williston Basin, are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice, rain, or frost, and related road restrictions, we may be unable to move our equipment between locations, thereby reducing our ability to provide services and generate revenues. The exploration activities of our customers may also be affected during such periods of adverse weather conditions. Additionally, extended drought conditions in our operating regions could impact our ability or our customers’ ability to source sufficient water or increase the cost for such water. 
+Intellectual Property 
+Over the last several years and in connection with the acquisition of Siren, and others in prior periods, we have significantly invested in our research and technology capabilities. Our efforts to date have been focused on developing innovative, fit-for-purpose solutions designed to enhance our core service offerings, increase completion efficiencies, provide cost savings to our operations and add value for our customers. A cornerstone of our technological advantage is a series of proprietary databases of U.S. unconventional wells that include production data, completion designs and reservoir characteristics. We utilize these databases to perform multi-variable statistical analysis that generates differential insight into fracture design optimization to enhance our customers’ production economics. Our emphasis on data analytics is also deployed during job execution through the use of real-time feedback on variables that maximizes customer returns by improving cost-effective hydraulic fracturing operations. 
+Today, we hold approximately 500 patents and patent licenses relating to our engineering and technology solutions. We seek patent and trademark protections for our technology when we deem it prudent, and we aggressively pursue protection of these rights when warranted. We believe our patents, trademarks, and other protections for our proprietary technologies are adequate for the conduct of our business and that no single patent or trademark is critical to our business. In addition, we rely, to a great extent, on the technical expertise and know-how of our personnel to maintain our competitive position, and we take commercially reasonable measures to protect trade secrets and other confidential and/or proprietary information relating to the technologies we develop. 
+4 
+Human Capital Management 
+As of December 31, 2024, we had approximately 5,700 employees and no unionized labor. We believe we have good relations with our employees and that one of our key competitive advantages is our people. Our highly trained, experienced and motivated employees are critical to delivering our hydraulic fracturing services. Taking care of our employees is one of our top priorities, and we continually invest in hiring, training and retaining the employees we believe to be the best in our field. We consistently assess the current business environment and labor market to refine our compensation and benefits programs in order to attract and retain top talent in our industry. We strive to promote from within our existing employee base to manage new hydraulic fracturing fleets and organically grow our operating expertise. This organic growth is essential in achieving the expertise and level of customer service we strive to provide each of our customers. As a result, we plan to continue to invest in our employees through both personal and professional training to attract and retain the best individuals in our areas of operation. Overall, we focus on individual contributions and team success to foster a culture built around operational excellence and superior safety. 
+Health and Safety 
+Our people are our most important asset and ensuring their safety and the safety of those around them is the most important thing we do. Making certain that the Liberty team is well trained to handle the complexities of daily field operations, and that their training and competency remains current with the latest technology and standards is a key component. In order to facilitate this training, we have developed the Liberty Frac Academy, a thorough program where employees are trained on various aspects of the Company, from safety in equipment operation to leadership skills. The Liberty Frac Academy not only ensures dissemination of high-quality training material, but also provides a forum for sharing best practices and lessons learned across the Company. As a result, we are among the safest service providers in the industry with a constant focus on Health, Safety and Environmental performance and service quality, as evidenced by an average incident rate that was consistently lower than the industry average from 2022 to 2024. Our employee-centered focus and reputation for safety has enabled us to obtain projects from industry leaders with some of the most demanding safety and operational requirements. 
+Programs and Benefits 
+One way we have demonstrated a history of investing in our workforce is by offering competitive salaries and wages. To foster a strong sense of ownership, restricted stock units are provided to eligible employees under our long-term incentive plan. Furthermore, we offer innovative benefits to all eligible employees, including, among others, comprehensive health insurance coverage, parental leave to all new parents, for birth or adoption, financial support for child adoption, leave to care for partners with serious health conditions, 401(k) savings plan and educational tuition assistance for both bachelor’s degree and master’s degree programs. We are also passionate about community investment and are a part of the Ban the Box initiative which provides work opportunities for formerly incarcerated individuals. 
+Governmental Regulation and Climate Change 
+As a company with operations primarily in the United States and Canada, we are subject to the laws of both jurisdictions in which we operate and the rules and regulations of various governing bodies, which may differ among those jurisdictions. Compliance with these laws, rules and regulations has not had, and is not expected to have, a material effect on our capital expenditures, results of operations and competitive position as compared to prior periods. We are also subject to numerous environmental and regulatory requirements related to our operations. For further information related to such regulation, see the risks described under the heading “Risk Factors” in this Annual Report. 
+Our operations are subject to numerous stringent and complex laws and regulations at the federal, state, and local levels governing the discharge of materials into the environment, environmental protection, and health and safety aspects of our operations. Failure to comply with these laws and regulations or to obtain or comply with permits may result in the assessment of administrative, civil, and criminal penalties, imposition of remedial or corrective action requirements, and the imposition of injunctions or other orders to prohibit certain activities, restrict certain operations, or force future compliance with environmental requirements. 
+There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons, other hazardous substances, and wastes, as a result of air emissions and wastewater discharges related to our operations, and because of historical operations and waste disposal practices. Spills or other releases of regulated substances, including such spills and releases that occur in the future, could expose us to material losses, expenditures, and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. The following is a summary of some of the existing laws, rules, and regulations to which we are subject. 
+5 
+U.S. Laws and Regulations 
+Hazardous Substances and Waste Handling 
+The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Under guidance issued by the U.S. Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. RCRA currently exempts many E&P wastes from classification as hazardous waste. Specifically, RCRA excludes produced waters and other wastes intrinsically associated with the exploration, development, or production of crude oil and natural gas from the definition of hazardous waste. However, these E&P wastes may still be regulated under state solid waste laws and regulations, and it is possible that certain oil and natural gas E&P wastes now classified as non-hazardous could be classified as hazardous waste in the future. Stricter regulation of wastes generated during our or our customers’ operations could result in increased costs for our operations or the operations of our customers, which could in turn reduce demand for our services and adversely affect our business. We cannot guarantee that the EPA will not revisit the exemption of E&P waste or that waste will not become more heavily regulated at the federal or state level. 
+Comprehensive Environmental Response, Compensation, and Liability Act 
+The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owner or operator of the site where the release occurred and anyone who transported or disposed or arranged for the transport or disposal of a hazardous substance released at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA and any state analogs may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources and for the costs of certain health studies. We currently own, lease, or operate, and previously owned, leased, or operated numerous properties that have been used for manufacturing and other operations for many years. These properties and the substances disposed or released on them may be subject to CERCLA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. 
+Worker Health and Safety 
+We are subject to a number of federal and state laws and regulations, including the OSHA regulatory standards, which establish requirements to protect the health and safety of workers. Among others, we may be subject to OSHA regulations for safe operation of cranes, power industrial trucks and similar equipment at our worksites, safe practices for working in hazardous locations and permit-required confined spaces, and proper use of required personal protective equipment by workers. OSHA’s hazard communication standard requires tracking of hazardous chemicals present at the worksite, sharing of such information with the workers, and training the workers to handle the chemicals appropriately. The EPA’s community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes also require maintenance of information about hazardous materials used or produced in operations and provision of this information to employees, state and local government authorities, and citizens. We are also subject to OSHA’s regulatory standard for respirable crystalline silica, which provides measures to protect workers in hydraulic fracturing operations from exposure to this chemical including limiting exposure to airborne respirable crystalline silica in excess of a specified limit. Additionally, the Federal Motor Carrier Safety Administration (the “FMCSA”) regulates and provides safety oversight of commercial motor vehicles, the EPA establishes requirements to protect human health and the environment, the federal Bureau of Alcohol, Tobacco, Firearms and Explosives establishes requirements for the safe use and storage of explosives, and the federal Nuclear Regulatory Commission establishes requirements for the protection against ionizing radiation. We are subject to Mine Safety & Health Administration regulations related to operation of sand mines including regulations for training and retraining of workers engaged in sand mine operations. Substantial fines and penalties can be imposed, and orders or injunctions limiting or prohibiting certain operations may be issued, in connection with any failure to comply with these laws and regulations. 
+6 
+Water Discharges 
+The federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the U.S. The discharge of pollutants into regulated waters, including jurisdictional wetlands, is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. To the extent the agencies expanding the range of properties subject to the Clean Water Act’s jurisdiction or impose more stringent requirements on discharges of wastewater, certain energy companies could face increased costs and delays with respect to obtaining permits, including for the discharge of dredge and fill activities in waters of the U.S. or wetland areas, which in turn could reduce demand for our services. Furthermore, the process for obtaining permits has the potential to delay our operations and those of our customers. Spill prevention, control, and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture, or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of wastewater and storm water runoff from certain types of facilities. The Clean Water Act and analogous state laws provide for administrative, civil, and criminal penalties for unauthorized discharges and, together with the Oil Pollution Act of 1990, impose rigorous requirements for spill prevention and response planning, as well as substantial potential liability for the costs of removal, remediation, and damages in connection with any unauthorized discharges. 
+Air Emissions 
+The federal Clean Air Act (the “CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants and other air emissions at specified sources. These regulations change frequently. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements, utilize specific equipment or technologies to control emissions of certain pollutants or prohibit certain types of emissions management practices. In recent years, the CAA has been used to impose additional stringent requirements upon oil and gas production operations. While many of these rules may not be directly applicable to our business, they are applicable to the business of our customers. Promulgation of stricter permitting or emission control requirements could delay or impair our or our customers’ ability to obtain air emission permits, to develop new wells and to continue to operate existing wells, and result in fewer wells being drilled or redeveloped, causing a decrease in demand for our services. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties, as well as injunctive relief, for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. 
+Climate Change 
+The EPA has determined that emissions of greenhouse gases, including carbon dioxide and methane, present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. The EPA has established greenhouse gas emissions reporting requirements for sources in the oil and gas sector and has also promulgated rules requiring certain large stationary sources of greenhouse gases to obtain preconstruction permits under the CAA and follow “best available control technology” requirements. Although we are not likely to become subject to greenhouse gas emissions permitting and best available control technology requirements because none of our facilities are presently major sources of greenhouse gas emissions, such requirements could become applicable to our customers. In addition, the EPA has used the CAA to impose additional greenhouse gas emissions control requirements upon our customers. Furthermore, the Inflation Reduction Act (“IRA 2022”) imposes a methane emissions charge on certain emissions from specific classes of sources that are required to report their greenhouse gas emissions, which began in calendar year 2024. This fee as well as additional requirements on greenhouse gas emissions from our customers could have an adverse effect on their costs of operations or financial performance, thereby adversely affecting our business, financial condition, and results of operations. Also, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, and many states have already established regional greenhouse gas “cap-and-trade” programs. The adoption of any legislation or regulation that restricts emissions of greenhouse gases from the equipment and operations of our customers or with respect to the oil and natural gas they produce could adversely affect demand for our products and services. 
+7 
+Hydraulic Fracturing 
+Our business is clearly dependent on hydraulic fracturing and horizontal drilling activities. As further described herein, hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shale. The process, which involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. There is considerable legislative and regulatory focus on the emissions of methane, which may be released during hydraulic fracturing, chemicals used in the hydraulic fracturing process, the discharge of wastewater from hydraulic fracturing operations and concerns about the triggering of seismic activity by the injection of produced waters into underground wells. The adoption of new or revised legislation or regulation could make it significantly more difficult and/or costly to drill and operate oil and gas wells. If adopted, such legislation or regulation could result in a decline in the completion of new oil and gas wells or the recompletion of existing wells, which could negatively impact the drilling programs of our customers and, consequently, delay, limit or reduce the demand for our services. Given the long-term trend towards increasing regulation, future regulation in the industry remains a possibility. 
+Some states, counties, and municipalities have enacted or are considering moratoria on hydraulic fracturing. For example, New York, Vermont, Maryland, and Washington have banned the use of high-volume hydraulic fracturing. Alternatively, some municipalities are, or have considered, zoning and other ordinances, the conditions of which could impose a de facto ban on drilling and/or hydraulic fracturing operations. Further, some states, counties, and municipalities are closely examining water use issues, such as permit and disposal options for processed water, which could have a material adverse impact on our financial condition, prospects, and results of operations if such additional permitting requirements are imposed upon our industry. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could reduce demand for our business by making it more difficult or costly for certain customers to perform fracturing to stimulate production from tight formations. 
+National Environmental Policy Act 
+Businesses and operations of our customers that are carried out on federal lands may be subject to the National Environmental Policy Act (“NEPA”), which requires federal agencies, including the U.S. Department of the Interior, to evaluate major agency actions having the potential to significantly impact the human environment. In the course of such evaluations, an agency will evaluate the potential direct, indirect, and cumulative impacts of a proposed project and, if necessary, will prepare a detailed Environmental Impact Statement that must be made available for public review and comment. To the extent that our customers’ current activities, as well as proposed plans, on federal lands require governmental permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects which in turn could reduce demand for our services. 
+Endangered Species Act and Migratory Bird Treaty Act 
+The federal Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or its habitat. The U.S. Fish and Wildlife Service (the “FWS”) must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development and development of sand mines used for hydraulic fracturing. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”), which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit. This prohibition covers most bird species in the U.S. Future implementation of the rules implementing the ESA and the MBTA are uncertain. If we or our customers were to have areas within our respective operations designated as critical or suitable habitat for a protected species, it could decrease demand for our services and have a material adverse effect on our business. 
+Canadian Laws and Regulations 
+Companies such as us offering energy services that include hydraulic fracturing, engineering, and wireline services in the Provinces of Alberta and British Columbia in Canada are regulated by both the provincial governments of Alberta and British Columbia (“Province”) and the federal government of Canada (“Canada”). This includes, but is not limited to, regulation related to environmental protection legislation, climate change legislation, fracking legislation, and legislation related to wildlife. In addition to being regulated by the Province and Canada, energy services companies may also be subject to other international, national, and subnational laws, regulations, and policies. 
+Provincial Legislation 
+Energy services companies are primarily regulated by provincial governments in Canada. For example, in Alberta, provincial legislation potentially applicable to our Canadian operations includes the Environmental Protection and 
+8 
+Enhancement Act , RSA 2000, e E-12. This Act promotes the protection, enhancement and wise use of the environment, and deals with matters such as air emissions, water discharges, and the handling of hazardous substances and waste control (for example, under the Waste Control Regulation , Alta Reg 192/1996). Other environmental legislation in the Province that applies to energy service companies includes: the Water Act, RSA 2000, c W-3 and associated regulations, under which companies must apply for a license for any water use; and the Wildlife Act, RSA 2000, c W-10 which provides for the protection and conservation of wild animals and endangered species in Alberta. 
+Other potentially applicable provincial legislation in Alberta includes legislation directed at the transportation of dangerous goods, including oil (the Dangerous Goods Transportation and Handling Act , RSA 2000, c D-4 and associated regulations), legislation intended to provide for the responsible management of oil wells and associated sites, including remediation responsibilities (the Oil and Gas Conservation Act , RSA 2000, c O-6 and associated regulations), legislation establishing regulatory bodies overseeing oil and gas and electricity in Alberta (the Responsible Energy Development Act , SA 2012, c R-17.3 and the Alberta Utilities Commission Act , SA 2007, c A-37.2), legislation governing the removal of gas or propane from Alberta (the Gas Resources Preservation Act , RSA 2000, c G-4), legislation to effect conservation and prevent waste of the oil sands resource in Alberta (the Oil Sands Conservation Act , RSA 2000, c O-7), and legislation governing worker safety (the Occupational Health and Safety Act , SA 2017, c O-2.1). 
+The Alberta Energy Regulator has a number of directives that are applicable to energy services companies, such as Directive 050, updated in November 2024, which addresses salinity ranges for soils that can receive drilling wastes, Directive 058, updated in October 2022, which sets out regulatory requirements for the handling, treatment, and disposal of upstream oilfield waste, and Directive 083, updated in November 2024, which sets out the requirements for managing subsurface integrity associated with hydraulic fracturing, including seismic monitoring in certain areas of Alberta. Other provinces in Canada have their own statutory regime applicable to oilfield service companies. 
+Federal Legislation 
+The Federal government in Canada shares certain jurisdiction with the provinces over certain environmental matters. Federal legislation potentially applicable to our Canadian operations includes legislation focused on regulating greenhouse gases (the Greenhouse Gas Pollution Pricing Act , SC 2018, c 12, s 186), legislation aimed at protecting wildlife (the Species at Risk Act , SC 2002, c 29, Fisheries Act, RSC 1985, c F-14, and Migratory Birds Convention Act, 1994, SC 1994, c 22), and legislation governing the transportation of potentially dangerous substances and prevention of pollution (the Transportation of Dangerous Goods Act, 1992 , SC 1992, c 34 and Canadian Environmental Protection Act, 1999, SC 1999, c 33). 
+Environmental assessment of major projects in Canada is shared between the federal and provincial governments. The federal environmental assessment legislation, the Impact Assessment Act , SC 2019, c 28, s1, governs approvals for federally regulated projects and was amended in June 2024. 
+9 
+Properties 
+Properties 
+Our corporate headquarters are located at 950 17 th Street, Suite 2400, Denver, Colorado 80202. We lease our general office space at our corporate headquarters. The lease expires in December 2027. We currently own or lease the following additional principal properties: 
+District Facility Location Size Leased or Owned 
+Midland, TX 90,000 sq. ft on 35 acres Owned 
+Midland, TX 70,000 sq. ft on 12 acres Owned 
+Midland, TX 14,000 sq. ft on 22 acres Owned 
+Odessa, TX 77,500 sq. ft on 48 acres Owned 
+Cibolo, TX 90,000 sq. ft on 34 acres Owned 
+Kermit, TX 5,000 acres Owned 
+Monahans, TX 3,200 acres Owned 
+Magnolia, TX 63,350 sq. ft Leased (through May 31, 2031) 
+Magnolia, TX 29,402 sq. ft Leased (through December 31, 2026) 
+Orla, TX 4 acres Leased 
+Shreveport, LA 215,000 sq ft. on 45 acres Owned 
+Cheyenne, WY 115,000 sq. ft on 60 acres Owned 
+Henderson, CO 50,000 sq. ft on 13 acres Leased (through December 31, 2034) 
+Henderson, CO 96,582 sq. ft on 12 acres Owned 
+Briggsdale, CO 7 acres Leased 
+Williston, ND 55,000 sq. ft on 50 acres Owned 
+Vernal, UT 30,901 sq. ft on 10 acres Leased (through September 30, 2025) 
+El Reno, OK 80,000 sq. ft on 33 acres Owned 
+Red Deer, AB 170,000 sq. ft on 42 acres Owned 
+Grand Prairie, AB 135,000 sq. ft on 40 acres Owned 
+We also lease several smaller facilities, which leases generally have terms of one to six years. We believe that our existing facilities are adequate for our operations and their locations allow us to efficiently serve our customers. We do not believe that any single facility is material to our operations and, if necessary, we could readily obtain a replacement facility. 
+Marketing and Customers 
+We have developed long-term partnerships with our customers through a continuous dialogue focused on their production economics. Further, we have a proven track record of executing our customers’ plans and delivering on time and in line with expected costs. Our customer base includes a broad range of integrated and independent E&P companies, including some of the largest E&P companies in our areas of operation. Our technological innovations, customer-tailored approach and track record of consistently providing high-quality, safe and reliable service has allowed us to develop long-term customer partnerships, which we believe makes us the service provider of choice for many of our customers. 
+Our sales and marketing activities typically are performed through our local sales representatives in each geographic region and are supported by our corporate headquarters. For the years ended December 31, 2024, 2023 and 2022, our top five customers collectively accounted for approximatel y 43% , 34%, and 30% of our revenues, respectively. For the year ended December 31, 2024, Occidental Petroleum Corporation accounted for more than 10% of consolidated revenues. For the years ended December 31, 2023, and 2022, no customers accounted for more than 10% of consolidated revenues. 
+10 
+Suppliers and Raw Materials 
+We have a dedicated supply chain team that manages sourcing and logistics to ensure flexibility and continuity of supply in a cost-effective manner across our areas of operation. We have built long-term relationships with multiple industry leading suppliers of proppant, chemicals and hydraulic fracturing equipment and have started to internally design and assemble key pump and maintenance parts. In addition, we have built a strong relationship with the assemblers of our custom-designed hydraulic fracturing fleets and believe we will continue to have timely access to new, high capability fleets as we continue to grow. In 2018, we vertically integrated a supplier of certain major components through the acquisition of ST9 Gas and Oil LLC, which subsequently changed its name to Liberty Advanced Equipment Technologies LLC, and now provides engineering design and packaging for certain equipment used in our operations. In October 2021, we vertically integrated a supplier of our containerized sand and last mile proppant logistics solutions with the acquisition of Proppant Express Solutions LLC. This, along with our two state-of-the-art sand mines in the Permian Basin, help us alleviate the risk of proppant supply shortages. 
+We purchase a wide variety of raw materials, parts and components that are manufactured and supplied for our operations. We are not dependent on any single source of supply for those parts, supplies or materials. To date, we have generally been able to obtain the equipment, parts and supplies necessary to support our operations, although we have experienced delivery delays and shortages on some items. While we believe that we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers, we may not always be able to do so. In addition, certain materials for which we do not currently have long-term supply agreements could experience shortages and significant price increases in the future. As a result, we may be unable to mitigate any future supply shortages and our results of operations, prospects and financial condition could be adversely affected. 
+Competition 
+The markets in which we operate are highly competitive. We provide services in various geographic regions across the United States and Canada, and our competitors include many large and small oilfield service providers, including some of the largest integrated service companies. Our hydraulic fracturing services compete with large, integrated companies such as Halliburton Company as well as other companies including Patterson-UTI Energy Inc. and ProFrac Holding Corp. In addition, we compete regionally with ProPetro Services, Inc. and other smaller service providers. 
+We believe that the principal competitive factors in the markets we serve are technical expertise, equipment capacity, work force competency, efficiency, safety record, reputation, experience and price. Additionally, projects are often awarded on a bid basis, which tends to create a highly competitive environment. We seek to differentiate ourselves from our competitors by delivering the highest-quality services and equipment possible, coupled with superior execution and operating efficiency in a safe working environment. 
+Available Information 
+We file or furnish annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The SEC also maintains an internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC. 
+We also make available free of charge through our website, www.libertyenergy.com, electronic copies of certain documents that we file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. 
+11
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+Item 13. Certain Relationships and Related Transactions, and Director Independence 
+The information required by this item concerning certain relationships and related person transactions and director independence is incorporated herein by reference to our definitive proxy statement for our 2025 annual meeting of stockholders, which will be filed with the SEC no later than 120 days after December 31, 2024, under the captions “Certain Relationships and Related Party Transactions” and “the Board and its Committees.”
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+Item 9A. Controls and Procedures 
+Evaluation of Disclosure Controls and Procedures 
+In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2024 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures. 
+There were no changes to our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 
+See page F-1 for Management’s Report on Internal Control Over Financial Reporting and page F-4 for Report of Independent Registered Public Accounting Firm on its assessment of our internal control over financial reporting.
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+Note 14— Related Party Transactions 
+Schlumberger Limited 
+During 2020, the Company acquired certain assets and liabilities of Schlumberger Technology Corporation (“Schlumberger”) in exchange for the issuance of shares of the Company ’ s Class A Common Stock amongst other consideration. During the year ended December 31, 2023, the Company repurchased and retired 3,000,000 shares of Class A Common Stock for $ 45.0 million or $ 15.00 average price per share from Schlumberger, under the share repurchase program. Effective January 31, 2023, after the repurchase and retirement, Schlumberger owns no shares of Class A Common Stock of the Company and no longer qualified as a related party. 
+During the year ended December 31, 2022, the Company repurchased and retired 1,700,000 shares of Class A Common Stock for $ 27.8 million or $ 16.35 average price per share from Schlumberger, under the share repurchase program. 
+On April 29, 2022, the Company, Liberty LLC, Schlumberger, and BofA Securities, Inc. and J.P. Morgan Securities LLC (together, the “Underwriters”), entered into an underwriting agreement, dated as of April 29, 2022, pursuant to which Schlumberger sold 14,500,000 shares of Class A Common Stock at a price of $ 15.50 per share to the Underwriters (the “Sale”). The Sale closed on May 3, 2022. Following the Sale, Schlumberger held 35,101,961 shares of Class A Common Stock. The Company did not receive any proceeds from the Sale. 
+Within the normal course of business, the Company purchased chemicals, proppant, other equipment, and maintenance parts from Schlumberger and its subsidiaries. During the period from January 1, 2023 until January 31, 2023, total purchases from Schlumberger were approximately $ 1.7 million. Although the Company continues to do business with Schlumberger, the Company no longer presents cash flows with Schlumberger as related party in the accompanying consolidated statements of cash flows. During the year ended December 31, 2022, total purchases from Schlumberger were approximately $ 21.7 million. 
+Additionally, the Company sold equipment to Schlumberger including $ 0.1 million during the year ended December 31, 2022. The Company recognized a minimal gain on the sale of equipment. 
+Franklin Mountain Energy, LLC 
+A member of the board of directors of the Company, Audrey Robertson, serves as Executive Vice President of Finance of Franklin Mountain Energy, LLC (“Franklin Mountain”). During the years ended December 31, 2024, 2023 and 2022, the Company performed hydraulic fracturing services for Franklin Mountain in the amount of $ 120.3 million, $ 176.1 million, and $ 131.8 million, respectively. 
+Amounts included in unbilled revenue from Franklin Mountain as of December 31, 2024 and 2023, were $ 0.0 million and $ 13.4 million, respectively. Receivables from Franklin Mountain as of December 31, 2024 and 2023, were $ 4.2 million and $ 12.1 million, respectively. 
+Liberty Resources LLC 
+Liberty Resources LLC, an oil and gas exploration and production company, and its successor entity (collectively, the “Affiliate”) had certain common ownership and management with the Company. Effective March 14, 2024, the Affiliate was no longer a related party, following its acquisition by an unaffiliated party. The amounts of the Company’s revenue related to hydraulic fracturing services provided to the Affiliate for the period January 1, 2024 through March 13, 2024, and the years ended December 31, 2023 and 2022, were $ 11.1 million, $ 38.8 million and $ 16.7 million, respectively. 
+On December 28, 2022 (the “Agreement Date”), the Company entered into an agreement with the Affiliate to amend payment terms for outstanding invoices due as of the Agreement Date to extend the due dates to April 1, 2024. Additionally, on August 15, 2023, the agreement was further amended in order to extend the due dates for certain invoices to January 1, 2025. Amounts outstanding from the Affiliate as of December 31, 2023 were $ 14.8 million, included in other assets in the consolidated balance sheets. All amounts outstanding with the Affiliate under the agreement were collected in full during the three months ended March 31, 2024. 
+Receivables from the Affiliate as of December 31, 2023 were $ 5.2 million, included in accounts receivable—related party. 
+During the period January 1, 2024 through March 13, 2024, and the years ended December 31, 2023 and 2022, interest income from the Affiliate was $ 0.5 million, $ 2.0 million, and $ 0.0 million, respectively. 
+F-30 
+LIBERTY ENERGY INC. 
+Notes to Consolidated Financial Statements 
+Oklo Inc. 
+During the three months ended September 30, 2023, the Company invested $ 10.0 million in a fission power and nuclear fuel recycling company, Oklo. Effective May 10, 2024, through an acquisition by a special purpose acquisition company, the Company ’ s investment converted into shares traded on the New York Stock Exchange. Additionally, Chris Wright, the Company ’ s Chief Executive Officer and Chairman of the Board during fiscal year 2024, was appointed to the Oklo board of directors. During the year ended December 31, 2024, the Company recorded an unrealized gain of $ 41.6 million, included in unrealized gain on investments, net in the accompanying consolidated statements of operations. As of December 31, 2024, the fair value of the Company ’ s investment using Level 1 inputs was $ 51.6 million. The Company was not party to any other transactions with Oklo during the years ended December 31, 2024, and 2023. 
+Nomad Proppant Services LLC 
+During the year ended December 31, 2021, the Company committed to investing $ 10.0 million in Nomad Proppant Services LLC (“Nomad”), a mobile sand mine company. Upon the commitment, the Company had a significant but non-controlling financial interest in Nomad. Within the normal course of business, the Company purchased proppant from Nomad for $ 5.5 million during the year ended December 31, 2024. Payables to Nomad as of December 31, 2024, were $ 0.6 million. Prior to the year ended December 31, 2024 the Company did not purchase any goods from Nomad. 
+As of December 31, 2024 and 2023, the value of the Company ’ s investment using the equity method accounting was $ 10.7 million and $ 11.4 million, respectively. During the years ended December 31, 2024 and 2023, the Company received cash distributions from Nomad in the amounts of $ 4.0 million and $ 0.8 million, respectively. 
+Bettering Human Lives Foundation 
+In December 2023, the Company established the Bettering Human Lives Foundation (the “Foundation”), a nonprofit organization dedicated to promoting clean cooking solutions and improving the well-being of communities worldwide. Mr. Wright, the Company’s CEO during fiscal year 2024, serves as the Chairman of the Foundation, and Anne Hyre serves as its executive director. Ms. Hyre is the sister-in-law of Mr. Wright. In December 2023, the Company made an initial commitment to make a charitable contribution of $ 1.0 million to the Foundation. In addition, effective January 1, 2024 Ms. Hyre is employed by a subsidiary of the Company and seconded to the Foundation, and Company and the Foundation entered into a professional services agreement (the “Professional Services Agreement”), whereby the Company provides certain administrative services for the Foundation. During the year ended December 31, 2024, the Company made charitable contributions of $ 0.9 million to the Foundation, and received $ 0.5 million in other service revenue under the Professional Services Agreement.
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+CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS 
+Policies and Procedures for Review of Related Party Transactions 
+A “ Related Party Transaction ” is a transaction, arrangement or relationship in which the Company or any of its subsidiaries was, is or will be a participant, the amount of which involved exceeds $120,000, and in which any related person had, has or will have a direct or indirect material interest. A “ Related Person ” is: 
+♦ any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors; 
+♦ any person who is known by us to be the beneficial owner of more than 5% of our Class A Common Stock; 
+♦ any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, executive officer or a beneficial owner of more than 5% of our Class A Common Stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5% of our Class A Common Stock; and 
+♦ any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10.0% or greater beneficial ownership interest. 
+Our Board has adopted a written related party transactions policy. Pursuant to this policy, our Audit Committee reviews all material facts of all Related Party Transactions and either approves or disapproves entry into the Related Party Transaction, subject to certain limited exceptions. The determination of the Audit Committee is documented in the Audit Committee’s minutes. In determining whether to approve or disapprove entry into a Related Party Transaction, our Audit Committee considers, among other factors, the following: (i) w hether the Related Party Transaction is on terms no less favorable than terms generally available to an unaffiliated third- party under the same or similar circumstances and (ii) the extent of the Related Person’s interest in the transaction. Furthermore, the policy requires that all Related Party Transactions required to be disclosed in our filings with the SEC be so disclosed in accordance with applicable laws, rules and regulations. 
+Related Party Transactions 
+The following is a description of transactions entered into, or in effect, after January 1, 2025 to which we have been a party, in which the amount involved in the transaction exceeds $120,000, and in which any of our directors, executive officers or beneficial owners of more than 5% of our voting securities, or affiliates or immediate family members of any of our directors, executive officers or beneficial owners of more than 5% of our voting securities, had or will have a direct or indirect material interest. We believe the terms obtained or consideration that we paid or received, as applicable, in connection with the transactions described below were comparable to terms available or the amounts that would be paid or received, as applicable, from unrelated third parties. 
+Transactions with Tim Babcock 
+Tim Babcock is currently employed by the Company as a director of operations. Tim Babcock is the son of Ken Babcock, a member of our Board. For the year ended December 31, 2025, Tim Babcock was paid gross compensation of approximately $211,000 for his services as an employee. 
+Transactions with the Bettering Human Lives Foundation 
+In December 2023, the Company established the Bettering Human Lives Foundation (the “ Foundation ”), a nonprofit organization dedicated to promoting clean cooking solutions and improving the well-being of communities worldwide. Mr. Wright, the Company’s former Chief Executive Officer also formerly served as Chairman of the Foundation, and his sister-in-law, Anne Hyre, currently serves as the Foundation’s executive director. Ms. Hyre is employed by the Company and seconded to the Foundation. Ms. Hyre received total compensation of approximately $177,000 from the Company for the year ended December 31, 2025. In addition, the Company and the Foundation are parties to a Support Services Agreement (the “Support Services Agreement”) whereby the Company provides certain administrative and operational support services to the Foundation. During the year ended December 31, 2025, the Company made charitable contributions of $0.9 million to the Foundation and received $0.6 million in other service revenue from the Foundation under the Support Services Agreement. 
+49 
+Transactions with Veriten LLC 
+Mr. Murti joined our Board in January 2025. He is a partner at Veriten LLC, a private research, investment and strategy firm, that the Company retained for consulting services in 2025 for approximately $250,000 and has retained again in 2026 for approximately $250,000. 
+Transactions with Franklin Mountain Energy 
+A former member of the Board, Ms. Audrey Robertson, served as Executive Vice President of Finance of Franklin Mountain Energy, LLC (“Franklin Mountain”) until its acquisition by an unaffiliated party. Accordingly, effective January 28, 2025, Franklin Mountain is no longer a related party. The amounts of the Company’s revenue related to completion services provided to Franklin Mountain during 2025 was $5.8 million. 
+Indemnification for Officers and Directors 
+Our Charter and Third Amended and Restated Bylaws (our “Bylaws”) provide indemnification rights to our directors and officers and permit us to purchase insurance on behalf of any officer, director, employee or other agent for any liability arising out of that person’s actions as our officer, director, employee or agent, regardless of whether Delaware law would mandate indemnification. Additionally, we have entered into separate indemnity agreements with our directors and certain officers to provide additional indemnification benefits, including the right to receive, in advance, reimbursements for expenses incurred in connection with a de fense for which the director or officer is entitled to indemnification. We believe that the limitation of liability provisions in our Charter, Bylaws and the indemnity agreements will facilitate our ability to continue to attract and retain qualified individuals to serve as directors and officers. 
+Conflicts of Interest 
+The Related Party Transactions described herein may cause certain conflicts of interests, including that: 
+♦ we may enter into contracts between us, on the one hand, and related parties, on the other, that are not as a result of arm’s-length transactions; 
+♦ our executive officers and directors that hold positions of responsibility with related parties may be aware of certain business opportunities that are appropriate for presentation to us as well as to such other related parties and may present such business opportunities to such other parties; and 
+♦ our executive officers and directors that hold positions of responsibility with related parties may have significant duties with, and spend significant time serving, other entities and may have conflicts of interest in allocating time. 
+50 
+HOUSEHOLDING 
+The SEC permits companies and intermediaries (such as brokers and banks) to satisfy delivery requirements for proxy statements and annual reports with respect to two or more stockholders sharing the same address by delivering a single proxy statement and annual report to those stockholders. This process, which is commonly referred to as “householding,” is intended to reduce the volume of duplicate information stockholders receive and reduce expenses for companies. Both the Company and some of our intermediaries may be householding our proxy materials and Annual Report on Form 10-K. Once you have received notice from your broker or another intermediary that they will be householding materials sent to your address, householding will continue until you are notified otherwise or until you revoke your consent. Should you wish to receive separate copies of our Annual Report on Form 10-K and proxy statement in the future, we will promptly deliver a separate copy of each of these documents to you if you send a written or oral request to us at our address or phone number appearing on the cover of this Proxy Statement, to the attention of the Corporate Secretary. If you hold your shares through an intermediary that is householding and you want to receive separate copies of our Annual Report on Form 10-K and proxy statement in the future, you should contact your bank, broker or other nominee record holder.
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